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S-C part of Norte de Carcará block, Santos Basin, WD 2,052m, oil shows report to ANP on 26 Nov ’18, drilling continues. PTD 6,669m, target Barra Velha fm, West Saturn DS. Equinor (op), partners ExxonMobil + Galp.

Carcará W.-3 (3-EQNR-1-SPS) appr S-C part of Norte de Carcará block, Santos Basin, WD 2,052m, oil shows

On 17 September 2018 Zennor Petroleum announced that its subsidiary Zennor North Sea Limited has agreed to acquire Mitsui E&P UK Limited’s 8.97% interest in the Britannia field (P213, Block 16/26a Area B and P345 Block 16/27b Area B). The deal is key with regards to the developing Finlaggan field which will be a sub-sea tie-back to the Britannia platform. Also, in the 30th Round, Zennor acquired acreage nearby to Finlaggan and Britannia. Through the deal, Zennor will double its production to around 5,000 boe/d. Mitsui will retain the majority of the decommissioning liability up to the agreed cap with Zennor fitting the balance. The effective date of the transaction is 1 January 2018 and the deal requires regulatory approval. Zennor submitted its Environmental Statement for the development of the Finlaggan discovery in block 21/5c (P2013) in early 2018. The development for the field comprises a subsea manifold and two production wells tied back to the Britannia platform (in block 16/26) which is operated by ConocoPhillips. Zennor has an option to drill a third well, two to three years after first production but this will be dependent on how the reservoir performs but the initial plan just involves two development wells. Fluids will be processed on the Britannia platform and exported to shore via existing infrastructure. Peak production rates at Finlaggan are expected to be 80 MMcfg/d and 4,500 bc/d. The subsea infrastructure has a design life of 15 years and the field is expected to produce for 10 years. Zennor commenced drilling activities in Q3 2018. The wells will then be suspended until the subsea infrastructure is installed in 2020 with the project planned to come onstream in late 2020. Following completion of the deal interest in the Britannia field will be held by ConocoPhillips (UK) Ltd (40.6%), Chevron North Sea Ltd (32.28%) ConocoPhillips (UK) Theta Ltd (9.01%), Zennor North Sea Ltd (8.97%), ConocoPhillips Petroleum Co (UK) Ltd (7.23%), ConocoPhillips Ltd (1.81%).

Zennor Petroleum announced that its subsidiary Zennor North Sea Limited has agreed to acquire Mitsui E&P UK Limited’s 8.97% interest in the Britannia field (P213, Block 16/26a Area B and P345 Block 16/27b Area B).

Aker BP announced on 31 July 2018 that it will acquire a package of 11 licences from Total in a deal worth USD 205 million. The licences include four discoveries which lie close to existing Aker BP-operated producing fields, therefore adding a total of 83 MMboe (net) which can be developed through tie-backs (Alve North through the Skarv FPSO, Trell and Trine through the Alvheim FPSO and Rind as part of the future NOAKA project). There is further exploration acreage in the southern part of the North Sea close to Aker BP’s Ula field. The licences are: PL 026 (62.13%), PL 036 E (64%), PL 102 C, PL 102 D, PL 102 F and PL 102 G (40%), PL 127 and PL 127 B (50%), PL 127 C (100%), PL 906 (20%) and PL 907 (20%). Completion of the deal is subject to government approval. Alve North was discovered in 2011 by 6607/12-2 S. Gas and oil were present in the Middle and Lower Jurassic – the Fangst and Bat groups – and the Cretaceous Cromer Knoll Group and recoverable reserves are estimated at 44 MMboe (NPD, December 2017). Total drilled Trell exploration well 25/5-9 in 2014. A 21 m gross oil column was proven in the Paleocene Heimdal Formation and estimated recoverable reserves are 16 MMbo (NPD, December 2017). Trine was discovered in 1973 by Elf’s well 25/4-2. The Heimdal Formation contained a 9 m oil column and recoverable reserves are estimated at 24 MMbo (NPD, December 2017). Rind was previously known as Lille Froy and it was also discovered by Elf. Both 25/2-5 (discovery well, 1976) and 25/2-13 (appraisal, 1990) proved oil and gas in the Middle Jurassic Vestland Group and the Lower Jurassic Statfjord Formation. The NPD (December 2017) gives estimated recoverable reserves of 27 MMboe. Total currently operates all licences in the deal apart from PL 906 and PL 907 which are operated by Aker BP.

Aker BP announced on 31 July 2018 that it will acquire a package of 11 licences from Total in a deal worth USD 205 million. The licences include four discoveries which lie close to existing Aker BP-operated producing fields, therefore adding a total of 83 MMboe (net) which can be developed through tie-backs (Alve North through the Skarv FPSO, Trell and Trine through the Alvheim FPSO and Rind as part of the future NOAKA project).

PetroReconvavo signed with Petrobras for operatorship of the Riacho de Forquilla cluster of fields, onshore Potiguar Basin, which includes 34 prod. leases. The deal is pending ANP + CADE approvals and partner first right of refusal.  PetroRecônvavo will operate 30 blocks with 100% and partner Petrobras with 50% in two, and 70% in two others. The deal has a price tag of USD 384.2 MM.

PetroReconvavo acquired operatorship and the production rights to 34 prod. Leases of Riacho de Forquilla cluster of fields from Petrobras, for US$384 MM.

Wenchang 19-9-1d was suspended as a gas discovery on 3 May 2017 after having been spudded on or around 20 April 2017 using the Kantan 3" semi-sub. The exploration well was likely targeting the Late Oligocene to Early Miocene Zhujiang and Zhuhai formations. Wenchang 19-9-1d is in the CNOOC operated Yangjiang 31 Block in the offshore Pearl River Mouth Basin. <P />

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Parkmead has increased its operated interest in the Perth and Dolphin oil fields from 60.05% to 100%, presumably taking over remaining partner Faroe’s stake. The fields lie in P218, P588 and P2154 / blocks 15/21a, 15/21b, 15/21c, 15/21f and 14/25a in Central North Sea. Eventual devt would involve fracking. Discussions are also underway with Nexen to tie the 46.3 MMboe (2P) devt back to its Scott facilities, located 10km SE.

United Kingdom (Moray Firth Province) (It's a petroleum rights. Please summarize by yourself). In IHS database: Scott op. by NEXEN (41.89%, MOL 21.84%, KNOC 20.64%, EDISON I 10.47%, ROCKROSE 5.16%) to be check.

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

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

ExxonMobil is thought to be considering divestment of its German assets, according to media reports in January 2020. ExxonMobil has a number of exploration and production assets predominantly in the Niedersachsen region, NW Germany. The company holds acreage either through subsidiaries Mobil Erdgas-Erdol GmbH and ExxonMobil Production Deutschland GmbH or as part of the BEB Erdgas und Erdol GmbH 50/50 joint venture with Shell. Recently ExxonMobil drilled the successful Burgmoor Z5 NPW (2019, 3,500m) with Vermilion on the Dummersee-Uchte (zusammenl.) exploration concession, NW Germany. The well tested 8.8 MMcfg/d from a 38.1m net pay zone in the Permian Zechstein Carbonate reservoir at 3,357.1 - 3,436.9m depth, estimated to contain 50 Bcfg mean recoverable resources. ExxonMobil is also considering the sale of it North Sea assets in the UK and the Netherlands, plus its 50% operator stake in the Romanian Domino and Pelican South fields in the Black Sea. In 2017, ExxonMobil sold its operated Norwegian assets to HitecVision-owned Point Resources in 2017. Point Resources merged with Eni Norge to form Var Energi in 2018, which then bought the remaining non-operated ExxonMobil assets in September 2019.

ExxonMobil is thought to be considering divestment of its German assets, according to media reports in January 2020. ExxonMobil has a number of exploration and production assets predominantly in the Niedersachsen region, NW Germany.

Separate fault block north of the main Ebok field in OML 67, formerly designated Ebok North Deep, shallow waters of the SE Niger Delta / WD 41m, TD 2,794m,  52m gross oil pay in 2 reservoirs believed in same Tertiary sands equivalent to those in the main Ebok field, said to have addit. upside, Transocean Adriatic lX JU. Plans include applying the same methodology to OML 115 in which similar potential is thought to exist.

Ebok Deep North 1 (Oriental Energy 100%) in Ebok marginal field licence, oil discovery encountered 52m net oil pay in two reservoirs.

Sound Energy, the African and European focussed upstream gas company, has provided the Company's first volumes estimate of the exploration potential of the Sidi Moktar exploration permits in Central Morocco. The Sidi Moktar Permits cover 2,700 sq kms in the Essaouira basin, central Morocco and contain an existing gas discovery in the Lower Liassic ('Kechoula') and significant pre-salt potential.  Sidi Moktar is close to existing infrastructure and gas demand, including the large-scale Moroccan state owned OCP Phosphate plant.  The Company has recently successfully re-entered, completed, perforated and flared gas at surface from the Argovian reservoir (historically the main producing reservoir in the Kechoula discovery).  The Company will provide an update on the Argovian work programme shortly.  The Company recently commissioned Echo Geoscience Management ('EG') to undertake an independent preliminary technical evaluation of the available historical exploration well and 2D seismic data across the Sidi Moktar Permits area with a focus on the under-explored pre-salt plays beneath the Argovian reservoir (the 'EG Study').  The Company is pleased to report the results of the EG Study, which has significantly enhanced the Company's view of the exploration potential and confirms the substantial upside of this pre-salt play.  EG have defined and mapped a portfolio of 28 Liassic, Triassic and Paleozoic leads in a variety of hydrocarbon trap types across the Sidi Moktar Licences.  Much of the potential lies within 11 of the pre-salt Triassic and Paleozic leads ranging in size individually from 200 Bcf to 2.5 Tcf.  The EG Study highlights an exploration potential best case of 8.9 Tcf with an high of 11.2 Tcf and a low case of 6.7 Tcf, unrisked gas originally in place (gross).  The largest of the leads include the following unrisked gas originally in place (gross): The 'EG6' Lead (30km south-east of the producing Meskala gas field), a tilted fault block with estimated volumes of 2.5 Tcf best case, a 4.3 Tcf high case and a 0.9 Tcf low case. The 'EG3' Lead (40km east of Meskala gas field), a tilted fault block with estimated volumes of 1.1 Tcf best case, a 1.9 Tcf high case and a 0.4 Tcf low case.  The 'EG7' Lead (20km east of the Kechoula gas discovery), a well-defined four-way-dip closure with a 0.7 Tcf best case with a 1.3 Tcf high case and a 0.3 Tcf low case. The Company expects to shortly sign a new eight-year Exploration Permit for the Sidi Moktar Licences covering a larger area of 4,499 sq kms.  The Company expects to hold a 75% position in this renewed Exploration Permit with Morocco's Office National des Hydrocarbures et des Mines ('ONHYM') holding a 25% position.  After award the Company will commence the reprocessing of existing 2D seismic data and begin the acquisition a minimum of 500 kms of new 2D seismic data and undertake further geological studies in anticipation of high impact exploration drilling.  The work programme will be focussed to address the critical risks with the expectation of increasing the chance of geological success to greater than 30% prior to drilling.  Preparations for the new 2D seismic programme are already underway. The Company cautions that exploration in the oil and gas industry contains an element of risk and there can be no guarantee that its current estimates of volumes of gas originally in place will be substantiated. Notwithstanding the preliminary volumetric assessments of exploration potential across the Sidi Moktar Licences estimated by the EG Study, the Company requires further exploration activity, including the acquisition of additional seismic and further drilling activities to substantiate the exploration potential and the potential recoverable volumes. Original article link Source: Sound Energy

Morocco (Essaouira B.) Meskala

AE-0024-2M-Okom-07, offshore Sureste Basin, 5km NNE of Wayil discovery, susp. results n/a late Nov ’18, Prospector II JU. PTD was 4,950m, target Cretaceous.

Yok 1EXP in AE-0024-2M-Okom-07, offshore Sureste Basin, 5km NNE of Wayil discovery, susp. results n/a late Nov ’18, target Cretaceous

On 17 April 2018 press reports indicated that provincial operator, Petrominera, signed an agreement with Chilean national oil company, ENAP-Sipetrol, to cede its 88% interest to CAPSA, owned by the Gotz family of Argentina, in the 123 sq km Pampa del Castillo-La Guitarra license in the San Jorge Basin. Petrominera ceded as well 7% of its interest to CAPSA for an amount of US$ 2.575 million. The deal has to be approved by the Chubut legislature. Petrominera will keep 5% interest of the block. The new contract includes the US$ 195 million investment by CAPSA for future development of the field. ENAP is currently producing an average of 2.82 Mbo/d in this mature field block. CAPSA is interested in this block as it operates the also very mature Diadema license adjacent to the field. In 2015, the Chubut provincial government approved a 10 year extension of the Sipetrol contract for the Pampa del Castillo-La Guitarra concession. ENAP will now concentrate on its ambitious Magallanes Area Incremental Project (PIAM) platform on the offshore 368 sq km Magallanes Block, Austral Basin, where it has invested to increase production. If this deal is finally completed, CAPSA will hold 95% and Petrominera 5% interest on the Pampa del Castillo-La Guitarra license.

Argentina, Pampa del Castillo-La Guitarra

1st appraisal to 2017 oil find in Angostura Sur block, Austral Basin in TdF, TD 2,107m, compl. o&g (tested) at TD 2,107m late Aug ’18. Roch (op), partners Crown Point, San Enrique Petrolera, Desarrollo Petrolero Ganadero + Secra.

Argentina (Austral B.) Angostura Sur

Imetame suspended with oil and gas shows the 1-VID-1-ES (1-IMET-027-ES) new-field wildcat (NFW), Vida prospect, in the ES-T-487 block on 7 April 2020 at a total depth (TD) of 1,890 m. Imetame filed an oil and gas show report for the well with the ANP on 6 April 2020. Partner Petro-Victory issued a press release on 7 April 2020 indicating the well drilled a 49 m net oil pay reservoir in the target Sao Mateus Formation from 1,560 m to 1,660 m. Operator Imetame recovered 24 API oil to surface on a drill-stem test. The operator plans to conduct completion and testing operations by 3rd quarter after formal ANP approvals. Petro-Victory estimates the well results exceed its pre-drill estimates of 855 Mbo in mean recoverable resources. The NFW was spudded on 28 February 2020. The NFW has a proposed total depth (PTD) of 1,700 m and is speculated to be targeting the Early Cretaceous Sao Mateus Formation. The well is located in the south central area of the block 192 m south-east of the Petrobras 1-STZ-001-ES plugged and abandoned as non-commercial oil at a TD of 2,340 m in 1998. Imetame is operator of the ANP Round 14, ES-T-487 contract and holds 100% working interest.

Brazil (Espirito Santo Salt Sub-basin (Espirito Santo Bsn)) Sao Mateus

The Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) has announced the results of Call for Bids NL17-CFB01, located in the Jeanne d’Arc Region. The sole criterion for selecting a winning bid is the total amount the bidder commits to spend on exploration of the parcel during Period I (the first period of a nine-year licence). The minimum acceptable bid for each parcel is $10,000,000 in work commitments. Call for Bids NL17-CFB01 offered three parcels totaling 317,407 hectares. A successful bid was received for Parcel 1 (121 453 ha) for $15,098,888 in work commitments from Husky Oil Operations (50%) and BP Canada Energy Group (50%). No bids were received for Parcels 2 and 3. Subject to the bidder satisfying the requirements specified in Call for Bids NL17-CFB01 and upon receiving Ministerial approvals, the Board will issue the new exploration licence in January 2018. PDF Call for Bids NL17-CFB01 Parcels map Original article link Source: C-NLOPB

Canada, not found

Cairn announced on 15 November 2018 that is has agreed a deal to farm down a 40% interest in its licence P2312 (blocks 3/16a and 3/17a) which contains the Chimera prospect to Suncor Energy. Cairn held the interest in the licence under the subsidiary name of Nautical Petroleum. Chimera is a Paleocene Heimdal Turbidite target with a secondary objective of Eocene turbidites. It is thought to hold 154 MMboe recoverable resources. The deal completed on 19 December 2018. Licence P2312 was awarded in the 29th Frontier Licensing Round in 2016. The licence covers an area of approximately 220 sq km. The nearest discovery is 3/17-2 (Tryfan) located roughly 3 km to the east. Interest in the licence is now held by Cairn subsidiary Nautical Petroleum Limited (60% + operator) and Suncor Energy UK Limited (40%).

United Kingdom, P2312

Shale gas strat well in 4/2018/p Gora block, Fore-Sudetic Monocline in SW Poland, TD 3,250m in early 2012 (San Leon), frac job over 3,413-3,414m and 3,272-3,273m in the Carboniferous, now recovering fracture fluid ahead of tests per se. Testing of the Siciny-2 is part of Ansila 35% farmin obligation from Gemini Res.

Siciny-2 strat Shale gas strat well in 4/2018/p Gora block, Fore-Sudetic Monocline in SW Poland, TD 3,250m in early 2012 (San Leon), frac job over 3,413-3,414m and 3,272-3,273m in the Carboniferous, now recovering fracture fluid ahead of tests per se. Testing of the Siciny-2 is part of Ansila 35% farmin obligation from Gemini Res.

Phoenix has reportedly disposed of its Colombian interests in order to focus on the Vaca Muerta in Argentina. Involved is a 70% interest in 8 blocks, buyer and value not revealed.  Another 70% in 3 permits is not part of this sale as the blocks are under a relinquishment process.

Phoenix has reportedly disposed of its Colombian interests in order to focus on the Vaca Muerta in Argentina. Involved is a 70% interest in 8 blocks, buyer and value not revealed.

Add. DEA 18 Nov + 6 Dec '19: Committed well in W-C part of AE-0008-4M-Amoca-Yaxche-06 block, offshore Sureste Basin, WD 26m, earlier reported suspended, then P&A dry and now an oil discovery, TMD 2,063m (TVD 1,890m) on 7 Oct '19, Independencia I JU. Target U. Miocene.

Itta 1EXP nfw (Pemex 100%), commitment well in W-C part of AE-0008-4M-Amoca-Yaxche-06 block, offshore, WD 26m, earlier reported suspended, then P&A dry and now an oil discovery, TMD 2,063m (TVD 1,890m), Target U. Miocene.

In February 2020, ORLEN Upstream Sp. z o.o. was awarded the 2/2020/L Debrzno – Czluchów contract in northern Poland. The 1,159 sq km Debrzno – Czluchów permit is located approximately 130 km southwest of the city of Gdansk. In a geological sense, the tract is spanning the limit of the Northeast German-Polish Basin and the Danish-Polish Marginal Trough. The potential reservoirs in the area include the Devonian and Permian (Zechstein) series, developed in the carbonate facies. The award is the result of the country’s 2018 tender call (Round 2) that closed on 7 August 2018. Background Information The Ministry of the Environment approved list of ten areas selected for offering in the 2017 tender call (Round 2) for prospection, exploration and exploitation of hydrocarbons on 29 June 2016. In the late 2017, following amendments, the areas Bzie – Debina – Strumien (76 sq km) and Ustronie N (1,163 sq km) had been removed from the offer. The catalogue of the areas on offer in the Round 2 was as follows: Bochnia (234 sq km), Damnica (1,038 sq km), Debrzno – Czluchów (1,159 sq km), Koszalin – Polanów (1,111 sq km), Sucha Beskidzka-Wisniowa (983 sq km), Szamotuly – Poznan Pólnoc (1,138 sq km), Zlotów - Zabartowo (1,070 sq km), Zarnowiec (1,121 sq km). On 8 May 2018, MoE published the notes 2018/C 163/01 through 2018/C 163/08 in the EU Official Journal, thus opening the tender calls for the respective selected areas. Bids were to be submitted to the headquarters of the Ministry of the Environment no later than on the last day of the 91-day period commencing on the day following the date of publication of the notice in the EU Official Journal. The tender closed on 7 August 2018. News from early October 2018 stated that ORLEN Upstream Sp. z o.o. applied for the Debrzno – Czluchów area. The application of ORLEN Upstream was in competition with an offer lodged by Polskie Gornictwo Naftowe i Gazownictwo (PGNiG).

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

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

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

As of 20 July 2020, Olympic Peru continues to look for partners in the onshore Block XIII A located in the Talara Basin. The block has been available for farm-out since 2010. Multiple wells have been drilled on the block by various operators over time. A table showing exploration drilling over time is provided below. Historical Exploration Drilling on Block XIII A         Operator Well Name Spud Date Completion Td Feet Td Meter Status Olympic Peru Inc Colan 139X 25-Oct-18 19-Apr-20 3,273 998 P&A dry Petroperu SA Paita 1 9-Jan-54 20-Jan-54 1,282 391 P&A dry Petroperu SA Paita 3 4-Jul-54 27-Jul-54 3,919 1,195 P&A dry Petroperu SA Paita 4 28-Oct-54 13-Nov-54 2,776 846 P&A dry Texas Petr Peoco 3-2 1-Feb-56 20-Mar-56 2,560 780 P&A dry Belco Petr Peoco 7-1 7-Dec-55 16-Mar-56 5,944 1,812 P&A oil shows Gulf Oil Corp PG-39-X 1 12-May-56 1-Jul-56 4,303 1,312 P&A dry Source: IHS Markit           © 2020 IHS Markit   Geology The north-east - south-west Talara Basin straddles the north-west Peru Pacific coastline approximately on either side of Talara, a city located at about its center and after which it is named. Its onshore part extends westwards from the Andean foothills to the marine continental platform, off Zorritos on the north to the Paita area on the south. The Talara Basin has a complex structure that reflects its complex tectonic evolution. Its north part and the adjacent Progreso (Tumbes) Basin are regionally tilted to the west. The basin is characterized by a very high density of normal and gravity-slide faults occurring a few meters to about 1 km apart, and development of roll-over structures. Strike-slip, reverse, and thrust faults also occur, the latter with detachment surfaces largely within the Paleozoic, but also within the Eocene section. Faulting is more intense onshore and in the offshore proximal, shallow platform (200 m or less water-depth). Faulting began with the onset of the Andean orogeny and persisted throughout the Tertiary, producing a complexly block-faulted basin, largely filled with Eocene terrigenous clastics deposits. (except from the IHS Markit Basin Monitor)

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

Early Jan ’19 well in E-C part of REC-T-128, Recôncavo onshore, TD 2,570m, tested 300 b/d of 34 API oil, LT tests planned. Targets Agua Grande + Sergi fm’s. GeoPark (op), partner Geopar – Geosol Participações.

1-PRC-001D-BA (1-GPK-004D-BA, Praia dos Castelhanos) (GeoPark 70% op, Geopar – Geosol Participações 30%) in E-C part of REC-T-128 block, TD=2570m, tested 300 b/d of 34 API oil, LT tests planned. Targets Agua Grande + Sergi fm’s.

63/94 Pruchnik-Pantalowice contract, enclaved within block 21/2001/p Zalesie-Jodlowka-Skopow, Outer Carpathian Foredeep in SE Poland, TD 1,969m (Precambrian), compl. gas (Miocene sst) after testing.

Pruchnik-37K appr 63/94 Pruchnik-Pantalowice contract, enclaved within block 21/2001/p Zalesie-Jodlowka-Skopow, Outer Carpathian Foredeep in SE Poland, TD 1,969m (Precambrian), compl. gas (Miocene sst) after testing.

It is understood that Turkiye Petrolleri A.O. (TPAO) has suspended the Narlikuyu 1 new field wildcat (NFW) offshore well in the block P32 of O33,P32,P33 exploration licence in the eastern Mediterranean Sea using early April 2020. The well, located at around 700 m water depth and approximately 45 km from the coastal city of Silifke, was spudded in February 2020 using the Fatih drillship. The O33,P32,P33 licence, covering an area of 3,728 sq km, was exclusively awarded to TPAO in April 2017.

Narlikuyu 1 nfw. in P32 of O33,P32,P33 licence, in E. Mediterranean, WD=700m off Silifke, ops concluded/suspended, results are not yet available.

IOR-7, onshore Pyay Embayment (Central Burma), P&A dry at TD ca. 2,500m+ in late Jan ’19, Elite Drilling rig. Targets believed Pyawbwe, Kyaukkok + Obogon fm’s. A 2nd well is tentatively planned from the same drillpad + testing if applicable. Petronas (op), partners PetroBrunei + UNOG.

Myanmar (Pyay Embayment (Central Burma B.)) Pyay

On 18 December 2017 partner Ecopetrol announced success in the Coyote 1 well located on the Parex Resource-operated De Mars Block of the Middle Magdalena Basin. The well encountered oil at multiple intervals totalling some 29 m (95 ft) a depth between 2,042 m (6,699 ft) to 2,177 m (7,142 ft). Ecopetrol and Parex are equal partners on the acreage. Background information On 27 April 2016 Parex Resoures announced it executed a farm-in agreement with Ecopetrol SA for the De Mares Block in the Middle Magdalena Basin. Subject to Agencia Nacional de Hidrocarburos (ANH) approval, Parex will operate and earn 50% working interest (WI) in the De Mares and nearby Playon blocks. Terms of the De Mares Block deal include Parex’s commitment to workover the Coyote 1 well and fund 100% of the costs, estimated at USD 3 million. Upon regulatory approval, the re-completion operations will commence. Following the Coyote workover, Parex will pay all costs associated with one additional exploration well, should the partners decide to continue their efforts on the acreage. Parex must complete these farm-in obligations by April 2018. The Coyote 1 stratigraphic test was drilled in 2012 and encountered oil in the Esmeraldes/La Paz Formation between a depth of 6,700 and 7,200 ft. It is the only well drilled on the block and tested low rates of 22° API gravity oil. The 706 sq km De Mares Block is located east of the La Cira-Infantes field which has produced some 850 MMbo to date. In September 2015, Parex announced another farm-in agreement with Ecopetrol for the Aguas Blancas light oil field located south of the La Cira-Infantes field. Aguas Blancas terms include USD 61 million in appraisal work for Parex to earn 50% WI and operatorship. The Aguas Blancas field is located on the Magdalena Medio contract of the Middle Magdalena Basin.  

Colombia (Llanos-Barinas B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: B op. by PERENCO (12.5791572199%, ECOPETROL 65.6008130717%, HOCOL 21.8200297084%) to be check.Aguas Blancas op. by PAREX (50.0%, ECOPETROL 50.0%) to be check.Magdalena Medio op. by ECOPETROL (100.0%) to be check.Playon (Prod) op. by PAREX (50.0%, ECOPETROL 50.0%) to be check.Playon op. by PAREX (50.0%, ECOPETROL 50.0%) to be check.De Mares op. by PAREX (50.0%, ECOPETROL 50.0%) to be check.

Gobernador Ayala block Neuquén Basin, compl. oil at TD 720m, tested 197 bo/d from the Centenario fm during Sep ‘18. Pluspetrol (op), partners YPF + Petr. Santa Fe.

Jaguel Casa de Piedra Sur-1008 appr Gobernador Ayala block Neuquén Basin, compl. oil at TD 720m, tested 197 bo/d from the Centenario fm

The CNPE has mandated ANP to organise the country's 17th and 18th rounds for exploratory areas in 2020 + 2021. The 17th will feature deepwater areas outside the pre-salt polygon in the Campos and Santos basins, and the Pará-Maranhão, Pelotas and Potiguar basins. The 18th is looking at more deepwater areas outside the pre-salt polygon in the Espírito Santo, and acreage in the Ceará and Pelotas basins.

The CNPE has mandated ANP to organise the country's 17th and 18th rounds for exploratory areas in 2020 + 2021. The 17th will feature deepwater areas outside the pre-salt polygon in the Campos and Santos basins, and the Pará-Maranhão, Pelotas and Potiguar basins. The 18th is looking at more deepwater areas outside the pre-salt polygon in the Espírito Santo, and acreage in the Ceará and Pelotas basins.

Tri-Star Petroleum Co acquired full interest from Senex Energy subsidiary Stuart Petroleum Pty Ltd in exploration licences PEL 288, PEL 289, PEL 290 and PEL 331, located in the Cooper-Eromanga Basin, on 14 February 2018.  Stuart Petroleum previously held 100% interest and operatorship, all of which has been transferred to Tri-Star. The licences cover a combined area of 33,105 sq km and were all awarded on 1 June 2013.  No wells have yet been drilled within the licence’s validity, but a number of historical wells lie within the licence areas.

Australia, PEL 331

Caspian Sunrise has signed a non-binding contract to sell its 99% interest in the Munayli dormant field / contract area, onshore S. Precaspian Basin. The deal has a nominal value, buyer not revealed.

Caspian Sunrise has signed a non-binding contract to sell its 99% interest in the Munayli dormant field / contract area, onshore S. Precaspian Basin. The deal has a nominal value, buyer not revealed.

On 28 October 2019, the Ministry for Natural Resources published a list of exploratory licenses available for investors in 2019 without auctions. The list includes 14 blocks covering 7,529 sq km in Western Siberia and Volga-Urals (Table 1). Total hydrocarbon resources are estimated at 743 MMbbl of oil and 1.477 Tcf of gas. Applications must be submitted by 9 December 2019. If any block receives more than one valid application, the block will be withdrawn from the list and could be offered through an auction. Table 1         Resources   Petroleum Province Political Block Surface, Oil, Gas, Contact Information Province sq km MMbbl Bcf Volga-Urals Volgograd Obl Ilovatskiy 622 88 14 400001, Volgograd, Profsoyuznaya Str., 30     Tersinskiy Yuzhnyy 1,482 66 308     Perm Kray Zagorskiy 1,026 20 17 614000, Perm, Kamchatovskaya Str., 5     Gumentsovskiy 33 5       Sverdlovsk Obl Mikhaylovskiy 1,237   1,138 620014, Yekaterinburg, Vaynera Str., 55 Western Siberia Kurgan Obl Priloginskiy 202 640000, Kurgan, Kuybysheva Str., 12, of.209     Privolnyy Yuzhnyy 133         Khanty-Mansiysk AO Varyngskiy Vostochnyy 484 107 628012, Khanty-Mansiysk, Studencheskaya Str., 2   Karabashskiy 61 521 57     Koltogorskiy 5 440 101     Khorlorskiy Severnyy 113 33     Snegirinnyy 3 465 99     Urmannyy 313 87       Khangokurtskiy 4 458 80

On 28 October 2019, the Ministry for Natural Resources published a list of exploratory licenses available for investors in 2019 without auctions. The list includes 14 blocks covering 7,529 sq km in Western Siberia and Volga-Urals

N-C part of PN-T-048 block, BT-PN-004 contract, onshore Parnaíba Basin, spudded 21 Jul ’19, en route to PTD 2,215m, gas shows report to ANP on 9 August. Target Cabeças + Poti fm’s, GWDC rig 120.

4-ENV-SWPGN1-MA (4-ENV-006-MA) npw -C part of PN-T-048 block, BT-PN-004 contract, onshore Parnaíba Basin, spudded 21 Jul ’19, en route to PTD 2,215m, gas shows report to ANP on 9 August. Target Cabeças + Poti fm’s,

Absheron Garbi oilfield in Caspian Sea, one-month well to TD 770m (Kirmaku fm), ops terminated 20 Jul ’19.

Azerbaijan, Absheron

On 3 October 2018 Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd had signed a Heads of Agreement with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.667% interest each in PEDL 183. On 5 November 2018 in an update from Union Jack Oil, the company confirmed that it has now signed a farm-in agreement for the deal. The licence is located in East Yorkshire and contains the West Newton A-1 gas discovery. There are also plans to drill the West Newton B appraisal well in Q1 2019. The deal is subject to regulatory approval. West Newton B will be located approximately 1.5 km south of the 2013 West Newton well. It is planned to target three potential Permian reservoirs in the Brotheran, Kirkham Abbey and Cadeby formations. The well has a planned TD of 2,000 m to the base of the Permian section. It was initially planned to be drilled with the KCA Deutag T-61 rig. In November 2017 Rathlin confirmed that it still plans to drill the well and in December the company stated that it is currently out to assess and determine rig availability. Drilling is planned to take 6 - 12 weeks where the company is not planning to test any shale horizons (TD likely to be 1,000 m above the Bowland Shale) estimated to be deeper than its Permian targets. It is hoped that the well will determine the commerciality of the discovery. In an update from the company on 17 June 2015 it confirmed that East Riding of Yorkshire Council has granted planning permission for the well. On 26 November 2015 Rathlin announced that it was pleased that the planning committee has unanimously approved the planning application for an extension at West Newton A. Following the well encountering gas the company can move forward with investigating the commerciality of the discovery within the Permian Kirkham Abbey Formation. On 26 July 2016 the OGA confirmed that the Environment Agency has granted a permit for the drilling of the well. In 2013 Rathlin Energy drilled with West Newton 1 (A) well. The well was drilled to a TD of 3,150 m into the Dinantian Carbonate section in the Carboniferous and was tested. The well was located north of West Newton and east of Marton in the parish of Aldbrough, East Riding Yorkshire. It had a primary target based from 2D mapping and is a Permian aged Caedby Carbonate reef. The source rock potential is present within the Permian basinal sediments, the Westphalian coal measures and the Bowland shale sequence. PEDL 183 was awarded in the 13th Onshore Licensing Round and covers an area of 913 sq km. Interest in the licence following the deal will be held by Rathin Energy (66.666% + operator), Humber Oil and Gas (16.667%) and Union Jack Oil Plc (16.667%).

Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd had signed a Heads of Agreement with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.667% interest each in PEDL 183

Coirón block, onshore Magallanes Basin, P&A (disappointing testing) Dec '19, TD n/a. Target unconventional Zona Glauconitica tight gas. ENAP (op), partner ConocoPhillips.

Chile, not found

Lundin used the “Leiv Eiriksson” S/S to spud exploration well 16/1-31 S targeting the Jorvik prospect in PL 338 on 10 March 2019. The objective was the Jorvik conglomerate. The company drilled to TD at 2,220 m and the well was plugged back on 10 May 2019. The following day Lundin kicked-off exploration sidetrack 16/1-31 A targeting the Tellus East prospect (weathered and fractured Basement with a potential sandstone drape) and on 18 June 2019 it was plugging and abandoning. As it was not possible to target both with a single well, the two wells were being drilled in a Y formation. The top hole is located approximately 4 km northwest of the Edvard Grieg platform, between the Edvard Grieg and Ragnarrock fields. On 20 June 2019 Lundin announced that oil was discovered in both wells with the combined estimated resources between 4 and 37 MMboe. The Jorvik branch confirmed oil in 30 m of Triassic conglomerate reservoir and in the overlying thin high quality sandstone. Well testing of the conglomerate produced results of 130 bo/d and indicated communication with the Edvard Grieg field.  The Tellus East branch encountered a 60 m gross oil column in porous, weathered basement reservoir likened to producing layers in the Tellus area of the Edvard Grieg field. Both wells have the potential to be developed from the Edvard Grieg platform and will be evaluated with other infill targets and tie-in opportunities. In 2013 Lundin drilled the first well on the Jorvik prospect which lies immediately east of Edvard Grieg and is a continuation of the same play onto the Haugaland High. 16/1-17 proved mobile oil, but the reservoir (pre-Jurassic conglomerate and pebbly sandstone) was tight with haematite cementation. Potential reserves were estimated at 46 MMboe (in PL 338) prior to drilling. Tellus was drilled in early 2011, just to the north of Edvard Grieg. 16/1-15 made a new discovery in the Lower Cretaceous/Basement with potential reserves (given at the time) of 11-55 MMboe. The field was developed as part of Edvard Grieg and the reserves are now included in the overall field volumes. The completion of drilling of the 14 development wells at Lundin’s Edvard Grieg field was achieved in July 2018. The results exceeded pre-drill expectations and there is no material water production. Earlier in 2018 Lundin announced a reserves increase of 51 MMboe (since the end of 2016) to 274 MMboe, representing a 47% increase compared with the PDO. Good drilling results and production performance indicated that the oil in place volumes were higher than originally calculated and that more of the oil is in the better quality sandstone part of the reservoir (with less in the poorer quality conglomerate zone). The field was producing at a facilities-capacity rate of 95,000 boe/d in July 2018 but double this rate is actually possible. The nearby Lundin-operated Solveig (Luno II) and Rolvsnes discoveries will be tied-back to Edvard Grieg and the 2018 discovery made by Equinor at Lille Prinsen could also potentially be tied-in. Lundin Norway AS operates PL 338 with a 65% interest. It is partnered by OMV (Norge) AS (20%) and Wintershall Dea through Wintershall Norge AS (15%).

016/01-31S (Jorvik) 31A (Tellus Øst) near Edvard Grieg, appr. (Lundin 65 op, OMV 20%, Wintershall 15%) in PL 338, 31S - tested 130 bo/d from a similar 30m of Triassic conglomerate reservoir with a thin, high quality sst. in communication to Edvard Grieg. Horiz well required for prod. 31A - 60m oil column in porous, weathered basement reservoir.

On 10 July 2019 the Republica Dominicana’s Ministerio de Energia y Minas (MEM) unveiled in Houston, the 14 blocks offered in the Dominican Republic 1st Licensing Round – 10 Onshore and four offshore. Publication of qualified companies will be on 8 November 2019, with winners announcement on 27 November 2019. The Production Sharing Contract (PSC) model will be used in the round, which is will conclude in December 2019. The exploration period for onshore is eight years, and for offshore 10-years. Below the list of the blocks offered:   Basin Blocks Seismic Wells Drilled Prospectivity Cibao CB1 ~630 km 2D 16 - MD 1,000-12,000 ft Four wells with gas shows, Two oil seeps CB2 At least three plays in the basin CB3 Several potential prospects CB4 CB5 CB6   Enriquillo EN1 ~1,000 km 2D Nine wells - MD 500-15,800 ft Nine wells drilled EN2 Basin with the most seismic coverage on the island EN3 At least three plays in the basin   Several undrilled prospects identified Azua AZ1 ~40 km 2D 58 wells  - MD 300-13,000 ft Proved petroleum system with two existing fields - Maleno and Higuerito At least three plays in the basin   Several oil seeps in the central part of the basin San Pedro de Macoris SP1 ~1,900 km 2D Three wells Proved petroleum system with oil shows in the onshore part of the basin SP2 At least three plays in the basin SP3 San Pedro -1, showed paraffin and light oil with 30° API SP4     Below MEM’s issued timeline: MEM - Timeline In June 2019 MEM officially announced its plans for the country’s first bid round with 14 blocks. The onshore blocks are located - Cibao Basin: Six Enriquillo Basin: 3, and Azua Basin: 1. Four blocks will be offer offshore in the San Pedro Basin. The Roadshow will take place in Houston on 10 July 2019. The Base Nacional de Datos de Hidrocarburos (BNDH), the national digital archive which contains geological and geophysical information for the country starting in 1903 till 2013 was developed by a third party and presented in 2016. It has 21,500 km of seismic lines, 1,490 maps and plans, 805 seismic profiles, 212 wells – which the ministry estimates it has an acquisition cost of USD 145 million. The MEM identified six potential zones for hydrocarbons, the basins: Enriquillo, Azua, San Juan, San Pedro de Macoris, Ocoa and Cibao Oriental. Background Information In early December 2018 the Minister of Energy and Mines signed USD 1.07 million contract with a consulting company for the evaluation, planning, promotion and execution of a Bid Round for the exploration and exploitation of hydrocarbons. The tender to hire consulting services was first announced in May 2018, with nine companies from five countries presenting proposals -  “The country has to make the leap to reduce its dependence on oil imports in all ways and one of the most important is to promote the exploration and exploitation of hydrocarbons, especially gas, both for its economic and environmental benefits”, said the Minister Antonio Isa Conde. The Minister of MEM Antonio Isa Conde presented in late August 2018 the “Informes de Trabajos 2014-2018”, which reports the work that has been done since the creation of the ministry in 2013.  The first hydrocarbon exploration and exploitation regulation were issued in 2016 through the decrees 83-16. The contract for exploration and production of hydrocarbons was issued in early May 2018. According to the contract, the exploration period of the contracted area may be up to six (6) years following the signing of the contract and may be extended for up to four (4) additional one-year periods. Modification of this term and its extensions shall be authorized by decree. The exploitation period of the Contracted Area may be for up to twenty (20) years and a maximum of two (2), five-year extensions each. The first extension may be requested upon reaching seventy-five percent (75%) of. the term of the contract granting the rights for the exploration and exploitation of Hydrocarbons, Oil Reservoirs or other Hydrocarbon substances, while the second extension may be requested when fifty percent (50%) of the term of the first one has elapsed. Background Information In early June 2011, no additional information had been received concerning a possible bid round in 2011. In September 2010, the Industry and Trade Industry's Mining Department director, Octavio Taveras, announced that the Dominican Republic planned to launch an international oil exploration round in 2011. The announcement follows reports of a new oil seep in Higuey, La Altagracia province in the eastern part of the country. GHGeochem in the UK analyzed samples and reported that the oil seep is better quality than that found in Azua province. An assistance agreement is being finalized with MDOIL whereby the company will help characterize potential hydrocarbon bearing sedimentary basins in the country including the exclusive economic zone. The declaration follows a late 2009 announcement made by the department that Madrid's Complutense University found traces of natural gas in marine sediments in an area known as the Muertos Trough offshore. The Directorate is waiting for authorization from the president to sign a contract with MDOIL which hopes to expand the study to include all the basins in the country and to correlate them with the previous data. In early September 2010, there were no tenders planned for oil and gas exploration. Interested companies can approach the ministry directly concerning any of the seven identified basins. The onshore areas that have been outlined as potential opportunities are in Bahoruco, Samana, Azua and Maria Trinidad Sanchez provinces, and offshore in Ocoa and Samana Bays and Banco de la Plata. However, the country's 1958 hydrocarbons law must be updated as the regulatory framework is not clearly defined and does not attract investors.

On 10 July 2019 the Republica Dominicana’s Ministerio de Energia y Minas (MEM) unveiled in Houston, the 14 blocks offered in the Dominican Republic 1st Licensing Round – 10 Onshore and four offshore. Publication of qualified companies will be on 8 November 2019, with winners announcement on 27 November 2019.

SE part of Stabroek block, E. of Pluma discovery, WD 1,399m, TD 5,575m, ab. 63m of high quality, gas-condensate sst reservoir, Stena Carron DS to return to the Longtail discovery to complete a well test. ExxonMobil (op), partners Hess + CNOOCI.

Haimara 1 (located, about 31km east of the recent Pluma 1 discovery) (ExxonMobil 45% op, Hess 30%, CNOOC-Nexen 25%) in the SE of the Stabroek block, encountered about 63m of high-quality, gas condensate-bearing sandstone reservoir.

On 2 December 2017, it was announced that Enpet Enerji ve Petrol Ticaret Ltd Sti (Enpet) had been awarded the G26-A exploration licence on 22 November 2017. The licence was granted with a five year term and covers a total area of 585 sq km in the Western Pontides. Enpet is 100% owner and operator of the licences.

Turkey (Pontides) (It's a petroleum rights. Please summarize by yourself). In IHS database: G26-A op. by ENPET (100.0%) to be check.

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

UAE, not found

On 25 March 2020 Perenco completed the acquisition of interest from BP in a number of blocks across the following licences in the Southern North Sea - P001, P133, P138, P016, P024, P028, P030, P302, P380, P005 and P050. A complete list of interest exchanged is in the table below. All of the blocks involved were classed as 'Carboniferous Areas' by the OGA. The deal is in line with BP's planned programme to divest USD 10 billion worth of assets by the end of 2020. The major is in the process of reshaping its portfolio in the North Sea and is concentrating on the core hubs of Clair, Quad 204 and ETAP. Asset Percent Seller Buyer Date completed P001                                            048/06a Hyde Field (CA)                                          048/06a Rest of Block Excluding Hyde (CA)                           042/30a All (CA)                                                042/29a Cleeton Subarea Inc Cleeton Field (CA)                    042/29a Neptune Area (CA)                                     042/29a Ravenspurn (CA)                                       047/10b Hyde Field (CA)                                           047/010b Rest of Block Excluded Hyde and Disc (Rest) (CA)          90% BP Perenco 25-03-20 P133 047/15a Amethyst Field (CA) 047/15a Rest of Block (CA) 75% 90% P138 048/07b (CA) 90% P016 047/03b (CA) 58.50% P024 048/07a (CA) 90% P028 047/05a Hyde (CA) 047/05a (Rest1) (CA) 047/05a (Rest2) (CA) & 047/05c Neptune (CA) 047/04a (CA) 047/05c Rest of Block (CA) 90% 58.5% 16.85% P030 047/09a (CA) 047/08a (CA) 69.23077% P302 047/03c (CA) 047/04c (CA) 047/04b Rest of Block SW (E) (CA) 047/04b Rest of Block NE (CA) 047/04b Neptune Field Area C (CA) 047/09b (CA) 58.55% 90% 65.997% P005 047/14a (CA) 75.6% P050 047/13a (CA) 90% P380 043/26a Ravenspurn North (CA) 90.00%

United Kingdom, P138

On 16 October 2018 the Directorate of Energy, Mines and Industrial Administration awarded the adjacent Landarre (373 sq km), Lore (373 sq km) and Sustraia (560 sq km) exploration licences to Ente Vasco de la Energia (EVE) and HEYCO, effective 17 October 2018. The Basque Country licences have been granted for an initial six year period with the option to drill an exploratory well, dependent on environmental approval, in the final year. The applications were published on 27 July 2011 and included the Lurra block, however a request to withdraw the Lurra application was made on 24 May 2018. Landarre, Lore and Sustraia partners are Ente Vasco de la Energia (EVE) through subsidiary Sociedad De Hidrocarburos De Euskadi SA (SHESA) (50% + Op) and partner HEYCO Energy Group Inc through subsidiary Petrichor Euskadi (50%).

EVE (Ente Vasco de la Energia) op. and HEYCO (50/50) awarded the adjacent Landarre (373 sq km), Lore (373 sq km) and Sustraia (560 sq km) exploration licences.

Central Petroleum Ltd closed the deal to bring in Incitec Pivot Ltd to exploration permit ATP 2031-P. Incitec Pivot Queensland Gas Pty Ltd acquired 50% interest in the permit on 7 December 2018. The two companies entered a memorandum of understanding (MoU), when Central Petroleum was awarded the Taroom Trough permit, on 27 August 2018. Under the MoU, which was announced on 25 June 2018.  Incitec had a period of exclusivity in which to discuss commercial opportunities for the acreage.  For Incitec to enter a 50:50 joint venture, it is expected to fund up to AUD 20 million of an exploration campaign within the acreage which is expected to start in 2019. Incitec operates the Gibson Island facility in Brisbane which manufactures fertilizers. Incitec has reported that the impact of increasing costs of natural gas supply to the Australian East Cost could be as high as AUD 50 million through 2019 resulting in future uncertainties for the facility. Closure costs of the facility are estimated at around AUD 70 million. Incitec has entered ATP 2031-P to source economic gas for supply to the Gibson Island manufacturing facility. Short term gas supply arrangements expired on 31 December 2019. ATP 2031-P was awarded for a period of 12 years and will expire, or be eligible for renewal, on 26 August 2030. Under the terms of the award, if a subsequent petroleum lease is granted over the permit area, any gas produced must be solely for the Australian domestic market. There is scope under the farm-in agreement for gas produced to be supplied to Incitec’s Gibson Island fertiliser facility. The block was offered as PLR201718-1-1 alongside one other block in the 2017 Queensland State Acreage Release, which was open between September and December 2017. Central announced that it was preferred tendered for the block on 1 March 2018 and was subsequently awarded ATP 2031-P for nil consideration after the finalization of native title agreements. ATP 2031-P, which covers an area of 77 sq km, was awarded to Central Petroleum on 27 August 2018. Central Petroleum has now completed a farm-down of 50% interest to Incitec Pivot Queensland Gas Pty Ltd.

Central Petroleum Ltd closed the deal to bring in Incitec Pivot Ltd to exploration permit ATP 2031-P. Incitec Pivot Queensland Gas Pty Ltd acquired 50% interest in the permit

ConocoPhillips has successfully tested oil in exploration well Tinmiaq 8, a vertical borehole designed to appraise the recent 300 MMbo Willow discovery. The Tinmiaq 7 well was drilled to a final TD of 1,262m in lease AA092673, according to reports in April 2018. The well forms part of a six-well programme, All of which have encountered oil, with reportedly "encouraging" results having been gleamed from related flow tests. In mid-January 2017, ConocoPhillips indicated that the Willow discovery had been made in the federal National Petroleum Reserve-Alaska (NPR-A), with oil encountered in both the Tinmiaq 2 and Tinmiaq 6 exploration wells. The discovery was made in the Brookian Nanushuk Formation, the same formation in which Armstrong Energy and Repsol recently began developing a discovery in the Pikka Unit, estimated to be able to produce 120,000 bbls/d. The Tinmiaq 2 well sustained a 12-hour test rate of 3,200 bo/d. Consequently, ConocoPhillips expects the recoverable potential of the resource to be over 300 MMbo. Appraisal began in January 2017 and a 3D seismic survey is currently being acquired over the area. The Willow Field could produce up to 100 Mbbls/d, with commercial production potentially starting as early as 2023. Tinmiaq 2 and 6 are located in NPR-A leases AA00081807 and AA00081808 respectively, part of the GMT Unit. The GMT Unit is operated by ConocoPhillips Alaska (78% WI + Op), with Anadarko Petroleum holding a 22% interest.

Not Found

ADNOC has assigned Total a 40% stake in the Ruwais Diyab unconventional gas block in which Total will explore, appraise + develop those resources. ADNOC retains a 60% stake in the block, which calls for a 6-7 year explo/appr phase + 40 years production. This is the first of its kind in the region. It is recalled that earlier this year Total also was assigned interests in the Umm Shaif, Nasr + Lower Zakum (conventional) blocks.

ADNOC has assigned Total a 40% stake in the Ruwais Diyab unconventional gas block in which Total will explore, appraise + develop those resources. ADNOC retains a 60% stake in the block.

On 12 July 2018, it was announced that Turkiye Petrolleri A.O. (TPAO) had been awarded the M42-B2,B3,B4 exploration licence on 5 July 2018. The licence has been granted a five year term with an expiry date of 5 July 2023. It covers a total area of 458 sq km in the Southeast Turkey Zagros Fold Belt. TPAO will be 100% owner and operator of the licence.

Turkey, M42-B2,B3,B4TPAO (100%) had been awarded the M42-B2,B3,B4 exploration licence

Wintershall Dea GmbH disclosed on 9 January 2020 it had entered into an agreement with RDG GmbH & Co. KG (RDG) for the purpose of selling interests in several production contracts in the country's various petroleum provinces. The catalogue of the assets is as follows (working interest in bracket): 1) Aitingen (33.33%), 2) Hebertshausen (100%), 3) Landau (66.67%), 4) Lauben/Bedernau (50%), 5) Schwabmuenchen (100%), 6) Suderbruch (100%) and 7) Tannheim/Engelsberg (50%). The licenses sold to RDG yield approximately 1,000 boe/d, some 2% of the company's daily output in Germany. The Wintershall Dea's move follows a global revision of the domestic asset portfolio and a strategic decision to concentrate on the core assets, i.e. oil production from the Emlichheim and Mittelplate fields and gas production in the Verden area (all in northern Germany). The Aitingen, Hebertshausen, Lauben/Bedernau, Tannheim/Engelsberg and Schwabmuenchen blocks are located in the Molasse Basin (Alpine Foreland), the Landau concession is located within the northern sector of the Upper Rhine Graben, while the Suderbruch concession falls within the Lower Saxony Sub-basin (Northwest German Basin).

Wintershall Dea GmbH disclosed on 9 January 2020 it had entered into an agreement with RDG GmbH & Co. KG (RDG) for the purpose of selling interests in several production contracts in the country's various petroleum provinces.

As a result of Xinjiang Autonomous Region government announcement to put out for auction five blocks to Chinese company for exploration and development cooperation on in December 2017, three Chinese domestic company have secured the rights for three bcloks on 23 January 2018 after a bidding competition. Shenergy Co obtaines Keping South Block at a bidding price of CNY 1.49 bn ($230 million), Xinjiang Energy (Group) wins Wensu West Block at a price of CNY 380 million ($59 million) and Zhongman Petroleum takes Wensu Block at price of CNY 867 million ($135 million). The other two blocks, Keping West and Qiemo East, has no deal made as no company bid for auction.

China, not found

In January 2019 Moesia was still looking for partners for additional funding of its planned operations in the 1-5 Devetaki, 1-7 Tarnak, 1-9 Miziya and 1-10 Botevo exploration permits in northwestern Bulgaria. In April 2018 industry sources reported that a company from the UK was interested in a partnership with Moesia but no more details were communicated. The company completed the reprocessing of more than 2,000 km of data across all four blocks. Moesia anticipates to re-appraise the Devetaki gas field which produced more than 15 Bcf of gas and condensate at economic rates but was not appraised or developed optimally. The Devetaki field is believed to contain significant incremental volumes and being located adjacent to existing infrastructure it offers near term production potential. Interest in the four permits are 100% held by Moesia Oil and Gas EOOD.

Bulgaria, 1-5 Devetaki

Aker BP, operator of production licence PL 340, has concluded the drilling of wildcat well 24/9-12 S and appraisal well 24/9-12 A, which was drilled 850 metres southwest of the discovery well, 24/9-12 S. The wells were drilled about two kilometres north of the Bøyla field, 26 km southwest of the Alvheim field and 200 km northwest of Stavanger. The primary exploration target for wildcat well 24/9-12 S was to prove petroleum in reservoir rocks (injectites) in the Eocene (Intra Hordaland group sandstones). The secondary exploration target was to prove petroleum in underlying Upper Paleocene reservoir rocks (the Hermod formation). The objective of well 24/9-12 A was to delineate the discovery, as well as to obtain information regarding the placement of a potential development well. In the primary exploration target, well 24/9-12 S encountered an oil column of about 10 metres in a 40-metre thick sandstone layer, which is interpreted as being injectites in the Hordaland group with very to extremely good reservoir properties. The oil/water contact was encountered. Three thin, oil-bearing, partially cemented sandstone layers with moderate to good reservoir properties and totalling 5 metres were also encountered higher up in the Hordaland group. The sandstones are interpreted as being remobilised sand from the Heimdal and Hermod formation, which has presumably been injected into the overlying Hordaland group. In the secondary exploration target, the wildcat well encountered about 50 metres of water-bearing sandstone layers in the underlying Hermod formation, generally with good to very good reservoir properties. Appraisal well 24/9-12 A encountered an oil column of about 30 metres in reservoir sandstone layers interpreted as being injectites in the Hordaland group with very to extremely good reservoir properties, as in the discovery well. The oil/water contact was not encountered. Higher up in the Hordaland group, four thin gas-bearing sandstone layers totalling five metres and with very good reservoir properties were also encountered. Preliminary estimates indicate that the size of the discovery is between 5 and 10 million standard cubic metres (Sm3) of recoverable oil. The licensees will consider tying the discovery into the existing infrastructure in the Alvheim area. The wells were not formation-tested, but extensive data acquisition and sampling have been carried out. These are the fourth and fifth exploration wells in production licence PL 340. The licence was awarded in APA 2004. 24/9-12 S was drilled to respective vertical and measured depths of 2251 and 2285 metres below the sea surface and was terminated in the Heimdal formation in the Paleocene. 24/9-12 A was drilled to respective vertical and measured depths of 2162 and 3000 metres below the sea surface, and was terminated in the Hermod formation in the Paleocene. Water depth is 120 metres. The wells have been permanently plugged and abandoned. Aker BP is the operator of PL340 with a 65 percent working interest. The partners are Point Resources with 20 percent and Lundin Petroleum with 15 percent. Wells 24/9-12 S and 24/9-12 A were drilled by the Transocean Arctic drilling rig, which will now drill wildcat well 34/2-5 S in production licence 790 in the northern North Sea, where Aker BP is the operator. Click here for Aker BP announcement (issued Feb 19 2018): Exploration success in PL340 near Alvheim Original article link Source: NPD

024/09-12A appraisal well, 850m SW of recent Frosk discovery, op. by Aker BP (65%, Point Res. 20%, Lundin 15%) in PL 340 licence, north of Bøyla, 30m oil column in reservoir sst interpreted as Hordaland group injectites, very-to-extremely-good properties as in the discovery. OWC not encountered. Higher up in the Hordaland, 4 thin gas layers totalling 5m were intersected with good reservoir properties.

Subject to approvals, Pioneer Natural Resources has signed an agreement with an undisclosed buyer to sell all of its assets in the West Panhandle field in Texas for USD 201 million. Net production averaged ca. 6,000 boe/d in Q1 ‘18.

Subject to approvals, Pioneer Natural Resources has signed an agreement with an undisclosed buyer to sell all of its assets in the West Panhandle field in Texas for USD 201 million. Net production averaged ca. 6,000 boe/d in Q1 ‘18.

On 29 March 2018, the consortium of Petrobras, ExxonMobil, and Statoil, was granted preliminary awards for the C-M-657 and C-M-709 blocks in the offshore Campos Basin through the ANP Round 15. For the C-M-657 block the consortium offered a bonus of USD 643.1 million and 1,075 work units.  Petrobras has 30% working interest and is operator of the block, ExxonMobil has 40%, and Statoil has 30% working interest. There was one other bid for the block.  The consortium of Shell, Chevron, and Petrogal offered a bonus of USD 418.76 million and 1,080 work units. For the C-M-709 block the consortium offered a bonus of USD 453.17 million and 1,253 work units.   Petrobras has 40% working interest and is operator of the block, ExxonMobil has 40%, and Statoil has 20% working interest. There was one other bid for the block.  There was one other bid for the block by the consortium of Shell, Chevron, and Petrogal who offered a bonus of USD 244.19 million and 1,184 work units.  

the consortium of Petrobras, ExxonMobil, and Statoil, was granted preliminary awards for the C-M-657 and C-M-709 blocks in the offshore Campos Basin through the ANP Round 15.

Kina Petroleum Corp is offering equity in its wholly owned and operated exploration licenses: PPL 435 and PPL 436, located in the Fly Platform, Papuan Basin. Both licences were scheduled to expire in November 2018, but Kina has submitted a new application covering both areas - APPL 642. This is also expected to be available to interested parties for farm in. PPL 435 and PPL 436 cover a combined area of 19,380 sq km and were awarded in 2012, for six years. Rather than extend the licences, with associated area reductions, Kina submitted APPL 642 to maintain its position in the basin. APPL 642 covers an area of around 16,900 sq km over main prospects which are considered to lie along a liquids fairway extending from Elevala-Ketu, in PRL 21. The application also extends eastward into an expired licence area held by Kengaku, hosting the Saratoga prospects, located to the south of the Panakawa oil seep. The timeline for an exploration licence to be awarded or refused by the Minister for Petroleum and Energy is variable. Based awards within the area, this could be around 18 months. Under previously scheduled work commitments, one well was planned (to a minimum of 1,000 m, at a forecasted cost of AUD 20 million). However, the commitment to drill was replaced by the acquisition of seismic which was scheduled for late-2016/17. The option to remove the well commitments and complete an additional phase of seismic would allow the existing prospects to be further delineated with additional seismic control before moving to a drill phase. Any newly approved work programme in relation to application APPL 642 is likely to contain a seismic commitment which potential partners would be asked to assist in. Recent seismic reprocessing/interpretation and any planned, new 2D seismic data acquisition, will likely focus on delineating the Aiambak and Lake Murray East leads in PPL 435 and the Sturt, Alligator, Dalbert, and Oriomo prospects in PPL 436. The combined prospects and leads are estimated to contain prospective resources over 13 Tcf gas and 181 MMb liquids (best estimate). Aeromagnetic and gravity survey data has been acquired (completed in June 2014) which has been merged and interpreted by Kina alongside reprocessed vintage 2D seismic data. The gravity data defines the Aiambak and Alligator/Sturt Prospects which are located on the hanging wall of the southern Fly Platform edge. Aiambak is located updip of the Lake Murray 1 well which was drilled in 1973, encountering gas in the Toro Sandstone. Kina considers the prospect to be in connection with the well after gas testing. Alligator and Sturt prospects are located updip of oil seeps observed at the Panakawa 1 well. Through source-migration studies, Kina believes that the prospects have potential to receive charge from oil mature sources rocks from the Wabuda and Morehead Troughs. Cott Oil and Gas Ltd completed a farm-in to PPL 435 and 456 in mid-February 2013. However, Cott subsequently withdrew in July 2015 to focus on other areas of its portfolio. Kina is now seeking farm-in partners for both PPL 435 and PPL 436 (and APPL 642 upon award). The PPL 435 and PPL 436 licences cover a combined area of 19,380 sq km and were awarded on 25 July and 30 November 2012 respectively, for a period of six years. Kina Petroleum Corp holds 100% interest and operatorship of both permits. APPL 642 covers an area of around 16,900 sq km and was registered with the Department of Petroleum & Energy on 2 May 2019. Companies interested in pursuing this opportunity should contact: Richard Schroder – Kina Petroleum MD Tel: +61 2 8247 2500 Email: richard.schroder@kinapetroleum.com

(Papuan b.) PPL 435 & 436 op. by KINA PT (100%), Kina Petroleum Corp is offering equity in its wholly owned and operated exploration licenses: PPL 435 and PPL 436, located in the Fly Platform, Papuan Basin. Both licences were scheduled to expire in November 2018, but Kina has submitted a new application covering both areas - APPL 642.

On 14 October 2019, the Federal Agency for Subsoil Use held an auction for three blocks in Krasnoyarsk Kray (Eastern Siberia). The winning bids were submitted by Irkutsk Oil Company (INK) and Krasnoyarsk Oil & Gaz Company (KNK). The winners of the auction will obtain 27-year E&P licenses including a 7-year exploratory stage. Details of the offer are as follows: The Belyakskiy block covers 1,323 sq km in the Baykit Basin and encompasses several leads. One well has been drilled in the block. Reservoirs of the Riphean-Vendian section are the main exploratory target. Hydrocarbon resources (category D1) of the block are estimated at 40 MMbbl of oil and 579 Bcf of gas. The starting price amounted to RUB 13.5 million (USD 0.2 million). INK offered RUB 14.85 million (USD 0.23 million). The Teryanskiy block covers 3,700 sq km in the Baykit Basin. No wells have been drilled in the block. Reservoirs of the Riphean-Vendian section are the main exploratory target. Hydrocarbon resources (category D1) of the block are estimated at 44 MMbbl of oil and 2,308 Bcf of gas. The starting price amounted to RUB 15.5 million (USD 0.23 million). KNK offered RUB 17.05 million (USD 0.27 million). The Yelomovskiy block covers 2,892 sq km in the Baykit Basin. No wells have been drilled in the block. Reservoirs of the Riphean-Vendian section are the main exploratory target. Hydrocarbon resources (categories D1+D2) of the block are estimated at 26 MMbbl of oil and 3,415 Bcf of gas. The starting price amounted to RUB 18.1 million (USD 0.27 million). KNK offered RUB 19.91 million (USD 0.31 million).

Russia, not found

Whalsay is looking to farmout its 100% in P1078 / block 9/3b (Bentley heavy oil field) on flexible terms along with operatorship in order to move the field into devt. The proposed devt features a 20-well slot platform designed for 45,000 bo/d + 180,000 bw/d through an FSO. Contacts: Jon.Fitzpatrick@gneissenergy.com, Paul.Weidman@gneissenergy.com or Rosemary.Johnson-Sabine@gneissenergy.com.

Whalsay is looking to farmout its 100% in P1078 / block 9/3b (Bentley heavy oil field) on flexible terms along with operatorship in order to move the field into devt. The proposed devt features a 20-well slot platform designed for 45,000 bo/d + 180,000 bw/d through an FSO.

On 10 October 2019, BP with 100% working interest was granted a preliminary award for the 1,171.92 sq km S-M-1500 block in the deep-water offshore Santos Basin from the ANP Round 16. There were no other bids for the block. The company bid a bonus of USD 74.88 million at 1 USD to 4.11 BRL and USD 8.74 million in minimum work commitments.  BP is operator with 100% working interest.

Brazil, not found

PGNiG secured sole rights to the 669-sq km 10/2019/L Sierpowo contract SW of Gdansk in the Pomeranian Trough, N. Poland. It was tendered in 2018 (Round 3).

PGNiG secured sole rights to the 11/2019/L Blazowa contract, (270km²) in the SE Poland and 10/2019/L Sierpowo (669km²) contract SW of Gdansk in the Pomeranian Trough.

Simwell Resources is offering significant equity and operatorship to a single company or consortium, to farm into licence P2326 (blocks 29/22b, 29/23b, 29/27 & 29/28). Simwell has identified two Plio-Pleistocene gas leads named Q29-A and Q29-B. The leads form a combination of structural and stratigraphic traps with shallow reservoirs in water depths of 80 – 85 m. Both leads show similarities with Dutch producing fields. The primary play targets biogenic gas in sandstone reservoirs trapped in anticlinal structures with mudstones providing intraformational seals. Rotliegend, Upper Jurassic and fractured chalk sequences provide secondary objectives. However, a deeper mature Carboniferous source rock would be required to source these secondary objectives but is currently unproven in the area. Lead Q29-A is 9.25 sq km and was identified from anomalously bright seismic amplitudes. The seismic interpretations highlight, stacked reservoirs, velocity pull down, attenuation, associate salt diaper, sea bed depression and gas chimneys. Lead Q29-B is a shallow gas accumulation trapped in a 4-way dip closure within Pleistocene aged sediments with an areal extent of 55.58 sq km. Lead Q29-B shows similar but slightly subtler seismic characteristics to Lead Q29-A. As of February 2019, the opportunity was still available. The licence was awarded on the 15 May 2017 from the 29th Seaward Licensing Round. The first three-year phase of the work programme is being fulfilled by obtaining more 2D seismic and completing an AVO study. Simwell is also working on a commercial feasibility study based on an offshore Netherlands shallow gas model with the aim to complete it in Phase A. Phase B consists of another three-year phase with a contingent commitment of shooting a 250 sq km 3D seismic survey, unless the OGA decide the new shoot seismic data is not required to make a decision to drill a well. Furthermore, multi-client 3D data partially covers the acreage of which could be used instead of shooting new 3D seismic data. Two exploration wells have been drilled in the acreage. The first exploration well 29/23b-2 was drilled in 1973 by Oxy which penetrated the Zechstein and was dry. The second exploration 29/27-1 was drilled in 1987 by Hess. The primary objective was an algal build-up comprising of reservoir quality dolomitic packstones and grainstones trapped laterally by lime muds with Zechstein evaporates providing the overlying seal. Two cores were cut but neither were oil bearing. For further details please contact: David Hughes Tel: +44 (0)20 8878 0212 Email: dhughes@simwellresources.com

Simwell Resources is offering significant equity and operatorship to a single company or consortium, to farm into licence P2326 (blocks 29/22b, 29/23b, 29/27 & 29/28). Simwell has identified two Plio-Pleistocene gas leads named Q29-A and Q29-B. The leads form a combination of structural and stratigraphic traps with shallow reservoirs in water depths of 80 – 85 m. Both leads show similarities with Dutch producing fields.

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

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

During early January 2020 GPC, through its Petrosalam Oil Company subsidiary, had successfully completed its Northwest October 3 (NWO 3) appraisal/development well, located on its Northwest October PSC in the central Gulf of Suez. The well is expected to be brought online imminently at a rate of 2,000 bo/d. Operations were carried out utilising the ADES Group "Admarine 88" jack-up in ~60m WD. The well is appraising/developing the company's 2006 Northwest October 1 (NWO 1) oil discovery. It reached 2,880m TD, encountering oil the Palaeocene Nukhul, Mokattam & Thebes formations. A successful appraisal NWO 2, was drilled in 2010. With NWO 3 being brought online shortly, production from the field is expected to reach 5,000 bo/d. In Q4 2013, Fuji Oil sold its 50% stake in the Petrosalam JV to EnQuest. In H2 2015, EnQuest also exited, with no activity being carried out in the interim. The company's 50% equity in Petrosalam was assigned to EGPC, which already held a 50% carried interest in the JV. In H2 2017, EGPC assigned its 100% interest to GPC, which now holds 100% equity.

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Husky reports a successful explo well in block 15/33, WD 80m in the South China Sea SE of Hong Kong. Four oil-bearing zones totalling 70m were encountered, testing to follow, whereafter a 2nd well will be drilled.  Husky also plans 2 explo wells in nearby block 16/25 in 2H ’18.

Husky reports a successful explo well in block 15/33, WD 80m in the South China Sea SE of Hong Kong. Four oil-bearing zones totalling 70m were encountered, testing to follow, whereafter a 2nd well will be drilled. Husky also plans 2 explo wells in nearby block 16/25 in 2H ’18.

SE part of GS-29 Extn block, KG deepwaters, WD 420m, new pool discovery:  new pay sand interval (2,182-2,200m) encountered during testing of Object 1 (Object 1A: 2,182-2,186m + Object 1B: 2,195-2,200m), flowed 3,773 bo/d 3.2 MMcfg/d on a 1/2” choke. Object II (1,906-1,911m) also gauged 223 bo/d + 188 Mcfg/d on a 1/4” choke. Jack Bates SS.

GS-29 8(SUB) op. by ONGC (100%) in SE part of GS-29 Extn ML block, new pool discovery: new pay sand interval (2182-2200m) encountered during testing. Object 1 flowed 3773 bo/d + 3,2 MMscfg/d [1/2” choke] and Object II gauged 223 bo/d + 188 Mscfg/d [1/4” choke]. WD=420m.

Banjul has reportedly shortlisted 11 co’s to participate in its licensing round which opened November last for 6 blocks (2 onshore, 4 offshore). Companies identified include CNOOC, Eni, FAR, Impact O&G, Svenska, Talon Petr., Total, and a Tullow-Woodside group, the interest seemingly for the offshore.

Banjul has reportedly shortlisted 11 co’s to participate in its licensing round which opened November last for 6 blocks (2 onshore, 4 offshore). Companies identified include CNOOC, Eni, FAR, Impact O&G, Svenska, Talon Petr., Total, and a Tullow-Woodside group, the interest seemingly for the offshore.

Sava 10 block, Slavonian sub-basin in NE Croatia, drilled 22 Jul – early Aug ’19, TD 1,270m, Miocene gas encountered and preparing for test.

Berak 1 nfw in Sava 10 block, Slavonian sub-basin, TD=1270m, Miocene gas encountered and preparing for test.

Petroleum Development Oman LLC (PDO) completed drilling operations at the Zauliyah South 1 horizontal exploration well on 10 April 2020 after reaching a TD of 2,846 m. No result has been reported. The well was spudded on 17 March 2020 in the Block 6 onshore licence with L/R “58”. It is located in the Ghudun-Khasfah High of the Oman Basin. The Zauliyah oil field was discovered in June 1981 and brought onstream in April 1984. Discovery well Zauliyah Northeast 1 found the Gharif Formation objective to be oil bearing. In tests the Gharif flowed at 2,000 b/d of 43°API oil. The find was successfully appraised by four wells in 1983/1984, Zauliyah Northeast 2 to Zauliyah Northeast 5. These wells were later renamed Zauliyah. The Oman government own a 60% stake in PDO, with the remaining equity held by Shell (34%), Total (4%) and Partex (2%). PDO is 100% rightholder of Block 6.

Oman (Ghudun-Khasfah High (Oman B.)) Zauliyah

According to reports in early-October 2018, Noble Energy and Edison International have notified Argos Resources of their intention to withdraw from the PL001 License. Noble was the block operator with 75% interest as partner Edison held the remaining 25%, while Argos held a 5% overriding interest in the block by virtue of the farm out agreement signed between the companies in April 2015. Once the exit is complete, Noble and Edison will have no assets left in the Falklands. It was said that Argos plans to maintain the license while seeking new partners. PL001 covers 1,126 sq km in the North Falkland Basin and located west of Premier’s Sea Lion discovery, which is still awaiting a final investment decision. Noble and Edison initially planned to drill an exploration well on the Rhea prospect in the block, but plans were terminated in 2016. The partners disclosed plans to drop the Northern and Southern licences in 2017, following the non-commercial results of the Humpback 1 exploration well. Background Information Argos Resources received an official approval for a three year extension to the PL001 License in August 2016. The extension pushed the current 2nd exploration phase expiration date out to November 2019.

Noble Energy (75% op.) and Edison International (25%) have notified Argos Resources (->100%) of their intention to withdraw from the PL001 License. Once the exit is complete, Noble and Edison will have no assets left in the Falklands.

Cenovus Energy has entered into an agreement to sell its Palliser crude oil and natural gas assets in southeastern Alberta to Torxen Energy and Schlumberger for cash proceeds of $1.3 billion. The sale is expected to close in the fourth quarter of this year, subject to customary closing conditions. As with other recently announced divestiture agreements, proceeds from the Palliser sale will be used to deleverage the company’s balance sheet. Net proceeds from the sale of Cenovus’s Pelican Lake assets, which closed on September 29, 2017, have been used to retire the first tranche of the company’s $3.6 billion asset-sale bridge facility and to pay down a portion of the second tranche. Net proceeds from the Palliser sale and the recently announced Suffield asset sale, which is also expected to close in the fourth quarter of 2017, will be applied against the outstanding balance of the bridge facility.Cenovus Energy's Canadian assets - including Palliser (Source: Cenovus) 'Our strategy to optimize our portfolio by selling non-core assets and using the proceeds to pay down debt is firmly on track,' said Brian Ferguson, President & Chief Executive Officer. 'We continue to target between $4 billion and $5 billion in announced asset sale agreements by the end of the year, and we remain committed to returning to our long-term debt ratio target.' Cenovus is focused on using cash flow from its operations and asset sale proceeds to achieve its target of being below two times net debt to adjusted earnings before interest, taxes, depreciation and amortization (EBITDA). The sale process for Cenovus’s Weyburn carbon-dioxide enhanced oil recovery operation in Saskatchewan is proceeding as expected. Cenovus anticipates reaching a sale agreement for the Weyburn asset in the fourth quarter of 2017. In addition, Cenovus has certain other non-core assets that are currently being evaluated for potential sale. Credit Suisse and Scotiabank acted as financial advisors to Cenovus for the Palliser transaction. Original article link Source: Cenovus Energy

Cenovus Energy has entered into an agreement to sell its Palliser crude oil and natural gas assets in southeastern Alberta to Torxen Energy and Schlumberger for cash proceeds of $1.3 billion.

Mexico awarded just under half of the 35 shallow-water blocks it tendered on Tuesday, in an auction muddied by the promises of the presidential frontrunner to review contracts awarded under a historic energy opening if he wins the July 1 election.The country’s oil regulator awarded 16 blocks in the Gulf of Mexico to firms including Spain’s Repsol, France’s Total, Italy’s Eni, Britain’s Premier Oil and Mexico’s state-run Pemex, which was the biggest winner overall.A final, competitive round of bidding in the Southeast Basins improved what started as a patchy showing, with little interest in fields believed to contain high amounts of natural gas.About $8.6 billion in investment is expected from the projects to be developed in the awarded blocks, Mexico’s Energy Minister Pedro Joaquin Coldwell said, with early production starting in 2022 and a production potential of 280,000 barrels per day (bpd).Andres Manuel Lopez Obrador, who has a comfortable lead in most polls, said that if he wins the July vote, he would review more than 90 contracts signed since Mexico passed legislation in 2013 ending Pemex’s 75-year monopoly, looking for signs of corruption.Click here for full Reuters articleSource: Reuters

CNH-RO3-LO1/2017 Bid Round or Ronda 3.1 - 35 shelf blocks granting preliminary awards for 16 blocks out of 35 on offer.

Mexican President Enrique Pena Nieto on 3 November 2017 said that the Ixachi 1 NFW, in the AE-0032-M-Joachin-02 contract area, discovered initial gross original in place estimates of 1.5 billion boe. The well was reported by Pemex as being the company's largest onshore light oil, gas and condensate discovery in the last 15 years with 3P recoverable reserves that could reach 350 MMboe. Ixachi 1 is located 4km NW of the Mocarroca 1 NFW that discovered oil in 2005. The well should be able to be brought on line quickly, as it is located near existing infrastructure. The Vera Cruz Basin NFW was spudded on 25 January 2017 with a PTD of 7,728m. The well had targets in the Cretaceous. It was spud to explore a possible extension of the Faja de Oro play on Mexico's Gulf Coast. Pena Nieto also said that Ixachi is similar in size to the Talos-operated Zama-1 (Zama-1SON) discovery also made in 2017, located on Block 7 (Contracto CNH-R01-L01-A7/2015). That well tested 28-30 deg API oil & some associated gas and discovered initial gross original oil in place estimates in the range of 1.4 Bbls to 2 Bbls.

Ixachi 1 op. by Pemex (100%) in A-0269-M-Campo Perdiz block, estimated to contain original volumes in place of up to 1,5 billion boe, which could represent recoverable resources of 350 MMboe. Largest Mexican onshore oil find in 15 years.

Eni has withdrawn from the offshore North Coast Marine Area 1 Block (NCMA 1) and Block 9 (part of the NCMA 1 unitised area), according to industry sources in mid-November 2018. It is not wholly understood if this deal is subject to government approval. Eni's departure leaves Shell as the main stakeholder. Eni's 17.31% interest gives the Royal Dutch supermajor's total WI of 80.5%. National Oil Company, Petrotrin holds the remaining 19.5%. As part of the state-mandated process to replace debt-laden Petrotrin, Heritage Petroleum is stated to replace Petrotrin as the new state E&P company once it is fully operational by 1 December 2018. Previously in May 2017, Shell had also acquired 17.31% WI from Centrica, in a transaction involving a number of blocks including NCMA 1, Block 9, Block 22 and NCMA 4. This deal involved Centrica's disposal of it's remaining gas assets in Trinidad and Tobago to Shell for US$ 36 million, Shell has been improving its strategic position in gas in Trinidad in recent years, through its purchase of BG in 2016, its stake in LNG plants in Trinidad, its purchase of remaining Centrica interest in 2017, acquisition of Chevron's offshore gas assets in late May 2017, and now capitalising on Eni's withdrawal from NCMA 1.The NCMA 1 Block, contains the Hibiscus, Poinsettia and Chaconia gas fields. The President of Venezuela, Nicolas Maduro, and the Prime Minister of Trinidad and Tobago (T&T), Keith Rowley signed a joint declaration on 25 August 2018, for the execution of the Dragon Field interconnection project. The delayed project will transport gas from the Dragon Field via a planned 30km subsea pipeline to Shell's Hibiscus platform in Trinidad and Tobago territorial water, before entering Trinidad's gas grid.

NCMA 1

In late October 2019, Khalda Petroleum Co (Khalda) successfully tested the Barakat Deep 1 exploratory well in its Khalda Offset (New) A-West concession, Northern Egypt Basin. Without further disclosed information, the operator reported the presence of gas and condensate, which were presumably found in the Lower Cretaceous Alam El Bueib Member of the Burg El Arab Formation. The operator spudded the Barakat Deep 1 well on 27 August 2019 with a planned TD at 4,420 m. Khalda is a JV between EGPC (50%), Apache (33.5%) and Sinopec (16.5%). The Khalda Offset (New) A-West is a 3,271 sq km concession awarded to Khalda in January 1998. The concession includes the Nakhaw oil discovery made in 2002.

Egypt, Khalda Offset

Ranger-1 well encounters approx. 230 feet of high-quality, oil-bearing reservoir Well is located approx. 60 miles northwest of Liza phase one project Discovery provides a new play concept for the 6.6 million acre Stabroek Block Exxon Mobil announced Friday positive results from its Ranger-1 exploration well, marking ExxonMobil’s sixth oil discovery offshore Guyana since 2015. The Ranger-1 well discovery adds to previous world-class discoveries at Liza, Payara, Snoek, Liza Deep and Turbot, which are estimated to total more than 3.2 billion recoverable oil-equivalent barrels. ExxonMobil affiliate Esso Exploration and Production Guyana began drilling the Ranger-1 well on Nov. 5, 2017 and encountered approx. 230 feet (70 meters) of high-quality, oil-bearing carbonate reservoir. The well was safely drilled to 21,161 feet (6,450 meters) depth in 8,973 feet (2,735 meters) of water. 'This latest success operating in Guyana’s significant water depths illustrates our ultra deepwater and carbonate exploration capabilities,' said Steve Greenlee, president of ExxonMobil Exploration Company. 'This discovery proves a new play concept for the 6.6 million acre Stabroek Block, and adds further value to our growing Guyana portfolio.'The Ranger-1 discovery is located approx. 60 miles northwest of the Liza phase one project in the 6.6 million acre Stabroek Block Following completion of the Ranger-1 well, the Stena Carron drillship will move to the Pacora prospect, 4 miles from the Payara discovery. Additional exploration drilling is planned on the Stabroek Block for 2018, including potential appraisal drilling at the Ranger discovery. The Stabroek Block is 6.6 million acres (26,800 sq kms). Esso Exploration and Production Guyana is operator and holds 45 percent interest in the Stabroek Block. Hess Guyana Exploration holds 30 percent interest and CNOOC Nexen Petroleum Guyana holds 25 percent interest. Original article link Source: ExxonMobil

Ranger 1 op. by ExxonMobil (45%, Hess 30%, CEO 25%), located ~60 miles NW of the Liza discovery, in the Stabroek block, encountered ~70m of high-quality, oil-bearing carbonate reservoir. The well tested a new play concept that targeted a feature HES officials described as “a large four-way structure that is different geologically than the stratigraphic traps that have been drilled thus far on the block” and is the first discovery on the block made in a carbonate interval. Previous discoveries were stratigraphically trapped (typically higher risk than a four-way closure) sandstone reservoirs.

Uzynada gas-cond discovery area, S. of Barsagelmes field, South Caspian Basin on Caspian coast, tested 3.63 MMcfg/d + 1,150 bc/d in Jan '20 from the Lower Red Bed Series between 6,746-6,752m. Uzynada was discovered in 2017 by the country's 1st super-deep well, Uzynada 7.

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

Penglai 13-2-7 (PL 13-2-7) was suspended, having intersected oil in the target reservoirs, on or around 6 July 2019 after having been spudded on or around 25 June 2019, using the "Bohai 5" jack-up. The oil and gas appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations. Penglai 13-2-7 is in the CNOOC operated Bozhong 06 Block in the offshore Bohai Gulf Basin.<P />

Penglai 13-2-7 (PL 13-2-7) in the CNOOC operated Bozhong 06 Block in the offshore Bohai Gulf Basinwas suspended, having intersected oil in the target reservoirs. The oil and gas appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations.

Further to DEA 6 Nov ’18, the 2018/2019 Madagascar Licensing Round involving 44 blocks in the Morondava Basin, off the W. of the island between Cap St André and Morombe, has been suspended until further notice. The round was in partnership with BGP + TGS and the roadshows in Houston on 19 Feb and London on 26 Feb are still being held by them, but now only as shortened morning sessions and not associated with OMNIS.

The 2018/2019 Madagascar Licensing Round involving 44 blocks in the Morondava Basin, off the W. of the island between Cap St André and Morombe, has been suspended until further notice. The round was in partnership with BGP + TGS and the roadshows in Houston on 19 Feb and London on 26 Feb are still being held by them, but now only as shortened morning sessions and not associated with OMNIS.

The Canadian Environmental Assessment Agency (CEAA) announced on 6 December 2018 that funding is being made available to assist with participation in the regional assessment of offshore oil and gas exploratory drilling East of Newfoundland and Labrador. The submission deadline for applications is 8 January 2019. The regional assessment will center on the effects of existing and planned offshore oil and gas exploratory drilling in the offshore area east of Newfoundland and Labrador. The regional assessment aims to improve the efficiency of the environmental assessment process as it applies to oil and gas exploration drilling, whilst simultaneously ensuring the highest standards of environmental protection. Recipients and the amount of funding allocated will be announced at a later date. To apply for funding or request an application form, contact the Participant Funding Program by writing to CEAA.FP-PAF.ACEE@canada.ca.

Not Found

On 6 November 2019, Talos Energy announced it will initiate a process to sell down part of its 100% working interest at the Hershey prospect in Q4 2019. On 19 September 2019, Talos announced it had entered into an agreement with ExxonMobil to acquire 100% interest in the Hershey prospect covering Green Canyon blocks 326 (G34977), 327 (G34978), 370 (G34980) and 371 (G34981). Detailed terms of the deal were not divulged, other than it is 100% contingent-based and contains no well commitment. On 1 July 2020, the Bureau of Ocean Energy Management (BOEM) approved exploration plan N-10093 filed by Talos on 21 November 2019. The plan details the drilling of up to eight wells in the Hershey blocks: one on the far east-central side of GC 326, three in the southwest quarter of GC 327, one in the southwest quarter of GC 370 and three in the northwest quarter of GC 371. The surface locations for the proposed wells lie in 2,793 – 3,079 ft (851 – 938 m) of water, about 112 mi (180 km) southwest of the onshore supply base at Port Fourchon, Louisiana. The company plans to use a dynamically positioned semisubmersible or drillship for the operations. The plan calls for the drilling, abandoning and completing of each well to take up to 90 days. Hershey is a large subsalt prospect, with potential for several stacked Miocene-aged reservoirs. Talos estimates the prospect may hold oil-weighted, gross unrisked resources of 100-300 MMboe. Depending on the size of a discovery, it could be developed as a subsea tieback to various facilities in Green Canyon controlled by Talos or with new infrastructure dedicated to the field. The blocks lie in up to 3150 ft (960 m) of water, about 112 mi (180 km) southwest of the onshore supply base at Port Fourchon, Louisiana Exxon picked up the blocks at Sale 227 on 20 March 2013 with combined sole bonus bid of USD 99.7 million. Competition for the blocks included Maersk (sole bid), and Ecopetrol and Murphy (bidding jointly). Combined second-place bids for the blocks were USD 41.8 million.

United States (Deep Water Gulf of Mexico B.) GC 326 op. by TALOS (100%), on 6 November 2019, Talos Energy announced it will initiate a process to sell down part of its 100% working interest at the Hershey prospect in Q4 2019.

In its first quarter 2018 report released on 7 May 2019, Tethys Oil AB (concession partners of CC Energy Development S.A.L. (Oman) Ltd (CCED) and Mitsui E&P Middle East (MEPME) B.V) announced that an oil discovery had been made at the Masarrah 1 new field wildcat in Block 03 (Afar). The well will now undergo a long-term production test. It was spudded in the fourth quarter of 2018 based on the interpretation of recently acquired seismic data to explore deeper objectives. Masarrah 1 is located approximately 11 km east of the Farha South infrastructure. Tethys Oil previously commented that it had identified more than ten leads based on interpretation of old 2D seismic data). CCED operates the onshore 5,915 sq km Block 03 (Afar) concession with a 50% share, the remaining interests are held by Tethys Oil (30%) and MEPME (20%).

Masarrah 1 near-field exploration well (CCED 50% op, Tethys Oil 30%, MEPME 20%) in Afar block 3, east of Farha South infrastructure, oil discovery, targeted a structure analogous to the Ulfa and Samah discoveries around 10 km NE of Ulfa 1. It had good oil shows in the targeted Precambrian Khufai Fm and tested light oil with good flow rates.

In early August 2018, BP was reported to have signed a new agreement with the Egyptian General Petroleum Company (EGPC) for Northeast Ramadan block in the Gulf of Suez. The agreement includes a commitment for BP to spend USD 46 million, which includes the drilling of three exploration wells during the first exploration period and a USD 4 million bonus. The Northeast Ramadan block was awarded to BP on 2 December 2016 as part of EGPC 2016 Bid Round. Background information On 12 May 2016, EGPC launched its 2016 Bid Round for 11 blocks. The company offers five blocks in the Gulf of Suez (Northeast October, North Issran Offshore, Northeast El Hamd, Northeast Ramadan and East Badri) and six in the Western Desert (Northwest Razzak, South Alam El Shawish, West Badre El Din, Southeast Meleiha, Southeast Siwa and North Umbaraka). Six blocks including Northeast Ramadan were awarded on 2 December 2016 by the Egypt Oil Ministry with a total investment of USD 200 million. The companies are committed to drill a total of 33 wells in the six areas.

In early August 2018, BP was reported to have signed a new agreement with the Egyptian General Petroleum Company (EGPC) for Northeast Ramadan block in the Gulf of Suez.

The authorities have approved a 30% transfer from Shell to Woodside in the 1-14 Han Kubrat block, 6,893 sq km in Black Sea shelf + deepwaters, ahead of explo drilling next April. The deal has yet to be gazetted. Partners-to-be: Shell + Woodside.

The authorities have approved a 30% transfer from Shell to Woodside in the 1-14 Han Kubrat block, 6,893 sq km in Black Sea shelf + deepwaters, ahead of explo drilling next April. The deal has yet to be gazetted. Partners-to-be: Shell + Woodside.

On 6 December 2019, the Federal Agency for Subsoil Use held an auction for the Ozernyy block in Komi Republic (Timan-Pechora Basin). Local Soyyu won the contest with the offer of RUB 2.218 million (USD 0.03 million). The winner will obtain a 25-year E&P license including a seven-year exploratory stage. The Ozernyy block covers 611 sq km. Hydrocarbon resources (categories D1+D2) of the block are estimated at 9 MMbbl of oil and 103 Bcf of gas. The starting price amounted to RUB 1.848 million (USD 0.03 million).

Local Soyyu won the 611-sq km Ozernyy block in the Komi Republic.

The acquisition by Angus of a 51% operating stake from Wingas Storage in the Saltfleetby gasfield is now complete (DEA 20 Jun '19). Saltfleetby lies in PEDL 005, Lincolnshire, formerly run by Wingas (now renamed Saltfleetby Egy), who retains 49%.

The acquisition by Angus of a 51% operating stake from Wingas Storage in the Saltfleetby gasfield is now complete (DEA 20 Jun '19). Saltfleetby lies in PEDL 005, Lincolnshire, formerly run by Wingas (now renamed Saltfleetby Egy), who retains 49%.

Drilling and subsequent log analysis confirmed 2m of oil saturated sand at 793m with fluorescence (oil shows) across expanded target interval Well reached TD at 845m and is currently being completed for testing 4 well conventional programme will address: multiple wells different targets significant conventional potential with very material upside oil and gas targets non-binary outcome, 3 of 4 wells have multiple objectives Petrel Energy has announced that Schuepbach Energy Uruguay (51%-owned by Petrel) has successfully drilled the Cerro Padilla-1 well to a Total Depth (TD) of 845m. The well encountered significant oil shows with logging confirming 2m of oil saturated sand at 793m. (Working Interests Petrel 51%: Schuepbach Energy 49%). On the back of what is the first ever confirmed discovery of hydrocarbons in Uruguay the well is being completed for production testing.   Cerro Padilla-1 is the first of four conventional exploration wells to be drilled in the Norte Basin Uruguay on concessions covering 3.5 million acres. Piedra Sola and Salto concessions onshore Norte Basin Uruguay covering 3.5m acres Petrel CEO David Casey said: 'While further evaluation is required to understand the full potential of these excellent initial results, the significance of being the first group to discover oil in this frontier basin cannot be underestimated.  Although only a modest discovery in its own right, and regardless of the results of production testing, when viewed in the context of what this could mean for the rest of the programme and the concessions as a whole, it represents a quantum first step in redefining the oil and potentially gas prospectivity of the Notre Basin. It’s not been an easy process drilling  the first onshore exploration well in 30 years in Uruguay but this is an outstanding achievement for the first of a four well programme.'  He went on to say 'I would like to thank the team that got us here, in particular, Martin Schuepbach for his geological vision and expertise, local staff and contactors, new onsite drilling experts New Tech Global Ventures, drillers New Force Energy, partners Schuepbach Energy and our shareholders that have supported us in reaching this significant milestone.'Four well programme extends SE/NW across both concessions Original article link Source: Petrel Energy

Uruguay, not found

Beach Energy Ltd spudded the Hanson West 1 appraisal well in PPL 255, located in the Cooper-Eromanga Basin, on 19 July 2019.  The well was drilled by the “SLR Rig 184” land rig.  On 27 July 2019 the well was plugged and abandoned at a total depth of 1,808 m.  Evaluation of the well results is ongoing. The well was drilled to appraise the Hanson field, which was discovered in May 2011.  The field has been producing oil since April 2013. Hanson West 1 was the eighth appraisal well to be drilled at the field. Hanson West 1 followed the Hanson East 1 appraisal well which was plugged and abandoned, after encountering oil shows, on 16 July 2019 PPL 255, which covers an area of 2 sq km, was awarded on 13 August 2019.  Beach Energy Ltd holds 100% interest and operatorship, with 50% held through subsidiary Great Artesian Oil and Gas Pty Ltd.

Beach Energy Ltd Hanson West 1 (appraisal) PPL 255, Cooper-Eromanga Basin - P&A

Total (op), ExxonMobil + Hellenic Petroleum have reportedly been formally awarded 8-year rights to the SW Crete block, 19,868 sq km, and W. Crete block, 20,058 sq km in deepwaters off Crete. The group initiated the tender by filling expressions of interest for both blocks in May ‘17.

Total (op), ExxonMobil + Hellenic Petroleum have reportedly been formally awarded 8-year rights to the SW Crete block, 19,868 sq km, and W. Crete block, 20,058 sq km in deepwaters off Crete. The group initiated the tender by filling expressions of interest for both blocks in May ‘17.

China's Sinochem could be selling its 40% stake in the Peregrino Field on the Campos Basin shelf to Australian operator Karoon and if the deal is completed it would be Karoon's first production anywhere in the world. The two companies are said to have been in talks over the deal since 2017. Negotiations are being conducted directly by Karoon's board of directors in Australia and Sinochem in China, with support from both company's local Brazilian offices. In February 2017, Sinochem said it was looking to sell its 40% in the Peregrino and Pitangola blocks including Peregrino and Peregrino South fields, according to Brazilian sources. The interest was purchased from Norway's Statoil for US$ 3.07 billion in 2010 beating several Chinese rivals. Equinor owns the remaining 60% of the heavy oil Peregrino Field. Sinochem is selling its largest overseas upstream interest with a capacity to produce 100,000 bo/d to reshape its portfolio. The Sinochem sale price for its Peregrino interest was not disclosed but said to be at a big discount to its purchase price. For Equinor, Peregrino has been a technical and financial success. The field is located in 100m water depth. The possible sale of Peregrino also comes ahead of the second phase of the project's development, expected to cost about US$ 3.5 billion with production from the new phase set to start in 2021. The second phase will add about 250 MMbo in recoverable reserves to Peregrino, which currently has a reserve estimate between 300 to and 600 MMbo. The ANP board of directors on 8 September 2016 approved for Statoil a phase two development plan for Peregrino Field with a deadline for the start of production of December 2020. Phase two calls for the installation of a third wellhead platform in the Peregrino field. The Peregrino phase two project calls for drilling 22 wells including 15 oil producers and 7 water injection wells. Statoil will also conduct a pilot project using polymer injection to reduce water production. The water cut for the field have increased to about 50%. Production of the field started in April 2011 and passed 100 MMbo in 2015. On 30 January 2015, Statoil submitted the phase two plan of development for Peregrino Field to the ANP calling for the installation of a new fixed platform (Peregrino C) in a 120m water depth, enabling access to an undeveloped portion of the field (Peregrino Southwest) inaccessible from the existing A and B platforms. At 14o API the oil from Peregrino is the second heaviest oil ever produced in Brazil.

China's Sinochem could be selling its 40% stake in the Peregrino Field on the Campos Basin shelf to Australian operator Karoon and if the deal is completed it would be Karoon's first production anywhere in the world.

Ref. DEA 12 Dec '17, Santos is exercising a 40% farmin option with Melbana in the latter's WA-488-P (Beehive prospect), 4,100 sq km offshore Bonaparte Basin. Total, who had a similar arrangement, has declined, which could bring Santos to an 80% deal in exchange for funding planned Beehive-1. Santos must respond to this modified offer by 4 Dec '19.

Santos is exercising a 40% farmin option with Melbana (60% op) in the WA-488-P (4100km², offshore, Beehive prospect).

Petsec Energy has completed the transaction with Oil Search to acquire all of the shares of its subsidiary Oil Search (ROY) Limited which holds a 40% working interest (34% participating interest) in the Al Barqa (Block 7) licence and operatorship, in the Republic of Yemen. Completion of the Oil Search agreement follows the 2016 transaction with KUFPEC (25% working interest) to acquire their interests in Block 7, and the transactions with AWE (25% working interest) and Mitsui E&P Middle East (10% working interest) completed and approved by the Yemen Ministry of Oil and Minerals in 2014. The acquisition of Oil Search (ROY) Limited increases Petsec’s potential working interest in Block 7 to 100% and operatorship of the block. Block 7 is an onshore exploration permit covering an area of 5,000 sq kms (1,235,527 acres) located approx. 340 kms East of Sana’a, 80 kms North East of the Company’s Damis (Block S-1) Production Licence, and 14 kms East of OMV’s Al Uqlah (Habban) Oilfield. The block contains the Al Meashar oil discovery made by Oil Search in 2010 as well as an inventory of nine prospects and leads defined by 2D and 3D seismic surveys, with target sizes ranging from 2 to 900 MMbbl oil gross. The Al Meashar Oilfield, with a target resource of 11 MMbbl to 50 MMbbl, contains two suspended discovery wells that intersected over an 800 metre oil column which in 2010-11 delivered flow rates ranging from 200 to 1,000 bopd in short-term testing of the wells. The oil column extends over the same reservoir sequence as that of the Habban Oilfield in the adjacent Al Uqlah (Block S-2). Petsec Energy has secured a 100% interest in two production and exploration licenses in the highly productive Shabwah Basin in Central Yemen, Blocks S-1 and 7, which contain six oil & gas fields – one developed and five yet to be developed, with cumulative target resources between 45 and 84 million barrels of oil and 550 billion cubic feet of gas, in addition to further high potential exploration targets. Block 7 is a key addition to the Company providing material upside to Petsec’s existing Production Licence, Damis (Block S-1) acquired in February 2016 from Occidental Petroleum, which holds the developed An Nagyah Oilfield and four undeveloped oil and gas fields, containing substantial oil and gas resources in excess of 34 million barrels of oil and 550 billion cubic feet of gas. The developed AnNagyah Oilfield was estimated, based on limited production rates of 5,000 bopd for trucking purposes, by DeGolyer and MacNaughton, reserve engineers, to contain gross 2P reserves of 12.8 MMbbl, of which the financial net to Petsec Energy is 5.6 MMbbl of oil, having a NPV 10 of US$155.4 million based on January 2016 forward oil prices. Petsec’s Chairman, Mr Terry Fern stated: 'We are pleased to have secured the acquisition of 100% of both Blocks 7 and S-1 so we can now concentrate on bringing these acquired oil and gas fields into production. This oil and gas production is critically important to the local Yemeni people to provide employment and revenues, absent since 2015 because of the country’s political issues. We were heartened by the recent welcome and encouragement we received from senior members of the Yemen Government currently based in Riyadh, Saudi Arabia, and hope this offered support will allow the early restart of production of the An Nagyah Oilfield, which will demonstrate to the World that foreign investment is welcome in Yemen, and will encourage other foreign oil companies to join us in rebuilding the Yemen oil industry. We look forward to working with the Ministry of Oil & Minerals in developing Yemen’s oil and gas industry.' Original article link Source: Petsec Energy

Yemen (Shabwa Sub-basin (Marib-Al Jawf-Hajar B.)) Habban

Zenith proposed acquisition of Nordic Petroleum under a share deal (DEA 4 Nov '19) has been scrapped. The decision is said to be due to unexpected complications and potentially high costs.

Zenith proposed acquisition of Nordic Petroleum under a share deal (DEA 4 Nov '19) has been scrapped. The decision is said to be due to unexpected complications and potentially high costs.

In mid-December 2019, Mellitah Oil and Gas BV (Mellitah) was logging the NC169A A 58 exploration well in the Al Wafa field, NC 169A (Wafa) block. The well was spudded on 25 September 2019 with the NWD 11 land rig to a TD of 2,601 m. Mellitah is a joint venture formed by the National Oil Corporation (NOC, 50%) and Eni (50%). The Al Wafa field is an oil, condensate and gas field separated into a north and a south area. The southern part of the field was discovered by Shell in 1964 with the D1-52 well which tested 166 bc/d & 3 MMscf/d. The northern part of the field is the main producing field and was discovered by Sirte Oil in June 1991 after a test of 20 MMscf/d from Devonian. On 15 January 2018, the Libyan National Oil Company (NOC) and the Algerian national oil company Sonatrach signed an agreement to jointly work on a reservoir development plan for their respective Al Wafa and Alrar fields. Both Al Wafa and Alrar are located along the central part of the Libya-Algerian border in the north-eastern limit of the Illizi Basin.

In mid-December 2019, Mellitah Oil and Gas BV (Mellitah) was logging the NC169A A 58 exploration well in the Al Wafa field, NC 169A (Wafa)

Panyu 4-2/5-1 field area, S. Xijiang Sag, S. China Sea, WD 90m, ops terminated (results n/a) on 22 Apr ’18, Nanhai 2 SS. Target Oligo-Miocene sst.

Panyu 9-6-1 (PY 9-6-1) nfw Panyu 4-2/5-1 field area, S. Xijiang Sag, S. China Sea, WD 90m, ops terminated (results n/a) on 22 Apr ’18, Nanhai 2 SS. Target Oligo-Miocene sst.

Jinzhou 19-1-1 (JZ 19-1-1) was suspended (results TBC) on or around 18 March 2020 after having been spudded on or around 22 February 2020, using the "Zhongyouhai 6" jack-up. The oil and gas exploration well was likely targeting the Guantao, Dongying and Shahejie formations. Jinzhou 19-1-1 is in the CNOOC operated Jinzhou 09 Block in the offshore Liaodong Bay, Bohai Gulf Basin. <P />

Jinzhou 19-1-1 (JZ 19-1-1) was suspended (results TBC) on or around 18 March 2020 after having been spudded on or around 22 February 2020, using the "Zhongyouhai 6" jack-up. The oil and gas exploration well was likely targeting the Guantao, Dongying and Shahejie formations. Jinzhou 19-1-1 is in the CNOOC operated Jinzhou 09 Block in the offshore Liaodong Bay, Bohai Gulf Basin. <P />

Pursuant to Total’s assignment of a 40% stake in the Ruwais Diyab unconventional gas block/project (DEA 12 Nov ’18), Total is fracking + testing 3 wells. The company has also assumed operatorship effective 1 Feb ’19. ADNOC retains a 60% stake in the contract, shown below (Total map).

Pursuant to Total’s assignment of a 40% stake in the Ruwais Diyab unconventional gas block/project (DEA 12 Nov ’18), Total is fracking + testing 3 wells. The company has also assumed operatorship effective 1 Feb ’19. ADNOC retains a 60% stake in the contract,

In a transaction valued at USD 3.2 billion (including a stock transfer, assumption of long-term debt and preferred shares), Callon Petr will take over / merge with fellow Houston-based shale player Carrizo O&G, increasing their positions in the Permian (particularly Delaware Basin) and Eagle Ford areas. The new company will be held by Callon and Carrizo shareholders on a 54:46 basis. Companies’ combined prod for Q1 ’19 was 102,300 boe/d (71% oil).

Callon Petroleum is taking over fellow US shale player Carrizo Oil & Gas in a deal worth US$3.2 billion. The combined company will have more than 200,000 net acres in the Permian basin and Eagle Ford shale.

Carnarvon Petroleum Ltd is offering equity in exploration permits AC/P62 and AC/P63, located in the Vulcan Sub-basin, Bonaparte Basin. A dataroom became available from end-October 2019 to demonstrate Jurassic, Triassic and Permian prospects. The Vulcan Sub-basin is an oil region from proven Triassic, Jurassic and Cretaceous reservoirs. Producing fields include Montara, Skua and Swift which have produced at rates of several Mbopd from individual wells. Carnarvon has stated that from recent broadband and full wave form inversion reprocessing of seismic data, small, intragraben structures can now be mapped accurately, increasing the understanding of fault structures and the prospectively of the basin. AC/P62 covers an area of 1,503 sq km in the Vulcan Sub-basin and was awarded for a period of six years on 2 November 2017. Carnarvon holds 100% interest in the permit and is offering a farminee circa 40% equity in return for paying 100% of the seismic data licensing fees for Carnarvon. Carnarvon reported that it has already licensed the recently acquired Cygnus 3D data, which covers 682 sq km of the AC/P62 area which has been utilised to improve geological interpretations. The 2010 Cartier 3D survey also covers all of the licenced area. In the initial guaranteed three-year term, to be completed by November 2020, Carnarvon has been undertaking a review of available data including petrophysics data, fault seal analysis and well biostratigraphy reviews. In the following terms, to be committed to on a year by year basis, well planning is outlined for permit year four, with the subsequent well drilled in year five. Total cost for the six-year work programme is estimated at around AUD 37 million. However, in April 2020, Carnarvon submitted a programme suspension application to the National Offshore Petroleum Titles Administrator (NOPTA). The assessing Joint Authority is providing increased flexibility for operators to alter permit conditions where impacts of the coronavirus disease 2019 (COVID-19) are apparent (including the reduced capability to complete programmes). If the application is approved, the work programme is likely to be suspended for a period of 12 months. AC/P62 contains two existing discoveries and nine historical dry wells or wells with shows. Keeling and Great Auk were discovered in January 1990 and May 2009 respectively and are considered non-commercial. The fields and surrounding dry wells are located on basin bounding horst structures with faults to seabed which Carnarvon has stated are likely leaking, completely or partially, from traps. Carnarvon has delineated three oil prospects in the Triassic and Jurassic sections: Vulture, Chick and Birdie. There are also four, large, Permian oil prospects, including Moa. Within the basin, Permian targets are yet to be explored, but Carnarvon interprets high potential within reefal plays where the risk of hydrocarbon retention could be mitigated by a middle Triassic seal. The Moa Prospect is a Permian reef play which covers an area of approximately 132 sq km and where the crest sits at a depth of around 4,500 m. AC/P63 covers an area of 585 sq km and was awarded for a period of six years on 8 February 2018. Carnarvon holds 100% interest in the permit and is offering a farminee to acquire circa 50% equity in return for assisting with the year five work programme to drill the Toucan Prospect (estimated AUD 30 million). Carnarvon reports that it has identified a number of Jurassic and Cretaceous leads within the previously difficult to image intra graben areas, within structures that have faults which terminate within the Jurassic/Cretaceous syn rift, similar to the locations of intra graben fields such as Skua and Montara. The Jurassic Toucan Prospect is considered 'drill-ready' with around 6 sq km closure with 140 m of vertical relief. The primary target would be the crest of a structural high of the Plover Formation at around 1,900 m below sea level. Carnarvon interprets that hydrocarbon charge could come from both the Plover and Vulcan formations and the trap is considered fault bounded, terminating in the Cretaceous level. Work commitments assigned to AC/P63 include, for the first three-year period, licensing or purchasing 3D data from the Cygnus survey, undertaken in late 2015/early 2016, and analysis and reprocessing of this, and additional, seismic over the licence area. A well is planned under the contingent work commitments, scheduled between February 2022 and February 2023. Pre- and post-well studies are also included in the work commitments. Companies interested in pursuing this opportunity should contact: Stephen Molyneux – Exploration Manager Tel:      +61 8 9312 2665 Email:  smolyneux@cvn.com.au Jeff Goodall, Chief Geologist Email: jgoodall@cvn.com.au

Carnarvon Petroleum Ltd AC/P62 and AC/P63, Bonaparte Basin - farm-in opportunity open

In early April 2020, Occidental of Oman Inc (Oxy) completed operations at the Artal 1 exploration well in its 4,080 sq km Block 9 (Suneinah) licence. No result has been reported however a 2-7/8" completion has been run. The 6-1/8" lateral hole reached a TD of 3,232 m. The initial pilot hole was drilled to a depth of 3,085 m. Artal 1 was spudded on 24 February 2020 and has an initial PTD of approximately 3,073 m. Following the exploration and production sharing agreement revision in early-2017, participants in Block 9 are Occidental of Oman Inc. (50% - operator), OQ Upstream (45%) and Mitsui E&P Middle East BV (MEPME) (5%).

Oman, not found

SONATRACH and OMV signed a Memorandum of Understanding to initiate discussions with a view to identifying the possibilities for both parties to jointly invest in exploration, development and production of hydrocarbons in Algeria. The Memorandum of Understanding shows the interest of both parties in assessing opportunities for collaboration following the recent promulgation of the new hydrocarbons law. SONATRACH has also signed a Memorandum of Understanding with CEPSA in order to examine the possibilities of joint investment in the fields of exploration, development and production of hydrocarbons in Algeria. and internationally. The signing of this protocol will also allow SONATRACH and CEPSA to consolidate their existing partnership, through the search for new cooperation opportunities. Through the conclusion of this Memorandum, SONATRACH confirms its desire to consolidate its partnership policy, particularly within the framework of the provisions of the Law on Hydrocarbon Activities, which aim in particular to increase hydrocarbon reserves and production levels. Original article link Source: SONATRACH  

SONATRACH and OMV and CEPSA signed a MOU to initiate discussions with a view to identifying the possibilities for both parties to jointly invest in exploration, development and production of hydrocarbons in Algeria.

16th discovery in Stabroek block, NE of Liza in deepwater Guyana Basin, WD 1,933m, 29m oil sst reservoir, Noble Tom Madden DS. Block gross discovered recoverable resources now >8 Bboe, not yet counting Uaru. ExxonMobil (op), partners Hess + CNOOCI.

Uaru 1 (ExxonMobil 45% op, Hess 30%, CNOOC-Nexen 25%) in Stabroek block located approximately 16km NE of the Liza fild, sixteenth discovery, encountered approximately 29m of high-quality oil-bearing sandstone reservoir. Operator stimated gross discovered recoverable resources, includes 15 discoveries, for the block to more than 8 Boe, up from the previous estimate of 6 Boe.

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

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