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BP confirms 2 late 2017 discoveries in the North Sea: 29/4e-5 (Z) (Capercaillie) nfw, P2189 / block 29/4e, location west of BP’s Vorlich (aka Marconi) discovery, TD 3,750m in Sep ‘17, light oil and gas-cond in the Paleocene + Cretaceous, Paul B Lloyd Jr SS. Well data now under evaluation. Options include a tie-back devt to existing infrastructure. BP 100%. 206/9b-5 (Achmelvich) nfw, P2125, NE part of Clair field West of Shetlands, TD 2,395m in Dec ‘17, oil in the Mesozoic, Paul B Lloyd Jr SS BP (op), partners Shell + Chevron.  

206/09b-05 (Achmelvich) op. by BP (27,62%, Enterprise Oil 27,97%, ConcoPhillips 24%, Chevron 19,42%, Britoil 0,98%) in P2125, NE part of Clair field, ops terminated, was drilled to a TD=2395m and encountered oil in Mesozoic age reservoirs. No details were given of the volumes that have been found. Evaluation and interpretation of the well results is "ongoing to assess future options". 029/04e-05Z (Capercaillie) op. by BP (100%) in P2189 block, was drilled to a TD=3750m and encountered light oil and gas-condensate in Paleocene and Cretaceous-age reservoirs. BP did not reveal the volumes discovered but said the well data is currently under evaluation and that options are expected to be considered for a "possible tie-back development to existing infrastructure".

Union Jack Oil announced on 9 March 2020 that it has agreed two deals with Terrain Energy in PEDL 005(R) and PEDL 339. For PEDL 005(R), block TF/38b Keddington, Union Jack Oil will acquire Terrain's 35% interest in the block which includes the producing Keddington field in return for GBP 200,000. Union Jack Oil has assumed costs of GBP 35,000 in relation to Keddington site activities from the effective date of 1 January 2020. For PEDL 339, block TF/38c, Union Jack Oil will acquire Terrain's 15% interest in the licence. Completion of the deals is pending OGA approval. Keddington was discovered in in 1998 by Morrison Middlefield Resources Ltd subsidiary Candecca Resources Ltd. The field produces 28 bo/d from a Carboniferous reservoir. The partners in Keddington believe that there is remaining potential within the field which can be realized through further development drilling at the field. Approval is in place for the drilling of a further two wells and Egdon is finalizing its assessment of potential in-fill drilling locations. The site lease has been extended until 2029. In February 2020 Egdon completed the acquisition of a 20% interest from Terrain Energy in PEDL 005, block TF38b – Louth. The acreage contains the Louth prospect which Egdon is looking to farm down and potentially drill an exploration well later in 2020 or 2021. Following completion of the deals interest in PEDL 005(R) – block TF/38b Keddington will be Egdon Resources U.K. Limited (45% + operator) and Union Jack Oil Plc (55%). Interest in PEDL 339 will be held by Egdon Resources U.K. Limited (65% + operator) and Union Jack Oil (35%).

UJO has taken on a further 35% from partner Terrain Energy in PEDL 005(R) (Keddington oilfield) for GBP 200,000, pushing its stake to 55% whilst operator Egdon retains its 45%. In parallel, UJO is also acquiring 15% in adjacent PEDL 339 (Louth + North Somercotes prospects).

Total continued offering an opportunity to acquire a participating interest in the Yetagun West Block (YWB), located in the Andaman Sea, in November 2018. The company is planning to open a data room for the block in early 2019. Total is operator and sole interest holder in YWB. The company is planning to drill an exploration well in the block in 2H 2019. Potential exploration targets could be Miocene to Pleistocene deepwater reservoirs, likely within turbidite sand bodies. Secondary target could be Oligocene deltaic sandstones. No prior drilling has been conducted in the acreage. The study period for YWB has been extended by two years to August 2019. Final decision on the drilling plan could be made by that time. YWB is located mostly in deep water, with maximum depths exceeding 2,000 m. The last activity in the block was a 3D seismic acquisition that covered over 4,000 sq km, between January and May 2018. The new data likely supported the identification of potential drilling targets. Shearwater Geoservices’ “Polar Empress” S/V conducted the survey. The same seismic campaign also covered adjacent block MD-04 to the south, operated by Eni. In November 2016, Total submitted an Environmental Impact Assessment (EIA) report to the government, in view of future drilling. The previous activity in the block was a 2,000 km 2D seismic survey conducted between April and May 2016, using the “Polarcus Asima” S/V. YWB was officially awarded to Total on 25 February 2015. The block was offered as part of the 2013 Myanmar Offshore Bid Round. The farm-in opportunity for the block was initially offered by Total in July 2017. Background Information The Yetagun West Block is located in the deepwater Andaman Sea Basin, with water depth ranging from 1,000 m to 3,000 m. The block is situated along the Myanmar boundary with India, north of block MD-4 and immediately west of Petronas Carigali’s block M-12. To date, no exploration drilling has been conducted within the block perimeter. Although there is no exploration work conducted, 8.5 km west from the block boundary, in the India territory, block AN-DWN-2002/2, operator ONGC drilled one deepwater exploration well, ANDW-5 in November 2011. The wildcat ANDW-5 was spudded in water depth of 1,995 m with Transocean “Dhirubhai Deepwater KG-1” drillship. The well was plugged and abandoned in late January 2012, likely as a dry well.

Total continued offering an opportunity to acquire a participating interest in the Yetagun West Block (YWB), located in the Andaman Sea, in November 2018. The company is planning to open a data room for the block in early 2019. Total is operator and sole interest holder in YWB.

Wellesley acquired 40% interest from Total and 20% interest from Spirit in PL 685 with effect from 1 July 2018. Four months later, in the same licence, Wellesley then transferred 40% of its equity to Aker BP with effect from 30 November 2018. Both deals were announced on 6 December 2018. The licence covers a 407 sq km area over parts of blocks 34/6, 35/1 and 35/4. The acreage covered by the licence has yet to be drilled. It lies in between the Peon and Garantiana discoveries. The Peon discovery well was located on the apex of a mound structure and targeted a Pleistocene fluvio-glacial / glacio-marine sand body at a very shallow level. A 38 m thick, homogenous, unconsolidated sand was encountered at 574 m (named the Peon Sandstone of the Nordland Group) and 19 m of this contained very dry gas (99.5 vol% methane). The well was re-entered for testing in 2006 but the planned test could not be carried out. Equinor is currently considering developing Peon. If the development of Peon does go ahead it is likely to use an unmanned, remotely operated, stand-alone platform. Estimated recoverable reserves are approximately 690 Bcfg. Total discovered Garantiana in 2012 with 34/6-2 S. The Cook Formation was oil-bearing (gross oil column of 100 m) and was tested at a rate of 4,300 bo/d through a 28/64” choke. Downdip sidetrack 34/6-2 A found the OWC which had not been encountered in the original hole. In 2014 the find was appraised by 34/6-3 S. This well proved a 120 m gross oil column in a very good quality Cook Formation reservoir with no OWC. On test the well flowed at a stable rate of 5,912 bo/d through a 24/64” choke and a maximum rate of 6,919 bo/d through a 28/64” choke. Recoverable reserve estimates were increased to 38-88 MMbo. The reservoir lies at a depth of approximately 3,810 m and has a porosity of 20%. Garantiana partner Point Resources confirmed in April 2018 that the Equinor-operated field will be developed as a subsea tie-back. The host facility was due to be chosen later in 2018. Earlier reports from Wood Group in 2017 showed that the hosts which were being considered were Equinor’s Gullfaks B and Visund facilities. Following the completion of both deals, interests in PL 685 are divided between Aker BP ASA (40% + operator), Wellesley Petroleum AS (40%) and Petoro AS (20%).

Norway (Tampen Spur (Viking Graben Province)) Visund

E. part of Sichuan Basin, TD 8,060m (Pre-Cambrian Nantuo fm), ops terminated end-Feb ’18, shows in Permian Maokou carbs. Multiple targets, mainly Jurassic clastics and Pre-Cambrian carbs.

Wutan-1 nfw E. part of Sichuan Basin, TD 8,060m (Pre-Cambrian Nantuo fm), ops terminated end-Feb ’18, shows in Permian Maokou carbs. Multiple targets, mainly Jurassic clastics and Pre-Cambrian carbs.

The new Director General of the Sierra Leone Petroleum Directorate has decided to temporarily suspend the ongoing 4th Licensing Round (see DEA 22 May ’18) for up to 6 months to enter a period of industry consultation. The bid deadline was previously 27 Sep ’18. To recall, the round includes 5 blocks, namely SL-A-18, SL-B-18, SL-C-18, SL-D-18 + SL-E-18, 5,000-7,000 sq km apiece, total 31,653 sq km. See official map below:

The new Director General of the Sierra Leone Petroleum Directorate has decided to temporarily suspend the ongoing 4th Licensing Round (see DEA 22 May ’18) for up to 6 months to enter a period of industry consultation. The bid deadline was previously 27 Sep ’18. To recall, the round includes 5 blocks, namely SL-A-18, SL-B-18, SL-C-18, SL-D-18 + SL-E-18, 5,000-7,000 sq km apiece, total 31,653 sq km.

Shoal Point is looking to sell its 66.67% in EL 1070,  1,030 sq km in the Anticosti Basin off W. Newfoundland, Gulf of St. Lawrence. Shoal Point (op), partner Enegi Oil.

Shoal Point is looking to sell its 66.67% in EL 1070, 1,030 sq km in the Anticosti Basin off W. Newfoundland, Gulf of St. Lawrence. Shoal Point (op), partner Enegi Oil.

Commitment well in W-C part of AE-0008-4M-Amoca-Yaxche-06 block, offshore Sureste Basin, WD 26m, TMD 2,112m and evaluating. Target U. Miocene, Independencia I JU.

Commitment well in W-C part of AE-0008-4M-Amoca-Yaxche-06 block, offshore Sureste Basin, WD 26m, TMD 2,112m and evaluating. Target U. Miocene, Independencia I JU.

PEMEX plugged and abandoned dry the Cruver 1EXP new-field wildcat (NFW) in the AE-0028-2M-Cotaxtla-01 entitlement block in the onshore Veracruz Basin on 2 February 2019 according to official information reported by the CNH.  The NFW reached a final total depth (TD) of 7,868 m.   The NFW was spudded on 30 March 2018.     The proposed total depth (PTD) of the well was 7,722 m and the fractured Middle and Lower Cretaceous Orizaba Formation was the main objective. The NFW is located approximately 25 km south south-east of the Ixachi 1 discovery well.  This represents another deep exploration well in the deeper Cretaceous trend discovered by PEMEX in this area with the Ixachi 1.  PEMEX was granted a permit to drill the well on 15 March 2018. The NFW had estimated prospective resources of 218 MMboe.  The drilling cost for the well was estimated to be USD 28.69 million at 1USD = 18.3 MXN and the completion cost is estimated to be USD 5.52 million. SENER awarded the AE-0028-2M-Cotaxtla-01 entitlement block to Pemex 100% through Ronda 0 on 27 August 2014. The operator was granted a two year extension for the entitlement on 27 August 2017.  The block covers an approximate area of 466.41 sq km.

PEMEX plugged and abandoned dry the Cruver 1EXP new-field wildcat (NFW) in the AE-0028-2M-Cotaxtla-01 entitlement block in the onshore Veracruz Basin on 2 February 2019 according to official information reported by the CNH.

Lundin has agreed to acquire Fortis’ 10% stake in PL 539 + 860 and its 30% in PL 820 S + 825. It also agrees to take a further 20% again in PL 860 but from Statoil, taking its total holding to 40%. Interests-to-be: PL 539 (Skagerrak on Danish border): MOL (op), partner Lundin PL 820 S (adjacent to above):  MOL (op), partners Lundin + Wintershall PL 825 (mid-SNS): Faroe (op), partners Lundin + Spirit Energy PL 860 (Central Graben): MOL (op), partners Lundin + Petoro.

Lundin has agreed to acquire Fortis’ 10% stake in PL 539 + 860 and its 30% in PL 820 S + 825. It also agrees to take a further 20% again in PL 860 but from Statoil, taking its total holding to 40%. Interests-to-be: PL 539 (Skagerrak on Danish border): MOL (op), partner Lundin PL 820 S (adjacent to above): MOL (op), partners Lundin + Wintershall PL 825 (mid-SNS): Faroe (op), partners Lundin + Spirit Energy PL 860 (Central Graben): MOL (op), partners Lundin + Petoro.

Hocol is taking over operatorship and interests from Chevron of the Ballena + Chuchupa fields in La Guajira, N. Colombia. Operations have so far been run under the Guajira association contract (Ecopetrol-Chevron 57:43). The deal is subject to govt approval.

Ecopetrol (->100%) will take over Chevron’s 43% stake in the Chuchupa & Ballena field in the Caribbean Sea.

An auction is planned 26 Aug '20 for 25-yr rights to the Yelovyy block, 791 sq km in the Kaymys-Vasyugan Province, Tyumen Oblast, W. Siberia, application deadline 11 August. Starting price USD 800,000. Contact: Tyumennedra, email [email protected].

Russia (W. Siberia B.), an auction is planned 26 Aug '20 for 25-yr rights to the Yelovyy block, 791 sq km in the Kaymys-Vasyugan Province, Tyumen Oblast, W. Siberia, application deadline 11 August.

In the first half of 2019, Lukoil-Zapadnaya Sibir reported a new oil discovery in the Pokamasovskiy Severnyy license in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Wildcat Verkhneposyltymskaya 110, spudded in 2018 and drilled to 2,975 m, tested oil from two reservoirs in the Jurassic section. Reservoir Tyumen Formation Yu2 Unit (Aalenian-Callovian), perforated at 2,927-2,931 m, flowed with oil and water at rates of 74 b/d and 22 b/d, accordingly. Reservoir Vasyugan Formation Yu1 (1) Unit (Oxfordian) tested oil and water at rates of 211 b/d and 41 b/d, accordingly. The Pokamasovskiy Severnyy block covers 476 sq km in the Middle Ob Province and encompasses the Pokamasovskoye Severnoye and Posyltymskoye discoveries and several prospects. Pre-drilled resources of the Verkhneposyltymskaya-1 prospect were estimated at 5 MMbbl of oil. It must be noted that the estimation was done just for the Upper Jurassic section.

Verkhneposyltymskoye Lukoil-Zapadnaya Sibir reported a new oil discovery in the Pokamasovskiy Severnyy license in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Tested oil from two reservoirs in the Jurassic section. Reservoir Tyumen Formation Yu2 Unit (Aalenian-Callovian), perforated at 2,927-2,931 m, flowed with oil and water at rates of 74 b/d and 22 b/d, accordingly. Reservoir Vasyugan Formation Yu1 (1) Unit (Oxfordian) tested oil and water at rates of 211 b/d and 41 b/d, accordingly.

Severna Backa block, N. Serbia, drilled Aug-Sep '19, no details. Followed by Palic-3X, spudded mid-Oct '19.

Palic-2X appr Severna Backa block, N. Serbia, Abandoned: no details

KrisEnergy continued offering a farm-in opportunity in the Bala-Balakang PSC (formerly Tanjung Aru PSC), located in offshore Makassar Strait, in April 2019. The 838 sq km block is located at the southern edge of the Kutei Basin, with water depths ranging between 20 and 1,800 m. The block is estimated to contain over 8 Tcf of in-place resources. KrisEnergy holds 85% operating interest in the block while Natuna Ventures Pte Ltd holds the remaining 15% participating interest. The operator is offering up to 42% interest in the block, in return for pro-rata share of back costs and for full carry on a discretionary exploration well to be drilled by 12 December 2019 (end of exploration year 8). A possible drilling candidate is the North Papandayan prospect which is estimated to contain mean in-place resources of approximately 2.7 Tcfg in multiple turbidite channels and fans ranging from Lower Miocene to Plio-Pleistocene. The Bala-Balakang PSC contains two gas discoveries, Halimun 1 and Papandayan 1. As of 31 December 2018, contingent resources from the two discoveries were estimated at approximately 110 Bcfg (on a 100% working interest basis). The broader Papandayan and Halimun prospect areas hold the largest exploration potential in the block. The block is expected to be primarily gas prone. Typical exploration targets in the block are Miocene to Pliocene channel/fan complexes with structural and stratigraphic traps, analogous to the Jangkrik, Merakes and Gendalo fields located to the north. Further exploration is also expected to yield biogenic gas in Plio-Pleistocene reservoirs. All the firm commitments for the first exploration term in the PSC have been fulfilled, following the acquisition of a 500 sq km 3D Broadband seismic survey by KrisEnergy in 2014. The survey commenced on 24 March 2014 using Western Geco’s “Western Monarch” M/V, and was completed on 11 April 2014. The survey complemented the existing 3D seismic dataset and allowed the identification of multiple play types and bright spots at various depths. The block was awarded in 2011. Firm commitments for the first three years of exploration included G&G studies (USD 0.50 million) and 500 sq km 3D seismic acquisition (USD 5 million). The block was offered in late September 2011 as part of the Second Petroleum Bidding Round 2011 under the direct offer mechanism. The farm-in opportunity in the block was initially offered in November 2015. For further information, interested parties may contact: Mike Whibley Vice President, Technical [email protected] Dr. Gadjah E. Pireno Exploration Manager, Indonesia [email protected] Background Information The Bala-Balakang PSC was previously known as Tanjung Aru PSC. The idea to change the block name was initiated by the government of West Sulawesi in late October 2014, based on the administration area which is essentially located in Western Sulawesi province. The name change was approved by Indonesian authorities in 2015. The block was officially awarded on 19 December 2011 to a consortium of KrisEnergy (43%, operator), Neon Energy (42%) and Natuna Ventures Pte Ltd (15%). In August 2015, KrisEnergy acquired the whole of Neon Energy’s interest, increasing its total stakes to 85%. The block straddles the Kutei Basin and the Pater Noster Shelf and originally covered an area of around 4,200 sq km, of which approximately half in shelf water and half in deep water, with maximum depths of 2,500m. The same acreage was previously operated by Hess between 2001 and 2009, under the Tanjung Aru PSC. Earlier, a portion of the block was covered by Mobil’s Makassar Strait Block A since 1973 until partial relinquishments in 1990. Tanjung Aru PSC history Hess (50%, operator) and Petronas Carigali (50%) were initially awarded the Tanjung Aru PSC on 7 December 2001. The effective date of the contract was on 22 November 2001. The 4,190 sq km block is located to the south of Chevron's Ganal PSC. Signature bonus paid was USD 7.75 million. The total commitment for the 10-year exploration period would amount to USD 81.75 million. The firm three-year work commitment included drilling of three exploratory wells and acquisition of 2,000 km of 2D seismic data and 400 sq km of 3D seismic coverage. Prior to the award, no drilling had previously been undertaken within the limits of the block. Hess commenced exploration in the block between 8-29 April 2002, when it acquired a 2,035km 2D seismic survey. Hess also purchased 1,477sq km of 3D data over the block from an extensive regional 3D "spec" survey over the deepwater Makassar Strait acquired by PGS in 1999. Prior to the first drilling campaign in the block, Pertamina farmed-in for a 15% stake, acquiring 7.5% each from Hess and Petronas Carigali. Hess drilled three commitment wells which yielded two small gas discoveries (Halimun 1 and Papandayan 1, both in July 2002). For both wells, the Upper Miocene primary objective was interpreted as a basin floor fan but turned out to be mud-rich. The Plio-Pleistocene secondary objectives, interpreted as canyon fill, contained multiple gas bearing sands. The last well drilled, Rinjani 1, was plugged and abandoned in January 2005 with gas shows and was not tested. It targeted Middle Miocene turbidite sandstones and Upper Eocene sandstones in a stratigraphic trap. Post-drill analysis on Rinjani 1 indicated that the source rock potential of Oligo-Miocene syn-rift deposits is relatively low for thermogenic gas generation. However, further potential in the area could be found in the Plio-Pleistocene reservoirs charged with biogenic gas. Hess' first well, Halimun 1, was spudded on 7 July 2002. On 20 July 2002, the well was plugged and abandoned as a non-commercial gas discovery after being drilled to TD at 2,401 m. Halimun 1 was drilled in 1,061m of water and was targeting Upper Miocene and Pliocene sandstones with a PTD of 3,048 m. The well lies some 34 km south of Mobil's 1994 Perintis 1 non-commercial gas/condensate discovery (6 MMcf/d plus 150 bc/d). Hess then relocated the "Sedco 601" S/S and on 21 July 2002 spudded wildcat Papandayan 1 as the second and final well of the drilling campaign. The well was drilled to TD at 2,463 m and was plugged and abandoned as a non-commercial gas discovery without being tested on 30 July 2002. Papandayan 1 was drilled in 554 m of water and was targeting Upper Miocene and Pliocene sandstones with a PTD of 2,652 m. The well lies in the north of the block and is located 13.5 km west of Halimun 1. Wildcat Rinjani 1 was spudded on 3 January 2005 using the "Ocean Baroness" S/S in 1,159 m of water. The well plugged and abandoned with gas shows on 15 January 2005 after being drilled to TD at 2,727 m, without testing. Rinjani 1 had a PTD of 2,758 m and was targeting Middle Miocene turbidite sandstones and Upper Eocene clastics in a stratigraphic trap about 10 km south of Halimun 1. Rinjani 1 was the operator's final commitment well in the block. Prior to the spud of Rinjani 1, Chevron farmed in to the PSC for a 10% stake from Hess. It was initially reported in May 2005 that Hess and partners indicated their intent to totally relinquish the block following the drilling of the committed three exploration wells. Formal approval for the relinquishment was likely received in late 2009. At the time of relinquishment, rightholders of the block were Hess (32.5%, operator), Petronas Carigali (42.5%), Pertamina (15%) and Chevron (10%).

KrisEnergy continued offering a farm-in opportunity in the Bala-Balakang PSC (formerly Tanjung Aru PSC), located in offshore Makassar Strait, in April 2019. The 838 sq km block is located at the southern edge of the Kutei Basin, with water depths ranging between 20 and 1,800 m. The block is estimated to contain over 8 Tcf of in-place resources. KrisEnergy holds 85% operating interest in the block while Natuna Ventures Pte Ltd holds the remaining 15% participating interest. The operator is offering up to 42% interest in the block, in return for pro-rata share of back costs

In late October 2017, Agiba Petroleum completed the Aman East 1X NFW as a Cretaceous oil discovery. The well encountered hydrocarbons in the Bahariya Formation. The discovery lies to the east of the Aman Field, located on the Meleiha PSC in the Shushan Basin. Aman East 1X was spudded on 27 August 2017. It is the second successful well on the PSC in 2017. In September 2017, the company made a Cretaceous Alam El Bueib Formation oil & gas discovery in the Meleiha South 1X NFW, drilled on the Meleiha West development lease. Equity in the Agiba consortium is split between Eni (38%), Lukoil (12%) and EGPC (50%, carried).<P />

Egypt, Meleiha (Dev)

On 11 March 2019, United Oil & Gas PLC (United) announced that it had signed an option agreement with Elephant Oil Ltd (Elephant) to farm into Block B, potentially taking a 20% interest in the production sharing agreement. The Block B licence data is limited to a single seismic line and a CGG-acquired airborne Falcon Gravity Gradiometer survey.  This data suggests the presence of numerous large structures in the licence, with the potential to hold >200MMbbls. The Allada structure has already been identified by Elephant Oil as a prospect. Under the farm in option agreement, United have agreed to fund passive seismic and field studies up to a value of USD 175 thousand.  The completion of the passive seismic programme is being targeted for April.  The goal is to calibrate the depth to basement and obtain further information on the oil and gas seeps.  This will further de-risk maturity and migration in the area ahead of the completion of a final decision to exercise the farm in option. If United chooses to exercise the option, then the company will farm into the PSC for a 20% interest and will be responsible to fund 30% of the non-drilling and 20% of the drilling costs in the Phase 1 work programme as approved under the PSC.  United would also pay Elephant the sum of US$260,000, representing one quarter of the pro rata (20%) past costs expended by Elephant on the prospect, with the remaining US$780,000 paid in three equal six-monthly instalments. Block B covers an area of 4,590 sq km. The acreage is undrilled. Participants are Elephant, operator with a 90% interest and Société Béninoise des Hydrocarbures (Sobeh), the Benin state oil company, with a 10% interest (carried through exploration).

United Oil & Gas has signed an option agreement with Elephant Oil to acquire a 20% stake in the block B PSC, (4590km²) undrilled on the Dahomey Embayment, west of Cotonou. The block contains one prospect (Allada).

Equinor spudded its Mist exploration well 7219/9-3 on 12 July 2020. It was using the “Transocean Enabler” S/S to drill the well in PL 532. Mist lies approximately 6 km south of Kayak and 22 km southwest of Johan Castberg. The objective was the Lower Jurassic Tubaen Formation, expected at 913 m and mapped to be 150 m thick. Porosity was forecast at 29% and chance of success at 32%. The prospect was prognosed to contain oil and gas and operations were estimated to last for 39 days. On 28 July 2020, 16 days after spudding, Equinor was preparing to pull the BOP and abandon the well having drilled to TD - 1,338 m. Equinor’s Kayak discovery was made in 2017. 7219/9-2 proved two oil-bearing sandstones (27 m and 18 m) in the upper part of the Lower Cretaceous Kolje Formation (a new play type for the area) with no OWC. Estimated recoverable reserves are 25-50 MMboe. Johan Castberg contains recoverable reserves of 558 MMboe and first oil is expected in Q4 2022. The three fields involved in the project – Skrugard, Havis and Drivis – will be developed using an FPSO, 10 subsea templates, two satellite structures and 30 wells, with oil exported by shuttle tanker. CAPEX is estimated at NOK 47.2 billion (USD 5.79 billion) and the break-even price is around USD 31 per barrel. Johan Castberg is forecast to produce for at least 30 years. The PDO, submitted on 5 December 2017, was approved by the Ministry of Petroleum and Energy on 11 June 2018. Interest in PL 532 is divided between Equinor Energy AS (50% + operator), Var Energi AS (30%) and Petoro AS (20%).

(Barents Sea Platform)Well 7219/9-3 on PL 532 abandoned with results not available op. by EQUINOR (50%), VAR EN (30%), PETORO (20%) objective in Lower Jurassic Tubaen Formation

PL 825 between Oseberg, Veslefrikk + Huldra, WD 119m, TD 3,469m, 56m gross (17m net) gas/condensate column in the Ness fm, 86m of water-bearing reservoir in the main Oseberg target. No hc contact in the Ness. Preliminary gas-condensate recoverable volumes 2.7-17 MMboe in the Ness, unlikely to be commercial standalone. Transocean Arctic SS. Faroe (op), partners Lundin + Spirit Egy.

030/06-30 (Rungne) (Faroe 40% op. Equinor 30%, Spirit Egy. 20%, DNO 10%) in PL 825, encountered only a water-bearing reservoir in the primary Oseberg Fm target, while hitting a 56m gross gas-condensate column with 17m of net pay in Middle Jurassic Ness Fm sst.

Sonatrach (100%) was awarded Gassi El Agreb Zotti licence (831km²), located ~70km SW of the Hassi Messaoud Field.

Sonatrach (100%) was awarded Gassi El Agreb Zotti licence (831km²), located ~70km SW of the Hassi Messaoud Field.

On 19 December 2017, Pluspetrol announced the acquisition by GeoPark of the 179 sq km Aguada Baguales, the 238 sq km El Porvenir and the 138 sq km Puesto Touquet blocks in the Neuquen Basin. The deal was closed for US$ 52 million and is subject to official approval. As reported by GeoPark, the blocks produce a combined 2,700 boe/d, 70% liquids and 30% gas. GeoPark also estimates proven and probable (2P) oil and gas reserves of approximately 12-14 million barrels of oil equivalent and 3P reserves of approximately 18-20 MMboe and approximately 15-30 MMboe in prospective exploration resources plus additional potential in the Vaca Muerta Shale. GeoPark is returning with more strength to the local market after divesting some assets in the Santa Cruz province, Austral Basin. Pluspetrol is the third leading hydrocarbon producer in Argentina and intends to concentrate activity on its strategic assets like the Centenario Block, the former Petro-Andina Resources licences, the Vaca Muerta assets and its Peru holdings.

Argentina, El Porvenir (CNQ-15 M)

The government of Equatorial Guinea has partnered with ExxonMobil in Block EG-06 through a 20-percent stake held by national oil company GEPetrol. ExxonMobil discovered oil at its Block EG-06 Avestruz-1 well, drilled in October 2017. Commerciality is yet to be established for the Avestruz discovery. The block is located next to the legacy oil-producing Block B and EG-11, ExxonMobil’s most recently signed acreage. ExxonMobil has struck oil with its Avestruz-1 well in Block EG-06, announced the Ministry of Mines and Hydrocarbons of Equatorial Guinea. The well was drilled in October 2017. The operator is now assessing potential commerciality. Avestruz-1 is located approx. 160 kms offshore Malabo in an exploration area adjacent to ExxonMobil’s Zafiro field, a prolific legacy oilfield in Equatorial Guinea’s northern maritime area. The company signed its production sharing contract for Block EG-06 in 2015, followed by its entry into nearby Block EG-11 in 2017. 'Equatorial Guinea’s partnership with ExxonMobil continues to yield new oil discoveries, testifying to the huge potential in this country and our enabling environment for oil and gas exploration,' said Minister of Mines and Hydrocarbons H.E. Gabriel Mbaga Obiang Lima. 'We hope that commerciality will be established at Avestruz-1 and look forward to seeing more developments in the areas surrounding Block B.' The government of Equatorial Guinea has partnered with ExxonMobil in Block EG-06 through a 20-percent stake held by national oil company GEPetrol. An ExxonMobil local subsidiary is the operator with 80 percent. At the Zafiro field in Block B, ExxonMobil’s affiliate has a 71.25 percent interest, GEPetrol has 23.75 percent and the state has 5 percent. Since 1996 Zafiro has produced over 1 billion barrels of oil. Distributed by APO Group on behalf of Ministry of Mines, Industry and Energy Equatorial Guinea. Original article link Source: Ministry of Mines, Industry and Energy Equatorial Guinea

Equatorial Guinea, not found

Egyptian Natural Gas Holding Co. (EGAS) has awarded 5 of its of its 16 blocks proposed in its 2018 bid round, namely North Sidi Gaber (Block 4), North El Fanar (Block 6), East Damanhur (Block 10), West Sherbin (Block 11) and Northeast El Amereya (Block 3). Egyptian General Petroleum Corporation (EGPC) has awarded 7 of its of its 11 blocks proposed in its 2018 bid round, namely North Beni Suef (Block 5), West El Fayoum (Faiyum) (Block 7), South Abu Sennan (Block 10), Southeast Siwa (Block 11), Southeast Horus (Block 9), West Amer (Block 2) and Northwest El Amal (Block 4)

Egyptian Natural Gas Holding Co. (EGAS) has awarded 5 of its of its 16 blocks proposed in its 2018 bid round, namely North Sidi Gaber (Block 4), North El Fanar (Block 6), East Damanhur (Block 10), West Sherbin (Block 11) and Northeast El Amereya (Block 3). Egyptian General Petroleum Corporation (EGPC) has awarded 7 of its of its 11 blocks proposed in its 2018 bid round, namely North Beni Suef (Block 5), West El Fayoum (Faiyum) (Block 7), South Abu Sennan (Block 10), Southeast Siwa (Block 11), Southeast Horus (Block 9), West Amer (Block 2) and Northwest El Amal (Block 4)

Shell has reportedly signified of its intention to withdraw from CNH-R02-L01-A15.CS/2017 (block 15), 976 sq km in the Sureste Basin offshore, which it shares with optr Total 60:40. Qatar Petroleum has only recently announced its acquisition of interests from Total (DEA 7 May '20), which would have led to Total (op) 42%, Shell 40%, QP 18%. The latest news would lead to a 50:50 between Total + QP. All moves are pending govt approvals.

Shell has reportedly signified of its intention to withdraw from CNH-R02-L01-A15.CS/2017 (block 15), 976 sq km in the Sureste Basin offshore, which it shares with optr Total 60:40. Qatar Petroleum has only recently announced its acquisition of interests from Total (DEA 7 May '20), which would have led to Total (op) 42%, Shell 40%, QP 18%. The latest news would lead to a 50:50 between Total + QP

On 31 July 2020 Equinor agreed to sell 40.8125% of its interest and transfer operatorship of licences P234 (block 3/28a), P493 (block 3/28b), P920 (3/27b) and P977 (blocks 9/2a and 9/3a) to EnQuest. A sale and purchase agreement has been signed between the two companies for the licences that host the Bressay heavy oil field. The sale is for an initial consideration of GBP 2.2 million (as a carry against 50% of Equinor's net share of costs) and a further consideration of GBP 11.48 (USD 15 million) will be payable when the Bressay field development plan is approved. The deal is estimated to complete in Q4 2020. Located northeast of Kraken field, the Bressay field was discovered in 1976 with heavy oil and a small gas cap in the Upper Paleocene Teal Sands. The heavy oil has an average API of 12° and a viscosity of 550 cP. An environmental statement was submitted for the field in June 2013 which described the development via 70 development wells, with operations commencing in 2016, first oil in 2018 and peak production was anticipated to take place between 2022 and 2025. However, by November 2013 the development was stated to be delayed and in August 2016 the concept selection was deferred because of market conditions and the need to simplify the development concept. A number of development scenarios are still under consideration, one involves a tie back to Kraken field. Interest in the licences P234, P493, P920 and P977 is held by EnQuest Heather Ltd (40.8125% + operator), Equinor (UK) Ltd (40.8125%) and Chrysaor Ltd (18.375%).

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

Liari ML, Lower Indus onshore, TD 3,241m, discovered gas + condensates and successfully tested, Anton-4001 rig.

Ramdiani 1 (UEPL 100%) in Liari ML block onshore, TD=3241m, discovered gas + condensates and successfully tested.

Local media reported on 15 July 2019 that representatives of ExxonMobil met with the Romanian authorities to discuss the future of the Domino and Pelican South offshore gas project. Unconfirmed information stated that the supermajor would be seeking to divest part or the totality of its 50% stake in the XIX Neptun East license (Neptun Deep) covering the two offshore discoveries which are estimated to hold between 42 and 84 Bcm of gas. The company did not comment the rumor. It is recalled that in late 2018 ExxonMobil and its 50% partner OMV Petrom decided to postpone their final investment decision (FID) for what is commonly referred as the largest gas project in the Black Sea, mainly because of the enacting of a new offshore legislation which is negatively affecting the economics of the project. The Domino gas field was discovered by OMV Petrom in 2012 with the Domino 1 wildcat. The well encountered a net pay of 71 m with 2P reserves estimated at 2 Tcf of gas. In late 2012 ExxonMobil took over the operatorship and a 50% interest from OMV Petrom in the XIX Neptun East block. Pelican South was discovered in early 2015 about 22 km to the northwest of Domino. The field holds 2P reserves estimated at 500 Bcfg. The XIX Neptun permit is divided into two blocks: XIX Neptun East and XIX Neptun West. Interest in the XIX Neptun East block is held by Exxon Mobil Exploration and Production Romania Ltd (50% - operator) and OMV Petrom SA (50%).

Exxon Mobil Corp - XIX Neptun East license (Domino and Pelican South gas discoveries) - ExxonMobil reportedly in discussions with Romanian authorities

On 19 February 2019, Repsol announced a gas discovery at wildcat Kaliberau Dalam 2X (KBD-2X), in the Sakakemang PSC, located onshore in the South Sumatra Basin. After a preliminary assessment, recoverable reserves from KBD-2X are estimated to be at least 2 Tcfg, from a fractured pre-Tertiary Basement reservoir. The company plans to follow up the discovery with an appraisal well in the coming months. Earlier local reports in mid-February 2019 indicated that KBD-2X tested gas at a rate of around 45 MMcfg/d. Reportedly the well reached a total depth of around 2,430 m MD in early February 2019, and the testing programme commenced on 10 February. The success of the well at the fractured basement zone will open up additional potential in the basement in the South Sumatra Basin, which the Indonesian oil and gas regulator, SKK Migas, has highlighted as a potential area for giant gas discoveries. Repsol was understood to be preparing to commence DST operations on the wildcat in early February 2019. The company suspended the drilling activity around early October 2018, after the well experienced loss and kick during operations, which has caused damage to the mud pump and blow out preventer (BOP) valves. The operator was planning to sidetrack the well using 12-1/4” casing to bypass the problem area. Well operations were expected to resume by end-October or early November 2018. Wildcat KBD2X was spudded on 20 August 2018 using the “PRA-15” rig, operated by PT Plumpang Raya Anugrah. The well was targeting the pre-Tertiary Basement, in line with recent exploration drilling in the block. The Indonesian oil and gas regulator, along with representatives of the local administration, conducted a well site inspection on 29 August 2018. The drilling campaign was delayed from the initial planned Q4 2017 schedule. Well site and road access construction for KBD-2X were likely carried out in 2017. The drilling location may have been matured following a 350 sq km survey 3D seismic acquired in late 2015/2016. The operator also processed 4,750 km of gravity and magnetic data acquired in the block around 2017. It is understood that the operator is planning to drill another well in 2019, after the completion of KBD-2X. The previous drilling activity carried out in the block was Kukulambar 2X, spudded on 28 July 2016. The well was possibly targeting the Lower Miocene carbonates of the Batu Raja Formation and the pre-Tertiary Basement, and likely encountered gas shows. The block is currently operated by Repsol which holds 45% interest. Petronas holds another 45% interest and the remaining 10% stakes are held by Mitsui Oil Exploration Co. Ltd. (MOECO). Repsol and Petronas signed the interest transfer agreement December 2018, while MOECO acquired its interest from Repsol in August 2018. The current Sakakemang PSC covers an area of approximately 536 sq km. The block is considered as a highly prospective exploration area due to the proximity to producing blocks. It lies adjacent to ConocoPhillips' gas-rich Corridor PSC and south of Pertamina’s Jambi Merang block, also the site of the producing gas/condensate fields at Pulau Gading and Sungai Kenawang. The area, under various guises and operators, had been worked since the early 1900s with initial emphasis on oil exploration rather than gas, and production was limited to three shallow oil fields of pre-WWII vintage, all from Air Benakat sandstones. Typical exploration objectives in the area are hydrocarbon accumulation in the Upper Oligocene-Lower Miocene Talang Akar Formation and Lower Miocene Batu Raja carbonate build-ups. Further upside potential has been identified in the pre-Tertiary Basement. Background Information The Sakakemang block was previously operated by PT Pertamina/ConocoPhillips (Sakakemang) Ltd. JOB under the Sakakemang JOA which was totally relinquished in early 2009. The Sakakemang JOA was awarded to Pertamina and Gulf Resources on 7 December 2001 with contract effective date on 22 November 2001. The working interest split for the JOA was 70% Gulf (then a Conoco subsidiary) and 30% Pertamina. Standard JOA terms apply and signature bonuses totalled USD 2.3 million. The 10-year commitment amount to USD 43 million, with USD 14.5 million assigned for the first three years commitment, consisting of the reprocessing of existing seismic, acquisition of 500 km of 2D seismic and the drilling of two exploratory wells. In late March 2003, ConocoPhillips received BP Migas approval to rename its Gulf Resources subsidiary companies in Indonesia. The move followed the completion of the merger between Conoco Inc and Phillips Petroleum Co on 30 August 2002. Included in the companies renamed was Gulf Resources (Sakakemang) Ltd. The operating company became ConocoPhillips (Sakakemang) Ltd effective 10 October 2002. In 2003, Pertamina and ConocoPhillips spudded vertical wildcat Sumpal North 1 which was suspended as a gas discovery after a flow rate of 5.8 MMcf/d was reported. Targeting fractured pre-Tertiary basement, Sumpal North 1 is located in the western part of the block about 4 km north of the ConocoPhillips operated Sumpal gas field in the adjacent Corridor PSC, that field producing from the same play. The well was drilled following the interpretation of a 513.5 km 2D seismic survey completed between 8 April 2002 and 30 June 2002. In 2004, the same consortium found non-commercial amounts of gas with the Kaliberau Dalam 1 wildcat, which targeted pre-Tertiary Basement and Air Benakat Formation. Also in 2004, Pertamina discovered oil and gas from the Air Benakat Formation with wildcat Kenawang P-1, located on the North Palembang High, about 5 km southeast of Kaliberau Dalam 1. The well had a PTD of 1,700 m and reserves have been quoted at 11 MMbbl of oil. The South Sumatra Basin lies mostly onshore on the island of Sumatra, with a minor proportion extending offshore into the South China Sea. It is delimited by the Barisan-Garba mountain ranges to the south and southwest, and separated from the Central Sumatra Basin by the Tiga Puluh Arch to the northwest. Tertiary sediments onlap the Sunda Platform to the northeast, and the Lampung Platform in the east, which separates the region from the West Java Basin. Deep basinal areas containing over 6,000 m of Tertiary sediments are located onshore. The basin is delineated by several major structural highs. The recently uplifted pre-Tertiary basement of the Barisan-Garba mountain ranges extends the length of the western and southern basin margins. Crystalline basement also outcrops in the Tiga Puluh Arch to the northwest, which separates the South from the Central Sumatra Basin. To the northeast, Tertiary sedimentary cover onlaps the continental margin of the Sunda Shelf, and in the southeast, it is separated from the Sunda-Asri sub-basins of the West Java Basin, by the shallow Lampung Platform. The Talang Akar group of plays represents the most significant play in the basin. It comprises Upper Oligocene-Lower Miocene reservoirs formed by high porosity fluvial, deltaic and coastal transgressive sands. Traps are mainly structural with anticlines and faulted anticlines of Middle Miocene-Pliocene age, but a stratigraphic component occurs where there is shale-out or pinch-out of sand lenses against basement highs. Batu Raja plays are mainly characterized by composite traps with Lower Miocene carbonate build-ups developed on pre-Tertiary structural highs or associated with anticlinal structures. The Air Benakat and Muara Enim plays are regressive shallow marine to littoral reservoir sandstones in anticlinal and/or fault controlled trap structures of Late Miocene-Pliocene age. Basement plays consist of fractured granites, granodiorites, phyllites, quartzites and limestones and are generally gas productive, but yield oil in some fields.

Kaliberau Dalam 2X (Repsol op. 45%, Petronas 45%, Mitsui Oil Exploration 10%), in Sakakemang PSC, had hit gas in targeting, pre-tertiary fractured basement play, tested ca. 45 MMcf/d of gas. SKK Migas did not reveal the size of the discovery, but Repsol confirmed that the recoverable resource estimate of at least 2 Tcf (the prospect had been estimated to hold 1,5 Tcf of gas). The discovery lies about 25 km from the the Grissik gas plant which gathers and processes production predominately from the ConocoPhillips-operated Corridor PSC, before sending it to buyers in Sumatra, West Java and Singapore. Potentially it is the largest discovery in Indonesia since the Exxon Mobil's Cepu discovery in 2001.

The CNH approved yesterday DEA’s acquisition of the 22.5-40% interests held by Sierra O&G in 6 blocks in the Campeche Deep Sea and Sureste offshore basins, deal now effective:

Mexico, not found

Pokamasovskiy Severnyy licence, Middle Ob Province in Khanty-Mansiysk AO, W. Siberia 2018-2019 well to TD 2,975m, tested 74 bo/d + water from the Tyumen Yu2 unit between 2,927-2,931m, and 211 bo/d + water from the Vasyugan Yu1 unit.

Verkhneposyltymskaya-110 nfw Pokamasovskiy Severnyy licence, Middle Ob Province in Khanty-Mansiysk AO, W. Siberia 2018-2019 well to TD 2,975m, tested 74 bo/d + water from the Tyumen Yu2 unit between 2,927-2,931m, and 211 bo/d + water from the Vasyugan Yu1 unit.

According to local reports in October 2018, state company YPF has plugged and abandoned the Caldenes Central 2 new-field wildcat (NFW) with oil and gas shows on its Los Caldenes block in September 2018. The well reached its total depth (TD) of 2,890 m (9,482 ft) in June 2018 after it was spudded in May 2018 with the original planned targeted depth of 3,020 m (9,908 ft) and objectives in the Kimmeridgian Sierras Blancas Formation and Tithonian to Valanginian Quintuco Formation. The Los Caldenes block covers 115 sq km of land in the Neuquen Embayment area of the Neuquen Basin on the Rio Negro Province. Caldenes Central 2 is situated approximately 3 km south of the Manzano Grande 1 oil and gas discovery from February 2015. The well tested 163.5 bo/d and 247 Mscfg/d plus 19 bw/d from the Sierras Blancas Formation and 119.5 bo/d and 1.5 MMscfg/d Quintuco Formation. Background Information Current production in Los Caldenes block comes from the field of the same name that was discovered in 1999. Oil production was put on-stream later in the same year before it was temporarily shut-in in April 2007, while gas production was put on-stream in March 2014. The field has produced a total of 532.9 Mbo and 563.3 MMscfg at the end of 2017.

Argentina (Neuquen Embayment (Neuquen B.)) Los Caldenes

After over a year in the making, and noises the round was in jeopardy during the spring, South Sudan's plans to offer 14 blocks for licensing have officially been shelved for 2020, a victim of CV19. A renewed effort could be launched in 2021 providing the virus can be beaten and industry interest rekindled. 10 blocks were to be on offer and 3 more were under negotiation.

Round postponment. After over a year in the making, and noises the round was in jeopardy during the spring, South Sudan's plans to offer 14 blocks for licensing have officially been shelved for 2020, a victim of CV19.

Block XII, 6,702 sq km in the Syria-Iraq border, was reportedly granted to the Iranian govt. An initial agreement on such had been reached in February, now ratified. The new block lies south of Al Furat and Deir Ez Zor acreage, currently under force majeure. Any revenue derived from production in this block would be used to pay Iran back for the credit under which Syria has imported Iranian oil since 2013.

Block XII, 6,702 sq km in the Syria-Iraq border, was reportedly granted to the Iranian govt. An initial agreement on such had been reached in February, now ratified. The new block lies south of Al Furat and Deir Ez Zor acreage, currently under force majeure. Any revenue derived from production in this block would be used to pay Iran back for the credit under which Syria has imported Iranian oil since 2013.

Aker BP completed the acquisition of Hess's Norwegian subsidiary Hess Norge on 22 December 2017. The deal was first announced on 24 October 2017 and is backdated to 1 January 2017. Hess will receive US$ 2 billion cash consideration however Aker BP will benefit from Hess Norge's tax loss carry forward, nominally valued at US$ 1.5 billion after tax. The deal comprises PL033, PL006 B & PL033 B containing the producing Hod and adjacent Valhall oil fields, in the Southernmost Norwegian North Sea on the Norway-Denmark border. Hod production commenced in September 1990 from Late Cretaceous Hod & Tor formations and the Early Paleocene Ekofisk Formation, having original recoverable volumes of 80.8 MMboe and has produced 75.3 MMboe to end 2016. Valhall production commenced in October 1982 from Late Cretaceous Hod and Tor formations, with original recoverable volumes of 1,136.5 MMboe and has produced 899 MMboe to end 2016. The deal also includes 15% in Statoil operated 15th Round 1996 award PL220 (248 sq km) in the Northern most Norwegian Sea, currently under extension after drilling 6710/10-1 (2000, Den norske, 2,267m TVD) which was P&A dry. Hess previously held 64.05% in PL006 B (Hod) and 62.5% in PL033 & PL033 B (Valhall) and after becoming 100% operator Aker BP concluded on the same date the sale of 10% in both licences to Pandion Energy. Hess is also selling its Danish subsidiary which includes 61.5% operator share of South Arne oil field.

Aker BP (->100%) completed the acquisition of PL 006 B, PL 033, PL 033 B & PL 220 blocks from Hess for US$1,5 billion.

Block 4845, SE Turkey Fold Belt, TD 3,460m in mid-2017, since tested high API hc from 2 intvs in the Bedinan fm, also 184 bo recovered from the Dadas Shale, LT test planned.

Turkey (Southeast Turkey Zagros Fold Belt (Zagros Prov.)) Cavuslu 1

Carnarvon is looking to dilute its 100% in AC/P62 (aka Condor project), 1,512 sq km in shallow waters of the S. Vulcan sub-basin (Bonaparte Basin). Farmin terms negotiable. Likewise AC/P63, 585 sq km in the same area, both blocks secured early 2018. Contact: [email protected].

Carnarvon is looking to dilute its 100% in AC/P62 (aka Condor project), 1,512 sq km in shallow waters of the S. Vulcan sub-basin (Bonaparte Basin). Farmin terms negotiable. Likewise AC/P63, 585 sq km in the same area, both blocks secured early 2018. Contact: [email protected].

Add. DEA 3 Sep '19: Kohat 3371-10 EL, Potwar Basin, TD 3,200m, gas-cond discovery, tested 12.7 MMcfg/d + 240 bc/d on 1/2” choke, WHFP 2,478 psi, from the Cret. Lumishwal fm, more recently 4.1 MMcfg/d + 50 bc/d on 1/" from the Hangu fm, CCDC-29 rig. OGDC (op), partners Mari Petr. + Saif Egy.

Togh-1 nfw Kohat 3371-10 EL, Potwar Basin, TD 3,200m, gas-cond discovery, tested 12.7 MMcfg/d + 240 bc/d on 1/2” choke, WHFP 2,478 psi, from the Cret. Lumishwal fm, more recently 4.1 MMcfg/d + 50 bc/d on 1/" from the Hangu fm, CCDC-29 rig. OGDC (op), partners Mari Petr. + Saif Egy.

On 1 December 2017, Chevron USA was officially awarded three Alaminos Canyon blocks: AC 647 (lease G36105), AC 814 (G36109) and AC 858 (G36111), located in the Burgos-Rio Grande and East Texas Coastal basins. All three blocks were originally offered as part of Western Gulf of Mexico Lease Sale 249, which was held on 16 August 2017. AC 647 and AC 814 are expected to expire on 30 November 2027, with AC 858 due to expire on 30 November 2024. Following official award, Chevron USA is now the operator and sole interest-holder (100% WI + Op) in AC 647, AC 814 and AC 858.

Not Found

Pan Orient suspended an exploration well, L53 BB1 under the Phase 2 exploration drilling campaign in the L53/48 Reserve Area A, onshore Chao Phraya Basin, on 7 February 2020. Located approximately 1.1 km west of the L53-DD well pad, the BB (DD Ridge) prospect was targeting oil within the Lower Miocene Series reservoirs. After setting a casing in a pilot hole at a depth of approximately 150 m, the operator decided to reinforce the L53 BB well pad. The strengthening work is expected to be completed within two weeks. Spudded on 4 February 2020, the L53 BB1 is the first exploration well drilled under the Phase 2 exploration drilling program which consists of five exploration wells and one appraisal well. The “E-05” land rig has been moved to the L53 AA well pad to drill the next exploration wells. The L53-BB1 well will resume drilling after the L53-AA2 and L53-AA1 exploration wells are completed. Earlier in November 2019, the operator completed the Phase 1 drilling program which consisted of L53 DD5 (and its sidetrack) and L53 DD6 (and its sidetrack) wells. The L53 DD5 ST1 well discovered oil, had undergone a 90 days production test and currently waiting for environmental and production license approvals from the DMF. The L53 DD6ST1 well only encountered a sub-commercial oil discovery. The L53/48 concession is fully owned and operated by Pan Orient (Siam) Ltd, which is in turn controlled by Pan Orient Energy Corp (50.01%) and Sea Oil Public Company (49.99%). The exploration Area A and B will expire in January 2021, after which the production areas (A, B, D, G and DD) will be retained. Background Information The L53/48 block lies onshore in the Kamphaeng Saen area of the Chao Phraya Basin, around 50km WNW of Bangkok. The area is covered by at least 580 sq km of 3D seismic data which were acquired since 2007. Eight minor oil discoveries were encountered from 2009 to 2019. As of early 2020, a total of five fields are producing (L53-A, L53-G, L53-D East, L53-DD and L53-B) and another two fields are appraising (L53-D and L53-D C-EXT). L53-AA South field has been temporarily shut-in while waiting for environmental and production license approvals. The oils were trapped in the Lower to Middle Miocene structural play which was sealed by Middle Miocene Series mudstone. The original 3,997 sq km L53/48 block was awarded to Pan Orient Energy on 8 January 2007 as the operator and sole interest holder, under the 19th Licensing Round. The concession agreement allows Pan Orient to explore for hydrocarbons over a period of six years with a minimum three years first phase commitment of approximately US$ 2.1 million, which includes 3D seismic acquisition and two exploratory wells.

an Orient suspended an exploration well, L53 BB1 under the Phase 2 exploration drilling campaign in the L53/48 Reserve Area A, onshore Chao Phraya Basin,Results n/a.

Industry press reports suggest that ExxonMobil has opened a data room for the sale of its entire NCS assets (preferably as one package) – some 35 licences which contain over 30 fields and discoveries, 20 of which are producing (Asgard, Fram, Fram H-North, Grane, Gungne, Kristin, Mikkel, Ormen Lange, Sigyn, Sleipner East and West, Snorre, Statfjord, Statfjord East, Statfjord North, Svalin, Sygna, Tordis, Tyrihans and Vigdis). ExxonMobil’s 2017 production reached 170,000 boe/d and its assets are estimated to be worth around USD 3 billion. It is understood that ExxonMobil will use the proceeds of the sale to fund its activities in high growth areas such as Guyana, Papua New Guinea, Brazil and Mozambique. The company will be aiming to strike a deal by the end of 2019 with transfers taking place in 2020 following government approvals. ExxonMobil entered Norway at the very beginning of the industry there, being awarded PL 001 in 1965. In 2017 it transferred its Norwegian operated upstream business to Point Resources (now Var Energi). The sale to Point Resources included the transfer of the majority of ExxonMobil’s E&P staff in Norway, the company’s operated interests in the producing Balder, Ringhorne and Ringhorne East fields, the partially developed Forseti field, the Jotun unit and adjacent exploration licences with remaining prospectivity, field assets including platforms and FPSOs and the company’s office building near Stavanger. It resulted in the Point Resources portfolio containing reserves and contingent resources of approximately 350 MMboe and production of approximately 50,000 boe/d.

Industry press reports suggest that ExxonMobil has opened a data room for the sale of its entire NCS assets (preferably as one package) – some 35 licences which contain over 30 fields and discoveries, 20 of which are producing (Asgard, Fram, Fram H-North, Grane, Gungne, Kristin, Mikkel, Ormen Lange, Sigyn, Sleipner East and West, Snorre, Statfjord, Statfjord East, Statfjord North, Svalin, Sygna, Tordis, Tyrihans and Vigdis). ExxonMobil’s 2017 production reached 170,000 boe/d and its assets are estimated to be worth around USD 3 billion.

Terra Nova and Holloman are looking to reduce their combined 100% in PEL 112 + 444, total 2,150 sq km in the Cooper-Eromanga. Upwards of 80% is available, and a full sale would imply an Australian exit for both. Currently Terra Nova (op) 51.5%, Holloman 48.5%. Terra Nova contact Istvan Gyorfi, [email protected].

Terra Nova and Holloman are looking to reduce their combined 100% in PEL 112 + 444, total 2,150 sq km in the Cooper-Eromanga. Upwards of 80% is available, and a full sale would imply an Australian exit for both. Currently Terra Nova (op) 51.5%, Holloman 48.5%.

MOL used the “Deepsea Bergen” S/S to drill an exploration well on its Evra and Iving prospects in PL 820 S located between the Jette and Ringhorne fields. 25/8-19 S was spudded on 2 November 2019 and TD was planned at 2,713 m (2,573 m TVD). Potential recoverable reserves are 181 MMboe (source: Lundin, October 2019). Evra is an injectite prospect, with remobilised Paleocene Hermod Sandstones expected in the Eocene Hordaland Group. Two sand bodies were expected – one at 1,783 m and the other at 2,023 m. The main objective for the Iving prospect (four-way closure at the BCU) was the Lower Jurassic Statfjord Formation at 2,207 m. There are also further targets in the Paleocene Ty Formation, the Triassic Skagerrak Formation and the Basement. The drilling plan called for a sidetrack (targeting Evra only with a planned TD of 2,104 m / 2,000 m TVD) if the well made a discovery at Evra and, on 23 December 2019, MOL is preparing for 25/8-19 A. PL 820 S contains the 2001 dry hole 25/8-13 which was drilled by Esso. Good reservoir sands were present in both the Ty Formation and the Statfjord Formation, although both were water-bearing. MOL Norge AS operates PL 820 S with a 40% interest. It is partnered by Lundin Norway AS (40%), Pandion Energy AS (10%) and Wintershall Dea Norge AS (10%).

025/08-19 S (Evra/Ivring) expl. (MOL 40% op, Lundin 40%, Pandion 10%, Wintershall Dea10%),1st well in PL 820 S, location between Jette + Ringhorne fields, WD=125m, industry rumours suggest a positive outcome.

On 31 January 2020, Total is understood to have taken over as operator of the Orange Sub-basin Block 5/6/7. Total was expected to operate the acreage in accordance with the deal between Occidental and Total announced on 5 May 2019 (See: Anadarko Petroleum Corp to be acquired by Occidental (Total will take Anadarko's African assets). Block 5/6/7: covers some 73,000 sq km primarily atop the Orange Sub-basin in water ranging between 150 m and 4,000 m. Total operates the tract with a 40% stake, Shell holds a 40% stake and PetroSA holds the remaining 20% stake. At the time of writing Petroleum Geo-Services ASA (PGS) was acquiring 3D seismic data atop Block 5/6/7.

Total is understood to have taken over as operator of the Orange Sub-basin Block 5/6/7. Total was expected to operate the acreage in accordance with the deal between Occidental and Total5/6/7

Sinopec – Xibei achieved commercial oil and gas in Shunbei field in the Tarim Basin. Shunbei 1-10H, a horizontal development well, is located in Shunbei 1 discovery and tested 860 b/d of oil and 2 MMcf/d of gas. The well has a TD of 7,768 m, the deepest well with oil and gas flow so far in the field. In 2015 Sinopec made a discovery of Shunbei in the Shuntuoguole North block when Shunbei 1 tested 45.4 Mscfg/d from an interval between 7,269 and 7,407 m in the Ordovician. Shunbei field is a marine carbonate field with reservoir buried deeper than 7,300 m. The field could hold geological resources of 8.5 bn bbl of oil and 17.6 Tcf of gas in place. In 2015 Sinopec made success in Shunbei 1-1H. The well tested 887 b/d of oil and 911 Mcf/d of gas through a 4 mm choke in the Ordovician. Following success of Shunbei 1-1H, Sinopec planned six development wells, including Shunbei 1-2H/1-3H/1-4H/1-5H/1-6H, and one exploration well Shunbei 2.  By mid-2016, all six wells completed and achieved oil flow with a rate of over 700 b/d of oil/per well. PetroChina reported in 2016 that Shunbei field, a large commercial field, has been confirmed. Sinopec started development of Shunbei 1 in early 2016 and plans to build Shunbei block with production capacity of 30,000 b/d of oil by 2020. During 2016 Sinopec has put seven producers on stream, with production capacity of 3,700 b/d of oil. In 2016 Sinopec also drilled another exploration well in the west of Shunbei 1 discovery, Shunbei 5 with a PTD of 7,546 m, in the block and the well tested 1,116 b/d of oil and 268 Mcf/d of gas in late July 2017. In 2017 PetroChina also tested oil and gas in Shunbei 3 in the field. In 2017, Sinopec – Xibei spudded a record ultra-deep exploration in the Tarim Basin. Shunbei 9, located in the Suntuoguole North block, has a PTD of 8,593 m with objective in the Ordovician. In 2018 Sinopec tested oil flow in Shunbei 7, which flowed 137 b/d of oil from the Ordovician Formation. This exploration well is located in in Shunbei 7 fault belt in the Suntuoguole North block, the well was spudded in April 2017 with a PTD of 8,029 m. Sinopec set a field development plan on Shunbei 1 area of the Shunbei field in 2017 that is to build up a 20,000 b/d of oil and 26 MMcf/d of gas production capacity by tapping 470 MMbbl of oil in place in this area by 2020. The plan includes to put 40-60 new wells plus 20 existing wells on stream with single well rate about 330 b/d.  

Sinopec – Xibei achieved commercial oil and gas in Shunbei field in the Tarim Basin. Shunbei 1-10H, a horizontal development well, is located in Shunbei 1 discovery and tested 860 b/d of oil and 2 MMcf/d of gas.

Murphy is reportedly looking into selling its remaining Asia-Pacific portfolio: - Brunei: Murphy partners deepwater blocks CA1 (Shell op) + CA2 (Petronas) with 8.05% + 30% resp. - Vietnam: operated blocks 15-1/05 + 144&145, the former containing the Lac Da Vang, Lac Da Nau + Lac Da Trang oil finds/fields. - Australia: operated AC/P57, AC/P58, AC/P59 + EPP43, and non-operated AC/P21 (Eni) and AC/P36 (Inpex). All lie off WA except EPP43, in the Bight.

Brunei, not found

Licensing authority is the Ministry of Petroleum.  Contracts are normally of concession type, but the Government of The Gambia is open to PSCs if so desired. Rights are normally granted for a six-year exploration period (+10 years) with the state having up to a 15% back-in right. Most of the terms and conditions under the Petroleum Act and Model Contract of 2004, amended in 2007, are negotiable. Licensing is to be through direct negotiations with the country's Petroleum Commission. Interested companies are invited to contact: Jerreh Barrow Commissioner for Petroleum Ministry of Petroleum & Energy Petroleum House Brusubi Roundabout Bijilo The Gambia Tel: +220 996 33 13 e-mail: [email protected]   The available blocks as of March 2018 are understood to be as listed below. Four blocks are available. There was no change in the list compared to the previous one. Total open acreage amounts to 14,176 sq km, of which 11,500 is onshore and 2,676 is offshore.   Open blocks       Block Name Area (sq km) Situation Block Basin Block A3 1,323  offshore Senegal (M.S.G.B.C.) Basin Block A6 1,353  offshore Senegal (M.S.G.B.C.) Basin Lower River 6,560  onshore Senegal (M.S.G.B.C.) Basin Upper River 4,940  onshore Senegal (M.S.G.B.C.) Basin            

Gambia, not found

PL 871 between Frigg and Froy, WD 109m, P&A’ing dry (traces of gas in the Frigg fm) at TD 2,125m (Balder), Transocean Arctic SS. Wellesley (op), partners Equinor + Lotos.

025/01-13 (Balcom) expl (Wellesley 60% op, Equinor 20% + Lotos 20%) in PL 871 between Frigg and Froy, P&A’ing dry (Early Eocene Frigg Fm was aquiferous with traces of gas in 10m net (50m gross) of good quality sst reservoir. 20m net (40m gross) of aquiferous Upper Balder Fm sst was also encountered at TD=2125m, WD=109m.

Ecuador's Hydrocarbons Minister, Carlos Perez, stated in early-mid April 2018, on the sidelines of the International Energy Forum, that the international arm ONGC Videsh of Indian oil-company ONGC is looking at purchasing a stake in oil fields in Ecuador and may participate in the upcoming Ronda Intracampos tender. He said, "We will be signing a confidentiality agreement with them in the following weeks and we will provide them with information in new blocks." ONGC is apparently looking for fields with a minimum 25,000 bo/d. ONGC Videsh Managing Director, Narendra K Verma stated, "We had a good meeting with Ecuador and we will explore the possibility of expanding our footprints in Ecuador. We are already present in Colombia." ONGC Videsh signed a strategic partnership agreement to form a joint Business Development Group with Chilean company GeoPark for activities in Latin America. ONGC may also invest in existing field joint ventures.Ecuador was originally planning to launch its Ronda Intracampos licensing round in March 2018, for eight blocks in the north east of the country in the Oriente-Maranon Basin, under a new contract model to attract investment in the country. This bid round is thought to be imminent. The blocks on offer will be carved out of state-owned Petroamazonas acreage and have thirteen undeveloped fields between them. The government has estimated around US$ 1.25 billion in investments are required for all of the blocks. On 13 March 2018, state-run Petroamazonas, with the support of the national government, hosted a presentation to launch the 'Ronda Oil & Gas 2018' auction for five fields under the new specific services contract model. These are unlikely to be of interest to ONGC as four of these are relatively small onshore oil fields with a low production rate and one is an offshore gas field.

Not Found

PA_1OGX119MA_PN-T-102, BT-PN-001 contract, PN-T-102 block, Parnaíba Basin, gas shows report to ANP on 11 Dec ’17. PTD is/was 2,178m, targets assumed Cabecas + Poti fm’s, Tuscany rig 120.

Brazil, BT-PN-001

In early April 2020, the Ukrainian Government published a list of blocks which will be auctioned during 2020. The list includes 23 blocks covering 3,691 sq km in Western Eastern and Southern Ukraine (Table 1). It is understood that auctions could be announced in April, June, September and November and any interested companies may submit applications during 90 days after the announcement. Table 1 Petroleum Province Sedimentary Basin Political Province Block Name Surface, sq km Resources and reserves, MMboe Starting Price, USD Eastern Ukraine Dnieper-Donets Chernihivska Opolonivska-2 231 4 8,300   Kharkivska Knyazhynska 75 587 14,356,500   Pechenizko-Kochetkivska 263 13 166,400     Saltivska 26 39 251,200   Poltavska Obolonska 496 427 n/a     Pysarivska-2 223   n/a   Sumska Surmachivska 1 2 45,600     Sumska and Kharkivska Filativska 372 3 n/a Southern Ukraine East European Platform Margin Odeska Izmailska 255 13 1,065,350       Kyslytska 371 7 781,200   North Caucasus Platform Zaporizka Pryazovske 348 22 809,300 Western Ukraine East European Platform Margin Chernivetska Tarashanska 255 8 645,800     Volynska Voynitska 157   148,400   North Carpathian Basin Chernivetska and Ivano-Frankivska Dykhtynetska 74 16-27 156,800   Ivano-Frankivska Kosmatska Skhidnyy 7 39 139,500   Lyubizhnyansko-Meryshorska 51 107 12,233,500   Lyuchkivsko-Berezivska 78 7 n/a   Rybnytska 148 1 n/a     Slyvkynska Pivdennyy 12 30 136,600   Lvivska Yavorivska 44 32-64 232,200     Monastyretske Pivdennyy 25   6,400     Lvivska and ivano-Frankivska Lysovytska 83 24 3,318,600   Pannonian Basin Zakarpatska Luchkivska 96 20 1,696,300

Ukraine (Carpathian Flysch Zone (North Carpathian B.)) Monastyretske Pivdennyy

BGM suspended with oil shows the 3-SDR-003-ES (3-BGM-003-ES) outpost in the ES-T-476 block in the onshore Espirito Santo Basin during late-November 2019 at an as yet unreported final total depth (TD). BGM filed an oil show report for the well with the ANP on 23 November 2019. The outpost was spudded on 5 November 2019. The well had a proposed total depth (PTD) of 1,000 m with the Early Cretaceous Sao Mateus and Mariricu formations as the primary targets. The well is located in the south-central area of the block approximately 260 m north-west of the 1-SDR-001-ES (1-BGM-001-ES) wildcat suspended by the operator. BGM Petroleo e Gas Ltda holds 100% working interest in the ANP Round 14, ES-T-476 contract.

3-SDR-003-ES (3-BGM-003-ES) BGM suspended with oil shows

Marcelo Mindlin's company, Petrolera Pampa, was reported in late May 2018 to have signed a contract for the 120 sq km Las Tacanas Norte Block, Neuquen Basin. The company was awarded the license in November 2017 after the Neuquen V Ronda bid. Petrolera Pampa will invest US$ 207 million and the 4 year contract plan calls for the drilling of eight wells to the Vaca Muerta Shale. The project also includes seismic registration, geophysical and geochemical works. The total commitment is 41,414 WU. The block is next to the El Mangrullo license, also operated by Petrolera Pampa.

Marcelo Mindlin's company, Petrolera Pampa, was reported in late May 2018 to have signed a contract for the 120 sq km Las Tacanas Norte Block, Neuquen Basin. The company was awarded the license in November 2017 after the Neuquen V Ronda bid. Petrolera Pampa will invest US$ 207 million and the 4 year contract plan calls for the drilling of eight wells to the Vaca Muerta Shale. The project also includes seismic registration, geophysical and geochemical works. The total commitment is 41,414 WU. The block is next to the El Mangrullo license, also operated by Petrolera Pampa.

Cairn confirmed on 10 March 2020 that the sale of its wholly-owned subsidiary Capricorn Norge AS was completed in late February 2020 (financially effective from 1 January 2020). The company announced in November 2019 that it was selling the subsidiary to Solveig Gas Norway AS for the sum of USD 100 million. At the turn of 2019 / 2020 Solveig was re-named Sval Energi. In February 2020 Capricorn held interests in 15 licences in Norway and operated three of these. It was then awarded a further three licences (all operated) in March 2020 under APA 2019. The licences include two small discoveries (Agat, Jette) and the Nova field which is under development and due onstream in Q3 2021. Capricorn drilled its first two operated wells on the NCS in 2019 – both were dry holes. A well is also planned in 2020 on the Duncan prospect. The company was pre-qualified as an operator in Norway in late 2015 and in February 2016 it was awarded its first licence. Cairn will use the proceeds of the sale to support its ongoing business (which includes assets in the UK). Sval Energi, established in 2011, was acquired in 2019 by HitecVision. It is a significant owner in Gassled (15.55%) and has recently been involved in deals to acquire interests in Polarled and Duva. Its strategy is to become an integrated, infrastructure-based E&P operating company. Capricorn's first NCS operated well was 6508/1-3 which targeted the Lynghaug prospect in PL 758. A 170 m section of Are Formation (the primary objective) was encountered with around 50 m of net sandstone interbedded with claystones and coals. Failure was put down to migration. If it had been successful it would have been a play opener for the Nordland Ridge and could have been developed as a tie-back to the Norne FPSO. Pre-drill reserves estimates were 70 MMboe. Its second well, 6608/11-9, was drilled on the Godalen prospect in PL 842. Godalen had an Upper Jurassic Rogn Formation objective with potential to contain 90 MMboe and could also have been tied-back to Norne in the event of a discovery. The Rogn Formation was absent, although there were some sands (total 40 m) in the Upper Jurassic Melke Formation (118 m total section). Nova was previously called Skarfjell and was discovered in 2012 by 35/9-7. Its reservoir is the Upper Jurassic Heather Formation. The discovery was appraised over the following year and the PDO was submitted in May 2018 (and received approval four months later). Operator Wintershall Dea intends to recover 77 MMboe from the field over an eight-year period using two 4-slot subsea templates (installed in May 2019) sited one kilometre apart (the northerly template will host three water injectors and the southerly one will have three producers). The templates will be tied back to Gjoa which lies approximately 16 km to the northeast. There is also provision for a third template with four more wells if needed. Gjoa will supply Nova with power (from shore), gas lift and water injection. Drilling of six wells will commence in H1 2020 and the installation of the other facilities will take place in 2019 / 2020. A new topsides module will be installed at Gjoa in May 2020 where processing will take place prior to export via the Troll oil pipeline to Mongstad. Maximum production is expected to be 50,000 boe/d and investment is estimated at NOK 9.9 billion (USD 1.23 billion). The field consists of three segments and the initial development relates solely to Nova Main, with the Southeast and East segments representing future upside potential.

Cairn Energy plc, Solveig Gas Norway AS, Sval Energi AS Sale of Capricorn Norge AS completed

Neptune spudded Dugong prospect exploration well 34/4-15 S using the “Deepsea Yantai” S/S on 18 June 2020. The prospect lies in PL 882, approximately 9 km northwest of Snorre B. The well’s objectives are the Upper Jurassic Intra-Draupne Formation and the Middle Jurassic Brent Group. Neptune confirmed on 3 July 2020 that hydrocarbons have been found in the reservoir which lies between 3,250 m and 3,400 m. The well will be cored and a contingent down-dip appraisal sidetrack is likely. The TD of 34/4-15 S is planned at 3,740 m (3,647 m TVD). According to partner Petrolia, potential pre-drill recoverable resources were 86 MMboe. The PDO for Equinor’s Snorre Expansion Project (Snorre 2040) was approved in July 2018. The project aims to increase the field’s recovery rate from 46% to 51% by producing a further 195 MMbo and extending field life beyond 2040. At a total estimated cost of NOK 19.3 billion (USD 2.31 billion) the development includes six subsea templates each with four wells. Of the 24 new wells half will be producers and the other half will be used for alternating water and gas injection. The templates will be tied back to Snorre A where upgrades will take place (to receive production and provide injection gas and water). First oil is expected in Q1 2021. PL 882 is operated by Neptune Energy Norge AS with 40%. Concedo ASA, Idemitsu Petroleum Norge AS and Petrolia NOCO AS are partners, holding 20% each.

Norway (Viking Graben Province), 34/4-15 S (Dugong) explo well, in PL 882, op. by Neptune (40%), CONCEDO (20%), IDEMITSU (20%), PETROLIA (20%). Neptune confirmed on 3 July 2020 that hydrocarbons have been found in the reservoir which lies between 3,250 m and 3,400 m. The well will be cored and a contingent down-dip appraisal sidetrack is likely. The TD of 34/4-15 S is planned at 3,740 m (3,647 m TVD).

On 12 June 2020, the Office National des Hydrocarbures et des Mines (ONHYM) officially announced the contract signature for the Mesorif reconnaissance licence with ConocoPhillips Morocco Ventures Ltd (ConocoPhillips), northern onshore Morocco. ConocoPhillips is the Operator of the two-year contract with 75% working interest, partnering ONHYM with carried 25%. The Operators' main commitments will consist of the achievement of geological and geophysical studies, and the acquisition of 2D seismic data during the second year of the licence. Phillips drilled some wells in the '80s both offshore and onshore Morocco, in Essaouira and Guercif basins.

ONHYM officially announced the contract signature for the Mesorif reconnaissance licence with ConocoPhillips (75% op, ONHYM 25%) northern onshore Morocco. The Operators' main commitments will consist of the achievement of g&g studies, and the acquisition of 2D seismic data during the second year of the licence.

Pande-Temane field/block, onshore Mozambique Basin, drilled 31 Dec ’17 – 11 Jan ’18, TD 1,765m. Targets Grudja G.10, 11 + 11a, some gas encountered, testing required. Rig to Pande-26 appr, spudded 6 Feb, intended as a future producer. Sasol (op), partners IFC + ENH.

Pande-Temane field/block, onshore Mozambique Basin, drilled 31 Dec ’17 – 11 Jan ’18, TD 1,765m. Targets Grudja G.10, 11 + 11a, some gas encountered, testing required.

The OGA has approved UJO’s 16.665% farmin to PEDL 183,  703 sq km on the N. coast of the Humber Estuary in E. Yorkshire and home to West Newton A-1 gas find. An appraisal is planned 1Q ’19. Partners are therefore now Rathlin (op), Humber O&G + UJO.

United Kingdom, PEDL 183

Without providing more details, the country’s Minister of Petroleum has reported that the DPOC recently made an oil discovery in the Palogue area (Block 7E) of the Upper Nile region, to be brought on production soon. DPOC (op), partners Petronas, CNPC, Nilepet, Sinopec and Tri-Ocean.

Without providing more details, the country’s Minister of Petroleum has reported that the DPOC recently made an oil discovery in the Palogue area (Block 7E) of the Upper Nile region, to be brought on production soon. DPOC (op), partners Petronas, CNPC, Nilepet, Sinopec and Tri-Ocean.

Husky has contracted COSL’s HYSY 981 SS for up to 10 wells (3 firm + 7 contingent) in the Liuhua 29-1 deepwater gasfield in block 29/26, WD 640 to 790m in the S. China Sea. Ops could start late 2018 – early 2019. Gas will be tied into the Liwan subsea facilities as of lateish 2020.

Hai Yang Shi You 981 for Liuhua

On 19 November 2019, Nostra Terra Inc. (NTI), a wholly owned subsidiary of North Terra Oil and Gas Company plc, has settled a conditional agreement with North Petroleum International Co. (North Petroleum) regarding Egypt’s East Ghazalat concession, Abu Gharadiq Basin. Under this agreement, NTI will transfer its 50% participating interest in the concession to North Petroleum, the concession’s operator, with provision for the conclusion of the arbitration and no further cash calls or liabilities for any past losses, including the amounts for the payment of November and December 2015 cash calls and interest. Matt Lofgran, Nostra Terra CEO said “I am very pleased that NTI has reached this agreement with North Petroleum, which sees Nostra Terra effect a clean exit from this non-core concession. Following the arbitration NTI had the option to pay past cash calls and continue with the asset. However, we have taken the view that because the asset is loss-making and given we are not the operator, despite the fact that we feel that we could improve operations significantly, ultimately the best resolution is for NTI to transfer its interest and have no past or future liability”. The agreement will be finalized under the condition of having the necessary formal approvals from the Egyptian government. However, if these approvals are not granted by December 31, 2019, North Petroleum will have the right to terminate the agreement provided that the obligatory termination notice is served on or before April 30, 2020. The East Ghazalat concession is operated by PetroSafwa, a JV between EGPC (50%), North Petroleum (25%) and Nostra Terra (25%). The contract includes two blocks, Safwa (Dev) and North Dabaa (Dev), both granted to PetroSafwa in 2011 and 2014, respectively. The Safwa (Dev) block comprises the Safwa oil field discovered in 2010, and the North Dabaa (Dev) includes the Dabaa North 1 gas discovery found in 2013.

Nostra Terra has reached a conditional agreement with North Petroleum under which it will transfer its 50% interest in the East Ghazalat concession to operator North, thereby ensuring its withdrawal.

Tigana oilfield in NE sector of LLA 34, Llanos Basin, TD 3,575m, test on ESP gauged ab. 1,900 b/d of 14.1 API oil on 34/64” choke from the Guadalupe fm, WHP 178 psi. The well is on stream and has been followed by the spudding of Tigana N.-5 aiming further downdip of Tigana N.-4.  

Colombia (Llanos-Barinas B.) ? op. by WINCHESTER (45.0%, PAREX 55.0%) in LLA 34 block

Cairn (through its subsidiary Capricorn) announced on 6 August 2019 that it had sold 10% of its interest in the Nova field to ONE-Dyas for the sum of USD 59.5 million. The field, currently under development with first oil due in September 2021, is covered by PL 378, PL 418 and PL 418 B. The deal sees ONE-Dyas take a 12.12% interest in PL 378 and 10% in both PL 418 and PL 418 B. Cairn stated that it will use the proceeds of the sale to fund exploration and development activities across its group portfolio. The deal was confirmed as complete on 4 December 2019 and is effective from 29 November 2019. Nova was previously called Skarfjell and was discovered in 2012 by 35/9-7. Its reservoir is the Upper Jurassic Heather Formation. The discovery was appraised over the following year and the PDO was submitted in May 2018 (and received approval four months later). Operator Wintershall Dea intends to recover 77 MMboe from the field over an eight-year period using two 4-slot subsea templates (installed in May 2019) sited one kilometre apart (the northerly template will host three water injectors and the southerly one will have three producers). The templates will be tied back to Gjoa which lies approximately 16 km to the northeast. There is also provision for a third template with four more wells if needed. Gjoa will supply Nova with power (from shore), gas lift and water injection. Drilling of six wells will commence in H1 2020 and the installation of the other facilities will take place in 2019 / 2020. A new topsides module will be installed at Gjoa in May 2020 where processing will take place prior to export via the Troll oil pipeline to Mongstad. Maximum production is expected to be 50,000 boe/d and investment is estimated at NOK 9.9 billion (USD 1.23 billion). The field consists of three segments and the initial development relates solely to Nova Main, with the Southeast and East segments representing future upside potential. Upon completion of the deal, interest in PL 378 is divided between Wintershall Dea Norge AS (75.76% + operator), Cairn through Capricorn Norge AS (12.12%) and ONE-Dyas Norge AS (12.12%) and interest in PL 418 and PL 418 B is held by Wintershall Dea Norge AS (45% + operator), Spirit Energy Norway AS (20%), Edison Norge AS (15%), Cairn through Capricorn Norge AS (10%) and ONE-Dyas Norge AS (10%).

Cairn (through its subsidiary Capricorn) announced on 6 August 2019 that it had sold 10% of its interest in the Nova field to ONE-Dyas for the sum of USD 59.5 million.

Block 6, South Oman Salt sub-basin drilled + susp 19-29 Oct ’19, TD 1,844m.

Waha NE-1 explWaha Block 6, South Oman Salt sub-basin drilled + susp 19-29 Oct ’19, TD 1,844m.

It has been reported that INEOS is in talks to acquire ConocoPhillips’ UK oil and gas portfolio. The latter holds interests in a number of producing fields throughout the UK, across the West of Shetlands, Northern North Sea, Moray Firth, Central North Sea, East Irish Sea and Southern North Sea. ConocoPhillips has also recently been drilling an infill exploration well at its Jasmine field. The potential deal has been rumoured to be worth upwards of GBP 3 billion and the companies have reportedly signed a three month exclusivity agreement.

It has been reported that INEOS is in talks to acquire ConocoPhillips’ UK oil and gas portfolio. The latter holds interests in a number of producing fields throughout the UK, across the West of Shetlands, Northern North Sea, Moray Firth, Central North Sea, East Irish Sea and Southern North Sea

Tata Petrodyne has reportedly been acquired by Chennai-based Invenire Energy Pvt Ltd for USD 100 MM.  Tata Petrodyne is now understood to be operating as a subsidiary of Invenire, the DGH having cleared the transfer of blocks. These comprise CY-OS-90/1 (PY-3 field), CB-OS/2, CB-OS/1 + PR-OSN-2004/1 in India, as well as sundry holdings in Tanzania and Indonesia. Of note, CB-OS/1 and PR-OSN-2004/1 are relinquished / proposed for relinquishment.

Tata Petrodyne has reportedly been acquired by Chennai-based Invenire Energy Pvt Ltd for USD 100 MM. Tata Petrodyne is now understood to be operating as a subsidiary of Invenire, the DGH having cleared the transfer of blocks. These comprise CY-OS-90/1 (PY-3 field), CB-OS/2, CB-OS/1 + PR-OSN-2004/1 in India, as well as sundry holdings in Tanzania and Indonesia.

Magellan play in Eastern offshore block 5, 1st of 3 commitment wells planned in 2H ’18 (spudded 12 Jun), gas discovery, Deepwater Invictus DS then to Bongos-1 off NE Trinidad.

Victoria 1 (BHP 65% op, Shell 35%) in block TTDAA 5, gas disc. (adds to BHP’s 2016 LeClerc Miocene-aged natural gas find).

OKE is understood to have signed a farmout deal to Shell and Kosmos for the later to each acquire a 45% stake in the 6,930-sq km area in the Orange Basin. Partnership therefore becomes Shell (op) 45%, Kosmos 45% + OKE 10%. The farmins coincide with the renewal of the contract term into phase 2 along with a part-relinquishment.

OKE is understood to have signed a farmout deal to Shell and Kosmos for the later to each acquire a 45% stake in the 6,930-sq km area in the Orange Basin. Partnership therefore becomes Shell (op) 45%, Kosmos 45% + OKE 10%.

BP announced on 3 July 2018 that it has agreed to acquire a 16.5% interest in the Clair field located in the West of Shetlands from ConocoPhillips. BP will acquire a ConocoPhillips subsidiary which holds a 16.5% interest in the BP operated Clair field, with ConocoPhillips retaining a 7.5% interest. BP also announced that it has entered into agreements with ConocoPhillips to sell its entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska as well as its 38% holding in the Kuparuk Transportation Company. Details of the transactions are not being disclosed, excluding customary adjustments. The transactions are expected to be cash neutral for the both companies and complete simultaneously during 2018. Both deals are subject to regulatory approvals and the effective date for the transaction will be 1 July 2018. Clair was discovered in 1977 by exploration well 206/8-1A, which penetrated a 586m oil column in a thick (>700m) sequence of Devonian to Carboniferous continental sandstones overlying Proterozoic basement. Clair was developed using a phased approach. Clair Phase 1 was sanctioned in 2001 and focused on the Core, Graben and Horst reservoir areas targeting an estimated recoverable resource of 300 million barrels. First production was achieved in February 2005 and Clair was developed via the first fixed offshore facility in the West of Shetlands. Oil and gas was exported via pipelines to the Sullom Voe Terminal on the Shetland Islands. The second phase of development, the Clair Ridge Project is designed to have a capacity of 120,000 barrels of oil and 100 million cubic feet of gas per day. The phase targets 640 million barrels of recoverable resources and is expected to produce through to 2050. In 2016, the construction and installation of two new bridge-linked platforms was completed. Hook-up and commissioning is under way with first oil expected in 2018.     Following completion of the deal interest in Clair will be held by BP Exploration Operating Co Ltd (44.13% + operator), Chevron North Sea Ltd (19.42%), Enterprise Oil Ltd (18.68%), Shell Clair UK Ltd (9.29%), ConocoPhillips (UK) Ltd (7.5%) and Britoil Ltd (0.98%).

BP will increase its stake in the Clair oilfield through an asset swap with ConocoPhillips. BP will acquire from an additional 16,5% interest in the field (-> 45,1% op.). ConocoPhillips will keep a 7,5% interest. For its part, ConocoPhillips will acquire BP's entire 39,2% interest (-> 94,68% op.) in the Greater Kuparuk Area on the Alaska North Slope and stake in the Kuparuk Transportation Company.

Al-Haj Group of Co’s, so far sole owner of the Baska North 3169-4 EL,  2,460 sq km in the Khyber Pakhtunkhwa province, has assigned a 4.15% interest in the 2,460-sq km block to Govt Holding Pvt Ltd (GHPL) retro-effective to 2015.

Al-Haj Group of Co’s, so far sole owner of the Baska North 3169-4 EL, 2,460 sq km in the Khyber Pakhtunkhwa province, has assigned a 4.15% interest in the 2,460-sq km block to Govt Holding Pvt Ltd (GHPL) retro-effective to 2015.

Equinor has acquired 10% from Spirit Energy in Norwegian Sea licences PL644 and PL644 B, effective from 31 August 2018. PL664 B contains the Hades/Iris discovery made by 6506/11-10 (2018, OMV, 4,536m) which encountered a 35m gas & condensate column in the primary targeted Early Cretaceous Lange Formation (Hades) and a 95m gas & condensate column of secondary targeted Middle Jurassic Garn Formation (Iris). Hades/Iris has estimated gross contingent resources of 63-210-322 MMboe (1C-2C-3C) with 75% gas and 25% condensate. PL644 B covers 27.5 sq km in Norwegian Sea block 6506/11, 8km N of Equinor-operated Morvin oil and gas field. PL644 B was awarded on 19 January 2016 as part of APA2015 and is an auxiliary licence to PL644 which lies adjacent to the W. PL644 cover a combined area of 303 sq km in blocks 6506/8, 10 & 11 and was awarded on 3 February 2012 under APA2011. In June 2016, Repsol (20%) exited PL644/B to Skagen44 and in December 2016 Statoil picked up Skagen44's 30% stake. Current equity partners are OMV (Norge) AS (30% + Op), Equinor Energy AS (40%), Faroe Petroleum Norge AS (20%), and Spirit Energy Norge AS (10%).

Norway (Voring) Equinor (->40%, OMV 30% Op, Faroe 20%) has acquired 10% from Spirit Energy (->10%) in licences PL 644 and 644 B.

Inpex has been awarded WA-533-P over 12,402 sq km in WD 50-600m, offshore Canning Basin, offered in the 2016 block release as W16-6. Commitments include G&G, and one well by March 2024.

Brazil (Ceara B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: BAR-M-344 op. by SHELL (50.0%, PETROBRAS 40.0%, PETROGAL 10.0%) to be check.FZA-M-057 op. by TOTAL (40.0%, PETROBRAS 30.0%, BP 30.0%) to be check.BAR-M-344 op. by SHELL (50.0%, PETROBRAS 40.0%, PETROGAL 10.0%) to be check.

Malleswaram ML, onshore KG Basin, tested 1.06 MMcfg/d + 40.8 bc/d, no further details.

Suryaraopeta W.-1 in Malleswaram ML, onshore KG Basin, tested 1.06 MMcfg/d + 40.8 bc/d, no further details.

On 1 November 2017, Shell Offshore was awarded two Alaminos Canyon blocks: AC 685 (G36106) and AC 729 (G36107), situated in the Burgos-Rio Grande and East Texas Coastal basins. Both blocks were originally offered as part of Western Gulf of Mexico Lease Sale 249, held on 16 August 2017, and are expected to expire on 31 October 2027. Following official award, Shell Offshore is now the operator and sole interest-holder (100% WI + Op) in AC 685 & AC 729.

Not Found

An auction was held yesterday for the Obskoy Yuzhnyy block, 321 sq km in the Ob Estuary, W. Siberia. Gazprom Neft Shelf won the 30-year contract for USD 15.2 MM (starting price USD 2.3 MM).

Gazprom Neft Shelf won the Obskoy Yuzhnyy block, 321 sq km in the Ob Estuary.

Location near Al Ain, East Abu Dhabi Exploration Concession, TD 4,877m (Jurassic) in mid-Mar ’17, gas discovery, now suspended. OMV (op), partner ADNOC.

UAE, not found

The NPD confirmed on 19 December 2018 that the deal for Pandion to acquire 10% of Wintershall’s interest in PL 820 S (agreed on 15 August 2018) has now completed with effect from 14 December 2018 (the deal is financially effective from 1 January 2018). The licence lies between Balder / Ringhorne and Jotun and covers parts of blocks 25/7 and 25/8. The northerly section of the licence lies across the southwestern part of the Jette field (abandoned) and this section applies only below Base Pliocene (the southerly section applies to all levels). An exploration well is due to be drilled in PL 820 S in 2019. Aker BP’s Jette was discovered by 25/8-17 in 2009 and contained oil in a Paleocene Heimdal Formation reservoir. It was brought onto production in May 2013 via a subsea template tied into Jotun A (an FPSO). Jotun itself was expected to continue producing until 2021 but water-cut in 2015 was 97% and production from tied-in fields had been declining. Therefore, both Jotun and Jette came off production in December 2016. Development of Jette had been challenging since the beginning: problems with the first producer meant that the development plan was subsequently revised to consist of two (shorter than planned) horizontal producers on the southern segment (which was believed to contain recoverable reserves of 5-9 MMboe) rather than one long horizontal on each of the south and north segments as originally planned. Due to a number of issues, including higher than expected costs and the reduction in recoverable reserves, profitability at Jette was lower than Aker BP’s initial estimates. The problems continued into production, with total 2014 production being less than half that of the six months of 2013, and 2015 production being only half of 2014 volumes. The deadline for final disposal of the Jette field facilities has been delayed to the end of 2020. Initial plans were to complete the work by 2018, based on production from the field ceasing in January 2016. However, as production continued until December 2016 the timescale has changed. Work will begin on the removal of some of the seabed infrastructure in summer 2018 and permanent plugging and abandonment of the wells will now be completed by 2019, after which the main seabed structures will be removed. Following completion of the deal, interest in PL 820 S is held by MOL Norge AS (40% + operator), Lundin Norway AS (30%), Wintershall Norge AS (20%) and Pandion Energy AS (10%).

Pandion acquired 10% of Wintershall’s interest in PL 820 S. Following completion of the deal, interest in PL 820 S is held by MOL Norge AS (40% + operator), Lundin Norway AS (30%), Wintershall Norge AS (20%) and Pandion Energy AS (10%).

Deepwater West Cape Three Points block 2, reportedly light oil find at 3,323m, w.o. confirmation + details, Stena Forth DS. Target Cenomanian. To be followed by Oak-1.

Austria (Vienna B.) ? op. by OMV (100.0%, OMV 100.0%) in Block 2

On 28 April 2020, Chevron USA completed acquisition of 4.9506% WI in ten contiguous Kuparuk River Unit leases from operator ConocoPhillips Alaska. The ten leases include North Slope ADLs 390434, 390505, 390506, 390697, 391908, 391909, 392113, 392157, 392158, 393883 & 393884. The transaction is effective as of 1 February 2020. The leases are sited ~5km due north from Oil Search’s recent successful Mitquq 1 NFW, which spudded the well in ADL 393875 on 25 December 2019, with the "Nabors 7ES" rig and encountered 60m of hydrocarbon pay within the primary objective Nanushuk interval (separate from the Pikka Development Nanushuk reservoir) during January 2020, intersecting 5m of net gas pay and 55m of net oil pay. No oil-water contact was encountered. Mitquq 1 also encountered 16m of hydrocarbon pay in its secondary Alpine C target, after having been drilled to a TD of 2,472m, encompassing 10m of net oil pay and 6m of net gas pay. Following completion of the transaction, equity in the aforementioned ten leases is now shared between ConocoPhillips Alaska (95.0494% WI + Op) and Chevron USA (4.9506%).

Chevron USA completed acquisition of 4.9506% WI in ten contiguous Kuparuk River Unit leases from operator ConocoPhillips Alaska. The ten leases include North Slope ADLs 390434, 390505, 390506, 390697, 391908, 391909, 392113, 392157, 392158, 393883 & 393884.

The Chadian Chamber of Deputies voted and approved on 26 November 2019 the award of seven exploration blocks to the British Virgin Island-based Ewaah Investor Limited company. Awarded blocks are Eridis I, II, III, IV, V, VI and VII located in the remote Al Kufra (Erdis) Basin in the northern border with Libya and northeaster border with Sudan. The PSA was signed on 6 September 2019 according to which the firm will spend over USD 83 million in exploration activities. A signature bonus of USD 3.5 million is expected to be paid in the following 60 days after the delivery of the approved contract. Following the agreement terms, 16.5% and 5% royalty tax has been set for oil and gas production, respectively. The Chadian portion of the Al Kufra (Erdis) Basin is located in a remote and highly unexplored desert area. Not a single discovery has been made in this basin as of late 2019 with no wells drilled in the Chadian part. Six NFWs were spudded in the Libyan sector between 1978 and 2010 and three wells in Sudan between 2012 and 2014, all of them suspended and abandoned as dry or with oil shows. The best potential reservoirs would be the Upper Ordovician sandstones with the Silurian shales as best source and seal rocks. Development costs are expected to be high and there is no petroleum infrastructure in the area with no pipelines at least in the 500 km around.

Ewaah Investors, based in Dubai, was officialy awarded seven blocks in the Erdis Basin which cover a combined area of ~170000km².

In a press release dated 31 March 2020, Oil Search announced it had successfully flow tested the Nanushuk 0 reservoir in the Stirrup 1 well (API 501032080900) at lease ADL 392044 in the North Slope. The well intersected an oil column of 75 ft (23 m) and flowed at a stabilized rate of 3,520 bpd from a single stimulated zone. Logs and core were acquired before conducting the flow test. The well was spud on 27 January 2020. The Alaska Oil and Gas Conservation Commission approved permit 2191530 to drill the well on 18 December 2019. The company filed a Lease Plan of Operations Application with the Alaska Department of Natural Resources (DNR) on 29 September 2109, which was approved on 6 December 2019. The Stirrup prospect in the Horseshoe block is described as a direct analog to the Horseshoe #1 (API 501032075100) Nanushuk discovery well drilled about 7 mi (11 km) to the east in lease ADL 392048 by Armstrong in 2017, which encountered more than 150 ft (46 m) of net oil pay in several reservoirs. With a potential resource of 200 – 400 MMbo, a successful outcome could de-risk additional fairways that could lead to a stand-alone development. Oil Search has contracted the Doyon Arctic Fox rig to drill the well. The application calls for the drilling of one well from an ice pad located in Section 26 of U8N3E and the acquisition of a walkaway vertical seismic profile. The well will be drilled to a true vertical depth of 6,000 ft (1,829 m) or less. Keiran Wulff, Managing Director of Oil Search, said, "We are very encouraged by the success of our 2019/20 Alaskan exploration programme, with oil discovered in all three penetrations, at Mitquq 1 Mitquq 1 ST1 and Stirrup, and excellent flow rates achieved in the two well tests. We also discovered high quality oil in a deeper reservoir at Mitquq which was not tested. While further appraisal will be required, these new discoveries may represent low cost tie-back options to the proposed Pikka Unit Development and have the potential to create substantial long-term value for Oil search shareholders, as well as having positive implications for the prospectivity of our acreage."

United States (Fish Creek Platform (North Slope B.)) Horseshoe

Oil was discovered in new-field wildcat G16783 4 S1B0 (Calpurnia), according to Anadarko in May 2017. The well is sited in Green Canyon Block GC 727 (G16783), situated in the East Texas Coastal Basin. G16783 4 ST1, which was drilled to final TD on 20 March 2017 encountered nearly 18m (~60 net feet) of oil pay in Miocene-aged sands. The well was spudded 7 March 2017, utilising the Diamond Offshore "Ocean Blackhornet" drillship. The Calpurnia well is expected to be tied back to one of Anadarko's nearby operated facilities in the Green Canyon protraction area. Equity in GC 727 is shared between Chevron USA (20.25% WI + Op), Statoil Gulf of Mexico (23.55%), Anadarko US Offshore (33.75%) and Shell Offshore (22.45%). Parent Company Anadarko Petroleum operates the lease.

GC 727 004S0B1 (Calpurnia) op. by Anadarko (33,75%, Statoil 23,55%, Shell 22,45%, Chevron 20,25%) in OCS lease G16783, 6m of net oil pay in the Miocene then 18m updip (subeco?).

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).

Commitment well in deepwater block 2, ops understood terminated around 8 Feb ’18, results yet n/a, Ocean Rig Poseidon DS now heading for Durban. Statoil (op), partner ExxonMobil.

Pilipili 1 op. by Statoil (65%, ExxonMobil 35%) in block 2, ops understood terminated, results yet n/a.

Block E, Bay of Gazimagusa off NE Cyprus, offshore Latakia Basin, WD ca. 250m, well suspended / concluded as Yavuz DS left location around 17 Sep ’19. PTD is/was 3,300m.

Karpaz 1 nfw (TPAO 100%) in Block E, Bay of Gazimagusa off NE Cyprus, offshore, WD ca. 250m, well suspended / concluded, PTD is/was 3300m.

Woodside was awarded the undrilled NT/P86 expl permit - originally offered as block NT17-1 in the 2017 Offshore Federal Acreage Re-release - on 16 Jul ’19 for a 6-year period. The block covers 8,340 sq km in the Bonaparte and Arafura-Money Shoal basins, adjacent to the Barossa and Caldita gas fields. Contract terms include 1,500 km 2D seismic, 1,000 sq km of 3D and further geotechnical studies.

Woodside was awarded exploration permit NT/P86.

Horizontal expl well near Hejiaping in the Hubei Province, S. Huangling Uplift, tested gas from the target Cambrian Niutitang fm, uncovering shale gas potential of the Upper Yangtze Platform, similar to last year’s E’Yiye-1 well (see DEA 10 Jul ’17). Details from GEPS.

China (Yishan Slope (Ordos B.)) Huangling (Changqing)

Aladdin is looking to dilute its 100% stake in explo licence M47-B1,B2,  305 sq km in SE Turkey. It contains the Basur-1 minor oil find. Contact Aladdin on tel +90 312 427 90 20.

Turkey, M47-B1,B2

Bass Oil has a HoA to acquire a 100% interest from Azipac in the North Madura PSC in coastal shallow waters off Java. Terms include drilling 1 firm well + 2 two contingent wells. The 626-sq km block contains the Reog prospect, a likely candidate for drilling.

Bass Oil has a HoA to acquire a 100% interest from Azipac in the North Madura PSC in coastal shallow waters off Java.

On May 29, Petrobras issued a press release indicating it completed the sale of its entire working interest in the Macau package of seven fields to SPE 3R Petroleum. The transaction concluded with SPE 3R Petroleum paying BRL 678.8 million (~USD 127.20 million, 1 USD = 5.34 BRL) to Petrobras. The seven production concessions include the Aratum, Lagoa Aroeira, Macau, Porto Carao, Salina Cristal, Sanhacu, and Serra. Petrobras held 100% working interest in all the production concessions, except the Sanhacu concession, in which Petrobras was the operator with 50% working interest. The remaining 50% working interest belongs to Petrogal Brasil S.A. Macau Package of fields Field Name Field sqkm Disc Date Year Cumul Gas Prod MMscf (2019) Cumul Oil Prod MMbbl (2019) Aratum 5.26 1982 944.53 5.26 Lagoa Aroeira 0.6 1989 58.72 0.81 Macau 2.5 1982 610.03 2.68 Porto Carao 0.9 1992 49.36 1.22 Salina Cristal 15.01 1987 11,909.99 27.08 Sanhacu 7.42 2007 11,959.05 0.40 Serra 3.3 1996 4,829.66 25.48 Source: IHS Markit © 2020 IHS Markit   Background Information On 30 March 2020, the ANP formally approved the sale and transfer of the entire working interest in the Macau package of seven fields from Petrobras to SPE 3R Petroleum. On 8 August 2019, Petrobras issued a press release indicating it signed the sales agreement with SPE 3R Petroleum SA for the Macau package of seven fields in the onshore Potiguar Basin. The terms of the deal were reported to be a total consideration of USD 191.1 million to be paid in two installments. The first installment of USD 48 million paid on signing date and the remainder of USD 143.1 million to be signed after formal approvals and transaction closing. On 22 September 2017, Petrobras issued a press release indicating that it is offering for potential sale and assignment 19 production concessions in five separate packages or poles onshore in the Potiguar and Sergipe-Alagoas basins.

Brazil (Potiguar B.) Macau op. by 3R PT (100%) Petrobras issued a press release indicating it signed the sales agreement with SPE 3R Petroleum SA for the Macau package of seven fields in the onshore, for US$191 MM. The seven production concessions include the Aratum, Lagoa Aroeira, Macau, Porto Carao, Salina Cristal, Sanhacu, and Serra.

Pluspetrol in late September 2018 tested oil on the Puesto Pinto Este a-1004 appraisal well on the CNQ-7/A Block, Neuquen Basin. 32 bo/d was tested from the Centenario psamites over 477.5/482.5m interval. The well was spud on 6 September and ended drilling on 10 September. The PTD of the well was 615m. and Venver was the drilling contractor. Pluspetrol operates the block with 50% and YPF holds a 50% interest also.

Argentina, CNQ-7/A

Tethys has fallen victim to partner pre-emption rights exercised in a block 53 transaction, namely the acquisition from Total of a 2% stake in the 694-sq km block 53 (Mukhaizna), onshore S. Oman Salt Basin. The block contains Mukhaizna, the single largest producing oilfield in Oman. Remaining partners Occidental (op), OOC, Indian Oil, Liwa Energy + Partex.

Tethys has fallen victim to partner pre-emption rights exercised in a block 53 transaction, namely the acquisition from Total of a 2% stake in the 694-sq km block 53 (Mukhaizna), onshore S. Oman Salt Basin. The block contains Mukhaizna, the single largest producing oilfield in Oman. Remaining partners Occidental (op), OOC, Indian Oil, Liwa Energy + Partex.

Only recently detailed, the Jan '20 award of the 243-sq km F4a explo licence to NAM (DEA 29 Jan '20) shows it is divided stratigraphically at the base Tertiary. F4a-deep is assigned to NAM (partner presumably EBN) and the shallower part to NAM and partners HALO, Neptune + EBN. The contracts run to 22 Jan '25 and call for a well by Jan '24.

(Central Graben Province) The 243-sq km F4a explo licence is divided stratigraphically at the base Tertiary. F4a-deep is assigned to NAM (partner presumably EBN) and the shallower part to NAM and partners HALO, Neptune + EBN.

In late May 2018, Shell suspended the Umbaraka North 2 outpost in the North Umbaraka block as a gas well after reaching a TD of 4,380 m. The well was spudded in early April 2018 with the Lower Paleozoic Shifah formation as the objective. Shell was awarded the North Umbaraka in July 2017 as part of the Egyptian General Petroleum Corporation (EGPC) 2016 bid round, with a commitment to spend USD 35.5 million. Background information In late March 2018, Shell suspended the Umbaraka North 1 wildcat in the North Umbaraka block as Shifah gas discovery after reaching a TD of 4,310 m. The well was spudded on 6 February 2018 with the “EDC-48” land rig. It has PTD of 4,250 m and the Lower Paleozoic Shifah formation as the objective.

Umbaraka North 1,2 (NUMB-1) in the North Umbaraka block, suspended as a gas discovery from Lower Paleozoic Shifah fm, TD=4310 m.

Parliament is expected to approve the Lease Agreement Hellenic Petroleum's onshore Arta-Preveza and NW Peloponnese blocks during February 2018. Hellenic signed the Lease Agreements with the Greek Government on 25 May 2017, following approval by the Court of Auditors. The blocks were pre-awarded to Hellenic as part of the Onshore Western Greece Tender in February 2016. Upon parliamentary ratification of the contracts, Hellenic will be given a three-phase, seven-year exploration term for each block, and has already indicated will consider farm-in offers from interested companies.

Parliament is expected to approve the Lease Agreement Hellenic Petroleum's onshore Arta-Preveza and NW Peloponnese blocks

Based on records from the Bureau of Ocean Energy Management (BOEM) Equinor has farmed in to the Repsol-operated Mollerussa prospect in the northwestern quadrant of the Walker Ridge (WR) protraction area of the deepwater central Gulf of Mexico, picking up a 20% stake. The four-block prospect covers WR 321 (G33964), WR 322 (G33965), WR 365 (G33967) and WR 366 (G33968).  The leases lie in a maximum water depth of 7,897 ft (2,407 m), about 183 mi (295 km) southeast of the onshore support base at Port Fourchon, Louisiana. While the BOEM approved Repsol's exploration plan N-9613 on WR 365 in 2015, no wells have been drilled on any of the Mollerussa blocks. Repsol has previously reported that the Paleogene prospect contains potential resource of 432 MMboe. Equinor's Paleogene-aged Monument prospect, which Repsol farmed in to in November 2019 with a 20% stake, is located about 19 mi (31 km) to the northwest and is due to spud soon. The nearest Paleogene production is at the ExxonMobil-operated Julia field approximately 16 mi (25 km) to the south. Repsol picked up the leases in a 60/40 partnership with Ecopetrol at Sale 213 held in March 2010, for a total of just over USD 15 million in high bids. Maersk also submitted sole bids for the four blocks, totaling just under USD 3 million. The current working interest ownership for the blocks is Repsol (40%), Ecopetrol (40%) and Equinor (20%). The leases expire in June 2020.

United States, not found

BGM suspended with oil shows the 1-SDR-001-ES (1-BGM-001-ES) new-field wildcat (NFW) in the ES-T-476 block in the onshore Espirito Santo Basin during late-June 2019.  The operator filed an oil show report with the ANP for the well on 17 June 2019. The NFW was spudded on 21 May 2019. The NFW had a proposed total depth (PTD) of 1,605 m with the Early Cretaceous Sao Mateus and Mariricu Formations as the primary target. The well is located in the south-central area of the block approximately 1.2 km south-west of the 1-LB-0001-ES wildcat plugged by Petrobras in 1973. BGM Petroleo e Gas Ltda holds 100% working interest in the ANP Round 14, ES-T-476 contract. On 6 December 2018, the ANP approved of Bertek divesting its 100% working interest in the ES-T-345 and ES-T-476 blocks in the onshore Espirito Santo Basin to newcomer BGM Petroleo e Gas Ltda.  On 29 January 2018, Bertek with 100% working interest was granted official awards by the ANP for the ES-T-345 and ES-T-476 blocks in the onshore Espirito Santo Basin from the ANP Round 14.  The company paid a total signature bonus of USD 153,312.30 for the two blocks and has work commitments of USD 551,735.02.  The blocks cover a total area of 46.14 sq km. The contract has one five-year exploration period and 7.5% royalties.  The rentals for the blocks are USD 14.15/sq km/year.  The local content is stipulated as 50% in the five-year exploration phase and in the development production phase is 50%.

1-SDR-001-ES (1-BGM-001-ES) nfw S-C part of ES-T-476, onshore Basin, oil shows report to ANP, suspended late June. PTD was 1,605m, target São Mateus and Mariricu fm’s.

Senegal round plans are firming-up, a presentation to this intent at Africa Oil Week. Nine blocks earmarked for offer (OUP-Nord 1-6, OUP-Sud, SOSP and SOSS). Two phases: phase 1 starts today with the media campaign, phase 2 Feb-Jul '20 with the block offer per se.

Senegal round plans are firming-up, a presentation to this intent at Africa Oil Week. Nine blocks earmarked for offer (OUP-Nord 1-6, OUP-Sud, SOSP and SOSS). Two phases: phase 1 starts today with the media campaign, phase 2 Feb-Jul '20 with the block offer per se.

As of 17 May 2018, Independent operator Paul L. Craig closed on a farm-out agreement in mid-November 2018 for the South Nanushuk prospect are in the National Petroleum Reserve-Alaska (NPR-A) and include AA-093747, AA-093748 and AA-093749. The total acreage included in the blocks is 35,425 acres (143.36 sq km). The acreage sets on trend south of the Horseshoe and Willow Nanushuk Formation oil discoveries drilled by Repsol and ConocoPhillips respectively. These discoveries were made in topsets of the west to east prograding clinoforms across the central North Slope. In August 2018, Independent operator Paul L. Craig and partners offered three blocks for sale or farm-out north of Umiat and west of Gubik fields. The three blocks called the The operator believes the Nanushuk clinoforms arc through the South Naunushuk prospect beginning south of Umiat Field and extend north though the Pikka Unit. The three tracts, include AA-093747, AA-093748 and AA-093749, were awarded from the NPR-A Sale 2013 for a bonus bid of USD 272,049 or USD 7.68 per acre. Partners in the tracts include Paul L. Craig 41.6667%, Peter G. Zamarello 50% and Paul Gardener 8.3333%. Contact information for Paul L. Craig 907-830-1151 or [email protected]

Paul L. Craig closed on a farm-out agreement in mid-November 2018 for the South Nanushuk prospect are in the National Petroleum Reserve-Alaska (NPR-A) and include AA-093747, AA-093748 and AA-093749. The total acreage included in the blocks is 35,425 acres (143.36 sq km).

Kadi ML, onshore Cambay Basin, possibly appr to Kadi S. field, ops terminated Dec '19 – presumably suspended, DR-12 rig. PTD was 2,285m. Likewise SKBL-175 expl, drilled Jan-early Mar '20, DR-23 rig. PTD ca. 2,300m.

SKBK-173 expl Kadi ML, onshore Cambay Basin, possibly appr to Kadi S. field, ops terminated Dec '19 – presumably suspended,

Upland Resources Limited announced on 30th November 2017 that it has agreed to farm-in to licence P2235 (block 11/24b) taking a 40% interest from Corallian Energy Limited. The acreage contains the Wick prospect which could hold P50 resources of 250 MMbbl. Environmental permitting is already in process to drill an exploration well on Wick which will likely need a Jack-up rig for the operations. Dry hole costs for the well are in the region of GBP 4.2 million. Upland will likely pay 53.33% of the first GBP 4.2 million of costs related to the environmental survey and the well. The deal completed on 24 May 2018. Wick is located in the Inner Moray Firth approximately 2 km from the Scottish coastline. The acreage has an extensive 3D seismic survey over it. Also, in the acreage is the Lybster discovery from 1996. The field was brought onstream in 2012 via wells which were drilled from onshore to offshore. Wick is thought to have the same petroleum system as Lybster consisting of a Lower to Middle Jurassic Beatrice Formation reservoir. Following completion of the deal interest in P2235 is held by Corallian Energy Limited (60% + operator) and Upland Resources (UK Onshore) Limited (40%).

Upland Resources announced that it has agreed to farm-in to licence P2235 (block 11/24b) taking a 40% interest from Corallian Energy (->40% op, Baron Oil 15%, Corfe 5%).