id,document,summary
56090,"On 9 August 2019, Petrobras published its teaser to sell the Campos Basin Garoupa Package of 11 fields that includes the Anequim, Bagre, Cherne, Congro, Corvina, Garoupa, Garoupinho, Malhado, Namorado, Parati, and Viola production concessions. The cluster also includes five fixed platforms, one semi-sub platform, gathering pipelines, and export pipeline that are for sale. Interested companies must submit the customary manifestation of interest by 23 August 2019 and qualification documents by 30 August 2019 to garoupa@baml.com.   Petrobras reported that in the last 12 months the 11 fields produced an average of 19,600 boe/d. Petrobras holds 100% working interest in the 11 contracts.","Brazil, Garoupa"
9750,"On 21 November 2017 Siccar Point Energy E&P Limited announced that it has agreed to farm down a 66.666% interest in two West of Shetland licences P1854 and P1935 to INEOS UK SNS Limited. The acreage contains the Lyon prospect which is thought to hold pre-drill mean recoverable resources of 1.4 Tcf (266 MMboe). Through this deal INEOS is building on its West of Shetlands acreage which it acquired through the acquisition of DONGâs business earlier in 2017. The company intends to become a significant player in this area and make use of the existing gas infrastructure in the West of Shetlands. The deal is pending regulatory approval. Licence P1854 comprises blocks 208/1b, 208/2, 208/3b, 217/27b and 217/28b and P1935 comprises blocks 217/22a, 217/23a and 217/24a. 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 which is now considered ready to drill. 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. Interest in the licences following completion of the deal will be Siccar Point Energy E&P Limited (33.334% + operator) and INEOS UK SNS Limited (66.666%).",United Kingdom (Faroes-Shetland Trough) (It's a petroleum rights. Please summarize by yourself). In IHS database: 217/24a op. by SICCAR PT (100.0%) to be check.217/22a op. by SICCAR PT (100.0%) to be check.217/23a op. by SICCAR PT (100.0%) to be check.
68273,"It was announced on 29 December 2019 that Petar Dogalgaz ve Petrol has been awarded the M42-D3,D4 exploration licence (Zagros Province) on 17 December 2019 for a period of five-year. The licence, covering an area of 307 sq km, is located towards southeast of the country and Petar Dogalgaz will be 100% owner and operator of the licence.","Petar Dogalgaz ve Petrol has been awarded the M42-D3,D4 exploration licence (Zagros Province) "
27726,"Liari ML, Lower Indus onshore in Sindh, TD 2,841m, gas-cond discovery in early Aug â18. Target Lower Goru, DFXK-1000 rig.","Hayat 1 in Liari ML, gas-cond discovery. Target Lower Goru, TD=2841m"
55726,"Further to DEA 2 Aug â19: PL 869 near the Bøyla + Alvheim fields in WD 118m, ops terminated 29 Jul â19, small gas discovery (0.6-1.7 MMcum recov).   24/9-13 (TD 2,272m) encountered 3m gas column in the Hordaland group, + 17m of good-quality Balder reservoir with oil traces. 24/9-13 A (TMD 3,433m, TVD 2,240m) encountered a 40m gas column in injectite zones, of which 7m good reservoir quality sst in the Hordaland. OWC not encountered. Deepsea Nordkapp SS off to PL 460 (Skogul field). Aker BP (op), partners Lundin + VÃ¥r Energi.","024/09-13 (Rumpetroll) (Aker BP 60% op, Lundin 20%, Var Energi 20%) in PL 869, near the Boyla field, P&A, small gas discovery (4-10 MMboe recov). Encountered 3m gas column in the Hordaland group, + 17m of good-quality Balder reservoir with oil traces. 24/09-13 A encountered a 40m gas column in injectite zones, of which 7m good reservoir quality sst in the Hordaland. OWC not encountered. "
41657,"Equinor acquired 8% interest in licence P1620 from Eni in February 2019. The licence contains the HP/HT gas condensate Rowallan prospect in block 22/19c which was spudded by Eni on 31 December 2018. Rowallan is a large structural closure estimated to hold P50 gross prospective resources of 220 MMboe. It is thought to be an analogue to the large Culzean field with reservoirs comprising of high quality sandstones at both the Middle Jurassic and Triassic levels. In the event of a success there is additional upside potential in the nearby Dundonald and Sundrum prospects which have similar geological characteristics to Rowallan. Serica was officially awarded the licence under the 25th Offshore Licensing Round in 2010. Following a deal in 2012 with JX Nippon, the Japanese company farmed in taking an 85% interest operatorship. Then in May 2014 Eni farmed into the licence taking a 50% interest and operatorship. The licence is located near the Eastern Trough Area Project (ETAP) which involves the joint development of the Marnock, Skua, Egret, Heron, Machar, Mungo, Madoes and Mirren fields. Interest in the licence is held by ENI UK Limited (32% + operator), JX Nippon Exploration and Production (U.K.) Limited (25%), Mitsui E&P UK Ltd (20%), Serica Energy (UK) Limited (15%) and Equinor (UK) Ltd (8%).",Equinor acquired 8% interest in licence P1620 from Eni The licence contains the HP/HT gas condensate Rowallan prospect in block 22/19c
41762,"Further to last yearâs bid round (see DEA 11 Sep â18), EGAS has awarded 100% interest and operatorship in the 1,418-sq km East Damanhour exploration block (onshore Nile Delta) to DEA, located west of the company Disouq devt leases. DEA is planning 5-7 wells during the first 3-year expl phase.","DEA has been awarded the East Damanhour tract, also known as Block 10, near its producing Disouq licence"
8836,"Wushi 16-1W-6d (WS 16-1W-6d) was suspended in early October 2017, having successfully intersected oil in the target reservoir. The success of the appraisal well expands the western extend of the discovery which enhance the Wushi Phase II development to a mid-large size oil development project. Wushi 16-1W-6d was spudded on or around 6 September 2017 using the ""Nanhai 4"" jack-up and was likely targeting the Liushagang Formation. Wushi 16-1W-6d is in the CNOOC operated Weizhou 12 Block in the Beibuwan Basin. ",Not Found
62691,"As of October 2019, it is understood that Reconnaissance Energy Africa Ltd. (ReconAfrica) via its subsidiary Reconnaissance Energy Namibia (Pty) Ltd is looking to farm out a stake in PEL 073 (Blocks 1719, 1720, 1721, 1819, 1820 and 1821). The 25,000 sq km licence straddles the Okavango and Owambo basins. The company plans to spud its first well within the acreage before 29 January 2020 targeting the Permian aged shales (Prince Albert or equivalent). In addition, the company will test conventional potential. The well is understood to farm part of the commitments for the first exploration period. For additional information contact: Jay Park Email: Jay.Park@ReconAfrica.com Reconnaissance Energy Africa Ltd. Berkeley Square House, Berkeley Square London UK W1J 6BD Exploration drilling within the Owambo to date: Five wells have been drilled all located between 300 km and 500 km to the west of ReconAfrica's acreage and all P&A dry. There is one questionable exception, the deepest well drilled within the basin - 5 1A - bottomed in the Tsumeb Subgroup. After reaching a total depth of 2,509 m, the well was shut-in, waiting for a bigger rig to deepen the well. Months later, the decision was made to abandon rather than deepen the well. Before plunging the well, another water sample was collected. This sample included hydrocarbons. It was assumed that it was diesel as diesel had been added to the mud system while drilling. Samples of this oil were analyzed in several laboratories and its origin was questionable. That said Circle Oil, which held exploration rights in the area during 2003-2006, reported an open hole DST in the well from 2,072 to 2,056 m, presumably in the Tsumeb Subgroup limestones of the Otavi Group flowed 1,680 bw/d (salt water & mud), and oil shows with a density of 29.5 deg API. Geochemical analyses relate this to the Proterozoic and generated from a marine source rock. Background information ReconAfrica was awarded an exploration covering the area in early 2015. The first exploration period is understood to end on 29 January 2019.","Namibia, not found"
50736,"The ANH has approved the proposed farmout, by Amerisur, of a 50% stake in 4 blocks to Oxy in the Putumayo Basin, namely PUT-9 (491 sq km), Mecaya (300 sq km), Terecay (2,372 sq km) + Tacacho (2,383 sq km). Oxy will fund a USD 93.25 MM explo/appraisal programme between 2019-2021, plans including 1,068 km of 2D seismic + 4 explo wells. Amerisur will retain operatorship + 50%.","The ANH has approved the proposed farmout, by Amerisur, of a 50% stake in 4 blocks to Oxy in the Putumayo Basin, namely PUT-9 (491 sq km), Mecaya (300 sq km), Terecay (2,372 sq km) + Tacacho (2,383 sq km). Oxy will fund a USD 93.25 MM explo/appraisal programme between 2019-2021, plans including 1,068 km of 2D seismic + 4 explo wells. Amerisur will retain operatorship + 50%."
70199,"Norwegian Noroil has signed an MoU with the authorities with the aim to help develop block 17 resources. It is not yet clear whether this will lead to a farmin, since operator Sudapet has been looking to offload 25% of its 100% in the 17,000-sq km Muglad Basin block.","Noroil has signed an MoU with the authorities with the aim to help develop block 17 resources. It is not yet clear whether this will lead to a farmin, since operator Sudapet has been looking to offload 25% of its 100% in the 17 000-sq km block."
70709,"The Dutch Ministry announced on 21 January 2020 that the 243 sq km F4a exploration licence was awarded to NAM who will be the operator with Neptune and HALO as partners. The licence is in the north of block F4 and is valid from 22 January 2020 for five years. During the validity period, NAM must submit a work program before 22 January 2023 which should detail an intended exploration well and the well must be drilled before 22 January 2024. Multiple shallow gas prospects have been identified in the licence. HALO and Neptune submitted competing bids during the 13-week period after NAM's application for F4a. The Dutch Ministry announced that in October 2019 all parties agreed to share the licence interests with NAM as operator. The commitment well that will be drilled by the end of the fourth year will have Tertiary sandstone targets. HALO identified multiple shallow gas prospects in the licence that have amplitude anomalies in four-way dip-closed structures. Two wells have been drilled on the licence. In 1971 the first well was F4-1, an exploration well which was plugged and abandoned dry. The well had targets in the Triassic Bunter Sandstone Formation but was drilled to evaluate the regional stratigraphy down to the Zechstein Group. In 1980 the F4-2 well was drilled in the east of the licence, it was abandoned dry. The targets were in the Lower Permian Rotliegend Sandstone Formation but also with secondary targets in the Triassic Bunter Sandstone Formation, Zechstein carbonates and Carboniferous. It is believed that the shallow gas play has not previously been targeted in the area covered by F4a. The F4a licence is next to exploration licence B16b, B17, E3a, E6a, F1 and F2b that was granted to NAM at the same time, also valid from 22 January 2020. HALO and Neptune are not partners in that neighboring licence. The neighboring F5 exploration licence was awarded to Neptune (operator) and HALO on 3 October 2019 with a four year validity period and a well commitment in year three. The F5 licence lies to the south of the Hanze oil and gas field (Dana) and to the west of the F3-FB oil and gas field (Neptune), both are producing. Industry sources indicated the F5 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. Two prospects have been mapped as extending across licences F5 and F4a. The F4a licence is held by Nederlandse Aardolie Mij BV (operator), Neptune Energy Group Ltd, HALO Exploration & Production Netherlands BV and Energie Beheer Nederland BV (40%).","Netherlands, F5"
51168,"PEDL 183, S. Zechstein Basin in Yorkshire, S. of the 2013 discovery, TD 2,061m, âsubstantial hydrocarbon accumulationâ within 65m net intv in the main target Kirkham Abbey fm, deeper target in the Cadeby fm encountered shows with an oil-saturated core. Testing planned 3Q â19. KCA Deutag T-61 rig. Rathlin (op), partners Humber O&G + UJO. Release from https://reabold.com/.","West Newton A-2 appr. (Rathlin Egy 66, 67% op, Union Jack 16,67%, Humber O&G 16,67%) in PEDL 183 block, had been drilled to a TD=2061m and intersected both gas and liquids. Net 65m hc saturated interval was encountered within the primary Kirkham Abbey Fm which indicated âa substantial hc accumulationâ, hydrocarbon shows had also been observed in the secondary target Cadeby formation with an oil saturated core. Preliminary data suggested a best estimate contingent resource of at least the pre-drill estimate of 189 Bcf, or 31,3 MMboe."
48484,"Zaafrane block, onshore Ghadames Basin, recently tested 2,000 bo/d + 5 MMcfg/d (believed from the Trias), to be tied-in to facilities nearby and production. Mazarine (op), partners Medex, Etap (carried).","Sidi Marzoug 1 (SMG-1) (Mazarine op. 90%, Medex Petroleum 10%. Etap is carried for 50%) in the Zaafrane exploration permit, onshore. The well flowed at an equipment constrained rate of 2000 b/d of oil and 5 MMcf/d of gas. The well will be completed for production and tied-in to the Ghrib production facilities located about 15 km north-west of SMG 1."
22777,"Statoil Gulf of Mexico, local subsidiary of Equinor (previously known as Statoil), was awarded Green Canyon Block GC 889 (G36307) on 1 June 2018. The block, which was originally offered as part of OCS Lease Sale 250, lies 15km northeast of the Shenandoah oilfield. The original Shenandoah #1 discovery well was drilled in early 2009 on Block WR 52 and encountered more than 91m (300 feet) net of Inboard Lower Tertiary oil pay. LLOG assumed operatorship of Shenandoah discovery in April 2018. Following official award, Statoil Gulf of Mexico (Equinor) is now the operator and sole interest-holder (100% WI + Op) in GC 889.","Statoil Gulf of Mexico, local subsidiary of Equinor (previously known as Statoil), was awarded Green Canyon Block GC 889 (G36307) on 1 June 2018. The block, which was originally offered as part of OCS Lease Sale 250, lies 15km northeast of the Shenandoah oilfield. The original Shenandoah #1 discovery well was drilled in early 2009 on Block WR 52 and encountered more than 91m (300 feet) net of Inboard Lower Tertiary oil pay. LLOG assumed operatorship of Shenandoah discovery in April 2018. Following official award, Statoil Gulf of Mexico (Equinor) is now the operator and sole interest-holder (100% WI + Op) in GC 889."
72179,"Uzynada-7 gas-cond discovery area, Caspian coastal area (S. Caspian Basin), reportedly tested a commercial gas flow from some 7,000m depth, no further details.","Uzynada-8 appr Uzynada-7 gas-cond discovery area, Caspian coastal area (S. Caspian Basin), reportedly tested a commercial gas flow from some 7,000m depth, no further details."
73579,"Arunachal Pradesh authorities have granted PEL rights to Cairn, believed to be on block AA-ONHP-2017/2, 73 sq km offered in the OELP I round in the Schuppen Belt (Assam Shelf):","Arunachal Pradesh authorities have granted PEL rights to Cairn, believed to be on block AA-ONHP-2017/2, 73 sq km offered in the OELP I round in the Schuppen Belt."
11051,"Parnaiba Gas Natural (PGN) suspended with results unreported the 4-PGN-ARAGUAINA-SE-MA (4-PGN-022-MA) new-pool wildcat (NPW) in the BT-PN-001 contract, PN-T-102 block on 10 December 2017. The well may be a dry hole as the operator has yet to file a gas show report for it. The NPW was spudded on 14 November 2017. The well had a proposed total depth (PTD) of 2,178 m. The primary targets were the Devonian Cabecas Formation and the Mississippian Poti Formation. The well is located in the southeastern corner of the discovery evaluation plan (PAD), the PA_1OGX119MA_PN-T-102 in the Parnaiba Basin approximately 20.4 km north southeast of the 1-OGX-FAZSERRINHA-MA (1-OGX-120-MA) NFW gas discovery well drilled in 2013.  On 11 October 2017 the ANP approved a 3rd modification to the discovery evaluation plan (PAD) operated by Parnaiba Gas Natural (PGN) associated with the BT-PN-001 contract, PN-T-102 block that includes new commitments and a final expiry extension pending conditions. The operator will have a decision point on 20 December 2017 to drill a horizontal well from a side-track of firm well, assumed to be the 3-PGN-ARAGUAINA-003D-MA (3-PGN-021D-MA) outpost. The horizontal well is dependent on the results of the firm well. The operator has a second decision point on 6 April 2018 to drill another exploration well on a newly mapped structure nearby. If all of the commitments are met the final expiry of the PAD will be on 10 September 2018. On 15 June 2016 the ANP approved a 2nd modification to the discovery evaluation plan (PAD) operated by Parnaiba Gas Natural (PGN) associated with the BT-PN-001 contract, PN-T-102 block that includes a final expiry extension pending conditions. Two new-field wildcats are associated with the PAD and include the 1-OGX-ARAGUAINA-MA (1-OGX-119-MA) and the 1-OGX-FAZSERRINHA-MA (1-OGX-120-MA) both located in the block. The PAD modification approval has firm and contingent commitments. The June 2016 firm commitment for the PAD is for the operator to conduct petrophysical and geo-mechanical analysis of the data obtained from drilling the 3-PGN-ARAGUAINA-002A-MA (3-PGN-016A-MA) outpost, suspended with gas shows in January 2016. The operator will also have to stimulate the outpost well and conduct a formation test. The operator has to conclude the firm commitments by 15 November 2016 and decide to conduct the contingent commitments or the PAD will expire. The contingent commitments include the acquisition of 102 km of 2D seismic and the drilling of one well and a formation test of that well.  If the contingent commitments are conducted the PAD will have a final expiry date of 10 February 2018 whereby commerciality will have to be declared or the PAD relinquished. On 26 June 2014 the ANP originally approved the discovery evaluation plan (PAD) filed by Parnaiba Gas Natural (PGN) for the PA_1OGX119MA_PN-T-102 carved out of the BT-PN-001 contract, PN-T-102 block in the Parnaiba Basin. The contract was partially relinquished with an evaluation area carved out of the block for the two discovery wells that covers an area of 963.70 sq km. Two new-field wildcats are associated with the PAD and include the 1-OGX-ARAGUAINA-MA (1-OGX-119-MA) and the 1-OGX-FAZSERRINHA-MA (1-OGX-120-MA) both located in the block. The PAD covers an area of 963.70 sq km. The original expiry date of the PAD was 10 October 2016. Parnaiba Gas Natural is the operator of the BT-PN-001 contract with a 100% working interest after acquiring all of the working interest from former partners Imetame, Orteng and Delp. On 28 December 2015 the ANP granted Parnaiba Gas Natural approval to acquire all of the working interest in the BT-PN-001 contract, PN-T-102 block from its three former partners Imetame who held 16.665% working interest, Orteng who held 16.6665%, and Delp with 16.67%.  ",Brazil (Parnaiba B.) 3-PGN-ARAGUAINA-002A-MA op. by PARNAIBA (100.0%) in PN-T-102 block
69820,"On 24 December 2019, the award of the Kef Abbed, Metline and Tiskraya prospecting permits to Panoceanic Energy became effective with the publication of the award in the government gazette (Journal Officiel de la République Tunisienne). In early July it was reported that Norwegian company Panoceanic Energy was awarded the three offshore blocks. The Kef Abbed (6588 sq km), Metline (4,824 sq km) and Tiskraya (3,864 sq km) blocks fall in the Tellian Atlas Basin. They were previously operated by Repsol who relinquished them in October 2014. The company acquired shallow cores over its three offshore blocks in 2013. In September 2013, the company completed an airborne gravimetric and magnetic survey over the three blocks. Repsol also completed the acquisition of 2,500 km of non-conventional 2D seismic data using Dolphinâs âArtemis Atlanticâ seismic vessel in April 2013.","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)"
61956,"PL 921, SE of Troll in WD 203m, P&A'ing (P&A'd) at TMD 2,017m (2,000m TVD), West Hercules SS. Targets Heather, Sognefjord, Brent, Johansen + Statfjord fmâs. Equinor (op), partners Petoro, DNO + Lundin.","032/04-03 S (Gladsheim) nfw. (Equinor 50% op, Petoro 20%, DNO 15%, Lundin 15%) in PL 921, SE of Troll , P&A results awaited, targets Heather, Sognefjord, Brent, Johansen + Statfjord fmâs. WD=203m."
84409,"On 23 June 2020, the Israeli Ministry of Energy announced the launch of a 3rd Offshore Licensing Round. The bid round comprises one offshore exploration block, Block 72, which is located in the north of Israel's Exclusive Economic Zone (EEZ), close to the disputed offshore border with Lebanon. The block covers an area of approximately 257 sq km and comprises part of the acreage previously held under the expired Alon D (367) exploration licence. The licence will have an initial period of three years and includes two Drill-or Drop decision points after three and five years. Extensions of up to seven years are permitted after the award date. The bid submission deadline for the licensing round is 23 September 2020. In late March 2020, Noble Energy Mediterranean Ltd and its partners in the Alon D (367) exploration licence submitted an appeal to the Ministry of Energy regarding the expiry of the licence. Noble had submitted a request to the Petroleum Commissioner to extend the licence in late February 2020, stating that political and security problems had caused a delay to planned drilling operations. The Commissioner rejected the extension and stated that the licence would be released for bidding. Noble was originally awarded the 400 sq km licence in the Levantine Basin on 1 March 2009. There are currently no exploratory wells drilled within the contract. Noble 47.059% (operator) was partnered in the licence by Delek Drilling Ltd Partnership 52.941%. Noble Energy and Delek Drilling had been previously awarded a 32 month extension for the Alon D (367) by the Ministry of Energy on 21 August 2017. The licence had originally expired in March 2016 but an appeal was subsequently launched by the joint venture partners. Interested companies are expected to register their interest and obtain a data package from the Ministry of Energy (http://www.energy-sea.gov.il/English-Site/Pages/Offshore%20Bid%20Rounds/3rd_Bid_Round.aspx). The participation fee is USD 10,000. Announcement of the successful bidders is expected on 26 October 2020. Â Map Source: Israeli Ministry of Energy","On 23 June 2020, the Israeli Ministry of Energy announced the launch of a 3rd Offshore Licensing Round. The bid round comprises one offshore exploration block, Block 72, which is located in the north of Israel's Exclusive Economic Zone (EEZ), close to the disputed offshore border with Lebanon"
62684,"Khalda Offset (New) A-East permit, N. Egypt Basin, drilled 4 Feb â early Mar â19, TD 4,771m, tested 5,000 bo/d. Currently drilling an offset well. Target Alam El Bueib, 5 + 6 units, Safa + Masajid fmâs.","Egypt, Khalda Offset"
9741,"Premier Oil Vietnam Offshore BV has completed two infill wells campaign at Chim Sao field, in Block 12W, Nan Con Son Basin, offshore Vietnam, on or around 20 November 2017. Drilling commenced on or around 3 September 2017 using the âPV Drilling VIâ J/U. The wells will be used to increase the declining production rate in the fields. The last development drilling activity in Block 12W was conducted in the Chim Sao field with two injector wells completed in late 2014, for reservoir pressure maintenance. The block consists of two producing fields, Chim Sao and Dua field. The Chim Sao and Dua fields were both discovered in 2006. Oil production from Chim Sao commenced in October 2011 and gas production in 2012. The Dua field came onstream on July 2014 via a subsea tie-back to Chim Sao field. Average production from Chim Sao and Dua fields are approximately 22,000 bo/d in September 2017. Premier Oil is operator of Block 12W with a 53.125% interest. Partners in the block are Santos Petroleum Ventures BV (31.875%) and PVEP (15%).","Vietnam (Nam Con Son B.) ? op. by PREMIER (53.125%, SANTOS 31.875%, PETROVIET 15.0%) in Block 12W"
23334,"Aker BP has taken a 23.835% interest in PL 159 D from operator Equinor. The deal was reported by the NPD on 5 June 2018 and it is effective from 31 May 2018. PL 159 D covers a 7 sq km area over part of block 6507/3 to the east of Aerfugl. It contains the 2009 Idun North gas discovery. Aker BP operates the neighbouring licences (PL 212, PL 212 B and PL 262) which contain the Aerfugl and Skarv fields and it is assumed that the company is interested in developing Idun North along with Aerfugl. Idun North discovery well 6507/3-7 proved gas in the Middle Jurassic Fangst Group with estimated recoverable reserves given at the time of 20-105 Bcfg. The Aerfugl field is in development, with the PDO being approved in April 2018. Aerfugl will be a phased development using a total of six subsea wells tied-back to the Skarv FPSO. Phase I (three producers in the southern part of the field) passed concept selection in March 2017. The development will utilise electrically heated flowlines, chemical pumps and scale inhibitor packages for flow assurance and first gas is due in October 2020. Test production from the field was carried out in advance of the PDO submission in order to provide in depth knowledge of the reservoir. The plan for Phase II is yet to be finalised but is likely to consist of two wells in the northern part of the field together with a well on Snadd Outer (PL 212 E) and is tentatively due onstream in Q3 2023. Following completion of the deal, interest in PL 159 D is divided between Equinor Energy AS (36.165% + operator), DEA Norge AS (40%) and Aker BP ASA (23.835%).","Aker BP acquired 23,835% interest in the licences PL 159 D from Equinor (->36,165% + Op, DEA 40%)"
41788,"On 12 February 2019, BP and IEOC were awarded the West Sherban Onshore exploration block (Block 11), Nile Delta onshore basin as a part the Egyptian Natural Gas Holding Co. (EGAS) 2018 bid round closed on 29 November 2018. The companies are committed to drill two wells during the first exploration period. The commitments include an expenditure of USD 18 million and a signature bonus of USD 5 million. Background information The West Sherban Onshore block is part of former Disouq exploration licence (RWE Dea op 50%, INA 50%), relinquished in July 2013. The former operators of the area were IEOC (Eni), Arco & RWE Several wells were drilled in the block including Tafiyah 1 (find some oil and gas), Kafr El Sheikh 1 (gas shows), Sidi Ghazy 1, Tafiyah West 1, Helal 1, Kafr El Sheikh Northeast 1, El Hamul 1, Nidoco 8 and Abadiyah 1 (dry holes). The Abu Madi West and Khilala Northwest fields are not part of the block.","BP and IEOC were awarded the West Sherban Onshore exploration block (Block 11), Nile Delta onshore basin as a part the Egyptian Natural Gas Holding Co. (EGAS) 2018 bid round "
31586,"ONGC Videsh and Uzbekneftegaz (UNG) have signed a co-operation Agreement and a Confidentiality Agreement providing for joint preparation of specific proposals for co-operation through the exchange of information on the investment blocks in Uzbekistan within 4 months. The agreements were signed during President of Uzbekistanâs visit to India on 30 September â 1 October 2018. Uzbekistan offers 22 E&P investment blocks across all its petroleum basins on an open negotiations basis. Background Information This is not the first time that ONGC attempts to enter Uzbekistan. In May 2011, UNG and ONGC signed a co-operation memorandum on a possible 5-year exploration programme for the Middle Syr-Darya area (part of the Syr-Darya Basin). The preliminary studies were supposed to take 6 months, however, there have been no announcements of a concrete deal having been reached. Most of the Syr-Darya Basin is located on the territory of Kazakhstan, and only the basinâs south-western and southern margins fall within Uzbekistan. There are no existing discoveries in the basin in either of the countries. The 2011 agreement also provided for ONGC and UNG to co-operate in increasing production from low productivity wells. The project was to be funded from the Export-Import Bank of Indiaâs USD 2 billion loan to Uzbekistan. In November 2013, ONGC and Petrovietnam Exploration & Production (PVEP) signed an MoU regarding joint development of the Kossor investment block in western Uzbekistan (Daryalyk-Daudan Depression). As part of the document, ONGC was supposed to present its proposals for the project in Q1 2014, however, no progress has been reported regarding this potential deal either. It is understood that PVEP has drilled at least one unsuccessful exploration well in the Kossor block.",ONGC Videsh and Uzbekneftegaz (UNG) have signed a co-operation Agreement and a Confidentiality Agreement providing for joint preparation of specific proposals for co-operation through the exchange of information on the investment blocks in Uzbekistan within 4 months.
56704,"Sundulbari-Agartala Dome lease, onshore Tripura-Cachar Basin, presumed new pool gas discovery, establishes the first Middle Bhuban sand in the block. Background from GEPS.","Sundulbari-Agartala Dome lease, onshore Tripura-Cachar Basin, presumed new pool gas discovery, establishes the first Middle Bhuban sand in the block."
88226,"Woodside is the latest to admit it is on the lookout for potential M&A deals, taking advantage of the current market downturn. While not excluding deals with heavier capital investment, Woodside will favour assets that are producing or close thereto and would prefer operatorships. One such candidate would be increasing its 35% in the Sangomar project in Sénégal, where it has pre-emptive rights over existing (Cairn->Lukoil) or potential deals (Far).","Woodside is the latest to admit it is on the lookout for potential M&A deals, taking advantage of the current market downturn. While not excluding deals with heavier capital investment, Woodside will favour assets that are producing or close thereto and would prefer operatorships. One such candidate would be increasing its 35% in the Sangomar project in Sénégal, where it has pre-emptive rights over existing (Cairn->Lukoil) or potential deals (Far)."
78979,"In March 2020 Total and partners Shell and Mitsui produced an average of 25,000 b/d of oil and 8.5 MMcf/d of gas from the Tempa Rossa oil and gas field in the Gorgoglione exploitation concession. Production started in December 2019 with the testing of the installations and is ramping up since then. The field has a target production rate of 50,000 bo/d from six wells. The Tempa Rossa field, discovered by Fina in 1989, holds 2P reserves estimated at 400 MMbbl of oil (16-22° API) and 200 Bcf of gas in heterogeneous Miocene and Cretaceous limestones reservoirs of the Apulian Platform. Initially scheduled for 2012, the production start-up was delayed numerous times. The produced crude will be routed to the Eni-operated Taranto refinery through the existing 136-km Viggianno-Taranto pipeline (used to transport the oil produced from Eniâs Val dâAgri concession). The final agreement between the group and the Basilicata regional authorities for the launch of commercial oil and gas production was signed on 6 February 2020. Interest in the Gorgoglione exploitation concession is shared between Total E&P Italiana SpA (50% - operator), Shell Italia E&P SpA (25%) and Mitsui E&P Italia B Srl (25%).","Italy, Gorgoglione"
10802,"In late November 2017, Anadarko US Offshore and Venari Offshore acquired a total of 62.5% WI from Statoil Gulf of Mexico in Walker Ridge blocks WR 11 (G36079), WR 55 (G36080), WR 145 (G36082) and WR 189 (G36083), situated in the East Texas Coastal Basin. The transactions are effective as of 1 October 2017. The blocks lie close to the Andarko-owned Coronado oil discovery, located on WR 98, 2km south-west of WR 55. In late June 2017, Anadarko submitted an exploration programme to the BOEM, with ten proposed locations in water depths ranging from 1,809-2,005m, situated 5km south-east of Coronado. Chevron made the initial Coronado discovery in 2013, but then transferred operatorship and its stake in the field to Anadarko. Industry sources suggested that Chevron was never very optimistic by what it saw at Coronado. The discovery well in WR 98 encountered 122m (400 feet) of net pay at a TVD of 9,713m (31,866 feet). Following completion of the transactions, equity in WR 11, WR 55, WR 145 and WR 189 is now shared between Statoil Gulf of Mexico (37.5% WI + Op), Anadarko US Offshore (37.5%) and Venari Offshore (25%).",Not Found
35246,"OKEA confirmed on 15 November 2018 that all of the relevant approvals have been received relating to the companyâs acquisition of Shellâs 44.56% operated interest in Draugen (PL 093 and PL 176) and 12% interest in Gjoa (PL 153). The deal is expected to complete by 30 November 2018. During 2017 the assets contributed around 14% (25,000 boe/d) of Shellâs Norwegian production. The deal is agreed for an initial consideration of USD 556 million (NOK 4.52 billion) with Shell retaining an 80% liability for the total decommissioning costs up to an agreed limit of USD 78 million after tax (NOK 638 million). OKEA will be responsible for the remaining liability. Decommissioning costs for the two assets are estimated to be around USD 120 million after tax (NOK 1 billion). Once OKEA has completed the decommissioning Shell will pay an additional USD 46 million (NOK 375 million) to OKEA. The deal, which was reported by Shell on 20 June 2018, increases OKEAâs net reserves to 53 MMboe. The company is intending to extend the life of Draugen into the 2040âs. The transaction is part of Shellâs global value driven divestment programme initiated following its acquisition of BG in February 2016 in a deal that valued the company at USD 70 billion. The company is aiming to divest USD 30 billion of assets as it seeks to reduce debt and simplify its portfolio. Shell retains a significant presence in Norway operating Ormen Lange and Knarr and partnering in Troll, Valemon and Kvitebjorn. It drilled two exploration wells on the NCS in 2018 (Tyttebaer and Coeus) and was offered operatorship of PL 958 as part of the 24th Licensing Round (see separate article). Following completion of the deal interest in PL 093 and PL 176 will be divided between OKEA AS (44.56% + operator), Petoro AS (47.88%) and Neptune E&P Norge AS (7.56%). Interest in PL 153 will be split between Neptune Energy Norge AS (30% + operator), Petoro AS (30%), Wintershall Norge AS (20%), OKEA AS (12%) and DEA Norge AS (8%).",OKEA confirmed on 15 November 2018 that all of the relevant approvals have been received relating to the companyâs acquisition of Shellâs 44.56% operated interest in Draugen (PL 093 and PL 176) and 12% interest in Gjoa (PL 153). The deal is expected to complete by 30 November 2018.
55105,"QP has agreed with Total to acquire a 10% stake from Total in the Orinduik and Kanuku offshore blocks, Total retaining 15% in the process. Orinduik, 1,835 sq km, is operated by Tullow, partners otherwise Total + EcoAtlantic. Kanuku, 6,530 sq km, is run by Repsol, partners Tullow + Total:","Guyana, Orinduik"
88573,"KrisEnergy accepted the withdrawal request by local partner Palang Sophon Limited (PSL) in the G10/48 concession located in the Pattani Trough, Gulf of Thailand, on 31 July 2020. Upon approval from the Department of Mineral Fuels (DMF), PSL is obligated to pay for the necessary decommissioning costs for the field facilities within the concession, prior to transferring 11% participation interest to KrisEnergy. The reason for withdrawal is likely associated to the global uncertainties related to the coronavirus disease 2019 (COVID-19) outbreak and low oil prices. Upon completion of the deal, KrisEnergy would be the sole effective shareholder for the concession. Previously PSL held the 11% interest following the acquisition of an indirect 14.67% interest in KrisEnergy G10 (Thailand) Ltd, which holds 75% interest in the concession, in February 2015. As of August 2020, KrisEnergy is still offering a farm-in opportunity up to 44.5% participating interests in the concession. The concession contains five oil fields, including the Wassana field that was brought onstream in 2015. The field has been producing from a series of stacked Miocene fluvial sand at a range of 3,250 to 5,000 bo/d in 2019. Production from the field was suspended in June 2020 due to the drop in global oil prices. Background Information The original 18,780 sq km of G10/48 concession was originally awarded to Pearl Oil in December 2006. The concession is situated at the southern section of the Pattani Basin in water depth of 60 m, containing a producing field, Wassana (2009) and four oil discoveries Niramai (2009), Mayura (2010), Nong Yao Southwest 1 (2012) and Rayrai (2015). The Wassana field is one of the most matured assets for KrisEnergy in the Gulf of Thailand. KrisEnergy acquired operatorship in the G10/48 concession from Mubadala (which had acquired Pearl Oil) in May 2014. The last exploration activity in the concession is the drilling of Montha-1 in late-November 2018, targeting the Pattani Sequence III sandstone which comprises thinly stacked layers of alluvial sandstones. Located approximately 15 km west-northwest of the producing Wassana oil field, the well was plugged and abandoned dry. The G10/48 concession is under a 20-year production period which commenced on 7 December 2015. The Wassana Production Area was granted on 9 February 2015 by the Thailand Department of Mineral Fuel (DMF). On 8 December 2015, DMF also approved an Exploration Reserved Area of approximately 1,525 sq km, comprising contiguous and non-contiguous to the Wassana production area, for up to five years. On 30 January 2019, the Exploration Reserved Area received a reduction to 114.4 sq km, almost 60% cutback from the previous reservation area (283 sq km).","Palang Sophon has withdrawn from G10/48 in the Pattani Trough, Gulf of Thailand, its 11% transferring to KrisEnergy"
79710,"On 5 May 2020, Hocol Petroleum, a 100% subsidiary of Ecopetrol, announced that the Bullerengue 3 shallower-pool wildcat (SPW) discovered gas in several sand intervals in a shallower reservoir than the Bullerengue 1 discovery, which produces from Eocene sandstones of the Chengue Formation. It is speculated that the Bullerengue 3 discovered gas in the Miocene-Oligocene sandstones of the Cienaga de Oro Formation. The company indicated that they are doing several production tests since 17 November 2019. The Bullerengue 3 SPW lies in the SSJN 1 Block in the Atlantico Department in the Lower Magdalena Basin. The 920.11 sq km SSJN 1 Block is owned and operated by Lewis Energy with 50% working interest, and non-operating partner Hocol with the remaining 50% working interest since December 2009 when Hocol farmed in. The original 1,672.7 sq km SSJN 1 Block was officially awarded to Lewis Energy in December 2008, and in July 2019, 752.28 sq km were relinquished. Background Information The Bullerengue gas/condensate field was discovered in October 2015 by the Bullerengue 1 new-field wildcat (NFW). The NFW was drilled to a TD of 2,286 m (7,500 ft) where it tested 2.5 MMcfg/d and 50 barrels of condensate in an unreported reservoir. Five other wells have been drilled in the structure: Bullerengue Sur 1 to 4 and Bullerengue SW 1. The Bullerengue Sur 1 exploratory well found 25 m (80 ft) of Eocene Age gas pay over several horizons, Ecopetrol SA announced on 27 December 2019. The field started production in October 2015. In December 2019, Ecopetrol SA announced that Hocol Petroleum Ltd, their 100% owned subsidiary, and Lewis Energy Colombia are evaluating the Lewis Energy-operated Bullerengue SW-1 outpost well on contract block SSJN 1 in the Lower Magdalena Basin. The Bullerengue SW-1 outpost spudded in July 2019 and is located about 3 km southwest of the Bullerengue 1 gas/condensate discovery well.","Bullerengue 3 expl. (Lewis Energy 50 % op, Hocol 50%) in SSJN1 block, in Caribbean, reportedly gas find in prospect shallower than the 2015 Bullerengue-1 discovery now on stream, several intvs encountered, no details. "
71494,"On 6 February 2020, Gazprom Neft-Vostok announced discovery of a new pool at the Urmanskoye field in Tomsk Oblast (Western Siberia). New-pool wildcat Urmanskaya 26 was drilled to 3,660 m in the south-eastern extension of the field in the Archinskiy license. The well tested oil at a rate of 670 b/d from carbonate reservoirs of the Paleozoic basement. The company estimated 3P oil reserves of the pool at 37 MMbbl in-place and 11 MMbbl of recoverable. In 2020, the operator plans to drill four horizontal development wells aiming at speedy development of the new discovery. Urmanskoye, discovered in 1974, is located in the Kaymys-Vasyugan Province. Fourteen pools, mostly linked to stratigraphic traps, are distributed within the 400 m Paleozoic-Lower Jurassic section. Five oil accumulations including the new discovery are localized in the upper portion of a basement (weathering crust) in fractured reservoirs. Initial 2P reserves of the field are estimated at 295 MMbbl of oil. Commercial oil production was started in 2005 and the output reached 9,600 b/d in 2009. Since then, production has been declining.",Gazprom Neft-Vostok announced discovery of a new pool at the Urmanskoye field in Tomsk Oblast. Urmanskaya 26 npw. was drilled to 3 660 m in the SE extension of the field in the Archinskiy license. The well tested oil at a rate of 670 b/d from carbonate reservoirs of the Paleozoic basement. The company estimated 3P oil reserves of the pool at 37 MMbbl in-place and 11 MMbbl of recoverable.
84273,"On 23 June 2020 Summit Petroleum acquired an additional 25% interest in the P2382 licence (block 22/14c) from Ping Petroleum UK and Ping exited the licence. The deal sees Summit take sole interest in the licence. The Mallory discovery, the 22/14b-3 discovery and the K2 prospect are in the 181 sq km licence. The licence was awarded to Summit and Ping in 2018 with both companies holding an equal share and Summit taking operatorship. In March 2019 Summit acquired 25% interest from Ping. The licence is open for farm-out (between 25% and 40%) and it has a drill-or-drop well commitment on the licence. Summit intends to target the drill ready K2 prospect before October 2022 to meet the licence commitment. Other prospects in the block include the Rustler and Rattler prospects. Summit Petroleum Ltd hold sole interest in the licence.","(Central Graben Province) P2382 op. by SUMITOMO (75%), PING PT (25%), Summit Petroleum acquired an additional 25% interest in the P2382 licence (block 22/14c) from Ping Petroleum UK (->0%)."
15691,"United Oil & Gas has announced the completion of the farm-in and the transfer of the 20 per cent interest in the Walton-Morant Licence, offshore Jamaica from Tullow Jamaica to UOG. Further to the announcement of 27 November 2017, the Company confirms that the Petroleum Corporation of Jamaica ('PCJ') has granted its approval to the assignment, assumption of obligations and transfer of the 20 per cent. interest in the Walton-Morant Licence to UOG with the effect from 1st March. Accordingly, Tullow, the operator, has now 80 per cent. interest and UOG 20 per cent. interest in the Walton-Morant Licence. In addition, the Company has been informed by Tullow that it intends to commence acquiring the 3D seismic focusing on the high-graded Colibri lead in March 2018. Tullow's licence offshore Jamaica (Source: Tullow Oil) Original article link Source: United Oil & Gas ","United Oil & Gas has announced the completion of the farm-in and the transfer of the 20 per cent interest in the Walton-Morant Licence, offshore Jamaica from Tullow Jamaica to UOG."
33463,"Wellesley spudded the third of its three back-to-back wells in the Grosbeak area on 27 July 2018. Using the âTransocean Arcticâ S/S for 35/11-21 S in PL 248 I, the company targeted Grosbeak West in the southern part of the field. The well had objectives in the Middle Jurassic Ness (expected at 2,543 m, 2,335 m TVDSS) and Etive (expected at 2,621 m, 2,413 m TVDSS) formations. It was drilled to TD at 2,800 m (2,564 m TVDSS) in the Lower Jurassic Cook Formation and it proved a 90 m oil column (45 m net sandstone) in the Ness and Etive sections with no OWC. The Ness reservoir was tested and flowed at a rate of 6,265 MMbo/d through a 48/64â choke. On 6 September 2018 sidetrack 35/11-21 A was kicked-off. This well investigated the Upper Jurassic Sognefjord Formation (expected at 2,203 m, 1,945 m TVDSS) and Middle Jurassic Fensfjord Formation (expected at 2,292 m, 2,034 m TVDSS) in addition to the Ness (expected at 2,656 m, 2,398 m TVDSS) and Etive (expected at 2,741 m, 2,483 m TVDSS) formations. Wellesley drilled to TD at 2,931 m (2,614 m TVDSS) in the Cook Formation. A 45 m gas column was present in the Sognefjord Formation (20 m sandstone) with no GWC, a 1 m gas column above an 8 m oil column (2 m sandstone) was present in the Fensfjord Formation and a 50 m oil column (15 m sandstone) was proven in the Ness Formation with no OWC. Total recoverable reserves (from the NPD) are estimated at 50-120 MMbo plus 250-413 Bcfg, a significant increase on the previous estimate. The well was abandoned on 17 October 2018. New licence PL 248 I was carved out from Statoilâs PL 248 C in December 2017 and Wellesley subsequently took over Statoilâs 30% interest and operatorship. It covers the western part of Grosbeak. The eastern part lies in newly-awarded PL 925 which Wellesley acquired in APA 2017. Grosbeak was drilled in 2009 by Wintershall with well 35/12-2. Oil and gas was encountered in the Sognefjord Formation and oil was present in the Middle Jurassic Brent Group. Estimated recoverable reserves (based on the discovery well) were calculated at 35-190 MMboe. In 2011 the find was appraised by 35/12-4 S and 35/12-4 A. A 40 m oil column was proven in a good quality Ness Formation reservoir in 35/12-4 S and the well tested at 5,032 bo/d, with associated gas, through a 44/64â choke. The 35/12-4 A sidetrack investigated the upper part of the Ness Formation but no hydrocarbons were present. Interest in PL 248 I is divided between Wellesley Petroleum AS (60% + operator) and Petoro AS (40%).","Norway, PL 248"
66782,"According to reports in early-December 2019, the government of Neuquen Province has awarded a new 35-year unconventional exploitation concession for the Aguila Mora block to Vista Oil & Gas on 29 November 2019. Commitments for the new license include a two-year pilot plan targeting shale oil from the Vaca Muerta Formation for USD 32 million. Specifically, Vista is expected to reactivate three existing wells, drill two new horizontal wells, and construct new surface facilities as part of the program. The company operates the block with 90% interest, with provincial company GyP Neuquen holding the remaining 10% stake. Aguila Mora block covers 97 sq km of land in the Northeast Platform part of Neuquen Basin. The block is situated adjacent to ExxonMobilâs Bajo del Choique - La Invernada block where the Vaca Muerta shale is also being developed. Aguila Mora area includes the Aguila Mora shale oil and gas field that was discovered and put on-stream in August 2013. The field produced over 189 Mbo and 249 MMscfg, along with 129 Mb of water, from Vaca Muerta Formation before it was temporarily shut-in in late-2015. Background Information Vista acquired the Aguila Mora block from Shellâs Argentinean subsidiary, O&G Developments, in October 2018. The transaction was executed as an addendum to a prior agreement from September 2018 where Vista assigned 35% of its 45% non-operating interest to Shell on the latterâs operated Coiron Amargo Sur Oeste block.","Argentina, Coiron Amargo Sur Oeste"
35445,"It has been reported that INEOS is in talks to acquire ConocoPhillipsâ UK oil and gas portfolio. The latter holds interests in a number of producing fields throughout the UK, across the West of Shetlands, Northern North Sea, Moray Firth, Central North Sea, East Irish Sea and Southern North Sea. ConocoPhillips has also recently been drilling an infill exploration well at its Jasmine field. The potential deal has been rumoured to be worth upwards of GBP 3 billion and the companies have reportedly signed a three month exclusivity agreement.","It has been reported that INEOS is in talks to acquire ConocoPhillipsâ UK oil and gas portfolio. The latter holds interests in a number of producing fields throughout the UK, across the West of Shetlands, Northern North Sea, Moray Firth, Central North Sea, East Irish Sea and Southern North Sea"
56109,"Canada-based Vermilion Explorationâs second quarter 2019 report, recently released, states that its Croatian subsidiary Vermilion Zagreb Exploration d.o.o. tested new-field wildcat Ceric 1 in the Sava 10 (SA-10) licence in northeastern Croatia. The well yielded gas flow at a rate of 6.2 MMcf/d - stabilized flowing pressure of 1,376 psi on a 0.37â choke â from 1,167-1,177 m zone within the Upper Miocene Pannonian sandstone succession. The 18-hour flow test followed upon a one-hour test following perforating that delivered 15.0 MMcf/d (stabilized flowing wellhead pressure of 851 psi on a 0.86â choke). Both tests were formation water-free. The well, solely operated by Vermilion, encountered net 10 m (32 feet)-thick reservoir in two Upper Miocene horizons (1,020-1,022 m and 1,167-1,177 m), with only the lower zone tested. Ceric 1, started in mid-June 2019, is located in the Vukovar-Srijem county, approximately 100 km east-southeast of the capital city of Zagreb. In a geological sense, the area falls within the Slavonian Sub-basin, tectonic unit of the Pannonian Basin. The well was believed to be targeting the Pannonian-age (Miocene) series at shallow depths (+/-1,200-1,300 m). Vermilion reaffirmed in May 2019 it is planning to drill the Ceric 1 exploration well - the spud of the well was expected on 17 June 2019. The drilling of the well was expected to take approximately 30 days. The news on the successful testing of Ceric 1 was disclosed on 29 July 2019. Background Information The Sava 10 contract was awarded to Vermilion on 10 June 2016 following the 1st onshore licensing round. The contract has a five-year exploration phase and a 25-year production phase. The tract is situated along the border with Bosnia and Herzegovina and Serbia. The Sava 10 block holds three oil fieldsin the central-eastern sector - the Djeletovci, Ilaca and Privlaka fields (fenced off) â producing oil from the reservoirs in the Middle Miocene Vukovarska Formation. All three fields were put onstream in 1984. There is also the Vukovar oil field in the northern part of the licence, discovered in the mid-fifties and soon abandoned after producing an estimated 15,000 bo and deemed non-commercial, holding the reservoir in the Middle Miocene (Vukovarska Formation) below 1,500 m. The latest exploration activity in the block dates back to April-May 2018, when Vermilion conducted a 2D seismic survey over the Sava 10 licence. Industry sources suggested that the survey delivered good image of the subsurface and the operator successfully interpreted several prospects for future drilling.","Vermilion Explorationâs second quarter 2019 report, recently released, states that its Croatian subsidiary Vermilion Zagreb Exploration d.o.o. tested new-field wildcat Ceric 1 in the Sava 10 (SA-10) licence in northeastern Croatia. The well yielded gas flow at a rate of 6.2 MMcf/d - stabilized flowing pressure of 1,376 psi on a 0.37â choke â from 1,167-1,177 m zone within the Upper Miocene Pannonian sandstone succession. "
21461,"AE-0020-M-Okom-03 block, offshore Sureste Basin, WD ca. 80m, P&A results n/a at TD 4,765m mid-May â18, Prospector II JU. Targets Cret. + Jurassic.","Manik-101AEXP op. by Pemex (100%) in AE-0020-M-Okom-03 block, offshore Sureste Basin, WD ca. 80m, P&A results n/a at TD 4,765m mid-May â18, Prospector II JU. Targets Cret. + Jurassic."
14794,"PL 340 north of Bøyla, oil encountered, preliminary evaluation 30-60 MMboe, higher that the pre-drill estimate of 3 -21 MMboe, Transocean Arctic SS. Appraisals 24/9-12 A + B may follow. Aker BP (op), partners Point Resources + Lundin. ","024/09-12 (Frosk) op. by Aker BP (65%, Point Res. 20%, Lundin 15%) in PL 340 licence, an oil discovery with a preliminary resource estimate of between 30 and 60 Mmboe."
29170,"South East Siwa bidding block (Northern Egypt Basin/Qattara Ridge) Former operators Shell, Apache Part of the former Badr El Din exploration block (Shell op, 100%): relinquishment after expiry of contract (June 1990). West Ghazalat exploration block relinquished by Apache Wells drilled in the block Northern Egypt Basin Ghazalat West D-1 abandoned in July 2013 by Apache at TD of 4,648 m. Targeting Cretaceous, Jurassic and Paleozoic Ras Qattara West 1 abandoned in July 1989 by Conoco at 4,690 m. Targeting the Jurassic Sobek 1 and Sobek 2 targeting Cretaceous and Jurassic Qattara Ridge Gahzalat 1 P&A, dry in 1959 by Sahara Petroleum Co at 2,941 m in the Cambrian. Target Cretaceous.",Egypt Egyptian Natural Gas Holding Co (EGAS) offering South East Siwa bidding block
63521,"On 1 November 2019, Chevron USA was awarded Mississippi Canyon blocks MC 798 (G36783) and MC 842 (G36784), located in the Louisiana Coastal Basin. Both blocks 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. Chevron USA accounted for 17 of the high bids, worth a total of US$ 22.6 million. Following formal award, Chevron USA is the operator and sole interest-holder (100% WI + Op) in MC 798 and MC 842.",Not Found
31667,"Columbus Energy announced on 8 October 2018 that the purchase of Steeldrum Oil Company assets in Trinidad and Tobago has been completed. Columbus Energy announced on 13 July 2018 that it signed a Purchase and Sale Agreement (SPA) for USD 5.8 million to acquire Steeldrum Oil Company assets in the Trinidad Basin close to the Columbusâ current assets. Innis-Trinity Field: 100%, production 120-150 bo/d, 4 MMbl reserves South Eris Field: 100%, production 80-100 bo/d, 1.6 MMbbl Cory Moruga Development Project: 83.8%, expected recoverable reserves 1.1 MMbbl Basin Names Contract Name Block Name Operator Name / Interest Pct. Field Name Award Date Disc Date Soldado Sub-basin (Trinidad Basin) Cory (Rock Dome) Cory E/2 , & Cory E/1 Touchstone Exploration Inc (16.2%), Steeldrum Oil Company Inc (83.8%)* Carapal Ridge 01-Jul-1970 2001 Cory E/2 , & Cory E/1 Moruga West-Rock Dome 15-Jul-1957 Cory E/2 , & Cory E/1 Snowcap 1 15-Dec-2010 Cory F   Southern Range Uplift (Trinidad Basin) Cory D          Columbus Sub-basin (Trinidad Basin) Inniss-Trinity Inniss-Trinity Steeldrum Oil Company Inc (100%)* Moruga North-Inniss-Antilles-Trinity 01-Dec-2009 15-Sep-1956        Trinidad Basin~Southern Range Uplift (Trinidad Basin) South Erin South Erin Steeldrum Oil Company Inc (100%)* South Erin 01-Jun-1998 15-Apr-1988        * Operator  According to the press release, Columbus has been granted with the acquisition a first priority use of two rigs at market rates, which the company will use for the planned exploration activity in the South West Peninsula. The SPA is subject to certain regulatory, joint venture partner, and third-party approvals. Closing is expected in 4Q 2018. On 20 November 2015 Rex International Holding Ltd (38.6%) signed an agreement with West Indian Energy Holding AS (60.14%) and GELCO Energy Inc. (3%) to merge their assets in Trinidad and Tobago and create a new company â Steeldrum Oil Company Inc. In addition to the assets that the companies will bring in to the merger, Rex and West Indian will make a cash contribution of USD 1 million each, less net cash which is estimated to amount to USD 0.3 million and USD 1.03 respectively. Innis-Trinity Block : Rex International Holding (RIH), a subsidiary of Rex Caribbean Oil Co., signed an agreement with Petrorin to farm-in the block â 100%. South Erin Block:  On 23 April 2014, Rex International Holdingsâ announced that through its 64.17 % ownership in license holding company Caribbean Rex Limited, it acquired the remaining 25% interest in the Jasmin Oil and Gas Limited which holds a 100% interest in the block Cory Moruga Block: As of 23 February 2015, Rex International Holding Ltd announced that an indirect subsidiary has increased the companyâs interest in the block from 20% to 83.8% via the acquisition of all the outstanding shares of Parex Resources (Trinidad) Limited for an aggregate consideration of USD1.5 million.",Columbus Energy announced on 8 October 2018 that the purchase of Steeldrum Oil Company assets in Trinidad and Tobago has been completed. Columbus Energy announced on 13 July 2018 that it signed a Purchase and Sale Agreement (SPA) for USD 5.8 million to acquire Steeldrum Oil Company assets in the Trinidad Basin close to the Columbusâ current assets.
66795,"On 1 December 2019, Equinor Gulf of Mexico (formerly Statoil) was awarded Alaminos Canyon blocks AC 31 (G36734) and AC 75 (G36735). 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. Equinor Gulf of Mexico accounted for 23 of the high bids, worth a total of US$ 16.8 million. Following official award, Equinor Gulf of Mexico is now the operator and sole interest-holder (100% WI + Op) in AC 31 and AC 75.",Not Found
45857,"Oil Search has recently signed for a 50.07% interest from sole holder ExxonMobil in PPL 569, 150,085 sq km on the Eastern Plateau in WD up to 5,000m. The deal is yet to be approved by the authorities. PPL 569 commitments call for 1,000 sq km of 3D seismic by late 2020.","Oil Search is acquiring a 50.07% interest in PPL 569 from ExxonMobil (->49,93%) with details of the transaction undisclosed. "
80320,"DigOil is looking to dilute its holding in block III, shared 32:68 with Efora Energy under the Semliki Energy banner, partner state SNH. The 1,602-sq km permit lies in the Nord-Kivu province, East African Rift System. Former licence holder Total could be a contender. 2-3 explo wells are planned in the N. part of the block, Okapi, Gorille + Genette prospects identified.","DigOil is looking to dilute its holding in block III, shared 32:68 with Efora Energy under the Semliki Energy banner, partner state SNH. The 1,602-sq km permit lies in the Nord-Kivu province, East African Rift System. Former licence holder Total could be a contender. 2-3 explo wells are planned in the N. part of the block, Okapi, Gorille + Genette prospects identified."
25593,"Woodside has plugged and abandoned wildcat Dhana Hlaing 1 in Block A-7, located in the southern part of the Rakhine Basin, on 18 July 2018. Well results have not been reported, as further assessment is underway. The well was drilled to a TD of 4,500 m, slightly shallower than the PTD of 4,526 m. Dhana Hlaing 1 was spudded on 26 June 2018 using Transoceanâs âDhirubhai Deepwater KG2â D/S. As of early July 2018, operations were ongoing at a drilled depth around 2,800 m. Dhana Hlaing 1 is located in the western part of Block A-7, at a water depth of 2,057 m. The well likely targeted a dry gas prospect within Pliocene turbidite sandstones. Analogy with previous discoveries made in the adjacent Block A-6 to the north (Shwe Yee Htun 1, Pyi Thit 1) suggests large prospective resources, estimated by the operator to exceed 100 MMboe. The âDhirubhai Deepwater KG2â was hired by Woodside in November 2017. The firm five-month contract will run from May to October 2018. Dhana Hlaing 1 is the second well in the campaign, following the Aung Siddhi 1 gas discovery in block AD-1, located in the northern part of the basin. A preliminary cost estimation for the drilling campaign in Block A-7, as of December 2017, was at approximately USD 60 million. Water depths in the area range from around 200 m in the eastern part of the block, to more than 2,000 m in the west. The turbidite plays targeted in the southern Rakhine Basin are interpreted to derive from the paleo-Irrawaddy fluvial system, unlike the northern part of the basin (Shwe complex, Thalin) where the terrigenous influx is derived from the Ganges-Brahmaputra fluvial system. The western area of Block A-7 is covered by 2D and 3D seismic data acquired between late 2015 and early 2016. In May 2017, Woodside reported a plan for an additional 3D seismic acquisition in the eastern sector of the block. Woodside is the operator of Block A-7 with 45% interest. The other participants are Shell (formerly BG Group) with 45% interest and MPEP (a subsidiary of local company MPRL) with 10%. Background Information Myanmar Oil and Gas Enterprise (MOGE) signed Production Sharing Contracts (PSCs) for blocks A-4, A-7, AD-2 and AD-5 with Woodside Australia, BG Group and MPRL Pte Ltd on 20 March 2015. A new acquisition of 3D seismic data is included as a work commitment for each block. Values of total commitment work for four blocks are estimated at USD 1.1 billion. The signing of the PSCs was the result of the 2013 Myanmar Offshore Bid Round. From November 2015 to April 2016, Woodside acquired 3D seismic data over the western part of block A-7 and adjacent blocks AD-5 and A-6. The survey (âThazin 3Dâ) was conducted using PGSâs âRamform Titanâ survey vessel. A total of approximately 14,000 sq km of 3D seismic data were acquired. An additional 2D seismic survey (âSabae 2Dâ) was conducted over block A-7 in April 2016, consisting of 1,295 km of 2D seismic data. In December 2016, Woodside conducted a seabed survey over blocks A-7 and AD-5, comprising multi-beam echosounder survey and sea floor coring. One exploratory well, A-7 1, has been drilled in the shallow water portion of Block A-7. The well, drilled in 1976 by Cities Service Co, was plugged and abandoned as dry, without testing.","Dhana Hlaing 1 in Block A-7, P&A, results have not been reported, as further assessment is underway. Dry well most probably. "
27761,"Siwa block, W. Desert, drilled and P&A between 4-late Jun â18, TD 4,572m (Desouqy fm), ST-4 rig. Targets Safa + Desouqy. Apache (op), partners Tharwa + Sinopec.","Siwa M-1 (Ic 09-2) nfw Siwa block, W. Desert, drilled and P&A between 4-late Jun â18, TD 4,572m (Desouqy fm), ST-4 rig. Targets Safa + Desouqy. Apache (op), partners Tharwa + Sinopec."
67696,"PPL 242, Cooper Eromanga, drilled 17 Nov â 10 Dec '19, susp oil at TD 4,235m. Senex (op), partner Beach subs.",Growler NE-2 appr Growler NE-2 appr
30867,"On 28 September 2018, Petrobras was granted a preliminary award for the Sudoeste de Tartaruga Verde block through the 5th PSC Pre-Salt Bid Round after being the high bidder for the block. Petrobras paid a fixed bonus of USD 17.50 million at USD 1.00 to BRL 4.00 exchange rate and has a first exploration period financial guarantee of USD 62.50 million to cover the cost of the one well drilling commitment. Petrobras offered the minimum state take of 10.01% and won the block as there were no other bidders. Petrobras has 100% working interest in the PSC contract. The PSC contract has a seven year exploration period. The local content is 55% for the exploration phase and 65% for the development phase for the block.","On 28 September 2018, Petrobras was granted a preliminary award for the Sudoeste de Tartaruga Verde block through the 5th PSC Pre-Salt Bid Round after being the high bidder for the block. "
14858,"Kafra block, Seguedine Rift in Chad Basin, spudded Dec â18, reportedly discovery of some sort (âhydrocarbons encounteredâ). ","Kafra 1 op. by Sonatrach - Sipex (100%) in Kafra block, âhad encountered hydrocarbonsâ - local media reported."
76633,"Aker BP, operator of PL 1008, has concluded the drilling of wildcat well 6506/5-1 S. The well was drilled about 50 kms southwest of the Skarv field in the Norwegian Sea and 210 kms west of Brønnøysund. The objective of the well was to prove petroleum in Upper Cretaceous reservoir rocks (the Lysing Formation). Well 6506/5-1 S encountered a total gas column of about 15 metres in the Lysing Formation, of which 10 metres of sandstones of very good reservoir quality. Deeper in the Lysing Formation, about 25 metres of net water-bearing reservoir rocks were encountered, mainly of moderate reservoir quality. Preliminary estimates place the size of the discovery between 1.0 and 2.4 billion standard cubic metres (Sm3) of recoverable gas. The licensees will evaluate the discovery together with nearby prospects with regard to further follow-up. The well was not formation-tested, but extensive data acquisition and sampling have been carried out. This is the first exploration well in production licence PL 1008. The licence was awarded in APA 2018. Well 6506/5-1 S was drilled to a measured depth of 3225 metres and a vertical depth of 3166 metres below sea level, and it was terminated in the Lange Formation in the Lower Cretaceous. Water depth at the site is 409 metres. The well has been temporarily plugged and abandoned. Well 6506/5-1 S was drilled by the Deepsea Nordkapp drilling facility, which will now drill observation well 25/4-K-7 H on the Alvheim field in the central part of the North Sea, where Aker BP is operator. Original article link Source: NPD","6506/05-01 S (Nidhogg) nfw. (Aker BP 60% op, Wellesley 40% ) in PL 1008 block, Skarv area near Ãrfugl, WD=442m, P&A at TMD=3225 m (3198m TVD), minor gas discovery , Target Lysing Fm gas-cond. A total gas column of about 15m in the Lysing Fm, of which 10m of sst are of âvery good reservoir qualityâ,"
81182,"Kotri North 2568-21 EL, Kirthar Fold Belt, Sindh, susp at TD 4,136m in mid Dec '19, re-entered for rigless testing during 1Q, non-commercial gas and suspended again. Target L. Goru. UE (op), partner PPL.","Pakistan (Indus B.) Unarpur 2 op. by UNITED EN (60%), PPL (40%) in Kotri North 2568-21 EL block, total depth 4136 m susp at TD 4,136m in mid Dec '19, re-entered for rigless testing during 1Q, non-commercial gas and suspended again"
85689,"Cairn confirmed in its full year announcement in March 2020 that it had agreed an asset exchange agreement with Shell involving two licences P2379 (blocks 22/11b, 22/12b, 22/16b and 22/17c) and P2380 (block 22/12d). The exchange concerning the two licences was complete on 23 June 2020. In the UK, Cairn operates through its wholly owned subsidiary - Nautical Petroleum. Shell has acquired a 50% interest in licence P2379 which contains the Diadem prospect, the licence has a firm well commitment that is expected to be drilled in 2022. In exchange for the P2379 interest, Cairn has acquired a 50% interest in licence P2380 from Shell. The P2380 licence has a firm well commitment well on the Jaws prospect, which is expected to be drilled in 2H 2021. The Jurassic Fulmar sandstone play is prolific in the area and if the wells are successful then they could be tied into the Nelson facilities. The commitment well for Jaws is required to be drilled to a depth of 3,730 m or the base of the Upper Jurassic. P2380 was awarded in the 30th Offshore licensing round which focussed on âmatureâ areas of the North Sea and comprises of just one block â 22/12d. Any potential discoveries could be used to extend the field life at Nelson. Shell also picked up licence P2377 in the 30th Round which also contains a firm commitment well on a prospect known as Orlov and is within reach of a tie-back to Nelson. In September 2019 Zennor Petroleum and ONE-Dyas pulled out of licence P2379 leaving Cairn as the sole participant. The licence comprises of four blocks â 22/11b, 22/12b, 22/16b and 22/17c and contains three discoveries 22/11b-3 (Lima), 22/12a-10 (Phoenix) and 22/16-6 (Dalziel). The first of the three discoveries was 22/12a-10 (Phoenix) back in 2004. The discovery was made by Shell as a near field exploration project for the Nelson facilities. The discovery was appraised in 2010 with well 22/12a-12 which confirmed oil bearing sands within the Forties Sandstone Member within a relatively simple and low risk 4-way dip closed structure. A sidetrack of the appraisal well 22/12a-12Y was kicked-off and penetrated the reservoir outside of the structure and did not encounter any hydrocarbons. 22/11b-13 (Lima) was discovered in 2008. The well targeted three Jurassic pods. Of the three pods, only one (Fulmar 1) contained oil which is stratigraphically trapped within thin sandstones pinching out before the pod. The most recent discovery was 22/16-6 (Dalziel) in 2015. This was drilled by ENGIE targeting the Upper Jurassic Fulmar prospect. It encountered oil and tested in excess of 8,000 boe/d. Following completion of the deals interest in the licences will be held by 50% each between Cairn and Shell.","United Kingdom (Central Graben Province), Cairn confirmed in its full year announcement in March 2020 that it had agreed an asset exchange agreement with Shell involving two licences P2379 (blocks 22/11b, 22/12b, 22/16b and 22/17c) and P2380 (block 22/12d). "
13511,"On 29 January 2018, Petrobras with 100% working interest was granted an official award by the ANP for the PAR-T-175 block in the onshore Parana Basin from the ANP Round 14. Â Â ",Petrobras with 100% working interest was granted an official award by the ANP for the PAR-T-175 block in the onshore Parana Basin from the ANP Round 14.
17598,"On 27 March 2018, PEMEX with 100% working interest was granted a preliminary award for the 471 sq km Area 29, AS-CS-13 block from the CNH-RO3-LO1/2017 Bid Round. The final official contract signature award is to take place within 90 days or 1 July 2018. The company bid the maximum state take of 65.00% over the minimum of 22.5% for the Area 31 block and a work units factor of 2 equivalent to two wells. Additionally the company submitted a tie-break bonus of USD 13.08 million. There were three other bids for the block. The second highest bidder was the consortium of DEA, Premier, and Sapura who bid 65% state take and 1 additional work units factor.  The consortium did not offer a tie-break bonus.  ","PEMEX with 100% working interest was granted a preliminary award for the 471 sq km Area 29, AS-CS-13 block from the CNH-RO3-LO1/2017 Bid Round. "
48986,"S. part of Ebes block, Bihar sub-basin in E. Hungary, drilled 2Q â19, TD 2,045m (Algyo fm), results yet n/a. Target assumed L. Pannonian sst.","Hajdúbagos 1 in S. part of Ebes block, Bihar sub-basin in E. Hungary, TD=2045m (Algyo fm), results yet n/a. Target assumed L. Pannonian sst."
9411,"Laizhou Bay Sag, S. Bohai Gulf Basin, WD 20m, ops terminated 15 Nov â17, Bohai 4 JU. KL 6-6-2 appr was spudded back-to-back, indicating a likely successful outcome of the wildcat. Targets Dongying + Shahejie fmâs.",China (Bohai Gulf B.) Kenli 6-6 (Bo) 1 op. by CNOOC TJ (100.0%) in Bonan block
65846,"EnQuest reports the award of PM 409 in partnership with Petronas 15%. The 1,700-sq km block lies off Peninsular Malaysia in WD 70-100m. An initial 4-year term applies to the PSC with commitments to 1 well. EnQuest is already involved in Malaysia through its PM 8E + Tanjong Baram contracts. PM 409 was one of several shallow water blocks offered earlier this year under a Petronas round (DEA 26 Apr '19 map extract refers):","Malaysia, not found"
52529,"The list of awardees for 18 blocks of the 23 offered under OALP-III is now available. ONGC got 7, OIL 6 and Vedanta 5. Block list + details from GEPS. Likewise for OALP II, where 14 blocks found takers (OIL 6, Vedanta 5, ONGC 1, IOC 1 and Reliance â BP 1. Details from GEPS II.","The list of awardees for 18 blocks of the 23 offered under OALP-III is now available. ONGC got 7, OIL 6 and Vedanta 5. Block list + details from GEPS. Likewise for OALP II, where 14 blocks found takers (OIL 6, Vedanta 5, ONGC 1, IOC 1 and Reliance â BP 1."
43428,"Further to DEA 27 Feb â19: Visund A platform in PL 120, explo extn of devt well 34/8 A-36H, TMD 6,068m (3,318m TVD), 115m oil column in the U&L parts of the Statfjord group, 17-20m net, OWC in the L. Statfjord group at ab. 3,170m, 12-28 MMbo recoverable, P&A 22 Feb â19. Equinor (op), partners Petoro, COP + Repsol.","034/08-18S (Telesto) (Equinor op. 59,07%, Petoro 16,93%, COP 13%, Repsol 11%) Visund A platform in PL 120, 115m oil column in the U&L parts of the Statfjord group, 17-20m net, OWC in the L. Statfjord group at ab. 3170m, 12-28 MMbo recoverable."
72471,"ConocoPhillips has abandoned its third back-to-back exploration well using the âLeiv Eirikssonâ S/S in the Balder area. 25/7-9 S was spudded on 12 January 2020 and targeted Hasselbaink, an injectite prospect similar to those with which Aker BP has had success in recent months slightly further to the west. The top of the injectite reservoir was expected around 1,700 m TVD in the Eocene and partner Lundin quoted potential reserves of 45 MMboe. Hasselbaink lies 3 km southeast of Enniberg and 9 km southeast of Busta - the two wells which ConocoPhillips drilled immediately prior to Hasselbaink. 25/7-9 S was drilled to TD at 1,980 m (1,895 m TVDSS) in the Paleocene Sele Formation. The well is a dry hole, although two thin (1 m) Hordaland Group sandstones contained some shows. It was plugged and abandoned on 15 February 2020. Aker BPâs Frosk, Froskelar Main, Froskelar Northeast and Rumpetroll discoveries (made in 2018 and 2019) were all injectite prospects. Paleocene Heimdal / Hermod Formation sands were remobilised and injected into the Eocene Hordaland Group. Combined estimated reserves are around 100-200 MMboe. Interest in PL 917 is held by ConocoPhillips Skandinavia AS (40% + operator), Lundin Norway AS (20%), Suncor Energy Norge AS (20%) and Var Energi AS (20%).","025/07- 09 S (Hasselbaink) nfw. (ConocoPhillips 40% op, Lundin 20%, Suncor 20%, VÃ¥r Energi 20%) in PL 917 block, Balder area, P&A dry (was targeting Eocene injectities and intersected 2 thin sst layers of about 1m in the Eocene Hordaland group, with very good reservoir properties and traces of petroleum) at TMD=1955m in Sele Fm. WD=126m. "
66431,"Chauk field area in IOR-2 block, Central Burma Basin, northernmost well in structure, P&A results n/a mid-Nov '19. PTMD was 1,113m, co. ZJ 450 rig.","Chauk L-145 appr Chauk field area in IOR-2 block, Central Burma Basin, northernmost well in structure, P&A results n/a mid-Nov '19. PTMD was 1,113m,"
77458,"NAM have discovered gas in the Spijkenisse-Intra prospect that was drilled by the Spijkenisse Oost-4 exploration well in the Botlek III licence. According to NAM's work schedule, if the discovery contains sufficient gas volumes the discovery well could be put into production at the end of April 2020. On 13 March 2020 NAM spudded the Spijkenisse Oost-4 exploration well and the drilling operations were complete on 13 April 2020. The DrillTec ""Synergy II"" rig was used for the work. Spijkenisse-Intra is a small tilted fault block between the producing Spijkenisse-Oost and the suspended Spijkenisse West gas fields. The well was deviated to the southwest from the Spijkenisse Oost well pad to target gas in the Triassic Bunter Sandstone Formation that is prognosed at approximately 2,540 m TVD. The prospect has an estimated free water level at 2,590 m TVD and, unlike Spijkenisse-Oost and Spijkenisse-West, an oil leg is not expected. Production was forecast to commence in 2019 and continue until 2026 in the high case or until 2021 in the mid case. The high case recoverable gas forecast is 8 Bcfg. Spijkenisse Oost was discovered in 1990 by exploration well Spijkenisse Oost ST1 and it was brought onstream in October 2006. The field has a gas column and a short oil column in the Upper and Middle Bunter Sandstone Formations. The crest of the structure at Upper Bunter Sandstone level is at approximately 2,400 m TVDSS with the GOC at 2,474 m TVDSS and the FWL at 2,482 m TVDSS. In 2013 it was forecast that the field would produce until 2020 in the mid case. Spijkenisse West was discovered in 1992 by Spijkenisse West 1, which is approximately 4 km west from the Spijkenisse Oost discovery well. The field was producing gas through the Spijkenisse Oost-3 well from 2006 until 2016. The field contains gas and a short oil column in the Middle and Upper Bunter Sandstone reservoir. The Upper Bunter Sandstone crest is interpreted at 2,498 m TVDSS, the GOC is at 2,590 m TVDSS and the FWL at 2,597 m TVDSS. The Botlek III licence is held by NAM (50% + operator) and Energie Beheer Nederland BV (50%).","Spijkenisse Oost 4 expl. (NAM (a 50/50 JV between Shell and ExxonMobil) 50% op, EBN 50%) in Spijkenisse-Intra gas prospect (Bunter sst), Botlek III block near Rotterdam in Zuid Holland, commercial gas disc. PTD was 2 540m."
69976,"On 20 January 2020, Shell, Petronas and the Egyptian Natural Gas Holding Company (EGAS) signed agreements with the Egyptian Ministry of Petroleum and Mineral Resources for E&P activities in two offshore blocks located in the Nile Delta Basin, Mediterranean Sea. The first agreement covers activities in the North El Fanar offshore block. It states minimum investment expenditures of USD 129 million and includes a signature bonus of USD 3 million for the drilling of an exploration well. The block, which covers an area of 2,264 sq km was granted to Shell and Petronas in February 2019 following the EGAS International 2018 Bid Round. The first agreement covers activities in the North Sidi Gaber offshore block. It states minimum investment expenditures of USD 180 million and includes a signature bonus of USD 10 million for the drilling of three exploration wells. The block, which covers an area of 2,040 sq km was granted to Shell and Petronas in February 2019 following the EGAS International 2018 Bid Round.","Shell (25% op, Petronas 25%, EGPC 50%) was awarded: N. El Fanar Offshore and North Sidi Gaber Offshore blocks."
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.","Algeria, Zemlet El Arbi (Dev)"
56533,"W-D is looking to farmout up to 50% in licence 9/16*,  382 sq km in the Sogne Basin (W. Danish North Sea), currently Wintershall Dea (op, 50%), partners ONE-Dyas + Danish North Sea Fund. It is recalled the Vibe-1 HPHT nfw is planned here 2020. * blocks 5504/3a, 5604/22c, 26b, 26c, 27a, 27b + 31a.","W-D is looking to farmout up to 50% in licence 9/16*, 382 sq km in the Sogne Basin (W. Danish North Sea), currently Wintershall Dea (op, 50%), partners ONE-Dyas + Danish North Sea Fund. It is recalled the Vibe-1 HPHT nfw is planned here 2020. * blocks 5504/3a, 5604/22c, 26b, 26c, 27a, 27b + 31a."
37149,"On 7 December 2018, it was announced that Turkiye Petrolleri A.O. (TPAO) had been awarded a new exploration licence, M40-D, on 30 November 2018. The licence was granted with a five year term and covers an area of approximately 514 sq km in the Southeast Turkey Zagros Fold Belt and the SE Turkey - North Syria Platform. TPAO will be 100% owner and operator of the licences. TPAO had filed an application for the licence on 27 March 2018.","Turkey, M40-D"
74369,"On 27 February 2020, the Federal Agency for Subsoil Use held an auction for four blocks in Orenburg Oblast (Volga-Ural Province). About 20 companies submitted applications and the winning bids were offered by Neftisa, Rosneft, Zarubezhneft and UDS Neft. Winners of the auction will obtain 25-year E&P licenses. Details of the offer are as follows: The Yuzhnyy block covers 510 sq km and encompasses the Teplovskoye and Uralskoye gas fields with combined 2P reserves estimated at 47 Bcf. Hydrocarbon resources (category D1) of the block are estimated at 12 MMbbl of oil and 86 Bcf of gas. The starting price amounted to RUB 43.8 million (USD 0.67 million). Neftisa-subsidiary Sladkovsko-Zarechnoye, competing against Tatneft-Samara and Belkamneft, won the auction with the offer of RUB 48.18 million (USD 0.74 million). The Babichevskiy block covers 392 sq km. Hydrocarbon resources (category D1) of the block are estimated at 30 MMbbl of oil and 58 Bcf of gas. The starting price amounted to RUB 6.85 million (USD 0.11 million). Rosneft-subsidiary Orenburgneft, competing against 15 companies, won the auction with the offer of RUB 1,507 million (USD 23.2 million). The Novobarabanovskiy block covers 272 sq km. Hydrocarbon resources (category D1) of the block are estimated at 20 MMbbl of oil and 51 Bcf of gas. The starting price amounted to RUB 6.05 million (USD 0.09 million). UDS Neft, competing against 14 companies, won the auction with the offer of RUB 1,204.555 million (USD 18.5 million). The Turgayskiy block covers 96 sq km. Hydrocarbon resources (category D1) of the block are estimated at 8 MMbbl of oil. The starting price amounted to RUB 2.05 million (USD 0.03 million). Zarubezhneft-Dobycha Samara, competing against 8 companies, won the auction with the offer of RUB 81.18 million (USD 1.25 million).","Neftisa winning rights to Yuzhnyy block (510km²), Turgayskiy block (96²km) won by Zarubezhneft-Dobycha Samara, Babichevskiy block (392km²) won by Rosneft-sub Orenburgneft and Novobarabanovskiy block (272km²), won by UDS Neft."
60893,"On 14 October 2019 Energean Oil and Gas announced that, subject to the completion of its acquisition of Edison Exploration and Production S.p.A, it has subsequently entered into a Sale and Purchase Agreement (SPA) with Neptune Energy Group Holdings Ltd for Neptune to acquire Edison's UK and Norwegian subsidiaries. Cash consideration for the deal is an initial USD 250 million and it will have an effective date of 1 January 2019. A further consideration of USD 30 million could be paid to Energean if the Glengorm discovery (by the end of 2025) or the Isabella prospect (if successful - by the end of 2026), receive field development approval from the Oil and Gas Authority. The deal is subject to regulatory approvals and is expected to complete in 2020. Energean intends to focus its activities in the Mediterranean area and therefore its North Sea assets are considered to be non-core. Energean Oil and Gas announced on 4 July 2019 that it had agreed to acquire Edison Exploration and Production S.p.A. The Greece-based company will acquire the upstream division of Edison, controlled by Franceâs EDF, for a consideration of USD 750 million (to be adjusted for working capital) with an additional contingent consideration of USD 100 million payable upon achievement of the first gas from the Argo and Cassiopea project offshore Sicily, which is expected by 2022. Edison will also keep an 8% royalty on profit production from future discoveries made in Egypt within the North Thekah Offshore and North East Hap'y blocks. In the UK Edison holds interests in three licences â P701, P1820 and P2215 through its subsidiary Euroil Exploration Limited. The company is a partner in the HPHT Glengorm discovery made by CNOOC in early 2019. The 250 MMboe gas condensate discovery is slated for appraisal in 2020. Edison is also a partner in the Total operated Isabella HPHT target which is scheduled to be drilled in Q4 2019 and is another gas condensate target. Edison also holds interest in producing UK fields - Markham, Scott and Telford, Wenlock and Tors which is strategically important to Neptune's operated Cygnus field. In Norway Edison holds interests in 14 licences, five of which it operates. These contain two fields which are under development â Dvalin (118 MMboe gas, due onstream in 2020) and Nova (79 MMboe oil and gas, due onstream 2021) â and four small discoveries (which, according to the NPD, are unlikely to be developed).",Norway (Uer Terrace (Viking Graben Province)) Nova
79557,"In around March 2020, Sweetpea Petroleum Pty Ltd, a PetroHunter Energy company, took 100% ownership in exploration permits EP 136 and EP 143 after sharing a 50:50 joint venture partnership with Paltar Petroleum Pty Ltd. The permits are located in the McArthur Basin and are prospective for shale gas and conventional gas/oil. Paltar entered into voluntary administration with KPMG administrators appointed on 17 April 2019. Subsequently, Paltar and Sweetpea entered into a Sales Agreement on 12 July 2019 with the settlement coming on 6 August 2019. The transfer of interest is now complete. The permits cover an area of 6,250 sq km and were awarded to Sweetpea in 2012. They are scheduled to expire, on 27 August 2021. Within the McArthur Basin, Sweetpea also participates in three other surrounding permits with operator Origin Energy through a small holding in Falcon Oil & Gas Pty Ltd. In each case, Sweetpea was the original operator in the permits. Origin entered in 2014. Sweetpea Petroleum Pty Ltd has acquired Paltar Petroleum's 50% interest in EP 136 and EP 143, within the McArthur Basin. The increase gives Sweetpea 100% ownership of the exploration permits.","PetroHunter Energy company, took 100% ownership in exploration permits EP 136 and EP 143 (prospective for shale gas and conventional gas/oil) after sharing a 50:50 joint venture partnership with Paltar Petroleum Pty Ltd."
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. "
25533,"BT-PN-005 contract, PN-T-049 block C, ParnaÃba Basin, assumed P&A dry 20 Jun â18, no shows report. PTD was 1,221m, target Cabeças + Poti fmâs.","4-PGN-FAZENDATORRAO-002-MA (4-PGN-024-MA) (Parnaiba Gas Nat.100%) in PN-T-049 block, assumed P&A dry."
33522,"PPL 253, Cooper-Eromanga, TD 1,754m, suspended assumed oil on 22 Oct â18, Saxon rig 183.","Australia, PPL 253"
88491,"Exxon has secured an unconventional exploitation contract for the Los Toldos II Oeste block, 77 sq km in the Neuquén Basin. A pilot well is required in phase 1 (4 yrs), drilling and completion of 2 horiz wells, 3D seismic targeting the Vaca Muerta. Exxon (op) partner GyP Neuquén.","(Neuquen B.) Exxon has secured an unconventional exploitation contract for the Los Toldos II Oeste block, 77 sq km"
85382,"The Q16-Charlie-North light o&g discovery has been renamed Q16-Maasmond (Maas River Mouth). Maasmond-1 discovery was drilled in 2019 from Europoort (Rotterdam) and deviated northwards 3km offshore, and has led to changes approved to the production facility at the Q16-Maas gas discovery (aka Q16-FB or Maasgeul-3ST1) site to be fed by Q16-Maasmond oil for perhaps 17 months at max. 2,013 b/d. ONE-Dyas (op), partners Taqa Offshore + EBN.","Netherlands (Anglo-Dutch B.) Maasmond 01 op. by EBN (50%), SHELL (25%), EXXONMOBIL (25%) in Botlek II block, Q16-Charlie-North light o&g discovery has been renamed Q16-Maasmond (Maas River Mouth)."
48757,"In addition to its farmin offer for VSM 22 (DEA 14 May â19), Telpico is also offering a 49% stake in block LLA 42, Â 468 sq km in the Llanos Basin, in exchange for well costs on the Zapata prospect therein (inter alia), and a 65% stake in VSM 3, Â 421 sq km in the U. Magdalena, terms negotiable. www.telpico.com.","Telpico is also offering a 49% stake in block LLA 42, 468 sq km in the Llanos Basin, in exchange for well costs on the Zapata prospect therein (inter alia), and a 65% stake in VSM 3, 421 sq km in the U. Magdalena, terms negotiable."
10138,"On 29 November 2017 Beach Energy Ltd reported that it had entered into a binding agreement with Cue Exploration Pty Ltd, a wholly owned subsidiary of Cue Energy Ltd, to acquire equity in exploration permit WA-359-P and WA-409-P, located in the North Carnarvon Basin. Under the terms of the agreement, Beach will acquire a 21% interest in WA-359-P in return for a one off payment to Cue of AUD 900,000 for past costs and future payments equating up to 4% of Cueâs cost for the drilling of the Ironbark 1 exploration well. The agreement is subject to certain conditions, including BP exercising its option, reached in a previous separate agreement, to acquire a 42.5% interest in WA-359-P. The company has until 11 December 2017 to exercise this option. Other conditions include the formation of a joint venture and associate Joint Operating Agreement with full funding for the Ironbark 1 exploration well, as well as the current permit holders obtaining an extension to the current expiry date of 25 April 2018, in order to allow sufficient time for planning and drilling of Ironbark 1. Beach Energy also acquired, for a nominal consideration, a call option over a 7.5% interest in WA-409-P. If undertaken, Beach is to make future payments equating up to 7.5% of Cueâs costs for the drilling of an exploration well within the permit, as well as a 10% royalty payment to Cue on all future revenue earned by Beach from the permit. The option may be exercised until 31 July 2019. WA-359-P was awarded on 1 February 2005 and covers an area of 648.9 sq km. Assuming satisfaction of conditions, interest in WA-359-P will become BP (42.5% interest) Cue Energy Ltd (36.5% interest) and Beach Energy Ltd (21% interest). WA-404-P was awarded on 17 July 2007 and covers an area of 1,377 sq km. Interest in WA-404-P would become BP (80% interest), Cue Energy Ltd (12.5% interest) and Beach Energy Ltd 7.5% interest). ",Australia (Warburton - Cooper - Eromanga B.s) Revenue
21074,"The NPD confirmed on 9 May 2018 (effective from 30 April 2018) that Lundin has completed its deal to acquire Statoilâs 20% interest in PL 860. Lundin reported on 1 February 2018 that it had agreed a deal with Fortis to acquire the latterâs 10% interests in PL 539 and PL 860 and its 30% interests in PL 820 S and PL 825. This deal was reported as complete by the NPD on 20 February 2018 (effective from 15 February 2018). Lundin entered PL 539 and PL 860 in late 2017 by acquiring 10% interests from Fortis. PL 539 covers part of block 3/7 to the west of Trym and contains the 2015 Myrhauk prospect dry hole 3/7-10 S. PL 820 S lies between Jotun and Balder, covering parts of blocks 25/7 and 25/8 (below Base Paleocene) and PL 825 lies between Oseberg, Veslefrikk and Huldra covering parts of blocks 30/3 and 30/6. PL 860 covers parts of blocks 2/6, 2/9 and 3/4 to the east of Ekofisk, northeast of Valhall and the northwest of Trym and contains the 1997 oil discovery made by 2/6-5. Operator MOL is intending to drill a well on the Oppdal / Driva prospects on the Mandal High in PL 860 in Q3 2018. Oppdal is mapped to extend south into PL 539 and potential reserves for both prospects are 434 MMboe. The Myrhauk well was drilled by Premier, targeting the Upper Jurassic Ula Formation and the Middle Jurassic Bryne Formation in a three-way dip closure with up-dip pinchout. Prior to drilling, Premier put potential reserves at 10-135 MMboe with Top Reservoir expected at 3,346 m TVD. However, no Ula Formation was present and the 100 m thick Bryne Formation had 45 m of sands but contained no hydrocarbons. 2/6-5 was drilled by Saga on a structural closure mapped at Top Shetland Group on the northern part of the Mandal High. The well proved oil in a very tight Upper Cretaceous Tor Formation reservoir and also exhibited shows in the Ekofisk Formation and in Basement. Two intervals in the Tor Formation were perforated and flowed after acid stimulation, although only water with 3% oil was produced. Test permeability was just 0.4 mD. Â Following the completion of both deals interest in PL 539 is held by MOL Norge AS (80% + operator) and Lundin Norway AS (20%), interest in PL 820 S is held by MOL Norge AS (40% + operator), Lundin Norway AS (30%) and Wintershall Norge AS (30%), interest in PL 825 is held by Faroe Petroleum Norge AS (40% + operator), Lundin Norway AS (30%) and Spirit Energy Norge AS (30%) and interest in PL 860 is divided between MOL Norge AS (40% + operator), Lundin Norway AS (40%) and Petoro AS (20%).",Norway (Cod Terrace (Central Graben)) Ula
71631,"The previous licence holders in PL 019 F (Repsol 61%, INEOS 34% and KUFPEC 5%) have all withdrawn with effect from 31 January 2020 (reported by the NPD on 6 February 2020). Their interests have been acquired by Aker BP (55%) and DNO (45%) and Aker BP has assumed operatorship. This deal aligns the interests in PL 019 F with PL 065 which lies immediately to the west. PL 019 F (3 sq km of block 2/1 which was split from PL 019 B in December 2018) contains the southeasterly extension of Tambar which lies mostly in PL 065. Tambar was discovered in 1983 by 1/3-3. It is located on the Ula Trend at the eastern margin of the Central Trough, between Gyda and Ula and is a hanging wall trap formed by the extension and minor contraction of a late Jurassic fault array. Tambar has been developed as a tie-back to the Ula Field, some 16 km to the northwest. The development uses a remotely controlled wellhead facility without processing equipment. The field was granted a lifetime extension until 1 January 2022 by the NPD on 8 July 2016. In the original PDO, approved on 15 July 2001, the lifetime of the facility was defined as 15 years, meaning it was due to expire on 15 July 2016. In 2018 two new infill wells, targeting undrained areas in the north and south of the field as part of re-development work, were completed and initial performance exceeded pre-drill expectations. This, plus the implementation of gas lift in three existing wells, will extend the lifetime of the field from 2018 to 2028, with the potential for it to be extended again in the future. The upgrade is targeting reserves of 27 MMboe, producing an additional 4,000-6,000 boe/d, and total investments were forecast at approximately NOK 1.7 billion (USD 205 million). Interest in PL 019 F is now held by Aker BP ASA (55% + operator) and DNO Norge AS (45%).","The previous licence holders in PL 019 F (Repsol 61%, INEOS 34% and KUFPEC 5%) have all withdrawn. Their interests have been acquired by Aker BP (55%) and DNO (45%) and Aker BP has assumed operatorship."
44802,"Area 058 (block 3), drilled + P&A dry between 20 Oct â18 â early Feb â19, DECS-26 rig. PTD was 2,484m.","A-001-059/3 (Arabian Gulf Oil Co. (Agoco) 100%) in Area 058 (Block 3), P&A dry."
82731,"Larus Energy Ltd is looking for a joint venture partner in its wholly owned and operated exploration licence PPL 579, located in the south-east of Papua New Guinea in Larusâ newly defined Torres Basin.Larus Energy reports it is offering significant equity in the permit, with a farminee to take part in an upcoming exploration programme. Larus has contracted Moyes & Co. to assist in the divesture process.A data room is open for interested parties.In August 2017 Larus reported that it was increasing its efforts in the farm-out process, with results of seismic now available and the discovery of an oil seep within the licence area. In Q4 2017 it was reported that discussions were ongoing with a number of potential partners, with new confidentiality agreements signed in November. Moyes & Co is being utilised in an advisory capacity during the process, in which interested parties have been outlined since 2015 and have been conducting geological, geophysical and commercial due diligence as is required for farminees. In August 2015 Larus reported that discussions and due diligence was continuing, with 14 companies interested in the asset. In February 2017 Larus was awarded PPL 579 to replace PPL 326 which expired in September 2016. The newly awarded licence covers 9,257 sq km across both onshore and offshore Papuan Plateau/Aure Fold Belt. PPL 579 is scheduled to expire in March 2023. Larus also holds 100% interest in the neighbouring application APPL 580 which was submitted for approval consideration in December 2015. Larus is looking for a partner to assist with the ongoing work programme in the permit, although Larus has reported that the first two years was already fully funded. In the first two years, Larus undertook work to develop the shallow Miocene play potential which includes the Vekwala and Sunday prospects. In 2015 and 2016, the Haere and Hahonau 2D seismic surveys were completed from which the data will was processed to facilitate lead and prospect mapping. Further, smaller surveys have also been completed over the asset by Larus. In December 2018, Larus received approval to vary the work commitments for the third and fourth years. The requirement to dill an exploration well has bene replaced with the acquisition of a high resolution airborne magnetics and gravity survey. Larus plans to acquire around 7,250 sq km at a cost of USD 2.5 million. The survey is required by March 2021. Suitable partners will be asked to fund 3D seismic data acquisition to help further define Vekwala and Sunday prospects which is required prior to drilling. The first exploration well is currently due by March 2023. Larus reports that there is potential for both Mesozoic and Tertiary targets within the permit area.Potential reservoirs include a Mesozoic Puri Limestone equivalent, the Tertiary Talama and Lavao units and also a potential Toro sandstone equivalent. The early â mid Jurassic Manil Shale and Miocene-Pliocene Aure Beds Shale are thought to form potential source rocks, with the Orubadi Shale and intraformational units possible as seals. The Vekwala prospect has been reported to potentially contain resources of 13 Tcfg and 180 MMb liquids within a Jurassic reservoir. Water depth at location is approximately 42 m and the main target is at a depth of approximately 3,600 m below seabed. Previously the Sunday Prospect was outlined as the main target in the licence. The Sunday Prospect lies in a water depth of approximately 600 m and the main target is at a depth of approximately 3,000 m below seabed in a Cretaceous reservoir. Sunday is considered to be a 40 km long anticline which could contain 13.5 Tcfg with 160 MMb liquids. There are also several other prospects and leads present. The prospects and leads in the licence are thought to be part of a Mesozoic petroleum system. In August 2016 onshore oil seeps were invested by Larus. This was followed up by further sampling of light crude oil near the Imila village, north of Kapiano, withinAPPL 580. Geochemical analysis has confirmed that the oil has been generated in the Torres Basin. Analysis will now be undertaken to understand the source rock and maturity to further validate the hydrocarbon system model being constructed by Larus. PPL 579 covers an area of 9,257 sq km and was awarded in February 2017. Larus Energy holds 100% interest and is looking to divest its interest. Parties interested in pursuing this opportunity should contact: Ian Cross, Managing Director Moyes & Co Tel: +1 281 501 7110 Email: icross@moyesco.com  Andy Melvin, Managing Director Moyes & Co Tel: + 44 7702 855895           Email: amelvin@moyesco.com","Larus Energy Ltd is looking for a joint venture partner in its wholly owned and operated exploration licence PPL 579, located in the south-east of Papua New Guinea in Larusâ newly defined Torres Basin.Larus Energy reports it is offering significant equity in the permit, with a farminee to take part in an upcoming exploration programme."
73569,"On 3 December 2019 Equinor spudded exploration well 15/3-12 S on the Sigrun East prospect. The well location is approximately 4 km southeast of Sigrun discovery well 15/3-4. 15/3-12 S is located in PL 025 but it was drilled sole risk between Equinor and Neptune, using the âWest Phoenixâ S/S. TD was reached at 3,810 m (3,652 m TVDSS) in the Middle Jurassic Sleipner Formation. Three oil-bearing sandstones (9 m, 4 m, and 9 m) were proven in the Middle Jurassic Hugin Formation (which itself was 100 m thick) with no OWC. Estimated recoverable reserves are 7-17 MMboe. On 21 January 2020 sidetrack 15/3-12 A was kicked-off. This well was drilled because the main wellbore was not sited in an optimal position to test the secondary Upper Jurassic Draupne target. Equinor had drilled the 12-1/4"" hole to section TD at 3,593 m (3,427 m TVD) and had started logging, but then ran into issues which led to a technical sidetrack (T2) being kicked-off in early February 2020. This well was drilled to TD at 4,037 m (3,796 m TVD) in the Sleipner Formation. Both the Draupne (85 m) and the Hugin (120 m) formations were present but they were water-wet. There were some oil shows in a thin 3 m sandstone in the Sleipner Formation but the well is classified as a dry hole. Development of the Sigrun East discovery is being considered as a tie-back to Gudrun. On 2 March 2020 the well was being abandoned. The Sigrun discovery was made by Elf Petroleum in 1982. 25/3-4 proved oil and gas at four levels in the Hugin and Sleipner formations with different pressure regimes. A test in the Hugin Formation flowed at a rate of 3,868 bo/d plus 8.65 MMcfg/d through a 40/64â choke. A downdip appraisal well was drilled in 1983 / 1984 which established an OWC at 4,023 m. The Hugin Formation was absent and the Sleipner Formation consisted of thin sandstones with a net pay of less than 7 m. In 2018 Equinor drilled appraisal well 15/3-11 which confirmed a 35 m oil column (15 m of sandstone) in the Hugin Formation with no OWC. As a result of this well, Equinor increased the estimated recoverable reserves range from 2-9 MMboe to 7-13 MMboe and a development using the Gudrun facilities is being considered. Equinor Energy AS operated the Sigrun East well with a 75% interest. It was partnered by Neptune Energy Norge AS (25%).","015/03-12 S,A (Sigrun East) (Equinor 36% op. Neptune 25%, OMV 24%, Repsol 15%) in PL 025 block 9,4 + 9m oil reservoirs in the target Middle Jurassic Hugin Fm, total 100m of moderate quality, no OWC. Sidetrack (A) targets U. Jurassic Draupne + Hugin found water-wet. Est. 6-17 MMboe recoverable, tie-into Gudrun to be considered. TD=3810 m."
41566,"In late December 2018, Qarun Petroleum Co (Qarun) suspended (awaiting test) the Bolt 118-1 exploration well in the East Bahariya Ext.III (Bolt) concession, Abu Ghardiq Basin. The well was spudded on 15 November 2018 with the âEDC-63â land rig and drilled to a TD of 3,597 m in the Albian Kharita formation. It had a planned TD of 2,819 m and the Aptian Alam El Bueib as the objective. 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.","Egypt (Gindi B.) ? op. by APACHE (50.25%, KNOC 25.0%, SIPC 24.75%, QPC 0.0%) in Qarun (Dev) block"
17591,"OMV New Zealand Ltd and joint venture partner Mitsui E&P Australia Pty Ltd were offering a farm in opportunity in three offshore Taranaki Basin exploration permits: PEP 60091, PEP 60092 and PEP 60093. The companies have been successful with Sapura Exploration and Production Sdn Bhd acquiring 30% interest in the permits on 26 March 2018. Sapura also entered OMV permits PEP 51906 and 57075, located in the offshore Taranaki Basin. OMV reported that it was ideally looking for a partner across five of its offshore assets, but was also considering individual bids. The opportunity on offer was for a farminee to gain a balanced position as a non-operator within the blocks. For the Mitsui joint venture blocks, the companies were looking for a partner to acquire around 40% [combined] interest. In PEP 60091, OMV held 57.14% and operatorship with partner Mitsui E&P prior to the completion of the Sapura farm-in deal. The permit area contains prospects and leads, with potential thought to be within the Miocene Moki Formation, Eocene Kapuni, Kaimiro and Mangahewa formations and Paleocene Farewell Formation. The North Cape and Rakopi formations may also provide targets. The Te Whatu four-way dip closed prospect would be the primary target, with Late Cretaceous and Paleocene sand potential. In this permit a drill or drop decision is required by March 2018, with the well then planned between April 2018 and March 2020. PEP 60092 and PEP 60093 were awarded to and OMV and joint venture in April 2016 after being applied for in the 2015 Blocks Offer. OMV completed the 2D seismic reprocessing over PEP 60092 as part of the initial work programme. Geological and geophysical technical studies were reported to be ongoing in June 2016 in both PEP 60092 and PEP 60093. Exploration drilling would be required in 2022 in both permits if it was opted for, with drill/drop decisions available prior to committing to a well. There are two historical wells in PEP 60092 â Taranga 1, drilled in 1992, and Taimana 1, drilled in 1984. Both were plugged and abandoned as dry holes. There are two wells also in PEP 60093 â the Takapou A well that was drilled in 2004 and encountered oil and gas shows, and the Kopuwai 1 well that was drilled in 2007 and encountered oil shows. There are a number of prospects and leads within the three permits. OMV reports that potential reservoir targets exist in the North Cape Sandstone as well as in the Moki and Mount Messenger formations. Interested parties were requested to make expressions of interest and sign a confidentiality agreement. Once completed, virtual summary presentations and a physical dataroom were made available. The permits cover a total area of 6,721 sq km. Participants in the permits were OMV New Zealand Ltd (57.14% + Operator) and Mitsui E&P New Zealand (42.86%). Upon completion of Sapura entering the permits, participants are now: OMV New Zealand Ltd (40% + Operator), Mitsui E&P New Zealand (30%) and Sapura Exploration and Production Sdn Bhd (30%). Interested parties were to contact: Simon Lang, Head of Exploration, Development and Production Address: Level 10, Deloitte House, 10 Brandon Street, Wellington CBD, New Zealand Email: Simon.lange@omv.com  Tim Allan, Exploration and Appraisal Manager Address: Level 10, Deloitte House, 10 Brandon Street, Wellington CBD, New Zealand Email: tim.allan@omv.com  ","OMV New Zealand Ltd and joint venture partner Mitsui E&P Australia Pty Ltd were offering a farm in opportunity in three offshore Taranaki Basin exploration permits: PEP 60091, PEP 60092 and PEP 60093. "
84890,"Equinor spudded a HPHT exploration well on the Atlantis prospect approximately 9 km north of Huldra on 13 May 2020. It is using the ""West Hercules"" S/S for 30/2-5 S in PL 878. On 8 July 2020 it was announced that the well was a gas and condensate discovery having encountered a 160 m gas column in the targeted Middle Jurassic Brent group. This included 60 m of poor to moderate quality sandstone reservoir within the Ness (30 m), Etive (15 m), Tarbert (10 m) and Rannoch (5 m poor-quality only) Formations. The well was terminated at a TD of 4,390 m in the Lower Jurassic Drake Formation and the discovery has estimated recoverable reserves between 19 to 63 MMboe. As of 7 July 2020 Equinor was plugging and abandoning the well. Huldra was discovered in 1982 by well 30/2-1 and it came onstream in November 2001. It is a rotated fault block structure with a Brent Group reservoir lying between 3,500-3,900 m. The reservoir was initially HPHT but compression was required to aid production from 2007. From the Huldra platform wet gas was transported to Heimdal for further processing and export and condensate was exported through Veslefrikk. Production ceased in September 2014 by which time it had produced 618 Bcfg, representing a recovery rate of 80%. Interest in PL 878 is divided between Equinor Energy AS (60% + operator), Source Energy AS (20%) and Wellesley Petroleum AS (20%).","Norway (Viking Graben Province), 30/2-5 S (Atlantis) exploration well, operated by EQUINOR (60%), WELLESLEY (20%), SOURCE EN (20%), in PL 878, announced as a gas and condensate discovery. 160 m gas column in the targeted Middle Jurassic Brent group. This included 60 m of poor to moderate quality sandstone reservoir within the Ness (30 m), Etive (15 m), Tarbert (10 m) and Rannoch (5 m poor-quality only) Formations. The well was terminated at a TD of 4,390 m in the Lower Jurassic Drake Formation and the discovery has estimated recoverable reserves between 19 to 63 MMboe."
26348,"OMV has acquired a 25% interest in PL 615 and PL 615 B from operator Equinor. The deal was reported by the NPD on 25 July 2018 and is effective from 29 June 2018. PL 615 covers a 410 sq km area over part of blocks 7324/1, 7324/2, 7324/3 and 7325/1. Two wells have previously been drilled in PL 615 targeting the Apollo (dry) and Atlantis (minor gas discovery) prospects. In October 2018 Equinor plans to return to the licence to drill an exploration well on the Intrepid Eagle prospect (see separate article). PL 615 B covers a 568 sq km area over blocks 7425/10 and 7425/11. Exploration well 7324/2-1 (a dry hole) targeted the Apollo prospect which had a Realgrunnen Group target similar to OMVâs 2013 Wisting Central discovery. The well encountered 15 m of good quality sandstone in the Jurassic Sto Formation. The Snadd Formation comprised a 170 m poor reservoir quality section. The well was dry. The second exploration well in PL 615 was 7325/1-1 targeting the Atlantis prospect. The well encountered a 10 m sandstone with hydrocarbon shows in the main objective â the Middle Triassic Kobbe Formation â but reservoir quality was poor. The Snadd Formation contained 55 m net of sandstone with a 10 m section containing gas. No sandstone was present in the Klappmyss Formation â a secondary target â but there was a 10 m gross sandstone section with poor reservoir properties in the Havert Formation. The find is not considered to be commercial. Interest in PL 615 and 615 B is now held as follows: Equinor Energy AS (55% + operator), OMV (Norge) AS (25%) and Petoro AS (20%).",OMV has acquired a 25% interest in PL 615 and PL 615 B from operator Equinor.
56539,"Total is looking to sell its 100% interest in P2158, Â 37 sq km in the Moray Firth and home to the 2005 15/18b-11 Yeoman o&g discovery. This could be developed along with Hibiscusâ Marigold find in adjacent P198. Contact: Simon.Pearce@total.com.","Total is looking to sell its 100% interest in P2158, 37 sq km in the Moray Firth and home to the 2005 15/18b-11 Yeoman o&g discovery. This could be developed along with Hibiscusâ Marigold find in adjacent P198."
25348,"Total secured rights to ultra-deepwater block 2912, Â 7,900 sq km in the Orange Basin, on 16 May â18. Â It lies west of the companyâs existing block 2913B in WD 3,000-4,000m. Total (op) 85%, partner Namcor.","Total secured rights to ultra-deepwater block 2912, 7,900 sq km in the Orange Basin, on 16 May â18. It lies west of the companyâs existing block 2913B in WD 3,000-4,000m. Total (op) 85%, partner Namcor."
65116,"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 2019, 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. As of September 2019, the opportunity was still available. PEDL 068 is located in North Yorkshire and contains"
24493,"On 26 June 2018, Kosmos confirmed in an announcement that the Anapai-1A replacement wellbore for the Anapai-1 NFW on deepwater Block 45 was dry and is being plugged and abandoned. Kosmos reported that 'the prospect was fully tested, encountering high quality reservoirs in the targeted zones, but did not find hydrocarbons."" The Anapai-1A wellbore reached at final TD of 4,556m after being spudded with the ""ENSCO DS-12"" rig around 22 May 2018. The original well, which was spudded in April 2018, was P&A'd after encountering stability issues before reaching TD. Anapai-1A had the same objectives as Anapai-1 and is located in a water depth of around 1,643m. The wells had the objective of testing ""lower Cretaceous reservoirs in a structural trap on the flank of the basin,"" Kosmos CEO Andy Inglis said in the 26 June 2018 press release. Kosmos identified the Anapai prospect a number of years ago in the central portion of the 5,126 sq km block and previously indicated that the prospect hosts potential resources in the order of 700 MMboe in Early Cretaceous Upper Albian sands. Inglis also confirmed that the ""forward drilling program remains unchanged given the independent nature of the prospects."" Kosmos next plans to drill and undertake a second high-impact oil test over the Pontoenoe prospect in Block 42 after it completes operations on Anapai-1A. He also said this is, ""the first of up to three independent prospects in Block 42 offshore Suriname. Pontoenoe is a similar play type to the Turbot and Longtail discoveries located approximately 70 km to the west in Guyana."" The two other prospects on Block 42 are the Aurora and Apetina stratigraphic plays which the company estimates to contain over 500 MMboe of potential resources. Inglis, in a 7 May 2018 conference call, said that Kosmos has five 3D seismic defined prospects spread out across the two Surinamese deepwater blocks in total. Kosmos has five additional one-well options remaining for the ""ENSCO DS-12"" drillship and so follow up drilling in 2019-2021 is possible. The oil petroleum system has been proven in the area with Exxon's world-class discoveries in the Stabroek Block in neighbouring Guyana. Kosmos has a 50% interest in the 5,126 sq km Block 45 alongside Chevron. Kosmos is currently operator but operatorship will be passed to Chevron in the event of a commercial discovery as part of the terms of a 2012 farm-in agreement. The tract is located in water depths ranging from 198 to 2,000m. PGS's ""Ramform Sovereign"" vessel completed a 5,295 sq km 3D seismic survey in October 2012 over blocks 42 and 45. In 2016, an additional 6,500 sq km was acquired over these blocks in late 2016 (majority likely to be over Block 42) with the CGC ""Oceanic Sirius"" and ""7 Oceans"" as part of a farm-in agreement with Hess for Block 42. Processing of this data is ongoing and will exceed the minimum work obligations of phase one when complete, (1,000 sq km). The extension of the initial period of the PSC is due to expire in mid-September 2018, with two renewal periods of two years each allowed with additional one-well commitments for each.","Anapai 1A (Kosmos 50% op, Chevron 50% op in case of commercial disc.) in Block 45, encountered high quality Lwr Cretaceous 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 70km to the west in Guyana). TD=4556m."
76347,"6th ANP PSC round Aram block, 4,476 sq km in Santos deepwaters, was granted to Petrobras and partner CNODC on 30 Mar '20. GEPS map extract below.","6th ANP PSC round Aram block, 4,476 sq km in deepwaters, was granted to Petrobras (80% op.) and partner CNODC (20%)."
73922,"Ref. DEA 20 Jan '20, IPC announces the completion of the acquisition, from Granite Oil Corp., of Alberta assets for USD 59 MM. This provides for total 2P reserves of 14 MMboe + 6.2 MMboe unrisked contingent resources + production of ab. 1,500 bo/d. Assets also include infrastructure to continue gas injection enhanced oil recovery as well as production facilities.","PC announces the completion of the acquisition, from Granite Oil Corp., of Alberta assets for USD 59 MM. This provides for total 2P reserves of 14 MMboe + 6.2 MMboe unrisked contingent resources + production of ab. 1,500 bo/d. Assets also include infrastructure to continue gas injection enhanced oil recovery as well as production facilities."
48878,"West Kalabsha block, N. Egypt Basin, drilled 18 Feb â mid-Mar â19, P&A at TD 4,612m (Carb. Dhiffah fm), EDC rig 54. Target Alam El Bueib 3A, 6, 3G + 3C. Apache (op), partner Sinopec Intl.","Egypt, Kalabsha (Dev)"
64451,"Commitment well in W-C part of AE-0008-4M-Amoca-Yaxche-06 block, offshore Sureste Basin, WD 26m, susp. results n/a at TMD 2,112m. Target U. Miocene, Independencia I JU.",Mexico (Chicontepec Sub-basin (Tampico-Misantla B.)) Independencia
50838,"In mid-June 2019, state company Integracion Energetica Argentina (IEASA), formerly ENARSA, announced that it has received four bids from four qualified operators on its 100%-held Aguada del Chanar block that was offered through a licensing round called ADCH 01/2019. State company YPF reported to be the highest bidder with over USD 95.6 million, followed by Pan American Energy with USD 45 million, Tecpetrol with 40.1 million, and Vista Oil & Gas with USD 8.1 million. It was mentioned back in February 2019 that official award for the block is expected sometime in June 2019. Aguada del Chanar block covers 57 sq km of land in the Neuquen Embayment part of Neuquen Basin. It is situated adjacent to Wintershallâs Aguada Federal block on the western side where the operator has been targeting resources in the Vaca Muerta Formation shale, and also directly next to YPFâs La Amarga Chica block on the southwestern side where the operator and Malaysian state partner Petronas recently agreed to enter the development phase on their Vaca Muerta shale oil project in late-2018. IEASA joined provincial company GyP Neuquen as a 50% stakeholder in the Aguada del Chanar block in February 2010 before receiving a 25-year exploitation permit in August 2012 with the option of a 10-year extension. IEASA became the 100% holding operator for the concession when a 35-year permit for unconventional exploitation was granted in October 2018. The unconventional permit was awarded with the expected commitment of a USD 10 million work program that includes an acquisition of 80 sq km of 3D seismic and an exploration well workover in the tight reservoirs of Punta Rosada-Lajas formations by October 2020. Background Information Fields in Auguada del Chanar block have produced over 78 Mbo and 3.3 Bscfg as of January 2019, with 29 Mbo and 33 MMscfg from the Vaca Muerta Formation.","Integracion Energetica Argentina SA (IEASA) received four bids on Aguada del Chanar block, Neuquen Basin"
27570,"On 15 August 2018 Pandion announced that it has agreed a deal with Wintershall to acquire 10% of the latterâs interest in PL 820 S. The licence lies between Balder / Ringhorne and Jotun and covers parts of blocks 25/7 and 25/8. The northerly section of the licence lies across the southwestern part of the Jette field (abandoned) and this section applies only below Base Pliocene (the southerly section applies to all levels). An exploration well is due to be drilled in PL 820 S in 2019. The deal is subject to government approval and will be financially effective from 1 January 2018. Aker BPâs Jette was discovered by 25/8-17 in 2009 and contained oil in a Paleocene Heimdal Formation reservoir. It was brought onto production in May 2013 via a subsea template tied into Jotun A (an FPSO). Jotun itself was expected to continue producing until 2021 but water-cut in 2015 was 97% and production from tied-in fields had been declining. Therefore, both Jotun and Jette came off production in December 2016. Development of Jette had been challenging since the beginning: problems with the first producer meant that the development plan was subsequently revised to consist of two (shorter than planned) horizontal producers on the southern segment (which was believed to contain recoverable reserves of 5-9 MMboe) rather than one long horizontal on each of the south and north segments as originally planned. Due to a number of issues, including higher than expected costs and the reduction in recoverable reserves, profitability at Jette was lower than Aker BPâs initial estimates. The problems continued into production, with total 2014 production being less than half that of the six months of 2013, and 2015 production being only half of 2014 volumes. The deadline for final disposal of the Jette field facilities has been delayed to the end of 2020. Initial plans were to complete the work by 2018, based on production from the field ceasing in January 2016. However, as production continued until December 2016 the timescale has changed. Work will begin on the removal of some of the seabed infrastructure in summer 2018 and permanent plugging and abandonment of the wells will now be completed by 2019, after which the main seabed structures will be removed. Following completion of the deal, interest in PL 820 S will be held by MOL Norge AS (40% + operator), Lundin Norway AS (30%), Wintershall Norge AS (30%) and Pandion Energy AS (10%).","Pandion will acquire a 10% interest in PL 820S from Wintershall (->20%, MOL 40% op. Lundin 30%)."
27420,"In early August 2018, the General Directorate of Petroleum Affairs (GDPA) awarded Guney Yildizi Petroleum (GYP) two production leases comprising of areas N47-b3-1 (41.87 sq km) and N47-b4-1 (51.34 sq km). The leases are located in the SE Turkish province of Mardin (District X) and will be valid for an initial term of four and six years respectively. They effectively replace part of GYP's Block 4968 exploration licence.The move follows a successful exploration and appraisal campaign on the block, which discovered the Dirsekli Field. The Dirsekli 1 NFW was drilled in 2013/2014 and is understood to have encountered oil in the Late Cretaceous Mardin carbonates as well as Paleocene dolomites. One appraisal well has been drilled so far. Both wells have been completed and placed on-stream. During Q1 2018, the field produced at a rate of around 26 bo/d.",TPAO (100%) was awarded exploration licences N47-b3-1 (41.87 sq km) and N47-b4-1
8407,"A set of agreements have been signed between Pertamina and ExxonMobil over the Jambaran Tiung Biru (JBT) unitisation project straddling the Cepu PSC and the Jawa Bagian Timur 3 PPC, E. Java. They are the Joint Operation Agreement, Unitisation Agreement, Unitisation Operation Agreement, Cepu Gas Marketing Agreement and Settlement Agreement, all marking the finalisation of 41.4% interest transfer from ExxonMobil to Pertamina, now 90.8% in partnership with the local govt (9.2%). Â ","ExxonMobil has tranfered its interest in Jambaran Tiung Biru to Pertamina (->90,8%, Local gvt. 9,2%)."
32166,"On 27 September 2018, the ANP granted formal approval to Imetame to acquire the 30.65% working interest held by lone partner Orteng in the Cardeal Amarelo and Cardeal do Nordeste production concessions. Imetame now holds 100% working interest in both production concessions. The Cardeal do Nordeste production is currently involved in unitization negotiations with Alvopetro regarding the gas discovery covering several contiguous blocks. However, Orteng still holds its 30.65% working interest in the remaining valid exploration area of the BT-REC-035 contract, REC-T-210 block and BT-REC-036 contract, REC-T-211 block Imetame was operator of both production concession contracts with a 69.35% working interest and lone partner was Orteng with 30.65% working interest. On 10 January 2018, the ANP approved a resolution to arbitrate the technical terms for the preliminary unitization agreement between Alvopetro and Imetame regarding the Cabure, Cabure Leste, and Cardeal do Nordeste production concessions and the REC-T-212 block that share a common gas reservoir in the onshore Reconcavo Basin. Alvopetro issued a press release regarding the unitization agreement on 15 January 2018. It provided the following information including that total estimated in place gas reserves for the unitized are estimated to be 127.1 Bcfg. The ANP approved of the following ownership split of the reservoir based on working interest and block area involved. The three companies involved in the process Alvopetro, Imetame, and Orteng will have 60 days to finalize various additional requirements to conclude the unitization agreement including preparation and filing a joint development plan, choosing the unit operator, and execute a joint operating agreement. If the parties are unable to reach an agreement by 13 March 2018, the ANP will make the final decisions. According to Alvopetro, the ANP evaluated all of the technical information regarding the common reservoir and decided on the working interest share of each party as follows. Alvopetro was granted 49.1 % of the reservoir that represents 62.4 Bcfg in place estimated reserves. Imetame was granted 36.1 % of the reservoir that represents 45.9 Bcfg in place estimated reserves. Orteng was granted 14.8 % of the reservoir that represents 18.8 Bcfg in place estimated reserves.  On 12 July 2016, the ANP granted formal approval to Imetame to merge the 3.36 sq km Cardeal Amarelo Oeste production concession into the 2.56 sq km Cardeal Amarelo production concession retroactive to 5 May 2015. The merged Cardeal Amarelo production concession now covers an area of 5.92 sq km. The production concessions were granted final awards in May 2015. On 13 May 2015, the ANP granted formal approval to Imetame for its commerciality declaration of the 8.37 sq km Cardeal do Nordeste production concession retroactive to 2 April 2015. It was carved out of the northeastern corner of the BT-REC-036 Contract, REC-T-211 block. The 1-IMET-003-BA and 1-IMET-010D-BA are considered the discovery wells for the production concession. The operator also filed two additional commerciality declarations that were granted formal awards out of the discovery evaluation plan (PAD), the Cardeal Amarelo production concession and the Cardeal Amarelo Oeste production concession from the REC-T-210 block. As a result of the production concession carve outs from the REC-T-211 block, the area has been reduced to 17.28 sq km from 28.21 sq km. It still remains valid as a PAD for the 1-IMET-005-BA new-field wildcat. On 13 May 2015, the ANP granted formal approval to Imetame for its commerciality declaration of the 2.56 sq km Cardeal Amarelo production concession retroactive to 5 May 2015. The block was carved out of the western area of the BT-REC-036 contract, REC-T-211 block. The 1-IMET-002-BA is the discovery well for the production concession. The operator also filed two additional commerciality declarations that were granted formal awards out of the discovery evaluation plan (PAD), the Cardeal Amarelo production concession and the Cardeal Amarelo Oeste production concession from the REC-T-210 block. As a result of the production concession carve outs from the REC-T-211 block, the area has been reduced to 17.28 sq km from 28.21 sq km. It still remains valid as a PAD for the 1-IMET-005-BA new-field wildcat. On 13 May 2015, the ANP granted formal approval to Imetame for its commerciality declaration of the 3.36 sq km Cardeal Amarelo Oeste production concession retroactive to 5 May 2015. The new block was carved out of the eastern area of the BT-REC-035 contract, REC-T-210 block. The 1-IMET-001-BA is the discovery well for the production concession. As a result of the production concession carve out, the REC-T-210 block was divided into two separate blocks but a part relinquishment was also reported and the area reduced to 8.056 sq km in one block from 11.416 sq km. The contract remains valid as a PAD area for the 1-IMET-009D-BA new-field wildcat.","Imetame (->100%) acquired the 30,65% working interest held by lone partner Orteng in the Cardeal Amarelo and Cardeal do Nordeste production concessions. "
61236,"Austin, TX-based Parsley Energy has agreed to acquire Jagged Peak Energy in a stock deal valued at USD 2.27 bn including debt. Involved are assets in Permianâs Delaware Basin, adding onto Parsley's existing acreage here and Midland Basin holdings. The transaction is expected to close in 1Q '20.","Austin, TX-based Parsley Energy has agreed to acquire Jagged Peak Energy in a stock deal valued at USD 2.27 bn including debt. Involved are assets in Permianâs Delaware Basin, adding onto Parsley's existing acreage here and Midland Basin holdings. "
25911,"LL-87 block, offshore Gulf of Suez, WD 28m, TD 4,764m, abandoned dry in Apr â18, ST-Bahari 1 JU. Gulf of Suez Petroleum = EGPC + BP.","LL-87 block, offshore Gulf of Suez, WD 28m, TD 4,764m, abandoned dry in Apr â18, ST-Bahari 1 JU. Gulf of Suez Petroleum = EGPC + BP."
39963,"W. part of 14/2001/L Pniewy-Steszew contract area, Fore-Sudetic Monocline in W. Poland, TD 3,155m, tested 2.2 MMcfg/d from the target Rotliegendes during Dec â18.","Turkowo 2 (PGNiG 100%) pos. aprr. in 14/2001/L Pniewy-Steszew block, production tests indicating that the well has capacity to produce 2 MMcfg/d from Rothligende sst"
14590,"Paterno block in Sicily, N. Caltanissetta Basin, assumed terminated but no results. PTD was 1,600m, target Numidian Flysch, Massarenti 7000 rig. Eni (op) 50%, partner Edison.","Biancavilla-1 nfw Eni (op) 50%, partner Edison in Paterno block in Sicily, N. Caltanissetta Basin, assumed terminated but no results. PTD was 1,600m, target Numidian Flysch,"
52171,"Pandion has acquired Aker BPâs 30% interest in PL 842 with effect from 14 June 2019 (confirmed by the NPD on 26 June 2019). The licence is located northeast of Norne and covers parts of blocks 6608/10, 11 and 12. An exploration well targeting the Godalen prospect is due to be drilled in PL 842 in July 2019. The deal was originally announced by Pandion on 31 December 2018. The Godalen well will target potential recoverable reserves of 90 MMboe in the Upper Jurassic Rogn Formation, and if it is successful a tie-back to Norne will be considered. TD is planned at around 1,700 m and the well should be in operation for around 30 days. Following completion of the deal interest in PL 842 is held by Cairn through Capricorn Norge AS (40% + operator), Skaggen44 AS (30%) and Pandion Energy AS (30%).",Pandion has acquired Aker BPâs 30% interest in PL 842
55658,"Pakistan Petroleum Ltd (PPL) has plugged and abandoned (P&A) the Durab X-1 new field wildcat (NFW) well within the Kotri 2468-12 EL (Lower Indus Basin) onshore exploration licence during late July 2019 after drilling to a TD of 2,415 m. The well was spudded on 30 June 2019 using the Schlumbergerâs SLR-225 land rig with a prognosed TD of 2,415 m in the Cretaceous. The Kotri EL licence, located in the Sujjawal district of Sindh province, covers an area of 1,660 sq km and PPL hold 100% equity in the block. PPL had announced the Yasar X-1 gas and condensates discovery on 13 August 2018. It was drilled to a TD of 2,720 m and was reported to have flowed 3.2 MMcfg/d and 475 bc/d through 32/64â choke during drill stem test (DST) from the âUpper Sandâ unit of Cretaceous Lower Goru Formation. Â Background Information Kotri EL, which originally covered an area of 2,378 sq km, was awarded to PPL on 29 April 2010 under the 2009 Licensing Round. The 2009 Licensing Round was launched by the Directorate General of Petroleum Concessions (DGPC) on behalf of the Government of Pakistan on 25 June 2009. This followed shortly after the approval of new Petroleum Exploration & Production Policy 2009 and Model Petroleum Concession Agreement (PCA) / Pakistan Petroleum (Exploration & Production) Rules. Nine wells have been drilled in the area to date, one of which, Charo 1, was suspended as a gas discovery by Tullow Pakistan Ltd in June 1995 after reaching TD at 1,340 m. A further two wells encountered minor quantities of gas: Burdi Babar 1, which was plugged and abandoned (P&A) by Oil and Gas Development Corporation (OGDC) in April 1986 after reaching TD at 3,658 m, and Meting 1, which was P&A by Tullow Pakistan Ltd in December 1997 after reaching TD at 4,290 m. PPL conducted a 2D seismic campaign over the block between February and July 2011 - a total of 599 line km was acquired during this survey. The company was granted a 24-month extension to the third contract year of the Kotri EL with effect from 29 April 2013. The company acquired 426 sq km of 3D seismic (vibroseis / dynamite source) over the block during June to November 2014 using a Sinopec crew. On the basis of this seismic, two prospects were identified which were planned to be drilled during 2016. PPL was granted a renewal to the Kotri EL and the block entered into two-year Phase-II with effect from 29 April 2015. The licence area also reduced to 1,660 sq km. The company acquired 374 sq km 3D seismic over the block during December 2016-March 2017 using the Bureau of Geophysical Prospectingâs (BGP) âBGP-9501-Aâ seismic crew. PPL was granted a 12-month extension to the Phase-II of initial term of the licence from 28 April 2017 to 27 April 2018. PPL made the Kotri X-1 tight gas discovery in the block in May 2016. PPL announced on 19 May 2016 that during cased-hole drill stem test, the well flowed good quality gas at an average rate of 3.4 MMcfg/d at flowing wellhead pressure of 608 psi from the Massive Sand unit of the Cretaceous Lower Goru Formation. The well was drilled to a TD of 3,892 m. The Kotri prospect was understood to be a north-northwest â south-southeast trending, fault-bounded, anticlinal structure. The company earlier drilled Rajab X-1 NFW which was abandoned in May 2018 at a TD of 4,090 m after proved as dry well. It was spudded on 3 April 2018.","Durab X1 nfw (UEPL 50% op. Asia Resources Oil 10%, PPL 40%) in Kotri North 2568-21 EL, P&A, the well is assumed to have been dry, and it is not clear if the well was tested prior to abandonment."
52565,"On 3 July 2019, it was reported that Eni with partner Vitol obtained Block 3, deep waters of the Tano Basin which had been offered in Ghanaâs First Offshore Licensing Round. Other participants in the acreage will be the Ghana national Petroleum Corporation and an indigenous player who will be selected during the contract negotiation. The authorities have invited the companies for negotiation on the detailed terms of the Petroleum Agreement, and the official award will follow. Block 3 is located around 50 km south-east of the Eni-operated Sankofa gas/condensate/oil field. Tullow Oil was the other company who lodged a bid for this block. In May 2019, it appeared that the Ghanaian Ministry of Energy was disappointed with the outcome of the bid round after receiving only three bids for the six blocks on offer. The deadline for the submission of bids was 21 May 2019. Sixteen companies had expressed interest in pursuing bids for open acreage these included: Tullow Oil, Total, ENI, Cairn, Harmony Oil and Gas Corporation, ExxonMobil, CNOOC, Qatar Petroleum, BP, Vitol, Global Petroleum Group, Aker Energy, First E&P, Kosmos, Sasol and Equinor. The auction was open on 15 October 2018. Of the six blocks on offer, only three (Blocks 2, 3 and 4) were open to competitive bid. Ultra-deep-water Block 5 and Block 6 would be awarded after direct negotiations with IOCs with relevant technical expertise and financial capacity. The coastal Block 1 will stay under control of National oil company GNPC that will operate the permit with a foreign company as technical partner.","Eni (op) Vitol, GNPC and a yet-to-be-disclosed local company have secured rights to WB03 (block 3), medium-deep waters. WB03 lies ab. 50km SE of the John Agyekum Kufuor (JAK) FPSO serving the Sankofa field and is adjacent east to UB Resourcesâ Offshore Cape Three Points South block. It is also assumed to contain the Lynx-1 o&g discovery (Lukoil, 2014)."
85018,"Further to DEA 29 Apr '20 (adds. status): NW part of AE-0013-2M-Pilar de Akal-Kayab-04 (AE-0161-Chalabil) block, offshore Sureste Basin, WD 37m, P&A dry as of Jan '20, Indepedencia I JU. PTMD was 4,790m (4,750m TVD), target U. Jurassic.","Mexico (Sureste B.), Ku-201EXP npw, operated by PEMEX (100%), NW part of AE-0013-2M-Pilar de Akal-Kayab-04 (AE-0161-Chalabil) block, offshore, WD 37m, P&A dry as of Jan '20, Indepedencia I JU. PTMD was 4,790m (4,750m TVD), target U. Jurassic."
20443,"Statoil announced on 30 April 2018 that it has agreed to sell its 17% interest in the Alba field, which lies in block 16/26 (P213) to Verus Petroleum. The field is considered a non-core asset and the sale will enable Statoil to focus on core activities. Under the agreement Statoil will retain decommissioning liabilities for the infrastructure in place, but any new installations will be the responsibility of Verus. The effective date of the transaction is 1 January 2018. It is subject to partner and regulatory approval. Alba was discovered in 1984 and first production was achieved in January 1994, since then it has produced over 424 MMbo and 122 Bcfg. Chevron, who operates the field, commenced development drilling in January 2018, following an 18-month break. This follows a 4D survey which was acquired in 2014 from which data was used to plan for development drilling to sustain production and increase recovery. Development drilling is expected to continue beyond 2020. Following completion of the deal interest in Alba will be held Chevron North Sea Limited (23.37%, operator), Endeavour Energy UK Limited (25.68%), Verus Petroleum UK Limited (17%), Mitsui E&P UK Limited (13.3%), Spirit Energy Resources Limited (12.65%), EnQuest Production Limited (6.8%) and EQ Petroleum Sabah Limited (1.2%).","United Kingdom, Alba"
56765,"On 16 August 2019, the National Oil, Gas and Biofuel Agency (ANPG), Cabinda Gulf Oil Company Limited a wholly owned subsidiary of Chevron and Sonangol E.P. signed a cooperation protocol for the study and evaluation of Block 33. Block 33 currently does not have an operator, should the results of the study prove promising Chevron may assume this role, with Sonangol as a partner. The 4,936 sq km block located primarily atop the Congo Fan plays host to a small oil discovery - Calulu 1 - discovered in the early 2003 by Esso Exploration Angola (Block 33) Ltd. Water depths across the block range between 1,500 and 2,500 m. Itâs worth noting that this is the second study protocol signed by Chevron this year - in June the company signed a similar agreement for Block 34.",ANPG & Cabinda Gulf Oil Company a wholly owned subsidiary of Chevron and Sonangol E.P. signed a cooperation protocol for the study and evaluation of Block 33.
16512,"PetroChina-Sichuan completed a new field wildcat Wutan 1 in the eastern section of the Sichuan Basin in end-February 2018. The well had multiple objectives, primarily targeting the Jurassic clastic and Pre-Cambrian carbonate formations, to better understand the basin evolution and new play fairways. It encountered shows in the Permian Maokou carbonate Formation. The well reached a TD of 8,060 m with bottom-hole in the Pre-Cambrian Nantuo Formation. Ultra-deep pressure and ultra-high temperature were experienced at this unit. In the shallower section, high pressure with high H2S content was seen in the Permian carbonate Formation during drilling. The well likewise intersected high temperature at the Cambrian Salt Formation. PetroChina plans to produce 30 Bcm by 2020 and 70 Bcm by 2035 in the Sichuan Basin. The company has been exploring the basin for more than 60 years and has proven 92 Tcf of gas in place by 2017. PetroChina produced 21 Bcm in 2017. Currently, the main reservoir in the eastern Sichuan Basin is the Carboniferous Formation found in the Datianchi Complex fields such as Wubaiti (Datianchi Complex). PetroChina is looking for a new gas play to further explore the upside in the area.",China (Sichuan B.) ? op. by PETCHIN SC (100.0%) in Wubaiti block
47726,"Ugandaâs 2nd round, in which 7 blocks will be available in the Albertine Graben, is expected to launch during the 9th EAPCE conference taking place 8-10 May in Mombasa, Kenya.","Ugandaâs 2nd round, in which 7 blocks will be available in the Albertine Graben, is expected to launch during the 9th EAPCE conference taking place 8-10 May in Mombasa, Kenya."
50801,"Era secured sole rights to the 153-sq km M32-C4 licence in the Koniya Basin, S-C Turkey, on 28 May â19 for 5 years.","Era secured sole rights to the 153-sq km M32-C4 licence in the Koniya Basin, S-C Turkey, on 28 May â19 for 5 years."
15285,"Shell signed the PSC for block 4 on 20 Feb â18 after 2 years of negotiations for what has become a 7-year contract (3 phases). The permit covers 2,265 sq km onshore in the Ionian Zone. Commitments include 125 km of 2D seismic + reprocessing of the same amount in phase 1, 300km of 2D + reprocessing of 200km + an optional 3,000m well in phase 2, 1 well in phase 3. The award will be effective upon gazettal. ",Shell (100%) was formally awarded the Block 04 PSC.
79579,"PTTEP has completed an outpost well, WMG-D01 (DA) (Wang Mai Sung-D01 (DA)), in the S1 Reserved Area, onshore Phitsanulok Basin, on 2 April 2020, as an oil well. The well was drilled to a TD of 2,386 m using the â50151HDâ land rig. Spudded on 24 March 2020, the well located approximately 5 km southeast of the Sam Phaya C-01 oil discovery and 10 km northeast of the Pratu Tao field, likely targeted analogous sandstone reservoirs of the Upper Oligocene-Middle Miocene Lan Krabu Formation. The previous exploration drilling activity in the block was Chik Yao A-02ST that was abandoned as dry on 21 September 2019. The new-field wildcat was drilled to a TD of 3,518 m, using the âGWT-11â land rig. The Phisanulok Basin has proven to be a prolific oil province in onshore Thailand. New oil accumulations have been found in the heavily faulted geology over the years of exploration by PTTEP. Although new accumulations could be small, early and cheaper monetisation is possible due to mature extensive network of development in the surrounding area. The S1 Reserved Area, which also contains the Sirikit field, is operated by PTTEP with 100% interest. Background information The S1 Reserved Area consists a total of 33 fields, 15 of them are producing including the Wang Mai Sung B field. PTTEP concluded the WMG-B01 oil discovery on 23 October 2014. The well was drilled to a TD of 3,424 m using the âGWT-11â land rig. It was spudded on 9 October 2014. Oil was discovered likely in the reservoirs of the Upper Oligocene-Middle Miocene Lan Krabu Formation. The Phitsanulok basin is a north-south trending intracratonic rift, covering an area about 6,000 sq km over the central plains of Thailand. The basin fill comprises alluvial fan, fan delta, alluvial plain, lacustrine delta and open lake deposits, with sediments up to 8 km thick at the western of the basin. Thai-Shell and PTTEP carried out extensive exploration and the production activities of this basin and in particular at the Sirikit Field which originally contained over 100 MMboe (P+P) of recoverable reserves. PTTEP acquired the operatorship of the Block S1 (Sirikit) complex on 30 December 2003, when it agreed to buy the entire right holdings of Thai Shell for around USD 205 million.",Thailand (Sukhothai Depression (Phitsanulok B.)) Wang Mai Sung B
30925,"The energy ministry has plans for a new round designated Litoral in which blocks 3, 4, 39 + 40 in the Progreso, Borbón + Cayo basins would be offered, too early for details. Past data however suggests blocks 3 + 4 (3,000 sq km) are in the transition zone,  block 39 (3,850 sq km) and block 40 (4,000 sq km) lie in WD 100-2,000m, the latter on the Peru border.","The energy ministry has plans for a new round designated Litoral in which blocks 3, 4, 39 + 40 in the Progreso, Borbón + Cayo basins would be offered, too early for details. Past data however suggests blocks 3 + 4 (3,000 sq km) are in the transition zone, block 39 (3,850 sq km) and block 40 (4,000 sq km) lie in WD 100-2,000m, the latter on the Peru border."
13364,"On 2 January 2018, the General Directorate of Petroleum Affairs (GDPA) approved the transfer of a 12.25% interest in the Block 4877 production licence from Foinavon Energy Inc to Park Place Energy Turkey Ltd, a subsidiary of Park Place Energy Inc. The companies had applied for the transfer on 21 November 2017. Following the transaction Turkish Petroleum Corp (TPAO) operates the acreage with a 51% interest and is partnered by Park Place Energy Inc through its two subsidiaries, Park Place Petrol Arama Uretim AS (26.75%) and Park Place Energy Turkey Ltd (22.25%).The Block 4877 production lease is located off the north coast of Turkey towards the western end of the Black Sea and contains four producing gas fields in water depths ranging from 600m to 1,200m. The three nearer shore gas fields of Ayazli (discovered in 2004), Ayazli East (discovered 2005) and Akkaya (discovered in 2006) were included in an initial phase of development, with first gas production in 2007. The deeper water Akcakoca field (originally discovered in 1976) was developed later, with first gas production in 2011. All of the fields are developed using unmanned well head platforms/tripods, tied back via a 25km, 12"" pipeline to a shared onshore processing and compression facility at Cayagzi.Park Place Energy Inc obtained its interest in the production lease in 2016, through the acquisition of three Tiway Oil BV subsidiaries. The company has drawn up plans to carry out a redevelopment of the producing fields, as it believes that it can access substantial behind-pipe reserves through a low-cost work programme.","General Directorate of Petroleum Affairs (GDPA) approved the transfer of a 12.25% interest in the Block 4877 production licence from Foinavon Energy Inc to Park Place Energy Turkey Ltd, a subsidiary of Park Place Energy Inc. "
68062,"Only 3 of 10 blocks offered in the Red Sea round have attracted bids: Chevron has taken its 1st position in Egypt with the northernmost block 1 (3,057 sq km), and Shell got blocks 3 + 4 (3,097 + 3,084 sq km resp), the latter in partnership with Mubadala. At the time of round closing in September, Shell, ExxonMobil, Statoil, Dragon Oil, Rosneft and Total had been expected to bid. Ganope map adaptation below.","Only 3 of 10 blocks offered in the round have attracted bids: Chevron has taken its 1st position in Egypt with the northernmost block 1 (3057km²), and Shell got blocks 3 + 4 (3097 + 3084km² resp), the latter in partnership with Mubadala. At the time of round closing in September, Shell, ExxonMobil, Statoil, Dragon Oil, Rosneft and Total had been expected to bid. "
56179,"In the quarterly report on 12 August 2019, Valeura Energy Inc. provided the production test details for Inanli 1 appraisal well at the Yamalik discovery in Block F18-C (deep) in the Thrace Basin and it was reported that a 21 m gross interval between 4,263 to 4,284 m depth was stimulated and the well started flowing since 3 August 2019. Average gas flow rate during the first eight days was 643 Mcf/d along with 44 bw/d whereas condensate production was low in the well â condensate gas ratio was 5 bbl/MMcf. Petrophysical data indicated that the zone is moderately fractured with a 14.2 m of net sand of 5% average porosity which is above the cutoff value of 3% porosity. The company carried out small reservoir stimulation prior to production testing and applied artificial lift. Valeura had reported on 25 June 2019 that it was commencing the reservoir stimulation and testing operations in Inanli 1 well and all the required equipment have been arrived at the wellsite. The company planned to conduct Diagnostic Fracture Integrity Test (DFIT) and Extended Leakoff Test (XLOT) operations during that week, which will be followed by the reservoir stimulation during the first week of July 2019. The company intends to test at least four zones. Valeura had earlier reported on 9 May 2019 in the quarterly report that it had conducted two DFITs in Inanli 1 well which indicated the presence of deep gas at a very high pressure. The company had reported on 28 January 2019 that the Inanli 1 well reached the final TD of 4,885 m in the Eocene Kesan Formation and the casing was set to secure the well for future completion, fraccing and production testing. The objective zone between 3,270 m to 4,885 m (1,615 m gross) within the Mezardere â Kesan formations is high net-to-gross sandstone and, on the basis of drilling and wireline logging data, it is interpreted to contain over-pressured gas. The well encountered more natural fracturing than the Yamalik 1 well, containing four distinct intervals of approximately 600 m gross â all four within the Kesan formation. The drilling rig was released to drill next appraisal well, Devepinar 1, located 18 km west of Yamalik 1. Inanli 1 was the first of the three-well appraisal drilling programme at the Yamalik discovery. Inanli 1, located 6 km north-east of Yamalik 1 and designed to test the vertical extent of the basin-centred gas play, was spudded on 8 October 2018 using the KCA Deutag T-700 land rig with a PTD of 5,000 m. The main objectives were the Eocene Teslimkoy and Kesan formations, lying just below the Mezardere formation. The company expected to complete the drilling activity in late December 2018 which will be followed by a fraccing and testing operation during Q1 2019. It will be the final earning well under Phase 3 of the Banarli farm-in to be funded by Equinor (previously Statoil Banarli Turkey B.V.). Valeura Energy had earlier released the results for third quarter (quarter ending 30 September 2018) on 13 November 2018 in which it was reported that the drilling activity in Inanli 1 well was continuing and it reached 3,460 m depth near the base of Mezardere Formation where a casing will be run. The well encountered high pressure sand in lower Mezardere Formation of Oligocene age between 3,262 m to 3,440 m depth which the company believed was gas-bearing. The company subsequently reported on 20 December 2018 that the well was drilling at 4,145 m depth, achieving positive results. On the basis of drilling and gamma ray log data recorded while drilling, the well was reported to have encountered the top of the main objective at around 3,270 m depth. Initial results suggested 40% net-to-gross of the drilled prospective section which was similar to Yamalik discovery well. The well was reported to have encountered over-pressured gas throughout the objective section with several instances of gas flowing through the wellbore to the surface which was safely flared. The company had completed the Yamalik 1 re-completion operation and connected the newly-build pipeline to the gas production infrastructure in Q3 2018 before initiating long term production testing.   Background Information On 6 January 2017, Valeura announced that it had received a USD 6 million payment and subsequently completed the farm out to Statoil ASA for its F18-C and F19-D1, D4 licences in the Thrace Basin. It was announced on 30 December 2016 that the company had received the relevant government approvals for the farm in. Statoil can now earn up to a 50% interest in the deep rights by investing USD 36 million in the Banarli licences. The USD 6 million payment is a contribution to back costs incurred on the Banarli licences. The agreement covers the farm-out of the deeper formations, below approximately 2,500 m, in the licences. Valeura Energy will continue to hold 100% of the rights to the shallower formations. Valeura spudded the Yamalik 1 new field wildcat on 13 May 2017. It was designed to evaluate a potential high-impact, over-pressured, basin-centred gas play below approximately 2,500 m in the Thrace Basin. Statoil funded the drilling programme on a 100% basis up to a cap of 110% of the AFE amount. On 15 May 2018, Statoil officially changed its name to Equinor.","Valeura Energy Inc. provided the production test details for Inanli 1 appraisal well at the Yamalik discovery in Block F18-C (deep) in the Thrace Basin and it was reported that a 21 m gross interval between 4,263 to 4,284 m depth was stimulated and the well started flowing since 3 August 2019. Average gas flow rate during the first eight days was 643 Mcf/d along with 44 bw/d whereas condensate production was low in the well â condensate gas ratio was 5 bbl/MMcf."
69836,"It was announced on 19 January 2020 that Turkiye Petrolleri A.O. (TPAO) has been awarded the G17-A onshore exploration licence (Thrace Basin) on 9 January 2020 for a period of five-year. The licence, covering an area of 585 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-A 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)"
11282,"Statoil has signed up for a 25% interest from Petrobras in the latterâs Roncador field offshore Campos Basin. Statoil will pay an initial USD 2.35 bn, followed by additional payments totalling up to USD 550 MM. Roncador has been in production since 1999 with output currently ar. 240,000 bo/d + 40,000 boe/d associated gas, >1 Bboe remaining recoverable. Petrobras will retain 75%.",Brazil (Campos B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Roncador op. by PETROBRAS (100.0%) to be check.
79913,"Green Canyon block 166, WD 649m, drilled mid-Mar - 13 Apr '20, results n/a, Valaris DS-18 (formerly Rowan Relentless DS). EnVen (op), partners Ridgewood, Red Willow Offshore + Houston Egy.","GC 166 SS1S0B0 (Dothraki) nfw Green Canyon block 166, WD 649m, drilled mid-Mar - 13 Apr '20, results n/a, Valaris DS-18 (formerly Rowan Relentless DS). EnVen (op), partners Ridgewood, Red Willow Offshore + Houston Egy."
75950,"Panyu Low Massif, PRMB, South China Sea, WD 187m, ops concluded (results n/a) late Mar '20, Nanhai 8 SS. Target Oligo-Miocene clastics.","Panyu 29-3-1 (PY 29-3-1) nfw Panyu Low Massif, PRMB, South China Sea, WD 187m, ops concluded (results n/a) late Mar '20, Nanhai 8 SS. Target Oligo-Miocene clastics."
67813,"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. The well was concluded as a wet gas discovery on 4 December 2019, with the rig leaving the wellsite on 5 December 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. With the well a success, tie-back to the Shell operated Prelude facilities, which lie around 150 km southwest, offer a potential avenue for commercialisation. 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 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. 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% operated interest in the permit.","Bratwurst 1 nfw. (Shell 100%), committed well in AC/P64, Caswell sub-basin, ops terminated. significant gas-cond find. WD ca. 155m, PTD was 4750m."
84589,"Further to DEA 1 Jul '20, Vintage was selected as preferred applicant for CO2019-E, now PELA 679, 393 sq km in the Cooper-Eromanga, released as part of the 2019 SA acreage release. 5-yr commitments include 100 sq km of 3D seismic + 2 wells. A farm-in partner may be sought.","Australia (Cooper-Eromanga B.), Vintage was selected as preferred applicant for CO2019-E, now PELA 679, 393 sq km in the Cooper-Eromanga, released as part of the 2019 SA acreage release. 5-yr commitments include 100 sq km of 3D seismic + 2 wells. A farm-in partner may be sought."
9743,"Effective 1 October 2017 Hilcorp Alaska LLC was officially awarded 14 tracts covering about 76,682 acres (310 sq km) off Alaskaâs 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 saleâs 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"
80864,"NEO Energy has taken over operatorship of the Babbage gasfield from Spirit Energy, who has withdrawn along with its 13% interest. The Babbage field + Cobra discovery lie in P456 / block 48/2a, from which Neo hopes to bring production to between 80-100,000 boe/d. Day-to-day management of the field has been entrusted to ODE, a Doris Group-owned company. Until now, Babbage was run by Spirit in partnership with Dana (40%) and Neo (47%).","NEO Energy has taken over operatorship of the Babbage gasfield from Spirit Energy, who has withdrawn along with its 13% interest. The Babbage field + Cobra discovery lie in P456 / block 48/2a, from which Neo hopes to bring production to between 80-100,000 boe/d. Day-to-day management of the field has been entrusted to ODE, a Doris Group-owned company. Until now, Babbage was run by Spirit in partnership with Dana (40%) and Neo (47%). "
38282,"Further to DEA 19 Nov â18, Petrel has signed a share purchase agreement (SPA) to acquire Warrego Energy via a reverse takeover, expected to be completed on 19 Feb â19. Warrego runs EP 469 in the North Perth Basin, where partner Strike Energy will fund AUD 11 million towards the drilling of West Erregulla-2 in 1H â19. Outside Australia, Petrel has interests in Uruguay, Ireland and Spain, where it plans to drill next year (Tesorillo-1).",Petrel has acquired 100% interest in EP 469 block from Warrego Egy.
36669,"On 4 December 2018, DEA issued a press release indicating it signed an agreement to acquire all of the non-operated working interest assets held by Sierra Oil and Gas in six exploration blocks offshore in the Campeche Deep Sea and Sureste basins. The deal is pending formal governmental approvals. The deal value has yet to be reported. Sierra held varying non-operated working interest percentages in the six blocks of 22.5% to 40%. The CNH-R01-L01-A7/2015 contract is the highlight of the deal with the Zama discovery now being appraised.  DEA indicated that it is now one of the largest acreage holders in the country with this acquisition as it is now combined with the five blocks it has acquired through various bid rounds. DEA acquisition of Sierra Assets in offshore Mexico â 4 December 2018 Block Contract Previous Operator and Partners New Operator and Partners Area sq km Bid Round Well Commitments Area 2 CNH-R01-L01-A2/2015 Hokchi 47.5%,Talos 20%, Sierra Blanca 22.5%, Premier 10% Hokchi 47.5%,Talos 20%, DEA 22.5%, Premier 10%                    195.64 R1.1 1 Area 7 CNH-R01-L01-A7/2015 Talos 35%, Sierra 40%, Premier 25% Talos 35%, DEA 40%, Premier 25%                    468.19 R1.1 1 A4.CS CNH-R01-L04-A4.CS/2016 PC Carigali 50%, Sierra 50% PC Carigali 50%, DEA 50%               2,380.34 R1.4  A5.CS CNH-R01-L04-A5.CS/2016 Murphy 30%, Ophir 23.33%, PC Carigali 23.34%, Sierra 23.33% Murphy 30%, Ophir 23.33%, PC Carigali 23.34%, DEA 23.33%               2,595.78 R1.4 1 A11.CS CNH-R02-L01-A11.CS/2017 Repsol (60%), Sierra (40%) Repsol 60%, DEA 40%                   537.20 R2.1  AP-CS-G10 CNH-R02-L04-A29.CS/2018 Repsol 30%, PC Carigali 28.33%, Sierra 25%, PTTEP 16.76% Repsol 30%, PC Carigali 28.33%, DEA 25%, PTTEP 16.76%               3,280.26 R2.4 2  Source: IHS Markit  © 2018 IHS Markit",DEA issued a press release indicating it signed an agreement to acquire all of the non-operated working interest assets held by Sierra Oil and Gas in six exploration blocks offshore in the Campeche Deep Sea and Sureste basins.
61731,"The govt website (www.bndh.gob.do) announces it has settled on a final list of blocks available under the DR's 1st round, prequalification deadline for which is 5 Nov '19. The text, dated yesterday, reports 15 blocks on offer, although the official map still shows 14 as earlier reported. Updates will be reported when available. 14 blocks so far: Onshore: Cibao Basin (6 blocks), Enriquillo Basin (3 blocks), Azua Basin (1 block). Offshore: San Pedro Basin (4 blocks).","The govt website (www.bndh.gob.do) announces it has settled on a final list of blocks available under the DR's 1st round, prequalification deadline for which is 5 Nov '19. The text, dated yesterday, reports 15 blocks on offer, although the official map still shows 14 as earlier reported. Updates will be reported when available. 14 blocks so far: Onshore: Cibao Basin (6 blocks), Enriquillo Basin (3 blocks), Azua Basin (1 block). Offshore: San Pedro Basin (4 blocks)."
12309,"Lundin Petroleum has announced that its wholly owned subsidiary Lundin Norway has completed the drilling of the Hurri exploration well 7219/12-3S located in PL533 in the southern Barents Sea. The well was dry. The main objectives of the well were to test the reservoir properties and hydrocarbon potential of the Upper Jurassic Hekkingen formation and Middle Jurassic Stø formation. The well encountered no reservoir development in the Hekkingen formation and good reservoir in the Stø formation but with no indications of hydrocarbons. Extensive data acquisition and sampling were carried out. The well was drilled using the semi-submersible drilling rig Leiv Eiriksson which after completion of operations on the Hurri well will proceed to abandon the Filicudi discovery well, also located in PL533. Lundin Norway is the operator of PL533 with a 35 percent working interest. The partners are Aker BP with 35 percent and DEA Norge with 30 percent.Lundin's Hurri Prospect is 2 km southwest of the Filicudi oil discovery (Source: Lundin) Original article link Source: Lundin Petroleum ","7219/12-03 S (Hurri) op. by Lundin (35%, Aker BP 35%, DEA 30%) in PL 533 block, 32km NW of Alta discovery, no reservoir properties in Hekkingen and a good reservoir in Sto fms. but with no indication of hc. P+A, dry ."
78888,"Equinor spudded 30/6-31 S using the ""West Hercules"" S/S on 4 April 2020. The rig was on site on 11 March 2020 but a few days later it had left and was back at shore, delayed due to the coronavirus disease 2019 (COVID-19). 30/6-31 S targeted the Middle Jurassic Helleneset prospect on the eastern flank of Oseberg in PL 053. Equinor drilled to TD at 2,852 m (2,832 m TVD) and abandoned the well on 25 April 2020. Results will be announced shortly. Equinor was successful earlier in the year (July 2019) in drilling a well on the western flank of Oseberg. An exploration extension of development well 30/6-H9 (T4) found a 112 m oil column in the Lower Jurassic Statfjord Formation in the southern part of the Alpha structure, a segment of Oseberg that was previously undrilled (and known as Alpha Main Statfjord). Estimated recoverable reserves are 22 MMbo. Equinor brought the new volumes online shortly after discovery and was considering the use of water injection to boost production further. The drilling was part of the Oseberg Vestflanken 2 project which came onstream in October 2018 using a new platform â Oseberg H. Interest in PL 053 is divided between Equinor Energy AS (49.3% + operator), Petoro AS (33.6%), Total E&P Norge AS (14.7%) and ConocoPhillips Skandinavia AS (2.4%).","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."
24657,"As announced on 2 July 2018, SOCO International plc (SOCO) entered into a sale and purchase agreement (SPA) with Quill Trading Corporation (QTC) and WMLC Resources Limited (WMLC) to sell its entire shareholding in SOCO Cabinda Ltd. QTC and WMLC will pay SOCO up to USD 5 million for SOCOâs 85% stake in SOCO Cabinda (holds a 22% interest in the Cabinda North Block). The completion of the SPA is conditional upon customary approvals. The long stop date is 31 July 2018. The interests in the licence upon close of deal will be ENI (operator) with a 48% interest, Sonangol P&P with a 20% interest, SOCO Cabinda with a 22% interest (held entirely by QTC and WMLC) and Angola Consulting Resources with a 10% interest. Itâs worth noting that QTC already holds an interest in SOCO Cabinda. Background Information In late 2017, Eni took over operatorship of the 2,400 sq km Cabinda Norte block (formerly Cabinda A) located in the north of Angola, adjoining the Congo Brazzaville border. The Cabinda onshore area is underlain by a graben separated from the main Atlantic rift by a basement high. The graben, known in Democratic Republic of Congo (DRC) as the Lemba Trough, has its own kitchen, and is a proven oil play in Cabinda and in DRC. In the sixties Chevron, then Gulf, explored extensively in the area and drilled an estimated 69 wildcats and four outposts in the 4,625 sq km area which is now under license. Gulf made one gas and five oil discoveries considered marginal at the time, an additional seven wells had oil shows. New exploration techniques (3D and much improved 2D seismic), better geological models and new concepts, and the excellent wildcat coverage for calibration of the models, have all contributed to the understanding of the area and itâs prospectively.",Quill Trading Corp and WMLC Resources acquired 22% non-operating interest in the Cabinda Norte (2151km²) block from Soco for up to US$5 MM.
27052,"Further to 24 Jul â18. WA-437-P, Greater Phoenix area in N. Carnarvon Basin (Bedout), additional light oil discovered in the Crespin (22m net pay) and Milne (18m net pay) members, adding to oil in the Caley member and gas/condensate in the Baxter member, 132m of net hydrocarbon pay in total so far, Ensco 107 JU. Quadrant (op), partner Carnarvon.","Dorado 1 (Quadrant 80% op, Carnarvon 20%) in WA-437-P (Gr. Phoenix area), light oil discoveries had been made in the Crespin and Milne Members, adding an additional 40m of net oil pay. This takes the total hc net pay in the well to 132m, which also includes the previous light oil discovery in the Caley Member standstone, as well as gas and condensate in the Baxter Member."
87820,"Further to DEA 16 Jun '20 (adds status): N. part of Green Canyon block 767, WD 1,532m, target post-salt U. Miocene, 1st of up to 4 wells planned P&A'd dry mid-Jun '20, Valaris DS-18 (ex-Rowan Relentless) released. EnVen (op), partners Ridgewood + Murphy.","(GOM B.) Mt. Ouray nfw in N. part of Green Canyon block 767, operated by EnVen (40%) and partners Ridgewood (40%) + Murphy (20%), P&A dry. WD=1,532m, target post-salt U. Miocene."
33476,"The Beaufort prospect in FEL 5/13 / blocks 35/25a, 35/30, 36/21a, 36/26a, 44/5a + 45/1a is committed as part of phase 2 explo, hoped to be drilled in 2019 / 2020. Underlying Beaufort (ex-Ventry) is the Walton prospect (ex-Ventry Deep). Woodside is believed to be looking to farmout the 948-sq km licence, 45% available. Currently Bluestack Egy partner.","Ireland, not found"
48631,"Pertamina is looking into the possible sale of its 60% interest in the Muara Enim CBM PSC, 520 sq km in S. Sumatra, current optr Trisula CBM Energy (NuEnergy Gas). Letters of Interest are invited by 14 Jun â19 to Ida Yusmiati, PT Pertamina (Persero), Jl. Medan Merdeka Timur No. 1A, Jakarta 10110 (ida.yusmiati@pertamina.com).","Pertamina is looking into the possible sale of its 60% interest in the Muara Enim CBM PSC, 520 sq km in S. Sumatra, current optr Trisula CBM Energy (NuEnergy Gas). "
22318,"OMVÂ : Roseldorf Tief-4 nfw, Lower Austria permit, Vienna Basin in NE Austria, P&A âunsuccessfulâ in late 2017. PTD was ca. 2300m. RAGÂ : Hiersdorf-9 (HIER-009) appr, E. part of Upper Austria permit, TD 2,582m, P&A non-commercial oil in summer 2017, co. E200 rig.","OMV : Roseldorf Tief-4 nfw, Lower Austria permit, Vienna Basin in NE Austria, P&A âunsuccessfulâ in late 2017. PTD was ca. 2300m. RAG : Hiersdorf-9 (HIER-009) appr, E. part of Upper Austria permit, TD 2,582m, P&A non-commercial oil in summer 2017, co. E200 rig."
77946,"Moran ML, Assam Shelf, ops terminated (assumed suspended) late 2019. Likely targets Miocene Tipam + Oligocene Barail Groups and Eocene Sylhet fm.","MGB expl Moran ML, Assam Shelf, ops terminated (assumed suspended) late 2019. Likely targets Miocene Tipam + Oligocene Barail Groups and Eocene Sylhet fm."
10011,"Questerre Energy has closed an acquisition of producing Bakken/Torquay oil assets in the Antler area of southeast Saskatchewan. Michael Binnion, President and Chief Executive Officer of Questerre, commented: 'This accretive acquisition consolidates our operated working interest at Antler. We now own 100% of these assets and add low-decline, high netback light oil production to our base of conventional assets. Post this acquisition, current production from the area, including adjacent production from Pierson, Manitoba, is approx. 450 bbl/d.' The Company acquired approx. 180 bbls/d of light oil production in the Antler area for gross consideration of $7.25 million, subject to customary industry adjustments. Acquired assets include 3D seismic data over the producing acreage with a value of approx. $0.77 million. The effective date of the acquisition is October 1, 2017. The proved and probable reserves associated with these assets will be assessed by the Company's independent reserve engineers in conjunction with the year-end 2017 reserve evaluation. Questerre also reported that it is submitting its comments on the draft hydrocarbon regulations to the Ministry of Energy and Natural Resources in Quebec this week. The Company anticipates that subject to the review of the comments received from stakeholders, the regulations should be finalized in early 2018. Questerre Energy is leveraging its expertise gained through early exposure to shale and other non-conventional reservoirs. The Company has base production and reserves in the tight oil Bakken/Torquay of southeast Saskatchewan. It is bringing on production from its lands in the heart of the high-liquids Montney shale fairway. It is a leader on social license to operate issues for its Utica shale gas discovery in the St. Lawrence Lowlands, Quebec. It is pursuing oil shale projects with the aim of commercially developing these massive resources. Original article link Source: Questerre Energy ","Canada, not found"
14784,"AIM-listed Baron Oil has entered into an option agreement with Corfe Energy to be assigned part of its rights to farm in to UK North Sea Licence P2235, which contains the Wick Prospect. Baron's option must be exercised by 28 February 2018. The Wick Prospect lies close to the shore of NE Scotland, 5 kms north and updip from the Lybster Field, which has been developed from onshore facilities. The prospect has been defined by 3D seismic mapping by Baron and others and a recent announcement by Upland Resources stated it has estimated in-place P50 Prospective Resources of around 250 million barrels of oil sands of Jurassic and Triassic age (unrisked) in the licence area. The Wick Prospect will be tested by a well drilled to a total depth of 1200 metres in a water depth of 50 metres. Drilling operations are expected to commence in September 2018, at an estimated total cost of £4.2 million. Under the terms of the agreements between Corfe and the licence operator, Corallian Energy, if the option is exercised by Baron and subject to necessary consents, the Company would pay 20% of the well costs (£840,000), plus £6,500 in back costs, to earn a 15% interest in the licence. Malcolm Butler is a non-controlling director and shareholder of Corfe but the proposed arrangement involves no financial benefit to Corfe and he has recused himself from Corfe's decision. In Peru Block XXI it remains the intention of the board to drill well El Barco-3X on the Minchales trend and the Company is currently in discussions with a third party who is interested in participating in the well. The block is currently in force majeure, due to some difficulties with the local administration, but it is hoped these can be overcome shortly and the well can be drilled within the next six months. The estimated cost of this well is US$1.4 million, to a total depth of 1850 metres, and it is planned to test both a low-risk, relatively small, shallow gas play and a higher risk, higher potential oil and gas play in fractured basement. Bill Colvin, Chairman of Baron commented: 'As shareholders were informed at the beginning of January, following our success in securing the release of all monies held against the Z-34 Guarantee Bond the board has reviewed a broad range of possibilities to diversify the activities of the Company. 'After due consideration, the board believes that near-term drilling activities in areas where discoveries can easily and profitably be developed represent the best way forward. The Wick Prospect offers an excellent opportunity to drill a relatively low-risk well this year with significant potential and provides the possibility of early, low cost development. Success in the Wick well would provide shareholders with a meaningful uplift in the asset value of the Company. We are also in the process of evaluating another near-term drilling opportunity in the UK 'Now that we have the funds, we will finally be able to move forward with the drilling of the El Barco well in our 100% owned onshore Peru Block XXI and we are encouraged by third party interest in the prospect. This will test a structure defined after several years of extensive geophysical work on the block, the results of which indicate a good chance of success.' Original article link Source: Baron Oil ","United Kingdom, not found"
53547,"ADX has finalised its farm-in agreement (see DEA 8 Apr â19) with Australian Parta Energy for a 50% stake in the 1,104-sq km Parta (E X-10) permit in the Banat sub-basin, in exchange for funding the first USD 1.5 million of a 100-sq km 3D seismic campaign planned in the N. part of the block in Nov â19. The farm-in will exclude the Parta appraisal programme area which includes the Iecea Mare lease.","ADX has finalised its farm-in agreement (see DEA 8 Apr â19) with Australian Parta Energy for a 50% stake in the 1,104-sq km Parta (E X-10) permit in the Banat sub-basin, in exchange for funding the first USD 1.5 million of a 100-sq km 3D seismic campaign planned in the N. part of the block in Nov â19. The farm-in will exclude the Parta appraisal programme area which includes the Iecea Mare lease."
77805,"Advent is looking into farming-down its 85% equity held by its Asset Energy sub in PEP 11, 4,574 sq km offshore in the Sydney Basin, in exchange for funding of drilling in relation to a gas devt project. The farmin % is thought to be negotiable, current partner Bounty O&G. Equity is also thought to possibly be available in RL 1, 165 sq km offshore in the Bonaparte Basin. Contact: David Breeze, email david@bphenergy.com.au.","Advent is looking into farming-down its 85% equity held by its Asset Energy sub in PEP 11, 4,574 sq km offshore in the Sydney Basin, in exchange for funding of drilling in relation to a gas devt project. The farmin % is thought to be negotiable, current partner Bounty O&G. "
40476,"Hitherto-unreported, PGS sub Panoceanic Energy was awarded 9-year rights to licence 2017/14 covering roughly 10,000 sq km off the SW coast of Greenland effective 23 Aug â18. Panoceanic has also 2 applications pending in the Davis Strait, submitted 14 Dec â18.","PGS sub Panoceanic Energy was awarded 9-year rights to licence 2017/14 covering roughly 10,000 sq km off the SW coast of Greenland effective 23 Aug â18. Panoceanic has also 2 applications pending in the Davis Strait"
39276,"As of 10 January 2019, ExxonMobil Canada has acquired Suncorâs 35% working interest in offshore exploration license EL 1134 located in the Flemish Pass Basin giving the company a 100% working interest in the block. The 2,088.99 sq km block was awarded on 15 January 2013 from the NL12-02 Call for Bids held in 2011 for a work commitment bid of CAD 19,875,875. There were no details of the transfer of interest available. In February 2018, ExxonMobil Canada announced it had acquired Husky Oil Operations Ltd 65% working interest and operatorship of offshore exploration license EL 1134 located in the Flemish Pass Basin. There have been no wells drilled in the block under the current contract however a 3D seismic program was acquired over a majority of the contract in 2016. The block originally had a partnership of Husky Oil (operator) 40%, Suncor 35%, and Repsol 25% however Repsol released their interest to Husky which left a working interest breakdown of Husky 65% and Suncor 35%. After the transaction, the block partnership is now ExxonMobil Canada 65% and Suncor 35%. ExxonMobil Canada now is the sole owner of rights to the block.","Canada, EL 1134"
52520,"Hardy is ending its years-long involvement in Indiaâs upstream by selling out its o&g arm to Hindustan for USD 1.5 MM. The deal is subject to usual approvals. Three offshore blocks are involved in the Cauvery + Godavari basins: CY-OS-2, CY-OS-90/1 + GS-OSN-2000/1, none of which are Hardy-operated.","Hardy is ending its years-long involvement in Indiaâs upstream by selling out its o&g arm to Hindustan for USD 1.5 MM. The deal is subject to usual approvals. Three offshore blocks are involved in the Cauvery + Godavari basins: CY-OS-2, CY-OS-90/1 + GS-OSN-2000/1, none of which are Hardy-operated."
25239,"BHP Billiton Petroleum (Deepwater) was awarded Green Canyon Block GC 823 (G36305) on 1 July 2018. The block is situated in the East Texas Coastal Basin. The block was originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, BHP Billiton Petroleum (Deepwater) is now the operator and sole interest-holder (100% WI + Op) in GC 823.","BHP Billiton Petroleum (Deepwater) was awarded Green Canyon Block GC 823 (G36305) on 1 July 2018. The block is situated in the East Texas Coastal Basin. The block was originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, BHP Billiton Petroleum (Deepwater) is now the operator and sole interest-holder (100% WI + Op) in GC 823."
52445,"On 27 June 2019, the Federal Agency for Subsoil Use held an auction for four blocks in Perm Kray (Volga-Ural Province). Lukoil-Perm and STG-Service emerged as the winner of the auction. Details are as follow: The Osinskiy Zapadnyy block covers 440 sq km and encompasses the Glubokovskiy prospect with oil resources estimated at 7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 28 MMbbl of oil. The starting price amounted to RUB 17.74 million (USD 0.28 million). The winner of the auction will obtain a 25-year license. Lukoil-Perm offered RUB 19.51 million (USD 0.31 million). The Oshinskiy block covers 40.5 sq km and encompasses a part of the Kudryavtsevskoye field with 3P oil reserves estimated at 0.7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 13 MMbbl of oil. The starting price amounted to RUB 23.273 million (USD 0.36 million). The winner of the auction will obtain a 25-year license. Lukoil-Perm offered RUB 25.6 million (USD 0.40 million). The Cherchinskiy block covers 10.5 sq km and encompasses the Cherchinskoye field with 3P oil reserves estimated at 0.3 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil. The starting price amounted to RUB 4.14 million (USD 0.06 million). The winner of the auction will obtain a 25-year license. Lukoil-Perm offered RUB 4.55 million (USD 0.066 million). The Zubovskiy block covers 6.04 sq km and encompasses the Zubovskoye field with 2P oil reserves estimated at 0.1 MMbbl. The starting price amounted to RUB 4.488 million (USD 0.07 million). The winner of the auction will obtain a 20-year license. STG-Service offered RUB 4.936 million (USD 0.076 million).","Lukoil-Perm had been awarded the Osinskiy, Osinskiy Zapadnyy, Cherchinskiy blocks and STG-Service Zubovskiy block."
52288,"Lime Petroleumâs parent company Rex International announced that Lime signed an agreement on 21 June 2019 to acquire Wintershall Deaâs 30% interest in PL 838 and PL 838 B. The licences cover parts of blocks 6507/3, 6507/5 and 6507/6. Operator PGNiG will drill exploration well 6507/5-9 S on the Shrek prospect in PL 838 in October 2019. The well will be drilled using the âDeepsea Nordkappâ S/S to a TD of 2,303 m over the course of around 24 days. The objectives are the Jurassic Viking, Fangst and Bat groups and partner Aker BP reports prospective resources of 10-22 MMboe. If the well is successful a sidetrack is planned. Prospective horizons were identified and de-risked through using the Rex Virtual Drilling tool which focusses on AVO and geological / geophysical analysis. Shrek is located approximately 9 km south of Skarv and, in the event of a discovery, could be tied back to the Skarv facilities. The deal is subject to regulatory approval. Skarv is operated by Aker BP. Gas production began on 1 January 2013 and oil production commenced three months later. Skarv was developed using an FPSO and five subsea templates, with tanker offtake for oil and gas piped through an 80 km line into the Asgard Transport System and on to the European market. The field has an expected field life of 25 years. Following completion of the deal interest in PL 838 and PL 838 B will be held by PGNiG Upstream Norway AS (40% + operator), Aker BP ASA (30%) and Lime Petroleum AS (30%).",Lime Petroleumâs parent company Rex International announced that Lime signed an agreement on 21 June 2019 to acquire Wintershall Deaâs 30% interest in PL 838 and PL 838 B.
84289,"Further to DEA 5 Feb '20, the takeover by PGN sub Saka Energi of Petronas' 80% interest + operatorship in the Muriah PSC off E. Java was made official by Migas on 22 Jun '20. Saka holds 100% in the 2,821-sq km, 2-block permit.",The takeover by PGN sub Saka Energi of Petronas' 80% interest + operatorship in the Muriah PSC off E. Java was made official by Migas
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%)."
51790,"The NPD reported on 20 June 2019 that Equinor has carved out a new licence from PL 193. PL 193 GS consists of two part blocks from block 34/11 covering an area of 38 sq km. With effect from 29 May 2019 Spirit Energy left licences PL 193 GS and PL 193 E transferring its 19% interest in the licences to Equinor. In the second half of 2019 Equinor will drill test production well 34/10-C-21 A at Nokken located in PL 193 GS, east of Gullfaks. The Middle Jurassic Brent Group reservoir will be tested and fracked. Testing is expected to commence 1H 2020 and last between three and six months depending on well performance. Results from the well will be used to determine the development solution for the field. The well will be an extended reach well, drilled by the Gullfaks C rig. Nokken was discovered in 1996 by Statoilâs 34/11-2 S well. Gas and condensate flowed from the Etive and Ness formations (DST 1A) at a rate of 4.5 MMcfg/d plus 786 bc/d and from the Tarbert and Ness formations (DST 2) at a rate of 6.1 MMcfg/d plus 471 bc/d. The NPD (December 2018) puts potential recoverable reserves at 125 Bcfg plus 9 MMbc. Interests in PL 193 E and PL 193 GS is held by Equinor Energy AS (58.55% + operator), Petoro AS (30%), A/S Norske Shell (6.45%) and Total E&P Norge AS (5%).",The NPD reported on 20 June 2019 that Equinor has carved out a new licence from PL 193. PL 193 GS consists of two part blocks from block 34/11 covering an area of 38 sq km.
32217,"The ANP has cleared Imetame to acquire the 30.65% interest held by partner Orteng in the Cardeal Amarelo and Cardeal do Nordeste prod. leases, Imetame now sole holder. Orteng otherwise retains its 30.65% in the remaining valid exploration areas of the related BT-REC-035 contract, REC-T-210 block and BT-REC-036 contract, REC-T-211 block.","Brazil, BT-REC-035"
10308,"Pancontinental has been awarded operatorship and 75% of block 2713, Â 10,947 sq km in the Orange Basin, WD 500-3,200m, for an initial 4-year term. A new Petroleum Exploration Licence (PEL) will now be issued over the area. Pancontinental (op), partners Cuevos Investments 15%, Namcor 10%. ","Namibia, not found"
10374,"Confirmation DEAs 28 + 30 Nov â17: ExxonMobil has now confirmed the award of PSC rights to deepwater blocks C14, C17 and C22, total ab. 34,000 sq km west of held acreage, in WD 1,000-3,500m. ExxonMobil (op) 90%, partner SMHPM. Sketch below extracted from GEPS map, blocks outlined in red (from S to N C14, C17 C22): ","Mauritania, not found"
55536,"On 2 August 2019, the State Agency for Geology and Subsoil Use of Ukraine announced an auction for five licenses in the eastern Ukraine. The auction is scheduled for 30 October 2019 with its application deadline on 29 October. 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 Vatazhkivska block covers 181.8 sq km in Poltavska Oblast (Dnieper-Donets Basin). Seismic coverage amounts to 533 km. One well has been drilled in the block. Gas resources of the Vatazhkivska prospect are estimated at 106 Bcf. Commitments include acquisition of 2D and 3D seismic data and drilling of two wells with PTDs of 5,700 m and 6,300 m. The starting price amounts to UAH 6.794 million (USD 0.27 million). The Pechenizko-Kochetkivska block covers 262.7 sq km in Kharkivska Oblast (Dnieper-Donets Basin). Seismic coverage amounts to 895 km. No wells have been drilled in the block. Gas resources of the Pechenizka prospect are estimated at 63 Bcf. Commitments include acquisition of 2D and 3D seismic data and drilling of one well. The starting price amounts to UAH 4.658 million (USD 0.18 million). The Saltivska block covers 26.16 sq km in Kharkivska Oblast. Seismic coverage amounts to 294 km. One well has been drilled in the block. Gas resources of the Saltivska prospect are estimated at 0.2 Bcf. Commitments include acquisition of 2D and 3D seismic data and drilling of one well. The starting price amounts to UAH 7.032 million (USD 0.28 million). The Knyazhynska block covers 75.32 sq km in Kharkivska Oblast. Seismic coverage amounts to 265 km. No wells have been drilled in the block. Hydrocarbon resources of the block are estimated at 107 MMbbl of oil, 2.1 Tcf of gas and 30 MMbbl of condensate. Commitments include acquisition of 2D and 3D seismic data and drilling of one well. The starting price amounts to UAH 254.583 million (USD 10 million). The Zakhidnotokarsko-Krasnyanska block covers 91.1 sq km in Luhanska Oblast (Dnieper-Donets Basin). Seismic coverage amounts to 476 km. Three wells have been drilled in the block. Gas resources of the block are estimated at 31 Bcf. Commitments include acquisition of 2D and 3D seismic data and drilling of one well. The starting price amounts to UAH 1.534 million (USD 0.06 million).","On 2 August 2019, the State Agency for Geology and Subsoil Use of Ukraine announced an auction for five licenses in the eastern Ukraine. The auction is scheduled for 30 October 2019 with its application deadline on 29 October."
12014,"SDX Energy, the North Africa focused oil and gas company, has provided an update on its operations in Morocco. The KSR-16 well has been connected to the sales line and flow testing is expected to commence early next week. The Company will update the market on the results in due course. In addition, SDX has been granted a four-month extension to its Lalla Mimouna permit, through to July 22, 2018. This will allow the Company sufficient time to evaluate the results of its upcoming exploration drilling campaign on the permit, which is expected to take place in March 2018. Following the recent announcement of its spud, the ELQ-1 well in the Gharb Centre permit has been drilled to a total depth of 1484 meters and has encountered 22.6 net meters of reservoir interval and two meters of marginal net conventional gas pay, in the Hoot formation. Management are of the view that the intervals are not sufficiently commercial to complete the well. As such, the well will be plugged and abandoned and the drilling rig will move to the ONZ-7 development location. Paul Welch, President and CEO of SDX, commented: 'Despite the result at ELQ-1, we remain very upbeat about the remainder of our Moroccan drilling campaign, which has already yielded discoveries from the first three of this nine well campaign. It is important to note that this well is also the only one in the current program drilled using legacy low-resolution 3D data, acquired from the previous operator. It was an important test that has strengthened our belief in the need to acquire high resolution 3D seismic data, that we have successfully used in our first three wells, across all of our concessions of interest. 'As previously mentioned, a new high-resolution 3D seismic program, in the Gharb Centre concession, has been awarded and the acquisition is on track to begin in the second quarter of 2018. The result of this survey will double the area covered by high resolution 3D data, providing significant additional potential for prospect delineation. We remain on track to achieve our target of increasing gas sales volumes in Morocco by up to 50% and we look forward to updating the market on this in due course.' Original article link Source: SDX Energy ","Morocco, not found"
38253,"Block 53 (Mukhaizna), onshore S. Oman Salt Basin, Tethys has agreed to acquire Totalâs 2% stake in the 694-sq km block for USD 32 million. Encompasses Mukhaizna, the single largest producing oil field in Oman (100,000+ b/d oil). 30-year PSA signed in 2005. Tethys-Total deal still subject to approval, effective date 1 Jan â18. Remaining partners in Block 53 are Occidental (op, 45%), OOC (20%), Indian Oil (17%), Liwa Energy (15%) and Partex (1%).","Block 53 (Mukhaizna), onshore S. Oman Salt Basin, Tethys has agreed to acquire Totalâs 2% stake in the 694-sq km block for USD 32 million. Encompasses Mukhaizna, the single largest producing oil field in Oman (100,000+ b/d oil). 30-year PSA signed in 2005. Tethys-Total deal still subject to approval, effective date 1 Jan â18. Remaining partners in Block 53 are Occidental (op, 45%), OOC (20%), Indian Oil (17%), Liwa Energy (15%) and Partex (1%)."
69043,"Mukhaizna block 53, ops concluded (suspended?) Dec '19 at TD 3,513m, 3-1/2"" completion string understood run. Rig presumably to Leenah-2, spudded 10 Dec '19, pilot well to 2,948m. Oxy (op), partners OOC, IOCL, Liwa Egy, Total + Partex.","Leenah 1 nfw Mukhaizna block 53, ops concluded (suspended?) Dec '19 at TD 3,513m, 3-1/2"" completion string understood run. Leenah-2 spudded 10 Dec '19, pilot well to 2,948m, presumably same rig. Oxy (op), partners OOC, IOCL, Liwa Egy, Total + Partex."
28574,"Total and partners announce the sale of the 100,000 b/d Joslyn oil sands mining project to Canadian Natural Resources for CD 225 MM. The project had been suspended 4 years ago owing to low oil prices. Total (op), partners Suncor, Joslyn Partnership + Inpex.","Total and partners announce the sale of the 100,000 b/d Joslyn oil sands mining project to Canadian Natural Resources for CD 225 MM. The project had been suspended 4 years ago owing to low oil prices. Total (op), partners Suncor, Joslyn Partnership + Inpex."
24331,"Further to DEA 15 Mar â18, Cairn has now signed a 30-year PSC for block 61, 13,000 sq km on the Demerara Plateau, eastern offshore in WD 60-1,100m, on 26 Jun â18. The block had been preliminarily assigned in 1Q â18, presumably under the open door 2017 offer by Staatsolie. Commitments include 2D seismic + drilling in the explo phase. Staatsolie is entitled to a 20% stake in devt + production. The block outline has yet to be officially published.","Cairn has now signed a 30-year PSC for block 61, 13,000 sq km on the Demerara Plateau, eastern offshore in WD 60-1,100m,"
20647,"Cooper secured VIC/P72, 271 sq km in the Gippsland Basin, on 3 May â18 for a 6-year term. Commitments 260 sq km 3D seismic reprocessing, G&G + 1 explo well in 3 years. Cooper may consider farming-out.","Australia, not found"
23298,"Nong Yao field area in offshore block G11/48, Pattani Trough, drilled 23 Apr â 3 May â18, TD 2,173m, dry, Ensco 115 JU. Follow-ups Nong Yao-7 + 7ST are understood to have also been drilled. Mubadala (op), partner KrisEnergy.","Nong Yao 6, 6ST appr Nong Yao field area in offshore block G11/48, Pattani Trough, drilled 23 Apr â 3 May â18, TD 2,173m, dry, Ensco 115 JU. Follow-ups Nong Yao-7 + 7ST are understood to have also been drilled. Mubadala (op), partner KrisEnergy."
15157,"SK Innovation has announced an oil discovery in the PRMB Block 17/03 in the South China Sea. This marks SK Innovationâs first discovery in the area since its decision to push forward with offshore oil exploration projects as an operator in the South China Sea. Since its signing of block 17/03 PSC in February 2015, SK Innovation has been focusing its technical capabilities on geological and geophysical surveys. In December 2017, it drilled its first exploration well into 2,014m depth and found 34.8m net oil pay. The oil production of the well was tested up to 3,750 barrels per day. SK Innovation plans to drill follow-up appraisal wells to assess reserves and commerciality of the project. SK Innovation currently holds 80% working interest in the block, and 20% is held by CNOOC, the Chinese stated-owned company specializing in offshore oil and gas. A spokesperson from SK Innovation said: 'SK Innovation was the first private company in Korea to step into the upstream oil and gas business, and the companyâs focus on technical expertise ever since its beginning in 1983 led to this significant milestone. Once the commerciality of the project in PRMB is secured, SK Innovation will use it as a platform of growth into other areas in the South China Sea' Original article link Source: SK Innovation ","Lufeng 12-3 (Pr) 1 (LF 12-3-1) op. by SK Innovation (80%, CNOOC 20%) in PSCA 17/03 E. of Lufeng Sag, oil disc. encountered 34,8 m net oil pay, tested up to 3 750 bo/d from Miocene and Oligocene clastics, WD=100m, TD=2014m."
47262,"Alaminos Canyon block 380, lease G32954, WD 1,980m, 122m net oil pay encountered, drilling continues en route to PTD. Target subsalt Frio + Wilcox sands, Deepwater Thalassa DS. Shell (op), partners Equinor + Repsol.","AC 380 001 S0B0 (Blacktip) NFW (Shell 52,375% op. Chevron 20%, Equinor 19,125%, Repsol 8,5%), in G32954 lease, in the Perdido thrust belt, around 48 km from the Perdido spar platform and Whale discovery, encountered more than 122m of net oil pay with good reservoir and fluid characteristics."
69691,"Block ND-2, ultra-deeps off West Luconia, Sarawak, suspended 14 Jan '20, no reason invoked although the move may be linked to claimed border disputes. Target Late Miocene Cycle V turbidite fans, West Capella DS. Wholly-owned, 5,454-sq km ND-2 remains open for farmin:","Lala 1 nfw. in Block ND-2 (remains open for farmin), ultra-deeps off West Luconia, suspended 14 Jan '20, no reason invoked although the move may be linked to claimed border disputes. Target Late Miocene Cycle V turbidite fans."
58043,"P2133 / block 42/4 off Scarborough, SNS, WD 71m, tested, ops terminated late Aug â19, Valaris 121 JU. Target gas in Zechstein Dolomites + Carb. (Visean) channels. ONE-Dyas (op), partners Spirit Egy + Neptune.",United Kingdom (Silverpit B. (Anglo-Dutch B.)) Neptune
26056,"Approximately on 12 July 2018 Black Sea Oil & Gas completed drilling operations in exploration well Paula 1 in the XV-Midia West block. The well was spudded using the GSP âUranusâ J/U in mid-June 2018 in the northeastern part of the block in a water depth of about 75 m. It was targeting the Upper Pontian to Pliocene. The block includes the Ana and Doina fields. The Ana (previously named Doina Sister) and Doina fields are located about 105 km from the coast. The Doina field was discovered in 1995 while the Ana field was discovered in 2007. Both are located along the same fault trend with the same reservoir horizon in the Dacian to Recent Series (Dacian to Holocene) below 766 m. Interest in the XV-Midia West block is divided between Black Sea Oil & Gas SRL (65% + operator), Petro Ventures Europe BV (20%) and Gas Plus International BV (15%).","Paula 1 (BSOG 65% op, Petro Ventures 20%, Gas Plus 15%) in XV-Midia West block, drilling operations terminated, results n/a. It was targeting the Upper Pontian to Pliocene, WD=75m."
55248,"According to local press reports of 30 July 2019 the Minister of Energy declared that the Council of Ministers approved on 29 July 2019 a deal between Total and Eni for the acquisition by the French major of an undisclosed stake in the Eni-operated Block 2, 3, 9 and 8. Until now Eni held Block 2, 3 and 9 along with South Korean KOGAS and Block 8 on its own. The Eni-Total consortium has plans for a five-well drilling program offshore Cyprus starting in late 2019 and was awarded Block 7 on 29 July 2019 (see separate articles). Total expressed interests in acquiring stakes in Block 8 and in Blocks 2, 3 and 9 back in 2018. The French and Italian majors are already equal partners in Block 11 - operated by Total - and in Block 6 - operated by Eni â where the group made the Calypso 1 discovery in early 2018.","The council of ministers has reportedly approved the award of southwestern deepwater block 7 to Total (op) + Eni. The 4,555-sq km block contract will run 3+2+2 years + 25 prod. Meanwhile a Total deal with Eni to farmin to the latterâs offshore blocks 2, 3, 9 + 8 has also been approved. Kogas already partners Eni in blocks 2, 3 + 9."
17069,"Alamein-Yidma lease, Alamein sub-basin, NW Desert, P&A dry at TD 2,743m in late Jan â18, EDC rig 67. Targets Abu Roash G + Bahariya fmâs.",Egypt (Alamein Sub-basin (Northern Egypt B.)) Alamein
87032,"Mississippi Canyon block 505, (lease G35827), 1st of 2 proposed wells, WD 1,012m, ops terminated 21 Jul '20, West Neptune DS.",(Deep Water Gulf of Mexico B.) Dry well op. by LLOG (100%) in MC 505 block
13982,"PT Medco Energi has completed Tala 2A and Tala 2C from its three-well exploration drilling campaign in the Rimau PSC, located in onshore South Sumatra, at end-December 2017. The wells were drilled at the Iliran High structure. Fluid sample testing is yet to be carried out on the two wells. The company plans to proceed with the third well, Tala 2B, likely in Q1 2018. The wells could be targeting heavy oil in shallow sandstone reservoirs of the Middle Miocene Telisa Formation. The operator previously spudded Tala 3 on 22 July 2012. The well was drilled to a TD of 115 m, with bottom-hole in the Pre-Tertiary Basement. The well encountered water and was abandoned in early August 2012. It was the sixth shallow well drilled within the Iliran High since September 2011, targeting heavy oil in the area. The previous wells in the campaign were Shallow Heavy Oil (SHO) 2, Tala 1, Tala 2, Taba 2 and Taba 1. Stratigraphic test well SHO 2 was abandoned in April 2012, with results unreported. The well was drilled to a TD of 555 m and may have targeted sandstones of the Upper Oligocene to Lower Miocene Talang Akar Formation, carbonates of the Lower Miocene Batu Raja Formation and sandstones of the Telisa Formation. Tala 1 was spudded on 27 February 2012, located 2.2 km east-southeast of the Tala 2 well and with a PTD of 103 m. The well was suspended with oil shows. Tala 1 was the fourth shallow well drilled within the Iliran High since September 2011. Tala 2 was likely suspended with oil shows in January 2012. The well, located about 3.8 km southeast of the Taba 2 well, was spudded on 4 December 2011 and was drilled to a TD of 94 m. The first two exploration wells that were drilled at the same structure were Taba 1 and Taba 2. Both possibly encountered heavy oil as cyclic steam injection/stimulation were conducted. All the shallow wells drilled on the Taba and Tala structures were likely targeting the Middle Miocene Telisa shallow marine sandstones trapped in a faulted anticline structure, and were drilled using land rig âEMSCOâ. Rightholders of the block are Medco (95%, operator) and Perusahaan Daerah Pertambangan Energi (5%).","Indonesia (South Sumatra B.) ? op. by MEDCO RM (95.0%, PDPDE 5.0%) in Rimau block"
12499,"Premier Oil has signed a Sales and Purchase Agreement (SPA) with Batavia Oil for the entire shares of Premier Oil Kakap B.V. which holds an 18.75% non-operating interest in the producing Kakap PSC located in the Natuna Sea. The SPA, signed on 19 December 2017, calls for a purchase price of USD 3.2 million. Completion of the deal is subject to government approval, which is expected to be received in early 2018. The sale is in line with Premierâs current strategy of portfolio management aimed at disposing non-core assets. Batavia Oil is an international oil and gas company established in 2017. Based in the Netherlands, Batavia Oil is concentrating on the acquisition of minority and non-operating interests in producing blocks. The company is focused on positive cash flows at USD 45 per barrel. Upon completion, the Kakap PSC will be Bataviaâs first asset. The Kakap PSC is operated by Star Energy with 56.25% interest. Premier Oil Kakap is holding 18.75%, and the other partners are SPC (fully owned subsidiary of PetroChina) (15%) and Pertamina (10%). The PSC is due to expire in 2028. The block produced approximately 2,500 bo/d and 12 MMcfg/d in December 2017.","Premier has signed with Batavia Oil for the sale 18,75% stake in the Kakap PSC for US$3,2 MM. So far Star Energy (op), partners Premier SPC (PetroChina) + Pertamina. "
8964,"Ref. DEA 26 Sep â17, block 13T, Lokichar Basin, ops terminated at TD 2,721m late Sep â17, now reported P+A. Tullow (op), partners Africa Oil + Mærsk (Total).","Kenya (East African Rift System, Eastern Branch) Ekales 3 op. by TULLOW (50.0%, MAERSK 25.0%, AFRICA OIL 25.0%) in Block 13T"
64987,"The joint venture partnership of Metgasco Pty Ltd, Vintage Energy Pty Ltd and Bridgeport Energy Ltd has entered into an agreement with Senex Energy Ltd to enter PRL 211, located in the Cooper-Eromanga Basins. The joint venture 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. The Vali Prospect, located solely in ATP 2021-P, is scheduled to be drilled in December 2019 which could provide significant de-risking of the Odin Prospect. Under the terms of the initial farm-in agreement, a term sheet has been executed with a 90-day exclusivity period for the companies to negotiate a final farm-in agreement. Upon completion, it's proposed that Vintage will acquire operatorship of the licence with 42.5% interest. The remaining interest will be split between Bridgeport (21.25%), Metgasco (21.25%) and current holder Senex (15%). A number of conditions must be satisfied by 31 January 2020 including Ministerial approvals, a demonstration of sufficient funds being available to drill a well and the execution of a formal farm-in agreement. 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. It's 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. 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. Across the state and licence boundary, ATP 2021-P is mainly prospective for Permian gas and Jurassic oil accumulations. The Vali Prospect could be tested in December 2019 which comprises an anticlinal structure at the Toolachee and lower Patchawarra levels with independent closure at a depth of around 2,250 m. Metgasco has reported that the prospect is likely to contain reservoir characteristics similar to that of the nearby Kinta 1 gas discovery. The Kinta 1 well intersected 37 m of interpreted gas pay but did not retuned hydrocarbons to surface. Vali has been assigned P50 recoverable resources of 19 Bcf.","Bridgeport Energy Ltd, Metgasco Pty Ltd, Vintage Energy Pty Ltd extend their JV partnership to PRL 211, Cooper-Eromanga Basins"
35883,"Pennine plans to drill the Ramica prospect in the Velca block, onshore Ionian Zone, have been pushed back to 2019 on administrative issues. The 310-sq km block remains open for farmin, virtual data room available. Partner Albpetrol. Contact Desmond Smith, des.smith@penninecorp.com.","Pennine plans to drill the Ramica prospect in the Velca block, onshore Ionian Zone, have been pushed back to 2019 on administrative issues. The 310-sq km block remains open for farmin, virtual data room available. Partner Albpetrol."
61797,"In early October 2019, Dana Gas updated on the divestment of its Egyptian assets. The companyâs CEO, Patrick Allman-Ward, confirmed that several offers were received and were being evaluated. The deadline to submit offers is 15 November 2019. In late July 2019, it was reported that Dana Gas intends to sell all its Egyptian assets. Danaâs holdings in the country include the North El Arish Offshore block located in the Eastern part of the Mediterranean area as well as four production concessions and one exploration block located onshore. The production concessions are made of 14 blocks covering together 417 sq km onshore northeastern Nile Delta. The exploration block, El Matariya Onshore is operated by BP and Dana Gas has a 50% stake. In 2018, the production of Dana Gas in Egypt was 34,500 boe/d, essentially gas. The company has retained investment bank Tudor, Pickering, Holt & Co to manage the sales process. Dana Gas made this strategic decision to leave Egypt in order to focus on the Kurdistan assets. The company abandoned the Merak 1 deep water wildcat in the North El Arish Offshore exploration block in late July 2019. The company failed to find commercial hydrocarbons in the well. Before drilling, Dana Gas CEO Patrick Allman-Ward said: âIf the geology works out the way that we think it will, then in the success case it could be a 4-6 Tcf of gas reserve"". The targets are mainly in the Tertiary (Pliocene and Miocene) with potential secondary targets in the Mesozoic (Cretaceous) in the southern part of the block (Syrian Arc). The North El Arish Offshore block is adjacent to the border with Israel and Palestinian Territories. Background Information Dana Gas announced on 18 February 2014 that it had signed an agreement for the Block 6 (North El Arish Offshore). The company is committed to spending USD 71.5 million, paying a signature bonus of USD 20 million and drilling three wells. The Block, which was included in the Egyptian Natural Gas Holding Companyâs (EGAS) 2012 international bid round, was awarded to Dana Gas on 22 April 2013. It covers 2,980 sq km and lies in water depths from 20 to 1,000 m. The agreement includes an eight-year exploration period with three phases starting with an initial four-year exploration period and two additional two-year extension periods. A 20-year development lease period will be granted in case of commercial discovery. In late November 2015, Dana Gas completed a 1,800 sq km 3D seismic survey in the deepwater North El Arish Offshore exploration block.","In early October 2019, Dana Gas updated on the divestment of its Egyptian assets. The companyâs CEO, Patrick Allman-Ward, confirmed that several offers were received and were being evaluated. The deadline to submit offers is 15 November 2019. In late July 2019, it was reported that Dana Gas intends to sell all its Egyptian assets. Danaâs holdings in the country include the North El Arish Offshore block located in the Eastern part of the Mediterranean area as well as four production concessions and one exploration block located onshore"
18536,"Taymyrskiy Vostochnyy block, Anabar-Khatanga Depression (Lena-Anabar Basin), Krasnoyarsk Kray in E. Siberia, TD 5,750m, testing yielded non-commercial results, completed Apr â18. ZJ70DBS rig. Despite the disappointing results, Lukoil plans to drill 2 more wells in the block.","Taymyrskiy Vostochnyy block, Anabar-Khatanga Depression (Lena-Anabar Basin), Krasnoyarsk Kray in E. Siberia, TD 5,750m, testing yielded non-commercial results, completed Apr â18. ZJ70DBS rig. Despite the disappointing results, Lukoil plans to drill 2 more wells in the block."
8546,"PEMEX suspended as a significant oil and gas discovery the Ixachi 1 new-field wildcat (NFW) in the AE-0032 block in the onshore Veracruz Basin during early-November 2017. PEMEX issued a press release on 3 November 2017 indicating the well has estimated in place resources of 1.5 Bboe with recoverable reserves estimated to be potentially in the 350 MMboe range. There was no other detailed information regarding the productive horizon or flow rates but the well was targeting the Middle and Lower Cretaceous Formation, Orizaba Formation. The well reached an as yet unreported final total depth (TD) with the last reported depth being 6,911 m. The NFW was spudded on 25 January 2017 after receiving approval from the CNH on 20 September 2016. The well had a proposed total depth (PTD) of 7,728 m. The Middle and Lower Cretaceous Formation, Orizaba Formation, were the main objectives. The well is a significant Cretaceous test that will represent the deepest well ever drilled in the Veracruz Basin if it reaches its PTD. The well is located in the south central area of the block about 4 km northwest of the Mocarroca 1 NFW completed as a Tertiary oil and gas discovery in 2005. The The Ixachi 1 is located basin-ward of Lower Cretaceous Orizaba Formation producing trend on the Cordoba Platform. This trend produces from the Lower Cretaceous in the Miralejos, Copite, Mata Pionche, and Mecayucan fields.  The largest field is the Mata Pionche Field that has produced 35.7 MMbo and 209 Bcfg. The reservoirs are fractured low porosity carbonates deposited in a variety of shelf environments. The fracturing in the formations were aided by northwest to southeast Laramide compression and thrust faults.  The Ixachi prospect is a four way closure on a northwest to southeast trending anticlinal feature above a basement high. The Middle Cretaceous Formation is the main objectives from 6,368 m to 7,048 m and the Lower Cretaceous Formation is a secondary objective from 7,228 m to 7,498 m. The Middle and Lower Cretaceous formations are speculated to possibly consist of a basin-ward prograding reef and associated facies. It is speculated to be a basin-ward continuation of the Cordoba Platform carbonate trend 20 km to the west and similar to the Golden Lane El Abra reef trend located 200 km to the north. The nearest deep Cretaceous test drilled was the Torcaza 101A located 29 km to the northwest. The well was plugged and abandoned with results unreported, assumed dry hole, in 1981 and a total depth (TD) of 6,741 m. The Mecayucan 1 discovery and field is the principal analogue located 8 km northwest of the Torcaza 101A. The well is located higher on the platform but was productive from the Lower Cretaceous. The Ixachi 1 is a high temperature, high pressure well with target formation temperatures estimated to be 167° C and bottom hole pressure (BHP) estimated at 11,305 psi with a wellhead pressure (WHP) estimated at 4,550 psi. The drilling cost for the well is estimated to be USD 27.21 million with exchange rate of 18.3 MXN to 1 USD and completion costs are estimated to be USD 5.9 million. PEMEX estimates prospective resources for the prospect of 128 MMboe. SENER awarded the AE-0032-M-Joachin-02 block entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 976.40 sq km.  ",Mexico (Veracruz B.) Ixachi 1 op. by PEMEX (100.0%) in AE-0032 block
39970,"Fort St. John area, Montney Basin in BC, ops terminated at TD 1,873m, gas + cond encountered in the Montney fm, calculated 55 API, drilling now underway in Calima-2 (horiz), Calima-3 also planned.","Calima 1 nfw/strat in Fort St. John area, in BC, ops terminated at TD=1873m, gas + cond encountered in the Montney fm (256,5m thick with the top and base of the sequence being encountered very close to prognosis) calculated 55° API."
83578,"Petrobras published a teaser on Friday for the sale of its 100% in the Atum, Curimã, Espada + Xaréu fields (Ceará package) in shallow waters of the Ceará Basin, avg production 4,200 bo/d + 2.7 MMcfg/d in 2019 (suspended in March). EoIs by 10 Jul '20 + qualification docs by 17 Jul '20 to Bank of America at pbr-shallow@bankofamerica.com. Release + map here.","Brazil (Ceara B.) Atum op. by PETROBRAS (100%) Petrobras published a teaser on Friday for the sale of its 100% in the Atum, Curimã, Espada + Xaréu fields (Ceará package) in shallow waters of the Ceará Basin, avg production 4,200 bo/d + 2.7 MMcfg/d in 2019 (suspended in March)."
28152,"Ref. DEA 26 Feb â18, the authorities have approved Petronasâ farmin to offshore blocks A2 + A5 from FAR ahead of drilling the Samo prospect (Stena DrillMAX DS). Petronas gets 40%, FAR retaining 40% and operatorship, although Petronas has the right to take over as leader for any devt. Petronas will fund 80% of Samo well costs up to USD 45 MM, USD 6 MM cash, and reimburses FAR Â 80% of back-costs. Partner otherwise Erin Energy. Block A2 covers 1,298 sq km, A5Â 1,378 sq km:","Gambia, Block A2"
21459,"Exxon in March farmed out a 50% stake in 273ER (Deepwater Durban licence) to Statoil, now theoretically Equinor. The 50,169 sq km block lies in the deepwater Durban sub-basin (Natal Trough), WD 2,400-3,000m. Partnership now 50:50.","Exxon in March farmed out a 50% stake in 273ER (Deepwater Durban licence) to Statoil, now theoretically Equinor. The 50,169 sq km block lies in the deepwater Durban sub-basin (Natal Trough), WD 2,400-3,000m. Partnership now 50:50."
13577,"Red Emperor is frustrated by the slow progress surrounding the ratification of interest increase in SC 55. The company is now considering the merits of maintaining its presence in the block and is considering the possible sale of its 37.5% stake in the 9,913-sq km offshore unit which contains the ready-to-drill Cinco gas prospect. Currently Palawan55 E+P (op), partners Century Red + Pryce Gases. ","Red Emperor (Palawan55 E+P (op), partners Century Red + Pryce Gases) is frustrated by the slow progress surrounding the ratification of interest increase in SC 55. The company is now considering the merits of maintaining its presence in the block and is considering the possible sale of its 37,5% stake in the unit which contains the ready-to-drill Cinco gas prospect. "
65671,"Shell was drilling with oil shows on the ACFO (1-SHEL-031-RJS) new-field wildcat (NFW) in the Alto CF Oeste P3 contract, ALTO_CF_O block during early-December 2019 after filing two show reports. Shell filed an oil show report with the ANP for the well on 8 November 2019 and a second show report was filed on 2 December 2019. The NFW was spudded on 6 October 2019. The proposed total depth is 5,200 m with the pre-salt Early Cretaceous Barra Velha Formation as the primary target. The prospect has super-giant potential with reserves greater than 500 MMboe. Shell is utilizing the âBrava Starâ 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=5200m."
58377,"EG is reportedly hoping to launch its next licensing round towards 2H 2020, its 2019 offer still at the open stage with bid deadline on 27 Sep â19 (24 explo blocks + 2 appraisal units, re. DEA 3 Jun â19 + map). Terms will possibly be modified for the next release, an open-door process with EoIâs required during 3-4 months. Failing this, a more traditional round could otherwise be held in 2021.","Equatorial Guinea, not found"
74871,"Aguada Baguales block, Neuquén Basin, TD 1,475m in Aug '19, minor oil find (7 bo/d + some water) in the Centenario + Lotena fm's, well now completed.",Argentina (Huincul Uplift (Neuquen B.)) Aguada Baguales
55535,"Rey Resources Ltd and Doriemus Plc entered into a farm-in agreement in March 2019, which will see Doriemus acquire interest in licence L 15, located in the Canning Basin. Doriemus initiated the farm-in agreement on 5 March 2019. Doriemus is to acquire 50% interest in L 15 under the farm-in agreement. To acquire 50% interest, and operatorship, in L 15 Doriemus must fund up to AUD 1 million in development costs associated with bringing the Kora West field back into production over the first 12 months. Doriemus reported that funds were already available prior to completion of due diligence. Doriemus reported on 15 February 2019 that the interest sale of Horse Hill Developments, UK, has also provided strength to its balance sheet as the West Australian farm-ins progress. Additional spend could also be raised from a combination of cash reserves and production revenue from its 20% interest in the Lidsey oil field, located in the Wessex Basin, UK. L 15 is 100% owned by Gulliver Productions Pty Ltd, a wholly owned subsidiary of Rey Resources, and covers an area of 165 sq km over the Kora West field. The field was discovered in 1984 and produced around 20,000 bbl oil between 1989 and 1992. With 2P recoverable reserves of nearly 400,000 bbl, Doriemus plans to bring the Kora West field back into production by around May 2019. Doriemus reported on 15 February 2019 that it had completed its due diligence relating to the acquisition of interest in Rey Resourcesâ L 15 (West Kora) licence. The company planned to seek finalisation of the previously reported farm-in agreement and joint operating agreement. Doriemus first announced on that it had entered into a farm-in deal with Rey Resources 31 December 2018, for two Canning Basin permits, exploration permit EP 487 (Derby Block) and production licence L 15 (West Kora). The companies signed two independent binding letters of intent for Doriemus to acquire 50% interest and operatorship in both assets. In Ep 487, the farm-in agreement was terminated in August 2019, after Doriemus failed to meet required funding conditions for the farm-in. L 15 was awarded on 1 April 2010. Should the farm-in be completed, interests will become: Doriemus Plc (50% + operator) and Gulliver Productions Pty Ltd (50%). Until this time, Gulliver Productions remains as operator with 100% interest. Doriemus currently holds minority, non-operated interest in three licences in onshore United Kingdom. Upon completion of the deal with Rey will see Doriemus enter Australia for the first time.","PL 216 (Dalwogan), 230 sq km in the Taroom Trough, Bowen-Surat Basin, was awarded for CBM ops on 23 Jul â19 for 30 years"
23444,"AE-0020-M-Okom-03 block, offshore Sureste Basin, WD 78m, susp o&g at TD 4,765m on 27 Apr â18, Prospecter II JU.","Manik 101AEXP (Pemex 100%) in AE-0020-M-Okom-03 block, completed, o&g disc. WD=78m, TD=4765m. (w.o. details) "
41687,"PPL 225, onshore Cooper-Eromanga, TD 1,344m, P&A with oil shows, Ensign rig 950.","Teringie-4 appr in PPL 225, onshore Cooper-Eromanga, TD 1,344m, P&A with oil shows,"
58810,"Oil and Gas Development Company Ltd (OGDCL) has assigned 2.5% interest in Rakhshan 2764-2 EL (Balochistan Basin) onshore concession to Government Holding Pvt. Ltd (GHPL) with effect from 21 August 2019. As a result of this transaction the equity split is as follows: OGDCL (97.5%, operator) and GHPL (2.5%). The licence covers 2,458 sq km area and is located in the Kharan and Panjgur districts of Balochistan province. Rakhshan EL was exclusively awarded to OGDCL with the signing of Petroleum Concession Agreement (PCA) on 21 March 2014. OGDCL acquired 267 line km 2D seismic (dynamite / vibroseis source) in Rakhshan EL from December 2017 to May 2018 using its SP-2 seismic crew. The company had earlier acquired 315 line km 2D seismic (dynamite source) from November 2015 to February 2016 using the Bureau of Geophysical Prospecting (BGP) âBGP 9501-Dâ seismic crew. It was reported in May 2019 that OGDCL was granted an extension up to 31 August 2019 to the Phase-I of initial term of the Rakhshan EL - it was made effective retrospectively from 21 March 2017. No wells have been drilled on the acreage to date. Rakhshan EL was offered under the 2012 Licensing Round which was launched from 11 October 2012 to 10 March 2013.","OGDCL (->97,5% op.) assigned 2,5% working interest in the Rakhshan 2764-2 EL to Government Holdings (Pvt)."
22648,"As reported on 28 May 2018, Sonangol E.P is expected to hold bid rounds for onshore and offshore blocks by end 2018 or early 2019. To date no information on the number or location of the blocks is available. It worth noting that in February 2018, during its annual press conference Sonangol E.P announced that it would develop a new Modal Production Sharing Agreement (PSA) for Onshore Exploration and Production. The announcement seems to suggest that no new onshore bidding rounds will take place until the new Modal Onshore PSA is finalized. The last reports regarding Sonangol E. Pâs plans to auction 18 offshore oil and gas concessions within the Congo Fan - Lower Congo Basin and the Namibe Basin were in August 2016. At the time a planned date for the auction had not been announced there were however, rumors that Sonangol might be able to launch in 2018.",Sonangol E.P is expected to hold bid rounds for onshore and offshore blocks by end 2018 or early 2019. To date no information on the number or location of the blocks is available.
68845,"BP Exploration & Production (E&P) was awarded Desoto Canyon Block DC 666 (G36798) on 1 January 2020. DC 666 is anticipated to expire on 31 December 2029. The block is sited 4km southeast of the Spiderman/Amazon oilfield, which was discovered in 2003 by Anadarko Petroleum on Desoto Canyon blocks 620 and 621. DC 666 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. BP E&P accounted for 21 of these high bids, worth a total of US$ 14.7 million. BP E&P is now the operator and sole interest-holder (100% WI + Op) in DC 666.",BP (100%) was awarded Desoto Canyon Block DC 666 (G36798).
43842,"Pan Orient has completed 90-days production testing on the new-field wildcat L53 DD1 in the L53/48 concession, onshore Chao Phraya Basin, on 18 February 2019. The daily oil production for L53 DD1 is around 530 barrels, based on the reported cumulative production from 21 November 2018 to 10 February 2019. L53 DD1 has been temporarily shut-in until Production License is granted. The well was reported to have flowed at an average rate of 645b/d of oil within the âDDâ sand, from 21 November to 9 December 2018, prior to shut-in for a workover. On 12 December 2018, production commenced from the âCCâ sand using a beam pump with average oil production of 504 b/d. The oil production from âCCâ sand increased to 756 b/d using an electrical submersible pump from 16 January to 10 February 2019. Located 5 km south of the U Thong oilfield, the deviated wildcat was drilled to a total depth of 1,373 m (1,323 m TVD) on 22 October 2018. The well was immediately appraised by L53 DD2 well, which has also temporarily shut-in after a completion of 90-day production test. The measured density of the oil in L53 DD1 is approximately 24 degrees API gravity with Basic Sediment and Water (BS&W) of 0.4%. The DD sand is the deepest of three oil bearing sands and represents 8 m of the 26 m of total interpreted net oil pay encountered in the well. The well encountered a combined 26 m of net oil pay from three zones across 165 m interval (960-1,125 m TVD), interpreted from wireline logs. The other two reservoirs, âBB sandâ and âCC sandâ share the same oil-water contact with the L53-DD2, which is 24 â 29 m structural high than those in L53-DD1. The reservoirs quality is excellent with high permeability which was confirmed by pressure data and oil samplings from each of the zones. The completion of L53 DD1 has fulfilled the USD 600,000 minimum annual expenditure that is required to retain the 214 sq km of the L53/48âs âExploration Reserved Areaâ. The previous exploratory well, L53-AC-C1 was abandoned on 31 December 2017, with oil shows. A fluid sampling determined the oil shows area to be dominantly water-bearing reservoir. The L53/48 concession produced at approximately 455 b/d of oil in October 2018, as compared to 505 b/d of oil in late 2017. The concession holds a 2P crude oil reserves of 546,500 barrels from the Lower Miocene sandstone reservoir, excluding the exploration area (As of 31 December 2017). 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 and G) will be retained. Background Information The L53/48 block lies onshore in the Kamphaeng Saen Sub-basin 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. Seven minor oil discoveries were encountered from 2009 to 2013 with estimated total recoverable reserves of approximately 25 MMbbl. As of December 2018, a total of three fields are producing (L53-A, L53G, L53-D East), two are developing (L53-B and L53-DD) 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 sealed by Middle Miocene Series mudstone. The reservoirs were deposited in lacustrine environment. The block also covers an area that was previously partially covered by BPâs B04/27 and Britoilâs Block BT concessions. It encompasses and excludes the Kampheang Saen field (previously called Neung), which was discovered by BP in February 1987. 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. On 2 February 2015, Pan Orient Energy Corp closed the sale of 49.99% of its own equity interest in Pan Orient (Siam) Ltd, which is in turn operator of the concession, to Sea Oil Public Company. With all conditions being met, Sea Oil transferred a consideration of USD 38.5 million to Pan Orient. Pan Orient (Siam) Ltd remained operator of the block with 100% interest, as an equally controlled subsidiary of Pan Orient Energy Corp and Sea Oil Public Company. In October 2016, the operator completed a five wells workover program which has increased production from 192 bo/d in August 2016 to 303 bo/d. The December 2016 production from L53-G1 was substantially reduced to approximately 100 bo/d, as a result of a replacement of downhole pump. The focus for the 2017 was to maximize production from the existing wells. In late 2016 and 2017, the operator attempted to find several upside potentials within the Miocene sandstone reservoirs by drilling L53-ANE-A1 and L53 AC C1 in the Reserve Area A. The wells failed to encounter hydrocarbons within the target intervals, which were determined to have excellent quality of sandstones.","L53 DD4 (Pan Orient 100%) in L53 DD field area (onshore), 15,6m net oil pay in the BB/CC sand, as well as the AA2 sand (new pool). A 90-day test is planned."
39732,"On 16 January 2019, Polskie Górnictwo Naftowe i Gazownictwo SA (PGNiG SA), the Polish state-controlled company, announced that it had signed an Exploration and Production Sharing Agreement (EPSA) for the 619 sq km on-offshore Block 5 concession with Ras Al Khaimah Petroleum Authority and RAK GAS LLC. It is the first block to be awarded as part of the Ras Al Khaimah License Round 2018 (also termed the RAK-2018 Bid Round) for which bids were submitted at the end of November 2018. His Highness Sheikh Saud Bin Saqr Al Qasimi, Ruler of Ras Al Khaimah and Ambassador of the Republic of Poland to the United Arab Emirates Robert Rostek witnessed the agreement being formalized by President of the PGNiG Management Board Piotr Wozniak and CEO of RAK GAS LLC Nishant Dighe. The contract enables work to be conducted in three, two-year exploration stages, followed by a 30-year production phase. Financial commitments have yet to be disclosed. RAK Gas LLC completed the acquisition of an extensive 2,200 sq km MC3D seismic survey over unlicensed and underexplored offshore acreage in February 2018. Although the Polarcus-operated survey only intersected with a marginal offshore section of the newly awarded block, it was reported that the new data significantly improved understanding of the complex geological setting in which it is located.",PGNiG was awarded E&P rights to on/offshore block 5 (619km²).
55024,"EL 1122, S. of the North Amethyst field offshore in the Jeanne dâArc Basin, WD 117m, P&A dry late Jun â19, Henry Goodrich SS now on White Rose field. Husky (op), partner Suncor.",Canada (Jeanne d'Arc B.) White Rose
59713,"Khewari 2568-3 EL, Indus onshore, Sindh, P&A after tests at TD 3,993m in mid-Sep '19, Hilong rig 17. Target assumed L. Goru. OGDC (op), partner GHPL.","Pirano 1 nfw within the Khewari 2568-3 EL onshore concession (OGDCL 95%, GHPL 5%), P&A at a TD= 3993m after carrying out testing."
10999,"Tartagal Oriente block, Olmedo sub-basin (Noroeste (Cretaceous) Basin), P+A dry earlier this month, Chinese rig. PTD was 2,913m, target Tupambi + Los Monos fmâs, High Luck Group (op), partners Maxipetrol + JHP Intl. ","Argentina (Michicola-Boqueron Arch) El Pacara 2001 op. by NEW TIMES (93.25%, MAXIPETROL 6.0%, JHP 0.75%) in Tartagal Oriente block"
12099,"UE secured the 14-sq km Rahim D&PL in the Sanghar District, Lower Indus Basin, retro-effective 9 Sep â14. It was excised from the UEâs Khipro block around the Rahim-1 o+g discovery (2007). UE (op), partners Bow Energy + Govt Holdings. ",United Energy Pakistan Ltd (UEPL) (100%) has been awarded the Rahim D&PL (Lower Indus Basin) onshore development and production lease
53375,"The Dutch Ministry reported on 11 July 2019 that it has awarded exploration blocks G7, G10, G11 and G13a (1,079 sq km) to NAM and block G13b (16 sq km) to Neptune Energy effective from 3 July 2019. The Dutch Ministry decided to split the G13 block into two separate blocks following the competing bid from Neptune. The G13b block cover a small area in the eastern and/or southern part of the G13 block which neighbours Neptuneâs operated blocks G14, G16 and G17. NAM made the original application for all the blocks on 17 September 2016. The 13-week period during which competing bids could be received ended on 19 December 2016. The blocks lie on the border with the German Continental Shelf. Eleven exploration wells were drilled within the surface area covered by the blocks between 1990 and 1998. All the wells were unsuccessful. On 9 June 2010 GDF SUEZ relinquished its exploration licences for blocks G10, G11 and G13. The licences were awarded in June 2008 and the company did not drill any wells during its tenure. Interest in blocks G7, G10, G11 and G13a will be held by Nederlandse Aardolie Mij BV (operator) and Energie Beheer Nederland BV and interest in block G13b will be held by Neptune Energy Netherlands BV (operator) and Energie Beheer Nederland BV.","The Dutch Ministry reported on 11 July 2019 that it has awarded exploration blocks G7, G10, G11 and G13a (1,079 sq km) to NAM and block G13b (16 sq km) to Neptune Energy"
12333,"Hitherto unreported, on 30 October 2017, Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) finished drilling new-field wildcat Gnojnica 3K in the contract 28/96/ŠRopczyce-Bratkowice-Strzyżów in southern Poland (Carpathians). The well, solely operated by PGNiG and drilled to the final depth of 1,853 m (TVD 1,695 m) in the Miocene series, was completed for gas production following successful tests (rates undisclosed) finished on 21 November 2017. Gnojnica 3K, drilled by the Skytop TR800 drilling unit from Exalo Drilling, was started on 20 September 2016. The well is located approximately 25 km west of the city of Rzeszow, within the tectonic units of the Carpathian Flysch Zone. The well had a planned final depth of approximately 1,872 m (TVD 1,695 m), targeting the autochthonous Miocene (Sarmatian-Badenian) sandstone series.","Poland, not found"
36657,"PL 231, Bowen-Surat Basin, TD 1,200m, 38m net coal + 25m carbonaceous shale / coalbeds encountered, DSTâd over 441-940m, 100 psi within the Reidâs Dome Beds, results n/a. Silver City rig 25. State Gas (op), partner Dome Petr. Res.","Nyanda-4 expl/appr in PL 231, Bowen-Surat Basin, TD 1,200m, 38m net coal + 25m carbonaceous shale / coalbeds encountered, DSTâd over 441-940m, 100 psi within the Reidâs Dome Beds, results n/a. "
86921,"The nomination period for NZ's 2020 block offer opened 27 Jul '20, with only the onshore Taranaki Basin on the table. All nominations must be submitted to NZP&M by 21 Aug '20 via blockoffernominations@mbie.govt.nz.","New Zealand, not found"
14281,"In October 2017, Surgutneftegaz completed testing of a new exploratory well in the Tundrinskoye license in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Verkhnesolkinskaya 50, spudded in August 2017, reached 2,980 m in September. Oil flows were tested from the Sortym (Neocomian) and Tyumen Formations. Reservoir BS10 perforated at 2,436-2,443 m flowed with oil at a rate of 28 b/d. The interval 2,865-2,892 m (Yu2-3) tested oil at a rate of 16 b/d. Based on primary data, 2P reserves of the discovery were estimated by IHS Markit at 3 MMbbl. Tundrinskoye license (KhMN00422NE) covers 973 sq km in the southwestern part of the Middle Ob Province and encompasses the Tundrinskoye field and the Malo-Komaryinskaya prospect. Â ","Verkhnesolkinskaya 50,Surgutneftegaz completed testing of a new exploratory well in the Tundrinskoye license Oil flows were tested from the Sortym (Neocomian) and Tyumen Formations. Reservoir BS10 perforated at 2,436-2,443 m flowed with oil at a rate of 28 b/d. The interval 2,865-2,892 m (Yu2-3) tested oil at a rate of 16 b/d. "
72436,"Nashpa D&PL, Potwar onshore P&A late Jan '20 at TD 5,220m (original hole), sidetracked, depth n/a, Sinopec-78 rig. OGDC (op), partners PPL + GHPL.","Nashpa-5A appr Nashpa D&PL, Potwar onshore P&A late Jan '20 at TD 5,220m (original hole), sidetracked, depth n/a, Sinopec-78 rig. OGDC (op), partners PPL + GHPL."
51158,"Rosneft transferred 2 licences in the Yakutia (Sakha) Republic, E. Siberia, to its existing 51:49 JV with BP YermakNeftegaz, so far only present in W. Siberia. Involved are the Sredne-Lenskiy + Olekminskiy blocks now held under subsidiary Srednelenskoye. Olekminskiy covers 6,121 sq km undrilled, while Sredne-Lenskiy is 9,834 sq km, both in the Predpatom Basin.","Rosneft transferred 2 licences in Yakutia (Sakha) Republic, to its existing 51:49 JV with BP YermakNeftegaz, so far only present in W. Siberia. Involved are the Sredne-Lenskiy (9834km²) + Olekminskiy (6121km² undrilled) block, both in the Predpatom B."
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 Equinorâs 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%)."
11604,"Area 4 (Ichalkil-Pokoch) PSC (CNH-RO1-LO2-A4/2015), offshore Sureste Basin in WD 46m, TDâd early Aug â17, tested 3 separate zones (1 Cretaceous, 2 Jurassic) between Aug - late Oct, calculated avg 1,800 b/d light oil, suspended o+g mid-Dec â17, Ocean Scepter JU. Fieldwood (op), partner Petrobal.","Mexico (Sureste B.) Ichalkil 2DEL op. by RIVERSTONE (50.0%, PETROBAL 50.0%) in Area 4 (Ichalkil) block"
43465,"Petronas Carigali plugged and abandoned wildcat Yetaung 1 in the Yetagun Development and Production Area, offshore Mergui Terrace, around mid-February 2019, with results unreported. The well reached a total depth of 2,150 m in the 12 1/4â casing. The operator acquired wireline logs, sampling and formation testing prior to abandoning the well. Yetaung 1 was spudded in late January 2019, drilled using Japan Drillingâs âHakuryu-5â S/S. The well, located approximately 20 km south of the Yetagun field facilities, was likely intended to find additional reserves to sustain future production from Yetagun. The well was likely targeting Lower-Middle Miocene fluvial sandstones of the Mergui Group, which are producing at Yetagun. After the completion of Yetaung 1, the rig was mobilized to drill exploration well Yetagun Southeast 1. The operator has options to drill up to two additional exploration wells, also in the Yetagun Southeast area. According to IHS Petrodata, the rig is under contract until March 2019 (excluding the options). The exploration drilling campaign was previously expected to commence in late 2018. Reportedly, in early August 2018 Petronas was in discussion with Japan Drilling on bid clarifications as part of the rig tender process. The company awarded several service contracts for its exploration drilling campaign around May 2018. Petronas has likewise commenced a new infill drilling campaign in the Yetagun field in mid-January 2019, using the âWest Vencedorâ tender-assist rig (TAR). The last exploration activity in the area was wildcat Ye Thurein 1. The well, located in block M-12, outside of the Yetagun Development and Production Area, was plugged and abandoned with gas shows in October 2014. The well was drilled using UMWâs âNaga 1â S/S rig and reached TD at 1,528 m. The surface location of Ye Thurein is approximately 3.1 km northeast of the Aung Zay Ya 1 discovery made by M-12 JV led by Texaco in November 1997. Aung Zay Ya 1 discovered gas and condensate in Lower Pliocene clastics. Right holders of the Yetagun Development and Production Area, as well as the surrounding blocks M-12, M-13 and M-14, are Petronas Carigali (operator, total interest of 40.9% via two subsidiaries), MOGE (20.5%), Nippon (19.3%) and PTTEP (19.3%). Background Information The field was discovered in December 1992 by Texaco's wildcat Yetagun 1, which was drilled to a TD of 2,513m and flowed at a combined rate of 74.3 MMcfg/d plus 1,787 bc/d from four DSTs. The discovery was initially appraised by four exploration wells in 1993, establishing commercial recoverable reserves of 1.8 Tcfg and 50 MMbc and forming the basis of a 15-year Gas Sale Agreement (GSA) signed with the Petroleum Authority of Thailand (PTT) under ""take-or-pay"" terms on 10th March 1997. Under the GSA, PTT is obliged to purchase gas up to 400 MMcfg/d (260 MMcfg/d as first-phase and an additional 140 MMcfg/d as second-phase of the supply agreement) once reserves exceed 2.0 Tcfg. With the confirmation of additional reserves, Premier has the right to increase the production up to 400 MMcfg/d plus 12,000 bc/d after 2003. In 1998 Premier drilled three successful exploration wells to delineate additional reserves, one each in the southern, eastern and northern parts of the Yetagun field, increasing the certified recoverable reserves to 2.6 Tcfg plus 82.3 MMbc. On 16 September 2002 UK-based Premier Oil entered into an agreement to sell selected upstream assets worth US$ 359 million to Petronas for its 26.666% operated interest in the Yetagun gas/condensate field in Myanmar. With regard to the Burmese assets, which Petronas will now operate, the Malaysian state firm is also set to assume US$ 152 million in debt and pay Premier US$ 207 million in cash. This however is subject to revision, as the remaining partners will be offered the option to increase their right holdings, by acquiring part of the stake that Premier is proposing to sell to Petronas. This would reduce the amount of Yetagun assets to be acquired by Petronas and accordingly reduce the amount of assumed debt and cash payments. Petronas Carigali completed a seismic survey on 15 May 2007, using the VeritasCGG ""Pacific Sword"" S/V to acquire 2D seismic data over the blocks M-12, M-13 and M-15. Petronas involvement in the area commenced with the acquisition of a 36.354% asset from Texaco in 1997 and Premier Oil took over operatorship from Texaco. In 2002, Petronas took over the operatorship after Premier sold its share to interested partners. Partners in blocks M-12 and M-13 are Petronas Carigali (40.9%, operator), MOGE (20.5%), PTTEP (19.3%) and Nippon (19.3%). On 6 March 2007, Petronas Carigali plugged and abandoned sidetrack Yetagun North-east 1ST1 in the Yetagun Development and Production Area as a dry well, at a TD of approximately 2,410m. The principal hole, Yetagun North-east 1, was spudded on 31 January and drilled to a TD of 2,250m. It was the second of a two-four well exploration programme in the company's blocks in the basin, using the ""Hakuryu III"" S/S. Petronas Carigali plugged and abandoned newfield wildcat, Danna 1, as a dry well on 14 October 2008. The well was drilled to a TD of 2,999m, and failed to encounter any form of hydrocarbon. The well was spudded on 8 September 2008 in the water depth of 109m, using the ""Naga 1"" S/S. The well was targeting the Lower Miocene sandstone in a structure northwest of the Yetagun gas and condensate field.","Yetagun 1 (Petronas 40,91%, Myanma O&G Enterprise 20,45%, Nippon Oil Explo. 19,32%, PTTEP 19,32%) in M-14 block, P&A, results unreported."
62214,"It was announced on 22 October 2019 that Turkiye Petrolleri A.O. (TPAO) has been awarded the L46-C2 exploration licence (Zagros Province) on 15 October 2019. The licence, covering an area of 152 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.","Turkey, L46-C2"
11763,"RockRose Energy announced on 3 August 2017 that it had agreed a sale and purchase agreement to acquire the entire issued share capital of Sojitz Energy Project Limited for a consideration of USD 2.5 million. The company will receive USD 1.7 million at completion of the deal to reflect an effective economic date for the transaction of 1 January 2016. The deal completed on 22 December 2017. The assets involved in the deal include a 15% interest in the Tors field unit area which includes the Kilmar (P683) and Garrow (P1034) fields which are linked to the Trent field. A 7.5% interest in the Grove field unit area (P083 and P901) and a 10% interest in the Seven Seas field (P1354). Sojitz Energy Project Limited also held a 13.5% interest in the Gryphon field but this is understood to not be part of the deal and will likely be awarded to a different Sojitz subsidiary. RockRoseâs strategy is to build a portfolio of mature producing assets with a view to extend the field life giving the company access to significant tax losses. The recently established company has undertaken deals with Egerton Energy, announced in March 2017, to acquire Egertonâs interest in the Galahad and Mordred fields in the Southern North Sea and also agreed a deal with Maersk in December 2016 to acquire its interest in the Scott and Telford fields.","RockRose Energy has agreed to acquire entire issued share capital of Sojitz Energy. The assets involved in the deal include a 15% interest in the Tors field unit area which includes the Kilmar (P683) and Garrow (P1034) fields which are linked to the Trent field. A 7,5% interest in the Grove field unit area (P083 and P901) and a 10% interest in the Seven Seas field (P1354). "
33944,"Sumbagsel 2 PPC in S. Sumatra, P&A 31 Oct â18, some gas recovered (3 DSTs, no results). Targets assumed Batu Raja + TAF.","Sekarwangi 1 (PT Indo CBM Sumbagsel II 30% op. PT Metana Enim Energi 30%, PT Pertamina Hulu Energi Metana Sumatra 5 40%) in Muara Enim II CBM PSC, P&A, some gas recovered (3 DSTs, no results). Targets assumed Batu Raja + TAF. "
8835,"Penglai 7-6-7 (PL 7-6-7) was suspended on or around 31 August 2017, having successfully encountered oil in the target reservoirs. The appraisal well was spudded on or around 13 August 2017 using the ""Bohai 7"" jack-up and was likely targeting the Guantao, Dongying and Shahejie formations to appraise the Penglai 7-6 oil discovery made in March 2015 by CNOOC. Penglai 7-6-7 is in the CNOOC operated Qinhuangdao 36 Block in the offshore Bohai Gulf Basin and is approximately 1.6km NE of the Penglai 7-6-2 appraisal well. ",Not Found
73976,"In February 2020, industry sources indicated that BHP is looking to divest its interests in Algeria. The company is partner of Eni in a cluster of fields known as the ROD integrated development, Berkine Basin, south-eastern Algeria On 21 July 2016, partner BHP announced that the validity of six production concessions in the ROD asset will be extended by ten years. The concessions are: Rhourde Ouled Djemma (ROD)/402A, Rhourde El Rouni Nord (RERN)/401A, Rhourde El Attar (RAR)/402A, Bir Sif Fatima (BSF)/402, Sif Fatima Nord-Est (SFNE)/402 and Rhourde Debdeba (TAGI)/402A. The validity of the concessions will thus be extended from 2026 to 2036. The six concessions are believed to have a gross combined output of around 49,000 b/d of oil. Participants in the six concessions are: ENI, operator with 31.35%, BHP with 17.65% and Sonatrach with 51%. The Rhourde Ouled Djemma - Bir Sif Fatima North - Bir Rebaa Sud-Est (ROD-BSFN-BRSE) field was originally discovered by Agip in 1996 with the Bir Rebaa Sud-Est 1 wildcat. As was to be proved subsequently, the well had intersected the southern part of the field.",BHP (Algerie) Inc looking to sell Algerian interests?
34008,"On 29 October 2018, Eni announced that it signed a farm-in agreement with Sonatrach to farm into three exploration blocks in the Berkine Basin, south-eastern Algeria. The blocks are: Sif Fatima II, Zemlet El Arbi and Ourhoud II. Interests will be split as follows: Eni 49% and Sonatrach 51%. The blocks are located in the northern part of the Berkine Basin where Eni operates already oil and gas production from several fields in the Sif Fatima area and the Menzel Ledjmet area. The exploration program will include the acquisition of 2,600 sq km of 3D seismic and the drilling of five exploration wells for a total cost of USD 80 million. The development program of already identified resources will include the drilling of 18 development wells, the construction of a 188 km 8-inch condensate pipeline, an oil gathering network tied to the Bir Rebaa Nord facilities and a gas gathering network tied to the Bir Rebaa Nord - Menzel Ledjmet Est gas line for a total cost estimated at USD 1.1 billion. The company recently launched two infrastructure projects to support its development activities: a photovoltaic power plant and a gas pipeline. Under an agreement signed in July 2018, Sonatrach and Eni will aim to create a gas hub in the basin based on the Bir Rebaa Nord and the Menzel Ledjmet Est fields. The idea is to use gas made available from Bir Rebaa Nord (and probably other fields nearby in the future) for export through the Menzel Ledjmet Est gas plant which becomes the center of the hub. Part of the project is the construction of a 180 km gas line which will connect Bir Rebaa Nord and Menzel Ledjmet Est. In March 2017 representatives of Sonatrach and Eni kicked off the construction of the Bir Rebaa photovoltaic (PV) plant at the Bir Rebaa Nord oil field. The plant will cover 20 ha and have a capacity of 10 MW. The electricity generated by the plant will power the oil fieldâs production facilities. This will make available the gas previously used in power generation for a better valorization. Eniâs announced farm in into the three exploration blocks fits the companyâs strategy to develop resources in the Berkine Basin which becomes an important production center. The company estimates that the three exploration blocks, covering together 8,500 sq km, hold reserves of 145 MMb of oil equivalent which should be confirmed through an important exploration program. First production is expected to start by the end of 2020. Eni is currently participating in 32 production permits in the Berkine Basin with a production of 90,000 boe/d net to the company.","Algeria, Bir Rebaa"
9362,"VIM-5, Lower Magdalena, 10km E of Clarinete + Oboe fields, spudded 25 Oct â17, TD 2,849m on 9 Nov â17, 59m of gas pay within the Lower Tubara, Cienaga de Oro, and fractured basement reservoirs which now need to be better analysed, testing planned shortly. Pioneer 302 rig off to Canadonga-1 nfw, 1-week well spudded 4 Nov, target gas.  ","Pandereta 1 op. by Canacol (100%) in VIM 5 block, 59m of gas pay within the Lwr Tubara, Cienaga de Oro fmâs, and fractured basement reservoirs which now need to be better analysed, testing planned shortly. "
62300,"Buru Energy Ltd spudded the Miani 1 oil exploration well in L 08, located in the Canning Basin, on 2 October 2019. The well was drilled by the ""NGD 405"" land rig and had a revised planned total depth (TD) of 3,000 m. On 29 October 2019, Buru reported that the well had reached TD at 3,006 m in the Frasnian Clastics section, which was encountered at TD. Elevated mud gas readings and oil shows were observed in a section of dolomitised limestone between 2,970 and 2,990 m. Buru now plans to run logging operations over the interval to assess the hydrocarbon indications. On 23 October 2019 Buru reported that it was running a wiper trip over the Anderson Formation shales, to condition the hole for logging. The wiper trip was required as the first attempt at a logging run was unable to pass below 1,650 m. On 29 October, Buru further reported that wireline logs were not possible in the formation due to poor hole conditions. The lower section will be evaluated with LWD tools. Initial log results indicated the lower Nullara Carbonate may be prospective, though the well had not yet penetrated this unit. Therefore, it was planned that once the wiper trip was completed, the well would be deepened to around 3,000 m to evaluate this section. Logging would then be undertaken at the new total depth. On 21 October 2019 Buru reported that it was pulling out of hole, in preparation to run wireline logs, after reaching a total depth of 2,689 m. During drilling minor hydrocarbon shows were encountered, which would be evaluated by the wireline log operations. Buru reported that thick units of tight limestones, with dolomite sections, were encountered during drilling. However, the expected vuggy porosity zones were not encountered. Miani 1 was targeting what was previously known as the âHotdogâ prospect, which is a carbonate sag feature, with a reservoir target in the Nullara Reef unit, sourced by the Laurel Carbonates. The prospect is well defined from 3D seismic. Estimated recoverable reserves, best case, are reported at 17 MMbo. The well was spudded as planned, being scheduled to spud in early-October 2019. Site construction was reported to be well advanced as of late-July 2019. Environmental clearances and heritage approvals were achieved by July 2019. The well lies in the L 08 permit, which contains the Sundown, Terrace West and Lloyd oil fields, discovered in 1982, 1985 and 1987 respectively. All three have ceased production or are shut-in. L 08, which covers an area of 326 sq km, was awarded on 22 October 1984. Buru Energy Ltd holds 100% interest and operatorship of the licence.",Australia (Margaret Terrace (Canning B.)) Lloyd
55110,"Equinor has agreed to buy an 85% stake + operatorship from Soliton Resources in so far wholly-owned P2390 / blocks 23/26e + 30/1d), home to the Isolde shallow water prospect:","United Kingdom, P2390"
83502,"The state company ONHYM 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 Â 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",Open Acreage in Morocco: 30 blocks on offer
21482,"Despite a first effort launched in 2013, DIG is still looking to farmout its 12,965-sq km Mopongo block, NE Congo in the Carnot and Busira sub-basins, NW Cuvette Centrale. Currently DIG (op), partners SNPC + sundry local interests. * Divine Inspiration Group","Despite a first effort launched in 2013, DIG is still looking to farmout its 12,965-sq km Mopongo block, NE Congo in the Carnot and Busira sub-basins, NW Cuvette Centrale. Currently DIG (op), partners SNPC + sundry local interests. * Divine Inspiration Group"
14712,"Area A, Eastern Desert, spudded 11 Dec â17, tested 2,452 bo/d from the Hamman Faraun MBR/Belayim fm on 2â choke on 28 Jan â18, later stabilised at  1,900 b/d on 1â choke.","South Kheir 1X (SK-1X) op. by Kuwait Egy. (70%, Petrogas E&P 30%) in Shukheir (Area A) tested successfully at an initial oil flow rate of 2 452 bo/d from the Hamman Faraun MBR/Belayim Fm [2ââchoke], after that the well stabilized at an oil rate of 1 900 bo/d [1ââchoke]. "
81153,"Pakistan Petroleum Ltd (PPL) reported on 28 April 2020 in the quarterly report (quarter ending 31 March 2020) that a rig-less testing was carried out in the Unarpur 2 appraisal well within the Kotri North 2568-21 EL (Kirthar Fold Belt) onshore concession, operated by United Energy Pakistan (UEP), during which minor, non-commercial quantity of gas was flowed and the well was subsequently suspended for further evaluation. UEP had earlier suspended the well during mid-December after drilling to a TD of 4,136 m - reached in mid-November. The well was spudded on 3 August 2019 using the âExalo-303â land rig with a prognosed TD of 4,174 m in the Cretaceous and it was targeting the Cretaceous Lower Goru Formation. The operations were temporarily suspended in mid-August 2019 after reaching 1,161 m depth due to flood in the area and the drilling activity was subsequently resumed during the second week of September 2019. The well reached 1,472 m depth by mid-September and progressed to 3,073 m depth by the end of the month. It was drilling at 3,384 m depth during mid-October 2019 and reached 3,720 m by the end of the month. A 7"" liner was set after reaching the TD in November 2019. Kotri North EL, which covers an area of 2,472 sq km, is located in the Sindh province and current equity split is as follows: UEP (60%, operator) and Pakistan Petroleum Ltd (PPL) (40%). UEP had made the Unarpur 1 gas discovery in the block in March 2019 which during testing had flowed 18.5 MMcfg/d through 44/64â choke at a well head flowing pressure of 1,916 psi between 3,833.6 m to 3,853.7 m (12,578 to 12, 644 ft) perforated interval within the Cretaceous Lower Basal Sand unit of Lower Goru Formation. It also flowed 54 bw/d during testing. Unarpur 1 was drilled to a TD of 3,938 m. UEP had earlier drilled Aliabad 1 exploratory well in the block which was suspended in February 2018 after conducting testing. The well was spudded on 29 November 2017 and it reached the TD of 4,340 m in mid-January 2018. Â Background Information The Kotri North EL block was exclusively awarded to PPL on 29 April 2010. PPL subsequently assigned 10% working interest in the block to Asia Resource Oil Ltd with effect from 27 May 2011. PPL acquired 569 line km of 2D seismic over the acreage during September 2010-January 2011 using the BGP '2273' land crew. The company subsequently acquired an additional 44 line km of 2D seismic during March 2012, using the BGP â9501-Eâ seismic crew. In April 2015, PPL abandoned the Kotri North X-1 new field wildcat well following testing, having reached TD at 3,650.7 m by the end of March 2015. The well failed to find hydrocarbons. PPL was granted a ten-month extension to the third year of Phase I of the Kotri North EL from 29 June 2015 till 28 April 2016. The company acquired 475 sq km 3D seismic over the block during April-November 2016 using the âBGP 9501-Aâ seismic crew. It was reported in June 2017 that PPL was granted a two-month extension to the third year of Phase-I of the Kotri North EL from 29 April 2016 to 28 June 2016. The licence has subsequently been granted renewal as well and it entered into two-year Phase-II of initial term with effect from 29 June 2016. PPL assigned 50% of its working interest along with operatorship in the block to UEP with effect from 2 August 2017. As a result of this transaction the revised equity split in the block was as follows: UEP (50%, operator), PPL (40%) and Asia Resource Oil Ltd (AROL) (10%). UEP subsequently acquired AROLâs full 10% interest in the block on 17 April 2018."," United Energy Pakistan (UEP) completed testing in Unarpur 2 appraisal well in Kotri North EL (Lower Indus Basin) during which minor, non-commercial quantity of gas was flowed and the well was subsequently suspended for further evaluation."
72868,"Mitsui is reportedly looking at its options to partner Bapex in blocks 8 + 11, total 14,574 sq km in the West Bengal Basin, a 1st such move by a Japanese co. Mitsui would propose to drill 2 explo + 2 devt wells:",Moeco (Mitsui Oil Exploration Comp.) is in talks with NOC Bapex for a possible exploration JV onshore Bangladesh. Mitsui has its eye on onshore blocks 8 and 11 and the operator has reportedly proposed drilling four wells across this acreage.
61620,"Qiongdongnan Basin, E. Lingshui Sag, WD 1,830m, gas find, tested >35 MMcf/d from the basement. PTD was 3,015m, target Oligo-Miocene clastics, Blue Whale 1 SS.","China (Songliao B.) ? op. by PETCHIN DQ (100.0%, PETCHIN DQ 100.0%) in Yongle block"
74781,"P1820, WD 80m, HP/HT gas-cond prospect, reportedy gas-cond discovery in several horizons (possibly thin, therefore commerciality under question), results under evaluation, Noble Sam Hartley JU. PTD was 5,380m, target Triassic Joanne + Judy sst. Total (op), partners Neptune, Euroil + Ithaca.",United Kingdom (Silverpit B. (Anglo-Dutch B.)) Neptune
29242,"Qatar Petroleum (QP) has reported that two appraisal wells drilled on the small Abruk structure in the north-west of the country during 2016 had yielded disappointing results. The wells Abruk 3 and Abruk 4 were believed to have been evaluating Chevronâs 2001 Abruk 2 oil discovery, which has been drilled broadly on trend with an initial well which had been abandoned with oil shows by QPC (60%) and IPC (40%) in 1970. The structure is located on a peninsula of land 5km east of the Dukhan oil field, which is contiguous to Bahrainâs Hawar Island border. Â EnCana farmed in to onshore Block 2 which contained the discovery during 2Q 2002. EnCana acquired a 40% equity stake in the concession and assumed operatorship, it joined Chevron (30%) and Svenska (30%) as partners in the acreage. It subsequently became 100% rightholder following the withdrawal of its partners prior to entering a second exploration period. EnCana completed a 500 sq km 3D survey to identify up-dip closure and stratigraphic pinch-out of the Upper Jurassic, Jubaila grainstone identified in the Abruk 2 oil discovery within its onshore Block 2 concession during 2005. A farm-out flyer prepared by Encana subsequently indicated that the Abruk structure was filled to spill point and had reserves of 3 MMbo.","Qatar Petroleum (QP) has reported that two appraisal wells drilled on the small Abruk structure in the north-west of the country during 2016 had yielded disappointing results. The wells Abruk 3 and Abruk 4 were believed to have been evaluating Chevronâs 2001 Abruk 2 oil discovery, which has been drilled broadly on trend with an initial well which had been abandoned with oil shows by QPC (60%) and IPC (40%) in 1970. The structure is located on a peninsula of land 5km east of the Dukhan oil field, which is contiguous to Bahrainâs Hawar Island border. "
11473,"NW part of Okany Kelet (East) block, Bihar sub-basin in E. Hungary, susp. for testing at TD 3,120m (Paleozoic basement) on 30 Nov â17, Rotary rig 69. Â Targets assumed Lower Pannonian, Miocene + basement. ",Hungary (Pannonian B.) Mezosas Del-Nyugat 2 op. by MOL (100.0%) in Okany-Kelet block
9108,"Australian Gasfields Ltd (AGF) and Beach Energy Ltd entered into an agreement in July 2017 for AGF to acquire complete interest in two Cooper-Eromanga permits: production licence PL 184 (Thylungra field) and exploration permit ATP 932-P. The deal, which is expected to be completed by end-January 2018, will see AGF increase its interest to 100% in both permits. Currently, AGF holds 19.6% in PL 184 and has zero interest in ATP 932-P. Since early 2016, Beach has undertaken geological and geophysical studies in PL 184, in which AGF has contributed around AUD 770,000. The studies have been focused on the determining commercial opportunities for the Thylungra discovery. PL 184 was awarded on 13 September 2001 and is due to expire on 12 September 2021. Both Beach and AGF have participated in the permit since October 2001. Beach Energy currently holds its interest through Beach Energy Ltd (74.2% + operator) and subsidiary company Mawson Petroleum Pty Ltd (6.2%). ATP 932-P covers at area of 1,541 sq km and was awarded on 15 February 2013. Beach had been offering a farm-in opportunity in the block after a deal with Real Energy to acquire 50% interest failed to complete in 2012. ATP 932-P is currently 100% owned by Beach Energy, through its subsidiary companies: Drillsearch Energy Pty Ltd (50% + operator) and Circumpacific Energy (Australia) Pty Ltd.  ",Australia (Eromanga B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: ATP 932-P(b) op. by ENERGY WD (100.0%) to be check.ATP 932-P(c) op. by ENERGY WD (100.0%) to be check.ATP 932-P(a) op. by ENERGY WD (100.0%) to be check.
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. "
20527,"Siccar Point announced on 28 March 2018 that it has farmed down a 30% interest in licences P1028 and P1189 which contains the appraising Cambo field and also a 22.5% interest in the Blackrock prospect in licence P1830 to Shell UK Limited. The Cambo field is being appraised with well 204/10a-5, which spudded on 24 April 2018. Blackrock is planned to be drilled in 2019. It is understood that in return for the interest Shell will carry costs in relation to the aforementioned exploration and appraisal wells and also any potential development on Cambo. The deal was completed on 1 May 2018. Cambo was discovered in 2002 by Amerada Hess with well 204/10-2. Five wells in total have been drilled on the structure to date. The plan for the appraisal well is to undertake an Extended Well Test (EWT) on the field. Cambo has an Hildasay reservoir and the field is thought to hold approximately 600 MMbo in place. The plan for the potential development is that it will be developed in two phases. Phase one involves a leased FPSO with seven producing wells and two water injectors and the plan is to produce approximately 87 MMbo and also some associated gas. Phase two details have not been defined to date. FID for the field is scheduled for the first half of 2019. 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. Following completion of the deal interests in P1028 and P1189 are held by Siccar Point Energy (70% + operator) and Shell UK Limited (30%). Interest in P1830 is held by Siccar Point Energy (52.5% + operator), INEOS E&P UK Limited (25%) and Shell UK Limited (22.5%).","United Kingdom, P1189"
25749,"In late May 2018, Apache abandoned the Alamein Yidma G 1 (Alyid-G-1) (Le38-3) wildcat in the Alamein-Yidma lease, Alamein Sub-basin, Northeastern Western Desert after reaching a TD of 2,590 m. The well was spudded on 3 May 2018, using the ""EDC-61"" land rig. The well, also called Alyid-G-1- Tuna, had a planned TD of 2,591 m and the Kharita Member as the objective. Apache operates the block with a 50% interest. Partners IPR-Transoil and Sojitz Oil & Gas holds 30% and 20% interests respectively","Alamein Yidma G 1 (Alyid-G-1) (Le38-3) wildcat in the Alamein-Yidma lease, Alamein Sub-basin, Northeastern Western Desert after reaching a TD of 2,590 m.P&A results n/a"
78090,On 17 April 2020 it was announced that Sonatrach signed two memoranda of understanding (MOU) on upstream exploration with Turkish company TPAO and Russian company Zarubezhneft. The MOU's will set a frame in which further talks will be held with each company to identify attractive projects in Algeria's upstream. Zarubezhneft is specialist in IOR/EOR and is likely to focus on projects to assist Sonatrach increasing the oil recovery at its existing fields. This comes one month after Sonatrach signed a similar agreement with Chevron and indicates that the revised hydrocarbon law introduced in December 2019 is attracting new companies to Algeria.,"TPAO and Zarubezhneft each signed an MoU with Sonatrach paving the way for discussions over joint E&P opportunities in the country, taking advantage of its new hydrocarbon law. Inter alia, this includes the absence of the 51% required state participation in all foreign investment projects, and likewise the stateâs pre-emptive right in proposed sale of Algerian assets to foreign investors."
50046,"Mirpur Khas 2568-7 EL, Lower Indus onshore, Sindh, TD 3,984m, susp after testing presumably gas in late Apr â19, Hilong rig 5. Target L. Goru. UE (op), partners Bow Energy, Zaver Petr. + GHPL.","Baudero-1 nfw in Mirpur Khas 2568-7 EL TD 3,984m, susp after testing presumably gas in late Apr â19,Target L. Goru. UE (op), partners Bow Energy, Zaver Petr. + GHPL."
16550,"Mari Petroleum Company Ltd (MPCL) reported on 16 March 2018 that it has signed a MOU with Polskie Gornictwo Naftowe I Gazownictwo SA (PGNiG) on 15 February 2018 for strategic cooperation in exploration and production (E & P) activities. MPCL stated that the initiative aims at future local and international upstream projects including farm-in opportunities and shale gas potential in Pakistan. The MOU for strategic cooperation was signed by MD/CEO MPCL, Mr Ishfaq N. Ahmed and PGNiGâs MD, Mr. Przemyslaw Krogulec at MPCL office in Islamabad. The signing ceremony was witnessed by senior officials of the two companies.",MPCL has signed a MOU with PGNiG for strategic cooperation in exploration and production (E & P) activities in Pakistan.
21877,"Fracción C block, onshore Austral Basin, 1st in 4-well programme, TMD 1,760m, gas discovery in the U. TobÃfera, over 40m of gas shows, running prod. csg ahead of testing. Petreven H-205 rig next to Los Alamos X-1 (ELA-1), spudding in next few days.","Estancia La Maggie X-1004 (ELM) Cia General de Combustibles (100%) in Santa Cruz I block (Fracción C), onshore, 1st in 4-well programme, TMD=1760m, gas discovery in the U. TobÃfera, over 40m of gas shows, running prod. csg ahead of testing."
48997,"Vashishtha ML, KG shelf, WD 185m, believed susp. at TD 4,525m, Sagar Vijay DS released on 12 May â19.","G-1-N AD nfw Vashishtha ML, KG shelf, WD 185m, believed susp. at TD 4,525m,"
34867,"Bass Oil announced on 13 November 2018 the signing of a Heads of Agreement with Azipac for the acquisition of 100% interest and operatorship in the North Madura PSC, located in shallow water East Java Basin. The deal is contingent to the signing of a detailed sale and purchase agreement and reception of the necessary regulatory approvals. The PSC has a remaining commitment of one exploration well plus two contingent wells in case of success. The Reog prospect has been identified as the top drilling candidate. According to Azipac, the prospect, located in the western part of the PSC, could contain up to 1.3 Tcfg within three stacked carbonate buildups of the Kujung Formation. The prospect is located 3 km east of the Ujung Pangkah field (Pangkah PSC) which has produced 9,000 bo/d and 44 MMcfg/d in 2017. Drilling of the Reog prospect is expected in 2019. Upon completion of the deal, Bass will likely seek a farm-in partner in the PSC to offset exploration risk and share drilling cost. Earlier in 2018, Azipac estimated a cost of approximately USD 8 million for the well. The seismic commitment in the block was fulfilled with a 400 sq km 3D seismic survey acquired in the block in late 2017, using the âPGS Apolloâ S/V as part of a multi-client survey project that also covered Petronas Carigaliâs North Madura II and Ketapang PSCs. The purpose of this survey was to assess the potential of the deeper reservoir. According to AziPac, the under-explored Ngimbang clastics could provide further upside in the area. The exploration period for the North Madura PSC is due to expire in May 2020 following a four-year extension effective on 18 May 2016. Background Information The North Madura block was offered on 30 November 2009 as part of the Second Petroleum Bidding Round 2009 under the direct offer mechanism. The block was awarded to AWE (50%, operator) and Black Platinum Energy (50%) on 18 May 2010. Mitra Energy then farmed-in and acquired 25% interest from Black Platinum on 9 June 2011. Firm commitments for the first three years of exploration include G&G studies (USD 0.4 million), and drilling of one exploration well (USD 8 million). Signature bonus for the block was USD 1 million. The block covers an area of approximately 1,850 sq km following partial relinquishment in 2016 and comprises two separate areas in shelf water. It is adjacent to Pertaminaâs West Madura Offshore PSC, which includes Poleng and KE 6 oil fields and KE 5 gas field and to Petronas Carigaliâs Ketapang PSC, which includes the Bukit Tua oil and gas field. Several sub-blocks were previously covered by the Pangkah PSC, currently operated by Saka Energi. AziPac initially entered the block in October 2015, acquiring a combined 50% interest from Mitra Energy (25%) and North Madura Energy Limited (25%), a wholly-owned subsidiary of Black Platinum Energy. In 2016, operator AWE divested its 50% interest to Azipac which became sole interest holder in the block. The company then commenced to seek a farm-in partner for the block. The previous exploration activity in the block was a 350 km 2D seismic survey in September 2014. No wells have been drilled to date under the North Madura PSC. AWE was planning to drill wildcat Dyah 1 in late 2015, however the plan did not go through. Dyah is likely a carbonate prospect likely located northeast of the Ujung Pangkah field, near the Reog prospect.",Bass Oil has a HoA to acquire a 100% interest from Azipac in the North Madura PSC in coastal shallow waters off Java.
12457,"Hurri NFW 7219-12-3 S in PL533 was being P&A dry on 10 January 2018. The well encountered no reservoir in the Middle Jurassic to Lower Cretaceous Hekkingen Formation (Fm), and good reservoir in the Jurassic Sto Fm but no hydrocarbons were present. 7219-12-3 S had reached TD at 2,750m MD (2,707m TVD) and carried out logging by 8 January 2018 after spudded on 3 December 2017. The ""Leiv Eiriksson"" semi-sub is operating in 313m WD, and planned duration was 60 days for the main wellbore, extending to 122 days for a discovery including sidetrack and testing. PTD was 2,720m MD (2,689m TVD), planned to be drilled vertically targeting 218 MMboe prospective recoverable resources in the Jurassic and Triassic. Lundin recently concluded the Hufsa NFW 7219/12-2 S, 15km SE of Hurri on PL533, P&A in November 2017 after it reached 2,100m MD (1,854m TVD) and discovered non-commercial gas in the Early Jurassic Nordmela Fm. Hurri lies on trend with the Filicudi discovery 1.5km to the NE on PL533, with estimated recoverable resources of 35-100 MMboe. Filicudi was discovered in January 2017 by 7219/12-1, which encountered oil in Triassic Tubaen Fm, and gas in Jurassic Sto and Nordmela Fms. PL533 also contains the Salina discovery made by 7220/10-1 (2012, Eni, 2,405m) 15km to the SE of Hurri, which found gas and condensate in the Early Cretaceous Knurr Fm and Middle Jurassic Sto Fm (estimated recoverable resources of 31-44 MMboe). PL533 was awarded to an Eni-led partnership in the 20th Licensing Round on 15 May 2009 with a five year initial term which has been extended to November 2017. Eni withdrew from PL533 in September 2015 with its 40% stake reassigned to the remaining partners. Licensees are Lundin Norway AS (35% + Op), Aker BP ASA (35%), and DEA Norge AS (30%).","Norway (S. Barents) 7219/12-03 S (Hurri) op. by Lundin (35%, Aker BP 35%, DEA 30%) in PL 533 block, 32km NW of Alta discovery, no reservoir properties in Hekkingen and a good reservoir in Sto fms. but with no indication of hc. P&A, dry ."
18399,"Sangatta PPC in E. Kalimantan, N. of Sangatta field, TD ca. 2,100m, long-delayed well drilled from Aug â17 until Jan â18, likely P&A w/ results unreported. Background from GEPS.","Indonesia, Brajanata-1, Sangatta PPC, E. Kalimantan, N. of Sangatta field, TD ca. 2,100m, long-delayed well drilled from Aug â17 until Jan â18, likely P&A w/ results unreported."
32071,"14 blocks will be on offer as of late October-early November in the 2nd round of open acreage licensing programme (OALP-II). Total 29,000 sq km, essentially derived from 13 EoIs submitted. Meanwhile 7 expressions of interest have been received to date under the (OALP-III). The govt now plans to offer 5 CBM blocks along with the other units, which will be selected based on EoIs made, the deadline for which is 15 Nov â18","14 blocks will be on offer as of late October-early November in the 2nd round of open acreage licensing programme (OALP-II). Total 29,000 sq km, essentially derived from 13 EoIs submitted. Meanwhile 7 expressions of interest have been received to date under the (OALP-III). The govt now plans to offer 5 CBM blocks along with the other units, which will be selected based on EoIs made, the deadline for which is 15 Nov â18"
48870,"The DGH closed its 2nd and 3rd rounds of OALP (open acreage licensing programme) on schedule on 15 May â19. Technical bids have reportedly been opened already however applicants have yet to be revealed. OALP II had 14 blocks on offer, OALP III 23 blocks. Maps + round details from GEPS.","India, not found"
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 shareholdersâ 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 Lionâs position in the area, as the company was also awarded 100% interest in the East Seram exploration block in May 2018, following Indonesiaâs 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 52/64â choke. A 12 hours flow period on 16/64â 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"
62183,"As of 22 October 2019, Petrolera Monterrico SA (Petromont) is looking for a partner to continue development operations in Block II located in the Talara Basin in northern Peru. Block II was granted to Vegsa Contratistas Generales on 17 January 1992 as a service contract. On 5 January 1996, the company converted the original contract into a licensing contract for production for a 20-year period. With service and workover operations and completion of new wells, Vegsaâs planned to boost production from around 600 to 1,200 bo/d. At that time, some 110 wells were producing from three fields, Coyonitas, Golondrina and Hualtacal. Vegsa fulfilled its first one-year obligations for the new contract with one well drilled and completed as an oil producer in the Hualtacal field in December 1996. The second one-year period began on 5 January 1997 with commitments to drill two wells to TD 2,300m or to the Lower Eocene Mogollon Formation. These were drilled in the Golondrina field, #12006 in January 1997 and #12004 in February 1997. The Block II third one-year period called for the drilling of a total of 4,760 m, i.e. two or three wells, depending on the depths of the Mogollon reservoir. This ranges in depths from around 1,200 m in the eastern portion of Block II to some 2,200 m in the western part. By decree published on 3 September 1997, Vegsaâs subsidiary Petrolera Monterrico S.A. was authorized to assume the entire interests in Block II, previously held by Vegsa C.G. The block has undergone several periods of development drilling prior to entering into Force Majeure in September 2018 which has since been lifted.","As of 22 October 2019, Petrolera Monterrico SA (Petromont) is looking for a partner to continue development operations in Block II located in the Talara Basin in northern Peru. "
45206,"ENAP has completed a 50% farmout to partner ConocoPhillips on the 3,230-sq km El Turbio Este block , an original agreement to this intent having been signed in early 2018. A 1,300-sq km 3D seismic survey is currently underway here, believed close to completion. El Turbio Este lies in the Santa Cruz Province, Austral Basin.",ENAP (->50%) has completed a 50% farm-out process to partner ConocoPhillips on the El Turbio Este block
30105,"East Abu Sennan block, Abu Gharadiq Basin, W. Desert, compl. oil at TD 2,280m in late Aug â18. Target Bahariya fm, ST 13 rig. Likewise Abu Sennan East G 1 (EAS-G-1), compl. oil at TD 1,865m on 31 Jul â18, same rig. Target Bahariya.","Egypt, Abu Gharadiq (Dev)"
24255,"Sharjah is understood to have launched its 1st onshore round process yesterday for blocks A, B + C, available under 30-year contracts + 10-year extension from Sharjahâs NOC. A data room will open on 4 Jul â18 along with other documentation required. Bids close 18 Nov â18, any contracts effective 1 Jan â19. SNOC will retain 25% in blocks A + C, and a 50% in B, which is an un-appraised deep gas play below the Sajaa gas-cond field.","Sharjah is understood to have launched its 1st onshore round process yesterday for blocks A, B + C, available under 30-year contracts + 10-year extension from Sharjahâs NOC. A data room will open on 4 Jul â18 along with other documentation required. Bids close 18 Nov â18, any contracts effective 1 Jan â19. SNOC will retain 25% in blocks A + C, and a 50% in B, which is an un-appraised deep gas play below the Sajaa gas-cond field."
41460,"On 8 February 2019, Impact Oil and Gas announced that it had farmed into Totalâs Block 2912 (PEL 91). The 7,900 sq km Orange Sub-basin block is located adjacent to the west of Totalâs Block 2913B (PEL56). Water depth range between 3,000 m and 4,000 m. To date the area is virtually unexplored. Only a few 2D seismic lines cross the licence in an east west direction and the area is undrilled. Total plans to drill a well within the adjacent Block 2913B targeting the Venus prospect in late 2019. Total via is wholly owned subsidiary Total E&P Namibia B.V. operates the block with an 66.11% interest, Impact Oil and Gas via its wholly owned subsidiary Impact Oil and Gas Namibia (Pty) Ltd. holds an 18.89% stake and NAMCOR holds the remaining 15% interest. Background information  On 16 May 2018, Total was awarded the exploration licence. At the time Total operated the block with an 85% interest and NAMCOR held the remaining 15% stake.","Total has signed a farm-out agreement with Impact Oil and Gas over its ultra-deepwater Block 2912a. Under the deal, Impact will own 18.89%, with Total operating the project with a 66.11% interest. Namcor holds a 15% share of the block. "
27481,"Further to DEA 6 Aug â18: MLHP-7 (Etinde EA), original hole TD 3,550m, sidetracked to 3,270m, target Isongo 410 + 510 sands found water-wet, deeper 310 gas shows. Well to be P&Aâd, Topaz Driller JU then off to drill IE-4. New Age (op), partners Lukoil, Bowleven, SNH carried. 1st of 2 appr wells planned in the shallow-water block around the Isongo M2 gas-cond discovery area.","MLHP-7 (Etinde EA), original hole TD 3,550m, sidetracked to 3,270m, target Isongo 410 + 510 sands found water-wet, deeper 310 gas shows. Well to be P&Aâd, Topaz Driller JU then off to drill IE-4. New Age (op), partners Lukoil, Bowleven, SNH carried. 1st of 2 appr wells planned in the shallow-water block around the Isongo M2 gas-cond discovery area."
27554,"Although still a relatively modest affair, Gulf of Mexico operators showed more interest in Sale 251 than they exhibited at the most recent sales, sending USD 178,069,406 in high bids to the governmentâs coffers about USD 53 million more than the last sale. The Bureau of Ocean Energy Management (BOEM) reported that 29 companies took part in the 15 August 2018 region-wide auction placing 171 bids on 144 blocks. The bidders exposed a total of USD 202.6 million. By comparison, the last Gulf-wide sale, held in March 2018, saw 148 blocks awarded to the 33 participating companies and brought in USD 124.7 million. Deepwater blocks (= 400 m/1,312 ft) accounted for 111 (77%) of the blocks taken with most of the bidding action centering on the Miocene trend in the Mississippi Canyon and Green Canyon areas. Significant bidding activity also occurred along the DeSoto Canyon-Lloyd Ridge boundary line that is likely chasing Norphlet objectives and in Alaminos Canyon for the Paleogene play. The number of shallow water blocks bid on in Sale 251 dropped from the last sale, with 33 shallow water blocks getting bids in this sale vs 46 last sale. High Island and Main Pass areas received much of this saleâs shelf bidding. For all water depths, there were 124 single-bid blocks. Twenty blocks garnered multiple bids, with one block fetching four bids. Hess Corporation tendered the highest bid of the sale, submitting USD 25.9 million for Mississippi Canyon (MC) block 338. Hessâ offer topped a USD 2.1 million bid from a group led by LLOG Exploration Offshore. The saleâs most expensive block was part of the Silvergate prospect. Noble Energy tested Silvergate in 2016, drilling out of MC block 338 into MC block 339, to a depth of about 20,000 ft (6,096 m) targeting subsalt Miocene objectives. The company reported that the well did not encounter commercial hydrocarbons and was plugged and abandoned. MC block 338 is also adjacent to Shellâs Kepler field, an Upper Miocene accumulation. Hess doled out a total of USD 36.1 million in high bids, the second most in the sale, and took 16 blocks. Nine of these 16 tracts were in the Viosca Knoll area. ExxonMobil won the most blocks and was the biggest spender in the sale, reeling in 25 of the 26 tracts it bid on while expending USD 40.5 million. All of ExxonMobilâs high bid blocks are closely grouped along the boundary line separating the DeSoto Canyon and Lloyd Ridge areas. Many of the blocks ExxonMobil just procured were held by Shell until they expired in February 2018. The company likely picked up this acreage for its Norphlet sand potential, playing the southern extension of the trend. Two of these DeSoto Canyon blocks are the third and fourth most expensive in the sale, coming in at USD 8.5 million and USD 7.5 million. BP E&P Inc. and Equinor Gulf of Mexico were the other two big players in the sale. Following its strong 27 block showing in the last sale, BP placed bids on 25 blocks winning 19 of them for USD 12.5 million. BP spread its bidding across the Green Canyon (GC), Atwater Valley (AT) and Mississippi Canyon areas, but it focused on a group of five blocks in the MC area about 15 miles (24 km) west of Shellâs recently sanctioned Vito project and near Anadarkoâs Haleakala prospect, an undrilled subsalt Miocene play. BP took four of the blocks (MC blocks 936, 979, 980 and AT block 10). Shell Offshore Inc., which only bid on four blocks in Sale 251, took the fifth block (MC block 978) outbidding BP and Equinor with its USD 4.6 million bonus. Like ExxonMobil, Equinor concentrated its bidding in a single area. However, Equinor chose to direct its aim at the Alaminos Canyon (AC) area. Of the 16 blocks picked up by the company, 13 of them are clustered in the northeast quarter of Alaminos Canyon along a sparely explored portion of the Lower Tertiary Wilcox trend. This group of blocks includes the AC block 200 discovery, an undeveloped Pliocene oil find made by ExxonMobilâs in 1998. Equinorâs seven-block acreage position for its Coral prospect, a Wilcox play, lies about 20 miles (32 km) southeast of the new pick-up. Chevron U.S.A. Inc. did not have a large presence at Sale 251. The company bid on and won only five blocks, but it still placed USD 18.7 million in high bids, the third largest sum in the sale. The bulk of its bid money, USD 11.1 million, went to MC block 743. ExxonMobil unsuccessfully wagered USD 2.3 million for the same block. MC block 743 is just east of established Miocene oil production at Fieldwoodâs Big Bend and Chevronâs Blind Faith fields, but it is also about 10 miles (16 km) south of multiple Norphlet oil finds. The most recent being Chevronâs 2017 Norphlet discovery at its Ballymore prospect in MC block 607. Chevron also spent about USD 4.7 million to pick-up Garden Banks blocks 956 and 957. These blocks lie just west of North Platte project, an appraised Wilcox oil find, and they are also the site of Cobalt International Energyâs Baffin Bay prospect, an undrilled Wilcox play. TOTAL, the operator of North Platte, was the high bidder on two blocks just north of the project. In addition to new plays, several operators appear to be revisiting old plays. Houston Energy and Beacon Energy Exploration combined to win Walker Ridge 544 where BP made the 2006 Tucker prospect discovery, a Wilcox oil accumulation that was not developed. The Chevronâs 2015 Wilcox discovery at the Sicily prospect in Keathley Canyon block 814 has been reacquired by Deep Gulf Energy (now Kosmos Energy), with Anadarko taking adjacent KC block 815. Anadarko won Walker Ridge block 925 which sits just north of another undeveloped Wilcox oil find, Equinorâs Logan prospect in WR blocks 969 and 970. A Murphy combine was high bidder for GC block 852. This block lies just southwest of Chevronâs appraised Wilcox oil find at the Anchor project and immediately north of Cobaltâs unsuccessful Ardennes prospect well, the Gulfâs deepest well, which was drilled to a final depth of 36,552 (11,141 m). At AT blocks 398 and 444, EnVen Energy Venture has won acreage that is the site of the undeveloped 2005 subsalt Bonsai discovery, a Lower Pliocene-Upper Miocene oil and gas find made by BP, and Eniâs Bonsai South prospect, an untested subsalt Plio-Miocene play. BOEM sale statistics and materials for Lease Sale 251 are available at http://www.boem.gov/Sale-251/. All apparent high bids tendered during Sale 251 will be subject to BOEM review before the blocks can be officially awarded. The government processes the apparent winning high bids via a two-stage economic analysis to ensure that the public receives fair market value for all tracts leased as part of sale offering. Sale 251 was the third sale held under the 2017-2022 OCS Oil and Gas Leasing Program. It encompassed about 14,622 unleased blocks, located from three to 230 miles (five to 368 km) offshore in water depths ranging from nine to more than 11,115 feet (three to 3,400 meters).","GoM Lease sale 251 - 29 companies took part, placing 171 bids on 144 blocks. ExxonMobil won the most blocks and was the biggest spender in the sale, getting 25 of the 26 tracts it bid on BP and Equinor were the next big players, BP winning 19 of 25 sought, and Equinor 16."
88153,"In August 2020, the Agencia Nacional de Hidrocarburos (ANH) published the status of Exploration and Production (E&P) contracts and Technical Exploration Agreements (TEAs) valid as of 30 June 2020, and indicated that the Merecure Block in the Llanos Basin, is now operated by Cepsa Colombia with 35% working interest, and non-operating partners Parex Resources Colombia Ltd with 35% working interest and Perenco with the remaining 30%. Parex announced on 7 March 2019 it had signed a farm-in agreement to acquire 35% working interest from the 70% working interests owned by operator Cepsa Colombia. As part of the agreement, Parex would pay 100% of the cost to drill two exploration wells. Parex indicated that the Tamariniza 1 new-field wildcat (NFW) was drilled in the second quarter of 2019 as part of the agreement. In March 2007, the original 2,381.90 sq km Merecure Block was awarded to operator Cepsa, with 100% working interest. Petrobras farmed-in in the block in December 2008 acquiring 30% working interest and later in April 2014 Perenco took over the working interest previously owned by Petrobras. In October 2016, Cepsa relinquished part of the block remaining with 1,142.11 sq km, and in April 2020, it made a partial relinquishment again, so that now the Merecure block has an area of 571.11 sq km. Background Information In August 2019, Parex Resources reported oil in the Cepsa-operated Tamariniza 1 NFW. Tests yielded some 800 bo/d gross. The well was spudded on 12 March 2019 and reached a total depth (TD) of some 5,173 ft (1,577 m) on 25 March 2019.","(Llanos-Barinas B.) Merecure block, op. by MUBADALA I (70%), PERENCO (30%) the Agencia Nacional de Hidrocarburos (ANH) indicated that the Merecure Block is now operated by Cepsa Colombia with 35% working interest, and non-operating partners Parex Resources Colombia Ltd with 35% working interest and Perenco with the remaining 30%."
15884,"Hitherto-unreported, Kapul secured PPL 610, Â 255 sq km in the Papuan Fold Belt, in mid-2017 for a 6-year term. Â It covers part of Oil Searchâs former PPL 260. ",Kapul Petroleum was awarded exploration licence PPL 610.
39336,"E. part of 32/96/p Kornik-Sroda block, Fore-Sudetic Monocline in W. Poland, P&A late Dec â18, lost string in target top Rotliegendes. PTMD was 4,700m (TVD 3,680m).","Poland, Kornik-Sroda"
83918,"Dhok Sultan 3371-15 EL, Potwar onshore, suspended at TD 5,607m (Eocene) in mid-Jun '20, tested, CCDC-32 rig. PPL (op) partner GHPL.","(Potwar B.) Dhok Sultan South X1 op. by PPL (75%), GHPL (25%) in Dhok Sultan 3371-15 EL block, operations temporarily suspended, testing was conducted from late-April until early June, after a TD of of 5,607m was reached in early April. This was shy of the PTD of 5,750m."
23703,"Todayâs EU Journal carries an invitation to bid for E&P rights to a 1,800-sq km area designated Å ilute-Taurage by the Lithuanian Geological Survey. The permit lies in the Å ilute, Taurage and Jurbarkas districts and Pagegiai municipality, and covers 132 sq km of urban areas and 623 sq km of âprotectedâ areas. Bids deadline 31 Oct â18 to the Lithuanian Geological Survey under the Ministry of the Environment, S. Konarskio g. 35, LT-03123, Vilnius. Award slated for 1Q â19.","Todayâs EU Journal carries an invitation to bid for E&P rights to a 1,800-sq km area designated Å ilute-Taurage by the Lithuanian Geological Survey. The permit lies in the Å ilute, Taurage and Jurbarkas districts and Pagegiai municipality, and covers 132 sq km of urban areas and 623 sq km of âprotectedâ areas. Bids deadline 31 Oct â18 to the Lithuanian Geological Survey under the Ministry of the Environment,"
52459,"Uzbekneftegaz (UNG) says it has possibly made a âgiantâ gas discovery in the North Ustyurt Basin, north-western Uzbekistan. Well Arslan 12 tested unspecified volumes of gas on 27 June 2019. The well is located in the area of three recent discoveries, understood to comprise Arslan, Surgil Quyi (Surgil Lower) and Surgil Janubiy (Surgil South), which are now thought to be parts of a single gas field. All these discoveries are located east of the large Surgil field. No further details of the new discovery have so far been released. The Surgil field was discovered by UNG in 2002. Its official published reserves stand at 120 Bcm (4.1 Tcf) of gas. It has multiple clastic reservoirs in Middle-Upper Jurassic continental deposits in a depth rage from 1,725 to 2,721 m. Surgil is the main source of gas for the Ustyurt Gas Chemical Plant launched in May 2016. The plant has been built by Uz-Kor Gas Chemical, a joint venture between UNG and a consortium of Korean companies led by Korea Gas Corporation (Kogas).","Arsian 12 expl, (UzKorGasChemical 100%), a giant gas field is looking likely in the Karakalpakstan in NW Uzbekistan, the well yielding unspecified (gas kick) volumes of gas on 27 Jun â19. The area comprises the Arslan, Surgil Quyi (Surgil Lower) and Surgil Janubiy (Surgil South) finds, now thought to be probably parts of a single gasfield east of the Surgil field per se. All these discoveries are located east of the large Surgil field. No further details of the new discovery have so far been released. The Surgil field was discovered by UNG in 2002. Its official published reserves stand at 4,1 Tcf of gas. It has multiple clastic reservoirs in Middle-Upper Jurassic continental deposits in a depth range from 1725 to 2721 m."
11511,"BP and partner Kosmos Energy have reportedly secured 5 offshore blocks with 10% partner Petroci. Involved are CI-526, CI-602, CI-603, CI-707 + CI-708, total 14,740 sq km in WD 1,000-3,500m and actually previously held by the likes of Total or ExxonMobil. Details awaited. ","BP and Kosmos Energy awarded 5 new DW offshore oil blocks: CI-526, CI-602, CI-603, CI-707 and CI-708."
21888,"White Rose field area, 10km N. of the SeaRose FPSO, Jeanne dâArc Basin off N&L, 2Q â18 discovery, >85m light oil column. Husky (op), partners Suncor + Nalcor.","White Rose field area, 10km N. of the SeaRose FPSO, Jeanne dâArc Basin off N&L, 2Q â18 discovery, >85m light oil column. Husky (op), partners Suncor + Nalcor."
47113,"KrisEnergy renews its farm-in opportunity for the Sakti PSC off E. Java Basin, up to 47% available in the 3,700-sq km block in return for pro-rata share of back costs and a carry on a explo/appr well. Â KrisEnergy (op), partner Golden Heaven Jaya. Contact: Mike.Whibley@krisenergy.com.","KrisEnergy renews its farm-in opportunity for the Sakti PSC off E. Java Basin, up to 47% available in the 3,700-sq km block in return for pro-rata share of back costs and a carry on a explo/appr well. KrisEnergy (op), partner Golden Heaven Jaya. "
35497,"Kapul secured in July sole rights to PPL 610, Â 255 sq km in the Papuan Fold Belt, Papuan Basin for a 6-year term. It covers part of the expired PPL 260 licence (ex-Oil Search, who was subsequently awarded PPL 545 in Aug â17).","Kapul secured sole rights to PPL 610, 255 sq km in the Papuan Fold Belt."
45059,"ANOC has awarded explo rights to Bharat Petroleum and Indian Oil Corp for Onshore Block 1, 6,162 sq km mostly onshore. The Indian coâs will hold a 100% stake during the 35-year E&P phase, ADNOC retaining a 60% back-in right during the production phase. Of note, Onshore Block 1 also covers the separate Ruwais Diyab unconventional gas block where Total is conducting an explo-appraisal phase targeting tight gas resources in the Diyab fm, which can then be followed by a 40-year production term.","ANOC has awarded explo rights to Bharat Petroleum and Indian Oil Corp (100%) for Onshore Block 1 (6162km² mostly onshore. ADNOC retaining a 60% back-in right during the production phase. Of note, Onshore Block 1 also covers the separate Ruwais Diyab unconventional gas block where Total is conducting an explo-appraisal phase targeting tight gas resources in the Diyab fm, which can then be followed by a 40-year production term."
48081,"Ecopetrol is on the lookout for partners in its 4,000-sq km COL-5 block in the Caribbean, secured only in March. The permit lies adjacent to its Purple Angel and Fuerte Sur blocks in the Sinú Basin, and had earlier been held under TEA terms. A data room will be available. Meanwhile the company intends to apply for more deepwater rights when ANH offers additional offshore blocks âin the next few weeksâ.","Ecopetrol is on the lookout for partners in its 4,000-sq km COL-5 block in the Caribbean, secured only in March. The permit lies adjacent to its Purple Angel and Fuerte Sur blocks in the Sinú Basin, and had earlier been held under TEA terms"
22895,"On 30 May 2018, the Ivorian Ministry committee agreed a series of negotiations undertaken with Dragon Oil plc (Dragon Oil) about the award of block CI-24. It is understood that the presidential consent is the last step to reach in order to finalize the award. CI-24 will be the first Sub-Saharan African asset for Dragon Oil, as the Dubai-based oil and gas exploration and production company has a portfolio mainly focused on Middle East and Saharan Africa so far. 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 Vitolâs block CI-202. Water depth varies from 0 m in the north to 1,500 m in the southwest corner of the tract. In the current CI-24 area, 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 Ivorian Ministry committee agreed a series of negotiations undertaken with Dragon Oil plc (Dragon Oil) about the award of block CI-24.
83305,"Armour has agreed to sell its 10% interest in PL 1084 (Murrungama), 18 sq km of CSG rights SW of Chinchilla in the Surat Basin, to APLNG for a total AUD 4 MM. PL 1084 had been granted to the team in March, a conversion of ATP 2046-P.","(Bowen - Surat B.s) PL 1084 op. by ORIGIN Armour has agreed to sell its 10% interest in PL 1084 (Murrungama), 18 sq km, to APLNG for a total AUD4 MM. PL 1084 had been granted to the team in March, a conversion of ATP 2046-P."
16468,"Yongye 2HF was suspended as a future gas producer in late 2017, following completion of production testing where stabilized flow rate of approximately 2.12 MMcfg/d was achieved. Yongye 2HF was last reported to be carrying out fracture stimulation in early March 2017. The horizontal shale gas well commenced drilling on 19 November 2016, targeting the Wufeng-Longmaxi interval, reaching TD of 5,796m MD on 26 December 2016 and was suspended for fracture stimulation and testing on 3 January 2017. The vertical wellbore Yongye 2 was spudded on 2 August 2016 and was drilled to a TD of 4,150m MD in the Baota Formation on 28 October 2016. Yongye 2 had a PTD of 4,227m and was targeting the primary objectives of the Silurian Wufeng Formation and the First Member of the Longmaxi Formation and secondary objectives of the Triassic Jialingjiang and Feixianguan formations and Permian Changxing and Maokou formations. Yongye 2 is geographically located in Chongqing City, Rongchang County, Wuma Village and is within the Sinopec operated Rongchang-Yongchuan Block. ",Yongye 2HF was suspended as a future gas producer following completion of production testing where stabilized flow rate of approximately 2.12 MMcfg/d was achieved.
78227,"G20-A block, Sea of Marmara shallow waters in Thrace Basin, ops terminated (possibly Susp.) Feb '20, GSP Saturn JU.","Gümüsyaka 1 (TPAO 100%) in G20 explo block. P&A, Results are not yet available, targeted the Degirmenköy member of the Eocene Sogucak Fm."
7584,"Hitherto unreported, on 8 June 2017, Oil & Gas Development Central Kft (OGD), subsidiary of Sand Hill Petroleum BV, completed drilling new-field wildcat Almosd Nyugat 1 in the Ujleta permit in northeastern Hungary. The well reached the final depth of 2,470 m (TVD 2,408 m) and tested commercial quantities of gas in multiple horizons within the Lower Pannonian (Miocene) succession. The well was subsequently completed as producer. Almosd Nyugat 1 was started on 25 May 2017. The well is located in the central-eastern part of the block, close to the border with Romania. In a geological sense, the well is located within the Hajdusag Sub-basin, tectonic unit of the Pannonian Basin. Almosd Nyugat 1, drilled on the Dreher prospect defined based on Peneszlek 3D seismic, had its targets likely within both, the Lower Pannonian and Miocene series.",Hungary (Pannonian B.) Almosd Nyugat 1 op. by OGD (100.0%) in Ujleta block
56138,"The OGA this morning approved Shellâs 50% farmin to Cluffâs so far wholly-owned P2437 (228 sq km, block 48/8b, Selene gas prospect), Shell paying for the costs to date. Shell has also committed to drill Selene asap, target Leman sst, paying 75% of well costs but capped at USD 25 MM.","P2437 farmin: done deal, The OGA this morning approved Shellâs 50% farmin to Cluffâs so far wholly-owned P2437 (228 sq km, block 48/8b, Selene gas prospect), Shell paying for the costs to date. Shell has also committed to drill Selene asap, target Leman sst, paying 75% of well costs but capped at USD 25 MM."
25272,"Europa has completed an updated prospect inventory for FEL 1/17 (521 sq km) + 2/13 (765 sq km) in the South Porcupine Basin and is offering these for farmin along with 3/13 (766 sq km, Main Porcupine) prior to embarking on drilling plans. Drilling targets have been identified in the 3 licences, namely Edgeworth, Egerton + Ervine in 1/17, Kiely East & West + Kilroy in 2/17, and Beckett, Shaw + Wilde in 3/17. A data room opened yesterday. A well is also planned mid-2019 on the Inishkea prospect in Slyne licence LO 16/20, subject to funding. All this amidst Parliament) passing in Thursday the Fossil Fuel Divestment Bill, which requires the Ireland Strategic Investment Fund to divest direct investments in fossil fuel undertakings within 5 years and not to make future investments in the industry.","Europa has completed an updated prospect inventory for FEL 1/17 (521 sq km) + 2/13 (765 sq km) in the South Porcupine Basin and is offering these for farmin along with 3/13 (766 sq km, Main Porcupine) prior to embarking on drilling plans. Drilling targets have been identified in the 3 licences, namely Edgeworth, Egerton + Ervine in 1/17, Kiely East & West + Kilroy in 2/17, and Beckett, Shaw + Wilde in 3/17. A data room opened yesterday. A well is also planned mid-2019 on the Inishkea prospect in Slyne licence LO 16/20, subject to funding. All this amidst Parliament) passing in Thursday the Fossil Fuel Divestment Bill, which requires the Ireland Strategic Investment Fund to divest direct investments in fossil fuel undertakings within 5 years and not to make future investments in the industry."
65725,"S-C part of ES-T-476, onshore Espirito Santo Basin, drilled + susp oil shows 5-late Nov '19, shows report on 23 Nov. PTD was c. 1,700m, targets São Mateus + Mariricu fmâs.","Suspended: 3-SDR-003-ES (3-BGM-003-ES) appr onshore Espirito Santo Basin, drilled + susp oil shows 5-late Nov '19, shows report on 23 Nov. PTD was c. 1,700m, targets São Mateus + Mariricu fmâs."
67321,"OMV Petrom will be acquiring OMV's 30% interest in the 14,220-sq km 1-21 Han Asparuh licence. The deal should complete in mid-2020. Han Asparuh lies in deeper water of the Black Sea, currently run by Total (op), partners OMV + Repsol.","OMV Petrom will be acquiring OMV's 30% interest in the 14,220-sq km 1-21 Han Asparuh licence. The deal should complete in mid-2020. Han Asparuh lies in deeper water of the Black Sea, currently run by Total (op), partners OMV + Repsol."
72392,"On 14 February 2020, Eneva was granted final awards for the PN-T-47, PN-T-48A, PN-T-66, PN-T-67A, PN-T-68, and PN-T-102A in the onshore Parnaiba Basin. On 10 September 2019, Eneva bid on and was granted preliminary awards for the PN-T-47, PN-T-48A, PN-T-66, PN-T-67A, PN-T-68, and PN-T-102A in the onshore Parnaiba Basin. There were no other bids for the blocks.  1st Open Door Bid Round - Preliminary Results - Eneva - 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 Parnaiba PN-T-102A 2,098.21 7.5 707 1121 5,745,125.00 84,449.07 132,569 Eneva (100%) Parnaiba PN-T-47 3,067.76 7.5 707 1897 9,722,125.00 101,939.07 168,898 Eneva (100%) Parnaiba PN-T-48A 1,612.57 7.5 673 1448 7,421,000.00 88,006.08 90,814 Eneva (100%) Parnaiba PN-T-66 3,066.33 7.5 578 2673 13,699,125.00 69,033.77 223,879 Eneva (100%) Parnaiba PN-T-67A 1,440.28 7.5 449 336 1,722,000.00 72,706.57 90,948 Eneva (100%) Parnaiba PN-T-68 2,494.59 7.5 578 1336 6,847,000.00 83,331.14 168,664 Eneva (100%) Totals Onshore 13,779.74 45,156,375.00 875,772.75 Source: IHS Markit         © 2019 IHS Markit","ENEVA SA - Parnaiba Basin -PN-T-47, PN-T-48A, PN-T-66, PN-T-67A, PN-T-68, and PN-T-102A blocks - final awards from 1st Open Door Bid Round"
22452,"Kuwait Energy is reportedly looking to sell off its assets in Egypt and Iraq to alleviate debt. In Egypt, Â the Abu Sennan, Abu Sennan GPZZ (KEE) (Dev), Abu Sennan H (KEE) (Dev), Al Zahraa (Dev), Burg El Arab North (Dev), Burg El Arab South (Dev), Diaa (Dev), East Umm El Yusr, Ghard (Dev), Kareem (Area A) Kheir (Area A), Rana (Dev), Shahd (Dev), Shahd South East (Dev), Shebl (Dev) - Shukheir (Area A), and Umm El Yusr (Area A) permits are involved.","Kuwait Energy is reportedly looking to sell off its assets in Egypt and Iraq to alleviate debt. In Egypt, the Abu Sennan, Abu Sennan GPZZ (KEE) (Dev), Abu Sennan H (KEE) (Dev), Al Zahraa (Dev), Burg El Arab North (Dev), Burg El Arab South (Dev), Diaa (Dev), East Umm El Yusr, Ghard (Dev), Kareem (Area A) Kheir (Area A), Rana (Dev), Shahd (Dev), Shahd South East (Dev), Shebl (Dev) - Shukheir (Area A), and Umm El Yusr (Area A) permits are involved."
36295,"PRL 149, Cooper-Eromanga, P&A oil shows at TD 2,172m on 22 Nov â18. Senex (op), partner Beach.","Flanker 1 (Senex 60%, op, Beach 40%) in PRL 149 block, having failed to intersect any hydrocarbons."
83064,"Amu-Darya Basin, near the Shorkum, Andakli, Parsankul + Hoja Garbiy fields, spudded Nov '19, gas discovery reported 16 Jun '20, tested 6.9 MMcf/d on a 14mm choke. A 2nd well is now planned at this location.","(Amu-Darya) Urtakum (Ortakum) 1 nfw, (UzbekNefteGaz 100%) near the Shorkum, Andakli, Parsankul + Hoja Garbiy fields, gas discovery reported 16 Jun '20, tested 6,9 MMscf/d on a 14mm choke. A 2nd well is now planned at this location."
78824,"Location in open area SW of Katowice in central Silesia, S. Poland, target Lower Carboniferous rumoured dry and reservoir tight. PTD was 4,500m (Devonian).","Orzesze-1 strat Location in open area SW of Katowice in central Silesia, S. Poland, target Lower Carboniferous rumoured dry and reservoir tight. PTD was 4,500m (Devonian)."
69246,"According to official reports in January 2020, Interoil has completed its acquisition of 8.34% and operatorship in five Roch-operated blocks in the Santa Cruz Province. It was said that Interoil's partner in its other Argentinean assets, Selva Maria Oil, will be operating the blocks until the company receives the operator license from the Argentine government. Other partners in the blocks are Echo Energy with 70% stake, and a subsidiary of Integra Oil & Gas, IOG Resources SA, with the remaining 21.66%. Echo entered the block in October 2019 following a purchase agreement with Phoenix Global Resources, while Integra Oil & Gas reportedly acquire its stake from previous operator Roch's original 30% interest. The blocks consisted of Campo Bremen, Chorrillos, Moy Aike, Oceano, and Palermo Aike, and all situated in onshore and shelf of Austral Basin. Block Name Basin Name Onshore/Offshore Contract Sqkm Onshore Sqkm Shelf Sqkm Deep Water Sqkm Campo Bremen Austral Basin Onshore 809.16 809.16 Chorrillos Austral Basin Onshore 650.7 650.7 Moy Aike Austral Basin Onshore 728.45 728.45 Oceano Austral Basin Onshore/Offshore 102.73 77.99 24.74 Palermo Aike Austral Basin Onshore 525.13 525.13  In August 2019, daily production in Campo Bremen block was 3.7 MMscfg/d and 92 bo/d, Chorrillos block was 11.1 MMscfg/d and 651 bo/d, Moy Aike was 146 Mscfg/d and 82 bo/d, and Oceano was 2.9 MMscfg/d and 34 bo/d. Meanwhile, the Palermo Aike block only has several discoveries and abandoned fields.  Background Information Interoil entered Argentina in April 2019 through a joint venture with Selva Maria Oil on Mata Magallanes Oeste and Canadon Ramirez blocks in San Jorge Basin and La Brea block in Neuquen Basin.","Interoil closed an agreement with Roch under which it acquired an 8.34% interest from the latter in 5 mature prod. leases designated Santa Cruz Sur Assets (Campo Bremen, Palermo Aike, Oceano, Chorillos..)."
11873,"Pirkoh D&PL, Sulaiman Fold Belt, 1-1/2 year well to TD 4,950m, P&A dry (tested) in late Dec â17, co. N-3 rig. Main target Cretaceous.","Pirkoh Deep 1 op. by OGDCL (100%) in Pirkoh D&PL block, 1-1/2 year well to TD 4,950m, P&A dry (tested), Main target Cretaceous."
27205,"In Q2 2018, Agiba Petroleum encountered oil in its Meleiha North Deep 1X deeper-pool test. The well has been completed as an oil producer in the objective Early Cretaceous Alam El Bueib (AEB) Formation. It was drilled in the northern part of the Meleiha Field, located on the Meleiha PSC in the Shushan Basin. The deviated well was spudded on 19 April 2018 and drilled to a TD of 3,525m (TVD 3,262m) in the Jurassic Masajid Formation. Operations were carried out using the SinoTharwa Drilling #8 rig. Meleiha North Deep 1X is the first exploration well drilled on the concession in 2018. It continues the successful trend of discovering oil in the AEB interval, which lies below the Bahariya Formation, the main-oil pool of the Meleiha Field. The AEB was first tested in 1996, when the Meleiha Deep 1 well was drilled. Equity in the Agiba consortium is split between Eni (38%), Lukoil (12%) and EGPC (50%, carried). ","In Q2 2018, Agiba Petroleum encountered oil in its Meleiha North Deep 1X deeper-pool test. The well has been completed as an oil producer in the objective Early Cretaceous Alam El Bueib (AEB) Formation. "
51505,"PUT-7, Putumayo Basin, same drillpad, all 3 wells commercial oil in multiple zones (U Sand, A-Limestone + N Sand), tested 100-300 boe/d in each zone (Pomorroso 682 bo/d of 35 API oil in Dec â18), w.o. clearance to commingle production from a single wellbore.","PUT-7, Putumayo Basin, same drillpad, all 3 wells commercial oil in multiple zones (U Sand, A-Limestone + N Sand), tested 100-300 boe/d in each zone (Pomorroso 682 bo/d of 35 API oil in Dec â18), w.o. clearance to commingle production from a single wellbore."
50780,"On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the F21-D4 onshore exploration licence in the Thrace Basin on 28 May 2019. The company had submitted the application on 27 July 2018. The licence covers around 7 sq km area in the Istanbul province and it has been granted for eight-year term with an expiry date of 27 May 2027. TPAO is 100% owner and operator of the licence. TPAO had applied for 124 sq km area for the F21-D4 exploration licence.",TPAO has been awarded the F21-D4 onshore exploration licence in the Thrace Basin on 28 May 2019. The company had submitted the application on 27 July 2018. The licence covers around 7 sq km area in the Istanbul province and it has been granted for eight-year term with an expiry date of 27 May 2027. TPAO is 100% owner and operator of the licence. TPAO had applied for 124 sq km area for the F21-D4 exploration licence.
84688,"On 2 July 2020, the Federal Agency for Subsoil Use published a list of exploratory licenses available for investors without auctions. The list includes six blocks in Western Siberia and one block in Yakutia (Sakha) Republic (Eastern Siberia). The offered blocks cover 6,247 sq km with combined hydrocarbon resources estimated at 174 MMbbl of oil and 1.548 Tcf of gas (Table 1). Applications must be submitted by 12 August 2020. If any block receives multiple valid applications, the block will be offered via an auction. Table 1     Resources  Petroleum Province Political Block Surface, Oil, Gas, Contact Information Province sq km MMbbl Bcf Western Siberia Kurgan Obl Pokrovskiy 151 640000, Kurgan, Kuybysheva Str., 12, office 209   Utichyevskiy 300     Khanty-Mansiysk (Yugra AO) Kondinskiy 2 487 36 41 628012, Khanty-Mansiysk, Studencheskaya Str., 2  Kondinskiy 3 493 37 45   Kondinskiy 4 373 19 31    Kondinskiy 5 421 28 31  Eastern Siberia Yakutia (Sakha) Rep Atyyakhskiy 4,022 54 1,400 677018, Yakutsk, Ammosova Str., 18","Russia, On 2 July 2020, the Federal Agency for Subsoil Use published a list of exploratory licenses available for investors without auctions. The list includes six blocks in Western Siberia and one block in Yakutia (Sakha) Republic (Eastern Siberia). The offered blocks cover 6,247 sq km with combined hydrocarbon resources estimated at 174 MMbbl of oil and 1.548 Tcf of gas (Table 1). Applications must be submitted by 12 August 2020. I"
36727,"Parnaiba Gas Natural (PGN) plugged and abandoned dry the 1-PGN-BL103E-MA (1-PGN-028-MA) new-field wildcat (NFW) in the PN-T-103 contract on 16 October 2018. The NFW reached a final total depth (TD) of 2,295 m on 7 October 2018. The operator has not filed and gas show reports for the well with the ANP through early-December 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.",Parnaiba Gas Natural (PGN) plugged and abandoned dry the 1-PGN-BL103E-MA (1-PGN-028-MA) new-field wildcat (NFW) in the PN-T-103 contract
55093,"By July 2019, no definite plan for the Banda gas field development in shallow waters of the Senegal (M S G B C) Basin, central offshore Mauritania, had emerged. The authorities reportedly hired the services of French law firm Gide Loyrette Nouel to promote the project. Eight companies had shown interest to participate in the Banda development but the challenge is to identify enough local electricity demand. The Banda development is currently envisaged as a gas-to-wire scenario feeding a power plant around Nouakchott. On 9 October 2017 it was reported that the Mauritanian authorities had talks with eight companies interested to bid for the Banda gas field development. Mamadou Amadou Kane, responsible for the development of the Banda field at the Ministry of Petroleum, Energy & Mines indicated that he expected four companies to submit firm offers. On 7 April 2017 it was reported that the Mauritanian authorities plan an auction in the second half of 2017 to award the development of the Banda gas field. Price Waterhouse Cooper is reportedly advising the government on the operation. In early 2017 the governments of Mauritania, Mali and Senegal held talks on the Banda Gas to Power project. The three countries want to jointly move this project forward as a public-private partnership. The three countries have committed to signing a power purchase agreement over 20 years for the full output of the planned 300 MW power plant. The power purchase agreement will pave the way for a bid round in which the industry partners for the project will be selected. In July 2015, the Mauritanian government was seeking an advisor to find an upstream partner to develop the Banda gas field. The Banda project came to a standstill when Tullow withdrew in late 2014 due to the fall in the oil price. The Banda field will supply gas to a power plant to be built in two phases: first 180 MW, then 120 MW. The project also entails transmission infrastructure for electricity distribution within Mauritania and exports to Mali and Senegal. Up to 60% of the generated power could be exported. Gas consumption of the power plant is pegged at 60 MMcf/d with the two phases on stream. Based on proved reserves of 590 Bcf, the field should be able to supply the power plant for over 20 years.  Banda is a significant gas discovery with associated oil made in September 2002, located approximately 20km east of the Chinguetti producing oil field. The Banda field lies in water depth ranging in between 200-400m.",Mauritania (Senegal (M.S.G.B.C.) B.) Chinguetti
61954,"CEP is looking to dilute its 100% interest in the 9/2017/L Wolin contract, 590 sq km on/offshore on the Pomeranian High, NW Poland. 2D + 3D seismic have recently been recorded here, the latest (135 sq km of 3D offshore) completed in June. A data room opened this week. Contact ADamte@cepetro.com or PPutnam@cepetro.com.","CEP is looking to dilute its 100% interest in the 9/2017/L Wolin contract, 590 sq km on/offshore on the Pomeranian High, NW Poland. 2D + 3D seismic have recently been recorded here, the latest (135 sq km of 3D offshore) completed in June. "
60084,"Shell has CNH clearance to farmout a 40% stake to Chevron in the CNH-R02-L04-AP-CS-G01/2018, CNH-R02-L04-AP-CS-G02/2018 and CNH-R02-L04-AP-CS-G04/2018 contracts, total 5,962 sq km in the ultra-deep-water Campeche Deep Sea Basin. Shell retains 60% + operatorship. Commitments are to 3 firm + 3 contingent wells.","Shell (->60% op.) farm-out 40% WI to Chevron in the CNH-R02-L04-AP-CS-G01/2018, CNH-R02-L04-AP-CS-G02/2018, CNH-R02-L04-AP-CS-G04/2018 contracts in the ultra-DW part of Basin. "
45414,"GSS Energy could be looking for farm-in partners in the Trembul KSO, located in onshore East Java Basin. The company indicated in its 2018 annual report to be in the final stages of regulatory approvals for gas production from two wells in the block, targeting first gas by the end of 2019. By farming out some interest, the company could gather cash resources towards the commercialization of the wells and for potential new exploration wells to be drilled in the block. The total production rate from the two wells, SGT-1 and Trembul P-1, has been estimated at approximately 3.5 MMcfg/d. The last activity in the block was in August 2018 with the successful re-entry and production testing of Trembul P-1 (originally drilled by Pertamina in 2005). Two gas-bearing sandstones were tested and flowed at an aggregate rate of 2 MMcfg/d. The previous well, SGT-1, was drilled by SGT in 2017 and encountered gas in eight sandstone intervals. SGT-1 was estimated to have a production capacity 1.5 MMcfg/d for 14 years, from two of the discovered gas zones. The Trembul KSO was awarded in October 2016 to PT SGT, with GSS Energy holding 51% and the Central Java government holding 49% in the joint venture. After the initial three-year commitment period, GSS is entitled to increase its effective economic interest to 89%, with the Central Java government retaining 11% interest. GSS Energy is a Singapore-listed company which operates in the precision engineering business. The company has diversified into the oil and gas business in 2014. Background Information GSS Energy had announced the initial award of the Trembul KSO on 5 October 2016. In acceptance of the award, PT SGT made a payment of USD 0.5 million to Pertamina. Following acceptance, the operator commenced discussions with Pertamina towards finalizing the formal joint operations agreement. The Trembul area lies in the Kening Trough, between the Purwodadi High and the East Cepu High. Reservoir potential could be found in the Ledok, Wonocolo, Ngrayong, Tawun and Kujung formations. The Trembul field was discovered in 1913 by Dutch company NKPM. The field started production in 1917, reaching a peak rate from eight wells before being abandoned in 1941, with a cumulative production of 434,000 bo. On 13 December 2017, GSS Energy announced the discovery of oil and gas at the SGT-1 well. The well, drilled to TD at 1,255 m, encountered eight hydrocarbon bearing sandstone intervals with a total net pay of 37 m. Following successful production testing, Pertamina approved commercial production from two gas zones within the lower Ngrayong Formation, at depths of 863-869 m and 910-915 m. A plateau production rate of 1.5 MMcf/d of sweet gas (91% methane, with no H2S and negligible CO2) for 14 years is estimated for the gas zones.","GSS Energy could be looking for farm-in partners in the Trembul KSO, located in onshore East Java Basin."
78524,"In August 2019, Total SA was still waiting for production licences at the Mpyo and Jobi East fields to be issued by the Ministry of Energy and Mineral Development (MEMD). The fields are located in the Exploration Area 1/1A licence which contains the Lyec and Para blocks. Moreover, in April 2020, Total and Tullow signed an agreement in which Tullow will sell its interest in the Lake Albert project to Total. The deal is expected to be completed in 2H 2020 with an effective date of 1 January 2020. The Mpyo and Jobi East discoveries were made in July 2010 and May 2011, respectively. The Mpyo and Jobi East fields hold oil recoverable resources in Upper Pliocene sands estimated at 89 MMbbl and 190 MMbbl, respectively. The most recent seismic acquisition in the area was performed by Total in mid-2014, when a 340 sq km 3D seismic survey was completed over the former EA1 licence and included the Mpyo, Gunya, Ngiri, Jobi-Rii and Jobi-East discoveries. Before Tullow and Total's deal, interest in the Exploration Area 1/1A licence was held by Total E&P Uganda (33.33% + operator), CNOOC Uganda Ltd (33.33%) and Tullow Uganda Ltd (33.33%). Background Information On 30 August 2016, the MEMD granted three petroleum production licences to Total over other oil fields located in the EA1 (Ngiri, Jobi-Rii and Gunya). Jobi-East In May 2011, Jobi East 1 well encountered 20 m of net hydrocarbon bearing reservoir in a fault block adjacent to the Jobi structure and reached a TD of 567 m. Logging and sampling confirmed the presence of oil in two zones of high quality reservoir totalling 15 m of net pay. Gas was also found within sands totalling 5 m of net pay. The first appraisal well, Jobi East 5/5ST, was found to be water bearing in August 2011. The second appraisal well, Jobi East 2/2ST, successfully extended the field five kilometres northward by intersecting a total net hydrocarbon bearing reservoir of 22.5 m in October 2011 and the well was suspended at a TD of 495 m. The well was subsequently tested and reached a maximum flow rate of 40 b/d of oil. Jobi East 6 (TD of 380 m) and Jobi East 7 /7A (TD of 444 m) were spudded between July and August 2013, using the Caroil #2 land rig. The Jobi East 7 /7A well was side-tracked, cored and suspended on 28 August 2013. Jobi East 3/3A was spudded on 3 September 2013, reaching a TD at 254 m in late September 2013. The well was further completed in October 2013 and tests yielded maximum flow rate of around 12.6 b/d of oil. In early November 2013, operator Total completed the appraisal well Jobi East 4 at a TD of 235 m. The well was spudded with the OGEC 600 land rig, immediately after the completion and flow testing at the Jobi East 3/3A appraisal well. Mpyo Tullow discovered oil with the Mpyo 1 in August 2010 (32 m net hydrocarbon bearing sands in two zones). The Mpyo 3 well was drilled in May 2011 (at TD of 584 m) and it waslocatwed1.6km southeast of the Mpyo 1 wildcat in a down-dip location and within an adjacent fault block. Mpyo 3 well found a 21 m net hydrocarbon bearing sands in June 2011 at a depth of 340 m, in line with pre-drilling expectations. Total re-entered the Mpyo 1 (TD of 465 m) in August 2012 and tested it. The Mpyo 3 well yielded a maximum flow rate of 174 b/d of oil. Mpyo 4 was drilled between June and July 2013. Flow tests on that well yielded maximum rates of 210 b/d of oil. The Mpyo 5, 6 and 7 were drilled in between September and November 2013.","Tullow has agreed the sale of its 33.33% interests in the Lake Albert devt project to Total for USD 575 MM cash plus post first oil contingent payments, CNOOC has rights of pre-emption on 50% of the Uganda Interests on the same terms and conditions as Total."
51988,"Local industry sources indicate that operator of the Raseiniai contract in the west-central part of Lithuania, Odin Energi, is farming out a negotiable share in the contract. Interested parties should contact: tom.odinenergi@gmail.com. The 1,520 sq km Raseiniai block is located within the Baltic Syneclise. Background Information The Raseiniai permit was awarded to UAB LL Investicijos for a 10-year term on 6 September 2007. The Raseiniai block is believed to cover a trend of so-far unexplored Silurian reef structures, similar but expected to be of larger size than the Ordovician reefs found on Gotland Island off the coast of Sweden.","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"
22752,"Chevron USA was awarded Walker Ridge blocks WR 242 (G36316) and WR 286 (G36317). 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 WR 242 & WR 286.","Chevron USA was awarded Walker Ridge blocks WR 242 (G36316) and WR 286 (G36317). 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 WR 242 & WR 286."
16497,"Hunt Oil discovered oil and gas with the Ulmu 1 NFW, with testing due to follow as of early March 2018. It was drilled to 3,698m TD in the VIII Urziceni Est exploration concession on the Moesian Platform, SE Romania. It was scheduled to spud during October 2017 with a PTVD of 3,700m MD, to target the Mesozoic and Palaeozoic. Ulmu lies approximately 6km ESE of the Padina Nord 1 gas condensate discovery, drilled to a TD of 2,640m in 2014. The Ulmu 1 location was covered by a 260 sq km 3D seismic survey over the Padina area during early May 2015. In December 2016, the Hunt/OMV Petrom joint venture (JV) commenced experimental oil and gas production from the Padina North 1 discovery at a rate of 1,900 boe/d. VIII Urziceni Est partners are Hunt Oil Company of Romania Srl (50% + Op) and OMV Petrom SA (50%). ","Ulmu 1 op. by Hunt (50%, Petrom 50%) in VIII Urziceni Est (6km ESE of the Padina Nord 1 g&cond disc.), o&g disc."
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 countryâs 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%).
53694,"E. part of 10/2007/p Murowana Goslina-Klecko licence, Mogilno - Lodz Trough in W. Poland, PTD est. 3,500m, completed of late, results unreported but rumours say unspectacular. Background from GEPS.","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."
11934,"Gharb Centre block, Rharb-Prérif, 1st of 2 commitment wells in permit, TD 1,484m, 22.6m net reservoir + 2m net marginal conventional gas pay in the Hoot fm, considered non-commercial and well to be P+Aâd.  Rig then to ONZ-7 devt. Meanwhile a 4-month extension has been granted on the Lalla Mimouna block until 22 Jul â18, allowing time to evaluate the results of its upcoming (March) explo drilling campaign in this block. ","ELQ-1 op. by SDX (75%, ONHYM 25%) in Gharb Centre block, 1st of 2 commitment wells in permit, TD 1,484m, 22.6m net reservoir + 2m net marginal conventional gas pay in the Hoot fm, considered non-commercial and well to be P+Aâd."
61730,"Lingshui low-high in Qiongdongnan Basin, WD 200m, ops terminated results n/a during Oct '19, HYSY 982 SS.","Lingshui 15-2-1 (LS 15-2-1) nfw Lingshui low-high in Qiongdongnan Basin, WD 200m, ops terminated results n/a"
36283,"On 28 November 2018, the Federal Agency for Subsoil Use held an auction for the Obskoy Yuzhnyy block in the Ob Estuary of the Kara Sea (Western Siberia). Competing against Gazprom Neft and Corporation Energy, Gazprom Neft Shelf emerged as the winner of the contest with the offer of RUB 1,018 million (USD 15.2 million). The winner of the auction will obtain a 30-year E&P license which includes a 10-year exploratory stage. Obskoy Yuzhnyy covers 321 sq km in the southern part of the South Kara-Yamal Province. Hydrocarbon resources of the block are estimated at 356 MMbbl of oil, 6.045 Tcf of gas and 123 MMbbl of condensate. The starting price amounted to RUB 152.065 million (USD 2.3 million).","Gazprom Neft Shelf won the Obskoy Yuzhnyy block, 321 sq km in the Ob Estuary."
37627,"DNO has acquired Shell's 30% equity in PL827 S, effective 30 November 2018. PL827 S applies to stratigraphies above the Late Cretaceous Shetland Group and covers 51.6 sq km on block 35/10, located 5km SW of Vega main field and 7km WNW of Vega Sor. The licence was awarded on 5 February 2016 (APA2015) and has a commitment to reprocess and acquire 3D seismic, followed by a drill-or-drop decision in February 2019. No previous wells have been drilled on the acreage. Equinor also operates PL630 BS which applies to the Cretaceous and older on a 13.3 sq km area within PL827 S. On 31 March 2017 Tullow Oil exited PL827 S with its 40% operator stake taken up by Statoil (now Equinor). Revised PL827 S participants are Equinor Energy AS (70% + Op) and DNO Norge AS (30%).","Norway, PL 827 S"
58050,"BHP has sold its interests in the Samurai discovery to an undisclosed private equity firm. The deal involves 100% in GC 388 (lease G35863), 431 (G35866) + 475 (G35870), and 50% in GC 432 (G32504) + 476 (G32510), where Murphy operates (50%).",United States (Sigsbee Sub-basin (DWGoM B.)) Samurai
37937,"In December 2018 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.","In December 2018 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."
63739,"SundaGas and Timor GAP were awarded production sharing contract (PSC) TL-SO-19-16, located in the Bonaparte Basin, on 8 November 2019. The PSC has been awarded for a seven year period and will expire, or be eligible for renewal, in November 2026. SundaGas is making its entry into East Timor with the award of 75% interest in the PSC and operatorship. Timor GAP, East Timor's national petroleum company, has been awarded the remaining 25% as joint venture partner. Under the terms of the award, minimum work commitments have been assigned to the block. These include seismic reprocessing, of 800 sq km 3D and 2,000 km 2D in years 1-3, an exploration well and post well studies in years 4 and 5 and in years 6 and 7, development planning, plus two further wells: either exploration or appraisal. The block contains the Chuditch gas and condensate discovery, which was made in November 1988, with reservoir encountered in the Plover Formation. TL-SO-19-16, which covers an area of around 3,571 sq km, was awarded on 8 November 2019. Participants in the PSC are SundaGas (75% + Operator) and Timor GAP (25%).",ANPM signed the PSC contract for Block TL-SO-19-16 with a JV between privately-owned SundaGas and national oil company Timor Gap.
16228,"In January 2018, Sasol acquired a 40% interest of the Block DE8 from Perenco. Perenco retains the remaining 60%. DE8 exploration permit is located along the coast off Omboue, 90-190km SSE of Port Gentil, in water depths ranging from 0 to 80m. Straddling the limit between the North and South Gabon sub-basins, DE8 surrounds three fields operated by Perenco Oil Gabon Ltd, Tchatamba Marin, Tchatamba West and Tchatamba South. Potential reservoirs in the area are the Albian Upper Madiela unit, which is the main reservoir on the Tchatamba complex, and the Senonian Batanga Formation. Potential source rocks lie in the Turonian Azile and Albian Madiela formations.",Sasol acquired a 40% interest of the Block DE8 from Perenco (->60%).
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%."
37603,"Azimuth Group's subsidiary Azinor received a Letter of Intent (LOI) from an unconfirmed party, which may farm in for non-operated equity in P2165 (Boaz), P2317 (Goose) and P2179 (Hinson), as announced on 10 December 2018. AziNor was farming out part equity in all three licences to participate in a 2019 drilling campaign. AziNor was offering 50-75% from its 100% in P2165 which covers part-block 16/8c and contains the drill ready Boaz prospect, N of the Enoch Field. Boaz has a Triassic Skaggerak Formation (Fm) reservoir, with 37% geological chance of success (CoS) and Pmean prospective resources are 242 mmboe. Azinor was farming down from 80% of its 100% stake in P2317 over part blocks 14/13a, 14b & 15b, 12km N of the producing Claymore Field. It contains the Goose prospect, a stratigraphic trap in Lower Cretaceous Scapa sandstone with Pmean prospective resources of 75 mmboe and 36% CoS. Azinor was farming down from 49% in P2179 - 21/25c which is operated by MOL (51%), and is located S of the Gannet and Guillemot complexes and W of the Annasuria Cluster. It contains the Hinson prospect which is estimated to hold 97 MMbo and 178 Bcfg P50 recoverable resources in Late Jurassic sands within a Kimmeridge Clay stratigraphic trap. Azinor recently had success with the 2018 Agar-Plantain appraisal/discovery with estimated recoverable resources of 15-50 MMboe.","United Kingdom, P2179"
70612,"Add. DEA 8 Nov '19: Block 22/12, Beibu Gulf, location between WZ 6-12N and WZ 6-12S fields in WD ~30m, P&A'd Nov '19 at TMD 2,025m after encountering the target T30 + T32 reservoirs, oil columns identified in the T30A, T31L, T31C + T32L sands, est. 600,000 incremental barrels to the Weizhou field. CNOOC (op), partners Horizon Oil, Fosun + Majuko.","Weizhou 6-12 M1 (WZ 6-12 M1) npw Beibu Gulf, location between WZ 6-12N and WZ 6-12S fields in WD ~30m, P&A'd Nov '19 at TMD 2,025m after encountering the target T30 + T32 reservoirs, oil columns identified in the T30A, T31L, T31C + T32L sands, est. 600,000 incremental barrels to the Weizhou field. CNOOC (op), partners Horizon Oil, Fosun + Majuko."
25618,Repsol has secured 31 of 45 tracts bid for under the North Slope Areawide NS2017W Lease Sale held on 7 Dec â17. The awarded tracts total 179 sq km on trend and east of the Nanushuk oil discovery. Block details from GEPS.,Repsol has secured 31 of 45 tracts bid for under the North Slope Areawide NS2017W Lease Sale held on 7 Dec â17. The awarded tracts total 179 sq km on trend and east of the Nanushuk oil discovery.
56711,"Further to DEA 11 Mar â19, authorities have approved the transfer of all interest in Maromba heavy oil field (BC-020A, SE Campos Basin shelf, WD 160m) from prior operator Petrobras and partner Chevron to BW Offshore. The USD 115 million acquisition price will be paid in three installments as the devt progresses towards first oil.","Authorities have approved the transfer of all interest in Maromba heavy oil field (BC-020A, SE Campos Basin shelf, WD 160m) from prior operator Petrobras and partner Chevron to BW Offshore. The USD 115 million acquisition price will be paid in three installments as the devt progresses towards first oil."
82361,"Egdon Resources announced on 21 January 2020 that it has agreed a deal with Shell for the latter to farm-in to licences P1929 (blocks 41/18a and 41/19a) and P2304 (block 41/24) which contain the Resolution and Endeavour gas discoveries. Under the terms of the deal Shell will acquire a 70% interest and operatorship in the licences in return for funding 85% of the costs for the acquisition and processing of a 3D survey over the discoveries up to USD 5 million. Shell will also pay for all studies and costs included in a well investment decision on the licences. Completion of the deal is subject to regulatory approval. On 8 June 2020 Egdon disclosed that it was granted a licence extension for P1929 and P2304 by the Oil and Gas Authority (OGA) and it had also agreed a revised work obligation and timescale applicable to both licences. In the same announcement, Egdon stated that it will progress with the reassignment of operatorship and interest in the licences to Shell. In April 2019 Egdon announced the results of a Competent Person's Report (CPR) prepared by Schlumberger Oilfield UK Plc which stated that the Resolution gas discovery is estimated to contain Contingent mean Gas Resources of 231 Bcf with a P90 to P10 range of 389 Bcf. Egdon planned to shoot 3D seismic during spring 2020 subject to a successful farm-out. Following this the plan would be to drill and test an appraisal well on Resolution prior to a potential field development. In an update on 27 November 2019 Egdon reported that the OGA approved a six month licence extensions to P1929 and P2304 until 31 May 2020, the second extension in June 2020 extended the licence to 31 May 2024. Within the latter four year extension, Egdon must acquire 400 sq km of 3D seismic in P1929 and P2304 before 21 May 2021 and drill a well down to 1,700 m TVDSS or 75 m below the Base Permian unconformity in one of the licences before 30 November 2022. Resolution is a dip and fault closed structure defined on reprocessed 2D seismic. Resolution will be appraised with an offshore well because the well cost is comparable with an onshore to offshore well and has a lower delivery risk. Egdon will develop Resolution via an offshore well head platform linked via pipeline to an onshore gas processing facility. The main risk is thought to be the ability to produce gas from the relatively tight carbonate. Total drilled well 41/18-2 in block 41/18 in 1966 and made a gas discovery which flowed 2.5 MMcf/d from Permian Hauptdolomit fractured carbonates. Interest in licences P1929 and P2304 following completion of the deal will be held by Shell U.K Ltd (70% + operator) and Egdon Resources UK Ltd (30%).","(Anglo-Dutch B.) Egdon Resources (-> 30%) has agreed a deal with Shell (->70% op), for to farm-in to licences P1929 (blocks 41/18a and 41/19a) and P2304 (block 41/24) which contain the Resolution and Endeavour gas discoveries. Under the terms of the deal Shell will acquire a 70% interest and operatorship in the licences in return for funding 85% of the costs for the acquisition and processing of a 3D survey over the discoveries up to US$5 MM. "
68255,"An auction was held 23 Dec â19 for 25-yr rights to the 2,913-sq km Sylvinskiy block in the Sverdlovsk Oblast, Ural Foredeep. InterGaz won the rights for USD 130,000 ($120,000 starting price).",InterGaz won the sole rights to the Sylvinskiy (2913km)² block in the Sverdlovsk Oblast.
65284,"Premier's 60% farmin to Icewine Area A is now a done deal, made in exchange for paying full costs (up to USD 23 MM) of an appraisal on the 1991 Malguk-1 light oil well (Central North Slope), designated Charlie-1 and due to spuds in Feb â20 (the DNR has just approved the plan of ops). Premier also has the option to obtain 50% in Areas B + C for USD 15 million if Charlie-1 were successful. 88 Energy (op) retains 30%, partnered by Burgundy Xploration.","Premier's 60% farmin to Icewine Area A is now a done deal, made in exchange for paying full costs (up to USD 23 MM) of an appraisal on the 1991 Malguk-1 light oil well (Central North Slope), designated Charlie-1 and due to spuds in Feb â20 (the DNR has just approved the plan of ops). Premier also has the option to obtain 50% in Areas B + C for USD 15 million if Charlie-1 were successful. 88 Energy (op) retains 30%, partnered by Burgundy Xploration."
71340,"On 3 February 2020, PetroRio announced that it signed a definitive agreement to acquire 80% working interest in the Tubarao Martelo production concession from Dommo Energia and would acquire the FPSO OSX-3 for USD 140 million. The goal of the transaction is for PetroRio to jointly operate the easterly adjoining Polvo field and the Tubarao Martelo field as a cluster development thus reducing OPEX costs 50% with the synergies and extending field recoverable reserves life to 2035. The announcement by PetroRio also included an update on three new pool discoveries drilled by the operator in December 2019 that are within 6-7 km of the FPSO OSX-3 in the western area of the Polvo production concession. PetroRio plans to tie-back production from its Polvo A fixed platform in the Polvo field to the FPSO OSX-3 located approximately 9.9 km to the southwest and de-commission the FPSO Polvo by mid-2021 with a Capex estimated to be between USD 50-60 million. The transaction is complex with additional financial commitments by PetroRio besides the USD 140 million for the purchase of the FPSO OSX-3. From the current transaction date to the completion of the tieback operation, PetroRio will have rights to 80% of the production from the Tubarao Martelo Field and be responsible for 100% of the FPSO's charter expenses, the Tubarao Martelo field's Opex, and Capex and abandonment costs. During this phase, through approximately mid-2021, Dommo will reimburse PetroRio a monthly fee of USD 840 thousand equivalent to 20% of Dommo's current Opex, excluding the FPSO charter costs. Once the tieback is complete, PetroRio will be responsible for 100% of all costs for the cluster and Dommo will stop paying the monthly fee with PetroRio to have rights to 95% of the produced oil from the cluster up to 30 MMbo produced after tieback, and 96% thereafter. The 1 January 2019 BAR reserves report had the Polvo field holding original oil in place (OOIP) of 404.84 MMbo and original gas in place (OGIP) of 32.55 Bcfg and with a cumulative production of 44.06 MMbo and 4.36 Bcfg represented a recovery factor to that date of 11% for oil and 13% for the gas. The 1 January 2019 BAR reserves report had the Tubarao Martelo field holding OOIP of 428.49 MMbo and OGIP of 46.96 Bcfg and with a cumulative production of 15.02 MMbo and 1.65 Bcfg represented a recovery factor to that date of 4% for oil and 4% for the gas. Both fields have a low GOR of approximately 100 cu-ft/bo and produce oil of 20° to 21° API. The Polvo field had an average daily production in 2019 of approximately 8,437 bo/d and Tubarao Martelo 5,815 bo/d. Dommo Energia held 100% working interest in the Tubarao Martelo production concession but after formal governmental approvals PetroRio will be the operator with 80% working interest and Dommo will hold 20%. On 3 February 2020, PetroRio also announced that it completed two directional special wells and one horizontal development well in the Polvo production concession and discovered three new oil pools one in the Eocene Embore Formation and two in the early-Cretaceous Quissama Formation. The three wells include the POL-N (9-POL-042D-RJS) and POL-Na (9-POL-043DP-RJS) special wells completed in December 2019 and the POL-Nb (7-POL-44HP-RJS) horizontal development well completed and initially tested in January 2020. On 3 December 2019, Dommo Energia announced that it was nearing conclusion of the revitalization project in its Tubarao Martelo field in the Campos Basin that it originally announced it would undertake in November 2018. On 26 November 2018, the company announced that the revitalization project consisted in the completion of well 7-TBMT-4HP-RJS, that needed to be connected to FPSO OSX 3, and the workover of 4 producing wells (7-TBMT-2HP-RJS, 7-TBMT-6HP-RJS, 7-TBMT-8H-RJS and 9-OGX-44HP-RJS). The company indicated that the revitalization project would increase production in the field to an estimated of 10,000 bo/d by the end of 2019. The estimated cost of the project was USD 80 million. From January to October 2019 the field has produced an average of 5,831 bo/d, 597 Mcfg/d, and 2,345 bw/d. In October 2019, only three wells were producing, the 7-TBMT-6HP-RJS, 7-TBMT-8H-RJS and 9-OGX-44HP-RJS, with the 7-TBMT-2HP-RJS not producing. The Tubarao Martelo field was discovered in December 2010 with well 1-OGX-WAIKIKI-1-RJS (1-OGX-25-RJS). The well was targeting post-salt Eocene sandstones of the Carapebus Formation and post-salt Upper Cretaceous carbonates of the Imbetiba Formation. The carbonate reservoir is the main reservoir of the field. Tubarao Martelo field was appraised between February 2011 and April 2011 by 2 wells (3-OGX-35D-RJS and 3-OGX-41D-RJS). The field was declared commercial in April 2012 by OGX. It was the first commercial declaration of an offshore oil discovery for the company. The Tubarao Martelo field started production in December 2013 through the FPSO OSX-3. As of September 2019, is has produced 17.6 MMbo and 1.8 Bcf of gas. Development drilling started in September 2012 and concluded in February 2013. No improved recovery techniques have been applied in this field. The Polvo production concession covers an area of 134.1 sq km and has been producing since 2007 when it was brought online by former operator Devon. From February 2012 to February 2013 the Polvo Field produced an average of 13,711 bo/d, 20° API, and about 20,000 bw/d. There are about 10 wells producing currently. The Polvo Field reservoirs include the Maastricthian and Turonian turbidites of the Carapebus Formation and the Early Cretaceous Quissama Formation carbonates are also productive. Rumors of BP possibly selling assets surfaced in August 2012. On 6 May 2013, HRT announced that it acquired 60% working interest and operations of the Campos Basin Polvo production concession from BP Energy do Brasil Ltda. The retroactive purchase date is 1 January 2013 for a price of USD 135 million. HRT acquired all associated equipment from a separate BP subsidiary that owns and operates the Polvo A fixed platform and other drilling and production equipment with the exception of the FPSO Polvo that is owned and operated under contract by BW Offshore. The transaction was granted formal approval by the ANP on 18 December 2014.",Petro Rio has signed to acquire an 80% interest from Dommo Energia in the Tubarão Martelo ('Hammer Shark') field in BM-C-039.
80579,"Three new onshore fields were discovered during 2019, 2 oil + 1 gas. Field names or operational details have not been released.","Saudi Arabia, Three new onshore fields were discovered during 2019, 2 oil + 1 gas. Field names or operational details have not been released."
44020,"Petrel has exercised a 2016 option over the shares in Palatine Energy, holder of application EPA-0127, Â 8,700 sq km onshore in the Coolcalalaya sub-basin (Perth Basin).","Petrel has exercised a 2016 option over the shares in Palatine Energy, holder of application EPA-0127, 8,700 sq km onshore in the Coolcalalaya sub-basin (Perth Basin)."
67073,"Effective 26 Nov '19 Wintershall Dea picked-up Gas-Union's 15% in P1239 (blocks 44/23f & 44/18d), P1733 (44/19f), P1902 (44/23c), P1903 (44/24c & 44/23d) + P2115 (44/23g), total 227 sq km. WD now runs the licences with a 64.5% interest, remaining partners Gazprom + XTO (Exxon).","Wintershall has acquired Gas-Union's 15% interest in the following licences - P1239, P1733, P1902, P1903 & P2115."
17384,"The Cook Inlet Areawide 2018W Lease Sale is to be held on 9 May, bids due by the 7th. Â 815 tracts totalling about 17,000 sq km will be on offer on- and offshore. Min bid per acre USD 15.","The Cook Inlet Areawide 2018W Lease Sale is to be held on 9 May, bids due by the 7th. 815 tracts totalling about 17,000 sq km will be on offer on- and offshore. Min bid per acre USD 15."
50051,"Ref. DEA 8 Feb â19, Cluffâs sale of a 70% operating interest in its so far wholly-owned P2252 in the SNS to Shell is now completed. The deal is in return for a full carry on an agreed work programme which includes 400 sq km of 3D seismic by Shearwater over the Pensacola gas prospect. Â P2252 comprises blocks 41/5 41/10 + 42/1. Cluff retains 30%.", Cluffâs sale of a 70% operating interest in its so far wholly-owned P2252 in the SNS to Shell is now completed.
70176,"According to local reports in early-January 2020, state company Petropar has launched a call for bids on its Petropar II, Petropar IV, and Petropar V blocks to look for potential partners to perform exploration work on said areas through a Production Sharing Agreement where the state company will hold an interest between 20% to 40%. It was said that interested companies with at least five years of international E&P experience and certified average production level of 1 Mboe/d over the last three years are expected to submit their qualifications by 6 March 2020, followed by their technical and economic offers which are due by the end of the same month. Minimum commitments reportedly include evaluation of historical technical data of the block, Environmental Impact Assessment (EIA), reprocessing of existing seismic data geophysical data as well as new acquisition of 500 km of 2D seismic during the prospection stage. Meanwhile, additional commitments during the exploration phase include acquisitions of 2D & 3D seismic and other geophysical surveys and studies in the area along with drilling of exploration wells. The winning proposals are scheduled to be announced in the first week of May 2020, followed by official awards by the end of the same month. Petropar II and Petropar IV (also known as La Patria) blocks cover 6,079 sq km and 8,003 sq km of land, respectively, in Chaco Basin (or Curupayty Basin). Meanwhile, Petropar V (also known as Demattei) block covers 7,996 sq km of land in Pirity Basin (or Cretaceous Basin). The area of the blocks included several P&A'd wells, with none of them drilled since the late 1980's. In addition, Petropar reportedly still plans to look for partners on Petropar I (Palo Santo) and Petropar III (Curupaity) blocks as well after the last call for the blocks was declared null and void in 2018. Background Information No commercial hydrocarbon production has been established in Paraguay. Local reports indicate that small volumes of gas have been produced over the years in the Gabino Mendoza block for local consumption. However, the production volumes have never been officially reported.","According to local reports in early-January 2020, state company Petropar has launched a call for bids on its Petropar II, Petropar IV, and Petropar V blocks to look for potential partners to perform exploration work on said areas through a Production Sharing Agreement where the state company will hold an interest between 20% to 40%. "
59749,"1st well in Pribrezhnyy Vostochnyy licence, shallow-water Nabil Bay off Sakhalin, shore-based drilling, spudded May '19, TMD 3,047m (2,500m TVD), 1,450m horiz leg, 70m of oil-saturated intv's identified in the Miocene Dagi fm, cased testing planned. PTD was 3,490m (2,300m TVD, 1,950m horiz leg).","Pribrezhnaya Vostochnaya 1 nfw (Rosneft 100%), 1st well in Pribrezhnyy Vostochnyy licence, shallow-water Nabil Bay off Sakhalin, shore-based drilling, TVD=2500m, 1450m horiz leg, 70m of oil-saturated intv's identified in the Miocene Dagi fm, cased testing planned. "
56027,"On 7 August 2019 South Pacific Resources Ltd (SPR) reported than it plans to exit Papuan New Guinea oil and gas exploration in favour of mineral sand exploration. SPR plans to acquire Takmur Pte Ltd which holds mineral tenement and a production facility in Indonesia. Upon completion of the acquisition, and with shareholder approvals, SPR will sell its Papua New Guinean assets for a ânominal amountâ to Ana and Bella Pty Ltd. An agreement has already been initiated between the two companies. SPR stated that the current oil price and a lack of prospectivity in exploration permits PPL 356, 357, 366 and 367, led to the decision to focus on the Takmur deal. The permits cover a combined area of 5,510 sq km located both onshore and offshore Papuan Basin. It is expected that once the sale of the exploration licences is completed, they could become available for farm-in / purchase depending on their validity at that time. SPR had been looking for a partner since they became eligible in 2012, after being awarded on 30 November 2010. Each licence was scheduled to expire on 30 November 2016 but negotiations have been initiated with the Department of Petroleum to extend the terms. Upon failure to secure extensions, itâs likely that Ana and Bella will become responsible for returning the acreage back to the government. PPL 356 and PPL 357 are located in the offshore Papuan Basin. PPL 356 is located in water depths generally less than 200 m, whereas PPL 357 extends beyond the present-day shelf break into excess of 1,000 m water depth. No wells have been drilled to date in either licence. SPB reports that the area is thought prospective for gas within Tertiary petroleum systems. PPL 356 lies between the liquids rich Pasca and Uramu fields and the dry gas of the Pandora field. Target plays within the permit are likely to be on trend with the buried Miocene carbonate reefs which lay under a regional Pliocene clastic seal. PPL 357 lies to the southeast of the Flinders and Hagana dry gas fields. SPR regional studies suggest that the Pliocene, shallow marine reservoir sands could extend to the PPL 357 block. PPL 366 and PPL 367 lie in the onshore Papuan Basin. Located close the Barikewa gas field and adjacent to the Highlandsâ prolific Toro Sandstone reservoirs, the permits are considered to carry low play risk by SPB for Cretaceous reservoir plays. Trap geometry is expected to be the main geological risk for the identified leads, including the Gamma River lead and Turama lead. SPR had also entered into other exploration programmes in PNG, including the application of five unconventional shale gas applications in the Papuan Basin. Applications (UHPLA 1-5) were submitted to the Department of Petroleum in June 2016 over a total area of 75,000 sq km. The applications came after the finalization of the Unconventional Hydrocarbons Act, 2015, in February 2016. The Act would provide successful applicants with access to both open acreage and areas with existing conventional plays and licences. The application areas by SPR spread over high profile fields including: Pânyang, Hides, Moran, Gobe and Elk-Antelope but the applications lapsed during Q3 2018. For commercial and technical support an agreement with Tamarind Management Sdn Bhd was formed. Under the terms of the co-operation agreement, Tamarind was to assist South Pacific Resources with management and operations to assess and develop the full potential of the licences.  Tamarind was to be assigned 20 million share options in South Pacific Resources as part of the agreement.           Settlement date set for 7 October 2019",On 7 August 2019 South Pacific Resources Ltd (SPR) reported than it plans to exit Papuan New Guinea oil and gas exploration in favour of mineral sand exploration.
51021,"On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the F19-D3 offshore exploration licence in the Marmara Sea in Thrace Basin on 28 May 2019. The company had submitted the application on 27 July 2018. The licence covers around 5 sq km area and it has been granted for an eight-year term with an expiry date of 28 May 2027. TPAO is 100% owner and operator of the licence. The company had submitted the application on 20 July 2018.",TPAO has been awarded the F19-D3 offshore exploration licence in the Marmara Sea in Thrace Basin
47772,"Brisbane Petroleum and partner/shareholder Longreach Oil are looking to farmout PLs 18 (188 sq km) + 280 (91 sq km) on the Saint George Bollon Slope, Bowen-Surat Basin. The companies jointly hold 100% in PL 280 and Brisbane 50% in PL 18 (partner Delbaere Assoc.).","Brisbane Petroleum and partner/shareholder Longreach Oil are looking to farmout PLs 18 (188 sq km) + 280 (91 sq km) on the Saint George Bollon Slope, Bowen-Surat Basin. The companies jointly hold 100% in PL 280 and Brisbane 50% in PL 18 (partner Delbaere Assoc.)."
62042,"Lukoil and Equatorial Guinea's Energy Minister have signed a memorandum of understanding (MoU) for the company to participate in exploration and production in the country. This could expand the Russian major's existing African activities from Cameroon, Congo, Ghana and Nigeria.",Lukoil and Equatorial Guinea's Energy Minister have signed a MoU for the company to participate in E&P in the country.
29336,"Upland Resources Limited announced on 30th November 2017 that it has agreed to farm-in to licence P2235 (block 11/24b) taking a 40% interest from Corallian Energy Limited. The acreage contains the Wick prospect which could hold P50 resources of 250 MMbbl. Environmental permitting is already in process to drill an exploration well on Wick which will likely need a Jack-up rig for the operations. Dry hole costs for the well are in the region of GBP 4.2 million. Upland will likely pay 53.33% of the first GBP 4.2 million of costs related to the environmental survey and the well. The deal completed on 24 May 2018. Wick is located in the Inner Moray Firth approximately 2 km from the Scottish coastline. The acreage has an extensive 3D seismic survey over it. Also, in the acreage is the Lybster discovery from 1996. The field was brought onstream in 2012 via wells which were drilled from onshore to offshore. Wick is thought to have the same petroleum system as Lybster consisting of a Lower to Middle Jurassic Beatrice Formation reservoir. Following completion of the deal interest in P2235 is held by Corallian Energy Limited (60% + operator) and Upland Resources (UK Onshore) Limited (40%).","Upland Resources announced that it has agreed to farm-in to licence P2235 (block 11/24b) taking a 40% interest from Corallian Energy (->40% op, Baron Oil 15%, Corfe 5%)."
8842,"On 6 November 2017, GeoPark announced that its Tigana Norte-3 appraisal well in the Llanos Basin LLA-34 Block produced 970 bo/d of 15deg API oil with less than a 0.25% water cut in the Late Cretaceous Guadalupe Formation and is already on production. The production test was conducted with an electric submersible pump through a choke of 32/64"" and a wellhead pressure of 129 psi. The well, which is assumed to have spudded in September 2017, reached a TD of 3460m and encountered net oil pay in the Guadalupe and Mirador Formations. The well was drilled to a bottom hole location 15m down dip of Tigana Norte-1, which was the lowest known oil and did not encounter the oil-water contact. The appraisal is located 690m to the west of the Tigana Norte-2 development well and potentially extends the Tigana/Jacana complex to the NE. Tigana Norte-3 was drilled outside of the 3P outline in a 2016 independent reserves certification report. Tigana Norte-4 is currently being drilled to further delineate the NE boundary of the field. A production test conducted on Tigana Norte-2 with an electric submersible pump in the Guadalupe Formation, resulted in a production rate of 1,980 bo/d of 14.7 degrees API, with less than 1% water cut and the well is currently producing 2,600 bo/d with les than a 0.5% water cut. The Tigana Norte-1 NFW discovery was drilled in 2014 and lies to the NE of the Tigana, Tigana Sur, Tigana Sur Oeste and Jacana discoveries made in the last four years. GeoPark operates the block with 45% WI and Parex Resources holds the remainder.","Colombia, LLA 34"
53634,"According to BHPâs Operational Review for the year ended 30 June 2019, its Tuk 1 New Field wildcat (NFW), Block 23 (a), was plugged and abandoned (P&A) with hydrocarbons encountered â as previously reported in late May 2019.  This discovery alongside Hit-Hat-1, Block TTDAA-14 and Bele-1 in the Block 23 (a) have âestablished additional volumes around the Bongos discoveryâ - evaluations are ongoing. On 17 April 2019 BHP reported in its Operations Review for the nine months ended 31 March 2019, that it had encountered hydrocarbons in the Bele 1 NFW which drilling was still in progress. The interest holders are the operator BHP with 70% and BP holds the remaining 30%. The well was spudded on 24 April 2019 in 1,954 m water depth using the Transocean Drillship Deepwater Invictus. It reached total depth of 14,799.87 ft (4,511 m). According to local sources, BHP plans two-three wells appraisal program in its deep-water blocks: TTDAA 5, TTDAA 14, and 23 (a). Details have not been released. Preliminary estimates of the combined unrisked gas resource potential of the blocks TTDAA 5, TTDAA 6, TTDAA 28 and TTDAA 29 are in the range of 2.4-23.6 Tcf and the unrisked crude oil resources are in the range of 428-4,200 MMbo. Hi-Hat-1 NFW was spudded on 20 May 2019, in 1,782 m water depth and reach total depth (TD) of 12,480.31 ft (3,804 m). The proposed total depth (PTD) was 3,688 m (12,100 ft) with the main objective in the Pliocene. This is likely to be the appraisal well for Bongos 2 NFW, located in the Trinidad Basin. The well which was plugged and abandoned (P&A), with three gas zones and at least one zone being gas/condensate was spud on 20 July 2018 in 1,910 water depth using the Transocean Drillship, Deepwater Invictus, and it reached total depth (TD) of 5,151 m in October 2018. It replaced Bongos 1 NFW which encountered mechanical problems. The rig was moved to well location on 18 July 2018, and it was expected to stay for approximately 90 days. The operator acquired in 2014 17,700 sq km 3D seismic over seven blocks, included the TTDAA 14. The interest holders are BHP with 70% and the remaining 30% with BP TT. Plans for the well were first reported in late February 2018.  Background Information The operator planned to drill two wells â Bele 1 and Tuk 1. Trinidad and Tobago Marine Advisory Notice announced the arrival of the drillship in late February 2019 for the operatorâs three wells program, including the Hi Hat-1 â likely to be the appraisal well for Bongos 2 NFW, TTDAA 14 Block. BHP drilled two wells in this block Burrokeet 1 and 2 As of mid-January 2017, due to mechanical problems BHP plugged and abandoned (P&A) the Burrokeet 1 NFW. The well was spudded on 5 August 2016, with a proposed total depth (PTD) of 8,534 m (28,000 ft) and it reached 3,337 m (10,948 ft). The main objective was in the Eocene, in a water depth of 1,923 m. BHP P&A its Burrokeet 2 NFW. The well reached a total depth (TD) of 7,347 m (24,105 ft) in mid-December 2016. It was spudded on 18 August 2016, in 1,923 m water depth. As of early May 2018, BHP was still interpreting the acquired 17,700 sq km of 3D seismic shot over seven blocks including the Block 23 (a). The acquisition conducted by PGS began in Mid-March 2014 and it is estimated that it was completed in mid-November 2014. On 17 April 2014, local sources confirmed that BP farmed out a majority interest to BHP Billiton in deep-water blocks TTDAA 14 and 23(a). BP on 25 July 2011 reported that it was awarded two deep-water exploration and production blocks in Trinidad and Tobago, doubling the companyâs acreage holdings in the country. BP was awarded a 100% interest in the blocks 23 (a) and TTDAA 14, both of which are in deep-water frontier acreage of Trinidadâs eastern coast. The contracts were awarded as production sharing contracts. Block 23(a) is located about 300 km NE of BPâs Galeota Point operations base. The block covers 2,600 sq km in water depths averaging 2,000m.","Bele 1, Tuk 1 (hc disc) in Block 23 (a) targeting Pliocene reserves, TD=3982ms and 4511m respectively, WD around 2000m and Hi-Hat 1 (hc disc) was drilled in Block 14, also targeting Pliocene reserves, TD=3804m end WD=1782m. ""These 3 discoveries in our Northern licences have established additional volumes around the Bongos disc. and evaluations are ongoing"" operator said."
38966,"Further to DEA 17 + 19 Jan â18, ExxonMobil has inked a JOA with Ghana Oil Co. for the Deepwater Cape Three Points (DWCTP) PSC in WD 1,550-2,850m. Partnership becomes XOM (op) 80%, GNPC 15%, GOIL 5%. Â The contract for the 1,457-sq km unit still remains subject to govt approval.","ExxonMobil has inked a JOA with Ghana Oil Co. for the Deepwater Cape Three Points (DWCTP) PSC in WD 1,550-2,850m. Partnership becomes XOM (op) 80%, GNPC 15%, GOIL 5%. The contract for the 1,457-sq km unit still remains subject to govt approval."
12369,"Bombay Offshore-1 shallow-water block, believed susp. around 23 Dec â17 at TD 2,525m, Aban Ice DS released 24 Dec. ",SMH-A expl India (Bombay B.) SMH A op. by ONGC (100.0%) in BOFF ML believed susp.
16748,"On 7 March 2018 AustChina Holdings Ltd reported that it has signed an Option Deed for the sale of its 100% owned subsidiary company Surat Gas Pty Ltd. The purchaser, which is undisclosed at this stage of the deal, paid AustChina AUD 10,000 to enter a 21 day window to exercise the option, valued at AUD 6.5 million. The deal will remain subject to the purchaser obtaining finance to complete the purchase and it has 60 days to do so (until 7 May 2018). Surat Gas holds 50% interest in three Adavale-Galilee-Eromanga basin permits: ATP 1072-P, ATP 1095-P and ATP 1098-P. ATP 1072-P covers an area of 6,525 sq km and was awarded on 24 January 2013. It is scheduled to expire, or be eligible for renewal, in early 2019. The block was originally released as PRL 2010-1-3, as part of the 2010 Queensland Acreage Release. ATP 1095-P, which covers an area of 1,620 sq km, was awarded on 1 June 2015 and is scheduled to expire on, or be eligible for renewal by, 31 May 2019. The block was originally offered as PLR2010-2-4 in the 2010 Queensland State Acreage Release. ATP 1098-P covers an area of 5,376 sq km and was awarded on 1 June 2015. It is scheduled to expire on, or be eligible for renewal by, 31 May 2019. Surat Gas applied for the licence on 27 September 2010, after it was offered in the 2010 Queensland State Acreage Release. There are a number of wells within ATP 1072-P and ATP 1098-P, drilled prior to the permits being awarded. However no discoveries have yet been made, with all wells either dry or encountering hydrocarbon shows. Current participants the exploration permits are: Eastern Gas Holdings Pty Ltd (50% + Operator) and Surat Gas Pty Ltd (50%). Once the deal has been completed, the listed participants are not expected to change, but Surat Gas will be held under a new parent company. AustChina will no longer hold interest in any exploration licences as its focus moves towards broadening investment opportunities in the resources and energy sector. Background In 2012 Sierra Oil Ltd acquired Surat Gas from Coalbank before Coalbank took back the company in May 2015. In early 2016 Coalbank reported that it was seeking opportunities with potential partners in ATP 1072-P, ATP 1095-P, and ATP 1098-P to conduct exploration through multi-well drilling programmes and 2D seismic surveys. Renaming of Coalbank to AustChina Holdings took place on 7 August 2017. Following which, AustChina completed a farm-out arrangement by transferring 50% interest and operatorship in the permits to Eastern Gas Holdings Pty Ltd, a wholly owned subsidiary of Ranger Resources Ltd. At the time, Surat Gas reported that Eastern Gas would be required to spend a minimum AUD 30,000 over a three month period in order to earn its interest. The activities undertaken and funded included geological and geophysical data reviews. In addition, Surat Gas were to be carried for a further AUD 650,000 in exploration expenditure. The permit areas remain heavily underexplored.   ","Australia, ATP 1072-P"
26459,"On 25 July 2018 local media reported that Sudan and Russia signed an agreement on gas exploration in the Red Sea. The agreement was signed by Bakhit Ahmad Abdullah, Undersecretary of the Sudanese Ministry of Oil and Gas and Sergey Panov head of the Russian institute Rosgeologia. The Minister of Natural Resources, Dimitri Kolybkin who is heading the Russian delegation in Sudan was present at the signature. He met also the Sudanese President Omar al-Bashir.","On 25 July 2018 local media reported that Sudan and Russia signed an agreement on gas exploration in the Red Sea. The agreement was signed by Bakhit Ahmad Abdullah, Undersecretary of the Sudanese Ministry of Oil and Gas and Sergey Panov head of the Russian institute Rosgeologia. The Minister of Natural Resources, Dimitri Kolybkin who is heading the Russian delegation in Sudan was present at the signature. He met also the Sudanese President Omar al-Bashir."
11339,"Petrelâs Schuepbach subsidiary has entered into a share purchase agreement for the sale of up to a 49.9% of its local arm to Prospex O+G for up to â¬2,053,750. Involved is the Tesorillo project in Andalucia, S. Spain, under suspension since 2013 pending tangible drilling plans. The final closing is subject to, inter alia, the completion of a magnetotelluric programme and the approval of a Tesorillo appraisal (presumably Almarchal-2) for drilling within the 6-year licence term. Both the Tesorillo and adjacent Ruedalabola blocks are involved in the above, total 380 sq km. ","Spain, Ruedalabola"
41453,"After reporting a gas discovery on 1 February 2019 local media announced on 7 February that ExxonMobil E&P Cyprus (Offshore) Ltd found oil in commercially viable quantities in the Glafkos-1 wildcat in the offshore Block 10. We recall that tensions are high between the Cyprus republic and Turkey on the matter of hydrocarbon exploration and that informal public announcements are often used to play with the adverse partyâs nerves. A formal announcement from ExxonMobil is expected around mid-February. The company spudded the well on 9 January using the Stena IceMAX drillship after it completed work on the Delphynus-1 wildcat some 15 km to the south. It was understood that the Glafkos prospect would be an analogue to the Zohr field in Egypt but some reports suggest a deeper target. ExxonMobil contracted the Stena IceMAX drillship for its capacity to drill to depths over 10,000 m and its specialisation in strong pressure variation conditions. Approval of Environment Impact Assessment (EIA) was expected by the end of July 2018. In March 2018 the company had probed the seabed to select drilling sites. Block 10 was formally awarded to ExxonMobil and Qatar Petroleum on 5 April 2017 as a result of the countryâs third offshore licensing round. It covers 2,555 sq km to the southwest of the island against the maritime boundary with Egypt at water depths between 1,670 m and 2,515 m. Contract terms in Cyprus provide for an initial three-year exploration period with two two-year renewals. At least a 25% relinquishment of the original license area is mandatory upon each renewal. In case of a discovery, the operator has the right to be awarded an exploitation concession. An exploitation concession is granted for a period of up to 25 years with an option for one renewal of ten years. ExxonMobil E&P Cyprus (Offshore) Ltd is operator in the Block 10 with a 60% interest and Qatar Petroleum International Upstream OPC is partner with the remaining 40% interest.",After reporting a gas discovery on 1 February 2019 local media announced on 7 February that ExxonMobil E&P Cyprus (Offshore) Ltd found oil in commercially viable quantities in the Glafkos-1 wildcat in the offshore Block 10.
88532,"In July 2020 Tangram Energy was still offering the opportunity for interested parties to farm-in to licence P2421 (block 211/23c) containing the 211/23b-12 (Skye) discovery and Skylark prospects. The opportunity was previously announced in December 2019. The structures are located on the Dunlin and Dunlin SW fault blocks. The Tarbert Sandstone is the primary reservoir discovered in well 211/23b-12 on Skye discovery. The well, drilled by Hess in 1994, proved high quality log and RFT data. From recent analysis, it is thought to contain a hydrocarbon column of 17.2 m and a DST undertaken achieved 4,771 b/d with no water produced. From core analysis undertaken on a core from the Tarbert sands, an average horizontal permeability of 2,020.8 mD with 84.75% of the sand registering above 1,000 mD. Average porosities of 24% were registered and 96.7% of the core porosity was between 21% to 30%. Tangram has conducted seismic interpretation, depth conversion, static modelling and reservoir studies along with petrophysical analysis. Further rock physics work is to be undertaken on the existing reservoir. STOIIP P50 volumes for Skye are 15 MMbo, for Skylark A structure they are 20.4 MMbo and for Skylark B 21.7 MMbo. The development concept for Skye and Skylarks comprises two wells that will target both proven and up-side resources which would be tied back to existing infrastructure of a nearby hub. The acreage is located 8 km from the Causeway and Fionn fields, 11.5 km from Thistle and Deveron and 19 km from the Cormorant North infrastructure. Interest in the licence is held solely by Tangram Energy Limited. For further information, please contact Martin Smith â Technical Director Martin.smith@tangram-energy.com (tel - +44 (0) 2031 676401)",In July 2020 Tangram Energy was still offering the opportunity for interested parties to farm-in to licence P2421 (block 211/23c) containing the 211/23b-12 (Skye) discovery and Skylark prospects.
78046,"Ayzavat prospect in Mubarek investment block, Amu-Darya Basin, strong gas shows while drilling, testing planned and discovery likely to be registered. Likely target Callovian-Oxfordian carbs around 3,400m.","Ayzavat-8 expl, Ayzavat prospect in Mubarek investment block, Amu-Darya Basin, strong gas shows while drilling, testing planned and discovery likely to be registered. Likely target Callovian-Oxfordian carbs around 3,400m."
11204,"Yingzhong 1 structure in the central Yingxiongling structure belt, W. Qaidam Basin, TD 5,450m, tested 70 MMcfg/d of gas (open flow) plus a significant amount of oil, high pressure + high H2S content ","China, not found"
41339,"Committed well in AC/P54, Vulcan sub-basin (Bonaparte), WD 125m, ops terminated this week, w.o. results, GSF Development Driller I SS off location.","Orchid 1 (PTTEP 100%) was plugged and abandoned (results TBC) in the offshore exploration permit AC/P54, results n/a."
26641,"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 âmini-basinsâ. 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."
52375,"S-C part of ES-T-476, onshore Espirito Santo Basin, oil shows report to ANP on 17 Jun â19, suspended late June. PTD was 1,605m, target São Mateus and Mariricu fmâs.","1-SDR-001-ES (1-BGM-001-ES) nfw, S-C part of ES-T-476, onshore, oil shows report to ANP, suspended late June. PTD was 1605m, target São Mateus and Mariricu fmâs. "
30613,"On 17 September 2018, the Joint Venture Pan Andean Resources Ltd, through one of its arm Petrel Resources plc, announced that the outstanding issues with the Ghana National Petroleum Corporation (GNPC) regarding block Tano 2A (still invalid as of today) were understood to be resolved. A further announcement is awaited in due course to inform about the final resolution, and the delineation of the new block, which will mainly lie in shallow waters of Tano Basin with a small deepwater portion, to the north of Tullowâs Jubilee and Eniâs Sankofa fields. The onshore/offshore Tano 2A permit was originally awarded in 2008 to the Pan Andean Resources, owned by Clontarf Energy (60%), Petrel Resources plc (30%) and Abbey Oil & Gas Ltd (which brings the Ghanaian interests in the contract, with 10%). However, it is understood that long lasting negotiations with GNPC resulted in the block suspension around 2014, when operator Erin Energy was awarded a neighbor block (Expanded Shallow Water Tano) that partly overlapped Pan Andeanâs block Tano 2A. In 2015, the Ministry of Energy invited the JV to submit a new application for a shallow to deepwater block.","Ghana, Sankofa"
71058,Mari Petroleum Company Ltd (MPCL) has been awarded the Taung 2567-12 EL (Kirthar Fold Belt) exploration licence with the signing of Petroleum Concession Agreement (PCA) on 31 January 2020. MPCL is the operator of the licence with 60% interest whereas remaining 40% equity is held by Pakistan Oilfields Ltd (POL). The licence covers an area of 151 sq km and it is located in the Jamshoro district of Sindh province. The block was offered under the 2018 onshore bid round and MPCL-POL JV appeared as the successful bidder. MPCL reported on 20 February 2019 that it had been provisionally awarded the Taung 2567-12 EL.,Mari (60% op. POFL 40%) has picked up the Taung block (2567-12) in Jamshoro district in Sindh province.
18863,"VIM 5 block, Lower Magdalena, appraisal to NE part of the Clarinete gasfield, drilled 12-27 Mar â18, TD 2,838m, 27m gas pay in the target Cienaga de Oro sst, 3 separate intvs perforated prior to tying the well into the Jobo gas processing facility. Pioneer 302 rig. To be followed by Breva-1 nfw in VIM 21, target shallow Porquero sst, spudding by monthâs end, then on to .Borojo-1 nfw, Esperanza block, target CDO.","Chirimia 1 op. by Canacol (100%) in VIM-5 block, 27m of net gas pay in the target Ciénega de Oro (CDO) Fm. (24% porosity)."
20049,"On 5 February 2018, the Czech Mining Authority awarded the Bosovice I mining plot in southeastern Czech Republic to domestic operator MND a.s. The contract, official coordinates of which have yet to be disclosed, was granted for the production of oil and gas and is situated within the the contract Svahy Ceského masÃvu (Slopes of Bohemian Massif). The block, covering 0.013 sq km, is situated within the Carpathian Flysch Zone. Background Information The block Svahy Ceskeho masivu (1,640 sq km) was granted to MND on 30 June 2004. The contract terms call for a 15-years exploration period, until 30 June 2019. The Bosovice I mining plot is likely associated with the 1991 Bosovice 1 gas discovery and the wells Bosovice 104/104a and 105 drilled nearby. In a geological sense, the wells falls within the Carpathian Flysch Zone.",Czech Mining Authority awarded the Bosovice I mining plot in southeastern Czech Republic to domestic operator MND
37501,"Spirit Energy has acquired a further 10% in North Sea licences PL167, PL167 B and PL167 C from Equinor, effective 30 November 2018. Spirit Energy acquired its initial 10% in the licences on 31 August 2018. PL167 contains the Verdandi and Lille Prinsen discoveries, with estimated recoverable resources of 4 to 11 MMboe in Palaeocene Heimdal Formation at Verdandi, and 15 to 35 MMboe at Lille Prinsen, likely in Triassic sands. Potential upside has been identified within thin stringer sands of the Eocene Grid Formation in both discoveries. Lille Prinsen is located 2km S of Verdandi on the Utsira High, and the licence is located 4km NE of Ivar Aasen oil field which came online in December 2016, 5km SE from Hanz oil field which is being developed in the second phase of Ivar Aasen, and 8km NW of Johan Sverdrupp which will be brought into production in Q4 2019. PL167 was awarded in March 1991 in the 13th Licensing Round and originally covered 209 sq km on block 16/1, later reduced to 40.96 sq km in March 2000, and then to its current 21.36 sq km in January 2007. PL167 B was awarded on 2003 covers 3.5 sq km of block 25/10, reduced from 37 sq km when it was converted to a production licence in 2006. PL167 C is in its four year initial phase and was awarded on 2 March 2018 in APA 2017 and covers 13 sq km over block 16/1, E of Ivar Aasen. PL167, B & C licensees are Equinor ASA (60% + Op), Lundin Norway AS (20%) and Spirit Energy Norge AS (20%). ","Spirit Energy has acquired a further 10% in North Sea licences PL167, PL167 B and PL167 C from Equinor, effective 30 November 2018. Spirit Energy acquired its initial 10% in the licences on 31 August 2018. PL167 contains the Verdandi and Lille Prinsen discoveries, with estimated recoverable resources of 4 to 11 MMboe in Palaeocene Heimdal Formation at Verdandi, and 15 to 35 MMboe at Lille Prinsen, likely in Triassic sands. C"
10466,"Vietsovpetro (VSP) has concluded operations at appraisal well Thien Nga 3X (12/11-TN 3X) in Block 12/11, offshore Nam Con Son Basin, in late March 2017. Gas was successfully tested with the well flowing more than 35 MMcfg/d from the Oligocene Cau sandstones. It was understood that four highly deviated pilot holes were drilled to a depth ranges of 4,500 m to 5,510 m. The well was spudded on or around 20 August 2016 and was drilled to a TD of 5,510 m using the âMurmanskayaâ J/U. It was intended to test the extent of the Dua and Cau sandstones. The Thien Nga 1X gas and condensate discovery was made in 2001 by Samedan Vietnam under Block 12W. The well flowed 20 MMcfg/d and 150 bc/d from the Upper Oligocene Cau Formation. The discovery was appraised in 2002 with the 12W-TN 2X well which flowed minor gas from the same formation. The last activity in the block was the drilling of 12/11-QF 1X (Quyt 1X). The well, spudded in late October 2015 using the âCuu Longâ J/U did not encounter hydrocarbons in the Lower Miocene to Oligocene Dua and Cau formations. Quyt 1X was plugged and abandoned at a TD of TD 4,360 m in February 2016. A 1,200 sq km 3D seismic survey was completed over the block in Q3 2013, using CGGâs âGeo Coralâ S/V. The Miocene and Oligocene clastics prospects have been mapped within the block. Vietsovpetro is operator of Block 12/11 with a 100% interest. Vietsovpetro is a joint venture between PetroVietnam (51%) and Zarubezhneft (49%). ","Vietnam (Nam Con Son B.) 12/11-QF 1X op. by ZARUBEZ N (60.0%, VIETSOV 0.0%, SOVICO HLD 40.0%) in Block 12/11"
55991,"BT-SOL-004A contract, SOL-T-191 block, onshore Solimões Basin, drilled 14 May â 30 Jun â19, P&A assumed dry as no shows report to ANP, TD 2,090m. Target Jurua + possibly Uere fmâs.","1-RNB-004-AM nfw (Rosneft 100%) in SOL-T-191. onshore block, P&A assumed dry as no shows reports to ANP, TD=2090m. Target Jurua + possibly Uere fmâs."
67302,"GeoPark + Parex have executed an agreement under which GeoPark will assume, subject to ANH approval, a 50% interest in block LLA 94 in exchange for funding its 50% pro-rata share of existing commitments, with no carry. Parex was awarded this block in July under the (1st) Proceso Permanente de Asignación de Ãreas (PPAA) Ciclo 1, 357 sq km on the S. Casanare trend, Llanos Basin. GeoPark otherwise confirms the 2nd PPAA assignments, namely LLA 123 + 124, res. 358 sq km + 112 sq km in the Llanos (DEA 10 Dec '19). Final contracts are expected to be signed in December 2019 or early 2020. Maps and release from GeoPark.",GeoPark takes 50% interest in LLA 94 from Parex (->50% op.).
16874,"HIGHLIGHTS:Strata-X Energy has acquired two new Prospecting Licenses for its Serowe CSG Project covering 406,735 acres. The new licenses offset those already held by the Company in addition to offsetting lands of ASX listed peers. The Serowe CSG Project now spans 680,000 acres in heart of the Botswana CSG fairway, that are 100% owned and operated by the Company.With the goal of developing the CSG resource, the Company has selected a Botswana environmental firm to seek the necessary environment approvals required before the appraisal program can begin. The environmental approvals are expected in the third quarter of 2018. The proposed appraisal programme is designed to prove commercial completion methods and convert resources to reserves. To achieve this, the Company plans to apply the latest completion and production methods to yield commercial gas flow rates. Once that is achieved, the Company can convert resources into reserves.Ron Prefontaine, Chairman of the Board, stated that, 'With the new licenses, Strata-X now has 680,000 acres in its 100% owned Serowe CSG Project, which is located within the Kalahari Basin CSG fairway.The new additions provide our shareholders material upside for our proposed appraisal programmes in Botswana.'The new acreage lies adjacent to a bitumen highway between Serowe, the regional capital, and Orapa, the site of the worldâs largest diamond mine and large potential energy market.Tenement Renweal Terms The new Prospecting Licenses known as PL016-2018 and 017-2018 carry a primary term of 3 years with two, 2- year extensions. To complete the issuance of the PL016-2018 and 017-2018 Prospecting Licenses, Strata-X Australia, owner of the existing Republic of Botswana subsidiaryâs Rhino CBM and Sharpay Enterprises, created a new wholly owned Republic of Botswana subsidiary to hold Licenses called Jab Right Pty Ltd.Original article linkSource: Strata-X","Botswana, Kalahari"
66747,"The authorities have issued a list of 32 E&P and production-only blocks selected for auctioning. Most of the acreage lies onshore, only 2 covering parts of the Aral Sea. No specific timetable has been released. Block details are available here.","Kazakhstan, not found"
59971,"Petrobras is selling its interest and associated production facilities in the wholly-owned, 33-sq km Carapanaúba and 24-sq km Cupiúba leases in the Solimões Basin. EoI's were due 20 Sep '19 and qualification docs are required by 4 October.","Petrobras is selling its interest and associated production facilities in the wholly-owned, 33-sq km Carapanaúba and 24-sq km Cupiúba leases in the Solimões Basin. EoI's were due 20 Sep '19 and qualification docs are required by 4 October."
85278,"The NPD confirmed on 3 July 2020 that Lundin has increased its interest in PL 1057 by 30%. Lundin acquired the equity from Sval Energi and it also took over operatorship, both effective from 30 June 2020. PL 1057 lies on the margin of the More and Voring basins, to the west of Ellida and Midnattsol and northeast of Tulipan. It was awarded under APA 2019 in February 2020 and covers 3,721 sq km over blocks 6302/2, 6302/3, 6303/1, 6303/2, 6303/3, 6402/11, 6402/12, 6403/10, 6403/11 and 6403/12. TGS is carrying out its 'Atlantic Margin 20' 3D multi-client survey in summer 2020 which covers PL 1057 and also extends further to the west. Data over an area totalling 5,600 sq km will be acquired over a three-month period starting in late May 2020 using the ""Polarcus Adira"". PL 1057 contains the 6403/10-1 exploration well drilled by Norsk Hydro in 2002. The well's targets were the Upper Cretaceous Nise and Springar formations where flat spots had been identified. Its location was in a low structural position on the southern part of the Solsikke dome. No sandstone was present in either formation and, whilst the Nise Formation exhibited high porosity in siltstones, permeability was low. The well was abandoned as a dry hole. Interest in PL 1057 is divided between Lundin Energy Norway AS (60% + operator) and Sval Energi AS (40%).","Norway (More B.), PL 1057, Lundin has acquired another 30% from Sval Energi and taken over operatorship of PL 1057, 3,721 sq km over blocks 6302/2 + 3, 6303/1, 2 + 3, 6402/11 + 12, 6403/10, 11 + 12, effective 30 Jun '20. Lundin (op, 60%), partner Sval."
70102,"Thailand Government is planning to officially launch and invite bid proposals for a new Thailand 23st Petroleum Bidding Round, in April 2020. Only offshore blocks located in the Gulf Thailand will be auctioned this round, with details definition still in progress. The Department of Mineral Fuels (DMF) is scheduled to send invitations to potential companies by March 2020 and the blocks will eventually open for bid proposals in April 2020. Applications need to be submitted by September 2020. The stage of screening and selection procedures will be conducted in Q4 2020. Finally, contract signing for the winning bidders is scheduled for January 2021. The onshore acreage offering has been excluded, due to limitations with environmental issues. An amendment to the existing Agricultural Land Reform Act of 1975 is necessary to enable exploration and production activities to be carried out in onshore areas of the country. The DMF would probably re-offer six blocks in the Gulf of Thailand, which was offered during the 21st Petroleum Bidding Round in 2014. The proposed offshore bid blocks are G01/57, G02A/57-G02B/57, G03/57, G04/57, G05A/57-G05B/57 (Gulf of Thailand Basin) and G06/57 in the north Malay Basin. The government considers the new bidding round as a priority to accelerate the discovery and development of new domestic petroleum resources in a country that heavily relies on gas and LNG imports. The government estimates that proven gas reserves in Thailand will be exhausted within six to seven years, if no further exploration is conducted. Background Information Since the 1st Licensing Round was launched in 1971, a total of 847 concessions and 2 PSC blocks were offered to E&P companies in Thailand. The last licensing round, 22nd Bidding Round was officially launched on 24 April 2018, offering two major fields in the Gulf of Thailand. The auction of Erawan and Bongkot blocks was originally planned for November 2014, however it was delayed due to amendment of the Petroleum Act. A revised Petroleum Act was enacted on 23 June 2017, implementing the use of Production Sharing Contracts (PSCs) and service contracts, in addition to royalty/tax concessions. the first official PSCs were awarded on 25 February 2019 to PTTEP and Mubadala Petroleum for G1/61 (Erawan field) and G2/61 (Bongkot field) blocks. The long-delayed 21st Bidding Round, on the other hand, has been officially cancelled in late January 2020, after five years of suspension from the official launching date. Several attempts to relaunch did not proceed as planned due to political instability and economic slowdowns. The bid round was originally planned to begin in 2011, however was suspended in February 2015 (four months after official launch) in response to strong opposition by local activist groups pushing for reforms to the existing petroleum laws.","Thailand Government is planning to officially launch and invite bid proposals for a new Thailand 23st Petroleum Bidding Round, in April 2020. Only offshore blocks located in the Gulf Thailand will be auctioned this round, with details definition still in progress. The Department of Mineral Fuels (DMF) is scheduled to send invitations to potential companies by March 2020 and the blocks will eventually open for bid proposals in April 2020. Applications need to be submitted by September 2020. "
65113,"Corallian Energy Limited is seeking farm-in partners to drill an appraisal well on the 1977 Curlew-A discovery made with well 29/7-1. Corallian is looking to divest up to 60% interest in the licence and in October 2018 announced that it had agreed to farm down 10% interest to Talon Petroleum Limited. The remaining interest is still available. The appraisal well is planned to be drilled in the first half of 2020 with a Jack-up rig in water depths of 93 m. TD is 2,700 m and well costs are in the region of GBP 9.7 million. The company has 3D seismic over the discovery. In November 2019 it was confirmed that the opportunity is still available. The Curlew-A discovery was made by Shell and is a 4-way dip closed oil bearing structure. The discovery well encountered net oil sands (Cromarty and Odin Members of the Sele and Balder Fm) of 10.5 m and recovered multiple oil samples of 36° API. The licence was previously held by Shell until it relinquished the acreage in 2016 prior to Corallian picking up the acreage in the 30th Licensing Round and is currently in its first phase. In October 2018 Schlumberger completed a Competent Personâs Report (CPR) stating that 3C combined Contingent Resources of the Cromarty and Odin reservoirs were 68 MMbo and 79 Bcf (82 MMboe recoverable), 2C Contingent Resources are 39 MMboe. There is updside in a secondary objective of the Forties Sandstone unit which wasnât encountered during the discovery well but may be developed across the south-western flank. Resources of 22 MMbo have been estimated for the Forties sands and 8 MMboe in the chalk. Following completion of the deal in May 2019 with Talon Petroleum, interest in the licence is held by Corallian Energy Limited (90% + operator) and Talon Petroleum Limited (10%). For further information, please contact: Andrew Hindle Commercial Director +44 7775712817 Andrew.hindle@corallian.co.uk",Corallian Energy Limited is seeking farm-in partners to drill an appraisal well on the 1977 Curlew-A discovery made with well 29/7-1. Corallian is looking to divest up to 60% interest in the licence and in October 2018 announced that it had agreed to farm down 10% interest to Talon Petroleum Limited.
80215,"The IHSM-hosted virtual promotional meeting for the 2020 Somali licensing round pre-announcement tool place yesterday, during which it was revealed that the round will run 4 Aug '20 - 12 Mar '21. Fifteen blocks will be offered - 10 in ultra-deepwater of the Somali Basin + 5 in coastal - ultradeep Lamu Basin waters.","The IHSM-hosted virtual promotional meeting for the 2020 Somali licensing round pre-announcement tool place yesterday, during which it was revealed that the round will run 4 Aug '20 - 12 Mar '21. Fifteen blocks will be offered - 10 in ultra-deepwater of the Somali Basin + 5 in coastal - ultradeep Lamu Basin waters."
16707,"Sinopec â Xibei achieved oil flow in Shunbei 7 in Shuntuoguole North block in the Tarim Basin in early March 2018. The well tested 137 b/d of oil from the Ordovician reservoir.  Sinopec spudded Shunbei 7, an ultra-deep exploration well, in the Tarim Basin in April 2017. The well, located in Shunbei 7 fault belt in the Suntuoguole North block, had a PTD of 8,029 m with objective in the Ordovician. Shunbei 7 reached a TD of 7,900 m on 10 November 2017 with only minor shows encountered.  The company decided to sidetrack and the well reached a revised TD of 8,121m (TVD 7,863.7 m) in February 2018. The success of Shunbei 7 indicated further exploration potential in the Shuntuoguole block. Background Information In 2015 Sinopec made a discovery of Shunbei in the Shutuoguole North block when Shun Bei 1 tested 45.4 Mscfg/d from an interval between 7,269 and 7,407 m in the Ordovician. Shunbei field is a marine carbonate field with reservoir buried deeper than 7,300 m. The field could hold geological resources of 8.5 bn bbl of oil and 17.6 Tcf of gas in place. In 2015 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. Following success of Shunbei 1-1H, Sinopec planned six development wells, including Shunbei 1-2H/1-3H/1-4H/1-5H/1-6H, and one exploration well Shunbei 2. By mid-2016, all six wells completed and achieved oil flow with a rate of over 700 b/d of oil/per well. PetroChina reported in 2016 that Shunbei field, a large commercial field, has been confirmed. Sinopec started development of Shunbei 1 in early 2016 and plans 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 2016 Sinopec also drilled another exploration well in the west of Shunbei 1 discovery, Shunbei 5 with a PTD of 7,546 m, in the block and the well tested 1,116 b/d of oil and 268 Mcf/d of gas in late July 2017. In 2017 PetroChina also tested oil and gas in Shunbei 3 in the field. In 2017, Sinopec â Xibei spudded a record ultra-deep exploration in the Tarim Basin. Shunbei 9, located in the Suntuoguole North block, has a PTD of 8,593 m with objective in the Ordovician. In 2018 Sinopec tested oil flow in Shunbei 7, which flowed 137 b/d of oil from the Ordovician Formation. This exploration well is located in in Shunbei 7 fault belt in the Suntuoguole North block. Sinopec set a field development plan on Shunbei 1 area of the Shunbei field in 2017 that is to build up a 20,000 b/d of oil and 26 MMcf/d of gas production capacity by tapping 470 MMbbl of oil in place in this area by 2020. The plan includes to put 40-60 new wells plus 20 existing wells on stream with single well rate about 330 b/d.  ",Sinopec â Xibei achieved oil flow in Shunbei 7 in Shuntuoguole North block in the Tarim Basin in early March 2018. The well tested 137 b/d of oil from the Ordovician reservoir.
14727,Noble has agreed to sell its deepwater US GoM assets to Fieldwood Energy for USD 710 MM. Fieldwood has so far been involved in shallower waters (<400m) areas. Involved are 12 fields (6 producing*) as per the table below: ,Fieldwood Energy has agreed to acquire DW Nobleâs Gulf of Mexico assets for US$710 MM.
48572,"P1830 / blocks 204/4b + 5b, location between Rosebank + Cambo fields in WD 1,115m, targets Colsay / Hildasay fm, thin oil-bearing sst within 34m of intra-volcanic siliciclastic sediments, some gas in the Hildasay, commerciality not established but considered unlikely, Ocean GreatWhite SS then pencilled for the Lyon gas prospect. Siccar Point (op), partners Ineos + Shell.","204/05b-02 (Blackrock) (Siccar Point 52,5% op, Suncor 25%, Shell 22,5%) in P1830 / blocks 204/4b + 5b, location between Rosebank + Cambo fields in WD=1115m, targets Colsay / Hildasay fm, thin oil-bearing sst within 34m of intra-volcanic siliciclastic sediments, some gas in the Hildasay, commerciality not established but considered unlikely."
20582,"The CNH has signed up CNH-RO2-LO3-VC-01/2017 contract, Area 6 block, 193 sq km in the Veracruz Basin, held by Bloque VC 01, S.A.P.I. de C.V., a JV comprising Roma E&P, Tubular Technology, Suministros Marinos e Industriales de Mexico, and Golfo Suplemento Latino. The group was 2nd-place bidder, but wins out after the Shandong consortium failed to pay the USD 2.2 MM tie-break bonus.","Mexico, Area 6"
76859,"Origin has agreed with partner Falcon O&G to increase its interest in their Beetaloo Basin JV* by 7.5% to 77.5% in exchange for increasing its carry of Falconâs share of costs by AUD 25 MM to AUD 59 MM. origin also takes on responsibility for timing control, budgets and any future farm-down options. Ops are currently on hold owing to CV19.","Origin has agreed with partner Falcon O&G (->22,5%) to increase its interest in their Beetaloo Basin JV* by 7.5% to 77.5%."
76373,"Cairn is exercising a 2018 option to acquire a 40% interest from Total in block C-7, 7,291 sq km in the deepwater MSGBC Basin, northern offshore. The deal is subject to govt approval and calls for a well targeting a turbidite fan play. So far Total (op, 90%), partner SMHPM.","Mauritania, C-7"
64196,"Petrobras on 22 August 2019 filed an oil show report with the ANP for appraisal well 3BRSA1368SES on the BM-SEAL-4 Block in the Sergipe-Alagoas Basin. The Petrobras 10000 rig, operated by Transocean, spud the well on 20 June in a water depth of 2,647m. The well has a planned total depth of 5,609m and is in the Moita Bonita area with the Early Cretaceous Muribeca Formation as the projected objective. The well completed operations on 9 October and now is assumed to be suspended as a potential oil producer in the future. Petrobras on 17 April 2019, filed an oil and gas show report with the ANP for the 3BRSA1367SES outpost well on the BM-SEAL-4 Block. It was spud on 13 March also using the Petrobras 10000 rig, in a water depth of 2,625m. The well had a planned total depth of 5,490m and soon after the show report, Petrobras finished the drilling of the well in the Moita Bonita area. Petrobras claimed the drilling of the well confirmed the extent of the gas discovery Petrobras claims with a total thickness of 39m and a reservoir depth of 5,227m. The well also discovered a deeper oil reservoir, with a total thickness of 24m. It was the fifth appraisal well extension well in the Moita Bonita area, whose discovery 1BRSA1088SES was reported in August 2012. The BM-SEAL-4 Block is currently in its third period which calls for the drilling of three wells. The Discovery Assessment Plan (PAD) for 1BRSA1088SES expires in December 2020. The 3BRSA1367SES is located about 5.3km north-west of the discovery well and should be the final required well for the PAD. The drilling of the 3BRSA1367SES represented the resumption of the exploratory activities in the Sergipe-Alagoas Basin which had seen no drilling in three years. The Early Cretaceous Muribeca Formation was believed to be the objective. Block BM-SEAL-4 was acquired in ANP Round 2 by Petrobras which has a 75% stake while partner ONGC has the remaining 25%. On 20 July 2018, Petrobras disclosed the start of its binding offer phase farm-in divestment process on four deepwater blocks in the Sergipe-Alagoas Basin including BM-SEAL-4. Petrobras is offering 35% of the block. It is also offering 30% of the SEAL-M-499 Block where it also holds 100%. Petrobras is expected to issue a declaration of commerciality for its PADs in the offshore Sergipe Alagoas Basin in 2020 and probably relinquish the remaining exploration areas on expiry in the deepwater basin. On 18 February 2016, the ANP board of directors reviewed the Discovery Assessment Plans (PADs) currently in progress in the deepwater Sergipe-Alagoas Basin and decided based on proposal 1151 of December 2015, to grant a postponement of two years for the remaining required activities in six PADs in the basin. The PADs included 1BRSA851SES (SEAL-M-426), 1BRSA1022SES (BM-SEAL-4), 1BRSA1083SES (SEAL-M-426), 1BRSA1088SES (SEAL-M-499), 1BRSA1104SES (SEAL-M-349) and 1BRSA1108SES (SEAL-M-424). Exceptions to the postponement were drilling the next well planned on the PAD for 1BRSA1088SES and the acquisition of 3D seismic data for the PADs of 1BRSA1104SES and 1BRSA1088SES. The final deadline for the six PAD's was reset to 1 December 2020. ",3BRSA1368SES Petrobras on the BM-SEAL-4 Block in the Sergipe-Alagoas Basin oil show report with the ANP
61157,"Mari and partner PPL secured the Ghauri D&PL around the 2014 Ghauri oil discovery retro-effective 1 Jan '16. It lies over 17.5 sq km excised from the Ghauri 3273-3 EL in the Potwar Basin, Punjab.","MPCL (Mari Petroleum 65% op, PPL 35%) has been awarded the Ghauri D&PL."
11369,"P2062, West of Shetlands, WD 250m, 168-day HPHT well to PTVD 5,791m, target Solan & Otterbank sst, ops terminated and West Phoenix SS next retained for 6604/5-1 (BalderbrÃ¥) in Wintershallâs PL 894, Norwegian Sea. Nexen (op), partners BP + Siccar Point.",United Kingdom (West Shetland B.) ? op. by PREMIER (100.0%) in Solan block
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."
69503,"By H2 2019, the Siwa Petroleum Company (Siwa Petco) had been awarded a development lease (DL) across the Siwa X 1X discovery. The DL has been carved out of the Siwa PSC, located in the under-explored southern part of the Faghur Basin. Siwa X 1X was spudded in December 2018 and is understood to have tested at 5,200 bo/d from the Carboniferous Desouqy Formation, after reaching 4,698m TD (4,724m PTD) in the same interval. Operations were carried out using the Egyptian Drilling Company #54 rig. The well was drilled just ~2.3km NW from Eni's July 2018 South West Meleiha B 1X oil discovery in the same formation, on the adjacent South West Meleiha concession. Equity in the Siwa Petco consortium is split between Apache (16.7%), Sinopec (8.3%), Tharwa (25%) and EGPC (50%, carried).","By H2 2019, the Siwa Petroleum Company (Siwa Petco) had been awarded a development lease (DL) across the Siwa X 1X discovery."
50117,"Vanam ML, KG shallow waters, south of 2015 YS-6 2 (junked), WD ca. 24m, TMD 5,324m, gas discovery, tested 17.476 MMcf/d, ops continue, Aban II JU. Targets assumed Raghavapuram Shale, Gollapalli + Ravva fmâs.","YS-6 2 in Yanam ML block, WD ca. 24m, TMD=5324m, gas discovery, tested 17,476 MMcf/d, ops continue, Targets assumed Raghavapuram Shale, Gollapalli + Ravva fmâs."
28994,"ATP 1189-P, Cooper-Eromanga Basin, drilled and P&A oil shows between 26 Aug - 1 Sep â18, TD 1,586m. Santos (op), partner Delhi Petr.","Agentsmith 1 (Santos Ltd 70% Op, Beach Energy 30%) in ATP 1189-P. P&A, oil shows."
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."
78425,"In early 2020, the Ethiopian Ministry of Mines, Petroleum & Natural Gas offered 22 open blocks in the country (see attached map): Ethiopia blocks on offer Block Name Block Sqkm Main Political Province Basin Names Gambela 157075.86 Binshangul Gumuz Amhara Massif~Abbay (Blue Nile) Basin North West 82516.38 Amara Mekele Basin~Amhara Massif~Northeast African Fold Belt Afar Area 62997.88 Afar Afar Basin~Red Sea Basin~Mekele Basin~Ogaden Sub-basin (Somali Basin)~Northeast African Fold Belt Rift Valley Block 43054.83 Ye Debub Biheroch Afar Basin~Amhara Massif Omo 30598.73 Ye Debub Biheroch Amhara Massif~South Omo Graben (EARS, East Branch)~Chew Bahir Graben (EARS, East Branch) Metema 29827.79 Binshangul Gumuz Mekele Basin~Northeast African Fold Belt~Amhara Massif Afar 24589.42 Afar Afar Basin~Mekele Basin~Red Sea Basin~Northeast African Fold Belt Block 05 18299.34 Oromiya Ogaden Sub-basin (Somali Basin) Block 07 12254.06 Sumale Ogaden Sub-basin (Somali Basin)~Mandera-Lugh Sub-basin (Somali Basin) Block 02 12232.2 Oromiya Ogaden Sub-basin (Somali Basin)~Mandera-Lugh Sub-basin (Somali Basin) Block 06 12232.2 Oromiya Ogaden Sub-basin (Somali Basin) Block 18 12232.19 Sumale Ogaden Sub-basin (Somali Basin) Block 01 12206.7 Oromiya Ogaden Sub-basin (Somali Basin) Block AB8 12135.44 Amara Abbay (Blue Nile) Basin~Amhara Massif Block AB9 12128.45 Amara Abbay (Blue Nile) Basin~Amhara Massif Block AB5 12108.5 Amara Amhara Massif~Abbay (Blue Nile) Basin Block AB6 12108.5 Amara Amhara Massif~Abbay (Blue Nile) Basin Block AB3 12068.51 Amara Amhara Massif Block AB2 12068.5 Amara Amhara Massif Block 19 6467.74 Sumale Ogaden Sub-basin (Somali Basin) Block 21 6094.66 Sumale Mudugh Sub-basin (Somali Basin) ~Ogaden Sub-basin (Somali Basin) Area 4 3679.4 Ye Debub Biheroch Amhara Massif~East African Rift System, Eastern Branch Source: IHS Markit 2020 © 2019 IHS Markit  Another five blocks were under discussions in Ethiopia in late 2019. The Government confirmed in late year that a Production Sharing Agreement (PSA) concerning one or more of these blocks was pending to be approved. These blocks could be Block 10 and Block 14 to be awarded to the British Delonex. Blocks Under Discussion in Ethiopia (late 2019) Basin Name Block Name Block Sqkm Existing drilling Existing discoveries Existing Exploratory Surveys Political Province Amhara Massif Block AB1 9,900 no no no Amara Amhara Massif Block AB4 9,900 no no 2011 (seismic) Amara Amhara Massif Block AB7 9,900 no no no Amara Ogaden Sub-basin (Somali Basin) Block 10 - possibly DELONEX 12,207 no no 1989 (2D) Sumale Ogaden Sub-basin (Somali Basin) Block 14 - possibly DELONEX 12,207 no no 1962 (2D), 1963 (Gravity/Magnetic). 1992 (2D) Sumale Source: IHS Markit, 2020        Until the update of the existing Petroleum law is approved by the Government, contracts are awarded in the form of Model PSA of 1994 between the government of Ethiopia, represented by the Minister of Mines and Energy, and a contractor. Contracts have an initial exploration term of four years and an optional two-year term, with two possible further exploration periods of two years (4+2+2). The development and production period is of 25 years. Minimum exploration and expenditure obligations are negotiable as well as signature and production bonuses. The income tax is 30% but will be reduced to 25% according to the petroleum draft being prepared by the Ministry. For further details, interested companies are invited to contact: Mr. Ketsela Tadesse Director â Petroleum Licencing & Administrative Dictatorate Ministry of Mines, Petroleum & Natural Gas P.O.Box 751 Addis Ababa, Ethiopia Phone: + 251 11 646 12 09 Fax: + 251 11 646 34 39 Ktadesse22@gmail.com","In early 2020, the Ethiopian Ministry of Mines, Petroleum & Natural Gas offered 22 open blocks in the country"
28631,"UK-listed Coro Energy plc announced on 3 September 2018 an agreement to acquire a 42.5% interest in the Bulu PSC, located on offshore East Java Basin, from AWE (now a subsidiary of Mitsui). The block contains the Lengo gas field, which has an approved Plan of Development (POD) in place and is pending Gas Sales Agreement (GSA). The deal overrides a previous agreement between AWE and HyOil, which did not come to completion and has been terminated. Coro will work with AWE and HyOil towards a tripartite deal, which will include a total consideration payable by Coro of USD 10.96 million plus cost reimbursements, broken down as follows: USD 2 million to HyOil in new ordinary Coro shares upon closing of the transaction. An additional USD 1 million to HyOil in new ordinary Coro shares upon signing of the first GSA. A further USD 1 million to HyOil in new ordinary Coro shares after approximately six months from commercial production startup. USD 6.96 million in cash to AWE, plus back costs and other working capital adjustments amounting to an estimated USD 1.04 million. Upon closing of the deal, Coro will hold a direct 42.5% participating interest in the PSC. Partners in the PSC will remain KrisEnergy (42.5%, operator) and local companies PT Satria Energindo (10%) and PT Satria Wijaya Kusuma (5%). KrisEnergy is continuing to offer its stakes in the block for sale. The transaction is subject to various conditions including joint venture partner pre-emption rights and regulatory approvals. The original agreement between AWE and HyOil for the Bulu PSC was announced in May 2016, however it did not come to completion, pending final approvals. This acquisition marks the first entry of Coro Energy in South East Asia upstream business. The company intends to further expand its portfolio in the region, and will continue to evaluate entry opportunities targeting growth assets with a focus on Indonesia, Malaysia and Vietnam. Coro is currently generating cash flow from production assets in onshore Italy. The Plan of Development for the Lengo field was officially approved in 2014 and FEED works were carried out in 2015. GSA negotiations are ongoing. According to Coro, an MOU for gas sales was signed in January 2018 for potential supply to the Tuban industrial complex in East Java. The field is estimated to contain 2C resources of 359 Bcf of dry gas. Background Information Indonesian company PT Petroland Energi, through its subsidiary Sebana Ltd, was awarded the Bulu PSC on 14 October 2003, under the ""Third Round"" of Migas acreage releases which closed on 31 July 2003. Signature bonuses totaled USD 3 million and the PSC carried a work commitment amounting to USD 6.9 million in the first three years. Sebana Ltd was partnered by Gwinet Ltd (10%), owned by PT Satria Energindo, the largest shareholder in PT Petroland Energi. The Lengo 1 well was spudded on 8 March 2008 and was plugged and abandoned at a TD of 986 m on 7 April 2008. The well flowed 12.8 MMscf/d with gas (having less than 15% CO2) present over a 42 m interval in both the Upper Oligocene/Lower Miocene Kujung I carbonate unit and Middle Miocene Ngrayong sandstones. The Lengo East 1 wildcat was plugged and abandoned in mid-June 2010 with the well encountering gas. The well, located 20 km east of the Lengo 1 discovery in the adjacent Bulu PSC, was spudded on 28 May 2010 using Transocean's ""Trident IX"" J/U rig and was drilled to a TD of 872 m, shallower than the PTD of approximately 1,000 m. It targeted the Oligocene to Lower Miocene Kujung carbonates and the Middle Miocene Ngrayong sandstones. Partner AWE Limited elected not to participate in this drilling campaign and then-operator Pearl drilled this as a âsole riskâ well. KrisEnergy announced the completion of the Lengo 2 appraisal well on 17 May 2013, with the well drilled to TD at 838 m. Two DSTs have been conducted over the main Kujung I carbonate reservoir. The first DST, between 736 m and 757m, flowed 4.8 MMscf/d of gas with a flowing wellhead pressure of 587 psig. The second DST, between 736 and 784 m, flowed 21 MMscf/d of gas with a flowing wellhead pressure of 487 psig, with the flow rate constrained by surface equipment. Approximately 42 m of core have also been collected from the reservoir interval. According to the operator, the good test results showed that the Kujung I reservoir is better developed in Lengo 2 than in discovery well Lengo 1.","Coro Energy (formerly Saffron Energy in Italy) has signed conditional agreements for its 1st Indonesian asset, a 42.5% stake from AWE in the 698-sq km Bulu PSC for US%11 MM."
81512,"Re. DEA 28 May '20 (updated website): State ANPG* announces the availability of data packages for exploration blocks to be offered in the onshore Lower Congo (CON1, CON5 + CON6) and Kwanza (KON5, KON6, KON8, KON9, KON17 + KON20) basins. Parties interested in consulting this data as well as participating in a data show room are invited to contact ANPG via licensing_round2020@anpg.co.ao. ANPG also advises that the 2020 bidding process will be modified on account of CV19, although the objectives will not change in relation to the previously announced bidding schedules. Relevant updates will be made through the website. All proposed blocks had been offered in the cancelled 2014/2015 onshore round despite 40 companies submitting bids (mostly local and with little or no o&g experience). *ANPG â Agência Nacional de Petróleo, Gás e BiocombustÃveis.","State ANPG* announces the availability of data packages for exploration blocks to be offered in the onshore Lower Congo (CON1, CON5 + CON6) and Kwanza (KON5, KON6, KON8, KON9, KON17 + KON20) basins."
29308,"OMV and Malaysian Sapura Energy have entered into a Heads of Agreement to form a strategic partnership. The plan is for OMV to acquire a 50% interest in Sapura Energyâs subsidiary Sapura Upstream, and help develop the Austrian companyâs growth prospects in South East Asia.","OMV and Malaysian Sapura Energy have entered into a Heads of Agreement to form a strategic partnership. The plan is for OMV to acquire a 50% interest in Sapura Energyâs subsidiary Sapura Upstream, and help develop the Austrian companyâs growth prospects in South East Asia."
30466,"Walker Ridge block 595, OCS lease G36088, WD 2,952m, cleared to P&A by the BOEM 21 Sep â18, results n/a, Deepwater Pontus DS. Â PTD was perhaps ca. 8,000m (Wilcox pay in adjacent Stones field). Â Stones has been producing since Sep â16, the worldâs deepest offshore o&g project.","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, PTD was perhaps ca. 8,000m (Wilcox pay in adjacent Stones field)."
14319,"AC/P63, 585 sq km in the offshore Vulcan Sub-basin, awarded on 8 Feb â18 for 6 years. More from GEPS.","Carnarvon Petr. (100%) was awarded exploration permit AC/P63 (585km²), located in the Vulcan Sub-basin."
27064,"NT/P82, 6,332 sq km in Bonaparte Basin off N. Territory, Santos has taken over Magellan Petroleumâs interest effective 7 Aug â18, now holds 100%.",Santos completed acquisition of 100% interest of exploration permit NT/P82 from Magellan Petroleum
23715,"The latest on Madagascarâs long-awaited licensing round is for a Nov â18 opening. Parliament is yet to approve the new petroleum legislation, although the new round may still use the current petroleum code if need be. The offer could include the Morondava Basin, Cap d'Ambre and Sainte Marie Island areas. Meanwhile OMNIS remains available for direct negotiation outside a tendering process for open onshore blocks and offshore blocks outside the 40-44 units to be proposed in the coming round.","The latest on Madagascarâs long-awaited licensing round is for a Nov â18 opening. Parliament is yet to approve the new petroleum legislation, although the new round may still use the current petroleum code if need be. "
51900,"Alpha Petroleum Resources is reportedly up for sale according to press. The company runs the Cheviot field (100% in part-blocks 2/10b, 2/15a + 3/11b east of Shetlands). The offer is Alpha/Cheviot on the basis of the sanction-ready devt plan, value ab. USD 650 MM, or a 70% carried stake. Meanwhile an agreement with Teekay to provide the Petrojarl Varg FPSO on Cheviot for 7 years has been terminated on financial issues. First oil had been planned 2Q â21.","Alpha Petroleum Resources is reportedly up for sale according to press. The company runs the Cheviot field (100% in part-blocks 2/10b, 2/15a + 3/11b east of Shetlands). The offer is Alpha/Cheviot on the basis of the sanction-ready devt plan, value ab. USD 650 MM, or a 70% carried stake."
86153,"CFD 7-5-1 completed on 21 July 2020 without result reported. CNOOC â Tianjin spudded a new-field wildcat CFD 7-5-1 in Bohai offshore, Bohai Gulf Basin on 5 July 2020. The well is located in Boxi Block in the western part of the Bohai Gulf, in a water depth of approximately 20 m. The well is targeting the Mio-Oligocene clastic play. âBohai 5â J/U is used for the drilling operation. There have been several wells drilled in this area before 2010, such as CFD 7-1/2/3 and CFD 8-1/2, all wells are dry. However no well drilled in this area for the last ten years. There is a small field found in this area. CFD 1-6, with reservoir in pre-Tertiary fractured granite basement. But the field was shut down after less than one year production in 1995, because it failed to yield sustainable production due to the limitations of the fracture reservoir system. In greater CFD area, there is CFD oil fields complex, which is comprised of CFD11-1, 11-2, 11-3/5, 11-6/12-1 and 12-1S fields. The main oil accumulation of the CFD fields cluster is in the Neogene Lower Minghuazhen and Guantao formations from top to bottom. The oil is moderately heavy to medium oil type. The traps are draping anticlines developed on basement highs. Bohai offshore is the important production base for CNOOC. After nearly 40 years exploration and production the company has found more than 70 fields with approved about 4 bn tons of oil in place by 2019.","(Bohai Gulf b.), Caofeidian 7-5-1 new-field wildcat was completed without result reported. The well is located in Boxi Block operated by CNOOC LTD (100%) in the western part of the Bohai Gulf, in a water depth of approximately 20 m. The well is targeting the Mio-Oligocene clastic play."
62872,"On 4 November 2019, Kosmos Energy announced that it had drilled a dry hole at its Moneypenny prospect located in Mississippi Canyon block 214 (G24059) in the northeast quadrant of the Mississippi Canyon (MC) protraction area in the deepwater Central Gulf of Mexico. Well MC 214 2S0B1 (API 608174138001) is located in 5,778 ft (1,761 m) of water about 132 mi (212 km) east of the onshore support base at Port Fourchon, Louisiana. Well MC 214 2S0B1 was originally drilled in 2018 as a development well in the Miocene-aged Odd Job field, operated by Kosmos and located in MC 214 and MC 215. The Moneypenny prospect was a deeper pool test and drilled in October 2019 as an exploration tail to the development well, which will now be completed. Kosmos used the Valaris 8503 drillship for the exploratory portion of the well. Kosmos operates the lease with 61.05702% working interest. The remaining working interest owners are Ridgewood (19.47149%) and ILX (19.47149%). MC 214 was acquired by operator Spinnaker (50%) and Dominion (50%) at Sale 182 in March 2002 for a bonus bid of USD 3,575,555. The partnership beat out a competing bid of USD 218,925 from Conoco. Norsk Hydro acquired Spinnaker in 2005, and then merged with Statoil in 2007. Also in 2007, Eni acquired this and other Gulf of Mexico assets from Dominion. Deep Gulf Energy acquired Statoil's interest in 2011. Calypso then joined the partnership in 2013. Eni sold its interest to Deep Gulf in 2014. Ridgewood and ILX joined the partnership in 2015. Calypso withdrew in 2018, resulting in the current working interest ownership. Background Information Eni drilled the Odd Job discovery well MC 214 1S0B0 (API 608174125900) in 2013. Deep Gulf Energy drilled the MC 215 1S0B1 (API 608174129101) in 2015, confirming that the field extends into MC 215. Odd Job came online in 2016 and has produced over 9.9 MMbo and 6.4 Bcfg through the end of June 2019. It is tied back to the Murphy-operated Delta House floating production system in MC 254 about 12 mi (20 km) to the west.","MC 214 002S0B1 (Monneypenny) (Kosmos 61,06% op, Ridgewood 19,47%, ILX 19,47%) in G24059 lease Odd Job field area P&A dry, w.o details"
35011,"On 15 November 2018 it was announced that Azinor Catalyst has been successful with operations on its Plantain prospect and appraisal of its Agar discovery. Following two re-spuds of initial wellbore 9/14a-17 (A & B), the well 9/14a-17B targeting Plantain, was drilled to a depth of 2,254 m where it encountered the prospect at 2,066 m. A total of 27 m of high quality net reservoir sandstones in the Eocene Lower Frigg Formation were encountered and through logging-while-drilling and pressure analysis indicated a thin net oil pay zone with a significant underlying zone of residual hydrocarbons. Based on this result the sidetrack was kicked-off. Well 9/14a-17Z encountered the Upper Frigg Formation at 1,763 m and penetrated a gross reservoir of 20 m with a high net to gross ratio confirmed by log and pressure analysis and an average porosity of 30%. No Oil-Water contact was encountered. The sidetrack reached a depth of 1,962 m. It is thought recoverable resources from Agar are estimated at 15 to 50 MMboe. In terms of development the Beryl Bravo facilities are located 12 km to the north east of Agar-Plantain and the Alvheim FPSO is located approximately 14 km to the south east. The well will now be plugged and abandoned. On 24 August 2018 Azinor Catalyst spudded an exploration / appraisal well, 9/14a-17, targeting the Plantain prospect located down-dip of the Agar discovery. On 4 September 2018 it was confirmed that the well had been re-spudded as 9/14a-17A. Then, on 23 September 2018, a second re-spud occurred as 9/14a-17B. On 31 October 2018 operations on well 9/14a-17B were completed and the company kicked-off sidetrack 9/14a-17Z. The company is used the Transocean âLeaderâ (S/S) for the well. The Agar discovery was made in 2014 with well 9/14a-15A which encountered a 33 ft oil column 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 were water bearing. The appraisal well is planned to delineate the down-dip element of the Agar discovery with the sidetrack aiming to test the Plantain prospect. Agar is thought to hold commercial 2C volumes of 15 MMboe and Plantain could hold up to 45 MMboe (Pmean) and 98 MMboe (P10). If the operations are successful then development options could be tie backs to Beryl Bravo, Alvheim FPSO or a standalone FPSO. On 14 August 2018 it was announced that Faroe Petroleum has farmed into the licence taking a 12.5% interest from AziNor. Following completion of a deal interest in P1763 will be held by Apache Beryl Limited (50% + operator), Cairn subsidiary, Nautical Petroleum Limited (25%), AziNor Catalyst Limited (12.5%) and Faroe Petroleum (12.5%).","009/14a-17B (Plantain/Agar) (Apache 50% op, Nautical 25%, Faroe 12,5%, Azinor 12,5%) in P1763 block, encountered roughly 27m of high quality net reservoir sst. of the Eocene Lower Frigg Fm. at a depth of 2066m. TD=2540m"
65735,"S-C part of Marlim Leste prod. lease, Campos Basin, WD 2,024m, oil shows report to ANP 22 Nov '19. PTD 3,878m, target Carapebus fm, Ocean Courage SS.",Oil shows: 4-MLL-084-RJS (4-BRSA-1372-RJS) npw
13398,"Bozhong 36-1-6 (BZ 36-1-6) was suspended (results TBC) in early January 2018 after having been spudded on or around 26 October 2017 using the ""Haiyangshiyou 923"" jack-up. The oil and gas exploration/appraisal well was likely targeting the Guantao, Dongying and Shahejie formations. Bozhong 36-1-6 is in the CNOOC operated Bonan Block in the offshore Bohai Gulf Basin and is approximately 5.5km SW of successful oil well Bozhong 36-1-2d, drilled by CNOOC in March 2017. ",Bozhong 36-1-6 (BZ 36-1-6)in the CNOOC operated Bonan Block was suspended (results TBC)
13244,"Chupalskiy licence, W. Kaymys-Vasyugan Province in Khanty-Mansiyskiy AO, W. Siberia, drilled MayJul â17, TD 3,145m, Â 2 new pools in the Tyumen Achimov, tested 201 bo/d from below 2,992 in the former, and 99 bo/d from below 2,803m in the latter. Â ",Russia (West Siberian B.) Kuzovatkinskaya 72 op. by ROSNEFT (100.0%) in Chupalskiy block
69771,"On 24 December 2019, the award of the Saouaf permit to Upland (Saouaf) Ltd became effective with the publication of the award in the government gazette (Journal Officiel de la République Tunisienne). On 28 June 2019 the formal signing of the Saouaf permit contract took place in Tunis. Signatories were Upland (Saouaf) Ltd, the Ministry of Industry and Small & Medium Enterprises and state oil company ETAP. Participants in the block are Upland, operator with 50% and ETAP, carried through exploration, with 50%. The first exploration period has a duration of two years and carries a one well commitment. According to Upland Resources, the Saouaf block has a good gas potential. An independent report by Blackwatch Petroleum lists 11 prospects and 1 discovery with a total mean recoverable resource of 1,961 Bcf of gas. In April 2019, Upland Resources had already received farm-in offers for the acreage by interested parties. Now that the Saouaf contract is signed, Upland can actively look for a partner. In August 2018, Upland Resources announced that it had been awarded the 4,004 sq km Saouaf Permit. The permit covers acreage atop the North-South Axis, Central Atlas Graben Zone, Kasserine Island and East Tunisian Platform (Pelagian Basin). It was mentioned that should a new discovery be made, the state oil company ETAP (as joint venture partner) would have a right to âback-inâ for a minority stake by paying its share of past costs and funding its share of future costs. Upland proposed a work programme that includes an initial 2D seismic survey, followed by the drilling one or more new wells, drilling is conditional on the results of the seismic survey. To date only five wells are known to have been drilled within the area covered by the permit, all of which were drilled in the 1950s. Two of the wells Dekrila 1 and Edjehaf 1 were plugged and abandoned with gas shows and oil shows respectively. Uplands mentioned that a gas discovery had been made within the permit, it is speculated that the Company is referring to the Dekrila 1 well. The well was drilled within the North South Axis by Cie des Petroles de Tunisie between 1954 and 1955 to a TD of 2,139 m (within the Lower Cretaceous).","Tunesia Panoceanic Energy was awarded Kef Abbed, Metline and Tiskraya prospecting permits and Saouaf permit to Upland (Saouaf). "
19478,"KrisEnergy, operator of Block A, located in the Khmer Trough, offshore Cambodia, continued to offer a farm-in opportunity in the block, up to 47.5%. The company is seeking suitable partners with financial and technical capabilities to participate in the development of the block (Apsara field), following a series of agreements signed with Cambodian government on 23 August 2017. The company intends to retain operatorship, given its expertise in developing small to mid-sized oil fields in the Gulf of Thailand. KrisEnergy is planning to acquire a 1,200 sq km 3D seismic survey in the block in 2018. The survey will assess the Apsara field area for optimal development planning, and will support the identification of additional prospects in the block. On 20 October 2017, the company announced that it will proceed with the Final Investment Decision (FID) for the fieldâs first phase development. The company was granted approval by the Cambodia authority for its development plan on 23 August 2017, and was expected to declare the FID for the project within 60 days from approval. First oil is targeted 24 months after the FID, in late 2019. KrisEnergy is the operator of the block with 95% interest. The remaining 5% interest has been formally transferred to the Cambodian government, via the General Department of State Property and Non Tax of the Ministry of Economy and Finance. The Apsara field complex will be the first petroleum development in the country. The structure is estimated to hold recoverable 2P reserves of approximately 55 MMbo from the initial stages of development (Phase 1a and Phase 1b). The development concept involves one wellhead platform producing into an FSO for Phase 1a, and three more platforms for Phase 1b. The block contains several other fault blocks which could be developed progressively through multiple phases, depending on commercial success of the initial stage and successful future exploration. The latest drilling activity in the block was conducted in 2010 by previous operator Chevron with three successful appraisal wells, namely Pimean Akas 3, Pimean Akas 5 and Pimean Akas 6. The wells encountered oil pay in multiple reservoir zones. For further information, interested parties may contact: James Parkin VP Exploration james.parkin@krisenergy.com or Mike Whibley VP Technical mike.whibley@krisenergy.com Background Information Block A was officially awarded in 2002 to Chevron (70%, operator) and MOECO (30%). The contract block covers an area of 3,083 sq km over the Khmer Basin in the Gulf of Thailand, where water depths range from 50-80 meters. In 2010, Singapore-based KrisEnergy Ltd, an independent oil and gas company acquired a 23.75% participating interest in block A from Chevron. On 11 August 2014, KrisEnergy acquired an additional 30%, plus operatorship, from Chevron. The transaction was valued at USD 65 million and subject to working capital adjustment. In November 2011, the former Cambodian petroleum regulator, Cambodian National Petroleum Authority (CNPA), notified the Block A joint venture of its intention to exercise its right to assume a 5% participating interest in the block. A production permit application (PPA) for the Apsara discovery was submitted in 2010 and updated in 2012 by Chevron. An updated PPA was submitted by the new operator KrisEnergy in November 2014. As of December 2016, the PAA was still under review by Cambodian Ministry of Mines and Energy (MME). Likewise, negotiations between KrisEnergy and the MME were ongoing regarding the 5% interest transfer and the renegotiation of fiscal terms for the Block A contract. Phase one of the Apsara project involves up to 20 development wells from single platform with oil will be processed and stored in a FPSO prior to commercial sales. This concept is similar to other fields in the Gulf of Thailand. Peak production from the field is expected to be at 10,000 barrels oil per day. First oil production is expected 24 months after the FID. KrisEnergy was previously holding a 52.25% operating interest in the block, with partners MOECO (28.5%) and GS Energy 14.25%. Both partners withdrew from the block in October 2016, leaving KrisEnergy as sole rightholder (pending the 5% transfer to Cambodian government).","KrisEnergy, operator of Block A, located in the Khmer Trough, offshore Cambodia, continued to offer a farm-in opportunity in the block, up to 47.5%."
14331,"POT-T-619 block, onshore Potiguar Basin, PTD 620m, suspended with results unreported on 4 Feb â18 after a week of operations, target Cretaceous Alagamar fm, EBS-05 rig.","1-619AB-1-RN (1GPK3RN) in POT-T-619 block, onshore Potiguar Basin, PTD 620m, suspended with results unreported on 4 Feb â18 after a week of operations, target Cretaceous Alagamar fm,"
75602,"ADX Energy Ltd (ADX) disclosed in its recently published operational update that it is expecting to receive award of the exploration permit(s) in central Austria, the area known as the Upper Austria, likely around mid-2020. As it is understood, the company, assisted by RAG Exploration & Production GmbH (REP), member of RAG Austria AG, lodged the application(s) for the permits in November 2019. The area of interest is located is located within the Molasse Basin and was partly overlapping the Alpine domain. To run its operations, ADX created a fully owned UK-based holding company, Terra Energy Limited, with Austria subsidiary ADX VIE GmbH to manage domestic assets. Background Information ADX disclosed on 2 July 2019 it had entered into binding agreements with REP to acquire the Zisterdorf and Gaiselberg oil and gas fields in eastern Austria. In addition, ADX purchased from RAG Austria the geological and 2D/3D seismic data for yet to be licensed exploration areas in central Austria (Upper Austria) covered by the seismic, falling partly within the Upper Austria permit. The transaction, with an effective date as of 1 January 2019, was closed on 30 November 2019. The Upper Austria contract, operated by REP, covers 5,587 sq km extending from the city of Steyer in the east to the city of Burghausen on the border with Germany in the west. Originally awarded in 1981 (area 4,549 sq km), the block, solely operated by RAG, undergone several renewals since: effective 1 January 2015, RAG changed the area of the block, relinquishing the northwestern part of it, at the same time enlarging the tract in the eastern and southeastern direction (over the Northern Calcareous Alps). RAG Austria holds the exploration and production rights until 2022. In regards of the areas in central Austria, a data user agreement has been effectuated to access REPâs information over some 3,650 sq km of the area. It is understood that as part of their transaction, RAG and ADX have undertaken a revision of the prospectivity of the Upper Austria block and new application(s) are being submitted to the authorities within the area covered by RAG-ADX data user agreement The portfolio of future drilling locations consists of 19 ready-to-drill prospects, eight out of which have already approved rig site locations. The latest activity in the area dates ack to May 2019, when RAG commenced drilling wildcat Höcken 1 (result unreported).","ADX Energy Ltd (ADX) disclosed in its recently published operational update that it is expecting to receive award of the exploration permit(s) in central Austria, the area known as the Upper Austria, likely around mid-2020. "
20452,"Senex Energy Ltd, through wholly owned subsidiary Stuart Petroleum, was awarded production licence PL 1022, located in the Bowen-Surat Basin, on 26 April 2018. The licence has been granted for a period of 30 years and will expire, or be eligible for renewal, in April 2043. The licence has been awarded as part of Senexâs Western Surat Gas Project, over the Glenora and Eos project areas. During 2017, 30 appraisal and development wells were drilled at this part of the project. Senex reported that it expects two further production licences to be granted in the near future as part of the project, in the western section. PL 1022 was applied for in December 2016. Senex reports that the awarding of the licence is another milestone in the development of the Western Surat Gas Project. PL 1022, which covers an area of 230 sq km, was awarded on 26 April 2018. Stuart Petroleum Cooper Basin Gas Pty Ltd holds 100% interest and operatorship of the licence.","Australia, PL(A) 1022"
16813,"On 1 January 2018, Bayerisches Staatsministerium für Wirtschaft, Infrastruktur, Verkehr und Technologie granted the Velden-Teising exploration contract in southern Germany (Bavaria) to domestic operator Genexco GmbH. The contract, valid until 31 December 2020, has been secured to explore the remaining hydrocarbon potential of the Upper Cretaceous-lowermost Tertiary sandstone series. The Velden-Teising permit is located some 60 km east-northeast of the city of Munich, just north of the Salzach Inn contract of RAG. In a geological sense, the tract is located in the Alpine Foreland. The tract is covering the Velden and Teising oil, gas and condensate fields. Background Information The area of Teising was covered from 1 June 2010 to early 2015 by the company Nasser Berg Energie GmbH, involved in the geothermal energy and gas storage business. In 2015, Nasser Berg Energie divested the tract to Genexco GmbH (effective 31 May 2015). In 2017, Genexco applied for an enlargement of the Teising area, to include also the nearby Velden field. The operational concept in the tract foresees the reestablishment of the production from previously exploited Lower Tertiary sandstones, as well as exploration of the oil leg tested previously in the Turonian-age clastics. The company is offering a farm-in opportunity in the tract.","Germany, Teising"
78954,"Corallian Energy announced on 29 April 2020 that it has signed a Work Sharing and Confidentiality Agreement with a large European E&P company for licence P2478 (blocks 17/5, 18/1 and 18/2) which houses the Dunrobin prospect in the Inner Moray Firth. The licence was being farmed out, but this has now been put on hold until 30 September 2020 whilst the interested party undertakes its own regional technical work. The exclusivity period could be extended to 31 December 2020 if the agreement proceeds to a farm-out of interest in the licence. The Dunrobin prospect has a Beatrice Formation and Dunrobin Bay Group sandstone target. The prospect consists of three large shallow Jurassic rotated fault blocks that are mostly mapped on 3D seismic data with a single culmination with DHI. Dunrobin covers an area of 40 sq km with a Pmean prospective resources of 174 MMboe. Interest in P2478 is held by Corallian Energy Limited (45% + operator), Upland Resources (UK Onshore) Limited (40%) and Baron Oil Plc (15%).",United Kingdom (Inner Moray Firth B. (Moray Firth Province)) Beatrice
68277,"On 17 December 2019, the Federal Agency for Subsoil Use held an auction for three blocks in Yamalo-Nenets Autonomous Okrug (Western Siberia). Rosneft and Gazprom Neft emerged as the winners of the auction. The companies will obtain 25-year E&P licenses with a seven-year exploratory stage. The Kharampurskiy Zapadnyy block covers 898 sq km in the Nadym-Taz Province and encompasses the Kharampurskoye Zapadnoye oil discovery with 3P reserves estimated at 31 MMbbl and seven prospects with combined resources estimated at 43 MMbbl of oil and 82 Bcf of gas. Seismic coverage amounts to 1,300 km. Six wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 100 MMbbl of oil, 3.743 Tcf of gas and 69 MMbbl of condensate. The starting price amounted to RUB 402.826 million (USD 6.5 million). Rosneft, competing against its subsidiary, won the auction with the starting price. The Mitikyakhskiy 1 block covers 1,188 sq km in the Nadym-Taz Province and encompasses several prospects with combined resources estimated at 139 MMbbl of oil, 2.776 Tcf of gas and 93 MMbbl of condensate. Seismic coverage amounts to 2,069 km. Two wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 485 MMbbl of oil, 325 Bcf of gas and 10 MMbbl of condensate. The starting price amounted to RUB 539.81 million (USD 8.7 million). Rosneft, competing against Gazprom Neft, won the auction with the starting price. The Yamburgskiy Severnyy block covers 2,101 sq km in the Nadym-Taz Province and encompasses a part of the Mitiyakhskaya prospect with resources estimated at 11 MMbbl of oil, 206 Bcf of gas and 7 MMbbl of condensate. Seismic coverage amounts to 2,994 km of 2D data and 151 sq km of 3D data. One well has been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 750 MMbbl of oil, 22.461 Tcf of gas and 370 MMbbl of condensate. The starting price amounted to RUB 353.833 million (USD 5.7million). Gazprom Neft, competing against Rosneft, won the auction with the starting price.","Rosneft won Kharampurskiy Zapadnyy (898km²) in the Nadym-Taz Province and Mitikyakhskiy 1, (1188km²) in the same area."
37908,"Lundin spudded an exploration well on the Silfari prospect in PL 830 on 18 October 2018 using the âLeiv Eirikssonâ S/S. The well was a play-opener with targets in the Permian and Jurassic. It had the potential to contain 193 MMboe. 6307/1-1 S is located in the southern part of the Froan Basin to the southeast of Fenja. The Froan Basin is a new core area for Lundin and it maps a number of prospects and leads across PL 830 and neighbouring PL 934. 6307/1-1 S reached TD at 4,114 m (3,796 m TVD) in rocks of unknown age and is a dry hole. Reservoir rocks were not encountered in the Permian and water-wet sands were encountered in a 60 m section of the Tofte Formation. Reservoir quality was good and on 20 December 2018 Lundin was abandoning the well. Â Fenja, operated by Neptune, consists of the Pil and Bue accumulations which were discovered in 2014. Neptune will develop Pil initially, using a subsea tieback to the Njord A platform. Recoverable reserves are approximately 100 MMboe. The development will use two subsea templates hosting three horizontal producers, two water injectors and a single gas injector. Bue represents upside and will be confirmed by Pil development wells before it is potentially brought into production at a later date. Oil will be processed on Njord A before being transferred to Njord B for onward export via shuttle tanker. Gas will initially be re-injected into the Pil reservoir and will later be exported via Njordâs connection to the Asgard Transport System. According to the impact assessment from June 2017, oil production is expected to peak at approximately 42,000 bo/d in 2023 with gas production expected to peak at approximately 100 MMcf/d between 2025 and 2036. Total investment costs are approximately NOK 10.2 billion (USD 1.22 billion), with first oil scheduled for 2021 and a 16 year life forecast. PL 830 is operated by Lundin Norway AS which holds a 40% interest. Lundin is partnered by Petoro AS (20%), Equinor Energy AS (20%) and Neptune E&P Norge AS (20%).",Norway (Donna and Halten Terraces (Voring B.)) Fenja
11461,"On 14 December 2017, the Lebanese Petroleum Administration (LPA) announced that the Council of Ministers has approved the awards of two exclusive petroleum licences for the exploration and production in Blocks 4 and 9 to a consortium comprised of Eni, Total and Novatek. The move follows an announcement by the LPA in October, which stated that the three-company consortium was the sole bidder in the country's extended first offshore licensing round. The country restarted its first offshore licensing round in January 2017, following the approval of two crucial decrees related to block delineation, tender protocol and Model Exploration & Production Agreements (EPA). The acreage offered included Blocks 1, 4, 8, 9 and 10, with the latter three partly covering an area that is claimed by Isarel. The 46 companies that were shortlisted in a first prequalification round in 2013 remained eligible to bid. In the 2013 prequalification round, twelve companies pre-qualified to bid as operators and 34 companies pre-qualified to bid as non-operators. In a second prequalification round, which was conducted between 2 February 2017 and 31 March 2017, eight further companies were shortlisted. The bid round had been beset by delays for several years, due to the failure to obtain Cabinet approval, and the lack of the necessary ratification of two decrees. It was officially launched by the Ministry of Energy & Water (MEW) on 2 May 2013. The bid round had originally been scheduled to close on 4 November 2013, but was extended on several occasions.",Not Found
16252,"CPO-9, E. Llanos Basin in Meta, 60m heavy oil column below 2,500m, 8 API oil. Ecopetrol (op), partner Repsol.","Lorito 1 op. by Ecopetrol (55%, Repsol 45%) in CPO-9 block heavy oil disc. 60m heavy oil column below 2500m, 8°API oil in Tertiary sands."
77278,"PEP 60093, offshore Taranaki Basin, WD 131m, TD 4,317m, several hydrocarbon-charged layers encountered while drilling, well now assumed P&A but considered a discovery, COSL Prospector SS. Target North Cape fm + Paleogene sst. A planned 4th well in the current campaign (Maui-8) has been deferred on account of CV19. OMV (op), partners Mitsui + SapuraOMV. Map below at the time of Sapura's farmin to OMV's PEP acreage in 2018:","NToutouwai 1 nfw. (OMV % op, Mitsui E&P, Sapura Energy ) in PEP 60093, offshore block, several hydrocarbon-charged layers encountered while drilling, well now assumed P&A but considered a discovery, Target North Cape fm + Paleogene sst. WD=131m, TD=4317m."
13290,"China has sold exploration rights for three oil and gas exploration blocks in the remote northwest Xinjiang region for more than 2.7 billion yuan ($422 million), the Xinhua news agency reported on Wednesday. It said that Shenergy Co, Xinjiang Energy (Group) Co and Zhongman Petroleum and Natural Gas Group Corp (ZPEC) secured the rights after a bidding competition that attracted seven companies. Lack of private investment in oil and gas exploration has been a big stumbling block in Beijingâs attempts to reform the sector, and it has picked the hydrocarbon-rich autonomous region of Xinjiang to try to break the grip of big state-owned companies. The three blocks in the regionâs Tarim basin were among five that the government put up for auction in December, totaling 9,091 sq kms (3,510 sq miles). Original article link Source: Reuters ","China, not found"
78419,"The Chadian Ministry of Petroleum and Energy is promoting the countryâs open acreage which is available to companies for direct negotiations. As of December 2019, the free blocks were: CHAD Open Acreage Basin Names Block Name Block Sqkm Main Political Province Borkou-Ennedi Sub-basin (Al Kufra Basin)~Djado Basin~Tibesti Massif~Chad Basin Djado Block II 13,848 Tibesti Borkou-Ennedi Sub-basin (Al Kufra Basin)~Faya Sub-basin (Chad Basin) Largeau Block I 11,706 Borkou Chad Basin Moussoro Block 11,927 Kanem Chad Basin Lac Chad Block 11,900 Kanem Chad Basin Lac Chad Block I 3,783 Kanem Chad Basin~Bodele Sub-basin (Chad Basin) Siltou Block II 17,800 Borkou Chad Basin~Bodele Sub-basin (Chad Basin) Siltou Block I 11,803 Tibesti Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Manga Block 16,759 Tibesti Chad Basin~Bornu Trough - Chad Basin~Termit Trough - Chad Basin LC-2008 10,988 Hadjer-Lamis Chad Basin~Darfur - Ouaddai Massifs~Bongor Trough MD-2008 11,725 Ville de Ndjamena Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block IV 17,709 Borkou Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block VII 11,815 Batha Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block III 10,623 Borkou Darfur - Ouaddai Massifs~Doba Trough~Bongor Trough Chari-Ouest Block III 4,681 Tandjile Darfur - Ouaddai Massifs~Doseo Trough~Doba Trough~Salamat Basin BDS-2008 41,887 Mayo-Kebbi Est Djado Basin~Tibesti Massif Djado Block I 21,569 Tibesti Doba Trough~Darfur - Ouaddai Massifs WD 1-2008 2,029 Mayo-Kebbi Ouest Faya Sub-basin (Chad Basin)~Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Largeau Block VI 11,770 Ennedi-Ouest Faya Sub-basin (Chad Basin)~Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Largeau Block II 11,739 Borkou Source: IHS Markit © 2019 IHS Markit  The latest version of the Hydrocarbon Law in Chad was translated into English in August 2008. On 27 August 2007, Chad's Prime Minister M. Nouradine Delwa Kassiré Comakye announced that the country had promulgated legal texts and implemented mechanisms relating to the specific management of its oil incomes in order to adhere to the Extractive Industries Transparency Initiative (EITI). The Government solemnly declared that the principles of this initiative from that moment on would be applied to Chad and the incomes drawn from the extractive industries would be declared and used in total transparency. The Al Kufra Basin is better known as Erdis Basin in Chad. The south extension in Niger and Chad of the Murzuq Basin is called Djado Basin (or Jadu Basin) and has seen no hydrocarbon exploration in the past. The Faya-Largeau area is poorly explored, with only a few low-quality seismic lines acquired in the 1980s. The Lake Chad area was one of the first regions to be explored in Chad, but unlike the Doba Trough, it has not been intensively explored. Three discoveries have been made: Kanem-1 in 1974, Sedigi in 1975 and Kumia-1 in 1976.",The Chadian Ministry of Petroleum and Energy is promoting the countryâs open acreage which is available to companies for direct negotiations.
76196,"The DGH has reportedly decided to merge the OALP VI (ending 31 Mar '20) & VII (ending 31 Jul '20) rounds as a result of the uncertainties due to the COVID-19 pandemic. EoIâs received between Dec '19 and Jul '20 will be joined and acreage offered as a merged round. Ref. DEA 26 Mar '20, it is recalled the DGH was also considering extending the deadline for OALP V bid submissions (opened 14 Jan '20), last set for 16 Apr '20. Also in light of the above, a new deadline has yet to be settled upon. 11 blocks are on offer in OALP V, total 19,800 sq km in 8 basins. http://www.dghindia.gov.in, bids via the e-portal.","The DGH has reportedly decided to merge the OALP VI (ending 31 Mar '20) & VII (ending 31 Jul '20) rounds as a result of the uncertainties due to the COVID-19 pandemic. EoIâs received between Dec '19 and Jul '20 will be joined and acreage offered as a merged round. Ref. DEA 26 Mar '20, it is recalled the DGH was also considering extending the deadline for OALP V bid submissions (opened 14 Jan '20), last set for 16 Apr '20. "
15243," PETRONAS to farm-in to Gambian Blocks A2/A5 for drilling of offshore exploration well FAR retains 40% equity in Blocks A2/A5 and Operatorship The joint venture is targeting to drill the Samo-1 well in late 2018 PETRONAS to fund 80% of well costs up to a US$45M cap and pay other consideration to FAR of US$8.6M The Samo Prospect assessed by FAR to contain prospective resources of 825mmbbls oil  FAR has signed a Farm-out Agreement ('FOA') with a subsidiary of Petroliam Nasional Berhad ('PETRONAS') to assign a 40% interest in each of the highly prospective offshore petroleum licences, Blocks A2 and A5 in The Gambia. FAR is to retain a 40% interest in each of the licences. PETRONAS will fund 80% of total well costs of the Samo-1 exploration well up to a maximum total cost of US$45.0 million. Based on a completion date of 31 March 2018, FAR is to be paid estimated cash of US$13.5 million for reimbursement of back costs and cash consideration. In addition to this, PETRONAS will fund FARâs share of non-well costs up to a maximum amount of US$1.5 million. FAR will remain Operator through the exploration phase of the A2/A5 licences, including the drilling of the Samo-1 well, and PETRONAS has a right to become the Operator for development. The Samo-1 well is expected to be drilled in late 2018 and will be the first exploration well offshore The Gambia since 1979. FAR estimates the Samo Prospect contains prospective resources of 825mmbbls oil (best estimate, 100%, unrisked - refer ASX announcement of 21 Nov 2017). Completion of the FOA is subject to Ministerial approval from the Government of The Republic of the Gambia and customary joint venture consents. FAR Managing Director, Cath Norman, said: 'This farm-out deal with PETRONAS is further recognition of the value of our Gambian licences and FARâs status as a partner of choice in the Mauritania-Senegal-Guinea-Bissau-Conakry Basin. FAR has built an enviable position in the basin and we look forward to drilling the Samo-1 well later this year. Success in this well would be of significant value to our shareholders and truly transformational for the people of The Gambia.  PETRONAS brings world class technical and financial strength to our joint venture. PETRONAS also has significant deep-water development expertise in the event of a discovery. FAR welcomes PETRONAS to the Joint Venture and looks forward to a long and successful relationship. We again wish to acknowledge the cooperation and support of the Gambia Ministry of Petroleum and Energy, the Gambia National Petroleum Company (GNPC), the Government of the Gambia and our broader Gambian stakeholders as we jointly progress with our drilling preparations. This deal is further demonstration of The Gambiaâs credentials as an investment destination.'  Farm-out terms FAR Gambia Ltd, a wholly owned subsidiary of FAR Ltd, has entered in to a Farm-out Agreement with PC Gambia Limited, a wholly owned subsidiary of PETRONAS, to assign a 40% interest in its offshore Blocks A2 and A5 Petroleum Licences in The Gambia. FAR is to retain a 40% interest in the blocks. PETRONAS will fund 80% of total well costs of the Samo-1 exploration well up to a maximum total cost of US$45.0 million (including a portion of well back costs to be paid on completion). Based on a completion date of 31 March 2018, estimated total well back costs to be refunded by PETRONAS are US$6.4 million. Also, on completion, PETRONAS will pay FAR cash consideration of US$6.0 million and reimburse non-well back costs estimated at US$1.1 million. In addition to this, PETRONAS will fund FARâs share of non-well costs up to a maximum amount of US$1.5 million. Based on FARâs latest Samo-1 well cost estimates, the agreed well cost cap is expected to be in excess of FARâs share of well costs. Pursuant to the FOA, if FARâs share of well costs is less than the agreed cap, then at least 50% of the balance is to be paid in cash to FAR. FAR will remain Operator through the exploration phase of the A2/A5 licences, including the drilling of the Samo-1 well, and PETRONAS has a right to become the Operator for development. Completion of the FOA is subject to the approval of The Republic of the Gambian Government and customary joint venture consents. The Samo Prospect, offshore The Gambia FAR has completed detailed geotechnical studies and assessed significant hydrocarbon resource potential in its two blocks offshore The Gambia. The Blocks A2 and A5 permit area, covering 2,682km2, are adjacent to and on trend with FARâs world class SNE oil field discovery and have significant exploration potential. A2 and A5 sit within the rapidly emerging and prolific Mauritania-SenegalGuinea-Bissau ('MSGB') Basin and lie approx. 30km offshore in water depths ranging from 50 to 1,500 metres (Figure 1). From 1,504km2 of modern 3D seismic data acquired in A2 and A5, FAR has identified large prospects similar to the 'shelf edge' plays FAR has successfully drilled in Senegal. FAR has mapped two drillable prospects, Samo and Bambo and additional leads in the blocks (Figure 2). An independent oil and gas advisory firm, RISC Operations Pty Ltd (RISC), conducted an audit of FARâs internal estimate of Prospective Resources for the Samo prospect located in The Gambia permit A2. The Samo prospect has a best estimate Prospective Resource of 825 million barrels of oil on a gross unrisked basis. RISCâs report of the assessment of the probabilistic resources confirms it was carried out in accordance with industry standard SPE-PRMS practices. The Samo prospect has two target intervals, is on trend and shares many similarities with the giant SNE oil field. As such it is very highly rated with an estimated chance of success (CoS) in one or both targets, endorsed by RISC, of 55%. It is rare to have an exploration prospect with such a high CoS but this reflects the adjacent discovery at SNE and the confidence FAR Limited has developed in exploring in the play fairway which is yet to experience a dry well (refer ASX announcement 21 Nov 2017). Original article link Source: FAR Ltd ","Petronas has agreed to farmin 40% interest to offshore blocks A2 + A5 from FAR (40% op, GNPC 20%)."
47088,"On 5 April 2019 Petrogas plugged and abandoned its vertical appraisal well B10-4 in the A12b & B10a licence. The well was spudded on 21 March 2019 in a water depth of 50 m using the Maersk âResoluteâ J/U. B10-4 was the first well appraising the B10-FA field. The rig moved to Petrogasâ A15-A field to drill a development well. The B10-FA field is located in the northern part of the Dutch waters some 280 km north of the city of Den Helder. The gas field was discovered in 1991 and was never put in production. Its reservoir is situated below a depth of 592 m in the Miocene. The gas is assumed to be biogenic sourced with zero or negligible condensate. Interest in the A12b & B10a licence is held by Petrogas E&P Netherlands BV (operator), TAQA Offshore BV, RockRose (NL) CS1 BV and Energie Beheer Nederland BV (50%).",Petrogas plugged and abandoned its vertical appraisal well B10-4 in the A12b & B10a licence. Results n/a
44405,"Premier Oil plc announced on 5 April 2017 that it signed a share purchase agreement with Al-Haj Energy Limited for selling its Pakistani upstream assets. Under the agreement Premier will sell its subsidiary in the country holding exploration and production assets, Premier Oil Pakistan Holdings BV, to Al Haj for a cash consideration of USD 65.6 million. Al-Haj paid an initial interim deposit of USD 15 million to Premier and was obliged to pay a further USD 10 million within 60 days. Closing of the transaction is subject to all necessary government and regulatory approvals and it was reported to have an economic date of 1 January 2017. The deal was initially expected to be finalised by the end of 2017 but could not be completed due to delays in regulatory approvals from the Pakistani government. It was subsequently reported by Premier that Pakistani government approved the sale in November 2018 and the sale will be completed during Q1 2019. Premier reported in March 2019, under its 2018 annual report, that it has received USD 40 million of deposits from Al-Haj and has also collected USD 25 million in cash flows since the economic date of the transaction (1 January 2017). Premier currently hold non-operated interests in six gas producing onshore fields in the country which include Qadirpur, Kadanwari (including Kadanwari 14), Zamzama, Bhit, Badhra and Zarghun South. Oil and Gas Development Company Ltd (OGDCL) operates Qadirpur field which is one of the major producing field in the country with a production rate of 355 MMcfg/d during 2016. Kadanwari, Bhit and Badhra fields are operated by ENI, Zamzama field is operated by Tri Resources whereas Mari Petroleum Pakistan Ltd (MPCL) operates the Zarghun South field. Â Field Name Operator Premier Interest Badhra Eni 6% Bhit Eni 6% Kadanwari Eni 15.79% Qadirpur OGDCL 4.75% Zamzama BHP 9.375% Zarghun South MPCL 3.75% Â Â Background Information Premier had announced on 12 January 2017 that it extended the offer deadline for the sale of its Pakistani exploration and production (E&P) assets till late January 2017 with a new effective date of 1 January 2017. Premier had earlier agreed terms with one bidder, but due to the bidderâs inability to put in place the necessary funding arrangements during exclusivity period, the process was reopened. The company reported on 17 November 2016 that the exclusivity period with the preferred bidder for the sale of assets had been ended and it had reopened the process to a limited group of potential buyers with an offer deadline of early January 2017. It is understood that Premier had earlier received bids from five companies which include KUFPEC, Oil and Gas Development Company Ltd (OGDCL), Ocean Pakistan Ltd (OPL), POGC (Polish) and Pakistan Petroleum Ltd (PPL). The interested companies were required to submit bids by mid-December 2015. It was reported on 9 July 2015 that Premier Oil had received an offer from one company â the companyâs name was not disclosed. It had been reported in the media that Premier is intending to take this move to further streamline its portfolio in a lower oil price environment.",Premier Oil plc announced on 5 April 2017 that it signed a share purchase agreement with Al-Haj Energy Limited for selling its Pakistani upstream assets.
61534,"CNOOC â Zhanjiang made a gas discovery at YL 8-3-1, the well is reported to test over 35 MMcf/d of gas from basement in October 2019. CNOOC â Zhanjiang spudded YL 8-3-1, a deep water NFW, in the Qiongdongnan Basin on 17 July 2019. The well is located in the east of Lingshui Sag in 1,830 m of water and has a PTD of 3,015 m with target in Miocene-Oligocene clastic play. âBlue Whale 1â S/S is used for the drilling operation. In 2018 CNOOC completed YL 8-1-1, north of YL 8-3-1, and the well penetrated gas pay in the Oligocene Yacheng and granite basement formations. But the discovery is small in size without commercial value. Following YL 8-1-1, CNOOC drilled two NFW wells, YL 3-1 and YL 13-1-1, in this area without success. In 2015 CNOOC drilled LS 18-2-1 (alternatively YL 7-1-1), west to YL 8-3-1, and the well is reported with gas discovery. In 2011, BG drilled YL 2-1-1, further north to this well in this area, without success. Background Information CNOOC has achieved several gas discoveries in deep water Qiongdongnan Basin. In early 2014, CNOOC made first deep water gas discovery of Lingshui 17-2 in the Qiongdongnan Basin. Lingshui 17-2-1 tested 56 MMscfg/d and 490 b/d of condensate at an interval 3,321 - 3,351 m from the Huangliu Formation of the Upper Miocene. The following five appraisal wells were all successful and the discovery booked 3.6 Tcf of proven gas in place. In end 2014, CNOOC made a gas discovery in Lingshui 25-1-1 in this deep water area, the well penetrated 73 m gas pay and tested 36 MMcf/d of gas and 395 b/d of condensate from the Huangliu Formation of the Miocene. In 2015 CNOOC made two additional gas discoveries, Lingshui 18-1-1 and Lingshui 18-2-1, in this area. Lingshui 18-1-1 tested 37.6 MMcf/d of gas and 165 b/d of oil (more likely condensate) from the Pliocene Yinggehai Formation indicating 1.9 Tcf of possible gas in place reserves.",China (Central Qiongdongnan Depression (Qiongdongnan Bsn)) Lingshui 18-2 (Qg) 1
41136,"N. part of AE-0089-2M-Cinturón Subsalino-07 block, DW GoM Basin, WD 1,940m, susp gas-cond at TD 5,394m on 16 Dec â18, La Muralla IV SS. Target Wilcox.","Kokitl 1EXP (Pemex 100%) in N. part of AE-0089-2M-Cinturón Subsalino-07 block, susp gas-cond disc. at TD=5394m WD=1940m. Target Wilcox."
81053,"In early 2020, the Ethiopian Ministry of Mines, Petroleum & Natural Gas offered 22 open blocks in the country (see attached map): Ethiopia blocks on offer Block Name Block Sqkm Main Political Province Basin Names Gambela 157075.86 Binshangul Gumuz Amhara Massif~Abbay (Blue Nile) Basin North West 82516.38 Amara Mekele Basin~Amhara Massif~Northeast African Fold Belt Afar Area 62997.88 Afar Afar Basin~Red Sea Basin~Mekele Basin~Ogaden Sub-basin (Somali Basin)~Northeast African Fold Belt Rift Valley Block 43054.83 Ye Debub Biheroch Afar Basin~Amhara Massif Omo 30598.73 Ye Debub Biheroch Amhara Massif~South Omo Graben (EARS, East Branch)~Chew Bahir Graben (EARS, East Branch) Metema 29827.79 Binshangul Gumuz Mekele Basin~Northeast African Fold Belt~Amhara Massif Afar 24589.42 Afar Afar Basin~Mekele Basin~Red Sea Basin~Northeast African Fold Belt Block 05 18299.34 Oromiya Ogaden Sub-basin (Somali Basin) Block 07 12254.06 Sumale Ogaden Sub-basin (Somali Basin)~Mandera-Lugh Sub-basin (Somali Basin) Block 02 12232.2 Oromiya Ogaden Sub-basin (Somali Basin)~Mandera-Lugh Sub-basin (Somali Basin) Block 06 12232.2 Oromiya Ogaden Sub-basin (Somali Basin) Block 18 12232.19 Sumale Ogaden Sub-basin (Somali Basin) Block 01 12206.7 Oromiya Ogaden Sub-basin (Somali Basin) Block AB8 12135.44 Amara Abbay (Blue Nile) Basin~Amhara Massif Block AB9 12128.45 Amara Abbay (Blue Nile) Basin~Amhara Massif Block AB5 12108.5 Amara Amhara Massif~Abbay (Blue Nile) Basin Block AB6 12108.5 Amara Amhara Massif~Abbay (Blue Nile) Basin Block AB3 12068.51 Amara Amhara Massif Block AB2 12068.5 Amara Amhara Massif Block 19 6467.74 Sumale Ogaden Sub-basin (Somali Basin) Block 21 6094.66 Sumale Mudugh Sub-basin (Somali Basin) ~Ogaden Sub-basin (Somali Basin) Area 4 3679.4 Ye Debub Biheroch Amhara Massif~East African Rift System, Eastern Branch Source: IHS Markit 2020 © 2019 IHS Markit  Another five blocks were under discussions in Ethiopia in late 2019. The Government confirmed in late year that a Production Sharing Agreement (PSA) concerning one or more of these blocks was pending to be approved. These blocks could be Block 10 and Block 14 to be awarded to the British Delonex. Blocks Under Discussion in Ethiopia (late 2019) Basin Name Block Name Block Sqkm Existing drilling Existing discoveries Existing Exploratory Surveys Political Province Amhara Massif Block AB1 9,900 no no no Amara Amhara Massif Block AB4 9,900 no no 2011 (seismic) Amara Amhara Massif Block AB7 9,900 no no no Amara Ogaden Sub-basin (Somali Basin) Block 10 - possibly DELONEX 12,207 no no 1989 (2D) Sumale Ogaden Sub-basin (Somali Basin) Block 14 - possibly DELONEX 12,207 no no 1962 (2D), 1963 (Gravity/Magnetic). 1992 (2D) Sumale Source: IHS Markit, 2020        Until the update of the existing Petroleum law is approved by the Government, contracts are awarded in the form of Model PSA of 1994 between the government of Ethiopia, represented by the Minister of Mines and Energy, and a contractor. Contracts have an initial exploration term of four years and an optional two-year term, with two possible further exploration periods of two years (4+2+2). The development and production period is of 25 years. Minimum exploration and expenditure obligations are negotiable as well as signature and production bonuses. The income tax is 30% but will be reduced to 25% according to the petroleum draft being prepared by the Ministry. For further details, interested companies are invited to contact: Mr. Ketsela Tadesse Director â Petroleum Licencing & Administrative Dictatorate Ministry of Mines, Petroleum & Natural Gas P.O.Box 751 Addis Ababa, Ethiopia Phone: + 251 11 646 12 09 Fax: + 251 11 646 34 39 Ktadesse22@gmail.com","In early 2020, the Ethiopian Ministry of Mines, Petroleum & Natural Gas offered 22 open blocks in the country "
38397,"In parallel to F.R 43.GM (DEA 7 Jan â19, Global MED secured 6-year rights to the contiguous F.R 44.GM + F.R 45.GM licences in the Ionian Sea on the maritime boundary with Greece. Commitments include 300km of 2D seismic initially, plus 3D seismic and an explo well in subsequent phases as warranted. The blocks cover resp. 745 sq km and 749 sq km in WD 400-1,100m.","Italy, not found"
58715,"On 25 July 2019, the Dar Petroleum Operating Co (DPOC) group discovered oil in the Jamam 1 well in the Adar area (Block 3) of the Upper Nile region. The well was spudded on 16 April 2019, reached a TD of 1,320 m and encountered 5.3 MMbbl of good quality oil recoverable resources in the Miocene sandstones. The Minister of Petroleum reportedly said that âwe are looking at over 300 MM reserves with the hope of more discoveries because there are two more wells that are under reviewâ. He also addressed that production from the new discovery would start before the end of 2019. Darpet operates Block 3E and Block 7E with Nilepet (8%), CNPC (41%), Sinopec (6%), Tri-Ocean (5%) and Petronas (40%) as partners. As of August 2019, the blocks were producing at a rate of approximately 130,000 bbl/d.","An unnamed Miocene oil find is reported in block 3, Upper Nile state near the Adar oilfield, Melut Basin, TD 1,320m, a figure of 300 MMbo articulated. The find appears to be distinct from the recent Jamam discovery in block 7 (DEA 26 Aug â19). DPOC (op), partners Petronas, CNPC, Nilepet, Sinopec + Tri-Ocean. Minister of Petroleum reportedly said that âwe are looking at over 300 MM reserves with the hope of more discoveries because there are two more wells that are under reviewâ."
24029,"Bagla D&PL, Lower Indus onshore, TD 2,910m, tested gas + cond, results not yet released. Target Lower Goru.","Khirun 01 in Bagla D&PL, tested gas + cond, ops completed, Target Lower Goru, results not yet released."
63761,"On 1 November 2019, BHP Billiton Petroleum (Deepwater) was awarded three East Breaks blocks, EB 655 (G36715), EB 656 (G36716) and EB 701 (G36720), 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, BHP Billiton Petroleum (Deepwater) is the operator and sole interest-holder (100% WI + Op) in EB 655, EB 656 and EB 701.","BHP Billiton Petroleum (Deepwater) was awarded three East Breaks blocks, EB 655 (G36715), EB 656 (G36716) and EB 701 (G36720),"
27463,"Pandion Energy agreed to acquire 10% in PL820 S from Wintershall on 15 August 2018. The deal is subject to regulatory and partner approval with an effective date of 1 January 2018. Awarded in APA 2015, 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 partners have elected to drill PL820 S and a NFW is planned for 2019. Within PL820 S, and 1.5km S of Jette, is NFW 25/8-13 (2001, ExxonMobil, 2,276m) drilled under PL027 B, which was P&A dry after reaching TD within the Early Jurassic Statfjord Group. Lundin acquired Fortis Petroleum's entire 30% interest in PL820 S on 15 February 2018. Pandion purchased Tullow Oil's six licence interests on 22 June 2017, then acquired 10% of the Valhall and Hod fields from Aker BP on 22 December 2017. Pending completion of the Wintershall-Pandion deal PL820 S licence participants are MOL Norge AS (40% + Op), Wintershall Norge AS (30%) and Lundin Norway AS (30%). ","Pandion will acquire a 10% interest in PL 820S from Wintershall (->20%, MOL 40% op. Lundin 30%)."
71340,"On 3 February 2020, PetroRio announced that it signed a definitive agreement to acquire 80% working interest in the Tubarao Martelo production concession from Dommo Energia and would acquire the FPSO OSX-3 for USD 140 million. The goal of the transaction is for PetroRio to jointly operate the easterly adjoining Polvo field and the Tubarao Martelo field as a cluster development thus reducing OPEX costs 50% with the synergies and extending field recoverable reserves life to 2035. The announcement by PetroRio also included an update on three new pool discoveries drilled by the operator in December 2019 that are within 6-7 km of the FPSO OSX-3 in the western area of the Polvo production concession. PetroRio plans to tie-back production from its Polvo A fixed platform in the Polvo field to the FPSO OSX-3 located approximately 9.9 km to the southwest and de-commission the FPSO Polvo by mid-2021 with a Capex estimated to be between USD 50-60 million. The transaction is complex with additional financial commitments by PetroRio besides the USD 140 million for the purchase of the FPSO OSX-3. From the current transaction date to the completion of the tieback operation, PetroRio will have rights to 80% of the production from the Tubarao Martelo Field and be responsible for 100% of the FPSO's charter expenses, the Tubarao Martelo field's Opex, and Capex and abandonment costs. During this phase, through approximately mid-2021, Dommo will reimburse PetroRio a monthly fee of USD 840 thousand equivalent to 20% of Dommo's current Opex, excluding the FPSO charter costs. Once the tieback is complete, PetroRio will be responsible for 100% of all costs for the cluster and Dommo will stop paying the monthly fee with PetroRio to have rights to 95% of the produced oil from the cluster up to 30 MMbo produced after tieback, and 96% thereafter. The 1 January 2019 BAR reserves report had the Polvo field holding original oil in place (OOIP) of 404.84 MMbo and original gas in place (OGIP) of 32.55 Bcfg and with a cumulative production of 44.06 MMbo and 4.36 Bcfg represented a recovery factor to that date of 11% for oil and 13% for the gas. The 1 January 2019 BAR reserves report had the Tubarao Martelo field holding OOIP of 428.49 MMbo and OGIP of 46.96 Bcfg and with a cumulative production of 15.02 MMbo and 1.65 Bcfg represented a recovery factor to that date of 4% for oil and 4% for the gas. Both fields have a low GOR of approximately 100 cu-ft/bo and produce oil of 20° to 21° API. The Polvo field had an average daily production in 2019 of approximately 8,437 bo/d and Tubarao Martelo 5,815 bo/d. Dommo Energia held 100% working interest in the Tubarao Martelo production concession but after formal governmental approvals PetroRio will be the operator with 80% working interest and Dommo will hold 20%. On 3 February 2020, PetroRio also announced that it completed two directional special wells and one horizontal development well in the Polvo production concession and discovered three new oil pools one in the Eocene Embore Formation and two in the early-Cretaceous Quissama Formation. The three wells include the POL-N (9-POL-042D-RJS) and POL-Na (9-POL-043DP-RJS) special wells completed in December 2019 and the POL-Nb (7-POL-44HP-RJS) horizontal development well completed and initially tested in January 2020. On 3 December 2019, Dommo Energia announced that it was nearing conclusion of the revitalization project in its Tubarao Martelo field in the Campos Basin that it originally announced it would undertake in November 2018. On 26 November 2018, the company announced that the revitalization project consisted in the completion of well 7-TBMT-4HP-RJS, that needed to be connected to FPSO OSX 3, and the workover of 4 producing wells (7-TBMT-2HP-RJS, 7-TBMT-6HP-RJS, 7-TBMT-8H-RJS and 9-OGX-44HP-RJS). The company indicated that the revitalization project would increase production in the field to an estimated of 10,000 bo/d by the end of 2019. The estimated cost of the project was USD 80 million. From January to October 2019 the field has produced an average of 5,831 bo/d, 597 Mcfg/d, and 2,345 bw/d. In October 2019, only three wells were producing, the 7-TBMT-6HP-RJS, 7-TBMT-8H-RJS and 9-OGX-44HP-RJS, with the 7-TBMT-2HP-RJS not producing. The Tubarao Martelo field was discovered in December 2010 with well 1-OGX-WAIKIKI-1-RJS (1-OGX-25-RJS). The well was targeting post-salt Eocene sandstones of the Carapebus Formation and post-salt Upper Cretaceous carbonates of the Imbetiba Formation. The carbonate reservoir is the main reservoir of the field. Tubarao Martelo field was appraised between February 2011 and April 2011 by 2 wells (3-OGX-35D-RJS and 3-OGX-41D-RJS). The field was declared commercial in April 2012 by OGX. It was the first commercial declaration of an offshore oil discovery for the company. The Tubarao Martelo field started production in December 2013 through the FPSO OSX-3. As of September 2019, is has produced 17.6 MMbo and 1.8 Bcf of gas. Development drilling started in September 2012 and concluded in February 2013. No improved recovery techniques have been applied in this field. The Polvo production concession covers an area of 134.1 sq km and has been producing since 2007 when it was brought online by former operator Devon. From February 2012 to February 2013 the Polvo Field produced an average of 13,711 bo/d, 20° API, and about 20,000 bw/d. There are about 10 wells producing currently. The Polvo Field reservoirs include the Maastricthian and Turonian turbidites of the Carapebus Formation and the Early Cretaceous Quissama Formation carbonates are also productive. Rumors of BP possibly selling assets surfaced in August 2012. On 6 May 2013, HRT announced that it acquired 60% working interest and operations of the Campos Basin Polvo production concession from BP Energy do Brasil Ltda. The retroactive purchase date is 1 January 2013 for a price of USD 135 million. HRT acquired all associated equipment from a separate BP subsidiary that owns and operates the Polvo A fixed platform and other drilling and production equipment with the exception of the FPSO Polvo that is owned and operated under contract by BW Offshore. The transaction was granted formal approval by the ANP on 18 December 2014.",Petro Rio has signed to acquire an 80% interest from Dommo Energia in the Tubarão Martelo ('Hammer Shark') field in BM-C-039.
25267,"Following govt approval of the move, the transfer of 35% + operatorship of FEL 2/14 from Providence to Total is now complete. FEL 2/14, 872 sq km in the Main Porcupine Basin, contains the undrilled Diablo prospect and the (drilled) Druid & Drombeg prospects. Equity is now Total (op) 35%, Capricorn 30%, Providence 28% + Sosina 7%.","Following govt approval of the move, the transfer of 35% + operatorship of FEL 2/14 from Providence to Total is now complete. FEL 2/14, 872 sq km in the Main Porcupine Basin, contains the undrilled Diablo prospect and the (drilled) Druid & Drombeg prospects. Equity is now Total (op) 35%, Capricorn 30%, Providence 28% + Sosina 7%."
64612,"On 16 October 2019, Waha Oil Co (Waha) completed as an oil well the outpost 59 A 150 in the 059 - Central block, Zelten Platform (Sirte Basin) with the ADC 16 rig and the Waha Limestone Formation as a primary objective. The well was spudded on 5 September 2019 to a PTD of 2,028 m. Waha (059-A) is an oil field discovered by Waha in 1961 when the discovery well encountered oil in the Waha Limestone Formation (Upper Cretaceous). The field was put on-stream in July 1963 and water recovery started in 1977. Waha is a joint venture formed by the National Oil Corporation (NOC, 59.170%), ConocoPhillips Libya Waha (16.330%), Marathon Petroleum Libya (TOTAL16.330 %) and Hess Libya (8.170%).","Waha Oil Co completed as an oil well the 59 A 150 outpost in Waha (059-A9 field, Sirte Basin"
40973,"Congoâs Council of Ministers agreed late 2018 to award Marine XX to Total and partner SNPC (assumed 85:15). Total is believed to be now awaiting the award ratification to embark on exploration. The 3,300-sq km block was offered under the Congo Round Phase I.","Congoâs Council of Ministers agreed late 2018 to award Marine XX to Total and partner SNPC (assumed 85:15). Total is believed to be now awaiting the award ratification to embark on exploration. The 3,300-sq km block was offered under the Congo Round Phase I."
32858,"Karoon Gas is renewing a 2013 offer to dilute its 100% stake in WA-314-P, Â 998 sq km in deepwaters of the Caswell sub-basin, ahead of embarking on explo drilling. The block lies NW of the Poseidon field. Contact: Ian Reid, IReid@karoongas.com.au .","Karoon Gas is renewing a 2013 offer to dilute its 100% stake in WA-314-P, 998 sq km in deepwaters of the Caswell sub-basin, ahead of embarking on explo drilling. The block lies NW of the Poseidon field. Contact: Ian Reid, IReid@karoongas.com.au "
84758,"Pakistan Petroleum Ltd (PPL) reported on 28 April 2020 in the quarterly report that it had re-entered the Margand X-1 (also called Mor Gandh X-1) discovery well within the Margand 2866-4 EL (Kirthar Fold Belt) onshore licence and it was deepened to a TD of 5,100 m before initiating testing in a deeper section of Jurassic Chiltan Formation. It was subsequently reported to have flowed around 15 MMcfg/d through 128/64"" choke during testing along with 120 b/d of water. The Margand discovery is estimated to hold around 1 Tcf of gas reserves but it believes to contain high nitrogen and carbon dioxide content with total non-hydrocarbons ratio up to 40%. PPL plans to drill another exploratory well in the block by the end of 2020. PPL had earlier reported the gas discovery in this well on 23 December 2019 after drilling to a TD of 4,500 m. A drill stem test (DST) was carried out and it flowed 10.7 MMcfg/d and 132 b/d of liquids through 64/64"" choke with a well head flowing pressure (WHFP) of 516 psi from the Chiltan Limestone Formation. PPL was conducting the study about the nature of liquid which is assumed to be condensates. It was reported that the well had a potential to flow at higher rates through acid stimulation. This was the first discovery in Kalat Plateau, opening up a new area for hydrocarbon exploration. Margand X-1 was the first well in the Margand EL block and it was spudded on 30 June 2019 using the âWDI-812â land rig with a prognosed TD of 4,500 m. Prior to initiating DST in early December 2019, PPL conducted wireline logging and modular dynamic testing which suggested the presence of hydrocarbons. Margand X-1 was drilling at 1,168 m depth during mid-July 2019, reached 1,743 m by the end of the month and progressed to 2,116 m depth during mid-August 2019. It was drilling at 2,800 m depth by the end of August, reached 3,488 m by mid-September and 3,669 m depth during late September 2019. It was drilling at 3,703 m depth in October 2019, progressed to 4,279 m by mid-November and reached the final TD of 4,500 m in late November 2019. Margand EL covers an area of 2,484 sq km and is located in Balochistan province. PPL currently hold 100% interest in the block. PPL reported in the 2H 2018 report in March 2019 that it has acquired 2,434 line km gravity and magnetic data in the block. The company had earlier acquired 261 line km of 2D seismic (dynamite source) in the acreage between December 2017 to April 2018 using the BGP 9501-B seismic crew.  Background Information PPL (operator), along with OMV, were awarded the Margand exploration license, with the Petroleum Concession Agreement (PCA) having been signed on 28 February 2014. The equity split at the time of award was as follows: PPL (50%, operator) and OMV (50%). It was subsequently announced in January 2017 that OMV has farmed out from the block assigning its full 50% interest to PPL, effective 30 June 2016. PPL was granted a 12-month extension to the Phase-I of initial term for Margand EL from 28 February 2017 to 27 February 2018. It was followed by a further 12-month extension to the Phase-I from 28 February 2018 to 27 February 2019. PPL was subsequently granted the renewal with licence entering into two-year Phase-II of initial term with effect from 28 February 2019.","Pakistan (Kirthar Fold Belt) Margand X-1 nfw, op. by PPL (100%) in Margand 2866-4 EL block, gas discovery re-entered for deepening to 5,100m, tested a deeper section of Jurassic Chiltan fm, 15 MMcfg/d + 120 bw/d on 2"" choke. In late 2019 this well (TD 4,500m) was DST'd, flowing 10.7 MMcfg/d and 132 b/d of liquids on 1"" choke from the Chiltan."
26332,"PEMEX plugged and abandoned dry the Oni 1EXP new field wildcat (NFW) in the AE-0006 block on 26 June 2018. The well reached a final total depth (TD) of 6,705 m during early-May 2018. The operator tested a zone from 6,327 m to 6,635 m with negative results. The NFW was spudded on 13 October 2017.  The well had a proposed total depth (PTD) of 7,100 m. The Middle Cretaceous and Jurassic sections were the primary objectives.  The âCantarell Iâ J/U drilled the well in an estimated water depth of 70 m.  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 Oni 1 EXP is estimated to be located in the central southwestern area of the block approximately 13 km west of the Xanab field. SENER granted the AE-0006-3M-Amoca-Yaxche-04 entitlement block to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 872.2 sq km.","Oni 1EXP Pemex 100%) in the AE-0006 block, tested a zone from 6327 to 6635m with negative results. The Middle Cretaceous and Jurassic sections were the primary objectives, P&A dry."
34586,"In early October 2018, TransGlobe Energy Corp (TransGlobe) abandoned the Ghazalat South 1 (SGZ-1) exploration well in the South Ghazalat permit, Abu Gharadiq Basin. The well was spudded in early October 2018 and drilled to a TD of 935 m. It has the Cenomanian Bahariya formation as the target. SGZ-1 well final cost is estimated at USD 700,000. Background Information TransGlobe reported on 8 November 2013 that the official signature for the award of the four exploration permits, Northwest Gharib, Southwest Gharib, Southeast Gharib and South Ghazalat has been held on 7 November 2013. The four PSCs were won in the 2011/2012 EGPC bid round. Expenditure commitments for the four blocks for the initial three-year period are of USD 101.1 million, including USD 40.6 million for signatures bonuses, acquisition of new 2D or 3D seismic surveys and the drilling of up to 40 wells. For each permit, the initial exploration period run for three years, plus possible two extensions of two year each. TransGlobe is the sole participant in the four PSCs. The contracts were ratified into Law on 3 October 2013. On 13 June 2015, TransGlobe completed its 408 sq km 3D seismic survey over the South Ghazalat permit. The survey started on 3 May 2015 by CGG, the contractor. The survey is part of a large seismic programme that includes the acquisition of 1,000 sq km 3D seismic data (in Northwest Gharib (NWG), Southwest Gharib (SWG) and Southeast Gharib (SEG)) as well as 300 km of 2D seismic data in the Eastern Desert plus a 400 sq km 3D seismic survey in the South Ghazalat for a total of USD 36 million.","TransGlobe Energy Corp (TransGlobe) abandoned the Ghazalat South 1 (SGZ-1) exploration well in the South Ghazalat permit, Abu Gharadiq Basin."
31562,"Further to DEA 3 Oct â18 (adds results)Â : Mubarak (block 20) 2769-4 EL, Middle Indus onshore, TD 3,610m late August, gas discovery, tested 6.48 MMcfg/d on a 1/2â choke from the Lower Goru B-sand, WHP 1,308 psi, SLR-15 rig. OMV (op), partners Eni + Govt Holdings.","Mitha 1 (OMV 57% op, Eni 38%, GHPL 5%) in Mubarak 2769-4 EL, onshore, gas discovery tested 6,48 MMcfg/d [1/2â choke] from the Lower Goru B-sand, TD=3610m."
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. "
24154,"Hitherto unreported, in early May 2018, Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) completed with gas new-field wildcat Królewska Góra-1K in the 28/96/p Ropczyce-Bratkowice-Strzyzów contract in southern Poland (Carpathians). The well reached the final depth of 1,350 m, obtained commercial gas flows from the Miocene clastic series (results unreported) and was completed as producer. PGNiG was the sole operator of the well. Królewska Góra 1K, located approximately 25 km west of the city of Rzeszow, within the tectonic units of the Carpathian Flysch Zone, was started in late March 2018. The well had a planned final depth estimated to be approximately 2,300 m, targeting the Autochthonous Miocene sandstone series. Test results indicate that annual production from the newly discovered deposit may reach approximately 100 MMcf/d of high-methane gas. PGNiG is expecting the discovery well to be on-line in late 2019. Background Information The Ropczyce-Bratkowice-Strzyzow contract was granted to PGNiG on 13 May 1996. It was due to expire on 13 May 2014 but was extended to 13 May 2018 (at the time of renewal, the company carved out of the concession the area in the western sector of the tract, suburbs of the cities Ropczyce and Rzeszow). In 2017, PGNiG received approval from the Department of Geology and Geological Concessions for the conversion of the contract 28/96/p, holding the prospection/exploration rights until then, into a joint exploration and production contract (received new designation: 28/96/L). The latest well operation in the area dates back to late October/early November 2016, when PGNiG finalised successful new-field wildcat Gnojnica 2K - the well was completed with gas in the Autochthonous Miocene sandstone series.","Królewska Góra-1K op. by PGNiG (100%) in the contract 28/96/ŠRopczyce-Bratkowice-Strzyżów, gas disc, with anticipated potential production of 2 MMcf/d of high methane gas from Badenian (Miocene) sst. "
70485,"Ranipur 2768-11 EL, Middle Indus onshore, Sindh, TD 1,504m (U. Goru), gas-cond discovery, tested 1.85 MMcfg/d + 6 bc/d on 1/2â choke from the L. Ranikot fm, WHFP 285 psi. OGDC (op), partners GHPL + SEHCL.","Metlo 1 nfw. (OGDC 95% op, GHPL 2,5%% + SEHCL 2,5%) in Ranipur 2768-11 EL, onshore, Sindh, TD=1504m (U. Goru), gas-cond discovery, tested 1,85 MMcfg/d + 6 bc/d on 1/2â choke from the Paleocene, L. Ranikot Fm."
12287,"PRL 151, Cooper-Eromanga, drilled 22 â late Dec â17, P+A gas shows at TD 2,624m. Target Patchawarra. ","Squeaky 1 op. by Beach in PRL 151, targeting a stratigraphic prospect, encountered moderate gas shows, it contained gas pay of sub-commercial quality and the well was P & A."
9521,"On 14 October 2017, Eni together with Oman Oil Co Exploration & Production LLC (OOCEP), a wholly-owned subsidiary of state company Oman Oil Co SAOC (OOC), signed an Exploration & Production Sharing Agreement (EPSA) with the Omani Government for Block 52 (JuzorAl Hallaniyyat). The block (90,760 sq km) is located offshore of the southern third of Oman in water depths ranging between 10-3,000m.The block has been awarded following the country's 2016 Licensing Round, which was launched in October 2016 and closed in February 2017. It was among a total of four blocks on offer, which are located in different parts of the country. Block 52 is largely unexplored, with only three wells having been drilled on the vast acreage. So far there are no discoveries, however oil and/or gas shows have been reported in all three wells. The last well, Sawqirah Bay South 1, was drilled by Petroleum Development Oman (PDO) in 1991. It encountered gas shows in the Lower Tertiary and the Cretaceous Aruma Group. It is understood the block contains liquid hydrocarbon potential and that there are currently six mapped prospects.Eni operates the acreage with an 85% interest, with OOCEP holding the remaining 15%.","Oman, Block 52 (Juzor Al Hallaniyyat)"
27741,"Fell block, onshore Magallanes Basin, TD 2,009m, gas discovery, tested avg 5.8 MMcfg/d, 2,738 psi WHP, on various chokes from the Springhill fm. A stabilised flow rate is yet to be determined. Gas is now being sold to Methanex on a long-term contract.","Jauke 1 in Fell block, onshore, gas discovery, tested avg 5.8 MMcfg/d, on various chokes from the Springhill fm. A stabilised flow rate is yet to be determined. TD=2009m"
51993,"Sudan Petroleum Corp (Sudapet) is looking to farm out some equity in Block 25 in which the state company has 100% of interest. In late 2018, a long-term production test at the Rawat Central field was started which flowed at a rate of approximately 600 b/d of waxy oil. The produced oil was being transported by truck to the El Obeid refinery where is sold as a fuel oil for nearby factories. See here for more information.","Sudan Petroleum Corp (Sudapet) is looking to farm out some equity in Block 25 in which the state company has 100% of interest. In late 2018, a long-term production test at the Rawat Central field was started which flowed at a rate of approximately 600 b/d of waxy oil. The produced oil was being transported by truck to the El Obeid refinery where is sold as a fuel oil for nearby factories. See here for more information."
71682,"Shell has acquired a 50% operating stake from Ecopetrol in the Fuerte Sur, Purple Angel and COL-5 blocks, 2,583, 2,234 + 3,985 sq km resp. in the Caribbean and home to the Kronos, Gorgon + Purple Angel discoveries. Ecopetrol retains 50%:","Shell has acquired a 50% operating stake from Ecopetrol (->50%) in the Fuerte Sur, Purple Angel and COL-5 blocks, 2 583, 2 234 + 3 985km² resp. home to the Kronos, Gorgon + Purple Angel discoveries. "
38237,"Sinopec â Xibei achieved oil and gas flow in an appraisal well in Shunbei field in the Tarim Basin. Shunbei 501, drilled in Shunbei 5 discovery area, tested 2,087 b/d of oil and 1.52 MMcf/d of gas. The success of the well makes field extension southwards. The well has a TD of 8,160 m. In 2017 Sinopec tested oil and gas in Shunbei 5. This exploration well is located in the west of Shunbei 1 discovery, and was spudded in 2016 with a PTD of 7,546 m. Sinopec has a target to build 10,000 b/d of oil production capacity in Shunbei 5 area. 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 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 4,000 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 2018 Sinopec has built Shunbei field with annual production capacity of 500K tons of oil in the Tarim Basin. The field has produced 250K tons of oil in the first half of 2018, daily output reaching 10,650 b/d. The company plan to reach annual production of 2 million tons of oil (40,000 b/d) and 3 Bcm (300 MMcf/d) of gas by 2023.","Sinopec â Xibei achieved oil and gas flow in an appraisal well in Shunbei field in the Tarim Basin. Shunbei 501, drilled in Shunbei 5 discovery area, tested 2,087 b/d of oil and 1.52 MMcf/d of gas. The success of the well makes field extension southwards. "
61551,"S. part of BM-SEAL-004 block, Sergipe Alagoas offshore, WD 2,647m, oil shows report to ANP 22 Aug '19, assumed tested during September, since suspended, Petrobras 10000 DS. PTD was 5,609m, target Calumbi fm. Petrobras (op), partner ONGC Videsh.","Brazil, BM-SEAL-004"
20816,"On 4 May 2018, the MME published a press release indicating approved of holding the 5th PSC Pre-Salt Bid Round that includes four blocks. President Temer has to now grant approval but this is expected shortly. The four blocks include the Pau Brasil block, the Tartaruga Verde block, the Saturno block, and the Tita block. The Saturno block includes the previous Saturno area plus the S-M-645 block removed from the ANP Round 15. The Tita block will include the northeastern portion of the former Saturno block and the S-M-534 block removed from the ANP Round 15. The S-M-534 and S-M-645 were classified as âStrategic Areasâ and is the reason they have now been incorporated into the pre-salt demarcated area and can be offered only under the PSC model contract regime. The preliminary schedule reported was for the bid submittal to be on 28 September 2018. Petrobras now has 30 days after publication in the DOF to exercise its preferential rights for any blocks in the round. The Pau Brasil block received no bids in the 3rd PSC Pre-Salt Bid Round and the Sudoeste de Tartaruga Verde received no bids in the 2nd PSC Pre-Salt Bid Round, both held in October 2017. The ANP will present its request for the addition of the blocks to the CNPE who will also decide on holding the 5th PSC Pre-Salt Bid Round as a separate round in 2018 and if the Saturno, S-M-534, and S-M-645 blocks will also be included in the round. On 4 April 2018, the ANP published a press release indicating the possible addition of the Pau Brasil and Sudoeste de Tartaruga Verde blocks to the 5th PSC Pre-Salt Bid Round which would bring the total number of blocks on offer to five. The Pau Brasil block received no bids in the 3rd PSC Pre-Salt Bid Round and the Sudoeste de Tartaruga Verde received no bids in the 2nd PSC Pre-Salt Bid Round, both held in October 2017. The ANP will present its request for the addition of the blocks to the CNPE who will also decide on holding the 5th PSC Pre-Salt Bid Round as a separate round in 2018 and if the Saturno, S-M-534, and S-M-645 blocks will also be included in the round. On 2 April 2018, the MME published a press release indicating the possible addition of the 5th PSC Pre-Salt Bid Round to be held in 2018 with three blocks on offer, Saturno block if it is removed from the ANP 4th Pre-Salt Bid Round, and two blocks removed from the ANP Round 15, the S-M-534 and the S-M-645 blocks. This is what it will propose to the CNPE. It is unclear when and how fast the CNPE will rule on this proposal. That may be the reason that the final tender documents for the ANP 4th Pre-Salt Bid Round have not yet been published, the date originally set was 29 March 2018. Also it will mean that Petrobras will have another chance to have preferential rights for the block that it did not choose in the ANP 4th Pre-Salt Bid Round. On 2 April 2018, the MME published a press release indicating a possible modification to the 4th PSC Pre-Salt Bid Round with the removal of the Saturno block that would leave four blocks available in the round. The current planned ANP 5th Pre-Salt Bid Round would become the ANP 6th Pre-Salt Bid Round. Preliminary Map with proposed ANP and MME modifications to ANP 4th, 5th Pre-Salt Bid Rounds â 4 May 2018","Brazil, Tartaruga"
38498,"Heritage, incorporated on 5 Oct â18 as Trindadâs new NOC and replacing debt-laden Petrotrin, is looking to partner with an entity capable of assisting with financing and technology. Heritage first intends to stabilise its staffing and value its assets, which comprise E&P and marketing.","Trinidad and Tobago, not found"
66752,"Petrobras in early December 2019 released a teaser to disclose the divestment opportunity to sell its interest in the ES-T-506 and ES-T-516 exploration blocks in the Espirito Santo Basin. The Round 11 blocks are operated by Cowan Petroleo e Gas (50%) with Petrobras as partner holding the remaining 50%. Offers must be separate for each block with Cowan as operator having the right of first refusal for the transactions. Both areas are in the first exploration period, which is due for expiry in June 2020 but may be extended to June 2022. The minimum exploration program for the first period of exploration in both blocks calls for the drilling of three wells in each block.The ANP board of directors on 23 August 2018, approved the reinstatement of 646 days on the contracts for Round 11 blocks ES-T-496 and ES-T-516 in the Espirito Santo Basin. The blocks were previously in force majeure. The ruling is counted from the date of issuance of the environmental licenses for the blocks which was 9 June 2017, so the end of the first exploration period for the contracts at that time went from 30 August 2016 to 14 June 2019, while the end of the second exploration period changed from 30 August 2018 to 14 June 2021. The blocks included a total of five new field wildcats with oil and gas shows that have not been developed. In the central part of the ES-T-506 Block the 1BRSA424ES was drilled to a total depth of 1,666m in 2006 and found oil shows. In the northwest part of the block, also in 2006, Petrobras found oil and gas shows in the 1BRSA428ES at a total depth of 1,548m. In the southwest part of the block in 2007, Petrobras reached a total depth of 1830m and found oil shows in the 1BRSA488ES. However, no wells have been drilled on these blocks under the most recent Round 11 contracts awarded to Cowan in 2013. ",Not Found
87850,"Simwell Resources released a statement on 5 August 2020 disclosing that it has farmed-out a 70% stake and operatorship in its P2332 licence (blocks 41/3, 41/4 and 41/9) to Shell. The deal has received Oil and Gas Authority (OGA) approval. The licence covers 715 sq km and is directly west of the Shell operated P2252 licence (41/5a, 41/10a and 42/1a). Simwell was awarded the P2332 licence in May 2017 in the 29th Offshore licencing round. Simwell mapped two Carboniferous leads in the Scremerston Formation and Fell Sandstone Formation and mapped the Permian Zechstein Z3 carbonate play fairway. Simwell believe that each of the two Carboniferous leads could contain more than 500 Bcfg recoverable. The 29th round award was granted with a 3D seismic commitment that has already been satisfied by the 3D survey shot by Shell in the neighbouring P2252 licence, which also extended approximately 160 sq km into P2332. The seismic survey commenced on 1 August 2019 and it was being processed in August 2020. The P2332 licence commitments have therefore been satisfied until the drilling decision which is required before May 2023. In May 2019 Shell acquired a 70% interest in the neighbouring licence P2252. The licence hosts the Pensacola prospect which has a Zechstein reservoir target and is expected to be drilled in late-2021. Interest in P2332 is held by Shell UK Ltd (70% +operator) and Simwell Resources Ltd (30%).","(Anglo-Dutch B.) P2332, Simwell Resources has farmed-out a 70% stake and operatorship (blocks 41/3, 41/4 and 41/9) to Shell. The deal has received Oil and Gas Authority (OGA) approval. The licence covers 715 sq km and is directly west of the Shell operated P2252 licence (41/5a, 41/10a and 42/1a)."
25240,"East Breaks Block EB 914 (G36192), situated in the East Texas Coastal Basin, was awarded to BHP Billiton Petroleum (Deepwater) on 1 July 2018. The block was originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, BHP Billiton Petroleum (Deepwater) is now the operator and sole interest-holder (100% WI + Op) in EB 914.","East Breaks Block EB 914 (G36192), situated in the East Texas Coastal Basin, was awarded to BHP Billiton Petroleum (Deepwater) on 1 July 2018. The block was originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, BHP Billiton Petroleum (Deepwater) is now the operator and sole interest-holder (100% WI + Op) in EB 914."
53367,"Melbana Energy Ltd reported on 15 July 2019 that it was intending to make a takeover offer for Metgasco Ltd. Under the offer the company plans to acquire 100% of the ordinary shares in Metgasco, by offering shareholders four fully paid Melbana shares for every one Metgasco share. Melbana reported that the offer has an implied value of AUD 0.04 per share, which is a 48% premium on the closing price of Metgasco shares on 12 July 2019 and a 35% premium on the five day weighted average. For the takeover to be successful Melbana must receive an acceptance of 50.1% from shareholders.","Melbana Energy Ltd reported on 15 July 2019 that it was intending to make a takeover offer for Metgasco Ltd. Under the offer the company plans to acquire 100% of the ordinary shares in Metgasco, by offering shareholders four fully paid Melbana shares for every one Metgasco share. Melbana reported that the offer has an implied value of AUD 0.04 per share, which is a 48% premium on the closing price of Metgasco shares on 12 July 2019 and a 35% premium on the five day weighted average. For the takeover to be successful Melbana must receive an acceptance of 50.1% from shareholders."
85858,"On 9 July 2020, Petrobras announced a closing of the sale of the Pescada, Arabaiana and Dentao fields on the Potiguar Basin shelf to OP Pescada, a subsidiary of local Brazilian operator Ouro Preto. The deal, for just US$ 1.5 million, includes the Petrobrasâ 65% and operator status in the fields where OP Pescada already has the other 35%. The fields had a combined production in the first half of 2020 of 260,000 bbls of oil and 6.7 MMcfg/d. The transactions is still awaiting regulatory approval. Â In early June 2020, it was disclosed that Petrobras was in an active divestment process and expected to soon conclude a sale agreement for its 65% working interest in the Pescada and Arabiana gas and condensate fields. The company is in direct negotiations with working interest partner Ouro Preto on the blocks which is presumably exercising a right of first refusal to acquire the Petrobras share and operator status on fields off the coast of Rio Grande do Norte. Negotiations have been in progress since early this year. Petrobras on 12 March 2019, announced the start of its binding phase in the competitive process to divest rights on the Polo Grande do Norte concession package in the state of Rio Grande do Norte and Potiguar Basin. The divestment package included: the Agulha, Cioba, Ubarana, Oeste de Ubarana, Pescada and Arabaiana concessions. Previously, Petrobras extended the deadline for companies to register interest in a divestment bidding process for 30 shelf oil and gas concessions in a September 2017 securities filing. The fields were organized into seven packages and Petrobras had a 100% working interest in most of them except the Pescada and Arabaiana fields. On 28 July 2017, Petrobras published a brief teaser on the sale of the areas in compliance with new transparency regulations determined by the Federal Audit Court. ","Brazil (Potiguar B.), Petrobras announced a closing of the sale of the Pescada, Arabaiana and Dentao fields to OP Pescada, a subsidiary of local Brazilian operator Ouro Preto. "
7739,"First well in block 54, Demerara Plateau offshore, P+Aâing at TD 2,685m, no significant reservoir quality rocks were encountered although logging and sampling proved the presence of gas condensate, Noble Bob Douglas DS. Tullow (op) 30%, Statoil 50%, Noble 20%.","Araku 1, first well op. by Tullow (30%, Statoil 50%, Noble 20%) in block 54, P&Aâing at TD=2685m, no significant reservoir quality rocks were encountered although logging and sampling proved the presence of gas condensate. "
61879,"D-33 (BOFF I, III, SWBH) (Add.) offshore block, NE of D-33 B field in offshore Bombay Basin, believed susp. at TD 3,770m in early Oct '19, Aban Ice DS.",India (Bombay B.) D-33 B
21449,"GuatiquÃa block, Llanos Basin, TD 4,036m in March, more recently tested avg 1,050 b/d of 15.3 API oil for 10 days from the Lower Sand 1A target under pressure buildup. Targets assumed Gacheta + Ubaque Lower Sand 1 fmâs.","Coralillo 1 op by in GuatiquÃa block, tested avg 1050 b/d of 15,3° API oil for 10 days from the Lower Sand 1A target under pressure buildup. Targets assumed Gacheta + Ubaque Lower Sand 1 fmâs. TD=4036m."
29342,"As of 11 September 2018, Pancontinental Oil & Gas NL (Pancontinental) is understood to be on the lookout for a Block 2713 (PEL 87) partner. The company mentioned that it intends to seek a major joint venture partner to fund an accelerated forward programme which will include a 3D seismic survey over its Late Aptian aged âSuper Fanâ. Pancontinental recently completed the first stage of assessing the potential prospective oil resources within the block (see article: Pancontinental Oil & Gas NL interpret a ""Super Fan"" within Block 2713 (PEL 87)). To date, the company has identified several leads with a combined best estimate in excess of 1.3 billion barrels of oil: Lead Unrisked Gross (100 percent) Prospective Oil (mmbbl) Play Type Best Estimate Probability of Geologic Success Lead A Mound facies 152 11% Lead C1 Structural (4-way rollover) 73 19% Lead D Structural/Stratigraphic 345 10% Lead G First Turbidite lobe/Sheet sand 349 7% Lead H Structural/Mound (4-way rollover) 40 7% Entire Super Fan Aptian Depositional Wedge 1329 5% Â On 4 December 2017, Pancontinental announced that it had via its wholly owned subsidiary Pancontinental Orange Pty Ltd been awarded Block 2713. The 10,947 sq km block straddles the Luderitz and Orange Sub-basins in water ranging between 400 m and 3,200 m deep. Interests in the licence are as follows: Pancontinental operates the licence with a 75% interest, Custos Investments (Pty) Ltd holds a 15% carried interest and the National Petroleum Corporation of Namibia holds a 10% carried interest.",Pancontinental Oil & Gas NL (Pancontinental) is understood to be on the lookout for a Block 2713 (PEL 87) partner. The company mentioned that it intends to seek a major joint venture partner to fund an accelerated forward programme which will include a 3D seismic survey over its Late Aptian aged âSuper Fanâ.
71546,"The ANP in late January 2020 approved the transfer of ExxonMobil's 35% working interest in the POT-M-475 and 50% in the CE-M-603 block in the Potiguar and Ceara basins to Ouro Preto Oleo e Gas (OP Energia) and Azibras. Both blocks are undrilled. OP will now be the operator in both blocks with a 30% working interest in partnership with Azibras, which will have 70%. ExxonMobil previously operated both blocks and Azibras had 65% in POT-M-475 and 50% in CE-M-603. The first period of exploration for both blocks is due for expiry in 2021 and the second period will end in 2023. The ANP in late July 2019 approved a two-year extension of the first phase of exploration for both these Round 11 offshore, frontier blocks. With the extensions the first period of exploration will expire in July 2021 for the CE-M-603 block and in August 2021 for the POT-M-475. AziLat since 2016 has been looking to farm down its interests on these conjugate equatorial margin blocks. Both blocks have recent 3D seismic data. AziLat on 20 October 2015, announced an agreement to buy a share of the two offshore blocks from the bankrupt Oleo e Gas Participacoes (OGPar). The blocks were awarded in 2013.","ExxonMobil transferred 35% WI in the POT-M-475 and 50% in the CE-M-603 block in the Potiguar and Ceara basins to Ouro Preto Oleo e Gas (OP Energia) and Azibras. Both blocks are undrilled. OP will now be the operator in both blocks with a 30% working interest in partnership with Azibras, which will have 70%."
73476,"M-field area, Makiivska (Makeevskoye) licence in Lugansk Oblast, Dnieper-Donets Basin, TD 1,985m, P&A'ing non-commercial gas shows.","Makeevskoye-30 (M-30) M-field area, Makiivska (Makeevskoye) licence in Lugansk Oblast, Dnieper-Donets Basin, TD 1,985m, P&A'ing non-commercial gas shows."
26725,"OMV AG, via wholly owned subsidiary OMV New Zealand Ltd., is offering 30% equity in offshore exploration permit PEP 51906, located in the Taranaki Basin. The opportunity is one of several that OMV is currently offering offshore New Zealand. OMV previously completed a farm-in deal on 26 March 2018 with Sapura Exploration and Production Sdn Bhd, in which Sapura acquired 30% interest. The deal also included interest in three OMV/Mitsui joint venture permits in the offshore Taranaki Basin. OMV continues to hold 70% interest and operatorship in the permit and is seeking a second partner. OMV initially reported that it would prefer a deal with a partner that included PEP 51906 and PEP 57075, in which it is also offering 30% equity, but would consider individual bids. Given its proximity to the Maui, Maari and Tui fields, the petroleum system within the permit are well understood. The Cretaceous Rakopi and Wainui formations are the principal source units and reservoir potential exists across the Late Cretaceous to Miocene stratigraphy where seal risk is low. Trapping structures are typically structural, nearby successes including differential compaction and drape over a basement high (e.g. Tui), faulted anticlinal features (e.g. Maari and Maui) and fault bounded closures (e.g. Ruru 3). Previous work has included acquisition of the 2013 Kaka 3D seismic survey in the southeast of the permit, from which new exploration insights have been identified. The Matuku 1 well was drilled in the permit by OMV in 2013. The well failed to encounter commercial hydrocarbons, though oil shows were observed in the targeted Eocene, Paleocene and Late Cretaceous targets. The well was drilled down to the oil-prone Late Cretaceous Rakopi Formation. OMV reported a lack of charge at the deep Cretaceous levels is likely the primary reason for the failure. However, encouragingly, high quality sandstone and seals were encountered at Matuku 1, adding a component of de-risking to the two main plays of the Cascade Prospect, located in the south of the permit.  Cascade is the principal prospect within the permit and comprises a three-way fault bounded structure with closure over 21 sq km. The primary targets include Late Cretaceous and Paleocene sandstones, charged from the proximal Maui Kitchen and with local potential from the underlying âCascade kitchenâ. Under the current permit obligations, a drill or drop decision is required before 19 November 2018 with an exploration well due before 19 November 2019. PEP 51906 was awarded on 19 November 2009 and covers an area of 1,613 sq km. Interests in the permit are OMV New Zealand Ltd (70% + operatorship) and Sapura Exploration & Production (NZ) Sdn Bhd (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 30% equity in offshore exploration permit PEP 51906, located in the Taranaki Basin."
27769,"29/2001/L Srem-Jarocin contract, Fore-Sudetic Monocline in W. Poland, TD 3,050m in early Aug â18, tested commercial gas from the Rotliegendes target, since completed as a potential 4.9 MMcfg/d producer. PGNiG (op), partner Orlen Upstream.","Chwalecin-1K, 29/2001/L Srem-Jarocin contract, Fore-Sudetic Monocline in W. Poland, TD 3,050m in early Aug â18, tested commercial gas from the Rotliegendes target, since completed as a potential 4.9 MMcfg/d producer. PGNiG (op), partner Orlen Upstream."
55421,"Barents PL 855, NW of Wisting find in WD 449m, P&Aâing w.o. results, West Hercules SS. PTD was 1,558m, targets Stø (o&g) + Snadd (oil) fmâs. Equinor (op), partners OMV + Petoro.","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."
71631,"The previous licence holders in PL 019 F (Repsol 61%, INEOS 34% and KUFPEC 5%) have all withdrawn with effect from 31 January 2020 (reported by the NPD on 6 February 2020). Their interests have been acquired by Aker BP (55%) and DNO (45%) and Aker BP has assumed operatorship. This deal aligns the interests in PL 019 F with PL 065 which lies immediately to the west. PL 019 F (3 sq km of block 2/1 which was split from PL 019 B in December 2018) contains the southeasterly extension of Tambar which lies mostly in PL 065. Tambar was discovered in 1983 by 1/3-3. It is located on the Ula Trend at the eastern margin of the Central Trough, between Gyda and Ula and is a hanging wall trap formed by the extension and minor contraction of a late Jurassic fault array. Tambar has been developed as a tie-back to the Ula Field, some 16 km to the northwest. The development uses a remotely controlled wellhead facility without processing equipment. The field was granted a lifetime extension until 1 January 2022 by the NPD on 8 July 2016. In the original PDO, approved on 15 July 2001, the lifetime of the facility was defined as 15 years, meaning it was due to expire on 15 July 2016. In 2018 two new infill wells, targeting undrained areas in the north and south of the field as part of re-development work, were completed and initial performance exceeded pre-drill expectations. This, plus the implementation of gas lift in three existing wells, will extend the lifetime of the field from 2018 to 2028, with the potential for it to be extended again in the future. The upgrade is targeting reserves of 27 MMboe, producing an additional 4,000-6,000 boe/d, and total investments were forecast at approximately NOK 1.7 billion (USD 205 million). Interest in PL 019 F is now held by Aker BP ASA (55% + operator) and DNO Norge AS (45%).","The previous licence holders in PL 019 F (Repsol 61%, INEOS 34% and KUFPEC 5%) have all withdrawn. Their interests have been acquired by Aker BP (55%) and DNO (45%) and Aker BP has assumed operatorship."
11228,"According to local media, 5 offshore blocks have recently be been signed up with companies from âfriendly countriesâ. Developments will be reported as and when applicable. ","Syria, not found"
41883,"On 12 February 2019, Merlon Petroleum was awarded the North Beni Suef exploration block (Block 5), Gindi Basin onshore basin as a part of the Egyptian General Petroleum Corporation (EGPC) 2018 bid round closed on 1 October 2018. The company is committed to invest USD 38 million including the drilling of eight wells. The signature bonus is USD 3.2 million. Background information The North Beni Suef block is part of the former Faiyum-Agila exploration block (operated by Braspetro, 100%) and relinquishment in October 1978, former ESSOâs East Desert exploration block, relinquished in November 1991, former Qarun exploration block (operated by Shell), relinquished in April 1989 and Northern part of East Beni Suef exploration licence (operated by Apache 33.5%, Sinopec 16.5%, Dana Petroleum 50%), relinquished in January 2016. Some producing field are carved from the Block: West of Nile producing from the Cenomanian Abu Roash reservoir, Azhar producing from Albian Kharita reservoir and Fayoum from Bahariya and Abu Roash reservoirs.","Merlon Petroleum was awarded the North Beni Suef exploration block (Block 5), Gindi Basin onshore basin as a part of the Egyptian General Petroleum Corporation (EGPC) 2018 bid round"
9850,"Tambeyskoye Zapadnoye o/g/c discovery area, Yamal-Nenets AO, W. Siberia, TD 3,820m (M. Jurassic) in Nov â14. Reservoir Yu6 more recently tested 9.6 MMcfg/d from between 3,652-3,689m on 10mm choke, other reservoirs tested at lower rates and well to be P+Aâd. Â ",Russia (South Kara - Yamal Province (West Siberian B.)) Tambeyskoye Zapadnoye
50751,"ConocoPhillips has withdrawn from PL 120 B, effective from 29 May 2019, transferring its 13% interest to Equinor. The NPD confirmed the transfer on 5 June 2019. PL 120 B covers a 20 sq km area over parts of blocks 34/7 and 34/8 which include the northern areas of Gimle and Sindre. Production from both fields is temporarily shut-in due to low reservoir pressure. At Gimle, plans to drill a new producer are being evaluated. At Sindre, the problems are compounded by the presence of sealing faults in the reservoir which reduce communication, therefore new drainage strategies are under consideration. Gimle was discovered in December 2004 by long-reach well 34/10-48 S, which was drilled for a total length of 7,393 m from the Gullfaks C platform and encountered oil in the Middle Jurassic Brent Group. Gimle was developed using three producers and one water injector and it came onstream in May 2006. Sindre was discovered in early 2017 by exploration well 34/10-55 S (also drilled from Gullfaks C) which proved a 170 m oil and gas column in the Lower Jurassic Statfjord Formation. It has been developed using a single producer. A PDO exemption for the field was granted on 27 March 2017 and the field commenced production in May 2017. Following the withdrawal of ConocoPhillips, interests in PL 120 B are divided between Equinor Energy AS (72.06% + operator), Petoro AS (16.94%) and Total E&P Norge AS (11%).","ConocoPhillips has withdrawn from PL 120 B, transferring its 13% interest to Equinor (-> 72,07%, Petoro 16,94%, Total 11%)"
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. "
47459,"HitecVision confirmed on 23 April 2019 that it is selling 100% of its ownership of CapeOmega to Partners Group in a deal which values CapeOmega at Euro 1.2 billion. Partners Group is one of the largest private markets investment managers in the world, headquartered in Switzerland. The company aims to help CapeOmega further expand its assets, focussing on greenfield developments and brownfield acquisitions. CapeOmega currently owns interests in four NCS licences which contain one producing field (Enoch â 21.8% of the licence, 4.36% of the field) and two abandoned fields (Brynhild â 49% and Oselvar â 45%), and equity in three infrastructure facilities (Gassled â 16.32%, Nyhamna â 13.18% and Polarled â 33.27%). Enoch, operated by Repsol Sinopec, lies mostly in UK waters but extends into Norwegian block 15/5. The field 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 UK Brae A platform located 15 km to the northwest. The field was temporarily shut-in in January 2012 due to a leak in the subsea wellhead and was brought back onstream in December 2015. It has produced intermittently since then and is now in its tail-end phase. Lundinâs Brynhild field was abandoned in May 2018, around 10 years ahead of schedule, as production was no longer profitable. The field had been beset by problems since it came onstream (six months behind schedule) in December 2014 and production declined significantly from 1.6 MMbo in 2015 to just 437,000 barrels in 2017. Estimates of recoverable reserves also declined from an initial 23 MMboe, to 7.4 MMboe reported by Lundin in February 2016 and then to a figure from the NPD in December 2017 of just 5 MMboe. Faroe shut down production from Oselvar in April 2018. The field was abandoned 14 years earlier than planned in the PDO. Falling reservoir pressure much earlier than expected and a high water cut led to decreasing production volumes and a reserves downgrade. Some of the facilities (Oselvar was a subsea tie-back to Ula) have been re-used in the development of the nearby Oda field which came onstream in March 2019. Production from Oselvar started in 2012 and the field had a planned life of 20 years. Gassled encompasses almost all of Norwayâs gas transport systems and is operated by Gassco. Nyhamna is a processing plant, built originally to service Ormen Lange but which, since 2018, also receives gas through the Polarled pipeline. First gas flowed (from the Aasta Hansteen field) through Polarled on 16 December 2018. It has opened up the northerly part of the Norwegian Sea, providing capacity for future field tie-backs.","HitecVision confirmed on 23 April 2019 that it is selling 100% of its ownership of CapeOmega to Partners Group in a deal which values CapeOmega at Euro 1.2 billion. Partners Group is one of the largest private markets investment managers in the world, headquartered in Switzerland. "
36162,Cluff advises a 6-month extn has been granted to the initial term of both wholly-owned P2252 + P2248 in the SNS to 31 May â19. An exclusivity agreement has also been signed with an undisclosed company for P2252 subject to a definitive farmout agreement being entered by 31 Jan â19 and completed by 28 Feb â19. The extension of P2252 was granted in exchange for committing to a seismic and a well (Pensacola prospect) by 28 Feb â19. Â The P2248 extension is subject to Cluff making a firm well commitment by 28 Feb â19.,Cluff advises a 6-month extn has been granted to the initial term of both wholly-owned P2252 + P2248 in the SNS to 31 May â19. An exclusivity agreement has also been signed with an undisclosed company for P2252 subject to a definitive farmout agreement being entered by 31 Jan â19 and completed by 28 Feb â19. The extension of P2252 was granted in exchange for committing to a seismic and a well (Pensacola prospect) by 28 Feb â19. The P2248 extension is subject to Cluff making a firm well commitment by 28 Feb â19.
20433,"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 wellâs 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"
40617,"In mid-January 2019, Belorusneft reported that its wholly owned subsidiary Yangpur made a new oil discovery in the Izvestinskiy license in Yamalo-Nenets Autonomous Okrug (Western Siberia). In the second half of 2018, Yangpur re-entered well Pyakupurskaya 435 drilled in 1986. The original well with TD of 2,831 m was aimed at appraisal of the north-eastern flank of the Komsomolskoye field. Side-track Pyakupurskaya 435s2 with a total length of 2,365 m targeted the Bogdanovskiy prospect located between the Osenneye and Vyuzhnoye fields. It is understood that oil accumulations were identified in the Tyumen Formation Unit Yu2 (Middle Jurassic) and the Vasyugan Formation Unit Yu1 (Upper Jurassic). After applying fracking stimulation, Yangpur tested oil flow at a rate of 584 b/d from reservoir Yu1. The company estimated 2P reserves of the pool at 4 MMbbl of oil. The Izvestinskiy license covers 1,036 sq km in the central part of the Nadym-Taz Province and encompasses the Izvestinskoye, Izvestinskoye Vostochnoye, Metelnoye, Osenneye and Vyuzhnoye fields. In 2018, Yangpur produced 3,860 b/d of oil and the new discovery compensated companyâs production.",Russia (West Siberian B.) ? op. by BELORUSN (100.0%) in Izvestinskiy block
71471,"Hitherto-unreported find in the West Esh El Mellaha (Dev) block, Gulf of Suez onshore, TD 2,136m (basement), oil in the U. Cret. Matulla + Duwi fm's, tested in Aug '19. Esh El Mellaha, = Lukoil-EGPC JV.","Rabeh N.-1 nfw find in the West Esh El Mellaha (Dev) block, Gulf of Suez onshore, TD 2,136m (basement), oil in the U. Cret. Matulla + Duwi fm's, tested in Aug '19. Esh El Mellaha, = Lukoil-EGPC JV."
12812,"GeoPark has announced the successful drilling and testing of the Uaken-1 exploration well in the Fell block (GeoPark operated, 100% WI) in Chile.  GeoPark drilled and completed the Uaken-1 exploration well to a total depth of 3,658 feet. A production test through different chokes in El Salto formation resulted in an average production rate of 0.8 million standard cubic feet per day of gas (or 125 boepd) with a wellhead pressure of 158 pounds per square inch. Additional production history is required to determine stabilized flow rates of the well. Surface facilities are in place and the well is already in production. GeoPark has a long-term contract to sell gas to the large Methanex methanol plant located approx. 100 kms from the Fell block which is connected by a pipeline.  The Uaken gas field discovery in the shallow El Salto formation provides additional low-cost production and creates a new gas play across the Fell block that can be tested in identified leads and prospects. In addition, there are multiple wells in already discovered oil and gas fields within the Fell block that can be re-entered to test this formation.  Original article link Source: GeoPark ","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."
16583,"Inpex has been awarded WA-533-P over 12,402 sq km in WD 50-600m, offshore Canning Basin, offered in the 2016 block release as W16-6. Commitments include G&G, and one well by March 2024.","Brazil (Ceara B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: BAR-M-344 op. by SHELL (50.0%, PETROBRAS 40.0%, PETROGAL 10.0%) to be check.FZA-M-057 op. by TOTAL (40.0%, PETROBRAS 30.0%, BP 30.0%) to be check.BAR-M-344 op. by SHELL (50.0%, PETROBRAS 40.0%, PETROGAL 10.0%) to be check."
18940,"South Disouq block, onshore Nile Delta Basin, TD 2,764m, 30.7m net gas pay in the target Abu Madi, testing planned, well to be connected to the infrastructure adjacent to SD-1X, whose production start is expected 2H â18 (plateau 50 MMcf/d).  1st in planned 4-well programme at South Disouq, to be followed by SD-4X + 3X apprâs and Kelvin-1 nfw (up-dip of SD). SDX (op), partner IPR.","Yunus-1X (Ibn Yunus-1X) South Disouq block, onshore Nile Delta Basin, TD 2,764m, 30.7m net gas pay in the target Abu Madi, testing planned, well to be connected to the infrastructure adjacent to SD-1X, whose production start is expected 2H â18 (plateau 50 MMcf/d). 1st in planned 4-well programme at South Disouq, to be followed by SD-4X + 3X apprâs and Kelvin-1 nfw (up-dip of SD). SDX (op), partner IPR."
30025,"The Ministry of Hydrocarbons, Energy and Mines (Ministère des Hydrocarbures, de lâEnergie 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 lâEnergie 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 lâEnergie 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 lâEnergie et des Mines Direction Générale des Hydrocarbures Directeur : Moustapha BECHIR Tele : +222 422 101 28 E-mail : mobechir@yahoo.fr"
25244,"Chevron USA was awarded Green Canyon Block GC 635 (G36298), situated in the East Texas Coastal Basin, on 1 July 2018. The block was 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 GC 635.","Chevron USA was awarded Green Canyon Block GC 635 (G36298), situated in the East Texas Coastal Basin, on 1 July 2018. The block was 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 GC 635."
63610,"CNH-R03-L01-AS-CS-15/2018 block, offshore Sureste Basin, drilled Oct-Nov '19, oil find, 37m gross pay (36m net) in the Lower Pliocene as well as in the deeper of 2 sands logged in Xaxamani-2EXP, OWC not encountered, Odin JU. PTMD was 2,600m (1,843m TVD). Hokchi (op), partner Talos.",Mexico (Comalcalco Sub-basin (Sureste B.)) Hokchi
12901,"On 18 January 2018, Exxon Mobil Corp signed a PSC to obtain exploration and production rights for the Deepwater Cape Three Points (DWCTP) block, offshore Ghana. The official award is still subject to governmental approval. The new block DWCTP (about 1,500 sq km) will not include the Dzata 2A gas discovery made by Vanco in 2011. It will be located between current blocks operated by PetroGulf, UB Resources and AGM Petroleum, in water depths ranging from 1,550 to 2,850 m. The US Major will hold 80% operated interest in the blocks, the Ghana National Petroleum Corporation (GNPC) will have 15% interest, and a minority partner (5%) is still to be identified. Exxon Mobil CEO Steve Greenlee commented âThe addition of this block reaffirms ExxonMobilâs commitment to pursuing high-quality projects in areas with large resource potential. We are excited to partner with the government of Ghana as we employ our significant upstream experience and technological expertise in assessing the exploration opportunities in this block.â ","ExxonMobil (80% op. GNPC 15%, Local partner 5%) signed for PSC rights to the Deepwater Cape Three Points (DWCTP) block."
57473,"Further to DEA 27 Aug â19: The 7 onshore blocks available since yesterday under the OALP-IV offer have been identified as shown below, following their publication through http://online.dghindia.org/oalp. Bid deadline 31 Oct â19. Listing by block name, basin type and sq km:","OALP-IV blocks The 7 onshore blocks available since yesterday under the OALP-IV offer have been identified as shown below, following their publication through http://online.dghindia.org/oalp. Bid deadline 31 Oct â19. Listing by block name, basin type and sq km:"
72439,"ENI suspended as an oil and gas discovery the Saasken 1EXP directional new-field wildcat (NFW) in the CNH-R02-L01-A10.CS/2017 contract, Area 10 block during early-February 2020 at a final total depth (TD) of 3,830 m. On 17 February 2020, ENI issued a press release and stated the Saasken 1EXP was a discovery with 80 m of good quality net pay in the Lower Pliocene and Upper Miocene and it estimates possible resources of 200 to 300 MMbo in place. After evaluating all of the technical data from the well the operator estimates the discovery well could produce approximately 10 Mbo/d but did not report any potential gas volumes. The NFW was spudded on 20 October 2019. The proposed total depth (PTD) for the NFW was 4,563 m measured depth (MD) and 4,421 m true vertical depth (TVD). The primary targets were the Lower Pliocene and Lower Miocene with secondary targets in the deeper Oligocene and Eocene. The Valaris âEnsco 8505â S/S drilled the well in a water depth of 354 m. The NFW is located in the south-western corner of the block The Saasken 1EXP drilling cost was estimated at USD 51.77 million and abandonment costs were 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 7 May 2019, the CNH approved the drilling permit request submitted by ENI for the Saasken 1EXP NFW. In the CNH-R02-L01-A10.CS/2017 PSC contract, Area 10 block, ENI is the operator with 65% working interest, Lukoil has 20% working interest, and Capricorn holds 15% after formal approvals granted on 19 December 2019. On 25 September 2018, the CNH approved the exploration plan presented by ENI for the CNH-R02-L01-A10.CS/2017 contract, Area 10 block from the CNH-R02-L01/2016 Bid Round.","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."
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 nationâs 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)"
79070,"Total has agreed with Repsol to take over the latter's 22.6% stake in the TFT o&g field, Illizi Basin, SE Algeria. The deal is subject to govt approval. The TFT contract expired in 2019 and was replaced by new terms allowing production (currently 80,000 boe/d) for another 25 years. More devt drilling is planned. Resulting partnership will be Sonatrach-Total 51:49.","Algeria, Tin Fouye"
34816,"SPI is looking to dilute its 100% in PPL 565, 3,970 sq km in the Gulf of Papua, Fly Platform, and retain ab. 20% non-operated.","SPI is looking to dilute its 100% in PPL 565, 3,970 sq km in the Gulf of Papua, Fly Platform, and retain ab. 20% non-operated."
11299,"PetroChina â Xinjiang achieved commercial gas with an appraisal well Dixi 505 in the Kelameili field, Junggar Basin, flowing 4.2 MMcf/d from the Permian Wutonggou Formation. Located in the Dixi 179 well block, Dixi 505 further confirmed the Wutonggou reservoir distribution in Dixi 179 area and indicated potential undeveloped reserves. Background information The Kelameili gas field includes Dixi 14, Dixi 17, and Dixi 18 and Dixi 10 discoveries and has the main reservoir in the Carboniferous. In 2007, 3 Tcf in place gas had been proved with additional 1.6 Tcf of possible gas reserves. With success appraisal work in 2008, a total of approximately 3.7 Tcf of proven gas in place had been confirmed. The Kelameili field was onstream in 2008. By November 2010, the field had 25 wells producing at a rate of 60 MMscfg/d. In 2015, PetroChina drilled several successful wells around Kelameili field which added additional reserves, such as Dixi 189, Dixi 323, Dixi 405, Dixi 406, Dixi 407 and Dixi 106. In 2016 the field produced at a rate of 70 MMcf/d of gas. Â ",China (Junggar B.) Dixi (Kelameili) (Ju) 106 op. by PETCHIN XJ (100.0%) in Kelameili block
26311,"PA_1OGX117MA_PN-T-49 PAD within BT-PN-005 contract, PN-T-049 block A, PTD 1,611m, target Cabeças + Poti fmâs, suspended with gas shows in late Jul â18, no further information.","PA_1OGX117MA_PN-T-49 PAD within BT-PN-005 contract, PN-T-049 block A, PTD 1,611m, target Cabeças + Poti fmâs, suspended with gas shows in late Jul â18, no further information."
23220,"On 8 June 2017 ADX Energy reported it has agreed to buy the 4.7 sq km DEE V-19 Iecea Mare licence from Amromco Energy. This licence is situated within ADX Energyâs E X-10 Parta exploration licence. The deal is valued at USD 35,393 + 5% royalty on production. The companyâs plan is to re-drill two wells - Carpinis 55 and Iecea Mare 35 - to test 33 Bcfg of prospective and contingent resources. The re-drill of Carpinis 55 â which will be named Iecea Mica 2 - is engineered as a simple vertical well. The drilling is planned to start during Q4 2018. The permit is located in western Romania. Amromco was awarded to the company in 2004. The licence contains the Iecea Mare oil and gas field which was discovered in 1985 and put onstream in 1986. Its reservoir is situated below 2,000 m in the Paleozoic. In 1998 the field considered as depleted was shut-in. In 2005 Amromco started gathering information in order to launch field enhancement programme but finally the production at the Iecea Mare field did not resume. Interest in the DEEV-19 Iecea Mare licence will be held solely by ADX Energy Panonia SRL.",ADX Energy reported it has agreed to buy the DEE V-19 Iecea Mare licence from Amromco Energy.
69927,"According to local press reports, quoting Chevron's Corporate Communication Manager, the company has received approval from SKK Migas to open a data room for the Indonesia Deepwater Development (IDD) in the Rapak and Ganal PSCs, located in the Makassar Strait, for potential investors. As of January 2020, there has not been any final selection of partner, who could potentially also assume operatorship and work alongside SKK Migas to realize the IDD project and bring the fields (Gendalo, Gandang and Gehem) onstream. In January 2019, local media reported that Chevron and SKK Migas agreed on a development concept change for the IDD project, from Floating Production Unit (FPU) to Shallow Water Platform (SWP). The change also meant using a higher percentage of local content, resulting in total cost saving to around USD 5 billion, compared to the previous reported figure of USD 6 billion. The authority was hoping to approve the Plan of Development (PoD) following the agreement on change of development concept, and line up work progress such as award and completion of the FEED contract, and submission of the Environmental Impact Assessment document for approval prior to proceeding with the baseline survey. As of end-2018, the reported development concept involved a production capacity of 920 MMcfg/d and 30,000 bc/d. Total combined production is estimated to be around 3 Tcf of gas. In mid-April 2018, local media reported that the company had completed approximately 65% of the pre-FEED study project, with target completion date around mid-2018. Result of the study were to be used in revising the plan of development. Interests in the Rapak and Ganal PSCs are split among Chevron (62%), Eni (20%) and Sinopec (18%). The Rapak PSC will expire in 2027 and the Ganal PSC in 2028. Background Information The second phase of the IDD involves the development of Gendalo, Gandang (Ganal PSC) and Gehem (Rapak PSC) fields. The Maha field (Makassar Strait PSC) field, previously part of the project, has been excluded due to the PSC expiring in 2020 and Chevron not intending to continue to operate the block. The Makassar Strait block was offered for bidding by the government in 2018, but it was not awarded. Chevron submitted a previous POD revision for the IDD project in 2016, but the proposal was sent back by SKK Migas for further modifications. Reportedly, the regulator rejected Chevronâs request for investment credit of 240% for the project, saying that such incentive should not exceed 100%. The revised POD proposed a total investment of less than USD 10 billion, lower than the USD 12 billion estimated in 2013. The operator was initially expecting to produce first gas in 2022 from Gendalo and in 2023 from Gehem. The updated plan also included reserves upgrades and request for contract extensions. Estimated production rates based on the POD revision are 700 MMcfg/d and 20,000 bc/d (from the Gendalo hub) and 420 MMcfg/d plus 27,000 bc/d (Gehem hub). In mid-July 2017, Chevron was reported to have submitted to SKK Migas a proposal to conduct pre-FEED studies for the second phase of the IDD. The plan reportedly called for improved economics and efficiency measures from the previous PoD. The company reportedly completed the study for the development project and submitted proposal to SKK Migas to possibly utilize the existing Floating Production Unit (FPU) at the Jangkrik field, operated by ENI, for the purpose of reducing cost. It was also reported that SKK Migas suggested other options for the development, where Chevron can build its own facility and tap into the Jangkrik field for electric power. Chevron reportedly started its tendering process in looking for a suitable contractor for pre-FEED studies for the second phase of IDD project in early October 2017. The tendering process was reportedly expected to complete around late October or early November 2017, with Pre-FEED work starting after that, for an estimated duration of five months. The approval for the development plan budget was received in early September 2017, as reported by local media, with estimated USD 3.3 million, lower than the previous submitted plan budget of USD 15 million from Chevron. In mid-December 2017, Chevron awarded two contracts for preliminary development studies for the second phase of IDD. The contracts were signed on or around 13 December 2017, first between the operator and Worley Parsons for the feasibility study of engineering work and project design for subsea systems, and second with PT Tripatra Engineering for the scope of production facilities. The purpose of the studies was to find ways to reduce the capital cost and at the same time increase the level of viability for the project. The work studies were likely completed in 2018. The first phase of IDD came onstream in August 2016 with the Bangka field, developed as a subsea tie-back to the West Seno field. The field averaged approximately 90 MMcfg/d and 4,300 bc/d in 2016. According to the initial plan, Gehem and Gendalo would constitute the two production hubs for the second phase, gathering gas respectively from the northern and southern areas of the development. Peak production from the second phase of IDD was initially projected to be 1.1 Bscfg/d and 35,000 bc/d, with at least 25% to be allocated domestically.","According to local press reports, quoting Chevron's Corporate Communication Manager, the company has received approval from SKK Migas to open a data room for the Indonesia Deepwater Development (IDD) in the Rapak and Ganal PSCs, located in the Makassar Strait, for potential investors."
36938,"DNO has taken Shellâs 30% interest in PL 827 S under a deal reported by the NPD on 8 December 2018. The transfer is effective from 30 November 2018. PL 827 S is located to the northwest of Wintershallâs 2015 Syrah discovery, and covers an area of 52 sq km over part of block 35/10. Syrah exploration well 35/11-18 found a 275 m thick Middle Jurassic Brent Group section with light oil columns in the Tarbert Formaton (11 m) and the Oseberg Formation (3 m â the Oseberg Formation is the basal part of the Brent Group in this area of Norway). There was also an 8 m hydrocarbon column in the Upper Jurassic Heather Formation. The well was then sidetracked 450 m to the south (35/11-18 A) and proved gas and oil in two Heather Formation sandstones (33 m and 24 m thick), oil throughout the Brent Group (270 m thick) and a 46 m light oil column in the Cook Formation. The Cook and Oseberg formations were tested and exhibited good flow properties and recoverable reserves were estimated at 6-19 MMbo. PL 827 S is operated by Equinor Energy AS (70%) partnered by DNO Norge AS (30%).",Norway (Oseberg Fault Block (Horda Platform)) Oseberg
78614,"It was reported in April 2020 that Kirthar Pakistan B.V (KPBV), a subsidiary of KUFPEC, has assigned 25% interest in Makhad 3371-19 EL onshore exploration licence in Potwar Basin to Government Holdings Pvt. Ltd (GHPL) which would be effective retrospectively from the date of award â 22 May 2019. As a result of this transaction the revised equity split is as follows: KPBV 75% (operator) and GHPL 25%. The block, covering an area of 1,563 sq km, is located in the Attock, Mianwali and Chakwal districts of Punjab Province and Kohat district of Khyber Pakhtunkhwa Province. KPBV was exclusively awarded the licence on strategic partner basis (government to government basis) with the signing of Petroleum Concession Agreement (PSA) on 22 May 2019. The company had committed to spend at least USD 9.8 million in the block by completing 980 work units during the three-year Phase-I of initial term of the Makhad EL concession. This would be achieved by acquiring either 600 line km (LKM) of 2D seismic data or equivalent work units 3D seismic data and by drilling one exploratory well of over 4,500 m depth. In addition to the minimum work commitment, the company will also spend a minimum of USD 30,000 per year on social welfare schemes in the area. Kirthar Pakistan had submitted the application for Makhad EL on 8 March 2013. It is understood that the company had applied for a larger block area of 2,357 sq km. Five wells are previously known to have been drilled on the acreage which were all proved to be unsuccessful.","Pakistan, Makhad 3371-19"
83196,"28/96/L Ropczyce-Bratkowice-Strzyzów licence, Carpathian Flysch Zone in S. Poland, drilled + compl. gas between 5 Feb â Jun '20, tested TMD 1,862m (1,657m TVD) in early March, Exalo F200 rig. Target Sarmatian-Badenian sst.","(North Carpathian B.) Gnojnica 5K op. by PGNiG (100%) in 28/96/L block, drilled + compl. gas between 5 Feb â Jun '20, tested TMD 1,862m (1,657m TVD) in early March,"
65295,"On 13 August 2019, Total spudded the Richat 1 new field wildcat well in block C-9, deep waters of the MSGBC Basin, central offshore Mauritania. The well is located in the central part of the block in around 2,500 m of water. Operations were finished on 27 September 2019. No results were released. Industry sources suggest that the well did not encounter significant hydrocarbons and that it was plugged and abandoned. It was reported that the Richat structure was related to salt diapirism and that this process possibly also caused a breach of seal. In mid-July 2019 it was reported that Total exercised its option to use the âPacific Santa Anaâ drillship to drill a well in block C-9. The company was to drill the Richat prospect. In early March 2019 industry sources suggested that Total will drill its well in block C-9, deep waters of the MSGBC Basin, central offshore Mauritania with the âPacific Santa Anaâ drillship. The well will be drilled around mid-2019 once the rig comes up from Senegal where it starts work for Total in April. It is not yet known which prospect Total will drill in block C-9. At this stage, the rig slot is an option and probably depends on Total finding a partner to share the drilling risk. In late March 2018 it appeared that Total was planning an exploration well in block C-9. The company was looking for a rig to start drilling in the fourth quarter of 2018. In addition to one firm well, there were to be options for two additional wells. Block C-9 was awarded to Total in 2012, it covers 10,250 sq km and is undrilled. The company completed two 3D seismic surveys over the acreage, one in 2013 and the other in 2017. Total targets Upper Cretaceous turbidite sand channels on the continental slope / basin floor which have been prolific for Kosmos further south with the Tortue, Teranga Marsouin and Yakaar discoveries in Mauritania and Senegal. Recent drilling closer to C-9 also by Kosmos was unsuccessful with the Hippocampe and Lamantin wells in the C-8 and C-12 blocks, respectively, coming up dry. The sands which Total targets in C-9 are related to the Nouakchott river system while the sands containing Tortue and Yakaar/Teranga are related to the Senegal river system. Since it took operatorship of the C-18 block in 2017, Total increased its footprint in the M.S.G.B.C. basin in general and in Mauritania in particular. The company operates now five deep water blocks in the country: C-7, C-9, C-15, C-18 and C-31. The C-18 acquisition joins C-9 and C-7 to constitute a large continuous acreage position totaling over 30,000 sq km. Participants in block C-9 are: Total, operator with 90% and SMHPM with 10%.","TOTAL SA finished Richat 1 well in in block C-9, No results were released. Industry sources suggest that the well did not encounter significant hydrocarbons and that it was plugged and abandoned. It was reported that the Richat structure was related to salt diapirism and that this process possibly also caused a breach of seal."
86917,"Pertamina EP reported in late July 2020 that wildcat Akasia Prima 1 (AKP-1), in the Jawa Bagaian Barat (JBB) PPC, located offshore in West Java, has made oil and gas discovery. The well has probably completed operation however test results have not been reported. In mid-July 2020, local media reported the well was undergoing drill stem test (DST). Spudded in late April 2020, the well reached a total depth of around 2,560 m in mid-June 2020 and was likely targeting the Eocene-Oligocene Jatibarang Formation as well as Lower-Upper Cibulakan Group. Pertamina reported pre-drill resources (P50) of around 75 MMbo and 10.3 Bcfg. In 1H 2020, the operator plugged and abandoned Akasia Besar 2 (ASB-2) and Akasia Besar 3 (ASB-3) as dry wells in the block. ASB-3 was targeting the volcaniclastics zone of the Jatibarang Formation and had a planned total depth of 2,700m. The operator recovered a core section in ASB-2, for the purpose of assessing the quality of the reservoir. In 2016, the operator via contractor Elnusa, acquired a 1,120 sq km 3D seismic survey. The seismic data was acquired to improve the definition of reservoir distribution in the area. ASB-3 was the first appraisal well drilled in the Akasia Besar field which was discovered in 2012. The discovery well Akasia Besar 1 reportedly flowed over 2,200 bo/d and 0.8 MMcfg/d from two DSTs conducted on a carbonate reservoir of the Middle-Upper Miocene Upper Cibulakan Group. It is understood that the first two tests conducted on the Jatibarang Formation did not flow. The Akasia Besar 1 well was brought onstream through a put on production (POP) scheme in 2013. Pertamina is operator and sole interest holder in the JBB PPC.","(West Java B.) Akasia Prima 1 (AKP-1), in the Jawa Bagaian Barat (JBB) PPC, located offshore in West Java, has made oil and gas discovery op. by PERTAMINA (100%) in Jawa Bagian Barat (JBB) block, TD = 1900 m, likely targeting the Eocene-Oligocene Jatibarang Formation as well as Lower-Upper Cibulakan Group."
36986,"It is understood that Petronas Carigali has acquired a 45% participating interest from operator Repsol in the Sakakemang PSC, located onshore South Sumatra, around November 2018. Earlier on 30 August 2018, MOECO agreed to acquire a 10% participating interest in the block from the operator. After governmental approvals of both deals, the new ownership for the Sakakemang PSC will be Repsol (45%, operator, via subsidiary Talisman Sakakemang), Petronas Carigali (45%), and MOECO (10%). As of December 2018, exploration drilling was underway in the block with wildcat Kaliberau Dalam 2X (KBD 2X). It is understood that the operator was preparing to sidetrack the well in late October 2018 after the well experienced loss and kick during operations. KBD 2X was spudded on 20 August 2018. The well is targeting the pre-Tertiary Basement, in line with recent exploration drilling in the block. Previous exploration activity in the block included a 350 sq km survey 3D seismic in late 2015/2016, and one exploration well, Kukulambar 2X, in 2016. The well, likely targeting Lower Miocene carbonates of the Batu Raja Formation and the pre-Tertiary Basement, encountered gas shows. The Sakakemang PSC was awarded to Talisman Energy in 2014. The block is considered as a highly prospective exploration area due to the proximity to producing blocks such as ConocoPhillips' gas-rich Corridor PSC and Pertamina/Talisman Jambi Merang JOA (which will be transferred to Pertamina in 2019). Background Information The Sakakemang block was previously operated by PT Pertamina/ConocoPhillips (Sakakemang) Ltd. JOB under the Sakakemang JOA which was totally relinquished in early 2009. The Sakakemang JOA was awarded to Pertamina and Gulf Resources on 7 December 2001 with contract effective date on 22 November 2001. The working interest split for the JOA was 70% Gulf (then a Conoco subsidiary) and 30% Pertamina. Standard JOA terms apply and signature bonuses totalled USD 2.3 million. The 10-year commitment amount to USD 43 million, with USD 14.5 million assigned for the first three years commitment, consisting of the reprocessing of existing seismic, acquisition of 500 km of 2D seismic and the drilling of two exploratory wells. In late March 2003, ConocoPhillips received BP Migas approval to rename its Gulf Resources subsidiary companies in Indonesia. The move followed the completion of the merger between Conoco Inc and Phillips Petroleum Co on 30 August 2002. Included in the companies renamed was Gulf Resources (Sakakemang) Ltd. The operating company became ConocoPhillips (Sakakemang) Ltd effective 10 October 2002. In 2003, Pertamina and ConocoPhillips spudded vertical wildcat Sumpal North 1 which was suspended as a gas discovery after a flow rate of 5.8 MMcf/d was reported. Targeting fractured pre-Tertiary basement, Sumpal North 1 is located in the western part of the block about 4 km north of the ConocoPhillips operated Sumpal gas field in the adjacent Corridor PSC, that field producing from the same play. The well was drilled following the interpretation of a 513.5 km 2D seismic survey completed between 8 April 2002 and 30 June 2002. In 2004, the same consortium found non-commercial amounts of gas with the Kaliberau Dalam 1 wildcat, which targeted pre-Tertiary Basement and Air Benakat Formation. Also in 2004, Pertamina discovered oil and gas from the Air Benakat Formation with wildcat Kenawang P-1, located on the North Palembang High, about 5 km southeast of Kaliberau Dalam 1. The well had a PTD of 1,700 m and reserves have been quoted at 11 MMbbl of oil. The South Sumatra Basin lies mostly onshore on the island of Sumatra, with a minor proportion extending offshore into the South China Sea. It is delimited by the Barisan-Garba mountain ranges to the south and southwest, and separated from the Central Sumatra Basin by the Tiga Puluh Arch to the northwest. Tertiary sediments onlap the Sunda Platform to the northeast, and the Lampung Platform in the east, which separates the region from the West Java Basin. Deep basinal areas containing over 6,000 m of Tertiary sediments are located onshore. The basin is delineated by several major structural highs. The recently uplifted pre-Tertiary basement of the Barisan-Garba mountain ranges extends the length of the western and southern basin margins. Crystalline basement also outcrops in the Tiga Puluh Arch to the northwest, which separates the South from the Central Sumatra Basin. To the northeast, Tertiary sedimentary cover onlaps the continental margin of the Sunda Shelf, and in the southeast, it is separated from the Sunda-Asri sub-basins of the West Java Basin, by the shallow Lampung Platform. The Talang Akar group of plays represents the most significant play in the basin. It comprises Upper Oligocene-Lower Miocene reservoirs formed by high porosity fluvial, deltaic and coastal transgressive sands. Traps are mainly structural with anticlines and faulted anticlines of Middle Miocene-Pliocene age, but a stratigraphic component occurs where there is shale-out or pinch-out of sand lenses against basement highs. Batu Raja plays are mainly characterised by composite traps with Lower Miocene carbonate build-ups developed on pre-Tertiary structural highs or associated with anticlinal structures. The Air Benakat and Muara Enim plays are regressive shallow marine to littoral reservoir sandstones in anticlinal and/or fault controlled trap structures of Late Miocene-Pliocene age. Basement plays consist of fractured granites, granodiorites, phyllites, quartzites and limestones and are generally gas productive, but yield oil in some fields.",Indonesia (South Sumatra B.) Benakat
66837,"Energean Oil & Gas is offering 40% from its 100% stake in 4219-26 and 4218-30 exploration concession (338 sq km), in the southern Adriatic Sea. Energean acquired 3D seismic over the entire concession in February 2019, and has an outstanding one well commitment. The acreage was offered in the first licensing round and Energean's concession contract was formally signed on 15 March 2017. The seven year exploration period includes commitments to acquire 3D seismic data, drill one firm well (with a further contingent well), and thereby invest at least US$ 19 million (US$ 5 million in the initial phase). Netherland Sewell & Associates has estimated 1.8 Tcfg and 144 MMb oil/condensate P50 unrisked prospective recoverable resources on the Energean acreage. Energean Montenegro Ltd is sole concessionaire.",Not Found
66483,"According to local media reports in early December 2019, Pertamina EP has conducted three drill stem test (DST) in wildcat Tulip Jingga 1 (TJA-1), in the Sungai Gelam area of the Muaro Jambi Regency, located in the Jambi PPC (South Sumatra Basin). The first and second DST recorded oil shows while the third DST reportedly had gas and condensate flow. The company is currently carrying out test evaluations to determine the reservoir potential. TJA-1 was spudded on 12 September 2019 using PDSIâs rig # 41.3 and was targeting a depth of around 2,230 m MD. Purpose of the well is to add new reserves and potentially increase future production from the block. Well operations have been estimated to take around 118 days (likely including testing), with expected completion in late December 2019. Reportedly the potential reserves are estimated to be 11.83 MMboe. The last exploration well drilled in the block was Puspa 3 in early 2017. The well was drilled to a TD of approximately 3,120 m, with at least five DSTs conducted. The well was plugged and abandoned after encountering gas shows. Exploration in the area has focused on shallower sandstones of the Miocene Air Benakat Formation and deeper Talang Akar Formation sandstones along with fractured, weathered Pre-Tertiary igneous basement and granite wash sediments. Good reservoir quality has been observed in the sands locally, but areal extent is limited. Structural plays seem the most common play, with carbonate build-ups and stratigraphic traps seen as minor. As of September 2019, the PPC oil production was reported to be around 2,830 bo/d. The cumulative volume is from 11 fields, namely Kenali Asam, Bajubang, Tempino, Sungai Gelam, Ketaling Barat, Ketaling Timur, Setiti, Bungin Batu, Panerokan and Simpang Tuan. Pertamina operates the Jambi PPC with 100% interest. Background Information A 550 sq km 3D survey covering the Puspa area was conducted wherein a discovery was made in late 2009. This survey was done by Elnusa and the advance party for the survey started in late April 2011 while data recording was from early July 2011 to mid-June 2012. The Puspa 1 (Puspa A) wildcat was suspended in early December 2009 with the well test yielded 31 MMcfg/d plus 630 bc/d but the test intervals were not released. The well, located 13 km northeast of the Sungai Gelam A oil and gas field, was spudded on 14 May 2009 using National's ""80 B"" rig and it was drilled to a TD of 2,876 m, slightly deeper than the PTD of 2,850 m. It targeted sandstones of the Upper Oligocene to Lower Miocene Talang Akar Formation. PT Pertamina EP temporarily suspended the Puspa 2 appraisal well in late May 2015. IHS understands that Puspa 2 was a successful oil and gas appraisal well. Testing operations commenced in early February 2015 after the well reached a total depth of 2,985 m. Puspa 2, situated north of Puspa 1 wildcat, was spudded on 25 November 2014. It had a PTD of 3,000 m, primarily targeting Upper Oligocene to Lower Miocene Talang Akar sandstones. The pre-Tertiary basement could have been a secondary target.","Pertamina EP has conducted three drill stem test (DST) in wildcat Tulip Jingga 1 (TJA-1), in the Sungai Gelam area of the Muaro Jambi Regency, located in the Jambi PPC (South Sumatra Basin). The first and second DST recorded oil shows while the third DST reportedly had gas and condensate flow. The company is currently carrying out test evaluations to determine the reservoir potential."
40094,"Wellesley acquired Aker BPâs 20% interest in PL 871 on 28 December 2018. The deal was announced by the NPD on 16 January 2019. PL 871 covers an area of 150 sq km over parts of blocks 25/1, 25/2, 25/4 and 25/5. Wellesley is planning to drill exploration well 25/1-13 targeting the Balcom prospect in the licence during February 2019 (see separate article). Aker BP is looking to create a development hub in this area with its NOAKA project, and further reserves found at Balcom could strengthen the project economics. The Ministry had initially instructed Aker BP and Equinor to work together to find a common solution for developing the fields in the NOAKA project but both companies had differing ideas and could not agree on a combined way forward. As a result, it is understood that separate solutions can now be moved forward, with concept selections due in early 2019. Following completion of the deal Wellesley Petroleum AS operates PL 871 with a 60% interest. It is partnered by Equinor Energy AS (20%) and LOTOS Exploration and Production Norge AS (20%).","Wellesley (->60%) acquired Aker BPâs 20% (->0%, Equinor 20%, Lotos 20%) interest in PL 871 block."
43536,"Ecopetrol has been granted sole explo rights to the COL 5 unit in the Caribbean, where it now has rights to 6 blocks. Ecopetrol will be seeking to farmout the 4,000-sq km permit, which is adjacent to its Purple Angel and Fuerte Sur blocks in the Sinú Basin. COL 5 had earlier been held under TEA terms. This is the 1st contract signed under the revamped regulatory framework for offshore ops, signed into law last week. Up to another 9 contracts are hoped to be signed in the near future, with TEA conversions likely for Anadarko, Exxon, Repsol + Shell.",Ecopetrol has been granted sole explo rights to the COL 5 unit in the Caribbean.
40822,"On 29 January 2019, the Federal Agency for Subsoil Use held an auction for eight blocks in Bashkortostan Republic (Volga-Ural Province). Nine companies submitted bids and Bashneft, Lukoil-Perm, UDS Neft and Sabunskiy (Udmurtia) emerged as the winners. The companies will obtain 25-year E&P licenses. Â The Amzyanskiy block covers 76 sq km and encompasses four prospects with combined oil resources estimated at 7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 9 MMbbl of oil and 27 Bcf of gas. The starting price amounted to RUB 17.05 million (USD 0.26 million). UDS Neft offered RUB 18.755 million (USD 0.28 million). The Baykinskiy block covers 348 sq km and encompasses six prospects with combined oil resources estimated at 8 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 26 MMbbl of oil and 52 Bcf of gas. The starting price amounted to RUB 19.81 million (USD 0.3 million). Bashneft offered RUB 21.791 million (USD 0.33 million). The Verkhne-Yarkeyevskiy block covers 349 sq km and encompasses nine prospects with combined oil resources estimated at 12 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 10 MMbbl of oil and 17 Bcf of gas. The starting price amounted to RUB 24.95 million (USD 0.38 million). Bashneft offered RUB 39.92 million (USD 0.6 million). The Toshkurovskiy block covers 244 sq km and encompasses three prospects with combined oil resources estimated at 7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 5 MMbbl of oil and 2 Bcf of gas. The starting price amounted to RUB 13.5 million (USD 0.2 million). Lukoil-Perm offered RUB 14.85 million (USD 0.23 million). The Turtykskiy block covers 358 sq km and encompasses eight prospects with combined oil resources estimated at 9 MMbbl and seven oil fields excluded from the offer. Hydrocarbon resources (category D1) of the block are estimated at 8 MMbbl of oil and 1 Bcf of gas. The starting price amounted to RUB 22.47 million (USD 0.34 million). Bashneft offered RUB 296.604 million (USD 4.5 million). The Kushkulskiy Severnyy block covers 424 sq km and encompasses six prospects with combined oil resources estimated at 7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil and 2 Bcf of gas. The starting price amounted to RUB 14.52 million (USD 0.22 million). Sabunskiy offered RUB 15.972 million (USD 0.24 million). The Burayevskiy Zapadnyy block covers 451 sq km and encompasses eleven prospects with combined oil resources estimated at 20 MMbbl and several oil fields excluded from the offer. Hydrocarbon resources (category D1) of the block are estimated at 23 MMbbl of oil and 10 Bcf of gas. The starting price amounted to RUB 51.06 million (USD 0.77 million). Bashneft offered RUB 66.378 million (USD 1 million). The Shakhtauskiy block covers 67 sq km and encompasses the Novo-Berezovskaya prospect with oil resources estimated at 2 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil and 34 Bcf of gas. The starting price amounted to RUB 3.5 million (USD 0.05 million). Bashneft offered RUB 3.851 million (USD 0.06 million).","Russia, not found"
21896,"CNOOC announced on 18 May the signature of PSCs for blocks 22/11 + 23/07 in the Beibu Gulf, South China Sea. Block 22/11 covers 1,663 sq km in WD 40-80m and 23/07Â 1,210 sq km in WD 20-4 m. Husky will operate during the explo phase, CNOOC as customary has the right to take over with 51% in the event of a commercial find.","China, not foundCNOOC announced on 18 May the signature of PSCs for blocks 22/11 + 23/07 in the Beibu Gulf, South China Sea. Block 22/11 covers 1,663 sq km in WD 40-80m and 23/07 1,210 sq km in WD 20-4 m. Husky will operate during the explo phase, CNOOC as customary has the right to take over with 51% in the event of a commercial find."
13505,"On 29 January 2018, Petroil with 100% working interest was granted official awards by the ANP for the REC-T-109, REC-T-119, and REC-T-120 blocks in the onshore Reconcavo Basin from the ANP Round 14.  ","Petroil with 100% working interest was granted official awards by the ANP for the REC-T-109, REC-T-119, and REC-T-120 blocks in the onshore Reconcavo Basin from the ANP Round 14. "
73303,"Further to DEA 19 Feb '20: PL 894, 15km E. of discovery, confirmed P&A'ing dry by the NPD, TMD 4,121m ss (3,816m TVD, Springar fm), Scarabeo 8 SS. Wintershall Dea (op), partners Equinor + Petoro.","6604/05-02 S (Balderbrå) appr. (Wintershall Dea 40% op, Equinor 40%, Petoro 20%) in PL 894, 15km E. of discovery, P&A dry, encountered only traces of gas across 3 intervals spanning 210m in the U. Cretaceous Springar Fm, of which 140m of sst was of poor reservoir quality and has significantly downgraded the resource estimate for Balderbra g&c disc.The GWC was not found."
27350,"On 8 August 2018 the Dutch Ministry reported it had approved the transfer of Energy06âs 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 Energy06âs 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."
66997,"Canacol Energy, in December 2019, said it will drill an unnamed exploration well in the Middle Magdalena Valley VMM-45 Block in the three-year Phase 1 period, after it secured the acreage in Colombia's latest round. No firm timeline was given. Canacol will also carry out geological studies on the block that it obtained in December 2019 at the Agencia Nacional de Hidrocarburos (ANH) Phase II of the Permanent Process of Assignment of Areas, or PPA. The company picked up two other blocks at the process: VIM-33 and VMM-49. Canacol said the company has the option to extend the exploratory work programme by a further three years (Phase 2) on each of the exploration contracts. Canacol is a leading gas player in the country, holding processing capacity of up to 330 MMcf/d.","Canacol is the 1st to confirm the formal award of its rights under the latest ANH Proceso Permanente de Asignación de Ãreas (PPAA) Ciclo 2. Sole rights have been bagged for VIM 33 (629 sq km) in the Lower Mag B, VMM 45 (503 sq km) in the Middle Magdal B, and VMM 49 (600 sq km) in the Middle Magdal.B)"
10162,"Statoil has been awarded the 133-sq km Bajo del Toro Este licence in the Neuquén Basin, a result fot he GyP Neuquénâs 5th round. The new block lies adjacent to the Bajo del Toro block held by YPF (op) and Statoil, and expands on Statoilâs coverage of Vaca Muerta resources. Statoil (op) 90%, partner GyP. Map below courtesy Statoil: ",Argentina (Northeast Platform (Neuquen B.)) Bajo del Toro
50361,"According to reports in early-June 2019, GeoPark has completed the Jauke 2 deeper pool wildcat (DPW) well on its 100%-held Fell block with gas discovery after the well flowed 5,900 Mscfg/d in the Tobifera Formation during production testing. The well reached its total depth (TD) of 2,952 m (9,685 ft) in March 2019, after it was initially spudded in January 2019 as an outpost well to appraise the Jauke 1 gas discovery in the shallower Springhill Formation that was made in August 2018. The Fell block covers approximately 1,506 sq km of onshore land in the Magallanes Basin. According to reports in late-2018, GeoPark planned to drill two wells on Fell block as part of its 2019 work program. In addition, the company also plans to test an unconventional oil project on the same block in the Estratos con Favrella Formation shale. Background Information GeoPark is the first and largest non-state controlled oil and gas producer in Chile and began operating the Fell block in 2006. Most hydrocarbons in the block are produced from the conventional Lower Cretaceous Springhill Formation and Pliensbachian to Callovian Tobifera Formation, or unconventional tight gas from Paleocene-age Zona Glauconitica Formation.","Jauke 2 in Fell block GeoPark 100% gas discovery after the well flowed 5,900 Mscfg/d in the Tobifera Formation during production testing. The well reached its total depth (TD) of 2,952 m (9,685 ft)"
69449,"Neptune has assigned 20% of its 50% operated stake in northern North Sea PL817 and PL817 B to Source Energy AS, effective 20 December 2019, ahead of the planned Eirik NFW scheduled for Q1 2020. PL817 was awarded in APA 2015 on 5 February 2016, and covers 163 sq km of undrilled acreage in blocks 15/2 and 15/3. PL817 B was awarded in APA 2016 on 10 February 2017, covers 53 sq km on 24/11 and 24/12 and contains previous dry well 24/12-6 S (DNO, 2010, 5,207m). PL817 & PL817 B partners are Neptune Energy Norge AS (30% + Op), OMV (Norge) AS (50%) and Source Energy AS (20%).","Neptune (-> 30% op, OMV 50%) has assigned 20% of its 50% operated stake in PL 817 and PL 817 B to Source Energy."
60883,"On 14 October 2019 Energean Oil and Gas announced that, subject to the completion of its acquisition of Edison Exploration and Production S.p.A, it has subsequently entered into a Sale and Purchase Agreement (SPA) with Neptune Energy Group Holdings Ltd for Neptune to acquire Edison's UK and Norwegian subsidiaries. Cash consideration for the deal is an initial USD 250 million and it will have an effective date of 1 January 2019. A further consideration of USD 30 million could be paid to Energean if the Glengorm discovery (by the end of 2025) or the Isabella prospect (if successful - by the end of 2026), receive field development approval from the Oil and Gas Authority. The deal is subject to regulatory approvals and is expected to complete in 2020. Energean intends to focus its activities in the Mediterranean area and therefore its North Sea assets are considered to be non-core. Energean Oil and Gas announced on 4 July 2019 that it had agreed to acquire Edison Exploration and Production S.p.A. The Greece-based company will acquire the upstream division of Edison, controlled by Franceâs EDF, for a consideration of USD 750 million (to be adjusted for working capital) with an additional contingent consideration of USD 100 million payable upon achievement of the first gas from the Argo and Cassiopea project offshore Sicily, which is expected by 2022. Edison will also keep an 8% royalty on profit production from future discoveries made in Egypt within the North Thekah Offshore and North East Hap'y blocks. In the UK Edison holds interests in three licences â P701, P1820 and P2215 through its subsidiary Euroil Exploration Limited. The company is a partner in the HPHT Glengorm discovery made by CNOOC in early 2019. The 250 MMboe gas condensate discovery is slated for appraisal in 2020. Edison is also a partner in the Total operated Isabella HPHT target which is scheduled to be drilled in Q4 2019 and is another gas condensate target. Edison also holds interest in producing UK fields - Markham, Scott and Telford, Wenlock and Tors which is strategically important to Neptune's operated Cygnus field. In Norway Edison holds interests in 14 licences, five of which it operates. These contain two fields which are under development â Dvalin (118 MMboe gas, due onstream in 2020) and Nova (79 MMboe oil and gas, due onstream 2021) â and four small discoveries (which, according to the NPD, are unlikely to be developed).",United Kingdom (Edale Gulf (Pennine High)) Markham (STOR)
36896,"ZhenHua Oil sub North Petroleum International Company has picked up a 4% stake from CEFC China in the Adco onshore oil concession (11,114 sq km). The authorities have approved the move, which results in Adco (op, 60%), partners BP, Total, CNPC, Inpex, GS Energy + NPIC.","UAE, not found"
80494,"ONGC has reportedly awarded 13 contract areas comprising 49 marginal producing o&g fields to 7 companies in Andhra Pradesh, Assam, Gujarat, + Tamil Nadu. The winners have yet to be reported. It is recalled (DEA 6 May '20) that ONGC had bagged 24 bids for 14 contract blocks comprising 50 marginal fields under its 2019 Marginal Nomination Fields (MNF) round. The offer comprised 64 fields within 17 onshore contract blocks, 3 of which (14 fields) failed to attract a bid.","ONGC has reportedly awarded 13 contract areas comprising 49 marginal producing o&g fields to 7 companies in Andhra Pradesh, Assam, Gujarat, + Tamil Nadu. The winners have yet to be reported. It is recalled (DEA 6 May '20) that ONGC had bagged 24 bids for 14 contract blocks comprising 50 marginal fields under its 2019 Marginal Nomination Fields (MNF) round. The offer comprised 64 fields within 17 onshore contract blocks, 3 of which (14 fields) failed to attract a bid."
52213,"Santos secured rights to ATP 2045-P in partnership with Starzap (Shell sub), a 1,211-sq km unit in the Bowen-Surat Basin, on 17 June for 6 years. This was offered as PLR 2018-1-5 last year:","Santos (50%,op) and JV partner Shell (50%) was officially awarded exploration permit ATP 2045"
29326,"On 11 September 2018, Cairn Energy reported that it negotiated an option to acquire a 30% working interest from Total in block C-7, deep waters of the Senegal (M S G B C) Basin, northern offshore Mauritania, following the evaluation of the recently acquired 3D seismic. The target on the block is the Cretaceous turbidite fan play. Cairn can exercise its option upon a well decision based on the current seismic evaluation. The well could be drilled in 2021. In June 2018, Total completed a 3D seismic survey on blocks C-7 and C-18. The survey was acquired with CGGâs Oceanic Sirius seismic vessel, it covered 13,180 sq km in the southern parts of blocks C-7 and C-18. In May 2017, Total was awarded block C-7. Currently participants in the acreage are Total, operator, with 90% and state company SMHPM with 10%. The block covers 7,300 sq km, it is located north of Totalâs block C-9 and BP/Kosmos C-6 and C-12. BP/Kosmos found hydrocarbon shows in the Lamantin 1 wildcat in blocks C-6 / C-12, just south of the block C-7 border, in December 2017. In July 2015 Dana Petroleum, the former operator of the C-7 block, was still in talks with the Mauritania authorities on a validity extension of its block C-7. The Mauritanian authorities who were also open for third party offers on the block eventually selected Totalâs offer. The C-7 block contains four hydrocarbon discoveries: Pelican, Aigrette, Cormoran and Fregate. Dana Petroleum made a gas and condensate discovery with new-field wildcat Pelican 1 in 2004. Dana estimates that the well has discovered about 1 Tcf of gas in-place, with 'technically' recoverable reserves in the range of 600 to 800 Bcf together with 10-13 MMb of associated liquids. As the base of the hydrocarbon-bearing interval was not encountered in the well, these figures could be revised upwards. The Pelican 1 well is located offshore in 1,700 m of water about 150 km north of the Chinguetti field. It reached a TD of 3,825 m. On 7 December 2006, Dana abandoned wildcat Aigrette 1 as an oil discovery. The discovery is considered by the company as being non-commercial. The well found oil in the targeted Cretaceous sandstones. An about 20 m (gross) oil column has been identified from pressure testing and fluid sampling. A sample recovered from this interval has confirmed the presence of oil. Dana advised on 10 January 2011 that it has discovered gas with new-field wildcat Cormoran. Four separate gas columns have been encountered in the well, two adjoining the Pelican discovery, one within the deeper Cormoran prospect and one at the base of the well (Petronia prospect). Stabilised flow rates of 22-24 MMcfg/d were obtained on a 32/64ââ choke over the interval 3,679-3,712 m in the Lower Pelican sands of the Senonian Series. Operator Dana considers that higher rates could have been obtained from the DST had flow not been constrained by sand production. In early February 2014, Dana Petroleum, was reported to have encountered up to 30 m of net gas & condensate and oil pay in multiple Cretaceous sands in the Fregate 1 wildcat. The well encountered gas, condensate and oil pay in good quality multiple sands in the Petronia main target (Santonian to Coniacian) and in the Lower Cormoran (Santonian) target. However, the previously considered as promising deeper turbidite Fregate main target in the Turonian series, contained only non-commercial hydrocarbon shows. The well was plugged and abandoned at TD of 5,426 m. Tullow, Danaâs partner, said this wildcat has achieved an important technical breakthrough by establishing a new oil play in deepwater Late Cretaceous turbidites."," Cairn Energy reported that it negotiated an option to acquire a 30% working interest from Total in block C-7, deep waters of the Senegal (M S G B C) Basin, northern offshore Mauritania, following the evaluation of the recently acquired 3D seismic. The target on the block is the Cretaceous turbidite fan play."
57127,"Sanha Devt Area in Block 0 / Area B, WD 71m, PTD was 5,002m (4,812m TVD), USD 30-million well P&A dry in Jun â19, Ensco 109 JU. Chevron (op), partners Sonangol EP, Total + Eni.","Sanha 105-3X expl/dpw Sanha Devt Area in Block 0 / Area B, WD 71m, PTD was 5,002m (4,812m TVD), USD 30-million well P&A dry. Chevron (op), partners Sonangol EP, Total + Eni."
48034,"Pennine signed an MoU with a yet-undesignated private co. to undertake a business combination transaction for assets in SW Alberta, 50-100% interests involved + operatorship. The 50-sq km assets feature wells + infrastructure. The deal could close by end July.","Pennine signed an MoU with a yet-undesignated private co. to undertake a business combination transaction for assets in SW Alberta, 50-100% interests involved + operatorship. The 50-sq km assets feature wells + infrastructure. "
37999,"On 19 December 2018 the NPD confirmed that Wintershall has transferred its 20% interest in PL 777, PL 777 B, PL 777 C and PL 777 D to OMV (effective 14 December 2018). The Hornet exploration well is due to be drilled in PL 777 in 2019. PL 777 B, C and D cover the Glitne field which was abandoned in 2013 after coming onstream in August 2001. The Hornet exploration well was originally due to be drilled in Q4 2018 but Aker BP confirmed in May 2018, in its Q1 2018 results, that it has delayed the well and it will now be drilled in 2019. The company believes that the prospect contains recoverable reserves ranging from 17-166 MMboe and that, if successful, it could be developed as a tie-back to Ivar Aasen. Following completion of the deal interest in PL 777, PL 777 B, PL 777 C and PL 777 D is now divided between Aker BP ASA (40% + operator), Petoro AS (20%), Var Energi AS (20%) and OMV (Norge) AS (20%).","Wintershall has transferred its 20% interest in PL 777, PL 777 B, PL 777 C and PL 777 D to OMV. Following completion of the deal interest is now divided between Aker BP ASA (40% + operator), Petoro AS (20%), Var Energi AS (20%) and OMV (Norge) AS (20%)."
25442,"Oil Search has acquired a further 25% stake from ExxonMobil (it already had 30%) in the latterâs PPLs 474, 475, 476 and PRL 39 in the Eastern Foldbelt, onshore Papuan Gulf Basin. Oil Search-funded seismic is already underway here. Exxon (op) 45%, partner Oil Search.","Oil Search (->55%) has bought a 25% stake in the PPLs 474, 475 and 476 and PRL 39 from ExxonMobil (->45% op.)."
34792,"On 12 November 2018, Oil Minister Mohammed bin Khalifa Al Khalifa informed Russian reporters on the sidelines of the ADIPEC conference in Abu Dhabi that Bahrain had awarded Moscow-based JSC Rosgeologia (Rosgeo) a contract to undertake a marine and geological study of its 2017 offshore Khalij Al Bahrain (KAB) unconventional oil and gas discovery. Few details have been released, but the work to commence during 4Q 2018 is presumably intended to evaluate the feasibility of a range of field development scenarios. Rosgeo was founded according to Russian Federation Presidentâs Decree No. 957 of 15 July 2011. The new company is based upon what was Tsentrgeologiya one of the most oldest exploration companies in Russia. The parent company operates multi-industry projects in all eight Federal Districts of Russia. During the ADIPEC conference, it was demonstrating the potential of geothermal energy development in the Middle East.","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."
51010,"On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the G18-B4 onshore exploration licence in the Zagros Province towards southeast of the country on 28 May 2019. The licence covers around 138 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 G18-B4 exploration licence on 4 February 2019.",TPAO has been awarded the G18-B4 onshore exploration licence in the Zagros Province towards southeast of the country
41278,"On 6 February 2019, Pertamina Hulu Energi (PHE) and regional government-owned company PT Migas Hulu Jabar ONWJ (MUJ) signed an addendum to a previous agreement for the transfer of 10% participating interest (PI) in the Offshore Northwest Java (ONWJ) PSC from PHE to MUJ. The addendum addressed calculations of tax obligations for both partners in relation with the gross split contract for the block. In addition, the regional government via MUJ committed to support upstream activities in the area by simplifying and accelerating the issuance of the necessary permits. The addendum is expected to ensure sustainable long-term cooperation between Pertamina and the local administration in West Java. The addendum is a follow-up of the initial agreement signed on 19 December 2017, whereby PHE transferred the 10% PI to MUJ, in accordance with Regulation of Ministry of Energy and Mineral Resources No. 37/2016. Pertamina Hulu Energi is operator of the block, following a twenty-year extension signed on 18 January 2017. The ONWJ contract was the first to adopt the new Gross Split scheme which was implemented by the government on 16 January 2017. Oil and gas production from the block is being used entirely to support national strategic needs such as fuel, power plants and raw materials for fertilizer production. The latest development in the ONWJ PSC was the SP field, which was brought onstream in October 2018. The field has a production capacity of 30 MMscfd, catering for local consumption. SP was the first field development project carried out under Gross Split fiscal terms. MUJ is a business unit controlled by the Jakarta and West Java provincial governments, and by several regencies in the West Java area. Background Information PT Pertamina and SKK Migas, witnessed by Indonesian Minister of Energy and Mineral Resources, signed an extension for the Offshore Northwest Java (ONWJ) PSC on 18 January 2017. The contract will be valid for 20 years, from 19 January 2017 to 18 January 2037. The final government/contractor split for the new contract was set at 42.5%/57.5% for oil and 37.5%/62.5% for gas. Financial commitments for the first three years of the contract will be USD 82.3 million. Signature bonus to be paid by Pertamina is USD 5 million. Total investment for the 20-year duration of the contract is estimated at around USD 8.5 billion. The ONWJ PSC was originally awarded in 1967. The interest split in the block until 18 January 2017 was Pertamina Hulu Energi with 58.2795%, EMP ONWJ Limited with 36.7205% and Kufpec with 5%.","On 6 February 2019, Pertamina Hulu Energi (PHE) and regional government-owned company PT Migas Hulu Jabar ONWJ (MUJ) signed an addendum to a previous agreement for the transfer of 10% participating interest (PI) in the Offshore Northwest Java (ONWJ) PSC from PHE to MUJ. The addendum addressed calculations of tax obligations for both partners in relation with the gross split contract for the block."
17603,"On 27 March 2018, the consortium of ENI and Lukoil, was granted a preliminary award for the 808 sq km Area 28, G-CS-01 block from the CNH-RO3-LO1/2017 Bid Round. The final official contract signature award is to take place within 90 days or 1 July 2018. The consortium bid the maximum state take of 65.00% over the minimum of 22.5% for the Area 28 block and a work units factor of 1.5 equivalent to two wells. Additionally the company bid a tie-break bonus of USD 59.82 million to win the block representing the highest tie-break bonus offered in the round. The provisional consortium working interest breakdown is estimated to be ENI, operator with 50% working interest, and Lukoil with 50% working interest. There were four other bids for the block. The second highest bidder was the consortium of DEA and Premier who bid 65% state take, 1.5 additional work units factor, and a tie-break bonus of USD 14.17 million.  ","the consortium of ENI and Lukoil, was granted a preliminary award for the 808 sq km Area 28, G-CS-01 block from the CNH-RO3-LO1/2017 Bid Round. "
32493,"Equinor has signed an agreement with PGNiG to sell its non-operated interest in the Tommeliten gas-cond discovery area (42.38% in PL 044 TA, 30% in PL 044) NCS, for USD 220 MM. Conoco operates both tracts.","Equinor has signed an agreement with PGNiG to sell its non-operated interest in the Tommeliten gas-cond discovery area (42.38% in PL 044 TA, 30% in PL 044) NCS, for USD 220 MM. Conoco operates both tracts."
24054,"Beach Energy Ltd spudded the Tourville 1 exploration well in PRL 151, located in the Cooper-Eromanga Basin, on 8 June 2018. The well was drilled by the âSaxon Rig 183â. On 17 June 2018 the operator plugged and abandoned the well, after encountering only gas shows, at a total depth of 2,804 m. The well was one of several exploration wells Beach was undertaking in its Cooper-Eromanga Basin acreage during 2018. PRL 15, which covers an area of 93 sq km, was awarded on 16 December 2014. Beach Energy Ltd holds 100% interest and operatorship, with 50% held through wholly owned subsidiary Great Artesian Oil and Gas Pty Ltd.","Tourville 1 (Beach 100%) in PRL 151 block, P&A, gas shows."
30907,"PT PP Energi has acquired 70% of PT Odira Energi Karang Agung which operates the Karang Agung PSC, located in onshore South Sumatra. According to a company presentation in September 2018, PP Energi is committed to increasing production from the block to 1,000 bo/d. The share acquisition was completed in May 2018, for a cost of approximately USD 3.1 million. The rationale of the transaction was to expand PP Energyâs footprint in Indonesiaâs upstream business. PT Odira Energi Karang Agung holds 85% operating interest in the PSC. Consequently, PP Energi will control an indirect interest of 59.5%. The remaining 15% direct interest in the Karang Agung PSC is held by three local government-owned companies. PT PP Energi is a subsidiary of state-owned construction and engineering company, PT PP (Persero) Tbk. The subsidiary was established in 2016, looking to invest across the energy value chain from upstream to downstream and power, energy financing and commodity trading, in order to support Indonesiaâs energy needs. The Karang Agung PSC contains the Ridho field which started producing oil in February 2017 and reached approximately 280 b/d one month later. Production capacity from the field has been reported at approximately 2,000 b/d. The Plan of Development for the field was approved in 2011, and first oil was originally scheduled for 2013. The project experienced several delays due to issues such as securing the necessary forestry permits. According to local reports in May 2015, Indonesian service company PT Ratu Prabu was planning to acquire 75% interest in the Karang Agung PSC from Odira Energy Persada for a reported price of approximately USD 60 million. However, further reports in August 2015 indicated that Ratu Prabu reconsidered the plan, due to oil price falling below USD 50 per barrel at the time. Background Information The Karang Agung PSC is located in the northern margin of the North Palembang Sub-basin of the South Sumatra Basin. Largely covered by Tertiary sedimentation the basin trends east-west to NW-SE and is primarily in back-arc setting. The oldest tertiary sediments are the Lahat Formation representing syn-rift deposition, with possible lacustrine deposits of Eocene age. This is followed by the Upper Oligocene to Lower Miocene Talang Akar Formation and following further rifting, the build of the Bata Raja carbonates. The latter is not consistent in this area but the former two formations are proven source rock and reservoir in this basin. Odira plugged and abandoned Ridho 1 outpost as an oil and gas well, in late December 2009. The well, which was drilled to appraise the Sinar 1 oil discovery, was spudded in early November 2009 and was drilled to a TD of 1,700m as planned. It targeted sandstones of the Lower Eocene to Middle Oligocene Lemat Formation and Upper Oligocene to Lower Miocene Talang Akar Formation trapped in an anticline structure. Three DSTs were conducted at undisclosed intervals and the well tested a cumulative rate of 3,682 bo/d plus 10.6 MMscfg/d. This was the second commitment well drilled in the block since its award in January 2007. It followed the drilling of Rahmat 1 new pool wildcat.",Indonesia PT Odira Energy Persada Karang Agung PSC - PT PP Energi acquired 70% of operating company
66021,"In early December 2019, Tomskneft-VNK reported a small oil discovery in Tomsk Oblast (Western Siberia). Wildcat Zagornaya 10, drilled in the Pozhevyy license, discovered an oil accumulation in the Vasyugan Formation Yu1 Unit (Oxfordian). Recoverable 3P reserves of the discovery, named after local geologist Yu. A. Chikishev, are estimated at 9 MMbbl of oil. The Pozhevyy block covers 2,009 sq km in the Kaymys-Vasyugan Province and encompasses several small oil discoveries. Tomskneft-VNK is equally owned by Gazprom Neft and Rosneft.","Russia, not found"
78641,"CFD 28-1-1d completed in late April 2020 without result reported. CNOOC â Tianjin spudded a new-field wildcat CFD 28-1-1d in Bohai offshore, Bohai Gulf Basin on 28 March 2020. The well is located in the south of Boxi Block in the western part of the Bohai Gulf, in a water depth of approximately 15 m. The well is targeting the Mio-Oligocene clastic play. âHYSY 932â J/U is used for the drilling operation. There are few wells drilled around this area. CFD 22-2-1 was drilled in 2006 with uncommercial oil flow tested in the Shahejie Formation. CFD 23-3-1 was drilled in 2004 as a dry hole. CFD 23-1-1 was drilled in 1989 with a result of low oil flow tested. The well also near onshore Chengdao field, located in shallow water transitional zone in the Jiyang Depresion operated by Sinopec Shengli. The Chengdao field has its main reservoir in the Guantao and Dongying and Shahejie formations of the Tertiary, secondary reservoir in the Ordovician buried hill. The field holds about 440 million tons of oil in place and produced at a rate about 7,000 b/d of oil.",China (Chengning Uplift (Bohai Gulf B.)) Chengdao (Shengli Complex)
15808,"Fresh from exercising its farmin option to P2235 (Wick prospect, ref. DEA 19 Feb â18), Baron Oil has also acquired a 5% stake from Corallian Energy in offshore P1918 in S. England (Colter discovery). A Colter appraisal is planned mid-2018. Corallian (op), partners Corfe Energy. UOG + Baron. ",Baron Oil has also acquired a 5% stake from Corallian Energy in offshore P1918 in S. England (Colter discovery).
12076,"Calik Petrol Arama Uretim San. ve Tic. A.S. completed the Caliktepe Guney 4 appraisal well in Block 4495, southeast Turkey, in December 2017. The well, which is believed to have had a primary objective in the Ordovician Bedinan Formation, was brought on-stream at a rate of 200 bo/d. Block 4495 was first awarded in 2009 and covers an area of 497 sq km in the Southeast Turkey Zagros Fold Belt. Calik Petrol is 100% owner and operator of the block. Calik also completed the Caliktepe Guney 2 and 3 appraisal wells in the licence area in 2017. The Caliktepe Guney 1 discovery well was completed in March 2016 as an oil producer in the Bedinan Formation. Â ","Caliktepe Guney 4 appraisal well in Block 4495, southeast TurkeyThe well, which is believed to have had a primary objective in the Ordovician Bedinan Formation, was brought on-stream at a rate of 200 bo/d. southeast Turkey "
40925,"PetroRio has agreed to the acquisition from Chevron of the latterâs 51.74% interest + operatorship in the Frade field + 154-sq km lease, Campos Basin, boosting PetroRio's interest here from 18.26% to 70%. Until now, Chevron (op), partners Petrobras + PetroRio.","Brazil, Frade"
39913,"On 29 October 2018, Eni announced that it signed a farm-in agreement with Sonatrach to farm into three exploration blocks in the Berkine Basin, south-eastern Algeria. The contracts are understood to have been approved by government on 27 December 2018. The blocks are: Sif Fatima II, Zemlet El Arbi and Ourhoud II. Interests will be split as follows: Eni 49% and Sonatrach 51%. The blocks are located in the northern part of the Berkine Basin where Eni operates already oil and gas production from several fields in the Sif Fatima area and the Menzel Ledjmet area. The exploration program will include the acquisition of 2,600 sq km of 3D seismic and the drilling of five exploration wells for a total cost of USD 80 million. The development program of already identified resources will include the drilling of 18 development wells, the construction of a 188 km 8-inch condensate pipeline, an oil gathering network tied to the Bir Rebaa Nord facilities and a gas gathering network tied to the Bir Rebaa Nord - Menzel Ledjmet Est gas line for a total cost estimated at USD 1.1 billion. The company recently launched two infrastructure projects to support its development activities: a photovoltaic power plant and a gas pipeline. Under an agreement signed in July 2018, Sonatrach and Eni will aim to create a gas hub in the basin based on the Bir Rebaa Nord and the Menzel Ledjmet Est fields. The idea is to use gas made available from Bir Rebaa Nord (and probably other fields nearby in the future) for export through the Menzel Ledjmet Est gas plant which becomes the center of the hub. Part of the project is the construction of a 180 km gas line which will connect Bir Rebaa Nord and Menzel Ledjmet Est. In March 2017 representatives of Sonatrach and Eni kicked off the construction of the Bir Rebaa photovoltaic (PV) plant at the Bir Rebaa Nord oil field. The plant will cover 20 ha and have a capacity of 10 MW. The electricity generated by the plant will power the oil fieldâs production facilities. This will make available the gas previously used in power generation for a better valorization. Eniâs announced farm in into the three exploration blocks fits the companyâs strategy to develop resources in the Berkine Basin which becomes an important production center. The company estimates that the three exploration blocks, covering together 8,500 sq km, hold reserves of 145 MMb of oil equivalent which should be confirmed through an important exploration program. First production is expected to start by the end of 2020. Eni is currently participating in 32 production permits in the Berkine Basin with a production of 90,000 boe/d net to the company.","On 29 October 2018, Eni announced that it signed a farm-in agreement with Sonatrach to farm into three exploration blocks in the Berkine Basin, south-eastern Algeria."
69285,"69 licences were offered for award yesterday under APA 2019, down from 83 last year as the Barents loses some sparkle. 33 in the North Sea, 23 in the Norwegian Sea + 13 in the Barents Sea to Aker BP, Capricorn, Chrysaor, Concedo, ConocoPhillips, DNO, Edison, Equinor, Idemitsu, Ineos, Lime, Lotos, Lundin, Neptune, OKEA, OMV, ONE-Dyas, Pandion, PGNiG, Repsol, Shell, Source Energy, Spirit, Suncor, Total, VÃ¥r, Wellesley + Wintershall Dea. Equinor received the most licences at 23, followed by VÃ¥r with 17 and Aker BP with 15. Companies must now accept the offers and awards will be made officially in the coming weeks. Assignment details from GEPS, alternatively from the official list and maps here.",APA 2019 Round: 69 licences were offered
73126,"Oranto has revived a farmin opportunity for its Cayar Offshore Shallow block, as well as now also offering equity in St.-Louis Offshore Shallow, total 9,287 sq km in the MSGBC Basin. Data room via Simco Petroleum Management in London. Both blocks are run by Oranto (op) and Petrosen, albeit with different interests.","Oranto has revived a farmin opportunity for its Cayar Offshore Shallow block, as well as now also offering equity in St.-Louis Offshore Shallow, total 9,287 sq km in the MSGBC Basin."
26960,"Yelemes-Ayirshagyl (BNG) contract, Precaspian Basin, TD 4,852m, 350-m sidetrack completed in May, testing ongoing as of early Aug, 75 m of the 121 m identified for testing has been perforated.","Yelemes-801 ST Yelemes-Ayirshagyl (BNG) contract, Precaspian Basin, TD 4,852m, 350-m sidetrack completed in May, testing ongoing as of early Aug, 75 m of the 121 m identified for testing has been perforated"
48914,"In early-May 2019, the provincial oil and gas company of Chubut, Petrominera Chubut, officially launched a call for tenders on the Bella Vista Oeste block through a process called Concurso Publico Nacional e Internacional 02/2019. Offers will be received until 15 August 2019 for a 25-year exploitation concession in the area that is currently being operated by by Interenergy, a subsidiary of CAPSA, under a transitory service contract on behalf of Petrominera. Bella Vista Oeste block covers 217 sq km of land in San Jorge Basin. The block was last operated by Sinopec starting in 2011 before it was returned to Petrominera and the province of Chubut in April 2017 after the area was heavily damaged by a severe weather event. For more information, Petrominera Chubut can be reached via licitaciones@pmch.com.ar or (0297) 4443059. Background Information In Bella Vista Oeste block area, Bella Vista field has produced over 32 MMbo and 5 Bscfg since it was put on stream in 1952 and under recovery since 1999. Meanwhile, Puesto Quiroga field has produced 1.8 MMbo and 835 MMscfg since 1978 and under recovery since 2014.","Argentina, Puesto Quiroga (CGSJ-18 M)"
67400,"On 11 September 2019, BW Energy Gabon Pte Ltdâs partner Panoro announced that the wildcat Dussafu Hibiscus Marin 1 (DHIBM-1) intersected 33 m of hydrocarbon sands in the Gamba formation with porosities ranging between 21% and 23%. The well was spudded around 12 August 2019 was drilled to a TD of 3,538 m MD in the Ruche EEA (Dussafu) permit. The results of DHIBM-1 are highly encouraging and Hibiscus Updip Prospect pre-drill resources of 12 MMbo could be exceeded. Earlier on 30 August 2019 while logging the well Panoro announced that DHIBM-1 had intersected oil likely in the Gamba sandstones and. The sidetrack DHIBM-1ST started at the conclusion of the logging operations to better assess the resources of the discovered structure. The company used the âNorveâ J/U owned by Borr Drilling Ltd, the rig was reported to be on site on 6 August 2019. The jack-up was positioned in 116 m of water depth at about 2 km southwest of existing well Hibiscus Marine 1 (HIBM-1). The latter well was plugged and abandoned with oil shows in the Gamba sandstones by Arco in 1991. The wildcat DHIBM-1 is a vertical well which target was to intersect the Aptian Gamba sandstone in an updip position from HIBM-1. BW Energy Ltd estimated the P50 prospective resources unrisked of the Hibiscus Updip prospect at 12 MMbo. Should the wildcat DHIBM-1 be positive, its resources could be aggregated with those of the existing Ruche and Ruche Northeast accumulations and be the subject of additional phases of development. BW Energy operates the Ruche EEA (Dussafu) permit with 73.5% and partner Panoro 7.5%, GOC 9% and Tullow 10%. Background Information The Hibiscus prospect was tested by Arco in 1991 with the wildcat HIBM-1. The well yielded disappointing results encountering oil shows in the Gamba sandstones but with good permeabilities. BW Energy entered in the Ruche EEA (Dussafu) permit in April 2017 when acquiring the interest of former operator Harvest Natural Resources.",Gabon (South Gabon Sub-basin (Gabon Coastal B.)) Gamba
71788,"Wintershall Dea has signed up the contract for 2018 EGAS round block East Damanhour (Damanhur) (block 10), 1,418 sq km in the onshore Nile Delta, west of the Disoug assets. East Damanhour had been assigned to WD in February last.","Wintershall Dea has signed up the contract for 2018 EGAS round block East Damanhour (Damanhur) (block 10), 1,418 sq km in the onshore Nile Delta, "
32378,"Northern Gulf Petroleum Pte Ltd (NGP) is still inviting proposals to acquire its 10% participating interest in the G01/48 concession located in the Kra Sub-basin (Gulf of Thailand Basin), as of October 2018. The 1,495 sq km block contains the Manora field that was producing approximately 6,285 bo/d in September 2018. The concession is operated by Mubadala Petroleum with 60% interests. The remaining 30% interest is held by Tap Oil. Aside from Manora, the G01/48 block contains the Malida 1 oil discovery and it is believed to contain significant potential for additional discoveries. For additional information, please contact: pantaporn@northerngulfoil.com. The acquisition opportunity was initially reported in mid-September 2015. The last exploration drilling activity in the G01/48 concession was conducted in 12 November 2017, with the objective to extend the Manora field life up to two years. The well is located approximately 10 km northeast of the Manora Production Area. Ladawan 1 was plugged and abandoned with non-commercial oil discovery. No well test has been carried out. Likely future exploration targets in the block will be Middle to Upper Miocene fluvial sandstones trapped in fault-bounded structures, analogous to the discovered fields in the area. Background Information The G01/48 concession was granted to Occidental Exploration Pte Ltd (50%, operator) and partner Syarikat Borcos Shipping Sdn Bhd (50%) in December 2006. In 2007, Occidental registered a company name change to Northern Gulf Petroleum Pte Ltd. Subsequently, Pearl Oil (later acquired by Mubadala Petroleum) acquired the entire 50% stake of Syarikat Borcos plus an additional 10% and operatorship from Northern Gulf Petroleum. In October 2010, Tap Oil acquired an indirect 30% interest in the block via the acquisition of a 75% share of Northern Gulf Petroleum. In 2012, Tapâs indirect interest was converted into direct interest through transfer to subsidiary Tap Energy (Thailand) Pty Ltd. Northern Gulf retained the remaining 10% direct interest. The Manora oil field was discovered via Manora 1 wildcat in mid-December 2009. The discovery was appraised with outposts Manora 2, Manora 3 and Manora 4 in 2010 (two oil wells, one dry). Additional exploration in the block was in late 2012 with dry wildcats Manora 5 (targeting a separate structure to the north of the main Manora field) and Kinaree 1ST1. In late 2013, Mubadala conducted a new drilling campaign with the Malida 1 oil discovery and appraisals Malida 1ST1 (oil shows) and Malida 1ST2 (oil). The Manora field came onstream in November 2014. The field is expected to produce for 11 years at a plateau rate of 15,000 bo/d.",Thailand (Kra Sub-basin (Gulf of Thailand B.)) Malida 1
61739,"PEMEX plugged and abandoned dry the Kenora 1AEXP directional new-field wildcat (NFW) in the AE-0059-3M-Mezcalapa-09 (AE-0142-Comalcalco) entitlement block of the onshore Sureste Basin during mid-October 2019. The CNH reported the well didn't encounter the geological objectives as planned. The NFW replacement wellbore was spudded on 8 December 2018. The well had a proposed total depth (PTD) of 5,828 m measured depth (MD) and 4,820 m true vertical depth (TVD). The fractured Cretaceous was the main objective from 4,480 m to 4,820 m. The CNH issued a drilling permit for the well on 22 March 2018. The original Kenora 1 NFW was junked and abandoned in October 2017 due to unspecified mechanical and geological issues. SENER granted the AE-0059-3M-Mezcalapa-09 entitlement to Pemex 100% through Ronda 0 on 27 August 2014 and it was relinquished on 27 August 2019. It was superseded by the AE-0142-Comalcalco entitlement. The block covers an official area of 1,021.48 sq km. On 3 October 2017, PEMEX junked and abandoned the Kenora 1 directional new-field wildcat (NFW) in the AE-0059 block. The well spudded seven months later than expected and PEMEX did not drill the well to its PTD due to geological and mechanical problems. The well only reached a total depth (TD) of 2,107 m. The NFW was spudded on 10 July 2017. The prospect is located in the southwestern area of the block about 980 m west of the Menta 1 and midway between the Sen and Terra fields. It is also located on the same pad utilized by PEMEX to drill the Kali 1 NFW in 2007. The trap is a 14 sq km closed anticlinal structure bounded by reverse faults. The well will be deviated in a southeast direction at a kick off point (KOP) at 3,870 m. PEMEX estimates 3P reserves for the structure of 48 MMboe. The drilling cost for the well is estimated at USD 15.2 million with exchange rate of 20.5 MXN to 1 USD and completion costs are estimated to be USD 2.1 million. On 15 November 2016, the CNH approved a PEMEX request to modify its AE-0059 block that included changes to its exploration program and an official report regarding the area reduction that was originally granted in November 2015. The exploration plan modification was originally requested by PEMEX in February 2016 but has taken almost eight months for formal approvals due to requests by the CNH for additional information from the operator. The exploration plan modification included no reduction in the number of geological studies of 11 and increasing the amount of re-processing 3D seismic from 0 sq km to 213 sq km. The total estimated investment was reduced from MXN 1,551 million to MXN 469 million. The exploration well commitment was reduced from two to one new-field wildcat (NFW), the Kenora 1 and one appraisal well. The area was reduced from the original 976 sq km to 487 sq km due to environmental and populated areas.","Kenora 1AEXP nfw ( Pemex 100%) in the AE-0059-3M-Mezcalapa-09 (AE-0142-Comalcalco) block, P&A dry."
67550,"On 18 December 2019, Petrobras issued a press release indicating it terminated an Integrated Business Model agreement, related to the Strategic Partnership agreement of 16 October 2018 with CNPC, for 20% working interest in the Campos Basin Marlim, Marlim Leste, Marlim Sul, and Voador production concessions and economic viability studies for the conclusion and operation of the Comperj refinery. The economic viability study indicated that completing the Comperj refinery did not present an attractive economic return and the company is now studying alternatives as to what to do with the refinery. Other press reports indicated that the company may attempt to divest part of its working interest in the Marlim, Marlim Leste, Marlim Sul, and Voador production concessions through its ongoing divestment process. On 16 October 2018, Petrobras issued a press release indicating it signed an Integrated Business Model agreement, related to the Strategic Partnership agreement of 4 July 2018, with CNODC, subsidiary of CNPC, for 20% working interest in four Campos Basin production concessions and economic viability studies for the conclusion and operation of the Comperj refinery. The 20% working interest in four production concessions in the Campos Basin include Marlim, Marlim Leste, Marlim Sul, and Voador. Petrobras would remain the operator with 80% working interest. The agreement also covers both companies and an independent consultant conducting studies of the technical and economic viability to complete the Comperj refinery in the State of Rio de Janeiro.","A 'strategic partnership' agreement reached Oct '18 between Petrobras and CNPC has been terminated. This conferred a 20% stake to CNPC in the Marlim, Marlim Leste, Marlim Sul + Voador leases."
34703,"On 12 November 2018, Eni announced that it had signed an agreement with Mubadala for the sale of 20% stake of the Nour North Sinai (Nour) exploration block, East Nile Delta. The completion of the transaction is subject to the fulfillment of certain standard conditions, including all necessary authorizations from Egyptâs authorities. This signing was made while Eni is drilling ahead the Nour 1 wildcat in the block. Eniâs CEO, Claudio Descalzi, said: âThis transaction strengthens our partnership after the successful relationship in Zohr and confirms Mubadala Petroleumâs trust in Eniâs robustness as operator, both in projects development and exploration activities.â Eni was drilling ahead the Nour 1 wildcat in the Nour exploration block in early November 2018. The well was spudded on 26 September 2018, with Saipemâs âScarabeo-9â S/S in 295 m of water. It has a planned TD of 5,800 m and primary objective in the carbonate/cretaceous play found in the Zohr field. The well will also test the extension of the Pliocene Kafr El Sheikh Formation to the eastern part of Nile Delta as well as the Oligocene play. Eni is the operator of the block with 85% interest and Tharwa Petroleum Company holds the remaining 15%. Background information On 14 August 2018, Eni announced that it was awarded the Nour exploration block in the East Nile Delta. The block, which is located some 50 km offshore, covers 739 sq km in water depths ranging from 50 to 400 m. Eni and partners are committed to spend USD 105 million for the drilling of two wells.","Mubadala has signed an agreement to acquire 20% interest to in the Nour (North Sinai Offshore) block, 739 sq km from Eni (65%, op, Tharwa Petr 15%) in WD=50-400m."
63859,"Further to DEA 8 Nov '19: Chevron has agreed to sell it 45% interest in SC 38 (Malampaya field), 834 sq km in the Northwest Palawan Basin, to Udenna Corp., a deal to be completed 1H '20. Shell (op), partners Chevron + PNOC-EC (who earlier was interested in boosting its 10%).","Chevron has agrred to sell it 45% interest in SC 38 (Malampaya field) (834km²) to Udenna Corp, the price has not been revealed. Prior to the move, Shell (op), partners Chevron + PNOC-EC (who earlier was interested in boosting its 10%)."
16690,"Total SA announced on 18 March 2018 that it had paid US$ 1.15 billion for a 20% stake in a new 40-year concession agreement to operate the offshore Nasr and super giant Umm Shaif oil fields. Eni SpA acquired an initial 10% holding on 11 March 2018, while Abu Dhabi National Oil Company (ADNOC) subsidiary ADNOC Offshore will retain a 60% government working interest. The Supreme Petroleum Council (SPC) approved the creation of a new operating consortium prior to the expiry of the former Abu Dhabi Marine Operating Co (ADMA-OPCO) contract for the ADMA Central Block. The remaining 10% interest has yet to be awarded. ADNOC had confirmed in October 2016 that it planned to combine its two largest offshore operating companies, namely ADMA-OPCO and Zakum Development Company (Zadco) into a single operating unit. It subsequently announced on 15 October 2017 that it had established a new subsidiary âADNOC Offshoreâ to be responsible for the development and delivery of oil and gas resources in Abu Dhabi waters. In launching its new unified brand in line with a 2030 smart growth strategy, ADNOC entered a transition period during which former company names are hereby being referenced for the purposes of clarity and historical integrity. ADMA-OPCO shareholders were ADNOC 60%, BP 14.66%, Total 13.33% and JODCO 12%. ADMA-OPCO was 100% right holder in the ADMA Central Block up until the point that its 45 year ADMA contract expired on 18 March 2018. Background information The 1,303 sq km former ADMA Central concession encompassing both the giant Nasr and super-giant Umm Shaif oil fields expired in March 2018. Although discovered in 1971, the Nasr oil field was only brought onstream during 2015. Early production averaged around 22,000 bo/d during 4Q 2017, but the field is being developed to reach a peak plateau rate of 65,000 bo/d in 2H 2019. Umm Shaif was producing at a rate of around 250,000 bo/d during 4Q 2017. A new oil gathering network is to be commissioned during 2H 2019, which will allow an average production rate of 275,000 bo/d to be sustained until the year 2031. The original Abu Dhabi offshore concession was awarded to D'Arcy Exploration Company in 1953. In 1955 the concession was assigned to ADMA, a company owned by BP and CFP. BP assigned 45% of its interest to Japan Oil Development Company Limited (JODCO) in 1972. In January 1973 ADNOC acquired 25% interest in ADMA Limited. The following January ADNOC increased its shareholdings in ADMA to 60%. ADMA-OPCO was subsequently incorporated in 1977 to operate the ADMA concessions on behalf of the interest holders, ADNOC (60%) and ADMA (40%). In early November 2010, ADMA-OPCO CEO Ali Rashid Al Jarwan re-affirmed the fact that his company intended to increase its offshore oil production capacity to 1.75 million barrels a day (MMbbl/d) by 2019. Â Â ","UAE, not found"
41570,"Marque Oil & Gas is looking for partners to farm into licence P2409 (blocks 206/05a and 206/10a) which contains the Freya and Fulla undeveloped discoveries. Freya is interpreted to hold 35 MMbo mean recoverable resources (141 MMbo STOIIP) and Fulla to contain 25 MMbo STOIIP. Marque is currently interpreting new and existing 3D seismic, reprocessing 100 km of seismic and reprocessing log data. The company plan to acquire new high-density ocean bottom seismic during year 2 and 3 with a drill or drop decision being made before October 2024. Freya and Fulla are located on the Rona Ridge close to the Clair field of which is an analogue to Freya. The Whiting Sands Unit and Clair Group reservoirs are trapped in a dip closure against a fault and sealed by the Cromer Knoll Group. Marque believe the economic success of Freya hinges on finding and drilling into a fracture zone to achieve similar flow rates to Clair. Fullaâs reservoirs consist of the Whiting Sands Unit and Victory Formation trapped from a combination of a pinchout and dip structure. The reservoirs are sealed by the Shetland Group and both discoveries are sourced by the Kimmeridge Clay Formation.  Freya was discovered by Mobil from exploration well 206/10a-1 in 1980 which penetrated oil bearing sands in the Devonian-Carboniferous Clair Group and in the overlying shallow marine Cretaceous Sandstones. Mobil proved a 300 m hydrocarbon column but DSTs were inconclusive as to why the well didnât flow to surface. Freya was deemed a heavy oil discovery due to having APIâs of less than 18° and a high viscosity which lead to Mobil abandoning the licence as the company decided it was sub-commercial. Faroe Petroleum acquired the acreage in 2004 where the company re-interpreted the oil samples and felt there was a possibility that the fluids were closer to 22° API which are found at Clair. Faroe conducted an economic assessment where the minimum economic field size was close to the mean reserve estimate and therefore Faroe would focus on Fulla where the economics were more robust. Fulla was discovered by well 205/5a-3 in August 2011 by Faroe. The well encountered oil in the Cretaceous and Faroe interpreted Fulla as having a breached residual oil column in the Clair Group indicating that the trap was once full. Faroe relinquished the licence due to the economics not meeting its minimum threshold. Interest in P2409 is held solely by Marque Oil and Gas Ltd.",Marque Oil & Gas is looking for partners to farm into licence P2409 (blocks 206/05a and 206/10a) which contains the Freya and Fulla undeveloped discoveries. Freya is interpreted to hold 35 MMbo mean recoverable resources (141 MMbo STOIIP) and Fulla to contain 25 MMbo STOIIP.
11975,"Aker BP completed the acquisition of Hess's Norwegian subsidiary Hess Norge on 22 December 2017. The deal was first announced on 24 October 2017 and is backdated to 1 January 2017. Hess will receive US$ 2 billion cash consideration however Aker BP will benefit from Hess Norge's tax loss carry forward, nominally valued at US$ 1.5 billion after tax. The deal comprises PL033, PL006 B & PL033 B containing the producing Hod and adjacent Valhall oil fields, in the Southernmost Norwegian North Sea on the Norway-Denmark border. Hod production commenced in September 1990 from Late Cretaceous Hod & Tor formations and the Early Paleocene Ekofisk Formation, having original recoverable volumes of 80.8 MMboe and has produced 75.3 MMboe to end 2016. Valhall production commenced in October 1982 from Late Cretaceous Hod and Tor formations, with original recoverable volumes of 1,136.5 MMboe and has produced 899 MMboe to end 2016. The deal also includes 15% in Statoil operated 15th Round 1996 award PL220 (248 sq km) in the Northern most Norwegian Sea, currently under extension after drilling 6710/10-1 (2000, Den norske, 2,267m TVD) which was P&A dry. Hess previously held 64.05% in PL006 B (Hod) and 62.5% in PL033 & PL033 B (Valhall) and after becoming 100% operator Aker BP concluded on the same date the sale of 10% in both licences to Pandion Energy. Hess is also selling its Danish subsidiary which includes 61.5% operator share of South Arne oil field. ","Aker BP (->100%) completed the acquisition of PL 006 B, PL 033, PL 033 B & PL 220 blocks from Hess for US$1,5 billion."
12841,"Location in Murgab sub-basin of Amu-Darya Basin, near the Afghan border in S. Turkmenistan, TD 4,109m, tested 4.1 MMcfg/d + 82 bc/d cond from 2 intvs below 1,920m + 1,942m presumably in the Lower-Middle Jurassic as in the 2000 discovery. ","Tagtabazar-One 16 appr, Location in Murgab sub-basin of Amu-Darya Basin, near the Afghan border in S. Turkmenistan, TD 4,109m, tested 4.1 MMcfg/d + 82 bc/d cond from 2 intvs below 1,920m + 1,942m presumably in the Lower-Middle Jurassic "
78108,"Committed well in Isla Norte block, drilled 1Q '20, TD 2,876m, logged as non-commercial, to P&A. Targets Tobifera + Springhill fm's. GeoPark (op), partner ENAP.","Huillin X 1 nfw. (GeoPark 60% op, ENAP 40%), committed well in Isla Norte block, logged as non-commercial, to P&A. Targets Tobifera + Springhill Fm's. TD=2876m. "
85185,"On 18 June 2020, the ANP board of directors approved a reassignment of working interests on the POT-T-785 Block in the Potiguar Basin. Geopark Brasil Exploração e Produção de Petróleo e Gás is assigning 30% to Petroil Ãleo e Gás on the Round 14 block. Geopark will now have 70% and will continue as operator of the block. The deal is also contingent on Petroil paying its share of the guarantee on the 32 sq km block. The five-year exploration contract for the block is due for expiry on 28 January 2023. The block includes only one historical well, a 1989, Petrobras dry hole drilled in the southwest corner reaching a depth of 2,650m.  ",Not Found
68808,"Caofeidian 2-2-2 (CFD 2-2-2) was suspended on or around 13 November 2019, having intersected oil in the target reservoirs with the production testing of the well having commenced on 15 November 2019 using the ""Haiyangshiyou 282"" jack-up. Caofeidian 2-2-2 was been spudded on or around 29 August 2019, using the ""Zhongyouhai 10"" jack-up. The oil exploration well was likely targeting the Guantao, Dongying and Shahejie formations. Caofeidian 2-2-2 is in the CNOOC operated Boxi Block in the offshore Bohai Gulf Basin. ","Caofeidian 2-2-2 (CFD 2-2-2) was suspended on or around 13 November 2019, having intersected oil in the target reservoirs with the production testing of the well having commenced on 15 November 2019 "
85829,"In early July 2020, Chevron USA acquired deep operating rights in the Hoffe Park discovery, which encompasses contiguous Mississippi Canyon blocks MC 122, MC 165 and MC 166, from Murphy Exploration & Production. The Hoffe Park discovery is located in the Middle Miocene and has a gross resource potential of between 75-120 MMboe, according to figures from June 2019. Murphy encountered oil in multiple zones in appraisal well G34424 1 (Hoffe Park 2), the first Hoffe Park appraisal well drilled during July 2019. Murphy had previously indicated in January 2019 that Hoffe Park, at that time, had a net mean resource potential of 30 MMboe and a net resource upside potential of 48 MMboe. On 27 December 2016, TD was reached in Hoffe Park discovery well G35318 1, which had a bottom-hole location in neighbouring block MC 166 (surface location in MC 122). The Hoffe Park discovery well was described by Murphy CEO Roger Jenkins at the time as âone of the fastest wells Iâve ever seenâ. Following this designation, Murphy E&P remains the operator of MC 122, MC 165 and MC 166 between the surface and 6,248m (20,500 ft). Chevron USA operates all three blocks between 6,248m (20,500 ft) and 30,480m (99,999 ft). Equity in all three blocks at all depths is split between Murphy Exploration & Production â USA (60% WI + Op) and Ridgewood Hoffe Park (40%).","United States (GOM B.), Mississippi Canyon blocks MC 122, MC 165 and MC 166, Chevron USA acquired deep operating rights in the Hoffe Park discovery from Murphy Exploration & Production. The Hoffe Park discovery is located in the Middle Miocene and has a gross resource potential of between 75-120 MMboe, according to figures from June 2019."
43982,"Nour 1 ST1 (Eni 40% op, BP 25%, Mubadala 20%, Tharwa Petroleum 15%) in Nour North Sinai Offshore PSC, 10m of gas pay in Oligocene sand section, primary Cretaceous carbonate objective dry.TD=5913m. (informal ad).","Nour 1 ST1 (Eni 40% op, BP 25%, Mubadala 20%, Tharwa Petroleum 15%) in Nour North Sinai Offshore PSC, 10m of gas pay in Oligocene sand section, primary Cretaceous carbonate objective dry.TD=5913m. (informal ad)."
26810,"Shell has recently farmed-in to onshore Block 42 (Sharqiya) in NE Oman, with the company understood to have also acquired operatorship of the acreage. Prior to the transaction, the block was solely held by Oman Oil Co Exploration & Production LLC (OOCEP), a wholly-owned subsidiary of Oman Oil Co SAOC (OOC). It is unclear at this point how much equity Shell has received in this asset.The move follows the signing of a Heads of Agreement (HoA) between the two companies in April 2017, to collaborate in the exploration of onshore Block 42. Under the terms of the agreement the two companies were to conduct an initial aerial study, before potentially undertaking further and more focused activities in the block. The block covers an area of 25,590 sq km in the NE of the country and is believed to hold hydrocarbon potential in several geological plays. A number of potential exploration leads are understood to have been mapped at Haima, Mid-Lower Nafun, Masirah Bay and Abu Mahara reservoir levels. OOCEP previously stated that the presence of hydrocarbons has already been proven by previous exploration wells, with the most recent having been drilled in 2015. At the time, the company drilled two exploration wells in a back-to-back drilling programme to evaluate the hydrocarbon potential of the Sedrah NW and Rimal al Sharqiya prospects.","Shell has recently farmed-in to onshore Block 42 (Sharqiya) in NE Oman, with the company understood to have also acquired operatorship of the acreage. Prior to the transaction, the block was solely held by Oman Oil Co. E&P."
69775,"On 17 January 2020, Gazprom Neft announced a new deal with Royal Dutch Shell plc in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Their joint venture Salym Petroleum Development (SPD) will acquire a 100% stake at newly created company Salymskiy-2 LLC from Gazprom Neft-Khantos. Prior to the deal, license KhMN02196NR shall be transferred from Gazprom Neft-Khantos, the current license operator, to Salymskiy-2. The Salymskiy-2 license covers 376 sq km in the Ural-Frolov Province and it is adjacent to the Salymskoye Zapadnoye, Vadelypskoye and Verkhnesalymskoye fields developed by SPD. Two wells have been drilled in the license. Also, the operator is in the process of interpretation of recently acquired 3D seismic data. SPD is equally owned by Gazprom Neft and Shell. It must be noted that Gazprom Neft invited Shell to join several projects in Russia. In Western Siberia, two companies may team for development of the Achimov reservoirs in the Yamburgskoye field where Gazprom Neft operates as a contractor for Gazprom. In the Okhotsk Sea (offshore Sakhalin), Shell is invited to explore and develop the Ayashskiy license including the recent Neptune and Triton oil discoveries.","Salym Petroleum, has agreed to buy a 100% stake in Salymskiy 2 (380km²) block from Gazprom Neftâs regional subsidiary, Gazprom Neft Khantos"
14364,"An ONGC Videsh led Indian Consortium has been awarded a 10% stake in the Lower Zakum Concession, offshore Abu Dhabi. The Concession award by the Supreme Petroleum Council (SPC), on behalf of the Abu Dhabi government, to the Abu Dhabi National Oil Company (ADNOC) and the Indian Consortium, is the first time that Indian oil and gas companies have been given a stake in the development of Abu Dhabiâs hydrocarbon resources. The Indian Consortium comprising of Indian Petroleum Sector Public Enterprises is led by ONGCâs international arm ONGC Videsh and includes Indian Oil Corp and the international arm of Bharat Petroleum Corp (Bharat PetroResources). The Indian Consortium will contribute a sign-up bonus of USD 600 million to enter the concession for a 10% stake. The Concession, which has a term of 40 years with an effective date of 9th March 2018, was signed by Shri Shashi Shanker, Chairman, ONGC Group of companies and His Excellency Dr Sultan Ahmed Al Jaber, ADNOC Group Chief Executive Officer, and member of Abu Dhabiâs Supreme Petroleum Council in the presence of Honourable Prime Minister of India Shri Narendra Modi and His Highness Sheikh Mohamed bin Zayed Al Nahyan, Crown Prince of Abu Dhabi and Deputy Supreme Commander of the United Arab Emirates Armed Forces. ADNOC is finalizing the potential partners for the remaining 30% of the available 40% stake in the Lower Zakum Concession earmarked for international oil and gas companies. The current production of this field is about 400,000 bopd and Indian Consortium annual share shall be about 2 MMT. The field profile is to set to achieve plateau target of 450,000 bopd by 2025. Commenting on the Concession award, Shri Shashi Shanker said: 'We are delighted to partner with ADNOC in this important offshore concession. We are hopeful that this historic agreement will lead to further opportunities for Indian oil and gas companies to participate in the UAEâs energy sector. The agreement reflects the vision of the Honourable Prime Minister of India towards strengthening hydrocarbon linkages with the UAE on a win-win basis.' H.E. Dr Al Jaber said: 'Our strategic partnership with ONGC, and the other members of the Consortium, marks a new chapter in the strategic economic relationship between the UAE and India. This mutually beneficial partnership will create opportunities for ADNOC to increase its market share, in the fast-growing Indian market. By delivering high quality crude to Indiaâs expanding refining industry, it will help India meet its growing energy demand. 'This agreement supports ADNOCâs strategy to maximise economic value and recovery from its offshore oil and gas resources. This is an attractive and strategic agreement for both parties that will deliver competitive returns and long term growth opportunities.' The present transaction marks the entry of ONGC Videsh in the highly prospective UAE region and is consistent with its stated strategic objective of adding high quality producing assets to its existing E&P portfolio. Original article link Source: ONGC Videsh ","ONGC Videsh led Indian Consortium has been awarded a 10% stake in the Lower Zakum Concession for US$600 MM. (Total 13,3%)"
8419,"Anadarko has taken over operatorship from ExxonMobil in the ultra-deepwater Hadrian North discovery in Keathley Canyon blocks 918 + 919 (resp. OCS leases G32654 + G21447) retro-effective 1 Jan â17. The deal expands on Anadarkoâs existing adjacent Lucius field unit operatorship, a tie-back of both fields now closer to reality. Â Devt drilling at Hadrian North will start next year, with first oil in mid-2019. Anadarko (op) 48.95%, ExxonMobil 23.29%, Petrobras 16.51%, Teikoku 7.75%, Eni 3.48%. ","ExxonMobil has tranfered its interest in Jambaran Tiung Biru to Pertamina (->90,8%, Local gvt. 9,2%)."
18535,"Block N, Baram Delta - NW Sabah Trough offshore, rumours abound that the ultra-deepwater well was a significant gas discovery, no further information. Mærsk Deliverer SS. Total (op), partners Shell + Petronas.","Tepat 1, Block N, Baram Delta - NW Sabah Trough offshore, rumours abound that the ultra-deepwater well was a significant gas discovery, no further information. Mærsk Deliverer SS. Total (op), partners Shell + Petronas."
67120,"On 6 October 2019, Sonatrach was awarded the Reggane II exploration permit. The award was confirmed by presidential decree on 8 December 2019. It is assumed that the new permit is a re-award of the Reggane Hirane exploration permit, also operated by Sonatrach, which was due to expire in June 2019. The acreage contains four gas discoveries.",Sonatrach (100%) was awarded the Reggane II exploration permit.
16898,"Sebou block, onshore Rharb Basin, location on the downthrown side of main bounding fault in the Ksiri area, TD 1,304m, 5.2m net gas pay across 2 zones in the Guebbas and Hoot fmâs, tested 12.9 MMcfg/d on 40/64â choke (max. 13.5 MMcf/d). Reservoir thickness above pre-drill expectations, avg porosity 33%. Now under pressure build-up after which production testing.",Morocco (Rharb Sub-basin (Rharb-Prerif B.)) Ksiri
32011,"SHESA secured rights to the Lore, Sustraia + Landarre blocks from the regional authorities of the PaÃs Vasco authorities on 9 Oct â18. The awards will become effective a day after publication of the orders in the regional gazette in the coming weeks. The blocks are adjacent and cover resp. 373 sq km, 560 sq km and 373 sq km E. of Bilbao. ShHESA (op), Petrichor Euskadi equal partner.","SHESA secured rights to the Lore, Sustraia + Landarre blocks from the regional authorities of the PaÃs Vasco authorities "
52968,"On 20 June 2019, Mubadala Petroleum plugged and abandoned a new-field wildcat Nong Nuch-1, located offshore in the G11/48 concession, in the Narathiwat Ridge, as a dry well. It is the first well ever drilled in the Narathiwat Ridge. Spudded on 16 June 2019, the well was drilled to a total depth (TD) of 1,015 m using âEnsco 115â J/U, most likely targeting the Middle Miocene fluvial sandstone, an analogy to the producing reservoirs in the adjacent Bongkot and Nong Yao fields. Previously in June 2019, the operator completed an appraisal drilling campaign in the Nong Yao field, on 12 June 2019. Three wells were drilled within 22 days from the same surface location, resulting in mixed outcomes. Spudded on 22 May 2019, Nong Yao 9 and its first sidetrack well were likely plugged and abandoned after having encountered oil, most likely in the targeted Pattani Sequence III reservoir. Subsequently, Nong Yao 9ST2 well was kicked off on 7 June 2019 and abandoned as dry. Interest in G11/48 concession is divided between Mubadala Petroleum (Thailand) Limited (90%, operator) and Palang Sophon (10%). Mubadala increased its stakes in the concession from 67.5% to 90% in June 2018, after acquiring an additional 22.5% interest from previous partner KrisEnergy for a consideration of USD 13.3 million. Background Information The G11/48 concession consists of seven other fields such as Nong Yao (producing under improved recovery regime) Nong Yao C, Nong Yao SW, Angun-1 (appraising) Boondarik-1, Bua Luang-1 and Mantana-1 (discoveries). Pearl Oil (Thailand) Ltd and partners was officially awarded the G11/48 concession on 13 February 2007. The original G11/48 concession covers a surface area of 13,600 sq km, mainly located in Pattani Trough (Gulf of Thailand), with minor portion in the north of Malay Basin and Narathiwat Ridge.","Thailand, G11/48"
68925,"An auction was held 23 Dec '19 for the 57.4-sq km Kamskiy Zapadnyy block in Udmurtia. Dalpromsintez and Flagman Engineering applied, the latter winning the 25-yr rights with a USD 2,000 offer ($1,000 starting price).",Flagman Engineering won Kamskiy Zapadnyy block (55km²) in Udmurtia Republic.
84782,"Saih Rawl field area in block 6, Ghaba Salt sub-basin (Oman Basin), ops terminated 16 May '20, TD 5,299m, rig 50.","Oman (Ghaba Salt Sub-basin (Oman B.)), Saih Rawl N.-1 expl, in in block 06, ops terminated 16 May '20, TD 5,299m, rig 50."
66387,"Formerly Faroe Petroleum, now DNO, announced on 16 January 2019 that it had been awarded of two new Norwegian licences from the APA round, blocks 1/6 and 1/9 and as a result, the company started the process of equalizing interests in two UK blocks â 30/14a and 30/14b which collectively host the cross-border Edinburgh prospect. DNO then completed the acquisition of block 30/14a from Total which completed in April 2019. DNO was then awarded 30th round licence P2401 which contains block 30/14b. In December 2019 Shell and Spirit Energy completed their farm-in to the UK acreage which now equalises interest between the UK and Norwegian licences. Edinburgh is thought to be one of the largest remaining undrilled structures in the Central North Sea. The prospective reservoirs include the Upper Jurassic Ula age-equivalent (Freshney and Fulmar) and Triassic Skagerrak formations. The prospect sits at the south-eastern end of the prolific Josephine Ridge area. It is a large, tilted Mesozoic fault block and covers an area of 40 sq km. The acreage was previously held by Maersk and acquired by Total via the acquisition of the Danish major. Following completion interests in the blocks is held by Shell U.K. Ltd (40% + operator), DNO North Sea (U.K.) Ltd (45%) and Spirit Energy Resources Limited (15%).","Formerly Faroe Petroleum, now DNO, announced on 16 January 2019 that it had been awarded of two new Norwegian licences from the APA round, blocks 1/6 and 1/9 "
85022,"EL 1156, 16km from Bay du Nord discovery in deepwater Flemish Pass Basin, WD 972m, TD ca. 4,000m, reportedly potential commercial oil find (34 API), sidetrack concluded 5 Jul '20, w.o. results, Transocean Barents SS. Target assumed Tithonian as in BdN (43 API oil). Equinor (op), partner BP.","Canada (Flemish Pass B.), Cappahayden K-67Z, operated by Equinor (60%), BP (40%), EL 1156, WD 972m, TD ca. 4,000m, reportedly potential commercial oil find (34 API), sidetrack concluded 5 Jul '20, w.o. results. Target assumed Tithonian as in BdN (43 API oil). "
35086,"As of mid-November 2018, reports suggest that Total was in discussion with Aime Ngoy Mukena (Minister for Hydrocarbons) and Hubert Mihimi (head of SONAHYDROC) over a potential agreement to acquire Block I and II (previously operated by Oil of DRC Sprl). As of June 2018, it is understood that Oil of DRC Sprl (Oil of DRC), a joint venture between Caprikat Ltd and Foxwhelp Ltd and Government were in negotiations for the return of Blocks I and II. According to local sources sanctions imposed on Dan Getler have prevented the mobilization of capital necessary for the continuation of work within Block I and II (Caprikat Ltd and Foxwhelp Ltd are subsidiaries of Gertlerâs Fleurette Group). It is understood that the blocks will be returned to the state with a commitment from the state that the new operator once identified will reimburse the costs incurred by Oil of DRC (estimated at USD 118,8 million). Oil of DRC operates Blocks I & II with an 85% interest, the state oil company, SONAHYDROC hold the remaining 15% and will be carried through exploration. Both blocks were previously held by Tullow.","As of mid-November 2018, reports suggest that Total was in discussion with Aime Ngoy Mukena (Minister for Hydrocarbons) and Hubert Mihimi (head of SONAHYDROC) over a potential agreement to acquire Block I and II (previously operated by Oil of DRC Sprl). As of June 2018, it is understood that Oil of DRC Sprl (Oil of DRC), a joint venture between Caprikat Ltd and Foxwhelp Ltd and Government were in negotiations for the return of Blocks I and II. "
50202,"Mississippi Canyon block 800, WD 950m, 7 MMboe (oil) discovery, subsea tie-back in 4Q â19 through the existing Gladden pipeline to the Medusa spar. Noble Sam Croft DS. Rig then contracted by Apache for a well in block 58, Suriname. This announcement is by partner Kosmos, who also outlines plans to drill the Moneypenny, Oldfield and Resolution prospects by year-end 2019.","MC 800 SS001S1B0 (Gladden Deep) (W&T Offsh 57,50% op, Kosmos 20%, Arena Explo 12,5%, CL&F Res. 10%) in G18292 lease (MC 800 block), WD=950m, ca. 7 MMboe (oil) discovery, in-line with pre-drill estimates, subsea tie-back in 4Q â19 through the existing Gladden pipeline to the Medusa spar."
9595,"Manora oilfield area in G01/48, Gulf of Thailand, TD 2,175m, 3.3m oil column below 2,033m, considered uneconomic and well P&Aâd, Ensco 115 JU released to drill Manora-6. Mubadala (op) 60%, Tap 30%, Northern Gulf Petr. 10%.","Thailand (Gulf of Thailand B.) ? op. by MUBADALA I (60.0%, TAP EN TH 30.0%, NGP 10.0%) in G01/48 block"
76109,"Kampar block in C. Sumatra, P&A gas discovery late Dec '19. Targets assumed Sihapas fm and/or Oligocene clastics.","Bingo 1 nfw. in Kampar block P&A gas discovery, Targets assumed Sihapas Fm. and/or Oligocene clastics."
61789,"According to official reports in mid-October 2019, Echo Energy has signed an agreement to acquire 70% of non-operating interest from Phoenix Global Resources in five Roch-operated blocks in the Santa Cruz Province for USD 7 million in cash and a potentially an additional USD 1.5 million pending on an increase in the proven reserves of said assets by 1 October 2020. The transaction is currently waiting on approval from the provincial government. The blocks consisted of Campo Bremen, Chorrillos, Moy Aike, Oceano, and Palermo Aike, and all situated in onshore and shelf region of Austral Basin. Block Name Basin Name Onshore/Offshore Contract Sqkm Onshore Sqkm Shelf Sqkm Deep Water Sqkm Campo Bremen Austral Basin Onshore 809.16 809.16 Chorrillos Austral Basin Onshore 650.7 650.7 Moy Aike Austral Basin Onshore 728.45 728.45 Oceano Austral Basin Onshore/Offshore 102.73 77.99 24.74 Palermo Aike Austral Basin Onshore 525.13 525.13 Â Background Information In August 2019, daily production in Campo Bremen block was 3.7 MMscfg/d and 92 bo/d, Chorrillos block was 11.1 MMscfg/d and 651 bo/d, Moy Aike was 146 Mscfg/d and 82 bo/d, and Oceano was 2.9 MMscfg/d and 34 bo/d. Meanwhile, the Palermo Aike block only has several discoveries and abandoned fields.","Echo has agreed with Petrolera El Trebol to acquire a 70% stake in 5 mature producing blocks in Santa Cruz Sur, adjacent to Echo's existing Tapi Aike block."
26509,"PUT-14, 464 sq km in onshore Putumayo Basin, Amerisur Resources has signed to acquire 100% interest and operatorship from Gulfsands, with no consideration paid, only a commitment to take over the work programme, which involves 98km of 2D acquisition and an expl well.",Amerisur Resources has struck a farm-in agreement with Gulfsands Petroleum to gain a 100% interest in the Putumayo 14 (Put-14) Block.
46299,"In April 2019 it was confirmed that Warwick Onshore Exploration has left onshore licence EXL 269 which contains Cuadrillaâs Preston New Road wellsite. The companyâs 5% interest has been split between Cuadrilla subsidiary Cuadrilla Elswick (No.2) Ltd (3.3125%) and Spirit Energyâs subsidiary Elswick Energy Ltd (1.6875%). The acreage not only contains the shale gas exploration site at Preston New Road but also the Elswick discovery which is a small Permian gas field producing onsite electricity. Cuadrilla announced in November 2018 that it has seen natural gas flow to surface along with the recycled water from the Shale at its Preston New Road site in EXL 269. Volumes of gas are small and due to operation constraints from micro-seismicity mean that not as much sand has been injected into the shale during the fraccing process as was planned. The company commenced hydraulic fracturing work on 15 October 2018. Fraccing operations were expected to take approximately three months to complete where the company was to frac two wells. On 29 October 2018 Cuadrilla confirmed that three micro-seismic events above 0.5 ML have been recorded at the site with one event measuring 1.1 ML. Following the events an 18 hour pause to fraccing operations was undertaken. On 14 December 2018 Cuadrilla announced that further micro-seismic events had been recorded with the largest reaching 0.9 ML. Cuadrilla again paused operations for 18 hours and the well integrity was checked and verified. On 6 February 2019, Cuadrilla confirmed that flow testing indicated there is the presence of high quality gas in an excellent shale gas reservoir. A complex fracture system was introduced into the shale and when sand was injected into the fractures they have remained in place whilst the gas flowed. The gas has a high methane content so requires minimal processing. Work is not fully completed on testing but during the early stages gas flowed at a stabilised rate of 100,000 scf/d and peaked at 200,000 scf/d. The company has submitted an application to the OGA to allow the wells to be tested fully. If approval is given Cuadrilla expects to commence work later in 2019. The well has been shut-in to allow monitoring and pressure build up. Following completion of the deal interest in the licence is held by Cuadrilla subsidiary Cuadrilla Elswick Limited (46.1875% + operator), AJ Lucas subsidiary Elswick Power Limited (23.75%), Spirit Energy subsidiary (22.75%) and another Cuadrilla subsidiary Cuadrilla Elswick (no.2) Limited (7.3125%)",United Kingdom (West Lancashire Sub-basin (East Irish Sea B.)) Elswick
35676,"Gazprom has reportedly signed an MoU which could lead to exploration of 4 blocks, details of which are elusive for now. Prior to moving further, more complete block data will be required by the company. Meanwhile the South Sudan govt opened yesterday the countryâs 2nd intl o&g conference in Juba. The above was presumably announced yesterday.","South Sudan, not found"
9536,"On 1 November 2017, PETRONAS officially awarded the Production Sharing Contract (PSC) for SK-405B to a consortium of Murphy Sarawak Oil Co, MOECO Oil (Sarawak) and Petronas Carigali (PCSB). The block will be operated by Murphy with 59.5% interest. MOECO will hold 25.5% interest while Petronas Carigali will have the remaining 15% stake. Financial terms of the PSC were not disclosed. The commitments for the PSC will include reprocessing of seismic data and one exploration well during the first three years of exploration period. SK-405B covers an area approximately 2,352 sq. km in the Tatau and Balingian Province and located in water depth ranges from 20 to 50 m. Main exploration targets in this area are the Upper Oligocene to Lower Miocene clastic (Cycle I, II and III). The basement interval potential is untested in the block. The award was made following a competitive bidding exercise where PETRONAS invited bids from upstream companies for these blocks. SK-405B was offered in the 2015 Exploration Opportunity Malaysia by PETRONAS.","Malaysia, not found"
87847,"On July 2020, Cairn Energy plc announced the farm-outs of its 35.1% working interest from the C1, C2, C3 and C4 contracts, which correspond to C1, C2, C3 and C4 blocks, respectively. All blocks are in offshore Sandino Basin (Pacific and Pacific Coastal basins) in water depths ranging 200 m to 1,000 m. The updated players are Equinor Nicaragua Holdings BV (Operator) with 85% working interest and the Empresa Nicaraguense del Petroleo (PETRONIC) with 15% working interest. On 28 May 2015 Statoil was awarded four blocks totaling some 16,000 sq km in the Nicaraguan Pacific. The interest holders in the blocks were Equinor (formerly Statoil) operator with 85% working interest and the Empresa Nicaraguense del Petroleo (PETRONIC) with 15% working interest. On 17 May 2019, Cairn Energy plc announced signed a farm-in agreement with 35.1% working interest in the C1, C2, C3 and C4 contracts, which correspond to C1, C2, C3 and C4 blocks, respectively. The new working interest breakdown were Equinor (operator) with 49.9% working interest, Cairn Energy with 35.1% working interest and the Empresa Nicaraguense del Petroleo (PETRONIC) with 15% working interest.","(Pacific and Pacific Coastal b.) Cairn Energy plc announced the farm-outs of its 35.1% working interest from the C1, C2, C3 and C4 blocks. The updated players are Equinor Nicaragua Holdings BV (85%, op.) and PETRONIC (15%). "
33420,"Gabon is planning the launching of its 12th Shallow and Deepwater Round on 7 Nov â18 at 8:50 during the 25th Africa Oil Week in Cape Town. A technical and fiscal workshop will then be proposed at the Southern Sun Hotel at 11:00 detailing the new petroleum code, round and associated terms, as well as dates and venues of the roadshows supported by Spectrum.","Gabon, not found"
52989,"On 1 July 2019, Gazprom registered a new long-term license offshore Sakhalin. License ShOM16554NR, valid until 1 July 2049, granted exploration and production rights for the Tsentralno-Pogranichnyy block in the North Sakhalin Basin. Based on the current legislation, license was awarded without an auction meaning that Gazpromâs competitor Rosneft was not applying for the area. Tsentralno-Pogranichnyy covers 6,320 sq km south of the Kirinskiy block where Gazprom reported three gas discoveries including giant Kirinskoye Yuzhnoye during the last decade. The area encompasses several big structures which need to be confirmed by 3D seismic. Water depth ranges from 0 m at the Sakhalin coast to 300 m in the east.","Gazprom secured rights to the Tsentralno-Pogranichnyy block (licence ShOM16554NR), 6320km²."
68810,"On 1 January 2020, Occidental Petroleum (Oxy), via its recently acquired subsidiary Anadarko US Offshore, was awarded four Keathley Canyon blocks: KC 778 (G36838), KC 824 (G36842), KC 780 (G36840) and KC 779 (G36839). All four contiguous blocks are sited in the East Texas Coastal Basin and are anticipated to expire on 31 December 2029. Chevron's 2011 Moccasin discovery well, G22367 1, was drilled in adjacent block KC 736, in very close proximity to the northern border of Oxy's newly-awarded KC 780. The Moccasin NFW was drilled to 9,615m and encountered ~115m of net oil pay in the Early Tertiary Wilcox sands. Repsol acquired a 30% WI in the Moccasin discovery from LLOG and Beacon Offshore in June 2019. Following formal award, Anadarko US Offshore (Oxy) is now the operator and sole interest-holder (100% WI + Op) in KC 778, KC 779, KC 780 and KC 824.","Occidental Petroleum (Oxy), via its recently acquired subsidiary Anadarko US Offshore, was awarded four Keathley Canyon blocks: KC 778 (G36838), KC 824 (G36842), KC 780 (G36840) and KC 779 (G36839)."
13870,"Hitherto unreported, Anadarko and Cove Energy have withdrawn from the deepwater Lamu Basin blocks L11A, L11B and L12. Anadarko withdrew as of 31 May â17, leading to Eni taking over operatorship. Cove withdrew in 3Q â17. The partners had been planning to drill the Mlima prospect in in L11B. Current interests: Eni (55%, op), partner Total (45%).","Total has agreed to acquire interests in 3 offshore Guyana Basin blocks, marking its entry into the country: -Canje ,to acquire 35% from JHI Associates - remaining partners ExxonMobil (35%, op) and Mid-Atlantic O&G (30%)"
65096,"Committed well in Emir Oil Concession block, Mangyshlak-Central Caspian Basin onshore W. Kazakhstan, drilled Oct '18 â Feb '19, TD 3,983m, oil intvs in the M. Triassic (T2B) reservoir, currently cleaning-up after perforating, oil recovered. Testing is planned. Targets Middle Triassic T2A, T2B + T2C carbs. Emir Oil = Reach Energy - MIE Holding 60:40","Kariman-16 expl Committed well in Emir Oil Concession block, Mangyshlak-Central Caspian Basin onshore W. Kazakhstan, drilled Oct '18 â Feb '19, TD 3,983m, oil intvs in the M. Triassic (T2B) reservoir, currently cleaning-up after perforating, oil recovered. Testing is planned. Targets Middle Triassic T2A, T2B + T2C carbs. Emir Oil = Reach Energy - MIE Holding 60:40"
51301,"On 17 June 2019, PTT Exploration and Production Public Company Limited (PTTEP) announced the US$ 622 million acquisition of Partex Holding B.V. (Partex) from the Calouste Gulbenkian Foundation. PTTEP President and Chief Executive Officer Phongsthorn Thavisin confirmed that his company's PTTEP HK Holding Limited subsidiary had signed a Share Purchase Agreement (SPA) and expects to complete the deal at the end of 2019. Partex holds interests in the Abu Dhabi, Oman, Kazakhstan, Brazil and Angola, but its history is firmly rooted within the Middle East. Phongsthorn confirmed that âPartex has invested in Omanâs largest onshore oil field(s) for more than 80 years. This acquisition is not only a gateway for PTTEP to invest in one of the strategic areas of the Middle Eastâs oil and gas business, but also allows us to create new business partnership with both national oil companies of Oman and UAE, and world-class oil and gas players as we follow our Expand & Execute strategyâ. According to PTTEP, the Partex acquisition will add 16,000 barrels of oil a day (bo/d) of nett production and approximately 65 million barrels of oil equivalent (MMboe) to 2P company reserves. Partex portfolio summary: ADNOC Gas Processing (AGP): the largest gas processing complex in Abu Dhabi with a total capacity of 8 billion cubic feet per day (Bcf/d). The gas processing plants in which Partex holds a 2% interest have a processing capacity of 1.2 Bcf/d.         PDO (Block 6): the largest onshore producing oil asset in Oman. The primary concession, in which Partex holds a 2% interest encompasses almost 100,000 square kilometers or one third of the countryâs area. PDO produced 610,1700 bo/d in 2018. Mukhaizna (Block 53): Occidental-operated largest producing oil field in Oman. Mukhaizna produced approximately 120,000 bo/d in 2018, accounting for around 13% of the country's total oil production. Partex holds a 1% interest. Oman LNG (OLNG): three liquefaction trains with total LNG production capacity of 10.4 million tons per annum (MMtpa). Oman LNG LLC is the operator of OLNG in which Partex holds a 2% interest. Dunga Project: Total-operated oil field in Kazakhstan producing around 15,000 bo/d. Partex holds 20% interest in the project. Potiguar Project: Partex-operated oil field in Brazil yielding 300 bo/d in 2018. Partex holds a 50% interest. Angola Block 17/06: Total-operated project at pre-FID stage encompassing Gardenia, Begonia, Canna and Forsythia assets. Partex holds 2.5% interest in the project.",Oman (South Oman Salt Sub-basin (Oman B.)) Mukhaizna
82686,"ReconAfrica announces the award of sole rights covering 9,921 sq km in the Kavango Basin in NW Botswana, adjacent to the company's existing licence in NE Namibia. The contract runs 4+10 years, plus 25+20 years production if warranted. ReconAfrica has also entered into a 50% farm-out option agreement with a private company for 3 years term. Release here. Of note, travel restrictions in Namibia will be lifted in July or August, allowing a resumption of work here (3 wells planned as of Oct '20).","(Kavango B), ReconAfrica (100%) announces the award of sole rights covering 9,921 sq km in the in NW Botswana, adjacent to the company's existing licence in NE Namibia. "
63480,"Luda 25-1-2 (LD 25-1-2) was suspended, having intersected oil in the target reservoirs, on or around 25 September 2019 after having been spudded on or around 21 August 2019, using the ""Zhongyouhai 6"" jack-up. The oil appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations with the objective of appraising the easterly extension of the Luda 25-1-1 oil discovery made by CNOOC in March 2019. Luda 25-1-2 is in the CNOOC operated Block 06/17 in the offshore Bohai Gulf Basin and is approximately 2.2km E of Luda 25-1-1. ","Luda 25-1-2 (LD 25-1-2) is in the CNOOC operated Block 06/17 in the offshore Bohai Gulf Basin and is approximately 2.2km E of Luda 25-1-1, was suspended, having intersected oil in the target reservoirs The oil appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations with the objective of appraising the easterly extension of the Luda 25-1-1 oil discovery "
17378,"PL 359, S. of Edvard Grieg in WD 100m, TD 2,450m, better-than-expected 22m gross oil column below 1,947m in Triassic sst, structure gross resource range upped from 30-80 MMboe to 40-100 MMboe, well P&Aâing, Island Innovator SS off to 6/1-28 S (Rolvsnes) appr. Lundin (op), partners OMV, Statoil, Wintershall.","Norway 016/04-11 (Luno II) pos. aprr. by Lundin (, OMV %, Statoil %, Wintershall %) in PL 359, S. of Edvard Grieg, better-than-expected 22m gross oil column below 1947m in Triassic sst, structure gross resource range upped from 30-80 MMboe to 40-100 Mmboe. WD=100m, TD=2450m."
38204,"O&G Development Central Kft. (OGD), domestic subsidiary of Sand Hill Petroleum BV, was selected by the Ministry of Innovation and Technology as the bid winner of the area Körösladány in eastern Hungary, offered during the 2018 tender call that closed in end-October. The pre-award of the block to OGD 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 494 sq km Körösladány area is located within the Nagykunsag, Bihor and Bekes sub-basins, tectonic units of the Pannonian Basin. Background Information The tender call for the Körösladány block was published in the EU Official Journal on 21 June 2018. The closing date of the tender was 26 September 2018. The countryâs 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.",Hungary Sand Hill Petroleum was awarded Körösladány in eastern Hungary.
36023,"Invictus will be looking to farmout SG 4571 in 1H â19. The 650-sq km block lies in the Rufunsa Basin in N. Zimbabwe, run by Invictus with partner Geo Associates.","Invictus will be looking to farmout SG 4571 in 1H â19. The 650-sq km block lies in the Rufunsa Basin in N. Zimbabwe, run by Invictus with partner Geo Associates."
34113,"Add. DEA 26 Sep â18 (content): AE-0009 block, offshore Sureste Basin, WD 43m, P&A dry late Sep â18 at TD 3,730m.","Teca 1DEL (Pemex 100%) in AE-0009-Tucoo-Xaxamani-01 contract, P&A, dry, testing indicated salt water, the primary target was the Upper Miocene Fm. TD=3730m."
78931,"Chengbei 830 flow tested approximately 1,128 bo/d from the Dongying Formation on 11 April 2020 and was completed as an oil producer in late April 2020. The oil appraisal well was spudded in late February 2020 and was drilled to a TD of 3,680m MD in mid-March 2020. Chengbei 830 was targeting the Dongying Formation with the objective of appraising the eastern slope of the Chengbei Low Uplift, Bohai Gulf Basin. Chengbei 830 is in the Sinopec operated Chengdao Block in the nearshore Bohai Gulf Basin. ",Not Found
12740,"Aker BP has been offered interests in 23 new production licenses in Norway, of which 14 as operator, through the Awards in pre-defined areas (APA 2017) licensing round. 'We are very pleased with these awards, which support Aker BPâs growth strategy by giving access to attractive exploration opportunities both around existing production hubs as well as in new prospective areas,' said SVP Exploration, Gro G. Haatvedt. 'We would also like to emphasize that access to new exploration acreage is vital in order to maximize the long-term value creation from the petroleum activity on the Norwegian Continental Shelf,' said Haatvedt. Of the 23 production licenses awarded to Aker BP, 15 are located in the North Sea (11 as operator), 3 in the Norwegian Sea (2 as operator) and 5 in the Barents Sea (1 as operator). The APA 2017 awards were announced by the Ministry of Petroleum and Energy on Tuesday 16 January 2018. In total, 75 licenses were offered to a total of 34 companies. Original article link Source: Aker BP ","Aker BP has been offered interests in 23 new production licenses in Norway, of which 14 as operator, through the Awards in pre-defined areas (APA 2017) licensing round"
78159,"UJO has secured OGA approval for the acquisition of Terrain Energy's 35% interest in PEDL 005(R) (Keddington field) for GBP 200,000 effective 1 Jan '20. It has also taken on Terrain's 15% in PEDL 339 (Louth + North Somercotes prospects), effective 30 Mar '20. Both licences are now run by Egdon (op) + partner UJO. It is recalled Egdon has been seeking to farm down its 45% interest in PEDL 005, 50 sq km mostly onshore in Lincolnshire (E. Midlands, Humber Basin). The acreage contains the Louth prospect.","UJO has secured OGA approval for the acquisition of Terrain Energy's 35% interest in PEDL 005(R) (Keddington field) for GBP 200,000 effective 1 Jan '20. It has also taken on Terrain's 15% in PEDL 339 (Louth + North Somercotes prospects), effective 30 Mar '20. Both licences are now run by Egdon (op) + partner UJO. It is recalled Egdon has been seeking to farm down its 45% interest in PEDL 005, 50 sq km mostly onshore in Lincolnshire (E. Midlands, Humber Basin). The acreage contains the Louth prospect."
48081,"Ecopetrol is on the lookout for partners in its 4,000-sq km COL-5 block in the Caribbean, secured only in March. The permit lies adjacent to its Purple Angel and Fuerte Sur blocks in the Sinú Basin, and had earlier been held under TEA terms. A data room will be available. Meanwhile the company intends to apply for more deepwater rights when ANH offers additional offshore blocks âin the next few weeksâ.","Ecopetrol is on the lookout for partners in its 4,000-sq km COL-5 block in the Caribbean, secured only in March. The permit lies adjacent to its Purple Angel and Fuerte Sur blocks in the Sinú Basin, and had earlier been held under TEA terms"
52879,"Graben Neudorf block, NE of Karlsruhe in NW Germany, reportedly significant oil find, testing underway. Target Pechelbronn beds at ab. 900m.","Steig 1 (Rhein Petroleum 100%) in Graben Neudorf block, NE of Karlsruhe, reportedly significant oil find, testing underway. Target Pechelbronn beds at ab. 900m."
25050,"On 9 July 2018, it was announced that Turkiye Petrolleri A.O. (TPAO) had been awarded three exploration licences, L42-C1,C3,C4, L43-C1,C2 and N51-B on 3 July 2018. The licences have been granted a five year term with an expiry date of 3 July 2023. The licences cover a total area of 1284 sq km in the Southeast Turkey Zagros Fold Belt. TPAO will be 100% owner and operator of the licence.","TPAO had been awarded 4 exploration licences, L42-C1,C3,C4, L43-C1,C2 and N51-B."
42754,"Tongtan 1 was drilled to a TD of 5,086m MD on 30 January 2019 and was suspended for further evaluations in mid-February 2019. The gas exploration well was spudded in September 2018 to drill to a PTD of 5,040m and was targeting the primary objectives of the Cambrian Longwangmiao and Maokou formations and secondary objectives of the Xixiangchi and Xixia formations. Tongtan 1 is in the PetroChina operated Liangxian-Hechuan Block in the Sichuan Basin and is geographically located in Chongqing City, Hechuan County, Sanmiao Town, Fusi Village. ","Tongtan 1 was drilled to a TD of 5,086m MD on 30 January 2019 and was suspended for further evaluations in mid-February 2019. The gas exploration well was spudded in September 2018 to drill to a PTD of 5,040m and was targeting the primary objectives of the Cambrian Longwangmiao and Maokou formations and secondary objectives of the Xixiangchi and Xixia formations. Tongtan 1 is in the PetroChina operated Liangxian-Hechuan Block in the Sichuan Basin and is geographically located in Chongqing City, Hechuan County, Sanmiao Town, Fusi Village. "
30609,"Total has agreed to purchase from Chevron the share capital of Chevron Denmark Inc., itself holding a 12% stake in the Danish Underground Consortium (DUC), 12% in Licence 8/06, and 7.5% in the Tyra West pipeline. The deal is subject to approvals from partners and the relevant authorities. Through this, Total will boost its stake in DUC from 31.2% to 43.2%.",Denmark (Tail End Graben (Central Graben)) Tyra
34596,"EL 2434R (ex-ELs 2431-2434), offshore Scotian Basin, ops terminated (assumed P&Aâing) at TD 7,400m, West Aquarius SS released. âNon-commercialâ quantities of hc encountered. 1st of up to 7 wells planned in this licence. BP (op), partner Hess.","Aspy D-11 (BP 50%,op, Hess 50%) in the former EL 2434, P&A, the probe (1st of up to 7 wells planned in this licence) did not encounter commercial quantities of hc, TD=7400m."
62730,"Sherritt is on the lookout for partners willing to share in block 10 ops, 219 sq km in the Bay of Cardenas. Nfw LT-100 ST is currently en route towards PTD 5,700m, testing planned. Meanwhile Melbana continues its hunt for partners in nearby block 9.","Cuba, Block 9"
25992,"Quadrant Energy Pty Ltd, via subsidiary company, Quadrant Northwest Pty Ltd, spudded the Dorado 1 wet gas exploration well in WA-437-P, located in the Bedout Sub-basin, around 5 June 2018. On 24 July 2018 joint venture partner Carnarvon Petroleum reported that wireline logging and evaluation had been completed, with oil confirmed in the Caley Member, and in addition gas and condensate confirmed in the upper Baxter Member. A 7â liner is now being set, in preparation to drill through the deeper Crespin and Milne members. Carnarvon reported that an âexcellent reservoirâ unit had been encountered within the Caley target, with 79.6 m net pay over a 96.1 m gross interval within the unit. Average porosity of 20%, with 82.5% hydrocarbon saturation and permeability between 100 and 1,000 mD has been measured within the Caley. Light oil has also been recovered to surface as part of the logging and evaluation programme, estimated at 49.6º API. In addition, gas and condensate samples were acquired from the top Baxter unit during the intermediate testing. A total 10.5 m net pay, across a 21 m gross interval, has been estimated. Pressure data acquired has indicated separate hydrocarbon columns within the two units. However additional information would be required on the Baxter to determine its characteristics, as it was not completely drilled through in the Dorado 1 well. Further drilling, into the Baxter, Crespin and Milne Member units is now planned, to evaluate the secondary targets. It is reported that all sands to date are observed to be hydrocarbon charged, with no water saturated sands yet encountered. The forward plan is now to drill through the secondary targets, to a planned total depth of 4,550 m. Fluid sampling and pressure testing is planned once total depth is achieved. Once drilling and evaluation is fully complete, the joint venture plan to offer revised resources estimates Wireline logging was undertaken after the operator drilled the 8-1/2â hole to a depth of approximately 4,044 m. The significance of gas indications observed from cuttings and while logging during drilling warranted the wireline logging programme to be brought forward, having originally been planned on achieving total depth. Previously, in June 2018, Carnarvon reported that elevated gas readings had been observed within a number of Caley Sandstone intervals between 3,853 and 3,947 m. Oil shows were also encountered in the Hove Member. Though Carnarvon reported the Hove would not be tested at this well, it may lead to targets of this interval in future wells. The well is being drilled by the âEnsco 107â J/U rig which arrived onsite around 23 May 2018 and awaited swell conditions to subside before spudding.  The Dorado prospect is located in the centre of WA-437-P, approximately 17 km southwest of Roc 1, and is estimated to cost around AUD 50 million to drill. The prospect is on trend with the Phoenix, Phoenix South and Roc discoveries. Dorado 1 is targeting stacked sands within the Caley Sandstone Member of the Middle Triassic Lower Keraudren Formation as a primary objective. The trapping mechanism of the prospect relies on dip closure and the erosional truncation of the Caley and Milne members by the Dorado Canyon which was subsequently filled by shales that are juxtaposed against the target reservoirs. Mean prospective resources have been reported by joint venture partner Carnarvon Petroleum as 545 Bcf gas and 32 MMb condensate in the Caley 1 sand and potentially 500 Bcf gas and 29 MMb condensate in sands 2 - 5 (average per sand level). The deeper Milne Sandstone Member is considered a secondary target. Carnarvon reported that total Pmean reserves have been estimated in the order of 2.5 Tcf gas and 147 MMb condensate. A discovery at Dorado could lead to a number of development scenarios for the Phoenix area fields. The commitment to drill in WA-437-P lies in Term Six, which was suspended for 18 months from 4 February 2016 following the drilling of the Roc 1 well. The suspension was approved to allow time for the completion and interpretation of the Bilby 2D and Capreolus MC3D seismic surveys before further exploration/appraisal work was considered. Roc 2 was subsequently drilled in July 2016. WA-437-P, which covers an area of 4,871 sq km, was awarded on 4 August 2009. Participants in the permit are: Quadrant Northwest Pty Ltd (80% + Operator) and Carnarvon Petroleum Ltd. (20%).","Australia (Roebuck B.) Dorado 1 (Quadrant 80% op, Carnarvon 20%) in WA-437-P (Greater Phoenix area), 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. Drilling ahead to 4 550m to further evaluate the Baxter sand and the secondary targets in the Crespin and Milne fms."
11731,"Operated assets in Louisiana continue to generate some US$2.5 million pa in free cash after all opex, G&A and taxes AIM-listed President Energy, has announced the disposal of its entire non-operated, non-core beneficial interest in the East White Lake Field, Vermillion Parish, Louisiana, USA, with effect 1 January 2018. The Disposal of this peripheral asset to Alpha Imperial Corp for a total sum of US$525,000 reduces debt and at the same time provides more resources for President to concentrate on its core Argentine assets where production continues to increase with the successful workover programme at the Puesto Flores Field continuing and pilot testing of certain wells at the currently shut-in Estancia Vieja Field planned for Q1 2018. The effect on President of the Disposal is minimal with the Company's continuing share of its operated assets in Louisiana robust and stable, producing approximately 300 boepd, generating annualised free positive cash on current oil prices after all opex, G&A and taxes of some US$2.5 million per annum and the recent Triche operated acquisition performing substantially ahead of expectations. East White Lake Field The Company held a non-operated 25% working interest (21.8% net revenue interest) in the main Field and approximately 2% working and net revenue interest in the 'Houston' well also in the Field. In the calendar year 2017, President is estimated to have received a sum equivalent to approximately US$22k per month from the Field as a whole after opex, not insubstantial Operator Charges but excluding depreciation. Average production for the last 3 months of the year net to President is estimated at approximately 65 boepd and in general is declining with, in President's opinion, no possible significant economic uplift. Reserves at the Field are currently estimated by President at 154 mboe and therefore the Disposal makes no material difference to the Group's overall 1P and 2P reserves which remain at over 16MMboe and 25MMboe respectively. There will also be certain liabilities for de-commissioning and abandonment at the end of life of the Field for what was at one time a significant producing field with a number of wells. Taking into account the above and President's strategy to concentrate on operating its own increasing profitable producing fields, it was decided it was an appropriate time to dispose of the Company's interest in the Field. The Disposal After considering a recent offer from the Operator of a significantly lesser value, President's interest has now been sold to Alpha for the above sum together with the assumption by Alpha of the Liabilities and indemnification of President in respect thereof. Alpha will take over the US$150,000 Surety Bond for the Field, locked up through the Field life. Alpha is a company whose ultimate beneficial owner is Peter Levine, the Chairman and largest shareholder of President Energy, and the purchase price will be satisfied by reducing the sum of US$525,000 from the debt owed by President to IYA Global, another company whose ultimate beneficial owner is Peter Levine. The effect of this is to further lessen the debt and interest burden on the Company, which has already been reduced by the recent US$2 million debt capitalisation of monies owed to IYA thereby freeing up more of the existing financial resources for further growing the profitable Argentine producing assets. Original article link Source: President Energy ",President Energy announces sale of non-operated asset in Louisiana
68251,"On 24 December 2019, the Federal Agency for Subsoil Use held an auction for four blocks in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Several companies including small local enterprises submitted bids. The winners of the auction will obtain 25-year E&P licenses. The Lakhsenturskiy Vostochnyy block covers 50.8 sq km in the Ural-Frolov Province. Seismic coverage amounts to 147 km. Two exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 7 MMbbl of oil. The starting price amounted to RUB 1.327 million (USD 0.02 million). Lukoil- Zapadnaya Sibir offered RUB 1.46 million (USD 0.02 million). The Untygeyskiy Vostochnyy block covers 258 sq km in the Middle Ob Province. Seismic coverage amounts to 270 km. Five exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 67 MMbbl of oil. The starting price amounted to RUB 12.413 million (USD 0.2 million). Petrotek-Neft offered RUB 13.654 million (USD 0.22 million). The Mytayakhinskiy block covers 320 sq km in the Ural-Frolov Province and encompasses parts of the Mytayakhinskoye and Shishkyuganskoye fields with combined 3P reserves estimated at 23 MMbbl of oil. Also, the area includes three prospects with combined oil resources estimated at 12 MMbbl. Seismic coverage amounts to 650 km. Four exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 110 MMbbl of oil. The starting price amounted to RUB 292.79 million (USD 4.72 million). Rosneft-subsidiary Sorovskneft offered RUB 731.975 million (USD 11.8 million). The Okrainnyy block covers 45.7 sq km in the Ural-Frolov Province and encompasses the Okrainnoye field with 3P reserves estimated at 3.4 MMbbl of oil. Seismic coverage amounts to 61 km. Two exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 1 MMbbl of oil. The starting price amounted to RUB 73.732 million (USD 1.19 million). Kunovatskaya Neftegazovaya Kompaniya offered RUB 81.105 million (USD 1.31 million).","Lukoil-Zapadnaya Sibir won Lakhsenturskiy Vostochnyy (50.8km²) in the Ural-Frolov Province, Rosneft sub Sorovskneft won Mytayakhinskiy, (320km²) in the same area, Kunovatskaya Neftegazovaya Kompaniya won Okrainnyy (45.7km²) block in the same area. "
50367,"On 27 April 2019 Equinor used the âTransocean Spitsbergenâ S/S to spud exploration well 6507/3-13 on the Snadd Outer Outer prospect in PL 159 B. TD was reached at 3,420 m and on 3 June 2019 Equinor was abandoning the well. The primary target was the Upper Cretaceous Lysing Formation and there was a secondary target in the Cretaceous Lange Formation named Black Vulture. A sidetrack was potentially planned but it is believed that this will not be drilled. The Snadd Outer Outer prospect lies to the northeast of Snadd Outer which was drilled by BP with 6507/3-9 S in 2012. Snadd Outer has a Lysing Formation reservoir and recoverable reserves at the time of discovery were given as 42-81 Bcfg. The discovery will be brought onstream in Phase II of the Aerfugl development (planned for 2020 / 2021). Aerfugl, which was previously called Snadd, lies to the southwest of Snadd Outer. Aerfugl has estimated recoverable reserves of 975-1,653 Bcfg plus 31-48 MMbc in its Lysing Formation reservoir. Interest in PL 159 B is divided between Equinor Energy AS (53% + operator), DNO through Faroe Petroleum Norge AS (32%) and INEOS E&P Norge AS (15%).","6507/03-13 (Snadd Outer Outer) (Equinor 53% op, DNO 32%, INEOS 15%) in PL 159 B, P&A, results n/a. The primary target was the Upper Cretaceous Lysing Fm and there was a secondary target in the Cretaceous Lange Fm named Black Vulture. A sidetrack was potentially planned but it is believed that this will not be drilled."
28898,"On 1 September 2018 Tailwind Energy completed the acquisition of Shellâs and ExxonMobilâs interest in the Triton Cluster in the Central North Sea. Under the deal Tailwind has acquired 29.26% in licence P361, 64.63% in the unitised Bittern licence, 100% interest in licences P1792 and P233 blocks (029/01a Bittern Area), P013 (021/25a Guillemot W / NW (Upper), 021/30a Guillemot W / NW (Upper), Gannet E and 50% interest in P215. The Triton Cluster comprises of Guillemot NW, Guillemot W, Bittern and Gannet E. Bittern was developed jointly with Guillemot West and Guillemot Northwest as part of the Triton project. The Triton project was initially a subject of controversy as the respective operators of the two blocks it straddled failed to agree on a development scheme. A joint development scheme for the field was finally agreed on 5 November 1997. The solution involved the development of Bittern jointly with Guillemot West and Guillemot Northwest as a subsea development tied back to a new-built FPSO vessel, moored mid-way between the fields. Bittern came on stream on 15 April 2000 and production commenced from the Guillemot Northwest and Guillemot West fields on 20 April 2000. Gannet E is in the process of being redeveloped via a tie-back to three existing wells to the Gannet Alpha platform and then on to the Titron FPSO. Gannet E was shut in, in 2011, but is expected back onstream later in 2018. Following the completion of this deal interest in P361 is held by Dana Petroleum (E&P) Ltd (65.90% + operator), Tailwind Energy Ltd (29.26%) and Endeavour North Sea Ltd (4.84%). In the Bittern unitised licence the interest is held by Dana Petroleum (E&P) Ltd (32.95% + operator), Tailwind Energy Ltd (64.63%) and Endeavour North Sea Ltd (2.42%). In Licences P1792 + P233 (029/01a Bittern Area), P013 (021/25a Guillemot W / NW (Upper) + 021/30a Guillemot W / NW (Upper) + Gannet E, Tailwind holds 100% interest. Lastly in P215 interest in the licence is now held by Dana Petroleum (E&P) Ltd (50% + operator), Tailwind Energy Ltd (50%).","Tailwind Energy has agreed to acquire the entire UK business of EOG Resources, which include 100% in the Conwy field and 110/12a-1 Corfe discovery in the East Irish Sea, a 25% interest in the Columbus gas development and also interest in number of Southern North Sea licences."
63102,"In late October 2019, Badr El Din Petroleum Co (BAPETCO) tested oil after drilling the exploration well Sitra C03-2 in the Sitra (Dev) lease, Abu Gharadiq Basin. After successful testing, the well was rapidly brought onstream at 1,880 bo/d and 4.2 MMscf/d. The well was spudded on 13 July 2019 with the âEDC-51â land rig to a TD of 3,100 m, in the Kharita Member of the Burg El Arab Formation. The operator was targeting Cenomanian pools: the Bahariya Formation as a primary objective and the E and G members of the Abu Roash Formation as secondary objectives. BAPETCO, also named Sitra Petroleum or SIPETCO, is a JV between the EGPC, Shell Australia AG and Shell Egypt NV. The Sitra (Dev) lease was granted to BAPETCO in December 1985. It includes six fields (Sitra 1-1, Sitra 3, Sitra C18-1 ST, Sitra East C4, Sitra 5 and Sitra 8), all discovered by Shell between 1982 and 2019.","Sitra C03-2 in the Sitra (Dev) lease, fter successful testing, the well was rapidly brought onstream at 1880 bo/d and 4,2 MMscf/d."
41369,"Armour is looking to dilute its 100% interests in its licences in the McArthur, Georgina, and Carpentaria (Isa Super Basin) basins, namely EP 171, 174, 176, 190, 191 + 192 in the NT, and ATP 1087-P in QLD. There are also 12 applications lodged between 2009 - 2014 totalling ab. 80,000 sq km. A data room is available to review shale gas plays + shallower conventional plays identified. Background from GEPS.","Australia, ATP 1087-P"
63523,"Equinor Gulf of Mexico, on 1 November 2019, was awarded two Alaminos Canyon blocks, AC 76 (G36736) and AC 197 (G36738), situated in the East Texas Coastal Basin. Both 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. 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 AC 76 and AC 197.",Not Found
71939,"In late January 2020, Arabian Gulf Oil Co (Agoco) reached a total depth (TD) of 2,134 m in the Y-003-47 outpost well (047-Y-001 field) located in the Kotla Graben, onshore in central Sirte Basin. Y-003-47 was spudded on 30 September 2019 with the NWD-6 rig to target Upper Cretaceous (Rakb Group) and possibly Eocene objectives. Agoco has not yet reported the completion and results of the well which reached TD in the Upper Cretaceous Etel Formation. Â 047-Y-001 is an approximately 1 MMbo recoverable oil field discovered by Amoseas Libya in the 1960s. It is located in Agoco's 047 block, next to the Dor Mansour, Beda, Kotla and Haram producing oil fields. Agoco is 100% owned by the National Oil Corporation (NOC).","Arabian Gulf Oil Co (Agoco) reached a total depth (TD) of 2,134 m in the Y-003-47 outpost well (047-Y-001 field) located in the Kotla Graben, "
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."
25370,"PTTEP Australasia Pty Ltd announced on 15 July 2018 that it had signed a sale and purchase agreement, for the sale of its Montara asset to Jadestone Energy (Eagle) Pty Ltd. Under the terms of the sale, Jadestone will purchase PTTEPâs 100% interest in the Montara field and asset for a cost of USD 195 million. The deal is expected to be completed during 2018. In addition to the payment for interest, which will be adjusted to take into account work capital until the completion of the deal, PTTEP will also be eligible for up to an additional USD 160 million for production and development milestones and dependent on oil price changes. The sale and purchase is subject to a number of conditions, including those outlined in the initial sale and purchase agreement and regulatory approvals, including from the National Offshore Petroleum Titles Administrator (NOPTA) and National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA). The Montara field lies in production lease AC/L7, which was awarded on 20 March 2007. The Montara field was discovered in 1988 and has been producing oil since June 2013. The licence also contains the Bilyara oil and Padthaway and Tahbilk gas discoveries, made in 1988, 2000 and 1990 respectively. The gas discoveries had been outlined to be included in PTTEPâs proposed Cash-Maple development. PTTEP reported that the sale of the Montara asset was part of its strategy to focus on operations in other core areas, which at this time were reported to be in Southeast Asia and the Middle East.",PTTEP has sold its 100%-held Montara oilfield off Australia to Jadestone Energy (Eagle) for US$195 MM.
13888,"PetroQuest Energy has announced the sale of its Gulf of Mexico properties on January 31, 2018, but effective as of December 1, 2017. As a result of the sale, the Company has eliminated an approximate $35.4 million undiscounted abandonment liability from its long-term obligations. The Company received no proceeds from the sale of these properties and is required to contribute $3.75 million towards future abandonment costs. In connection with the sale, the Company expects to receive a cash refund of approx. $10.3 million related to a depositary account that served to collateralize a portion of the Company's offshore bonds. All of the Company's production is now derived from assets located onshore Louisiana and Texas.      During the fourth quarter of 2017, the Sold Assets produced approx. 26.1 MMcfe/d (21% oil, 75% gas, 4% NGL). Production from the Sold Assets has declined over the last 60 days as a result of natural declines. The Company estimates net daily production for January 2018 to be approx. 13.8 MMcfe/d (24% oil, 71% gas and 5% NGL), or 47% below the fourth quarter 2017 rate.   As of December 31, 2017, the Company's estimated proved reserves attributable to the Sold Assets totaled approx. 11 Bcfe (100% proved developed) with estimated pre-tax discounted future net cash flows (PV-10) of approx. ($2.4) million, using SEC pricing ($2.98/Mcf for natural gas and $51.34/Bbl for oil). The following tables set forth information about the Company's estimated proved reserves, including proforma for the divestiture of the Sold Assets: Including the Sold Assets, the Company estimates that its 2017 production was approx. 27.6 Bcfe, or 75.6 MMcfe per day. Estimated fourth quarter 2017 production, including the Sold Assets, totaled approx. 8.6 Bcfe, or 93.7 MMcfe per day, compared to guidance of 91-95 MMcfe/d. Estimated production for 2017 was 17% higher than 2016 and estimated fourth quarter 2017 production was 87% higher than the year-ago quarter. Based upon estimated 2017 production, the Company estimates that it achieved a 247% reserve replacement ratio during 2017 and expects that its all-in finding and development costs during 2017 to be approx. $0.70/Mcfe. The Company expects to provide first quarter 2018 guidance metrics and 2018 capital expenditure guidance and plans in connection with its 2017 year-end earnings release in early March 2018. Management's Comment 'After completing the sale of our Gulf of Mexico properties, we have eliminated a considerable long-term abandonment liability and have substantially reduced our exposure to future regulatory, environmental, surety and weather risks inherent in offshore operations. In addition, the sale will increase our net liquidity by $6.5 million and allow us to focus our attention on developing our onshore assets in East Texas and in the Louisiana Austin Chalk trend,' said Charles T. Goodson, Chairman, Chief Executive Officer and President. 'While our production and reserve profiles will experience near-term reductions after this divestiture, we believe that this transaction will ultimately drive value creation.' Original article link Source: PetroQuest Energy ","Gulf of Mexico, not found"
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 â 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 â 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 â 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 â Minimum and Maximum State Participation â 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 â Blocks on Offer â 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 â Blocks on Offer â General Summary Map  ","Mexico, not found"
30642,"On 24 September 2018, Kuwait Energy plc (KE) announced that it had agreed to sell its entire issued share capital to United Energy Group Ltd (UEG). Under the terms of the agreement UEG will acquire the share capital of KE for an approximate consideration of USD491 million on a fully diluted basis which equates to approximately USD1.50 per share. The agreement has been approved unanimously by the KE Board of Directors. KE operates Block 9 in Iraq which contains the Faihaa oil field. Faihaa, which is believed to represent an extension of the Yadavaran field in Iran, is currently producing approximately 20,000 b/d. KE has a 60% interest in Block 9 with partners Dragon Oil plc 30% and Egyptian General Petroleum Corporation (EGPC) 10%. It also signed a 20 year gas development and production service contract with the Iraqi Ministry of Oil for the Siba field on 5 June 2011. KEC 30% is partnered in the contract by Turkiye Petrolleri A.O. (TPAO) 30%, Missan Oil Company (MOC) 25% and EGPC 15%. In April 2018, UEG was awarded the Sindbad Block in the south of Iraq as part of a tender for exploration, development and production of blocks on Iraqâs borders with Kuwait and Iran. The contract when ratified will have a 34 year duration + optional nine-year extension.","Kuwait, not found"
38047,"Ecopetrol has acquired a 10% stake in the recently-awarded Saturno block, 100 sq km in the central Santos pre-salt and so far Shell-Chevron 50:50 and to be 45:45. The agreement is subject to approval by the energy ministry and ANP.","Brazil, Saturno"
16099,"Sebou block, onshore Rharb Basin, location on the downthrown side of main bounding fault in the Ksiri area, TD 1,304m, 5.2m net gas pay across 2 zones in the Guebbas and Hoot fmâs, avg porosity 33%. Reservoir thickness above pre-drill expectations. Testing planned prior to hook-up. ","Sebou block, onshore Rharb Basin, location on the downthrown side of main bounding fault in the Ksiri area, TD 1,304m, 5.2m net gas pay across 2 zones in the Guebbas and Hoot fmâs, avg porosity 33%. Reservoir thickness above pre-drill expectations. Testing planned prior to hook-up. "
72276,"In late December 2019, Qarun Petroleum Co (Qarun) successfully tested Cobra 3, a new pool wildcat of the Cobra field, Bolt 150 (Dev) block, Abu Gharadiq Basin. The well presumably encountered oil in the Albian to Cenomanian Lower Kharita Member of the Burg El Arab Formation. The company spudded Cobra 3 on 21 September 2019 with the EDC-63 land rig and drilled the well to a TD of 3,261 m. The Cobra field was discovered in October 2019 after the new field wildcat Cobra 1 tested oil in the Bahariya Formation, the field was brought immediately onstream. Qarun is a JV between EGPC (50%) and its partners Apache (25.125%), Dana Petroleum Qarun (12.5%) and Sinopec (12.375%). The Bolt 150 (Dev) block was granted to Qarun in September 2019. It covers an area of 21 sq km and includes also the Bolt 150-1ST discovery.","Cobra 3 npw (Qapetco = Apache-Dana Petr.-Sinopec-EGPC JV) in Cobra field area, Bolt 150 (Dev) block, tested oil, likely from the Lower Kharita (Burg El Arab Fm), TD= 3261m."
30397,"On 24 September 2018, Tullow and partners announced that the Cormorant-1 exploratory well within Tullowâs Walvis Sub-basin PEL 037 (Blocks 2012B, 2112A and 2113B) was in the process of being plugged and abandoned as an unsuccessful well. The well, drilled at a water depth of 548 m reached its total depth of 3,855 m on 21 September 2018. It penetrated a 50 m fan system within the Cormorant Prospect (interbedded sands and claystones were encountered at the primary objective but proved to be water bearing). According to Pancontinental Oil and Gas NL (Pancontinental) wet gas signatures, indicative of oil were first encountered in the overlying shale section and persisted throughout the targeted interval, indicating that there has been significant hydrocarbon generation in the area. On 4 September 2018, Africa Energy Corp (Africa Energy) and Pancontinental announced the spudding of the well (Africa Energy holds a 10% effective interest in the licence).  As of 3 September 2018, the âOcean Rig Poseidonâ D/S was on location.  The well was viewed as high impact as it was the first well within Namibia and the Walvis Sub-basin, since Repsol plugged and abandoned the Welwitschia 1A well as dry in June 2014.  The Cormorant Prospect is an Albian aged base of slope turbidite fan located above Aptian aged source rocks. 3D seismic data of the 124 MMbbl, 120 sq km Prospect showed a Type II AVO anomaly, consistent with oil fill (Tullow believed it to be light oil). The well drilled targeting the Cormorant Prospect did not include an objective within the underlying Uppar Fan 2 Lead (the underlying lead is understood to be 300 m deeper). Drilling took less than 20 days to complete. Prior to the group deciding to drill the Cormorant Prospect, the largest and most developed prospect within the licence was understood to be an Albian base of slope Albatross turbidite fan with a prospective resource of 349 MMbbls. Pancontinental believes that the prospect is underlain by oil mature source rocks. To date four prospects and three leads have been identified within the licence:  Prospect/Lead Status AREA (Sq Km) PROSPECTIVE RESOURCE (MMbbls) Results Albatross Prospect 293 349  Seagull & Gannet S Prospect 273 338  Seagull & Gannet N Prospect 90 104  Cormorant Prospect 120 124 Drilled in September 2018, P&A as dry Upper Fan 2 Lead 85   Lower Fan 3 Lead 352   Lower Fan 4 Lead 170   Total (Prospects)   915   Interests in the licence are as follows: Tullow Kudu Limited (Tullow) a wholly owned subsidiary of Tullow Plc operates the licence with a 35% interest, ONGC Videsh upon closing of the 2 July 2017 farm in deal holds a 30% stake, Pancontinental Namibia Pty Ltd (held by Pancontinental with a 66.67% interest and Africa Energy with a 33.33% interest) holds a 30% interest and Paragon Holdings (Pty) Ltd holds the remaining 5% free-carried interest. Background Information In 1995, Sasol drilled a well within the area currently under licence as PEL 037. The well is located towards the north western portion of the licence to the west of the Albatross prospect. The well was drilled to a TD of 3,712 m and tested an upper cretaceous closer which was found to be dry. However, it is worth noting that hydrocarbon content and wetness recorded in the well increased steadily towards the bottom of the well. On 27 November 2017, Pancontinental Oil and Gas NL (Pancontinental) announced that the licence group had voted in favor of drilling the Cormorant Prospect and that the targeted spud date was 1 September 2018, subject to the Ministry of Mines and Energy allowing the group entry into the second renewal phase.  On 9 January Tullow confirmed that the group would drill the Cormorant Prospect in the second half of 2018 and that preparations for drilling were underway. On 8 March 2018, Pancontinental announced that the group had contracted the âOcean Rig Poseidonâ D/S for the drilling of the well. The targeted spud date was 1 September 2018. It also announced that the Ministry of Mines and Energy had granted the group entry into the second renewal phase.  On 13 June 2018, Pancontinental, partner to Tullow in the licence, announced that significant progress regarding preparations for the spud of the Cormorant-1 exploratory well had been made. In addition to reconfirming the 1 September 2018, spud date Pancontinental mentioned that the well will be located at a water depth of 545 m and is expected to take 34 days to drill.",Namibia (Orange Sub-basin (SW African Coastal B.)) Kudu
42153,"As announced on 15 February 2019, PTTEP officially signed the Share Purchase Agreement (SPA) with TATEX Thailand for a 33.8% stake in APICO LLC which holds assets in the Khorat Plateau. The deal is worth approximately USD 64 million and is expected to be completed within 1H 2019. Prior to the acquisition, the ownership of the Apico LLC joint venture consists of NuCoastal (39%), Tatex Thailand (33.8%) and Salamander Energy (27.2%). Apico LLC holds 35% participating interest in Sinphuhorm project in blocks EU1 and E5N, operated by PTTEP. After the completion of this transaction, PTTEPâs interest will increase to 66.8%. In 2018, Sinphuhorm field produced at an average of approximately 79 MMcf/d of gas and 245 b/d of condensate. Apico LLC also holds 100% ownership in the adjacent blocks L15/43 and L27/43. The 15/43 concession contains the Sinphuhorm East 1 field which is currently under development planning and Environmental Impact Assessment. L27/43 concession contains the undeveloped Dong Mun gas discovery and several undrilled prospects. The production period for Dong Mun field is scheduled to expire on 24 September 2032. Background Information Ophir reported recoverable reserves (2P) of 2.7 MMbo and 850 Bcfg, plus contingent resources (2C) of 2.8 MMbo and 652 Bcfg for Sinphuhorm effective end-2014, following an audit by RPS Energy. US-based NuCoastal Corporation was formally awarded concessions L15/43 and L27/43 in 2003. In March 2006, Apico (Khorat) Limited, a 100% owned subsidiary of US-based Apico LLC, officially acquired 100% interest of exploration concessions L15/43 and L27/43 from NuCoastal Corporation. Apico LLC had in early 2005 signed an agreement with NuCoastal to acquire both concessions. NuCoastal entered into a Service Agreement with Apico, to provide necessary services for the effective operations of Apico operated petroleum concessions in Thailand. Former operator NuCoastal acquired approximately 370km of 2D seismic, shot over the southern extension of the Phu Horm field, over the Dong Mun gas discovery and over other leads in the concession, from 6 January 2006 to 11 February 2006. The survey is understood to have been paid by Apico. Sinphuhorm field was discovered in 1983 by Phu Horm 01 well operated by Exxon. Sinphuhorm field was formerly known as Phu Horm field until it was renamed in 2008 in honour of the Thai Royal Family. The field was suspended for more than 10 years until it was farmed-out to Amerada Hess (Operator-80%) and PTTEP (20%) in mid-1990. Sinphuhorm field is a double-crested structure, the northern part of which was investigated by Phu Horm-1 and Phu Horm 2. The southern part of the structure lies in Reserved Area (E5/A1) and was tested by Phu Horm 3. Sinphuhorm field came on stream in November 2006. The Sinphuhorm East structure was successfully drilled by Apico in late 2013, with the Sinphuhorm East 1 well. The well was suspended as a future gas producer after having tested over 50 MMcfg/d from the Permian carbonates of the Pha Nok Khao (PNK) Formation. A Production Area for Sinphuhorm East was approved by DMF in August 2014. Development planning and Environmental Impact Assessment (EIA) were ongoing as of December 2015. L27/43 contains the Dong Mun gas discovery, drilled by Exxon in 1990 under the E5/A concession. Discovery well Dong Mun 1 was designed to test a shelf edge reefal build-up and reached a TD of 3,475m in Permian Saraburi Group limestones. The well was tested over four intervals in the same limestones, flowing a maximum of 23 MMcfg/d from the section 2,705-2,798m. Tests over the deeper sections showed a marked reduction in flow rates, attributed to the lower permeabilities at depth. Dong Mun 2 appraisal well was then drilled approximately 12 km southeast from the discovery, in May-August 1990, but was abandoned having flowed only 0.13 MMcfg/d from a limestone section at 2,763-2,882m. The well tested a similar reefal build up to that of Dong Mun 1, but this time within a carbonate platform (rather shelf edge) setting. A second appraisal Dong Mun 3, located approximately 2.5 km southeast from the discovery was drilled during November 2007-January 2008 and was suspended as gas shows. Apico LLC submitted a request for further extension for the development period of the Dong Mun field for a two-year term, an additional to the previous two-year additional term of development period for the concession that expired on 28 August 2018. The operator was preparing to conduct a drilling campaign in the block, comprising one delineation well and pre-development wells intended to prove up additional reserves and to provide extra production capacity once the field comes onstream. The operator is progressing with the field development plan after received land permit and additional drilling Environmental Impact Assessment (EIA) report approval from the government. The application of the production area was submitted after the successful re-entry drilling of the Dong Mun 3ST in February 2012. The approval was granted by the Thailand Department of Mineral Fuels (DMF) on 22 August 2012. The company is estimated to invest USD 23 million in the development. Output capacity was estimated to be 14 MMscfg/d. On 31 December 2012, the field was estimated to contain 90 Bscf of gas reserves (2P).",PTTEP officially signed the Share Purchase Agreement (SPA) with TATEX Thailand for a 33.8% stake in APICO LLC which holds assets in the Khorat Plateau. The deal is worth approximately USD 64 million
52063,"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 âOcean Greatwhiteâ 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. 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, results n/awaited, targets Paleocene/Eocene Balder/Flett Fmâs."
9269,"On 15 November 2017, the UK-based company Savannah Petroleum plc (Savannah) informed that it has signed a lock-up agreement regarding a USD 140 MM acquisition of Nigerian assets from Seven Energy International Ltd (Seven). Upon finalization of the deal (expected in Q2 2018), Savannah will acquire Sevenâs working interests in two marginal fields located southeastern Niger Delta. Savannah will own 40% in Frontier Oil-operated Uquo oil and gas field, as well as 31.875% in Universal Energy Resources (UER) -operated Stubb Creek oil field (Seven had 62.5% in UER so far). Savannah will also acquire a stake in the 260 km Accugas gasline and associated infrastructure. The deal is worth USD 87.5 MM cash and USD 52.5 MM shares, implying a possible new share issue. A lock-up agreement is understood to be binding contract prohibiting both parties from selling any shares of stock for a specified period of time. Lock-up periods typically last 180 days but can last for as little as 120 days or as long as 365 days. As of late 2017, Savannah was an E&P company active only in Niger, where it expects to spud the first of three exploration wells as soon as the company shares are back to the trading market (end of lock-up agreement). The well was initially planned to be spudded in August 2017 in the Block R3 (East area).  ","Nigeria (Niger Delta) (It's a petroleum rights. Please summarize by yourself). In IHS database: Stubb Creek op. by UNIV EN RS (60.0%, SINOPEC 40.0%) to be check.Uquo op. by FRONTIER L (100.0%) to be check."
64556,"Theia Energy Pty Ltd, previously Finder Shale Pty Ltd, is seeking a farm in partner to fund exploration activities in Canning Basin permit EP 493. Theia Energy is offering a 30 â 50% equity position in return for contributions to well costs, as well as payment for historical costs on the permit. A data room is open during 2019 for interested parties. The permit covers the mature liquids rich shale play Goldwyer III â Bakken Shale analogue at shallow depths and is ideally situated close to existing infrastructure. Theia Energy is looking for a farm-in partner to assist with an appraisal/development programme, with plans to initially appraise by drilling the Helios 1 vertical well, targeting the Goldwyer and Nambeet formations in 2020.This would be followed by the Helios 1H horizontal hole in 2021, targeting the Goldwyer. Theia has reported that the unconventional Goldwyer has estimated potential resources in place of up to 24 Bboe and the Nambeet 8 Bboe. Finder Energy was initially looking for a farm in partner to assist with costs of Theia 1 exploration well when the farm-out was first announced in May 2015. Theia 1 subsequently spudded on 15 July 2015 and reached a TD of 1,645 m on 28 August 2015. During drilling Theia Energy utilised a âslim-holeâ drilling technique, which reduces environmental impact and costs and also allowed the acquisition of a continuous core section. Theia Energy reported that a total 778 m of continuous core had been acquired during drilling. Upon reaching total depth wireline logs were run over the cored interval of the target Ordovician Goldwyer Formation. Theia Energy reported that high wet gas mud readings, increased wireline resistivity, fluorescence, positive well desorption indications, and a geothermal gradient validated the geological model and de-risk the Canning Goldwyer shale play. In 2015 Theia Energy suspended term one of the work programme until 28 February 2018 to facilitate the completion of a 220 km 2D seismic survey. However, on 28 February 2018 Theia Energy received approval from the Department of Mines, Industry Regulation and Safety (DMIRS) to vary the work conditions, from which, Theia Energy was exempt from completing the survey (AUD 2.6 million). The exemption also extended to the drilling of two exploration wells in term two (AUD 17.95 million). The exemption to drill an exploration well in permit term 2 was first approved after Theia-1 exploration well was drilled in term one, which DMIRS credited towards the term two commitments (leaving the requirement to drill two wells). The wells were deferred to term three and are due by 28 February 2022 after work suspensions were granted in January, and again, in October 2019. The wells are expected to cost a total of AUD 10.6 million. On 5 September 2017, the Western Australia government implemented a moratorium on hydraulic fracturing. This was lift on 27 November 2018 following an independent inquiry by Environmental Protection Authority chairperson Dr Tom Hatton. The final report made 44 recommendations to the existing regulatory framework. Theia awaits the full implementation of the new terms to begin its remaining work programme of appraising its Ordovician tight gas play. EP 493, which covers 4,628 sq km, was awarded on 1 March 2015 and is scheduled to expire, or be eligible for renewal by, 28 February 2025. Theia Energy Pty Ltd, which holds 100% interest in the permit, and is offering 30-50% equity and participation in the next phase of exploration. Companies interested in pursuing this opportunity should contact: Ryan Taylor-Walshe, General Manger Tel: +61 474 979 474 Email: ryan@theiaenergy.com Jop van Hattum, COO           Tel: +31 430 739 507                   Email: j.vanhuttum@theiaenergy.com","Theia Energy Pty Ltd seeking farm in partner for EP 493, Canning Basin"
9150,"AGF has agreed to acquire Beachâs interests in PL 184 (Thylungra field) and ATP 932-P, Cooper-Eromanga, AGF taking on full ownership as of early 2018. Currently, AGF has 19.6% in PL 184 and has 0% in ATP 932-P.",Australian Gasfields (->100%) has acquired complete interest in 2 permits: production licence PL 184 (Thylungra field) and exploration permit ATP 932-P from Beach.
37582,"Hong-Kong based New Times Energy subsidiary, High Luck reported on 12 December 2018 that it tested oil on the Los Blancos x-2001 exploration well on the Chirete Block of the Oran-Olmedo Basin. 550 bo/d at 34deg API with virtually no water cut was tested from the Ordovician Las Brenas Formation. Gas shows were also reported in the well. Further evaluation will be conducted to determine commerciality of the tests. It was spud on 27 October 2018 and finished drilling on 29 November 2018 with a 2,705m TD. High Luck operates with 50% and Petrolera Pampa holds 50% interest in the Chirete license. High Luck has submitted a contract extension request to the Salta authorities as the contract expired on 18 November 2018, in order to complete the evaluation of this discovery.","Argentina, Chirete"
11388,"In mid-December 2017 the Dutch Ministry reported that TAQA left the P9a, P9b & P9d on 7 November 2017. It is yet unknown who acquired TAQAâs 20% interest in the licence. The licence is situated about 70 km north of Rotterdamâs harbour. The P9-A gas field straddles the P9a, P9b & P9d and the P9c, P9e & P9f licences. The field was discovered in August 2000 and put onstream in October 2009. Its reservoir is situated below 3,193 m in Scythian Volpriehausen Fm sandstones. Discovery well â P9-A â was drilled to a total depth of 4,009 m. The well test recovered 1,100 Mcfg/d from a 10 m interval through a 1â choke. Before the deal, interest in the licence was divided between Petrogas E&P Netherlands BV (80% + operator) and TAQA Offshore BV (20%). Â ","It is yet unknown who acquired TAQAâs 20% interest in the P9a, P9b & P9d licences."
58234,"An unnamed Miocene oil find is reported in block 3, Upper Nile state near the Adar oilfield, Melut Basin, TD 1,320m, a figure of 300 MMbo articulated. The find appears to be distinct from the recent Jamam discovery in block 7 (DEA 26 Aug â19). DPOC (op), partners Petronas, CNPC, Nilepet, Sinopec + Tri-Ocean.",South Sudan (Melut B.) Jamam
65398,"After thinking of selling-down for a while, Shell has reportedly elected to withdraw from its last Gabonese holdings, deepwater BC 9 (5,970 sq km) and BCD 10 (7,055 sq km). Its 75% transfers to partner CNOOCI who ends up sole holder of the acreage, home to the 2014 Leopard gas find.","After thinking of selling-down for a while, Shell has reportedly elected to withdraw from its last Gabonese holdings, deepwater BC9 and BCD10 (home to the 2014 Leopard gas find). Its 75% transfers to partner CNOOCI (->100%)."
14906,"SW part of Green Canyon block 392, OCS lease G32499, NE of Caicos + Wildling prospects in Shenzi field area, WD 1,250m, cleared to P&A by the BOEM on 9 Feb â18, well understood dry. Target Miocene, Deepwater Invictus SS (contract for which recently renewed for 2 years). BHP (op), partners Repsol + Statoil.","GC 392 001S0B0 (Scimitar) op. by BHP (65%, Repsol 20%, Statoil 15%) in G32499 OCS Lease, P&A, dry."
73312,"North Slope lease ADL 392044, Horseshoe block, oil shows in the target Nanushuk O, cores + logs under evaluation prior to testing. PTD max. 1,829m, Doyon Arctic Fox rig.","Stirrup 1 nfw. (Oil Search 65,63%, Repsol 25%, GMT Explo. 9,38%) North Slope lease ADL 392044, Horseshoe block, oil shows in the target Nanushuk O, cores + logs under evaluation prior to testing. PTD max. 1,829m."
66703,"Further to DEA 2 Dec '19: Chiripia Oeste area in Tapi Aike block, Magallanes Basin, 1st of 4 wells planned here, TMD 2,513m (Palermo Aike fm), wireline logging completed, 6 zones of interest, stimulation + rigless testing planned. The Petreven H-205 rig is transferring to drill Campo Limite-1001 (CLix). CGC (op), partner Echo Egy.","Argentina (Austral B.) ? op. by CGC (81.0%, ECHO EN 19.0%) in Tapi Aike block"
68004,"The CNH has approved the award of prod. leases for the Cahua, Octli + Teca fields, carve-outs of the AE-0009-3M-Tucoo-Xaxamani-01 block, offshore Sureste Basin. The name of the contract is AE-0009-4M-Tucoo Xaxamani-01 Campos Teca, Cahua y Octli. Cahua covers 17.9 sq km around the Cahua-1 gas-cond discovery (Sep '17). Octli is 20.4 sq km around the Octli-1 o&g find Aug '17). Teca surrounds the Teca-1 o&g discovery (Jun '16), 25.35 sq km.","The CNH has approved the award of prod. leases for the Cahua, Octli + Teca fields, carve-outs of the AE-0009-3M-Tucoo-Xaxamani-01 block, offshore Sureste Basin. The name of the contract is AE-0009-4M-Tucoo Xaxamani-01 Campos Teca, Cahua y Octli. Cahua covers 17.9 sq km around the Cahua-1 gas-cond discovery (Sep '17). "
80351,"Lundin has completed its deal, reported in early March 2020, to acquire Neptune's 20% interests in PL 886 and PL 886 B. The transfer is effective from 30 April 2020. PL 886 covers blocks (or parts of) 6306/6, 6306/8 and 6306/9 and PL 886 B lies adjacent to the northeast, covering parts of blocks 6307/1 and 6307/4. Lundin plans to drill a well on the Melstein prospect, which is targeting a new play with potential recoverable reserves of 160 MMboe, in PL 886 in 2021. It is also understood that there is a prospect in PL 886 B called Tarva, but no drilling plans have yet been released for this. The closest field to these licences is Fenja where development is progressing towards an onstream date of Q4 2021. Neptune will develop the Pil accumulation initially, using a subsea tieback to the Njord A platform. Recoverable reserves are approximately 97 MMboe. The project will use two subsea templates hosting three horizontal producers, two water injectors and a single gas injector. The drilling plan has been modified due to the effects of coronavirus disease 2019 (COVID-19) and drilling will now take place over two years in three phases. Bue represents upside and will be confirmed by Pil development wells before it is potentially brought into production at a later date. Oil will be processed on Njord A before being transferred to Njord B for onward export via shuttle tanker. Gas will initially be re-injected into the Pil reservoir and will later be exported via Njordâs connection to the Asgard Transport System. Plateau production is expected to be approximately 40,000 bo/d and gas production expected to peak at approximately 100 MMcf/d between 2025 and 2036. Total investment costs are approximately NOK 10.2 billion (USD 1.22 billion), with 16-year life forecast. Upon completion of the deal, PL 886 and PL 886 B interests are divided between Lundin Energy Norway AS (60% + operator), Petoro AS (20%) and Spirit Energy Norway AS (20%).","Lundin has completed its deal, reported in early March 2020, to acquire Neptune's 20% interests in PL 886 and PL 886 B. "
45621,"On 29 March 2019 Jetex Petroleum reported that it is looking to farm-out part of its interest in the P10c and the P4, P7 & P8b exploration licences. The licences are situated in the southwestern part of the Dutch waters of the North Sea adjacent to the UK border and about 100 km east of the city of Den Helder. The P10c licence contains three exploration wells: P10-1 (dry, Penzzoil, 1969), P10-2 (dry, Conoco, 1985) and P10-4 (dry, Petro-Canada, 2003). Seven wells were drilled in the P4, P7 & P8b licence: P4-1 (dry, Bow Valley, 1977), P7-1 (dry, Unocal, 1969), P8-1 (dry, Mobil, 1976), P8-4 (dry, Mobil, 1984), P8-7 (dry, Wintershall, 2011), P8-8 (dry, Dana, 2011), P10-1 (dry, Pennzoil, 1969), P10-2 (dry, Conoco, 1985) and P10-4 (dry, Petro-Canada, 2003). Interest in the P10c licence is held by Jetex Petroleum Inc (operator + 60%) and Energie Beheer Nederland BV (40%). while the P4, P7 & P8 licence is held solely by Jetex Petroleum Inc.","Jetex Petroleum reported that it is looking to farm-out part of its interest in the P10c and the P4, P7 & P8b exploration licences. The licences are situated in the southwestern part of the Dutch waters of the North Sea adjacent to the UK border and about 100 km east of the city of Den Helder."
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 Searchâs focus on expanding exploration potential to support the expansion of LNG projects. In doing so, Oil Search reported that the companyâs 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.)."
6836,"RockRose Energy has signed a sale and purchase agreement to acquire the entire issued share capital of Idemitsu Petroleum UK from Idemitsu Kosan, a Japanese corporation. The Acquisition will be funded out of the existing facilities and cash resources of the Company. Completion of the Acquisition is conditional upon confirmation from the UK Oil and Gas Authority that there is no objection to change of control. The Idemitsu UK's assets comprise, inter alia, a substantial number of producing fields in the North Sea which include: The Acquisition also brings with it a number of key employees and its premises in London, which will enhance RockRose's internal expertise providing continuity on the acquired assets and assisting with the management of the wider portfolio. On closure of this Acquisition and previously announced transactions, RockRose will have a projected 6,200 - 7,000 boepd of production in 2018 on an aggregated basis. Andrew Austin, Chairman of RockRose said: 'RockRose is continuing to deliver on its stated strategy of building a business through the acquisition of mature producing assets. We believe that this acquisition is a significant one for the Company and that this portfolio also has a lot of potential for extended field life and gives Rockrose access to significant tax losses. 'We continue to review further acquisition opportunities in North West Europe and, post completion of this along with the previously announced Maersk, Sojitz and Egerton transactions by the end of this year, will have established a material business in the North Sea, set to deliver value to our shareholders.' The Acquisition constitutes a reverse takeover for the purposes of the listing rules, the Company has requested that the UK Listing Authority to suspend the listing of the shares with immediate effect. The Company will proceed to prepare and publish a new prospectus in the coming weeks which will include a competent persons report on the assets of the Company as enlarged by the Acquisition. Further details and updates on the Acquisition will be released in the near future. Original article link Source: RockRose Energy ","RockRose has agreed with Idemitsu for the purchase of the latterâs UK sub issued share capital. This involves interests in Repsolâs Tain (50%), Burghley (41,1%), Beauly (40%), Ross (30,8%), Black (30,8%), and Galley (17,4%) fields, in Shellâs Howe (20%) and Nelson (7,5%) fields, and in Premierâs Balmoral (6,7%) and Stirling (16%) fields. No value is revealed."
38000,"The NPD confirmed on 19 December 2018 that the deal for Pandion to acquire 10% of Wintershallâs interest in PL 820 S (agreed on 15 August 2018) has now completed with effect from 14 December 2018 (the deal is financially effective from 1 January 2018). The licence lies between Balder / Ringhorne and Jotun and covers parts of blocks 25/7 and 25/8. The northerly section of the licence lies across the southwestern part of the Jette field (abandoned) and this section applies only below Base Pliocene (the southerly section applies to all levels). An exploration well is due to be drilled in PL 820 S in 2019. Aker BPâs Jette was discovered by 25/8-17 in 2009 and contained oil in a Paleocene Heimdal Formation reservoir. It was brought onto production in May 2013 via a subsea template tied into Jotun A (an FPSO). Jotun itself was expected to continue producing until 2021 but water-cut in 2015 was 97% and production from tied-in fields had been declining. Therefore, both Jotun and Jette came off production in December 2016. Development of Jette had been challenging since the beginning: problems with the first producer meant that the development plan was subsequently revised to consist of two (shorter than planned) horizontal producers on the southern segment (which was believed to contain recoverable reserves of 5-9 MMboe) rather than one long horizontal on each of the south and north segments as originally planned. Due to a number of issues, including higher than expected costs and the reduction in recoverable reserves, profitability at Jette was lower than Aker BPâs initial estimates. The problems continued into production, with total 2014 production being less than half that of the six months of 2013, and 2015 production being only half of 2014 volumes. The deadline for final disposal of the Jette field facilities has been delayed to the end of 2020. Initial plans were to complete the work by 2018, based on production from the field ceasing in January 2016. However, as production continued until December 2016 the timescale has changed. Work will begin on the removal of some of the seabed infrastructure in summer 2018 and permanent plugging and abandonment of the wells will now be completed by 2019, after which the main seabed structures will be removed. Following completion of the deal, interest in PL 820 S is held by MOL Norge AS (40% + operator), Lundin Norway AS (30%), Wintershall Norge AS (20%) and Pandion Energy AS (10%).","Pandion acquired 10% of Wintershallâs interest in PL 820 S. Following completion of the deal, interest in PL 820 S is held by MOL Norge AS (40% + operator), Lundin Norway AS (30%), Wintershall Norge AS (20%) and Pandion Energy AS (10%)."
77092,"Premier Oil announced on 7 April 2020 that it plans to exit the Icewine Area A joint venture, operated by Accumulate Energy (a 100% owned subsidiary of 88 Energy) on the North Slope of Alaska once regulatory approvals have been received. The move comes on the heels of 88 Energy's announcement that the Charlie 1 well in Area A discovered gas condensate. 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. Background Information The Charlie 1 (API 502232003300) exploration well in state lease ADL 393380 (Sec 21, T4NR9E, Umiat Meridian) discovered gas condensate in the Torok formation in both the Middle and Lower Stellar targets and will now be plugged and abandoned based on a 7 April 2020 press release by 88 Energy. 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. 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.","United States, not found"
29433,"Bukhari ML (Badin I), onshore Lower Indus Basin, TD 2,668m, in June, gas-cond discovery, susp. Aug â18, TCPDC-4002 rig. Target Lower Goru.","Guni 1 (UEPL 100%) in Bukhari ML (Badin I), gas-cond discovery, Target Lower Goru."
39890,"PEMEX plugged and abandoned dry the Betan 1EXP new-field wildcat (NFW) in the AE-0051-5M-Mezcalapa-01 entitlement during late-January 2019. The final total depth (TD) was 2,580 m.  The NFW was spudded on 19 November 2018. The well had a proposed total depth (PTD) of 2,666 m and the primary target was the Miocene.       The NFW had estimated prospective resources of 25 MMboe.  The prospect is located in the north central area of the block. SENER awarded the AE-0051-5M-Mezcalapa-01 entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 974.04 sq km. The entitlement has been modified five times, the latest was 13 September 2018 whereby the area of the block was increased from 652 to 1,548 sq km. Previously the well was officially located in the AE-0052-3M-Mezcalapa-02 whose area was reduced and incorporated into the AE-0051 block.","Betan 1EXP (NFW) in the AE-0051-5M-Mezcalapa-01 entitlement, P&A dry"
81901,"Meleiha (Dev) block, N. Egypt Basin, drilled late Feb â late May '20, P&A'd. Targets assumed Bahariya, Khatatba + Alam El Bueib. Agiba = EGPC, Eni + Lukoil JV.","Egypt (Northern Egypt B.) ? op. by ENI SPA (76%), LUKOIL (24%), EGPC (0%) in Meleiha (Dev) block"
15200,"In late September 2017, Khalda abandoned the Qasr Southeast 1 in the Qasr development lease as a dry hole after reaching a TD of 2,835 m. The well was spudded on 6 September 2017 with âEDC-67â land rig with a planned TD of 2,835 m and objectives in the Kharita Member and the Bahariya formation. Background information Khalda made a significant gas discovery in wildcat Qasr 1 located in the Ozoris area of the Khalda Offset Block A. The well flowed at a combined rate of 51.8 MMcf/d of natural gas and 2,688 b/d of condensate from two zones. The well logged 185m of net pay from six formations between 2,108-4,140m. This is probably the largest Jurassic column ever discovered in the Western Desert, opening new exploration possibilities in the region. Pressure analysis of the Jurassic reservoirs indicates the presence of a 204m of vertical hydrocarbon column (vertical/structural relief and not thickness). The well was suspended on 8 May 2003, at a total depth of 4,182m in the Paleozoic, as originally planned. Primary targets included the Alam El Bueib '3D' Unit, the Cenomanian Bahariya and Khatatba formations. The well is located 2km south of the Ozoris field. A production test of the Middle Jurassic Lower Safa formation from perforations between 3,934-3,988m flowed 38.1 MMcf/d natural gas and 2,155 bc/d, through a 1"" choke and with flowing wellhead pressure of 2,549 psi. The thickest pay interval of 95m was encountered in the Triassic- Lower Jurassic Ras Qattara formation. However, only 27m of the least prospective upper zone could be tested due to mechanical problems encountered while completing the well. Perforated between 4,039-4,068m flowed 13.7 MMcf/d of natural gas and 533 bc/d, on a 1"" choke with 851 psi of flowing wellhead pressure. Â ","Qasr Southeast 1 op. by Khalda (Apache 33,5%, Sinopec 16,5%, EGPC 50%, carried) in Qasr development lease, P&A, dry."
86239,"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 July 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",(Bove & M.S.G.B.C b.) 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.
23642,"As of June 2018, Join Oil is looking for a partner to develop the Zarat field which straddles two offshore blocks at the Tunisia-Libya border. One block is the Zarat exploration license formerly operated by PA Resources, now belonging 100% to Tunisian state company ETAP. The other block is the Joint Oil exploration block, formerly operated by Sonde Resources, now belonging 100% to Joint Oil, a joint venture between ETAP and the National Oil Corporation of Libya. Consultancy BeicipFranlab was mandated by Joint Oil to market the Zarat opportunity and maintains a physical data room in its premises at Rueil-Malmaison near Paris. More information is on the website jointoilblock-zarat.com. In July 2015, PA Resources announced that it submitted a plan of development for the Zarat field, shallow waters of the Pelagian Basin, eastern offshore, to the Tunisian authorities. The field was to be developed in two phases. Phase one included four production wells and facilities to process 20,000 b/d of oil and 10 MMcf/d of gas. Phase two included another four development wells and expanded facilities to process 40,000 b/d of oil and 200 MMcf/d of gas. A final investment decision was expected in 2017 and first oil in 2020. The Zarat field has P+P recoverable reserves ranging from 114 to 147 MMb oil equivalent depending on the estimates. Half of the reserves are liquids and half is gas. The Zarat field development can serve as a hub to develop other stranded resources in the vicinity such as the Elyssa gas/condensate field located in the Zarat block. The Zarat discovery holds 60% of inert gas. On 12 June 2012, the Tunisian Government, through its Direction Generale de lâEnergie (DGE), announced an initiative for offshore oil & gas operators to study options of the sequestration of CO2 and other inert and acid gas. The faulted anticline Zarat discovery was made by Marathon Petroleum Zarat Ltd in June 1992. The pay zone is the Lower Eocene El Gueria limestones below 2,630m, and is reported to be 25m of oil and 65m of gas and condensate. The discovery well was tested over two intervals. In 2011, appraisal well Zarat Nord 1, located 2km northeast of the Zarat 1 discovery well and 3km northeast of the Zarat 2 appraisal well, confirmed the extension of the previously proven Zarat accumulation. Zarat is located on the nummulite bar which produces at Ashtart and Bouri, about mid-way between these two fields.","Tunisia, Zarat Field"
60155,"Local sources reported that BHP spudded on 21 August 2019 the well Boom 1, TTDAA 14 Block in the Trinidad Basin using the Transocean Deepwater Invictus drillship. The main objective is the Miocene Turbidite Sandstones, with proposed total depth (PTD) of 4,450 m (14,600 ft) in 2,207 m (7,242 ft) water depth. Transocean Deepwater Invictus will remain in Trinidad and Tobago until March 2020. The interest holders are BHP with 70% and the remaining 30% with BP TT. Block TTDAA 14, Bongos 2 was a part of the second phase objective. Hi Hat 1 NFW is assumed is the appraisal well for Bongos 2 â it was plugged and abandoned (P&A) with hydrocarbons encountered. On 17 April 2014, local sources confirmed that BP farmed out a majority interest to BHP Billiton in deep-water blocks TTDAA 14 and 23(a). BP on 25 July 2011 reported that it was awarded two deep-water exploration and production blocks in Trinidad and Tobago, doubling the companyâs acreage holdings in the country. BP was awarded a 100% interest in the blocks 23 (a) and TTDAA 14, both of which are in deep-water frontier acreage of Trinidadâs eastern coast. The contracts were awarded as production sharing contracts. Block 23(a) is located about 300 km NE of BPâs Galeota Point operations base. The block covers 2,600 sq km in water depths averaging 2,000m. On 12 June 2013, the Trinidad and Tobago Minister of Energy and Energy Affairs announced that four PSCâs were executed with BHP Billiton for deepwater blocks TTDAA 5, TTDAA 6, TTDAA 28 and TTDAA 29. The BHP applications for the blocks which were on offer during the 2012 Deepwater competitive Bid Round were accepted on 30 November 2012. The minister mentioned that BHP is committed to spend approximately USD 565 million for the first exploration phase and a further USD 459 million over optional phases. The minimum work program commitment involves the acquisition of approximately 5,330 sq km of 3D seismic and the drilling of six deepwater exploration wells. BG announced in June 2014 that it had farmed in the block taking 35% interest. Currently, the interest holders in the block are the operator BHP with 65% and BG holds the remaining 35%.","Boom 1 appr. (BHP op. 70%, BP 30%) in block TTDAA 14, target Miocene turbidites. P&A with unreported result. WD =2207m, PTD was 4450m."
11229,"Dommo Energia is reportedly back-tracking on the proposed sale of its 30% in BS-004 to Azibras as required conditions could not be fulfilled on time. Dommo (ex-OGX) had agreed to sell part of its 40% in the Queiroz Galvão-operated block (Atlanta + Oliva leases), deepwater Santos Basin for USD 33 MM and contingent payments of USD 30 MM. So far Queiroz Galvão (op), partners Dommo + Barra Energia. ","Brazil (Santos B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Oliva op. by QUEIROZ (30.0%, DOMMO EN 40.0%, BARRA EN 30.0%) to be check."
53383,"Acordeón wellpad in VIM-5, Lower Magdalena, TD 2,667m, confirmed new gas accumulation in the Cienaga de Oro sands, tested for 32-hour period, flowed an average of 16 MMcfg/d, will be tied into the Jobo facility and put onto permanent prod by end-month, Pioneer rig 53.","Ocarina 1 expl. Acordeón wellpad (Canacol 100%) in VIM-5 block, confirmed new gas accumulation in the Cienaga de Oro sands, tested for 32-hour period, flowed an average of 16 MMscfg/d, will be tied into the Jobo facility and put onto permanent prod by end-month, TD=2667m"
11968,"NW-C part of Canto do Amaro prod. lease, onshore Potiguar Basin, oil shows report to ANP 3 Jan â18. PTD is/was 1,008m, target Açu.","3-CAM-1040D-RN (3-BRSA-1358D-RN) appr, NW-C part of Canto do Amaro prod. lease,oil shows "
21144,"IGas has agreed to sell some non-core assets to Onshore Petroleum Ltd for GBP 3.14 MM. Assets involved include PL 220 (Long Clawson + Rempstone fields), ML3 (Egmanton field), ML6 (Bothamsall + Apleyhead fields), ML7 (South Leveton field), PEDL 070 (Avington field), PL 205 (Storrington field), PEDL 158 + P1270 (Lybster field), PEDL 257 (Lingfield-1 discovery) + PEDL 235 (Godley Bridge discovery). Completion of the deal is expected in 2H â18.","IGas has agreed to sell some non-core assets to Onshore Petroleum Ltd for GBP 3.14 MM. Assets involved include PL 220 (Long Clawson + Rempstone fields), ML3 (Egmanton field), ML6 (Bothamsall + Apleyhead fields), ML7 (South Leveton field), PEDL 070 (Avington field), PL 205 (Storrington field), PEDL 158 + P1270 (Lybster field), PEDL 257 (Lingfield-1 discovery) + PEDL 235 (Godley Bridge discovery). Completion of the deal is expected in 2H â18."
52522,Enauta has renewed a 2017 farmout effort for its wholly-owned PAMA-M-265 + 337 blocks in the Para-Maranhão deepwaters. These are home to the Gameia + Tembe prospects that have been pending environmental permits since 2015:,Enauta has renewed a 2017 farmout effort for its wholly-owned PAMA-M-265 + 337 blocks in the Para-Maranhão deepwaters. These are home to the Gameia + Tembe prospects that have been pending environmental permits since 2015:
62286,"It was confirmed in October 2019 that Alkane Energy has completed the acquisition of a 50% interest in PEDL 130 (block SK/66a) from Egdon Resources UK Ltd. The licence houses two Coal Mine Methane projects, one known as Clipstone 1 and the other is Bilsthorpe Colliery. The licence is located next door to the Eakring-Duke's Wood conventional oil field which was discovered back in 1939. Following completion of the deal, interest in PEDL 130 is held by Egdon Resources UK Ltd (50% + operator) and Alkane Energy UK Ltd (50%).","United Kingdom, PEDL 130"
16528,"Shell has agreed to sell its New Zealand holdings to OMV for USD 578 MM. The deal includes Maui (PML 381012, Shell 83.75%), Pohokura (PMP 38154, 48%) as well as its operatorship of the Great South Basin venture (PEP 50119, 61%) which includes a drilling commitment, and various infrastructure. Regulatory approval is required prior to completion expected in 4Q â18. Shell had been present in New Zealand for over 100 years. OMV therefore takes charge of ab. 1/2 of NZâs gas production. Word on the street is that so far Asian-focused Sapura Energy will soon be farming-in to OMV acreage in the Taranaki Basin (rumoured PEPâs 51906, 57075, 60091, 60092 + 60093). ","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."
41701,"North Sea Natural Resources (NSNR) is offering equity in licence P2321 to interested joint venture partners/investors in return for funding a 3D survey plus two appraisal wells and a well test with NSNR operating the seismic phase. The estimated cost for the 3D survey covering 1,580 sq km is between USD 6 â 10 million with two wells and test estimated to cost USD 35 million. The primary prospect is the Jurassic sand Devilâs Hole Horst, which NSNR has estimated to contain prospective resources of 2.3 Bbo (5.7 Bbo STOIIP) with a chance of success of 34%. The Lower Zechstein Dolomite Z1 prospect is estimated to hold prospective resources of 2.9 Bbo (14.6 Bbo STOIIP) and the Upper Zechstein Dolomite Z3 prospect has contingent resources of 134 MMbo (669 MMbo STOIIP). NSNR has derived a 60% and 75% chance of success for each dolomitic prospect, respectively. The work commitments involve a firm commitment to acquire 700 km of 2D seismic, a contingent 3D seismic survey and two wells are intended, costed and planned but are not a work commitment. The licence was awarded in the 29th Offshore Licensing Round in May 2017 and a drill or drop decision will be made in May 2021. As of February 2019, NSNR stated it was in talks with two major oil companies but the farm in opportunity was still available. Devilâs Hole Horst is interpreted as a large stratigraphic closed structure with an area of 282 sq km. The prospect is located in shallow waters approximately 75 â 80 m. The reservoir is sourced from a Jurassic graben source kitchen and located on a Palaeozoic structural high. The prospect has similarities to the Johan Sverdrup field in Norway. The Lower Zechstein Dolomite Z1 prospect is a four-way dip closured structure with an aeral extent of 904 sq km. The Upper Dolomite Z3 prospect is too thin to be mapped but is interpreted to be a four-way closure at the Top Salt level. The structure was first drilled in July 1697 by Amoco and discovered a 15 m pay with oil and gas shows. The dry tests on the discovery well failed due to cement damage to the reservoir. Amoco drilled 27/10-1 in June 1970 which encountered 53 m net reservoir, 1.5 m pay zone and reservoir porosities ranging from 20 â 24%. The OWC was calculated at a depth of 1,368 TVD. Interest in P2321 is held solely by North Sea Natural Resources Ltd (100%).","North Sea Natural Resources (NSNR) is offering equity in licence P2321 to interested joint venture partners/investors in return for funding a 3D survey plus two appraisal wells and a well test with NSNR operating the seismic phase. The estimated cost for the 3D survey covering 1,580 sq km is between USD 6 â 10 million with two wells and test estimated to cost USD 35 million."
33872,"On 29 October 2018, Sonatrach signed an agreement with BP & Equinor for the exploration and possible development of unconventional hydrocarbons in the basins in the south west of Algeria. No precise details are yet available on the extent and location of the area(s), except that it is envisaged to continue and extend use of existing field facilities (for example, in the Reggane and Ahnet Basins). BP and Sonatrach had previously conducted technical studies in 2013. Work commitments include a 3D seismic survey and exploration drilling. The agreement comes following the signature of an MoU between the three companies on 26 February 2018, which included identifying new joint opportunities. It has been speculated that the deal has paved the way for Equinor to return to the Hassi Mouina area in the Timimoun Basin. The PSC was awarded to the company (as Statoil) in 2005 and relinquished in 2015. At least four Palaeozoic gas discoveries were made by the company. ",Not Found
14203,"In late Q4 2017, Sonatrach P&A dry its Rhourde Hamra Est Profond 1 ST 2 (RHAEP 1 ST 2) deeper-pool test. The well was drilled on the Rhourde Nouss In Amedjane exploration licence in the Berkine Basin. It was spudded on 24 November 2016 using the ENAFOR #37 rig (day rate ~US$ 26,400) and reached a TD of 4,162m in the Ordovician Azzel Formation. Two mechanical sidetracks were drilled.RHAEP 1 ST 2 had a primary target in the Ordovician, below the Triassic reservoir of the Rhourde Hamra Sud Est Field. The surface location of the well lies within the Rhourde Hamra Sud Est production licence, with Rhourde Nouss In Amedjane conferring exploration rights across the field. Sonatrach operates Rhourde Nous In Amedjane with 100% equity.","Algeria, Rhourde Nouss In Amedjane"
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. "
28299,"29 August 2018, Uzbekneftegaz (UNG) reports a gas condensate discovery at Tumaris, in the northern Amu-Darya Basin, close to the state border with Turkmenistan (Romitan county). Exploration well Tumaris 1 has tested between 300-400 thousand cubic metres/day (10.3-13.7 MMscf/d) of gas from Callovian-Oxfordian carbonates from a depth interval of 2,020-2,028 m. The Tumaris structureâs area is 13 sq km. The prospect was matured for drilling in 2017. Its prospective (pre-drill) resources were estimated at 5.2 Bcm (178 Bcf) of gas and 131,000 t (ca. 1 MMb) of condensate. UNG is continuing test operations at well Tumaris 1 and is preparing to drill two outposts, wells 2 and 3 in near future.","29 August 2018, Uzbekneftegaz (UNG) reports a gas condensate discovery at Tumaris, in the northern Amu-Darya Basin, close to the state border with Turkmenistan (Romitan county). Exploration well Tumaris 1 has tested between 300-400 thousand cubic metres/day (10.3-13.7 MMscf/d) of gas from Callovian-Oxfordian carbonates from a depth interval of 2,020-2,028 m. The Tumaris structureâs area is 13 sq km. Its prospective (pre-drill) resources were estimated at 5.2 Bcm (178 Bcf) of gas and 131,000 t (ca. 1 MMb) of condensate."
30032,"In late August 2018, Apache completed the Alam El Shawish South C1-2 (SAES C1-2) (Hf032-8) exploration well in the South Alam El Shawish block, Western Desert as an oil and gas discovery. The well was spudded on 25 July 2018 with the Sino Tharwaâs ST-10 land rig and drilled to a TD of 2,179 m in the Albian Kharita Member. It had a planned TD of 2,225 m and objectives in the Cenomanian Abu Roash G Member and the Bahariya formation. Apache was awarded South Alam El Shawish block on 2 December 2016 as part of the EGPC 2016 bid round.","Apache completed the Alam El Shawish South C1-2 (SAES C1-2) (Hf032-8) exploration well in the South Alam El Shawish block, Western Desert as an oil and gas discovery. "
83383,The ADNR conducted its 1st online o&g lease sale yesterday. Three bids were placed for acreage on the Iniskin Peninsula (2) and one for a tract across on/offshore areas south of the Cosmopolitan Unit in the S. Cook Inlet. The highest bidder was Hilcorp. The Alaska Peninsula Areawide 2020W sale was also held on 17 June but failed to attract any offers.,"The ADNR conducted its 1st online o&g lease sale 2020, yesterday. Three bids were placed for acreage on the Iniskin Peninsula (2) and one for a tract across on/offshore areas south of the Cosmopolitan Unit in the S. Cook Inlet. The highest bidder was Hilcorp."
84130,"Sumitomo subsidiary Summit Exploration and Production has become 100% operator of P2382, with the exit of Ping Petroleum (25% stake), effective by 25 June 2020. P2382 covers 181 sq km of block 22/14c and was awarded on 1 October 2018 in the 30th Seaward Licensing Round. The licence has a firm obligation to reprocess 3D seismic data during the initial term, followed by a drill or drop decision on 30 September 2022. The acreage contains several low risk Palaeocene exploration prospects in the prolific Forties Palaeocene sandstone on trend with Huntington (adjacent W) and Everest (adjacent NE) fields which could be tied back to nearby existing infrastructure. The acreage contains two minor Triassic oil discoveries, 22/14b- 3 (1989, Shell, 4,194m), and Mallory 22/14a- 7 (2008, BG, 4,073m), whilst a third NFW had oil shows only, 22/14- 1 (1974, Conoco, 4,176m). Ping Petroleum farmed out 25% from its previous 50% stake in P2382 to Summit on 21 March 2019. P2382 is now 100% operated by Summit Exploration and Production Ltd (Sumitomo). Summit was previously, and likely still is, farming out 25-40% in the licence.","United Kingdom (Central Graben Province) P2382 op. by SUMITOMO (75%), PING PT (25%)"
17424,"Sapura has farmed into OMV and Mitsui acreage in shallow waters of the Taranaki Basin, namely 30% in PEP 57075 + 51906 (OMV (op)), and PEP 60091, 60092 + 60093 (OMV (op), partner Mitsui), total 8,900 sq km: Â ","New Zealand, PEP 60091Sapura has farmed into OMV and Mitsui acreage in shallow waters of the Taranaki Basin, namely 30% in PEP 57075 + 51906 (OMV (op)), and PEP 60091, 60092 + 60093 (OMV (op), partner Mitsui), total 8,900 sq km: "
79408,"NZOG is offering equity in PEP 55794 (Totoa) in the Great South Basin. This was already aired in 2018 along with PEP 52717 in the Canterbury Basin (map below refers), but the difference now is that PEP 55794 was reduced by 50% at the end of March, with a drill-or-drop due in March 2022. The Kaipatiki prospect has been identified as the main candidate for drilling. PEP 55794 now covers 4,918 sq km in shelf + deep waters. Contact: Chris.McKeown@nzog.com.","NZOG is offering equity in PEP 55794 (Totoa) in the Great South Basin. This was already aired in 2018 along with PEP 52717 in the Canterbury Basin (map below refers), but the difference now is that PEP 55794 was reduced by 50% at the end of March, with a drill-or-drop due in March 2022. The Kaipatiki prospect has been identified as the main candidate for drilling. "
62299,"On 28 October 2019, the Federal Agency for Subsoil Use announced an auction for six blocks in Yamalo-Nenets Autonomous Okrug (Western Siberia). The auction is scheduled on 18 December 2019 with its application deadline on 26 November. The winners of the auction will obtain 25-year E&P licenses with a seven-year exploratory stage. Additional information may be requested from: Uralnedra 620014, Yekaterinburg, Vaynera str., 55, office 425, ural@rosnedra.gov.ru 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 amounts to RUB 113.21 million (USD 1.77 million). 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 amounts to RUB 530.82 million (USD 8.3 million). The Tiltimskiy block covers 2,453 sq km in the Ural-Frolov Province. Seismic coverage amounts to 115 km. No wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 28 MMbbl of oil, 186 Bcf of gas and 4 MMbbl of condensate. The starting price amounts to RUB 10.17 million (USD 0.16 million). 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 amounts to RUB 118.65 million (USD 1.85 million). 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 amounts to RUB 245.95 million (USD 3.8 million). The Tiltimskiy Severnyy block covers 2,579 sq km in the Ural-Frolov Province. Seismic coverage amounts to 79 km. No wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 30 MMbbl of oil, 195 Bcf of gas and 5 MMbbl of condensate. The starting price amounts to RUB 10.8 million (USD 0.17 million).","Russia, not found"
14183,"PM-331 off Pen. Malaysia, TD 1,636m, P&A on 31 Jan â18, no further information, targets were Oligocene - Lower Miocene Group J + K clastics, P.V. Drilling III JU.","Malaysia (Malay B.) Umbai 1 op. by PETRONAS (100.0%) in PM-331 block P&A, no further information, targets were Oligocene - Lower Miocene Group J + K clastics"
13575,"In the second half of 2017, Kalmtatneft completed testing of an exploratory well in Tsekertinskaya license in Kalmykia (North Caucasus). Baryernaya 1 spudded in 2015 reached its final TD 5,800 m in May 2017. Based on logging, three intervals were identified for testing. In August, the company tested gas and condensate at rates of 4.45 MMcf/d and 585 b/d through 14 mm choke from two lower intervals tested together at a depth around 5,500 m. Based on 3D seismic data and the well results, Kalmtatneft estimated 3P reserves ta 260 Bcf of gas and 12 MMbbl of condensate with possible increase to 438 Bcf and 20 MMbbl. In 2018-2019, the company plans to drill outpost Baryernaya 2 with a PTD of 5,600 m. The well was aimed at exploration of the Lower Triassic section of the Baryernyy prospect with pre-drilled resource estimates of 40 MMbbl of oil. The prospect is located in the southwestern part of the 3,530 sq km block. In 2013-2014, Kalmtatneft drilled wildcat Biryuzaksakaya Vostochnaya 1 in the same license. The well drilled to 3,397 m at the Tithonian section. No hydrocarbons were tested in open hole and the well was abandoned without setting of a production casing. Kalmtatneft is equally owned by Tatneft and Lukoil-subsidiary Ritek.","Baryernaya 1 op. by Kalmtatneft (100%) in Tsekertinskaya license in Kalmykia, tested gas and condensate at rates of 4,45 MMscf/d and 585 bcond/d through 14 mm choke from two lower intervals tested together at a depth around 5 500 m, estimated 3P reserves ta 260 Bcf of gas and 12 MMbbl of condensate with possible increase to 438 Bcf and 20 MMbbl. "
35054,"Mirpur Khas 2568-7 EL, Lower Indus onshore, TD 3,104m, gas discovery, tested 9.5 MMcfg/d from the Upper Basal Sands of the Lower Goru target, WHFP 1,880 psi, Hilong rig 16. UE (op), partners Bow Energy, Zaver + GHPL.","Gormani 1 (UE op, partners Bow Energy, Zaver + GHPL) in Mirpur Khas 2568-7 EL, onshore, gas discovery, tested 9,5 MMscfg/d from the Upper Basal Sands of the Lower Goru target. TD=3104m."
13518,"On 29 January 2018, Parnaiba Gas Natural with 100% working interest was granted official awards by the ANP for the PN-T-117, PN-T-118, PN-T-119, PN-T-133, and PN-T-134 blocks in the onshore Parnaiba Basin from the ANP Round 14. Â Â "," Parnaiba Gas Natural with 100% working interest was granted official awards by the ANP for the PN-T-117, PN-T-118, PN-T-119, PN-T-133, and PN-T-134 blocks in the onshore Parnaiba Basin from the ANP Round 14. "
56407,"PPL 24, Cooper Eromanga, likely appr to 1982 gas find, susp at TD 2,048m earlier this week, Ensign rig 950.","Suspended: Marana-2 appr PPL 24, Cooper Eromanga, likely appr to 1982 gas find, susp at TD 2,048m earlier this week,"
20112,"Nagykorös block, Bacs-Kiskun prov., Pannonian Basin, P&A dry at TD 2,691m (Cret.). Target L. Pannonian clastics + Miocene.","Nagykorös block, Bacs-Kiskun prov., Pannonian Basin, P&A dry at TD 2,691m (Cret.). Target L. Pannonian clastics + Miocene."
16725,"On 19 March 2018, Australian Independent Petsec Energy Ltd announced that it had completed its outstanding acquisition of Oil Search (Yemen) Limited (OSYL) assets and in doing so secured a 100% financial interest in the onshore 4,939 sq km Block 7 (Al Barqa) concession. The company had formerly announced on 15 November 2016 that it had entered into an agreement with KUFPEC to acquire its 25% working interest in block, but that the agreement with KUFPEC, as well as its 2015 agreement to acquire block interests and operatorship from OSYL, remained subject to approval from Government of Yemen and the Ministry of Oil and Minerals. During September 2015 it had completed the acquisition of a 29.75% participating interest in the block following the acquisition of both a 8.5% interest from Mitsui E&P Middle East B.V. and 21.25% from AWE Limited (as previously recorded in 1H 2014). Petsec Energy had announced in April 2015 that it had concluded an agreement to acquire an additional 34% working interest (40% financial) in the Block 7 concession from OSYL. The acquisition was to take its total participating involvement up to 63.75% at which point it intended to assume full operatorship of the concession once the deal was ratified by the oil ministry and parliament. Petsec has been steadily expanding its position in the block despite worsening security and logistical challenges. It remained in a state of Force Majeure throughout 2014, nevertheless the government granted OSYL another 12 month licence extension to June 2015, and a 5,000 sq km of airborne magnetic/gravity survey is to be complimented by 250 km of 2D as soon as the operational environment improves. Petsec announced on 30 May 2014 that it had concluded an agreement to acquire an additional 8.5% working interest (10% financial) from Mitsui E&P Middle East BV, thereby taking its total participating involvement up to 29.75%. Otis Energy Ltd had sought to acquire the stake from Mitsui, but been unable to conclude a deal within the time frame allocated. Otis had announced in late December 2013 that all non-governmental partners had approved a preliminary agreement signed during 2Q 2013, but the longstop date for this expired on 24 April 2014, and so the parties had 20 working days until 22 May 2014 within which to complete the transaction. Petsec had previously stated on 28 March 2014 that it was in the process of acquiring a 21.25% working interest in the concession from AWE Limited as part of an agreement requiring full government and partner approval. Block 7 has been held under Force Majeure since the onset of civil unrest in the country in 2011, however a contract extension had been granted to operator OSYL by the government to June 2013, and this was subsequently extended for an additional 12 months to early June 2014. In a company annual report released on 17 October 2012, AWE confirmed that its Yemen concessions had remained under Force Majeure since May 2011 following the onset of civil unrest in the country during February 2011. It had a 19.25% working interest in onshore Block 7 (held by its subsidiary company ARC Energy), and prior to relinquishment it held a 29.75% working interest in the onshore 1,203 sq km Block 74 (Qusa), held by subsidiaries ARC Energy and Adelphi Energy. AWE acquired the acreage positions through corporate acquisition and it intends to refocus its exploration portfolio, with Yemen is no longer regarded as a core area. Significantly, Block 7 includes the 2010 Al Meashar oil discovery and a number of sizeable follow-up prospects. OSYL suspended as a future oil producer Al Meashar 2, pending evaluation of well results on 20 January 2011. It had tested the fractured Basement reservoir section of the appraisal at rates of up to 140 bo/d using a Jet Pump. The well, is located to the south of Block 7 and wireline logging had been completed over the Basement section to a depth of 3,750m TD, which contained oil shows over the interval 3,200m to 3,750m. Prior to this, oil shows had been encountered between 3,200m to 3,460m. Al Meashar 2 had been spudded using UBD or âManaged Pressure Drillingâ techniques with a PTD of 3,740m, using the L/R Joeco ""50106"" on 9 October 2010 to appraise the Al Meashar 1 fractured Basement discovery, which flowed oil but proved inconclusive in terms of productive potential due to formation damage. OSYL had suspended the Al Meashar 1 new-field wildcat on 30 April 2010 as a potential future producer after having to undertake a fishing operation to recover a stuck bottom hole assembly following the completion of the second drill-stem test (DST) over the interval 3,180m-3,660m in the basement section. Flow rates averaged approximately 600 bbl of oil and mud per day and periodically tested higher whilst the well was cleaning up. An open hole DST had previously been undertaken over the interval 3,125m to 3,660m during March 2010 and a production logging tool (PLT) was run following the end of the test, oil flow was obtained from both above and within the basement section. Flow rates from the first test averaged approximately 400 bbls of oil and mud per day and periodically tested higher. Previous testing had resulted in the well flowing oil and drilling fluids to the surface at unstabilised rates. A large amount of unrecovered drilling fluid was lost to the formation. The well reached TD of 3,660m in basement and high levels of gas were observed in the section, following which logging operations were conducted over the open hole section. Al Meashar 1 was spudded using the land rig âJoeco 50106"" on 29 November 2009, to the south of the Block 7 concession with a PTD of approximately 3,650m and a fractured basement play objective. The pre-drill estimate was that the prospect may hold up to 25 MMbo recoverable. OSYL completed a 272 sq km 3D seismic survey in the south-western portion of the block in late July 2008. The initial work commitment for both blocks 7 and 74 included the reprocessing and acquisition of 2D seismic and the drilling of at least seven exploration wells over a 36 month first exploratory period (FEP). Reprocessing of approximately 1,200 km of existing 2D data was also undertaken. Block 7 is located in the Shabwa Sub-basin of the Marib-Al Jawf-Hajar Basin. Soviet company Technoexport drilled five exploration wells in the area between 1983 and 1987. Shabwa 1 was spudded in December 1983 and was plugged and abandoned with oil & gas shows in Tithonian Lam sandstones. The Shabwa 2 to 5 exploration wells were also unsuccessful. Following the merger of North Yemen and the People's Democratic Republic of Yemen (PDRY), Technoexport left the region and the West Shabwa area was divided into 12 blocks. BP became operator of the block in 1991 and during the period 1992 to 1994 drilled five wells, all of which were reportedly dry. Hunt is believed to have submitted an unsuccessful application for the block in 2004. Oil Search was provisionally awarded the Block 7 on 23 July 2005 as part of the Second Yemen Bid Round (Bid Round II). A Production Sharing Agreement (PSA) for the block was signed on 15 April 2007 and the block was ratified by the Yemeni Parliament in March 2008. Equity interests in the block had been Oil Search (Yemen) Limited (32%), ARC Energy Ltd (19.25%), Kufpec (Aden) Ltd (20.25%), Mitsui (E&P) Middle East (8.5%), Dhakwan Petroleum & Mineral Company Limited (5%) and The Yemen Company (15%), however once all pending deals have been fully approved by the government, the participants will be: Petsec Energy (Operator 85% - once finalised) and The Yemen Company (15% carried). Â ",Petsec Energy has taken over operatorship of Block 7 (Al Barqa) after gaining a 100% interest from Oil Search.
35684,"PL 615, W. of Atlantis discovery in Barents, WD 452m, TD 1,678m, 30m gas column in the upper part of the Snadd target, of which 20m moderate-poor reservoir quality, GWC at 1492m 10-20 Bcum recoverable. The lower part of the Snadd is also host to some gas, poor-moderate tight reservoir, 1-4 Bcum recoverable. 15m of aquiferous reservoir was encountered in the Stø fm. Profitability is currently unclear. West Hercules SS now off to Goliat for 7122/7-7 S appr. Equinor (op), partners OMV + Petoro.",Norway (Finnmark Platform (Barents Sea Platform)) Goliat
26671,"Aker BP announced on 31 July 2018 that it will acquire a package of 11 licences from Total in a deal worth USD 205 million. The licences include four discoveries which lie close to existing Aker BP-operated producing fields, therefore adding a total of 83 MMboe (net) which can be developed through tie-backs (Alve North through the Skarv FPSO, Trell and Trine through the Alvheim FPSO and Rind as part of the future NOAKA project). There is further exploration acreage in the southern part of the North Sea close to Aker BPâs Ula field. The licences are: PL 026 (62.13%), PL 036 E (64%), PL 102 C, PL 102 D, PL 102 F and PL 102 G (40%), PL 127 and PL 127 B (50%), PL 127 C (100%), PL 906 (20%) and PL 907 (20%). Completion of the deal is subject to government approval. Alve North was discovered in 2011 by 6607/12-2 S. Gas and oil were present in the Middle and Lower Jurassic â the Fangst and Bat groups â and the Cretaceous Cromer Knoll Group and recoverable reserves are estimated at 44 MMboe (NPD, December 2017). Total drilled Trell exploration well 25/5-9 in 2014. A 21 m gross oil column was proven in the Paleocene Heimdal Formation and estimated recoverable reserves are 16 MMbo (NPD, December 2017). Trine was discovered in 1973 by Elfâs well 25/4-2. The Heimdal Formation contained a 9 m oil column and recoverable reserves are estimated at 24 MMbo (NPD, December 2017). Rind was previously known as Lille Froy and it was also 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. Total currently operates all licences in the deal apart from PL 906 and PL 907 which are operated by Aker BP.","Aker BP announced on 31 July 2018 that it will acquire a package of 11 licences from Total in a deal worth USD 205 million. The licences include four discoveries which lie close to existing Aker BP-operated producing fields, therefore adding a total of 83 MMboe (net) which can be developed through tie-backs (Alve North through the Skarv FPSO, Trell and Trine through the Alvheim FPSO and Rind as part of the future NOAKA project). "
16177,"Eni has sold Mubadala a 10% stake in the Shorouk offshore block 9, containing the producing (400 MMcf/d) Zohr gasfield, for USD 934 MM. Eni, through IEOC, so far held a 60% stake + operatorship, partners BPÂ + Rosneft. Completion of the deal is subject to standard conditions. ","Egypt (Nile Delta B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Zohr (Dev) op. by ENI SPA (60.0%, ROSNEFT 30.0%, BP 10.0%, PETROSHOR 0.0%) to be check.Shorouk Offshore op. by ENI SPA (60.0%, ROSNEFT 30.0%, BP 10.0%) to be check."
64857,"As of 5 November 2019, PetroChina had completed fracture stimulation at Yutan 1 and backflow of fracture fluids were underway. Yutan 1 was drilled to a TD of 6,350m MD and was suspended for testing in late August 2019, having encountered good oil and gas shows in the Permian interval. Yutan 1 was spudded in December 2018 to drill to a PTD of 6,350m and was targeting the Permian Wutonggou Formation as well as the Kelamayi Formation and Shuixigou Group. Yutan 1 is in the PetroChina operated Huoyanshan Block in the Tuha Basin. ","PetroChina had completed fracture stimulation at Yutan 1 and backflow of fracture fluids were underway. Yutan 1 was drilled to a TD of 6,350m MD and was suspended for testing in late August 2019, having encountered good oil and gas shows in the Permian interval. Yutan 1 was spudded in December 2018 to drill to a PTD of 6,350m and was targeting the Permian Wutonggou Formation as well as the Kelamayi Formation and Shuixigou Group. Yutan 1 is in the PetroChina operated Huoyanshan Block in the Tuha Basin. "
84614,"Amidst the ratification on 21 Jun '20 of 8 agreements (DEA 23 Jun '20), Shell is understood to have been assigned the North Cleopatra and North Marina coastal offshore blocks astride the Herodotus and Nile Delta basins. North Cleopatra covers 4,505 sq km and North Marina 4,599 sq km, offered under the cancelled West Mediterranean bid round. GEPS map extracts below.","Egypt (Herodotus and Nile Delta b.), Shell has been awarded the North Cleopatra and North Marina offshore concessions. The two blocks are located along the Egyptian coastline and extend across the boundary between the Herodotus and Nile Delta basins. North Cleopatra and North Marina cover an area of 4,505 sq km and 4,599 sq km, respectively. Both blocks were expected to be on offer as part of the West Mediterranean Bid-round canceled in January 2020 by the Ministry of Petroleum and Mineral Resources."
15064,"Kuwait Energy has made an oil discovery in the South Kheir 1X NFW. The well was tested in late January 2018, and flowed from the Miocene Hammam Faraun Member of the Belayim Formation, at a maximum rate of 2,452 bo/d, on a 128/64"" choke. The discovery is located on the Kheir development lease of the ""Area A"" PSA, in the onshore western Gulf of Suez. It lies to the south of the Kheir Field. The well was spudded on 11 December 2017.The ""Area A"" PSA comprises of six contiguous development leases. It is operated under an Exploration & Production Service Contract with state-entity General Petroleum Co (GPC). Under the terms of the rare risk-service agreement, contractors/IOCs carry all the cost of exploration activity. If a development lease is granted and production commences, then contractors are paid a service fee related to output, with the state (in the form of GPC), entitled to 100% of production. Kuwait Energy (70% WI) and Petrogas (30% WI), signed the PSA in 2013. GPC holds the concession rights with 100% equity.","South Kheir 1X (SK-1X) op. by Kuwait Egy. (70%, Petrogas E&P 30%) in Shukheir (Area A) tested successfully at an initial oil flow rate of 2 452 bo/d from the Hamman Faraun MBR/Belayim Fm [2ââchoke], after that the well stabilized at an oil rate of 1 900 bo/d [1ââchoke]. "
8431,"EnQuest subsidiary EnQuest Heather Limited, partnered by Ithaca Energy (UK) Limited, has been awarded an out of round licence in the Northern North Sea. Licence P2334 which comprises of one block â 211/18h was officially awarded on 1 July 2017 (executed on 26 October 2017). The licence is situated between the West Don field to the west and the Conrie field to the east. The licence covers an area of 6.6 sq km. Interest in the licence is held by EnQuest Heather Limited (60%) and Ithaca Energy (UK) Limited (40%).","EnQuest (60%) partnered by Ithaca Energy (40%), has been awarded an out of round P2334 licence. "
81304,"PetroChina â Xinjiang made an important breakthrough in the Junggar Basin. Chepai 24, a NFW, tested 845 b/d of oil and 586 Mcf/d of gas through a 6 mm choke after a racking from the Permian Jiamuhe 3 Formation on 14 May 2020. The well was drilled in the west of the Shawan Sag near Chepaizi High in the northwest of the basin. The existing fields found in this area has main reservoirs in the Jurassic and Triassic formation. This is the first commercial oil and gas flow achieved from the Jiamuhe Formation in this area. The Jiamuhe Formation consist of coarse-grained clastics deposited in an alluvial fan environment and some volcanic rocks. It has been identified as reservoirs mainly in the northwestern. Background Information Several exploration successes have been achieved recently in the Shawan area in the Junggar Basin. In April 2020, PetroChina made a new gas discovery in the Junggar Basin in April 2020. Shatan 2 tested 847 Mcf/d of gas from 5,490 to 5,589 m in the Permian Fencheng Formation. The well is drilled in the Shanwan Sag and the success indicated a gas play fairway of 3,200 sq km. In October 2019, PetroChina made an important breakthrough in the Junggar Basin. Chetan 1 tested commercial oil flow in the Carboniferous Tailegula Formation on 22 October 2019. This is the first well which makes a breakthrough in the Carboniferous in this area and it indicates a significant potential prospective for carboniferous play in this area. In December 2018, PetroChina made oil discovery in Shatan 1 in the Shawan Sag. The well tested 190 b/d of oil from 5,344 to 5,375 m in the Permian Wuerhe Formation. Shatan 1 is drilled in the northwest Shawan Sag. The well also encountered good oil shows in other formations during drilling, such as Triassic Baikouquan and Karamay formations. The success of the well indicated a new exploration potential prospective area for the Wuerhe play fairway. The Junggar Basin is one of the key exploration and production base for PetroChina. The company has approved more than 25 oil and gas fields by 2018 with total of 22 bn bbls of oil and 6 Tcf of gas in place reserves. In 2019 PetroChina produced 12.47 million tons of oil (249,000 b/d) in the basin, and company plans to increase oil production to 260,000 b/d by 2020.","Chepal 24 nfw. in Shawan Sag near Chepaizi High, Basin, tested 845 bo/d + 586 Mcfg/d on 6mm choke from a fracked Permian Jiamuhe 3 fm on 14 May '20. This is the 1st commercial flow from the Jiamuhe in this area (otherwise Jurassic + Triassic)."
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 companyâs 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 UKâs 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 Petrofacâs interests in the Greater Stella area licences and related infrastructure interests for a staged total of US$250 MM. The deal should increase Ithacaâs 2P reserves by over 20 MMboe. Involved are licences P011 (Stella/Harrier, 100%), P1665/P2190 (Hurricane, 100%), P1392 (Jacky,100%), P1293 (Athena, 40%),"
39890,"PEMEX plugged and abandoned dry the Betan 1EXP new-field wildcat (NFW) in the AE-0051-5M-Mezcalapa-01 entitlement during late-January 2019. The final total depth (TD) was 2,580 m.  The NFW was spudded on 19 November 2018. The well had a proposed total depth (PTD) of 2,666 m and the primary target was the Miocene.       The NFW had estimated prospective resources of 25 MMboe.  The prospect is located in the north central area of the block. SENER awarded the AE-0051-5M-Mezcalapa-01 entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 974.04 sq km. The entitlement has been modified five times, the latest was 13 September 2018 whereby the area of the block was increased from 652 to 1,548 sq km. Previously the well was officially located in the AE-0052-3M-Mezcalapa-02 whose area was reduced and incorporated into the AE-0051 block.","Betan 1EXP (NFW) in the AE-0051-5M-Mezcalapa-01 entitlement, P&A dry"
63519,"On 1 November 2019, BHP Billiton Petroleum (Deepwater) was awarded 11 Garden Banks blocks: GB 630 (G36802), GB 672 (G36731), GB 676 (G36803), GB 677 (G36804), GB 716 (G36732) and GB 760 (G36733), GB 762 (G36805), GB 805 (G36806), GB 806 (G36807), GB 852 (G36809) and GB 895 (G36810), all located in the East Texas Coastal Basin. The blocks were originally offered as part of OCS Gulf of Mexico Lease Sale 253, held on 21 August 2019, which garnered more than US$ 159 million in high bids. BHP Billiton Petroleum (Deepwater) accounted for 20 high bids, worth a total of US$ 41.8 million. Following official award, BHP Billiton Petroleum (Deepwater) is the operator and sole interest-holder (100% WI + Op) in all 11 Garden Banks blocks.",Not Found
48071,"On 7 May 2019 the NPD reported that Wellesley has taken Equinorâs 20% interest in PL 871, effective from 30 April 2019. The licence contains dry hole 25/1-13 which was drilled on the Balcom prospect, between Frigg and Froy, in Q1 2019. 25/1-13 confirmed the presence of the main Eocene Frigg Formation objective, finding a 50 m section with 10 m of sandstone. There were some gas shows but the sands were water-wet, as was a 40 m Balder section (with 20 m of sandstone). Wellesley Petroleum AS operates PL 871 with an 80% interest. It is partnered by LOTOS Exploration and Production Norge AS (20%).","Wellesley has taken Equinorâs 20% interest in PL 871, (Central Viking Graben (Viking Graben Province)) Frigg"
40400,"On 15 January 2019, the Federal Agency for Subsoil Use held an auction for two blocks in Yamalo-Nenets Autonomous Okrug (West Siberia). Gazprom Neft-Noyabrskneftegaz emerged as the winner for both licenses. The winner of the auction will obtain 25-year E&P licenses with a seven-year exploratory stage. Details of the offer are as follows: The Novoromanovskiy block covers 110 sq km in the northern part of the Middle Ob Province and encompasses a part of the Romanovkoye oil field with 3P reserves estimated at 42 MMbbl. Seismic coverage amounts to 253 km of 2D data and 135 sq km of 3D data. Four exploratory wells have been drilled in the area. Hydrocarbon resources (categories D1+D2) of the block are estimated at 54 MMbbl of oil, 38 Bcf of gas and 1 MMbbl of condensate. The starting price amounted to RUB 428.78 million (USD 6.4 million). Gazprom Neft-Noyabrskneftegaz offered RUB 471.658 million (USD 7 million). The Stakhanovskiy Severnyy block covers 2,083 sq km in the southern part of the Nadym-Taz Province and encompasses the Stakhanovskoye Severnoye and Yokhturskoye Severnoye discoveries with combined 3P reserves estimated at 9 MMbbl of oil and two prospects with combined resources estimated at 29 MMbbl of oil, 60 Bcf of gas and 1 MMbbl of condensate. Seismic coverage amounts to 1,912 km of 2D data. Nine exploratory wells have been drilled in the area. Hydrocarbon resources (categories D1+D2) of the block are estimated at 175 MMbbl of oil, 2.3 Tcf of gas and 41 MMbbl of condensate. The starting price amounted to RUB 269.42 million (USD 4 million). Gazprom Neft-Noyabrskneftegaz offered RUB 296.363 million (USD 4.4 million).","Russia, not found"
30661,"On 24 September 2018, Kuwait Energy plc (KE) announced that it had agreed to sell its entire issued share capital to United Energy Group Ltd (UEG). Under the terms of the agreement UEG will acquire the share capital of KE for an approximate consideration of USD491 million on a fully diluted basis which equates to approximately USD1.50 per share. The agreement has been approved unanimously by the KE Board of Directors. KE operates Block 9 in Iraq which contains the Faihaa oil field. Faihaa, which is believed to represent an extension of the Yadavaran field in Iran, is currently producing approximately 20,000 b/d. KE has a 60% interest in Block 9 with partners Dragon Oil plc 30% and Egyptian General Petroleum Corporation (EGPC) 10%. It also signed a 20 year gas development and production service contract with the Iraqi Ministry of Oil for the Siba field on 5 June 2011. KEC 30% is partnered in the contract by Turkiye Petrolleri A.O. (TPAO) 30%, Missan Oil Company (MOC) 25% and EGPC 15%. In April 2018, UEG was awarded the Sindbad Block in the south of Iraq as part of a tender for exploration, development and production of blocks on Iraqâs borders with Kuwait and Iran. The contract when ratified will have a 34 year duration + optional nine-year extension.","Iraq, Sindbad Block"
74779,"Boxi block, Shaleitian Uplift in W. Bohai Gulf Basin, WD 22m, ops terminated 15 Mar '20, results n/a, Bohai 9 JU. Target Oligo-Miocene clastics.","China, Boxi"
67934,"The Neuquén authorities have granted Equinor sole rights to the Aguila Mora Noreste block, offered under the open-door Plan Exploratorio Neuquen round in July. Commitments call for seismic reprocessing in year 1, an explo well in year 2-3, and G&G in year 3. The 73-sq km block is adjacent south of Equinorâs own Bajo del Toro Este block:","The Neuquén authorities have granted Equinor sole rights to the Aguila Mora Noreste block, offered under the open-door Plan Exploratorio Neuquén"
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%)."
22098,"The authorities have set back the bid deadline for the 4th round from 28 Jun â18 to 27 Sep â18 following an election period. Five blocks remain available, namely SL-A-18, SL-B-18, SL-C-18, SL-D-18 + SL-E-18, 5,000-7,000 sq km apiece. Illustration below http://www.pd-sl.com/data-portal. Of note, SL-C-18 comprises the Mercury, Jupiter and a large part of Venus oil discoveries. SL-B-18 is home to Lukoilâs Savannah-1 (2013, oil shows). SL-A-18, SLD-18 and SL-E-18 are undrilled. Contact Raymond Kargbo, raymond.kargbo@pd.gov.sl or John Clark, john.clark@ercl.com.","The authorities have set back the bid deadline for the 4th round from 28 Jun â18 to 27 Sep â18 following an election period. Five blocks remain available, namely SL-A-18, SL-B-18, SL-C-18, SL-D-18 + SL-E-18, "
10888,"On 11 December 2017 it was announced that the merger between Centrica and Stadtwerke Munchen GmbH to combine Centricaâs 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 seeâs Centrica take a 69% interest with Bayerngas Norgeâs existing shareholders owning 31% of the joint venture. Spirit Energyâs 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 Centricaâs cash generative and near-term production profile and Bayerngas Norgeâs more recent production assets (to have come onstream) and the latterâs 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 â 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"
81926,"Castanha devt area in Cabinda Sul onshore block, P&A dry at TD 2,961m (Mayombe Complex) early Jun '20. Target pre-salt Lucula sst.","Angola, Cabinda Sul (Castanha)"
38393,"Local news reported in early January 2019 that for 2019 Trinidad and Tobagoâs Heritage Petroleum Company Limited is seeking a joint venture partner, which will help with financing and technology and assist with the production of oil. According to the companyâs Chairman Wilfred Espinet, âWe are going to, first of all, determine what is the value of our assets before we engage in this because we want to ensure when we sit down with anyone we know the value of our assets so that we get a fair deal.â. The company plans seismic program over the highly prospective fields, in order to have a better understanding of the potential, and plans to increase the oil production to 40,000 bo/d. The Chairman plans to have a permanent staff by the end of 2019. Trinidad and Tobago Heritage Petroleum Company Limited - was incorporated on 5 October 2018 in the business of exploration, development, production and marketing of crude oil. Heritage, Paria Fuel Trading Company as well as another company will fall under the holding company, Trinidad Petroleum Company. The new company, replaces Petrotrin.","Heritage Petroleum Company Limited is seeking a joint venture partner, which will help with financing and technology and assist with the production of oil. "
34211,"On 10 October, the ANP approved a 50% working interest transfer from Newo Equipamentos to NTF Oleo e Gas Ltda in the Itaparica block. NTF is assumed to be a small local Brazilian company. Newo will remaing the operator of the contract with a 50% working interest and NTF has 50%. On 31 August 2017, the Agencia Nacional de Petroleo (ANP) granted a Final Award contract to Newo Equipamentos for the Itaparica block after it was granted a preliminary award through the ANP 4th Marginal Fields Bid Round. On 11 May 2017, the Agencia Nacional de Petroleo (ANP) held the ANP 4th Marginal Fields Bid Round resulting in eight blocks provisionally awarded to the high bidders including the Itaparica block to Newo Equipamentos. Newo bid BR 5,710,000 representing the highest bid and most contested block in the round and beat out three other bids. The second highest bid was by Dimensional Eng who bid BR 2,264,646.46 and the third highest bid was made by Munkcs & Reboque who bid BR 1,077,777. The fourth highest bid was made by the consortium of Oil and Gas Investments Group (70%) and Geomecanicas SA (30%) who bid BR 501,350. The minimum work program calls for expenditures of BR 2,800,000 with four workovers. There were no local content requirements for the block. The company has a three year evaluation phase from contract signature date. The Itaparica block covers an area of 21.68 sq km with 16 shut-in or plugged and abandoned wells. The original oil in place was reported by the ANP to be 37.29 MMbo and 33.04 Bcfg. The field has produced 1,553,583 bo and 13,104,473 Mcfg.",Brazil (Southeast Reconcavo Sub-basin (Reconcavo B.)) Itaparica
69716,"Santos Ltd spudded the Toltec 1 exploration well in ATP 1189-P, located in the Cooper-Eromanga Basin, on 3 January 2020. The well was drilled to a total depth of 2,422 m, before being suspended as a gas discovery on 12 January 2020. The well was part of Santos' ongoing exploration programme within the ATP 1189-P permit. ATP 1189-P, which covers an area of 3,452 sq km, was awarded on 1 January 2015. The well was located in the Aquit. B block, in which participants are Santos Ltd (25% + Operator), Santos subsidiaries Vamgas Pty Ltd (5%) and Santos Petroleum Pty Ltd (25%) and Beach Energy subsidiaries Lattice Energy Ltd (25%) and Delhi Petroleum Pty Ltd (20%).","Toltec 1 (Santos 55% op. Beach Energy 45%) in ATP 1189 Block, gas discovery. "
85186,"Eco Atlantic, one of the partners in the Orinduik Block, offshore Guyana, has highlighted that the oil discovered in the Joe and Jethro discoveries could now be more attractive due to reduced supply from Venezuela, sources reported in early July 2020. Gil Holzman, CEO of Eco Atlantic, has pointed out that US sanctions on Venezuela have resulted in over 18 MMbo from Venezuela idling at sea being unable to find buyers. Holzman said, âThe outlook for (heavy) oil going from 2024 onwards is very promising. Many Gulf Coast and European and Chinese refineries are very thirsty for this kind of heavy oil and we see a narrowing supply due to the sanctions on Venezuelaâ¦We therefore forecast that the price for heavy oil will get better and betterâ. He followed up that there are positive indicators for the commercialization of the asset: âIn terms of its producibility, all the reservoir ingredients are very positive, the permeability and porosity are high. We have an overpressure in the reservoir and the temperature is high. It is now 94°C and that means the oil is mobile and the potential is there for it to flow to produceâ.Back in March 2020, Tullow admitted in its 2019 Annual Report that its Joe and Jethro discoveries ""were ultimately disappointing with lower oil quality discovered than originally prognosed"".Tullow had previously reported in November 2019 that the oil found in the Jethro and Joe discoveries, made in August and September 2019 respectively, was found to be heavy and highly sulphurous rather than the light oil discoveries made by ExxonMobil in the neighbouring Stabroek Block. Tullow warned that it was assessing the commercial viability of these discoveries (both estimated to contain over 100 MMboe of recoverable oil) and reviewing options following this development. Heavier oil is much less desirable as its more costly to extract and less valuable. On 12 August 2019, Tullow announced that it had discovered oil in the Jethro-Lobe 1 NFW. On 16 September 2019, Tullow announced the Joe 1 NFW as a play opening oil discovery on the Orinduik Block. Joe 1 is located less than 30km to the west of the Jethro-Lobe 1 well.Tullow Oil operates the block with 60% WI, Total holds 25% WI and EcoAtlantic holds 15% WI. On 29 July 2019 Qatar Petroleum entered into an agreement to acquire 10% WI from French supermajor Total in the offshore Orinduik and Kanuku blocks in Guyana. The deal is still thought to be pending approval. ","Guyana (Guyana B.) Eco Atlantic, one of the partners in the Orinduik Block, offshore Guyana, has highlighted that the oil discovered in the Joe and Jethro discoveries could now be more attractive due to reduced supply from Venezuela, "
55839,"UKOG has agreed to acquire Magellanâs 35% in PEDL 137 + 246, home to the Horse Hill field, for GBP 12 MM. UKOGâs interest here therefore jumps to 85.635%, and provides for full operatorship on the drilling programme and production framework.","UKOG (->85,635% op.) has agreed to acquire Magellanâs 35% in PEDL 137 + 246, home to the Horse Hill field, for GBP12 MM. "
64987,"The joint venture partnership of Metgasco Pty Ltd, Vintage Energy Pty Ltd and Bridgeport Energy Ltd has entered into an agreement with Senex Energy Ltd to enter PRL 211, located in the Cooper-Eromanga Basins. The joint venture 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. The Vali Prospect, located solely in ATP 2021-P, is scheduled to be drilled in December 2019 which could provide significant de-risking of the Odin Prospect. Under the terms of the initial farm-in agreement, a term sheet has been executed with a 90-day exclusivity period for the companies to negotiate a final farm-in agreement. Upon completion, it's proposed that Vintage will acquire operatorship of the licence with 42.5% interest. The remaining interest will be split between Bridgeport (21.25%), Metgasco (21.25%) and current holder Senex (15%). A number of conditions must be satisfied by 31 January 2020 including Ministerial approvals, a demonstration of sufficient funds being available to drill a well and the execution of a formal farm-in agreement. 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. It's 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. 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. Across the state and licence boundary, ATP 2021-P is mainly prospective for Permian gas and Jurassic oil accumulations. The Vali Prospect could be tested in December 2019 which comprises an anticlinal structure at the Toolachee and lower Patchawarra levels with independent closure at a depth of around 2,250 m. Metgasco has reported that the prospect is likely to contain reservoir characteristics similar to that of the nearby Kinta 1 gas discovery. The Kinta 1 well intersected 37 m of interpreted gas pay but did not retuned hydrocarbons to surface. Vali has been assigned P50 recoverable resources of 19 Bcf.","Bridgeport Energy Ltd, Metgasco Pty Ltd, Vintage Energy Pty Ltd extend their JV partnership to PRL 211, Cooper-Eromanga Basins"
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%)."
9846,"Repsol has reportedly seen the award formally inked of its Iñiguazú block, 644 sq km in Tarija, Sub-Andean Chaco Basin. The block lies adjacent to the Margarita-Huacaya gasfield in the Caipipendi area, where drilling has been underway since July at Boyuy X-2. The legislative assembly needs to approve the contract by end 2017. Repsol (op) 15%, Shell 15%, Pan American Energy 10%, YPFB 60%. ",Bolivia (Chaco Sub-Andean Zone (Chaco B.)) Margarita-Huacaya
31828,"Terra Nova Energy Ltd and Holloman Corp are seeking to divest their combined 100% interest in exploration licences PEL 112 and PEL 444, located in the Cooper-Eromanga Basin. Both companies would consider farming-down around 80% combined interest or fully divesting ownership to interested parties. If the companies are successful at fully divesting their interest, it will result in Australian exits for both. 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. In 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. Wolfman 1 well was drilled within the Mulka very 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%). Companies interested in these opportunities should contact: Istvan Gyorfi, Exploration Manager, Terra Nova Phone: +65 9152 5427 Email: Istvan.gyorfi@paclng.com","Australia Holloman Corp, Terra Nova Energy (Australia) Pty Ltd looking to divest PEL 112 and PEL 444, Cooper-Eromanga Basin"
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 doesnât have to relinquish any area. If the exploration period ends and the contractor doesnât have any discoveries it must relinquish 100%. If the exploration period ends and the operator doesnât 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. "
14625,"Parliament is expected to approve the Lease Agreement Hellenic Petroleum's onshore Arta-Preveza and NW Peloponnese blocks during February 2018. Hellenic signed the Lease Agreements with the Greek Government on 25 May 2017, following approval by the Court of Auditors. The blocks were pre-awarded to Hellenic as part of the Onshore Western Greece Tender in February 2016. Upon parliamentary ratification of the contracts, Hellenic will be given a three-phase, seven-year exploration term for each block, and has already indicated will consider farm-in offers from interested companies. ",Parliament is expected to approve the Lease Agreement Hellenic Petroleum's onshore Arta-Preveza and NW Peloponnese blocks
9027,"Africa Oil Corp. and Eco (Atlantic) O+G have agreed a strategic partnership for exploration in Namibia and Guyana. AOC will acquire a 19.77% shareholding in ECO for USD 10.9 MM in a share deal and secure an ECO board position. This new investment complements AOCâs 28.5% in Africa Energy Corp., itself holder of rights offshore Namibia and offshore South Africa. ","Namibia, not found"
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 Equinorâs 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%)."
42747,"Eni has been pre-awarded the West Sherbean Onshore block, following the announcement of the winners of the EGAS 2018 International Bid Round on 12 February 2019. SDX was the sole competing bidder for the acreage. The 1,538 sq km block is located in the Nile Delta Basin and lies adjacent to the Abu Madi and Nile Delta concessions, in which Eni holds 37.5% and 50% equity respectively. Work commitments include expenditure of US$ 18 million and two wells in the initial exploration period. A US$ 5 million signature bonus will be paid. Upon PSC signature, Eni will operate the concession with 50% equity, in partnership with BP (50%).","Eni has been pre-awarded the West Sherbean Onshore block, following the announcement of the winners of the EGAS 2018 International Bid Round on 12 February 2019. SDX was the sole competing bidder for the acreage. The 1,538 sq km block is located in the Nile Delta Basin and lies adjacent to the Abu Madi and Nile Delta concessions, in which Eni holds 37.5% and 50% equity respectively. Work commitments include expenditure of US$ 18 million and two wells in the initial exploration period. A US$ 5 million signature bonus will be paid. Upon PSC signature, Eni will operate the concession with 50% equity, in partnership with BP (50%)."
25585,"Eni waiting for the signature of the award of the Lagia North exploration block in the Sinai onshore area. The block covers 1,457 sq km onshore in the northern Gulf of Suez, surrounding the three existing producing leases Asl, Ras Sudr and Ras Matarma operated by the government-owned General Petroleum Company (GPC). Background information An agreement has been initialed for the award of the North Lagia block to Burren Energy Egypt Ltd. The British company will operate the block with a 90% interest while partner Goura Oil will have a 10% interest. The final agreement was assumed to signed in 2005. The bid round was organized by the Ganope El Wadi Petroleum Holding Company (Ganope), with a total of five exploration blocks offered in Upper Egypt under PS terms. The blocks are in the southern Gulf of Suez, the Red Sea and the Western Desert. The deadline was 16 November 2004.",Eni waiting for the signature of the award of the North Lagia exploration block in the Sinai onshore area (1457km²).
14157,"L10, offshore Broad Fourteens Basin, started 17 Nov â17 targeting the Ziegler prospect, completed as a gas discovery and hooked up for prod on 25 Jan â18, Ensco 101 JU. Engie (op), partners Rosewood, XTO, EBN.","L/10-39 op. by Engie (38,55%, EBN 40%, Rosewood 11,4%, XTO 10,05%) in L10 & L11a block, gas discov. gas."
38496,"The BOEM has approved BP as operator and sole owner of the Tiber + Guadalupe discoveries in the NW Keathley Canyon and slated for devt, following Chevronâs decision to withdraw in Sep â18. Prior to this the acreage had been run by Chevron and BP 50:50.",United States (Chicontepec Sub-basin (Tampico-Misantla B.)) Guadalupe
19928,"The ANP on 17 April 2018 extended the contracts for 11 blocks from ANP Round 12 and five from Round 11 in the Reconcavo, Parnaiba and Sergipe-Alagoas basins for two years. Both rounds were conducted in 2013. The extended contracts are from Petrobras for REC-T-52, REC-T-80, REC-T-50, REC-T-51, REC-T-60, REC-T-32, REC-T-61, REC-T-40, SEAL-T-420, SEAL-T-112, PN-T-150 and PN-T-166, Galp (PN-T-182 and PN-T-136) and Geopark (REC-T-94 and SEAL-T-268). The first exploration phase of these contracts was previously due to end in 2019 or 2020. The possibility to extend the contracts was made official by a resolution of the National Energy Policy Council (CNPE) in February 2017 and in October 2017 the ANP issued a resolution regulating the signature of amendments to Round 11 and 12 contracts for the exploration phase. The ANP also noted that to be eligible for the extensions that operators must comply with all obligations of the contracts, especially the payment of special participation taxes in addition to paying the financial guarantees for the work programs. The extensions were the result of arguments by the companies that they had to reschedule exploration programs due to low oil prices and long delays in the environmental licensing process. Brazil currently has 154 contracts from Rounds 11 and 12 which include 46 offshore blocks and 108 onshore blocks.",Not Found
8877,"Early November 2017, Tullow Oil plc completed the drilling of the appraisal well Amosing-7 in the Block 10BB. Amosing -7 was the last well of the 2017 drilling programme. Therefore the Marriott-46 rig was demobilised. The well encountered 25 m of net oil and gas pay. No further information was disclosed. Tullow Oil operates blocks 10BB with a 50% interest partnered with Africa Oil with 25% and Maersk Oil & Gas with 25%. Gross unrisked oil resources (2C) South Lokichar Basin are estimated at 754 MMbbl. Tullow and its partners signed the Early Oil Pilot Scheme (EOPS) agreement to transport oil from the South Lokichar fields to Mombasa on 14 March 2017. The EOPS represents an immediate step on the road to full commercialization of the oil resources and it will be followed by a full-scale Field Development Plan. In mid-March 2017, Tullow Oil completed the appraisal well Amosing 6 that encountered 35 meters of net gas and oil pay. The well was drilled near a bounding fault and was spudded early February 2017 with the âPR Marriot 46â land rig. The Amosing 6 was the second well in a four-well drilling campaign in the South Lokichar Basin (Blocks 10BB and 13T), which started in December 2016 and led to the Erut 1 oil discovery in January 2017. The Amosing field has recoverable resources estimated at 151.1 MMbbl of oil, whereas the Ngamia field has 296.7 MMbbl of oil.","Kenya (East African Rift System, Eastern Branch) Erut 1 op. by TULLOW (50.0%, MAERSK 25.0%, AFRICA OIL 25.0%) in Block 13T"
17616,"Pertamina will reportedly be signing a contract with NIOC in May for the further devt off the Mansouri field, SE of Ahvaz in Khuzestan. Pertamina will hold an 80% stake but intends to farmout. Plans are to boost output from 60,000 b/d to 250,000 b/d in 5 years. The field is currently run by National Iranian South Oil Co.",Pertamina will reportedly be signing a contract with NIOC in May for the further devt. off the Mansouri field.
68874,"Wintershall Dea GmbH disclosed on 9 January 2020 it had entered into an agreement with RDG GmbH & Co. KG (RDG) for the purpose of selling interests in several production contracts in the country's various petroleum provinces. The catalogue of the assets is as follows (working interest in bracket): 1) Aitingen (33.33%), 2) Hebertshausen (100%), 3) Landau (66.67%), 4) Lauben/Bedernau (50%), 5) Schwabmuenchen (100%), 6) Suderbruch (100%) and 7) Tannheim/Engelsberg (50%). The licenses sold to RDG yield approximately 1,000 boe/d, some 2% of the company's daily output in Germany. The Wintershall Dea's move follows a global revision of the domestic asset portfolio and a strategic decision to concentrate on the core assets, i.e. oil production from the Emlichheim and Mittelplate fields and gas production in the Verden area (all in northern Germany). The Aitingen, Hebertshausen, Lauben/Bedernau, Tannheim/Engelsberg and Schwabmuenchen blocks are located in the Molasse Basin (Alpine Foreland), the Landau concession is located within the northern sector of the Upper Rhine Graben, while the Suderbruch concession falls within the Lower Saxony Sub-basin (Northwest German Basin).","Wintershall Dea is selling its operated participating interests in certain domestic oil concessions to compatriot player RDG. The concessions being sold include Aitingen (in which Wintershall Dea holds a 33.33% interest), Schwabmuenchen (100%), Lauben/Bedernau (50%) and Hebertshausen (100%), all of which are located in Bavaria, southern Germany.Also part of the deal is Wintershall Deaâs 66% interest in the Landau concession in Rhineland-Palatinate, the Tannheim/Engelsberg concession (50%) in Baden-Wurttemberg and the Suderbruch concession (100%) in Lower Saxony.The licences contribute about 1000 boe/d to Wintershall Deaâs production."
27951,"On 20 August 2018 it was reported that the Neuquen provincial government will award a 35 year production concession to partners Pluspetrol and YPF subsidiary YSur on the 230 sq km La Calera Block, Neuquen Basin. The partners are committed to an initial 2 year pilot plan including the drilling of 10 wells and US$ 180 million investment. If the plan is successful, the companies will start a contingent plan for 2019-2021 to drill 35 horizontal wells and to construct production infrastructure including a pipeline network and a 70 MMcfg/d gas treatment plant. This second stage would include an US$ 450 million investment. The total development plan is expected to include up to 207 wells with a US$ 2.21 billion investment. In the meantime, the Energy and Mining Ministry (MINEM) recently announced limits to the application of Resolution 46 which grants special pricing for new unconventional gas projects. It is not clear if this project will be included or not in this regime. Recently the partners applied for inclusion in this Plan Gas promotional pricing plan. This 230 sq km block is located between the Loma Campana and Aguada Pichana Este blocks within the Vaca Muerta gas window sweet spot. Two drilling rigs are expected to be used for the project. In late December 2017, the operator completed a 13 stage frack and tested gas on the La Calera x-3001(h) horizontal wildcat. Tests were conducted over the 3,184-4,612m gross interval. The well targeted the Vaca Muerta Shale.","Pluspetrol and YPF have been awarded explo rights to the 230 sq km La Calera Block,"
68647,"Ref. DEA 17 Jul '19, Premier's 20% farmin to Mubadala's Andaman I + South Andaman offshore gross split contracts is now a done deal, effective Dec '19. Partnership 80:20:",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.
21145,"Ref. DEA 27 Apr â18, 16 companies had filed EoI, qualification docs + participation fees for the 4th Pre-Salt round by the 20 April deadline. The list of companies is now published and includes BP, Chevron, CNODC, CNOOC, DEA (newcomer), Ecopetrol, ExxonMobil, Petrogal, Petrobras, Petronas (newcomer), Qatar Petr., Queiroz Galvão, Repsol, Shell, Statoil, and Total. The round is pencilled for 7 June and will comprise the Itaimbezinho, Três Marias, Dois Irmãos and Uirapuru areas in the Campos + Santos basins.","Ref. DEA 27 Apr â18, 16 companies had filed EoI, qualification docs + participation fees for the 4th Pre-Salt round by the 20 April deadline. The list of companies is now published and includes BP, Chevron, CNODC, CNOOC, DEA (newcomer), Ecopetrol, ExxonMobil, Petrogal, Petrobras, Petronas (newcomer), Qatar Petr., Queiroz Galvão, Repsol, Shell, Statoil, and Total. The round is pencilled for 7 June and will comprise the Itaimbezinho, Três Marias, Dois Irmãos and Uirapuru areas in the Campos + Santos basins."
31232,"Ahead of drilling, Europa is preparing to farmout Licence Option 16/20, 945 sq km in WD 950-2,000m, Erris sub-basin (NW Ireland Offshore Basin). Prospects identified include Inishkea (main, target gas), Inishkea NW, Inishkea W, the Bofin lead, Corrib North discovery, Corrib NW prospect. A data room is due to open Jan â19. Contact Murray Johnson, Murray.Johnson@europaoil.com.",Ireland (Slyne Sub-basin (NW Ireland Offshore B.)) Corrib
87624,"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 â Kina Petroleum MD Tel: +61 2 8247 2500 Email: richard.schroder@kinapetroleum.com","(Papuan B.) PPL 435 & PPL 436, operated by KINA PT (100%), Kina Petroleum Corp is offering equity."
52856,"8 July 2019, Uzbekneftegaz (UNG) reports another gas discovery in the North Ustyurt Basin (north-western Uzbekistan). Well Kushkair 1 has been drilled to a TD of 3,550 m and has tested gas with condensate at rates of up to 200,000 cu m/d (6.85 MMscf/d). UNG is continuing to test the well and expects to estimate of the discoveryâs reserves later in H2 2019. Although UNG calls Kushkair a new discovery, the company drilled the first exploration well, Central Kushkair 1, not later than in the early 1980s. The well was drilled to a TD of 3,780 m and tested 50,000 cu m/d (1.7 MMscf/d) of gas from the Upper Carboniferous carbonates. The top Carboniferous in this well occurs at 3,548 m. The Kushkair discovery is located in the south-western part of the North Ustyurt Basin, around 40 km south-west of the large Urga gas field. Earlier this month UNG reported a âgiantâ gas discovery in Ustyurt, at Arslan-Surgil Janubiy, east of the major Surgil gas field. However, numerous exploration wells drilled in the basinâs Uzbek sector since in the 2000s have been unsuccessful or have resulted in minor discoveries, leading to several operators relinquishing their exploration acreage in the region (e.g. Gazprom, Petronas, Petrovietnam and the Aral Sea consortium (ASOC)). Background Information Most of the known gas fields in the North Ustyurt Basinâs Uzbek part have their reservoirs in Jurassic clastics, but gas pools in Paleozoic (Carboniferous) reservoirs have been found in four fields (Karachalak, Kokchalak, Urga Shimoliy and Chibiny). Oil and gas shows have also been registered in Paleozoic formations in several wells drilled in the Uzbek sector, e.g. Karakuduk, Barsakelmes Sharkiy, Karaumbet Shimoliy and others. A gas pool in Carboniferous limestones has been discovered at Tarymgaya in the neighbouring Daryalyk-Daudan Basin in Turkmenistan. Two general play types are believed to be prospective in the Paleozoic (Pre-Upper Permian) formations - one is represented by Paleozoic buried hills, while the other is associated with reservoirs within the Paleozoic formations. The Paleozoic buried hills play is controlled by secondary reservoir development at the top of Paleozoic formations because of processes such as leaching, weathering etc. A discovery in this play is known at Kokchalak where the reservoir is represented by weathered Lower-Middle Carboniferous limestones. The gas/condensate discovery at Karachalak is believed to belong to the Intra-Paleozoic play. A gas pool at Karachalak occurs slightly deeper than the top Paleozoic. Hydrocarbons have been tested from Visean fractured and leached limestones.","Kushkair 1 (UzbekNefteGaz 100%) SW part of basin in NW of the country, TD=3550m gas-cond discovery, tested up to 6.85 MMcfg/d, ops continue. Despite the official notion of âdiscoveyâ, a well designated Central Kushkair was drilled in the early 80s, TD=3780m, 1,7 MMcfg/d on test from U. Carboniferous carbs."
74046,"Oil Search Ltd spudded the Gobe Footwall 1 oil and gas exploration well in PDL 4, located in the Papuan Fold Belt, on 12 November 2019. The well was targeting the Gobe Footwall Prospect, a nearfield exploration well to the Gobe Main oil field, with an aim to extend the field life of the Gobe field. Though both the Toro and Iagifu target reservoirs were encountered, both were determined (from logs and pressure/sample data) to be water bearing, with minor oil shows. Oil Search reported on 6 February 2020 that it was preparing to plug and abandon the well. The rig was released from site on 12 February 2020 after reaching a total depth of 4,370 m. The Gobe Footwall 1 well was drilled by the ""High Arctic 103"" land rig and had a planned total depth of 3,650 m. Oil Search reported on 9 January 2020 that the well was sidetracked to ensure the main objectives were reached at the correct depth. The main bore hole was plugged-back and sidetracked at a depth of 1,230 m to reach the footwall objective after it was determined a more vertical angle was required. The well had already drilled through the Darai Formation in the 12-1/4"" section, from 2,226 to 2,914 m. The Gobe Footwall prospect lies directly to the southwest of the Gobe oil field in the underlying footwall of the sub-thrust. It is targeting the Iagifu and Toro sandstones, and was drilled from an existing Gobe Main field wellpad as a deviated well. Oil Search reports that data indicates the Gobe Footwall structure is similar to both the Agogo and Hedinia footwall structures. The Gobe Main and southeast fields have been producing oil since 1998 and have around 5-10 years left of production at declining current rates of around 800 bo/d. It is hoped that near field success could extend the field life. Since acquiring around 50 km of 2D seismic data between Gobe and Iehi in 2018, Oil Search had been processing and interpreting the data to delineate possible targets and provide the best drilling locations. The Iehi gas field has potential to backfill the PNG LNG project in the future. In the case of a gas find in the near field exploration efforts, reserves could provide a suitable and economic route to market. PDL 4, which covers an area of 340 sq km, was awarded on 24 December 1996.","Gobe Footwall-1ST expl. (Oil Search 10% op, Merlin 73,48%, Ampolex 14,52%, Petroleum Resources Gobe 2%) in SW sector of PDL 4 block, P&A oil shows at TD=4370m, Target Upper Jurassic Iagifu + Cretaceous Toro sst."
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%)"
15321,"In early 2018, Magyar Olaj- es Gazipari Rt (MOL) is processing seismic data acquired in September/October 2017 during the Szeghalom 3D seismic survey over the Okány Nyugat (West) permit in eastern Hungary. The 484 sq km Okány Nyugat block, solely operated by MOL, is located in the Békés and HajdúâBihar political provinces, within the Nagykunsag and Bihar sub-basin, tectonic units of the Pannonian Basin.",Hungary (Nagykunsag Sub-basin (Pannonian B.)) Szeghalom
34552,"The NPD reported on 8 November 2018 that Equinor has transferred its 6.65% equity in PL 018 C and PL 018 DS to Petrolia with effect from 31 October 2018. The licences cover the same 24 sq km area over the southerly part of block 1/5 and contain the eastern extent of Flyndre. PL 018 C applies above Top Ekofisk and below Base Hidra. PL 018 DS applies from Top Ekofisk to Base Hidra. Flyndre straddles the UK / Norway border (with 7% in Norway) and was discovered in 1974 by Phillips Petroleum with Norwegian well 1/5-2. The fieldâs reservoir is the Paleocene Balmoral Sandstone at around 3,000 m. Flyndre started production in March 2017 using a single horizontal well as a subsea tie-back to the Clyde platform in the UK. From Clyde the produced oil and gas is exported to the Teeside and St Fergus terminals. When the field came onstream it was expected to produce up to 10,000 bo/d and was planned to remain onstream until at least 2023. However, production has been lower than forecast and pressure is declining faster than anticipated. Interest in PL 018 C is now held by Total E&P Norge AS (88.35% + operator), Petrolia NOCO AS (6.65%) and Petoro AS (5%) and interest in PL 108 DS is divided between Total E&P Norge AS (60.01% + operator), Production Energy Company AS (15%), Aker BP ASA (13.34%), Petrolia NOCO AS (6.65%) and Petoro AS (5%).","Equinor has transferred its 6,65% equity in PL 018 C and PL 018 DS to Petrolia. Interest in PL 018 C is now held by Total (88.35% + op), Petrolia (6.65%) and Petoro AS (5%) and interest in PL 108 DS is divided between Total (60.01% + op), Production Energy Company AS (15%), Aker BP (13.34%), Petrolia (6.65%) and Petoro AS (5%)."
64471,"Victoria was awarded PPL 268, 2 sq km in the Cooper-Eromanga, on 6 Nov '19 over the 2007 Vanessa gas-cond discovery/field. Victoria (op), partner Acer Egy.",Australia (Focsani Trough (Moesian Platform)) Victoria
37309,"Total SA reported on 13 December 2018 that it had agreed to sell 4% of its share in the Ichthys LNG Project to joint venture partner, and operator of the project, Inpex. Under the terms of the sale, Inpex is paying USD 1.6 billion. The deal is subject to relevant authority approvals. Total currently holds a 30% interest in the project, and so will be reducing its holding to 26% once the sale is complete.  Inpexâs share in the project will increase to 66.245% upon completion of the agreement. Total reported that its sale of interest in the project was part of its âconstant portfolio review to optimize our capital allocationâ. The Ichthys field was discovered in December 1980 and supplies gas to the Ichthys LNG facilities, located onshore at Darwin, via an 890 km pipeline. The project commenced production in July 2018, with condensate initially produced. The first shipment of LNG was shipped in late October 2018. The field is located in production licence WA-50-L. Holding in WA-51-L, which lies to the west. As well as Inpex and Total, minor interests are held by a number of Japanese companies, which are supplied LNG from the project and hold interest as part of their original supply agreements. The Ichthys project is expected to produce up to 8.9 MMtpa LNG once at production plateau.","Australia, WA-51-L"
69951,"An auction was held 29 Nov '19 for 30-yr rights to the 343-sq km Khambateyskiy block (of state significance) on the SE part of the Yamal Peninsula + Ob Estuary, Yamal-Nenets AO, W. Siberia. It contains the Khambateyskoye gas â cond discovery. Gazprom Neft won for USD 31 MM vs the USD 28 MM starting price.","An auction was held 29 Nov '19 for 30-yr rights to the 343-sq km Khambateyskiy block (of state significance) on the SE part of the Yamal Peninsula + Ob Estuary, Yamal-Nenets AO, W. Siberia. It contains the Khambateyskoye gas â cond discovery. Gazprom Neft won for USD 31 MM vs the USD 28 MM starting price."
63486,"Bozhong 13-2-4 (BZ 13-2-4) was suspended, having intersected oil in the target reservoirs, on or around 22 July 2019 after having been spudded on or around 23 May 2019, using the ""Kantan 6"" 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 Bozhong 13-2 discovery. Bozhong 13-2-4 is in the CNOOC operated Boxi Block in the offshore Bohai Gulf Basin. ",Not Found
73479,"Lagniappe was conferred sole rights to ADL 393770, 5.8 sq km in the E North Slope and offered in Sale 2018W, effective 1 Sep '19.",Lagniappe (100%) was conferred sole rights to ADL 393770 (5.8km²) in the E North Slope.
14165,"Eni has made a lean gas discovery in Block 6 Offshore Cyprus with Calypso 1 NFW. The well, which was drilled in 2,074 meters of water depth reaching a final total depth of 3,827 meters, encountered an extended gas column in rocks of Miocene and Cretaceous age. The Cretaceous sequence has excellent reservoir characteristics. An intensive and detailed data collection (fluids and rock samples) has been executed on the well. Calypso 1 is a promising gas discovery and confirms the extension of the 'Zohr like' play in the Cyprus Exclusive Economic Zone (EEZ). Additional studies will be carried out to assess the range of the gas volumes in place and define further exploration and appraisal operations. Eni is the Operator of Block 6 with 50% of participation interest while Total is partner with the remaining 50%. Eni has been present in Cyprus since 2013 and detains interests in six licenses located in the EEZ of Cyprus (in Blocks 2, 3, 6, 8, 9 and 11), five of which are operated. Original article link Source: Eni ","Cyprus, not found"
9156,"Marlim lease, Campos Basin, WD 604m, special well considered npw, susp. o+g late Oct â17, 196m carb. reservoir, Norbe VIII SS. Â PTD was 4,539m, target Macabu fm. ","9-MRL-231DA-RJS successful appr. by Petrobras (100%) in Marlim lease, susp. o+g, 196m of carb. reservoir encountered, in the pre-salt, Aptian Macabu fm. WD=604m, PTD was 4539m."
71437,"Sitra (Dev) block, Abu Gharadiq Basin, drilled 19 Nov â Dec '19, TD 945m, believed dry. Targets L. Bahariya B, C + D units. Sitra = Shell-EGPC JV.","Sitra Petroleum Co (Sitra) plugged and abandoned the outpost well Sitra 1 2 in the Sitra (Dev) block, Abu Gharadiq Basin. Results are not available."
22872,"The application deadline for the 19 regular tender blocks offered under the Conventional O&G bid round 2018 has been extended to 3 Jul â18 (ex-19 Jun â18), bid docs remaining available until 26 June (ex-7 June). It is recalled that 4 out of 5 blocks offered under the direct offer mechanism were awarded by the MEMR on 2 May â18.","The application deadline for the 19 regular tender blocks offered under the Conventional O&G bid round 2018 has been extended to 3 Jul â18 (ex-19 Jun â18), bid docs remaining available until 26 June (ex-7 June). It is recalled that 4 out of 5 blocks offered under the direct offer mechanism were awarded by the MEMR on 2 May â18."
50157,"Buru is looking to farm-down in L8 (L 08), 326 sq km in the Canning Basin ahead of a drilling programme involving the Miani prospect, PTD 2,400m, target L. Laurel Shale. Contact: info@buruenergy.com.","Buru is looking to farm-down in L8 (L 08), 326 sq km in the Canning Basin ahead of a drilling programme involving the Miani prospect, PTD 2,400m, target L. Laurel Shale. "
58391,"In early September 2019 the Government of the Federation of Bosnia and Herzegovina and the Federal Ministry of Energy Mining and Industry (FMERI) announced they will launch a bidding round for three blocks in the Pannonian Basin (BiH Po-1, BiH Po-2 and BiH Tz) and one block in the Dinarides (BiH D-1). To provide further information regarding the technical potential of the four blocks on offer and to present the regulatory and fiscal terms and conditions, the FMERI has announced it will hold a roadshow in Sarajevo and another in London during October. In addition, the FMERI and the Federal Institute for Geology representatives will be present at the Central-Eastern Europe and Caspian (CEEC) Scout Group Meeting in Ankara, Turkey on the 3 - 4 October 2019 and at the Balkans Petroleum Summit on the 24 - 25 October 2019 in Montenegro to provide information about the blocks. A Data Room is also immediately available at the Federal Institute for Geology in Sarajevo. The four blocks on offer are: Block names Geological location Area (km2) Location (cities area) BiH D-1 The Dinarides                      3,237 Mostar, Siroki Brijeg BiH Po-1 The Pannonian Basin                         110 Odzak BiH Po-2 The Pannonian Basin                            93 Orasje BiH Tz The Pannonian Basin                      1,511 Tuzla  The roadshow in Sarajevo can be attended on 1 October 2019 at the Chamber of Commerce of the FBiH, Branislava Durdeva 10. Registrations must be received before 27 September 2019. The roadshow in London can be attended on 9 October 2019 at The British Museum, Great Russell St, Bloomsbury, London WC1B 3DG. Registrations must be received before 25 September 2019. All national and international oil companies, and any bona fide investors wishing to attend these roadshows should register via email to BiHroadshow@ihsmarkit.com, stating the name and position of requested attendees and the roadshow event venue. Acceptance of registration will be confirmed by email reply. The Republic of Bosnia and Herzegovina is divided in two political entities, the Federation of Bosnia and Herzegovina and the Republic of Srpska. The district of Brcko is a third self-governing administrative unit in the northeastern part of the country. Two wells have been drilled on the licence blocks on offer. In 1987 the Podravski Novigrad 1 well was drilled on licence block BiH Po-1, the objective was in the Miocene. The well was suspended with TD at 3,300 m and the findings were not reported. In 1934 the Pozarnica 1 well was drilled on the BiH Tz licence block, it was reported to have encountered oil with a TD at 800 m. Between 1989 to 1992 Amoco carried out a project across the central and outer Dinarides Mountains. Prospective structures were identified close to Trebinje, Stolac, Nevesinje, Mostar and Dreznica (which was described as a megastructure). It was reported from this study that there is oil and gas potential at depths of approximately 2,000 m to 4,000 m in the northern region and between 4,000 m to 6,000 m in the southern Dianrides area. In early November 2011 the government of the Federation of Bosnia and Herzegovina signed a Memorandum of Understanding with Shell to explore for potential natural oil and gas accumulations and develop a data room. According to Shellâs studies, the Dinarides area have oil particularly in the area of Gornja Dreznica. Oil was also identified near the Posavina enclave (north) and Majevica (northeast). Following Shellâs decision in October 2015 to put an end to its exploration project in the country, the local paper Dnevni Avaz announced that Croatian INA, Australian Key Petroleum, French Total and British Spectrum had sent letters of intent to the Federation between late October 2015 and mid-February 2016.","In early September 2019 the Government of the Federation of Bosnia and Herzegovina and the Federal Ministry of Energy Mining and Industry (FMERI) announced they will launch a bidding round for three blocks in the Pannonian Basin (BiH Po-1, BiH Po-2 and BiH Tz) and one block in the Dinarides (BiH D-1). "
45721,"Chariot has been awarded the Lixus Offshore block, 2,390 sq km north of the companyâs existing acreage (Kenitra + Mohammedia, see below) in WD 0-850m. It contains the 2009 Anchois Tertiary gas discovery (300 Bcf 2C) along with deeper potential. Chariot (op) 75%, partner Onhym 25% carried.","Chariot (75% op, Onhym 25% carried) has been awarded the Lixus Offshore (2390km²) in WD=0->850m. It contains the 2009 Anchois Tertiary gas discovery (300 Bcf 2C) along with deeper potential."
74630,"Liberia's 2020 offshore licensing round will lick-off on 15 Apr '20 at the Conference Hall of the Farmington Hotel near Roberts Airport, Monrovia. The authorities also note that should Covid-19 travel restrictions be imposed, the decision to convert the physical meeting to an online ceremony only will be expected. The status of the launch event will in principle be clarified by 1 April. Nine blocks (LB 25-33 in brown below) are normally expected to be offered in the Harper Basin, for which 2D + 3D seismic data are available. The offer will be coordinated by TGS. Map below TGS, release here.","Liberia, not found"
19667,"DE8, shallow waters off Omboué, SSE of Port Gentil, drilled 2 Feb â mid-Mar â18, TD 2,302m, minor oil find in the Anguille fm, Dagda JU. Perenco (op), partner Sasol.","Gabon, DE8"
51365,"On 13 May 2019, Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) was granted the 4/2019/L Zlotow-Zabartowo contract in western Poland. It is understood, the permit is valid for an initial five-year exploration term, followed by 25-year production period. The award resulted from the countryâs 2018 tender call. The 1,070 sq km Zlotow-Zabartowo contract is located in northern Poland, approximately 100 km northeast of the city of Poznan. In a geological sense, the tract is falling within the Northeast German-Polish Basin. The potential reservoirs in the area include the Permian (Rotliegend/Zechstein) series. Background Information The Ministry of the Environment approved list of ten areas selected for offering in the 2017 tender call (Round 2) for prospection, exploration and exploitation of hydrocarbons on 29 June 2016. [The catalogue of the areas on offer in the Round 2 was as follows: Bochnia (234 sq km), Damnica (1,038 sq km), Debrzno â Czluchów (1,159 sq km), Koszalin â Polanów (1,111 sq km), Sucha Beskidzka-Wisniowa (983 sq km), Szamotuly â Poznan Pólnoc (1,138 sq km), Zlotów - Zabartowo (1,070 sq km), Zarnowiec (1,121 sq km). In the late 2017, following amendments, the areas Bzie â Debina â Strumien (76 sq km) and Ustronie N (1,163 sq km) had been removed from the offer.] On 8 May 2018, MoE published the notes 2018/C 163/01 through 2018/C 163/08 in the EU Official Journal, thus opening the tender calls for the respective selected areas. Bids were to be submitted to the headquarters of the Ministry of the Environment no later than on the last day of the 91-day period commencing on the day following the date of publication of the notice in the EU Official Journal. The tender closed on 7 August 2018. News from early October 2018 stated PGNiG applied for the Zlotow-Zabartowo area.","PGNiG (100%) has been awarded the 4/2019/L Zlotow-Zabartowo (1 070km²) E&P concession, in central Poland."
10176,"EnQuest has completed the acquisition of an initial 25% interest in the Magnus oil field, a 3.0% interest in the Sullom Voe Oil terminal and supply facility ('SVT') and additional interests in associated infrastructure from BP as planned. EnQuest is now the operator of both Magnus and SVT. This acquisition and the associated details of the transaction were originally announced on 24 January 2017Location of Magnus field (Source: BP) Original article link Source: EnQuest ",United Kingdom (East Shetland B. (Viking Graben Province)) Magnus
41849,"On 12 February 2019, IEOC (Eni) was awarded the South East Siwa exploration block (Block 11), Northern Egypt Basin/Qattara Ridge as a part of the Egyptian General Petroleum Corporation (EGPC) 2018 bid round closed on 1 October 2018. The company is committed to invest USD 17 million including the drilling of four wells. The signature bonus is USD 1.15 million. Background information The South East Siwa block is part of the former Badr El Din exploration block (operated by Shell) and relinquishment in June 1990 and West Ghazalat exploration block relinquished by Apache. The wells drilled in the block are Ghazalat West D-1 abandoned in July 2013 by Apache at TD of 4,648 m. Targeting Cretaceous, Jurassic and Paleozoic, Ras Qattara West 1 abandoned in July 1989 by Conoco at 4,690 m and Sobek 1, Sobek 2 targeting Cretaceous and Jurassic and Ghazalat 1 P&A, dry in 1959 by Sahara Petroleum Co at 2,941 m in the Cambrian.","IEOC (Eni) was awarded the South East Siwa exploration block (Block 11), Northern Egypt Basin/Qattara Ridge as a part of the Egyptian General Petroleum Corporation (EGPC) 2018 bid round "
10777,"On 11 October 2017, Sonatrach was formally awarded the Hassi Messaoud II exploration and exploitation contract. The award is effective from 27 February 2017 and is valid for an initial three-year term. It has been granted under the current 2005 Hydrocarbons Law. The new ""parallel"" licence is contiguous to the Hassi Messaoud production concession, which contains the Hassi Messaoud Field. It does not replace the existing production licence over the giant oilfield, but instead confers exploration (and future production) rights, across the ~4,900 sq km area. Two wells have already been spudded under the new licence. In 2016, three NFWs were drilled under the Hassi Messaoud production concession agreement. One well, Rhourde El Henna 1 ST 1 (RDH 1 ST 1) was P&A dry. Two wells, Hassi Hmirat 1 (HHT 1) and Nord Hassi Guettar West 1 (NHGAW 1) made oil & gas discoveries in the Ordovician Hamra Quartzite, in structures to the SW of Hassi Messaoud. Sonatrach will operate Hassi Messaoud II with 100% equity.",Not Found
46976,"ExxonMobil has made its 13th oil find in the Stabroek block, deepwater Guyana Basin, the 5th find in in the Turbot area likely planned devt hub. Yellowtail TDâs at 5,622m in WD 1,843m, encountered 89m of good quality sst reservoir. It had spudded on 27 Mar â19 using the Noble Tom Madden DS. ExxonMobil (op), partners Hess + CNOOCI. Meanwhile Exxon has contracted the Noble Don Taylor DS for a year in Guyana starting early Oct â19.","Yellowtail 1 (ExxonMobil 45% op, Hess 30%, CNOOC-Nexen 25%) in the Stabroek block, 10km NW of the Tilapia disc. 89m of ""high-quality oil bearing sandstone reservoir"", TD=5622m in a WD=1843m."
86512,"Systemoil Energy CY Ltd is seeking to acquire a majority stake in Alba Resources LLC and Myronivkabudmontazh LLC, and has received clearance from the Antimonopoly Committee for the transactions, according to local press sources from mid July 2020. Alba is currently owned by Dafresion Services Ltd and operates South Medvedivska (20.1 sq km), whilst Myronivkabudmontazh belongs to Dimoreno Ventures Ltd and holds South Khrestyshchenska (22.7 sq km). Both Dafresion and Dimoreno are registered in Limassol, Cyprus, with Arkady Gaevsky as beneficiary. The two permits are located in Kharkov Region, Dnieper-Donets Basin and three exploration wells are already planned across the acreage, likely in 2021. Systemoil recently bought Geoinvest Group LLC in late May 2020, to acquire Barhanovsko-Podilska special permit in Poltava Region, Dnieper-Donets Basin. It is also Cyprus-registered and headed by Mykola Zlochevsky, a former minister for Ecology and Natural Resources (2010-12) and founder-owner of the Burisma Group. ","Systemoil Energy CY Ltd is seeking to acquire a majority stake in Alba Resources LLC and Myronivkabudmontazh LLC, and has received clearance from the Antimonopoly Committee for the transactions, according to local press sources from mid July 2020. Alba is currently owned by Dafresion Services Ltd and operates South Medvedivska (20.1 sq km), whilst Myronivkabudmontazh belongs to Dimoreno Ventures Ltd and holds South Khrestyshchenska (22.7 sq km). "
71618,"Archinskiy licence, SE extension of Urmanskoye field, Tomsk Oblast (Western Siberia), TD 3,660m, discovered new pool of 11 MMbbl of recoverable oil in Paleozoic basement carbonates, quick development planned. Background from GEPS.","Urmanskaya 26 npw. (Gazprom Neft-Vostok 100%) in the SE extension of the field Urmanskoye field in the Archinskiy license in Tomsk Oblast, discovery of a new pool, tested oil at a rate of 670 b/d from carbonate reservoirs of the Paleozoic basement. The company estimated 3P oil reserves of the pool at 37 MMbbl in-place and 11 MMbbl of recoverable. TD=3 660 m."
41738,"On 7 February 2019 Frontera Energy and Parex Resources signed a farm-in agreement for 50% interest in the VIM-1 Block of the Lower Magdalena Basin. Per terms of the deal, which is subject to ANH approval, Frontera will fund all costs for the first USD 10 million of drilling, testing and completing the La Belleza 1 exploration well, slated to spud during Q2 2019. After this initial payout, all costs on the block will be divided evenly between Frontera and Parex.",Frontera Energy has farmed into the VIM 1 block in Colombia after striking a deal with Parex Resources. 50/50).
29108,"Karsal 3272-18 EL, Potwar Basin, 1st well in block, last reported at 3,675m, oil discovery, DSTâd 313 bo/d + minor gas on 1/2â choke from Eocene Chorgali + Sakesar carbs, WHP 77 psi. Drilling continues to test deeper formations, PTD 4,190m. CCDC-29 rig.",Pakistan (Potwar Plateau (Potwar B.)) Karsal
37643,"On 10 December 2018, the Canada-Nova Scotia Offshore Petroleum Board (C-NSOPB) issued a Call for Bids NS18-3, which comprises two industry-nominated shallow water parcels located on the Scotian Shelf, and encompassing Sable Island. These parcels are sited in maximum water depths up to 100m, within the Sable Sub-basin where 23 significant discoveries have been made to date. A number of undrilled exploration prospects have been identified on both NS18-3 parcels, including the Marmora discovery, with proven gas trapped in a sandstone reservoir. The NS18-3 parcels are directly adjacent to 10 significant discoveries containing an estimated 1.3 Tcf of recoverable gas and 15 MMbbls of recoverable oil. ExxonMobil is currently in the process of decommissioning and abandonment of the Sable Offshore Energy Project, which encompasses seven offshore platforms located directly adjacent to these parcels and originally producing from six natural gas fields: Alma, Glenelg, North Triumph, Thebaud, South Venture and Venture. The Sable Island development spans more than 200 sq km and includes 340km of subsea pipelines and 22 wells. ExxonMobil anticipates the complete removal of all offshore facilities by 2020. The public have an opportunity to submit written comments on Call for Bids NS18-3, which must be received by 8 February 2019 at 4:00 pm (Atlantic Time), and will be posted publicly. Bids for the two NS18-3 parcels must be submitted to the C-NSOPB by 8 May 2019 before 4:00 pm (Atlantic Time). Successful bidders may be awarded Exploration Licences (ELs), subject to the federal and provincial Ministerial review and approval process set out in legislation.",Not Found
74557,"Genel Energy may dilute its 75% equity in its Lagzira Offshore reconnaissance licence, located in the Tarfaya Basin.The block was awarded on 18 February 2020 and is understood to be an effective re-award of the company's Sidi Moussa Offshore exploration permit (5,018 sq km) which was relinquished upon expiry on 16 February 2020. The company was planning to recommence a farm-out campaign on the previous permit in Q2 2020, prior to considering further commitments on the licence. Genel had previously planned for the campaign to start in Q1 2020, ahead of a drill or drop decision.Sidi Moussa lay in WD between 40-1,500m. It was originally awarded to Island Oil & Gas with 50% equity in June 2009. Partners at the time were Serica (25%) and ONHYM (25%, carried). In 2010, Longreach Oil & Gas (now Wolverine) farmed-in, acquiring 10% equity from Island. In the same year San Leon acquired operatorship, through the acquisition of Island. In May 2013, Genel completed its US$ 51.3 million farm-in, acquiring 60% operated equity pro-rata from the existing partners. In 2014 the Sidi Moussa 1 (SM 1) NFW was drilled, reaching 2,825m TD (983m WD) in mid-October 2014. An unsuccessful test of fractured and brecciated Late Jurassic carbonates resulted in it being P&A with oil shows. In October 2015, Wolverine (as PetroMaroc) exited, assigning its equity to San Leon. Genel commenced a farm-out process in 2016, seeking partners to drill the Nour Deep well, which would target a 350 MMbo early Jurassic clastics prospect. Following a licence extension in Q4 2017, which saw the well commitment being replaced by the seismic campaign, partners San Leon (10%) and Serica (5%) also exited the permit. A 2,000 sq km 3D seismic survey was subsequently acquired between August-November 2018. Equity in Lagzira Offshore is split: Genel (75% +Op) and ONHYM (25%, carried).","Genel Energy may dilute its 75% equity in its Lagzira Offshore reconnaissance licence, located in the Tarfaya "
31253,"On 3 October 2018 Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd have agreed a deal with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.667% interest each in PEDL 183. The licence is located in East Yorkshire and contains the West Newton A-1 gas discovery. There are also plans to drill the West Newton B appraisal well in Q1 2019. The deal is subject to regulatory approval. West Newton B will be located approximately 1.5 km south of the 2013 West Newton well. It is planned to target three potential Permian reservoirs in the Brotheran, Kirkham Abbey and Cadeby formations. The well has a planned TD of 2,000 m to the base of the Permian section. It was initially planned to be drilled with the KCA Deutag T-61 rig. In November 2017 Rathlin confirmed that it still plans to drill the well and in December the company stated that it is currently out to assess and determine rig availability. Drilling is planned to take 6 - 12 weeks where the company is not planning to test any shale horizons (TD likely to be 1,000 m above the Bowland Shale) estimated to be deeper than its Permian targets. It is hoped that the well will determine the commerciality of the discovery. In an update from the company on 17 June 2015 it confirmed that East Riding of Yorkshire Council has granted planning permission for the well. On 26 November 2015 Rathlin announced that it was pleased that the planning committee has unanimously approved the planning application for an extension at West Newton A. Following the well encountering gas the company can move forward with investigating the commerciality of the discovery within the Permian Kirkham Abbey Formation. On 26 July 2016 the OGA confirmed that the Environment Agency has granted a permit for the drilling of the well. In 2013 Rathlin Energy drilled with West Newton 1 (A) well. The well was drilled to a TD of 3,150 m into the Dinantian Carbonate section in the Carboniferous and was tested. The well was located north of West Newton and east of Marton in the parish of Aldbrough, East Riding Yorkshire. It had a primary target based from 2D mapping and is a Permian aged Caedby Carbonate reef. The source rock potential is present within the Permian basinal sediments, the Westphalian coal measures and the Bowland shale sequence. PEDL 183 was awarded in the 13th Onshore Licensing Round and covers an area of 913 sq km. Interest in the licence following the deal will be held by Rathin Energy (66.666% + operator), Humber Oil and Gas (16.667%) and Union Jack Oil Plc (16.667%).",Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd have agreed a deal with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.667% interest each in PEDL 183. The licence is located in East Yorkshire and contains the West Newton A-1 gas discovery.
36961,"Yinggehai Basin, WD 60m, targets Yinggehai + Huangliu fmâs, ops terminated 8 Dec â18, Nanhai 7 SS.","China, not found"
65484,"On 26 November 2019, Colombia's Agencia Nacional de Hidrocarburos (ANH) received 17 initial bids for 15 blocks, out of the 59 offered and below the expected 20, as part of the for Phase II of the Permanent Process of Assignment of Areas, or PPAA. Initial bids total roughly US$ 523.4 million. The highest bids received, including total bid offered and the minimum counter offer, are as follows:->LLA-100 - Hocol - bid total: US$ 15,491,009 - minimum counter offer: US$ 15,688,309->LLA-119 - Frontera Energy - bid total: US$ 14,303,263 - minimum counter offer: US$ 14,500,563->LLA-121 - Ecopetrol - bid total: US$ 62,479,977 - minimum counter offer: US$ 62,677,277->LLA-122 - Ecopetrol-Parex - bid total: US$ 66,409,207 - minimum counter offer: US$ 66,606,507->LLA-123 - Hocol-Geopark - bid total: US$ 19,614,579 - minimum counter offer: US$ 19,811,879->LLA-124 - Hocol-Geopark - bid total: US$ 25,727,920 - minimum counter offer: US$ 25,925,220->PUT-21 - Gran Tierra - bid total: US$ 11,177,045 - minimum counter offer: US$ 11,374,345->PUT-33 - Gran Tierra - bid total: US$ 10,867,284 - minimum counter offer: US$ 11,064,584->PUT-36 - Amerisur - bid total: US$ 480,654,180 - minimum counter offer: US$ 48,851,480->SN-26 - La Luna-Captiva - bid total US$ 60,707,237 - minimum counter offer: US$ 60,904,537->VIM-33 - Canacol - bid total US$ 33,235,185 - minimum counter offer: US$ 33,432,485->VMM-45 - Canacol - bid total US$ 19,700,405 - minimum counter offer: US$ 19,897,705->VMM-46 - Parex - bid total US$ 26,211,305 - minimum counter offer: US$ 26,408,605->VMM-49 - Canacol - bid total US$ 78,712,835 - minimum counter offer: US$ 78,910,135->VSM-36 - Parex - bid total US$ 30,127,710 - minimum counter offer: US$ 30,325,010Qualified parties have until 5 December 2019 to submit a counter offer. On 19 November 2019, the ANH published the final list of pre-qualified companies for Phase II of PPAA. In total, 28 companies have pre-qualified and two have failed to qualify for the entitlement to bid on the 59 blocks on offer. Of the 28 companies who have met the pre-qualification financial requirements, 16 are accredited to submit proposals and counter offers for offshore areas. Observations on the list were open trough 14-15 November 2019. Below is the list of pre-qualified companies:1. CNE Oil and Gas SAS (subsidiary of Canacol) - not qualified for future bid round cycles & not offshore2. Frontera Energy Colombia Corp3. Ecopetrol SA4. Parex Resources (Colombia) Ltd5. Geoproduction Oil and Gas GMBH - not offshore6. Occidental Andina LLC 7. Occidental de Colombia LLC - not offshore8. Gran Tierra Energy Colombia LLC9. Cepsa Colombia SA - not offshore10. Geopark Colombia SAS11. Occidental Condor LLC12. Aspect Holdings LLC - not offshore13. Hunt Overseas Oil Co14. Ecopetrol Costa Afuera SAS15. Hocol SA16. Amerisur Exploracion Colombia Ltd - not offshore17. Mansarovar Energy Colombia Ltd18. Union Temporal La Luna Captiva (La Luna E&P S de RL 70% & Captiva Resources, LLC 30% -Operator) - not offshore19. Noble Energy Ltd20. Hupecol Oriente Colombian Holdings LLC - not offshore21. ONGC Videsh Ltd22. Colombia Energy Development Co - not offshore23. Interoil Colombia Exploration and Production INC - not offshore24. Vetra Exploracion y Produccion Colombia SAS25. Petroleos Sud Americanos SA Ltd - not offshore26. CNOOC Petroleum Colombia Ltd27. Lewis Energy Colombia INC28. IsmocolThe pre-qualification list includes the usual Colombian players. No new major players have pre-qualified to bid, however some major companies which hold only a few assets in the country, have qualified such as Chinese state company CNOOC. CNOOC previously acquired the Villarrica Norte and Boqueron blocks through its acquisition of Nexen. IOCs currently participating offshore in Colombia such as Shell, ExxonMobil and Repsol are notable in their absence. Emerald Energy PLC failed to meet legal, economic and financial, technical and operational plus corporate social responsibility capa","75% of the blocks on offer in Colombia's 2nd round of the' permanent offer' failed to attract bids, only 15 blocks ended up finding a taker, none offshore."
85482,"Tal 3370-3 EL, Potwar onshore, TD 4,939m, gas-cond discovery in the Lockhart + Hangu fm's, so far tested 6,516 boe/d, KCA Deutag T-72 rig. MOL (op), partners OGDC, PPL, POL + GHPL.","Pakistan (Potwar B.), Mami Khel South 1 exploratory well, in Tal 3370-3 EL, operated by PPL (30%), OGDCL (30%), POL (25%), MOL (10%), GHPL (5%), gas-cond discovery in the Lockhart + Hangu fm's. Successful drill stem test (DST) conducted over the Paleocene Lockhart and Hangu formations: 16.12 MMcfg/d and 3,240 bc/d through 32/64"" choke at a wellhead flowing pressure of 4,476 psi, produced water at a rate 48 b/d. The well was spudded on 6 October 2019 and was drilled to the final TD of 4,939 m. "
71893,"PL 917, Balder area in WD 126m, PTD 1,985m, P&A at TMD 1,955m (1,899m TVD, Sele fm), hc traces, Leiv Eiriksson SS. Target Eocene Hordaland Gp. ConocoPhillips (op), partners Lundin, Suncor + VÃ¥r Energi.","025/07- 09 S (Hasselbaink) nfw. (ConocoPhillips 40% op, Lundin 20%, Suncor 20%, VÃ¥r Energi 20%) in PL 917 block, Balder area, P&A dry (intersected 2 thin sst layers of about 1m in the Eocene Hordaland group, with very good reservoir properties and traces of petroleum) at TMD=1=955m (1 899m TVD, Sele Fm). WD=126m, PTD=1985m."
58378,"P2085, SNS, commitment well to 2-year extn of licence term (to 20 Dec â19), TMD 2,297m (Leman sst), 25m gas column at the top of the reservoir, assessment planned to determine potential Harvey devt, Maersk Resilient JU. IOG could fast-track Harvey through exporting gas via the re-commissioned Thames pipeline. Ref. DEA 26 Jul â19, it is recalled IOG has agreed a farmout to CalEnergy of a 50% interest in all of its upstream assets, as well as the Harvey licences within 3 months of completion of this well.",United Kingdom (Indefatigable Shelf (Anglo-Dutch B.)) Thames
81406,"Oil Search has recently (March) accepted an offer of award for APPL 608, 3,408 sq km east of the Hides + Angore gasfields, onshore Papuan Basin. The formal award is now awaiting Ministerial approval. Once secured, Oil Search is understood looking to farmout the new permit, possibly towards late 2020.","Papua New Guinea, APPL 608 Oil Search has accepted an offer of award for APPL 608, 3,408 sq km east of the Hides + Angore gasfields, onshore Papuan Basin."
66711,"Bids were placed for 92 tracts totalling 4,254 sq km out of the 350 offered at the 2019 NPR-A sale on 11 Dec '19. North Slope Exploration picked up 85 tracts, Emerald House 4 + ConococPhillips 3. Map from the BLM.","United States, not found"
80764,"5 months after applying, Derkim Poliüretan was awarded the M46-C and M46-D explo licences, resp. 595 + 613 sq km in the Zagros Fold Belt, SE Turkey, on 13 May 20 for 5 years.",Derkim was awarded 2 exploration licences: M46-C & M46-D.
28254,"As of 1 August 2018, Independent operator Paul L. Craig and partners are offering three blocks for sale or farm-out north of Umiat and west of Gubik fields. The three blocks called the South Nanushuk prospect are in the National Petroleum Reserve-Alaska (NPR-A) and include AA-093747, AA-093748 and AA-093749. The total acreage included in the blocks is 35,425 acres (143.36 sq km). The acreage sets on trend south of the Horseshoe and Willow Nanushuk Formation oil discoveries drilled by Repsol and ConocoPhillips respectively. These discoveries were made in topsets of the west to east prograding clinoforms across the central North Slope. The operator believes the Nanushuk clinoforms arc through the South Naunushuk prospect beginning south of Umiat Field and extend north though the Pikka Unit. A local new story reporting on the offering reported that all terms were negotiable. The three tracts, include AA-093747, AA-093748 and AA-093749, were awarded from the NPR-A Sale 2013 for a bonus bid of USD 272,049 or USD 7.68 per acre. Partners in the tracts include Paul L. Craig 41.6667%, Peter G. Zamarello 50% and Paul Gardener 8.3333%. Contact information for Paul L. Craig 907-830-1151 or drpaulcraig@gmail.com",United States (Taroom Trough (Bowen - Surat B.s)) Horseshoe
62366,"On 29 October 2019, Hess announced an oil discovery at its Esox prospect in Mississippi Canyon block 726 (G24101) in the deepwater Central Gulf of Mexico. Based on the drilling permit approved by the Bureau of Ocean Energy Mangement (BOEM) on 16 September 2019, the Esox well appears to be a re-entry of well MC 726 3S0B0 (API 608174121600) which was drilled in 2012 in the Tubular Bells field. Situated in the south-central portion of the Mississippi Canyon (MC) protraction area in 4,609 ft (1,405 m) of water, it is approximately 100 mi (161 km) southeast of the onshore support base at Port Fourchon, Louisiana. Approximately 6 mi (10 km) east of the Tubular Bells production facility in MC 724, the well encountered about 191 net ft (58 m) of oil in high-quality Miocene reservoirs. Hess had previously characterized the Esox prospect as an amplitude-supported subsalt Miocene play with multiple stacked targets. The prospectâs primary objective was in a stratigraphically shallower interval than the pay zone at Tubular Bells. The well is planned to be tied back to the Tubular Bells facility with production expected in Q1 2020. A standard-size, 5,670-acre (21.3 sq km) tract, the lease was awarded to BP which submitted a sole bid of USD 14.25 million at Sale 182 in March 2002. It was the third-highest bid of the sale and there were no competing bids for the block. Chevron and Hess farmed into the block in 2003. Hess currently operates the block with 57.14% working interest, with the remaining 42.86% interest owned by Chevron. Background Information The Tubular Bells discovery well was drilled in MC 725 in 2003. The field came onstream in November 2014 and has produced 30.1 MMbo and 77.9 Bcfg through June 2019.","MC 726 Esox 1 explo. (Hess 57,14% op, Chevron 42,86%) in the G24101 lease (MC block 726), 58m net of âhigh-quality oil-bearing Miocene reservoirsâ to be fast-tracked as a subsea tie-back to the Tubular Bells platform. WD=1405m. "
84586,"GeoPark advises it is still on trying to dilute its 75% in block 64, 7,635 sq km in the Marañon Basin in N. Peru, ahead of devt of the Situche Central field for which an EIA was submitted a couple of years ago. Partner Petroperu.","Peru (Maranon B.) Block 64 op. by GEOPARK (75%), PETROPERU (25%), GeoPark advises it is still on trying to dilute its 75% in block 64, 7,635 sq km in the Marañon Basin in N. Peru, ahead of devt of the Situche Central field for which an EIA was submitted a couple of years ago. Partner Petroperu."
66845,"Crown Point Energy reported on 4 December 2019, that it plugged and abandoned the Sur Rio Malargue x-1002(d), in the 1,041 sq km Cerro de los Leones license, northern Neuquen Basin. The drilling rig was the SAI-318. The well was spud on 10 November to test the Tertiary-Upper Cretaceous Sandstone on an extension of the structural crest. It reached 1,183m TD on 18 November and was abandoned after well log analysis confirmed no hydrocarbons present in the well.Crown Point Energy reported on 4 June 2019 that it was planning to spud two exploration wells in this exploration permit in the Mendoza province. These wells were planned for Q3 2019 at a cost of US$ 3.7 million. Crown Point acquired 214 sq km of 3D seismic to determine drilling locations in the northern portion of the block. The first NFW spud in the area, Sur Rio Malargue x-1001(d) was logged recently and shown to be a potential discovery. The company requested a four month extension for the exploration permit in this block to 23 February 2020 to complete the drilling and evaluation of that well.","Argentina, Cerro de los Leones"
75587,"On 22 March 2020, Egyptian government sources disclosed that Edison International SpA (Edison) abandoned its first deep-water exploration wildcat Ameeq 1 in the North Thekah offshore block (block 7), Levantine Basin. This failure comes a few weeks after Eni abandoned the Nigma 1 exploration well in the Northeast Hapy Offshore Block in the same basin. For the Egyptian state, these two successive setbacks represent a disappointment for the country in its efforts to convince the IOCs to start a new phase of exploration in its deep Mediterranean waters. Edison holds a 100% working interest in the North Thekah offshore block, which had been initially granted to Edison and Petroceltics in April 2013. Edison is a fully owned subsidiary of Edison SpA, a JV between Transalpina di Energia Srl (80.12%), EDF (19.35) and other partners (0.53%). Background information Edison started drilling operations of its first deep-water exploration Ameeq 1 in the North Thekah offshore block (block 7) on 18 January 2020. The company declared that the operation for which the semi-submersible rig Maersk Discoverer had been contracted, was estimated to take two months to reach the Ameeq prospect situated at a total depth of 5,200 m with 982 m of water depth. On 3 March 2020, Maersk Drilling announced a one-well contract for its rig in direct continuation of the current contract. This new contract, which was expected to commence in March 2020 had an estimated duration of 21 days for an approximate value of USD 3.8 million.","Ameeq 1 nfw. (Edison 100%) 1st of 3 commitment wells normally planned in DW North Thekah block, WD=982m in E. Mediterranean, reportedly dry, PTD was ca. 5200m. This will no doubt be a major disappointment to Energean, in the process of taking over Edison, and to the govt who has been actively promoting DW acreage."
37585,"Partners in the Repsol-operated offshore Colombian RC-12 Block may look to farm-out equity, industry sources speculated in December 2018. Repsol operates the block with 50% WI, with Ecopetrol holding the remaining 50% WI. The block was awarded in 2007 as part of the Ronda Caribe 2007 bid round. A 300 sq km 3D seismic survey was completed in 2014, fulfilling the Phase I commitments. RC-12 has had its contract extended, including a nine month extension approved in January 2017 by the Agencia Nacional de Hidrocarburos (ANH). It is thought that partners may seek to farm-out in order to fund a commitment well on the block which is undrilled apart from the dry 1980 Jarara 1 NFW. ","Colombia, RC 12"
64445,"Solodovskiy licence in Perm Kray (Volga-Urals), 4 finds made between 2017-2019 on the Solodovskaya + Solodovskaya Vostochnaya prospects, several oil pools in the Famennian-Moscovian, combined under the designation im. Yu.Gavrina after local geologist Yuriy Gavrin. First oil expected in 2022.","Russia (Volga-Urals B.) ? op. by LUK PERM (100.0%, LUK PERM 100.0%) in Solodovskiy block"
45208,"Ãndico-1 wellpad in Crudos Pesados Oeste-5 (CPO-5), Llanos Basin, directional well SW, P&Aâing dry at TMD 3,489m, E-2029 rig. To be followed by Pavo Real-1 and/or an appraisal in the Ãndico structure. Partner Amerisur.","Calão 1, (Amerisur %) Ãndico-1 wellpad in CPO-5 block, directional well SW, P&Aâing dry at TMD=3489m."
69173,"PL 917, WD 126m, P&A minor oil discovery on 9 Jan '20 at TMD 3,225m (3,188m TVD, Skagerrak), 5m oil-braing Nansen sst, 6m o&g bearing sst in the Eiriksson fm, 8m gas sst in the Skagerrak, est recov. 1-5 MMcum oil equivalent. Leiv Eiriksson SS. COP (op), partners Lundin, Suncor + VÃ¥r Energi.","MC 522 003S0B1 (Fourier Deep) expl. (Shell 100%) Mississippi Canyon block 522 (lease G08823), Fourier field area, ops terminated, results n/a. Target assumed Norphlet below the main Middle Miocene reservoirs."
74212,"Wintershall Dea has been unsuccessful with its appraisal of the 2018 Balderbra gas discovery in PL 894. 6604/5-2 S was spudded on 22 January 2020 using the âScarabeo 8â S/S. It targeted three Upper Cretaceous Springar Formation sandstones, with the first mapped at 3,633 m (3,389 m TVD), and was also designed to locate the GWC. However, although a total of 210 m of Springar Formation was present in the well (with 140 m of this being poor quality sandstone) there were only traces of gas and the well is classed as a dry hole. Pressure communication with the discovery was also not established. Recoverable reserves for Balderbra have been reduced from 247-671 Bcfg plus 6-19 MMbc (at discovery) to 106-283 Bcfg plus 1-6 MMbc which, according to partner Lundin, is not considered commercially viable. On 26 February 2020 the well was abandoned, with TD at 4,155 m (3,816 m TVDSS) in the Springar Formation. Two sidetracks had been planned for 6604/5-2 S â one to the southwest (TD 4,120 m, 3,808 m TVD) and the other to the east (TD 4,258 m, 3,878 m TVD) â and Wintershall Dea had also intended to carry out two DSTs. Balderbra discovery well 6604/5-1 targeted a robust structural closure (Maastrichtian sand drape over older tilted fault blocks) with an amplitude anomaly between the Gullris (6604/2-1) and Gro (6603/12-1) wells. A gross gas column of 190 m across three separate sandstones totalling 90 m was encountered in the Springar Formation. The upper sandstone unit is thin with variable permeability, the middle sand is thicker (56 m gross) and laminated with 21% porosity, and the lower sand has a gross thickness of 129 m and 15% porosity. The three units are not in pressure communication and no GWC was encountered. The find could be developed as a tie-back to Aasta Hansteen. Interest in PL 894, subject to completion of a deal, is held by Wintershall Dea Norge AS (30% + operator), Equinor Energy AS (40%), Petoro AS (20%) and Lundin Norway AS (10%).","6604/05-02 S (BalderbrÃ¥) appr. (Wintershall Dea 40% op, Equinor 40%, Petoro 20%) in PL 894, 15km E. of discovery, P&A dry, encountered only traces of gas across 3 intervals spanning 210m in the U. Cretaceous Springar Fm, of which 140m of sst was of poor reservoir quality and has significantly downgraded the resource estimate for Balderbra g&c disc.The GWC was not found."
51758,"ExxonMobil is said to be looking into the possible sale of the remainder of its Norwegian upstream holdings. This would include interests in some 20 fields, including Snorre, Statfjord or Ormen Lange. A data room is open to gauge industry reaction. A global price of USD 3-4 bn is articulated. Sign of the times, Exxon is looking to bank on successes in Guyana, Mozambique and PNG, inter alia.","ExxonMobil is said to be looking into the possible sale of the remainder of its Norwegian upstream holdings. This would include interests in some 20 fields, including Snorre, Statfjord or Ormen Lange. A data room is open to gauge industry reaction. A global price of USD 3-4 bn is articulated. "
72342,"On 15 January 2020, INA Industrija Nafte d.d. (INA) reached the final depth of 1,739 m (TVD 1,693 m) in wildcat Selnica 1 IS (Istok - East) in the Zebanec mining plot, enclave within a yet to be awarded block - Sjeverozapadna Hrvatska 1 (SZH-1) - in northern Croatia. After encountering wellbore stability issues/circulation losses at total depth, the well was suspended with oil and gas shows - a sidetrack is mooted. Selnica 1 IS was spudded on 24 December 2019, using the National 402 drilling unit from Crosco Zagreb. The Zebanec mining plot is located close to the border with Hungary and Slovenia. It falls within the Mura Sub-basin, tectonic unit of the Pannonian Basin. The well was targeting the Lower/Middle Miocene successions, with secondary target in the Mesozoic karstic series. The initial planned total depth was 1,750 m. Background Information The Selnica field is the second oldest commercial oil field in the country. Oil seeps have been recorded from the nearby Peklenica region since 1788 and commercial exploitation from shallow mineshafts began in 1868. The first commercial oil well in this field was drilled in 1885. Between 1954 and 1956 Singer drilled the Selnica 1 exploration well to a total depth of 2,814 m and found oil in the Abichi Mb. The field was abandoned in 1965. News in 2018 was that INA is planning to drill appraisal Selnica 1 IS, but the project was deferred.","Selnica 1 IS (Istok - East) (INA 100%) in the Zebanec mining plot, enclave within a yet to be awarded block - Sjeverozapadna Hrvatska 1 (SZH-1) - in northern Croatia. After encountering wellbore stability issues/circulation losses at total depth, the well was suspended with oil and gas shows - a sidetrack is mooted."
51095,"South Bengara II PSC, onshore Greater Tarakan Basin, ops terminated (results n/a, believed P&A) in early Jun â19. PTD was 1,100m, target L. Miocene Birang fm.","Bella-3 appr South Bengara II PSC, onshore Greater Tarakan Basin, ops terminated (results n/a, believed P&A) in early Jun â19. PTD was 1,100m, target L. Miocene Birang fm."
58649,"REC-T-212 block, onshore Recôncavo, gas shows report to ANP on 28 Aug, susp early Sep â19. PTD was 1,650m, targets Caruacu mb in Maracangalha fm. Despite its nfw classification, this is an appr to the unitised + producing Carbure-Cardeal do Nordeste field. Imetame (op), partner Alvopetro.","REC-T-212 block, onshore Recôncavo, gas shows report to ANP on 28 Aug, susp early Sep â19. PTD was 1,650m, targets Caruacu mb in Maracangalha fm. Despite its nfw classification, this is an appr to the unitised + producing Carbure-Cardeal do Nordeste field. Imetame (op), partner Alvopetro."
55899,"Santos Ltd spudded the Napowie 5 appraisal well in PPL 151, located in the Cooper-Eromanga Basin, on 22 July 2019. The well was drilled by the âEnsign 970â land rig. On 3 August 2019 the operator plugged and abandoned the well, after encountering gas shows, at a total depth of 3,155 m. The well was the second of several being drilled to appraise the Napowie field, which was discovered in June 1993. Napowie 5 followed Napowie 6. The field has been producing gas since June 2018. PPL 151, which covers an area of 66 sq km, was awarded on 1 January 1999. Participants in the permit are Santos Ltd (40.70% + Operator), various Santos subsidiaries (25.9%) and Beach Energy subsidiaries Delhi Petroleum Pty Ltd (20.21%) and Lattice Energy Ltd (13.19%).","Santos Ltd Napowie 5 (appraisal) in PPL 151 block, Cooper-Eromanga Basin - P&A, gas shows"
17866,"On 27 March 2018, the government of Tierra del Fuego Province officially launched a call for tenders for the CA 12 I and CA 12 II blocks with a presentation at the IAPG (Instituto Argentino del Petroleo y del Gas) headquarters in Buenos Aires. A call for CA 12 I (Licitacion Nacional & Internacional No 1/2017) was originally announced in November 2017 with the opening of envelopes scheduled for 21 February 2018. However, in late-2017 the date was pushed back to 10 May 2018, while CA 12 II (Licitacion Nacional & Internacional No 1/2018) was added into the mix in early-2018 with the same due date. 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. According to the provincial government, data package will be available through 13 April 2018 with presentation of the offers expected between 16 April 2018 and 2 May 2018. No current information is available regarding the expected work commitments, however during the promotion of CA 12 I in late-2017, it was said that the first exploration period should include geophysical and geological work, before followed by the drilling of an exploratory well in the second period. It is also worth noting that according to the provincial decree No 2829 from October 2017, YPF will get the privilege of the right of preference after the state company initially presented a proposal to explore the CA 12 I block back in January 2017. The bid round process is handled by the Secretary of Energy and Hydrocarbons of the Tierra del Fuego Province with contact information of licitacion-ca12@tierradelfuego.gov.ar. 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.","On 27 March 2018, the government of Tierra del Fuego Province officially launched a call for tenders for the CA 12 I and CA 12 II blocks with a presentation at the IAPG (Instituto Argentino del Petroleo y del Gas) headquarters in Buenos Aires."
30268,"The Neuquén authorities have reportedly granted PAE new unconventional exploitation rights over the former Madalena Energy Coirón Amargo Sur Este (CASE) block, 246 sq km. A shale oil pilot project calls for 8 wells over the next 4 years. Coirón Amargo Sur field came onstream shortly after discovery of o&g in 2011. PAE (op), partners Madalena Energy + GyP Neuquén.","Pan American Energy (55% op. Madalena Egy 35%, G&P Neuquen 10%) has been awarded explo rights to the Coiron Amarco Sur Este (CASE) license."
29476,"On 8 September 2018, the Government of Russian Federation issued a Decree announcing an auction for the Obskoy Yuzhnyy block in the Ob Estuary of the Kara Sea (Western Siberia). The auction must be held before the end of 2018. Taking into account that Obskoy Yuzhnyy is defined as a Site of the Federal Significance, the auction could be limited to participants where the State has a controlling stake (Gazprom, Rosneft and Zarubezhneft). Obskoy Yuzhnyy covers 321 sq km in the southern part of the South Kara-Yamal Province. Hydrocarbon resources of the block are estimated at 356 MMbbl of oil, 6.045 Tcf of gas and 123 MMbbl of condensate. A long-term E&P license includes a 10-year exploratory stage. The starting price amounts to RUB 152.065 million (USD 2.17 million).","On 8 September 2018, the Government of Russian Federation issued a Decree announcing an auction for the Obskoy Yuzhnyy block in the Ob Estuary of the Kara Sea (Western Siberia). The auction must be held before the end of 2018."
84785,"Margand 2866-4 EL, Kalat Plateau in Kirthar Fold Belt, 2019 gas discovery re-entered for deepening to 5,100m, tested a deeper section of Jurassic Chiltan fm, 15 MMcfg/d + 120 bw/d on 2"" choke. In late 2019 this well (TD 4,500m) was DST'd, flowing 10.7 MMcfg/d and 132 b/d of liquids on 1"" choke from the Chiltan. PPL plans to drill another explo well in the block by year-end.","Pakistan (Kirthar Fold Belt) Margand X-1 nfw, op. by PPL (100%) in Margand 2866-4 EL block, gas discovery re-entered for deepening to 5,100m, tested a deeper section of Jurassic Chiltan fm, 15 MMcfg/d + 120 bw/d on 2"" choke. In late 2019 this well (TD 4,500m) was DST'd, flowing 10.7 MMcfg/d and 132 b/d of liquids on 1"" choke from the Chiltan."
53529,"Yanam ML, Krishna-Godavari shallow waters, WD 24m, established the commercial potential of the lower synrift play corridor, testing recently concluded, assumed suspended, Aban II JU. More from GEPS.","YS-6 2 (SUB) expl Yanam ML, Krishna-Godavari shallow waters, WD 24m, established the commercial potential of the lower synrift play corridor, testing recently concluded, assumed suspended."
33678,"Australia-based ADX Energy announced on 31 October 2018 that it reached into an agreement with SDP Services Limited, an independent specialized oilfield service company based in India, for the farm-out of a 50% interest in the d363C.R-.AX exploration permit under application offshore western Sicily. The application, detained by ADX Energyâs wholly-owned subsidiary AuDAx Energy, is covering the Nilde oil field, which the company is planning to redevelop. According to the deal, which is conditional to the official award of the permit, SDP Services will contribute to the work program of the exploration permit for a maximum consideration of EUR 20.82 million (USD 23.6 million) in exchange of a 50% non-operating interest and a 5% net profit royalty interest on any future production from the Nilde field. ADX Energy expects that the enhancement of the financial capability of AuDAx energy brought by this new partner will facilitate the grant of the permit after the Italian regulatory authorities negatively assessed the financial ability of AuDAx Energy to fulfill the commitments related to license. AuDAX Energy applied for the d363C.R-.AX exploration permit, covering 725 sq km offshore western Sicily, on 29 January 2010. Proposed commitments for the initial six-year period include the reprocessing of legacy seismic and development studies and the drilling of a well within the first four years. The block, sited in water depths ranging from 30 m to 200 m, encompasses the Nilde oil field as well as the Norma 1 and the Naila 1 oil discoveries. The Nilde field was discovered by Agip in 1977 with the Nilde 2 wildcat. The well, drilled to a TD of 2,143 m, tested some 2,500 bo/d of 38.9° API oil from a Miocene reservoir (Serravallian Nilde Limestone) at a shallow depth (1,500 m). The field was put on-stream in 1981. The completion of the Nilde 6dir horizontal well in 1986 brought the average production rate of the field to 11,796 bo/d in 1987. However, the field was abandoned in 1989 due to excessive water production and low oil prices. Between 1981 and 1989 the Nilde field produced 20.5 MMbbl of oil. According to an independent assessment by GE Plan and Hot Engineering from 2016, the remaining 2C contingent recoverable resource of the Nilde field could now be estimated at 60 MMbbl of oil. A previous independent assessment, by Senergy (GB) Limited dated 15 February 2016 pointed to contingent resources (2C) of 34 MMbbl of oil (20.2 MMbbl of oil 1C and 54.4 MMbbl of oil 3C) for the Nilde field (28.4 MMbbl) and the two adjacent discoveries Norma (3.9 MMbbl) and Naila (1.7MMbbl). Upon completion of the deal, interest in the d363C.R-.AX exploration permit will be shared between AuDAX Energy Srl (50% - operator) and SDP Services Ltd (50%).",Italy (Sud-Tellian Atlas) Norma 1
14167,"Carnarvon Petroleum Ltd was awarded exploration permit AC/P63, located in the Vulcan Sub-basin, Bonaparte Basin, on 8 February 2018. The permit has been awarded for a period of six years and will expire, or be eligible for renewal, on 7 February 2024. Work commitments have been assigned for the duration of the permitâs validity. For the first three-year period, which is committed, the operator will licence or purchase 542 sq km 3D data from the multi-client Cygnus survey, undertaken in late 2015/early 2016, and will then conduct analysis and reprocessing of this, and additional, seismic over the licence area. A well is planned under the contingent work commitments, scheduled between February 2022 and February 2023, at an estimated cost of AUD 30 million. Pre- and post-well studies are also included in the work commitments. The permit was awarded after being offered as block AC17-3 in the 2017 Federal Offshore Acreage Release. It is the first permit to be announced as awarded from this round, which saw 11 blocks close in October 2017. Ten blocks remain open. AC/P63, which covers an area of 585 sq km, was awarded on 8 February 2018. Carnarvon Petroleum Ltd holds 100% interest and operatorship of the permit.","Australia, not found"
52346,"On 23 January 2019, National Iranian Oil Company announced that it had encountered 40° API oil at a depth of 3,770 m in the Minoo 1 exploration well in Khuzestan Province. The well, which is believed to have been spudded in December 2017, is being drilled at the Minoo (Abadan) prospect. It is located close to the Iran-Iraq border, approximately 15 km south-east of the Siba gas field in Iraq. Drilling and testing of the well was continuing in May 2019. The Minoo (Abadan) prospect, located in the Dibdibah Sub-basin, is presumed to be an anticlinal structure with Cretaceous objectives. Iran has stated that the oil encountered at Minoo represents the first oil discovery in the Abadan area.","Minoo 1 National Iranian Oil Company announced that it had encountered 40° API oil at a depth of 3,770 m in the Minoo 1 exploration well in Khuzestan Province. "
70869,"On 27 January 2020, ExxonMobil reported that it has increased its gross recoverable resource estimate for its prolific Stabroek Block, offshore Guyana by 2 Bboe. Total gross recoverable resources are now estimated to be greater than 8 Bboe, rather than the 6 Bboe estimate touted, since 31 July 2019. The latest estimate is based on the results of a total of 15 discoveries. ExxonMobil announced concurrently that it had made its 16th discovery on the block, encountering 29m of high-quality oil-bearing sandstone reservoir with the Uaru 1 well (see related article). This well has not been added to the resource estimate yet. Both Tripletail 1 and Mako 1 have been drilled since the previous resource estimate and will have contributed to the jump in the recoverable resources estimated on the block. Tripletail encountered 33m of high-quality oil-bearing sandstone reservoir in the Turbot area of the block in September 2019 and Mako 1, in December 2019, encountered 50m of high-quality oil-bearing sandstone reservoir around 9.6km south of the Liza 1 discovery. First oil was produced in Guyana on 20 December 2020, with the start up of Liza Phase 1 utilising the ""Liza Destiny"" Floating Production Storage and Offloading (FPSO) vessel. Production is currently ramping up and will be up to 120,000 bo/d. Lisa Phase 2 is expected by mid-2022, utilising a similar concept with the ""Liza Destiny"" FPSO having a planned capacity of 220,000 bo/d. ExxonMobil and partners are targeting at least 750,000 bo/d in production and five FSPOs on the Stabroek Block by 2025. The Stabroek Block is operated by ExxonMobil with 45% WI. Hess (30%) and CNOOC (25%) hold the remaining WI. Later this year, ExxonMobil is going to start drilling in Guyana outside of the Stabroek Block, with wells planned on its deepwater Canje and Kaiteur Blocks to the north east of Stabroek. ExxonMobil has applied to Guyana's Environmental Protection Agency for three wells on each block. Tanager 1 is thought to be the key prospect on Kaieteur, with Bulletwood the key prospect on Canje, alongside Jabillo and Sapote.","ExxonMobil reported that it has increased its gross recoverable resource estimate for its prolific Stabroek Block, offshore Guyana by 2 Bboe. Total gross recoverable resources are now estimated to be greater than 8 Bboe, rather than the 6 Bboe estimate touted, since 31 July 2019. The latest estimate is based on the results of a total of 15 discoveries. ExxonMobil announced concurrently that it had made its 16th discovery on the block, encountering 29m of high-quality oil-bearing sandstone reservoir with the Uaru 1 well "
67312,"Tangram is offering equity in so far wholly-owned, 76-sq km P2440 (block 48/20c), home to the 48/20b-6 (Uno) gas discovery (ConocoPhillips, 1990) off the Norfolk coast. Contact Martin.Smith@tangram-energy.com. Likewise for P2359 (blocks 13/30c + 14/26d), 174 sq km off Aberdeen and containing the 13/30-2 (Samedi) oil discovery (Britoil, 1984).","Tangram is offering equity in so far wholly-owned, 76-sq km P2440 (block 48/20c), home to the 48/20b-6 (Uno) gas discovery (ConocoPhillips, 1990) off the Norfolk coast."
13547,"On 29 January 2018, local media reported that Statoil had decided to quit negotiations about Angoche Area A5-A after two years of discussions with Mozambican government. Statoilâs rights were passed to Eni, the operator of the block. The 5,145 sq km offshore block, which is located in the Angoche Basin, was awarded to Eni on 29 October 2015 in the Mozambique fifth licensing round, subject to agreement on the terms. Eni was handed the operatorship of the block with a 34% interest. Partners are Sasol 25%, Statoil 25% and ENH 15%. The partners are committed to spend USD 115 million for the first 4-year period including the acquisition of 4,000 sq km 3D seismic data and the drilling of three wells. Â ","The lack of progress in negotiations and an unattractive business environment are reportedly behind Statoilâs decision to quit block A5-A. 25% will presumably re-distributed among remaining parties Eni (op) 34%, Sasol 25%, ENH 15%."
79157,"A comprehensive three-year scientific study by CSIROâS GISERA into the air, water and soil impacts of hydraulic fracturing in Queensland has found little to no impacts on air quality, soils, groundwater and waterways. The study also found current water treatment technology used for treating water produced from coal seam gas wells is effective in removing hydraulic fracturing chemicals and naturally occurring (geogenic) chemicals to within relevant water quality guidelines. Research objectives for Air, Water and Soil Impacts of Hydraulic Fracturing in the Surat Basin, Queensland, conducted by the CSIROâs Gas Industry Social and Environmental Research Alliance, were developed in response to community concerns about the potential for chemicals used in hydraulic fracturing operations to affect air quality, soils and water resources. The study analysed air, water and soil samples taken before, during and up to six months after hydraulic fracturing operations at six coal seam gas wells in the Surat Basin in Queensland. GISERA Director Dr Damian Barrett said that the CSIRO research conducted via GISERA in this region was an Australian first and provided unique insights into the impacts of hydraulic fracturing in Australia. 'This new research provides valuable data about hydraulic fracturing in coal seam gas formations in the Surat Basin, Queensland,' Dr Barrett said. 'Previously, the only information about hydraulic fracturing was from overseas studies in quite different shale gas formations. 'Clearly governance, industry regulation and operational integrity are crucial in managing risk and potential impacts of hydraulic fracturing.' Results from the studies showed: Air quality monitoring found hydraulic fracturing operations had little to no impacts on air quality, with no significant variation between air quality at hydraulic fracturing operational sites and control sites where no hydraulic fracturing activities occurred. Levels of most atmospheric air pollutants detected were generally below relevant national air quality objectives. Increased levels of airborne particles were associated with dust from vehicle movement. Hydraulic fracturing chemicals were not detected in water samples taken from nearby groundwater bores, soil samples from sites adjacent to operational wells, or in water samples from a nearby creek. Water produced from the wells immediately after fracturing contained hydraulic fracturing chemicals, elevated concentrations of major ions (salts), ammonia, organic carbon, some metals and organic compounds, with concentrations reducing to a pre-fractured state within 40 days. Current water treatment operations are effective in removing hydraulic fracturing chemicals and geogenic chemicals either completely or reducing levels to within acceptable limits according to water quality guidelines. Some types of biocides used in hydraulic fracturing fluids and some geogenic chemicals were completely degraded in soil samples within two to three days. Soil microbial activity was reduced by the addition of hydraulic fracturing fluids and produced water. GISERA is a collaboration between CSIRO, Commonwealth and state governments and industry established to undertake publicly reported independent research. The purpose of GISERA is for CSIRO to provide quality assured scientific research and information to communities living in gas development regions focusing on social and environmental topics. Original article link Source: CSIRO",Australia (Taroom Trough (Bowen - Surat Bsns)) Link
7258,"Meleiha NE A block, Shoushan sub-basin, W. Desert, susp. oil (AEB-6) at TD 3,581m in Sep â17, Emsco-602 rig. Targets Alam El Bueib, Bahariya and Masajid fmâs. Agiba = EGPC (50%), IEOC (38%), Lukoil (12%).","Egypt (Northern Egypt B.) ? op. by ENI SPA (76.0%, LUKOIL 24.0%, AGIBA 0.0%) in Meleiha (Dev) block"
68269,"On 27 December 2019, Gazprom provided update on appraisal of the Kruzenshternskoye field in Yamalo-Nenets Autonomous Okrug (Western Siberia). In 2019, the company drilled a highly deviated well with a TD of 4,900 m targeting the offshore extension of the field some 3.9 km from the coast. Based on the well and new seismic data, 3P gas reserves of the field were increased by 12.33 Tcf from 56.17 Tcf to 68.5 Tcf. Also, recoverable 3P condensate reserves were boosted from 21.6 MMbbl to 92.8 MMbbl. Kruzenshternskoye, discovered in 1976, is located on the western coast of the Yamal Peninsula but the major part of the field lays in the Kara Sea (South Kara-Yamal Province).","Gazprom provided update on appraisal of the Kruzenshternskoye field (discovered in 1976) in Yamalo-Nenets AO. In 2019, the company drilled a highly deviated well with a TD of 4900 m targeting the offshore extension of the field some 3,9 km from the coast. Based on the well and new seismic data, 3P gas reserves of the field were increased by 12.33 Tcf from 56.17 Tcf to 68.5 Tcf. Also, recoverable 3P condensate reserves were boosted from 21.6 MMbbl to 92.8 MMbbl."
76556,"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 licence P2470 (blocks 11/23, 11/24c and 11/25b) which was also on offer has now been relinquished, as of 31 March 2020. This licence was thought to host a number of prospects including Dunbeath, Camster, Camster South and Whalingoe along with the Knockinnon discovery. 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.","United Kingdom, Frigg"
69853,"On 30 November 2019, INA Industrija Nafte d.d. (INA) completed drilling new-field wildcat Jankovac 1 in the Drava 2 permit in northeastern Croatia. The well was drilled to the final depth of 1,635 m (TVD 1,598 m) in an undisclosed Mesozoic succession. The results of the well, solely operated by INA, have yet to be disclosed. Jankovac 1 was spudded on 14 November 2019, using the National 402 drilling unit from Crosco. The well is located in the northern sector of the permit, approximately 10 km west of the city of Koprivnica. In a geological sense, the well is situated within the Somogy-Drava Sub-basin, tectonic unit of the Pannonian Basin. The well had an initial planned final depth of 1,400 m, targeting the Lower and Middle Miocene successions. A secondary target was in the Mesozoic basement series. Background Information The 2,468 sq km Drava 2 block was granted to INA on 10 June 2016, from the country's 1st onshore bidding round (closed on 18 February 2015). The permit encompasses some 30 fields and discoveries (carved out from the permit area), in particular the Molve and the Kalinovac gas fields. The latest drilling operation in the country dates back to mid-2018, when INA abandoned dry wildcat Mala Jacenovaca 1. The well was drilled to the total depth of 1,223 m (TVD 1,171 m) in the Middle Miocene series.","Jankovac 1 nfw. (INA 100%) in the Drava 2 permit in NE of the country, completed. The well was drilled to the final depth of TD=1635m in an undisclosed Mesozoic succession. The results of the well, have yet to be disclosed."
29114,"YPF and YPFB have agreed to jointly evaluate the potential of the gas-prone Sauce Mayu block, 458 sq km in the Sub-Andean Zone, Chaco Basin, Chuquisaca. Plans include a well in 2019, results of which may pave the way for larger investment (up to USD 588 MM suggested). Sauce Mayu surreounds Repsolâs Monteagudo field.","YPF and YPFB have agreed to jointly evaluate the potential of the gas-prone Sauce Mayu block, 458km² in the Sub-Andean Zone."
24817,"N. part of AD-1, deepwater N. Rakhine Basin, WD ca. 1,400m, compl results n/a late Jun â18. PTD was 4,600m, target Pliocene turbidites, Dhirubhai Deepwater KG2 DS.","Aung Siddhi 1 (Woodside and CNPC 50/50 JV) in deepwater Block AD-1, operations likely completed, with results unreported. PTD was 4 600m, target Pliocene turbidites."
43919,"IGas Energy spudded Springs Road-1 exploration well in PEDL 140 on 22 January 2019. The vertical well will be drilled to a depth of approximately 3,500 m through the Bowland Shale and into the Carboniferous Limestone and based on the findings of the first well, it was thought that a possible horizontal well will be drilled in a southern direction through the Bowland Shale. On 15 February 2019 IGas announced that it has encountered shales (including the Bowland Shale) on prognosis at approximately 2,200 m. In a further update from IGas on 11 March 2019 the company announced that it has encountered a hydrocarbon bearing shale sequence of over 250 m with significant gas indications observed throughout the shale section and additionally within sands in the Millstone Grit sequence. The company has recovered 150 m of shale core with petrophysical core analysis ongoing. Following encountering both the primary and secondary targets the company is now drilling its tertiary target, to provide further information on the resource potential for multiple hydrocarbon bearing horizons within the Gainsborough Trough. Â IGas has drilled a number of boreholes at the site to monitor groundwater. The boreholes were successfully drilled in February 2016, these will enable the company to understand conditions, prior to, during and after operations. If drilling is successful the company will move forward in submitting a subsequent planning application to test and frack the well. PEDL 139 was awarded in the 12th Landward Licensing Round and comprises of one block SK/69. PEDL 140 was awarded under the same licence round and comprises of two blocks â SK/78f and SK/79a. IGas shot a 3D seismic survey over PEDL 139 and PEDL 140 during 2014. Interest in PEDL 139 is held by IGas subsidiary Island Gas Limited (14.5%), INEOS Upstream Ltd (40%), other IGas subsidiary GP Energy Ltd (17.5%), Egdon Resources UK Ltd (14.5%) and eCORP Oil & Gas UK Ltd (13.5%).","Springs Road 01 (IGas 32%, INEOS 40%, Egdon 14.5%, eCORP O&G 13,5%) the second in a three-well exploratory drilling programme at sites at Tinker Lane and Springs Road in PEDL 140, encountered a hc bearing shale sequence of over 250m, including the upper and lower Bowland shale and significant gas indications were observed throughout the shale section and additionally within sands in the Millstone Grit sequence."
47223,"On 31 March 2019, Delek Drilling Ltd Partnership announced that it had signed an agreement with S.O.A. Energy Israel Ltd under which it will acquire a 25% interest in each of the Ofek New (405) and Yahel New (406) onshore exploration licences. Following the transaction, which was subject to fulfilment of several conditions, interests in each of the licences will be S.O.A. Energy 45%, Delek Drilling 25%, Globe Exploration (I.H.D.) Partnership Ltd 20% and Capital Point Ltd 10%. S.O.A. Energy will also assume operatorship of the licences from Globe Exploration. The Yahel New (406) licence covers an area of 397.5 sq km in the Judea Basin and was awarded on 21 June 2017. The Ofek New (406) licence covers an area of 344 sq km and was also awarded in June 2017. S.O.A. is planning to drill a well in the Ofek New (406) licence in mid-2019. On 3 November 2013, Globe Exploration announced that the Ofek 2ST1 well in the previous licence (Ofek 381) had reached the Permian objective at a depth of 6,460 m and that log data had indicated substantial signs of gas and condensate over a net interval of 50 m. Globe Exploration stated that the discovery can only be confirmed by production tests but at the time it did not have sufficient funds to cover the USD 2.5 million estimated costs. The Ofek 1 exploration well was plugged and abandoned as a dry hole in the licence in February 2012.",Delek Drilling Ltd Partnership announced that it had signed an agreement with S.O.A. Energy Israel Ltd under which it will acquire a 25% interest in each of the Ofek New (405) and Yahel New (406) onshore exploration licences.
16047,"On 6 March 2018, Petrolera Cardenas Mora, S.A.P.I. de C.V., a Cheiron Holdings Limited subsidiary, was granted an official award by the CNH for the CNH-A3.Cardenas-Mora/2018 contract from the CNH-A4-Cardenas-Mora/2017 farm-out bid round for the 168.46 sq km Cardenas-Mora block in the onshore Sureste Basin. Petrolera Cardenas Mora has a 50% working interest in the contract and is the operator and PEMEX has a 50% non-operated working interest. The contract is a license contract with a 25 year development phase and two possible five year extension periods. The minimum work program has been set at 7,844 work units equivalent to USD 8.5 million at an oil price of between USD 60 to USD 65/bbl. The JOA for the Cardenas-Mora license contract has Petrolera Cardenas Mora paying PEMEX a fee of USD 125 million for previous work conducted in the block.   ",Egypt's Cheiron Holdings operatorship and 50% in the CNH-A3-Cárdenas-Mora/2017 block.
22324,"Block 12, Al Muthanna + Najaf prov. in S. Iraq, confirmed oil discovery today, TD 4,277m, tested ab. 4,000 bo/d in 1Q â18. Target Kurrachine fm. To be appraised later this year by Salman-2 & 3.","Salman 1 Block 12, Al Muthanna + Najaf prov. in S. Iraq, confirmed oil discovery today, TD 4,277m, tested ab. 4,000 bo/d in 1Q â18. Target Kurrachine fm. To be appraised later this year by Salman-2 & 3."
81107,"The Chadian Ministry of Petroleum and Energy is promoting the countryâs open acreage which is available to companies for direct negotiations. As of December 2019, the free blocks were: CHAD Open Acreage Basin Names Block Name Block Sqkm Main Political Province Borkou-Ennedi Sub-basin (Al Kufra Basin)~Djado Basin~Tibesti Massif~Chad Basin Djado Block II 13,848 Tibesti Borkou-Ennedi Sub-basin (Al Kufra Basin)~Faya Sub-basin (Chad Basin) Largeau Block I 11,706 Borkou Chad Basin Moussoro Block 11,927 Kanem Chad Basin Lac Chad Block 11,900 Kanem Chad Basin Lac Chad Block I 3,783 Kanem Chad Basin~Bodele Sub-basin (Chad Basin) Siltou Block II 17,800 Borkou Chad Basin~Bodele Sub-basin (Chad Basin) Siltou Block I 11,803 Tibesti Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Manga Block 16,759 Tibesti Chad Basin~Bornu Trough - Chad Basin~Termit Trough - Chad Basin LC-2008 10,988 Hadjer-Lamis Chad Basin~Darfur - Ouaddai Massifs~Bongor Trough MD-2008 11,725 Ville de Ndjamena Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block IV 17,709 Borkou Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block VII 11,815 Batha Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block III 10,623 Borkou Darfur - Ouaddai Massifs~Doba Trough~Bongor Trough Chari-Ouest Block III 4,681 Tandjile Darfur - Ouaddai Massifs~Doseo Trough~Doba Trough~Salamat Basin BDS-2008 41,887 Mayo-Kebbi Est Djado Basin~Tibesti Massif Djado Block I 21,569 Tibesti Doba Trough~Darfur - Ouaddai Massifs WD 1-2008 2,029 Mayo-Kebbi Ouest Faya Sub-basin (Chad Basin)~Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Largeau Block VI 11,770 Ennedi-Ouest Faya Sub-basin (Chad Basin)~Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Largeau Block II 11,739 Borkou Source: IHS Markit © 2019 IHS Markit  The latest version of the Hydrocarbon Law in Chad was translated into English in August 2008. On 27 August 2007, Chad's Prime Minister M. Nouradine Delwa Kassiré Comakye announced that the country had promulgated legal texts and implemented mechanisms relating to the specific management of its oil incomes in order to adhere to the Extractive Industries Transparency Initiative (EITI). The Government solemnly declared that the principles of this initiative from that moment on would be applied to Chad and the incomes drawn from the extractive industries would be declared and used in total transparency. The Al Kufra Basin is better known as Erdis Basin in Chad. The south extension in Niger and Chad of the Murzuq Basin is called Djado Basin (or Jadu Basin) and has seen no hydrocarbon exploration in the past. The Faya-Largeau area is poorly explored, with only a few low-quality seismic lines acquired in the 1980s. The Lake Chad area was one of the first regions to be explored in Chad, but unlike the Doba Trough, it has not been intensively explored. Three discoveries have been made: Kanem-1 in 1974, Sedigi in 1975 and Kumia-1 in 1976.","The Chadian Ministry of Petroleum and Energy is promoting the countryâs open acreage which is available to companies for direct negotiations. As of December 2019, the free blocks were: CHAD Open Acreage Basin Names Block Name Block Sqkm Main Political Province Borkou-Ennedi Sub-basin (Al Kufra Basin)~Djado Basin~Tibesti Massif~Chad Basin Djado Block II 13,848 Tibesti Borkou-Ennedi Sub-basin (Al Kufra Basin)~Faya Sub-basin (Chad Basin) Largeau Block I 11,706 Borkou Chad Basin Moussoro Block 11,927 Kanem Chad Basin Lac Chad Block 11,900 Kanem Chad Basin Lac Chad Block I 3,783 Kanem Chad Basin~Bodele Sub-basin (Chad Basin) Siltou Block II 17,800 Borkou Chad Basin~Bodele Sub-basin (Chad Basin) Siltou Block I 11,803 Tibesti Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Manga Block 16,759 Tibesti Chad Basin~Bornu Trough - Chad Basin~Termit Trough - Chad Basin LC-2008 10,988 Hadjer-Lamis Chad Basin~Darfur - Ouaddai Massifs~Bongor Trough MD-2008 11,725 Ville de Ndjamena Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block IV 17,709 Borkou Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block VII 11,815 Batha Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block III 10,623 Borkou Darfur - Ouaddai Massifs~Doba Trough~Bongor Trough Chari-Ouest Block III 4,681 Tandjile Darfur - Ouaddai Massifs~Doseo Trough~Doba Trough~Salamat Basin BDS-2008 41,887 Mayo-Kebbi Est Djado Basin~Tibesti Massif Djado Block I 21,569 Tibesti Doba Trough~Darfur - Ouaddai Massifs WD 1-2008 2,029 Mayo-Kebbi Ouest Faya Sub-basin (Chad Basin)~Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Largeau Block VI 11,770 Ennedi-Ouest Faya Sub-basin (Chad Basin)~Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Largeau Block II 11,739 Borkou "
61937,"Official information, recently disclosed, confirmed that Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) abandoned new-field wildcat Radew 1 in the 48/2009/L Tychowo permit in northwestern Poland in mid-July 2019. The well, drilled to the final depth of 3,400 m in the Lower Carboniferous series, was solely operated by PGNiG. The Radew 1 well was spudded on 9 April 2019, using the Masseranti 6000E drilling unit. The well is located some 15 km southwest of the city of Koszalin. In a geological term, it is falling within the Pomeranian Trough, tectonic unit of the Danish-Polish Marginal Trough. The Tychowo permit is located in the Zachodnio-Pomorskie political province, some 100 km north-east of the city of Szczecin. It covers now the western part of the country's national grid block 65 and the northwestern sector of the block 85. Radew 1 had a planned final depth of 3,400 m, targeting the Carboniferous and Devonian series. On 30 April 2019, the well reached a depth of 2,286 m in the Lower Triassic series. By the end of May, Radew 1 reached a depth of 3,037 m in the Permian (Zechstein) succession. The final depth was reached on 19 June 2019. Testing was completed on 16 July 2019 and the well was plugged with gas shows. Background Information The Tychowo contract was granted to PGNiG on 20 August 2009. The contract had a six-year validity term. On 20 August 2015, the 48/2009/p Tychowo contract was prolonged until 31 December 2016. Concurrently, the permit was diminished in its eastern part and reduced from 807 sq km to 315 sq km. In 2016, the tract was extended and the operator commenced procedure for changing the rights in the tract from exploration to exploration-production. The process was concluded on 3 July 2018 and the designation of the tract was changed from 48/2009/p to 48/2009/L. At the same time, the contract received a new exploration term of five years, until 3 July 2023, and the production term of subsequent 25 years. The latest exploration activity in the area dates back to late 2015/early 2016, when PGNiG completed the acquisition of Drzewiany 3D seismic programme. Earlier, in December 2012/January 2013, PGNiG acquired a 3D seismic survey Rabino, partly covering the Tychowo contract. Targets in the area are related to the presence of the Lower Permian (Rotliegend) sandstone successions and the Upper Permian (Zechstein) carbonate series, proven hydrocarbon series. The latest exploration concepts include also the distribution of the underlaying Upper Palaeozoic - Devonian-Carboniferous - series in the subsurface, with the Carboniferous series being the most promising. Since 2016, PGNiG is progressing a new petroleum concept related to potential presence of hydrocarbon-charged syn-rift structures in the structurally lower parts of the basin. To the west and northwest of the Tychowo region, there are the Daszewo oil, as well as the Bialogard and Daszewo North gas fields. Only a few wells are known to have been drilled within the area of the block, most of them during the 1960s and 1970s. The latest drilling operation in the area dates back to December 2014, when PGNiG abandoned new-pool wildcat Daszewo 27k in the 15/2008/p Bardy permit. The well was drilled to the final depth of 3,727 m in the (undisclosed) Devonian series.",Poland (Pomeranian Trough (Danish-Polish Marginal Trough)) Tychowo
30943,"Mari Petroleum Company Ltd (MPCL) announced on 14 September 2018 that it has discovered oil in Bolan East 1 new-field wildcat (NFW) well within the Ziarat 2967-2 EL (Sulaiman Fold Belt) onshore block. It is located near Mach city in Kachhi district in Balochistan province. Drill stem test (DST) was conducted after drilling to a final TD of 1,500 m, reached in mid-August, and the well is reported to have flowed 810 bo/d of 15.6â API through 32/64â choke from the Jurassic Chiltan Formation limestone at a well head flowing pressure (WHFP) of 134 to 167 psi. DST was also carried out in Upper Cretaceous Moro / Mughal Kot formations which flowed 690 bo/d of 15.6â API through 32/64â choke at a WHFP of 142 to 158 psi. MPCL expects an increased flow rate from Moro/Mughal Kot zone if DST is conducted after acid stimulation. Bolan East 1 was spudded on 22 May 2018 using the âMari-1â land rig with a prognosed TD of 1,550 m. It was targeting the Paleocene Dunghan Limestone, Cretaceous Moro/Mughal Kot and Jurassic Chiltan Limestone formations. Bolan East 1 was drilling at 497 m depth by the end of May 2018. The well experienced gas-kick after reaching 1,296 m depth during late June 2018 and it was subsequently controlled in July. The Ziarat licence, located in Balochistan province, currently covers an area of 1,205 sq km and the equity split is as follows: MPCL (60%, operator) and PPL Europe E&P Ltd (40%). MPCL had acquired 220 line km 2D seismic in the block during July-December 2015 period. The company carried out reprocessing of the data using the services of Geofizyka Torun which was completed in April 2017.  Background Information Mari Petroleum Company Ltd (MPCL) was previously known as Mari Gas Company Ltd (MGCL) - the name was changed with effect from 19 November 2012. The Ziarat EL licence was exclusively awarded to MGCL on 22 January 2003 and it is essentially identical to the acreage that was surrendered by Premier-Kufpec Pakistan Exploration Ltd (PKPEL) from its Bolan EL in August 2002. The work programme for the initial three-year exploration phase (with a minimum financial commitment of US$3.65 million) is believed to have included the drilling of one exploration well. MGCL assigned a 15% working interest in the acreage to Pakistan Oilfields Ltd (POL) with effect from 7 November 2003 and a further 25% working interest was subsequently transferred to MND E&P Ltd with effect from 25 November 2004 following the acquisition of 62.4km 2D seismic over the block in June 2004. The licence was granted a one-month extension to the second contract year with effect from 22 January 2005 and POL assigned its entire 15% working interest in the acreage to MND with effect from 27 January 2005, as a result of which the current equity split was as follows - Mari Gas Co Ltd (MGCL) (60%, operator) and MND E&P Ltd (40%). Although the first well to be drilled during the current licence term, Ziarat 1 (Khost 1), failed to flow from the Jurassic Chiltan Formation due to high levels of H2S (hydrogen sulphide) on reaching a final TD of 1,050m in November 2005, a successful DST over the basal part of the Palaeocene Dunghan Formation tested 6.87 MMcf/d through a 32/64"" choke at a wellhead flowing pressure of 664 psi - the gas having a calorific value of 946 Btu/cf (85.49% methane, 1.9% ethane, 6.68% carbon dioxide, 4.45% nitrogen and over 6,000 ppm H2S). It is understood that the structure is approximately 35 sq km in size and an appraisal well, Ziarat 2 (Khost 2), subsequently flowed 1,994 bo/d from the Palaeocene Dunghan Formation at a depth of around 1,100m through a 64/64"" choke on reaching a final TD of 1,209m in July 2008. A further exploration well on the acreage, Shahrig 1, was P&A on reaching a final TD of 1,550m in April 2008. A one-year extension was granted to the Phase-I of initial term with effect from 22 February 2006. The licence entered into two-year Phase-II of initial term with effect from 22 February 2007. MGCL was granted a one-year extension to the Phase-II of initial term with effect from 22 February 2009. A further one-year extension to Phase-II was granted with effect from 22 February 2010. Mari Petroleum was granted an additional one-year extension to Phase-II of initial term with effect from 22 February 2011. Pakistan Petroleum Ltd (PPL) entered into the block after acquiring MND Exploration and Production Ltd (MND E&P) on 9 April 2013. Mari Petroleum was granted two further one-year extensions up to 21 February 2014. The company was granted an additional one-year extension to the Phase-II of initial term with effect from 22 February 2014. A further six-month extension to the Phase-II of initial term of the Ziarat EL was granted with effect from 22 February 2016. MPCL was granted a first two-year renewal to the Ziarat EL from 2 August 2016 to 1 August 2018. The block area was also reduced from 2,444 sq km to 1,205 sq km.","Bolan E.-1 (Mari 60% op, PPL 40%) in Ziarat 2967-2 EL, tested 810 b/d of 15,6° API oil [1/2â choke] from the Jurassic Chiltan Fm , the Upper Cretaceous Moro / Mughal Kot fmâs later gauged 690 b/d of 15,6° API oil [1/2â choke], TD=1500m."
14273,"Subject to approvals, Pampa Energia has agreed to sell Petrolera Entre Lomas SA (PELSA) and several other Neuquen and Rio Negro assets to Vista O&G* for USD 360 million. PELSA holds a 73.15% operated interest in the Charco del Palenque, Jarilla Quemada, Bajada del Palo and Entre Lomas concessions, as well as 100% in the 25 de Mayo-Medanito SE and Jaguel de los Machos blocks. *Vista was incorporated in Mexico in early â17 and is headed by former YPF CEO Miguel Galuccio.",Pampa Energia has agreed to sell Petrolera Entre Lomas SA (PELSA) and several other Neuquen and Rio Negro assets to Vista O&G* for USD 360 million.
48868,"Bahga devt lease, Abu Gharadiq Basin, drilled 20 Feb â mid Mar â19, P&A at TD 3,025m (Abu Roash G), EDC rig 72. Petro Alam = Shell, North Petroleum Intl, EGPC JV.","Egypt, Abu Gharadiq (Dev)"
80275,"In late March 2020, INA-Industrija nafte d.o.o. (INA) received the final award of the Drava 3 (DR-3) block in northeastern Croatia. The grant followed a decision of the Government that authorized the Ministry of Energy to sign off the contract. The Drava 3 permit is solely operated by INA. The contract has a three-year exploration term, with an option for a two-year extension. The Drava 3 block, located along the border with Hungary, falls within the Somogy-Drava Sub-basin, tectonic unit of the Pannonian Basin. The contract is the result of the country's second onshore tender call, organised in late 2018/2019. The news on the award was publicised by INA on 30 March 2020. Background Information Croatiaâs 2nd onshore bidding round was announced on 31 October 2018 and closed on 28 June 2019. The Croatian Hydrocarbon Agency (CHA) was tendering seven blocks in the northern part of the country: Drava 3 (DR-3), Sava 6 (SA-6), Sava 7 (SA-7), Sava 11 (SA-11), Sava 12 (SA-12), Sjeverozapadna Hrvatska 1 (SZH-1) and Sjeverozapadna Hrvatska 5 (SZH-5). The Government of the Republic of Croatia, acting through Croatian Hydrocarbon Agency, announced on 29 August 2019 that it had pre-awarded the Drava 3 to INA. The pre-award is a prerequisite to opening negotiations for the contract. The signing of the final contract was expected in late 2019/early 2020. The Drava 3 area is holding several producing oil and gas fields operated by INA. The first exploration operation â likely seismic survey - is expected in the second half of 2020.",INA-Industrija nafte d.o.o. (INA) received the final award of the Drava 3 (DR-3) block in northeastern Croatia. The grant followed a decision of the Government that authorized the Ministry of Energy to sign off the contract. The Drava 3 permit is solely operated by INA
77125,"Lime has agreed with Equinor to acquire a 20% interest in each of PL 263D + 263E, total 66 sq km on the Halten Terrace, Norwegian Sea. NFW Apollonia is pencilled to be drilled here in late 2020, target Jurassic. The transfer is pending regulatory approval. Partnership to become Equinor (op), Pandion + Lime.","Norway, not found"
35354,"Sacgasco Ltd announced on 19 November 2018 that it had signed an exclusive option agreement to acquire all the issued shares in RL Energy Pty Ltd. Under the terms of the deal, Sacgasco will initially make a payment of AUD 200,000 cash and 2 million Sacgasco shares to the RL Energy shareholders. An exclusive option is then to be exercised, by 30 January 2019. Once this is complete, Sacgasco will pay a further AUD 25,000 and 4 million Sacgasco shares to the RL Energy shareholders. RL Energy had previously entered an agreement to farm-in, for up to 60% interest into exploration permit PEP 11, located in the Sydney Basin. As part of the acquisition by Sacgasco, it will assist in the lodgement for and environmental approval for 3D seismic over the permit, which is part of RL Energyâs farm-in commitments, at an estimated cost of AUD 326,000. Under the terms of the farm-in agreement, RL Energy can earn an initial 5% interest by arranging environmental proposals for a new 3D seismic survey over the permit area. RL Energy can then earn up to a further 55% by funding Advent Energyâs share of a 500 sq km 3D seismic survey, up to a capped amount of AUD 4 million. The seismic acquisition is under the work programme for the permit and is scheduled between February 2020 and February 2021. It was reported that joint venture partner Bounty Oil and Gas NL supports the farm-in. However, it has been subsequently reported, in mid-October 2018 that operator Advent Energy Ltd, had issued a notice to joint venture partner Bounty Oil and Gas it was exercising an option to acquire 100% interest in exploration permit PEP 11 as it is in default of payments for a number of outstanding costs. Bounty reports that it currently retains its 15% interest, and that it was conducting discussions with Asset Energy around the disputed cash calls. PEP 11 covers an area of 4,573 sq km and was awarded on 24 June 1999. Participants in the permit are currently Asset Energy Pty Ltd, a wholly owned subsidiary of Advent Energy, 85% and Bounty Oil and Gas 15%, though this is being disputed. RL Energy has the option to farm-in for up to 60% interest. .",Sacgasco Ltd announced on 19 November 2018 that it had signed an exclusive option agreement to acquire all the issued shares in RL Energy Pty Ltd.
15539,"On 27 February 2018, Alvopetro Energy announced results from testing its 1ALV6DBA new field wildcat well on the REC-T-183 Block of the Reconcavo Basin. The well was originally drilled in 2014 with a total depth of 3,550m. Logs showed the well encountered 168m of potential hydrocarbon net pay in several intervals, using a 6% porosity cut-off. Plans called for the test of two intervals and possibly a third. Alvopetro perforated and completed 10m of potential net pay in the first interval of the Gomo Member of the Candeias Formation, with 9.7% average porosity. During the 6-hour, cased-hole test the interval flowed natural gas without stimulation at an average rate 240 Mcfg/d or 40 boe/d on a 12/64"" choke, with a final flowing tubing head pressure of 249 psi. After the test, the well was shut-in and an injectivity test was performed to evaluate permeability and expected productivity after stimulation. The interval was then sealed with a bridge plug. In the second interval, 6m was perforated and completed in a potential net pay zone of the Caruacu Member of the Maracangalha Formation, with 11.1% average porosity. A 34-hour, cased-hole test was performed and the interval flowed natural gas without stimulation at a final stabilized rate of 92 Mcf/d or 15 boe/d on a 8/64"" choke with a flowing tubing head pressure of 414 psi. During the test 12 barrels of 61deg API condensate was also recovered. Alvopetro then moved up-hole to test a third interval where a 15m interval was tested with 11.5% porosity in the Caruacu Member of the Maracangalha Formation. This test produced only formation water. Alvopetro is currently analyzing the fluid composition data from the second interval and pressure data from both the first and second intervals in order to predict productivity of the two intervals after stimulation. Alvopetro on 9 October 2014 announced the 1ALV6DBA as a hydrocarbon discovery with 189m of potential net pay over several intervals. Based on logs and mapping Alvopetro has estimated that the structure contains 3.8 Tcfg of gas in place or 620 MMboe. Over 40m of core was taken for extensive special core analysis studies. The 1ALV6DBA had a planned total depth of 3,677m. It was spud with the Early Cretaceous Candeias Formation was the projected objective. The block contains three old dry holes and one 1968 well with oil and gas shows. Alvopetro has a 100% interest in the block. ","1ALV6DBA new field wildcat well on the REC-T-183 Block of the Reconcavo Basin.Logs showed the well encountered 168m of potential hydrocarbon net pay in several intervals, using a 6% porosity cut-off."
67172,The OGA reports 104 applications for 245 blocks or parts thereof from 71 companies including new entrants. Awards are expected in 2Q '20.,"United Kingdom, not found"
37975,"In November 2018, the Government of Russia had registered seven new licenses awarded in the Volga-Ural Province and the Yenisey-Khatanga Basin. Bashneft obtained two five-year exploratory licenses in Bashkortostan Republic (Volga-Ural Province) offered in September 2018: The Abdulovskiy block (UFA02445NP) covers 75 sq km. Its oil resources are estimated at 10 MMbbl. The Mancharovskiy block (UFA02446NP) covers 284 sq km. Its oil resources are estimated at 11 MMbbl. Company NovoKhim obtained two seven-year exploratory licenses in Krasnoyarsk Kray (Yenisey-Khatanga Basin), also offered in September 2018: The Malo-Balakhninskiy block (KRR03109NP) covers 5,702 sq km. Its hydrocarbon resources are estimated at 234 MMbbl of oil and 3.083 Tcf of gas. The Bolshe-Balakhninskiy block (KRR03110NP) covers 5,681 sq km. Its hydrocarbon resources are estimated at 208 MMbbl of oil and 2.997 Tcf of gas. Three long-term licenses were registered based on results of auctions held in October-November 2018. Detailed information regarding the auctions and blocks may be found in the Pre-Award section of GEPS. Udmurtia-registered company Sabunskiy secured two licenses in Samara Oblast (Volga-Ural Province): The Matyanovskiy block (SMR02257NR) covers 528 sq km in the southwestern flank of the Tatarskiy Yuzhnyy Dome and encompasses the Bugulminskiy, Nabokovskiy, Suvarskiy, Khersonskiy and Lefanovskiy Yuzhnyy prospects with combined oil resources estimated at 20 MMbbl. Seismic coverage amounts to 1,320 km. 28 exploratory wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 50 MMbbl of oil and 3 Bcf of gas. The Podkolskiy block (SMR02258NR) covers 178 sq km in the northern part of the Buzuluk Depression and encompasses the Uvarovskiy Severnyy and Podkolskiy prospects and a part of the Ostrogorskiy prospect. Combined oil resources of the prospects are estimated at 6 MMbbl. Five exploratory wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 26 MMbbl of oil and 17 Bcf of gas. Gazprom Neft-Aero Bryansk registered license KRR03111NR in Krasnoyarsk Kray. The Leskinskiy block covers 3,027 sq km in the Yenisey-Khatanga Basin with some extension into the South Kara-Yamal Province. Seismic coverage amounts to 288 km. No wells have been drilled in the block. Hydrocarbon resources (category D2) of the block are estimated at 73 MMbbl of oil and 3.9 Tcf of gas.","Russia, KRR03111NR"
37970,"It was reported in December 2018 that Saif Energy Ltd has assigned its full 10% interest in Bannu West 3370-13 EL (Potwar Basin) onshore concession to Zaver Petroleum Corporation Ltd (ZPCL) and it would be effective retrospectively from 8 June 2018. The licence covers an area of 1,230 sq km and is located in the FATA administrative region of the country. MPCL is the operator of this licence and the revised equity spilt is as follows: MPCL (55%, operator), Oil and Gas Development Company Ltd (OGDCL) (35%) and ZPCL (10%). MPCL initiated 3D seismic acquisition (dynamite/vibroseis source) programme in the block in July 2018 and a total of 216 sq km was acquired by the end of the November 2018 â the survey was continuing although the company has already exceeded the planned target of 150 sq km 3D acquisition.  Background Information The licence was awarded to Tullow Pakistan (Developments) Ltd (85%, operator) and Tullow Pakistan (Operations) Private Ltd (15%) on 27 April 2005 and the work programme for the initial three year exploration phase (with a minimum financial commitment of US$13.16 million) is believed to include G&G studies, the acquisition of 150 sq km 3D seismic and the drilling of one exploration well. Tullow Pakistan (Developments) Ltd assigned a 35% working interest to OGDC with effect from 12 September 2005, with a further 10% also assigned to Saif Energy Ltd. It is understood that Tullow Pakistan (Operations) Private Ltd also assigned a 5% working interest to OGDC at the same time, as a result of which the revised equity split was as follows - Tullow Pakistan (Developments) Ltd (40%, operator), OGDCL (40%), Saif Energy Ltd (10%) and Tullow Pakistan (Operations) Private Ltd (10%). Tullow Pakistan (Operations) Private Ltd subsequently assigned its entire 10% working interest to Mari Gas Co Ltd (MGCL) with effect from 24 May 2006, as a result of which the revised equity split is as follows - Tullow Pakistan (Developments) Ltd (40%, operator), OGDCL (40%), Saif Energy Ltd (10%) and Mari Gas Co Ltd (MGCL) (10%). Mari Gas Co Ltd (MGCL) subsequently changed its name to Mari Petroleum Company Ltd (MPCL) with effect from 19 November 2012. The licence was granted a one year extension to the first contract year with effect from 1 September 2007 - a one year extension having previously been granted. Tullow was granted an additional one year extension to the first contract year of the license with effect from 1 September 2008, followed by a further 12 month extension to the first contract year with effect from 1 September 2009. Tullow was granted an additional one-year extension to the first contract year of the licence concession with effect from 1 September 2010. It was followed by a further two-year extension effective 1 September 2011. Tullow was granted an additional four-year extension to the first contract year of the Bannu West EL from 1 September 2013 to 31 August 2017. It was reported in Tullow Oilâs 2016 Financial Results that Tullow Pakistan (Developments) Ltd had agreed in May 2016 to sell its 20% interest and transfer operatorship in Bannu West EL to MPCL. MPCL subsequently announced on 28 March 2017 that the government has granted approval for the operatorship of Bannu West EL. The company also announced acquiring 5% interest from Oil and Gas Development Company Ltd (OGDCL) in the block and as a result, effective 20 March 2017, MPCL became the operator of block with revised equity split as follows: MPCL (35%, operator), OGDCL (35%), TPDC (20%) and Saif Energy Ltd (10%). MPCL announced on 19 July 2017 that it signed the Head of Terms (HoT) agreement with Tullow Pakistan (Development) Ltd for acquiring Tullowâs entire working interests in three onshore blocks in Pakistan â Bannu West, Block 28 and Kalchas blocks. It was subsequently reported in early July 2018 that MPCL acquired Tullowâs full 20% working interest in the Bannu West EL with effective date as 7 June 2018 and the revised equity split was as follows: MPCL (55%, operator), OGDCL (35%) and Saif Energy Ltd (10%). MPCL acquired 105 line km 2D seismic (dynamite / vibroseis source) in the block using the Mari Seismic Unitâs âMSU-1â seismic crew. The survey was initiated in March 2018 with a plan of acquiring 99 line km 2D and it was completed in April 2018.","Saif Energy Ltd has assigned its full 10% interest in Bannu West 3370-13 EL (Potwar Basin) onshore concession to Zaver Petroleum Corporation Ltd (ZPCL) and the revised equity split was as follows: MPCL (55%, operator), OGDCL (35%) and Saif Energy Ltd (10%). "
26642,"The DNR has released a list of blocks in 3 areas - Harrison Bay (269 sq km), Gwydyr Bay (93 sq km) and the Storms area (124 sq km) - to be offered the Special Alaska Lease Sale Areas (or SALSA), which will happen concurrently with the regular North Slope lease sale in the autumn. The blocks are located S. of the Prudhoe Bay Field and W. of the Trans Alaska Pipeline System (TAPS). Terms and conditions will be made public in mid-Aug â18. See GEPS for full list.","The DNR has released a list of blocks in 3 areas - Harrison Bay (269 sq km), Gwydyr Bay (93 sq km) and the Storms area (124 sq km) - to be offered the Special Alaska Lease Sale Areas (or SALSA), which will happen concurrently with the regular North Slope lease sale in the autumn. The blocks are located S. of the Prudhoe Bay Field and W. of the Trans Alaska Pipeline System (TAPS)."
25437,"New Age is looking for a partner in the Foum Ognit Offshore permit, 7,969 sq km off W. Sahara in the Aaïun-Tarfaya offshore basin. New Age (op), partner Onhym.","Oil Search (->55%) has bought a 25% stake in the PPLs 474, 475 and 476 and PRL 39 from ExxonMobil (->45% op.)."
20527,"Siccar Point announced on 28 March 2018 that it has farmed down a 30% interest in licences P1028 and P1189 which contains the appraising Cambo field and also a 22.5% interest in the Blackrock prospect in licence P1830 to Shell UK Limited. The Cambo field is being appraised with well 204/10a-5, which spudded on 24 April 2018. Blackrock is planned to be drilled in 2019. It is understood that in return for the interest Shell will carry costs in relation to the aforementioned exploration and appraisal wells and also any potential development on Cambo. The deal was completed on 1 May 2018. Cambo was discovered in 2002 by Amerada Hess with well 204/10-2. Five wells in total have been drilled on the structure to date. The plan for the appraisal well is to undertake an Extended Well Test (EWT) on the field. Cambo has an Hildasay reservoir and the field is thought to hold approximately 600 MMbo in place. The plan for the potential development is that it will be developed in two phases. Phase one involves a leased FPSO with seven producing wells and two water injectors and the plan is to produce approximately 87 MMbo and also some associated gas. Phase two details have not been defined to date. FID for the field is scheduled for the first half of 2019. 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. Following completion of the deal interests in P1028 and P1189 are held by Siccar Point Energy (70% + operator) and Shell UK Limited (30%). Interest in P1830 is held by Siccar Point Energy (52.5% + operator), INEOS E&P UK Limited (25%) and Shell UK Limited (22.5%).","United Kingdom, P1189"
32781,"New Zealand Oil and Gas Ltd (NZOG) reported on 21 February 2018 its intention to hold full interest and operatorship in the PEP 55794 exploration permit, located in the Great South Basin, by acquiring joint venture partner Woodside Energy Ltd.âs 70% interest. On 25 June 2018 the participants submitted an application to New Zealand Petroleum and Minerals (NZP&M) for the transfer of interest which was subsequently approved on 18 October 2018. PEP 55794 had been outlined as open for farm-out by NZOG and is planned to be marketed alongside PEP 52717, located in the Canterbury Basin. NZOG reported that, after a drill decision extension was granted for PEP 52717, the timetable of the two permits coincides, making the marketing of a joint package feasible. PEP 55794 was awarded to the Woodside (70%) and NZOG (30%) joint venture in December 2013 after being applied for in the 2013 Blocks Offer. The joint venture acquired the Toroa 3D seismic survey in Q2 2015, acquiring a total of 1,169 sq. km. A contingent well is due between April 2020 and March 2021, with a drill/drop decision due by 31 March 2020. PEP 55794 covers an area of 9,835 sq km. NZOG 2013 O Ltd., a wholly owned subsidiary of NZOG, now holds 100% operated interest in the permit.","NZOG) reported on 21 February 2018 its intention to hold full interest and operatorship in the PEP 55794 exploration permit, located in the Great South Basin, by acquiring joint venture partner Woodside Energy Ltd.âs 70% interest. "
63487,"Kenli 6-1-6 (KL 6-1-6) and Kenli 6-1-6sa (KL 6-1-6Sa) were suspended, having intersected oil in the target reservoirs, on or around 16 August 2019 after having been spudded on or around 28 July 2019, using the ""Bohai 9 jack-up"". The oil and gas appraisal wells were likely to be targeting the Guantao, Dongying and Shahejie formations. Kenli 6-1-6/6Sa are in the CNOOC operated Bozhong Block in the offshore Bohai Gulf Basin. CNOOC had drilled up to 10 appraisal wells with average TD of 1,816m MD at the Kenli 6-1 discovery and had encountered oil and gas pay zones with total thickness of approximately 136m. CNOOC is expecting the Kenli 6-1 discovery to be a mid-size oil and gas field with estimated reserves of between 15.7-157 MMboe. ",Not Found
32828,The OGA intends to launch a mini-round in 1Q â19 for acreage around the Greater Buchan Area (formerly Repsolâs) for which the OGA is keen to see developed some 150 â 300 MMboe. Supporting information will be provided to those interested in participating. for the area to interested companies.,The OGA intends to launch a mini-round in 1Q â19 for acreage around the Greater Buchan Area (formerly Repsolâs) for which the OGA is keen to see developed some 150 â 300 MMboe. Supporting information will be provided to those interested in participating. for the area to interested companies.
40405,"An auction was held 15 Jan â19 for the Pukhutsyayakhskiy block, 825 sq km in the South Kara-Yamal Province, Yamal-Nenets AO. Gazprom Neft-Aero Bryansk submitted a USD 310,000 winning bid for the 8+17 year E&P licence. Starting price was USD 260,000.","Gazprom Neft-Aero Bryansk won Pukhutsyayakhskiy block (825km²) in the S.Kara-Yamal Province, Yamal-Nenets AO."
75106,"On 13 February 2020, Eni presumably abandoned the exploratory well Nigma 1 in the Northeast Hapy Offshore block, Levantine Deep Sub-basin (Levantine Basin). The well, which was spudded in late November 2019 was drilled by ADVantage, a joint venture between ADES and Vantage Drilling International. In early October 2019, the company confirmed the award of a deep-water drilling contract in the Egyptian Mediterranean area and indicated that it would provide the work via Vantage Drillingâs Tungsten Explorer. The contract was running for one firm well estimated to run for 73 days. Four other wells have been drilled in the Northeast Hapy Offshore block. Eni subsidiary IEOC made the Fahd 1 gas discovery in 2002. Gujarat drilled three wells in 2012: Hapy North 1 was dry while Hapy North 2 and 4 hit gas. Participants in the Northeast Hapy Offshore block are: IEOC, operator with 70% and Edison with 30%.",Egypt (Gulf of Suez B.) October
55102,"Crudos Pesados Oeste-5 (CPO-5), Llanos Basin, TD 3,044m, oil in the Une fm (8m net in the LS3, 9m in the LS2, 3.2m in the LS1 sands), tested 253 b/d of 38.9 oil from the LS3 on pump. Rig now en route to drill Ãndico-2 appr. ONGC Videsh (op), partner Amerisur.",Colombia (Llanos Sub-basin (Llanos-Barinas B.)) Sol 1
71792,"Total is reportedly looking to sell a 10% stake in round 16 block C-M-541, deepwater Campos pre-salt, to retain 30% + operatorship, partners Qatar Petroleum + Petronas. Drilling is said to be planned this year on the Nemo prospect at ab. 7,000m. Map below courtesy Total.","otal is reportedly looking to sell a 10% stake in round 16 block C-M-541, deepwater Campos pre-salt, to retain 30% + operatorship, partners Qatar Petroleum + Petronas."
45328,"PPL has assigned a 2.5% stake to GHPL (govt) in its 2,455-sq km Bela West 2566-6 EL (Bela-Muslimbagh-Zhob Ophiolite Belt, Balochistan). The move follows the Dec â18 farmout of 35% to Kirthar Pakistan. Partnership now PPL (op), KP, GHPL. Of note, Bela W.-1 nfw is currently drilling in the 2,455-sq km block.",Pakistan (Northern Potwar Deformed Zone (Potwar B.)) Bela
34169,"Mirpur Khas 2568-7 EL, Lower Indus onshore, TD 3,104m, testing underway of target Lower Goru, Hilong rig 16. UE (op), partners Bow Energy, Zaver + GHPL.","Gormani-1 nfw in Pakistan, Mirpur Khas 2568-7 EL Lower Indus onshore, TD 3,104m, testing underway of target Lower Goru, UE (op), partners Bow Energy, Zaver + GHPL."
29524,"Vegas Oil & Gas (Vegas) is offering a farm-in opportunity for a technical partner in its East Lagia block in the Sinai. Up to 35% interest will be available for the potential partner. The pro-rata funding costs of the operations undertaken by Vegas were budgeted at USD 4.3 million. Vegas plans to acquire 550 km of 2D seismic data over the block in November 2018. The company is waiting for the mining clearance of the selected areas in the block. This seismic programme budgeted at USD 3.9 million is in addition to the contractual work obligations and it is necessary to meet the mandatory 25% relinquishment under the PSA at the end of the exploration period. A Surface Geochemical Survey budgeted at USD 0.4 million is also planned during exploration operations. Vegas operates the block with a 100% interest.  The block is located east of the Petrosinaiâs development lease that includes the Lagia field. For contact: Either Vegas Oil & Gas Loukas Tripelopoulos Deputy CEO Phone number: +30 210 809 30 96 Email: info@Vegasoil.com Or Zebra Data Liam Whitehead Account Manager Phone Number: +44 173 222 0058 Email: liam.w@zebradata.com Background Information In early November 2012, Vegas Oil and Gas was awarded East Lagia (Block 11) exploration block in the 2011 EGPC bid round. The exploration phase of seven years includes three phases: First period of 2 years with a commitment to conduct an air gravity/magnetic survey. Second phase of three years with commitment to run a 500 km 2D survey Third period of 2 years with a commitment to drill one exploration well.","Egypt, Lagia (Dev)"
29710,"F18-C / F19-D1 / F19-D4 block (Banarli), Thrace Basin in NW Turkey, TD 4,196m, as of 12 Sep â18 testing gauged 2.53 MMcfg/d + cond on 20/64â choke, WHP 2,535 psi. Flow now stabilising at 1.4 MMcf/d but still cleaning up. Next well Inanli-1 is now preparing to spud, 1st of 3 apprâs planned, location 6km NE of Yamalik.","Yamalik-1 nfw in F18-C / F19-D1 / F19-D4 block (Banarli), Thrace Basin in NW Turkey, TD 4,196m, as of 12 Sep â18 testing gauged 2.53 MMcfg/d + cond on 20/64â choke, WHP 2,535 psi. Flow now stabilising at 1.4 MMcf/d but still cleaning up. Next well Inanli-1 is now preparing to spud, 1st of 3 apprâs planned, location 6km NE of Yamalik."
67924,"Ref. DEA 11 Nov '19, the 49% farmin by Petronas from Repsol in the Andaman III PSC was signed-up on 23 Dec '19. The 8,523-sq km permit lies off Aceh in shelf-deepwaters of the N. Sumatra Basin. A min. 50-day (dry) well is planned late 2020 in the deeper water sector, Rencong-1X, target likely Tampur fm gas. Repsol (op), partner Petronas.","The 49% farmin by Petronas from Repsol in the Andaman III PSC was signed-up on 23 Dec '19. The 8,523-sq km permit lies off Aceh in shelf-deepwaters of the N. Sumatra Basin."
55720,"Block 15/06, deepwater Congo Fan, WD 1,587m, drilled and P&A dry, Ocean Rig Poseidon DS. Targets possibly Miocene + Oligocene sst. Eni (op), partners Sonangol P&P + Sonangol Sinopec Intl 15.","Berimbau 1 (Eni 36,84% op. Sonangol 36,84%, SSI Fefteen 26,32%), within Block 15/06 is understood P&A as dry. Very little information is available on the well however, given its proximity to the Caxixi 1 well (thought to be a non-commercial discovery), one might assume that Berimbau 1 was targeting a similar prospect (potentially Miocene and Oligocene age sandstones on the flanks of a salt diaper or below a salt canopy). DW = 1587m."
39934,The table below outlines the Licensing Options awarded from the 2015 Atlantic Margin Licensing round which have now been converted to Frontier Exploration Licences. The list was last updated in January 2019. List of converted licences from 2015 Atlantic Margin Licensing Round Licensing Option Operator FEL Number LO16/01 Eni FEL12/18 LO16/03 ExxonMobil FEL05/18 LO16/04 ExxonMobil FEL06/18 LO16/05 Nexen FEL01/18 LO16/06 Nexen FEL02/18 LO16/07 Nexen FEL03/18 LO16/08 Nexen FEL04/18 LO16/10 Equinor FEL07/18 LO16/11 Equinor FEL08/18 LO16/12 Equinor FEL09/18 LO16/13 Equinor FEL10/18 LO16/14 Woodside FEL11/18 LO16/17 AzEire FEL01/19 LO16/27 Total FEL02/19,The table below outlines the Licensing Options awarded from the 2015 Atlantic Margin Licensing round which have now been converted to Frontier Exploration Licences. The list was last updated in January 2019. List of converted licences from 2015 Atlantic Margin Licensing Round Licensing Option Operator FEL Number LO16/01 Eni FEL12/18 LO16/03 ExxonMobil FEL05/18 LO16/04 ExxonMobil FEL06/18 LO16/05 Nexen FEL01/18 LO16/06 Nexen FEL02/18 LO16/07 Nexen FEL03/18 LO16/08 Nexen FEL04/18 LO16/10 Equinor FEL07/18 LO16/11 Equinor FEL08/18 LO16/12 Equinor FEL09/18 LO16/13 Equinor FEL10/18 LO16/14 Woodside FEL11/18 LO16/17 AzEire FEL01/19 LO16/27 Total FEL02/19
13284,"As of mid-January the PSA agreement by Shell for the 2,265 sq km onshore block 4 was under review by the authorities for approval. Â The long-awaited PSA was signed by the AKBN only recently. ","PSA agreement by Shell for the 2,265 sq km onshore block 4 was under review by the authorities for approval. "