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The parliament has reportedly approved a couple of explo contracts with 2 Russian companies for 3 blocks. A company designated 'Mercury' was assigned blocks 7 (9,531 sq km) and 19, and another designated 'Vilada' block 23, 2,159 sq km N. of Damascus. No details on these awards nor the companies could yet be unearthed.

The parliament has reportedly approved a couple of explo contracts with 2 Russian companies for 3 blocks. A company designated 'Mercury' was assigned blocks 7 (9,531 sq km) and 19, and another designated 'Vilada' block 23, 2,159 sq km N. of Damascus. No details on these awards nor the companies could yet be unearthed.

Appraisal to Ankleshwar-41S find, CB-ONN-2003/2, Cambay onshore, ops terminated (susp?) late May ’18 at TD 2,509m, John-14 rig. GSPCL (op), partners GAIL, Jubilant + GeoGlobal Res.

Appraisal to Ankleshwar-41S find, CB-ONN-2003/2, Cambay onshore, ops terminated (susp?) late May ’18 at TD 2,509m, John-14 rig. GSPCL (op), partners GAIL, Jubilant + GeoGlobal Res.

Shell On 10 October 2019, the consortium of Shell, Chevron, and QPI bid on and were granted preliminary awards for the 1,107.94 sq km C-M-659 block and 703.69 sq km C-M-713 block in the deep-water offshore Campos Basin from the ANP Round 16. There was one other bid for both of the blocks. For the C-M-659 block the consortium bid a bonus of USD 173.72 million at 1 USD to 4.11 BRL and 1,324 work units equivalent to USD 56.70 million in minimum work commitments. The competing bid came from Petronas who bid USD 101.12 million and 1,301 work units. For the C-M-713 block the consortium bid a bonus of USD 134.01 million at 1 USD to 4.11 BRL and 206 work units equivalent to USD 8.82 million in minimum work commitments. The competing bid came from the consortium of BP and Equinor who bid USD 124.96 million and 192 work units. Shell is operator of both contracts with 40% working interest, Chevron holds 35%, and QPI holds 25% working interest.

Brazil, not found

The NPD confirmed on 5 September 2019 that Spirit has acquired 40% interest in PL 780 from Suncor with effect from 14 August 2019. The licence is located in the North Sea covering part of block 16/1. No wells have historically been drilled on the acreage covered by the licence but it is located directly adjacent to Ivar Aasen. PL 780 was awarded during APA 2014. The Ivar Aasen oil and gas discovery (originally named Draupne) was made in 2008. A 44 m thick Middle Jurassic Hugin/Sleipner Formation sandstone reservoir with varying reservoir properties was encountered containing light oil with a small gas cap. The Aker BP operated field came onstream on 24 December 2016 with the company expecting to recover approximately 210 MMboe (including Asha, Hanz and West Cable). A 20 year field life is anticipated with a daily production capacity of 68,000 boe/d. The field was developed using a manned PDQ platform with capacity for the planned subsea tie-back of Hanz. Following completion of the deal Spirit Energy Norway AS (100% + operator) is the sole participant in the licence.

Norway (Gudrun Terrace (Viking Graben Province)) Ivar Aasen

The BOEM announces the Lease Sale 254 will be held on 18 Mar '20, 14,585 blocks totalling 315,655 sq km available in WD 3-3,388m off Texas, Louisiana, Mississippi, Alabama + Florida. Customary terms + conditions here.

The BOEM announces the Lease Sale 254 will be held on 18 Mar '20, 14,585 blocks totalling 315,655 sq km available in WD 3-3,388m off Texas, Louisiana, Mississippi, Alabama + Florida.

As announced on 19 November 2018 Petrel Energy has agreed to acquire Warrego Energy through a reverse takeover, whereby Warrego shareholders will own approximately 77% of the enlarged Petrel, subject to shareholder approval at a general meeting on 31 January 2019. Following completion the enlarged company will be re-branded as Warrego Energy Ltd and will apply to list on the AIM exchange, targeted for 15 February 2019. Petrel holds WI in the Tesorillo and Ruedalabola exploration licences located in the Cadiz province, southern Spain through Tarba Energia, a joint venture between Petrel Energy (85%) and Prospex Oil & Gas (15%). Interests will be revised if Prospex executes an option to increase its share to 49.9% for EUR2 million (US$ 2.4 million). Tesorillo contains the Almarchal 1 (1965, Valdebro, 3,465m MD) gas discovery in Miocene Aljibe Formation sands, which is expected to be drilled by the Tesorillo 1 appraisal well during H2 2019. Ruedalabola contains the Puerto de Ojen 1 NFW which encountered gas shows in 1957. Aberdeen-based Warrego operates Australian North Perth Basin Exploration Permit EP469.

Petrel Energy has agreed to acquire Warrego Energy through a reverse takeover, whereby Warrego shareholders will own approximately 77% of the enlarged Petrel,

On 7 November 2019, the Federal Agency for Subsoil Use announced an auction for the Sylvinskiy block in Sverdlovsk Oblast (Volga-Urals). The auction will be held on 23 December 2019 with its application deadline on 22 November. The winner of the auction will receive a 25-year E&P license. Additional information can be requested from: Uralnedra 620014, Yekaterinburg, Vaynera str., 55, office 425, ural@rosnedra.gov.ru The Sylvinskiy block covers 2,913 sq km in the Ural Foredeep. Hydrocarbon resources (category D1) of the block are estimated at 702 Bcf of gas. The starting price amounts to RUB 7.326 million (USD 0.11 million).

Russia, not found

YPF secured the Loma Amarilla Sur block for Vaca Muerta shale exploration. It lies between Vista’s Escondida + La Pampa Energia’s Rincón de la Aranda units (outline yet n/a). Plans include 4 x 2,500m horiz wells, USD 60 MM.

Argentina, Loma Amarilla

B05/27, shallow water Pattani Trough (Gulf of Thailand Basin), TD 1,960m, P&A dry on 15 Jul ’18, Ensco 115 JU.

Ban Yen SW-1 (MP B5 in the B05/27 concession, located in the Pattani Trough. P&A, dry hole

Santos Ltd completed the acquisition of 45% interest in four of Quadrant Energy’s North Carnarvon permits on 21 December 2017.  Santos has acquired the interest in retention leases WA-43-R and WA-50-R and exploration permits WA-499-P and WA-501-P. The retention leases both cover areas of 80 sq km and cover part of the Rosella gas discovery that was made in 2007.  WA-501-P contains the Libris sub-commercial oil discovery that was made in 2007. WA-501-P covers an area of 81 sq km, while WA-499-P covers an area of 1,558 sq km. Santos Ltd has acquired interest in four of Quadrant Energy’s permits.  In WA-43-R and WA-50-R interests are split between Quadrant Northwest Pty Ltd (55% + Operator) and Santos (BOL) Pty Ltd (45%).  In WA-499-P and WA-501-P interests are held by Quadrant Northwest Pty Ltd (55% + Operator) and Santos Offshore Pty Ltd (45%). 

Australia (North Carnarvon B.) ? op. by QUADRANT E (55.0%, SANTOS 45.0%) in WA-499-P block

BP has put its first shale gas well on stream (probably for a pilot production test) in the Sichuan Basin. Wei 206-H1, located in Neijiang-Dazu PSC block, currently produces at a rate of 350 Mcf/d of gas after fracking. BP spudded Wei 206-H1, a shale gas exploration horizontal well, in the block on 30 August 2017. The well has a PTD of 4,790 m with target in the Longmaxi shale. BP completed drilling operation on Wei 206-H1 and reached a TD of 4,368 m on 28 December 2017. During drilling the well penetrated 30-50 m shale in the Longmaxi Formation and proved newly acquired 3D seismic interpretation. Following Wei 206-H1, BP has spudded additional wells in Neijiang – Dazu and Rongchangbei blocks. Next to the BP block in the west PetroChina has established Weiyuan shale gas field, the field has main reservoir in the Longmaxi Formation. In 2018 PetroChina produced 1.5 Bcm of shale gas from Weiyuan field. Background Information BP signed two shale gas production sharing contracts (PSC) with CNPC in 2016 on the Neijiang-Dazu and Rongchangbei in the Sichuan Basin. The Neijiang-Dazu block has area of approx. 1,500 sq km and the Rongchangbei block has area of approx. 1,000 sq km. CNPC is operator for both blocks. Neijiang – Dazu block used to be a joint study between CNPC and ConocoPhillips during 2013 to 2014. ConocoPhillips completed the study without moving forward to PSC. Rongchangbei block used to be a joint study between CNPC and Eni during 2013 to 2014. Eni completed the study without moving forward to PSC. The main reservoir in the blocks is the Silurian Longmaxi shale.

BP has put its first shale gas well on stream (probably for a pilot production test) in the Sichuan Basin. Wei 206-H1, located in Neijiang-Dazu PSC block, currently produces at a rate of 350 Mcf/d of gas after fracking.

F4a, 243 sq km offshore, was granted to NAM (op) and partners Neptune and HALO on 22 Jan '20 for a 5-year term. A work programme must be filed within 3 years.

Netherlands, not found

Boxi block, Bohai Gulf Basin, WD 15m, ops terminated late Apr '20, HYSY 932 JU. Target Oligo-Miocene clastics.

Caofeidian 28-1-1d (CFD 28-1-1d) nfw Boxi block, Bohai Gulf Basin, WD 15m, ops terminated late Apr '20, Target Oligo-Miocene clastics.

Add. DEA 20 Jun ’19:  JPDA 11-106, Timor Sea, WD 168m, P&A non-commercial find (non-moveable hc in the Jurassic target), Mærsk Deliverer SS released. Target Jurassic + Triassic. Eni (op), partners Inpex + Timor GAP PSC 11-106 Unipessoal.

East Timor, not found

In May 2020, SDX Energy (SDX) confirmed its decision to farm-out its entire stake in the N.W. Gemsa concession, onshore Gulf of Suez Basin. The concession consists of three producing fields included in the North West Gemsa (Dev) Geyad, North West Gemsa (Dev) Al Amir and North West Gemsa (Dev) Al Ola blocks. The Geyad field, which was discovered in 2009, has a daily production rate of 670 bbl with 3 wells. The Al Amir and Al Amir Southeast/Al Ola fields were discovered in 2005 and 2008, respectively. SDX is reporting a combined gross production of 3,060 bbl/d with 11 wells. The three fields have operating costs around USD 10/bbl and are fully developed. As a result, capex is expected to be minimal going forward. The North West Gemsa (Dev) Geyad, North West Gemsa (Dev) Al Amir and North West Gemsa (Dev) Al Ola blocks have been granted to Al-Amir Petroleum, a JV between GANOPE (50%), SDX Energy (25%) and North Petroleum (25%, operator).

Egypt (Gulf of Suez B.), North West Gemsa (Dev), SDX Energy (SDX) confirmed its decision to farm-out its entire stake in the N.W. Gemsa concession, onshore Gulf of Suez Basin. The concession consists of three producing fields included in the North West Gemsa (Dev) Geyad, North West Gemsa (Dev) Al Amir and North West Gemsa (Dev) Al Ola blocks.

Vic/P44, offshore Otway Basin, WD 58m, 1st in region in 7 years, TMD 2,442m, gas find in Waare C fm, 780m gross, 62m net, Ocean Monarch then to Elanora-1 in Vic/L24. Cooper (op), partner Mitsui.

Australia, not found

Ithaca is taking over operatorship of the Alon D block following Noble’s decision to withdraw (47.06%). Ithaca is Delek Group-owned, and the latter already has an interest in the 403-sq km block through 2 subs. Resulting partnership would be Delek 75% with Ithaca (op) holding the remaining 25%.

Ithaca is taking over operatorship of the Alon D block following Noble’s decision to withdraw (47.06%). Ithaca is Delek Group-owned, and the latter already has an interest in the 403-sq km block through 2 subs. Resulting partnership would be Delek 75% with Ithaca (op) holding the remaining 25%.

On 26 December 2017, Lukoil provided update on its first well in the Taymyrskiy Vostochnyy block in Krasnoyarsk Kray (Eastern Siberia). Some hydrocarbon flows were obtained during open-hole tests but they were considered as non-commercial. The company mentioned low hydrocarbon saturation and thin reservoirs within the drilled section. Vertical Zhuravlinaya 1 with a PTD of 5,500 m, spudded on 4 April 2017, is targeting reservoirs of the Lower Cambrian section. The company plans to complete drilling by mid-April 2018 and testing by October 2018. Contractor ERIELL is drilling the well by using rig ZJ70DBS. The Taymyrskiy Vostochnyy block (contract KRR15948NR) covers 13,800 sq km in the Anabar-Khatanga Depression (Lena-Anabar Basin), a frontier unexplored area. Lukoil won an auction for the block in mid-2015 paying a signature bonus of USD 32 million. Before the acquisition, seismic coverage amounted to about 2,500 km. No wells have been drilled in the block. Hydrocarbon resources (category D2) of the block were estimated at 33 MMbbl of oil, 319 Bcf of gas and 4 MMbbl of condensate. Reservoirs of the Devonian-Permian section are the main exploratory targets. In 2016, Lukoil recorded 2,501 km of new seismic data preparing drilling locations. The Zhuravlinyy prospect is located in the north-eastern part of the block bordering the Khatanga Bay (Laptev Sea).

Russia, not found

The Bradarac-Maljurevac 2X appraisal well was operational from mid-July 2019 to mid-October 2019. The well was drilled on the Bradarac-Maljurevac field in the Juzna Srbija licence, which is operated by NIS. The Bradarac-Maljurevac 2X well follows the drilling and testing of the Bradarac-Maljurevac 1X appraisal well in the first half of 2019. The Bradara-Maljurevac oil field was discovered in August 1985 and put onstream ten years later. The field is producing from one reservoir in the Upper Miocene below a depth of 2,700 m. The Bradarac-Maljurevac field is located about 55 km southeast of Belgrade. Interest in the licence is held solely by NIS which is majority owned by Gazprom Neft, the oil arm of Russia’s state-owned natural gas monopoly Gazprom.

NIS Juzna Srbija - Bradarac-Maljurevac 2X - Operations complete no details

The CNH has signed up CNH-RO2-LO3-VC-01/2017 contract, Area 6 block, 193 sq km in the Veracruz Basin, held by Bloque VC 01, S.A.P.I. de C.V., a JV comprising Roma E&P, Tubular Technology, Suministros Marinos e Industriales de Mexico, and Golfo Suplemento Latino. The group was 2nd-place bidder, but wins out after the Shandong consortium failed to pay the USD 2.2 MM tie-break bonus.

Mexico, Area 6

The Ministry of Hydrocarbons, Energy and Mines (Ministère des Hydrocarbures, de l’Energie et des Mines) is the licensing authority. Contracts are signed by the state, as represented by the Minister of Hydrocarbons, Energy and Mines. The Directorate General of Hydrocarbons (Direction Générale des Hydrocarbures) is responsible for the supervision of petroleum operations. Interested parties should contact: Ministère des Hydrocarbures de l’Energie et des Mines Direction Générale des Hydrocarbures Directeur : Moustapha BECHIR Telephone : +222 422 101 28 e-mail : mobechir@yahoo.fr   It is also possible to contact the Socété Mauritanienne des Hydrocarbures et du Patrimoine Minier (SMHPM). Department of Exploration and Promotion Director : Chemsdine Sow Deina Telephone : +222 46 47 66 69   As of September 2017, it is understood that the blocks listed in the table below were available for licensing. Fifty eight blocks were available. There were no changes in the list compared to the previous one. Total open acreage amounts to 770,907 sq km of which 664,728 is onshore and 106,179 is offshore.   Open blocks       Block Name Area (sq km) Situation Block Basin C-1 3,138 offshore MSGBC Basin C-2 3,877 offshore MSGBC Basin C-4 9,037 onshore MSGBC Basin C-5 11,124 onshore MSGBC Basin C-14 12,830 offshore MSGBC Basin C-15 16,251 offshore MSGBC Basin C-16 12,367 offshore MSGBC Basin C-17 12,519 offshore MSGBC Basin C-20 10,175 offshore MSGBC Basin C-21 14,926 offshore MSGBC Basin C-22 12,683 offshore MSGBC Basin C-23 6,244 offshore MSGBC Basin C-24 8,615 onshore MSGBC Basin C-25 11,010 onshore MSGBC Basin C-26 10,875 onshore/offshore MSGBC Basin C-27 11,760 onshore MSGBC Basin Onshore Block 11 15,153 onshore MSGBC Basin Ta-2 13,766 onshore Taoudeni Basin Ta-3 14,354 onshore Taoudeni Basin Ta-4 11,746 onshore Taoudeni Basin Ta-5 11,273 onshore Taoudeni Basin Ta-6 11,585 onshore Taoudeni Basin Ta-7 14,132 onshore Adrar Sub-basin (Taoudeni Basin) Ta-8 14,076 onshore Adrar Sub-basin (Taoudeni Basin) Ta-9 12,141 onshore Taoudeni Basin Ta-10 14,749 onshore Taoudeni Basin Ta-11 14,107 onshore Hodh Sub-basin (Taoudeni Basin) Ta-12 14,135 onshore Hodh Sub-basin (Taoudeni Basin) Ta-13 14,834 onshore Taoudeni Basin Ta-14 11,581 onshore Taoudeni Basin Ta-15 10,712 onshore Taoudeni Basin Ta-16 12,955 onshore Taoudeni Basin Ta-17 13,057 onshore Taoudeni Basin Ta-18 20,005 onshore Taoudeni Basin Ta-19 20,106 onshore Taoudeni Basin Ta-20 21,491 onshore Taoudeni Basin Ta-21 16,514 onshore Hodh Sub-basin (Taoudeni Basin) Ta-22 21,351 onshore Taoudeni Basin Ta-23 17,584 onshore Hodh Sub-basin (Taoudeni Basin) Ta-24 20,648 onshore Hodh Sub-basin (Taoudeni Basin) Ta-25 20,528 onshore Taoudeni Basin Ta-26 14,557 onshore Taoudeni Basin Ta-27 18,943 onshore Taoudeni Basin Ta-28 14,769 onshore Taoudeni Basin Ta-32 9,787 onshore Taoudeni Basin Ta-33 12,332 onshore Taoudeni Basin Ta-34 8,976 onshore Taoudeni Basin Ta-36 15,501 onshore Adrar Sub-basin (Taoudeni Basin) Ta-37 18,840 onshore Adrar Sub-basin (Taoudeni Basin) Ta-38 9,568 onshore Adrar Sub-basin (Taoudeni Basin) Ta-39 9,273 onshore Adrar Sub-basin (Taoudeni Basin) Ta-40 10,712 onshore Taoudeni Basin Ta-41 11,702 onshore Eglab-Reguibat Massif Ta-42 11,903 onshore Taoudeni Basin Ta-43 11,814 onshore Taoudeni Basin Ta-44 13,060 onshore Taoudeni Basin Ta-45 14,423 onshore Eglab-Reguibat Massif Ta-46 14,735 onshore Taoudeni Basin    

Mauritania, not found

Further to DEA 8 Feb ’19, Central Sumatra Coastal Plans & Pekanbaru block, E. of Beruk NE field in Central Sumatra, TD 853m, tested oil from 2 intervals, could be swiftly commercialised and will likely be appraised in the future. Pertamina (op), partner Bumi Siak Pusako.

onshore Cooper-Eromanga, TD 1,344m, P&A with oil shows,

NW part of AE-0382-2M-Amatitlán block, Tampico-Misantla Basin onshore, drilled 12 Jan – mid-May '20, TD 3,275m, tested 2.1 MMcfg/d + 9.6 bc/d, target Cret. Tamaulipas fm + Jurassic.

Mexico (Tampico-Misantla B.) Taxtunu 1EXP op. by PEMEX (100%), LUKOIL (0%), RENAISS O (0%), OTHERS (0%), AMATITLAN (0%) in AE-0382 block drilled 12 Jan – mid-May '20, TD 3275m, tested 2.1 MMcfg/d + 9.6 bc/d, targeted the Cretaceous Tamaulipas fm. and Late Jurassic Kimmeridgian.

Equinor was formally granted AUS-106, 2,279 sq km in shallow waters of the Austral Basin, on 28 October as a result of the Argentina's 1st offshore round earlier this year. Commitments 32km of 2D seismic, 1,500 sq km of 3D, 3,000km of gravity/mangetics in phase 1 (4 yrs) + a well in phase 2 (3 yrs).

Equinor was formally granted AUS-106 (2279km²) block in shallow waters as a result of the Argentina's 1st offshore round.

Ref. DEA 18 May ’18, CNOOC announced on Friday the signature of PSCs for blocks 22/11 + 23/07 in the Beibu Gulf, South China Sea. Block 22/11 covers 1,663 sq km in WD 40-80m and 23/07  1,210 sq km in WD 20-4 m. Husky will operate during the explo phase, CNOOC as customary has the right to take over with 51% in the event of a commercial find.

Husky signed PSC with CNOOC for blocks 22/11(1663km²) and 23/07 (1210km²) in the area of the South China Sea. Husky will operate the PSCs during the exploration phase, with its Chinese partner holding the right to take up a 51% stake later.

Nostra Terra, through its New Horizons Energy 1 sub, has agreed to farmout a 75% stake to Cypress Egy in its so far wholly-owned small Pine Mills acreage in eastern Texas. The deal is in exchange for the farminee drilling + completing an explo well in a small part of the Pine Mills area within 6 months, upon which it has already acquired 3D seismic. NT will be carried for 25% through the well.

Nostra Terra, has agreed to farmout a 75% stake to Cypress Egy in its so far wholly-owned small Pine Mills acreage in eastern Texas.

On 17 July 2018 Parex Resources reported a potential sale of its Llanos Basin assets, namely the Cabrestero, LLA-32, and LLA-34 blocks in the Southern Casanare (SoCa) department. The three blocks combined total some 540 sq km. Parex operates Cabrestero Block with 100% interest and the LLA-32 Block with 87.5% interest. The adjacent LLA-34 Block is operated by GeoPark subsidiary Winchester Oil and Gas and Parex holds a 55% interest. Parex jointly discovered these SoCa assets where its working interest production has increased from zero in 2012 to 38,510 boe/d, as reported in Q2 2018. This strategic repositioning is currently under review and Parex continues to assess this and other means to enhance value for its shareholders.

Parex Resources reported a potential sale of its Llanos Basin assets, namely the Cabrestero, LLA-32, and LLA-34 blocks in the Southern Casanare (SoCa) department. The three blocks combined total some 540 sq km.

PGNiG has agreed with Total to acquire the latter’s 22.2% in PL 146 + 333 for an undisclosed amount. Acreage totals 87 sq km in the Feda Graben, and contains the King Lear, Julius, Romeo + Espen discoveries. Partnership to become Aker BP (op), partner PGNiG.

PGNiG announced that it has agreed a deal with Total to acquire the latter’s 22.2% interest in PL 146 and PL 333 for an undisclosed sum.

On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the F19-C3,C4 onshore exploration licence in the Thrace Basin on 28 May 2019. The company had submitted the application on 27 July 2018. The licence covers approximately 8 sq km in the Marmara Sea and it has been granted for eight-year term with an expiry date of 27 May 2027. TPAO is 100% owner and operator of the licence.

TPAO has been awarded the F19-C3,C4 onshore exploration licence in the Thrace Basin on 28 May 2019. The company had submitted the application on 27 July 2018. The licence covers approximately 8 sq km in the Marmara Sea and it has been granted for eight-year term with an expiry date of 27 May 2027. TPAO is 100% owner and operator of the licence.

CAOG Pte Ltd, a fully-owned subsidiary of Berlanga International, continued to offer a farm-in opportunity in the onshore block MOGE-4, located in the Pyay Embayment (Central Burma Basin), as of June 2019. The company’s plan for the two-well drilling campaign has been delayed to 1H 2020 from the original planned date of late 2019. In February 2018, the company received MOGE’s approval for a two-year extension of the exploration period for the block. With the extension, the expiry of the exploration period has been pushed from 1 December 2018 to 30 November 2020. The request for extension was submitted by the operator in late August 2017. The first three-year exploration period for the block commenced from 1 December 2015. CAOG has planned to drill up to two wells in the block. Each well is expected to be drilled to a TD not exceeding 2,500 m, and could potentially target the Lower Miocene carbonates of the Pyawbwe Formation, analogue to the nearby Htantabin field, and the Upper Oligocene sandstones of the Okhmintaung Formation. The MOGE-4 block is believed to be oil-prone, and is located near existing facilities serving producing fields in the area. A total of 390 km of 2D data was acquired by contractor AlphaGeo (India) Limited. The block was offered as part of the Myanmar 2013 Onshore Bidding Round. Luxemburg-based CAOG and local partner AOEX Geo Services Co Ltd were announced as winners of the block in October 2013, and a PSC was officially signed in September 2014. CAOG holds 94.5% operating interest in the block while Apex Geo Services holds the remaining 5.5%. The farm-in opportunity was first offered in December 2015. A data room is available in Yangon. Interested parties may contact: Hans Braakman Email: hans.braakman@berlanga-group.com Steve Elliott Email: steve.elliott@berlanga-group.com Background Information Block MOGE-4, covering 912 sq km, is located in the Myintha area, in the southern part of the Pyay Embayment Sub-basin. The block is one of the blocks offered in Myanmar first bidding round in 2011 and was initially awarded to Tianjin New Highland petroleum Co and SUNTECH Company in late December 2012. The official PSC was not awarded for unknown reason, but most likely the PSC terms and discussion did not go through. The block was last operated by MOGE since 7 March 2005. The block contains the Htantabin field, discovered in 1981 by MOC. The field was brought onstream in November 1981 and produced approximately 550 Mb until 1987. Subsequently, the field was believed to produce intermittently at a very low rate of around 10 bo/d and 1,000 Mscf/d. The field production was reportedly suspended as of March 2009. The field main reservoir is constituted by fractured limestones within the Pyawbwe Formation. At least 22 appraisal and development wells have been drilled on the field. MOGE also acquired a total of 94km of seismic lines over the field during 1998, and further 78km of 2D data from January to June 1999. In addition to the Htantabin discovery, four other new-field wildcats have been drilled in the block. Two dry wells, Htantaung 1 and Myintha 1, were drilled by unknown operators in the central part of the block. Between 1991 and 1992, MOGE drilled Chinmyaung 1 to a depth of 3,116m. The well was tested over several intervals but only encountered gas shows. In 2000, MOGE drilled the Kansei 1 wildcat to a TD of 1,591m. The well, located about 3km east of the Htantabin field, is assumed to be dry.

CAOG Pte Ltd, a fully-owned subsidiary of Berlanga International, continued to offer a farm-in opportunity in the onshore block MOGE-4, located in the Pyay Embayment (Central Burma Basin

It was reported on 6 February 2020 that TransAtlantic Exploration Mediterranean Int. Pty Ltd (TEMI) has transferred its full 50% interest and operatorship in E17-B4-1 production lease to Petrogas Petrol Gaz ve Petrokimya Ürünleri Ins. San. ve Tic. A.S. on 28 January 2020. As a result of this transaction the revised equity split for E17-B4-1 lease is as follows: Petrogas 55% (operator), Petrako Petrol Dogalgaz Ins. Taah. Isl. ve Dis Tic. Ltd. Sti. 10% and Valeura Energy Netherlands B.V 35%. TEMI and Petrogas, both are the subsidiaries of TransAtlantic Petroleum. TEMI had submitted the application to the government on 16 September 2019 for the approval of this transaction. The licence, located towards northwest of the country in Thrace Basin, covers an area of 32 sq km and it was awarded to TEMI on 22 October 2014.

TransAtlantic Exploration Mediterranean Int. Pty Ltd (TEMI) has transferred its full 50% interest and operatorship in E17-B4-1 production lease to Petrogas

As of June 2018, Pura Vida Energy NL (Pura Vida) is still understood to be looking to farm out a stake in its Nkembe offshore block in North Gabon Sub-basin (Gabon Coastal Basin) however, was in dispute with the Director General of Hydrocarbons (DGH) (see article: Pura Vida Energy NL in dispute with Director General of Hydrocarbons (DGH) over its Nkembe offshore block). Pura Vida Energy NL is looking actively to farmout its 80% stake in its Nkembe offshore block in North Gabon Sub-basin (Gabon Coastal Basin). The Nkembe Permit has prospects defined by 3D seismic in the Pre, Sub and Post Salt fairways. The interests in the Nkembe PSC are shared between Pura Vida, operator with 80%, and the State of Gabon 20% (carried). Pura Vida’s first phase work program comprises acquiring 550 sq km of Multi Azimuth 3D seismic data and the drilling of one well to 2,000 m, which is required to be completed by 2017.  The block contains the Mouveni West prospect that has a mean recoverable resource of 639 MMbo in a 50 square kilometre trap defined by 3D seismic data. The reservoirs are Cretaceous Gamba shoreface and Dentale deltaic sands. A further prospect in the Pre-Salt fairway offers follow up potential being Palomite Deep with mean recoverable resource of 225 MMbo. The Sub Salt prospects are combined structural/stratigraphic traps. The reservoirs are Senonian/Cenomenian turbidites. The Lepidote Deep prospect is defined on existing 3D seismic data as a compressional anticline with approximately 400 m of relief and an area of 35 square kilometres and has a mean resource of 131 MMbo. The reservoirs are Upper Cretaceous Anguille turbidites. Pura Vida signed a Production Sharing Contract (PSC) for the Nkembe block on 11 January 2013. The block covers 1,210 sq km in the North Gabon Sub-basin (Gabon Coastal Basin) in 50 to 500 m of water. The contract is subject to approval by Presidential Decree. The exploration period will have a duration of seven years and will include an initial period of four years. The work programme for the first term will involve a 550 sq km Multi Azimuth (MAZ) 3D seismic survey and an exploration well to a minimum depth of 2,000 m subsea. The first renewal phase would call for the acquisition of a further 550 sq km of MAZ 3D seismic data and two exploration wells to a minimum depth of 3,000 m subsea. The signature bonus was USD 9 million. For more information please contact: Charle T’chen in Libreville: Tel: +214 01745282 Tchen.ch@iipconsulting.com Or Email: Andy Morrison in Australia: Tel: +61892262011 Email: amorrison@puravidaenergy.com.au

Pura Vida Energy NL (Pura Vida) is still understood to be looking to farm out a stake in its Nkembe offshore block in North Gabon Sub-basin (Gabon Coastal Basin) however, was in dispute with the Director General of Hydrocarbons (DGH) (see article: Pura Vida Energy NL in dispute with Director General of Hydrocarbons (DGH) over its Nkembe offshore block). Pura Vida Energy NL is looking actively to farmout its 80% stake in its Nkembe offshore block in North Gabon Sub-basin (Gabon Coastal Basin).

Last of 4 wells planned in pre-salt Alto de Cabo Frio Oeste area, Santos Basin, WD 1,720m, oil shows report to ANP, Brava Star DS. Target assumed Barra Velha + Ipatema fm's.

ACFO (1-SHEL-031-RJS) nfw. (Shell 55% op, CNOOCI 20%, Qatar Petr 25%) in Alto CF Oeste P3 contract, ALTO_CF_O block, target Barra Velha, oil shows report to ANP on 8 Nov '19. WD=1720m, PTD=5200m.

Duyung block, S. part of Mako field in offshore W. Natuna Basin, TD 503m, successfully appraised Mako gas field earlier this month, but 2 DST attempts on the intra-Muda reservoir were unsuccessful due to formation damage, though a full logging suite was acquired that suggests testing would have yielded flow rates similar to the discovery well. Asian Endeavour I JU is moving to the Tambak-1 appr, targeting the potentially 250-Bcf Tambak structure. The 2 wells are part of a 15% for Coro Energy, partners otherwise Conrad (op) + Empyrean.

Duyung block, S. part of Mako field in offshore W. Natuna Basin, TD 503m, successfully appraised Mako gas field earlier this month, but 2 DST attempts on the intra-Muda reservoir were unsuccessful due to formation damage, though a full logging suite was acquired that suggests testing would have yielded flow rates similar to the discovery well. Asian Endeavour I JU is moving to the Tambak-1 appr, targeting the potentially 250-Bcf Tambak structure. The 2 wells are part of a 15% for Coro Energy, partners otherwise Conrad (op) + Empyrean.

Cairn Energy and Shell have agreed to swap 50% equity in adjacent licences P2379 (currently Cairn 100% Op) and P2380 (Shell 100% Op), as released in March 2020. P2379 contains the Woodstock Prospect and P2380 contains the Jaws prospect, both in Jurassic Fulmar sandstone with potential for near term production. A well is planned on each licence in H2 2020/H1 2021. P2379 covers 305.6 sq km on blocks 22/11b, 12b, 16b & 17c, located S of Nelson Field (Shell Op) and NW of Montrose Area (Repsol Sinopec Op). P2380 covers 93 sq km of blocks 22/12d, adjacent to the NE of P2379. Shell operated Howe and Bardolino oil fields are located adjacent to the NE. Both licences were awarded on 1 October 2018 in the 30th Seaward Licensing Round. P2379 saw Zennor North Sea (35%) and ONE-Dyas (25%) exit on 1 October 2019, and Cairn Energy subsidiary Nautical Petroleum Ltd is now 100% operator. Shell UK Ltd is 100% operator of P2380.

Cairn Energy and Shell have agreed to swap 50% equity in adjacent licences P2379 (currently Cairn 100% Op) and P2380 (Shell 100% Op), as released in March 2020. P2379 contains the Woodstock Prospect and P2380 contains the Jaws prospect, both in Jurassic Fulmar sandstone with potential for near term production.

Southwest Alamein block, W. Desert, TD 4,413m (Kharita), gas-cond. discovery, compl. late Aug ’18, EDC rig 53. Targets Abu Roash G, Kharita + Bahariya.

Egypt (Alamein Sub-basin (Northern Egypt B.)) Alamein

MOGE-3, Central Burma Basin, P&A dry at TD 2,272m mid-May ’19, Asia Drilling rig 2. Targets L. Miocene Pyawbwe, L. Oligocene Padaung + U. Oligocene Okhmintaung fm’s between 600-2,800m. Third in 4-well programme, next well Pyae Sone Kywal 1. PTTEP (op), partners Palang Sophon, MOECO + Win Precious Res.

Aung Chan Thar 1 nfw (PTTEP op. 77,5%, Palang Sophon 10%, MOECO % 10%, Win Precious Res. 2,5%) in MOGE-3 block, P&A dry at TD=2272m, Targets L. Miocene Pyawbwe, L. Oligocene Padaung + U. Oligocene Okhmintaung fm’s between 600-2800m.

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.  Bertek was granted the official awards for the blocks in January 2018 through the ANP Round 14. 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%.

Brazil, ES-T-476

PRL 155, Cooper-Eromanga, drilled 11-22 Feb '20, susp. at TD 3,376m, under evaluation.

Kalladeina-8 appr PRL 155, Cooper-Eromanga, drilled 11-22 Feb '20, susp. at TD 3,376m, under evaluation.

OMV has farmed in to North Sea licence PL807 by acquiring 40% from exiting INEOS and 5% from operator EDF subsidiary Edsion, effective from 31 May 2018. PL807 was awarded on 5 February 2016 in APA 2015 covering 402 sq km over blocks 2/8, 2/9 and 2/11 with a drill or drop decision due by 5 August 2019. It is located adjacent to the Norway/Denmark border, E of the Valhall Field and contains 7 NFW wells, two dry and five with shows. PL807 current licence partners are Edison Norge AS (55% + Op) and OMV Norge AS (45%).

OMV has farmed in to North Sea licence PL807 by acquiring 40% from exiting INEOS and 5% from operator EDF subsidiary Edsion,

Central part of PN-T-103 block, Parnaíba Basin, P&A dry early Apr ’19. PTD was 2,229m, targets Cabeças + Poti fm’s.

Brazil, PN-T-103

Mississippi Canyon block 339, WD 1,434m, cleared to P+A by the BOEM 11 Nov ’17, results n/a but believed unsuccessful. West Capricorn DS. Background from GEPS.

United States, not found

On 1 August 2020, BHP Billiton Petroleum (Deepwater) was formally awarded contiguous Alaminos Canyon blocks AC 36, AC 80 and AC 81. The acreage, sited in the East Texas Coastal Basin, has yet to be drilled. The blocks were originally offered as part of recent GOM-wide OCS Lease Sale 254, which was held on 18 March 2020. BHP Billiton Petroleum (Deepwater) is the operator and sole interest-holder (100% WI + Op) in AC 36, AC 80 and AC 81.

(GOM B.) BHP was formally awarded Alaminos Canyon blocks AC 36, AC 80 and AC 81 as the operator and sole interest-holder (100%).

On 28 June 2018, the ANP approved of the transfer of 100% working interest from former operator Proen Projetos, Engenharia, Comercio e Montagem in the Rio do Carmo production concession to Phoenix Empreendimentos Ltda.  Phoenix is now operator and holds 100% working interest in the onshore Potiguar Basin contract.  Proen is currently going through the Brazilian bankruptcy process. On 23 March 2010, the ANP granted ProenEngenharia e Manutencao a 46-day extension to the appraisal phase for the 1.2 sq km Rio do Carmo production concession in the Potiguar Basin. No other details were available, though the Brazilian oilfield services company has been trying to revitalize the field since December 2006. On 4 December 2006, the ANP granted an official award of the Rio do Carmo production concession to Proen from the 2nd ANP Marginal Fields Tender Round.

Proen Projetos tranfered 50% op. WI in the Rio do Carmo (100%) production concession to Phoenix Empreendimentos

Vermilion secured sole rights to the 1,208-sq km Kadarkút block, Zala sub-basin in SW Hungary, on 25 Feb '20 for 4+2+2 years explo. It was issued in the 2019 licensing round.

Hungary, not found

Yet-unconfirmed, the authorities are offering former OK Energy-operated acreage for exploration rights (ER) off the south coast. In this area, OK operated the former 1TCP block (since an ER) over about 7,000 sq km in WD 0-300m. Should this be confirmed, the offer would entail blocks 3422 A, B + D, shown below and which would therefore recently have been relinquished/cancelled.  OKE otherwise retains acreage in the Algoas/Outeniqua Basin (ER 257) and in the Orange Basin.

Yet-unconfirmed, the authorities are offering former OK Energy-operated acreage for exploration rights (ER) off the south coast. In this area, OK operated the former 1TCP block (since an ER) over about 7,000 sq km in WD 0-300m. Should this be confirmed, the offer would entail blocks 3422 A, B + D, shown below and which would therefore recently have been relinquished/cancelled. OKE otherwise retains acreage in the Algoas/Outeniqua Basin (ER 257) and in the Orange Basin.

Oil Search has a signed an agreement to acquire a slew of oil assets in the Alaska North Slope from privately-owned companies Armstrong Energy and GMT Exploration Company, according to reports in late October 2017. The deal, which is estimated to be worth ~US$ 400 million, includes Oil Search purchasing a 25.5% interest in the Pikka Unit and adjacent exploration acreage and a 37.5% interest in the Horseshoe block from Armstrong and GMT. These blocks are co-owned by Repsol. The Nanushuk play includes the Horseshoe block, which discovered oil in March 2017, in what Repsol called the biggest US onshore find in 30 years. It also confirmed that the Nanushuk Formation has one of the highest potentials of the prolific Alaska North Slope zone. Exploration wells Horseshoe-1 and Horseshoe-1A were drilled in North Slope lease ADL 392048 during the 2016-2017 winter drilling campaign and verified the Nanushuk as an important and emerging play. Horseshoe-1 was drilled to a TD of 1,828m (6,000 feet) and encountered over 45m (150 feet) of net oil pay in several reservoir zones in the Nanushuk section. Horseshoe-1A sidetrack was then kicked off and drilled to a total depth of 2,504m (8,215 feet), encountering more than 30m (100 feet) of net oil pay in the Nanushuk in the process. The contingent resources identified in Repsol and Armstrong Energy's blocks in the Nanushuk play in Alaska could amount to ~1.2 Bbls of recoverable light crude oil. Oil Search bought in assuming the field holds 500 MMbbls, expecting production to begin in 2023, with output to plateau at 80,000 to 120,000 bbls/d. In a statement, Oil Search Chief Executive Peter Botten said: "With the quality of the assets, the fact that they're tier 1, and the fact that we've gone in very conservatively against what Repsol are saying, I think we can demonstrate to the market that this will be a super deal for Oil Search in the medium term." Oil Search will assume operatorship on 1 June 2018, has the option of doubling its stake in the Alaskan assets for an additional US$ 450 million and plans to fund the deal from its cash reserves. Oil Search expects that the transaction will be completed by Q1 2018 at the latest.

Not Found

PPL 165, onshore Cooper-Eromanga Basin, TD 2,565m, P&A with oil shows. Santos (op), partner Beach. Ensign rig 974 has since spudded Merchant-1 nfw in PPL 17.

Bugsy 1, (Santos 66,6% op.Beach 33,4%) in PPL 165, was targeting the Jurassic Birkhead and the early Permian Merrimella Fms, having only encountered oil shows in the target reservoirs.

A result of an MoU in 2016, BP and Socar have signed a 25-year PSA for joint E&P of block D-230, 3,200 sq km in the North Absheron Basin, NE of Baku in the Caspian Sea (WD 400-600m). BP will operate during the explo phase with 50%.

Azerbaijan, Absheron

Lundin confirmed on 22 January 2018 that it has re-assessed the reserves for Alta and Gohta following the drilling which took place on the discoveries in 2016 and 2017. As a result it has downgraded its estimates for both fields to a combined 115-390 MMboe. At the time of discovery, reserves for Alta were estimated at 125-400 MMboe and for Gohta were 91-184 MMboe. Two appraisal wells, each with a sidetrack, were drilled at Alta in 2015, all confirming communication with the discovery well. The sidetrack of the second appraisal well, 7220/11-3 A, was re-entered in 2016 and was deepened and tested at a rate of 21 MMcfg/d through a 64/64” choke. In 2017 Lundin spudded a further appraisal well - 7220/11-4 - which encountered a 4 m gas column and a 44 m oil column in Permo-Triassic clastic carbonates. Good communication with the previous Alta wells was confirmed from pressure data, with the same fluid contacts and gradients. The well was tested and flowed at a constrained rate of 6,050 bo/d through a 56/64” choke, indicating very good reservoir quality and lateral continuity through the reservoir. Sidetrack 7220/11-4 A found a 10 m gas column and a 44 m oil column in the Permo-Triassic Orn Formation with the same hydrocarbon contacts. The sidetrack was intended to help as a calibration point for a horizontal well and EWT in 2018 A Gohta appraisal well was drilled in 2017. 7120/1-5 had a planned duration of 75 days with an option to sidetrack and, depending on the results, perform up to two well tests. However, after drilling to a shallower-than-planned TD of 2,527 m (the plan was 2,952 m) in the Permian Roye Formation Lundin abandoned the well as a dry hole. A 300 m gross section of Permian carbonates was present in the well but reservoir quality was poor and there were only weak shows. 7120/1-5 was drilled to define the northeasterly extent of the field and provide a calibration point for a potential future horizontal well and extended well test Alta is covered by PL 609 where interest is divided between Lundin Norway AS (40% + operator), DEA Norge AS (30%) and Idemitsu Petroleum Norge (30%). Gohta lies within PL 492 which is operated by Lundin Norway AS with a 40% interest. Lundin is partnered by Aker BP ASA (60%).

Lundin (40%op. AkerBP 60%) confirmed that it has re-assessed the reserves for Alta and Gohta following the drilling which took place on the discoveries in 2016 and 2017. As a result it has downgraded its estimates for both fields to a combined 115-390 MMboe. At the time of discovery, reserves for Alta were estimated at 125-400 MMboe and for Gohta were 91-184 MMboe.

DNO is expected to make an offer for the share capital of Faroe Petroleum it does not already own, value GBP 607.9 MM. Most of Faroe’s assets are in Norway, and the company has 7,500 boe/d gross production.

DNO is expected to make an offer for the share capital of Faroe Petroleum it does not already own, value GBP 607.9 MM. Most of Faroe’s assets are in Norway, and the company has 7,500 boe/d gross production.

According to reports in mid-January 2018, Pampa Energia has agreed to sell its ownership of Petrolera Entre Lomas SA (PELSA) and several other assets to Vista Oil & Gas for USD 360 million. Closing of the transaction is pending on regulatory approvals. PELSA currently holds 73.15% interest and operatorship on four concessions in the Neuquen and Rio Negro provinces, namely the Charco del Palenque and Jarilla Quemada blocks (both areas formerly part of the Agua Amarga concession), along with Bajada del Palo and Entre Lomas. As part of the transaction, Pampa Energia also sold 3.85% of additional interest that the company held directly on said assets. Pampa Energia is the majority owner of PELSA with 58.88%, with partner Pluspetrol as the next largest shareholder with 40.7% interest. In addition, Pluspetrol is also a direct partner in said blocks with 23% interest. Outside of the PELSA-operated blocks, the transaction was said to include the sale of the company’s 100% interest and operatorship of the 25 de Mayo-Medanito SE and Jaguel de los Machos blocks in Rio Negro Province as well. Charco del Palenque (184 sq km), Jarilla Quemada (194 sq km), Bajada del Palo (452 sq km), and Entre Lomas (733 sq km) production concessions located on the Neuquen Embayment part of Neuquen Basin. Meanwhile, the 25 de Mayo-Medanito SE (125 sq km) and Jaguel de los Machos (112 sq km) blocks are located in the Northeast Platform part of Neuquen Basin.

Argentina (Neuquen B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Jaguel de los Machos op. by PETROQUIM (80.0%, PAMPETROL 20.0%) to be check.Bajada del Palo (CNQ-11 M) op. by PEL SA (43.3544330637%, PLUSPET RS 31.2872650688%, PAMPA EN 25.3583018675%) to be check.Jarilla Quemada op. by PEL SA (43.3544330637%, PLUSPET RS 31.2872650688%, PAMPA EN 25.3583018675%) to be check.Entre Lomas op. by PEL SA (43.3544330637%, PLUSPET RS 31.2872650688%, PAMPA EN 25.3583018675%) to be check.

The Ministry of Energy of the Republic of Kazakhstan, Eni and KazMunayGaz (KMG) have signed the agreement to transfer to Eni 50% of the subsoil use rights of the offshore Caspian Isatay block. This exploration and production agreement was signed on 21 December 2017. The parties (Eni and KMG) will establish a joint operating company which will carry out a work programme in the block. According to Eni, the Isatay block is estimated to have significant potential in geological conditions that are not complex and technologically developable in short time. The Isatay block is located at the southern margin of the Precaspian Basin, east of the Kalamkas-More discovery made by the North Caspian (Kashagan) consortium in which Eni is also a participant. The water depths at Isatay vary between 4-8 m, the distance to the shore is 40 km. KMG estimates Isatay’s undiscovered resources at 240 MM tonnes of oil equivalent (ca. 1.8 Bb). The Kazakh legislation requires KMG to have a minimum 50% share in any offshore contract.

Kazakhstan (North Buzachi Uplift (North Ustyurt B.)) Kalamkas-More

EnerVest, on behalf of certain institutional partnerships, has entered into definitive agreements to sell its Eagle Ford and Austin Chalk assets to TPG Pace Energy Holdings ('TPGE'), an energy-focused special purpose acquisition entity led by former Occidental Petroleum CEO Steve Chazen, for approx. $2.66 billion in cash and stock. As part of the transaction, TPGE and EnerVest are partnering to create Magnolia Oil & Gas Corp, a new company led by Chazen who will serve as Magnolia’s full-time Chairman, President and CEO. The transaction is expected to close late in the second quarter of 2018.EnerVest Operating, will continue to operate the assets under a long-term arrangement, and EnerVest will provide certain additional corporate services to Magnolia.  Upon closing, Magnolia will trade on the NYSE under a new ticker, and EnerVest will receive approx. $1.2 billion in cash and will retain roughly 120 million shares of common stock.'EnerVest’s strategy always has been to optimize returns for our investors and to leverage the strengths of our operating company to advance that strategy,' said John B. Walker, EnerVest founder and CEO. '“I have known Steve for more than 20 years and I cannot think of a better executive to lead Magnolia. The playbook he perfected at OXY is a great match for the outstanding acreage we have assembled in South Texas over the last 10 years.  All of us at EnerVest look forward to partnering with Steve as he builds Magnolia going forward.''In creating Magnolia, we have a unique opportunity to build a new company anchored by what we consider to be some of the highest quality oil producing acreage in the country,' said Chazen.  'We believe Magnolia’s acreage in Karnes County has some of the best economics in the United States and, when coupled with the upside in the Giddings Field, is a great fit with our criteria.  Our objective is to maximize shareholder returns by generating steady production growth, strong pre-tax margins in excess of industry norms and significant free cash flow.  Assuming  moderate commodity prices, we  plan to invest less than 60% of cash flow to fund a drilling program that consistently delivers more than 10% annual production growth.  I look forward to leading this rigorous capital allocation process at Magnolia for the benefit of our shareholders and employees.'Original article linkSource: EnerVest

United States (Sigsbee Sub-basin (DWGoM B.)) Magnolia

Valeura Energy Inc expects to resume testing of on its Yamalik 1 NFW on the F18-c (Banarli) Deep licence in July 2018. Equipment, including a snubbing rig and a production test unit, have started to arrive on location and well operations are expected to begin in the coming weeks. The objective is to drill out the bridge and flow-through plugs in the well and flow all four previously tested intervals in a commingled fashion within the 5.5" production casing string. The company is then planning to immediately tie-in the well to existing production facilities via a new pipeline which is nearing completion. Tie-in will allow for gas sales and long-term testing.<P />In mid-January 2018, Valeura had suspended testing operations on the Yamalik 1 NFW due to limitations with the surface testing equipment, which could not cope with flowback during milling operations given the combination of high-pressure gas, condensate, frac sand and milling debris. The Yamalik 1 NFW was spudded in the NW Turkish province of Tekirdag (District I) on 13 May 2017 by the KCA Deutag T207 rig and reached a final TD of 4,196m in July 2017. A comprehensive testing programme, comprised of four production tests with two frac-stages for each test interval, was carried out in November and December.<P />As part of the third and fourth tests, fracs were completed in the Eocene Kesan formation to access a combined 92m of indicated net gas pay. The third test was carried out over a depth interval from 3,488m to 3,635m, with the well being produced for a total 37 hours. Over the final 24 hours of the test, the well produced at an average restricted rate of approximately 0.9 MMcfg/d and 20-30 bc/d. The fourth test was carried out over a depth interval from 3,488m to 3,635m, with the well being produced for a total 41 hours. Over the final 24 hours of the test, the well produced at an average restricted rate of approximately 0.4 MMcfg/d and 30-50 bc/d. Combined with the results from the first and second tests, the well tested an aggregate 24-hour rate of around 2.9 MMcfg/d, which exceeded expectations.<P />The estimated all-in cost of the Yamalik 1 testing programme is US$ 10.3 million, which will be funded by Statoil. The well forms part of Statoil's Phase 1 commitment under the Banarli Deep Rights Farm-in, which the companies completed in early January 2017. Under the agreement Statoil has the option to earn 50% equity in the deep formations of the Barnali licences (F18-c and F-19-d1 & d4) by investing in a three-phase exploration programme that includes payments and carried costs of at least US$ 36 million. The total cost for drilling, coring, logging and casing Yamalik 1 is US$ 12.85 million.<P />Yamalik 1 was designed as a first test of a deep, basin-centred gas play concept in the Thrace Basin. The key objectives of the well were to prove the presence of reservoir rock, confirm that the encountered reservoirs are over-pressured, and to demonstrate that there are significant sections of the reservoirs which are gas-saturated. Valeura currently operates the acreage with a 100% interest.

Yamalik 1 appraisal well by Valeura (50% op, Statoil 50%) in F18-C / F19-D1 / F19-D4 block (Banarli), 60-day testing programme complete, 4 tests + 2 frac stages / tested intv starting at the bottom of the well. The 1st such test was completed in the Kesan fm, 151m fracced below 3996m, flowed 800 Mcfg/d + 60-70 bc/d (56 API) avg for 24 hrs. The 2nd test in the Kesan was completed after 2 slick-water fracs to access 34m of net gas pay below 3819m.  The 39-hour test resulted in also 800 Mcfg/d avg. A 4th test in the Kesan accessed 66ms of net gas pay below 3320m, 400 Mcfg/d + 30-50 bc/d. The aggregate with the earlier tests now reach 2,9 MMcf/d TD=4196m.

China has drilled its 2nd gas hydrates well, in the Shenhu Trough of the PRMB, South China Sea. A significant find was reportedly made, a massive avg flow of ab. 1 MMcf/d is touted, recorded over the month test which completed 18 Mar '20, Bluewhale 2 SS. Confirmation is evidently required. A 1st well in 2017 gauged avg 182 Mcf/d during a 60-day test. A bespoke drillship is reported under construction.

China (Shenhu-Ansha Uplift (Pearl River Mouth B.)) Shenhu (Gas Hydrates)

The NPD confirmed on 9 June 2018 that DEA has transferred its 30% interest in PL 771 to operator MOL with effect from 31 May 2018. This deal follows two earlier deals relating to PL 771 and also PL 617: in April 2018 Fortis withdrew from both licences, transferring its 30% interest to MOL. MOL then passed this equity to OMV with effect from 22 May 2018. The licences are located immediately east of Valhall on the Norwegian / Danish border. PL 617 covers 112 sq km over part of block 2/9 and PL 771 covers 260 sq km over parts of blocks 2/8 and 2/9. Valhall was discovered in 1975 by well 2/8-6 drilled by Amoco and first oil was produced in October 1982 from the field’s Upper Cretaceous chalk reservoir (Tor and Hod formations). By January 2017 the field, together with Hod, had produced 1 Bboe, more than three times what was expected in the original PDO. The operator has ambitions to produce at least another 500 MMboe over the field’s lifetime. Following completion of all deals, MOL Norge AS operates both PL 617 and PL 771 with a 70% interest and is partnered by OMV (Norge) AS (30%).

DEA has transferred its 30% interest in PL 771 to operator MOL with effect from 31 May 2018. This deal follows two earlier deals relating to PL 771 and also PL 617:

Nong Yao offshore field area, G11/48, S. Pattani Trough, P&A oil on 6 + 9 Apr ’19 at TDs 2,200m + 1,870m resp, Ensco 115 JU. Main target W. extn of the L-M Miocene sst reservoir. Mubadala (op), partner Palang Sophon.

Yao-8, 8ST1 appr Nong Yao offshore field area, G11/48, S. Pattani Trough, P&A oil on 6 + 9 Apr ’19 at TDs 2,200m + 1,870m resp, Ensco 115 JU. Main target W. extn of the L-M Miocene sst reservoir. Mubadala (op), partner Palang Sophon.

Medco has likely completed operations on wildcat Tuna 1 in the South Natuna Block B PSC Extension, around mid-August 2019, with results unreported. The well is located in the unexplored Area VI of the PSC. Tuna 1 was spudded around early July 2019 using the “COSLBoss” J/U. Upon completion of this well, the rig is believed to have been mobilized to the Belanak field, possibly to conduct development drilling. It is understood that the drilling plan may also include a second exploration well, Tuna 2, located approximately 10 km Northwest of Tuna 1. Typical reservoirs in the area include Oligo-Miocene sandstones of the Gabus and Arang formations. Medco completed a 1,400 sq km 3D seismic survey in the eastern part of the PSC (Areas V, VI and VII) in late 2018. ConocoPhillips, previous operator of the block, drilled one well in 1973 (Sokang 1, small gas discovery), in area VII of the PSC. Medco’s last exploration well, SW Bawal 1, was completed in early November 2018. The well was drilled using “COSLBoss” J/U and was reported to have flowed gas from the first DST, while the operator continued to stabilize gas flow. Additional tests were likely conducted, however further results have not been reported. SW Bawal 1 is located approximately 10 km southwest of the Bawal field (area I of contract block). The well was spudded in September 2018, possibly targeting the Upper Miocene-Lower Oligocene sandstones of the Gabus Formation. The South Natuna Sea Block ‘B’ PSC is operated by Medco with 75% interest, through two subsidiaries. The other 25% is held by Prime Natuna Energy. The PSC is due to expire in 2028. Background Information The South Natuna Sea Block 'B' PSC was awarded to Conoco on 16 October 1968. A then large Signature Bonus of USD 7 million was paid with a work programme commitment of USD 14 million in six years. The contract originally covered a huge strip of 103,287 sq km across the Indonesian sector of the South China Sea between latitudes 03° 00' N and 04° 40' N and encompassing large parts of both East and West Natuna basins and the dividing Natuna Arch. The area was subsequently reduced to 14,907 sq km at the time of a contract extension signed on 3 August 1990. Under the terms of the initial contract, Conoco drilled a total of 64 exploration and appraisal wells and some 35 development wells between October 1968 and August 1990. It also shot a total of almost 40,000 line km of reflection seismic, 246 km of refraction seismic and recorded 3,828km of gravity data. The exploration programme resulted in discoveries that were brought onstream as the Udang field (1981), the Kepiting field (1986) and the Ikan Pari field (1989), as well as several oil and/or gas discoveries deemed non-commercial at that time largely due to the lack of a gas market. All of these fields were relatively small, with Udang being the largest with recoverable reserves of 67 MMbo. The three fields were all off production by the mid-1990s. The largest discovery was made in December 1989 at Alu-Alu East 1. That well flowed at the aggregate rate of 12,289 bo/d, 187 bc/d plus 61.57 MMcf/d from Arang and Gabus Formation sandstones. The discovery was delineated in 1990 and quickly brought onstream in early 1993 as the Belida field. The field is believed to contain up to 370 MMbo plus 330 Bcfg recoverable (2P). The PSC was granted a 20-year extension on 3 August 1990 to allow production to continue from the contract area. The extension became effective on 16 October 1998 and lasts until 16 October 2018 and was granted on the basis of payment of a new Signature Bonus of USD 3 million and commitment to a new work programme of USD 30 million in nine years. Two further part relinquishments in 1992 and 1997 have reduced the PSC to 11,162 sq km. Between the award of the extension up to the end of 1997 Conoco drilled a further 16 exploratory and delineation wells, drilled 40 development wells and acquired 4,686km of 2D data and 2,097 sq km of 3D data, including the first 3D shot in the basin in a 207 sq km survey acquired in 1991. Following a Letter of Intent signed in April 1997, on 12 July 1998 a Gas Sales Agreement was initialed between Pertamina and SembCorp Gas Pte Ltd of Singapore. This called for the delivery, under the West Natuna Gas Project, of 325 MMscf/d for 22 years from three adjacent PSCs, Conoco's South Natuna Sea Block 'B' PSC, Gulf's Kakap PSC and Premier's Natuna Sea Block "A" PSC. SembCorp Gas is utilising the gas for power generation and petrochemical projects in Singapore. Delivery is via a 469km, 28" diameter trunkline from West Natuna to Singapore. The project was completed ahead of schedule and gas sales to Singapore commenced in January 2001, well before the planned start date of 15 July 2001. In order to accommodate the lifespan of the Conoco-led project, the three operating companies involved, Conoco, Gulf and Premier were granted extensions to their PSCs, these being announced simultaneous to the signing of the gas supply agreement on 15 January 1999. The Block 'B' PSC was extended to 2028 from its expiry date of 2018. Since the conception of the gas project, ConocoPhillips has focused on delineating many of the earlier "non-commercial" gas or gas/condensate discoveries and increasing its gas reserves in the area through new wildcat drilling. From the start of 1998 to mid-2000, Conoco drilled some 18 exploratory and delineation wells and shot 619km of 2D and 2,710 sq km of 3D data. Seven development wells at Belida were drilled in the corresponding period. During this period, significant new gas discoveries were made at Belut West 2, Kaci 1, Keong 1 and Siput 1, and the earlier Belanak (1975), Belut (1975), Belut North (1974), Buntal (1990), Hiu (1979), Kerisi (1991), Tawes (1988) and Tembang (1981) discoveries were successfully delineated. Field development for the gas project has been the main focus of operations since 2000. Gas produced from the block, through the West Natuna Transportation System, is sold to Singapore, following a 22-year sales contract started in 2001, and to Petronas' Duyong gas facilities, under a 20-year contract since 2002. The latest field onstream in the block was Belut South. Gas production from the field commenced on 26 April 2014 with initial production at around 40 MMcfg/d. Production is tied back to the Belut North field. Total production capacity is around 120 MMcfg/d. The field is also producing LPG to Pertamina. The field development plan was approved in mid-2011. Belut South has recoverable gas (2P) of around 190 Bcf.

Tuna 1 (Medco 75% op, Prime Natuna Energy 25%) South Natuna Block B PSC Extension has likely completed operations, with results unreported.

Santos Ltd spudded the Tigris 1 exploration well in ATP 1189-P, located in the Cooper-Eromanga Basin, on 9 April 2018. The well was drilled by the “Ensign 950” land rig.  On 17 April 2018 the well was plugged and abandoned as a dry hole, after reaching a total depth of 1,909 m. The well was the second in an ongoing exploration drilling programme in ATP 1189-P following the Bantam 1 well, which encountered a total 5.5 m net pay. ATP 1189-P, which covers an area of 9,151 sq km, was awarded on 1 January 2015.  Participants in the block containing the well are Santos Ltd (57.5% + Operator), Santos subsidiaries Santos Australia Hydrocarbon Pty Ltd (5%) and Vamgas Pty Ltd (7.5%) and Beach Energy subsidiary Delhi Petroleum Pty Ltd (30%).

Australia (Cooper - Eromanga B.s) Bantam 1

Bengal Energy Ltd is seeking to farm-out interest in exploration permit ATP 934-P, located in the Warburton-Cooper-Eromanga Basin.  Bengal holds 100% interest and operatorship of the permit and is looking for a partner to assist in the upcoming work programme.  Technical presentation material is available for interested parties, upon signing a confidentiality agreement. Bengal reports that it has outlined seven prospects within the permit.  The prospects are targeting stratigraphic traps within the Permian Toolachee and Patchawarra formations.  Bengal reports four permits within the Coonaberry East area of the permit (total 131.8 Bcf gas in place), two within the Ghina South area (59/5 Bcf gas in place) and one in the Coonaberry North area (29.5 Bcf gas in place).  Across the whole permit, Bengal has estimated a possible 666 Bcf 2P gas in place. Bengal is now planning a 260 sq km 3D seismic survey, which meets the permit commitment terms and would also allow acquisition of data over six of the seven outlined prospects. The seismic is planned for Q1 2019 and would aim to identify drill locations, with two to three wells then targeted for drilling in Q4 2019.  It is looking for a partner to assist in the work programme. ATP 934-P covers an area of 1,460 sq km and was awarded on 1 March 2015.  Bengal Energy Ltd holds 100% interest and operatorship of the permit. Parties interested in pursuing this opportunity should contact: Gordon Macmahon (Vice President, Exploration) – email: gmacmahon@bengalenergy.ca            tel: +1 403 781 7017 Richard Edgar (Executive Vice President) – email: redgar@bengalenergy.ca tel: +1 403 781 7016

Bengal Energy Ltd is seeking to farm-out interest in exploration permit ATP 934-P, located in the Warburton-Cooper-Eromanga Basin. Bengal holds 100% interest and operatorship of the permit and is looking for a partner to assist in the upcoming work programme.

LF 8-1-2 was completed on 21 November 2017 without result reported. CNOOC – Shenzhen spudded an appraisal well in the PRMB, South China Sea, on 11 October 2017. LF 8-1-2 is drilled in the Lufeng Sag in 130 m of water with objective in the Miocene-Oligocene clastic paly, particularly in Oligocene Formation. “Nanhai 2” S/S is used for the drilling operation. In 2014 CNOOC completed LF 8-1-1 as an oil discovery well. In the Lufeng sag, there have been several fields on producing, such as LF 13-1/2 operated by CNOOC and LF 7-2 operated by New Field. In this area, several wells have been drilling apart from LF 8-1-1, LF 14-4-1 were reported as discovery well, and another few wells, such as LF 9-2-1, LF 9-6-1, LF 14-2-1, LF 14-3-1 and LF 15-2-1 are not success. CNOOC made discovery of LF 14-4-1 in 2014 when the well penetrated about 150 m of oil pay and tested 1,320 b/d of oil from the Lower Tertiary Zhuhai Formation. In 2015, CNOOC drilled an appraisal well, LF 14-4-2, and reported as a success oil well. In 2017 CNOOC made a discovery in LF 14-8-1d, the well tested commercial oil flow in the Oligocene formation.

China, not found

On 1 December 2019 Wintershall Dea spudded an exploration well, using the “Scarabeo 8” S/S, in PL 894. 6604/6-1 investigated the Gullstjerne prospect which had an Upper Cretaceous Springar Formation sandstone target. The well is located 16 km east of Balderbra which made a new gas condensate discovery in 2018 (in the same licence) and which has similar Springar Formation reservoirs. TD for 6604/6-1 was reached at 3,640 m in the Springar Formation. Three separate sandstones, totalling 120 m, were encountered in the Springar Formation (185 m thick) but the reservoir quality was generally quite poor. There were some traces of gas but the well is a dry hole. It was abandoned on 11 January 2020. Balderbra discovery well 6604/5-1 targeted a robust structural closure (Maastrichtian sand drape over older tilted fault blocks) with an amplitude anomaly between the Gullris (6604/2-1) and Gro (6603/12-1) wells. A gross gas column of 190 m across three separate sandstones totalling 90 m was encountered in the Springar Formation. The upper sandstone unit is thin with variable permeability, the middle sand is thicker (56 m gross) and laminated with 21% porosity, and the lower sand has a gross thickness of 129 m and 15% porosity. The three units are not in pressure communication and no GWC was encountered. Estimated recoverable reserves are between 247-671 Bcfg and 6-19 MMbc. Interest in PL 894 is held by Wintershall Dea Norge AS (40% + operator), Equinor Energy AS (40%) and Petoro AS (20%).

6604/06-01 (Gullstjerne) nfw. (Wintershall Dea 40% op, Equinor 40%, Petoro 20%) in PL 894 block, E. of Balderbrå disc, encountered about 185m of Springar Fm sst, with reservoir rocks in 3 zones totalling about 120m. However, while the sst. contained traces of gas, the reservoir were mainly of poor to moderate quality. P&A'ing dry. WD=1127m, TD=3606m.

By Q4 2018, Sonatrach was understood to have re-entered and concluded drilling operations in its A1-96/2 NFW. Results are not available. The well was drilled on block 2 of the Area 96 EPSA IV concession, located in the Ghadames Basin. It was originally spudded on 21 April 2014, with operations carried out using the ENTP #215 rig. Operations were suspended on 21 May 2014, due to the deteriorating security situation in the area. The well had reached a depth 2,460m in the Silurian Tannezuft Formation before the suspension. A1-96/2 had a PTD of 2,530m and was targeting the Devonian. Area 96 comprises of three blocks in the Ghadames Basin. It was originally awarded to Sonatrach in 2008 (50% +Op) following the EPSA IV Bid Round 4 in 2007. Partners are IOCL (25%) and OIL (25%). Three NFWs were drilled between 2012-2014 on block 1 (A1-96/1, B1-96/1, C1-96/1). All were Palaeozoic discoveries. The conclusion of drilling of A1-96/2 marked the resumption of activities by Sonatrach in Libya, after a four-year hiatus. <P />

Not Found

Mauhu 1 area of the Mahu field, Junggar Basin, recently tested 910 bp/d + 280 Mcfg/d from the Upper Wurhe fm, well since completed for production.

Mauhu 1 area of the Mahu field, Junggar Basin, recently tested 910 bp/d + 280 Mcfg/d from the Upper Wurhe fm, well since completed for production.

Government Holdings (GHPL) has taken a minority interest (2.5%) from OGDC in the Kulachi 3170-8 EL, 2,495 sq km in the Indus onshore Basin, Dera Ismail Khan, Layyah + Dera Ghazi Khan districts of Khyber Pakhtunkhwa. The deal has been made retro-effective 7 Jan '15.

GHPL has taken a 2,5% interest from OGDC (->95,45% op, KPOGCL 2,05%) in the Kulachi 3170-8 EL block (2495km²).

Equinor spudded an HPHT exploration well on the Atlantis prospect approximately 9 km north of Huldra on 13 May 2020. It used the "West Hercules" S/S for 30/2-5 S in PL 878. The well has made a gas and condensate discovery, having encountered a 160 m gas column in the targeted Middle Jurassic Brent Group. This included 60 m of poor to moderate quality sandstone reservoir within the Ness (30 m), Etive (15 m), Tarbert (10 m) and Rannoch (5 m) formations. The well was terminated at a TD of 4,390 m in the Lower Jurassic Drake Formation and the discovery has estimated recoverable reserves between 19 and 63 MMboe. The well was plugged and abandoned on 12 July 2020. Huldra was discovered in 1982 by well 30/2-1 and it came onstream in November 2001. It is a rotated fault block structure with a Brent Group reservoir lying between 3,500-3,900 m. The reservoir was initially HPHT but compression was required to aid production from 2007. From the Huldra platform wet gas was transported to Heimdal for further processing and export and condensate was exported through Veslefrikk. Production ceased in September 2014 by which time it had produced 618 Bcfg, representing a recovery rate of 80%. Interest in PL 878 is divided between Equinor Energy AS (60% + operator), Source Energy AS (20%) and Wellesley Petroleum AS (20%).

Norway (Viking Graben Province), 30/2-5 S (Atlantis) exploration well, operated by EQUINOR (60%), WELLESLEY (20%), SOURCE EN (20%), in PL 878, announced as a gas and condensate discovery. 160 m gas column in the targeted Middle Jurassic Brent group. This included 60 m of poor to moderate quality sandstone reservoir within the Ness (30 m), Etive (15 m), Tarbert (10 m) and Rannoch (5 m poor-quality only) Formations. The well was terminated at a TD of 4,390 m in the Lower Jurassic Drake Formation and the discovery has estimated recoverable reserves between 19 to 63 MMboe.

RockRose Energy has signed a sale and purchase agreement to acquire the entire issued share capital of Idemitsu Petroleum UK from Idemitsu Kosan, a Japanese corporation. The Acquisition will be funded out of the existing facilities and cash resources of the Company.  Completion of the Acquisition is conditional upon confirmation from the UK Oil and Gas Authority that there is no objection to change of control. The Idemitsu UK's assets comprise, inter alia, a substantial number of producing fields in the North Sea which include: The Acquisition also brings with it a number of key employees and its premises in London, which will enhance RockRose's internal expertise providing continuity on the acquired assets and assisting with the management of the wider portfolio. On closure of this Acquisition and previously announced transactions, RockRose will have a projected 6,200 - 7,000 boepd of production in 2018 on an aggregated basis. Andrew Austin, Chairman of RockRose said: 'RockRose is continuing to deliver on its stated strategy of building a business through the acquisition of mature producing assets. We believe that this acquisition is a significant one for the Company and that this portfolio also has a lot of potential for extended field life and gives Rockrose access to significant tax losses. 'We continue to review further acquisition opportunities in North West Europe and, post completion of this along with the previously announced Maersk, Sojitz and Egerton transactions by the end of this year, will have established a material business in the North Sea, set to deliver value to our shareholders.' The Acquisition constitutes a reverse takeover for the purposes of the listing rules, the Company has requested that the UK Listing Authority to suspend the listing of the shares with immediate effect. The Company will proceed to prepare and publish a new prospectus in the coming weeks which will include a competent persons report on the assets of the Company as enlarged by the Acquisition. Further details and updates on the Acquisition will be released in the near future. Original article link Source: RockRose Energy

RockRose has agreed with Idemitsu for the purchase of the latter’s UK sub issued share capital. This involves interests in Repsol’s Tain (50%), Burghley (41,1%), Beauly (40%), Ross (30,8%), Black (30,8%), and Galley (17,4%) fields, in Shell’s Howe (20%) and Nelson (7,5%) fields, and in Premier’s Balmoral (6,7%) and Stirling (16%) fields. No value is revealed.

On 14 December 2017, it was announced that two bids submitted by a consortium of Total S.A., Eni International BV and JSC Novatek in Lebanon’s First Offshore Licensing Round had been approved by the cabinet. The consortium has been awarded Blocks 4 and 9. Exploratory drilling is expected to commence in early 2019. The initial exploration phase of the licences will last up to five years with a possible one year extension. The First Offshore Licensing Round closed on 12 October 2017. The Total consortium was the sole bidder, submitting two bids, one for Block 4 and one for Block 9. No other bids were made. The Lebanese Government was offering five offshore blocks (1,4,8,9 and 10) for exploration and production. Fifty-two international companies were pre-qualified to participate in the licensing round (46 pre-qualified at initial launch of the round in 2013 and an additional six companies pre-qualified at a second round in February/March 2017).  

Lebanon, Block 9

Block XX, Tamsag Basin in FE Mongolia, TD 2,960m, top Lower Tsagaantsav reservoir at 2,803m, o&g shows between 2,803-2,880m, gross reservoir similar to that found northwards (oil-bearing) in PetroChina's adjacent block XIX, 3 zones totalling 22m gross (14m net) identified for probable testing. DQE Intl 40105 rig next to Gazelle-1 before end September.

Mongolia, not found

According to industry sources, the Yaguasito-1 NFW drilled in Q2 2018 on the Tiple Block, was plugged and abandoned as a dry well. The well reached a TD of 2,803m and was targeting a stratigraphic objective in the Guadalupe Formation. No further details are available. The Llanos Basin well was drilled by GeoPark to fulfil a commitment by the company to drill one exploration well on the block at an estimated cost of US$ 7-8 million. On 23 October 2017, GeoPark announced that it had executed a joint venture agreement with CEPSA's Colombian subsidiary, CEPSA Colombia SA, for the Tiple Block. In the event of a commercial discovery, GeoPark was to assume 85% WI and operatorship of the block, subject to contract. Currently, CEPSA has 70% WI and operatorship of the Tiple Block and Perenco 30%, which is now likely to remain. The second extension of the E&P contract expired on 1 May 2018. There are two producing fields on the Tiple Block: Cubarro (discovered in 2010) and Palmero (discovered in 2012) which both produce oil from the Mirador Formation. CEPSA acquired 200 sq km of 3D seismic over the block in 2015. The block lies to the east of GeoPark's prolific LLA-34 Block. In this neighbouring block, GeoPark has discovered more than 230 MMbo of 3P gross reserves and is producing 50,000 bo/d in less than five years on the block from a base of no production. The fields are producing in the Late Cretaceous Guadelopue Formation and Eocene Mirador Formation. The main fields are the Jacana/Tigana complex which are still being appraised and developed (see related Scout article). The exploration area covers approximately 332 sq km with full 3D seismic coverage. GeoPark operates the LLA-34 Block with 45% WI with Parex holding the remaining interest.

Yaguasito 1 (Cepsa 70% op, Perenco 30%) Tiple Block P&A, dry.

Red Willow Offshore is seeking to reduce its working interest at the EnVen-operated Dothraki prospect, where a well is planned in Green Canyon block 166 (G35655) in the deepwater central Gulf of Mexico. The prospect targets an Upper Miocene-aged amplitude anomaly and lies about 7 mi (11 km) north of the Eni-operated Allegheny field, which has produced over 49 MMbo and 95 Bcfg through the end of September 2019. The company is seeking to farm out a 10 – 15% working interest stake. The Bureau of Ocean Energy Management (BOEM) approved exploration plan N-10076 on 8 July 2019 which proposes drilling four wells using a dynamically positioned semisubmersible or a drillship in water depths ranging from 2129 – 2324 ft (649 – 708 m), although Red Willow's farm out material states that the exploration well will be drilled in 1,978 ft (603 m). It is expected to take 120 days to drill, complete and install a subsea tree for each well. The plan calls for drilling operations at the first well to begin on 1 December 2019, but Red Willow has updated this to March 2020. The well has a proposed total depth of 23,000 ft (7,010 m). In a May 2019 presentation to investors, EnVen described Dothraki as a 750-acre (3 sq km) Upper Miocene-aged amplitude in a suprasalt mini-basin, analogous to the Fieldwood-operated Big Bend field in MC 698 (G28022) which has produced over 20 MMbo and 10 Bcfg through the end of October 2019. A multi-well development will be required in the success case, with planned tie-back to the EnVen-operated Prince TLP 13 mi (21 km) to the north in EW 1003 (G13091). Additional information provided by Red Willow estimates a gross resource potential of 6.9 – 20.2 MMboe with a gross rate potential of 6,000 – 15,000 boed. The gross dry hole cost is estimated at USD 48 MM, with the completion cost at USD 40 MM and hook-up cost at USD 129 MM. At Sale 235 in March 2015, a partnership of Ridgewood (47.5%), Red Willow (47.5%) and Houston Energy (5%) submitted a bid of USD 5.166 million for GC 166. There was one competing bid submitted by Fieldwood Energy of USD 710,100. EnVen farmed into the block in January 2019 and currently operates the lease with 33.5% working interest. The remaining interest is distributed between Ridgewood (33.5%), Red Willow (30%) and Houston Energy (3%). Background Information Exxon drilled four wells on the block between 1985 – 1989, targeting the Pliocene interval. None were producers. All four are located to the northwest of EnVen's planned wells.

Red Willow Offshore is seeking to reduce its working interest at the EnVen-operated Dothraki prospect, where a well is planned in Green Canyon block 166 (G35655) in the deepwater central Gulf of Mexico. The prospect targets an Upper Miocene-aged amplitude anomaly and lies about 7 mi (11 km) north of the Eni-operated Allegheny field,

According to local reports in late-June 2019, state company YPFB’s subsidiary, YPFB Chaco, has completed its Florida X-2D new-field wildcat (NFW) well on the El Dorado Este block with gas discovery from the Iquiri Formation as of late-May 2019. The well reached its total depth (TD) of 4,338 m (14,232 ft) in mid-May 2019 after it was spudded in January 2019 with planned total depth (PTD) of 4,440 m (14,567 ft) and objective in the Iquiri Formation. The El Dorado Este block covers 182.5 sq km of onshore land situated in the Foothill Belt of Chaco Basin. YPFB reportedly planned to invest USD 19.8 million in the drilling of Florida X-2D, followed by USD 68. 5 million in the development phase if results are positive. YPFB Chaco is the operator with 90% interest, while partner Petrolex (100% subsidiary of Clontarf Energy) holds 10%. Background Information The El Dorado Este block area includes two producing gas fields, El Dorado and El Dorado Sur, which were put on-stream in 2009 and 2011, respectively. The fields have produced a combined total of 87.7 Bscfg and 2 MMbc at the end of 2018.

Florida X-2D nfw (YPFB 90% op, Clontarf 10%) in El Dorado Este block, according to local reports gas disc. from the Iquiri Fm.

Shell signed on Thursday an EPSA to Kahil block 55, last held by Petrogas over 7,517 sq km on/offshore SE Oman until its expiry in Feb ’18. Commitments include customary G&G + 1 well.

Oman, not found

On 3 February 2020, PetroRio announced that it signed a definitive agreement to acquire 80% working interest in the Tubarao Martelo production concession from Dommo Energia and would acquire the FPSO OSX-3 for USD 140 million. The goal of the transaction is for PetroRio to jointly operate the easterly adjoining Polvo field and the Tubarao Martelo field as a cluster development thus reducing OPEX costs 50% with the synergies and extending field recoverable reserves life to 2035. The announcement by PetroRio also included an update on three new pool discoveries drilled by the operator in December 2019 that are within 6-7 km of the FPSO OSX-3 in the western area of the Polvo production concession. PetroRio plans to tie-back production from its Polvo A fixed platform in the Polvo field to the FPSO OSX-3 located approximately 9.9 km to the southwest and de-commission the FPSO Polvo by mid-2021 with a Capex estimated to be between USD 50-60 million. The transaction is complex with additional financial commitments by PetroRio besides the USD 140 million for the purchase of the FPSO OSX-3. From the current transaction date to the completion of the tieback operation, PetroRio will have rights to 80% of the production from the Tubarao Martelo Field and be responsible for 100% of the FPSO's charter expenses, the Tubarao Martelo field's Opex, and Capex and abandonment costs. During this phase, through approximately mid-2021, Dommo will reimburse PetroRio a monthly fee of USD 840 thousand equivalent to 20% of Dommo's current Opex, excluding the FPSO charter costs. Once the tieback is complete, PetroRio will be responsible for 100% of all costs for the cluster and Dommo will stop paying the monthly fee with PetroRio to have rights to 95% of the produced oil from the cluster up to 30 MMbo produced after tieback, and 96% thereafter. The 1 January 2019 BAR reserves report had the Polvo field holding original oil in place (OOIP) of 404.84 MMbo and original gas in place (OGIP) of 32.55 Bcfg and with a cumulative production of 44.06 MMbo and 4.36 Bcfg represented a recovery factor to that date of 11% for oil and 13% for the gas. The 1 January 2019 BAR reserves report had the Tubarao Martelo field holding OOIP of 428.49 MMbo and OGIP of 46.96 Bcfg and with a cumulative production of 15.02 MMbo and 1.65 Bcfg represented a recovery factor to that date of 4% for oil and 4% for the gas. Both fields have a low GOR of approximately 100 cu-ft/bo and produce oil of 20° to 21° API. The Polvo field had an average daily production in 2019 of approximately 8,437 bo/d and Tubarao Martelo 5,815 bo/d. Dommo Energia held 100% working interest in the Tubarao Martelo production concession but after formal governmental approvals PetroRio will be the operator with 80% working interest and Dommo will hold 20%. On 3 February 2020, PetroRio also announced that it completed two directional special wells and one horizontal development well in the Polvo production concession and discovered three new oil pools one in the Eocene Embore Formation and two in the early-Cretaceous Quissama Formation. The three wells include the POL-N (9-POL-042D-RJS) and POL-Na (9-POL-043DP-RJS) special wells completed in December 2019 and the POL-Nb (7-POL-44HP-RJS) horizontal development well completed and initially tested in January 2020. On 3 December 2019, Dommo Energia announced that it was nearing conclusion of the revitalization project in its Tubarao Martelo field in the Campos Basin that it originally announced it would undertake in November 2018. On 26 November 2018, the company announced that the revitalization project consisted in the completion of well 7-TBMT-4HP-RJS, that needed to be connected to FPSO OSX 3, and the workover of 4 producing wells (7-TBMT-2HP-RJS, 7-TBMT-6HP-RJS, 7-TBMT-8H-RJS and 9-OGX-44HP-RJS). The company indicated that the revitalization project would increase production in the field to an estimated of 10,000 bo/d by the end of 2019. The estimated cost of the project was USD 80 million. From January to October 2019 the field has produced an average of 5,831 bo/d, 597 Mcfg/d, and 2,345 bw/d. In October 2019, only three wells were producing, the 7-TBMT-6HP-RJS, 7-TBMT-8H-RJS and 9-OGX-44HP-RJS, with the 7-TBMT-2HP-RJS not producing. The Tubarao Martelo field was discovered in December 2010 with well 1-OGX-WAIKIKI-1-RJS (1-OGX-25-RJS). The well was targeting post-salt Eocene sandstones of the Carapebus Formation and post-salt Upper Cretaceous carbonates of the Imbetiba Formation. The carbonate reservoir is the main reservoir of the field. Tubarao Martelo field was appraised between February 2011 and April 2011 by 2 wells (3-OGX-35D-RJS and 3-OGX-41D-RJS). The field was declared commercial in April 2012 by OGX. It was the first commercial declaration of an offshore oil discovery for the company. The Tubarao Martelo field started production in December 2013 through the FPSO OSX-3. As of September 2019, is has produced 17.6 MMbo and 1.8 Bcf of gas. Development drilling started in September 2012 and concluded in February 2013. No improved recovery techniques have been applied in this field. The Polvo production concession covers an area of 134.1 sq km and has been producing since 2007 when it was brought online by former operator Devon. From February 2012 to February 2013 the Polvo Field produced an average of 13,711 bo/d, 20° API, and about 20,000 bw/d. There are about 10 wells producing currently. The Polvo Field reservoirs include the Maastricthian and Turonian turbidites of the Carapebus Formation and the Early Cretaceous Quissama Formation carbonates are also productive. Rumors of BP possibly selling assets surfaced in August 2012. On 6 May 2013, HRT announced that it acquired 60% working interest and operations of the Campos Basin Polvo production concession from BP Energy do Brasil Ltda. The retroactive purchase date is 1 January 2013 for a price of USD 135 million. HRT acquired all associated equipment from a separate BP subsidiary that owns and operates the Polvo A fixed platform and other drilling and production equipment with the exception of the FPSO Polvo that is owned and operated under contract by BW Offshore. The transaction was granted formal approval by the ANP on 18 December 2014.

Petro Rio has signed to acquire an 80% interest from Dommo Energia in the Tubarão Martelo ('Hammer Shark') field in BM-C-039.

PL 777 / part-blocks 15/2, 3, 5 + 6, Glitne area, WD 116m, P&A dry at TMD 4,173m (4,162m TVD, Skagerrak fm) 4,197m, Deepsea Stavanger SS off to 25/2-20. Aker BP (op), partners Petoro, OMV + VÃ¥r Energi.

015/06-16S (Hornet Main) expl. (Aker BP 40% op, Var Energi 20%, Petoro 20%, OMV 20%) in PL 777, P&A dry, struck poor-quality sst. reservoirs in the Hugin, Sleipner and Skagerrak Fm. WD=116m. TMD=4173m.

On 29 March 2018, Shell with 100% working interest was granted a preliminary award for the POT-M-948 block in the offshore Potiguar Basin through the ANP Round 15. For the POT-M-948 block Shell offered a bonus of USD 3.4 million and 74 work units.   There were no other bids for the block.  

Shell with 100% working interest was granted a preliminary award for the POT-M-948 block in the offshore Potiguar Basin through the ANP Round 15.

Vintage Energy Ltd reported on 3 August 2018 that it had signed a sale and purchase agreement (SPA) with Beach Energy Ltd, to acquire interest in exploration permit EP 126, located in the Bonaparte Basin.  Vintage Energy will be acquiring 100% interest and operatorship in the permit. The deal remains subject to a number of relevant authority approvals, which were reported to remain pending as of late November 2018. The companies entered a heads of agreement for the deal in June 2018.  Under the terms of the SPA Vintage Energy will take on all permit obligations, including the requirement to abandon the Cullen 1 well, which was drilled in the permit. The permit was awarded to Territory Oil and Gas Pty Ltd in June 2011.  Beach first acquired interest in October 2011, taking 90% interest. After a number of additional interest changes, Beach acquired full interest in the permit in July 2015. During the permit’s validity the Cullen 1 well was drilled, in 2014. It was targeting both conventional and unconventional gas potential.  Target units included the shale and tight sands of the Carboniferous Milligans Formation, Carboniferous Bonaparte Formation and Upper Devonian Langfield Group.  Beach reported that 1,000 m of limestone and interbedded shales had been encountered, with elevated gas readings and natural fractures observed.  In addition, 1,600 m of dark marine shale was encountered. The well was suspended pending testing. Beach had been offering a farm-in opportunity in the permit. Beach was offering a negotiable farm-in opportunity, with the potential farminee to participate in part of the work programme associated with the evaluation of the Cullen 1 well.  A staged farm-in opportunity was available, with a partner to initially carry Beach through an extended production test of the Cullen 1 carbonate play for permit entry.  Future testing would then be undertaken on the shale gas interval of the well. EP 126, which covers an area of 6,740 sq km, was awarded on 15 June 2011. Once the deal is complete, Vintage Energy Pty Ltd will hold 100% interest and operatorship of the permit.

Vintage Energy had signed a SPA with Beach Energy, to acquire interest in exploration permit EP 126.

SE part of AE-0018-M-Okom-01 block, offshore Sureste Basin, WD 27m, J&A 10 Apr ’18, West Titania JU.  PTD was PTD 6,040m, target Kimmeridgian limestones + dolomites.

SE part of AE-0018-M-Okom-01 block, offshore Sureste Basin, WD 27m, J&A 10 Apr ’18, West Titania JU. PTD was PTD 6,040m, target Kimmeridgian limestones + dolomites

South B prospect in L53/48, onshore Chao Phraya Basin, TMD 1,789m, 2 possible oil zones proved water-bearing, P+A’ing. Target Oligocene - Miocene clastics.

L53 AC-C1 op. by PanOrient Energy (100%), South B prospect in L53/48 block, 2 possible oil zones proved water-bearing, P+A’ing. Target Oligocene - Miocene clastics. TMD=1789m.

As announced on 11 March 2020, Chevron has finalized a deal with UC Malampaya Philippines Pte Ltd (a wholly-owned subsidiary of Udenna Corp.) to sell its participating interest of 45% shares in SC 38, located in Northwest Palawan Basin. Signed on 25 October 2019, this deal is part of Chevron's global divestment effort amounting to USD 23 billion through 2023. SC 38 contains the deepwater Malampaya field, the sole gas and condensate producer in the Philippines. The field supplies gas to the Santa Rita, San Lorenzo and Iligan power plants operated by Kepco and First Gas Power Corp, to generate a total of 2,700 MW per day, which account for over 40% of the power demand of Luzon island. Prior to the divestment, right holders of SC 38 were Shell (45%, operator), Chevron (45%) and PNOC-EC (10%). Incorporated in 2002, Udenna Corp. was founded in Davao city and is primarily involved in petroleum, shipping, real estate and telecommunications industries. The independent company holds 51.4% interests in Phoenix Petroleum which is engaged in trading refined petroleum products and lubricants, operation of oil depots and storage facilities and allied services. In 2007, Phoenix expanded its portfolio by acquiring the Batangas Union Industrial Park and Calaca terminal in Luzon with capacity of 50 million liters. Previously in February 2018, PNOC-EC expressed interest to acquire an increased stake in the Malampaya project. The state-owned company and the Department of Energy (DOE) had also conducted a feasibility study on Malampaya field extension when the service contract expires in 2024. In late 2018, Shell submitted a request to extend SC 38, in order to operate the Malampaya field beyond 2024. Background Information The SC 38 was initially awarded to Occidental on 23 February 1989. Within the same year, Occidental discovered Camago field which flowed around 33 MMscfg/d and 730 bc/d. Shell farmed-in in June 1990. In 1992, Shell drilled the Malampaya 1 discovery which flowed around 38 MMcfg/d and 14 Mbbl/d. A declaration of commerciality for the field was signed in 1998. The 10-year exploration contract phase expired on 22 February 1999 with all work commitments fulfilled. The field came onstream in September 2001 at an initial rate of 87 MMcf/d. The 2P recoverable reserves for the field are estimated at 3.5 Tcfg, 123 MMbc and 30 MMbo from the Lower Miocene Nido Formation. The Phase 1 of the Malampaya-Camago project reportedly saw an investment of USD 1.2 billion. A development drilling program on the field, worth USD 135 million, was completed in 2000. The first of the five deviated development wells (each costing USD 20-30 million), Malampaya 5 (MA-5), was spudded on 15 February 2000 and was drilled to a final TD of 3,800 m. The main gas reservoir in the well was cased-off as a future gas producer. A pilot hole from Malampaya 5 confirmed the existence of a 50-55 m oil leg below the gas column and appeared to have resolved the ambiguity regarding the field's gas-oil and oil-water contacts. The oil is described as light crude, similar to Nido. Phase 2 development consisted of the drilling of two infill wells, Malampaya 11 and Malampaya 12, between March and July 2013. The wells, with an estimated cost of USD 250 million, added up to production from the five wells drilled in Phase 1. The field have cumulatively produced approximately 1.9 Tcfg, 75 MMbc and 1.9 MMbo in 2018. Shell managed to mitigate the field production decline since 2015, utilizing a new offshore platform, the Depletion Compression Platform (DCP). The Phase 3 development was conducted to maintain field production levels and meet gas sale commitments until the end of the current production license in 2024. The eastern side of the field still has an upside potential of medium size gas accumulation, which is believed to be holding approximately 100 Bcf.

Philippines (Northwest Palawan B.) Malampaya

The Hydrocarbons Agency (AZU) will shortly launch the Third Onshore Round, following government approval on 30 January 2019. Four blocks will be offered in the round: Dinarides (DI) 13, 14, 15 & 16, which cover 12,134 sq km in the SW of the country. The acreage is highly underexplored although Ravni Kotari 1 (1959, 4,535m) and Nin 1 (1976, 5,220m) encountered hydrocarbon shows, both located with DI-15. Successful bidders will be granted a Production Sharing Agreement (PSA) of up to 30 years, with an initial five year exploration period which can be extended by up to two years. During 2014, Spectrum reprocessed 13,100km of historical 2D seismic shot across the onshore area between 1972-1997. The Third Round will overlap with the ongoing Second Onshore Round which closes on 28 June 2019, with seven blocks offered: Drava-03 (DR-03), Sava-06 (SA-06), Sava-07 (SA-07), Sava-11 (SA-11), Sava-12 (SA-12), Sjeverozapadna Hrvatska-01 (SZH-01) and Sjeverozapadna Hrvatska-05 (SZH-05), all located in the N & NW of the country. Details at https://www.azu.hr

Not Found

HHE is understood to have taken over the Püspökladány block from TDE Services earlier this year, along with a majority interest. The permit lies over 878 sq km in the Békés, Hajdú-Bihar and Jász-Nagykun-Szolnok districts, Hajdusag sub-basin in E. Hungary. Drilling is planned next year.

HHE is understood to have taken over the Püspökladány block from TDE Services earlier this year, along with a majority interest. The permit lies over 878 sq km in the Békés, Hajdú-Bihar and Jász-Nagykun-Szolnok districts, Hajdusag sub-basin in E. Hungary. Drilling is planned next year.

The authorities of the Khyber Pakhtunkhwa province have reportedly opened 6 blocks said to have been ‘dormant’ for the last 10 years, namely Marwat, Kohat, Goragulto, Wali, Latamber + Paharpur. No further details for now.

The authorities of the Khyber Pakhtunkhwa province have reportedly opened 6 blocks said to have been ‘dormant’ for the last 10 years, namely Marwat, Kohat, Goragulto, Wali, Latamber + Paharpur. No further details for now.

On 10 November 2019, the National Iranian Oil Co (NIOC) announced that it has discovered a new oil field in the Khuzestan Province, in SW Iran. Minister of Petroleum Bijan Zangeneh stated that the new field was named Namavaran, adding that it is estimated to contain in-place volumes of around 53 Bbo. The fields reservoir reportedly sits at a depth of 3,100m with an average thickness of approximately 80m. In his announcement the Minister said that of the 53 Bbo resource figure, around 31 Bbo had been previously discovered, with 22 Bbo added recently. Covering an area of 2,400 sq km, Namavaran under- and/or over-lies various other existing oil fields in the area (e.g. Ab-Teymour, Jofeir, Sepeher), suggesting that a recent near field exploration campaign has simply proven up an existing play in the area. In addition, reports imply that the reservoir in question is fairly tight, indicating that only relatively small amounts are recoverable. As such the country's proven reserves will have seen a modest increase, but not as much as a 33% boost like President Rouhani is reported to have claimed.

Press has been rife with reports of a super-discovery in Khuzestan, designated Namavaran and assumed made by NIOC. The fields reservoir reportedly sits at a depth of 3100m with an average thickness of approximately 80m. The massive reserves quoted (53 Bbo) are thought to be attributable to parts of the Mansuri, Sepehr, Susangerd and Ab-E-Teimur fields, in the Oligo-Miocene Gachsaran or Asmari Fm's. The new reservoir would feature an already-respectable 22,2 Bbo of additional reserves, assumed to be in-place, possibly ~10% recovery factor.

During a visit to China in mid-September 2018 Venezuela’s President Nicolas Maduro signed with China a total of twenty-eight agreements, including a memorandum for cooperation was signed for Ayacucho Block 6, where China will drill 300 wells. More details have not been released. On 29 August 2008, local press reported that PDVSA and Administración Nacional Uruguaya de Combustibles, Alcohol y Pórtland (ANCAP) signed an agreement to conduct exploration and production activities in the Ayacucho 6 Block (formerly Hamaca) located in the Orinoco Oil Belt. The Ministry of Energy and Petroleum (MENPET)and PDVSA president Rafael Ramirez said that reserves in the block have been certified, 19 Bbo in place volume, approximately 3.8 Bbo (20%) of which is considered recoverable with present technology. Additionally, the Venezuelan government agreed to provide Uruguay with oil, natural gas and gasoline for 100 years. Background information On 21 July 2006, Uruguayan Ancap President Daniel Martínez along with Argentinian Enarsa President Ezequiel Espinosa and Venezuelan PDVSA President Rafael Ramírez signed an agreement to conduct quantification and certification study of the reserves of the Ayacucho 6 Block (formerly Hamaca) located in the Orinoco Oil Belt in the Southern-Eastern region of Venezuela. This block, whose name is Ayacucho 6, covers an area of some 500 sq km. The new project will be Ancap and Enarsa’s first oil venture in Venezuela. The move follows the authorities and PDVSA's intention, announced on 19 August 05, to conduct a certification of its Orinoco Oil Belt reserves. After the certification of the reserves is completed the companies will be eligible to negotiate joint venture agreement with PDVSA. On 20 January 2006, Venezuelan Minister of Energy and Petroleum (MEP) and President of PDVSA Rafael Ramírez and the Argentine Minister of Federal Planning Julio de Vido, signed an agreement for the cooperation of their respective state-owned oil companies. The Letter of Intent established that ENARSA personnel will work in the Ayacucho 6 Block (Orinoco Oil Belt) while Venezuelan personnel will participate in the exploratory evaluation of blocks CAA-16 and CAA-20 in the Golfo San Jorge. ENARSA was created by Kirchner in 2004 for the purpose of returning state participation to the energy sector. The company has very little in financial assets but was granted by the Argentine Congress exclusive rights to all offshore blocks not under final contract before its creation.

Venezuela Government of Venezuela Signed memorandum for cooperation for Ayacucho Block 6 - East Venezuela Basin

Horiz. well in Zauliyah oilfield area, block 6, Ghudun-Khasfah High (Oman Basin), ops terminated 10 Apr '20, TD 2,846m, rig 58.

Oman (Oman B.) Zauliyah South 1 op. by GOVT OM (60%), SHELL (34%), TOTAL (4%), PTTEP (2%) in Block 06 ops terminated 10 Apr '20 at TD 2846m, no results.

Correction DEA 9 Jan ’19 : Noble denies the transferral of its interest in block C-37 (Yoyo), 688 sq km offshore in the Douala Basin, to an undisclosed buyer – this was an industry rumour. The block features the deepwater Yoyo-Yolanda gas-cond find which straddles the offshore border with Equatorial Guinea and pencilled for a unitised devt by Noble + Atlas. Noble (op), partner SNH.

Correction DEA 9 Jan ’19 : Noble denies the transferral of its interest in block C-37 (Yoyo), 688 sq km offshore in the Douala Basin, to an undisclosed buyer – this was an industry rumour. The block features the deepwater Yoyo-Yolanda gas-cond find which straddles the offshore border with Equatorial Guinea and pencilled for a unitised devt by Noble + Atlas. Noble (op), partner SNH.

SE of Manora platform in G01/48, Pattani Tough / Kra Sub-basin, GoT, TMD 3,881m on 11 Dec '19, target sands mainly water-wet, P&A'ing, Valaris 115 JU. Mubadala (op), partners Tap + Northern Gulf Petr.

Yothaka E.-2 appr Mubadala (op), partners Tap + Northern Gulf Petr.SE of Manora platform in G01/48, Pattani Tough / Kra Sub-basin, GoT, TMD 3,881m on 11 Dec '19, target sands mainly water-wet, P&A'ing,

The NPD confirmed on 5 July 2018 that Equinor has acquired M Vest’s 20% interest in PL 796 (effective from 29 June 2018). The APA 2014 licence covers an area of 253 sq km over parts of blocks 6407/2, 6407/3, 6407/5 and 6407/6, lying to the north, east, south and southwest of Mikkel. It contains the 2011 Cortina gas discovery made by OMV. Equinor will drill a well on the Lanterna prospect in PL 796 in 2019. OMV’s exploration well 6407/5-2 S targeted the Chamonix and Cortina stacked prospects in what was then PL 471. Although the main stratigraphic Chamonix prospect (Upper Cretaceous Lysing Formation) was found to contain tight sandstones, the well proved a gross gas column of 40m in the secondary Cortina target (Upper Jurassic Rogn Formation) and the Middle Jurassic Garn Formation also contained gas. At the time of drilling it was reported that the partners were assessing potential tie-back options but PL 471 was relinquished in 2013. Interest in PL 796 is now divided between Equinor Energy AS (60% + operator), Edison Norge AS (20%) and Point Resources AS (20%).

Equinor has acquired M Vest’s 20% interest in PL 796 (

Endeavour Energy UK has launched the sale of its North Sea oil and gas assets at an ambitious price target of $500 million, according to two industry sources and a document seen by Reuters.The sale is part of group asset sales after Endeavour’s U.S. parent company filed for bankruptcy in 2014.The UK company and its administrators have hired audit firm Deloitte as their corporate finance advisor on the sale, dubbed 'Project Arrow', the document showed.Information documents for the portfolio, which includes non-operating interests in five producing fields, a development project and some fields that have ceased production, were sent to potential buyers in February, with bids expected at the end of last month. The sources said the sale price target was ambitious given that some of the fields are no longer producing oil.The transaction could either be a sale of the share capital of Endeavour or a sale of individual assets or a package of assets.Endeavour Energy could not be reached for comment and Deloitte declined to comment.Endeavour’s Houston-based parent company Endeavour International Corporation, which was founded in the early 2000s and delisted from the New York Stock Exchange in 2014, was forced to file for bankruptcy following a sharp drop in oil prices that year.It subsequently abandoned a deal with bondholders to halve its $1.2 billion debt and instead announced a sale of its U.S. assets, accounting for 18 percent of the company’s total portfolio, and the North Sea fields. That process failed to attract bidders back then, as oil prices remained low.Endeavour's Producing AssetsThe UK North Sea, off the northeastern coast of Scotland, has however seen a flurry of deals in the past two years as longstanding operators make way for a new generation of smaller firms focused on squeezing more profit out of old assets.Private equity-backed buyers such as Neptune Energy, Chrysaor and Siccar Point Energy have snapped up unwanted assets from major energy producers, which have seen investment fall by around 60 percent since 2013, according to energy consultancy Wood Mackenzie.Although North Sea oil output has halved from its peak of almost 3 million barrels a day at the turn of the century, it has rebounded slightly in the past couple of years as new projects have come on stream.Sources did not give any indication on the potential bidders but said that private equity firms continue to have an appetite to invest.Wood MacKenzie estimates that there are 20 private equity-backed vehicles with war chests of around $15 billion for North Sea acquisitions.Click here for information on Endeavour's North Sea AssetsOriginal article linkSource: Reuters

Endeavour Energy UK has launched the sale of its North Sea oil and gas assets at an ambitious price target of $500 million,

On 22 March 2018, Chrysaor reported that it had agreed a deal with Spirit Energy, where Chrysaor will acquire the remaining interest held by Spirit in the Armada field complex (23.58%), Maria (64%) and Seymour (43%). Spirit Energy will still retain liability for decommissioning. The value of the deal has not been disclosed, however it is expected to complete during H2 2018. Chrysaor is looking to drill new wells on the mature fields in a bid to realise their full potential. The Armada development comprises Fleming, Drake and Hawkins fields. These fields were developed together and came onstream in 1997. The Seymour and Maria fields were developed later as subsea tie-backs to Armada. The produced hydrocarbons from Seymour are combined with that produced from the other Armada fields and the gas is exported via the CATS pipeline to Teesside. Liquids are transported through the Forties Pipeline System (Forties) to the Kinneil processing plant at Grangemouth. Upon completion of the deal Chrysaor will be operator and hold 100% interest in the Greater Armada cluster (Drake, Fleming and Hawkins), Seymour and Maria.

On 22 March 2018, Chrysaor reported that it had agreed a deal with Spirit Energy, where Chrysaor will acquire the remaining interest held by Spirit in the Armada field complex (23.58%), Maria (64%) and Seymour (43%). Spirit Energy will still retain liability for decommissioning.

On 7 December 2017, the Federal Agency for Subsoil Use held on auction for the Proninskiy block in Samara Oblast (Volga-Ural Province). Region-Neft emerged as the winner of the auction with the bid of RUB 125.86 million (USD 2.125 million). The winner of the auction will obtain a 25-year E&P license. The Proninskiy block covers 405 sq km and encompasses the Proninskiy, Maklaushskiy, Starososnovskiy and Novo-Yulduzskiy prospects and three leads. Combined oil resources of the prospects are estimated at 40 MMbbl. Oil resources (category D1) of the block are estimated at 26 MMbbl. The starting price amounted to RUB 40.6 million (USD 0.7 million).

Russia, not found

The Western Australian State Government announced that it had opened the 2019 Western Australian State Acreage Release on 10 December 2019. Three blocks, located in the North Carnarvon and Perth basins, are available for bidding, which will close on 9 April 2020. Block L19-1/T19-1 is a combined block and is located in the offshore North Carnarvon Basin. The block covers an area of 629 sq km. It contains the Boojum gas discovery, which was made in 2004 but considered non-commercial due to its location. There are also a number of wells within the permit area – Pepper 1, drilled in 1970 and encountering gas shows and Nero 1 and Sulla 1, which were drilled in 2005, and Nero 2/2ST1 and Gaius 1, which were drilled in 2006 – all of which were plugged and abandoned as dry holes. The block is located in an area surrounded by existing oil and gas discoveries, some of which are producing or have produced. L19-1/T19-1 is being offered as a combined area as a combined application – for a unified work programme – is required. Two permits will be issued (to one applicant) but the work programme will be considered as one unit, across both areas. L19-2 is also located in shallow waters of the North Carnarvon Basin. It covers an area of 1,677 sq km. This block also contains existing discoveries – the Flinders Shoal oil discovery, which was made in 1969 and the Nares oil discovery, made in 1990 but sub-commercial due to the reservoir sand quality. The Nasutus oil discovery, made in 1999, also extends into the southwestern corner of the block. As with L19-1/T19-1, there are a number of previously drilled wells within the L19-2 area. Sandy North 1 (1968), Ripple Shoals 1 (1970), Immortelle 1 (2002) and Crackling South 1 (2003) all encountered oil or gas shows. Mary Anne 1 (1968), Beagle 1 (1969), Crackling 1 (1993), Hardman 1 (2000), Nettie 1 (2000), Banjo 1 (2003) and Hyssop 1 (2003) were all dry holes. Located adjacent to L19-1/T19-1, the block is also in close proximity to existing oil and gas discoveries. T19-2 is located in the Perth Basin and covers an area of 131 sq km. The block contains no existing discoveries or wells, but is located around 8 km east of the Dunsborough oil discovery, which is within adjacent block WA-481-P. Companies looking to apply for a block in the round are required to make the application payment and use the online system to make their bid. Applications are no longer accepted by delivery or post.

The Western Australian State Government announced that it had opened the 2019 Western Australian State Acreage Release on 10 December 2019. Three blocks, located in the North Carnarvon and Perth basins, are available for bidding, which will close on 9 April 2020.

Zawtika-25, block M-09, Moattama Basin, WD 120m, P&A results n/a (though tested) in late Jul ’19, TD 3,450m, Noble Clyde Boudreaux SS off to Zawtika-26  6km to the SE, spudded end Jul ’19. PTTEP (op), partner MOGE.

Zawtika-25, PTTEP (op), partner MOGE, block M-09, Moattama Basin, WD 120m, P&A results n/a (though tested) in late Jul ’19, TD 3,450m,

PRL 145, Cooper-Eromanga, P&A dry at TD 2,142m on 27 Oct ’18. Senex (op) partner Beach.

Huey 1 (Victoria Oil 40% Op, Permian Oil 20%, Beach 25%, Springfield O&G 15%) in PRL 145 block, P&A dry.

F1 fault zone in the Wensu block, Tarim Basin, TD 2,250m on 6 Jan '20, tested 1.5 MMcfg/d from 4 zones totalling 32.5m in a pre-Cambrian basement weathered zone at the end of April. 11m of oil pay was also encountered. To be followed by Hong-26 appr.

China (Tarim B.) Hong-11 nfw op. by ZPEC (100%) in Wensu block, F1 fault zone, D 2,250m on 6 Jan '20, tested 1.5 MMcfg/d from 4 zones totalling 32.5m in a pre-Cambrian basement weathered zone at the end of April. 11m of oil pay was also encountered.

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%).

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%).

Kirthar Pakistan BV (KPBV), a subsidiary of Kuwait Foreign Petroleum Exploration Company (KUFPEC), has plugged and abandoned the Paharpur X-1 new field wildcat (NFW) well within the Paharpur 3170-5 EL (Indus Basin) onshore concession during May 2019 at a TD of 3,000 m. The well was spudded on 12 March 2019 using the ‘CCDC-27’ land rig with a prognosed TD of 3,000 m in the Cambrian. This was the company’s first exploratory well in the block and it was targeting the Cambrian Khewra Sandstone and Permian Tobra Formation. The well was drilling at 1,052 m depth by the end of March and reached 1,956 m during mid-April 2019. It progressed to 2,845 m depth by the end of April 2019. The Paharpur licence covers an area of 2,213 sq km in the Dera Ismail Khan, Tank and Bhakkar districts of the Khyber Pakhtunkhwa / Punjab provinces, and current equity split is as follows: KPBV 60.07% (operator), Pakistan Petroleum Ltd (PPL) 35%, Government Holdings (Pvt) Ltd (GHPL) 2.5% and Khyber Pakhtunkhwa Oil and Gas Company Ltd (KPOGCL) 2.43%.   Background Information The Paharpur licence was exclusively awarded to KPBV on 13 March 2015. KPBV subsequently assigned 2.5% working interest to Government Holdings (Pvt) Ltd (GHPL) and 2.43% to Khyber Pakhtunkhwa Oil and Gas Company Ltd (KPOGCL) with effect from 13 March 2015. As a result, the revised equity split was as follows: KPBV 95.07% (operator), GHPL 2.5% and KPOGCL 2.43%. KPBV had carried out 1,178 LKM 2D seismic acquisition (dynamite source) in the block from October 2016 to March 2017 using the Bureau of Geophysical Prospecting’s (BGP) ‘9501-B’ seismic crew. KPBV was granted a 12-month extension to the Phase-I of initial term of Paharpur EL from 13 March 2018 to 12 March 2019. KPBV assigned 35% of its working interest in Paharpur EL to PPL with effect from 29 November 2018. As a result, the revised equity split is as follows: KPBV 60.07% (operator), PPL 35%, GHPL 2.5% and KPOGCL 2.43%.

Pakistan, Paharpur 3170-5 EL