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Cairn has joined the regional bandwagon and secured sole preliminary rights to block 61, ca. 13,000-sq km area on the Demerara Plateau, eatersn offshore, in 1Q ’18. The assignment was presumably made under the open door 2017 offer by Staatsolie. PSC negotiations are underway with Staatsolie with a view to finalising the contract. 2D seismic and contingent 3D seismic are proposed in as of 2019. 

Cairn has secured sole preliminary rights to block 61, ca. 13000km² area.

NW part of block III, Talara Basin, drilled + P&A dry between 30 Mar – mid-May ’18, TD 2,092m. Targets Mal Paso + Salina Mogollón fm’s.

Lagunitos-13433X (Grana y Montero Petrolera 100%) in Block III, P&A, dry.

On 1 December 2017, Chevron USA was officially awarded Keathley Canyon blocks KC 53 (G36114) and KC 97 (G36115), situated in the East Texas Coastal Basin. KC 53 and KC 97 were originally offered as part of Western Gulf of Mexico Lease Sale 249, which was held on 16 August 2017. The leases are expected to expire on 30 November 2024. Following official award, Chevron USA is now the operator and sole interest-holder (100% WI + Op) in KC 53 and KC 97.

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Socar and Lukoil used the Davos venue to sign an MoU on the joint exploration of a block containing the Goshadash + Precaspian-Guba structures, as well as a block containing the Nakhchivan structure in shallowish waters of the South Caspian Basin.

Socar and Lukoil used the Davos venue to sign an MoU on the joint exploration of a block containing the Goshadash + Precaspian-Guba structures, as well as a block containing the Nakhchivan structure in shallowish waters of the South Caspian Basin.

The recent allocation of 5 offshore blocks to Tullow is in limbo, Peruvian lawmakers questioning why the awards were made the same day as the resignation of the former president on 24 March. A bill is understood to have been submitted which could invalidate the awards based on failure to conduct a proper public consultation process.  Blocks involved are Z-64 through Z-68, WD 50-3,500m (DEA 10 Jan ’18).

The recent award of five offshore blocks to Tullow Oil have been drawn into question with additional Peruvian lawmakers questioning why the awards were made the same day as the resignation of the former president. Tullow has indicated on its website it is awaiting official award of the blocks.

On 8 May 2019 the Romanian High Court ruled that the state must move forward with the sale of an 8% stake in OMV Petrom to the company’s employees as provided by the 2003 decree on the privatization of the former state company. It is recalled that Petrom was sold to Austria’s OMV in 2004 for a consideration of EUR 1.5 billion, the Romanian state keeping a 20.6% share in the group. If implemented, the sale of the 8% stake to Petrom’s employees, which has been long delayed due to difficulties to determine which employees should be entitled, should be done at the same price paid by OMV in 2004, i.e. approximately 54% of the current price of the share. It remains unclear which employees would be allowed to purchase the shares (at the time of privatization Petrom was employing 60,000 persons versus 12,500 today). The ruling coalition in Romania was discussing the matter in late-June 2019.

On 8 May 2019 the Romanian High Court ruled that the state must move forward with the sale of an 8% stake in OMV Petrom to the company’s employees as provided by the 2003 decree on the privatization of the former state company.

Eight blocks totalling 26,210 sq km are to be available auctionless in the Yamal-Nenets AO, W. Siberia. Applications to Uralnedra by 4 Feb '20. Should any block receive multiple valid applications, it will be withdrawn and auctioned. Contact: Uralnedra, 620014, Yekaterinburg, Vaynera St 55.

Eight blocks totalling 26,210 sq km are to be available auctionless in the Yamal-Nenets AO, W. Siberia. Applications to Uralnedra by 4 Feb '20.

Pursuant to the Aug '19 acquisition by Oxy of Anadarko, and the subsequent sale to Total of most assets, the latter announces today the intended deal to acquire those assets involved cannot be concluded. This leaves Occidental with sizeable assets in the country, which Sonatrach is unlikely to take on as earlier suggested using its pre-emption rights, its financial clout having been reduced under the current industry crisis.

Pursuant to the Aug '19 acquisition by Oxy of Anadarko, and the subsequent sale to Total of most assets, the latter announces today the intended deal to acquire those assets involved cannot be concluded. This leaves Occidental with sizeable assets in the country, which Sonatrach is unlikely to take on as earlier suggested using its pre-emption rights, its financial clout having been reduced under the current industry crisis.

Guercif Licence, onshore Guercif Basin, Predator currently working on an EIA for the USD 2-million well, which will target the Moulouya prospect and spud by end-year. Company is seeking farm-in partners to dilute its 75% stake and finance the larger 3-well expl programme. Currently, state company ONHYM is sole partner.

Guercif Licence, onshore Guercif Basin, Predator currently working on an EIA for the USD 2-million well, which will target the Moulouya prospect and spud by end-year. Company is seeking farm-in partners to dilute its 75% stake and finance the larger 3-well expl programme. Currently, state company ONHYM is sole partner.

In late February 2019, sources reported that Apache is planning to divest its US Gulf of Mexico acreage, which encompasses assets in all three regions of the US GOM (Western, Central and Eastern). This follows an earlier divestment of deepwater projects that occurred in 2014, when Apache transferred stakes in its Lucius and Heidelberg development projects and 11 exploration blocks to Freeport-McMoRan for a total of US$ 1.4 billion, in order for Apache to shift its focus towards to more shallow water ventures. Apache currently holds equity in over 30 deepwater GOM leases and five producing fields. These include Desoto Canyon blocks DC 710 and DC 711, East Breaks blocks EB 158, EB 159 and EB 597 (encompassing Bilboa - a producing oilfield), Ewing Banks blocks EW 746, EW 782, EW 785, EW 826, EW 911, EW 954, EW 966 and EW 998, Garden Banks blocks GB 463 and GB 506, Green Canyon blocks GC 490 (Wide Berth - a producing gas field), GC 647, GC 691, GC 692, GC 991 and GC 992, Mississippi Canyon blocks MC 150 (Cognac - producing oilfield), MC 267, MC 268, MC 30, MC 311 (Bourbon - producing oil and gas field), MC 312, MC 357, MC 358, MC 366 and MC 573 and Viosca Knolls Block VK 873 (Einset - a producing oil and gas field). During Q3 2018, Apache's US GOM assets produced 3,037 bo/d and 10.280 MMcfg/d, down from the same quarter in Q3 2017, when the company produced 3,512 bo/d and 10.196 MMcfg/d.

Apache is planning to divest its US Gulf of Mexico acreage, which encompasses assets in all three regions of the US GOM (Western, Central and Eastern). This follows an earlier divestment of deepwater projects that occurred in 2014, when Apache transferred stakes in its Lucius and Heidelberg development projects and 11 exploration blocks to Freeport-McMoRan for a total of US$ 1.4 billion, in order for Apache to shift its focus towards to more shallow water ventures. Apache currently holds equity in over 30 deepwater GOM leases and five producing fields. These include Desoto Canyon blocks DC 710 and DC 711, East Breaks blocks EB 158, EB 159 and EB 597 (encompassing Bilboa - a producing oilfield), Ewing Banks blocks EW 746, EW 782, EW 785, EW 826, EW 911, EW 954, EW 966 and EW 998, Garden Banks blocks GB 463 and GB 506, Green Canyon blocks GC 490 (Wide Berth - a producing gas field), GC 647, GC 691, GC 692, GC 991 and GC 992, Mississippi Canyon blocks MC 150 (Cognac - producing oilfield), MC 267, MC 268, MC 30, MC 311 (Bourbon - producing oil and gas field), MC 312, MC 357, MC 358, MC 366 and MC 573 and Viosca Knolls Block VK 873 (Einset - a producing oil and gas field). During Q3 2018, Apache's US GOM assets produced 3,037 bo/d and 10.280 MMcfg/d, down from the same quarter in Q3 2017, when the company produced 3,512 bo/d and 10.196 MMcfg/d.

Kheir block, Gulf of Suez onshore, TD 927m, oil find, tested the Rudeis and/or Kareem fm's, no specifics, EDC rig 2.

Kharaza 1 (Kuwait Egy. 70% op, Petrogas 30%) in Kheir block, onshore, TD=927m, oil disc. oil presumably flowed from the Yusr Member of the Burdigalian Rudeis Fm or from the Serravallian Kareem Fm, no specifics.

Babejia field area, Golaghat Extn IIA ML North block, S. Assam Arakan Basin, tested 560 bo/d + 195 Mcfg/d on 6 mm choke from between 2,357-2,361m in the Sylhet fm, and 483 Mcfg/d on 6,, choke from between 2,5352,631m in the Basement.

Babejia 2 (BJAB) npw Babejia field area, Golaghat Extn IIA ML North block, S. Assam Arakan Basin, tested 560 bo/d + 195 Mcfg/d on 6 mm choke from between 2,357-2,361m in the Sylhet fm, and 483 Mcfg/d on 6,, choke from between 2,5352,631m in the Basement.

CNH-RO1-LO2-A1/2015 (aka Area 1) contract, ab. 1.5km NE of discovery in WD 33m, offshore Sureste Basin / Campeche Bay, TD 4,220m, 40m net oil pay in the Orca fm, 27m net oil again in the deeper Cinco Presidentes fm, tested 7,000 b/d of 30 API oil (no CO2 nor H2S), constrained, potential 10,000 b/d upon completion. West Castor JU.  Results, along with the reservoir models of the Amoca and Miztón fields, have raised Eni’s estimate of Area 1 hc in-place to 2 Bboe, 90% oil. The PoD for Area 1 will soon be submitted to the CNH for approval. Production target 1H ‘19.

Tecoalli 2DEL appraisal well by Eni (100%) in Area 1 (CNH-R01-L02-A1/2015), test flowed at an equipment-constrained rate of 7000 bo/d of 30°API oil (no CO2 nor H2S), but is expected to deliver at a rate of 10000 bpd on completion.

SONATRACH and ExxonMobil signed a Memorandum of Understanding (MoU) to initiate joint discussions on potential exploration and development opportunities in Algeria. The Memorandum of Understanding shows the interest of the parties in evaluating the options for collaboration following the recent promulgation of the new Algerian hydrocarbons law. Original article link Source: SONATRACH

Algeria, not found

Repsol has signed a service contract for the 644-sq km Iniguazu block in the Chaco Basin, the result of a presidential approval that was received a year ago. Repsol is partnered by Shell Pan American Energy and YPFB Andina. Regional targets Huamampampa, Icla + Santa Rosa fm’s.

Repsol has signed a service contract for the 644-sq km Iniguazu block in the Chaco Basin, the result of a presidential approval that was received a year ago. Repsol is partnered by Shell Pan American Energy and YPFB Andina. Regional targets Huamampampa, Icla + Santa Rosa fm’s.

NW Gharib block, E. Desert, susp oil (34m of Red Bed reservoir) at TD 1,620m in mid-Dec ’17.

Egypt, not found

Alaminos Canyon block 728, OCS lease 31195, cleared to P&A by the BOEM on 17 Nov ’17, results yet n/a, Deepwater Pontus DS’ 1st assignment. Shell (op), partner Chevron.

United States (Deep Water Gulf of Mexico B.) ? op. by SHELL (60.0%, CVX 40.0%) in AC 728 block

Ecopetrol reports that its subsidiary in the United States, Ecopetrol America Inc., was awarded four blocks in Lease Sale 249, a competitive process carried out in that country for the exploration of hydrocarbons in deep waters of the Gulf of Mexico. The blocks awarded were Garden Banks 77, 78, 121 and 122. In these areas there are prospects such as the so-called 'Blacktail', close to production platforms, which would allow, in case of a discovery, obtain early production thanks to the possibility to connect with existing facilities in the area. The proposal to achieve the award of the blocks was led and presented by Ecopetrol America, which has 50% of the participation. Repsol E & P USA Inc will be the operator and will have the remaining 50%. The results were announced by the Bureau of Ocean Energy Management (BOEM). The award grants the right to the two companies to explore the blocks for five years at an approximate water depth of 240 meters. The new blocks are part of Ecopetrol's exploratory strategy to increase reserves and hydrocarbon production, which has offshore areas as one of its priority areas. Likewise, the incorporation of the 'Blacktail' prospect to the portfolio reinforces the initiative of focusing on prospects close to areas with existing infrastructure. 'We are pleased to increase the presence in areas with high potential offshore the Gulf of Mexico in the United States, where we already have a production exceeding 12 thousand barrels per day, thanks to the outstanding work of our technicians and the partnership with a partner like Repsol , with which we have other exploratory projects in Colombia and abroad,' assured the president of Ecopetrol, Felipe Bayón. Original article link (in Spanish) Source: Ecopetrol

Repsol (op. 50%, Ecopetrol 50%) was awarded 4 Garden Banks blocks 77, 78, 121 and 122.

Total spudded exploration well 30/12d-11 in licence P1820 on 13 October 2019 targeting the Isabella prospect. The HP/HT (12,960 psi and 175 degrees centigrade) gas condensate prospect is located on one of the largest undrilled fault blocks in the Central North Sea and is thought to hold pre-drill estimated resources of 142 MMboe. The well was drilled with the Noble Sam Hartley (J/U). On 11 March 2020 Total confirmed that it was plugging and abandoning the well. The Isabella trap is formed by closure on a salt pierced anticline. The reservoir target is the Triassic Joanne and Judy Sandstones. The well which is planned to be slightly deviated has an estimated TD of 5,607 m and dry hole cost of GBP 57 million (125 day well). P1820 was awarded in the 26th Offshore Licensing Round to Valiant and Apache North Sea Ltd. On 23 September 2013 Ithaca announced that it has agreed to farm down a 10% interest in licence P1820 (blocks 30/6b, 30/11a and 30/12d) to Edison subsidiary EDF Production UK Limited in return for a cash payment. It was confirmed that the deal completed on 31 December 2013. On 13 August 2018 Neptune announced that it had agreed to acquire Apache’s interest in the licence and then late 2018 / early 2019 the operatorship was transferred over to Total. Interest in P1820 is held by Total E&P North Sea UK Limited (30% + operator), Neptune E&P UK Limited (50%), Edison subsidiary, Euroil Exploration Limited (10%) and Ithaca Energy (UK) Limited (10%).

030/12d-11 (Isabella) - P1820 Total (30% + Op), Neptune 50%, Delek subsidiary Ithaca Energy UK Ltd 10%, EDF (Edison) via subsidiary Euroil Exploration Ltd 10%) Kimmeridge U Jurassic reservoir: 10m net gas pay, Trias Joanne reservoir : 30 m net pay

PL 719 / block 7321/8, Fingerjupet High in Barents Sea, WD 466m, TMD 1,874m (1,777m TVD, Snadd fm), P&A dry, Leiv Eiriksson SS off to 16/1-33 S (Sorvesten) in PL 780. Main targets Stø, Fruholmen + Snadd fm's. Spirit (op), partners Lukoil + Aker BP.

Norway (Barents Sea Platform), 7321/8-2 S nfw (Sandia), in PL 719 op. by CENTRICA (35%), LUKOIL (30%), AKER BP (20%), MUNCHEN ST (12%), BAYERNGAS (3%), Tigas (0%), P&A dry. The primary target formations were the Middle Jurassic-Upper Triassic Sto, Fruholmen and Snadd. Sandsone reservoirs were encountered in all three, at thicknesses of 20 m, 30 m and 2 m respectively, but were found to be water-bearing. The well had an additional target in the Lower Cretaceous Kolje formation, which was also found to be dry with traces of hydrocarbon. The well was drilled to a TD of 1,899 m MD (1,777 m TVDSS) and terminated in the Upper Triasic Snadd formation.

On 8 November 2018, the Federal Agency for Subsoil Use held an auction for the Leskinskiy Yuzhnyy block in Krasnoyarsk Kray (Eastern Siberia). Novatek-Yurkharovneftegaz won the contest with the offer of RUB 2,041 million (USD 30.9 million), almost 60 times higher of the starting price. The winner of the auction will obtain a 27-year E&P license including a 7-year exploratory stage. The Leskinskiy Yuzhnyy block covers 3,630 sq km in the western part of the Yenisey-Khatanga Basin. Seismic coverage amounts to 360 km. No wells have been drilled in the block. Hydrocarbon resources (category D2) of the block are estimated at 120 MMbbl of oil and 4.3 Tcf of gas. The starting price amounted to RUB 35 million (USD 0.53 million). The block is adjacent to licences operated by Novatek in Krasnoyarsk Kray and Yamalo-Nenets Autonomous Okrug.

Russia Novatek wins Leskinskiy Yuzhnyy license in Yenisey-Khatanga for USD 31 million

Battonya-Pusztafoldvar Dél (South) contract, Békés sub-basin in SE Hungary, tested 2 MMcfg/d, no water for 6 hrs on 28/64” choke, WHFP 543 psi, from 884-893m in Pannonian sst.

Mezohegyes-21 appr Battonya-Pusztafoldvar Dél (South) contract, Békés sub-basin in SE Hungary, tested 2 MMcfg/d, no water for 6 hrs on 28/64” choke, WHFP 543 psi, from 884-893m in Pannonian sst.

1st of 2 appr’s planned in South Disouq block, onshore Nile Delta Basin, TD 2,379m, 27m net conventional gas pay in the target Abu Madi, to be tested + completed as a producer Rig to SD-3X next. SDX (op), partner IPR. www.sdxenergy.com.

SD-4X pos. appr. (SDX op.55%, IPR Egy. 45%) in onshore South Disouq licence, TD=2379m, 27m net conventional gas pay in the target Abu Madi, to be tested + completed as a producer.

NW part of the Aruba deepwater block, TD reached (n/a) by end August, probably completed by now as West Capella DS taken by Sabah Shell for a 5-well campaign + potential options starting Oct ’18. Repsol (op), partners Total + Shell.

NW part of the Aruba deepwater block, TD reached (n/a) by end August, probably completed by now as West Capella DS taken by Sabah Shell for a 5-well campaign + potential options starting Oct ’18. Repsol (op), partners Total + Shell.

Armour Energy Ltd is looking to farm-down its 100% owned exploration licences across the McArthur and Georgina basins. Armour operates six licences under the jurisdiction of the Northern Territory: EP 171, 174, 176, 190-192, which are all available for farm-in. There are also seven applications in place which were lodged between 2009 and 2010, covering nearly 45,000 sq km and Native Title negotiations are ongoing. Armour was also offering interest in an additional exploration licence and four applications across the region and into Queensland jurisdiction. On 15 October 2019 Armour reported that it had entered into an agreement with Santos, for Santos to acquire 70% interest in ATP 1087-P and applications ATP 1107-P, ATP 1192-P, ATP 1193-P, EP(A) 172 and EP(A) 177. The deal is worth around AUD 15 million plus a further AUD 65 million in work programme commitments. Across ATP 1087-P, Armour reports 364 Bcf of contingent resources (3C) to date and anticipates enough gas in place to supply a 6 MMtpa LNG plant for 25 years. It was reported by the company that the proof of concept in Egilabria opens up a potential for additional 18.7 Tcf of prospective resources from shale gas, primarily within the Lawn formation and across staked plays. Both the Lawn and Riverleigh formations are considered proven source rocks, which lay under basal anticlinal plays. The source rock quality at Egilabria displayed TOC up to 11% with mature, dry gas. Armour would ideally revisit the wells to conduct an appraisal pilot to target 2-3 Bcf of recoverable gas. In the remaining acreage where Armour operates with 100% interest, the company is seeking a partner to assist in additional seismic acquisition and drill a combination of exploration wells and appraisal/pilot wells to push the needle on 22 Tcf of prospective shale gas resources. A data room is available to review the shale gas plays and shallower, conventional plays which have been identified by Armour. Armour is focusing on shale gas plays and deeper oil plays. The McArthur Basin contains large unexplored areas with stacked play opportunities as identified by Armour from seismic interpretation in the McArthur Group (Barney Formation), and the deeper Tawallah Group (Wollogorang and McDermott formations). To further delineate these opportunities, Armour is looking for a partner to assist with a regional seismic programme before drilling deep stratigraphic wells. To date, just six wells exploration wells have been drilled by Armour in over 45,000 sq km of licensed area. Gas flows up to 3.3 MMcf/d have been achieved from the McArthur Group. Prospective resources for the McArthur Group (Barney Creek Formation), within EP 171 and EP 176, has been reported by Armour to be around 1.2 MMbbl oil and 13 Tcf gas. There are also conventional oil and gas plays, including 18 prospects along the Batten Trough, dominantly in the Coxco Dolomite. The Glyde and Lamont Pass discoveries encountered gas bearing intervals within the dolomites and dolomitic shales of the target Middle Proterozoic Barney Creek Formation prior to drilling in to the Coxco Dolomite Formation which formed the wet gas discovery made by nearby zinc exploration well Glyde River 9, drilled in 1979. Upon lifting of the hydraulic fracturing moratorium, which has been in place since September 2016, the Northern Territory government agreed to implement all of the 135 recommendations laid out in the final scientific enquiry report. This has affected the timeline in relation to the award considerations of Armour's extensive application areas. Non-invasive activities have been permitted during the Native Title negotiations carried out. Armour considers the areas ready for farm-out upon final the awards. Armour Energy Ltd is offering participating equity in seven exploration licences as the company seeks to further test the shale gas/oil and conventional plays present. Interested parties should contact: Richard Fenton – Armour Energy, CEO Email: [email protected]

Armour Energy Ltd is looking to farm-down its 100% owned exploration licences across the McArthur and Georgina basins. Armour operates six licences under the jurisdiction of the Northern Territory: EP 171, 174, 176, 190-192, which are all available for farm-in.

It was announced on 28 November 2019 that Arar Petrol ve Gaz Arama Uretim Pazarlama A.S has been awarded the M42-C exploration licence (Zagros Province) on 22 November 2019 for a period of five-year. The licence, covering an area of 613 sq km, is located towards southeast of the country and Arar Petrol will be 100% owner and operator of the licence. The company had filed the application on 20 November 2018.

Arar Petrol ve Gaz Arama Uretim Pazarlama A.S has been awarded the M42-C exploration licence (Zagros Province)

Hokchi was reported testing oil and gas shows in the Xaxamani 2EXP new-pool wildcat (NPW) in the CNH-R03-L01-AS-CS-15/2018 contract in the offshore Sureste Basin during early-August 2019 according to partner Talos.  The partners plan to conduct a drill-stem test (DST) prior to moving the rig to drill the Tolteca prospect in the block. The NPW spudded in late-July 2019 and reached an unreported total depth (TD) in early-August 2019. The NPW had a proposed total depth (PTD) of 910 m.   The prospect has a primary target in the Lower Pliocene, from 751 m to 784 m and 810 m to 841 m.   The well is being drilled by the Borr Drilling “Odin” J/U in a water depth of 19m.   The NPW is located in the south-eastern area of the block approximately 570 m south-west of the Xaxamani 1 non-commercial oil well drilled by PEMEX in 2003.   The unrisked prospective resources are reported to be 43.6 MMboe. The drilling cost for the Xaxamani 2EXP NPW is USD 18.42 million and the completion cost is estimated to be USD 17.93 million. On 12 July 2019, the CNH approved the drilling permit request submitted by operator Hokchi for the Xaxamani 2EXP new-pool wildcat (NPW). Hokchi is operator of the contract with 75% working interest and lone partner Talos with 25%.   On 12 July 2019, the CNH approved a modification to the exploration plan submitted by operator Hokchi on 31 May 2019 for the CNH-R03-L01-AS-CS-15/2018 contract in the offshore Sureste Basin. The approved modified exploration plan includes the confirmation of the Xaxamani 1 discovery on the block through the drilling of the Olmeca prospect, now named the Xaxamani 2EXP well with a modified location with respect to the discovery well.  If successful, then there will be an evaluation plan proposed.  The operator maintained two possible drilling scenarios for the block pending results of the Olmeca prospect. On 12 April 2019, the CNH officially approved of the Talos farm-in to the Hokchi operated CNH-R03-L01-AS-CS-15/2018 contract.  The new working interest breakdown in the contract is Hokchi operator with 75% working interest and Talos with 25% working interest. On 27 June 2018, Hokchi Energy (Pan American) with 100% working interest was granted an official PSC contract award for the 264.24 sq km CNH-R03-L01-AS-CS-15/2018 contract from the CNH-R03-L01/2017 Bid Round.  The company bid the maximum state take of 65.00% over the minimum of 22.5% for the Area 31 block and a work units factor of 1 equivalent to one well.  There were two other bids for the block.  The second highest bidder was the consortium of ENI and Lukoil who bid 42.35% state take and 1 additional work units factor. On 27 March 2018, Pan American Energy with 100% working interest was granted a preliminary award for the contract.

Hokchi was reported testing oil and gas shows in the Xaxamani 2EXP new-pool wildcat (NPW) in the CNH-R03-L01-AS-CS-15/2018 contract in the offshore Sureste Basin during early-August 2019 according to partner Talos.

A15-A gasfield / A15a licence, drilled 11-29 Apr ’19, ops terminated results n/a, Maersk Resolute JU. Petrogas (op), partners RockRose + EBN.

A/15-05 (Petrogas op. 36%, RockRose 24%, EBN 40%), A15-A gasfield in A15a licence, ops terminated results n/a.

Pursuant to Egdon’s takeover of Cirque Energy’s 100% in EXL 294 containing the Fiskerton field east of Lincoln, East Midlands (DEA 31 Oct ’17), Union Jack has agreed to farmin to the small 3-block licence with 20%.  The deal is valued at GBP 137,000, and UJ will fund 3D seismic re-processing around Fiskerton to identify further production opportunities from the reservoir. The 1997 Fiskerton Airfield-1 discovery and now field flows from the Westphalian Basal sst at ab. 16 bo/d, 30-40 b/d planned after workovers.

Union Jack Oil has agreed to acquire a 20% stake in Fiskerton Airfield (EXL 294 block) from Egdon Resources (->80%).

NOGA is after a potential 50% partner in its so far wholly-owned AC/L5 containing the Corallina + Laminaria fields, offshore Bonaparte Basin. The partner is sought to participate in further devt of the producing fields. Contact: [email protected] or [email protected].

NOGA is after a potential 50% partner in its so far wholly-owned AC/L5 containing the Corallina + Laminaria fields, offshore Bonaparte Basin. The partner is sought to participate in further devt of the producing fields.

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

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

As of April 2020, China National Offshore Oil Corp (CNOOC) is seeking partners in its BC9 and BCD10 contracts in the Gabon Coastal Basin offshore Gabon. The company operates the contracts BC9 and BCD10 with a 100% interest since Shell exited the licences in November 2019. The company attempts to farm out up to 50% stake prior to drill two high impact wells between late 2020 and 2021, one in each block. According to CNOOC all commitments have been met in both contracts. The company is to enter, in September 2020, in the 2-year fourth exploration period of the BC9 contract with the possibility to be extended up to three years. The BCD10 licence holds the multi Tcf Leopard gas discovery (2014) and is in a gas holding period until 2026 with minimal work commitments. CNOOC identified, both in post-salt and in pre-salt sequences, some 25 leads and/or prospects of which two are drill-ready. The "Tigre" prospect is to be drilled in about 2,000 m of water depth in the BC9 block targeting an approx. 100 sq km area in the pre-salt Gamba sandstones of Aptian age. The "Seal" prospect is to be drilled in approx. 400 m of water depth in the southeastern corner of the BCD10 block targeting the carbonate of the Albian Madiela Group formation in a large 3-way structure with mean recoverable resources estimated at 356 MMbo. CNOOC is also working on the Leopard gas discovery studying for a further appraisal program to determine the feasibility of a standalone development. CNOOC has open a data room since March 2020 with an anticipated bid deadline in mid-2020. Contact details:         Lucas Ong Business Development Advisor                          E-mail: [email protected]               Tel: +44 1895-555319 Ben Kilner Team Lead, Global Exploration                          E-mail: [email protected]               Tel: +44 1895-555310   Background information The blocks BC9 and BCD10 were initially granted to Shell on September 2007. BC9 and BCD10 blocks are mainly in deep waters, covering a total of some 13,400 sq km of which about 530 sq km are in shallow waters. CGG acquired a 6,000 sqkm 3D seismic program between 2010 and 2011. CNOOC farmed in both blocks in 2012. The partners drilled a first wildcat N'Komi Marin 1 in 2014, the well intersected a 200 m paleo-oil column in the pre-salt Gamba formation. It was followed by a success with the Leopard gas and condensate discovery made in October 2014. The latter drilled to TD of 5,063 m intersected a substantial gas column of 200 m of net gas pay in the Gamba formation. The discovery was confirmed by the appraisal Leopard 2 suspended in January 2016. CGG completed in March 2016 the acquisition of a 3D seismic program in the BCD10 block. Six exploration wells were drilled before 2007, in the areas covered by the actual BC9 and BCD10 blocks, targeting post-salt objectives such as the Cenomanian Cap Lopez formation and the Albian Madiela Group formation. All were dry except the Grand Large N'Kendji Marine 1 wildcat, which encountered non-commercial oil in February 1985. The well, drilled by Elf Gabon, is located 85 km west of Sette Cama in 163 m of water. It bottomed in the Albian Madiela Group at a depth of 3,893m.

China National Offshore Oil Corp (CNOOC) is seeking partners in its BC9 and BCD10 contracts in the Gabon Coastal Basin offshore Gabon.

Final in 4-well back-to-back programme in Fracción D, onshore Austral Basin, Cañadon Salto field area in W. part of block, TD 1,511m, > 60m gas column interpreted from wireline logs in the Tobifera, 30m potential net wet gas pay between 1,272-1,304m. Testing planned using the Quintana 1 rig, Petreven H-205 rig. CGC (op), partner Echo Energy.

Final in 4-well back-to-back programme in Fracción D, onshore Austral Basin, Cañadon Salto field area in W. part of block, TD 1,511m, > 60m gas column interpreted from wireline logs in the Tobifera, 30m potential net wet gas pay between 1,272-1,304m. Testing planned using the Quintana 1 rig, Petreven H-205 rig. CGC (op), partner Echo Energy.

Shell bagged WA-534-P, 2,716 sq km in the Caswell sub-basin (Bonaparte Basin), on 20 Sep ‘18.  for 6 yrs. Commitments include new seismic in yr 4 + 1 well in yr 5.

Shell bagged WA-534-P, 2,716 sq km in the Caswell sub-basin (Bonaparte Basin), on 20 Sep ‘18. for 6 yrs. Commitments include new seismic in yr 4 + 1 well in yr 5.

Todd is looking to farmout part of its 50% operating stake in PEP 57080, 2,446 sq km in the offshore Taranaki Basin, ahead of 3D seismic. Partner Beach. The company is also farming out a significant equity in its wholly-owned PEP 60094, 2,153 sq km in the offshore Eastern Taranaki Mobile Belt. Contact [email protected].

Todd is looking to farmout part of its 50% operating stake in PEP 57080, 2,446 sq km in the offshore Taranaki Basin, ahead of 3D seismic. Partner Beach. The company is also farming out a significant equity in its wholly-owned PEP 60094, 2,153 sq km in the offshore Eastern Taranaki Mobile Belt.

Talon has agreed to acquire a 10% stake from Corallian Energy in the 121-sq km P2396 containing the 45mmboe 1977 Curlew oil discovery, a 1st move in an attempt to widen the Australian company’s North Sea presence. Talon will fund 15% of a planned Curlew-A appraisal. The deal is subject to OGA approval and will result in Corallian (op) 90%, Talon 10%.

United Kingdom, Curlew

Bridgeport Energy Ltd reported in August 2019 that it was farming out interest in permits ATP 2023-P, ATP 2024-P, ATP 948-P and PL 256, located in the Cooper-Eromanga Basin, to New Era. Bridgeport is farming down non-operated interest to New Era Oil and Gas in the permits. ATP 2023-P and ATP 2024-P are in the application stage. Bridgeport solely applied for the permits and was reported as preferred tenderer in January 2017. They remain pending award.  The applications cover areas of 434 sq km and 421 sq km respectively. New Era is farming in for 50% in these assets. Under the terms of the farm-in, once the permits are awarded, as authority-to-prospect licences, New Era will fund part of a four-year work programme, to include seismic and drilling. ATP 948-P was awarded on 1 June 2014 and covers an area of 2,004 sq km. Bridgeport holds 100% interest in the permit. PL 256 covers 15 sq km and was awarded on 17 April 2014.  The licence contains the Bargie oil field, which was discovered in January 1994 and is producing. Bridgeport holds 93.9% and operatorship, with joint venture partner Inland Oil (Production) Pty Ltd holding the remaining 6.1%. Bridgeport reported it is farming out 30% to New Era. Under the farm-out to New Era, Bridgeport reported that the companies were planning drilling within ATP 948-P and PL 256, to take place in November 2019. Under the farm-in terms, New Era will fund 60% of well costs for interest acquisition in ATP 948-P and PL 256, to a cap of AUD 1 million in PL 256 and AUD 1.06 million in ATP 948-P. Above the cap, cost splits will be on an interest holding basis. It is reported that New Era is itself being acquired by Indus Energy NL, via reverse takeover. Indus is to acquire all the shares in New Era, with the new company to be called New Era Oil and Gas NL.

Australia, ATP 2024-P

Deepwater PL 842 / blocks 6608/10, NE of Norne, WD 378m, P&A dry at TD 1,676m, Transocean Arctic SS off to Dvalin devt drilling. Main target Upper Jurassic Rogn fm not encountered. Capricorn (op), Skagen44 + Pandion.

6608/11-09 (Godalen) (Cairn 40% op.Skagen44 30%, Pandion 30%) in PL 842, P&A dry, failed to find the primary target in U. Jurassic rocks in the Rogn Fm. while it only found 118m with alternating layers of clay stone, siltstone and sst in a secondary objective in the Melke Fm. No traces of petroleum in the well.

VÃ¥r Energi assigned 35% (from its 60% stake) plus operating responsibilities to Equinor in PL293, effective 30 April 2020. PL293 is located 20 km W of the Vega field, 30 km NW of the Troll Field and adjacent to the W of production licence PL293 B. PL293 was awarded on 11 April 2003 covering 1,067.5 sq km and has subsequently been reduced to 145 sq km over blocks 34/12, 35/7 & 35/10. It was converted to a production licence on 12 April 2009. It contains the 34/12-1 (2008, Eni, 4,713m MD) Afrodite gas/condensate discovery with estimated recoverable resources of 32 MMboe in Early Jurassic Cook Formation. The acreage also contains the 35/10-2 (1996, Statoil, 4,677m MD) minor gas discovery in Middle Jurassic Tarbert and Ness formations, which the NPD states is unlikely to be developed. Current PL293 equity partners are Equinor Energy AS (75% + Op) and VÃ¥r Energi AS (25%).

VÃ¥r Energi assigned 35% (from its 60% stake) plus operating responsibilities to Equinor in PL293,

On 17 June 2020, it was learned that the Nigerian Department of Petroleum Resources (DPR) extended for one week the initial registration period of the 2nd Marginal Fields Bid Round that was launched on 1 June. Local sources indicated that over 300 oil companies have applied to be prequalified for the auction so far, but some 200 more could apply until 21 June, the new deadline for the applicants to register. The full revised schedule is detailed in a separate article. Interested parties are invited to visit the DPR portal for the exercise (https://marginal.dpr.gov.ng/). Further enquiries will be sent to [email protected] and [email protected] or asked through phone at +234 (1) 27 900 00 or +234 (1) 90 371 50. Although the process is primarily designed for Nigerian oil companies in order to acquire petroleum permits, foreign companies can also apply as long as 51% operated interest is kept by an indigenous party. The contributors of the 57 marginal fields (undeveloped assets) are mainly the five Majors ExxonMobil, Shell, Chevron, Total and Eni, active in Niger Delta for decades. They were requested by the authorities to release some of their non-core business assets. In April 2020, the DPR also revoked ten permits operated by indigenous companies with intention to put them on offer in the bid round, considering the companies were inactive. However, these companies are now contesting this decision and secured in early June a joint order of the Federal High Court of Nigeria. The below map provides with a visual representation of the Nigerian marginal blocks offered in 2020 (the small red outlines). They are located onshore, in swamps and in the shallow waters of Niger Delta. This image also indicates the existing blocks of the five Majors from which most of the marginal fields were carved out.

On 1 June 2020, the Department of Petroleum Resources (DPR) on behalf of the Federal Government (FG) launched the 2nd Marginal Fields Bid Round. The process is designed for Nigerian oil companies

BP announced on 21 November 2018 that it has agreed to sell 36% interest in the Bruce field, 34.84% interest in the Keith field and 50% interest in the Rhum field to Serica Energy plc. Under the terms of the deal Serica will pay an initial consideration of GBP 12.8 million along with a share of cash flows over the next four years, a consideration equivalent to 30% of BP’s post-tax decommissioning costs and several contingent payments of future asset performance and product prices. BP expects to receive an overall payment in the region of GBP 300 million. In addition to the interest approximately 110 staff working for BP on the Bruce assets are also expected to make the transition to Serica. BP is to retain a 1% interest in Bruce to oversee its future operational and financial performance. Subject to receipt of third party and regulatory approval, the deal is expected to complete in Q3 2018. Bruce is a middle Jurassic gas, condensate, oil field discovered in 1974 by Hamilton Brothers Oil Co with well 9/8-1. It is a complex structure comprising three reservoirs - Bruce sandstone (oil and gas condensate), Statfjord sandstone (oil and gas condensate), and Turonian limestone (gas condensate). Appraisal drilling was largely unsuccessful until 1981. The field was not developed until 1990 and was developed using two bridge-linked platforms D and PUQ. It was brought onstream on 19 May 1993. During Phase II of the Bruce development a third platform was added to accommodate additional gas compression facilities. This CR platform, is bridge linked to the two original Bruce Field Platforms. Improved recovery commenced in 1997 with produced water being re-injected into the reservoir. The Keith field was discovered initially in 1983 by well 9/8a-8 which was drilled as a Bruce outpost. The field was not brought onstream until 2000. It has been developed as tie-back to Bruce. The Rhum field was discovered in 1977 with well 3/29-2 by a Joint Operating Agreement between BP and Iranian Oil. It was not initially developed due to the HP/HT nature of the reservoir. In 2002 the field development plan was submitted to the then Department of Trade and Industry. It was developed as a subsea tie-back to the Bruce field with two production wells and the completion of an appraisal well. Production commenced in 2005. Following completion of the deal, interest in Bruce (lying in licences P90, P209 and P276) will be held by Serica Energy plc (36% + operator), Total E&P UK Ltd (43.25%), BHP Billiton Petroleum Great Britain Limited (16%), Marubeni Oil and Gas (U.K.) Limited (3.75%) and BP Exploration and Operating Company (1%). Interest in Keith (P209) will be held by Serica Energy plc (34.84% + operator), BHP Billiton Petroleum Great Britain Limited (31.83%), Total E&P UK Ltd (25%) and Marubeni Oil and Gas (U.K.) Limited (8.33%). Interest in Rhum (P198, P566 and P975) will be held by Serica Energy plc (50% + operator) and Iranian Oil Company (U.K.) Limited (50%).

United Kingdom (Viking Graben Province) (It's a petroleum rights. Please summarize by yourself). In IHS database: Bruce op. by BP (37.0%, TOTAL 43.25%, BHP BILLIT 16.0%, MARUBENI 3.75%) to be check.Hamilton op. by ENI SPA (0.0%, ENI SPA 46.1%, ENI SPA 45.0%, ENI SPA 8.9%) to be check.Statfjord op. by CENTRICA (100.0%) to be check.Keith op. by BHP BILLIT (0.0%, BP 34.83333%, BHP BILLIT 31.83333%, TOTAL 25.0%, MARUBENI 8.33334%) to be check.Rhum op. by BP (50.0%, NIOC 50.0%) to be check.

Total SA announced on 12 November 2018 that it had signed a new concession agreement with Abu Dhabi National Oil Company (ADNOC), to undertake an unconventional gas exploration program within the new 6,000 sq km onshore Ruwais Diyab Concession. Located in western Abu Dhabi, contiguous to the ADNOC Onshore concession, the contract allows for two exploration and appraisal phases for a period of up to seven years, followed by a 40-year development and production period. Total will operate the exploration phase of this new concession with a 40% interest in partnership with ADNOC holding 60%. Total is a longstanding participant in Abu Dhabi's upstream sector, so it has extensive experience and understanding of the regional geology. It believes the Diyab play has multi-trillion cubic feet (TCF) gas potential. If that potential is proven then it plans to develop unconventional gas in stages, in line with both growing domestic consumption and export opportunities. The Oxfordian to mid-Kimmeridgian, Diyab Formation has long been regarded as a source rock for Aptian, Thamama Group reservoirs within onshore and southern offshore Abu Dhabi. In the west it comprises finely laminated, organic rich, dark grey peloidal lime mudstones to wackestones. Al Suwaidi et al (2000) noted that it contains both oil and gas prone kerogens.

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 4 December 2018, local media reported Lukbeloil’s (a wholly owned Lukoil subsidiary) Lisyanskoye discovery in Saratov Oblast (Volga-Urals). Drilled within the Rovenskiy block (license SRT00472NP), well Lisyanskaya 1 tested approximately 375 b/d of oil from Lower Carboniferous sandstones of the Bobrikovskiy Formation. No reserves estimations were mentioned.

Russia (Volga-Urals B.) ? op. by LUKOIL (100.0%) in Rovenskiy block

An auction was held 2 Mar '20 for onshore block XIh, 195 sq km SE of Tbilisi in the Kura Basin. Georgia O&G won the tender for the former Elenilto Georgiahepd permit.

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

OGDC has sold a 2.5% interest in the so far wholly-owned, undrilled onshore Pasni West 2562-1 EL, 2,295 sq km in the Makran Coastal Trough, Balochistan, to the Govt Holdings effective 4 Dec ‘17.

Pakistan, not found

It is understood that Turkiye Petrolleri A.O. (TPAO) has completed the drilling activity in Kuzupinari 1 shallow water new-field wildcat (NFW) well within the P34-B offshore licence (Iskenderun Basin) in the Mediterranean Sea during Q3 2019. It was spudded in March 2019 using the Rowan Norway jack-up rig. The well, located approximately 15 km from the Karatas coastline and 60 km from the town of Adana, had a prognosed TD of around 4,500 m. The company recently drilled Erdemli Kuzey 1 shallow water new-field wildcat in the Block 4856 offshore licence using the same rig. The P34B exploration licence covers an area of 494 sq km and TPAO hold 100% interest. It was exclusively awarded to TPAO on 30 November 2018.

Kuzupinari 1 shallow water nfw. within the P34-B offshore licence, completed, results unreported.

In May 2018, local sources reported that Pan American Energy (PAE) has completed the Coiron Amargo Sur 14R H new-field wildcat (NFW) in April 2018 as an oil well in Coiron Amargo Sur Este (CASE) block after it tested 628.4 bo/d from the Vaca Muerta Formation shale. The horizontal well was spudded in October 2017 and reached the total depth (TD) of 4,804 m (15,761 ft) in November 2017. The CASE block covers 246 sq km of land in the Neuquen Embayment of Neuquen Basin. PAE operates the block with 55% equity, with partners Madalena Energy at 35% and provincial company GyP Neuquen with 10% interest. Background Information In January 2017, Madalena transferred 55% working interest and operatorship in CASE block to PAE at the cost of USD ten million.

Pan American Energy (PAE) has completed the Coiron Amargo Sur 14R H new-field wildcat (NFW) in April 2018 as an oil well in Coiron Amargo Sur Este (CASE) block after it tested 628.4 bo/d from the Vaca Muerta Formation shale.

On 28 December 2017, OIL India Ltd (OIL) announced the gas discovery in its Chandmari South 5 exploration well (presumably an outpost well of Chandmari South field). OIL is understood to have encountered multiple sands in the Eocene Narpuh and Lakadong & Therria formations. Production testing results indicated that gas is produced at a rate of 0.05 MMcm/d (1.77 MMcf/d) from a 10 m sand interval within the Lakadong & Therria formations at a depth of 4,290 m. The Chandmari South 5 well is believed to be located in the Dum-Duma Block B ML in Assam Shelf.   OIL is understood to have spudded the Chandmari South 5 in late 2016 and was carrying out the production testing operations in Q2 FY 2017-18. Chandmari South 5 is believed to have been targeting a TD around 4,500 m. The Chandmari South field lies directly to the south of the Barekuri field (formerly Chandmari North) and approximately 5 km to the north of the producing Makum field. Chandmari South 1, drilled in a period between October 2001 to March 2002, with TD 4,011 m, was the gas discovery well of the Chandmari South field. Later OIL drilled Chandmari South 2 in 2007 and Chandmari South 4 in 2012-2013. Chandmari South 2 had a TD of around 4,000 m and discovered heavy high pour point oil from the Tipam Formation. Chandmari South 4 was listed as a new pool discovery after testing across the interval 3,915 - 3,920 m in the Lakadong & Therria formations flowed oil at a rate of 75.5 b/d and gas at 1.34 MMcf/d.   Dum-Duma Block B ML comprises around 317 sq km area. OIL holds 100% interest in the Dum-Duma Block B ML, which was awarded on 26 November 1989 for a period of 20 years. The licence was subsequently renewed for a further 20 years, with effect from 26 November 2009.     

India (Assam Shelf) (It's a petroleum rights. Please summarize by yourself). In IHS database: Dum-Duma Block B ML op. by OIL INDIA (100.0%) to be check.

Industry sources reported, early-March 2020, that Genel Energy Plc (Genel) was officially awarded the Lagzira Offshore reconnaissance permit, through its subsidiary Genel Energy Morocco Limited. The surface exploration block covers the former Sid Moussa offshore blocks which belonged to the same company until the PSC's relinquishment in February 2020. The reconnaissance licence has a one-year duration to March 2021, when a one-year extension might be possible, according to the Moroccan oil legislation. The permit is operated by Genel with 75% working interest, with partner ONHYM, 25%. During the previous contract, Sidi Moussa (August 2009 – February 2020), operated by the same group presented above, 2,000 sqkm of 3D seismic was run in 2018 and one successful well was drilled through Sidi Moussa 1, which encountered 26° API oil drilled in fractured and brecciated cavernous Upper Jurassic carbonates. Farther testing program over the same interval failed to produce oil at sustainable rates, probably because of the reservoir damage suffered during drilling and well control operations. Different sources reported the licence's unrisked resources estimated at about 750 Mmboe.

Morocco (Aaiun-Tarfaya B.) Sidi Moussa 1

On 30 November 2018 Aker BP and Equinor completed a deal which saw the former gain a 4% interest in PL 615 and PL 615 B from the latter. PL 615 covers a 410 sq km area over parts of blocks 7324/1, 7324/2, 7324/3 and 7325/1 and contains the western part of the Atlantis gas discovery and the recent (November 2018) gas discovery at Intrepid Eagle. PL 615 B lies further northeast, covering a 568 sq km area over blocks 7425/10 and 7425/11. 7325/1-1 was drilled on the Atlantis prospect in 2014 and proved 55 m net of sandstone in the Triassic Snadd Formation with a 10 m gas column. A 10 m sandstone section with hydrocarbon shows was present in the Middle Triassic Kobbe Formation (the main objective) and the Lower Triassic Havert Formation also contained sand but with poor reservoir properties. Reserve volumes were estimated at 18-70 Bcfg. The Intrepid Eagle discovery was made by 7324/3-1, located approximately 13 km west of Atlantis. A 30 m gas column was present (net 20 m reservoir) in the upper part of the Snadd Formation with estimated recoverable reserves of 350 – 700 Bcf gas. Gas was also proven in a lower part of the Snadd Formation – the same reservoir as Atlantis – but the sandstone was tight and so a total gas column height could not be established. Reserves for this reservoir are estimated at 35 – 140 Bcfg. Following completion of the deal, interests in both PL 615 and PL 615 B are divided between Equinor Energy AS (51% + operator), OMV (Norge) AS (25%), Petoro AS (20%) and Aker BP ASA (4%).

Norway, PL 615

PL 847, Naglfar Dome, TD 3,916m, being abandoned as of 12 Feb ‘19, likely dry, Transocean Spitsbergen SS. Wintershall (op), partners Equinor, OMV + Repsol.

6706/06-02S (Marisko) (Wintershall 40% op, OMV 20%, Repsol 20%, Dyas 10%, Equinor 10%) in PL 847 block. P&A results n/a, targeted the Nise Fm.

Mississippi Canyon block 387, WD ca. 2,000m, oil find in Miocene sst, tie-back to LLOG’s Delta House facilities in MC 254 envisaged, 1st oil later in 2019. LLOG also plans to bring Buckskin and Stonefly online in 2019.  LLOG (op), partners BP, Centaurus, Kosmos + Ridgewood.

United States (Deep Water Gulf of Mexico B.) ? op. by LLOG (0.5%, LLOG 49.5%, RED WILLOW 23.75%, ILX PROSP 4.83347%, ILX PROSP 4.83347%, RIDGEWOOD 3.93838%, HOUSTON EN 2.5%, RIDGEWOOD 2.30428%, ILX PROSP 2.20806%, RIDGEWOOD 1.33592%, RIDGEWOOD 0.71607%, RIDGEWOOD 0.71607%, RIDGEWOOD 0.71607%, RIDGEWOOD 0.71607%, RIDGEWOOD 0.71607%, RIDGEWOOD 0.71607%) in MC 254 block

ExxonMobil and Sonangol signed an MoU for exploration of the Namibe Basin. The block identity or location has yet to be revealed, but it is known Exxon was negotiating for block 42 (7,200 sq km in WD 3,000-3,500m, Angola, Benguela (Kwanza) and Namibe basins), block 43 (7,000 sq km in WD 2,500-2,800m, Angola + Namibe basins) and block 44 (6,000 sq km in WD 3,000-3,500m, Angola + Namibe basins).

Sonangol and ExxonMobil have signed a MOU signaling the intention to enter into a set of risk service contracts off. cover Blocks 30, 44 and 45.

Linhe Depression, Hetao Basin, TD’d in July, tested 90 bo/d from the Oligocene Linhe fm, 25m of pay in 4 layers.

Song-5 Linhe Depression, Hetao Basin, TD’d in July, tested 90 bo/d from the Oligocene Linhe fm, 25m of pay in 4 layers.

Ophir is pulling out of CI-513, 1,440 sq km in deepwaters and so far shared with partners African Petroleum + Petroci (carried). The move is likely related to Ayame-1 nfw, drilled last year and P&A dry. The block was subject to a drill-or-drop expiring this month, and may therefore be relinquished:

Ophir is pulling out of CI-513, 1,440 sq km in deepwaters and so far shared with partners African Petroleum + Petroci (carried).

Siccar Point Energy has entered into a Sale and Purchase Agreement to divest its 26.0% equity interest across three production licences covering the Jackdaw discovery to Dyas UK.  Completion of the transaction remains subject to customary regulatory and partner consents. Siccar Point Energy divests equity in Jackdaw Siccar Point Energy’s CEO Jonathan Roger commented: 'As Jackdaw operator Shell has carried out some excellent work in progressing this opportunity. However, with an exciting programme of exploration, appraisal and development activity in our West of Shetland portfolio we have chosen to focus our resources in this core area and monetise our Jackdaw interest'. Dyas CEO Robert Baurdoux commented: 'Dyas aspires to invest in material upstream projects, which are managed by experienced operators. With our Catcher and Mariner developments nearing first  production, Jackdaw will provide Dyas with the opportunity to join Shell in developing this exciting  gas-condensate field and bringing more gas into our portfolio. Jackdaw field According to information on the Siccar Point web site - the Jackdaw field is located in the Central North Sea area 250 km east of Aberdeen and 10 km north-east of Jade. Siccar Point acquired a 26% non-operated interest in the field from the takeover of OMV (U.K.) in January 2017. Jackdaw was discovered in 2005 and has subsequently been appraised by two additional wells. The field is a gas/condensate accumulation in Jurassic sandstones. The structure is an intra-basinal high located in the East Central Graben area of the Central North Sea. The overall structure is divided up into a number of fault compartments. Two of the fault compartments have been drilled with proven hydrocarbons. The field is currently being re-assessed by the operator with a decision on forward activity expected later in 2017. A full field development would be expected to produce well over 100 million barrels of oil equivalent. Original article link Source: Siccar Point Energy / energy-pedia

United Kingdom, not found

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

Timor Sea JPDA, JPDA 03-20

Mubadala announced an agreement to farm out 20% interest in the Andaman I and South Andaman gross split contracts, in offshore North Sumatra, to Premier Oil, on 17 July 2019. The deal is subject to customary conditions and approvals. Upon final approval, Mubadala will remain operator of both blocks with 80% interest. The deal will reinforce the cooperation between Mubadala and Premier in exploring the deep water area of the North Sumatra Basin. The companies are also partnering in the adjacent Andaman II PSC, in which Premier holds a 40% operating interest and Mubadala controls 30%. The remaining 30% in the Andaman II block is held by KrisEnergy. In May 2019, PGS completed a large multi-client 3D seismic survey across the South Andaman, Andaman I and Andaman II blocks. The new data, covering approximately 9,000 sq km, will improve the understanding of the proven Miocene carbonate and Oligo-Miocene clastic plays and of the deeper, unproven syn-rift plays in the area. The survey, which commenced in December 2018, was acquired using the “PGS Apollo” S/V. No exploration drilling has taken place within the Andaman I block, while two unsuccessful wells have been drilled in the South Andaman acreage by previous operators (Lasmo in 2000 and Eni in 2008). Mubadala signed gross split contracts for the Andaman I and South Andaman blocks in April 2018 and February 2019 respectively, with initial interest of 100% in both blocks. Background Information Andaman I block The Andaman I block was offered as part of the Conventional Oil and Gas Bidding First Round 2017 under the Direct Offer mechanism. Mubadala was awarded the block on 31 January 2018, and contract signature under Gross Split fiscal terms took place in April 2018. The base government/contractor split under Gross Split terms is 57%/43% for oil and 52%/48% for gas, subject to modifiers depending on the specific situation of the block. Signature bonus for the block was USD 750,000. The block, with an area of approximately 7,400 sq km, is located primarily in the deep water area of the South Sumatra Basin, with the western edge bounded by the Mergui Ridge. No well has been drill to date within the acreage. Exploration targets in the area could be clastic reservoirs of the Upper Oligocene Parapat Formation, Lower Miocene Bampo Formation and Middle Miocene Baong Formation, mostly in structural trap settings. The minimum exploration commitments for the first three-year exploration period include G&G studies and a 500 sq km 3D seismic survey, for a total value of USD 2.15 million. The seismic commitment was likely fulfilled by the multi-client 3D survey acquired in early 2019. South Andaman block The South Andaman block was offered in the Conventional Oil and Gas Bidding Third Round 2018 under the Direct Offer mechanism. Mubadala was announced as the winner of the block on 27 December 2018 and signed the Gross Split contract on 18 February 2019. Signature bonus amounted to USD 2 million. The block has an area of approximately 3,550 sq km and is located in the offshore part of the North Sumatra Basin, under the Aceh Province jurisdiction. Water depth in the block ranges between approximately 100 and 1,500 m. The block was initially reported by Migas as an active Joint Study Area (JSA) in January 2017. Potential exploration targets in the block include fluvial to alluvial clastic reservoirs deposited during the syn-rift stage (Parapat, Bampo formations) and post-rift stage (Baong and Keutapang formations), ranging from Oligocene to Upper Miocene. The minimum exploration commitments for South Andaman include G&G studies and 500 sq km of 3D seismic acquisition, for a total expenditure of USD 2.15 million. The seismic commitment was likely fulfilled by the multi-client 3D survey acquired in early 2019.

Premier confirmed it had signed an agreement with operator Mubadala to earn a 20% interest in South Andaman and Andaman I blocks PSC split PSC.

PGNiG last month secured sole rights to the 1,070-sq km 4/2019/L Zlotow-Zabartowo contract in NW Poland for a 5+25 year term. It had been issued in the 2018 tender call.

PGNiG last month secured sole rights to the 1,070-sq km 4/2019/L Zlotow-Zabartowo contract in NW Poland

In late May 2018, Apache suspended the Kanayes West Far West 1 (Ig026-1) exploration well in the West Kanayes exploration block as an oil & gas well. The well was spudded on 14 April 2018 with the Sino Tharwa’s “ST-10” land rig and drilled to a TD of 4,008 m. It has a planned TD of 4,008 m and objectives in the Alam El Bueib 6 Unit, Upper Safa Member, and the Masajid formation. Apache Oil Egypt operates the West Kanayes block with a 67% interest and Sinopec International Petroleum E&P Corp (SIPC) holds the remaining 33% interests.

Kanayes West Far West 1 (Ig026-1) (Apache 67%, SIPC 33%) in West Kanayes block oil & gas disc. objectives in the Alam El Bueib 6 Unit, Upper Safa Member, and the Masajid formation.

On 27 October 2017 Shell and partners CNOOC and QPI were granted a preliminary award for being the high bidder of the Alto de Cabo Frio Oeste block in the 3rd PSC Pre-Salt Bid Round.  Shell as operator with 55% working and with 20% partner CNOOC and 25% partner QPI, offered the minimum state take of profit oil of 22.87% and USD 106.38 million in total fixed bonus to be paid to the Brazilian government based on the USD to BRL exchange rate of the day of 1USD/3.29 BRL.  There were no other bids for the block.  The PSC contract has a seven year exploration-evaluation phase and the minimum work program is to drill one exploration well. The minimum financial guaranty for the three year period is USD 47.95 million which is less than the estimated cost of drilling a pre-salt exploration well.  

Shell (55%), CNOOC (20%), Qatar Petr. (25%) prelim. awarded Alto de Cabo Frio Oeste during 3rd PSC Pre-Salt deepwater round.

11 November 2019, Ozlitineftgaz (a Uzbekneftegaz research institute) and Schlumberger Oilfield Eastern Limited have signed a Confidentiality Agreement and a Memorandum of Understanding (MoU). The documents aim at technological cooperation in the field of exploration, development and production optimisation at new and existing fields in Uzbekistan, as well as the co-ordination of projects in line with applicable law. Under the MoU, the parties may, by mutual consent, engage production capacities and process resources, labour and financial resources, own developments, technology and know-how for bilateral projects. In addition, following the talks, the parties agreed on the development of scientific and technological cooperation in the areas of field geology and geophysics, field development, processing and transportation of oil, gas condensate and gas, underground gas storage, technological services for oil and gas companies in Uzbekistan.

Uzbekistan, not found

In the first quarter 2020, Novatek-Yurkharovneftegaz was completing the drilling of a new-field wildcat at the Shtormovoy license in Yamalo-Nenets Autonomous Okrug (Western Siberia). Shtormovaya 125 with a PTD of 3,600 m is aimed at exploration of reservoirs in the Middle Jurassic-Neocomian section at the Yavayskaya Yuzhnaya prospect. By January 2020, the well reached 3,354 m. Based on the well results, Novatek plans to book 3P reserves estimated at 3.6 Tcf of gas and 86 MMbbl of condensate. Yavayskaya Yuzhnaya is located in the north-eastern part of the Gydan Peninsula (South Kara-Yamal Province) extending in the Kara Sea. The well is located near the coast, almost in the middle of the prospect.

In the first quarter 2020, Novatek-Yurkharovneftegaz was completing the drilling of a new-field wildcat at the Shtormovoy license in Yamalo-Nenets Autonomous Okrug (Western Siberia). Shtormovaya 125 with a PTD of 3,600 m is aimed at exploration of reservoirs in the Middle Jurassic-Neocomian section at the Yavayskaya Yuzhnaya prospect. By January 2020, the well reached 3,354 m. Based on the well results, Novatek plans to book 3P reserves estimated at 3.6 Tcf of gas and 86 MMbbl of condensate. Yavayskaya Yuzhnaya is located in the north-eastern part of the Gydan Peninsula (South Kara-Yamal Province) extending in the Kara Sea. The well is located near the coast, almost in the middle of the prospect.

Brazil’s CNPE has approved holding the 5th PSC Pre-Salt round involving 4 blocks in the Campos + Santos basins, namely Pau-Brasil, Sudoeste de Tartaruga Verde, Saturno + Titã. President Temer approval is now required but tentative bid submittal will be 28 Sep ‘18. Saturno and Titã were due to be offered in the 15th and 4th pre-salt rounds, but the federal audit court ordered their withdrawal as a unitisation process would be required. Petrobras has right of 1st refusal on the 4 blocks. More round background from GEPS, map below refers (offered blocks in brown):

Brazil, Tartaruga

SE part of AE-0094-Cinturon Plegado Perdido-12 block, DW GoM Basin, WD 1,630m, susp. Results n/a early Apr ’18, La Muralla IV SS. PTD was 6,830m, target Wilcox.

Doctus-1DEL op. by Pemex (100%) in SE part of AE-0094-Cinturon Plegado Perdido-12 block, DW GoM Basin, WD 1,630m, susp. Results n/a early Apr ’18, La Muralla IV SS. PTD was 6,830m, target Wilcox.

Shell has used the “Scarabeo 8” S/S to drill an exploration well on the Tyttebaer prospect in PL 373 S. 34/5-2 S, which spudded on 31 May 2018, is located approximately 11 km southwest of the Shell-operated Knarr field which has been producing since 2015, and 4 km east of the 2010 Blabaer discovery. TD was reached at 3,712 m in the Lower Jurassic Amundsen Formation. There was 85 m of the Lower Jurassic Cook Formation objective present in the well and 50 m of this was sandstone (with poor to moderate reservoir quality). However, the well was dry and it was abandoned on 4 July 2018. Knarr (previously known as Jordbaer) was developed using two subsea templates for production and injection connected to an FPSO which has a production capacity of 63,000 boe/d and a storage capacity of 800,000 boe. Oil is exported using shuttle tankers and gas via an existing export pipeline in the UK (FLAGS). Knarr Central (discovered in 2008 by well 34/3-1 S) and Knarr West (discovered by 34/3-3 S in 2011) have combined recoverable reserves of approximately 70 MMboe and the field is expected to produce for 6-20 years. The reservoir is the Lower Jurassic Cook Formation. Blabaer was discovered by 34/5-1 S. A 65 m oil column was encountered in the primary Cook Formation objective and potential reserves for this compartment (prior to drilling) were given at 21 MMbo. A sidetrack drilled into a separate segment was dry. This discovery now lies within Aker BP’s PL 790. Interest in PL 373 S is held by A/S Norske Shell (45% + operator), Idemitsu Petroleum Norge AS (25%), Wintershall Norge AS (20%) and DEA Norge AS (10%).

034/05-02S (Tyttebær) (Shell 45%, Idemitsu 25%, Wintershall 20%, DEA 20%) in PL 373 S block, P&A, dry, had encountered 85m of thick rocks in the Cook fm, however 50m were sandstone with generally poor to moderate reservoir quality.

Corallian Energy Limited spudded appraisal well 98/11a-6 on the Colter discovery locater in licence P1918 on 6 February 2019. In an update on 25 February 2019 partner, United Oil and Gas plc announced that the well had reached TD in the Sherwood Sandstone at 1,870 m. The well remained (unexpectedly) on the southern side of the Colter prospect bounding fault but encountered oil and gas show over a 9.4 m section at the top of the Sherwood Sandstone reservoir, this is separate to the original appraisal target. Petrophysical evaluations indicate net pay of 3 m. Similar indications of oil and gas shows were encountered in the 1983 well – 98/11-1. It is thought that the two wells may share a common oil-water contact having both intercepted the down-dip margin of the Colter South prospect. On 25 February 2019 Corallian kicked-off sidetrack 98/11a-6Z targeting the Sherwood Sandstone target within the Colter prospect on the northern side of the bounding fault. Operations will take two weeks to complete. As of 6 March 2019 operations were continuing. The Colter discovery was made by BP in 1986 where 41.9° API was recovered on test from a 10.5 m oil column. Through the merging and reprocessing of 3D seismic Corallian has mapped 100 m of vertical relief up-dip of 98/11-2. Well costs are in the region of GBP 7 million. Corallian announced on 28 September 2018 that it had contracted the “Ensco-72” for the well. Licence P1918 was initially awarded to Infrastrata from the 26th Seaward Licensing Round prior to Corallian taking the acreage. The company reprocessed 156 km of 2D seismic and 33.5 sq km of 3D seismic over the licence. It is thought that Colter could hold mean prospective resources of 22 MMbo (recoverable). Interest in P1918 following completion of two deals will be held by Corallian Energy Limited (34% + operator), Corfe Energy Limited (40%), United Oil and Gas Plc (10%), Andalas Energy and Power (8%) and Baron Oil Plc (8%).

098/11a-06 (Colter South, Colter-2) (Coralian op. 49%, Corfe Egy. 25%, UOG 10%, Resolute O&G 8%, Baron Oil 8%) in P1918 / block 98/11a off the Dorset coast, ops terminated at TD=1870m (Sherwood sst), o&g shows over a 9,4m intv, 3m net pay, seeminly supporting the BG estimate of 15 MMbo mean recoverable, assessment yet to be refined.

The NPD confirmed on 30 May 2020 that both Petrolia and Wintershall Dea have withdrawn from PL 937 (9 January 2020) and PL 937 B (23 January 2020), with their interests (both 30%) transferring to operator INEOS. INEOS subsequently completed a deal with Lime Petroleum on 29 May 2020 whereby the latter has acquired 15% in each licence. PL 937 lies to the south of Fenja covering parts of blocks 6306/2 and 6306/3 and PL 937 B is located immediately east of Fenja (part of block 6406/12). An exploration well is planned in 2021 which will target the Fat Canyon prospect. Fat Canyon lies updip from Fenja. It is an Upper Jurassic pinchout play which could contain potential recoverable resources of over 200 MMboe. The prospect is supported by Lime's parent Rex International Holding's Rex Virtual Drilling technology. Neptune's Fenja field (consisting of Upper Jurassic fan systems in the Pil and Bue accumulations), is under development. The company will develop Pil initially, using a subsea tieback to the Njord A platform. The development will use two subsea templates hosting three horizontal producers, two water injectors and a single gas injector. Oil will be processed on Njord A before being transferred to Njord B for onward export via shuttle tanker. Gas will initially be re-injected into the Pil reservoir and will later be exported via Njord’s connection to the Asgard Transport System. Recoverable reserves are approximately 97 MMboe. Plateau production is expected to be approximately 40,000 bo/d and gas production expected to peak at approximately 100 MMcf/d between 2025 and 2036. Total investment costs are approximately NOK 10.2 billion (USD 1.22 billion), with first oil scheduled for H1 2022 and a 16-year life forecast. Bue represents upside and will be confirmed by Pil development wells before it is potentially brought into production at a later date. Interest in both PL 937 and PL 937 B is divided between INEOS E&P Norge AS (85% + operator) and Lime Petroleum AS (15%).

After withdrawal of Wintershall DEA and Petrolia from PL 937 + 937 B their 30% have transferred to Ineos (->85% op, Lime 15%), total 369 sq km on the Frøya High.

ConocoPhillips successfully tested oil in exploration well Tinmiaq 9, a vertical borehole designed to appraise the recent 300 MMbo Willow discovery, according to reports in April 2018. The well, drilled in lease AA081747, forms part of a six-well programme, designed to further appraise the Willow discovery. All six of these wells have encountered oil, with reportedly "encouraging" results having been gleamed from associated flow tests. In mid-January 2017, ConocoPhillips indicated that the Willow discovery was 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

Bhubandar field / ML, Tripura-Cachar, TD 2,185m, new-pool gas find, so far tested 498 Mcf/d from 1,954-1,957m in the U. Bhuban fm, more testing planned.

BUAF (BU-6, BU AF) npw Bhubandar field / ML, Tripura-Cachar, TD 2,185m, new-pool gas find, so far tested 498 Mcf/d from 1,954-1,957m in the U. Bhuban fm, more testing planned.

Total is looking to dilute its 100% in PPL 576, 14,769 sq km in deeper waters of the Papuan Basin. The Greater Mailu prospect is slated for drilling here through Mailu-1 nfw in WD ca. 2,000m in the coming weeks. It is believed up to 50% would be available.

Total is looking to dilute its 100% in PPL 576, 14,769 sq km in deeper waters of the Papuan Basin. The Greater Mailu prospect is slated for drilling here through Mailu-1 nfw in WD ca. 2,000m in the coming weeks. It is believed up to 50% would be available.

On 27 June 2019 the NPD confirmed that Equinor has transferred 32% of its interest in PL 159 G (awarded under APA 2018 in March 2019) to DNO (effective from 21 June 2019). The licence covers two very small areas (1,4 sq km each) in blocks 6507/2 and 6507/3 between the Marulk and Aerfugl fields and just to the southwest of Equinor’s recent Snadd Outer Outer / Black Vulture discoveries. This equity transfer aligns the interests of PL 159 G with PL 159 B, the licence in which Snadd Outer Outer / Black Vulture was drilled.      Equinor’s exploration well 6507/3-13 drilled the Upper Cretaceous Lysing Formation Snadd Outer Outer prospect and the Cretaceous Lange Formation Black Vulture prospect. The well encountered 25 m of Lysing Formation (at approximately 2,800 m) with a gas column of 5 m. Within the Lange Formation (around 3,200 m) there was a 25 m sandstone section (14 m net) in which oil and gas was proven. Estimated recoverable reserves are 2-12 MMboe in the Lysing Formation and 1-48 MMboe in the Lange Formation. Following completion of the deal, interest in PL 159 G is divided between Equinor Energy AS (53% + operator), DNO North Sea (Norge) AS (32%) and INEOS E&P Norge AS (15%).

Equinor has transferred 32% of its interest in PL 159 G (awarded under APA 2018 in March 2019) to DNO

Petronas has reportedly taken a 30% stake from Equinor in a set of Walker Ridge blocks (WR 270, 271, 272, 227, 315 + 316) including that hosting the current Monument well drilling in block 316 (DEA 19 Dec '19), where partnership becomes Equinor (op) 50%, Petronas 30%, Repsol 20%.

Petronas has taken a 30% stake in the high-profile Monument exploration well currently being drilled by Equinor (->50% op, Repsol 20%) in the six DW associated blocks WR 270, 271 (G35080), 272, 227, 315 and 316.

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

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

Beach has agreed with OMV to acquire a 30% interest in frontier PEP 50119, 16,760 sq km in deepwaters of the Great South Basin and home to the Tawhaki prospect. The deal is in exchange for the 30% funding of Tawhaki-1 due to spud early 2020 (COSL Prospector SS), and is conditional on usual approvals. Resulting partnership OMV (op), Beach + Mitsui.

New Zealand, PEP 50119

Effective 2 February 2019, BOEM records show Ridgewood Hoffe Park LLC acquiring 40% working interest in Mississippi Canyon blocks 121 (G34423), 122 (G34424), 165 (G35317) and 166 (G35318) from Murphy Exploration and Production Company USA, which retains 60% working interest and remains operator. Murphy previously held 100% working interest in these blocks, three of which (MC 122, 165, and 166) were previously operated by Chevron USA Inc with 75% working interest until it exited the blocks effective 5 September 2018. The blocks lie in about 4,140 – 4,652 ft (1,262 – 1,418 m) of water about 115 mi (185 km) east-southeast of the onshore supply base at Port Fourchon, Louisiana, and contain the Hoffe Park discovery. Background Information The Hoffe Park field was discovered by Chevron when it drilled the MC 166 1S0B0 (API 60817413520000) discovery well, which was spudded on 10 December 2016 and reached a total depth of 18,014 ft (5491 m) on 6 January 2017. It encountered hydrocarbons in subsalt Miocene-aged sands, but no other details were released. At the time, Chevron operated with 75% working interest and Murphy was the sole partner (25%).  Chevron later pulled out of the project and left Murphy as the sole owner. At the Scotia Howard Weil Energy Conference held on 25 March 2019, Murphy reported it expected to spud the second Hoffe Park well in MC 165 in the third quarter of 2019 and quoted net mean resource potential of 30-48 MMboe.

Ridgewood Hoffe Park acquiring 40% working interest in Mississippi Canyon blocks 121 (G34423), 122 (G34424), 165 (G35317) and 166 (G35318) from Murphy (->60% op.)

PentaNova, via affiliate Alianza Petrolera, announces the finalisation of negotiations with YPF to move to a 50% Interest in the Llancanelo heavy oil field/blocks, total 27 sq km in the N. Neuquén Basin. This comprises the takeover of 10% from Roch and 11% from YPF. Farm-in terms include up to 6 months for the partners to complete a joint programme to complete the full devt plan on the block, with the aim of brining the block into a large heavy oil project. Mendoza authority approval is now awaited for the move to complete. www.pentanovaenergy.com.

Alianza Petrolera Argentina has agreed to acquire a 10% stake in the Llancanelo block from Roch (->0%, YPF 50% op, Patagonia Oil 11%, PentaNova 29%).

In Q3 2018, Tharwa Petroleum made an oil discovery in its East Abu Sennan G 1X (EAS G 1X) NFW, located on the East Abu Sennan PSC in the Abu Gharadig Basin. The well encountered oil in the Cretaceous Upper Bahariya Formation. It was spudded on 22 July 2018, reaching 1,865m TD in the Cretaceous Kharita Formation. Operations were carried out using the Tanmia Petroleum "Tanmia 1" rig. EAS G 1X is the second discovery made on the block in 2018. In January 2018, the EAS C 1X NFW discovered oil in the same interval, after reaching 2,423m TD. It was drilled ~5km south of EAS G 1X. A successful appraisal, EAS C 2X was drilled May-June 2018. The campaign follows on from two oil discoveries being made in the south of the block in 2017. Six wells have now encountered oil, since Tharwa commenced its drilling campaign in 2017. The company operates East Abu Sennan with 100% equity.

Tharwa Petroleum made an oil discovery in its East Abu Sennan G 1X (EAS G 1X) NFW, located on the East Abu Sennan PSC in the Abu Gharadig Basin. The well encountered oil in the Cretaceous Upper Bahariya Formation. It was spudded on 22 July 2018, reaching 1,865m TD in the Cretaceous Kharita Formation.

On 9 October 2018, PEMEX reported it completed as an oil and gas discovery the Mulach 1EXP new-field wildcat (NFW) in the AE-0051-4M-Mezcalapa-01 entitlement block.  The operator reported that it drilled five reservoirs of light oil in the Upper Miocene.  The CNH reported that the reservoir interval perforated was from 3,323 m to 3,347 m.  The NFW reached a final total depth (TD) of 3,976 m.  PEMEX indicated it estimates 3P reserves for the discovery of 100 MMboe. The NFW was spudded on 10 July 2018 in a water depth of 21 m.  On 2 July 2018, the CNH approved a drilling permit for the NFW. The well was targeting the Miocene Formation at a proposed total depth (PTD) of 4,040 m.  The unrisked prospective resources were 120 MMboe and represents the best prospect out of the six prospects identified within the block. It is located in the very northeastern corner of the block about 7.5 km south-west of the Yaxche field, the nearest Miocene producing field. On 20 June 2018, the CNH approved the modification of the exploration plan for the additional two-year exploration period submitted by PEMEX for the AE-0051-4M-Mezcalapa-01 entitlement block.  The modified exploration plan for the block includes the addition of the drilling of the Mulach 1EXP well in the north-eastern area of the block. The AE-0051 block had its original phase extension exploration plan approved on 10 October 2017.  The other five prospects include the offshore Chejekbal 1EXP, Coatzin 1EXP, Tlamatini 1EXP, and deeper pool wildcat (DPW) Tetl 1001EXP.  There is one onshore prospect, the deeper pool wildcat (DPW) Tupilco 3001EXP.  The prospects are targeting the Tertiary and deeper Cretaceous and Jurassic plays. The AE-0051-4M-Mezcalapa-01 entitlement block was originally granted to PEMEX on 27 August 2014 with a two-year extension granted on 27 August 2017.  The block covers an approximate area of 652.77 sq km after being reduced due to environmentally sensitive areas located within the central area of the onshore-offshore block.

PEMEX reported it completed as an oil and gas discovery the Mulach 1EXP new-field wildcat (NFW) in the AE-0051-4M-Mezcalapa-01 entitlement block.

Petrobras reports that has encountered oil in an exploration well on the Sudoeste de Tartaruga Verde block, located in the Campos Basin.  The well, informally called Natator, is located 130 km from the city of Macaé (RJ), in water depths of 1,080 meters, with the discovery of oil in carbonate reservoirs in the post-salt section. The well data will be analyzed to better target exploratory activities in the area and assess the potential of the discovery.  The Sudoeste de Tartaruga Verde block, acquired in the 5th Production Sharing Round, in September 2018, is inserted in the so-called Pre-salt Polygon, under a production sharing regime. Petrobras is the operator of the block with 100% interest, with Pre-sal Petróleo S.A. (PPSA) as manager. Original article link Source: Petrobras

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

AziNor Catalyst is offering the opportunity to farm-in to licence P2278 (blocks 13/16b and 13/17) to drill a well on the Churchward prospect. AziNor is looking for a partner to fund an exploration well in return for a material interest in the licence. The estimated gross well cost is GBP 9 million. The well is required to be drilled to a depth of at least 2,350 m or 30 m into the Upper Jurassic, whichever is shallower. AziNor has derived a P50 resource potential of 525 MMbo recoverable with a potential 2 Bbo upside. P2278 was awarded in September 2015 during the 28th Licensing Round. The work programme is currently in the first four year term. Purchasing and reprocessing 3D seismic data and associated geotechnical studies have been completed. A ‘drill or drop’ decision is expected by September 2019. As of January 2019, the opportunity was still available. Churchward consists of a large structural stratigraphic trap located on the northern flank of the Halibut Horst within the Smith Bank Graben. The trap was interpreted through the merging and reprocessing of WesternGeco’s Captain 2003 and Petro-Canada’s 2006 seismic surveys. An exploration well will target the Ettrick (J71) and Buzzard (J63) sandstone units that were deposited in axial submarine channels. The Buzzard sandstones are interpreted to exhibit similar reservoir properties to those discovered in the Buzzard field which lies approximately 75 km south east of Churchward. The reservoir sands are sourced from mature Kimmeridge ‘Hot Shales’ with potential TOCs of 6-7%. The Kimmeridge Clay also forms the primary seal for the Jurassic reservoir sands. An AVO and potential DHI effect associated with a phase change has been interpreted on the top of the reservoir sands. Amoco drilled well 13/17-1 in 1975 to a depth of 2,526 m within the current acreage. The well targeted the Rotliegend Group sandstones and was disclosed as dry/shows. Evidence for a working petroleum system within the Smith Bank Graben was proven in 1977 by the discovery of Captain Field, located immediately south of P2278. The field produces from Upper Jurassic sands and Lower Cretaceous and Rotliegend sands. P2278 is held solely by AziNor Catalyst. For further information please contact: Nick Terrell Tel+44 (0)20 3588 0065 Email: [email protected]

AziNor Catalyst is offering the opportunity to farm-in to licence P2278 (blocks 13/16b and 13/17) to drill a well on the Churchward prospect. AziNor is looking for a partner to fund an exploration well in return for a material interest in the licence.

On 29 March 2018, the consortium of ExxonMobil with 50% working interest, Murphy with 20%, and Queiroz Galvao with 30%, was granted preliminary awards for the SEAL-M-430 and SEAL-M-573 blocks in the offshore Sergipe-Alagoas Basin through the ANP Round 15. For the SEAL-M-430 block the consortium offered a bonus of USD 1.10 million and 200 work units.  There were no other bids for the block. For the SEAL-M-573 block the consortium offered a bonus of USD 1.10 million and 116 work units.   There were no other bids for the block.  

the consortium of ExxonMobil with 50% working interest, Murphy with 20%, and Queiroz Galvao with 30%, was granted preliminary awards for the SEAL-M-430 and SEAL-M-573 blocks in the offshore Sergipe-Alagoas Basin through the ANP Round 15.

Further to DEA 9 Jun '20 (farmin offer), SDX reports it has sold its 50% interest in the Al-Amir JV operating the NW Gemsa acreage, onshore Gulf of Suez Basin, to Gulf Energy for USD 3 MM. The acreage encompasses the NW Gemsa (Dev) Geyad, NW Gemsa (Dev) Al Amir + NW Gemsa (Dev) Al Ola field leases (fully developed).

Egypt (Gulf of Suez B.), North West Gemsa (Dev) Geyad op. by SDX ENERGY (50%), NORINCO (50%), EGPC (0%). On 14 July 2020, SDX Energy (SDX) announced the selling of its working interest in the Al-Amir JV operating the NW Gemsa concession, onshore Gulf of Suez Basin, to Gulf Energy. GANOPE (50%) and North Petroleum (25%, operator) are expected to remain partners with Gulf Energy (25%) in the JV.

EHongdi 1 was plugged and abandoned at a TD of 1,865m MD in the Sinian Dengying Formation in mid-November 2017 after having been spudded on 15 July 2017. The shale gas exploration/stratigraphic well had a PTD of 1,915m and was targeting the Lower Cambrian Nutitang Formation. EHongdi 1 is geographically located in Hubei Province, Hongping Town, Hongju Village. <P />

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Block 6 (North El Arish Offshore), E. Mediterranean’s Pleshet Sub-basin, 2,980 sq km, Dana is still seeking a partner, 8-year expl agreement signed on 18 Feb ’14, wildcat planned by end-’18.

Block 6 (North El Arish Offshore), E. Mediterranean’s Pleshet Sub-basin, 2,980 sq km, Dana is still seeking a partner, 8-year expl agreement signed on 18 Feb ’14, wildcat planned by end-’18.

In early February 2018, BP Canada Energy Group acquired 10% WI from Anadarko Canada E&P in two Grand Banks exploration licences: EL 1125 and EL 1126 (Labrador-Newfoundland Shelf). The transactions are effective as of 15 January 2018. The exploration licences were originally awarded to Chevron by the C-NLOPB on 12 November 2015, based on a US$43 million work commitment. EL 1126 is the site of sidetracked NFW Fitzroya A-12, which was kicked-off in February-March 2016 with the the "West Hercules" semi-sub. Fitzroya A-12 was drilled in a 743m of water, about 26km northwest of Statoil's 2013 Bay du Nord C-78Z discovery on EL 1112. That new field wildcat found between 300 and 600 MMb of 34-degree oil (recoverable) in what has been described as an "excellent" Jurassic reservoir with high permeability and porosity, spurring a great deal of renewed interest in the waters of the Flemish Pass. Following completion of the February 2018 transactions, equity in EL 1125 and EL 1126 is now shared between Statoil Canada (40% WI + Op), Chevron Canada (40%) and BP Canada Energy Group (20%).

BP (->20%) acquired 10% WI from Anadarko (-> 0%, Statoil 40% op, Chevron 40%) in 2 Grand Banks exploration licences: EL 1125 and EL 1126.

Khalda Petroleum has been awarded the Chelsea 2 development lease (DL), as a carve out from the Khalda Offset PSC, located in the Matruh Basin. The award is effective from February 2018, with the DL valid for a minimum 20-year term. The block is believed to include part of the Chelsea South oifield, located on the adjacent Chelsea South DL, which forms part of the West Kanayes concession. The field was discovered in October 2018, after the Chelsea South 1X NFW was drilled. It reached a TD of 4,556m in the Jurassic Lower Safa and had dual objectives in the Cretaceous Alam El Bueib and Safa horizons. Equity in the Khalda Petroleum consortium is split between Apache (33.5%), Sinopec (16.5%) and EGPC (50%, carried).

Khalda Petroleum has been awarded the Chelsea 2 development lease (DL), as a carve out from the Khalda Offset PSC, located in the Matruh Basin.

NC 041 block, offshore Pelagian Basin, ops terminated late Jan '20 at TD 3,235m, targets Eocene Cherahil B, Reineche + Metlaoui penetrated, Valaris 5004 SS. Mellitah = NOC-Eni JV.

A-001-17/1-NC041 nfw. (Mellitah = NOC-Eni JV). in NC 041 offshore block, ops terminated at TD=3235m, w.o. details, targets Eocene Cherahil B, Reineche + Metlaoui penetrated.

Simwell Resources released a statement on 5 August 2020 disclosing that it has farmed-out a 70% stake and operatorship in its P2332 licence (blocks 41/3, 41/4 and 41/9) to Shell. The deal has received Oil and Gas Authority (OGA) approval. The licence covers 715 sq km and is directly west of the Shell operated P2252 licence (41/5a, 41/10a and 42/1a). Simwell was awarded the P2332 licence in May 2017 in the 29th Offshore licencing round. Simwell mapped two Carboniferous leads in the Scremerston Formation and Fell Sandstone Formation and mapped the Permian Zechstein Z3 carbonate play fairway. Simwell believe that each of the two Carboniferous leads could contain more than 500 Bcfg recoverable. The 29th round award was granted with a 3D seismic commitment that has already been satisfied by the 3D survey shot by Shell in the neighbouring P2252 licence, which also extended approximately 160 sq km into P2332. The seismic survey commenced on 1 August 2019 and it was being processed in August 2020. The P2332 licence commitments have therefore been satisfied until the drilling decision which is required before May 2023. In May 2019 Shell acquired a 70% interest in the neighbouring licence P2252. The licence hosts the Pensacola prospect which has a Zechstein reservoir target and is expected to be drilled in late-2021. Interest in P2332 is held by Shell UK Ltd (70% +operator) and Simwell Resources Ltd (30%).

(Anglo-Dutch B.) P2332, Simwell Resources has farmed-out a 70% stake and operatorship (blocks 41/3, 41/4 and 41/9) to Shell. The deal has received Oil and Gas Authority (OGA) approval. The licence covers 715 sq km and is directly west of the Shell operated P2252 licence (41/5a, 41/10a and 42/1a).

On 23 July 2019 the Dutch Ministry confirmed that an exploration licence has been awarded to Neptune and HALO for block F5 for a period of four years. The detailed work programme must be submitted in year two, with a well due in year three. The award is effective from 3 October 2019. The original application for the licence (for a six-year term) was made on 19 June 2015 by Van Dyke but the company subsequently withdrew its application. Neptune (then GDF Suez) and HALO both made separate competing bids (both requesting a four-year term). The licence lies to the south of the Hanze oil and gas fields (Dana) and to the west of the F3-FB oil and gas field (Neptune), all of which are producing. Industry sources indicated the licence has a shallow gas anomaly that will be targeted and Neptune confirmed in late November 2019 that they will target a Tertiary gas reservoir. Five wells have previously been drilled in F5: F5-1 by Tenneco in 1975, F5-2 by BP in 1982, F5-3 by Mobil in 1987, F5-4 by RWE in 1998 and F5-5 by Veba in 2001. All were dry holes except F5-4 which encountered oil shows. Hanze was discovered in 1996 by F2-5 which found a 76 m oil column in the Paleocene and Upper Cretaceous chalks of the Ekofisk and Ommelanden formations. The reservoir lies between 1,340 m and 1,478 m subsea and the API of the oil is 37°. The field was developed using a manned production platform and a tanker mooring and loading system. Oil is exported via shuttle tanker and gas via NOGAT. In 2009 gas production started from the shallow Pliocene reservoir at Hanze. Originally the Pliocene was considered too challenging to develop but new drilling techniques meant that this reservoir could be re-assessed. In October 2013 Dana reported that Hanze infill well F2-A6ST3 had doubled oil production from the field. When the field came onstream in August 2001 end of field life was projected for 2011, reserves were 47 MMboe and the recovery factor was 30%. However, these figures have later been revised: the recovery factor has increased to 53%, reserves are put at 67 MMbo plus approximately 20 Bcfg and the field is expected to produce until 2030. Interest in F5 is divided between Neptune Energy Netherlands BV (operator), HALO Exploration & Production Netherlands BV and Energie Beheer Nederland BV (40%).

Neptune and HALO were awarded block F5.

PETRONAS officially awarded the Production Sharing Contract for Block V, Block W and ND 10 to a consortium of ExxonMobil and Petronas Carigali (PCSB) on 12 March 2018. The blocks will be operated by ExxonMobil with 50% interest while Petronas Carigali (PCSB) will have the remaining 50% stake. Application for the blocks was possibly submitted during the 2H of 2017. Financial terms of the PSC were not disclosed. The commitments for the PSC will include acquisition and reprocessing of new 3D seismic data and drilling of one exploration well in each block during the first three years of exploration period. The frontier blocks, Block V, Block W and ND 10 covers a total area approximately 18,000 sq km. Block V and Block W are located in water depth range of 2,000 to 2,700 m (ultra deepwater). The blocks straddles the Baram Delta and Northwest Sabah Trough. ND 10 is located in the NW Sabah Platform (Dangerous Ground) with a maximum water depth of 1,300 m. Main exploration targets in the area are the carbonate buildup equivalent to the Oligocene Nido carbonate play in the Northwest Palawan Basin in Philippines and the pre-MMU syn-rift fault blocks play. As to date, no exploration drilling has taken place in these blocks. Tepat 1 (Total) was a play opener for the Northwest Sabah Trough. The well, drilled between December 2017 – March 2018 using the Maersk Drilling “Maersk Deliverer” S/S, encountered gas in the carbonate buildup equivalent to the Oligocene Nido carbonate play in the Northwest Palawan Basin, Philippines. Background Information Block V Block V was previously promoted as part of the 2014 Malaysia Exploration Opportunities. Block V covers an area approximately 2,900 sq km straddles the Baram Delta and Northwest Sabah Trough and located in water depth range of 2,000 to 2,700 m. The block was previously operated by Murphy Oil under two different PSC’s: Block K (1999 – 2006) and Block P (2006 – 2013). Block P (excluding Rempah field) was partially relinquished on 22 January 2013. The Rempah gas holding area was retained until 22 January 2018. The block is covered by 2D and 3D seismic data acquired between 2001 and 2008. No exploration drilling was conducted in the block by previous operators. Block W Block W previously promoted as part of the 2015 Malaysia Exploration Opportunities. OB4-00 covers an area approximately 4,600 sq km with majority in the Northwest Sabah Trough and located in water depth range of 2,000 to 1,700 sq km. The block was previously operated by Murphy Oil under Block K PSC (1999 – 2006) and BHP Billiton under Block Q PSC (2007 – 2014).   The nearby fields are Rotan located approximately 30 km southeast, Dolphin located approximately 22 km southeast and Buluh located approximately 33 km southeast of the block. The block is covered by 2D and 3D seismic data acquired between 2008 and 2012. No exploration drilling was conducted in the block by previous operators. ND 10 The block is only covered by 2D seismic data jointly acquired by Petronas Carigali and BHP Billiton between mid-May and late June 2012. The 6,300 line km 2D seismic survey was acquired using the CGG’s “Elnusa Finder” S/V. No exploration drilling was conducted in the block. Petroleum System Source Rock A variety mode of potential mixed oil and gas-prone source rocks could be present including pre-and post-Stage III interbedded shales, organic rich shales or syn-rift stage, mainly pre-MMU, deposited in lacustrine or restricted marine conditions, distal deltaic shales of prograding deltas from the east. Reservoir The Early Eocene and older syn-rift clastics (pre-MMU/ DRU) and local carbonate buildup equivalent to the Oligocene Nido carbonate play in the Northwest Palawan Basin in Philippines. Trap Tilted fault block in the Pre-MMU syn-rift play and carbonate buildups on rift shoulders Seal Intra-formational deepwater shales. The composited condensed sections on the top of syn-rift, pre-MMU are could potential be a regional seal for the lower syn-rift traps in the area.

PETRONAS officially awarded the PSC for Block V, Block W and ND 10 to a consortium of ExxonMobil (op, 50%) and Petronas Carigali (50%).

NE Hapy block, offshore E. Nile Delta, WD 1,200m, drilled Nov ’19 – Feb ’20, results n/a, Tungsten Explorer DS. IEOC (op), partner Edison.

Nigma 1 nfw. (Eni 70% op. Edison 30%) in the DW NEHO (North East Hapy Offshore) PSC, was understood that drilling operations concluded. Results are not yet available. The well is assumed to be targeting the Volans prospect, understood to be a Cenozoic clastics objective.

On 17 July 2019 ADX Energy announced the completion of a farm-in agreement disclosed in April 2019 and providing for the acquisition by Australia-based Parta Energy of a 50% interest in the E X-10 Parta license in exchange of funding the first USD 1.5 million of a 3D seismic survey to be carried out during the last quarter of 2019. The deal is excluding the Parta appraisal program covered by the DEE V-19 Iecea Mare licence. ADX Energy will remain the operator of the Parta block. The E X-10 Parta exploration permit, covering 1,004 sq km in western Romania, was awarded to ADX Energy and partner RAG in December 2012 for a three-year initial period. The contract was extended until June 2019 to allow the completion of the phase one of the work program including a combined 2D/3D seismic survey. In June 2019 ADX Energy was granted a further extension of phase one based on a work program of 100 sq km of 3D seismic, 60 km of 2D seismic and two exploration wells. ADX became the sole rightholder of the permit in March 2019 when RAG sold its 50% interest. Interest in the E X-10 Parta permit is held solely by ADX Energy Panonia Srl. ADX Energy Panonia is 100% held by Danube Petroleum which belongs to ADX Energy (62.5%) and Reabold Resources (37.5%).

ADX has finalised its farm-in agreement (see DEA 8 Apr ’19) with Australian Parta Energy for a 50% stake in the 1,104-sq km Parta (E X-10) permit in the Banat sub-basin, in exchange for funding the first USD 1.5 million of a 100-sq km 3D seismic campaign planned in the N. part of the block in Nov ’19. The farm-in will exclude the Parta appraisal programme area which includes the Iecea Mare lease.

Pandion announced on 16 April 2019 that it has agreed a deal with Equinor to acquire its 20% interest in PL 263 D and PL 263 E. PL 263 E is a new licence that will be carved out from PL 263. The PL 263 D and PL 263 E licences are located in the Haltenbanken area in the Norwegian Sea in blocks 6407/1 and 6507/10, respectively. PL 263 D was awarded in APA 2017. Equinor is currently maturing the Appolonia prospect which could be incorporated to Equinor’s drilling program for 2020, subject to a positive drill decision. The deal is subject to government approval and completion of the carve-out of PL 263 E from PL 263. The annual APA rounds are designed to enhance exploration activity in mature areas where smaller discoveries can make use of existing infrastructure for fast-track development. The rounds have proven particularly popular in recent years with the newer companies to the NCS which bring fresh new thinking to these much-explored areas. The APA system has resulted in quicker circulation of acreage, increased exploration activity in mature areas and a more diverse mix of companies working on the NCS. Following completion of the deal interest in PL 263 D and PL 263 E will be held by Equinor Energy AS (50% + operator), Spirit Energy Norway AS (30%) and Pandion Energy AS (20%).

Norway, PL 263 D

Shell suspended with oil shows the ACFO (1-SHEL-031-RJS) new-field wildcat (NFW) in the Alto CF Oeste P3 contract, ALTO_CF_O block on 12 December 2019 at a final total depth (TD) of 5,120 m. In March 2020, the ANP reported the well results for the significant NFW indicating it was an oil well but has not published a final status of whether it is a commercial or non-commercial discovery nor has the operator reported any details about it yet. The operator concluded drilling operations on 1 December 2019 and was speculated to have conducted some testing operations on the oil show reports it filed since the rig remained on location until early-January when it moved back to the Argonauta Field to conduct more development drilling. There has been no official report as to the final status of the well. Shell filed a total of three show reports with the last one on 20 December 2019 after concluding its drilling operations. Shell filed an oil show report with the ANP for the well on 8 November 2019, a second show report was filed on 2 December 2019, and a third show report filed on 20 December 2019. However, the ANP removed the two earlier show reports filed for the well for unknown reasons. The NFW was spudded on 6 October 2019. The proposed total depth was 5,200 m with the pre-salt Early Cretaceous Barra Velha Formation was the primary target. The prospect has super-giant potential with reserves greater than 500 MMboe. Shell utilized the “Brava Star” D/S to drill the well in a water depth of 1,720 m. The significant NFW is located in the northeastern area of the block approximately 32 km east south-east of the nearest wells in the Atlanta Field. It is also located approximately 74 km north-east of the northern edge of the Mero Field. Shell is the operator of the contract with 55% working interest and partners are CNOOC with 20% and QPI with 25%. On 16 September 2019, Shell was granted a permit by IBAMA to drill up to three new-field wildcats (NFWs) in the Alto CF Oeste P3 contract, ALTO_CF_O block. The permit grants the operator the right to drill up to three wells, one firm well and two contingent wells. Shell may choose the location of two of the contingent wells from three proposed locations. Shell originally filed its environmental permit request in February 2018. Shell has plans to drill up to three new-field wildcats (NFWs) in the Alto CF Oeste P3 contract, ALTO_CF_O block after filing its environmental permit in February 2018. The Alto Cabo Frio Oeste structure is a western continuation of the Cabo Frio high with some separation from the easterly adjoining, larger structural closure of the Alto de Cabo Frio Central. The NFWs to be drilled will have proposed total depths of approximately 5,500 m to 6,000 m and will target the Barra Velha and Itapema formations of the pre-salt series in the Santos Basin. The drilling was expected to commence in the block during 2nd quarter 2019.The structure is potentially very large and depending on separation from the Alto do Cabo Frio structure, reservoir properties, and oil migration, it may be a large reservoir. The wells are located in the central area of the block and about 64 km north-east of the Mero field. On 31 January 2018, the consortium of Shell as operator with 55% working interest, CNOOC 20%, and QPI with 25% was granted an official award for the Alto de Cabo Frio Oeste block from the 3rd PSC Pre-Salt Bid Round. The ANP changed the official denomination of the block to the Alto CF Oeste P3 contract, ALTO_CF_O block. Shell as operator with 55% working and with 20% partner CNOOC and 25% partner QPI, offered the minimum state take of profit oil of 22.87% and USD 106.38 million in total fixed bonus to be paid to the Brazilian government based on the USD to BRL exchange rate of the day of 1USD/3.29 BRL. There were no other bids for the block. The PSC contract has a seven-year exploration-evaluation phase and the minimum work program is to drill one exploration well. The minimum financial guaranty for the three-year period is USD 47.95 million which is less than the estimated cost of drilling a pre-salt exploration well.

Brazil (East Campos Sub-basin (Campos B.)) Argonauta

N. part of Mississippi Canyon block 816 (lease G33178), WD 1,707m, to suspend suggesting a positive outcome. Target Pliocene + Miocene sands, West Capricorn SS. Ownership of the lease is divided by depth. Details from GEPS.

MC 816 3S0B0 (Taggert) appr N. part of Mississippi Canyon block 816 (lease G33178), WD 1,707m, to suspend suggesting a positive outcome. Target Pliocene + Miocene sands.

In Late March 2019, Esh El Mellaha Co. (Eshpetco) abandoned Wadi El Sahl North 1ST1 exploration well, a sidetrack of the Wadi El Sahl North 1 discovery, in the West Esh El Mellaha (WEEM) development lease, southern onshore Gulf of Suez basin as a dry hole at a TD of 2,879 m in the basement. The well was spudded on 1 March 2019, using the “Shams-2” land rig. The company abandoned another sidetrack of the Wadi El Sahl North 1, Wadi El Sahl North 1ST, in late February 2019 at a TD of 2,433 m in the Nukhul formation. The well was spudded on 26 January 2019. The primary objective for the two wells was the Lower Miocene Nukhul formation and the secondary objectives were the Cretaceous Matulla and the Nubia formation. Eshpetco is a JV between Lukoil and EGPC. Lukoil operates the block with a 100% interest. Background information At end-January 1999, Eshpetco suspended well Wadi El Sahl North 1 as a potential Nukhul oil well in its West Esh El Mellaha (WEEM) development lease located on the southern Gulf of Suez. The well was completed as an oil producer. The intervals 2,643-2,649 m in the Matulla Formation and 2,417-2,424 m in the Nukhul Formation were perforated for tests. Preliminary results indicate that oil has flowed to surface from the Nukhul interval. The presence of oil indicates that oil generating capability has been extended in the WEEM concession at least 3 km from the Rabeh Field to the Wadi El Sahl North 1 area. It would appear that the Wadi El Sahl N-1 well crossed a fault above the Nukhul and reached TD in the downthrown side of the fault. The well is located on a prospect identified in 1996 to the south-west of Rabeh. As Abu Marwa North 1, the well offsets a discovery made to the south by Seagull in the South Hurghada block, now in the Wadi El Sahl development lease operated by Washpetco and carved out from the South Hurghada license. The well will take approximately one month to drill to almost 2,000 m sub-surface at a cost of about USD 1 million. The company is using the Santa Fe 169 rig. The development lease was operated by West Esh El Mellaha Petroleum Company or “Eshpetco”, at that time, a joint-venture company between Coplex, Cabre and EGPC established in December 1997 with the carving out of the 82 km² concession from the southeastern portion of the West Esh El Mellaha (WEEM) exploration block.

Esh El Mellaha Co. (Eshpetco) abandoned Wadi El Sahl North 1ST1 exploration well, a sidetrack of the Wadi El Sahl North 1 discovery, in the West Esh El Mellaha (WEEM) development lease, southern onshore Gulf of Suez basin as a dry hole at a TD of 2,879 m in the basement.

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

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

Azimuth subsidiary AzEire Ltd has applied to convert Licensing Options (LO) 16/31 and 16/32 into Exploration Licences (EL's), to be effective from the LO expiry of 30 November 2019. The licences were awarded out of round in Ireland's Celtic Sea open door policy on 1 December 2016. LO16/31 covers 1,654 sq km and overlies the southern edge of LO13/2 which was relinquished by Azimuth upon expiry on 30 April 2016. LO16/32 covers 1,509 sq km overlying the central and southern edge of LO13/1 which was also relinquished by Azimuth upon expiry on 30 April 2016. AzEire Ltd operates both licences with 100% equity.

Azimuth subsidiary AzEire Ltd has applied to convert Licensing Options (LO) 16/31 and 16/32 into Exploration Licences (EL's),

Petrobras was drilling with oil shows on the 3-SES-194 (3-BRSA-1371-SES) outpost in the BM-SEAL-010 contract, SEAL-M-424 block during late-December 2019. Petrobras filed an oil show report for the well with the ANP on 16 December 2019. The outpost was spudded on 6 November 2019. The well has a proposed total depth (PTD) of 5,546 m. The Late Cretaceous to Tertiary Calumbi Formation is the main objective. Petrobras is utilizing the “Petrobras 10000” D/S to drill the well in a water depth of 2,696 m. The NPW is located in the southern area of the block approximately 2.9 km north north-west of the 3-BRSA-1244-SES outpost well for the Moita Bonita prospect. Petrobras holds 100% working interest in the contract BM-SEAL-010 contract, SEAL-M-347, SEAL-M-424 blocks. The SEAL-M-424 block is one of three blocks that is part of the Moita Bonita discovery evaluation area. In March 2019, the ANP reported that Petrobras made a partial relinquishment of the BM-SEAL-010 contract, SEAL-M-347, SEAL-M-424 blocks retroactive to 28 August 2018. Previously the BM-SEAL-010 contract covered 1,259.38 sq km with the SEAL-M-347 block having 755.87 sq km and the SEAL-M-424 block having 503.51 sq km. Petrobras relinquished 464.32 sq km of the western area of the SEAL-M-347 block leaving a valid exploration area of 291.55 sq km. A total of 131.88 sq km of the north-eastern block area was relinquished from the SEAL-M-424 block leaving a valid exploration area of 371.63 sq km. The total valid BM-SEAL-010 contract area is now 663.18 sq km.

Petrobras - Sergipe-Alagoas Basin - BM-SEAL-010 contract, SEAL-M-424 block - drilling with oil shows 3-SES-194 (3-BRSA-1371-SES)