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Eni + Total have signed with Sonatrach to form a joint partnership for Algerian deeper water exploration. In parallel, Eni + Total will pursue new [believed offshore] exploration opportunities.

Algeria, not found

NES field area, Abu Sennan (GPC) (Dev) block, Abu Gharadiq Basin, P&A at TD 3,050m (Kharita) early Aug '19, EDC rig 16.

Egypt, Abu Gharadiq (Dev)

The conversion of Schlumberger’s 27.5% ‘synthetic interests’ in the Anoual permit (8,880 sq km in E. Morocco) to a standard partnership was approved by the authorities on 16 April. Possibly involved too are the Tendrara Lakbir + Matarka blocks which had been subject to the same conversion request. Sound (op), 47.5%, Schlumberger 27.5%, Onhym 25%.

Morocco, Tendrara (Dev)

CNPC has reportedly taken over from Chevron as optr of the Chuandongbei project serving the Luojiazhai, Dukouhe-Qilibei and Tieshanpo sour gas fields in Sichuan. A phase 2 devt will soon address the Tieshanpo field in which 7 wells are planned as of late Nov '19. Chuandongbei is currently served by 3 trains, total capacity 258 MMcf/d, production started in 2016. Phase 3 devt envisages a couple more trains for the Dukouhe-Qilibei field group, total capacity >530 MMcf/d.

CNPC has reportedly taken over from Chevron as optr of the Chuandongbei project serving the Luojiazhai, Dukouhe-Qilibei and Tieshanpo sour gas fields in Sichuan.

On 20 December 2019 Source Energy acquired a 20% interest in PL 817 and PL 817 B from operator Neptune (confirmed by the NPD on 10 January 2020). A well is due to be drilled on the HPHT Eirik prospect in PL 817 in 2021. PL 817 lies to the west of Gudrun on the border with the NCS and covers parts of blocks 15/2 and 15/3. PL 817 B lies immediately north, covering parts of blocks 24/11 and 24/12. The Eirik prospect lies on the western flank of Gudrun and has an Upper Jurassic objective at around 4,200 m TVDSS. Pressures of over 800 bar could be encountered. More details will be available closer to spud. Gudrun came onstream in April 2014 and, according to the NPD, had remaining recoverable reserves of 116 MMboe from its total estimated recoverable volume of 248 MMboe in December 2018. The HPHT oil and gas field was discovered by Elf in 1975 with well 15/3-1 S. It was developed using a steel platform, with the wellstream being partially stabilised at the process facility onboard before export via a 55 km pipeline to Sleipner A. Production at the field is in decline so the Gudrun Phase II project is being implemented to increase recovery by maturing new drilling targets, updating the drainage strategy, implementing other IOR measures (including a water injection plant) and carrying out an infill drilling campaign. Start-up of the project is scheduled for 2021. The phasing in of the nearby 15/3-4 (Sigrun) discovery, for which a PDO exemption has already been granted, is also under consideration. A power-from-shore solution is being designed as part of the Utsira High Area power grid project (see separate article), due in 2022. Following completion of the deal, interests in both licences are divided between Neptune Energy Norge AS (30% + operator), OMV (Norge) AS (50%) and Source Energy AS (20%).

Neptune (-> 30% op, OMV 50%) has assigned 20% of its 50% operated stake in PL 817 and PL 817 B to Source Energy.

United Oil and Gas Plc (United) has agreed an option to farm-in to block 49/29c (P2264) which contains the Acle prospect in the Southern North Sea. The company will acquire a total of 24% interest in the acreage from Swift Exploration Limited and Stelinmatvic Industries Ltd (12% from each) which currently hold 50% each in the acreage. In return for the interest United will pay 30% of the first exploration well on the prospect. The well has an estimated cost of USD 10 million. Execution of this option is dependent on further partners coming into the licence and a drilling commitment for the well. On 30 November 2018 Swift relinquished blocks 49/30b and 50/26a which are also part of P2264. Therefore, one block remains in the licence in which the Acle prospect sits. The Acle prospect is thought to hold gross recoverable resources of 50 Bcf to 160 Bcf and is located to the west of the Davy North gas field. Acle is thought to be a 2.5 sq km four-way dip closure with a further fault bounded upside. The reservoir is the Permian Rotliegendes formation as is common with most of the producing fields in the area. If an exploration campaign was successful then development could be via the Sean fields to the north of the prospect. Two wells have been drilled in the area which were both dry but these were believed to be off structure. Following the execution of the option along with other partners farming in to the acreage to drill a well, United Oil and Gas Plc will hold a 24% interest. Swift Exploration Limited and Stelinmatvic Industries Ltd interests would potentially change due to further farm-in partners.

United Oil and Gas Plc (United) has agreed an option to farm-in to block 49/29c (P2264) which contains the Acle prospect in the Southern North Sea. The company will acquire a total of 24% interest in the acreage from Swift Exploration Limited and Stelinmatvic Industries Ltd (12% from each) which currently hold 50% each in the acreage. In return for the interest United will pay 30% of the first exploration well on the prospect.

Shuangtan 18 flow tested approximately 10.82 MMcfg/d from the Permian Qixia carbonate Formation on 18 July 2020. The success of Shuangtan 18 further confirmed the gas potential of the Permian carbonate reservoir within the southern area of the Shuangyu Structure of the Sichuan Basin. Shuangtan 18 was spudded in November 2018 and was suspended for testing at PTD of 7,650m in early March 2020. Shuangtan 18 is in the PetroChina operated Beichuan-Jiange Block in the Sichuan Basin and is geographically located within Sichuan Province, Jinyang City, Houba Town, Linjing Village.

(Sichuan Basin)

Te Giac Trang (White Rhinoceros) field in block 16-1, Cuu Long Basin, TD 4,906m, compl. early Apr '20, Idun JU. L. Miocene Bach Ho + L-U Oligocene 'D & E' sequence target reservoir intvs fracked + completed as dual producers. * HLJOC = PetroVietnam, PTTEP, Soco + OPECO.

Te Giac Trang-15X (16-1-TGT-15X) appr Te Giac Trang (White Rhinoceros) field in block 16-1, Cuu Long Basin, TD 4,906m, compl. early Apr '20, Idun JU. L. Miocene Bach Ho + L-U Oligocene 'D & E' sequence target reservoir intvs fracked + completed as dual producers. * HLJOC = PetroVietnam, PTTEP, Soco + OPECO.

Chanda D&PL, Potwar Basin, re-entry of 1999 discovery for workover, tested 700 bo/d + 2.2 MMcfg/d on 1/2” choke from the Hangu / Cretaceous Lumshiwal fm’s, the 1st time oil is encountered in the Hangu fm here, WHFP ab. 1,200 psi. The 1999 discovery zone tested up to 1,223 b/d of 41 API oil + 5.2 MMcfg/d on 1/2” choke from the Jurassic Datta fm. OGDC (op), partners Zaver + Govt Holdings.

Chanda 1 (OGDCL op.72%, GHPL 17,5%, Zaver 10,5%) in Chanda D&PL block, flowed 700 bo/d and 2,2 MMcfg/d [32/64” choke] from the Hangu / Cretaceous Lumshiwal Fms.

Chrysaor has completed its USD 2.675 bn acquisition of ConocoPhillips’ UKCS assets, adding some 72,000 boe/d to its portfolio, including from Britannia, Clair and J-Block fields. The deal is retro-effective 1 Jan '18. ConocoPhillips otherwise retains its commercial trading business + operatorship of the Teesside oil terminal. For a list of acquired assets, please refer to GEPS. www.harbourenergy.com.

Chrysaor has completed its USD 2.675 bn acquisition of ConocoPhillips’ UKCS assets, adding some 72,000 boe/d to its portfolio, including from Britannia, Clair and J-Block fields.

On 8 June 2018 the Ministry of Environment approved the transfer of a 60% stake and operatorship in the Aitoloakarnania exploration permit from Energean Oil & Gas to Repsol. The effective date of the transfer will the date of the reception by the licensing authority Hellenic Hydrocarbon Resources Management (HHRM) of the required documents (notarial act of transfer and a modified bank guarantee). The deal was announced in March 2017. Energean was selected as preferred bidder for the Aitoloakarnania block on 4 February 2016. The block was part of the “Call for Tenders for the exploration and exploitation of hydrocarbons Onshore Western Greece”, which was launched in 2014. The contract was officially awarded to the company on 15 March 2018 upon publication of the ratification of the contract by the Greek parliament in the official gazette. When the transfer will be effective, interest share in the Aitoloakarnania exploration permit will be shared between Repsol Exploracion Aitoloakarnania SA (60% -operator) and Energean Oil & Gas SA (40%).

Ministry of Environment approved the transfer of a 60% stake and operatorship in the Aitoloakarnania exploration permit from Energean Oil & Gas to Repsol.

SK-319 off Central Luconia, Sarawak, P&A dry end Sep ’18, Naga 7 JU off to E6 field. Target Middle Miocene Cycle IV/V carbs. Shell (op), partner Petronas.

Malaysia (Central Luconia Province) E6

In October 2017, Rift Energy Corp. was still looking at farming out up to 49% working interest in its onshore Block L19, prior to starting with drilling operations. The company has been farming out a stake at least since early 2015. Rift Energy applied for a validity extension period to its second exploration period that was due to expire in September 2017. To date, over 21 leads including four drillable prospects (two gas and two oil) have been identified (see Background Information). Targets include shallow oil and deeper gas (Karoo Sandstone Formation). The company estimates that the top ten leads and prospects contain mean recoverable resources of 856 MMbbl of oil and 13Tcf of gas. Rift Energy owns a 100% participating interests in the block. The tract covers approximately 9,000 sq km in the Lamu Basin and is adjacent to Block L17/L18 operated by Afren in southern Kenya. Contact details Tom Guidish - Vice President of Operations Tel: +1.832.299.6692 ext 112 Email: tguidish@riftenergycorp.com Background Information Rift Energy Corp. signed its Production Sharing Contract (PSC) for Block L19 on 21 June 2012. This marked Rift Energy’s first entry in Kenya. The company is headquartered in Woodlands, Texas, but it is a privately held Canadian company focused on acquiring oil and gas projects in East and Central Africa. The 6-year exploration schedule included an initial 2-year period, and two additional 2-year renewal periods. The initial period work commitments included a USD 250 K Aerial gravity and magnetic survey, as well as a 2D seismic survey. The PSC terms included an additional USD 20 million programme comprising 3D seismic acquisition or the drilling of an exploratory well in case of a first renewal period. Finally there is a commitment of USD 20 million exploratory well in case of a second optional renewal period. The licence was partially relinquished (25%) in September 2014 and entered into the first renewal period. Exploratory works in the licence The acreage includes one exploration well, Ria Kalui 1, drilled by Mehta Exploration between July 1961 and December 1962. The well was plugged at a TD of 1,538 m. Tar staining and bitumen were found in cuttings (Permo-Triassic arkoses and pebble sandstones). In early 2013, Rift Energy completed a 7,064 line-km aerial gravity and magnetic survey. In late 2013, the company completed a geochemical survey that included 640 geochemical sample points. The geochemical survey reportedly indicated the presence of hydrocarbons within the block. During 2014, Rift Energy completed a 724 line-km 2D seismic program, which was further integrated with the aerial gravity and magnetic data. All the data collected was integrated and allowed Rift to propose the existence of four drillable prospects: Saturn, Mercury, Mars and Jupiter.

Kenya Rift Energy Corp still seeking a partner in Block L19 prior to drilling operations

Ref. recent DEAs, blocks on offer for the upcoming round are firming-up, the latest inventory shown below (18 units) and ready for a March 2020 launch. Applications deadline mid-Apr '20 with the DGPC. Bid docs can be obtained from www.ppisonline.com. Positions are as customary defined in the block name, e.g. '3069-9' = N 30, E 69, 9th block in area):

DEAs, blocks on offer for the upcoming round are firming-up, the latest inventory shown below (18 units) and ready for a March 2020 launch. Applications deadline mid-Apr '20 with the DGPC.

Sapura has made its entry into the Australian upstream by signing a farm-in deal with Finder Exploration for AC/P61, EP 483, TP/25 + WA-412-P. Sapura gets 70% + operatorship in Bonaparte AC/P61 (355 sq km), and likewise in North Carnarvon Basin EP 483 + TP/25 (total 1,076 sq km) and WA-412-P (387 sq km), Finder retains 30%. The deal remains subject to usual approvals.

Sapura Upstream has acquired 70% of portfolio of exploration permits comprising EP 483 & TP/25, WA-412-P and AC/P 61 from Finder Exploration (will retain a 30% non-operating interest).

Total and Uzbekneftegaz have signed a co-operation agreement providing for studies on opportunities for joint exploration in Uzbek blocks. A joint working group will be established within the framework of this agreement.

Total and Uzbekneftegaz have signed a co-operation agreement providing for studies on opportunities for joint exploration in Uzbek blocks. A joint working group will be established within the framework of this agreement.

Wellesley acquired 40% interest from Total and 20% interest from Spirit in PL 685 with effect from 1 July 2018. Four months later, in the same licence, Wellesley then transferred 40% of its equity to Aker BP with effect from 30 November 2018. Both deals were announced on 6 December 2018. The licence covers a 407 sq km area over parts of blocks 34/6, 35/1 and 35/4. The acreage covered by the licence has yet to be drilled. It lies in between the Peon and Garantiana discoveries. The Peon discovery well was located on the apex of a mound structure and targeted a Pleistocene fluvio-glacial / glacio-marine sand body at a very shallow level. A 38 m thick, homogenous, unconsolidated sand was encountered at 574 m (named the Peon Sandstone of the Nordland Group) and 19 m of this contained very dry gas (99.5 vol% methane). The well was re-entered for testing in 2006 but the planned test could not be carried out. Equinor is currently considering developing Peon. If the development of Peon does go ahead it is likely to use an unmanned, remotely operated, stand-alone platform. Estimated recoverable reserves are approximately 690 Bcfg. Total discovered Garantiana in 2012 with 34/6-2 S. The Cook Formation was oil-bearing (gross oil column of 100 m) and was tested at a rate of 4,300 bo/d through a 28/64” choke. Downdip sidetrack 34/6-2 A found the OWC which had not been encountered in the original hole. In 2014 the find was appraised by 34/6-3 S. This well proved a 120 m gross oil column in a very good quality Cook Formation reservoir with no OWC. On test the well flowed at a stable rate of 5,912 bo/d through a 24/64” choke and a maximum rate of 6,919 bo/d through a 28/64” choke. Recoverable reserve estimates were increased to 38-88 MMbo. The reservoir lies at a depth of approximately 3,810 m and has a porosity of 20%. Garantiana partner Point Resources confirmed in April 2018 that the Equinor-operated field will be developed as a subsea tie-back. The host facility was due to be chosen later in 2018. Earlier reports from Wood Group in 2017 showed that the hosts which were being considered were Equinor’s Gullfaks B and Visund facilities. Following the completion of both deals, interests in PL 685 are divided between Aker BP ASA (40% + operator), Wellesley Petroleum AS (40%) and Petoro AS (20%).

Norway (Tampen Spur (Viking Graben Province)) Visund

DNO, the Norwegian oil and gas operator, has announced completion of testing and appraisal of the Baeshiqa-2 exploration well in the Kurdistan Region of Iraq and the imminent spud of an exploration well on a separate prospect, Zartik, located 15 kms southeast on the same license. The testing has proven oil and gas in three separate Triassic aged reservoirs. Evaluation of the test results will determine next steps towards further appraisal and assessment of commerciality. As previously reported, in November 2019 DNO issued a notice of discovery to the government that hydrocarbons had been flowed to surface from the upper part of Triassic Kurra Chine B reservoir during first phase of testing. The reservoir produced between 900 and 3,500 barrels of oil per day (bopd) with specific gravity ranging between 40 and 52 API and sour gas between 8.5 to 15 million standard cubic feet per day (MMcfd). Following a workover and acid stimulation, testing resumed in March 2020 in three other separate Triassic aged reservoirs with each flowing variable rates of light oil and sour gas, too.  During the second phase of testing, the lower Kurra Chine B reservoir produced between 600 to 3,500 bopd with specific gravity ranging between 47 and 55 API and sour gas between 4 to18 MMcfd. The test demonstrated that the upper and lower Kurra Chine B reservoirs are in communication, proving a hydrocarbon-bearing reservoir interval of around 150 meters. The Kurra Chine A reservoir flowed between 950 to 3,100 bopd of 30 to 34 API and sour gas ranging from 1.8 to 3.6 MMcfd from a hydrocarbon-bearing reservoir interval of 70 meters.   The Kurra Chine C reservoir was the deepest encountered in the well covering only 34 meters of what is expected to be a thicker reservoir of around 200 meters. The drilled interval has been exposed to significant fracture damage due to the pumping of lost circulation material. The reservoir produced between 200 to 1,200 bopd of 52 API gravity and sour gas between 3.8 to 6 MMcfd. Shallower Jurassic aged reservoirs were encountered during drilling and tested. However, the tested zones were not acid stimulated, and the results are inconclusive. The well was spud in February 2019 and drilled to a total depth of 3,204 meters (2,549 meters TVDSS), encountering almost a kilometer of fractured carbonates with poor to good oil shows. Baeshiqa-2 well was drilled safely, below budget and with all exploration objectives achieved. The Zartik-1 well is anticipated to spud on 15 May 2020. Site construction was completed ten days ago on time and below budget. DNO acquired a 32 percent interest and operatorship of the Baeshiqa license in 2017. Partners include ExxonMobil with 32 percent, Turkish Energy Company with 16 percent and the Kurdistan Regional Government with 20 percent. Original article link Source: DNO

Baeshiqa 2 expl. (DNO (op), partners ExxonMobil, Turkish Egy Co + KRG (carried) in Baeshiqa PSC, light oil + sour gas find in the upper part of Triassic Kurrachine B, testing of the latter + other Jurassic + Triassic zones now completed: The Upper Kurrachine B gauged 900-3,500 b/d of 40-52 API oil + 8.5-15 MMcf/d sour gas under phase 1, and in March a lower Kurrachine B flowed 600-3,500 b/d of 47-55 API oil + 4-18 MMcfd sour gas, total hc reservoir ab. 150m. The Kurrachine A yielded 950-3,100 b/d of 30-34 API oil + 1.8-3.6 MMcfd sour gas, 70m reservoir. The Kurrachine C (deepest) encountered only 34m of what is expected to be a 200m reservoir, but significantly fracture-damaged due to lost circulation. It tested 200-1,200 b/d of 52 API oil + 3.8-6 MMcfd sour gas. TMD=3204m

On 26 July 2019, Indonesian Ministry of Energy and Mineral Resources (MEMR) offered the East Gebang exploration block, located offshore in the North Sumatra Basin, under the Conventional Oil and Gas Bidding Third Round 2019. Access to bid documents is scheduled from 26 July 2019 to 18 October 2019. Submission of participating documents is from 18 October 2019 to 25 October 2019 at 2.30 pm (Western Indonesian Time). The data package for the East Gebang block comprises approximately 9,013 km of 2D seismic data (vintage from 1968 to 2012), 471 sq km of 3D seismic data (2007), three G&G reports and three G&G maps. As an incentive to participate to the bidding exercise, free access to the data package will be granted to all companies that purchase the bid document for the related block. The data package will be only charged to the eventual winner of the block. The minimum signature bonus for the block will be USD 2.5 million. Minimum firm commitments for the first three-year exploration period include G&G studies, 400 sq km of 3D seismic acquisition and processing. The contract will require a mandatory relinquishment of 20% of the block area at the end of the third year. The block, covering an area of approximately 4,214 sq km, is located offshore North Sumatra, at water depths of less than 100 m. There are 11 wells previously drilled within the block area. North Sumatra Oil drilled five exploration wells in the 1970s, including three new-field wildcats (NSO 1N, NSO 1S, NSO 4N) and two outposts (NSO 3S, NSO 4S), under the Malacca Strait PSC. Aquitaine took over operatorship of the block in 1978 and drilled Pusung 1. NSO 1S was drilled to a total depth of 2,020 m and was a gas and condensate discovery, while the remaining five wells were either dry holes or gas shows. In 1985, Chevron drilled Glagah 1 under the Langsa PSC. The well was plugged and abandoned as a gas and condensate discovery. Bow Valley Exploration drilled three wildcats under the Asahan PSC from 1985 to 1986. Two of the wells (Kemiri 1 and Kerinci 1) were unsuccessful while the third one (Kambuna 1, 1986) was a gas and condensate discovery. The Glagah and Kambuna discoveries are excluded from the East Gebang bidding block. In 1988, Petroz drilled wildcat Tonjol 1 under the Asahan PSC, encountering minor gas indications in the Belumai Formation. In 2001, Matrix Oil drilled wildcat Kambuna West 1 (Offshore Asahan PSC), which was plugged and abandoned with gas shows. Petronas Carigali drilled exploration wells Tanjung Perling 1 (2012, gas shows), and Pakol South 1 (2014, dry) under the West Glagah Kambuna PSC. Proven reservoir in the block area are the Belumai Formation, Baong Formation, Keutapang Formation and the Peutu carbonates. Pre-tertiary Basement is also proven to be a reservoir, with the discovery in Glagah 1 well. Several prospects and leads have been identified in the area with total recoverable unrisked resources estimated at 10 MMSTB and 488 Bcfg. Background Information West Glagah Kambuna PSC The West Glagah Kambuna block covers an area of 3,244sq km. It was officially awarded to Petronas Carigali and PT Pertamina on 30 November 2009, under the regular tender mechanism for the Phase II 2008 Tender Round, with 60-40 partnership interest. Firm commitments for the first three years of exploration include G&G studies (USD 2.0 million), acquisition of 500 km 2D seismic data (USD 0.5 million), acquisition of 350sq km 3D seismic data (USD 10 million) and drilling of two exploration wells (USD 23 million). The firm seismic acquisition commitments have been fulfilled. A signature bonus of US$ 8.0 million was paid for the block. Throughout the exploration period, Petronas Carigali drilled two exploration wildcats, Tanjung Perling 1- spudded in August 2012 and completed as a gas shows well in September 2012. The second well Pakol South 1- spudded in December 2013 and completed as dry well in January 2014. Petronas Carigali completed a 370 sq. km 3D seismic survey from November to late December 2010 using the “Geo Natuna” survey vessel. And in between March to April 2012, the company shot additional 800 km of 2D seismic using the Nordic Maritime “Nordic Energy” Vessel. These seismic data were used to evaluate and mature exploration prospect in the block. The operator has filed a relinquishment request for the PSC in November 2015. Exploration commitments for the PSC have likely been completed.

On 26 July 2019, Indonesian Ministry of Energy and Mineral Resources (MEMR) offered the East Gebang exploration block, located offshore in the North Sumatra Basin, under the Conventional Oil and Gas Bidding Third Round 2019.

Karish (I/7) lease, sidetrack 700m N. of K.N. gas discovery, GWC at 4,791m VD, light oil/cond rim above GWC, total hc column 310m, confirms confirming best est. 0.9 Tcf + 34 MMbbl light oil / condensate recoverable resources, Stena DrillMAX to Karish Main devt. Karish North will be developed via a tie-back to the Energean Power FPSO. Release here.

Karish North 1 ST, (Energean 100%) sidetrack 700m N. of the original Karish North near-field explo well in Karish block, light oil/cond rim above GWC, total hc column 310m, confirms best est. 0,9 Tcf + 34 MMbbl light oil / condensate recoverable resources.

Equinor used the “Transocean Spitsbergen” S/S to spud a well on the Presto prospect on 4 March 2019. 36/1-3 is located in PL 885 to the east of Agat. Presto has potential recoverable reserves of 160 MMboe according to partner Capricorn. The main objective is the Lower Cretaceous Agat Sandstone which is mapped to pinch-out against the Basement High. There is also secondary potential in an Upper Cretaceous, stacked, channelised turbidite fan complex. Equinor drilled to TD at 2,913 m and on 25 March 2019 the well was abandoned. Results are expected to be announced shortly. Two wells have previously been drilled just off-prospect (as mapped by Capricorn) – 36/1-2 to the north and 35/3-5 to the west. 36/1-2 was drilled by Saga in 1975 and recorded shows from the Upper Cretaceous Tryggvason Formation to the Upper Jurassic Intra-Heather Sandstone. The shows were strongest in the Agat Formation. 35/3-5 was also drilled by Saga in 1981/2 and it also encountered weak shows in the Agat Formation. Interests in PL 885 are divided between Equinor Energy AS (20% + operator), Cairn through Capricorn Norge AS (30%), Wellesley Petroleum AS (30%) and Petoro AS (20%).

036/01-03 (Presto) (Equinor 20% + op. Cairn 30%, Wellesley Petrol. 30%, Petoro 20%) in PL 885 - P&A, results awaited, primarily targeting Early Cretaceous Agat sst with a secondary target in the Late Cretaceous turbidite complexes, and mean gross prospective resources are estimated at 160 MMboe.

Corallian Energy Limited is seeking farm-in partners to drill an appraisal well on the 1977 Curlew-A discovery made with well 29/7-1. Corallian is looking to divest up to 60% interest in the licence and in October 2018 announced that it has agreed to farm down 10% interest to Talon Petroleum Limited. The remaining interest is still available. The appraisal well is planned to be drilled in Q3 2019 with a Jack-up rig in water depths of 93 m. TD is 2,700 m and well costs are in the region of GBP 9.7 million. The company has 3D seismic over the discovery. The Curlew-A discovery was made by Shell and is a 4-way dip closed oil bearing structure. The discovery well encountered net oil sands (Cromarty and Odin Members of the Sele and Balder Fm) of 10.5 m and recovered multiple oil samples of 36° API. The licence was previously held by Shell until it relinquished the acreage in 2016 prior to Corallian picking up the acreage in the 30th Licensing Round and is currently in its first phase. In October 2018 Schlumberger completed a Competent Person’s Report (CPR) stating that 3C combined Contingent Resources of the Cromarty and Odin reservoirs were 68 MMbo and 79 Bcf (82 MMboe recoverable), 2C Contingent Resources are 45 MMboe. There is updside in a secondary objective of the Forties Sandstone unit which wasn’t encountered during the discovery well but may be developed across the south-western flank. Resources of 22 MMbo have been estimated for the Forties sands. Following completion of the deal in May 2019 with Talon Petroleum, interest in the licence is held by Corallian Energy Limited (90% + operator) and Talon Petroleum Limited (10%). For further information, please contact: Andrew Hindle Commercial Director Andrew.hindle@corallian.co.uk +44 7775712817

Corallian is looking to divest up to 60% interest in the licence and in October 2018 announced that it has agreed to farm down 10% interest to Talon Petroleum Limited. The remaining interest is still available.

The ANP in early December 2019 approved the allocation to Petrobras by Repsol-Sinopec of its 11.11% of the BM-ES-21 Contract Block ES-M-414, in the deepwater Espirito Santos Basin. Petrobras now has 100% of the block. The deal has been pending ANP approval since June. The block from ANP Round 6 was awarded in 2004 and in 2011, Petrobras reported a natural gas discovery there in the post-salt with the 1BRSA983ESS, also known as Malombe, in 980m of water. Between 2009 and 2014, five wells other wells were drilled on the block but most of that acreage has been relinquished. The ANP in late March 2018 approved a request by Petrobras to delay the deadline for a commerciality declaration of the Malombe discovery (1BRSA983ESS) until November 2022 in Block ES-M-414. The reasoning of Petrobras when requesting the extension was very similar to the reasons given by Statoil when it recently was granted a five-year extension to complete exploration on the Campos Basin C-M-539 Block containing the Pao de Acucar, Seat and Gavea discoveries. Both companies cited portions of the concession contract which allow that a declaration of commerciality must wait for the creation of a natural gas market or the installation of transportation infrastructure. The Malombe gas discovery has been under evaluation since 2014. Prior to the granting of the extension, the contracts exploratory phase would have ended. The 1BRSA983ESS was suspended with gas shows in 2011 at a total depth of 3,025m.

Not Found

Bid submission deadline for the 4 blocks on offer has been postponed from 27 May to 4Q '20, specific date yet n/a. Details from oil.gas@fmeri.gov.ba or BiHLicensingQueries@ihsmarkit.com. It is recalled 4 blocks totalling 4,951 sq km are available, 3 in the Pannonian Basin (BiHPo1, BiHPo2 + BiHTz) and 1 in the Dinarides (BiHD1) as per the map below.

Bid submission deadline for the 4 blocks on offer has been postponed from 27 May to 4Q '20, specific date yet n/a.

Further to DEA 17 May ’18: Prospect astride blocks N4, N7c and N8, P&A gas discovery on 13 May ’18, Prospector 1 JU. Oranje-Nassau (well op), partners Hansa HC (blk op) + EBN.

N/7-4 (Tanzaniet prospect near from Ruby disc.) (Oranje-Nassau op.30%, Hansa Hydroc. (wholly owned by Discover Exploration - 30%), Energie Beheer 40%) in block N7c, now announced gas discovery.

CNPC and Petrobras have reportedly signed HoA that could lead to the Chinese company acquiring interests in the re-vitalisation of Petrobras’ Marlim, Voador, Marlim Leste + Marlim Sul fields (Marlim cluster), Campos Basin. TheLoI includes a joint assessment of the suspended Comperj refinery project in Rio de Janeiro state, which could be used to process any heavy oil produced. Tenders are reportedly out for 2 FPSOs for ops at Marlim.  Petrobras and CNPC are already engaged in joint ops at the Libra field.

Brazil (Campos) Petrobras and CNPC have signed a letter of intent that may see the Chinese player acquiring stakes in the Marlim fields.

In May 2017, Khalda Petroleum suspended the Herunefer West 1 exploration well in the Khalda Offset-A East block after the well yielded 1,694 bo/d from the Jurassic Safa Member. The well was spudded on 16 February 2017 with the SinoTharwa’s “ST-4” land rig and drilled to a TD of 4,663 m in the Lower Jurassic Qattara formation. The main targets were the Safa Member and the Masajid formation.  The planned TD was 4,572 m. Khalda Petroleum Co is a JV between the EGPC (50%), Apache Oil Egypt (33.5%) and Sinopec IP Corp (16.5%). Background information Herunefer is a gas & condensate field located in the Northern Egypt Basin, onshore Egypt. On 6 May 2014, Apache Corporation announced that the Herunefer 1X wildcat in the Khalda Offset concession had discovered gas & condensate in the Alamein, Alam El Bueib-6, Masajid, Upper Safa and Lower Safa formations. The well tested a combined rate of 49 MMscf/d of gas and 7,700 bc/d from the Jurassic Upper and Lower Safa formations.  

Egypt, Khalda Offset (Dev)

HZ 27-5-1 completed in late March 2020 without result reported. CNOOC – Shenzhen spudded a new-field wildcat (NFW) on 20 February 2020 in the Pearl River Mouth Basin of the South China Sea. HZ 27-5-1 (Huizhou 27-5-1), located in the Huizhou Sag in a water depth of about 110 m area, is targeting the Mio-Oligocene clastic play. “Nanhai 7” S/S is used for the drilling operation and it is expected to complete by mid-April 2020. The Huizhou Sag is also one of the important exploration focuses for CNOOC in the Pearl River Mouth Basin. For the past few years extensive drilling progress has been carried out. In 2019, a few wells were drilled in the Huizhou Sag, with result unreported yet, such as HZ 22-8-1, HZ 20-1-1d, HZ 25-10-1 and HZ 14-1-1d, etc. There are also a few discoveries made earlier in the area, tested oil in the Miocene Zhujiang Formation, however no further appraisal drilling work has been done to those discoveries due to possible small size and uneconomic at that time. These discoveries include HZ 21-1S, HZ 27-1, 27-4, 27-3, HZ 26-2-1 and HZ 26-3-1 etc. While previous dry holes drilled in the Huizhou Sag included HZ 22-2, HZ 23-1/23-2 and HZ 14-2, etc. Background Information Huizhou Sag is an oil-rich generated source kitchen in the Pearl River Mouth Basin, there are several existing producing fields in the area, such as Huizhou 26-1, 21-1, 32-2, 32-3, Huizhou 19-1/2/3, and Huizhou 25-3/4/8 fields cluster etc., those fields together have already produced a cumulative of over 400 million bbls of oil as of 2018. While the Huizhou 32-5 oilfield comprehensive adjustment/Huizhou 33-1 oil field joint development project commenced production a year earlier in January 2019.

Shenzhen – HZ 27-5-1 – Completed without result reported – PRMB, South China Sea

Mubadala Petroleum plugged and abandoned appraisal well Nong Nuch-4, located offshore in the G11/48 concession, in the Narathiwat Ridge, on 3 July 2019, with minor oil. The well was drilled to a total depth (TD) of 1,116 m, approximately 1,400 m shallower than its discovery well, Nong-Nuch-2. Spudded on 29 June 2019 using “Ensco 115” J/U, Nong Nuch-4 encountered 0.9 m of oil in the primary objective, most likely the Middle Miocene fluvial sandstone which is the producing reservoir in the adjacent Bongkot and Nong Yao fields. Nong Nuch-4 was drilled back-to back with the new-field wildcat Nong Nuch-2 which was completed on 28 June 2019. Spudded on 22 June 2019, the discovery well was drilled to a TD of 2,516 m prior to being plugged and abandoned as an oil and gas discovery. The first new-field wildcat, Nong Nuch-1 was also the first well drilled in the Narathiwat Ridge. It was drilled to a TD of 1,015 m from 16 until 20 June 2019, prior to being abandoned as dry. Interest in G11/48 concession is divided between Mubadala Petroleum (Thailand) Limited (90%, operator) and Palang Sophon (10%). Mubadala increased its stakes in the concession from 67.5% to 90% in June 2018, after acquiring an additional 22.5% interest from previous partner KrisEnergy for a consideration of USD 13.3 million. Background Information The G11/48 concession consists of seven other fields such as Nong Yao (producing under improved recovery regime) Nong Yao C, Nong Yao SW, Angun-1 (appraising) Boondarik-1, Bua Luang-1 and Mantana-1 (discoveries). Pearl Oil (Thailand) Ltd and partners was officially awarded the G11/48 concession on 13 February 2007. The original G11/48 concession covers a surface area of 13,600 sq km. In January 2010, Kris Energy completed the sale and purchase agreement to buy over 25% working interest in block G11/48 from Tana Resources, a wholly owned subsidiary of Tana Exploration LLC. After the transaction completed, interest in G11/48 are divided between Pearl Oil (Thailand) Limited (75%, Operator) and Kris Energy (25%). Previously on 12 June 2019, the operator completed an appraisal drilling campaign in the Nong Yao field. Three wells were drilled within 22 days from the same surface location, resulting in mixed outcomes. Spudded on 22 May 2019, Nong Yao 9 and its first sidetrack well were likely plugged and abandoned after having encountered oil, most likely in the targeted Pattani Sequence III reservoir. Subsequently, Nong Yao 9ST2 well was kicked off on 7 June 2019 and abandoned as dry.

Mubadala Petroleum plugged and abandoned appraisal well Nong Nuch-4, located offshore in the G11/48 concession, in the Narathiwat Ridge, on 3 July 2019, with minor oil.

The 147-sq km Ledyanoy block in the Khanty-Mansiysk AO, W. Siberia, was auctioned to Rosneft on 8 Feb ’18 for USD 6.6 MM (starting price USD 6 MM). Ledyanoy lies in the Middle Ob Province and contains the Ledyanoye oil find.

Rosneft secured the Ledyanoy block in the Khanty-Mansiysk AO.

GeoPark Ltd is looking to dilute its 75% in block 64,  7,635 sq km in the Marañon Basin in N. Peru, ahead of devt of the Situche Central field for which an EIA has been submitted. Partner Petroperu.

GeoPark Ltd is looking to dilute its 75% in block 64, 7,635 sq km in the Marañon Basin in N. Peru, ahead of devt of the Situche Central field for which an EIA has been submitted. Partner Petroperu.

On 13 May 2019 Equinor spudded a second well on the Korpfjell prospect in PL 859 (delayed from summer 2018). 7335/3-1 was located approximately 8 km south of the first Korpfjell well and was drilled using the “West Hercules” S/S. TD was reached in the Lower Triassic Havert Formation and was abandoned as a dry hole around 14 June 2019. Tight sandy intervals were encountered in the Triassic Havert Formation, Klappmyss Formation and Kobbe Formation (125 m). In the Triassic Snadd Formation sandy intervals of poor reservoir quality were encountered, with some sandstone layers containing traces of gas. Whilst not a target, the Realgrunnen Group was investigated and proven to have around 170 m sandstone reservoir of moderate to good quality. The hotly-anticipated 2017 Korpfjell exploration well 7435/12-1 proved a 34 m gas column in the Lower-Middle Jurassic Sto Formation with estimated recoverable reserves of 212-424 Bcfg (40-75 MMboe) which in this location is non-commercial. The prospect was mapped with a closure of 850 sq km, which is 3-4 times the closure of Johan Sverdrup, and it was the first well to be drilled in the recently awarded 23rd Round acreage near the Russian border. Interest in PL 859 is divided between Equinor Energy AS (30% + operator), DNO Norge AS (20%), Petoro AS (20%), ConocoPhillips Skandinavia AS (15%) and Lundin Norway AS (15%).

7335/03-01 (Korpfjell Deep) expl. (Equinor op, DNO, Petoro, COP, Lundin) in PL 859, ab. 8km SE of Korpfjell gas find that was non-commercial, WD=239m, P&A dry at TD=4268m, (L. Havert fm), targets Klappmyss, Havert, Snadd + Kobbe fm’s. Encountered sandy and mainly tight intervals at both targets, some thin sst layers in the Triassic revealed traces of gas, around 170m of sst reservoir of moderate-to-good quality were proven in the Realgrunnen sub-group of Triassic age that was not targeted by the well.

Talos and Hokchi have agreed to swap interests in Sureste offshore assets. Talos will assign a 25% interest in its block 2 to Hokchi in exchange for 25% stake in the latter’s adjacent block 31. Hokchi will operate both blocks, Talos 25%. CNH approval is yet required. Block 2 (CNH-RO1-LO1-A2/2015) covers 195 sq km in the Sureste and is otherwise shared with Sierra Blanca P&D + Premier. Hokchi’s block 31 was awarded under round 3.1 in June.

Talos and Hokchi have agreed to swap interests in Sureste offshore assets.Talos will assign a 25% interest in its Area 2 to Hokchi in exchange for 25% stake in the latter’s adjacent Area 31. Hokchi will operate both blocks, Talos 25%.

As of June 2020, it is believed that Heritage Oil plc was still seeking partners for the Rukwa Basin licence that includes the Ruwa South block. The contract covers 4,395 sq km over the Ruwa Graben, Western Branch of the East African Rift System. Heritage is the sole participant in the licence. Heritage had plan to drill its first new-field wildcat well in November 2018. The Hammerkop prospect will target a mean resource of 300 MMbo. Heritage Oil has identified in eight prospects that are analogous to the Ugandan discoveries based on a legacy 2,300 km of 2D seismic survey and a 600 km infill 2D seismic survey for a total unrisked mean prospective resources of 800 MMbl and 2.2 Tcf. On 27 June 2016, scientific journals informed that a consortium formed by Helium One and two universities in the UK had discovered 54 Bbbl of helium in the southern part of the Rukwa Graben (within the Rukwa South Licence). The helium (and nitrogen) gas was sampled at surface, bubbling out of the ground. Researchers believe that the discovered helium field is a game changer for the future security of society’s helium needs. Helium One informed previously that the helium was trapped in 27 leads defined by 2D seismic and supported by data from two legacy hydrocarbon exploration wells (see Background Information). Background Information Earlier exploration activity within the Rukwa Graben was conducted by Amoco in the mid-1980s with the acquisition of about 2,300 km of 2D seismic data and the drilling of two wells in 1987, Ivuna 1 (TD 2,316 m) and Galula 1 (TD 1,524 m). Both wells were plugged and abandoned as dry. The Rukwa Production Sharing Agreement (including both Rukwa North and Rukwa South tracts) was awarded to Heritage between October and November 2011. The first exploration period was to last for four years. Heritage completed reprocessing the legacy 2D seismic data and performed additional well data studies between 2012 and 2013. The company acquired and processed 600 km of 2D (OBC and land) seismic data targeting the basin margins. Initial interpretation indicated that the main prospective region was located in the Rukwa South area, therefore in January 2014 Heritage relinquished the Rukwa North tract. Rukwa Graben Geology The Rukwa Basin is part of the East African Rift System, Western Branch. Bordered by strike-slip faults that are connected to those of Lake Tanganyika, the Rukwa is approximately 350 km long in a northwest-southeast direction and 30-60 km wide. It is partly covered by Lake Rukwa, a very shallow lake (up to 5 m deep), fed by the Songwe and Momba rivers from the south, the Kayu and Rungwe rivers from the north and the Lukwati River from the east. Three major stratigraphic units have been recognized, from oldest to youngest: the Karoo Supergroup (Permian-Triassic), the Red Sandstone Group (Jurassic-Cretaceous) and the Lake Beds (Late Miocene-Recent). The three units crop out along the margins of the sub-basin or are exposed in stream cuts. The recent rifting commenced around eight million years ago and the oldest rift-related deposits contain Upper Miocene palynomorphs and mammalian fossils.

Tanzania (East African Rift System, Western Branch) Rukwa Basin op. by HERITAGE (100%), Heritage Oil Plc Believed still seeking partners for the Rukwa Basin licence

Vista Oil & Gas reported in a press release on 25 October 2018 that the Neuquen provincial government approved through a decree in September an addenda to the UTE contract on the Coiron Amargo Sur Oeste (CASO) Block that reflects Vista ceding to Shell subsidiary, O&G Developments, its 35% interest acquired as the stake of APCO in the license. This ceding of the interest was approved as part of a swap agreement on 22 August 2018 where Vista will obtain from O&G Developments a 90% stake on the Aguila Mora license, Neuquen Basin. This part of the deal is still pending approval from the authorities. The 35% ceded interest by Vista in exchange for the 90% stake in Aguila Mora also includes an additional US$ 10 million contribution from Shell to improve the water facility in the Cruz de Lorena Block in order to improve the water supply for Vista operations. Vista will retain a 10% working interest in CASO, Shell will have 80% and provincial company Gas y Petroleo del Neuquen will have 10%. Vista will hold 90% and Gas y Petroleo del Neuquen 10% working interest in Aguila Mora. This will increase Vista's total net acreage in Vaca Muerta to about 15,000 acres. The 170 sq km Aguila Mora block is located in the Vaca Muerta Shale oil window, as is the CASO Block. In December 2016 Aguila Mora, was granted a 35 year unconventional production concession. O&G Developments tested oil in 2013 from the Vaca Muerta on the Aguila Mora x-1001(h) and in July 2014 found oil and gas in the Aguila Mora x-3(h) horizontal well. The well tested 354 bo/d and some gas after a 10 stage fracturing. In December 2014, 346 bo/d with some associated gas was tested in the Aguila Mora e-5 (h) appraisal horizontal well also targeting the Vaca Muerta Shale.

Argentina, Coiron Amargo Sur Oeste

1 June 2020, Lukoil and Uzbekneftegaz (UNG) signed a new Memorandum of Understanding (MoU). The document provides for co-operation in the field of joint exploration and production of oil and gas in Uzbekistan. It also calls for establishment of a joint venture company for the purpose of geological exploration and commercial production. The joint venture will study geological and geophysical data in order to evaluate petroleum potential of new investment blocks. In October 2018, the two companies signed the original MoU aimed at developing their co-operation and exchanging experience in geological exploration in Uzbekistan. It was announced at the time that the parties would jointly evaluate an unspecified prospective area of 45,000 sq. km. Vintage seismic datasets would be re-interpreted and new seismic would be acquired in order to define potential drilling prospects. The MoU’s term was set at two years. Although the blocks in question were not specified, it is understood that Lukoil is looking at blocks LIV Akbuget, LV Beshbulak and LVI Tashkuduk in northern Uzbekistan. A small part of the LVI Tashkuduk block falls within the limits of the Syr-Darya Basin, while the rest of the blocks are in what is interpreted as a non-prospective territory between sedimentary basins.

Lukoil and UNG (Uzbekneftegaz) signed a new MoU. The document provides for co-operation in the field of joint exploration and production of oil and gas in Uzbekistan.

Jetex Petroleum Inc is seeking to farm-out up to 50% interest in licence P2227 (blocks 12/29a and 22/28a) which contains the Sigma discovery. The company is looking to develop the discovery by testing two objectives through a 6,800 ft vertical appraisal well. The horizontal well and test will cost USD 9 million including a USD 70,000 day rig cost. The two objectives consist of the Alness sand reservoir (proven oil) and Beatrice conventional sand reservoir. The Alness sand reservoir is planned to be drilled with a horizontal wellbore. Jetex has derived reserves for Alness and Beatrice of 35 MMbbl and 15 MMbbl respectively. Both reservoirs are sealed by thick Oxfordian Shales which could act as an effective fault seal. Jetex has completed a stimulation study independently with Xodus completing a preliminary MODPU development plan. The initial term of P2227 ends on 30 November 2019. Further potential in Jetex’s recently awarded blocks from the 31st Licensing Round in June 2019 are also understood to be available for farm-in. Blocks 11/25b, 12/21 – 12/24, 12/27 and 12/28b are located to the north and west of licence P2227.  Well 12/29-1 discovered Sigma in August 1981 reaching a TD of 7,660 ft by Kerr McGee Oil. The primary objective of 12/29-1 was to core the Lower Cretaceous and Middle Jurassic Sandstones to assess their potential as reservoirs. The secondary objective was to drill deeper into the Pre-Permian which had the potential to be hydrocarbon bearing. Highland Petroleum who held the acreage before Jetex acquired its 100% interest August 2017 reported that that a 66 ft interval flowed at 100 bo/d between 6,852 - 6,942 ft and no water contact was encountered. Interest in P2227 and Jetex’s 31st Licensing Round blocks is held solely by Jetex Petroleum Inc (100%).

Jetex Petroleum Inc is seeking to farm-out up to 50% interest in licence P2227 (blocks 12/29a and 22/28a) which contains the Sigma discovery. The company is looking to develop the discovery by testing two objectives through a 6,800 ft vertical appraisal well.

Doriemus announced on 27 February 2019 that it has agreed to sell 20% interest in the Lidsey field located in licence PL 241 to Angus Energy. Angus paid approximately USD 0.6 million with the transferal of over 8 million shares to Doriemus. Angus announced that the deal completed on 18 April 2019. The Lidsey field was discovered in March 1987 by Carless Exploration Ltd when oil was encountered in the limestones of the Middle Jurassic Great Oolite Formation. The reservoir is sealed by the overlying Oxford Clay and sourced by the Lias, Kimmeridge Clay and Oxford Clay. The structure is a tilted fault block dip closed to the north, east and west and fault sealed to the south. Over the years several EWTs were carried out with daily production in the test periods of between 40-66 bo/d. The field was eventually brought onstream in March 2008 after construction of new production facilities. Angus drilled Lidsey X2 in October 2017 which produces horizontally via an artificial lift from the Great Oolite Formation with a net oil pay of 443 m. Interest in PL 241 is held by Angus Energy Weald Basin No.3 Ltd (80% + operator), Brockham Capital Ltd (10%) and Terrain Energy Ltd (10%).

United Kingdom (Weald Sub-basin (Wessex B.)) Brockham

BP has plugged and abandoned exploration well Uba Deep 1 in the Berau PSC, located in the Bintuni Basin, likely in early March 2019, with results unreported. The well was drilled to a TD of around 3,370 m. The drilling targets likely included Permian sandstones of the Ainim Formation and Triassic quartzose sandstones of the Tipuma Formation, to explore the deeper reservoirs in the Ubadari field area. PTD for the well was approximately 3,400 m. According to local media reports, the well had reached a depth of 1,188 m (3,900 feet) as of mid-December 2018. The company planned to complete drilling operations in late Q1 2019. Uba Deep 1 was spudded in late November 2018 using “ENSCO 106” J/U. The rig reached the location on or around 22 November 2018, after conducting development drilling activities in the Vorwata field. Reportedly, the drilling cost was planned to be around USD 56 million. The operator was targeting pre-drill resources of 1.2 Tcfg to be potentially added to the Tangguh LNG project. Uba Deep 1 could be a commitment well that was due to be drilled in the Berau PSC before 2019. Other potential candidates for future drilling in the block include the Inos and Kepe-Kepe leads. The last exploration activity in the block was a 730 sq km OBN 3D seismic survey over the Tangguh Unitized area, which was completed around March 2018. The survey commenced in early August 2017 with BGP’s cable-layer, Dong Fang Kan Tan No. 2 and SeaBird’s "Voyager Explorer" S/V. Axxis Geo Solutions’ “Neptune Naiad” was also utilized as additional source to assist in the project. Around 20 February 2017, BP commenced a geotechnical survey over the Ubadari area, using the “Mariner” MV. The vessel was scheduled to continue the survey over the Ofaweri area. The Tangguh project is covered by three PSCs, namely the Berau, Muturi and Wiriagar PSCs, with partnership for the LNG project comprising of BP (40.22, operator), CNOOC (13.9%), MI Berau (a Mitsubishi/Inpex JV) (16.30%), Nippon Oil (12.23%), KG (JOGMEC/Mitsui/MI Berau/JX) (10.00%) and LNG Japan (Soijtz/Sumitomo) (7.35%). Production in August 2018 was around 1.3 Bcfg/d plus 2,700 bc/d. The Ubadari field was discovered in 1997 by ARCO, with the Ubadari 1 wildcat. The well tested 45 MMcfg/d from the Middle Jurassic Roabiba Sandstones. Appraisal well Ubadari 2, drilled in 1998, about 7 km southwest of the discovery well, was dry. Typical objective in the area is the Middle Jurassic Roabiba Sandstone, which is producing for the Tangguh Gas Project. The Ainim Formation flowed gas in the Mogoi Deep 1 discovery by BP in 1996 (onshore Muturi PSC), however the Tipuma Formation has yet to be proven as a reservoir. BP announced the Final Investment Decision for the Tangguh Expansion Project on 1 July 2016. The expansion will consist of one new LNG processing train (Train 3) with capacity of 3.8 MMtpa of LNG, equal to each of the first two trains. This will raise the overall processing capacity of the Tangguh plant to 11.4 MMtpa. The upstream developments related to the expansion will include two new offshore platforms, 13 production wells, expanded LNG loading facility and other infrastructure. Construction works are expected to take three and a half to four years, starting in late 2016. The new facility could be online in 2020. As of May 2018, development drilling was underway at the Vorwata field, using the “ENSCO 106” J/U. Following the completion of Uba Deep 1, the rig has likely been mobilized to the Wiriagar Deep field. Background Information BP was reported to have 3D seismic data reprocessing in Q1 2015. The operator intended to enhance seismic imaging covering Permian sequence and obtain better understanding of the subsurface fault-style definition within the Berau Bay area. Aside from the seismic reprocessing project, the operator also intended to conduct a detailed biostratigraphy study. Tangguh LNG Project The Tangguh LNG Project is based on 14.4 Tcf of proven and certified gas reserves from the Vorwata, Wiriagar Deep, Roabiba, Ofaweri, Wos, and Ubadari fields. BP may conduct new exploration to further raise the amount of recoverable reserves. BPMigas, Indonesia's former upstream industry regulator, approved the Plan of Development (POD) for the Tangguh LNG Project in late July 2007. The Vorwata field, in the Berau PSC, was put onstream in June 2009 and the first LNG cargo from the Tangguh project has been lifted on 6 July 2009. The cargo went to POSCO's LNG regasification terminal in Gwangyang, South Korea. The Vorwata field, which has 2P recoverable reserves of 8.33 Tcfg, was the initial source of gas for the Tangguh LNG project. Around 15 development wells were drilled in the field prior to production. The development drilling campaign commenced in late June 2007 and was completed in March 2009. Preliminary facilities include two unmanned platforms, subsea pipelines, two LNG processing trains, storage tanks, and an LNG tanker loading terminal. By the end of 2010, over 100 LNG cargos had been exported. Tangguh Expansion The Plan of Further Development (POFD) for the third LNG train was submitted in September 2012, after the finalization of reserves certification. Once submitted, the POFD was expected to be fast-tracked and approved within one month. Ministry approval of the POFD for the new facility had been initially reported in late November 2012, while in-principle approval had been granted by authorities earlier that month. Tangguh Train 3 is part of a USD 12 billion multi-year investment plan by BP in Indonesia. Tangguh produced approximately 1.3 Bscfg/d and 3,500 bc/d in March 2013. BP received formal approval for the third LNG train on 15 May 2013, as Indonesian Minister of Energy and Mineral Resources Jero Wacik signed the Plan of Further Development (POFD) during the 37th Indonesian Petroleum Association (IPA) Conference in Jakarta. The POFD also includes the drilling of 11 development wells and the execution of a joint study for the supply of 180 MMscfg/d to the local fertilizer industry. At least 40% of LNG production from the third train will be allocated to the domestic market, to state electricity firm PT PLN. In addition, up to 15 MMscf/d of piped gas produced from Tangguh will be allocated for the generation of 50 MW to support local developments, commencing from Train 3 startup date. Finally, to address short term needs of the local communities, BP will supply PLN with gas sufficient to generate 8 MW of power (4 MW in January 2013 and 4 MW in the following years). A Supply and Offtake Agreement for 4 MW of power was signed by BP and PLN in early December 2013. With this agreement, gas will be used to supply energy to private users and businesses in the Teluk Bintuni regency. The Environmental Impact Assessment for the Tangguh Expansion was approved in August 2014. BP previously expected to reach the FID on the USD 12 billion in 2015, after the reception of further regulatory and partner approvals. BP announced on 22 October 2014 the award of onshore FEED contracts for Train 3. Two consortia, led by local firms PT Tripatra and PT Rekayasa respectively, have been awarded the works that will cover the new LNG train, LNG jetty and associated infrastructure. The FEED had a planned duration of 12 months.

Uba Deep 1 (BP op. 48%, MI Berau (Mitsubishi/Inpex) 22,86%, Nippon Oil 17,14%, KG Berau 12%) in Berau PSC, off W. Papua, P&A early Mar ’19, results n/a, target assumed Permian Black shale Ainim + Tipuma Triassic red bed fm’s.

The DoE has received an area nomination for a 14,920-sq km block in the Sandakan Basin, Sulu Sea, WD 150-4,200m. The area is designated Nominated Area 1 / NA1, an undrilled open expanse under the conventional energy contracting programme, aka PCECP.  The potential applicant has not been named. GEPS map extract below:

The DoE has received an area nomination for a 14,920-sq km block in the Sandakan Basin, Sulu Sea, WD 150-4,200m. The area is designated Nominated Area 1 / NA1, an undrilled open expanse under the conventional energy contracting programme, aka PCECP. The potential applicant has not been named. GEPS map extract below:

On 2 March 2020 Spirit Energy announced the proposed divestment of three licences containing the Hejre and Solsort fields to INEOS. The deal is subject to governmental approval and on 4 August 2020 INEOS confirmed that the deal is expected to close within the year. The HPHT Hejre discovery is in the 5/98 licence (blocks: 5603/24a, 5603/28b, 5604/21b and 5604/25b), which INEOS will hold 100% interest in after it acquires the 15% and 25% interest from Spirit Energy Danmark ApS and Spirit Energy Petroleum Danmark AS. The Solsort discovery is in the 4/98 and 3/09 licences (blocks: 5604/25d, 5604/26a, 5604/29a, 5604/30d, 5604/26a Solsort and 5604/30a Solsort), which INEOS will acquire 30% interest in from Spirit Energy Danmark ApS. The southeast section of the Solsort discovery extends into the neighbouring 7/89 South Arne licence which is operated by Hess. INEOS is evaluating the possible development scenarios for Solsort field with the concept select decisions expected in 2021. INEOS announced the Hejre development concept in June 2020. The Hejre HPHT (1,011 bar and 160 degrees Celsius) oil and gas discovery was made in 2001 by the Hejre-1 well and appraised in 2004 by Hejre-2. The reservoir is in the Upper Jurassic Heno Formation at approximately 5,200 m. The previous operator (DONG) commenced development work on the field using contractors Technip France SAS, partnered by Daewoo Shipbuilding and Marine Engineering Co. Ltd (DSME) for the engineering, procurement, fabrication, hook-up and commissioning assistance of the Hejre wellhead and processing platform. A 8000-tonne jacket was installed in 2014 and five development wells were drilled between and March 2016. The field development ceased in 2016 when DONG terminated the contract for the platform after a dispute with the contractor over delays in the topside and platform. In September 2017 INEOS acquired DONG Energy and took over its 60% interest in the licence and in December 2017 Spirit Energy was formed from the merger of Centrica and Bayern Norge AS to take 40% interest in the licence. The Solsort oil and gas field was discovered by Solsort 1 (6504/26-5) in 2010, the TD was at 3,041 m TVDSS and three sidetracks were drilled with a reach of up to 1.5 km. In 2013 the discovery was successfully appraised by Solsort 2 (5604/26-6) which tested oil and associated gas from the Paleocene Rogaland Group sandstone. Two sidetracks were drilled from Solsort 2 but both were dry.

(Central Graben Province) Spirit Energy announced the divestment to INEOS of three licences (4/98, 3/09 and 5/98 licences) containing the Hejre and Solsort fields. The deal is subject to governmental approval and INEOS confirmed that the deal is expected to close within the year. After completion, INEOS will hold 100% interest in all licences.

On 2 March 2018, Marathon Oil revealed that it had sold its 16.33% interest in the Waha Oil Group to the French group Total for USD 450 million. According to Total the assets have reserves and resources of more than 500 MMboe. The production from the concession is about 300,000 boe/d and the output is expected to reach 400,000 boe/d by the end of 2020. Waha Oil Group is a JV between NOC (operator with 59.17%), Marathon Oil (16.33%), Amerada Petroleum Corp. Libya (8.17%) and Continental Oil Co of Libya (16.3%). Marathon said the company’s exit from Libya was part of its strategy to focus on high margin, high return US resource plays.

Marathon Oil has struck a deal which will see it sell its stake 16,33% in the Waha concession in Libya to Total for US$450 MM. (National Oil Corporation 59,18%, ConocoPhillips 16,33%) and Hess 8,16%).

Offers submitted by 6 companies for Intracampos round rights (XII Petrolera Intracampos Round) were opened yesterday. Bidders are Flamingo Operating (US), Frontera-Geopark consortium, Gran Tierra, Petrobell (Uruguay), Petrolamerec (Ecuador) + Zarubezhneft. It would seem that Grant Tierra’s wins have already been determined (see related entry + map), however formal assignments are yet to be announced. All proposed blocks but one received offers (none were submitted for Pañayacu Norte).

Offers submitted by 6 companies for Intracampos round rights (XII Petrolera Intracampos Round) were opened yesterday. Bidders are Flamingo Operating (US), Frontera-Geopark consortium, Gran Tierra, Petrobell (Uruguay), Petrolamerec (Ecuador) + Zarubezhneft. It would seem that Grant Tierra’s wins have already been determined (see related entry + map), however formal assignments are yet to be announced. All proposed blocks but one received offers (none were submitted for Pañayacu Norte).

17 January 2018, the Turkmengeologiya national exploration company has tested gas with condensate in the Tagtabazar-One 16 appraisal (outpost) well. The well has flowed ca. 120 Mcm/day (4.1 MMscf/d) of gas and 13 cu m (82 bbl) of condensate from two intervals of 1,924-1,920 m and 1,951-1,942 m. The well has been drilled to a TD of 4,109 m, deeper than the original PTD of 3,779 m. Although the company does not provide further details, the intervals tested are likely to be Lower-Middle Jurassic clastics, which contain two proven reservoirs in the Tagtabazar-One gas/condensate and oil field. The field is located in the Murgab Sub-basin of the Amu-Darya Basin in southern Turkmenistan, around 20 km from the border with Afghanistan. It was discovered in 2000 by well Tagtabazar-one (Toreshikh) 1. The field’s two Lower-Middle Jurassic reservoirs occur at depths of 1,728 and 1,858 m. Its initial 2P reserves are estimated at 1.1 Tcf of gas and 9 MMb of oil. The discovery well was completed at a TD 2,580 m in the Triassic shales. Up to 14 more wells (nos. 2 to 15) were drilled between 2000-2004. These wells also attempted to test Triassic intervals, but no hydrocarbon flows had been recorded.

Turkmengeologiya national exploration company has tested gas with condensate in the Tagtabazar-One 16 appraisal (outpost) well. The well has flowed ca. 120 Mcm/day (4.1 MMscf/d) of gas and 13 cu m (82 bbl) of condensate from two intervals of 1,924-1,920 m and 1,951-1,942 m.

Mississippi Canyon block 522 (lease G08823), Fourier field area, ops terminated and Deepwater Thalassa DS released 11 Jan '20, results n/a. Target assumed Norphlet below the main Middle Miocene reservoirs.

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

Lundin reported on 31 July 2018 that it has agreed a swap deal with DNO for a package of assets in the North and Barents seas. Lundin will acquire 15% interests in PL 921 and PL 924 and 10% interests in PL 926 and PL 929 from DNO in return for divesting 10% interests in PL 767, PL 825, PL 902 and PL 950 The deal is subject to government approval. PL 921 covers parts of blocks 32/4 and 32/7 and lies to the southeast of Troll. A commitment well is due to be drilled in this licence (probably in 2019) on the Gladsheim prospect. PL 924 is located northeast of Troll and covers parts of blocks 31/2, 31/3, 32/1 and 35/12. It contains dry hole 31/3-4 drilled by Tullow in 2013 / 2014 on the Mantra prospect. PL 926 covers parts of blocks 33/9, 33/12 and 34/10 between Statfjord and Gullfaks. Two wells (plus a sidetrack) lie within the licence – 33/9-18, 33/9-18 A (Statoil, dry holes, 1994 / 1995) and 34/10-39 S (Statoil, dry hole, 1995). PL 929 lies to the north of Gjoa and covers parts of blocks 35/6 and 36/4. PL 767 covers parts of blocks 7120/3, 7121/1, 7121/2 and 7121/4 and is located north of Snohvit North. A well is planned on the Setter / Pointer prospects in late 2018 / early 2019. PL 825 lies between Oseberg, Huldra and Veslefrikk and contains Norks Hydro’s 1982 / 1983 well 30/6-11 which had residual oil shows in the Middle Jurassic Brent Group, Lower Jurassic Cook Formation and the top part of the Lower Jurassic Statfjord Formation. A well was spudded on the Rungne prospect in October 2018. PL 902 covers parts of blocks 7120/1, 7120/2, 7120/3, 7120/4, 7120/5 and 7120/6 to the south of Alta and Gohta and contains Lundin’s Skalle gas discovery made by 7120/2-3 S in 2011 and the oil discovery made in 1989 by Shell’s 7120/1-2. PL 950 is located south of Snohvit and to the southwest of Alke North and South. It covers parts of blocks 7020/1, 7020/2 and 7120/11.

Norway (East Shetland B. (Viking Graben Province)) Gullfaks

Sapakara West-1 well provides further confirmation of geologic model with 79 meters (259 feet) of net oil and gas condensate pay. The third and fourth exploration well locations in Block 58 have been identified.   Apache Corp and Total have announced a significant oil discovery at the Sapakara West-1 well drilled offshore Suriname on Block 58. The well was drilled using the Noble Sam Croft with Apache as operator holding a 50% working interest and Total holding a 50% working interest. Sapakara West-1 was drilled to a depth of approx. 6,300 meters (20,700 feet), and successfully tested for the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals. Preliminary fluid samples and test results indicate at least 79 meters (259 feet) of net oil and gas condensate pay in two intervals. The shallower Campanian interval contains 13 meters (43 feet) of net gas condensate and 30 meters (98 feet) of net oil pay, with API oil gravities between 35 and 40 degrees. The deeper Santonian interval contains 36 meters (118 feet) of net oil-bearing reservoir with API oil gravities between 40 and 45 degrees. 'Our second discovery offshore Suriname this year further proves our geologic model and confirms a large hydrocarbon system in two play types on Block 58. Based on a conservative estimate of net pay across multiple fan systems, we have discovered another very substantial oil resource with the Sapakara West-1 well,' said John J. Christmann, Apache CEO and President. 'Importantly, our data indicates that the Sapakara West-1 well encountered a distinct fan system that is separate from the Maka Central-1 discovery we announced in January this year.' Block 58 comprises 1.4 million acres and offers significant potential beyond the discoveries at Sapakara West and Maka Central. Apache has identified at least seven distinct play types and more than 50 prospects within the thermally mature play fairway. Upon completion of operations at Sapakara West-1, the Sam Croft will move to the third prospect in Block 58, Kwaskwasi, which is located approx. 10 kms (6 miles) northwest of Sapakara West-1. The fourth exploration target is Keskesi, which will be drilled approx. 20 kms (12 miles) southeast of Sapakara West-1. Both exploration wells will test oil-prone upper Cretaceous targets in the Campanian and Santonian intervals in reservoirs that appear to be independent from the Maka and Sapakara discoveries.Apache announces significant oil discovery offshore Suriname Photo: Noble Sam Croft (Source: Noble Drilling) Click here for Total announcement: Total Announces a Second Discovery in Block 58 Note: Total announced December 23 it had signed an agreement with Apache Corp to acquire a 50 percent working interest and operatorship in the highly prospective Block 58 offshore Suriname, further expanding Total’s footprint in the prolific Guyana-Suriname basin. See: Total enters Suriname with 50 percent operated stake in Block 58 Original article link Source: Apache Corp

Suriname (Guyana B.) Maka Central 1

Jambi PPC (onshore South Sumatra), Sungai Gelam area in Muaro Jambi regency, 3 DSTs run, the 3rd of which yielded has + cond., no details. PTMD was 2,230m, 118-day well spudded 12 Sep ’19, PDSI rig 41.3.

Tulip Jingga 1 (TJA-1), (Pertamina EP 100%) in the Jambi PPC, operator has conducted 3 drill stem test (DST) in wildcat The first and second DST recorded oil shows while the third DST reportedly had gas and condensate flow. The company is currently carrying out test evaluations to determine the reservoir potential.

On 24 October 2019, Italian Eni SpA, part of the Petrobel Belayim Petroleum Co (Petrobel) company with Egyptian General Petroleum Co (EGPC), announced that a new appraisal well, Sidri 36, was completed positive in the Abu Rudeis B10 lease, onshore/offshore Gulf of Suez Basin. Sidri 36 assessed the Abu-Rudeis Sidri field continuity westward in a down dip position compared to the Sidri 23 new-pool wildcat drilled in Q2 2019 (separate article). Sidri 26 reportedly encountered a 200-m hydrocarbon column in the clastic sequence of the Cretaceous Nubia Formation. The well is expected to be brought onstream shortly, at a rate of 5,000 bo/d. Background Information Abu Rudeis Sidri was discovered in July 1957 by the well Rudeis 2 which encountered oil, gas and condensate in the Nukhul Formation. In 1957 the field was put onstream and has been producing until 2015 when a redevelopment plan was conducted by the operator.

Sidri 36 appr. (Petrobel=Eni/EGPC 100%) in Sidri B 11 block encountered an important 200m hc column in the clastic sequences of the Nubia Fm, the well will be completed and put into production in the next few days with an expected initial flow rate of about 5000bo/d. The Sidri South discovery is estimated to contain about 200 MMbo in place

Ref. DEA 18 Sep ’18, more details are filtering out on Argentina’s planned offshore bid round, set for launch in October, bid opening Feb ’19. - interested companies must register in a list for group classification: A = eligible for all blocks, B = deep & shallow water blocks, C = shallow-water blocks. Companies in The Energy Intelligence’s top 100 list are believed to be automatically qualifiable.  Operators must hold min. 30%, non-operators min. 5%. Registrations close in January. - explo period 13 years (4+4+5), 50% relinquishment after 2nd explo phase, 30 years prod with multi 10-yr extns. Shallow water blocks explo phase 11 years (4+4+3). Royalties 5-12% depending on performance. It is recalled 38 blocks totalling 225,000 sq km will be on offer in shallow-to-ultra-deepwaters: 14 in the N. part of the Argentina Basin (6,000-9,000 sq km apiece), 18 over 90,000 sq km (3,600-6,300 sq km apiece) in the W. part of the Malvinas Basin, 7 ultra-deepwater (3,000-9,000 sq km apiece) and 6 shallow-water in the Austral Basin (2,000-2,700 sq km apiece). 12 companies have shown interest so far, of which Anadarko, CNOOC, Equinor + Petronas. Contact: Rodrigo Garcia Berro at RGarciaBerro@minem.gob.ar or +54-911-6648-9244.

More details are filtering out on Argentina’s planned offshore bid round, set for launch in October, bid opening Feb ’19. - interested companies must register in a list for group classification: A = eligible for all blocks, B = deep & shallow water blocks, C = shallow-water blocks. Companies in The Energy Intelligence’s top 100 list are believed to be automatically qualifiable. Operators must hold min. 30%, non-operators min. 5%. Registrations close in January. - explo period 13 years (4+4+5), 50% relinquishment after 2nd explo phase, 30 years prod with multi 10-yr extns. Shallow water blocks explo phase 11 years (4+4+3). Royalties 5-12% depending on performance. It is recalled 38 blocks totalling 225,000 sq km will be on offer in shallow-to-ultra-deepwaters: 14 in the N. part of the Argentina Basin (6,000-9,000 sq km apiece), 18 over 90,000 sq km (3,600-6,300 sq km apiece) in the W. part of the Malvinas Basin, 7 ultra-deepwater (3,000-9,000 sq km apiece) and 6 shallow-water in the Austral Basin (2,000-2,700 sq km apiece). 12 companies have shown interest so far, of which Anadarko, CNOOC, Equinor + Petronas.

Osaka Gas has agreed to acquire the issued share capital of shale gas developer Sabine O&G Corp, the 1st such deal by a Japanese company. Osaka Gas intends to continue focusing on its US business which comprises the Freeport LNG liquefaction project, IPP projects and Sabine’s shale gas project.

United States, not found

China has reportedly auctioned 3 o+g blocks in the Tarim Basin, NW Xinjiang for some USD 422 MM to Shenergy Co., Xinjiang Energy Co. and Zhongman Petroleum and Gas Group. Seven companies participated in the auction. The 3 blocks were part of 5 earmarked for sale, total 9,091 sq km.

Shenergy Co, Xinjiang Energy (Group) Co and ZPEC (Zhongman Petr.&Natural Gas) secured the rights for 3 oil and gas exploration blocks in the remote northwest Xinjiang region, for more than US$422 MM, after a bidding competition that attracted 7 companies.

On 27 September 2018 GSNZ SPV1 Ltd completed the acquisition of interest and operatorship of the Ahuroa asset, located in the Eastern Taranaki Mobile Belt, from Contact Energy Ltd.  GSNZ has purchased the Ahuroa production permit, PMP 52278, as well as the Ahuroa Gas Storage Facility. Contact Energy reported that it had reached the agreement to sell the asset in December 2017.  It was reported that the sale of the Gas Storage Facility was for NZD 200 million.  The deal was subject to relevant authority approvals, but was completed as planned, being expected to be finalized before end 2018.  It was reported that Contact Energy has retained the right to use the facility for future needs. The Ahuroa production permit contains the Ahuroa UGS field, which was discovered in 1987.  It is a gas and condensate producing field, that also has an underground gas storage element to its development, which commenced activity in 2011. PMP 52278, which covers an area of 11 sq km, was awarded on 16 December 2010.  It is scheduled to expire in December 2050.  GSNZ SPV1 Ltd now holds 100% interest and operatorship of the permit.

GSNZ SPV1 completed the acquisition of interest and operatorship of the Ahuroa asset (Ahuroa production permit, PMP 52278) from Contact Energy.

On 10 September 2018 Cyclone Energy Pty Ltd completed the transfer of its remaining 33.72% interest in the Jingemia oil field to RCMA Australia Pty Ltd. The field is located in L 14, Perth Basin, in which RCMA now holds 93.72% operated interest with partner Norwest Energy NL (6.23%). Cyclone Energy has now completed its exit from the field and no longer holds interest in any licence or field. Cyclone Energy and RCMA Australia both acquired interest in the permit in 2017, after acquiring it from previous participants Origin Energy Developments Pty Ltd, AWE Ltd, Roc Oil Ltd and John Geary. Cyclone moved to operator on 20 July 2017. The new joint venture had planned a workover programme to bring new life into the oil field. Jingemia was brought back online in December 2017 after being placed into care and maintenance in 2012. RCMA took over operatorship on 11 May 2018 from Cyclone and has now completed its acquisition of interest also. L14, which covers an area of 45 sq km, was awarded on 21 June 2004.  Now that the change of operator and interest is complete, participants in the permit are: RCMA Australia Pty Ltd (93.72% + operator) and Norwest Energy NL (6.28%).

Australia (Dongara Terrace (Perth B.)) Jingemia

On 19 December 2019, the CNH formally approved of the Capricorn working interest swap with ENI with ENI entering the CNH-R02-L01-A9.CS/2017 contract operated by Cairn subsidiary Capricorn, and Cairn acquiring a 15% working interest in the ENI operated CNH-R02-L01-A10.CS/2017 contract. Capricorn Energy is operator of the CNH-R02-L01-A9.CS/2017 contract and held 65% working interest and Citla Energy held 35% working interest. Capricorn now holds 50% working interest, Citla has 35% working interest, and ENI holds 15% working interest. In the ENI operated CNH-R02-L01-A10.CS/2017 contract, ENI held 80% working interest and Lukoil had a 20% working interest. ENI now holds a 65% working interest, Lukoil 20% working interest, and Capricorn holds 15%. On 10 September 2019, Cairn reported with its 1st half 2019 results that it has swapped 15% working interest with ENI with ENI entering the CNH-R02-L01-A9.CS/2017 contract operated by Cairn subsidiary Capricorn, and Cairn acquiring a 15% working interest in the ENI operated CNH-R02-L01-A10.CS/2017 contract. Capricorn is currently drilling the Bitol 1EXP in the CNH-R02-L01-A9.CS/2017 while ENI is drilling the Saasken 1EXP in the CNH-R02-L01-A10.CS/2017 block. On 16 May 2019, the CNH approved a modified exploration plan for the Capricorn operated CNH-R02-L01-A9.CS/2017 PSC contract, Area 9 block involving only changes to the drilling schedule of prospects and a change in the proposed budget. From its November 2018 approved exploration plan Capricorn had planned to drill the Bitol-Kukulkan prospect first and the Alom prospect second. This has been changed to drilling the Alom prospect first and the Bitol-Kukulkan prospect second. The second modification in the exploration plan is an increase in the well drilling budget. The total budget approved for the exploration plan is USD 125.85 million. The estimated drilling expenditures for the two commitment wells increased from USD 105.21 million to USD 113.20 million. The Alom prospect is to be drilled first and has an estimated proposed total depth of 3,000 m in a water depth of 140 m. It is targeting stacked, DHI supported Pliocene sandstones starting at 1,550 m. The prospective resources now reported for the Alom prospect is 103 MMboe. The overlapping Bitol and Kukulkan prospects have been merged into one prospect, Bitol-Kukulkan, as reported by the CNH. The NFW will be drilled directionally to an estimated proposed total depth of 5,300 m in a water depth of 180 m.It is targeting stacked Pleistocene, Pliocene, and Upper and Lower Miocene sandstones from 765 m to 3,980 m. The prospective resources now reported for the Bitol-Kukulkan prospect is 261 MMboe. Parent company Cairn contracted the “Maersk Developer” S/S to drill its commitment wells commencing in 3rd quarter 2019. On 7 May 2019, the CNH approved the drilling permit request submitted by ENI for the CNH-R02-L01-A10.CS/2017 PSC contract, Area 10 block and the Saasken 1EXP directional new-field wildcat (NFW). The Saasken 1EXP is located in the south-western corner of the block and the primary targets are the Lower Pliocene and Lower Miocene with secondary targets in the deeper Oligocene and Eocene. The proposed total depth (PTD) for the NFW is 4,563 m measured depth. The “Ensco 8505” J/U will drill the well in a water depth of 354 m. The well was scheduled to spud in mid-June 2019. The Saasken 1EXP drilling cost is estimated at USD 51.77 million and abandonment costs are estimated to be USD 4.13 million. The prospect trap is reported to be an anticlinal structure related to a salt intrusion with related normal faulting. The operator has the option of drilling to its deeper Oligocene and Eocene targets pending results obtained drilling its primary Pliocene and Miocene targets. On 14 March 2019, the CNH approved of the working interest exchange between ENI and Lukoil in the CNH-R02-L01-A10.CS/2017 contract and CNH-R02-L01-A12.CS/2017 contract. In the CNH-R02-L01-A10.CS/2017 PSC contract, Area 10 block, ENI previously held a 100% working interest. The new working interest breakdown is ENI operator with 80% working interest and Lukoil with 20% working interest. On 25 September 2018, the CNH approved the exploration plan presented by ENI for the CNH-R02-L01-A10.CS/2017 PSC contract, Area 10 block from the CNH-R02-L01/2016 Bid Round.

Mexico (Reforma-Akal Fold Belt (Sureste B.)) May

On 4 January 2018 Total completed the drilling operations in the Rubin 1 exploration well in the 1-21 Han Asparuh permit. According to industry sources, logging operations were conducted probably in the Upper Miocene as well as in the Lower Oligocene where oil and gas shows occurred. The well bottomed in thick carbonates at a total depth of 7,030 m below sea level (5,500 m below sea floor). On 23 September 2017 the ‘Noble Globetrotter II’ drillship spudded Rubin 1 in a water depth of 1,530 m about 14 km northeast of the Polshkov 1 exploration well. It had a planned total depth of 5,500 m (below sea floor) with several targets but its main objective was the Polshkov High structure. In May 2016 Total spudded exploration well Polshkov 1 in the permit. The well was targeting Lower Oligocene sandstones, Middle Eocene sandstones and Upper Jurassic to Lower Cretaceous carbonates. In August 2016 the well reached a total of 5,615 m (below sea floor) and in September 2016 it was plugged and abandoned as a discovery. Partner Repsol reported the well encountered oil and gas in an Oligocene play. The permit is adjacent from the south to OMV Petrom’s and ExxonMobil’s XIX Neptun East permit in the Romanian waters where a significant deepwater gas discovery was made in 2012 with Domino 1. The area is little explored with water depth ranging from 150 m to 2,000 m. In October 2013 OMV, operator at that time, with partners concluded a 3,000 km 2D seismic survey and in January 2014 the group completed a 7,740 sq km 3D on the permit.   Interest in the 14,220 sq km 1-21 Han Asparuh permit is held by Total E & P Bulgaria BV (40% + operator), OMV offshore Bulgaria GmbH (30%, operator until May 2014) and Repsol SA (30%). The required work program includes 10,000 km of 2D seismic, 5,000 sq km of 3D seismic and two deep wells.

Total completed the drilling operations in the Rubin 1 exploration well in the 1-21 Han Asparuh permit. According to industry sources, logging operations were conducted probably in the Upper Miocene as well as in the Lower Oligocene where oil and gas shows occurred. The well bottomed in thick carbonates at a total depth of 7,030 m below sea level (5,500 m below sea floor).

Sitra (Dev) block, Abu Gharadiq Basin, TD 3,019m (Bahariya), in Sep '19 tested 1,964 bo/d + 27 MMcfg/d presumably from the Bahariya, EDC-72.

Sitra C03-4 appr Sitra (Dev) block, Abu Gharadiq Basin, TD 3,019m (Bahariya), in Sep '19 tested 1,964 bo/d + 27 MMcfg/d presumably from the Bahariya,

According to reports in June 2018, Sierra Oil & Gas has tapped Scotia Waterous to handle its farm-out in the Talos Energy-operated Area 2 (CNH-R01-L01-A2/2015). Sources in late May 2018 confirmed that WI is available in the tract, with Sierra offering part of its 45% WI. Talos, which operates the block, is not expected to offer any of its WI. The entrance of a new partner into the block would come at a time when plans are in the works to drill in the contract area. Possible objectives could include the Pliocene sequence at a depth of 2,780m. The blocks is located in the prolific Sureste Basin, and contains Tertiary clastic plays, typical of the Salinas sub-basin. In the joint venture, Talos operates with 45% WI, Sierra holds 45% WI and Premier holds 10% WI. Premier has an option to increase to 25% from 10% WI. Talos and partners won the block at Round 1. Mexico offered 14 shallow water exploration tracts in the first phase of the round. Pemex drilled the Luhua 1 in the area in 2002.

According to reports in June 2018, Sierra Oil & Gas has tapped Scotia Waterous to handle its farm-out in the Talos Energy-operated Area 2 (CNH-R01-L01-A2/2015).

On 5 November 2019, the Bureau of Land Management (BLM) announced that it will hold an oil and gas lease sale bid opening for 350 tracts covering about 3.98 million ac (16,106 sq km) in the National Petroleum Reserve in Alaska (NPR-A). The sale will be held on 11 December 2019 at 10:00 a.m. AKST and will be livestreamed at blm.gov/live. Bids must be received by 4:00 p.m. AKST on 9 December 2019 at BLM Alaska State Office, ATTN: Carol Taylor (AK932), 222 West 7th Avenue #13, Anchorage, AK 99513-7504. Last year's lease sale held on 12 December 2018 included 254 tracts covering about 2.85 million ac (11,545 sq km). Bids were received on 16 tracts covering 174,044 ac (69 sq km). ConocoPhillips, Emerald House and Nordaq submitted the bids totaling over USD 1.53 million. ConocoPhillips has been the most active company in leasing over the last few years as it sought to expand its holdings following the recent Nanushuk trend oil discoveries made in the region. According to BLM Alaska State Director Chad Padgett, "We are working on a new Integrated Activity Plan for the NPR-A. With advancements in drilling technology, it was prudent to develop a new plan that provides for greater economic development of our resources while still providing protections for important resources, such as subsistence uses.” A map of the tracts being offered in 2019 is available at https://www.blm.gov/sites/blm.gov/files/uploads/Oil_Gas_Alaska_2019_NPR-A_lease_sale_Tracts_Offered_Map.pdf.

On 5 November 2019, the Bureau of Land Management (BLM) announced that it will hold an oil and gas lease sale bid opening for 350 tracts covering about 3.98 million ac (16,106 sq km) in the National Petroleum Reserve in Alaska (NPR-A).

In early May 2018, the Federal Agency for Subsoil use added three blocks in Yakutia (Sakha) Republic (Eastern Siberia) to a list of assets to be auctioned in 2018. It is understood that the Andylakhskiy, Borulakhskiy and Nizhnetyukyanskiy blocks will be auctioned in the third quarter of 2018. The Andylakhskiy block covers 376 sq km in the Lena-Vilyuy basin and encompasses the Andylakhskoye discovery with 2P reserves estimated at 267 Bcf of gas and 5 MMbbl of condensate. Gas resources of the block are estimated at 103 Bcf. The NIzhnetyukyanskiy block covers 233 sq km in the Lena-Vilyuy Basin and includes the Nizhnetyukyanskoye discovery with 3P reserves estimated at 138 Bcf of gas. Gas resources of the block are estimated at 103 Bcf. The Borulakhskiy block covers 5,379 sq km in the northwestern part of the Predpatom Basin. Its hydrocarbon resources are estimated at 74 MMbbl of oil and 5,651 Bcf of gas.

Russia (Vilyuy Sub-basin (Lena-Vilyuy B.)) Nizhnetyukyanskoye

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

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

CNOOC made a new oil discovery with the drilling of the Weizhou 11-1M-2d wildcat well in Q3 2019, using the "Haiyangshiyou 931" jack-up. The discovery was successfully appraised with two follow-up appraisal wells Weizhou 11-1M-1d and Weizhou 11-1M-3d. Weizhou 11-1M-2d was likely to be targeting the Weizhou and Liushagang formations. Weizhou 11-1M-2d is in the CNOOC operated Yulin 35 Block in the offshore Beibuwan Basin.

Not Found

On 31 July 2020 Equinor agreed to sell 40.8125% of its interest and transfer operatorship of licences P234 (block 3/28a), P493 (block 3/28b), P920 (3/27b) and P977 (blocks 9/2a and 9/3a) to EnQuest. A sale and purchase agreement has been signed between the two companies for the licences that host the Bressay heavy oil field. The sale is for an initial consideration of GBP 2.2 million (as a carry against 50% of Equinor's net share of costs) and a further consideration of GBP 11.48 (USD 15 million) will be payable when the Bressay field development plan is approved. The deal is estimated to complete in Q4 2020. Located northeast of Kraken field, the Bressay field was discovered in 1976 with heavy oil and a small gas cap in the Upper Paleocene Teal Sands. The heavy oil has an average API of 12° and a viscosity of 550 cP. An environmental statement was submitted for the field in June 2013 which described the development via 70 development wells, with operations commencing in 2016, first oil in 2018 and peak production was anticipated to take place between 2022 and 2025. However, by November 2013 the development was stated to be delayed and in August 2016 the concept selection was deferred because of market conditions and the need to simplify the development concept. A number of development scenarios are still under consideration, one involves a tie back to Kraken field. Interest in the licences P234, P493, P920 and P977 is held by EnQuest Heather Ltd (40.8125% + operator), Equinor (UK) Ltd (40.8125%) and Chrysaor Ltd (18.375%).

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

Local industry sources indicate that Nafta a.s. was granted a new exploration contract in the southeastern part of the country on 4 October 2018. The tract, named Besa, holds11 years validity term. Nafta is the sole operator of the tract. The Besa contract, located in the Kosicky political province of eastern Slovakia, some 30 km southeast of the city of Kosice, is covering approximately 260 sq km. In a geological sense, the tract is situated within the East Slovak Sub-basin (Pannonian Basin). The application for the area was lodged likely in late August/early September 2018. Background Information Nafta is the only active operator in eastern Slovakia, holding the Vychodoslovenska nizina permit (awarded on 21 July 2003, valid until 4 November 2019), as well as some dozen production concessions. The Besa block is covering almost the same area as the previously-existing block Besa nad Latoricou (27 February 2003-22 February 2012) Although the exploration in the area has a long history, the East Slovak Sub-basin is still believed to hold untapped hydrocarbon potential. In 2009, Nafta conducted the acquisition of a 3D vibroseismic survey designated Trhovište in the nearly Vychodoslovenska nizina block (roughly 135 sq km on new data was acquired). In late 2015, Nafta drilled outpost Senné 46 - planned total depth of 1,851 m - that tested commercial quantities of gas (rates undisclosed) from the reservoirs in the Upper Sarmatian-Upper Badenian (Miocene) strata.

Nafta a.s. was granted a new exploration contract in the southeastern part of the country on 4 October 2018. The tract, named Besa, holds11 years validity term. Nafta is the sole operator of the tract. The Besa contract, located in the Kosicky political province of eastern Slovakia,

On 8 December 2017, the consortium of Shandong Kerui Oilfield Service Group Co, Ltd, Sicoval MX, S.A. de C. V., and Nuevas Soluciones Energeticas A&P, S. A. de C. V. signed the contracts with the CNH and was granted official final awards for the CNH-RO2-L03-CS-02/2017 and CNH-RO2-L03-CS-03/2017 contracts from the CNH-RO2-LO3/2016 Bid Round.  The CNH-RO2-L03-CS-02/2017 contract is also known as the Area 10, CS-02 block.  The CNH-RO2-L03-CS-03/2017 contract is also known as the Area 1, CS-03 block.  The consortium formed a separate subsidiary, Shandong and Keruy Petroleum, S.A. de C.V. with 100% working interest as the official designated operating company for the blocks.  The 248 sq km CNH-RO2-L03-CS-02/2017 contract has a total financial commitment of USD 15.2 million, all in work commitments including two additional wells.  The 215.10 sq km CNH-RO2-L03-CS-03/2017 contract has a total financial commitment of USD 15.5 million, all for work commitments including two additional wells. On 12 July 2017 the consortium of Shandong, Sicoval, and Nuevas Soluciones was the high bidder in the CNH-RO2-LO3/2016 Bid Round for the Area 10 and Area 11 blocks in the Sureste Basin and was granted preliminary awards.   For the 248.00 sq km Area 10 block there were two other bids.  The Shandong consortium offered the maximum additional royalties of 40% and 1.5 work unit factor equivalent to two additional wells.  The second highest bid was by DEP PYG who offered 22.51% royalties and 0.0 work units factor.    For the 215.10 sq km Area 11 block there were five other bids for the block.  The Shandong consortium offered the maximum additional royalties of 40% and 1.5 work unit factor equivalent to two additional wells.  The second highest bid was by Tonalli Energia who offered 33.30% royalties and 0.0 work units factor.      It is estimated that the winning Shandong consortium is split 34%-33%-33% but the final official equity breakdown will only be reported at a later date. The general license contract terms include a 1st exploration period of two years with the possibility of a two-year extension.  In the case of a discovery the operator can request a two-year evaluation phase for oil and a three-year evaluation phase for non-associated gas discoveries once the evaluation plan is approved.  The total contract term is for 30 years with the possibility of two five year extensions for a 40-year total contract term from signature date. The base royalty rate is a sliding scale royalty depending on type of hydrocarbon and oil price.  The values for oil range from 5% for USD 40/bbl oil to 25% for USD 200/bbl oil.  The relinquishment schedule is tied to exploration well commitments.  If the exploration period ends but the operator offers to drill an additional well it doesn’t have to relinquish any area.  If the exploration period ends and the contractor doesn’t have any discoveries it must relinquish 100%.  If the exploration period ends and the operator doesn’t offer to drill an additional exploration well it will have to relinquish 50% of the area.  Local content during the exploration period is 26% for the exploration and evaluation period, and varies from 27% to 38% in the development period.

Mexico (Campeche Deep Sea B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: 11 op. by REPSOL (60.0%, SIERRA PER 40.0%) to be check.10 op. by ENI SPA (100.0%) to be check.12 op. by LUKOIL (100.0%) to be check.15 op. by TOTAL (60.0%, SHELL 40.0%) to be check.Area 1 (Tecoalli A) op. by ENI SPA (100.0%) to be check.2 op. by PEMEX (50.0%, RWE 50.0%) to be check.Area 1 (Tecoalli B) op. by ENI SPA (100.0%) to be check.Area 1 (Mizton) op. by ENI SPA (100.0%) to be check.8 op. by PEMEX (50.0%, ECOPETROL 50.0%) to be check.Area 1 (Amoca) op. by ENI SPA (100.0%) to be check.

IPC (ex-Lundin) handed its 35% interest in PM-328, Malay Basin, presumably back to Petronas who had ceded IPC its stake in the first place in 2014. Petronas becomes optr again along with partners Dyas + E&P Malaysia Venture. PM-328 covers 5,600 sq km in WD 45-60m and remains undrilled. It surrounds the Puteri + Abu South West blocks and their fields.

IPC (ex-Lundin) handed its 35% interest in PM-328, Malay Basin, presumably back to Petronas who had ceded IPC its stake in the first place in 2014. Petronas becomes optr again along with partners Dyas + E&P Malaysia Venture. PM-328 covers 5,600 sq km in WD 45-60m and remains undrilled. It surrounds the Puteri + Abu South West blocks and their fields.

Songtao Sag in Qiongdongnan Basin, WD 220m, drilled + compl. 26 May – mid-Aug ’18, HYSY 981 SS. Target Miocene-Oligocene clastics.

Songtao Sag in Qiongdongnan Basin, WD 220m, drilled + compl. 26 May – mid-Aug ’18, HYSY 981 SS. Target Miocene-Oligocene clastics.

Sinopec – Xibei achieved oil and gas flow in an appraisal well in Shunbei field in the Tarim Basin. Shunbei 53X, drilled in Shunbei 5 discovery area, tested 780 b/d of oil and 2.6 MMcf/d of gas. The success of the well makes field extension southwards. In 2017 Sinopec tested oil and gas in Shunbei 5. This exploration well is located in the west of Shunbei 1 discovery, and was spudded in 2016 with a PTD of 7,546 m. Sinopec has a target to build 10,000 b/d of oil production capacity in Shunbei 5 area. In 2018 Sinopec achieved oil and gas flow in an appraisal well drilled in Shunbei 5 discovery area, Shunbei 501 tested 2,087 b/d of oil and 1.52 MMcf/d of gas. The success of the well makes field extension southwards. The well has a TD of 8,160 m. Background Information In 2015 Sinopec made discovery of Shunbei in the Shutuoguole North block when Shunbei 1 tested 45.4 Mscfg/d from an interval between 7,269 and 7,407 m in the Ordovician. Following Sinopec made success in Shunbei 1-1H. The well tested 887 b/d of oil and 911 Mcf/d of gas through a 4 mm choke in the Ordovician. Sinopec reported in 2016 that Shunbei field, a large commercial field, has been confirmed. Sinopec started development of Shunbei 1 in early 2016 and planned to build Shunbei block with production capacity of 30,000 b/d of oil by 2020. During 2016 Sinopec has put seven producers on stream, with production capacity of 3,700 b/d of oil. In November 2017, Sinopec set a revised field development plan on Shunbei 1 area of the Shunbei field to build up a 20,000 b/d of oil and 26 MMcf/d of gas production capacity by 2020. In 2017 Sinopec produced at a rate of 6,000 b/d of oil. By end 2017 Shunbei field has been approved nearly 100 MMbbl of oil and 260 Bcf of gas in place reserves. In 2018, with Shunbei 5 discovery developed, Sinopec produced 520K tons of oil from the field.  The company has target to reach annual production of 1 million tons of oil in 2019 and plan to reach 2 million tons of oil (40,000 b/d) by 2023.

Tests: Shunbei 53X appr Deep well in southwards extn of Shunbei 5 discovery area, Tarim Basin, tested 780 bo/d + 2.6 MMcfg/d

Tlou was granted the ca. 1,000-sq km Boomslang block, a new CBM prospecting licence on-trend with the Lesedi CBM project, for an initial 3-year term.

Tlou was granted the ca. 1,000-sq km Boomslang block, a new CBM prospecting licence on-trend with the Lesedi CBM project, for an initial 3-year term.

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

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

Further to DEA 22 Oct ’18, the OGA intends to launch a mini-round in 1Q ’19 for acreage around the Greater Buchan Area for which the OGA is keen to see developed some 150 – 300 MMboe. Supporting information is available from the OGA on the area, which lies in the Outer Moray Firth and features currently unlicensed acreage, including a number of undeveloped discoveries (outlined in blue below).

OGA intends to launch a mini-round in 1Q ’19 for acreage around the Greater Buchan Area for which the OGA is keen to see developed some 150 – 300 MMboe. Supporting information is available from the OGA on the area, which lies in the Outer Moray Firth and features currently unlicensed acreage, including a number of undeveloped discoveries

License partnership of Block 29 makes two significant oil discoveries in the Polok and Chinwol prospects Polok discovery opens a new play within Mexico’s Salina Basin Wintershall Dea and its license partners have made significant oil discoveries on the Polok and the Chinwol prospects in Block 29 offshore Mexico. Polok is a play opening discovery within the Early Miocene reservoir of the Salina Basin (part of the Sureste Basin), whereas Chinwol encountered oil in formations of the Pliocene. Hugo Dijkgraaf, Wintershall Dea Chief Technology Officer and Executive Board member responsible for global exploration, said: 'These are breakthrough discoveries, confirming the materiality and quality of Wintershall Dea’s exploration license portfolio in the Sureste Basin. They emphasize Mexico’s importance as one of Wintershall Dea’s key target regions for growth globally.' Polok and Chinwol are the first announced discoveries from a block, awarded in Mexico’s deep water round 2.4. in 2018. Juan Manuel Delgado, Managing Director for Wintershall Dea’s Mexican business, pointed out: 'This is a great success. We have had a strong belief that discoveries like these could be made here. The Polok and Chinwol discoveries are a strong evidence of the oil potential of the Salina Basin. Opening a new play there, we are confident to further unlocking additional resources in Block 29 and the wider Wintershall Dea license portfolio. We are well positioned and looking forward contributing to the development of Mexico’s oil and gas sector.' The Polok-1 exploration well was drilled to a total depth of 2,620 meters and encountered more than 200 meters of net oil pay from two zones in the lower Miocene. The Chinwol-1 exploration well was drilled to a total depth of 1,850 meters and encountered 150 meters of net oil pay from three zones in the lower Pliocene. The discoveries in Mexico’s Block 29 are 88 kms from the Mexican coastline of Tabasco and approx. 50 kms west-northwest of the world class Zama discovery, where Wintershall Dea holds a significant stake of 40%. The wells were drilled in water depths of 500 to 600 meters. The discoveries are just 12 kms apart from each other. The reservoirs show excellent petrophysical properties. An intensive data collection has been carried out in both wells, including a total of 108 meters of core. The license partnership will work on potential appraisal measures and development options for the Polok and Chinwol discoveries, taking into account current market conditions. The Block 29 partners are Wintershall Dea (25%), Repsol (operator, 30%), PC Carigali Mexico Operations S.A de C.V., the Mexican subsidiary of PETRONAS (28.33%) and PTTEP Mexico E&P Limited, S. de R.L. de C.V. (16.67%).Location of Block 29 (Source: Wintershall Dea) Wintershall Dea in Mexico In Mexico, Wintershall Dea operates the producing onshore Ogarrio oil field, in partnership with Pemex. Furthermore, Wintershall Dea and its partners in Block 7 are currently assessing development options for the already appraised Zama discovery. Wintershall Dea holds shares in ten exploration blocks in the Sureste and Tampico Misantla Basins, of which three as operator. About Block 29 Location: Salina Basin (part of the Sureste Basin), offshore Mexico Discoveries: Polok and Chinwol Distance to shore: 88 kms Distance to Zama discovery: 50 kms Water depth: 500 - 600 meters below sea level Partnership: Wintershall Dea (25%), Repsol (operator, 30%), PC Carigali Mexico Operations S.A de C.V., the Mexican subsidiary of PETRONAS (28.33%) and PTTEP Mexico E&P Limited, S. de R.L. de C.V. (16.67%) Original article link Source: Wintershall DEA

Chinwol 1, Polok 1 nfw's, (Repsol 30% op. Petronas 28,33%, Sierra Nevada 25%, PTT E&P 16,67% ), SE part of CNH-R02-L04-AP-CS-G10/2018 contract, Area 29, AP-CS-G10 block, off Tabasco, 2 oil disc. 12km apart, the 1st made from DW Round 2.4 acreage: - Chinwol 1 over 150m net oil pay from 3 zones in the L. Pliocene WD=462m, TD=1850m

Melbana is planning to make an all-share offer to take over 100% of Metgasco, offering 4 of its shares for every 1 of Metgasco’s (a 48% premium on its closing price last Friday). Metgasco has stakes in acreage in Australia and in the shallow water GoM, where it recently participated in the South Marsh Island 74 D-14 expl well, a duster for operator Byron Energy.

Melbana is planning to make an all-share offer to take over 100% of Metgasco, offering 4 of its shares for every 1 of Metgasco’s (a 48% premium on its closing price last Friday). Metgasco has stakes in acreage in Australia and in the shallow water GoM, where it recently participated in the South Marsh Island 74 D-14 expl well, a duster for operator Byron Energy.

Sinopec – Xibei tested gas in Xinghuo 6, which flowed 1.7 MMcf/d of gas in the Lower Tertiary Kumugeliemu Formation, in the Tarim Basin. This NFW is located in Shaya High of the Tabei Uplift, the success of the well indicated prospective exploration potential in this area. Several wells have bene drilled in this area, such as Xinghuo 1, Xinghuo 2 and Xinghuo 4, but without discovery. Xinghuo 6 is the first well which achieved commercial gas flow. PetroChina has found an oil/gas field, Yaha field, near this area. Background information The Yaha Field, located on the Tabei uplift in the Tarim basin, was discovered in 1993 when Ya 3 tested 780 bo/d and 5.6 MMscfg/d from Tertiary. The field came on production in 2000. The Yaha Field was reported to hold 260 MMbbls of proven in-place condensate and 1,386 Bcf of proven in-place gas. The main reservoirs of the Yaha Field is Lower Tertiary Kumugeliemu sands. The Ordovician-Cambrian carbonates is the secondary reservoir.

(Tarim B.) Xinghuo 6 nfw, operated by Sinopec – Xibei (100%) in Tianshan Southern Margin block, tested gas which flowed 1.7 MMcf/d of gas in the Lower Tertiary Kumugeliemu Formation. This nfw is located in Shaya High of the Tabei Uplift, the success of the well indicated prospective exploration potential in this area.

Repsol and Ecopetrol were awarded Garden Banks blocks GB 77 (G36147), GB 78 (G36148), GB 121 (G36149) and GB 122 (G36149), situated in the East Texas Coastal Basin, on 1 December 2017. The leases are expected to expire on 30 November 2022. The leases were originally offered as part of Central Gulf of Mexico Lease Sale 249, which was held in New Orleans in August 2017 and drew bids on just 90 offshore tracts, totalling about a half-million acres, less than 1% of the 307,561 sq km available. Lease Sale 249 garnered US$ 121,143,055 in high bids for 90 tracts covering 2,056 sq km (508,096 acres) in the Gulf of Mexico, it was announced on 16 August 2017 by the BOEM. The blocks are located 20km northwest from the Conger Field on GB 215, close to the Baldpate (GB 260) and Enchilada (GB 128) fields. Conger is a sub-salt, high-pressure, high-yield gas/condensate field and was originally developed via three subsea producers, with first oil being achieved in 2000. Following award, equity in GB 77, GB 78, GB 121 and GB 122 is split between Repsol E&P USA (50% WI + Op) and Ecopetrol America (50%).

Not Found

Alliance is on the lookout for a partner willing to share the drilling of a well in ADL 392104 (Guitar Unit) on the North Slope, targets Ivishak fm (vert.) + Kuparuk C (deviated). The Guitar Unit includes leases ADL 392104, 391544 + 391545.

Alliance is on the lookout for a partner willing to share the drilling of a well in ADL 392104 (Guitar Unit) on the North Slope, targets Ivishak fm (vert.) + Kuparuk C (deviated).

Ref. DEA 23 Sep '19: P2085, SNS, commitment well to 2-year extn of licence term (to 20 Dec ’19), TMD 2,297m (Leman sst), 25m gas column at the top of the reservoir, but now seen to be a gas pocket of limited extent and therefore possibly sub-commercial. However a larger structure is interpreted up-dip NE of the earlier 48/23-2 well, suggesting some 40 Bcfe recoverable. Results are being integrated into the seismic model covering the area of the Redwell discovery (ex-Wherry) in adjacent P2441 east of Harvey for further evaluation. Release here.

48/24b-6 (Harvey) appr P2085, SNS, commitment well to 2-year extn of licence term (to 20 Dec ’19), TMD 2,297m (Leman sst), 25m gas column at the top of the reservoir, but now seen to be a gas pocket of limited extent and therefore possibly sub-commercial.

Commitment shallow gas well, West Thrace acreage (Banarli licence), 4th well in programme, drilled 1Q '20, ireline logs indicate gas zones, to be confirmed with production testing, expected once safe field operations can resume.

Kuzey Atakoy-4 expl Commitment shallow gas well, West Thrace acreage (Banarli licence), 4th well in programme, drilled 1Q '20, ireline logs indicate gas zones, to be confirmed with production testing, expected once safe field operations can resume.

Sénégal has postponed its planned 2020 round, the application deadline slipped from 31 Jul '20 to 30 Sep '20. 12 offshore blocks are on offer, including deep + ultra-deepwater units in the MSGBC Basin:

Senegal, not found

On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the F20-D4 onshore exploration licence in the Thrace Basin on 28 May 2019. The company had submitted the application on 26 July 2018. The licence covers 57 sq km area in the Istanbul and Tekirdag provinces and it has been granted for eight-year term with an expiry date of 25 May 2027. TPAO is 100% owner and operator of the licence.

TPAO has been awarded the F20-D4 onshore exploration licence in the Thrace Basin on 28 May 2019. The company had submitted the application on 26 July 2018. The licence covers 57 sq km area in the Istanbul and Tekirdag provinces and it has been granted for eight-year term with an expiry date of 25 May 2027. TPAO is 100% owner and operator of the licence.

Nandigama N.-1: West Godavari ML, KG onshore, TD ca. 3,000m, in 2019 tested 154 bo/d + 880 Mcfg/d from the Nandigama fm. Penugonda-5 npw: Kavitam ML, KG onshore, TD ca. 4,000m, in 2019 tested 2.86 MMcfg/d possibly from the Cret. Raghvapuram Shale.

Nandigama North 1 explo (ONGC 100%) in West Godavari ML block, suspended

The DOE will launch the pre-determined blocks in the Philippines Conventional Energy Contracting Programme (PCECP) on 10 Sep ’18. A total of 14 service areas have been earmarked: 4 blocks in W. Luzon, 1 in the Cotaboto Basin, 1 in the Cagayan Basin, 2 in the Agusan-Davao Basin, 3 in the Sulu Sea and 3 in the East Palawan Basin. The application period will be 180 days as of round opening. Several roadshows are planned. Contact: Petroleum Resources Development Division, email prdd@doe.gov.ph. Full list of blocks and background from GEPS.

The DOE will launch the pre-determined blocks in the Philippines Conventional Energy Contracting Programme (PCECP) on 10 Sep ’18. A total of 14 service areas have been earmarked: 4 blocks in W. Luzon, 1 in the Cotaboto Basin, 1 in the Cagayan Basin, 2 in the Agusan-Davao Basin, 3 in the Sulu Sea and 3 in the East Palawan Basin. The application period will be 180 days as of round opening. Several roadshows are planned.

P2358 / block 12/23c, Moray Firth, WD 106m, TD in Valhall sands, oil indications over 6m in the target Captain sands, OWC at 1,606m, logging still required. Borgland Dolphin SS.

013/23c-11 Liberator A2 (13/23c-A3-L2)) appr/devt, P2358 / block 12/23c, TD in Valhall sands, oil indications over 6m in the target Captain sands, OWC at 1606m, logging still required. WD=106m.

Vietsovpetro has suspended appraisal well, Ca Tam 5X (09-3/12-CT 5X) in Block 09-3/12, Cuu Long Basin, on or around 7 January 2018, as oil well. The well, spudded early October 2017 and it was drilled to a TD of 3,900 m using the “PV Drilling” J/U. Four DSTs were conducted in the target interval, the Oligocene D unit. A steady flow approximately 1,800 bo/d was observed in two of the DST test. The last activity in the block was the drilling of appraisal well, 09-3/12-CT 4X (Ca Tam 4X) in between late May and mid-September 2016. The well, spudded in late May 2016 and drilled to a TD of 4,350 m MD (3,800 m TVDss) using the “Tam Dao 02” J/U. Three DSTs have been conducted in the Lower Miocene section and one DST in the Oligocene unit. Cumulative test rate of 6,920 bo/d was encountered. It was reported that the well encountered more productive sands in the deeper section compared to the previous appraisal well, Ca Tam 3X.  The Oligocene unit tested around 3,960 bo/d with no water flow. Net oil saturated thickness of formations from both the appraisal wells could be more than 100 m. Block 09-3/12 is operated by Vietsovpetro with 55% interest alongside partners PVEP (30%) and Bitexco (15%). Vietsovpetro is a joint venture between PetroVietnam (51%) and Zarubezhneft (49%).

Ca Tam 5X (09-3/12-CT 5X) in Block 09-3/12, Cuu Long Basin, op. by VIETSOV (55.0%, PETROVIET 30.0%, BITEXCO 15.0%) in Block 09-3/12, oil well, Four DSTs were conducted in the target interval, the Oligocene D unit. A steady flow approximately 1,800 bo/d was observed in two of the DST test.

Lakócsa lease, Somogy-Drava sub-basin in SW Hungary, compl oil at TD ca. 2,000m in Dec ’17, oil in L. Pannonian + Miocene sst.

Pettend Kelet-2 appr Lakócsa lease, Somogy-Drava sub-basin in SW Hungary, compl oil at TD ca. 2,000m in Dec ’17, oil in L. Pannonian + Miocene sst.

On 7 November 2018, the consortium of BP with 60% working interest and Equinor Brasil with 40%, was granted official awards for the C-M-755 and C-M-793 blocks in the offshore Campos Basin through the ANP Round 15. On 29 March 2018, the consortium was granted preliminary awards for the two blocks. For the C-M-755 block the consortium offered a bonus of USD 13.1 million and 200 work units. For the C-M-793 block the consortium offered a bonus of USD 13.1 million and 200 work units.    There were no other bids for either of the blocks.

Consortium of BP with 60% working interest and Equinor Brasil with 40%, was granted official awards for the C-M-755 and C-M-793 blocks in the offshore Campos Basin through the ANP Round 15.

Sources said that that Samuel H Cade and Daniel K Donkel are currently looking to divest equity in the recently acquired Houston-Willow Oil & Gas Exploration License Area (ADL 391282), which encompasses 76 sq km (18,698 acres) of land just north of the City of Houston, Alaska and ~48km (~30 miles) due north of Alaska's largest city, Anchorage. The exploration licence is effective as of 1 December 2018 for a period of five years and includes a US$ 500,000 work commitment. The license area is sited just north of the Castle Mountain Fault which has brought the deeper, more mature portion of the coal-bearing Miocene Tyonek sandstone formation, to the surface. Compressional forces associated with this fault movement have folded the coal-bearing strata, resulting in at least two anticlinal structures that enhances the development of a coalbed methane resource on structural highs. There is also the potential for discoveries of conventional gas in the sandstone and siltstone beds of the Tyonek Formation.

Sources said that that Samuel H Cade and Daniel K Donkel are currently looking to divest equity in the recently acquired Houston-Willow Oil & Gas Exploration License Area (ADL 391282), which encompasses 76 sq km (18,698 acres) of land just north of the City of Houston, Alaska and ~48km (~30 miles) due north of Alaska's largest city, Anchorage.

Cairn, through its subsidiary Capricorn, spudded exploration well 6508/1-3 targeting the Lynghaug prospect in PL 758 on 20 June 2019. This is the company’s first operated well in Norway and it was drilled using the “Transocean Arctic” S/S. Its location is 6 km southeast of Norne and 8 km northeast of Skaugumsasen. The well reached TD at 1,663 m subsea in the Lower Jurassic Are Formation. A 170 m section of Are Formation (the primary objective) was encountered with around 50 m of net sandstone interbedded with claystones and coals. The well is a dry hole and is being abandoned on 9 July 2019. Prior to drilling, Cairn prognosed potential recoverable reserves of approximately 70 MMboe. If the well had been successful it would have been a play opener for the Nordland Ridge and could have been developed as a tie-back to the Norne FPSO. The 2011 Skaugumsasen oil and gas discovery made by Det norske with exploration well 6508/1-2 lies in the southwesterly part of PL 758. The well encountered an 18 m gas column and a 23 m oil column in the Lower Jurassic Tilje / Are formations and recoverable reserves were estimated at 6 MMboe at the time of discovery. PL 758 is operated by Cairn through Capricorn Norge AS (50%) with Skagen 44 (30%) and Lundin Norway AS (20%) as partners.

Norway (Donna and Halten Terraces (Voring B.)) Norne

Ithaca has agreed the sale of its 7.5% interest in the Wytch Farm field to Verus Petroleum for USD 53 MM. Involved are PL 089, P 534 + PEDL 328 across Poole Harbour. Partnership will be Perenco (op) 87.5%, Verus 7.5%, Repsol Sinopec 5%, effective 1 Jul ’17.

Verus Petroleum has acquired 7,5% interest in the Wytch Farm field from Ithaca (->0, Perenco 87,5%, Verus 7,5%, Repsol Sinopec 5%) for US$53 MM. Involved are PL 089, P 534 + PEDL 328 across Poole Harbour.

Location S. of Anchor Point, S. Kenai Peninsula, Cook Inlet Basin, susp at TD 3,200m on 20 Jan ’19, results n/a. Target Miocene Tyonek/Hemlock fm’s.

Seaview-8 expl S. of Anchor Point, S. Kenai Peninsula, Cook Inlet Basin, susp at TD 3,200m on 20 Jan ’19, results n/a. Target Miocene Tyonek/Hemlock fm’s.

Huizhou 27-5-1 (HZ 27-5-1) was suspended (results TBC) in early April 2020 after having been spudded on or around 21 February 2020, using the "Nanhai 7" semi-sub. The oil and gas exploration well was likely targeting the Zhujiang and Enping formations. Huizhou 27-5-1 is in the CNOOC operated Haifeng 25 Block in the offshore Pearl River Mouth Basin and is located south of the Huizhou 21-1 field. <P />

Huizhou 27-5-1 (HZ 27-5-1) was suspended (results TBC) in early April 2020 after having been spudded on or around 21 February 2020, using the "Nanhai 7" semi-sub. The oil and gas exploration well was likely targeting the Zhujiang and Enping formations. Huizhou 27-5-1 is in the CNOOC operated Haifeng 25 Block in the offshore Pearl River Mouth Basin

Lower Austria permit, Vienna Basin in NE Austria, 9-month well P&A'd Jul '20, PTD ca. 4,500m believed reached late 2019, Bentec rig. 7-inch liner run, 3 intv's perforated, non-commercial.

(Vienna B.) Altlichtenwarth Tief 1 explo well operated by OMV (100%) in Lower Austria A block abandoned, believed non-commercial

Reabold has conditionally agreed to acquire Humber O&G's 16.665% in PEDL 183 (West Newton oilfield) subject to OGA approval. The deal is for GBP 1.4 MM + 350,000,000 shares, bringing Reabold's interest here to ab. 56%. PEDL 183 covers 702 sq km NE of Hull in Yorkshire, and site construction is underway for the drilling of the B-1 well. Resulting partnership-to-be: Rathlin (op), partner UJO.

Reabold has conditionally agreed to acquire Humber O&G's 16.665% in PEDL 183 (West Newton oilfield) subject to OGA approval. The deal is for GBP 1.4 MM + 350,000,000 shares, bringing Reabold's interest here to ab. 56%. PEDL 183 covers 702 sq km NE of Hull in Yorkshire, and site construction is underway for the drilling of the B-1 well. Resulting partnership-to-be: Rathlin (op), partner UJO.

Back in August, Vintage signed with Beach to acquire the latter’s 100% in EP 126,  6,740 sq km mostly onshore in the Bonaparte Basin. The deal remains pending usual approvals.

Vintage signed with Beach to acquire the latter’s 100% in EP 126, 6,740 sq km mostly onshore in the Bonaparte Basin.

It was announced on 14 February 2020 that Aladdin Middle East Ltd (AMEL) has been awarded the E28-C onshore exploration licence (Pontides Basin) on 5 February 2020 for a period of five-year. The licence, covering an area of 544 sq km, is located towards northwest of the country and AMEL will be 100% owner and operator of the licence. AMEL had filed the application on 19 June 2019.

AMEL (Aladdin Middle East Ltd) has been awarded the F28-B1,B2, E28-C onshore exploration licence.

Sonatrach and OMV announce the signing of an MoU to identify potential upstream opportunities where the two parties can jointly invest in Algerian E&P opportunities, taking advantage of the new Algerian hydrocarbon law.

Algeria, not found

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

Myanmar, MOGE-4

In early December 2018 the Republica Dominicana’s Minister of Energy and Mines signed USD 1.07 million contract with a consulting company for the evaluation, planning, promotion and execution of a Bid Round for the exploration and exploitation of hydrocarbons. The model contract which will be used for the bid round will be the Production Sharing Contract (PSC). The tender to hire consulting services was first announced in May 2018, with nine companies from five countries presenting proposals -  “The country has to make the leap to reduce its dependence on oil imports in all ways and one of the most important is to promote the exploration and exploitation of hydrocarbons, especially gas, both for its economic and environmental benefits”, said the Minister Antonio Isa Conde. Dominican Republic’s Minister of Energy and Mines (MEM) Antonio Isa Conde presented in late August 2018 the “Informes de Trabajos 2014-2018”, which reports the work that has been done since the creation of the ministry in 2013.  The Base Nacional de Datos de Hidrocarburos (BNDH), the national digital archive which contains geological and geophysical information for the country starting in 1903 till 2013 was developed by a third party and presented in 2016. It has 21,500 km of seismic lines, 1,490 maps and plans, 805 seismic profiles, 212 wells – which the ministry estimates it has an acquisition cost of USD 145 million. The MEM identified six potential zones for hydrocarbons, the basins: Enriquillo, Azua, San Juan, San Pedro de Macoris, Ocoa and Cibao Oriental. The first hydrocarbon exploration and exploitation regulation was issued in 2016 through the decrees 83-16. The contract for exploration and production of hydrocarbons was issued in early May 2018. According to the contract, the exploration period of the contracted area may be up to six (6) years following the signing of the contract and may be extended for up to four (4) additional one-year periods. Modification of this term and its extensions shall be authorized by decree. The exploitation period of the Contracted Area may be for up to twenty (20) years and a maximum of two (2), five-year extensions each. The first extension may be requested upon reaching seventy-five percent (75%) of. the term of the contract granting the rights for the exploration and exploitation of Hydrocarbons, Oil Reservoirs or other Hydrocarbon substances, while the second extension may be requested when fifty percent (50%) of the term of the first one has elapsed. Background Information In early June 2011, no additional information had been received concerning a possible bid round in 2011. In September 2010, the Industry and Trade Industry's Mining Department director, Octavio Taveras, announced that the Dominican Republic planned to launch an international oil exploration round in 2011. The announcement follows reports of a new oil seep in Higuey, La Altagracia province in the eastern part of the country. GHGeochem in the UK analyzed samples and reported that the oil seep is better quality than that found in Azua province. An assistance agreement is being finalized with MDOIL whereby the company will help characterize potential hydrocarbon bearing sedimentary basins in the country including the exclusive economic zone. The declaration follows a late 2009 announcement made by the department that Madrid's Complutense University found traces of natural gas in marine sediments in an area known as the Muertos Trough offshore. The Directorate is waiting for authorization from the president to sign a contract with MDOIL which hopes to expand the study to include all the basins in the country and to correlate them with the previous data. In early September 2010, there were no tenders planned for oil and gas exploration. Interested companies can approach the ministry directly concerning any of the seven identified basins. The onshore areas that have been outlined as potential opportunities are in Bahoruco, Samana, Azua and Maria Trinidad Sanchez provinces, and offshore in Ocoa and Samana Bays and Banco de la Plata. However, the country's 1958 hydrocarbons law must be updated as the regulatory framework is not clearly defined and does not attract investors.

In early December 2018 the Republica Dominicana’s Minister of Energy and Mines signed USD 1.07 million contract with a consulting company for the evaluation, planning, promotion and execution of a Bid Round for the exploration and exploitation of hydrocarbons.

Hardly news by now, in late January Real achieved 2.5 MMcfg/d from its Tamarama-3 tight gas well in ATP-927-P, Cooper-Eromanga. Tamarama-2 & 3 data will form the basis of initial reserves for the Windorah gas project.

Real achieved 2.5 MMcfg/d from its Tamarama-3 tight gas well in ATP-927-P, Cooper-Eromanga. Tamarama-2 & 3 data will form the basis of initial reserves for the Windorah gas project.

Wellesley has transferred its 30% interest in PL 810 to Aker BP with effect from 30 October 2017 (reported by the NPD on 2 November 2017). PL 810 is an APA 2015 licence covering 128 sq km over parts of blocks 2/1, 7/12 and 8/10 between Ula, Oda and Tambar.   PL 810 contains just a single well, dry hole 7/12-13 S, drilled by Det norske in 2012 when the area was held under PL 450. It targeted Storebjorn - an Upper Jurassic intrapod prospect, dip-closed to the south-east and fault-sealed in all other directions. The Gyda and Ula formations were the main objectives and it was estimated, prior to drilling, to contain reserves of around 96 MMboe. The main risks were reservoir quality, seal to the north-west and source effectiveness. TD was reached at 4,575m in the Middle Triassic and the reservoir section was found to be water-bearing. Faroe Petroleum Norge AS operates PL 810 with a 40% interest. It is partnered by Aker BP ASA (30%) and Centrica Resources (Norge) AS (30%).  

Wellesley has transferred its 30% interest in PL 810 to Aker BP. (Faroe Petr. 40% + op, Centrica 30%).