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In January 2019 Overgas was still offering the opportunity for interested parties to farm-in to licences Provadia and 1-18 Trakiya. The Provadia licence is located in the eastern part of the country while the 1-18 Trakiya licence is situated in southern Bulgaria. The company started looking for partners in May 2016. Between 2011 and 2014 Overgas conducted two 2D seismic surveys and one 3D seismic survey totaling respectively 812 km and 55 sq km in the Provadia licence. No fields are situated within the permit area. The last known drilling activity consists of Krivnya 12 which was drilled to a total depth of 2,769 m in the Lower Triassic and abandoned as a dry hole in 1984. In the 1-18 Trakiya licence, the company drilled the Trakiya 1 exploration well between 2014 and 2015. The hole reached a total depth of 1,717 m bottoming in metamorphic rocks without reaching the targeted Jurassic sediments. It was subsequently re-entered for testing and recovered only gas shows. In late 2012 Overgas conducted a 474 km 2D seismic survey in the permit. For further information please contact: Dimitar Merachev Tel - +359 2 865 11 99 [email protected]

Bulgaria, 1-18 Trakiya

Yuganskiy-11 licence (KhMN02997NR), Khanty-Mansiysk-Yugra AO, W. Siberia, tested 898 bo/d from the Neocomian Akhskaya BS8 fm, also some oil from Tyumen Yu2.

Yuganskaya - 11 1, (Rosneft - Uvatneftegaz 100%) in the Yuganskiy-11 license (KhMN02997NR - 285km²), in Khanty-Mansiysk-Yugra Autonomous Okrug, tested oil from the Akhskaya Fm Unit BS8 (Neocomian) and the Tyumen Fm Unit Yu2 (Middle Jurassic). It is understood that the Neocomian reservoir flowed with oil at a rate of 898 b/d. The company estimated 3P reserves of the discovery, named after geologist V.M.Matusevich, at 40 MMbbl of oil.

The authorities announce the offer of 75 production licences on the NCS under the Award in Pre-Defined Areas 2017 (APA 2017) round. This is the highest ever awarded in an NCS round.  The licences are distributed over the North Sea (45), the Norwegian Sea (22) and the Barents Sea (8), offered to 34 oil companies, 19 of which have been offered one or more operatorship. Statoil was the first to announce its individual offers, 17 as operator and 14 as a partner. The offer includes 3 commitment wells, including Gladsheim eat of Troll in PL 921 and Ørn in PL 942, Norwegian Sea. List of awardees and map.

MPE announced that it had offered in APA 2017 round. The licences are distributed over the North Sea (45), the Norwegian Sea (22) and the Barents Sea (8), offered to 34 oil companies, 19 of which have been offered one or more operatorship. Statoil was the first to announce its individual offers, 17 as operator and 14 as a partner.

New Age Ltd is understood to be looking for a partner for its Foum Ognit Offshore permit (western Sahara), which comprises 4 sub-units totaling 7,969 sq km in the Aaiun-Tarfaya offshore basin. New Age is the operator of the permit with a 75% interest. Onhym, the national company, carries the remaining 25% interest. Background information On 23 December 2013, New Age signed with Onhym a 3-1/2 year Petroleum Agreement for the Foum Ognit Offshore block. The commitments include G&G work, the reprocessing of the available 2D seismic data and the acquisition of 2,000 km of 2D and 1,000 sq km of 3D seismic data The Aaiun--Tarfaya-Dakhla Basin is a Mesozoic rift basin located both onshore and offshore the passive Atlantic margin of southern Morocco and extends southwards throughout Western Sahara. The basin is formed of a faulted basement made of Precambrian and Paleozoic rocks, overlain by a Triassic-Liassic sequence composed mainly of clastics, including microconglomerates, sandstones, red shales with evaporites and lagoonal deposits. The shaly and saliferous plastic formations should have generated halokinetic structures. The postrift sequence starts with the Liassic-Dogger sub-sequence related to the opening of the Atlantic and to the progressive setting of a marine environment and carbonate sedimentation. In wells MO-2, MO-8 and Cap Juby 1 located further north, the Liassic and Dogger sections are made of limestones with sandy and shaly intervals. The second postrift sub-sequence is a true passive margin basin formed in Late Jurassic time, with a carbonate platform to the east and an open marine domain to the west. Reefal build-ups are present along the edge of this platform. During the Cretaceous, sands and conglomerates were deposited in the east of the basin, and thick shaly and silty rocks to the west, and a fourth postrift sequence started at the end of Albian time, with marls, shaly limestones, shales, organic rich bituminous chalks and shaly limestones with chert and phosphates. Phosphates series were deposited during a regression period starting during the Coniacian. Alpine movements have produced regional unconformities during the Oligocene and Miocene times along the shelf break. Tertiary erosion has formed canyons later filled by Cenozoic turbiditic deposits.  On 19 December 2014, New Age completed its 2,145 km 2D survey over the Foum Ognit Offshore block, which comprises 4 sub-units totaling 7,969 sq km in the Aaiun-Tarfaya offshore basin (offshore Western Sahara). This USD 2 million seismic survey started on 26 November 2014 using the SeaBird “Harrier Explorer” vessel.  On 22 February 2017, New Age completed 999 sq km of 3D seismic data over the northern part of its Foum Ognit Offshore permit. The survey started on 2 February 2017 using the “BGP Prospector” vessel. On 17 August 2017, Glencore had officially released its 18.75% interest in the Foum Ognit Offshore permit (western Sahara), which comprises 4 sub-units totaling 7,969 sq km .

New Age Ltd is understood to be looking for a partner for its Foum Ognit Offshore permit (western Sahara), which comprises 4 sub-units totaling 7,969 sq km in the Aaiun-Tarfaya offshore basin. New Age is the operator of the permit with a 75% interest. Onhym, the national company, carries the remaining 25% interest.

SK-320 off central Luconia, Sarawak, one of 2 wells planned with Buah Keras-1, P+A dry around 26 Jan ’18, Hakuryu 5 SS. Target Middle Miocene Cycle IV carbs. Mubadala (op), partners Petronas + Shell.

Malaysia (Central Luconia Province) Buah Keras 1 op. by MUBADALA I (55.0%, PETRONAS 25.0%, SHELL 20.0%) in SK-320 block

The deadline to nominate lands for consideration to the Canada-Nova Scotia Offshore Petroleum Board (C-NSOPB) as part of the upcoming 2019 Nova Scotia Call for Bids is 1 December 2018. In addition to reviewing nominated lands received by the C-NSOPB, the Board has outlined Call for Bids Forecast Areas on a rolling three-year basis for 2019 and 2020. The Forecast Area for the Nova Scotia 2019 Call for Bids covers approximately 22,700 sq km of shelf and deepwater to the northwest of Exploration Licence EL 2434R, surrounding Sable Island and its associated offshore gas development area, which is in the process of being decommissioned and abandoned by ExxonMobil. Sable Island, located ~225km off the east coast of Nova Scotia, encompasses seven offshore platforms, originally producing from six natural gas fields: Alma, Glenelg, North Triumph, Thebaud, South Venture and Venture. The Sable Island development spans more than 200 sq km and includes 340km of subsea pipelines and 22 wells. ExxonMobil anticipates the complete removal of all offshore facilities by 2020. The C-NSOPB Call for Bids Forecast Areas are reviewed on an annual basis to determine whether the planned areas should be amended.

The deadline to nominate lands for consideration to the Canada-Nova Scotia Offshore Petroleum Board (C-NSOPB) as part of the upcoming 2019 Nova Scotia Call for Bids is 1 December 2018. In addition to reviewing nominated lands received by the C-NSOPB, the Board has outlined Call for Bids Forecast Areas on a rolling three-year basis for 2019 and 2020.

OMNIS announced that it will officially launch the offshore Bid Round on 7 November during the Africa Oil Week Conference which is taken place between 5 and 9 November in Cape Town (South Africa). The 44 offshore blocks are located in the Morondava Basin for a total of 63,296 sq km. The Bid Round will be open for six months with the closing date being 30 May 2019. Roadshows will be held in London on Tuesday 19 February from and in Huston on Tuesday 26 February 2019. In addition, the OMNIS team will be present at the PROSPEX (12-13 December) and the APPEX (27 February-1 March) meetings, both held in London. The parliament has not yet approved the new petroleum legislation. However, OMNIS announced that the bid round will use the current petroleum code if the new legislation is not approved in time. The initial draft prepared by OMNIS and the Ministry of Mines and Petroleum was discussed during a two-day workshop in March 2015 by representatives of various governmental departments, the civil society and representatives of oil exploration companies already active in Madagascar. OMNIS stays open for direct negotiation outside a tendering process for open onshore blocks and offshore blocks outside the blocks to be proposed for the coming biding round. In view of this bid round, new seismic data has been acquired and treated by TGS/NOPEC (15 000 km) and BGP (13 000 km). Geospec/Robertson has also retreated OMNIS old data and integrating regional setting in order to produce better understanding of the Morondava basin potential. In total, over 55,500 km of 2D seismic data acquired between 1969 and 2013 are available over the offered blocks. Additionally, data over nine wells that were drilled either on or nearby the offered blocks are available: Chesterfield-1, Heloise-1, Morondava-1, Vaucluse-1, Epong-1, Morombe-1, Ankamotra-1, Cap St André-1 and 2. For more information: https://madagascarlicensinground2018.com/ http://www.omnis.mg http://www.tgs.com http://www.bgp.com.cn Background information On 7 March 2011, media reports indicated that the Madagascar government has suspended plans for an offshore bid round. Priority was to be given to the open acreage located in the offshore part of the Morondava Basin. The last tender in the country closed on 8 December 2006. In total, 122 offshore blocks were offered: 75 in the Morondava Basin, 24 in Cap d'Ambre and 23 in the area of Sainte Marie Island. In late August 2013, it was understood that OMNIS has postponed the launching of the Madagascar international bid round until December 2014 due to the extension of the transition period for the presidential elections. 39 onshore blocks and 264 offshore blocks will be offered during the future bid rounds.

Madagascar, not found

On 30 April 2018, Gas y Petroleo del Neuquen (GyP Neuquen) reported that the company awarded six blocks through the "Neuquen Exploratory Plan" series of bid rounds. Small operator Selva Maria Oil SA was granted rights on La Tropilla II and Huacalera Norte blocks. Selva Maria investments committed for the two blocks are US$ 17.1 million. Selva Maria in February filed offers for 5 areas. GyP had originally rejected the offers based on high acreage concentration criteria. GyP Neuquen considered that the company would exceed the maximum value of 250 sq km per company stipulated by the plan if they accepted those offers. The Selva Maria offers totaled 793 sq km. Selva Maria holds the La Brea license in the Jujuy province (Oran Olmedo Basin) and was recently awarded the Mata Magallanes Block in the San Jorge Basin. The entire Neuquen Exploratory Plan involves 50 blocks. Many important players like Chevron were said to be interested in various prospects. Chevron was awarded the Loma del Molle permit in October 2017 with a US$ 22 million investment commitment. These offered areas are inactive oil and gas blocks offered every three months through bid rounds or private initiatives. Bids in the Neuquen province will maintain the current system where GyP Neuquen retains a portion of the contract on a carried basis although the new federal hydrocarbon law has limited this practice. The blocks in the plan are currently reserved for GyP Neuquen as the sole rightholder. Some of these blocks have unconventional potential. For more information please email [email protected] or call +54 299 5678200.

Argentina, Huacalera Norte

UKOG is acquiring Solo Oil's 30% interest in PEDL331 for GBPS 350,000 (US$ 439,000), and will increase its share of the licence to 95%, subject to OGA consent. UKOG announced on 12 December 2018 that it had entered into a binding heads of terms with Solo, and advised that the transaction fee will be satisfied through GBPS 90,450 (US$ 113,000) cash plus 17,989,326 new ordinary shares in UKOG. PEDL331 contains the Arreton 2 conventional oil discovery (1974, BG, 2,813m), consisting of three stacked Jurassic oil pools with an aggregate gross P50 oil in place of 127 MMBO. The acquisition will correspondingly increase UKOG's share of the Arreton discovery's recoverable Contingent Resource volumes by 46%, from 10.2 MMBO to a material 14.9 MMBO UKOG net. A further significant increase in oil recovery factor above the current estimated 12% is likely via adoption of an early stage reservoir pressure support scheme (i.e. water reinjection). PEDL331 covers 200 sq km over Isle of Wight onshore blocks SZ38a, 47, 48a, 57 & 58a, and was awarded in the 14th Landward Round, valid for five years initial term commencing 21 July 2016. The Arreton-3 appraisal well, is scheduled to be drilled, cored and tested in Q1 2020. After completion of Arreton-3 flow testing, UKOG plans to drill the larger look-alike Arreton South exploration prospect. Also, within PEDL331 is the landward extension of the M Prospect in adjacent offshore licence P1916, plus further undrilled oil prospects in tight limestones and shales of the Kimmeridge Clay, Oxford Clay and Lias Formations comparable to the Horse Hill Weald area licences. In 2016, Doriemus acquired Angus Energy's (now UKOG) 5% working interest PEDL331. UKOG also became operator. Pending completion of the PEDL331 transaction, participants are UK Oil and Gas Investments Plc (65% + Op), Solo Oil Plc (30%), and Doriemus Plc (5%).<P /><P />

United Kingdom, PEDL 331

The NPD confirmed, on 5 November 2019, that Var has taken a 20% interest in PL 901 from Equinor, adding to the 30% interest that Var already held in the licence. Subsequent to this, on 19 November 2019, a change of operator was reported – from Equinor to Var (effective 1 November 2019). PL 901 was awarded in APA 2016 and covers a 278 sq km area over parts of blocks 7122/5, 7122/6 and 7123/4, to the east and south of Tornerose. It contains the 2008 Tornerose appraisal wells 7123/4-1 S and 7123/4-1 A which only encountered shows. The deal is effective from 31 October 2019. Tornerose was discovered in 1987 by 7122/6-1. A 75 m gas column was encountered in the Upper Triassic Snadd Formation but at the time the find was considered uneconomic as companies exploring the Barents Sea were looking for oil. However, the development of nearby Snohvit meant that gas finds became more interesting so the discovery was appraised in 2006. 7122/6-2 was a success and Statoil confirmed that Tornerose was a viable project. However, the appraisal drilling in 2008 (in what is now PL 901) was disappointing, with the hydrocarbons in both 7123/4-1 S and sidetrack 7123/4-1 A being classed as residual. In 2019 Equinor was granted an extension to the PDO submission date for Tornerose and nearby Snohvit Beta from December 2019 to December 2024, although it is likely that this will need to be extended again. The two discoveries hold approximately 100 Bcfg and 140-200 Bcfg respectively, not enough to warrant a standalone development. Therefore, the projects cannot proceed until there is sufficient capacity at the Melkoya LNG facility (which is likely to be 2038). In 2012 Equinor ruled out the possibility of an expansion of capacity at Melkoya (ie a second train or a dewpoint facility/pipeline) on economic grounds. The company is, however, looking at options for a further phase of development at Snohvit to include compression (either onshore, subsea or on the platform), the drilling of new wells and a potential new pipeline to shore, with a view to extending production past 2050. Concept selection for this Snohvit Future Phase II project will take place in December 2019, with FID by the end of 2020 and potential start-up in 2025. Interest in PL 901 is now held by Var Energi AS (50% + operator), Equinor Energy AS (30%) and Concedo ASA (20%).

The NPD confirmed, on 5 November 2019, that Var has taken a 20% interest in PL 901 from Equinor, adding to the 30% interest that Var already held in the licence.

Industry rumours suggest O&G Devt Central (Sand Hill) is looking to farm down its central Hungary positions, namely Nagykata (551 sq km), Mogyorod (521 sq km) + Ocsa (592 sq km) blocks, share negotiable.

Industry rumours suggest O&G Devt Central (Sand Hill) is looking to farm down its central Hungary positions, namely Nagykata (551 sq km), Mogyorod (521 sq km) + Ocsa (592 sq km) blocks, share negotiable.

News is that Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) and LOTOS Petrobaltic concluded drilling operations in new-field wildcat Stawno 1 in the 1/2000/Ł Kamień Pomorski contract in northwestern Poland in October 2017. The results of the well have yet to be disclosed. Stawno 1 was started in late July 2017. The well, drilled by a rig from PGNiG’s subsidiary Exalo Drilling, is located some 20 km northeast of the city of Szczecin within the Pomeranian High, tectonic unit of the Northeast German-Polish Basin. Stawno 1 had a planned final depth of just over 3,200 m, targeting the Upper Permian (Zechstein) carbonates and the Lower Permian (Rotliegend) siliciclastics. The news on the spud of the well was announced on 2 August 2017. The well was drilling ahead at an undisclosed depth in mid-September 2017.

Poland (Northeast German-Polish B.) Stawno 1 op. by PGNiG (51.0%, LOTOS PETR 49.0%) in 1/2000/L block

Block partner Medco in its July 2020 exploration report indicated that the Juum 1 NFW, on CNH-R02-L04-AP-CM-G01/2018 (Block 10), has been abandoned as a dry hole. Medco revealed the total exploration cost for the well totalled US$ 45.5 million, of which US$ 9 million was net cost to Medco. Pre-drill planned total costs were estimated to be US$ 76.3 million.On 20 June 2020, the "Maersk Valiant” drillship departed from Juum 1. The drill ship arrived on 6 May 2020, likely spudding shortly after. The Repsol Exploracion Mexico operated Juum 1 was targeting 221 MMboe in prospective resources in the Miocene (3,335-3,600m) and the Oligocene (4,050-4,385m). The vertical well had a PTD of 4,460m. The well was planned to take 72 days to drill and plug. The well is sited in 1,755m of water depth. Repsol used the same rig on the Polok 1 and Chinwol 1 NFWs, on the Repsol-operated CNH-R02-L04-AP-CS-G10/2018 Block (Block 29). In January 2020, Mexico's Comisión Nacional de Hidrocarburos (CNH) outlined Repsol's plans for a two-well programme on operated Block 29, which would utilise “Maersk Valiant” for batch drilling (originally planned for between March and June 2020), leaving little time for drilling on Block 10, which presumably lead to the one-well option being exercised. In early February 2020, Maersk Drilling confirmed a one-well option under contract with Repsol.Repsol had identified two prospects on the tract. They are the drilled Juum 1, and Lool 1, a Jurassic Age prospect targeting prospective resources of 101 MMboe. Lool 1 has objectives in the 4,400-4,750m interval, while Juum 1 was targeting light oil (35° API). Investments are expected to reach just over US$ 150 million through 2023. The CNH in June 2019 stated that one well will spud in 2020, while the other will spud in 2021, without providing an exact timeline.

(GOM B.) Juum 1 nfw, operated by Repsol (40%) partners MEDCO (20%) + Petronas (40%), has been abandoned as a dry hole.

Vintage has concluded a 30% farmin from RCMA (op) and Metgasco in prod. licence L 14, 39 sq km in the Perth Basin and home to the Jingemia oilfield. The deal is in exchange for Vintage funding 50% of the Cervantes explo well spudding by 3Q '20, and paying AUD 100,000 to Metgasco for future expenditure relating to Cervantes and AUD 100,000 to RCMA for seismic re-processing over the L14 licence. Metgasco also has the right to drill a 2nd optional well with the same farmin obligations, exercisable between Apr-Dec '20.

Vintage has concluded a 30% farmin from RCMA (op) and Metgasco in prod. licence L 14, 39 sq km in the Perth Basin and home to the Jingemia oilfield. The deal is in exchange for Vintage funding 50% of the Cervantes explo well spudding by 3Q '20, and paying AUD 100,000 to Metgasco for future expenditure relating to Cervantes and AUD 100,000 to RCMA for seismic re-processing over the L14 licence.

LOTOS has been awarded Kretingos exploration & production (E&P) licence in the Baltic Basin. The new award was ratified on 7 March 2018 and covers 158 sq km located between Kretinga and Genciai fields to the W and Nausodis Field to the E, which are all operated by LOTOS, and produce from a Cambrian reservoir. LOTOS has a stake in nine Lithuanian Baltic Basin blocks (seven operated), with average net production of 968 boe/d during 2017, whilst year-end reserves were 3.6 MMbo. AB LOTOS Geonafta is sole licensee for Kretingos.

Lotos has been awarded Kretingos licence

The Senegal authorities plan to launch a bidding round for exploration acreage in October 2019. Both the “MSGBC Summit” in Dakar and the “Africa Oil & Power 2019” in Cape Town have been mentioned as launch pads. In early September 2018, Mamadou Faye, CEO of Petrosen said that a bid round for ten exploration blocks is planned to be launched in the first or second quarter of 2019. One of these blocks will be onshore. According to Faye, the new petroleum law should be ready by end-2018, ahead of the bid round. In February 2019, industry sources indicated that the new petroleum law which was approved by parliament in January 2019 will be signed into law only after presidential elections to be held in late February. This means that the launch of the bid round could be delayed to the second half of 2019. In August 2018, industry observers indicated that the Senegal authorities may launch a bid round before the revision of the hydrocarbon legislation is completed. Some progress was also made on another front: to make available suitable acreage blocks for the bid round. According to list of valid permits published by Senegal, all onshore blocks are available except Fortesa’s acreage. In the offshore, the high potential Senegal Offshore Sud permit is now free. It used to be operated by Elenilto who did not meet work commitments. Most of the ulra deep water acreage currently held by Total under a non-exclusive technical evaluation permit would also be available. Petrosen has now an attractive portfolio of acreage blocks to be offered in a bid round. So far, however, no details on the planned bid round were announced. As of February 2018 it appeared that there will be no bid round in Senegal any time soon. The revision of the hydrocarbon legislation takes longer than anticipated and there is no indication as to when it will be completed. The government also intended to get back acreage from small non-performing operators to offer it in the bid round. There also progress is slow. Senegal’s Energy Minister said that in the future the country would like to sign petroleum contracts with major oil companies rather than small players to ensure that hydrocarbon resources are effectively developed. In early April 2016 it was reported that Petrosen intended to launch a bid round for ultra deep offshore acreage in 2017. The blocks to be offered have yet to be created, they will be adjacent to the west of the existing deep water blocks Saint-Louis Profond and Cayar Profond of Kosmos, Rufisque Offshore Profond and Senegal Offshore Sud Profond of African Petroleum. The number of new ultra deep water acreage blocks has not yet been defined although some sources mentioned five blocks. They were to be delimited once 2D seismic data yet to be acquired had been evaluated in the second half of 2016. The launch of the planned bid round also depends on the completion of the revision of the hydrocarbon legislation which was under way at the time. It was initially anticipated that the new law would be ready at the end of 2016.

Senegal, Rufisque Offshore Profond

On 14 February 2020, ExxonMobil with 100% working interest was granted a final award for the 708.97 sq km C-M-479 block in the deep-water offshore Campos Basin from the ANP Round 16. On 10 October 2019, ExxonMobil with 100% working interest was granted a preliminary award for the 708.97 sq km C-M-479 block in the deep-water offshore Campos Basin from the ANP Round 16. There were no other bids for the block. The company bid a bonus of USD 6.17 million at 1 USD to 4.11 BRL and USD 10.49 million in minimum work commitments. ExxonMobil is operator with 100% working interest.

Exxon Mobil Corp - Campos Basin – C-M-479 - final award from ANP 16 Bid Round

Cairn's exchange of a non-operating 50% stake with Shell in so far wholly-owned P2379 (Diadem prospect) in return for 50% in Shell’s P2380 (Jaws prospect) was completed on 23 Jun '20, having been agreed in March. Partnership becomes 50:50 in both:

United Kingdom (Central Graben Province), Cairn confirmed in its full year announcement in March 2020 that it had agreed an asset exchange agreement with Shell involving two licences P2379 (blocks 22/11b, 22/12b, 22/16b and 22/17c) and P2380 (block 22/12d).

In early September 2018 there were Press reports that MOL is intending to sell its North Sea assets and leave the region. The Hungarian-based company entered Norway in 2015 by the acquisition of Ithaca Petroleum Norge AS for an initial sum of USD 60 million, with potential additional bonus payments of up to USD 30 million (on a sliding scale) depending on exploration success from its licence portfolio between 2015 and 2017. Since then, MOL has added acreage through a series of deals and licensing rounds. It currently (13 September 2018) holds 20 licences in the Norwegian North Sea which contain a number of small discoveries including Blabaer, Freke and Trell. MOL will operate a well on the stacked Oppdal and Driva prospects in block 2/6 on the Mandal High later in September 2018. Oppdal (Paleocene Vale Formation) and Driva (Permian Auk Formation) will be drilled by 2/6-6 S. Driva lies within PL 860 and Oppdal is located mainly in PL 860 but also extends into PL 539 to the southeast. Partner Lundin puts potential recoverable reserves at 434 MMboe and chance of success at 30%.

Norway (Heimdal Terrace (Viking Graben Province)) Vale

Saturno pre-salt area, E. of Libra field in Santos deepwaters, WD 2,609m, ops terminated 30 May '20, Brava Star DS. PTD was 5,100m, target Barra Velha fm. Shell (op), partners Chevron + Ecopetrol.

Brazil (Santos B.) Saturno 1 op. by SHELL (45%), CVX (45%), ECOPETROL (10%) in Saturno block, WD = 2069 m, drilling concluded with a PTD of 5100 m. The well is targeting the pre-salt Aptian carbonates of the Barra Velha Fm. WD=2 609 m. The NFW lies the SE part of the N-S oriented Saturno prospect, which is about 20 km south of the Alto de Cabo Frio Central prospect and about 74 km east of the Libra field. P&A, dry, no shows.

Cairn has an option to acquire a 30% interest from Total in block C-7,  7,291 sq km in the deepwater MSGBC Basin, northern offshore. Cairn can exercise the option upon a well decision based on the current seismic evaluation. The well could be drilled in 2021. Total (op, 90%), partner SMHPM.

Mauritania, C-7

Sinopec tested 22 MMcf/d of gas, through a 14 mm choke under well head pressure of 35.87 Mpa, in a horizontal shale gas development well in the Sichuan Basin on 11 April 2019. Jiaoye 189-8H, located in Pingqiao area of Jiaoshiba field second phase block, has a TD of 4,597 m with a horizontal section of 1,708 m. The well achieved a record high flow rate in the field so far after a 16-stage fracking. It is said that an advanced fracking technology is applied on the fracking operation and the success indicated a way to mitigate the risk of complex geology in the field. Currently, Sinopec has 33 wells on stream in Pingqiao area with production rate of 74 MMcf/d of gas. Background Information In 2018, Sinopec produced 6 Bcm of shale gas from the Jiaoshibas field in the Sichuan Basin, same as in 2017. The company plans to produce 6.3 Bcm in 2019. In 2018 Sinopec put additional 81 wells on stream in the field and added 5.4 Bcm of gas reserves. Jiaoshiba field has produced cumulative of 21.5 Bcm of shale gas by 2018 since it produced gas in 2012. Sinopec completed Jiaoshiba field first phase development by end 2015, building a production capacity of 5 Bcm per year. The company started Jiaoshiba field 2nd phase development program in early 2016, focusing on drilling program in Jiangdong, Pingqiao, Baitao and Baima blocks.  Apart from the Jiaoshiba field, Sinopec also has achieved several successes in shale gas exploration drilling in other blocks in the Sichuan Basin, such as Yongchuan, Weiyuan-Rongxian and Dingshan area, in particularly Weiyuan-Rongxian block has been approved 4.4 Tcf of gas in place in 2018. China has approved cumulative of over 37.6 Tcf of shale gas in place reserves by end 2018. Currently all shale gas fields are found in the Sichuan Basin, such as Jiaoshiba, Weiyuan, Changning, Zhaotong and Weirong.  China produced over 10 Bcm of shale gas in 2018.

Jiaoye 189-8H, (Sinopec 100%) horizontal shale gas development well has a TD=4597 m with a horizontal section of 1 708 m, located in Pingqiao area of Jiaoshiba field, tested 22 MMcf/d of gas, through a 14 mm choke. It is said that an advanced fracking technology is applied on the fracking operation and the success indicated a way to mitigate the risk of complex geology in the field.

Pertamina is looking to dilute/sell its 40% in the Muara Enim II CBM PSC, multiple blocks totalling 877 sq km in central South Sumatra. Muara Enim II is overlain by a conventional o&g PSC, infrastructure ready. Suggested targets are the U. Miocene Mangus, Suban, Petai, Merapi + Kladi coal seams. NuEnergy (op), partners Pertamina + Metana Enim Energi.

Pertamina is looking to dilute/sell its 40% in the Muara Enim II CBM PSC, multiple blocks totalling 877 sq km in central South Sumatra. Muara Enim II is overlain by a conventional o&g PSC, infrastructure ready. Suggested targets are the U. Miocene Mangus, Suban, Petai, Merapi + Kladi coal seams. NuEnergy (op), partners Pertamina + Metana Enim Energi.

Kayo Bloc Nord permit, drilled 26 Sep – 26 Nov ’18, TD 2,644m (Sialivakou fm), Chela + Mengo sst oil-bearing. A further explo well is planned in this block in June. Wing Wah (op), partner SNPC (carried).

Homloni-5 (HOL) apprKayo Bloc Nord permit, drilled 26 Sep – 26 Nov ’18, TD 2,644m (Sialivakou fm), Chela + Mengo sst oil-bearing.

In early March 2020, Anadarko US Offshore acquired a total of 66.66666% equity in MC 80 from existing lease partners Talos Resources (33.33333%), ILX Prospect Alfalfa South (16.66666%) and Ridgewood Alfalfa South (16.66667%). The transactions are effective as of 1 January 2020. The block shares its western with Murphy-operated block MC 79, site of the 2014 Otis gas discovery. The discovery well logged over 21m of net hydrocarbons in Miocene reservoir of a high-condensate yield gas. Following completion of the transactions, Anadarko US Offshore is now the sole interest-holder (100% WI) in MC 80. Anadarko US Offshore's parent company, Andarko Petroleum, now operates the block.

Anadarko (Oxy) (->100%) acquired a total of 66,7% equity in MC 80 from existing lease partners Talos, ILX Prospect and Ridgewood.

Eni Timor Leste SpA, a wholly owned subsidiary of Eni SpA, is offering interested companies the opportunity to farm into or possibly acquire Production Sharing Contract S06-04 also known as Block E, located in the Bonaparte Basin. Participating interest of up to 35% was thought to have been initially available, with negotiable terms. In May 2020, it was reported in the media that Eni could be looking to exit its Australian production and exploration position, which could also include its Timor Leste assets. Eni has reported that the permit contains the Samara Prospect, with potential mean estimates for oil in place of 319 MMbbl of oil. The prospect reservoir targets are within the Plover and Nome formation sandstones. There are additional oil prospects outlined by Eni, including Estado Lauana, Paramin, Deleco and Atara, which range in size from between 111 to 393 MMbbl of oil in place. There have been no wells yet drilled within the permit area. However, Eni conducted a 3D seismic survey in 2007, which covered a number of permits including S06-04. A total of 8,400 sq km of data was acquired. The permit was awarded in November 2006 and was scheduled to expire in 2014. As of August 2020, it is under a renewal consideration by Autoridade Nacional do Petróleo e Minerais (ANPM). In 2009 Eni and Joint Venture Partners Kogas and Galp Exploration & Production, relinquished around 25% of the permitted area, reducing the total area to 2,310 sq km, with S06-04 (E) covering around 1,810 sq km. The permit was the only valid licence in East Timor for a period of time, before an additional PSC (TL-SO-15-01) was awarded in December 2015. S06-04, which covers an area of 2,310 sq km, was awarded on 3 November 2006. Participants in the permit are Eni Timor Leste SpA (80% interest and operatorship) Korea Gas Corp (KOGAS) (10% interest) and Galp Energia Espana SA (10% interest). Companies interested in pursuing this opportunity should contact: Satyavan Reymond, Exploration Manager Email: [email protected]

(Bonaparte B.) Block E in Production Sharing Contract S06-04, operated by ENI (80%) and partners Galp (10%) + Kogas (10%), Eni is offering interested companies the opportunity to farm into or possibly acquire the block.

L-II ML block, onshore Cauvery Basin, gas cond discovery, tested 1.43 MMcf/d + 54 bc/d, no further details.

Vanjiyur-3 nfw in L-II ML block, onshore Cauvery Basin, gas cond discovery, tested 1.43 MMcf/d + 54 bc/d, no further details.

The National Agency for Mineral Resources (NAMR) plans to launche the Romania’s 11th licensing round in September 2019. A total of 28 blocks will be included in the licensing round – 21 onshore and seven offshore. The bid deadline is expected to be nine months from the gazetting of the tender call in the Official Journal of the European Union (OJEU).

The National Agency for Mineral Resources (NAMR) plans to launche the Romania’s 11th licensing round in September 2019. A total of 28 blocks will be included in the licensing round – 21 onshore and seven offshore. The bid deadline is expected to be nine months from the gazetting of the tender call in the Official Journal of the European Union (OJEU).

AIM-listed Egdon Resources has reached agreement on Heads of Terms in respect of a farm-out of interests in PEDL253 to Union Jack Oil and Humber Oil & Gas.  PEDL253 is located in Lincolnshire and contains the Biscathorpe Prospect, scheduled for drilling around mid-2018. Under the agreed terms, UJO and Humber will each acquire 6% of Egdon's interest in PEDL253 by paying their pro-rata share of the Biscathorpe-2 well cost plus an additional £10,000 per percentage point interest acquired.  This is equivalent to a farm-in with a 1.36 times promote at the estimated well cost.  UJO and Humber will also each acquire 4% of Montrose Industries interest in PEDL253 under the same terms. The Biscathorpe Prospect is located between Lincoln and Louth. It lies on the southern margin of the Humber Basin on trend with, and to the west of, the producing Keddington oil field (14 kms, Egdon operated) and the Saltfleetby gas field (20 kms). The Biscathorpe-2 well will target a down-dip area of the structure which was tested in a crestal position by the Biscathorpe-1 well drilled in 1987 by BP which found oil in a 1.2 metres thick sandstone of Westphalian (Carboniferous) age.  The structure has been mapped using reprocessed 3D seismic data and the sandstone is predicted to thicken to the north and east away from the Biscathorpe-1 well. The Mean Gross Prospective Resources at Biscathorpe are estimated by Egdon to be ca. 14 million barrels of oil and the well has been assessed by the Company as having a 40% chance of success.  The transaction is subject to contract and approval from the Oil and Gas Authority.  On completion the interests in PEDL253 will become: Egdon Resources U.K. (Operator) 40.80% (29.31% share of well cost*) Montrose Industries 27.20% (19.54% share of well cost*) Union Jack Oil  22.00% (37.57% share of well cost*) Humber Oil & Gas 10.00 % (13.57% share of well cost*) * at the current estimated well cost Mark Abbott, Managing Director of Egdon Resources, said: 'We are pleased to have achieved our objective of balancing our financial exposure and technical risk on the near-term Biscathorpe-2 well.  We welcome both Humber Oil & Gas as a new partner and UJO's increased participation in PEDL253.  We now look forward to drilling this high potential conventional oil prospect around mid-2018.' Click here for Union Jack Oil announcement: Proposed Farm-in for an Additional 10% Interest in the Drill-Ready Biscathorpe Prospect Commercial Partnership Memorandum Signed with Humber Oil & Gas Limited Oversubscribed Placing and Subscription to raise £1.25m   Original article link Source: Egdon Resources

United Kingdom (East Midlands Platform (Anglo-Dutch B.)) Saltfleetby

SW corner of Loma La Lata-Sierra Barrosa block, Neuquén Basin, TMD 3,765m, hitherto-unreported drilled + completed oil Jan-Aug '19. Fracked over 2,411-3,701m (horiz) in Vaca Muerta, test rates not revealed.

Argentina, Loma la Lata-Sierra Barrosa

According to reports in early-December 2019, the government of Neuquen Province has awarded a new 35-year unconventional exploitation concession for the Aguila Mora block to Vista Oil & Gas on 29 November 2019. Commitments for the new license include a two-year pilot plan targeting shale oil from the Vaca Muerta Formation for USD 32 million. Specifically, Vista is expected to reactivate three existing wells, drill two new horizontal wells, and construct new surface facilities as part of the program. The company operates the block with 90% interest, with provincial company GyP Neuquen holding the remaining 10% stake. Aguila Mora block covers 97 sq km of land in the Northeast Platform part of Neuquen Basin. The block is situated adjacent to ExxonMobil’s Bajo del Choique - La Invernada block where the Vaca Muerta shale is also being developed. Aguila Mora area includes the Aguila Mora shale oil and gas field that was discovered and put on-stream in August 2013. The field produced over 189 Mbo and 249 MMscfg, along with 129 Mb of water, from Vaca Muerta Formation before it was temporarily shut-in in late-2015. Background Information Vista acquired the Aguila Mora block from Shell’s Argentinean subsidiary, O&G Developments, in October 2018. The transaction was executed as an addendum to a prior agreement from September 2018 where Vista assigned 35% of its 45% non-operating interest to Shell on the latter’s operated Coiron Amargo Sur Oeste block.

Argentina, Coiron Amargo Sur Oeste

On 22 January 2020, Gazkop-Wilchwy Sp. z o.o. was granted the 2/2020 Wilchwy exploitation contract in southern Poland (Silesia). The contract is solely operated by Gazkop-Wilchwy, a company specialising in production and sale of the methane gas extracted from closed coal mines. The Wilchwy block is located in the Slaskie political province, some 40 km southwest of the city of Katowice. In a geological sense, the tract is situated within the Outer Carpathian Foredeep (surface area), with the targets of exploration located within the underlying Carboniferous series belonging to the Upper Silesian Basin (south of the limit of the NE German-Polish Basin). Background Information From October 2009 to December 2017, the Wilchwy area - contract 63/2009/p Wilchwy - was held by Pol-Tex Methane that was prospecting and producing gas from the Carboniferous coals.

Poland, not found

Effective 4 Dec ’17, AP signed for entry into the 2nd extn periods along with 50% area red’s of its SL-03 and SL-04A-10 licences and to modify the related work programmes. SL-03 now expires 23 Apr ‘19 and SL-04A-10  17 Sep ‘19 should the company (operating through 2 subs) commit to 1 well/block by prior to 1 Nov ’18 (Leo + Vega prospects identified). SL-03 drops from 1,930 sq km to 962 sq km, and SL-04A-10 from 1,995 sq km to 995 sq km. Map below prior to area change:

Sierra Leone, SL-04A-10

SIA Odin Energi Latvija is seeking to farm-out (likely negotiable) working interest in its offshore contract 2018/1. The acreage is marketed based on the presence of a shallow-water prospect (E17) that may contain reserve potential estimated to be approximately 78 MMbo. Interested companies should contact Tom Haselton at [email protected], tel.: +370 699 55 001. The 32 sq km block 2018/1 covers most of the E17 prospect, located in the Latvian territorial waters adjacent to the border with Lithuania. In a geological sense, the area is located within the Baltic Syneclise (Liepaja-Saldus Ridge/Liepaja Depression). Rightholding structure in the contract is Odin Energi Latvija (operator), Nostrum Oil & Gas Coöperatief U.A. and Geobaltic. Background Information The 2018/1 license was awarded on 9 January 2018 to Odin Energi Latvia as operator. The contract holds a 10-year exploration term and 20-year production period (overall duration of 30 years). Although little is known on the participation structure in the contract, is understood that the share of Odin and Nostrum in the license are comparable, with an insignificant working interest of Geobaltic and a 10% carried stake of Latvian Development Agency (LIDA). The award of the 2018/1 contract closed an invitation to bid for the area - designation 1/2017 - issued by the Ministry of Economics of the Republic of Latvia on 23 August 2017. In late July-early August 2019 Odin Energi Latvija acquired 2D seismic survey over the contract 2018/1. The project, conducted from by UAB Geobaltic, secured approximately 1,000 km of new seismic data.

SIA Odin Energi Latvija is seeking to farm-out (likely negotiable) working interest in its offshore contract 2018/1. The acreage is marketed based on the presence of a shallow-water prospect (E17) that may contain reserve potential estimated to be approximately 78 MMbo.

Hibiscus Petroleum Bhd is looking for a farm-in partner in its VIC/L31 licence, located in the Gippsland Basin. Hibiscus is farming out up to 50%. Hibiscus reports that an electronic data room is available, with interested parties required to sign a confidentiality agreement prior to gaining access. VIC/L31 covers an area of 34 sq km and was awarded on 5 December 2013. Carnarvon Hibiscus Pty Ltd, a wholly owned subsidiary of Hibiscus Petroleum Bhd, currently holds 100% interest and operatorship of the licence. It contains the Seahorse West oil field, which was discovered in November 1981. The field has estimated 2P recoverable reserves of around 8 MMbo. Two wells were planned for Q4 2015/Q1 2016 as part of the field development. However, the final investment decision (FID) was first deferred until mid-2017 and then to approximately 2020 in light of the current low oil price environment. Interested parties in the opportunity should contact: Mark Paton, Chief Business Development Officer Tel: +60 3 2092 1300 Email: [email protected]

Hibiscus Petroleum Bhd is looking for a farm-in partner in its VIC/L31 licence, located in the Gippsland Basin. Hibiscus is farming out up to 50%. Hibiscus reports that an electronic data room is available, with interested parties required to sign a confidentiality agreement prior to gaining access. VIC/L31 covers an area of 34 sq km and was awarded on 5 December 2013.

Equinor and Wellesley have completed a series of deals relating to assets in the North Sea. Wellesley has gained from Equinor a 45% operated interest in PL 090 JS (35/11), which covers the southwestern part of Grosbeak, and has increased its interests in both PL 884 (35/3) and PL 885 (35/3, 36/1) by 10%. PL 884 contains the Agat and Cyclops discoveries and Wellesley is understood to be considering drilling a further well at Agat in the near future. PL 885 lies immediately to the east and a well will be drilled on the Presto prospect in late 2018 / early 2019. Lastly, Equinor has gained a 10% interest in PL 903 (25/1, 30/10) from Wellesley. Wellesley has been building up its acreage position in the Grosbeak area over the last year or so. It drilled three new wells in the area in 2018 – the Serin dry hole, the Kallasen minor oil discovery and a successful Grosbeak West appraisal well. The latter – 35/11-21 S - proved a 90 m oil column (45 m net sandstone) in the Middle Jurassic Ness and Etive sections and was tested at a rate of 6,265 MMbo/d through a 48/64” choke. Sidetrack 35/11-21 A found a 45 m gas column in the Sognefjord Formation (20 m sandstone), a 1 m gas column above an 8 m oil column (2 m sandstone) in the Fensfjord Formation and a 50 m oil column (15 m sandstone) in the Ness Formation. Total recoverable reserves are estimated by the NPD at 50-120 MMbo plus 250-413 Bcfg, a significant increase on the previous volumes of 35-190 MMboe (based on the discovery well). Agat was discovered in 1980 by 35/3-2 which tested gas condensate from the Lower Cretaceous Agat Formation sandstone. An appraisal was drilled straight afterwards to the east but mechanical problems forced it to be junked. The well was re-spudded as 35/3-4 and was successful. Cyclops exploration well 35/3-7 S was drilled in 2009 by VNG and gas was encountered in the Agat Formation. Based on the results of this well, total estimated recoverable reserves for the whole Agat area (including 35/3-2 and 35/3-4) are 105-280 Bcf gas and therefore future development is possible. Equinor’s Presto well 36/1-3 will be located to the east of Agat and the prospect has potential recoverable reserves of 160 MMboe. The main objective is the 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. PL 903 covers the abandoned Frigg, Northeast Frigg and Odin fields. A re-development of these fields is being considered as part of the NOAKA project (Aker BP’s North of Alvheim area fields and Equinor’s Krafla and Askja area fields). Following completion of all deals, interests in PL 090 JS are divided between Wellesley Petroleum AS (45% + operator), Idemitsu Petroleum Norge AS (40%) and Neptune Energy Norge AS (15%), interests in PL 884 are held by Wellesley Petroleum AS (50% + operator), Cairn through Capricorn Norge AS (30%) and Equinor Energy AS (20%), 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%) and interests in PL 903 are held by Equinor Energy AS (90% + operator) and Wellesley Petroleum AS (10%).

Equinor and Wellesley have completed a series of deals relating to assets in the North Sea. Wellesley has gained from Equinor a 45% operated interest in PL 090 JS (35/11), which covers the southwestern part of Grosbeak, and has increased its interests in both PL 884 (35/3) and PL 885 (35/3, 36/1) by 10%.

PL 248 I, Viking Graben, 1km NW of Serin, P&A 9 Oct ’18, w.o. results, TD 2,931m, Transocean Arctic SS. Wellesley (op), partners Petoro + Capricorn.

035/11-21 A (Grosbeak West) in PL 248 I, P&A (results yet n/a).

S. part of Waitsia field area, permit L1/L2, onshore Perth Basin, compl. Aug ’15 at TD 3,530m, cleanup and testing underway, gauged 38.7 MMcfg/d from the Kingia sst (3,173-3,215m) on 80/64” choke, WHP 1,315 psi for 2.1 hrs. Of note, pay is 30% of that encountered in Waitsia-3 (50 MMcf/d), underling the strong performance of each well. Further testing is planned, after which Waitsia-4 will be flowed. Map: AWE.

Australia (Perth B.) Waitsia 2 op. by AWE (50.0%, ORIGIN EN 50.0%) in L 01 block

Ricocure has reportedly been awarded full explo rights to former BHP block 3B/4B, 17,500 sq km in the Orange Basin. It had been awarded under TCP terms in Feb ’17 in WD 300-2,500m. In parallel, sister South African company Sezigyn has reportedly been assigned its rights to the adjacent, former Shell Orange Deepwater Area, 37,400 sq km undrilled in the deepwater Orange Basin and under TCP terms since Nov ’17.

Ricocure has been granted exploration rights over Block 3B/4B that was relinquished by BHP in 2016.

Premier was the first to directly announce the award of a 2017-round direct-offer block, namely Andaman II in partnership with Mubadala + KrisEnergy (both 30%). The-7,400 sq km permit lies off Aceh in the N. Sumatra Basin. Plans are to acquire 3D seismic in the initial 3-year term, commitments G+G, gravity-magnetics, 1,850 sq km 3D seismic. The other direct offer contract signatures are as follows: Mubadala: Andaman I, 7,364 sq km, commitments G+G, 500 sq km 3D seismic PT Tansri Madjid Energi: Peacock-Lampung (Merak Lampung), 5,104 sq km, commitments G+G, 500km 2D PT Saka Energi Sepinggan: Pekawai (8,157 sq km) and West Yamdena (8,210 sq km), commitments G+G, 1 well Unallocated: South Tuna, commitments G+G, 1,000km 2D Of note, there are no awards under the regular tender mechanism (Kasuri III, Cob, East Tanimbar + Memberamo blocks).      

Premier Oil (40%, Mubadala 30%, Kris Egy 30%) was awarded Andaman II exploration block off. Aceh province.

Dayalpur / Hazarigaon fileds area, Additional Golaghat Extn II A PML, Assam Shelf, TD 2,681m, tested 2.84 MMcfg/d from between 2,497.5–2,499.5m  + 1.99 MMcfg/d from between 2,481.5–2,484m.

India (Assam Shelf) ? op. by ONGC (100.0%) in Additional Golaghat Extn II A PML block

Upland is reportedly studying ‘unsolicited’ farmin offers for its 4,004-sq km Saouf (Saouaf) block in N. Tunisia, in which 2D seismic and maybe explo wells are planned. ETAP is carried through exploration. The block is home to a couple of gas structures (Dekrila + Bou Dabbous) as well as the SNJ oil prospect.  ETAP has also approached Upland to envisage farming-into other specific, producing Tunisian oilfields.

Upland is reportedly studying ‘unsolicited’ farmin offers for its 4,004-sq km Saouf (Saouaf) block in N. Tunisia, in which 2D seismic and maybe explo wells are planned. ETAP is carried through exploration. The block is home to a couple of gas structures (Dekrila + Bou Dabbous) as well as the SNJ oil prospect.

President's acquisition from CGC of the Angostura block, 365 sq km in the Neuquén Basin, Río Negro, has been cleared by the authorities (DEA 21 Oct '19). The explo phase of the contract has also been extended 4 years from Nov '19. Angostura produces some 2.8 MMcfg/d + 50 bopd. www.presidentenergyplc.com.

President's acquisition from CGC of the Angostura block, 365 sq km in the Neuquén Basin, Río Negro, has been cleared by the authorities (DEA 21 Oct '19). The explo phase of the contract has also been extended 4 years from Nov '19. Angostura produces some 2.8 MMcfg/d + 50 bopd.

As part of its second quarter update on 9 July 2020, Noble Energy announced its entry into Egypt upstream exploration after being awarded a 27% non-operated working interest in the North Cleopatra and North Marina offshore concessions, in the Herodotus and Nile Delta basins. Other partners in the blocks are Shell and Tharwa Petroleum (separate article). This award reinforces Noble Energy's presence in the East Med. region where the company operates the Leviathan and Tamar fields in the Israeli waters.

Egypt (Herodotus and Nile Delta b.), Noble Energy announced its entry into Egypt upstream exploration after being awarded a 27% non-operated working interest in the North Cleopatra and North Marina offshore concessions. Other partners in the blocks are Shell (63%, op.) and Tharwa Petroleum (10%).

Add. DEA 21 Dec ’17 (status): AE-0080-2M-Cinturon Plegado Perdido-06 block, NE of Exploratus-1 discovery in GoM Basin, WD 2,685m, P+A dry 11 Dec ’17, La Muralla IV SS. PTD was 3,530m, target Miocene.

Mexico (Sureste B.) ? op. by PETRONAS (50.0%, ECOPETROL 50.0%) in 6 block

Vaalco has completed the latest, 2-well Gamba devt drilling campaign in the Etame field, namely Etame-9H + 11H. Each well is expected to produce initially 2,500-3,500 bo/d. Vaalco (op), partners Sasol, Addax, Tullow + PetroEnergy.

Vaalco has completed the latest, 2-well Gamba devt drilling campaign in the Etame field, namely Etame-9H + 11H. Each well is expected to produce initially 2,500-3,500 bo/d. Vaalco (op), partners Sasol, Addax, Tullow + PetroEnergy.

It has been reported in the media during May 2020, that Eni SPA could be looking to exit its Australia exploration and production position. A divestment process could be launched by end-May 2020 as the company is reported to be working with investment bank Citi to prepare the offering. It is thought that a divestment of its northern Australian portfolio could also include its Timor Leste position also. Eni's operations currently supply natural gas into the Australian Domestic market from the operated Blacktip gas field. Domestic markets are seen to be less exposed to the global demand and price fluctuations making the asset a stable, medium-term acquisition. Eni also holds an 11% stake in the Darwin LNG project, operated by ConocoPhillips (soon to be Santos). Both assets are in natural reservoir decline with Bayu-Undan gas and condensate field expected to cease around 2023. Darwin LNG is planned to be backfilled by the Barossa field, in which, Eni does not participate. Moving past 2023, production for Eni could be limited to the declining Blacktip field until new assets come on stream. The project could keep producing to the domestic market until around 2048. No financial investment decisions have been made for Eni's 'upside' projects including: Evan Shoals, Blackwood or Penguin. Any future development decisions would unlikely see gas production before in the next 10-15 years, but the portfolio is estimated to contain in excess of 700 MMboe of remaining resources (net to Eni). Near filed exploration or field de-development is another option to increase the upside of the portfolio from Eni's existing oil assets, such as Woollybutt and Kitan. Likely if sold, the assets could form one package, but could attract a consortium of buyers to handle the diverse nature of the assets across domestic gas production, LNG in Darwin and plant infrastructure. During Eni's time in Australia and Timor Leste, it has participated in over 90 wells, including 43 new field wild cats, since 1984. Moving to the northern Australian offshore basins in 2000, Eni is now thought to be preparing to divest its remaining gas assets.

Eni Australia Ltd, Eni Timor Leste SpA could be looking to divest its entire Australian gas portfolio

Committed well in P2378, Jæren High in CNS, WD 89m, P&A dry 28 Oct '19, West Phoenix SS. Target Fulmar sands. Equinor (op), partner Shell.

022/10b-09A (Lifjellet) nfw. (Equinor 75% op, Shell 25%) committed well in P2378, Jæren High, P&A dry. Target Upper Jurassic Fulmar sands. WD=89m.

Igiri Petr is offering to farm-down up to 80% (plus operatorship) of its full interest in PPL 523 and 532 in the south Fly Platform and central Papuan Fold Belt, respectively (see map). The partner would support 2 seismic survey and potentially an expl well in ’21. More from GEPS.

Igiri Petr is offering to farm-down up to 80% (plus operatorship) of its full interest in PPL 523 and 532 in the south Fly Platform and central Papuan Fold Belt, respectively (see map). The partner would support 2 seismic survey and potentially an expl well in ’21.

AE-0028-2M-Cotaxtla-01 block, SE of Ixachi find in onshore Veracruz Basin, assumed P&A dry late Nov ’18. PTMD was 7,722m, target M. Cret. Orizaba carbs.

Mexico, AE-0028-2M-Cotaxtla-01

Advent Energy Ltd announced on 28 September 2018 that it had signed a binding agreement to sell the majority shares in its wholly owned subsidiary Offshore Energy Pty Ltd to Bonaparte Petroleum Pty Ltd.  Bonaparte Petroleum has agreed to purchase 90% of the shares in Offshore Energy, currently held by Advent. The agreement is conditional upon board approval of both companies, Bonaparte Petroleum showing it has the capability to fund the work programme proposed in the transaction and potential shareholder approval, if required by the Australian Securities Exchange (ASX). Offshore Energy holds 100% interest in exploration licence EP 386 and retention lease RL 1, both located in the onshore Bonaparte Basin.  Bonaparte Petroleum has indicated that it has the capability to progress the licences, and under the terms of purchasing the shares has agreed to submit required documents for the drill of one or two exploration wells within EP 386, as well as acquiring 50 km new 2D seismic prior to the end of the current permit validity period, which concludes on 31 March 2020.  The company will also complete the decommissioning of two existing wells.   The work will be fully funded by Bonaparte Petroleum under the share acquisition. Further terms to the agreement include the issue of 10% interest, under a standard joint operating agreement, to Advent on the award of any subsequent retention or production licences over the current asset area. Under these terms Advent will earn a 10% share in Bonaparte Petroleum, and transfer the remaining shares in Offshore Energy to Bonaparte Petroleum.  A further 10% interest in any subsequent licences will be granted to Advent upon the discovery of 15 MMboe reserves. An option remains for Advent to buy back into REL 1. If EP 386 is not renewed or transferred to a retention or production licence, Advent will also be reinstated as operator and holder of RL 1. If Bonaparte Petroleum chooses not to proceed with the transaction outlined in the agreement reached on 28 September 2018, Advent will be paid a break fee of AUD 50,000. Advent Energy Ltd had been aiming to farm-out interest in the licences, alongside its other Australian asset PEP 11, located in the Sydney Basin.

Advent Energy Ltd announced on 28 September 2018 that it had signed a binding agreement to sell the majority shares in its wholly owned subsidiary Offshore Energy Pty Ltd to Bonaparte Petroleum Pty Ltd. Bonaparte Petroleum has agreed to purchase 90% of the shares in Offshore Energy, currently held by Advent.

Santos Ltd completed the sale of 50% interest and in exploration permit ATP 1177-P, located in the Bowen-Surat Basin, on 28 June 2018.  Orient (Denison Trough) Pty Ltd has acquired the interest, with Santos exiting the permit. The companies entered the agreement in April 2018, before it was registered by the Queensland State Government on 28 June 2018. ATP 1177-P was awarded to Santos QNT Pty Ltd and joint venture partner Australia Pacific LNG Pty Ltd on 29 November 2013 after being applied for in April 2013.  The permit was renewed in October 2017 and is due to expire, or be further renewed, in November 2021. Joint venture partner Australia Pacific LNG Pty Ltd holds 50% interest and has taken over operatorship on Santos’ exit. The permit contains the Yamala gas discovery, which was made in 1997.  There are also a number of dry wells to the north and south areas of the permit. ATP 1177-P, which covers an area of 315 sq km, was awarded on 29 November 2013. Now that Orient has completed acquisition of Santos’ interest, participants in the permit are Australia Pacific LNG Pty Ltd (50% + Operator) and Orient (Denison Trough) Pty Ltd (50%).

Santos completed the sale of 50% interest in exploration permit ATP 1177-P to Orient (Denison Trough).

Argentina’s planned offshore round 1 is tentatively set for a Jul ’18 launch, and has reportedly attracted the likes of Anadarko, CNOOC, Petronas, Shell or Statoil. The inventory is said to include some 5,000 sq km in the Austral Basin, 90,000 sq km in the Malvinas Oeste, and 130,000 sq km in the ‘Argentina Norte’, although acreage is still being delineated. It is recalled Spectrum and Searcher Seismic have been surveying the shelf and deeper waters in cooperation with YPF.

Argentina’s planned offshore round 1 is tentatively set for a Jul ’18 launch, and has reportedly attracted the likes of Anadarko, CNOOC, Petronas, Shell or Statoil. The inventory is said to include some 5,000 sq km in the Austral Basin, 90,000 sq km in the Malvinas Oeste, and 130,000 sq km in the ‘Argentina Norte’, although acreage is still being delineated. It is recalled Spectrum and Searcher Seismic have been surveying the shelf and deeper waters in cooperation with YPF.

Queensland’s Mines Minister has stated that the GLNG and APLNG joint venture partners have been granted 2 licences. The first, PRL2016/17-1A, 86 sq km, Bowen Basin, directly W. of Arcadia gas field, has been granted to Santos (op), along with GLNG partners Petronas, Total and Kogas, and the APLNG JV. Additionally, a yet-unnamed 95-sq km licence in the Surat Basin was awarded solely to the APLNG JV. Santos and APLNG confirmed the 1st award in separate statements, while the latter has yet to be confirmed.

Queensland’s Mines Minister has stated that the GLNG and APLNG joint venture partners have been granted 2 licences. The first, PRL2016/17-1A, 86 sq km, Bowen Basin, directly W. of Arcadia gas field, has been granted to Santos (op), along with GLNG partners Petronas, Total and Kogas, and the APLNG JV. Additionally, a yet-unnamed 95-sq km licence in the Surat Basin was awarded solely to the APLNG JV. Santos and APLNG confirmed the 1st award in separate statements, while the latter has yet to be confirmed.

Invictus has opened the Cabora Bassa project for offers, which involves the Mzarabani + Msasa prospects in block SG 4571, Rufunsa Basin. The 9.25-Tcf prospective resources have led Invictus to the offer of the 651-sq km permit, currently shared with Geo Assoc. (20%). Contact: http://envoi.co.uk/.

Zimbabwe, not found

Press of 7 September 2018, reported that the Uganda National Oil Company (UNOC) and China National Offshore Oil Corp (CNOOC) signed a Memorandum of Understanding (MoU) to jointly explore for oil and gas in the Albertine Graben. The block outline has not been disclosed but is located on the southern part of the Lake Albert. CNOOC already has interests in Uganda. It operates the PL01/2012 (Kingfisher) licence and has interest in production licenses (former Exploration Areas 1, 1A, 2 and 3A) : Kasamene-Wahrindi (PL01/2016), Kigogole-Ngara (PL02/2016), Nsoga (PL03/2016), Ngege (PL04/2016), Mputa-Nzizi-Waraga (PL06/2016), Ngiri (PL06/2016), Jobi-Rii (PL07/2016), Gunya (PL08/2016). Following Tullow farm-out deal to Total and CNOOC pre-emption rights, interests in the licences should be shared as follow: Total 44.12%, CNOOC 44.12% and Tullow with 11.76%. However, the companies have not yet received the governmental approval the complete the deal. The Lake Albert Development Project aims to develop 1.4 Bbbl of oil equivalent recoverable resources from the Albertine Graben for a cost of USD 5.2 billion with first production starting in 2021 at plateau rates of 230k b/d. The project’s Final Investment Decision (FID) is expected in the second half of 2018, with first oil expected 36-months after the FID. The oil production will be exported through the so-called East African Crude Oil Pipeline which is expected to be completed by 2021. Uganda is also planning to construct a refinery at Hoima with a capacity of refining 30,000 b/d to cater for demand of petroleum products in East Africa.

Press of 7 September 2018, reported that the Uganda National Oil Company (UNOC) and China National Offshore Oil Corp (CNOOC) signed a Memorandum of Understanding (MoU) to jointly explore for oil and gas in the Albertine Graben. The block outline has not been disclosed but is located on the southern part of the Lake Albert. )

7 October 2018, Total E&P and Uzbekneftegaz (UNG) signed a co-operation agreement providing for studies of opportunities for joint exploration work in the investment blocks in Uzbekistan. A joint working group will be established within the framework of this agreement which will prepare specific proposals for further development of co-operation. The new agreement is preceded by a confidentiality agreement regarding information on the investment blocks signed by the two companies in September 2018. Uzbekistan offers 22 E&P investment blocks across all its petroleum basins on an open negotiations basis.

Uzbekistan, not found

By decree of 21 November 2017 the Ministry of Economic Development canceled the Masseria Montarozzo exploration permit held by Cygam Energy Italia in the Puglia region for non-fulfillment of contractual obligations. The company, whose Italian subsidiary was dissolved in November 2016 following its bankruptcy in 2016, failed to drill an exploratory well as required by the commitments of the permit. The effective date of the cancelation is 1 November 2015. Cygam Energy Italia was awarded the Masseria Montarozzo exploration permit on 11 October 2013 for six years. Commitments included the re-processing of 50 km of 2D seismic data in the first period and the drilling of a 1,400-m exploration well in the second period. The 155-sq km permit was located to the south-east of Foggia in the Bradano Basin. The main objective in the area is gas in Pliocene sandstones. Cygam Energy filed a voluntary assignment in bankruptcy in Canada in 2015. Cygam Energy Italia SpA was operating the Masseria Montarozzo exploration permit with a 100% interest.

Italy (Southeast Peri-Apenninic Foredeep Province) (It's a petroleum rights. Please summarize by yourself). In IHS database: Masseria Montarozzo op. by CYGAM EN (100.0%) to be check.

CNOOC spudded an exploration well called 206/21-1 targeting the Howick prospect in licence P2298 on 31 August 2019. Howick was thought to have a derived a mean recoverable volume of 74 MMboe. The well was drilled with the “Island Innovator”. Operations wrapped up around the 17 October 2019 with the rig moving off location on 18 October 2019. The prospect is a 4-way dip closure with Cretaceous and Jurassic target intervals of thick, sandy reservoirs. The reservoirs consist of the Lower Cretaceous Victory Formation and Middle Cretaceous Commodore Formation deposited in a shallow marine environment. The reservoirs are sourced by the Kimmeridge Clay Formation with the hydrocarbon phase interpreted to be oil. The Howick prospect has a CoS of 39%. A further Middle-Upper Jurassic reservoir forms a secondary target. Dunstan, Swinho and Embleton are additional leads that lie within the acreage which CNOOC estimate to hold 60 MMboe mean recoverable resources. Howick is interpreted through a full Pre-Stack Depth Migrated, broadband processed 3D seismic data set. P2298 is held solely by CNOOC Petroleum Europe Ltd.

United Kingdom, P2298

OKEA has agreed to acquire Equinor's 40% operated stake in Aurora discovery licences PL195 and PL195 B, as released on 15 July 2020. The deal will be effective from 1 January 2020, subject to approval by the Ministry of Petroleum and Energy. Aurora gas discovery 35/8-3 (1988, Gulf, 3,944m) is located 24km W of the Gjøa Field and has estimated recoverable resources of 12-28 MMboe in 31.9m net pay (70m gross) of Middle Jurassic Intra Heather Formation sandstone. Average porosity in the reservoir quality sand was 15.6% with an estimated average water saturation of 22%. OKEA intends to develop Aurora via tie-back to Gjøa, and without further appraisal drilling to limit costs. Gjøa is operated by Neptune Energy (OKEA 12% partner) and currently under redevelopment (P1 segment), due online late 2020/early 2021. 6km NE of Gjøa is the Duva Field which is also currently being developed. PL195 covers 30 sq km of block 35/8 and was awarded in the 14th Round on 10 September 1993. PL195 B (15 sq km of block 35/8) adjacent to the SW was awarded in APA 2005 on 6 January 2006. Pending OKEA farm-in completion, PL195/B partners are Equinor Energy AS (40% + Op), Petoro AS (35%) and Wintershall Dea Norge AS (25%).

Norway (Viking Graben Province), PL 195, OKEA has agreed to acquire Equinor’s 40% operated interest in PL195 + 195 B (Aurora discovery) west of Gjøa, deal to be retro-effective 1 Jan '20. Partnership to become OKEA (op), Petoro + Wintershall Dea. Aurora is planned to be tied-in to Gjøa.

Summit Petroleum is offering the opportunity for interested partners to farm-in to licence P2382 (block 22/14c) containing the drill ready K2 prospect. A site survey was carried out over the prospect in June 2019 with a view to drill the well in 2020 however the well could be delayed but is required to be drilled before October 2022. The K2 prospect lies immediately southwest of the Everest gas field and northeast of Huntington and is a four-way dip closure. The prospect is thought to be separated from Everest by a saddle with both K2 and Everest having similar AVO responses which isn’t seen on the saddle. The primary reservoir is the Forties Sandstone reservoir with the K2 prospect thought to hold 29 MMboe (base case resources). There is a deeper Mey Sandstone anomaly which could contain 15 MMboe recoverable resources. Other prospects exist in the block – one is Rustler and the other Rattler which exhibit DHI's and could add further resources of 58 MMboe at a later date. Planned well costs are estimated at GBP 12.8 million (dry hole) with any development having lots of options including tie-backs to Everest, Huntington, Arran, Nelson and Forties. Summit is offering a minimum of 25% interest and maximum of 40% interest and is open to negotiation. Interest in the licence is currently held by Summit Exploration and Production Limited (75% + operator) and Ping Petroleum UK Limited (25%).

Summit Petroleum is offering the opportunity for interested partners to farm-in to licence P2382 (block 22/14c) containing the drill ready K2 prospect.

PEMEX plugged and abandoned dry the Sejel 1EXP directional new-field wildcat (NFW) in the AE-0055 block in the onshore Sureste Basin during late-June 2019.   The well reached a final total depth (TD) of 7,100 m. The NFW was spudded on 17 December 2018.   The well had a proposed total depth (PTD) of 6,998 m and the primary target was the Jurassic.   The NFW will attempt to extend the successful deeper Jurassic plays in the area like Bricol, Chinchorro, Palangre, Pareto, and the most recent discovery Chocol in March 2017.     The NFW has prospective resources of 58 MMboe.  The prospect is located in the south-central area of the block, on trend with and approximately 6.6 km south-east of the Chocol 1 NFW oil and gas discovery completed in early-2017. A drilling permit for the well was granted by the CNH on 3 October 2018. SENER granted the AE-0055-4M-Mezcalapa-05 entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block covered an approximate area of 971.9 sq km but now covers an area of 658.6 sq km after two area reductions. PEMEX suspended as an oil and gas discovery the Chocol 1 directional new-field wildcat (NFW) in the AE-0055 block in the onshore Sureste Basin on 8 April 2017.  PEMEX reported in late July 2017 that the well tested 5,308 bo/d and 4 MMcfg/d.  The operator tested oil and gas from the Cretaceous objective from 5,089 m to 5,549 m.  The NFW reached a total depth (TD) of 7,213 m measured depth (MD) and 6,888 m true vertical depth (TVD) during early December 2016. The operator spudded the well on 22 February 2016. It had a proposed total depth (PTD) of 7,368 m measured depth (MD) and 7,012 m true vertical depth (TVD). The Cretaceous and Upper Jurassic formations were the primary objectives.  The well is located in the western central area of the block.  It is also located 6.7 km northeast of the Pareto field discovery and 7.8 km east of the Tupilco field.  The prospect will attempt to reach reservoirs below a high angle normal fault located over a small salt structure.  The area is an extensional province with salt structures and salt withdrawal grabens.  The NFW is a high temperature, high pressure well with temperatures estimated at about 160° C and a bottom hole pressure of 16,700 psi. The prospect size was reported to be 87 MMboe.  On 9 February 2016, the CNH approved plans by PEMEX to drill the Chocol 1.

Sejel 1EXP directional new-field wildcat (NFW) in the AE-0055 block onshore, P&A, dry.

PEDL 253 in Central Lincolnshire, E. Midlands, TD 2,133m, drilled with oil shows in Jan-Feb ’19 (see DEA 21 Feb ’19), recent petrophysical analyses found hydrocarbon saturations of greater than 50% in the upper parts of the Dinantian, with good quality oil extracts obtained from the Westphalian and Dinantian. A side-track (targeting the Dinantian interval) may still be on the cards. Egdon (op), partners Montrose, UJO + Humber O&G.

Suspended: Biscathorpe-2 expl in PEDL 253 in Central Lincolnshire, E. Midlands, TD 2,133m, drilled with oil shows in Jan-Feb ’19 (see DEA 21 Feb ’19), recent petrophysical analyses found hydrocarbon saturations of greater than 50% in the upper parts of the Dinantian, with good quality oil extracts obtained from the Westphalian and Dinantian. A side-track (targeting the Dinantian interval) may still be on the cards. Egdon (op), partners Montrose, UJO + Humber O&G.

MOL used the “Deepsea Bergen” S/S to drill an exploration well on its Evra and Iving prospects in PL 820 S located between the Jette and Ringhorne fields. 25/8-19 S was spudded on 2 November 2019 and was drilled to TD at 2,760 m. Pre-drill potential recoverable reserves are 181 MMboe (source: Lundin, October 2019). Evra is an injectite prospect, with remobilised Paleocene Hermod Sandstones expected in the Eocene Hordaland Group. Two sand bodies were expected – one at 1,783 m and the other at 2,023 m. The main objective for the Iving prospect (four-way closure at the BCU) was the Lower Jurassic Statfjord Formation at 2,207 m. There were also further targets in the Paleocene Ty Formation, the Triassic Skagerrak Formation and the Basement. The drilling plan called for a sidetrack (targeting Evra only with a planned TD of 2,104 m / 2,000 m TVD) if the well made a discovery at Evra and on 31 December 2019 MOL kicked off 25/8-19 A which is designated as an appraisal, indicating that a discovery has, indeed, been made. Operations are continuing on 10 March 2020. PL 820 S contains the 2001 dry hole 25/8-13 which was drilled by Esso. Good reservoir sands were present in both the Ty Formation and the Statfjord Formation, although both were water-bearing. MOL Norge AS operates PL 820 S with a 40% interest. It is partnered by Lundin Norway AS (40%), Pandion Energy AS (10%) and Wintershall Dea Norge AS (10%).

025/08-19 S (Evra/Ivring) expl. (MOL 40% op, Lundin 40%, Pandion 10%, Wintershall Dea10%),1st well in PL 820 S, location between Jette + Ringhorne fields, WD=125m, industry rumours suggest a positive outcome. Evra is an injectite prospect, with remobilised Paleocene Hermod Sandstones expected in the Eocene Hordaland Group.

Hitherto unreported, on 25 February 2020, the Ministry for Innovation and Technology signed off the concession agreement pertaining to the Pusztaszer area in southeastern Hungary, granted to Hungarian Horizon Energy Group (HHE). The contract has a four-year exploration term, with an option for a two-year extension, and the utimate validity of 20 years (includes production stage), until 25 February 2040. HHE is the sole operator of the contract. The 1,326 sq km Pusztaszer area is located within the Kiskunsag Sub-basin, tectonic unit of the Pannonian Basin. The Ministry informed on 4 December 2019 that HHE was pronounced the winner of the 2019 tender call for the Pusztaszer area. HHE is acting in the country through Hungarian Horizon Energy Kft, Background Information The 2019 bidding round was opened by the Ministry for Innovation and Technology on 28 May 2019 through the announcements in the EU Official Journal. Eight areas were offered in the tender: Csongrad, Csorna, Erd, Kadarkut, Kisvarda, Nyirbator, Pusztaszer and Zala-Kelet. The closing date for the round, area-dependent, was set on 25/26 September 2019. On 25 September 2019, the Ministry for Innovation and Technology closed the tender procedure for the Pusztaszer block.

Hungary (Pannonian B.) Pusztaszer op. by HHE (100%)

Argentina’s planned offshore bid round is to be launched in October, bid opening Feb ’19.  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 [email protected] or +54-911-6648-9244.

Argentina’s planned offshore bid round is to be launched in October, bid opening Feb ’19. 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.

Faroe spudded appraisal well 31/7-3 S at Brasse East in PL 740 on 20 November 2018 using the “Transocean Arctic” S/S. It was targeting potential recoverable reserves of 12.5 MMboe on the eastern flank of the Brasse field, identified following recent seismic reprocessing and re-interpretation work. The well reached TD at 2,705 m (2,247 TVDSS) and is a dry hole. Water-wet sands were encountered in a Jurassic reservoir (48 m) with excellent reservoir quality. On 17 December 2018 sidetrack 31/7-3 A was kicked off targeting incremental reserves of 61 MMboe in the main Brasse reservoir. The well reached TD at 2,863 m (2,254 m TVDSS) and encountered oil. It penetrated around 40 m of Jurassic reservoir and reservoir depths and hydrocarbon contacts were similar to what was prognosed. On 9 January 2019 Faroe was performing logging operations. Brasse discovery well 31/7-1 was drilled in 2016 and proved a 21 m oil column plus an 18 m gas column in the Jurassic Fensfjord Formation. Sidetrack 31/7-1 A was drilled to appraise the southeastern part of the discovery and confirmed oil and gas columns of 25 m and 6 m respectively. In 2017 Faroe appraised the find with 31/7-2 S, which confirmed a 9 m oil column in the Sognefjord Formation and on test flowed at a maximum rate of 6,187 bo/d through a 1” choke from a 3.6 m perforated interval, and 31/7-2 A which proved an 18 m oil column plus a 4 m gas column. Both wells have the same OWC as the discovery well (2,172 m), although 31/7-2 A has a deeper GOC (2,154 m), and there is good pressure communication between all wells. Reserves have been upgraded from 43-80 MMboe to 56-92 MMboe (46-76 MMbo plus 59-97 Bcfg). Faroe is progressing plans for development as a subsea tie-back to either Brage or Oseberg and envisages 3 - 6 production wells plus a potential water injector. It believes that it could achieve a rate of 30,000 boe/d with first oil in 2021 / 2022. Capex is forecast at USD 500-700 million (based on four wells and one subsea template) and the final concept selection will take place in 2018 with PDO submission likely in 2019. Interest in PL 740 is divided between Faroe Petroleum Norge AS (50% + operator) and Point Resources AS (50%).

Faroe Petroleum plc PL 740 - 31/7-3 S (Brasse East), 31/7-3 A (Brasse North) appraisal wells - Dry hole and logging in oil appraisal

Shell has announced one of its largest U.S. Gulf of Mexico exploration finds in the past decade from the Whale deep-water well. The well encountered more than 1,400 net feet (427 meters) of oil bearing pay. Evaluation of the discovery is ongoing, and appraisal drilling is underway to further delineate the discovery and define development options.  'Deep water is an important growth priority as we reshape Shell into a world-class investment case,' said Andy Brown, Upstream Director for Royal Dutch Shell. 'Today’s announcement shows how, through exploration, we are sustaining a strong pipeline of discoveries and future projects to sustain this deep-water growth.' Whale is operated by Shell (60%) and co-owned by Chevron U.S.A. Inc. (40%). It was discovered in the Alaminos Canyon Block 772, adjacent to the Shell-operated Silvertip field and approx. 10-miles from the Shell-operated Perdido platform. 'Whale builds on Shell’s successful, nearly 40-year history in the deep waters of the Gulf of Mexico and is particularly special in that it offers a combination of materiality, scope and proximity to existing infrastructure,' said Marc Gerrits, Executive Vice-President Exploration for Royal Dutch Shell. 'The result is another opportunity to think differently about ways we can competitively develop deep-water resources.' This major discovery in a Shell heartland adds to the company’s Paleogene exploration success in the Perdido area. Through exploration, Royal Dutch Shell has added more than one billion barrels of oil equivalent resources in the last decade in the Gulf of Mexico. Shell currently has three Gulf of Mexico deep-water projects under construction – Appomattox, Kaikias, and Coulomb Phase 2 – as well as investment options for additional subsea tiebacks and Vito, a potential new hub in the region. The Shell group expects its global deep-water production to exceed 900,000 boe per day by 2020, from already discovered, established areas. Shell announces large deep-water discovery in Gulf of Mexico Background Drilling operations for the Whale well were completed in June 2017 to a depth of approx. 22,948-feet (measured depth). The Whale discovery is located approx. 200-miles (322 kms) southwest of Houston in approx. 8,000-feet of water. Original article link Source: Shell

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

It is thought that Hydrocarbon Finder LLC (HCF) was drilling an exploratory well in its onshore 1,390 sq km Block 15 (Jebel Aswad) licence between October 2017 and January 2018, however official details are yet to be reported. The well is believed to be located in the southern part of the block, near to the border of Block 27 (Wadi Aswad), and roughly 6.5 km northeast of Occidental’s Nasiyah Far East 1 discovery well which completed as a Cretaceous Natih Formation producer in 2015. According to the website of HCF on 7 March 2016, the company is planning to undertake a subsurface evaluation of the Jebel Aswad area in Block 15 (Jebel Aswad). It will also evaluate new leads and prospects, as well as looking at deeper reservoir potential in existing structures. Furthermore, in late-2016, HCF reported that it will commence a study to assess unconventional potential in the block however, as of November 2017, no further updates were available. In early-2016, a Royal Decree was issued endorsing Tethys Oil Ltd to concede 100% of its share of the Block 15 (Jebel Aswad) licence to ODIN Energi A/S (article 1), as well as endorsing Odin Energi A/S to concede 90% of its share quota, to HCF (article 2). The decree was enforced on the date of issue of the Official Gazette in which it was published. Therefore, HCF (operator) owns a 90% share in the Block 15 (Wadi Aswad) licence, Odin Energi A/S holds the remaining 10%.     

It is thought that Hydrocarbon Finder LLC (HCF) was drilling an exploratory well in its onshore 1,390 sq km Block 15 (Jebel Aswad) licence between October 2017 and January 2018, however official details are yet to be reported. The well is believed to be located in the southern part of the block, near to the border of Block 27 (Wadi Aswad), and roughly 6.5 km northeast of Occidental’s Nasiyah Far East 1 discovery well which completed as a Cretaceous Natih Formation producer in 2015.

Hitherto unreported in late March 2019 Edison International SpA (Edison) farmed out 70% of its 100% interest in the Northeast Hapy Offshore exploration block to Eni subsidiary International Egyptian Oil Co (IEOC). IEOC becomes operator. Edison was awarded the the 2,458 sq km block in 2015 and operated it alone. The company had a commitment to spend a minimum of USD 86 million and drill three wells. Edison has paid a signature bonus of USD 1.5 million. NE Hapy Offshore Block is traversed by minor faults formed by the interplay of the three major fault trends (Temsah Fault Trend, Rosetta Fault Trend & Hinge Zone Faults) affecting the Nile Delta Basin. These faults are anticipated to play an important role in shaping the prospectivity of the block. The Block lies to the east of BP’s recent Oligocene gas & condensate discoveries of Salamat and Atoll. Edison is understood to sell its exploration & production unit to focus on the retail operations of gas and electricity. Edison's main E&P activities are in Egypt, Italy and the North Sea (Norway and UK) with other operations in Algeria, Croatia, Falkland Islands and Israel. The company’s E&P assets are estimated at USD 2-3 billion. Edison assets in Egypt were as follows. Exploration concessions: North Thekah Offshore and North East Hapy Offshore deep-water exploration blocks in the east Mediterranean. Edison holds also a 100% interest in the concessions. Development leases: Abu Qir, North El Amirya and North Idku concessions in the Nile Delta offshore.  Edison holds a 100% interest in the concessions and also a 20% PI in the Rosetta offshore production license operated by Shell.

Edison International SpA (Edison) farmed out 70% of its 100% interest in the Northeast Hapy Offshore exploration block to Eni subsidiary International Egyptian Oil Co (IEOC).

On 6 June 2019, Eni’s partner New Age (African Global Energy) Ltd via its local subsidiary New Age M12 Holding Ltd (New Age) in the shallow offshore Marine XII licence (Litchendjili Marin, Minsala, Nene-Banga and Nkala) agreed to sell its 25% stake in the licence to Lukoil for USD 800 million (all-cash deal). The deal is subject to the approval by the government of the Republic of Congo. Eni Operates the blocks with a 65% interest, New Age and SNPC hold 25% and 10% interest respectively. Nene and Litchendjili fields were put on stream in early 2015. The current production (May 2019) was reported at 28,000 boe/d (oil, condensate and gas) with 60 MMscf/d of marketable gas. The license covers five discovered fields containing 1.3 Bboe (2P) reserves according to international independent auditor. New Age said that the sale of its position in Marine XII will be utilized to further strengthen its balance sheet and to redeploy into earlier stage opportunities within its African portfolio, including the Marine III license which is also in the Republic of Congo. Background information In late November 2018 New Age was reported to be looking to sell its interest in the permit. The company hired vercore and Bank of America Merrill Lynch to help with the sale (initially reports suggested the sale may raise in the region of USD 1 billion). According to reports Lukoil is expected to secure New Ages stake for between USD 300 and 500 million. When the deal is finalized it will mark Lukoil’s entrance into Congo (Brazzaville).

Lukoil has agreed to buy NewAge's entire 25% stake in the Marine XII block (Eni op. 65%, SNPC 10%) for US$800 MM.

Mumbai High-SW ML, Bombay offshore, tested 783 bo/d + 2.77 MMcfg/d from between 2,448.5­­­­­–2,450.5m in the Mukta fm, and 125 bo/d + 180 Mcfg/d from between 2,377–2,379.5m in the Heera fm. PTD was 2,515m, Aban Ice DS.

B-203-2 (B-203#B) (ONGC 100%) in the Saurashtra-Dahanu block, oil and gas discovery. On testing, the well flowed oil at 783 b/d and gas at 2,77 MMcf/d from the Mukta Sst Fm of Early Oligocene age. A limestone interval in the Heera Fm Early Oligocene age also flowed oil at 125 b/d and gas at 0,183 MMcf/d.

On 18 May 2020, CNOOC offered 15 blocks with a total area of 9,453 sq km under the CNOOC 2020 Offshore China Open Block Tender. The bid round will close on 31 October 2020. The bid round will be held under the Regulations of the People's Republic of China on the Exploitation of Offshore Petroleum Resources in Cooperation with Foreign Enterprises. In the Announcement of Notification for Bidding Blocks Offshore China of 2020 it is stated CNOOC is willing to be “flexible” in negotiating certain terms stating: “In 2020, CNOOC will innovate cooperation modes with foreign enterprises and expand the scope of partners while continuing to uphold the vision of win-win cooperation. In the meantime, for deep water areas and deep formation, CNOOC will adopt flexible and preferential business arrangements in terms of exploration period, relinquishment, signature fee, participating interest and X factor [profit petroleum share] in the hope of achieving the goals of expanding cooperation with foreign enterprises and enhancing foreign investments in China offshore oil and gas exploration and development”.Although the base terms for the bid round have not been stated, it is understood the generic terms that apply under a production sharing contract are:->State participation of 51%.->Signature bonus.->Oil royalty based on annual production tranches at rates between 0% and 12.5%.->Gas royalty based on annual production tranches at rates between 0% and 3%.->Environmental Protection Tax based on rates of emissions of polluting substances.->Cost recovery ceiling of 50% to 62.5% (dependent on royalty rate).->Contractor profit share based on average daily production with effective rates in the range 49% to 29% (after state participation).->Income tax rate of 25%.->Special Oil Gain Levy applies to all production whenever the weighted average price of crude oil sold in any month exceeds US$ 40 per barrel for months before 1 November 2011, US$ 55 per barrel for months before 1 January 2015 and US$ 65 per barrel for months after 1 January 2015 (in the range 20% to 40%).->VAT at a rate of 5% payable on crude oil and gas production. The general rate on purchases is 16%.->Other minor taxes including withholding taxes on dividends, royalty payments, etc.<P />

n 18 May 2020, CNOOC offered 15 blocks with a total area of 9,453 sq km under the CNOOC 2020 Offshore China Open Block Tender. The bid round will close on 31 October 2020.

Perupetro in the first half of 2019, plans to offer and complete the award on three blocks with hydrocarbon potential. In the next few months, Perupetro will begin the bid process for the blocks, according to the company president Seferino Yesquen. He also said the offering would prove Perupetro's, "ability to attract investment." One of the blocks to be offered includes part of the former Block 126 in the Ucayali Basin. This is the location of the undeveloped Sheshea 1X undeveloped discovery that tested 1,450 bo/d. The discovery area will be put together with other surrounding open areas to form a new block. The other two blocks will be in the onshore Tumbes Basin and despite being smaller in size, they have already aroused the interest of two companies that are not small. The two companies have expressed interest in gas exploitation in the Talara Basin with a possible eye to supplying gas to Ecuador. Yesquen announced that the bidding process for these three areas will be done quickly beginning in the first quarter of 2019 with the award process completed within six months. Yesquen said that there are already companies interested in all the areas.

Not Found

Octant is looking to dilute its 100% in block L17/L17, 4,794 sq km mainly offshore in the Lamu Basin off S. Kenya, a data room open believed in London. Octant is otherwise engaged in Kenyan block 1 and in Tanzania.

Octant is looking to dilute its 100% in block L17/L17, 4,794 sq km mainly offshore in the Lamu Basin off S. Kenya, a data room open believed in London. Octant is otherwise engaged in Kenyan block 1 and in Tanzania.

According to local media reports, quoting the Deputy Head of SKK Migas, Petronas Carigali, operator of Muriah PSC, located in offshore East Java, is in discussion with its partner Saka Energi (subsidiary of PT Perusahaan Gas Negara, PGN) on the possibility of changing management role in the block. Saka Energi may continue production from the Kepodang field if taking over operatorship of the PSC, with a limited production volume of 20 MMcfg/d for a period up to three months, due to limited remaining reserves in the field. Petronas suspended gas supply from Kepodang on 23 September 2019. According to PGN, the supply was interrupted on the grounds of the termination of the Gas Sales Agreement (GSA) between Petronas Carigali and buyer PT Perusahaan Listrik Negara (PLN). The GSA termination has also led to the end of the gas transportation agreement through the Kalija I pipeline network operated by PT Kalimantan Jawa Gas, a PGN affiliate company. Gas produced from Kepodang was supplied to the Tambak Lorok power plant operated by PLN. Under the GSA signed in 2012, the daily contract quantity was 116 MMcfg/d, however the field was unable to meet the contracted volumes due to insufficient gas reserves. Gross production from the field in 2018 was approximately 50 MMcf/d. In July 2017, Petronas requested force majeure due to the field being unable to fulfill the daily contract quantity. According to a material balance analysis conducted by government oil and gas research agency Lemigas in 2017, gas resources were estimated at only 107 Bcfg whereas the total sales volume from the approved Plan of Development (POD) amount to 354 Bcfg. First production from Kepodang was achieved in 2015 at an initial rate of 56 MMcfg/d. Petronas Carigali is operator of the Muriah PSC with 80% interest and PGN is holding a 20% participating interest via its upstream arm Saka Energi. Background Information The Kepodang field, as the Keladi discovery has been labeled, is located about 180km north-east of Semarang in Central Java, in water depths of between 60-70 meters. The field was originally discovered by Cities with the JS 15-1 well in 1971. This wildcat tested 11.45 MMcf/d from Lower "OK" sandstones and 10.54 MMcf/d of CO2 from Kujung Unit III carbonates. Conoco's Kepodang 1 wildcat in 1981 and Shell's Keladi 1 wildcat in 1993 both confirmed the discovery, and the field was successfully delineated by BP in 2001 with a three well programme. A MOU for gas supply to Tambak Lorok was signed between BP and PLN in July 2001. First gas from the field was initially scheduled for late 2014, as per the GSA signed in June 2012 with buyer PT PLN, having an effective date 30 months after the signing. Gas price has been set at USD 4.61 per MMBtu, with an annual escalation of 8.6% plus transport fees. The field eventually came onstream in August 2015 at an initial rate of 56 MMcfg/d. The field has been developed through a Central Processing Platform and a Wellhead Platform. Gas production was transported via pipeline to the onshore facility and supply gas for the Tambak Lorok power plant in Central Java.

According to local media reports, quoting the Deputy Head of SKK Migas, Petronas Carigali, operator of Muriah PSC, located in offshore East Java, is in discussion with its partner Saka Energi (subsidiary of PT Perusahaan Gas Negara, PGN) on the possibility of changing management role in the block. Saka Energi may continue production from the Kepodang field if taking over operatorship of the PSC, with a limited production volume of 20 MMcfg/d for a period up to three months, due to limited remaining reserves in the field.

Emperor Energy has agreed to sell its rights to the Cryano R3 offshore retention lease, 80 sq km in the Carnarvon Basin, to BR Cyrano Pty Ltd for AUD 325,000 subject to deal approval by 31 Dec ’19.

Emperor Energy has agreed to sell its rights to the Cryano R3 offsh retention lease (80km²), to BR Cyrano Pty for AUD 325,000

Equinor has completed the acquisition of Barra Energia’s 10% in block BM-S-008 for USD 379 MM, and also assigned 6.5% to ExxonMobil and Galp. The deal had been announced a year ago and aimed at aligning the partners’ interests across the two licences for the Carcará area, Santos Basin. Resulting partnership in BM-S-008 and Carcará North are therefore Equinor (op) 40%, Exxon 40%, Galp 20%.

Equinor (op,->40%) has completed the acquisition of Barra Energia’s 10% in block BM-S-008 for USD 379 MM, and also assigned 6,5% to ExxonMobil (->40%) and Galp (->20%).

On 28 October 2019, the Argentine government granted an exploration permit for AUS-106 block to Equinor through the publication of Resolution 676/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Work program in the first exploration period of four years consists of 2D seismic acquisition of 32 km, 3D seismic acquisition of 1,500 sq km, and 2D gravimetry and magnetometry acquisition of 3,000 km, followed by a drilling commitment for one well in the second exploration period of three years. An optional third exploration period of four years is possible, although accompanied by a 50% partial relinquishment. Equinor will operate the block with 100% participating interest. AUS-106 covers 2,279 sq km of areas, respectively, on the continental shelf of Austral Basin with approximated water depth of up to 80 m. Exploration target for the block is expected to be oil and gas in the Springhill Formation. The formation has been proven to be a producer in several gas fields in the Austral Basin, although no discoveries have been made in the area of AUS-106. Equinor won the rights for the block after submitting an offer of USD 22.87 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019.  Beside AUS-106, Equinor also received 100% operatorship on the adjacent AUS-105 block, along with MLO-121 block in Malvinas Basin and CAN-108 block in Argentina Basin. In addition, the company won CAN-102 and CAN-114 in Argentina Basin in a partnership with state company YPF, as well as MLO-123 block in Malvinas Basin as part of a consortium with YPF and operator Total. Background Information The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.

On 28 October 2019, the Argentine government granted an exploration permit for AUS-106 block to Equinor

LF 13-9-1 completed in early August 2020 without result reported. CNOOC – Shenzhen spudded a new-field wildcat in the Pearl River Mouth Basin, South China Sea, in early July 2020. LF 13-9-1 is located in the Lufeng Sag, in the north of LF 13-1, in a water depth of 120 m area. The well is believed to be targeting the Mio – Oligocene clastic play. “Nanhai 5” S/S is used for the drilling operation. LF 13-1 field has primary reservoir in the Zhujiang Formation and secondary one in the Oligocene Enping Formation. The field has been producing since 1993 and produced at a rate of 5,200 bo/d in 2018. In the north of the LF 13-1 field, CNOOC drilled two well, LF 13-1N-1 in 2017 and LF 13-1NE-1 in 2014, both wells are dry. The Lufeng Sag is 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 early 2020, CNOOC has drilled LF 7-3-1, LF 7-8-1 and LF 9-8-1, wells completed without result reported. In June 2019, CNOOC made two discoveries in the Lufeng Sag, LF 9-4-1 and LF 7-10-1d completed as an oil discovery well. In 2018, SK Innovation made LF 12-3-1 discovery. The well was drilled to a TD of 2,014 m and encountered 34.8 m net oil pay. Test rates from the well was up to 3,750 bo/d from the Lower Miocene Zhujiang Formation. In 2017 CNOOC made discovery in LF 14-8-1 and tested oil from the Oligocene Enping Formation. In 2016, LF 7-9-1 was drilled and completed as a dry hole. In 2014, CNOOC made discovery of LF 8-1-1 and LF 14-4-1. LF 14-4-1 penetrated about 150 m of oil pay and tested 1,320 b/d of oil from the Lower Tertiary Zhuhai Formation Background Information There are several fields on production in the Lufeng Sag: LF 7-2 field is operated by Newfield and it was on stream in 2014. The field is producing from the Zhujiang reservoir at a rate of 10,300 bo/d in 2018. LF 13-2 field, operated by CNOOC, also has reservoir in the Zhujiang Formation and on stream in 2006. It is produced at a rate of 3,500 bo/d in 2018. LF 13-1 field has primary reservoir in the Zhujiang Formation and secondary one in the Oligocene Enping Formation. The field has been producing since 1993 and produced at a rate of 5,200 bo/d in 2018. LF 22-1 field - The field was officially shut down in June 2009 after nearly 12 years production as the field depletion. In 2019, CNOOC is preparing to launch a new overall development plan for Lufeng oil fields cluster in the South China Sea oil fields cluster. The Lufeng oil fields cluster, including Lufeng 14-4/14-8/8-1, Lufeng 15-1 and Lufeng 22-1, lies in the east or southeast part of the existing Lufeng oil fields group Lufeng 7-2 and Lufeng 13-1 fields. The Lufeng 22-1 field SPS will be connected to the drilling/production platform in the Lufeng 15-1 field via a 19 km of pipeline. A drilling/production platform will be built in the Lufeng 14-4 field and linked with the platform in the Lufeng 15-1 field via a 23.8 km pipeline.

(Pearl River Mouth B.), Lufeng 13-9-1 nfw, located in the Lufeng Sag, operated by CNOOC LTD (100%), completed, results n/a. The well is believed to be targeting the Mio – Oligocene clastic play.

Croatia’s 2nd onshore round opened on 31 Oct ’18 for 7 blocks, applications to the CHA by 30 Jun ‘19. Map below www.azu.hr.

Croatia’s 2nd onshore round opened on 31 Oct ’18 for 7 blocks, applications to the CHA by 30 Jun ‘19.

Energean Oil & Gas announced on 27 February 2020 that it had reached into an agreement with Total for the acquisition of the 50% stake held by the French major in the Block 02 offshore exploration permit located in the Ionian Sea. Upon completion of the deal, Energean will also assume the operatorship of the permit. Commitments related to the current exploration period include the acquisition of 1,800 km of 2D seismic which should allow to de-risk the prospectively of the license. Energean estimates at EUR 0.5 million the cost associated with the seismic survey. The block encompasses a potential target consisting in a four-way closure at the top Jurassic of the Apulian Platform which could be an analog to the Vega oil field located offshore Sicily. About 40% of the structure extends into the adjoining d84F.R-EL exploration permit application sited in Italian waters and operated by Edison E&P, which will be controlled by Energean Oil & Gas upon completion of an acquisition deal to be closed during H1 2020 (see separate article). The 2,422-sq km Block 02, located in the Ionian Sea, offshore Western Greece, was offered as part of the Second International Licensing Round 2014. The inventory included a total of 20 blocks, 10 of which were located offshore Western Greece, one offshore southern Greece and nine offshore southern Crete. The bid deadline was originally set to 14 May 2015 and was then postponed to 14 July 2015. Negotiations between a Total-led consortium (the sole bidder for the tract) and the Greek government were concluded on 17 March 2017 and the group was formerly awarded the block on 15 March 2018. Interest in Block 02 is shared between Total E&P Greece B.V. (operator - 50%), Edison International S.p.A (25%) and Hellenic Petroleum SA (25%). Upon completion of both the acquisition of Edison E&P and the deal with Total, Energean will hold a 75% operating interest in the license. The balance will be held by Hellenic Petroleum SA.

Energean has signed to acquire Total's 50% operating stake in offshore block 2, 2,422 sq km in the Ionian Sea and home to a Jurassic prospect straddling the Italian border. Partners-to-be Energean (op, 75%), Hellenic + Edison (under buyout by Energean)

On 6 June 2018, Savannah Petroleum PLC (Savannah) announced that the Amdigh 1 wildcat, R3 block of the R3/R4 PSC Area had encountered 22m of net oil bearing reservoir sandstones in the E1 and E2 reservoir units within the primary Eocene Sokor Alternances objective. The well was spudded on 6 May 2018 using the “GW-215” land rig and drilled to a TD of 2,469 m. It had a planned TD of 2,576 m and the Sokor Alternance "A" Sands as primarily target and the Upper Sokor Sands “US” as the secondary target (considered to be upside). Amdigh 1 is in the southernmost sector of Niger’s R3 block, approximately 10 km north of Savannah’s first discovery, Bishiya 1. The prospect has estimated total mean unrisked recoverable resources of 39 MMbbl. The well costs were estimated at USD 6 to 8 million (Savannah, December 2017). Savannah Niger is the operator of the Agadem R1, R2, R3, and R4 blocks through a joint venture between Savannah Petroleum Ltd (95%) and Niger Exploration (5%). Prospect overview:   R3 block area: Drilled prospects ü  The Bushiya oil discovery is located the southernmost sector of the R3 East 3D survey area and covers a surface of approximately 16 sq km. It shows excellent hydrocarbon potential according to the interpretation of the seismic data. Bushiya has the Alternance Sokor "A" Sands (Eocene) as primary target and the Upper Sokor "US" Sands (Oligocene-Miocene) as secondary target with a volume potential of 28 MMbbl and 38 MMbbl respectively. ü  The Amdigh oil discovery is Savannah’s second well (deviated 20º). also located in the R3 East area few kilometers north of Bushiya discovery. Pre-drill estimates are 33 MMbbl for the "A" Sands and 25 MMbbl for the "US" secondary target.  Prospects to be drilled: ü  The third prospect to be drilled will be Kunama which is the northernmost prospect in the R3 East area, right on the block limits. It covers a surface of approximately 12 sq km and shows excellent reservoir potential. The targets are the same with volumes of 24 MMbbl for the "A" Sands and 75 MMbbl for the "US" sands. ü  Eridal, Efital and Mujia are considered as optional drilling targets in R3 block. They cover a surface of around 12 sq km. The targets are the same with volumes of 15 MMbbl, 75 MMbbl and 47 MMbbl respectively for the "A" Sands and 28 MMbbl, 60 MMbbl and 59 MMbbl respectively for the "US" secondary target. R1 block area (Drilling plans cancelled by Savannah in December 2017): ü  The Damissa and Mena prospects will be evaluated once the seismic is done. They are located in the southern part of the R1 block and have volumes of 85 MMbbl and 54 MMbbl respectively for the "A" Sands and 55 MMbbl and 16 MMbbl respectively for the "US" secondary target. ü  Kiski is considered as optional drilling target in the R1 block. It hosts volumes of 19 MMbbl for the "A" Sands while the “US" secondary target has not yet been evaluated. Note: Volumes are given as unrisked mean recoverable resources with an estimated recovery factor of 30% (CGG Robertson, December 2017). The drilling operations will be performed through three phases: the first phase will consist on the drilling itself and logging of the targets. In case of suspended well, a dedicated cheaper rig will test the reservoirs in the phase two. If satisfactory results, a workover rig will complete the well for future production in phase three. The drilling will take between 35 and 40 days on each prospect with a 7 to 10 days transition period. Total depths will range between 2,100 m and 2,600 m. GWDC is the drilling company in charge and is a subsidiary of China National Petroleum Corporation (CNPC) which holds the operatorship in Niger's Agadem, Bilma and Tenere permits. Savannah in Niger: timeline Savannah was awarded the Exclusive Exploration Authorization for the Agadem R1, R2 blocks on 4 August 2014. Signature bonus amounted to USD 42 million. Between November 2014 and February 2015, Savannah acquired an airborne Full Tensor Gravity (FTG) survey by the Arkex aircraft. On 14 May 2015, Savannah reported that it had interpreted 680 sq km of 3D seismic data in the south western part of the Agadem R1 block, leading to 14 drill-ready prospects. The survey covered approximately 8% of the whole R1, R2 permit. In July 2015 the R3/R4 licence was awarded to Savannah. On 30 September 2015, Savannah reported that the restart of exploration activity might be subject to the introduction of a partner. In July 2015 the company received approvals from the Ministry of Environment to acquire new seismic surveys and drill new exploration wells over the R1, R2 permit. Upon initial geological evaluation, Savannah identified 29 leads on the R3, R4 licence. On 17 February 2016, Savannah reported that it signed a contract with BGP Niger SARL to acquire some 2D and 3D data over the R1, R2 and R3, R4 permits. The start of the acquisition was scheduled for the first half of 2016. On 24 January 2017, Savannah reported that it had completed the acquisition of an 800 sq km 3D seismic survey over a portion (800 sq.km) of its R3 licence area. The survey was completed two weeks ahead of schedule and on budget. On 11 April 2017, Savannah confirmed that its three-well drilling programme will be focused on the R3 PSC area. The company would use the land rig GW215 which was already in Niger. Savannah also reported that the construction of the logistic camp had already started and that it was still expecting to start drilling the first well before the end of the first half year 2017. On 15 March 2017, Savannah reported that it signed a Letter of Award (LoA) with Great Wall Drilling Company Niger (GWDC) for a three-well drilling programme with the option to drill 6 more in the Block R3. On 4 December 2017, Savannah reported that it had extended its drilling campaign from three to five wells. The two new prospects to drill were Damissa and Mena located in block R1 with total unrisked mean recoverable resources of 101 MMbbl and 50 MMbbl of oil respectively. The company also announced that a seismic survey of approximately 500 sq km was going to be acquired over block R1. Drilling was planned to start in early 2018 targeting the Bushiya, Amdigh and Kunama prospects using the GWDC 215 rig at a cost of USD 6 to 8 million per well. On 20 December 2017, Savannah announced that regarding several changes with respect to the transaction with Seven Energy, it had decided to drill only the initially planned three prospects in Niger and not to acquire the additionally planned 3D seismic over block R1 in 2018. It was understood that the prospects not to be drilled in 2018 were Damissa and Mena, located in block R1. On 3 April 2018, Savannah announced that the drilling of its first prospect Bushiya in R3 block had started on 31 March 2018. The well Bushiya 1 primarily targeted the Alternance Sokor "A" Sands with the Upper Sokor Sands “US” as secondary target. The prospect had estimated total mean unrisked recoverable resources of 36 MMbbl. On 23 April 2018, Savannah discovered oil in Niger with its first drilled well Bushiya 1. On 30 April 2018, the CEO of Savannah Andrew Knott reportedly announced that the company considered to sell at least 50% of its assets in Niger before planned first oil in 2021. On 3 May 2018, Savannah reported that it was granted a one-year extension period to its R1/R2 PSC in Niger. On 6 June 2018, Savannah discovered oil in its second well Amdigh 1.

Amdigh 1 (Savannah Petr. 100%), 2nd of multi-well programme in R3 East area, was drilled to a TD=2469m and preliminary results indicate the well intersected 22m of net oil bearing reservoir sst. in the E1 and E2 reservoir (good to excellent quality) units within the primary Eocene Sokor Alternances objective.

Azinor is looking for partners willing to share in the 2019 drilling of 3 prospects, namely 16/8c Boaz in P2165, 14/14b Goose in P2137 and 21/25c Hinson in P2179. Full details from Azinor.

Azinor is looking for partners willing to share in the 2019 drilling of 3 prospects, namely 16/8c Boaz in P2165, 14/14b Goose in P2137 and 21/25c Hinson in P2179. Full details from Azinor.

On 14 October 2017, Tethys Oil signed an Exploration & Production Sharing Agreement (EPSA) with the Omani Government for Block 49 (Montasar). The onshore block (15,439 sq km) is located in the SW of Oman along the border with Saudi Arabia. The EPSA has an initial three-year exploration period, with an optional extension period of another three years. In case a commercial discovery is made, the EPSA will be transformed in to a 15-year production licence, which can be extended for another five years.<P />The block has been awarded following the country's 2016 Licensing Round, which was launched in October 2016 and closed in February 2017. It was among a total of four blocks on offer, which are located in different parts of the country. <P />Block 49 is largely unexplored, with nine wells having been drilled within the block boundaries. So far there are no discoveries, however oil and/or gas shows have been reported in several wells. Among the legacy wells is the Dauka 1 (1955) NFW, which is the first exploration well ever drilled in Oman. The last well, Shisr 1, was drilled by Circle Oil in 2015. It was P&A well above the primary objective due to drilling difficulties that had not been encountered to the same extent in previous wells drilled in the area. It is understood the block contains liquid hydrocarbon potential and that there are currently two large mapped prospects. These are located within an area covered by 3D in the south of the block.<P />Tethys Oil operates the acreage with a 100% interest.

Oman, Block 49 (Montasar)

On 11 May 2020, Petrobras issued a press release indicating that the 9-BUZ-039DA-RJS well in the Buzios production concession in the Santos Basin, encountered 208 m of reservoir rocks, assumed to be the pre-salt Barra Velha Formation, with the same quality oil as the one that is being produced in the Buzios field, as indicated by test. The company did not release any more details regarding those tests. The 9-BUZ-039DA-RJS service well spudded on 10 February 2020 and it is still being drilled by the Ocyan drillship ODN I on 2,104 m of water. The well lies in the southeastern part of the Buzios block, outside the main structure of the field in what it could be a new pool or extension of the current structure. The Buzios Field, in the block of the same name, is under two different contracts: the Cessao Onerosa or Transfer of Rights (ToR) contract and the ToR Excess Volumes. On 30 March 2020, the consortium of Petrobras, CNODC, and CNOOC were granted a final award for the 852.21 sq km Buzios block in the deep-water offshore Santos Basin from the 2019 ToR Excess Volumes PSC Bid Round. Petrobras is operator with 90% working interest, CNODC holds 5% working interest, and CNOOC holds 5% working interest. For the ToR contract, Petrobras holds 100% working interest. This special concession contract regime, created in 2010, allowed Petrobras to explore and produce hydrocarbons, up to 5 Bboe, in six contract areas of the pre-salt, 3.06 Bboe for Buzios. The Buzios Field is currently the largest commercial field in Brazil. The field was discovered in 2010 by stratigraphic well 2-ANP-001-RJS drilled in the Franco prospect. The well was targeting Lower Cretaceous Pre-salt microbialites and coquinas of the Barra Velha and Itapema formations. Appraisal of the Buzios Field started in May of 2011 and concluded in December of 2013 with the declaration of commerciality. The Franco prospect was re-named Buzios Field. Development drilling started in September of 2014 and is still on-going. Secondary recovery drilling started in January of 2015 and is also still on-going. Gas injection in Buzios started in August of 2018. Buzios contains oil of about 28° API, GOR of 1,432 cu-ft/bbl, CO2 of 23% molar, and H2S between 30-90 ppmv. The 2019 ANP BAR reserves report estimates original oil in place (OOIP) for Buzios Field of 29.15 Bbo and original gas in place (OGIP) of 29.08 Tcfg. Assuming a 24% recovery factor (FR) the recoverable oil is estimated at 7 Bbo and assuming a 41% RF for the gas, a 12 Bcfg is estimated for the recoverable gas. In March 2020, Petrobras announced that the Buzios field reached a production record of 640 Mbo/d and 790 Mboe/d. The field is producing from four platforms: P-74, P-75, P-76 and P-77. In January 2020, the P-77 platform reached its production capacity of 150 Mbo/d.

9-BUZ-39DA-RJS (Petrobras 90% op., CNOOC 5%, CNODC 5%), Service well in SE Búzios field area, southeastern part of the Buzios block, Santos pre-salt, WD 2104m, oil encountered (208m column below 5400m), ops continue.

An auction was held 25 Mar '20 for 35-yr rights to the 16.2-sq km Kostovatovskiy Yuzhnyy block in Udmurtia Republic (Volga-Ural Province). UDS Neft secured the block with a USD 10.6 MM offer (starting price USD 5,000). Five co's participated.

UDS Neft won the Kostovatovskiy Yuzhnyy block in Udmurtia Republic.

CNH has approved the sale of 50% in 3 onshore Sureste Basin blocks by Jaguar to Vista O&G under a USD 27.5 MM (+ USD 10 MM past costs) deal. Involved are  Area 1 from Ronda 2.3, run by Jaguar, Area 10 from Ronda 2.2 run by Pantera (Jaguar-Sun God JV),  and Area 1 in the Tampico Misantla Basin from Ronda 2.3.

CNH has approved the sale of 50% in 3 onshore blocks by Jaguar to Vista O&G under a US$27,5 MM.

Baron has been cleared on a 5th renewal under the exploration phase on block XXI, 2,425 sq km in the Sechura Basin. It is recalled the block has been available for farmin for long, 50% + possibly operatorship available in exchange for USD 0.5 MM contribution to costs of past seismic + drill a 1,850m commitment well targeting the Minchales sands (Zapayal fm), Mancora fm + fractured basement. Contact [email protected].

Baron has been cleared on a 5th renewal under the exploration phase on block XXI, 2,425 sq km in the Sechura Basin. It is recalled the block has been available for farmin for long, 50% + possibly operatorship available in exchange for USD 0.5 MM contribution to costs of past seismic + drill a 1,850m commitment well targeting the Minchales sands (Zapayal fm), Mancora fm + fractured basement

Following a Council of Ministers session on 20 March the decision was taken to award 5-year rights to SPM on the 4,626-sq km block 1-25 Vratsa West (Vratza Zapad, or Vratca Zapad), Lovech province on the Moesian Platform, NW Bulgaria. Signature bonus is €210,000, investment pledge €7.4 MM including 2D + 3D seismic. A farmout is not ruled out. The award is yet to be gazetted.

Following a Council of Ministers session on 20 March the decision was taken to award 5-year rights to SPM on the 4,626-sq km block 1-25 Vratsa West (Vratza Zapad, or Vratca Zapad), Lovech province on the Moesian Platform,

TPAO and Zarubezhneft each signed an MoU with Sonatrach paving the way for discussions over joint E&P opportunities in the country, taking advantage of its new hydrocarbon law. Inter alia, this includes the absence of the 51% required state participation in all foreign investment projects, and likewise the state’s pre-emptive right in proposed sale of Algerian assets to foreign investors.

TPAO and Zarubezhneft each signed an MoU with Sonatrach paving the way for discussions over joint E&P opportunities in the country, taking advantage of its new hydrocarbon law. Inter alia, this includes the absence of the 51% required state participation in all foreign investment projects, and likewise the state’s pre-emptive right in proposed sale of Algerian assets to foreign investors.

Anadarko acquired 22% equity from 15 contiguous North Slope leases (ADLs 390672-390677, 390679, 391015-391016 & 391914-391919,) previously 100%-owned ConocoPhillips leases.

Anadarko acquired 22% equity from 15 contiguous North Slope leases (ADLs 390672-390677, 390679, 391015-391016 & 391914-391919,) previously 100%-owned ConocoPhillips leases.

Deep well in southwards extn of Shunbei 5 discovery area, Tarim Basin, tested 780 bo/d + 2.6 MMcfg/d.

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

On 1 December 2017, Chevron USA was awarded Mississippi Canyon Block MC 35 (G36126), situated in the Louisiana Coastal Basin. MC 35 was originally offered as part of Western Gulf of Mexico Lease Sale 249, which was held on 16 August 2017. The lease is expected to expire on 30 November 2024. Following official award, Chevron USA is now the operator and sole interest-holder (100% WI + Op) in MC 35.

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Lundin used the “Leiv Eiriksson” S/S to spud exploration well 16/1-31 S targeting the Jorvik prospect (Triassic conglomerate) in PL 338 on 10 March 2019. The company drilled to TD at 2,220 m (2,123 m TVDSS) in the Triassic. On 11 May 2019 exploration sidetrack 16/1-31 A was kicked-off targeting the Tellus East prospect (weathered and fractured Basement with a potential sandstone drape) and this well reached TD at 2,650 m (1,977 m TVDSS) in Basement. It was abandoned on 22 June 2019. As it was not possible to target both prospects with a single well, the two wells were drilled in a Y formation. The top hole is located approximately 4 km northwest of the Edvard Grieg platform, between the Edvard Grieg and Ragnarrock fields. The Jorvik well confirmed a 29 m oil column in the Triassic conglomerate and an overlying thin (1 m) sandstone. The OWC was not identified. The well tested at 130 bo/d through a 26/64” choke and indicated communication with the Edvard Grieg field. If a horizontal well were to be drilled through this reservoir Lundin would expect that it would flow at commercial rates. Recoverable reserves are estimated at 3-22 MMbo plus up to 12 Bcfg. The Tellus East well encountered a 62 m gross oil column in porous, weathered Basement likened to the producing reservoir in the Tellus area of the Edvard Grieg field. The OWC was estimated to be between 1,910 m and 1,912 m TVDSS. Estimated recoverable reserves are 1-13 MMbo plus up to 7 Bcfg. Following drilling, the wells were reclassified as appraisals and will be considered for development using wells drilled from the Edvard Grieg platform.   In 2013 Lundin drilled the first well on the Jorvik prospect which lies immediately east of Edvard Grieg and is a continuation of the same play onto the Haugaland High. 16/1-17 proved mobile oil, but the reservoir (pre-Jurassic conglomerate and pebbly sandstone) was tight with haematite cementation. Potential reserves were estimated at 46 MMboe (in PL 338) prior to drilling. Tellus was drilled in early 2011, just to the north of Edvard Grieg. 16/1-15 made a new discovery in the Lower Cretaceous/Basement with potential reserves (given at the time) of 11-55 MMboe. The field was developed as part of Edvard Grieg and the reserves are now included in the overall field volumes. The completion of drilling of the 14 development wells at Lundin’s Edvard Grieg field was achieved in July 2018. The results exceeded pre-drill expectations and there is no material water production. Earlier in 2018 Lundin announced a reserves increase of 51 MMboe (since the end of 2016) to 274 MMboe, representing a 47% increase compared with the PDO. Good drilling results and production performance indicated that the oil in place volumes were higher than originally calculated and that more of the oil is in the better quality sandstone part of the reservoir (with less in the poorer quality conglomerate zone). The field was producing at a facilities-capacity rate of 95,000 boe/d in July 2018 but double this rate is actually possible. The nearby Lundin-operated Solveig (Luno II) and Rolvsnes discoveries will be tied-back to Edvard Grieg and the 2018 discovery made by Equinor at Lille Prinsen could also potentially be tied-in. Lundin Norway AS operates PL 338 with a 65% interest. It is partnered by OMV (Norge) AS (20%) and Wintershall Dea through Wintershall Norge AS (15%).

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

East Abu Sennan block, Abu Gharadiq Basin, drilled + susp 13 Dec ’17 -  Jan ’18, TD 2,423m (Kharita), tested oil, ST-13 (Thanmia) rig. Target Abu Roash G.

Abu Sennan E.-C1 expl East Abu Sennan block, Abu Gharadiq Basin, drilled + susp 13 Dec ’17 - Jan ’18, TD 2,423m (Kharita), tested oil, ST-13 (Thanmia) rig. Target Abu Roash G.

On 30 July 2020 OMV and Sonatrach signed a Memorandum of Understanding (MOU) on collaboration in upstream activities. The agreement provides for joint work aimed at identifying exploration, development and production opportunities in Algeria based on the new hydrocarbons law. OMV is not currently active in Algeria. Elsewhere in Africa, the company has operations in Tunisia and Libya.

Algeria, not found

NW Sitra block, Abu Gharadiq Basin, W. Desert, TD 1,814m, P&A dry, no details. Target Cretaceous.

NW Sitra-9 (TransGlobe Energy100%) in North West Sitra concession has come up dry, targeting a stacked Cretaceous prospect, but no hydrocarbons were found.

F18-C / F19-D1 / F19-D4 block (Banarli), Thrace Basin in NW Turkey, TD 4,196m, 60-day testing programme complete, 4 tests + 2 frac stages / tested intv starting at the bottom of the well. The 1st such test was completed in the Kesan fm, 151m fracced below 3,996m, flowed 800 Mcfg/d + 60-70 bc/d (56 API) avg for 24 hrs (DEA 28 Nov ’17). The 2nd test in the Kesan was completed after 2 slick-water fracs to access 34m of net gas pay below 3,819m.  The 39-hour test resulted in also 800 Mcfg/d avg (DEA 12 Dec ’17). A 4th test in the Kesan accessed 66ms of net gas pay below 3,320m, 400 Mcfg/d + 30-50 bc/d. The aggregate with the earlier tests now reach 2.9 MMcf/d. £In a change from earlier plans, plans are to mill out the bridge and flow-through plugs in the well and flow all of the intervals together using a 5.5” prod casing, should facilities permit. Ultimately it is planned to tie-in the well to the regional network.  

Yamalik 1 appraisal well by by Valeura (50% op, Statoil 50%) in F18-C / F19-D1 / F19-D4 block (Banarli), 60-day testing programme complete, 4 tests + 2 frac stages / tested intv starting at the bottom of the well. The 1st such test was completed in the Kesan fm, 151m fracced below 3,996m, flowed 800 Mcfg/d + 60-70 bc/d (56 API) avg for 24 hrs. The 2nd test in the Kesan was completed after 2 slick-water fracs to access 34m of net gas pay below 3819m. The 39-hour test resulted in also 800 Mcfg/d avg. A 4th test in the Kesan accessed 66ms of net gas pay below 3320m, 400 Mcfg/d + 30-50 bc/d. The aggregate with the earlier tests now reach 2,9 MMcf/d TD=4196m.

COP secured 7 tracts totalling 323 sq km as a result of the NPR-A 2017 lease sale held on 7 Dec ‘17. ConocoPhillips was partnered with Anadarko (22%) who were the sole bidders on the acreage. COP however reported last month it had agreed to acquire all of Anadarko’s interest under the partnership, all shared NPR-A acreage involved and therefore COP 100%.

ConocoPhillips (78% op. Anadarko 22%) has been officially awarded 7 tracts as a result of the NPR-A 2017 oil & gas lease sale covering the National Petroleum Reserve-Alaska (NE NPR-A L-079,080,081,083,108,110,111).