id,document,summary
52785,"Agiba secured in March devt rights to the Southwest Meleiha 1 lease, a carveout from the IEOC-operated Southwest Meleiha explo block in the N. Egypt Basin. The lease surrounds the 2018 Meleiha SW B-1 light oil find.","Agiba secured in March devt rights to the Southwest Meleiha 1 lease, a carveout from the IEOC-operated Southwest Meleiha explo block in the N. Egypt Basin. The lease surrounds the 2018 Meleiha SW B-1 light oil find."
71821,"Shell suspended with oil shows the ACFO (1-SHEL-031-RJS) new-field wildcat (NFW) in the Alto CF Oeste P3 contract, ALTO_CF_O block on 12 December 2019 at a final total depth (TD) of 5,120 m. The operator concluded drilling operations on 1 December 2019 and was speculated to have conducted some testing operations on the oil show reports it filed since the rig remained on location until early-January when it moved back to the Argonauta Field to conduct more development drilling. There has been no official report as to the final status of the well. Shell filed a total of three show reports with the last one on 20 December 2019 after concluding its drilling operations.    Shell      filed an oil show report with the ANP for the well on 8 November 2019, a      second show report was filed on 2 December 2019, and a third show report      filed on 20 December 2019. However, the ANP removed the two earlier show      reports filed for the well for unknown reasons.   The NFW      was spudded on 6 October 2019.   The      proposed total depth was 5,200 m with the pre-salt Early Cretaceous Barra      Velha Formation was the primary target.  The      prospect has super-giant potential with reserves greater than 500 MMboe.  Shell is utilizing the “Brava Star”      D/S to drill the well in a water depth of 1,720 m.  The      significant NFW is located in the northeastern area of the block      approximately 32 km east south-east of the nearest wells in the Atlanta      Field. It is also located approximately 74 km north-east of the northern      edge of the Mero Field.   Shell is      the operator of the contract with 55% working interest and partners are      CNOOC with 20% and QPI with 25%.    On 16 September 2019, Shell was granted a permit by IBAMA to drill up to three new-field wildcats (NFWs) in the Alto CF Oeste P3 contract, ALTO_CF_O block. The permit grants the operator the right to drill up to three wells, one firm well and two contingent wells. Shell may choose the location of two of the contingent wells from three proposed locations. Shell originally filed its environmental permit request in February 2018.   Shell has plans to drill up to three new-field wildcats (NFWs) in the Alto CF Oeste P3 contract, ALTO_CF_O block after filing its environmental permit in February 2018. The Alto Cabo Frio Oeste structure is a western continuation of the Cabo Frio high with some separation from the easterly adjoining, larger structural closure of the Alto de Cabo Frio Central. The NFWs to be drilled will have proposed total depths of approximately 5,500 m to 6,000 m and will target the Barra Velha and Itapema formations of the pre-salt series in the Santos Basin. The drilling was expected to commence in the block during 2nd quarter 2019.The structure is potentially very large and depending on separation from the Alto do Cabo Frio structure, reservoir properties, and oil migration, it may be a large reservoir. The wells are located in the central area of the block and about 64 km north-east of the Mero field.  On 31 January 2018, the consortium of Shell as operator with 55% working interest, CNOOC 20%, and QPI with 25% was granted an official award for the Alto de Cabo Frio Oeste block from the 3rd PSC Pre-Salt Bid Round. The ANP changed the official denomination of the block to the Alto CF Oeste P3 contract, ALTO_CF_O block. Shell as operator with 55% working and with 20% partner CNOOC and 25% partner QPI, offered the minimum state take of profit oil of 22.87% and USD 106.38 million in total fixed bonus to be paid to the Brazilian government based on the USD to BRL exchange rate of the day of 1USD/3.29 BRL. There were no other bids for the block. The PSC contract has a seven-year exploration-evaluation phase and the minimum work program is to drill one exploration well. The minimum financial guaranty for the three-year period is USD 47.95 million which is less than the estimated cost of drilling a pre-salt exploration well.","ACFO (1-SHEL-031-RJS) nfw. (Shell 55% op, CNOOCI 20%, Qatar Petr 25%) in Alto CF Oeste P3 contract, ALTO_CF_O block, target Barra Velha, oil shows report to ANP on 8 Nov '19. WD=1720m, PTD=5200, and was speculated to have conducted some testing operations on the oil show reports it filed since the rig remained on location until early-January "
40954,"On 1 February 2019, the State Agency for Geology and Subsoil Use of Ukraine announced an auction for seven licenses. The auction is scheduled for 2 May 2019 with its application deadline on 1 May. The winners of the auction will obtain 20-year E&P licenses. Additional information can be requested from:  Kiev  Antona Tsedika Str., 16, offices 415 & 416  Tel: +38 (044) 536 1320 and 456 6056  The Efremivska Pivnichyy block covers 99.5 sq km in Kharkiv Oblast (Dnieper-Donets Basin). Seismic coverage amounts to 311 km. No wells have been drilled in the block. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well.   The Dobrenska block covers 122 sq km in Kharkiv Oblast and encompasses the Dobrenska and Lannivska structures. Seismic coverage amounts to 77 km. One well has been drilled in the block. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well.   The Opolonivska-1 block covers 248 sq km in Chernihiv Oblast (Dnieper-Donets Basin) and encompasses the Zakhorivska Pivnichna and Strilnykivska prospects with combined oil resources estimated at 20 MMbbl. Seismic coverage amounts to 1,390 km. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well.   The Opolonivska-2 block covers 231 sq km in Chernihiv Oblast and encompasses several prospects with combined oil resources estimated at 4 MMbbl. Seismic coverage amounts to 850 km. Four exploratory wells have been drilled in the block. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well.   The Kalyuzhna-1 block covers 162 sq km in Sumy Oblast in the western part of the Dnieper-Donets Basin and encompasses the Lebedinska, Kalyuzhna and Tryhubivska structures. Seismic coverage amounts to 285 km. One well has been drilled in the block. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well.   The Drohobytska block covers 141 sq km in Lviv Oblast (Pre-Carpathian Foredeep). Seismic coverage amounts to 439 km. Eleven wells have been drilled in the block. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well.   The Kadobnyanska block covers 21 sq km in Ivano-Frankivsk Oblast (Pre-Carpathian Foredeep). Seismic coverage amounts to 132 km. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well.","On 1 February 2019, the State Agency for Geology and Subsoil Use of Ukraine announced an auction for seven licenses. The auction is scheduled for 2 May 2019 with its application deadline on 1 May. The winners of the auction will obtain 20-year E&P licenses. "
55169,"In the second quarter of 2019, Bashneft-subsidiary Sorovskneft discovered a new oil pool in the Ityakhskoye Severnoye field in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Wildcat Unlorskaya Zapadnaya 9 tested oil at a rate of 75 b/d through a 5 mm choke from the Tyumen Formation Unit Yu2 (Middle Jurassic) perforated at 2,808-2,828 m.   Ityakhskoye Severnoye, located in the Ural-Frolov Province, was discovered in 2018 when Unlorskaya Zapadanaya 9 tested oil at a rate of 27 b/d from the Tyumen Formation Unit Yu4. IHS Markit estimated 3P reserves of the reservoir at 30 MMbbl of oil. The Ityakhskiy Severnyy license encompasses the Suryeganskoye Yuzhnoye, im. A.Yu.Iskrina and Ityakhskoye Severnoye discoveries and several prospects. Bashneft is owned by Rosneft.","Russia, not found"
79373,"Bridgeport Energy (QLD) Pty Ltd was awarded exploration permit ATP 2024-P, located in the Cooper-Eromanga Basin, on 8 April 2020. The permit has been awarded for six years so will expire, or be eligible for renewal, on 7 April 2026.  Under the work commitments at least one well is required to be drilled within the first four years of the permit term. Two wells are already located in the permit area – Thurra 2 and Wemyss 1, but both are dry holes.  ATP 2024-P was one of two awarded to Bridgeport on the same day, with ATP 2023-P also awarded. It was applied for in Jan 2017 after being offered as block PLR2015-2-18 in the Queensland 2015 state acreage offer. The round was open between 14 May and 8 October 2015. Native title agreements were required to be met before award.  The permit is reported to be prospective for conventional and coalbed methane (CBM) resources.  ATP 2024-P, which covers an area of 421 sq km, was awarded on 8 April 2020. Bridgeport Energy (QLD) Pty Ltd applied for 100% interest in the block, but between application and award has reached farm-out agreements with New Era Oil & Gas Pty and Leigh Creek Energy Ltd to divest 50% and 20% respectively.","Bridgeport Energy (QLD) Pty Ltd was awarded exploration permit ATP 2024-P, located in the Cooper-Eromanga Basin,"
23513,"The 8th Licensing Round will shortly open, for unlicensed acreage west of 6deg 15' E longitude. Energistyrelsen (the Danish Energy Agency) had hoped to launch the round at the EAGE conference in Copenhagen but is awaiting final signature from the Minister of Energy, Utilities and Climate. Denmark has softened fiscal terms for the period 2017-25 with a view to ensuring Tyra Field redevelopment, and this may prompt increased participation in the 8th Round. Further bid rounds are expected to follow on a roughly biennial occurrence with each new round scheduled a year after the previous round's awards have been issued. The 7th Licensing Round was launched on 24 April 2014 and results were announced on 25 February 2016 after much delay, with sixteen licences awarded. The 7th round will form the template for future bid rounds, although a shorter timeframe is expected. The open door procedure will continue to the area east of 6deg 15' E, although onshore and nearshore licensing ceased in February 2018.","The 8th Licensing Round will shortly open, for unlicensed acreage west of 6deg 15' E longitude. Energistyrelsen (the Danish Energy Agency) had hoped to launch the round at the EAGE conference in Copenhagen but is awaiting final signature from the Minister of Energy, Utilities and Climate."
35540,"Tunisian state company Etap is promoting the country’s open blocks that are available to companies for direct negotiations.    The Department of Energy of Tunisia indicate that the bids relating to prospection and/or exploration permit granting should be submitted to the General Manager of Energy with the name and address of the tender. Bid opening and bid evaluation will be done during the fourth week following the considered quarter.    The open blocks are in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored. Etap has a special data room for visiting companies wishing to explore in Tunisia. Data are available on blocks including geophysical data (seismic lines, airmag, and gravity surveys) and geological data well reports and studies may be accessed at free of charge. Visitors benefit from Etap's expertise in any area.     Interested parties may contact    Etap    54 Avenue Mohamed V    1002 Tunis    Tunisia    Tel : +216 71 28 53 00    Etap web site: http://www.etap.com.tn    The available blocks as of November 2018 are understood to be as listed below.   There are 39 available blocks.     There was no change from the previous list. Some block areas were revised.  Total open acreage amounts to 133,001 sq km of which 82,002 sq km is onshore and 50,999 sq km is offshore.          Open   blocks                                           Block   Name         Area (sq km)         Situation         Block   Basin             Ain   Soltane         552         onshore         Sud-Tellian   Atlas             Beni   Khedache         4,271         onshore         Dahar   Uplift (Ghadames Basin)             Bir   Abdallah         2,045         onshore         Dahar   Uplift (Ghadames Basin)             Bizerte         3,466         onshore         Sud-Tellian   Atlas             Boughrara         3,019         onshore         Djefara   Basin             Chaffar         3,560         offshore         Pelagian   Basin             Chanchou         4,541         onshore         Djefara   Basin             Chenini         4,724         offshore         Pelagian   Basin             El   Garsi         2,256         offshore         Pelagian   Basin             El   Rimel         259         onshore         Dahar   Uplift (Ghadames Basin)             Jalta         7,784         offshore         Tellian   Atlas             Jebil         2,228         onshore         Dahar   Uplift (Ghadames Basin)             Kairouan         4,930         onshore         Pelagian   Basin             Kanbout         2,706         onshore         Dahar   Uplift (Ghadames Basin)             Korbous         6,290         offshore         Sud-Tellian   Atlas             Ksar   Ezzaouia         2,093         offshore         Djefara   Basin             Ksar   Tlili         4,433         onshore         Central   Atlas Graben Zone             Ksour   Essaf         4,343         offshore         Pelagian   Basin             La   Skhira         4,109         offshore         Pelagian   Basin             Majoura         4,335         onshore         Moroccan-Algerian-Tunisian   Atlas             Maktaris         5,435         offshore         Pelagian   Basin             Mellegue         3,842         onshore         Central   Atlas Graben Zone             Mezouna         4,092         onshore         Kasserine   Island             Mides         983         onshore         Moroccan-Algerian-Tunisian   Atlas             Mrezga         3,354         offshore         Pelagian   Basin             Ouedhref         1,541         offshore         Ashtart   Sub-basin (Pelagian Basin)             Sidi   Amor         3,917         offshore         Sud-Tellian   Atlas             Sidi   Salem         3,379         onshore         East   Tunisian Platform (Pelagian Basin)             Sidi   Toui         2,275         onshore         Dahar   Uplift (Ghadames Basin)             Smida         493         onshore         Ghadames   Basin             Sufaeitula         5,143         onshore         Kasserine   Island             Taguelmit         5,137         onshore         Djefara   Basin             Tamazret         3,915         onshore         Dahar   Uplift (Ghadames Basin)             Tebaga         5,388         onshore         Dahar   Uplift (Ghadames Basin)             Tibar         4,516         onshore         Diapir   Zone             Touareg         464         onshore         Ghadames   Basin             Triaga         1,716         onshore         Pelagian   Basin             Zahret   Midyen         3,874         onshore         Sud-Tellian   Atlas             Zaphir         1,594         offshore         Pelagian   Basin",Tunisian state company Etap is promoting the country’s open blocks that are available to companies for direct negotiations. The Department of Energy of Tunisia indicate that the bids relating to prospection and/or exploration permit granting should be submitted to the General Manager of Energy with the name and address of the tender. Bid opening and bid evaluation will be done during the fourth week following the considered quarter. The open blocks are in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored.
72583,"Chi Oil & Gas Pty Ltd was awarded exploration permit ATP 2039-P, located in the Adavale-Eromanga Basin, on 29 November 2019. The permit has been awarded for a period of six years and will expire, or be eligible for renewal, on 28 November 2025.  Chi Oil & Gas applied for the block as PLR201718-2-1, and was announced as preferred tenderer on 26 September 2018. Chi Oil & Gas was required to complete the negotiation of land access, native title and environmental agreements before the permit was awarded, as an Authority to Prospect (ATP) permit.   Under the block offer rules, Chi Oil & Gas must produce all gas discovered for the domestic gas market.  There are three historical wells located within the block area. Blondie 1 and Duff Gordon 1 were both dry holes, Buckable 1 encountered oil shows.  ATP 2039-P, which covers an area of 5,263 sq km, was awarded to Chi Oil & Gas on 1 November 2019. Chi Oil & Gas Pty Ltd holds 100% interest and operatorship of the permit.","Chi O&G was awarded ATP 2039-P, 5,263 sq km in the Adavale-Eromanga Basin, south-central QLD."
73314,"Pertamina reported that it has signed an agreement with Repsol to acquire a participating interest (PI) in the Southeast Jambi block on 26 February 2020. The signing ceremony for the agreement, which involved a 27% PI, was carried out in Central Jakarta by Pertamina Hulu Energi (PHE) Southeast Jambi and Repsol Exploracion Southeast Jambi BV. Repsol will remain as operator of the block with 40% interest, while MOECO holds the remaining 33% PI.  The Southeast Jambi block covers an area of 1,121 sq km. The block was offered as part of the Conventional Oil and Gas Bidding First Round 2018 and was eventually awarded to Repsol and MOECO in May 2018, under the gross split scheme contract. Signature bonus for this block was set at USD 500,000. Minimum commitments required for the block are three G&G studies and 300 km of 2D seismic survey, with a total investment value of USD 4.65 million.  The operator is planning to acquire a 300 km 2D seismic survey in the block in 2H 2020, as part of the work commitment. In December 2019, an airborne gravity-magnetic survey was completed in the block. The survey was acquired by CGG over a period of approximately 20 days, for the purpose of identifying potential locations for the seismic survey.  Background Information  On 19 February 2018, the Government of Indonesia via the Ministry of Energy and Mineral Resources (MEMR) offered the Southeast Jambi block under the Conventional Oil and Gas Bidding First Round 2018, via the Direct Offer mechanism. Access to bid documents was scheduled from 19 February 2018 to 27 March 2018, with the clarification forum between 22 February 2018 and 29 March 2018. Bid submission for Direct Offer blocks was due by 4 April 2018. The block is subject to the Gross Split PSC term which has a government/contractor base split of 57%/43% for oil and 52%/48% for gas. The base split can be further modified by variable components and progressive components depending on the specific status of the block.","Pertamina (-> 60%) has signed to acquire a 27% stake from optr Repsol (->40% op.) in the Southeast Jambi block, (1121km²)"
60871,"South Ghazalat block, Abu Ghadariq Basin, W. Desert, late 2018 discovery to be brought on stream 4Q '19. The well had tested a combined 3,840 b/d of 35-38 API oil from the U. + L. Bahariya, of which a calculated 2,437 b/d + 1.4 MMcfg/d on 40/64"" choke from a 13m intv in the L. Bahariya, and 1,403 b/d light oil, 1 MMcfg/d + water on 1"" choke from 7m in the U. Bahariya. An appraisal is hoped to be spudded before end 2019.","Egypt, Ghazalat (Dev)"
24923,"On 1 July 2018, Dana Petroleum abandoned the Raya 1 wildcat in the El Qa’a Plain block, Gulf of Suez as a dry hole. The well was spudded on 17 June 2018 and was targeting the Nukhul formation in a tilted fault block structure.  Dana Petroleum operates the block with a 37.5% interest. Partners in the application are Petroceltic with a 37.5% and Rockhopper with a 25% interest.  Background information    On 8 November 2012, Petroceltic International plc plc (Petroceltic) announced its participation in a joint venture which was the successful bidder on Block 12 (El Qa’a Plain) in the 2011 EGPC bid round. The block is composed of two largely unexplored areas covering 1,824 sq km in the southern part of the Sinai Peninsula, east of the prolific Gulf of Suez. The overall licence term for the Block is six years, with the work commitment in the first 4 year-period comprising the acquisition of a minimum 450 sq km of new 3D seismic data and the drilling of at least one exploration well. The new concession was formally awarded in 2013.  On 23 November 2015, Dana Petroleum started its seismic operations over El Qa’a Plain block. A 35 km 2D and 467 sq km seismic survey were conducted by Geofizika, the contractor, between November 2015 and January 2016.  On 16 August 2016, Rockhopper Exploration plc (Rockhopper) announced the completion of the acquisition of Beach Petroleum Egypt Pty Ltd (Beach Egypt). The deal was announced on 15 August 2015 and amended on 18 April 2016.Under the agreed amended terms, Rockhopper will acquire the entire issued share capital of Beach Egypt for up to USD 20.5 million (USD 11.9 million will be received upon completion, with approximately USD 8.6 million to occur over the next 12 months subject to receipt of outstanding receivables). Beach Egypt has a 22% interest in the Abu Sennan lease and 25% interest in the El Qa’a Plain block.","Raya 1X (Dana 37,5% op, Petroceltic 37,5%, Rockhopper 25%) in El Qa'a Plain block, P&A dry, Target L. Miocene Nukhul fm."
36318,"Chevron has completed the farm out of its 20% stake in PL859 to DNO Norge effective 22 November 2018, and hence is no longer involved in the Norwegian Continental Shelf (NCS). Chevron confirmed in early October 2018 that it had signed a deal to transfer its last remaining NCS licence stake to DNO in July 2018. PL859 contains the Korpfjell Shallow gas discovery estimated at 210 to 425 Bcfg recoverable resources, drilled in 2017 by 7435/12-1 (TD: 1,540m MD) which encountered a 34m gas column in the Early to Middle Jurassic Sto Formation (Fm) primary objective, with good to very good reservoir quality, and a gas/water contact at 580m SSTVD. The well also identified minor gas in poor quality Middle Triassic Kobbe Fm and water-bearing Middle to Late Triassic Snadd Fm of moderate quality. The partners plan to drill the Korpfjell Deep NFW 7335/3-1 on the licence in Q4 2018 to fulfil the two well firm commitment due by mid 2019, with the ""West Hercules"" semi-sub going on contract to Equinor in early October 2018 for a three well campaign. It is targeting Triassic Fruholmen and Early to Middle Jurassic Sto Fms, with a secondary target in sandstones of the Triassic Snadd, Cob and Havert Fms, and deeper Permian source rock in the Orret Fm. PL859 covers blocks 7434/7, 8 & 9, 7435/9, 10, 11 & 12, 7335/1, 2 & 3, 7336/1 & 7436/10 (3,409 sq km), and was awarded on 10 June 2016 in the 23rd Round. PL859 equity partners are now Equinor Energy AS (previously Statoil, 30%+ Op), DNO Norge AS (20%), ConocoPhillips Skandinavia AS (15%), Lundin Norway AS (15%) and Petoro AS (20%).","Chevron has completed the farm out of its 20% stake in PL859 to DNO Norge effective 22 November 2018, and hence is no longer involved in the Norwegian Continental Shelf (NCS). "
10928,"Bozhong 19-6-2 (BZ 19-6-2) successfully flowed 1,000 bo/d and 6.4 MMcfg/d from the target reservoirs from production testing and was suspended in early December 2017. The appraisal well confirmed the Bozhong 19-6 discovery as a mid-size oil and gas discovery which is classified by CNOOC to contain recoverable resources of 15-150 MMboe and further gas exploration potential of buried hill reservoirs in the offshore Bohai Basin. Bozhong 19-6-2 was spudded in mid-August 2017 using the Bohai 12"" jack-up, targeting the Guantao, Dongying and Shahejie formations and buried hill reservoir. Bozhong 19-6-2 is in the CNOOC operated Bozhong Block in the offshore Bohai Gulf Basin and is approximately 2.5km NE of oil and gas discovery Bozhong 19-6-1 drilled by CNOOC in April 2017. <P />","China, Bozhong"
45047,"Predator signed for the Guercif Onshore permit, 4 blocks N. of Sound’s Tendrara acreage in the Rharb of NE Morocco. The 30-month initial term calls for reprocessing 250km of 2D seismic + 1 well to 2,000m target Miocene Rharb. Predator (op), partner Onhym.","Predator Oil & Gas, signed a petroleum agreement covering the Guercif Onshore permit, northeast Morocco. The Guercif permit includes four blocks, located north of Sound Energy’s Tendrara permit and east of SDX’s permits."
87221,"On 30 July 2020, the Agencia Nacional do Petroleo (ANP) granted formal approval for Petrobras to transfer 100% working interest to Eagle Exploracao de Oleo e Gas Ltda for the Conceicao, Fazenda Matinha, Fazenda Santa Rosa and Querera production concessions in the onshore Tucano Basin. The approval is conditioned to both companies presenting documents with details about the decommission of the fields.  Petrobras had reported on 9 March 2020 the signature of the sales agreement with Eagle Exploracao de Oleo e Gas Ltda for the Tucano Sul cluster of four producing gas fields mentioned above. The total consideration for the sale was USD 3.01 million which was to be paid in two installments, USD 602,000 on 9 March 2020 and USD 2.41 million on the official closing date of the transaction. On 9 July 2019, Petrobras published its teaser to sell the Tucano Sul cluster of four producing gas fields in the onshore Tucano Basin.          Tucano Basin fields   sale - general information             Field Name         Field sqkm         Disc Date Year         Prod Start Date         Avg. cond. Prod.   (bc/d) (Jan-May 2020)         Avg. gas prod.   (Mcfg/d) (Jan-May 2020)             Conceicao         9.8         1967         25-Feb-1970         0.38         486.45             Fazenda Matinha         3.95         1986         05-Apr-2005         0.15         99.16             Fazenda Santa Rosa         4.58         1992         25-Oct-2005         0.45         139.39             Querera         5.4         1962         01-Jul-1962         0.00         44.13             Source: IHS Markit                     ©   2020 IHS Markit","(Tucano B.) the Agencia Nacional do Petroleo (ANP) granted formal approval for Petrobras to transfer 100% working interest to Eagle Exploracao de Oleo e Gas Ltda for the Conceicao, Fazenda Matinha, Fazenda Santa Rosa and Querera production concessions. "
55465,"Stuart Petroleum Cooper Basin Pty Ltd, a wholly owned subsidiary of Senex Energy Ltd has been awarded two production licences over the Lacerta coalbed methane (CBM) field – PL 1023 and PL 1014, Bowen-Surat Basins. The licences are valid from 23 July 2019 after applications were submitted in December 2016. They are valid for a period of 30 years and scheduled to expire on 22 July 2049. To accommodate the awards, exploration permit ATP 795-P has been relinquished and ATP 767-P has been reduced in area.  The Lacerta field is now completely covered by PLs after PL 1022, which covers the eastern area of the field, was previously awarded to Stuart Petroleum on 26 April 2018. The three production licences are part of Senex’s Western Surat Gas Project, over the Glenora and Eos project areas.  Lacerta was discovered in 2006 and trail production commenced in 2007. A financial investment decision was initial made in 2018 for Roma North of the Western Surat Gas Project and most recently, approval for a 50 well drilling campaign in June 2019.    ATP 795-P, which covered an area of 218 sq km was awarded on 21 October 2005 and reached its expiry period on 31 October 2017, after the submission of the PL applications. The permit is no longer active.  ATP 767-P was awarded on 18 June 2004 and is scheduled to expire on 30 June 2026 after a third successful renewal in July 2018. To accommodate the PL awards, the permit has been reduced in area by approximately 75%, from 314 to 77 sq km. The remaining area covers the Pegasus coalbed methane field.  PL 1023 and PL 1024, which cover a combined area of 456 sq km over the Lacerta field, were awarded on 23 July 2019. Stuart Petroleum Cooper Basin Gas Pty Ltd, a Senex Energy subsidiary, holds 100% interest and operatorship of the licence.","Senex Energy Ltd has been awarded two production licences over the Lacerta coalbed methane (CBM) field – PL 1023 and PL 1014, Bowen-Surat Basins."
43537,"Campos Colpa-Caranda block, Foothill Belt / Chaco Basin, P&A TD 4,630m (PTD was 5,350m) in late 2019. Target believed Devonian Robore + Silurian Sara sst.","Caranda X-1005 npw in Campos Colpa-Caranda block, Foothill Belt / Chaco Basin, P&A TD 4,630m (PTD was 5,350m) in late 2019. Target believed Devonian Robore + Silurian Sara sst."
59428,"Lukoil and KMG have reached an agreement on joint studies on hydrocarbon potential of certain parts of Kazakhstan, areas not specified. Both companies are already involved in the Zhenis offshore block inter alia, and an agreement on the I-P-2 offshore project is expected to be finalised before year end.","Lukoil and KMG have reached an agreement on joint studies on hydrocarbon potential of certain parts of Kazakhstan, areas not specified. Both companies are already involved in the Zhenis offshore block inter alia, and an agreement on the I-P-2 offshore project is expected to be finalised before year end."
53560,"Aker BP spudded exploration well 25/2-20 in the NOAKA area on 29 June 2019 using the “Deepsea Stavanger” S/S. Just three days later (2 July 2019) the well was re-spudded as 25/2-21. The well location is in PL 442 between East Frigg and Frigg Gamma Delta and immediately north of Rind. 25/2-21 targeted the Liatarnet prospect which had a Tertiary Skade Formation objective at approximately 1,025 m, prognosed to be 35 m thick. Reservoir temperature was expected to be 30 degrees Celsius and pressure 100 Bar. TD was planned at 1,350 m. On 12 July 2019 Aker BP announced that it had made an oil discovery of between 80-200 MMboe, with more information due to be reported in due course. On 14 July 2019 the well was abandoned.  A development solution for the NOAKA area has not yet been agreed upon by operators Equinor (Askja Krafla) and Aker BP (North of Alvheim). As a 50% partner in the Askja Krafla licences Aker BP has vetoed the two separately-operated unmanned production platforms option that was favoured by Equinor and is pushing ahead for a central hub platform with processing and quarters. It maintains that this solution is the only one that will facilitate economic development of all the resources in the area and provide infrastructure which could support any future discoveries. In April 2019 Aker BP confirmed that discussions are still ongoing. Recoverable reserves in NOAKA are estimated to be around 500 MMboe.   Aker BP’s North of Alvheim area consists of Langfjellet (25/2), Frigg Gamma Delta (25/2 and 25/3), Froy (25/2 and 25/5), Fulla (30/11 and 25/2) and Rind (25/2). Langfjellet was discovered in 2016 and contains oil in the Middle Jurassic Hugin Formation. The Frigg Gamma Delta discovery was made in 1986 and oil and gas is present in the Eocene Frigg Sandstone at around 1,900 m. The Middle Jurassic Brent Group Froy field was originally developed by Elf and produced between 1995 and 2001. Due to problems with the reservoir, recovery rates were only half what was expected and, because of the low oil price at that time, the field was shut down with considerable remaining reserves. Fulla discovery well 30/11-7 proved volumes of 6-19 MMboe in good quality sands of the Middle Jurassic Etive Formation (Lower Brent Group) in 2009. A sidetrack was then drilled to locate further reserves in the Upper Brent Group and confirmed gas condensate in the Tarbert Formation. Rind was previously known as Lille Froy and it was discovered by Elf. Both 25/2-5 (discovery well, 1976) and 25/2-13 (appraisal, 1990) proved oil and gas in the Middle Jurassic Vestland Group and the Lower Jurassic Statfjord Formation. The NPD (December 2017) gives estimated recoverable reserves of 27 MMboe.  Equinor’s Askja Krafla area includes a number of discoveries in block 30/11 made between 2011 and 2016: Askja East, Askja Southeast, Askja West, Beerenberg, Haraldsplass, Krafla Main, Krafla North, Krafla West, Madam Felle and Slemmestad. The discoveries all have Brent Group reservoirs at depths between 2,900 m and 3,800 m TVD.  Interest in PL 442 is split between Aker BP ASA (90.26% + operator) and LOTOS Exploration and Production Norge AS (9.74%).","025/02-20,21 (Liatårnet) expl. (Aker BP 90,26% op, Lotos 9,74%) in Noaka (= North of Alvheim, Krafla + Askja) in PL 442 oil discovery of 80-200 MMboe gross resources, currently being completed, more data acquisition and analysis to follow, targeted the mid-Tertiary Skade Fm."
48281,"Ref. DEA 9 May ’19 (adds map): Indo’s 2nd Conventional O&G round 2019 was launched 8 May ’19,  4 blocks on offer under the regular tender mechanism. The mapp below illustrates thos blocks on offer (full map from GEPS). Contact: https://e-wkmigas.esdm.go.id.","Indo’s 2nd Conventional O&G round 2019 was launched 8 May ’19,  4 blocks on offer under the regular tender mechanism. "
35381,"An auction is planned 15 Jan ‘19 for 25-year rights to the Pukhutsyayakhskiy block, 825 sq km in the Yamal-Nenets AO, W. Siberia. Application deadline 12 Dec ‘18. Starting price USD 0.26 MM. Contact: Yamalnedra, email yamal@rosnedra.gov.ru.","An auction is planned 15 Jan ‘19 for 25-year rights to the Pukhutsyayakhskiy block, 825 sq km in the Yamal-Nenets AO, W. Siberia. Application deadline 12 Dec ‘18. Starting price USD 0.26 MM. "
13867,"Mitsui has won the bidding war to take over AWE for AUD 0.95 / share (around USD 470 million), after China Energy Reserve and Chemical Group and Mineral Resources couldn’t match its offer. Through the deal, the Japanese company is most notably taking over the Waitisa gas project, marking its first time as operator of a gas field. An offer is expected to be sent to AWE investors on 9 Feb ’18.","Australia, not found"
26089,"PL 925, overlay of S. part of Grosbeak structure, WD 358m, TD 2,726m, Heather fm sandstone units largely water-wet with some gas traces, to be P&A as dry, Transocean Arctic SS. Wellesley (op), partner Concedo.","035/12-07 (Serin) (Wellesley 90% op, Concedo 10%) in PL 925 block, overlay of S. part of Grosbeak structure, Upper Jurassic Heather fm. sst units largely water-wet with some gas traces, to be P&A as dry, WD=358m, TD=2726m."
14455,"Repsol Sinopec is to take over RockRose’s 17.416% and JX Nippon’s 15.168% interests in block 15/23a / P324 (Galley field), ending up sole holder of the tract after the deal is approved. Galley went onstream in 1998 and is due for re-development. ",Repsol Sinopec has acquired both RockRose Energy and JX Nippon’s interest in block 15/23a (P324) which contains the Galley field.
13246,"PEL 570, Cooper-Eromanga, ops terminated 22 Jan ’18, results yet n/a, Ensign rig 970. Santos (op), partners Ambassador O+G + New Standard Energy.  ","Australia (Eromanga B.) Casimir 1 op. by SANTOS (35.0%, BEACH 47.5%, SUNDANCE E 17.5%) in PEL 570 block"
81475,"On 5 May 2020, the ANP granted final award for the 2.85 sq km Fazenda Sori and the 5.06 sq km Pojuca Norte blocks in the Reconcavo Basin, to operator Brasil Refinarias with 100% working interest.  The blocks had been preliminary awarded on 10 September 2019 during the 1st ANP Open Door Bid Round to operator Brasil Refinarias with 50% working interest and partner Guindastes Brasil Locacao de Equipamentos Ltda with the remaining 50% working interest.",The ANP granted the Fazenda Sori (2.85km²) and 5.06km²) Pojuca Norte field onshore leases to Brasil Refinarias. Both had been issued under the 1st ANP Open Door Bid Round.
15419,"100/94 Przemysl G contract, Outer Carpathian Foredeep in SE Poland, drilled Nov-Dec ’17, TD 2,030m (Miocene), tested up to 7.6 MMcfg/d, completed for production. Target Upper Badenian - Lower Sarmatian. ","100/94 Przemysl G contract, Outer Carpathian Foredeep in SE Poland, drilled Nov-Dec ’17, TD 2,030m (Miocene), tested up to 7.6 MMcfg/d, completed for production. Target Upper Badenian - Lower Sarmatian. "
22853,"Manora prod. area in G01/48, N. Gulf of Thailand, WD 46m, Footwall prospect SW of the Manora platform, TMD 2,458m, 93m net pay logged, of which 26m pay in the target 490-60 sand, 2m in the other 400 sands, 32m in the 300 level sands and 33m at the 500 level sand. The latter two are considered new contingent resources. Plugging, and following completion Ensco 115 JU to drill MNA-20 & 21 devt. Mubadala (op), Tap, Northern Gulf Petr.","Manora prod. area in G01/48, N. Gulf of Thailand, WD 46m, Footwall prospect SW of the Manora platform, TMD 2,458m, 93m net pay logged, of which 26m pay in the target 490-60 sand, 2m in the other 400 sands, 32m in the 300 level sands and 33m at the 500 level sand. The latter two are considered new contingent resources. Plugging, and following completion Ensco 115 JU to drill MNA-20 & 21 devt. Mubadala (op), Tap, Northern Gulf Petr."
66062,"Shell Australia Pty Ltd spudded the Bratwurst 1 exploration well in exploration permit AC/P64, located in the Caswell Sub-basin, Browse Basin, on 29 September 2019. The well was drilled by the ""Ocean Apex"" S/S, operated by Diamond Offshore. In early December 2019 the well was concluded, with the rig leaving the wellsite on 5 December 2019.  In its environmental submission to the National Offshore Petroleum Safety and Management Authority (NOPSEMA), which was published in January 2019, Shell reported that the well would be located in a water depth of around 155 m. Following two requests for further information by NOPSEMA on 20 February 2019 and 17 April 2019, the environmental plan was accepted on 15 May 2019. The well was subsequently spudded as planned, being scheduled for Q3 2019.  The well formed part of the term one work commitments in AC/P64, requiring a well to be drilled in the first three years of the permit, by September 2021. In the event of a discovery, tie-back to the Shell operated Prelude facilities, which lie around 150 km southwest, offers a potential avenue for commercialisation.  There are two, previously-drilled, wells within the permit area - Maret 1, drilled in 1991 and Circinus 1, drilled in 1999. Oil and gas shows were observed at Maret 1, while Circinus 1 was dry.    AC/P64, which covers an area of 500 sq km, was awarded on 20 September 2018. Shell Australia Pty Ltd holds 100% interest and operatorship of the permit.",Australia (Caswell Sub-basin (Browse B.)) Prelude
79440,"Coastal has taken over full rights to blocks TP/27, EP 475, 490 + 491 (aka Cerberus blocks) from Tanami Energy (Skye Energy Ventures sub) retro-effective 7 Sep '19 for AUD 1.2 MM. Cerberus totals 3,832 sq km on the Enderby Terrace + Peedamullah Shelf, N. Carnarvon Basin. Coastal is now looking to farmout to complete the remaining work programmes – 7 wells are required before the permits expire.","Coastal has taken over full rights to blocks TP/27, EP 475, 490 + 491 (aka Cerberus blocks) from Skye Energy Ventures for AUD 1.2 MM, Cerberus totals 3,832 sq km on the Enderby Terrace + Peedamullah."
18692,"Add. DEA 28 Feb ’18 (adds test result): Khaskeli ML (Badin I), Lower Indus onshore, TD 1,753m, tested 182 bo/d + 50 Mcfg/d presumably from the Lower Goru target. TCPDC-2001 rig.",Pakistan (Indus B.) Khaskeli
41558,"As reported on 11 February 2019, Conrad Petroleum and Empyrean Energy have agreed with Coro Energy on a deal by which Coro will acquire a 15% participating interest in the Duyung PSC, located in the West Natuna Basin. The total consideration payable by Coro will include USD 4.8 million (including USD 2.95 million in cash and USD 1.85 million in Coro shares), plus a contribution of USD 10.5 million to partially fund the exploration drilling programme planned for 2019.  Conrad and Empyrean currently participate in the PSC with 90% and 10% interests respectively, through operating subsidiary West Natuna Exploration Limited (WNEL). Upon completion of the transaction (contingent to regulatory approval), the new interest holders in the block will be Conrad (76.5%), Empyrean (8.5%) and Coro (15%) via direct ownership, as WNEL will transfer all of its interest to the respective companies.  By the time of the agreement, Coro has paid USD 1.75 million of the total cash consideration, plus USD 1.2 million towards the 2019 drilling campaign. The balance payment from Coro is due by 31 December 2019.  The block includes the Mako field, estimated to contain 2C gas resources of 276 Bcf and 3C resources of 392 Bcf. The operator submitted a Plan of Development (POD) for the field in 2018, and has signed a Heads of Agreement for gas sales to a Singapore buyer.  The planned drilling programme includes one well targeting the Tambak prospect (formerly “Mako Deep”), scheduled for 2019, and one shallow appraisal well in the Mako field (“Mako Shallow”). Prospective resources at Tambak are estimated between 200 and 300 Bcf, with a mid-case of 250 Bcf and geological chance of success (GCOS) of 45%, within Lower Gabus sandstones. The Mako Shallow appraisal is estimated to contain 100 Bcf of additional prospective resources for the Mako field, with a GCOS of 75%.  On 17 January 2019, Conrad and Empyrean signed an amendment of the Duyung PSC to convert the existing contract from to Gross Split terms. Subsequently, the operator has submitted a revised POD which is expected to be approved in Q1 2019.  The Duyung PSC will be the second acquisition of Coro Energy in Indonesia, following the 42.5% interest in the Bulu PSC in 2018. Both blocks represent near-production assets located close to existing infrastructure with access to regional gas markets.  Background Information  The Duyung PSC was awarded to Transworld (100%) in January 2007. The block was offered under the direct mechanism during the second phase of the ""Fifth Round"" of Migas-controlled acreage releases which opened on 15 August 2006. A signature bonus of USD 1.5 million was paid and firm commitments included G&G studies worth USD 1 million, acquisition of 400 sq km 3D seismic data and drilling one exploration well. The seismic commitment was conducted from late 2008 to early 2009 using PGS's 'Orient Explorer’ vessel. Around 360 sq km of data was acquired.    In September 2015, WNEL had agreed to farm out 85% interest to Hague and London Oil, however the agreement was terminated as of 1 April 2016 due to lack of the necessary regulatory approvals.    On 12 May 2017, Empyrean reported the completion of the first stage of a proposed deal with Conrad Petroleum for the acquisition of a 10% stake WNEL for an initial consideration of USD 2 million, pursuant to a Sale and Purchase Agreement (SPA) signed on 4 April 2017. Under the terms of the SPA, Empyrean had the option to pay further cash consideration of USD 2 million that would grant the company an additional 10% interest in WNEL. However, Empyrean reported on 30 May 2017 that it would not proceed to acquire the additional 10% interest, thus retaining only the initial 10% stake in WNEL while Conrad Petroleum retained the remaining 90% stake plus operatorship.    The Mako structure is estimated to have a lateral extent of 304 sq km with tested reservoir of approximately 7 m of fine sand layer within the Intra Muda Formation. In August 2018, Empyrean reported that modeling studies on the field indicated estimated gas initially in place (GIIP) of 705 Bcf, with upside potential case of 1,317 Bcf. The company at the time also reported recoverable contingent resources of 433 Bcf (2C) and 646 Bcf (3C).  The structure was originally drilled in 1999 by Lasmo with wildcat Mako 1, which encountered 7 m gas-bearing sandstones from logs, but was not tested. The structure was reinvestigated in mid-2017 by WNEL, with Mako South 1. The well flowed gas at a stabilized rate of 10.9 MMcf/d, with no CO2 recorded. According to the operator, test results indicated a laterally continuous reservoir with permeability in the order of multi-Darcy. The well reached a depth of 1,330 feet (approximately 405 m) on 19 June 2017.","Indonesia, Bulu PSC"
62169,"On 18 October 2019, the Argentine government granted an exploration permit for MLO-118 block to a consortium of a partnership of ExxonMobil and Qatar Petroleum through the publication of Resolution 657/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Work program in the first exploration period of four years consists of 2D seismic acquisition of 784.53 km and reprocessing of 1,968.21 km, 3D seismic acquisition of 1,763.82 sq km and reprocessing of 1,469.85 sq km, along with 2D gravimetry and magnetometry acquisition of 5,017.69 km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment. ExxonMobil operates the block with 70% interest while partner Qatar Petroleum holds the remaining 30%.  MLO-118 covers 4,203 sq km of deepwater area (as designated by the Argentine Secretary of Energy) in Malvinas Basin with approximated water depth below 200 m. Exploration target for the blocks in the area is expected to be oil and gas in the Springhill Formation, which has not produced from any fields on the Malvinas Basin side in comparison to the adjacent Austral Basin side where several offshore gas fields are currently producing.  ExxonMobil and Qatar Petroleum won the rights for MLO-118 after submitting a joint offer of USD 29.95 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019. Along with MLO-118, the group also won the rights for MLO-113 and MLO-117 blocks with offers of 30.1 million and 34.475 million, respectively. The offshore blocks marked the second partnership between ExxonMobil and Qatar Petroleum in Argentina after Qatar Petroleum's purchase of 30% equity in ExxonMobil affiliates in mid-2018.  Background Information  The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.","On 18 October 2019, the Argentine government granted an exploration permit for MLO-118 block to a consortium of a partnership of ExxonMobil and Qatar Petroleum "
52595,"Equinor reports a new pool discovery on the west flank of Oseberg field. A 112m oil column was encountered in a segment hitherto-untested in the Statfjord fm drilled by the Askepott rig under the Oseberg Vestflanken phase 2 project. Recoverable resources est. 22 MMbo, to be brought on stream via the new, unmanned Oseberg H platform. Equinor (op), partners Petoro, Total + COP.","Equinor reports a new pool discovery on the west flank of Oseberg field. A 112m oil column was encountered in a segment hitherto-untested in the Statfjord fm drilled by the Askepott rig under the Oseberg Vestflanken phase 2 project. Recoverable resources est. 22 MMbo, to be brought on stream via the new, unmanned Oseberg H platform. Equinor (op), partners Petoro, Total + COP."
25525,"Phoenix has taken on a 100% stake from Proen Projetos, Engenharia, Comércio e Montagem in the tiny (1.2 sq km) Rio do Carmo prod lease, Potiguar Basin, following ANP approval in late June.   Proen is currently undergoing a Brazilian bankruptcy process.",Phoenix has taken a 100% stake from Proen Projetos in the Rio do Carmo (100%) production concession.
63056,"On 2 November 2019, the Argentine government granted an exploration permit for MLO-123 offshore block to a consortium of Total, state company YPF, and Equinor through the publication of Resolution 695/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Total operates the block with 37.5% interest, followed by YPF with 37.5%, and Equinor with the remaining 25% stake. Work program in the first exploration period of four years consists of 2D seismic acquisition of 720 km, 2D seismic reprocessing of 1,393 km, 3D seismic acquisition and reprocessing of 3,000 sq km, and 2D gravimetry and magnetometry acquisition of 6,000 km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment.  MLO-123 covers 3,789 sq km of deepwater area (as designated by the Argentine Secretary of Energy) in Malvinas Basin with approximated water depth of up to 180 m. Exploration target for the block is expected to be oil and gas in the Springhill Formation, which has not produced from any fields on the Malvinas Basin side in comparison to the adjacent Austral Basin side where several offshore gas fields are currently producing.  The consortium of Total, YPF, and Equinor won the rights for MLO-123 after submitting an offer of USD 44.465 million. Along with MLO-123, Total also received 50% interest and operatorship in a partnership with BP on CAN-111 and CAN-113 blocks in Argentina Basin from Round 1.  Background Information  The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.","Equinor has been formally awarded more rights it won in Argentina's 1st offshore round earlier this year: Austral Basin: AUS-105 (2,157 sq km) + 106 (2,283 sq km, see also DEA 5 Nov)"
39995,"Faroe spudded appraisal well 31/7-3 S at Brasse East in PL 740 on 20 November 2018 using the “Transocean Arctic” S/S. It was targeting potential recoverable reserves of 12.5 MMboe on the eastern flank of the Brasse field, identified following recent seismic reprocessing and re-interpretation work. The well reached TD at 2,705 m (2,247 TVDSS) and is a dry hole. Water-wet sands were encountered in a Jurassic reservoir (48 m) with excellent reservoir quality. On 17 December 2018 sidetrack 31/7-3 A was kicked off targeting incremental reserves of 61 MMboe in the main Brasse reservoir. The well reached TD at 2,863 m (2,254 m TVDSS) and encountered oil. It penetrated around 40 m of Jurassic reservoir and reservoir depths and hydrocarbon contacts were similar to what was prognosed. On 18 January 2019 the well was abandoned.  Brasse discovery well 31/7-1 was drilled in 2016 and proved a 21 m oil column plus an 18 m gas column in the Jurassic Fensfjord Formation. Sidetrack 31/7-1 A was drilled to appraise the southeastern part of the discovery and confirmed oil and gas columns of 25 m and 6 m respectively. In 2017 Faroe appraised the find with 31/7-2 S, which confirmed a 9 m oil column in the Sognefjord Formation and on test flowed at a maximum rate of 6,187 bo/d through a 1” choke from a 3.6 m perforated interval, and 31/7-2 A which proved an 18 m oil column plus a 4 m gas column. Both wells have the same OWC as the discovery well (2,172 m), although 31/7-2 A has a deeper GOC (2,154 m), and there is good pressure communication between all wells. Reserves have been upgraded from 43-80 MMboe to 56-92 MMboe (46-76 MMbo plus 59-97 Bcfg).   Faroe is progressing plans for development as a subsea tie-back to either Brage or Oseberg and envisages 3 - 6 production wells plus a potential water injector. It believes that it could achieve a rate of 30,000 boe/d with first oil in 2021 / 2022. Capex is forecast at USD 500-700 million (based on four wells and one subsea template) and the final concept selection will take place in 2018 with PDO submission likely in 2019.    Interest in PL 740 is divided between Faroe Petroleum Norge AS (50% + operator) and Var Energi AS (50%).","031/07-03 S, 3A (Brasse Øst) (Faroe Petr. 50% + Op, Vår Energi 50%) commitment well in PL 740 block, S. of Brage, encountered 48m gross Jurassic reservoir with excellent properties but was aquiferous, WD=124m, TD=2,247m. Sidetrack 3A, has encountered 40m gross hydrocarbon bearing Jurassic reservoir. TD=2254m."
78383,"Sundulbari 2 field area, Sundulbari-Agartala Dome PML, Tripura-Cachar Basin, TD ca. 2,500m, reportedly tested gas in Feb '20, Armco rig.","Sundalbari 15 (SD-15, SDAN) appr Sundulbari 2 field area, Sundulbari-Agartala Dome PML, Tripura-Cachar Basin, TD ca. 2,500m, reportedly tested gas "
33440,"Senex Energy Ltd spudded the Snatcher North 1 oil appraisal well in PRL 145, located in the Cooper-Eromanga Basin, on 3 September 2018.  On 15 October 2018 the operator suspended the well, as an oil well, after reaching a total depth of 2,627 m.  The well was drilled to appraise the Snatcher field, which was discovered in July 2009 and has been producing since December 2009.  It was the ninth appraisal well to be drilled at the field, with the most recent drilling in 2014.  PRL 145, which covers an area of 98 sq km, was awarded on 27 October 2014.  Participants in the permit are Senex Energy subsidiaries Victoria Oil Exploration (1977) Pty Ltd (40% + Operator) and Permian Oil Pty Ltd (20%), and Beach Energy subsidiaries Impress (Cooper Basin) Pty Ltd (25%) and Springfield Oil and Gas Pty Ltd (15%).","Australia, PRL 145"
86746,"The New Zealand Block Offer 2019 was opened 27 Jul '20, acreage available in the Taranaki onshore, total 2,451 sq km. Bids by 4 Nov '20, awards by 1 Apr '21. Questions + process via blockofferquestions@mbie.govt.nz before 14 Oct '20.","New Zealand, not found"
31790,"On 8 October 2018 the National Agency of Natural Resources (AKBN) opened a tender call for the Block 5 onshore exploration permit. Interested companies are invited to submit their bid within 30 days from the announcement, i.e. before 7 November 2018. Awards under production-sharing terms will be for an initial period of up to five years, extendable to seven.  Block 5 covers some 2,100 sq km in southwestern Albania, in the Vlore and Gjirokaster provinces. Past exploration in the block includes 192 km of 2D seismic acquired by OMW in the 2000’s. 15 Unsuccessful exploratory well have been drilled in the block before 1990 (two with oil and/or gas shows). OMW drilled one well in 2004 (Kanina 1) to a TD of 5,362 m and encountered oil and gas shows. The block was already offered by AKBN on two occasions in 2015 and 2016 with no bid received.  Bids have to be filed with:  National Agency of Natural Resources  Bul. Bajram Curri, No. 18, Blloku Vasil Shanto  Tirana, Albania  Attention to: Adrian Bylyku, Executive Director  www.akbn.gov.al  The official announcement is available here.","On 8 October 2018 the National Agency of Natural Resources (AKBN) opened a tender call for the Block 5 onshore exploration permit. Interested companies are invited to submit their bid within 30 days from the announcement, i.e. before 7 November 2018. Awards under production-sharing terms will be for an initial period of up to five years, extendable to seven. Block 5 covers some 2,100 sq km in southwestern Albania, in the Vlore and Gjirokaster provinces."
26364,"The NPD confirmed on 25 July 2018 that DEA has acquired 13% interest in PL 211 and PL 211 B from Total with effect from 27 June 2018. PL 211 was awarded in the 15th Round and covers a 242 sq km area over parts of blocks 6506/6 and 6507/4. PL 211 B is located immediately south, covering 37 sq km over parts of blocks 6506/9 and 6507/7, and was awarded in APA 2006.   The licences contain the large Victoria gas discovery made by Mobil’s 6506/6-1, drilled in 2000, and appraised by current operator Total in 2009. The discovery is HPHT and has Middle and Lower Jurassic reservoirs in a four-way dip-closed domal structure. Victoria is one of the largest undeveloped discoveries on the Norwegian Continental Shelf and prior to Total drilling this appraisal, the NPD estimated that it held recoverable reserves of approximately 3.1 Tcf of gas. However, the reservoir is complex and the reserves range has subsequently been lowered to 706 Bcf-2.12 Tcf recoverable gas.  Interest in both licences is now split between Total E&P Norge AS (57% + operator) and DEA Norge AS (43%).",DEA has acquired 13% interest in PL 211 and PL 211 B from Total with effect from 27 June 2018.
38541,"Oyster is on the lookout for partners in its wholly-owned, 11,200 sq km block 1101 (Antsiranana) in the Ambilobe Basin along the northern tip of the island:","Oyster is on the lookout for partners in its wholly-owned, 11,200 sq km block 1101 (Antsiranana) in the Ambilobe Basin along the northern tip of the island:"
61010,"Sadiqabad 2870-5 EL, Indus onshore, Punjab, P&A at TD 3,773m (Cret.) late Sep '19, Hilong rig 9. PPL (op), partner GHPL","Cholistan X-1 nfw (PPL 97,5% op, GHPL 2,5%) within the Sadiqabad 2870-5 EL onshore licence P&A with results so far unreported, after carrying out testing. TD=3773 m."
80761,"It was announced on 17 May 2020 that Derkim Poliüretan Sanayi ve Ticaret A.S. has been awarded the M46-C onshore exploration licence (Southeast Turkey Zagros Fold Belt) on 13 May 2020 for a period of five-year. The licence, covering an area of 595 sq km, is located towards southeast of the country and Derkim Poliüretan will be 100% owner and operator of the licence.   Derkim Poliüretan had submitted the application on 10 January 2020.",Derkim Poliüretan awarded M46-C exploration licence in southeast Turkey
74189,"Cairn confirmed on 10 March 2020 that the sale of its wholly-owned subsidiary Capricorn Norge AS was completed in late February 2020 (financially effective from 1 January 2020). The company announced in November 2019 that it was selling the subsidiary to Solveig Gas Norway AS for the sum of USD 100 million. At the turn of 2019 / 2020 Solveig was re-named Sval Energi. In February 2020 Capricorn held interests in 15 licences in Norway and operated three of these. It was then awarded a further three licences (all operated) in March 2020 under APA 2019. The licences include two small discoveries (Agat, Jette) and the Nova field which is under development and due onstream in Q3 2021. Capricorn drilled its first two operated wells on the NCS in 2019 – both were dry holes. A well is also planned in 2020 on the Duncan prospect. The company was pre-qualified as an operator in Norway in late 2015 and in February 2016 it was awarded its first licence. Cairn will use the proceeds of the sale to support its ongoing business (which includes assets in the UK). Sval Energi, established in 2011, was acquired in 2019 by HitecVision. It is a significant owner in Gassled (15.55%) and has recently been involved in deals to acquire interests in Polarled and Duva. Its strategy is to become an integrated, infrastructure-based E&P operating company.  Capricorn's first NCS operated well was 6508/1-3 which targeted the Lynghaug prospect in PL 758. A 170 m section of Are Formation (the primary objective) was encountered with around 50 m of net sandstone interbedded with claystones and coals. Failure was put down to migration. If it had been successful it would have been a play opener for the Nordland Ridge and could have been developed as a tie-back to the Norne FPSO. Pre-drill reserves estimates were 70 MMboe.  Its second well, 6608/11-9, was drilled on the Godalen prospect in PL 842. Godalen had an Upper Jurassic Rogn Formation objective with potential to contain 90 MMboe and could also have been tied-back to Norne in the event of a discovery. The Rogn Formation was absent, although there were some sands (total 40 m) in the Upper Jurassic Melke Formation (118 m total section).   Nova was previously called Skarfjell and was discovered in 2012 by 35/9-7. Its reservoir is the Upper Jurassic Heather Formation. The discovery was appraised over the following year and the PDO was submitted in May 2018 (and received approval four months later). Operator Wintershall Dea intends to recover 77 MMboe from the field over an eight-year period using two 4-slot subsea templates (installed in May 2019) sited one kilometre apart (the northerly template will host three water injectors and the southerly one will have three producers). The templates will be tied back to Gjoa which lies approximately 16 km to the northeast. There is also provision for a third template with four more wells if needed. Gjoa will supply Nova with power (from shore), gas lift and water injection. Drilling of six wells will commence in H1 2020 and the installation of the other facilities will take place in 2019 / 2020. A new topsides module will be installed at Gjoa in May 2020 where processing will take place prior to export via the Troll oil pipeline to Mongstad. Maximum production is expected to be 50,000 boe/d and investment is estimated at NOK 9.9 billion (USD 1.23 billion). The field consists of three segments and the initial development relates solely to Nova Main, with the Southeast and East segments representing future upside potential.","Cairn Energy plc, Solveig Gas Norway AS, Sval Energi AS Sale of Capricorn Norge AS completed"
35371,"L20, Canning Basin, separate structure midway between Ungani + Ungani Far West fields, TD 2,322m, oil shows encountered earlier ended non-commercial although reservoir apparently excellent. Suspended as a potential water injector, DDGT-1 rig. Buru (op), partner Roc.","Ungani West 1 (Buru Energy 50% op. Roc Oil 50%) in L 20 block, a full log suite over the interval indicated several zones of good to excellent porosity with interpreted moderate oil saturations, however a detailed wireline pressure survey indicated there was no commercially producible oil column in the well."
67033,"It was reported in November 2019 that Oil and Gas Development Company Ltd (OGDCL) has assigned 5% working interest in the Tirah 3370-14 EL (Pishin-Katawaz Basin) onshore licence to Government Holdings Pvt Ltd (GHPL) which was made effective retrospectively from 21 March 2014. The revised equity split is as follows: OGDCL 95% (operator) and GHPL 5%. OGDCL is currently conducting 2D seismic acquisition in the block which was initiated in August 2019 with a plan of 286 LKM and as of end of November 2019, a total of 41 LKM was acquired.  The Tirah block covers 1,946 sq km area and is located in the Khyber, Orakzai and Kurram districts of Khyber Pakhtunkhwa province. The block was offered under the 2012 Licensing Round which was launched from 11 October 2012 to 10 March 2013 and OGDCL was declared as the successful bidder for this block. It was exclusively awarded to OGDCL with the signing of Petroleum Concession Agreement (PCA) on 21 March 2014.   As reported in August 2019, OGDCL was granted a two-year extension to the Phase-I of initial term for Tirah EL from 21 March 2019 to 20 March 2021. The period from 21 March 2017 to 20 March 2019 was also regularized as an extension.   No wells are known to have been drilled on the acreage specified by the application to date.",OGDCL has assigned 5% working interest in the Tirah 3370-14 EL (Pishin-Katawaz Basin) onshore licence to Government Holdings Pvt Ltd (GHPL) 
47095,"Santos Ltd and JX Nippon Oil and Gas Exploration completed the sale of interest in exploration permit WA-498-P, located in the North Carnarvon Basin, to Skye Alba Pty Ltd, on 14 December 2018.  Skye Alba, through wholly owned subsidiary Skye Energy Pty Ltd is now sole owner and operator of the permit.  The sale and purchase agreement between the companies was entered into on 1 March 2018.  Prior to the dealing, Santos held 75% and operatorship, while JX Nippon held the remaining 25%.  The companies had been looking to divest interest in a number of North Carnarvon basin permits, including WA-498-P.  No wells have yet been drilled in the permit’s validity, though it does contain one previously drilled well – Bligh 1, which was plugged and abandoned as a dry hole in 2002. There is one well outlined under the permit’s work programme, scheduled between April 2019 and April 2020.  The permit is due to expire, or be eligible for renewal, on 15 April 2020.  WA-498-P, which covers an area of 81 sq km, saw an interest change completed as of 14 December 2018.  Skye Energy Pty Ltd now holds 100% interest and operatorship of the permit.",Skye acquired Santos’s 75% operating interest and JX Nippon’s 25% participating interest in WA-498-P block.
73060,"As of February 2020, CNOOC is farming out the AGC Profond block, deep waters of the MSGBC Basin. The company offers a negotiable equity portion for farm-in. The block is located along the Cretaceous shelf edge with prospectivity in carbonate and clastic reservoirs. Six prospects have been high-graded for possible drilling. Among these are Wolverine and Civet. Wolverine is a prospect in Barremian carbonates in the northern part of the block. It has a mean in-place resource estimate around 1,500 MMboe. Civet is a salt-related anticline with Albian clastic reservoirs in the southern part of the block. It has a mean in-place resource estimate around 1,000 MMboe.  A data room is available. For further information contact Louis Nicolas Amedee Manesme. Phone: +44 1895 555 107.  As of March 2018, CNOOC was planning to drill an exploration well in the AGC Profond block. The well was to be drilled in 2019 but drilling operations are delayed until the AGC treaty between Guinea-Bissau and Senegal is renewed. The renewal is expected to happen in 2020.  CNOOC farmed into AGC Profond in March 2017 and took operatorship from Impact Oil and Gas. The block was awarded to Impact Oil and Gas in October 2014. The acreage covers approximately 6,700 sq km in water depths from 1,400 m to 3,700 m.   The AGC Profond block was previously operated by Ophir with FAR and AGC as partners. Ophir plugged and abandoned the new-field wildcat Kora 1 well as dry in 2011. The well encountered mainly Albian, Coniacian and Barremian claystone and thinly-bedded limestones sequence instead of the targeted sandstone reservoir facies. The well was drilled in 2,651 m of water and reached a TD of 4,447 m.","CNOOC is farming out the AGC Profond block, deep waters of the MSGBC Basin. The company offers a negotiable equity portion for farm-in. The block is located along the Cretaceous shelf edge with prospectivity in carbonate and clastic reservoirs."
13679,"The CNH held its CNH-RO2-LO4/2017 round (Ronda 2.4) yesterday for 29 deepwater blocks. 39 bids were received, and preliminary awards made for 19 of 29 blocks on offer, total 44,178 sq km, to 18 companies.  Six blocks were taken in the Perdido, 4 in the Mexican Ridges, and 9 in the Salina Basin.   Shell was the most active, followed by Repsol, Petronas and Pemex. ExxonMobil, DEA and Noble (qualified) did not participate. Newcomers include PTTEP and Qatar Petr. The table below sums up the assignments  (source: GEPS). ","CNH-RO2-LO4/2017 Bid Round or Ronda 2.4 - 19 of the 29 blocks were provisionally awarded to 18 companies. 6 blocks were taken in the Perdido, 4 in the Mexican Ridges, and 9 in the Salina Basin. Shell was the most active, followed by Repsol, Petronas and Pemex.  "
58850,"S. part of block XX, Asgat Sag in Tamsag Basin, FE Mongolia, P&A dry at TD 2,000m, Daton DXZ1 rig.","Red Deer 1 explo. (Petro Matad 100%) in Block XX, P&A, dry."
26591,"Perenco is acquiring 49% in Petrofac’s Mexico assets – including Santuario, Magallanes and Arenque - for an initial cash consideration of USD 200 million. The deal is still subject to approvals (expected in Q4 ’18).","Perenco is acquiring 49% in Petrofac’s Mexico assets – including Santuario, Magallanes and Arenque - for an initial cash consideration of USD 200 million. The deal is still subject to approvals (expected in Q4 ’18)."
72753,"Bridgeport secured sole rights to ATP 2022-P, 438 sq km around the Inland field in the Cooper-Eromanga, effective 4 Dec '19 for 6 years. It was offered as PLR2015-2-10 under the 2015 QLD acreage offer.","Bridgeport secured sole rights to ATP 2022-P, 438 sq km around the Inland field."
22989,"Lukoil + KazMunayGaz signed an agreement on principles for implementation of the Zhenis offshore block / project, Mangyshlak-Central Caspian Basin. Zhenis lies in the S. Kazakh Caspian sector on the border with Turkmenistan. There are no discoveries here to date.","Lukoil + KazMunayGaz signed an agreement on principles for implementation of the Zhenis offshore block / project, Mangyshlak-Central Caspian Basin. Zhenis lies in the S. Kazakh Caspian sector on the border with Turkmenistan. There are no discoveries here to date."
22091,"White Rose field area, 10km N. of the SeaRose FPSO, Jeanne d’Arc Basin off N&L, 2Q ’18 discovery, >85m light oil column. Husky (op), partners Suncor + Nalcor.",Canada (Jeanne d'Arc B.) White Rose
72492,"In February 2020, Arrow Exploration Corp announced they are looking for partners to explore the LLA 23 Block on the Llanos Basin as part of their near-term company strategy.  The 465.17 sq km LLA 23 Block is owned and operated by Carrao Energy SA, a subsidiary of Arrow Exploration. The original block was awarded in March 2009 to Petromont SA and in September 2018 Carrao Energy became the owner and operator of the LLA 23 Block after Canacol Energy Ltd sold some of its assets to Arrow Exploration. Canacol Energy became the operator of the block with 71% working interest, in November 2011, and partner Green Power Sucursal Colombia held the remaining 29% working interest.   Background information  The LLA 23 Block is relatively unexplored, with about 21 wells drilled, 4 producing fields and 1 discovery (Pumara 1).          LLA 23 Block Producing   Fields and discoveries                                                     Field/Discovery         Discovery         Spudded         Total Depth         Put on Stream         Cum Oil (end 2018)         Cum Gas (end 2018)         Main reservoir             Labrador         Agueda 1 ST         Nov-12         11,130 ft (3,392 m)         Dec-12         3.9 MMbo         486.3 MMscfg         U. Cret. Gacheta Fm.             Leono - Pantro         Leono 1         Nov-13         11,995 ft (3,656 m)         Dec-13         1.8 MMbo         56.2 MMscfg         U. Cret. Gacheta Fm.             Tigro         Tigro 1         Aug-14         12,270 ft (3,740 m)         Sep-14         327.7 Mbo                   Eoc. Mirador Fm.             Maltes         Maltes 1         2014                   Dec-14         106.2 Mbo (end of 2016)         2.2 MMscfg (end of   2016)         Oli. - Eoc. Carbonera   C7 Mb.             Pumara 1          Pumara 1         Mar-17         10,713 ft (3,265 m)                                       Oli. - Eoc. Carbonera   C7 Mb.             Danes         Danes 1         Oct-18         11,276 ft (3,437 m)         Nov-18         22.8 Mbo         606 Mscfg         U. Cret. Gacheta Fm.             Source: IHS Markit                                                                     ©   2020 IHS Markit","n February 2020, Arrow Exploration Corp announced they are looking for partners to explore the LLA 23 Block on the Llanos Basin as part of their near-term company strategy. The 465.17 sq km LLA 23 Block is owned and operated by Carrao Energy SA, a subsidiary of Arrow Exploration. "
49061,"In March 2019, Lukoil-Zapadnaya Sibir received an exploratory license for the Tazovskiy Zapadnyy block in Yamalo-Nenets Autonomous Okrug (Western Siberia). License SLKh02575NP is valid until March 2026. A long-term combined license for the block was available in December 2018 when it was auctioned but the auction became invalid due to lack of participants. It is understood that Lukoil decided to secure exploratory rights for the area instead of waiting for a new auction.  The Tazovskiy Zapadnyy block covers 1,170 sq km in the eastern part of the Nadym-Taz Province and encompasses the Tazovskaya Zapadnaya prospect with hydrocarbon resources estimated at 8.6 Tcf of gas and 316 MMbbl of condensate. Seismic coverage amounts to 1,921 km of 2D data and 28 sq km of 3D data. Five exploratory wells have been drilled in the area. Hydrocarbon resources (categories D1+D2) of the block are estimated at 72 MMbbl of oil, 9.4 Tcf of gas and 38 MMbbl of condensate.",Lukoil secured sole 8-year rights to the Tazovskiy Zapadnyy block (1170km²) in the Yamal-Nenets AO under licence SLKh02575NP.
46931,"On 12 April 2019, the CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round with little change except that there are now 20 companies that have expressed an interest.  There remain 13 companies authorized to pay data base access fees, 10 companies with data base access, and 11 companies that have initiated the prequalification process.   On 13 March 2019, Secretary of Energy Rocio Nahle was reported in the press at the IHS Markit CERAWeek conference to have said that PEMEX may seek to delay the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round until 2020.  There has also been reports in Mexico that PEMEX may seek to transform the process into only a Service Contracts type round.  Further details are expected in the future.    On 11 January 2019, the CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round.  The CNH reported that there is a total of 19 companies that have expressed an interest, 13 companies authorized to pay data base access fees, 10 companies with data base access, and 11 companies that have initiated the prequalification process.   On 11 December 2018, the CNH reported modifications to the schedule for the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round due to a request by SENER received on 7 December 2018.  There were some reports that the round might be cancelled also but SENER decided to extend the round by six months.      The modified schedule as of 11 December 2018 is now reported to be the following:       The period to pay the data room access fee is 27 April 2018 until 8 July 2019.       Reception of pre-qualification documents is from 22 July 2019 until 23 August 2019.       The list of pre-qualified companies will be published on 29 August 2019.       The final version of the bid documents will be published on 5 September 2019.       The      bid submittal date is 9 October 2019.     On 26 November 2018, the CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round.  The CNH reported that there are a total of 18 companies that have expressed an interest, 12 companies authorized to pay data base access fees, 10 companies with data base access, and 11 companies that have initiated the prequalification process.    On 18 July 2018, the CNH modified the bid documents for the CNH-R03-L02/2018 Bid Round, the CNH-R03-L03/2018 Bid Round, and the CNH-A6-7 Asignaciones/2018 Farm Out Bid Round whereby all of the bid rounds are now running concurrently and the calendars for all three rounds have been modified substantially with the bid submittal date now on 14 February 2019.  The CNH reported that this has been done at the request of the new incoming administration in order for the new Secretary of Energy to have time to review all of the bid documents and model contracts for possible modifications.  The new Energy Secretary will have approximately two months to review the contracts from 1 December 2018 until 6 February 2019 when the final versions of the bid documents will be published.    On 13 July 2018, the CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm Out Bid Round.  The CNH reported that there are a total of 12 companies that have expressed an interest, eight companies authorized to pay data base access fees, seven companies with data base access, and six companies that have initiated the prequalification process.    On 19 June 2018, the CNH modified the bid documents for the CNH-A6-7 Asignaciones/2018 Farm Out Bid Round for seven contracts that includes 27 PEMEX exploration and production entitlements.  The modifications also included publication by the SHCP regarding the royalties to be offered and the changes to the bidding criteria.  The bidding criteria will not include additional royalties offered as these are fixed percentages now, see table below.  Most are set at 15% additional royalties with the Giraldas-Sunuapa contract the only one set differently at 6%.  The modified bid documents also include the fixed initial bonus payment to be made to PEMEX by the winning bidder.  These initial payments range from a low of USD 5 million to a high of USD 146 million and total bonus payments are USD 587 million.  The lone bidding criteria now will be an additional cash payment offered with the highest additional cash payment to indicate the winning company.  The additional cash payment will be split 20% to the Mexican government and 80% to PEMEX.  The winning bidder will have 55% working interest while PEMEX will retain 45%.  Some of the contracts will be only for production and some will be for exploration and production.  Also the majority of contracts have some type of geological depth restrictions.  The bid submittal date is 31 October 2018.    On 15 June 2018, the CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm Out Bid Round.  The CNH reported that there are a total of 8 companies that have expressed an interest, four companies authorized to pay data base access fees, four companies with data base access, and two companies that have initiated the prequalification process.    On 27 April 2018, the CNH officially launched the CNH-A6-7 Asignaciones/2018 Farm Out Bid Round for seven contracts that includes 27 PEMEX exploration and production entitlements.  There are also seven state controlled blocks that were incorporated into several of the contracts. There is one bid document and joint operating agreement (JOA) for the seven blocks but there is one separate contract for each block. The contract type will be a License Contract.  PEMEX will be paid a fixed fee established in the bid documents and will have 45% working interest.  Total current production for all fields was reported to be 33 Mbo/d and 190MMcfg/d.  The estimated total recoverable reserves is 183 MMbo and 983 Bcfg with an estimated investment of USD 870 million.      The seven packages have been split into three groups.  A company must pay USD 136,612 at exchange rate of 1USD to 18.3 MXN to access one group for the data room purposes.  If a company wants to access all of the data for the three groups the fee will be USD 409,836.        On 5 March 2018, the CNH published information for seven packages that includes 36 exploration and production entitlements that PEMEX will farm-out, now reported to launch the first week of April 2018.  The CNH has published preliminary information on its CNIH website regarding the seven packages of blocks to be farmed-out.  PEMEX CEO Carlos Trevino reported on 6 March 2018 at CERAWeek conference that it plans to have the preliminary awards for these farm-outs concluded by September 2018 and final contract signatures prior to 1 December 2018 when the new administration will take office.  He also indicated that the Ayin-Batsil block would be re-offered as a farm out block in 2018 and that is all he estimates the company can do for this year.    The CNH has approved various modifications and migration requests by PEMEX involving up to 50 blocks since November 2017.  Two packages of blocks, the Cauchy block and the Costero blocks, that were originally requested to be migrated for farm-out purposes have not been included in the latest information regarding the farm-out round.            CNH-A6-7   Asignaciones/2018 Farm Out Bid Round – Companies List – 11 January 2019             Company         Companies that have   paid Access to the Data Room         Companies that have   begun the prequalification process             California Resources   Corporation         1         1             China Offshore Oil   Corporation E&P Mexico, S.A.P.I. de C.V.         2         2             Compania Espanola de   Petroleos, S.A. U.         3         3             Deutsche Erdoel   Mexico, S. de R.L. de C.V.         4         4             ECP Hidrocarburos   Mexico, S.A. de C.V.         5         5             Frontera Energy   Corporation         6         6             Galem Energy, S.A.P.I.   de C.V.         7                       Gran Tierra Mexico   Energy, S. de R.L. de C.V.         8         7             Hokchi Energy, S.A. de   C.V.         9                       Petrobal S.A.P.I. de   C.V.         10         8             Southerngeo Mexico,   S.A.P.I. de C.V.         11         9             Tecpetrol   International S.L.U.         12         10             Vista Oil & Gas   Holding II, S.A. de C.V.         13         11             Source: IHS Markit            ©   2019 IHS Markit           CNH-A6-7 Asignaciones/2018 Farm Out Bid Round - PEMEX Farm-Out Blocks – 19 June 2018 with Additional Royalties and Initial Bonus Payments            Contract Area         Basin         Entitlement or   Farm-Out Block Nomenclature         Entitlement (AE &   A blocks)         Fields-Production, AR   Entitlements, State Owned Blocks         Area sq km         Remaining OOIP Mmbo         Remaining OGIP Bcfg         Reported Risked  Median Prospective Resources MMboe         Additional Royalties %         Initial Bonus Payment   MM USD         Total Minimum Work   Program work units         Calculated work unit   values MM USD 1,044/work unit             1         Sureste         Artesa         AE-0058-M-Mezcalapa-08         Artesa, Gaucho,   Nispero, Rio Nuevo, Sitio Grande         893.13         1476.4         2025.7         147.5         15.00         86.00         33,750.00         35.24             2         Sureste         Bacal-Nelash         A-0027, A-0036,   A-0235, A-0339         Arroyo Prieto, Bacal,   Nelash, Tiumut         160.8         281.3         501            15.00         66.00         27,220.00         28.42             3         Veracruz         Bedel-Gasifero         AE-0040-Tesechoacan-02         Bedel, Eltreinta,   Gasifero         1168.11         500         649         133.83         15.00         128.00         31,196.00         32.57             4         Sureste         Cinco Presidentes         A-0092-M-Campo Cinco   Presidentes         Cinco Presidentes, Rodador         167.12         831.6         665.6            15.00         120.00         15,606.00         16.29             5         Sureste         Giraldas-Sunuapa         AE-0054-2M-Mezcalapa-04         Chiapas-Copana,   Comoapa, Muspac, Giraldas, Sunuapa         1726.38         1058.5         3951.1         210.68         6.00         36.00         33,465.00         34.94             6         Sureste         Juspi-Teotleco         AE-0057-M-Mezcalapa-07         Juspi, Teotleco         449.95         390.4         1592.7         143.9         15.00         146.00         38,383.00         40.07             7         Sureste         Lacamango         A-0187-M-Campo   Lacamango         Lacamango         16.26         75.3         95.5            15.00         5.00         9,818.00         10.25             TOTALS                     4581.75         4613.5         9480.6         635.91            587.00            197.77                   Source: IHS Markit                                    © 2018 IHS Markit            CNH-A6-7 Asignaciones/2018 Farm Out Bid Round - PEMEX Farm-Out Blocks – 27 April 2018            Contract Area            Basin            Entitlement or   Farm-Out Block Nomenclature            Entitlement (AE &   A blocks)            Fields-Production, AR Entitlements,   State Owned Blocks            AE Blocks            A Blocks            AR-State Blocks            Area sq km            Remaining OOIP Mmbo            Remaining OGIP Bcfg            Reported Risked  Median Prospective Resources MMboe             1            Sureste            Artesa            AE-0058-M-Mezcalapa-08            Artesa,   Gaucho, Nispero, Rio Nuevo, Sitio Grande, Carmito, Acuyo, Sabancuy            1            5            3            893.13                  147.5                   Artesa         A-0029-M-Campo   Artesa                           134.2         235.3                         Artesa         A-0141-M-Campo   Gaucho                           36.9         92.2                         Artesa         A-0236-M-Campo   Nispero                           324.5         232.4                         Artesa         A-0291-M-Campo   Rio Nuevo                           193         220.9                         Artesa         A-0312-M-Campo   Sitio Grande                           787.8         1,244.80                   2         Sureste            Bacal-Nelash            A-0027-M-Campo   Arroyo Prieto            Arroyo   Prieto, Bacal, Nelash, Tiumut            0            4            0            160.8            21.8            57.2                         Bacal-Nelash         A-0036-2M-Campo   Bacal                           120.7         137.9                         Bacal-Nelash         A-0235-2M-Campo   Nelash                           86.2         162.9                         Bacal-Nelash         A-0339-2M-Campo   Tiumut                           52.7         142.9                   3         Veracruz            Bedel-Gasifero            AE-0040-Tesechoacan-02            Bedel,   Eltreinta, Gasifero, Mixtan, and Palmaro            1            3            2            1,168.11                  133.83                   Bedel-Gasifero         A-0045-M-Campo   Bedel                           214.50         113.50                         Bedel-Gasifero         A-0122-M-Campo   El Treinta                           160.70         212.50                         Bedel-Gasifero         A-0140-M-Campo   Gasifero                           124.80         323.00                   4         Sureste            Cinco   Presidentes            A-0092-M-Campo   Cinco Presidentes            Cinco   Presidentes, Rodador            0            2            0            167.12            715.6            551                         Cinco   Presidentes         A-0292-M-Campo   Rodador                           116         114.6                   5         Sureste            Giraldas-Sunuapa            AE-0054-2M-Mezcalapa-04            Chiapas-Copana,   Comoapa, Muspac, Giraldas, Sunuapa, AR-0428 Campo Iris            2            5            1            1,726.38                  158.27                   Giraldas-Sunuapa         AE-0063-3M-Grijalva-01                                 52.42                   Giraldas-Sunuapa         A-0083-M-Campo   Chiapas-Copano                           177.30         827.50                         Giraldas-Sunuapa         A-0099-M-Campo   Comoapa                           127.10         118.80                         Giraldas-Sunuapa         A-0144-M-Campo   Giraldas                           289.70         840.50                         Giraldas-Sunuapa         A-0230-M-Campo   Muspac                           85.90         1,190.20                         Giraldas-Sunuapa         A-0317-M-Campo   Sunuapa                           378.50         974.10                   6         Sureste            Juspi-Teotleco            AE-0057-M-Mezcalapa-07            Juspi,   Teotleco, AR-0470 Campo Arroyo Zanapa            1            2            1            449.95                  143.9                   Juspi-Teotleco         A-0169-M-Campo   Juspi                           28.4         102.4                         Juspi-Teotleco         A-0329-M-Campo   Teotleco                           362.1         1,490.30                   7         Sureste            Lacamango            A-0187-M-Campo   Lacamango            Lacamango            0            1            0            16.26            75.3            95.5                   TOTALS                     5         22            7            4,581.75            4,613.70            9,480.40            635.92             Source:   IHS Markit                                    © 2018 IHS Markit           CNH-A6-7 Asignaciones/2018 Farm Out Bid Round - PEMEX Farm-Out Blocks – A blocks – CNH reported Reserves and Cumulative Production from 1 January 2017            Entitlement or   Farm-Out Block Nomenclature            Entitlement ( A blocks)            OOIP MMbo            OGIP BCFG            Cum_Prod Oil MMbo            Cum_Prod Gas Bcfg            RF Oil to 1/1/2017            RF Gas to 1/1/2017            1P Oil at 1/1/2017            1P Gas at 1/1/2017            Bid Round Remaining   OOIP Mmbo            Bid Round Remaining   OGIP Bcfg             Bacal-Nelash            A-0027-M-Campo   Arroyo Prieto            24.79            60.50            2.45            2.81            10%            5%            1.49            1.40            21.8            57.2             Artesa            A-0029-M-Campo   Artesa            191.41            333.68            53.26            95.09            28%            28%            7.82            8.41            134.2            235.3             Bacal-Nelash            A-0036-2M-Campo   Bacal            230.21            291.83            109.12            153.48            47%            53%            2.06            4.50            120.7            137.9             Bedel-Gasifero            A-0045-M-Campo   Bedel            219.83            99.07            1.80            0.51            1%            1%            9.98            10.04            214.50            113.50             Giraldas-Sunuapa            A-0083-M-Campo   Chiapas-Copano            320.19            2,226.60            142.11            1,396.05            44%            63%            6.70            34.69            177.30            827.50             Cinco   Presidentes            A-0092-M-Campo   Cinco Presidentes            1,043.81            1,006.23            326.42            452.15            31%            45%            11.11            15.45            715.6            551             Giraldas-Sunuapa            A-0099-M-Campo   Comoapa            171.80            215.27            44.15            95.45            26%            44%            2.21            3.62            127.10            118.80             Bedel-Gasifero            A-0122-M-Campo   El Treinta            154.46            242.36            1.07            2.64            1%            1%            25.62            124.82            160.70            212.50             Bedel-Gasifero            A-0140-M-Campo   Gasifero            133.30            384.79            6.73            39.68            5%            10%            12.59            87.81            124.80            323.00             Artesa            A-0141-M-Campo   Gaucho            45.92            136.37            8.93            44.03            19%            32%            0.57            0.52            36.9            92.2             Giraldas-Sunuapa            A-0144-M-Campo   Giraldas            464.59            2,828.60            174.70            1,974.52            38%            70%            2.61            168.55            289.70            840.50             Juspi-Teotleco            A-0169-M-Campo   Juspi            39.98            175.06            11.56            71.99            29%            41%            0.44            3.06            28.4            102.4             Lacamango            A-0187-M-Campo   Lacamango            107.20            147.81            31.45            51.99            29%            35%            2.84            2.01            75.3            95.5             Giraldas-Sunuapa            A-0230-M-Campo   Muspac            163.20            2,720.05            77.01            1,526.71            47%            56%            0.68            8.21            85.90            1,190.20             Bacal-Nelash            A-0235-2M-Campo   Nelash            89.71            171.25            3.35            7.45            4%            4%            5.09            10.93            86.2            162.9             Artesa            A-0236-M-Campo   Nispero            479.46            484.55            153.85            249.57            32%            52%            4.09            8.02            324.5            232.4             Artesa            A-0291-M-Campo   Rio Nuevo            279.90            400.12            86.70            178.46            31%            45%            0.71            2.25            193            220.9             Cinco   Presidentes            A-0292-M-Campo   Rodador            163.06            182.19            45.77            65.80            28%            36%            5.17            6.87            116            114.6             Artesa            A-0312-M-Campo   Sitio Grande            1,152.59            1,837.86            364.70            591.70            32%            32%            0.13            6.49            787.8            1,244.80             Giraldas-Sunuapa            A-0317-M-Campo   Sunuapa            427.75            1,160.25            48.03            170.89            11%            15%            6.96            70.57            378.50            974.10             Juspi-Teotleco            A-0329-M-Campo   Teotleco            393.52            1,614.79            29.59            108.05            8%            7%            9.12            42.53            362.1            1,490.30             Bacal-Nelash            A-0339-2M-Campo   Tiumut            54.69            146.18            1.96            3.12            4%            2%            0.98            2.37            52.7            142.9             GRAND   TOTALS               6,351.39         16,865.42            1,724.71            7,282.14            N/A            N/A            118.97            623.13            4,613.70            9,480.40             ©   2018 IHS Markit                                    Source: IHS Markit","CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round with little change except that there are now 20 companies that have expressed an interest.  There remain 13 companies authorized to pay data base access fees, 10 companies with data base access, and 11 companies that have initiated the prequalification process. "
24228,"PentaNova announced on 21 June 2018 that it has signed a definitive agreement with LATAM Oil & Gas Corp (LATAM) subsidiary, Panacol Oil & Gas, to sell half of it's 80% WI in the SN-9 Block located in the Lower Magdalena Valley under the same terms as the original LoI signed with American Oil. In return, Panacol will fully fund PentaNova's commitments during the first phase of the SN-9 E&P contract for the amount of US$ 22.29 million, subject to ANH approval. The agreement is expected to close within the next 30 days during which time Panacol will be required to place US$3.0 million in escrow to fund near-term activities. Panacol is also required to pay approximately US$ 650,000 in past costs and provide a standby letter of credit for US$ 3.0 million to guarantee further payments into the escrow account. PentaNova will reimburse 50% of the funds invested by Panacol in the Phase I activities from 70% of the proceeds of PentaNova's net production. PentaNova previously reported on 28 September 2017 that it had entered into a Letter of Intent (LoI) with American Oil and Gas (American Oil) to farm-out half it's stake in the SN-9 Block. An assignment agreement was signed in April 2018, between American Oil and LATAM, approved by PenaNova, for the assignment of all rights and obligations as outlined in the LoI to LATAM, which was then reassigned to it's wholly owned subsidiary Panacol. LATAM may itself be a subsidiary of LATAM Energy Corp, a Canadian company focused on Colombia, but without any notable assets to date in the country. PentaNova itself farmed in during January 2017. The remaining interest is held by Mexican company Desarrolladora Oleum SA de CV with 15% WI and Colombian CleanEnergy Resources SA (owned by CEREX SA) with the remaining 5% WI. PentaNova believes that the gas play being developed by Canacol in the neighbouring Esperanza Block extends into the south eastern portion of the SN-9 block, based on 2D seismic and one discovery well, Hechizo-1, drilled in late 1992 to early 1993 that tested a combined rate of 10.3 MMscfg/d. The company has emphasised that this will be the immediate focus of activity. It is planning to acquire 140 sq km of 3D seismic in October-November 2018 and the first exploration well in mid-2019.<P />",PentaNova has agreed to farmout a 40% stake to Panacol in the Sinú 9 block.
18877,"Total E&P USA Inc. and Statoil Gulf of Mexico LLC have completed the acquisition of the deepwater Gulf of Mexico assets they successfully bid for at Cobalt International Energy’s bankruptcy sale that was held on 6 March 2018. The two companies tendered a joint bid of USD 339 million to capture the crown jewel of the Cobalt auction, the North Platte discovery located primarily on Garden Banks block 958 and 959.  Discovered in 2012, this subsalt Wilcox oil accumulation lies in some 4,500 ft (1,372 m) of water approximately 175 miles (280 km) offshore Louisiana. Cobalt successfully appraised its discovery before the bankruptcy, drilling 11 boreholes from three surface locations. Owing to the results of these delineation wells, the former operator estimates the gross recoverable resource range for North Platte at 500 to 650 MMbbl of oil equivalent.  With the completion of the deal, Statoil owns a 40% working interest in the four-block North Platte unit that consists of Garden Banks blocks 915 (G30869), 916 (G30870), 958 (G32460), and 959 (G30876). Three of the four blocks in the unit have expired and are now held by unit operations. A suspension of production has been submitted for the unit and is awaiting government approval. Already a partner in the North Platte project, the acquisition increases Total’s working interest from 40% to 60%. Total takes over as operator as part of the North Platte transaction, which has an effective date of 1 January 2018.  Total also successfully bid on several other Cobalt assets at the bankruptcy auction. Along with North Platte, Total picked up Cobalt’s 20% working interest in Chevron U.S.A. Inc.’s Anchor project, which is another Paleogene-aged, subsalt Wilcox discovery made in 2014 in the Green Canyon area. Total paid USD 181 million for the asset. This new working interest augments Total’s equity position in Anchor to 32.5%, after having obtained the 12.5% stake previously held by Samson Offshore last December.  Anchor lies in some 5,200 feet (1,585 m) of water in the southwest quadrant of the Green Canyon (GC) protraction area, roughly 150 miles (240 km) southwest of the coastal support base at Port Fourchon, Louisiana. The appraisal phase is completed at Anchor. In Chevron's Q3 2017 earnings call of 27 October 2017, Chairman and CEO John Watson said that Anchor remains in the concept development stage and is not yet in front end engineering and design. Cobalt estimates the gross recoverable resource range for Anchor at 330 to 600 MMbbl of oil equivalent.  The Anchor project is covered by a six-block unit consisting of GC blocks 762 (G25198), 763 W/2 (G25199), 806 (G31751), 807 (G31752), 850 (G31757), and 851 (G31758). Like North Platte, the Anchor leases have passed their expected expiration date and are held by unit operations. Chevron filed for a suspension of production in January 2018 intended to hold the leases while a development plan matures. Chevron (55%), Total (32.5%) and Venari Offshore LLC (12.5%) comprise the Anchor ownership group.  Total rounded out its participation in the asset sale taking 13 of Cobalt’s deepwater exploration blocks for USD 25 million.  The US Bankruptcy Court for the Southern District of Texas approved the results of Cobalt’s asset sale on 5 April 2018.",Total E&P USA Inc. and Statoil Gulf of Mexico LLC have completed the acquisition of the deepwater Gulf of Mexico assets they successfully bid for at Cobalt International Energy’s bankruptcy sale that was held on 6 March 2018. 
37394,"Petrofac is understood looking to dilute its 30% in PM-304, 684 sq km offshore Terengganu, Peninsular Malaysia, containing the producing Cendor + Desaru W. fields and developing Irama field. Petrofac (op), partners Petronas, Kufpec + PVEP.","Petrofac is understood looking to dilute its 30% in PM-304, 684 sq km offshore Terengganu, Peninsular Malaysia, containing the producing Cendor + Desaru W. fields and developing Irama field. Petrofac (op), partners Petronas, Kufpec + PVEP."
19250,"Ardent Oil is farming out interest in licence 12/16 (blocks 5605/11a, 5605/12, 5605/15a and 5605/16a) containing the Astrild prospect. The licence was awarded in the 7th Danish Licensing Round in April 2016. Ardent has a work programme spread over six years consisting of four phases. Phase 1 (2016-2018) requires data reprocessing, inversion and technical studies to be undertaken followed by a drill or drop decision. Phase 2 (2019) will involve drilling a well to evaluate the Triassic targets while phase 3 consists of committing to a second exploration well or to relinquish the licence. Phase 4 will involve drilling the second exploration well. Astrild has been defined on a PGS 3D Danish megamerge survey (11,180 sq km) composed of pre-stack merged 3D volumes of various vintages. Ardent also has reprocessed legacy 2D data. A total of 29 wells were used during the technical analyses.   Astrild is a large, untested four way dip closed structure trapping the Triassic Skagerrak and Rhaetic Formations which are composed of high porosity reservoir sands. The sands were deposited in alluvial fans and plains in a moderate energy environment. Lower Keuper Shales and Lower Salt form the principle seals for the Skagerrak reservoirs and Lower Jurassic claystones seal the Rhaetic reservoirs. Marine shales within the Lower Namurian and Dinantian stratigraphy likely source the reservoirs. The Permian Kupfershiefer source rock acts as a potential secondary source. The prospect area is mapped between 35 sq km (Skagerrak) and 42 sq km (Rhaetic). The key risk associated with Astrild is the presence of a source rock creating sufficient volumes of hydrocarbons.    Interest in 12/16 is held by Ardent Oil (Denmark) SA (80% + operator) and Danish North Sea Fund (20%).     For further information please contact:  Peter Browning-Stamp  Peter.Browning-Stamp@ardentoil.com","Ardent Oil is farming out interest in licence 12/16 (blocks 5605/11a, 5605/12, 5605/15a and 5605/16a) containing the Astrild prospect. "
82711,"On 9 June 2020 the NPD confirmed that CapeOmega has transferred its 21.8% interest in PL 048 D to Petrolia NOCO (effective from 28 May 2020). PL 048 D covers a 6 km area of block 15/5 and contains the easterly extension of the cross-border (UK) Enoch field. The unitised equity in Enoch which Petrolia now holds is 4.36%.  CapeOmega gained its interest in PL 048 D from Noreco in 2016.   Enoch lies mostly (80%) in UK waters and has a Paleocene Forties Sandstone reservoir at a depth of approximately 2,100 m. It came onstream in May 2007 as a subsea tie back to the Brae A platform located 15 km to the northwest. The field is now in its tail-end phase and is expected to be shut-down at the end of 2022.  Following completion of the deal, interest in PL 048 D is held by Equinor Energy AS (58.9% + operator), Petrolia NOCO AS (21.8%), Aker BP ASA (10%) and DNO Norge AS (9.3%).","(Viking Graben Province) PL 048 op. by EQUINOR (78%), KPC (22%) CapeOmega assigned its 21,8% stake in Enoch Field licence PL 048 D to Petrolia NOCO. Following completion of the deal, interest in PL 048 D is held by Equinor 58.9% + op., Petrolia NOCO 21.8%, Aker BP 10% and DNO9.3%."
80814,"On 18 May 2020, KL news confirms a company deal in which Petronas subsidiary, Petronas Suriname Exploration and Production B.V. (PSEPBV) completed a 50% interest farm-down to ExxonMobil Exploration and Production Suriname B.V. (EEPS). Located approximately 120 km off the coast of Suriname in water depths ranging from some 50 m to 1,000m, Block 52 covers 4,749 sq km and is considered to have potential in the Upper Cretaceous. Along with new 3D seismic, the high impact Sloanea 1 new-field wildcat (NFW) well is planned for a Q3 2020 spud date. Block 52 is adjacent to Block 58 where Apache and partner Total are drilling the Kwaskwasi 1 NFW targeting Campanian and Santonian objectives that are independent from Q1 2020 Sapakara West 1 and Maka Central 1 discoveries on the acreage. Petronas is Apache's partner in Block 53 where both the Popokai 1 and Kolibrie 1 were abandoned with oil shows in 2015 and 2017, respectively. PSEPBV also operates Block 48, which remains undrilled.  Background information   On 26 April 2013, Staatsolie signed a Production Sharing Contract (PSC) with Malaysia’s Petronas for Block 52. Petronas will invest USD 25 million on the block, conducting 3D seismic and drilling at least one exploration well. Block 52 covers 4,743 sq km and is considered to have high-impact potential in the Upper Createcous. Under the 30-year contract, should the Malaysian company develop a commercial discovery on the acreage, Staatsolie would have the option to participate with a 20% stake.   With this deal, Petronas becomes anther new entrant in the deepwater frontier acreage. It follows Apache that was awarded a PSC for Block 53 in October 2012 and Chevron’s June 2012 signing for a 50% WI in nearby Blocks 42 and 45.   Nearby, Staatsoile offered four blocks in the Offshore Demerara Plateau - Blocks 54 (8,824 sq km), Block 55 (7,765 sq km), Block 56 (5,704 sq km) and Block 57 (5,527 sq km). Closing date for bids was 26 July 2013. Data packages became available on 8 October 2012 and include some 5,000km 2D Broadseis seismic data acquired in December 2011. Respective 2D acquisitions for each block are 1,350km in Block 54, 1,073km in Block 55, 938km in Block 56 and 1,018km in Block 57. The Demerara Plataea is a prominent submarine plateau located off the coasts of Suriname and French Guiana. Water depths of the blocks on offer range between 200m to 3000m.","ExxonMobil has acquired a 50% stake from Petronas in block 52, 4,861 sq km in WD 50-1,100m, Guyana-Suriname Basin. Sloanea-1 nfw is planned here, target U. Cretaceous, 2-3 month well, semi sought. So far Petronas (op), partner Wintershall Dea. Staatsolie has a 20% back-in right in the event of a commercial find."
29705,"KG-OSN-2009/3 shallow-water block in KG Basin, multiple reservoirs between 3,351-3,944m, gas flowed from 3,610-3,715m on test, appraisal drilling required to determine commerciality. West Telesto JU.","India (Krishna-Godavari B.) ? op. by VEDANTA R (90.9090909091%, VEDANTA R 9.09090909091%) in KG-OSN-2009/3 block"
16998,"In late February 2018, Tiba Petroleum Co (TIPETCO) temporary abandoned the JD C3-1 (Hj 035-6) exploration well in the Abu El Gharadiq (Dev) JD block.   The well was spudded on 30 January 2018 using the L/R “EDC-72”. It has a planned TD of 2,675 m and objectives in the Lower Bahariya and Kharita members.  Tiba Petroleum Co (TIPETCO) is a JV between Egyptian General Petroleum Co, Shell Austria AG, Apache Oil Egypt and Sinopec.",Egypt (Abu Gharadiq B.) Abu El Gharadiq
48623,"Yinggehai Basin, WD 65m, ops terminated 13 May ’19, Nanhai 4 JU. Target Plio-Miocene sands.","Dongfang 4-1-1 (DF 4-1-1) nfw Yinggehai Basin, WD 65m, ops terminated 13 May ’19, Target Plio-Miocene sands."
17791,"On 29 March 2018, the consortium of Shell with 40% working interest, Chevron with 40%, and Petrogal with 20%, was granted a preliminary award for the C-M-791 block in the offshore Campos Basin through the ANP Round 15.    For the C-M-791 block the consortium offered a bonus of USD 166.50 million and 1,203 work units.  There were two other bids for the block.  The consortium of BP, Statoil, and Total offered a bonus of USD 160.1 million and 204 work units while the third place bid was from the consortium of ExxonMobil, Petrobras, and QPI who offered a bonus of USD 124.62 million and 200 work units.","the consortium of Shell with 40% working interest, Chevron with 40%, and Petrogal with 20%, was granted a preliminary award for the C-M-791 block in the offshore Campos Basin through the ANP Round 15."
24457,"On 28 June 2018 Neptune Energy Group announced that it has agreed to acquire 100% of the shares of VNG Norge AS (which holds interests in Norway and Denmark – see separate article for details on Norway) with effect from 1 January 2018. The acquisition will increase Neptune’s production by approximately 4,000 boe/d and its net reserves/resources by over 50 MMboe (based on 2017 figures). In Denmark, the company – through VNG Danmark - is partner in the 4/98 Solsort and 3/09 licences which contain the Solsort field. Approval for the acquisition is required from the Supervisory Board of VNG AG and from the relevant authorities. Completion is expected in Q4 2018.  VNG reported in January 2018 that it was assessing options for the future of its oil and gas business in Norway and Denmark. The company said that it saw long term value creation in the sector but was looking for a strategic partner to aid future growth. Reports in the press indicated that VNG would sell a majority stake in the subsidiary and that this sale could be valued at up to USD 500 million.  The Solsort field was discovered in 2010 by exploration well Solsort-1 (5604/26-5) which found oil in the Paleogene. The find was appraised in 2013 and oil and gas was tested from the Paleocene. The field lies in the Central Graben immediately east of the Svend field and northeast of the South Arne field, both of which are producing Chalk oil fields.  Interest in the 3/09 and 4/98 Solsort licences is held by INEOS E&P A/S (35% + operator), Bayerngas Danmark ApS, Danish North Sea Fund (20%) and VNG Danmark ApS (15%).","Neptune Energy has agreed to the acquisition of VNG Danmark, providing Neptune with interests in assets such as the Greater Njord Area / hub, Fenja, the Utsira High area, and Ivar Aasen. and Solsort devt project."
63844,"1st well in PL 782 S, NW of Balder in Central Viking Graben, WD 125m, TD 4,705m (Heather fm), encountered 2 separate gas/cond + oil-bearing intvs totalling 25m in the Draupne fm, no hc/water contact, 1-10 MMcum recoverable oil equivalent, Leiv Eiriksson SS. COP (op), partners Aker BP, Wintershall Dea + Equinor.","025/07-07 (Busta) expl. (COP op, Aker BP, Wintershall Dea, Equinor) 1st well in PL 782 S, NW of Balder, small discovery, encountered 2 separate gas/cond + oil-bearing intvs totalling 25m in the Draupne fm, no hc/water contact, 6-60 Mmboe recoverable, WD=125m, TD=4705m (Heather fm)."
55739,"Medco agreed to acquire 100% interest in the North Sokang PSC, located in the East Natuna Sea, from previous operator Black Platinum Energy, on 23 July 2019. The deal is subject to government approval.  This acquisition will expand Medco’s acreage East Natuna, which also includes the South Sokang PSC and a part of the South Natuna Sea Block B PSC. In early August 2019, the company reported plans to conduct exploration activities in the area in 2019/2020.  The North Sokang PSC includes the Dara 1 gas discovery. Black Platinum was previously planning to drill up to two wells to appraise the discovery, subject to finding a farm-in partner. As of March 2018, the discovery was estimated to contain in-place resources of 1,495 Bcfg.  A major risk associated with exploration in the area is the high CO2 content in the gas, however the shallower reservoirs (above 800 m) have been found to contain low contamination.  According to a Preliminary Plan of Development released by Black Platinum in 2018, potential commercial scenarios for future gas production from the Dara field include the domestic market via a Floating LNG (FLNG) facility or a new-build pipeline to Natuna island. Another option under consideration was sale to Singapore via the West Natuna Transportation System.  Background Information  On 22 September 1997, the North Sokang block, with an area of 10,260 sq km, was awarded to Total after a period of direct negotiations and upon payment of bonuses of USD 1.25 million. The PSC carried a firm Work Obligation of USD 24.8 million in the first three years and USD 64 million in 10 years. Prior to Total, the block was part of the South Natuna Sea Block B, awarded to Conoco in 1968. Only two wells had been drilled within the block limits at that time, both on its southern margin by Conoco in 1974 and 1975. The first, Antoni 1, was abandoned as a sub-commercial gas discovery but the second, Teri 1, flowed 7.2 MMcf/d. It is believed that the gas in both wells contained a high CO2 ratio.  Total completed a 67 km 2D seismic survey over the block in August 1998 following the completion of an earlier 3D programme in July 1998. In 2000, Total conducted a two-well drilling campaign with Dara 1 and Dara 2. Both wells encountered gas which was deemed non-commercial due to the high CO2 content. Total relinquished the block in September 2001.  The North Sokang block was again offered on 20 May 2010 as part of the First Petroleum Bidding Round 2010 under the direct offer mechanism. The block covered an area of 5,466 sq km in shelf waters, with maximum depths of around 130 m. The block was officially awarded on 26 November 2010. Firm commitments for the first three years of exploration included G&G studies (USD 0.70 million), 800 km 2D seismic acquisition (USD 1.5 million) and drilling of one exploration well (USD 8.0 million).  Dara exploration history  Dara 1 was plugged and abandoned on 12 May 2000 by Total as a non-commercial gas discovery with 12-88% CO2. About 25.5m of net gas pay was encountered and it targeted Upper Miocene deltaic sands. The well was spudded on 19 March 2000 and was drilled to a TD of 2,375m, short of the PTD at 3,036 m.   Dara 2, located 25 km west of Dara 1, was abandoned by Total on 17 June 2000 with non-commercial gas volumes encountered. Gas is believed to have contained 70-80% CO2. The well was spudded on 15 May 2000 and was drilled to a TD of 1,500 targeting Pliocene deltaic sands.  Black Platinum’s first well Dara 3 well was a successful gas appraisal well drilled in the block during 2012. The well was plugged and abandoned in late November 2012. The well intersected 18m of net gas pay and tested 9 MMcfg/d, with 1.9% CO2 and no water, from stacked Upper Pliocene deltaic sandstones of the Muda Formation. Bypassed gas was targeted from these sands, which could have thicknesses of 1 to 10 m each, and Dara 3 has proven the viability of this play, with low CO2, in the area. Dara 3, located within the vicinity of the Dara 1 discovery well, was spudded on or around 31 October 2012 and was drilled to a TD of 970 m, slightly deeper than the PTD of 960 m, using the using the Diamond Offshore “Ocean General” S/S. It is the second of two planned appraisal well campaign in the block, immediately following the Dara 4 well.   Dara 4 appraisal well was plugged and abandoned in late October 2012. Net gas pay of 5 m was encountered from the primary Pliocene sand objective but it was likely non-commercial as no DST was conducted. A gas sample with 1.3% CO2 was recovered from one of the Pliocene sand units. The well, located 2.7km southeast of the Dara 2 appraisal and 18km west of the Dara 1 gas discovery, was spudded on or around 11 October 2012 and was drilled to a TD of 770 m. It had a PTD of around 740 m and had similar targets as with the Dara 3 appraisal well. Dara 4 fulfilled the firm one well drilling commitment for the block.  Dara is a large four-way dip structure. The Dara 2 and Dara 4 wells were drilled in the central part of the structure, while Dara 1 and Dara 3 were drilled in the eastern part.","Medco agreed to acquire 100% interest in the North Sokang PSC, located in the East Natuna Sea, from previous operator Black Platinum Energy,"
25275,"Jawa Bagian Barat (JBB) PPC, in West Java, o&g discovery mid-Jul ’18, DST2 flowed 3 MMcf/d, DST3  6 MMcfg/d, and 1,320 bo/d from DST 4  in the U. + L. Cibulakan groups.","Jawa Bagian Barat (JBB) PPC, in West Java, o&g discovery mid-Jul ’18, DST2 flowed 3 MMcf/d, DST3  6 MMcfg/d, and 1,320 bo/d from DST 4  in the U. + L. Cibulakan groups."
66220,"According to local reports in early-December 2019, state company YPF has completed Al Sur del Lago 1 new-field wildcat (NFW) well as an oil and gas discovery from the Vaca Muerta Formation on its 100%-held Loma La Lata-Sierra Barrosa block in October 2019. The well flowed 408.8 bo/d and 303 Mscf/d with 208 b/c of water during production testing between the interval of 2,333 to 4,269 m (7,654 to 14,006 ft) in August and September 2019, after it was re-entered in early-August 2019. The well was previously suspended in late-May 2019 at the total depth (TD) of 4,315 m (14,157 ft) after it was initially spudded in April 2019 with planned total depth (PTD) of 4,297 m (14,098 ft).    Loma La Lata-Sierra Barrosa block covers 1,661 sq km of land in the Neuquen Embayment and Huincul Uplift parts of Neuquen Basin.  The block is situated directly next to YPF and Chevron’s Loma Campana block, where the best Vaca Muerta oil producer field of the same name is located with average producing rate of 10 Mbo/d in 2018.  Background Information  Loma La Lata field was the best producing conventional field in Argentina in 2018 with average production rate of 28.9 Mbo/d and 352 Mmscfg/d.","Al Sur del Lago 1 nfw. Loma La Lata-Sierra Barrosa block, tested 409 bo/d + 303 Mcfg/d + water from between 2333-4269m (Vaca Muerta). TD=4315m."
27702,"BT-PN-004 contract, PN-T-048 block 2, P&A assumed dry early Aug ’18.  PTD was 1,510, targets believed Cabeças + Poti fm’s.","4-PGN-FAZHAVANA-002D-MA (4-PGN-026D-MA) (PGN (Parnaiba Gas Natural 100%) in the PN-T-048 Block 2. P&A, dry."
53620,"NW part of CNH-R01-L04-A2.CPP/2016, Area 2, DW GoM Perdido area, WD 3,275m, PTD 7,000m, ops terminated in May but results hitherto unreported, discovered an oil structure of ca. 916 MMbbl (a bit less than half of pre-drill estimates), Rowan Renaissance DS. Total (op), partner ExxonMobil.","Total plugged and abandoned dry the Etzil 1SON new-field wildcat (NFW) stratigraphic test in the CNH-R01-L04-A2.CPP/2016, Area 2 - Perdido block during mid-May 2019. "
80178,"Sinopec – Xibei achieved oil and gas flow in an appraisal well in Shunbei field in the Tarim Basin on 7 May 2020. Shunbei 71X, drilled in Shunbei 7 fault belt, tested 2,628 b/d of oil and 882 Mcf/d of gas. The success of the well indicated 560 MMbbl of oil geological resource in the field.   In late March 2020 Sinopec achieved oil and gas flow at Shunbei 52A, drilled in Shunbei 5 discovery area, tested 2,428 b/d of oil and 2.3 MMcf/d of gas. The well has a TD of 8,137 m. The success of the well further confirmed reserves in this part of the field.   Sinopec accelerate development at Shunbei field, the company has built up a production capacity of 18,000 b/d of oil and 33 MMcf/d of gas by April 2020.   Background Information  In 2015 Sinopec made discovery of Shunbei in the Shutuoguole North block when Shunbei 1 tested 45.4 Mscfg/d from an interval between 7,269 and 7,407 m in the Ordovician. Following the discovery Sinopec made success in Shunbei 1-1H, the well tested 887 b/d of oil and 911 Mcf/d of gas through a 4 mm choke in the Ordovician.   Sinopec reported in 2016 that Shunbei field, a large commercial field, has been confirmed. Sinopec started development of Shunbei 1 in early 2016 and planned to build Shunbei block with production capacity of 30,000 b/d of oil by 2020.   During 2016 Sinopec has put seven producers on stream, with production capacity of 3,700 b/d of oil.   In November 2017, Sinopec set a revised field development plan on Shunbei 1 area of the Shunbei field to build up a 20,000 b/d of oil and 26 MMcf/d of gas production capacity by 2020. In 2017 Sinopec produced at a rate of 6,000 b/d of oil.  By end 2017 Shunbei field has been approved nearly 100 MMbbl of oil and 260 Bcf of gas in place reserves.   In 2017 Sinopec tested oil and gas in Shunbei 5. In 2018 Sinopec achieved success in an appraisal well, Shunbei 501, which tested 2,087 b/d of oil and 1.52 MMcf/d of gas. The success of the well makes field extension southwards.   In 2018, with Shunbei 5 discovery developed, Sinopec produced 520K tons of oil from the field. The company had target to reach annual production of 1 million tons of oil in 2019 and planned to reach 2 million tons of oil (40,000 b/d) by 2023.   In 2018 Sinopec added additional 350 MMbbls of oil and 500 Bcf of gas in place in Shunbei 1 and Shunbei 5 areas in the field.   In 2019 Sinopec produced 750k tons of oil in the field and planned to reach 1.25 million tons in 2020.   By 2019 Shunbei field has been approved total 450 MMbbl of oil and 780 Bcf of gas in place reserves.","Sinopec – Xibei achieved oil and gas flow in an appraisal well in Shunbei field in the Tarim Basin on 7 May 2020. Shunbei 71X, drilled in Shunbei 7 fault belt, tested 2,628 b/d of oil and 882 Mcf/d of gas. The success of the well indicated 560 MMbbl of oil geological resource in the field."
76948,"Accumulate Energy (a 100% owned subsidiary of 88 Energy) announced on 7 April 2020 that the Charlie 1 (API 502232003300) exploration well in state lease ADL 393380 (Sec 21, T4NR9E, Umiat Meridian) on the North Slope of Alaska discovered gas condensate in the Torok formation in both the Middle and Lower Stellar targets. The well reached total depth of 11,112 ft (3,387 m) on 30 March 2020. At that time, the company stated that logging while drilling results were largely consistent with the nearby Malguk 1 exploration well. Charlie 1 will now be plugged and abandoned.  While no flow tests were undertaken, mainly due to time constraints given the length of the remaining season, gas condensate samples were retrieved from the Torok formation at 10,506 ft (3,202 m) and 10,656 ft (3,248 m). A water sample was retrieved from the Indigo target in the Schrader Bluff formation. An attempt was made to sample the Lower Lima target in the Seabee formation, but was unsuccessful due to insufficient reservoir quality. Mud gas observed while drilling the Seabee, which was the formation where ""live oil"" was observed across the shakers in Malguk 1, indicated the hydrocarbons there are heavier than in the Torok. Logs and sidewall cores were acquired over the HRZ formation, which remains a viable target according to the company.  The well was spud on 2 March 2020 using Rig-3 from Nordic-Callista Services. The drilling permit was approved on 10 February 2020 by the Alaska Oil and Gas Conservation Commission (AOGCC). The company received approval on 22 November 2019 from the Alaska Department of Natural Resources (ADNR) for its Lease Plan of Operations, which was submitted on 8 August 2019.  Charlie 1 targeted the Upper Cretaceous age Schrader Bluff, Seabee and Torok formations. It was designed as a step out appraisal to the Malguk 1 well drilled by BP in 1991. Malguk 1 encountered oil shows but was not tested at the time due to operational complications. With revised petrophysical analysis and 3D seismic acquired in 2018, Accumulate identified what it considered to be bypassed pay in Malguk 1. Charlie 1 was positioned to intersect four bypassed zones from Malguk 1 in addition to three other prospective zones. Gross, unrisked mean prospective resources were estimated at 1.6 Bbo.  In a 23 August 2019 press release, 88 Energy announced it had concluded a farmout agreement with Premier Oil. Under the terms of the agreement, Premier will fully fund Charlie 1 up to USD 23 million in return for acquiring a 60% in Icewine Area A. Accumulate will retain 30% working interest with the remaining 10% held by Burgundy Xploration. At the conclusion of the work program, Premier will have the option to assume operatorship of Icewine Area A. The company will have the additional option to obtain 50% working interest in Areas B and C for USD 15 million if the well is successful. Following the results of Charlie 1, Premier informed the joint venture that it intends to withdraw from the project since the well did not meet its pre-drill expectations  The 1,440 ac (5.83 sq km) ADL 393380 contract (block NS-0291B) was preliminarily awarded for a bonus bid of USD 37,771.20 at sale NS2016W held on 14 December 2016 and officially awarded on 7 July 2017 to Accumulate Energy (77.55%) and Burgundy Xploration (22.45%).","United States, 248"
85143,"Saudi Aramco signed a preliminary agreement with Royal Dutch Shell to jointly pursue both international and domestic gas opportunities on 8 March 2018. The Memorandum of Understanding (MoU) was signed in London during the official state visit of Saudi Crown Prince Mohammed bin Salman. It includes provision for both upstream and gas liquefaction projects. Shell Chief Executive Officer (CEO) Ben van Beurden informed reporters following the associated ceremony that it was “a discussion that began some time ago and now we have signed a memorandum to work on gas projects from upstream to downstream across the world and in Saudi Arabia, concrete projects would be announced in due course”.  In recent years, under the leadership of Minister of Energy, Industry and Mineral Resources Khalid Al-Falih and the Supreme Council of the Saudi Arabian Oil Company (established in 2015), Saudi Arabia has significantly transformed its strategic approach to gas, recognising its critical role in determining a balanced energy future for the country.",Saudi Aramco signed a preliminary agreement with Royal Dutch Shell to jointly pursue both international and domestic gas opportunities on 8 March 2018. The Memorandum of Understanding (MoU) was signed in London during the official state visit of Saudi Crown Prince Mohammed bin Salman.
55980,"4th in 4-well campaign, Padaukpin oilfield area in MOGE-3, Central Burma Basin, ops terminated Jul ’19 at TD ca. 2,000m, possible gas indications and mud loss during drilling, formation-tested. Targets L. Miocene Pyawbwe, L. Oligocene Padaung + U. Oligocene Okhmintaung fm’s. PTTEP (op), partners Palang Sophon, MOECO + Win Precious Res.","Pyae Sone Kywal 1 (PTTEP 77,5% op, Palang Sophon 10%, MOECO 10%, Win Precious 2,5%) in onshore block MOGE-3, It is understood that the well encountered possible gas indications and mud loss during drilling. Results of the well are to be confirmed."
24751,"Equinor has agreed to acquire Barra’s 10% in the BM-S-008 licence in the Santos Basin for USD 379 MM, thus enabling Equinor and partners to better align interests across the 2 licences for the Carcará area (BM-S-008 and Carcará North). Upon closing, Equinor intends to sell 3.5% to ExxonMobil and 3% to Galp, so fully aligning interests across BM-S-008 and Carcará North (Equinor 40%, Exxon 40%, Galp 2’%). Equinor operates both and plans to deliver 1st oil between in 2023-24. Map extract below courtesy Equinor.","Equinor has upped (->46,5%) its stake in the BS-S-8 block - part of the Carcara area after buying out minority stakeholder Barra Energia for US$379 MM."
66951,"On 11 December 2019, the Federal Agency for Subsoil Use held an auction for two blocks in Udmurtia Republic (Volga-Ural Province). Lukoil and Udmurtneft (Rosneft/Sinopec) emerged as the winners.  Results of the action as follows:  The Pyzepskiy Yuzhnyy block covers 61.7 sq km and encompasses the Pyzherskoye Yuzhnoye field with 3P reserves estimated at 4.7 MMbbl of oil. Oil resources (category D1) of the block are estimated at 2 MMbbl. The starting price amounted to RUB 107.4 million (USD 1.65 million). Lukoil-Perm offered RUB 236.28 million (USD 3.63 million). The winner of the auction will obtain a 25-year E&P license.  The Kacheshurskiy block covers 115 sq km and encompasses the Kacheshurskaya and Menilskaya Severnaya prospects with combined oil resources estimated at 3.6 MMbbl. Oil resources (category D1) of the block are estimated at 5 MMbbl. The starting price amounted to RUB 8.7 million (USD 0.13 million). Udmurtneft offered RUB 66.12 million (USD 0.99 million). The winner of the auction will obtain a 25-year E&P license.",Lukoil-Perm won Pyzepskiy Yuzhnyy block (62km²) and Udmurtneft (Rosneft/Sinopec) won Kacheshurskiy block (115km²).
15184,"On 15 February 2018, it was announced that Neptune Energy Group completed the takeover of Engie E&P International SA. Neptune will thus become an independent E&P company active in the North Sea, North Africa and South East Asia. In Algeria, Engie operates the Touat gas development which is due to come on stream in the first quarter of 2018. The Touat gas project is developed by the Groupement Touat led by Engie. It is a cluster development of 9 fields that entails the drilling of 40 development wells in total (25 to first gas) and the construction of associated infrastructure at the cost of around USD 2 billion. The project taps 2,800 Bcf of gas reserves and was initially due to come on stream in 2014. Plateau production rate is expected to be around 435 MMcf/d of gas.   ",Algeria (Sbaa Sub-basin (Timimoun B.)) Touat
56084,"PEDL 183 in Yorkshire, S. of 2013 discovery, TD 2,061m, test equipment arriving on site today, 4-8 week ops evaluating the Kirkham Abbey reservoir (65m net intv). Permissions in place for construction of the West Newton B site + drilling-testing of 2 more wells. Rathlin (op), partners Humber O&G + UJO.","United Kingdom, PEDL 183"
31083,"Lundin has agreed to acquire Equinor’s 15% in PL 359, home to the Luno II oil find, which will bring Lundin’s interest to 65%, in alignment with Edvard Grieg nearby. The cash deal will be accompanied by Lundin transferring its 20% in PL 825 (Rungne) to Equinor. Effective date of the transaction will be 1 Jan ‘18 subject to usual approvals. PL 359 partners are currently Lundin (op) 50%, OMV 20%, Equinor + Wintershall 15% each.","Lundin (->65%, OMV 20%, Wintershall 15%) has agreed to acquire Equinor’s 15% in PL 359, home to the Luno II oil find. The cash deal will be accompanied by Lundin transferring its 20% in PL 825 (Rungne) to Equinor. "
63622,"On 30 October 2019, two state-run agencies, the Egyptian National Petroleum for Exploration and Development Company (ENPEDCO) and the Egyptian General Petroleum Corporation (EGPC) were granted two exploration licences by Egyptian Authorities to jointly explore the Abu Sennan and Ras Qattara areas, in the Western Desert. The decree signed by the Egyptian Authorities is related to an agreement inked by each party in early September 2019, which stipulates that the two state-run agencies are committed to drill four exploratory wells for a minimum investment of USD 4 million.  The South East Abu Sennan licence extends over 1,009 sq km, mainly in the Abu Gharadiq Basin. It includes one oil field, El Diyur South West, and 7 dry exploratory wells. El Diyur South West was discovered in 2005 by Apache and is currently operated from a distinct production acreage by DIPETCO.  The South East Ras Qattara licence is divided in three areas, totaling 2,994 sq km. The western area mainly extends across the Northern Egypt and Abu Gharadiq basins and comprises 7 fields (among which 5 are operated from distinct production acreages) and 11 dry exploratory wells. The eastern area mainly extends in the Gindi Basin. It includes the Qarun field, five discoveries and about 15 dry exploratory wells. Qarun was discovered in 1994 by Apache and is currently operated from a distinct production acreage by Qarun Petroleum. The last area (central), which also extends in the Gindi Basin only includes 5 dry exploratory wells.","Egypt, Abu Gharadiq (Dev)"
58689,"On 20 August 2019, MND a.s. was granted the Nasedlovice mining plot in southeastern part of the country, within the Slopes of Bohemian Massif permit. It is understood that the contract, coordinates of which have yet to be disclosed, is related to area of the Nasedlovice 2 well (Nasedlovice field).  The surface area of the license is less than 1 sq km. The Nasedlovice 2 well is situated approximately 25 km southeast of the city of Brno, within the Carpathian Flysch Zone.  Background Information  New-field wildcat Nasedlovice 2 was drilled during September-November 2015. The well, targeting the Palaeogene (Eocene?) series, was drilled to the final depth of 3,550 m and, in early December, the operator tested the autochthonous Paleogene series over the interval 3,258-3,288 m.  The well was completed for production in late 2015/early 2016. It is understood, MND commenced production from the Nasedlovice 2 well in May/June 2018 (test production mode?).  The 1,640 sq km Svahy Ceskeho masivu block (Slopes of Bohemian Massif) was granted to MND as sole rightholder on 30 June 2004. It was granted for a 15-year term, until 30 June 2019.","MND a.s. was granted the Nasedlovice mining plot in southeastern part of the country, within the Slopes of Bohemian Massif permit."
55702,"Kina Petroleum Corp is offering an opportunity for a farm-in partner to acquire equity in its wholly owned exploration licence PPL 340, located in the onshore Papuan Basin. Kina first considered the offer in 2013, estimating approximately 35% interest would be available. Farm-in conditions and equity level were assessed post processing and interpreted of aeromagnetic and gravity survey data (acquired in 2013/14) which provided more information on the mid-Miocene reef units present within the licence.   Kina has reported that an exploration well in the permit would likely first test the Port Moresby Prospect once newly acquired seismic data further defines the prospect. The Port Moresby Prospect lies in the south-west of the permit and is a platform carbonate shelf target which has been identified as an aerogravity high.  If hydrocarbons are present, it is estimated that prospective resources could be in the region of 660 Bcf gas (best estimate). However, required seismic in PPL 340 would be in the order of USD 30,000 / km, making delineation of large area closure prospects uneconomical.  In 2H 2018 Kina carried out a soil gas geochemical survey over the Lizard Prospect, located in the northwest of the permit. The survey was designed to provide an economic method of better defining the prospect. Kina is now planning a second phase of sampling in August 2019 to confirm the initial results before possibly running a seismic survey to confirm structural closure. Lizard is a shallow structure at approximately 650 m depth within the Upper Miocene. Kina understands that the Plio-Pliocene uplift and tilting caused regional drainage to the east, into Lizard.     In March 2017 the licence was renewed for a further five years and it will now expire, or be eligible for further renewal, on 31 March 2022.  Kina is planning to undertake further gravity/gradiometry surveying and seismic acquisition in the first four years of validity, before a possible well between March 2021 and March 2022. A standalone seismic survey has been considered too expensive by Kina in relation to the risk weighted analysis of the Lizard Prospect.  In a previous farm in offer with Hunt Energy in 2013, Hunt agreed to fund a work programme, including an aeromagnetic and gravity survey and 2D seismic acquisition, based on the results of the aeromagnetic survey. On November 2013 Kina reported that the farm-out agreement had been terminated prior to seismic acquisition and the option to drill an exploration well for Hunt to acquire additional interest. Since the termination of the agreement, Kina has removed the commitment to drill an exploration well within the current licence validity period.  PPL 340 covers an area of 4,320 sq km across five blocks and was awarded in 2010.  Kina Petroleum Corp currently holds 100% interest and operatorship of the licence. A five-year licence extension has been submitted which was approved in early 2017.   Companies interested in pursuing this opportunity should contact:   Richard Schroder – Kina MD  Email: richard.schroder@kinapetroleum.com","Kina Petroleum Corp is offering an opportunity for a farm-in partner to acquire equity in its wholly owned exploration licence PPL 340, located in the onshore Papuan Basin. Kina first considered the offer in 2013, estimating approximately 35% interest would be available"
62680,"A renewed auction is planned 16 Dec '19 for 25-year rights to the Ilinskiy block, 377 sq km in the Rostov Oblast, applications by 22 November. The block has already recently been offered but without success. Starting price USD 4,100. Contact: Yugnedra, yugnedra@rosnedra.gov.ru.","Russia, not found"
84229,"Jadestone Energy reported on 29 June 2020 that it has signed an agreement with Mandala Energy to acquire the latter's 90% operating interest in Lemang PSC, located onshore in South Sumatra. The deal will involve an initial amount of USD 12 million in cash and a further USD 5 million to be paid upon first gas onstream, plus other contingent payments amounting to USD 26.7 million in the event of positive outcome.  The deal is subject to approval from the Government of Indonesia and Jadestone hopes to close by Q1 2021, upon which Jadestone will hold 90% operating interest and PT Hexindo Gemilang (a subsidiary of Eneco Energy) will retain the remaining 10% participating interest (PI). The regional government has the right to acquire 10% PI of the PSC according to the Ministerial Regulation No. 37/ 2016.  The PSC contains the Akatara field which ceased oil production in December 2019 after reaching the economic threshold for oil production.   The Akatara field was brought onstream in November 2016. As of late 2018, the field was producing over 1,000 bo/d. Mandala was planning to conduct further development activities, such as artificial lift, to increase production to 2,000 bo/d. Gas from the field has not been commercially produced, however Mandala was previously in negotiations to supply 25 MMcfg/d to PT PGN.  Background Information  The Lemang PSC was officially awarded on 18 January 2007 to PT Hexindo Gelimang Jaya (a majority-owned subsidiary of Ramba Energy) (59%) and PT Indelberg Indonesia (41%). Firm commitments included 500 km 2D seismic acquisition, 500 sq km 3D seismic acquisition and drilling of four wells. The 2D seismic acquisition commitment was fulfilled in early June 2012 with the completion of a 550 km 2D seismic survey. This survey commenced in late September 2011 and was conducted by Quest Geophysical Asia.  Ramba Energy completed the acquisition of 41% participating interest in the PSC from Indelberg in November 2010. In late 2011, a new joint operating agreement was reached by which Eastwin Global Investments entered the block with a 49% interest, and the remaining 51% stakes were consolidated into Hexindo.  In late April 2014, Ramba Energy announced that it has commenced a process to farm-out its stake in the PSC.  In October 2015, Ramba and Mandala Energy signed a farm-out agreement by which Mandala earned a 35% interest in the block for a total investment of up to USD 179.6 million. The deal was completed in February 2016. Along with the farm-out to Mandala, Hexindo acquired a 15% interest from the other PSC partner Eastwin Global Investment such that the net effect of the agreement resulted in Mandala, Hexindo and Eastwin holding 35%, 31% and 34% stake respectively in the block.  On 1 October 2018, Mandala exercised the option to acquire the additional 6% interest from Eneco Energy (formerly Ramba Energy). The option was part of the original farm-out deal signed in September 2017, by which Mandala initially acquired a 15% interest from Hexindo. The deal received approval from SKK Migas on 10 June 2019 and subsequently completed in July 2019. The deal saw Mandala holding a total of 90% operating interest and Hexindo retained 10% PI.  Akatara field development  First oil production from the Akatara field was achieved on 16 November 2016. The milestone was reached following the issuance of the necessary forestry lease permit by Indonesian Ministry of Forestry and Environment. Initial production was expected to reach 500 bo/d from the Akatara 2 well. The operator planned to increase output with additional production from other existing wells and from new development wells drilled from 2017 onwards.  The development plan for the block includes the recompletion of exploration wells Selong 1, Akatara 1 and Akatara 2, followed by eight new development wells and two step-out wells. Production was initially achieved through temporary facilities (Early Production Facilities). In this early stage, oil was transported by truck to the Tempino field and from there is pipelined to the Plaju refinery. In a later phase, the operator plans to install permanent facilities, possibly with a higher production capacity. A new pipeline was also planned to be built, in order to connect the block directly with the Plaju refinery.  The block was expected to produce up to 4,000 bo/d during the early production phase. Commercial gas production is expected to commence at a later stage. According to local media, quoting the operator in late February 2017, the block could potentially produce approximately 10,000 bo/d by 2022 if further development activities are conducted. The block is estimated to carry 115 Bcf of wet gas in place (best estimate).","Indonesia (Tiga Puluh Arch) Lemang op. by MANDALA EN (90%), ENECO EN (8%), TRIDATU (2%)"
31701,"Total is understood to be evaluating its options for some USD 1 bn investment in B-H, in which a bid round is tentatively planned for a an area situated between the towns of Bihac and Neum , W. Bosnia on the Adriatic – note recent rumours suggested round plans. had been scrapped, but these have since been dispelled and plans are still on.","Total is understood to be evaluating its options for some USD 1 bn investment in B-H, in which a bid round is tentatively planned for a an area situated between the towns of Bihac and Neum , W. Bosnia on the Adriatic – note recent rumours suggested round plans. had been scrapped, but these have since been dispelled and plans are still on."
70539,"JOG has entered into a conditional SPA to acquire 70% + operatorship in P2170 / blocks 20/5b + 21/1d from Equinor for 2 milestone payments (USD 3 & 5 MM linked to Verbier clearance + production) + a royalty based on potential future production from the Verbier Upper Jurassic (J62-J64) reservoir. Partnership-to-be Jersey (op) 70%, Equinor 30%.","Jersey O&G (->88% op, CIECO 12%) has entered into a conditional SPA to acquire 70% + op. in P2170 (home to Verbier disc.)  from Equinor (->0%)"
83717,"The ANP has approved the transfer of Petrobras' 100% in 10 fields from the so-called Enchova and Pampo packages to UK-based Trident for USD 851MM, as agreed last July. The fields include Bicudo, Bonito, Enchova, Enchova Oeste, Marimba, Pirauna, Badejo, Linguado, Pampo + Trilha in the Campos Basin.","The ANP has approved the transfer of Petrobras' 100% in 10 fields from the so-called Enchova and Pampo packages to UK-based Trident for US$851 MM. The fields include Bicudo, Bonito, Enchova, Enchova Oeste, Marimba, Pirauna, Badejo, Linguado, Pampo + Trilha."
22133,"Mirpur Khas 2568-7 EL, Lower Indus onshore, TD 4,054m, susp mid-May ’18 after testing, results yet n/a. UE (op), partners Bow Energy + Govt Holdings.","Ali Nord 1 UE (op), partners Bow Energy + Govt Holdings in Mirpur Khas 2568-7 EL, TD 4,054m, susp mid-May ’18 after testing, results yet n/a.  "
15290,"In early February 2018, ExxonMobil Canada acquired 65% WI from Husky Oil Operations in EL 1134 (Flemish Pass Basin). The transactions are effective as of 1 February 2018. Approximately 7km west of EL 1134 lies NFW Aster C-93A, which was fully written off in the first quarter of 2015, as the well did not encounter economic quantities of hydrocarbons. EL 1134 was originally awarded on 15 January 2013 for a nine-year to Husky Oil Operations (40% WI + Op), Suncor Energy (35%) and Repsol E&P Canada (25%), as the winning bid in respect of the Call for Bids No. NL12-02 - Parcel No.1. Following completion of the February 2018 transaction, equity in EL 1134 is now shared between ExxonMobil Canada (65% WI + Op) and Suncor Energy (35%).","ExxonMobil acquired 65% WI+op. from Husky Oil (->0%, Suncor 35%) in EL 1134."
66392,"On 29 November 2019 (reported by the NPD on 5 December 2019) Aker BP took a 40% interest from Spirit in PL 780. The licence covers an 18 sq km area over part of block 16/1, located between Ivar Aasen and Hanz. A well is planned for Q3 2020 on the Sorvesten prospect. Sorvesten is mapped as a rotated fault block with an Upper-Middle Jurassic Vestland Group reservoir. Volumes are expected to be small but chance of success is high and a find could be tied-back to the Aker BP-operated Ivar Aasen field.  Suncor was a partner in PL 780 until August 2019 when it withdrew, passing its 40% interest to Spirit.   The Ivar Aasen oil and gas discovery was made in 2008. A 44 m thick Middle Jurassic Hugin/Sleipner Formation sandstone reservoir with varying reservoir properties was encountered containing light oil with a small gas cap. The field came onstream on 24 December 2016, with Aker BP expecting to recover approximately 210 MMboe (including Asha, Hanz and West Cable). A 20-year field life is anticipated with a daily production capacity of 68,000 boe/d. The field was developed using a manned PDQ platform with capacity for the planned subsea tie-back of Hanz.   Following completion of the deal, interest is divided between Spirit Energy Norway AS (60% + operator) and Aker BP ASA (40%).","Aker BP took a 40% interest from Spirit in PL 780. The licence covers an 18 sq km area over part of block 16/1, located between Ivar Aasen and Hanz. "
42295,"Hocol, subsidiary of Colombian state oil company Ecopetrol, is currently in the process of transferring ownership of two of its wholly owned blocks, CPO-17 and LLA-65, to its parent company, Ecopetrol, industry sources revealed in February 2019. Both blocks are located in the Llanos Basin. The Godric Norte-1 NFW was suspended in February 2018 on the CPO-17, whilst test results were analysed. On the LLA-65 Block, the Bonifacio-1 NFW was announced as a discovery on in February 2018. It is not currently know why Ecopetrol is taking control of these blocks.","Hocol, subsidiary of Colombian state oil company Ecopetrol, is currently in the process of transferring ownership of two of its wholly owned blocks, CPO-17 and LLA-65, to its parent company, Ecopetrol, industry sources revealed in February 2019. Both blocks are located in the Llanos Basin. The Godric Norte-1 NFW was suspended in February 2018 on the CPO-17, whilst test results were analysed. On the LLA-65 Block, the Bonifacio-1 NFW was announced as a discovery on in February 2018. It is not currently know why Ecopetrol is taking control of these blocks."
26232,"Local media reports that MEMR may auction the West Kampar and Selat Panjang blocks, both in onshore Central Sumatra, due to bankruptcy of the current PSC operators. More from GEPS.","Local media reports that MEMR may auction the West Kampar and Selat Panjang blocks, both in onshore Central Sumatra, due to bankruptcy of the current PSC operators. "
67927,"Ex-prospect G in Andaman Sea block A-3, Rakhine Basin, WD 1,100m, ops concluded at TD ca. 1,950m, target gas in Pliocene turbidites, Maersk Viking DS.  1st of 3 wells planned, to be followed by Yan Aung Myin-1 (ex-prospect A-South, position shifted to #2) and Kissapanadi-1 (Mya Channel Fill). Posco (op), partners ONGC Videsh, MOGE, Gail + Kogas.","Mahar 1 nfw. (Posco 51% op , ONGC Videsh 17%, MOGE 15%, Gail 8,5%, Kogas 8,5%), 1st of 3 wells planned in ex-prospect G in Andaman Sea block A-3, WD=1100m, ops. concluded at TD ca. 1950m, results n/a, target gas in Pliocene turbidites,. "
84867,"Draupner is offering equity in wholly-owned P2331 (blocks 38/22b, 38/23a, 38/27, 38/28, 44/2 + 44/3a, Balvenie prospect, 490 sq km on the N. Dogger Shlf) and P2487 (blocks 38/21b + 38/22c, Durham prospect, 252 sq km in the Mid NS High) in exchange for coverage of historic costs, work programme participation and/or a cash offer. Contact: Ann-Charlotte Hogberg, email ach@draupnerenergy.com.","United Kingdom (Anglo-Dutch B.) P2331 op. by DRAUPNER (100%), Draupner is offering equity in wholly-owned P2331 (blocks 38/22b, 38/23a, 38/27, 38/28, 44/2 + 44/3a, Balvenie prospect, 490 sq km on the N. Dogger Shlf) and P2487 (blocks 38/21b + 38/22c, Durham prospect, 252 sq km in the Mid NS High) in exchange for coverage of historic costs, work programme participation and/or a cash offer"
78676,"Kirthar has assigned a 25% interest to the Govt Holdings from its so far wholly-owned Makhad 3371-19 EL, 1,563 sq km in the Potwar Basin, retro-effective 22 May '19 (award). It lies in the Attock, Mianwali + Chakwal districts of Punjab.",Kirthar has assigned a 25% interest to the Govt Holdings from its so far wholly-owned Makhad 3371-19 EL (1563km²).
69342,"Liberty Resources Corp is seeking farm-in interests for its 100% owned Exploration Permit Application STP-EPA-0076 (previously L12-5), located in the Officer - Gunbarrel Basin. Liberty is reported to be open to negotiating the farm-in terms, with operatorship available.   It has been reported that several companies have shown interest, with discussion ongoing in early 2020 with interested parties.  The application was lodged by Liberty on 2 November 2012 and covers an area of 22,730 sq km. Once an exploration permit is awarded, minimum work commitments will include 100 km of 2D seismic data acquisition or reprocessing in the first two years, followed by an exploration well by year four. It remains in the application phase at this stage.  Reports by Ryder Scott, after studying adjoining blocks in 2010, indicates up to 125 Bb of convention oil in place maybe present within a large neo-Proterozoic Graben. Shale potential may be present.  Liberty Resources Corp is reported to be seeking a farm-in partner in Exploration Permit Application STP-EPA-0076 with negotiable terms available.","Liberty Resources Corp is seeking farm-in interests for its 100% owned Exploration Permit Application STP-EPA-0076 (previously L12-5), located in the Officer - Gunbarrel Basin. Liberty is reported to be open to negotiating the farm-in terms, with operatorship available. It has been reported that several companies have shown interest, with discussion ongoing in early 2020 with interested parties."
68121,"United Energy Pakistan (UEP) has discovered gas in Bitro 1 new field wildcat (NFW) well within the Latif 2669-3 EL (Lower Indus Basin) onshore concession during early December 2019. After drilling to a TD of 3,613 m, a modular dynamic test (MDT) was carried out and the well is reported to have flowed gas at a rate of 28.6 MMcfg/d through 44/64"" choke at a wellhead flowing pressure (WHFP) of 3,116 psi from the perforated zone between 3,354 m to 3,360 m depth in 'B-Sand' unit of Cretaceous Lower Goru Formation. It also flowed water at a rate of 152 b/d. The well was spudded on 6 October 2019 using the Schlumberger's SLR-215 land rig with a prognosed TD of 3,647 m in the Cretaceous. It was reported to have been drilling at 1,480 m depth by mid-October 2019 and had reached 2,981 m by the end of October before progressing to the final TD of 3,613 m in mid-November 2019.    The Latif EL block, located in the Sindh province, currently covers an area of 547 sq km and the equity split is as follows: UEPL (33.4%, operator), Eni Pakistan Ltd (33.3%) and Pakistan Petroleum Ltd (33.3%). UEPL had acquired Latif EL from OMV following the signing of USD 193 million (EUR 157 million) agreement on 28 February 2018 under which OMV sold its upstream business in Pakistan to United Energy. The transaction was completed on 28 June 2018.    UEPL was granted an extension to the second two-year renewal period of the Latif EL from 1 November 2018 to 30 November 2019.          Background Information    Latif EL was originally awarded to OMV (Pakistan) Exploration GmbH on 23 October 2003 with an area of 1.498 sq km. The work programme for the three-year Phase-I of initial exploration phase (with a minimum financial commitment of USD 5.15 million) is believed to include G&G studies, 1,000km 2D seismic reprocessing, 300 sq km 3D seismic acquisition and the drilling of one exploration well to penetrate the Cretaceous Lower Goru Formation or a depth of 3,400m (whichever is shallower).     A total of 348 sq km 3D seismic was acquired over the acreage between July-December 2005, which supplemented the earlier acquisition of 362 sq km 3D seismic and 71 line km 2D seismic between December 2004-April 2005.     The licence was granted a six-month extension to the Phase-I with effect from 23 October 2006 and the first well to be drilled during the licence term, Latif 1, was declared a gas condensate discovery in March 2007. The Latif 1 well was reported to have encountered a total of 18.7 m net gas / condensate pay in three layers between 3,200-3,450m on reaching a final TD of 3,520m in the Cretaceous Lower Goru Formation in February 2007 - two of which were successfully tested. Although preliminary results show that the well is capable of flowing over 1,700 boe/d (10 MMcf/d) from the tested zones, the actual flow potential and size of the field will only be determined following a long-term test and appraisal - a 3D seismic acquisition programme planned over the structure in addition to the drilling of further wells.     The licence area was increased to 1,743 sq km in early 2007. The contract enters to two-year Phase-II of initial term on 1 July 2007 along with reduction in area to 1,219 sq km.     In addition to appraising reservoir sands, it is reported that the Latif 2 appraisal well also discovered an additional hydrocarbon-bearing zone at a shallower depth. The well was suspended as a potential gas producer in June on reaching a final TD of 3,488m and a total of 422.86 sq km 3D appraisal seismic was acquired over the discovery area between March-June 2008. A further appraisal well, Latif 3, was P&A on reaching a final TD of 3,500m in February 2009.     OMV was granted the first two-year renewal with effect from 1 July 2009 with reduction in area to 874 sq km. The second two-year renewal was awarded with effect from 1 July 2011 along with area reduction to 547 sq km.","Bitro 1 nfw. (Eni 18,42%, KPC 15,79%, Al-Haj Group 15,79%, OGDCL 50%) in the Kadanwari D&PL onshore concession, gas disc. MDT was carried out and the well is reported to have flowed gas at a rate of 28.6 MMcfg/d [44/64""choke] from the 'B-Sand' unit of Cretaceous Lower Goru Fm."
68648,"PL 894, E. of Balderbrå in WD 1,127m, TD 3,606m, target Springar sst, P&A'ing dry, Scarabeo 8 SS then off to 6604/5-2 S (Balderbrå) in same block. Wintershall Dea (op), partners Equinor + Petoro.","6604/06-01 (Gullstjerne) nfw. (Wintershall Dea 40% op, Equinor 40%, Petoro 20%) in PL 894 block, E. of Balderbrå in WD=1127m, TD=3606m, target Springar sst, P&A'ing dry. "
68036,"On 26 December 2019, the Ministry of Natural Resources released a list of blocks planned for auctions in 2020. The list includes 83 blocks in North Caucasus, Volga-Urals, Timan-Pechora, Western Siberia and Eastern Siberia (Table 1). Combined 3P reserves of fields, included in the offer, are estimated at 168 million bbl of oil and 1.928 Tcf of gas. Combined hydrocarbon resources of the offered blocks are estimated at 2.952 Bbbl of oil, 21.998 Tcf of gas and 763 MMbbl of condensate. During 2020, the Government will add blocks to be proposed by its local branches and some blocks planned but not auctioned from the 2019 list.  Table 1          Petroleum Province         Political Province         Block         3P reserves         Resources             Oil, MMbbl         Gas, Bcf         Condensate, MMbbl         Oil, MMbbl         Gas, Bcf         Condensate, MMbbl             Eastern Siberia         Irkutsk Obl         Bilchirskiy                     45                                    Polivinskiy                  17         2,579         28                          Teteyskiy Yuzhnyy                  299         2,329         16                                 Tubinskiy                                       15         2,976         32                       Krasnoyarsk Kray         Chadobetskiy Zapadnyy                  96         1,010                                    Gorchinskiy Severnyy                  37         2,147                                    Kazantsevskoye field            654                                             Kolymovskiy                  18         363                                    Novotaymyrskiy Vostochnyy                  29         411                                           Oskobinskiy                                       276         4,572                       North Caucasus         Dagestan Rep         Berikey                                       1                                 Timan-Pechora         Komi Rep         Druzhnyy                  6         45                                    Kedrovskiy         2               1                                       Krayniy                  1                                       Kushnyurskiy-1                  36                                       Kushnyurskiy-2                  33                                       Lekkerskoye field (Serpukhovian pool)         20                                                Nizhniy                  2         3                                    Otradnyy                  2         21                                    Pionerskiy                  8                                              Trudovoy                                       1         3                                 Nenets AO         Saremboyskiy         9         1,096                                                     Volga-Urals         Bashkortostan Rep         Atyashevskiy         1               5                                       Bizhbulyakskiy                  1                                       Fedorovskiy                  4                                       Kalmashevskiy                  37                                       Kamskiy Yuzhnyy                  5                                       Mayachnyy                  41         154                                    Sukhoyazskiy-2         9               1                                              Tenyayevskiy                                       4                                           Orenburg Obl         Abdulinskiy         4                                                Aldarkinskiy Severnyy                  4         7                                    Alpayevskiy         2               19                                       Filippovskiy                  11                                       Karinovskiy         5                                                Kolganskiy Severnyy         5               25                                       Leningradskiy Yuzhnyy                  1                                       Lysovskiy                     64         2                          Ratchinskiy                  5                                       Repinskiy Vostochnyy                  14                                       Sharlykskiy                  4                                       Sofiyevskiy         1               30                                       Umirkinskiy         11               46                                       Vostretsovskiy                  9                                              Yemelyanovskiy         4                                                                         Perm Kray         Altayskiy         1                                                Gezhskiy Severnyy                  9         12                                    Kyshtymskiy                  1                                       Mezhevskoy Yuzhnyy         1                                                Peschankovskiy         1                                                Pultovskiy                  2                                       Ust-Obvinskiy                  12                                       Verkh-Dobryanskiy         1                                                Verkh-Sypanskiy         2                                                Vetosskiy         1                                                Yolkinskiy         12         24                                                    Yurmanskiy         1                                                                         Samara Obl         Bolshe-Tokayskiy         1                                                Glebovskiy         1               21                                       Ishchanskiy         1                                                Perovomayskiy Vostochnyy                  15                                       Sosnovskiy                  9                                       Teleginskiy                  8                                       Tomylovskiy         2                                                Yamskoy         1                                                       Zharinovskiy         11                                                                         Saratov Obl         Dergachevskiy Yuzhnyy                  585         4,987         681                          Grigoryevskiy         1               29                                       Ilovlinskiy Zapadnyy            6                                             Khvalynskiy Severnyy                  14                                       Nekrasovskiy            8            2         51                                    Shiroko-Karamyshskiy         1         37                                                    Smirnovskiy                   34                             17                                 Udmurtia Rep         Chutyrskiy         20                                                Kostovatovskiy Yuzhnyy                  10                                              Mozhginskiy                                       26                                 Western Siberia         Khanty-Mansiysk AO (Yugra)         Enitorskiy         27               384                                       Nezhdannyy         2               69                                       Nyatlongskiy         5               105                                       Verkhnekondinskiy            69            1         10                                           Zaozernyy Yuzhnyy                                       139                                           Tomsk Obl         Chvorovyy-2         2                             60                                           Tyumen Obl         Yelovyy                                       307         192         4","On 26 December 2019, the Ministry of Natural Resources released a list of blocks planned for auctions in 2020. The list includes 83 blocks in North Caucasus, Volga-Urals, Timan-Pechora, Western Siberia and Eastern Siberia"
38526,"On 13 August 2018, using the “Scarabeo 8” S/S, Total spudded an exploration well in PL 255 B located to the south of Kristin and Tyrihans. 6406/6-5 S targeted the Jasper prospect but was junked just two days after spud (TD – 381 m). On 16 August 2018 the well was re-spudded as 6406/6-6 S. Jasper had primary objectives in the Middle Jurassic Garn (top expected around 4,468 m) and Ile (top expected around 4,595 m) formations and sandstone was also prognosed in the Lower Jurassic Tofte Formation (4,788 m). The well was drilled to TD at 4,911 m and on 27 November 2018 Total kicked-off a geological sidetrack – 6406/6-6 A. This sidetrack is designated an appraisal well therefore implying that 6406/6-6 S has made a discovery (assumed gas). The well was abandoned on 5 January 2019 after reaching TD at 4,869 m and results are expected shortly.  PL 255 B contains the 2002 gas discovery made by Shell with 6406/5-1 and it lies immediately adjacent to the Tvillingen South gas condensate discovery made by Maersk in 2015.   6406/5-1 proved a 41 m hydrocarbon column in the Middle Jurassic Garn Formation. Reservoir pressure was high at 777 bar. The discovery is believed to be non-commercial.  The Tvillingen South discovery well was 6406/6-4 S. It encountered a 25 m gas column in a 102 m section of good quality Garn Formation sandstone and estimated recoverable reserves given at the time were 9–19 MMboe.  Interest in PL 255 B is held by Total E&P Norge AS (40% + operator), Petoro AS (30%) and Equinor Energy AS (30%)."," Norway Total E&P Norge AS PL 255 B - 6406/6-5 S, 6406/6-6 S (Jasper) exploration, 6406/6-6 A (appraisal) - Abandoned, awaiting results "
19234,"Bourakebougou gasfield area + block (carveout from block 25), Taoudeni Basin in S. Mali, 4 wells reportedly completed, TDs 105-111m, gas. It is understood 13 shallow wells are planned + 2 deep (TD’s ca. 2,000m).","Bourakebougou gasfield area + block (carveout from block 25), Taoudeni Basin in S. Mali, 4 wells reportedly completed, TDs 105-111m, gas. It is understood 13 shallow wells are planned + 2 deep (TD’s ca. 2,000m)."
73056,"Metgasco Pty Ltd, Vintage Energy Pty Ltd and Bridgeport Energy Ltd reported on 24 February 2020, that they have executed the farm-in agreement, to enter PRL 211, located in the Cooper-Eromanga Basin. Under the terms of the farm-in, which was entered into in November 2019, the companies will be acquiring interest from current operator of PRL 211, Senex Energy Ltd. A number of conditions are required to be satisfied, including executing a formal farm-in agreement. Other conditions include Ministerial approvals and a demonstration of sufficient funds being available to drill a well. The remaining conditions are expected to be completed by 31 March 2020.  Under the terms of the farm-in agreement, it's proposed that Vintage will acquire operatorship of the licence with 42.5% interest, with the remaining interest split between Bridgeport (21.25%), Metgasco (21.25%) and current holder Senex (15%). Senex will be free carried for the first well, as part of the farm-in terms.   The joint venture partnership of Metgasco, Vintage Energy, Bridgeport Energy and Senex Energy already has ownership of adjacent exploration licence ATP 2021-P, which is on the Queensland side of the basin (subject to relevant authority approvals and registration of the interests). PRL 211, located in South Australia, is currently 100% owned by Senex's subsidiary Stuart Petroleum Pty Ltd. Entry into the retention lease provides the joint venture with complete access to the Odin Prospect which straddles both ATP 2021-P and PRL 211.   With the Odin structure being the main target, the terms extend to specifically drilling the prospect, for which, Vintage will be liable for 50% of the costs to acquire its 42.5% equity. The remaining costs will be split evenly between Bridgeport and Metgasco. The well is planned to be drilled in Q4 2020. It is expected that the initial well costs will be around AUD 4 million. Subsequent well testing costs will reflect the equity share in the licence once the farm-in deal is completed.     The Vali Prospect, located solely in ATP 2021-P, was drilled in December 2019/January 2020 and was, prior to drilling, reported to provide significant de-risking of the Odin Prospect. The Vali 1 exploration well encountered 35 m net gas pay in the primary Patchawarra Formation, plus additional gas recovery and oil shows the deeper Triassic and Jurassic secondary targets. Vintage reported that the results are on the high side of pre-drill estimates. Oil shows in the Jurassic Westbourne and Birkhead formations were also reported by Vintage. As of 16 January 2020, Vintage plans to case and suspend the well for potential stimulation, which could increase permeability in the Patchawarra sandstones, flow testing and future production.  PRL 211 was awarded over exploration licence PEL 637 (replacement of PEL 516, 2010), which was awarded in 2014 to Stuart Petroleum. Origin entered in 2015 forming the subsequent partnership for PRL 211, which was awarded on 25 October 2017. PRL 211 now covers nearly 100 sq km. The joint venture partnership ended on 26 June 2018 with Stuart acquiring Origin's 40% interest.   The Odin Prospect comprises an anticlinal structure on the eastern boundary of the permit with an independent closure at a depth of around 2,300 m. The Strathmount 1 exploration well, which was drilled in 1987, lies within the extent of the prospect. The well encountered 21 m of reservoir sands and 13.7 m of interpreted gas pay. Gas flow testing indicated returned gas to surface, but rates were too small to measure. On the 2016 Snowball 3D seismic data, Metgasco reports that the well appears to have intersected the sands outside of the Toolachee and lower Patchawarra level. Odin has been assigned gross P50 recoverable resources of 12.6 Bcf, a 3.9 Bcf upgrade from estimates released in 2018.","Vintage will acquire operatorship of the PRL 211 licence with 42,5% interest, with the remaining interest split between Bridgeport (21,25%), Metgasco (21,25%) and current holder Senex (->15%)."
67198,"On 20 October 2019 Sonatrach was awarded the El Hadjira II exploration permit covering 4,750 sq km in the Hassi Messaoud Basin. The award was confirmed by presidential decree on 8 December 2019. It is understood that this permit replaces the El Hadjira permit which was due to expire in June 2018. Sonatrach operates the acreage with a 100% interest. The permit lies west of the Bir Seba oil development operated by a PTTEP / Petro Vietnam partnership. The El Hadjira II block contains the Moukheg El Kebach oil discovery.","Sonatrach (100%) was awarded the Reggane II (Reggane B.) and El Hadjira II, Garet El Bouib II explo permit in the Hassi Messaoud B. "
76509,"Oman's 1st deepwater well (WD ~880m) has reportedly ended in block 52 (Juzor Al Hallaniyyat), Qamar sub-basin off SE Oman, the Pacific Bora DS released but remaining in country until further notice. Well results yet n/a. Eni (op), partners Qatar Petr. + Oman Oil Co.","Oman, Block 52 (Juzor Al Hallaniyyat)"
24934,"An auction was held 3 Jul ’18 for 10 blocks in the Khanty-Mansiysk AO, W. Siberia, although 9 were withdrawn due to single applications or no interest. The remaining Kumskiy block was won by local Kiyevskoye with a USD 1.05 MM offer against the starting price of USD 0.96 MM. The 413-sq km block lies in the Middle Ob Province and contains the Kumskoye + Fobosskoye oil discoveries.",Kumskiy block was won by local Kiyevskoye with a USD 1.05 MM offer against the starting price of USD 0.96 MM. The 413-sq km block lies in the Middle Ob Province and contains the Kumskoye + Fobosskoye oil discoveries.
32878,"By September 2018, Apache was understood to have successful completed its North Ras Qattara 9 7 (NRQ 9 7) appraisal/development well as an oil producer. The well was drilled on the NRQ Part B development lease (DL) of the NRQ concession in the Alamein Basin. It reached 2,590m TD in the Cretaceous Kharita Formation, with operations carried out by the Egyptian Drilling Company #61 rig. NRQ 9 7 is understood to have been an appraisal of the 2017 NRQ 11X discovery (2,588m TD) drilled ~0.7km to the east. It tested 750 bo/d from the Cretaceous Abu Roash ""G"" dolomite and Bahariya Formation. The well is one of two drilled on the block in 2018. Apache operates NRQ with 23.45% equity, in partnership with Sinopec (11.55%), IPR (15%) and EGPC (50%, carried). ","Apache was understood to have successful completed its North Ras Qattara 9 7 (NRQ 9 7) appraisal/development well as an oil producer. The well was drilled on the NRQ Part B development lease (DL) of the NRQ concession in the Alamein Basin. It reached 2,590m TD in the Cretaceous Kharita Formation"
73362,"PPL 36, Cooper-Eromanga drilled 21-24 Feb '20, susp. at TD 871m, under evaluation. Santos (op), partner Beach sub's.","Jena-24 appr PPL 36, Cooper-Eromanga drilled 21-24 Feb '20, susp. at TD 871m, under evaluation. Santos (op), partner Beach sub's."
87471,"N. part of YD SN 1 block, Lower Magdalena, P&A dry 25 Jun '20.","(Lower Magdalena B.) Ecopetrol (100%) reported that the Obiwan 1 nfw in the Hocol operated YD SN 1 Block, was plugged and abandoned dry."
58534,"Kamose (Dev) block, offshore Nile Delta, compl. gas at TD 2,664m, on stream 29 Aug ’19 (20 MMcfg/d).   North Sinai Petr = MOG Egy-EGPC 50:50.","Kamose Main-1 expl. (North Sinai Petr = MOG Egy-EGPC 50:50) in Kamose (Dev) block, offshore, compl. gas at TD=2664m, on stream (20 MMcfg/d)."
34284,"Tower has signed a Petroleum Agreement for offshore blocks 1910A, 1911 and 1912B,  total 23,297 sq km in the Walvis Basin and Dolphin Graben (in yellow below) for a 4-yr term. Commitments USD 5 MM for the initial term, to be effective on finalisation of a joint operating agreement between Tower (op), 80%, ZM Fourteen Investment CC 10% + Namcor 10% (carried). Map extract from Tower:","Tower has signed a Petroleum Agreement for offshore blocks 1910A, 1911 and 1912B, total 23,297 sq km in the Walvis Basin and Dolphin Graben."
57074,"Further to DEA 14 Aug ’19, Gazprom Neft has actually been awarded blocks Taymyrskiy Zapadnyy 1 through 12 (and not just 1 + 6 as originally reported) for 7 years. They cover a total of 5,000 sq km on the right bank of the Yenisey Estuary astride the Yenisey-Khatanga Basin + Taymyr Fold Belt.","Gazprom Neft has actually been awarded blocks Taymyrskiy Zapadnyy 1 through 12 (and not just 1 + 6 as originally reported) for 7 years. They cover a total of 5,000 sq km on the right bank of the Yenisey Estuary astride the Yenisey-Khatanga Basin + Taymyr Fold Belt."
38402,"Dyas acquired 10% from Equinor in adjacent licences PL847 and PL847 B, effective from 20 December 2018. PL847 operator Wintershall is currently drilling the Marisko prospect NFW 6706/6-2 S which spudded on 4 December 2018. It is targeting gas in the Late Cretaceous Nise (1,2 & 3) Formation sandstone reservoirs. Estimated drill time is 135 days including two well tests and an optional sidetrack. PL847 was awarded in February 2016 in the APA 2015 round, and covers 790 sq km on blocks 6706/5 & 6706/6. PL847 B was awarded in APA2016 on 10 February 2017 covering 289 sq km of block 6707/4, adjacent to the E of PL847. P847 & PL847 B licensees are Wintershall Norge AS (40% + Op), Equinor Energy AS (10%), Repsol Norge AS (20%), OMV Norge AS (20%) and Dyas Norge AS (10%).","Dyas acquired 10% from Equinor in adjacent licences PL847 and PL847 B,"
16578,"INPEX has been awarded an exploration permit for Release Area WA-533-P as Operator in Australia’s 2017 Offshore Petroleum Exploration Acreage Release. INPEX Browse will hold a 100% participating interest in the Block where it will pursue exploration activities. The Block is located off the northern coast of Western Australia and covers a surface area of 12,402km2. The Block’s water depth ranges between approx. 50m and 600m.INPEX awarded exploration block WA-533-P offshore Western Australia The Block lies on an offshore extension of the onshore Canning Basin in Western Australia where promising oil and gas fields have been discovered and developed. The Block is therefore considered to be located in a highly promising exploration area where oil discoveries are expected. With the awarding of this exploration permit, the total number of offshore exploration blocks held by INPEX Group companies in Australia increases to 22. INPEX’s proactive exploration activities in Australia are expected to contribute to the continuous enhancement of the company’s E&P activities, positioned as one of the growth targets outlined in INPEX’s medium- to long-term vision. INPEX will continue to proactively pursue business development opportunities in Australia and the Asia-Oceania region. The impact of this development on the company’s consolidated financial results is minimal. Original article link Source: INPEX ","Australia, not found"
66742,"Hitherto-unreported, Gini secured sole rights to PPL 643, 85 sq km in the central Papuan Fold Belt, back in Apr '19 for 6 years. It lies over the S. part of the Paua oil discovery:","Papua New Guinea, not found"
14719,"Rosneft reportedly secured the Kochemskiy licence, 3,621 sq km undrilled N. of Irkutsk in in the Katangsky district, E. Siberia, in an auction last week, starting price believed USD 750,000.  The tender had been planned for Nov ’17 but was cancelled for lack of interest on the 3 blocks involved (Kochemskiy, Verkhnekatangskiy + Chitorminskiy, ref. DEA 19 Sep ’17). ","Rosneft reportedly secured the Kochemskiy licence, 3 621 sq km undrilled N. of Irkutsk in in the Katangsky district."
63479,"Luda 25-1-3 (LD 25-1-3) was suspended, having intersected oil in the target reservoirs, on or around 22 September 2019 after having been spudded on or around 23 August 2019, using the ""Bohai 5"" jack-up. The oil appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations with the objective of appraising the northerly extension of the Luda 25-1-1 oil discovery made by CNOOC in March 2019. Luda 25-1-3 is in the CNOOC operated Block 06/17 in the offshore Bohai Gulf Basin and is approximately 2.4km N of Luda 25-1-1.  <P /><P />","The oil appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations with the objective of appraising the northerly extension of the Luda 25-1-1 oil discovery made by CNOOC in March 2019. Luda 25-1-3 is in the CNOOC operated Block 06/17 in the offshore Bohai Gulf Basin and is approximately 2.4km N of Luda 25-1-1."
37262,"Turkmennebit state exploration and production trust is engaged in drilling appraisal wells in the Uzynada discovery onshore Western Turkmenistan. As of 13 December 2018, two wells were being drilled, Uzynada 8 and 17.  The Uzynada discovery is located close to the Caspian coast, some 30 km south of the Barsagelmes field (South Caspian Basin). It was was discovered by well no. 7 in May 2017. The well flowed gas with condensate at rates of 17.1 MMcf/d and 1,200 b/d, respectively, from the interval of 6,689-6,695 m.   The well has been drilled to 7,150 m and is the first super-deep well in Turkmenistan. It was drilled by Turkmennebit with a Chinese-made “ZJ70” heavy drilling rig.   The discovery is important for understanding prospectivity of the Block 21’s which lies immediately offshore. Four prospective intervals were identified in well 7 prior to drilling, including the Apsheronian Formation at -3,100 m subsea, the Upper Red Beds (Pliocene) at -4,000 m, and two intervals in the Lower Red Beds at -5,600 m and -6,125 m.   Seismic surveys were carried out over the Uzynada structure in 1973 and 1980. At least four exploration wells were drilled in the Uzynada structure in the 1970s, to TDs between 4,200 m and 4,400 m. None of those wells had been successful.",Turkmenistan (West Turkmen Sub-basin (South Caspian B.)) Uzynada
39206,"On 15 December 2018, Perenco Gabon S.A. completed the Simba 2 appraisal well located at the Simba Marine 1 field within the Simba Block. The well was spudded on 20 November 2018 with the Borr Norve J/U. the well was drilled to a TD of 2,852 m and suspended as a producer.  The Simba field was discovered by Agip Gabon SA in 2003 with the Simba 1 well. the well was drilled to a TD of 2,787 m and intersected oil assumed to be within the Albian or Cenomanian age Madiela Formation but possibly within the Cap Lopez sandstones.    Perenco Gabon SA operates the block with a 50% interest, Tullow Oil Gabon SA holds the remaining 50%.",Perenco Gabon S.A. completed the Simba 2 appraisal well located at the Simba Marine 1 field within the Simba Block. 
51791,"On 24th June 2019 Apache confirmed that Chrysaor has signed an agreement involving interests in eight blocks in the Beryl area. Through the deal Chrysaor will farm-in to five of Apache’s operated licences and increase its interest in two other licences. Chrysaor will acquire 39.5% non-operated interest in licences P103 (Area W), P2335, P2353, P2354 and P2355. The company will also increase its interest to 39.5% in licences P103 (Area AA) and P1985 through acquiring interest from Apache. In return, Chrysaor will transfer 5.5% interest in licence P1986 which will increase Apache’s interest from 55% to 60.5%. The deal involves acreage that is focussing on the Tertiary injectite play of which Apache had success in 2015 through the Corona discovery. All eight blocks are within tie-back distance to the Apache-operated Beryl production platform. The deal is subject to regulatory approval from the Oil and Gas Authority.             Licence         Operator         Pre-Completion Equity         Post-Completion Equity             Chrysaor   Limited         Apache   Beryl I Limited         Chrysaor   Limited         Apache   Beryl I Limited             P103 (Area W)         Apache Beryl   I Limited         0%         100%         39.50%         60.50%             P2335         Apache Beryl   I Limited         0%         100%         39.50%         60.50%             P2353         Apache Beryl   I Limited         0%         100%         39.50%         60.50%             P2354         Apache Beryl   I Limited         0%         100%         39.50%         60.50%             P2355         Apache Beryl   I Limited         0%         100%         39.50%         60.50%             P103 (Area AA)         Apache Beryl   I Limited         4.08%         95.92%         39.50%         60.50%             P1985         Apache Beryl   I Limited         22.78%         77.22%         39.50%         60.50%             P1986         Apache Beryl   I Limited         45%         55%         39.50%         60.50%           Apache made the Corona discovery in October 2015 which was the company’s first Tertiary aged injectite prospect. Apache reported reserves at Corona in the region of 9-19 MMboe (Pmean to P10), comprising of 98% oil and 2% gas. The discovery well penetrated a 362-foot hydrocarbon column height with 225-foot net pay and excellent reservoir quality. Apache believe the geological concept is well understood and the play is on trend with multiple producing properties. Several remaining undrilled prospects exist within the Corona development area.     The Beryl area comprises the Beryl field along with Loirston, Ness, Nevis, Skene and Buckland all produced from two fixed platforms – Beryl Alpha and Beryl Bravo. Beryl is a multi-reservoir oil field, one of the largest oil fields in the UK North Sea. It was discovered in 1972 and since then over 200 development wells have been drilled on the field which has been developed using the Beryl A and B platforms in conjunction with a number of subsea wells. Production from the B platform is piped to concrete storage cells at the base of the Beryl A platform (864,000 bo capacity) until it is transferred into tankers through the two SPM's (Single Point Moorings). Gas production began in 1992 through the SAGE (Scottish Area Gas Evacuation) gas export system to St Fergus.","Chrysaor has agreed to acquire a 39,5% non-op. interest in 5 licences: P103 Area W, P2335, P2353, P2354 and P2355 in the Beryl area from Apache (->60,5%)."
82172,"Hitherto unreported, Medco's Tunisian assets were taken over by Anglo Tunisian O&G in Nov '19. Involved are the Sud Remada + Jenein Centre blocks (explo) and Bir Ben Tartar, Cosmos + Yasmin (prod) and non-operated Borj El Khadra + Adam (Eni op).","(Ghadames B.) Sud Remada op. by MEDCO (86%), CYGAM EN (14%), ETAP (0%), Medco's Tunisian assets were taken over by Anglo Tunisian O&G. Involved are the Sud Remada + Jenein Centre blocks (explo) and Bir Ben Tartar, Cosmos + Yasmin (prod) and non-operated Borj El Khadra + Adam (Eni op)."
22913,"Caipipendi block, Sub-Andean Zone (Chaco Basin), TD 3,050m in late Apr ’18, assumed suspended w.o. test, targets Cangapi + Castellon fm’s (compared to the Huamampampa, Icla + Santa Rosa fm’s producing in Margarita-Huacaya gasfield). Repsol (op), partners Shell + Pan American Egy.","Margarita-2 Caipipendi block, Sub-Andean Zone (Chaco Basin), TD 3,050m in late Apr ’18, assumed suspended w.o. test, targets Cangapi + Castellon fm’s (compared to the Huamampampa, Icla + Santa Rosa fm’s producing in Margarita-Huacaya gasfield). Repsol (op), partners Shell + Pan American Egy."
9637,"On 22 August 2017 Premier announced that it had reached an agreement to farm down its entire 33.8% interest in the Wytch Farm field (licences PL89 and P534) for a consideration of USD 200 million. The company stated that it will release letters of credit amounting to USD 75 million in connection with future field decommissioning liabilities. On 12 September 2017 the acquiring company was named to be Verus Petroleum SNS Limited. However, in an update on 16 November 2017 Premier stated that existing operator Perenco UK Limited had pre-empted the deal and it was in fact Perenco which will be acquiring the 33.8% interest. Premier announced that it and Perenco have entered a Sale and Purchase agreement on 20 November 2017. The deal is subject to regulatory approval. Wytch Farm is located in southern Dorset, in an area of extreme environmental sensitivity. It was discovered in 1974 and was brought onstream five years later. The field's onshore sector has been developed with conventional sub-vertical producers, while its offshore extension under Poole and Bournemouth bays has been exploited with extended reach wells, with one of the longest wells having a step-out approaching 11 km. Production from the field was approximately 5,000 boe/d net to Premier as of 30 June 2017. Following completion of the deal interest in Wytch Farm will be held by Perenco UK Limited (87.6% + operator), Ithaca Energy (UK) Limited (7.4%) and Repsol Sinopec North Sea Limited (5%).","United Kingdom (Wessex B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Wytch Farm op. by PERENCO (53.81%, VERUS SNS 33.81%, DELEK GRP 7.43%, REPSOL NS 4.95%) to be check."
29940,"Kirthar 2667-7 EL, Kirthar Fold Belt in Sindh, P&A dry early Sep ’18, tested. PTD was 3,537m, Exalo-304 rig. PGNiG (op), partner PPL.","Pakistan, Kirthar 2667-7 ELRoshan 1 (PGNiG 70%, PPL 30%) the exploratory well within the Kirthar 2667-7 EL onshore block, P&A, after failed to flow hydrocarbons during testing."
45410,"Aker BP spudded appraisal well 2/11-12 S on 10 January 2019 at Hod West in PL 033 using the “Maersk Interceptor” J/U. 2/11-12 S was drilled to TD at 2,956 m (2,884 m TVDSS) in the Upper Cretaceous Hidra Formation. A 120 m section of limestone was proven in the Upper Cretaceous Hod Formation, but reservoir properties were poor and there were only traces of oil. In the secondary Tertiary Hordaland Group objective there was 200 m of poor reservoir, again with some oil shows. The well is classed as a dry hole. On 13 February 2019 Aker BP kicked off exploration sidetrack 2/11-12 A targeting the Hod Deep West prospect which had prospective recoverable reserves of 2-22 MMboe. The company reached TD at 3,427 m (3,189 m TVDSS) in the Permian Zechstein Group and this well is also a dry hole. The main target was the Upper Jurassic but there was no reservoir present and the secondary Permian Rotliegendes Group target was not reached. A 45 m Lower Cretaceous Tuxen and Asgard Formation carbonate exhibited some oil shows but again was of poor quality and on 7 March 2019 the well was abandoned. The results from these wells were key for the progression of the field’s re-development studies and resource estimates will subsequently be re-evaluated. The Hod group passed DG1 for the re-development in December 2017 and believed that a further 70 MMboe could be produced using an unmanned platform linked to Valhall Field Centre. The platform would have 12 slots, with six new wells planned (to be drilled from 2022-2023).    Production from Hod started in September 1990 from the field’s chalk reservoir in the Upper Cretaceous Hod and Tor formations and Lower Paleocene Ekofisk Formation at around 2,700 m using an unmanned wellhead platform. The field consists of the Hod East, Hod Saddle (which connects to Valhall) and Hod West structures. There has been no production from the Hod platform since 2013 and the facility is awaiting decommissioning and disposal. Production continues from the Hod Saddle area and is carried out using four wells drilled from Valhall. Initial recoverable reserves were 80 MMboe and around 4 MMboe of this was remaining as of December 2018. In place reserves are approximately 450 MMboe.    Hod is covered by PL 033 where interest is held by Aker BP ASA (90% + operator) and Pandion Energy AS (10%).","002/11-12 S (Hod Deep West) (Aker BP 90% + op, Pandion Egy 10%) in PL 033, encountered traces of oil in reservoir rocks of poor quality in both its exploration targets and was classified as dry, 002/11-12 A, did not find reservoir rocks in its primary target in the Upper Jurassic Eldfisk and Ula Fms, and did not reach its secondary target in Permian rocks."
53689,"Further to DEA 12 Jul ’19, PL 442, NOAKA* area north of Rind, WD 110m, PTD 1,350m, abandoned on 14 Jul ‘19 after being announced as an oil discovery of 80-200 MMboe, Deepwater Stavanger SS. Aker BP (op), partner Lotos. NOAKA = North of Alvheim, Krafla + Askja","025/02-20,21 (Liatårnet) expl. (Aker BP 90,26% op, Lotos 9,74%) in Noaka (= North of Alvheim, Krafla + Askja) in PL 442 oil discovery of 80-200 MMboe gross resources, currently being completed, more data acquisition and analysis to follow, targeted the mid-Tertiary Skade Fm."
18632,"As reported by local industry sources, Rosneft has started testing operations in the Tsentralno-Olginskaya 1 exploratory well in the Khatangskiy block. The well was drilled to a TD of 4,100 m in 2017, but testing was postponed then.  In October 2017, Rosneft submitted a reserve report for the Tsentralno-Olginskoye oil discovery to the State Commission for Reserves (GKZ) for official registration. According to the GKZ, 3P reserves of the discovery were estimated at 591 MMbbl of oil. No details regarding stratigraphy, depth or tests were provided at the time. It should be noted that Tsentralno-Olginskoye is the first state-registered discovery in the Lena-Anabar Basin meaning the new petroleum province inauguration.  Background Information  Russian Government awarded the Khatangskiy block to Rosneft on 17 December 2015. Rosneft had paid a signature bonus of RUB 282.512 million (USD 4 million). The block covers 17,218 sq km in the Khatanga Bay and the Laptev Sea. Its pre-drill hydrocarbon resources were estimated at 604 MMbbl of oil, 7.8 Tcf of gas and 109 MMbbl of condensate, but, after analysing new data, Rosneft reduced its estimations to 428 MMbbl of liquids and 4 Tcf of gas. Commitments during a 10-year exploratory stage include acquisition of 1,000 km of seismic data and drilling of an exploratory well.  On 3 April 2017, Rosneft spudded the first exploratory well in the block. Highly-deviated Tsentralno-Olginskaya 1 with a PTD of 4,147 m (TVD of 3,125 m) was spudded from the Khara-Tumus peninsula and its bottom hole is located some 2,500 m west in the Khatanga Bay. Permian clastic reservoirs are the well’s main exploratory target.",Russia (Lena-Anabar B.) Tsentralno-Olginskoye
32095,"Baron is looking to offload a 50% stake + possibly operatorship in block XXI,  2,425 sq km in the Sechura Basin, in exchange for USD 0.5 MM contribution to costs of past seismic + drill a 1,850m commitment well targeting the Minchales sands (Zapayal fm), the Mancora fm and the fractured basement. Contact malcolm@butlermail.org.","Baron is looking to offload a 50% stake + possibly operatorship in block XXI,  2,425 sq km in the Sechura Basin, in exchange for USD 0.5 MM contribution to costs of past seismic + drill a 1,850m commitment well targeting the Minchales sands (Zapayal fm), the Mancora fm and the fractured basement."
20515,"Nigerians Express Petroleum and Misana Energy are understood to have sold their 15% interests in block 25 (Melut Basin, S. Sudan), to existing holder Sudapet, now sole owner of the 24,707-sq km block.","Sudan, Block 25"
73396,"On 23 February 2020, the General Directorate of Mining and Petroleum Affairs (MAPEG) awarded Turkish Petroleum Corp (TPAO) a new and exclusive exploration licence for block M47-b4. The onshore area is located in the SE Turkish province of Siirt (District X) and is surrounded by exploration licences held by various companies. It covers an area of around 153 sq km and will be valid for an initial five-year exploration term, which can be extended up to a maximum period of nine years after extensions.<P />The area covered by block M47-b4 has been previously licenced to various operators but remains largely unexplored. So far seven wells have been drilled on the acreage, with some of those exhibiting oil shows. Aladdin Middle East Ltd submitted the original application for the block in July 2019. Rival applications were submitted by Guney Yildizi Petroleum AS (GYP), Karma Yatirim Enerji AS (Karma) and TPAO. The latter now operates the block with a 100% interest.",TPAO awarded a new and exclusive exploration licence for block M47-b4. 
33785,"An auction will be held 20 Dec ’18 for 25- year rights the Tazovskiy Zapadnyy block, 1,170 sq km in the E. Nadym-Taz Basin, Yamalo-Nenets AO, W. Siberia. Application deadline 26 November, starting price USD 7.57 MM. Contact: Yamalnedra, yamal@rosnedra.gov.ru.","Russia, not found"
78294,"Ardent is understood to have placed its farmin offer on hold until the autumn for P2300, P2329, P2427 + P2486 in the SNS. At present P2329, P2427 + P2486: Ardent (op, 25%), partners Horizon Egy + Simwell Res. P2300: Ardent (op, 50%), Horizon Egy + Simwell Res.","Ardent is understood to have placed its farmin offer on hold until the autumn for P2300, P2329, P2427 + P2486 in the SNS. At present P2329, P2427 + P2486: Ardent (op, 25%), partners Horizon Egy + Simwell Res. P2300: Ardent (op, 50%), Horizon Egy + Simwell Res."
12495,"Block 09-3/12, Cuu Long Basin, susp. oil at TD 3,900m on 7 Jan ’18 after DST’ing 1,800 b/d in 2 of the 4 tests run in the target Oligocene D, PV Drilling II JU. Vietsovpetro (op), partners PVEP + Bitexco.","Ca Tam 5X (09-3/12-CT 5X) appr (Con Son Swell) ? op. by VIETSOV (55.0%, PETROVIET 30.0%, BITEXCO 15.0%) in Block 09-3/12, DST’ing 1,800 b/d in 2 of the 4 tests run in the target Oligocene D, "
79219,"Petro Matad is seeking joint venture partners for the next exploration/development phase of Block XX in the eastern Gobi Basin in Mongolia. Following the successful drilling of Heron 1 in late 2019, which flow tested an average of 200 bo/d from the Lower Tsagaantsav Formation, Petro Matad is looking to fast track the development of the discovery and has applied for an exploitation licence covering the discovery. Petro Matad is planning to acquire an additional 250 sq km 3D seismic data south of the Heron discovery (costing US$ 4-5 million) and to drill additional wells in the discovery area covered by the existing 3D seismic data. Petro Matad is the operator and sole rightholder of Block XX.",Not Found
87026,"N-C part of AE-0133-Cuichapa block, onshore Sureste Basin, reported P&A dry on 28 Jul '20. PTMD was 4,606m, (4,395m TVD), target Kimmeridgian.",(Sureste B.) Andarani 1 well operated by PEMEX (100%) in AE-0133 block reported dry 
66593,"United Energy Pakistan (UEP) has discovered gas in Bitro 1 new field wildcat (NFW) well within the Latif 2669-EL (Lower Indus Basin) onshore concession during early December 2019. After drilling to a TD of 3,613 m, a modular dynamic test (MDT) was carried out and the well is reported to have flowed gas at a rate of 28.6 MMcfg/d through 44/64"" choke at a wellhead flowing pressure of 3,116 psi from the 'B-Sand' unit of Cretaceous Lower Goru Formation. The well was spudded on 6 October 2019 using the Schlumberger's SLR-215 land rig with a prognosed TD of 3,647 m in the Cretaceous. It was reported to have been drilling at 1,480 m depth by mid-October 2019 and had reached 2,981 m by the end of October before progressing to the final TD of 3,613 m in mid-November 2019.  The Latif EL block, located in the Sindh province, currently covers an area of 547 sq km and the equity split is as follows: UEPL (33.4%, operator), Eni Pakistan Ltd (33.3%) and Pakistan Petroleum Ltd (33.3%). UEPL had acquired Latif EL from OMV following the signing of USD 193 million (EUR 157 million) agreement on 28 February 2018 under which OMV sold its upstream business in Pakistan to United Energy. The transaction was completed on 28 June 2018.  UEPL was granted an extension to the second two-year renewal period of the Latif EL from 1 November 2018 to 30 November 2019.      Background Information  Latif EL was originally awarded to OMV (Pakistan) Exploration GmbH on 23 October 2003 with an area of 1.498 sq km. The work programme for the three-year Phase-I of initial exploration phase (with a minimum financial commitment of USD 5.15 million) is believed to include G&G studies, 1,000km 2D seismic reprocessing, 300 sq km 3D seismic acquisition and the drilling of one exploration well to penetrate the Cretaceous Lower Goru Formation or a depth of 3,400m (whichever is shallower).   A total of 348 sq km 3D seismic was acquired over the acreage between July-December 2005, which supplemented the earlier acquisition of 362 sq km 3D seismic and 71 line km 2D seismic between December 2004-April 2005.   The licence was granted a six-month extension to the Phase-I with effect from 23 October 2006 and the first well to be drilled during the licence term, Latif 1, was declared a gas condensate discovery in March 2007. The Latif 1 well was reported to have encountered a total of 18.7 m net gas / condensate pay in three layers between 3,200-3,450m on reaching a final TD of 3,520m in the Cretaceous Lower Goru Formation in February 2007 - two of which were successfully tested. Although preliminary results show that the well is capable of flowing over 1,700 boe/d (10 MMcf/d) from the tested zones, the actual flow potential and size of the field will only be determined following a long-term test and appraisal - a 3D seismic acquisition programme planned over the structure in addition to the drilling of further wells.   The licence area was increased to 1,743 sq km in early 2007. The contract enters to two-year Phase-II of initial term on 1 July 2007 along with reduction in area to 1,219 sq km.   In addition to appraising reservoir sands, it is reported that the Latif 2 appraisal well also discovered an additional hydrocarbon-bearing zone at a shallower depth. The well was suspended as a potential gas producer in June on reaching a final TD of 3,488m and a total of 422.86 sq km 3D appraisal seismic was acquired over the discovery area between March-June 2008. A further appraisal well, Latif 3, was P&A on reaching a final TD of 3,500m in February 2009.   OMV was granted the first two-year renewal with effect from 1 July 2009 with reduction in area to 874 sq km. The second two-year renewal was awarded with effect from 1 July 2011 along with area reduction to 547 sq km.","Pakistan (Lower Indus B) 	Bitro 1 nfw. (Eni 18,42%, KPC 15,79%, Al-Haj Group 15,79%, OGDCL 50%) in the Kadanwari D&PL onshore concession, gas disc. MDT was carried out and the well is reported to have flowed gas at a rate of 28.6 MMcfg/d [44/64""choke] from the 'B-Sand' unit of Cretaceous Lower Goru Fm."
65814,"Wintershall DEA and partner ONE-Dyas are jointly looking to offer up to a 50% interest in licence 9/16 in exchange for the incoming partner’s commitment to fund the HPHT Vibe-1 exploration well. The licence was awarded in April 2016 during the 7th Danish Licensing Round, it is situated in the Tail End Graben and comprises of seven blocks (5504/3a, 5604/22c, 5604/26b, 5604/26c, 5604/27a, 5604/27b and 5604/31a). The Vibe-1 exploration well is slated to spud in September 2020 to target the Moneypenny Fan Complex prospect, it has a planned TD of 4,330 m and will cost in the region of USD 44 million (dry hole).    Three stacked plays have been identified in licence 9/16. The shallowest is the Lower Cretaceous K12 Vyl Formation and Upper Jurassic J70 turbidite sand play, there is also an Upper Jurassic fluvial to shallow marine J60 sand play and the third play is in multiple Middle Jurassic sands. The licence hosts three discoveries known as Amalie-1 (1991), Svane-1A (2002) and Xana-1X (2015). The discovery well for Amalie-1, encountered hydrocarbons in the Lower Cretaceous Vyl Formation, Middle Jurassic Bryn Formation and in the J60 turbidite sands. If a larger discovery is made nearby then the Amalie-1 discovery could be tied-in and developed. The Svane-1A discovery well penetrated a 6 m thick oil bearing J70 turbidite sand package, the well also encountered gas condensate in the Middle Jurassic sands. The HPHT Xana-1X exploration well proved light oil and gas in an Upper Jurassic reservoir. Xana-1X lies northwest and up-dip of Svane-1A and it was mapped as a combined lateral pinch-out and fault seal trap with stacked deep-water sandstones.   The Vibe-1 well will be located east of Svane-1A and will target the Moneypenny Fan Complex prospect in the stacked J70 turbidite fan and channel sandstone reservoir. Although designated as HPHT, the Vibe-1 well is only expected to experience moderate pressure in the J70 sands. Vibe-1 is designated as HPHT because high pressure is expected in the underlying J60 sands (as experienced by Svane-1A). The Svane-1A well is located at the western margin of the Moneypenny Fan Complex prospect. The well encountered a 6 m thick, 0.54 net/gross, 26% average porosity J70 sandstone with 90% average oil saturation. The J70 sand at Svane-1A is too thin to create a seismic amplitude response but it is expected to be within the westernmost extent of the prospect and it is included in the P10 volumes for Moneypenny Fan Complex. It is interpreted that sands greater than 30 m thick created the amplitude response, which was mapped and used to estimate the Moneypenny Fan Complex volumes at Pmean level (167 MMboe STOIIP and 66 MMboe recoverable resources). Two other prospects (Channel and Honeyrider) and two leads (Vesper Lynd East and Greater Elstra King) also lie within the licence. The gross recoverable resource potential including the prospects and leads is estimated to be 165 MMboe (Pmean) and 293 MMboe (P10).  The licence carries two firm commitments and one optional commitment. The first commitment has already been fulfilled, it comprised geotechnical work and seismic interpretation, which enabled the Upper Jurassic turbidites to be mapped. The second commitment will be fulfilled by drilling Vibe-1. The optional third commitment requires a second well to be drilled before February 2021. This second well would likely be an appraisal of the Moneypenny Fan Complex prospect, if Vibe-1 is successful.   Interest in the licence is held by Wintershall Dea GmbH (50% + operator), ONE-Dyas Denmark ApS (30%) and Danish North Sea Fund (20%).",Wintershall DEA and partner ONE-Dyas are jointly looking to offer up to a 50% interest in licence 9/16 in exchange for the incoming partner’s commitment to fund the HPHT Vibe-1 exploration well.
68633,"CNPC has taken a 75% stake + operatorship in the Mazenga block following an agreement to this intent signed 16 Dec '19 with ENH. Mazenga lies over 22,812 sq km in S. Mozambique, Mozambique Basin. It was awarded to ENH in Dec '18. Partnership now CNPC – ENH.",CNPC has taken a 75% stake + op. in the Mazenga (22812km²) onshore block following an agreement with ENH (->25%). 
24420,"Khanpur 2870-7 EL, Lower Indus onshore, 1st well in block, P&A dry at TD 3,300m mid-Jun ’18, co. N-2 rig. OGDC (op), partner GHPL.",Pakistan (Jacobabad High (Indus B.)) Khanpur
26686,"OMV AG, via wholly owned subsidiary OMV New Zealand Ltd., is offering a farm-in opportunity after increasing its interest in exploration permit PEP 50119, located in the Great South and Canterbury basins.  OMV is offering up to 40%, non-operated equity in the permit.  OMV reports that the permit contains structural prospects, most likely containing liquids within mid-Cretaceous, half-graben traps.  The main prospect has been outlined as Tawhaki, which lies in the eastern portion of the permit and could contain recoverable resources of 1 Bbo.  Here, a thick package of Cretaceous and Paleocene marine shales seal Cretaceous sands draped over a basement high. OMV reports that potential oil charge has been modelled from Cretaceous syn-rift coals and that the Tawhaki prospect is thought to be analogous to the Utsira High in the North Sea, which includes the Evdard Greif, Ivar Aasen, Johan Sverdrup and Ragnarock discoveries.  These four contain potential recoverable resources of over 2,300 MMboe.  Under the current permit obligations, a commitment well is due to be drilled before 11 July 2019, with a drill or drop decision to be make before 11 October 2019.   On 16 March 2018 Shell reported that it had reached a deal to sell its remaining assets in New Zealand to OMV for USD 578 million (NZD 798 million) subject to regulatory approvals. This included Shell’s 60.98% operated interest in PEP 50119, which was subsequently transferred to OMV.  PEP 50119 covers an area of 16,760 sq km in deep water and was awarded on 11 July 2007.  Participants in the permit are OMV New Zealand Ltd. (82.93% + Operator) and Mitsui E&P Australia Pty Ltd (17.07%).  Interested parties should contact:  Alan Clare, Exploration & Appraisal Manager  Address: Level 20, The Majestic Centre, 100 Willis Street, Wellington 6011, New Zealand  Email: alan.clare@omv.com","OMV AG, via wholly owned subsidiary OMV New Zealand Ltd., is offering a farm-in opportunity after increasing its interest in exploration permit PEP 50119, located in the Great South and Canterbury basins.  OMV is offering up to 40%, non-operated equity in the permit. "
69008,"On 10 January 2020, local media reported that Belorusneft discovered three new oil pools at the Makanovichskoye Vostochnoye field. Well Makanovichskaya Vostochnaya 2 tested oil at a rate of 750 b/d from the Voronezh Formation at a depth 4,073 m. Also, oil accumulations were identified in reservoirs of the Semiluki and Sargayevo formations. According to Belorusneft, combined in-place reserves of the pools are estimated at 6 MMbbl of oil. The company plans to drill 7-9 development wells in the field. It is understood that the field, discovered in 2017, has been re-named to Gartsevskoye. Makanovichskaya Vostochnaya 2 reached 4,180 m in November 2019. It was side-tracked from 3,600 m and drilled to 4,231 m.","Belorusneft discovers 3 oil pools at Makanovichskoye Vostochnoye (Gartsevskoye)Well Makanovichskaya Vostochnaya 2 tested oil at a rate of 750 b/d from the Voronezh Formation at a depth 4,073 m. Also, oil accumulations were identified in reservoirs of the Semiluki and Sargayevo formations. According to Belorusneft, combined in-place reserves of the pools are estimated at 6 MMbbl of oil. "
33858,"Eni executives confirmed in late October 2018 that farm-out talks for its 100% WI in the CNH-R01-L02-A1/2015 (Amoca-Mizton-Tecoalli) contract area continue. Talks ""are proceeding"" in negotiation phase, but the company does not expect to see any cash reflection in its balance sheet this year. Reports in early April 2018 indicated that Eni was in talks to farm-out WI to Qatar Petroleum. Up until the late October comments, made in a Q3 2018 conference call, Eni had neither confirmed or denied farm-out reports. It is interesting to note that Qatar Petroleum is already partnered with the Italian company in the deepwater Round 2.4 Block 24. That tract is located in the Salina de Istmo Basin. As for CNH-R01-L02-A1/2015, on 31 July 2018, the Comision Nacional de Hidrocarburos (CNH) approved Eni's development plan for the shallow water Production Sharing Contract (PSC). While the company's roadmap for the offshore block calls for a FPSO to be moored in 2020, though Eni plans to kick off an early production scheme on the Mizton Field via a platform. Fast-track production will account for 8,000 bo/d. Eni, which has already reached out to contractors, plans to have an FPSO with the capacity for 90,000 bo/d to handle production from the Mizton and Amoca fields. The FPSO will also have the capacity for 75 MMcfg/d and 80,000 bw/d. Production for the Tecoalli Field is forecast to begin in 2024. Eni expects to take the Final Investment Decision (FID) in 4Q 2018. The PSC contract area is estimated to hold 2.1 billion of oil equivalent in place (90% oil). Eni has drilled a series of wells in the CNH-R01-L02-A1/2015 contract since winning the area in 2015. The overall plan calls for 22 development wells and ten injector wells (it is assumed that the four exploration wells drilled in the contract area will be completed). Natural gas will be transmitted via a 24.3 km subsea pipeline to the onshore San Ramon facility (operated by Pemex). Up to 25% of the FPSO will contain 'Mexican content.' The project also calls for four wellhead platforms. Eni won the three-field contract area with 100% WI on 30 September 2015 at Mexico's Round 1.2. The company made a bid of 83.75% for the contract area under a PSC model.<P />","Mexico, CNH-R01-L02-A1/2015"
31285,"El Wastani Petroleum (Wasco) has been awarded a development lease (DL) across the East South Abu El Naga 1 (ESAEN 1) Messinian Abu Madi gas discovery. The award is understood to be effective from Q3 2018. ESAEN 1 was drilled by Dana Gas on the North El Salhiya Onshore PSC, located in the Nile Delta Basin. Operations were carried out between January-March 2018 by the SinoTharwa Drilling #2 rig, with the well reaching 2,730m TD. Testing was carried out in May 2018. Whilst detailed test results are not available, the well is understood to be capable of producing up to 5 MMcfg/d in production configuration. The discovery lies on the western shores of Lake Manzala. ESAEN 1 was the second NFW to be drilled under the PSC agreement. The first, Bahy 1, was P&A dry in Q4 2017. Wasco, a 50/50 JV between Dana Gas and EGPC, will operate the DL. The remaining exploration lease area of the PSC was relinquished in July 2018, at the end of the extension to the first exploration period.","El Wastani Petroleum (Wasco) has been awarded a development lease (DL) across the East South Abu El Naga 1 (ESAEN 1) Messinian Abu Madi gas discovery. The award is understood to be effective from Q3 2018. ESAEN 1 was drilled by Dana Gas on the North El Salhiya Onshore PSC, located in the Nile Delta Basin. Operations were carried out between January-March 2018 by the SinoTharwa Drilling #2 rig, with the well reaching 2,730m TD. Testing was carried out in May 2018. Whilst detailed test results are not available, the well is understood to be capable of producing up to 5 MMcfg/d in production configuration. The discovery lies on the western shores of Lake Manzala. ESAEN 1 was the second NFW to be drilled under the PSC agreement. The first, Bahy 1, was P&A dry in Q4 2017. Wasco, a 50/50 JV between Dana Gas and EGPC, will operate the DL. The remaining exploration lease area of the PSC was relinquished in July 2018, at the end of the extension to the first exploration period."
20476,"Oranje-Nassau Energie has acquired the 30% interest held by INEOS in P1630. The deal is believed to have completed in April 2018 and makes Oranje-Nassau the sole holder of the licence which contains the Crosgan discovery.  Licence P1630 was awarded in the 25th Offshore Licensing Round and comprises blocks 42/10a, 42/15a and 42/15c covering a total area of approximately 52 sq km. The licence contains Crosgan which was discovered in 1990 with well 42/15a-2 drilled by Total. The discovery well’s Bunter objective at 1,162 m -1,202 m was found to be water-bearing. However, the Permian Hauptdolomit tested at 7.63 MMcfg/d (post acidisation) and a Carboniferous aged reservoir tested at 15 Mcfg/d. Appraisal drilling took place in early 2015 and further gas was confirmed in the Carboniferous.","United Kingdom, P1630"
61735,"Pan-Petroleum (Panoro) has reportedly agreed to sell its 12.1913% interest in OML 113 to PetroNor for USD 10 MM. The 1,593-sq km licence in the western delta offshore is home to the producing Aje field.   At the same time, a separate agreement has been reached between PetroNor and Yinka Folawiyo (optr) to create a new 55:45 holding company led by PetroNor for the next phases of the Aje project. Closing of the 2 interlinked deals is pending official clearance. So far Yinka Folawiyo (op), partners New Age, Energy Equity Res, Panoro + MX Oil. Release here.","Pan-Petroleum (Panoro) has reportedly agreed to sell its 12,2% WI in OML 113 (1593²km) licence to PetroNor for US$10 MM. "
61631,"On 17 October 2019, the Argentine government granted an exploration permit for MLO-124 block to a consortium of Eni, Tecpetrol, and Mitsui & Co through the publication of Resolution 645/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Work program in the first exploration period of four years consists of 2D seismic acquisition of 867 km, 3D seismic acquisition of 4,418 sq km, and 2D gravimetry and magnetometry acquisition of 6,500 km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment. Eni operates the block with 80% interest, followed by partners Tecpetrol and Mitsui with 10% stake each.  MLO-124 covers 4,421 sq km of deepwater area (as designated by the Argentine Secretary of Energy) in Malvinas Basin with approximated water depth below 200 m. Exploration target for the blocks in the area is expected to be oil and gas in the Springhill Formation, which has not produced from any fields on the Malvinas Basin side in comparison to the adjacent Austral Basin side where several offshore gas fields are currently producing.  The consortium lead by Eni won the rights for MLO-124 after submitting an offer of USD 67.605 million with a bonus of USD 5 million to edge out another offer by a partnership of Equinor and state company YPF of USD 27.185 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019. The concession is marked as Eni’s second offshore asset in Argentina after the Tauro-Sirius block in Austral Basin, where the company holds a 30% non-operating stake.  Background Information  The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.","Argentina, MLO-124"
28168,"Lufeng 12-3-2 (LF 12-3-2) was plugged and abandoned in June 2018, having intersected oil in the target reservoirs, after having been spudded in May 2018 using the ""Nanhai 6"" semi-sub. The oil appraisal well was likely targeting the Zhuhai and Enping formations with the objective of exploring the easterly extension of the Lufeng 12-3-1 oil discovery made by SK Innovation in January 2018, which flow tested approximately 3,750 bo/d. Lufeng 12-3-2 is in Block 17/03 PSC in the offshore Pearl River Mouth Basin and is approximately 2km ESE of Lufeng 12-3-1. Rightholders of Block 17/03 are SK Innovation (80%, operator) and CNOOC (20%), with CNOOC having the rights to back-in for a further 51% interest in the development and production phase. ","Lufeng 12-3-2 (LF 12-3-2) was plugged and abandoned in June 2018, having intersected oil in the target reservoirs,"
25475,"On 17 July 2018 Oil Search Ltd reported that the farm-in agreement with ExxonMobil Corp for licences surrounding the Elk-Antelope fields, is now complete. The deal sees Oil Search expand its onshore acreage in the Papuan Basin which is thought to hold prospectively on trend with carbonate plays analogous to Elk-Antelope. Oil Search has acquired 25% interest in exploration licences PPLs 474, 475 and 476, plus retention lease PRL 39. Exxon previously held 100% interest in all licences after the takeover of InterOil in 2017.  Oil Search considers the acreage to be on trend with existing gas plays and with potential for new plays close to existing infrastructure. The transaction is in line with Oil Search’s focus on expanding exploration potential to support the expansion of LNG projects. In doing so, Oil Search reported that the company’s exploration and appraisal budget for 2017 increased from USD 250-300 to USD 270-320 million which included the continued appraisal of the Muruk discovery.  The northern acreage entered into by Oil Search surrounds the Elk-Antelope field which provides the basis for the proposed Papua LNG Project, in which, ExxonMobil already holds 35% interest and Oil Search 22.8% interest in the Total operated project. This acreage includes the large gas fields Triceratops, Bobcat and Raptor. To the south, down the Aure Fold Belt, Tovala gas discovery adds validation to a working petroleum system in along the coast in PPL 474. The discovered resources within the farm-in area sees Oil Search add 2P recoverable reserves of around 600 MMboe (net) to its PNG portfolio and increases its net acreage along the carbonate plays from onshore Elk-Antelope to the offshore Gulf licences adjacent by around 32%.     Since the farm in agreement was announced by Oil Search on 29 May 2017, several proposed terms have not been brought through to completion. Initially Oil Search proposed to acquire 30% interest but this was revised to 25%. PPL 477 was also included in the agreement but was later dropped due to a lack of perceived prospectively in the licence area. Finally, Oil Search was to undertake a seismic programme to acquire data in 2017/18 on behalf of ExxonMobil. However, an Oil Search operated 2D seismic programme, which commenced in March 2018, is not thought to be part of the final farm-in agreement but covers around 200 km over permits PPL 475, 476 and PRL 39. The data is being acquired to mature a number of leads and identify prospect information to be used in future drilling programmes.     Oil Search has completed a farm-in deal with Exxon Mobil to acquire 25% interest in PPLs 474, 475, 476 and PRL 39. Exxon Mobil continues as operator with 75% interest.","Oil Search (->55%) has bought a 25% stake in the PPLs 474, 475 and 476 and PRL 39 from ExxonMobil (->45% op.)."
81827,"In May 2020 Island Gas (subsidiary of IGas Energy Plc) acquired Total E&P UK Ltd's 20% interest in three onshore licences PEDL 273 (194 sq km), PEDL 305 (142 sq km) and PEDL 316 (111 sq km). IGas is the operator of the three licences that cover a total area of 447 sq km across blocks: SE/41e, SE/31c, SK/49, SK/59b, SK/87c SK/88b and SK/89e. Total hold no further interest in the licences and the deal marks Total's exit from the UK onshore.  All three licences are located in the East Midlands and Yorkshire. IGas is already operator of the three licences, therefore the deal has increased its interest from 35% to 55%. In 2017 Total started to reduce its stake in the three licences when INEOS acquired 30% interest from Total.   Interest in the three licences PEDL 273, PEDL 305 and PEDL 316 is held by IGas subsidiary Island Gas Ltd (55% + operator), INEOS Upstream Ltd (30%) and Egdon Resources UK Ltd (15%).","Total (20%) has exited onshore licences PEDL273, PEDL305 and PEDL316, with its 20% stake assigned to operator IGas,"
30993,"The “Leiv Eiriksson” S/S has been used by Lundin to drill an appraisal well at Alta with a 720 m horizontal section through the Permo-Carboniferous Falk and Orn formation (Gippsdalen Group) reservoir (32 m below the GOC and 12 m above the assumed OWC). 7220/11-5 S is located in PL 609 approximately 1.5 km west of 7220/11-3 and 3 km southwest of 7220/11-4 and was spudded on 6 April 2018. TD is 3,057 m (1,912 m TVDSS) in the Orn Formation and well results are better than expected with excellent reservoir quality, productivity and connectivity. A completion string was run and a two-month extended well test was carried out to monitor reservoir performance, with pressure gauges having already been installed in 7220/11-4 so that the pressure communication across the field could be observed during the testing. Over the two month period two tests were performed. A 30 day test flowed at a constrained rate of 7,500 bo/d through a 60/64” choke and a 25 day test flowed at rates of up to 18,000 bo/d through a 118/64” choke. In total 675,000 bo was produced and shipped, using the “Teekay Scott Spirit” tanker, to Mongstad. As a result of the well reserves are expected to be upgraded, with the update due to be published in early 2019. If development of Alta goes ahead Lundin is likely to use subsea wells tied-back to an FPSO. Abandonment is continuing on 1 October 2018, with the rig expected to move off location around 5 October 2018.  Alta was discovered in 2014 by exploration well 7220/11-1. The objective was a composite section of Triassic Kobbe Formation sandstones and Permo-Carboniferous weathered carbonates, sandstones and intrusives in a four-way dip closed structure. A 46 m oil column with an 11 m gas cap was proven in good quality carbonates of the Gipsdalen Group. Two tests were performed in the oil zone and flowed at a maximum rate of 3,260 bo/d plus 1.7 MMcfg/d through a 36/64” choke. Recoverable reserves were estimated at 125-400 MMboe (85-310 MMb of this being oil) at the time of discovery. However, an update in January 2018 led to a downgrading of reserves for the combined Alta and Gohta project to 115-390 MMboe (at discovery Gohta was estimated to contain reserves of 91-184 MMboe).    Two successful appraisal wells and two sidetracks were drilled at Alta in 2015, all confirming communication with the discovery well. The sidetrack of the second appraisal well, 7220/11-3 A, was re-entered in 2016 and was deepened and tested at a rate of 21 MMcfg/d through a 64/64” choke. Additionally, seawater was injected into the carbonate Falk and Orn Formations at rates of 5,000 b/d and 18,200 b/d respectively.     Appraisal well 7220/11-4 was drilled in 2017 and encountered a 4 m gas column and a 44 m oil column in Permo-Triassic clastic carbonates. Good communication with the previous Alta wells was confirmed from pressure data, with the same fluid contacts and gradients. The well was tested and flowed at a constrained rate of 6,050 bo/d through a 56/64” choke, indicating very good reservoir quality and lateral continuity through the reservoir. Sidetrack 7220/11-4 A deviated 900 m to the north and proved a 10 m gas column and a 44 m oil column in the Orn Formation with the same hydrocarbon contacts. The sidetrack was intended to help as a calibration point for 7220/11-5 S.    Interest in PL 609 is divided between Lundin Norway AS (40% + operator), DEA Norge AS (30%) and Idemitsu Petroleum Norge (30%).","7220/11-05 S (Alta) pos. appr. (Lundin op, 40%, Idemitsu 30%, DEA 30%) in PL 609, was drilled 700m horizontally in the oil zone, encountering all targeted reservoir intervals (Late Permian - Early Triassic Kobbe conglomerates and Ørn carbonates), before an extended production test was carried out. The well flowed at a constrained rate of about 7500 bo/d for 30 days [60/64” choke], and then flowed at a maximum rate of up to 18000 bo/d for 25 days (118/64” choke - constrained by surface facilities)."
33847,"Beacon Offshore Energy Exploration was formally awarded Walker Ridge Block WR 544 (G36474) as of 1 November 2018. The block is expected to expire on 31 October 2028. The block, situated in the East Texas Coastal Basin, was originally offered as part of OCS Lease Sale 251, which was held on 15 August 2018. The sale garnered 171 bids for 144 tracts in both shallow and deepwater from a total of 29 companies. According to officials, a total of US$ 178,069,406 was received in high bids. Following official award, equity in WR 544 is shared between Beacon Offshore Energy Exploration (50% WI) and Houston Energy (50%). BOE Exploration & Production operates the block.",Not Found
52304,"On 29 June 2019, Novatek announced that it had signed a Sales and Purchase Agreement with Japanese Mitsui and JOGMEC for a 10% stake in Arctic LNG 2 project in Yamalo-Nenets Autonomous Okrug (Western Siberia). The agreement also foresees a long-term LNG offtake of 2 MMtpa of LNG by Japanese partners. The deal will be finalized after regulatory approvals.  Note that on 5 March 2019, Novatek and Total SA signed a Sales and Purchase Agreement transferring to Total a 10% stake at the Arctic LNG 2 followed, on 7 June 2019, by the signature of Sales and Purchase Agreements with CNODC and CNOOC regarding the sale of 10% stakes in the Arctic LNG 2 project to each of Chinese companies. (CNODC is a wholly owned subsidiary of CNPC).  Arctic LNG 2 will include three liquefaction trains with capacity of 6.6 MMtpa each installed on gravity-based platforms in the Ob Estuary. The Salmanovskoye (Utrenneye) gas/condensate discovery is the feedstock for the LNG plant. In 2014-2017, Novatek-subsidiary Arctic SPG2 drilled six appraisal wells that resulted at extension of the discovery’s productive area and increase of its reserves. As the end of 2018, the company estimated 3P reserves of the discovery at 67.7 Tcf of gas and 840 MMbbl of condensate and oil. Salmanovskoye, discovered in 1979, is located in the South Kara-Yamal Province in the Gydan Peninsula with a minor extension to the Ob estuary. About 60 identified hydrocarbon accumulations are distributed within the 2,100 m sedimentary section aging from Valanginian to Cenomanian.",Novatek announced that it had signed a Sales and Purchase Agreement with Japanese Mitsui and JOGMEC for a 10% stake in Arctic LNG 2 project in Yamalo-Nenets Autonomous Okrug (Western Siberia).
10962,"Kosmos Energy has completed drilling the Lamantin-1 exploration well located in Block C-12 offshore Mauritania in approx. 2,200 meters of water. Lamantin-1 was drilled to a total depth of 5,150 meters and was designed to evaluate a previously untested Lower Campanian base of slope fan supplied from the Nouakchott River system, trapped in a combination structural-stratigraphic feature, and charged from underlying, oil-prone Cenomanian/Turonian and Albian source rocks. As interpreted from logs and samples collected during drilling and wireline operations, the Company's evaluation suggests the Campanian reservoir objective was water bearing with some residual hydrocarbons. Kosmos believes the prospect failed due to a lack of trap, related to a combination of up-dip sand pinch-out and top / base seal effectiveness. The well will now be plugged and abandoned and the well results integrated into the ongoing evaluation of the significant remaining prospectivity in Kosmos’ large acreage position. Andrew G. Inglis, chairman and chief executive officer, said:  'We are still in the early stages of exploring this newly emerging basin and our forward drilling program remains unchanged given the independent nature of the prospects. The drillship will now proceed as planned to test the independent Requin Tigre prospect offshore Senegal, which will be followed by two high-impact oil tests offshore Suriname in mid-2018.' The Requin Tigre prospect is a Cenomanian/Albian base of slope fan supplied from the proven Senegal River system, and is located approx. 150 kms offshore, 60 kms west of the Tortue discovery, and 80 kms north of the Yakaar discovery in approx. 3,100 meters of water. It is estimated that drilling will take approx. sixty days. Kosmos holds rights in the C-6, C-8, C-12, C-13, and C-18 contract areas under production sharing contracts with the Government of Mauritania’s Société Mauritanienne Des Hydrocarbures et de Patrimoine Minier (SMHPM). The blocks range in water depth between 100 and 3,000 meters, and have combined acreage of over 40,000 sq kms gross. Kosmos is the exploration operator of Block C-12 with 28 percent equity and is joined by its partners BP (62 percent) and SMHPM (10 percent). Original article link Source: Kosmos Energy ","Lamantin 1 op.by Kosmos (28%, BP 62%, state SMHPM 10%) in C-12 block, P&A, after encountred, previously untested, Lower Campanian water-bearing reservoir with some residual hydrocarbons. Kosmos said that “the prospect failed due to a lack of trap, related to a combination of up-dip sand pinch-out and top/base seal effectiveness”. TD=5150m."
71131,"Kina Petroleum Corp is offering an opportunity for a farm-in partner to acquire equity in exploration licence PPL 437, located in the Papuan Basin. Kina holds 57.5% interest and operatorship in the permit with partner Heritage Oil (42.5%). Kina is seeking a partner in return for funding an upcoming work programme which would ideally include much needed 2D seismic acquisition. In early-January 2020, Kina reported that, along with Heritage, it was in discussions with a potential farminee. Heritage is looking to divest its entire 42.5% interest in PPL 437. As part of a portfolio review, the company no longer sees Papua New Guinea as a core growth region and is thus looking to exit the country.  PPL 437 is located immediately north of the Elevala and Ketu fields which lay in Horizon’s operated PRL 21. Kina considers the Malisa Prospect as drill ready and the permit also contains Ebony, Mango and Ketu North prospects. Kina has submitted a permit extension application to the Department of Petroleum in a bid to continue exploration past the due expiry date of 18 February 2019. Under an extension, Kina would like to acquire seismic along the Mango, Ebony and Kandis prospects ahead of constraining and ranking.    Malisa has the potential for gas within the Kimu and Elevala/Toro formations, with Heritage reporting that it could contain 2P prospective recoverable resources of 280 Bcf gas. The licence lies in close proximity to the Elevala, Ketu, Stanley, P’nyang and Juha discoveries, meaning opportunities for development through the proposed Western LNG project or third party access to the considered P’nayng to Kutubu pipeline, should a discovery be made.     A total 170.4 km of 2D seismic was acquired over Malisa in 2014 during the Gosur Survey. Interpretation of this data was reported to be completed in 2H 2017, along with integrated aerogravity data. Initial results show significant prospectivity in the east of the permit. In addition, vintage seismic data has been reprocessed within the licence, which is now complete and fully interpreted. Once the Malisa data and reprocessed vintage seismic data have been merged, farm-in conditions and equity level will again be assessed prior to pushing the opportunity further to potential farminees.    Under the work commitments, the option existed to either drill one well or complete an additional phase of seismic in place of the well before reaching the end date of 18 February 2019. It is thought that the terms were renegotiate to allow Kina to submit an extension application in 2H 218. Drilling targets could potentially be identified through interpretation of reprocessed vintage 2D seismic data. A seismic programme was expected in 2018 which did not materialise.   Heritage farmed into PPL 437 in 2013 with the condition that Kina would be free-carried through the first seismic programme. Additional interest could be earned by Heritage (up to 50%) if the option to drill an exploration well was taken, in which Kina would also have been free carried.    Kina is also offering a farm-in opportunity in its two southern Western Province licences: PPL 435 and PPL 436, which are interpreted to extend the liquids fairway from Stanley-Tingu-Elevala-Ketu fields.    PPL 437, which covers an area of 1,537 sq km, was awarded on 19 February 2013 and is scheduled to expire on, or be eligible for renewal by, 18 February 2019.Operator Kina Petroleum Corp holds 57.5% interest with partner Heritage Oil Ltd (42.5). Kina is seeking a farm-in partner to assist in a continued exploration programme. Heritage is looking to exit the permit.    Companies interested in pursuing this opportunity should contact:  Richard Schroder – Kina, MD    Email: richard.schroder@kinapetroleum.com  Krey Stirland – Heritage Oil, Vice President Business Development    Email: krey.stirland@heritageoilltd.com","Kina Petroleum Corp offering farm-in opportunity in PPL 437, Papuan Basin"
20308,"Beach Energy Ltd spudded the Lady Bay 1 gas exploration well in PEL 630, located in the Cooper-Eromanga Basin, in late March 2018.  On 20 April 2018 Beach Energy plugged and abandoned the well, at a total depth of 3,133 m, after only encountering gas shows.  The well was targeting a possible stratigraphic trap within the Patchawarra Formation, in an underexplored section of the “Permian Edge” play fairway, as a primary objective.  As a secondary objective the well targeted the Tirrawarra Formation.  PEL 630, which covers an area of 393 sq km, was awarded on 9 September 2014.  Participants in the licence are Beach Energy Ltd (50% + Operator) and Bridgeport (Cooper Basin) Pty Ltd (50%).",Australia (Cooper - Eromanga B.s) Tirrawarra
73539,"Armstrong has acquired a 72% stake from Borealis Alaska in the latter's Castle West prospect, leases AA093758 – AA093765, Nanushuk fairway in the NPR-A.",Armstrong O&G announced that it had acquired a 72% interest in Borealis Alaskas Castle West prospect in the National Petroleum Reserve (AA093758 – AA093765).
34409,"According to local reports in November 2018, the government of Tierra del Fuego Province has given a preliminary award for the CA 12 I block to state company YPF following the call for tenders (Licitacion Nacional & Internacional No 1/2017) that ended in August 2018. No information is available regarding the expected work commitments that the company submitted in its 2-year exploration plan for the block. However, it has been said during promotional events for the call that the first exploration period should include geophysical and geological work, then followed by the drilling of an exploratory well in the second period. YPF presented a proposal to explore the CA 12 I block back in January 2017, and received the privilege of the right of preference as noted in the provincial decree No 2829 from October 2017.  The Province launched a call for tenders for the CA 12 I block, along with CA 12 II, in March 2018 after the call for the first block was originally announced in November 2017. CA 12 II (Licitacion Nacional & Internacional No 1/2018) was added into the mix in early-2018. YPF was reportedly the only company that submitted a bid for the CA 12 I block with a two-year exploration plan, while no offers were received for the CA 12 II block.  The 2,279 sq km CA 12 I block and 2,928 sq km CA 12 II are situated next to each other on the onshore side of Austral Basin.  Background Information  CA 12-1 was preliminary awarded to Roch in early-2011, although it was returned to the Province by the end of the year.",The government of Tierra del Fuego Province has given a preliminary award for the CA 12 I block to state company YPF following the call for tenders (Licitacion Nacional & Internacional No 1/2017)
25167,"In July 2018, it was reported that INEOS left licences P1026, P1191 and P1272 which contain the Rosebank discovery. Suncor acquired its 10% interest increasing its interest to 40% in each licence. Further to this deal INEOS also left licence P1830 which contains the Blackrock prospect on 29 June 2018 with Suncor acquiring its entire 25% interest in the licence. It is understood that Chevron has extended its re-tender for the Rosebank field development drilling campaign. The plan is to drill 11 top holes commencing in 2020 until 2021 lasting approximately 120 days. The main drilling programme will commence in 2022 with the drilling of 17 subsea wells – nine producers and eight water injectors. The field will be developed via a Floating Production, Storage and Offloading unit. A Final Investment Decision for the project is planned for early 2019. Seismic interpretation is ongoing over the entire licence, the results of which will be used in final prospect definition. An exploration well is planned to drill Blackrock in 2019.  Rosebank was discovered in August 2004 by well 213/27-1Z which encountered two reservoirs – Rosebank and Lochnagar - with a total net pay of 52 m. Rosebank has a Paleocene reservoir and Lochnagar has an Upper Jurassic reservoir. Appraisal well 205/1-1, drilled in 2007 on the Rosebank structure, tested 6,000 b/d of good quality oil with API values of 37°. The field is situated in water depths of approximately 1,100 m. Between April and August 2011 a 350 sq km High Density 3D OBN survey was performed over Rosebank with SeaBird’s “Munin Explorer”. This was the second phase of the Rosebank High Density 3D survey. The first stage was shot in 2010 and covered an area of 256 sq km. Front End Engineering Design studies commenced in 2012. In 2013 Chevron submitted and Environmental Statement for the project. The produced oil was to be shuttled by tanker, while gas will be exported via a newly installed pipeline. Back when the Environmental Statement was submitted it was thought that peak oil production was expected to reach 82,000 b/d with peak gas production, expected three years after the initial oil production, at 134 MMcf/d.  The Blackrock prospect is situated between the Cambo and Rosebank fields and has a Colsay / Hildasay reservoir target. The licence, P1830, was awarded in the 26th Offshore Licensing Round. The planned 2019 exploration well, if successful, could add substantial resources to the planned area development.  Interest in P1026, P1191 and P1272 is held by Chevron North Sea Limited (40% + operator), Suncor Energy (40%) and Siccar Point Energy (20%). Interest in P1830 is held by Siccar Point Energy (52.5% + operator), Suncor Energy (25%) and Shell UK Ltd (22.5%).","Ineos has withdrawn from P1026, P1191 + P1272 containing the Rosebank discovery, its 10% going to Suncor (->40%). Ineos also left P1830 (Blackrock prospect), Suncor also taking on its 25%."
50992,"On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the L42-D onshore exploration licence in the Zagros Province towards southeast of the country on 28 May 2019. The licence covers around 608 sq km area and it has been granted for a five-year term with an expiry date of 27 May 2024. TPAO is 100% owner and operator of the licence.  TPAO had filed the application for L42-D exploration licence on 26 October 2018.",TPAO has been awarded the L42-D onshore exploration licence in the Zagros Province towards southeast of the country 
66755,"In late November 2019, Beni Suef Petroleum Co abandoned the West of Nile X 31 development well at the West of Nile X field, East Beni Suef (Dev) West of Nile X block, Gindi Basin.  The well was spudded on 22 October 2019 and drilled to a TD of 2,164 m. The operator was targeting the Upper Cenomanian sandstones of the Abu Roash G Member.  The West of Nile X field was discovered in January 2015 after de new field wildcat West of Nile X 01 encountered oil in the G Member of the Abu Roash Formation. The field was developed with 16 wells, from which three were completed as water injectors. It was brought on stream in 2015.  Beni Suef Petroleum Co is a JV between EGPC (50%), Dana Petroleum (25%), Apache (16.75%) and Sinopec (8.25%). It is operating the East Beni Suef (Dev) West of Nile X block since July 2015.","Egypt (Gulf of Suez B.) ? op. by ENOC (100.0%, GUPCO 0.0%) in July block"
18533,"The ANP has formally approved ExxonMobil’s acquisition of 50% + operatorship from Queiroz Galvão in Round 13 blocks SEAL-M-351 + SEAL-M-428, total 1,513 sq km in the Sergipe-Alagoas deepwaters. Murphy Oil also farmed in for 20%, with QG retaining 30%. The deal includes reimbursement to QG of 70% of the bonus paid made for the farmin blocks (ab. USD 31.6 MM).","Brazil, SEAL-M-428The ANP has formally approved ExxonMobil’s acquisition of 50% + operatorship from Queiroz Galvão in Round 13 blocks SEAL-M-351 + SEAL-M-428, total 1,513 sq km in the Sergipe-Alagoas deepwaters. Murphy Oil also farmed in for 20%, with QG retaining 30%. The deal includes reimbursement to QG of 70% of the bonus paid made for the farmin blocks (ab. USD 31.6 MM)."
40930,"Talon has agreed to acquire EnCounter Oil Ltd through a binding HoA on the latter’s share capital. Involved are the Rocket + Skymoos prospects in licences P2363 + P2392. It is recalled Encounter has been offering equity in return for funding a GBP 9 MM well to test both prospects in the Verbier + Catcher areas. Contact: Graham Dore, Graham@encounteroil.co.uk.",United Kingdom (West Central Shelf (Central Graben)) Catcher
26724,"OMV AG, via wholly owned subsidiary OMV New Zealand Ltd. is offering up to 40% equity in its exploration permit PEP 57073, located in the East Coast Basin.  The opportunity is one of several that OMV is currently offering offshore New Zealand.  OMV reports that it ideally would like a deal with a partner that would include several assets, but would consider individual bids.    OMV has already secured one partner in the permit, with Statoil ASA (now Equinor ASA) acquiring a non-operated 30% share in February 2016.   PEP 57073 is considered frontier acreage, with only minor exploration having taken place to date. No well has been drilled within the permit, however the Tawatawa 1 and Titihaoa 1 wells, both having encountered gas shows, lie just inboard of the permit boundary. The extensive Pegasus MC3D broadband survey acquired by Schlumberger in 2016 covers a significant portion of the permit. Preliminary interpretation of the survey has defined a number of leads and prospects, both structural and stratigraphic, within the Neogene stratigraphy. The primary plays are associated with compressional related anticlines, and drape and pinch-outs of turbidite sands within inverted “mini-basins”.  A drill or drop decision is required by the joint venture by 30 September 2018. Should the joint venture commit to further work, a further 1,000 sq km of 3D seismic data would be acquired by 31 March 2019. A drill or drop decision, along with a 50% area relinquishment, would then be required by 31 March 2021, with the first exploration well due to be drilled between April 2021 and March 2022 should the permit be retained.  PEP 57073 was awarded on 1 April 2015 and covers an area of 9,800 sq km. Interests in the permit are OMV New Zealand Ltd (70% + Operator) and Equinor New Zealand BV (30%).  Interested parties should contact:  Alan Clare, Exploration & Appraisal Manager    Address: Level 20, The Majestic Centre, 100 Willis Street, Wellington 6011, New Zealand    Email: alan.clare@omv.com","OMV AG, via wholly owned subsidiary OMV New Zealand Ltd. is offering up to 40% equity in its exploration permit PEP 57073, located in the East Coast Basin.  The opportunity is one of several that OMV is currently offering offshore New Zealand. "
22360,"On 22 May 2018, Egyptian General Petroleum Corporation (EGPC) launched its 2018 bid round including 11 blocks.  Five blocks in the Western Desert: North Beni Suef (Block 5), North El Minya (Block 6), West El Fayoum (Block 7), South Abu Sennan (Block 10), Southeast Siwa (Block 11)   Two blocks in Nile Delta: South Burg El Arab (Block 6), Southeast Horus (Block 9)  Three blocks in the Gulf of Suez: South Lagia (Block 1), North Amer (Block 2) and East Badri (Block 3).     One block in the Eastern Desert: Northwest El Amal (Block 4)        The deadline for receiving bids for blocks is 8 October 2018.","On 22 May 2018, Egyptian General Petroleum Corporation (EGPC) launched its 2018 bid round including 11 blocks. Five blocks in the Western Desert: North Beni Suef (Block 5), North El Minya (Block 6), West El Fayoum (Block 7), South Abu Sennan (Block 10), Southeast Siwa (Block 11)  Two blocks in Nile Delta: South Burg El Arab (Block 6), Southeast Horus (Block 9) Three blocks in the Gulf of Suez: South Lagia (Block 1), North Amer (Block 2) and East Badri (Block 3).    One block in the Eastern Desert: Northwest El Amal (Block 4)    The deadline for receiving bids for blocks is 8 October 2018."
87019,"Polish Oil and Gas Company (PGNiG) has successfully drilled another well on the Mielec – Bojanów fields. Together with the previous wellbore in the area, the Korzeniówek-2K appraisal well will ultimately add approx. 24 mcm per year to PGNiG’s natural gas output. Korzeniówek 2-K is located in the village of Pustków,  county of Debica, in the Polish region of Podkarpacie. Exploration work in the area was commenced by the PGNiG Geology and Hydrocarbon Production Branch in late 2017, with the spudding of the first well – Korzeniówek-1K. The recorded flow of high-methane natural gas is typical of the region’s prevalent geological structure – the Carpathian Foredeep Basin miocene formation. According to PGNiG’s estimates, annual gas production from Korzeniówek-2K will be close to 17.4 mcm, plus approx. 6.6 mcm from the previously drilled Korzeniówek-1K. 'Positive results returned by another gas well drilled in Podkarpacie confirm that the region is key to ensuring Poland’s energy security,  its producing reserves play a very important role in our strategy of diversifying gas supply sources,' said Jerzy Kwiecinski, President of the PGNiG Management Board. 'Thanks to the drilling of further wells and the use of state-of-the-art digital tools in field production processes, we want to step up the domestic output of natural gas in the years to come,' he added. Both wells will be brought on stream via the existing infrastructure of the Pilzno Gas Production Facility. The PGNiG Geology and Hydrocarbon Production Branch is analysing the acquired geological and formation data, which will influence its decision to continue exploration work in the area. Original article link Source: PGNiG","Poland, not found"
12283,"Premier transferred its 30% in P1720 on 20 Dec ’17, Dyas taking over the interest in the small (7.4 sq km) permit. The licence contains part of Arran North (23/16c-8, 2002), the subject of a devt plan in 2010, still under discussion. Currently Dana (op), partner Dyas 50%.","Premier Oil exited licence P1720 with Dyas (->50%, Dana Petr. 50% + op) taking the company’s 30% interest. "
30300,"Shell Australia Pty Ltd was awarded exploration permit WA-534-P, located in the Caswell Sub-basin, Bonaparte Basin, on 20 September 2018.  The permit has been awarded for a period of six years and will expire, or be eligible for renewal, on 19 September 2024.  The permit was applied for as block W17-3 in the 2017 Offshore Acreage Release.  Work commitments have been assigned for the duration of the validity. In years one to three, which are one term and form the initial committed work programme, the operator is required to licence data from the Caswell and Heywood 3D seismic surveys and complete geological and geophysical studies. In year four, which is contingent at this stage as well as the following two years, 330 sq km new 3D seismic will be acquired. The first well is then scheduled for year five, between September 2022 and September 2023.  Finally, in year six, post well analysis and geological and geophysical studies are outlined.  Six wells are located in the permit area.  Three of these encountered gas shows: Heywood 1, Intermezzo 1 and Minuet 1.  The permit was one of three awarded to Shell on this date, with AC/P64 and AC/P65, located in the Browse Basin, also granted.  WA-534-P, which covers an area of 2,716 sq km, was awarded on 20 September 2018.  Shell Australia Pty Ltd holds 100% interest and operatorship in the permit.","Shell Australia Pty Ltd was awarded exploration permit WA-534-P, located in the Caswell Sub-basin, Bonaparte Basin,"
49096,"On 16 May 2019, the Argentine government granted AUS-105 block to Equinor following the company’s offer of USD 15.2 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019. Equinor will operate the block with 100% participating interest. Work program for the first exploration period is assumed to be limited to seismic work, as there is no drilling commitment required by the government for blocks offered in Round 1 until the second exploration period. Exploration target for the block is expected to be oil and gas in the Springhill Formation. The formation has been proven to be a producer in several gas fields in the Austral Basin, although no discoveries have been made in AUS-105.    AUS-105 covers 2,118 sq km of area on the continental shelf of Austral Basin with approximated water depth of up to 80 m.   Along with AUS-105, Equinor also received 100%-held operatorship on AUS-106 block in Austral Basin, MLO-121 block in Malvinas Basin, and CAN-108 block in Argentina Basin from Round 1. In addition, the company also won CAN-102 and CAN-114 in Argentina Basin in a partnership with state company YPF, along with MLO-123 block in Malvinas Basin as part of a consortium with YPF and operator Total.    Background Information    The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. An official resolution for granting the exploration permits is expected to be published on 1 August 2019, with official granting of the permits to follow within 15 days.","Equinor ASA received AUS-105 block from Round 1 offshore bid round, Austral Basin"
12787,"Ivory Coast awarded Tullow Oil two new oil and gas blocks on Wednesday, including one along the maritime boundary with Ghana, government spokesman Bruno Kone said. Africa-focused Tullow now holds stakes in nine Ivorian blocks, eight of which it has picked up since an international tribunal in September ruled in favour of Ghana in a dispute over the countries’ sea border. It also has a 21.33 percent position in Ivory Coast’s Espoir field, which is operated by Canada’s CNR. Speaking after a cabinet meeting, Kone said the government had awarded Tullow blocks CI-520, an onshore block near the commercial capital Abidjan, and CI-524, which is adjacent to its acreage in Ghana. Tullow operates the Jubilee oil and gas field in Ghanaian waters and is developing the TEN fields. Having emerged from one of the longest downturns in the sector’s history, Tullow is now cautiously reviving its search for new oil and gas resources in Africa and Latin America. Original article link Source: Reuters ",Tullow was awarded 2 blocks: 1 onshore CI-520 near to the Abidjan and 1 offshore: CI-524.
48297,"Oil and Gas Development Company Ltd (OGDCL) has plugged and abandoned the Qadirpur Deep X-1 deeper pool wildcat (DPW) well within the Qadirpur D&PL (Middle Indus Basin) onshore block during late April 2019 after carrying out testing. It is understood that the well was unsuccessful in finding the hydrocarbons. It was drilled to a TD of 1,454 m depth, reached in early April 2018, where a 9 5/8” casing was set. The well was spudded on 23 December 2018 using the ‘HL-17’ land rig with a prognosed TD of 4,830 m in the Cretaceous. It was mainly targeting the Cretaceous Lower Goru Formation and had an estimated cost of USD 20 million.  Qadirpur Deep X-1 was drilling at 514 m depth by the end of December 2018 and reached 1,448 m depth by the end of January 2019. The well encountered mud loss problem in mid-February 2019 after drilling to 1,454 m depth. A cementing operation was initiated in late February which was continuing till end of March 2019.  OGDCL had drilled the Qadirpur Deep 1 well in 2007 to a TD of 4,703 m in the Jurassic Chiltan Formation. Although five DSTs were undertaken (three in the Cretaceous Sembar Formation and two in the Cretaceous Lower Goru Formation), it is understood that only one DST was successful - the well reported to have flowed 4.28 MMcf/d (and 46 bw/d) from the Sembar Formation over an 18m interval between 4,478-4,496 m through a 32/64"" choke at a wellhead flowing pressure of 770 psi.   Qadirpur D&P covers an area of 389 sq km, in the Sindh province and was awarded to OGDCL on 18 August 1992. Production from the field, which is estimated to have recoverable reserves of 5.1 Tcf, is believed to have commenced in September 1995. Operator OGDCL holds a 75% stake in the lease. The remaining interest is split between Kuwait Foreign Petroleum Exploration Company (Kufpec) (13.25%), Pakistan Petroleum Ltd (PPL) (7%), and Premier Oil Plc (4.75%).    Eocene Sui Main Limestone (SML) and Sui Upper Limestone (SUL) are the main reservoirs for this field. The gas also has been discovered from Upper Eocene Habib Rahi Limestone and Cretaceous Sembar Formation.","Qadirpur Deep X 1 (OGDCL 75% op. KUFPEC 13,25%, PPL 7%, Premier Oil 4,75%) in Qadirpur D&PL block, P&A, the well was targeting Cretaceous exploratory targets under the producing Eocene Qadirpur gas field and after carrying out testing. It is understood that the well was unsuccessful in finding the hydrocarbons.."
9979,"Samarang PSC, offshore Baram Delta - Inboard Belt of NW Sabah Province, P&A results yet n/a on 22 Nov ’17, West Telesto JU. Target Upper Miocene Stage IVC/B sst. ",Malaysia (Baram Delta) Sumazau 1 op. by PETRONAS (100.0%) in Samarang block
85496,"On 14 July 2020, SDX Energy (SDX) announced the selling of its working interest in the Al-Amir JV operating the NW Gemsa concession, onshore Gulf of Suez Basin, to Gulf Energy.  Following this USD-3-million transaction, SDX will use USD1.4 million to discharge its remaining liabilities on the concession.  SDX decided in May 2020 to sell its stake in the NW Gemsa concession. The latter comprises three production fields, each located in a development block: North West Gemsa (Dev) Geyad, North West Gemsa (Dev) Al Amir and North West Gemsa (Dev) Al Ola.   The Geyad field discovered in 2009 includes three wells and has a daily production rate of 670 bbls. The Al Amir and Al Amir Southeast/Al Ola fields discovered in 2005 and 2008 have combined gross production of 3,060 bbl/d with 11 wells. All three fields have operating costs of approximately USD 10/bbl and are fully developed.   GANOPE (50%) and North Petroleum (25%, operator) are expected to remain partners with Gulf Energy (25%) in the JV.","Egypt (Gulf of Suez B.), North West Gemsa (Dev) Geyad op. by SDX ENERGY (50%), NORINCO (50%), EGPC (0%). On 14 July 2020, SDX Energy (SDX) announced the selling of its working interest in the Al-Amir JV operating the NW Gemsa concession, onshore Gulf of Suez Basin, to Gulf Energy. GANOPE (50%) and North Petroleum (25%, operator) are expected to remain partners with Gulf Energy (25%) in the JV."
26654,"Further to DEA 6 Jul ’18, officials confirmed today that Pertamina will operate the 6,264-sq km Rokan block in Central Sumatra under a gross split PSC, for 20 years starting from the expiry of Chevron’s contract in Sep ’21 until ’41.","Further to DEA 6 Jul ’18, officials confirmed today that Pertamina will operate the 6,264-sq km Rokan block in Central Sumatra under a gross split PSC, for 20 years starting from the expiry of Chevron’s contract in Sep ’21 until ’41."
8563,"PUT-4, Putumayo Basin, TD 3,865m, 5 separate oil zones encountered, cumulative 65m in the U. Pepino, Villeta N, Villeta M2 + Villeta A+B, testing planned later this month starting with Villeta B. ","Siriri 1 op. by Gran Tierra Energy (100%) in PUT 4 block, penetrated 5 separate zones having a cumulative potential net oil pay thickness of some 65 m in U. Pepino, Villeta N, Villeta M2 + Villeta A+B fms."
34715,"On 1 November 2018, Gran Tierra Energy (GTE) reported it increased its working interest from 55% to 100% in the PUT-1 Block of the Putumayo Basin. The PUT-1 Block contains the Vonu 1 multi-zone oil discovery well, drilled by GTE in 2017, along with potentially prospective areas where the prolific Cretaceous Villeta group is developed. Gran Tierra remains operator of the acreage where former partner Lewis Energy held 45% interest.  Background information  Only two wells were previously drilled on the PUT-1 Block. Texaco spudded the Alguacil 1 NFW on 23 September 1969 in a 50/50 partnership with Gulf Oil. The well was P&A as a dry hole at a depth of 10,628 ft (3,239 m) in Cretaceous age section on 23 September 1969. There were no recorded tests run in the well. The second well was drilled by the same partnership. The Tucan 1 NFW was spudded on 10 July 1969 and was P&A as a dry hole with shows on 17 September at a depth of 9,920 ft (3,024 m) in Cretaceous age section. No well tests were reported  The PUT 1 block covers 465 sq km and it was awarded to Lewis Energy Colombia (100%) on 31 March 2009.  Gran Tierra Energy Colombia farmed into the block and assumed operatorship on 24 August 2014. The current ownership of the block is GTE 55% and Lewis Energy Colombia 45%. The block has been under suspension due to community protests since early 2015.  On 5 June 2017 GTE announced a multi-zone oil discovery in its Vonu 1 new-field wildcat (NFW) located on the PUT-1 Block. Log interpretation indicated oil saturation within six separate reservoirs having a cumulative pay thickness of some 157 ft true vertical depth (TVD). The well encountered 8.2 ft of net oil pay in the Villeta N Sand Member, 3.4 ft of net oil pay in the Villeta M1 Limestone Member, 8.7 ft of net oil pay in the Villeta M2 Limestone Member, 91.1 ft of net oil pay in the Villeta A Limestone Member, 15.3 ft of net oil pay in the Villeta U Sand Member and 30.7 ft of net oil pay in the Villeta T Sand Member. GTE expects to test all zones individually during June 2017. The Vonu 1 NFW was spudded on 6 May 2017 aimed at the multi-zone structural prospect defined on 3D seismic as separate from the adjacent Costayaco field. The directional well targeted the Caballos Formation, the Villeta U, T and N Sand Members and the Villeta A Limestone Member. Gran Tierra is operator with 55% interest and Lewis Energy holds the remaining 45%.",GTE (Gran Tierra Energy) reported it increased its working interest from 55% to 100% in the PUT-1 Block.
56145,"Blocks N4, N5 + N8 were converted from explo rights into 30-year prod. Licences on 25 Jul ’19. All lies in the GEMS area, which also includes the N7c prod licence and the Geldsackplate licence in German waters. ONE-Dyas (op), partners Discover Petr. + EBN.","Blocks N4, N5 + N8 were converted from explo rights into 30-year prod. Licences on 25 Jul ’19. All lies in the GEMS area, which also includes the N7c prod licence and the Geldsackplate licence in German waters. ONE-Dyas (op), partners Discover Petr. + EBN."
73021,"As of February 2020, Oranto Petroleum International is looking for a partner on its acreage in Senegal. The company operates the Cayar Offshore Shallow and Saint-Louis Offshore Shallow blocks, M S G B C Basin, northern offshore of the country. The blocks are located east of the BP-operated GTA floating LNG project. Interested parties can view a data room at Simco Petroleum Management’s London offices.  Participants in the blocks are as follows: in Cayar Offshore Shallow (3,870 sq km), Oranto operates with 90% and Petrosen holds the remaining 10%. In Saint-Louis Offshore Shallow (5,417 sq km), Oranto operates with 80% and Petrosen holds the remaining 20%.  Two petroleum systems have been recognized on the acreage: a Turonian oil and gas system and an Albian gas and light oil system. Three main plays have been identified in the blocks:   - Slope Front Channel play 3-way dip closures faulted up dip. Paleocene, Maastrichtian, Campanian and Turonian  - Slope Front Channel play - stratigraphic trap. Paleocene, Maastrichtian, Campanian and Turonian  - Shelfal Play - faulted dip closure. Albian-Cenomanian.","Oranto Petroleum International is looking for a partner on its acreage in Senegal. The company operates the Cayar Offshore Shallow and Saint-Louis Offshore Shallow blocks, M S G B C Basin, northern offshore of the country."
44579,"PL 869 (Alvheim area), WD 120m, sidetrack of 24/9-14 S (o&g disc.), also o&g well, gross resource estimate 60-130 MMboe with part of the discovery possibly straddling the UK-Norway border. Well P&A’d 12 Mar ’19, Scarabeo 8 SS. Individual results:   - 24/9-14 S nfw: TD 2,097m (Sele fm), 30m total gas column, 38m oil column in the Hordaland group injectites, GOC encountered, but not OWC.   - 24/9-14 A appr: TMD 4,432m (1,847m TVD), several gas + oil-bearing zones totalling 540m. The gas/oil + oil/water contacts as above.   To be followed by 24/9-15 (Froskelår NE) and 24/9-13 (Rumpetroll).  Aker BP (op), partners Lundin + Vår Energi.","024/09-14 S nfw, (Froskelaar Main) (AkerBP 65%, Point Res. 20%, Lundin 15%) in PL 869, also o&g well, 30m total gas column, 38m oil column in the Hordaland group injectites, GOC encountered, but not OWC, gross resource estimate 60-130 MMboe with part of the discovery possibly straddling the UK-Norway border. 024/09-14 A appr, several gas + oil-bearing zones totalling 540m. The gas/oil + oil/water contacts as above."
20655,"PL 025, SE of Gudrun in WD ca. 105m, targets assumed Draupne & Hugin fm’s, 52-day well cleared by the NPD 3 May, spud believed imminent, Deepsea Bergen SS. Statoil (op), partners Neptune, OMV + Repsol.",Norway (South Viking Graben (Viking Graben Province)) Gudrun
45488,"Talos has agreed to sell Otto a 16.67% stake in Green Canyon block 21, home to a planned Bulleit appraisal. The deal is in exchange for Otto paying 22.22% of the well cost.  Noble Don Taylor DS starting work 2Q ’19.","Talos has agreed to sell Otto a 16.67% stake in Green Canyon block 21, home to a planned Bulleit appraisal. The deal is in exchange for Otto paying 22.22% of the well cost. "
22953,"On 22 April 2018 Statoil (now Equinor) spudded exploration well 16/1-29 S on the Lille Prinsen prospect in PL 167 using the “Deepsea Bergen” S/S. Potential recoverable reserves, according to partner Lundin, were 55 MMboe and the well had a 44% chance of success. The target was the Triassic / Lower Jurassic. The prospect lies between Hanz, Ivar Aasen and Johan Sverdrup and directly below the 2003 Verdandi oil and gas discovery. The well was cored at around 1,900 m and then had to be technically sidetracked before being drilled to TD at 2,024 m. On 3 June 2018 it was abandoned. Results are expected shortly.  Statoil had potential plans for a geological sidetrack - 16/1-29 A – which would have had a planned TD of 2,250 m.  Verdandi was drilled by Statoil with exploration well 16/1-6 S. Oil and gas were proven in the Eocene Grid Formation, gas was present in the Paleocene Heimdal Formation and the well reached TD at 1,997 m in the Ekofisk Formation. A sidetrack was drilled to further delineate the Heimdal Formation downdip but the reservoir was significantly deeper and thinner than expected and the well was abandoned as a dry hole.   Equinor Energy AS operates PL 167 with an 80% interest and is partnered by Lundin Norway AS (20%).","016/01-29 S (Lille Prinsen) (Equinor 80% op, Lundin 20%) in PL 167 P&A, the target was the Triassic / Lower Jurassic, results yet n/a.   "
79643,"Epsilon Development Company has made a new gas discovery in its Mubarek investment block in the Amu-Darya Basin. Well Beshkent Shimoliy 1 has tested 200,000 (6.85 MMscf/d) cu m/d gas and 20 t of oil (ca. 150 b/d) in an open hole test. The new discovery's reserves are estimated at 4 Bcm of gas and 300,000 t of oil (137 Bcf and 2.3 MMb). It is assumed that the hydrocarbons have been tested from the Callovian-Oxfordian carbonates.  The Beshkent Shimoliy discovery is situated north-east of the Beshkent gas-condensate and oil field. It was discovered in 1974. The field has one reservoir in Callovian-Oxfordian carbonates at a depth of 3,090 m, and its initial recoverable 2P reserves stood at 1.17 Tcf of gas and 46.4 MMb of liquid hydrocarbons.","Beshkent Shimoliy 1 nfw. (Epsilon Development Company 100%) E of Beshkent o/g/c field in XX Kultak-Kamashi block, tested 6.85 MMcfg/d + ab. 150 bo/d presumably from Callovian-Oxfordian carbs, reserves estimated 137 Bcfg + 2.3 MMbo."
18709,"SK-318 off Central Luconia Sarawak, P&A results n/a around 8 Apr ’18, Deepwater Nautilus SS. Target assumed Middle Miocene Cycle IV/V carbs. Shell (op), partners Petronas + PB ExPro (PetroBrunei sub).","Timi 1 op. by Shell (75%, Petronas 15%, PetroBrunei 10%) in SK-318, P&A results n/a, Target assumed Middle Miocene Cycle IV/V carbs. "
88542,"With the effect as of 24 July 2020, the officials in Slovakia accepted the change of the rightholding structure in the Svidnik contract in eastern Slovakia. Following the departure of a partner and the official approval, the contract became fully owned by Discovery GeoServices Corporation, acting in Slovakia through subsidiary Alpine Oil & Gas s.r.o.  The 34 sq km Svidnik permit is located some 50-80 km north-east of the city of Kosice, close to the border with Poland. In a geological sense, the area is located within the Carpathian Flysch Zone (partly in the Raca and Siary sub-units of the Magura thrust).   Background Information  The Svidnik block was initially granted to Aurelian Oil & Gas effective 1 August 2006. On 1 August 2014, the Svidnik contract was extended until 30 July 2016 and, on 1 August 2016, the validity of the contract was prolonged until 1 August 2021. At the same time, the area of the block was reduced from 469 sq km to 145 sq km. On 18 June 2018 the area of the Svidnik block was diminished from 145 sq km to 34 sq km.  On 7 April 2008, Aurelian announced it had agreed to farm-out a 25% share in the tracts to JKX. Soon thereafter, on 5 June 2008, Aurelian announced it had agreed to farm-out a 25% share in the Svidnik, Medzilaborce and Snina licences to S.N.G.N. ROMGAZ SA. On 12 November 2012, San Leon Energy plc and Aurelian Oil & Gas plc announced they have agreed on the terms of a recommended merger pursuant to which San Leon will acquire the entire issued and to be issued share capital of Aurelian. The transaction was closed in February 2013. San Leon Energy sold its 50% operating stake in the Medzilaborce, Snina and Svidnik contracts to Discovery GeoServices Corporation on 5 April 2014. By mid-2014 (possibly still in late April/May?), Discovery GeoServices Corporation effectuated change of the legal entity holding the contracts: previous owner of the concessions, Aurelian Oil&Gas Slovakia s.r.o., was changed to Alpine Oil & Gas s.r.o. In early April 2018, partner JKX Oil & Gas withdrew from the respective Concession Agreement and the Joint Operation Agreement. In June 2018, ROMGAZ SA upped its share in the Svidnik block, by acquiring a 8.33% stake (to hold 33.33%). News from early 2020 suggested that ROMGAZ had opted to withdraw from the joint-venture group.  The group active in the tract was intending since 2015 to spud a wildcat well in the block at the location Smilno (location Zborov was selected as an alternative). However, due to strong opposition of the local communities, the spud of the Smilno well was continually postponed. In summer of 2018, following the withdrawal of JKX from the consortium, the group relinquished all holdings in Slovakia, diminishing the size of the Svidnik block just to the area of the expected drilling location. The situation in late 2018 was such that, after completing an environmental assessment study for the location Smilno and Zborov in 2017 and winning access to the wellsite, the operator was hopeful to be able to commence the drilling operations. The drilling was expected take place in 2019. It is understood, the decision to pull out of the project was taken in late 2019.  The area of interest is known for past hydrocarbon production activities, for example in the vicinity of the village of Mikova. The results of magnetotelluric surveys, combined with reinterpretation of the vintage seismic data helped to identify a number of shallow prospects, with the Smilno 1 well proposed to test one of such prospects.","Following the departure of a partner and the official approval, the contract became fully owned by Discovery GeoServices Corporation, acting in Slovakia through subsidiary Alpine Oil & Gas s.r.o."
9373,"According to media reports, on 14 November 2017 the Oman Ministry of Oil and Gas (MOG) and ARA Petroleum LLC (ARA) signed an Exploration and Production Sharing Agreement (EPSA) for Block 31 (Suneinah North) following its release in the Oman Licensing Round 2016. It is assumed that Ara is 100% owner and operator of the licence.  Block 31 (Suneinah North) is situated in the Suneinah Foredeep Basin, to the north of Occidental Petroleum Corporation’s (Oxy) Block 09 (Suneinah) and Hydrocarbon Finder’s Block 15 (Jebel Aswad). There is one Cretaceous Shu’aiba Formation gas discovery located in the 8,526 sq km block, and the MOG report the tight gas Natih E play as another potential target. Previous owners include PDO, DNO and Oxy.  ARA is a new exploration and production company based in Oman which is seeking to develop oil and gas resources both at home and internationally. Initial focus will be on enhancing production from proven accumulations. In Oman, the company has interests in Block 44 (Shams) where it 100% owns and operates the licence via its subsidiary ARA Petroleum Oman Block 44. Qarat Al Milh Petroleum LLC (a wholly owned subsidiary of the Zubair Corporation and ARA) was awarded a contract to explore, develop and produce hydrocarbons within Petroleum Development Oman LLC’s Block 06 contract, in a region known as the PDO QSF area. The 24 year contract was signed on 1 September 2016 and following the passing of an audit for safe operations, work commenced on 1 March 2017. ","Oman (Oman B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Block 15 (Jebel Aswad) op. by HC FINDER (90.0%, ODIN 10.0%) to be check.Block 09 (Suneinah) op. by OXY (50.0%, OMAN OIL 45.0%, MITSUI EPM 5.0%) to be check.Block 44 (Shams) op. by ARA PETROL (100.0%) to be check.Block 06 op. by PRIMERA (100.0%) to be check."
62737,"On 1 November 2019, Africa Oil Corp announced that it confirmed its intention to acquire Petroleo Brasileiro SA (Petrobras)'s 50% in a Nigerian oil and gas venture (Petrobras Oil & Gas BV - POGBV), despite the withdrawal of the Swiss-based trading company Vitol Group and the upstream company Delonex Energy in this acquisition. Africa Oil Corp remains the sole buyer. The new venture POGBV had 16% working interest in Total-operated OML 130 (Akpo and Egina producing/developing fields), 12.49% in Chevron-operated Agbami producing field, and also 8% working interest in Chevron-operated OML 127 block.  Africa Oil President and CEO Keith Hill commented “Africa Oil Corp considers this to be a unique and transformational opportunity to acquire an increased interest in world class producing assets operated by Chevron and Total"".  In early 2019, it was understood that the buyer will have to pay at least USD 1.4 Billion for the Brazilian company’s 50% holding in POGBV. The other 50% stake is owned by Brazilian investment bank BTG Pactual, which intends to keep its stake for now. The deal is not expected to be ratified by the authorities before year-end 2019.  The Brazilian company originally agreed on 31 October 2018 to sell its 50% stake in a Nigerian oil and gas venture to a consortium led by Vitol Group (50%) partnering with Delonex Energy (25%) and Africa Oil Corp (25%).  This divestiture plan from Brazilian company Petrobras had already been initiated in May 2016, when Brazilian bank BTG Pactual was also looking at selling its stake in the Petrobras Oil & Gas BV joint venture (POGBV). Since 2013, POGBV relinquished assets in Angola, Benin, Gabon, Namibia, and Tanzania.   Background Information  In June 2013, Petrobras’ affiliate Petrobras International Braspetro B.V. (PIBBV) concluded a USD 1.525 billion deal with investment bank BTG Pactual for a 50% stake in its various Exploration and Production projects in Africa. The Joint venture was formed via BTG Pactual and its clients acting through the BTG Pactual Vehicle, acquiring a 50% stake in Petrobras Oil & Gas B.V (formally a 100% owned subsidiary of PIBBV). Upon conclusion of the deal the bank acquired interests in Angola, Nigeria, Libya, Benin, Gabon, Namibia and Tanzania.  In early May 2018, three groups of trading and upstream companies reportedly submitted bids to acquire Nigerian Petrobras stakes. Vitol’s consortium appeared as the preferred bidder, while other interested parties included Glencore (together with Nigerian company Seplat and Maurel & Prom) and Famfa Oil, together with Royal Dutch Shell.","Nigeria, OML 127"
51020,"On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the L41-C1,C2,C3 onshore exploration licence in the Zagros Province towards southeast of the country on 28 May 2019. The licence covers around 456 sq km area and it has been granted for a five-year term with an expiry date of 27 May 2024. TPAO is 100% owner and operator of the licence.  TPAO had filed the application for L42-D exploration licence on 26 October 2018.","TPAO has been awarded the L41-C1,C2,C3 onshore exploration licence in the Zagros Province towards southeast of the country "
69197,"According to press, Repsol could be looking at a sale of its local upstream operations, potential suitors PTTEP or Mubadala. One explo + 5 devt blocks would be involved, total 3,100 sq km on & offshore. Early days yet.","According to press, Repsol could be looking at a sale of its local upstream operations, potential suitors PTTEP or Mubadala. One explo + 5 devt blocks would be involved, total 3,100 sq km on & offshore. Early days yet."
50012,"Beach advises that the sale of a 40% interest in its Otway assets to O.G. Energy is now complete. TheAUD 344 MM deal was announced last October and is retro-effective 1 Jul ’18. Beach retains 60% + operatorship, of which the Geographe, Thylacine, Halladale, Speculant, Black Watch + La Bella gasfields, the Enterprise + Artisan prospects and the Otway gas plant. Map of permits involved courtesy Beach:",Beach advises that the sale of a 40% interest in its Otway assets to O.G. Energy is now complete. TheAUD 344 MM deal was announced last October and is retro-effective 1 Jul ’18
20822,"Tri-Star Petroleum Co acquired full interest from Senex Energy subsidiary Stuart Petroleum Pty Ltd in exploration licences PEL 288, PEL 289, PEL 290 and PEL 331, located in the Cooper-Eromanga Basin, on 14 February 2018.  Stuart Petroleum previously held 100% interest and operatorship, all of which has been transferred to Tri-Star.  The licences cover a combined area of 33,105 sq km and were all awarded on 1 June 2013.  No wells have yet been drilled within the licence’s validity, but a number of historical wells lie within the licence areas.","Australia, PEL 331"
9648,"Frontera Energy in November 2017 announced, that the Agencia Nacional de Hidrocarburos (ANH), on 22 September 2017, had approved the transfer of Frontera's interests in a number of Caguan-Putumayo Basin assets, to Amerisur Resources. The transfer is subject to execution of a formal amendment. Amerisur previously announced in March 2017 that it is acquiring working interest from Frontera (then Pacific E&P) in the following blocks:->60% in PUT-9->58% in Mecaya->100% in Terecay->50.5% in TacachoThe total consideration for these transactions was US$4.85MM. Also, a 2% Overriding Royalty Interest (ORRI) will be payable to Pacific E&P in respect to Amerisur net production from the Terecay Block and a 1.2% ORRI on net production from the PUT-9 Block. The Chief Executive Officer of Amerisur, John Wardle, said, ""I am very pleased to announce this important acquisition which positions Amerisur for significant growth in the Caguan-Putumayo basin. The working interests we have acquired are strategically located close to our OBA transfer system, thus potentially securing rapid and basin leading margin monetisation of new reserves in these blocks, and expose the Company to the full suite of exploration opportunity in the basin.""<P />",Not Found
27770,"Bajada de Añelo block, Neuquén Basin, P&A Jun ’18, no details. Target Vaca Muerta.","Bajada de Añelo block, Neuquén Basin, P&A Jun ’18, no details. Target Vaca Muerta."
15456," Pacora-1 well encounters approx. 65 feet of high-quality, oil-bearing sandstone High quality resources to be integrated into giant Payara field development Further drilling on the Stabroek Block planned in 2018 ExxonMobil has announced its seventh oil discovery offshore Guyana, following drilling at the Pacora-1 exploration well. ExxonMobil encountered approx. 65 feet (20 meters) of high-quality, oil-bearing sandstone reservoir. The well was safely drilled to 18,363 feet (5,597 meters) depth in 6,781 feet (2,067 meters) of water. Drilling commenced on Jan. 29, 2018. 'This latest discovery further increases our confidence in developing this key area of the Stabroek Block,' said Steve Greenlee, president of ExxonMobil Exploration Company. 'Pacora will be developed in conjunction with the giant Payara field, and along with other phases, will help bring Guyana production to more than 500,000 barrels per day.' The Pacora-1 well is located approx. four miles west of the Payara-1 well, and follows previous discoveries on the Stabroek Block at Liza, Payara, Liza Deep, Snoek, Turbot and Ranger.The Pacora-1 well is located approx. four miles west of the Payara-1 well in the Stabroek block Following completion of the Pacora-1 well, the Stena Carron drillship will move to the Liza field to drill the Liza-5 well and complete a well test, which will be used to assess concepts for the Payara development. ExxonMobil announced project sanctioning for the Liza phase one development in June 2017. Following Liza-5, the Stena Carron will conduct additional exploration and appraisal drilling on the block. The Stabroek Block is 6.6 million acres (26,800 sq kms). Esso Exploration and Production Guyana is operator and holds 45 percent interest in the Stabroek Block. Hess Guyana Exploration holds 30 percent interest and CNOOC Nexen Petroleum Guyana holds 25 percent interest. Original article link Source: ExxonMobil ","Pacora 1 op. by ExxonMobil (45%, Hess 30%, CNOOC Nexen 25%) in the Stabroek block, reportedly discovery (7th in block), struck 20m of what Hess termed ""high-quality, oil-bearing sandstone reservoir""."
65538,"P2358 / block 12/23c, Moray Firth, WD 106m, TD in Valhall sands, oil indications over 6m in the target Captain sands, OWC at 1,606m matching the regional expectation depth, and a substantial residual oil column was found below the OWC. Well P&A'ing as planned, Borgland Dolphin SS to be released (conclusion of 2019 drilling programme).  Plans are now for a multi-well appraisal of Serenity and the Liberator West in summer 2020. Release from i3 Energy.","013/23c-11 Liberator A2 (13/23c-A3-L2)) appr/devt, P2358 / block 12/23c, TD in Valhall sands, oil indications over 6m in the target Captain sands, OWC at 1606m, logging still required. WD=106m."
15036,"Sebou permit, onshore Rharb Basin, location on upthrown side of the main bounding fault in the Ksiri area, TD 1,293m, 8m net high quality reservoir in the Gaddari and Guebbas sequences, avg porosity 30% but low gas saturation and deemed non-commercial, well to be P&A’d. Rig to SAH-2 on the downthrown side of the fault. ","Ksiri South 2 op. by SDX Egy. (75%, ONHYM 25%) in Sebou block, P&A, non commercial gas disc. encountered 8m net of high-quality reservoir in the Gaddari and Guebbas sequences, however, with low gas saturation."
34822,"Chenjia area of Xinglongtai buried hill field, West Sag of Liaohe Depression in the Bohai Gulf Basin, tested 355 bo/d + 208 Mcfg/d from between 3,732-3,783m. Target Mesozoic basement reservoir.","Chenjia area of Xinglongtai buried hill field, West Sag of Liaohe Depression in the Bohai Gulf Basin, tested 355 bo/d + 208 Mcfg/d from between 3,732-3,783m. Target Mesozoic basement reservoir."
74484,"APLNG was awarded gas production licence PL 1084, 18 sq km of coal seam gas exploration tenure in the Bowen-Surat Basin, on 11 Mar '20 over former ATP 2046-P and previously PLR2018-1-2 in the 2018 QLD acreage release. It contains the 1983 Xyloleum gas discovery. APLNG (op), partner Armour Egy. Mar & release here.",APLNG (Australia Pacific LNG Pty Ltd) was awarded production licence PL 1084.
66092,"Add. DEA 18 Nov '19: Commitment well in W-C part of AE-0008-4M-Amoca-Yaxche-06 block, offshore Sureste Basin, WD 26m, P&A dry at TMD 2,112m on 7 Oct '19, Independencia I JU. Target U. Miocene.","Itta 1EXP nfw Commitment well in W-C part of AE-0008-4M-Amoca-Yaxche-06 block, offshore, WD 26m, P&A dry at TMD 2,112m on 7 Oct '19, Independencia I JU. Target U. Miocene."
63848,"FAR is on the lookout for partners in its renewed blocks A2 + A5, MSGBC deepwaters. Plans include 3D seismic in A5 and subsequent drilling, several prospects at hand. FAR (op), partner Petronas. Contact Peter Nicholls, p.nicholls@far.com.au. More from GEPS.","FAR is on the lookout for partners in its renewed blocks A2 + A5, MSGBC deepwaters. Plans include 3D seismic in A5 and subsequent drilling, several prospects at hand. FAR (op), partner Petronas. "
63773,"Hess was awarded Mississippi Canyon blocks MC 683 (G36776) and MC 727 (G36780) on 1 November 2019. The blocks are sited in the Louisiana Coastal Basin and were originally offered as part of OCS Gulf of Mexico Lease Sale 253, which was held on 21 August 2019 and garnered more than US$ 159 million in high bids. Hess accounted for six of these high bids, worth a total of US$ 8.3 million. Following official award, Hess is now the operator and sole interest-holder (100% WI + Op) in MC 683 and MC 727.",Hess was awarded Mississippi Canyon blocks MC 683 (G36776) and MC 727 (G36780) 
39024,"Eni and OOCEP signed on 14 Jan ’19 for PSC rights to block 47,  8,524 sq km in the A’Dakhiliyah governorate and issued in the 2017 Oman round. Eni (op, 90%), partner OOCEP.   Eni and BP have also signed a HoA which will lead to E&P rights to block 77,  3,100 sq km, in the area of BP’s Khazzan field. Following signature of the PSA, Eni (op), partner BP 50:50.   Meanwhile some 2,500 sq km of 3D seismic are about to start in Eni’s block 52 (Juzor Al Hallaniyyat), Polar Empress SV.","Eni and OOCEP signed on 14 Jan ’19 for PSC rights to block 47,  8,524 sq km in the A’Dakhiliyah governorate and issued in the 2017 Oman round. Eni (op, 90%), partner OOCEP. "
66808,"United Oil & Gas announced on 17 July 2019 that it had signed a non-binding Heads of Terms agreement to sell its interest in licence P2366 (blocks 15/18d and 15/19b) to Anasuria Hibiscus UK Limited. In an update on 7 October 2019 it was confirmed that the Sale and Purchase Agreement (SPA) had been signed. United Oil and Gas was awarded the licence in the 30th Offshore Licensing Round. The acreage contains the Crown discovery. The signing of the SPA triggered a payment of USD 100,000 from Hibiscus to United Oil and Gas. Following the approval from the OGA which was confirmed on 12 December 2019 a further payment of USD 900,000 will follow. USD 50,000 of this total is payable to Swift Exploration which held a 5% interest in the licence. Subject to further milestones being agreed an additional sum of USD 3 million will be paid before the end of 2020 and then a further USD 1 million paid once the field is on production.   Crown was discovered by ConocoPhillips by exploration well 15/19-9 in 1998. The well was drilled to test a four-way dip closed structure and encountered oil and gas in the Balmoral Sandstone Member. The sands were good quality with a net to gross in the region of 35-90%. United Oil and Gas published the results of a Competent Persons Report on 1 February 2019 which estimated the Crown discovery to hold 2C gross unrisked contingent resources of 6.35 MMbbl STOIIP. The work programme involved rock physics modelling and seismic reprocessing.  Interest and operatorship in P2366 is now held by Anasuria Hibiscus UK Limited (100%).","United Kingdom, P2366"
67320,"Novatekl won an auction yesterday for 25-year rights to the Ladertoyskiy Vostochnyy block, 952 sq km undrilled in the South Kara-Yamal Province. Starting price was USD 1.15 MM, obtained for USD 1.29 MM.","Novatekl won an auction yesterday for 25-year rights to the Ladertoyskiy Vostochnyy block, 952 sq km undrilled in the South Kara-Yamal Province. Starting price was USD 1.15 MM, obtained for USD 1.29 MM."
11370,"A purchase + sale agreement reached 1 Apr ’17 for the acquisition of block 1-2006 PSC from City Peten has been terminated. The 395-sq km block 1-2006 lies in the Chapayal Basin, the cash-and-share deal had been costed at USD 58.13 MM. City was also to grant Oronova the right to acquire up to 100% in adjacent block 1-2011 (Yalcanix), 1,527 sq km:  ","Guatemala, 1-2011"
86477,"On 17 July 2020, the Bureau of Ocean Energy Management (BOEM) announced that it will offer ~318,892 sq km (~78.8 million acres) for a new region-wide lease sale, Lease Sale 256, slated for November 2020. The lease sale will encompass approximately 14,755 unleased blocks, including all of the available unleased areas in federal waters of the Gulf of Mexico. “The Gulf of Mexico provides a fundamental role for our nation’s energy portfolio,” said Mike Celata, Director of BOEM’s Gulf of Mexico Region. “As one of the most productive basins in the world, the development of its resources is essential to our nation’s energy security.” Lease Sale 256 will represent the seventh offshore sale under the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Programme and will be livestreamed from New Orleans. The Gulf of Mexico Outer Continental Shelf (OCS), covering about 160 million acres, is estimated to contain about 48 billion barrels of undiscovered technically recoverable oil and 141 trillion cubic feet of undiscovered technically recoverable gas. On 18 March 2020, the US Bureau of Ocean Energy Management (BOEM) held Gulf of Mexico Lease Sale 254, which attracted a total of US$ 93 million in high bids, a sharp ~42% (US$ 66.3 million) drop compared to the total amount bid in preceding GOM Lease Sale 253, which was held on 21 August 2019 and garnered US$ 159.3 million in high bids. BHP submitted the highest amount for Green Canyon Block GC 80, with an US$ 11.1 million bid. More information on Gulf of Mexico Lease Sale 256 is available at: <A HREF=""https://www.boem.gov/Sale-256/"">https://www.boem.gov/Sale-256/</A>.","The Bureau of Ocean Energy Management (BOEM) announced that it will offer ~318,892 sq km (~78.8 million acres) for a new region-wide lease sale, Lease Sale 256, slated for November 2020. The lease sale will encompass approximately 14,755 unleased blocks, including all of the available unleased areas in federal waters of the Gulf of Mexico. "
8871,"On 3 November 2017, TransGlobe Energy Corp (TransGlobe) abandoned the Boraq 5ST2 appraisal well in South Alamein exploration block in the Alamein Sub-basin, Western Desert. The well has failed to produce hydrocarbons form two tested zones namely the Lower Abu Roash “G” carbonate Unit and the Abu Roash “E” sand Unit. The original hole Boraq 5 was drilled in mid-May 2017 before being plugged the first time at a depth of 1,441 m. A second sidetrack was drilled on 31 May 2017 and cased on 9 June 2017 after the well encountered up to 5 m estimated pay in A/R-G Unit, however it missed A/R-E Unit. Background information On 31 May 2009, Cepsa suspended the Boraq 1 wildcat in South Alamein exploration block after reaching TD of 4,485m. The well was spudded on 4 February 2009 using the L/R ""Sino Tharwa-12"". The PTD is 4,535m, expected in the Bahrein Formation and the Jurassic is the target. Cepsa was still discussing the farm out of 50% interest in the South Alamein exploration block covering 3,228 sq km to El Paso. The company signed the agreement for the concession on 5 April 2007. The contract is valid for a first period of three years, and work commitments include seismic acquisition and the drilling of several exploration wells. The block was offered as Block 9 under terms of the 2005 Bid Round by EGPC.  In August 2009, Cepsa supended the Boraq 2 exploration well in South Alamein exploration block in the Alamein Sub-basin as an oil discovery. The well reached TD of 3,250 in the Alam El Bueib Formation on 26 July 2009. The well was spudded on 14 June 2009 with a PTD of 3,200m and the Cretaceous section as the target.  In late October 2009, Cepsa suspended the Nawwar 1 wildcat in South Alamein exploration block in the Alamein Sub-basin, Western Desert after reaching TD of 2,857m in the Masajid Formation. The well was spudded on 4 September 2009 using the L/R ""Sino Tharwa-12"".  On 21 February 2010, Cepsa suspended the Noran 1 wildcat in South Alamein exploration block in the Alamein Sub-basin, Western Desert after reaching  TD of 4,469m. The well was spudded on 11 November 2009 using L/R ""SinoTharwa-12"" with objectives in the Cretaceous sediments and the Jurassic Lower Safa Formation.  On 24 June 2010, Cepsa suspended the Thanaa 1 wildcat in South Alamein exploration block in the Alamein Sub-basin, Western Desert after reaching TD of 4,425m in the Jurassic sediments. The well was spudded on 7 March 2010 using L/R ""SinoTharwa-12"" with objectives in the Bahrein, Kahataba and Safa formations.  On 30 July 2013, TransGlobe closed the Share Purchase Agreement (""SPA"") and acquired the shares of Cepsa Egypt SA B.V. (""Cepsa Egypt""), a wholly owned subsidiary of COMPAÑÍA ESPAÑOLA DE PETRÓLEOS, S.A.U. (a company registered in Spain) (""Cepsa"") which holds a 50% working interest in the South Alamein Concession. The remaining 50% working interest was acquired on 7 June 72012 from EP Energy LLC. The South Alamein Concession is located onshore in the Western Desert of Egypt and includes portions of the prolific Alamein and Tiba basins. The current gross size of this exploration concession is 1,423 square kilometers (355,832 acres) following a 25% relinquishment of non-prospective acreage on 4 April 2012. The concession is in the final 2-year exploration phase. The concession includes the Boraq 2 oil discovery. The primary Cretaceous zone tested at a rate of 800 to 1,323 bo/d of 34 °API oil with no water and a 13% pressure drawdown. The company said test rates are not necessarily indicative of long-term performance but it is anticipated that when combined with secondary tested zones within the Cretaceous, the well should be capable of initial production of approximately 1,700 bo/d. In early November 2013, TransGlobe abandoned the Taef 1 exploration well in South Alamein exploration block in the Alamein Sub-basin as a dry hole after reaching TD of 2,266 m. The well was spudded in mid-October 2013. ",Egypt (Northern Egypt B.) Boraq 5 op. by TRANSGLOBE (100.0%) in South Alamein/A block
84509,"On 30 June 2020 Gidgee Energy Pty Ltd was announced as preferred tender for the bid block CO2019-D, located in the Cooper-Eromanga Basins. The block, which will be granted as petroleum exploration licence PELA 679, was released as part of the 2019 South Australian Acreage Release and covers an area of approximately 742 sq km.     Gidgee has proposed firm work commitments for the first five-year term of the permit and includes the drilling of a minimum of seven wells, with the option to drill an eighth if required. The total guaranteed work programme costs will be AUD 23.45 million.    Native Title approvals are required before the South Australian Government can formally award the permit. Once granted, Gidgee Energy will hold 100% interest and operatorship.    CO2019-D, which covers an area of 742.24 sq km, is one of six blocks to be awarded by the South Australian Government following the successful 2019 bid round in the Cooper and Otway Basins. Six companies have been awarded interest along with Gidgee Energy, including Beach Energy Ltd, Cooper Energy, Leigh Creek, Oilex/Armour (Cordillo Energy) and Vintage Energy. The total acreage awarded covers around 15,000 sq km.","Oilex sub Cordillo has been successful in its application for block CO2019-D, in the Northern O&G Fairway of the Eromanga Basin. Commitments include 250 sq km of 3D seismic + 2 wells in 5 years. The block is part of Oilex's proposed sale to Armour Energy."
27468,"Equinor Brasil Energia Ltda concluded operations on the Guanxuma B (1-STAT-010B-SPS) side-track wellbore in the BM-S-008 contract evaluation area and is assumed to have suspended the well with results unreported on about 9 August 2018 prior to the spudding of the second side-track wellbore from the same surface location.  There were no show reports filed to date with the ANP for this wellbore.   The side-track wellbore was spudded on 30 July 2018.  The operator suspended with oil shows the Guanuxma A (1-STAT-010A-SPS) prior to spudding the first side-track wellbore at the same surface location and it is speculated the well was a directional geological side-track.  The NFW had reported proposed total depth (PTD) of 6,630 m and was targeting the pre-salt Early Cretaceous Barra Velha and Itapema formations.  Statoil utilized the SeaDrill “West Saturn” D/S to drill the well.    On 10 January 2018, Equinor Brasil Energia Ltda was granted a drilling permit to drill the Guanxuma and other prospects and appraisal wells in the BM-S-008 contract evaluation area by environmental authority IBAMA.    The rig first conducted a cased hole formation test of the 3-SPS-104DA (3-BRSA-1216DA-SPS) outpost and prior to moving to the Guanxuma prospect.  The Carcara prospect area is to be unitized with the Norte de Carcara block that Statoil and partners acquired through the 2nd PSC Pre-Salt Bid Round.      The      Guanxuma NFW is located approximately 31 km southwest of the Carcara      discovery in the southwestern area of the block. The structure has at least two culminations and Statoil will test      the northwestern area of the structure with an appraisal well.  Two additional appraisal wells are      planned for the structure if it is productive, one offsetting the Guanxuma      1 prospect and the other offsetting the Guanxuma NW prospect.  Former operator Petrobras had plans to      drill the well for several years.    Equinor Brasil Energia Ltda has a blanket permit to drill a total      of seven wells, two new-field wildcats (NFW), and five appraisal      wells.  Additionally the permit      covers conducting a formation test of the 3-SPS-104DA (3-BRSA-1216DA-SPS)      outpost that is part of the discovery evaluation plan (PAD)      commitments.  The two NFWs include      the Guanxuma prospect and a new prospect, the Urtiga prospect. The      appraisal wells include the Carcara NW that is located to the northeast of      the 3-SPS-104DA outpost and there will be three appraisal wells on the Guanxuma      structure if found productive and one appraisal scheduled for the Urtiga      structure if productive.  The      original provisional schedule was for the operator to commence drilling      the first well in 3rd quarter 2017, the testing of the      3-SPS-104DA outpost and drilling of two wells in 2018, the drilling of two      wells in 2019, and the final two wells in 2020 that may extend into      2021.  The timing of the drilling      changed with the operator waiting to bid on the Carcara Norte block in the      2nd Pre-Salt Bid Round, and the entry of new partner Exxon      Mobil.    The Urtiga prospect is located approximately 23      km west of the Carcara structure and is a new prospect developed by the      operator.  The operator plans for      one southeastern appraisal if the structure is productive.    Current      working interest breakdown in the contract is Equinor Brasil operator with      40% working interest, Exxon Mobil with 40% working interest, and Petrogal Brasil Ltd (Galp Energia) with      a 20% working interest pending formal approvals for the 10% Barra working      interest acquisition.    On      4 July 2018, Equinor issued a press release indicating it signed an      agreement to acquire the 10% working interest in      the BM-S-008 contract, Carcara discovery evaluation area held by Barra      Energia for USD 379 million pending formal governmental approvals.  Once formal approvals are granted, the      operator will then sell and assign 6.5% of the 10% to partners ExxonMobil      and Petrogal in order to equalize working interest in the BM-S-008 contract      and contiguous PSC contract Norte de Carcara block.  The Barra working interest represents      the last piece of the puzzle here for Equinor to move forward with      development of the unitized Carcara discovery development which it hopes      to bring on-stream by 2023 to 2024.       It reported that total estimated recoverable reserves are 2      Bboe.       On      31 January 2018, the consortium of Statoil      operator with 40% working interest, ExxonMobil with 40%, and Petrogal with      20% was granted an official award for      the Norte de Carcara block from the 2nd PSC Pre-Salt Bid Round.  The      PSC contract has a three year exploration-evaluation phase and the minimum      work program is to drill one appraisal well.      On 28 November 2017, the ANP officially approved of the 10% working interest acquisition by Statoil from Queiroz Galvao in the BM-S-008 contract Carcara discovery evaluation area.  The total transaction value was USD 379 million.  Statoil paid Queiroz Galvao 50% or USD 189.5 million with the formal governmental approvals and the remaining 50% when certain conditions are met such as unitization with the Norte de Carcara block that Statoil and partners won in the 2nd PSC Pre-Salt Bid Round.  The conclusion of the unitization process likely a year or two in the future.  The resulting working interest breakdown in the BM-S-008 contract with the formal governmental approval is Statoil operator with 76% working interest, Petrogal Brasil Ltd (Galp Energia) with a 14% working interest, and Barra Energia with a 10% working interest.  Also ExxonMobil farmed-in to the contract on 27 October 2017.  Once the ExxonMobil farm-in for 36.5% is approved the resulting working interest breakdown in the BM-S-008 contract will be Statoil operator with 36.5% working interest, ExxonMobil with 36.5% working interest, Petrogal Brasil Ltd (Galp Energia) with a 17% working interest and Barra Energia with a 10% working interest.       On 27 October 2017, Statoil announced that it concluded a farm-out agreement with ExxonMobil for the discovery evaluation plan (PAD) PA_4BRSA971BSPS_BM-S-8 of the BM-S-008 contract, Carcara discovery.  The transaction was announced after the results of the 2nd Pre-Salt Bid Round whereby the consortium of Statoil (40%), Exxon Mobil (40%), Petrogal (20%) won the Norte de Carcara block with a bid of 67.12% state take won the Norte de Carcara block plus the fixed bid of USD 910 million (1USD = 3.3 BRL).  The transaction is complex with two different fiscal regimes and different working interest as well as formal approvals for the pending 10% working interest acquisition in the BM-S-008 contract by Statoil from Queiroz Galvao.  In its press release Statoil indicated that its portion of the bonus is approximately USD 364 million for its 40% working interest in the Norte de Carcara block.  For the BM-S-008 contract, the transaction has two phases.  The first phase is that Statoil divested 33% of its 66% working interest to Exxon Mobil for a total consideration of USD 1.3 billion, USD 800 million in an upfront payment and a contingent cash payment of approximately USD 500 million.  Additionally upon the formal approvals and closing of the 10% working interest from Queiroz Galvao, Statoil will divest 3.5% of the 10% to Exxon Mobil and 3% to Galp for a total consideration of USD 250 million, USD 155 million as an upfront payment and USD 95 million as a contingent cash payment.  The resulting working interest breakdown in the BM-S-008 contract will be Statoil operator with 36.5% working interest, Exxon Mobil with 36.5% working interest, Petrogal Brasil Ltd (Galp Energia) with a 17% working interest and Barra Energia with a 10% working interest.  All the partners have agreed that Statoil will be operator of the unitized field development subject to ANP approval.  The discovery evaluation plan (PAD) PA_4BRSA971BSPS_BM-S-8 was modified in August 2017 pending results of the 2nd Pre-Salt Bid Round but now can move forward once the contract for the Norte de Carcara block is signed.  Statoil has provisional plans to drill several wells in the contract including two new-field wildcats.     On 23 August 2017, the ANP granted Statoil approval for an extension and modification to the discovery evaluation plan (PAD) PA_4BRSA971BSPS_BM-S-8 of the BM-S-008 contract, Carcara discovery.  The ANP granted the operator an extension of six months after the contract is signed for the Norte de Carcara block on offer in the 2nd PSC Pre-Salt Bid Round for the joint block owners to file a combined discovery evaluation plan (PAD).  The PAD has a current final expiry date of 1 March 2018 which will be extended once the joint PAD is filed and approved.  The contracts from the bid round are scheduled to be signed in early 2018, which would give the PAD a date of approximately 29 July 2018 for the companies involved to file the joint PAD.    On 14 September 2000, Petrobras, operator (50%), Shell (40%) and Petrogal (10%) were originally awarded the 4,865 sq km BM-S-008 contract through the ANP Round 2.  Through various relinquishments and partnership changes during the contract phases the contract now covers 815.22 sq km as a discovery evaluation plan (PAD).  The PAD has been extended and modified a number of times since the original contract expired on 9 August 2010 and now has a final expiry date of 1 March 2018.   Petrobras was granted approvals by the ANP on 8 January 2014 for a modified discovery evaluation plan (PAD) for the 2,089.51 sq km Santos Basin BM-S-008 contract, PA_1BRSA532ASPS_BM-S-8, evaluation area that also included a partial relinquishment and modification of the PAD nomenclature to reflect the Carcara discovery well, the PA_4BRSA971BSPS_BM-S-8.  Originally the PAD was granted based on the 1-SPS-052A (1-BRSA-532A-SPS) Bem-Te-Vi prospect but the area around the well was relinquished with the modified PAD approval.  On 30 March 2016 the ANP approved a second modification to the PAD.  The modification included substituting the long term cased hole production test of the 3-SPS-104DA (3-BRSA-1216DA-SPS) directional outpost with the drilling of the 3-SPS-105 (3-BRSA-1290-SPS) outpost.  The operator was required to maintain the commitment to conduct a cased hole formation test of the 3-SPS-104DA (3-BRSA-1216DA-SPS) and to drill the Guanxuma prospect.",Equinor Brasil Energia Ltda concluded operations on the Guanxuma B (1-STAT-010B-SPS) side-track wellbore in the BM-S-008 contract evaluation area and is assumed to have suspended the well with results unreported on about 9 August 2018 prior to the spudding of the second side-track wellbore from the same surface location.  There were no show reports filed to date with the ANP for this wellbore. 
47717,"Add. DEA 18 Dec ’18 : AE-0028-2M-Cotaxtla-01 block, SE of Ixachi find in onshore Veracruz Basin, confirmed P&A dry, but on 2 Feb ’19 at TD 7,868m. Target M. Cret. Orizaba carbs.","Cruver 1EXP (Pemex 100%) in the AE-0028-2M-Cotaxtla-01 entitlement onshore block, P&A dry. PTD of the well was 7,722 m and the fractured Middle and Lower Cretaceous Orizaba Fm was the main objective."
35681,"LLA 23, Llanos Basin, TMD 3,437m (Ubaque fm), 3m potential net oil pay in each of the Gacheta D2 + D3 sands, and 7m in the Ubaque. Thinner zones of potential pay were also interpreted in the Mirador C7. Testing is planned.","Colombia, LLA 23"
33941,"On 1 November 2018 OMV Petrom reported that the takeover of Repsol’s interest in the V Baicoi deep, VI Targoviste deep, XII Pitesti deep and XIII Targu Jiu deep blocks has been approved by the National Agency for Mineral Resources (NAMR). In Q2 2018 Repsol had notified OMV Petrom of its intention to exit the four blocks where it held 49% interest. The blocks are situated in the southeastern part of the country.  Repsol was officially granted the 49% interest in the deep blocks (below 2,500 m) by NAMR on 17 September 2013. The investments done by Repsol and OMV Petrom amount to more than USD 200 million. It includes 2D and 3D seismic surveys and the drilling of two deep wells. A third exploration well is currently in the drilling phase below 5,000 m.  Interest in the four licences is now solely held by OMV Petrom SA.","OMV Petrom reported the takeover of Repsol’s interest in the V Baicoi deep, VI Targoviste deep, XII Pitesti deep and XIII Targu Jiu deep blocks "
16621,"Petsec Energy has completed the transaction with Oil Search to acquire all of the shares of its subsidiary Oil Search (ROY) Limited which holds a 40% working interest (34% participating interest) in the Al Barqa (Block 7) licence and operatorship, in the Republic of Yemen. Completion of the Oil Search agreement follows the 2016 transaction with KUFPEC (25% working interest) to acquire their interests in Block 7, and the transactions with AWE (25% working interest) and Mitsui E&P Middle East (10% working interest) completed and approved by the Yemen Ministry of Oil and Minerals in 2014. The acquisition of Oil Search (ROY) Limited increases Petsec’s potential working interest in Block 7 to 100% and operatorship of the block. Block 7 is an onshore exploration permit covering an area of 5,000 sq kms (1,235,527 acres) located approx. 340 kms East of Sana’a, 80 kms North East of the Company’s Damis (Block S-1) Production Licence, and 14 kms East of OMV’s Al Uqlah (Habban) Oilfield. The block contains the Al Meashar oil discovery made by Oil Search in 2010 as well as an inventory of nine prospects and leads defined by 2D and 3D seismic surveys, with target sizes ranging from 2 to 900 MMbbl oil gross.The Al Meashar Oilfield, with a target resource of 11 MMbbl to 50 MMbbl, contains two suspended discovery wells that intersected over an 800 metre oil column which in 2010-11 delivered flow rates ranging from 200 to 1,000 bopd in short-term testing of the wells. The oil column extends over the same reservoir sequence as that of the Habban Oilfield in the adjacent Al Uqlah (Block S-2).Petsec Energy has secured a 100% interest in two production and exploration licenses in the highly productive Shabwah Basin in Central Yemen, Blocks S-1 and 7, which contain six oil & gas fields – one developed and five yet to be developed, with cumulative target resources between 45 and 84 million barrels of oil and 550 billion cubic feet of gas, in addition to further high potential exploration targets. Block 7 is a key addition to the Company providing material upside to Petsec’s existing Production Licence, Damis (Block S-1) acquired in February 2016 from Occidental Petroleum, which holds the developed An Nagyah Oilfield and four undeveloped oil and gas fields, containing substantial oil and gas resources in excess of 34 million barrels of oil and 550 billion cubic feet of gas. The developed AnNagyah Oilfield was estimated, based on limited production rates of 5,000 bopd for trucking purposes, by DeGolyer and MacNaughton, reserve engineers, to contain gross 2P reserves of 12.8 MMbbl, of which the financial net to Petsec Energy is 5.6 MMbbl of oil, having a NPV 10 of US$155.4 million based on January 2016 forward oil prices. Petsec’s Chairman, Mr Terry Fern stated:'We are pleased to have secured the acquisition of 100% of both Blocks 7 and S-1 so we can now concentrate on bringing these acquired oil and gas fields into production. This oil and gas production is critically important to the local Yemeni people to provide employment and revenues, absent since 2015 because of the country’s political issues. We were heartened by the recent welcome and encouragement we received from senior members of the Yemen Government currently based in Riyadh, Saudi Arabia, and hope this offered support will allow the early restart of production of the An Nagyah Oilfield, which will demonstrate to the World that foreign investment is welcome in Yemen, and will encourage other foreign oil companies to join us in rebuilding the Yemen oil industry. We look forward to working with the Ministry of Oil & Minerals in developing Yemen’s oil and gas industry.'Original article linkSource: Petsec Energy",Yemen (Shabwa Sub-basin (Marib-Al Jawf-Hajar B.)) An Nagyah
36020,"Wintershall today secured a 10% interest in the Ghasha concession + sour gas project, following the award of a 25% interest to Eni earlier this month. Ghasha comprises the Hail, Ghasha-Butini, Dalma and sundry offshore fields in the Al Dhafra region. ADNOC retains a 60% interest, so a further 5% interest could yet be assigned.","Wintershall today secured a 10% interest in the Ghasha concession + sour gas project, following the award of a 25% interest to Eni earlier this month. Ghasha comprises the Hail, Ghasha-Butini, Dalma and sundry offshore fields in the Al Dhafra region. ADNOC retains a 60% interest, so a further 5% interest could yet be assigned."
39925,"In January 2019 Overgas was still offering the opportunity for interested parties to farm-in to licences Provadia and 1-18 Trakiya. The Provadia licence is located in the eastern part of the country while the 1-18 Trakiya licence is situated in southern Bulgaria. The company started looking for partners in May 2016.   Between 2011 and 2014 Overgas conducted two 2D seismic surveys and one 3D seismic survey totaling respectively 812 km and 55 sq km in the Provadia licence. No fields are situated within the permit area. The last known drilling activity consists of Krivnya 12 which was drilled to a total depth of 2,769 m in the Lower Triassic and abandoned as a dry hole in 1984.  In the 1-18 Trakiya licence, the company drilled the Trakiya 1 exploration well between 2014 and 2015. The hole reached a total depth of 1,717 m bottoming in metamorphic rocks without reaching the targeted Jurassic sediments. It was subsequently re-entered for testing and recovered only gas shows. In late 2012 Overgas conducted a 474 km 2D seismic survey in the permit.   For further information please contact:  Dimitar Merachev  Tel - +359 2 865 11 99  info@russgeocom.com",In January 2019 Overgas was still offering the opportunity for interested parties to farm-in to licences Provadia and 1-18 Trakiya. 
40908,"On 30 January 2019 the Croatian Hydrocarbon Agency (CHA) reported it is planning the 3nd onshore bidding round. The bid round will consist of four exploration blocks covering a total acreage of 12,134 sq km situated in the Dinaride in southwestern Croatia. The tender is expected to be launched by the end of February 2019.          Block   names (from North to South)         Area (sq km)             Dinaridi 13 (DI-13)         3,556             Dinaridi 14 (DI-14)         2,698             Dinaridi 15 (DI-15)         2,864             Dinaridi 16 (DI-16)         3,016           More information are available at the CHA website: www.azu.hr  The licence for the exploration and production of hydrocarbons grants the investor the right to exploration and the direct award of the production licence if the investor has concluded the production sharing agreement (PSA) and has fulfilled all its obligations.  The maximum validity period is 30 years – including the exploration and production periods – and starts on the day the PSA enters into force. The conclusion of the PSA with the selected company is expected within a 6-month period and the indicative granting deadline is set on 31 October 2019. The exploration period is five years (divided into two phases: three years and two years) and can be extended two times for a period of six months per extension. Upon the expiry of the first exploration phase, the company is required to relinquish 25% of the exploration block. Upon the completion of the second exploration phase, the company is required to relinquish any areas that have not been declared exploitation fields.","Croatia, not found"
25959,"South Block A PSC, 421 sq km, onshore N. Sumatra Basin. As part of its divestment programme, Lion Energy has sold its 40.7% interest to Blue Sky Resources for a nominal USD 10 fee, although Lion still has a right to a production royalty of up to USD 4.5 million. Operator Renco Elang Energy retains 59.3%. Amanah Timur-2 expl well still planned, likely this year, followed by a well into the Jerneh prospect.","Lion Energy has sold its 40,7% interest in South Block A PSC (421km²) to Blue Sky Resources (Renco op.59,3%)"
23263,"Larus remains on the lookout for a partner in its wholly-owned PPL 579,  9,257 sq km on/offshore in the Torres Basin, SE PNG, in exchange for participation in an upcoming explo programme. The area is home to live oil seeps, light oil and indicative of a petroleum system hitherto unknown here. Larus has an application pending for further acreage here, APPL 580,  842 sq km adjacent north to PPL 579. Contact: Ian Cross, icross@moyesco.com.","Papua New Guinea, APPL 580"
15849,"State (and partner) SNPC has recommended that the operator be awarded a 50-sq km new (production) licence for 20 years to its Tilapia oilfield, offshore Lower Congo Basin off Pointe Noire. This would replace the current, 50.5-sq km PSC which is due for expiry in 2020. Plans are to drill TLP-103 (devt) as of mid-Jun ’18, 64-day well targeting the Tilapia field’s existing reservoirs (R1/R2 + Mengo) and appraising the Djeno section, SMP rig. Petro Kouilou (Anglo African O&G, op), partner state-owned SNPC 44%. ","State (and partner) SNPC has recommended that the operator be awarded a 50-sq km new (production) licence for 20 years to its Tilapia oilfield, "
62790,"Further to DEA 6 Sep '19, P2133 / block 42/4 off Scarborough, SNS, WD 71m, hc reported encountered and tested, ops terminated late Aug ’19, Valaris 121 JU. Target gas in Zechstein Dolomites + Carb. (Visean) channels. ONE-Dyas (op), partners Spirit Egy + Neptune.","42/4-1 (Darach Central) expl in P2133 / block 42/4 off Scarborough, SNS, WD 71m, hc reported encountered and tested, ops terminated late Aug ’19, Valaris 121 JU. Target gas in Zechstein Dolomites + Carb. (Visean) channels. ONE-Dyas (op), partners Spirit Egy + Neptune."
85412,"Aker BP and Shell have completed a swap deal whereby Aker BP has acquired a 10% interest in PL 1056 and Shell has acquired 20% in PL 1005. PL 1056 covers an area of 4,549 sq km over blocks 6302/1 to 6302/12 in the deepwater More Basin to the west of Ormen Lange. It contains the 2005 Tulipan gas discovery. PL 1005 covers 1,775 sq km over blocks 6404/9, 6404/12, 6405/4, 6405/7 and 6405/10 and contains the 2003 Ellida oil discovery. It is located north of Ormen Lange in the deepwater Voring Basin. The deal was confirmed by the NPD on 10 July 2020 and is effective from 30 June 2020.   Statoil (now Equinor) drilled Tulipan well 6302/6-1 and confirmed gas in the Paleocene Rogaland Group at around 3,900 m below a very thick Quarternary (Naust Formation) North Sea Fan. The find was small and the well was not tested.  Ellida well 6405/7-1, also operated by Statoil, proved oil in the Upper Cretaceous Nise Formation between 2,760 m and 2,823 m, with good oil shows below this depth. However, reservoir quality was generally poor and on test the well flowed only 252 b/d of 31°API oil.   Following completion of the deal, interest in PL 1005 is divided between Aker BP ASA (40% + operator), Var Energi AS (40%) and A/S Norske Shell (20%) and interest in PL 1056 is held by A/S Norske Shell (30% + operator), Petoro AS (20%), DNO Norge AS (20%), Wintershall Dea Norge AS (20%) and Aker BP ASA (10%).","Norway (More B.), PL 1056, Aker BP has acquired a 10% stake in PL 1056, 4,549 sq km in the More Basin (blocks 6302/1 + 12, Tulipan discovery), in exchange for Shell getting 20% in PL 1005, 1,775 sq km over blocks 6404/9 + 12, 6405/4, 7 + 10 (Ellida discovery) in the deepwater Voring Basin. The deal is effective 30 Jun '20. PL 1005 partners now Aker BP (op), Vår + Shell and PL 1056 Shell (op), Petoro, DNO, Wintershall Dea + Aker BP."
48912,"Talon Petroleum is searching for farm-in partners to fund a well to drill the Rocket prospect in licence P2392 (blocks 28/8b & 28/9b) in return for significant equity. The prospect is located in the Central Graben near the Catcher Area where Palaeocene aged Cromarty Sandstone reservoirs are trapped stratigraphically to form the AVO anomaly supported Rocket prospect. Encounter estimate Rocket to hold most likely STOIIP of 68 MMbo with an upside of 150 MMbo. The well cost is estimated at GBP 7 million. Talon acquired the previous licence holder Encounter Oil on 15 May 2019 and announced that it had received strong interest from potential partners and is confident in securing partners in the near term.   The Cromarty B1 Sands are expected to be present at the Rocket prospect with the sands having similar characteristics to the Bonneville field 4 km to the east of the prospect. Encounter estimate net to gross to be within the region of 90 metres, porosities of 32% and the sands are interpreted to be ponded in the hanging wall of the N-S fault system. A salt high in the north and east creates a drape structure providing dip closure. In the west and south dip closure is formed from a combination of an upthrown closure and a stratigraphic pinch-out at the base of the depositional slope. The crest of the structure lies at 3,050 feet with a maximum closing contour of 3,400 feet. The API is estimated to range between 24° and 31° with GOR’s of 200-300 scf/stb. The licence was awarded on 1 October 2018 in the 30th Seaward Licensing Round.  Interest in P2363 is held solely by Talon Petroleum Ltd (100% + operator).  For further information please contact:   Graham Dore  Tel: +44 (0) 7718 883610  Email: graham@encounteroil.co.uk","United Kingdom, P2363"
33554,"Equinor spudded an exploration well on its Skruis prospect in PL 532 on 27 September 2018 using the “Songa Enabler” S/S. 7220/5-3 is located east of Kramsno and north of Nunatak. The well was drilled to TD at 1,782 m in the Upper Triassic Fruholmen Formation and has made a new light oil discovery with estimated recoverable reserves of 12-25 MMbo. A 35 m oil column (30 m sandstone) was proven in the Middle Jurassic Sto Formation with an OWC at 1,415 m subsea. There was a further 30 m of water-wet sandstone in the Sto Formation and a 110 m water-wet sandstone in the Lower Jurassic Nordmela Formation. It is likely that the find will be developed as a tie-in to Johan Castberg. On 26 October 2018 the well was abandoned.   Kramsno well 7220/4-1 (also in PL 532) proved a 130 m gross gas column in the Jurassic Sto and Nordmela formations (with poorer than expected reservoir quality) and a 45 m gross gas column was present in the Snadd Formation. Initial recoverable reserve estimates for the discovery ranged from 70 to 140 Bcf. The well was drilled between December 2013 and February 2014.     Nunatak was also drilled in 2013 in PL 532 (as part of the same drilling campaign as Kramsno). The Cretaceous Knurr Formation target was gas-bearing but the reservoir is of poor quality and the discovery was deemed non-commercial.    The PDO for Johan Castberg (in PL 532) was approved on 28 June 2018. The development contains recoverable reserves of 450-650 MMboe and first oil is expected in Q4 2022. The three fields involved in the project – Skrugard, Havis and Drivis – will be developed using an FPSO, 10 subsea templates, two satellite structures and 30 wells, with oil exported by shuttle tanker (Equinor, together with other companies operating in the area, is still investigating the future profitability of an oil terminal at Veidnes). CAPEX is estimated at NOK 47.2 billion (USD 5.79 billion) and the break-even price is around USD 31 per barrel. Johan Castberg is forecast to produce for at least 30 years.    Interest in PL 532 is held by Equinor Energy AS (50% + operator), Eni Norge AS (30%) and Petoro AS (20%).",Norway (Bjornoyrenna Fault Complex (Barents Sea Platform)) Johan Castberg
66247,"Total has reportedly acquired a 30% interest from Equinor in ER 257 (aka Algoa East), 9,367 sq km on the Agulhas Plateau off the south coast. Resulting partnership Equinor (op) 60%, Total 30%, OK Energy 10%:","Total has reportedly acquired a 30% interest from Equinor in ER 257 (aka Algoa East), 9,367 sq km on the Agulhas Plateau off the south coast. Resulting partnership Equinor (op) 60%, Total 30%, OK Energy 10%:"
62150,"PRL 145, Cooper-Eromanga, P&A dry at TD 1,905m, Senex (op), partner Beach. SLR rig-185 has since spudded Snatcher-12 appr.","Snatcher North 2 (Senex 60% op, Beach 40%) in PPL 240, P&A after failing to intersect any hc."
78407,"AUREP is the Department responsible for the promotion of petroleum exploration under the Ministère des Mines of Mali. As of March 2016, AUREP had finalized a new division of the country in exploration acreage blocks. The old open block limits and denominations are not valid any more. The release of the new block limits was contingent on the new petroleum bill to be passed into law. The list of new acreage blocks became available in late-November 2016, it is presented below.    In the west of the country, the new blocks are smaller than the previous ones. In fact the old blocks were divided in two in this area. The amount of available seismic data has doubled between 2004 and 2014, this has translated into a better understanding of the geology of the various sedimentary basins in the country. Therefore it was possible to design new block limits that take into account the improved basin definition. A new block, N° 29, was added in the far south of the country.    AUREP stands for AUtorite pour la REcherche Petroliere.  Interested parties should contact:    Ahmed Ag Mohamed    Directeur, AUREP  Tel: +223 788 046 67  Email: inassakok@yahoo.fr     The available blocks as of April 2020 are understood to be as listed below.  There are thirty-nine open blocks.  There was no change from the previous list.   Total open acreage amounts to 850,451 sq km all onshore.             Open   blocks                                           Block   Name         Area   (sq km)         Situation         Block   Basin             Block   1A1         21,156                   Hank   Sub-basin (Taoudeni Basin)             Block   1A2         34,279                   Hank   Sub-basin (Taoudeni Basin)             Block   1B1         14,876                   Hank   Sub-basin (Taoudeni Basin)             Block   1B2         14,932                   Hank   Sub-basin (Taoudeni Basin)             Block   2A         10,842                   Hank   Sub-basin (Taoudeni Basin)             Block   2B         10,890                   Hank   Sub-basin (Taoudeni Basin)             Block   3A         10,506                   Taoudeni   Basin             Block   3B         12,843                   Hank   Sub-basin (Taoudeni Basin)             Block   4A         10,733                   Taoudeni   Basin             Block   4B         10,797                   Taoudeni   Basin             Block   5A         29,965                   Taoudeni   Basin             Block   5B         29,782                   Taoudeni   Basin             Block   6         23,600                   Taoudeni   Basin             Block   7         39,991                   Taoudeni   Basin             Block   8A         16,556                   Taoudeni   Basin             Block   8B         19,267                   Taoudeni   Basin             Block   9A         19,120                   Taoudeni   Basin             Block   9B         24,223                   Taoudeni   Basin             Block   10         37,566                   Taoudeni   Basin             Block   11         33,141                   Iullemmeden   Basin             Block   12A         32,557                   Taoudeni   Basin             Block   12B         21,063                   Nara   Graben (Taoudeni Basin)             Block   13A         42,863                   Taoudeni   Basin             Block   13B         27,748                   Taoudeni   Basin             Block   14         20,250                   Iullemmeden   Basin             Block   15         17,090                   Iullemmeden   Basin             Block   16A         16,972                   Taoudeni   Basin             Block   16B         15,553                   Taoudeni   Basin             Block   18         19,793                   Nara   Graben (Taoudeni Basin)             Block   19         13,991                   Taoudeni   Basin             Block   21         22,244                   Taoudeni   Basin             Block   22         22,115                   Taoudeni   Basin             Block   23         14,311                   Taoudeni   Basin             Block   24A         29,053                   Taoudeni   Basin             Block   24B         31,010                   Taoudeni   Basin             Block   26         24,036                   Pharusian   Fold Belt             Block   27         20,340                   Mantass   Depression (Iullemmeden Basin)             Block   28         8,498                   Taoudeni   Basin             Block   29         25,898                   Taoudeni   Basin",AUREP is the Department responsible for the promotion of petroleum exploration under the Ministère des Mines of Mali. 
55380,"Beach Energy Ltd spudded the Hanson West 1 appraisal well in PPL 255, located in the Cooper-Eromanga Basin, on 19 July 2019.  The well was drilled by the “SLR Rig 184” land rig.  On 27 July 2019 the well was plugged and abandoned at a total depth of 1,808 m.  Evaluation of the well results is ongoing.  The well was drilled to appraise the Hanson field, which was discovered in May 2011.  The field has been producing oil since April 2013. Hanson West 1 was the eighth appraisal well to be drilled at the field. Hanson West 1 followed the Hanson East 1 appraisal well which was plugged and abandoned, after encountering oil shows, on 16 July 2019    PPL 255, which covers an area of 2 sq km, was awarded on 13 August 2019.  Beach Energy Ltd holds 100% interest and operatorship, with 50% held through subsidiary Great Artesian Oil and Gas Pty Ltd.","Beach Energy Ltd Hanson West 1 (appraisal) PPL 255, Cooper-Eromanga Basin - P&A"
71503,"The Dubai Supply Authority (DUSUP) and the Abu Dhabi National Oil Co (ADNOC) have announced a giant gas discovery in an area between Saih Al Sidirah and Jebel Ali in the Emirates of Abu Dhabi and Dubai respectively. The discovery is estimated to hold 80 Tcf of shallow gas resources in place and was made within an area of 5,000 sq km between the Emirates. It follows ADNOC's first drilling campaign in Dubai, which included more than ten exploration and appraisal wells. ADNOC reportedly utilised both conventional and unconventional drilling and completion technologies and methods to access the trapped gas, including horizontal drilling and hydraulic fracturing to enable optimal productivity while reducing the number of drilling rigs required. The company's stated that this new discovery reinforces the commitment to ensuring sustainable and economic gas supply and achieving gas self-sufficiency. <P />The discovery was announced during the signing of a strategic cooperation agreement between DUSUP and ADNOC, to continue to explore and develop the shallow gas resources in this area in a joint project named 'Jebel Ali'. Sheikh Ahmed bin Saeed, DUSUP's director general, said, ""The agreement is an important step forward in further enhancing cooperation and tapping synergies to maximise the UAE's resources, as part of our leadership's vision for the next 50-year phase of development. This partnership enables our organisations to combine each other's capabilities to capture the greatest possible benefits from the UAE's hydrocarbon assets. <P />As part of the agreement, ADNOC, in collaboration with DUSUP, will deploy capital, technology, and expertise to develop and produce shallow gas resources and conduct further exploration to assess further volumes and firm up development costs. The gas produced will be supplied to DUSUP, to support Dubai's economic growth ambitions and enhance its energy security as it reinforces its position as a pivotal hub of the global economy.","ADNOC and the Dubai Supply Authority have reportedly signed a strategic agreement to jointly develop the Jebel Ali project, an 80 Tcf in-place onshore gasfind announced 3 February 2020 and shared by Abu Dhabi and Dubai. Further exploration [appraisal] of the shallow gas + devt are said planned in the area which lies between Saih Al Sidirah and Jebel Ali. It is also the 1st time ADNOC has explored in Dubai."
48576,"Equinor has exercised preferential rights to acquire an extra 22.45% in the Anadarko-operated Caesar Tonga oilfield (Green Canyon) from Shell for USD 965 MM cash, lifting its stake to 46%. Partner Chevron. The deal will be retro-effective 1 Jan ’19, with closing subject to customary approvals. Map extract below courtesy Equinor:","Equinor has disrupted Delek Group's planned US$965 MM agreement to buy Shell's stake in Caesar-Tonga oilfield asset by exercising its own preferential rights. Equinor has agreed to take over Shell's 22.45% interest. The asset is located 300 km SW of New Orleans and covers blocks GC683, GC726, GC727 and GC770 in DW of about 1500m."
10661,"In October 2017, Apache was understood to have concluded drilling operations in its West Kalabsha Y 2X (WKAL Y 2X) appraisal well, located on the West Kalabsha PSC in the Faghur Basin. It was spudded in Q3 2017 and drilled to a TD of 4,907m. Operations were carried out using the Egyptian Drilling Company #54 rig. WKAL Y 2X is the first appraisal of the 2013 WKAL Y 1X discovery (TD 4,800m). It encountered oil in the Jurassic Safa sandstones. The discovery lies ~4km SE of the company's 2012 Wafaa 1X oil discovery. Apache operates the PSC with 67% equity, in partnership with Sinopec (33%). ","Egypt, Kalabsha (Dev)"
87222,"On 28 July 2020, CNH reported abandoned dry the well Max 1 EXP directional new-field wildcat (NFW).The well was drilled by Shell and is located in the CNH-R02-L04-AP-CS-G02/2018 contract, Area 21 Block in the ultra-deep-water Campeche Deep Sea Basin, spudded on early May 2020. Shell is operator of the contract and holds 60% working interest and Chevron holds 40% working interest.  The NFW had a proposed total depth (PTD) of 7,480 m measured depth (MD) and 7,332 m true vertical depth (TVD) and was planned as a Type S directional with a maximum inclination of 22.46° in the section 3,690-4,026 m, Lower Miocene and Upper Oligocene, and then drill back to vertical below 4,026 m. The primary target was the Upper Jurassic Oxfordian from approximately 6,970 m to 7,100 m with the analog being the Jurassic Norphlet in the northern Gulf of Mexico or the productive reservoir in the Ek-Balam fields in the Sureste Basin.  The NFW is in the north-eastern area of the block, nearest well is Chibu 1EXP located approximately 31.2 km north-west and the nearest historical well is the Tamha 1 plugged and abandoned (P&A) by PEMEX in 2008 located140 km south. The prospect trap is a north-east south-west oriented, salt nucleated anticline. The Max prospect has estimated unrisked prospective resources of 291 MMboe with 14% of Geological Chance of Success. The hydrocarbon expected is oil 26° API.  The ""Deepwater Thalassa"" D/S drilled the well in a water depth of 2,511 m. The drilling cost for the well was estimated to be USD 84.8 million and the abandonment cost was estimated to be USD 7.0 million.  On 7 May 2018, Shell was granted an official award for the CNH-R02-L04-AP-CS-G02/2018 contract, the 2,048.35 sq km, Area 21 block (alternate block name AP-CS-G01).    On 13 June 2019, Shell was granted approval by the CNH for the first exploration plan related to the CNH-R02-L04-AP-CS-G02/2018 contract, Area 2, that includes geophysical and geological studies as well as the drilling of one firm commitment exploration well with an incremental case of drilling a second exploration well.        On 13 February 2020, Shell was granted approval by the CNH to drill the Max 1EXP directional new-field wildcat (NFW),","(Campeche Deep Sea B.) Max 1 EXP nfw, operated by SHELL (60%), CVX (40%) in the CNH-R02-L04-AP-CS-G02/2018 contract, Area 21 Block, WD = 2511 m, reported abandoned dry."
84502,"Cluster ML (KG-DWN-98/2), deepwater KG Basin, WD 630m, TD 3,225m Feb '20, 1Q FY 2020-21 gas find, tested 20.1 MMcf/d + 18.54 MMcf/d + water from 2 intvs, well suspended late Apr '20, Louisiana SS.","(Krishna-Godavari B.) KGD982NA-CHAN-B 1 (CHN BAA) nfw op. by ONGC (100%) in Cluster ML (KG-DWN-98/2) block, gas find, tested 20.1 MMcf/d + 18.54 MMcf/d + water from 2 intvs."
79422,"ConocoPhillips is looking to sell-out of WL4-00, 2,530 sq km in shallow waters off Sarawak, in which it holds 50% + operatorship. The balance is held by Petronas. Commitments fulfilled.","ConocoPhillips is looking to sell-out of WL4-00, 2,530 sq km in shallow waters off Sarawak, in which it holds 50% + operatorship. The balance is held by Petronas. Commitments fulfilled."
48566,"Sinopec achieved exploration success in the Jiaoshiba shale gas field area in the Sichuan Basin, Shengye 2HF, a horizontal shale gas outpost located in the field second phase block in south of the field, tested 11.4 MMcf/d of gas. The well is drilled on Dongshen prospect belt and gas reservoir is under normal pressure regime.  In 2018 Sinopec tested commercial gas, 5.6 MMcf/d, in Jiaoye 10HF in this part of the field, the gas reservoir is also under normal pressure regime.    Main producing reservoir in the field has high pressure gradient of 1.5, no well has achieved commercial gas rate in the reservoir with normal pressure regime. The success demonstrates sweet spot for normal pressure reservoir in the field area.   In 2016 Sinopec drilled Shengye 1 without result reported.  Background Information  In 2018, Sinopec produced 6 Bcm of shale gas from the Jiaoshibas field in the Sichuan Basin, same as in 2017. The company plans to produce 6.3 Bcm in 2019.   In 2018 Sinopec put additional 81 wells on stream in the field and added 5.4 Bcm of gas reserves. Jiaoshiba field has produced cumulative of 21.5 Bcm of shale gas by 2018 since it produced gas in 2012.   Jiaoshiba field was discovered in 2013 and started production in 2014. By 2017 the field has held a total 21.2 Tcf (600.8 Bcm) of gas in place within a total field area of 576 sq km.  Sinopec completed Jiaoshiba field first phase development by end 2015, building a production capacity of 5 Bcm per year. The company started Jiaoshiba field 2nd phase development program in early 2016, focusing on drilling program in Jiangdong, Pingqiao, Baitao and Baima blocks.    Apart from the Jiaoshiba field, Sinopec also has achieved several successes in shale gas exploration drilling in other blocks in the Sichuan Basin, such as Yongchuan, Weiyuan-Rongxian and Dingshan area, in particularly Weiyuan-Rongxian block has been approved 4.4 Tcf of gas in place in 2018.","Sinopec achieved exploration success in the Jiaoshiba shale gas field area in the Sichuan Basin, Shengye 2HF, a horizontal shale gas outpost located in the field second phase block in south of the field, tested 11.4 MMcf/d of gas. The well is drilled on Dongshen prospect belt and gas reservoir is under normal pressure regime. "
66743,"Mari secured sole rights to the 1,610-sq km Wali West 3269-1 EL, Pishin-Katawaz Basin, Khyber Pakhtunkhwa in Potwar, on 18 Nov '19 as a result of the 2018 round:",Pakistan (Mari-Kandhkot High (Jaisalmer B.)) Mari
52314,"The Santa Cruz authorities plan a licensing effort for 4 onshore blocks totalling 2,350 sq km in the Austral Basin during 2H ’19. These would be Camusu Aike (245 sq km), El Campamento (1,109 sq km), El Martillo (609 sq km), La Azucena (387 sq km), in purple below:","The Santa Cruz authorities plan a licensing effort for 4 onshore blocks totalling 2,350 sq km in the Austral Basin during 2H ’19. These would be Camusu Aike (245 sq km), El Campamento (1,109 sq km), El Martillo (609 sq km), La Azucena (387 sq km),"
21160,"The long-awaited Intracampos bid round has been once more delayed, this time from 30 Apr ’18 to June.  8 blocks are on offer (namely Araza Este, Charapa, Chanangue, Espejo, Iguana, Panayacu Norte, Perico and Sahino) and a focus on central-SE fields currently dormant or requiring further explo/appraisal.","The long-awaited Intracampos bid round has been once more delayed, this time from 30 Apr ’18 to June.  8 blocks are on offer (namely Araza Este, Charapa, Chanangue, Espejo, Iguana, Panayacu Norte, Perico and Sahino) and a focus on central-SE fields currently dormant or requiring further explo/appraisal.   Ecuador (Putumayo B.) Charapa    "
62392,"Uchtepa field area, close to the Kyrgyz border in Fergana Basin, tested gas at 5.1-6.9 MMcf/d from the Cretaceous (reservoirs XIX + XVIII below 1,050m).","Uchtepa-12 appr Uchtepa field area, close to the Kyrgyz border in Fergana Basin, tested gas at 5.1-6.9 MMcf/d from the Cretaceous (reservoirs XIX + XVIII below 1,050m)."
59818,"On 23 September 2019, partner Kosmos announced that the Yakaar 2 appraisal well, Cayar Profond block, deep waters of the MSGBC Basin, found gas. The well intersected 30 m of net gas pay in similar high-quality Cenomanian reservoir to the Yakaar 1 wildcat. Yakaar 2 was drilled approximately nine Km from Yakaar 1 and confirmed the southern extension of the field. The well was drilled in approximately 2,300 m of water and reached a total depth of around 4,800 m. The “Valaris DS-12” rig is now moving to drill the Orca 1 exploration well in Mauritania which is the last in this year’s program for BP in Senegal/Mauritania.  The Yakaar 2 well results confirm that the Yakaar-Teranga resource base can support a standalone gas development. The current (September 2019) view is that this would be a phased development with phase 1 providing domestic gas and data to optimize the development of future phases which would be LNG for export. Senegal signed a contract in August 2019 for a LNG-fuelled floating power plant. This will provide a sizeable domestic LNG demand which can be covered by the Yakaar development.  Available information suggests that BP is batch drilling the three following wells: Orca 1 in clock C-8, Yakaar 2 in Cayar Profond block and GTA 1 in GTA block.  The Yakaar 2 appraisal well was spudded around 8 May 2019 with the “Ensco DS-12” drillship which drilled the top-hole section before moving on to the GTA 1 location in the unitized GTA block. On 14 July 2019, the rig left the GTA 1 location to move to Dakar for maintenance. The “Ensco DS-12” was renamed “Valaris DS-12” in the meantime. The rig moved to the Yakaar 2 location on 22 August 2019 and it is understood that as of early September drilling resumed on the well.  As of 4 April 2019, the “Ensco DS-12” had entered Mauritanian waters in preparation for BP’s drilling campaign in Senegal and Mauritania. In late October 2018 industry sources announced that BP contracted the “Ensco DS-12” drillship for two firm wells plus four one well options starting in April 2019 offshore Senegal. This rig has carried out the BP/Kosmos drilling campaign of 2017 when Yakaar was discovered. According to an update by Kosmos Energy, the 2019 drilling campaign will include an exploration well in Mauritania, one appraisal well in Senegal and one appraisal well in the unitized GTA block. The well in Senegal is Yakaar 2, on the Yakaar field in the Cayar Profond Block. The well in the GTA block will target the eastern portion of the Tortue/Ahmeyim field. Both fields are in deep waters of the MSGBC Basin.  In the second quarter of 2018, Kosmos indicated that an appraisal well of the Yakaar 1 gas discovery is planned for 2019.  In May 2017, Kosmos announced that the Yakaar 1 new field wildcat well discovered gas. The well intersected a gross hydrocarbon column of 120 m in three pools within the Lower Cenomanian objective and encountered 45 m of net pay. The reservoir sands which are of very good porosity and permeability according to Kosmos, are interpreted to be present over a very large area. The company estimates the gross Pmean gas resource discovered by Yakaar 1 at 15 Tcf. Preliminary analysis of gas samples indicates a condensate/gas ratio of 15 to 30 barrels per million standard cubic feet. The Yakaar well was drilled to a TD of 4,932 m.  Andrew Inglis, chairman and CEO of Kosmos said that the gas resource discovered in the Teranga – Yakaar area could support a second cost-competitive LNG hub (in addition to the one planned at Tortue).  The Yakaar prospect is a structural-stratigraphic trap in a large base of slope Lower Cenomanian turbidite fan with stacked and amalgamated sand channels (versus a single sand channel in Teranga-1). The hydrocarbon charge is believed to come from the Neocomian – Valanginian source rock which was interpreted to be in the oil generation window in the Yakaar area. The same source rock is believed to have charged Teranga 1 but in this inboard location, the burial depth is greater and the rock is in the gas generation window. Kosmos estimated pre-drill that the Yakaar prospect had a gross unrisked resource potential of 15 Tcf of gas and 750 MMb of condensate.  Participants in the Cayar Profond block are: Kosmos BP Senegal Ltd, operator with 65%, BP with 25% and Petrosen, the state oil company of Senegal, with 10%. In Kosmos BP Senegal Ltd, BP plc holds 49.99% while Kosmos holds 50.01%.","Yakaar 2 appr. (Kosmos BP Senegal Ltd 60%, BP 30%, Petrosen 10%) in Cayar Profond block, 9km south of the discovery, 30m net gas pay in the Cenomanian target, partner Kosmos comments the Yakaar-Teranga resource base is world-scale and has the potential to support an LNG project. Devt will be phased, Phase 1 providing domestic gas and data."
15042,"Mississippi Canyon Block 607, OCS lease G34451, location ab. 5km from Blind Faith production hub in WD 1,981m, TMD 8,898m, significant oil discovery (205m net pay in the Norphlet), results of sidetrack B2 not released, discovery cleared to TP&A by the BOEM on 16 Feb ’18.  Pacific Sharav DS. Chevron (op), partner Total.","United States (Deep Water Gulf of Mexico B.) ? op. by CVX (60.0%, TOTAL 40.0%) in MC 607 block"
67873,"According to local media report, Repsol and Petronas Carigali (via its subsidiary Petronas Andaman III Indonesia BV) signed an official contract agreement on the latter's acquisition of 49% participating interest in the Andaman III PSC, in offshore North Sumatra Basin, on 23 December 2019. With the completion of the deal, Repsol will hold the remaining 51% operating interest in the block.  In early December, Repsol received approval from the government of Indonesia, to farm out a 49% participating interest in the block to Petronas Carigali. Likewise, Repsol also received approval for a two-year extension of the exploration period in the PSC.   Local media reported in early November 2019 that the exploration extension was recommended by BPMA, the Aceh upstream regulator, prior to final approval by the Ministry of Energy and Mineral Resources.  IHS Markit initially reported the farm-in agreement in early November 2019, pending official approval. Repsol opened a data room in September 2018 offering up to 49% in the block.  The new partner will support the drilling of high-impact wildcat Rencong 1X, planned for late 2020. The well will target Upper Eocene-Lower Oligocene carbonates of the Tampur Formation. The well will fulfill the exploration commitments for the PSC.   In late November 2017, the operator completed the seismic commitment for the PSC with a 3D seismic survey covering more than 3,000 sq km. The survey, acquired using Elnusa’s “Elsa Regent” vessel, was reported as the largest 3D seismic survey acquired in Indonesia at the time.  The block is operated by Repsol’s fully owned subsidiary Talisman (Andaman) BV. Prior to the farm-in by Petronas, the company was holding 100% interest in the PSC.  The Andaman III PSC, awarded in 2009, covers approximately 8,500 sq km and lies between shelf and over 1,300 m water depth.  Background Information  The Andaman III block was offered during Phase II 2008 Tender Round under the regular tender mechanism and was officially awarded to Talisman (100%, operator) on 30 November 2009. The company paid a signature bonus of USD 7.5 million for the block. Firm commitments for the initial three-year exploration period included G&G studies worth USD 2 million, acquisition of 2,500 sq km 3D seismic (USD 15 million) and drilling one well (USD 30 million). The seismic acquisition commitment was initially planned in 2010 but was pushed back to a later date.  Second exploration phase commitments (Year 4 to 6) include G&G studies (USD 0.6 million), acquisition of 500 sq km 3D seismic data (USD 3 million) and drilling one exploration well, likely carried over from the first exploration phase (USD 30 million).  Multiple play types exist in the area, including carbonate build-up on a basement high or on an anticline, syn-rift clastics with combined stratigraphic-structural trap component, inverted syn-rift clastics close to the Mergui Ridge, carbonate build-ups on flanks of the Mergui Ridge and Barisan fold-belt anticlines. Potential source rocks in the area in include the shales of the Eocene Parapat (lacustrine syn-rift), Oligocene Bampo, Lower Miocene Peutu/Belumai and Middle Miocene Baong formations. Potential reservoirs which could have commercial accumulations in this deepwater area are the Belumai carbonates and Parapat syn-rift sandstones. Shales of the Bampo and Baong formations would be the likely seals.","Repsol and Petronas Carigali (via its subsidiary Petronas Andaman III Indonesia BV) signed an official contract agreement on the latter's acquisition of 49% participating interest in the Andaman III PSC, in offshore North Sumatra Basin,"
30949,"Serica Energy plc announced that it has agreed a further deal for the Bruce and Keith fields in the North Sea with Total. Under the deal, Serica will acquire a further 42.25% interest in the Bruce field and a further 25% interest in the Keith field. Initial consideration for the interests is USD 5 million payable on deal completion then a deferred consideration of USD 15 million to be paid in three USD 5 million instalments, payable every 8 months following completion of the acquisition and subject to continued production from the nearby Rhum field. Total will retain a 1% interest in the assets. This deal follows the announcement from BP in November 2017 in which it agreed to sell 36% interest in the Bruce field, 34.84% interest in the Keith field and 50% interest in the Rhum field to Serica. Under the terms of that deal Serica will pay an initial consideration of GBP 12.8 million along with a share of cash flows over the next four years, a consideration equivalent to 30% of BP’s post-tax decommissioning costs and several contingent payments of future asset performance and product prices. BP expects to receive an overall payment in the region of GBP 300 million. In addition to the interest approximately 110 staff working for BP on the Bruce assets are also expected to make the transition to Serica. BP is to retain a 1% interest in Bruce to oversee its future operational and financial performance. In an update on 22 May 2018 Serica confirmed that amidst the decision by the US Government to withdraw from the Joint Comprehensive Plan of Action (JCPOA) and reintroduce US Sanctions on Iran, the company remains committed to complete the deal with BP which is partnered by the Iranian Oil Company (U.K) Limited in the Rhum field.  On 1 October 2018 Serica announced that the deal is still pending.   Further to US’ withdrawal from the JCPOA certain services are currently provided under authorisations obtained from the US Office of Foreign Assets Control (OFAC) related to the Rhum field. The current OFAC licence which was issued to BP enable the provision of goods, services and support by certain US persons expired on 30 September 2018. Serica and BP submitted applications to renew the licence. On 1 October 2018 Serica announced that the licence has been renewed until 4 November 2018.   Bruce is a middle Jurassic gas, condensate, oil field discovered in 1974 by Hamilton Brothers Oil Co with well 9/8-1. It is a complex structure comprising three reservoirs - Bruce sandstone (oil and gas condensate), Statfjord sandstone (oil and gas condensate), and Turonian limestone (gas condensate). Appraisal drilling was largely unsuccessful until 1981. The field was not developed until 1990 and was developed using two bridge-linked platforms D and PUQ. It was brought onstream on 19 May 1993. During Phase II of the Bruce development a third platform was added to accommodate additional gas compression facilities. This CR platform, is bridge linked to the two original Bruce Field Platforms. Improved recovery commenced in 1997 with produced water being re-injected into the reservoir. The Keith field was discovered initially in 1983 by well 9/8a-8 which was drilled as a Bruce outpost. The field was not brought onstream until 2000. It has been developed as tie-back to Bruce. The Rhum field was discovered in 1977 with well 3/29-2 by a Joint Operating Agreement between BP and Iranian Oil. It was not initially developed due to the HP/HT nature of the reservoir. In 2002 the field development plan was submitted to the then Department of Trade and Industry. It was developed as a subsea tie-back to the Bruce field with two production wells and the completion of an appraisal well. Production commenced in 2005.   Following completion of the deal, interest in Bruce (lying in licences P90, P209 and P276) will be held by Serica Energy plc (78.25% + operator), BHP Billiton Petroleum Great Britain Limited (16%), Marubeni Oil and Gas (U.K.) Limited (3.75%), Total E&P UK Ltd (1%) and BP Exploration and Operating Company (1%). Interest in Keith (P209) will be held by Serica Energy plc (58.84% + operator), BHP Billiton Petroleum Great Britain Limited (31.83%), Marubeni Oil and Gas (U.K.) Limited (8.33%) and Total E&P UK Ltd (1%). Interest in Rhum (P198, P566 and P975) will be held by Serica Energy plc (50% + operator) and Iranian Oil Company (U.K.) Limited (50%).","Serica Energy plc announced that it has agreed a further deal for the Bruce and Keith fields in the North Sea with Total. Under the deal, Serica will acquire a further 42.25% interest in the Bruce field and a further 25% interest in the Keith field. "
45048,"PSCs were signed on 21 Mar 19 for offshore PM-407 (6,275 sq km) + PM-415 (3,455 sq km) by PTTEP HKO, a subsidiary of PTTEP + Petronas. The Malay Basin blocks will be operated by PTTEP (55% in PM-407, 70% in PM-415) with Petronas holding the balance. Commitment include acquisition + processing of 3D seismic + 2 explo wells in PM-407,  2 explo wells in PM-415 in 4 years. Both blocks had been offered during the 2018 round. http://www.pttep.com.","PTTEP will operate PM407 on 55% and PM415 on 70%, with Petronas holding the non-operating balance in each tract."
46574,"On 16 April 2019, Sound Energy announced that Moroccan authorities had approved the conversion of Schlumberger’s 27.5% interest in the Anoual permit (former Meridja reconnaissance area) to a direct licence position.  Sound Energy operates the permit with a 47.5% interest, Schlumberger’s holds a 27.5% interest and ONHYM holds the remaining 25%.    Background information  Sound Energy announced on 20 February 2017, that it had signed a binding agreement for the acquisition of OGIF assets in Eastern Morocco. OGIF's Eastern Moroccan assets include a 20% interest in Tendrara, a 75% interest in Meridja (including a 55% interest over which Sound Energy has exercised its option, subject to regulatory and other approvals) and an application for a 75% position in the relinquished area close to Tendrara. The agreement followed the non-binding heads of agreement signed on 19 January 2017.  On 12 September 2017, Sound Energy announced that it had completed the acquisition of Oil & Gas Investment Fund’s (OGIF) assets in Eastern Morocco. The company will operate the Tendrara permit, the Anoual permit and the Matarka reconaissance licence (covering the Tendrara relinquished are).","Morocco, Tendrara (Dev)"
37706,"BT-PN-003 contract, E-C part of PN-T-086 block, Parnaíba Basin, TD 1,698m (PTD was 2,650m), assumed dry as no shows report by end. Targets Cabeças + Poti fm’s.","Brazil, BT-PN-003"
52946,"On 10 July 2019 Total announced that it has signed an agreement to divest a number of non-core UK assets to Petrogas NEO UK Ltd. The acquiring company is the exploration and production segment of the Oman based conglomerate MB Holding. Petrogas has partnered with private equity investor HitecVision for the deal. The overall consideration for the deal amounts to USD 635 million and the deal has an effective date of 1 January 2019. Completion of the deal is subject to regulatory approval and is expected to close in December 2019.   A number of the assets involved in the acquisition were acquired by Total through the USD 7.45 billion acquisition of Maersk made in March 2018. Total stated the acquisition is in-line with its portfolio management strategy, aiming to lower its break-even point through optimizing capital allocation and divesting in high technical cost assets. Total’s primary objective is to maintain the organic break-even before dividend below USD 30/b.    Petrogas stated that through the acquisition it is taking on expected average 2019 production of 25,000 boe/d, putting it among the top 20 producers. Through the deal Petrogas will take over 110 employees and contractors through picking up operatorship of assets (Quad 15 and Flyndre) and a fully owned FPSO. Petrogas along with HitecVision plan to become a full-cycle North Sea operator focusing on combining value creation in the North Sea with high environmental, social and Governance standards. The Total acquisition is the first step in the implementation of this strategy and will provide further expansion through organic and in-organic activities which include growing the operatorship position further. Petrogas believes that the assets acquired provide a number of organic growth opportunities including infill drilling and development discoveries close to infrastructure.          Assets   acquired by Petrogas             Field         Interest sold         Operator             Dumbarton         100%         TOTAL             Balloch         100%             Lochranza         100%             Drumtochty         100%             Flyndre         65.94%             Affleck         66.67%             Cawdor         60.60%             Golden Eagle         31.56%         CNOOC             Scott         5.16%             Telford         2.36%","United Kingdom, Golden Eagle"
65734,"Alto CF Oeste P3 contract, ALTO_CF_O block, Santos Basin, WD 1,720m, PTD 5,200m, target Barra Velha, oil shows report to ANP on 8 Nov and again on 2 Dec '19, Brava Star DS. Shell (op), partners CNOOCI + Qatar Petr.","ACFO (1-SHEL-031-RJS) nfw. (Shell 55% op, CNOOCI 20%, Qatar Petr 25%) in Alto CF Oeste P3 contract, ALTO_CF_O block, target Barra Velha, oil shows report to ANP on 8 Nov '19. WD=1720m, PTD=5200m."
36193,"Sri Lanka’s tender plans for the 2,924-sq km block M2 (shown below) have apparently once more been revised. It would seem the round will now be launched ‘within weeks’ for the block which is host to the Cairn Barracuda + Dorado gas finds (>1 Tcf resources). The round would close 4 months after opening.   Meanwhile progress continues towards the offer of offshore blocks M1 + C1 in the Mannar + Cauvery basins reportedly hoped to launch by year-end.","Sri Lanka’s tender plans for the 2,924-sq km block M2 (shown below) have apparently once more been revised. It would seem the round will now be launched ‘within weeks’ for the block which is host to the Cairn Barracuda + Dorado gas finds (>1 Tcf resources). The round would close 4 months after opening. Meanwhile progress continues towards the offer of offshore blocks M1 + C1 in the Mannar + Cauvery basins reportedly hoped to launch by year-end."
52004,"Tullow’s assignment of sole rights to offshore block Z-64 in the Tumbes Basin has reportedly been signed-off by the govt. Meanwhile Tullow continues to work with Perupetro to execute licences for other offshore blocks Z-65, Z-66, Z-67 + Z-68. A 35% farmin to Karoon’s Z-38 is also pending signature by Perupetro.",Tullow’s assignment of sole rights to offshore block Z-64 in the Tumbes Basin has reportedly been signed-off by the govt.
10380,"Statoil has commenced the relinquishment process for Block AD-10, located in Bengal Deep Sea Fan in late November 2017, at the end of the first study period of 2 and a half years. Statoil is operator and sole interest holder of the block, which was officially awarded in April 2015. Contract commitments for the first study period included environmental and social impact studies, and the acquisition of new 2D seismic data. After the fulfilment of commitments, the operator had the option to decide whether to continue with a three-year exploration period, or to exit the block. The 2D seismic commitment for the block was fulfilled with a survey conducted between June and July 2016, using the “Polarcus Amani” MV. The acquisition covered approximately 4,800 km. Later in January-February 2017, Statoil acquired a new 3D seismic survey covering approximately 2,500 sq km, in conjunction with Shell. The survey covered the southern part of Shell’s Block AD-11 and the southwest part of Statoil’s AD-10. This survey was also carried out by the “Polarcus Amani”. Prospective target in the block are Pliocene turbidite plays.","Myanmar, Block AD-10"
35812,"In early October 2018, Pluspetrol plugged and abandoned the El Deschave x-1 exploratory well drilled to extend production from the Centenario Formation reservoir on the CNQ-7/A license, Neuquen Basin. The well was spud on 10 September and was finished drilling on 16 September. The PTD was 638m. ","Argentina, CNQ-7/A"
86245,"Kina Petroleum Corp is offering equity in its wholly owned and operated exploration licenses: PPL 435 and PPL 436, located in the Fly Platform, Papuan Basin. Both licences were scheduled to expire in November 2018, but Kina has submitted a new application covering both areas - APPL 642. This is also expected to be available to interested parties for farm in.  PPL 435 and PPL 436 cover a combined area of 19,380 sq km and were awarded in 2012, for six years. Rather than extend the licences, with associated area reductions, Kina submitted APPL 642 to maintain its position in the basin. APPL 642 covers an area of around 16,900 sq km over main prospects which are considered to lie along a liquids fairway extending from Elevala-Ketu, in PRL 21. The application also extends eastward into an expired licence area held by Kengaku, hosting the Saratoga prospects, located to the south of the Panakawa oil seep. The timeline for an exploration licence to be awarded or refused by the Minister for Petroleum and Energy is variable. Based awards within the area, this could be around 18 months.  Under previously scheduled work commitments, one well was planned (to a minimum of 1,000 m, at a forecasted cost of AUD 20 million). However, the commitment to drill was replaced by the acquisition of seismic which was scheduled for late-2016/17. The option to remove the well commitments and complete an additional phase of seismic would allow the existing prospects to be further delineated with additional seismic control before moving to a drill phase. Any newly approved work programme in relation to application APPL 642 is likely to contain a seismic commitment which potential partners would be asked to assist in.     Recent seismic reprocessing/interpretation and any planned, new 2D seismic data acquisition, will likely focus on delineating the Aiambak and Lake Murray East leads in PPL 435 and the Sturt, Alligator, Dalbert, and Oriomo prospects in PPL 436. The combined prospects and leads are estimated to contain prospective resources over 13 Tcf gas and 181 MMb liquids (best estimate).     Aeromagnetic and gravity survey data has been acquired (completed in June 2014) which has been merged and interpreted by Kina alongside reprocessed vintage 2D seismic data. The gravity data defines the Aiambak and Alligator/Sturt Prospects which are located on the hanging wall of the southern Fly Platform edge. Aiambak is located updip of the Lake Murray 1 well which was drilled in 1973, encountering gas in the Toro Sandstone. Kina considers the prospect to be in connection with the well after gas testing. Alligator and Sturt prospects are located updip of oil seeps observed at the Panakawa 1 well. Through source-migration studies, Kina believes that the prospects have potential to receive charge from oil mature sources rocks from the Wabuda and Morehead Troughs.    Cott Oil and Gas Ltd completed a farm-in to PPL 435 and 456 in mid-February 2013. However, Cott subsequently withdrew in July 2015 to focus on other areas of its portfolio. Kina is now seeking farm-in partners for both PPL 435 and PPL 436 (and APPL 642 upon award).    The PPL 435 and PPL 436 licences cover a combined area of 19,380 sq km and were awarded on 25 July and 30 November 2012 respectively, for a period of six years. Kina Petroleum Corp holds 100% interest and operatorship of both permits. APPL 642 covers an area of around 16,900 sq km and was registered with the Department of Petroleum & Energy on 2 May 2019.    Companies interested in pursuing this opportunity should contact:     Richard Schroder – Kina Petroleum MD    Tel: +61 2 8247 2500     Email: richard.schroder@kinapetroleum.com","(Papuan b.) PPL 435 & 436 op. by KINA PT (100%), Kina Petroleum Corp is offering equity in its wholly owned and operated exploration licenses: PPL 435 and PPL 436, located in the Fly Platform, Papuan Basin. Both licences were scheduled to expire in November 2018, but Kina has submitted a new application covering both areas - APPL 642. "
52000,"Odin is looking to farm-down its wholly-owned Raseiniai block, 1,520 sq km in the Baltic Syneclise, and Rietavas block, 1,594 sq km further east in central Lithuania, share negotiable. Contact: tom.odinenergi@gmail.com.","Odin is looking to farm-down its wholly-owned Raseiniai block, 1,520 sq km in the Baltic Syneclise, and Rietavas block, 1,594 sq km further east in central Lithuania, share negotiable"
36474,"On 28 November 2018, New Stratus Energy Inc (NSE) reported that the exclusivity period for the letter of intent (LOI) with Vetra Energia has expired, yet negotiations continue for exploration and production assets in the Llanos and Putumayo basins. The LOI was announced on 31 May in which Stratus will acquire Vetra for a base price of USD 88.5 million and the transaction was anticipated to close by 31 July 2018. Vetra is a Spanish company that owns the following acreage: Llanos Basin exploration blocks include 100% of the LLA-5, LLA-64, LL-78, in addition to the La Punta Block on which the Santo Domingo field is located. Putumayo Basin exploration acreage includes the PUT-8 with 50% interest, while a 69.5% interest share belongs to Vetra in each of the following Suroiente Block fields – Cohembi, Pinuna-Quillacinga and Quinde. This deal will represent NSE’s entry to Colombia.","New Stratus Energy Inc, Vetra Energia SL acquisition LOI for assets in Llanos and Putumayo basins"
59774,"ONE-Dyas spudded exploration well Maasmond-1 on 27 June 2019 using the “Deutag T46” L/R. The top-hole location is onshore in the Rotterdam Europoort area (covered by NAM’s Botlek III licence) but the well is deviating offshore to the Charly-North prospect in the Q16b and Q16c-deep licence which is below top Triassic. Operations were completed on the 22 September 2019 and the well was reported to be gas bearing. On 27 September 2019 further information had not been released.  ONE-Dyas produces oil from the Q16-Maas field which straddles licences Botlek-Maas, T1, Q16c-diep and P18d. Q16-Maas was discovered in August 2011 by exploration well Maasgeul-3ST1 which also deviated from the same onshore location as Maasmond-1. First gas was achieved in April 2014. The field contains approximately 29 Bcfg in a Triassic Bunter Sandstone reservoir at a depth of around 2,500 m. Due to the high condensate:gas ratio an LNG stripping facility has been installed at the gas treatment plant at the wellsite. The wellstream is split into one gas and three liquids (condensate, propane and butane) streams. The produced gas is exported directly into the GTS network. A new development sidetrack (Maasgeul-3ST3) was drilled in 2018.  Interest in Q16b and Q16c-deep licence is divided between ONE-Dyas BV (49% + operator), Energie Beheer Nederland BV (40%) and TAQA Offshore BV (11%).","Maasmond 01 (MSM-01) nfw. (ONE-Dyas Op 49%, TAQA Offshore 11%, EBN 40%) in Botlek III block had reportedly encountered gas with operations likely to conclude shortly."
67626,"It is thought that around mid-2019 Repsol SA possibly entered into a Sales Purchase Agreement (SPA) to divest its entire Papua New Guinea portfolio. The signing of the agreement was followed by a period of exclusivity, which ended in September 2019. The SPA progression could depend on financier and ministerial securities. The Minister for Petroleum will need to provide the ministerial securities to show the government's support for the development of the Stanley field, located in PDL 10 and remove the cancellation notice assigned to the licence. It's understood that the Minister has already shown his support to the field development and has encouraged the purchaser to continue with the agreement. In order to clear the licence of the cancellation notice, the Minister will require clearance from the Department of Petroleum.  Repsol again packaged up its entire PNG portfolio in early-2019 as it looks to exit the country. Repsol acquired its PNG portfolio in 2015 through the purchase of Talisman Energy. With the assets not laying in Repsol’s core focus, it has been looking to exit the country. Repsol has already been successful in reducing its exploration licences and applications in PNG, including PRL 38 which covered the 900 Bcf, offshore, Pandora field. The remaining assets are now thought to form the basis for the sales agreement - however, it is not exactly known which assets will remain if the sale goes ahead as expiring exploration and retention licences may be allowed to lapse to reduce the purchase costs. In early-December 2019, the pre-emptive rights options for the current joint venture partners was available. The outcome could be known by end-December 2019 / Q1 2020.   Repsol currently holds interest through four local, 100% owned, subsidiary companies. Net 2C resources in PNG total around 1.5 Tcf gas and 25 MMb condensate (285 MMboe combined) across a range of assets with joint venture partners: Horizon Oil, Kina Petroleum, Kumul Petroleum, Oil Search, Osaka Gas, P3 Global Energy and Santos. Gross 2C resources in the permits are in the order of 3 Tcf gas with 65 MMb condensate across late Jurassic to Early Cretaceous clastic reservoirs.  Repsol had entered into a sales agreement in 2018 with Balang International Pte Ltd. Balang, a subsidiary company of China Changcheng Natural Gas Power Co, had agreed to purchase all shares in Repsol’s local entities, subject to conditions, which were expected to be completed by Q4 2018. However, ongoing issues relating to PDL 10 and the Stanley field delayed the transaction, which likely heavily contributed to the deal collapse. The offer was withdrawn in early-2019.",Repsol possibly entered into a Sales Purchase Agreement (SPA) to divest its entire Papua New Guinea portfolio.  
25952,"Further to 18 Jul ’18. WA-437-P, Greater Phoenix area in N. Carnarvon Basin (Bedout), while well is still the hydrocarbon bearing zone, wireline evaluation results have provided more information. In addition to the Caley Mb light oil find, 10.5m of net gas and condensate pay encountered in the Baxter Mb, good quality reservoir, though maybe a gas cap to further oil resources. 7” liner being set ahead of drilling to 4,550m to further evaluate the Baxter sand and the secondary targets in the Crespin and Milne. Ensco 107 JU. Quadrant (op), partner Carnarvon.","Dorado 1 (Quadrant 80% op, Carnarvon 20%) in WA-437-P (Greater Phoenix area), wireline evaluation results have provided more information. In addition to the Caley Mb light oil find, 10,5m of net g & cond. pay encountered in the Baxter Mb, good quality reservoir, though maybe a gas cap to further oil resources. 7” liner being set ahead of drilling to 4,550m to further evaluate the Baxter sand and the secondary targets in the Crespin and Milne fms."
75958,"EPUKI has acquired Petronas' subsidiary Humbly Grove Energy Ltd, taking over fully the Humbly Grove gas storage facility in Hampshire in the process. Humbly Grove, in PL 116, was converted from production into a hub for processing crude from a number of small onshore fields in Southern England. EPUKI is otherwise involved in gas storage in the Czech Republic, Slovakia + Germany.","United Kingdom, PL 116"
38691,"Murphy Oil Corp and Mitsui & Co Ltd are looking to farm out equity in three Bonaparte Basin permits.  Murphy is the operator with 60% interest in AC/P57, AC/P58 and AC/P59, which are located in the Vulcan Sub-basin and cover a total of 4,300 sq km. Joint venture partner Mitsui holds the remaining 40% interest in the permits. Both companies are looking to farm-down around half of their respective interests in return for assistance in funding the future exploration programmes.  As of early January 2019 it is thought the companies were looking to conclude the farm-out process. No deals have yet been announced for the acreage.  Murphy had been finalising prospect mapping across the acreage before releasing the permits for farm-in early-2018. A data room was opened in Perth from March 2018. Interested parties must book to access, and sign a confidentiality agreement.  All but the northern area of AC/P58 is fully covered by 3D seismic data with tie-in wells. AC/P59 crosses the Caswell and Vulcan sub-basins between the Crux gas discovery, the Sinopec operated Puffin field and PTTEP operated Montara, Skua and Swift oil fields. AC/P57 lies directly east of the Puffin field within the Vulcan Sub-basin and AC/P58 lies north of the PTTEP operated Oliver and Audacious oil fields within the northern extent of the Vulcan Sub-basin.  Murphy considers the permits to be prospective for oil accumulations. Through 18 oil discoveries across the Sub-basin, around 380 MMb oil on a 2P recoverable basis has already been discovered, primarily in the Plover, Vulcan and Puffin sandstones across both stratigraphic plays and structural plays, including unconformities, tilted fault blocks and anticlines. Gas reserves in the basin are around 6 Tcf.  In AC/P57 leads have been identified with the potential for recoverable resources of 160 MMb. Murphy previously suspended the AC/P57 permit work programme for a 12 month period, in 2017, facilitating time to licence 284 sq km of New Broadband Long Cable Cygnus 3D seismic data over the south east of the permit, at a cost of around AUD 1.97 million.  In AC/P58 it is planned to extend the seismic coverage to identify further prospects and leads.  AC/P59 has the primary two prospects in the assets, with Hawking, an anticlinal prospect, and Fisher, a tilted fault block.  Murphy reports it has estimated potential recoverable resources of 350 MMb. The joint venture extended AC/P59 for 12 months by licensing 660 sq km of Cygnus seismic data for around AUD 3.9 million. Cygnus was acquired by Polarcus in 2015/16. Two additional phases of the survey are due to extend the coverage to the north within the basin.  The three permits were awarded to Murphy with joint venture partner Mitsui on a 50% equity split, in 2014/15. Murphy increased its holding to 60% in 2015.    In the remaining, non-committed, work programmes, well planning is scheduled to take place between 2018 and 2020, with one optional exploration well in each permit between 2019 and 2021. Water depths across the permits range from around 50 to 500 m and well costs are estimated at around AUD 60 million each (valid at the time of the work commitments registrations).   Within the Vulcan Sub-basin three areas were offered in the 2017 Australia Federal Government Offshore Acreage Release covering a total of 1,252 sq km. The areas were released for bidding on 16 May 2017 under a work programme bidding system and closed on 19 October 2017.   Murphy holds 60% interest and operatorship in AC/P57, AC/P58 and AC/P59 through subsidiary company Murphy Australia Oil Pty Ltd. Joint venture partner Mitsui holds the remaining 40% interest in each permit through its subsidiary Mitsui E&P Australia Pty Ltd. Both companies will be seeking to farm-down equity beginning in early 2018.  Companies interested in pursuing this opportunity should contact:    Paul Carroll, Exploration Manager – Murphy Oil Corp    Tel: +61 8 6313 5200    Email: paul_carroll@murphyoilcorp.com","Murphy Oil Corp and Mitsui & Co Ltd are looking to farm out equity in three Bonaparte Basin permits.  Murphy is the operator with 60% interest in AC/P57, AC/P58 and AC/P59, which are located in the Vulcan Sub-basin and cover a total of 4,300 sq km."
14787,"Aker Energy, a 50-50 joint venture between Aker ASA and TRG AS, has entered into an agreement with a subsidiary of Hess Corporation to acquire its interests in Ghana consisting of a 50 percent participating interest in the Deepwater Tano Cape Three Points block ('WT/CTP'). The Tano Basin offshore Ghana is a prolific petroleum region where Aker Energy sees considerable potential to apply the Aker Group's experience from the Norwegian Continental Shelf (NCS) to  build a significant E&P activity in Ghana together with Ghana National Petroleum Corporation ('GNPC'). The total cash consideration for the transaction is USD 100 million, consisting of USD 25 million payable upon closing of the transaction and a further USD 75 million payable upon approval of the Plan for Development and Operation (PDO) on the DWT/CTP block. The acquisition is subject to approval from relevant Ghanaian authorities and other customary closing conditions. The DWT/CTP block  The DWT/CTP block covers approx. 2,010 sq kms in a prolific petroleum region. In the last ten years, seven exploration wells and five appraisal wells have been drilled on this block. The discovered contingent resources are estimated to be 550 million barrels (2C) with a remaining prospective volume upside of approx. 400 million barrels. Aker Energy has drawn upon the expertise in oil field development from the companies in the Aker Group and is currently progressing a commercially robust development solution with a fast-track first phase targeting approx. 400 million barrels. The field development concept will be based on a FPSO with a subsea production system. The development concept will build on experience gained from the NCS with multilateral wells with improved completion solutions providing improved reservoir contact and recovery factor. Proven artificial lift solutions will further enhance recovery rates while infield pipeline solutions will ensure flow properties. The subsea production system will be designed to facilitate rapid tie-backs to the centrally located FPSO in the second phase. The PDO will be submitted in 2018 with anticipated first oil in 2021. Original article link Source: Aker ASA ","Ghana, not found"
12636,"On 19 June 2017, Eni Maroc B.V was awarded El Jadida Offshore reconnaissance licence by ONHYM, the Morocco national company. The new block is located south of Rabat Deep Offshore permit in the Doukkala basin. The objectives include the Cambro-ordovicain quartzite, Middle Devonian vuggy reefal carbonates and the Permo-Triassic sandstones and conglomerates. Eni is the operator of the block with a 75% interest and ONHYM retains the remaining 25% (carried). ","Eni Maroc B.V was awarded El Jadida Offshore reconnaissance licence by ONHYM,"
32820,"Equinor announced on 18 October 2018 that it has agreed to sell its non-operated interests in PL 044 to PGNiG. The licence contains the Tommeliten Gamma and Tommeliten Alpha discoveries. Equinor holds a 30% interest in PL 044 and a 42.38% interest in the Tommeliten Unit (PL 044 TA). The agreed purchase price is USD 220 million. Equinor stated that the sale is due to its focus on the Norwegian Continental Shelf and to prioritise projects that create higher value for the company. PGNiG, the Polish National Oil Company announced that the acquisition has significant importance as it looks to diversify its gas imports, currently it’s heavily dependent on Russia. Through the acquisition it will allow PGNiG to export gas from Tommeliten Alpha to Poland via Denmark through the planned Baltic Pipe pipeline. The deal is subject to regulatory approval with an effective date of 1 January 2018.  Tommeliten Alpha was discovered by Det norske in February 1977 by New-field wildcat 1/9-1. The first 2D seismic survey in block 1/9 was carried out in 1974 which consisted of a 1x1 km grid oriented northwest-southeast. The survey revealed the presence of four structures at the top of the ""Chalk"" Group: Alpha, Beta, Delta and Gamma. Seismic anomalies caused by gas were seen in the crestal areas and in the Tertiary section above Alpha, Delta and Gamma. Salt diapirs were interpreted below these three structures. Well 1/9-1 was drilled near the crest of the dome and encountered 100 m (330 ft) of porous and hydrocarbon-bearing chalk. In 2015, operator ConocoPhillips shelved it’s USD 2.24 billion development of Tommeliten Alpha due to low oil prices. Tommeliten Alpha would be developed using a similar subsea production system to Tommeliten Gamma and tied back to either the Ekofisk field facilities or the Valhall platform. However, additional reserves were required to justify a development. A final field investment decision was expected in early 2016 with aim to bring the field onstream in Q4 2019. Tommeliten Gamma, located 10 km to the north and was developed using a six-well subsea tieback to the Edda platform. From Edda the hydrocarbons were piped to the Ekofisk centre. Gas was then sent to Emden in Germany and liquids transported to Teesside in England. The field was abandoned in 1998 after almost 10 years of production. In July 2000, it was reported that the six gas production wells had been plug and the christmas trees removed.  Following completion of the deal interest in PL 044 will be divided between ConocoPhillips Skandinavia AS (41.88% + operator), PGNiG Upstream Norway AS (30%), Total E&P Norge AS (15%) and Eni Norge AS (13.12%). Interest in the Tommeliten Unit, PL 044 TA will be split by ConocoPhillips Skandinavia AS (28.26% + operator), PGNiG Upstream Norway AS (42.38%), Total E&P Norge AS (20.23%) and Eni Norge AS (9.13%).",Norway (Girardot Sub-basin (Upper Magdalena B.)) Delta
53590,"Likely in early July 2019, Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) reached the final depth in new-field wildcat Klecko 1 in the 10/2007/p Murowana Goslina-Klecko contract in western Poland. Voices in the street suggest the well came out short of expectations. The operational details of the well, solely operated by PGNiG, are being sought.  Klecko 1 was spudded on 14 February 2019, using the Bentec 450 (unit 350) drilling rig. The well is located in the eastern sector of the tract, approximately 35 km northeast of the city of Poznan and 10 km northwest of the city of Gniezno. The contract is situated within the Mogilno - Lodz Trough, tectonic unit of the Northeast German Polish Basin.    The well has a planned final depth estimated to be approximately 3,500 m, targeting the Permian series (it is believed the well is aiming to validate the presence and facial development of the Rotliegend reservoir, with the Zechstein Main Dolomite being a secondary target).  At the end of February 2019, the well reached a depth of 286 m in the Cretaceous series. News in mid-June 2019 said that the well was being drilled, nearing the target horizon.    Background Information    PGNiG was granted a five-year contract for the 782 sq km 10/2007/p Murowana Goslina-Klecko permit on 3 August 2007. The contract was granted from an out of bid round procedure. Likely in April 2017, PGNiG converted the contract holding the prospection/exploration rights into a joint exploration and production contract (the contract received a new designation: 10/2007/L).    The principal reservoirs in the area are related to the presence of Lower Permian Rotliegend sandstones (gas-bearing), as well as the Upper Permian Zechstein series (oil/gas).    The latest seismic exploration activity dates back to August 2014, when PGNiG concluded the acquisition of 2D seismic programme Owieczki-Bielawy partly covering the Murowana Goslina-Klecko block.","PGNiG reached the final depth in new-field wildcat Klecko 1 in the 10/2007/p Murowana Goslina-Klecko contract in western Poland. Voices in the street suggest the well came out short of expectations. The operational details of the well, solely operated by PGNiG, are being sought."
39341,"L31/50, onshore Khorat Plateau, P&A gas shows 13 Dec ’18, TD 4,009m, Sinopec 50765 rig. Targets Pha Nok Khao lmst + Phu Kradung sst.","Thailand, L31/50"
61556,"Echo has agreed with Petrolera El Trebol to acquire a 70% stake in 5 mature producing blocks in Santa Cruz Sur, Austral Basin, adjacent to Echo's existing Tapi Aike block. Plans include drilling + part-funding the Campo Limite explo well. The acquired assets will remain operated by Roch.","Argentina, Tapi Aike"
10056,"CNOOC has taken over the full interests in the Wenchang 13-1 / 13-2 fields in the South China Sea, following expiry of the CNOOC-Husky PSC on 15 Nov ’17. The fields have been producing since 2002 via 2 wellhead platforms and the Nan Hai Fen Jin FPSO, and were shared by CNOOC (op) and Husky 60:40.",China (Zhu-3 Depression (Pearl River Mouth B.)) Wenchang 13-1
9025,Trident Petroleum’s assignment of the 194-sq km North Magawish block 4 looks to have been finally signed up. It was offered in the 2014 Ganope round and won on 3 Aug ’15 in shallow waters of the Gulf of Suez Basin. Trident has committed to 4 wells.  ,"Egypt (Gulf of Suez B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: N. Magawish op. by TRIDENT (100.0%, MAGAPETCO 0.0%) to be check."
65481,"88 Energy indicated in late November 2019 that it has finalised its farm-out agreement with Premier Oil for 60% WI in Area A of the conventional Project Icewine acreage, sited in the Alaska North Slope Basin. The transaction was formally approved by the Division of Oil & Gas on 20 November 2019 and has an effective date of 1 October 2019. Area A encompasses the Malguk 1 discovery, sited in and drilled by BP in March/April 1991 on previous ADL 373006 (current ADL 393382). The well encountered 77m of light oil pay in turbidite sands in the Torok Formation, within the Brookian play. The well has yet to be tested. Premier estimates an accumulation of more than 1 Bbo (in place), according to original well data and its evaluation of the existing 3D dataset. There is also significant upside in the shallower Schrader Bluff Formation, which has yet to be explored in a play, with similarities to the Pikka/Horseshoe trend. 88E indicated in late August 2019 that the 'western play fairway' contains some 720 MMbbls of net prospective resources (2.4 Bbbls gross), the 'central play fairway' some 193 MMbbls of net prospective resources (373 MMbbls gross) and the 'eastern play fairway' with some 96 MMbbls (124 MMbbls gross). Under the terms of the Sale and Purchase Agreement, Premier will pay the full costs of an appraisal well up to a total of US$ 23 million to test the Malguk 1 discovery reservoir. This new apprisal well is planned to be both drilled and tested in Q1 2020. Following completion of the agreement, Premier Oil now holds 60% WI in Area A of the conventional Project Icewine acreage. The remaining Area A equity is shared between Burgundy Xploration (88E's Joint Venture partner in Project Icewine - 10% WI) and Accumulate Energy Alaska (88 Energy subsidiary - 30% WI).","88 Energy indicated in late November 2019 that it has finalised its farm-out agreement with Premier Oil for 60% WI in Area A of the conventional Project Icewine acreage, sited in the Alaska North Slope Basin. "
58180,"Tap has signed a sale agreement with Kensington Energy to dispose of its residual Australian and New Zealand holdings. Involved are 20% in BHP’s WA-72-R (Tallaganda gas find), 15% in Eni’s WA-25-L (Woollybutt field), 5% orri on o+g+c over 66.67% in PMP 38748 (Sidewinder field). Effective date of the sale is 31 Mar ’19.   Tap is still working on exiting WA-34-R (Prometheus + Rubicon fields), completion expected by year-end.","Australia, WA-25-L"
87209,"Equinor, operator of production licence PL 532, has concluded the drilling of wildcat well 7219/9-3. The well was drilled about 25 kms south of the Johan Castberg field in the Barents Sea and 220 kms northwest of Hammerfest. The primary exploration target for the well was to prove petroleum in reservoir rocks in the Upper Triassic to Lower Jurassic (the Tubåen Formation). The secondary exploration target was to collect data to improve understanding of potential reservoir rocks in the Upper Triassic (parts of the Fruholmen Formation). In the primary exploration target, the well encountered the Tubåen Formation with a thickness of about 110 metres, of which a total of 50 metres of sandstone layers with very good reservoir properties. About 290 metres of the Fruholmen Formation were drilled in the secondary exploration target, whereof several sandstone layers totalling 75 metres with reservoir properties varying from good to very good. The well is dry. The well was not formation-tested, but data acquisition has been carried out. This is the tenth exploration well in production licence 532. The licence was awarded in the 20th licensing round in 2009. Well 7219/9-3 was drilled to a vertical depth of 1306 metres below sea level, and was terminated in the Fruholmen Formation in the Upper Triassic. Water depth at the site is 326 metres. The well will now be permanently plugged and abandoned. Well 7219/9-3 was drilled by the Transocean Enabler drilling facility, which will now drill production wells for the development of the Johan Castberg field, where Equinor is the operator. Original article link Source: Equinor","(Barents Sea Platform) 7219/9-3 (Mist) nfw, in PL 532, part-blocks 7219/9, 7220/4, 5, 7 + 8, operated by EQUINOR (50%), VAR EN (30%), PETORO (20%), P&A'ing dry at TD 1,306m (Fruholmen fm).  In the primary exploration target, the well encountered the Tubåen Formation with a thickness of about 110 metres, of which a total of 50 metres of sandstone layers with very good reservoir properties. About 290 metres of the Fruholmen Formation were drilled in the secondary exploration target, whereof several sandstone layers totalling 75 metres with reservoir properties varying from good to very good. The well was not formation-tested, but data acquisition has been carried out. "
51608,"A 2nd Intracampos round is hoped to be launched under new PSC terms towards Nov ’19. Earlier plans were for 5 blocks to be offered in the Napo Basin, and possibly 14 ex-Petroamazonas fields if earlier plans are adhered to. More recently acreage in the S. Oriente Basin has reportedly been earmarked.   The future could see a Marañón Basin offer and offshore acreage in the Gulf of Guayaquil.","A 2nd Intracampos round is hoped to be launched under new PSC terms towards Nov ’19. Earlier plans were for 5 blocks to be offered in the Napo Basin, and possibly 14 ex-Petroamazonas fields if earlier plans are adhered to. More recently acreage in the S. Oriente Basin has reportedly been earmarked. The future could see a Marañón Basin offer and offshore acreage in the Gulf of Guayaquil."
67173,"Total has reached an agreement with Sonangol to acquire interests in offshore blocks 20/11 + 21/09 in the Kwanza Basin. Partnership becomes Total (op), 50%, BP 30%, Sonangol 20% in 20/11 (4,800 sq km), WD 300-1,700m, and Total (op) 80%, Sonangol 20% in 21/09 (4,882 sq km), WD1,600-1,800m. These blocks contain the Cameia, Mavinga, Bicuar + Golfinho for which a devt hub is to be set up.   Total will pay Sonangol USD 400 mMMillion at closing plus USD 100 MM at FID.","Total has reached an agreement with Sonangol to acquire interests in offshore blocks 20/11 + 21/09 in the Kwanza Basin. Partnership becomes Total (op), 50%, BP 30%, Sonangol 20% in 20/11 (4,800 sq km), WD 300-1,700m, and Total (op) 80%, Sonangol 20% in 21/09 (4,882 sq km), WD1,600-1,800m. These blocks contain the Cameia, Mavinga, Bicuar + Golfinho for which a devt hub is to be set up. Total will pay Sonangol USD 400 mMMillion at closing plus USD 100 MM at FID"
57477,"Deepwater Qiongdongnan Basin, WD 1,000m, ops terminated mid-Aug ’19, results n/a, HYSY 982 SS.","Lingshui 25-1W-1 (LS 25-1W-1) nfw Deepwater Qiongdongnan Basin, WD 1,000m, ops terminated mid-Aug ’19, results n/a, "
31674,"As of 28 September 2018, 88 Energy Ltd. Subsidiary Accumulate Energy has entered in an agreement to acquire a 69.1% working interest in 23 Great Bear Petroleum oil & gas leases on the North Slope adjacent to the company’s Icewine Project. According to a company press release “Consideration for the leases was a cash payment of USD 206,388 (net to 88E), of which USD 167,663 will be directed to lease rentals due by 1st October 2018.”  In addition, the company signed an oil & gas lease with the Arctic Slope Regional Corporation (ASRC) in five blocks located to the west of the Icewine Project.  The two acquisitions increase 88 Energy’s lease position by 45,239 net acres to 371,478 net acres across the Company’s three main project areas on the Central North Slope of Alaska.","88 Energy entered into an agreement with Great Bear Petr.(->20,1%, Borealis Alaska 10,8%) to acquire a 69,1% WI in 17 North Slope ADLs, adjacent to, and north of, the Central Play Fairway at Project Icewine."
20116,"Total is reportedly to take over Oryx’s 30% stake in the 405-sq km Haute Mer B block, the deal subject to waiver of pre-emption rights by other partners and govt approval. The USD 13.3 MM deal (inclusive of some back costs) should be effective Jan ’18. So far Total (op, 34.62%), Oryx (30%), Chevron (20.38%), SNPC 15%.","Total is reportedly to take over Oryx’s 30% stake in the 405-sq km Haute Mer B block, the deal subject to waiver of pre-emption rights by other partners and govt approval. The USD 13.3 MM deal (inclusive of some back costs) should be effective Jan ’18. So far Total (op, 34.62%), Oryx (30%), Chevron (20.38%), SNPC 15%"
55850,"CNH-R01-L01-A2/2015 contract block, Sureste Basin offshore, WD 42m, P&A oil shows late Jun ’19, Odin JU then drilled Xaxamani-2EXP. PTD was 4,325m, targets Pliocene + Miocene. Hokchi (op), partners Wintershall Dea + Talos.","Yaluk 1EXP nfw (Hokchi Egy 47,5% op, Sierra Blanca 27,5%, Talos 25%) in the CNH-R01-L01-A2/2015 block P&A with non-commercial o&gas shows."
63776,"Equinor Gulf of Mexico, on 1 November 2019, was awarded Mississippi Canyon Block MC 758 (G36782), sited in the Louisiana Coastal Basin. The block was originally offered as part of OCS Gulf of Mexico Lease Sale 253, held on 21 August 2019, which garnered more than US$ 159 million in high bids. Equinor Gulf of Mexico accounted for 23 of the high bids, worth a total of US$ 16.8 million. Following formal award, Equinor Gulf of Mexico is the operator and sole interest-holder (100% WI + Op) in MC 758.",Equinor (100%) was awarded Mississippi Canyon Block MC 758 (G36782).
80592,"Equinor, operator of production licence PL 827 S, has concluded the drilling of wildcat well 35/10-6. The well was drilled about 20 kms northwest of the Fram field in the northern part of the North Sea, and about 145 kms northwest of Bergen. The objective of the well was to prove petroleum in reservoir rocks from the Early Eocene and Late Palaeocene Age (Intra Balder and Sele Formation sandstones). Sandstones were not encountered in the Balder Formation. In the Sele Formation, sandstones were encountered with a thickness of about 40 metres with good to very good reservoir properties. The well is dry. Data acquisition has been carried out in the well. This is the first well in production licence 827 S. The licence was awarded in APA 2015. Well 35/10-6 was drilled to a vertical depth of 1907 metres below sea level and was terminated in the Lista Formation from the Late Palaeocene Age. Water depth at the site is 368 metres. The well has been permanently plugged and abandoned. Well 35/10-6 was drilled by the West Hercules drilling facility, which will now drill wildcat well 30/2-5 S in production licence 878 in the northern North Sea, where Equinor is the operator. Original article link Source: NPD","Norway (Utsira High (Horda Platform)) Balder  035/10-06 (Gabriel) nfw 1st well in PL 827 S, N. of Gnomoria discovery in WD 368m, TD 1,907m (Lista fm), Balder + Sele sst targets dry, P&A'd, Equinor (op), partner DNO. "
25591,"Woodside, on behalf of joint operator CNPC, reported the results of wildcat Aung Siddhi 1 in deepwater Block AD-1, located in the northern Rakhine Basin, on 19 July 2018. The well discovered gas in two primary sandstone objectives. Based on log interpretation, the upper sandstone contains a 60-m gross gas column with 10 m net gas pay. The lower sandstone contains a 45-m gross gas column with 16 m of net gas pay. The gas columns have been confirmed by pressure measurements and gas sampling. The well was drilled to a TD of 4,540 m. Further assessment of the discovery is underway.  Aung Siddhi 1 was drilled using Transocean’s “Dhirubhai Deepwater KG2” D/S at a water depth of 1,391 m, approximately 100 km southwest of the Myanmar coastline. Operations at the well were completed around late June 2018.  The rig reached location at the end of April 2018, and a pilot hole was likely drilled prior to the spud of the actual well. Aung Siddhi 1 was spudded on 2 May 2018. Drilling was underway as of late May 2018 at a depth of approximately 2,900 m. Operations were initially expected to take approximately 40 days.  Aung Siddhi 1 was targeting dry gas in Pliocene turbidite sandstones, with a PTD of 4,600 m. The play is likely analogue to the Thalin 1A discovery in block AD-7. Pre-drill resources at Aung Siddhi 1 have been estimated by the operator to exceed 100 MMboe.  Drillship “Dhirubhai Deepwater KG2” was hired by Woodside in November 2017 for a firm five-month drilling contract, starting from May 2018. After the completion of Aung Siddhi 1, the rig was mobilized to Block A-7 to drill wildcat Dhana Hlaing 1. The campaign is expected to continue with appraisal well Shwe Yee Htun in Block A-6 in July 2018. Additional wells could be drilled in block AD-1 and in the adjacent block AD-8 in 2019, depending on results of the initial drilling.  Woodside has agreed to acquire 50% interest from CNPC in blocks AD-1, and AD-8, plus shallow water block AD-6, subject to the fulfillment of certain conditions precedent. As of December 2017, the transaction was pending completion. Upon closing of the deal, Woodside will be the operator for deepwater drilling activities while CNPC will be in charge of liaisons with the government.  The previous activity in block AD-1 was wildcat Aung Pyi Hein 1 in early 2015. The well, located at a water depth of 1,700 m, was drilled to TD around 5,000 m using CNOOC’s “Hai Yang Shi You 981” S/S rig. The well was likely targeting Pliocene turbidite sandstones, and it was likely dry.    No wells have been drilled within block AD-8.    Blocks AD-1, AD-6 and AD-8 were officially awarded to CNPC (with 100% interest) in January 2007.    The farm-in to blocks AD-1, AD-6 and AD-8 will increase Woodside’s position in the northern Rakhine Basin, where the company holds interests in blocks AD-7 (40%, joint operator with POSCO Daewoo), AD-02 (45%, non-operator) and A-4 (45%, non-operator). Woodside also has interest in the central/southern Rakhine Basin, in blocks A-6 (40%, joint operator), A-7 45%, operator) and AD-5 (55%, operator).    Woodside has drilled three wells in block AD-7 between February and October 2017, using the “Dhirubhai Deepwater KG2” D/S. The first two wells, Thalin 1B and Thalin 2, appraised the Thalin 1A discovery. The third well, Khayang Swal 1, was targeting a different prospect in the southern part of the block, and it encountered water-wet sandstones. Khayang Swal is situated approximately 30 km west-northwest of Aung Siddhi 1.  Background Information    On 15 January 2007, Chinese state company CNPC signed three PSCs with Myanmar state company MOGE for the offshore blocks AD-1, AD-6 and AD-8. The frontier blocks lie within the Exclusive Economic Zone (EEZ) of Myanmar's waters in the Bay of Bengal, in proximity with POSCO Daewoo's blocks A-1 and A-3 in the Rakhine Basin. Water depths in AD-1 and AD-8 exceed 1,000 m, while AD-6 is located primarily in shelf waters.    Total signature bonus for Blocks AD-1, AD-6 and AD-8 is estimated at USD 10 million.    In November 2007 to January 2008, CNPC acquired 9,401 km 2D seismic survey covering blocks AD-1, AD-6 and AD-8. The data was acquired by BGP using the ""Dong Fung Kan Tan 1"" M/V. The company previously shot a single test line over Block AD-1 in May 2007. It is understood that Block AD-8 is the most prospective of the three blocks, although the 2D seismic data suggest that structural traps are not developed in Blocks AD-1 and AD-8. Relatively little exploration has taken place in the potentially gas rich deepwater area.    Exploration activities in the blocks were halted in 2009 due to boundary disputes with Bangladesh. However, the issue was resolved with a sentence by ILTOS in March 2012.    CNPC completed 2,100 sq km 3D seismic survey over two blocks, AD-1 and AD-8, on 21 January 2013. The survey was carried out by a 12-streamer geophysical vessel MV Hai Yang Shi You 720 owned by China Oilfield Services Ltd (COSL) in water depths range from 1,000 m to over 2,000 m. The survey commenced in early December 2012.    In block AD-6, CNPC conducted a two-well drilling campaign between March and May 2014. The wells, Aung Zabu 1 and Aung Zabu 2, were drilled at water depth of less than 100 m, likely targeting Pliocene sandstones. It is understood that both wells were dry.","Aung Siddhi 1 (Woodside and CNPC 50/50 JV) in DW Block AD-1, gas disc, in two primary sst. objectives. Based on log interpretation, the upper sst contains a 60m gross gas column with 10m net gas pay. The lower sst. contains a 45m gross gas column with 16m of net gas pay. The gas columns have been confirmed by pressure measurements and gas sampling. Well disappointing not commercial ?.   "
53187,"On 1 July 2019 MOL completed the acquisition of a 16% interest from Cairn subsidiary Nautical Petroleum and a 4% interest acquisition from Premier in licences P2070 and P2454. The acreage contains the Laverda discovery and Catcher North accumulation which is planned for development via single well tie-backs to Varadero. Drilling is scheduled to commence in 2020 with first oil targeted for early 2021. As part of the work Premier will also drill an infill well on its Varadero field to target resources out of reach of existing production wells, prior to drilling the Catcher North and Laverda development wells. The company will also shoot a 4D survey across the Catcher Area in Q2 2020 to confirm future infill well locations.   The Catcher Area Development comprises three fields: Catcher, Varadero and Burgman tied back to the BW Catcher Production Storage and Offloading (FPSO). From the FPSO the oil is shuttled by tanker and gas is exported via the gas pipeline tied to the Fulmar A to St Fergus gas Pipeline. Laverda is part of the Catcher Area Development expansion along with Catcher North.   Following completion of the deal interest in P2070 and P2454 is held by Premier Oil UK Limited (5% + operator), Cairn subsidiary Nautical Petroleum Limited (20%), Molgrowest (I) Ltd (20%) and ONE-Dyas E&P Limited (10%).",MOL completed the acquisition of a 16% interest from Cairn subsidiary Nautical Petroleum and a 4% interest acquisition from Premier in licences P2070 and P2454. The acreage contains the Laverda discovery and Catcher North accumulation
67696,"PPL 242, Cooper Eromanga, drilled 17 Nov – 10 Dec '19, susp oil at TD 4,235m. Senex (op), partner Beach subs.",Growler NE-2 appr Growler NE-2 appr
68717,"According to official reports from early-January 2020, Premier Oil and partner Rockhopper Exploration have signed a set of heads of agreement with Navitas Petroleum for the latter company to farm-in for 30% interest in the concession of PL 32 as well as the blocks of PL 4b & PL 4c blocks in the adjacent concession of PL 4. Premier is the operator on both blocks with 60% stake on PL 32 and 36% on PL 4 while Rockhopper holds all the remaining equity. PL 4a block was specifically excluded from the farm-out/farm-in, although Rockhopper as the majority holder in PL 4 has granted Navitas and Premier the option to do the same alignment in the block within the next eight years at an additional cost. Completion of the agreement is expected in Q1 2020.  PL 32 and PL 4 cover offshore deepwater areas of 541 sq km and 761 sq km, respectively, in North Falkland Basin.  The aforementioned areas of PL 32, PL 4b, and PL 4c include the Sea Lion field where Premier and Rockhopper plan to begin the first phase of development with the expectation to develop 250 MMbo (up from prior reports at 220 MMbo) over a 20-year period. Peak production of the field has been predicted at 85,000 b/d with associated capex to first oil estimated at approximately USD 1.8 billion. Latest reports from Premier and Rockhopper indicated that Front End Engineering and Design (FEED) phase for Sea Lion field was completed in Q1 2019. The companies entered into several service agreements during 2018 in preparation for the anticipated project, although Environmental Impact Statement for the project is still awaiting approval from the Falkland Islands government as of late-2019.  In addition, PL 4b block area covers the Beverley and Zebedee oil and gas discoveries from 2011 and 2015, respectively, while PL 4a block covers the Isobel Deep oil prospect from 2015.  Background Information  According to resource estimation done in May 2016, the Sea Lion field is estimated to hold 1,667 MMb of oil in place, with discovered 2C and 3C resources standing at 517 MMbo and 900 MMbo, respectively.",Premier has signed a preliminary agreement with Navitas for acquire a 30% interest in the Sea Lion project in in PL 032.
44597,"On 18 March 2019, industry sources reported that the National Petroleum Agency of Sao Tome & Principe (ANP-STP) awarded to French major TOTAL SA and Angola National Oil Company Soc Nacional de Petroleos de Angola (Sonangol E.P) the offshore Block 01 located in the Sao Tome & Principe Exclusive Economic Zone (EEZ). Following the payment of a USD 2.5 million signature bonus, Total will operate the area with 55% interest, alongside with Sonangol E.P (30%) and ANP-STP (15%). The new partners are committed to spend USD 1 million over a 4-year period on social projects in the country.  The undrilled Block 01 covers about 3,300 sq km, in water depths ranging 2,000 to 2,700 m. Block 01 is adjacent to the Nigeria-Sao Tome & Principe Joint Development Zone to the north, where Total also signed in mid-March 2019 an oil production sharing contract for three undrilled frontier blocks."," (Saint George Total and Sonangol have reportedly signed up the PSC for ultra-deepwater, 3,292-sq km Block 01,  8-year explo phase, 28 years total. Total (op) 55%, Sonangol 30%, Govt 15%. "
36267,"Petrobras has agreed to sell Perenco the Pargo field cluster for USD 370 MM, of which the Carapeba, Pargo, and Vermelho leases totalling 315 sq km in the Campos Basin. The deal is pending ANP + IBAMA approvals.  Perenco will be sole holder of the leases thereafter.","Perenco, acquired the Pargo, Carapeba and Vermelho shallow-water fields from Petrobras for US$370 MM."
52249,"Siccar Point Energy E&P Limited spudded exploration well 208/02-1 on 16 May 2019. The well was targeting the Lyon prospect in block 208/02 (P1854) and had a planned TD of 2,666 m. The company was using the “Ocean Greatwhite” S/S for operations. Lyon is a Paleocene/Eocene Balder/Flett Formation prospect thought to hold pre-drill mean recoverable resources of 1.4 Tcf (266 MMboe). The well was plugged and abandoned and as of 24 June 2019 the rig had left location. On 28 June 2019 Siccar Point announced that the well was drilled to a TD of 4,005 m encountering 44 m of siltstone and claystone with gas shows but no reservoir quality sandstones were encountered.  Licence P1854 comprises blocks 208/1b, 208/2, 208/3b, 217/27b and 217/28b. First Oil which previously operated licence P1854 estimated that a planned well on Lyon would cost in the region of GBP 42 million. In addition to Lyon, First Oil had identified three other prospects in the licence including the Eden prospect which is thought to have pre-drill recoverable resources of 456 Bcf (86 MMboe). TGS shot a 3D survey over the area in 2012 which has helped define the Lyon structure. Lyon has a strong class III AVO anomaly and the reservoir is prognosed to be the shallow marine Balder Sands. First Oil was originally awarded the licence as part of the 26th Seaward Licensing Round. In November 2017 Siccar Point announced that INEOS had farmed into the acreage taking a 66.66% interest and on 22 December 2017 an environmental statement was submitted for the well.    Interest in the licence is split between Siccar Point Energy E&P Limited (33.334% + operator) and INEOS UK SNS Limited (66.666%).","208/02-01 (Lyon) (Siccar Point 33,33% op, INEOS 66,67%) in P1854, P&A dry, Eocene Balder target interval contained 44m of siltstone and claystone with gas shows but the well did not encounter reservoir quality sandstone. WD=1452m, TD=4005m. "
20471,"Bridge Petroleum 5 Ltd has acquired Burgate E&P Ltd, Comtrack (UK) Ltd and Simwell Resources Ltd’s interest in block 113/27d (P2076), which contains the Castletown gas discovery. Prior to the deal with Bridge Petroleum, the three partners were seeking to farm-out Castletown to raise funds to drill an appraisal well.  Well 113/27-2 was drilled in 1988 by ESSO which discovered Castletown however the gas accumulation in the Triassic sandstones was considered too small to develop. A new evaluation, using depth migrated 3D seismic data, indicated that the well was drilled down flank and through a major fault causing a large gas accumulation remains to be proven up-dip. The Mercia Mudstone Group provides a regional seal which attains a thickness of 1,000 m across the basin. Gas charge comes from the Carboniferous Coal Measures which underlie much of the basin.   Following completion of the deal interest and operatorship of P2076 is held solely by Bridge Petroleum 5.","United Kingdom, P2076"
58541,"On 10 September 2019, Cairn reported with its 1st half 2019 results that it has swapped 15% working interest with ENI with ENI entering the CNH-R02-L01-A9.CS/2017 contract operated by Cairn subsidiary Capricorn, and Cairn acquiring a 15% working interest in the ENI operated CNH-R02-L01-A10.CS/2017 contract.      Capricorn Energy is operator of      the CNH-R02-L01-A9.CS/2017 contract and held 65% working interest and      Citla Energy held 35% working interest.  Cairn reported it now has 50% working      interest, Citla has 35% working interest, and ENI holds 15% working      interest.    In the ENI operated CNH-R02-L01-A10.CS/2017      contract, ENI held 80% working interest and Lukoil had a 20% working      interest.  ENI now holds a 65%      working interest, Lukoil 20% working interest, and Capricorn holds 15%.    The deal is pending formal      approvals.  Capricorn      plans to spud the Alom 1EXP in the CNH-R02-L01-A9.CS/2017 while ENI has      plans to spud the Saasken 1EXP in the CNH-R02-L01-A10.CS/2017 block.  Both wells are expected to spud by 4th      quarter 2019.   On 16 May 2019, the CNH approved a modified exploration plan for the Capricorn operated CNH-R02-L01-A9.CS/2017 PSC contract, Area 9 block involving only changes to the drilling schedule of prospects and a change in the proposed budget. From its November 2018 approved exploration plan Capricorn had planned to drill the Bitol-Kukulkan prospect first and the Alom prospect second.  This has been changed to drilling the Alom prospect first and the Bitol-Kukulkan prospect second.  The second modification in the exploration plan is an increase in the well drilling budget.  The total budget approved for the exploration plan is USD 125.85 million.  The estimated drilling expenditures for the two commitment wells increased from USD 105.21 million to USD 113.20 million.  The Alom prospect is to be drilled first and has an estimated proposed total depth of 3,000 m in a water depth of 140 m.  It is targeting stacked, DHI supported Pliocene sandstones starting at 1,550 m.  The prospective resources now reported for the Alom prospect is 103 MMboe.  The overlapping Bitol and Kukulkan prospects have been merged into one prospect, Bitol-Kukulkan, as reported by the CNH.  The NFW will be drilled directionally to an estimated proposed total depth of 5,300 m in a water depth of 180 m.  It is targeting stacked Pleistocene, Pliocene, and Upper and Lower Miocene sandstones from 765 m to 3,980 m.  The prospective resources now reported for the Bitol-Kukulkan prospect is 261 MMboe.  Parent company Cairn contracted the “Maersk Developer” S/S to drill its commitment wells commencing in 3rd quarter 2019.  On 7 May 2019, the CNH approved the drilling permit request submitted by ENI for the CNH-R02-L01-A10.CS/2017 PSC contract, Area 10 block and the Saasken 1EXP directional new-field wildcat (NFW).  The Saasken 1EXP is located in the south-western corner of the block and the primary targets are the Lower Pliocene and Lower Miocene with secondary targets in the deeper Oligocene and Eocene. The proposed total depth (PTD) for the NFW is 4,563 m measured depth.   The “Ensco 8505” J/U will drill the well in a water depth of 354 m.   The well was scheduled to spud in mid-June 2019.   The Saasken 1EXP drilling cost is estimated at USD 51.77 million and abandonment costs are estimated to be USD 4.13 million. The prospect trap is reported to be an anticlinal structure related to a salt intrusion with related normal faulting.  The operator has the option of drilling to its deeper Oligocene and Eocene targets pending results obtained drilling its primary Pliocene and Miocene targets.   On 14 March 2019, the CNH approved of the working interest exchange between ENI and Lukoil in the CNH-R02-L01-A10.CS/2017 contract and CNH-R02-L01-A12.CS/2017 contract.  In the CNH-R02-L01-A10.CS/2017 PSC contract, Area 10 block, ENI previously held a 100% working interest.  The new working interest breakdown is ENI operator with 80% working interest and Lukoil with 20% working interest.   On 25 September 2018, the CNH approved the exploration plan presented by ENI for the CNH-R02-L01-A10.CS/2017 PSC contract, Area 10 block from the CNH-R02-L01/2016 Bid Round.","Cairn reported with its 1st half 2019 results that it has swapped 15% working interest with ENI with ENI entering the CNH-R02-L01-A9.CS/2017 contract operated by Cairn subsidiary Capricorn, and Cairn acquiring a 15% working interest in the ENI operated CNH-R02-L01-A10.CS/2017 contract.  Capricorn Energy is operator of the CNH-R02-L01-A9.CS/2017 contract and held 65% working interest and Citla Energy held 35% working interest.  Cairn reported it now has 50% working interest, Citla has 35% working interest, and ENI holds 15% working interest.  In the ENI operated CNH-R02-L01-A10.CS/2017 contract, ENI held 80% working interest and Lukoil had a 20% working interest.  ENI now holds a 65% working interest, Lukoil 20% working interest, and Capricorn holds 15%."
22109,"Exxon signed up the PSCs for undrilled offshore blocks V, W and ND 10 on 12 Mar ’18, partner Petronas 50%. Commitments include acquisition and reprocessing of new 3D seismic + 1 well in each block within 3 years.   Frontier blocks V (2,900 sq km) + W (4,600 sq km) straddle the Baram Delta + NW Sabah Trough ultradeepwaters.   ND 10 lies in the NW Sabah Platform (Dangerous Ground) WD","Exxon signed up the PSCs for undrilled offshore blocks V, W and ND 10 on 12 Mar ’18, partner Petronas 50%. Commitments include acquisition and reprocessing of new 3D seismic + 1 well in each block within 3 years. Frontier blocks V (2,900 sq km) + W (4,600 sq km) straddle the Baram Delta + NW Sabah Trough ultradeepwaters. ND 10 lies in the NW Sabah Platform (Dangerous Ground) WD"
85979,"Tethys Petroleum reports the results of testing the exploration well Klymene KBD-02 drilled in the company’s Kul-Bas contract area (block 1897RD Kul-Bas), North Ustyurt Basin. The test period for the first zone (Jurassic) has been completed and the testing for the second potential zone has been initiated. The test in the first zone was done using different choke sizes between 5 and 11 mm. The 11 mm choke increased production to over 700 bo/d from 400 bo/d on 9 mm choke achieved in June.  Tethys has now tested a second zone at depths of 2127.4 - 2145.4 m (possibly in the Cretaceous). The test produced at an average rate of 15.5 tonnes/hour or 372 t/day (approximately 2,700 bo/d) using an 11 mm choke. On a 9 mm choke, the average production rate was 276 t/day (2,000 bo/d). The oil quality is high, the pressure is very good and currently there is no water present.  Over the next 10-12 days, wireline logging, work with different chokes and pressure tests will be carried out. The current storage and distribution capacity on the site is limited and this may affect Tethys' ability to run tests with larger choke sizes.   The well has been drilled to a TD of 2,750 m, it was spudded in summer 2019. The well was originally supposed to take between 3 and 4 months to complete but took longer time due to a combination of circumstances including finance, harsh weather and the pandemic.   Background Information  Klymene is located to the west of the current producing fields in Tethys’ Akkulka exploration contract (Kyzyloy, Doris, Akkulkovskoye and others). The prospect was identified from seismic acquired and interpreted by Tethys in 2013 and indicates a four-way dip closure with bright spots at 2 of 3 prospective stratigraphic levels within the Cretaceous and Jurassic sequences, both of which are productive in the Doris oilfield some 60 km to the east. The Klymene prospect has the potential to be an order of magnitude bigger than the Doris oil discovery and surrounding prospects (the geographical area of the prospect is up to 10 times the areal extent of the Doris oil field). Klymene has been independently estimated to hold 422 MMb of unrisked mean recoverable oil resources.  Tethys has previously drilled one exploration well, Kalypso KBD 01, in the Kul-Bas contract area. The well has not been completed.  In February 2020, the company received confirmation of an extension of the Kul-bas Exploration Contract until December 31, 2022.","(North Ustyurt b.) Klymene KBD 02 explo well, operated by TETHYS PT (100%) in 1897RD Kul-Bas block, was now tested in a second zone at depths of 2127.4 - 2145.4 m (possibly in the Cretaceous). The test produced at an average rate of 15.5 tonnes/hour or 372 t/day (approximately 2,700 bo/d) using an 11 mm choke. On a 9 mm choke, the average production rate was 276 t/day (2,000 bo/d). The oil quality is high, the pressure is very good and currently there is no water present.  "
56849,"Equinor spudded an exploration well targeting the Sputnik prospect in PL 855 on 18 June 2019 using the “West Hercules” S/S. 7324/6-1 is located approximately 30 km northwest of the Wisting discovery and approximately 6 km from the Gemini North discovery, drilled in 2017, in the same licence. The well was targeting a large channel system in the Upper Triassic Snadd Formation and the Middle Jurassic Sto Formation was a secondary target. Gas above oil was expected in the Sto Formation while just oil was expected in the Snadd Formation. Equinor drilled to 746 m and, for a period of around two weeks, temporarily suspended the well whilst waiting for BOP repairs and maintenance to be completed. The well was then drilled to TD at 1,600 m in the Snadd Formation. A 15 m oil column has been proven in the middle part of the Snadd Formation with an OWC at 1,354 m. The reservoir quality is poor. The upper and lower parts of the Snadd Formation also contained sandstones (60 m and 45 m respectively), but again quality was poor and both sands were water-wet. The Sto Formation contained a good quality, water-bearing sandstone which was 20 m thick. Estimated recoverable reserves are 20-65 MMboe. The well was abandoned on 31 July 2019.  7325/4-1 was drilled in 2017 targeting the Gemini North prospect. The well had objectives in the shallow Jurassic Realgrunnen Group (743 m) and the Upper Triassic Snadd Formation (812 m). Both were expected to contain oil similar to nearby Wisting. However, instead of the anticpated oil, gas was discovered in the main objective. A 19 m gas column (no GWC) was proven in the Middle Jurassic Sto Formation, which had good reservoir quality, and a 5 m oil column was encountered in a poor quality Snadd Formation. Estimated recoverable reserves were reported to be 14 – 35 Bcfg and 0.6 – 1.9 MMbo and the find was declared non-commercial.    Equinor Energy AS operates PL 855 with a 55% interest. It is partnered by OMV (Norge) AS (25%) and Petoro AS (20%).","7324/06-01 (Sputnik) (Equinor 55% op. OMV 25%, Petoro  20%) in PL 855 (30 kms NE of the Wisting disc.), P&A, oil disc. encountered poor reservoir quality sands in various parts of the Snadd Fm and 20m of good quality aquiferous sands in the Sto Fm, preliminarily discovery size estimated at 19 – 63 MMbbbl of oil. Fluid samples from the well contained light oil and water. TD=1569m, WD=449m"
82401,"Bahamas Petroleum Company has announced that, in its efforts to expand the Company's portfolio options, it has been awarded the AREA OFF-1 petroleum licence offshore Uruguay. Highlights 	BPC has been awarded the OFF-1 licence, offshore Uruguay 	OFF-1 contains a management estimated resource potential of up to 1 billion barrels of oil equivalent (BBOE), based on current mapping from multiple exploration plays and leads in relatively shallow waters with significant running room 	The OFF-1 licence play system is directly analogous to the prolific Cretaceous turbidite discoveries currently being evaluated/developed offshore Guyana and Suriname 	OFF-1 has an initial 4-year exploration period, with a work obligation limited to reprocessing and reinterpretation of selected historical 2D seismic data - there is no drilling obligation, and the licence includes staged no-cost exit points at BPC's sole election 	OFF-1 is thus comparable to the 'low cost option' represented by BPC's licences in The Bahamas when they were first awarded - a modest work commitment over 4 years that secures a sizeable, technically high quality, frontier play, with regional seismic available and exciting exploration upside 	Uruguay is a stable, well-regulated operating environment with an attractive, internationally comparable fiscal regime 	BPC believes that OFF-1 has the capacity to generate similar value uplift to the Company's existing licences in The Bahamas, where the Company's primary focus remains commencement of exploration drilling on Perseverance-1, expected to spud in late 2020 / early 2021, and targeting recoverable P50 oil resources 0.77 billion barrels, with an upside of 1.44 billion barrels Simon Potter, Chief Executive Officer of Bahamas Petroleum Company, said: 'The scale of the opportunity that our planned drilling campaign in The Bahamas may unlock for us, at the end of 2020, means that our personnel are and will remain entirely focussed on their efforts to deliver the Perseverance-1 exploration well successfully.   However, the current period of introspection in our industry is presenting nimble, forward-thinking companies such as ourselves with compelling opportunities to expand our portfolio and achieve countercyclical growth. The recently-closed Open Licencing round in Uruguay presented exactly such an opportunity for us where, for very low cost, we have been able to secure an exploration licence of an extremely high-calibre that, even as recently as a few months ago, we most likely would have been outbid on by much larger players.   We are especially pleased to have been awarded OFF-1 given that the licence represents a similarly underappreciated opportunity to that secured by the Company in 2007 in The Bahamas - a licence in a region with extensive existing seismic of various vintages, but largely underexplored, and requiring the application of more modern, state of the art seismic imaging technology and techniques to understand the full extent of the petroleum resource.   We are confident that over the next four years we can bring to bear our expertise, gained in The Bahamas over the past decade, on OFF-1 so as to more fully evaluate the licence's potential, in the hope that in the longer-term we can create an opportunity of equal value and industry interest to what we have thus far accomplished in The Bahamas.' Click here for full announcement Source: Bahamas Petroleum","(Pelotas B.) BPC (Bahamas Petroleum Company) announces the award of offshore block OFF-1 for 4+3+3 years explo, commitments seismic reprocessing + reinterpretation of vintage 2D seismic. OFF-1 was on offer in the country's open round and covers ab. 15,000 sq km in WD 20-1,000m. BPC's rationale is owed to perceived similarities between the area and the Guyana - Suriname basins.BPC will hold a100% interest in the licence, however, ANCAP has the right to back-in for up to a 20% participating interest in each commercial field that is developed."
17848,"Bahrain, the smallest oil producer in the Arabian Gulf, has made an oil discovery off its west coast - the largest since the commodity was first discovered in the country in 1932.'The find represents the largest discovery of oil in the kingdom since 1932, when extraction started on Bahrain’s first oil well within the Bahrain Oil Field,' the state-run Bahrain News Agency reported on Sunday. 'The new resource is forecast to contain highly significant quantities of tight oil and deep gas, understood to dwarf Bahrain’s current reserves.'Most of Bahrain's current oil production, which averages 210,000 barrels per day, comes from the offshore Abu Safah field, which it shares with Saudi Arabia, the world's biggest oil exporter. Bahrain produces around 50,000 bpd from the Bahrain Oil Field, according to the Energy Information Administration.'The discovery, which is expected to support extensive, long-term downstream activities, follows a recent uplift in oil and gas exploration projects,' the news agency said. 'Last year the [Higher] Committee [for Natural Resources and Economic Security] took the decision to accelerate initiatives to explore sites to the west of Bahrain, which resulted in the discovery of the resource and oil being struck in the fourth quarter of 2017.'Bahrain will start the development of its tight gas reserves this year, the minister of oil told The National in January, even as the country prepares to bring online a liquefied natural gas import terminal in 2019 to meet its rising domestic demand.Bahrain has 'large' tight gas deposits within the onshore Khuff reservoirs, said Sheikh Mohammed bin Khalifa Al Khalifa in January.The kingdom is likely to cooperate with international oil companies to develop its latest discovery, according to Iman Nasseri, acting managing director - Middle East at London-based Facts Global Energy.'They will need either international oil companies or a partnership with one of the major independent shale producers in the States to help them get it off the ground,' said Mr Nasseri.Development of tight oil and gas will be difficult, but some countries in the region are making headway in this field. Oman, the biggest oil producer in the Middle East outside Opec, is pumping tight gas from Khazzan field with the help of BP .'There are major issues to deal with when it comes to shale developments,' said Mr Nasseri. 'On the gas side, however, it is gradually happening with Oman’s Khazan field being developed now and Saudi Aramco also working on their shale gas development.'Bahrain is undertaking various projects to develop its energy sector.Last year it awarded TechnipFMC a $4.2 billion contract to expand the capacity of its sole Sitra refinery to 360,000 bpd from 267,000 bpd. The kingdom plans to develop an aromatics facility in a joint venture between state-owned Bahrain Petroleum Company and Kuwait’s state-owned Petrochemical Industries Corporation. Work is already under way on the aromatics project, with front end and engineering and design work already, Sheikh Mohammed said in January.The kingdom is also building an 800 million cubic feet a day terminal to import liquefied natural gas to meet its rising needs for power generation and industrial use.Bahrain is unlikely to halt plans to import LNG in light of the new discovery.'We believe Bahrain will start importing LNG from 2019 and its imports will gradually rise to around 5 million tons per year by 2025,' said Mr Nasseri.Original article linkSource: The National","Bahrain has discovered the country’s largest oilfield in decades, located off the west coast in the Khaleej Al Bahrain basin. The new tight oil & deep gas resource is expected to contain many times the amount of oil produced by Bahrain’s existing oilfields, as well as large amounts of gas. The oil discovery is the kingdom’s largest since 1932. Any details has not yet disclosed on the potential of the newly discovered resource."
25542,"Magellan play in Eastern offshore block 5, 1st of 3 commitment wells planned in 2H ’18 (spudded 12 Jun), gas discovery, Deepwater Invictus DS then to Bongos-1 off NE Trinidad.","Victoria 1 (BHP 65% op, Shell 35%) in block TTDAA 5, gas disc. (adds to BHP’s 2016 LeClerc Miocene-aged natural gas find)."
25602,"Further to DEA 5 Jul ’18: N. part of AD-1, deepwater N. Rakhine Basin, WD ca. 1,400m, TD 4,540m, gas discovery, 60m gross, 10m net pay in an upper sst, 45m gross + 16m net in a lower sst. Target Pliocene turbidites, Dhirubhai Deepwater KG2 DS.","Aung Siddhi 1 (Woodside and CNPC 50/50 JV) in Block AD-1, gas disc, in 2 primary sst. objectives (Pliocene-aged turbidite channel complexes?). Based on log interpretation, the upper sst contains a 60m gross gas column with 10m net gas pay. The lower sst. contains a 45m gross gas column with 16m of net gas pay. The gas columns have been confirmed by pressure measurements. Low net to gross suggests reservoir quality may be insufficient for commerciality. Well disappointing not commercial ?.   "
86831,"Eni is on the lookout for a couple of offshore rigs as well as a seismic contractor for some OBN 4D. Although the field of application is not revealed, a likely contender is block 15/06 and/or shallow waters where the Eni-led New Gas Consortium is at work for gas fields, as water depths specified are from 150-2,500m. EoI's are required by 7 Aug '20 for the rigs and 30 July for the seismic.","Angola (Congo Fan) Block 15/06 op. by SONANGOL (41%), ENI SPA (37%), SINOPEC (13%), NEW BRIGHT (9%)"
24666,"Agua del Cajón block, Neuquén Basin, drilling completed at TD 4,300m and assumed suspended. Targets Los Molles and/or Lajas fm’s, possibly also unconventional reservoirs in the Vaca Muerta + Quintuco shales.","Agua del Cajón block, Neuquén Basin, drilling completed at TD 4,300m and assumed suspended. Targets Los Molles and/or Lajas fm’s, possibly also unconventional reservoirs in the Vaca Muerta + Quintuco shales."
80250,"Zebanec block, enclaved within Sjeverozapadna Hrvatska 1 (SZH-1) contract unit, Mura sub-basin in N. Croatia, TMD 1,739 m (1,693m TVD) mid-Jan '20, P&A o&g shows after wellbore issues, sidetrack under consideration. Target Miocene.","Selnica-1 IS (Selnica E.-1) nfwS Zebanec block, enclaved within Sjeverozapadna Hrvatska 1 (SZH-1) contract unit, Mura sub-basin in N. Croatia, TMD 1,739 m (1,693m TVD) mid-Jan '20, P&A o&g shows after wellbore issues, sidetrack under consideration. Target Miocene."
55330,"Equinor spudded an exploration well targeting the Sputnik prospect in PL 855 on 18 June 2019 using the “West Hercules” S/S. 7324/6-1 is located approximately 30 km northwest of the Wisting discovery and approximately 6 km from the Gemini North discovery, drilled in 2017, in the same licence. The well was targeting sand channels in the Triassic Sto and Snadd formations prognosed at 792 m and 937 m respectively. Gas above oil is expected in the Sto Formation while just oil is expected in the Snadd Formation. It is anticipated that the oil type will be similar to that at Wisting Central. Equinor drilled to 746 m and, for a period of around two weeks, temporarily suspended the well whilst waiting for BOP repairs and maintenance to be completed. As of 30 July 2019 Equinor was plugging and abandoning the well.   7325/4-1 was drilled in 2017 targeting the Gemini North prospect. The well had objectives in the shallow Jurassic Realgrunnen Group (743 m) and the Upper Triassic Snadd Formation (812 m). Both were expected to contain oil similar to nearby Wisting. However, instead of the anticpated oil, gas was discovered in the main objective. A 19 m gas column (no GWC) was proven in the Middle Jurassic Sto Formation, which had good reservoir quality, and a 5 m oil column was encountered in a poor quality Snadd Formation. Estimated recoverable reserves were reported to be 14 – 35 Bcfg and 0.6 – 1.9 MMbo and the find was declared non-commercial.  Equinor Energy AS operates PL 855 with a 55% interest. It is partnered by OMV (Norge) AS (25%) and Petoro AS (20%).","7324/06-01 (Sputnik) (Equinor 55% op. OMV 25%, Petoro  20%) in PL 855, P&A, results awaited, targeting sand channels in the Triassic Sto and Snadd Fm."
47714,"ADNOC launched its 2019 round on 1 May ’19 for 5 onshore + offshore blocks totalling 34,000 sq km. Offshore blocks 3, 4 + 5 and onshore blocks 2 + 5 are available the onshore acreage also under separate licensing opportunities for unconventionals.   A promotional meeting will be held in Abu Dhabi on 22 May, and bid deadline is end November. Round details + registration via https://www.adnoc.ae/en/block-bid/bid-process-and-roadshow.  ADNOC map below:","ADNOC launched its 2019 round on 1 May ’19 for 5 onshore + offshore blocks totalling 34,000 sq km. Offshore blocks 3, 4 + 5 and onshore blocks 2 + 5 are available the onshore acreage also under separate licensing opportunities for unconventionals. "
53700,"PNOC-EC has signed an MoU to for cooperation and joint studies with Ratio related to its fully-owned SC 76, which covers 4,160 sq km on the NE flank of the East Palawan Basin, WD 200-2,000m. Block originally offered as Area 4 in PECR V. Background from GEPS.",PNOC-EC and Ratio Petroleum signed a MOU to permit PNOC’s entry to SC 76.
22088,"KNOC and Uzbekneftegaz signed an agreement on 17 May paving the way for an agreed work programme in the Dehkanabad (XXXVII) and Tashkurgan (XLV) Investment blocks, Afghan-Tajik Basin. This calls for a 5-year explo period starting in June under KNOC financing on a risk basis.",KNOC and Uzbekneftegaz signed an agreement for an agreed work programme in the Dehkanabad (XXXVII) and Tashkurgan (XLV) blocks.
87043,"On 29 July 2020 CEPSA CEO Philippe Boisseau and Sonatrach CEO Toufik Hakkar met in Algiers. The two companies signed a Memorandum of Understanding (MOU) on expanding collaboration in upstream activities. The agreement provides tor joint work aimed at identifying exploration, development and production opportunities based on the new hydrocarbons law. Under the MOU, both companies will investigate opportunities to jointly invest in hydrocarbon projects outside of Algeria.  E&P activities of Cepsa in Algeria are as follows. the company operates the Rhourde El Krouf, Ourhoud and Bir El Msana fields in the Berkine Basin. The combined production of these three fields is 130,000 b/d of oil. In the same basin, the company is also developing the Kechen En Nasseur oil discovery in the Rhourde Er Rouni II block. In the Timimoun Basin, Cepsa partners Total for the Timimoun gas development project which came on stream in 2018 and produces around 170 MMcf/d of gas.",Algeria (Ghadames B.) Rhourde El Krouf
48057,"Independent Oil & Gas (IOG) is offering interested parties to farm-in to its Core Project which consists of six discovered gas fields in the Southern North Sea. The project involves developing the Blythe, Elgood (Blythe Hub), Elland, Nailsworth, Southwark (Vulcan Satellites) and Goddard discoveries. The company estimate its Core Project to hold 410 Bcf (302 Bcf 2P Reserves and 108 Bcf 2P Contingent Resources). The Field Development Plan (FDP) involves a two-phase approach and was submitted to the Oil and Gas Authority (OGA) in October 2018. Phase 1 consists of developing the Blythe Hub and Southwark Field from the Vulcan Satellites Hub. Phase 1 is planned to be developed via two unmanned wellhead platforms at Blythe and Southwark and a subsea tieback at Elgood with up to five long reach wells being drilled. If the appraisal well is successful at Harvey, it will also be developed in Phase 1 by two more development wells. Produced gas will be exported via IOG’s Thames pipeline to the Bacton Terminal in Norfolk. Phase 2 will involve developing the Nailsworth and Elland discoveries from the Vulcan Satellites and Goddard Contingent Resources plus Prospective Resources, if successfully appraised. Phase 2 will consist of drilling five wells on Nailsworth and Elland, two wells will target Goddard’s 2C Contingent Resources and one well for the Prospective Resources. The Final Investment Decision (FID) is planned to be made in H1 2019 and First Gas is targeted for Q4 2020, from the Southwark field. IOG announced on 7 May 2019 that a number of well-funded potential partners are interested in the opportunity. If successful, this process could provide funding via a development carry which would reduce the new capital required for its Core Project. A partner is expected to be announced in H1 2019 which would enable IOG to choose between an industrial and/or capital markets funding solution for the Final Investment Decision.     The Blythe gas discovery consists of a Leman Sandstone Formation reservoir which comprises of aeolian and fluvial facies with the Kupferschiefer Shale providing the seal. The structure is interpreted as a shallow relief four-way closure with NW-SE trending faults either side and across the structure. Blythe lies in licence P1736 which was extended by the OGA till 31 December 2019 subject to the FDP being submitted to the OGA by 30 June 2019 and an FID made by 30 September 2019. Elgood’s reservoir consists of the Leman Sandstone Formation which is trapped by the Zechstein Group within a four-way dip closed structure on a NW-SE trending anticlinal ridge. Elgood is located in licence P2260 which the drill or drop commitment was waived by the OGA in January 2019 subject to the FDP being submitted by 30 June 2019. The Leman Sandstone Formation also forms the reservoir at the Vulcan Satellites but are interpreted as being tighter due to being more deeply buried. P2438 was awarded to IOG in the 30th Licensing Round in October 2018 and contains the Goddard discovery which also lies in Leman Sandstone Formation play.     Interest in the Blythe Hub, Vulcan Satellites and Goddard is held solely by Independent Oil and Gas plc.",Independent Oil & Gas (IOG) is offering interested parties to farm-in to its Core Project which consists of six discovered gas fields in the Southern North Sea.
62146,"Further to DEA 3 Sep '19, 28/96/L Ropczyce-Bratkowice-Strzyzów block, Carpathian Flysch Zone in S. Poland, TD 1,279m, testing concluded in late July, well completed for gas production in Aug '19, IRI-750 rig.","Krolewska Gora-2K appr 28/96/L Ropczyce-Bratkowice-Strzyzów block, Carpathian Flysch Zone in S. Poland, TD 1,279m, testing concluded in late July, well completed for gas production "
12421,"By Q4 2017, Tharwa Petroleum had drilled the East Abu Sennan Deep 1X (EAS H 1X) NFW on its East Abu Sennan PSC. The well was drilled to a TD of 2,409m using the Tanmia Petroleum ""Tanmia 1"" land rig. It is thought have a primary objective in the Jurassic. The NFW is first in a two-well campaign. <P />The 640 sq km block is located in an under-explored part of the Abu Gharadig Basin, and was awarded to Tharwa following the 2007 EGPC Big round. However a protracted delay meant that the PSC for the concession was not signed until July 2014. A 500 sq km 3D seismic survey was acquired by CGG across the block in H2 2015. Tharwa operates the concession with 100% equity. ","East Abu Sennan Deep 1X (EAS H 1X)Tharwa operates the concession with 100% equity, in East Abu Sennan PSC, The well was drilled to a TD of 2,409m using the Tanmia Petroleum ""Tanmia 1"" land rig.Results n/a"
81119,"ExxonMobil has re-launched the sale of its 6.79% stake in the Azeri-Chirag-Gunashli (ACG) field in the Caspian Sea, 2 years after the initial offer concurrent with a similar move by Chevron (9.57%, later sold to MOL).  ACG ownership is currently BP (op, 30.37%), Socar (25%), MOL (9.57%), Inpex (9.31%), Equinor (7.27%), Exxon (6.79%), TPAO (5.73%), Itochu (3.65%), ONGC Videsh (2.31%).","Azerbaijan (South Caspian B.) Azeri-Chirag-Guneshli (ACG) op. by BP (30%), SOCAR (25%), MOL (10%), EQUINOR (7%), EXXONMOBIL (7%), TPAO (6%), INPEX (5%), METI (5%), ITOCHU (4%), ONGC (2%) ExxonMobil has re-launched the sale of its 6.79% stake in the Azeri-Chirag-Gunashli (ACG) field in the Caspian Sea, 2 years after the initial offer concurrent with a similar move by Chevron (9.57%, later sold to MOL)."
8329,"Argentine company Liminar Energia SA was reported to increase its participation by the acquisition of 51% of the common shares of Canadian operator Crown Point Energy, with assets in the Neuquen, San Jorge and Austral basins. Liminar is part of the ST Group owned by Pablo Peralta. In 2015 had previously acquired about 14.18% of the Crown Point common stock at a value of US$ 0.25 per share. Crown Point Energy has interests in the Neuquen Basin Cerro de los Leones Block and also in the Tierra del Fuego province Las Violetas, Angostura Sur and Rio Cullen licenses.<P />",Not Found
9733,"Ineos has acquired a 66.666% stake from Siccar Point in P1854 (317 sq km) and P1935 (212 sq km), West of Shetlands, Siccar Point retaining operatorship and the balance. The deal boosts Ineos’ presence in the area, having already picked-up Dong (Ørsted) interests in nearby licences containing the ‘Lyon cluster’: Lyon, Tobermory, Bunnehaven and Cragganmore.  The Lyon gas prospect targets Balder sands and is pencilled for drilling, potentially helping Ineos on its target to becoming a significant player in northern gas fields.  ","United Kingdom, P1935"
55235,"Neptune Energy announced on 29 July 2019 that it had entered into an agreement with Wintershall Dea for the acquisition of interests in the Bramberge¸ Annaveen-Emslage and Meppen-Schwefingen oil and gas fields in the Emsland region as well as in some undisclosed gas fields which Neptune Energy is operating in the Grafschaft Bentheim region. The deal, which is subject to regulatory and partners approval and expected to close during the third quarter of 2019, will increase Neptune Energy’s net production by approximately 600 boe/d, which represents a 5% production increase for the company’s German production.  The Bramberge oil and gas field is covered by the 10-sq km Bramberge concession which operated by Neptune Energy. The field produced 524,422 bbl of oil and 197,448 Mcf of gas in 2017. Wintershall Dea reported on 29 July 2019 to hold a 22.42% interest in the concession.  The Annaveen-Emslage abandoned field is covered by Lingen-Hebelermeer III, IV and V concessions. Wintershall Dea reported to hold 7.5% in the concessions which are operated by BEB Erdgas & Erdoel (An Exxon Mobil and Shell JV).  The Meppen-Schwefingen field is covered by the Lingen-Meppen I and II concessions operated by Neptune Energy. Wintertshall Dea declared to hold a 10.4% interest in the field which produced 151,719 bbl of oil and 36,808 Mcf of gas in 2017.  It is understood that the gas fields located in Grafschaft Bentheim region are Frenswegen-Denekamp, Itterbeck-Halle and Kalle, all operated by Neptune Energy with a 50% interest with a 25% participation of Wintershall Dea.","Neptune Energy Group Ltd, Wintershall Dea GmbH - Neptune acquires interest in Bramberge, Annaveen-Emslage, Meppen-Schwefingen and numerous undisclosed fields in northwest Germany from Wintershall Dea"
35841,"On 21 November 2018, the CNH granted the official award after contract signature for the CNH-M5-Miquetla/2018 license contract with Operadora de Campos DWF, S.A. as operator and PEMEX as partner.      The contract was migrated from      the AE-0388-2M-Miquetla exploration entitlement block and represents the      fourth legacy service contract migrated to an exploration and production      contract (CEE).    Operadora de Campos DWF, S.A.      de C.V. is the operator with 51% working interest and non-operating      partner is PEMEX with 49% working interest.  The minimum work commitments      for the contract include 11,209 work units for exploration activity and      14,911 work units for development activity for a total of 26,120 work      units.  With and oil price of USD      55-60/bbl this equates to USD 1,000/work unit or the total work      commitments are approximately equivalent to USD 26.12 million.    On 19 January 2017, the CNH approved a request by PEMEX to modify Anexo 2 (Addendum 2) of its Exploration and Production entitlement to include the exploration commitments approved for the AE-0388-M-Miquetla block on 13 October 2016. This represents another step in the migration to an Exploration and Production contract (CEE).  On 13 October 2016, the CNH approved a request by PEMEX to modify its exploration commitments for five modified Service Contracts including the AE-0388-M-Miquetla block Exploration and Production entitlement.  In September 2015 SENER granted PEMEX rights to all horizons instead of just the Paleocene and Upper Cretaceous productive zones in the block area.  The rights include all stratigraphic horizons to the Jurassic and also for unconventional exploration and production.  As a result, PEMEX has requested modifications to its exploration commitments for the block that includes the provisional proposal to drill one unconventional test well within the block to the Upper Jurassic Pimienta Formation.  The proposed horizontal test is the OPS-1 well.  It has a proposed total depth (PTD) of approximately 4,700 m measured depth (MD), 3,204 m true vertical depth (TVD), the Pimienta Formation objective at 2,816 m and a 1,500 m horizontal leg.  The total approved investment commitment for the block is USD 9.18 million.  The approved budget also includes re-processing existing 3D seismic, geological studies as well as the drilling of the horizontal test.  The OPS-1 well has estimated resources to be incorporated of 11.7 MMb of 33° to 38° API oil.  PEMEX has a provisional trajectory for the horizontal to be drilled in a northwest to southeast direction.  The CNH approved modifications were sent to SENER who will grant the final approvals.  If PEMEX proceeds with its planned horizontal test, it will have to have the final plans approved by the CNH.      PEMEX is the underlying titleholder to the entitlement and there was no mention of the companies involved in the Service Contract but it is assumed they will remain as partners in the CEE. The CNH suggested in its final opinion that PEMEX considers farming out to other companies in order to share risk and have companies involved with the latest technology to help it develop the unconventional potential in the country.   One of the factors in the CNH suggestion for PEMEX to farm-out was the marginal economics of the planned activity.   On 11 January 2017, the CNH approved a request by PEMEX to modify the area of the adjoining AE-0388-M-Miquetla and the A-0217-M-Campo Miquetla blocks in order to exclude the Castillo de Teayo archeological site.  The AE-0388-M-Miquetla block was reduced by 1.60 sq km from 140.83 sq km to 139.23 sq km and the A-0217-M-Campo Miquetla was reduced by 1.60 sq km from 202.52 sq km to 200.92 sq km. The AE-0388-M-Miquetla block has undergone a number of modifications over the past year.  On 1 September 2015, the Secretaria de Energia de Mexico (SENER) granted formal approval for the migration of the A-0388-Miquetla block production entitlement Service Contract to the AE-0388-M-Miquetla block Exploration and Production entitlement. The block covers an area of 139.23 sq km in the Tampico-Misantla Basin after modification on 11 January 2017. The Exploration and Production entitlement continues to have a 25 year total term from original granting date of 13 August 2014 but now has a new commencement date to the two phase exploration period.  The first three year exploration phase of the entitlement commenced on 1 September 2015 indicating a final expiry of 1 September 2018 and there is the possibility of a two year extension period.  Additionally in October 2016 the Exploration and Production entitlement was modified significantly with changes to the exploration commitments and rights to all geological horizons.  The entitlement is still in the final migration process to the CEE which is expected to occur by 4th quarter 2017, or two years from the initial 2015 date SENER and PEMEX reported at the start of the process.","CNH granted the official award after contract signature for the CNH-M5-Miquetla/2018 license contract with Operadora de Campos DWF, S.A. as operator and PEMEX as partner.  "
44261,"Ref. DEA 13 Mar ’19, rumours are now suggesting that the Cholula find in CNH-R01-L04-A5.CS/2016 (block 5), Salina del Istmo / Sureste Basin, may be smaller than thought. A commerciality threshold of 200-500 MMbbl is suggested, and partner Ophir says more drilling would be required to establish commerciality within the block. Murphy (op), partners Petronas, Ophir + Sierra (DEA). Note that Ophir is seeking to sell out (23.33%).","Cholula 1 (Murphy op. 30%, Petronas 23, 34%, Sierra 23, 33%, Ophir (Medco) 23,33%) in CNH-R01-L04-A5.CS/2016 (block 5), o&g disc, no details yet (rumours are now suggesting that the find may be smaller than thought). A commerciality threshold of 200-500 MMbbl is suggested. Ophir revealed little detail, saying only that the well was drilled during February and March 2019 and ""encountered hydrocarbons"". It said that ""further drilling is likely to be required to confirm the commerciality of the block."" "
37139,"Lion Energy announced on 12 December 2018 a conditional sale and purchase agreement for the acquisition of the 16.5% stake owned by Gulf Petroleum Investment Company (GPI) in the Seram (Non-Bula) PSC, located in onshore/offshore Seram island. Upon completion, Lion will have increased its participating stake in the block from 2.5% to 19%, via wholly-owned subsidiary Seram Energy Pte Ltd.  The total purchase price is USD 44 million, subdivided into USD 32 million upfront payment and contingent payments of USD 7.2 million (within four months from Plan of Development approval for the Lofin gas discovery) and USD 4.8 million (within four months from first commercial gas production).  Lion is in discussions to secure funding towards the upfront payment prior to obtaining shareholders’ approval. Completion of the deal is likewise subject to other conditions to be met by 11 December 2019, including customary approvals from Indonesian regulator and PSC partners, as well as Lion providing a corporate guarantee for the contingent payments. Upon completion, the effective date of the transaction will be 1 November 2018.  The proposed transaction will strengthen Lion’s position in the area, as the company was also awarded 100% interest in the East Seram exploration block in May 2018, following Indonesia’s Conventional Oil and Gas Bidding First Round 2018.  The other partners in the Seram (Non-Bula) PSC are CITIC (41%, operator), PT Petro Indo Mandiri (30%) and PT GHJ (10%). The PSC is due to expire on 31 October 2019, however on 31 May 2018 the partners signed a new gross split contract to continue operations in the block for a new 20-year term. Signature bonus for the new contract was USD 1 million. The operator has committed to invest approximately USD 49 million for the first five years of the new contract.  The Lofin discovery is estimated to contain 2 Tcfg in place within Manusela carbonates. The 20-year contract extension is expected to allow for full development of the discovery. Additionally, the block is producing oil from the Oseil and satellite fields, with a rate of approximately 2,000 b/d as of mid-2018.  Background Information    Seram (Non-Bula) PSC History    Located onshore on the Seram island, the Seram PSC was awarded to Gulf and Western Indonesia Inc (G&W) on 1 November 1969 in order to re-habilitate the Bula oil field which had been damaged during World War II. After drilling nine unsuccessful shallow exploration wells and carrying out re-habilitation work and limited development drilling on the Bula field, G&W assigned the PSC to Associated Australian Oilfields NL (AAR) in 1972. AAR shot seismic but did not drill and CSR acquired AAR in 1978. CSR drilled seven exploration wells and undertook development work at Bula.  A Kufpec-led group farmed-in for exploration rights in 1985 but the Bula field, covered by an area of 35 sq km to a sub-sea level of 600m, was excluded from the deal. Kufpec concentrated on the deeper potential of the PSC.  On 11 July 2006, CITIC announced that it had entered in a USD 97.4 million sales purchase agreement to acquire a 51% operating stake in the Seram PSC Extension from operator Kufpec.  In February 2018, CITIC agreed to sell a 10% participating interest to PT GHJ, an independent local company. Later, in Q2 2018, Kufpec divested its interest in the block to another local company, PT Petro Mandiri.  Lofin gas discovery    CITIC suspended Lofin 1 ST1 wildcat as a gas with oil/condensate discovery in mid-December 2012. The well encountered more than 160 m of hydrocarbon column in the Jurassic carbonates of the Manusela Formation. The well flowed at a final rate of 15.7 MMcf/d with 171 bbl/d cumulative oil/condensate (36.1° API). Lofin 1 was spudded on 17 January 2012.  Appraisal well Lofin 2 was spudded on 31 October 2014. The well had initial PTD of 5,425 mMD/5,321 mSSTVD, targeting the Manusela Formation. The well was drilled to a final TD of 5,861 mMD (5,686 mSSTVD). In an attempt to collect good reservoir data, a seven days multi-rate test using different choke sizes was conducted by the operator. The test recorded 17.8 MMcf/d of gas with 2,634 b/d of water and completion fluid and 54 b/d of 34.4º API condensate/oil with a flowing wellhead pressure of 2,250 psi over 96 hours flow period on 52/64” choke. A 12 hours flow period on 16/64” choke was also conducted which has recorded 4.95 MMcf/d of gas with 12 b/d of condensate with 280 b/d of water with wellhead pressure of 5000 psi.  Lofin 2 intersected a total gas column of up to 1,300 m.","Indonesia, Seram (Non-Bula) PSC Extension"
82482,"On 8 June 2020 Union Jack Oil announced it has agreed a deal with Humber Oil and Gas to acquire the remainder of Humber's interest in PEDL 180 (block SE/90a) and PEDL 182 (block SE/91b) that host the Wressle field and the Broughton North prospect. Union Jack will pay GBP 500,000 to increase its interest in each licence by 12.5% and Humber will exit the licences. Union Jack will also acquire a deferred consideration element, amounting to GBP 1.04 million, payable to Calmer LP when first oil is achieved. The deal has enabled Union Jack to increase its interest in the Wressle field from 27% to 40%. The acquisition will be effective from 1 March 2020.  Operator of the licence, Egdon Resources, was granted planning consent for the Wressle field development on 17 January 2020. Following the consent, Egdon began to progress the field development and it completed the installation of groundwater monitoring wells in early-May 2020. First oil from Wressle is expected in 2H 2020 with a target production rate of 500 bopd. The project is estimated to have a break-even price of USD 17.62/b. The field was discovered in 2014 by the Wressle 1 exploration well that encountered hydrocarbons in the Carboniferous: Penistone Flags Member (~20 m thick), Wingfield Flags Member (~6 m thick) and the Ashover Grit Member (~6 m thick).   On completion of the deal, interest in PEDL 180 and PEDL 182 will be held by Egdon Resources U.K Limited (30% + operator), Europa Oil & Gas Limited (30%) and Union Jack Oil plc (40%).","United Kingdom (Anglo-Dutch B.) PEDL 180 op. by EUROPA OGH (30%), EGDON (30%), UNION JACK (28%), HUMBER (13%), HEYCO (0%), UJO has agreed to acquire Humber O&G's 12,5% in PEDL 180 + 182 (Wressle project + Broughton North prospect SE of Hull) for GBP 500,000 cash, thereby boosting its interest to 40%. Partnership now to be Egdon (op) 30%, Europa 30%, UJO 40%."
8139,"Carnarvon Petroleum Ltd was awarded exploration permit AC/P62, located in the Vulcan Sub-basin, Bonaparte Basin, on 2 November 2017.  The permit has been awarded for a period of six years and will expire, or be eligible for renewal, on 1 November 2023. Work commitments have been assigned for the duration of the permit’s validity. In the first three year term work programme, to be completed by November 2020 and which is committed, Carnarvon will be undertaking review of available data including petrophysics data, fault seal analysis and well biostratigraphy reviews.  In the following terms, to be committed to on a year by year basis, well planning is outlined for year 4, with the subsequent well drilled in year 5 at a cost of around AUD 30 million.  Total cost for the six year work programme is estimated at around AUD 37 million. The permit was applied for after being offered as block AC16-3 in the 2016 Offshore Federal Acreage Release.   AC/P62 contains two existing discoveries: Keeling and Great Auk, which were discovered in January 1990 and May 2009 respectively.  Both were considered non-commercial.  There are some additional historical exploration wells within the permit area, though most were dry and only a couple encountered shows. AC/P62, which covers an area of 1,503 sq km, was awarded on 2 November 2017.  Carnarvon Petroleum Ltd holds 100% interest and operatorship of the permit.    ",Carnarvon Petr. has been awarded AC/P62 block (1512km²).
10887,"On 11 December 2017 it was announced that the merger between Centrica and Stadtwerke Munchen GmbH to combine Centrica’s European oil and gas exploration and production business with Bayerngas Norge AS, has completed. The newly formed incorporated European E&P company is named Spirit Energy. The deal which was announced on 17 July 2017 see’s Centrica take a 69% interest with Bayerngas Norge’s existing shareholders owning 31% of the joint venture. Spirit Energy’s plans for 2018 include progressing development projects such as Maria and Oda, appraisal drilling at the Fogelberg discovery and the drilling of a number of exploration wells. Also, in conjunction with Wintershall, the company will submit a plan for the development of the Skarfjell field. The newly formed organisation aims to create a strong and sustainable E&P business through combining Centrica’s cash generative and near-term production profile and Bayerngas Norge’s more recent production assets (to have come onstream) and the latter’s development portfolio. The strategy behind the merger was down to a number of aligning points such as the mix of producing and developing assets with both strong positions in the UK and Norway and also assets in the Netherlands, Denmark and Germany held between them. The merger creates a robust, self-financing entity with an attractive financial profile. It could generate approximately GBP 100 – 150 million of net present value expected through synergies and cost savings and portfolio optimisation. Lastly, it provides the opportunity to strengthen the entity through further consolidation and joint ventures including the potential for an initial public offering (IPO) in the medium term.  Centrica was formed as one arm of British Gas following its privatisation in 1997 (the other being BG). The company holds interest in 81 assets in the UK, mainly focused on gas in the Southern Gas Basin, interest in 18 assets in Norway and a further five in the Netherlands. Bayerngas holds interest in eight UK fields, 13 Norwegian fields and two Danish assets. ","United Kingdom (Central Graben Province) ? op. by CHRYSAOR H (36.0%, CENTRICA 64.0%) in Maria block"
50115,"Godavari Onland ML, KG Basin, TD est. 2,500m, gas-cond discovery, tested ~1.6 MMcf/d and ~4.2 MMcfg/d + ~190 bc/d from 2 intv’s, few details.","Billakurua-1 (BK AA) nfw in Godavari Onland ML, KG Basin, TD est. 2,500m, gas-cond discovery, tested ~1.6 MMcf/d and ~4.2 MMcfg/d + ~190 bc/d from 2 intv’s, few details."
40401,"Oil Search has exercised a right to acquire a 50% operating interest in 120 leases totalling 878 sq km in the eastern Alaska North Slope. These leases were run by Lagniappe Alaska LLC, an Armstrong subsidiary, since being won in Nov ’18. It is expected that the leases will be formally awarded in mid-2019. The forward programme includes reprocessing of existing seismic + new 3D.","Oil Search has exercised a right to acquire a 50% operating interest in 120 leases totalling 878km² in the eastern Alaska North Slope. These leases were run by Lagniappe Alaska LLC, an Armstrong subsidiary."
20862,"Nausherwani / 2864-2 EL in Balochistan, 1st well in block, P&A dry at TD 4,782m in late Apr ’18, WDI-812 rig. Targets Paleocene Rakhshani, Eocene Kharan + Oligocene Siahan sst + Panjgur fm’s.","Pakistan, not found"
34815,"Bahrain is understood to have awarded Rosgeologia (Rosgeo) a contract to run marine and geological studies of its 2017 offshore Khalij Al Bahrain (KAB) unconventional o&g discovery. Work should start by year-end, probably to help establish field development scenarios.","Bahrain, not found"
12147,"Block 4495, Dist. X, SE Turkey Zagros Fold Belt, 200 bo/d from the Ordovician Bedinan fm, compl. Dec ‘17. ","Caliktepe Guney-4 appr Turkey (Zagros Province) op. by CALIK PT (100.0%) in 4495 block, 200 bo/d from the Ordovician Bedinan fm, "
43702,"On 6 March 2019, the State Agency for Geology and Subsoil Use of Ukraine held an auction for ten licenses. No applications were submitted for seven blocks and the remaining offered blocks were won by Burisma, DTEK and Ukrgazvydobuvannya.  The Pivdenno-Kobzivska block covers 368 sq km in Kharkiv Oblast (Dnieper-Donets Basin). Seismic coverage amounts to about 1,000 km. Oil resources of the block are estimated at 24 MMbbl. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 9.623 million (USD 0.34 million). Ukrgazvydobuvannya offered UAH 30.949 million (USD 1.1 million). The winner of the auction will obtain a 20-year E&P license.  The Svitankovo-Lohinska block covers 197 sq km in Kharkiv Oblast and it encompasses three structures. Seismic coverage amounts to about 700 km. One well has been drilled in the area. Hydrocarbon resources of the block are estimated at 6 MMbbl of oil and 122 Bcf of gas. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 17.7 million (USD 0.63 million). DTEK-subsidiary Naftogazsystemy offered UAH 85 million (USD 3 million). The winner of the auction will obtain a 20-year E&P license.  The Dubrivsko-Radchenkivska block covers 65 sq km in Poltava Oblast (Dnieper-Donets Basin) and it encompasses the Radchenkivske and Radchenkivske Zakhidnyy fields. Seismic coverage amounts to about 800 km. About 100 wells have been drilled at the fields. Hydrocarbon 3P reserves of the fields are estimated at 12 MMbbl of oil and 17 Bcf of gas. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 17.502 million (USD 0.63 million). Burisma-subsidiary Naftogazopromyslova Geologiya offered UAH 25.1 million (USD 0.9 million). The winner of the auction will obtain a 20-year E&P license.  The Suvorivska block covers 463 sq km on the south-western edge of the Moldavskaya depression in Odeska Oblast. Reservoirs of the Jurassic and Triassic sections (2,000-4,500 m) are the main target for exploration. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 9.221 million (USD 0.33 million). The winner of the auction could obtain a 5-year exploration license.  The Zakhidnotokarsko-Krasnyanska block covers 91 sq km in Luhanska Oblast (Dnieper-Donets Basin). Seismic coverage amounts to about 500 km. Gas resources of the block are estimated at 31 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 4.596 million (USD 0.16 million). The winner of the auction could obtain a 20-year E&P license.  The Dykhtynetska block covers 74 sq km in Chernivtsi and Ivano-Frankivsk Oblasts (Western Ukraine). Seismic coverage amounts to about 200 km. Oil resources of the block are estimated at 3 MMbbl of oil. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 10.099 million (USD 0.36 million). The winner of the auction could obtain a 20-year E&P license.  The Kniazhynska block covers 75 sq km in Kharkiv Oblast. Seismic coverage amounts to about 250 km. Hydrocarbon resources of the block are estimated at 107 MMbbl of oil, 2.1 Tcf of gas and 30 MMbbl of condensate. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 498.43 million (USD 17.8 million). The winner of the auction could obtain a 20-year E&P license.  The Saltivska block covers 26 sq km in Kharkiv Oblast. Seismic coverage is limited to a single regional line. One well has been drilled in the block. Gas resources of the block are estimated at 0.2 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 18.319 million (USD 0.65 million). The winner of the auction could obtain a 20-year E&P license.  The Pechenizko-Kochetkivska block covers 263 sq km in Kharkiv Oblast. Seismic coverage is limited to about 900 km. Gas resources of the block are estimated at 63 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 11.701 million (USD 0.4 million). The winner of the auction could obtain a 20-year E&P license.  The Vatazhkivska block covers 182 sq km in Poltava Oblast and it encompasses the Vatazhkivska prospect with gas resources estimated at 106 Bcf. Seismic coverage amounts to about 500 km. One well has been drilled in the area. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 18.178 million (USD 0.65 million). The winner of the auction could obtain a 20-year E&P license.","On 6 March 2019, the State Agency for Geology and Subsoil Use of Ukraine held an auction for ten licenses. No applications were submitted for seven blocks and the remaining offered blocks were won by Burisma, DTEK and Ukrgazvydobuvannya. The Pivdenno-Kobzivska block covers 368 sq km in Kharkiv Oblast (Dnieper-Donets Basin). Seismic coverage amounts to about 1,000 km. Oil resources of the block are estimated at 24 MMbbl. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 9.623 million (USD 0.34 million). Ukrgazvydobuvannya offered UAH 30.949 million (USD 1.1 million). The winner of the auction will obtain a 20-year E&P license. The Svitankovo-Lohinska block covers 197 sq km in Kharkiv Oblast and it encompasses three structures. Seismic coverage amounts to about 700 km. One well has been drilled in the area. Hydrocarbon resources of the block are estimated at 6 MMbbl of oil and 122 Bcf of gas. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 17.7 million (USD 0.63 million). DTEK-subsidiary Naftogazsystemy offered UAH 85 million (USD 3 million). The winner of the auction will obtain a 20-year E&P license. The Dubrivsko-Radchenkivska block covers 65 sq km in Poltava Oblast (Dnieper-Donets Basin) and it encompasses the Radchenkivske and Radchenkivske Zakhidnyy fields. Seismic coverage amounts to about 800 km. About 100 wells have been drilled at the fields. Hydrocarbon 3P reserves of the fields are estimated at 12 MMbbl of oil and 17 Bcf of gas. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 17.502 million (USD 0.63 million). Burisma-subsidiary Naftogazopromyslova Geologiya offered UAH 25.1 million (USD 0.9 million). The winner of the auction will obtain a 20-year E&P license. The Suvorivska block covers 463 sq km on the south-western edge of the Moldavskaya depression in Odeska Oblast. Reservoirs of the Jurassic and Triassic sections (2,000-4,500 m) are the main target for exploration. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 9.221 million (USD 0.33 million). The winner of the auction could obtain a 5-year exploration license. The Zakhidnotokarsko-Krasnyanska block covers 91 sq km in Luhanska Oblast (Dnieper-Donets Basin). Seismic coverage amounts to about 500 km. Gas resources of the block are estimated at 31 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 4.596 million (USD 0.16 million). The winner of the auction could obtain a 20-year E&P license. The Dykhtynetska block covers 74 sq km in Chernivtsi and Ivano-Frankivsk Oblasts (Western Ukraine). Seismic coverage amounts to about 200 km. Oil resources of the block are estimated at 3 MMbbl of oil. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 10.099 million (USD 0.36 million). The winner of the auction could obtain a 20-year E&P license. The Kniazhynska block covers 75 sq km in Kharkiv Oblast. Seismic coverage amounts to about 250 km. Hydrocarbon resources of the block are estimated at 107 MMbbl of oil, 2.1 Tcf of gas and 30 MMbbl of condensate. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 498.43 million (USD 17.8 million). The winner of the auction could obtain a 20-year E&P license. The Saltivska block covers 26 sq km in Kharkiv Oblast. Seismic coverage is limited to a single regional line. One well has been drilled in the block. Gas resources of the block are estimated at 0.2 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 18.319 million (USD 0.65 million). The winner of the auction could obtain a 20-year E&P license. The Pechenizko-Kochetkivska block covers 263 sq km in Kharkiv Oblast. Seismic coverage is limited to about 900 km. Gas resources of the block are estimated at 63 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 11.701 million (USD 0.4 million). The winner of the auction could obtain a 20-year E&P license. The Vatazhkivska block covers 182 sq km in Poltava Oblast and it encompasses the Vatazhkivska prospect with gas resources estimated at 106 Bcf. Seismic coverage amounts to about 500 km. One well has been drilled in the area. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 18.178 million (USD 0.65 million). The winner of the auction could obtain a 20-year E&P license."
63083,"On 1 November 2019, the Argentine government granted an exploration permit for MLO-121 offshore block to Equinor with 100% interest through the publication of Resolution 694/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Work program in the first exploration period of four years consists of 2D seismic acquisition of 444 km, 2D seismic reprocessing of 57 km, 3D seismic acquisition and reprocessing of 4,290 sq km, and 2D gravimetry and magnetometry acquisition of 8,580 km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment.  MLO-121 covers 4,293 sq km of deepwater area (as designated by the Argentine Secretary of Energy) in Malvinas Basin with approximated water depth between 50 to over 100 m. Exploration target for the block is expected to be oil and gas in the Springhill Formation, which has not produced from any fields on the Malvinas Basin side in comparison to the adjacent Austral Basin side where several offshore gas fields are currently producing.  Equinor won the rights for MLO-121 after submitting an offer of USD 66.195 million to edge out a competing offer by a partnership of Eni and Mitsui of USD 42.385 million. Along with MLO-121, Equinor also received 100%-held operatorship on the blocks of AUS-105 and AUS-106 in Austral Basin, as well as CAN-108 block in Argentina Basin. In addition, the company won CAN-102 and CAN-114 in Argentina Basin in a partnership with YPF, along with MLO-123 block in Malvinas Basin as part of a consortium with YPF and operator Total.  Background Information  The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.","Equinor has been formally awarded more rights it won in Argentina's 1st offshore round earlier this year: Austral Basin: AUS-105 (2,157 sq km) + 106 (2,283 sq km, see also DEA 5 Nov)"
51841,"Maigaiti Slope 2 block, Yubei area in Tarim Basin, ops terminated late May ’19 at TD 7,332m, Target Ordivician Yingshan carbs.","Yuzhong-2 nfw Maigaiti Slope 2 block, Yubei area in Tarim Basin, ops terminated late May ’19 at TD 7,332m, Target Ordivician Yingshan carbs."
78160,"Block P32 of O33,P32,P33 licence, Cilicia-Adana Basin in E. Mediterranean, WD 700m off Silifke, ops concluded/suspended early Apr '20, Fatih DS.","Narlikuyu 1 nfw. in P32 of O33,P32,P33 licence, in E. Mediterranean, WD=700m off Silifke, ops concluded/suspended, results are not yet available."
24651,"During June 2018, a new company named Dragon Oil (registered in Nigeria and Cote d’Ivoire) was awarded coastal block CI-24. The company (not to be mistaken with Dubai-based Dragon Oil Ltd) not only intends to re-develop and bring back the Belier oil field into production, but also has plans to explore the surrounding areas and develop the gas reserves in the block.   Belier is the first commercial discovery and the first field to come onstream in Cote d'Ivoire. ExxonMobil (Esso) produced almost 20 MMbbl of oil for 12 years from the Belier field, before abandonment in 1992. Two other discoveries were made in the mid-1970s, but never developed (Ivco 6 and Ivco 8).  The 839 sq km block CI-24 is located offshore Abidjan. The northern limit of the block is the coastline and it adjoins to the east Vitol’s block CI-202. Water depth varies from 0 m in the north to 1,500 m in the southwest corner of the tract.",Ministry of Energy awards 9 blocks from 11 E&P blocks proposed for the last auction that took place on 27 June 2018.
16383,"D12a, GEMS acreage in NW German Basin, drilled + compl. gas 4 Dec ’17 – 3 Mar ’18, Mærsk Resolve JU. Wintershall (op), partners Engie + EBN.","D12-07 (Andalusite North) op. by EBN (50%, Wintershall 31,78%, Engie 18,22%) in Netherlands/UK border in licence D12a, successfully encountered gas in the Late Carboniferous Limburg Group reservoir."
19395,"KrisEnergy is understood to have upped its offer from 10% to 44.5% in its 1,651-sq km G10/48 block (in yellow below) and producing Wassana lease (in mauve) in the Pattani Trough, Gulf of Thailand. Currently KrisEnergy (op, 89%), partner Palang Sophon. Contact Mike.Whibley@krisenergy.com or James.Parkin@krisenergy.com.","Thailand, G10/48"
70971,"The Uzbekistan Cabinet of Ministers has published a draft decree that approves lists of petroleum exploration wells, without requirement to obtain licences, as well as fields and prospects to be licensed, to be kept in Uzbeneftegaz' (UNG) ownership up to 2025. These lists are provided below  Table 1. UNG's spudded stratigraphic test, wild cat and outpost wells not requiring licence to be kept in UNG's ownership on condition to complete the wells by 2025                    Ustyurt Region         Well number             1         Ultan         1             2         Shimoliy Urga         2             3         Alpomish         1             4         Sherkala         2             5         Karakuduk (Paleoz.)         1             6         Kuyi Sharkiy Berdah         1             7         Namunali         1             8         Kiykulak         1                       Bukhara-Khiva (Amu-Darya) Region                       9         Shon-Sharaf         1             10         Telegri         1             11         Urtakum         1             12         Urtabulak         1             13         Tuygu         2             14         Turunkul         1             15         Kokdumalak         1 Strat Test                       Fergana Region                       16         Palvantash Garbiy         162                       Central Kyzylkym (Syr-Darya) Region                       17         Baymurod         1 Strat Test           Table 2. Fields and prospects where UNG will be licensed to drill exploration wells based on direct negotiations                     Ustyurt Region                       Fields             1         Aral             2         Inam             3         Shege             4         Arslan             5         Kyzyl-Shaly             6         Beskala             7         Kuyi Surgil             8         Kushkair             9         Aralyk                       Prospects             10         Urga Shimoliy             11         Karaumbet Janubiy             12         Zhalgyztoy             13         Muynak Sharkiy             14         Kosbulak             15         Ultan             16         Kamka             17         Satbay             18         Shahlo             19         Shagala             20         Ak-Tepe             21         Umid             22         Asia Zholbarysy             23         Rispay             24         Sulama Verkhnyaya             25         Kiykulak             26         Orzu             27         Sherkala             28         Aydos Biy             29         Kuyi Shimoliy Berdah             30         Karakuduk             31         Hakim-ata             32         Namunali             33         Shagyrlyk (Jurass clast.)             34         Garbiy Kuyi Surgil                       Bukhara-Khiva (Amu-Darya) Region                       Fields             35         Jangul             36         Illanli             37         Koshtepe             38         Zirobod             39         Uzunchak             40         Tarnasay             41         Marvarid             42         Yormok             43         Auzikent             44         Jankara             45         Jeyhun             46         Chakkakum             47         Karomat             48         Murodtepa             49         Shortak             50         Andakli             51         Tumaris             52         Kulbeshkak Janubiy             53         Shorkum             54         Dultatepa             55         Sharkiy Hatar                       Prospects             56         Almalyk             57         Shorbulak Janubiy             58         Garbiy Akkum             59         Chavata             60         Karabag             61         Yangi Kumsultan             62         Miroydin             63         Kulanchi             64         Kiyiksoy             65         Shirinsoy             66         Tandirli             67         Balandtepa             68         Akkum Janubiy             69         Andabazar             70         Yangi Naistan             71         Telegri             72         Chorgumbaz             73         Hatam             74         Yangi-Naur             75         Fayzli             76         Toshguzar             77         Shirinkuduk             78         Zarbulak             79         Ambartepa             80         Tuprokkala             81         Kimerek             82         Toshtepa             83         Boynazar             84         Hamal             85         Tuygu             86         Jambulak Shimoliy             87         Oynakul             88         Langarota                       Fergana Region                       Fields             89         Hojaosman Garbiy              90         Chakar             91         Hankyz Shimoliy             92         Uchtepa (Low. Cret)                       Prospects             93         Boburmirzo             94         Zilol             95         Markaziy Avval (Low. Cret)             96         Kuyi Kashkarkyr (Upp. Cret)             97         Kasansay             98         Boston Garbiy             99         Kutarma             100         Hakkulabad Shimoliy             101         Baynalminal             102         Hartum Sharkiy (Paleog.)             103         Akbarabad             104         Palvantash Shimoliy             105         Naray             106         Kashkarkyr Sharkiy                       Surkhandarya   Region                       Prospects              107         Angor             108         Pogranichnaya             109         Bokaty             110         Kaldara             111         Togaybulak             112         Ikkizak             113         Besharcha             114         Koshtar (paleogen)                       SW   Gissar Region                       Prospects             115         Shamolikam             116         Gulbulak","The Uzbekistan Cabinet of Ministers has published a draft decree that approves lists of petroleum exploration wells, without requirement to obtain licences, as well as fields and prospects to be licensed, to be kept in Uzbeneftegaz' (UNG) ownership up to 2025. "
72383,"On 14 February 2020, Geopark was granted final awards for the POT-T-834, REC-T-58, REC-T-67, and REC-T-77 blocks in the onshore Potiguar and Reconcavo basins.  On 10 September 2019, Geopark bid on and was granted preliminary awards for the POT-T-834, REC-T-58, REC-T-67, and REC-T-77 blocks in the onshore Potiguar and Reconcavo basins. There were no other bids for the blocks.          1st   Open Door Bid Round - Preliminary Results - Geopark - 9-10-2019             Basin         Block         Area sq km         Royalties %         Minimum Work Units         Bid_Work Units         Tot_WU_Bid_Value USD         Min Bonus USD          Bonus Bid USD          Win_Consort-Comp             Potiguar         POT-T-834         30.46         7.5         228         234         321,750.00         12,500.00         62,509         Geopark (100%)             Reconcavo         REC-T-58         31.53         7.5         209         209         287,375.00         12,500.00         12,500         Geopark (100%)             Reconcavo         REC-T-67         31.19         7.5         211         211         290,125.00         12,500.00         12,500         Geopark (100%)             Reconcavo         REC-T-77         31.19         7.5         211         211         290,125.00         12,500.00         12,500         Geopark (100%)             Totals Onshore            124.37                     1,189,375.00            100,008.50                Source: IHS Markit                                                                                         ©   2019 IHS Markit","GeoPark Ltd - Potiguar and Reconcavo basins - POT-T-834, REC-T-58, REC-T-67, and REC-T-77 blocks - final awards from 1st Open Door Bid Round"
36139,"On 21 November 2018, the Council of Ministers met and agreed on the draft agreement to award the XXVII exploration licence to Societe Nationale des Petroles du Congo (SNPC). As is the norm SNPC was awarded the licence but only holds a 15 % interest, Perenco Exploration & Production Congo Ltd (Perenco) operates the area with an 85% stake.  The licence was awarded for a period of two years and in non-renewable.  Perenco’s bid was opened on 29 March 2017.   The 565 sq km area sits atop the shelf within the Lower Congo Basin. It plays host to the 2011 Nkaba 1 oil and gas discovery and the 1985 Boatou Marine 1 oil discovery. Nkaba 1 is estimated to hold some 22 MMbo and 27,500 MMscf gas. Boatou Marine 1 is estimated to hold some 10 MMbo.","A consortium comprising Total, Eni and Perenco have been awarded Block XXVII (Marine 20)in the recent licensing round."
24787,"BP announced on 3 July 2018 that it has agreed to acquire a 16.5% interest in the Clair field located in the West of Shetlands from ConocoPhillips. BP will acquire a ConocoPhillips subsidiary which holds a 16.5% interest in the BP operated Clair field, with ConocoPhillips retaining a 7.5% interest. BP also announced that it has entered into agreements with ConocoPhillips to sell its entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska as well as its 38% holding in the Kuparuk Transportation Company. Details of the transactions are not being disclosed, excluding customary adjustments. The transactions are expected to be cash neutral for the both companies and complete simultaneously during 2018. Both deals are subject to regulatory approvals and the effective date for the transaction will be 1 July 2018.  Clair was discovered in 1977 by exploration well 206/8-1A, which penetrated a 586m oil column in a thick (>700m) sequence of Devonian to Carboniferous continental sandstones overlying Proterozoic basement. Clair was developed using a phased approach. Clair Phase 1 was sanctioned in 2001 and focused on the Core, Graben and Horst reservoir areas targeting an estimated recoverable resource of 300 million barrels. First production was achieved in February 2005 and Clair was developed via the first fixed offshore facility in the West of Shetlands. Oil and gas was exported via pipelines to the Sullom Voe Terminal on the Shetland Islands.   The second phase of development, the Clair Ridge Project is designed to have a capacity of 120,000 barrels of oil and 100 million cubic feet of gas per day. The phase targets 640 million barrels of recoverable resources and is expected to produce through to 2050. In 2016, the construction and installation of two new bridge-linked platforms was completed. Hook-up and commissioning is under way with first oil expected in 2018.      Following completion of the deal interest in Clair will be held by BP Exploration Operating Co Ltd (44.13% + operator), Chevron North Sea Ltd (19.42%), Enterprise Oil Ltd (18.68%), Shell Clair UK Ltd (9.29%), ConocoPhillips (UK) Ltd (7.5%) and Britoil Ltd (0.98%).","BP will increase its stake in the Clair oilfield through an asset swap with ConocoPhillips. BP will acquire from an additional 16,5% interest in the field (-> 45,1% op.). ConocoPhillips will keep a 7,5% interest. For its part, ConocoPhillips will acquire BP's entire 39,2% interest (-> 94,68% op.) in the Greater Kuparuk Area on the Alaska North Slope and stake in the Kuparuk Transportation Company."
63056,"On 2 November 2019, the Argentine government granted an exploration permit for MLO-123 offshore block to a consortium of Total, state company YPF, and Equinor through the publication of Resolution 695/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Total operates the block with 37.5% interest, followed by YPF with 37.5%, and Equinor with the remaining 25% stake. Work program in the first exploration period of four years consists of 2D seismic acquisition of 720 km, 2D seismic reprocessing of 1,393 km, 3D seismic acquisition and reprocessing of 3,000 sq km, and 2D gravimetry and magnetometry acquisition of 6,000 km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment.  MLO-123 covers 3,789 sq km of deepwater area (as designated by the Argentine Secretary of Energy) in Malvinas Basin with approximated water depth of up to 180 m. Exploration target for the block is expected to be oil and gas in the Springhill Formation, which has not produced from any fields on the Malvinas Basin side in comparison to the adjacent Austral Basin side where several offshore gas fields are currently producing.  The consortium of Total, YPF, and Equinor won the rights for MLO-123 after submitting an offer of USD 44.465 million. Along with MLO-123, Total also received 50% interest and operatorship in a partnership with BP on CAN-111 and CAN-113 blocks in Argentina Basin from Round 1.  Background Information  The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.","Equinor has been formally awarded more rights it won in Argentina's 1st offshore round earlier this year: Austral Basin: AUS-105 (2,157 sq km) + 106 (2,283 sq km, see also DEA 5 Nov)"
75037,"N. flank of Cheremshanskoye discovery area in Tomsk Oblast, W. Siberia, tested 476 bo/d (no water) on 10mm choke from 2,630.8-2,633.8m and 2,644-2,655m in the Callovian-Oxfordian Vasyugan Unit Yu1. A w/o rig has been moved onto discovery Cheremshanskaya-3 in the S. part of the field to test the L. Jurassic Yu14 unit.",Russia (Kaymys - Vasyugan Province (West Siberian B.)) Cheremshanskoye (Tomsk)
38592,"Esperanza block, Lower Magdalena, 21-day well to TMD 2,815m, 31.7m net gas pay in the shallow Porquero sst + 49.4m net gas in the CDO reservoir, the thickest combined to date in the company’s Lower Mag drilling.","Nelson-13 devt Esperanza block, Lower Magdalena, 21-day well to TMD 2,815m, 31.7m net gas pay in the shallow Porquero sst + 49.4m net gas in the CDO reservoir, the thickest combined to date in the company’s Lower Mag drilling."
11976,"Aker BP completed the sale of 10% of the Valhall and Hod fields to Pandion Energy on 22 December 2017, after completing the acquisition of Hess Norge on the same date. The deal was first announced on 4 December 2017 for an undisclosed consideration. Valhall and Hod are located in the SW corner of block 2/8 and the NW corner of block 2/11, proximate to the Danish maritime boundary, and licensed via PL006 B, PL033 and PL033 B. Valhall came online in October 1982 and has produced 746 MMbo and 933 Bcfg from Late Cretaceous Hod and Tor formations, to end September 2017. Hod Field production commenced in September 1990, with cumulative output (to September 2017) of 62 MMbo and 65 Bcfg from Hod & Tor formations and the Early Paleocene Ekofisk Formation. Valhall and Hod had combined average output of 32,100 bo/d and 38.8 MMcfg/d (39 MMboe/d) for the 12 months to September 2017, with an estimated 232 MMboe combined remaining recoverable reserves (77% oil), however Aker BP is targeting 500 MMboe further production from the fields. Aker BP first agreed to acquire Valhall & Hod partner Hess Norge in October 2017 for US$ 2 billion cash, with Aker BP to gain Hess' US$ 1.5 billion tax loss carry forward. Revised PL006 B, PL033, PL033 B, Valhall Field and Hod Field participants Aker BP ASA (90% + Op) and Pandion Energy (10%).","Aker BP (->90%) completed the sale of 10% of the Valhall and Hod fields (PL 006 B, PL 033 and PL 033 B blocks) to Pandion Energy."
48819,"Ref. DEA 23 Aug ’18 (Santos farmin option), Santos and PRL 3 partners have signed an LoI pursuant to which Santos will acquire a 14.32% stake in the licence (P’nyang gasfield) for USD 187 MM - subject to the award of a production development licence to replace PRL 3. The LoI will help towards alignment between the PNG LNG project and the PRL 3 JV, ahead of FEED entry for the planned 3-train expansion at the plant site. Two of the proposed trains will be fed by gas from the Elk-Antelope fields and the 3rd from the PNG LNG project and the P’nyang field. Partnership will become (source: Oil Search):","Santos and PRL 3 partners (ExxonMobil 36,86%, Oil Search 36,86%, Merlin Petroleum 11,96%) have signed an LoI pursuant to which Santos will acquire a 14.32% stake in the PRL 3 licence (P’nyang gasfield) for USD 187 MM. "
78496,"As of April 2020, China National Offshore Oil Corp (CNOOC) is seeking partners in its BC9 and BCD10 contracts in the Gabon Coastal Basin offshore Gabon. The company operates the contracts BC9 and BCD10 with a 100% interest since Shell exited the licences in November 2019. The company attempts to farm out up to 50% stake prior to drill two high impact wells between late 2020 and 2021, one in each block. According to CNOOC all commitments have been met in both contracts. The company is to enter, in September 2020, in the 2-year fourth exploration period of the BC9 contract with the possibility to be extended up to three years. The BCD10 licence holds the multi Tcf Leopard gas discovery (2014) and is in a gas holding period until 2026 with minimal work commitments.  CNOOC identified, both in post-salt and in pre-salt sequences, some 25 leads and/or prospects of which two are drill-ready. The ""Tigre"" prospect is to be drilled in about 2,000 m of water depth in the BC9 block targeting an approx. 100 sq km area in the pre-salt Gamba sandstones of Aptian age. The ""Seal"" prospect is to be drilled in approx. 400 m of water depth in the southeastern corner of the BCD10 block targeting the carbonate of the Albian Madiela Group formation in a large 3-way structure with mean recoverable resources estimated at 356 MMbo. CNOOC is also working on the Leopard gas discovery studying for a further appraisal program to determine the feasibility of a standalone development.    CNOOC has open a data room since March 2020 with an anticipated bid deadline in mid-2020.  Contact details:         Lucas Ong Business Development Advisor             E-mail: Lucas.Ong@intl.cnoocltd.com                   Tel: +44 1895-555319  Ben Kilner Team Lead, Global Exploration              E-mail: Ben.Kilner@intl.cnoocltd.com                         Tel: +44 1895-555310     Background information  The blocks BC9 and BCD10 were initially granted to Shell on September 2007. BC9 and BCD10 blocks are mainly in deep waters, covering a total of some 13,400 sq km of which about 530 sq km are in shallow waters. CGG acquired a 6,000 sqkm 3D seismic program between 2010 and 2011. CNOOC farmed in both blocks in 2012. The partners drilled a first wildcat N'Komi Marin 1 in 2014, the well intersected a 200 m paleo-oil column in the pre-salt Gamba formation. It was followed by a success with the Leopard gas and condensate discovery made in October 2014. The latter drilled to TD of 5,063 m intersected a substantial gas column of 200 m of net gas pay in the Gamba formation. The discovery was confirmed by the appraisal Leopard 2 suspended in January 2016. CGG completed in March 2016 the acquisition of a 3D seismic program in the BCD10 block.    Six exploration wells were drilled before 2007, in the areas covered by the actual BC9 and BCD10 blocks, targeting post-salt objectives such as the Cenomanian Cap Lopez formation and the Albian Madiela Group formation. All were dry except the Grand Large N'Kendji Marine 1 wildcat, which encountered non-commercial oil in February 1985. The well, drilled by Elf Gabon, is located 85 km west of Sette Cama in 163 m of water. It bottomed in the Albian Madiela Group at a depth of 3,893m.",CNOOC is seeking partners in its BC9 and BCD10 contracts in the Gabon Coastal Basin offshore Gabon. The company operates the contracts BC9 and BCD10 with a 100% interest since Shell exited the licences in November 2019. 
22286,"Nexen is offering equity in the Villarrica Norte block in Huila, Upper Magdalena, the 447-sq km block previously under force majeure. Petrobras (op), Nexen 50:50.  Contact Lana Ellard (Lana.Ellard@nexencnoocltd.com) or Lance Dunn (Lance.Dunn@nexencnoocltd.com).","Nexen is offering equity in the Villarrica Norte block in Huila, Upper Magdalena, the 447-sq km block previously under force majeure. Petrobras (op), Nexen 50:50. "
67494,"On 12 December 2019, W&T Offshore acquired 75% working interest and operatorship of the producing Magnolia Field, which encompasses Garden Banks block GB 783 and GB 784, from ConocoPhillips. The US$ 20 million deal is effective as of 1 October 2019. Tracy W Krohn, Chairman and Chief Executive Officer of W&T, had this to say: ""We are pleased to announce another purchase of producing properties that meets all the criteria we have outlined in the past as necessary to drive increased shareholder value from acquisitions. At the beginning of the year, we announced that we were looking closely at acquisition opportunities and that the current environment for acquisitions in the Gulf of Mexico was very good. We have now executed two accretive transactions in 2019. We will continue to actively pursue any opportunities that meet our criteria and are accretive to W&T.""The Magnolia Field was discovered in May 1999 on GB 783 in 1,433m of water. The well, G11573 A1 BP1, was drilled to a depth of 5,141m and encountered hydrocarbon-bearing sections of 45-60m net. The field began production in 2004 and the initial development was completed in 2006. Magnolia total net proved reserves are pegged at 4.1 MMboe, of which 67% are oil and 5% natural gas liquids. Current reserves are proved developed and 73% of the reserves are classified as proved developed producing. In October 2019, the Magnolia Field produced ~2,300 boe/d (82% oil) net to ConocoPhillips. Following completion of the December 2019 transaction, equity in GB 783 and GB 784 is now shared between W&T Offshore (75% WI + Op) and Marubeni Oil & Gas (USA) (25%).",Not Found
59439,"24 September 2019, KazMunayGaz (KMG) and Equinor signed a Joint Study Agreement as part of their long-term co-operation. The parties will study of certain oil and gas prospective areas in the Republic of Kazakhstan with a view to obtain E&P contracts in future. The Agreement provides for geological and geophysical studies to evaluate the hydrocarbon potential of oil and gas areas in Kazakhstan. No specific areas have been publicly named.  Equinor currently has no E&P assets in Kazakhstan. Just a few days ago, KMG signed a similar agreement with Lukoil.",KMG and Equinor signed a JSA as part of their long-term co-operation. The parties will study of certain oil and gas prospective areas in the Republic of Kazakhstan with a view to obtain E&P contracts in future. The Agreement provides for geological and geophysical studies to evaluate the hydrocarbon potential of oil and gas areas in Kazakhstan. No specific areas have been publicly named. Equinor currently has no E&P assets in Kazakhstan. 
9043,"On 13 November 2017 Hague and London Oil (HALO) reported that the takeover of non-operated offshore licences from Tullow was completed. Consequently HALO is a producer of more than 2,500 boe/d, having 2P reserves in excess of 12 MMboe and more than 19 MMboe in contingent resource The table below shows Tullow’s assets and its participation interest: Asset Operator Tullow’s   participation E10 ENGIE 30% E11 ENGIE 30% E14 ENGIE 30% E15c ENGIE 25% E15a Wintershall 4.69% E15b Wintershall 21.12% E18a Wintershall 17.6% F13a Wintershall 4.69% J9 NAM 9.95% K8 NAM 9.95% K11 NAM 9.95% K7 NAM 9.95% K14 NAM 9.95% K15 NAM 9.95% L13 NAM 9.95%   HALO was formed in 2012 and combined with Wessex Oil in 2014. The company’s portfolio is so far comprised of assets in the United Kingdom, Western Sahara, French Guyana and the Scattered Islands.  ","Netherlands, J9"
34812,"Ophir Energy plugged and abandoned a step-out exploration well, B08/38-11 in the B08/38 concession, Gulf of Thailand, on 21 October 2018, with oil shows. Located 5 km north of the Bualuang Alpha and Bravo platforms, the well was drilled to a TD of 2,328 m by Seadrill’s ‘West Cressida’ J/U, after the completion of three wells for the Phase IV development drilling campaign in the Bualuang field. The B08/38-11 well was targeting Middle Miocene clastics, the producing reservoir in the Bualuang field.    The well was spudded on 12 October 2018. The drilling location was identified by a 3D OBC seismic survey which was acquired in 2015. The Bualuang North prospect was estimated to contain 36.7 MMbbl (P50) of OIIP with well cost is around USD 4.8 million.     The Phase IV development drilling campaign commenced on 8 August 2018, and is expected to include up to 14 wells and an expansion of the water disposal capacity on the Bravo platform. Following the decision of Phase IV development, 2P reserves for the field have increased by 13% to 49.4 MMboe. Auditor ERC Equipoise forecasts that the development will convert 9.2 MMbo of contingent resources (2C) into proved and probable reserves (2P) to the field.    Ophir Energy became operator and 100% interest holder in the B08/38 concession following the acquisition of Salamander Energy, effective on 2 March 2015.    Background Information    Bualuang field located in the west of the Gulf of Thailand in water depths of approximately 60 m, 60 km west of the Chevron-operated fields and Mubadala-operated Jasmine oil field in the Pattani Trough. The field has a Miocene, fluviolacustrine, sandstone reservoir with porosity of around 30% and permeability of up to 1 Darcy.     The original operator SOCO drilled discovery well Pornsiri 1 on July 1997. The well targeted the same upthrown fault block as Sun Oil's B7/32 2 discovery (1993). The well was drilled to a TD of 1,820m and logging indicated that the Miocene sandstones were oil bearing but the objective Rat Buri limestone was devoid of hydrocarbons. Pornsiri 1 was suspended with the intention to re-enter and test at a later date.     Pornsiri 2 (August 1997) was classed as a step-out well and was located some 20km north, of the original well. It was spudded on 13 August 1997 and was drilled to a TD of 1,372m, but failed to encounter significant hydrocarbons however and was abandoned dry on 19 August 1997. SOCO then returned to the main structure and drilled Pornsiri 3 (September 1997). This well reached a TD of 1,280m and confirmed the reservoir intersected by Pornsiri 1. The well was tested, but only flowed 50 bbl of water and minor oil, and the well was subsequently suspended, with the intention of possibly re-entering it to be tested in the future.     The Bualuang field was put onstream from one well, Bualuang 5 (BA-05), drilled from the “Alpha” platform, on 27 August 2008. Following a period of multi-rate testing of this well, other five producers were brought on-stream sequentially with production expected to rise to a peak rate of approximately 8,000 bo/d from the field.    A second wellhead platform (“Bravo”) was installed and commissioned in November 2012. The “Atwood Mako” rig was relocated to the platform around mid-November 2012 and was expected to start operations shortly thereafter, for an extended development drilling programme. The rig previously conducted a short development drilling campaign (likely including two workover wells) from the Bualuang Alpha platform, starting around 20 September 2012, and then drilled two exploration wells (Bualuang NW 1 and Bualuang NW 1ST) in the Greater Bualuang area.    The field produced its 25 millionth barrels oil in October 2015, which is a significant achievement given the field was originally projected to contain only 14 million barrels of 2P reserves. The field produced at a rate of 12,500 bo/d in 2014, which is the highest rate in field’s history. First half output (9,900 bo/d) was negatively affected by a six-week shut down, but performance in the second half exceeded expectations, with 15,100 bo/d.     Salamander has been also planning for step-out exploration drilling in the Bualuang area, with one well targeting the southern culmination of the Bualuang East Terrace structure. The well would target multiple Miocene sandstone reservoirs of the “T2”, “T4” and “T5” levels. In-place prospective resources are estimated between 5 and 25 MMbo. The East Terrace South well could also potentially be sidetracked to explore an analogue prospect further south (East Terrace Far South). EIA approval for the well was in place as of mid-2014. If proved to be commercially viable, the prospects could be drained by the “Charlie” platform.    On 11 September 2016, the field production rate increased to 9,700 bo/d while in process of ramping up, as compared to before commissioning of the new facilities. The project total cost was USD 20 million and is expected to increase Net Present Value (NPV) of Bualuang by USD 80 million and payback within 12-18 months.    On 25 January 2016, the operator completed production optimization activities on the oilfield, resulting in an increase in daily oil production. The operator reported that the production averaged 13,000 boe/d on a full year proforma basis. This exceeded guidance with both the Bualuang and Sinphuhorm fields producing ahead of budget.     In September 2016, Ophir completed water debottlenecking program within 5 months, with a final tie-in to Bualuang field. The production from Bualuang had been suspended for 10 days to give way to the upgrading works and subsequently resumed on 2 September 2016. Ophir Energy tested an instantaneous rate of 9,700 bw/d at a water disposal rate of 64,000 bw/d, an increment of 1,400 bw/d compared to prior month.    The initial phase of the Phase IV drilling consists of operations on five wells from the “Alpha” and “Bravo” platforms, comprising three re-drills using existing slots and two well workovers. The first oil from Phase IV is expected in the second half of 2018.     To enable further development of additional resources, the operator is also planning to install the third wellhead platform (“Charlie”) in 1H 2019. The new platform will consist of a 12-slot wellhead structure, bridge-linked to the existing Alpha and Bravo platforms, and equipped with additional power generation.    In mid-May 2017, Ophir announced that the Final Investment Decision (FID) was obtained to commence the drilling campaign project that is forecast to cost USD 145 million from 2018 until 2020. In January 2018, the field production has dropped 6% to 7,800 bo/d, compared to the previous year’s average. After the completion of the phase IV drilling program, production in the second half of 2018 is expected to average over 9,000 bo/d.    The previous infill drilling campaign in the Bualuang field was completed on 6 August 2017. The operator managed to offset the predicted natural well decline from four new wells which contributed to 1,400 bo to the field daily production. The field managed to maintain its production at an average of 8,300 bo/d across 2017.","B08/38-11 in the B08/38 concession, P&A with oil shows."
9956,"PetroChina – Xinjiang achieved commercial gas flow in the Junggar Basin. Mei 001, an appraisal well, was drilled to assess Mei 6 discovery of the Kelameili gas field and it tested 740 Mcf/d of gas from the Jurassic Badaowan Formation. The well confirmed source rock generation potential in the Carboniferous and indicated multi reservoir target in this area.   PetroChina achieved commercial gas flow in Mei 6 in late 2016, the well was drilled in the Dixi 12 area of the Kelameili gas field and it tested 3 MMcf/d of gas from the Carboniferous volcanic reservoir.  Mei 6 well was spudded on 24 July 2016 with a PTD pf 4,550 m and had objective to test the hydrocarbon occurrence in the deep Carboniferous volcanic reservoir and the extension of the Kelameili gas field.  Dixi 12 was discovered in 2006. The well tested flowing 84 bo/d and 5,087 Mcfg/d from a Cretaceous interval. ",China (Junggar B.) Mei (Ju) 6 op. by PETCHIN XJ (100.0%) in Dishui Quan block
20798,"Senex Energy Ltd was awarded exploration licence PEL 639, located in the Cooper Basin, on 26 April 2018.  The permit has been awarded for a period of five years and will expire, or be eligible for renewal, on 25 April 2023.  Work commitments have been assigned for the duration of the permit’s validity, with the first four years a guaranteed work programme.  The work programme will include 300 sq km new 3D seismic and two wells in year one, an additional 275 sq km 3D seismic and six wells in year two, four wells in year three and one well in each of years four and five.  Senex applied for the permit after it was offered as block CO2013-A in the 2013 South Australian Acreage Release.  The block is located on trend with the western flank oil fairway proven to the north in Senex operated PEL 111 and PEL 104, along with Beach Energy’s PEL 91. The block has both conventional and unconventional rights attached to it, including rights to any shale gas discoveries.   PEL 639, which covers an area of 627 sq km, was awarded on 26 April 2018.  Senex Energy Ltd holds 100% interest and operatorship of the licence.","Australia, not found"
56873,"ATP-927-P, Cooper-Eromanga, Real Energy reports that the Tamarama-2 and 3 appr wells have exhibited lower flow rates than expected (due to mechanical, not geological, issues) and is looking for ways to improve them. Background on the tight gas wells from GEPS.","ATP-927-P, Cooper-Eromanga, Real Energy reports that the Tamarama-2 and 3 appr wells have exhibited lower flow rates than expected (due to mechanical, not geological, issues) and is looking for ways to improve them."
22444,"On 21 May 2018 TOTAL E&P Cyprus BV announced to the Cypriot government that the company wanted to acquire stakes in Block 8 offshore southern Cyprus.  Block 8 was awarded to Eni Cyprus Ltd in April 2107 as a result of the country’s third offshore licensing round in its Exclusive Economic Zone (EEZ) which closed in July 2016. The block covers 4,555 sq km to the south of the island at water depths between 650 m and 2,770 m. Eni and Total are already partners in Block 6 and in Block 11 where they made two gas discoveries in 2017 and 2018.  Eni Cyprus Ltd is currently the sole right holder in Block 8.","On 21 May 2018 TOTAL E&P Cyprus BV announced to the Cypriot government that the company wanted to acquire stakes in Block 8 offshore southern Cyprus. Block 8 was awarded to Eni Cyprus Ltd in April 2107 as a result of the country’s third offshore licensing round in its Exclusive Economic Zone (EEZ) which closed in July 2016. The block covers 4,555 sq km to the south of the island at water depths between 650 m and 2,770 m. Eni and Total are already partners in Block 6 and in Block 11 where they made two gas discoveries in 2017 and 2018. Eni Cyprus Ltd is currently the sole right holder in Block 8."
25865,"Ridderade-Ost contract, NW German Basin, 35km SW of Bremen, sidetrack wildcat drilled in May ’18, kicked off from a depth of 395m, plugged at 1,605m after failing to encounter hydrocarbons. Original Bockstedt-Südost-1 nfw was drilled in 2009.","Bockstedt-Südost 1a (Wintershall 100%) in the Ridderade-Ost contract, P&A dry."
25328,"On 16 May 2018, Total E&P Namibia B.V. (Total) was awarded an exploration licence covering Block 2912 within the Orange Sub-basin. Water depth across 7,900 sq km the block range between 3,000 m in the east, and 4,000 m in the west. The ultra deep-water area is located to the west of Total’s Block 2913B in which it plans to drill and exploratory well in 2019.    To date the area is virtually unexplored. Only a few 2D line cross the licence in an east west direct and the area is undrilled.   Total operates the block with an 85% interest, NAMCOR holds the reaming 15% stake.","Total E&P Namibia B.V. (Total) was awarded an exploration licence covering Block 2912 within the Orange Sub-basin. Water depth across 7,900 sq km the block range between 3,000 m in the east, and 4,000 m in the west. "
9461,"Sonatrach has made a Silurian oil & gas discovery in its Sai Est 1 ST 1 (SAIE 1 ST 1) NFW. The well is located on the Zemlet El Arbi exploration licence in the Berkine Basin. It was spudded on 20 December 2016 and drilled to a TD of 4,700m, using the ENTP #194 rig. A mechanical sidetrack was drilled from 3,343m. The discovery lies ~7km SE of the 2015 Sai 1 (SAI 1) Silurian oil & gas discovery (TD 4,710m). It is the sixth exploration well to be drilled on the block in 2017. In October 2016, Sonatrach also completed the Sai Sud 1 (SAIS 1) NFW as a Silurian oil & gas discovery, ~6km to the west. It was drilled to a TD of 4,703m. The company was awarded Zemlet El Arbi, which lies to the north of the Hassi Berkine Complex, in October 2015. It has drilled 15 wells on the block since award, with seven discoveries made. Sonatrach operates the licence with 100% equity.<P />","Algeria, Zemlet El Arbi (Dev)"
36797,"On 28 November 2018, the Federal Agency for Subsoil Use held an auction for five blocks in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Severo-Aykurusskiy, Slavneft-Megionneftegaz, Gazprom Neft Khantos and Surgutneftegaz emerged as the winners. The winners of the auction will obtain 25-year E&P licenses.  The Ay-Kurusskiy block covers 420 sq km in the Kaymys-Vasyugan Province and encompasses the Ay-Kurusskoye oil discovery with 3P reserves estimated at 41 MMbbl. Seismic coverage amounts to 25 km. Seven exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 82 MMbbl of oil. The starting price amounted to RUB 469.58 million (USD 7.1 million). Severo-Aykurusskiy offered RUB 939.2 million (USD 14.2 million).  The Polevoy block covers 521 sq km in the Middle Ob Province and encompasses the Polevoye, Pyatkovskoye and Negusyakhskoye Severnoye oil discoveries with combined 3P oil reserves estimated at 14 MMbbl. Seismic coverage amounts to 780 km. Five exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 82 MMbbl of oil. The starting price amounted to RUB 222.4 million (USD 3.37 million). Slavneft-Megionneftegaz offered RUB 244.65 million (USD 3.7 million).  The Vayskiy Severnyy block covers 502 sq km in the Ural-Frolov Province and encompasses the Vayskoye Severnoye oil discovery with 3P reserves estimated at 4 MMbbl and 17 prospects with combined resources estimated at 96 MMbbl of oil. Seismic coverage amounts to 740 km. One exploratory well has been drilled in the block. Resources (categories D1+D2) of the block are estimated at 63 MMbbl of oil. The starting price amounted to RUB 300.06 million (USD 4.5 million). Gazprom Neft Khantos offered RUB 750.15 million (USD 11.25 million).  The Srednevayskiy block covers 211 sq km in the Ural-Frolov Province and encompasses the Srednevayskoye oil discovery with 3P reserves estimated at 6.5 MMbbl and seven prospects with combined resources estimated at 27 MMbbl of oil. Seismic coverage amounts to 225 km. Two exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 20 MMbbl of oil. The starting price amounted to RUB 169.73 million (USD 2.6 million). Gazprom Neft Khantos offered RUB 424.33 million (USD 6.5 million).  The Sanlorskiy Yuzhnyy block covers 298 sq km in the Ural-Frolov Province and encompasses the Sanlorskoye Yuzhnoye oil discovery with 3P reserves estimated at 58 MMbbl. Seismic coverage amounts to 396 km. Two exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 93 MMbbl of oil. The starting price amounted to RUB 506.43 million (USD 7.7 million). Surgutneftegaz offered RUB 1,468.65 million (USD 22.33 million).",Government of Russia awards five licenses in Khanty-Mansiysk
41581,"In late December 2018, Qarun Petroleum Co (Qarun) abandoned the Bolt 122-1 exploration well in the East Bahariya Ext.III (Bolt) concession, Abu Ghardiq Basin. The well was spudded on 12 November 2018 with the “EDC-47” land rig and drilled to a TD of 3,968 m in the Cenomanian Bahariya formation. It had a planned TD of 4,045 m and the Albian Kharita Member and the Bahariya formation as the objectives.  Qarun Petroleum Co is a JV between the EGPC, Apache Oil Egypt, Dana Petroleum and Sinopec IP Corp.  Background information    Qarun was awarded the East Bahariya Ext.III (Bolt) concession in the Abu Ghardiq Basin, Western Desert in August 2018.","Qarun Petroleum Co (Qarun) abandoned the Bolt 122-1 exploration well in the East Bahariya Ext.III (Bolt) concession, Abu Ghardiq Basin. "
17381,"Chrysaor has agreed with OKEA to acquire a 15% stake the latter’s PL 038D / block 15/12a containing the Grevling oil find south of Sleipner. When completed, partnership in the 33-sq km block will be OKEA (op, 55%), Petoro (30%), Chrysaor (15%).","Chrysaor takes 15% interest in PL 038 D, which contains the Grevling oil discovery, from Okea (->55%, Petoro 30%)."
37583,"On 4 December 2018, the federal Secretary of Energy publicly released the first question and answer document for the Ronda I Offshore Exp Plan 2018 including 38 blocks. The document can be downloaded from https://costaafuera.energia.gob.ar/docs/preguntas/Preguntas%20y%20Respuestas%20Ronda1%20-%2004.12.2018.pdf. The tender was launched on 6 November 2018. On 14 February 2019 the presentation of company qualification and submission of offers will take place. The opening of A and B envelopes will take place on 14 March 2019. Pre-awards will be announced on 15 April 2019 and final awards on 15 July 2019. Future operators will be divided in class A, B, and C categories depending on the company's equity. The class A operators can be awarded any of the offered areas if they had over US$ 250 million equity in the last tax year. The other categories will have progressive restrictions for ultra deep and deepwater bidding areas. ",Not Found
15841,"Ref. DEA 17 Jan ’18, the 75 new licences offered in January in APA 2017 have been awarded on 2 Mar ’18 to their 34 applicants. Licence details/background from GEPS.   ","Norway, not found"
37286,"Qiulitage structure belt in the Kuche Depression, Tarim Basin. TD 6,316m in Oct ’18, tested 11.6 MMcfg/d + 150 bc/d, est. 3 Tcf GIP. Appraisals Zhongqiu 101 + 102 are planned, as well as Zhongqiu-2 (separate structure W. of the discovery).","China, not found"
44700,"Ref. DEA 21 Nov ’18, Total and Sonangol have reportedly signed up the PSC for deepwater, 3,292-sq km block 1, Gabon-Douala Deep Sea Basin + Calabar Fan. 8-year explo phase, 28 years total. Block 1 abuts the recently-signed blocks 7, 8 + 11 in the JDZ (block 1 in blue, ref. map below). Total (op) 55%, Sonangol 30%, Govt 15%.","Total and Sonangol have reportedly signed up the PSC for ultra-deepwater, 3,292-sq km Block 01,  8-year explo phase, 28 years total. Total (op) 55%, Sonangol 30%, Govt 15%. "
50329,"Hitherto unreported, on 13 October 2018, Oil & Gas Development Central Kft (OGD), subsidiary of Sand Hill Petroleum BV, concluded drilling appraisal Bagamer Del 2 in the Uljeta contract in eastern Hungary. The well reached the final depth of 2,928 m (TVD 2,895 m), failed to encounter commercial quantities of gas and was plugged. OGD was the sole operator of the well.  Bagamer Del 2, spudded on 29 September 2018, is located in the southeastern part of the block, close to the border with Romania. The well is situated within the Bihar sub-basin, tectonic unit of the Pannonian Basin.  The well had a planned final depth estimated at some 2,900 m.    Background Information    The 883 sq km Ujleta block, located in the Hajdú-Bihar and Szabolcs-Szatmár-Bereg political provinces, was granted to OGD in mid-February 2015 as the results of the country’s 2014 tender call. OGD is the sole operator of the tract.  The latest activity in the Bagamer area dates back to April-May 2017, when OGD completed with gas new-field wildcat Bagamer Del 1. The latest drilling operation in the Ujleta block took place in September 2018, when OGD completed drilling wildcat Letavertes Del 1 that encountered multiple gas-charged horizons in the Lower Pannonian and Miocene series – the well bottomed at 2,257 m (TVD 2,042 m) – and was completed for production.","Oil & Gas Development Central Kft (OGD), subsidiary of Sand Hill Petroleum BV, concluded drilling appraisal Bagamer Del 2 in the Uljeta contract in eastern Hungary. The well reached the final depth of 2,928 m (TVD 2,895 m), failed to encounter commercial quantities of gas and was plugged. "
81154,"NEO Energy has completed the acquisition of Spirit Energy's 13% interest and operatorship of licence P456 which hosts the Babbage gas field. It was confirmed that NEO acquired the interest on 14 May 2020.   Babbage was discovered in 1989 by Amoco’s 48/2-2Z well and appraisal drilling took place in 2006. The field has a Permian Leman Sandstone reservoir. During Phase 1 of development three horizontal multi-fractured wells were drilled between April and November 2009 and a platform was installed in September 2009. Production commenced from the field in August 2010. During phase 2, which took place between 2012 and 2013, there were 2 multi-fracced development wells were drilled. The Not Permanently Attended Installation (NPAI) is tied-back to the West Sole field which is located 28 km to the south. The field is expected to produce over 175 Bcfg over a life of 20 years.  Following the completion of the deal interest in the licence is held by NEO Energy (SNS) Limited (60% + operator) and Dana Petroleum (E&P) Limited (40%).",NEO Energy has completed the acquisition of Spirit Energy's 13% interest and operatorship of licence P456 which hosts the Babbage gas field. It was confirmed that NEO acquired the interest 
16903,"PetroChina will take 10 percent stakes in two of Abu Dhabi National Oil Company’s (ADNOC) offshore concessions under a 40-year agreement signed on Wednesday. PetroChina paid a participation fee of 2.1 billion dirhams ($575 million) for the Umm Shaif and Nasr concession and a fee of 2.2 billion dirhams ($600 million) for the Lower Zakum concession, ADNOC said in a statement.In the Umm Shaif and Nasr concession, PetroChina joins France’s TOTAL and Italy’s Eni which were recently awarded a 20 percent and 10 percent stake respectively.In the Lower Zakum concession, CNPC joins an Indian consortium led by ONGC Videsh, Japan’s INPEX, TOTAL and Eni.ADNOC retains a 60 percent majority share in both concessions.'These agreements strengthen our growing relationship with ADNOC, and will help to meet China’s expanding demand for energy and contribute to asset portfolio optimization and profitability enhancement of PetroChina,' Wang Yilin, who is chairman of both PetroChina and its parent China National Petroleum Corporation (CNPC), said in a statement.The 40-year agreements, signed by ADNOC and CNPC, are backdated to March 9, 2018, ADNOC said.In February 2017, CNPC, China’s largest oil and gas producer, was awarded an 8 percent interest in Abu Dhabi’s onshore concession, operated by ADNOC Onshore. It also has a 40 percent stake in the Al Yasat concession with ADNOC.'Energy cooperation is an increasingly important aspect of the UAE’s relations with China, the No. 1 oil importer globally and a major growth market for our products and petrochemicals,' ADNOC Group Chief Executive Sultan Ahmed al Jaber said in the statement.Original article linkSource: Reuters","UAE, not found"
55455,"The authorities have cleared Area 5 to be granted under E&P rights, formerly Ratio’s. Area 5 covers 8,720 sq km SW of the island. Contact dgcs.opm@gov.mt and www.continentalshelf.gov.mt.  It is also confirmed that blocks 1, 2 + 3 of Area 3 are now under a 1-year exploration study agreement to Edison, total 6,400 sq km off N. Malta in the Pelagian Basin, possible 2-year extn.","The authorities have cleared Area 5 to be granted under E&P rights, formerly Ratio’s. Area 5 covers 8,720 sq km SW of the island."
58386,"EP 469, onshore Perth Basin, TD 5,100m (Holmwood shale), Australia’s deepest onshore, Kingia net gas pay increased from 41m to 58m, reservoir pressure avg 6,820 psi suggesting 220m gross column.  Testing planned in coming weeks. Strike (op), partner Warrego.","Erregulla West 2 (Strike 50% op. Warrego 50%) in EP 469, Australia’s deepest onshore well, Kingia net gas pay increased from 41m to 58m, reservoir pressure avg 6,820 psi suggesting a gross column of 220m. TD=5100m (Holmwood shale). "
71591,"Santos Ltd spudded the Bugsy 1 exploration well in PPL 165, located in the Cooper-Eromanga Basin, on 19 January 2020. The well was drilled by the ""Ensign 974"" land rig. On 30 January 2020 the well was plugged and abandoned after encountering oil shows. It has been drilled to a total depth of 2,564 m.  The well is located in close proximity to the Malgoona oil field, which produced between 1990 and 2004.  PPL 165, which covers an area of 4 sq km, was awarded on 27 August 1999. Santos Ltd holds 40.7% and operatorship, with a further 25.9% held through various subsidiaries. The remaining 33.4% is held by Beach through subsidiaries Lattice Energy Ltd and Delhi Petroleum Pty Ltd.","Santos Ltd Bugsy 1 (exploration) PPL 165, Cooper-Eromanga Basin - P&A, oil shows"
11190,"PZ1 structure in the Satpayev block, Caspian (WD 7-7.5m), commitment well drilled Jun-Nov ’17, reportedly tested oil, rates n/a. Targets Mesozoic + Paleozoic PTD 3,500m in the Middle Carboniferous Bashkirian.  Satpayev Operating = ONGC-Videsh - KMG 25:75     ","Kazakhstan, 25"
66854,"Interra Resources reported on 11 December 2019 that wildcat Kuala Pambuang 1 (KP-1), in the Kuala Pambuang PSC, located in Central Kalimantan, has reached its total depth at approximately 1,149 m (3,771 ft). Borehole cutting analysis from the well has shown live oil at several zones within the primary reservoir targets, which subsequently confirmed by the electrical wireline logs (EWL). DTS was also conducted at the open hole with live oil samples collected.  The operator plans to complete the well next by installing casing and run casing perforation test at the potential reservoir. Likewise, further analysis is currently performed on the data and oil samples collected.  Wildcat KP-1 was spudded on 7 October 2019. The well has a planned total depth of around 1,100 m. As reported by SKK Migas, Rig Vinct # 02/500 was used for the drilling operation which was estimated to last approximately 26 days.     The target for the well, derived from data analysis and geological modeling conducted in 2017, has been identified in the Berai carbonate reefs, built on an extensive carbonate platform as the main reservoir. Secondary objectives are the clastic sedimentary reservoirs (Warukin Formation), situated above and below the carbonate platform. Interra reported exploration costs for the block of approximately USD 4,500 in Q4 2018.  Reportedly, the block has unrisked prospective resources of 67 MMbbl for low case, 305 MMbbl for mid case and 1,288 MMbbl for high case as per assessment conducted by ERC Equipoise Pte Ltd in January 2019.  The operator likely received technical approval for the well in late 2018, at which time it was in preparation to secure a drilling rig as well as preparing the drilling site. KP-1 is the first of possibly two commitment wells to be drilled in the block.  In Q1 2015, the company completed a 304 km of 2D seismic survey in the block, an initial seismic data interpretation was likewise completed in Q3 2015. The results from the initial study was encouraging and the company decided to proceed with the advanced seismic processing technique, with the aim on finding the reservoir fluid content and the rock properties in the area, which also lead to limiting the possible explorations targets.  The Kuala Pambuang PSC is operated by PT Mentari Pambuang Internasional (MPI) with 100% interest. Interra holds an effective interest of 67.5% in MPI. The company reported in November 2017 to be looking for a farm-in partner, to help with the funding of its exploration well campaign. However, as of Q1 2019, Interra indicated that the drilling and work programme for the year would be funded internally using available cash resources.  Background Information  The Kuala Pambuang block was offered in late September 2011 as part of the Second Petroleum Bidding Round 2011 under the direct offer mechanism. Preliminary award/announcement of winning bidder was made on 7 December 2011.   The block was officially awarded on 19 December 2011 and firm commitments include G&G studies (USD 1.20 million) and 200 km 2D seismic acquisition (USD 3 million). G&G studies were ongoing during 2012.  Goldwater signed a sale and purchase agreement on 3 February 2012 for the acquisition of 49% of the total issued and paid up share capital of PT Mentari Pambuang Internasional (MPI), a limited liability company registered in Indonesia and owned by PT Mentari ABDI Pertiwi. The deal was agreed on a “willing buyer, willing seller basis” and it involved cash consideration of USD 312,000 to MPI and a call option for Goldwater to acquire an additional 18.5% interest from MPI which can exercised anytime during the first three-year exploration phase. The deal was completed in February 2012 and the cash payment was funded from Interra’s existing funds on hand.  The main prospective targets in the area, Warukin sandstones and Berai carbonates, had been historically identified by Royal Dutch Shell during pre-World War II exploration activities.","Kuala Pambuang-1 nfw (PT Mentari Pambuang Intern.100%) Commitment well in Kuala Pambuang block, TD=1149m reached, oil noted in several zones and DST'd, 'live oil samples collected'. Plans are to complete by installing casing and testing the potential reservoirs. Targets Warukin, U&L Berai fm's."
39838,"On 21 January 2019, Genel Energy plc announced that it had reached agreement with Chevron Corporation to acquire a 30% equity interest in Chevron’s Sarta Block in the Kurdistan Region of Iraq. Genel will pay 50% of ongoing field development costs in the block until an agreed production target is reached in addition to a success fee payable once a production milestone is achieved. Genel has estimated that its total spend will be approximately USD 60 million up to the end of 2020. Interests in closing of the acquisition, which is subject to the approval of the Kurdistan Regional Government (KRG), will be Chevron 50% (operator), Genel Energy 30% and the KRG 20%. Chevron completed drilling of the Sarta 3 appraisal well in the block in 2018. Sarta 3 had a PTD of approximately 3,940 m and reached a TD of 4,023 m. Chevron completed testing operations at the Sarta 2 exploration well in the second half of 2015. Both wells have been individually tested at rates of approximately 7,500 bo/d.","Iraq, not found"
56785,"On 18 August 2019, Savannah Petroleum (Savannah) announced that the Nigerian President Muhammudu Buhari had approved Seven Energy’s asset transfer (Seven’s interests in Seven Uquo Gas Limited, Universal Energy Resources Limited and Accugas Limited). With only the transaction completion process pending for the deal to be closed, Savannah is in now the right position to continue its campaign in Niger with the testing of Amdigh 1 discovery as the main short term objective.   Savannah’s CEO, Andrew Knott, said that “The receipt of Consent in relation to the Seven Energy Transaction is a significant milestone for Savannah. I look forward to working with all stakeholders as we advance the Seven Assets.”  Savannah Niger is the operator of the Agadem R1, R2, R3, and R4 blocks through a joint venture between Savannah Petroleum Ltd (95%) and Niger Exploration (5%).","On 18 August 2019, Savannah Petroleum (Savannah) announced that the Nigerian President Muhammudu Buhari had approved Seven Energy’s asset transfer (Seven’s interests in Seven Uquo Gas Limited, Universal Energy Resources Limited and Accugas Limited). "
79078,"Equinor, operator of production licence PL 053, has concluded the drilling of wildcat well 30/6-31 S. The well was drilled about 7 kms southeast of the Oseberg C platform in the northern North Sea and 140 kms west of Bergen. The objective of the well was to prove petroleum in Middle Jurassic reservoir rocks (Intra Heather Formation sandstones). The well encountered poorly developed sandstones in the Intra Heather Formation with poor reservoir quality and no traces of petroleum. The well is classified as dry. Data has been collected. This is the 31st exploration well in production licence PL 053. The licence was awarded in the 4th licensing round in 1979. Well 30/6-31 S was drilled to respective vertical and measured depths of 2830 metres and 2852 metres below sea level. The well was terminated in the Ness Formation in the Middle Jurassic. Water depth at the site is 107 metres. The well has now been permanently plugged and abandoned. Well 30/6-31 S was drilled by the West Hercules drilling facility, which will now drill wildcat well 35/10-5 in production licence 827 S in the northern North Sea, where Equinor is the operator. Original article link Source: Equinor",Norway (Oseberg Fault Block (Horda Platform)) Oseberg
14106,"According to reports in mid-January 2018, Pampa Energia has agreed to sell its ownership of Petrolera Entre Lomas SA (PELSA) and several other assets to Vista Oil & Gas for USD 360 million. Closing of the transaction is pending on regulatory approvals. PELSA currently holds 73.15% interest and operatorship on four concessions in the Neuquen and Rio Negro provinces, namely the Charco del Palenque and Jarilla Quemada blocks (both areas formerly part of the Agua Amarga concession), along with Bajada del Palo and Entre Lomas. As part of the transaction, Pampa Energia also sold 3.85% of additional interest that the company held directly on said assets. Pampa Energia is the majority owner of PELSA with 58.88%, with partner Pluspetrol as the next largest shareholder with 40.7% interest. In addition, Pluspetrol is also a direct partner in said blocks with 23% interest. Outside of the PELSA-operated blocks, the transaction was said to include the sale of the company’s 100% interest and operatorship of the 25 de Mayo-Medanito SE and Jaguel de los Machos blocks in Rio Negro Province as well. Charco del Palenque (184 sq km), Jarilla Quemada (194 sq km), Bajada del Palo (452 sq km), and Entre Lomas (733 sq km) production concessions located on the Neuquen Embayment part of Neuquen Basin. Meanwhile, the 25 de Mayo-Medanito SE (125 sq km) and Jaguel de los Machos (112 sq km) blocks are located in the Northeast Platform part of Neuquen Basin.","Argentina (Neuquen B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Jaguel de los Machos op. by PETROQUIM (80.0%, PAMPETROL 20.0%) to be check.Bajada del Palo (CNQ-11 M) op. by PEL SA (43.3544330637%, PLUSPET RS 31.2872650688%, PAMPA EN 25.3583018675%) to be check.Jarilla Quemada op. by PEL SA (43.3544330637%, PLUSPET RS 31.2872650688%, PAMPA EN 25.3583018675%) to be check.Entre Lomas op. by PEL SA (43.3544330637%, PLUSPET RS 31.2872650688%, PAMPA EN 25.3583018675%) to be check."
68559,"Premier has reached heads of terms (presumably with partner Moeco and/or GS Energy) for a full carry on a 2-well appraisal campaign in the Tuna PSC, offshore East Natuna Basin, probably to the Kuda Laut-1 and Singa Laut-1 gas finds (aka ‘Tuna field’). The 999-sq km block is assumed still open for farmin prior to drilling:","Premier has reached heads of terms (presumably with partner Moeco and/or GS Energy) for a full carry on a 2-well appraisal campaign in the Tuna PSC, offshore East Natuna Basin, probably to the Kuda Laut-1 and Singa Laut-1 gas finds (aka ‘Tuna field’). The 999-sq km block is assumed still open for farmin prior to drilling:"
75718,"Real secured ATP 2051-P ('Project Vebnus'), 153 sq km in the Taroom Trough, Bowen-Surat Basin, on 23 Mar '20 for 6 years. It was applied for as PLR2019-1-11 on 30 Oct '19. Real Energy (op), partner Strata X.","Real Energy with JV partner Strata X, was awarded permit ATP 2051-P, located in the Taroom Trough."
55235,"Neptune Energy announced on 29 July 2019 that it had entered into an agreement with Wintershall Dea for the acquisition of interests in the Bramberge¸ Annaveen-Emslage and Meppen-Schwefingen oil and gas fields in the Emsland region as well as in some undisclosed gas fields which Neptune Energy is operating in the Grafschaft Bentheim region. The deal, which is subject to regulatory and partners approval and expected to close during the third quarter of 2019, will increase Neptune Energy’s net production by approximately 600 boe/d, which represents a 5% production increase for the company’s German production.  The Bramberge oil and gas field is covered by the 10-sq km Bramberge concession which operated by Neptune Energy. The field produced 524,422 bbl of oil and 197,448 Mcf of gas in 2017. Wintershall Dea reported on 29 July 2019 to hold a 22.42% interest in the concession.  The Annaveen-Emslage abandoned field is covered by Lingen-Hebelermeer III, IV and V concessions. Wintershall Dea reported to hold 7.5% in the concessions which are operated by BEB Erdgas & Erdoel (An Exxon Mobil and Shell JV).  The Meppen-Schwefingen field is covered by the Lingen-Meppen I and II concessions operated by Neptune Energy. Wintertshall Dea declared to hold a 10.4% interest in the field which produced 151,719 bbl of oil and 36,808 Mcf of gas in 2017.  It is understood that the gas fields located in Grafschaft Bentheim region are Frenswegen-Denekamp, Itterbeck-Halle and Kalle, all operated by Neptune Energy with a 50% interest with a 25% participation of Wintershall Dea.","Neptune Energy Group Ltd, Wintershall Dea GmbH - Neptune acquires interest in Bramberge, Annaveen-Emslage, Meppen-Schwefingen and numerous undisclosed fields in northwest Germany from Wintershall Dea"
29989,"On 18 September 2018, Novatek announced that exploratory well Salmanovskaya 294, drilled by subsidiary Arctic SPG-2, discovered two deeper pools in the Salmanovskoye (Utrenneye) field in Yamalo-Nenets Autonomous Okrug in Western Siberia. The company discovered additional 405 Bcf (13.8 Tcf) of gas and 40 MMt (320 MMbbl) of condensate in Middle Jurassic reservoirs. According to the company, 3P reserves of the field are now estimated at 2 Tcm (68.5 Tcf) of gas and 100 MMt (800 MMbbl) of condensate. The company submitted its new reserves estimations to the State Commission for Reserves (GKZ) for revision and confirmation. Well Salmanovskaya 294 was spudded in May 2017, TD of 4,400 m was reached in November 2017.  Background Information  The Salmanovskoye field was discovered in 1979 and in the South Kara-Yamal Province on the Gydan Peninsula with a minor extension to the Ob estuary. The field is part of the company’s Arctic LNG-2 project. Arctic LNG 2 will include three liquefaction trains with capacity of 6.6 MMt/year each installed on gravity-based structures in the Ob Estuary. The Salmanovskoye (Utrenneye) gas/condensate discovery is the feedstock for the LNG plant. In 2014-2017, Novatek-subsidiary Arctic SPG2 drilled six appraisal wells that resulted at extension of the discovery’s productive area and increase of its reserves. As the end of 2017, the company estimated 3P reserves of the discovery at 54.8 Tcf of gas and 475 MMbbl of condensate and oil.","Novatek announced that exploratory well Salmanovskaya 294, drilled by subsidiary Arctic SPG-2, discovered two deeper pools in the Salmanovskoye (Utrenneye) field in Yamalo-Nenets Autonomous Okrug in Western Siberia. The company discovered additional 405 Bcf (13.8 Tcf) of gas and 40 MMt (320 MMbbl) of condensate in Middle Jurassic reservoirs. According to the company, 3P reserves of the field are now estimated at 2 Tcm (68.5 Tcf) of gas and 100 MMt (800 MMbbl) of condensate. The company submitted its new reserves estimations to the State Commission for Reserves (GKZ) for revision and confirmation."
21127,"Aker is reportedly talking over the acquisition / participation in the South Deepwater Tano (SDWT) block, 3,478 sq km adjacent south to its Deepwater Tano-Cape Three Points (DWT-CTP) unit, and currently held by AGM Petroleum. A potential collaboration, co-investments or different corporate transactions are envisaged. A potential deal would depend on results of drilling due to be carried out across both blocks in 2H ’18. It is recalled up to 2 wells are planned in the DWT-CTP block, in which Aker partners with Lukoil, FuelTrade + GNPC.","Aker is reportedly talking over the acquisition / participation in the South Deepwater Tano (SDWT) block, 3,478 sq km adjacent south to its Deepwater Tano-Cape Three Points (DWT-CTP) unit, and currently held by AGM Petroleum. A potential collaboration, co-investments or different corporate transactions are envisaged. A potential deal would depend on results of drilling due to be carried out across both blocks in 2H ’18. It is recalled up to 2 wells are planned in the DWT-CTP block, in which Aker partners with Lukoil, FuelTrade + GNPC."
87283,"EnQuest has agreed to acquire 40.8125% and operatorship from Equinor in Bressay heavy oil field licences P234 (3/28a), P493 (3/28b), P920 (3/27b) and P977 (9/2a & 9/3a), as released on 31 July 2020. Initial consideration is GB£ 2.2 million (US$ 2.86 million), to be payed as 50% of Equinor’s net share of costs from deal completion (expected Q4 2020) with a contingent consideration of US$ 15 million following Field Development Plan (FDP) government approval for Bressay. The contingent payment increases to US$ 30 million if EnQuest sole risks Equinor in the submission of the FDP. The development concept selection was deferred in 2016 due to challenging market conditions and the need to simplify the development concept. Extensions to licence expiry dates and commitments are condition precedents to completion. A development concept being considered is a tie back to Kraken heavy oil field (EnQuest Op, 12km NE). EnQuest will become operator on P&A of discovery well 3/28-1 (1976, Chevron, 1,527m, Tertiary reservoir). The field was later successfully appraised. Estimated gross STOIIP is 600-1,050 MMbo and 100-300 MMbo estimated gross recoverable. 50km S is the Equinor operated Mariner Field. Chrysaor entered the licence when it acquired a package of assets from Shell in 2017. Current field partners Equinor UK Ltd (81.625% + Op) and Chrysaor Ltd (18.375%).","(East Shetland Platform) EnQuest has agreed to acquire 40.8125% and operatorship from Equinor in Bressay heavy oil field licences P234 (3/28a), P493 (3/28b), P920 (3/27b) and P977 (9/2a & 9/3a). Current field partners Equinor UK Ltd (81.625% + Op) and Chrysaor Ltd (18.375%). After completion, new field partners will be EnQuest (40.8125%, op.), Equinor UK Ltd (40.8125%) and Chrysaor Ltd (18.375%)."
80768,"Press suggests Eni could be looking to exit its Australia E&P position as of end May '20. The company, present in Australia since 1984, is reportedly working with investment bank Citi to prepare the offering. It is assumed an Australian withdrawal could also extend to the Timor Leste holdings (TL-SO-T 19-13 + Kitan field).   Eni Australia is involved in the operated Blacktip gasfield and in the COP-run Darwin LNG project, as wells as in the pending Evan Shoals, Blackwood and Penguin projects. Woolybutt is also part of the inventory, but is shutting down. Remaining net resources to Eni are 700 MMboe.","Eni Australia Ltd, Eni Timor Leste SpA could be looking to divest its entire Australian gas portfolio"
7394,"On 23 October 2017, US Company Hess Corp reported that it is currently selling its 80.75% operated interest in producing Ceiba and Okume Complexes to Dallas-based Kosmos Energy and London-based Trident Energy. The deal, expected to close by end 2017, is worth USD 650 million and will be effective back on 1 January 2017. Contacted, Tullow Oil confirmed that it remains partner with 14.25% interest. CEO John Hess said: “Proceeds from asset sales, along with cash on our balance sheet, are expected to fund the development of our truly world class investment opportunity offshore Guyana.” Kosmos proactively enters Equatorial Guinea, as it recently signed a PSC covering the three offshore exploration blocks surrounding Ceiba/Okume producing fields, namely EG-21, Block W and Block S. It is assumed that upon official ratification of the deal, Kosmos will operate the permits with 80% interest, alongside with GEPetrol (20%). In 2016, Hess’ crude oil volumes from Ceiba/Okume Complex (46,250 bo/d) represented almost 30% of total country’s output. However, the company recorded the largest decrease in production (22% drop from 2015). In 1H 2017, production from Ceiba/Okume continued to decrease to 35,000 bo/d. In 2016, operator ExxonMobil remained the largest producer in Equatorial Guinea (55% of country’s output) from its Zafiro field. Atlas/Noble produced the remaining 15% of country’s crude oil, from the Aseng field.  ",Equatorial Guinea (Rio Muni B.) Ceiba
9526,"Shantou 18-6-1 was plugged and abandoned (results TBC) in early November 2017 after having been spudded on 25 September 2017 (revised from 10 September 2017) using the ""COSL Prospector"" semi-sub. The gas exploration well was likely targeting the Wenchang Formation in a submarine fan system setting. The Shantou 18-6 Prospect is estimated to contain gas in place resources of 3 Tcf. Shantou 18-6-1 is in Block Tainan-Chaoshan PSC operated under a 50/50 joint venture partnership Tainan-Chao Petroleum Operating Co Ltd between CNOOC and CPC. <P />",Not Found
12239,"Statoil has acquired a 50% interest in licence P2338 from Apache. The latter was awarded the licence in the Supplementary Round which was held in 2016. The licence contains just one block – 16/18c which is situated between the Thelma field and the cross-border Utgard field. The deal completed on 6 December 2017. The Offshore 2016 Supplementary Licensing Round offered 14 blocks which were in areas located outside of the 29th Frontier Licensing Round. The round offered the Innovate Licence concept. Under the terms of the award, Apache is due to obtain 3D seismic over the acreage. There is also a Drill or Drop decision on the licence.  Interest in the licence is held by Apache North Sea Limited (50%) and Statoil (U.K.) Limited (50%).",United Kingdom (East Shetland Platform) (It's a petroleum rights. Please summarize by yourself). In IHS database: Thelma op. by CNR (100.0%) to be check.
55597,"Pacific Oil and Gas (POG, operator) and partner Bukit Energy are looking at divesting their conventional and unconventional assets, Kisaran PSC and MNK Kisaran PSC, located onshore in the Central Sumatra Basin, with operatorship and 100% interest available, as of early August 2019. The operator is planning to exit the region and concentrate on its LNG business in Canada.  The conventional block contains the Parit Minyak field, for which a Plan of Development (POD) has been approved by the government in 2015. The field is targeted to be onstream in 2020, with production up to 9,500 bo/d.  A third-party assessment revealed that the field has reserves estimates of 2.7 MMbo (1P), 10.7 MMbo (2P), plus 41 MMbo (2C). Several prospects and leads have also been mapped out in the block, with unrisked potential resources estimated at 350 MMbo. The operator also identified estimated resources of 850 Bcf and up to 100 MMbbl of liquid hydrocarbons in the deeper tight sand reservoir.  The other partner in both blocks, New Zealand Oil and Gas (NZOG), had also been in discussions for divesting its interests, earlier in 2019.  Details for both blocks are listed as below:          Asset         Area, sq km         Location         Valid contract period         Ownership         Firm Commitment (first three years)         Contract Status             Kisaran         871         North Sumatra and Riau provinces         17 May 2001 - 16 May 2031         POG - 55%, Operator   Bukit Energy - 22.5%   NZOG - 22.5%         -         Development             MNK Kisaran         2,180         North Sumatra and Riau provinces         22 May 2015 - 21 May 2045         POG - 55%, operator   Bukit Energy - 33.75%   NZOG - 11.25%         USD 11.6 million   1 well (planned in 2020)         Exploration           Moyes & Co. is the representative for this opportunity. For more information and to request Confidentiality Agreement, interested parties may contact:    Ian Cross    Managing Director    Tel: +65 9776 0753    Email: icross@moyesco.com         Maureen Macaulay    Manager A&D    Tel: +1 713 8514643    Email: mmcaulay@moyesco.com    Background Information    Kisaran PSC    The block, covering an area of about 870 sq km in the Central Sumatra Basin, includes the Parit Minyak field which was originally expected onstream in Q3 2016. Oil production from the first development phase is estimated at 1,400 b/d. Additional production from the second development phase is projected to reach 9,500 bo/d. The field is estimated to contain 2P reserves of around 11 MMbo, with 44 MMboe in the greater field area. Additional unrisked resources of 300 MMboe are estimated from near-field prospects identified from 3D seismic. All exploration commitments have been fulfilled for the PSC, which is due to expire in 2031. The block is operated by Pacific Oil & Gas with 55% interest. Bukit Energy holds 22.5% interest while the other partner is New Zealand Oil & Gas (NZOG) (22.5%).    MNK Kisaran PSC    The 2,180 sq km unconventional block is located in the Central Sumatra Basin, partially overlapping the conventional Kisaran PSC. Bukit holds 33.75% in the block. Operator Pacific Oil & Gas (55%) and NZOG (11.25%) are the other partners in the block. The operator is planning to conduct exploration drilling in the block targeting the Parit Minyak Deep structure, which was previously mapped using a 3D survey, with potential resources estimated at 712 Bcfg and 25 MMbc. Shale units in the Oligocene to Upper Miocene would be the primary targets in this block.","Pacific Oil and Gas (POG, operator) and partner Bukit Energy are looking at divesting their conventional and unconventional assets, Kisaran PSC and MNK Kisaran PSC, located onshore in the Central Sumatra Basin, with operatorship and 100% interest available, as of early August 2019."
16569,"Inpex Browse E&P Pty Ltd, a wholly owned subsidiary of Inpex Corp, was awarded exploration permit WA-533-P, located in the Canning and Roebuck basins, on 19 March 2018.  The permit has been awarded for a period of six years and will expire, or be eligible for renewal, on 18 March 2024. The permit was awarded to Inpex after being offered as block W16-6 in the 2016 Offshore Federal Acreage Re-release during 2017.  Work commitments have been assigned for the validity of the permit, with 5,005 km 2D and 1,035 sq km 3D seismic acquisition as well as geotechnical studies to be undertaken in years 1 – 3, between March 2018 and March 2021.  Further geotechnical studies are then outlined, including play evaluation and maturation of prospects, in years four and five.  In the final current permit year, between March 2023 and March 2024, one exploration well is planned at an estimated cost of AUD 25 million. WA-533-P, which covers an area of 12,439 sq km, was awarded on 19 March 2018.  Inpex Browse E&P Pty Ltd holds 100% interest and operatorship.","Australia, not found"
11879,"PA_1OGX066MA_PN-T-67 discovery evaluation plan area within BT-PN-007 contract, PN-T-067 block, Parnaíba Basin, drilled 20-28 Dec ’17, suspended results yet n/a.  PTD was 1,674m, targets Cabecas + Poti fm’s. ","Brazil (Parnaiba B.) 4-PGN-SESAORAIMUNDO-MA op. by PARNAIBA (100.0%) in PN-T-067, suspended results yet n/a.  PTD was 1,674m, targets Cabecas + Poti fm’s. "
26339,"PEMEX plugged and abandoned with oil and gas shows the Nantzin 1EXP new field wildcat (NFW) in the AE-0004 block on 20 June 2018.      The NFW reached a total depth (TD) of 5,142 m.    The NFW was spudded on 10 March 2018 after      receiving a permit from the CNH on 20 February 2018.         The      well had a proposed total depth (PTD) of 5,838 m.     The      Middle Cretaceous was the primary objective and the middle Miocene a      secondary objective.       The      “Cantarell II” J/U drilled the well in an estimated water depth of 70 m.  The      Nantzin prospect has estimated prospective resources of 218 MMboe.  The drilling cost for the well was      estimated to be USD 33.33 million at 1USD = 18.3 MXN and the completion      cost was estimated to be USD 11.42 million.       This      NFW represents the first of four wells planned for the block after PEMEX      had its modified exploration plan approved on 10 October 2017.        The NFW      is located in the north eastern area of the block approximately 5.2 km      northwest of the Tecoalli 1001 drilled in the Area 1 (Tecoalli A&B)      enclave block by PEMEX in 2014 prior to the block award to ENI.      SENER granted the AE-0004-4M-Amoca-Yaxche-04 entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 701.26 sq km.","Nantzin 1EXP (Pemex 100%) in the AE-0004. The Middle Cretaceous was the primary objective and the middle Miocene a secondary objective. P&A, oil and gas shows."
17650,"Providence announced on 28 March 2018 that it has entered an agreement to farm down 50% interest in Exploration Licence (SEL) 1/11 which contains the Barryroe field to a Chinese Consortium led by APEC Energy Enterprise Limited. In exchange for the 50% interest APEC will pay 50% of all the cost obligations associated with the drilling of three vertical wells including any associated sidetracks and well tests. APEC will provide a drilling unit, operational services and technical assistance to complete the drilling programme. Providence will act as operator for the drilling programme, once the programme completes APEC will have the right to acquire operatorship for the development/production phase. The deal is expected to close in Q3 2018.     Barryroe was discovered in 1973 by Esso. The field was originally not developed due to the waxy crude and that it was thought to be too compartmentalised. Barryroe lies directly below the Seven Heads gas field. The discovery was appraised in 2011 and tested with flow rates of between 1,300 and 1,600 bo/d. The oil is light (30° to 42°API) and has a relatively high wax content ranging from 12 to 22%. Following a resource audit for the in-place and recoverable resources for the Basal Wealden reservoir by Netherland Sewell & Associates Inc (NSAI) in April 2013 have revealed that with a recovery factor of 35%, 2P in-place volumes of 761 MMbo with recoverable resources estimated at 266 MMbo and 187 Bcf of associated gas have been derived. These resource calculations, combined with the RPS Energy resource assessment from 2011 of the overlying Middle Wealden, total recoverable resources for the field at 311 MMbo and 207 Bcf (346 MMboe). There is potential for additional resources in the Lower Wealden and Purbeckian Sandstones but Providence states that reservoir information and well test data is limited over these intervals and further data is required before confirming a final resource estimate for Barryroe.   In November 2015 the Barryroe partners were granted a two year licence extension to the first phase of the licence to (July 2017) and the second phase (July 2019). The areal extent of the licence was also increased by approximately 118 sq km to accommodate the mapped potential of the field.  Interest in Standard Exploration Licence 1/11 following completion of the deal will be held by Providence Resources (40% + operator) through its subsidiary EXOLA Ltd, APEC Energy Enterprise Limited (50%) and Lansdowne Oil & Gas (10%).",Ireland (North Celtic Sea B. (Celtic Sea Graben System)) Seven Heads
65877,"PEMEX plugged and abandoned with non-commercial oil and gas shows the Pox 101AEXP ST new-field wildcat (NFW) in the AE-0007-2M-Amoca-Yaxche-05 (AE-0152-Uchukil) entitlement block during early-November 2019 after reaching a total depth (TD) of 6,989 m.     The results were reported by      the CNH in early December 2019.   It was a replacement wellbore      for the original Pox 101AEXP that encountered drilling problems. The      surface location moved approximately 50 m form the junked and abandoned      Pox 101EXP.        The      Pox 101AEXP was spudded on 17 January 2019 and the side-track in late-July      2019.   The      well had a proposed total depth (PTD) of 6,540 m and the primary targets      were the Cretaceous and Jurassic formations.   The      NFW was expected to traverse a 530 m allochthonous salt canopy at this      location to reach the objectives.   The      well was drilled by the “West Titania” J/U in a water depth of 94 m.   The      NFW is located in the west central area of the block approximately 6 km      east north-east of the 2003 Pox 1 new-field wildcat plugged and abandoned      dry after extensive testing in 2009 in the westerly adjoining      AE-0005-2M-Amoca-Yaxche-03 entitlement block.   The      drilling permit for the well was granted on 8 August 2018.   The      NFW has unrisked prospective resources of 109 MMboe.   SENER      awarded the AE-0007-2M-Amoca-Yaxche-05 entitlement block to Pemex 100%      through Ronda 0 on 27 August 2014 but expired on 27 August 2019 and      replaced by the AE-0152-Uchukil entitlement block on 28 August 2019. The      block covers a modified area of 792.23 sq km.","Mexico, AE-0152-Uchukil"
30831,"Advent Energy Ltd announced on 28 September 2018 that it had signed a binding agreement to sell the majority shares in its wholly owned subsidiary Offshore Energy Pty Ltd to Bonaparte Petroleum Pty Ltd.  Bonaparte Petroleum has agreed to purchase 90% of the shares in Offshore Energy, currently held by Advent.  The agreement is conditional upon board approval of both companies, Bonaparte Petroleum showing it has the capability to fund the work programme proposed in the transaction and potential shareholder approval, if required by the Australian Securities Exchange (ASX).  Offshore Energy holds 100% interest in exploration licence EP 386 and retention lease RL 1, both located in the onshore Bonaparte Basin.  Bonaparte Petroleum has indicated that it has the capability to progress the licences, and under the terms of purchasing the shares has agreed to submit required documents for the drill of one or two exploration wells within EP 386, as well as acquiring 50 km new 2D seismic prior to the end of the current permit validity period, which concludes on 31 March 2020.  The company will also complete the decommissioning of two existing wells.   The work will be fully funded by Bonaparte Petroleum under the share acquisition.  Further terms to the agreement include the issue of 10% interest, under a standard joint operating agreement, to Advent on the award of any subsequent retention or production licences over the current asset area. Under these terms Advent will earn a 10% share in Bonaparte Petroleum, and transfer the remaining shares in Offshore Energy to Bonaparte Petroleum.  A further 10% interest in any subsequent licences will be granted to Advent upon the discovery of 15 MMboe reserves.  An option remains for Advent to buy back into REL 1. If EP 386 is not renewed or transferred to a retention or production licence, Advent will also be reinstated as operator and holder of RL 1.  If Bonaparte Petroleum chooses not to proceed with the transaction outlined in the agreement reached on 28 September 2018, Advent will be paid a break fee of AUD 50,000.  Advent Energy Ltd had been aiming to farm-out interest in the licences, alongside its other Australian asset PEP 11, located in the Sydney Basin.","Advent Energy Ltd announced on 28 September 2018 that it had signed a binding agreement to sell the majority shares in its wholly owned subsidiary Offshore Energy Pty Ltd to Bonaparte Petroleum Pty Ltd.  Bonaparte Petroleum has agreed to purchase 90% of the shares in Offshore Energy, currently held by Advent."
55639,"Eni is taking over from Sonangol EP as operator of block 1/14,  3,730 sq km in Congo Fan shallow waters. The deal is pending ministerial approval and will be retro-effective 1 Jun ’19. Partnership-to-be is Eni (op) 35%, Sonangol P&P 30%, Equinor 25%, ACREP 10%.","Eni is taking over from Sonangol EP as operator of block 1/14,  3,730 sq km in Congo Fan shallow waters. The deal is pending ministerial approval and will be retro-effective 1 Jun ’19. Partnership-to-be is Eni (op) 35%, Sonangol P&P 30%, Equinor 25%, ACREP 10%.     "
34442,"Block A2, 1st well offshore Gambia in 40 years, south + on trend with SNE field in Senegal (MSGBC Basin), WD 1,017m, P&A’ing oil shows at TD 3,240m, Stena DrillMAX DS. Target Albian. The licence has been extended 6 months to provide for well results analysis. FAR (op), partners Petronas + Erin.","Samo 1 (FAR 34% op, Petronas 34%, Erin Egy 17%, GNPC 15%) in A2 block, P&A, drilled a TD=3240m and wireline logs interpreted so far indicate the main target horizons are water bearing. However, it added that oil shows were encountered over several levels, indicating the area has access to an active hc charge system."
76699,"Area I, South Natuna Sea block B Extn, ops terminated later Mar '20, gas discovery reported early April, no details, Hakuryu-5 JU released to Singapore. Targets Arang + Gabus fm's. Medco (op), partner Prime Natuna Egy.","Bronang 2 expl. (Medco 75% op, Prime Natuna Egy 25%) in Area I, South Natuna Sea block B Extn, gas discovery reported early April, no details, Targets Arang + Gabus Fm's."
15699,"AIM-listed Egdon Resources has reached agreement on Heads of Terms in respect of a farm-out of interests in PEDL253 to Union Jack Oil and Humber Oil & Gas.  PEDL253 is located in Lincolnshire and contains the Biscathorpe Prospect, scheduled for drilling around mid-2018. Under the agreed terms, UJO and Humber will each acquire 6% of Egdon's interest in PEDL253 by paying their pro-rata share of the Biscathorpe-2 well cost plus an additional £10,000 per percentage point interest acquired.  This is equivalent to a farm-in with a 1.36 times promote at the estimated well cost.  UJO and Humber will also each acquire 4% of Montrose Industries interest in PEDL253 under the same terms. The Biscathorpe Prospect is located between Lincoln and Louth. It lies on the southern margin of the Humber Basin on trend with, and to the west of, the producing Keddington oil field (14 kms, Egdon operated) and the Saltfleetby gas field (20 kms). The Biscathorpe-2 well will target a down-dip area of the structure which was tested in a crestal position by the Biscathorpe-1 well drilled in 1987 by BP which found oil in a 1.2 metres thick sandstone of Westphalian (Carboniferous) age.  The structure has been mapped using reprocessed 3D seismic data and the sandstone is predicted to thicken to the north and east away from the Biscathorpe-1 well. The Mean Gross Prospective Resources at Biscathorpe are estimated by Egdon to be ca. 14 million barrels of oil and the well has been assessed by the Company as having a 40% chance of success.  The transaction is subject to contract and approval from the Oil and Gas Authority.  On completion the interests in PEDL253 will become: Egdon Resources U.K. (Operator) 40.80% (29.31% share of well cost*) Montrose Industries 27.20% (19.54% share of well cost*) Union Jack Oil  22.00% (37.57% share of well cost*) Humber Oil & Gas 10.00 % (13.57% share of well cost*) * at the current estimated well cost Mark Abbott, Managing Director of Egdon Resources, said: 'We are pleased to have achieved our objective of balancing our financial exposure and technical risk on the near-term Biscathorpe-2 well.  We welcome both Humber Oil & Gas as a new partner and UJO's increased participation in PEDL253.  We now look forward to drilling this high potential conventional oil prospect around mid-2018.' Click here for Union Jack Oil announcement: Proposed Farm-in for an Additional 10% Interest in the Drill-Ready Biscathorpe Prospect Commercial Partnership Memorandum Signed with Humber Oil & Gas Limited Oversubscribed Placing and Subscription to raise £1.25m   Original article link Source: Egdon Resources ",United Kingdom (East Midlands Platform (Anglo-Dutch B.)) Saltfleetby
79250,"Skye Energy Ventures Pty Ltd, through its subsidiary company Skye Petroleum Pty Ltd, is offering a farm-in opportunity to exploration permit EP 497, located in the Peedamullah Shelf/Barrow Sub-basin, North Carnarvon Basin. Skye is likely offering a low-cost entry with no drill commitments and is seeking a partner to assist in Early Cretaceous oil play exploration. Commercial discoveries could potentially be developed alongside Skye Energy Venture operated oil assets located to the north in adjacent permits.  The central area of the permit, within the Barrow Sub-basin, is covered by the Flinders 3D survey which was acquired by TGS in 2001. The survey extends north over the Cyrano, Chervil, Herald North and Pepper South oil discoveries which offer structural plays in the Upper Jurassic to Lower Cretaceous. The play extends to the 1993 Santa Cruz oil/gas discovery with EP 497.  Santa Cruz 1 was drilled on vintage 2D seismic data and is not covered by the Flinders 3D seismic survey. Thus, the areal coverage of the structure is currently unknown. Low quality structure maps from the vintage data indicate that the well clipped a structure of around 50 sq km with the possibility of additional stratigraphic elements analogous to the Stag oil field. The well encountered a biodegraded gas cap with a 10 m oil leg below in the Birdrong Sandstone at a depth of around 430 m. Although the sandstone was found to be of poor quality at location, the permit could also offer prospectivity in the Mardie Greensand and Barrow Group, all of which overlain by the regional, and proven, Muderong Shale seal. In the nearby Herald North field, oil derived from pre-Jurassic calcareous source rocks appears to have migrated and filled the reservoir. The migration path is not clear. This oil is thought to have biodegraded in situ by the influx of meteoric waters.  Two wells are also located within the permit area: Bricklanding 1 and Dill 1. Bricklanding 1 was designed to test the low side fault closure against the Flinders Fault in 2006. The well was plugged and abandoned with minor gas shows in the Calypso Formation.   EP 497 is now in term three of a six year work programme after being awarded on 16 November 2017 to Carnarvon Petroleum. Skye Petroleum (previously Skye Alba) acquired 100% interest in July 2018. The permit offers an exploration upside to the oil and gas assets held by Skye in the adjacent permits. In the remaining three year work programme, commitment spend totals around AUD 6.9 million dollars through geochemical studies and 100 sq km of new 3D seismic data acquisition in the final term. In the first two years, it is thought that Carnarvon focused on building a well and seismic database of the block through data collection, mapping and geotechnical work.  Across 11 discoveries and abandoned fields held by Skye Energy Ventures, recoverable resources totaled around 40 MMb oil and 90 Bcf gas. It is thought, that before further appraisal, development and advance production techniques, around 10-15 MMbo and 50 Bcf gas could remain. Skye is specifically targeting advanced oil recovery to maximise production from the existing assets. Infrastructure within the permits includes Chervil, South Pepper and Herald North pipelines and the Port Airlie Island terminal.  EP 497 covers an area of 478 sq km and is 100% owned and operated by Skye Petroleum Pty Ltd. The company is seeking a farm-in partner to assist with the exploration work programme over the next three years, until the permit is scheduled to expire on, or be renewed by, 15 November 2023.   Companies interested in pursuing this opportunity are to contact:  Joseph Graham – Skye Energy Ventures CEO  Phone: +61 (0) 417 592 555  E-mail: joseph.graham@skyeev.com","Skye Energy Ventures Pty Ltd, through its subsidiary company Skye Petroleum Pty Ltd, is offering a farm-in opportunity to exploration permit EP 497, located in the Peedamullah Shelf/Barrow Sub-basin, North Carnarvon Basin. "
85380,"Further to DEA 11 Jun '20, ReconAfrica's award of sole rights to 9,921 sq km of Okavango (Kavango) Basin acreage last month at the start of the panhandle in NW Botswana is now named as PEL 001/2020 (GEPS map extract below). The contract runs 4+10 years, plus 25+20 years production if warranted. Commitments include: HR airmag in yr 1, regional geol studies in yr 2, environmental impact studies, pre-drill operational environmental assessment in yr 3, identification of all necessary regulatory permits and approval, soil geochemical sampling for identifying hydrocarbon plumes, supporting drill selection, in yr 4.","Namibia, (Okavango B.), ReconAfrica's award of sole rights to 9,921 sq km of Okavango (Kavango) Basin acreage last month at the start of the panhandle in NW Botswana is now named as PEL 001/2020. The contract runs 4+10 years, plus 25+20 years production if warranted."
43662,"The award of 2018 Round 6 block Drava was signed off by the authorities 7 Feb ’19 and is now effective. The 185-sq km unit lies in the Nagykunsag, Bihor + Bekes sub-basins (Pannonian Basin).","Hungary, Drava"
25179,"Premier announced on 30 April 2018 that it is selling its interest in a number of assets in the Babbage area to Verus Petroleum. The deal will see Verus obtain 47% interest in the Babbage field, 50% interest in the Cobra discovery and a number of exploration commitments. The sale of Babbage amounts to GBP 62.9 million (USD 88.1 million) and exploration commitments of GBP 17 million (USD 23.8 million). If the development of Cobra proceeds then additional payments would take place depending on third party business in addition to a cash payment of GBP 5.5 million (USD 7.7 million). The effective date of the deal is 1 January 2018 and completion is expected during H2 2018 subject to partner and government approval. On 6 July 2018, Spirit Energy announced it has reached agreement to take operatorship of the Babbage and Cobra licences. Spirit plans to drill an exploration well at the Python prospect in Q2 2019 to further prove up reserves in the region. Transfer of operatorship from Premier Oil is subject to completion of the divestment of Premier Oil's 47% interest in Babbage and 50% interest in the Cobra licence to Verus Petroleum and receiving relevant regulatory approvals.  Babbage was discovered in 1989 by Amoco’s 48/2-2Z well and appraisal drilling took place in 2006. The field has a Permian Leman Sandstone reservoir. During Phase 1 of development three horizontal multi-fractured wells were drilled between April and November 2009 and a platform was installed in September 2009. Production commenced from the field in August 2010. During phase 2, which took place between 2012 and 2013, there were 2 multi-fracced development wells were drilled. The Not Permanently Attended Installation (NPAI) is tied-back to the West Sole field which is located 28 km to the south. The field is expected to produce over 175 Bcfg over a life of 20 years.   Cobra is a segmented structure spread over five separate segments of Rotliegendes Sandstone. The discovery was made by Amoco in November 1984, when well 48/2-1 was reported to have encountered gas, although it would not flow at commercial rates unstimulated. An appraisal well was drilled by EnCore in May 2008, which targeted the same 3-way closure. However, it was abandoned as uncommercial. When tested the well flowed a maximum unstimulated rate of 1.1 MMcf/d dry gas. Verus is planning to drill a new appraisal well in 2019 to test the presence of further volumes of gas, which could be tied-back to the Babbage field.  Following completion of the deal interest in Babbage, which is located in block 48/2a and covered by licence P456 will be held by Verus Petroleum UK Limited (47%), Dana Petroleum (E&P) Ltd (40%) and Spirit Energy Southern North Sea Ltd (13% + operator). Interest in P2212, P2290 and P2301 will be held by Verus Petroleum UK Limited (50%) and Sprit Energy Southern North Sea Limited (50% + operator).",Premier announced on 30 April 2018 that it is selling its interest in a number of assets in the Babbage area to Verus Petroleum. 
15033,"SACOS has secured a 40-year oil shale concession in the Attarat Umm Ghudran area, some 2,500 b/d expected in an initial phase using oil shale pyrolysis. A preliminary agreement to this intent had been signed in 2014.",Jordan (Western Arabian Province) ? op. by SACOS (100.0%) in Attarat Umm Ghudran (SACOS) block
30453,"The Bureau of Safety and Environmental Enforcement (BSEE) has issued Shell Offshore Inc. a permit for the permanent abandonment of the WR 595 1S1B0 sidetrack well (API: 608124012401) at the Stones SW prospect in the ultra-deepwater Central Gulf of Mexico. The company has not disclosed the result or final drilling depth of the sidetrack or the WR 595 1S0B0 original hole (API: 608124012400) that tested a subsalt Wilcox play next to Shell’s Stones field. The BSEE approved the permit on 21 September 2018 and the operator planned to begin plugging the well on the day the permit was received, anticipating the work would take seven days. Shell has conducted operations on Walker Ridge block 595 through 100% owned OCS lease G36088 using the Transocean drillship “Deepwater Pontus.”  Shell mobilized the “Deepwater Pontus” to drill site in late July where the dynamically positioned drillship began operations on the Stones SW prospect, a near-field Lower Tertiary (Paleogene) Wilcox play found along the edge of the Sigsbee Escarpment in some 9,700 ft (2,957 m) of water. Located near the center of the Walker Ridge (WR) protraction area, the prospect area resides roughly 250 miles (400 km) south-southwest of New Orleans, Louisiana, and about 180 miles (288 km) from the nearest shoreline. Shell-operated Stones field, a producing Wilcox oil accumulation, lies immediately northeast of the prospect.  Shell spudded the WR 595 1S0B0 on 2 August 2018. After about a month, the company ceased drilling operations on the original hole and proceeded to plug it back and use the borehole to start the sidetrack on 31 August at a depth of 22,437 ft (6,839 m). The Stones SW drill site corresponds to the WR 595 “H” surface location in the operator’s nine-well, N-10015 exploration plan that covers WR blocks 594 and 595. The Bureau of Ocean Energy Management (BOEM) approved this plan in June 2018. This drill site lies in 9,685 ft (2,952 m) of water in the SE/4 SW/4 NW/4 of WR block 595. The company scheduled 195 days of rig time to drill and suspend this well, which is designed to spud and bottom in WR block 595. The shallow hazard survey indicates that allochthonous salt is not encountered in the top-hole of the WR 595-H well down to its investigation limit of 6,850 ft (2,088 m) below the mudline or -16,535 ft (5,040 m) subsea. All the nine drill sites associated with Stones SW exploration plan are located to the east and ostensibly in front of the edge of the Sigsbee Escarpment, which means that the wells will probably be clear of the salt canopy.  The Stones SW wells are targeting the stratigraphic section that is correlative to the Wilcox pay zone found around 26,250 ft (8,001 m) in the adjacent Stones field. Discovered in 2005 and sanctioned in 2013, Shell brought Stones field onstream in September 2016. As of July 2018, the field is producing from four subsea wells tied back to the “Turritella,” a floating, production, storage, and offloading (FPSO) vessel. Since coming online, the field has flowed 9.4 MMbbl of oil, 1.4 Bcf of gas, and 613,733 bbl of water through February 2018.  OCS lease G36088 (WR-595) is a standard 5,760-acre (23.31 sq km) deepwater tract that was awarded 100% to Shell Offshore Inc. at Central Gulf Sale 247, held in March 2017. Bidding alone and without competition, the company acquired the G36088 lease with a bonus bid of USD 4,556,719. The BOEM issued the acreage on 1 July 2017 with a 10-year term that is scheduled to expire on 30 June 2027.  Background Information    Less than ten miles (16 km) north of Stones field, Shell tested the Ipanema prospect on WR block 376, likely targeting subsalt Miocene and Wilcox objectives. The company drilled three boreholes to assess the prospect. The WR 376 #1 (API: 608124011900), WR 376 #2 (API: 608124012000) and WR 376 #2 BP1 (API: 608124012001) wells were subsequently plugged and abandoned in January 2018. Although the outcome of this drilling program has not been publicly disclosed, the WR 376 lease (G33375) was relinquished by Shell in July 2018 one year before its scheduled expiry date of July 2019, making the Ipanema wells either dry or non-commercial.  WR block 594 and 595 were part of Shell’s original Stones unit (Contract No. 754306006). They were held by unit operations past their 2006 expiration date, but were dropped from the unit and terminated by government regulators in 2009. Eni and Ecopetrol attempted to acquire these blocks in 2010 as did a combine of LLOG, Houston Energy and Red Willow Offshore in both 2015 and 2016. The BOEM rejected the high bids of both these groups because the cash bonus was deemed below the fair market value. Stones SW is now situated along the southwest border of the nine-block, Shell-operated Stones field production unit. As of March 2018, the WR Block 508 “Stones” Unit consists of WR blocks 464 (S/2), 507, 508, 509, 551, 552, 553, 596, and 597.",WR 595 001S1B0 (Stones SW prospect) (Shell 100%) in the ultra-deepwater OCS Lease G36088. The company has not disclosed the result or final drilling depth.
80968,"Jersey Oil and Gas (JOG) announced on 20 May 2020 that it has completed the acquisition of Equinor's 70% interest and operatorship in licence P2170 (Blocks 20/5b and 21/1d). The deal originally announced on 27 January 2020 stated that the acquired interest is in return for two milestone payments and associated royalties with the Verbier discovery. Under the terms of the deal JOG will pay USD 3 million once the Field Development Plan has been sanctioned by the OGA. A further payment of USD 5 million will be paid once Verbier comes onstream. With regards to the royalties, Equinor will receive (net 70%) payments on the first 35 MMbo produced. JOG is hoping to push towards select gate in Q3 2020 as it looks to develop the Greater Buchan Area which is comprised of the Buchan redevelopment project, Verbier, J2 discovery and Glenn. Following the development concept selection process is completed JOG will launch its farm-out process for the project.    The company believes that its acreage contains 120 MMboe of discovered mean recoverable resources and further potential within identified mean prospective resources. It is estimated from JOG that Buchan (Devonian) alone contains over 80 MMbo (recoverable) with further potential in a shallower reservoir (Andrew sands) sat above the main Buchan reservoir. Buchan is thought to be the main new hub for the area development. The development of the J2 discovery will run concurrently with Buchan. J2 is thought to be made up of two accumulations, approximately 20 MMbo present in the Sgiath sandstone Formation and further recoverable oil in Upper Jurassic sands which are thought to be a potential eastern extension of the Verbier discovery. Glenn is located 15 km to the east of Buchan and could be a potential tie-back to Buchan. Glenn is a faulted horst with oil sat within Upper Jurassic, shallow marine Sgiath Formation sands. It is thought that Glenn could hold up to 14 MMbo (recoverable). The Verbier discovery, which was unsuccessfully appraised by Equinor with JOG as a partner in 2019 is thought to contain approximately 25 MMboe. It is thought that a large part of the mapped area of the Verbier discovery located to the northwest of the recent appraisal well remains untested along with further additional resource potential thought to sat in a deeper horizon beneath Verbier. JOG also has a prospect called Cortina in this area and from the recent acquisition of the 2018 PGS Geostreamer 3D data this additional potential will be further reviewed.  Following completion of the deal, interest in P2170 is held by Jersey Petroleum Ltd (88% + operator) and CIECO V&C (UK) Ltd (12%).","Jersey has completed the acquisition of 70% + operatorship in P2170 / blocks 20/5b + 21/1d from Equinor in exchange for payment (USD 3 & 5 MM linked to Verbier clearance + production) + royalty based on oil production from the Verbier U. Jurassic reservoir. Jersey (op) 70%, Equinor 18%, CIECO 12%"
73536,"Berezivske field area, Kharkiv Oblast, Dnieper-Donets Basin, TD 6,100m, tested 8.6 MMcfg/d from the Tournaisian, adding 17 Bcf of proven reserves. Xinjiang Beiken Energy Engineering Co rig.","erezivske field area, Kharkiv Oblast, Dnieper-Donets Basin, TD 6,100m, tested 8.6 MMcfg/d from the Tournaisian, adding 17 Bcf of proven reserves. "
71131,"Kina Petroleum Corp is offering an opportunity for a farm-in partner to acquire equity in exploration licence PPL 437, located in the Papuan Basin. Kina holds 57.5% interest and operatorship in the permit with partner Heritage Oil (42.5%). Kina is seeking a partner in return for funding an upcoming work programme which would ideally include much needed 2D seismic acquisition. In early-January 2020, Kina reported that, along with Heritage, it was in discussions with a potential farminee. Heritage is looking to divest its entire 42.5% interest in PPL 437. As part of a portfolio review, the company no longer sees Papua New Guinea as a core growth region and is thus looking to exit the country.  PPL 437 is located immediately north of the Elevala and Ketu fields which lay in Horizon’s operated PRL 21. Kina considers the Malisa Prospect as drill ready and the permit also contains Ebony, Mango and Ketu North prospects. Kina has submitted a permit extension application to the Department of Petroleum in a bid to continue exploration past the due expiry date of 18 February 2019. Under an extension, Kina would like to acquire seismic along the Mango, Ebony and Kandis prospects ahead of constraining and ranking.    Malisa has the potential for gas within the Kimu and Elevala/Toro formations, with Heritage reporting that it could contain 2P prospective recoverable resources of 280 Bcf gas. The licence lies in close proximity to the Elevala, Ketu, Stanley, P’nyang and Juha discoveries, meaning opportunities for development through the proposed Western LNG project or third party access to the considered P’nayng to Kutubu pipeline, should a discovery be made.     A total 170.4 km of 2D seismic was acquired over Malisa in 2014 during the Gosur Survey. Interpretation of this data was reported to be completed in 2H 2017, along with integrated aerogravity data. Initial results show significant prospectivity in the east of the permit. In addition, vintage seismic data has been reprocessed within the licence, which is now complete and fully interpreted. Once the Malisa data and reprocessed vintage seismic data have been merged, farm-in conditions and equity level will again be assessed prior to pushing the opportunity further to potential farminees.    Under the work commitments, the option existed to either drill one well or complete an additional phase of seismic in place of the well before reaching the end date of 18 February 2019. It is thought that the terms were renegotiate to allow Kina to submit an extension application in 2H 218. Drilling targets could potentially be identified through interpretation of reprocessed vintage 2D seismic data. A seismic programme was expected in 2018 which did not materialise.   Heritage farmed into PPL 437 in 2013 with the condition that Kina would be free-carried through the first seismic programme. Additional interest could be earned by Heritage (up to 50%) if the option to drill an exploration well was taken, in which Kina would also have been free carried.    Kina is also offering a farm-in opportunity in its two southern Western Province licences: PPL 435 and PPL 436, which are interpreted to extend the liquids fairway from Stanley-Tingu-Elevala-Ketu fields.    PPL 437, which covers an area of 1,537 sq km, was awarded on 19 February 2013 and is scheduled to expire on, or be eligible for renewal by, 18 February 2019.Operator Kina Petroleum Corp holds 57.5% interest with partner Heritage Oil Ltd (42.5). Kina is seeking a farm-in partner to assist in a continued exploration programme. Heritage is looking to exit the permit.    Companies interested in pursuing this opportunity should contact:  Richard Schroder – Kina, MD    Email: richard.schroder@kinapetroleum.com  Krey Stirland – Heritage Oil, Vice President Business Development    Email: krey.stirland@heritageoilltd.com","Kina Petroleum Corp offering farm-in opportunity in PPL 437, Papuan Basin"
13448,"Yanchang Petroleum achieved a breakthrough in shale gas exploration in the Ordos Basin. Yunye – Ping 3, tested 1.87 MMcf/d of gas, through a 10-stage with CO2 fracking,  in the Permian Shanxi Formation, which is an important success in non-marine shale gas exploration since Liuping 177 tested gas in non-marine Triassic in 2011 in the Basin.  Yanchang Petroleum has completed 5 wells in Yunye – Ping 3 area, with average tested gas rate about 70 Mcf/d. After Yunye – Ping 3 success, it is estimated about 1.8 Tcf of shale gas in place in this area.  Yanchang Petroleum started shale gas exploration in the Ordos Basin in 2008. In 2011, Liuping 177 tested gas in Triassic shale.  The well was completed on 22 July 2010 with a good show in the shale interval. On 24 April 2011, the company conducted a fracture work over a shale interval in the Chang 7 formation and tested with gas flowing.  In 2012, Yanchang Petroleum drilled Yanye Ping-1 and tested gas in Triassic shale.  In 2013, Yanchang Petroleum completed drilling operation in Yanye Ping-2 in the Ordos Basin. The shale gas horizontal well is located in Xiasiwan of Ganquan County in Shanxi Province. The well was spudded on 16 December 2012 and completed on 14 February 2013. This is the second horizontal well the company drilled for shale gas exploration.  For the last few years, less shale gas exploration progress has been reported from Yanchang Petroleum. The company originally planned to produce 500 million cubic meters shale gas by 2015 but this target is not met. However, In 2018 Yanchang Petroleum reports it has confirmed 5.8 Tcf of shale gas in place in the Ordos Basin and plans to build up 1.5 Bcm of shale gas production capacity by 2020.   ","Shale gas well in Ordos Basin, 10-stage CO2 frac yielded 1.87 MMcfg/d CO2 fracking in the Permian Shanxi fm. "
41265,"Pakistan Petroleum Ltd (PPL) has plugged and abandoned (P&A) the Misrial X-1 new field wildcat (NFW) well within the Hisal 3372-23 EL (Potwar Basin) onshore concession in late January 2019 after it failed to flow hydrocarbons during testing. The company had drilled a sidetrack hole – the sidetrack drilling was initiated in October 2018 after reaching 5,167 m depth. The well was spudded on 1 February 2018 using the “CCDC-23” land rig with a prognosed TD of 5,208 m in the Eocene.  Misrial X-1 was reported to have been drilling at 503 m depth by mid-February 2018 and reached 1,130 m by the end of the month. After setting 18 5/8” casing at 1,543 m depth, the well reached 1,546 m during mid-March. It was drilling at 2,301 m depth by the end of March and reached 3,000 m by mid-April 2018 after setting 13 3/8” casing at 2,997 m. It progressed to 3,581 m depth by the end of April and reached 4,265 m by mid-May 2018. The well progressed to 4,718 m by the end of May, reached 4,877 m in early June 2018 where a 9 5/8” casing was set and it progressed to 4,953 m by the end of the month.   The well reached 5,167 m depth in late July 2018 which was followed by testing. It was reported by Pakistan Oilfields Ltd (POL), a partner in the Hisal block, that the testing in the first formation was not successful, whereas it could not be done in the second formation due to a fishing problem – a sidetrack drilling was subsequently initiated in October 2018.    Hisal EL covers an area of 1,506 sq km and is located in the Attock, Chakwal and Rawalpindi districts of Punjab province. Current equity split is as follows: PPL 65% (operator), Pakistan Oilfields Ltd (POL) 25% and Attock Oil Company (AOC) 10%.    PPL acquired 63 line km of 2D infill seismic (vibroseis source) in the block during September-October 2017. The company had earlier acquired 463 line km 2D seismic in the block during February-June 2016 using a Dana Geophysics seismic crew.         Background Information    PPL was exclusively awarded the Hisal EL licence with the signing of Petroleum Concession Agreement (PCA) on 10 February 2014. PPL then assigned 25% working interest to POL and 10% working interest to AOC, effective from 30 November 2016. As a result, the new equity split is as follows: PPL 65% (operator), POL 25% and AOC 10%.    The block was offered under the 2012 Licensing Round which was launched from 11 October 2012 to 10 March 2013. A total of 58 blocks were offered for competitive bidding - the bids were opened on 10 March 2013. A total of 66 bids were received for 50 blocks from various companies, whereas eight blocks did not receive any bid. Oil and Gas Development Company Ltd (OGDCL) was the highest bidder in 28 blocks, whereas Pakistan Petroleum Ltd (PPL) is believed to be a highest bidder in nine blocks and Pakistan Oilfields Ltd (POL) in five blocks. Al Haj and Oil & Gas Investment Ltd (OGIL) were the highest bidders in two blocks each, whereas Ocean Pakistan Ltd (OPL), OMV-PPL, TRI and Mari Petroleum Pakistan Ltd (MPCL) were the highest bidders in one block each. As a result of this bidding round, the E&P Companies had committed to invest a minimum finacial expenditure of around US$ 372 million (Pak Rupees 37 billion).    Al Haj Group had also submitted application for Hisal block during the bid round which was rejected by the government.    PPL was granted a ten-month extension to the Phase-I of initial term of Hisal EL, effective from 10 February 2017 to 9 December 2017. A further 11-month extension was granted from 10 March 2018 to 9 February 2019.","Misrial X-1 (PPL 65% op, Pakistan Oilfields 25%, Attock Oil 10%) in the Hisal 3372-23 EL onshore concession, P&A after it failed to flow hydrocarbons during testing.  "
62226,"It was announced on 22 October 2019 that Turkiye Petrolleri A.O. (TPAO) has been awarded the M47-A2,A4 exploration licence (Zagros Province) on 15 October 2019. The licence, covering an area of 204 sq km, is located towards southeast of the country and TPAO will be 100% owner and operator of the licence. It was earlier announced on 22 March 2019 that TPAO had filed the application on 12 March 2019 over an area around 300 sq km.","Turkey, M47-A2,A4"
33440,"Senex Energy Ltd spudded the Snatcher North 1 oil appraisal well in PRL 145, located in the Cooper-Eromanga Basin, on 3 September 2018.  On 15 October 2018 the operator suspended the well, as an oil well, after reaching a total depth of 2,627 m.  The well was drilled to appraise the Snatcher field, which was discovered in July 2009 and has been producing since December 2009.  It was the ninth appraisal well to be drilled at the field, with the most recent drilling in 2014.  PRL 145, which covers an area of 98 sq km, was awarded on 27 October 2014.  Participants in the permit are Senex Energy subsidiaries Victoria Oil Exploration (1977) Pty Ltd (40% + Operator) and Permian Oil Pty Ltd (20%), and Beach Energy subsidiaries Impress (Cooper Basin) Pty Ltd (25%) and Springfield Oil and Gas Pty Ltd (15%).","Australia, PRL 145"
41599,"Coro has agreed to acquire a 15% interest in the 911-sq km Duyung PSC, W. Natuna Sea, from West Natuna Exploration (Conrad + Empyrean-held) for USD 4.8 MM cash-and-share and a contribution of USD 10.5 MM towards 2019 drilling in the Mako gasfield.","Coro has agreed to acquire a 15% interest in the 911-sq km Duyung PSC, W. Natuna Sea, from West Natuna Exploration (Conrad + Empyrean-held) for USD 4.8 MM cash-and-share and a contribution of USD 10.5 MM towards 2019 drilling in the Mako gasfield."
12994,"SK-408, off Central Luconia, Sarawak, 3rd in 3-well programme, P+A results n/a around 19 Jan ’18, Hakuryu-11 JU. Targets Middle Miocene Cycle IV / V carbs. Sapura (op), partners Shell + Petronas.","Malaysia (Central Luconia Province) Pepulut 1 op. by SAPURA EN (40.0%, SHELL 30.0%, PETRONAS 30.0%) in SK-408 block"
11447,"On 13 December 2017, the Israeli Petroleum Commissioner and the Ministry of National Infrastructures, Energy & Water Resources (MIEWR) awarded Energean Oil & Gas five offshore exploration licences following a recommendation by the Petroleum Council. The awarded licences comprise Blocks 12, 21, 22, 23 and 31, which are located near the company's Karish and Tanin gas fields. They will be valid for an initial three-year exploration term and are extendable to a maximum period of seven years. Energean believes that the licences are highly prospective and in case a discovery is made, would benefit from being developed via tie-backs to the FPSO that the company will construct for the development of the Karish and Tanin fields.<P />The blocks have been awarded following the country's 1st Offshore Bidding Round (OBR), which was formally announced by MIEWR with a call for bids on 15 November 2016. The acreage offered had been drawn-up for competitive bidding on recommendation by the Petroleum Council and comprised 24 blocks, located close to the large gas discoveries. The blocks are up to 400 sq km in area and are in water depths of around 600-1,800m. The Council's recommendation was based on an evaluation of the Levant Basin's petroleum system by Beicip Franlab. The research had been commissioned by the MIEWR and found that at a best guess there were resources totalling around 6.6 Bbo and 75 Tcfg as-yet undiscovered in Israeli waters. These are estimated to be found in four different plays extending from the shallow margins in the east to the deep basin in the west.<P />Companies were able to bid for any number of blocks, with a bid bond of US$ 70,000 payable per block. Bids were evaluated based on the proposed work programme (90%), technical competence (5%) and signature bonus (5%). Energean operates the acreage with a 100% interest.",Not Found
31198,"Egdon is offering material equity offered for a promoted share of the well costs of an additional well at Kirkleatham in licence PEDL 068. As of September 2018, the opportunity was still available.  PEDL 068 is located in North Yorkshire and contains the Westerdale-1 and Ralph Cross-1 gas discoveries. Planning consent for the Kirkleatham Gas Field has been extended for a further seven years where a sidetrack will test up-dip Zechstein gas or deeper well to test underlying Carboniferous tight gas sands is planned. The sidetrack well is planned to be deviated and drilled to a depth of 6,890 ft (2,100 m). The COS on the well is 47%. Dry hole cost of the well is estimated at GBP 2.8 million (USD 4.5 million).     Interest in the licence is held by Egdon Resources UK Ltd (68% + operator), Dess Energy Ltd (22%) and Montrose Industries Ltd (10%).   For further information please contact:    Martin Durham    Email: Martin.Durham@egdon-resources.com",Egdon is offering material equity offered for a promoted share of the well costs of an additional well at Kirkleatham in licence PEDL 068.
52608,"On 4 July 2019, Perth (Australia)-based Pura Vida Energy (PVD) announced it had entered into a binding agreement with Gemini Resources Limited of the UK to earn a 35% stake in the 4/2018/p Gora and 5/2018/p Nowa Sol permits in southwestern Poland. As stipulated in the agreement, PVD has pledged to invest USD 6.5 million to earn the stake. Of that amount, Pura Vida will spend USD 3.9 million on a two-stage fracture stimulation and flow test of the Siciny 2 well (Gora block) and USD 2.25 million on a similar test at the Jany C1 well (Nowa Sol block). In addition, EUR 0.25 million will be transferred to Gemini Resources to ensure the right to earn the 35% interest in the assets. The planned technical works are expected to commence during the third quarter of 2019, shortly after the conclusion of the transaction.  The 700 sq km Gora block is located approximately 90 km north-west of the city of Wroclaw and some 40 km south-southeast of the city of Zielona Gora. It partly covers the country's grid blocks 245 (southeastern sector), 246 (southern part), 265 (northeastern part) and 266 (western and central parts). The 1,167 sq km Nowa Sol area is located just to the east of the city of Zielona Gora. It partly covers the country's grid blocks 224 (southern part), 244 and 245 (southwestern corner). In geological sense, the blocks are falling within the Fore-Sudetic Monocline, tectonic unit of the NE German-Polish Basin.  PVD is targeting some 1.6 Tcfg (circa 270 MMboe) of the 2C contingent resource in the Gora concession. The resource potential is related to a 1,460 m-thick section of tight Carboniferous sand-shale succession penetrated by the Siciny 2 well. In the Nova Sol block, the active group is targeting the 2C contingent resource of 36 MMbbls of oil within the Upper Permian (Zechstein) carbonate series. Additional 210 Bcfg of prospective resources is expected within multiple already identified and drill-ready conventional prospects in the Gora Licence.  Background Information  The Gora permit was initially granted on 30 June 2008 to Mazovia Energy Resources Sp. z o.o. under the designation 30/2008/p. The contract was offered for a five-year term. On 15 November 2010, San Leon Energy announced it had signed a binding agreement with Mazovia Energy Resources Sp. z o.o., subsidiary of EurEnergy Resources, for the purpose of acquiring a 100% interest in three Mazovia-operated concessions in south-western Poland (Gora, Winsko and Rawicz). On 30 September 2014, SLE relinquished the Gora permit in south-western Poland. The company released the block ahead of the official expiry date (30 December 2014) in order to be able to re-apply for the area with new contract terms. The new application was lodged with the authorities the same day, i.e. on 30 September 2014.  The Nowa Sol permit was granted initially to Liesa Investments Sp. z o.o. on 5 February 2009 for a five-year term. At the time of the award, Liesa Investments was a subsidiary of Gold Point Energy (GPE) of Canada. The latter company was acquired thereafter by San Leon Energy. On 5 February 2014, SLE secured the validity extension of the contract for additional six years. On 12 September 2014, six years ahead of the official expiry date (5 February 2020), SLE relinquished the Nowa Sol permit. The company released the block in order to re-apply for the area with the new contract terms. The new application was lodged on 30 September 2014 (the intention was to be granted the contract before the country’s new geologic and mining law, approved in mid-2014, becomes effective on 1 January 2015).  On 19 September 2017, SLE announced it has entered into definitive agreements with Gemini Resources for the purpose of divesting 100% interests in the Nowa Sol area under application. Gemini Resources paid nominal cash consideration of EUR 1 plus a 5% net profits interest on a yet to be re-awarded permit. Closing of the transaction was contingent on the approvals by the government of Poland. The deal was also adjusted for San Leon’s eventual decommissioning liabilities.  In December 2018, SLE, was granted the Gora and Nowa Sol permits in southwestern Poland. Still in December 2018, the rights to the contracts were transferred to Gemini Resources.  Targets of exploration in the Gora and Nowa Sol tracts are associated with the Permian successions, both the Rotliegend and Zechstein series. The Carboniferous succession, as well as the Lower Palaeozoic series form additional targets of exploration, related to unconventional, tight, successions.","Pura Vida has agreed a 35% farmin in the 5/2018/p Nowa Sol + 4/2018/p Gora blocks from San Leon sub Gemini Resources (->65%) for AUD6,15 MM. "
53619,"Premier has signed to take 20% stakes in the Mubadala-operated Andaman I and South Andaman blocks in the little-explored N. Sumatra Basin, offshore Aceh. Of note, the UK player operates the nearby Andaman II block.",Premier confirmed it had signed an agreement with operator Mubadala to earn a 20% interest in South Andaman and Andaman I blocks PSC split PSC.
9436,"Kenli 6-6-1 (KL 6-6-1) was suspended (results TBC) on or around 6 November 2017 after having been spudded on or around 13 October 2017 using the ""Bohai 4"" jack-up. The oil exploration well was likely targeting the Guantao, Dongying, and Shahejie formations. Kenli 6-6-1 is in the CNOOC operated Bonan Block in the offshore Bohai Gulf Basin and is approximately 1.8km E of the discovery well Kenli 6-5-1.<P />",Not Found
25156,"On 10 July 2018, a Brazilian media reported that Petroleo Brasileiro SA (Petrobras) was nearing a sale’s agreement regarding the divestment of its two large producing blocks in Nigeria, estimated to worth USD 1.3 Billion. The buyer would be a consortium led by trading company Vitol Group partnering with upstream companies Delonex and Africa Oil (part of Lundin Group), who already entered in exclusive talks with Petrobras on 18 June. Once the sale’s agreement is confirmed, the deal is not expected to be ratified by the authorities before 2019, mainly due to the current trial regarding Equinor’s stake in Agbami producing field.  The new venture Petrobras Oil & Gas BV had 16% working interest in Total-operated OML 130 (Akpo and Egina producing/developing fields), 12.49% in Chevron-operated Agbami producing field, and also 8% working interest in Chevron-operated OML 127 block.  In early May 2018, three groups of trading and upstream companies reportedly submitted bids to acquire Nigerian Petrobras stakes. Vitol’s consortium appeared as the preferred bidder, while other interested parties included Glencore (together with Nigerian company Seplat and Maurel & Prom) and Famfa Oil, together with Royal Dutch Shell.  Petroleo Brasileiro SA is looking at selling its 50% stake in Petrobras Oil & Gas BV, a new venture also composed by investment bank BTG Pactual (40%) and Helios Investment Partners (10%). This divestiture plan from Brazilian company Petrobras had already been initiated in May 2016, when Brazilian bank BTG Pactual was also looking at selling its stake in the Petrobras Oil & Gas BV joint venture. Since 2013, Petrobras Oil & Gas BV joint venture relinquished assets in Angola, Benin, Gabon, Namibia, and Tanzania.   Background information  In June 2013, Petrobras’ affiliate Petrobras International Braspetro B.V. (PIBBV) concluded a USD 1.525 billion deal with investment bank BTG Pactual for a 50% stake in its various Exploration and Production projects in Africa. The Joint venture was formed via BTG Pactual and its clients acting through the BTG Pactual Vehicle, acquiring a 50% stake in Petrobras Oil & Gas B.V (formally a 100% owned subsidiary of PIBBV). Upon conclusion of the deal the bank acquired interests in Angola, Nigeria, Libya, Benin, Gabon, Namibia and Tanzania.","On 10 July 2018, a Brazilian media reported that Petroleo Brasileiro SA (Petrobras) was nearing a sale’s agreement regarding the divestment of its two large producing blocks in Nigeria, estimated to worth USD 1.3 Billion. The buyer would be a consortium led by trading company Vitol Group partnering with upstream companies Delonex and Africa Oil (part of Lundin Group), who already entered in exclusive talks with Petrobras on 18 June."
26312,"BM-S-008 contract PAD, Santos pre-salt, WD 1,990m, PTD 6,630m, following an oil shows report to the ANP in mid-Jul ’18, Equinor’s CFO confirmed during a recent earnings call that Guanxuma is a discovery, no further information as operations are still ongoing, targets Barra Velha + Itapema fm’s, West Saturn DS. Equinor (op), partners Petrogal, Barra Energia + Queiroz Galvão.","Guanxuma-A (1-STAT-010A-SPS, Guanxuma-1) nfw BM-S-008 contract PAD, Santos pre-salt, WD 1,990m, PTD 6,630m, following an oil shows report to the ANP in mid-Jul ’18, Equinor’s CFO confirmed during a recent earnings call that Guanxuma is a discovery, no further information as operations are still ongoing, "
14595,"Lundin has agreed to acquire Fortis’ 10% stake in PL 539 + 860 and its 30% in PL 820 S + 825. It also agrees to take a further 20% again in PL 860 but from Statoil, taking its total holding to 40%. Interests-to-be:  PL 539 (Skagerrak on Danish border): MOL (op), partner Lundin  PL 820 S (adjacent to above):  MOL (op), partners Lundin + Wintershall  PL 825 (mid-SNS): Faroe (op), partners Lundin + Spirit Energy  PL 860 (Central Graben): MOL (op), partners Lundin + Petoro.","Lundin has agreed to acquire Fortis’ 10% stake in PL 539 + 860 and its 30% in PL 820 S + 825. It also agrees to take a further 20% again in PL 860 but from Statoil, taking its total holding to 40%. Interests-to-be: PL 539 (Skagerrak on Danish border): MOL (op), partner Lundin PL 820 S (adjacent to above):  MOL (op), partners Lundin + Wintershall PL 825 (mid-SNS): Faroe (op), partners Lundin + Spirit Energy PL 860 (Central Graben): MOL (op), partners Lundin + Petoro."
48400,"As of early April 2019, the Ecuador’s Ministry of Non-Renewable Natural Resources still plans to offer Blocks 20, 22 and 29 in the Subandino Bid Round – as previously reported in early October 2018. Blocks 22 and 29 were originally scheduled to be offered in the first phase of the Suroriente Bid Round, Ronda Bloque 70. A schedule has not been announced.             Block         Number of Prospects / Field         P10 (MMBO)         P90 (MMBO)         OOIP Total Swanson's Mean (MMBO)             20         1         3,800         22,174         11,392             22         6         438         234         332             29         3         81         30         54             TOTAL            4,319         22,438         11,778           Ecuador’s Secretaria de Hidrocarburos still plans the Suroriente Bid Round. The ronda will be split in two phases, The First Phase, Ronda Bloque 80, will start during the 4Q 2018 and will offer seven and not nine blocks: 80,81,82,84,85,86 & 87 and will require an investment of USD 729 for exploration and USD 1.38 billion for development – Blocks 22 and 29 were moved to the Subandino Bid Round. The Second Phase, Ronda Bloque 70, will start during 3Q 2019 and will offer seven blocks: 70,71,72, 73, 76, 77 and 78 – the investment required will be USD 285 million for exploration and USD 1.38 for development.   It appears that most of the blocks included in this round, will be the blocks which did not receive bids during the 2012-2013 Suroriente E&P Bid Round. The bidding results were underwhelming, with only four blocks out of 16 receiving offers. For the 13 blocks available to non-national oil companies (NOCs), Repsol’s subsidiary Repsol Cuba (Block 29) and the Chinese CNPC and Sinopec joint venture (JV) Andes Petroleum (Blocks 79 and 83) bid. The 16 bid blocks offered, are listed below:    Oriente (Maranon extension from Peru, Blocks 78, 79, 80, 81,      83, 84, 86 and 87),     Santiago (Blocks 28, 70, 71, 72, 73 and 77),     Napo High and Napo (Putumayo Basin extension from Colombia, Blocks 22 and 29).","the Ecuador’s Ministry of Non-Renewable Natural Resources still plans to offer Blocks 20, 22 and 29 in the Subandino Bid Round – as previously reported in early October 2018. Blocks 22 and 29 were originally scheduled to be offered in the first phase of the Suroriente Bid Round, Ronda Bloque 70."
47944,"A PSA is reportedly to be inked soon for block B2 in Jonglei State, the SA participant unreported but possibly PetroSA or Newage.","A PSA is reportedly to be inked soon for block B2 in Jonglei State, the SA participant unreported but possibly PetroSA or Newage."
35922,"Simwell is looking to dilute its 100% and transfer operatorship in P2326 / blocks 29/22b, 23b, 27 + 28,  693 sq km in the SNS, 2 leads identified, target shallow gas akin to that producing in the Netherlands. Contact elliebell@simco-pet.com.","Simwell is looking to dilute its 100% and transfer operatorship in P2326 / blocks 29/22b, 23b, 27 + 28,  693 sq km in the SNS, 2 leads identified, target shallow gas."
55918,"PRL 130, Cooper-Eromanga, 10-day well P&A on 4 Aug ’19, SLR rig 185.","Wirruna 1 nfw in PRL 130, P&A, with results awaited."
22813,"Further to DEA 17 May ’18: Prospect astride blocks N4, N7c and N8, P&A gas discovery on 13 May ’18, Prospector 1 JU. Oranje-Nassau (well op), partners Hansa HC (blk op) + EBN.","N/7-4 (Tanzaniet prospect near from Ruby disc.) (Oranje-Nassau op.30%, Hansa Hydroc. (wholly owned by Discover Exploration - 30%), Energie Beheer 40%) in block N7c, now announced gas discovery."
59539,"On 16 September 2019, the State Agency for Geology and Subsoil Use of Ukraine held an auction for the Tatalivska license in the western Ukraine. Ukrgazvydobuvannya won the contest with the offer of UAH 27.46 million (USD 1.06 million). The winner of the auction will obtain a 20-year E&P license.  The Tatalivska block covers 24.1 sq km in Chernivetska Oblast (North Carpathian Basin). Seismic coverage amounts to 70 km. Oil resources of the Tatalivska prospect are estimated at 67 MMbbl. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 26.153 million (USD 1 million).",Ukrgazvydobuvannya won the Tatalivska license in the western Ukraine.
36487,"On 13 September 2018 Zennor North Sea completed the acquisition of Verus Petroleum’s 4% interest in block 211/22a Contender Area, licence P201. The block contains the north east sector of the Cormorant field (Cormorant East / Contender). Zennor acquired First Oil’s 7.6% and Dana’s 20% interest in the block back in 2016.   The Cormorant field was discovered in September 1972 by Shell with well 211/26-1. In January 2013 Cormorant East was brought onstream just 85 days after making the discovery (originally called Contender) this is believed to be UKCS record.  Interest in the block is now held by TAQA Bratani Limited (60% + operator), Zennor North Sea Limited (31.6%) and Zennor Resources (N.I.) Limited (8.4%).","United Kingdom, P201"
44924,"On 30 November 2018, Predator Oil & Gas (Predator), through its subsidiary Predator Gas Ventures Ltd, signed a petroleum agreement covering the Guercif Onshore permit, northeast Morocco. The Guercif permit includes four blocks, located north of Sound Energy’s Tendrara permit and east of SDX’s permits. The company was awarded an exclusive licence for the permit on 30 November 2018 subject to the provision by Predator of a Bank Guarantee.  The permit includes a thirty-month initial period with commitments to reprocess 250 km of 2D seismic and to drill one well to a minimum depth of 2,000 m to test the Miocene gas layer, which is producing in the Rharb basin.    The agreement includes two possible extension periods. The first extension period will last for 36 months and will be followed by a second extension period of 30 months. During the possible extension periods the company plans to explore the deeper Triassic gas and Jurassic oil and gas.    Predator will operate the permit with a 75% interest and ONHYM will held the remaining 25%.","Predator Oil & Gas (Predator), through its subsidiary Predator Gas Ventures Ltd, signed a petroleum agreement covering the Guercif Onshore permit, northeast Morocco. The Guercif permit includes four blocks, located north of Sound Energy’s Tendrara permit and east of SDX’s permits."
67911,"Oilex Limited announced on 23 December 2019 that it has entered into a binding term sheet with Burgate Exploration and Production Ltd to acquire 100% interest in licence P2446 (blocks 113/22a and 113/27a). The acreage contains the Doyle and Peel prospects. In addition to Oilex Limited has also entered into an exclusivity agreement for the potential acquisition of 100% interest in licence P2076 (block 113/27d) which contains the Castletown discovery. The acreage is on trend with the Rhyl and North Morecambe producing gas fields which produce from the Triassic Ormskirk sandstones.   The Doyle prospect is a tilted fault block set up against a north-south trending boundary fault of the Tynwald Fault Zone to the east. The fault is down-thrown to the east and the footwall of the Ormskirk Sandstone juxtaposes Mercia Mudstone forming a cross-fault seal. The Peel prospect is fault bounded to the east, also by the Tynwald Fault Zone with cross-seal from the Mercia Mudstone Group. To the south and south-west dykes have been emplaced which are thought to provide vertical seals. The amplitude of the Ormskirk reflector seen at Peel is similar to the Ryhl gas field so there is a possibility that this indicates gas charge.   The Castletown discovery was made with well 113/27-2 in 1988 which encountered gas in the Ormskirk sandstones, the St Bees Triassic sandstones and the Permian Collyhurst Sandstone. Recent 3D seismic indicates that the well was drilled significantly down flank of the crest and through a major fault and that a large gas accumulation may be proven up dip of 113/27-2. Oilex state that with Castletown having gas in multiple reservoirs the company will look to appraise the field with a view to develop Castletown at a later date.   Interest in the licences will be held solely by Oilex Limited once the deals are complete.","Oilex has agreed to take on P2446 (Doyle-Peel prospects) from Burgate E&P, as it has for adjacent P2076 (Castletown) from Burgate, Comtrack + Simwell Res. The licences cover 186 and 32.4km ² resp. in the Morecambe Bay."
22611,"On 22 May 2018, Vista Oil and Gas issued a press release indicated it farmed-in for a 50% working interest to three Jaguar Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V. contracts acquired in the CNH-RO2-LO2/2016 and CNH-RO2-LO3/2016 Bid Rounds.  The contracts include the 349.0 sq km CNH-RO2-L03-CS-01/2017 and 95.20 sq km CNH-RO2-L02-A10.CS/2017 contracts in the Sureste Basin to be operated by Vista and the 72.40 sq km CNH-RO2-L03-TM-01/2017 contract in the Tampico-Misantla Basin to be operated by Jaguar.  The terms of the deal reported by Vista is that it will pay Jaguar USD 27.5 million and USD 10.0 million as an investment carry.  There will also be additional unspecified contingent payments based on oil price and operational performance.  Vista reported that an independent reserves evaluation carried out for the company calculated 1P reserves of 7.2 MMboe with the producing fields on the blocks currently producing approximately 500 bo/d.  The transaction is pending formal approvals by the CNH.    On 8 December 2017, Jaguar      Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V. signed the      contract with the CNH and was granted official final awards for the CNH-RO2-L03-TM-01/2017      contract from the CNH-RO2-LO3/2016 Bid Round.  The CNH-RO2-L03-TM-01/2017 contract is      also known as the Area 5, TM-01 block.       Jaguar formed a separate subsidiary, Jaguar Exploracion y      Produccion 2.3, S.A.P.I. de C.V. with 100% working interest as the      official designated operating company for the block.  The 72.40 sq km CNH-RO2-L03-TM-01/2017      contract has a total financial commitment of USD 42.2 million, USD 16.1      million in work commitments including two additional wells plus the      tie-break bonus of USD 26.10 million.  On 12 July 2017 Jaguar      Exploracion was the high bidder in the CNH-RO2-LO3/2016 Bid Round for the      Area 5 block in the Tampico-Misantla Basin and was granted a preliminary      award.  For      the 72.40 sq km Area 5 block Jaguar offered the maximum additional      royalties of 40% and 1.5 work unit factor equivalent to two additional      wells.  There were seven other bids      for the block and six offered the same royalties and work units so ended      in a tie.   Jaguar won the tie break      with a bonus bid of USD 26.1 million beating the 2nd      place bonus offer from DEP PYG who offered a bonus of USD 5.002 million.  Jaguar has 100%      working interest in the contract.     On 8 December 2017, Jaguar      Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V. signed the      contracts with the CNH and was granted official final awards for the CNH-RO2-L03-CS-01/2017      and CNH-RO2-L03-CS-06/2017 contracts from the CNH-RO2-LO3/2016 Bid      Round.  The CNH-RO2-L03-CS-01/2017      contract is also known as the Area 9, CS-01 block.  The CNH-RO2-L03-CS-06/2017 contract is      also known as the Area 14, CS-06 block.       Jaguar formed a separate subsidiary, Jaguar Exploracion y      Produccion 2.3, S.A.P.I. de C.V. with 100% working interest as the      official designated operating company for the blocks.  The 95.20 sq km CNH-RO2-L03-CS-01/2017      contract has a total financial commitment of USD 66.19 million, USD 37.3      million in work commitments including two additional wells plus the      tie-break bonus of USD 28.89 million.       The 148.20 sq km CNH-RO2-L03-CS-06/2017 contract has a total      financial commitment of USD 33.4 million all for work commitments      including two additional wells.  On      12 July 2017, Jaguar Exploracion was the high bidder in the      CNH-RO2-LO3/2016 Bid Round for the Area 9 and Area 14 blocks in the      Sureste Basin and was granted preliminary awards.  For the 95.20 sq km CS-01, Area 9 block      there were eight other bids with seven offering the maximum additional      royalties and work units factor.  Jaguar      offered the maximum additional royalties of 40% and 1.5 work unit factor      equivalent to two additional wells.       It won the tie-break for the block with a bonus offer of USD 28.89      million after the second highest bid by Promotora y Operadora, and      Consorcio 5M offered a bonus of USD 10.12 million.   The Area 9 block was the most contested      in the bid round.  For the 148.20 sq      km Area 14 block there were three bids.       Jaguar offered the maximum additional royalties of 40% and 1.5 work      unit factor equivalent to two additional wells.  It beat the second-place bid from      Perseus who offered 40% additional royalties but only 1.0 work units factor      or one well.  Jaguar has 100% working      interest in the contracts.     On 8 December 2017, the      consortium of Sun God Energia de Mexico, S.A. de C.V. / Jaguar Exploracion      Y Produccion De Hidrocarburos, S.A.P.I. de C.V. signed the contract with      the CNH and was granted an official final award for the CNH-RO2-L02-A10.CS/2017 contract from the      CNH-RO2-LO2/2016 Bid Round.  The      CNH-RO2-L02-A10.CS/2017 contract is also known as the Area 4 block.  The consortium formed a separate      subsidiary, Pantera Exploracion y Produccion 2.2, S.A.P.I. de C.V. with      100% working interest as the official designated operating company for the      block.  The 349 sq km      CNH-RO2-L02-A10.CS/2017 contract has a total financial commitment of USD      24.7 million, all for work commitments that includes two extra wells. On      12 July 2017, the consortium of Sun God Energy and Jaguar Exploracion was      the high bidder in the CNH-RO2-LO2/2016 Bid Round for the Area 10 block in      the Sureste Basin and was granted a preliminary award.  For the 349.00 sq km Area 10 block there      was one other bid.  The Sun God      consortium offered the maximum additional royalties of 25% and 1.5 work      unit factor equivalent to two additional wells.  It won the block after the second      highest bid by Perseus Exploracion was for 8.88% additional royalties and      0.0 work units or no wells.    The general license contract      terms include a 1st exploration period of two years with the possibility      of a two-year extension.  In the      case of a discovery the operator can request a two-year evaluation phase      for oil and a three-year evaluation phase for non-associated gas      discoveries once the evaluation plan is approved.  The total contract term is for 30 years      with the possibility of two five year extensions for a 40-year total      contract term from signature date. The base royalty rate is a sliding      scale royalty depending on type of hydrocarbon and oil price.  The values for oil range from 5% for USD      40/bbl oil to 25% for USD 200/bbl oil.       The relinquishment schedule is tied to exploration well      commitments.  If the exploration period      ends but the operator offers to drill an additional well it doesn’t have      to relinquish any area.  If the      exploration period ends and the contractor doesn’t have any discoveries it      must relinquish 100%.  If the      exploration period ends and the operator doesn’t offer to drill an      additional exploration well it will have to relinquish 50% of the      area.  Local content during the      exploration period is 26% for the exploration and evaluation period, and      varies from 27% to 38% in the development period.","Vista Oil and Gas issued a press release indicated it farmed-in for a 50% working interest to three Jaguar Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V. contracts acquired in the CNH-RO2-LO2/2016 and CNH-RO2-LO3/2016 Bid Rounds.  "
31146,"PEMEX suspended with results unreported the Kili 1EXP new-field wildcat (NFW) in the AE-0109-Cinturon Subsalino-13 entitlement during late-September 2018.      The NFW was spudded on 26 August 2018.   The CNH granted the operator a permit for the NFW on 6 August 2018.       The      NFW had a proposed total depth (PTD) of 2,530 m and was targeting the      Lower Miocene on a salt related anticlinal structure.     PEMEX      utilized the “La Muralla IV” S/S to drill the well in a water      depth of 825 m.         Estimated      well costs for the NFW was USD 72.57 million.    It is      located approximately 20 km south southwest of the Vespa 1 NFW discovery      drilled in 2013 in the northerly adjoining AE-0085 block.     On 4 May 2018, the CNH officially approved of the modified exploration plan submitted by PEMEX for the AE-0109-Cinturon Subsalino-13 entitlement.  The modified plan includes the drilling of the Kili 1EXP new-field wildcat (NFW) prospect instead of the Marentus 1EXP that was previously planned to be drilled from the original approved exploration plan in August 2017.  The Kili 1EXP is the same location as the Gallus 1EXP prospect that was previously considered an alternate prospect location.  The entitlement has only a one well commitment in the first four year exploration period.    On 16 August 2017, the CNH officially approved of the exploration plan submitted by PEMEX for the AE-0109-Cinturon Subsalino-13 entitlement.  The exploration plan approved includes one firm commitment well, the Marentus 1EXP with 173 MMboe in estimated reserves.  The Marentus 1EXP is planned to be drilled in 3rd or 4th quarter 2017.  It will have a proposed total depth (PTD) of 3,000 m and will be drilled in a water depth of 540 m.  It is located approximately 26.4 km southwest of the Vespa 1 NFW discovery drilled in 2013 in the northerly adjoining AE-0085 block.  The Marentus 1EXP NFW is targeting the Lower Miocene on a salt induced anticlinal structure.  Estimated well costs for the NFW is USD 71.78 million.  PEMEX has a second prospect named the Gallus 1EXP with 102 MMboe in estimated reserves but it is not a commitment well.   Other firm commitments include three geological studies already completed in 2016 and three studies in 2017 and two studies in 2018.  There are no seismic or processing commitments.      During mid-June 2016, the CNH reported that PEMEX was granted the AE-0109 block, AE-0109-Cinturon Subsalino-13 entitlement on 25 January 2016.  The block is located in the Deep Water Gulf of Mexico Basin, Mexican Ridges Province.  The block covers an official area of 915.476 sq km adjacent and to the south of the AE-0085 block where the Vespa 1 oil and gas discovery is located on the border of the two blocks.  The CNH granted approval for the PEMEX request for the entitlement on 10 August 2015 and it took SENER six months to grant formal approval. This represents one of two exploration entitlements awarded outside of Ronda 0 on 27 August 2014.  This entitlement is also different in that it grants PEMEX a total term of 35 years instead of the 25 years of the Ronda 0 entitlements.  It also includes a four year exploration period with a possible three year extension period.    PEMEX is assumed to have requested the block due to the Vespa 1 discovery that is located on the southern border of the AE-0085 block.      In late November 2013 the Comision Nacional de Hidrocarburos (CNH) reported that PEMEX’s Vespa 1 new-field wildcat (NFW) well was completed on 31 October 2013 as an oil and gas producer from the Middle Miocene interval between 2,874-2,921 m. This NFW is located in the Mexican Ridges Province of the Gulf of Mexico. It was spudded on 24 August 2013 in 777 m of water.  The well reached a final total depth (TD) of 3,418 m.",Mexico (Sigsbee Sub-basin (DWGoM B.)) Vespa 1
6676,"Anadarko acquired 22% equity from 15 contiguous North Slope leases (ADLs 390672-390677, 390679, 391015-391016 & 391914-391919,) previously 100%-owned ConocoPhillips leases.","Anadarko acquired 22% equity from 15 contiguous North Slope leases (ADLs 390672-390677, 390679, 391015-391016 & 391914-391919,) previously 100%-owned ConocoPhillips leases."
61300,"P1330, Silverpit Platform, WD ca. 15m, 73m gas zone in the Leman sands, net-to-gross ratio 71%, 16% porosity, gas saturation 82%, GWC encountered. To be suspended as a future producer, Valaris 123 JU. Premier (op), partner Dana Petr.","42/28d-14 (Tolmount East) pos. appr. (Premier op. 50%, Dana Petr. 50%) in P1330, Silverpit Platform, 73m gas zone in the Leman sands, net-to-gross ratio 71%, 16% porosity, gas saturation 82%, GWC encountered. To be suspended as a future producer, WD ca. 15m."
68814,"Total assigned 10% from its 60% stake in North Sea licence PL785 S to partner Equinor, on 20 December 2019. PL785 S covers Jurassic and older stratigraphies over 621.7 sq km on 26/2 and 31/11. It was awarded on 6 February 2015 in APA 2014 with partners electing to drill from a drill or drop decision on 6 February 2019, and a well due within two years. The acreage is undrilled, and lies 90km from the Norwegian coast and 40 km S of the Troll Field. Fortis Petroleum exited PL785 S assigning 40% to Equinor (then Statoil), on 23 April 2018. PL785 S partners are Total E&P Norge AS (50% + Op) and Equinor Energy AS (50%).<P />","Total assigned 10% from its 60% stake in North Sea licence PL785 S to partner Equinor, on 20 December 2019. PL785 S covers Jurassic and older stratigraphies over 621.7 sq km on 26/2 and 31/11."
71804,"On 3 November 2019, CC Energy Development S.A.L. (Oman) Ltd (CCED) spudded the Yamin 1 exploration well in Block 4 (Ghunaim). The well completed drilling operations in in mid-November 2019 after reaching a TD of 1,560 m in the Proterozoic Masirah Bay Formation. CCED is continuing to evaluate the well results however, according to the Q4 2020 report of partner Tethys Oil AB, the well encountered oil shows whilst drilling but failed to flow oil to surface on testing. The well was designed to evaluate the Proterozoic Khufai formation. CCED operate Block 3 (Afar) and Block 4 (Ghunaim) with a 50% interest, the remaining interests are held by Tethys Oil (30%) and Mitsui E&P Middle East B.V. (20%).","Yamin 1 nfw. (CCED 50% op, Tethys Oil 30%, Mitsui 20%) in Block 04 (Ghunaim), TD=1560m (Proterozoic Masirah Bay Fm.) in Nov '19, results now under evaluation. "
30893,"Bunbury Energy Pty Ltd is offering a farm-in opportunity for its 100% owned exploration licence EP 496, located in the Bunbury Trough, Perth Basin. Bunbury Energy was awarded the permit on 9 October 2017, which covers previously un-licenced acreage in the basin. The equity available is open to discussion with interested parties, in return for assistance with the forthcoming exploration work programme. Operatorship is also available but will be offered based on the expertise and experience of the interested Farminee.   The first well in the permit area is scheduled for permit term four, with a second in permit term six at a cost of AUD 5 million per well. Due to the lack of data available, no prospects or leads have been identified. However, Bunbury Energy has reviewed the geology and likely targets, placing both as analogous to the Whicher Range gas field that was discovered in 1968. Under the permit award terms, no hydraulic fracturing is permitted after a ban was introduced in September 2017. However, as with the Whicher Range field, which saw five failed attempts to fracture stimulate the Willespie Formation, Bunbury Energy anticipates that the clays of the Willespie Formation (around 16%) would inhibit the process and will only consider conventional exploration within the permit.  Approximately 70 km of vintage 2D seismic data has been acquired within the permit along single lines following main roads and not in any conventional survey configuration. New surveys will again run along existing roads. Bunbury Energy already has permission from Main Roads Western Australia to conduct the surveys and the environmental planning is being finalised.  In May and September 2018, Bunbury made changes to the conditions of the first two year work programmes by introducing a six month suspension and deferring planed 2D seismic acquisition. The deferred seismic incorporated into the term two increasing the planned 50 km to 200 km 2D seismic data acquisition. The seismic survey is planned to be conducted primarily along public roads and rights-of-ways using up to four vibrator trucks. A community engagement period before data acquisition is planned to deal with public enquiries and provide education on seismic surveying. Once the seismic has been acquired, processed and interpreted, Bunbury will assess the remaining work commitments and plans for future exploration within the permit area.  EP 496 covers an area of 669 sq km and was initially applied for as application STP-EPA-0132 on 15 May 2015. The permit has been awarded for a period of six years and it will expire, or be eligible for renewal, on 8 October 2023. Bunbury Energy Pty Ltd is seeking a farm-in partner to explore the new acreage of the Perth Basin which lies 25 km to the north-northeast of the CalEnergy Resources operated Whicher Range field.   Companies interested in pursuing this opportunity should contact:  Wal Muir, CEO   Email: wmuir@bunburyenergy.com.au   Tel: +61 (0) 4 1305 2327","Bunbury Energy Pty Ltd is offering a farm-in opportunity for its 100% owned exploration licence EP 496, located in the Bunbury Trough, Perth Basin. "
75937,"SE part of SEAL-T-291, Sergipe-Alagoas onshore, believed P&A dry mid-Mar '20. PTD was 450m, target Serraria fm. Nova (op), partner Petrobras.","1-NOVA-2 (1-NOVA-003-AL) nfw. (Nova 50% op, Petrobras 50%) in SE part of SEAL-T-291, onshore block, believed P&A dry mid-Mar '20. PTD was 450m, target Serraria Fm.."
72111,"Elixir Energy Ltd (previous Elixir Petroleum Ltd) provided updates regarding its 2019 drilling program at the Nomgon 1 well in Nomgon IX CBM PSC on 5 February 2020. The Nomgon 1 well has reached to a TD of 491 m and wireline logging is underway. The well hit the goal and targets that the company set for this well to discovery thick gassy coal seams below 300 m. Nomgon 1 intersected total net coal of 82 m, 63 m of that is deeper than 300 m including 51 m thickest coal seam measured from section 373 – 424 m depth. Abundant gas bubbling from the recovered core was observed across the whole interval. Coal bed fractures and cleating, as critical permeability factors are visible. The vertical well also indicated syncline coal bed seams.     Nomgon 1, a new-field wildcat well, located in Nomgon IX CBM PSC in the South Gobi Basin in Mongolia, was spudded on 16 January 2020, targeting the Permian age sediment at a depth suitable for CBM extraction. The well was completed reaching a TD at 491 m in early February 2020. Following, the company will continue core test for gas content and composition, commencing logging and permeability testing. The logging and later gas desorption results will deliver more accurate figures shortly. Permeability testing results will also follow in the short term.  Elixir Energy has a two fully tested core-holes program planned in 2019 in Nomgon IX CBM PSC, with an option for a third well. The aim of the drilling program is to determine the presence and thickness of coal, gas content and composition which will be used to make a contingent resource assessment in the new year 2020.   The first well, Ugtaal – 1, was spudded on 11 November 2019 and hit a TD of 752 m on 8 December 2019. It was deeper than pre-drill prognosed TD of 600 m. Net coal thickness was confirmed by logging at about 43 m. Permeability test was successfully taken, but result was less than expectation, coal quality was also poor than expectation. Ugtaal -1 lies approximately 37 km to the North-East of the Nomgon-1 well and is situated in a different Permian sub-basin to the Nomgon -1 in the large Nomgon IX PSC block.  Nomgon-1 is the second well of the drilling program.  Elixir Energy Ltd holds 100% interests in Nomgon IX CBM PSC.  Background Information  Elixir Petroleum Limited, based in Australia, is an international oil and gas exploration company with operations in Mongolia, the United States and France. The company obtained Nomgon IX CBM PSC following acquisition of Golden Horde Limited (GOH), a privately-owned Australian company, in December 2018.   The Nomgon IX CBM PSC is the first unconventional PSC issued pursuant to the country’s updated Petroleum Law, which was passed by Parliament in 2014.Nomgon IX, which covers an area of over 7 million acres, lies adjacent to the Chinese border and is ideally placed for future gas sales into the extensive Northern China gas transmission and distribution network. In addition to Chinese gas demand, Mongolia currently has no gas production and there is a strong political desire to replace high pollution coal power and heat generation with low emission clean-burning gas fired generation. With the potential to find and develop multiple Tcf of gas from CBM, both the Mongolian and Chinese markets could be supplied with Mongolian CBM.  The PSC is located in what is considered to be one of the most prospective basins in Mongolia for CBM. The PSC surrounds one of the world’s largest producing thermal coal deposits, Tavan Tolgoi, which has an estimated resource of over 6 billion tons and produced over 14 million tons of coal in 2016. Data from wells within the Tavan Tolgoi mine indicate gas contents of up to 15 cm/t (480 cf/t) at depths of 467 m below surface which is considered high by world CBM standards and is a good indication that surrounding areas are likely to contain similar gas content levels.  Based on current assessment on The Nomgon IX prospective CBM resource, the block has Best estimate unrisked recoverable CBM gas prospective resource of 40.1 Tcf, risked best estimate recoverable CBM gas prospective resource of 7.6 Tcf.  Elixir has high graded a number of areas which it considers the most prospective for CBM within the PSC. The planned 2019 exploration program will be initially focused on these areas where, based on existing gravity data and field mapping, it is interpreted that coals may be present and be at the right depth for CBM production.","Elixir Petroleum Ltd – Nomgon 1 – Reaching drilling targets – Nomgon IX CBM PSC – South Gobi Basin, Mongolia"
27350,"On 8 August 2018 the Dutch Ministry reported it had approved the transfer of Energy06’s interest in the S3a, S3b, Q16b/c-deep, P18d, T1 and Botlek-Mass to Oranje-Nassau.  Following the deal, interest in the S3a, Q16b/c-deep, P18d, T1 and Botlek-Mass licences are now held by Oranje-Nassau BV (50%), TAQA Offshore BV (10%) and Energie Beheer Nederland BV (40%).  Interest in the S3b is also divided between Oranje-Nassau BV, TAQA Offshore BV and Energie Beheer Nederland BV but the split is not known.","Transfer of Energy06’s interest in the S3a, S3b, Q16b/c-deep, P18d, T1 and Botlek-Mass to Oranje-Nassau. Following the deal, interest in the S3a, Q16b/c-deep, P18d, T1 and Botlek-Mass licences are now held by Oranje-Nassau BV (50%), TAQA Offshore BV (10%) and Energie Beheer Nederland BV (40%). Interest in the S3b is also divided between Oranje-Nassau BV, TAQA Offshore BV and Energie Beheer Nederland BV but the split is not known."
87044,"Fumao 1HF was reported to have flow tested at an undisclosed stabilized rate of commercial gas as of mid-July 2020 with further production testing underway. Fumao 1HF was drilled to TD on 14 July 2019 and was suspended for fracture stimulation and testing in late July 2019, having intersected strong shale gas shows in the target reservoir.  The shallow pool shale gas exploration well was spudded in June 2019 to drill to a PTD of 2,530m with a 1,000m horizontal section targeting the Permian Maokou Formation with the objective of exploring a new shallow pool shale gas reservoir of the Fuling shale gas field, which had been producing from the deeper Siluiran Longmaxi Formation. Fumao 1HF is in the Sinopec operated Fuling Block in the Sichuan Basin and is geographically located in Chongqing City, Fuling County, Jiaoshi Town, Nanmu Village and used the same well site ground as the Jiaoye 1 well. <P />",Not Found
26326,"On 25 July 2018 the NPD announced that Wellesley has exited PL 248 J and transferred its remaining 10% interest to Cairn, through its subsidiary Capricorn with effect from 30 June 2018. The licence was created on 18 December 2017 after the northeasterly part of PL 248 C was split into two new licences (the second licence created was PL 248 I). PL 248 J lies to the north of Byrding. Capricorn became operator of the licence at the time by acquiring Statoil’s (now Equinor) 30% interest.  Equinor operates the Byrding field and it started production in July 2017. It has been developed using a dual-branch multilateral well drilled from the Fram H North subsea template. The wellstream is piped to Troll C for processing and from there the oil is transported to Mongstad and the gas to Kollsnes via Troll A. Byrding has recoverable reserves of 11 MMboe and is expected to have an 8-10 year life.    Following completion of the deal interest in PL 248 J is now divided between Capricorn Norge AS (60% + operator) and Petoro AS (40%).","Wellesley has exited PL 248 J and transferred its remaining 10% interest to Cairn, through its subsidiary Capricorn "
10966,"S. part of EG-06 along the Nigeria border, NW of Ophir’s Fortuna Complex in WD 1,100m, ops terminated a month ago, now confirmed oil discovery according to a govt release. Commerciality has yet to be established. West Polaris DS. Exxon (op), partner GEPetrol. Note: Avestruz = Ostrich. ",Equatorial Guinea (Niger Delta) Fortuna Complex
9073,"The Ministry of Energy and Mineral Resources (MEMR) has announced it is interest in exploring the potential of conventional and unconventional oil and gas in six open exploration blocks across Jordan. As such, MEMR is inviting qualified oil and gas companies to submit their Expression of Interest (EoI) to participate in a tender for the blocks.  The acreage being offered includes the Azraq Block, Sirhan Block, North Highlands Block, West Safawi Block, Dead Sea Block and Jafr Block. <P />Interested companies are requested to submit their EoI's via email to <A HREF=""mailto:generals@memr.gov.jo"">generals@memr.gov.jo</A>, with the subject heading ""Jordan MEMR - Oil and Gas Exploration EOI"". The deadline for the submission of the EoI is 3pm on 31 December 2017. Selected companies will be invited to receive the EoI package and further tender documents in order to prepare and submit their exploration work plan, which will be evaluated by the MEMR. Companies with an approved work plan will be eligible to sign a Memorandum of Understanding (MoU) and/or a Production Sharing Agreement (PSA). Further details are available at <A HREF=""http://memr.gov.jo/Pages/viewpage.aspx?pageID=302"">http://memr.gov.jo/Pages/viewpage.aspx?pageID=302</A>.",Not Found
25539,"BM-S-008 contract PAD, Santos pre-salt, WD 1,990m, oil shows report to ANP 13 Jul ’18. PTD 6,630m, targets Barra Velha + Itapema fm’s, West Saturn DS. Equinor (op), partners Petrogal, Barra Energia + Queiroz Galvão.","1-STAT-010A-SPS (Guanxuma-1) (Equinor 46,5% op, ExxonMobil 36,5%, Petrogal 17%) in BM-S-008, WD=1990m, oil shows report to ANP, targets Barra Velha + Itapema fm’s,"
52829,"Ref. DEA 27 Jun ’19, Parex confirms the award of 2 blocks made under Colombia’s Permanent Process of Assignment of Areas (PPAA). Parex however states it is not partnered in the blocks, which are LLA-94, 361 sq km on the S. Casanare trend, Llanos Basin, and VSM-25, 276 sq km in the Upper Magdalena and the co’s 1st block in this region. Contracts are expected to be signed in 3Q ’19.","Parex confirms the award of 2 blocks made under Colombia’s Permanent Process of Assignment of Areas (PPAA). Parex however states it is not partnered in the blocks, which are LLA-94, 361 sq km on the S. Casanare trend, Llanos Basin, and VSM-25, 276 sq km in the Upper Magdalena and the co’s 1st block in this region. Contracts are expected to be signed in 3Q ’19."
43643,"As of 5 March 2019, Accumulate Energy announced hydrocarbon shows were encountered in the primary objective on the Winx 1 new-field wildcat in oil & gas lease ADL 391720, drilling continues toward the proposed total depth of 6,500 ft (1,980 m). The leases are located to the west of the Repsol operated Horseshoe Nanushuk oil discover announce in 2017. According to company release no traces of hydrocarbons were encountered in the shallower Seabee turbidites and non-commercial oil shows were observed in an upper Nanushuk interval 4,459 – 4,530 ft (1,359 - 1,381 m), deeper horizons have yielded more encouraging results. Elevated mud gas readings and oil shows were found between 4,669 ft and 4,901 ft (1,423 m and 1,494 m) within the Nanushuk Formation, as well as in the Torok Formation at 6,053 ft (1,845 m) depth.  Accumulate spud the Winx 1 on 15 February 2019 using the Nordic-Calista Services rig 3. Surface casing will be set at approximately 2,500 ft (762 m). The primary objective of the well is the relatively shallow Cretaceous age Nanushuk Formation at around 4,800 ft (1,463 m) however the well will drill to the deeper Torok Formation as a secondary objective at approximately 6,000 ft (1,829 m).  The Winx prospect is on a block of four Great Bear Petroleum Leases in which 88 Energy Ltd., Otto Energy Ltd. and Red Emperor Ltd. acquired a collective 90 percent working interest earlier in the year. The lease terms were set to expire 30 April 2019 but were extended by the Alaska Division of Oil and Gas to 30 April 2021, contingent on the drilling of an exploration well by 30 May 2019.  The company indicated the prospect is “comprising multiple stacked objectives with a gross mean unrisked prospective resource” of 400 million barrels.",United States (Fish Creek Platform (North Slope B.)) Horseshoe
53703,"CI-40, target Albian, drilled in Q2 ’19, believed to be tight hole, results unreported, 2nd appr and tie-back to the Baobab FPSO may follow if successful. CNR (op), partners Svenska Petr + Petroci.","Kossipo-2X completed appr CI-40, target Albian, drilled in Q2 ’19, believed to be tight hole, results unreported, 2nd appr and tie-back to the Baobab FPSO may follow if successful. CNR (op), partners Svenska Petr + Petroci."
14527,"Early Feb ’18, Oranje-Nassau transferred its 24% in A15a block/field to Dyas. The 67-sq km block lies in the N. part of the country’s offshore. Petrogas (op), partners Dana Petr., Dyas + EBN.","Dyas has taken 24% interest in licence A15a from Oranje-Nassau Energie (-> 0%, Petrogas E&P 27% + Op, Dana Petr. 9%, EBN 40%)."
61167,"Rosneft submitted the sole offer for the Irkinskiy Zapadnyy block tendered yesterday in the Krasnoyarsk Kray, E. Siberia. The starting price and offer was USD 6.2MM for the 7,846 sq km block inthe Yenisey-Khatanga Basin, 7+20 year rights.",Rosneft was awarded Irkinskiy Zapadnyy block (7846km²) in Krasnoyarsk Kray (Yenisey-Khatanga Basin).
12421,"By Q4 2017, Tharwa Petroleum had drilled the East Abu Sennan Deep 1X (EAS H 1X) NFW on its East Abu Sennan PSC. The well was drilled to a TD of 2,409m using the Tanmia Petroleum ""Tanmia 1"" land rig. It is thought have a primary objective in the Jurassic. The NFW is first in a two-well campaign. <P />The 640 sq km block is located in an under-explored part of the Abu Gharadig Basin, and was awarded to Tharwa following the 2007 EGPC Big round. However a protracted delay meant that the PSC for the concession was not signed until July 2014. A 500 sq km 3D seismic survey was acquired by CGG across the block in H2 2015. Tharwa operates the concession with 100% equity. ","East Abu Sennan Deep 1X (EAS H 1X)Tharwa operates the concession with 100% equity, in East Abu Sennan PSC, The well was drilled to a TD of 2,409m using the Tanmia Petroleum ""Tanmia 1"" land rig.Results n/a"
12746,"DNO, the Norwegian oil and gas operator, has announced that its wholly-owned subsidiary DNO Norge has been awarded participation in 10 exploration licenses under Norway's Awards in Predefined Areas (APA) 2017 licensing round. Of the 10 licenses, seven are in the North Sea, one in the Norwegian Sea and two in the Barents Sea. Prior to today's announcement, DNO held interests in 11 licenses offshore Norway and the United Kingdom, of which eight are on the Norwegian Continental Shelf and three on the UK Continental Shelf. The new awards under the APA 2017 licensing round include: PL 921: Statoil Petroleum AS (operator), Petoro AS, DNO Norge AS (30%) PL 922: Spirit Energy Norge AS (operator), Maersk Oil Norway AS, VNG Norge AS, DNO Norge AS (20%) PL 923: Statoil Petroleum AS (operator), Petoro AS, Wellesley Petroleum AS, DNO Norge AS (20%) PL 924: Statoil Petroleum AS (operator), DNO Norge AS (30%) PL 926: Faroe Petroleum Norge AS (operator), Concedo ASA, DNO Norge AS (30%) PL 929: ENGIE E&P Norge AS (operator), DEA Norge AS, Pandion Energy AS, DNO Norge AS (20%) PL 931: Wellesley Petroleum AS (operator), DNO Norge AS (40%) PL 943: Statoil Petroleum AS (operator), Capricorn Norge AS, DNO Norge AS (30%) PL 951: Aker BP ASA (operator), Eni Norge AS, Concedo ASA, DNO Norge AS (20%) PL 953: Wintershall Norge AS (operator), Concedo ASA, DNO Norge AS (30%) Original article link Source: DNO ","DNO, the Norwegian oil and gas operator, has announced that its wholly-owned subsidiary DNO Norge has been awarded participation in 10 exploration licenses under Norway's Awards in Predefined Areas (APA) 2017 licensing round."
27894,"AziNor Catalyst announced on 14 June 2018 that a subsidiary of Cairn Energy has agreed to farm-in to licence P1763 (blocks 9/9d and 9/14a) taking a 25% interest. Cairn has also agreed to join AziNor for 50% of the sole risk drilling activity on Agar-Plantain. Furthermore, AziNor will retain operatorship for the proposed appraisal well and Cairn will have an option to take operatorship in the future. The deal completed on 7 August 2018.  The initial appraisal wellbore will delineate the down dip section of the Agar discovery reservoir with a sidetrack targeted to test the Plantain prospect. The target depth is 1,675 m and combined mid-case resources of 60 MMboe with significant upside of 98 MMboe are estimated. The gross well cost is USD 9.2 million (dry hole) or USD 12.8 million (success case including Plantain sidetrack). Agar has a CoS of 58%. The rig contractor has been identified and a spud date slated for Q2 2018. The success case will take 37 days to drill.   The Agar discovery is located in the Viking Graben east of Beryl field and west of the Alvheim hub. The Eocene Agar discovery was made in 2014 with well 9/14a-15A which encountered an 11 m oil-down-to in high quality Eocene Frigg Formation sands. The well was drilled by MPX which was primarily targeting the Upper Jurassic sands of the Aragon prospect. The Upper Jurassic sands were encountered in the well but was water bearing. The sands are trapped within a stratigraphic trap which was also proven by the discovery well with the reservoir package being mapped confidently on high quality 3D broadband seismic data. Through high quality seismic data and advanced quantitative interpretation techniques AziNor have significantly de-risked the Plantain prospect. If the operations are successful then development options could be tie backs to Beryl Bravo, Alvheim FPSO or a standalone FPSO.   Following completion of the deal interest in P1763 is held by Apache Beryl Limited (50% + operator), Cairn subsidiary, Nautical Petroleum Limited (25%), AziNor Catalyst Limited (12.5%) and Faroe Petroleum (12.5%) – Faroe interest is pending deal completion.","AziNor Catalyst announced on 14 June 2018 that a subsidiary of Cairn Energy has agreed to farm-in to licence P1763 (blocks 9/9d and 9/14a) taking a 25% interest. Cairn has also agreed to join AziNor for 50% of the sole risk drilling activity on Agar-Plantain. Furthermore, AziNor will retain operatorship for the proposed appraisal well and Cairn will have an option to take operatorship in the future. The "
55204,"After several years of waiting, Svenska has reportedly farmed-out equity to CNOOC’s West Africa Petroleum E&P in Sinapa block 2 and Esperanca blocks 4A + 5A, total 5,725 sq km in shelf waters.  Several prospects are identified of which Atum in block 2 and Anchova across blocks 2 & 4A. The contract is set for expiry Nov ’20 with drilling set beforehand. So far Svenska (op), partners Petroguin + FAR.","Guinea-Bissau, Block 2 (Sinapa)"
29481,"Emperor is seeking to farmout wholly-owned retention lease R3/R1,  80 sq km in the Carnarvon Basin. Equity and terms are negotiable. The lease contains the 2003 Cyrano oil discovery.","Emperor is seeking to farmout wholly-owned retention lease R3/R1,  80 sq km in the Carnarvon Basin. Equity and terms are negotiable. The lease contains the 2003 Cyrano oil discovery."
17794,"On 29 March 2018, the consortium of Petrobras with 40% working interest, ExxonMobil with 40%, and Statoil with 20%, was granted preliminary awards for the C-M-657 and C-M-709 blocks in the offshore Campos Basin through the ANP Round 15.    For      the C-M-657 block the consortium offered a bonus of USD 643.1 million and      1,075 work units.  There was one      other bid for the block.  The      consortium of Shell, Chevron, and Petrogal offered a bonus of USD 418.76      million and 1,080 work units.  For      the C-M-709 block the consortium offered a bonus of USD 453.17 million and      1,253 work units.   There was one      other bid for the block by the consortium of Shell, Chevron, and Petrogal      who offered a bonus of USD 244.19 million and 1,184 work units.    ","the consortium of Petrobras with 40% working interest, ExxonMobil with 40%, and Statoil with 20%, was granted preliminary awards for the C-M-657 and C-M-709 blocks in the offshore Campos Basin through the ANP Round 15. "
88159,"On 2 March 2020 Spirit Energy announced the proposed divestment of three licences containing the Hejre and Solsort fields to INEOS. The deal is subject to governmental approval and on 4 August 2020 INEOS confirmed that the deal is expected to close within the year. The HPHT Hejre discovery is in the 5/98 licence (blocks: 5603/24a, 5603/28b, 5604/21b and 5604/25b), which INEOS will hold 100% interest in after it acquires the 15% and 25% interest from Spirit Energy Danmark ApS and Spirit Energy Petroleum Danmark AS. The Solsort discovery is in the 4/98 and 3/09 licences (blocks: 5604/25d, 5604/26a, 5604/29a, 5604/30d, 5604/26a Solsort and 5604/30a Solsort), which INEOS will acquire 30% interest in from Spirit Energy Danmark ApS. The southeast section of the Solsort discovery extends into the neighbouring 7/89 South Arne licence which is operated by Hess. INEOS is evaluating the possible development scenarios for Solsort field with the concept select decisions expected in 2021. INEOS announced the Hejre development concept in June 2020.  The Hejre HPHT (1,011 bar and 160 degrees Celsius) oil and gas discovery was made in 2001 by the Hejre-1 well and appraised in 2004 by Hejre-2. The reservoir is in the Upper Jurassic Heno Formation at approximately 5,200 m. The previous operator (DONG) commenced development work on the field using contractors Technip France SAS, partnered by Daewoo Shipbuilding and Marine Engineering Co. Ltd (DSME) for the engineering, procurement, fabrication, hook-up and commissioning assistance of the Hejre wellhead and processing platform. A 8000-tonne jacket was installed in 2014 and five development wells were drilled between and March 2016. The field development ceased in 2016 when DONG terminated the contract for the platform after a dispute with the contractor over delays in the topside and platform. In September 2017 INEOS acquired DONG Energy and took over its 60% interest in the licence and in December 2017 Spirit Energy was formed from the merger of Centrica and Bayern Norge AS to take 40% interest in the licence.  The Solsort oil and gas field was discovered by Solsort 1 (6504/26-5) in 2010, the TD was at 3,041 m TVDSS and three sidetracks were drilled with a reach of up to 1.5 km. In 2013 the discovery was successfully appraised by Solsort 2 (5604/26-6) which tested oil and associated gas from the Paleocene Rogaland Group sandstone. Two sidetracks were drilled from Solsort 2 but both were dry.","(Central Graben Province) Spirit Energy announced the divestment to INEOS of three licences (4/98, 3/09 and 5/98 licences) containing the Hejre and Solsort fields. The deal is subject to governmental approval and INEOS confirmed that the deal is expected to close within the year. After completion, INEOS will hold 100% interest in all licences. "
9043,"On 13 November 2017 Hague and London Oil (HALO) reported that the takeover of non-operated offshore licences from Tullow was completed. Consequently HALO is a producer of more than 2,500 boe/d, having 2P reserves in excess of 12 MMboe and more than 19 MMboe in contingent resource The table below shows Tullow’s assets and its participation interest: Asset Operator Tullow’s   participation E10 ENGIE 30% E11 ENGIE 30% E14 ENGIE 30% E15c ENGIE 25% E15a Wintershall 4.69% E15b Wintershall 21.12% E18a Wintershall 17.6% F13a Wintershall 4.69% J9 NAM 9.95% K8 NAM 9.95% K11 NAM 9.95% K7 NAM 9.95% K14 NAM 9.95% K15 NAM 9.95% L13 NAM 9.95%   HALO was formed in 2012 and combined with Wessex Oil in 2014. The company’s portfolio is so far comprised of assets in the United Kingdom, Western Sahara, French Guyana and the Scattered Islands.  ","Netherlands, J9"
24987,"Pertamina is looking to sell out from the Babar Selaru PSC, the Arafura Sea, its 15% interest available in the deepwater block.  It is recalled Inpex is also looking to farmout up to 40% in the 5,713-sq km block, where it holds 85% + operatorship (DEA 3 Feb ’16).   Letters of Intent to Pertamina are invited by 20 Aug ‘18 to Andi Wisnu, Andi.Wisnu@pertamina.com and Dedi Yusmen, dedyy@pertamina.com.","Pertamina is looking to sell out from the Babar Selaru PSC, the Arafura Sea, its 15% interest available in the deepwater block.  It is recalled Inpex is also looking to farmout up to 40% in the 5,713-sq km block, where it holds 85% + operatorship (DEA 3 Feb ’16). Letters of Intent to Pertamina are invited by 20 Aug ‘18 to Andi Wisnu, Andi.Wisnu@pertamina.com and Dedi Yusmen, dedyy@pertamina.com."
50297,"As of early June 2019, industry sources have suggested that Equinor is expected to sign a deal with Sonangol for an operator interest in the Kwanza Basin Block 5/06. Very little detail is available however, in June 2018, Equinor and Sonangol E.P., signed a Memorandum of Understanding (MOU) aimed at developing greater cooperation in the areas of management, logistics, financial, scientific research, development and operations within the oil sector. The MOU included areas where Equinor would collaborate regarding exploration (Block 5/06 and Block 18/15).   Although unconfirmed, it is expected that the partnership in the block will be Equinor holding a 50% operator interest and Sonangol holding the remaining 50% stake.",Equinor is reportedly in line to sign with Sonangol for operatorship of the latter’s so far wholly-owned block 5/06 (5700km²) (presumably 50:50).
15790,"Nim 2568-9 EL, Lower Indus onshore, P&A dry at TD 2,412m late Feb ‘18, Sinopec rig 149. Target Lower Goru. OGDC (op), partner Govt Holdings.","Ganjo Takkar 1 op. by OGDC (95%, GHPL 5%) in Nim 2568-9 EL, P&A dry."
55474,"On 23 July 2019, Australia Pacific LNG Pty Ltd (APLNG) was awarded a production licence over the Reedy Creek coalbed methane (CBM) project in the Taroom Trough, Bowen-Surat Basin. Licence PL 412 covers an area of 150 sq km and is valid for a period of 30 years. The licence will expire on 22 July 2049.  The APLNG joint venture, comprising Origin Energy, ConocoPhillips and China Petrochemical Corp (Sinopec) commenced a phase of development drilling at Reedy Creek in neighbouring licence PL 404 during 2017.  The field was discovered in February 2009 and has been producing since 2014. To date, 11 CBM wells have been drilled in the PL 412 permit area, including Reedy Creek and Lucky Gully wells.  To make room for the new PL, one of the three blocks of ATP 606-P has been relinquished. The exploration permit continues to cover two areas: one between the Spring Gully and Lacerta fields and the other over the Wubagul discovery. ATP 606-P has been reduced in area by approximately 45%, from 322 to 172 sq km but once covered over 14,000 sq km upon first being awarded on 28 October 1994.  PL 412, which covers an area of 150 sq km, was awarded on 22 July 2019.  Australia Pacific LNG Pty Ltd hold 100% interest and operates the licence.","Australia Pacific LNG Pty Ltd (APLNG) was awarded a production licence over the Reedy Creek coalbed methane (CBM) project in the Taroom Trough, Bowen-Surat Basin."
45688,"Equinor spudded exploration well 7132/2-2 targeting the Gjokasen Deep prospect on 6 January 2019 in PL 857 using the “West Hercules” S/S. The top hole section was drilled and then the rig was moved off location on 14 January 2019 to complete the drilling of the Gjokasen Shallow 7132/2-1 well (see separate article). Gjokasen Deep was re-entered on 10 February 2019. 7132/2-2 is located approximately 3 km southwest of the Gjokasen Shallow well and it targeted potential recoverable reserves of 428 MMboe according to partner Lundin. It was drilled to an initial TD at 3,400 m but was later sidetracked to 3,495 m subsea in the Permian Roye Formation. Sands were proven in the Triassic Snadd Formation (25 m), Kobbe Formation (17 m), Klappmyss Formation (17 m), Upper Havert Formation (26 m) and Lower Havert Formation (110 m) but no hydrocarbons were present. The well was drilled to the extended TD after increased formation gas was identified, to investigate source rock and deeper reservoir potential,l but no reservoir was found in this section. On 2 April 2019 the well is being abandoned.   Gjokasen Deep is one of four prospects that will be drilled in the Barents Sea Southeast in 2019. The others are the Gjokasen Shallow well which was a dry hole, Equinor’s Korpfjell Deep prospect in PL 859 which lies in the north part of the region and Aker BP’s Stangnestind prospect in PL 858 which lies to the northeast of Gjokasen. All of these wells were delayed from 2018. All three licences were awarded in the 23rd Round in 2016 and the results are eagerly awaited as this area of the NCS was completely undrilled apart from Statoil’s first Korpfjell well in 2017 which was disappointing (finding gas instead of the anticipated oil).    Interest in PL 857 is held by Equinor Energy AS (40% + operator), Aker BP ASA (20%), Lundin Norway AS (20%) and Petoro AS (20%).","7132/02-02 (Gjøkåsen Deep) (Equinor 40% op, Aker BP 20%, Lundin 20%, Petoro 20%) in PL 857, contrary to earlier industry rumours the well is dry, encountered good and variable quality sst in the late Triassic and sst in the early Triassic of poor quality” but “none were hydrocarbon-bearing”. WD=304m, TD=3 495m (late Permian). "
72944,"Mid-January 2020, industry sources reported that Vegas Oil & Gas (Vegas) was looking for a partner to further explore its 2,991 sq km East Lagia block located in the onshore northern area of the Gulf of Suez within the Sinai Peninsula (Sinai Platform and Gulf of Suez Basin). Vegas holds 100% working interest in the block whose first exploration phase will expire on 21 March 2020. Vegas will enter the second phase, extending for three years, having already fulfilled financial commitments of both the first and second phases.  According to the company, the block includes significant prospect and lead inventory with potential for large prospective resources in multiple plays. The main reservoir targets are the Pre-Miocene Nubia Sandstone units in the southwest area and primarily the Intra Paleozoic Sandstone in the northern area. Multiple mature source rocks are assumed in the Eocene, Cretaceous and Paleozoic units.  The subsurface evaluation is based on 768 km of 2D seismic acquired and processed in 2019 in addition to 509 km of old 2D data reprocessed in 2019.  Location of the block in the vicinity of the Sudr and Asl producing oil fields and the GPC onshore plant is expected to reduce potential development costs.  Transaction process  Vegas intends to market up to 35% participation interest. Upon execution of a confidentiality agreement, Vegas will provide interested parties with access to further relevant information, including information in respect of the bidding process and possible access to the data room. The data room will be available from 26 January and offers are expected prior to close of business on 31 March 2020.  For further information please contact:  Ahmed Hagras, Promote Energy (Cairo, Egypt)  ahmed.hagras@promote-energy.com  Mobile: +20 122 312 7157","Vegas Oil & Gas (Vegas) was looking for a partner to further explore its 2,991 sq km East Lagia block located in the onshore northern area of the Gulf of Suez within the Sinai Peninsula (Sinai Platform and Gulf of Suez Basin). "
26653,"N. slope of Chuanzhong Uplift, Sichuan Basin, TD 8,420m reached on 24 Jun ‘18, completed with gas shows. More from GEPS.","Chuanshen 1 (Sinopec – Xinan) in completed with shows in the Permian Maokou Formation. The well reached a final TD of 8,420 m, the bottom hole temperature is as high as 200°C."
85968,"Hitherto-unreported nfw in SSJN1 block, Atlántico dept (Lower Magdalena), drilled 5-27 Nov '19, gas discovery in the Eocene Chengue fm, tested during 1H '20, results n/a. Lewis (op), partner Hocol.","(Lower Magdalena b.), Merembé-1 nfw operated by LEWIS EN (50%), ECOPETROL (50%) in SSJN 1 block, drilled 5-27 Nov '19, gas discovery in the Eocene Chengue fm, tested during 1H '20, test results n/a yet."
19518,"Committed well in Luna Muetse (E13) block, Gabon Coastal Basin offshore, WD 2,668m, 78, gross oil column, completed during 1Q ’18, assessment underway, PTD was 5,500m, West Capella DS. Repsol (op), partner Woodside.","Ivela 1 op. by  Repsol (60%, Woodside 40%) in Luna Muetse (E13) block, 78m gross oil column, assessment underway, PTD= 5500m, WD= 2668m."
84240,"Huizhou Sag, PRMB, WD 113m, TD 4,276m, completed as the first mid-to-large size o&g discovery in the shallow water area of the basin, HYSY 943 JU. More from GEPS. Of note, 3D seismic is currently being acquired in the area (ref. DEA 17 Jun '20).","(Pearl River Mouth B.) Huizhou 26-6 (Pr) 1 op. by CNOOC LTD (100%) in Xijiang 10 block, WD = 100 m, significant oil and gas discovery in the South China Sea, WD=113 m, tested 2,020 b/d of oil and 15.36 MMscf/d of gas respectively. It is expected to become the first mid-to-large sized condensate oil and gas field in the shallow water area of the basin.  "
38959,"Dyas has acquired 10% interest in PL 847 and PL 847 B from Equinor under a deal reported by the NPD on 22 December 2018, effective from 20 December 2018. PL 847 covers blocks 6706/5 and 6706/6 while PL 847 B covers part of block 6707/4. The licences are located approximately 65 km north of Aasta Hansteen with PL 847 containing the 2003 gas discovery made by 6706/6-1 and the currently operating Marisko well (67-6/6-2 S).   6706/6-1 targeted the Nise Formation Hvitveis prospect and was drilled by Esso in PL 264. It reached a TD of 3,451 m in the Paleocene and proved gas in an unnamed Paleocene reservoir. The NPD puts estimated recoverable reserves at 265 Bcfg (December 2018). At the time of discovery it was considered non-commercial due to the lack of any infrastructure in the area. However, following the start-up of Aasta Hansteen in December 2018 and the establishment of infrastructure in this area there is now the potential to export gas through the new Polarled pipeline to Nyhamna. Additional gas volumes proven by the Marisko well, spudded on 4 December 2018 and targeting the Upper Cretaceous Nise Formation (see separate article), could therefore potentially be developed in the future using the Aasta Hansteen facilities.  Following completion of the deal, the interest split in each licence is as follows: Wintershall Norge AS (40% + operator), OMV (Norge) AS (20%), Repsol Norge AS (20%), Dyas Norge AS (10%) and Equinor Energy AS (10%).",Norway (Nyk High (Voring B.)) Aasta Hansteen
50976,"ENEVA SA suspended with gas shows the 1-ENV-BL69E-MA (1-ENV-004-MA) new-field wildcat (NFW) in the PN-T-069 block during mid-June 2019 at an as yet unreported final total depth (TD).  The operator filed a gas show report with the ANP for the well on 11 June 2019.      The      NFW was spudded on 18 May 2019.      The      NFW had a proposed total depth (PTD) of 1,698 m.     The      Devonian Cabecas Formation and the Mississippian Poti Formation were the      primary targets.          The      NFW is located in the north-central area of the block approximately 42.4      north-east of the 1-OGX-101-MA plugged      and abandoned in 2012 by operator OGX.      ENEVA SA has 100% working interest in the ANP Round 13, 3,066.97 sq km, PN-T-069 contract awarded on 23 December 2015.","1-ENV-BL69E-MA (1-ENV-004-MA) NFW (Eneva 100%) in the PN-T-069 block, suspended with gas shows."
78267,"In early 2020, Octant Energy confirmed it is looking for a farm-in partner for the Block L17/L18. The company is offering interest in the licence in return for a commitment to fund an exploration well prior the end of the current term which is valid until 23 April 2021.   Several leads and prospects were identified by a 1,000 sq km 3D seismic survey. Access to the data room can be made available after execution of a confidentiality agreement.  Interest in the licence is solely held by Octant Energy Corp.  Contacts:  Rick Schmitt – rick.schmitt@octantenergy.com  Richard Higgins – rhiggins@havocpartners.com",Octant Energy confirmed it is looking for a farm-in partner for the Block L17/L18. The company is offering interest in the licence in return for a commitment to fund an exploration well prior the end of the current term which is valid until 23 April 2021. 
42367,"Faroe spudded appraisal well 31/7-3 S at Brasse East in PL 740 on 20 November 2018 using the “Transocean Arctic” S/S. It was targeting potential recoverable reserves of 12.5 MMboe in a separate structure to the east of Brasse, identified following recent seismic reprocessing and re-interpretation work. The well reached TD at 2,705 m (2,273 m TVDSS) in the Fensfjord Formation and is a dry hole. Water-wet sands were encountered in the Sognefjord Formation (45 m net thickness) with excellent reservoir quality. On 17 December 2018 sidetrack 31/7-3 A was kicked off targeting incremental reserves of 61 MMboe in the northern part of the main Brasse reservoir. The well reached TD at 2,863 m (2,254 m TVDSS) in the Fensfjord Formation and encountered oil and gas. It confirmed a 15 m gas column and a 47 m oil column in the Sognefjord Formation, however the net reservoir thickness is only 12 m (75 m gross) and reservoir quality is poor to moderate. The OWC is 20 m deeper than in the central and southern parts of the field. Reserves for Brasse will be updated in due course. On 18 January 2019 the well was abandoned.  Brasse discovery well 31/7-1 was drilled in 2016 and proved a 21 m oil column plus an 18 m gas column in the Jurassic Fensfjord Formation. Sidetrack 31/7-1 A was drilled to appraise the southeastern part of the discovery and confirmed oil and gas columns of 25 m and 6 m respectively. In 2017 Faroe appraised the find with 31/7-2 S, which confirmed a 9 m oil column in the Sognefjord Formation and on test flowed at a maximum rate of 6,187 bo/d through a 1” choke from a 3.6 m perforated interval, and 31/7-2 A which proved an 18 m oil column plus a 4 m gas column. Both wells have the same OWC as the discovery well (2,172 m), although 31/7-2 A has a deeper GOC (2,154 m), and there is good pressure communication between all wells. Reserves have been upgraded from 43-80 MMboe to 56-92 MMboe (46-76 MMbo plus 59-97 Bcfg).   Faroe is progressing plans for development as a subsea tie-back to either Brage or Oseberg and envisages 3 - 6 production wells plus a potential water injector. It believes that it could achieve a rate of 30,000 boe/d with first oil in 2021 / 2022. Capex is forecast at USD 500-700 million (based on four wells and one subsea template) and the final concept selection will take place in 2018 with PDO submission likely in 2019.    Interest in PL 740 is divided between Faroe Petroleum Norge AS (50% + operator) and Var Energi AS (50%).","Faroe Petroleum plc PL 740 - 31/7-3 S (Brasse East), 31/7-3 A (Brasse) appraisal wells - Abandoned, dry hole and oil and gas appraisal"
14278,"In February 2017, Surgutneftegaz completed testing of a new exploratory well at the Vysotnoye license in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Vysotnaya 885, spudded in November 2016, reached its TD of 2,632 m in January 2017. In February, the company reported a new pool in the Vikulov Formation (Aptian) after testing oil at a rate of 138 b/d from the interval 1,570-1,574 m (VK1).  Vysotnoye, discovered in 2009, is located in the central part of the Ural-Frolov Province. As of 2016, 3P reserves of three pools, distributed within the Middle-Upper Jurassic section, were estimated at 35 MMbbl.   ","Surgutneftegaz completed testing of a new exploratory well at the Vysotnoye license,  a new pool in the Vikulov Formation (Aptian) after testing oil at a rate of 138 b/d from the interval 1,570-1,574 m (VK1)."
79285,"Coastal Oil & Gas Pty Ltd has acquired 100% interest in exploration blocks TP/27, EP 475, EP 490 & EP 491 from a Skye Energy Ventures subsidiary company Tanami Energy Pty Ltd. The deal was completed on 27 September 2019 for the consideration of approximately AUD 1.2 million and gives new player Coastal Oil and Gas full control of the 'Cerberus' blocks, located in the Enderby Terrace and Peedamullah Shelf, North Carnarvon Basin.  EP 475, EP 490 and EP 491 cover areas of 651 sq km, 1,405 sq km and 1,441 sq km respectively, and TP/27 covers 335 sq km. All four permits are now held 100% by Coastal Oil & Gas. Tanami Energy had picked up the acreage from Carnarvon Petroleum in 2018 after the company was searching for a farm-in partner in return for funding exploration activities. The new operator is also seeking a farm-in partner as it looks to complete the remaining work programmes and prove up existing and new prospects.  Under the remaining work commitments, an ambitious seven exploration wells are required before the permits expire. EP 475 was awarded in 2011 and is due to expire on 27 May 2021. EP 490 & 491, and TP/27 were awarded in 2014 and are due to expire on 27 May 2023. For the latter permits, Carnarvon Petroleum had been granted several suspensions to provide additional time in the permits to find a farm-in partner. As of May 2018, the wells were contingent upon Carnarvon entering the fourth term of the permits prior to undertaking the drilling programmes. The fourth term commenced on 28 May 2020.   The areas have significant 2D and 3D seismic data coverage and are located in shallow water depths, of around 50 m. Primary target depths range from 1,000 to 2,000 m, comprising multiple play types, including a Jurassic play and an evolving play in the Permian and Triassic, which was proven following success in the Roebuck Basin at Phoenix South, Roc and Dorado.   Coastal Oil & Gas Pty Ltd acquired four exploration permits from Tanami Energy Pty Ltd on 27 September 2019, which cover around 3,200 sq km in the North Carnarvon Basin. Coastal Oil & Gas now hold 100% interest in TP/27, EP 475, EP 490 & EP 491.","Coastal Oil & Gas Pty Ltd has acquired 100% interest in exploration blocks TP/27, EP 475, EP 490 & EP 491 from a Skye Energy Ventures subsidiary company Tanami Energy Pty Ltd."
69949,"N. part of Chauk field area in IOR-2 block, Central Burma Basin, ops terminated mid-Jan '20, results n/a, ZJ 450 rig. PTD was ca. 1,500m, target L-M Oligocene Shwezetaw fm.","Shwezettaw 1 nfw (Goldpetrol 100%) N. part of Chauk field area in IOR-2 block, ops terminated, results n/a, PTD was ca. 1,500m, target L-M Oligocene Shwezetaw fm."
68012,"On 27 December 2019, the Federal Agency for Subsoil Use held an auction for the Bukharinskiy block of the State Significance in Yamalo-Nenets Autonomous Okrug (Western Siberia). Novatek-subsidiary Arctic LNG 1 won the contest with the offer of RUB 2,346 million (USD 37.8 million). Ownership of licenses in the region and possession of existing or planned LNG facilities were the pre-conditions for applicants. Only Novatek meets the requirements. The winner of the auction will receive a 30-year license with a 10-year exploratory stage.   The Bukharinskiy block covers 2,447 sq km including 1,608 sq km in the south-western part of the Gydan Peninsula and 839 sq km in the Ob and Taz estuaries (South Kara-Yamal Province). It encompasses the Bukharinskaya prospect with D0 resources estimated at 33.464 Tcf of gas and 237 MMbbl of condensate. Hydrocarbon resources (categories D1+D2) of the block are estimated at 7.292 Tcf of gas and 351 MMbbl of condensate. The starting price amounted to RUB 2,133.2 million (USD 34.4 million).","Novatek won the 2,447-sq km Bukharinskiy block (of state significance) in the Gydan peninsular area (Ob and Taz bays), Yamal-Nenets AO, W. Siberia."
24245,"Block 45, Guyana Deepsea Basin, P&A dry at TD 4,556m on 26 Jun ’18, Ensco DS-12 off to drill Pontoenoe-1 nfw in block 42. Target L. Cret., Kosmos (op), partner Chevron (op in case of commercial discovery).","Anapai 1A (Kosmos 50% op, Chevron 50%) in Block 45, encountered high quality reservoir, it did not encounter any hydrocarbons and the decision was made to plug and abandon the well (was a similar play type to the Turbot and Longtail discoveries which lie roughly 70 kilometres to the west in Guyana). TD=4556m."
45197,"Talimarzhan field, Kultak-Kamashi investment block in the Amu-Darya Basin, tested 6.85 MMcfg/d in mid-Mar ’19, acidisation is hoped to boost flow to 12 MMcf/d.","Talimarzhan 2, (Centrex Europe Energy & Gas, GAZPROM , UZBEKNEFTEGAZ ) in Talimarzhan field, Kultak-Kamashi investment block, tested 6,85 MMcfg/d, acidisation is hoped to boost flow to 12 MMcf/d."
42426,"On 10 February 2019, at the India Petrotech event 2019, Indian Government, launched the third round of Open Acreage Licensing Programme (OALP-III). Of the offered 23 blocks, three blocks are located in the Assam Shelf and two blocks are located in Assam-Arakan fold belt (Tripura-Cachar Basin).     At the event, the Directorate General of Hydrocarbons (DGH) issued the Notice Inviting Offers (NIO) and Model Revenue Sharing Contract (MRSC) for OALP-III, offering a total of 23 blocks, including 14 onshore, three shallow water, one deepwater and five coalbed methane (CBM) blocks, covering a combined area of around 31,700 sq km. Bidders were invited to submit their bids via the e-bidding portal from 11 February 2019, until the bid closing deadline on 10 April 2019. It is understood that of the 23 blocks offered, five CBM blocks have been carved out by the Directorate General of Hydrocarbons (DGH).   The Assam Shelf and Assam-Arakan Basin covers onshore area of around 136,825 sq km, consisting Assam Shelf of around 56,000 sq km and Assam-Arakan fold belt (Tripura Cachar Basin) of around 80,825 sq km. It is understood from DGH that the Assam Shelf has discovered resources of around 1,868.4 MMtoe and undiscovered resources of around 4,132.8 MMtoe, whereas the fold belt region has discovered resources of around 178 MMtoe and undiscovered resources of around 1,454.8 MMtoe. The Assam Shelf and Assam-Arakan Basin is a proven basin. As of February 2019, it is understood from DGH report that so far around 1,308 exploration wells have been drilled in the basin, with several commercial oil and gas discoveries and more than 100 oil and gas fields. Around 69,771.9 km 2D and 15,137.26 sq km 3D seismic data has been acquired in the basin.    Offered two blocks are in Tripura-Cachar Basin while three blocks are located in Assam Shelf-Schuppen belt. Oligocene to Pliocene are the resource plays in fold belt region, while Assam Shelf has resource plays from Paleocene to Pliocene.     The table below lists the details of five blocks on offer under OALP-III in Assam Shelf and Tripura-Cachar Basin:           Block name         Approx. area    (sq km)         Target depth for wells   to be drilled (m)         Minimum net worth   requirement    (USD million)         Requisite bid bond    (USD)         Block history                 Onshore                                Assam Shelf                                AA-ONHP-2018/1         248.87         1,500         5.00         121,500         133.94 km 2D, 69.96 sq km 3D seismic data and   3 wells drilled                  AA-ONHP-2018/2         2,526.74         1,500         12.20         1,000,000         1 well drilled                  AA-ONHP-2018/3         1,234.42         2,000         7.99         598,500         407.45 km 2D seismic data                 Tripura-Cachar                                AA-ONHP-2018/4         44.01         3,000         5.00         21,000         107.58 km 2D seismic data                 AA-ONHP-2018/5         207.74         2,500         5.00         99,000         105.51 km 2D seismic data                 Source: DGH,   India         ©   2019 IHS Markit                                           For more details on bidding terms and conditions for OALP-III, please refer to main OALP-III bidding article in GEPS.    https://pgeps.ihsenergy.com/GEPS/Display/c08aaae4-1e04-4685-9bd7-5fc853b25dcd","On 10 February 2019, at the India Petrotech event 2019, Indian Government, launched the third round of Open Acreage Licensing Programme (OALP-III). Of the offered 23 blocks, three blocks are located in the Assam Shelf and two blocks are located in Assam-Arakan fold belt (Tripura-Cachar Basin).    At the event, the Directorate General of Hydrocarbons (DGH) issued the Notice Inviting Offers (NIO) and Model Revenue Sharing Contract (MRSC) for OALP-III, offering a total of 23 blocks, including 14 onshore, three shallow water, one deepwater and five coalbed methane (CBM) blocks, covering a combined area of around 31,700 sq km. Bidders were invited to submit their bids via the e-bidding portal from 11 February 2019, until the bid closing deadline on 10 April 2019. It is understood that of the 23 blocks offered, five CBM blocks have been carved out by the Directorate General of Hydrocarbons (DGH). The Assam Shelf and Assam-Arakan Basin covers onshore area of around 136,825 sq km, consisting Assam Shelf of around 56,000 sq km and Assam-Arakan fold belt (Tripura Cachar Basin) of around 80,825 sq km."
38366,"Global MED secured in Dec ’18  6-year rights to F.R 43.GM,  730 sq km in the Ionian sea adjacent to the company’s F.R 41.GM + F.R 42.GM granted a year earlier. Plans include 676km of 2D seismic over the 3 blocks, later 3D seismic + 1 explo well if warranted.",Global MED was awarded the F.R43.GM (Sibari-Crotone B.) and F.R 44.GM and F.R 45.GM offshore exploration permits in Ionian Sea for six years. 
48998,"Nanggroe Aceh Darussalam 2 PPC in N. Sumatra, P&A believed dry Mar ‘19, PDSI N110/59 rig. PTD was 2,125m, target M-U Miocene Besitang River sst.","Radiatus Madu-1 (RDM) nfw Nanggroe Aceh Darussalam 2 PPC in N. Sumatra, P&A believed dry,PTD was 2,125m, target M-U Miocene Besitang River sst."
64665,"PTTEP is believed to have plugged and abandoned wildcat Pundarika 1 located in the western part of block M-09, Moattama Basin, in early November 2019, with results unreported.  The well, spudded around late September 2019, was drilled using the ""Noble Clyde Boudreaux"" S/S. Possible drilling targets may include Pliocene sandstones of the Moattama Series and Oligo-Miocene carbonates of the Burman Limestone.  Pundarika 1 is the first of three exploration wells planned to be drilled in the ""M9 west"" area between late 2019 and early 2020. The planned TD for the wells could be approximately 3,000-3,500 m TVDSS. The other wells in the programme are Aungpyitan 1 and Uppala 1.  The ""Noble Clyde Boudreaux"" has been operating for PTTEP since late 2018 to conduct an appraisal drilling campaign in the central and eastern part of block M-09 (Zawtika field area) and exploration drilling in block M-11. The latter activity consisted of wildcat Pyae Wa Chan Thar 1. The well was plugged and abandoned in June 2019 as dry.  PTTEP is operator of block M-09 with 80% interest, while MOGE holds the remaining 20%. The adjacent exploration block M-11 to the south is operated by PTTEP with 100% interest.  Background Information  The last exploration well in the western part of block M-09 was Bawga Siddhi 1. The well was plugged and abandoned in September 2010. The well experienced abnormal over pressured zone and gas influx in the wellbore which caused the operator to terminate drilling at 3,052 m, shallower than the PTD of 4,089 m, due to safety reasons. The well failed to reach its drilling objectives but the operator confirmed the presence of net pay, 19 m of gas bearing sandstone above the not-reached objectives.    PTTEP reported that the Zawtika Project commenced gas production for the domestic market on 14 March 2014, with initial sales rate of 40 MMscfg/d and planned peak of 100 MMcfg/d. Domestic gas is used for power generation.  Gas export to Thailand commenced on 5 August 2014. Production gradually ramped up to the daily contract quantity of 240 MMscfg/d as stipulated in the Gas Sales Agreement with buyer PTT.  Due to the highly faulted structures, numerous platforms and wells are required to develop the Zawtika and nearby fields. The initial phase of the Zawtika project (Phase 1A) consisted of three wellhead platforms (ZWP1, ZWP2 and ZWP3, located in the Shwepyihtay, Kakonna and Zawtika fields respectively) and one integrated central processing/living quarter’s platform (ZPQ). Further development phases will be necessary in order to maintain the stipulated production plateau.","Pundarika 1 nfw (PTTEP 80% op, MOGE 20%) in W. part of block M-09 (Zawtika), 1st in 3 wells planned, P&A results n/a. "
74941,"As announced on 12 March 2020, Pan Orient plugged and abandoned the third exploration well under Phase 2 drilling program, L53 AA1 and its sidetrack (L53 AA1ST1) in the L53/48 Reserve Area A, onshore Chao Phraya Basin, as dry wells. Spudded on 25 February 2020, the L53 AA1 well was targeting a structural closure located approximately 1.2 km south up-dip of the previously drilled L53 AA2 well. The sidetrack well was targeting a separate and up dip structural closure west of the L53 AA2 exploration well.  Following the well abandonment, the ""E-05"" land rig will be demobilized and the drilling campaign is expected to resume in the second half of April 2020, utilizing a new drilling rig with a substantially reduced day rate. The operator is planning to start with a water disposal well at the L53 DD well pad, followed by resumption of drilling of the L53-BB1 well. Another exploration well, L53 AC-E, will be targeting the West A1-A4 prospect fault compartments with Kamphaeng Saen area. Two additional appraisal wells will complete the drilling program.    The eastern side of the AA prospect was earlier tested by the L53 DD6ST1 well, encountering 5 m of net oil sand within the targeted CC sand. Located on the west fault block of the producing L53 DD field, the AA and AA North prospects have structural closure areas of 0.69 and 0.27 sq km, respectively. Both wells were drilled from the same AA well pad.   L53-BB1 was originally spudded on 4 February 2020 but it was suspended after three days of drilling in order to reinforce the well pad.  Commenced on 25 January 2020, Phase 2 exploration drilling program consists of three appraisal wells and five exploration wells (including sidetracks), focusing on accessing the upside potential within the L53 DD oil discovery. The drilling campaign was previously planned to be commenced in Q4 2019.  The earlier Phase 1 exploration drilling program in the concession was completed on 27 August 2019, resulting in two discoveries in the L53 DD5ST1 and L53 DD6ST1 wells. The wells were suspended prior to receiving approvals from the Department of Mineral Fuel (DMF) for a 90-day production test.  The remaining oil reserves in L53/48 concession were around 1.24 MMbbl at 31 December 2019, as evaluated by Sproule International Ltd. The concession produced 499 Mbbl of oil from the L53 A, D, G and DD fields in 2018.  The L53/48 concession is fully owned and operated by Pan Orient (Siam) Ltd, which is in turn controlled by Pan Orient Energy Corp (50.01%) and Sea Oil Public Company (49.99%). The exploration Area A and B will expire in January 2021, after which the production areas (A, B, D, G and DD) will be retained.  Background Information  The L53/48 block lies onshore in the Kamphaeng Saen area of the Chao Phraya Basin, around 50km WNW of Bangkok. The area is covered by at least 580 sq km of 3D seismic data which were acquired since 2007.   Eight minor oil discoveries were encountered from 2009 to 2019. As of late 2019, a total of six fields are producing (L53-A, L53-G, L53-D East, L53-DD, L53-B and L53-AA South) and another two fields are appraising (L53-D and L53-D C-EXT). The oils were trapped in the Lower to Middle Miocene structural play which was sealed by Middle Miocene Series mudstone.   The original 3,997 sq km L53/48 block was awarded to Pan Orient Energy on 8 January 2007 as the operator and sole interest holder, under the 19th Licensing Round. The concession agreement allows Pan Orient to explore for hydrocarbons over a period of six years with a minimum three years first phase commitment of approximately US$ 2.1 million, which includes 3D seismic acquisition and two exploratory wells.",Thailand (Chao Phraya B.) L53-G
27361,"SE part of Green Canyon block 432, OCS lease G32504, sidetrack of GC 432 2S0B1 in WD 1,067m, drilled to 9,778m and has encountered more than 46m of oil pay, including in zones not seen in the Samurai discovery well, Deepwater Asgard DS. Murphy (op), partner BHP.","GC 432 002S0B1 (Samurai-2) (Murphy 50% op. BHP 50%) in G32504, has encountered more than 46m of oil pay, including in zones not seen in the Samurai discovery well, target subsalt M. Miocene."
55023,"IOG has agreed a farmout to CalEnergy Resources of a 50% interest in all of its upstream assets (except for the Harvey licences), as well as the Thames pipeline and associated Thames reception facilities for an initial GBP 40 MM downpayment.  CalEnergy will have the option, within 3 months of the Harvey appraisal completion, to farmin with 50% to the Harvey licences for GBP 20 MM.  IOG will retain operatorship. Assets also include the Goddard field and the Vulcan satellites and Blythe hubs.",United Kingdom (Indefatigable Shelf (Anglo-Dutch B.)) Thames
56279,"On 7 August 2019 Oilex Ltd announced that it has entered into an agreement to acquire Holloman Energy Corporation’s subsidiary company Holloman Petroleum Pty Ltd. Holloman holds 48.5003% interest in two Cooper-Eromanga Basin permits: PEL 112 and PEL 444, alongside operator of the permits Terra Nova Energy. Both Terra Nova and Holloman had been looking to divest their interests in the permits.  Oilex has also signed an agreement with joint venture partner Terra Nova, as reported on 14 August 2019. The agreement is for Oilex to acquire an additional 30.833% interest, with the option to increase to 51.4997%, which would result in 100% interest after 12-15 months.    Oilex has agreed to acquire 100% interest in the Holloman subsidiary for the consideration of 40,416,917 ordinary Oilex Shares, plus AUD 24,250 payable upon completion. The structure values the deal at around AUD 1.2 million, based on AUD 0.03 per Oilex share. The deal is set to close on 30 September 2019.    The permits are located in the Western Flank Fairway and Terra Nova reports that there are a number of Namur and Birkhead structural prospects within both permits.    PEL 112 covers an area of 1,000 sq km and was awarded on 17 April 2003. Terra Nova has outlined the Milo, Libby and Drole structural prospects, which combined hold a potential 9 MMb oil in place. Milo is outlined as the primary target, with the largest potential resource and lowest risk. One exploration well is due in 2019. The well will likely target one of these prospects and be positioned from the 2012 Mulka 3D seismic survey, which is located in the north of the permit area.     The Wolfman 1 well was drilled within the Mulka survey area in 2013. It targeted a dip closure in the Namur Sandstone at around 1,200 m depth but was dry at location. Secondary, deeper, targets of the Birkhead and Hutton formations were also dry.    PEL 444 covers an area of 1,150 sq km and was also awarded on 13 April 2003. Terra Nova has identified the Maverick mid-Birkhead prospect which is considered as a key exploration target.  It has a potential 1.71 MMbo resource. The Crater and Moraine Namur prospects have also been outlined as potential targets. The prospects in PEL 444 have been identified from the merged Jasmin and Wingman seismic datasets, which Terra Nova has reported as providing high level mapping of the licence. Terra Nova considers there is potential for the Hoplite 1 oil play fairway to extend into PEL 444. One commitment well is due in 2021.    The Baikal 1 well was drilled in 2015, located approximately 8 km west of Hoplite 1. The well targeted this the oil play within the mid-Birkhead channel sands but was dry at location. However, the channel sands, which were mapped from seismic, were encountered and now provides qualification to the current exploration model.    PEL 112 and PEL 444 are held by Terra Nova Energy Australia Pty Ltd (a Claren Energy subsidiary - 51.5% + Operator) and Holloman Petroleum Pty Ltd (48.5%).  Upon completion of Oilex acquiring Holloman Petroleum Pty Ltd and interest held by Terra Nova, interests will become: Oilex Ltd (79.333%, with the option to increase to 100%) and Terra Nova (20.667%).             PEL 112 and PEL 444 are held by Terra Nova Energy Australia Pty Ltd (a Claren Energy subsidiary - 51.4997% + Operator) and Holloman Petroleum Pty Ltd (48.5003%).  Upon completion of Oilex acquiring Holloman Petroleum Pty Ltd plus the interest held by Terra Nova, Oilex Ltd will hold","Oilex had entered into an agreement with Perseville Investing and Terra Nova Energy to acquire up to a further 51,4997% interest in petroleum exploration licences 112 and 444."
84985,"As of early July 2020, the Nigerian Department of Petroleum Resources (DPR) declared that over 600 companies have applied to be prequalified for the 2nd Marginal Fields Bid Round launched on 1 June. The initial registration period lasted until 21 June, after a short extension period. The DPR is now evaluating the applications and is understood to be able to announce the prequalified bidders in the next days or weeks (originally planned on 5 July). The full revised schedule of the auction is detailed in a separate article.  Interested parties are invited to visit the DPR portal for the exercise (https://marginal.dpr.gov.ng/). Further enquiries will be sent to info@dpr.gov.ng and marginal@dpr.gov.ng or asked through phone at +234 (1) 27 900 00 or +234 (1) 90 371 50.    Although the process is primarily designed for Nigerian oil companies in order to acquire petroleum permits, foreign companies can also apply as long as 51% operated interest is kept by an indigenous party.   The contributors of the 57 marginal fields (undeveloped assets) are mainly the five Majors ExxonMobil, Shell, Chevron, Total and Eni, active in Niger Delta for decades. They were requested by the authorities to release some of their non-core business assets. In April 2020, the DPR also revoked ten permits operated by indigenous companies with intention to put them on offer in the bid round, considering the companies were inactive. However, these companies are now contesting this decision and secured in early June a joint order of the Federal High Court of Nigeria.  The below map provides with a visual representation of the Nigerian marginal blocks offered in 2020 (the small red outlines). They are located onshore, in swamps and in the shallow waters of Niger Delta. This image also indicates the existing blocks of the five Majors from which most of the marginal fields were carved out.","Nigeria (Niger Delta), as of early July 2020, the Nigerian Department of Petroleum Resources (DPR) declared that over 600 companies have applied to be prequalified for the 2nd Marginal Fields Bid Round launched on 1 June."
9790,"PL 533, S. Barents Sea S. of the Filicudi find in WD 337m, target Stø fm, cleared to drill by the NPD on 3 Nov ’17, Leiv Eiriksson SS over from 7219/12-2 S expl (TD’d at 2,075m (1,829m TVD, targets Nordmela + Tubåen fm’s) in which a non-commercial gas find was made (22m column) , and sidetrack A was dry (TMD 1,878m, 1,618m TVD). Well to P&A and rig off to drill the Hurri prospect also in PL 533. Lundin (op) 35%, Aker BP 35%, DEA 30%.","Norway, PL 533"
9031,"SE part of Estreito field area, onshore Potiguar, oil shows report to ANP on 30 Oct ’17, suspended early Nov ’17, Sonda Conv. rig 86. PTD was 438m, target Açu fm.",Brazil (Potiguar B.) 3-ET-2000-RN op. by PETROBRAS (100.0%) in Estreito block
9586,"The BOEM has awarded Ecopetrol and Repsol 50:50 rights to 4 deepwater blocks in the GoM, namely Garden Banks 77, 78, 121 + 122 in WD 240m. Rights were granted for 5 years from Lease Sale 249 held on held on 16 Aug ‘17 in New Orleans.  It is recalled 99 bids were placed on 90 tracts from 27 companies. Total had offered the single highest bid, over USD 12 MM for Garden Banks block 1003. ","United States, not found"
74117,"Union Jack Oil announced on 9 March 2020 that it has agreed two deals with Terrain Energy in PEDL 005(R) and PEDL 339. For PEDL 005(R), block TF/38b Keddington, Union Jack Oil will acquire Terrain's 35% interest in the block which includes the producing Keddington field in return for GBP 200,000. Union Jack Oil has assumed costs of GBP 35,000 in relation to Keddington site activities from the effective date of 1 January 2020. For PEDL 339, block TF/38c, Union Jack Oil will acquire Terrain's 15% interest in the licence. Completion of the deals is pending OGA approval.   Keddington was discovered in in 1998 by Morrison Middlefield Resources Ltd subsidiary Candecca Resources Ltd. The field produces 28 bo/d from a Carboniferous reservoir. The partners in Keddington believe that there is remaining potential within the field which can be realized through further development drilling at the field. Approval is in place for the drilling of a further two wells and Egdon is finalizing its assessment of potential in-fill drilling locations. The site lease has been extended until 2029. In February 2020 Egdon completed the acquisition of a 20% interest from Terrain Energy in PEDL 005, block TF38b – Louth. The acreage contains the Louth prospect which Egdon is looking to farm down and potentially drill an exploration well later in 2020 or 2021.  Following completion of the deals interest in PEDL 005(R) – block TF/38b Keddington will be Egdon Resources U.K. Limited (45% + operator) and Union Jack Oil Plc (55%). Interest in PEDL 339 will be held by Egdon Resources U.K. Limited (65% + operator) and Union Jack Oil (35%).","UJO has taken on a further 35% from partner Terrain Energy in PEDL 005(R) (Keddington oilfield) for GBP 200,000, pushing its stake to 55% whilst operator Egdon retains its 45%. In parallel, UJO is also acquiring 15% in adjacent PEDL 339 (Louth + North Somercotes prospects)."
68830,"On 17 December 2019, the General Directorate of Mining and Petroleum Affairs (MAPEG) awarded Petar Dogalgaz ve Petrol Arama San. Tic. AS a new and exclusive exploration licence for block M42-d3, d4. The onshore licence is located in the SE Turkish provinces of Urfa (District XI) and adjoins the company's M42-d1, d2 block, which was awarded in late January 2019. It will be valid for an initial five-year exploration term.<P />Block M42-d3, d4 covers an area of 306.52 sq km and is largely unexplored, with no wells having been drilled on the acreage so far. Turkish Petroleum Corp (TPAO) submitted the original application for the block on 1 November 2018, with Petar Dogalgaz and Calik Petrol submitting rival applications of 7 and 8 February 2019 respectively. Petar Dogalgaz now operates the M42-d3, d4 licence with a 100% interest.","Petar Dogalgaz ve Petrol Arama San. Tic. AS awarded a new and exclusive exploration licence for block M42-d3, d4."
80129,"On 22 April 2020, Empyrean Energy, the oil and gas development company with interests in China, Indonesia and the United States, announced the launch of an Open Offer pursuant to which Qualifying Shareholders were able to subscribe for 1 new Ordinary Share in the Company at a price of 3.5 pence each for every 8 Ordinary Shares held at the Record Date. The Open Offer closed for acceptance at 11.00 a.m. on 11 May 2020 and the Company advises that valid applications, including pursuant to the Excess Application Facility, were received in respect of a total of 11,358,275 new Ordinary Shares, being approx. 20 per cent. of the Ordinary Shares made available pursuant to the Open Offer. Accordingly, the Company has raised gross proceeds of approx. £397,540 pursuant to the Open Offer. The Company has also issued 500,000 new Ordinary Shares to investors outside of the Open Offer through a direct subscription, raising a further £17,500 and increasing the gross proceeds raised to approx. £415,040. Together with the proceeds of the subscription announced on 14 April 2020, the Company has raised a total of approx. £825,990 in recent weeks. Application has been made for the new Ordinary Shares to be issued pursuant to the Open Offer and the Subscription to be admitted to trading on AIM.  Admission of the New Ordinary Shares is expected to take place on 14 May 2020. The New Ordinary Shares will rank pari passu with the existing Ordinary Shares. Following the issue of the New Ordinary Shares, Empyrean's total issued share capital will comprise 471,197,281 Ordinary Shares, each with voting rights. This figure may be used by shareholders as the denominator for the calculations by which they will determine if they are required to notify their interest in, or a change to their interest in, securities of the Company under the Financial Conduct Authority's Disclosure and Transparency Rules. The Company confirms that John Laycock, a director of Empyrean, subscribed for a total of 400,000 new Ordinary Shares under the Open Offer. Following this subscription, Mr Laycock has an interest in 3,200,000 Ordinary Shares, representing approx. 0.68 per cent. of the enlarged issued share capital of the Company. As previously stated, the Board may exercise its right to use its reasonable endeavours to place those Ordinary Shares not taken up pursuant to the Open Offer, amounting to 46,059,100 Ordinary Shares, at not less than the Issue Price, in order to raise up to the maximum proceeds under the Open Offer. Further announcements will be made as appropriate. Tom Kelly, Empyrean CEO, commented: 'We are pleased that the Subscription and Open Offer has raised funds at the higher end of our expectations, particularly given the unique challenges currently being experienced in equity markets as a result of CoVID-19, and the current oil market volatility.  I would like to thank our existing Shareholders for their support of these capital raising initiatives and we look forward to updating Shareholders on the progress of operations in the near future.' Original article link Source: Empyrean Energy","Empyrean Energy, the oil and gas development company with interests in China, Indonesia and the United States, announced the launch of an Open Offer pursuant to which Qualifying Shareholders were able to subscribe for 1 new Ordinary Share in the Company at a price of 3.5 pence each for every 8 Ordinary Shares held at the Record Date. "
59422,"20 September 2019, President of Lukoil and Chairman of the Management Board of KazMunayGaz (KMG) signed an Agreement on Joint Studies. The two companies agreed on major terms of co-operation and expressed their willingness to begin studies on mineral resources in order to evaluate the hydrocarbon potential of certain areas in the Republic of Kazakhstan. The press releases by either of the companies do not specify which specific areas will be studied.   Earlier this year, Lukoil, the Kazakhstan Ministry of Energy and KMG signed a contract for hydrocarbon exploration and production on the offshore Zhenis block. Baseline agreement on the I-P-2 offshore project was also signed this year and is expected to be finalised before the year’s end. In addition, Lukoil and KMG partner in a number of large projects such as Karachaganak, Tengiz, Kumkol and Caspian Pipeline Consortium.  Lukoil was probably the first major oil company who reacted positively to the adoption of the new Code on the Subsurface in Kazakhstan (came into effect in June 2018). In February 2018, Lukoil’s president said that subsequent to adoption of this new legislation, the company was planning to sign new exploration/field development contracts in Kazakhstan “in near future”, as it viewed the new code as stimulating foreign investment in Kazakhstan’s E&P opportunities.","Lukoil and KMG have reached an agreement on joint studies on hydrocarbon potential of certain parts of Kazakhstan, areas not specified. Both companies are already involved in the Zhenis offshore block inter alia, and an agreement on the I-P-2 offshore project is expected to be finalised before year end."
17793,"On 29 March 2018, the consortium of Petrobras with 60% working interest and Shell with 40%, was granted preliminary awards for the POT-M-859 and POT-M-952 blocks in the offshore Potiguar Basin through the ANP Round 15.    For the      POT-M-859 block the consortium offered a bonus of USD 4.08 million and 229      work units.  For      the POT-M-952 block the consortium offered a bonus of USD 6.06 million and      176 work units.        There were no other bids for either of the blocks.","the consortium of Petrobras with 60% working interest and Shell with 40%, was granted preliminary awards for the POT-M-859 and POT-M-952 blocks in the offshore Potiguar Basin through the ANP Round 15. "
62180,"On 23 October 2019, the Argentine government granted an exploration permit for MLO-117 block to a consortium of a partnership of ExxonMobil and Qatar Petroleum through the publication of Resolution 673/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Work program in the first exploration period of four years consists of 2D seismic acquisition of 781.44 km and reprocessing of 1,474.13 km, 3D seismic acquisition of 2,058.26 sq km and reprocessing of 1,715.22 sq km, along with 2D gravimetry and magnetometry acquisition of 5,721.27 km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment. ExxonMobil operates the block with 70% interest while partner Qatar Petroleum holds the remaining 30%.  MLO-117 covers 4,903 sq km of deepwater area (as designated by the Argentine Secretary of Energy) in Malvinas Basin with approximated water depth below 200 m. Exploration target for the blocks in the area is expected to be oil and gas in the Springhill Formation, which has not produced from any fields on the Malvinas Basin side in comparison to the adjacent Austral Basin side where several offshore gas fields are currently producing.  ExxonMobil and Qatar Petroleum won the rights for MLO-117 after submitting a joint offer of USD 34.475 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019. Along with MLO-117, the group also won the rights for MLO-113 and MLO-118 blocks with offers of 30.1 million and 29.95 million, respectively. The offshore blocks marked the second partnership between ExxonMobil and Qatar Petroleum in Argentina after Qatar Petroleum's purchase of 30% equity in ExxonMobil affiliates in mid-2018.  Background Information  The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.","On 23 October 2019, the Argentine government granted an exploration permit for MLO-117 block to a consortium of a partnership of ExxonMobil and Qatar Petroleum"
62138,"Senex Energy Ltd, through wholly owned subsidiary Victoria Oil Exploration (1977) Pty Ltd), spudded the Snatcher North 2 oil appraisal well in PRL 145, located in the Cooper-Eromanga Basin, on 10 October 2019. The well was drilled by the ""Saxon 185"" land rig. On 19 October 2019 the well was plugged and abandoned as a dry hole, after reaching a total depth of 1,905 m.  The well was drilled to appraise the Snatcher field, which was discovered in July 2009 and has been producing since December 2009. The Snatcher North 1 appraisal well was successfully drilled in 2H 2018.  PRL 145, which covers an area of 98 sq km, was awarded on 27 October 2014.Participants in the permit are Senex Energy subsidiaries Victoria Oil Exploration (1977) Pty Ltd (40% + Operator) and Permian Oil Pty Ltd (20%), and Beach Energy subsidiaries Impress (Cooper Basin) Pty Ltd (25%) and Springfield Oil and Gas Pty Ltd (15%).","Snatcher North 2 (Senex 60% op, Beach 40%) in PPL 240, P&A after failing to intersect any hc"
73145,"It was reported on 6 February 2020 that TransAtlantic Exploration Mediterranean Int. Pty Ltd (TEMI) has transferred its full 50% interest and operatorship in E17-C2-1 production lease to Petrogas Petrol Gaz ve Petrokimya Ürünleri Ins. San. ve Tic. A.S. on 28 January 2020. As a result of this transaction the revised equity split for E17-C2-1 lease is as follows: Petrogas 55% (operator), Petrako Petrol Dogalgaz Ins. Taah. Isle. ve DíS Tic. Ltd. STI. 10% and Valeura Energy Netherlands B.V 35%. TEMI and Petrogas, both are the subsidiaries of TransAtlantic Petroleum.  TEMI had submitted the application to the government on 16 September 2019 for the approval of this transaction. The licence, located towards northwest of the country in Thrace Basin, covers an area of 116 sq km and it was awarded to TEMI on 4 December 2014.",TransAtlantic Exploration Mediterranean Int. Pty Ltd (TEMI) has transferred its full 50% interest and operatorship in E17-C2-1 production lease to Petrogas 
33384,"Parnaiba Gas Natural (PGN) is assumed to have plugged and abandoned dry the 1-PGN-BL103E-MA (1-PGN-028-MA) new-field wildcat (NFW) in the PN-T-103 contract during mid-October 2018.      The operator has not filed and      gas show reports for the well with the ANP through late-October 2018.     The NFW was spudded on 27 September 2018.         The well had a proposed total      depth (PTD) of 1,633 m.  The Devonian Cabecas Formation and the      Mississippian Poti Formation were the primary targets.    The NFW is located in the north      central border area of the block with the nearest well the Petrobras      operated 1-BXC-001-MA (1-BRSA-1362-MA) located 25 km northwest in the      PN-T-086 block.  Parnaiba Gas Natural has 100%      working interest in the contract.","Brazil, PN-T-103"
10938,"On 8 December 2017, the consortium of Sun God Energia de Mexico, S.A. de C.V. / Jaguar Exploracion Y Produccion De Hidrocarburos, S.A.P.I. de C.V. signed the contract with the CNH and was granted official final awards for the CNH-RO2-L02-A4.BG/2017, the CNH-RO2-L02-A5.BG/2017, the CNH-RO2-L02-A7.BG/2017, the CNH-RO2-L02-A8.BG/2017, and the CNH-RO2-L02-A9.BG/2017 contracts from the CNH-RO2-LO2/2016 Bid Round.  The contracts were originally denominated as the Area 4, 5, 7, 8, and 9 blocks.  The consortium formed a separate subsidiary, Pantera Exploracion y Produccion 2.2, S.A.P.I. de C.V. with 100% working interest as the official designated operating company for the block.  The 440.3 sq km CNH-RO2-L02-A4.BG/2017 contract has a total financial commitment of USD 29.5 million, all for work commitments that includes two extra wells. The 444.6 sq km CNH-RO2-L02-A5.BG/2017 contract has a total financial commitment of USD 9.3 million, all for work commitments that does not include extra wells. The 445.0 sq km CNH-RO2-L02-A7.BG/2017 contract has a total financial commitment of USD 32.13 million, USD 28.0 million for work commitments that includes two extra wells and USD 4.13 million tie-break bonus payment.  The 416.1 sq km CNH-RO2-L02-A8.BG/2017 contract has a total financial commitment of USD 31.6 million, all for work commitments that includes two extra wells.  The 349.0 sq km CNH-RO2-L02-A9.BG/2017 contract has a total financial commitment of USD 24.7 million, all for work commitments that includes two extra wells. On 12 July 2017, the consortium of Sun God Energy and Jaguar Exploracion was the high bidder in the CNH-RO2-LO2/2016 Bid Round for the Area 4, Area 5, Area 7, Area 8, and Area 9 blocks in the Burgos Basin and was granted preliminary awards.   For the 440.30 sq km Area 4 block there was one other bid.  The Sun God consortium offered the maximum additional royalties of 25% and 1.5 work unit factor equivalent to two additional wells.  It won the block after the second highest bid by Iberoamericana, Newpek, and Verdad was for 15.76% royalties and 1.0 work units or one well.   For the 444.60 sq km Area 5 block the Sun God consortium offered additional royalties of 16.96% and 0.0 work unit factor equivalent to no additional wells.  It won the block after the second highest bid by Iberoamericana, PJP4 was for 8.09% royalties and 1.0 work units or one well. For the 445.00 sq km Area 7 block there were two other bids.  The Sun God consortium offered the maximum additional royalties of 25% and 1.5 work unit factor equivalent to two additional wells.  There was one other equivalent bid so it ended in a tie.  Sun God won the tie-break for the block with a bonus offer of USD 4.13 million after the second highest bid by Iberoamericana, PJP4 made a bonus offer of USD 2.92 million.   For the 416.10 sq km Area 8 block the Sun God consortium offered the maximum additional royalties of 25% and 1.5 work unit factor equivalent to two additional wells.  There were no other bids for the block. For the 464.00 sq km Area 9 block the Sun God consortium offered the maximum additional royalties of 25% and 1.5 work unit factor equivalent to two additional wells.  There were no other bids for the block. It is estimated that the winning consortium is split 50%-50% but the final official equity breakdown will only be reported at a later date. The general license contract terms include a 1st exploration period of two years with the possibility of a two-year extension.  In the case of a discovery the operator can request a two-year evaluation phase for oil and a three-year evaluation phase for non-associated gas discoveries once the evaluation plan is approved.  The total contract term is for 30 years with the possibility of two five year extensions for a 40-year total contract term from signature date. The base royalty rate is a sliding scale royalty depending on type of hydrocarbon and oil price.  The values for oil range from 5% for USD 40/bbl oil to 25% for USD 200/bbl oil.  The relinquishment schedule is tied to exploration well commitments.  If the exploration period ends but the operator offers to drill an additional well it doesn’t have to relinquish any area.  If the exploration period ends and the contractor doesn’t have any discoveries it must relinquish 100%.  If the exploration period ends and the operator doesn’t offer to drill an additional exploration well it will have to relinquish 50% of the area.  Local content during the exploration period is 26% for the exploration and evaluation period, and varies from 27% to 38% in the development period.","Mexico (Campeche Deep Sea B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: 10 op. by ENI SPA (100.0%) to be check.12 op. by LUKOIL (100.0%) to be check.Area 4 (Ichalkil) op. by RIVERSTONE (50.0%, PETROBAL 50.0%) to be check.8 op. by PEMEX (50.0%, ECOPETROL 50.0%) to be check.7 op. by ENI SPA (45.0%, CAIRN EN 30.0%, CITLA 25.0%) to be check.Area 4 (Pokoch) op. by RIVERSTONE (50.0%, PETROBAL 50.0%) to be check.9 op. by OTP (49.0%, ETAP 51.0%, TPS 0.0%) to be check.15 op. by TOTAL (60.0%, SHELL 40.0%) to be check."
42350,"Commitment well in PL 740, location S. of Brage in WD 124m, P&A’d as planned, Transocean Arctic SS.  31/7-3 S TMD 2,705m (2,247m TVD), target Sognefjord fm water-wet. Sidetrack 3A  TMD 2,855m (2,254m TVD), 40m gross hc-bearing Sognefjord logged, reservoir depth + hc contact as pre-drill expectations, 15m gas + 47m oil columns, OWC 20m deeper than at discovery. Faroe (op), partner Vår Energi.","31/7-3 S, 3A (Brasse Øst) expl Commitment well in PL 740, location S. of Brage in WD 124m, P&A’d as planned, Transocean Arctic SS.  31/7-3 S TMD 2,705m (2,247m TVD), target Sognefjord fm water-wet. Sidetrack 3A  TMD 2,855m (2,254m TVD), 40m gross hc-bearing Sognefjord logged, reservoir depth + hc contact as pre-drill expectations, 15m gas + 47m oil columns, OWC 20m deeper than at discovery. Faroe (op), partner Vår Energi."
10394,"In November 2017, internal sources reported that the newly created Petrolines Group (Petco) is being staffed in order to take full control of the operatorship of Block 2B. Both Sudapet and Petco will share the operatorship (50% of interest each) and their primary target will be to increase the output of the producing fields from current 22,000 b/d (as of September 2017) to a planned target of 26,000 b/d. To reach this target, Petrolines is planning to drill 12 new wells.  On 6 November 2016, the state company Sudan Petroleum Corp (Sudapet) and the - also national company - Petrolines for Crude Oil Ltd (Petco) were awarded the Block 2B, located in the south of Sudan, Muglad Basin. In August 2017, the block continued to be operated by the former partnership (Greater Nile Petroleum Company, GNPOC).  The two companies are seeking partners to continue developing the block which as of September 2017 was producing approximately 22,000 b/d of oil. The China National Petroleum Company (CNPC), which is part of the former operating partnership has tried to extend the previous contract conditions but the government is only keen to discuss a farm out of interest between 20% to 30%.  Block 2B was previously part of the Blocks 1, 2, 4 contract that was awarded in 1997 to the GNPOC consortium (Petronas, CNPC, Sudapet and State Petroleum).  Petco is a company 100% owned by the Sudanese Ministry of Petroleum and Gas with operations on oil transportation, supply and shipment.   ","Sudan (Muglad B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Block 2B op. by PETROLINES (50.0%, SUDAPET 50.0%) to be check."
33370,"On 25 October 2018, Spectrum announced that the Republic of Gabon would open its 12th Shallow and Deep-Water Licensing Round of open blocks at the 25th Africa Oil Week (AOW), Cape Town in November 2018.  H.E. Pascal Houangni Ambouroue, Gabonese Minister of Oil and Hydrocarbons, will make the announcement during a special session within the main auditorium of the Africa Oil Week at 08:50 on Wednesday 7th November 2018. This will be followed by a technical and fiscal workshop that will detail the new petroleum code, the license round and associated terms.  The Workshop will take place at the Southern Sun at 11:00 and include: further details of available blocks, the fiscal terms, timings and conditions of the 12th Gabon Licensing Round. The Minister will also announce the dates and venues of the associated global licence round Road Shows, supported by Spectrum.  In Collaboration with the Direction Générale des Hydrocarbures (DGH) Spectrum has undertaken a number of shallow water 3D seismic surveys across the open blocks available in the 12th License Round. Seismic has been acquired in both north and south of the country. The 11,500 sq km southern survey, now complete images the pre-salt and allows for the targeting of the intra syn-rift plays. In the North, acquisition of a 5,500 sq km 3D survey images pre and post-salt targets.  Spectrum can be contacted for data for license round evaluation facilitating immediate activity when the blocks are awarded.","Gabon, not found"
10954,"On 8 December 2017 the consortium of Roma Exploration and Production LLC, Tubular Technology, S.A. de C.V., Suministros Marinos e Industriales de Mexico, S.A. de C.V., and Golfo Suplemento Latino, S.A. de C.V. had the second-place bid in the CNH-RO2-LO3/2016 Bid Round for the Area 6 block in the Veracruz Basin and was granted a preliminary award after the first-place bidder, the Shandong consortium failed to pay the government the USD 2.2 million tie-break bonus.  The Roma led consortium must now pay the USD 1.5 million tie-break bonus and will have 140 days to sign for the contract if it does so.  The Shandong consortium now forfeits its bid guarantee bond of USD 250,000 for not signing the contract. On 12 July 2017 the consortium of Shandong, Sicoval, and Nuevas Soluciones was the high bidder in the CNH-RO2-LO3/2016 Bid Round for the Area 6 block in the Veracruz Basin and was granted a preliminary award.   For the 193.30 sq km Area 6 block the Shandong consortium offered the maximum additional royalties of 40% and 1.5 work unit factor equivalent to two additional wells.  There were two other bids for the block and one offered the same royalties and work units so ended in a tie.   Shandong won the tie break with a bonus bid of USD 2.2 million beating the 2nd place consortium of Roma, Tubular, Suministros Marinos, and Suplemento who offered a bonus of USD 1.5 million.   It is estimated that the winning Shandong consortium is split 34%-33%-33% but the final official equity breakdown will only be reported at a later date. The general license contract terms include a 1st exploration period of two years with the possibility of a two-year extension.  In the case of a discovery the operator can request a two-year evaluation phase for oil and a three-year evaluation phase for non-associated gas discoveries once the evaluation plan is approved.  The total contract term is for 30 years with the possibility of two five year extensions for a 40-year total contract term from signature date. The base royalty rate is a sliding scale royalty depending on type of hydrocarbon and oil price.  The values for oil range from 5% for USD 40/bbl oil to 25% for USD 200/bbl oil.  The relinquishment schedule is tied to exploration well commitments.  If the exploration period ends but the operator offers to drill an additional well it doesn’t have to relinquish any area.  If the exploration period ends and the contractor doesn’t have any discoveries it must relinquish 100%.  If the exploration period ends and the operator doesn’t offer to drill an additional exploration well it will have to relinquish 50% of the area.  Local content during the exploration period is 26% for the exploration and evaluation period, and varies from 27% to 38% in the development period.","Mexico (Campeche Deep Sea B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: 8 op. by PEMEX (50.0%, ECOPETROL 50.0%) to be check.12 op. by LUKOIL (100.0%) to be check.6 op. by PETRONAS (50.0%, ECOPETROL 50.0%) to be check."
57439,"Vintage has inked a study agreement with YPFB to evaluate the potential of the Cedro, Florida Oeste, La Guardia + Rodeo blocks in the Foothill Belt of the Chaco Basin in W. Santa Cruz. The blocks cover resp. 1,002 sq km, 153 sq km, 921 sq km + 983 sq km.","Bolivian subsidiary of Occidental Petroleum, Vintage Petroleum Boliviana, has signed a study agreement with state company YPFB to evaluate the potential of the Cedro, Florida Oeste, La Guardia, and Rodeo blocks. No details are available currently regarding the planned work commitment or amount of investment for the blocks. "
67195,"17 December 2019, Epsilon Development Company has announced a gas discovery with well Hatar Sharkiy 1 in the Amu-Darya Basin. The well is located north of the Kumli gas field, very close to the border of Lukoil's Kandym block. Epsilon provides no technical details, it only says that the flow rate ""has increased from 0 to 80,000 cu m/day (2.74 MMscf/d)"", which may indicate a re-entry rather than a newly drilled well. In the past, Uzbekneftegaz drilled wells in the Hatar area (Hatar 1 and 2), but both had been unsuccessful.  The new discovery's reservoir is most likely associated with the Callovian-Oxfordian carbonates, the main prospective play in the Amu-Darya Basin. Kumli field's Callovian-Oxfordian reservoir occurs at a depth of 1,958 m.","17 December 2019, Epsilon Development Company has announced a gas discovery with well Hatar Sharkiy 1 in the Amu-Darya Basin. The well is located north of the Kumli gas field, very close to the border of Lukoil's Kandym block. Epsilon provides no technical details, it only says that the flow rate ""has increased from 0 to 80,000 cu m/day (2.74 MMscf/d)"", which may indicate a re-entry rather than a newly drilled well. In the past, Uzbekneftegaz drilled wells in the Hatar area (Hatar 1 and 2), but both had been unsuccessful. The new discovery's reservoir is most likely associated with the Callovian-Oxfordian carbonates, the main prospective play in the Amu-Darya Basin. Kumli field's Callovian-Oxfordian reservoir occurs at a depth of 1,958 m."
84452,"Sundulbari 2 field area, Sundulbari-Agartala Dome PML, Tripura-Cachar Basin, as of Feb '20 tested 4 MMcfg/d + 11 MMcfg/d from 2 intvs likely in the Upper Bhuban sands. PTD was 2,500m, ARMCO rig.","(Tripura-Cachar B.) Sundalbari 15 op. by ONGC (100%) in Tichna ML block, TD = 2500 m appraisal well Sundulbari-Agartala Dome PML, Tripura-Cachar Basin - suspended"
80116,"Kirthar has assigned a 2.5% interest to GHPL in the Makhad 3371-19 EL, 1,563 sq km in the Potwar Basin, retro-effective to award on 22 May '19. Resulting partnership Kirthar – GHPL.","irthar has assigned a 2.5% interest to GHPL in the Makhad 3371-19 EL, 1,563 sq km in the Potwar Basin, Resulting partnership Kirthar – GHPL."
63755,"On 8 November 2019, the Federal Agency for Subsoil use offered two exploratory licenses in Kurgan Oblast (Western Siberia). Applications must be submitted by 19 December 2019. The successful applicants will receive five-year licenses. The Pokrovskiy (150.8 sq km) and Utichyevskiy (299.7 sq km) blocks are located in a low-prospective area of the West Siberian Basin. Hydrocarbon potential of the offered blocks has not been estimated. Applications must be mailed to 640000, Kurgan, Kuybysheva Str., 12, office 2019.","On 8 November 2019, the Federal Agency for Subsoil use offered two exploratory licenses in Kurgan Oblast (Western Siberia). Applications must be submitted by 19 December 2019."
65227,"It was announced on 24 November 2019 that Turkiye Petrolleri A.O. (TPAO) has been awarded the M41-C1,C3,C4 exploration licence (Zagros Province) on 18 November 2019 for a period of five-year. The licence, covering an area of around 415 sq km, is located towards southeast of the country and TPAO will be 100% owner and operator of the licence. TPAO had filed the application on 13 November 2018.","TPAO has been awarded the M41-C1,C3,C4 exploration licence (Zagros Province) on 18 November 2019 for a period of five-year. The licence, covering an area of around 415 sq km, is located towards southeast of the country and TPAO will be 100% owner and operator of the licence."
79080,"The Government of Sierra Leone has announced that following the conclusion of the Fourth Offshore Petroleum Licensing Round on 28 February 2020, six applications for offshore petroleum concessions were received and evaluated. Following the initial launch of the Fourth Licensing Round in 2018, the Petroleum Directorate of Sierra Leone, in partnership with GeoPartners and Getech, announced the re-opening of the 4th Licensing Round on 21st May 2019. The licensing round included a direct tender for licensing applications where 50% or more of the area is in water depths in excess of 2,500m (deadline 20th September 2019) and an open tender for other licence applications (deadline 22nd November 2019). The Government of Sierra Leone has announced that open offshore petroleum acreage has been provisionally awarded to: Cluff Energy Africa, covering Blocks 23, 24, 25, 36, 37,38, 39, 54, 55, 56, 57, 74, 75, 94 & 95 and Innoson Oil and Gas, covering Blocks 96, 97, 114, 115, 116, 117, 133,134, & 135. Click here for further licence round details Original article link Source:snradio.net / energy-pedia","Sierra Leone, not found"
84707,"On 6 July 2020 RockRose Energy announced that it has agreed with Vario Energy the terms for the acquisition of the ordinary share capital of RockRose Energy. The agreement with Vario Energy is for a recommended all-cash offer at a value of GBP 247.58 million. The acquisition could be via a court-sanctioned scheme or by a takeover offer. RockRose believe the deal is fair and advise shareholders to vote in favour of the scheme or takeover offer. The deal is subject to the approval of shareholders but it has already received the irrevocable approval to vote in favour of the scheme from the company's Directors, Managers and some shareholders- in total representing approximately 35% of the RockRose shares.   RockRose is an independent oil and gas company listed on the London Stock Exchange. Since RockRose was founded in 2015 it has built up its portfolio through corporate acquisitions. RockRose holds interest in onshore and offshore, operated and non-operated assets in the UK and the Netherlands. The company entered the Netherlands in 2018 when it acquired non-operated interest in assets from Dyas. In 2019 RockRose acquired operated interest in assets from the acquisition of Marathon Oil's UK North Sea assets. In the announcement on 6 July 2020 it was stated that RockRose directors believe that, given the current share price of the company, raising further equity capital would dilute the value for shareholders.  Vario Energy is a wholly owned subsidiary of Vario Investment Limited. The company has global commodities trading activities and interests in the energy sector support services and upstream development. The acquisition will represent Vario's expansion towards the creation of an integrated upstream and trading company.","United Kingdom, On 6 July 2020 RockRose Energy announced that it has agreed with Vario Energy the terms for the acquisition of the ordinary share capital of RockRose Energy. The agreement with Vario Energy is for a recommended all-cash offer at a value of GBP 247.58 million. The acquisition could be via a court-sanctioned scheme or by a takeover offer. RockRose believe the deal is fair and advise shareholders to vote in favour of the scheme or takeover offer. The deal is subject to the approval of shareholders but it has already received the irrevocable approval to vote in favour of the scheme from the company's Directors, Managers and some shareholders- in total representing approximately 35% of the RockRose shares."
59636,"TAG's Nov '18 sale of its NZ ops for USD 30 MM to Tamarind was completed 25 Sep '19. The deal involves the USD 30 MM cash, up to USD 5 MM in event specific payments, and 5% orri on any future production from the assets, which comprise TAG’s wholly-owned Taranaki PMP 38156 (Cheal + Cardiff), PMP 53803 (Sidewinder), PMP 60454 (Supplejack), PEP 51153 (Puka), PEP 57065 (Waitoriki) + a 70% interest in PMP 60291 (Cheal East) & PEP 54877 (Cheal East).","Malaysia's Tamarind Resources has signed an agreement to acquire Tag Oil's New Zealand exploration and production assets and operations (average net daily production 1048 boe/d) for US$ 30 MM. Concerning are assets in the onshore and include the Cheal, Cardiff, Sidewinder and Supplejack fields plus the Puka, Waitoriki and Cheal East discoveries."
59153,"Uganda’s 2nd round, open since May, has a application deadline of end Nov ’19. Five blocks totalling 4,928 sq km are on offer (DEAs 13 May, 16 Sep ’19). Promotional meetings are planned in London on 14 October, Houston on 17 October and Dubai on 22 October. Contact: Ikechi Vera Maduako (Schlumberger), email imaduako1@slb.com.","Uganda’s 2nd round, open since May, has a application deadline of end Nov ’19. Five blocks totalling 4,928 sq km are on offer (DEAs 13 May, 16 Sep ’19). Promotional meetings are planned in London on 14 October, Houston on 17 October and Dubai on 22 October"
22436,"On 18 April 2018, Husky Oil farmed out a 27.5% working interest in offshore Jeanne d’Arc Basin exploration license EL 1122 to Suncor Energy. Terms of the transaction were not released. EL 1122 was originally 297.83 sq km when first awarded. Husky relinquished 92.30 sq km of EL 1122 on 12 January 2016, returning roughly the southern third of the block to the government. EL 1122 now contains 205.53 sq km following the relinquishment.  Husky and Statoil were officially awarded EL 1122 effective 15 January 2011. In November 2010, the C-NLOPB announced the preliminarily award of Parcel 2 from the Call for Bids NL10-01 to the two companies for a work commitment bid of CAD 15,150,000. Statoil assigned Husky its 50% interest in EL 1122A and 65% interest in EL 1122C to accomplish the equity transfer, which took effect on 8 December 2015. Husky already had full ownership of the EL 1122B portion of the tract. Having drilled a well within Period 1 of the license’s term, Husky qualified for Period 2 which extended EL 1122 term to its full nine years.","Husky Oil (-> 72,5%) farmed out a 27,5% WI in offshore exploration license EL 1122 to Suncor Energy."
75963,"Sul Gato do Mato_P2 contract, Santos offshore, WD 2,048m, oil shows report to ANP 27 Mar '20, PTD 5,525m, targets Barra Velha + Itapema fm's, spudded 4 Mar '20, Brava Star DS. Shell is also reported to have cleared the procurement of an FPSO on the field capable of handling 90,000 bo/d. Shell (op), partners Ecopetrol + Total.","Sul Gato do Mato_P2 contract, Santos offshore, WD 2,048m, oil shows report to ANP 27 Mar '20, PTD 5,525m, targets Barra Velha + Itapema fm's, "
14439,"On 24 January 2018 the Dutch Ministry reported that partner Dyas transferred its 14% interest in Dana Petroleum’s F6b licence to Oranje-Nassau. Moreover Dana Petroleum submitted an application to convert F6b into a production licence in 2016 and the process is still ongoing. F6b contains three wells - F6-2 (1997 – oil shows), F6-3 (2004 - dry) and F6-4, 4ST1 (2011 – oil shows). The block was part of a farm out offer in 2013 when Tulip was looking to divest its interest in the block after acquiring interest following its acquisition of Smart Energy in 2012. Interest in F6b is held by KNOC through Dana Petroleum Netherlands BV (36% + operator), Energie Beheer Nederland BV (40%), Oranje-Nassau Holdings BV (14%) and Tulip Oil Netherlands BV (10%). .","Dyas has taken 24% interest in licence A15a from Oranje-Nassau Energie (-> 0%, Petrogas E&P 27% + Op, Dana Petr. 9%, EBN 40%)."
63033,"On 4 November 2019, at the Africa Oil Week event in Cape Town, the Ministry of Petroleum, Energy and Renewable Energy of Cote d'Ivoire launched a so-called Petroleum Promotional Campaign, offering five offshore blocks (CI-503, CI-102, CI-800, CI-801 and CI-802) under a call for Expression of Interest (EoI). Any companies interested in these exploration or development assets are invited to submit their EoI until 31 December 2019.  The exploration blocks CI-102 and CI-503 (850 and 315 sqkm, respectively) are located in shallow waters westwards off Abidjan, while CI-800, CI-801 and CI-802 are newly defined blocks that partly encompass Vitol's tracts CI-202, CI-523 and CI-525 that come to a renewal step in December 2019. Vitol's blocks' outlines have consequently been modified, freeing the Ibex, Impala, Ivco and Hippo oil and gas discoveries. Operator Vitol Eastern CDI Ltd (Vitol) and UK-based partner Nomad Energy Ltd (Nomad) were understood to offer substantial interest in these three blocks for long.   Contact : Société Nationale d’Opérations Pétrolières de la Côte d’Ivoire (Petroci)    Immeuble les Hévéas    14, boulevard Carde    BP V 194 Abidjan    Côte d’Ivoire    Tel : +225 20 202 500    Email : info@petroci.ci","On 4 November 2019, at the Africa Oil Week event in Cape Town, the Ministry of Petroleum, Energy and Renewable Energy of Cote d'Ivoire launched a so-called Petroleum Promotional Campaign, offering five offshore blocks (CI-503, CI-102, CI-800, CI-801 and CI-802) under a call for Expression of Interest (EoI). Any companies interested in these exploration or development assets are invited to submit their EoI until 31 December 2019. The exploration blocks CI-102 and CI-503 (850 and 315 sqkm, respectively) are located in shallow waters westwards off Abidjan, while CI-800, CI-801 and CI-802 are newly defined blocks that partly encompass Vitol's tracts CI-202, CI-523 and CI-525 that come to a renewal step in December 2019."
15817,"PetroChina – Sichuan completed an exploration drilling in the Sichuan Basin. Shuangtan 10, an exploration well, located in Shuangyushi prospect in Jiange area, reached a TD of 7,641 m at the Devonian Jinbaoshi Foprmation on 20 February 2018.  Shuangtan 10 was spudded on 22 June 2017 with a PTD of 7,525 m and had objectives in the Permian Qixia and Maokou formations, with second one in the Devonian.  ","PetroChina – Sichuan completed an exploration drilling in the Sichuan Basin. Shuangtan 10, an exploration well, located in Shuangyushi prospect in Jiange area,"
87221,"On 30 July 2020, the Agencia Nacional do Petroleo (ANP) granted formal approval for Petrobras to transfer 100% working interest to Eagle Exploracao de Oleo e Gas Ltda for the Conceicao, Fazenda Matinha, Fazenda Santa Rosa and Querera production concessions in the onshore Tucano Basin. The approval is conditioned to both companies presenting documents with details about the decommission of the fields.  Petrobras had reported on 9 March 2020 the signature of the sales agreement with Eagle Exploracao de Oleo e Gas Ltda for the Tucano Sul cluster of four producing gas fields mentioned above. The total consideration for the sale was USD 3.01 million which was to be paid in two installments, USD 602,000 on 9 March 2020 and USD 2.41 million on the official closing date of the transaction. On 9 July 2019, Petrobras published its teaser to sell the Tucano Sul cluster of four producing gas fields in the onshore Tucano Basin.          Tucano Basin fields   sale - general information             Field Name         Field sqkm         Disc Date Year         Prod Start Date         Avg. cond. Prod.   (bc/d) (Jan-May 2020)         Avg. gas prod.   (Mcfg/d) (Jan-May 2020)             Conceicao         9.8         1967         25-Feb-1970         0.38         486.45             Fazenda Matinha         3.95         1986         05-Apr-2005         0.15         99.16             Fazenda Santa Rosa         4.58         1992         25-Oct-2005         0.45         139.39             Querera         5.4         1962         01-Jul-1962         0.00         44.13             Source: IHS Markit                     ©   2020 IHS Markit","(Tucano B.) the Agencia Nacional do Petroleo (ANP) granted formal approval for Petrobras to transfer 100% working interest to Eagle Exploracao de Oleo e Gas Ltda for the Conceicao, Fazenda Matinha, Fazenda Santa Rosa and Querera production concessions. "
63963,"More news is filtering out over Iran's Namavaran discovery in Khuzestan (DEA 12 Nov '19). The field is touted as Iran's '2nd biggest find', the newly-established reservoir adding 22 Bbo to the known 31.3 Bbo reservoir – total 53 Bbo in-place in an zone thought to comprise the Mansuri, Sepehr, Susangerd and Ab-E-Teimur field areas. Further hope is being placed in exploration of S. parts of the reservoir at the Darkhovein field. Any recovery, thought to be ca. 10%, will be sanction-hampered.","Press has been rife with reports of a super-discovery in Khuzestan, designated Namavaran and assumed made by NIOC. The fields reservoir reportedly sits at a depth of 3100m with an average thickness of approximately 80m. The massive reserves quoted (53 Bbo) are thought to be attributable to parts of the Mansuri, Sepehr, Susangerd and Ab-E-Teimur fields, in the Oligo-Miocene Gachsaran or Asmari Fm's. The new reservoir would feature an already-respectable 22,2 Bbo of additional reserves, assumed to be in-place, possibly ~10% recovery factor."
62317,"Block 06-1, Nam Con Son Basin, ops terminated around 20 Oct '19, Hakuryu 5 SS. Target M-U Miocene Thong clastics. Rosneft (op), partners ONGC-Videsh + PVEP.","Vietnam, Block 06-1"
60758,"East Bahariya Ext.III (Bolt) concession, Abu Gharadiq Basin, W. Desert, P&A (tested, results disappointing) mid-Aug '19, TD 2,529m (Dahab Mb of Burg El Arab fm). Qapetco = EGPC, Apache, Dana, Sinopec JV.",Egypt (Alamein Sub-basin (Northern Egypt B.)) Burg El Arab
50062,"In late May 2019 Oil & Natural Gas Corporation Limited (ONGC) announced through a media release, it has made a gas and condensate discovery within the Suryaraopeta West 1 (SUW AA) new-field wildcat well, located within the Malleswaram ML onshore block (Krishna-Godavari Basin). The well was reported to have flowed around 1.06 MMcfg/d with 40.8 bc/d (interpreted to be condensate) from an unreported Formation.     The well has been assumed to have been both spudded during 2018 late year and suspended during March 2019.      A TD has been estimated to be around 2,900 m from regional drilling activity.    Malleswaram ML covers an area of 232 sq km. It was awarded to ONGC with effect from 22 November 2011.  On 3 November 2018, ONGC reported in its results for Q2 FY2018-19, that it made a new prospect discovery at the Bantumilli North 2 exploratory well, within the Malleswaram ML.     The well reached TD at 3,620 m. During testing, an interval in the      Late Cretaceous Raghavapuram Formation flowed oil at 497 b/d, along with      42.535 Mcm/d (1.502 MMcf/d) of gas. ONGC also noted that the discovery had      already been monetised and that it had opened up the area south of the Suryaraopeta      field for further exploration.   ONGC discovered the nearby Suryaraopeta field in April 2000, with the Suryaraopeta 1 (SUAA) exploration well, which was drilled to a final TD of 2,600 m in late March 2000.     Suryaraopeta 1 was the first well drilled on the Suryaraopeta      structure, in the Bantumilli-Mahadevapatnam area. During testing, a sand      horizon between 2,372-2,374 m in the Cretaceous Raghavapuram Shale      Formation (Object IIA) was reported to have yielded 200 bo/d through a 6      mm choke, opening a new area for exploration.","Suryaraopeta West 1 (exploration well), Malleshwaram ML, Krishna-Godavari Basin- Gas & condensate disc. have flowed around 1.06 MMcfg/d with 40.8 bc/d (interpreted to be condensate) from an unreported Formation. "
45391,"PL 885, WD 230m, TD 2,913m, P&A 25 Mar ’19, w.o. results, Transocean Spitsbergen SS. Target L. Cret Agat sst. Equinor (op), partners Capricorn, Petoro + Wellesley.","036/01-03 (Presto) (Equinor 20% + op. Cairn 30%, Wellesley Petrol. 30%, Petoro 20%) in PL 885 - P&A, results awaited, primarily targeting Early Cretaceous Agat sst with a secondary target in the Late Cretaceous turbidite complexes, and mean gross prospective resources are estimated at 160 MMboe."
47286,"In April 2019 Moesia was still looking for partners for additional funding of its planned operations in the 1-5 Devetaki, 1-7 Tarnak, 1-9 Miziya and 1-10 Botevo exploration permits in northwestern Bulgaria. In April 2018 industry sources reported that a company from the UK was interested in a partnership with Moesia but no more details were communicated.  The company completed the reprocessing of more than 2,000 km of data across all four blocks. Moesia anticipates to re-appraise the Devetaki gas field which produced more than 15 Bcf of gas and condensate at economic rates but was not appraised or developed optimally. The Devetaki field is believed to contain significant incremental volumes and being located adjacent to existing infrastructure it offers near term production potential.  Interest in the four permits are 100% held by Moesia Oil and Gas EOOD.","Moesia was still looking for partners for additional funding of its planned operations in the 1-5 Devetaki, 1-7 Tarnak, 1-9 Miziya and 1-10 Botevo exploration permits in northwestern Bulgaria."
70198,"Believed in Paliyad-Kalol-Limbodra ML, onshore Cambay Basin, drilled Nov-Dec '19, TD 1,750m, some o&g (shows) after testing 'Object I'.","LM XB expl Believed in Paliyad-Kalol-Limbodra ML, onshore Cambay Basin, TD=1,750m, some o&g (shows) after testing 'Object I'."
8833,"Bozhong 36-1-4 (BZ 36-1-4) was suspended in early August 2017, having successfully encountered oil in the target reservoirs. The oil appraisal/exploration well was spudded on or around 12 July 2017 using the ""Bohai 12"" jack-up and was likely targeting the Guantao, Dongying and Shahejie formations. Bozhong 36-1-4 is in the CNOOC operated Qinhuangdao 36 Block in the offshore Bohai Gulf Basin and is approximately 9km W of successful oil well Bozhong 36-1-2, drilled by CNOOC in March 2017. <P />",Not Found
12486,"Oman's Ministry of Oil and Gas has awarded oil concession Block 57 to Lebanon-based company Petroleb. The ministry signed an exploration and production-sharing agreement with the Lebanese firm on Wednesday for developing the Block 57. H E Mohammed bin Hamad al Rumhi, Minister of Oil and Gas, signed the agreement on behalf of the Omani government along with Salah Khayat, chief executive officer of Petroleb. Headquartered in Beirut, Petroleb is an upstream oil and gas company.Location of Block 57 Block 57, also know as Al Afif onshore oil block, lies in the southwestern part of the sultanate and is situated between South Oman Salt Basin and the Rub al Khali Basin. The block is spread across 2,262 sq km. As per the agreement, Petroleb has committed to carrying out geological and geophysical studies along with 3D seismic acquisition and drill wells during exploration periods. Speaking to reporters on the sidelines of a signing ceremony, Khayat said Block 57 would be Petroleb's first investment in Oman. He said, 'The contract has a number of phases and under the first phase, only exploration activities would be conducted. Oil exploration is a capital-intensive business, so there is a sizeable investment involved and we will do it. The money would be primarily spent on seismic activities and drilling one very deep well.' On future prospects of the Block 57, Khayat said, 'We looked at a number of blocks, not just one block. And we believe that we could add value to this particular block. We submitted our technical programme and our bid, and we were awarded this block.' On investments, he declined to reveal details but said it would require millions of dollars to conduct studies and drill wells. Original article link Source: Muscat Daily ",Petroleb (Lebanese upstream o&g company) was awarded onhore Block 57 (Al Afif - 2262km²).
8505,"Mexican President Enrique Pena Nieto on 3 November 2017 said that the Ixachi 1 NFW, in the AE-0032-M-Joachin-02 contract area, discovered initial gross original in place estimates of 1.5 billion boe. The well was reported by Pemex as being the company's largest onshore light oil, gas and condensate discovery in the last 15 years with 3P recoverable reserves that could reach 350 MMboe. Ixachi 1 is located 4km NW of the Mocarroca 1 NFW that discovered oil in 2005. The well should be able to be brought on line quickly, as it is located near existing infrastructure. The Vera Cruz Basin NFW was spudded on 25 January 2017 with a PTD of 7,728m. The well had targets in the Cretaceous. It was spud to explore a possible extension of the Faja de Oro play on Mexico's Gulf Coast. Pena Nieto also said that Ixachi is similar in size to the Talos-operated Zama-1 (Zama-1SON) discovery also made in 2017, located on Block 7 (Contracto CNH-R01-L01-A7/2015). That well tested 28-30 deg API oil & some associated gas and discovered initial gross original oil in place estimates in the range of 1.4 Bbls to 2 Bbls.","Ixachi 1 op. by Pemex (100%) in A-0269-M-Campo Perdiz block, estimated to contain original volumes in place of up to 1,5 billion boe, which could represent recoverable resources of 350 MMboe. Largest Mexican onshore oil find in 15 years."
86782,"On 29 April 2020 Woodside Energy Ltd, a wholly owned subsidiary of Woodside Petroleum Ltd, was awarded retention lease WA-94-R, in the Exmouth Sub-basin, North Carnarvon Basin. The permit has been awarded for a period of five years and is scheduled to expire or be eligible for renewal on 28 April 2025. Work commitments have been assigned for the entirety of the permits validity, for a total estimated expenditure of AUD 100,000. Annual works have been scheduled, including a project feasibility review and a technology review. In the last permit year, an assessment of the appropriateness of preliminary engagement with third party infrastructure owners for the proposed development concept, is also required.  The retention lease has been granted over part of the exploration license WA-430-P, and covers the Ragnar 1A gas discovery, which was made in 2012. The field has estimated 2P recoverable reserves of 385 Bcf of gas and 1.5 MMbbl of condensate. The lease is one of two awarded from the same exploration license on this date, with WA-93-R also awarded.   WA-94-R covers an area of 159.53 sq km and was awarded on 29 April 2020. Participants in the permit are Woodside Energy Ltd (70% interest and operatorship) and Mitsui E&P Australia Pty Ltd (30% interest).","Australia (North Carnarvon B.) WA-430-P (b) op. by WOODSIDE (70%), MITSUI (30%)"
50832,"As of 7 April 2019, Oil Search has completed testing at a total depth of 8,599 ft (2,621 m) on the Pikka B ST1 appraisal well located in state lease ADL 393028 within the southern part of the Pikka Unit. According to a company release the well encountered three Nanushuk Formation sands. A 299 ft (91 m) conventional core was recovered in the Nanushuk Formation. The company said early indications show the core was saturated with oil as in the original hole. The well flowed 2,410 bo/d at a restricted rate due to limitations of the testing equipment. The wellhead pressure was reported at 240 psi. According to the operator based on a final two hour test the well is calculated to flow at a rate of 3,800 bo/d with a flowing pressure of 50 psi at the wellhead.   Oil Search spud the well on 23 January 2019 using the Doyon Arctic Fox drilling rig. The objective of the well is to determine the potential resource volumes in the field this far south of the discovery and to test development conception.  The well is targeting oil pay in the Cretaceous Brookian Nanushuk sandstone in what the company calls the “Nanushuk Fairway”. Acquisition of a conventional core is planned along with a full suite of LWD and/or wireline logs, including fluid sampling where appropriate. A production test is planned for the Pikka B ST1 deviated sidetrack.  The Pikka Unit was formed in June 2015 as a result of exploration drilling of 16 wells over the period from 2012 through 2015 in an area between Kuparuk River and Alpine fields. The original unit was comprised of 63,304 ac (256.2 sq km). Those wells discovered oil in the Nanushuk formation across a 25,000 ac (101 sq km) area at a depth of about 4,100 ft (1,249.7 m). Repsol has since sold a controlling interest in the Pikka Unit acreage to Armstrong Energy LLC which sold its controlling interest to Oil Search who now operates the unit.","Pikka B ST1 appraisal (Oil Search 38,25% op, Repsol 49%, GMT Exploration 12,75%) in state lease ADL 393028 within the southern part of the Pikka Unit, encountered 3 Nanushuk Fm sands (91 m conventional core was recovered). The well flowed 2 410 bo/d at a restricted rate due to limitations of the testing equipment."
31706,"Pancontinental is offering equity in EP 447 (incl. the depleted Walyering gasfield), 1,108 sq km in the Perth Basin. Currently UIL Energy 100% but a 70% farmout of the smaller Walyering asset is being discussed with POG through the Bombora Natural Energy sub. POG contact: John Begg, John.Begg@pancon.com.au.","Pancontinental is offering equity in EP 447 (incl. the depleted Walyering gasfield), 1,108 sq km in the Perth Basin. Currently UIL Energy 100% but a 70% farmout of the smaller Walyering asset is being discussed with POG through the Bombora Natural Energy sub."
40809,"Earlier this month Sonangol EP secured risk service rights to blocks 30, 44, 45, 46, 47 and KON16.  Although Sonangol is the sole holder of these contracts, it is recalled ExxonMobil and Sonangol inked an MoU for joint participation in blocks 30, 44 + 45 and BP, Eni + Equinor are negotiating for a share in blocks 46 + 47.  Block 46 lies over 1,971 sq km within waters disputed by Congo, WD 2,300-3,300m. Block 47 is 2,217 sq km adjacent south of block 46 in the Congo Fan, WD as above. Block 30 lies in the Namibe Basin, 5,000 sq km, WD 300-1,000 m. Block 44: 6,000 sq km in the Angola + Namibe basins, WD 3,000-3,500m. Block 45: 7,100 sq km in WD 2,500-3,000m, Angola Basin. Onshore Kwanza, KON 16 covers 1,000 sq km. Note map scales below vary in the interest of an adequate block outline:","Angola, not found"
24821,"Commitment well in El Qa'a Plain block, Abu Gharadiq Basin, W. Desert, P&A dry end Jun ’18, TD reached 3 June. Target Nukhul fm, Dana (op), partners  Rockhopper + Petroceltic.","Raya 1X (Dana 37,5% op, Petroceltic 37,5%, Rockhopper 25%) in El Qa'a Plain block, P&A dry, Target Nukhul fm,"
33519,"BOFF ML, Bombay offshore, TD 3,454m, tested, ops terminated and JT Angel JU off location 23 Oct ’18.","India, BOFF ML"
14912,"According to reports in mid-February 2018, Pluspetrol has agreed to sell Apco Oil & Gas International along with other assets held by its subsidiary, Pluspetrol Black River, to Vista Oil & Gas for an undisclosed amount. Closing of the transaction is pending on regulatory approvals. Following this purchase, Vista will gain 55% interest and operatorship on Coiron Amargo Norte (115 sq km) and a non-operated 45% interest in the Coiron Amargo Sur Oeste (64 sq km) in Neuquen Basin. In addition, Vista will also obtain participating interest in the Charco del Palenque (184 sq km) and Jarilla Quemada (194 sq km) blocks (both areas formerly part of the Agua Amarga concession), to go with Bajada del Palo (452 sq km) and Entre Lomas (733 sq km) blocks in the basin. The equity will be acquired through the purchase of Pluspetrol’s 40.7% stake in said blocks’ operator Petrolera Entre Lomas SA (PELSA), along with Pluspetrol’s 23% direct ownership in the assets. Following a similar agreement executed with Pampa Energia around the same time (Pluspetrol’s majority partner in PELSA and said blocks), Vista will effectively become the operator of the aforementioned PELSA concessions with 100% interest. Additionally, Vista will also acquire non-operated interest in Sur Rio Deseado Este block in San Jorge Basin, specifically 16.94% in the production side (50 sq km) and reportedly 44% on the exploration side (256 sq km), while the company will also acquire 1.5% non-operated interest in the Acambuco block (1,189 sq km) in Noroeste Basin.","Argentina (Neuquen B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Coiron Amargo Sur Oeste op. by SHELL (45.0%, PLUSPET RS 45.0%, NEUQUEN 10.0%) to be check.Noroeste op. by MEDANITO (100.0%) to be check.Coiron Amargo Norte op. by PLUSPET RS (55.0%, MADALENA 35.0%, NEUQUEN 10.0%) to be check.Entre Lomas op. by PEL SA (43.3544330637%, PLUSPET RS 31.2872650688%, PAMPA EN 25.3583018675%) to be check.Bajada del Palo (CNQ-11 M) op. by PEL SA (43.3544330637%, PLUSPET RS 31.2872650688%, PAMPA EN 25.3583018675%) to be check.Jarilla Quemada op. by PEL SA (43.3544330637%, PLUSPET RS 31.2872650688%, PAMPA EN 25.3583018675%) to be check."
25862,"South Disouq block, onshore Nile Delta Basin, TD 2,390m, encountered ca. 10m of gas pay in the Abu Madi and Kafr el Sheik horizons (average porosity 21.7%), to be completed as producer. Production start-up at SD-1X discovery expected Q4 ’18.  SDX (op), partner IPR.","Disouq South 3 (SD-3X) pos. appr. (SDX 55% op, IPR Egy. 45%) in onshore South Disouq licence, encountered ca. 10m of gas pay in the Abu Madi and Kafr el Sheik horizons (average porosity 21.7%)."
24436,"Aladdin secured sole explo rights to licence M47-B1,B2 on 21 Jun ’18 for 5 years. It covers 305 sq km in the Southeast Turkey Zagros Fold Belt and contains the 1964 Basur oil discovery.","Aladdin secured sole explo rights to licence M47-B1,B2"
81937,"HHE secured sole rights to the Pusztaszer block, 1,326 sq km in the Kiskunság sub-basin, SE Hungary, on 25 Feb '20 for 4+2 years explo. It was released in the 2019 licensing round.",Hungary (Pannonian B.) Pusztaszer op. by HHE (100%)
6953,"Rosneft and the Kurdistan authorities have signed PSCs for 5 production blocks containing some 670 MMbbl recoverable, to be held 80% by Rosneft and presumably 20% by the KRG. The blocks have not been identified. Plans include geological exploration and pilot production starting as early as 2018, which could in turn lead to full devt as of 2021. ",Rosneft (80%) & KRG (20%) have signed PSA for 5 production blocs located in the Kurdish Autonomous Region.
59900,"Enping Sag in PRMB, WD 100m, ops terminated late Sep '19, results n/a, HYSY 943 JU. Target Oligo-Miocene clastics.","China, not found"
20093,"On 23 April 2018, it was reported that Oryx and Total had entered into a farmout agreement providing the transfer of Oryx’s 30% interests in the Haute Mer B permit to Total. The deal is subject to waiver of pre-emptive rights held by other partners and the approval of the government of the Republic of Congo.  Subject to closing, Oryx’s interests will be transferred for a cash consideration of USD 8 million. Total agreed to reimburse Oryx’s costs incurred between 1 January and the date of closing, which will result in a further payment of about USD 5.3 million.  The deal is expected to be closed before the end of June 2018 and the transfer will be deemed to be made with effect from January 2018.  Total E&P Congo was granted operatorship of the permit on 28 June 2013. Working interests are split between Total (34.62 %, operator), Oryx Petroleum (30%), Chevron (20.38 %) and Société Nationale des Pétroles du Congo (SNPC) with 15%.  Background information   The Haute Mer B block was carved out from Total's former 2,175 sq km Haute Mer permit, which expired on 31 December 2002 and was later split up into three sub-blocks, Haute Mer ""A"", ""B"" and ""C"". The contract was signed in July 2009.   Total plans to drill the Cretaceous carbonate Kaki Main Prospect in the southern sector of Haute Mer B permit. Partner Oryx Petroleum has reported that Kaki Main prospective resources are estimated at 121 MMbo unrisked gross (39 MMbo risked). Haute Mer B permit holds multiple large prospects with prospective oil resources of 650 MMb.","On 23 April 2018, it was reported that Oryx and Total had entered into a farmout agreement providing the transfer of Oryx’s 30% interests in the Haute Mer B permit to Total. "
22617,"On 28 June 2017, Block Energy (former Goldcrest Resources) announced the acquisition of an up to 75% stake from Georgia Oil and Gas in Block XIf. The deal amounted to USD 100,000 for an initial 5% working interest, USD 500,000 and USD 1 million in shares for the acquisition of further 20% (upon AIM admission), USD 1 million (aggregated) for additional 25% (upon AIM admission) and 25% by performing two sidetracks on designated wells.  As of May 2018, Block Energy had a 5% stake in Block XIf with an option to increase its stake to 75%.  Block XIf was awarded to Georgia Oil and Gas during the tender organized by the Georgian Government on 22 May 2017. Results of the tender were announced on 26 June 2017.  Block XIf is located east of capital Tbilisi (Kura Basin). It was held by Ninotsminda Oil Company a JV between Blake Oil and Gas and MND until February 2015, when the company relinquished the block. The Block holds the West Rustavi oil field. Cumulative production from the block amounts to approximately 35,400 t (260,000 bbl) of oil since production start in 1988. The Block holds 13 wells and 2D seismic coverage amounts to 20 km.","Block Energy (former Goldcrest Resources) announced the acquisition of an up to 75% stake from Georgia Oil and Gas in Block XIf. The deal amounted to USD 100,000 "
13506,"On 29 January 2018, Repsol with 100% working interest was granted an official award by the ANP for the ES-M-667 block in the offshore Espirito Santo Basin from the ANP Round 14.  ",Repsol with 100% working interest was granted an official award by the ANP for the ES-M-667 block in the offshore Espirito Santo Basin from the ANP Round 14.  
64862,"On 18 November 2019, Smart Oil Investment Ltd completed the sale of 1.04% interest of Block 05/31 PSC in the offshore Bohai Gulf Basin to Northern Offshore Ltd, after having entered into the sale and purchase agreement on 15 July 2019. Under the terms of the agreement, Northern Offshore had acquired a 1.04% participating interest in Block 05/31 PSC for RMB 50 million (US$ 7.08 million). Block 05/31 PSC contains the Caofeidian 1-2 and Caofeidian 2-4 oil discoveries. Following the completion of the deal, rightholders of Block 05/31 PSC are Smart Oil (98.96%, operator) and Northern Offshore (1.04%), with CNOOC having the rights to participate for up a further 51% of any development. <P />","Smart Oil Investment Ltd completed the sale of 1.04% interest of Block 05/31 PSC in the offshore Bohai Gulf Basin to Northern Offshore Ltd, after having entered into the sale and purchase agreement on 15 July 2019. Under the terms of the agreement, Northern Offshore had acquired a 1.04% participating interest in Block 05/31 PSC for RMB 50 million (US$ 7.08 million). Block 05/31 PSC contains the Caofeidian 1-2 and Caofeidian 2-4 oil discoveries. Following the completion of the deal, rightholders of Block 05/31 PSC are Smart Oil (98.96%, operator) and Northern Offshore (1.04%), with CNOOC having the rights to participate for up a further 51% of any development. "
83427,"The government of Guinea Bissau is promoting open exploration acreage through state company Petroguin. The licensing authority is the Ministry of Natural Resources but contracts are negotiated on behalf of the state by Petroguin. Petroguin will hold a stake in every permit. The government intends to have a competitive bidding process for acreage awards but no formal bid rounds are organized.  Interested parties should contact Petroguin:  Caixa Postal 387  Bissau  Director of Marketing and Business Development: Celedonio Placido Vieira  Tel: +245 966 63 80 60  Email: ceplavi@petroguin-ep.com  The available open blocks as of June 2020 are listed in the table below.  Five blocks are available.  There was no change in the list compared to the previous one.  Total open acreage amounts to 25,330 sq km, of which two thirds (17,080 sq km) is onshore and the rest (8,250 sq km) is offshore deep water.           Open blocks                                                    Block   Name            Area   (sq km)            Situation            Block   Basin             Block   2 Onshore            4,993            onshore            Bove-Senegal   Basins (Senegal M.S.G.B.C. Basin)             Block   4 Onshore            4,820            onshore            Bove   Basin             Block   5 Onshore            7,265            onshore            Bove   Basin             Block   5C            2,468            offshore            Senegal (M.S.G.B.C.) Basin             Block   6C            5,783            offshore            Senegal (M.S.G.B.C.) Basin","Guinea-Bissau, not found"
55725,"Oilex has agreed to acquire Holloman Energy’s 48.5% interests in Terra Nova-run PEL 112 + 444, total 2,255 sq km in the Warburton-Eromanga, deal value ab. USD 98,000. Both licences have been recently suspended and this may be renewed.  Plans include a re-assessment of seismic. Terra Nova (op), partner-to-be Oilex.","Oilex  has agreed to acquire Holloman Energy’s 48,5% interests in Terra Nova-run (51,50% op.) PEL 112 + 444, (total 2255km²). "
8925,"S. part of Waitsia field area, permit L1/L2, onshore Perth Basin, compl. Aug ’15 at TD 3,530m, cleanup and testing underway, gauged 38.7 MMcfg/d from the Kingia sst (3,173-3,215m) on 80/64” choke, WHP 1,315 psi for 2.1 hrs. Of note, pay is 30% of that encountered in Waitsia-3 (50 MMcf/d), underling the strong performance of each well. Further testing is planned, after which Waitsia-4 will be flowed. Map: AWE. ","Australia (Perth B.) Waitsia 2 op. by AWE (50.0%, ORIGIN EN 50.0%) in L 01 block"
83439,"Licensing authority is the Ministry of Petroleum.Contracts are normally of concession type, but the Government of The Gambia is open to PSCs if so desired. Rights are normally granted for a six-year exploration period (+10 years) with the state having up to a 15% back-in right. Most of the terms and conditions under the Petroleum Act and Model Contract of 2004, amended in 2007, are negotiable. Licensing is to be through direct negotiations with the country's Petroleum Commission.    Interested companies are invited to contact:    Jerreh Barrow    Commissioner for Petroleum    Ministry of Petroleum & Energy    Petroleum House  Brusubi Roundabout  Bijilo    The Gambia    Tel: +220 996 33 13  E-mail: jrosemax@gmail.com       The available blocks as of June 2020 are understood to be as listed below.   Five blocks are available. There was no change compared to the previous list.   Total open acreage amounts to 15,495 sq km of which 11,443 sq km is onshore and 4,052 sq km is offshore.          Open   blocks                                                    Block   Name            Area   (sq km)            Situation            Block   Basin             Block   A3            1,300            offshore            Senegal   (M.S.G.B.C.) Basin             Block   A4            1,376            offshore            Senegal   (M.S.G.B.C.) Basin             Block   A6            1,376            offshore            Senegal   (M.S.G.B.C.) Basin             Lower   River            6,475            onshore            Senegal   (M.S.G.B.C.) Basin             Upper   River            4,968            onshore            Senegal   (M.S.G.B.C.) Basin","Gambia, not found"
49267,"NW part of AE-0053-2M-Mezcalapa-03 block, onshore Sureste Basin in Tabasco, compl o&g at TD 7,047m mid-May ’19 after testing ab. 800 bo/d + gas from an HPHT reservoir. Targets Cret. (npw) + Jurassic (dpw).","Mexico, not foundQuesqui 1EXP (Pemex 100%) in NW part of AE-0053-2M-Mezcalapa-03 block, onshore in Tabasco, compl o&g at TD 7 047m mid-May ’19 after testing ab. 800 bo/d + gas from an HPHT reservoir. Targets Cret. (npw) + Jurassic (dpw)."
53702,"Correction to yesterday’s DEA: NW part of CNH-R01-L04-A2.CPP/2016, Area 2, DW GoM Perdido area, WD 3,275m, PTD 7,000m, ops terminated in May, now confirmed dry, Rowan Renaissance DS. Total (op), partner ExxonMobil.","Correction to yesterday’s DEA: NW part of CNH-R01-L04-A2.CPP/2016, Area 2, DW GoM Perdido area, WD 3,275m, PTD 7,000m, ops terminated in May, now confirmed dry, Rowan Renaissance DS. Total (op), partner ExxonMobil."
7858,"On 27 October 2017 Petrobras and partners BP and CNODC were granted a preliminary award for being the high bidder of the Peroba block in the 3rd PSC Pre-Salt Bid Round.  Petrobras as operator with 40% working interest exercised its preferential rights for the block and with 40% partner BP and 20% partner CNODC, offered the highest state take of profit oil at 76.96% and USD 607.90 million in total fixed bonus to be paid to the Brazilian government based on the USD to BRL exchange rate of the day of 1USD/3.29 BRL.  There were two other bids for the block representing the most contested block in the round.  There was a close 2nd place bid for the block by the consortium of Petrobras (30%), ExxonMobil (50%), and Statoil (20%) offering a state take bid of 65.64%.   There was a 3rd place bid for the block by the consortium of Petrobras (30%), CNOOC (20%), QPI (20%), and Shell (30%) offering a state take bid of 61.07%.  The PSC contract has a seven year exploration-evaluation phase and the minimum work program is to drill one exploration well. The minimum financial guaranty for the three year period is USD 47.95 million which is less than the estimated cost of drilling a pre-salt exploration well.  ","Petrobras (40%), BP (40%), CNOOC (20%) prelim. awarded Peroba block during 3rd PSC Pre-Salt deepwater round. "
27704,"WA-437-P, Greater Phoenix area in N. Carnarvon Basin (Bedout), oil volumes assessment complete, 171 MMbo 2C represents one of the most significant finds on the NW Shelf, 552 Bcf gas + 16 MMbc 2C also established. It is recalled light oil was discovered in the Crespin (22m net) and Milne (18m net) members, adding to oil in the Caley member and gas/cond in the Baxter member, 132m net hc pay. Ensco 107 JU. Quadrant (op), partner Carnarvon. Table below Carnarvon:","Dorado 1 (Quadrant 80% op, Carnarvon 20%) in WA-437-P (Greater Phoenix area), oil volumes assessment complete, 171 MMbo 2C represents one of the most significant finds on the NW Shelf, 552 Bcf gas + 16 MMbc 2C also established. It is recalled light oil was discovered in the Crespin (22m net) and Milne (18m net) members, adding to oil in the Caley member and gas/cond in the Baxter member, 132m net hc pay."
78640,"LF 9-8-1 completed in late April 2020 without result reported.  CNOOC – Shenzhen spudded a NFW in the PRMB Basin, South China Sea, on 28 March 2020. LF 9-8-1, located in the Lufeng Sag in a water depth of 150 m area, has target in the Mio-Oligocene clastic play. “Nanhai 2” S/S is used of the drilling operation.   In 2019 CNOOC made a oil discovery, LF 9-4-1, in this area.  In addition, CNOOC drilled LF 9-6-1 in 2017 as a dry hole and drilled LF 9-2-1 in 2003 also without success in this area.   The Lufeng Sag is one of the important exploration focuses for CNOOC in the Pearl River Mouth Basin. For the past few years extensive drilling progress has been carried out.  In 2019, CNOOC also made an oil discovery LF 7-10-1d.  In 2018, SK Innovation made LF 12-3-1 discovery. The well was drilled to a TD of 2,014 m and encountered 34.8 m net oil pay. Test rates from the well was up to 3,750 bo/d from the Lower Miocene Zhujiang Formation.  In 2017 CNOOC made discovery in LF 14-8-1 and tested oil from the Oligocene Enping Formation.   In 2014 CNOOC made discovery of LF 8-1-1 and LF 14-4-1. LF 14-4-1 penetrated about 150 m of oil pay and tested 1,320 b/d of oil from the Lower Tertiary Zhuhai Formation.   In 2019, CNOOC is preparing to launch a new overall development plan for Lufeng oil fields cluster in the South China Sea oil fields cluster.  The Lufeng oil fields cluster, including Lufeng 14-4/14-8/8-1, Lufeng 15-1 and Lufeng 22-1, lies in the east or southeast part of the existing Lufeng oil fields group Lufeng 7-2 and Lufeng 13-1 fields. The Lufeng 22-1 field SPS will be connected to the drilling/production platform in the Lufeng 15-1 field via a 19 km of pipeline. A drilling/production platform will be built in the Lufeng 14-4 field and linked with the platform in the Lufeng 15-1 field via a 23.8 km pipeline.  Background Information  There are several fields on production in the Lufeng Sag:   LF 7-2 field is operated by Newfield and it was on stream in 2014. The field is producing from the Zhujiang reservoir at a rate of 23,500 b/d of oil in 2016.   LF 13-2 field, operated by CNOOC, also has reservoir in the Zhujiang Formation and on stream in 2006. It is produced at a rate of 6,400 b/d of oil in 2016.   LF 13-1 field has primary reservoir in the Zhujiang Formation and secondary one in the Oligocene Enping Formation. The field has been producing since 1993 and produced 16,000 b/d of oil in 2016.   LF 22-1 field - The field was officially shut down in June 2009 after nearly 12 years production as the field depletion.",China (Zhu-1 Depression (Pearl River Mouth B.)) Lufeng 13-1
31751,"DNO has agreed a deal with Chevron to acquire the latter’s 20% interest in PL 859 (Korpfjell) in the northeastern area of the Barents Sea, close to the border with Russia. This is Chevron’s last remaining licence on the NCS and it is understood (from reports in the Press) that the company will subsequently close its Norwegian office. It did not apply for any acreage in the APA 2018 bidding round which closed in September 2018. The deal to transfer the licence is awaiting government approval.  PL 859 is operated by Equinor. The company will return to the licence in 2019 to drill a second well on the Korpfjell prospect (Korpfjell Deep). 7335/3-1 will be located approximately 8 km south of the first Korpfjell well and has a planned TD of 4,300 m. The objectives are the Jurassic / Triassic Realgrunnen Group, the Triassic Kobbe Formation, the Lower Triassic Havert Formation and the Lower Triassic Induan Formation. The well will also investigate the deep Upper Permian Orret Formation source. According to partner Lundin, potential reserves are 201 MMboe but chance of success is just 8%  The hotly-anticipated 2017 Korpfjell exploration well 7435/12-1 proved a 34 m gas column in the Lower-Middle Jurassic Sto Formation with estimated recoverable reserves of 212-424 Bcfg (40-75 MMboe) which in this location is non-commercial. The prospect was mapped with a closure of 850 sq km, which is 3-4 times the closure of Johan Sverdrup, and it was the first well to be drilled in the recently awarded 23rd Round acreage.","DNO has reached agreement with Chevron to bay it’s 20% interest (only asset in the country) in PL 859 (Korpfjell) licence (Equinor op. 30%, Petoro 20%, Lundin 15%, ConocoPhillips 15%)."
22833,"Shell has joined the Eurasia project, while Rosneft has quit it. This was announced by the KMG-Eurasia (a KazMunayGaz company) chief executive at the end of May. The project will remain open to new participants till the end of 2018. Reasons for Rosneft leaving the project have not been publicised.  The Eurasia Project aims to explore the Precaspian Basin’s deep petroleum potential by initially collecting and analysing all the available information, carrying out a series of regional seismic surveys and eventually drilling a 15 km deep well. The project is expected to run for 5 years. Its preliminary cost is estimated at USD 500 mln.  The Eurasia Project’s concept was originally unveiled in Kazakhstan in 2013. In June 2017, the Kazakhstan Ministry of Energy, the Geological Committee (part of the Ministry for Investment and Development), KMG-Eurasia, Agip Caspian Sea, RN-Exploration (Rosneft), CNPC, SOCAR and NEOS Geosolutions signed a memorandum of understanding within the framework of the Eurasia Project. The parties to the MOU had agreed to conduct exclusive negotiations on the main commercial, technical and contractual terms and conditions of the project implementation with a view to conclude a contract for the geological exploration of the Precaspian Basin in accordance with Kazakhstan legislation.  The Precaspian Basin falls into the territories of Kazakhstan and Russia and the project is supported by the governments of both countries. Their authorised bodies have expressed intent to exchange geological information and to co-ordinate work in order to carry out exploration activities on the same technological basis.","Shell has joined the Eurasia project, while Rosneft has quit it. This was announced by the KMG-Eurasia (a KazMunayGaz company) chief executive at the end of May. The project will remain open to new participants till the end of 2018."
26783,"In late July 2018, Fieldwood Energy acquired Marathon Oil's entire 18.2308% WI in five Mississippi Canyon blocks, which encompass the Gunflint Field (previously known as Freedom Field): MC 904 (G33182), MC 948 (G28030), MC 949 (G32363), MC 992 (G24133), MC 993 (G24134). Gunflint, which was discovered in 2008, contains stacked Middle Miocene age reservoirs between depths of 7,254-8,230m TVDss. A mixture of black oil, rich gas condensate, and dry gas have been encountered in seven reservoirs. Only three oil reservoirs, Green B, Green C, and Blue E, are considered commercially viable for development. Reservoir pressures and temperatures range from 17,000 to 19,000 psi and from 210 to 240degF, respectively. Petrophysical analysis determined that the primary reservoir sands are high-quality sandstones with good permeability. Following completion of the transaction, which is effective as of 1 April 2018, equity in MC 904, MC 948, MC 949, MC 992 (northern half) and MC 993 (northern half) is now shared between Fieldwood Energy (49.3726% WI + Op), Ecopetrol America (31.5%) and Samson Offshore Mapleleaf (19.1274%).","Fieldwood Energy acquired Marathon Oil’s entire 18,2 % WI in 5 Mississippi Canyon blocks, which encompass the Gunflint Field (previously known as Freedom Field): MC 904 (G33182), MC 948 (G28030), MC 949 (G32363), MC 992 (G24133), MC 993 (G24134)."
65102,"Corallian Energy is looking for farm-in partners for two UK licences awarded in the 31st UK Licensing Round. In the Northern North Sea it is offering equity in licence P2464 (block 3/12b) which hosts the Unst gas prospect and in the Moray Firth it is offering interest in P2478 (blocks 17/5, 18/1 and 18/2) which houses the Dunrobin prospect. Unst is an Eocene Frigg sandstone prospect which is seismically amplitude supported and is analogous to the Nuggets field. Unst is thought to hold 68 Bcf of gas. The Dunrobin prospect has a Beatrice Formation and Dunrobin Bay Group sandstone target. The prospect is estimated to hold 187 MMboe.   Interest in P2478 is held by Corallian Energy Limited (45% + operator), Upland Resources (UK Onshore) Limited (40%) and Baron Oil Plc (15%). Interest in P2464 is held by solely by Corallian Energy Limited.","Corallian Energy is looking for farm-in partners for two UK licences awarded in the 31st UK Licensing Round. In the Northern North Sea it is offering equity in licence P2464 (block 3/12b) which hosts the Unst gas prospect and in the Moray Firth it is offering interest in P2478 (blocks 17/5, 18/1 and 18/2) which houses the Dunrobin prospect."
56086,"Mubarek investment block, SW of Darbaza Shimoliy field in Amu-Darya Basin, spudded 2 Jun ’19, en route to PTD 3,000m, tested 342 Mcfg/d + some condensate at 2,445m, oil rate (also tested apparently) not specified. ZJ-50 rig.",Uzbekistan (North Amu-Darya Sub-basin (Amu-Darya B.)) Darbaza Shimoliy
48770,"In mid-March 2019, Apache Corporation abandoned the Kalabsha West Ebni North 1 (Ie 007-1) exploration well in the West Kalabsha exploration block at a TD of 4,612 m in the Carboniferous Dhiffah formation. The well was spudded on 18 February 2019 using the “EDC-54” land rig. It had a planned TD of 4,420 m and the Lower Cretaceous Alam El Bueib 3A, 6, 3G and 3C units as the objectives.  The West Kalabsha exploration block is operated by Apache Oil Egypt (67%) and Sinopec International Petroleum E&P Corp (33%).   Background Information  The area of the West Kalabsha block was previously held by Epedeco Sallum as part of a larger block called Sallum relinquished in November 1999. The Sallum block extended to the border with Libya and to the Mediterranean coastline. Epedeco recorded 1,181 km of 2D seismic data in the last quarter of 1996. The company drilled one well in the area which become West Kalabsha.   In early June 2004, Apache was assigned the West Kalabsha exploration block covering 2,714 sq km in the Northern Egypt Basin. The block was offered under the terms of the 2003 bid round.","Apache Corporation abandoned the Kalabsha West Ebni North 1 (Ie 007-1) exploration well in the West Kalabsha exploration block at a TD of 4,612 m in the Carboniferous Dhiffah formation."
76486,"At last a piece of welcome news: deepwater block 58, TD 6,300m, 79m net o&g pay in multiple intvs in Campanian (13m net gas-cond + 30m net oil, 35-40 API) and deeper Santonian (36m net oil reservoir, 40-45 API) in what is thought to be a distinct fan system separate from the recent Maka Central-1 find. Noble Sam Croft DS then to Kwaskwasi-1 10km NW of the above and onwards to Keskesi-1 (20km SE). Apache (op), partner Total (Apache operates the 1st 3 explo wells [as of Maka Central] and Total beyond). Release and map here.",Suriname (Guyana B.) Maka Central 1
17418,"Sapura Exploration and Production (NZ) ('Sapura E&P'), a wholly-owned subsidiary of Sapura Energy, has made inroads into New Zealand with a series of farm-in agreements to five offshore exploration permits within the Taranaki Basin, a prolific oil and gas region.The farm-in agreements, which has secured the New Zealand government approval, are with OMV New Zealand and Mitsui E&P Australia.'We are excited about our entry into New Zealand which may open up opportunities in a proven area for Sapura E&P,' said Tan Sri Dato’ Seri Shahril Shamsuddin, President & Group CEO, Sapura Energy Berhad, a global integrated oil and gas services company.'This is a strategic entry for Sapura E&P and we will be working with our partners to mature potential drilling locations prior to making well commitments. The joint venture will see Sapura E&P utilising its sub-surface technical expertise to support the exploration activities within these exploration areas,' he added.All five offshore exploration permits are located in shallow water within the prolific oil and gas region of the Taranaki Basin, where discovered volumes to date total more than 2.5 billion barrels of oil equivalent. The agreement provides access to a large acreage footprint of more than 8,900 sq kms.The offshore exploration permits comprise PEP 57075, PEP 51906, PEP 60091, PEP 60092 and PEP 60093.OMV is one of the country’s largest liquid hydrocarbon producers, the third largest gas producer and a major explorer in a number of offshore basins around New Zealand, particularly the Taranaki Basin. It is an experienced operator and has been active in New Zealand since 1999.Sapura E&P has a 30% interest in all five exploration permits, which will be operated by OMV New Zealand. The participating interests of PEP 57075 and PEP 51906 are held by Sapura E&P (30%) and OMV (70%) whilst participating interests of PEP 60091, PEP 60092 and PEP 60093 are held by Sapura E&P (30%), OMV (40%) and Mitsui E&P Australia (30%).Original article linkSource: Sapura Energy","Sapura E&P signed farm-in agreements with OMV and Mitsui E&P over 5 offsh. shallow water permits, comprise: PEP 57075, PEP 51906, PEP 60091, PEP 60092 and PEP 60093. The participating interests of PEP 57075 and PEP 51906 are held by Sapura (30%) and OMV 70% whilst participating interests of PEP 60091, PEP 60092 and PEP 60093 are held by Sapura 30%, OMV 40% and Mitsui 30%. All 5 exploration permits will be operated by OMV."
34232,"OMV has agreed to sell its OMV Tunisia Upstream GmbH subsidiary to Panoro Energy. Involved area a 49% stake in the Cercina/Cercina Sud, El Aïn/Gremda, El Hajeb/Guebiba and Rhemoura blocks and 50% in the Thyna Petroleum Services S.A. Operating Company (TPS). The agreed purchase price is USD 65 MM, subject to closing adjustments, to be retro-effective 1 Jan ‘18. ETAP retains the balance in all rights. OMV retains the Nawara devt rights in S. Tunisia (ref. DEA 24 Feb ’17).","Panoro will acquire 49% interests in the Cercina/Cercina Sud, El Ain/Gremda, El Hajeb/Guebiba and Rhemoura concessions from OMV for US$65 MM. The remaining stakes in the concessions continue to be held by Etap."
77687,"Neptune Energy is gaining a 15% stake in fallow block exploration area F03b, following an application from KNOC subsidiary Dana Petroleum in early February 2019. Dana Petroleum will operate the F03b fallow block (290 sq km) and is considering an exploration well in early 2021. Dana Petroleum submitted a fallow block activity plan on 29 June 2018. The fallow block application excludes the F03-FB Field area on the SW of the licence, currently 334 sq km which is operated by Neptune Energy. Under the Dutch 'Offshore Covenant', the holder of a licence can voluntarily surrender all or part of the acreage to a partner or third party, once prompted by the minister. F03b was awarded on 13 December 2007, and contains the E part of F03-FB oil field in Late Jurassic (Oxfordian) Upper Graben Formation, which was discovered in 1974 and commenced production in 1993. It lies adjacent to the SW of F03a which holds the F03-FA Field, operated by Spirit Energy, and is immediately W of the German border. The fallow block application acreage contains two dry NFWs drilled by NAM in 1971 and 1976. F03b partners are Neptune Energy Netherlands BV (36.6% + Op), TAQA Offshore BV (23.4%) and Energie Beheer Nederland (EBN, 40%).<P />",Neptune Energy is gaining a 15% stake in fallow block exploration area F/03b.
30833,"On 25 August 2018 DEA used the “Island Innovator” S/S to spud exploration well 7321/4-1. The well targeted the Graspett prospect in PL 721, located in the Fingerjupet Sub-basin to the northeast of Pingvin and northwest of Wisting. The objectives were the Jurassic Sto Formation (mapped at 1,422 m) and the Triassic Snadd Formation (expected at 1,589 m), with oil and a gas cap prognosed for both reservoirs. According to partner Aker BP Graspett had potential reserves of 32-263 MMboe. 7321/4-1 reached TD at 1,630 m in the Snadd Formation and is a dry hole. Water-wet sands were encountered in both the Sto (15 m) and Snaddd (32 m) formations and reservoir quality was poor. The well is being abandoned on 28 September 2018.  Statoil’s Pingvin well 7319/12-1 was drilled in 2014 to a TD of 1,540 m. It had shallow Cretaceous / Tertiary targets with a sand body defined by a strong amplitude anomaly. The well proved a 14 m gas column in a good quality, 30 m thick, Lower Paleocene Torsk Formation reservoir at 953 m. Recoverable reserves were estimated at 177-706 Bcfg (30-120 MMboe) which in this location is non-commercial.  OMV discovered Wisting in 2013 with exploration well 7324/8-1 which proved a 50 - 60 m oil column in the Jurassic Realgrunnen Group. This was the first oil discovery in the Hoop area of the Barents Sea and confirmed a new play. Appraisal well 7324/7-3 S was drilled in 2016, targeting the Wisting Central South and Wisting Central West segments, and encountered hydrocarbons in both the Sto and Fruholmen formations. This was followed by 7324/8-3 in 2017 which also confirmed a 55 m oil column in the Sto and Fruholmen formations. As of December 2016 the NPD reports recoverable reserves of 355 MMboe but an updated reserves estimate is expected from OMV as a result of the latest well.    Interest in PL 721 is held by DEA Norge AS (40% + operator), Aker BP ASA (40%) and Wintershall Norge AS (20%).","7321/04-01 (Gråspett) (DEA op 40%, Aker BP 40%, Wintershall 20%) in PL 721 NW of Wisting, P&A target Stø + Snadd fm’s both found dry. WD=499m, TD=1600m."
32581,"i3 Energy continues to seek partners to support the development of the Liberator oil field in P1987 and will also likely farm down the planned Liberator West appraisal on adjacent P2358, with spud expected in Q4 2018. i3 operates both licences with 100% equity and had previously reported a 90 day period of exclusivity with an unnamed party, which has now ended without a firm agreement. i3 is seeking cash consideration plus promoted development carry of i3 for Liberator. Funding requirement to first oil is US$ 45 million and the Liberator Field Development Plan (FDP) was submitted on 2 October 2017, with approval anticipated in Q1 2019. Liberator was discovered by 13/23d-8 (2013, Dana (KNOC)), which revealed 7.3m of net pay at the top of a 96 meter, high quality Lower Cretaceous Captain Sands reservoir. The Liberator field has preliminary estimated recoverable resources of 10 to 15 MMbo, and is located within block 13/23d, 64km from the south Moray coast in the Moray Firth's South Halibut Basin. The Liberator Phase 1 field development proposal is for two wells with one close to the existing manifold at Repsol Sinopec-operated Blake field and the other 2km from the Blake manifold. Fluids produced from Liberator will be co-mingled with those from the Blake field and processed by the Repsol Sinopec operated Bleo Holm FPSO. Field life is envisaged to be seven years until the end of the approved contract for Bleo Holm FPSO on Blake field. Production is expected to be approximately 9,500 bo/d and 2.5 MMcfg/d, with a 2020 peak of 15,000 bo/d and 3.7 MMcfg/d. Contact: Jonathan Wright or David van Erp at GMP FirstEnergy, Tel: +44(0)2074480200","i3 Energy continues to seek partners to support the development of the Liberator oil field in P1987 and will also likely farm down the planned Liberator West appraisal on adjacent P2358, with spud expected in Q4 2018. i3 operates both licences with 100% equity and had previously reported a 90 day period of exclusivity with an unnamed party, which has now ended without a firm agreement. i3 is seeking cash consideration plus promoted development carry of i3 for Liberator. Funding requirement to first oil is US$ 45 million and the Liberator Field Development Plan (FDP) was submitted on 2 October 2017, with approval anticipated in Q1 2019. Liberator was discovered by 13/23d-8 (2013, Dana (KNOC)), which revealed 7.3m of net pay at the top of a 96 meter, high quality Lower Cretaceous Captain Sands reservoir. "
8886,"On 8 November 2017, Tullow Oil plc reported that it has completed the appraisal well well Ngamia 11, Ngamia field, Block 10BB. The well is believed to have been spudded end September 2017 with the “Marriott PR 46” rig. The well encountered 143 m of net oil pay. Ngamia 11was completed and will be used in an extended water flood pilot test in conjunction with the Early Oil Pilot Scheme (EOPS) in the first half of 2018. The Block 10BB is operated by Tullow (50%) in partnership with Africa Oil (25%) and Maersk Oil and Gas (25%).","Kenya (East African Rift System, Eastern Branch) Ngamia 11 op. by TULLOW (50.0%, MAERSK 25.0%, AFRICA OIL 25.0%) in Block 10BB"
74916,"As of mid-March 2020, it is understood that Exxon is negotiating directly for three additional blocks within the Namibe basin. Its currently unclear which blocks are being negotiated for, but they will be blocks that were not awarded during the 2019 licencing round, these would include: Blocks 10, 11, 12, 13, 41, 42 and 43.  Sources have indicated that Exxon will operate the blocks with a 60% stake, Sonangol will hold the remainder and be carried through exploration.   Its worth noting that if and when Exxon is awarded the 3 additional blocks, it will hold the vast majority of acreage within the Angolan portion of the basin and all the acreage within the Namibian portion of the basin.","Angola, not found"
81454,"In late May 2020, Tomskneft-VNK reported the discovery of a new oil pool at the Pavlovskoye field in Tomsk Oblast (Western Siberia). New-pool wildcat Pavlovskaya 8, drilled in 2019, tested oil from reservoir Vasyugan Formation Unit Yu1/3+4 (Oxfordian) in the eastern part of the field. Recoverable oil reserves of the pool are estimated at 3.7 MMbl of 2P and 6.6 MMbbl of 3P.   Before the reported pool, reserves of Pavlovskoye located in the Karaysko-Moiseyevskiy license (Kaymys-Vasyugan Province) were estimated at 10 MMbbl of 2P and 11.5 MMbbl of 3P. Tomskneft-VNK is equally owned by Gazprom Neft and Rosneft.","Russia (Volga-Urals B.) Pavlovskoya 8 op. by LUKOIL (100%) in Pavlovskoye block , npw in Pavlovskoye field area in licence Karaysko-Moiseyevskiy, Kaymys-Vasyugan Province, Tomsk Oblast. 2019 well, now reported to have tested oil from the Vasyugan Fm Unit Yu1/3+4 reservoir in the E. part of field. Recoverable oil est. 3.7 MMbo of 2P / 6.6 MMbo 3P."
20350,"Ancap declared Uruguay’s 3rd offshore round void, no offers having been received by the 26 April deadline. Tullow and AziLat had reportedly filed to qualify as operators, but no offers were eventually received.","Ancap declared Uruguay’s 3rd offshore round void, no offers having been received by the 26 April deadline. Tullow and AziLat had reportedly filed to qualify as operators, but no offers were eventually received."
57220,"Petrobras was drilling with oil shows on the 3-SES-193 (3-BRSA-1368-SES) outpost in the BM-SEAL-004 block during late-August 2019.  The operator filed a show report with the ANP for the well on 22 August 2019.      The outpost was spudded on 20 June 2019.       The well has a proposed total depth (PTD) of 5,609 m.       The Late Cretaceous      to Tertiary Calumbi Formation is the main objective.     Petrobras is utilizing the “Petrobras 10000” D/S to drill the      well in a water depth of 2,647 m.          The      outpost is located in the southern area of the block approximately 4.8 km      west of the 3-BRSA-1194-SES outpost well for the Moita Bonita prospect      located in the south-easterly adjoining SEAL-M-499 block.        Petrobras is operator of the BM-SEAL-004 contract with a 75%      working interest and ONGC is the lone partner with 25% working interest.","3-SES-193 (3-BRSA-1368-SES) (Petrobras 75%, ONGC 25%) in the BM-SEAL-004 block P&A with oil shows."
74296,"The sale of Capricorn Norge to Solveig (now Sval Energi) was completed late Feb '20 and retro-effective 1 Jan '20. 15 licences (3 operated) are involved in the move, plus 3 operated under the APA 2019 round awarded this month.",Cairn has agreed with Solveig Gas to sell the latter its Norwegian subsidiary Capricorn Norge AS for US$100 MM.
26964,"Cooper-Eromanga Basin, 12 sq km, awarded 4 Jun ’18 for 15 years, encompasses successful Cuisinier-19 appr well. Santos (op), Bengal Energy and Bridgeport.","Cooper-Eromanga Basin, 12 sq km, awarded 4 Jun ’18 for 15 years, encompasses successful Cuisinier-19 appr well. Santos (op), Bengal Energy and Bridgeport."
66577,"Oil and Gas Development Company Ltd (OGDCL) has been exclusively awarded the Shakar Ganj West 3072-8 EL (Indus Basin) exploration licence on 18 November 2019. The licence covers an area of 2,479 sq km and it is located in the Pakpattan, Bahawalnagar, Vehari and Sahiwal districts of Punjab province. The block was offered under the ‘Onshore Bid Round 2018’ and it is awarded to OGDCL after the highest bid from SPEC was rejected by the government.  The bidding round was launched from 13 September 2018 to 26 November 2018 under which 10 onshore blocks were offered.",OGDCL has been exclusively awarded the Cholistan 2972-6 EL and Shakar Ganj West 3072-8 EL exploration licence.
56779,"Barents PL 855, NW of Wisting find in WD 449m, TVD 1,569m, encountered poor reservoir quality sands in various parts of the Snadd fm and 20m of good quality sands in the Sto fm, discovery size estimated at 19 – 63 MMbbbl of oil. Equinor (op), partners OMV + Petoro. West Hercules SS now drilling Lanterna well in PL 796 B (see DEA 8 Aug ’19), also for Equinor.","7324/06-01 (Sputnik) (Equinor 55% op. OMV 25%, Petoro  20%) in PL 855, P&A, oil disc. encountered poor reservoir quality sands in various parts of the Snadd Fm and 20m of good quality aquiferous sands in the Sto Fm, discovery size estimated at 19 – 63 MMbbbl of oil. Fluid samples from the well contained light oil and water. TD=1569m, WD=449m."
71897,"Block 12, Al Muthanna + Najaf prov. in S. Iraq, ops terminated mid-Jan '20. Salman-3 appr is planned later this year.","Salman-2 appr Block 12, Al Muthanna + Najaf prov. in S. Iraq, ops terminated mid-Jan '20. "
66984,"In October 2019, East Zeit Petroleum Co (ZEITCO) was awaiting to test its Wadi Dara South 2ST well at the Wadi Dara South 1 discovery, S. Wadi Dara (Dev) block, Gulf of Suez Basin.  The well was sidetracked from Wadi Dara South 2 in order to assess the Burdigalian Rudeis Formation. It was spudded in mid-2019 and drilled to a TD of 2,995 m.  The Wadi Dara South 1 discovery was found in August 2017 after the new field wildcat Wadi Dara South 1 tested oil in the Langhian-Lower Serravallian Kareem Formation at around 2,900 m depth.  The S. Wadi Dara (Dev) block is a 7.3 sq km acreage granted to ZEITCO in April 2018.  ZEITCO is a JV between EGPC (50%) and Dana Petroleum East Zeit Ltd (50%).","East Zeit Petroleum Co (ZEITCO) was awaiting to test its Wadi Dara South 2ST well at the Wadi Dara South 1 discovery, S. Wadi Dara (Dev) block, Gulf of Suez Basin. The well was sidetracked from Wadi Dara South 2 in order to assess the Burdigalian Rudeis Formation."
27058,"Zhahaquan field area, Qaidam Basin, flowed 58 b/d of oil from Upper Ganchaigou fm following fracking in late Jul ’18. Background from GEPS.","China Oil: Zha-17 appr, Zhahaquan field area, Qaidam Basin, flowed 58 b/d of oil from Upper Ganchaigou fm following fracking in late Jul ’18."
14492,"On 1 February 2018 the Dutch Ministry reported that Total transferred its 30% interest in the K1c block to ENGIE. The block is situated in the western part of the country’s offshore area, about 8 km east of the maritime border with the UK. Three wells were drilled in the block: K1-1, K1-2 and K1-5. The K1-1 exploration well was spudded by NAM in August 1979 and junked in September 1979. It was drilled to a total depth of 1,850 m bottoming in the Turonian to Maastrichtian Ommelanden Chalk Fm. The same year the company drilled the K1-2 exploration well which was abandoned with gas shows at a total depth of 4,536 m. In 2006 Wintershall drilled the K1-5 exploration well. The hole reached a total depth of 3,842 m and was abandoned dry. Interest in the block is held by ENGIE E&P Nederland BV (60% + operator) and Energie Beheer Nederland BV (40%).",Total (30%) has exited licence K01c to operator ENGIE (->60% + Op) and Energie Beheer Nederland (EBN) (40%).
59871,"Whalsay Energy Limited is offering the opportunity for interested partners to farm-in to licence P1078 which contains the heavy oil Bentley field. Whalsay Energy, which holds 100% interest in the field, is looking for a partner(s) to farm-in, take operatorship and move the field through to development. Bentley lies in block 9/3b in the Northern North Sea. It was discovered in 1977 by Amoco with well 9/3-1. The proposed development comprises a standalone development concept, initially targeting the core area of the field. The platform would likely have a 20 well slot design and conventional topside fluid handling facilities based on some of the UK's heavy oil field analogues (Kraken and Mariner) with processing and blending of Bentley crude to export specification. Production capacity would be designed to 45,000 bo/d and 180,000 bw/d. The platform would be connected to a leased Floating Storage and Offloading unit. The 20 wells would likely include 17 dual lateral and Electronic Submersible Pump (ESP) producing wells and three water-injectors. All produced oil will be exported via shuttle tanker. The full field is thought to hold P50 resources of 912 MMbo with the Phase I core area holding 578 MMbo of that. Reserves from Phase I are thought to be 131 MMbo in the P50 case. Cost to first oil is estimated to be USD 729 million at an oil price of USD 60/bbl (Brent). The economic field life is planned to be 35 years. Whalsay Energy see incremental projects as well in the area and is offering flexible farm-out terms.   Bentley is a four-way dip closure with reservoirs in the Dornoch Sandstone Formation and in the Upper Paleocene and Lower Eocene. Porosities of 34% have been seen within the reservoirs and in-situ viscosities of 1,500 cP at a reservoir temperature of 37.5°C have been recorded. An oil leg of 120 ft has been proven from the wells, reaching up to 200 ft on seismic interpretation. Xcite was awarded the Bentley block in 2003 under the promote licence scheme and converted it into a Traditional Licence in 2005. The field is classed as heavy with API values ranging from 10 to 12 degrees. Xcite first appraised Bentley in 2007 with well 9/3b-5 which was tested and flowed to surface. Following this well Xcite drilled 9/3b-6 and 6Z which again were successful and proved commercial flow-rates of 2,900 bo/d. In September 2012 Xcite completed a pre-production test with two horizontal wells 9/3b-7 and 7Z. Well 9/3b-7 was drilled into the reservoir close to the OWC to enable water production during the test and the sidetrack was geo-steered for a distance of 2,000 ft (610 m) close to the top of the reservoir. Control valves were installed to control flow from each well. The results of the test highlighted a number of key factors in the analysis of the reservoir and the fluid characteristics. During the test less water was produced than expected, impacting the ratio of oil to water produced and in-turn improving modelling on long-term oil production. The 68 day test produced a total of 148,599 bo that was sold to a refiner in Europe. In 2017 the nearby EnQuest operated Kraken field came onstream and in 2019, also in Quad 9, we have seen Equinor's heavy oil field Mariner also come onstream.   Whalsay Energy Limited holds 100% interest in P1078.  For further information on the opportunity please contact:  Jon Fitzpatrick – jon.fitzpatrick@gneissenergy.com (+44 7780 708900)  Paul Weidman – paul.weidman@gneissenergy.com (+44 7717 426958)  Rosemary Johnson-Sabine – rosemary.johnson-sabine@gneissenergy.com (+44 7565 087386)","Whalsay Energy Limited is offering the opportunity for interested partners to farm-in to licence P1078 which contains the heavy oil Bentley field. Whalsay Energy, which holds 100% interest in the field, is looking for a partner(s) to farm-in, take operatorship and move the field through to development. "
83723,"Add. DEA 22 Jun '20: Saturno pre-salt area, E. of Libra field in Santos deepwaters, WD 2,609m, now reported P&A dry 30 May '20, Brava Star DS off to Parque de Conchas. PTD was 5,100m, target Barra Velha fm. Shell (op), partners Chevron + Ecopetrol.","Brazil (Santos B.) ? op. by SHELL (45%), CVX (45%), ECOPETROL (10%) in Saturno block Saturno 1 (1-SHEL-33-RJS) (Shell 45% op, Chevron 45%, Ecopetrol 10%) on the Saturno_5 Block in the DW of the Basin, drilling concluded with a PTD of 5100 m. The well is targeting the pre-salt Aptian carbonates of the Barra Velha Fm. WD=2 609 m. The NFW lies the SE part of the N-S oriented Saturno prospect, which is about 20 km south of the Alto de Cabo Frio Central prospect and about 74 km east of the Libra field. P&A, dry, no shows."
8954,"AWE Petroleum Pty Ltd commenced testing of the Waitsia 2 gas appraisal well on 7 November 2017.  Initially clean-up operations were completed, with subsequent gas flows of 38.7 MMcfg/d observed instantaneously.  On 10 November 2017 AWE reported that average gas flows of 38.5 MMcfg/d, with a peak flow of 38.7 MMcfg/d, had been observed through an 80/64” choke at a well head pressure of 1,315 psi.  The initial flow test was completed over a 2.1 hour period and the well has now been shut-in for pressure testing. Flow testing at Waitsia 2 is being undertaken over the Kingia Sandstone between 3,173 and 3,215 m.  It is designed to evaluate the gas deliverability from the southern section of the Waitsia field.  Gas samples will also be collected during testing for further analysis. Waitsia 2 is the second well to be tested in the programme, with Waitsia 3 tested first and delivering excellent results.  Testing of the Waitsia 4 appraisal well will follow, with the full testing programme expected to be complete by the end of November 2017. The Waitsia field was discovered in September 2014 by the Senecio 3 appraisal well, which was appraising an unconventional field. The Waitsia 1 to 4 appraisal wells were subsequently drilled.  The first phase of production from the field commenced in August 2016.  The testing phase ongoing forms part of the appraisal process in preparation for the second phase of production, which is planned to increase production ten-fold and commence in around 2020.",Australia (Beharra Springs Terrace (Perth B.)) Waitsia
65577,"On 27 November 2019, local sources relay that Shell Gabon (Shell) withdraws from the deep offshore permits BC9 and BCD10 transferring its stake to partner China National Offshore Oil Corp. International Ltd (CNOOC). The blocks are the place of the second pre-salt discovery, Leopard 1, made in 2014 in Gabonese deep waters. The discovery contains a substantial net gas pay thickness of 200 m in a pre-salt Gamba and Dentale reservoir. A Shell official talked about it as potentially multi-Tcf commercial discovery that was likely confirmed early 2016 with the success of the appraisal Leopard 2.  The sold of its two last assets in Gabon marks the exit of the country for the major after 60 years of presence.  CNOOC operates BC9 and BCD10 with 100% interest.  Background information  On 13 September 2007, Shell was granted two adjacent offshore blocks the BC9 (5,970 sq km) and the BCD10 (7,055 sq km). Between October 2010 and June 2011, Shell conducted a 3D seismic acquisition over both blocks. The 6,000 sq km 3D seismic campaign was carried out by contractor CGGVeritas with the “CGG Symphony” vessel.    On 24 July 2012, CNOOC entered in both BC9 and BCD10 blocks when Shell sold 25% of its interest to the Chinese company. Shell remained operator with a 75% interest while CNOOC reimbursed part of the exploration costs spent by Shell before the deal.    On 22 June 2014, Shell Gabon suspended the N’Komi 1 well located in the northern part of the BC9 permit, Gabon Coastal Basin after reaching TD in the pre-salt layer.","Gabon, BCD10"
12768,"Al Dhafra JV Area 3 offshore concession area, evaluation of Oct ‘83 ADNOC oil discovery, susp. mid-Dec ’17, Key Singapore JU.  Al Dhafra = ADNOC – KNOC – GS Energy 60:30:10.","Bu Danah-2 expl/appr, Al Dhafra JV Area 3 offshore concession area, evaluation of Oct ‘83 ADNOC oil discovery, susp. mid-Dec ’17, Key Singapore JU. Al Dhafra = ADNOC – KNOC – GS Energy 60:30:10."
79780,"On 6 Mayo 2020, TOTAL announced its Block 15, Area 33 and Area 34 blocks farmout with Qatar Petroleum (QP), all located in offshore Sureste Basin in water depths ranging between 10 to 1,000m. The new player QP is taking about 30% of TOTAL's holding in each block.   The new working interest breakdown for the blocks is as follow:     For      Block 15, TOTAL holds 42% working interest (operator), QP holds 18% and      Shell keeps the same 40% working interest.  For      Area 33 Block, TOTAL holds 35% working interest (operator), QP holds 15%      and PEMEX keeps the same 50% working interest.  For      Area 34 Block, TOTAL holds 27.5% working interest, QP holds 15%, BP      (operator) and Hokchi Energy keep the same 42.5% and 15% working interest,      respectively.   The Block 15 (976.15 sqkm) was awarded on 25 September 2017 under the CNH-R02-L01-A15.CS/2017 contract and it is located offshore in water depths around 10 to 30 m. The Area 33 Block (583.34 sqkm) was awarded on 27 June 2018 under the CNH-R03-L01-AS-CS-06/2018 contract and is located offshore in water depths around 30 to 100 m. The Area 34 Block (739.16 sqkm) was awarded on 27 June 2018 under the CNH-R03-L01-G-CS-03/2018 contract and it is located offshore in water depths around 60 to 1,000 m.  The farm-outs are subject to customary regulatory and other approvals by Total's partners and Mexico's government.  Background  On 25 September 2017, the CNH signed the final award contract with the consortium of TOTAL E&P Mexico, S.A. de C.V. and Shell Exploracion y Extraccion de Mexico, S. de R.L. de C.V. for the CNH-R02-L01-A15.CS/2017 PSC contract, Area 15 block from the CNH-RO2-LO1/2016 Bid Round. TOTAL is operator with 60% working interest and Shell has 40% working interest.  On 27 June 2018, the consortium of TOTAL E&P Mexico, operator with 50% working interest and PEMEX Exploracion y Produccion with 50%, was granted an official PSC contract award for the 581 sq km CNH-R03-L01-AS-CS-06/2018 contract from the CNH-R03-L01/2017 Bid Round.    On 27 June 2018, the consortium of BP Exploration Mexico, TOTAL E&P Mexico, and Hokchi Energy (Pan American), was granted an official PSC contract award for the 734 sqkm CNH-R03-L01-G-CS-03/2018 contract from the CNH-R03-L01/2017 Bid Round.","Total farmed out 30% WI in a trio of offshore Mexican blocks to Qatar Petroleum. The blocks are CNH-R02-L01-A15.CS/2017, CNH-R03-L01-AS-CS-06/2018, and CNH-R03-L01-G-CS-03/2018."
27500,"Along with its Kenitra offshore block (DEA 10 Apr ’18), Chariot is also offering equity in its 4,619-sq km Mohammedia block in the Doukkala Basin in exchange for participation in drilling LKP-1a nfw in 2H ’19, WD 400m. Chariot (op), partner Onhym. Contact: Duncan Wallace, duncanw@chariotoilandgas.com .","Along with its Kenitra offshore block (DEA 10 Apr ’18), Chariot is also offering equity in its 4,619-sq km Mohammedia block in the Doukkala Basin in exchange for participation in drilling LKP-1a nfw in 2H ’19, WD 400m. Chariot (op), partner Onhym. Contact: Duncan Wallace, duncanw@chariotoilandgas.com ."
30796,"Advent has agreed to the sale of a 90% stake in its subsidiary Onshore Energy, sole holder of EP 386 + RL 1, total 2,722 sq km onshore in the Bonaparte Basin, to an unnamed buyer. Onshore Energy will drill at least 1 explo well and shoot min. 50km 2D seismic data by EP 386 expiry in Mar ’20.",Bonaparte Petroleum has acquired a 90% share in Onshore Energy (OE) subsidiary of Advent Energy which holds a 100% interest in EP386 and RL1.
10036,"Guatiquia block, Llanos Basin, target Lower Sand 1, spudded late Sep ’17,  3 pay zones encountered and testing underway. PTD is/was ca. 3,800m. Note: Frontera Energy  = former Pacific E&P.",Colombia (Llanos-Barinas B.) Alligator 1 op. by FRONTERA E (100.0%) in Guatiquia block
37011,"Azinor has received an LoI for the acquisition of non-operated interests in P2317 (Goose prospect), P2165 (Boaz prospect) and P2179 (Hinson prospect). Preparations for drilling the wells are underway.","United Kingdom, P2179"
49251,"SL’s suspended (4th) licensing round has been re-launched, supported by Getech.  The country’s full offshore* has been opened, under a direct tender for applications where 50% or more of the application area is in water depths >2,500m (deadline deadline 20 Sep ’19), and an open tender for all other applications (deadline 22 Nov ’19). Release and map from Getech, contacts Timothy Kabba, DG, PDSL (timothy.kabba@pd.gov.sl) and Sarah-Jane O’Shea (Sarah-Jane.OShea@Getech.com).  * a grid of 1,360-sq km graticular blocks each applies, barring environmentally-protected estuaries + 5km coastal fisheries zone.","SL’s suspended (4th) licensing round has been re-launched, supported by Getech.  The country’s full offshore* has been opened, under a direct tender for applications where 50% or more of the application area is in water depths >2,500m (deadline deadline 20 Sep ’19), and an open tender for all other applications (deadline 22 Nov ’19). "
67492,"On 1 December 2019, Total E&P USA was formally awarded contiguous East Breaks blocks EB 545 (G36708) and EB 546 (G36709), situated in the East Texas Coastal Basin. The blocks were originally offered as part of OCS Gulf of Mexico Lease Sale 253, held on 21 August 2019, which garnered more than US$ 159 million in high bids. Following award, Total E&P USA is now the operator and sole interest-holder (100% WI + Op) in EB 545 and EB 546.",Not Found
75969,"SE part of AE-0382-2M-Amatitlán block, Tampico-Misantla Basin, tested 84 bo/d + 18 Mcfg/d, completed late Mar '20. PTMD was 2,872m (2,092m TVD), target Cret. Tamaulipas fm.","Kela 1EXP nfw (now npw) SE part of AE-0382-2M-Amatitlán block, tested 84 bo/d + 18 Mcfg/d, completed late Mar '20. PTMD was 2,872m (2,092m TVD), target Cret. Tamaulipas Fm."
17581,"On 22 March 2018, the CNH published the final list of qualified participating companies for the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1).  A total of 21 companies qualified out of the 30 pre-qualified, nine dropped out.  Out of the 21 companies, 14 qualified individually and 18 qualified in various consortia, 11 of the 14 individual qualified companies also qualified in 22 separate consortia.  There is one new entry in Mexico for this bid round and that is Sapura Exploration and Production from Malaysia.  Please see tables below.  On 5 March 2018, the CNH published the final version of the bid documents and model contract for the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) and also published the list of qualified companies as operators or non-operators. There are a total of 30 companies that have qualified to participate in Ronda 3.1, 20 as operators and 10 as non-operators.  There were four companies that were involved in the qualification process but did not reach the final qualification stage and will not participate.  These were DEP PYG, Hokchi Energy, Noble Energy, and Statoil.  It is assumed that Pan American Energy LLC, that is now qualified as operator, has replaced Hokchi Energy as Pan American was never on the list of companies published by the CNH until now.  Final publication of companies and consortia will be on 22 March 2018.  The reception of bids will be on 27 March 2018.  On 28 February 2018, the SHCP issued a press release to stipulate the minimum and maximum state participation for the bid round.  The agency assigned minimum values of state participation at 8.5% for blocks considered to be gas prone and 22.5% for blocks considered to be oil and gas prone.  The maximum state participation for all blocks was set at 65%.  On 22 February 2018, the CNH reported modifications to the bid documents and model contract for the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1).  There were several changes to various clauses, small modifications to the license schedule, and two modifications to block areas due to environmental considerations.  The two blocks with area modifications include Area 27 and Area 31.  The Area 27 block was reduced approximately 75 sq km to 1,143 sq km and the Area 31 block reduced approximately 137 sq km to 264 sq km.    On 26 January 2018, the CNH reported that there are 38 companies that have so far expressed an interest in the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) with 22 companies that have paid access fees to the data room, 33 companies that have paid participation fees, and 31 companies have initiated the prequalification process.  The final list of pre-qualified companies will be published on 5 March 2018.  On 16 January 2018, the CNH published modifications to the bid documents and model contract for the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1).    There were various minor modifications made to the bid round schedule to allow interested companies some additional time to register and access the data room.     The 22 February 2018 modified bid round schedule is as follows.    The CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) was launched on 29      September 2017 with the publication of the initial bid documents.    Access to the data room commenced on 29 September 2017 and      will be available until 26 January 2018 which is also the last day to pay      the participation fee and request a pre-qualification meeting.    The reception of pre-qualification documents was extended      from 24 January 2018 to 6 February 2018.         The final list of pre-qualified companies and final bid      documents will be published on 5 March 2018 extended from 26 February      2018.    The dates to request authorization for the formation of      consortia has been moved from 7 March 2018 to 13 March 2018 giving      companies an additional week.    Formation and publication of companies and consortia will      occur on 22 March 2018, extended from 19 March 2018.    The reception of bids date has not changed and will be held      on 27 March 2018.   On 15 January 2018, the CNH reported that there are 27 companies that have so far expressed an interest in the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) with 12 companies that have paid access fees to the data room, 19 companies that have paid participation fees, and 14 companies have initiated the prequalification process.  On 22 December 2017, the CNH reported that there are 21 companies that have so far expressed an interest in the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) with seven that have paid access fees to the data room, 11 companies that have paid participation fees, and six companies have initiated the prequalification process.  On 15 December 2017, the CNH published modifications to the bid documents and model contract for the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1).    There were various minor modifications made but the bid round schedule has not been changed.  On 15 December 2017 the CNH reported that there are 14 companies that have so far expressed an interest in the round with six that have paid access fees to the data room, nine companies that have paid participation fees, and four companies have initiated the prequalification process.  On 23 November 2017, the CNH published modifications to the bid documents and model contract for the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1).  There were various modifications made but the bid round schedule has not been changed.  On 24 November 2017 the CNH reported that there are seven companies that have so far expressed an interest in the round with five that have paid access fees to the data room and one company has initiated the prequalification process.  The CNH held an administrative session on 28 September 2017 whereby it approved the launch of the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) with 35 blocks on the shelf on offer under the PSC contract regime as proposed by SENER in late-August 2017.  The bid documents were published on 29 September which is the official launch date of the round.  There are 35 blocks on offer covering a total area of 26,265 sq km down to a water depth of 500 m.  The CNH estimates 1.9 Bboe in prospective resources in the 35 blocks on offer.  There are 14 blocks in the Burgos Basin, 13 blocks in the Tampico-Misantla and Veracruz basins, and eight blocks in the Sureste Basin. Some of the blocks are revived from R2.1 that were not bid on.  The bid submittal date is 27 March 2018.  The PSC contract terms will reportedly be similar to the R2.1 terms with the bidding criteria being additional state take offered and additional work commitment of wells.  The additional well commitments are bid through the investment work factor with 0 being no wells, 1 being one additional well commitment, and 1.5 representing two additional well commitments.  The general bid round schedule is as follows.  Access to the data room commences on 29 September and will be available until 19 January 2018 which is also the last day to pay the participation fee and request a pre-qualification meeting.  The participation fee to access the data room is approximately USD 444,444 and is obligatory for the operator.  The non-operator only has to pay the participation fee of USD 41,667.  The final list of pre-qualified companies and final bid documents will be published on 26 February 2018.  Formation and publication of companies and consortia will occur on 19 March 2018.  The reception of bids will be held on 27 March 2018.  The general PSC contract terms include a 1st exploration period of four years with the possibility of a two year extension.  Relinquishment of the entire contract area is required if there is no evaluation or development plan filed for any discoveries.  There is the possibility of a 2nd exploration period of two years with 50% relinquishment if committing to one exploration well and 0% relinquishment for committing to two exploration wells in the extension period.  If a discovery is made there is an evaluation period of two years.  The development phase is for approximately 22 years from the date of an approved development plan with two possible five year extension periods.  The maximum contract term is 40 years.  Local content during the exploration period is 15%, 17& for the evaluation period, and 26% during the first year of the development period until 2025 when it increases to 35%.  A variety of taxes and fees apply to the PSC contract.  There is a maximum 60% cost recovery with an adjustment mechanism.  The bidding criteria include the additional State take percentage and additional investment commitments up to two wells.  The Secretaria de Hacienda y Credito Publico (SHCP) will publish the minimum values for the minimum State take percentage prior to the bid submission date.    The CNH held an administrative session on 24 August 2017 whereby it reviewed and gave its opinion regarding the PSC model contract as proposed by SENER for the CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) that may offer 35 blocks on the shelf.  The onshore blocks previously reported to be included in Ronda 3.1 will be offered at a later date in a separate round.  The CNH in a divided vote formalized its opinion that the model contract should be a license contract with some modifications proposed that would allow the state to have its payments in cash or in barrels.  The final decision on the contract model now reverts to SENER.  On 24 August 2017 SENER provisionally proposed 35 blocks to be offered in Ronda 3.1, 14 in the Burgos Basin, 13 in the Tampico-Misantla Basin, and eight blocks in the Sureste Basin.  The blocks are provisional and the final number of blocks will be finalized by SENER when it approves the launch of the bid round.  The blocks provisionally offered will be a combination of and a portion of the 102 blocks that were available for nomination through the modified Plan Quinquenal and after the provisional awards from R2.1.  The 14 blocks in the Burgos Basin are located in the northern and southern areas of the basin.  The blocks in the Tampico-Misantla, Sureste, and Veracruz basins appear to be all of the blocks available for nomination through the modified Plan Quinquenal with some blocks combined.  The nominations period for Ronda 3.1 for shelf and onshore conventional blocks opened on 2 March 2017 with the launch of the round originally scheduled for August 2017 and the bid reception originally scheduled for the 2nd week of February 2018.  On 2 March 2017 the Secretaria de Energia (SENER) announced significant changes to its Plan Quinquenal for bid rounds to be held in the future including Ronda 2.4 for Deep Water and Unconventional blocks and Ronda 3.1 and Ronda 3.2.  Final List of Qualified Participating Companies and Consortia - CNH-RO3-LO1/2017 Bid Round – 22 March 2018          Count         Company          Qualified Individually         Qualified in Consortia         Number of Consortia         Consortia Count         Consortium             1         BP Exploration Mexico   S. A. de C.V.         Y         Y         3         1         BP, Pan American             2         Capricorn EnergyMexico   S. de R.L. de C.V. - (Cairn)         Y         Y         2         2         Capricorn, Citla             3         Chevron Energia de   Mexico, S. de R.L. de C.V.         Y                             3         Capricorn, Citla, ECP             4         Citla Energy E&P   S.A.P.I. de C.V.                   Y         2         4         DEA, Premier             5         Compania Espanola de   Petroleos, S.A.U. (CEPSA)                   Y         2         5         DEA, Premier, Sapura             6         DEA Deutsche Erdoel   Mexico, S. de R.L. de C.V.         Y         Y         8         6         DEA, Sapura             7         ECP Hidrocarburos   Mexico, S.A. de C.V. (Ecopetrol)         Y         Y         2         7         DEA, Servicios de   Extraccion Petrolera Lifting             8         ENI Mexico, S. de R.L.   de C.V.         Y         Y         1         8         ENI, Lukoil             9         Galem Energy, S.A.P.I.   de C.V.                   Y         1         9         PC Carigali, ECP             10         Inpex Corporation                   Y         1         10         PEMEX, CEPSA             11         Lukoil Upstream   Mexico, S. de R.L. de C.V.                   Y         1         11         PEMEX, DEA             12         ONGC Videsh Limited         Y                             12         PEMEX, DEA, CEPSA             13         Pan American Energy LLC         Y         Y         3         13         PEMEX, Inpex             14         PC Carigali Mexico   Operations, S.A. de C. V.         Y         Y         1         14         Premier, DEA             15         Petroleos Mexicanos   (PEMEX)         Y         Y         6         15         Premier, DEA, Sapura             16         Premier Oil   Exploration and Production Mexico, S.A. de C.V.         Y         Y         5         16         Premier, Sapura             17         Repsol Exploracion Mexico,   S.A. de C.V.         Y                             17         Sapura, Galem             18         Sapura Exploraction   and Production Sdn Bhd                   Y         3         18         Shell, PEMEX             19         Servicios de   Extraccion Petrolera Lifting de Mexico, S.A. de C. V.                   Y         1         19         Total, BP             20         Shell Exploracion y Extraccion   de Mexico, S. de R.L. de C.V.         Y         Y         1         20         Total, BP, Pan American             21         Total E&P Mexico,   S.A. de C.V.         Y         Y         4         21         Total, Pan American                                                               22         Total, PEMEX             © 2018 IHS Markit         Source: IHS Markit                                                             Companies Pre-Qualified but Dropped Out - CNH-RO3-LO1/2017 Bid Round – 22 March 2018          Count         Company          Qualified Operator         Qualified Non-Operator             1         China Offshore Oil   Corporation E&P Mexico, S.A.P.I. de C.V.         Y                       2         ExxonMobil Exploracion   y Produccion Mexico S. de R.L. de C.V.         Y                       3         Murphy Sur, S. de R.L.   de C.V.         Y                       4         Ophir Mexico Limited         Y                       5         Controladora de   Infraestructura Petrolera Mexico, S.A. de C.V.                   Y             6         Mitsui & Co. Ltd                   Y             7         PetroBal, S.A.P.I. ce   C.V.                   Y             8         PTTEP Mexico E&P Limited,   S. de R.L. de C.V.                   Y             9         Sierra Blanca P&D,   S. de R.L. de C.V.                   Y           Pre-qualified Companies List - CNH-RO3-LO1/2017 Bid Round – 5 March 2018          Count         Company          Qualified Operator         Qualified Non-Operator             1         BP Exploration Mexico S. A. de C.V.         Y                       2         Capricorn EnergyMexico S. de R.L. de C.V. - (Cairn)         Y                       3         Chevron Energia de Mexico, S. de R.L. de C.V.         Y                       4         China Offshore Oil Corporation E&P Mexico, S.A.P.I. de C.V.         Y                       5         Citla Energy E&P S.A.P.I. de C.V.                   Y             6         Compania Espanola de Petroleos, S.A.U.                   Y             7         Controladora de Infraestructura Petrolera Mexico, S.A. de C.V.                   Y             8         DEA Deutsche Erdoel Mexico, S. de R.L. de C.V.         Y                       9         ECP Hidrocarburos Mexico, S.A. de C.V. (Ecopetrol)         Y                       10         ENI Mexico, S. de R.L. de C.V.         Y                       11         ExxonMobil Exploracion y Produccion Mexico S. de R.L. de C.V.         Y                       12         Galem Energy, S.A.P.I. de C.V.                   Y             13         Inpex Corporation         Y                       14         Lukoil Upstream Mexico, S. de R.L. de C.V.                   Y             15         Mitsui & Co. Ltd                   Y             16         Murphy Sur, S. de R.L. de C.V.         Y                       17         ONGC Videsh Limited         Y                       18         Ophir Mexico Limited         Y                       19         Pan American Energy LLC         Y                       20         PC Carigali Mexico Operations, S.A. de C. V.         Y                       21         PetroBal, S.A.P.I. ce C.V.                   Y             22         Petroleos Mexicanos (PEMEX)         Y                       23         Premier Oil Exploration and Production Mexico, S.A. de C.V.         Y                       24         PTTEP Mexico E&P Limited, S. de R.L. de C.V.                   Y             25         Repsol Exploración México, S.A. de C.V.         Y                       26         Sapura Exploraction and Production Sdn Bhd         Y                       27         Servicios de Extraccion Petrolera Lifting de Mexico, S.A. de C.   V.                   Y             28         Shell Exploracion y Extraccion de Mexico, S. de R.L. de C.V.         Y                       29         Sierra Blanca P&D, S. de R.L. de C.V.                   Y             30         Total E&P Mexico, S.A. de C.V.         Y                       ©   2018 IHS Markit         Source: IHS Markit                                CNH - CNH-RO3-LO1/2017 Bid Round – Minimum and Maximum State Participation – SHCP 28 February 2018          Area         Basin         CNH - Shapefile   Designation         Mininum State   Participartion %         Maximum State   Participartion %             1         Burgos         G-BG-01         8.5         65             2         Burgos         G-BG-02         8.5         65             3         Burgos         G-BG-03         8.5         65             4         Burgos         G-BG-04         8.5         65             5         Burgos         G-BG-05         22.5         65             6         Burgos         G-BG-06         22.5         65             7         Burgos         AS-B-53         22.5         65             8         Burgos         AS-B-54         22.5         65             9         Burgos         AS-B-55         22.5         65             10         Burgos         AS-B-56         22.5         65             11         Burgos         AS-B-57         22.5         65             12         Burgos         G-BG-07         22.5         65             13         Burgos         AS-B-60         22.5         65             14         Burgos         AS-B-61         22.5         65             15         Tampico-Misantla-Veracruz         G-TMV-01         22.5         65             16         Tampico-Misantla-Veracruz         G-TMV-02         22.5         65             17         Tampico-Misantla-Veracruz         G-TMV-03         22.5         65             18         Tampico-Misantla-Veracruz         G-TMV-04         22.5         65             19         Tampico-Misantla-Veracruz         G-TMV-05         22.5         65             20         Tampico-Misantla-Veracruz         G-TMV-06         8.5         65             21         Tampico-Misantla-Veracruz         G-TMV-07         8.5         65             22         Tampico-Misantla-Veracruz         G-TMV-08         8.5         65             23         Tampico-Misantla-Veracruz         G-TMV-09         8.5         65             24         Tampico-Misantla-Veracruz         G-TMV-10         8.5         65             25         Tampico-Misantla-Veracruz         G-TMV-11         8.5         65             26         Tampico-Misantla-Veracruz         G-TMV-12         8.5         65             27         Tampico-Misantla-Veracruz         G-TMV-13         8.5         65             28         Sureste         G-CS-01         22.5         65             29         Sureste         AS-CS-13         22.5         65             30         Sureste         AS-CS-14         22.5         65             31         Sureste         AS-CS-15         22.5         65             32         Sureste         G-CS-02         22.5         65             33         Sureste         AS-CS-06         22.5         65             34         Sureste         G-CS-03         8.5         65             35         Sureste         G-CS-04         22.5         65                       Source: IHS Markit         ©   2018 IHS Markit                                CNH - CNH-RO3-LO1/2017 Bid Round – Blocks on Offer – General Summary          Area         Basin         CNH - Shapefile   Designation         Area sq km         Fields Included         CNH Estimated   Prospective Resources  MMboe         Water Depth m         Minimum Work Units         Min Wus USD value   45-50 bbl oil             1         Burgos         G-BG-01         802                   85          <200          2,104         $2,104,000.00              2         Burgos         G-BG-02         816                   102          <200          2,141         $2,141,000.00              3         Burgos         G-BG-03         809                   60          <200          2,123         $2,123,000.00              4         Burgos         G-BG-04         778                   42          <200 - 500          2,046         $2,046,000.00              5         Burgos         G-BG-05         814                   36          <200          2,134         $2,134,000.00              6         Burgos         G-BG-06         820                   31          <200 - 500          2,150         $2,150,000.00              7         Burgos         AS-B-53         391                   71          <200          1,078         $1,078,000.00              8         Burgos         AS-B-54         390                   20          <200 - 500          1,076         $1,076,000.00              9         Burgos         AS-B-55         397                   19          <200          1,093         $1,093,000.00              10         Burgos         AS-B-56         419                   19          <200          1,147         $1,147,000.00              11         Burgos         AS-B-57         391                   23          <200          1,078         $1,078,000.00              12         Burgos         G-BG-07         811                   48          <200 - 500          2,128         $2,128,000.00              13         Burgos         AS-B-60         392                   15          <200          1,080         $1,080,000.00              14         Burgos         AS-B-61         392                   8          <200          1,080         $1,080,000.00              15         Tampico-Misantla-Veracruz         G-TMV-01         962          Tiburon, Tintorera          42          <200          2,504         $2,504,000.00              16         Tampico-Misantla-Veracruz         G-TMV-02         785                   35          <200 - 500          2,062         $2,062,000.00              17         Tampico-Misantla-Veracruz         G-TMV-03         842                   34          <200 - 500          2,206         $2,206,000.00              18         Tampico-Misantla-Veracruz         G-TMV-04         813                   89          <200          2,133         $2,133,000.00              19         Tampico-Misantla-Veracruz         G-TMV-05         808                   45          <200 - 500          2,121         $2,121,000.00              20         Tampico-Misantla-Veracruz         G-TMV-06         817                   30          <200          2,142         $2,142,000.00              21         Tampico-Misantla-Veracruz         G-TMV-07         1,103          Cangrejo, Mejillon, Kosni          284          <200          2,858         $2,858,000.00              22         Tampico-Misantla-Veracruz         G-TMV-08         1,138                   156          <200          2,945         $2,945,000.00              23         Tampico-Misantla-Veracruz         G-TMV-09         820                   31          <200          2,151         $2,151,000.00              24         Tampico-Misantla-Veracruz         G-TMV-10         791                   103          <200 - 500          2,078         $2,078,000.00              25         Tampico-Misantla-Veracruz         G-TMV-11         1,170                   80          <200          3,025         $3,025,000.00              26         Tampico-Misantla-Veracruz         G-TMV-12         1,225                   145          <200          3,162         $3,162,000.00              27         Tampico-Misantla-Veracruz         G-TMV-13         1,143                   144          <200          3,146         $3,146,000.00              28         Sureste         G-CS-01         808                   31          <200 - 500          2,119         $2,119,000.00              29         Sureste         AS-CS-13         471                                            -             <200          1,276         $1,276,000.00              30         Sureste         AS-CS-14         528                   20          <200          1,420         $1,420,000.00              31         Sureste         AS-CS-15         264                   51          <200          1,103         $1,103,000.00              32         Sureste         G-CS-02         1,027                   64          <200 - 500          2,668         $2,668,000.00              33         Sureste         AS-CS-06         581                   5          <200          1,552         $1,552,000.00              34         Sureste         G-CS-03         734                   8          <200          1,935         $1,935,000.00              35         Sureste         G-CS-04         798                   13          <200          2,095         $2,095,000.00              Totals                             26,262                   1,989.00                                            Source: IHS   Markit                                                                  © 2018 IHS   Markit           CNH - CNH-RO3-LO1/2017 Bid Round – Blocks on Offer – General Summary Map     ","Mexico, not found"
30127,"In late August 2018, Khalda Petroleum Co. (Khalda) abandoned the Netbu 1 (Ii013-3) wildcat in the Khalda Offset (New) A-West block after reaching a TD of 3,922 m.   The well was spudded on 27 July 2018 with “EDC-54” land rig. It had a PTD of 3,962 m and objectives in the Aptian Alam El Bueib Member.   The Khalda Offset (New) block is held by Khalda with a 100% interest.        In early November 2017, Khalda Petroleum Co. (Khalda) completed the Nu 1 (Ii013-2) wildcat in the Khalda Offset (New) A-West block as an oil well.   The well was spudded on 22 September 2017 with “EDC-61” land rig and drilled to a TD around 3,800 m in the Paleozoic layer.    Nu 1 had a PTD of 3,810 m and objectives in the Alam El Bueib Member and the Paleozoic layer.   The Khalda Offset (New) block is held by Khalda with a 100% interest.",Egypt (Northern Egypt B.) Nu 1
18616,"On 9 April 2018 Sound Energy announced that the sale of the company’s Italian subsidiary Apennine Energy SpA (held through the holding company Sound Energy Holdings Italy Limited) to Coro Energy (previously known as Saffron Energy) was completed on 9 April 2018. The consideration for the acquisitions was settled through the issue of 185,907,500 new ordinary shares in Coro Energy (valuated at GBP 0.001 each) to Sound Energy. In addition, Sound Energy will retain its economic rights on the proceeds of the sale of Badile land (estimated at GPB 1.6 million as of 30 June 2017) and on the benefits of VAT receivables linked to the Badile drilling costs (estimated at EUR 4 million). Finally, Coro will also grant Sound energy an overriding royalty of 5% on all potential revenue derived from the D.R74.AP permit (Laura gas discovery).  The assets held by Sound Energy in Italy are listed in the table below:          Exploration Permits                                                      Contract  Name            Operator / interest            Partners             Sq km            Location               Badile            Apennine Energy SpA - 100%            -            154.5            Lombardia               Carita            Apennine Energy SpA - 100%            -            525.25            Veneto               Costa del Sole            Apennine Energy SpA - 100%            -            41.52            Sicilia               D.R74.AP            Apennine Energy SpA - 100%            -            58.01            Ionian Sea               Monte Negro            Apennine Energy SpA - 100%            -            287.7            Basilicata               Monteluro            Apennine Energy SpA - 95%            Petren Srl - 5%            364.86            Marche               Montemarciano            Apennine Energy SpA - 75%            SARP - 25%            44.48            Marche               S. Maria Goretti            Apennine Energy SpA - 100%            -            101.3            Marche               Villa Gigli            Apennine Energy SpA - 100%            -            100.9            Marche               Exploitation Concessions                                                      Contract  Name            Operator / interest            Partners             Sq km            Location               Casa Tonetto            Apennine Energy SpA - 100%            -            4.8            Veneto               Fonte San Damiano            Apennine Energy SpA - 100%            -            23.71            Basilicata               Rapagnano            Apennine Energy SpA - 100%            -            8.49            Marche               San Lorenzo            Apennine Energy SpA -75%            SARP - 25%            4.95            Marche               Exploration Permit Application                                                   Contract  Name            Operator / interest            Partners             Sq km            Location               d503B.R-.CS            Apennine Energy SpA - 100%            -            82.61            Adriatic Sea               Posta del Giudice            Apennine Energy SpA - 100%            -            113.6            Puglia               Solfara Mare            Apennine Energy SpA - 100%            -            337            Calabria               Torre Del Ferro            Apennine Energy SpA - 100%            -            118            Calabria           The deal was announced on 5 October. At the time of the announcement it was also involving the acquisition by Coro Energy of Po valley Energy’s wholly-owned subsidiary Po Valley Operations Ltd but the latter agreement was terminated. The main reason invoked by the company was “the rapid pace of development of Saffron's activities in South East Asia, the regulatory and taxation issues inherent in the Po Valley Energy corporate approval process and the Saffron board's desire to limit upfront equity dilution”",On 9 April 2018 Sound Energy announced that the sale of the company’s Italian subsidiary Apennine Energy SpA (held through the holding company Sound Energy Holdings Italy Limited) to Coro Energy (previously known as Saffron Energy) was completed on 9 April 2018. 
44118,"CNH-R01-L04-A5.CS/2016 (block 5), Campeche Deep Sea / Salina Basin, WD 750m, susp. o&g, no details yet although results broadly in line with pre-drill expectations. PTMD was 2,746m (2,717 TVD), target Miocene, Deepwater Asgard DS. Murphy (op), partners Petronas, Ophir + Sierra (DEA).","Cholula 1 (Murphy op. 30%, Petronas 23, 34%, Sierra 23, 33%, Ophir (Medco) 23,33%) in CNH-R01-L04-A5.CS/2016 (block 5), o&g, no details yet. Ophir revealed little detail, saying only that the well was drilled during February and March 2019 and ""encountered hydrocarbons"". It said that ""further drilling is likely to be required to confirm the commerciality of the block."""
74399,"Equinor has acquired a 50% non-operating interest from Total in P2277 + P1891 (Finzean prospect, 12/30-2 nfw planned using the Sam Hartley JU). Partnership now 50:50.","Equinor has acquired a 50% non-operating interest from Total in P2277 + P1891 (Finzean prospect, 12/30-2 nfw planned using the Sam Hartley JU). Partnership now 50:50."
13129,"A consortium of BP and Kosmos Energy has won exploration rights to two offshore oil blocks in Sao Tome and Principe’s exclusive economic zone (EEZ), the national oil agency said. The two companies won Blocks 10 and 13 in a restricted tender, the agency’s director Orlando Pontes said in a statement late on Monday. They beat a second consortium of Portugal’s Galp Energia and Total, he said. Sao Tome and Principe, a tiny island nation in Africa’s Gulf of Guinea, is surrounded by oil-rich neighbours Nigeria, Cameroon, Equatorial Guinea and Angola. Despite a lack of significant discoveries after several years of prospecting, the industry sees its waters as likely to yield oil eventually, and several firms are currently exploring. Its 129,000 sq km EEZ is divided into 19 blocks. New York-listed Kosmos Energy, which is active in other parts of West and Central Africa, acquired licences to Blocks 5, 6, 11 and 12 in 2015 and 2016. The national oil agency said it expected the firm to begin drilling in 2019 based on seismic results. Original article link Source: Reuters ",Sao-Tome & Principe	Consortium composed by BP (operator of the blocks) and Kosmos (acting as technical operator during the exploration phase) was awarded 2 blocks: 10 & 13 in a restricted tender.
28680,"Hurricane Energy announced on 3 September 2018 that it has agreed a deal for Spirit Energy to farm-in to licences P1368 and P2294 taking a 50% interest in the licences. Licence P1368 contains the Lincoln discovery and P2294 contains the Warwick prospect, jointly the area is known as the Greater Warwick Area (GWA). Hurricane report that itself and Spirit Energy is looking towards a Final Investment Decision (FID) for full development on the GWA by 2021 with a view to start drilling operations in 2019 with first oil with the Transocean Leader (S/S) (following early production phase in 2020). To potentially unlock 500 MMboe the companies will approach the project in two phases. The first Phase in 2019 will see Hurricane fully carried through USD 180.6 million (gross) programme to drill, log and test three exploration and appraisal wells on the Lincoln discovery and Warwick prospect. In addition to this, the money will be used to tie-back one or more of the GWA wells back to the Floating, Production, Storage and Offloading vessel the “Aoka Mizu” in 2020 along with carrying modifications to the FPSO. The second phase in 2020, assuming phase 1 is successful and FID is made, the GWA wells will be tied-back to the FPSO, and tie-in to the West of Shetland Pipeline system for gas export allowing for first oil via an Early Production System by Q4 2020. There is a further contingent payment in the region of USD 150 – 200 million by Spirit Energy for Hurricane’s carry of full field development costs.   Hurricane is in the process of nearing its first Early Production System on the Lancaster field. The company focuses on Fractured Basement in the West of Shetlands. It had been looking for partners for the Lancaster development but still remains 100% in the project. In early August 2018 Hurricane announced that it was nearing the end of the offshore installation process at Lancaster. Once all infrastructure is in place the company hopes to achieve first oil by early 2019.  Following completion of the deal interest in P1368 and P2294 will be held by Hurricane Energy Plc (50%) and Spirit Energy (50%).",Hurricane Energy announced on 3 September 2018 that it has agreed a deal for Spirit Energy to farm-in to licences P1368 and P2294 taking a 50% interest in the licences. 
67794,"N47-B 471 sq km in the Zagros Province, SE Turkey, was awarded 10 Dec '19 for 5 years. The application had been filed in March.","N47-B 471 sq km in the Zagros Province, SE Turkey, was awarded "
42133,"In a teleconference call held on 14 February 2019, Woodside Petroleum Ltd chief executive officer Peter Coleman stated that Woodside is seeking to reduce its 75% equity holding in its operated Scarborough gas field, located in WA-01-R, North Carnarvon Basin, and in the proposed Pluto LNG Train 2 located on the Burrup Peninsula, Western Australia, in which Woodside holds 100% equity.  Woodside will retain a minimum of 40% equity in the Scarborough field, in which joint venture partner BHP Group Ltd holds the remaining 25%. Both Tokyo Gas and Kansai Electric have been offered a combined total of up to 10% equity at market pricing. Peter Coleman expressed a preference for a larger player to take the remaining available equity and stated that interested parties were seeking between 15-20%.  The equity offering in the Pluto LNG Train 2 is negotiable with Woodside seeking to divest down to approximately 50%. Tokyo Gas and Kansai Electric have again been offered a combined total of up to 10%, leaving 40% equity available should the Japanese LNG buyers, who are already partners in the Pluto LNG Train 1, take up the offer.  Woodside is continuing to work on the expansion plans for Pluto.  On 27 December 2018 Woodside announced that it had entered the Front End Engineering and Design (FEED) Phase for the second train at the Pluto LNG Project.  Part of the expansion will see the Scarborough asset tied in, to supply Train 2. Woodside has awarded a contract to Bechtel, which will see it undertake the FEED phase, including the finalization of costs and technical definition for the second train.  With FEED entered, Woodside hopes to reach Final Investment Decision (FID) on the project in 2020, with start-up then planned for 2024. In January 2019 four contracts were awarded associated with the Front-End Engineering and Design (FEED) phase of the Scarborough LNG Project.     WA-01-R in which Scarborough lies, covers an area of 720 sq km and was originally awarded on 30 January 1987. The license was most recently renewed on 2 November 2015. Interests in the permit are Woodside Petroleum Ltd (75% plus operatorship) and BHP Group Ltd (25%).","Woodside is seeking to reduce its 75% equity holding in its operated Scarborough gas field, located in WA-01-R, North Carnarvon Basin, and in the proposed Pluto LNG Train 2 located on the Burrup Peninsula, Western Australia, in which Woodside holds 100% equity. "
48829,"Tapir block, Llanos Basin, TD ca. 3,000m, LWD logs indicate 31m oil pay in multiple conventional reservoirs within the C7 (15m), Gacheta (11m) + Ubaque (3.6m) fm’s, testing planned, Weatherford rig 839. Additional minor potential net pay was identified in the C3 + Mirador fm’s. Farmin commitment for Arrow to gain 50% + operatorship through Carrao Energy. Partner Petrocol.","Rio Cravo E.-1 (RCE) (Arrow 50% op. Petrocol 50%) in Tapir block, LWD logs indicate 31m oil pay in multiple conventional reservoirs within the C7 (15m), Gacheta (11m) + Ubaque (3.6m) fm’s, testing planned. Additional minor potential net pay was identified in the C3 + Mirador fm’s. TD ca. 3,000m,"
10975,"On 12 December 2017 Melbana Energy Ltd reported that it has entered into a farm-in option agreement with Total SA and Santos Ltd for Melbana’s 100% owned exploration permit WA-488-P, located in the Bonaparte Basin. The permit contains the Beehive Prospect, which requires further seismic before the scheduled drill date by 21 March 2019 to test the structure. Under the agreement, Total and Santos are to fully fund a planned 400 sq km 3D seismic survey over the Beehive Prospect in return for an option to acquire an 80% participating interest in the permit (together or individually split). If the option is exercised, Melbana will retain 20% interest and be fully carried for the first well, which is likely to target the Beehive Structure. If a commercial discovery is made, Melbana will repay the carried funding from the cash flow post full field development, which, at 20% interest, would equate to approximately AUD 5 million based on a drill cost of AUD 20 million.  Melbana reports that the seismic survey planning has already commenced and is estimated to cost around AUD 5 million. With the potential of de-risking of the Beehive Prospect, well planning can commence to determine the preferred surface location. Melbana, previously MEO Australia Ltd, through its wholly owned subsidiary Finniss Offshore Exploration Pty Ltd, launched a farm-out of WA-488-P following its award as part of the 2012 Federal Offshore Acreage Release. Between 10 and 80% interest in the permit was made available with conditions and equity options always dependent upon the completion of seismic reprocessing and assessment of key elements within the permit. In December 2015, Melbana received approval to suspend/extend WA-488-P to facilitate additional seismic reprocessing and seismic inversion of 150 km 2D broadband data to de-risk the Beehive Prospect. After being completed by Q4 2017, Melbana reported that significant data quality improvements had been noted, providing better definition of the reef edge and in the overlying shale seal sequence in the Beehive Structure.  The Beehive 1 well will target the shallow, substantial Beehive Prospect in a new play type with global analogues. The primary target is thought to be a Carboniferous Carbonate build up play, which is analogous to the Ungani and Tengiz discoveries. The carbonate platform has been interpreted by Melbana to be approximately 18 km across with a mapped closure around 140 sq km. As a secondary objective the prospect contains an Ordovician Buried Hill play. Prospective recoverable resources have been estimated, with a Best Estimate of 558 MMboe and 305 MMboe for the Carboniferous Carbonate and Ordovician Buried Hill plays respectively.  If a discovery is made, Melbana reports that development plans could include an FPSO or pipeline options to existing infrastructure including Ichthys and Blacktip developments. Melbana entered WA-488-P on 18 February 2014 by means of an Option Agreement with Rex International Holding, for a 30% interest in the block. By 20 October 2014, Melbana had reached a settlement to allow Rex to withdraw from the permit due to the declining industry market and Rex’s move to focus on it key assets in Norway and Oman.       ",Australia (Bonaparte B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: WA-488-P op. by FINNISS (100.0%) to be check.
37567,"PEMEX plugged and abandoned dry the Yaaxtaab 1EXP new-field wildcat (NFW) in the AE-0013-M-Pilar de Akal-Kayab-04 entitlement during mid-December 2018.  The well reached a final total depth of 7,846 m.      The NFW was spudded on 27 November 2017.           The NFW had a proposed total depth (PTD) of 7,800 m.  It was drilled by the Seadrill “West Oberon” J/U in a water depth of 52 m.           The primary target would be the pre-salt sequence that includes the Middle and Lower Jurassic and possibly Triassic and Upper Paleozoic sediments underlying the Upper Jurassic, Callovian Louann salt. The salt thickness was reported to be 500 m at this location from approximately 6,000 m to 6,500 m.        This well would be one of the deepest wells ever drilled in the country with an estimated cost of USD 128 million.         The NFW is projected to take 14 months to drill and would take it again to near the end of the two year extension period of 27 August 2019.         PEMEX has estimated unrisked prospective resources for the project at 250 MMboe.       The NFW is located in the western central border area of the AE-0013-M-Pilar de Akal-Kayab-04 entitlement between the Ixtal and Batab production blocks, approximately 4.7 km north northeast of the Batab 1 oil and gas discovery well.         Through new seismic interpretation PEMEX proposed the NFW in order to test the hypothetical pre-salt, Jurassic play in the Sureste Basin.         On the 18 October 2017, PEMEX had its exploration plans approved for drilling two new field wildcats (NFW) in the AE-0013-M-Pilar de Akal-Kayab-04 entitlement which includes the significant Yaaxtaab 1EXP NFW.       In 2012, PEMEX published a presentation on the hypothetical pre-salt play.  According to the presentation the play extends in a north south direction then trends northeasterly around the Yucatan peninsula predominantly in ultra-deep water of the Campeche Deep Sea Basin and the Campeche Escarpment Basin.  The proposed Yaaxtaab 1EXP is located in the very southeastern area of the hypothetical play.    Little is known about the pre-salt sediments with the exception of a few wells and onshore outcrop studies indicating mostly redbeds. There are several wells in the shelf area that may have reached the pre-salt sequence both to the northwest and southeast.  The nearest well is the Le 1 located approximately 25.7 km west northwest and the Che 1 is located about 39 km to the south southeast.  The estimated sediment types for the pre-salt Jurassic sediments in the southeastern area of the pre-salt play are oolitic carbonate banks at the top of the sequence to fluvial and lacustrine sediments transitioning into deeper water to fluvial and alluvial fan systems.  However, initial geochemical modelling indicates the pre-salt play would have a tendency to be gas prone in most of the play area with a narrow updip window of oil to condensates.  PEMEX is using as an analogy the Brazilian pre-salt play where the most favorable facies developed in areas of ultra-deep water and poorer facies in the shelf areas.  However if the Santos Basin pre-salt play is used as an analogy then the Mexico pre-salt play may have more oil than the PEMEX geochemical model, similar to Santos, with the salt acting as a thermal sink.  There are a variety of play types postulated including graben structural traps and combination traps with salt and basement.    On the 10, 13, and 18 October 2017 the CNH approved PEMEX proposed modifications to addendum 2, the minimum exploration work commitments, of 16 exploration entitlements out of 101 granted a two year extension by SENER on 27 August 2017 including the AE-0013-M-Pilar de Akal-Kayab-04 entitlement.   The AE-0013 entitlement was granted on 27 August 2014 and with the recent approved modification is now denominated the AE-0013-2M-Pilar de Akal-Kayab-04 entitlement.  The block underlies or overlies many of the largest fields in Mexico including the Cantarell complex, Abkatun, Kambesah, Ku, Ixtoc, Ixtal, Taratunich, and Batab.","Yaaxtaab 1 (PEMEX 100%), in the offshore AE-0013-M-Pilar de Akal Kayab-04 Contract, now confirmed P&A dry."
59857,"LF 21-4-1 was completed in late September 2019 without result reported.  CNOOC – Shenzhen spudded a NFW in the PRMB Basin, South China Sea, on 16 August 2019. LF 21-4-1, located in the Lufeng Sag in a water depth of 300 m area, has target in the Mio-Oligocene clastic play. “Nanhai 6” S/S is used of the drilling operation.   In 2019, CNOOC has completed LF 16-7-1, LF 7-10-1d and LF 15-8-1 in the Lufeng Sag without result reported.   Around this area, several wells have been drilling, LF 8-1-1, LF 14-4-1 and LF 14-8-1 have been reported as discovery well, but another few wells, such as LF 9-2-1, LF 9-6-1, LF 14-2-1, LF 14-3-1 and LF 15-2-1 are not success.  CNOOC made discovery of LF 8-1-1 and LF 14-4-1 in 2014.LF 14-4-1 penetrated about 150 m of oil pay and tested 1,320 b/d of oil from the Lower Tertiary Zhuhai Formation.   In 2015, CNOOC drilled an appraisal well, LF 14-4-2, and reported as a success oil well.   In 2017 CNOOC drilled appraisal well, LF 8-1-2 to assess LF 8-1-1 discovery.   In 2017 CNOOC made discovery in LF 14-8-1 and tested oil from the Oligocene Enping Formation.   In addition, in 2018, SK Innovation made LF 12-3-1 discovery. The well was drilled to a TD of 2,014 m and encountered 34.8 m net oil pay. Test rates from the well was up to 3,750 bo/d from the Lower Miocene Zhujiang Formation.  Background Information    There are several fields on production in the Lufeng Sag:     LF 7-2 field is operated by Newfield and it was on stream in 2014. The field is producing from the Zhujiang reservoir at a rate of 23,500 b/d of oil in 2016.   LF 13-2 field, operated by CNOOC, also has reservoir in the Zhujiang Formation and on stream in 2006. It is produced at a rate of 6,400 b/d of oil in 2016.   LF 13-1 field has primary reservoir in the Zhujiang Formation and secondary one in the Oligocene Enping Formation. The field has been producing since 1993 and produced 16,000 b/d of oil in 2016.   LF 22-1 field - The field was officially shut down in June 2009 after nearly 12 years production as the field depletion.  In 2019, CNOOC is preparing to launch a new overall development plan for Lufeng oil fields cluster in the South China Sea oil fields cluster.  The Lufeng oil fields cluster, including Lufeng 14-4/14-8/8-1, Lufeng 15-1 and Lufeng 22-1, lies in the east or southeast part of the existing Lufeng oil fields group Lufeng 7-2 and Lufeng 13-1 fields. The Lufeng 22-1 field SPS will be connected to the drilling/production platform in the Lufeng 15-1 field via a 19 km of pipeline. A drilling/production platform will be built in the Lufeng 14-4 field and linked with the platform in the Lufeng 15-1 field via a 23.8 km pipeline.",LF 21-4-1 was completed in late September 2019 without result reported.
45717,"P2170 / blocks 20/5b + 21/1d, Outer Moray Firth, TD 3,784m, U. Jurassic sands target not encountered, contingent resource estimates likely to be revised towards the lower end of the initial Verbier estimate of 25 MMboe, West Phoenix SS. Equinor (op), partners Trap Oil (Jersey O&G) + CIECO. Map: JOG.","020/05b-14 (Verbuier) appr, (Equinor 70% op, Trap Oil (Jersey O&G) 18%, CIECO 12%) in P2170 / blocks 20/5b + 21/1d, U. Jurassic sands target not encountered, contingent resource estimations for the Verbier discovery likely to be revised towards the lower end of the initial estimate of 25 Mmboe. TD=3784m."
56839,"Lundin used the “Leiv Eiriksson” S/S to drill exploration well 16/5-8 S which was spudded on 8 July 2019. The well investigated the Goddo prospect in PL 815 and was drilled to TD at 2,468 m (2,093 m TVD) in Basement. An oil column of 20 m was confirmed in weathered and fractured Basement, similar to the reservoir found at Rolvsnes (located 9 km to the northwest) but not in pressure communication with it. Estimated recoverable reserves are 1-10 MMboe, with further upside possible in the area. Lundin will carry out an EWT at Rolvsnes in 2021 and the results from this will help the company decide its forward strategy relating to the Basement reservoirs in the region. The well is being abandoned on 20 August 2019 (expected end date 23 August 2019).  Prior to drilling, Lundin had provided a gross unrisked prospective resource estimate of 112 MMboe for Goddo, with the prospect proposed as a geological continuation of Rolvsnes and the same OWC (at 1,928 m subsea) forecast. There had also been plans for a potential sidetrack which would have been drilled with up to a 2,200 m horizontal section through the reservoir and a 10 day test could have been performed.   Lundin drilled an appraisal well at Rolvsnes over the summer of 2018. 16/1-28 S encountered 2,500 m of fractured and weathered Basement in a horizontal section. A 10 day test flowed at a maximum rate of 7,000 bo/d through a 52/64” choke. During the five-day main flow period production was maintained at a rate of approximately 4,200 bo/d. The test results indicate that the reservoir has good productivity supported by aquifer pressure. Following the results, the resource range at Rolvsnes was revised upwards to between 14 and 78 MMboe from the previous estimate of between 3 and 16 MMboe. Rolvsnes is considered a potential tie-back candidate to Edvard Grieg.  Prior to drilling the Goddo well, Lundin believed that Rolvsnes and Goddo together could contain over 250 MMboe.  Interest in PL 815 is held by Lundin Norway AS (60% + operator), Concedo ASA (20%) and Petoro AS (20%).","016/05-08 S (Goddo) nfw (Lundin 60% op, Concedo 20%, Petoro 20%) 1st well in PL 815, 14km S. of Edvard Grieg, small oil discovery of recoverable 10 MMboe max. in poor quality reservoir, weathered, basement rock (potential oil column of about 20m), not in communication with Rolvsnes, WD=104m, TD=2443m."
60749,"REC-T-108, onshore Recôncavo, , oil shows report to ANP 8 Oct '19. Drilling continues towards PTD 3,388m (spudded 21 Dec ’18), targets Agua Grande + Sergi fm’s.",Brazil (Central Reconcavo Sub-basin (Reconcavo B.)) Agua Grande
16535,"On 16 March 2018 Shell reported that it had reached a deal to sell its remaining assets in New Zealand to OMV for USD 578 million (NZD 798 million).  Shell reported that the deal the companies have reached will see the sale of shares in its New Zealand entities to OMV. The sale is the final step in Shell’s exit of New Zealand, which it has been planning for some time. Shell had reported in mid-December 2015 that it had commenced a strategic review of its assets in New Zealand and stated that it believes New Zealand is a “great place to do business and these assets are profitable, well maintained and are an important part of New Zealand’s energy mix”. However, the assets are considered just a part of Shell’s global business and so have been reviewed as part of the larger evaluation of assets. It was then reported in August 2016 that Shell had enlisted JPMorgan investment bank to commence the potential sale of its entire New Zealand portfolio.  The agreement with OMV includes the Maui and Pohokura assets as well as associated infrastructure and Shell’s operated interest in exploration permit PEP 50119 in the Great South Basin. These were the final assets held by Shell after the gradual divestment of its other interests over the last two years.  The deal with OMV is subject to conditions, including regulatory approval. In October 2017 it was reported in the media that a number of companies were thought to be showing an interest in Shell’s remaining New Zealand portfolio.  These included OMV, as well as Questus Energy, a Sydney private equity firm, Jadestone Energy, Vermillion Energy, Woodside and also potentially Beach Energy after reports it may look at Shell’s assets alongside bidding for Origin’s spinoff Lattice Energy, in which it was successful.  In January 2018 it was reported that it was thought Jadestone Energy and Questus Energy were no longer looking at a purchase and that Beach had also dropped interest after entering agreements to acquire Origin’s spinoff company, Lattice Energy.  The sale of assets in New Zealand has been part of a large, global initiative, in which Shell hopes to streamline and become more profitable and resilient in the current market. Following Shell’s acquisition of BG Group in February 2016, Shell continued to plan a reduction in 2016 CAPEX and to sell up to USD 30 billion worth of global assets by 2018, including a total exit of five to ten counties. Major streamlining has already taken place in Australia including exiting from Chevron’s Wheatstone LNG project. Shell reported that it is planning on focusing on big growth opportunities, with a focus on deep water and integrated gas.  ","OMV acquires Shell's New Zealand assets for US$578 MM. Concerning are following assets: 48% (->74%) interest in the Pohokura gas field, 83,75% (->93,75%) interest in the Maui gas field, and 60,98% (->82,93%) in explo block PEP 50119."
58201,"Tap Oil Ltd reported on 9 September 2019 that it had reached a deal to sell its remaining Australia and New Zealand to Kensington Energy Ltd. Under the terms of the sale and purchase agreement, Kensington Energy will be acquiring Tap’s interest in WA-25-L and WA-72-P, located in the Australian North Carnarvon Basin, as well as its overriding royalty interest in PMP 53803, located in New Zealand’s Taranaki Basin.  Kensington Energy will be paying USD 3.21 million in the transaction, which will have an effective date of 31 March 2019.   It is subject to regulatory conditions, though no government approvals are required and no pre-emptive rights have been exercised.  WA-25-L covers an area of 400 sq km and was awarded on 21 June 2002.  Tap holds 15% interest in the licence, which Kensington Energy will take at the completion of the deal. Partners in the licence are Eni Australia Ltd (65% + Operator) and Mobil Australia Resources Co Pty Ltd (20%).  The licence contains the Woollybutt and Woollybutt South fields, which were discovered in May 1997 and December 1999 respectively. Both produced, Woollybutt coming onstream in April 2003 and Woollybutt South in July 2008, until both were abandoned in June 2012.  Decommissioning is planned for 2020.  Tap Oil reported that field abandonment costs will be passed to Kensington Energy, with Tap having no future liability.  WA-72-R covers an area of 160 sq km and was awarded on 11 April 2016.  Tap Oil holds a 20% interest, which Kensington Energy is acquiring, with BHP Billiton holding 55% and operatorship and Santos holding the remaining 25%.  The licence contains the north sections of the Tallaganda and Bunyip gas discoveries, which were made in April 2012 and March 2014 respectively and are being appraised for potential development.  In PMP 53053 Tap Oil has a 5% oil, gas and condensate overriding royalty on 66.67% of the permit, which covers the Sidewinder field, discovered in September 2010. The field has been producing since October 2011.  Tap reported that its 2018 revenue from the royalty was USD 0.15 million. The PMP 53053 permit, which covers an are of 2.9 sq km and was awarded on 22 February 2012, is held 100% by Tamarind Resources.   Kensington Energy is a privately owned Australian oil and gas investment company, which is reported to be looking to acquire non-operated interest in oil and gas assets across Australasia to build a diverse portfolio of assets.  Tap has been attempting to divest its remaining Australasian assets, to focus on its Manora asset in Thailand, for some time.  During the process a number of licences have been surrendered, or sold to other parties.  The sale of interest to Kensington Energy is part of Tap’s final exit from the region. Tap currently holds interest in two other licences, outside of the Kensington Energy deal, WA-34-R and WA-22-L.  Both licences are planned to be surrendered.","Australia, WA-25-L"
25245,"On 1 July 2018, Chevron USA was awarded Mississippi Canyon blocks MC 34 (G36237), MC 241 (G36242), MC 285 (G36243), MC 329 (G36246), MC 606 (G36255) and MC 740 (G36257), situated in the Gulf of Mexico and Louisiana Coastal basins. The blocks were originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, Chevron USA is now the operator and sole interest-holder (100% WI + Op) in MC 34, MC 241, MC 285, MC 329, MC 606 and MC 740.","On 1 July 2018, Chevron USA was awarded Mississippi Canyon blocks MC 34 (G36237), MC 241 (G36242), MC 285 (G36243), MC 329 (G36246), MC 606 (G36255) and MC 740 (G36257), situated in the Gulf of Mexico and Louisiana Coastal basins. The blocks were originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, Chevron USA is now the operator and sole interest-holder (100% WI + Op) in MC 34, MC 241, MC 285, MC 329, MC 606 and MC 740."
39109,"In H2 2018, it was confirmed that Khalda Petroleum had successfully encountered gas in its Pacific 2 appraisal well, located on the WD 30/Abu Gharadig development lease (DL) of the WD Merged PSC. The well had been drilled in H1 2018. It was the first appraisal of the Q2 2015 Pacific 1X discovery, drilled ~1.5km to the NW. It reached 3,734m and encountered gas in the Cretaceous Abu Roash sandstone. Pacific 2 is one of four exploration wells drilled on the DL in 2018. Equity in the Khalda Petroleum consortium is split between Apache (33.5%), Sinopec (16.5%) and EGPC (50%, carried). ",Not Found
30831,"Advent Energy Ltd announced on 28 September 2018 that it had signed a binding agreement to sell the majority shares in its wholly owned subsidiary Offshore Energy Pty Ltd to Bonaparte Petroleum Pty Ltd.  Bonaparte Petroleum has agreed to purchase 90% of the shares in Offshore Energy, currently held by Advent.  The agreement is conditional upon board approval of both companies, Bonaparte Petroleum showing it has the capability to fund the work programme proposed in the transaction and potential shareholder approval, if required by the Australian Securities Exchange (ASX).  Offshore Energy holds 100% interest in exploration licence EP 386 and retention lease RL 1, both located in the onshore Bonaparte Basin.  Bonaparte Petroleum has indicated that it has the capability to progress the licences, and under the terms of purchasing the shares has agreed to submit required documents for the drill of one or two exploration wells within EP 386, as well as acquiring 50 km new 2D seismic prior to the end of the current permit validity period, which concludes on 31 March 2020.  The company will also complete the decommissioning of two existing wells.   The work will be fully funded by Bonaparte Petroleum under the share acquisition.  Further terms to the agreement include the issue of 10% interest, under a standard joint operating agreement, to Advent on the award of any subsequent retention or production licences over the current asset area. Under these terms Advent will earn a 10% share in Bonaparte Petroleum, and transfer the remaining shares in Offshore Energy to Bonaparte Petroleum.  A further 10% interest in any subsequent licences will be granted to Advent upon the discovery of 15 MMboe reserves.  An option remains for Advent to buy back into REL 1. If EP 386 is not renewed or transferred to a retention or production licence, Advent will also be reinstated as operator and holder of RL 1.  If Bonaparte Petroleum chooses not to proceed with the transaction outlined in the agreement reached on 28 September 2018, Advent will be paid a break fee of AUD 50,000.  Advent Energy Ltd had been aiming to farm-out interest in the licences, alongside its other Australian asset PEP 11, located in the Sydney Basin.","Advent Energy Ltd announced on 28 September 2018 that it had signed a binding agreement to sell the majority shares in its wholly owned subsidiary Offshore Energy Pty Ltd to Bonaparte Petroleum Pty Ltd.  Bonaparte Petroleum has agreed to purchase 90% of the shares in Offshore Energy, currently held by Advent."
68413,"N-C part of PN-T-048 block, Parnaíba Basin onshore, oil shows report to ANP 30 Dec '19, susp. early Jan '20. PTD was 2,722m, targets Cabeças + Poti fm's.","4-ENV-WTIANGUAR-MA (4-ENV-010-MA) npw in N-C part of PN-T-048 block, Parnaíba Basin onshore, oil shows report to ANP 30 Dec '19, susp. early Jan '20. PTD was 2,722m, targets Cabeças + Poti fm's."
19890,"In late February 2018, RWE Dea abandoned the Ras Budran East Offshore 1ST1 (ERBO-1ST1) wildcat, in the Gulf of Suez. The original hole ERBO-1, was spudded on 11 December 2017 with the “ST-12” land rig and drilled to a depth of 2,438 m. Then the well was sidetracked in late December 2017 and drilled to at a TD of 3,328 m in the Rudeis formation.  The well had a planned TD of 3,420 m and objectives in the Matulla, Raha and Nubia formations.  RWE Dea operates the block with an 80% interest and Dove Energy holding the remaining 20%.  Background information  On 12 November 2012, RWE Dea announced that it has been awarded the East Ras Budran Offshore concession in the Gulf of Suez. The block was offered in the International Bid Round 2011 of the Egyptian General Petroleum Corporation (EGPC). The licence award is subject to the Egyptian Parliament approval. The concession is adjacent to the Ras Budran producing concession operated by the company. It is the sixth licence held by RWE in Egypt.","RWE Dea abandoned the Ras Budran East Offshore 1ST1 (ERBO-1ST1) wildcat, in the Gulf of Suez. The original hole ERBO-1,"
41273,"Medco has sold Biyaq Oilfield Services a 25% stake in Mudawrat block 56,  5,808 sq km mostly onshore Eastern Flank + Oman Tertiary Basin.  Partnership now Medco (op), partners Intag + Biyaq.","Medco has sold Biyaq Oilfield Services a 25% stake in Mudawrat block 56,  5,808 sq km mostly onshore Eastern Flank + Oman Tertiary Basin.  Partnership now Medco (op), partners Intag + Biyaq.)"
24591,"WL4-00 astride the West Luconia + Central Luconia provinces off Sarawak, P&A results n/a around 23 Jun ’18, Naga 4 JU. Target Middle Miocene Cycle V clastics. COP (op), partner Petronas.","Salam-2 appr WL4-00 astride the West Luconia + Central Luconia provinces off Sarawak, P&A results n/a around 23 Jun ’18, Naga 4 JU. Target Middle Miocene Cycle V clastics. COP (op), partner Petronas."
85412,"Aker BP and Shell have completed a swap deal whereby Aker BP has acquired a 10% interest in PL 1056 and Shell has acquired 20% in PL 1005. PL 1056 covers an area of 4,549 sq km over blocks 6302/1 to 6302/12 in the deepwater More Basin to the west of Ormen Lange. It contains the 2005 Tulipan gas discovery. PL 1005 covers 1,775 sq km over blocks 6404/9, 6404/12, 6405/4, 6405/7 and 6405/10 and contains the 2003 Ellida oil discovery. It is located north of Ormen Lange in the deepwater Voring Basin. The deal was confirmed by the NPD on 10 July 2020 and is effective from 30 June 2020.   Statoil (now Equinor) drilled Tulipan well 6302/6-1 and confirmed gas in the Paleocene Rogaland Group at around 3,900 m below a very thick Quarternary (Naust Formation) North Sea Fan. The find was small and the well was not tested.  Ellida well 6405/7-1, also operated by Statoil, proved oil in the Upper Cretaceous Nise Formation between 2,760 m and 2,823 m, with good oil shows below this depth. However, reservoir quality was generally poor and on test the well flowed only 252 b/d of 31°API oil.   Following completion of the deal, interest in PL 1005 is divided between Aker BP ASA (40% + operator), Var Energi AS (40%) and A/S Norske Shell (20%) and interest in PL 1056 is held by A/S Norske Shell (30% + operator), Petoro AS (20%), DNO Norge AS (20%), Wintershall Dea Norge AS (20%) and Aker BP ASA (10%).","Norway (More B.), PL 1056, Aker BP has acquired a 10% stake in PL 1056, 4,549 sq km in the More Basin (blocks 6302/1 + 12, Tulipan discovery), in exchange for Shell getting 20% in PL 1005, 1,775 sq km over blocks 6404/9 + 12, 6405/4, 7 + 10 (Ellida discovery) in the deepwater Voring Basin. The deal is effective 30 Jun '20. PL 1005 partners now Aker BP (op), Vår + Shell and PL 1056 Shell (op), Petoro, DNO, Wintershall Dea + Aker BP."
63878,"Strike's West Erregulla gas find in EP 469, onshore Perth Basin, looks set to become one of WA's largest gas fields at 1.1 TCF resources, and more could come from further testing of the Wagina sst. Appraisal drilling may follow in 2H '20, 1st gas in 2022. Strike (op), partner Warrego Egy.","Strike Energy confirmed Erregulla West gas discovery is one of the largest onshore conventional gas fields ever in Western Australia with a best estimate contingent gas resource of 1,1 Tcf  and more could come from further testing of the Wagina sst."
55724,"Tecpetrol has reportedly secured 35-year unconventional rights licenses for the Los Toldos I Norte (202 sq km, gas target) and Los Toldos II Este (76 sq km, oil) blocks in the Neuquén. Tecpetrol (op), partner GyP Neuquén. Some background from GEPS.","Tecpetrol (partner GyP Neuquén) has reportedly secured 35-year unconventional rights licenses for the Los Toldos I Norte (202 sq km, gas target) and Los Toldos II Este (76 sq km, oil) blocks. "
17431,"Brazil’s government aims to hold an oil and gas auction in the second half of this year for areas left over after it settles a disputed contract with state-controlled oil firm Petrobras, according to a senior official.The choice reserves, located in the offshore Santos basin, are part of the 'transfer-of-rights' area that the government passed to Petrobras at a price that is still in dispute. Since 2014, negotiations to resolve the dispute have been contentious, with both parties claiming to be owed billions of dollars.A resolution is finally in sight, Mining and Energy Minister Fernando Coelho Filho said at an event last week, adding that the government could reach a deal within 40 days to pay Petrobras.Click here for full Reuters articleSource: Reuters","Brazil’s government aims to hold an oil and gas auction in the second half of this year for areas left over after it settles a disputed contract with state-controlled oil firm Petrobras, according to a senior official.The choice reserves, located in the offshore Santos basin, are part of the 'transfer-of-rights' area that the government passed to Petrobras at a price that is still in dispute. "
41938,"On 11 February 2019, the CNH approved a PEMEX request to modify the exploration work commitments for four entitlements in the onshore Tampico-Misantla Basin, unconventional play.  The blocks include the AE-0381-2M-Pitepec, the AE-0382-2M-Amatitlan, the AE-0385-2M-Soledad, and the AE-0386-2M-Miahuapan.  The proposed modified exploration plans include the drilling of one firm commitment horizontal unconventional well and one contingent horizontal unconventional well in each block.  Also each prospect will have a vertical pilot hole.  The approval of the exploration plan is also a requisite for the entitlements to be migrated to exploration and production contracts which has also been ongoing for about two years.      For the AE-0381-2M-Pitepec entitlement block the firm commitment well is the Axlatitla 1EXP with targets in the Upper Jurassic Kimmeridgian and Upper Jurassic Tithonian Pimienta Formation.  The proposed total depth (PTD) measured depth (MD) is 4,545 m and prospective resources are estimated to be 18 MMboe.    The contingent well is the Iscata 1EXP with targets in the Upper Jurassic Tithonian Pimienta Formation and Upper Jurassic Oxfordian Santiago Formation.  The proposed total depth (PTD) measured depth (MD) is 4,450 m for the Upper Jurassic Tithonian and 4,900 m for the Upper Jurassic Oxfordian target.  The true vertical depth for the pilot hole is 3,750 m and total prospective resources are estimated to be 38 MMboe from the two target zones.  The total budget for drilling both wells and G&G is USD 51.1 million.  The drilling is scheduled to commence in late 2019 and early 2020.     For the AE-0382-2M-Amatitlan entitlement block the firm commitment well is the Patsay 1EXP with targets in the Upper Jurassic Tithonian and Upper Jurassic Oxfordian.  The proposed total depth (PTD) measured depth (MD) is 5,295 m and TVD is 3,915 m with the top of the first target at 2,885 m and the second target at 3,445 m TVD.  The total prospective resources are estimated to be 48 MMboe for the two target zones.    The contingent well is the Solim 1EXP with targets in the Upper Jurassic Tithonian and Upper Jurassic Oxfordian.  The proposed total depth (PTD) measured depth (MD) is 4,445 m and 3,795 m TVD.  The total prospective resources are estimated to be 46.6 MMboe.  The total budget for drilling both wells and G&G is USD 55.1 million.  The drilling is scheduled to commence in late 2019 and early 2020.     For the AE-0385-2M-Soledad entitlement block the firm commitment well is the Akchan 1EXP with a target in the Upper Jurassic Kimmeridgian.  The proposed total depth (PTD) measured depth (MD) is 5,025 m and TVD is 2,840 m.  The total prospective resources are estimated to be 13.6 MMboe.    The contingent well is the Baku 1EXP with a target in the Upper Jurassic Kimmeridgian.  The proposed total depth (PTD) measured depth (MD) is 4,450 m and 2,950 m TVD.  The total prospective resources are estimated to be 9.75 MMboe.  The total budget for drilling both wells and G&G is USD 28.9 million.  The drilling is scheduled to commence in late 2019 and early 2020.     For the AE-0386-2M-Miahuapan entitlement block the firm commitment well is the Spun 1EXP with targets in the Upper Jurassic Tithonian and Upper Jurassic Oxfordian.  The proposed total depth (PTD) measured depth (MD) is 4,900 m for the first target and 5,252 m for the second target and TVD for the pilot hole is 3,772 m.  The total prospective resources are estimated to be 49 MMboe for the two target zones.    The contingent well is the Tlaxe 1EXP with targets in the Upper Jurassic Tithonian and Upper Jurassic Oxfordian.  The proposed total depth (PTD) measured depth (MD) is 4,530 m for the first target and 4,875 m for the second target and TVD for the pilot hole is 3,662 m.  The total prospective resources are estimated to be 45 MMboe.  The total budget for drilling both wells and G&G is USD 69.24 million.  The drilling is scheduled to commence in late 2019 and early 2020.   On 21 August 2018, the CNH issued a report and opinion to SENER regarding a PEMEX request for a two year extension of five exploration and production entitlements including the AE-0381-2M-Pitepec block, the AE-0382-2M-Amatitlan block, the AE-0385-2M-Soledad block, the AE-0386-2M-Miahuapan block, and the AE-0388-2M-Miquetla block. The entitlements have a first period expiry date of 1 September 2018 after being officially granted on 1 September 2015.  The two year extension period would keep the entitlements valid until 1 September 2020. The CNH reviewed the minimum work program (CMT) covering the five blocks that were supposed to be carried out during the course of the first three year exploration period and found that the operator did not comply with the minimum work commitments or investments on any of the blocks.  The operator met most commitments for studies and processing seismic but drilled none of the well commitments, which was one well in each block.   However, PEMEX justified the shortfall of its CMTs to the fact it is focusing exploration efforts on unconventional resources and the regulations for unconventional operations were not officially in force until early 2018.  PEMEX has been in the process to migrate the legacy Service Contracts, formerly production entitlements or A denominated blocks from Ronda 0, to the new exploration and production model contract (CEE) for several years now, the AE exploration and production entitlements an intermediate step, and they are still pending.     On 13 October 2016, the CNH approved a request by PEMEX to modify its exploration commitments for five modified Service Contracts that migrated to Exploration and Production entitlements.  In September 2015, SENER granted PEMEX rights to all horizons instead of just the Paleocene and Upper Cretaceous productive zones in the blocks.  The rights include all stratigraphic horizons to the Jurassic and also for unconventional exploration and production.    On 1 September 2015, the Secretaria de Energia de Mexico (SENER) granted formal approval for the migration of the legacy Service Contracts, formerly production entitlements or A denominated blocks to the Exploration and Production entitlements.","Mexico, AE-0386-2M-Miahuapan"
37077,"On 6 December 2018 the Dutch Ministry reported that Tulip Oil sold its participation in the F6b licence on 16 November 2018. It is yet not known who acquired Tulip Oil’s interest. In May 2016 operator Dana Petroleum submitted an application to convert F6b into a production licence which is currently still pending.  F6b contains the F6-5 (Zulu North) and the F6-6ST2 (Snellius) discoveries, both made in 2014. The F6-5 (Zulu North) oil discovery is situated in the northern part of the block. The reservoir is situated below a depth of 2,900 m in the Lower Graben Fm. The F6-6ST2 (Snellius) oil discovery was made in the central part of the block. Its reservoir was also encountered below a depth of 2,900 m in the Lower Graben Fm. F6b also contains three unsuccessful wells - F6-2 (1997 – oil shows), F6-3 (2004 - dry) and F6-4, 4ST1 (2011 – oil shows).  Tulip Oil held a 10% participation in the F6b licence, which is operated by KNOC through Dana Petroleum Netherlands BV (36%) with partners Energie Beheer Nederland BV (40%) and Oranje-Nassau Holdings BV (14%).","Netherlands, F6b"
12142,"Spirit Energy has sold its 40% in P2112 (blocks 43/29a + 40b, 48/4a, 4b + 5a to partners Holywell Resources + Atlantic Petroleum. The 485-sq km licence west of Schooner is now shared by Holywell (op) + Atlantic  2/3:1/3. ","Spirit Energy, the newly formed company as a result of the merger between Centrica and Bayerngas, has exited licence P2112 (Holywell Res.(->66,67% op.) and Atlantic Petroleum (->33,33%). "
57336,"Total is farming out a 30% interest in block 2913B (8,251 sq km, Total op, drilling planned in 2020), and 28.33% in block 2912 (7,841 sq km, Total op), deepwater Orange Basin. The deals are subject to necessary approvals:","otal is farming out to Qatar Petroleum a 30% interest in block 2913B (8,251 sq km, Total op, drilling planned in 2020), and 28.33% in block 2912 (7,841 sq km, Total op), deepwater Orange Basin. "
32453,"PEMEX completed as an oil and gas discovery the Semillal 1EXP horizontal new-field wildcat (NFW) in the AE-0070 block in the onshore Burgos Basin during early-October 2018.  The operator continues testing the well after a frac job.    The NFW      was spudded on 15 April 2018.   This      represents the first unconventional horizontal well spudded in the country      since 2014, while operators waited for the environmental regulations to be      approved.     The NFW had a proposed total depth (PTD) of 3,690 m      measured depth (MD) and 2,150 m true vertical depth (TVD).        The Upper Jurassic Pimienta Formation was the primary      objective.       The prospect size is reported to be 18 MMboe with a      proposed drilling and completion cost estimated at approximately USD 13.4      million.        PEMEX plans to drill a 1,500 m horizontal leg and frac      it with up to 15 stages.       PEMEX attempted to obtain approvals for horizontal      unconventional wells in 2015 but it was delayed for environmental reviews      regarding the activity.       The well is located in the southwestern area of the      block about 800 north-west of the Buenos Aires 1 well.    SENER granted the AE-0070-2M-Anhelido-02 entitlement      to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an      approximate area of 926.74 sq km.   On 20 February 2018, the CNH approved the drilling permit for PEMEX to drill the Semillal 1EXP horizontal new-field wildcat (NFW) in the AE-0070 block in the onshore Burgos Basin.  PEMEX suspended the drilling permit in 2016 due to lack of environmental regulations which have since been published after a two year delay.  On 9 November 2016, the CNH reported that PEMEX requested that its authorization to drill the Semillal 1 horizontal new-field wildcat (NFW) in the AE-0070 block in the onshore Burgos Basin be suspended due to environmental requirements by environmental protection agency ASEA. PEMEX requested the permits be suspended until ASEA issues specific public regulations regarding unconventional drilling activity.  Details were not reported regarding the ASEA requirements but are speculated to be very onerous.   On 25 February 2016, the CNH originally approved plans by PEMEX to drill the Semillal 1 horizontal new-field wildcat (NFW) in the AE-0070 block in the onshore Burgos Basin.","Mexico, AE-0070-2M-Anhelido-02"
14145,"PL 170, Cooper-Eromanga, TD 1,282m, drilled mid to late-Jan ’18, encountered 4.4m net pay in the Murta fm, suspended as oil producer. Santos (op), partner Beach.","Australia, Takyah-6 appr in PL 170, encountered 4.4m net pay in the Murta fm, suspended as oil producer. Santos (op), partner Beach."
11721,"Santos Ltd acquired a 45% in retention lease WA-55-R, located in the North Carnarvon Basin, on 21 December 2017.  Santos has acquired the interest partly from operator Quadrant Northwest Pty Ltd and partly from the withdrawal of previous holder Harriet (Onyx) Pty Ltd. Harriet (Onyx) Pty Ltd had held a 20% interest in the licence.  This, as well as 25% of Quadrant’s holding, has now been assigned to Santos, which had no previous interest in the licence.   WA-55-R contains the Kultarr 1 gas discovery, which was made in 2005.  Current work commitments for the licence include review of the discovery and evaluating options for its development. At the time of this deal, Santos also acquired a 45% interest in a number of other Quadrant permits within the North Carnarvon Basin – WA-43-R, WA-50-R, WA-499-P and WA-501-P.  Santos also increased its holding, to 45%, in exploration permit WA-01-P. WA-55-R, which covers an area of 139 sq km, was awarded on 1 May 2014.  Now that Santos has acquired interest and Harriet (Onyx) had withdrawn, participants in the permit are Quadrant Northwest Pty Ltd (55% + Operator) and Santos (BOL) Pty Ltd (45%).    ",Santos acquired a 45% in retention lease WA-55-R from Quadrant NW and partly from the withdrawal of previous holder Harriet (Onyx). 
36706,"Khaskeli ML (Badin I), Lower Indus onshore, tested and ops terminated at TD 1,986m in late Nov ’18, target Lower Goru assumed productive, no details, ZPEC rig 33.","Sukhi S,-1 nfw Khaskeli ML (Badin I), Lower Indus onshore, tested and ops terminated at TD 1,986m in late Nov ’18, target Lower Goru assumed productive, no details, Z"
80328,"PPL 6, Cooper Eromanga, P&A'd earlier this week, Ensign rig 967. Santos (op), partner Beach.","Gidgealpa S.-1 nfw PPL 6, Cooper Eromanga, P&A'd earlier this week, Ensign rig 967. Santos (op), partner Beach."
28936,"Echo Energy on 31 August 2018 announced an agreement signed with YPFB that will give it exclusive rights to continue a technical evaluation of the Rio Salado Block in the Tarija Basin for the next year. The work program includes interpreting and integration of three 2D seismic lines acquired in 2015 and 2016, according to the company. At the end of the technical evaluation agreement period, Echo will have the right to negotiate terms for a service contract with YPFB for the block if the company chooses to do so. The acquisition of a working interest in Rio Salado depends on the final commercial terms. Echo on 15 September 2017 announced the award of a seismic reprocessing contract for 3D seismic data on the Huayco and Rio Salado blocks. Echo Energy, on 25 July 2017 announced the signing of a Technical Evaluation Agreement (TEA) for the Rio Salado Block in the Tarija Basin. The TEA contract also included Pluspetrol and YPFB and was signed in Santa Cruz. The Rio Salado Block (502 sq km) includes two dry holes from the early 1960's. An enclave carved from the block includes Huayco Field. The block also includes, according to Echo, the extension of a structure it previously identified. The evaluation study contract gives a company rights to explore the block for a one or two year period but no economic rights for exploration or production and usually carries only a modest investment commitment. However, if initial exploration appears favorable, the company will be given the first option to sign a license contract with a view to drilling exploratory wells and developing production in the areas. ",Echo has signed a LoI with YPFB for a 1-year TEA over the Rio Salado licence area.
66753,"Spirit Energy has exited Valemon Field licences PLs 050 ES, HS & GS, and 193 B & D, assigning its 13% to operator Equinor, effective 29 November 2019. Valemon Field was originally estimated to hold 192 MMboe reserves prior to start up in January 2015, but this figure was retroactively downgraded to  99 MMboe at end 2018, when remaining recoverable reserves were 31 MMboe. Similarly production has fallen from 60,000 boe/d when it came online in January 2015, to 40,000 boe/d. This is likely due to its complex, fragmented reservoir with poor communication between different sections, an issue which was identified as a caveat to the original reserves estimate. The HPHT gas/condensate field produces from Early to Middle Jurassic Cook, Tarbert, Ness, Etive and Rannoch formations and was discovered by 34/10-23 (1985, Statoil, 4,764m), later incorporating 34/10-54 S (2014, Statoil, 4,280m). Subsequently Valemon West wildcat 34/11-6 (2017, Statoil, 7,126m MD/4,337m TVD) encountered an estimated 100-280 Bcfg in Tarbert sands. Valemon is operated by a remote-controlled production platform managed from a control room in Bergen, and was previously expected to produce until 2023, at around 60,000 boe/d. Condensate is piped to Kvitebjorn for processing and onward to Mongstad refinery near Bergen, while gas is piped for processing at Heimdal platform. Valemon Unit partners are Equinor Energy AS (66.775% + Op), Petoro AS (30%) and AS Norske Shell (3.225%).",Not Found
10187,"Arenite Petroleum has announced the sale of 50% interest in Promote Licence P2304 (UKCS Block 41/24) to Egdon Resources U.K. The consideration comprises paying the regulator the 2017 licence rental and OGA Levy and all transaction legal costs. Future conditional payments to Arenite of up to £725,000 net (being 50% of £1,450,000 gross) are listed below: On completion of the acquisition of a 3D survey over any part of the Licence (other than a third-party survey to which neither the P2304 Licensees nor the licensees of the P1929 licence have access) a cash payment of fifty thousand Pounds (£50,000). On completion of the drilling of the first well located wholly or partly within the area covered by the Licence a cash payment of one hundred thousand Pounds (£100,000). On first production, other than testing, from any well located wholly or partly within the area covered by the Licence a cash payment of one hundred thousand Pounds (£100,000). On reaching a total production of five billion standard cubic feet of gas (5 bcf) (or oil equivalent) from any wells located wholly or partly within the area covered by the Licence a cash payment of two hundred thousand Pounds (£200,000). On reaching a total production of twenty billion standard cubic feet of gas (20 bcf) (or oil equivalent) from any wells located wholly or partly within the area covered by the Licence a cash payment of one million Pounds (£1,000,000).   P2304 was awarded in the UK Offshore 28th Licensing Round with an effective date of 1 December 2015. By consolidating licences P1929 and P2304 under Egdon’s 100% control, OGA is minded to extend the Initial Term of the Licence until 1 December 2018.  The transfer of interests in P2304 from Arenite & Europa to Egdon is subject to regulatory approval. The Resolution (41/18-1, 1966, ~3mmscfgd) discovery and the Maxwell field (wells 41/24a-1 (1969, Total, 15mmscfgd), 41/24a-2 (1982, Total, 19mmscfgd), and 41/24-3 (1991, Conoco, 34 mmscfgd & 1280 bcpd)) have historically been considered to be small accumulations. Reinterpretation of the seismic data shows both fields are part of a much larger regional high structure which has hydrocarbon shows over an area covering up to five North Sea blocks. The Resolution reservoir is a Permian Hauptdolomite carbonate whereas the Maxwell discovery is in the younger naturally fractured Permian Plattendolomite carbonate. Additionally, extensive gas shows were also encountered in the thick underlying Carboniferous sandstones and shales but are yet to be flow tested. Commenting on the acquisition, Mike Cooper, CEO said:  'We are delighted that Egdon recognises the significant extension of the Resolution discovery into block 41/24 where three wells have each tested over 15 million standard cubic feet of gas per day in a shallower horizon than at Resolution. Though the outlook for the oil and gas sector has improved in the last 12 months, it has not been sufficient to deliver a farminee for the P2304 licence in isolation. However, by effectively combining the two licences, Egdon and the Oil & Gas Authority have had the vision of making the ‘pie bigger’, significantly improving the opportunity quality and dramatically lowering the economic threshold. This deal is a win-win for all parties and is consistent with OGA’s MER strategy. We wish Egdon every success going forward.' Click here for Egdon Resources announcement: P2304 Offshore Licence Acquisition Click here for Europa announcement: P2034 Offshore Licence Sale Source: Arenite Petroleum ","United Kingdom, not found"
9743,"Effective 1 October 2017 Hilcorp Alaska LLC was officially awarded 14 tracts covering about 76,682 acres (310 sq km) off Alaska’s south-central coast from the Cook Inlet Lease Sale 244 held by the Bureau of Ocean Energy Management (BOEM) on 21 June 2017. The company placed high bids in the amount of USD 3,034,815 and was the sale’s lone bidder. Sale 244 was the thirteenth and final OCS lease sale held under the 2012-2017 Five-Year Program. It offered some 1.09 million acres (4,410 sq km) for leasing and consisted of 224 blocks that stretched roughly from Kalgin Island in the north to Augustine Island in the south.  Each bid went through a 90-day evaluation process to ensure the public received fair market value before a lease was awarded. All materials and statistics for Lease Sale 244 are available at: http://www.boem.gov/ak244. Hilcorp Official Awards               Contract Company Name WI Bonus USD Acre Sqkm Lease Sale Award Date Basin   Y02434 Hilcorp Alaska 100 $62,208.00  5,184.26 20.98 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02435 Hilcorp Alaska 100 $37,416.00  3,118.47 12.62 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02436 Hilcorp Alaska 100 $68,376.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02437 Hilcorp Alaska 100 $142,500.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Y02438 Hilcorp Alaska 100 $111,606.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02439 Hilcorp Alaska 100 $313,500.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02440 Hilcorp Alaska 100 $474,582.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02441 Hilcorp Alaska 100 $203,319.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02442 Hilcorp Alaska 100 $111,606.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Y02443 Hilcorp Alaska 100 $256,500.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02444 Hilcorp Alaska 100 $474,582.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Y02445 Hilcorp Alaska 100 $474,582.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02446 Hilcorp Alaska 100 $152,019.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02447 Hilcorp Alaska 100 $152,019.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Totals     $3,034,815.00  76,681.62 310.32         Source: IHS Markit               ©   2017 IHS  ","United States, Y02440"
15103,"Lundin Petroleum has acquired Fortis Petroleum's entire 30% interest in PL820 S, effective on 15 February 2018. Awarded in APA 2015, licence PL820 S commenced on 5 February 2016 and covers 48 sq km in blocks 25/7 and 8. The licence sits 1km NW of Balder and 2km SW of Eitri fields. A NW portion of PL820 S in Jette field area has a stratigraphic vertical limitation to below Base Paleocene, thus excluding the shut-in Jette oil field (Aker BP). The work obligations of reprocessing 3D seismic and acquisition of new 3D seismic have been met, with a drilling decision due in February 2018 but yet to be confirmed. Within PL820 S, and 1.5km S of Jette, is NFW 25/8-13 (2001, Esso, 2,276m) drilled under PL027 B, which was P&A dry after reaching TD within the Early Jurassic Statfjord Group. Revised PL820 S licence participants are MOL Norge AS (40% + Op), Wintershall Norge AS (30%) and Lundin Norway AS (30%).","Lundin has agreed to acquire 30% from Fortis (-> 0, MOL 40% op, Wintershall 30%) in PL 820 S."
32845,"The authorities have cleared a plan by Reliance assign a 70% stake in CB-ONN-2003/1 to Sun O&G (SONG), It is also believed that BP has also sold its 30% in the same block to SONG, the 56-sq km unit therefore now wholly-owned in the Cambay onshore:","The authorities have cleared a plan by Reliance assign a 70% stake in CB-ONN-2003/1 to Sun O&G (SONG), It is also believed that BP has also sold its 30% in the same block to SONG, the 56-sq km unit therefore now wholly-owned in the Cambay onshore"
82808,"Europa Oil and Gas reported on 11 June 2020 that it was acquiring, subject to regulatory approval, 100% interest in Frontier Exploration Licence (FEL) 3/19 from DNO. The acquisition requires Europa to pay an upfront nominal fee and grant DNO a 5% Net Profits Interest for any future hydrocarbon production from accumulations within the licence. These include the Edge Prospect, with estimated un-risked prospective resources of 1.2 Tcfg. Prior to this transaction, the Department of Communications, Climate Action and Environment (DCCAE) had reported on 31 March 2020 that FEL 3/19 was held by CNOOC (80% + operator) and DNO (20%). Therefore, during Q2 2020 and prior to the deal with Europa, DNO acquired CNOOC's operated interest (the terms of which have not been reported).   FEL 3/19 spans the Slyne and Erris sub-basins, 18 km east of the producing Corrib gas field and around 24 km east of Europa's drill-ready Inishkea prospect in FEL 4/19. The Edge prospect and leads such as Clayton, Downey, Lynott and McGowan were identified in the licence and reported by Faroe Petroleum in 2016. Edge was described by Faroe Petroleum as a Triassic Sherwood Sandstone reservoir, with a reported chance of success of around 15%. The Corrib reservoir consists of the same formation at 3,300 m depth, whereas the Edge prospect is reportedly much shallower. Europa intend to re-launch the farmout of FEL 3/19 alongside its FEL 4/19 (Inishkea) farmout which, due to the proximity to the Corrib field, provide infrastructure-led exploration opportunities.   Following regulatory approval, FEL 3/19 will be wholly owned by Europa Oil and Gas (Holdings) plc.","Europa announces the conditional acquisition of FEL03/19, off NW Ireland, from DNO. The 956-sq km permit contains the 1.2 Tcf Edge prospect, adding onto Europa's other regional assets."
81576,"During May 2020, Agiba Petroleum P&A its Karm 1X exploration well, located on the Meleiha development lease (DL) of the Meleiha PSC. No further details are available. The well followed on from the drilling of the Tala 1X near-field exploration well in Q4 2019. It reached 3,461m TD in the Jurassic Masajid Formation, with oil shows reported. Tala 1X was exploring the Cretaceous Alam El Bueib and Bahariya sandstones in a satellite structure of the Meleiha Field. Karm 1X forms part of the company’s 2019-2020 exploration campaign across the Shushan Basin concession, which has seen two discoveries made to date. The Shemy 1X NFW encountered oil in the Cretaceous Matruh Formation in July 2019, whilst the Basma 1X NFW discovered oil in the Jurassic Khatatba Formation in April 2019. Equity in the Agiba consortium is split between Eni (38%), Lukoil (12%) and EGPC (50%, carried).<P />","Karm 1X exploration well (Agiba Petroleum 100% = Eni, Lukoil 76/24 JV) located on the South East Ras Qattara PSC. P&A, no further details are available."
10508,"Advent Energy and 15% partner Bounty O+G have agreed to jointly farmout a 10% stake in PEP 11,  4,574 sq km off NSW, Sydney Basin, to RL Energy in exchange for funding a commitment 200km 2D seismic survey and processing/interpretation (up to a cap). RL can run up to 50% if it funds 85% of committed 3D seismic (up to a cap). PEP 11 otherwise still remains open for farmin.  ","Australia (Sydney B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: PEP 11 op. by ASSET EN (85.0%, ASSET EN 85.0%, BOUNTY 15.0%, BOUNTY 15.0%) to be check."
22854,"UJO has agreed to buy a further 12.5% in Egdon’s PEDL 180 & 182 from Celtique Energie, boosting its interest here to 27.5%. The GBP 1.04 MM deal is a deferred consideration conditional on 1st production is subject to OGA approval. Egdon has picked up the balance of Celtique’s interest (ex-30%) on similar terms (i.e. at no initial cost). The licences lie south of Hull in Lincolnshire and are home to the Wressle structure and the Broughton North prospect. Partnership now to be Egdon (op) 30%, Europa 30%, UJO 27.5%, Humber O&G 12.5%.","UJO has agreed to buy a further 12.5% in Egdon’s PEDL 180 & 182 from Celtique Energie, boosting its interest here to 27.5%. The GBP 1.04 MM deal is a deferred consideration conditional on 1st production is subject to OGA approval. Egdon has picked up the balance of Celtique’s interest (ex-30%) on similar terms (i.e. at no initial cost). The licences lie south of Hull in Lincolnshire and are home to the Wressle structure and the Broughton North prospect. Partnership now to be Egdon (op) 30%, Europa 30%, UJO 27.5%, Humber O&G 12.5%."
57078,"Premier Oil is looking to sell its 25% stake in CNH-RO1-LO1-A7/2015 (aka Area 7), offshore Sureste Basin, which partly holds the Zama oil discovery (see DEA 27 Jun ’19).","Premier Oil is looking to sell its 25% stake in CNH-RO1-LO1-A7/2015 (aka Area 7), offshore Sureste Basin, which partly holds the Zama oil discovery "
69195,"PEL 155, Penola Trough, Otway Basin, TD 4,300m, 65m gross gas column identified in the target Pretty Hill fm, moveable gas not confirmed, Easternwell rig 106. Otway (op), partner Vintage Egy.","Nangwarry 1 expl. (Otway Energy 50%, op. Vintage O&G 50%) in PEL 155, gas disc. 120m of saturated gas column, within the Upper Pretty Hill Fm. and there is a possible 160m gas column within the mid-Pretty Hill section."
59803,"Location onshore in the Rotterdam Europoort area (Maasmond = Maas / Meuse River Mouth) within NAM’s Botlek III licence, deviated offshore to Charlie-Noord prospect in Q16b, ops terminated 22 Sep ’19, w.o. results, KCA-Deutag T-46 rig.","Maasmond 01 (MSM-01) nfw. (ONE-Dyas Op 49%, TAQA Offshore 11%, EBN 40%) in Botlek III block had reportedly encountered gas with operations likely to conclude shortly."
52987,"It was reported in June 2019 that Oil and Gas Development Company Ltd (OGDCL) has been exclusively awarded the Thal East D&PL (development and production lease) over its Thal East 1 gas discovery in Lower Indus Basin with effect from 8 January 2019. The lease, which has been excised from the Thal EL concession, covers 11.1 sq km area and is located in the Sukkur district of the Sindh province.   OGDCL had submitted the application for Thal East D&PL on 10 January 2019. The company had originally applied for 44 sq km lease area.  OGDCL had announced the Thal East 1 gas discovery on 14 January 2019 which was the first discovery to be made in Thal EL. It was reported that Thal East 1 had flowed from the Lower Goru Basal Sand at a rate of 22.5 MMcfg/d, through a 36/64” choke at wellhead flowing pressure of 3,820 psig. The well reached TD in late 2015 at 4,468 m in the Lower Goru Formation.","Pakistan, not found"
27034,"Santos Ltd completed the sale of 50% interest and in exploration permit ATP 1177-P, located in the Bowen-Surat Basin, on 28 June 2018.  Orient (Denison Trough) Pty Ltd has acquired the interest, with Santos exiting the permit.  The companies entered the agreement in April 2018, before it was registered by the Queensland State Government on 28 June 2018.  ATP 1177-P was awarded to Santos QNT Pty Ltd and joint venture partner Australia Pacific LNG Pty Ltd on 29 November 2013 after being applied for in April 2013.  The permit was renewed in October 2017 and is due to expire, or be further renewed, in November 2021.  Joint venture partner Australia Pacific LNG Pty Ltd holds 50% interest and has taken over operatorship on Santos’ exit.  The permit contains the Yamala gas discovery, which was made in 1997.  There are also a number of dry wells to the north and south areas of the permit.  ATP 1177-P, which covers an area of 315 sq km, was awarded on 29 November 2013. Now that Orient has completed acquisition of Santos’ interest, participants in the permit are Australia Pacific LNG Pty Ltd (50% + Operator) and Orient (Denison Trough) Pty Ltd (50%).",Santos completed the sale of 50% interest in exploration permit ATP 1177-P to Orient (Denison Trough).
37868,"Add. DEA 17 Dec ’18 (adds some details): East Sepinggan PSC, Kutei Basin in deepwater Makassar Strait, WD 1,592m, TMD 3,400m, gas-cond discovery, 15m net sands in 2 Miocene zones, tested 30 MMcfg/d + 100 bc/d, potential 70 MMcfg/d + 1,000 bc/d.","Merakes E.-1 (Eni op. 85%, Pertamina 15%) in East Sepinggan PSC, gas-cond discovery located 3 km east of the Merakes field, 15m of net gas-bearing sands in 2 Miocene-aged strata, tested 30 MMcfg/d + 100 bc/d from target Sepinggan turbidites (data indicating the hole could produce 70 MMscf/d of gas and 1000 bcon/d), WD=1580m TD=3400m."
63073,"On 6 November 2019, Petrobras bid on and was granted a preliminary award for the 146.71 sq km Itapu block in the deep-water offshore Santos Basin from the 2019 ToR Excess Volumes PSC Bid Round.     There were no other bids for      the block.   Petrobras will pay the fixed      bonus of USD 442.61 million at 1 USD to 3.99 BRL and it offered the      minimum government take of 18.15%.   Once the final award is      granted, Petrobras will have the rights to produce the excess volumes of      approximately 361 MMboe in the Itapu block.   Petrobras is operator with 100%      working interest.","Petrobras was granted a preliminary award for Itapu field (100%) and Buzios field (90% op, CNOOC 5%, CNODC 5%), biggest area on offer ANP's 2019 ToR Excess Volumes PSC round (aka Transfer of Rights) in the Brazilian pre-salt."
80009,"ENI plugged and abandoned wildcat Shwe Nan Htike 1 in block RSF-5, located in onshore Central Burma Basin, around late April 2020, with results unreported. It is understood that the well ran into a stuck pipe incident while operating at around 3,535 m, shallower than the PTD of approximately 3,800 m. Prior to the incident, wireline logs were acquired over two separate intervals (2,675-2,150 m and 2,757-3,420 m).    Operations were ongoing in late March 2020, with the well drilled to approximately 2,800 m and wireline survey ongoing.  Shwe Nan Htike 1 was spudded around mid-January 2020 and was likely targeting the Miocene and Oligocene sandstone reservoirs in the deeper section of the Ondwe structure. The well was drilled using the ""AD-1"" land rig operated by Asia Drilling.  Operations were originally expected to be completed in mid-2020, including abandonment after drilling. In case of positive indications during drilling, the operator was planning to conduct well testing at a later time, possibly followed by a second exploration well targeting another section of the structure.  An official ceremony for drilling commencement of the well was held on 30 December 2019, attended by the Myanmar Deputy Minister of Electricity and Energy.  The operator conducted public consultation activities with the local communities in March and May 2019, followed by the submission of Environmental Impact Assessment (EIA) report for the drilling plan in July 2019. According to the EIA report, the company proposed two wells, at the time tentatively named as ""Ondwe Deep 1"" and ""Ondwe Deep 2"".  Eni previously completed a 487 sq km of 3D seismic survey in January 2018. The survey, commenced on March 2017, was carried out by Geofizyka Torun. Operations were temporary halted in early July 2017 due to rainy season and resumed in late October 2017.  The block contains the Ondwe gas discovery, a NW-SE trending faulted anticline located in the southernmost part of the prolific trend that produced several fields such as Chauk-Lanywa and Yenangyaung. At least 12 wells have been drilled in the Ondwe structure between 1912 and 2000, with three wells encountering minor gas in shallow Miocene sandstones of the Obogon and Kyaukkok formations.  RSF-5 is one of two blocks that Eni holds onshore Myanmar. The other block is PSC K, located in the Bago Yoma-Sittoung Basin. Both blocks were officially awarded by MOGE on 30 July 2014 to Eni Myanmar BV (90%, operator) and Myanmar Petroleum Exploration and Production Ltd (10%).  After the initial study period, the commencement date for PSC K was on 25 January 2016 while for RSF-5 it was on 1 January 2017. Exploration period will be for six years, subdivided in three phases. The initial exploration period (three years) in RSF-5 expired on 31 December 2019 but it was automatically extended by two years, due to the ongoing drilling activity (first extension period). The second and final extension period, if warranted, will run from 2021 to 2022.  Background Information  RSF-5 is located in the Magway Division and the nearest oil fields are to the west of the block, the Minbu and Htaukshabin oilfields. The block was previously awarded to Exspan Myanmar Inc, a wholly owned subsidiary Indonesian P.T. Medco Energi Corp, as operator and 100% holding on 14 July 1997 (together with blocks EP-1 and MOGE-3). Exspan Myanmar Inc, acquired of 75km of 2D seismic over the Ondwe oil-prone structure between February to March 1999. Exspan Myanmar Inc plugged and abandoned Northwest Ondwe 1 (TD at 2,314m), as an uncommercial gas well on 14 January 2001. The well tested gas in one of the sands interval with trace gas recorded. The result discouraged Exspan from further testing the remaining sandstone intervals. The well was primarily targeting sandstones of the Lower Miocene Pyabwe Formation (below 914m) and the Upper Oligocene Okhmintaung and Upper Padaung Formations (below 1,524m). Secondary objectives were sandstones of the Oligocene Lower Padaung and Kyaukkok Formations.   The prominent structure in this block is the Ondwe structure. Gravity and surface geology suggest that the regional stratigraphic correlation indicates the upper Tertiary formations of the Ondwe structure are thickening towards the south and east in the inner Myanmar Tertiary Belt. The Ondwe structure is a gently pitching broad domal structure and is compartmentalized into a number of fault blocks by oblique and cross faults. It is bounded by Magwe syncline to the SW and Yenanyaung syncline to the NE. It is separated from oil producing Yenangyaung anticline by a saddle. The oil bearing Kanni Dome and Htaukshabin structures are located west of the Magwe syncline.","Shwe Nan Htike-1 nfw. (Eni 90% op., MPRL 10%), RSF-5, onshore in Central Burma Basin, ops terminated late Apr '20, results n/a, AD-1 rig. Stuck pipe at 3535m. PTD was ca. 3800m, target Miocene + Oligocene sst in deeper sections of the Ondwe structure. "
11509,"P1985, Beryl area, P+A’ing, WilPhoenix SS. Play similar to nearby Corona, target oil in Tertiary injectite. Apache (op), partner Chrysaor.  ","009/14b-16 (Titan) op. by Apache (77,22%, Enterprise 22,78%) in P1985, Beryl area, play similar to nearby Corona, target oil in Tertiary injectite. P&A with the results n/a."
48040,"Afar block 3, spudded 4Q ’18 east of Farha South infrastructure, 1Q ’19 discovery, LT testing planned, no details. CCED (op), partners Tethys Oil + MEPME.","Masarrah 1 near-field exploration well (CCED 50% op, Tethys Oil 30%, MEPME 20%) in Afar block 3, east of Farha South infrastructure, oil discovery, targeted a structure analogous to the Ulfa and Samah discoveries around 10 km NE of Ulfa 1. It had good oil shows in the targeted Precambrian Khufai Fm and tested light oil with good flow rates. "
87294,"On 31 July 2020 Equinor agreed to sell 40.8125% of its interest and transfer operatorship of licences P234 (block 3/28a), P493 (block 3/28b), P920 (3/27b) and P977 (blocks 9/2a and 9/3a) to EnQuest. A sale and purchase agreement has been signed between the two companies for the licences that host the Bressay heavy oil field. The sale is for an initial consideration of GBP 2.2 million (as a carry against 50% of Equinor's net share of costs) and a further consideration of GBP 11.48 (USD 15 million) will be payable when the Bressay field development plan is approved. The deal is estimated to complete in Q4 2020.  Located northeast of Kraken field, the Bressay field was discovered in 1976 with heavy oil and a small gas cap in the Upper Paleocene Teal Sands. The heavy oil has an average API of 12° and a viscosity of 550 cP. An environmental statement was submitted for the field in June 2013 which described the development via 70 development wells, with operations commencing in 2016, first oil in 2018 and peak production was anticipated to take place between 2022 and 2025. However, by November 2013 the development was stated to be delayed and in August 2016 the concept selection was deferred because of market conditions and the need to simplify the development concept. A number of development scenarios are still under consideration, one involves a tie back to Kraken field.  Interest in the licences P234, P493, P920 and P977 is held by EnQuest Heather Ltd (40.8125% + operator), Equinor (UK) Ltd (40.8125%) and Chrysaor Ltd (18.375%).","(East Shetland Platform) EnQuest has agreed to acquire 40.8125% and operatorship from Equinor in Bressay heavy oil field licences P234 (3/28a), P493 (3/28b), P920 (3/27b) and P977 (9/2a & 9/3a). Current field partners Equinor UK Ltd (81.625% + Op) and Chrysaor Ltd (18.375%). After completion, new field partners will be EnQuest (40.8125%, op.), Equinor UK Ltd (40.8125%) and Chrysaor Ltd (18.375%)."
70812,"Vonu Este pad, appraisal to Vonu discovery in PUT-1 block, Putumayo Basin, spudded 27 Nov '19, PTD 3,350m was to be reached by year-end, thus assumed under evaluation. Target Upper Cretaceous N + U sands and A-Limestone.","Cocona 1 nfw. (Gran Tierra Energy 100%) in PUT-1 block, PTD=3350m was to be reached by year-end, thus assumed under evaluation. Target Upper Cretaceous N + U sands and A-Limestone."
32362,"Ghana's licensing round was launched this week under the 2016 Petroleum Act. Three blocks (of 9 delineated) are available namely blocks 2, 3 + 4.  The remainder of the blocks will be released either under direct negs (5 + 6), through a subsequent round (7, 8 + 9), or reserved for GNPC’s Explorco (1), possibly in partnership.  EoI’s are expected by November, pre-qualified suitors and partners announced in December, and the bid deadline by end-Feb ’19.","Ghana's licensing round was launched this week under the 2016 Petroleum Act. Three blocks (of 9 delineated) are available namely blocks 2, 3 + 4."
22095,"Coirón Amargo Sur Este block, Neuquén Basin, TD 4,804m, tested 628.4 bo/d from the Vaca Muerta shale, compl. Apr ’18.PAE (op), partners Madalena Energy + GyP Neuquen.","Coirón Amargo Sur Este block, Neuquén Basin, TD 4,804m, tested 628.4 bo/d from the Vaca Muerta shale, compl. Apr ’18.PAE (op), partners Madalena Energy + GyP Neuquen"
84155,"Lemang PSC, 2,470 sq km in S. Sumatra, Jadestone has agreed to acquire Mandala's operated 90% stake. Licence contains Akatara field where oil production ceased end-'19 and gas production is planned. Gov't has a back-in right for 10% upon gas devt sanction, which, if exercised, would reduce Jadestone's stake to 81%. Remaining partner Hexindo Gemilang Jaya (Eneco sub).","(S. Sumatra),Jadestone has agreed to acquire Mandala's operated 90% stake in Lemang PSC (2470km²) in S. Sumatra, Licence contains Akatara field where oil production ceased end-'19 and gas production is planned. Gov't has a back-in right for 10% upon gas devt sanction, which, if exercised, would reduce Jadestone's stake to 81%. Remaining partner Hexindo Gemilang Jaya (Eneco sub)."
20937,"On 7 May 2018, Shell operator with 100% working interest was granted official awards for four blocks from the CNH-RO2-LO4/2017 Bid Round including the CNH-RO2-LO4-AP-CS-G01/2018 contract, CNH-RO2-LO4-AP-CS-G02/2018 contract, CNH-RO2-LO4-AP-CS-G04/2018 contract, and the CNH-RO2-LO4-AP-CM-G09/2018 contract.    On 31 January 2018, Shell operator with 100% working interest was granted preliminary awards for four blocks from the CNH-RO2-LO4/2017 Bid Round including the 2,079.50 sq km Area 20, AP-CS-G01, the 2,029.74 sq km Area 21, AP-CS-G02, 1,852.86 sq km Area 23, AP-CS-G04, and the 3,066.83 sq km Area 28, AP-CM-G09 block.  The final official contract signature award is to take place within 90 days or 1 May 2018.      For      the Area 20 block, the company bid 20% of additional royalties over the      minimum of 5%, 2.0 work units factor equivalent to two wells, and a      tie-break bonus of USD 90.15 million.  There was one other bid for the block by      PEMEX who bid 6.11% additional royalties and no additional work units      factor.    For      the Area 21 block, the company bid 20% of additional royalties over the      minimum of 5%, 2.0 work units factor equivalent to two wells, and a      tie-break bonus of USD 110.15 million representing the second highest      tie-break bonus in the round.  There      were four other bids for the block.       The second place bid was made by the consortium of Chevron, PEMEX,      and ONGC who bid the maximum additional royalties and additional work      units factor but lost the tie-break bonus offering USD 42.1 million.    For      the Area 23 block, the company bid 10.08% of additional royalties over the      minimum of 5%, 1.0 work units factor equivalent to one well.  There was one other bid for the block by      the consortium of Chevron, PEMEX, and Inpex who bid 13.44% additional      royalties but no additional work units factor.    For      the Area 28 block, the company bid 20% of additional royalties over the      minimum of 5%, 2.0 work units factor equivalent to two wells, and a      tie-break bonus of USD 43.15 million.  There was one other bid for the block by      PC Carigali who bid 19.88% additional royalties and no additional work      units factor.     The general license contract terms include the following:      The      exploration phase consists of an initial four (4) year period with two      three (3) year extension periods possible for a total of 10 years.  Each extension period is contingent on      the company committing to additional work commitments that includes one or      two wells.     There      is a three (3) year evaluation period following the exploration phase.     There      is a development and production phase which can be from 22 to 28 years for      a total contract term of 35 years.       There is the possibility of two extensions to this phase of 10 to      five (5) years for a total contract term of 50 years.     The      local content requirements are 3% in the exploration and evaluation phase,      4% in the development phase, and 10% in the production phase.     Rights      to the entire geological column.     The      basic royalty is a variable formula depending on hydrocarbon type and      price but starts at approximately 5% in addition to the additional      royalties bid for the contract.     There      is a rental rate of MXN 1,214/sq km for the first 60 months and then the      rate increases to MXN 2,904/sq km thereafter.     There      is an exploration and production tax of MXN 1,584/sq km during the      exploration phase which increases to MXN 6,335/sq km during the production      phase.     The      corporate income tax is 30%.     There      is also a profitability adjustment factor that can be modify the royalty      rate and the contractor’s profitability is to be measured quarterly and calculated      prior to corporate income tax and the exploration and production tax.","Mexico, Area 23"
37707,"May ’18 well in PEL 516, Cooper Basin, TD 2,795m, re-entered + fracked across 2,360-2,730m (Patchawarra sst), tested stable 8 MMcfg/d. A LT test will be undertaken 3Q ’19 over each of the discovered intvs after which a devt plan will be prepared based on test results.","Australia, PEL 516"
18942,"The Ministry for National Development, in cooperation with the Hungarian Office for Mining and Geology, is preparing the country’s next – sixth, 2018 – bid round for the prospection, exploration and production of hydrocarbons. In preparation for the round, the authorities have prepared over 35 blocks for licensing in the western, central and central-eastern part of the country. As during the period 2013-17, the opening of the round is expected in late May/June 2018, with some nine areas offered for the hydrocarbon operations and one to two blocks for the hydrothermal energy. The tender documents will be published in the EU Official Journal, marking the onset of the bid round.  The tender call will have three-month duration, closing in mid/late September 2018. The bid winners are expected to be pronounced in November 2018, with the awards of the contracts expected in early 2019. The list of the areas on offer may include seven-eight blocks (plus additional plot(s) for geothermal purposes).  Background Information  The country’s first bid round was pronounced in 2013 and had little success (two awards). Following modifications to the legal and fiscal terms, the tenders conducted in 2014, 2015, 2016 and 2017 attracted significant attention and resulted with the awards of 17 new concessions (awards from the 2017 round are expected in February 2018).","The Ministry for National Development, in cooperation with the Hungarian Office for Mining and Geology, is preparing the country’s next – sixth, 2018 – bid round for the prospection, exploration and production of hydrocarbons. In preparation for the round, the authorities have prepared over 35 blocks for licensing in the western, central and central-eastern part of the country. "
11131,"Norm secured explo licences G24-C1,C2 and G25-D1,D2 for 5 years effective 4 Dec ’17. Total 587 sq km in the W. Pontides. * full name Norm Ambalaj Sanayi ve Ticaret A.S. ",Turkey (Pontides) (It's a petroleum rights. Please summarize by yourself). In IHS database: G24-C1 op. by NORM AMB (100.0%) to be check.G25-D1 op. by NORM AMB (100.0%) to be check.
12359," Initial testing indicates potential for commercialisation of a large gas resource. Constrained flow rate of approximately 25 MMscfd recorded on test.  Estimated net gas pay of 34 metres intersected across two primary targets.   Beach Energy has announced a new gas field discovery at Haselgrove-3 ST1 in the onshore Otway Basin, South Australia. Flow test results from the primary target Sawpit Sandstone indicate a high deliverability reservoir and provide encouragement to move towards commercialisation of a large gas resource. Beach plans to undertake immediate follow-up testing to confirm well deliverability and assess connected volumes and gas composition. Haselgrove-3 ST1 is located on state forestry land in PPL 62 (Beach 100%), approx. eight kilometres south of Penola. Haselgrove-3 ST1 was drilled as a deviated well to a total measured depth of 4,331 metres and targeted the Sawpit Sandstone and shallower Pretty Hill Sandstone. The well intersected an estimated gross gas column of 104 metres (total vertical thickness (TVT)) in the Sawpit Sandstone, with estimated net pay of 25.6 metres (TVT). An estimated gross gas column of 11.6 metres (TVT) was also intersected in the shallower Pretty Hill Sandstone, with estimated net pay of 8.5 metres (TVT). Initial testing of the Sawpit Sandstone was undertaken to enable preliminary assessment of well deliverability and gas composition. A cased hole test was undertaken over the 4,023 – 4,185 metre interval and flowed gas at a rate of 25 MMscfd sustained over a 100 minute period through a  36/64” choke and at 2,700 psig well head pressure. Flow rates were constrained to 25 MMscfd due to the size of completion tubing (2 7/8”). Early indications suggest the Sawpit Sandstone could flow at rates greater than 25 MMscfd. Preliminary gas sample analysis indicates low inert content, which should minimise gas processing requirements. The well is currently shut-in with preparations underway for commencement of an initial production test (IPT) in late January 2018. The IPT will confirm well deliverability and gas composition, and will assist field development planning. Results will be integrated with other subsurface data to enable estimation of the size of the gas resource.     Beach’s CEO, Matt Kay, said: 'We are very encouraged by these results, and to witness in the early stage of testing such strong well deliverability from an onshore gas field is particularly pleasing. We look forward to continuing our operations in the Otway Basin and are appreciative of ongoing support provided by the local community. We would also like to thank the South Australian Government for their contribution of the $6 million PACE gas grant, which was a crucial element in Beach’s decision to drill this well.' Original article link Source: Beach Energy ","Haselgrove 3 ST1 op. by Beach (%) in PPL 62, 104m gross gas column encountered in the target Sawpit sst, 25,6m net, along with an est. 11,6m gross gas column in the shallower Pretty Hill sst, 8,5m est. net. The Sawpit tested a constrained 25 MMcf/d for 100 minutes from 4023-4185m [36/64” choke]."
16835,"Genexco secured on 1 Jan ’18 sole rights for 3 years to the Velden-Teising block in Bavaria, Alpine Foreland. It covers ab. 100 sq km and the Velden + Teising o/g/c fields. Genexco is already offering a farm-in opportunity to test the proven Upper Cretaceous-Lower Tertiary oil play. Both fields are to be re-developed (abandoned in 1986) and partners are sought for the pilot phase and full field re-devt. Contact: Peter Eckhard Oehms, eckhardoehms@genexco.de.","Germany, Teising"
21020,"IGas subsidiary Island Gas Limited and Egdon Resources have acquired a 3.67% interest and 1.33% interest respectively in licence PEDL 070 from Brigantes Energy. The licence contains one block – SU/52a which hosts the Avington field. The deal completed in early May 2018.   The Avington field is a composite structure comprising a northern footwall fault block and a southern hanging wall inversion anticline, covering 23 sq km. The Middle Jurassic Great Oolite reservoir is mapped juxtaposed across the fault separating the two structural elements of the field. The field was discovered in 1987 and was brought onstream in 2009. The field is expected to produce until 2022.   Interest in the licence is now held by IGas subsidiary Island Gas Limited (53.67% + operator), Egdon Resources U.K. Limited (28%), Aurora Production (U.K.) Limited (8.33%), Corfe Energy Limited (5%) and UKOG (GB) Limited (5%).","United Kingdom, PEDL 070"
84815,"Larus is on the lookout for a partner in its wholly-owned PPL 579, 9,257 sq km on/offshore in the Torres Basin, SE PNG, in exchange for participation in an upcoming explo programme comprising 3D seismic acquisition to help further define the Vekwala + Sunday prospects required prior to drilling. Contact Ian Cross, icross@moyesco.com.","Papua New Guinea (Papuan B.) PPL 579 op. by LARUS EN (100%), Larus is on the lookout for a partner in its wholly-owned PPL 579, 9,257 sq km on/offshore in the Torres Basin, SE PNG, in exchange for participation in an upcoming explo programme comprising 3D seismic acquisition to help further define the Vekwala + Sunday prospects required prior to drilling."
37431,"As reported on 14 December 2018, Exxon Mobil Corp and Sonangol signed a Memorandum of Understanding to explore the Namibe Basin. No additional information was provided however, on 15 November 2018, Carlos Saturnino (head of Sonangol) announced that Exxon Mobil Corp (Exxon) was in negotiations for deep-water blocks. The blocks (30, 41, 42, 43, 44 and 50) being negotiated for would grant Exxon access to the Angola Basin, Benguela Sub-basin (Kwanza Basin) and Namibe Basin.","Angola, not found"
65148,"Garden Banks 491, lease G35918, WD 600m, BHL in block 492, TD 7,700m, reservoir quality sands encountered but found water-bearing, well to P&A, West Capricorn DS probably off to spud the Oldfield prospect in Mississippi Canyon block 728 (lease G16644) in early Dec '19 (Kosmos 40%, Hess 60%). Kosmos-operated well in BP-run acreage.","GB 492 001S0B0 (Resolution) nfw. (Kosmos 50% op, BP 50%) in GB 491, lease G35918, was designed to test an amplitude-supported sub-salt prospect in the underexplored western GB area, reservoir quality sands encountered but found water-bearing, well to P&A, WD=600m, TD=7700m."
69821,"It was announced on 19 January 2020 that Turkiye Petrolleri A.O. (TPAO) has been awarded the G16-D onshore exploration licence (Thrace Basin) on 9 January 2020 for a period of five-year. The licence, covering an area of 262 sq km, is located towards northwest of the country and TPAO will be 100% owner and operator of the licence. TPAO had filed the application on 2 August 2019.  Arar Petrol ve Gaz Arama Uretim Pazarlama A.S was also interested in G16-D block and, as announced on 7 May 2019, the company had submitted an exclusive application for the exploration licence on 24 April 2019.","TPAO has been awarded the N39-B, N39-C, N39-A onshore exploration licence (Western Arabian Province) and G17-A, G17-D1,D2,D4, G17-C1,C4, G16-D, G16-C, G16-B onshore exploration licence (Thrace Basin)"
27864,"Pertamina EP has completed the Akasia Maju 1 (AMJ-1) wildcat in the Jawa Bagain Barat (JBB) PPC, located in onshore West Java, on 20 August 2018. According to the company, one of the production tests has flowed 1,700 bo/d while others flowed gas and condensate. The well was spudded on 20 March 2018 using Pertamina Drilling Services (PDSI) Rig #32.8/D1000-E, and drilled to a TD of 2,517 m.  Around mid-July 2018, the company reportedly discovered oil and gas from the initial testing stage at AMJ-1. The well flowed 3 MMcfg/d from DST 2, 6 MMcfg/d from DST 3 and 1,320 bo/d from DST 4. The tests were conducted over the Upper Oligocene to Middle Miocene intervals of the Upper and Lower Cibulakan groups.    In March 2018, the discovery was reported to have the potential to produce approximately 1,000 bo/d. The area comprises several producing fields, such as Jatibarang, the Cemara fields complex and Akasia Bagus.    In 2017, Pertamina drilled three wells in the block. The first well, Pondok Makmur Indah 1, likely discovered small volumes of gas. Haur Gede 1 was reported as an oil and gas discovery, with approximately 14 MMboe of 2C reserves according to local reports. Both discoveries were made in the Cibulakan Group. The third well was West Gantar 1 gas discovery, in August 2017. The well may have targeted the deeper Eocene-Oligocene clastics of the Jatibarang Formation in a stratigraphic play.  Pertamina is operator and sole interest holder in the JBB PPC.  Background Information  The JBB PPC is managed under Pertamina EP Asset 3, which comprises the Jatibarang, Subang and Tambun field areas. The asset produced approximately 10,000 bo/d and 55 MMcfg/d in 2017.  Aside from exploration drilling, a 3D seismic survey was completed in the block in December 2016, over the Akasia Besar area. Approximately 99% of the planned area of around 1,120 sq km has been covered by seismic data recording. Elnusa conducted the survey, which covered an area located in the Cirebon, Majalengka and Indramayu regencies.   Akasia Besar 1 wildcat was suspended on 28 August 2012 with at least 2,250 b/d of oil and 0.8 MMcf/d of gas flowed during the test. It had PTD of 2,700 m and was targeting Upper Oligocene to Lower Miocene sandstones of the Talang Akar Formation/Cibulakan Group and Lower Miocene carbonate build-up of the Batu Raja Formation.  PT Pertamina's upstream operating areas, converted to ""Production Sharing Cooperation Contracts"" (subsequently termed ""Pertamina Petroleum Contracts"" or PPCs), were signed with BPMigas on 17 September 2005. The signature was delayed from its original scheduled date of 25 June 2004 due to undisclosed ""internal problems"" within PT Pertamina. This was then rescheduled to take place on 12 December 2004 at a PSC signing ceremony but it was again delayed as the PPC model was still being examined by the government.","Pertamina EP has completed the Akasia Maju 1 (AMJ-1) wildcat in the Jawa Bagain Barat (JBB) PPC, located in onshore West Java, on 20 August 2018. According to the company, one of the production tests has flowed 1,700 bo/d while others flowed gas and condensate. "
86889,"New Zealand Petroleum & Minerals (NZP&M) opened the nomination period for the Block Offer 2020 on 27 July 2020. Areas within the onshore Taranaki Basin may only be nominated by interested parties for inclusion in the Block Offer 2020, the final area for which is expected to be released in 2021. All nominations must be submitted to NZP&M by 5 pm New Zealand Standard Time (NZST) on 21 August 2020.  Nominations must be submitted with an accompanying description and map of the nominated area, in addition to supporting evidence of prospectivity. Areas included in previous Block Offers, including those within the Block Offer 2019, may be nominated. Nominee companies are under no obligation to bid for the nominated area or areas if they are included in the final release area. Nominations should be to be submitted to: blockoffernominations@mbie.govt.nz  The nomination period for the Block Offer 2020 was opened on the same day that the delayed Block Offer 2019 was opened. The blocks available for tender in the Block Offer 2019 are restricted to the onshore Taranaki Basin and cover a total area of 2,451 sq km. All bids must be submitted to NZP&M by 5 pm New Zealand Standard Time (NZST) on 4 November 2020.","New Zealand, not found"
83327,"On 12 June 2020, Sirte Oil Co (Sirte) reported that the A-005-LP003D exploratory well encountered oil and gas in the Beda Formation after testing approximately 700 bo/d with no water flow. The well reached the reservoir formation at 2,178 m.   On 28 December 2019, Sirte spudded the well in the LP003D-A-001 field, onshore in central Sirte Basin using the ADWOC 37 rig with a planned depth of 2.259 m. The main objective was the Paleocene Beda Formation.  ELF first drilled LP003D-A-001 in the 1970s. This approximately 10 MMbbl Oil Recoverable (IHS Markit estimation) field was appraised with two wells in 1973 and 1975, respectively and then again in 2013 with one last well. All the wells encountered oil in the Beda Formation, but the field was never developed.  Sirte operates 003D block with the 100% of interest and is fully owned by the National Oil Corporation (NOC).","(Sirte B.) A-005-LP003D expl. (NOC 100%) in 003D block, o&g encountered below 2178m in the target Middle Paleocene (Montian), Beda Fm, limestones and calcareous claystones, tested 700 bo/d, no water, TD=2259m."
11627,"Pertamina has signed a 10% transfer for the benefit of Migas Hulu Jabar, representing the local govt, in the 8,155-sq km Offshore Northwest Java PSC Extn, resulting in a 90:10 partnership in the offshore contract.     ","Pertamina has signed a 10% transfer for the benefit of Migas Hulu Jabar, representing the local govt, in the 8155km² Offshore Northwest Java PSC Extn, resulting in a 90:10 partnership in the offshore contract.     "
55404,"Corallian Energy announced on 1 August 2019 that it has completed the acquisition of Corfe Energy’s interests in the following licences – PEDL 345, PEDL 330, P1918, P2235 and three licences awarded in the 31st Frontier Licensing Round. One licence comprises blocks 98/11b and 98/12, another is made up of 12/27, 17/5, 18/1 and 18/2 and the last is made up of 11/23, 11/24c and 11/25b. In all these licences, prior to the deal, Corallian and Corfe were JV partners.    The acreage is located in the Moray Firth and Wessex Basin. Corallian drilled two wells which completed in early 2019, one on the Wick prospect (dry) and an appraisal well on the Colter discovery where it made the Colter South discovery.   Following the completion of the deal Corallian will hold a 74% interest in its acreage in the Wessex Basin and a 45% interest in the Moray Firth.","Corallian Energy announced on 1 August 2019 that it has completed the acquisition of Corfe Energy’s interests in the following licences – PEDL 345, PEDL 330, P1918, P2235 and three licences awarded in the 31st Frontier Licensing Round. One licence comprises blocks 98/11b and 98/12, another is made up of 12/27, 17/5, 18/1 and 18/2 and the last is made up of 11/23, 11/24c and 11/25b. In all these licences, prior to the deal, Corallian and Corfe were JV partners. "
82813,"Operator Heritage Exploration and Production Ghana Ltd (Heritage) is offering stakes in its 180 sq km deepwater South West Tano block (western Ghana), located between Tullow's Jubilee and TEN producing fields. The percentage of working interests is negotiable, and the farminee could assume an operator role. The company is planning two firm wells to be drilled in 2H 2020, before the first exploration period expires in mid-2022 (see separate article).    Heritage operates the tract alongside with Blue Star Exploration Ghana Ltd, Ghana National Petroleum Company (GNPC) and GNPC Exploration and Production Company Ltd (Explorco).     Only one exploratory well was drilled by previous operator Tullow within the block's perimeter, Sapele 2, which was plugged and abandoned dry in early 2013.    Contact details:  Keith Walters (VP Operations)  Keith.Walters@heritageoilltd.com   +44 7384 513 630","Operator Heritage Exploration and Production Ghana Ltd (Heritage) is offering stakes in its 180 sq km deepwater South West Tano block (western Ghana), located between Tullow's Jubilee and TEN producing fields. The percentage of working interests is negotiable, and the farminee could assume an operator role. "
84665,"Viaro Energy and announce they have reached agreement on the terms of an all-cash offer pursuant to under which Viaro will acquire the share capital of RockRose, valued at GBP 247,575,825. The acquisition will be subject to usual approvals. Rockrose operates offshore UK and in the Netherlands. www.viaro.co.uk.","United Kingdom, Viaro Energy and announce they have reached agreement on the terms of an all-cash offer pursuant to under which Viaro will acquire the share capital of RockRose, valued at GBP 247,575,825. The acquisition will be subject to usual approvals"
69434,"S. part of ATP-2021-P, Surat Basin, TMD 3,217m, 35m net gas pay interpreted in the main target Patchawarra, gas in the Nappameri, shows in the Toolachee (gas) and Birkhead + Westbourne (oil), suspended 10 Jan '20 ahead of stimulation + test, Saxon rig 185. Vintage (op), Metgasco (carried) + Bridgeport.","Vali 1 ST1 (Vintage 50% op, Metgasco 25%, Bridgeport 25%) in ATP 2021-P block,  analysis of well data indicated over 35m of interpreted log net gas pay over a 312m gross interval in the primary target Patchawarra Fm. Potential gas pay was also calculated in the secondary Toolachee target and the Triassic age Nappamerri group, with oil shows also observed in the Jurassic age Westbourne and Birkhead Fms with good sand development."
67435,"DNO spudded exploration well 6507/7-16 S on the Canela prospect in PL 888 using the “Island Innovator” S/S on 28 October 2019. Canela lies approximately 5 km west of Heidrun and south of Dvalin and had objectives in the Middle Jurassic Fangst Group (the same reservoir as Heidrun) in down-faulted blocks. The well was drilled to TD at 3,238 m (3,184 m TVDSS) in the Lower Jurassic Tilje Formation. A 52 m gas column was present in the Garn, Not and Ile formations with 48 m of good sandstone and there was a 4 m oil column in the Ile Formation. In the underlying Ile, Ror and Tilje formations there was a net total of 75 m of water-bearing sandstones. Recoverable reserves are estimated at 6-13 MMboe. On 19 December 2019 the well was abandoned.  The Dvalin field, operated by Wintershall Dea, is under development with a planned onstream date of Q4 2020. A four-slot subsea template will be tied-back to the Heidrun platform where a new process module will be installed. Gas will be partially processed by this module before export through the Polarled pipeline to the onshore Nyhamna terminal. Wintershall Dea is intending to produce over 18 Bcm (630 Bcf) of gas with the total cost for development estimated at NOK 10 billion (USD 1.18 billion).  Interest in PL 888 is divided between DNO through Faroe Petroleum Norge AS (40% + operator), ConocoPhillips Skandinavia AS (30%) and Wellesley Petroleum AS (30%).",Norway (Donna and Halten Terraces (Voring B.)) Dvalin
78642,"BZ 8-4S-1d completed in late April 2020 without result reported.  CNOOC – Tianjin spudded a new-field wildcat BZ 8-4S-1d in the Bohai offshore, Bohai Gulf Basin on 25 March 2020. The well is located in the Bozhong Depression in 25 m of water. It is targeting the Tertiary clastic play. “Zhongyuouhai 5” J/U is used for the drilling operation.   There is an oil discovery in the north of the BZ 8-4S-1d. BZ 8-4-2, drilled in 2013, is reported testing oil from the Neogene Minghuazhen Formation. The following appraisal well, Bozhong 8-4-4, was tested oil of 660 b/d form the Minghuazhen reservoir. During the drilling operations, the well encountered oil pay of about 50 m and gas pay of about 11 m, the successful result confirmed the BZ 8-4 discovery.   Later additional three successful appraisal wells Bozhong 8-4-7/8d/9d extended the reserves scale of this area, the field was expected to become a mid-size oil field, stated by CNOOC in its 1Q Review 2014.  The BZ 8-4 discovery is under appraisal at the moment.   In addition, CNOOC completed BZ 8-3-1 in 206 to the south of BZ 8-4S-1d but without result reported.","China, Bozhong"
65134,"On 23 July 2019 the Dutch Ministry confirmed that an exploration licence has been awarded to Neptune and HALO for block F5 for a period of four years. The detailed work programme must be submitted in year two, with a well due in year three. The award is effective from 3 October 2019. The original application for the licence (for a six-year term) was made on 19 June 2015 by Van Dyke but the company subsequently withdrew its application. Neptune (then GDF Suez) and HALO both made separate competing bids (both requesting a four-year term). The licence lies to the south of the Hanze oil and gas fields (Dana) and to the west of the F3-FB oil and gas field (Neptune), all of which are producing. Industry sources indicated the licence has a shallow gas anomaly that will be targeted and Neptune confirmed in late November 2019 that they will target a Tertiary gas reservoir.  Five wells have previously been drilled in F5: F5-1 by Tenneco in 1975, F5-2 by BP in 1982, F5-3 by Mobil in 1987, F5-4 by RWE in 1998 and F5-5 by Veba in 2001. All were dry holes except F5-4 which encountered oil shows.     Hanze was discovered in 1996 by F2-5 which found a 76 m oil column in the Paleocene and Upper Cretaceous chalks of the Ekofisk and Ommelanden formations. The reservoir lies between 1,340 m and 1,478 m subsea and the API of the oil is 37°. The field was developed using a manned production platform and a tanker mooring and loading system. Oil is exported via shuttle tanker and gas via NOGAT. In 2009 gas production started from the shallow Pliocene reservoir at Hanze. Originally the Pliocene was considered too challenging to develop but new drilling techniques meant that this reservoir could be re-assessed. In October 2013 Dana reported that Hanze infill well F2-A6ST3 had doubled oil production from the field. When the field came onstream in August 2001 end of field life was projected for 2011, reserves were 47 MMboe and the recovery factor was 30%. However, these figures have later been revised: the recovery factor has increased to 53%, reserves are put at 67 MMbo plus approximately 20 Bcfg and the field is expected to produce until 2030.  Interest in F5 is divided between Neptune Energy Netherlands BV (operator), HALO Exploration & Production Netherlands BV and Energie Beheer Nederland BV (40%).",Neptune and HALO were awarded block F5.
86506,"BHP indicated in mid-July 2020 that it has been formally awarded the undrilled Green Canyon blocks GC 80 and GC 123, both situated in the Louisiana Coastal Basin. The blocks were originally offered as part of recent GOM-wide OCS Lease Sale 254, which was held on 18 March 2020. GC 123 is sited ~3km to the southwest of the Beacon Energy operated block GC 35, the site of the Tabasco prospect, which Beacon is expected to be targeting shortlym via its planned NFW G36624 1. Following the awards, BHP Billiton Petroleum (Deepwater) is now the operator and sole interest-holder (100% WI + Op) in both GC 80 and GC 123.","(GOM b.) BHP indicated that it has been formally awarded the undrilled Green Canyon blocks GC 80 and GC 123, both situated in the Louisiana Coastal Basin."
32667,"The Ministry of Hydrocarbons, Energy and Mines (Ministère des Hydrocarbures, de l’Energie et des Mines) is the licensing authority. Contracts are signed by the state, as represented by the Minister of Hydrocarbons, Energy and Mines. The Directorate General of Hydrocarbons (Direction Générale des Hydrocarbures) is responsible for the supervision of petroleum operations.    Interested parties should contact:    Ministère des Hydrocarbures de l’Energie et des Mines    Direction Générale des Hydrocarbures    Directeur : Moustapha BECHIR     Tele : +222 422 101 28  E-mail : mobechir@yahoo.fr          It is also possible to contact the Socété Mauritanienne des Hydrocarbures et du Patrimoine Minier (SMHPM).    Department of Exploration and Promotion    Director : Lemrabott Taleb     As of September 2018, it is understood that the blocks listed in the table below were available for licensing.  Sixty blocks were available.  There were no changes in the list compared to the previous one.  Total open acreage amounts to 751,519 sq km of which 678,762 is onshore and 72,757 is offshore.             Open blocks                                           Block Name         Area (sq km)         Situation         Block Basin             C-1         3,138         offshore         Senegal (M.S.G.B.C.) Basin             C-2         3,877         offshore         Senegal (M.S.G.B.C.) Basin             C-4         9,037         onshore         Senegal (M.S.G.B.C.) Basin             C-5         11,124         onshore         Senegal (M.S.G.B.C.) Basin             C-15         9,513         offshore         Senegal (M.S.G.B.C.) Basin             C-16         12,367         offshore         Senegal (M.S.G.B.C.) Basin             C-20         10,175         offshore         Senegal (M.S.G.B.C.) Basin             C-21         14,926         offshore         Senegal (M.S.G.B.C.) Basin             C-23         6,244         offshore         Senegal (M.S.G.B.C.) Basin             C-24         8,610         onshore         Senegal (M.S.G.B.C.) Basin             C-25         11,010         onshore         Senegal (M.S.G.B.C.) Basin             C-26         10,875         onshore/offshore         Senegal (M.S.G.B.C.) Basin             C-27         11,760         onshore         Senegal (M.S.G.B.C.) Basin             C-30         2,975         offshore         Senegal (M.S.G.B.C.) Basin             C-31         4,396         offshore         Senegal (M.S.G.B.C.) Basin             C-32         2,518         offshore         Senegal (M.S.G.B.C.) Basin             C-33         2,628         offshore         Senegal (M.S.G.B.C.) Basin             Onshore Block 11         15,153         onshore         Senegal (M.S.G.B.C.) Basin             Ta-2         13,766         onshore         Taoudeni Basin             Ta-3         14,354         onshore         Taoudeni Basin             Ta-4         11,746         onshore         Taoudeni Basin             Ta-5         11,273         onshore         Taoudeni Basin             Ta-6         11,585         onshore         Taoudeni Basin             Ta-7         14,132         onshore         Adrar Sub-basin (Taoudeni Basin)             Ta-8         14,076         onshore         Adrar Sub-basin (Taoudeni Basin)             Ta-9         12,141         onshore         Taoudeni Basin             Ta-10         14,749         onshore         Taoudeni Basin             Ta-11         14,107         onshore         Hodh Sub-basin (Taoudeni Basin)             Ta-12         14,135         onshore         Hodh Sub-basin (Taoudeni Basin)             Ta-13         14,834         onshore         Taoudeni Basin             Ta-14         11,581         onshore         Taoudeni Basin             Ta-15         10,712         onshore         Taoudeni Basin             Ta-16         12,955         onshore         Taoudeni Basin             Ta-17         13,057         onshore         Taoudeni Basin             Ta-18         20,005         onshore         Taoudeni Basin             Ta-19         20,106         onshore         Taoudeni Basin             Ta-20         21,491         onshore         Taoudeni Basin             Ta-21         16,514         onshore         Hodh Sub-basin (Taoudeni Basin)             Ta-22         21,351         onshore         Taoudeni Basin             Ta-23         17,584         onshore         Hodh Sub-basin (Taoudeni Basin)             Ta-24         20,648         onshore         Hodh Sub-basin (Taoudeni Basin)             Ta-25         20,528         onshore         Taoudeni Basin             Ta-26         14,557         onshore         Taoudeni Basin             Ta-27         18,943         onshore         Taoudeni Basin             Ta-28         14,769         onshore         Taoudeni Basin             Ta-29         12,870         onshore         Taoudeni Basin             Ta-32         9,787         onshore         Taoudeni Basin             Ta-33         12,332         onshore         Taoudeni Basin             Ta-34         8,976         onshore         Taoudeni Basin             Ta-36         15,501         onshore         Adrar Sub-basin (Taoudeni Basin)             Ta-37         18,840         onshore         Adrar Sub-basin (Taoudeni Basin)             Ta-38         9,568         onshore         Adrar Sub-basin (Taoudeni Basin)             Ta-39         9,273         onshore         Adrar Sub-basin (Taoudeni Basin)             Ta-40         10,712         onshore         Taoudeni Basin             Ta-41         11,702         onshore         Eglab-Reguibat Massif             Ta-42         11,903         onshore         Taoudeni Basin             Ta-43         11,814         onshore         Taoudeni Basin             Ta-44         13,060         onshore         Taoudeni Basin             Ta-45         14,423         onshore         Eglab-Reguibat Massif             Ta-46         14,735         onshore         Taoudeni Basin","The Ministry of Hydrocarbons, Energy and Mines (Ministère des Hydrocarbures, de l’Energie et des Mines) is the licensing authority. Contracts are signed by the state, as represented by the Minister of Hydrocarbons, Energy and Mines. "
87352,"Ref. DEA 7 Jul '20, PetroRio announces the ANP has only now (3 August) made effective the 80% acquisition from Dommo Energia in the Tubarão Martelo (Hammer Shark) field in BM-C-039, Campos Basin, where PetroRio now has operatorship. The field is host to the OSX-3 FPSO, also acquired for USD 140 MM. The deal provides for a tieback between the Tubarão Martelo (Hammer Shark) + Polvo (Octopus) fields using OSX-3 expected mid-'21, thus saving on the FPSO stationed on Polvo, inter alia.   Once the tieback is completed, PetroRio will be accountible for 100% of the cluster costs, Dommo being relieved of monthly fees. PetroRio will be entitled to 95% of oil produced, up to the first 30 MMbbl post-tieback, and 96% thereafter. Petro Rio (op), partner Dommo.","(Campos B.) BM-C-039 op. by PETRORIO (80%), DOMMO EN (20%). PetroRio announces the ANP has made effective the 80% acquisition from Dommo Energia in the Tubarão Martelo (Hammer Shark) field, where PetroRio now has operatorship. "
88503,"Central part of PN-T-68 block, onshore Parnaíba Basin, gas shows report to ANP 13 Aug '20. PTMD is/was 1,792m (1,650m TVD), targets possibly Cabeças and/or Poti fm's, GWDC rig 120.","(Parnaiba B.) 1-ENV-BL-084A-MA op. by OTHERS (58%), BTG PACT (34%), E ON (8%) in PN-T-084 block, TD = 2260 m, gas shows report to ANP 13 Aug '20. PTMD is/was 1,792m (1,650m TVD), targets possibly Cabeças and/or Poti fm's."
83551,"CAOG Pte Ltd, a fully-owned subsidiary of Berlanga International, continued to offer a farm-in opportunity in the onshore block MOGE-4, located in the Pyay Embayment (Central Burma Basin), in June 2020. This opportunity is likely aimed at identifying a potential partner to participate in two commitment exploration wells in the block in 2H 2020, ahead of the exploration period expiry at the end of November 2020.  The wells will likely target the Lower Miocene carbonates of the Pyawbwe Formation, analogue to the nearby Htantabin field, and the Upper Oligocene sandstones of the Okhmintaung Formation. Total depth is expected to be approximately 1,000 m for each well. Prospective resources for the main prospects and leads have been estimated between 60 and 180 Bcfg for high-case recoverable volumes. As of late 2019, Berlanga indicated an estimated drilling cost of approximately USD 10-15 million.  The MOGE-4 block is believed to be as-condensate prone, and is located near existing facilities serving producing fields in the area. A total of 390 km of 2D data was acquired by contractor AlphaGeo (India) Limited in 2016.  The first three-year exploration period for the block commenced on 1 December 2015 and expired on 30 November 2018. The operator submitted a request for extension in late August 2017 and approval was granted in February 2018, pushing the expiry to the current date of 30 November 2020.     The block was offered as part of the Myanmar 2013 Onshore Bidding Round. Luxemburg-based CAOG and local partner AOEX Geo Services Co Ltd were announced as winners of the block in October 2013, and a PSC was officially signed in September 2014.   CAOG holds 94.5% operating interest in the block while Apex Geo Services holds the remaining 5.5%. The farm-in opportunity was first offered in December 2015.  A data room is available in Yangon. Interested parties may contact:  Hans Braakman  Email: hans.braakman@berlanga-group.com  Romain Courel  Email: romain.courel@berlanga-group.com  Background Information  Block MOGE-4, covering 912 sq km, is located in the Myintha area, in the southern part of the Pyay Embayment Sub-basin. The block is one of the blocks offered in Myanmar first bidding round in 2011 and was initially awarded to Tianjin New Highland petroleum Co and SUNTECH Company in late December 2012. The official PSC was not awarded for unknown reason, but most likely the PSC terms and discussion did not go through.  The block was last operated by MOGE since 7 March 2005. The block contains the Htantabin field, discovered in 1981 by MOC. The field was brought onstream in November 1981 and produced approximately 550 Mb until 1987. Subsequently, the field was believed to produce intermittently at a very low rate of around 10 bo/d and 1,000 Mscf/d. The field production was reportedly suspended as of March 2009. The field main reservoir is constituted by fractured limestones within the Pyawbwe Formation. At least 22 appraisal and development wells have been drilled on the field. MOGE also acquired a total of 94km of seismic lines over the field during 1998, and further 78km of 2D data from January to June 1999.  In addition to the Htantabin discovery, four other new-field wildcats have been drilled in the block. Two dry wells, Htantaung 1 and Myintha 1, were drilled by unknown operators in the central part of the block. Between 1991 and 1992, MOGE drilled Chinmyaung 1 to a depth of 3,116m. The well was tested over several intervals but only encountered gas shows. In 2000, MOGE drilled the Kansei 1 wildcat to a TD of 1,591m. The well, located about 3km east of the Htantabin field, is assumed to be dry.","Myanmar (Central Burma B.) MOGE-4 op. by BERLANGA (95%), GIS (6%), CAOG Pte Ltd MOGE-4 - Farm-in opportunity still available (update)"
79327,"As of April 2020, China National Offshore Oil Corp (CNOOC) is seeking partners in its BC9 and BCD10 contracts in the Gabon Coastal Basin offshore Gabon. The company operates the contracts BC9 and BCD10 with a 100% interest since Shell exited the licences in November 2019. The company attempts to farm out up to 50% stake prior to drill two high impact wells between late 2020 and 2021, one in each block. According to CNOOC all commitments have been met in both contracts. The company is to enter, in September 2020, in the 2-year fourth exploration period of the BC9 contract with the possibility to be extended up to three years. The BCD10 licence holds the multi Tcf Leopard gas discovery (2014) and is in a gas holding period until 2026 with minimal work commitments.  CNOOC identified, both in post-salt and in pre-salt sequences, some 25 leads and/or prospects of which two are drill-ready. The ""Tigre"" prospect is to be drilled in about 2,000 m of water depth in the BC9 block targeting an approx. 100 sq km area in the pre-salt Gamba sandstones of Aptian age. The ""Seal"" prospect is to be drilled in approx. 400 m of water depth in the southeastern corner of the BCD10 block targeting the carbonate of the Albian Madiela Group formation in a large 3-way structure with mean recoverable resources estimated at 356 MMbo. CNOOC is also working on the Leopard gas discovery studying for a further appraisal program to determine the feasibility of a standalone development.    CNOOC has open a data room since March 2020 with an anticipated bid deadline in mid-2020.    Contact details:         Lucas Ong Business Development Advisor                          E-mail: Lucas.Ong@intl.cnoocltd.com               Tel: +44 1895-555319    Ben Kilner Team Lead, Global Exploration                          E-mail: Ben.Kilner@intl.cnoocltd.com               Tel: +44 1895-555310       Background information    The blocks BC9 and BCD10 were initially granted to Shell on September 2007. BC9 and BCD10 blocks are mainly in deep waters, covering a total of some 13,400 sq km of which about 530 sq km are in shallow waters. CGG acquired a 6,000 sqkm 3D seismic program between 2010 and 2011. CNOOC farmed in both blocks in 2012. The partners drilled a first wildcat N'Komi Marin 1 in 2014, the well intersected a 200 m paleo-oil column in the pre-salt Gamba formation. It was followed by a success with the Leopard gas and condensate discovery made in October 2014. The latter drilled to TD of 5,063 m intersected a substantial gas column of 200 m of net gas pay in the Gamba formation. The discovery was confirmed by the appraisal Leopard 2 suspended in January 2016. CGG completed in March 2016 the acquisition of a 3D seismic program in the BCD10 block.    Six exploration wells were drilled before 2007, in the areas covered by the actual BC9 and BCD10 blocks, targeting post-salt objectives such as the Cenomanian Cap Lopez formation and the Albian Madiela Group formation. All were dry except the Grand Large N'Kendji Marine 1 wildcat, which encountered non-commercial oil in February 1985. The well, drilled by Elf Gabon, is located 85 km west of Sette Cama in 163 m of water. It bottomed in the Albian Madiela Group at a depth of 3,893m.",China National Offshore Oil Corp (CNOOC) is seeking partners in its BC9 and BCD10 contracts in the Gabon Coastal Basin offshore Gabon. 
14828,"ADNOC has signed an agreement with Mubadala Investment Co’s Cepsa, awarding it a 20% stake in Abu Dhabi’s offshore SARB and Umm Lulu concession. This comprises 2 main fields under devt, namely Umm Lulu, part of the former ADMA offshore concession, and SARB, and  the Bin Nasher and Al Bateel smaller fields. The ADMA concession has been split into 3 new concessions to maximise commercial value.","UAE, not found"
64379,"In early November 2019, Divine Inspiration Group (DigOil) – partner of Efora Energy in the local company Semliki Energy - confirmed being seeking a new partner for its Block III. The company is planning an exploration well in the northern part of the licence.  The 3,217 sq km onshore licence is located in the Nord-Kivu province, eastern Democratic Republic of Congo (DRC), East African Rift System. Block III is crossed by the Semliki River and lies between Lake Albert and Lake Edward adjacent to Ugandan border. In May 2019, the company received a validity extension for its licence. As a result, the exploration phase is set to expire in January 2020.   Interest in the licence is held by Semliki Energy SPRL (85% + operator) and Societe National d’Hydrocarbures de la Republique du Congo (15%).","Democratic Republic of Congo, Block III"
70057,"Three suitors have been shortlisted as possible takeoverees for Exxon's 71.25% stake in the producing Zafiro Complex, offshore Bioko Island. The selected companies are Marathon, Lukoil and GazpromNeft. The deal is said to be worth close to USD 700 MM. Zafiro is shared by Exxon and national GEPetrol.","Three suitors have been shortlisted as possible takeoverees for Exxon's 71.25% stake in the producing Zafiro Complex, offshore Bioko Island. The selected companies are Marathon, Lukoil and GazpromNeft. The deal is said to be worth close to USD 700 MM. Zafiro is shared by Exxon and national GEPetrol."
66986,"Tnf Holdings Ltd was awarded exploration licence PPL 624 on 21 May 2019. The licence lays across the Madang Province to the north and Morobe to the south over a total area of 17,000 sq km, to the east of the Bismark Volcanic Arc. The area has limited seismic data and no known exploration wells have been drilled, making this one of Papua New Guinea's true frontier areas to explore. PPL 624 is valid for a period of 6 years and will expire, or be considered for renewal, on 20 May 2025.  Although the licence area does not extend offshore, the newly acquire Triok 2D seismic data comes within 10 Km of the licence southern boundary which could perhaps offer some ideas as to the prospectively of the area. Approximately 65 km to the north of the licence boundary, Heritage drilled the Kwila and Raintree wells in 2015 with a technical success in the latter. The last company to hold acreage over the newly awarded area was BIMEX Ltd with licence PPL 314. This expired in 2016.  The APPL 624 application took approximately 18 months to process after being submitted to the Department of Petroleum & Energy 22 November 2017. TnF Holdings also hold two further exploration applications: APPL 630 and APPL 631. The APPL 630 area was awarded as PPL 645 to Sino Industrial in May 2019 and is therefore scheduled for formal refusal. APPL 631 is situated over South Pacific Resource's PPL 367 licence which expired in 2016 and will likely be cancelled upon the country exit of the company – perhaps paving the way for TnF.  TnF Holdings, a new entry in to PNG, was awarded exploration licence PPL 624 on 21 May 2019.",Newcomer Tnf Holdings Ltd was awarded exploration licence PPL 624
27894,"AziNor Catalyst announced on 14 June 2018 that a subsidiary of Cairn Energy has agreed to farm-in to licence P1763 (blocks 9/9d and 9/14a) taking a 25% interest. Cairn has also agreed to join AziNor for 50% of the sole risk drilling activity on Agar-Plantain. Furthermore, AziNor will retain operatorship for the proposed appraisal well and Cairn will have an option to take operatorship in the future. The deal completed on 7 August 2018.  The initial appraisal wellbore will delineate the down dip section of the Agar discovery reservoir with a sidetrack targeted to test the Plantain prospect. The target depth is 1,675 m and combined mid-case resources of 60 MMboe with significant upside of 98 MMboe are estimated. The gross well cost is USD 9.2 million (dry hole) or USD 12.8 million (success case including Plantain sidetrack). Agar has a CoS of 58%. The rig contractor has been identified and a spud date slated for Q2 2018. The success case will take 37 days to drill.   The Agar discovery is located in the Viking Graben east of Beryl field and west of the Alvheim hub. The Eocene Agar discovery was made in 2014 with well 9/14a-15A which encountered an 11 m oil-down-to in high quality Eocene Frigg Formation sands. The well was drilled by MPX which was primarily targeting the Upper Jurassic sands of the Aragon prospect. The Upper Jurassic sands were encountered in the well but was water bearing. The sands are trapped within a stratigraphic trap which was also proven by the discovery well with the reservoir package being mapped confidently on high quality 3D broadband seismic data. Through high quality seismic data and advanced quantitative interpretation techniques AziNor have significantly de-risked the Plantain prospect. If the operations are successful then development options could be tie backs to Beryl Bravo, Alvheim FPSO or a standalone FPSO.   Following completion of the deal interest in P1763 is held by Apache Beryl Limited (50% + operator), Cairn subsidiary, Nautical Petroleum Limited (25%), AziNor Catalyst Limited (12.5%) and Faroe Petroleum (12.5%) – Faroe interest is pending deal completion.","AziNor Catalyst announced on 14 June 2018 that a subsidiary of Cairn Energy has agreed to farm-in to licence P1763 (blocks 9/9d and 9/14a) taking a 25% interest. Cairn has also agreed to join AziNor for 50% of the sole risk drilling activity on Agar-Plantain. Furthermore, AziNor will retain operatorship for the proposed appraisal well and Cairn will have an option to take operatorship in the future. The "
85412,"Aker BP and Shell have completed a swap deal whereby Aker BP has acquired a 10% interest in PL 1056 and Shell has acquired 20% in PL 1005. PL 1056 covers an area of 4,549 sq km over blocks 6302/1 to 6302/12 in the deepwater More Basin to the west of Ormen Lange. It contains the 2005 Tulipan gas discovery. PL 1005 covers 1,775 sq km over blocks 6404/9, 6404/12, 6405/4, 6405/7 and 6405/10 and contains the 2003 Ellida oil discovery. It is located north of Ormen Lange in the deepwater Voring Basin. The deal was confirmed by the NPD on 10 July 2020 and is effective from 30 June 2020.   Statoil (now Equinor) drilled Tulipan well 6302/6-1 and confirmed gas in the Paleocene Rogaland Group at around 3,900 m below a very thick Quarternary (Naust Formation) North Sea Fan. The find was small and the well was not tested.  Ellida well 6405/7-1, also operated by Statoil, proved oil in the Upper Cretaceous Nise Formation between 2,760 m and 2,823 m, with good oil shows below this depth. However, reservoir quality was generally poor and on test the well flowed only 252 b/d of 31°API oil.   Following completion of the deal, interest in PL 1005 is divided between Aker BP ASA (40% + operator), Var Energi AS (40%) and A/S Norske Shell (20%) and interest in PL 1056 is held by A/S Norske Shell (30% + operator), Petoro AS (20%), DNO Norge AS (20%), Wintershall Dea Norge AS (20%) and Aker BP ASA (10%).","Norway (More B.), PL 1056, Aker BP has acquired a 10% stake in PL 1056, 4,549 sq km in the More Basin (blocks 6302/1 + 12, Tulipan discovery), in exchange for Shell getting 20% in PL 1005, 1,775 sq km over blocks 6404/9 + 12, 6405/4, 7 + 10 (Ellida discovery) in the deepwater Voring Basin. The deal is effective 30 Jun '20. PL 1005 partners now Aker BP (op), Vår + Shell and PL 1056 Shell (op), Petoro, DNO, Wintershall Dea + Aker BP."
62533,"- Pyae Sone Kywal-1, 4th in 4-well campaign, Padaukpin oilfield area in MOGE-3, Central Burma Basin, P&A 'non-commercial' in Jul '19 at TD ca. 2,000m, gas indications and mud loss during drilling, PTTEP (op), partners Palang Sophon, MOECO + Win Precious R","Pyae Sone Kywal-1, 4th in 4-well campaign, Padaukpin oilfield area in MOGE-3, Central Burma Basin, P&A 'non-commercial' in Jul '19 at TD ca. 2,000m, gas indications and mud loss during drilling, PTTEP (op), partners Palang Sophon, MOECO + Win Precious Res."
69119,"Interoil closed an agreement with Roch under which it acquired an 8.34% interest from the latter in 5 (yet-undesignated) mature prod. leases in the Austral Basin, designated Santa Cruz Sur Assets. The USD 1 MM deal was paid in shares.   It is recalled a similar deal had been reached with Echo Energy in 4Q '19, namely the latter acquiring a 70% stake from Petrolera El Trebol in 5 Roch-operated mature producing blocks in Santa Cruz Sur, adjacent to Echo's existing Tapi Aike unit.","Interoil closed an agreement with Roch under which it acquired an 8.34% interest from the latter in 5 (yet-undesignated) mature prod. leases in the Austral Basin, designated Santa Cruz Sur Assets. It is recalled a similar deal had been reached with Echo Energy in 4Q '19, namely the latter acquiring a 70% stake from Petrolera El Trebol in 5 Roch-operated mature producing blocks in Santa Cruz Sur, adjacent to Echo's existing Tapi Aike unit."
9701,"QianSuidi 1 was drilled to a TD of 1,368m MD in the Ordovician Meitan Formation on 22 September 2017 and was plugged and abandoned in mid-October 2017 after having been spudded on 8 August 2017. QianShudi 1 encountered 14 intervals of gas shows in the Permian Maokou Formation between 96-200m MD and in the Silurian Longmaxi Formation-Ordovician Wufeng Formation between 1,133-1,142m MD. The shale gas exploration/stratigraphic well had a PTD of 1,700m and was targeting the Silurian Longmaxi Formation and Ordovician Wufeng Formation. QianSuidi 1 is geographically located in Guizhou Province, Zunyi City, Suiyang County, Taibai Town. ",Not Found
21368,"On 14 May 2018 Key Petroleum Ltd and Rey Resources Ltd reported that they had signed a sale and purchase agreement, which will see the companies acquire certain subsidiaries to complete an interest swap in permits EP 104, R1 and L15, located in the Canning Basin, and EP 437, located in the Perth Basin.  The deal remains subject to relevant authority approvals.  Under the terms of the agreement, Rey Resources is to acquire all the shares in Key’s wholly owned subsidiary Gulliver Productions Pty Ltd. Rey Resources also reported that it had agreed to acquire Indigo Oil Pty Ltd’s share in the permits. This will give it 100% interest in the Canning Basin licences, which are referred to by the company as the “Lennard Shelf blocks”. As part of the deal in the Canning licences, Key Petroleum will receive a royalty of 2.5% and Indigo a 0.5% royalty in L15 and R1.  Key Petroleum will also acquire all the shares in Rey Resources’ wholly owned subsidiary Rey Oil Gas Perth Pty Ltd, which holds a 43.47% interest in exploration permit EP 437.   Key Petroleum already holds the same interest as the Rey subsidiary, so acquisition will double its holding in the permit, increasing it to 86.94%.  Pilot Energy Ltd holds the remaining interest in the permit.  Key Petroleum’s sale of its Gulliver Productions subsidiary sees its exit from the Canning Basin and it reports this deal will allow it to focus on the Perth Basin acreage.  The EP 427 permit contains the Wye Knot prospect, which is planned to be drilled in 2018 and is targeting potential resources of 1.4 MMbo.  The permit is adjacent to Key’s L7 production licence, which contains the Mount Horner field.  Rey Resources has acquired licence to the north of its existing Canning Basin acreage. It hopes to farm-out some interest in the Lennard Shelf blocks. The licences are outlined as having conventional oil and tight gas potential.  L15 contains part of the Kora West oil field, while R1 contains the Point Torment gas discovery.","On 14 May 2018 Key Petroleum Ltd and Rey Resources Ltd reported that they had signed a sale and purchase agreement, which will see the companies acquire certain subsidiaries to complete an interest swap in permits EP 104, R1 and L15, located in the Canning Basin, and EP 437, located in the Perth Basin. "
63489,"Bozhong 19-6-17 (BZ 19-6-17) was suspended, having intersected gas and condensate in the buried hill reservoir, on or around 29 August 2019 after having been spudded on or around 1 June 2019, using the ""Haiyangshiyou 941"" jack-up. The gas and condensate appraisal well was targeting the Guantao, Dongying and Shahejie formations and buried hill reservoir. Following the drilling and testing of multiple successful appraisal wells, CNOOC has declared that the Bozhong 19-6 discovery to be a hundred million ton oil equivalent gas field. Bozhong 19-6-17 is in the CNOOC operated Bozhong Block in the offshore Bohai Gulf Basin and is approximately 17.5km NNW of discovery well Bozhong 19-6-1 drilled by CNOOC in April 2017. <P />",Not Found
72286,"CNH-R02-L01-A10.CS/2017 contract, Area 10 (block 10), Sureste Basin off Tabasco, WD 340m, TD 3,830m, suspended early Feb '20, now reported oil discovery, 80m net pay in L. Pliocene + U. Miocene, capacity pegged at >10,000 bo/d, est. 200-300 MMbbl OIP. Valaris 8505 SS. Eni (op), partners Lukoil + Capricorn.","Sáasken 1EXP nfw (Eni 65% op , Lukoil 20%, Capricorn 15%) CNH-R02-L01-A10.CS/2017 contract, Area 10 (block 10), off Tabasco, reported oil discovery, 80m net pay in L. Pliocene + U. Miocene (Eni said the reservoirs show ""excellent petrophysical properties""), capacity pegged at >10 000 bo/d, est. 200-300 MMbbl OIP. WD=340m, TD=3830m."
56760,"As of mid-August, the ANP’s Special Bidding Committee had approved 273 out of 600 exploration blocks in nine sectors and all 14 marginal fields blocks in five sectors (a total of 287 blocks) for the 1st ANP Open Door Bid Round, with bids to be submitted on 10 Sep ’19. To date, 47 companies have qualified to participate. More from GEPS.","As of mid-August, the ANP’s Special Bidding Committee had approved 273 out of 600 exploration blocks in nine sectors and all 14 marginal fields blocks in five sectors (a total of 287 blocks) for the 1st ANP Open Door Bid Round, with bids to be submitted on 10 Sep ’19. To date, 47 companies have qualified to participate"
35410,"In early October 2018, Magawish Petroleum Co. (Magapetco) suspended the East Esh El Mellaha Marine 28A (EEMM-28A) exploration well in the Esh El Mellaha Marine development lease, onshore southern Gulf of Suez.   The well was spudded on 16 September 2018 using the L/R “ZJ-45L” and drilled to a TD of 1,240 m in the Basement. It has a planned TD of 1,200 m and objectives in Miocene Kareem formation and the Basal Dolomite.  Magapetco is a JV between EGPC and Trident Petroleum Egypt.  Background information     The concession covers the eastern part of the Esh El Mellaha East Field. The field was discovered by Total in 1988 with the FE 87-08 well.   The EEMM development lease (14 sq km) awarded to Magapetco, a JV between Canadian Occidental Petroleum (Can Oxy) and EGPC on 18 April 1994. In November 2000, Can Oxy changed its name to Nexen and Trident Petroleum Egypt replaces Nexen’s name in the JV.","Magawish Petroleum Co. (Magapetco) suspended the East Esh El Mellaha Marine 28A (EEMM-28A) exploration well in the Esh El Mellaha Marine development lease, onshore southern Gulf of Suez. "
81511,"On 21 May 2020 Denison Gas Ltd was awarded Authority to Prospect permit ATP 2049-P, located in the Denison Trough, Bowen-Surat Basin, from the 2019 Queensland State Acreage Release. The permit, which covers an area of around 568 sq km, has been granted for a period of six years and is scheduled to expire, or be eligible for renewal on 20 May 2026. Under the terms of the award, any gas produced from acreage must be supplied to the Australian market, a term which is carried over should a production license be awarded over the permit.   Denison Gas applied for the acreage which was included in the 2019 Queensland State Acreage Release as PLR2019-1-3. The operator had its application accepted on 30 October 2019. The first relinquishment date of the permit will be after a period of four years, on 20 May 2024, until which time no amendments to the scheduled work programme will be allowed.   ATP 2049-P covers an area of around 568 sq km. Denison Gas Ltd holds 100% operated interest in the permit.","Santos and Denison Gas have been awarded rights in the Bowen + Surat basins of S. QLD, gas-prone acreage, believed issues of the 2019 Queensland State Acreage Release only now formally announced. Santos gets PLT2019-2-9/10/11/12, 2,000 sq km between Chinchilla + Roma, Denison PLR2019-1-3 (now ATP 2049-P), 568 sq km near Emerald in the Bowen Basin."
65128,"Egdon Resources UK Ltd is offering material equity in PL 090 (excluding Waddock Cross oilfield determination) in return for a promoted share cost of a future well. The well will target the Broadmayne prospect which is interpreted to consist of a dip and fault closed tilted fault block. The structure was mapped on 3D seismic which was reprocessed in 2017. The main objective is the Triassic Sherwood sand of which Egdon interpret is oil prone. The reservoir forms the primary reservoir at Wytch Farm. Egdon estimate the Sherwood sand to contain mean prospective resources of 2.8 MMbo. Further potential could exist in the Bridport Sandstone. Estimated dry hole well costs are GBP £2.5m. As of September 2019, the opportunity was still available.  Interest in PL 090 is held by Egdon Resources UK Ltd (42.5% + operator), Corfe Energy Ltd (20%), United Oil and Gas Plc (18.9583%) and Aurora Energy Resources Ltd (13.5417%).  For further details please contact:  Martin Durham  Email: Martin.Durham@egdon-resources.com",Egdon Resources UK Ltd is offering material equity in PL 090 (excluding Waddock Cross oilfield determination) in return for a promoted share cost of a future well. The well will target the Broadmayne prospect which is interpreted to consist of a dip and fault closed tilted fault block.
37283,"The authorities reportedly have plans for a new offshore round in 2019, despite 6 blocks being on offer since 9 Nov ’18. Timing and new blocks have yet to be disclosed. Meanwhile the Charuma onshore acreage, selected for the 2018 round but removed, will be up for grabs also next year.","Trinidad and Tobago, not found"
51844,"Basin-Centered Gas Accumulation (BCGA) play, block F18-C (deep), NE of Yamalik-1 in Thrace Basin / NW Turkey, TD 4,885m, 1,615m gross gas column from 3,270m (base Mezardere fm) to TD (Kesan fm), reservoir stimulation and testing programme started, min. 4 zones to be tested. Valeura well op, partner Equinor funding drilling.","Inanli-1 nfw,Basin-Centered Gas Accumulation (BCGA) play, block F18-C (deep), NE of Yamalik-1 in Thrace Basin / NW Turkey, TD 4,885m, 1,615m gross gas column from 3,270m (base Mezardere fm) to TD (Kesan fm), reservoir stimulation and testing programme started, min. 4 zones to be tested. Valeura well op, partner Equinor funding drilling."
12375,"PPL 62, Otway Basin, SA, TMD 4,331m, 104m gross gas column encountered in the target Sawpit sst, 25.6m net, along with an est. 11.6m gross gas column in the shallower Pretty Hill sst, 8.5m est. net.  The Sawpit tested a constrained 25 MMcf/d for 100 minutes from 4,023-4,185m on a 36/64” choke, 2,700 psi WHP, low inert content which should minimise gas processing requirements. A production test is planned later this month.  ","Haselgrove 3 ST1 op. by Beach (%) in PPL 62, 104m gross gas column encountered in the target Sawpit sst, 25,6m net, along with an est. 11,6m gross gas column in the shallower Pretty Hill sst, 8,5m est. net. The Sawpit tested a constrained 25 MMcf/d for 100 minutes from 4023-4185m [36/64” choke]."
7352,"LINN Energy has signed a definitive agreement to sell its interest in properties located in the Williston Basin to an undisclosed buyer for a contract price of $285 million, subject to closing adjustments. The properties to be sold consist of approx. 20,000 net acres in North Dakota, South Dakota and Montana with second quarter net production of approx. 8,000 BOE/d, proved developed reserves of ~20 MMBOE and proved developed PV-10 of approx. $186 million. For the fourth quarter of 2017, the Company had budgeted ~$7 million of capital for these properties. The sale is expected to close in the fourth quarter of 2017 with an effective date of March 1, 2017. This transaction is subject to satisfactory completion of title and environmental due diligence, as well as the satisfaction of closing conditions. RBC Richardson Barr and Jefferies LLC acted as co-financial advisors and Kirkland & Ellis LLP as legal counsel during the transaction. Original article link Source: LINN Energy ","United States, not found"
68298,"On 18 December 2019, the Federal Agency for Subsoil Use held an auction for four blocks in Yamalo-Nenets Autonomous Okrug (Western Siberia). Lukoil-Zapadnaya Sibir, Gazprom and Belorusneft-subsidiary Yangpur emerged as the winners of the auction. The winners will obtain 25-year E&P licenses with a seven-year exploratory stage.   The Milisskiy block covers 429 sq km in the Ural-Frolov Province and encompasses the Milisskoye oil discovery with 3P reserves estimated at 10 MMbbl and the Milisskaya prospect (deeper reservoirs) with oil resources estimated at 1 MMbbl. Seismic coverage amounts to 374 km. Six wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 24 MMbbl of oil, 38 Bcf of gas and 1 MMbbl of condensate. The starting price amounted to RUB 121.278 million (USD 1.96 million). Lukoil-Zapadnaya Sibir, competing against Lukoil-Komi, offered the starting price.  The Sopochnyy block covers 2,506 sq km in the South Kara-Yamal Province and encompasses the Sopochnaya prospect with resources estimated at 8.939 Tcf of gas and 79 MMbbl of condensate. Seismic coverage amounts to 1,616 km. No wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 289 MMbbl of oil, 6.418 Tcf of gas and 240 MMbbl of condensate. The starting price amounted to RUB 380.428 million (USD 6.1 million). Gazprom, competing against Rosneft, Novatek and Arctic LNG-1, won the auction with the starting price.  The Tydeottinskiy Yuzhnyy block covers 494 sq km in the Nadym-Taz Province. Seismic coverage amounts to 824 km of 2D data and 7 sq km of 3D data. No wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 209 MMbbl of oil, 5.371 Tcf of gas and 82 MMbbl of condensate. The starting price amounted to RUB 88.594 million (USD 1.43 million). Yangpur offered the starting price.  The Yampinskiy block covers 1,808 sq km in the Ural-Frolov Province and encompasses several prospects with combined resources estimated at 198 MMbbl of oil. Seismic coverage amounts to 3,178 km. Four wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 140 MMbbl of oil, 247 Bcf of gas and 4 MMbbl of condensate. The starting price amounted to RUB 265.923 million (USD 4.29 million). Lukoil-Zapadnaya Sibir, competing against Lukoil-Komi, offered the starting price.","Lukoil-Zapadnaya Sibir won Milisskiy (429km²) in the Ural-Frolov Province and Yampinskiy (1808km²) blocks in the same area. Gazprom won Sopochnyy block, (2506km²) in the South Kara-Yamal Province. Yangpur won Tydeottinskiy Yuzhnyy (494km²) block in the Nadym-Taz Province. "
55509,"Yakka Munga prospect in EP 428, Canning Basin, last reported at 1,610m en route to PTD 2,400m, good-excellent oil shows at various levels particularly at 1,443m, main target Reeves sst.  Buru (op), partner Roc (part farmin well).","Adoxa 1 nfw (Yakka Munga prospect) (Buru 50% op, Roc 50%) in EP 428 block, last reported at 1610m en route to PTD 2400m, good-excellent oil shows at various levels particularly at 1443m, main target Reeves sst.  "
21393,"Key Petroleum Ltd, through wholly owned subsidiary Key Cooper Basin Pty Ltd, is offering a farm-in opportunity in exploration permit ATP 924-P, located in the Cooper-Eromanga Basin.  Key is looking for a partner to fund two wells and make a cash consideration to cover back costs, in return for 50% interest in the permit.  Key reports that the permit has been outlined to have potential for Permian gas, with additional opportunity in Triassic and Jurassic units. The Barrolka field, which lies around 25 km south of the permit, has been outlined as an analogue field to potential hydrocarbon accumulations within ATP 924-P. Barrolka was discovered in 1976 and has been producing since 1999.  The primary reservoir is within the Permian Toolachee Formation.  Key reports that 3D seismic has defined a number of structures within the permit area.   ATP 924-P was awarded on 15 February 2013 and covers an area of 2,302 sq km.  Key acquired 100% interest from Beach Energy in November 2017, as well as in permits ATP 783-P and ATP 924-P.  Companies interested in this opportunity should contact:  Kane Marshall  Email: kmarshall@keypetroleum.com.au  Ric Jason  Email: rjason@keypetroleum.com.au  Tel: +61 (0) 8 9381 4322","Key Petroleum Ltd, through wholly owned subsidiary Key Cooper Basin Pty Ltd, is offering a farm-in opportunity in exploration permit ATP 924-P, located in the Cooper-Eromanga Basin.  "
61628,"On 17 October 2019, the Argentine government granted an exploration permit for MLO-113 block to a consortium of a partnership of ExxonMobil and Qatar Petroleum through the publication of Resolution 648/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Work program in the first exploration period of four years consists of 2D seismic acquisition of 962.96 km and reprocessing of 2,331.71 km, 3D seismic acquisition of 1,747.10 sq km and reprocessing of 1,455.92 sq km, along with 2D gravimetry and magnetometry acquisition of 5,156.01 km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment. ExxonMobil operates the block with 70% interest while partner Qatar Petroleum holds the remaining 30%.  MLO-113 covers 5,826 sq km of deepwater area (as designated by the Argentine Secretary of Energy) in Malvinas Basin with approximated water depth below 200 m. Exploration target for the blocks in the area is expected to be oil and gas in the Springhill Formation, which has not produced from any fields on the Malvinas Basin side in comparison to the adjacent Austral Basin side where several offshore gas fields are currently producing.  ExxonMobil and Qatar Petroleum won the rights for MLO-113 after submitting a joint offer of USD 30.1 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019. Along with MLO-113, the group also won the rights for MLO-117 and MLO-118 blocks with offers of 34.475 million and 29.95 million, respectively, that are still pending on official awards as of mid-October 2019. The offshore blocks marked the second partnership between ExxonMobil and Qatar Petroleum in Argentina after Qatar Petroleum's purchase of 30% equity in ExxonMobil affiliates in mid-2018.  Background Information  The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.","Argentina, MLO-117"
47035,"Europa Oil and Gas is offering interested parties to farm-in to Licence Option (LO) 16/20. Europa has identified 3 Tcf undiscovered GIIP in Triassic and Jurassic gas plays. In April 2019, Europa announced negotiations were still ongoing regarding the farm-in agreements with a major oil and gas company concerning licences LO 16/20, FEL 1/17 & FEL 3/13. Europa are expecting to be fully carried on a well on each licence and retain material interest in each licence with the final investment decision pending in the major’s head office. Furthermore, subject to meeting commercial and regulatory criteria, Europa have a site survey planned for summer 2019 for an exploration well (18/20-H) to be drilled on the Inishkea prospect in 2020. This would ensure a well would be drilled at the earliest opportunity, if negotiations are successful.   In February 2019, Europa announced an updated gross mean un-risked prospective resource estimate of 1.5 Tcf for the Inishkea prospect with a 33% chance of success. The prospect has been de-risked through the PSDM reprocessing of 770 sq km of 3D seismic over Inishkea and the Corrib gas field. Reprocessing was benchmarked and calibrated against Ocean Bottom Cable 3D seismic data over the Corrib gas field. Inishkea is defined as a large Triassic structure that lies 11 km from Corrib. The targeted Triassic gas play comprises of Triassic Sherwood sandstone reservoirs, Carboniferous source rocks and the combination of a Triassic Uilleann Halite top seal and fault seal providing the trapping mechanism. The water depths are relatively shallow (400 - 600 m) and do not require harsh environment sixth generation drillships, reducing drill costs. Europa conducted a drill cost estimate for a well on the Inishkea prospect and a dry hole cost including mobilisation and demobilisation of USD 28 million using a prevailing rig rate of USD 120,000 per day. Gas infrastructure is already present nearby at Corrib therefore a fast track path to commercialisation is potentially available, subject to negotiation and cooperation with the current infrastructure owners. The remaining inventory in LO 16/20 includes the Inishkea NW prospect (1,094 Bcf), Inishkea W prospect (212 Bcf), Bofin lead (69 Bcf), Corrib North discovery (40 Bcf) and Corrib NW prospect (26 Bcf).  Interest in LO 16/20 is held solely by Europa Oil & Gas (Inishkea) Ltd.  For further information please contact:  Murray Johnson  Email: murray.johnson@europaoil.com",Europa Oil and Gas is offering interested parties to farm-in to Licence Option (LO) 16/20. Europa has identified 3 Tcf undiscovered GIIP in Triassic and Jurassic gas plays.
45122,"End Feb ’19, Total acquired a 40% interest in P1964, P1965 + P2443 from Eni. Acreage lies on the Winterton High area in quads 53 + 54. Resulting partnership Eni (op) + Total.","End Feb ’19, Total acquired a 40% interest in P1964, P1965 + P2443 from Eni. Acreage lies on the Winterton High area in quads 53 + 54. Resulting partnership Eni (op) + Total."
69281,"The DGH has announced the launch of the 5th round of Open Acreage Licensing Programme (OALP-V). 11 blocks totalling 19,800 sq km are available over 8 basins. Bids are required by 18 Mar '20 using https://ebidding.dghindia.gov.in. Block details from GEPS, and other round specs from http://www.dghindia.gov.in.","The DGH has announced the launch of the 5th round of Open Acreage Licensing Programme (OALP-V). 11 blocks totalling 19,800 sq km are available over 8 basins. Bids are required by 18 Mar '20 "
58135,"Origin has negotiated a (up to) 75% farmin from Bridgeport in ATP 736, 737 + 738-P (total 6,391 sq km), and ATP 2025 + 2026-P (total 2,100 sq km) in the Cooper-Eromanga under s staged process. Origin is required to fund 5 explo wells targeting gas + liquids, capped at AUD 49 MM, by end 2024. The deal is subject to govt approval.    The above is also conditional on Bridgeport taking over full interests (100%) in ATP 736, 737 + 738-P (Senex 55%).","Australia, not found"
24445,"On 28 June 2018, Petrofac announced that it has agreed to sell its entire 45% stake in the Chergui concession onshore Pelagian Basin on the Kerkennah island, Gulf of Gabes, to Perenco. The transaction is expected to close by the end of 2018. On the Chergui concession, Petrofac operates the Chergui gas field which currently has an output of around 24 MMcf/d of gas and 300 b/d of condensate. Partner of Petrofac in Chergui is Tunisian state company ETAP with 55%.  In 2016 and early 2017, production from the field was severely disrupted by protests from the local population. The situation has normalized since mid-2017 when a wave of civil unrest which swept the whole of southern Tunisia subsided. Petrofac’s decision to sell Chergui is in line with its strategy to focus on core and less capital intensive activities. Chergui being the company’s only asset in Tunisia, the sale marks also Petrofac’s exit from the country.  Perenco, on the other hand, continues its growth in Tunisia after taking over OMV’s interest in the Ashtart, Douleb, Semmama and Tamesmida fields in March 2017 which added around 2,200 b/d of oil net to Perenco.  The last development well, Chergui 8 was put on-stream by Petrofac around July 2014.  The 90 Bcf Chergui gas field was discovered by Amoco in 1992 in the then Sud Kerkennah block. Gas is produced from the Eocene Reineche Member foraminiferal limestone.  Petrofac started commercial gas and condensate production from the Chergui Field in August 2008. The total cost of the development is approximately USD 100 million including the Chergui field central production facility in Kerkennah Island. The treated gas is transported through a 57km 8"" pipeline to the 24"" STEG's pipeline in Ain Turkia, north of Sfax. Condensate is trucked to a pipeline facility at Sidi El Itayem field just west of Sfax. The condensate is then transported via the pipeline to La Skhirra where it is sold into the international market.","Perenco acquired 45% op. interest in the Chergui block/field (168km²) from Petrofac (->0%, ETAP 55%)."
13194,"Shale gas well in Hubei, TD 2,332m, reportedly large find (500 Bcum), 86m of pay, tested 4.4 MMcf/d after frac job, 5 appraisals planned to firm up figures, Sinopec Jianghan rig. A 1,220-sq km area has been delineated for further exploration around the discovery. ","E'Yiye (Hubei) 1HF op. by MLR  (Ministry of Land & Resources), Shale gas well in Hubei prov., reportedly large find (17Tcf), 86m of pay, tested 4,4 MMcf/d after frac job, 5 appraisals planned to firm up figures. A 1 220km² area has been delineated for further exploration around the discovery. TD=2332m."
9259,"B-12 / Dahanu field area in C-Series PML, Bombay shallow waters, ops terminated Oct ’17 at TD 3,030m  results unreported but believed to have tested the ‘Object I’ and ‘IV’ , Parameswara JU.",India (Bombay B.) B-12C D op. by ONGC (100.0%) in C-Series Fields ML block
9975,"Lufeng Sag in PRMB, South China Sea, WD 130m, ops terminated 21 Nov ’17, results n/a, Nanhai 2 SS. Target Oligo-Miocene clastics. ",China (Pearl River Mouth B.) Lufeng 8-1 (Pr) 2 op. by CNOOC SHZ (100.0%) in Lufeng 14 block
53064,"11 July 2019, Uzbekneftegaz (UNG) reports a new gas discovery at Chakar in the Fergana Basin, eastern Uzbekistan. Well Chakar 2 was spudded in March 2019. On 10 July, the well was tested at a depth of 1710 m and flowed gas at a rate of up to 300,000 cu m/day (10.3 MMscf/d). The well is continuing to test. UNG plans to drill two outposts at Chakar in the near future.    Chakar is situated in the east of the Fergana Basin’s Uzbek sector, close to the recently discovered Uchtepa field. UNG does not reveal the discovery’s geological details, it is assumed that the gas likely occurs in the Bukhara Formation (Paleocene), a regional play in the Fergana Basin.     Background Information    In April 2019, UNG reported a new flow of gas obtained at the Uchtepa discovery in the Fergana Basin. Appraisal (outpost) well Uchtepa 7 has tested gas at a rate of 300-350 thousand cu m/d (10.3-12.0 MMscf/d). Well 7 has been drilled to a TD of 1,350 m.     Uchtepa was discovered by UNG in late 2017. Gas has been tested in wells 3, 4, 5 and 1-Jurassic, at rates reaching 386,000 cu m/d (13.2 MMscf/d).    Uchtepa is located south-east of the Andizhan and Sharihan-Hojaabad fields, close to the border with Kyrgyzstan.","Chakar 2 (UzbekNefteGaz 100%), tested at a depth of 1710 m and flowed gas at a rate of up to 10,3 MMscf/d. UNG does not reveal the discovery’s geological details, it is assumed that the gas likely occurs in the Bukhara Fm (Paleocene), a regional play in the Fergana Basin"
16697,"Inpex has been awarded WA-533-P in WD 50-600m in the offshore Canning Basin, offered in the 2016 block release as W16-6. Commitments include G&G, and one well by March 2024.","Inpex has been awarded WA-533-P in WD 50-600m in the offshore Canning Basin, offered in the 2016 block release as W16-6. Commitments include G&G, and one well by March 2024."
71030,"TAQA spudded the P15-20 (G2) exploration well on 22 October 2019 using the “Maersk Resolute” J/U to drill the exploration well in block P15a. The top hole is located at the P15-13 field (the P15-G platform) but since this is classified as an exploration well it is assumed that it will deviate to a new target. On 26 November 2019 TAQA was drilling the 8-1/2"" hole at 4,300 m. On 13 December 2019 operations were complete and the well was reported as gas bearing.  The P15-13 well was drilled in 1990, making a new discovery in the Triassic Bunter Sandstone. The well was converted to a producer (and renamed P15-G1) and the field was brought onstream in October 1993 through this single well. P15-G is a wellhead platform which is tied-back to the P15-D processing platform at Rijn to the northeast.  Interest in the permit is divided between TAQA Offshore BV (25% + operator), One-Dyas BV (14.2%), Dana Petroleum Netherlands BV (10.7%), RockRose (NL) CS1 BV, Wintershall Noordzee BV (1.1%) and Energie Beheer Nederland BV (40%).","P15-20 (G2) exploration well operations complete, gas"
35520,"As reported in late November 2018, Eni’s partner New Age (African Global Energy) Ltd via its local subsidiary New Age M12 Holding Ltd (New Age) in the Marine XII (Litchendjili Marin, Minsala, Nene-Banga and Nkala) is looking to sell its interest. New Age holds a 25% interest in the blocks. According the report New Age has hired Evercore to help with the sale which may raise in the region of USD 1 billion.   Eni Operates the blocks with a 65% interest, New Age and SNPC hold 25% and 10% interest respectively","Eni’s partner New Age (African Global Energy) Ltd via its local subsidiary New Age M12 Holding Ltd (New Age) in the Marine XII (Litchendjili Marin, Minsala, Nene-Banga and Nkala) is looking to sell its interest. New Age holds a 25% interest in the blocks. According the report New Age has hired Evercore to help with the sale which may raise in the region of USD 1 billion. Eni Operates the blocks with a 65% interest, New Age and SNPC hold 25% and 10% interest respectively"
43626,"In early March 2018, industry sources indicated that the authorities may be offering former OK Energy-operated acreage for exploration rights (ER) off the south coast in the Outeniqua basin. In this area, OK operated the OK Energy 1 block over about 7,000 sq km in WD 0-300m. Should this be confirmed, the offer would entail blocks 3422 A, B + D. OK Energy relinquished the block around February 2019, the company otherwise retains acreage in the Algoas/Outeniqua Basin (ER 257) and in the Orange Basin.   In January 2016, OK Energy was awarded Exploration Rights for block OK Energy 1. It is located northeast of Block 9. Eight wells were drilled in the area, the last by Soekor (Pty) Ltd in 1986, all of which were plugged and abandoned as dry. OK Energy operated the block with a 100% interest.","In early March 2018, industry sources indicated that the authorities may be offering former OK Energy-operated acreage for exploration rights (ER) off the south coast in the Outeniqua basin. In this area, OK operated the OK Energy 1 block over about 7,000 sq km in WD 0-300m. Should this be confirmed, the offer would entail blocks 3422 A, B + D. OK Energy relinquished the block around February 2019, the company otherwise retains acreage in the Algoas/Outeniqua Basin (ER 257) and in the Orange Basin. In January 2016, OK Energy was awarded Exploration Rights for block OK Energy 1. It is located northeast of Block 9. Eight wells were drilled in the area, the last by Soekor (Pty) Ltd in 1986, all of which were plugged and abandoned as dry. OK Energy operated the block with a 100% interest."
53314,"Santos Ltd spudded the Raffle Northwest 1 exploration well in PL 1046, located in the Cooper-Eromanga Basin, on 8 June 2019.  The well was drilled to a total depth of 2,468 m, before being suspended as a successful gas well, on 28 June 2019.  The well was drilled around 3 km north of the Raffle field and around 2 km southwest of the Hector South 1 gas discovery.  PL 1046, which covers an area of 51 sq km, was awarded on 8 May 2019.  Participants in the permit are Santos Ltd (37.5% + Operator), Beach Energy subsidiary Delhi Petroleum Pty Ltd (30%) and Santos subsidiaries Santos Petroleum Pty Ltd (25%) and Vamgas Pty Ltd (7.5%).","Raffle Northwest 1 expl. (Santos 52,5% op., Beach 30%, Vamgas 7,5%) in PL 1046, gas disc. "
40668,"PEMEX was conducting completion operations on the Kaneni 1EXP horizontal new-field wildcat (NFW) in the AE-0073 block in the onshore Tampico-Misantla Basin during late-January 2019.      The NFW reached a final total depth of 4,940 m measured depth (MD) and 3,269 m true vertical depth (TVD)       The NFW was spudded on 16 August 2018.         The NFW had a proposed      total depth (PTD) of 4,894 m measured depth (MD) and 3,175 m true vertical      depth (TVD).     The Upper Jurassic Pimienta Formation was the      primary objective.      The prospect size is reported to be 22 MMboe with      a proposed drilling and completion cost estimated at approximately USD 11      million.      PEMEX plans to drill a 2,000 m horizontal leg and      frac it with up to 15 stages.      The      well is located in the east central area of the block on the same drilling      pad as the Llano Lindo 1 NFW and 3.4 km southwest of the Defensa 101 well.    The well has been planned for a couple of years      now.    The CNH granted the latest drilling permit for      the well on 10 April 2018.    SENER granted the AE-0073-2M-Puchut-01      entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block      covers an approximate area of 944.86 sq km.     On 9 November 2016, PEMEX requested that its authorization to drill the Kaneni 1 horizontal new-field wildcat (NFW) in the AE-0073 block in the onshore Tampico-Misantla Basin be suspended due to environmental requirements by environmental protection agency ASEA.  PEMEX requested the permits be suspended until ASEA issues specific public regulations regarding unconventional drilling activity.  Details were not reported regarding the ASEA requirements but are speculated to be very onerous.  The CNH is expecting ASEA to publish its unconventional drilling regulations at an unspecified time in the future, presumably prior to any unconventional bid rounds, the first such rounds tentatively scheduled to be held by 2017.    On 25 February 2016, the CNH originally approved plans by PEMEX to drill the Kaneni 1 horizontal new-field wildcat (NFW) in the AE-0073 block in the onshore Tampico-Misantla Basin.","Mexico, not found"
51030,"On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the L44-A3,A4 onshore exploration licence in the Zagros Province towards southeast of the country on 28 May 2019. The licence covers around 304 sq km area and it has been granted for a five-year term with an expiry date of 27 May 2024. TPAO is 100% owner and operator of the licence.  TPAO had filed the application for L44-A3,A4 exploration licence on 26 July 2018.","TPAO has been awarded the L44-A3,A4 onshore exploration licence in the Zagros Province towards southeast of the country "
55753,"UK Oil and Gas Plc announced on 7 August 2019 that it has agreed to acquire Magellan Petroleum (UK) Investment Holdings Limited 35% interest in PEDL 137 and PEDL 246 which hosts the Horse Hill field for a total consideration of GBP 12 million. Magellan is owned by Tellurian Investments LLC. Following completion of the deal UKOG Horse Hill’s net interest will increase from 50.635% to 85.635%. The deal will give UK Oil and Gas full operatorship for the forward drilling programme and production schedule. Following completion of the deal the drilling of the HH-2/2Z Portland horizontal well will follow shortly.   Horse Hill is located in the Weald Basin and comprises of two fractured limestone members within the Kimmeridge section and an overlying Portland Sandstone reservoir which have all flowed oil. The field was discovered back in 2016. Extended Well Tests and production has been run on the field since 2018. In late summer 2019 it was reported that in total, from all horizons 60,186 barrels of oil had been produced. The drilling of HH-2/2Z is planned to commence in later summer 2019.",UK Oil and Gas Plc announced on 7 August 2019 that it has agreed to acquire Magellan Petroleum (UK) Investment Holdings Limited 35% interest in PEDL 137 and PEDL 246 which hosts the Horse Hill field for a total consideration of GBP 12 million.
24624,"Kalisat Energi is looking to dilute its 100% interest in the Long Hubung-Long Bagun PSC, 1,100 sq km onshore E. Kalimantan, ahead of committed wildcat drilling next year (Mamahak structure, PTD 2,200m). Contact: Maureen Macaulay, mmacaulay@moyesco.com.","Kalisat Energi is looking to dilute its 100% interest in the Long Hubung-Long Bagun PSC, 1,100 sq km onshore E. Kalimantan, ahead of committed wildcat drilling next year (Mamahak structure, PTD 2,200m). Contact: Maureen Macaulay, mmacaulay@moyesco.com."
13975,"On 1 February 2018, ConocoPhillips announced that it had signed an agreement to acquire Anadarko Petroleum’s 22% non-operated interest in the western part of the North Slope as well as the company’s working interest in the Alpine pipeline for USD 400-million. The transaction is subject to regulatory approval and will have an effective date of 1 October 2017 once all the approvals have been granted. Production in the assets amounted to approximately 63,000 barrels of oil equivalent per day. The deal appears to include all National Petroleum Reserve-Alaska (NPR-A) acreage including the Willow discovery announced last year, also located in the NPR-A. Additional lease details will be forth coming as information is made available.",United States (Barrow Arch (North Slope B.)) Alpine
29618,"Vegas Oil & Gas is offering a farm-in opportunity of up to 35% for a technical partner in its East Lagia block in the Sinai Peninsula, located east of Petrosinai’s Lagia devt. A USD 3.9-MM, 550-km 2D seismic programme is planned later this year. Contact Loukas Tripelopoulos (info@Vegasoil.com). Background from GEPS.","Egypt, Lagia (Dev)"
69832,"It was announced on 19 January 2020 that Turkiye Petrolleri A.O. (TPAO) has been awarded the G17-D1,D2,D4 onshore exploration licence (Thrace Basin) on 9 January 2020 for a period of five-year. The licence, covering an area of 290 sq km, is located towards northwest of the country and TPAO will be 100% owner and operator of the licence. TPAO had filed the application on 2 August 2019.  Arar Petrol ve Gaz Arama Uretim Pazarlama A.S was also interested in G17-D1,D2,D4 licence and, as announced on 7 May 2019, the company had submitted an exclusive application for the exploration licence on 24 April 2019.","TPAO has been awarded the N39-B, N39-C, N39-A onshore exploration licence (Western Arabian Province) and G17-A, G17-D1,D2,D4, G17-C1,C4, G16-D, G16-C, G16-B onshore exploration licence (Thrace Basin)"
25082,"Red Sky has agreed to buy out the Innamincka Dome o&g project in South Australia from Beach. This involves a 100% interest in PRLs 14 (Flax field), 17 (Yarrow field), 18 (Juniper field), 180 + 181, and 75% in PRL 182. The deal carries a price tag of AUD 1, however Red Sky will be in charge of obligations, including decommissioning, abandonment, rehabilitation, remediation or restoration. The initial focus will be on re-activation of Flax.","Australia, PRL 182"
14664,"Yuzgas BV looks set to acquire 90% in the Yuzivska permit from state company Nadra Ukrainy's wholly-owned subsidiary Nadra Yuzivska. A draft order to approve the transaction was submitted to Cabinet on 9 February 2018. Yuzgas is primarily funded by NAFTA of Slovakia, and will pay US$ 4 million initial consideration, with further contingent payments of US$ 5 million when cumulative output reaches 1 billion cubic metres gas (Bcmg) equivalent to 35 Bcfg, US$ 10 million at 3 Bcmg (106 Bcfg), and $21 million at 5 Bcmg (177 Bcfg), for a potential total deal value of US$ 40 million. Yuzgas was formed by Emerstone Capital Partners and successfully bid to farm into Yuzivska in August 2016, but the transaction was rejected by Ukraine's Cabinet of Ministers on 2 November 2016. NAFTA confirmed it would enter the Yuzgas partnership in August 2017, reviving the proposed farm-in. Yuzgas has pledged to invest US$ 200 million during its first five years in the licence, but will also benefit from US$ 80.1 million spent on exploration by Nadra Yuzivska, of which US$ 27.2 million will reportedly be reimbursed to Yuzgas. Yuzivska spans 7,886 sq km in the N of Donetsk Oblast and the SE of Khar'kov Oblast, within the Dnieper - Donets Basin. The block was originally offered for shale gas exploration in 2012, but also has conventional prospectivity. A 50 year PSA was awarded on 6 March 2013 to Nadra Yuzivska, at the time a JV between Shell (50% + Op), Nadra Ukrayny (40%) and SPK Geoservice (10%). The initial work programme consisted of three exploration wells during the first year and up to US$ 10 billion invested across the lifetime of the PSA, however force majeure was declared on 15 July 2014, due to the deteriorating security situation in the region. In 2015, Shell and SPK withdrew from the JV, prompting the farm-in tender, with Yuzgas beating competing bids from Burisma Holdings and Balkash Petroleum. <P />",Yuzgas BV looks set to acquire 90% in the Yuzivska permit from state company Nadra Ukrainy's.
24303,"On 29 May 2018 the Ministry of Energy reported it is planning a tender for the 1-22 Tervel offshore block. The 1-22 Tervel block will cover the area of the former 1-22 Teres block and is situated between the 1-21 Han Asparuh (Total) and the 1-14 Han Kubrat (Shell) blocks, adjoining the Turkish maritime boundary. The block – which was never drilled - encompasses 4,032 sq km in a water depth ranging between 1,800 m and 2,500 m.     The exploration period is five years from the date of the contract signature plus two two-year extensions, according to Art. 31 of the amended Underground Resources Act.    A first bid round for the 1-22 Teres block opened in December 2012 and closed in May 2013 with no bids received. According to industry sources, interest at the time was shown by Format Energy (US), Lukoil, OMV, RWE-Dea, Shell and TPAO.    A second tender for the 1-22 Teres block was launched in April 2015 and closed in September 2015 also with no bids received. At that time Anadarko had reported its interest to participate in the tender for both the 1-22 Teres and 1-14 Silistar (1-14 Han Kubrat) blocks. ExxonMobil and Statoil were also considering their participation. Industry sources reported in June 2015 that BP was talking to the Bulgarian authorities about its possible interest in the acreage on offer.","On 29 May 2018 the Ministry of Energy reported it is planning a tender for the 1-22 Tervel offshore block. The 1-22 Tervel block will cover the area of the former 1-22 Teres block and is situated between the 1-21 Han Asparuh (Total) and the 1-14 Han Kubrat (Shell) blocks, adjoining the Turkish maritime boundary. "
33562,"SK-316, offshore Central Luconia Province/Baram Delta, P&A gas discovery at TD 3,590m on 25 Oct ‘18, tested the Middle Miocene Cycle IV carbs (result n/a), Naga 6 JU.","Malaysia, SK-316"
28053,"On 24 August 2018 Ithaca Energy announced that it has agreed to acquire all the Greater Stella Area (GSA) licences and associated infrastructure interests of Dyas UK Limited and Petrofac Limited. The effective date of the transaction is 1 January 2018 and the deal is expected to complete towards the end of 2018 subject to regulatory approval. In return for the interest, Ithaca will pay an initial payment of USD 130 million along with deferred payments of USD 120 million paid over a period of 2020 to 2023. Depending on the performance going forward of the Stella and Harrier fields, Petrofac has the opportunity to earn up to USD 28 million by 2023.  Ithaca has acquired a 25.34% from Dyas and a 24.8% interest from Petorfac in the FPF-1 (Floating production Unit) infrastructure, a 25.34% interest from Dyas and a 20% interest from Petrofac in Stella and Harrier (licence P011), a 25.34% interest from Dyas and a 20% interest from Petrofac in the Hurricane asset (licences P1665 / P2190), a 47.5% interest from Dyas in the Jacky field (licence P1392) and a 17.5% interest from Dyas in the Athena field (licence P1293). Following completion of the deal, Ithaca will hold 100% in all the aforementioned assets apart from Athena in which it will hold a total of 40% interest. As a result of the deal Ithaca will increase its production forecast by 50% to approximately 22,000 boe/d with operating costs attributed at USD 18/boe. The transaction is hoped to increase the company’s 2P reserve based by more than 20 MMboe.  The GSA development is a new Central North Sea hub with the potential tie-in of Hurricane and Helios. Five development wells were drilled on Stella (three into Andrew and one into the Ekofisk reservoir) which fill the gas processing capacity on FPF-1 and two development wells were drilled on Harrier. One well drilled into the Harrier Ekofisk reservoir and the second well drilled into the Tor reservoir. The Tor reservoir is tied-into the GSA facility. The produced gas is being transported and processed on the FPF-1 via the Central Area Transmission System (CATS) and Teeside Gas and Liquids Processing (TGLP) terminal. The design life for the systems on Stella and Harrier is 15 years. Harrier was discovered in 2003 and has two Cretaceous reservoirs (Ekofisk and Tor). The field was developed under the UK’s small field allowance as its reserves are approximately 24 MMboe which is under the 45 MMboe limit. Stella was discovered by Shell in 1984 with well 30/6-3Z. The field comprises two reservoirs - the gas condensate-bearing Upper Paleocene Andrew Sandstone Unit and the oil-bearing Lower Paleocene Ekofisk Chalk Formation - which are draped over a salt-induced anticline. The structure has 300 m closure over a 22 sq km area. It was appraised in 2010 with well 30/6a-8. The well was tested and it confirmed the presence of hydrocarbons 150 m lower than previously identified, thus increasing the total measured hydrocarbon column to 250 m and in turn significantly increasing the reserves estimate. The well was tested and flowed at a restricted rate of 2,850 b/d of light oil (39 °API) and 2,150 bw/d. The sidetrack encountered 5 m true vertical thickness of Andrew Sandstone that was fully hydrocarbon-saturated. These well results increased the 2P reserves of the field by 12.8% to 42 MMboe.","Ithaca has agreed to buy-out Dana and Petrofac’s interests in the Greater Stella area licences and related infrastructure interests for a staged total of US$250 MM. The deal should increase Ithaca’s 2P reserves by over 20 MMboe. Involved are licences P011 (Stella/Harrier, 100%), P1665/P2190 (Hurricane, 100%), P1392 (Jacky,100%), P1293 (Athena, 40%),"
87066,"State-run Heritage Petroleum, in late July 2020, said it aims to identify and explore opportunities in deeper reservoirs within the company’s onshore North West District area, specifically below the Mid-Miocene unconformity. The company hopes to engage in joint studies for potential acreage acquisition. “Opportunities may range from reservoir appraisal within producing fault blocks to outstep or deeper rank exploration”, the company said. Interested parties seeking a detailed Expression of Interest document can make a request via email to BusinessDevelopment@Heritage-tt.comHeritage Petroleum is the E&P subsidiary of the recently formed Trinidad Petroleum Holding Ltd (Trinidad Petroleum). That is the company which has replaced the former state energy interest, Petrotrin. The company is seeking to boost onshore oil production, among other initiatives. ",Not Found
48573,"Nim 2568-9 EL, Hyderabad in Lower Indus onshore, TD 2,676m, tested 10.44 MMcfg/d + 120 bc/d on 1/2” choke, WHP 2,085 psi, from the target L. Goru. Co. N-55 rig. OGDC (op), partner GHPL.","Mangrio 1 (OGDC 95% op, GHPL 5%) in Nim 2568-9 EL block, gas and condensate discovery, tested 10.44 MMcfg/d + 120 bc/d on [1/2” choke], from the target L. Goru. TD=2676m."
26295,"Andalas Energy and Power has bought a further 10.25% stake in Eagle Gas Ltd for GBPS 225,000 (US$300,000) total consideration (GBPS 125,000 cash, rest in Andalas shares), as announced on 25 July 2018. Andalas now holds 25% of Eagle Gas, after it was previously announced on 16 July 2018 that Andalas had closed its acquisition of 14.75% stake in Eagle Gas for GBPS 150,000 (US$ 200,000) total consideration (GBPS 125,000 cash, GBPS 25,000 shares). Andalas reports that Eagle Gas holds 66.667% of P2112, although the OGA indicates that Holywell Resources has this stake, so it is assumed that Eagle has previously acquired either the 66.667% stake, or Holywell Resources. The licence covers 243 sq km on Southern North Sea part blocks 43/29a & 30b, and 48/4a, 4b & 5a, located 20km W of Schooner Field. It was awarded in the 27th Round on 20 December 2013 to Centrica (subsequently merged with Bayerngas Norge into Spirit Energy), Holywell, and Atlantic, with a firm commitment to reprocess 1,026 sq km of 3D seismic to pre SDM, and an option to drill a well to the shallower of 3,800m MD or 100m into the Namurian. The licence contains the Badger Rotliegend and Carboniferous prospect, and one prior well has been drilled on the acreage, 43/30-1 (1969, BP, 1,100m) which was P&A dry. Spirit Energy exited in January 2018, and remaining partner Atlantic Petroleum UK Ltd (33.333%) also reported in May 2016 that it is withdrawing from the licence.<P /><P />","Andalas Energy and Power has bought a further 10.25% stake in Eagle Gas Ltd for GBPS 225,000 (US$300,000) total consideration (GBPS 125,000 cash, rest in Andalas shares), as announced on 25 July 2018. Andalas now holds 25% of Eagle Gas,"
63130,"Capex has signed with GyP Neuquén for E&P rights to the 128-sq km Parva Negra Oeste area, target Vaca Muerta. Plans include 2D + 3D seismic reprocessing + 1 vertical + 1 horiz explo well.  The signature is the result of ‘Plan Exploratorio Neuquén’ which led to 3 applications in July: Equinor filed for the Aguila Mora Noreste block (73 sq km), Capex for Parva Negra Oeste, and Petrolera San Miguel went for the 50-sq km Neuquén Province’s side of the Catriel Viejo unit.",Capex has signed with GyP Neuquén for E&P rights to the 128-sq km Parva Negra Oeste area.
51408,"In early June 2019 industry sources indicated that Total was awarded the UDO-North exploration block in the deep waters of the MSGBC Basin. The block covers 10,000 sq km and is operated by Total with a 100% interest. The location of the acreage is not yet known but it is assumed that it borders on the Rufisque Offshore Profond (ROP) block also operated by Total.  Following the interpretation of the 3D seismic survey completed in June 2018 by Total, suitable prospects were identified and one of them is now being drilled (see below). The ROP block covers 10,357 sq km and was previously undrilled. The block is located between Kosmos Teranga and Yakaar gas discoveries in the north and Cairn’s FAN-1 oil discovery in the south, in water depths ranging from 100m to 3,000m. It lies on the Upper Cretaceous slope and basin floor fan play fairways and holds a considerable exploration potential. In August 2018, Petronas acquired a 30% stake in the ROP block from Total who remains operator with a 60% interest. Petrosen, the state company has the remaining 10%.     In April 2019 Total spudded the Jamm 1XB new field wildcat well in the ROP block. As of early June, drilling operations were ongoing. The location is in the central part of the northern portion of the block in around 2,000 m of water. Likely targets are Upper Cretaceous turbidite channels/fans on the lower slope. The hydrocarbon type to be expected could be rather oil than gas as the location falls into a compartment of the basin where Cairn made its oil discoveries. This compartment may have a lower geothermal gradient than the adjacent one to the north where Kosmos made several gas discoveries.  The UDO-North block is an area retained by Total from its UDO-TEA which it held from May 2017 to May 2019.  Background information  In May 2017, Total was awarded a 65,000 sq km reconnaissance permit in the ultra-deep offshore of Senegal. The permit, named UDO-TEA, is subdivided in two blocks which cover all territorial waters of Senegal west of currently licensed acreage. The reconnaissance permit is non-exclusive and valid for up to two years.  Earlier in 2017, Total greatly expanded its acreage position in the MSGBC Basin. It used to have only the C-9 block in Mauritania. Then, in quick succession, it added the Rufisque Offshore Profond block in Senegal on 2 May and the C-7 block on 12 May in Mauritania. As of mid-2017, Total operated a total of 27,900 sq km in deep waters of the MSGBC basin.","Total was awarded the UDO-North exploration block in the deep waters of the MSGBC Basin. The block covers 10,000 sq km and is operated by Total with a 100% interest. "
66990,"Further to DEA 28 Oct + 27 Nov '19: L11, onshore Perth Basin, TD 4,170m, gas find, prod. testing gauged up to 46 MMcfg/d on 76/64"" choke for 225 mins, WHP 1,855 psi, from 3,940-3,977m (Kingia sst). Main flow period 35 MMscfd on a 44/64”, WHP 3,466 psi, no evidence of depletion. Well now shut-in ahead of completion for production.   200 sq km if 3D seismic ('Trieste') has started in EP 320 SE of Beharra Springs. Beach (op) partner Mitsui.","Spings Deep-1 expl onshore Perth Basin, TD 4,170m, gas find, prod. testing gauged up to 46 MMcfg/d on 76/64"" choke for 225 mins, WHP 1,855 psi, from 3,940-3,977m (Kingia sst). Main flow period 35 MMscfd on a 44/64”, WHP 3,466 psi, no evidence of depletion. Well now shut-in ahead of completion for production. 200 sq km if 3D seismic ('Trieste') has started in EP 320 SE of Beharra Springs. Beach (op) partner Mitsui."
30759,"Beach Energy Ltd, through its subsidiary company Acer Energy, is looking for a farm-in partner to participate in developing part of its wet gas project, in PRLs 173 and 174 (previously PEL 101), located in the Cooper Eromanga Basin. When the opportunity was first released, Acer was a subsidiary of Drillsearch Energy. Drillsearch and its subsidiary companies are now part of Beach after a merger which was completed on 1 March 2016.   Acer reported that it is looking for a partner that could fund a share of the full development cycle of the wet gas project, actively participate in the joint venture and is commercially and strategically aligned with Drillsearch (now Beach).  Additionally, if interested parties had technical expertise in tight gas drilling operations and have relationships associated with downstream companies that could assist in the sales and marketing of hydrocarbons, these parties were to be given preference in the farm-in selection process.    In late May 2015 Drillsearch reported that it was looking to contract a rig to drill three new exploration wells, which are planned for FY2015, along with commencing a wet gas development plan and contracting a rig for further drilling work in 2016.  Two appraisal and eight development wells will be drilled in the latter period, with a further ten development wells planned for 2017.  Beach plans to explore and appraise the licences, with an aim to achieve commercial wet gas discoveries to supply a wet gas facility, modelled on the nearby Brownlow/Middleton Project. The work programme was planned is in three stages, which would see the more well defined prospects drilled, followed by drilling on the western edge of the acreage. Finally drilling of some of the leads in the north of the block is planned.   The prospects in PRLs 173 and 174 are outlined to have primary targets within the Permian Toolachee, Patchawarra and Epsilon formations and secondary objectives in the Jurassic Birkhead Formation.  There are a number of prospects outlined within the permit, with at least one well required by October 2015 under the current work programme.  The first well is outlined by Drillsearch to be likely to target the Kapok Central prospect, which has P50 recoverable reserves of 23 Bcfg and 0.46 MMbc.  Drillsearch also reports that significant unconventional potential is present within the area.  On 17 February 2015 Drillsearch was granted two retention leases, PRL 173 and PRL 174, over the previously permitted area of PEL 101. As such PEL 101 was relinquished and is now no longer valid.   PEL 101, which covered an area of 154 sq km, was relinquished on 17 February 2015 following the award of two retention leases, PRL 173 and PRL 174. PEL is now no longer valid.  Beach Energy Ltd holds 100% interest and operatorship of both licences, through wholly owned subsidiary Acer Energy Ltd, after joint venture partner Mid Continent Equipment withdrew in September 2018.  Companies interested in pursuing this opportunity should contact:  Janet Skinner, Western and Southern Australia  Tel: +61 8 8338 2833  Email: Janet.Skinner@beachenergy.com.au","Australia, PRL 173"
37139,"Lion Energy announced on 12 December 2018 a conditional sale and purchase agreement for the acquisition of the 16.5% stake owned by Gulf Petroleum Investment Company (GPI) in the Seram (Non-Bula) PSC, located in onshore/offshore Seram island. Upon completion, Lion will have increased its participating stake in the block from 2.5% to 19%, via wholly-owned subsidiary Seram Energy Pte Ltd.  The total purchase price is USD 44 million, subdivided into USD 32 million upfront payment and contingent payments of USD 7.2 million (within four months from Plan of Development approval for the Lofin gas discovery) and USD 4.8 million (within four months from first commercial gas production).  Lion is in discussions to secure funding towards the upfront payment prior to obtaining shareholders’ approval. Completion of the deal is likewise subject to other conditions to be met by 11 December 2019, including customary approvals from Indonesian regulator and PSC partners, as well as Lion providing a corporate guarantee for the contingent payments. Upon completion, the effective date of the transaction will be 1 November 2018.  The proposed transaction will strengthen Lion’s position in the area, as the company was also awarded 100% interest in the East Seram exploration block in May 2018, following Indonesia’s Conventional Oil and Gas Bidding First Round 2018.  The other partners in the Seram (Non-Bula) PSC are CITIC (41%, operator), PT Petro Indo Mandiri (30%) and PT GHJ (10%). The PSC is due to expire on 31 October 2019, however on 31 May 2018 the partners signed a new gross split contract to continue operations in the block for a new 20-year term. Signature bonus for the new contract was USD 1 million. The operator has committed to invest approximately USD 49 million for the first five years of the new contract.  The Lofin discovery is estimated to contain 2 Tcfg in place within Manusela carbonates. The 20-year contract extension is expected to allow for full development of the discovery. Additionally, the block is producing oil from the Oseil and satellite fields, with a rate of approximately 2,000 b/d as of mid-2018.  Background Information    Seram (Non-Bula) PSC History    Located onshore on the Seram island, the Seram PSC was awarded to Gulf and Western Indonesia Inc (G&W) on 1 November 1969 in order to re-habilitate the Bula oil field which had been damaged during World War II. After drilling nine unsuccessful shallow exploration wells and carrying out re-habilitation work and limited development drilling on the Bula field, G&W assigned the PSC to Associated Australian Oilfields NL (AAR) in 1972. AAR shot seismic but did not drill and CSR acquired AAR in 1978. CSR drilled seven exploration wells and undertook development work at Bula.  A Kufpec-led group farmed-in for exploration rights in 1985 but the Bula field, covered by an area of 35 sq km to a sub-sea level of 600m, was excluded from the deal. Kufpec concentrated on the deeper potential of the PSC.  On 11 July 2006, CITIC announced that it had entered in a USD 97.4 million sales purchase agreement to acquire a 51% operating stake in the Seram PSC Extension from operator Kufpec.  In February 2018, CITIC agreed to sell a 10% participating interest to PT GHJ, an independent local company. Later, in Q2 2018, Kufpec divested its interest in the block to another local company, PT Petro Mandiri.  Lofin gas discovery    CITIC suspended Lofin 1 ST1 wildcat as a gas with oil/condensate discovery in mid-December 2012. The well encountered more than 160 m of hydrocarbon column in the Jurassic carbonates of the Manusela Formation. The well flowed at a final rate of 15.7 MMcf/d with 171 bbl/d cumulative oil/condensate (36.1° API). Lofin 1 was spudded on 17 January 2012.  Appraisal well Lofin 2 was spudded on 31 October 2014. The well had initial PTD of 5,425 mMD/5,321 mSSTVD, targeting the Manusela Formation. The well was drilled to a final TD of 5,861 mMD (5,686 mSSTVD). In an attempt to collect good reservoir data, a seven days multi-rate test using different choke sizes was conducted by the operator. The test recorded 17.8 MMcf/d of gas with 2,634 b/d of water and completion fluid and 54 b/d of 34.4º API condensate/oil with a flowing wellhead pressure of 2,250 psi over 96 hours flow period on 52/64” choke. A 12 hours flow period on 16/64” choke was also conducted which has recorded 4.95 MMcf/d of gas with 12 b/d of condensate with 280 b/d of water with wellhead pressure of 5000 psi.  Lofin 2 intersected a total gas column of up to 1,300 m.","Indonesia, Seram (Non-Bula) PSC Extension"
13635,"Shell Integrated Gas Thailand and Thai Energy Company, affiliates of Royal Dutch Shell, have agreed to an asset sale of their 22.2222% interest in the Bongkot field and adjoining acreage offshore Thailand to PTT Exploration & Production (PTTEP) and PTTEP International, a wholly-owned subsidiary of PTTEP, for a transaction value of $750 million. The transaction is expected to complete in the second quarter of 2018, subject to completion conditions as prescribed in the agreement. The agreement is for Shell's stake in Blocks 15, 16 and 17 and Block G12/48. Following the completion of this transaction, PTTEP's stake in Bongkot will increase to 66.6667%, with the remaining 33.3333% owned by Total. PTTEP is the current operator of Bongkot.  Shell's decision to divest remains driven by our strategy to sell non-core assets in order to re-shape Shell into a simpler, more resilient and focused company. This sale takes Shell a step closer to its divestment target of $30 billion.  This announcement has no impact on Shell's other business interests in Thailand. Original article link Source: Shell ","Thailand, not found"
70689,"Mississippi Canyon block 728 (lease G16644), WD 1,581m, P&A'ing non-comm. hc (=dry?) at TD ~6,500m, Valaris 8503 SS off to Kodiak field. Kosmos (op), partner Hess.","MC 728 0003S0B0 (Oldfield) nfw. (Kosmos 40% op, Hess 60%) in lease G16644, WD=1581m, P&A, non-comm. hc at TD ~6500m. The well was drilled to test a sub-salt Miocene prospect."
74964,"In early-2020, local sources reported that state company ENAP has plugged and abandoned its Tiuque 1 new-field wildcat (NFW) well on the Coiron block in December 2019 after production testing in August and September 2019 did not produce positive results. The well reached an undisclosed total depth (TD) in June 2019 after it was spudded in April 2019 with expected investment of USD 7.3 million and objective of unconventional tight gas from the Paleocene-age Zona Glauconitica sandstone. ENAP operates the block with 51%, while US-based ConocoPhillips holds the remaining 49% stake.  Coiron block covers 1,647 sq km of land in Magallanes Basin. The block is situated directly adjacent to GeoPark’s best producing asset, Fell block.  Chilean environmental regulator, SEA, previously granted ENAP the approval to hydraulically fracture Tiuque 1 in January 2019, following an EIA that was originally filed in September 2018.  Background Information  ConocoPhillips signed a farm-in agreement with ENAP for the Coiron block in June 2016 with expected investment of up to USD 100 million over the next four years.","Chile, Fell"
23384,"Perenco in April took over Chevron’s 17.7% interest in the shallow-water No 177 concession (aka DRC Offshore). Perenco operates the 737-sq km Lower Congo Basin block under its Muanda Int'l Oil Co sub now with 67.72%, partner Teikoku.","Perenco took over Chevron’s 17,7% interest in the shallow-water No 177 concession (aka DRC Offshore). Perenco operates the 737-sq km block under its Muanda Int'l Oil Co sub now with 67,72%, partner Teikoku."
15147,"VIM 5 block, Lower Magdalena, 13-day well to TD 2,906m, tested 43 MMcfg/d* on 90/64” choke, FTP 1,008 psi for 41 hours from below 2,551m in the upper part of the Cienaga de Oro sst, 31m net gas pay. Pioneer 302 rig. Previous wells 1 & 2 had tested 29 + 51 MMcfg/d resp. from the CDO. *calculated 168 MMcf/d AOF.","Pandereta-3 tested 43 MMcfg/d* on 90/64” choke, FTP 1,008 psi for 41 hours from below 2,551m in the upper part of the Cienaga de Oro sst, 31m net gas pay."
9439,"Bozhong 29-1-6d (BZ 29-1-6d) was suspended (results TBC) on or around 6 November 2017 after having been spudded on or around 26 October 2017 using the ""Bohai 7"" jack-up. The deviated oil and gas appraisal/exploration well was likely targeting the Guantao, Dongying and Shahejie formations. Bozhong 29-1-6d is in the CNOOC operated Bonan Block in the offshore Bohai Gulf Basin and is approximately 4.4km E of Bozhong 29-1-1.<P />",Not Found
33962,"As of 2 November 2018, Union Cuba-Petróleo (CUPET) announced it has been producing a medium grade crude (22° gravity) oil discovery located northeast of Havana on the northwestern coast of Cuba. The well was identified as the Bacuranao 300L which was drilled to a depth below 2,400 m which is the depth at which the completion was made. No information was released on the specifics of the well other than to say the well has been producing for the last 10 months.  The well is in the North Cuban Province Basin which is where most of the production in Cuba is found however at a shallower depth of between 1,200 m - 1,800 m. Plays in the North Cuban province are characterized by fractured plays, with the Upper Jurassic to Cretaceous carbonates being the major reservoirs, and structural and porosity pinch-out being the dominant traps. Structural traps are generally faulted asymmetric anticlines in thrusts and thrust stacks. Six plays have been established by discoveries by February 2017, among which the Upper Jurassic-Neocomian Fractured Carbonate Stratigraphic-Structural and Middle-Upper Cretaceous Fractured Carbonate Stratigraphic-Structural plays are the most prolific plays containing more than 90% reserves in the basin. Fractured Serpentinite and Paleogene Clastics Stratigraphic-Structural plays are the minor plays in the basin.","Bacuranao 300L (CUPET 100%) in North Cuban Province, an oil find was made perhaps a year ago in NW Cuba, reportedly producing 22° API oil since Dec ’17. No further info."
84978,"On 7 July 2020 Comet Ridge Ltd reported that the Mahalo Gas Project (MGP) has been granted Petroleum Leases (PL) 1082 ""Humboldt"" and 1083 ""Mahalo"" by the Queensland State Government for a term of 30 years. The awarding of the leases, which lie in the northern part of ATP 1191-P, will now allow the project to transition to production.  In early June 2020 Comet reported that the MGP had been granted Queensland State Government environmental approval. This was the second of two approvals required for the gas development to move to production following Commonwealth approval in late May 2020. As a result, the project had fulfilled all federal and state environmental requirements, and all that was required was the issuing of Petroleum Leases from the Queensland State Government. Also reported was that the environmental work for Mahalo North was to begin in the approaching Spring or Summer season.  In late May 2020 Comet reported that the MGP was granted approval under the Commonwealth Government Environment Protection and Biodiversity Conservation Act (EPBC), which was one of two environmental requirements needed for the project to progress to the production phase. The second requirement was under assessment as of reporting by the Queensland State Government Department of Environment and Science.  Previously in late February 2020 Comet reported that it had signed a non-binding Memorandum of Understanding (MoU) with LogiCamms for the development of a >65 km pipeline connection from the Mahalo North field, located in the Bowen Surat Basin. Also included within the agreement was the option to potentially transfer Comet's share of gas from the Mahalo field. It was reported that both parties intended to carry out an evaluation of the technical and economic aspects of a six to eight inch diameter pipeline solution from Mahalo North which would transfer the company's net gas production which was in the range of around 20 to 50 TJ/d into larger pipelines to the south of the field. Under the terms of the MoU activities were to be conducted to get an understanding of debt funding options for both the upstream and pipeline portions of the project.  ATP 1191-P, which covers an area of 2,000 sq km, was awarded on 25 September 2015. Comet Ridge has a 40% interest in the Mahalo Coal Seam Gas project (909 sq km), with joint venture partners Santos QNT Pty Ltd (30% plus operatorship) and Australia Pacific LNG Pty Ltd (30%).  Background Information:    April 2004 - Mahalo discovered        October 2019 - Named Preferred Tender for the PRL2019-1-2 for the Mahalo North Block        June 2020 - Originally planned Final Investment Decision","Australia ((Bowen - Surat B.s)), Comet Ridge Ltd reported that the Mahalo Gas Project (MGP) has been granted Petroleum Leases (PL) 1082 ""Humboldt"" and 1083 ""Mahalo"" by the Queensland State Government for a term of 30 years. The awarding of the leases, which lie in the northern part of ATP 1191-P, will now allow the project to transition to production."
9995,"Tullow has agreed to farmout a 20% interest to UOG in the Walton Morant offshore licence comprising blocks 6, 7, 9, 10, 11, 12, 17, 25, 26, 27, total ab. 32,000 sq km in WD 20-1,000m plus a piece of shallow-water block 1 south of the island, Walton Basin. Plans include some 2,000 sq km of 3D seismic in 1H ’18. The deal is subject to authority approval.  ","Jamaica, Walton Morant"
8812,"Santos has farmed-in to 5 blocks in NW PNG (Papuan Fold Belt) between the Hides and P'nyang gasfields, namely PPL 395, 464, 487, 507 + 545 in which it obtains 20% subject to necessary approvals. Plans include drilling Muruk-2, Barikewa-3 appr’s and Karoma-1 nfw. Santos has also applied for 2 operated licences in the same area. ","Papua New Guinea (Papuan Fold Belt (Papuan B.)) (It's a petroleum rights. Please summarize by yourself). In IHS database: PPL 395 op. by OIL SEAR P (50.0%, EXXONMOBIL 50.0%) to be check."
43366,"1 March 2019, Zarubezhneft (Russia) has reached an agreement with Uzbekneftegaz (UNG) to rehabilitate three mature fields in the Fergana Basin: Alamyshik Janubiy, Hartum and Hartum Sharkiy. This has been announced following a meeting between the head of Zarubezhneft and the President of Uzbekistan who has given his approval to co-operation between Zarubezhneft and UNG.  Zarubezhneft intends to increase the oil production rates at these fields by applying proprietary technology in production management and by utilising state-of-the-art equipment. The parties are planning to establish a joint venture company in the near future.  Background Information  In June 2018, Zarubezhneft and UNG signed a Memorandum of Understanding to study possibilities of co-operation in Uzbekistan’s oil and gas sector. In August, the two companies began a project to study possibilities of improving hydrocarbon production from several mature fields in Uzbekistan’s part of the Fergana Basin. The fields under consideration were Hartum, Boston, Alamyshik Janubiy, Namangan, Tergachi and Shorbulak. Zarubezhneft’s experts held talks with UNG’s Andizhanneft subsidiary operating in Fergana. They discussed the use of electric submersible pumps and improving the efficiency of well repair work.  UNG had in the past signed production improvement and exploration MoUs/agreements for these fields and the surrounding areas with several companies, including Sinopec’s Dong Seng and KNOC. These companies are understood to have quit the projects due to their low economic efficiency.","Zarubezhneft has reached an agreement with Uzbekneftegaz (UNG) to rehabilitate three mature fields: Alamyshik Janubiy, Hartum and Hartum Sharkiy."
81894,"Total sold its 20% In PEDL 273 (194 sq km), PEDL 305 (142 sq km) and PEDL 316 (111 sq km) in Yorkshire (E. Midlands) to optr IGas. This marks Total's exit from UK onshore. Partnership now Island Gas (op), Ineos + Egdon.","United Kingdom, PEDL 316"
53187,"On 1 July 2019 MOL completed the acquisition of a 16% interest from Cairn subsidiary Nautical Petroleum and a 4% interest acquisition from Premier in licences P2070 and P2454. The acreage contains the Laverda discovery and Catcher North accumulation which is planned for development via single well tie-backs to Varadero. Drilling is scheduled to commence in 2020 with first oil targeted for early 2021. As part of the work Premier will also drill an infill well on its Varadero field to target resources out of reach of existing production wells, prior to drilling the Catcher North and Laverda development wells. The company will also shoot a 4D survey across the Catcher Area in Q2 2020 to confirm future infill well locations.   The Catcher Area Development comprises three fields: Catcher, Varadero and Burgman tied back to the BW Catcher Production Storage and Offloading (FPSO). From the FPSO the oil is shuttled by tanker and gas is exported via the gas pipeline tied to the Fulmar A to St Fergus gas Pipeline. Laverda is part of the Catcher Area Development expansion along with Catcher North.   Following completion of the deal interest in P2070 and P2454 is held by Premier Oil UK Limited (5% + operator), Cairn subsidiary Nautical Petroleum Limited (20%), Molgrowest (I) Ltd (20%) and ONE-Dyas E&P Limited (10%).",MOL completed the acquisition of a 16% interest from Cairn subsidiary Nautical Petroleum and a 4% interest acquisition from Premier in licences P2070 and P2454. The acreage contains the Laverda discovery and Catcher North accumulation
84834,"On 3 July 2020, the Ministry of Energy and Mines (MINEM) has given approval to Perupetro to proceed with the award of an exploration and exploitation of hydrocarbons contract in Block Z-67 to Tullow Oil plc. The 5,900 sq km block is locate offshore overlapping the Trujillo, Pacific Coastal, Salaverry, Lima, Yaquina basins off the coast of Santa, and Viru provinces. The block is situated to the west of technical evaluations area (TEA) Area LXXXIII operated by BP Exploration Operating Co. Ltd. Water depths across the block ranges from   According to the decree Block Z-67 consist of a preliminary clause, 23 clauses and 10 annexes, in addition to the intervention of the Central Reserve Bank (BCR) to guarantee the contractor company. There have been no wells drilled in the block to date, the block is however sparsely populated with 2D seismic. The nearest well to the block is located just 7 mi (11 km) from the northern block boundary. That well, the Delfin 1 was drilled by Oxy in 1971 to a total depth of 8,756 ft (2,669 m) in 390 ft (119 m) water depth. The well was P&A dry and reached total depth in basement.  The award comes after an original award of five blocks in 2018 to Tullow was declared unconstitutional based on a lack of consultation with the local fishing community which requires all communities be consulted prior to the award of a contract. Now that Blocks Z-64, Z-67 and Z-68 have been awarded, Tullow continues to negotiate with Perupetro on the remaining two blocks of the five which include Z-65 and Z-66. These remaining two blocks are located in a highly perspective fishing area and are likely going to take longer in the negotiations process with local fishing communities.","Peru (Trujillo B.) Block Z-67 op. by TULLOW (100%), the Ministry of Energy and Mines (MINEM) has given approval to Perupetro to proceed with the award of an exploration and exploitation of hydrocarbons contract in Block Z-67 to Tullow Oil plc. The 5,900 sq km block is locate offshore overlapping the Trujillo, Pacific Coastal, Salaverry, Lima, Yaquina basins off the coast of Santa, and Viru provinces."
12031,"In November 2017 partner Ecopetrol reported the Brahma 1 exploration well located in the in the Tayrona (B) Block of the offshore South Caribbean Deformed Belt encountered non-commercial accumulation of hydrocarbons and was plugged and abandoned (P&A). The well reached a total depth (TD) of some 3,667 m (12,028 ft) on 25 August 2017. With an approximate spud date of 5 July 2017, the Brahma 1 had a proposed total depth (PTD) of some 4,000 m and it was drilled with the “Petrobras 10000” drillship (DS), presumably to appraise the Orca 1 discovery well (2014). Interest holders in the block are operator Petrobras with 40%, Ecopetrol with 30%, Repsol with 20% and Statoil with 10%. Repsol previously held 30% interest, however as of early September 2014 it farmed down 10% interest to Statoil. The 16,500 sq km Tayrona (B) Block is located in water depths of 50 m to 1,500 m. In March 2016, Ecopetrol reported plans for the high-interest Orca appraisal drilling program, initially slated for 2016, hoping offshore Caribbean will give Colombian a “boost” in exploration. On 2 December 2014, Colombia’s first deepwater discovery was announced with Petrobras’s Orca 1 new-field wildcat (NFW). The well is located in the Tayrona Block, and was confirmed as a natural gas discovery. The operator reached a final total depth (TD) of 4,240 m in September 2014 and recent testing indicated natural gas from sandstones at a depth of 3,657 m (12,000 ft). The trap is a large four-way closure, some 460 sq km in size and resource estimates were reported at some 4Tcf of gas. The offshore well was spudded on 4 July 2014 using the “Plataforma Ocean Clipper” rig in 674 m (2,211 ft) of water. It had a proposed total depth (PTD) of 4,775 m targeting the Siamana Formation.  The Orca 1 NFW is located 1.59 km southeast of the Santa Ana 1 well which was plugged and abandoned (P&A) by Mobil Oil Company back in late 1979.The operator planned to spud the well by the end of May 2014, however details were not released regarding the cause of the delay. Orca 1 NFW was originally scheduled for the 2013-2014 drilling program, as previously reported by Petrobras in early March 2012. The Diamond offshore drillship Ocean Clipper arrived in Colombia on 21 June 2014 to drill the well.","Colombia (South Caribbean Deformed Belt) Brahma 1 op. by PETROBRAS (40.0%, ECOPETROL 30.0%, REPSOL 20.0%, STATOIL 10.0%) in Tayrona (B) block"
22436,"On 18 April 2018, Husky Oil farmed out a 27.5% working interest in offshore Jeanne d’Arc Basin exploration license EL 1122 to Suncor Energy. Terms of the transaction were not released. EL 1122 was originally 297.83 sq km when first awarded. Husky relinquished 92.30 sq km of EL 1122 on 12 January 2016, returning roughly the southern third of the block to the government. EL 1122 now contains 205.53 sq km following the relinquishment.  Husky and Statoil were officially awarded EL 1122 effective 15 January 2011. In November 2010, the C-NLOPB announced the preliminarily award of Parcel 2 from the Call for Bids NL10-01 to the two companies for a work commitment bid of CAD 15,150,000. Statoil assigned Husky its 50% interest in EL 1122A and 65% interest in EL 1122C to accomplish the equity transfer, which took effect on 8 December 2015. Husky already had full ownership of the EL 1122B portion of the tract. Having drilled a well within Period 1 of the license’s term, Husky qualified for Period 2 which extended EL 1122 term to its full nine years.","Husky Oil (-> 72,5%) farmed out a 27,5% WI in offshore exploration license EL 1122 to Suncor Energy."
78385,"E. flank of Oseberg in PL 053, TMD 2,852m (2,832m TVD) reached 22 Apr '20. Target M. Jurassic, West Hercules SS. Equinor (op), partners Petoro, Total + COP.","030/06-31 S (Helleneset) expl E. flank of Oseberg in PL 053, TMD=2,852m. Target M. Jurassic, Equinor 49,3% (op),  Petoro 33,6%, Total 14,7%+ COP 2,4%). Results n/a yet."
37654,"PetroChina – Xinjiang made a new oil discovery in the Junggar Basin on 15 December 2018. Shatan 1, a NFW, tested 215 b/d of oil from 5,344 to 5,375 m in the Permian Wuerhe Formation.   Shatan 1 is drilled in the Shawan Sag, southwest of the basin. The well also encountered good oil shows in other formations during drilling, such as Triassic Baikouquan and Karamay formations.   There are only a few small fields around this area with main reservoir in the Jurassic Sangonghe formation. The success of the well indicated a new exploration potential prospective area for the Wuerhe play fairway.        According to current understanding, The Shawan Sag, geologically, is very similar to the Mahu Sag where PetroChina has approved a giant field. It is expected to find another similar size of field in the Shawan Sag area.   Background Information  PetroChina started Exploration activity in the Mahu area in 1993 and found Mabei field when Ma 2 tested oil from the Permian in the same year. However, there is no further significant exploration success achieved in this area until 2012.   In 2012, PetroChina made a breakthrough in the Mahu Sag. Ma 131 tested 73 bo/d after fracture, from the Baikouquan Formation of the Triassic. Following Mahu 18 tested 347 bo/d and 247 Mscfg/d from the same reservoir, which confirmed and made expansion of the discovery.   In 2013, PetroChina tested oil in Mahu 1, flowing about 400 b/d in the Baikouquan formation of the Triassic. Mahu 1, a new field wildcat, was drilled in the south slope of the Mahu sag.   In 2014, Ma 19 tested 117 bo/d and 265 Mscfg/d from the Baikouquan Formation, which indicated a great potential of the Baikouquan reservoir in the Mahu area.   Furthermore in 2014, PetroChina made a discovery in Aihu 1 in this area and tested 191 bo/d and 78 Mscfg/d from Baikouquan Formation. The discovery indicated a sweet box between Ma 18 and Aihu 1. And the following wells in this area also made success, such as Aihu 011, Aihu 013 and Aihu 6.   In December 2014 PetroChina reported Mahu field discovery. The field, located in the west slope of the Mahu Sag, had defined 1.4 bn barrels of 3P oil in place within a 100 sq km area. In addition, the company had identified a 2,800 sq km play fairway in the Mahu area with potential of more than 7 bn barrels of in place oil resource.   In 2015 PetroChina started a pilot production project and planned to build the field with 50,000 bo/d capacity.  In 2016 Mahu 8 achieved commercial oil in the Upper Permian Wurhe Formation in Mahu 1 area in the south slope of the Mahu Sag, the following Mahu 11 and Mahu 15 also tested oil from the same reservoir, which approved the Wurhe reservoir in the Mahu field.    PetroChina continued to achieve exploration success around the Mahu Sag, not only in the west slope of the sag but in the east slope. By 2016 the company has made Mahu field extension in the following areas:  Ma 18 and Ma 131 pilot production area, Fengnan 4 and Aihu 2 appraisal drilling area and Da 13 new finding area.   In November 2017 PetroChina reported to has defined up to 9 bn bbl of 3P oil in place in the Mahu field in the Junggar Basin, among of which 3.7 bn bbl of proven oil in place has been confirmed. The main reservoir of the field is conglomerates in the Triassic Baikouquan Formation.   In 2018 PetroChina made breakthrough in shallow reservoir in Mahu Field. Mahu 18, one of the field discovery well, tested 670 Mcf/d of gas plus 24 b/d of oil in the Jurassic Sangonghe Formation, Mahu 015, an appraisal well, tested 2,880 b/d of oil plus 1.3 MMcf/d of gas in the Jurassic Badaowan Formation, which indicated great potential in middle-shallow depth reservoir formations in Mahu field apart from the Permian Wuerhe and Triassic Baikouquan formations.   In 2018 PetroChina is expected to produce 0.95 million tons of oil (19,000 b/d) in the Mahu field. It has been planned the field will reach 60,000 b/d of oil by 2021 and 100,000 b/d by 2025.","Shatan 1 (PetroChina – Xinjiang 100%) new oil discovery in the Shawan Sag, tested 215 b/d of oil from 5344 to 5375 m in the Permian Wuerhe Fm."
38375,"On 20 December 2018, the Bureau of Ocean Energy Management (BOEM) approved BP Exploration & Production Inc. as the designated operator and sole owner of the Tiber and Guadalupe units, two appraised deepwater Wilcox oil discoveries that are being groomed for potential development. Former operator Chevron U.S.A. Inc. announced its decision to withdraw from these Tigris area projects in September 2018. Before Chevron’s departure, the acreage in this venture had been jointly owned by Chevron (50%) and BP (50%).  The Tigris project area resides in the northwest Keathley Canyon area in the deepwater Western Gulf of Mexico, about 175 miles (280 km) southeast of Galveston, Texas. Tigris contains three Wilcox discoveries that lie in over 4,000 ft (1,219 m) of water: Tiber, Guadalupe, and Gibson. Appraisal activities concluded for Tiber and Guadalupe in 2017 while under Chevron’s auspices. The leases in both Tiber and Guadalupe have passed their scheduled expiry dates and are held for now by unit suspensions of production (SOP). Chevron had been progressing pre-feed and conceptual work was underway to develop these three accumulations as a multi-field tieback to a new central host facility. The Gibson lease has a November 2019 expected expiry date and is still jointly owned, according to BOEM records.  It remains to be seen if BP moves forward with these potential developments and it has a limited window in which to act. In order to maintain the SOP, BP must demonstrate to government regulators a reasonable schedule of development activity that will lead to the commencement of production. Failure to meet the proposed schedule could lead to the termination of the SOP and the leases. BP is already appealing the government’s termination of its Kaskida unit and its leases after BP’s request for a unit suspension of operations was denied. BP made the Kaskida discovery in 2006. This Wilcox oil find is also located in Keathley Canyon about 50 miles (80 km) southeast of the Tigris area.  Background Information  The nine-lease Tiber unit (Contract No. 754315003) consists of contiguous Keathley Canyon blocks 57 (G25777), 58 (G30910), 59 (G30911), 101 (G25781), 102 (G25782), 103 (G30917), 146 (G33006), 147 (G30926) and 148 (G30927). The Guadalupe unit (Contract No. 754317002) contains two leases over adjacent Keathley Canyon blocks 9 (G27697) and 10 (G27698).","BP Exploration & Production Inc. as the designated operator and sole owner of the Tiber and Guadalupe units, two appraised deepwater Wilcox oil discoveries that are being groomed for potential development. Former operator Chevron U.S.A. Inc. announced its decision to withdraw from these Tigris area projects in September 2018. Before Chevron’s departure, the acreage in this venture had been jointly owned by Chevron (50%) and BP (50%). "
9507,"Partner Ecopetrol confirmed in November 2017 that the Bullerengue Sur-3 appraisal well was abandoned on the Sinu-San Jacinto Basin SSJN-1 Block after failing to find any commercial quantities of hydrocarbons. The well was drilled in Q3 2017 to appraise the Bullerengue Sur-1 NFW. Operator Lewis Energy discovered gas in the Bullerengue Sur-1 NFW in the SSJN-1 Block (Sinu-San Jacinto Basin), in December 2016. The well was drilled between 18 November 2016 and 7 December 2016 on schedule and below the expected cost. The well is located 30km from Barranquilla and verified the southern extent of the Bullerengue oil and gas field, which was discovered with the Bullerengue-1 well in 2015. The presence of natural gas in an additional, shallower interval has also been proven. Around 25m of natural gas intervals were intercepted of Eocene age. Ecopetrol President, Juan Carlos Echeverry, said, ""Bullerengue adds to the successes we have had with Orca and Kronos in the last two years in the Colombian Caribbean, where we currently drill two other wells with Anadarko"". Operator Lewis Energy (50% WI) and partner Hocol (subsidiary of Ecopetrol) (50%) were awarded the 1,680 sq km license in the Ronda Colombia 2008 bid round.","Colombia, SSJN 1"
31224,"Marathon has emnbarked on the sale process of its UK offshore assets in order to focus on the US shale sector. Offers ae due in Dec ’18, a price tag of perhaps USD 200 MM suggested. Assets include an interest in the Foinaven (28%) + Foinaven East (47%) field + 40% in the Brae complex, as well as some 15,000 boe/d.","Marathon has emnbarked on the sale process of its UK offshore assets in order to focus on the US shale sector. Offers ae due in Dec ’18, a price tag of perhaps USD 200 MM suggested. Assets include an interest in the Foinaven (28%) + Foinaven East (47%) field + 40% in the Brae complex, as well as some 15,000 boe/d."
47769,"Petroandina, related to Pluspetrol, has reportedly acquired Eni’s local unit Agip Oil Ecuador.  Agip Oil has had a risk service agreement with Petroamazonas for block 10 (Oglan + Villano fields) in the Napo Basin since 2010. The move may be related to Eni’s inability to convert from risk service to participation contract.","Petroandina Resources Corp, part of the Grupo Pluspetrol, has acquired Agip Oil Ecuador (part of ENI) stocks. Involved is Block 10, located in the (ENI has reported estimated 2P reserves of 300 MMb of heavy oil in place for the Oglan Field)."
14659,"In early February 2018, Anadarko indicated that it is in the process of divesting its remaining Alaska assets for a total sum of ~$400 million. ConocoPhillips will acquire Anadarko's 22% non-operated interest in the Western North Slope of Alaska and Anadarko's interest in the Alpine pipeline. In 2017, the assets' gross daily production totalled 63,000 boe/d. With the deal, ConocoPhillips will have 100% in about ~4,850 sq km (~1.2 million acres) of exploration and development land and is expected to receive a ~14,000 boe/d net increase in net oil production when the deal closes. The deal remains subject to regulatory approval. Anadarko arrived in the state in 1993, when it saw the potential for major oil finds in the region. Its first venture was as a working interest owner in the Exxon-operated Thetis Island exploration drilling program in the Beaufort Sea (west of Oliktok Point). Oil was subsequently encountered in the prospect, and Anadarko took over the project in 1997 as operator.  In 1994, Anadarko, alongside ARCO Alaska (subsequently ConocoPhillips Alaska), discovered the Alpine oil field, located in the western North Slope. Alpine was declared a commercial discovery in 1996 and later went into production, with ARCO as operator and Anadarko as an equity holder. In recent years, Anadarko has appeared to have switched its focus to shale oil and gas in the Lower 48 states and, as a result, Anadarko's Alaska lease holdings have diminished, with the company retaining just its ownership interests in leases it has held jointly with ConocoPhillips, prior to Anadarko's recently announced divestment.",Anadarko indicated that it is in the process of divesting its remaining Alaska assets for a total sum of ~$400 million. ConocoPhillips will acquire Anadarko's 22% non-operated interest in the Western North Slope of Alaska and Anadarko's interest
9743,"Effective 1 October 2017 Hilcorp Alaska LLC was officially awarded 14 tracts covering about 76,682 acres (310 sq km) off Alaska’s south-central coast from the Cook Inlet Lease Sale 244 held by the Bureau of Ocean Energy Management (BOEM) on 21 June 2017. The company placed high bids in the amount of USD 3,034,815 and was the sale’s lone bidder. Sale 244 was the thirteenth and final OCS lease sale held under the 2012-2017 Five-Year Program. It offered some 1.09 million acres (4,410 sq km) for leasing and consisted of 224 blocks that stretched roughly from Kalgin Island in the north to Augustine Island in the south.  Each bid went through a 90-day evaluation process to ensure the public received fair market value before a lease was awarded. All materials and statistics for Lease Sale 244 are available at: http://www.boem.gov/ak244. Hilcorp Official Awards               Contract Company Name WI Bonus USD Acre Sqkm Lease Sale Award Date Basin   Y02434 Hilcorp Alaska 100 $62,208.00  5,184.26 20.98 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02435 Hilcorp Alaska 100 $37,416.00  3,118.47 12.62 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02436 Hilcorp Alaska 100 $68,376.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02437 Hilcorp Alaska 100 $142,500.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Y02438 Hilcorp Alaska 100 $111,606.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02439 Hilcorp Alaska 100 $313,500.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02440 Hilcorp Alaska 100 $474,582.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02441 Hilcorp Alaska 100 $203,319.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02442 Hilcorp Alaska 100 $111,606.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Y02443 Hilcorp Alaska 100 $256,500.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02444 Hilcorp Alaska 100 $474,582.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Y02445 Hilcorp Alaska 100 $474,582.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02446 Hilcorp Alaska 100 $152,019.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02447 Hilcorp Alaska 100 $152,019.00  5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Totals     $3,034,815.00  76,681.62 310.32         Source: IHS Markit               ©   2017 IHS  ","United States, Y02440"
33428,"Petro-Victory is acquiring a 50% interest in 5 yet-undisclosed onshore explo blocks in the Espirito Santo Basin from Imetame for ab. USD 440,000. Imetame will remain operator. This deal tags onto last month’s (DEA 5 Sep) acquisition of 4 onshore oilfields from Empresa de Engenharia de Petróleo for USD 1.6 MM, namely Andorinha + Alto Alegre in the Potiguar Basin (100%), Carapitanga in the Sergipe-Alagoas Basin (50% non-op) and São João in the Barreirinhas Basin (50% non-op). All deals require ANP approval.","Brazil, Alto Alegre"
68743,"The Federal Bosnian govt has published the relevant documentation required to proceed with applications in its 1st o&g licensing round, opened in September (DEA 10 Sep ’19). This features bid documents, the petroleum code, fiscal data and data room details, all available here (in both languages). Any questions related to these bidding instructions (including requests for clarification + amendments) may be sent to the oil ministry ( oil.gas@fmeri.gov.ba) or to BiHLicensingQueries@ihsmarkit.com.  Bids are invited between 1 Oct ’19 – 27 May ’20. Four blocks are available: 3 in the Pannonian Basin (BiHPo1, BiHPo2 + BiHTz), 1 in the Dinarides (BiHD1) as per the map below.","The Federal Bosnian govt has published the relevant documentation required to proceed with applications in its 1st o&g licensing round, opened in September (DEA 10 Sep ’19). This features bid documents, the petroleum code, fiscal data and data room details, all available here (in both languages)."
37221,"On 9 December 2018, it was announced that Turkiye Petrolleri A.O. (TPAO) had been awarded a new exploration licence, P34-B, on 30 November 2018. The licence covers an area of approximately 494 sq km in the Iskenderun Basin and is valid for eight years. TPAO had filed an application for the licence on 17 April 2018. It will be 100% owner and operator of the licence.","Turkey, P35-B"
67064,"On 17 October 2019, the Chinese Government officially announced the preferer tenderers for the 2019 Shanxi Province CBM Bid Round, following an earlier announcement on 19 July 2019 that 5 of the 10 blocks had received qualifying bids. On 9 May 2019, the Chinese Government offered 10 CBM exploration blocks for the 2019 Shanxi Province CBM Bid Round. The awarded tender blocks have an initial exploration period of three years and three months. The minimum annual investment on each block is not lesser than RMB 30,000 (~US$ 4,400) per sq km. The tender closed on 17 July 2019. The tender blocks are:->Block Name Size->West Hongtong Block 283.11 sq km (No bid)->Hongtong Block 278.21 sq km (No bid)->Linfen Block 215.7 sq km (No bid)->West Linfen Block 284.84 sq km (No bid)->South Linfen Block 299.85 sq km (No bid)->Fushan Block 278.16 sq km (Awarded to Shanxi Juyuan Coal Chemical Co Ltd)->South Guxian Block 226.11 sq km (Awarded to Shanxi Anxi Coal Industry Co Ltd)->East HeshunMafang Block 253.82 sq km (Awarded to Shanxi Blue Flame Coalbed Methane Group Co Ltd)->Xiyangzhanshang Block 266.85 sq km (Awarded to Shanxi Pingyao Fengyan Coal Group Co Ltd)->East HeshunHengling Block 137.62 sq km (Awarded to Shanxi Pingyao Coal Chemical Group Co Ltd)<P /><P />","On 17 October 2019, the Chinese Government officially announced the preferer tenderers for the 2019 Shanxi Province CBM Bid Round, following an earlier announcement on 19 July 2019 that 5 of the 10 blocks had received qualifying bids."
56775,"Pertamina EP has probably plugged and abandoned its exploration well Marlin 1 (MRL-1) as a dry hole, in the Tanjung 1 PPC, located onshore in the Barito Basin, around mid-August 2019. The well has penetrated six reservoir intervals within the target of the Lower Tanjung Formation. Sources indicated that DST conducted on the well has produced only water. Gas chromatography showed a gas peak at a coal marker.  Marlin 1 reached a total depth of around 1,840 m MD, shallower than the planned total depth of 1,878 m MD. The well was drilled using Pertamina Drilling Services Indonesia (PDSI) rig # 01.2/N80B Rig M, with initial estimated operation of 118 days. The well was initially reported to hold potential oil resources estimated at around 45 MMbbl.    According to Pertamina, exploration drilling cost for the planned campaign could be up to approximately USD 15 million. The company is reportedly planning to drill an additional well in the block in 2020.  The Marlin prospect may have been defined from a 3D seismic survey acquired between late 2013 and early 2014, covering 234 sq km and acquired by PT Daqing Citra. Primary exploration objective within the block are sandstones of the Eocene Tanjung Formation, which is already proven as a hydrocarbon producer within the surrounding fields.  The block contains mature oil fields such as Kambitin, Tanjung, Tapian Timur, Warukin Selatan and Warukin Tengah.  Pertamina commenced a polymer Enhanced Oil Recovery (EOR) project in the Tanjung field on 20 December 2018. The purpose of the project is to extract additional oil from the maturing field, which cannot be obtained using the primary and secondary (water or gas injection) recovery method.  In March 2018, local media reported that Pertamina was planning to carry out a development drilling campaign with around eight wells in the block, likely in 2H 2018. The wells would have a PTD between 650 m and 2,000 m. The two deepest wells would target new potential reservoir zones in the Warukin Formation sandstones, between the depths of 1,000 m and 2,000 m. The company also reportedly was planning to carry out workover for wells in the Warukin and Kambitin fields, targeting the sandstone reservoirs of Tanjung and Warukin formations, at the depths of 600 m to 900 m.  Pertamina completed a 300 km 2D seismic survey in the block around early April 2016. Acquisition commenced in early September 2015. The survey might have covered the northern portion of the block in which the primary exploration target is the Warukin Formation.  The block is operated by Pertamina with 100% ownership.  Background Information  Eight unsuccessful exploratory wells were drilled by BPM and NKPM within the central, northwest portion and southeast portion of the block from 1935 to 1940. Kuripan 1 wildcat was drilled by NKPM in the central portion of the block in 1940 and three wells drilled on the northwestern portion of the block by BPM from 1934 to 1935 are Mengkatip 1, Mengkatip 2 and Mengkatip 3. Four dry wells (Barito 09, Barito 13, Amuntai 09 and Amuntai 10) were drilled by BPM in 1935 within the northeastern portion of the block.   The EOR project originally covered the Kambitin, Tanjung, Tapian Timur, Warukin Selatan and Warukin Tengah oil fields, previously developed pre-WWII and by Pertamina in the 1960s and 1970s. Pilot projects were carried out at Warukin and Tanjung in the early 1990s but only the EOR project at the Tanjung field proved economically viable and the remaining fields reverted to Pertamina operatorship. Tanjung was the site of a waterflood project which commenced in 1995.   At end 2000, production stood at about 6,900 bbl/d of oil, this improving to over 7,200 bbl/d of oil by mid-2002 but decreasing slightly to about 7,050 bbl/d of oil by mid-2003. The latest official production data available is from December 2003, when output averaged 6,432 bbl/d of oil.  On 11 November 2004, the Tanjung Raya Fields EOR expired after its contracted 15-year lifespan. Pertamina/Talisman JOB was believed to have applied for an extension to the contract but the area was absorbed into PT Pertamina's UEP IV East Kalimantan operating area. Awarded to the Pertamina/Southern Cross (Tanjung) Ltd JOB on 11 November 1989 upon payment of signature bonuses totalling USD 2.5 million, the EOR carried a six-year work commitment of USD 117.9 million. Bow Valley acquired Southern Cross in June 1991 and, in turn, was taken over by fellow Canadian independent Talisman in August 1994.  On 22 May 2007, China PetroTech announced that it had signed a joint study agreement with PT Pertamina EP to explore the use of various Enhanced Oil Recovery (EOR) technologies to optimise production at Pertamina’s existing mature oil fields. The study area covered the Tapian Timur and Dahor fields in the Tanjung I PPC in South Kalimantan. The first phase of the 6-9 months of the study will involve the collection of various field data, geological and geophysical studies and engineering study. Subjected to the approval of BPMigas, the second phase will encompass field engineering and field pilot projects before implementation of a full EOR programme.   Pertamina conducted a 171 km of 2D seismic survey over the Tapian Timur area. This survey was carried out from late August to late October 2010 by PT Daqing.  Wildcat Piraiba 1 was completed in early June 2015, after testing oil and gas. The well was drilled to a total depth of 2,000 m and was spudded on 13 March 2015, targeting the Warukin Formation sandstone.","Marlin 1 (MRL-1) (Pertamina EP 100%) in the Tanjung 1 PPC, has probably P&A as a dry hole, the well has penetrated 6 reservoir intervals within the target of the Lower Tanjung Fm. Sources indicated that DST conducted on the well has produced only water."
55031,"Wintershall Dea has agreed to farmout some interests to ConocoPhillips in the Aguada Federal + Bandurria Norte blocks, Neuquén Basin, aiming for a joint pooling of expertise in devt: both blocks are home to Vaca Muerta shale resources.  Wintershall Dea retains operatorship and 45% in the 97-sq km Aguada Federal (partner GyPNeuquén 10%), and 50% in Bandurria Norte (105 sq km):","Argentina, Aguada Federal"
58491,"It is understood that MontD’or continued to offer a farm-in opportunity in the Tungkal PSC, located in onshore South Sumatra, in September 2019. The block contains three producing fields, Mengoepeh, Mengoepeh South and Pematang Lantih.  The company is conducting a development drilling campaign in the block, with two wells completed in the Pematang Lantih field in late 2018. Further drilling is planned in the Pematang Lantih and Mengoepeh fields, possibly in late 2019 to 2020. The operator is likewise assessing the remaining prospectivity in the block, based on the available seismic and new well data.  The block produced approximately 1,200 bo/d in Q1 2019.  MontD’or operates the Tungkal PSC with 100% interest, of which 30% is held by MontD’or’s affiliated company Fuel-X Tungkal. The PSC is due to expire in August 2022. In November 2018, a new 20-year contract was awarded to the same operator under gross split fiscal terms.  A farm-in opportunity in the block was previously offered in 2016.  Background Information    The 9,155 sq km Tungkal PSC was originally awarded to Asamera on 26 August 1992 upon payment of bonuses totaling USD 1.5 million. The PSC carried a work obligation of USD 9.167 million in three years, USD 21.137 million in six years and USD 32.357 million in 10 years. Two 25% partial relinquishments in November 1995 and August 1998 reduced the block area to 4,577 sq km. In May 1993, Freeport McMoran Inc farmed in for 40% but withdrew in August 1996. Asamera was re-named Gulf Resources in 1997.  Asamera acquired a 278 km 2D survey between November 1992 and February 1993 and a 1,074 km 2D survey between July 1993 and January 1994. Asamera drilled Kilis 1 (dry) in July 1994 and Lingir 1 (dry) in August 1994. In 1995 a further 409 km of 2D data was acquired and followed in late 1996 by a five well programme that lasted until October 1997. The first well, Mengoepeh 1, resulted in an oil and gas discovery (maximum 1,296 bo/d plus 3.269 MMcf/d from an unnamed formation). This was followed by wildcat Seling 1 (dry), delineation wells Mengoepeh 2 (oil shows) and Mengoepeh 3 (dry), and wildcat Rasa 1 (dry).  First production from the Mengoepeh field took place in December 2004 at 300 bo/d from one well, Mengoepeh 7. In early 2005, production stood at 1,200 bo/d from four wells Mengoepeh 7, 8, 9 and 11. Produced oil was transported to the Plaju refinery at Palembang.  The Pematang Lantih field was discovered in December 2014 from wildcat Pematang Lantih 3. MontD’or completed at least four DSTs in the Talang Akar Formation, recording oil flow. The well was spudded in mid-September 2014 and reached a TD of 1,425 m on 2 October 2014. Pematang Lantih 3 was targeting oil within sandstone reservoirs of the Upper Oligocene to Lower Miocene Talang Akar Formation. The well was put on production in July 2015. The prospect, located in the Pematang Lantih anticlinorium, was originally drilled in the late 1930s by BPM, with two unsuccessful wells.  The last reported exploration activity in the block was the drilling of the Pematang Lantih 4 appraisal well in late 2015. The well was spudded on 19 September 2015 and it had a PTD of around 1,450 m, primarily targeting the Talang Akar sandstones.    The Pematang Lantih field was initially brought onstream in July 2015 via Put on Production (POP) scheme of discovery well Pematang Lantih 3. Production rate from the well was reported at around 1,300 bo/d.  In May 2016, MontD’or reported that the combined production from the Mengoepeh, Mengoepeh South and Pematang Lantih fields was around 1,500 to 1,700 bo/d during the first half of the year.    A full Plan of Development (POD) for Pematang Lantih was approved in 2017, involving the drilling of two new development wells (Pematang Lantih 8 and 9). A Plan of Further Development (POFD) is believed to have been approved in mid-2018, calling for additional development drilling in the field.","It is understood that MontD’or continued to offer a farm-in opportunity in the Tungkal PSC, located in onshore South Sumatra, in September 2019. The block contains three producing fields, Mengoepeh, Mengoepeh South and Pematang Lantih."
68334,"ND-4, ultra-deepwater NW Sabah Platform, P&A results n/a around 19 Dec '19, West Capella DS. Target L. Oligocene clastics. The wholly-owned block is open for farmin.","Nuri 1 nfw. (Petronas 100%) in ND-4, ultra-deepwater NW Sabah Platform, P&A results n/a. Target L. Oligocene clastics. The wholly-owned block is open for farmin."
57420,"On 27 August 2019, Italian operator Eni SpA through its Nigerian subsidiary Nigeria Agip Oil Company Ltd (NAOC) reported that it made a significant gas and condensate discovery in the Obiafu SW Deep 4 exploratory well (also known as Obiafu 41 Deep), onshore OML 61. The company reached a total drilled depth of 4,374 m, encountering 130 m of high-quality hydrocarbon-bearing Oligocene deltaic sands. NAOC estimates the find to hold about 1 Tcf of gas and 60 MMbbl of associated condensate, which could be produced soon using the existing infrastructure, at a rate of 100 MMcf/d of gas and 3,000 b/d of condensate.  NAOC reached the drilling depth of 4,000 m in late May 2019 and no progress was made in June, while NAOC had set a planned TD for Obiafu SW Deep 4 around 4,600 m, targeting deeper gas horizons. The well was spudded on 15 March 2019 as a sidetrack from the existing Obiafu 41 development well. The company used the HP/HT “Hilong-27” land rig that Shell (SPDC) yet mobilized in 1H 2018 to drill a similar high-impact well in nearby OML 28. NAOC has selected several similar projects in its onshore acreage.  The onshore Obiafu-Obrikom field was discovered in 1967 and came on-stream in 1973. It had initially recoverable 2P reserves of 340 MMbbl of oil of which 75% has already been produced to date. Participants in OML 61 are Eni (NAOC) 20% operator, Oando Energy Resources (OER) 20% and NNPC 60%.","Obiafu 41 deep well (NAOC 100% = Eni 20% op. NNPC 60%, Nigerian independent 20%) in OML61 block, hit more than 130m of high quality hydrocarbon-bearing sands. “The find amounts to about 1 Tcf of gas and 60 MMb of associated condensate in the deep drilled, Oligocene sequences,” Eni said. According to the operator, the well can deliver in excess of 100 MMscf/d of gas and 3000 b/d of associated condensates, on stream immediately. TD=4374m. "
49247,"Lukoil secured sole 8-year rights to the 1,170-sq km Tazovskiy Zapadnyy block in the Yamal-Nenets AO under licence SLKh02575NP.  The award is the result of a Dec ’18 auction to which no applicants turned-up.",Lukoil secured sole 8-year rights to the Tazovskiy Zapadnyy block (1170km²) in the Yamal-Nenets AO under licence SLKh02575NP.
35670,"Megiddo-Jezreel (401) licence in NE Israel, TD 5,060m, testing programme completed and despite some 90-110 bo/d flowing from between 5,003-5,019m, the well is deemed non-commercial and will be P&A’d. Daflog F-400 rig.","Israel, not found"
72370,"Barakat Deep discovery area, Khalda Offset (New) A-West block, Northern Egypt Basin, TD 4,420m (Shifah D unit), susp w.o. test, EDC rig 54. Target Burg El Arab.","Barakat Deep-2 appr Barakat Deep discovery area, Khalda Offset (New) A-West block, Northern Egypt Basin, TD 4,420m (Shifah D unit), susp w.o. test, "
38206,"Magyar Olaj- es Gazipari Rt (MOL) was selected by the Ministry of Innovation and Technology as the bid winner of the Szeged DélKelet area in southeastern Hungary, offered during the 2018 tender call that closed in end-October. The pre-award of the block to MOL was pronounced on 5 December 2018. The company has now 90 days (with a possible extension for further 60 days) to negotiate the contract - the final award is expected in early 2019.  The 278 sq km Szeged DélKelet area is located within the Nagykunsag, Bihor and Bekes sub-basins, tectonic units of the Pannonian Basin.  Background Information    The tender call for the Szeged DélKelet block was published in the EU Official Journal on 21 June 2018. The closing date of the tender was 26 September 2018.  The country’s first bid round was pronounced in 2013 and had little success (two awards). Following modifications to the legal and fiscal terms, the tenders conducted in 2014, 2015, 2016 and 2017 attracted significant attention and resulted with the awards of 17 new concessions (awards from the 2017 round were effectuated in January/February 2018). As during the period 2013-17, the opening of the 2018 round was expected in late May/June 2018, with nine areas offered for the hydrocarbon operations and one to two blocks for the hydrothermal energy.  In preparation for the licensing rounds, until late 2018, the authorities have earmarked some 35 open areas in the western, central, eastern and northeastern part of the country. As during the period 2013-18, the opening of the next round is expected in late May/June 2019, with some nine areas to be offered for the hydrocarbon operations and one to two blocks for the hydrothermal energy. The tender documents, published in the EU Official Journal, mark the onset of the bid round.",MOL (100%) was awarded Szeged DélKelet area in southeastern Hungary
72321,"In January 2020, Perenco Exploration & Production Congo Ltd's (Perenco) Production sharing Contract for the Marine XXVII block was approved. The 565 sq km area sits atop the shelf within the Lower Congo Basin. It plays host to the 2011 Nkaba 1 oil and gas discovery and the 1985 Boatou Marine 1 oil discovery. Nkaba 1 is estimated to hold some 22 MMbo and 27,500 MMscf gas. Boatou Marine 1 is estimated to hold some 10 MMbo.   The effective date for the start of the of the PSC was January 2019.  Perenco operates the block with a 75% interest, Societe Nationale des Petroles du Congo holds the remaining 25% stake.   Background information   Perenco’s bid for the block was opened on 29 March 2017. On 21 November 2018, the Council of Ministers met and agreed to award the XXVII exploration licence to SNPC and Perenco.  (it was previously though that the split was 85% Perenco and 15% SNPC however, this was incorrect).   The licence was awarded for a period of two years and in non-renewable.",Perenco Exploration & Production Congo Ltd's (Perenco) Production sharing Contract for the Marine XXVII block was approved. The 565 sq km area sits atop the shelf within the Lower Congo Basin.
53303,"PL 502, SW of Johan Sverdrup in the Viking Graben, TD 2,028m, abandoned on 12 Jul ’19, results expected soon, Transocean Spitsbergen SS. Equinor (op), Petoro + Aker BP.","016/05-07 (Klaff) nfw (Equinor 44,44% op, Petoro 33,33%, Aker BP 22,22%) in PL 502, SW of Johan Sverdrup, P&A, results expected soon. TD=2028m."
59906,"Jianshan structure, W. Qaidam Basin, ops terminated Sep '19, results n/a. This was the 1st deep explo well in this area, PTD 5,800m, target basement gas.","China, not found"
42659,"HitecVision, owner of Verus Petroleum, is reportedly looking to sell the company according to press. Some USD 500 MM could be netted from a string of assets, particularly after Verus had announced in Sep ’18 an agreement to acquire from Itochu its subsidiary Cieco E&P for USD 400 MM in a cash-and-share deal. This includes a 23.1% interest in the Western Isles devt project (Harris + Barra oilfields), 25.8% in the Hudson field, 2% in the Brent pipeline system, and 1.2% in the Sullom Voe terminal. Verus also recently took on an interest in the Chevron-run Alba field as well as Babbage, inter alia. Neither company has confirmed of commented.","United Kingdom, Babbage"
27269,"AziNor Catalyst is offering the opportunity to farm-in to licence P2165 (block 16/8c) which contains the ‘Boaz’ prospect. The company holds 100% interest in the licence after acquiring MOL’s 51% in the licence in 2017. Azinor is looking for a carry on an exploration well in return for a significant portion of its interest. AziNor has calculated that the prospect has gross Pmean recoverable resources of 242 MMboe with a P10 of 544 MMboe. P2165 was awarded in February 2015 during the 28th Licensing Round. A drill or drop decision is required by January 2019. In August 2018 it is understood that the opportunity is still available.  Boaz consists of a large untested Triassic fault-bound structural closure. An exploration well is planned to target the Triassic Skagerrak Formation sands of the prospect to a depth of 4,700 m TVDSS. The Skagerrak Formation comprises thick and well developed alluvial and braid plain deposits which have been proven by numerous well penetrations in the adjacent Norwegian acreage to the east of the block. A new 3D Geostreamer seismic survey is said to show a significant improvement in data quality with initial reviews showing a brightening associated with the structure and possible flat spot which correlate to initial rock physics and amplitude modelling. AziNor are looking to farm down material equity of between 50-75% on a promoted basis.   Interest in P2165 is held solely by AziNor Catalyst Ltd (100%).  For further information please contact:  Nick Terrell  +44 (0)20 3588 0065  nick.terrell@azinorpetroleum.com",AziNor Catalyst is offering the opportunity to farm-in to licence P2165 (block 16/8c) which contains the ‘Boaz’ prospect. The company holds 100% interest in the licence after acquiring MOL’s 51% in the licence in 2017. Azinor is looking for a carry on an exploration well in return for a significant portion of its interest
31101,"Tullow has signed for 30-year PSC rights to offshore block 62 on 2 Oct ‘18, adding to its existing holdings (blocks 47 + 54).  Block 62 covers 4,061 sq km in WD 1,600-2,400m. Staatsolie has a 20% back-in right in the event of a commercial find.",Tullow has signed for PSC rights to offshore block 62 covers 4061km² in WD 1600-2400m. Staatsolie has a 20% back-in right in the event of a commercial find.
17358,"On 25 January 2018, the award of the Drávapalkonya contract in southwestern Hungary, pre-awarded to Hungarian Horizon Energy Group Kft (HHE) in November 2017, was signed off by the Minister for National Development and thus became official.  The 1,061 sq km Drávapalkonya area is located in the Baranya and Somogy political provinces, within the Pannonian Basin.  Background Information  On 13 June 2017, acting on behalf of the Hungarian State and in cooperation with the Hungarian Office for Mining and Geology, the Minister for National Development published an invitation to tender for a concession over the Drávapalkonya area. The tender closed on 25 September 2017.  On 17 November 2017, following recommendation of the tender committee from the Hungarian Office for Mining and Geology, MOL was selected as the winner of the bid round for the prospection, exploration and production of hydrocarbons in the Drávapalkonya area. The company had two months (plus additional two months extension) to negotiate the final contract.","Hungary, not found"
26844,"LLA-25, Llanos Basin, S. Cusiana field area, TD 4,715m reached on 23 Jul ‘18, logging underway, testing to be completed by end-month, H&P-900 rig. Frontera has stated that depending on results, there is the potential for 6-8 devt wells and expl prospects.","Acorazado-LLA-25, Llanos Basin, S. Cusiana field area, TD 4,715m reached on 23 Jul ‘18, logging underway, testing to be completed by end-month, H&P-900 rig. Frontera has stated that depending on results, there is the potential for 6-8 devt wells and expl prospects."
32101,"ATP 1189-P, Cooper-Eromanga Basin, drilled and susp gas between 21 – 28 Sep ’18, TD 2,436m, Ensign 950 rig. Santos (op), partner Beach.","Discovery: Aztec-1 nfw ATP 1189-P, Cooper-Eromanga Basin, drilled and susp gas between 21 – 28 Sep ’18, TD 2,436m, Santos (op), partner Beach"
79427,"Comet Ridge secured sole rights to ATP 2048-P (Mahalo North), 451 sq km in the Denison Trough, Bowen-Surat Basin, on 29 Apr '20 for 6 years. The block was offered as PLR2019-1-2 under the 2019 QLD acreage release.","Comet Ridge was officially awarded exploration permit ATP 2048 (Mahalo North), 451 sq km in the Denison Trough, located in the in Queensland."
35964,"It is understood that during summer of 2018, TDE Services farmed out a majority share (likely also the operatorship) in the Püspökladány contract in eastern Hungary to Hungarian Horizon Energy Group (HHE). According to the available information, the group is planning to commence exploration drilling activity still during late 2018. Further details on the transaction are being sought.  The 878 sq km Püspökladány block is located in the Békés, Hajdú–Bihar and Jász–Nagykun–Szolnok political provinces, southwest of the city of Debrecen, within the Hajdusag Sub-basin, tectonic unit of the Pannonian Basin.  Background Information  The Püspökladány contract was granted to PanBridge Hungary Zrt on 15 February 2016. The contract, resulting from the 2015 bid round, is valid for twenty years from the effective date, with one possible 10-year extension. (PanBridge Hungary initially was a joint-venture of TDE Services (15%) and Bankers Petroleum (85%). In 2017, Geo-Jade Petroleum, independent exploration and production company of China, purchased Bankers Petroleum and pulled out of the consortium.)  In the bidding process, PanBridge Hungary pledged to acquire 200 sq km of new 3D seismic data, as well as to drill three vertical exploration wells - to be drilled by 2019 - to assess the potential of the abandoned Biharnagybajom oilfield and surrounding exploration targets. The bid of PanBridge included EUR 2 million signature bonus, with the capital commitment for the concession reaching approximately EUR 14.5 million over the period of contract validity.  In August/September 2016, PanBridge Hungary acquired 230 sq km of new 3D seismic. The new seismic data was co-processed with the vintage 3D data and in early 2017 the entire dataset was interpreted, which resulted in the full coverage of the prospective areas of the Püspökladány area (Biharnagybajom field).  Following the departure of the partner in the consortium, TDE Services was farming out the Püspökladány contract.  The main development phase on the Biharnagybajom oil field spans the period 1940-1950, when 52 vertical wells were drilled. Resulting, 0.35 MMb of light oil and 2 Bcf of gas were produced. Bankers Petroleum is intending to redevelop the field and explore the prospects identified on both historical 2D and 3D seismic.",Hungary (Nagykunsag Sub-basin (Pannonian B.)) Biharnagybajom
10236,"On 24 January 2017 EnQuest announced that it has agreed a deal with BP to acquire a 25% interest and operatorship in the Magnus field, a 3% interest in the Sullom Voe terminal and supply facility, a 9% interest in the Northern Leg Gas Pipeline (NLGP) and a 3.8% interest in the Ninian Pipeline System (NPS). This equity has been acquired for a consideration of USD 85 million which will be funded by deferred consideration payable from the cash flow of the Transaction assets. EnQuest announced on 1 December 2017 that the deal has now completed. In addition to the completed deal, EnQuest has an option to acquire the remaining 75% interest in Magnus and BP’s interest in the aforementioned infrastructure.  Magnus was discovered in 1974 and is a giant Jurassic oil, gas and condensate field. The field was initially developed via a single platform with seven subsea satellite wells for production and injection located in the northern and southern parts of the field. The field was brought onstream in 1983. Following a decline in production in 1995 there was a change in the development strategy adding 13 new wells, completed with gas lift. In the same period six injectors were drilled targeting particular compartments. Then in 2000 an EOR scheme for the field was launched with WAG injection. This was followed in 2003 with miscible hydrocarbon gas injection. At the time gas from the field was a light methane/ethane gas which was too lean for optimal miscible recovery. The gas supply pipeline was therefore re-routed around Sullom Voe where the gas was enriched by injecting propane and butane. This gas supply came from Schiehallion via the West of Shetland Pipeline System to Sullom Voe and then on to Magnus for EOR. Interest in Magnus following the completion of the deal is EnQuest Plc (25% + operator) and BP Exploration Operating Co Ltd (75%).","United Kingdom (Viking Graben Province) ? op. by CNR (87.06%, JX HOLDG 12.94%) in Ninian block"
24857,"On 18 June 2018 BP acquired Premier’s 5% interest in P380 (block 43/26a Ravenspurn North Field Carboniferous Area) which contains part of the Ravenspurn North field.    Ravenspurn North was discovered in 1984 with well 43/26-1. The field is a large Permian gas (dry) field and was brought onstream in 1990. It is located adjacent to the Ravenspurn South accumulation which was discovered in 1976. On 2 December 2016, Perenco, on behalf of block operator BP, spudded well 43/26a-E12 targeting the Ravenspurn North Deep prospect. BP believed if successful, it could open a new phase of development in the region. The target was the Carboniferous beneath the depleted Rotliegend reservoir focussing on tight gas. The well was plugged and abandoned on 3 June 2017 and development sidetrack 43/26a-E12Z was kicked off and completed on 22 October 2017. BP states that the play warrants further exploration as the company is aware that the deeper carboniferous sands exist but what isn’t clear is that if gas is encountered can long term production from the play be sustained.  Interest in the block is held by BP Exploration Operating Company Ltd (90% + operator) and Perenco UK Limited (10%).",BP acquired 5% stake in P380 block 43/26a Ravenspurn N Field Carboniferous area from Premier Oil.
23512,"Stone Energy Offshore has completed acquisition of 40% equity in Mississippi Canyon blocks MC 554 (G34444) and MC 555 (G34445), situated in the Louisiana Coastal Basin, according to reports in early June 2018. The transaction is effective as of 1 April 2018. Following completion of the transaction, Stone Energy Offshore is now the operator and sole interest-holder (100% WI + Op) in MC 554 and MC 555.","Stone Energy Offshore has completed acquisition of 40% equity in Mississippi Canyon blocks MC 554 (G34444) and MC 555 (G34445), situated in the Louisiana Coastal Basin, "
50381,"Aker BP spudded an exploration well on the Freke-Garm prospect in PL 814 on 18 May 2019. 15/6-15 was drilled using the “Deepsea Stavanger” S/S. The prospect had pre-drill potential recoverable reserves of 16-81 MMboe and is located approximately 12 km northeast of Gina Krog and around 20 km southeast of Gudrun. The Hugin and Sleipner formations were the primary objectives (prognosed at 3,498 m TVD), with the well proving a 125 m Sleipner Formation with 40 m of sandstone. The secondary objective was the Skagerrak Formation (prognosed at 3,600 m TVD) which was proven to be 140 m thick but with just 15 m of poor quality sandstone present. TD was reached at 3,791 m in the Skagerrak Formation and on 5 June 2019 the well was being abandoned.  Freke was discovered by ExxonMobil with exploration well 15/6-10, spudded on 7 February 2009. The well encountered a 30 m gas condensate column in the Middle Jurassic but the reservoir was of poorer quality than expected. Freke lies on the Gudrun Terrace. It is a four-way dip closure of Middle Jurassic age delimited by a north-south trending horst. The main objective was the Hugin Formation, with further potential in the Sleipner Formation. Pre-drill reserves were estimated by Det norske (now Aker BP) at between 35 and 230 MMboe with light oil and a possible gas cap expected.     Interest in PL 814 is divided between Aker BP ASA (40% + operator), MOL Norge AS (30%) and OMV (Norge) AS (30%).","15/06-15 (Freke-Garm) (Aker BP 40% op, MOL 30%, OMV 30%), 1st well in PL 814, NE of Gina Krog in WD=109m, P&A’ing dry at TD =3761m (Triassic Skagerrak Fm), main targets Hugin (Middle Jur.) + Sleipner fm’s. "
30018,"Licensing authority is the Ministry of Petroleum.  Contracts are normally of concession type, but the Government of The Gambia is open to PSCs if so desired. Rights are normally granted for a six-year exploration period (+10 years) with the state having up to a 15% back-in right. Most of the terms and conditions under the Petroleum Act and Model Contract of 2004, amended in 2007, are negotiable. Licensing is to be through direct negotiations with the country's Petroleum Commission.    Interested companies are invited to contact:    Jerreh Barrow    Commissioner for Petroleum    Ministry of Petroleum & Energy    Petroleum House  Brusubi Roundabout  Bijilo    The Gambia    Tel: +220 996 33 13    E-mail: jrosemax@gmail.com         The available blocks as of September 2018 are understood to be as listed below.   No blocks are available. There was no change compared to the previous month.   All blocks which were previously open are now part of a bidding process for exploration acreage.","Licensing authority is the Ministry of Petroleum.  Contracts are normally of concession type, but the Government of The Gambia is open to PSCs if so desired. Rights are normally granted for a six-year exploration period (+10 years) with the state having up to a 15% back-in right. Most of the terms and conditions under the Petroleum Act and Model Contract of 2004, amended in 2007, are negotiable. "
50988,"In early June 2019 industry sources indicated that Total was awarded the UDO-North exploration block in the deep waters of the MSGBC Basin. The block covers 10,000 sq km and is operated by Total with a 100% interest. The location of the acreage is not yet known but it is assumed that it borders on the Rufisque Offshore Profond (ROP) block also operated by Total.  Following the interpretation of the 3D seismic survey completed in June 2018 by Total, suitable prospects were identified and one of them is now being drilled (see below). The ROP block covers 10,357 sq km and was previously undrilled. The block is located between Kosmos Teranga and Yakaar gas discoveries in the north and Cairn’s FAN-1 oil discovery in the south, in water depths ranging from 100m to 3,000m. It lies on the Upper Cretaceous slope and basin floor fan play fairways and holds a considerable exploration potential. In August 2018, Petronas acquired a 30% stake in the ROP block from Total who remains operator with a 60% interest. Petrosen, the state company has the remaining 10%.   In April 2019 Total spudded the Jamm 1XB new field wildcat well in the ROP block. As of early June, drilling operations were ongoing. The location is in the central part of the northern portion of the block in around 2,000 m of water. Likely targets are Upper Cretaceous turbidite channels/fans on the lower slope. The hydrocarbon type to be expected could be rather oil than gas as the location falls into a compartment of the basin where Cairn made its oil discoveries. This compartment may have a lower geothermal gradient than the adjacent one to the north where Kosmos made several gas discoveries.","Total was awarded the UDO-North exploration block in the deep waters of the MSGBC Basin. The block covers 10,000 sq km and is operated by Total with a 100% interest. "
14706,"Neptune Energy has announced the completion of the acquisition of ENGIE E&P International ('EPI'). The transaction sees Neptune become an international independent E&P company across the North Sea, North Africa and South East Asia, producing 154,000 net barrels of oil equivalent per day in 2017. Neptune’s new global platform offers a sustainable asset base throughout the E&P value chain, a good balance of oil and gas and with low operating costs. The North Sea region benefits from a strong operating base in strategic assets such as Cygnus in the UK and Gjøa in Norway, while Neptune is the leading offshore operator in the Netherlands. North Africa and Southeast Asia provide near-term gas volume growth into strengthening markets while Germany offers a strong, long-life oil production base. Sam Laidlaw, Executive Chairman of Neptune Energy Group, said:  'I am pleased to announce the completion of this significant achievement, which is the result of some three year’s work and marks a new beginning for Neptune Energy. Building on the success and hard work of the EPI team and leveraging its strong portfolio of assets, we aim to generate long term sustained value for the countries in which we operate, our employees and for our investors in order to create a leading international independent E&P company within the next 5 years. In creating and delivering this opportunity, the team at Neptune also have great support from our investors: China Investment Corporation (CIC), The Carlyle Group and CVC. We all have a shared vision to create an efficient independent E&P company of scale across diversified geographies, operating safely, and nimbly capturing new opportunities.' Jim House, Chief Executive Officer of Neptune Energy, said:  'I am extremely pleased to officially welcome the EPI business and its dedicated employees to the Neptune family. The business is driven by a dynamic organisation of more than 1,800 staff working across exploration, appraisal, development and production, all of whom are critical to the future growth and success of Neptune Energy. I very much look forward to working with our new colleagues as well as industry partners and other stakeholders as we execute on our ambitions.' Original article link Source: Neptune Energy ",Neptune Energy has announced the completion of the acquisition of ENGIE E&P International ('EPI'). 
59221,"Petronas has taken over Shell as operator of SK-8 containing the producing Jintan, Serai, Saderi and Cilipadi fields off Sarawak. Partnership has become Petronas (op) 25%, Shell 37.5% + JX Nippon 37.5%.   Likewise from JX Nippon in deepwater block R off Sabah (Bestari oilfield). Partnership now Petronas (op) 25%, JX Nippon 27.5%, Inpex 27.5% + Medco 20%.  Petronas has reportedly also been officially handed 18th round, shallower water blocks PM-407, PM-415 and PM-419 off Peninsular Malaysia and SB-3K off Sabah. Of note (ref. DEA 25 Mar '19), the PSCs were signed on 21 Mar 19 for PM-407 (6,275 sq km) + PM-415 (3,455 sq km) by PTTEP HKO, a PTTEP-Petronas venture. The Malay Basin blocks are/were to be operated by PTTEP (55% in PM-407, 70% in PM-415) with Petronas holding the balance. http://www.pttep.com.",Malaysia (Central Luconia Province) Serai
58639,"Occidental of Oman Inc (Oxy) has completed pilot hole drilling operations at the Saryiah 1 exploration well in its 4,085 sq km Block 9 (Suneinah) licence. The well was spudded in mid-August 2019 and reached a TD of approximately 2,490 m. Following the exploration and production sharing agreement revision in early-2017, rightholders in Block 9 are Occidental of Oman Inc. (50% operator), Oman Oil Exploration and Production LLC (45%) and Mitsui E&P Middle East BV (5%). Production from the block in July 2019 was reported to be approximately 91,000 b/d of condensate and 42,500 MMcfg/d.    Oxy’s prominent field in Block 9 is the Safah field. The Safah field was discovered in 1983 and produces oil from the Lower Cretaceous, Aptian, Shu'aiba Formation. The structure is a northward plunging faulted anticlinal nose radiating from the Lekhwair High. The anticlinal nose provides three-way dip closure with updip seal provided by a facies change to tight argillaceous lime mudstones. Structural dip averages less than 1° down the crest of the anticlinal nose. The field is divided into laterally equivalent east and west lobes, separated by a narrow structural low and coincident barrier of tight argillaceous limestones. The western lobe has generally a lower net to gross ratio, increased argillaceous content and more variable lithology than the eastern lobe. The eastern lobe is further subdivided into north-eastern and south-eastern lobes on the basis of reservoir PVT properties. The structure was probably modified by Late Tertiary orogenesis.",Occidental of Oman Inc completes drilling of Saryiah 1 exploration well in Block 9 (Suneinah)
28239,"Bozhong 19-6-8 (BZ 19-6-8) was suspended (results TBC) on or around 20 August 2018 after having been spudded in mid-June 2018 using the ""Haiyangshiyou 932"" jack-up. The gas and condensate appraisal well was likely targeting the Guantao, Dongying and Shahejie formations and buried hill reservoir. Following the drilling and testing of multiple successful appraisal wells, CNOOC has declared that the Bozhong 19-6 discovery to be a hundred million ton oil equivalent gas field. Bozhong 19-6-8 is in the CNOOC operated Bozhong Block in the offshore Bohai Gulf Basin and is approximately 11km N of discovery well Bozhong 19-6-1 drilled by CNOOC in April 2017. <P />",Bozhong 19-6-8 (BZ 19-6-8) was suspended (results TBC)
31230,"Commitment well in AE-0109-Cinturón Subsalino-13 block, DW GoM Basin, WD 825m, suspended (results yet n/a) late Sep ’18, La Muralla IV SS. PTD was 2,500m, target L. Miocene.","Kili 1EXP (Pemex 100%) in AE-0109-Cinturon Subsalino-13 contract, suspended with results unreported, was targeting the Lower Miocene on a salt related anticlinal structure. WD=825m, PTD=2530m,"
28779,"The award of SK-304 to COP was made after direct negotiations with Petronas in early Jun ’18 after a carve-out from open SK-304A. PSC commitments comprise seismic + 1 well in 3 years. The ca. 8,200-sq km block lies off SW Sarawak in WD 30-80m and is partnered by Petronas with 15%.",ConocoPhillips (85% op. Petronas 15%) has been granted Block SK-304.
78400,"The state company ONHYM has published a list of 30 open blocks located in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored:            Morocco - Open blocks             Block Name         Location         Area (sq km)             Asilah         Tanger-Tetouan         2275.31             Boudenib         Meknes-Tafilalet         27633.59             Boujdour Maritime         North Atlantic Ocean         33354.63             Boujdour Offshore I         North Atlantic Ocean         11094.2             Boujdour Offshore II         North Atlantic Ocean         17474.61             Casablanca Offshore         North Atlantic Ocean         3038.24             Dakhla Atlantique         North Atlantic Ocean         104063.6             El Jadidad Offshore         North Atlantic Ocean         6665.75             El Kansera         Rabat-Sale-Zemmour-Zaer         2586.17             Foum Ognit Offshore         North Atlantic Ocean         7954.8             Gharb Offshore Nord         North Atlantic Ocean         9761.45             Gharb Offshore Sud         North Atlantic Ocean         4470.17             Hassi Berkane         Oriental         5120.75             Ifni Deep Offshore         North Atlantic Ocean         14119.67             Lemsid         Laayoune-Boujdour-Sakia El Hamra         57015.12             Loukos Offshore         North Atlantic Ocean         1888.58             Mazagan Offshore         North Atlantic Ocean         11101.42             Mir Left Offshore         North Atlantic Ocean         3476.07             Moulay Bouchta         Taza-Al Hoceima-Taounate         4228.68             Ouarzazate         Souss-Massa-Draa         4109.44             Ouezzane         Tanger-Tetouan         4342.22             Rabat Deep Offshore         North Atlantic Ocean         9382.17             Safi Deep Offshore         North Atlantic Ocean         9767.94             Safi Offshore Nord         North Atlantic Ocean         6250.44             Safi Offshore Sud         North Atlantic Ocean         5943.69             Sakia El Hamra         Laayoune-Boujdour-Sakia El Hamra         13061.46             Souss         Souss-Massa-Draa         6250.11             Tadla-Haouz         Tadla-Azilal         21935.16             Taounate         Taza-Al Hoceima-Taounate         6771.62             Zag         Guelmim-Es Semara         65448.12           The Boujdour Offshore and Boujdour Onshore blocks are under negotiation.    Interested parties may contact: Onhym, 5 Avenue Moulay Hassan, 10050 Rabat - Morocco - Tel 00 212 537 23 9898 - Fax: 00 212 537 70 94 email: partenaire@onhym.com",he state company ONHYM has published a list of 30 open blocks located in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored: Morocco
14522,"Total has transferred to Engie its 30% in K1c,  274 sq km in the W. offshore. It contains 3 wells, of which 1 gas shows. Engie (op), partner EBN.",Total (30%) has exited licence K01c to operator ENGIE (->60% + Op) and Energie Beheer Nederland (EBN) (40%).
24724,"On 3 February 2018 Fogelberg appraisal well 6506/9-4 S was spudded by Spirit Energy. The company used the “Island Innovator” S/S to drill the well in PL 433. 6506/9-4 S is located in a down-dip position, approximately 1 km to the west of the discovery well, with the aim of adding 2P reserves, reducing volume uncertainty and confirming reservoir quality before the licence group commits to a FEED project. The well was drilled to TD at 4,738 m and encountered a 63 m gross hydrocarbon column in the Middle Jurassic Garn Formation and gas in the Middle Jurassic Ile Formation. Reservoir quality is better than that seen in the discovery well and the GWC is deeper. On 28 April 2018 sidetrack 6506/9-4 A was kicked-off from the 14” casing. Two cores were cut (around 4,288 m and 4,316 m) and the well reached TD at 4,497 m. A 58 m gross hydrocarbon column was confirmed in the Garn Formation and an 87 m gross hydrocarbon column was present in the Ile Formation. The well was tested and flowed at a maximum constrained rate of 21 MMcfg/d plus 547 bc/d through a 22/64” choke. Preliminary estimated recoverable reserves are 40-90 MMboe – a formal volumetric update will be provided after further interpretation. With this well Fogelberg has been declared commercial and, if development proceeds, it will be as a subsea tie-back to Asgard B (located at the Smorbukk field). On 3 July 2018 the well was being abandoned.    The licence term for PL 433 was extended in February 2017 with a deadline to submit a PDO by July 2019. The PDO was originally expected to be submitted in February 2017. Centrica (now Spirit) received MPE approval for the Environmental Impact Assessment (EIA) for Fogelberg in early 2014. The proposed plan (given at that time) included the installation of a four-slot subsea template (with three producers to be drilled initially) tied-back to either Asgard B or Heidrun. Costs were estimated at either NOK 7 billion (USD 1.18 billion) or NOK 11 billion (USD 1.86 billion) depending on which host facility was chosen.    The Fogelberg discovery well (6506/9-2 S) was Centrica’s first as an operator on the NCS and was drilled in 2010. Gas and condensate was confirmed in the Garn and Ile formations with no OWC indentified. The field is HPHT. It lies between Victoria and Smorbukk on the Halten Terrace.    Pending completion of a deal in PL 433 interest will be divided between Spirit Energy Norge AS (51.7% + operator), PGNiG Upstream Norway AS (20%), Faroe Petroleum Norge AS (15%) and Dyas Norge AS (13.3%).","6506/09-04S, 04A (Fogelberg) appr. pos. by Spirit (51,7%, Dyas 13,3%, PGNiG 20%, Faroe Petr.15%) in PL 433 block, N. of Smørbukk field + Åsgard complex, target Garn + Ile fm’s penetrated, 62,5m gross hc reservoir in the Garn + gas recorded in the Ile, reservoir quality better than that encountered in the discovery (6506/09-02S) with deeper GWC, preparing to test, TMD=4738m. 58 m gross hydrocarbon reservoir in the Garn fm and 87 m in the Ile fm, testing gauged 21 Mmcfg/d and 547 bc/d on 22/64” choke for 24 hrs. Estimated 40-90 mboe gross."
25533,"BT-PN-005 contract, PN-T-049 block C, Parnaíba Basin, assumed P&A dry 20 Jun ’18, no shows report. PTD was 1,221m, target Cabeças + Poti fm’s.","4-PGN-FAZENDATORRAO-002-MA (4-PGN-024-MA) (Parnaiba Gas Nat.100%) in PN-T-049 block, assumed P&A dry."
56140,"Sava 10 (SA-10) licence, Slavonian sub-basin in NE Croatia, tested 6.2 MMcf/d from 1,167-1,177m (Pannonian sst), WHP 1,376 psi, for 18 hrs. Gas was also encountered at 1,020-1,022m (U. Miocene) but not tested.","Ceric-1 nfw Sava 10 (SA-10) licence, Slavonian sub-basin in NE Croatia, tested 6.2 MMcf/d from 1,167-1,177m (Pannonian sst), WHP 1,376 psi, for 18 hrs. Gas was also encountered at 1,020-1,022m"
71228,"On 4 February 2020 RockRose Energy announced that it has signed a Sales and Purchase Agreement to acquire 100% equity of Speedwell Energy (1) Limited which holds 100% interest in the Cotton discovery formerly known as Carna located in licence P2341. RockRose has initially paid a limited consideration but a further payment will be made at the Final Investment Decision (FID). The plan to develop the field includes the drilling of two horizontal development wells which are planned to produce at 12,000 boe/d (70 MMcf/d). Speedwell has prepared a draft Field Development Plan for submission to the OGA.  The field was discovered with well 43/21b-5Z in 2009 encountering a gas column of up to 1,260 ft over six gas sandstone packages. Speedwell estimated the discovery to contain 97 Bcf.  Following completion of the deal interest in P2341 will be held by RockRose Energy Plc.",RockRose Energy announced that it has signed a Sales and Purchase Agreement to acquire 100% equity of Speedwell Energy (1) Limited which holds 100% interest in the Cotton discovery formerly known as Carna located in licence P2341.
78541,"CNOOC Intl is on the lookout for partners in its BC9 + BCD10 offshore blocks in the Gabon Coastal Basin, up to 50% available ahead of drilling 2 wells probably in 2021 (deepwater Tigre in BC9 and shallower Seal in BCD10). Acreage totals ab. 13,400 sq km mainly in deep waters. A data room opened in March, expected offer deadline mid-2020. Contact: Lucas.Ong@intl.cnoocltd.com or Ben.Kilner@intl.cnoocltd.com.","CNOOC Intl is on the lookout for partners in its BC9 + BCD10 offshore blocks in the Gabon Coastal Basin, up to 50% available ahead of drilling 2 wells probably in 2021 (deepwater Tigre in BC9 and shallower Seal in BCD10)."
67766,"On 18 December 2019, the Federal Agency for Subsoil Use held an auction for three blocks in Irkutsk Oblast (Eastern Siberia). Competing against Krasnoyarsk Oil & Gas Co, Sibenergiya won all blocks. The winner of the auction will obtain 27-year E&P licenses including a 7-year exploratory stage.   Details of the offer are as follows:  The Biryusinskiy block covers 2,524 sq km in the Angara-Yenisey Basin. No exploratory wells have been drilled in the area. Reservoirs of the Vendian-Cambrian section are the main exploratory targets. Hydrocarbon resources (categories D1+D2) of the block are estimated at 37 MMbbl of oil and 411 Bcf of gas. The starting price amounted to RUB 6.84 million (USD 0.1 million). Sibenergiya offered RUB 10.26 million (USD 0.16 million).  The Tareyskiy block covers 2,416 sq km in the Angara-Yenisey Basin. No exploratory wells have been drilled in the area. Reservoirs of the Vendian-Cambrian section are the main exploratory targets. Hydrocarbon resources (categories D1+D2) of the block are estimated at 31 MMbbl of oil and 377 Bcf of gas. The starting price amounted to RUB 5.57 million (USD 0.09 million). Sibenergiya offered RUB 10.026 million (USD 0.16 million).  The Udinskiy block covers 2,533 sq km in the Angara-Yenisey Basin. No exploratory wells have been drilled in the area. Reservoirs of the Vendian-Cambrian section are the main exploratory targets. Hydrocarbon resources (categories D1+D2) of the block are estimated at 15 MMbbl of condensate and 685 Bcf of gas. The starting price amounted to RUB 5.13 million (USD 0.08 million). Sibenergiya offered RUB 12.825 million (USD 0.2 million).","Sibenergiya won Biryusinskiy (2 524km²), Tareyskiy (2 416km²), Udinskiy (2 533km²) all in the Angara-Yenisey Basin"
8832,"Bozhong 36-1-3 (BZ 36-1-3) was suspended on or around 8 August 2017, having successfully encountered oil in the target reservoirs. A successful sidetracked borehole Bozhong 36-1-3ST1 was also drilled and successfully intersected oil. Bozhong 36-1-3 was spudded on or around 12 July 2017 using the ""Bohai 4"" jack-up and was likely targeting the Guantao, Dongying and Shehejie formations. Bozhong 36-1-3 is in the CNOOC operated Qinhuangdao 36 Block in the offshore Bohai Gulf Basin and is approximately 3km W of successful oil well Bozhong 36-1-2, drilled by CNOOC in March 2017. <P />",Not Found
50825,"In The authorities are planning for a licensing round, tentative opening in late 2020. The proposed offering would lie in the W. part of the B-H, too early for any inventory.","The authorities are planning for a licensing round, tentative opening in late 2020. The proposed offering would lie in the W. part of the B-H, too early for any inventory."
12846,"Fell block, Magallanes Basin, drilled 2H ’17, TD 1,115m, tested 800 Mcfg/d avg on various chokes from the El Salto fm, WHP 158 psi. A stabilised flow is yet to be determined. Gas is piped to a regional Methanex methanol plant. ","Uaken 1 op. by Geopark (100%) in Fell block, tested 800 Mscfg/d avg on various chokes from the El Salto fm, a stabilised flow is yet to be determined."
22845,The Georgian State Agency for O&G and Repsol signed an MoU at the end of May for a joint study of further hc potential in the Kura Basin with a view to possible future devt.,The Georgian State Agency for O&G and Repsol signed an MoU at the end of May for a joint study of further hc potential in the Kura Basin with a view to possible future devt.
44018,"Shell secured yesterday E&P rights to 2 blocks in the Caribbean, COL 3 and GUA OFF 3 (Guajira) totalling ab. 8,800 sq km and former TEAs. For now and in a nutshell, Shell intends to invest up to USD 650 MM in the new acreage. Commitments include reprocessing of 1,000 sq km of 3D and drill 1 well in COL 3, and shoot 2,461 sq km of 3D, sampling and re-processing in GUA OFF 3. Anadarko, Repsol and ExxonMobil are still awaiting TEA conversions. Release from ANH.","Shell has signed exploration and production contracts for two blocks off Col 3 & Gua 3, ab. 8800km² and former TEAs."
76629,"Tharwa is hoping to secure 6 concessions in 2020 and enter into partnerships with BP, Chevron, ExxonMobil, Shell + Total. No mention is made of any specific locations, however the company also plans 7 wells (expl + dev) this year, one down from last year's achievement. Tharwa is currently present in the Abu Gharadiq Basin (4 blocks).","Tharwa is hoping to secure 6 concessions in 2020 and enter into partnerships with BP, Chevron, ExxonMobil, Shell + Total. No mention is made of any specific locations, however the company also plans 7 wells (expl + dev) this year, one down from last year's achievement. Tharwa is currently present in the Abu Gharadiq Basin (4 blocks)."
85445,"Further to DEA 11 Jun '20, ReconAfrica's award of sole rights to 9,921 sq km of Okavango (Kavango) Basin acreage last month at the start of the panhandle in NW Botswana is now named as PEL 001/2020 (GEPS map extract below). The contract runs 4+10 years, plus 25+20 years production if warranted. Commitments include: HR airmag in yr 1, regional geol studies in yr 2, environmental impact studies, pre-drill operational environmental assessment in yr 3, identification of all necessary regulatory permits and approval, soil geochemical sampling for identifying hydrocarbon plumes, supporting drill selection, in yr 4.","Botswana (Okavango B.), ReconAfrica's award of sole rights to 9,921 sq km of Okavango (Kavango) Basin acreage last month at the start of the panhandle in NW Botswana is now named as PEL 001/2020. The contract runs 4+10 years, plus 25+20 years production if warranted."