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Eni continues on its relationship with Qatar Petroleum, farming-out the latter a 30% interest in the Tarfaya Offshore unit comprising 12 explo blocks totalling 29,000 sq km in WD up to 1,000m off Tarfaya, S. Morocco. The agreement is subject to clearance by the Moroccan authorities. Currently Eni (op), partner Onhym.

Qatar Petroleum has entered into an agreement with Eni (->45% op, ONHYM 25%) to acquire a 30% share in the Tarfaya shallow exploration permit, which comprises 12 explo blocks, covers a total area of approximately 23 900km² in WD of up to 1000m.

27/2001/L Koscian-Srem block, Fore-Sudetic Monocline in W. Poland, TD 2,802m, compl gas late May ’18, tested. Target Rotliegendes.

27/2001/L Koscian-Srem block, Fore-Sudetic Monocline in W. Poland, TD 2,802m, compl gas

Shell Offshore Inc. has provided an update for its Whale prospect in the deepwater Western Gulf of Mexico, characterizing the June 2017 oil strike as “one of the largest U.S. Gulf of Mexico exploration finds in the past decade” that “adds to the company’s Paleogene exploration success in the Perdido area.” The 31 January 2018 press statement revealed that the Whale discovery well, the AC 772 1S0B1 bypass well (API: 608054007901), reached a final measured depth of 22,948 ft (6,995 m) and penetrated more than 1,400 net ft (427 m) of oil-bearing pay. When the discovery well finalized, the project’s participants, operator Shell (60%) and Chevron (40%), opted to keep the results of the Whale bypass and original hole confidential saying only that hydrocarbons had been encountered. Whale is an exploratory play found near Shell’s Paleogene-aged production at the Great White field complex. The Whale drill site is found only one block northeast of Silvertip field, a producing Frio oil accumulation. The deeper Wilcox sand is the main reservoir interval at the complex’s Great White and Tobago fields. The Whale prospect resides in some 8,800 ft (2,682 m) of water in the south-central portion of the Alaminos Canyon (AC) area. It lies 150 miles (240 km) east of Port Isabel, Texas, and the US-Mexico maritime boundary is only 20 miles (32 km) due south of the Whale prospect. Shell operates on Alaminos Canyon block 772 through OCS lease G35153. Shell commenced appraisal operations in late October 2017 to gauge the magnitude and extent of the Whale accumulation. The delineation work is occurring in Alaminos Canyon block 728 (G31195), located about 4 miles (6.5 km) northeast of the discovery drill site. Following the discovery, Shell had a 13-well exploration plan approved by the Bureau of Ocean Energy Management over the Whale prospect covering AC blocks 684, 728, 771, and 772, which gives an indication of the potential size of the find. After receiving a permit to drill, the operator commenced the AC 772 #1 bypass on 23 April. The bypass borehole kicked out of the AC 772 1S0B0 original hole (API: 608054007900) at a depth of 20,300 ft (6,187 m). Shell spudded original hole on 7 February and is using the Noble “Globetrotter I” drillship to conduct the Whale activities. The permitted AC 772 #1 drill site corresponds to the AC 772 “C” surface location in Shell’s five-well, initial exploration plan (N-9899) that the BOEM approved in October 2015. The new-field wildcat was designed to spud and bottom in AC block 772, from a surface location sited approximately 2,200 ft (670 m) off the tract’s southwest corner. The operator had scheduled 200 days of rig time to drill and temporarily abandon a successful well. Shell reached total depth on the AC 772 #1 original hole after about 66 days of operations, and spent about 40 days on the bypass prior to applying to plug and abandon. The Whale prospect lies one block northeast of Silvertip field, which found on the east side of the Shell’s Great White field complex that consists of Great White, Silvertip, and Tobago fields. The hydrocarbon accumulations associated with the field complex are trapped in large structures formed along the Perdido Fold Belt, a prominent northeast-trending series of compressional folds in the southern AC protraction area. The Whale wells are structurally on-trend with the Silvertip accumulation and will target the correlative Paleogene-aged Frio interval found productive at Silvertip and likely the prospective deeper Wilcox section that produces at adjacent Great White and Tobago fields. It is estimated that a Whale prospect well will have seen the Lower Tertiary (Paleogene) strata age-equivalent to the main hydrocarbon-bearing reservoirs at the Great White complex at around 18,000 ft (5,486 m). Given the bypass’ kickoff point of 20,300 ft (6,187 m), it appears that the Whale wells may be testing Lower Paleocene and possibly older Cretaceous strata with a final drilling depth in the 22,000-25,000 ft (6,706-7,620 m) range. Shell owns a 60% working interest in the G35153 lease (AC-772) and operates this acreage for participating partner Chevron U.S.A. Inc., which holds the remaining 40% equity stake. The BOEM issued the ten-year lease, a standard 5,760-acre (23.31 sq km) tract, with a 1 January 2014 effective date and a scheduled primary term ending date of 31 December 2023. Bidding alone, Shell acquired the acreage 100% for USD 4,222,000 at OCS lease sale 233, held over the Gulf’s Western planning area in August 2013. Shell’s bonus bid topped a USD 2.06 million offer for the same tract made by Chevron U.S.A. Inc. In July 2016, Chevron U.S.A. Inc. farmed into the G35153 lease, taking a 40% non-operating interest in the tract in a transaction that took effect on 1 January 2016. The current equity split for the G35153 lease reverses the partner’s ownership of adjacent Silvertip field, where Shell operates with 40% of the title interest and Chevron owns the 60% majority stake.

AC 772 001S0B1 (Whale) op. by Shell (60%, Chevron 40%) in G35153 OCS Lease, large oil deep-water discovery, encountered more than 427m net of oil bearing pay. Evaluation of the discovery is ongoing, and appraisal drilling is underway to further delineate the discovery and define development options.

On 26 June 2018, Energistyrelsen, the Danish Energy Agency (DEA), launched the 8th Licensing Round. The round covers unlicensed acreage west of 6deg 15' E longitude, with around 14,500 sq km available for bidding, and closes on 1 February 2019.Pursuant to Article 12.1a of the Act on the Use of the Danish Subsoil (Subsoil Act), amended to September 2011, applications are invited for licences to explore and produce hydrocarbons under Articles 5 and 13. The bid round is also accompanied by a dedicated model licence. The following terms apply as delineated in the invitation to bid and the model licence:->Exploration period of six years. An additional four years may be requested. ->A production period of 30 years accompanied by a one-off DKK 100,000 fee. Extension possible. ->A 25% corporate income tax rate (including additional corporate tax of 3%), which is deductible from the basis for assessing Hydrocarbon Tax (HT). ->A HT rate of 52%. In determining the basis for assessing HT, a 5% hydrocarbon allowance is granted on investments for six years (a total of 30%). ->During the period from 2017 to 2025, companies may apply an investment window for certain types of investments to be approved by the DEA. Consequently, the hydrocarbon allowance over a six-year period is raised from 5% to 6.5% a year (a total of 39%). In addition, the rate of reducing balance depreciations in the HT is raised from 15% to 20%, and the time of deduction for the two deductions is changed from the date on which the investments are put into use to the date of payment. However, the deduction is subject to the condition that oil prices remain below US$ 75/barrel (2017 figures, escalated at 2% per year). If the price is higher, the tax deduction must be repaid. No tax losses from other income can be deducted from income derived from Danish oil and gas upstream activities. ->Through the Nordsofonden, the state will hold a paying interest of 20% in all licences. Where two or more applications for the same area are considered to be equally qualified under the selection criteria, the final selection will be made on the basis of a supplementary bid which amounts to an additional share to be offered to the Nordsofonden over and above the mandatory 20% (Article 12a.3) of the Subsoil Act. The total licence share of the Nordsofonden may not exceed 40%.In March 2017, fiscal terms applying to the ongoing development of the Tyra Field were relaxed. This allowed a full redevelopment of the Tyra Field to proceed that would allow the recovery of an estimated 129 MMbo. Similar terms have been applied to the 8th Licensing Round.

On 26 June 2018, Energistyrelsen, the Danish Energy Agency (DEA), launched the 8th Licensing Round. The round covers unlicensed acreage west of 6deg 15' E longitude, with around 14,500 sq km available for bidding, and closes on 1 February 2019.

F18-C / F19-D1 / F19-D4 block (Banarli), Thrace Basin in NW Turkey, TD 4,196m, further to DEA 28 Dec ’17, production testing operations have resumed.

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.

Further to DEA 6 Dec '19 (discovery): Römerberg permit, Upper Rhine Graben near Speyer, TD 2,415m, oil find in 2 zones of the target Buntsandstein, produced 1,500 bo to date under test, appraisal work required. Neptune (op), partner Palatina GeoCon.

Schwegenheim-1 nfw Römerberg permit, Upper Rhine Graben near Speyer, TD 2,415m, oil find in 2 zones of the target Buntsandstein, produced 1,500 bo to date under test, appraisal work required. Neptune (op), partner Palatina GeoCon.

On 11 June 2018 Total reported that it signed a new concession contract with Sonatrach, Repsol and Alnaft on the Tin Fouye Tabankort (TFT) field, Illizi Basin, south-east of Algeria. The new contract will become effective upon the approval by the Algerian authorities and replace the existing one which is due to expire in 2019. It will allow to continue production at the field for another 25 years. Interests in the new concession are: Sonatrach 51%, Total 26.4% and Repsol 22.6%. The partners will carry out drilling and investments required to develop additional reserves estimated at more than 250 million barrels of oil equivalent. These investments will allow to maintain the production of the field which is currently over 80,000 b/d of oil equivalent for six years. The new concession is a result of a framework agreement signed last year. In April 2017 Sonatrach and Total signed a framework agreement strengthening the existing partnership between the two companies. The agreement was signed by Sonatrach’s CEO Abdelmoumen Ould Kaddour and Total’s CEO Patrick Pouyanne. It established a new contractual framework for the Timimoun gas development, enabled continued joint operations on the TFT gas-condensate field, provided for the joint development of a new project and arranged a settlement of outstanding differences between the two companies. Background information The TFT field is a giant gas and oil field and is considered as one of the largest hydrodynamic trap in the world. The field was discovered in February 1961, with new-field wildcat Tin Fouye 1. The two main reservoirs are the Upper Ordovician Gara Louki Formation (oil & gas) at a depth of 1,400 - 1,500m and in the Lower Emsian F6 Sandstone Unit (oil) at 750m. The main Gara Louki reservoir has been subdivided into two superimposed geological units which are in vertical pressure communication. The upper unit has a coarser facies and extends over the whole of the reservoir with a constant thickness of between 10 and 20m from west to east. The lower unit is more laterally discontinuous with rapid lateral facies changes and displaying much poorer reservoir characteristics. Gross reservoir thickness of the Gara Louki Formation varies from 0 - 59m. Oil production started in 1961 from the F6 sandstone reservoir, but output went into a gradual decline. Water injection began in 1980 in the Ordovician reservoir. On 28 January 1995, Sonatrach, Total and Repsol announced that they had signed a 20 year production-sharing contract for the development of the gas, condensate and LPG reserves of the TFT field. Commercial gas production started in March 1999.

Tin Fouye Tabankort (TFT) awarded by Sonatrach 51%, Total 26,4%, Repsol 22,6%, Alnaft has a carried interest

On 1 December 2017, OMV AG completed the acquisition of a 24.99% stake in Severneftegazprom developing the Russkoye Yuzhnoye field in Yamalo-Nenets Autonomous Okrug (Western Siberia). The transaction is retroactive as of 1 January 2017. On 5 March 2017, OMV AG and Uniper SE (E.ON SE) signed an agreement to acquire a 24.99% stake in Severneftegazprom. Uniper SE had agreed to sell its share in the project for USD 1.85 billion plus cash on the balance sheet as 31 December 2016. By its completion, OMV adds 100,000 boe/d of production. In 2016, the company produced 311,000 boe/d worldwide. In addition, OMV books recoverable reserves of 580 MMboe. Russkoye Yuzhnoye, discovered in 1969, is located in the eastern part of the Nadym-Taz Basin. Hydrocarbon pools have been identified within the 2,400 m section, from Middle Jurassic to Turonian but the major portion of gas reserves belongs to Pokur Formation PK1 Unit (Cenomanian) at a depth around 900 m. In 2016, Severneftegazprom produced about 25 Bcm of gas (2.3 Bcf/d). Initial 2P reserves of the field are estimated at 31.9 Tcf of gas, 70 MMbbl of oil and 14 MMbbl of condensate. Before the announced deal, Severneftegazprom was owned by Gazprom (40%), Wintershall (35%) and Uniper (25%). It has to be noted that Russkoye Yuzhnoye is the feedstock for the Nord Stream pipeline linking Russia with Germany. OMV is involved in the Nord Stream-2 project scheduled for completion in 2019.  

Russia (Central Volga-Urals Province (Volga-Urals B.)) Yuzhnoye (Bashkortostan)

Pakistan Petroleum Ltd (PPL) has assigned 25% working interest in Bela West 2566-6 EL (Bela-Muslimbagh-Zhob Ophiolite Belt) onshore licence to Mari Petroleum Company Ltd (MPCL) with effect from 19 August 2019. As a result of this transaction, the revised equity split is as follows: PPL (37.5%, operator), Kirthar Petroleum Ltd BV (35%), MPCL (25%) and GHPL (2.5%). Bela West EL covers an area of 2,455 sq km and is located in the Khuzdar, Awaran and Lasbela districts of Balochistan province. PPL is currently drilling the Bela West X-1 new field wildcat (NFW) well in the licence which has reached a depth of 4,345 m depth during late July 2019. This is the company’s first well in the block and the drilling operation is expected to be completed in August 2019.   Background Information PPL was awarded the Bela West licence with the signing of a Petroleum Concession Agreement (PCA) on 10 February 2014. PPL acquired 609 line km 2D seismic in the block during June-November 2015 using the BGP “9501-E” seismic crew. The company was granted an 18-month extension to the Phase-I of initial term of Bela West EL from 10 February 2017 to 9 August 2018. It was followed by a further six-month extension up to 9 February 2019. It was reported in March 2019 that PPL had assigned a 2.5% working interest in the Bela West EL to GHPL which was made effective retrospectively from 28 February 2014. As a result of this transaction the revised equity split was as follows: PPL (62.5%, operator), Kirthar Petroleum Ltd BV (35%) and GHPL (2.5%). PPL was granted a 12-month extension to the Phase-I of initial term of Bela West EL from 10 February 2019 to 9 February 2020.

PPL have assigned 25% WI to Mari Petroleum Co Ltd (MPCL) in the Bela West 2566-6 EL .

Parnaiba Gas Natural (PGN) suspended with results unreported the 4-PGN-ARAGUAINA-SE-MA (4-PGN-022-MA) new-pool wildcat (NPW) in the BT-PN-001 contract, PN-T-102 block on 10 December 2017.  The well may be a dry hole as the operator has yet to file a gas show report for it.  The NPW was spudded on 14 November 2017.  The well had a proposed total depth (PTD) of 2,178 m.  The primary targets were the Devonian Cabecas Formation and the Mississippian Poti Formation. The well is located in the southeastern corner of the discovery evaluation plan (PAD), the PA_1OGX119MA_PN-T-102 in the Parnaiba Basin approximately 20.4 km north southeast of the 1-OGX-FAZSERRINHA-MA (1-OGX-120-MA) NFW gas discovery well drilled in 2013.   On 11 October 2017 the ANP approved a 3rd modification to the discovery evaluation plan (PAD) operated by Parnaiba Gas Natural (PGN) associated with the BT-PN-001 contract, PN-T-102 block that includes new commitments and a final expiry extension pending conditions.  The operator will have a decision point on 20 December 2017 to drill a horizontal well from a side-track of firm well, assumed to be the 3-PGN-ARAGUAINA-003D-MA (3-PGN-021D-MA) outpost.  The horizontal well is dependent on the results of the firm well.  The operator has a second decision point on 6 April 2018 to drill another exploration well on a newly mapped structure nearby.  If all of the commitments are met the final expiry of the PAD will be on 10 September 2018. On 15 June 2016 the ANP approved a 2nd modification to the discovery evaluation plan (PAD) operated by Parnaiba Gas Natural (PGN) associated with the BT-PN-001 contract, PN-T-102 block that includes a final expiry extension pending conditions.  Two new-field wildcats are associated with the PAD and include the 1-OGX-ARAGUAINA-MA (1-OGX-119-MA) and the 1-OGX-FAZSERRINHA-MA (1-OGX-120-MA) both located in the block. The PAD modification approval has firm and contingent commitments.  The June 2016 firm commitment for the PAD is for the operator to conduct petrophysical and geo-mechanical analysis of the data obtained from drilling the 3-PGN-ARAGUAINA-002A-MA (3-PGN-016A-MA) outpost, suspended with gas shows in January 2016.  The operator will also have to stimulate the outpost well and conduct a formation test. The operator has to conclude the firm commitments by 15 November 2016 and decide to conduct the contingent commitments or the PAD will expire.  The contingent commitments include the acquisition of 102 km of 2D seismic and the drilling of one well and a formation test of that well.  If the contingent commitments are conducted the PAD will have a final expiry date of 10 February 2018 whereby commerciality will have to be declared or the PAD relinquished. On 26 June 2014 the ANP originally approved the discovery evaluation plan (PAD) filed by Parnaiba Gas Natural (PGN) for the PA_1OGX119MA_PN-T-102 carved out of the BT-PN-001 contract, PN-T-102 block in the Parnaiba Basin. The contract was partially relinquished with an evaluation area carved out of the block for the two discovery wells that covers an area of 963.70 sq km.  Two new-field wildcats are associated with the PAD and include the 1-OGX-ARAGUAINA-MA (1-OGX-119-MA) and the 1-OGX-FAZSERRINHA-MA (1-OGX-120-MA) both located in the block. The PAD covers an area of 963.70 sq km. The original expiry date of the PAD was 10 October 2016. Parnaiba Gas Natural is the operator of the BT-PN-001 contract with a 100% working interest after acquiring all of the working interest from former partners Imetame, Orteng and Delp.  On 28 December 2015 the ANP granted Parnaiba Gas Natural approval to acquire all of the working interest in the BT-PN-001 contract, PN-T-102 block from its three former partners Imetame who held 16.665% working interest, Orteng who held 16.6665%, and Delp with 16.67%.  

Brazil (Parnaiba B.) 3-PGN-ARAGUAINA-002A-MA op. by PARNAIBA (100.0%) in PN-T-102 block

Further to DEA 5 Dec ’17, OMV announces the sale of its Pakistan assets to United Energy Group subsidiary Dragon Prime Hong Kong Ltd for €157 MM. The deal is subject to usual approvals and should close by year-end. Involved are 5 D&PLs of which the producing Sawan, Miano, Latif, Gambat, and Mehar blocks. It also holds interests in 5 explo blocks (4 operated).

Dragon Prime Hong Kong Limited acquired OMV’s interests in 5 development and production leases, operating the producing Sawan, Miano, Latif, Gambat and Mahar blocks, for US$191 MM. It also has an interest in 5 exploration blocks, with operatorships on 4.

Santos Ltd was awarded production licence PL 1035, located in the Warburton-Cooper-Eromanga Basin, on 9 July 2019.  The licence has been awarded for a period of five years and will expire, or be eligible for renewal, on 8 July 2024. The licence was applied for in June 2017. The licence contains the Monte gas discovery, which was made in June 1996. The licence is replacement tenure for PL 139, which covered the same area and location and was surrendered on 9 July 2019.  PL 139 had been awarded in June 1999. PL 1035 is one of three production licences awarded to Santos on this date, all as replacement tenure for prior licences. PL 1035, which covers an area of 25 sq km, was awarded on 9 July 2019.  Participants in the permit are Santos Ltd (25% + Operator), Santos subsidiaries Santos Petroleum Pty Ltd (25%) and Vamgas Pty Ltd (5%) and Beach Energy subsidiaries Lattice Energy Ltd (25%) and Delhi Petroleum Pty Ltd (20%).

Santos Ltd was awarded production licence PL 1035, located in the Warburton-Cooper-Eromanga Basin,

The BOEM intends to open 14,696 blocks totalling 315,655 sq km in WD 3-3,400m for o&g leasing offshore Texas, Louisiana, Mississippi, Alabama and Florida under Lease Sale 252. Some acreage will be excluded, namely those under Congressional moratorium, in the area known as the northern portion of the Eastern Gap, and blocks within the Flower Garden Banks National Marine Sanctuary. Proposed Notice of Sale from http://www.boem.gov/Sale-252/.

United States, not found

On 2 March 2020, operator Tower Resources plc reported it has executed binding heads of terms for a farm-out to OilLR Pty Ltd (OilLR) of a 24.5% working interest in its 119 sq km Thali permit, located in the shallow water of the Rio del Rey area, eastern Niger Delta. However, Tower Resources is still in discussion with several other parties regarding this farm-out deal. The parties' intention is to complete the transaction by 15 April 2020, subject to usual confirmatory due diligence and OilLR having provided payments to Tower and into escrow of USD 7.5 million, and Tower having demonstrated that it has funding from its own or other sources for the balance of the USD 15 million that include the funds Tower has already spent on the planned appraisal Njonji 3. Also, the agreement will terminate automatically on 29 March 2020 if Tower has not received proof of funding from OilLR by that date. As a reminder, Tower Resources hopes to spud the appraisal well Njonji 3 by mid-year 2020 and thus, has intensified the fundraising efforts for that drilling. Also, by mid-January 2020 the company obtained from the Cameroon Authorities an exceptional extension of the initial exploration period of the license, now valid until mid-September 2020. Based on an independent reserves’ report from Oilfield International Ltd in late 2018, Tower Resources estimates the gross mean contingent resources of the Njonji structure at 18 MMbbl of oil, which could be transformed into recoverable reserves in case of a success at Njonji 3. Drilling costs are estimated by the company between USD 10 million (dry hole) to USD 14 million (including DST). As of early 2020, the block contained five exploration wells including two discoveries: Rumpi 1 (oil and gas discovered by Pecten Cameroon in 1998), Njonji 1B (oil discovered by Total E&P Cameroon in 2008).

Tower (->76,5% op.) and OilLR Pty Ltd have reached heads of terms on the latter's possibly farming-into the Thali block (24.5%), 119 sq km in shallow waters. Discussions however continue with other possible suitors.

Pursuant to an MoU signed in January for risk service contracts to deepwater blocks 30, 44 + 45, it is now understood that Exxon will hold operatorship and 60% and Sonangol be carried for 40% through exploration when the Namibe Basin contracts get signed.

Angola, not found

On 10 October 2019, the consortium of Chevron, Repsol and Wintershall DEA bid on and were granted a preliminary award for the 698.21 sq km C-M-845 block in the deep-water offshore Campos Basin from the ANP Round 16. There were no other bids for the block. The consortium bid a bonus of USD 6.56 million at 1 USD to 4.11 BRL and USD 8.09 million in minimum work commitments.  Chevron is operator with 40% working interest, Repsol holds 40% working interest, and Wintershall DEA holds 20% working interest.

Brazil, not found

PEMEX suspended as a gas and condensate discovery the Kokitl 1EXP new-field wildcat (NFW) in the AE-0089-2M-Cinturon Subsalino-07 entitlement block on 16 December 2018.  The final total depth (TD) of the well was 5,394 m. The NFW was spudded on 6 October 2018.   The CNH granted the operator a permit for the NFW on 13 September 2018. The NFW had a proposed total depth (PTD) of 5,300 m and was targeting the Wilcox Formation. PEMEX utilized the “La Muralla IV” S/S to drill the well in a water depth of 1,940 m.      The NFW is located at the very northern block boundary and approximately 7.8 km north north-west of the Corfu 1 NFW plugged and abandoned dry in 2015. The NFW had prospective resources estimated to be 113 MMboe. SENER granted the AE-0089-2M-Cinturon Subsalino-07 entitlement to Pemex 100% through Ronda 0 on 27 August 2014.  The block covers an approximate area of 860 sq km. Pemex plugged and abandoned dry the Corfu 1 new-field wildcat (NFW) on 25 August 2015. The operator drilled the well to a total depth (TD) of 5,779 m.  The CNH reported the final status of the well as a non-commercial producer. The operator tested a zone from 5,730 m to 5,763 m but apparently non-commercial.  The NFW was spudded on 28 February 2015.  The well had a proposed total depth of 5,779 m.  The Paleocene to Eocene Wilcox Formation was the primary objective in a sub-salt structural objective. The “Bicentenario” semisubmersible drilled the well in a water depth of approximately 2,100 m.  The well is located in the south western area of the Deep-Water Gulf of Mexico Basin within the Mexican Ridges Province.  It is located about 72 km south-west of the Vasto 1 ST Pemex junked in the Perdido Fold Belt area in February 2015.

Mexico (Sigsbee Sub-basin (DWGoM B.)) Vasto 1

Carnarvon Petroleum Ltd was awarded exploration permit EP 497, located in the Peedamullah Shelf/Barrow Sub-basin, North Carnarvon Basin, on 16 November 2017. The permit has been awarded for a period of six years and will expire on, or be eligible for renewal by, 15 November 2023. The permit lies between approximately 2 km and 25 km from the Western Australia coastline and has been awarded by the Department of Mines, Industry Regulation and Safety. Carnarvon filed the permit application as STP-EPA-0142 on 28 October 2016, covering 478 sq km. The application area has been awarded in full as EP 497. Work commitments have been assigned for the duration of the permit’s validity and does not include any exploration drilling. In the first two years, Carnarvon will focus on building a well and seismic database of the block through data collection, mapping and geotechnical work. The central area of the permit, within the Barrow Sub-basin, is covered by the Flinders 3D survey which was acquired by TGS in 2001. The survey extends north over the Cyrano, Chervil, Herald North and Pepper South oil discoveries which offer structural plays in the Upper Jurassic to Lower Cretaceous. The play extends to the Santa Cruz oil/gas discovery with EP 497 which was discovered in 1993. Santa Cruz 1 was drilled on vintage 2D seismic data and is not covered by the Flinders 3D seismic survey. Thus, the areal coverage of the structure is currently unknown. Low quality structure maps from the vintage data indicate that the well clipped a structure of around 50 sq km with the possibility of additional stratigraphic elements analogous to the Stag oil field. Two wells are located within the permit area: Bricklanding 1 and Dill 1. Bricklanding 1 was designed to test the low side fault closure against the Flinders Fault in 2006. The well was plugged and abandoned with minor gas shows in the Calypso Formation. In the terms three to five discretionary programme, an offshore geochemical survey is planned followed by geotechnical studies. Should the survey prove up an area of accumulation, the sixth term will conclude with the acquisition of 100 sq km of new 3D seismic data. The total exploration programme over the six year validity period is expected to cost around AUD 7.9 million. Carnarvon has been awarded five exploration permits in the past 18 months, and is now operator of nine permits from the near shore Barrow Sub-basin to the Nancar Trough, Bonaparte Basin. Carnarvon is also continuing its joint venture with Quadrant Energy in the Roebuck Basin which includes the Phoenix South and Roc discoveries and Dorado Prospect. EP 497, which covers an area of 478 sq km, was awarded on 16 November 2017.  Carnarvon Petroleum Ltd holds 100% interest and operatorship of the permit.

Australia (Pine Creek Orogen) (It's a petroleum rights. Please summarize by yourself). In IHS database: EP(A) 256 (a) op. by NT GAS AUS (100.0%) to be check.EP(A) 256 (c) op. by NT GAS AUS (100.0%) to be check.STP-EPA-0142 op. by OTHERS (100.0%) to be check.EP (A) 287 (a) op. by ARAFURA O (100.0%) to be check.EP(A) 256 (b) op. by NT GAS AUS (100.0%) to be check.EP (A) 287 (c) op. by ARAFURA O (100.0%) to be check.EP (A) 287 (b) op. by ARAFURA O (100.0%) to be check.

L53 DD1 surface location in block L53/48, onshore Chao Phraya Basin, compl. oil at TMD 1,903m (1,589m TVD) on 12 Nov ‘18, combined 32m net oil pay over 4 intvs between 1,044-1,105m (VD), possibly in the L. Miocene.

L53 DD1 surface location in block L53/48, onshore Chao Phraya Basin, compl. oil at TMD 1,903m (1,589m TVD) on 12 Nov ‘18, combined 32m net oil pay over 4 intvs between 1,044-1,105m (VD), possibly in the L. Miocene.

Draupner Energy is farming out interest in licence P2331 (blocks 38/22b, 38/23a, 38/27, 38/28, 44/2 and 44/3a) which contains the Balvenie prospect and licence P2487 which hosts the Durham prospect. The prospects are located in shallow water (approximately 30 m) near gas production facilities and export infrastructure with spare capacity for a potential tie back. Balvenie and Durham have Middle Zechstein Hauptdolomit targets with upside in the Upper Zechstein and Lower Carboniferous Scremerston Formation. Mean recoverable resources for Balvenie in the primary targeted reservoir are 1,160 Bcf and in Durham its 723 Bcf. The company believes that in an ultimate success case the prospects could yield approximately 3 Tcf of recoverable gas. The company is looking for partners to further mature the prospects through the acquisition and processing of preferably 350 sq km but at least 200 sq km of 3D seismic data to primarily reduce the uncertainty on the extension and geometry of the Hauptdolomit target, improve the depth conversion model and reduce risks associated with the trapping mechanism. Alternatively, there is a lower cost option of a full carry on to acquire all available 2D seismic field data. However, this carries a higher risk, poorer pre-drill resource estimations and potentially misplacing the exploration well. Equity is available in exchange for coverage of historic costs, carry on work programme elements and/or a cash offer. The primary reservoir objective of the Zechstein Hauptdolomit has a thickness of 45 - 65 m at Balvenie. It consists of platform carbonates deposited in a lagoonal environment as ooid and oncolite shoals with local stromatolite development. Field studies onshore England show good lateral extent of the carbonate platform facies for at least 15 km. Porosity and permeability has been enhanced through dolomitisation. Offshore well data and onshore field studies prove good average porosities of 16% and up to 25% in places. Permeabilities average at 50 mD with localised fracture networks further enhancing the permeability. The anhydrite and halite of the Basalanhydrite and Stassfurt Halite form top seals. Further reservoir potential is provided through thin (10 m) limestones and dolomites from the Plattendolomit and Zechsteinkalk stratigraphy. The lowermost sedimentary package contains Upper Devonian Buchan sandstones and Middle Devonian Kyle limestones which overlie a fractured basement. These reservoirs could be penetrated by deepening the exploration well by 500 m to 2,700 m and running an additional casing string. The reservoirs are trapped by a 4-way dip closure ranging in size from 97 sq km to 197 sq km. The primary source rock is the Lower Carboniferous Scremerston formation which contains coals and organic rich shales with TOC’s of up to 40% and HI of 250 mgHC/gTOC. The 791 sq km licence P2331 was awarded on 15 May 2017 to Draupner in the 29th Licensing Round. The initial term for the licence is split into three phases each for a duration of three years. Phase A involved firm commitments of obtaining 2,000 km legacy 2D seismic data, all relevant well data in the acreage and G&G studies to be completed. Draupner completed this programme through obtaining over 5,800 km of 2D seismic data, collecting data on 5 wells and completing seismic interpretation, source rock modelling, reservoir and prospect evaluation. Licence P2487 was an additional acreage acquired in the 31st Offshore Licensing Round. P2331 and P2487 are held solely by Draupner Energy Limited (100% + operator). For further information please contact: Ann-Charlotte Hogberg, Commercial Director Tel +46 (0)7308 48077 Email: [email protected]

Draupner Energy is farming out interest in licence P2331 (blocks 38/22b, 38/23a, 38/27, 38/28, 44/2 and 44/3a) which contains the Balvenie prospect and licence P2487 which hosts the Durham prospect.

Operator Heritage Exploration and Production Ghana Ltd (Heritage) is offering an undisclosed working interest in its 180 sq km deepwater South West Tano block (western Ghana), located between Tullow's Jubilee and TEN producing fields. The company is planning two firm wells to be drilled in 2H 2020, before the first exploration period expires in mid-2022 (see separate article). Heritage operates the tract alongside with Blue Star Exploration Ghana Ltd, Ghana National Petroleum Company (GNPC) and GNPC Exploration and Production Company Ltd (Explorco). Only one exploratory well was drilled by previous operator Tullow within the block's perimeter, Sapele 2, which was plugged and abandoned dry in early 2013. Contact details: Keith Walters (VP Operations) [email protected] +44 7384 513 630

Ghana, TEN (Dev & Prod)

Pioneer Natural Resources has signed a purchase and sale agreement with Sundance Energy to sell approx. 10,200 net acres in the western portion of Pioneer’s Eagle Ford Shale acreage position for $102 million, subject to normal closing adjustments. The acreage is located in Atascosa, LaSalle, Live Oak and McMullen Counties, Texas. Current net production is approx. 1,100 barrels of oil equivalent per day.After the sale closes, which is expected during the second quarter of 2018 and is subject to the satisfaction of customary closing conditions, Pioneer’s acreage position in the Eagle Ford Shale will be approx. 59,000 net acres, all of which is held by production. As previously announced, the remaining Eagle Ford Shale acreage position is also being divested, with a data room expected to open next week.Original article linkSource: Pioneer Natural Resources

Reliance Ind. is selling some of its shale assets in the Eagle Ford to privately-held Sundance Egy for US$100 MM.

On 20 December 2017, the ANP approved the final step in a complex transaction whereby Statoil is now the operator and 100% working interest owner of the BM-ES-040 contract, ES-M-529 block and the BM-ES-041 contract, ES-M-531 block after acquiring a 50% working interest (WI) from former partner Perenco.   The deal was reported originally in early 2017 after a four step process led to Statoil being operator with 50% WI and Perenco the lone partner with 50% WI.  In July 2017 the operator was granted second extension of the PAD associated with the two contracts. On 16 December 2016, the ANP approved a complex transaction whereby Statoil is now the operator of the BM-ES-040 contract, ES-M-529 block and the BM-ES-041 contract, ES-M-531 block after acquiring a 50% working interest (WI) part of it from former operator and now 50% partner Perenco.  The transaction involved a four stage process for unknown reasons.  First Perenco farmed-out 30% WI and operations to Statoil, giving Statoil as operator 30% WI OGX with 50%, and Perenco and Sinochem each with 10% WI.  The second stage was Perenco assuming 40% WI of the OGX 50% WI and Sinochem assuming 10% with Statoil with 30%, Perenco with 50%, and Sinochem with 20%.  The third stage was Perenco assuming the 20% WI of Sinochem with Sinochem out and resulting in Statoil the operator with 30% WI and Perenco with 70% WI.  The final stage of the transaction was the acquisition by Statoil of 50% WI from Perenco resulting in the current approved working interest breakdown of Statoil as operator with 50% WI and Perenco with 50%.  There was no time-frame given by the ANP for when the separate transactions occurred nor has there been a report regarding the transaction value.  Both blocks are involved in the discovery evaluation plan (PAD) PA_1PERN4ESS_BM-ES-40, Dende prospect oil and gas discovery.  On 5 July 2017, the ANP approved a second request by Statoil, operator of the BM-ES-040 contract, ES-M-529 block and the BM-ES-041 contract, ES-M-531 block to modify the discovery evaluation plan (PAD) PA_1PERN4ESS_BM-ES-40, Dende prospect oil and gas discovery associated with the contracts.   The ANP modified the decision point date for stage 1 of the PAD from 16 March 2017 to 16 March 2018.  The PAD still has a final expiry date of 31 December 2019 if all commitments are met. On 15 February 2017, the ANP approved a request by Statoil, operator of the BM-ES-040 contract, ES-M-529 block and the BM-ES-041 contract, ES-M-531 block to modify the discovery evaluation plan (PAD) PA_1PERN4ESS_BM-ES-40, Dende prospect oil and gas discovery associated with the contracts.   The ANP modified the decision point date for stage 1 of the PAD from 31 December 2016 to 16 March 2017.  The PAD still has a final expiry date of 31 December 2019 if all commitments are met. On 8 July 2015, the ANP approved Perenco’s modified discovery evaluation plan (PAD) submitted for the PA_1PERN4ESS_ES-M-529 evaluation area that includes portions of the BM-ES-040 Contract, ES-M-529 block and BM-ES-041 Contract, ES-M-531 block. Both blocks were also partially relinquished.  The PAD approval is the result of the evaluation of the 1-DENDE-001-ESS (1-PERN-004-ESS) new-field wildcat (NFW) suspended with shows on 13 August 2013.  The partners have firm and contingent commitments for the PAD. They include acquiring new 3D Broadseis seismic, drilling up to two appraisal wells and conducting cased hole production tests.  If all of the firm and contingent commitments are carried out the PAD will have a final expiry of 31 December 2019.

Statoil is now the operator and 100% WI owner of the BM-ES-040 contract, ES-M-529 block and the BM-ES-041 contract, ES-M-531 block after acquiring a 50% WI from former partner Perenco.

On 25 August 2018 DEA used the “Island Innovator” S/S to spud exploration well 7321/4-1. The well targeted the Graspett prospect in PL 721, located in the Fingerjupet Sub-basin to the northeast of Pingvin and northwest of Wisting. The objectives were the Jurassic Sto Formation (mapped at 1,422 m) and the Triassic Snadd Formation (expected at 1,589 m), with oil and a gas cap prognosed for both reservoirs. According to partner Aker BP Graspett had potential reserves of 32-263 MMboe. 7321/4-1 reached TD at 1,630 m in the Snadd Formation and is a dry hole. Water-wet sands were encountered in both the Sto (15 m) and Snadd (32 m) formations and reservoir quality was poor. The well was abandoned on 1 October 2018. Statoil’s Pingvin well 7319/12-1 was drilled in 2014 to a TD of 1,540 m. It had shallow Cretaceous / Tertiary targets with a sand body defined by a strong amplitude anomaly. The well proved a 14 m gas column in a good quality, 30 m thick, Lower Paleocene Torsk Formation reservoir at 953 m. Recoverable reserves were estimated at 177-706 Bcfg (30-120 MMboe) which in this location is non-commercial. OMV discovered Wisting in 2013 with exploration well 7324/8-1 which proved a 50 - 60 m oil column in the Jurassic Realgrunnen Group. This was the first oil discovery in the Hoop area of the Barents Sea and confirmed a new play. Appraisal well 7324/7-3 S was drilled in 2016, targeting the Wisting Central South and Wisting Central West segments, and encountered hydrocarbons in both the Sto and Fruholmen formations. This was followed by 7324/8-3 in 2017 which also confirmed a 55 m oil column in the Sto and Fruholmen formations. As of December 2016 the NPD reports recoverable reserves of 355 MMboe but an updated reserves estimate is expected from OMV as a result of the latest well. Interest in PL 721 is held by DEA Norge AS (40% + operator), Aker BP ASA (40%) and Wintershall Norge AS (20%).

7321/04-01 (Gråspett) (DEA op 40%, Aker BP 40%, Wintershall 20%) in PL 721 NW of Wisting, P&A target Stø + Snadd fm’s both found dry. WD=499m, TD=1600m.

PT Medco Energi has completed Tala 2A and Tala 2C from its three-well exploration drilling campaign in the Rimau PSC, located in onshore South Sumatra, at end-December 2017. The wells were drilled at the Iliran High structure. Fluid sample testing is yet to be carried out on the two wells. The company plans to proceed with the third well, Tala 2B, likely in Q1 2018. The wells could be targeting heavy oil in shallow sandstone reservoirs of the Middle Miocene Telisa Formation. The operator previously spudded Tala 3 on 22 July 2012. The well was drilled to a TD of 115 m, with bottom-hole in the Pre-Tertiary Basement. The well encountered water and was abandoned in early August 2012. It was the sixth shallow well drilled within the Iliran High since September 2011, targeting heavy oil in the area. The previous wells in the campaign were Shallow Heavy Oil (SHO) 2, Tala 1, Tala 2, Taba 2 and Taba 1. Stratigraphic test well SHO 2 was abandoned in April 2012, with results unreported. The well was drilled to a TD of 555 m and may have targeted sandstones of the Upper Oligocene to Lower Miocene Talang Akar Formation, carbonates of the Lower Miocene Batu Raja Formation and sandstones of the Telisa Formation. Tala 1 was spudded on 27 February 2012, located 2.2 km east-southeast of the Tala 2 well and with a PTD of 103 m. The well was suspended with oil shows. Tala 1 was the fourth shallow well drilled within the Iliran High since September 2011. Tala 2 was likely suspended with oil shows in January 2012. The well, located about 3.8 km southeast of the Taba 2 well, was spudded on 4 December 2011 and was drilled to a TD of 94 m. The first two exploration wells that were drilled at the same structure were Taba 1 and Taba 2. Both possibly encountered heavy oil as cyclic steam injection/stimulation were conducted. All the shallow wells drilled on the Taba and Tala structures were likely targeting the Middle Miocene Telisa shallow marine sandstones trapped in a faulted anticline structure, and were drilled using land rig “EMSCO”. Rightholders of the block are Medco (95%, operator) and Perusahaan Daerah Pertambangan Energi (5%).

Indonesia (South Sumatra B.) ? op. by MEDCO RM (95.0%, PDPDE 5.0%) in Rimau block

ENI suspended with results unreported the Saasken 1EXP directional new-field wildcat (NFW) the CNH-R02-L01-A10.CS/2017 contract, Area 10 block during early-February 2020 at an unreported final total depth (TD). The NFW was spudded on 20 October 2019. The proposed total depth (PTD) for the NFW was 4,563 m measured depth (MD) and 4,421 m true vertical depth (TVD). The primary targets were the Lower Pliocene and Lower Miocene with secondary targets in the deeper Oligocene and Eocene. The Valaris “Ensco 8505” J/U drilled the well in a water depth of 354 m. The NFW is located in the south-western corner of the block The Saasken 1EXP drilling cost was estimated at USD 51.77 million and abandonment costs were estimated to be USD 4.13 million. The prospect trap is reported to be an anticlinal structure related to a salt intrusion with related normal faulting. The operator has the option of drilling to its deeper Oligocene and Eocene targets pending results obtained drilling its primary Pliocene and Miocene targets. On 7 May 2019, the CNH approved the drilling permit request submitted by ENI for the Saasken 1EXP NFW. In the CNH-R02-L01-A10.CS/2017 PSC contract, Area 10 block, ENI is the operator with 65% working interest, Lukoil has 20% working interest, and Capricorn holds 15% after formal approvals granted on 19 December 2019. On 25 September 2018, the CNH approved the exploration plan presented by ENI for the CNH-R02-L01-A10.CS/2017 contract, Area 10 block from the CNH-R02-L01/2016 Bid Round.

Saasken 1EXP nfw. (ENI 80%, Lukoil 20%) in CNH-R02-L01-A10.CS/2017 contract, Area 10, suspended with results unreported during early-February 2020 at an unreported final TD.

Bridgeport Energy (QLD) Pty Ltd was awarded exploration permit ATP 2023-P, located in the Cooper-Eromanga Basin, on 8 April 2020. The permit has been awarded for six years so will expire, or be eligible for renewal, on 7 April 2026. Under the work commitments at least one well is required to be drilled within the first four years of the permit term. No wells are located in the permit area to date. ATP 2023-P was one of two awarded to Bridgeport on the same day, with ATP 2024-P also awarded. It was applied for in Jan 2017 after being offered as block PLR2015-2-17 in the Queensland 2015 state acreage offer. The round was open between 14 May and 8 October 2015. Native title agreements were required to be met before award. The permit is reported to be prospective for conventional and coalbed methane (CBM) resources. ATP 2023-P, which covers an area of 434 sq km, was awarded on 8 April 2020. Bridgeport Energy (QLD) Pty Ltd applied for 100% interest in the block, but between application and award has reached farm-out agreements with New Era Oil & Gas Pty and Leigh Creek Energy Ltd to divest 50% and 20% respectively.

Bridgeport Energy (QLD) Pty Ltd was awarded exploration permit ATP 2023-P, located in the Cooper-Eromanga Basin

Abu Dhabi National Oil Company (ADNOC) approved the transfer of a 4% interest in the Lower Zakum field and Central Offshore Concession ( Umm Shaif and Nasr fields) from China National Petroleum Corporation’s (CNPC) publicly listed subsidiary PetroChina Company Limited (PetroChina) to China National Offshore Oil Corporation (CNOOC) on 27 July 2020. ADNOC Offshore issued tender documents during 2Q 2020 for the main Long-Term Development Plan (LTDP-1) EPC contract which is intended to sustain oil production capacity at 275,000 barrels a day (b/d) from the Umm Shaif field from 2024 to 2028. It is focused upon de-bottlenecking capacity constraints in the existing Umm Shaif infield pipelines network and includes several new offshore facilities. McDermott International announced on 9 May 2019 that ADNOC had awarded it a front end engineering design (FEED) services contract as the initial phase of the Umm Shaif Gas Cap Condensate Development Project. The scope of work includes preparation and submission of an engineering, procurement, construction and installation proposal (EPCI) proposal reflecting the design of the offshore facilities developed by McDermott through its FEED work. ADNOC had awarded China National Petroleum Corporation’s (CNPC) publicly listed subsidiary PetroChina Company Limited (PetroChina) the final 10% participating interest in its new oil development contact for the offshore Nasr and super giant Umm Shaif oil fields on 21 march 2018. The company paid a US$ 570 million (AED 2.1 billion) signature bonus, proportionally in line with the cash sums paid by its coventurers Eni SpA (10%) and Total SA (20%). ADNOC subsidiary ADNOC Offshore retains a 60% government working interest in the oil development consortium. Total announced on 18 March 2018 that it had paid US$ 1.15 billion for a 20% stake in the new 40-year concession agreement to operate both the Nasr and Umm Shaif oil fields. Eni had acquired an initial 10% holding on 11 March 2018. The Supreme Petroleum Council (SPC) approved the creation of a new operating consortium prior to the expiry of the former Abu Dhabi Marine Operating Co (ADMA-OPCO) contract for the ADMA Central Block. The remaining 10% interest has yet to be awarded. ADNOC had confirmed in October 2016 that it planned to combine its two largest offshore operating companies, namely ADMA-OPCO and Zakum Development Company (Zadco) into a single operating unit. It subsequently announced on 15 October 2017 that it had established a new subsidiary “ADNOC Offshore” to be responsible for the development and delivery of oil and gas resources in Abu Dhabi waters. In launching its new unified brand in line with a 2030 smart growth strategy, ADNOC entered a transition period during which former company names are hereby being referenced for the purposes of clarity and historical integrity. ADMA-OPCO shareholders were ADNOC 60%, BP 14.66%, Total 13.33% and JODCO 12%. ADMA-OPCO was 100% right holder in the ADMA Central Block up until the point that its 45-year ADMA contract expired on 18 March 2018. The 1,303 sq km former ADMA Central concession encompassing both the giant Nasr and super-giant Umm Shaif oil fields expired in March 2018. Although discovered in 1971, the Nasr oil field was only brought onstream during 2015. Early production averaged around 22,000 bo/d during 4Q 2017, but the field is being developed to reach a peak plateau rate of 65,000 bo/d in 2H 2019. Umm Shaif was producing at a rate of around 250,000 bo/d during 4Q 2017. A new oil gathering network is to be commissioned during 2H 2019, which will allow an average production rate of 275,000 bo/d to be sustained until the year 2031. The original Abu Dhabi offshore concession was awarded to D'Arcy Exploration Company in 1953. In 1955 the concession was assigned to ADMA, a company owned by BP and CFP. BP assigned 45% of its interest to Japan Oil Development Company Limited (JODCO) in 1972. In January 1973 ADNOC acquired 25% interest in ADMA Limited. The following January ADNOC increased its shareholdings in ADMA to 60%. ADMA-OPCO was subsequently incorporated in 1977 to operate the ADMA concessions on behalf of the interest holders, ADNOC (60%) and ADMA (40%). In early November 2010, ADMA-OPCO CEO Ali Rashid Al Jarwan re-affirmed the fact that his company intended to increase its offshore oil production capacity to 1.75 million barrels a day (MMbbl/d) by 2019. Partners in the Central Offshore concession effective 27 July 2020 are ADNOC Offshore (60%) Total (20%) Eni (10%), PetroChina (6%) and CNOOC (4%).

UAE, not found

Turkmen authorities report successful testing of well Uzynada 1 (2020) drilled in the Uzynada gas condensate discovery on the Caspian coast. The well tested 106,000 cu m of gas (3.63 MMscf/) and 143 tonnes (ca. 1,150 bbls) of condensate in January 2020. The hydrocarbons have been teseted from the Lower Red Bed Series (Pliocene), in the interval of 6,746-6,752 m. Uzynada was discovered in May 2017 (see details in Background below) by the country's first super-deep well Uzynada 7 (TD 7,150 m). Turkmenistan had since announced plans to drill appraisal (outpost) wells Uzynada 8 and 17, however, it has not been reported if these wells have been drilled and tested. In December 2019, it was announced that the Turkmengeologiya state exploration trust, in co-operation with Turkmennebit production company, was preparing to drill a 6,500 m deep exploration well in the Uzynada Gunorta (Uzynada South) prospect. The prospect was identified during a recent seismic survey. Background Information The Uzynada discovery is located close to the Caspian coast, some 30 km south of the Barsagelmes field (South Caspian Basin). It was was discovered by well no. 7 in May 2017. The well flowed gas with condensate at rates of 17.1 MMcf/d and 1,200 b/d, respectively, from the interval of 6,689-6,695 m. The well has been drilled to 7,150 m and is the first super-deep well in Turkmenistan. It was drilled by Turkmennebit with a Chinese-made “ZJ70” heavy drilling rig. In December 2018, Turkmennebit state exploration and production trust was reported to be drilling two appraisal wells at Uzynada, nos. 8 and 17. No further details were disclosed at the time.  The Uzynada discovery is important for understanding prospectivity of the Block 21’s which lies immediately offshore. Four prospective intervals were identified in well 7 prior to drilling, including the Apsheronian Formation at -3,100 m subsea, the Upper Red Beds (Pliocene) at -4,000 m, and two intervals in the Lower Red Beds at -5,600 m and -6,125 m. Seismic surveys were carried out over the Uzynada structure in 1973 and 1980. At least four exploration wells were drilled in the Uzynada structure in the 1970s, to TDs between 4,200 m and 4,400 m. None of those wells had been successful.

Turkmen authorities report successful testing of well Uzynada 1 (2020) in the Uzynada gas condensate discovery on the Caspian coast. The well tested 3,63 MMscf/d and ca. 1 150 b/d of condensate, from the Lower Red Bed Series (Pliocene), in the interval of 6746-6752 m.

Shell is reportedly talking to BP over the possible acquisition of the latter’s 27.5% in the Shearwater o&g field in P188, Central Graben, for some USD 250 MM. Currently Shell (op), partners BP + Exxon.

Shell is reportedly talking to BP over the possible acquisition of the latter’s 27.5% in the Shearwater o&g field in P188, Central Graben, for some USD 250 MM. Currently Shell (op), partners BP + Exxon.

Mubadala Petroleum plugged and abandoned the first well under the G01/48 exploration drilling campaign, Inthanin 1, located in the Kra Sub-basin, Gulf of Thailand, on or around 27 November 2019, as dry well. The well, located 3.7 km south-southwest of the Manora platform, was targeting the 400, 500 and 600 sands series. The targeted intervals were intersected within 15 m of the prognosed depths, however there was no indication of hydrocarbon charge. Additionally, the deeper units, 500 and 600 sand series, were found to be poorly developed. Spudded on 20 November 2019, Inthanin 1 well reached its total depth (TD) of 2,528 m on 24 November 2019. The drilling completion was ahead of schedule and below budget. The drilling rig, Valaris 115 J/U (formerly Ensco 115) has been mobilized from the Inthanin 1 well location to the next prospect location which is located around 6 km southeast of Manora platform. The intentionally deviated well, Yothaka East 1, is expected to be drilled on 29 November 2019, aiming to test the 490 and 500 sands series in a fault independent closure and the 600 sand series in a three-way dip closure. Krissana 1, a sidetrack well from the Yothaka East surface location, is designed to test the 300, 400, 500 and 600 sands series in a three-way dip closure. Development of these two fields cluster would require a new wellhead platform, to be tied-back to the processing and storage facilities in the Manora field. The prospects are located to the south and east of the Manora East fault and adjacent to major source kitchen. A contingent appraisal well, Yothaka East 2, will be drilled upon significant hydrocarbon indications in the Yothaka East 1 and Krissana 1 wells. The total cost for these three wells is estimated at USD 5.5 million gross, for dry hole cases. Priority is given to the prospects that are low cost to drill, quick to be developed, reachable from the existing platform and able to extend field life for several years. Another high graded prospect within the North Kra block, namely Manora DEFVX, is planned to be drilled in 2020. The G01/48 concession is operated by Mubadala Petroleum with 60% interests through its subsidiary MP G1 (Thailand) Limited, partnered with Tap Oil (30%) and Northern Gulf Petroleum Pte Ltd (10%). The previous exploration well, Manora 8 ST1, had successfully appraised the oil zones along the Manora East bounding fault, on 4 June 2018. Located 2.2 km southwest of the Manora A platform, the well encountered a total net oil pay of around 93 m (based on logs interpretation) from the primary objective of the 490-60 Series sands, as well as new pools in the secondary objectives, 300 and 500 Series sands, plus minor pay in the 400 Series sands. The well result has contributed additional volumes of 1.1 and 1.9 MMbbl to the 1P and 2P reserves within the Manora field, respectively. The result of the original borehole Manora-8, however, was below expectations with small contingent oil resources encountered probably in the primary objective of 600 series sands, which are primary producing sands in the Manora field. The Manora-8 and its sidetrack were targeting a three-way dip closure of the ‘Manora footwall A’ prospect in the upthrown side west of the Manora Central block. Background Information The G01/48 concession was officially awarded to Occidental Exploration Pte Ltd (50%, operator) and partner Syarikat Borcos Shipping Sdn Bhd (50%) in December 2006. In 2007, Occidental was renamed to Northern Gulf Petroleum (NGP) Pte Ltd. Subsequently, Pearl Oil (later acquired by Mubadala Petroleum) acquired the entire 50% stake of Syarikat Borcos plus an additional 10% and operatorship from NGP. In October 2010, Tap Oil acquired an indirect 30% interest in the block via the acquisition of a 75% share of NGP. In 2012, Tap’s indirect interest was converted into direct interest through transfer to subsidiary Tap Energy (Thailand) Pty Ltd. NGP retained the remaining 10% direct interest. Tap Oil elected to retain its stakes in the block after the completion of a full asset review conducted in 1H 2015. From 2009 until 2016, six newfield-wildcats were drilled within the G01/48 concession, with three oil discoveries in Manora (2009), Malida 1 (2013) and Sri Trang 1 (2016). The Manora oil field was discovered via Manora 1 wildcat in December 2009. The discovery was appraised by six oil wells and one dry well. Hydrocarbon discovery from Malida 1 enhances exploration potential between the new discovery and Manora field. A net pay of 9.5 m oil-bleed sandstone reservoir in the primary target between 2,396 to 2,412 m. The last new-field wildcat in the G01/48 concession was drilled at the northern of the block, in late 2017. Ladawan-1 well was drilled to a total depth of 2,175 m TVDss, after having encountered an interpreted 3.3 m oil column at the 500 Sand Series. The well result is considered non-commercially viable and no well test has been carried out.

Inthanin 1 (Mubadala 60% op, Tap Egy 30%, N.Gulf Petr. 10%) in G01/48 block, 1st of 3 explo wells planned in Manora oilfield area, P&A dry (TBC), targeted 400, 500 + 600 series sands were intersected, no significant shows were encountered while drilling and evaluation of log data indicated no zones of interest in the well. TD=2528m

Block 9 (Suneinah), drilled mid-Jan – Feb '20, ops terminated at TD 1,919m, completion string understood run. Oxy (op), partners OQ Upstream + Mitsui.

Khaznah-2 expl Block 9 (Suneinah), drilled mid-Jan – Feb '20, ops terminated at TD 1,919m, completion string understood run. Oxy (op), partners OQ Upstream + Mitsui.

On 28 June 2018 Neptune Energy Group announced that it has agreed to acquire 100% of the shares of VNG Norge AS (which holds interests in Norway and Denmark – see separate article for details on Norway) with effect from 1 January 2018. The acquisition will increase Neptune’s production by approximately 4,000 boe/d and its net reserves/resources by over 50 MMboe (based on 2017 figures). In Denmark, the company – through VNG Danmark - is partner in the 4/98 Solsort and 3/09 licences which contain the Solsort field. Approval for the acquisition is required from the Supervisory Board of VNG AG and from the relevant authorities. Completion is expected in Q4 2018. VNG reported in January 2018 that it was assessing options for the future of its oil and gas business in Norway and Denmark. The company said that it saw long term value creation in the sector but was looking for a strategic partner to aid future growth. Reports in the press indicated that VNG would sell a majority stake in the subsidiary and that this sale could be valued at up to USD 500 million. The Solsort field was discovered in 2010 by exploration well Solsort-1 (5604/26-5) which found oil in the Paleogene. The find was appraised in 2013 and oil and gas was tested from the Paleocene. The field lies in the Central Graben immediately east of the Svend field and northeast of the South Arne field, both of which are producing Chalk oil fields. Interest in the 3/09 and 4/98 Solsort licences is held by INEOS E&P A/S (35% + operator), Bayerngas Danmark ApS, Danish North Sea Fund (20%) and VNG Danmark ApS (15%).

Neptune Energy has agreed to the acquisition of VNG Danmark, providing Neptune with interests in assets such as the Greater Njord Area / hub, Fenja, the Utsira High area, and Ivar Aasen. and Solsort devt project.

Add. DEA 16 Apr ’18 (content + TD): SE part of AE-0094-Cinturon Plegado Perdido-12 block, DW GoM Basin, WD 1,630m, susp. o&g at TD 6,640m on 22 Mar ’18, La Muralla IV SS. Target Wilcox.

Mexico, not found

Block TTDAA 14, Trinidad Basin, WD 2,207m, ops terminated late Sep '19, Deepwater Invictus DS to Carnival-1. PTD was 4,450m, target Miocene turbidites, appraisal to Bongos, Hi Hat, Tuk and/or Bele gas finds. BHP (op), partner BP.

Boom 1 appr. (BHP op. 70%, BP 30%) in block TTDAA 14, target Miocene turbidites. P&A with unreported result. WD =2207m, PTD was 4450m.

Bridgeport secured sole rights to PEL 641,  1,953 sq km in the Cooper-Eromanga, on 9 Feb ’18 for 5 years. It was offered in the 2013 SA acreage release as CO2013-C. Commitments 200km of 2D + 200 sq km of 3D seismic in years 1 + 2 resp. + 5 wells.

Bridgeport Energy (100%) was awarded exploration licence PEL 641.

Equinor Energy do Brasil Ltda is assumed to have plugged and abandoned the Carcara West U1 (9-EQNR-002-SPS) special outpost well in the N_CARCARA block, Norte de Carcara_P2 contract of the Santos Basin during early-February 2019 at an as yet to be reported final total depth (TD).  It is assumed that it may have been a geo-technical well to evaluate shallow geo-hazards. The special well was spudded on 3 February 2019.    The well had a proposed officially reported total depth (PTD) of 3,215 m. The well was drilled by the “West Saturn” D/S in a water depth of 2,051 m.      The surface location of the special well is located only 27 m west of the Carcara West (3-EQNR-001-SPS) recently concluded in the block.    Current working interest breakdown in the contract is Equinor Brasil operator with 40% working interest, ExxonMobil with 40% working interest, and Petrogal Brasil Ltd (Galp Energia) with a 20% working interest. Equinor Brasil Energia Ltda has plans to drill up to five exploration wells in the Norte de Carcara_P2 contract, N_CARCARA block after filing its environmental permit in April 2018.  The Norte de Carcara structure is a northern continuation of the Carcara structure discovered by Petrobras and now operated by Equinor Brasil and partners in the BM-S-008 contract.  The wells to be drilled may all be considered outpost wells.  They will have proposed total depths of approximately 6,500 m to 7,000 m and will target the Barra Velha and Itapema formations of the pre-salt series in the Santos Basin.  The drilling is expected to commence in the block during early-2019.  The A prospect is located about 5.7 km north north-east of the 3-SPS-104A (3-BRSA-1216DA-SPS) outpost. On 31 January 2018, the consortium of Equinor Brasil Energia Ltda operator with 40% working interest, ExxonMobil with 40%, and Petrogal with 20% was granted an official award for the 312.92 sq km Norte de Carcara block from the 2nd PSC Pre-Salt Bid Round. The ANP changed the official denomination of the block to the Norte de Carcara_P2 contract, N_CARCARA block.  The consortium won the block with a profit oil state take bid of 67.12% and USD 911.85 million in total fixed bonus to be paid to the Brazilian government based on the USD to BRL exchange rate of the day of 1USD/3.29 BRL.  The PSC contract has a three year exploration-evaluation phase and the minimum work program is to drill one appraisal well. The minimum financial guaranty for the three year period is USD 47.95 million which is less than the estimated cost of drilling a pre-salt appraisal well.  There was a 2nd place bid for the block by Shell (100%) offering a state take bid of 50.46%.  The working interest breakdown for the block is the same as in the BM-S-008 contract that will be unitized with the Norte de Carcara block after Equinor acquired the 10% working interest from Barra Energia in June 2018.

Equinor Energy do Brasil Ltda is assumed to have plugged and abandoned the Carcara West U1 (9-EQNR-002-SPS) special outpost well in the N_CARCARA block, Norte de Carcara_P2 contract of the Santos Basin

Total picked up a 45% stake and operatorship from Tullow in block C-18, 13,338 sq km in deepwaters of the Senegal (MSGBC) Basin, northern offshore. The company now runs 3 deepwater units here, C-7, C-9 + C-18. It is understood that at the same time late last year BP also took 15% in C-18, resulting partnership Total (op), partners BP, Tullow, Kosmos + SMHPM. 3D seismic surveying is currently underway.

Total picked up a 45% stake and operatorship from Tullow in block C-18, 13,338 sq km in deepwaters of northern offshore.

On 30 July 2018, Petrofac Limited announced that it signed an agreement to sell 49% of the company's operations in Mexico to Perenco (Oil & Gas) International Limited, The deal encompasses the Pemex legacy assets Santuario and Magallanes (onshore) and the Arenque offshore contract. The official contract names are:<P />* The 153.193 sq km CNH-M2-Santuario-El Golpe/2017 PSC (A-0396-Santuario Block & A-0121 Campo El Golpe )* The 191.14 sq km AE-0395-Magallanes-Tucan-Pajona Block* The 2,191.4 sq km AE-0390-M-Arenque Block<P />While Santuario is a Production Sharing Contract (PSC), Magallanes and Arenque are production enhancement contract projects signed before energy reform. Under the terms of the agreement, Perenco will pay an initial cash consideration of US$ 200 million (US$ 30 million payable upon signing and US$ 170 million payable upon completion). Petrofac detailed that the total consideration comprises a fixed amount and contingent consideration depending upon a number of future milestones, including future field development and migration terms of Petrofac's Magallanes and Arenque oilfield contracts. This final amount, Petrofac said, is subject to adjustment based on achievement of the milestones above and will be capped at US$ 274 million. Petrofac added that it currently estimates that an impairment charge of approximately US$100 million, will be recorded because of the deal. Petrofac will use proceeds from the sale to reduce gross debt. The transaction is subject to approval by the Federal Competition Commission of Mexico (COFECE). That is expected to take place Q4 2018."We are delighted to welcome an experienced partner in Perenco to our Mexican operations," Petrofac's Group CEO Ayman Asfari said. "They bring strong technical capability that will complement our existing brownfield operations experience to strengthen our offering. We look forward to working with them and the other stakeholders to further develop our mature field interests in Mexico."As for Perenco, the agreement gives it an important foothold in the Latin American economy. "Mexico is a land of opportunities, a new play, a new country and an exciting new challenge for Perenco," Perenco's CEO Benoit de la Fouchardiere. "Partnering with Petrofac in Mexico will give us a fantastic opportunity to reach our goals in a timely manner and, by our results, demonstrate to the state company Pemex that we can also be a partner of choice for the future."Mexico's Comision Nacional de Hidrocarburos (CNH) on 18 December 2017 signed a PSC for CNH-M2-Santuario-El Golpe/2017, encompassing the A-0396-Santuario and A-0121 Campo El Golpe fields with Petrofac and state-run Pemex. Petrofac holds 36% equity interest in the PSC. Pemex retains the balance (64%). The contract is located in Tabasco state. According to the CNH at the time of signing, the PSC will have the capacity to tap 29,000 boe/d. In April 2018, according to data, oil production at Santuario was on the order of 6,021 bo/d. Petrofac originally won the Santuario 25-year oilfield service contract in October 2011. That was before energy reform in which Pemex awarded contracts with performance incentives, known as CIEP in Spanish, and the financed public works contracts, or COPF, to develop production in various parts of the country. The contracts, which were grandfathered into the Round Zero entitlements in August 2014, are being migrated over to a new contract model. Separately, regulators have approved the transitional plan for the field. Magallanes and Arenque oilfield are in the pipeline for migration to a new contract model. Petrofac in 2012 was awarded the integrated production service contract for the offshore Arenque contract. The Magallanes enhancement contract is a tariff-per-barrel-based service contract. In all, 22 integral service contracts have been earmarked to be migrated over to new contracts.<P />

Mexico, CNH-M2-Santuario-El Golpe/2017Perenco is acquiring 49% in Petrofac’s Mexico assets – including Santuario, Magallanes and Arenque fields for US$200 MM.

Block 15, Tripura-Cachar Basin, P&A dry at TD 3,100m in Oct ’18 (tested). PTD was 2,800m, Socar rig.

Semutang South 1 (Bapex 100%) exploration/appraisal well in onshore Block 15, P&A, dry

Bangchak Corporation Public Company Ltd (BCP) reported on 13 July 2018 that it had executed a sale and purchase agreement to divest its entire stake in SC 14C1 (Galoc), located offshore Northwest Palawan Basin, to Tamarind Galoc Pte Ltd. The deal involves approximately USD 20 million for shares in BCP’s subsidiary Nido Production Galoc (NPG), which owns 55.8% of the Galoc oil field. Part of the payment is due at the closing of the agreement while the remaining will be payable at agreed terms. BCP owns the stake in NPG through its wholly-owned Nido Petroleum, which was acquired in 2014. Prior to the asset disposal, interests in SC 14C1 were split among Galoc Production Company (GPC) (33%, operator, wholly-owned subsidiary of Nido Petroleum), Kufpec (26.84%), Nido Petroleum (22.88%), Oriental Petroleum (7.79%), Philodrill Corp. (7.21%) and Forum Energy (2.28%). The Galoc field is expected to deplete after 2020 as more than 80% of the recoverable reserves (approximately 4.7 MMbo) had been produced by end of 2017. The SC 14C1 production period is due to expire in December 2025. Due to that reason, the operator and its venture partners were expected to expand the field by developing the mid-Galoc area (MGA). However, poor results from two appraisal wells which were drilled in April 2017 had downgraded the potential of the area. Galoc 7 and its sidetrack intersected poor reservoir quality in the Galoc clastic units with combined gross thickness of 277 m and combined net reservoir thickness of 20 m. Tamarind Galoc, a wholly subsidiary of Tamarind Resources, was established to focus on oil and gas in Southeast Asia. The company is currently operating in New Zealand, Australia and Papua New Guinea. Background Information SC 14 in the Northwest Palawan Basin has had a complex contractual history since its award to Cities Service for on 17 December 1975. Its original partners include Oriental, Philodrill, PNOC, Husky as well as other local firms. The interest holdings were distributed differently in each of the four sub-blocks (A, B, C and D). On 17 December 1986, 14% of the original contract area was retained. This includes 12.5% held as Retained Area plus Matinloc/Pandan, Nido and Libro Production Areas. Cities made oil discoveries at Nido 1, Matinloc 1, Pandan 1, Libro 1, Tara 1 and Galoc 1. In 1982 a four years extension to the exploration period was granted. Alcorn, in its 1989 Annual Report, stated that oil in-place was estimated to range between 80 - 260 MMbo and recoverable reserves between 24 and 102 MMbo, implying a recovery factor between 30 and 40%. In 1990, recoverable reserves were revised to 25 to 40 MMbo. Unocal initially signed an agreement to carry out a phased study of the Galoc oil and gas field with the intent to determine the field's economic feasibility. In mid-October 2003, Unocal decided not to exercise its option to farm-in to the Service Contract and not to proceed with Phase 2 of the development of the Galoc field. The company considered the 150 MMbo in-place uneconomic. The Joint Venture continues to seek interested partners to develop the Galoc field. On 24 September 2004, partner Nido Petroleum announced that, subject to the approval of the Philippines Department of Energy (DOE), a farm-in agreement for the development of the Galoc field has been executed. Two previously unknown companies, Cape Energy Pty Ltd and Team Oil Ltd, have farmed-in to "the Philippines Joint Venture partner's share of SC-14C for carrying costs through development". The current partners will maintain their current equity position in the contract until the two companies have earned their respective interests. Although subject to confirmation, it appears that the farm-in is for SC 14C West Linapacan (North-east) only, and does not involve the other areas of SC 14. On 19 July 2005, the farm-in agreement for the development of the Galoc field was finally approved. Galoc Production Company formed by Vitol Holdings, Granby Oil and Team Oil took over the operatorship of the SC 14C Northeast block by acquiring 75% of the rightholding of the Phillippines Companies.GPC, a Netherlands-based oil investment company, completed a farm-in agreement for a 58.291% operating interest in SC 14C West Linapacan (North-east) on 19 July 2005, including the undeveloped Galoc field. The Galoc field was discovered by Cities in 1981 with the drilling of wildcat Galoc 1. The well was targeting what was believed to be a carbonate build-up identified from a seismic anomaly, but which turned out to be an unusual turbidite sandstone mound in the Lower Miocene Galoc Unit, which unconformably overlies the Nido Limestone. Galoc 1 was drilled to TD at 3,700m and intersected a 40m oil column. A DST in the Galoc Unit flowed 1,828 bo/d (35.3° API). Cities followed the discovery in the same year with the South Galoc 1A step-out, located 5km south of Galoc 1. The well was drilled on a similar but separate anomaly to the discovery and reached TD at 2,614m, encountering five gas bearing intervals in two zones, with a net pay of 15m. The lower zone yielded a flow of 3.77 MMcfg/d plus 280 bc/d while the upper zone tested 3.16 MMcfg/d plus 188 bc/d. South Galoc 1A was plugged and abandoned as a non-commercial gas/condensate discovery. Galoc lies in 320 m of water at about 2,300 metres below sea level, in a low relief domal structure with an areal extent of about 12 sq km at the oil/water contact. A combination stratigraphic/structural trapping mechanism is formed by the turbiditic sands being draped over a subtle anticlinal structure at Nido Limestone level. The field produced 385,000 barrels on long term test in 1988. The field was brought onstream on 9 October 2008, with oil flowing to the "Rubicon Intrepid" FPSO. In March 2006, information from DoE (Department of Energy) Petroleum Resources and Development Division indicated that the Galoc and Octon oil fields could likely produce a maximum of 16 MMbbl during a three to ten-year operation. On 16 September 2008, an independent reserves certification report indicated that Galoc field's 1P reserves were 15.9 MMbo, a 64% increase over the previous estimate of 9.7 MMbo. On 4 May 2011, partner Otto Energy reported an upgrade in gross remaining 2P reserves as of 1 January 2011, to approximately 7.35 MMbo. The upgrade was due to better than expected reservoir performance and to an extension of field life because of higher prevailing oil price. During 2011, Otto was assessing Phase 2 development which was then expected to unlock contingent resources of 2 to 8 MMbo. Following an independent assessment by GCA (Gaffney, Cline & Associates) as of 30 June 2011, 1P recoverable reserves increased to 12.4 MMbo, 19.2% higher than the previous estimate of 10.4 MMbo as of 31 December 2010. According to partner Nido, the increase was due to better than expected reservoir performance in the first half of 2011. The 2P and 3P recoverables estimate changed respectively by +1.6% and -2.2% from the previous estimates of 31 December 2010. An audit by GCA up to 31 December 2011 indicated a new 1P estimate of 14.44 MMbo recoverable, a 16.45% increase from the previous estimate of 12.4 MMbo (as of 30 June 2011). The new 2P recoverable reserves estimate was 22.89 MMbo, a 23.06% increase from the previous estimate of 18.6 MMbo. The new 3P recoverable reserves estimate was 29.44 MMbo, up from the previous 26.3 MMbo (11.94% increase). Nido attributed the increased reserves to a better than expected reservoir performance during the second half of 2011. Following approval of FID for Phase II field development in September 2012, operator Otto Energy announced an upgrade in reserves according to a third-party assessment as of 1 July 2012. The upgrade was due to higher recovery factors from existing wells and to the booking of new reserves previously classified as contingent. Remaining recoverable reserves have been estimated at 8.9 MMbo on a 1P basis (a 156% increase from a previous estimate as of January 2012) and 13.4 MMbo on a 2P basis (134% increase). A new reserves assessment was reported by Otto on 14 March 2013. The revision, carried out by advisor RISC, indicated EUR of 21.7 MMbo (1P) and 25.4 MMbo (2P) as of 1 January 2013. These figures mark increments of 13% (for 1P) and 1% (for 2P) from the previous assessment released in July 2012. The increase was attributed to better than expected reservoir performance and to field life extension due to higher prevailing oil prices. Remaining recoverable reserves have been estimated at 11.7 MMbo (1P) and 15.4 MMbo (2P). Reserves replacement ratio in the field has been estimated as 115% on a 1P basis and 98% on a 2P basis. Otto Energy was evaluating the possibility of a further expansion of the Galoc oil field in late August 2014. Following the first eight months of Phase II production, the operator gained a better understanding of the reservoir distribution between the producing Galoc Central area and the undeveloped Galoc Mid and North areas. Otto expects to issue a recommendation regarding further exploration and development activities between late 2014 and early 2015. Phase II performance has been in line with expectations since its startup in December 2013, with over 2 MMbo produced up to 31 July 2014. The two Phase I wells (Galoc 3ST1 and Galoc 4) continued producing according to forecasts through July 2014. Phase II wells (Galoc 5 and Galoc 6) were producing 4,680 bo/d as at 31 July 2014, contributing to 58% of the total field production. Otto also released an updated third-party reserves assessment as of 31 July 2014, based on decline curve analysis from Phase II production. Developed field reserves have been estimated at 9.2 MMbo (1P), 11.9 MMbo (2P) and 15.6 MMbo (3P). The updated 2P and 3P estimates are respectively 2% and 4% lower than previous estimates as of 31 December 2013. First oil production from Phase II development of the Galoc field was achieved on 4 December 2013. The initial output following the commissioning of new wells Galoc 5H and Galoc 6H was 14,500 bo/d. With the new developments, the field is anticipated to produce beyond 2020 with an estimated ultimate recovery of approximately 25 MMbo. Phase II development focused on the refurbishing of the “Rubicon Intrepid” FPSO and the drilling of horizontal production wells Galoc 5H and 6H. The project was completed in approximately 14 months, from FID to first production. Following the first eight months of Phase II production, the operator gained a better understanding of the reservoir distribution between the producing Galoc Central area and the undeveloped Galoc Mid and North areas. Otto originally expected to issue a recommendation regarding further exploration and development activities between late 2014 and early 2015. Phase II performance has been in line with expectations since its startup in December 2013, with over 2 MMbo produced up to 31 July 2014. The two Phase I wells (Galoc 3ST1 and Galoc 4) continued producing according to forecasts through July 2014. Phase II wells (Galoc 5 and Galoc 6) were producing 4,680 bo/d as at 31 July 2014, contributing to 58% of the total field production Nido Petroleum acquired the block operatorship from Otto Energy on 17 February 2015. In July 2015, the operator announced that the Mid-Galoc area is estimated to contain gross 1C-2C-3C contingent resources of 6.2-9.5-14.6 Mmstb respectively. In-place oil volumes for that area have been estimated at 52.6 MMbo (P90), 77.3 MMbbl (P50) and 113 MMbbl (P10). Recovery factors range between 12% and 13% and are typical of reservoir performance under a pressure depletion mechanism. Two horizontal development wells were planned to be tied back to the existing Galoc FPSO facilities. First oil production form mid Galoc area is expected to commence on 1 January 2018 with initial peak anticipated at 3,000 stb/d.

Tamarind (->55,8%) has bought a 55% stake in the Galoc field (lies off in SC 14C-1) from partner BCP for US$20 MM.

On 18 October 2019, the Federal Agency for Subsoil Use announced an auction for the Vladimirovskiy block in Tatarstan Republic (Volga-Urals Basin). The auction will be held on 20 December 2019 with its application deadline on 19 November. The winner of the auction will obtain a 25-year E&P license. Additional information can be requested from: Tatnedra, Kazan, N.Nazarbayeva Str., 15 The Vladimirovskiy block, comprised of two areas, covers 189.5 sq km and encompasses the Vladimirovskoye oil discovery with 3P reserves estimated at 1.3 MMbbl and the Kashtanovskaya and Tabachnaya prospects with combined oil resources estimated at 3 MMbbl. The starting price amounts to RUB 33.21 million (USD 0.52 million).

Russia, not found

It was reported in the Press in early March 2018 that OKEA has found a farm-in partner for PL 038 D which contains the Grevling oil discovery. It is understood that the new, as yet unnamed partner will take a 30% stake in PL 038 D. As a result of the deal it is likely that the development concept selection and FID will be made later in 2018, with potential first oil for Grevling possible in 2021. The NPD quotes estimated recoverable reserves at 30 MMbo. OKEA acquired its first interest (30%) in Grevling from Aker BP in 2016. It then took Repsol’s 40% and operatorship in 2017. Grevling was discovered in 2009 by 15/12-21 which encountered 67 m of net pay in the Middle Jurassic Hugin and Sleipner formations and the Upper Triassic Skagerrak Formation. Two DSTs were performed, flowing at a rate of 780 bo/d from the Sleipner and Skagerrak formations and 472 bo/d from the Hugin Formation (through a 20/64" choke). The OWC was not penetrated so a sidetrack (15/12-21 A) was drilled in a down-dip location to the east. This well confirmed oil in the same formations with a total of 36 m of net pay but the OWC was still not found. Appraisal well 15/12-23 was drilled in 2010 and found the OWC (or an ODT) at 3,251 m. The Hugin Formation was absent and the reservoir comprised just the Sleipner and Skagerrak formations which tested at a rate of 648 bo/d through a 16/64" choke. Sidetrack 15/12-23 A deviated to the west and found water-wet Hugin sands (with oil shows) and oil-bearing Sleipner sands (it TD’d in the Sleipner). Interest in PL 038 D is currently divided between OKEA AS (70% + operator) and Petoro AS (30%).    

OKEA (->40% op, Petoro 30%) has found a farm-in partner for PL 038 D which contains the Grevling oil discovery. It is understood that the new, as yet unnamed partner will take a 30% stake in PL 038 D.

Cosecha block in Arauca, Llanos Basin, TD 3,300m, reportedly light oil find flowing 3,025 b/d of 38 API crude. Oxy (op), partner Ecopetrol.

Colombia (Llanos Sub-basin (Llanos-Barinas B.)) Arauca

Oilex + GSPCL are discussing the sale of their respective 40% + 60% in the Bhandut PSC, 3 sq km in the Cambay Basin, with Kiri and Company Logistics. The deal is hoped to be completed by the end of this month. So far Oilex (op), partner GSPCL.

India (Cambay B.) Bhandut op. by KIRI (100%), Oilex + GSPCL have agreed the sale of their respective 40% + 60% in the Bhandut PSC, to Kiri and Company Logistics (->100%).

The following block will be up for auction on 27 Sep ’18 in Krasnodar Kray (North Caucasus), application deadline 28 Aug: -Kubanskiy Severnyy, 421 sq km in the Kubanskaya Zapadnaya Depression, undrilled. Starting price USD 0.03 million. Contact Yugnedra ([email protected]).

Russia, not found

EXL 269, Lancashire, horiz shale gas well fracked in the Upper Bowland Shale at 2,100-2,700m, high methane content, tested 200 Mcf/d peak, 100 Mcf/d stable, only 2 of the 41 planned stages fully fracked. Cuadrilla (op), partners Elswick Egy (Centrica), Elswick Power (AJ Lucas) + Warwick Onshore. Cuadrilla release here.

Preston New Road (LJ/06-8)EXL 269, Lancashire, horiz shale gas well fracked in the Upper Bowland Shale at 2,100-2,700m, high methane content, tested 200 Mcf/d peak, 100 Mcf/d stable, only 2 of the 41 planned stages fully fracked. Cuadrilla (op), partners Elswick Egy (Centrica), Elswick Power (AJ Lucas) + Warwick Onshore.

Itochu is looking to sell its Cieco-held interests in the Dana-operated Western Isles field project (Harris and Barra oilfields, 23%) and Hudson field in 206/24a  (26%), as well as minority stakes in the Brent System pipeline and the Sullom Voe terminal. A deal could fetch up to USD 250 MM.

United Kingdom, Brent

Hunt Oil discovered oil and gas with the Ulmu 1 NFW, with testing due to follow as of early March 2018. It was drilled to 3,698m TD in the VIII Urziceni Est exploration concession on the Moesian Platform, SE Romania. It was scheduled to spud during October 2017 with a PTVD of 3,700m MD, to target the Mesozoic and Palaeozoic. Ulmu lies approximately 6km ESE of the Padina Nord 1 gas condensate discovery, drilled to a TD of 2,640m in 2014. The Ulmu 1 location was covered by a 260 sq km 3D seismic survey over the Padina area during early May 2015. In December 2016, the Hunt/OMV Petrom joint venture (JV) commenced experimental oil and gas production from the Padina North 1 discovery at a rate of 1,900 boe/d. VIII Urziceni Est partners are Hunt Oil Company of Romania Srl (50% + Op) and OMV Petrom SA (50%).

Ulmu 1 op. by Hunt (50%, Petrom 50%) in VIII Urziceni Est (6km ESE of the Padina Nord 1 g&cond disc.), o&g disc.

According to a Surinamese press conference in early August 2020, Staatsolie's acting general manager, Agnes Moensi-Sokowikromo, said the company is mulling acquiring up to 20% in the Apache-led Block 58. Apache and Total are equal partners in the block, though the French supermajor will assume operatorship of the DW block, which hosts a trio (Maka Central, Sapakara West and Kwaskwasi) of world-class discoveries, once the current drilling programme completes with the drilling of Keskesi 1. The news comes as no surprise as Staatsolie has the right to acquire stake in the development stage, and previous statements indicate that state oil company will exercise its option to participate in the development and production stage with 20% interest. That would suggest that Apache and Total will hold 40% each in the contract. Maka Central was Suriname’s first ever commercial deepwater oil discovery earlier this year, If Staatsolie pulls the trigger, the company would have to dish out up to US$ 1.5 billion in planned development costs. It will likely cost between US$ 6 billion and US$ 7 billion in total to develop a floating production option for the block.US-based Apache Corporation, and new partner Total reported in February 2020 that they had made “a significant oil discovery" at the Maka Central 1 well on the offshore Suriname Block 58. Maka Central 1 tested for the presence of hydrocarbons in multiple stacked targets in the Late Cretaceous-aged Campanian and Santonian intervals, encountering both oil and gas condensate in what amounts as a blockbuster find in the former Dutch colony in South America. The well, drilled with the “Noble Sam Croft," also marks Suriname’s first major offshore discovery after several failed attempts. Apache's formation evaluation programme included logging-while-drilling and wireline logs, formation pressures, and preliminary core and fluid analysis.Block 58 is located on the Surinamese western maritime border, adjacent to the prolific Stabroek Block in Guyana. Apache won the Production Sharing Contract in Suriname’s 6th International Bid Round 2014 for Block 58. Total agreed a farm-in in December 2019 for 50% WI.

(Suriname B.) Block 58 op. by TOTAL (50%), APACHE (50%), Staatsolie is reportedly considering a farmin to Apache's offshore block 58. The state co. has an up to 20% back-in right to the 5,836 sq km mostly-deepwater permit which hosts the Maka Central, Sapakara West + recent Kwaskwasi finds.

Shell Australia announced on 21 Novemebr 2018 that it had reached an agreement to sell its 26.56% interest in the Greater Sunrise asset to the East Timor Government.  Shell becomes the second company to sell its interest in the project to the government, after ConocoPhillips reached a similar agreement in October 2018. The sale and purchase agreement entered into by Shell and the East Timor Government, values the interest at USD 300 million (AUD 414 million).  Shell reported that the sale is in line with its global strategy, which is seeing it become a “simpler and more resilient company”. The sale and purchase agreement is conditional on a number of conditions, including regulatory approvals, joint venture pre-emption rights and funding approvals. Upon completion of the deal, Shell will assign its 26.56% interest in permits JPDA 03-19, JPDA 03-20, NT/RL2 and NT/RL4 to the East Timor Government.  The JPDA contracts are, at this stage, within the previous-Joint Petroleum Development Area (JPDA) waters.  These will be renegotiated as East Timor PSCs, after the new maritime boundary was outlined in March 2018. These are expected in late 2018/early 2019. The permits contain the Sunrise and Troubadour discoveries, that make up the Greater Sunrise assets.  The discoveries were made in 1975 and 1974 respectively and contain over 5 Tcf gas and 225 MMb condensate. Shell’s sale comes after ConocoPhillips reached an agreement to sell its 30% interest in the assets to the East Timor Government, though this also remains subject to similar conditions to the Shell sale.  Both companies outlined that they differed in opinion with the East Timor Government over how the Greater Sunrise fields should be developed. Shell reported that it “[understood] the priorities of the Timor-Leste Government”. The development scenario for the fields has been long debated, with the Greater Sunrise joint venture (JV) preferring a Floating LNG (FLNG) option, over the East Timor Government’s suggestion to pipe the hydrocarbons back to an onshore plant in East Timor.  The JV have indicated this would be more costly, but also difficult as a development due to the bathymetry between the discoveries and East Timor. Both deals will have significance, as the East Timor Government has outlined that its preference remains, and with greater interest in the project it will have additional input into the development decisions. Upon announcement of the initial transaction, the East Timor Government reported that it would proceed with further discussions with the JV to evaluate the future development.  Woodside, operator of the assets, has indicated that the project falls under its “Horizon III” planned developments, which are scheduled for post-2027.   The Great Sunrise fields have been under discussion for development for some time, with Woodside initially planning to make a decision in 2009.  However a number of issues, including differing opinions in the development scenario, disputes around the maritime boundary and drop in oil price have pushed the development back a number of times.  Woodside has had several discussions with the East Timor government over the development, looking to come to an agreement. However the maritime boundary dispute put this on hold with Woodside reporting that it would wait for a resolution.   A new maritime boundary was agreed and the initial documents signed in March 2018.  The boundary is expected to be finalized and put in place in late 2018/early 2019.  The new maritime arrangement has included a “Special Regime” for Sunrise, which will see East Timor get at least 70% of the government revenues from the development, with the split to be 70:30 (in favour of East Timor) if the development sees a pipeline to East Timor, and split 80:20 if a pipeline to Australia is utilised.  It is not known if this will alter if the government has a stake in the project. Participants in the Greater Sunrise joint venture are: Woodside Petroleum Ltd (33.44% + Operator), OG ZOKA Ltd, a wholly owned subsidiary of Osaka Gas Co Ltd (10%) and Shell Australia Ltd (26.56%) and ConocoPhillips (30%) – both selling their respective shares to the East Timor Government.

Australia, NT/RL2

Equinor and Faroe reported on 5 December 2018 that they have agreed an asset swap deal (with no cash consideration) whereby Equinor will gain 7.5% interests in Bauge, Hyme and Njord in exchange for a 32% interest in Alve, a 17% interest in Marulk and its entire 14.82% interest in Ringhorne East and 28.85% interest in Vilje. The deal will be effective from 1 January 2019 and is subject to government approval. As a result of the deal, Equinor will strengthen its presence in the Njord area where it sees upside potential and is divesting assets which it sees as non-core or which are non-operated. Njord has been offline since 2016 pending a complete upgrade of its facilities as part of the Njord Future project which will add 175 MMboe (including Hyme). Production is scheduled to commence in 2020. Bauge is being developed as a subsea tie-back to Njord and is also due onstream in 2020. Faroe is getting into two new core areas (around Alvheim and Norne) and its acquired assets have a total estimated net volume of 17.6 MMboe. Consequently, it will increase its production by 7,000-8,000 boe/d in 2019. An exploration well is planned on the Snadd Outer Outer and Black Vulture prospects in the Alve licence (PL 159 B) in 2019.

Equinor and Faroe reported on 5 December 2018 that they have agreed an asset swap deal (with no cash consideration) whereby Equinor will gain 7.5% interests in Bauge, Hyme and Njord in exchange for a 32% interest in Alve, a 17% interest in Marulk and its entire 14.82% interest in Ringhorne East and 28.85% interest in Vilje.

Lime Petroleum has withdrawn from PL 762 with effect from 29 June 2018, transferring its 20% interest to Equinor. Lime had announced in January 2018 that it was intending to withdraw from the licence as it did not see this area in the Norwegian Sea – parts of blocks 6608/6, 6608/9, 6609/4 and 6609/7 – as core for the company and it wants to focus its portfolio of assets on and around the Utsira High in the North Sea. The NPD confirmed on 5 July 2018 that the deal was complete. Equinor acquired its first 40% in the licence in April 2018 by way of a deal with Fortis. PL 762 was awarded in APA 2013 and it covers part of the Traena Sub-basin and the Nordland Ridge to the northeast of Urd and Norne. It contains the 1983 dry hole 6609/7-1 drilled by Phillips. This well’s objective was the Upper Paleozoic but the Cretaceous Lange Formation sat directly upon the Zechstein Group, which in turn rested on metamorphic Basement. No sands were present in the Paleozoic and there were only traces of migrated hydrocarbons identified in cuttings from the Cretaceous section. Interest in PL 762 is now held as follows: Aker BP ASA (20% + operator), Equinor Energy AS (60%) and Petoro AS (20%).

Lime Petroleum has withdrawn from PL 762 with effect from 29 June 2018, transferring its 20% interest to Equinor.

Petro-Victory has agreed to acquire interests in 4 onshore oilfields from Empresa de Engenharia de Petróleo for USD 1.6 MM, namely Andorinha + Alto Alegre in the Potiguar Basin (100%), Carapitanga in the Sergipe-Alagoas Basin (50% non-op) and São João in the Barreirinhas Basin (50% non-op). The deals require ANP approval.

Brazil, Alto Alegre

On 30 July 2020, the Agencia Nacional do Petroleo (ANP) granted formal approval for Petrobras to transfer 100% working interest to Eagle Exploracao de Oleo e Gas Ltda for the Conceicao, Fazenda Matinha, Fazenda Santa Rosa and Querera production concessions in the onshore Tucano Basin. The approval is conditioned to both companies presenting documents with details about the decommission of the fields. Petrobras had reported on 9 March 2020 the signature of the sales agreement with Eagle Exploracao de Oleo e Gas Ltda for the Tucano Sul cluster of four producing gas fields mentioned above. The total consideration for the sale was USD 3.01 million which was to be paid in two installments, USD 602,000 on 9 March 2020 and USD 2.41 million on the official closing date of the transaction. On 9 July 2019, Petrobras published its teaser to sell the Tucano Sul cluster of four producing gas fields in the onshore Tucano Basin. Tucano Basin fields sale - general information Field Name Field sqkm Disc Date Year Prod Start Date Avg. cond. Prod. (bc/d) (Jan-May 2020) Avg. gas prod. (Mcfg/d) (Jan-May 2020) Conceicao 9.8 1967 25-Feb-1970 0.38 486.45 Fazenda Matinha 3.95 1986 05-Apr-2005 0.15 99.16 Fazenda Santa Rosa 4.58 1992 25-Oct-2005 0.45 139.39 Querera 5.4 1962 01-Jul-1962 0.00 44.13 Source: IHS Markit © 2020 IHS Markit

(Tucano B.) the Agencia Nacional do Petroleo (ANP) granted formal approval for Petrobras to transfer 100% working interest to Eagle Exploracao de Oleo e Gas Ltda for the Conceicao, Fazenda Matinha, Fazenda Santa Rosa and Querera production concessions.

PL 870, W. Stord Basin, WD 123m, ops terminated 10 days early, Transocean Spitsbergen SS released suggesting a disappointing outcome. PTD was 3,587m, target Statfjord fm. Equinor (op), partner Faroe Petr.

25/06-06 S (Pabow) (Equinor op, partner Faroe Petr) in PL 870, ops. terminated 10 days early, released suggesting a disappointing outcome. WD=123m, PTD was 3 587m, target Statfjord fm.

In mid-March 2018, Perenco Oil & Gas Gabon abandoned the Akoum South 1 (DAKMS-1) exploration well in the DE8 block after reaching a TD of 2,302 m. The well was spudded on 2 February 2018 using Petrofor’s “Dagda” J/U. It has objectives in the Albian Madiela formation. Perenco operates the block with a 60% interest and Sasol holds the remaining 40% interest. DE8 exploration permit is located along the coast off Omboue, 90-190km SSE of Port Gentil, in water depths ranging from 0 to 80m. Straddling the limit between the North and South Gabon sub-basins, DE8 surrounds three fields operated by Perenco Oil Gabon Ltd, Tchatamba Marin, Tchatamba West and Tchatamba South. Potential reservoirs in the area are the Albian Upper Madiela unit, which is the main reservoir on the Tchatamba complex, and the Senonian Batanga Formation. Potential source rocks lie in the Turonian Azile and Albian Madiela formations. Background Information DE8 and D7 were previously owned by Tullow Oil plc from 28 May 2004 to 17 April 2008 under the Akoum Marin exploration permit. With an area of 2,947 sq km, the Akoum Marin permit corresponded to the residual area of the Kowe block, which Marathon relinquished on 16 December 1999. Energy Africa drilled two wells back-to-back in the Akoum Marin permit, AKM-A1 and AKM-B1, in the first half of 2003. The latter was suspended as a potentially commercial oil discovery (Turonian Azile Formation) for a future re-entry. However, on 3 November 2003, the company indicated that, upon evaluation of seismic data in the area, the discovery was found to be too small to justify development. In February or March 2005, Tullow completed prospect evaluation based on interpretation of the 464km 2D seismic data acquired over three zones in the eastern portion of the Akoum Marin permit from 21 August to 2 September 2004. Gardline Geosurvey Ltd was contracted for the survey with the M/V "Sea Surveyor". The acquisition was in addition to the 2D and 3D seismic data recorded in 2003. In 2005, Tullow was engaged in a 2D seismic reprocessing project with Fugro Robertson over the permit. A further 2D seismic acquisition (87km) was processed and interpreted. The following well, Akoum Marin West 1 (AKM-C1), was plugged and abandoned as a dry hole at TD 2,329m on 16 February 2006. The well targeted the Albian Madiela Formation. The jack-up GSF "Adriatic VI" was released to drill the Soulandaka 1 exploration well some 20km to the southeast, on behalf of Marathon. On 13 March 2006, this well was plugged and abandoned as a dry hole at TD 1,875m. On 31 March 2016, Perenco closed the dataroom for DE8 permit. The data room opened on 15 January 2016. The company is expecting offers by 12 May 2016. Perenco operates the block with an 80% interest.

Gabon, Batanga

Following the acquisition of Sterling Resources by ONE-Dyas it is assumed the company is looking to farm-down interest in licence P1914 (part block 49/19b) containing the Niadar prospect. The company is looking for a partner(s) to drill the firm commitment well. Niadar is a Rotliegendes target and is located immediately north of the Brigantine Cluster. It was estimated that the prospect could hold pre-drill resources of 59 Bcf. In Sterling’s Q2 2015 results, announced on 6 August 2015, the company confirmed that it was a licence extension until 2017, as long as the company relinquished 50% of the licence acreage prior to the end of January 2016. This occurred on 31 August 2015 when the company relinquished block 44/18b. The end of the licence is slated for 31 December 2019. P1914 was awarded under the 26th Seaward Licensing Round and comprises of part block – 49/19b. The block covers a total area of 80 sq km. Texaco drilled well 49/14a-2 in 1989 approximately 1 km north of block 49/19b northern boundary. The well was plugged and abandoned with gas shows. If the Niadar exploration well is successful it could be potentially developed through utilising nearby infrastructure. Interest in P1914 is held solely by One-Dyas UK Limited (100%).

Following the acquisition of Sterling Resources by ONE-Dyas it is assumed the company is looking to farm-down interest in licence P1914 (part block 49/19b) containing the Niadar prospect. The company is looking for a partner(s) to drill the firm commitment well. Niadar is a Rotliegendes target and is located immediately north of the Brigantine Cluster.

Providence Resources is planning to offer material interest in Frontier Exploration Licence 3/04 which contains the Dunquin South prospect. In mid-February former operator ENI announced that it was relinquishing its interest in the licence. Following completion of this process Providence will formally announce the farm-out. Dunquin South is a large Carbonate structure. Its sister prospect, Dunquin North, was drilled in 2013 and confirmed the presence of both a reservoir and a residual hydrocarbon column however, there had been a seal breach. Escape features can be seen over the Dunquin North structure but are not present in the Dunquin South structure. ENI held just shy of 37% interest in the licence. Dunquin South is a Lower Cretaceous, Carbonate build-up prospect. The neighbouring Dunquin North prospect was drilled by well 44/23-1 in 2013. The well encountered a thick over-pressured carbonate reservoir system. 44/23-1 drilled through a 250 m massive porous carbonate reservoir which was water bearing. Petrophysical log interpretation showed elevated gas levels, together with oil shows in sidewall cores over the upper section suggesting a residual oil column. In 2014 it was confirmed that the prospect contained at least a 44 m residual oil column where the carbonate reservoir system was breached. Pre-breach oil STOIIP volumes were estimated to be 1.2 Bboe. Providence believes that the Dunquin South prospect is less likely to have been breached based on its high quality 3D seismic.

rovidence Resources is planning to offer material interest in Frontier Exploration Licence 3/04 which contains the Dunquin South prospect. In mid-February former operator ENI announced that it was relinquishing its interest in the licence. Following completion of this process Providence will formally announce the farm-out.

During February 2018, Al Yasat Company for Petroleum Operations LLC (Al Yasat) invited companies to bid on the front end engineering and design (FEED) contract for its planned development of three oil fields within the offshore Central Fields Block. Al Yasat completed an extensive 3D seismic campaign over the undeveloped Umm Al Salsal, Umm Al Dholou and Belbazem oil fields in October 2015. It subsequently drilled and tested a successful appraisal well on the Belbazem structure during 2016. The company is targeting a production rate of 45,000 barrels of oil a day (bo/d) and 30 million cubic feet of gas (MMcfg/d) by 2023 from the concession, which is contiguous to the super giant Umm Shaif and Zakum field development areas. Al Yasat has already adopted an accelerated contracting strategy and execution plan for its first offshore development, the US$ 150 million Bu Haseer Early Production Scheme Project which is targeting first oil in 2018.  

UAE, not found

In the Q1 2020 production figures published by NIS, the natural gas production in the quarter averaged 41,354 Mscf/d. The original production figures provided by NIS for the Q1 2020 period amounted to 96,000 toe. The Q1 2020 daily rate natural gas production represents an increase of 1% compared to Q4 2019 which averaged 40,904 Mscf/d. The 2020 daily output average up to the end of Q1 was 4.1% down compared to the Q1 2019 daily output that averaged 43,120 Mscf/d. Since the beginning of 2013 LPG (Liquefied petroleum gas) production is included in the oil and condensate production figures. The major gas producing fields are Medja, Martonos, Itebej, Torda Plitko and Milosevo.

Serbia (Banat Sub-basin (Pannonian B.)) Torda Plitko

Wensu block, Aksu area in Tarim Basin, 33.2m oil pay between 1,160-1,540m in the Miocene Jidike fm, tested ab. 200 bo/d in May. Follow-up appraisal Wen 7-1 then penetrated 57.1m of o&g pay in the Jidike fm + pre-Cambrian basement, tested 1.2 MMcfg/d from the basement in July.

China, not found

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

Pandion will acquire a 10% interest in PL 820S from Wintershall (->20%, MOL 40% op. Lundin 30%).

N-C part of Peroba P3 contract, location near Lula + Sapinhoá fields in Santos pre-salt, WD 2,235m, shows report to ANP early Jan ’19, susp early Feb ’19, ODN II DS. PTD est. 6,500m, targets Barra Velha + Itapema fm’s.

1-RJS-752 (1-BRSA-1363-RJS - Peroba) nfw N-C part of Peroba P3 contract, location near Lula + Sapinhoá fields in Santos pre-salt, WD 2,235m, shows report to ANP early Jan ’19, susp early Feb ’19, ODN II DS. PTD est. 6,500m, targets Barra Velha + Itapema fm’s

On 29 May 2018, the Georgian State Agency for Oil and Gas (SAOG) and Spanish Repsol signed a Memorandum of Understanding (MoU) on the joint study of hydrocarbon potential in the Kura Basin. The company will then present propositions for their development.

Georgia, not found

The following text is the view of the editor and addresses some of the highlights planned for 2020 – article written in July 2020. Disko Island and Nuusuuaq Peninsula onshore areas are open for licence applications Five further areas to be opened for licensing between November 2020 and January 2022 Drilling programme by GGO potentially starting in December 2020 Licensing: Greenland will see a series of Open Door Procedures and Licensing Rounds between 2020 and 2022. The first of these, covering the onshore Disko Island and Nuussuaq Peninsula areas, opened for bids in February 2020. An end date has not yet been given but a three-month notice period will be provided in advance of closing. Three blocks are available totalling 13,073 sq km. The next areas to open will be Davis Strait, Baffin Bay and Disko West (all offshore) in November 2020 and these will be followed in 2021 by Northeast Greenland and in 2022 by Central East Greenland. Region (area) Opening date Type Disko Island and Nuussuaq Peninsula February 2020 Open Door Procedure Davis Strait November 2020 Open Door Procedure Baffin Bay November 2020 Open Door Procedure Disko West November 2020 Open Door Procedure Northeast Greenland July 2021 Licensing Round Central East Greenland January 2022 Licensing Round Drilling: In late 2019 Greenland Gas and Oil (GGO) confirmed its plans to potentially undertake exploration drilling in its onshore licences in Jameson Land between December 2020 and March 2021. The company has identified three potential drilling locations – two in licence 2015/13 and one in 2015/14. The first well will be located in the southwestern part of 2015/13 and the second will lie in the northwest area of the same licence. A possible third well would lie in the northwestern part of 2015/14. The Jameson Land Basin is a multiple-play system and GGO sees the greatest potential in the Middle Jurassic (Pelion Member of the Vardekloft Formation and Olympen Formation) and the Lower Jurassic (Kap Stewart Formation and possibly the Neill Klinter Formation). Secondary targets are the Upper Jurassic Hareelv Formation in the southernmost licensed area and the Upper Triassic Gipsdalen and Fleming Fjord formations. Jameson Land was previously licensed to ARCO which, for a five year period ending in 1990, was the operator of approximately 10,000 sq km over the central part of the basin. A large amount of data was accrued but no exploration wells have been drilled to date. Studies by GEUS and several academic institutions, along with GGO’s own studies, suggest that the key elements for a hydrocarbon system exist. GGO has identified several major source and reservoir intervals and a number of potential drillable targets (50+ leads) throughout the 17 km stratigraphic thickness of the basin. Gross unrisked recoverable resource volumes (mid-case) are approximately 3.3 Bboe. GGO has acquired and processed a Full Tensor Gravimetric survey over its acreage and has integrated this with a reprocessed 2D seismic data set from GEUS. In addition to the three licences operated by GGO, there is another licence in the southwestern part of Greenland held by Panoceanic Energy. 2017/14 was awarded in August 2018 and covers an area of 9,999 sq km. No details of the work programme have been released.

Greenland, Disko Island and Nuusuuaq Peninsula onshore areas are open for licence applications Five further areas to be opened for licensing between November 2020 and January 2022 Drilling programme by GGO potentially starting in December 2020 Licensing: Greenland will see a series of Open Door Procedures and Licensing Rounds between 2020 and 2022. The first of these, covering the onshore Disko Island and Nuussuaq Peninsula areas, opened for bids in February 2020.

According to official reports in early-June 2020, state company ANCAP has awarded the offshore block OFF-1 to Bahamas Petroleum Company (BPC) following an offer that was submitted on 29 May 2020 as part of the ongoing Uruguay Open Round. Work commitments for the first exploration period of four years in the block include reprocessing 2,000 km of historical 2D seismic data and undertaking of new geophysical/geological studies with the investment cost of approximately USD 900,000 including mandatory contributions to various education and social funds and initiatives. A commitment of one exploration well is expected in the second phase if the operator selects a three-year option, or a 50% relinquishment with no drilling obligation if the operator decides to go with a shorter two-year option. The drilling of two wells and a 30% relinquishment are required in the third exploration phase of three years. BPC holds 100% stake in the block, although ANCAP has the right to back-in for up to 20% participating interest. OFF-1 offshore block covers 14,581 sq km of area in Rio Salado Basin with water depths ranging from 20 m to over 1,000 m. The block is situated adjacent to OFF-2 and OFF-3 on the eastern side where Kosmos Energy currently has a couple of pending awards after submitting its offers to ANCAP in October 2019. Approximately 12,000 km of 2D seismic data has been acquired on the block from the early 1970s through 2015 with no 3D coverage, although to-date the area has only been drilled by Chevron with a couple of plugged & abandoned wells in 1976. It was said that BPC estimated potential of the area up to 1 Bboe due to having a perceived exploration play that is similar in nature to the Guyana - Suriname basins as well as the Cretaceous turbidite plays that have been successfully explored in offshore north-eastern South America. The OFF-1 block marks BPC's first asset outside of the Bahamas where it holds 100% stake in five offshore blocks over waters approximately 200 to 500 meters deep in the Florida-Bahamas Platform Basin. On the northern side of the islands near the border with the United States, the company is the operator on the Miami block which covers 3,080 sq km of area. Meanwhile in the southern side against the border with Cuba, it operates four commercially co-joined offshore licenses of Bain, Cooper, Donaldson, and Eneas blocks which cover a total area of 12,241 sq km. Most recently BPC postponed the drilling of the Perseverance 1 exploration well for to December 2020 due to concerns for the safety of the crew amidst the coronavirus disease 2019 (COVID-19) pandemic. Background Information ANCAP launched a new biannual open round process called Uruguay Open Round with six blocks offshore and five blocks onshore in May 2019. In addition to areas that were previously offered in the last Uruguay Round 3 offshore round in 2018, the new licensing round also offers parcels that cover several recently relinquished offshore blocks in the south, along with onshore blocks in the north which cover areas that previously have been offered in their own open round process since 2014.

According to official reports in early-June 2020, state company ANCAP has awarded the offshore block OFF-1 to Bahamas Petroleum Company (BPC) following an offer that was submitted on 29 May 2020 as part of the ongoing Uruguay Open Round.

PPL 262, onshore Cooper-Eromanga Basin, TD 1,820m, Balgowan field appraisal suspended as successful oil well, Saxon rig 184 has since spudded Balgowan-4.

PPL 262, onshore Cooper-Eromanga Basin, TD 1,820m, Balgowan field appraisal suspended as successful oil well,

In October 2019, Madagascar Oil was still looking for partners for its Tsimiroro licence. The company seeks to share the risk of its exploration drilling plan. The licence is situated in the Sakamena Sub-basin (Morondava Basin). Madagascar Oil holds a 100% interest in the licence. Interested parties can contact Ian Cross at Moyes & Co: Tel: +65 9776 0753 Email : [email protected]

Madagascar, Tsimiroro

P-D is understood preparing to offer its wholly-owned DS-12 block for farmin. The 3,561-sq km unit lies in deepwaters of the Bay of Bengal on the Myanmar borderline:

P-D is understood preparing to offer its wholly-owned DS-12 block for farmin. The 3,561-sq km unit lies in deepwaters of the Bay of Bengal on the Myanmar borderline:

Premier Oil, together with its joint venture partners Mubadala Petroleum and Kris Energy, has been awarded the Andaman II Licence in the 2017 Indonesian Licence Round.  The Andaman II licence is located in the underexplored but proven North Sumatra basin offshore Aceh, Indonesia. Premier has identified numerous prospects and leads which exhibit DHIs (direct hydrocarbon indicators) on the existing 2D seismic data, significantly de-risking a potentially material gas play.  Premier assesses that the overall licence has the potential for significant gas volumes which, in the success case, would be delivered to existing gas consumers in North Sumatra.Premier Oil awarded Andaman II licence, offshore Indonesia The forward plan is to acquire 3D seismic in the initial three year term. Tony Durrant, CEO, commented: ‘This award is in line with Premier’s strategy of targeting low commitment high impact exploration in proven hydrocarbon provinces and has the potential to deliver significant organic growth opportunities for our existing Indonesian business in the longer term.’ The JV comprises Premier (operator, 40%), Mubadala Petroleum (30%), and Kris Energy (30%). Original article link Source: Premier Oil

Indonesia, not found

Red Willow, partner in the EnVen-operated Green Canyon block 166 (Dothraki prospect), is looking to sell a 10-15% interest from its 30% stake. Up to 4 wells are cleared to drill in WD 650-700m, 120-day wells, ops start in March. EnVen (op), partners Ridgewood, Red Willow + Houston Egy.

Red Willow, partner in the EnVen-operated Green Canyon block 166 (Dothraki prospect), is looking to sell a 10-15% interest from its 30% stake. Up to 4 wells are cleared to drill in WD 650-700m, 120-day wells, ops start in March. EnVen (op), partners Ridgewood, Red Willow + Houston Egy.

In a press release dated 19 September 2019, Talos Energy announced BP farmed in to the Puma West prospect in Green Canyon block 821 (G34561).  Talos will retain 25% working interest in the prospect while BP will obtain 75% working interest and assume operatorship. Puma West is a subsalt prospect targeting Mioecene reservoirs expected to be similar to those at BP’s Mad Dog field about 15 miles to the east. Mad Dog has produced over 230 MMboe to-date.  BP is constructing the Argos platform for the Mad Dog II project, adding 140,000 bo/d of additional production capacity at the field. The block is approximately 137 mi (220 km) south of the onshore supply base located at Port Fourchon, Louisiana. BP filed an exploration plan (N-10075) which was deemed submitted by the Bureau of Ocean Energy Management (BOEM) on 29 August 2019 and is currently under review. The plan proposes the drilling and completion of two wells, with each taking an estimated 135 days to drill. Water depths at the proposed locations vary from 4,069-4,098 ft (1,240-1,249 m). The partnership plans to drill the prospect before the end of October 2019 with the Seadrill “West Auriga” drillship. The block was originally leased by Apache (60%) and Stone (40%) in Sale 222 held on 20 June 2012 with a bonus bid of USD 3.48 million. BHP also submitted a sole bid of USD 583,160. Stone took over as operator with 100% working interest effective May 2014, and later merged with Talos in May 2018.

United States (Sigsbee Sub-basin (DWGoM B.)) Mad Dog

CNOOC has decided not to pre-empt the sale of Tullow's assets in Uganda to Total. Tullow announced last month it had agreed the disposal of its assets to Total and that CNOOC had rights of pre-emption to acquire 50% of the assets on same terms + conditions as Total. Accordingly, there are no changes to the previously-announced transaction or timeline and the deal should complete in 2H '20. Involved are: - Total-operated: Exploration Area 1/1A (Lyec), PL7/2016 (Jobi-Rii), PL8/2016 (Gunya), PL6/2016 (Ngiri) - Tullow-operated: PL3/2016 (Nsoga), PL1/2016 (Kasamene-Wahrindi), PL4/2016 (Ngege), PL2/2016 (Kigogole-Ngara), PL6/2016 (Mputa-Nzizi-Waraga) - CNOOC-operated: PL1/2012 (Kingfisher).

CNOOC has decided not to pre-empt the sale of Tullow's assets in Uganda to Total. Tullow announced last month it had agreed the disposal of its assets to Total and that CNOOC had rights of pre-emption to acquire 50% of the assets on same terms + conditions as Total. Accordingly, there are no changes to the previously-announced transaction or timeline and the deal should complete in 2H '20. Involved are: - Total-operated: Exploration Area 1/1A (Lyec), PL7/2016 (Jobi-Rii), PL8/2016 (Gunya), PL6/2016 (Ngiri) - Tullow-operated: PL3/2016 (Nsoga), PL1/2016 (Kasamene-Wahrindi), PL4/2016 (Ngege), PL2/2016 (Kigogole-Ngara), PL6/2016 (Mputa-Nzizi-Waraga) - CNOOC-operated: PL1/2012 (Kingfisher).

Correction DEA 13 Mar ’19 : Ref.  Wednesday’s piece on Eni acquiring interests in Yorkshire licences, this news has been dispelled by Eni, who has indeed not returned to UK onshore. Despite official sourcing, the news is in fact incorrect and should be disregarded. The offending article has been withdrawn from the relevant databases.

Correction Wednesday’s piece on Eni acquiring interests in Yorkshire licences, this news has been dispelled by Eni, who has indeed not returned to UK onshore. Despite official sourcing, the news is in fact incorrect and should be disregarded.

GK-OSN-2009/1, offshore Kutch Basin, PTD 3,830m, believed gas discovery, tesed late Dec ’18, w.o. confirmation. Parameswara JU. ONGC (op), partners GSPCL, Adani Welspun + IOC.

GKS091NFA A nfw in GK-OSN-2009/1, offshore Kutch Basin, PTD 3,830m, believed gas discovery, tesed late Dec ’18, w.o. confirmation.

As of 20 July 2020, Olympic Peru continues to look for partners in the onshore Block XIII B located in the Sechura Basin. The block has been available for farm-out since 2010. Multiple wells have been drilled on the block by various operators over time. A table showing exploration drilling over time is provided below. Historical Exploration Drilling on Block XIII B           Operator Name Well Name Spud Date Completion Td Feet Td Meter Technical Status International Petr Expectivia 1-X 4-Mar-54 2-Apr-54 5686 1733 P&A dry Olympic Peru Inc Rio Loco 1X 2-Feb 31-Dec-02 4711 1436 P&A gas International Petr Viru 01 8-Aug-53 4-Dec-53 7323 2232 P&A dry International Petr Viru 02 25-Sep-56 13-Oct-56 5983 1824 P&A dry International Petr Viru 05-X1 22-May-54 18-Jul-54 8063 2458 P&A dry Source: IHS Markit           © 2020 IHS Markit   Geology The Sechura Basin is situated in northwestern Peru, mainly onshore (about 19,000 sq km), but it extends southward into the offshore (almost 10,000 sq km out of the 500-m isobath). It is located along the desert of Sechura plain, between the Western Cordillera and the coastal range/outer shelf high. The basin is limited by basement highs in the north and south. Occasionally, the Sechura Basin is considered as a north continuation of the Salaverry Basin (Zuniga-Romero et al., 1998). Numerous fault structures ranging from intense to moderate are present in the Sechura Basin. Structures were formed and reshaped in response to multiple episodes of extension, compression/inversion and wrenching. There are extensional and growth faults, strike-slip faults, structural rollovers and a few thrusts. Normal faulting has been active since at least Late Cretaceous time, and probably earlier. It has created a basin of complexly faulted sedimentary blocks. Seismic data indicate that faulting is more intense offshore, especially on the west flank of the Coastal Range. (except from the IHS Markit Basin Monitor)

(Sechura b.) Block XIII-B operated by OLYMPIC (51%), ENEL AM (41%), Cdc Group (6%), GOVT NO (2%), Olympic Peru continues to look for partners in the onshore Block XIII B, available for farm-out since 2010. Multiple wells have been drilled on the block by various operators over time.

Sidetrack of 2014 Obaiyed J13-1, Obaiyed West (Dev) block, Northern Egypt Basin, P&A late Sep '19 at TD 3,574m, EDC rig 48. Target Alam El Bueib E.   The well was a sidetrack of Obaiyed J13-1 drilled in 2014. Obaiyed J13-1ST1 was spudded on 4 September 2019 with the "EDC-48" land rig and drilled to a TD of 3,574 m. The main objective was the E Unit of the Alam El Bueib Formation.   The Obaiyed West (Dev) block extends over 432 sq km and includes the Obaiyed gas field discovered in 1992. It was granted to Obaiyed Petroleum Co in December 2002.   Obaiyed Petroleum Co is a JV between EGPC (50%), Shell Egypt NV (25.5%) and Obaiyed Erdoel & Gewinnungs GmbH (24.5%).

Sidetrack of 2014 Obaiyed J13-1, Obaiyed West (Dev) block, Northern Egypt Basin, P&A

On 27 March 2018, the consortium of Total, BP, and Pan American, was granted a preliminary award for the 734 sq km Area 34, G-CS-03 block from the CNH-RO3-LO1/2017 Bid Round.  The final official contract signature award is to take place within 90 days or 1 July 2018. The consortium bid a state take of 50.49% over the minimum of 22.5% for the Area 34 block and a work units factor of 1 equivalent to one well.  The provisional consortium working interest breakdown is estimated to be Total, operator with 33.34% working interest, BP with 33.33%, and Pan American with 33.33% working interest. There was one other bid for the block.  The second highest bidder was the consortium of Shell and PEMEX who bid 40.36% state take and 0 additional work units factor.  

Total, BP, and Pan American, was granted a preliminary award for the 734 sq km Area 34, G-CS-03 block from the CNH-RO3-LO1/2017

On 8 December 2017, the consortium of Iberoamericana de Hidrocaruburos, S.A. de C.V. and Servicios PJP4 de Mexico S.A. de C. V. signed the contracts with the CNH and was granted official final awards for the CNH-RO2-L03-BG-01/2017 and CNH-RO2-L03-BG-04/2017 contracts from the CNH-RO2-LO3/2016 Bid Round.  The CNH-RO2-L03-BG-01/2017 contract is also known as the Area 1, BG-01 block.  The CNH-RO2-L03-BG-04/2017 contract is also known as the Area 4, BG-04 block.  The consortium formed a separate subsidiary, Iberoamericana de Hidrocaruburos CQ, Exploracion & Produccion de Mexico, S.A. de C.V. with 100% working interest as the official designated operating company for the blocks.  The 99.25 sq km CNH-RO2-L03-BG-01/2017 contract has a total financial commitment of USD 24.34 million, USD 20.1 million in work commitments including two additional wells plus the tie-break bonus of USD 4.24 million.  The 199.3 sq km CNH-RO2-L03-BG-04/2017 contract has a total financial commitment of USD 14.6 million, all for work commitments that includes one extra well. On 12 July 2017, the consortium of Iberoamericana and Servicios PJP4 was the high bidder in the CNH-RO2-LO3/2016 Bid Round for the Area 1 and Area 4 blocks in the Burgos Basin and was granted preliminary awards.   For the 99.25 sq km Area 1 block the Iberoamericana consortium offered the maximum additional royalties of 25% and 1.5 work unit factor equivalent to two additional wells.  There were two other bids for the block and one offered the same royalties and work units so ended in a tie. The Iberoamericana consortium won the tie break with a bonus bid of USD 4.3 million beating the 2nd place consortium of Shandong, Sicoval, and Nuevas Soluciones who offered a bonus of USD 3.2 million.   For the 199.30 sq km Area 4 block the Iberoamericana consortium offered the minimum additional royalties of 3.9% and 1.0 work unit factor equivalent to one well.  It won the block as there were no other bids.  It is estimated that the winning Iberoamericana consortium is split 50%-50% but the final official equity breakdown will only be reported at a later date. The general license contract terms include a 1st exploration period of two years with the possibility of a two-year extension.  In the case of a discovery the operator can request a two-year evaluation phase for oil and a three-year evaluation phase for non-associated gas discoveries once the evaluation plan is approved.  The total contract term is for 30 years with the possibility of two five year extensions for a 40-year total contract term from signature date. The base royalty rate is a sliding scale royalty depending on type of hydrocarbon and oil price.  The values for oil range from 5% for USD 40/bbl oil to 25% for USD 200/bbl oil.  The relinquishment schedule is tied to exploration well commitments.  If the exploration period ends but the operator offers to drill an additional well it doesn’t have to relinquish any area.  If the exploration period ends and the contractor doesn’t have any discoveries it must relinquish 100%.  If the exploration period ends and the operator doesn’t offer to drill an additional exploration well it will have to relinquish 50% of the area.  Local content during the exploration period is 26% for the exploration and evaluation period, and varies from 27% to 38% in the development period.

Mexico (Sureste B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: 12 op. by LUKOIL (100.0%) to be check.14 op. by ENI SPA (60.0%, CITLA 40.0%) to be check.Area 4 (Ichalkil) op. by RIVERSTONE (50.0%, PETROBAL 50.0%) to be check.Area 1 (Tecoalli A) op. by ENI SPA (100.0%) to be check.Area 1 (Tecoalli B) op. by ENI SPA (100.0%) to be check.Area 4 (Pokoch) op. by RIVERSTONE (50.0%, PETROBAL 50.0%) to be check.9 op. by OTP (49.0%, ETAP 51.0%, TPS 0.0%) to be check.Area 1 (Mizton) op. by ENI SPA (100.0%) to be check.Area 1 (Amoca) op. by ENI SPA (100.0%) to be check.

Bridgeport Energy Ltd was granted a ten year renewal to exploration permits ATP 2025-P and ATP 2026-P, located in the Cooper-Eromanga Basin, on 12 November and 31 October 2018 respectively.  The effective date of both renewals is 1 November 2017 and both are now due to expire on 31 October 2027. ATP 2025-P and ATP 2026-P were both awarded on 11 August 2017.  No wells have yet been drilled in either permit, however there are a number of previously drilled wells within the permits and oil discovery Moothandella 2 is located in ATP 2025-P. Bridgeport Energy Ltd is looking to farm-out interest in both permits, as part of a wider farm-down of its Cooper-Eromanga Basin assets. Bridgeport is looking to divest its interests via single or multiple farm-in options and negotiable farm-out interest of up to 60% equity. Regional 2D seismic and 3D seismic surveys and exploration wells are planned as part of minimum work commitments. Bridgeport will allow early participants the option to influence the exploration programmes. ATP 2025-P, which covers an area of 309 sq km, and ATP 2026-P, which covers 1,783 sq km, were granted a renewal in late October and early November 2018.  Bridgeport Energy (QLD) Pty Ltd holds 100% interest and operatorship of the permits.

Australia (Eromanga B.) ? op. by BRIDGEPT Q (100.0%) in ATP 2025-P block

Zennor has agreed to buy Mitsui’s 8.97% interest in the Britannia field in P213 / block 16/26a area B and P345 / block 16/27b area B. Completion of the deal is subject to usual approvals and would be effective 1 Jan ‘18. Zennor is already involved nearby with ownership of the Finlaggan field, due to be tied-into Britannia. Britannia has so far been co-owned by Chevron, ConocoPhillips + Mitsui, operating under the Britannia Operator Ltd name.

Zennor has agreed to buy Mitsui’s 8.97% interest in the Britannia field in P213 / block 16/26a area B and P345 / block 16/27b area B.

KG-ONN-2004/1, KG Basin onshore, HPHT well to TD 4,758m late Mar ’18, minor tight gas find, tested 60 Mcfg/d, commerciality to be established. Oil India Ltd (op), partner GeoGlobal Resources.

GDK-1 nfw in KG-ONN-2004/1, KG Basin onshore, HPHT well to TD 4,758m late Mar ’18, minor tight gas find, tested 60 Mcfg/d, commerciality to be established. Oil India Ltd (op), partner GeoGlobal Resources.

The NPD confirmed on 9 May 2018 (effective from 30 April 2018) that Lundin has completed its deal to acquire Statoil’s 20% interest in PL 860. Lundin reported on 1 February 2018 that it had agreed a deal with Fortis to acquire the latter’s 10% interests in PL 539 and PL 860 and its 30% interests in PL 820 S and PL 825. This deal was reported as complete by the NPD on 20 February 2018 (effective from 15 February 2018). Lundin entered PL 539 and PL 860 in late 2017 by acquiring 10% interests from Fortis. PL 539 covers part of block 3/7 to the west of Trym and contains the 2015 Myrhauk prospect dry hole 3/7-10 S. PL 820 S lies between Jotun and Balder, covering parts of blocks 25/7 and 25/8 (below Base Paleocene) and PL 825 lies between Oseberg, Veslefrikk and Huldra covering parts of blocks 30/3 and 30/6. PL 860 covers parts of blocks 2/6, 2/9 and 3/4 to the east of Ekofisk, northeast of Valhall and the northwest of Trym and contains the 1997 oil discovery made by 2/6-5. Operator MOL is intending to drill a well on the Oppdal / Driva prospects on the Mandal High in PL 860 in Q3 2018. Oppdal is mapped to extend south into PL 539 and potential reserves for both prospects are 434 MMboe. The Myrhauk well was drilled by Premier, targeting the Upper Jurassic Ula Formation and the Middle Jurassic Bryne Formation in a three-way dip closure with up-dip pinchout. Prior to drilling, Premier put potential reserves at 10-135 MMboe with Top Reservoir expected at 3,346 m TVD. However, no Ula Formation was present and the 100 m thick Bryne Formation had 45 m of sands but contained no hydrocarbons. 2/6-5 was drilled by Saga on a structural closure mapped at Top Shetland Group on the northern part of the Mandal High. The well proved oil in a very tight Upper Cretaceous Tor Formation reservoir and also exhibited shows in the Ekofisk Formation and in Basement. Two intervals in the Tor Formation were perforated and flowed after acid stimulation, although only water with 3% oil was produced. Test permeability was just 0.4 mD.   Following the completion of both deals interest in PL 539 is held by MOL Norge AS (80% + operator) and Lundin Norway AS (20%), interest in PL 820 S is held by MOL Norge AS (40% + operator), Lundin Norway AS (30%) and Wintershall Norge AS (30%), interest in PL 825 is held by Faroe Petroleum Norge AS (40% + operator), Lundin Norway AS (30%) and Spirit Energy Norge AS (30%) and interest in PL 860 is divided between MOL Norge AS (40% + operator), Lundin Norway AS (40%) and Petoro AS (20%).

Norway (Cod Terrace (Central Graben)) Ula

Puguang block / sour gas field outlying area, Chuandong Fold Belt in Sichuan Basin, 2017 well, reportedly tested 13 MMcfg/d on 8mm choke after fracking earlier this month, 6 pay zones encountered. PTD was 4,200m, 1,900m horiz section.   Drilling meanwhile continues on Fen-3, Fenshuiling prospect NW of the Puguang field, PTD 6,270m, target Permian Changxing fm, and up to 7 appraisals could follow.

Maoba 504-1H explChina (Sichuan B.)op. by SINOPEC ZH (100.0%) in Daxian-Xuanhan block, reportedly tested 13 MMcfg/d on 8mm choke after fracking earlier this month, 6 pay zones encountered.

Armenian Gas and Power (Canadian) secured explo rights to block 5 on 1 Dec ’17, one of 3 licences awarded during the month. The contract area covers 2,774 sq km in S-C Armenia and runs 5 years.

Armenian Government issued three exploration licenses to two companies. Armenian O&G received exploration licenses for Block 1 and Block 3 and AGAPE (Armenian Gas and Power Enterprises) received an exploration license for Block 5.

Petronas has further extended the bid deadline for explo blocks in the 2020 Malaysia bidding round from 30 Jul '20 to 30 Nov '20. Contacts: Block Promotion ([email protected]) and Asset/Field Promotion ([email protected]). It is recalled 8 explo blocks, 4 Discovered Resources Opportunity clusters + 3 Technical Study opportunities are on offer. Exploration blocks lie off Peninsular Malaysia (PM-326, 416, 417 + 524) and in shallow - deepwater Sabah (SB-408, 410, 414 + 2T). DROs include the Diwangsa Cluster and Rhu-Ara Cluster in off Peninsular Malaysia, and the Bambazon + Kerisi clusters in shallow - deepwater Sabah. Technical Studies are mainly off Peninsular Malaysia, namely the MASA cluster + Tembungo field off Sabah + one gasfield (BIGST cluster). Data room via EzDataRoom to 30 Nov '20 for exploration and DRO Clusters.

(Northwest Sabah Province), Petronas has further extended the bid deadline for explo blocks in the 2020 Malaysia bidding round from 30 Jul '20 to 30 Nov '20. It is recalled 8 explo blocks, 4 Discovered Resources Opportunity clusters + 3 Technical Study opportunities are on offer. Exploration blocks lie off Peninsular Malaysia (PM-326, 416, 417 + 524) and in shallow - deepwater Sabah (SB-408, 410, 414 + 2T). DROs include the Diwangsa Cluster and Rhu-Ara Cluster in off Peninsular Malaysia, and the Bambazon + Kerisi clusters in shallow - deepwater Sabah. Technical Studies are mainly off Peninsular Malaysia, namely the MASA cluster + Tembungo field off Sabah + one gasfield (BIGST cluster).

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

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

Along with its Monument sale (DEA 27 Sep ’18), Anadarko has sold its 37.5% in 10 contiguous Walker Ridge blocks (11, 55, 56, 98, 99, 100, 143, 144, 145, 189) which contain the undeveloped 2013 Coronado discovery. The sale was effective 1 Jul ’18 and made to existing partners Equinor and Venari Offshore, now 60:40.

Along with its Monument sale, Anadarko has sold its 37,5% in 10 contiguous Walker Ridge blocks (11, 55, 56, 98, 99, 100, 143, 144, 145, 189) which contain the undeveloped Coronado discovery, now shared between Equinor (60% WI + Op) and Venari Offshore (40%).

On 2 June 2018, it was announced that Calik Petrol Arama Uretim San. ve Tic. A.S. (Calik Petrol) had transferred a 50% interest in exploration licences M48-B2,B3 and M49-D1,D2, to High Power Eruh Petrol Arama ve Uretim Sirketi A.S. (High Power) on 21 May 2018. The transfer of interest was applied for on 18 April 2018 with the financial details of the transfer being unknown. The exploration licences cover 608 sq km in the Southeast Turkey Zagros Fold Belt. The new interests are as follows: Calik Petrol holding 50% and operatorship and High Power with the remaining 50% interest.

Calik Petrol had transferred a 50% interest in exploration licences, M48-B2, and M49-D1, D2 to High Power

Verus Petroleum announced on 20 September 2018 that it has signed a Sale and Purchase Agreement to acquire CIECO Exploration and Production (UK) Ltd, a wholly owned subsidiary of ITOCHU Corporation. The consideration for the deal is USD 400 million with an economic date of 1 January 2018. The acquisition includes a 23.1% interest in the Western Isles development (Harris and Barra), 25.8% in the Hudson field, 2% in the Brent pipeline and 1.2% in the Sullom Voe Terminal. CIECO held 12% in the Verbier discovery in licence P2170 but it has been confirmed that this asset is not part of the deal. The acquisition of the producing assets will add approximately 11,000 boe/d to the Verus portfolio. The transaction is subject to regulatory approvals and is expected to complete in the fourth quarter 2018.

Verus announces an agreement to acquire from Itochu its subsidiary Cieco E&P for US$ 400MM. This includes a 23,1% interest in the Western Isles devt project (Harris + Barra oilfields) and 25,8% in the Hudson field (both in P472). It will add ab. 11,000 boe/d to Verus’ daily production.

Trinidad’s 2017 nomination process has resulted in 8 blocks being selected for offer in the planned 2018 round, but the schedule is still not available. Shallow-water blocks NCMA 2, 1(b) and U(c), NCMA 3, 4(c) and Lower Reverse L, and onshore Charuma A + B.

Trinidad’s 2017 nomination process has resulted in 8 blocks being selected for offer in the planned 2018 round, but the schedule is still not available. Shallow-water blocks NCMA 2, 1(b) and U(c), NCMA 3, 4(c) and Lower Reverse L, and onshore Charuma A + B.

Santos Ltd was awarded production licence PL 1026, located in the Cooper-Eromanga Basin, on 9 July 2019.  The licence has been awarded for a period of five years and will expire, or be eligible for renewal, on 8 July 2024. The licence was applied for in February 2017. The licence contains the Raworth gas and condensate field, which was discovered in February 2001.  The field has been producing since June 2013. The licence is replacement tenure for PL 189, which covered the same area and location and was surrendered on 9 July 2019.  PL 189 had been awarded in March 2002. PL 1026 is one of three production licences awarded to Santos on this date, all as replacement tenure for prior licences. PL 1026, which covers an area of 18 sq km, was awarded on 9 July 2019.  Participants in the permit are Santos Ltd (40% + Operator), Santos subsidiary Vamgas Pty Ltd (15.5%), Beach Energy subsidiaries Delhi Petroleum Pty Ltd (32%) and Mawson Petroleum Pty Ltd (6.5%), Bridgeport Energy (Eromanga) Pty Ltd (2%), Bounty Oil and Gas NL (2%) and Energy World Corp subsidiary Australian Gasfields Ltd (2%).

Santos Ltd was awarded production licence PL 1026, located in the Cooper-Eromanga Basin,

Petrobras signed a sale agreement with Eagle Exploração de Óleo e Gás Ltda for the Tucano Sul gasfield cluster, onshore Tucano Basin (Conceicão, Fazenda Matinha, Fazenda Santa Rosa + Querera leases) for USD 3.01 MM cash. Deal pending various govt approvals.

Petrobras has agreed to sell a quartet of onshore natural gas fields (Conceicao, Fazenda Matinha, Fazenda Santa Rosa and Querera) to local company Eagle for US$3 MM.

Lease AA-093131, NPR-A North Slope, N. of Horseshoe Nanushuk oil discovery, oil pay believed encountered in the target Nanushuk fm (Cret.), Arctic Fox rig 1. ConocoPhillips (op), partner Anadarko.

United States (Taroom Trough (Bowen - Surat B.s)) Horseshoe

Zenith has paid Kufpec USD 250,000 of the USD 500,000 required for the acquisition of the latter's 22.5% in CTKCP*, operator of the Sidi El Kilani lease/field (204 sq km) and North Kairouan block (3,172 sq km), onshore Pelagian Basin. Pending govt approval, partnership will become CTKCP (op), Zenith, CNPC + ETAP). * Compagnie Tuniso-Koweito-Chinoise de Pétrole.

Tunisia (Pelagian B.) Sidi El Kilani op. by ETAP (55%), KPC (23%), CNOOC (23%), Zenith has paid Kufpec USD 250,000 of the USD 500,000 required for the acquisition of the latter's 22.5% in CTKCP*, operator of the Sidi El Kilani lease/field (204 sq km) and North Kairouan block (3,172 sq km), onshore Pelagian Basin. Pending govt approval, partnership will become CTKCP (op), Zenith, CNPC + ETAP). * Compagnie Tuniso-Koweito-Chinoise de Pétrole.

Total is looking to dilute its 50% stake in block 48/16, 3,563 sq km undrilled in deepwaters of the Congo Fan. A well is planned here in 1Q ’20. Partner Sonangol.

Total is looking to dilute its 50% stake in block 48/16, 3,563 sq km undrilled in deepwaters of the Congo Fan. A well is planned here in 1Q ’20. Partner Sonangol.

Equinor Energy do Brasil Ltda was evaluating oil shows in the Carcara East (3-EQNR-003-SPS) outpost well in the N_CARCARA block, Norte de Carcara_P2 contract during late-April 2019 according to the ANP and this is assumed to indicate the operator may be conducting testing operations.  The operator filed an oil show report with the ANP for the well on 27 March 2019. The outpost was spudded on 8 February 2019.    The well had a proposed total depth (PTD) of 6,796 m with the primary targets the pre-salt Early Cretaceous Barra Velha and Itapema formations. The well is being drilled by the “West Saturn” D/S in a water depth of 2,079 m.       The outpost is located approximately 4.5 km east south-east of the Carcara West (3-EQNR-001-SPS) recently concluded in the block according to the provisional coordinates published by the ANP.     Current working interest breakdown in the contract is Equinor Brasil operator with 40% working interest, ExxonMobil with 40% working interest, and Petrogal Brasil Ltd (Galp Energia) with a 20% working interest. Equinor Brasil Energia Ltda has plans to drill up to five exploration wells in the Norte de Carcara_P2 contract, N_CARCARA block after filing its environmental permit in April 2018.  The Norte de Carcara structure is a northern continuation of the Carcara structure discovered by Petrobras and now operated by Equinor Brasil and partners in the BM-S-008 contract.  The wells to be drilled may all be considered outpost wells.  They will have proposed total depths of approximately 6,500 m to 7,000 m and will target the Barra Velha and Itapema formations of the pre-salt series in the Santos Basin.  The drilling is expected to commence in the block during early-2019.  The A prospect is located about 5.7 km north north-east of the 3-SPS-104A (3-BRSA-1216DA-SPS) outpost. On 31 January 2018, the consortium of Equinor Brasil Energia Ltda operator with 40% working interest, ExxonMobil with 40%, and Petrogal with 20% was granted an official award for the 312.92 sq km Norte de Carcara block from the 2nd PSC Pre-Salt Bid Round. The ANP changed the official denomination of the block to the Norte de Carcara_P2 contract, N_CARCARA block.  The consortium won the block with a profit oil state take bid of 67.12% and USD 911.85 million in total fixed bonus to be paid to the Brazilian government based on the USD to BRL exchange rate of the day of 1USD/3.29 BRL.  The PSC contract has a three year exploration-evaluation phase and the minimum work program is to drill one appraisal well. The minimum financial guaranty for the three year period is USD 47.95 million which is less than the estimated cost of drilling a pre-salt appraisal well.  There was a 2nd place bid for the block by Shell (100%) offering a state take bid of 50.46%.  The working interest breakdown for the block is the same as in the BM-S-008 contract that will be unitized with the Norte de Carcara block after Equinor acquired the 10% working interest from Barra Energia in June 2018.

Equinor Energy do Brasil Ltda was evaluating oil shows in the Carcara East (3-EQNR-003-SPS) outpost well in the N_CARCARA block, Norte de Carcara_P2 contract during late-April 2019 according to the ANP and this is assumed to indicate the operator may be conducting testing operations. The operator filed an oil show report with the ANP for the well on 27 March 2019. The outpost was spudded on 8 February 2019.

Geonadr is offering seven onshore blocks in the second licensing round which opened on 29 January 2019. Five blocks are available in the Dnieper-Donets Basin - Dobrenska, Kaliuzhna 1, North Efremivska, Opolonivska 1 and Opolonivska 2, plus Drohobytska and Kadobnianska in the North Carpathian Basin. The blocks are offered as 20 year exploration & production licences with commitments to reprocess vintage seismic in the first year (stage I), acquire new seismic over 25% of the block area in the second year (stage II), and drill before the end of the fourth year (stage III). Companies have 90 days to apply to participate in the online auction which will held on 29 April 2019 using the ProZorro online bidding system. The seven blocks (over 1,000 sq km) are part of larger total offering of 30 blocks, covering 4,630 sq km. The blocks will be auctioned in a series of competitive licensing rounds, the first 10 of which were tendered on 6 December 2018 as Round 1, with the auction scheduled for 6 March 2019. A further 13 onshore blocks are earmarked for release in Round 3 in the coming year. The auctioned licences are offered on tax and royalty terms and only available to Ukrainian-registered companies, although foreign investors can participate via a local subsidiary. International companies can directly bid in the PSA rounds or may be able to farm into existing licences which will then be converted to PSAs. Full details at http://www.goukrainenow.com/ and https://prozorro.sale/

Not Found

NE flank of Ballymore discovery in Mississippi Canyon block 607, OCS lease G34451, WD 2,012m, cleared for suspension on 1 Jan ’19, results n/a but possibly successful, Pacific Sharav DS. Chevron (op), partner Total.

NE flank of Ballymore discovery in Mississippi Canyon block 607, OCS lease G34451, WD 2,012m, cleared for suspension on 1 Jan ’19, results n/a but possibly successful, (60.0%, TOTAL 40.0%) in MC 607 block