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S. part of Waitsia field area, permit L1/L2, onshore Perth Basin, compl. Aug ’15 at TD 3,530m, cleanup and testing underway, gauged 38.7 MMcfg/d from the Kingia sst (3,173-3,215m) on 80/64” choke, WHP 1,315 psi for 2.1 hrs. Of note, pay is 30% of that encountered in Waitsia-3 (50 MMcf/d), underling the strong performance of each well. Further testing is planned, after which Waitsia-4 will be flowed. Map: AWE.

Australia (Perth B.) Waitsia 2 op. by AWE (50.0%, ORIGIN EN 50.0%) in L 01 block

Goshawk Energy Pty Ltd was awarded special prospecting authority permit SPA 31 AO, located in the Canning Basin, on 3 December 2018.  The permit has been awarded for a period of six months and will expire on 2 June 2019. The permit is valid for surface exploration and work commitments outlined during the six months include completing the Coastal Canning Survey. The SPA was applied for in October 2016, as STP-SPA-0072.  It is the fifth awarded to Goshawk in recent months with SPA 28 AO, SPA 29 AO, SPA 30 AO and SPA 32 AO awarded in early November 2018, covering a combined total area of 41,725 sq km, also within the Canning Basin. SPA 31 AO, which covers an area of 15,943 sq km, was awarded on 3 December 2018.  Goshawk Energy (Canning Basin) Pty Ltd holds 100% interest and operatorship of the permit.

Australia, SPA 32 AO

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.

Block 4495, Dist. X, SE Turkey Zagros Fold Belt, compl. oil (240 b/d) in Feb ’18. Target Bedinan fm. 

Turkey (Zagros Province) Caliktepe Guney 5 op. by CALIK (100.0%) in 4495 block compl. oil (240 b/d), Target Bedinan fm

NW part of AE-0053-3M-Mezcalapa-03 block, onshore Sureste Basin in Tabasco, discovery looking to be the largest onshore Sureste discovery since 1987, est. 3P reserves 500 MMboe (up from erstwhile 40 MMboe). Meanwhile Quesqui 1DEL appr is underway, last reported below 4,400m in late Nov '19. The 34-sq km field calls for 11 devt wells. Production hoped to reach 300 MMcfg/d + 69,000 bc/d in 2020, 410 MMcf/d + 110 Mbc/d in 2021.

Quesqui 1EXP (Pemex 100%) in NW part of AE-0053-2M-Mezcalapa-03 block, onshore in Tabasco, compl o&g, testing ab. 800 bo/d + gas from an HPHT reservoir. Targets Cret. (npw) + Jurassic (dpw). Initial tests produced 4,478 bc/d of 43.8° API and 16.67 MMcfg/d from the Late Jurassic Kimmeridgiano Fm. Discovery looking to be the largest onshore Sureste discovery since 1987, est. 3P reserves 500 MMboe (up from erstwhile 40 MMboe).

PNOC-EC has signed an MoU to for cooperation and joint studies with Ratio related to its fully-owned SC 76, which covers 4,160 sq km on the NE flank of the East Palawan Basin, WD 200-2,000m. Block originally offered as Area 4 in PECR V. Background from GEPS.

PNOC-EC and Ratio Petroleum signed a MOU to permit PNOC’s entry to SC 76.

Senex is looking to dilute its 100% in PEL 639,  627 sq km in the Cooper Basin, awarded 26 Apr ’18 for 5 years. Commitments 300 sq km 3D seismic + 2 wells in 1st year, more seismic + wells beyond. Contact: info@senexenergy.com.au.

Australia, PEL 639

Tarba has agreed to acquire Petroleum Oil & Gas España's 100% in the El Romeral-1, -2 & -3 prod leases totalling 310 sq km in Andalucía, Guadalquivir Basin. The USD 837,000 deal was signed Dec '19, to be retro-effective Jul '19 upon approval of the transfer by the authorities, still awaited. A further USD 279,000 will be due for each of the next 3 wells to be drilled. Tarba is owned by Warrego Egy + Prospex O&G.

Tarba has agreed to acquire Petroleum Oil & Gas España's 100% in the El Romeral-1, -2 & -3 prod. leases totalling 310 sq km in Andalucía.

LLA 34, Llanos Basin, successfully drilled + tested a zone to the SE, outside the 2018 3P reserve area. Tigui-12 appr in the NE part of the field is currently being tested.

Tigui-18 appr LLA 34, Llanos Basin, successfully drilled + tested a zone to the SE, outside the 2018 3P reserve area. Tigui-12 appr in the NE part of the field is currently being tested.

On 15 October 2019, Abu Dhabi National Oil Company (ADNOC) signed strategic collaboration framework agreements with PJSC Lukoil Oil Company (Lukoil), PJSC Gazprom Neft (Gazprom Neft), the sovereign Russian Direct Investment Fund (RDIF) and Federal State Budgetary Organization “Russian Energy Agency” of the Russian Federation (REA). Russian President Vladamir Vladimirovich Putin was welcomed by Crown Prince of Abu Dhabi and Deputy Supreme Commander of the Armed Forces of the United Arab Emirates (UAE) Sheikh Mohammed bin Zayed Al Nahyan and UAE Minister of State and ADNOC Group CEO Dr Sultan Ahmed Al Jaber during a formal state visit. PJSC Lukoil Oil Company (Lukoil) formalized a contract to acquire a 5% interest in the Ghasha sour gas project from ADNOC. The majority of other draft agreements are intended to explore new opportunities for collaboration across the oil and gas value chain. The 2019 Abu Dhabi Bid Round is scheduled to close during November 2019.

Lukoil acquired a 5% WI in the offsh. sour gas Ghasha Concession (ADNOC ->55% op, ENI 25%, Wintershall 10%, OMV 5%).

Ref. DEA 28 Jan '20: Rharb Centre block, C-E Morocco, TMD 1,210m, gas find in the U. & L. Guebbas fm, 'successfully tested' in Feb '20, est. 1.3-1.9 Bcf recoverable. SDX (op), partner Onhym.

Ouled Youssef-2 (OYF) nfw. Rharb Centre block, C-E Morocco, TMD 1,210m, gas find in the U. & L. Guebbas fm, 'successfully tested' in Feb '20, est. 1.3-1.9 Bcf recoverable. SDX (op), partner Onhym.

On 4 March 2020 Equinor completed a farm-in, into two UK licences – P2277 and P1891 taking a 50% interest from Total in both licences which contain the Finzean prospect. Total is planning to drill exploration well 12/30-2 on its Finzean prospect. The company is planning to use the Noble Sam Hartley rig for drilling operations. Finzean comprises of stacked turbidite sands from Lower Cretaceous to Upper Jurassic in age (Punt, Ettrick and Burns sands) and is thought to be large enough for a stand alone development with pre-drill resources estimated 290 MMboe. Finzean is located across licences P2277 and P1891 and is a pinch-out of two Lower Cretaceous turbidite Punt Sands (one locally and one regionally sourced) on the north-eastern flank of the West Bank High. The prospect is sealed by overlying Lower Cretaceous Valhall shales and laterally by faulting and stratigraphic pinch-out. There is underlying potential in the Jurassic (previously known as Ferrick and Ulysses) which comprise of pinch-outs of the Upper Jurassic Burns and Ettrick sandstones against the West Bank High. Ferrick and Ulysses are sealed by the surrounding Kimmeridge Clay and laterally by faulting and pinch-out. All reservoirs are sourced by the Kimmeridge Clay to the north of the West Halibut Basin. Interest in the licence is now held by Total E&P North Sea UK Limited (50% + operator) and Equinor UK limited (50%).

Equinor completed a farm-in, into two UK licences – P2277 and P1891 taking a 50% interest from Total in both licences which contain the Finzean prospect.

SK-315 off Central Luconia, Sarawak, targets Middle Miocene Cycle IV / V carbs, P&A results n/a 24 Dec ’17, West Telesto J/U. Petronas (op), partner Vestigo Petr.

Kayu Sugi 1 op. by Petronas (50%, Vestigo Petr. 50%) in SK-315 off. Sarawak, targets Middle Miocene Cycle IV / V carbs, P&A results n/a.

OKEA spudded its first operated exploratory well on 16 October 2019 using the newbuild “Deepsea Nordkapp” S/S. 6407/9-12 is located on the Skumnisse prospect but is classified by the NPD as a Draugen appraisal. The well is located in PL 093 D approximately 4 km east of Draugen and the company hoped that it would identify new volumes in the area which could have helped in extending the field’s life into the 2040s. The main target was the Upper Jurassic Rogn Formation, prognosed at 1,658 m. A 12-1/4" pilot hole was drilled to around 1,050 m and the 20 x 9-5/8" casing was set before the well was suspended (around 18 October 2019) whilst the rig was used for the company's Infill O well (see separate article). On 1 November 2019 Skumnisse was re-entered and the reservoir section was drilled and cored. TD was reached at 1,775 m in the Middle Jurassic Garn Formation. The Rogn Formation (45 m thick) had only thin, poor quality clay-rich sandstones (totalling 15 m) and the well was abandoned as a dry hole on 8 November 2019. OKEA gained its interest in PL 093 in late 2018 by way of a deal with previous operator Shell. The deal covered both Draugen and Gjoa (a 12% non-operated interest) and consisted of an initial consideration of USD 526 million (NOK 4.52 billion) with Shell retaining an 80% liability for the total decommissioning costs up to an agreed limit of USD 74 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 43 million (NOK 375 million) to OKEA. The deal increased OKEA’s net reserves to 53 MMboe. Draugen’s main reservoir is the Rogn Formation at around 1,600 m. It also produces from the Middle Jurassic Garn Formation. OKEA believes that there are a number of follow-up targets which it will investigate in the coming years. Interest in PL 093 D is divided between OKEA ASA (44.56% + operator), Petoro AS (47.88%) and Neptune E&P Norge AS (7.56%).

6407/09-12 (Skumnisse) appr. (Okea 44,56% op, Petoro 47,88%, Neptune 7,56%) in PL 093 D P&A dry at TD=1775m, Target Upper Jurassic Rogn Fm. Well confirmed the presence of a number of clay-rich sst. layers in the expected reservoir interval, but these were thinner and with poorer reservoir quality than expected, with no traces of hc observed.

On 12 December 2018 Solo Oil announced that it has entered into a Sale and Purchase Agreement to sell 30% interest in PEDL 331 on the Isle of Wight to UK Oil and Gas Plc (UKOG) for a total consideration of GBP 350,000. The acreage contains one oil discovery known as Arreton 2. The field was discovered in 1974 and UKOG has been intending to drill the Arreton-3 well as a vertical pilot and horizontal appraisal to delineate the field and two further targets – Arreton North and South. Following completion of the deal interest in the licence will be held by UK Oil and Gas Plc (95% + operator) and Doriemus Plc 5%.

United Kingdom (Portland-Wight Sub-basin (Wessex B.)) Arreton 2

On 27 March 2018, Pan American Energy with 100% working interest was granted a preliminary award for the 401 sq km Area 31, AS-CS-15 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 1 equivalent to one well. There were two other bids for the block.  The second highest bidder was the consortium of ENI and Lukoil who bid 42.35% state take and 1 additional work units factor.  

Pan American Energy with 100% working interest was granted a preliminary award for the 401 sq km Area 31, AS-CS-15 block from the CNH-RO3-LO1/2017 Bid Round.

Sidetrack of Samurai-2 in SE part of Green Canyon block 432, deviated into 476, confirms high-quality Miocene sands + resources found in original hole in 432 + in communication. Reserves have been upped from 75 MMboe pre-drill to 90 MMboe. Samurai-2 TD’d at 9,778m with 46m total oil pay. Deepwater Asgard DS. Murphy (op), partner BHP Billiton.

GC 432 002S1B0 (Samurai-2) (Murphy 50% op. BHP 50%) in G32504, had “confirmed the presence of high quality sands and resources”, “the sands encountered in the sidetrack are equivalent and hydrostatically connected” to the pay zone in the Samurai-2 well in contiguous Green Canyon block 432. Due to the positive outcome of the sidetrack, Murphy has increased the discovered resource at Samurai to 90 MMbbl of oil equivalent (MMboe) from its pre-drill estimate of 75 MMboe.

Lime Petroleum’s parent company Rex International announced on 2 October 2019 that its deal with Wintershall Dea to acquire 30% interests in both PL 838 and PL 838 B, reported initially on 21 June 2019, had received regulatory approval and was expected to complete on 31 October 2019. The licences cover parts of blocks 6507/3, 6507/5 and 6507/6. Operator PGNiG is drilling exploration well 6507/5-9 S on the Shrek prospect in PL 838 in October 2019 and is believed to have made a discovery (as it will drill an appraisal sidetrack). The objectives are the Jurassic Viking, Fangst and Bat groups and partner Aker BP reports prospective resources of 10-22 MMboe. 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 commercial discovery, could be tied back to the Skarv facilities. 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%).

Rex International Holding subsidiary Lime Petroleum acquired a 30% stake in two licences PL 838 and PL 838B from Dea (->0%, PGNiG op.40%, AkerBP 30%).

North Slope, both wells flow tested the Nanushuk reservoir: Mitquq ST: ADL 393876 (Pikka East block), N. Slope, ab. 10km SE of Pikka Nanushuk Pad A, TD 2,472m, 52.5m net pay, 9m gas cap, tested stable 1,730 bo/d from a single stimulated zone. Stirrup: ADL 392044 (Horseshoe block), TD 1,512m, 23m net pay, flowed stable 3,520 bo/d from a single stimulated zone. Doyon crew demobilising and expected off-location by mid-April. Oil Search (op), partner Repsol.

Mitquq-1 ST1, Stirrup-1 nfw's North Slope, both wells flow tested the Nanushuk reservoir: Mitquq ST: ADL 393876 (Pikka East block), N. Slope, ab. 10km SE of Pikka Nanushuk Pad A, TD 2,472m, 52.5m net pay, 9m gas cap, tested stable 1,730 bo/d from a single stimulated zone. Stirrup: ADL 392044 (Horseshoe block), TD 1,512m, 23m net pay, flowed stable 3,520 bo/d from a single stimulated zone. Doyon crew demobilising and expected off-location by mid-April. Oil Search (op), partner Repsol.

In January 2020, Taas-Yuryakh-Neftegazdobycha completed a unique well at the Srednebotuobinskoye field in Yakutia (Sakha) Republic (Eastern Siberia). Well Srednebotuobinskaya 2087 has 15 sidetracks and each of them has an additional sidetrack. The combined length of the well is 12,792 m including 10,310 m drilled within the targeted reservoir. The well is producing oil at a rate of 2,931 b/d. The company named the well's design as the "birch leaf". Srednebotuobinskoye, discovered in 1970, is located in the Nepa-Botuoba Basin. Combined recoverable 2P reserves of eleven pools, distributed within the Vendian-Lower Cambrian section, are estimated at 925 MMbbl of oil, 6.2 Tcf of gas and 27 MMbbl of condensate. Taas-Yuryakh-Neftegazdobycha is owned by Rosneft (50.1%), BP (20%) and Oil India Consortium (29.9%) comprised of Oil India, ONGC and Bharat Petroleum Corp. In January-November 2019, the company produced 78,550 b/d of oil from the field.

Taas-Yuryakh-Neftegazdobycha completed a unique well at the Srednebotuobinskoye field in Yakutia (Sakha) Republic (Eastern Siberia). Well Srednebotuobinskaya 2087 has 15 sidetracks and each of them has an additional sidetrack. The combined length of the well is 12,792 m including 10,310 m drilled within the targeted reservoir.

1st in 3-well programme on the Uer Terrace, PL 925, TD 3,370m  (S), 3,263m (A), plugging, Transocean Arctic SS. Target M. Jurassic Fensfjord fm. Wellesley (op), partner Concedo.

035/12-6S, 6A (Kallasen) (Wellesley Petr. 90%, Concedo ASA 10%) in PL 925, P&A, w.o. results.

Protech secured sole rights to the 492-sq km M45-C block in the Zagros Fold Belt, SE Turkey, on 17 Dec '19 for 5 years. The award follows the rejection of an application for the same area by TPAO.

Protech secured sole rights to the 492-sq km M45-C block in the Zagros Fold Belt, SE Turkey,

SW part of L29/50 block, onshore Khorat Plateau, seismically-defined prospect, P&A’d in “Tombstone” (!, most likely tight lst) at TD 4,018m in mid-Jul '20, Sinopec rig released.

(Khorat Plateau B.) Dan Khun Thot 1 op. by TPI POLENE (100%) in L29/50 block, seismically-defined prospect, P&A’d in “Tombstone” at TD 4,018m in mid-Jul '20,

In late-July 2020 Union Jack Oil acquired 3% interest in licence PEDL 253 from Montrose Industries. The licence, which is operated by Egdon Resources, covers 95 sq km over two blocks: TF/18a and TF/28a. Mapped within the licence is the Biscathorpe discovery and the South Elkington prospect. Three wells have been drilled in the licence, two of the wells drilled in 1987 and 1975 were dry. The Biscathorpe-2 well was drilled in early-2019 down to 2,133 m, targeting the Dinantian carbonates within the Biscathorpe four-way dip closure. Post-well analysis indicated that the well encountered a 35 m oil column of good quality oil within the Dinantian interval. A sidetrack from Biscathorpe-2 could be drilled in the future to test the Westphalian reservoir, which is interpreted to thicken to the north, and appraise underlying Dinantian carbonate. The licence is west of licence PEDL 339 that is also operated by Egdon Resources and it contains the producing Keddington field. Exploratory drilling is planned on licence PEDL 339 to target either the Keddington South prospect or the Louth prospect. Interest in the licence is held by Egdon Resources UK Ltd (35.8% + operator), Union Jack Oil plc (25%), Humber Oil & Gas Ltd (20%) and Montrose Industries Ltd (19.2%).

(Anglo-Dutch B.) Union Jack Oil acquires 3% in PEDL 253 license from Montrose Industries TF/28a op. by EGDON (36%)

EnQuest has agreed to acquire 40.8125% and operatorship from Equinor in Bressay heavy oil field licences P234 (3/28a), P493 (3/28b), P920 (3/27b) and P977 (9/2a & 9/3a), as released on 31 July 2020. Initial consideration is GB£ 2.2 million (US$ 2.86 million), to be payed as 50% of Equinor’s net share of costs from deal completion (expected Q4 2020) with a contingent consideration of US$ 15 million following Field Development Plan (FDP) government approval for Bressay. The contingent payment increases to US$ 30 million if EnQuest sole risks Equinor in the submission of the FDP. The development concept selection was deferred in 2016 due to challenging market conditions and the need to simplify the development concept. Extensions to licence expiry dates and commitments are condition precedents to completion. A development concept being considered is a tie back to Kraken heavy oil field (EnQuest Op, 12km NE). EnQuest will become operator on P&A of discovery well 3/28-1 (1976, Chevron, 1,527m, Tertiary reservoir). The field was later successfully appraised. Estimated gross STOIIP is 600-1,050 MMbo and 100-300 MMbo estimated gross recoverable. 50km S is the Equinor operated Mariner Field. Chrysaor entered the licence when it acquired a package of assets from Shell in 2017. Current field partners Equinor UK Ltd (81.625% + Op) and Chrysaor Ltd (18.375%).

(East Shetland Platform) EnQuest has agreed to acquire 40.8125% and operatorship from Equinor in Bressay heavy oil field licences P234 (3/28a), P493 (3/28b), P920 (3/27b) and P977 (9/2a & 9/3a). Current field partners Equinor UK Ltd (81.625% + Op) and Chrysaor Ltd (18.375%). After completion, new field partners will be EnQuest (40.8125%, op.), Equinor UK Ltd (40.8125%) and Chrysaor Ltd (18.375%).

On 10 January 2018 Wintershall spudded a well on the Balderbra prospect in PL 894 using the “West Phoenix” S/S. 6604/5-1 targeted a robust structural closure with an amplitude anomaly between the Gullris (6604/2-1) and Gro (6603/12-1) wells. The objective was the Upper Cretaceous Springar Sandstone, expected to be reached at three levels (3,380 m, 3,515 m and 3,632 m). The main risks for the prospect were related to reservoir effectiveness: facies development and retention due to faulting. The well was drilled to TD at 3,858 m before a technical sidetrack was kicked-off. This wellbore has a TD of 3,760 m. It is understood that the rig left location on 19 March 2018 and results are expected imminently. The Gullris well was drilled by BG in 2011 on the Gjallar Ridge to the north of Balderbra. Sandstone (21% porosity and 200 mD permeability) was encountered in the Springar Formation but it was water-wet. Shell’s 2009 Gro well made a gas discovery, proving a 16 m gas column in the Springar Formation with recoverable reserve estimates in the region of 350-3,500 Bcf. The find was appraised in 2010 and a 50 m gas column was confirmed in the Springar Formation but reservoir quality was poorer than expected. Due to the variation in reservoir quality and gas saturation between this well and the discovery well, reserves were expected to be in the lower part of the range given after the discovery well was drilled. The Gro licence was relinquished in 2011. Interest in PL 894 is held by Wintershall Norge AS (40% + operator), Statoil Petroleum AS (40%) and Petoro AS (20%).  

Norway, PL 894

CBM well in ATP 2043-P, Bowen-Surat Basin, susp at TD 1,073m around 23 Apr '20, target Walloon Coal measures encountered (22m net coal), DTS proved somewhat disappointing. Savanna 406 rig.

Australia (Bowen - Surat B.s) ? op. by GALILEE EN (100.0%) in ATP 2043-P block

The state company ONHYM has published a list of 30 open blocks located in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored: Morocco - Open blocks Block Name Location Area (sq km) Asilah Tanger-Tetouan 2,275 Boudenib Meknes-Tafilalet 27,634 Boujdour Offshore I North Atlantic Ocean 11,094 Boujdour Offshore II North Atlantic Ocean 17,475 Boujdour Offshore Shallow North Atlantic Ocean 7,861 Casablanca Offshore North Atlantic Ocean 3,038 Dakhla Atlantique North Atlantic Ocean 104,064 El Jadidad Offshore North Atlantic Ocean 6,666 El Kansera Rabat-Sale-Zemmour-Zaer 2,586 Foum Ognit Offshore North Atlantic Ocean 7,955 Gharb Offshore Nord North Atlantic Ocean 9,866 Gharb Offshore Sud North Atlantic Ocean 4,459 Hassi Berkane Taza-Al Hoceima-Taounate 5,124 Ifni Deep Offshore North Atlantic Ocean 14,120 Lemsid Laayoune-Boujdour-Sakia El Hamra 57,015 Loukos Offshore North Atlantic Ocean 1,879 Mazagan Offshore North Atlantic Ocean 11,134 Mir Left Offshore North Atlantic Ocean 3,465 Moulay Bouchta Taza-Al Hoceima-Taounate 4,229 Ouarzazate Souss-Massa-Draa 4,109 Ouezzane Tanger-Tetouan 4,342 Rabat Deep Offshore North Atlantic Ocean 9,382 Safi Deep Offshore North Atlantic Ocean 9,786 Safi Offshore Nord North Atlantic Ocean 6,250 Safi Offshore Sud North Atlantic Ocean 5,947 Sakia El Hamra Souss-Massa-Draa 14,650 Souss Souss-Massa-Draa 6,250 Tadla-Haouz Tadla-Azilal 21,935 Taounate Taza-Al Hoceima-Taounate 6,780 Zag Guelmim-Es Semara 65,448   The Mogader Offshore block is under negotiation. Interested parties may contact: Onhym, 34 Avenue Al Fadila, 10050 Rabat - Morocco - Tel 00 212 537 23 8000 - Fax: 00 212 537 28 16 34 & 00 212 537 28 16 26 - email: partenaire@onhym.com

The state company ONHYM has published a list of 30 open blocks located in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored: Morocco - Open blocks

On 26 October 2018 it was announced that Talon Petroleum Limited has farmed into licence P2396 (block 29/7b). The company has taken 10% in the licence from Corallian Energy Limited. The acreage contains the 29/7-1 (Curlew A) discovery made in 1977. Talon stated the Curlew-A contains an independently certified gross 2C (Contingent Resource) volume of 45 MMboe. The companies are looking to appraise Curlew-A in Q3 2019. The deal is subject to regulatory approval. 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. If a confirmed decision is made the companies will progress the licence the second phase for the drilling of the well. Following completion of the deal interest in the licence will be held by Corrallian Energy Limited (90% + operator) and Talon Petroleum Limited (10%).

United Kingdom, P2396

Chevron Australia Pty Ltd was awarded retention lease WA-88-R, located in the Exmouth Plateau, North Carnarvon Basin, on 19 March 2018.  The licence has been awarded for a period of five years and will expire, or be eligible for renewal, on 18 March 2023.  The licence is located in close proximity to the Keto 1 and Sappho discoveries, which were made in 2010.  Under the work commitments assigned to WA-88-R, Chevron will conduct seismic reprocessing, technical studies, subsurface and engineering studies to enable modelling of the geology and gas market and cost reviews. The area was previously covered by exploration permit WA-205-P, which has been reduced in size as a result of the award of WA-88-R. WA-88-R, which covers an area of 80 sq km, was awarded on 19 March 2018.  Chevron holds 100% interest and operatorship through subsidiaries Chevron Australia Pty Ltd (66.67% + Operator) and Chevron (TAPL) Pty Ltd (33.33%).

Chevron Australia Pty Ltd was awarded retention lease WA-88-R, located in the Exmouth Plateau, North Carnarvon Basin,

AziNor Catalyst announced on 14 June 2018 that a subsidiary of Cairn Energy has agreed to farm-in to licence P1763 (blocks 9/9d and 9/14a) taking a 25% interest. Cairn has also agreed to join AziNor for 50% of the sole risk drilling activity on Agar-Plantain. Furthermore, AziNor will retain operatorship for the proposed appraisal well and Cairn will have an option to take operatorship in the future. The deal completed on 7 August 2018. The initial appraisal wellbore will delineate the down dip section of the Agar discovery reservoir with a sidetrack targeted to test the Plantain prospect. The target depth is 1,675 m and combined mid-case resources of 60 MMboe with significant upside of 98 MMboe are estimated. The gross well cost is USD 9.2 million (dry hole) or USD 12.8 million (success case including Plantain sidetrack). Agar has a CoS of 58%. The rig contractor has been identified and a spud date slated for Q2 2018. The success case will take 37 days to drill. The Agar discovery is located in the Viking Graben east of Beryl field and west of the Alvheim hub. The Eocene Agar discovery was made in 2014 with well 9/14a-15A which encountered an 11 m oil-down-to in high quality Eocene Frigg Formation sands. The well was drilled by MPX which was primarily targeting the Upper Jurassic sands of the Aragon prospect. The Upper Jurassic sands were encountered in the well but was water bearing. The sands are trapped within a stratigraphic trap which was also proven by the discovery well with the reservoir package being mapped confidently on high quality 3D broadband seismic data. Through high quality seismic data and advanced quantitative interpretation techniques AziNor have significantly de-risked the Plantain prospect. If the operations are successful then development options could be tie backs to Beryl Bravo, Alvheim FPSO or a standalone FPSO. Following completion of the deal interest in P1763 is held by Apache Beryl Limited (50% + operator), Cairn subsidiary, Nautical Petroleum Limited (25%), AziNor Catalyst Limited (12.5%) and Faroe Petroleum (12.5%) – Faroe interest is pending deal completion.

AziNor Catalyst announced on 14 June 2018 that a subsidiary of Cairn Energy has agreed to farm-in to licence P1763 (blocks 9/9d and 9/14a) taking a 25% interest. Cairn has also agreed to join AziNor for 50% of the sole risk drilling activity on Agar-Plantain. Furthermore, AziNor will retain operatorship for the proposed appraisal well and Cairn will have an option to take operatorship in the future. The

Santos and KrisEnergy are seeking to farm-out up to equity in the SS-11 shallow water offshore block in Bay of Bengal. In early September 2018, Santos reported that the sale of its producing Asian assets, as part of a wider asset sale including SS-11, to Ophir Energy, had been completed. In late August 2018, Ophir Energy Plc announced that in a general meeting held on 20 August 2018, the acquisition of southeast Asian non-core assets from Santos for aggregated cash considerations of USD 205 million pre-working capital adjustments, was approved by its shareholders. However, the company also stated that transaction was conditional subject to this approval from shareholders but completion in respect to exploration assets, such as SS-11 block is also conditional upon, amongst other things, regulatory and certain consents, and respective pre-emption regimes. Ophir envisages a completion date for exploration assets to be in the first half of 2019. In early-August 2018, Ophir Energy Plc announced that the UK Listing Authority as of 3 August 2018 approved a class 1 circular in relation to the transaction of southeast Asian non-core Assets from Santos. It was announced in early May 2018 that Santos had entered into an agreement to sell a number of non-core Asian assets, including SS-11 in Bangladesh, to Ophir Energy Plc.  The deal remains subject to a number of approvals, but is expected to complete in 2H 2018. Santos and KrisEnergy each hold 45% stake in SS-11 block with Santos as the operator, with Bangladesh Exploration and Petroleum Exploration Company Ltd (BAPEX) holding a 10% carried interest. The Production Sharing Contract (PSC) for the award of SS-11 block was signed on 12 March 2014. The block, which covers 4,475 sq km area, was offered under the Bangladesh Offshore Bidding Round 2012, launched from 9 December 2012 to 29 July 2013 for shallow water blocks. On 21 August 2015, Santos had announced a strategic review with the aim of addressing the share price fall issue. The company is considering a range of options including asset sales, structured finance transactions, company restructurings, capital markets transactions and other strategic alternatives. It is understood that the company was looking for fast-track sale of its assets, including outside Bangladesh. Companies interested in this opportunity can contact: Chris Luxton Tel: +618 8116 7192 Email: chris.luxton@santos.com   Mike Whibley Email: mike.whibley@krisenergy.com   Background Information Santos-KrisEnergy JV has committed to drill one exploration well in SS-11 block, carry out 1,876 line km 2D and 300 sq km 3D seismic during the initial five year exploration period and is expected to spend around USD 32 million for this work. The JV will provide a bank guarantee of USD 15 million. The five year Phase I will be followed by a three year second exploration period. SS-11, originally reported to cover an area of 4.622 sq km, straddles the margins of the Bengal Basin and Rakhine Basin. Portion of the block was under Block 18 (Block 17 & 18 PSC) last operated by Okland International LDC. This PSC was awarded in 1997 and was relinquished in 2011. Companies who have farmed-in to the block were Tullow, Total and PTTEP.  No wells have been drilled within the SS-11 block boundaries. Within the vicinity of the block, BODC 2 and BODC 3 dry holes were drilled by Bengal Oil Development Corp. from 1976 to 1977.

Santos and KrisEnergy are seeking to farm-out up to equity in the SS-11 shallow water offshore block in Bay of Bengal. In early September 2018, Santos reported that the sale of its producing Asian assets, as part of a wider asset sale including SS-11, to Ophir Energy, had been completed.

On 5 May 2020 it was announced that Sonatrach signed a memorandum of understanding (MOU) on upstream with Russian company Lukoil. The MOU will set a frame in which further talks will be held to identify attractive projects in Algeria's hydrocarbon exploration and production. Lukoil has identified West Africa and the Gulf of Mexico as strategic regions where it intends to develop activities. The company sees little prospects for expanding its resource base in Russia. Lukoil is currently active in following African countries: Ghana, Cameroon, Republic of Congo and Nigeria. This comes three weeks after Sonatrach signed a similar agreement with fellow Russian company Zarubezhneft and Turkish company TPAO. Chevron and ExxonMobil also signed MOU's on upstream lately with Sonatrach who indicates that the revised hydrocarbon law introduced in December 2019 is attracting new companies to Algeria.

Sonatrach signed a MoU with Lukoil, to begin discussions regarding partnership and a possible upstream country entry for the Russian-firm.

Thrace Basin Natural Gas Corporation (TBNG), a subsidiary of Valeura Energy Inc., spudded the Karaevli 6 appraisal well in Block F19-D3-1, Thrace Basin, in the third quarter of 2017 as part of its 2017 drilling programme. The well was plugged and abandoned following unsuccessful testing after reaching a TD of 1,261 m. TBNG completed the Karaevli 1 new field wildcat as a gas producer in January 2008. The most recent well drilled at the field was the Karaevli 5 appraisal well which was completed as a gas producer in the Osmancik Sandstone Formation in April 2010 after reaching a TD of 1,313 m. The field had produced greater than 500 MMcf of gas by the end of 2014. On 24 February 2017, Valeura announced that it had completed the acquisition of TBNG from TransAtlantic Worldwide Ltd for USD 20.9 million (which includes USD 3.1 million held in escrow pending a final reconciliation). Through its subsidiaries, Valeura now owns 81.5% of the shallow rights on the TBNG JV lands. TBNG is partnered in the well by Pinnacle Turkey Inc 18.5% and another Valeura subsidiary - Corporate Resources BV 40%.  

Turkey (Thrace B.) Karaevli 6 op. by VALEURA (41.5%, VALEURA 40.0%, PINNACLE T 18.5%) in F19-D3-1 block

On 29 January 2018, the consortium of Petrobras operator with 50% working interest and ExxonMobil with 50% working interest were granted official awards by the ANP for the C-M-210, C-M-277, C-M-344, C-M-346, C-M-411, and C-M-413 blocks in the Campos Basin from the ANP Round 14.  The two partners dominated the ANP Round 14 with the most bids and the highest bids.

the consortium of Petrobras operator with 50% working interest and ExxonMobil with 50% working interest were granted official awards by the ANP for the C-M-210, C-M-277, C-M-344, C-M-346, C-M-411, and C-M-413 blocks in the Campos Basin from the ANP Round 14.

It was announced on 19 January 2020 that Turkiye Petrolleri A.O. (TPAO) has been awarded the N39-B onshore exploration licence (Western Arabian Province) on 9 January 2020 for a period of five-year. The licence, covering an area of 613 sq km, is located towards southeast of the country and TPAO will be 100% owner and operator of the licence. TPAO had filed the application on 13 May 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)

In December 2018, it was understood that Total was formally awarded a prospecting permit for an offshore block, assumed to be called Mostaganem. An agreement for the block was originally signed on 29 October 2018. The precise location of the licence is unclear, but it may lie adjacent to and include part of, the 20,814 sq km Offshore Mostaganem prospecting permit. The licence was originally awarded to Sonatrach in 2017, on a two-year term. Equity in the new Mostaganem block is understood to be split Total (25% +Op), Eni (25%) and Sonatrach (50%). An exploration well has already been slated (optimistically) for 2019, following a 3D seismic campaign.Algeria's offshore zone remains frontier acreage, with just four wells having been drilled. In 1974, the Arzew 1 (TD 1,034 sq km) and Alger 1 (TD 1,205m) shallow-water wells were drilled. Both were P&A dry. Following the DSDP 371 well in 1975 (3,353m TD), Total drilled the Habibas 1 (HBB 1) well in 1977 in 935m WD, close to the border with Morocco. It was P&A dry, after reaching 4,496m TD. Sonatrach has been planning to drill an offshore well for a number of years, but the price tag (~US$ 100 million) and lack of offshore experience has hampered efforts to-date. Until now, Sonatrach had operated two offshore prospecting permits, Offshore Bejaia & Offshore Mostaganem, with 100% equity. <P />

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On 7 August 2019 Oilex Ltd announced that it has entered into an agreement to acquire Holloman Energy Corporation’s subsidiary company Holloman Petroleum Pty Ltd. Holloman holds 48.5003% interest in two Cooper-Eromanga Basin permits: PEL 112 and PEL 444, alongside operator of the permits Terra Nova Energy. Both Terra Nova and Holloman had been looking to divest their interests in the permits. Oilex has also signed an agreement with joint venture partner Terra Nova, as reported on 14 August 2019. The agreement is for Oilex to acquire an additional 30.833% interest, with the option to increase to 51.4997%, which would result in 100% interest after 12-15 months. Oilex has agreed to acquire 100% interest in the Holloman subsidiary for the consideration of 40,416,917 ordinary Oilex Shares, plus AUD 24,250 payable upon completion. The structure values the deal at around AUD 1.2 million, based on AUD 0.03 per Oilex share. The deal is set to close on 30 September 2019. The permits are located in the Western Flank Fairway and Terra Nova reports that there are a number of Namur and Birkhead structural prospects within both permits. PEL 112 covers an area of 1,000 sq km and was awarded on 17 April 2003. Terra Nova has outlined the Milo, Libby and Drole structural prospects, which combined hold a potential 9 MMb oil in place. Milo is outlined as the primary target, with the largest potential resource and lowest risk. One exploration well is due in 2019. The well will likely target one of these prospects and be positioned from the 2012 Mulka 3D seismic survey, which is located in the north of the permit area. The Wolfman 1 well was drilled within the Mulka survey area in 2013. It targeted a dip closure in the Namur Sandstone at around 1,200 m depth but was dry at location. Secondary, deeper, targets of the Birkhead and Hutton formations were also dry. PEL 444 covers an area of 1,150 sq km and was also awarded on 13 April 2003. Terra Nova has identified the Maverick mid-Birkhead prospect which is considered as a key exploration target.  It has a potential 1.71 MMbo resource. The Crater and Moraine Namur prospects have also been outlined as potential targets. The prospects in PEL 444 have been identified from the merged Jasmin and Wingman seismic datasets, which Terra Nova has reported as providing high level mapping of the licence. Terra Nova considers there is potential for the Hoplite 1 oil play fairway to extend into PEL 444. One commitment well is due in 2021. The Baikal 1 well was drilled in 2015, located approximately 8 km west of Hoplite 1. The well targeted this the oil play within the mid-Birkhead channel sands but was dry at location. However, the channel sands, which were mapped from seismic, were encountered and now provides qualification to the current exploration model. PEL 112 and PEL 444 are held by Terra Nova Energy Australia Pty Ltd (a Claren Energy subsidiary - 51.5% + Operator) and Holloman Petroleum Pty Ltd (48.5%).  Upon completion of Oilex acquiring Holloman Petroleum Pty Ltd and interest held by Terra Nova, interests will become: Oilex Ltd (79.333%, with the option to increase to 100%) and Terra Nova (20.667%).       PEL 112 and PEL 444 are held by Terra Nova Energy Australia Pty Ltd (a Claren Energy subsidiary - 51.4997% + Operator) and Holloman Petroleum Pty Ltd (48.5003%).  Upon completion of Oilex acquiring Holloman Petroleum Pty Ltd plus the interest held by Terra Nova, Oilex Ltd will hold

Oilex had entered into an agreement with Perseville Investing and Terra Nova Energy to acquire up to a further 51,4997% interest in petroleum exploration licences 112 and 444.

ANP’s Round 15 was held 29 Mar ’18 as the most successful one in history, despite no offers received for any onshore blocks. A total of 22 of 47 blocks in the offshore Ceara, Campos, Potiguar, Sergipe-Alagoas and Santos basins (covering circa 16,400 sq km) were pre-awarded in the round, with bonus bids totalling USD 2.42 billion and an estimated USD 369.44 million in work commitments.  ExxonMobil and Petrobras were again the most active companies, with a strong presence from Wintershall and other usual players (Shell, BP). For a full list of winners, participants + blocks please refer to GEPS. Of note, a day before (28th), authorities ruled to have blocks S-M-534 and S-M-645 (Santos Basin) removed from the round due to the fact that structures identified therein are a continuation of the Saturno structure, with all now to be offered in an additional “5th Pre-salt Round” to be held sometimes this year (and not in the 4th Pre-salt Round in June as initially thought).

ANP’s Round 15 was held 29 Mar ’18 as the most successful one in history, despite no offers received for any onshore blocks. A total of 22 of 47 blocks in the offshore Ceara, Campos, Potiguar, Sergipe-Alagoas and Santos basins (covering circa 16,400 sq km) were pre-awarded in the round, with bonus bids totalling USD 2.42 billion and an estimated USD 369.44 million in work commitments.

Lime Petroleum’s parent company Rex International announced that Lime signed an agreement on 21 June 2019 to acquire Wintershall Dea’s 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 “Deepsea Nordkapp” 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 Petroleum’s parent company Rex International announced that Lime signed an agreement on 21 June 2019 to acquire Wintershall Dea’s 30% interest in PL 838 and PL 838 B.

Bridgeport Energy Ltd is looking to sell interests in its Cooper-Eromanga tenements, up to 60% available either through single or multiple farm-ins. Involved are PEL 641 (1,953 sq km), ATP 269-P (389 sq km), ATP 948-P (2,004 sq km) + ATP 2026-P (1,783 sq km) as well as the Bargie field licence PL 256 (15.4 sq km) in conjunction with the above neighbouring ATP 948-P. Applications ATP 2022-P (438 sq km), ATP 2023-P (434 sq km), and ATP 2024-P (421 sq km) are also available, pending the award of the rights.

Australia, PEL 641

On 14 October 2017, ARA Petroleum, a subsidiary of the Omani Zubair Corp, signed an Exploration & Production Sharing Agreement (EPSA) with the Omani Government for Block 31 (Suneinah North). The onshore block (8,526 sq km) is located in northern Oman, around 200km SW of Muscat. <P />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. <P />Block 31 is largely unexplored, with only five wells having been drilled within the block boundaries. So far there are no discoveries, however oil and/or gas shows have been reported in several wells. The last well, Wadi Jiffra A1, was drilled by RAK Petroleum in 2011. It reached a TD of 3,250m and is believed to have encountered gas shows. It is understood that tight gas is the predominant play within the block and that there are currently four mapped prospects.<P />ARA Petroleum operates the acreage with a 100% interest.

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On 19 January 2018 Reliance Industries Ltd (RIL), in its Q3 FY17-18 report, announced that the Government of India (GoI) has approved the transfer of participating interest of Niko Resources Ltd (10%) in gas Block NEC-OSN-97/2 (NEC-25), located in the Bengal Basin to BP Exploration and Production Inc and RIL.        Reliance Industries is operator of the licence NEC-OSN-97/2, with 60% interest, with BP holding 30% and Niko Resources the remaining 10%. Once Niko’s withdrawal and transfer of the interest is complete, Reliance Industries will hold around 66% and BP 34%.     In early May 2017 it was reported that RIL and BP had agreed to acquire Niko Resources’ 10% interest in NEC-OSN-97/2 (NEC-25) block. Subsequently, it was reported that the companies have submitted an application for the transfer of interests to government of India, and were awaiting approval.     It was previously reported that Niko intended to withdraw from the block in July 2015.    

Niko Res farmed out his 10% stake in NEC-OSN-97/2 (Dirhubai 9,10,32,40, disc.) to Reliance Op (à 66%, BP 34%).

China’s Sinopec has decided to sell its oil assets in Argentina for $500 million to $600 million to Mexican company Vista Oil & Gas, a source with knowledge of the deal told Reuters on Tuesday. The price would be far less than the $2.45 billion that Sinopec paid in 2010 to buy the Argentine assets from U.S.-based Occidental Petroleum Corp. The assets are located mainly in the southern province of Santa Cruz. Click here for full Reuters article Source: Reuters

Argentina, not found

Tharwa Petroleum has completed its East Abu Sennan A 1X (EAS A 1X) NFW, as a Late Cretaceous oil discovery. The deviated well encountered oil in the objective Middle Abu Roash "G" sandstones. It has been tied into production, at an initial rate of 248 bo/d. EAS A 1X was drilled on the East Abu Sennan PSC, located in an under-explored part of the Abu Gharadig Basin. The well was spudded on 9 September 2017. It reached a TD of 2,316m in the Lower Cretaceous Kharita Formation in October 2017. Operations were carried out using the Tanmia Petroleum "Tanmia 1" rig. The discovery lies on trend with the Abrar Field to the south and the West Qarun Field in the north. Tharwa operates East Abu Sennan with 100% equity.<P />

East Abu Sennan A 1X (EAS A 1X)op. by Tharwa a Late Cretaceous oil discovery. The deviated well encountered oil in the objective Middle Abu Roash "G" sandstones. It has been tied into production, at an initial rate of 248 bo/d.

Total has bagged 2 new deepwater E&P contracts, namely C15 + C31, total 14,175 sq km. Total (op), partner SMHPM 10%. Elsewhere, Total plans drilling in C9 in 2019. Map below courtesy Total.

Mauritania, not found

According to local reports in August 2018, Zeus Ol has taken over operatorship of the Cerro Cabrera block in mid-year after Teuco Mining SA lost the rights on the block due to unfulfilled commitments in April 2018. State company Petropar originally had first priority to take over the Prospection Permit block but declined on the opportunity. Cerro Cabrera covers 4,869 sq km of land in the Chaco Basin. Zeus Ol is already the operator on the adjacent Boqueron Concession Law Contract block. There is one well drilled in the block, Cerro Leon 1, which was drilled in 1977. The well was P&A’d with minor gas shows in the same year. Background Information The MOPC officially granted a Prospection Permit to Teuco Mining for the Cerro Cabrera block in August 2016. The block was previously held for many years by Aurora Petroleos SA who had to relinquish the block in 2014.

According to local reports in August 2018, Zeus Ol has taken over operatorship of the Cerro Cabrera block in mid-year after Teuco Mining SA lost the rights on the block due to unfulfilled commitments in April 2018.

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

In mid-October 2017 KMG International sold its participation in the IV-5 Satu Mare licence to Serinus which became wholly owner of the licence. The permit is situated in northwestern Romania, and contains more than 25 prospects. Serinus reported in September 2017 having received from NAMR (National Agency for Mineral Resources) the drilling permits for two appraisal wells – Moftinu 1003 and Mofitnu 1004 - at the Moftinu field. The company plans to drill the wells in Q2 2018 fulfilling 2/3rd of the work commitments. Serinus will then decide whether to drill a third well or conduct a 3D seismic survey to comply with the work commitments. This drilling programme is part of the ongoing field development project. The Moftinu 1 gas discovery was drilled in 1971. In 2012 Winstar drilled the Moftinu 1000 exploration well which targeted various Pliocene gas zones with a planned total depth of 1,550 m. Open-hole logs also showed a 2 m gross gas-saturated zone in Miocene sands and production testing conducted in Miocene and Pliocene sands below 600 m yielded 1,600 Mcfg/d (aggregated). In 2014 Winstar drilled the Moftinu 1001 exploration well in the northern part of the structure and penetrated the entire Miocene and Pliocene sandstone section although it didn’t reach the planned total depth due to technical difficulties. Production testing was carried out over three Miocene to Pliocene sands intervals with an aggregate net pay of 26 m recovering up to 7,400 Mcfg/d and 18 b/d of condensate. Also in 2014 the company drilled the Moftinu 1002bis exploration well but the tests indicated a tight and damaged formation. The flow reached approximately 2,800 Mcfg/d for 30 minutes, and then it declined to 245 Mcfg/d over the following two hours. Despite the poor data quality, the well proved the existence of movable hydrocarbons in the four Miocene sands tested.   Interest in the permit is wholly held by Serinus Energy Romania SA.  

KMG International sold its participation in the E IV-05 Satu Mare licence to Serinus (->100%).

Kina Petroleum Ltd is offering an opportunity for a farm-in partner to acquire equity in its wholly owned exploration licence PPL 340, located in the onshore Papuan Basin. Kina first opened the offer in 2013, estimating approximately 35% interest would be available. Now that aeromagnetic and gravity survey data (acquired in 2013/14) has been processed and interpreted, farm-in conditions and equity level will be assessed prior to pushing the opportunity further to potential farminees. In March 2017 the licence was renewed for a further five years and it will now expire, or be eligible for further renewal, on 31 March 2022.  Kina is planning to undertake gravity/gradiometry surveying and seismic acquisition in the first four years of validity, before a possible well between March 2021 and March 2022. Kina is also eager to test soil gas techniques within the permit. Kina completed an aeromagnetic and gravity survey in 2013/14 which covered approximately 5,400 km to provide more information on the mid-Miocene reef units present within the licence. It will be used to plan a new 2D seismic survey which a farm-in partner will fund prior to the planning of drilling any identified prospects. In a previous farm in offer with Hunt Energy in 2013, Hunt agreed to fund a work programme, including an aeromagnetic and gravity survey and 2D seismic acquisition, based on the results of the aeromagnetic survey. On November 2013 Kina reported that the farm-out agreement had been terminated prior to seismic acquisition and the option to drill an exploration well for Hunt to acquire additional interest. Since the termination of the agreement, Kina has removed the commitment to drill an exploration well within the current licence validity period. Kina has reported that the first exploration well would likely test the Port Moresby Prospect once newly acquired seismic data further defines the prospect. The Port Moresby Prospect lies in the south-west of the permit and is a platform carbonate shelf target which has been identified as an aerogravity high.  If hydrocarbons are present, it is estimated that prospective resources could be in the region of 660 Bcf gas (best estimate). The licence also contains the Lizard Prospect, located in the northwest, with a shallow target at approximately 650 m depth within the Upper Miocene. Kina understands that the Plio-Pliocene uplift and tilting caused regional drainage to the east, into Lizard. The prospect will require additional seismic which is scheduled for 2017. PPL 340 covers an area of 4,320 sq km across five blocks and was awarded in 2010.  Kina Petroleum Ltd currently holds 100% interest and operatorship of the licence. A five year licence extension has been submitted which was approved in early 2017. Companies interested in pursuing this opportunity should contact: Richard Schroder – Kina MD Email: richard.schroder@kinapetroleum.com

Kina Petroleum Ltd is offering an opportunity for a farm-in partner to acquire equity in its wholly owned exploration licence PPL 340, located in the onshore Papuan Basin. Kina first opened the offer in 2013, estimating approximately 35% interest would be available.

RCMA Australia Pty Ltd will be looking to farm-down additional areas of production licence L14, located in the Perth Basin, upon completing seismic reprocessing over the area. In September 2019 a deal was reached with Metgasco to farm-out 60% interest over the Cervantes oil prospect. The deal contains the option for a second area should Metgasco decide by 31 March 2020. RCMA also reported in September that it is now preparing to offer an additional three locations to farm-down once 2D and 3D seismic data reprocessing is complete. Reprocessing is expected to be completed in November 2019. Under the Metgasco deal, RCMA will be funded 100% for well costs in return for 60% interest in any discovery. Metgasco is looking to farm-down around 30% of its acquired interest in return for 50% funding of its well costs. At this stage, the main objective will be the Cervantes oil prospect - a tilted fault block with targets in the Dongara, Kingia and High Cliff Sandstone. L 14 contains the Jingemia oil field, which was discovered in November 2002. RCMA is also considering a partner to fund a share of production costs or investment in the Jingemia field production.  Under the investment case, an agreement around buying into the business would be considered. The field produced from July 2004 to 2012 before being shut-in after previous operator Origin saw production fall at the field as recovery factors decreased. RCMA, through LEAP Energy, has reviewed the geology and circumstances relating to the causes of reduced production and believes improved oil recovery is possible along with attic oil remaining. Production restarted in December 2017 and is currently at around 330 bo/d from four wells with the assistance of jet pumps. Around 4.5 MMbo has been produced up to end 2018.    Under the exploration case, RCMA outlines an option for a three well farm-in which would cost an entry partner around AUD 14 million.  The target farm-in was for a four-well programme before securing Metgasco as a partner. RCMA has reported that it will consider other possibilities, such as an investment partner. RCMA currently holds 93.72% interest and operatorship of L 14 with Norwest Energy NL holding the remaining 6.28%. A sale and purchase agreement is pending relevant authority approvals for RCMA to acquire Norwest’s interest, which is expected to be completed in Q4 2019. A number of prospects and leads are outlined within the L14 block, which could be targeted for additional resources within the area.  The prospects outlined, lie in the north of the permit, are the Black Glove, Agile, Agile West and Tammar structures, with a total potential 20 MMb oil in place, with 9.5 MMb recoverable. Plenty of analogous fields lay within neighbouring licences including Dongara, Waitsia and Cliff Head. Stacked opportunities in the Dongara, Wagina, Irwin Coal Measures, Kingia Formation and High Cliff Formation are considered, which increases the geological chance of success for each prospect. The commercial chance of success is greatly improved for any new discovery by the proximity of existing infrastructure, including the Jingemia facility which is capable of processing up to 250,000 bbl liquids per day and is currently operational. The Dampier to Bunbury Natural Gas Pipeline is also located 12 km to the east of L14 to provide an efficient route to market in a gas case. Leads in the south of the permit are considered large structures by RCMA which could fit a gas case. But, the migration pathways are not well defined at this stage. Further seismic would be required to understand the opportunities further. RCMA contracted LEAP Energy to independently review the licence, and prospects and leads within, and produce a competent persons report on the prospective resources.  Interested parties are required to complete a non-disclosure agreement, in order to access LEAP Energy’s dataroom for the licence. L14 covers an area of 45 sq km and was awarded on 21 June 2004.  RCMA is expected to increase its holding to 100%, before farming out interest to Metgasco. Parties interested in pursuing this opportunity are asked to contact: Chris Newport, RCMA Energy – email: chris.newport@rcma.com     tel: +61 467 456 043

RCMA Australia Pty Ltd will be looking to farm-down additional areas of production licence L14, located in the Perth Basin, upon completing seismic reprocessing over the area.

On 11 August 2020, Petrobras indicated it has extended the deadline for companies to express interest in the Tayrona Contract, in the Guajira Basin and South Caribbean Deformed Belt. Petrobras announced the opportunity on 27 July 2020. Interested companies must submit the customary manifestation of interest by 21 August 2020, instead of 12 August 2020, to cc-tayrona_exp@petrobras.com.br. Petrobras is operator of the Tayrona Contract with 40% working interest and partners are Ecopetrol, with 30% working interest, Repsol with 20% and Equinor with the remaining 10%. A change in ownership with Petrobras holding 44.44% working interest and Ecopetrol the remaining 55.56% working interest is pending Agencia Nacional de Hidrocarburos (ANH) approvals. The Tayrona Contract includes three blocks: a 4,781.69 sq km western block (Tayrona A), a 5,283.88-central block (Tayrona B) and a 250.81 western block (Tayrona C). However, Petrobras is excluding part of the Tayrona B block, the part that corresponds to the discovery evaluation plan of the Orca well. Petrobras indicated that the concession has a firm commitment of one well and a deadline for the Posterior Exploratory Program 1 (PEP1) of 20 February 2022.

(Lower Guajira B.) Tayrona (A) operated by PETROBRAS (40%), partners ECOPETROL (30%), REPSOL (20%), EQUINOR (10%), Petrobras indicated it has extended the deadline for companies to express interest in the Tayrona Contract to 21 August 2020, instead of 12 August 2020.

On 9 November 2017, Tullow Oil plc (Tullow) reported that it plugged and abandoned the exploration well Ekales-3 with oil shows in Block 13T. End September 2017, the well reached a TD of 2,721 m. The well tested an undrilled structure east of the Ekales field in Block 13T. The next well to be drilled is the appraisal well Ngamia 11. The well will be completed and use in an extended water flood pilot test in conjunction with the Early Oil Pilot Scheme (EOPS). The second well will test the Etete structure, south of the Etom field. Tullow is evaluating further well location to be added to the drilling programme. The Block13T is operated by Tullow (50%) in partnership with Africa Oil (25%) and Maersk Oil and Gas (25%).

Kenya (East African Rift System, Eastern Branch) Ngamia 11 op. by TULLOW (50.0%, MAERSK 25.0%, AFRICA OIL 25.0%) in Block 10BB

On 14 June 2018, the Ministry for Natural Resources published a list of exploratory licenses available for investors without auctions. The list includes seven blocks covering 5,694 sq km in Nenets Autonomous Okrug (Timan-Pechora Basin). Total hydrocarbon resources are estimated at 687 MMbbl of oil and 24 Bcf of gas (Table 1). Applications have to be submitted by 25 July 2018. If any block receives more than one valid application, the block will be withdrawn from the list and could be offered through an auction. Table 1       Resources   Petroleum Province Political Block Surface, Oil, Gas, Contact Information Province sq km MMbbl Bcf Timan-Pechora Nenets AO Verkhne-Novoborskiy 751 100 199155, Sankt-Petersburg, Odoyevskogo Str., 24/1   Lembeyskiy 722 43 24     Novoborskiy Severnyy 1,038 110     Tabyagskiy 1,075 149     Chernovskiy 361 91     Syarnayuskiy 535 48       Yambotysskiy 1,212 146

On 14 June 2018, the Ministry for Natural Resources published a list of exploratory licenses available for investors without auctions. The list includes seven blocks covering 5,694 sq km in Nenets Autonomous Okrug (Timan-Pechora Basin).

PTTEP plugged and abandoned a new-field wildcat, SBP-B02 (BB) (Sarabop-B02 (BB)), in the S1 Reserved Area, onshore Phitsanulok Basin, on 29 June 2020, as a dry well. Spudded on 15 June 2020, the well was batch drilled with the SBP-B01 (BA) well which was cased and suspended on 14 June 2020. SBP-B02 (BB) was drilled to a total depth (TD) of 3,875 m, likely targeting sandstone reservoirs of the Lan Krabu Formation. The SBP-B01 (BA) well was spudded on 9 May 2020 and drilled to a TD of 4,460 m, using the “50151HD” land rig. The new-field wildcat was plugged and abandoned as a dry well on 30 June 2020. 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 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. Shell drilled the Sarabop A-1 wildcat on 21 May 1984. The well was plugged and abandoned at a TD of 4,950 m with oil shows. It is the deepest well drilled in the country. The S1 Reserved Area consists a total of 33 fields, including the Sirikit Complex which is under improved recovery regime. The field contributes the largest onshore crude oil production in the country. 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.

Thailand (Phitsanulok B.), Sarabop-B02 (BB) new-field wildcat, operated by PTTEP (100%) in S1 Reserved Area block, P&A, dry.

West Kalabsha block, N. Egypt Basin, P&A results n/a at TD 4,892m in June, EDC rig 54. Main targets AEB 1, 2 3A, 3C, 3G, 5 + 6. Apache (op), partner Sinopec.

West Kalabsha block, N. Egypt Basin, P&A results n/a at TD 4,892m in June, EDC rig 54. Main targets AEB 1, 2 3A, 3C, 3G, 5 + 6. Apache (op), partner Sinopec.

PEL 494, Otway Basin, susp. gas on 5 Nov '19 at TMD 3,384m (DEA 15 Oct '19), Ensign rig 932 released, testing planned Dec '19. Beach (op), partner Cooper.

Dombey 1 (Beach 70% op, Cooper 30%) in PEL 494, , susp. gas at TMD=3384m, testing planned Dec '19.

On 12 December 2017, YPF disclosed that it would carry out a long-term testing program to try and establish commercial production on four potential discovery wells on the San Sebastian Block in the Magallanes Basin. YPF has filed a petition with Chile's Environmental Assessment Service (SEA) for the testing of the wells known as Carpintero, Cisne Sur, Cisne Oeste and Gaviota Sur. The tests have been approved by the agency and are expected to last from one to two months for each of the wells. It is estimated that if the four discoveries are placed on production that they could produce up to 2327 bo/d with 8.5 MMcfg/d in associated gas also. This would be the case if the tests are positive and YPF moves forward with production plans, a scenario which according to the most recent YPF studies is plausible. The contract began on 4 January 2013 when YPF farmed in to the block for a 40% share and Wintershall farmed in for 10% while Chilean national oil company, ENAP held the remaining 50%. It is a special oil exploration contract (CEOP) used when foreign companies acquire license equity and explore for hydrocarbons in Chile. YPF and Wintershall by the terms of the farmin were required to supply 100% of the investment in the first exploration period of the contract. In December 2015, the contract moved to the second period of exploration and Wintershall and ENAP decided not to move to that period, so YPF continued with the contract at 100%. The second period commitment for YPF included the drilling of one exploration well on the block and the completion of two previous wells drilled in 2015. Between December 2014 and early 2017, eight wells were drilled in the San Sebastian Block and four of these had significant oil shows. In the event that crude oil is produced in the extended testing, it will be transported to ENAP facilities in Cullen where a storage space has been allocated. <P />

Chile, San Sebastian

Ref. DEA 11 Jun '19, PGNiG has completed the acquisition of Total’s 22.2% in PL 146 + 333, sum undisclosed. Acreage totals 87 sq km in the Feda Graben, and contains the King Lear, Julius, Romeo + Espen discoveries. Partnership now Aker BP (op), partner PGNiG.

PGNiG has completed the acquisition of Total’s 22.2% in PL 146 + 333, sum undisclosed. Acreage totals 87 sq km in the Feda Graben, and contains the King Lear, Julius, Romeo + Espen discoveries. Partnership now Aker BP (op), partner PGNiG.

Total strengthens its presence in the DW GoM by signing to acquire Samson Offshore Anchor, LLC, holder of a 12.5% interest in the 4 blocks* covering the Anchor discovery. The deal also includes a 12.5% interest in the nearby exploration block Green Canyon 761, boosting Total’s stake here to 37.5%. Anchor lies in WD >1,500m. Chevron (op), partners Cobalt + Venari. * Green Canyon blocks 806, 807, 850 + 851:  

Total acquired Samson Offshore Anchor, holder of a 12.5% interest in the 4 blocks* covering the Anchor discovery. The deal also includes a 12.5% interest in the nearby exploration block Green Canyon 761, boosting Total’s stake here to 37.5%. Anchor lies in WD >1,500m. Chevron (op) 55%, Cobalt 20% + Venari 12,5%. * Green Canyon blocks 806, 807, 850 + 851:

It was reported on 6 February 2020 that Amity Oil International Pty Ltd has transferred its full 50% participating interest in E19-D4-1 production lease to Petrogas Petrol Gaz ve Petrokimya Ürünleri Ins. San. ve Tic. A.S. on 28 January 2020. As a result of this transaction the revised equity split for E19-D4-1 lease is as follows: Turkiye Petrolleri A.O. (TPAO) 50% (operator) and Petrogas 50%. Amity Oil and Petrogas, both are the subsidiaries of TransAtlantic Petroleum. Amity Oil had submitted the application to the government on 16 September 2019 for the approval of this transaction. The licence, located towards northwest of the country in Thrace Basin, covers an area of 16.2 sq km and it was awarded to TPAO on 12 October 2017 for four-year term.

Amity transferred its 50% interest in 3 contracts to Petrogas Petrol. TPAO continues as optr with 50%, partner Petrogas. Of note, Amity and Petrogas are both subsidiaries of TransAtlantic Petroleum. Involved are: E18-C3-2 (28km²), E19-D4-1 (16,2km²) and F19-A1-1 (106km²).

Pursuant to the award of ATP 2050-P, 1,425 sq km in the Denison Trough, Bowen-Surat Basin, on 19 Dec '19, the permit became effective 1 Feb '20 and runs 6 years. Galilee applied for the unit as block PLR2019-1-1 under the QLD release on 30 Oct '19.

Galilee Energy (100%), was awarded exploration permit ATP 2050-P.

In early December 2019, Khalda Petroleum Co (Khalda) abandoned the new field wildcat Cadmium 1 in its Atoun (Dev) block, Northern Egypt Basin after unsuccessful test. Khalda spudded the well on 13 October 2019, presumably targeting the Lower Cretaceous Alamein Member of the Burg El Arab Formation and the units 1 and 6 of the Alam El Bueib Formation. The well had a planned TD of 4,420 m. The Atoun (Dev) block is a 41 sq km acreage granted to Khalda in June 2004 which includes the Atoun and Nakhaw gas fields and the Fox Deep 1 oil discovery. Khalda is a JV between EGPC (50%), Apache (33.5%) and Sinopec (16.5%).

Cadmium 1 nfw (Khalda 100% = JV between EGPC 50%, Apache 33.5%, Sinopec 16.5%) in Atoun (Dev) block, P&A after unsuccessful test presumably of the target Alamein Mb of the Burg El Arab + Alam El Bueib 1 + 6 units.

Crown Point reports the recent acquisition of the Pluspetrol shares of its former Apco stake representing 25.78% of the Rio Cullen, Angostura and Rio Cullen licenses in the Tierra del Fuego portion of the Austral Basin. Crown Point now holds a 51.56% share of these contracts. Roch will continue as operator with 20.28% interest. San Enrique will still keep 12.62%, DPG 11.54% and Secra 4% in all three blocks. Local company, Liminar Energia, a subsidiary of the Grupo ST, has recently acquired 51% of the shares of Crown Point Energy. Crown has recently requested a contract extension to 2026 for the Angostura and Rio Cullen licenses.

Argentina, Angostura

CB-ONN-2005/10 block, onshore Cambay Basin, TD 3,500m, o+g discovery, tested 283 bo/d + 148 Mcfg/d on 5mm choke from 2,834-2,836m (Object-I) in the GS-3 sand within the Eocene Hazad fm.

ANOR 1 (ANOR-A) op. by ONGC (51%, GSPCL 49%) in CB-ONN-2005/10 block onshore, o+g discovery, tested 283 bo/d + 148 Mcfg/d [5mm choke] from 2834-2836m (Object-I) in the GS-3 sand within the Eocene Hazad fm.

In May 2018 Overgas was still offering the opportunity for interested parties to farm-in to licences Provadia and 1-18 Trakiya. The Provadia licence is located in the eastern part of the country while the 1-18 Trakiya licence is situated in southern Bulgaria. The company started looking for partners in May 2016. Between 2011 and 2014 Overgas conducted two 2D seismic surveys and one 3D seismic survey totaling respectively 812 km and 55 sq km in the Provadia licence. No fields are situated within the permit area. The last known drilling activity consists of Krivnya 12 which was drilled to a total depth of 2,769 m in the Lower Triassic and abandoned as a dry hole in 1984. In the 1-18 Trakiya licence, the company drilled the Trakiya 1 exploration between 2014 and 2015. The hole reached a total depth of 1,717 m bottoming in metamorphic rocks without reaching the targeted Jurassic sediments. It was subsequently re-entered for testing and recovered only gas shows. In late 2012 Overgas conducted a 474 km 2D seismic survey in the permit. For further information please contact: Nikola Sechkariov Tel - +359 882 173 062 nikola_sechkariov@overgas.bg

Overgas was still offering the opportunity for interested parties to farm-in to licences Provadia and 1-18 Trakiya. The Provadia licence is located in the eastern part of the country while the 1-18 Trakiya licence is situated in southern Bulgaria.

Lukoil has reportedly joined the bandwagon of parties interested in the farmout of Exxon's XIX Neptun Est licence. Although Romgaz has already been talking over a 15-20% farmin, Lukoil is said to be negotiating for 50% in the 7,916-sq km unit. The block contains the Domino and Pelican South gas fields. Neptun is divided into XIX Neptun Est and XIX Neptun Vest (1,727 sq km), the latter apparently not part of the talks. Exxon (op), partner OMV Petrom.

Lukoil has reportedly joined the bandwagon of parties interested in the farmout of Exxon's XIX Neptun Est licence. Although Romgaz has already been talking over a 15-20% farmin, Lukoil is said to be negotiating for 50% in the 7,916-sq km unit. The block contains the Domino and Pelican South gas fields. Neptun is divided into XIX Neptun Est and XIX Neptun Vest (1,727 sq km), the latter apparently not part of the talks. Exxon (op), partner OMV Petrom.

Egdon Resources has announced an exclusivity agreement with an unidentified company to farm-into 100% operated adjacent Southern North Sea licences P1929 and P2304, on 4 November 2019. The company has exclusivity until 19 January 2020 and if executed completion is expected by 19 April 2020. P1929 and P2304 are due to expire in November 2019, pending OGA approval for an extension. P2304 covers block 41/24 (167 sq km), located immediately offshore from Scarborough in North Yorkshire. It was awarded in the 28th Round on 1 December 2015. It contains the Endeavour gas discovery made in fractured Permian Zechstein Plattendolomit by 41/24a-1 (1969, Elf, 1,816m). P1929 covers blocks 41/18a and 41/19a (204 sq km) and was awarded in the 26th Seaward Licensing Round on 1 February 2012. It contains the 41/18-01 (1966, Total, 2,067m) Resolution gas discovery has estimated mean Contingent Gas Resources of 231 Bcfg in Zechstein reservoir. Egdon acquired the 50% interests from Arenite Petroleum and Europa Oil & Gas in P2304 on 24 July 2018. P1929 and P2304 is currently 100% Egdon Resources UK Ltd (100%).

United Kingdom, P2304

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.    

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.

PL 894 / blocks 6604/5 + 6, 6605/4, 5 + 7, Norwegian Sea, WD 1,220m, P&A’ing at TD 3,760m, West Phoenix SS. Wintershall (op), partners Statoil + Petoro.

6604/05-01 (Balderbrå) op. by Wintershall (40%, Statoil 40%, Petoro 20%) in PL 894 block, P&A, results n/a.

Orlen secured sole rights to the 1,159-sq km 2/2020/L Debrzno – Czluchów contract SW of Gdansk in the Danish-Polish Marginal Trough, N. Poland, in Feb '20. The award is the result of the country’s 2018 tender call (round 2).

ORLEN was awarded the 1/2020/L Koszalin – Polanów (1111km²) and 2/2020/L Dębrzno – Człuchów contract SW of Gdansk in the Danish-Polish Marginal Trough.

NW part of AE-0053-3M-Mezcalapa-03 block, onshore Sureste Basin in Tabasco, discovery looking to be the largest onshore Sureste discovery since 1987, est. 3P reserves 500 MMboe (up from erstwhile 40 MMboe). Meanwhile Quesqui 1DEL appr is underway, last reported below 4,400m in late Nov '19. The 34-sq km field calls for 11 devt wells. Production hoped to reach 300 MMcfg/d + 69,000 bc/d in 2020, 410 MMcf/d + 110 Mbc/d in 2021.

Quesqui 1EXP (Pemex 100%) in NW part of AE-0053-2M-Mezcalapa-03 block, onshore in Tabasco, compl o&g, testing ab. 800 bo/d + gas from an HPHT reservoir. Targets Cret. (npw) + Jurassic (dpw). Initial tests produced 4,478 bc/d of 43.8° API and 16.67 MMcfg/d from the Late Jurassic Kimmeridgiano Fm. Discovery looking to be the largest onshore Sureste discovery since 1987, est. 3P reserves 500 MMboe (up from erstwhile 40 MMboe).

It was reported in early July 2018 that Mari Petroleum Company Ltd (MPCL) has acquired Tullow’s full 20% working interest in the Bannu West 3370-13 EL (Potwar Basin) onshore block with effect from 7 June 2018. MPCL is already the operator of this licence and the revised equity spilt is as follows: MPCL (55%, operator) and OGDCL (35%) and Saif Energy Ltd (10%). The licence covers an area of 1,230 sq km and is located in the FATA administrative region of the country. MPCL had announced on 19 July 2017 that it signed the Head of Terms (HoT) agreement with Tullow Pakistan (Development) Ltd for acquiring Tullow’s entire working interests in three onshore blocks in Pakistan – Bannu West, Block 28 and Kalchas blocks. MPCL recently acquired 105 line km 2D seismic (dynamite / vibroseis source) in the block using the Mari Seismic Unit’s “MSU-1” 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. The company also plans 3D seismic acquisition in the block using the same seismic crew.   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 Oil’s 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%).

Mari Petroleum Company Ltd (MPCL) has acquired Tullow’s full 20% working interest in the Bannu West 3370-13 EL (Potwar Basin) onshore block

Horiz well in Burhaan West field area, drilled 18 – late Jan ’18, TD 2,027m, no details.

Bout-2 appr Horiz well in Burhaan West field area, drilled 18 – late Jan ’18, TD 2,027m, no details.

EGPC has signed a USD 1 bn E&P agreement with Shell and partner Petronas relating to drilling in the Burullus-operated West Delta Deep Marine block (4,900 sq km). Eight explo wells are planned. Burullus = Shell-Petronas-EGPC. A similar, USD 10 MM deal was signed with Rockhopper, Kuwait Energy and Dover Corp for the Abu Sennan block (715 sq km, Abu Gharadiq Basin, W. Desert) leading to the drilling of 4 wells.

EGPC has signed a USD 1 bn E&P agreement with Shell and partner Petronas relating to drilling in the Burullus-operated West Delta Deep Marine block (4,900 sq km). Eight explo wells are planned. Burullus = Shell-Petronas-EGPC. A similar, USD 10 MM deal was signed with Rockhopper, Kuwait Energy and Dover Corp for the Abu Sennan block (715 sq km, Abu Gharadiq Basin, W. Desert) leading to the drilling of 4 wells.

Santos Ltd plugged and abandoned the Dorado 3 appraisal well in WA-437-P, located in the Roebuck Basin, in mid-Ocotber 2019, with the “Noble Tom Prosser” J/U leaving the wellsite on 17 October. The well had been drilled to a total depth of 4,643 m. Dorado 3 was the second appraisal at the Dorado discovery and was spudded, in a water depth of 90 m, on 28 July 2019 Testing was undertaken on the well at total depth. On 8 October 2019 the operator reported that the second flow test, over the Caley interval, had been completed, with successful results. The test was conducted over the 3,999 – 4,015 m interval, over an 11 m net Caley section, with flows of approximately 11.1 Mbo/d and 21 MMcfg/d observed (the maximum possible). As with the initial Baxter unit test, flows were constrained by surface equipment. The flows from the Caley indicate that production rates of up to 30 Mbo/d per well could be achieved. With both flow tests completed, the operator plans to evaluate the potential of non-constrained production tests. Testing of the Caley unit was undertaken after successful completion of testing the Baxter reservoir. Santos reported on 23 September 2019 that flow testing of the Baxter gas and condensate reservoir produced excellent results. Santos reported that Baxter flow testing has confirmed high productivity and fluid quality from the reservoir. The testing was first reported to be successful by venture partner Carnarvon Petroleum on 19 September 2019. Over a 12-hour period, a maximum flow rate of 48 MMcf/d was achieved, along with 4,500 bbl/d of associated condensate through a 60/64" choke. Testing was conducted across the reservoir section between 4,136 and 4,156 m. Preliminary interpretation of the well test indicates improved condensate gas ratio which could result in higher well deliverability upon production according to Santos. Prior to preparing for flow testing, in early September 2019, the operator undertook wireline logging, having reached a total depth of 4,643 m. Initial results from the wireline logging confirmed the presence of hydrocarbons within the Dorado reservoirs at this location, in the Caley, Baxter and Crespin units. Within the Caley reservoir, around 53 m net oil pay was observed, with a porosity of around 16%. Within the Baxter Member, around 9 m net pay was encountered, with 12% porosity and no water. The pressure data indicated connection with the Dorado 1 and 2 wells. The Crespin unit was not expected to be hydrocarbon bearing, but a hydrocarbon column of around 5 m was encountered, with average porosities of around 9%. Wireline logging has indicated no hydrocarbons within the Milne Member at this location, though a 60 m core was extracted from the Milne reservoir unit in early September.. Initial cores, of 175 m, were acquired from the well across the Caley and Baxter reservoirs. This was lower than original plans, which were to see 230 m of core, with Carnarvon reporting that the non-reservoir sections were drilled, rather than cored. Logging while drilling was undertaken across the cored sections, which have indicated porosity and permeability across the reservoirs, with indications of hydrocarbons. The wireline logging at total depth will provide more results on the reservoirs intersected. The Dorado 3 well was further appraising the Dorado discovery, which was made in August 2018. The Dorado 1 well made one of the largest oil discoveries on the northwest shelf. Oil was encountered in the primary target Caley Member, which forms the objective for the Dorado appraisal wells. Carnarvon reported that an “excellent reservoir” unit had been encountered within the Caley target, with 79.6 m net pay over a 96.1 m gross interval. 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 was also recovered to surface as part of the logging and evaluation programme, estimated at 49.6º API. In the discovery well, additional oil pay was encountered within the Crespin and Milne members. Light oil was recovered from both the Crespin and Milne units during evaluation. Net pay of 22 m, across a 50 m gross interval, was confirmed in the Crespin and 18 m net pay within a 30 m gross interval within the Milne Member. Average porosities of 14% and 13% were observed respectively. Dorado 2, the first appraisal well in the programme was spudded in early May 2019. Wireline logging results confirmed the pre-drill oil resource of the field and could provide a significant gas resource increase thanks to large hydrocarbon columns encountered in the Baxter and Milne reservoirs. At Dorado 2, within the primary target Caley Formation, 85 m of net reservoir was encountered. The Main Caley level presents an oil-water contact at 4,003 m, with 40 m of net oil pay. Overlying this, in the Upper Caley sands, Santos expects an additional 11 m of net oil pay, determined from early wellsite analysis. A further 32 m of net pay was encountered across the Baxter and Milne sandstone intervals which is currently interpreted to be gas bearing. The Dorado 2 and 3 wells were drilled to evaluate the extent of the Dorado resources, to assist in development planning. Better resource estimates will be made upon the conclusion of drilling. Oil will be the key target, with the joint venture reporting that development of oil would be a lower cost and quicker return, which could then lead to a wider field development including gas and condensate. If development is deemed suitable after appraisal drilling, Final Investment Decision (FID) is hoped to be reached in 2020. Dorado could be developed alongside the Roc discovery, which lies to the north and was discovered in 2016. WA-437-P, which covers an area of 4,871 sq km, was awarded on 4 August 2009. Participants in the permit are: Santos WA Northwest Pty Ltd (80% plus operatorship) and Carnarvon Petroleum Ltd (20%).

Santos Ltd plugged and abandoned the Dorado 3 appraisal well in WA-437-P, located in the Roebuck Basin,The test was conducted over the 3,999 – 4,015 m interval, over an 11 m net Caley section, with flows of approximately 11.1 Mbo/d and 21 MMcfg/d observed (the maximum possible).

The Norwegian Petroleum Directorate (NPD) has announced that Spirit Energy Norge, operator of production licence PL 682, is in the process of completing the drilling of wildcat wells 35/9-13 and 35/9-14 and appraisal well 35/9-14 A on the Måløy slope in the North Sea. The wells were drilled about 6 kms northwest of the Gjøa field, 19 kms northeast of the 35/9-7 Nova oil discovery and 66 kms west of Florø.The objective of well 35/9-13 was to prove petroleum in Upper Jurassic reservoir rocks (Intra Heather formation sandstones), to investigate the presence and quality of the reservoir rocks and to conduct extensive data acquisition in the event of a discovery. The objective of well 35/9-14 A was to delineate the discovery.Well 35/9-13 was temporarily plugged and abandoned due to technical problems. 35/9-14 was drilled 35 metres southeast of 35/9-13, with the same exploration target.Well 35/9-14 encountered an oil column of about 20 metres in the Intra Heather formation, of which 10 metres comprise the reservoir which is composed of sandstones with poor reservoir properties. The oil/water contact was not encountered.Well 35/9-14 A encountered about 30 metres of aquiferous Intra Heather formation sandstones with traces of hydrocarbons and with poor reservoir properties. The well is classified as dry.Preliminary estimates place the size of the discovery between 0.3 – 1 million standard cubic metres (Sm3) of recoverable oil. Preliminary assessments indicate that the discovery is not currently profitable. The licensees will evaluate the discovery together with other nearby prospects as regards further follow-up.The wells were not formation-tested, but extensive data acquisition and sampling have been conducted.Wells 35/9-13, 35/9-14 and 35/9-14 A were drilled to respective vertical depths of 3191, 3625 and 3707 metres, and respective measured depths of 3223, 3657 and 3900 metres below the sea surface. 35/9-13 was terminated in the Rødby formation in the Lower Cretaceous, while 35/9-14 and 35/9-14 A were both terminated in the Heather formation in the Middle Jurassic. Water depth in the area is 365 metres. The wells will now be permanently plugged and abandoned.The wells were drilled by the Songa Enabler drilling facility, which will now proceed to Kristiansund for maintenance, and then on to well operations on the Snorre field for Statoil.Click here for JV partner Cairn Energy's announcement: Tethys UpdateOriginal article linkSource: NPD

035/09-14 (Thetys) op. by Spirit (30%, Cairn Energy 30%, Wellesley 20%, Petoro 20%) in PL 682, encountered an oil column of about 20m in the Intra Heather fm. (Upper Jurassic). Of that, about 10m comprised the reservoir, which is composed of sandstones with poor reservoir properties, the oil/water contact was not encountered. P&A. 14A encountered about 30m of aquiferous Intra Heather formation sandstones with traces of hydrocarbons and with poor reservoir properties. P&A, dry.

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 – 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 latter’s offshore blocks 2, 3, 9 + 8 has also been approved. Kogas already partners Eni in blocks 2, 3 + 9.

An OVL-led group will team up with ADNOC with a 10% stake in the offshore Lower Zakum concession-to-be, the 1st Indian involvement in the Emirates. The group comprises OVL, Indian Oil Corp + Bharat Petro Resources. Signature bonus was USD 600 MM. The Concession will have a 40-year term to be effective 9 Mar ’18. ADNOC is still seeking to offload a further 30% in the 400,000 bo/d concession.

An OVL-led group will team up with ADNOC with a 10% stake in the offshore Lower Zakum concession-to-be, the 1st Indian involvement in the Emirates. The group comprises OVL, Indian Oil Corp + Bharat Petro Resources.

An auction was held 10 Dec '19 for the 1,720-sq km Punskiy block in the Krasnoyarsk Kray, E. Siberia. Irkutsk Oil Co. (INK) won the 27-year rights. Starting price was USD 175,000.

Irkutsk Oil Co. (INK) won the 1,720-sq km Punskiy block in the Krasnoyarsk Kray.

Bayerngas will be withdrawing from upstream activities onshore Germany and is selling its Reudnitz holdings SE of Berlin in Brandenburg to newly-formed domestic co. Genexco. Involved are 100% in the Reudnitz, Reudnitz Nordost and Reudnitz Südost blocks, total 554 sq km, the transfer of which is expected to be concluded late 2017.

Bayerngas will be withdrawing from upstream activities onshore Germany and is selling its Reudnitz holdings SE of Berlin in Brandenburg to Genexco. Involved are 100% in the Reudnitz, Reudnitz Nordost and Reudnitz Südost blocks, total 554km².

BP, Socar and Uzbekneftegaz have signed a JSA fo a joint assessment upstream opportunities in the Ustyurt region, namely the Samsk-Kosbulak (ex-CNODC) and XI Bayterek (ex-Tethys Petr.) blocks and an unnamed tract (X?) in the Aral Sea, North Ustyurt Basin. This follows on various earlier agreements to this intent going back to 1H ’18.

BP, Socar and Uzbekneftegaz have signed a JSA for a joint assessment of upstream opportunities in the, namely the Samsk-Kosbulak (ex-CNODC) and XI Bayterek (ex-Tethys Petr.) blocks and an unnamed tract (X?) in the Aral Sea, North Ustyurt Basin.

SEAL-T-198 block, believed P&A dry 20 Jun ’18, no show reports filed. PTD was 1,640m, is target Barra de Itiuba + Serraria fm’s.

1-JUCA-001-AL (1-BRSA-1361-AL) (Petrobras 100%) in SEAL-T-198 block, believed P&A dry.

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 in the More Basin, effective 30 Jun '20. Lundin (op, 60%), partner Dval. The area is currently subject to TGS's Atlantic Margin 20 MC3D survey.

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.

Eneco Energy (formerly Ramba Energy) announced the completion of a previously agreed farm-in deal with Mandala Energy in the Lemang PSC, located in onshore South Sumatra, in July 2019, whereby Mandala acquired an additional 6% participating interest in the block. The deal received approval from SKK Migas on 10 June 2019. Pursuant to this transaction, rightholders in the Lemang PSC are Mandala Energy (90%, operator) and Hexindo Gemilang Jaya (a majority-owned subsidiary of Eneco) (10%). Mandala exercised the option to acquire the additional 6% interest on 1 October 2018. The option was part of the original farm-out deal signed in September 2017, by which Mandala initially acquired a 15% interest from Hexindo. It is understood that Mandala also acquired a 34% interest from previous partner Eastwin Energy in late 2018. Mandala took over operations in the block from Hexindo in May 2017. The block contains the Akatara field, which came onstream in November 2016. As of late 2018, the field was producing over 1,000 bo/d. The operator is planning to conduct further development activities, such as artificial lift, to increase production to 2,000 bo/d. Likewise, negotiations are ongoing to commercialize gas from the field, targeting a supply of 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. Akatara field development First oil production from the Akatara field in the Lemang PSC was achieved on 16 November 2016. The milestone was reached following to 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 plans 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 is 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 is also planned to be built, in order to connect the block directly with the Plaju refinery. The block is 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.

Indonesia Mandala Energy Ltd, Ramba Energy Ltd Lemang PSC - Additional 6% farm-in by Mandala, completed

Bridgeport Energy Ltd is looking to divest its interests within the Cooper-Eromanga and Bowen-Surat Basins with single or multiple farm-in options and negotiable farm-out interest, up to 60% equity. The offer includes multiple permits across both basins.  The farm-in opportunities provide access to multiple reservoirs, play types and mapped prospects. Regional 2D seismic and 3D seismic surveys and exploration wells are planned as part of minimum work commitments. Bridgeport will allow early participants the option to influence the exploration programmes. Included in the opportunity are Queensland permits ATP 948-P, ATP 269-P, ATP 608-P, ATP 805-P and ATP 2026-P as well as Queensland application ATP 2022-P. Also included is South Australia permit PEL 641.  The licences combined cover an area of almost 7,000 sq km. The application for PELA 641 was made on 27 August 2014 by Bridgeport, and was subsequently awarded on 9 February 2018.  Bridgeport holds 100% interest in the application. The licence covers 1,953 sq km across the western oil flank of the Cooper-Eromanga Basins, which Bridgeport report as being virtually unexplored. Bridgeport plans 2D and 3D seismic across the area before assessing potential prospects. Bridgeport holds 100% interest in ATP 608-P, ATP 805-P and ATP 948-P, which contain the Rookwood South and Dongara 3 oil fields. Bridgeport completed a 3D seismic survey over the Bonga-Binneanna structures in 2015 to tie-in the fields and assess drilling opportunities in the structure flanks. From seismic interpretations and the Donga well test results, Bridgeport applied for a Petroleum Lease over ATP 805-P, which includes the Madison Lead. ATP 269-P covers an area of 389 sq km and was awarded in January 1980.  Bridgeport holds 80.545% in the licence, with joint venture partners Beach Energy, Entek Energy and Santos Ltd.  The licence is split into a number of blocks, after being reduced upon renewal a number of times. ATP 2026-P was awarded in August 2017 and covers an area of 1,783 sq km. The CBM permit was applied for on 30 March 2017 via Queensland’s open door policy. The ATP 2026-P area has largely been subject to conventional exploration with four unsuccessful wells drilled since 1980. The most recent well, Obelix 1, was drilled in June 2017 by Bridgeport Energy (Eromanga) Pty Ltd in ATP 794-P.  Both permits cover areas previously covered by ATP 794-P prior to its area reduction on 11 August 2017.  ATP 2026-P is operated by Senex, via wholly owned subsidiary Victoria Oil Exploration (1977) Pty Ltd, with 60% interest, with Bridgeport Energy (QLD) Pty Ltd holding the remaining 40%. Finally, application ATP 2022-P was made in January 2017 and covers an area of 438 sq km. The application has been accepted and is awaiting final award by the Queensland Government.  Bridgeport holds 100% interest. Companies interested in pursuing these opportunities should contact: Barry Smith, Business Development Manager Phone: +61 2 8960 8400 Email: bsmith@bridgeport.net.au   Moyes and Co is also being contracted to market the opportunity so further contact is available through: Ian Cross Tel: +65 9776 0753 Email: icross@moyesco.com

Bridgeport Energy Ltd is looking to divest its interests within the Cooper-Eromanga and Bowen-Surat Basins with single or multiple farm-in options and negotiable farm-out interest, up to 60% equity. The offer includes multiple permits across both basins.

Q10-A field area, drilled 26 Mar - 8 Apr ’19, o&g well, Prospector 1 JU. Tulip (op) partner EBN.

Q10-A3ST1 appr Q10-A field area, drilled 26 Mar - 8 Apr ’19, o&g well, Prospector 1 JU. Tulip (op) partner EBN.

PPL assigned a 32% interest to Mari Petr. in the Shah Bandar 2467-16 EL, 2,083 sq km in the Indus Basin onshore, Sindh, retro-effective 20 Jun ‘17. PPL (op), partners Mari + and Sindh Energy Holding Co.

PPL had assigned a 32% working interest in the Shah Bandar 2467-16 EL onshore concession to Mari Petr.Company.

Magnolia announces an agreement to acquire much of the South Texan assets of Harvest O&G for ab. USD 135 MM cash + 4.2 MM newly-issued shares (USD 56 MM). The deal is expected to close 31 Aug ’18 and be retro-effective 1 Jul ’18. Involved are Karnes County assets + the Giddings field, total 4,800 boe/d. www.magnoliaoilgas.com.

Newly-formed player Magnolia Oil & Gas Corporation has acquired multiple assets from Harvest Oil & Gas in an almost US$200 MM. deal.

The 177th OPEC and 7th OPEC – OPEC+ meeting concluded Friday with the formal decision to add 0.5 MMb/d to the group's cuts, total adjustments to be 1.7 MMb/d as of 1 Jan '20. Some contributors, notably Saudi Arabia, will continue additional voluntary contributions, leading to pledged total cuts of over 2.1 MMb/d. The next (18th) joint monitoring meeting will be held in early March in Vienna, the OPEC and non-OPEC meeting on 6 March. OPEC forecasts global economic growth in 2020 at 3%, and oil demand is expected to grow by 1.1 MMb/d.

(Ostergotland Lower Paleozoic B.) BY 1

Six blocks in W. Siberia and one in the Yakutia (Sakha) Republic (E. Siberia) totalling 6,247 sq km are planned to be sold off auctionless, applications by 12 Aug '20. Should any block receive multiple valid applications, it will be auctioned:

Russia, six blocks in W. Siberia and one in the Yakutia (Sakha) Republic (E. Siberia) totalling 6,247 sq km are planned to be sold off auctionless, applications by 12 Aug '20.

On 16 August 2018 Falcon Oil and Gas reported that it and farm-in partner Origin Energy Ltd had signed an agreement to mark Stage 1 of Origin’s farm-in to Falcon’s Beetaloo Basin assets as complete.  The signing was an amendment to the original agreement, reducing the work commitments planned under stage 1. The joint venture has drilled three vertical wells and fracture stimulated one horizontal well as part of the stage one programme. One further horizonal well was planned to be included in stage one, but the joint venture has determined that it is more beneficial to move onto phase two of the farm-in.  Therefore stage one has been signed as complete, though remains subject to government approval. The farm-in is seeing Origin acquiring 70% interest in three exploration permits within the Beetaloo Sub-basin: EP 117, EP 76 and EP 98. The farm-in is being conducted over three stages, with stage one complete as announced on 16 August 2018. The farm-in agreement was entered into in 2014, at which time both Origin and Sasol Petroleum were to acquire interest. However in May 2017 Sasol announced it would withdraw from the farm-in, and Origin took its share of the deal.   The first phase well results were better than anticipated and drilling and fracture stimulation of Amungee Northwest 1 was brought forward in the programme, being originally planned for after all the vertical holes that had been drilled. The full programme is to consist of nine exploration and appraisal wells. In phase two further wells will be drilled and stimulated. The budget has been increased by AUD 15 million, after the removal of the additional well in phase one, and will now be completed at a capped cost of AUD 65 million.  Any of the additional AUD 15 million not utilized, will be rolled over to phase 3. In phase 2, planned for 2019, an additional vertical well will be drilled as well as drilling and stimulation of two horizontal wells.  Preparation is ongoing as of August 2018. Once stage 2 is complete, drilling locations targeting the most prospective play will be outlined for stage 3. Origin has estimated total contingent resources within the permits of 6.6 Tcf gas. The Beetaloo Basin Project covers a total of 18,618 sq km through permits EP 117, EP 76 and EP 98 which are scheduled to expire on 29 April 2019.  Origin now holds 70% interest and operates the project. Falcon Oil & Gas Australia Pty Ltd holds the remaining 30%.

On 16 August 2018 Falcon Oil and Gas reported that it and farm-in partner Origin Energy Ltd had signed an agreement to mark Stage 1 of Origin’s farm-in to Falcon’s Beetaloo Basin assets as complete.

PTTEP has plugged and abandoned wildcat Pyae Wa Chan Thar 1 in Block M-11, straddling the Moattama Basin and the Andaman Sea Basin, around late June 2019. Initial results have not been reported, however it is understood that a series of MDT tests indicated tight reservoir. The well was drilled to a final TD of approximately 4,030 m MD using the “Noble Clyde Boudreaux” S/S, at a water depth of approximately 600 m. The potential geological targets in this area include Oligocene-Miocene carbonate rocks, shallow marine to deltaic sandstone beds within the Middle and Upper Miocene intervals and Pliocene basin floor fan deposits. As of May 2019, operations were ongoing around 3,800 m. Wireline logging and coring was conducted during drilling. Pyae Wa Chan Thar 1 was spudded in early April 2019. Late in the month, drilling was likely ongoing at approximately 2,000 m. There are no discoveries made to date in block M-11. The only well previously drilled in the block is wildcat Manizawta 1 by PTTEP, in 2013. The primary target, Miocene carbonates, was dry, however possible gas shows were encountered in the shallower Pliocene sandstone section. Pyae Wa Chan Thar 1 is located approximately 25 km northeast of Manizawta 1. PTTEP has contracted the “Noble Clyde Boudreaux” for an extended drilling campaign since Q3 2018, to conduct appraisal drilling over the Zawtika gas complex, in the eastern part of block M-09, and new-field wildcat drilling in block M-11 and in the western part of block M-09. The previous exploration activity in Block M-11 was a 3D seismic survey acquired in 2016 using the “Polarcus Asima” vessel. The planned area for the survey was approximately 1,500 sq km. PTTEP holds 100% operating interest in Block M-11. The company also operates the Zawtika Development and Production Area (80% interest), partnering with MOGE (20%). Background Information Block M-11 was awarded to PTTEP (100%) in 2005. In 2012, Total and JX Nippon farmed into the block for 40% and 15% interests respectively. Following the drilling of wildcat Manizawta 1 in 2013, the partners withdrew from the block, leaving PTTEP as sole interest holder. PTTEP plugged and abandoned new-field wildcat Manizawta 1 on 4 November 2013. The well was drilled to TD at around 3,550 m. The well was spudded on 21 September 2013 by Vantage Drilling’s drillship “Tungsten Explorer”. The prospect is located in the deeper section of the block at around 1,000 m of water depth. Manizawta 1 is approximately 47 km west of wildcat M-11A/1 drilled by Esso Burma in 1976. PTTEP reported that the Zawtika Project commenced gas production for the domestic market on 14 March 2014, with initial sales rate of 40 MMscfg/d and planned peak of 100 MMcfg/d. Domestic gas is used for power generation. Gas export to Thailand commenced on 5 August 2014. Production gradually ramped up to the daily contract quantity of 240 MMscfg/d as stipulated in the Gas Sales Agreement with buyer PTT. Due to the highly faulted structures, numerous platforms and wells are required to develop the Zawtika and nearby fields. The initial phase of the Zawtika project (Phase 1A) consisted of three wellhead platforms (ZWP1, ZWP2 and ZWP3, located in the Shwepyihtay, Kakonna and Zawtika fields respectively) and one integrated central processing/living quarter’s platform (ZPQ). Further development phases will be necessary in order to maintain the stipulated production plateau.

PTTEP has plugged and abandoned wildcat Pyae Wa Chan Thar 1 in Block M-11, straddling the Moattama Basin and the Andaman Sea Basin, around late June 2019. Initial results have not been reported, however it is understood that a series of MDT tests indicated tight reservoir. The well was drilled to a final TD of approximately 4,030 m MD using the “Noble Clyde Boudreaux” S/S, at a water depth of approximately 600 m.

W-C part of AE-0009-3M-Tucoo-Xaxamani-01 block, offshore Sureste Basin, WD 37m, susp. at TD 4,245m late Aug ’19, results n/a, Cantarell II JU.  PTMD was 4,105m (3,780m TVD) subsalt, targets L. Pliocene + L. Miocene.

W-C part of AE-0009-3M-Tucoo-Xaxamani-01 block, offshore Sureste Basin, WD 37m, susp. at TD 4,245m late Aug ’19, results n/a, PTMD was 4,105m (3,780m TVD) subsalt, targets L. Pliocene + L. Miocene.

Sonatrach is understood to have abandoned its Sif Fatima Nord 1 (SFN 1) NFW in October 2017. The well, located on the Sif Fatima II exploration licence in the Berkine Basin, was spudded on 27 April 2017. Drilling operations were carried out using the ENTP #139 rig. SFN 1 reached a TD of 4,400m and was targeting the Early Devonian in a prospect lying to the north of the Rhourde Dabdaba Nord Field. The well was the second spudded on the block in 2017. Sonatrach operates Sif Fatima II, which confers exploration rights across the Sif Fatima Field Complex, with 100% equity.

Algeria, Sif Fatima II (Dev)

On 11 May 2020, Petrobras filed with the ANP an oil show report for the 9AB135DRJS directional special well on its Albacora Field in the Campos Basin. A 214m light oil column was encountered in the well in the pre-salt. The discovery was confirmed by testing at depths below 4,630m, according to Petrobras. The well is located on the southern edge of the mapped field boundary and could also be considered an outpost. The Norbe VIII rig spud the well in a water depth of 450m on 15 February 2020. It has a planned total depth of 4,988m and is projected to have a pre-salt objective. The Albacora Field has been producing from post-salt since 1987, but Petrobras is investigating whether production from pre-salt reservoirs in the field is also viable. Petrobras had plans to start a long-term test in the pre-salt Forno reservoir in the Albacora Field using the 3BRSA1123RJS well drilled in 2012 for the test which will be connected to the P-31 FPSO. However, due to a shutdown of the P-31 and a series of technical problems regarding FPSO’s and equipment in the field it is unclear whether this has been conducted. The test was planned to provide information to assist in preparing the Albacora Field revitalization project. It should last for about a year with an expected production rate of about 11,000 bo/d. The average well in the mature post-salt Albacora Field currently produces from 605 to 2,000 bo/d. The pre-salt was first discovered in Albacora Field in April 2011 with the 6BRSA899DRJS deeper pool wildcat. Petrobras operates Albacora with a 100% working interest. The long-term test in the area was a requirement in the Albacora Development Plan, approved in November 2014. The Albacora Field is in the process of being redeveloped with the expectation that at least 14 new wells will be drilled. The field has been producing since 1987 in a water depth of 700m. Currently two platforms (P-25 and P-31) are operating in the field. Based on the Forno reservoir discovery, Petrobras has extended the useful life of the field to 2040 with proven reserves of 487 MMbo and total reserves of 659 MMbo. Total gas reserves are 459 Bcfg with proven reserves of 318 Bcfg. The Round Zero Albacora concession contract runs until 2025 but the ANP has an agenda to extend these contracts. <P /><P />

9-AB-135D-RJS (Petrobras 100%), Service well in Albacora lease, Campos pre-salt, WD 450m, 214m light oil column, test at 4630m likely in the Aptian Macabu fm, Norbe VIII DS. Petrobras is reportedly laying out an appraisal plan to access those pre-salt reservoirs in the area.  

CEP secured on 1 Dec ’17 sole rights to the 9/2017/Ł Wolin contract, 593 sq km on the Pomeranian High in NW Poland.

Poland, not found

On 16 May 2019, the Argentine government granted MLO-121 block to Equinor following the company’s offer of USD 66.195 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019. Equinor will operate the block with 100% participating interest. Work program for the first exploration period is assumed to be limited to seismic work and possibly coring, as there is no drilling commitment required by the government for blocks offered in Round 1 until the second exploration period. Exploration target for the block is expected to be oil and gas in the Springhill Formation, 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. MLO-121 covers 4,293 sq km of deepwater area in Argentina Basin with approximated water depth between 50 to over 100 m. Along with MLO-121, Equinor also received 100%-held operatorship on the blocks of AUS-105 and AUS-106 in Austral Basin, as well as CAN-108 block in Argentina Basin from Round 1. In addition, the company also won CAN-102 and CAN-114 in Argentina Basin in a partnership with YPF, along with MLO-123 block in Malvinas Basin as part of a consortium with YPF and operator Total. Background Information The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. An official resolution for granting the exploration permits is expected to be published on 1 August 2019, with official granting of the permits to follow within 15 days.

Equinor ASA received CAN-108 block from Round 1 offshore bid round, Argentina Basin

Mazarine Energy is acquiring nine production concessions from OMV Petrom, subject to regulatory consents, as announced on 28 September 2018. The concessions produce around 1,000 boe/d and are located in the Moinesti-Zemes region in Bacau County, NE Romania, within the South Carpathian Basin. OMV Petrom has been actively rationalising its portfolio and sold 19 fields to Mazarine in 2017 - Balaceanca, Buiesti, Caldararu, Campeni, Cerdac, Folesti, Ghelinta, Glodeni, Ileana-Artari, Nineasa, Nineasa Sud, Opariti, Pasarea, Posesti, Slanic Bai, Slanic-Ferastrau, Valcanesti, Valea Resca and Vizantea. OMV Petrom had originally offered 32 marginal fields for sale in November 2014. Hague based Mazarine also holds E&P acreage in Tunisia, and in May 2016 was granted access to US$ 500 million private equity from Carlyle International Energy Partners to fund further E&P acquisitions. Mazarine operates locally through wholly-owned subsidiary Mazarine Energy Romania SRL.

Mazarine Energy is acquiring nine production concessions from OMV Petrom, subject to regulatory consents, as announced on 28 September 2018. The concessions produce around 1,000 boe/d and are located in the Moinesti-Zemes region in Bacau County, NE Romania, within the South Carpathian Basin. OMV Petrom has been actively rationalising its portfolio and sold 19 fields to Mazarine in 2017 - Balaceanca, Buiesti, Caldararu, Campeni, Cerdac, Folesti, Ghelinta, Glodeni, Ileana-Artari, Nineasa, Nineasa Sud, Opariti, Pasarea, Posesti, Slanic Bai, Slanic-Ferastrau, Valcanesti, Valea Resca and Vizantea. OMV Petrom had originally offered 32 marginal fields for sale in November 2014. Hague based Mazarine also holds E&P acreage in Tunisia, and in May 2016 was granted access to US$ 500 million private equity from Carlyle International Energy Partners to fund further E&P acquisitions. Mazarine operates locally through wholly-owned subsidiary Mazarine Energy Romania SRL.

LLA-34, Llanos Basin, TD 3,669m, drilled 3Q ’18, tested 500 b/d of 31 API oil on ESP from the Mirador fm, potential also in the Guadalupe. Winchester (op), partner Parex.

Chirioca-2, LLA-34, Llanos Basin, TD 3,669m, drilled 3Q ’18, tested 500 b/d of 31 API oil on ESP from the Mirador fm, potential also in the Guadalupe. Winchester (op), partner Parex.