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Shell confirms a significant discovery in Alaminos Canyon block 772, adjacent to Shell’s Silvertip field and ab. 16km from the Perdido platform, 427m oil-bearing pay encountered, one of the largest GoM finds in a decade. The find is assumed to pertain to AC 772 1S0B1 nfw, WD 2,681m, susp at TD ab. 7,000m in Jul ‘17, at the time reported as a discovery in need of “further evaluation”, target Paleogene. Appraisal drilling is underway (AC 728 2S0B0, Deepwater Pontus DS) to define devt options. Shell (op), partner Chevron. 

AC 772 001S0B1 (Whale) op. by Shell (60%, Chevron 40%) in G35153 OCS Lease, adjacent to Shell’s Silvertip field and ab. 16km from the Perdido platform, 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.

Calima has been awarded 4-year rights to block 2813B,  5,344 sq km west of the Kudu gasfield in the Orange Basin, expanding on the company’s position in the Comoros and Western Sahara. Commitments include 2D or 3D seismic + a prospectivity review. Calima Energy (op), partners Trago Energy (20%), Harmattan Energy (14%), Namcor (10%). The block was previously Grisham’s and recently expired.

Aker is reportedly talking over the acquisition / participation in the South Deepwater Tano (SDWT) block, 3,478 sq km adjacent south to its Deepwater Tano-Cape Three Points (DWT-CTP) unit, and currently held by AGM Petroleum. A potential collaboration, co-investments or different corporate transactions are envisaged. A potential deal would depend on results of drilling due to be carried out across both blocks in 2H ’18. It is recalled up to 2 wells are planned in the DWT-CTP block, in which Aker partners with Lukoil, FuelTrade + GNPC.

Total is looking to divest multiple North Sea producing assets including 20% from its 60% interest in the Laggan-Tormore area as well as producing assets acquired from the Maersk Oil takeover which completed on 8 March 2018. The Golden Eagle, Dumbarton, Bruce and Keith fields are also potentially available. Laggan and Tormore fields commenced production in February 2016 and the development has an estimated 132 MMboe recoverable reserves, and anticipated plateau production is 90,000 boe/d.

Total is looking to divest multiple North Sea producing assets including 20% from its 60% interest in the Laggan-Tormore area as well as producing assets acquired from the Maersk Oil takeover which completed on 8 March 2018. The Golden Eagle, Dumbarton, Bruce and Keith fields are also potentially available. Laggan and Tormore fields commenced production in February 2016 and the development has an estimated 132 MMboe recoverable reserves, and anticipated plateau production is 90,000 boe/d.

Block A (A2), Baram Delta, P&A results n/a late Feb ’19, Deepwater Nautilus DS. Target assumed L. Pliocene Cycle V turbidites. Shell (op), partner PetroleumBRUNEI.

Rapong 1 (Shell 100%) HPHT well, in Block A (11,4km SW of the Perdana oil and gas field) operations completed with results pending.

Bijoro field area, Khipro EL, Lower Indus onshore, compl. oil at TD 2,607m (Cret.) in mid-Apr ‘18, TCPDC-4002 rig. UE (op), partners Bow Energy Res. + Govt Holdings.

Bijoro field area, Khipro EL, Lower Indus onshore, compl. oil at TD 2,607m (Cret.) in mid-Apr ‘18, TCPDC-4002 rig. UE (op), partners Bow Energy Res. + Govt Holdings.

The New Zealand Petroleum & Minerals (NZP&M) have announced that the 2019 Block Offer consultation for proposed blocks commenced on 25 September 2019. The due date for submission is the 20 November 2019 with the final area for tender expected to be announced in the first half of 2020. The proposed area for the 2019 Block Offer includes one onshore region in the Taranaki, covering an initial area of 2,568 sq. km which has been released for consultation with iwi and hapu groups. The area was selected based on its prospectivity, available data, potential commercial interest and alignment with the amended legislation relating to the 2018 Crown Minerals (Petroleum) Amendment Act, which restricts the allocation of exploration permits exclusively to the onshore Taranaki region. The onshore acreage outlined for bidding in the 2019 Block Offer covers a similar sized area to the 2018 Block Offer, which was around 2,200 sq. km. This remains significantly smaller than previous years with over 480,000 sq. km offered in 2017, 476,000 sq. km of which was offshore.

The New Zealand Petroleum & Minerals (NZP&M) have announced that the 2019 Block Offer consultation for proposed blocks commenced on 25 September 2019. The due date for submission is the 20 November 2019 with the final area for tender expected to be announced in the first half of 2020. The proposed area for the 2019 Block Offer includes one onshore region in the Taranaki, covering an initial area of 2,568 sq. km which has been released for consultation with iwi and hapu groups.

BGM plugged and abandoned dry the 3-SDR-002-ES (3-BGM-002-ES) outpost in the ES-T-476 block in the onshore Espirito Santo Basin during late-August 2019. The operator filed no show reports for the well through October 2019. The outpost was spudded on 21 July 2019. The well had a proposed total depth (PTD) of 1,700 m with the Early Cretaceous Sao Mateus and Mariricu Formations as the primary target. The well is located in the south-central area of the block approximately 280 m south-east of the 1-SDR-001-ES (1-BGM-001-ES) wildcat suspended by the operator prior to spudding this outpost. BGM Petroleo e Gas Ltda holds 100% working interest in the ANP Round 14, ES-T-476 contract. BGM suspended with oil shows the 1-SDR-001-ES (1-BGM-001-ES) new-field wildcat (NFW) in the ES-T-476 block in the onshore Espirito Santo Basin during mid-July 2019. The operator filed an oil show report with the ANP for the well on 17 June 2019 and a second oil show report on 7 July 2019.The NFW was spudded on 21 May 2019.The NFW had a proposed total depth (PTD) of 1,605 m with the Early Cretaceous Sao Mateus and Mariricu Formations as the primary target.The well is located in the south-central area of the block approximately 1.2 km south-west of the 1-LB-0001-ES wildcat plugged by Petrobras in 1973. On 6 December 2018, the ANP approved of Bertek divesting its 100% working interest in the ES-T-345 and ES-T-476 blocks in the onshore Espirito Santo Basin to newcomer BGM Petroleo e Gas Ltda.On 29 January 2018, Bertek with 100% working interest was granted official awards by the ANP for the ES-T-345 and ES-T-476 blocks in the onshore Espirito Santo Basin from the ANP Round 14.The company paid a total signature bonus of USD 153,312.30 for the two blocks and has work commitments of USD 551,735.02.The blocks cover a total area of 46.14 sq km. The contract has one five-year exploration period and 7.5% royalties.The rentals for the blocks are USD 14.15/sq km/year.The local content is stipulated as 50% in the five-year exploration phase and in the development production phase is 50%.

BGM plugged and abandoned dry the 3-SDR-002-ES (3-BGM-002-ES) outpost in the ES-T-476 block in the onshore Espirito Santo Basin

It was unofficially reported in mid November 2018 that YPF is close to confirming a partnership with Norway's Equinor to bid for a large offshore block probably in the Colorado or Salado Basin through the Argentina Ronda I, Offshore Exp Plan 2018. The schedule of detailed terms and conditions for the round was established 6 November 2018 with the launch of the round which will last to 14 February 2019, the deadline for the presentation of company qualification and submission of offers.

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Inpex, through its JODCO Lower Zakum Ltd subsidiary, has been awarded a 10% interest in the offshore Lower Zakum concession, the agreement running 40 years effective 9 Mar ’18. Lower Zakum is one of 3 new concession areas carved out by Adnoc from the previous Adma-Opco concession in which Inpex was already involved. Inpex has also secured an additional 28% interest in the Umm Al Dalkh oilfield, as well as a 25-year extension of the Satah and Umm Al Dalkh concession, boosting its interest to 40% in both fields under Adnoc operatorship. Lower Zakum is the largest field in the current ADMA offshore concession, and targets 450,000 bo/d. Umm Al Dalkh and Satah target a combined 45,000 bo/d. Targets for the Upper Zakum field and the ADCO Onshore Concession in which Inpex is already involved are resp. 1 MMb/d and 1.8 MM b/d.

Inpex has won a 10% stake in the Lower Zakum concession.

Further to DEA 13 Jul '20, Beach's latest award has been identified as VIC/P7192(V), 49 sq km offshore in the Otway Basin, secured on 10 July for 6 years.

Australia, (Otway B.), Beach Energy Ltd was awarded offshore exploration license VIC/P7192(V). The permit has been granted for an initial period of six years and is scheduled to expire or be renewed on 9 July 2026.

Mubadala Petroleum has likely plugged and abandoned a new-field wildcat Nong Nuch-2, located offshore in the G11/48 concession, in the southern Pattani Trough, on 28 June 2019, as an oil and gas discovery. Spudded on 22 June 2019, the well was drilled to a total depth (TD) of 2,516 m using “Ensco 115” J/U, most likely targeting the Middle Miocene fluvial sandstone, which are also the producing reservoirs in the adjacent Bongkot and Nong Yao fields. Located 20 km away from the Nong Yao and Bongkot fields, Nung Nuch-2 was drilled back to back with the previous newfield wildcat, Nong Nuch-1. Nung Nuch-1 was targeting a shallower reservoir than Nung Nuch-2, and the well has its TD at 1,015 m. Nung Nuch-1 was plugged and abandoned as a dry well. Previously in June 2019, the operator completed an appraisal drilling campaign in the Nong Yao field, on 12 June 2019. Three wells were drilled within 22 days from the same surface location, resulting in mixed outcomes. Spudded on 22 May 2019, Nong Yao 9 and its first sidetrack well were likely plugged and abandoned after having encountered oil, most likely in the targeted Pattani Sequence III reservoir. Subsequently, Nong Yao 9ST2 well was kicked off on 7 June 2019 and abandoned as dry. Interest in G11/48 concession is divided between Mubadala Petroleum (Thailand) Limited (90%, operator) and Palang Sophon (10%). Mubadala increased its stakes in the concession from 67.5% to 90% in June 2018, after acquiring an additional 22.5% interest from previous partner KrisEnergy for a consideration of USD 13.3 million. Background Information The G11/48 concession consists of seven other fields such as Nong Yao (producing under improved recovery regime) Nong Yao C, Nong Yao SW, Angun-1 (appraising) Boondarik-1, Bua Luang-1 and Mantana-1 (discoveries). Pearl Oil (Thailand) Ltd and partners was officially awarded the G11/48 concession on 13 February 2007. The original G11/48 concession covers a surface area of 13,600 sq km. In January 2010, Kris Energy completed the sale and purchase agreement to buy over 25% working interest in block G11/48 from Tana Resources, a wholly owned subsidiary of Tana Exploration LLC. After the transaction completed, interest in G11/48 are divided between Pearl Oil (Thailand) Limited (75%, Operator) and Kris Energy (25%). Nong Yao was brought onstream on 17 June 2015, with initial production rate of 2,500 bo/d. The field reached its peak production of around 10,500 bo/d in Q2 2016, after drilling four infill wells. Currently, the field is producing from 20 wells under an improved recovery regime. The gross production from Nong Yao field averaged about 7,110 bo/d in 2019.

Thailand (Gulf of Thailand B.) ? op. by MUBADALA I (90.0%, PALANG SP 10.0%) in Nong Yao block

Nafta Industrija Srbije (NIS) formally completed the takeover of Jadran-Naftagas on 26 March 2020, after former 34% partner Zarubezhneft had signalled in 2017 that it would exit the joint venture. Jadran-Naftagas holds the Posavina & Semberija exploration licence which covers approximately 24,500 sq km in the Pannonian Basin, on the Republika Srpska autonomous region of Bosnia & Herzegovina. It was awarded on 26 September 2011 with an initial three-year exploration phase which has been extended until September 2023. It contains the Obudovac field discovered by Obudovac 2 (2015, 2,800m TD), which commenced production in 2019. The contract is the only licensed acreage in Bosnia & Herzegovina, however the Federation of Bosnia and Herzegovina (FBiH) is currently holding a round for four onshore blocks, open for bidding until 27 May 2020. NIS' wholly-owned subsidiary Jadran-Naftagas operates Posavina & Semberija with 100% equity.

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On 3 August 2019, the Ukrainian Government announced a tender for three blocks in the Dnieper-Donets Basin (Eastern Ukraine). Applications must be submitted within three months after the announcement. The winners of the tender will sign Production Sharing Agreements valid for 50 years. The Grunivska block covers 1,082 sq km in Sumy and Poltava oblasts and encompasses seven structures. Seventeen wells have been drilled in the block. Hydrocarbon resources of the area are estimated at 100 MMboe. Commitments during a five-year exploratory stage include acquisition of 3D seismic data and drilling of two wells with an investment of UAH 500 million (USD 20 million). The Ichnyanska block covers 2,086 sq km in Chernihiv Oblast. Seventy wells have been drilled in the block. Hydrocarbon resources of the area are estimated at 100 MMboe. Commitments during a five-year exploratory stage include acquisition of 500 sq km of 3D seismic data and drilling of three wells with an investment of UAH 900 million (USD 35 million). The Okhtyrska block covers 672 sq km in Sumy, Poltava and Kharkiv oblasts and encompasses six structures. No wells have been drilled in the block. Hydrocarbon resources of the area are estimated at 164 MMboe. Commitments during a five-year exploratory stage include acquisition of 3D seismic data and drilling of two wells with an investment of UAH 500 million (USD 20 million).

An auction is planned 30 Oct ’19 for 20-year rights to 5 contracts in E. Ukraine, application deadline 29 October. Commitments to include 2D + 3D seismic + drilling: - Vatazhkivska, 182 sq km in the Poltavska Oblast, Dnieper-Donets Basin, starting price USD 270,000

Add. DEA 6 Apr '20: Area I, South Natuna Sea block B Extn, ops terminated late Mar '20, gas discovery reported early April, 79 Bcf resources, Hakuryu-5 JU. Targets Arang + Gabus fm's. Medco (op), partner Prime Natuna Egy.

Bronang-2 nfw Area I, South Natuna Sea block B Extn, ops terminated late Mar '20, gas discovery reported early April, 79 Bcf resources, Hakuryu-5 JU. Targets Arang + Gabus fm's. Medco (op), partner Prime Natuna Egy.

Ref. DEA 21 Dec ’18, the ANH has reportedly approved Ecopetrol’s 10% farmin to the PSC governing the Saturno project, 1,100 sq km in the central Santos pre-salt and until then Shell-Chevron 50:50.  Shell and Chevron retain 45% each.

ANH has reportedly approved Ecopetrol’s 10% farmin to the PSC governing the Saturno project, 1,100 sq km in the central Santos pre-salt and until then Shell-Chevron 50:50. Shell and Chevron retain 45% each.

Further to DEA 8 Aug ’17, Chevron has reportedly decided to sell its 25% in the multi-block, 11,374-sq km, South Natuna Sea block B PSC (in purple below), to operator Medco. PT Bumi Hasta Mukti (BHM) was earlier reported to be the buyer. The deal would result in Medco being 100% block holder.

Chevron has reportedly decided to sell its 25% in the multi-block (1374km²) South Natuna Sea block B PSC, to operator Medco. PT Bumi Hasta Mukti (BHM) was earlier reported to be the buyer.

Crudos Pesados Oeste-5 (CPO-5), Llanos Basin, currently testing 5,130 bo/d on 46/64” choke unassisted, 0.19% water cut. Gross 2P reserves 22.7 MMbo. Mariposa-1 in the same block is flowing 3,150 bo/d on 28/64”, 0.4% water cut, field devt planning underway. Mean gross prospective resources 49.3 MMbo in the LS3 at Índico + Mariposa. ONGC Videsh (op), partner Amerisur.  The latter reports a 2019 work programme comprising 4 more wells at Índico, drilling up to 6 wells on Coendu structure (PUT 9 + 12) starting 3Q ’19 and spudding  Miraparriba-1 in PUT-8 in 1H ’19.

Crudos Pesados Oeste-5 (CPO-5), Llanos Basin, currently testing 5,130 bo/d on 46/64” choke unassisted, 0.19% water cut. Gross 2P reserves 22.7 MMbo. Mariposa-1 in the same block is flowing 3,150 bo/d on 28/64”, 0.4% water cut, field devt planning underway. Mean gross prospective resources 49.3 MMbo in the LS3 at Índico + Mariposa. ONGC Videsh (op), partner Amerisur. The latter reports a 2019 work programme comprising 4 more wells at Índico, drilling up to 6 wells on Coendu structure (PUT 9 + 12) starting 3Q ’19 and spudding Miraparriba-1 in PUT-8 in 1H ’19.

Occidental Petroleum (Occidental) suspended its second exploration well XN-66 pending further evaluation within the 5,782 sq km Onshore Block 3 concession during late April 2020. It spudded the well in mid-March 2020, shortly before it completed an extensive 3D seismic acquisition campaign in the block. Occidental initiated a survey to acquire 3D seismic over a targeted section of the acreage during October 2019. Its initial well in the block (XN-65) had been drilled 6.5 km to the north of XN with results unreported. Abu Dhabi National Oil Company (ADNOC) had announced the award of the block to Occidental on 2 February 2019 following the closure of the Abu Dhabi Licensing Block Bid 2018. The block contract is operated 100% by Occidental throughout an exploration period extending up to nine years. It required a US$ 244 million (Dhs 893 million) signature bonus and will be valid for 35 years if extended through to development stage, during which time ADNOC will back into the contract. Block 3 is contiguous to the Shah Sour Gas development project operated by ADNOC Sour Gas in which Occidental has a significant investment. SPC had indicated on 4 November 2018 that it expected the first exploration and production licenses relating to the Abu Dhabi Licensing Block Bid 2018 to be awarded during the first quarter of 2019. It subsequently approved the initial award of two offshore blocks to a consortium led by Eni SpA in January 2019. Occidental participated in a competitive bid round. UAE Minister of State and Chief Executive Officer of ADNOC Group H.E. Dr. Sultan Ahmed Al Jaber confirmed that “39 bidding parties from all over the world” had elected to actively join the bid round process, which closed during October 2018. ADNOC had launched its inaugural bid round in early April 2018 after delineating four onshore and two offshore blocks for commercially competitive bidding. Abu Dhabi remains underexplored and the blocks on offer encompass significant, multi-billion barrel yet-to-find potential. Some of the blocks offered during the inaugural bid round to be held in Abu Dhabi contain existing discoveries. ADNOC also estimated that there are 310 undrilled reservoirs located within 110 mapped prospects and leads. In addition to the country’s conventional potential, the offered blocks also contain significant unconventional resource potential. Successful bidders entered agreements that, providing defined targets are achieved in the exploration phase, would provide them with the opportunity to then develop and produce any discoveries with ADNOC, under terms set out in the bidding package.

XN-66 expl. (Oxy 100%), 2nd explo well in onshore block 3, S. of Asab in E. Rub' Al Khali Basin, susp. results n/a late Apr / early May '20. A 3D seismic survey was also completed Apr '20 in block 3, coverage n/a.

Canacol reports that its Jan-Jun ’18 drilling programme (notably the Pandereta-3, Chirimia-1 and Breva-1 discoveries in the Lower Magdalena Valley Basin) has added a significant amount of gas reserves - 25.3 Bcf proved, 58.7 Bcf 2P and 89.2 Bcf 3P. Additionally, an independent audit of the Esperanza, VIM-21, VIM-5, VIM-19, and SSJN7 exploration blocks placed their combined Gross Prospective Resources at 948 Bcf risked and 2.6 Tcf unrisked.

Canacol reports that its Jan-Jun ’18 drilling programme (notably the Pandereta-3, Chirimia-1 and Breva-1 discoveries in the Lower Magdalena Valley Basin) has added a significant amount of gas reserves - 25.3 Bcf proved, 58.7 Bcf 2P and 89.2 Bcf 3P. Additionally, an independent audit of the Esperanza, VIM-21, VIM-5, VIM-19, and SSJN7 exploration blocks placed their combined Gross Prospective Resources at 948 Bcf risked and 2.6 Tcf unrisked.

Kosmos is aiming to reduce its 2020 capital budget for the base business by around 30% whilst keeping 2020 production flat. This has led to plans to defer its share of the BP-operated 2020 Tortue Phase 1 capital spending and extend the carry of capital obligations through the end of this year. The company's priority remains to sell down interests to support a self-funded growing gas business. FID on Tortue Phases 2 + 3 are expected mid-2022 and mid-2023 resp.

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On 2 March 2020, the Georgian State Agency of Oil and Gas held a tender for onshore block XIh. Georgia Oil and Gas emerged as the winner of the auction. Block XIh is located south east of Tbilisi, in the Kura Basin and covers about 195 sq km. The block was previously held by Elenilto Georgia, after the company won a tender for Block XIh amongst others, held by the government in 2012. Elenilto's contract was cancelled in April 2019.

Georgia O&G was awarded onshore block XIh (195km²), located SE of Tbilisi.

1st well in PL 882 NW of Snorre, WD 331m, hc find between 3,250-3,400m, coring planned, sidetrack likely. PTMD 3,740m (3,647m TVD), targets Draupne + Brent, Deepsea Yantai SS. Neptune (op), partners Concedo, Idemitsu + Petrolia.

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

Pan Orient Energy reports that its L53AC-C1 deviated exploration well, located in onshore concession L53, was drilled to a depth of 1,453 meters true vertical depth (1,789 meters measured depth) and encountered two zones of interest based on oil shows observed while drilling and open hole wireline logs. Upon further investigation of these two zones of interest through acquired pressure data and fluid samples, the zones were determined to be dominantly water bearing. Preparations are currently underway to plug and abandon the well. The L53AC-C1 exploration will fulfill the $600,000USD minimum annual exploration expenditure that is required to retain all the remaining acreage of the original concession, outside of existing production licenses. The go forward Concession L53 activities will include a multi-well workover program that is expected to commence in late January 2018, and permitting/preparations for two additional exploration locations, one of which will be drilled in mid to late 2018.Location of Pan Orient's L53AC-C1 exploration well (Source: Pan Orient Energy) Original article link Source: Pan Orient Energy

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

Statoil Gulf of Mexico LLC has farmed down its 100% working interest in the Monument prospect, bringing in two non-operating partners, Anadarko US Offshore LLC and Venari Offshore LLC, to participate in this subsalt Paleogene play. The formation of this new partnership might indicate that Statoil is setting the stage to test this prospect. But as of early March 2018, the Bureau of Ocean Energy Management (BOEM) has not yet issued any drilling permits for the planned Monument wells that are situated in Walker Ridge block 271 (OCS G35080) and Walker Ridge block 272 (OCS lease G35081). On 1 September 2015, the BOEM approved the five-well, initial Exploration Plan (EP) submitted by Statoil for the prospect that lies in up to 6,700 ft (2,042 m) of water in the deepwater Central Gulf of Mexico. The prospect is in the northwest quadrant of the Walker Ridge (WR) protraction area some 200 miles (320 km) south-southwest of the onshore support base of Port Fourchon, Louisiana. Statoil’s USD 81.7 million bonus for the WR block 271 was the highest bid on a block at Sale 227, held in March 2013. Statoil’s EP (N-9886) outlines the company’s intention to install wellheads, drill, and temporally or permanently abandon three wells (Locations A, B and C) in WR block 271 and two wells (Locations A and B) in WR block 272. The operator plans to use the dynamically positioned drillship to conduct operations at the prospect and has allocated 175 days of rig time per well with each well designed to bottom within the block it spuds. The water depth at the proposed drill sites ranges from 6,067-6,764 ft (1,849-2,062 m). According to the EP, Statoil had tentatively planned to begin operations in December 2015 by drilling the WR 271 “A” surface location with the drillship positioned in 6,734 ft (2,053 m) of water in the SW/4 NW/4 NE/4 of WR block 271. The shallow hazard survey for the proposed WR 271 “A” well shows that this borehole does not encounter the allochthonous salt canopy within survey’s depth limit of investigation of 4,838 ft (1,475 m) below the mudline or 11,572 ft (3,527 m) below sea level. The Monument wells will target the Paleogene-aged Wilcox sand section as their primary objective with a proposed total depth of 34,122 ft (10,400 m). The prospect is proximal to other Paleogene exploration and appraisal activity including Marathon’s Solomon prospect five miles (8 km) to the northwest on WR block 225 and Chevron’s Lewis prospect immediately south of Monument. The Lewis and Solomon wells both tested the Wilcox section and were permanently abandoned as dry holes. About 15 miles (24 km) north of Monument lies Anadarko’s Shenandoah prospect, an appraised Wilcox oil find discovered in February 2009.  Shenandoah has a gross recoverable resource range estimated from 165 to 300 MMboe. The status of the Shenandoah project is now in doubt after the operator Anadarko and ConocoPhillips withdrew from the project in February 2018.  As of January 2018, Statoil owns a 41.67% working interest in the G35080 (WR-271) and G35081 (WR-272) leases and operates the acreage for participating partners Anadarko US Offshore LLC with a 41.66% stake and Venari Offshore LLC with the remaining 16.67% share. The government originally awarded these block to Statoil (66.67%) and Samson Offshore LLC (33.33%) at Central Gulf Sale 227, held on 20 March 2013. The partnership tendered the highest bid on a block for Sale 227, submitting a bonus USD 81,787,999 to win WR block 271. This signature bonus topped a USD 17.5 million offer made on the same block by Shell Offshore. Statoil and Samson outbid Anadarko to take WR block 272 with a bonus of USD 10,111,999 vs. Anadarko’s USD 3.2 million tender offer. Standard-sized 5,760-acre (23.31 sq km) deepwater tracts, the subject leases have 10-year primary terms that started on 1 August 2013 and are scheduled to expire on 31 July 2023. In November 2017, Statoil became the sole owner of both leases when Samson sold its stake to Statoil. Statoil farmed out a 41.66% working interest in both leases to Anadarko and a 16.67% working interest to Venari thereby creating the partnership that now (March 2018) exists for the Monument prospect. This transaction took effect on 2 November 2017.

Statoil (->41,67%) has farmed down its 100% working interest in the Monument prospect (OCS G35080 and G35081), bringing in 2 non-operating partners, Anadarko (41,66%) and Venari Offshore (16,67%), to participate in this subsalt Paleogene play.

Shakra devt lease, Abu Gharadiq Basin, drilled 23 Jan – late Feb ’18, compl. oil after testing 857 b/d of oil/mud, TD ca. 2,000m, EDC rig 65.

Shakra S.1 op. by in Shakra devt lease, compl. oil after testing 857 b/d of oil/mud.

In July 2019, sources indicated that Lukoil had replaced GazProm as operator of the Nanga II permit, onshore Coastal Basin in partnership with the national company, SNPC. The contract includes Nanga IIA and Nanga IIB blocks. The change is understood to have occurred sometime in May or June 2019. Lukoil operates the permit with an 85% interest, Societe Nationale des Petroles du Congo (SNPC) holds the remaining 15% stake. The reservoirs expected in the area are the Vendji, Mengo, Djeno and Chela formations and the source rock in the area is the Sialivakou shales (known as the Bucomazi in DRC and Angola). Background information SOCO was awarded a one-year exploration licence for the Nanga II A block in October 2013. The deal has included the evaluation of aeromagnetic data and reprocessing several existing 2D seismic lines before deciding about a 3D seismic survey on the area. Following the completion of the interpretation of the reprocessed seismic data, the company relinquished the exploitation licence, which expired in October 2014. In late 2017, it is understood that Gazprom was awarded the Nanga II exploration licence in partnership with SNPC. GazProm was also involved in discussions with SNPC to secure financing the pipeline project from Pointe Noire to Brazzaville. The pipeline would carry refined products from the Congolaise de Raffinage (CORAF) refinery in Pointe-Noire to Brazzaville.

Gazprom replaced by Lukoil as operator in the Nanga II permit (blocks Nanga IIA and Nanga IIB)

NE part of SO Tartaruga Vd_P5 contract, SO_TRTG_VD block, Deepwater Campos Basin, WD 1,080m, oil shows in the target L. Cretaceous post-salt Quissama fm, shows report to ANP early Apr '20. PTD is/was 3,326m, Gold Star SS. Release and map here.

1-RJS-753 (1-BRSA-1375-RJS / Natator / Michelangelo) nfw. (Petrobras 100%), NE part of SO Tartaruga Vd_P5 contract, SO_TRTG_VD block, , WD=1 080m, oil shows in the target L. Cretaceous post-salt Quissama Fm, shows report to ANP early Apr '20. PTD is/was 3326m.

On 9 January 2020, the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) issued a Call for Nominations of Areas of Interest NL20-CFN01 located in eastern Newfoundland offshore region. A map showing the available areas are located at the C-NLOPB website www.cnlopb.ca in the Land Issuance section. The Call for Nominations closes at 04:00 P.M. Newfoundland Standard Time, 11 March 2020. According to the release, "The Board will consider any Nomination of an Area of Interest received in this Eastern Newfoundland Region and decide what Sector will be posted for further exploration. A Call for Nominations (Parcels) will be made in respect of Sector lands in accordance with the 2–year cycle model of Scheduled Land Tenure System for the Canada-Newfoundland and Labrador Offshore Area". All nominations submitted in response to the "Call for Nominations No. NL20-CFN01 (Areas of Interest)" can be submitted in paper or electronic format, by mail or email, and clearly marked as follows: Nomination submissions or comments regarding the Call for Nominations are acceptable in paper or electronic format. All submissions should be clearly labeled and submitted by the above-noted deadline. Email submissions can be sent to [email protected]. Mail: Canada-Newfoundland and Labrador Offshore Petroleum Board Suite 101, TD Place 140 Water Street St. John's, NL A1C 6H6 Attention: The Chair Email: [email protected]

On 9 January 2020, the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) issued a Call for Nominations of Areas of Interest NL20-CFN01 located in eastern Newfoundland offshore region. A map showing the available areas are located at the C-NLOPB website www.cnlopb.ca in the Land Issuance section. The Call for Nominations closes at 04:00 P.M. Newfoundland Standard Time, 11 March 2020.

Only 2 months after jointly acquiring Schlumberger's 49% in the Bandurria Sur block, Equinor + Shell have now taken on a further 5.5% each from YPF in the Vaca Muerta play, Neuquén Basin. Equinor and Shell now hold 30% each, balance YPF. Map below courtesy Equinor.

Argentina, Bandurria Sur

SSI has been cleared to transfer an 8.28% interest in devt areas of block 18 to Sonangol P&P. This includes the Plutonio, Galio, Paladio, Cromio + Cobalto finds, aka the Greater Plutonio project operated by BP. Partners BP and SSI agreed to that Sonangol P&P would gain its interest as part of an extension of the rights to 2032.

SSI has been cleared to transfer an 8.28% interest in devt areas of block 18 to Sonangol P&P. This includes the Plutonio, Galio, Paladio, Cromio + Cobalto finds, aka the Greater Plutonio project operated by BP.

Premier reports its Sea Lion field project is suspended with farm-in documentation however agreed with Navitas Petroleum. The latter is to acquire a 30% interest in the Sea Lion project in the North Falklands Basin, partnership to become Premier (op) 40%, Rockhopper + Navitas 30% ea. When work resumes, a new drill-centre is planned in the field, 29 wells in phase 1 devt (20 producers, 8 water injectors + 1 gas injector). Plateau production is expected at 85,000 b/d using an FPSO and tapping 250 MMbbl. The Ocean Endeavor SS has an LoI for this project.

Premier reports its Sea Lion field project is suspended with farm-in documentation however agreed with Navitas Petroleum. The latter is to acquire a 30% interest in the Sea Lion project in the North Falklands Basin, partnership to become Premier (op) 40%, Rockhopper + Navitas 30% ea.

West Gharib Block H, onshore Gulf of Suez, TD 1,609m, 46m net heavy oil pay across the Yusr + Bakr sands, 18% avg porosity. Well to be completed as a producer and connected to the Meseda facilities. Rig to Rabul-4 appr.

Rabul-5 expl/appr West Gharib Block H, onshore Gulf of Suez, TD 1,609m, 46m net heavy oil pay across the Yusr + Bakr sands, 18% avg porosity.

On 10 February 2020, PetroGulf disclosed additional information regarding its successful GNN 3 exploration well, located on the offshore Geisum development lease (DL). The well is understood to have encountered hydrocarbons in a ~150m gross interval within the Nukhul Miocene sandstone objective. This is the first time hydrocarbons have been encountered in the Nukhul Formation on the licence. The ADES Group "Admarine VIII" jack-up carried out operations in a WD of ~17m, located NW of the Geisum Field. The well forms part of a two-well campaign, which had initially been slated for H2 2017. The DL forms part of the Geisum & Tawila West PSC, located in the southern Gulf of Suez. The Geisum oil & gas field, discovered in the Miocene Shagar sandstones in 1980. The concession agreement comprises of two blocks and four fields, on which some 87 wells have been drilled. The PetroGulf consortium comprises of Cheiron (formerly PICO, 30%), KPC (through its subsidiary KUFPEC, 20%) and Ganope (50%, carried).<P />

PetroGulf disclosed additional information regarding its successful GNN 3 exploration well, located on the offshore Geisum development lease (DL). The well is understood to have encountered hydrocarbons in a ~150m gross interval within the Nukhul Miocene sandstone objective.

Further to DEA 30 Jan ’18, Block 10, Bhola Island on/offshore Bengal Basin, N. of Shahbazpur onshore field, gas encountered in 2nd zone, between 3,262 and 3,272m, with good flows during tests. PTD 3,550m, 3-month well underway since 9 Dec ’17. Test details from GEPS. Gazprom (well op), Bapex (block op).

Bangladesh (Bengal B.) Shahbazpur 6 op. by PETROBANGL (100.0%) in Block 10 Block 10, Bhola Island on/offshore Bengal Basin, N. of Shahbazpur onshore field, gas encountered in 2nd zone, between 3,262 and 3,272m, with good flows during tests. PTD 3,550m,

Highlights Oil flowed to surface from Kimmeridge Limestone 5 ('KL5') throughout 96 hours of near-continuous rod-pumping. Fluid returns, measured as half-hourly instantaneous pumped rates, currently range from around 10 to 72 barrels per day ('bpd'). Fluids flowed to surface consist of oil mixed with returned reactants ('spent acid') from an acid-wash programme. Associated average oil percentages ('oil-cut') exceed 30% with intermittent periods exceeding 50% by volume and continue to increase. To date, no obvious formation water has been observed in returns. 24-hour pumping operations will continue to enable flow to stabilise, return all spent acid and achieve 100% oil ('clean-up'). AIM-listed UK Oil & Gas Investments (UKOG) has announced that oil has flowed to surface from the naturally fractured KL5 reservoir at its 100% owned BB-1/1z exploration discovery, located in licence PEDL234. Fluid returns to surface, measured as half-hourly instantaneous pumped flow-rates over a 96-hour near-continuous period, ranged between 10 to 72 barrels per day ('bpd'). To date, fluid returns through the test equipment consist of a mixture of oil plus returned spent-acid from an acid wash treatment, with no observed obvious formation water component. Associated oil-cut steadily increased to over 30%, with intermittent periods exceeding 50% by volume. Flow continues to clean-up with an improving oil-cut trend. The artificial lift programme, which commenced last Friday, included several initial half-hour shut-downs to bleed off produced associated gas before it locked-up the pump. One short pressure build-up test was also undertaken. As the KL5 zone's steel casing was not perforated during the original 2017 well completion programme, two new casing-perforation runs were undertaken prior to testing. The current test, number 7, the first ever within the KL5 in the Weald's 100-year exploration history, straddles a discrete naturally fractured limestone interval close to the top of KL4, which corresponds to the previously reported occurrence of live oil in open natural fractures seen in BB-1 core. General Testing Update and Future Plans The KL5 24-hour rod-pumping programme is planned to continue until further notice to enable flow to stabilise and further clean-up with the aim of achieving 100% oil to surface. Prior to the KL5 test, oil and associated gas were recovered to surface from tests 5 and 6 within the uppermost KL3 and KL4, but with no sustained flow. Due to the limited time remaining on the planning consent, the decision was made to spend no further time on these zones and proceed ahead to the KL5 zone which, as reported in December, was known from core and geochemical analyses to contain oil in fractures and within the limestone rock matrix. In the light of results and analyses from tests 5 and 6, together with learnings from test 7 in KL5, the Company and its consultants are currently investigating the possibility that zones 5 and 6, originally perforated in summer 2017 and acidised during the original test programme, were damaged by a combination of the long residence times of spent acid within the reservoir prior to current testing and the perforating technique utilised. It is now thought that both fractures and perforated channels around the wellbore of KL3 and KL4 could be partially blocked by released clay particles and cement related debris, thus preventing sustainable fluid inflow. In this respect, serious consideration is being given to a possible future short sidetrack and selective re-test of KL3 and KL4 which electric logs show as oil-saturated. Existing planning consent time permitting, following completion of KL5 testing, the plan remains to test a 40 ft thick limestone zone in KL1 which, as per KL5, was not perforated or acid-washed in 2017. About BB-1/1z As previously reported, BB-1 was purposely drilled in a location where no conventional hydrocarbon trapping mechanism within the Kimmeridge reservoir section is evident. Therefore, in the Company's opinion, the now proven flow to surface of moveable, light Kimmeridge oil and associated solution gas at the BB-1z sidetrack, provides further proof that the Kimmeridge at Broadford Bridge contains a continuous oil deposit of up to 1400 ft gross vertical thickness. The near identical Kimmeridge reservoir parameters and geology seen at BB-1/1z and the Horse Hill-1 Kimmeridge oil discovery, in which the Company holds a 32.435% interest, some 27 km to the northeast, demonstrates that the Kimmeridge oil accumulation is also laterally extensive across the Central Weald Basin and, consequently, a potentially significant national oil resource. As previously reported in December, the integration of BB-1z petrophysical analyses with Geomark Research's in-depth geochemical analyses, strongly suggests that Broadford Bridge lies within the southern flank of the Kimmeridge continuous oil deposit, with the commercially viable extent of the play, determined by the presence of significant volumes of in-situ generated mobile oil within Kimmeridge shales and fractured limestones, terminating some few kilometres to the south of PEDL234. UKOG, as the largest licence holder in the Kimmeridge oil accumulation's 'sweet-spot' is well positioned to exploit this extensive and likely commercially viable oil resource.   Stephen Sanderson, UKOG's Executive Chairman, commented: 'These positive and encouraging initial oil flows from the first-ever Kimmeridge Limestone 5 test provide further supporting evidence for the presence and significant spatial extent of a viable Kimmeridge continuous oil deposit within the PEDL234 Licence. The KL5 test results, plus the many strands of technical evidence gathered from the well, now also indicate that the BB-1 location lies towards the southern edge of a thick, naturally-fractured, oil-saturated Kimmeridge "wedge", stretching around 30 kms to the north of BB-1 across the Weald. UKOG, as the largest licence holder in the thickest part of this "wedge", is therefore ideally placed to exploit the potentially commercially viable recoverable resources that now likely underlie our Licences. We look forward to further positive news from the ongoing KL5 test programme.' Original article link Source: UKOG

United Kingdom, not found

Nurzhanov field area, Precaspian Basin, mid-May tested 1,074 b/d of 37.8 API oil on 9mm choke from the Triassic between 3,252-3,265m, GOR 572 cf/bbl, ops continue.

Kazakhstan (Southern Precaspian Sub-basin (Precaspian B.)) NSV-11 npw Nurzhanov tested 1,074 b/d of 37.8 API oil on 9mm choke from the Triassic between 3,252-3,265m, GOR 572 cf/bbl, ops continue.

Further to 9 Jul 19, an auction will take place on 30 Aug ’19 for the Soletsko-Khanaveyskoye block area on the S. Gydan Peninsula, W. Siberia, starting price USD 38 million. The winner will obtain a 27-year licence. Novatek is already heavily involved in this area through Arctic LNG, inter alia. Background and contact information from GEPS.

Further to 9 Jul 19, an auction will take place on 30 Aug ’19 for the Soletsko-Khanaveyskoye block area on the S. Gydan Peninsula, W. Siberia, starting price USD 38 million. The winner will obtain a 27-year licence. Novatek is already heavily involved in this area through Arctic LNG, inter alia.

Bridge Petroleum 5 Ltd has acquired Burgate E&P Ltd, Comtrack (UK) Ltd and Simwell Resources Ltd’s interest in block 113/27d (P2076), which contains the Castletown gas discovery. Prior to the deal with Bridge Petroleum, the three partners were seeking to farm-out Castletown to raise funds to drill an appraisal well. Well 113/27-2 was drilled in 1988 by ESSO which discovered Castletown however the gas accumulation in the Triassic sandstones was considered too small to develop. A new evaluation, using depth migrated 3D seismic data, indicated that the well was drilled down flank and through a major fault causing a large gas accumulation remains to be proven up-dip. The Mercia Mudstone Group provides a regional seal which attains a thickness of 1,000 m across the basin. Gas charge comes from the Carboniferous Coal Measures which underlie much of the basin. Following completion of the deal interest and operatorship of P2076 is held solely by Bridge Petroleum 5.

United Kingdom, P2076

As announced on 12 February 2018, Sound Energy via it local subsidiary Sound Energy Morocco South Ltd, was granted a new eight year Sidi Moktar Petroleum Agreement (Agreement) covering Sidi Moktar by the Office National des Hydrocarbures et des Mines (ONHYM). The Agreement covers a large area across and beyond the permits formally known as Sidi Moktar Nord, Sud and Quest Permits. The new Agreement encompasses 4,499 sq km within the Essaouira Basin and will be named Sidi Moktar Onshore and is subject to approval from the Moroccan Energy and Finance Ministries. It includes three sub-areas (Sidi Moktar I, Sidi Moktar II and Sidi Moktar III). Upon the receiving approval from authorities, Sound Energy via it local subsidiary Sound Energy Morocco South Ltd will hold a 75% stake as operators and ONHYM will hold the remaining 25% interest. The eight year award will divided into three phases each with pre-agreed work commitments.

Sound Energy via it local subsidiary Sound Energy Morocco South Ltd, was granted a new eight year Sidi Moktar Petroleum Agreement (Agreement) covering Sidi Moktar by the Office National des Hydrocarbures et des Mines (ONHYM).

OGDC and Kufpec signed on 4 Jun ’18 an MoU designed to lead to cooperation in the upstream sector, within Pakistan and abroad, the Middle East quoted. OGDC has agreed to facilitate its operated blocks at home for Kufpec.

OGDC and Kufpec signed on 4 Jun ’18 an MoU designed to lead to cooperation in the upstream sector, within Pakistan and abroad, the Middle East quoted. OGDC has agreed to facilitate its operated blocks at home for Kufpec.

As of 10 January 2019, ExxonMobil Canada has acquired Suncor’s 35% working interest in offshore exploration license EL 1134 located in the Flemish Pass Basin giving the company a 100% working interest in the block. The 2,088.99 sq km block was awarded on 15 January 2013 from the NL12-02 Call for Bids held in 2011 for a work commitment bid of CAD 19,875,875. There were no details of the transfer of interest available. In February 2018, ExxonMobil Canada announced it had acquired Husky Oil Operations Ltd 65% working interest and operatorship of offshore exploration license EL 1134 located in the Flemish Pass Basin. There have been no wells drilled in the block under the current contract however a 3D seismic program was acquired over a majority of the contract in 2016. The block originally had a partnership of Husky Oil (operator) 40%, Suncor 35%, and Repsol 25% however Repsol released their interest to Husky which left a working interest breakdown of Husky 65% and Suncor 35%. After the transaction, the block partnership is now ExxonMobil Canada 65% and Suncor 35%. ExxonMobil Canada now is the sole owner of rights to the block.

ExxonMobil (->100%) has acquired Suncor’s 35% working interest in offshore exploration license EL 1134 (2089km²).

On 30 October 2019, the State Agency for Geology and Subsoil Use of Ukraine held an auction for two licenses in the eastern Ukraine. Local Nadra Karbon and a subsidiary of Nafta a.s. (Slovakia) emerged as the winners of the contest. The companies will obtain 20-year E&P licenses. The Vatazhkivska block covers 181.8 sq km in Poltavska Oblast (Dnieper-Donets Basin). Seismic coverage amounts to 533 km. One well has been drilled in the block. Gas resources of the Vatazhkivska prospect are estimated at 106 Bcf. Commitments include acquisition of 2D and 3D seismic data and drilling of two wells with PTDs of 5,700 m and 6,300 m. The starting price amounted to UAH 6.794 million (USD 0.27 million). Nafta PV offered UAH 6.846 million (USD 0.27 million). The Zakhidnotokarsko-Krasnyanska block covers 91.1 sq km in Luhanska Oblast (Dnieper-Donets Basin). Seismic coverage amounts to 476 km. Three wells have been drilled in the block. Gas resources of the block are estimated at 31 Bcf. Commitments include acquisition of 2D and 3D seismic data and drilling of one well. The starting price amounted to UAH 1.534 million (USD 0.06 million). Nadra Karbon offered UAH 1.651 million (USD 0.06 million).

Nadra Karbon won block covers 181.8 sq km in Poltavska Oblast (Dnieper-Donets Basin). Nafta PV won Zakhidnotokarsko-Krasnyanska block covers 91.1 sq km in Luhanska Oblast (Dnieper-Donets Basin).

Geisum + Tawila fields concession, offshore Gulf of Suez, WD 20m, ops terminated of late, results encouraging. Target Miocene sst. Appr/devt GNN-4 has spudded and is underway. The 104-sq km Geisum & Tawila West lease has been renewed for another 5 yers to Jun '27 with commitments to 2 wells. Petro Gulf Misr Co = Pico, Kufpec, EGPC JV.

Egypt (Gulf of Suez B.) Geisum NN-3 op. by PICO CHEIR (60%), KPC (40%), EGPC (0%) in Geisum Field block, WD = 43 m, ps terminated of late, results encouraging. Target Miocene sst.

Xinzhao West sub-unit in Hangjinqi block near Dongshemg gasfield, Ordos Basin, TD 4,278m in May, tested 1 MMcfg/d from the Shan 2 fm in late Jun ‘19.

Xinzhao West sub-unit in Hangjinqi block near Dongshemg gasfield, Ordos Basin, TD 4,278m in May, tested 1 MMcfg/d from the Shan 2 fm

Hokchi suspended as an oil discovery the Tolteca 1EXP directional new-field wildcat (NFW) in the CNH-R03-L01-AS-CS-15/2018 contract in the offshore Sureste Basin during early-November 2019 according to partner Talos. Partner Talos reported on 6 November 2019 that the Tolteca 1EXP had 37 m of gross pay with 36 m of net pay in the Lower Pliocene and the deeper of two sands logged in the Xaxamani 2EXP. The oil-water contact was not penetrated, and the areal extent is estimated to be larger than previously interpreted. The NFW was spudded on 4 September 2019. The NFW had a proposed total depth (PTD) of 2,600 m measured depth (MD) and 1,843 m true vertical depth (TVD). The Tolteca prospect had two primary, wildcat objectives in the Lower Miocene, but will also traverse the Lower Pliocene productive in the Xaxamani discovery, and so this is a secondary new-pool objective in this separate fault block. The Tolteca 1EXP prospect is located 2.8 km north-west of the Xaxamani 2EXP new-pool wildcat (NPW) drilled prior to this spud. The unrisked prospective resources are 32.3 MMboe and the risked prospective resources are reported to be 4.85 MMboe. On 8 August 2019, the CNH approved the drilling permit request submitted by operator Hokchi for the Tolteca 1EXP directional new-field wildcat (NFW) Hokchi is operator of the contract with 75% working interest and lone partner Talos with 25%. On 12 July 2019, the CNH approved a modification to the exploration plan submitted by operator Hokchi on 31 May 2019 for the CNH-R03-L01-AS-CS-15/2018 contract in the offshore Sureste Basin.

Mexico (Comalcalco Sub-basin (Sureste B.)) Hokchi

N. sector of KG-DWN-98/2, deepwater KG Basin, WD 630m, TD 3,225m in Feb '20, tested gas + water, rates n/a, Louisiana SS. Original hole drilled 14-21 Jul '19 to 1,376m (Platinum Explorer DS), re-entered Jan '20.

CHN BAA nfw (ONGC 100%) in N. sector of KG-DWN-98/2, deepwater block, WD 630m, TD=3225m in Feb '20, tested gas + water, rates n/a.

Total has sold its remaining 15% interest in Gina Krog to partner KUFPEC for USD 317 million following an announcement from KUFPEC on 30 August 2017. The acquisition, which was reported by the NPD as complete on 5 December 2017 (effective from 30 November 2017), gives KUFPEC a further 34 MMboe and 9,000 boe/d (it already held 15% from a previous deal with Total in 2016). Gina Krog came onstream in June 2017 and a new exploration well will be drilled in late 2017. The deal also includes the transfer of Total’s 15% interest in PL 813 which lies to the north of Gina Krog. Gina Krog, which is covered by PL 029 B, PL 029 C, PL 048 and PL 303, was developed using a fixed platform with 20 slots (for 11 producers and three injectors). Gas is piped to Sleipner East and oil is initially (until 30 September) being directly offshore loaded onto shuttle tankers through a flexible flowline and riser prior to the FSO being installed later in 2017. The platform will, in time, be powered from shore using the Utsira High area power solution (due in 2022). Investments totalled NOK 31 billion (USD 3.7 billion) and field life is expected to be 20 years. Operator Statoil will drill the new exploration well (15/6-14 S) as a sidetrack from development well 15/6-B2 in late December 2017. According to partner Aker BP, the well is targeting potential reserves of 8-21 MMboe and the prospect is named Central 3. Upon completion of the deal, both Gina Krog unitised field interests and interests in PL 813 are as follows: Statoil Petroleum ASA (58.7% + operator), KUFPEC Norway AS (30%), PGNiG Upstream Norway AS (8%) and Aker BP ASA (3.3%).    

Norway (South Viking Graben (Viking Graben Province)) Gina Krog

VMM-11, Middle Magdalena, P+A 27 Oct ’17, rig to Iguazu-1 nfw. PTD was TD 2,700m.

Niagara 1 op. by Parex (100%) in VMM 11 block, P&A results n/a.

In late April 2019, Rosneft transferred two long-term licenses in Yakutia (Sakha) Republic (Eastern Siberia) to its joint venture with BP. Yermak Neftegaz (Rosneft 51% and BP with 49%) will operate the Sredne-Lenskiy and Olekminskiy blocks via its subsidiary Srednelenskoye. It marks the expansion of Yermak’s E&P activities outside its current presence in the Yenisey-Khatanga Basin and the Nadym-Taz Province (Western Siberia). Rosneft won the licenses at an auction on 1 December 2015. The Olekminskiy block covers 6,121 sq km in the Predpatom Basin. Seismic coverage amounts to 145 km. No wells have been drilled in the area. Hydrocarbon resources (category D2) of the block are estimated at 90 MMbbl of oil and 1,360 Bcf of gas. Exploration of the block must be completed within seven years. The starting price amounted to RUB 12 million (USD 0.18 million). Rosneft offered RUB 700.8 million (USD 10.8 million). The Sredne-Lenskiy block covers 9,834 sq km in the Predpatom Basin. Seismic coverage amounts to 722 km. Three wells have been drilled in the area. Hydrocarbon resources (categories D1+D2) of the block are estimated at 42 MMbbl of oil and 483 Bcf of gas. Exploration of the block must be completed within seven years. The starting price amounted to RUB 5.4 million (USD 0.08 million). Rosneft offered RUB 302.94 million (USD 4.7 million). On 9 January 2019, Interfax reported that Yermak Neftegaz registered its first subsidiary in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). The Rosneft/BP joint venture became the sole owner of Zapadno-Nikolskoye at the end of December 2018, according to Interfax. Since 2015, Zapadno-Nikolskoye has not been owning any licenses in Russia but still existing as a legal entity. In late January 2019, Zapadno-Nikolskoye was re-named to Srednelenskoye. Rosneft inherited Zapadno-Nikolskoye as the result of the TNK-BP acquisition in 2013.

Rosneft transferred 2 licences in Yakutia (Sakha) Republic, to its existing 51:49 JV with BP YermakNeftegaz, so far only present in W. Siberia. Involved are the Sredne-Lenskiy (9834km²) + Olekminskiy (6121km² undrilled) block, both in the Predpatom B.

Santos Ltd was awarded production licence PL 1054, located in the Cooper-Eromanga Basin, on 16 October 2019. The licence has been awarded for a period of ten years and will expire, or be eligible for renewal, on 15 October 2029. The licence was applied for in September 2018. It contains the Tartulla gas, condensate and oil field, which was discovered in 1981 and has been producing since 2005. PL 1054, which covers an area of 73 sq km, was awarded on 16 October 2019. Participants in the permit are Santos Ltd (52% + Operator), Santos subsidiaries Vamgas Pty Ltd (7.2%) and Santos Australia Hydrocarbons Pty Ltd (2%) and Beach Energy subsidiaries Delhi Petroleum Pty Ltd (28.8%) and Lattice Energy Pty Ltd (10%).

Australia, PL(A) 1054

Woodside Petroleum Ltd reported that it had signed a sales and purchase agreement (SPA) with ExxonMobil subsidiary Esso Australia Resources for the acquisition of interest in the Scarborough asset WA-01-R, located in the Investigator Sub-basin, North Carnarvon Basin, on 14 February 2018.  Under the terms of the SPA, Woodside would acquire Esso’s 50% interest in the permit and Scarborough field for an initial payment of USD 444 million, followed by a secondary contingent payment of USD 300 million upon the Scarborough project reaching Final Investment Decision (FID). The acquisition of Esso’s 50% interest would increase Woodside’s interest in the asset to 75%, after it first acquired 25% interest in November 2016 from joint venture partner BHP Billiton.  At this time, Woodside also acquired 50% interest in WA-61-R, WA-62-R and WA-63-R, which contain an additional part of the Scarborough field and the Jupiter and Thebe discoveries.  The latter discoveries are outlined for tie-in to the Scarborough project. The SPA remains subject to relevant approvals, and also to BHP not exercising its pre-emptive rights to the asset.  BHP holds a 25% interest in Scarborough currently, after selling half its interest to Woodside previously, and also 50% in WA-61-R, WA-62-R and WA-63-R as sole partner to Woodside.  It is hoped that the SPA with Esso will be complete by end Q1 2018. Woodside reported that acquisition of the additional Scarborough interest and operatorship would result in “greater alignment, control and certainty for the project”.  The aim would be to tie Scarborough back to the Pluto LNG facilities as part of the expansion of the project and to fill the expected market gap for LNG supply in the 2020’s.  If Woodside’s proposal goes ahead, Scarborough would be scheduled to reach FID by 2020, with start-up in around 2025. As part of the Pluto expansion, Woodside also has plans for a “Burrup Hub concept” which would see additional expansion and synergies of both its Pluto and NWS LNG facilities.  Outlined in the plans is a Pluto-NWS interconnector pipeline, which would further utilise the existing facilities and use to produce additional gas fields – including Scarborough and also the Browse project fields.  Front End Engineering and Design (FEED) for the interconnection is planned for 2018.  

Woodside has acquired Exxon’s 50% interest in WA-01-R which contains the majority of the Scarborough gas field for US$774 MM. Following the completion of the deal, Woodside will hold a 75% interest in WA-1-R and a 50% interest in WA-61-R, WA-62-R and WA-63-R .

QP is reportedly to take over from Oxy as optr of the El-Shargi North Dome field off Doha upon expiry of the latter’s D&PSA agreement expires on 6 Oct ‘19. Oxy’s  D&PSA for El-Shargi South Dome expires in Dec ‘22.

QP is reportedly to take over from Oxy as optr of the El-Shargi North Dome field off Doha upon expiry of the latter’s D&PSA agreement expires on 6 Oct ‘19. Oxy’s D&PSA for El-Shargi South Dome expires in Dec ‘22.

On 14 May 2018 Key Petroleum Ltd and Rey Resources Ltd reported that they had signed a sale and purchase agreement, which will see the companies acquire certain subsidiaries to complete an interest swap in permits EP 104, R1 and L15, located in the Canning Basin, and EP 437, located in the Perth Basin.  The deal remains subject to relevant authority approvals. Under the terms of the agreement, Rey Resources is to acquire all the shares in Key’s wholly owned subsidiary Gulliver Productions Pty Ltd. Rey Resources also reported that it had agreed to acquire Indigo Oil Pty Ltd’s share in the permits. This will give it 100% interest in the Canning Basin licences, which are referred to by the company as the “Lennard Shelf blocks”. As part of the deal in the Canning licences, Key Petroleum will receive a royalty of 2.5% and Indigo a 0.5% royalty in L15 and R1. Key Petroleum will also acquire all the shares in Rey Resources’ wholly owned subsidiary Rey Oil Gas Perth Pty Ltd, which holds a 43.47% interest in exploration permit EP 437.   Key Petroleum already holds the same interest as the Rey subsidiary, so acquisition will double its holding in the permit, increasing it to 86.94%.  Pilot Energy Ltd holds the remaining interest in the permit. Key Petroleum’s sale of its Gulliver Productions subsidiary sees its exit from the Canning Basin and it reports this deal will allow it to focus on the Perth Basin acreage.  The EP 427 permit contains the Wye Knot prospect, which is planned to be drilled in 2018 and is targeting potential resources of 1.4 MMbo.  The permit is adjacent to Key’s L7 production licence, which contains the Mount Horner field. Rey Resources has acquired licence to the north of its existing Canning Basin acreage. It hopes to farm-out some interest in the Lennard Shelf blocks. The licences are outlined as having conventional oil and tight gas potential.  L15 contains part of the Kora West oil field, while R1 contains the Point Torment gas discovery.

On 14 May 2018 Key Petroleum Ltd and Rey Resources Ltd reported that they had signed a sale and purchase agreement, which will see the companies acquire certain subsidiaries to complete an interest swap in permits EP 104, R1 and L15, located in the Canning Basin, and EP 437, located in the Perth Basin.

Carnarvon is offering equity in revised WA-523-P and new TL-SO-T 19-14 PSC in the Sahul Syncline, Bonaparte Basin. Farm-in terms are negotiable at this stage. WA-523-P now covers 2,903 sq km west of the new maritime boundary, while  TL-SO-T 19-14 is 1,324 sq km to the east of the limit. Contact: Stephen Molyneux, [email protected].

East Timor, not found

1st of 2 Jarrar appr’s planned in PL 77 (Naccowlah), Cooper-Eromanga, oil in the Birkhead + Hutton, suspending at TD 1,947m.  Santos (op), partners Bounty, Beach, Bridgeport + Australian Gasfields.

1st of 2 Jarrar appr’s planned in PL 77 (Naccowlah), Cooper-Eromanga, oil in the Birkhead + Hutton, suspending at TD 1,947m. Santos (op), partners Bounty, Beach, Bridgeport + Australian Gasfields.

Westmount has acquired small net profit interests from InfraStrata in P1918 (0.5%, Colter prospect), P2235 (1%, Wick prospect), both off Dorset, and P2222 (0.5%, Oulton discovery off Aberdeen). The company had so far focused on the Guyana-Suriname Basin.

Westmount has acquired small net profit interests from InfraStrata in P1918 (0.5%, Colter prospect), P2235 (1%, Wick prospect), both off Dorset, and P2222 (0.5%, Oulton discovery off Aberdeen).

On 30 June 2020 Santos Ltd, through wholly owned subsidiary Santos QNT Pty Ltd, was awarded Authority to Prospect permit ATP 2057-P, located in the Roma Shelf, Bowen-Surat Basins. The permit was awarded following the PLR2019-2 Queensland State Acreage Release, where it was offered as bid block PLR2019-2-12. Santos has been awarded the permit for a period of six years, with a four-year committed work programme, which will expire on 29 June 2024. The permit is scheduled to expire or be eligible for renewal on 29 June 2026. Under the terms of the award, any gas produced from acreage must be supplied to the Australian market, a term which is carried over should a production license be awarded over the permit. Santos Ltd applied for the bid block PLR2019-2-12 on 13 February 2020. The expiry date of the schedule work programme for the permit is on 20 May 2024, until which time no amendments to the programme will be allowed. ATP 2057-P covers an area of 911 sq km. Santos QNT Pty Ltd holds 100% interest and operatorship in the permit.

Australia (Bowen - Surat B.s), ATP 2057-P, Santos Ltd was awarded Authority to Prospect permit ATP 2057-P. Santos has been awarded the permit for a period of six years, with a four-year committed work programme, which will expire on 29 June 2024. The permit is scheduled to expire or be eligible for renewal on 29 June 2026. ATP 2057-P covers an area of 911 sq km. Santos QNT Pty Ltd holds 100% interest and operatorship in the permit.

Chevron has agrred to sell it 45% interest in SC 38 (Malampaya field), 834 sq km in the Northwest Palawan Basin. The buyer and price have not been revealed. Prior to the move, Shell (op), partners Chevron + PNOC-EC (who earlier was interested in boosting its 10%).

Philippines, SC 38

South Disouq block, onshore Nile Delta, TMD 2,208m, 33m net gas sands near the base of the target Kafr el Sheikh fm, est. 24 Bcfe recoverabe gas + cond resources, well to be suspended ahead of testing. The successful outcome could require a devt well in the next 2-3 years and a tie-into the Ibn Yunus-1X well, facilities and onwards to the South Disouq CPF. SDX (op, 100% in this well), partners IPR + EGPC.

Sobhi 12X expl. (SDX op, 100% in this well, IPR + EGPC) in South Disouq block, onshore, TMD=2208m, 33m net of high-quality gas-bearing sands, with an average porosity of 20%, near the base of the Kafr El Sheikh (KES) Fm. est. 24 Bcfe recoverabe gas + cond resources, well to be suspended ahead of testing.

The Ministry of Energy announces the launch of a 3rd offshore licensing round, one tract on offer namely block 72, 257 sq km in the N. of the EEZ (in yellow on map below). It comprises part of the expired Alon D (367) licence and will run 3 years (extendable) with a drill-or-drop by expiry. Application deadline 23 Sep '20, winner on 26 Oct '20. EoIs + data package from http://www.energy-sea.gov.il/English-Site/Pages/Offshore%20Bid%20Rounds/3rd_Bid_Round.aspx.

On 23 June 2020, the Israeli Ministry of Energy announced the launch of a 3rd Offshore Licensing Round. The bid round comprises one offshore exploration block, Block 72, which is located in the north of Israel's Exclusive Economic Zone (EEZ), close to the disputed offshore border with Lebanon

Senex Energy Ltd, through wholly owned subsidiary Victoria Oil Exploration (1977) Pty Ltd, spudded exploration well Voodoo 1 in PRL 146, located in the Cooper-Eromanga Basin, on 25 November 2018.  On 3 December 2018 the well was suspended, after reaching a total depth of 2,252 m, with evaluation continuing in early December 2018. The well was one of several in Senex’s ongoing exploration programme across its Cooper-Eromanga licences. PRL 146, which covers an area of 98 sq km, was awarded on 27 October 2014.  Participants in the permit are Victoria Oil Exploration (1977) Pty Ltd (40% + Operator) Permian Oil Pty Ltd, another Senex subsidiary, (20%), and Beach Energy subsidiaries Impress (Cooper Basin) Pty Ltd (25%) and Springfield Oil and Gas Pty Ltd (15%).

Australia, PRL 146

Premier is finalising the farmout of a 50% interest in the Tuna PSC, 999 sq km off East Natuna, with Zarubezhneft. Premier will be carried through a couple of planned wells, for which a semisub is sought (Kuda Laut-2 + Singa Laut-2 appr's, both delayed to [early] 2021 - Premier has previously been granted a 1-year extension for the PSC to Mar '21). Of note, Z'neft already has interests in block 12/11 across the border in Vietnamese waters. Currently Premier (op, 80%), partner MOECO.

Premier (->30% op, MOECO 20%) is finalising the farmout of a 50% interest in the Tuna PSC (999km²) off East Natuna, with Zarubezhneft.

Shenye 1 was drilled to a TD of 4,980m MD with a 1,800m horizontal section and was suspended for further evaluation in late December 2019. The shale oil exploration well was spudded in June 2019 to drill to a PTD of 4,900m and was targeting the Fourth Member of the Shahejie Formation with the objective of exploring the shale oil potential of the Damintu Depression, Bohai Gulf Basin. Shenye 1 is in the PetroChina operated Jinganbao Oil Field Block in the Bohai Gulf Basin.

Shenye 1 was drilled to a TD of 4,980m MD with a 1,800m horizontal section and was suspended for further evaluation in late December 2019.

Summit E&P acquired a 25% interest from partner Ping Petroleum in licence P2382 (block 22/14c). The acreage contains two discoveries – 22/14a-7 (Mallory) and a small discovery made by well 22/14b-3. The deal completed on 19 March 2019. The discovery 22/14b-3 was made in 1989. The well was drilled targeting the Skagerrak Formation. 22/14a-7 (Mallory) was discovered in 2008 and was drilled as the structure is on trend with the Huntington field. Mallory lies on the northern edge of a salt wall which grew during the Triassic. The objective of the discovery well was to improve the understanding of the Jurassic and underlying Triassic. Following completion of the deal interest in the licence is held by Summit Exploration and Production Limited (75% + operator) and Ping Petroleum UK Limited (25%).

Summit E&P acquired a 25% interest from partner Ping Petroleum in licence P2382 (block 22/14c). The acreage contains two discoveries – 22/14a-7 (Mallory) and a small discovery made by well 22/14b-3.

Egdon is to take over sole ownership of promote P2304 off the North Yorkshire coast as a result of the withdrawal of partners Europa O+G and Arenite Petroleum. Plans include 3D seismic surveying and an explo well. The area contains the Resolution discovery in P1929, believed to extend into P2034. The transfer is subject to OGA approval.

United Kingdom (Anglo-Dutch B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Europa op. by COP (20.0%, EXXONMOBIL 50.0%, STATOIL 30.0%) to be check.

On 12 February 2020, the Kyrgyzstan Government announced an auction for the two blocks in the Fergana Basin. The auction will be held on 31 March 2020 with its application deadline on 24 March. Additional information may be requested from: Bishkek Prospect Erkindik, 2, office 225 Tel: +996 312 90-40-40, ext. 1021 The Mayli-Su II block covers 7.12 sq km in the eastern part of the Fergana Basin. Clastic reservoirs of the Cretaceous section are the main exploratory targets in the area. Recoverable 2P reserves of the block are estimated at 0.5 MMbbl of oil. The starting price amounts to USD 10,516. The Mayli-Su III block covers 8.31 sq km in the eastern part of the Fergana Basin. Clastic reservoirs of the Jurassic-Cretaceous section are the main exploratory targets in the area. Recoverable 3P reserves of the block are estimated at 5.4 MMbbl of oil and 2.1 Bcf of gas. The starting price amounts to USD 78,125.

On 12 February 2020, the Kyrgyzstan Government announced an auction for the two blocks in the Fergana Basin. The auction will be held on 31 March 2020 with its application deadline on 24 March.

E. flank of Oseberg in PL 053, WD 107m, TMD 2,852m (2,830m TVD, Ness fm) reached 22 Apr '20, target Intra Heather sst poorly-developed and dry, West Hercules SS off to 35/10-5 (Gabriel) in PL 827S, spudded 26 Apr. Equinor (op), partners Petoro, Total + COP.

Norway (Oseberg Fault Block (Horda Platform)) Oseberg

Kotri 2468-12 EL, Lower Indus onshore, Sindh, P&A results n/a at TD 2,415m in late Jul ’19,  Schlumberger 225 rig.

Durab X1 nfw (UEPL 50% op. Asia Resources Oil 10%, PPL 40%) in Kotri North 2568-21 EL, P&A, the well is assumed to have been dry, and it is not clear if the well was tested prior to abandonment.

Petronas Carigali plugged and abandoned wildcat Shwesitaw 1 in block IOR-7, located onshore in the Pyay Embayment (Central Burma Basin), as a dry well, around late January 2019. It is understood that a stuck pipe incident occurred during drilling, causing the loss of logging tools. By late December 2018, the well was being drilled at a depth of approximately 2,500 m, having exceeded the reported PTD of 2,450 m. The well was possibly targeting multiple sandstone intervals of the Lower Miocene Pyawbwe Formation and Middle Miocene Kyaukkok and Obogon formations. Elite Drilling is the drilling contractor for the well, using the “E-09” rig. Shwesitaw 1 was spudded on 4 November 2018. An official spud-in ceremony was held for the occasion, with attendance by Myanmar Minister of Electricity and Energy, regional government officials and PSC representatives. Petronas initially estimated approximately one month to complete drilling operations at Shwesitaw 1. In case of successful drilling, the operator planned to conduct a testing campaign at a later stage, using a different rig. The drilling location was likely matured following the interpretation of approximately 140 sq km of 3D seismic data acquired in 2016. Shwesitaw 1 is the first of a two-well drilling campaign in the block, with both wells planned to be drilled from a single well pad location. Petronas Carigali is the operator (82.25% interest) for block IOR-7, with partners PetroleumBrunei (5%) and local company UNOG Pte Ltd (12.75%). IOR-7 contains the Shwepyitha field in which the primary reservoir is within Miocene sandstones of the Obogon Formation. As of 2015, the field was producing approximately 145 bc/d and 0.8 MMcfg/d. It is understood that around April 2017, Petronas commenced a pilot project to increase production from the field. The contract for block IOR-7, together with IOR-5, was signed between Petronas and MOGE in mid-September 2014. Block IOR-5 is governed by conventional Production Sharing Contract while IOR-7, which contains the Shwephyitha gas field, is under the Improved Petroleum Recovery Contract. The award was part of the 2013 Onshore Myanmar Bid Round, which was launched in January 2013 and the result was announced in October the same year. Background Information On 17 January 2013, the Ministry of Energy of the Republic of the Union of Myanmar announced the Second Onshore Bidding Round 2013 with 18 blocks offered. A total of 15 of the 18 blocks were offered as Production Sharing Contracts (PSC), while the other 3 blocks were offered as Improved Petroleum Recovery (IPR) contracts. The Invitation of Sealed Bids for Petroleum Operations for Onshore Areas was closed 60 days after date of announcement, which was on 17 March 2013. Block IOR-7, covering 246 sq km, is located in the Shwepyitha area, some 170 km north-northwest of Yangon. The block contains the Shwepyitha gas and condensate field, discovered in 1968 by Peoples Oil Industry. The Shwepyitha 01 well flowed 5 MMcfg/d from Middle Miocene sandstones. The main reservoir in the field is represented by the Obogon Formation, buried at a depth of approximately 1,200 m. The field structure is a northwest-southeast trending anticline, following the regional trend. Field production commenced in November 1968, but reservoir pressure dropped rapidly and the field was temporarily shut-in in 1971. It was subsequently brought onstream again and the gas was supplied to cement mills and a methanol plant. MOGE conducted further exploration drilling in the field in 1991-1992, with at least two successful appraisal wells and one dry well. The field was producing at rates of 1 MMcfg/d and 400 bo/d in 2006. Cumulative production as of end-2006 was 100 Bcfg and over 3 MMbc. Total recoverable reserves from the field have been estimated at 120 Bcfg and 4 MMbc (2007). The last known development drilling activity in the field was conducted by MOGE in May 2011 with the completion of one well.

Petronas Carigali plugged and abandoned wildcat Shwesitaw 1 in block IOR-7, located onshore in the Pyay Embayment (Central Burma Basin), as a dry well,

Condor Petroleum (Canada) has signed a Heads of Agreement with the Ministry of Energy of which provides Condor a 120-day window to negotiate a definitive PSA with the Ministry. The document was signed on 12 November 2019. The PSA, if executed, would include five producing gas fields (unspecified) and the associated infrastructure along with the right to explore and develop certain exploration areas surrounding the current producing gas fields. The fiscal and operating terms expected to be defined in the PSA include royalty rates, cost recovery, profit splits, gas marketing and pricing, governance and steering committee structures and acquisition payments for the immoveable property in the fields. Condo Petroleum currently has E&P interests in Kazakhstan and Turkey.

Condor Petroleum (Canada) has signed a Heads of Agreement with the Ministry of Energy of which provides Condor a 120-day window to negotiate a definitive PSA with the Ministry.

During September-October 2019, Oryx Petroleum successfully drilled and completed the Banan 5 appraisal well on the Hawler Block in the Kurdistan Region of Iraq. The well, which was spudded in September, is the company's third in its 2019 appraisal campaign on the Banan Field (Zagros Foldbelt Basin) and follows the Banan 7 well. It was designed to assess both the Tertiary and Cretaceous reservoirs and reached a TD of 1,669m. The well was subsequently completed in the Cretaceous and placed on production in October 2019.<P />Oryx's 2019 drilling programme on the Banan Field consists of a total of four wells, with targets in the Tertiary Pila Spi and Cretaceous reservoirs. It includes the Banan 6, Banan 7 and Banan 5 wells, as well as a workover of the Banan 1 discovery well. In total the company had budgeted around US$ 18 million for the drilling campaign. <P />In 2018, Oryx resumed operations at the Banan Field. Operations on the field were suspended in 2014 as a result of security developments and escalating instability in the region following the advance of Islamic State militants.<P />The Banan Field was discovered by Oryx in early 2014 with the Banan 1 NFW. The well had successfully flowed oil in two of six cased-hole DSTs, making it the company's fourth consecutive discovery on the Hawler Block. DST#1 flowed light oil (API 27-30deg) at a rate of 3,500 bo/d from the Lower Jurassic Butmah Formation over a 23 hour period through a 128/64" choke. DST#6 was conducted over an interval in the Upper Cretaceous Shiranish & Top Kometan formations, with the well flowing naturally over a period of 42 hours through a number of different choke sizes. A sustained flow rate of 820 bo/d (API 15-21deg) was achieved over a 12 hour period through a 128/64" choke.<P />Oryx holds a 65% interest in the Hawler Block and is partnered by Korea National Oil Corp (KNOC) (15%) and the Kurdistan Regional Government (KRG) (20%).

Banan 5 appraisal well on the Hawler Block in the Kurdistan Region of Iraq. Discoveries & Successful Wells

Liaodong Bay, Bohai Gulf Basin, WD 20m, ops terminated late Apr ’19, Bohai 9 JU. Target Tertiary clastics.

Jinzhou 31-2S-1 (JZ 31-2S-1) nfw Liaodong Bay, Bohai Gulf Basin, WD 20m, ops terminated late Apr ’19, Bohai 9 JU. Target Tertiary clastics.

Imetame suspended with gas shows the 1-REN-001A-BA (1-IMET-026A-BA) new-field wildcat (NFW) in the REC-T-212 block during early-September 2019 at an unreported final total depth (TD).  The operator filed a gas show report with the ANP on 28 August 2019. The NFW was spudded on 14 August 2019.   Although classified officially as a NFW the well is an outpost for the unitized Carbure-Cardeal do Nordeste Field producing since September 2018.It is speculated the well has to be drilled as a NFW in order to establish the final production concession in the south-eastern quadrant of the field for final unitization approvals for the Alvopetro reported Carbure Natural Gas Unit. The well had a proposed total depth (PTD) of 1,650 m.   The primary target was the Early Cretaceous Caruacu Member of the Maracangalha Formation. The well is located in the very north-western corner of the block in order to drill the projected south-eastern portion of the reservoir, approximately 600 m south south-west of the 1-ALV-011-BA located in the northerly adjoining Carbure Leste production concession. The REC-T-212 block is partially unitized with Cabure, Cabure Leste, and Cardeal do Nordeste production concessions. On 23 December 2015, Imetame with 100% working interest was granted a final award for the ANP Round 13, REC-T-212 block. Carbure- Cardeal do Nordeste Field summary:  The field is currently producing from only two wells in the Cardeal do Nordeste production concession operated by Imetame.  There are two other productive wells operated by Alvopetro in the Carbure and Carbure Nordeste production concessions but not yet tied-in to the current pipeline system.  Alvopetro with 100% equity is constructing precedent setting midstream assets to produce the entire unit gas.  The company built an 11 km transport multi-phase pipeline from the Cardeal do Nordeste production concession to the UPGN.  It is building the first non-Petrobras operated natural gas processing facility, Alvopetro UPGN Bahiagas City Gate.  The state natural gas company Bahia Gas is building a 15 km gas pipeline to the UPGN to buy the gas for USD 7.66/MMbtu.  Imetame and Alvopetro plan to drill three to four additional wells including the current 1-REN-001-BA (1-IMET-026-BA) being drilled by Imetame.  All of the production facilities and well connections are expected to be completed by year-end 2019 with plateau production of 15.9 MMcfg/d projected for 2020. In April 2019, Imetame was producing two wells in the Cardeal do Nordeste production concession, the 1-IMET-003-BA and the 1-IMET-010D-BA.  Production averaged 620 Mcfg/d with 2.8 bc/d and 777 Mcfg/d respectively for the two wells. The Carbure Natural Gas Unit is split between designated operator Imetame 50.9% and Alvopetro 49.1% and includes portions or all of the Cabure, Cabure Leste, and Cardeal do Nordeste production concessions and pending inclusion of the north-west part of the REC-T-212 block once a production concession is granted.  Imetame holds 50.9% of the reservoir that represents 64.7 Bcfg OGIP and OGIP of 57.48 Bcfg and 19.69 MMbo as original oil in place (OOIP) was reported for the Cardeal do Nordeste production concession for 31 December 2018.  This implies 7 to 8 Bcfg in the REC-T-212 portion of the unitized reservoir.  Alvopetro holds 49.1 % of the reservoir that represents 62.4 Bcfg in estimated original gas in place (OGIP) reserves with 27.8 Bcfg reported as 2P reserves in June 2019 for the Carbure and Carbure Leste production concessions.  Alvopetro has not reported any oil reserves for its portion of the reservoir.   In March 2017, Alvopetro tested gas producer 1-ALV-198-A1-BA (1-ALV-011-BA) new-field wildcat (NFW) the REC-T-198 block and reported on some of the reservoir properties.   It tested the upper 21 m of 31 m potential net gas pay in its primary target the Early Cretaceous Caruacu Member of the Maracangalha Formation.  Average porosity reported to be 11.4% here with 46% calculated water saturation.  Average porosity was reported to be 14.3% with 46% calculated water saturation. The operator tested the well for 2.7 MMcfg/d during a 72-hour test period through 2 7/8” tubing unstimulated.  The production test utilized a 28/64” choke throughout the test period.  The operator also recovered 17 bbls of condensate 64° API and 5 bbls of water during the test period.  At the start of the test the well had an FTP of 1,281 psia and at the end of the test 563 psia.  The initial shut-in casing pressure was 1,345 psia and the ending shut-in casing pressure was 615 psia.  After the production test the operator conducted a build-up pressure test of the reservoir.  On 3 March 2017, Alvopetro tested the lowest 7 m of 31 m potential net gas pay in its primary target the Early Cretaceous Caruacu Member of the Maracangalha Formation.  Average porosity was reported to be 11.4% here with 46% calculated water saturation.  The operator tested the well for 500 Mcfg/d during a 48-hour test period through 2 7/8” tubing unstimulated.  The production test started off with a 12/64” choke and then went to a final choke size of 32/64”.  The operator also recovered 12 bbls of condensate 45° API and 92 bbls of water during the test period.   At the start of the test the well had an FTP of 826 psia and at the end of the test 144 psia.  The initial shut-in casing pressure was 1,427 psia and the ending shut-in casing pressure was 346 psia.  After the production test the operator conducted a build-up pressure test of the reservoir. On 27 September 2018, the ANP granted formal approval to Imetame to acquire the 30.65% working interest held by lone partner Orteng in the Cardeal Amarelo and Cardeal do Nordeste production concessions.  Imetame now holds 100% working interest in both production concessions. Imetame was operator of both production concession contracts with a 69.35% working interest and lone partner was Orteng with 30.65% working interest. On 10 January 2018, the ANP approved a resolution to arbitrate the technical terms for the preliminary unitization agreement between Alvopetro and Imetame regarding the Cabure, Cabure Leste, and Cardeal do Nordeste production concessions and the REC-T-212 block that share a common gas reservoir in the onshore Reconcavo Basin.  Alvopetro issued a press release regarding the unitization agreement on 15 January 2018.  It provided the following information including that total estimated in place gas reserves for the unitized are estimated to be 127.1 Bcfg.  The ANP approved of the following ownership split of the reservoir based on working interest and block area involved.  The three companies involved in the process Alvopetro, Imetame, and Orteng will have 60 days to finalize various additional requirements to conclude the unitization agreement including preparation and filing a joint development plan, choosing the unit operator, and execute a joint operating agreement.  If the parties are unable to reach an agreement by 13 March 2018, the ANP will make the final decisions.  According to Alvopetro, the ANP evaluated all of the technical information regarding the common reservoir and decided on the working interest share of each party as follows. Alvopetro was granted 49.1 % of the reservoir that represents 62.4 Bcfg in place estimated reserves with 27.8 Bcfg reported as 2P reserves in June 2019. Imetame was granted 36.1 % of the reservoir that represents 45.9 Bcfg in place estimated reserves and also the 14.8% of 18.8 Bcfg reserves previously held by Orteng. Orteng was granted 14.8 % of the reservoir that represents 18.8 Bcfg in place estimated reserves.

1-REN-001A-BA (1-IMET-026A-BA) new-field wildcat (NFW) in the REC-T-212, suspended with gas shows.

Block 9 (Suneinah), drilled 11 Apr – early May '20, TD 3,688m, 2-7/8" completion string being run. Oxy (op), partners OQ Upstream + Mitsui.

Malik S.-1 expl Block 9 (Suneinah), drilled 11 Apr – early May '20, TD 3,688m, 2-7/8" completion string being run. Oxy (op), partners OQ Upstream + Mitsui.

PPL 226, Cooper Eromanga, drilled 29 Dec '19 – 11 Jan '20, TD 3,052m, suspended oil.

Teringie-5 appr PPL 226, Cooper Eromanga, drilled 29 Dec '19 – 11 Jan '20, TD 3,052m, suspended oil.

The Bala-Balakang block (ex-Tanjung Aru), 3,145 sq km in WD 20-1,000m, Kutei Basin / Makassar Strait, remains open for offers by KrisEnergy (op, 85%), up to 42% available in exchange for a pro-rata share of back costs and carry on tentative explo drilling by end 2019. KrisEnergy (op), partner Natuna Ventures. Contact: [email protected].

Indonesia, not found

Dinan 15 flow tested approximately 635 bo/d and 2,597 bo/d from two intervals in the Second Member of the Permian Upper Urho Formation on 2 December 2019, after having achieved commercial oil flow of up to 635 bo/d from the Permian Wutonggou Formation in late October 2019. The oil exploration well was spudded on 4 July 2019 and was drilled to a TD of 3,980m MD on 15 September 2019, having encountered strong oil and gas shows in the Wutonggou and Upper Urho formations. The objective of Dinan 15 was to explore the oil and gas potential of the Wutonggou Formation in the eastern part of the Dinan 8 well, drilled by PetroChina in October 2013 and was the first well to flow test oil from the Wutonggou Formation in the Dongdaohaizi Sag, Junggar Basin. Dinan 15 is in the PetroChina operated Baijiahai Block in the Junggar Basin.

Dinan 15 flow tested approximately 635 bo/d and 2,597 bo/d from two intervals in the Second Member of the Permian Upper Urho Formation on 2 December 2019, after having achieved commercial oil flow of up to 635 bo/d from the Permian Wutonggou Formation in late October 2019.

E. part of Hugrijan ML, Assam Shelf, ops terminated late 2019, assumed suspended. PTD was 4,000m, targets probably Miocene Tipam sst + Oligocene Barail Group.

HZF expl E. part of Hugrijan ML, Assam Shelf, ops terminated late 2019, assumed suspended. PTD was 4,000m, targets probably Miocene Tipam sst + Oligocene Barail Group.

Exxon in March farmed out a 50% stake in 273ER (Deepwater Durban licence) to Statoil, now theoretically Equinor. The 50,169 sq km block lies in the deepwater Durban sub-basin (Natal Trough), WD 2,400-3,000m. Partnership now 50:50.

Exxon in March farmed out a 50% stake in 273ER (Deepwater Durban licence) to Statoil, now theoretically Equinor. The 50,169 sq km block lies in the deepwater Durban sub-basin (Natal Trough), WD 2,400-3,000m. Partnership now 50:50.

Carnarvon is offering equity in revised WA-523-P and new TL-SO-T 19-14 PSC in the Sahul Syncline, Bonaparte Basin. Farm-in terms are negotiable at this stage. WA-523-P now covers 2,903 sq km west of the new maritime boundary, while  TL-SO-T 19-14 is 1,324 sq km to the east of the limit. Contact: Stephen Molyneux, [email protected].

East Timor, not found

On 20 February 2020, the ANP granted formal approval for Wintershall to transfer a 30% working interest to Murphy in the POT-M-857, POT-M-863, and POT-M-865 blocks in the offshore, ultra-deep-water Potiguar Basin. TGS concluded shooting a 3D spec survey over the blocks and Wintershall DEA has already submitted an environmental permit request to drill a well in the POT-M-857 block. Terms of the deal were not disclosed. Wintershall DEA is the operator of the contracts with 70% working interest and Murphy holds a 30% non-operated working interest. On 9 October 2019, Wintershall issued a press release indicating it farmed-out a 30% working interest to Murphy in the POT-M-857, POT-M-863, and POT-M-865 blocks in the offshore, deep-water Potiguar Basin. On 8 July 2019, the Wintershall DEA do Brasil Exploracao e Producao Ltd filed an environmental permit request with IBAMA to drill one exploration well in the POT-M-857 block in the offshore Potiguar Basin. The prospect is named Poco 1 located in the central area of the block in a water depth of 2,000 m. The prospect is speculated to be targeting the Upper Cretaceous Quebradas turbidites. There was no timeline reported to drill the well, but it is assumed the permit process will take approximately one year pushing the drilling schedule into 2020 at least. On 7 November 2018, Wintershall with 100% working interest was granted official awards for the POT-M-857, POT-M-863, and POT-M-865 blocks in the offshore Potiguar Basin through the ANP Round 15. For the POT-M-857 block Wintershall offered a bonus of USD 17.31 million and 294 work units which won the block. There was one other bid for the block by the consortium of Petrobras, Petrogal, and Shell who bid USD 4.37 million bonus and 264 work units. For the POT-M-863 block Wintershall offered a bonus of USD 7.42 million and 265 work units which won the block. There was one other bid for the block by the consortium of Petrobras, and Shell who bid USD 3.29 million bonus and 250 work units. For the POT-M-865 block Wintershall offered a bonus of USD 4.95 million and 218 work units which won the block. There was one other bid for the block by the consortium of Petrobras, and Shell who bid USD 4.38 million bonus and 176 work units.

WintershallDea (->70% op.) transfered a 30% working interest to Murphy in the POT-M-857, POT-M-863, and POT-M-865 blocks in the ultra-deep-water offshore.

Amerisur has exercised a right of 1st refusal on the sale, by Vetra to Gran Tierra, of 50% + operatorship in PUT 8 in the Putumayo Basin. Consideration for the deal is USD 19.1 MM and Amerisur will end sole holder of the 440-sq km block.  Partners so far Vetra (op) + Amerisur sub Platino Egy.

Amerisur has exercised a right of 1st refusal on the sale, by Vetra to Gran Tierra, of 50% + operatorship in PUT 8. Consideration for the deal is US$19.1 MM and Amerisur will end sole holder of the 440-sq km block.

On 17 December 2018, ENI issued a press release indicating it signed a sales and purchase agreement with QPI Mexico for a 35% working interest in the Amoca, Mizton, and Tecoalli fields related to the CNH-R01-L02-A1/2015 PSC contract.  The transaction is subject to governmental approvals.  The deal when finalized will have QPI involved in the first production from a field development project by foreign companies in Mexico.  ENI currently holds 100% working interest in the contract.  After formal approvals, ENI will continue to be the operator with 65% working interest and QPI will hold 35% working interest. On 31 July 2018, the CNH formally approved the development plan submitted by ENI for the Amoca, Mizton, and Tecoalli fields related to the CNH-R01-L02-A1/2015 PSC contract.  The principal features of the development plan includes three phases with four fixed drilling platforms that will have 22 producing wells and 10 injectors, an FPSO, and pipeline to shore that will cost an estimated USD 7.496 billion to recover a total of 345.8 MMbo and 221.6 Bcfg through 2038.  The development concept was decided upon after review of several alternative production concepts. The three phases of the ENI development project will start with initial production from the Mizton field in 3rd quarter 2019 producing from seven wells and five water injection wells with all of the production going to shore via a 10”, multi-phase pipeline to the PEMEX San Ramon processing facility that will only take 8,000 bo/d of production.  The initial phase will conclude in the 4th quarter 2020. The second phase will commence in 4th quarter 2020 and is considered the definitive development phase that will produce the Amoca and Mizton fields jointly through two fixed production platforms, 16 production wells and eight water injection wells producing through a 90,000 bo/d capacity FPSO. The third phase will commence in 1st quarter 2024 and will include production from the Tecoalli field and the 2nd fixed platform in the Amoca field.  The Amoca field final development will include four additional production wells and two additional injectors while the Tecoalli field will have a small fixed platform to produce from only two production wells. Maximum production of oil will be 90,000 bo/d in 2021 and maximum gas production will be 60 MMcfg/d.  Plateau production of 90,000 bo/d is projected to last until 2025. A peculiar feature of the contract is that after year 10, ENI will have to purchase the FPSO and flag it as a Mexican vessel.  At the end of the contract period the FPSO and all equipment will revert to the government.

Mexico, CNH-R01-L02-A1/2015

PetroChina – Changqing achieved progress in shale oil exploration in the Ordos Basin. Chengye 1 and Chengye 2, two horizontal exploration wells, tested 886 b/d (121.38 t/d) and 791 b/d (108.38 t/d) of oil respectively from an oil-shale interval in the Chang 7 Unit (Yanchang 7 Unit) of the Upper Triassic Yanchange Formation after fracking. Chengye 1, a new-pool well, was spudded on 7 April 2019. The both wells, targeting the shale interval in the Yanchang Formation, were drilled in the Chenghao oil field which is located in the Yishan Slope of the basin. In the past few years, PetroChina - Changqing made great effort on shale oil exploration in the Ordos Basin. A giant shale oil field, Qingcheng field, was approved in the Ordos Basin in September 2019. Qingcheng Field, located in the southwest of the basin, has been approved 358 million tons (2.5 bn bbl) of oil in place in the Triassic Chang 7 Formation, with 693 million tons (4.9 bn bbl) of P3 oil in place, which indicated a 1 bn tons (7 bn bbls) scale field discovery. The Qingcheng field has been on development and it was expected to be produced at a rate of 12,800 b/d of oil in 2019. The field was also expected to reach a production of 60,000 b/d of oil in the next few years. Another shale oil field, Xin'anbian shale oil field, was reported to be the first shale oil field (initially was classified as tight oil) found in China to surpass 100 million tons (over 700 MMbbl) of proven oil in-place. The Xin'anbian shale oil field was discovered in 2007 when An 83 penetrated 17.5 m oil pay in the Chang 7 Unit of the Yanchang Formation, later on the well tested 12 t/d of commercial oil. This is the first time that commercial oil flow was obtained from the shale interval in the Xin'anbian area, it is also China's first giant shale oil field. Background Information The Ordos Basin is the important oil and gas production base for PetroChina, in particularly on unconventional, such as tight gas, tight oil and shale oil. In 2018 PetroChina produced total 23.6 million tons of oil and 38.7 Bcm of gas, the company has target to produce 24 million tons of oil and 42 Bcm of gas in 2020, 28 million tons of oil and 45 Bcm of gas in 2025. The Yanchang 7 Unit is the main source rocks in the Ordos Basin. Since 2011, PetroChina has started exploration for shale oil in the Chang 7 Unit. In 2014 the company confirmed Xin’anbian shale oil field with approved 700 MMb of oil in place. The Yanchang Formation is the most favorable oil-generating source rocks in the Ordos Basin, dominated with lacustrine mudstones and thin siltstones. Dark mudstones of the Yanchang Formation are as thick as 300 m to 400 m with an area of 80,000 sq km. The best source rock is within the Yanchang 7 Unit, single layer thickness of mudstones ranges from 5 m to 25 m, total thickness of mudstones ranges from 10 m to 50 m, maximum can be great than 80 m. The source intervals of the Yanchang 7 Unit have a TOC content ranging from 2% to 5%, bitumen A from 0.3% to 0.5%, and total hydrocarbon value of 1833 ppm to 3503 ppm.

Chengye 1 & 2 expl Horiz shale wells in the Chenghao oilfield, Yishan Slope, both fracked and tested resp. 886 bo/d + 791 bo/d from the Chang 7 Unit (Yanchang 7 Unit), Yanchange fm.

BM-S-050 contract, S-M-623 block, Santos Basin, WD 1,841m, oil shows report to ANP on 6 Jan '20. PTD is/was 6,665m, target Barra Velha fm, ODN I SS. Petrobras (op), partners Shell + Repsol-Sinopec.

3-SPS-106 (3-BRSA-1370-SPS, Sagitario) appr BM-S-050 contract, S-M-623 block, Santos Basin, WD 1,841m, oil shows report to ANP on 6 Jan '20. PTD is/was 6,665m, target Barra Velha fm, ODN I SS. Petrobras (op), partners Shell + Repsol-Sinopec.

On 24 March 2020, GHP Exploration announced that the company is farming out a 50% working interest in its West Gebel El Zeit block, Gulf of Suez Basin. According to GHP Exploration, multiple prospects have been identified within the block with significant resource potential. The block consists of an onshore as well as an offshore area extending into the northern boundary of the giant Zeit bay field. Total acreage is 214 sq km. It includes the C9 A 1 discovery found in 1984 and about 22 exploration dry (or oil show) wells drilled between 1974 and 2009. GHP Exploration was awarded the West Gebel El Zeit block in July 2018 by South Valley Egyptian Petroleum Holding Company (Ganope). The company was committed to spend a minimum of USD 6 million for the drilling of six wells.

GHP Exploration (Egypt) Ltd farming out its West Gebel El Zeit block, Gulf of Suez Basin

On 10 December 2019, the East Abu Sennan Petroleum Company (EASPCO) successfully completed its ASH 2 appraisal well, located on the Abu Sennan 4 development lease (DL) of the Abu Sennan PSC in the Abu Gharadig Basin. The well reached 4,030m TD in the Early Cretaceous Alam El Bueib sandstone with a 50m net oil pay encountered. An MDT was also carried out. Further rigless testing of the well is planned.ASH 2 was appraising the ASH oil field located ~800m SW of the company's 2015 ASH 1X ST1 discovery (4,777m TD). The sidetrack well was drilled into the objective AEB horizon, with a KOP at 2,196m. Upon testing of a 14m interval, the well flowed 3,900 bo/d of 46deg API oil and 3.1 MMcfg/d on a 64/64" choke. Equity in the EASPCO consortium is split between UEG (via Kuwait Energy, 12.5%), Dover (14%), Rockhopper (11%), Global Connect (12.5%) and EGPC (50%, carried). In late July 2019, UK junior United Oil & Gas plc (UOG) signed a US$ 16 million deal to acquire Rockhopper's Egyptian assets.<P />

Egypt, Abu Sennan

Statoil has picked up 50% from Apache in P2338 / block 16/18c effective 6 Dec ’17, resulting in a 50:50 partnership in the 22-sq km licence.

Statoil has acquired a 50% interest in licence P2338 from Apache (-> 50% op.).

In August 2019, the Federal Antimonopoly Agency approved a new deal between Gazprom Neft and Repsol SA. The Spanish company obtained the right to acquire a 50.01% stake in Karabashskoye-6, the operator of six long-term licenses in Khanty-Mansiysk Autonomous Okrug (Western Siberia). Gazprom Neft won the licenses at an auction in March 2018. In June 2019, all licenses were transferred to its fully owned subsidiary Karabashskoye-6. Gazprom Neft and Repsol already cooperate in the region through ASB Geo (Repsol with 50%) and Eurotek Yugra (Repsol with 75%). Licenses, operated by Karabashskoye-6, are as follows: The Karabashskiy 17 block covers 258 sq km in the Ural-Frolov Province. No exploratory wells have been drilled in the block. Resources (category D1+D2) of the block are estimated at 8 MMbbl of oil and 41 Bcf of gas. Gazprom Neft offered RUB 201.6 million (USD 3.5 million). The Karabashskiy 18 block covers 266 sq km in the Ural-Frolov Province. No exploratory wells have been drilled in the block. Resources (category D1+D2) of the block are estimated at 7 MMbbl of oil and 27 Bcf of gas. Gazprom Neft offered RUB 98.3 million (USD 1.7 million). The Karabashskiy 19 block covers 285 sq km in the Ural-Frolov Province. No exploratory wells have been drilled in the block. Resources (category D1+D2) of the block are estimated at 7 MMbbl of oil and 14 Bcf of gas. Gazprom Neft offered RUB 1.049 million (USD 0.02 million). The Karabashskiy 25 block covers 239 sq km in the Ural-Frolov Province. No exploratory wells have been drilled in the block. Resources (category D1+D2) of the block are estimated at 7 MMbbl of oil and 58 Bcf of gas. Gazprom Neft offered RUB 189.3 million (USD 3.3 million). The Karabashskiy 26 block covers 263 sq km in the Ural-Frolov Province. No exploratory wells have been drilled in the block. Resources (category D1+D2) of the block are estimated at 5 MMbbl of oil and 24 Bcf of gas. Gazprom Neft offered RUB 97.1 million (USD 1.7 million). The Karabashskiy 27 block covers 287 sq km in the Ural-Frolov Province. No exploratory wells have been drilled in the block. Resources (category D1+D2) of the block are estimated at 6 MMbbl of oil and 17 Bcf of gas. Gazprom Neft offered RUB 0.875 million (USD 0.02 million).

Repsol has been cleared to acquire a 50,1% stake in Gazprom Neft’s Karabashskiy-6 block. The companies are already cooperating in the nearby Karabashskiy 1, 2, 3, 9, 10, 78 and 79 blocks, mostly through their Evrotek-Yugra JV.

Wellesley has acquired a 30% interest in PL 829 and a 20% interest in PL 878 from Equinor. The deal was confirmed by the NPD on 5 December 2019 and is effective from 29 November 2019. PL 829 covers parts of blocks 6204/7, 6204/8, 6204/10 and 6204/11 and the decision to proceed with drilling a well was made in November 2019. PL 878 covers parts of blocks 30/2 and 30/3 and a well (30/2-5) will be drilled on the Atlantis prospect to the north of Huldra (the shallow gas pilot hole is expected in Q1 2020). Wellesley obtained its first 30% interest in PL 829 in 2016 by way of a deal with Point Resources. The licence contains two small gas discoveries made by 6204/11-1 (Statoil 1994) and 6204/10-2 R (Statoil 1997). Shell was a former partner in PL 878 and exited the licence in February 2019, leaving Equinor with 100% interest. The abandoned Huldra field lies in what is now PL 878. Huldra was discovered in 1982 by well 30/2-1 and it came onstream in November 2001. It is a rotated fault block structure with a Middle Jurassic Brent Group reservoir lying between 3,500-3,900 m. The reservoir was initially HPHT but compression was required to aid production from 2007. From the Huldra platform wet gas was transported to Heimdal for further processing and export and condensate was exported through Veslefrikk. Production ceased in 2014. Interest in PL 829 is now held by Equinor Energy AS (20% + operator), Wellesley Petroleum AS (60%) and Petoro AS (20%) and interest in PL 878 is divided between Equinor Energy AS (80% + operator) and Wellesley Petroleum AS (20%).

Wellesley has picked up 30% in PL 829 (part-blocks 6204/7, 8, 10 + 11) + 20% in PL 878 (part-blocks 30/2 + 3, Atlantis prospect) from Equinor. PL 829 now Equinor (op), Wellesley + Petoro

Area 96 (block 2), 2014 well to TD 2,530m, staged drilling leading to P&A in May ’18, TP 215 rig. Target Memouniat fm. Sipex (op), partner Indian Oil Corp + Oil India.

A-001-096/2 (Sipex op.50%, ONGC 25 %, Oil India 25 %) in the Area 096 (Block 2), the target was Devonian and Ashgillian Memouniat Fm, P&A with unreported results

On 6 December 2018, the State Geological Service announced the 2019 Round 1 for 10 onshore blocks located in five regions of the country and covering over 1,810 sq km. Further rounds will be held in the future as part of a planned total offering of 30 blocks to be conducted on a competitive basis. Round 1 bidders have 90 days to submit applications and the auction is to be held on 6 March 2019. The bid information document reveals the following details: ->The total area of the 30 blocks is 4,630 sq km.->The total number of concession blocks will be auctioned in a series of competitive licensing rounds.->All blocks are located in proven petroleum provinces with well-developed midstream infrastructure and extensively covered by geophysical surveys.->Licences for nine of the 10 blocks have a contract duration of 20 years. The remaining block (Suvorivska) has a 5-year exploration period.->There are minimum exploration program requirements for each block. Exploration work programs are divided into an initial 12 months (seismic reprocessing), followed by a second 12-month period (seismic acquisition) and then a 24-month period (typically one well) or a 1+1+2 sequence.->The prospective resources of the 10 blocks are estimated by the authorities to be 86.25 billion cubic metres of gas and 16.29 million tonnes of liquids. One block (Dubrivsko-Radchenkivska) has developed proven oil and gas reserves.->The initial price of most of the licences does not exceed US$ 0.7 million.->The highest bid in terms of a cash bonus will be awarded the block. While no fiscal terms have so far been revealed for the round, from recent developments it is probable that the following applies for concession agreements: ->The current production tax rates (royalties) apply:->Gas production from reservoirs shallower than 5,000m - 29%.->Oil production from reservoirs shallower than 5,000m - 29%.->Condensate production from reservoirs shallower than 5,000m - 45%.->Gas production from reservoirs deeper than 5,000m - 14%.->Oil production from reservoirs deeper than 5,000m - 14%.->Condensate production from reservoirs deeper than 5,000m - 21%.->In December 2017, amendments to royalty rates for gas and condensate production from "new wells" from 1 January 2018 are as follows:->Gas from deposits entirely or partly at a depth of up to 5,000m - 12% (from 29%).->Gas from deposits entirely or partly at a depth of more than 5,000m - 6% (from 14%).->Condensate from deposits entirely or partly at depth of up to 5,000m - 29% (from 45%).->Condensate from deposits entirely or partly at depth of more than 5,000m - 14% (from 21%).->The general corporate income tax rate is currently 18%.<P /><P />

Not Found

Badr El Din 3 (Dev) lease, W. Desert, susp. at TD 3,779m (Bahariya) late Aug ‘18, EDC rig 42.  Targets Abu Roash G + U. Bahariya.

Egypt (Abu Gharadiq B.) Badr El Din 15

Effective 1 October 2017 Hilcorp Alaska LLC was officially awarded 14 tracts covering about 76,682 acres (310 sq km) off Alaska’s south-central coast from the Cook Inlet Lease Sale 244 held by the Bureau of Ocean Energy Management (BOEM) on 21 June 2017. The company placed high bids in the amount of USD 3,034,815 and was the sale’s lone bidder. Sale 244 was the thirteenth and final OCS lease sale held under the 2012-2017 Five-Year Program. It offered some 1.09 million acres (4,410 sq km) for leasing and consisted of 224 blocks that stretched roughly from Kalgin Island in the north to Augustine Island in the south. Each bid went through a 90-day evaluation process to ensure the public received fair market value before a lease was awarded. All materials and statistics for Lease Sale 244 are available at: http://www.boem.gov/ak244. Hilcorp Official Awards               Contract Company Name WI Bonus USD Acre Sqkm Lease Sale Award Date Basin   Y02434 Hilcorp Alaska 100 $62,208.00 5,184.26 20.98 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02435 Hilcorp Alaska 100 $37,416.00 3,118.47 12.62 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02436 Hilcorp Alaska 100 $68,376.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02437 Hilcorp Alaska 100 $142,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02438 Hilcorp Alaska 100 $111,606.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02439 Hilcorp Alaska 100 $313,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02440 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02441 Hilcorp Alaska 100 $203,319.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02442 Hilcorp Alaska 100 $111,606.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02443 Hilcorp Alaska 100 $256,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02444 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02445 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02446 Hilcorp Alaska 100 $152,019.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02447 Hilcorp Alaska 100 $152,019.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Totals     $3,034,815.00 76,681.62 310.32         Source: IHS Markit               © 2017 IHS  

United States, Y02440

The CNPE has approved ANP’s plans to hold Round 16 which features 42 blocks totalling 29,912 sq km (4 in the Camamu-Almada Basin, 17 in the Campos, 3 in the Jacuipe, 5 in the Pernambuco Paraíba, 13 in the Santos basins). Please refer to GEPS for block details.

The CNPE has approved ANP’s plans to hold Round 16 which features 42 blocks totalling 29,912 sq km (4 in the Camamu-Almada Basin, 17 in the Campos, 3 in the Jacuipe, 5 in the Pernambuco Paraíba, 13 in the Santos basins). Please refer to GEPS for block details.

On 12 February 2020 Horizon Energy completed the acquisition of a 40% interest in licences P2329, P2427 and P2486 and a 30% interest in P2300 from Simwell Resources. Horizon also acquired a further 10% interest in P2300 from Comtrack Ventures. Operator of the licences, Ardent Oil Limited has been farming out the acreage. A highly prospective Upper Permian Zechstein (‘Z2’) play fairway has been interpreted within the acreage. The play has broad similarities with established analogues further east in Poland and Germany. A total of 12 leads have been mapped with individual most likely prospective resources of 165 Bcf, all 12 leads approximately contain 2 Tcf. The leads are a combination of structural and stratigraphic trapping, and the play fairway is identified on isopach maps of the Z2 Zechstein interval. Reservoir objectives consist of the Hauptdolomite carbonate buildups deposited in high energy shoals / barriers or reefal facies. Zechstein carbonates have been encountered in nearby wells and flowed hydrocarbons from intervals 40 – 60 m thick. Porosities of 6 – 20% have been recorded. The Stassfurthalite of the Z2 cycle provides top seal for the Hauptdolomite leads. Depths to the top of the Hauptdolomite are approximately 2,100 – 2,300 m subsea. Dinantian or early Namurian deep marine shales are the most likely sources of gas. Reservoir performance and trap integrity are considered the main risk. Following completion of the deals, interest in P2329, P2427 and P2486 is held by Ardent Oil Ltd (25% + operator), Horizon Energy subsidiaries Horizon Energy Partners Ltd (45%), Horizon Energy Acquisition Ltd (20%) and Simwell Resources Ltd (10%). Interest in P2300 will be held by Ardent Oil Ltd (50% + operator), Horizon Energy Partners Ltd (20%), Horizon Energy Acquisition Ltd (20%) and Simwell Resources Ltd (10%).

United Kingdom, P2427

SN-3 block of the Sinú-San Jacinto Basin, drilled 4-18 May ’18, TD ca, 2,400m, w.o. results. Gran Tierra (op), Perenco partner.

Tonga 1 (Gran Tierra (op), Perenco partner in SN-3 block. TD ca, 2400m, P&A, w.o. results.

On 14 July 2020, Polski Koncern Naftowy (PKN) ORLEN and the State Treasury, represented by the Minister of State Assets, signed a Letter of Intent (LoI) for the acquisition of Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) Group by PKN ORLEN. The acquisition of PGNiG Group, majority-owned by the Ministry of State Assets (71.88%), by PKN ORLEN is following the government's strategic decision to form financially strong, internationally-recognised brand that is capable to compete on the global markets. According to the Letter of Intent, the transaction model and its timetable will be developed by a team representing both parties to the agreement, whereby the leading role will be taken by PKN ORLEN. The procedure is contingent on the approval of the relevant competition authorities, including the European Commission and the domestic office UOKiK. The acquisition of PGNiG by PKN ORLEN follows up on the latter company's recent acquisitions of Energa Group and the conditional agreement of the European Commission to take over the LOTOS Group. Following the transaction, the joint revenues of PKN ORLEN, ENERGA Group, LOTOS Group and PGNiG Group would reach PLN 200 billion. The annual EBITDA of the main operational segments would reach PLN 20 billion. The international exploration and production activities of the joint group include Canada (ORLEN Upstream), Lithuania (LOTOS Geonafta), Pakistan (PGNiG), Poland (PGNiG, LOTOS Petrobaltic, ORLEN Upstream), Norway (PGNiG, LOTOS Petrobaltic) and the United Arab Emirates (PGNiG).

Poland, On 14 July 2020, Polski Koncern Naftowy (PKN) ORLEN and the State Treasury, represented by the Minister of State Assets, signed a Letter of Intent (LoI) for the acquisition of Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) Group by PKN ORLEN.

Dubai Petroleum Establishment (DP) has announced the discovery of a new offshore oil field during 2018. It is believed to have successfully tested the Aqam 2 exploratory well. DP re-evaluated the results of a 1990s well originally P&A’d on the Aqam structure which it now considers it to be a new field discovery. Aqam 2 had been spudded by the J/U "Noble David Tinsley" in June 2018.    Aqam is the first new offshore discovery to have been announced since 2010. A Dubai government statement on 4 February 2010 announced the discovery of a 'new offshore oil field' subsequently named 'Al Jalila' and located to the east of the Rashid oil field. The Al Jalila field had been named after the Dubai ruler’s daughter with Princess Haya bint Al Hussein of Jordan. It is understood that the announcement followed the re-entry and appraisal sidetracking of the undeveloped 1986 Jadid 1 oil discovery. During the last decade, DP has invested significant resources in a re-evaluation of its onshore & offshore geological framework and remaining hydrocarbon potential.

Dubai Petroleum Establishment (DP) has announced the discovery of a new offshore oil field during 2018. It is believed to have successfully tested the Aqam 2 exploratory well. DP re-evaluated the results of a 1990s well originally P&A’d on the Aqam structure which it now considers it to be a new field discovery.

The government of the Federation of Bosnia and Herzegovina has launched the bidding round in which four blocks - BiH Po-1, BiH Po-2, BiH Tz and BiH D-1 – within the limits of the Federation are expected to be licenced. On 7 January 2020 the government published information relevant to the bidding round and the data room on its website, located here. The documents include an overview of the blocks, regulations, evaluation criteria, submission forms and an indicative timeline. The timeline states that the bidding round commenced on 1 October 2019, the deadline for bid submissions is 27 May 2020 at 2.00 pm local time, the winner announcements will be on 24 June 2020 and the finalisation of negotiations and contract execution is expected to be in September 2020. All questions related to the bidding instructions (including requests for clarification and amendments) may be sent to both of the following e-mail addresses: [email protected] and [email protected]. Interested parties can gain access to the data from the Geological Survey in Sarajevo. The data includes geological, geochemical and geophysical reports, a GIS dataset and subsurface data. In early September 2019 the Government of the Federation of Bosnia and Herzegovina and the Federal Ministry of Energy Mining and Industry (FMERI) announced they will launch a bidding round for three blocks in the southern margin of the Pannonian Basin (BiH Po-1, BiH Po-2 and BiH Tz) and one block in the External Dinarides (BiH D-1). Block BiH Tz is in the Tuzla Basin, in the most southerly extent of the Pannonian Basin. The block is 1,511 sq km with 98 km of 2D seismic and 27 wells drilled within the licence. Of the 27 wells, 17 were oil bearing and five were oil and gas bearing. Eight leads and two prospects have been mapped in BiH Tz, with the main reservoir identified as the Upper Miocene deltaic to marine sandstones. Block BiH Po-1 is 110 sq km with 24 km of 2D seismic and 2 wells drilled towards the south of the licence. Block BiH Po-2 is 98 sq km with 27.6 km of 2D seismic and three wells drilled within the licence. Two wells close to BiH Po-1 and BiH Po-2 encountered oil shows and traces of oil and gas in Cretaceous, Eocene and Oligocene layers. Two leads have been identified and mapped in BiH Po-1 and one prospect has been mapped in BiH Po-2. The BiH D-1 block is 3,237 sq km and it is covered by 165 km of 2D seismic. No wells have been drilled within the licence. This block is considered to be a high risk and high reward opportunity due to its structural complexity. Hydrocarbon accumulations could be trapped in large footwall traps or restricted hanging wall traps at the thrust faults. The reservoir at the DiH D-1 block is expected to be the Upper Permian and Lower Triassic clastics and Jurassic and Lower Cretaceous dolomites. To provide further information regarding the technical potential of the four blocks on offer and to present the regulatory and fiscal terms and conditions, the FMERI hosted a roadshow in Sarajevo and another in London during October 2019. In addition, the FMERI and the Federal Institute for Geology representatives were present at the Central-Eastern Europe and Caspian (CEEC) Scout Group Meeting in Ankara, Turkey on the 3 - 4 October 2019 and they attended the Balkans Petroleum Summit on the 24 - 25 October 2019 in Montenegro to provide information about the blocks. The Republic of Bosnia and Herzegovina is divided in two political entities, the Federation of Bosnia and Herzegovina and the Republic of Srpska. The district of Brcko is a third self-governing administrative unit in the northeastern part of the country. Between 1989 to 1992 Amoco carried out a project across the Dinarides. Prospective structures were identified close to Trebinje, Stolac, Nevesinje, Mostar and Dreznica (which was described as a megastructure). It was reported from this study that there is oil and gas potential at depths of approximately 2,000 m to 4,000 m in the northern region and between 4,000 m to 6,000 m in the southern Dinarides area. In early November 2011 the government of the Federation of Bosnia and Herzegovina signed a Memorandum of Understanding with Shell to assess the country's hydrocarbon potential and develop a data room. According to Shell’s studies, the Dinarides area have oil particularly in the area of Gornja Dreznica. Oil was also identified near the Posavina enclave (north) and Majevica (northeast). Following Shell’s decision in October 2015 to put an end to its exploration project in the country, the local paper Dnevni Avaz announced that Croatian INA, Australian Key Petroleum, French Total and British Spectrum had sent letters of intent to the Federation between late October 2015 and mid-February 2016. The four blocks on offer: Block names Geological location Area (km2) Location (cities area) BiH D-1 The Dinarides  3,237 Mostar, Siroki Brijeg BiH Po-1 The Pannonian Basin  110 Odzak BiH Po-2 The Pannonian Basin  93 Orasje BiH Tz The Pannonian Basin  1,511 Tuzla

The government of the Federation of Bosnia and Herzegovina has launched the bidding round in which four blocks - BiH Po-1, BiH Po-2, BiH Tz and BiH D-1 – within the limits of the Federation are expected to be licenced. On 7 January 2020 the government published information relevant to the bidding round and the data room on its website, located here. The documents include an overview of the blocks, regulations, evaluation criteria, submission forms and an indicative timeline. The timeline states that the bidding round commenced on 1 October 2019, the deadline for bid submissions is 27 May 2020