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Fresh from exercising its farmin option to P2235 (Wick prospect, ref. DEA 19 Feb ’18), Baron Oil has also acquired a 5% stake from Corallian Energy in offshore P1918 in S. England (Colter discovery). A Colter appraisal is planned mid-2018. Corallian (op), partners Corfe Energy. UOG + Baron.

Baron Oil has also acquired a 5% stake from Corallian Energy in offshore P1918 in S. England (Colter discovery).

Rawson has completed an (initial) 25% farmout to Vintage in PEL 155, 226 sq km in the Otway Basin, for AUD 100,000. Vintage has an option on a further 25% by contributing to the cost of drilling Nangwarry-1 nfw on a 50:50 basis, target gas.

Australia (Otway B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: PEL 155 op. by RAWSON O&G (100.0%) to be check.

EP 21-3-1 was completed in late September 2019 without result reported. CNOOC – Shenzhen spudded a new-field wildcat EP 21-3-1 in the PRMB Basin on 9 August 2019. The well, located in the Enping Sag, is situated at a water depth of approximately 100 m area and is targeting the Mio-Oligocene clastic play. “HYSY 943” J/U is used for the drilling operation. In 2019, CNOOC has drilled a number of wells in the Enping Sag, such as EP 20-1-1, EP 20-2-1, EP 20-5-1, EP 10-6-1, EP 20-7-1 and EP 21-2-1d, all with result unreported. In November 2018, CNOOC completed EP 20-4-1 with oil in this area. In January 2019 an appraisal well, EP 20-4-2, was completed with success. In February and March 2018, CNOOC completed EP 15-2-1 and EP 10-2-1, in the Enping Sag with both penetrating oil-bearing zones. The EP 10-2-1 and EP 15-2-1 discoveries, together with existing EP 15-1 discovery, are expected to be a medium size cluster/joint development. EP 15-1 discovery was made in 2016 in the Enping Sag. Background Information In the past few years, 10 discoveries have been made in the Enping Sag, the most significant ones are EP 24-2, EP 18-1 and EP 23-1 fields cluster, with reservoirs from Miocene to Oligocene sands. The Miocene to Oligocene reservoirs are the most significant reservoirs in the PRMB, mainly predominated by sandstones and carbonates of the Lower Miocene Zhujiang Formation, sandstones of the Middle Miocene Hanjiang Formation, and sandstones of the Upper Oligocene Zhuhai Formation. These sandstones were mainly deposited as massive fluvial sands and as deltaic channel and tidal bars with good reservoir properties. To date, five fields have been brought onstream successively since 2014. The latest onstream field in the area is EP 23-1 fields cluster (together with EP 23-2 and EP 23-7), which started commercial production in November 2016 with initial flowing 5,597 bo/d from three wells. The cluster together with Enping 18-1 (on stream Sep 2016) were tied-into the Enping 24-2 facilities, the latter on stream in 2014. By December 2017, the EP 23-1 alone has cumulative production of 4.80 MMbbl, EP 23-2 alone has 1.20 MMbbl and EP23-7 alone has 0.9 MMbbl. EP 18-1 was discovered by BP Group with well Enping 18-1-1A in 1984. The field was further confirmed as a discovery after CNOOC obtained success from its first well Enping 18-1-2D in early 2012. The EP 18-1 was brought on stream in September 2016 with initial production at 2,010 bo/d from three well. By December 2017, the field has cumulative production of 1.76 MMbbl. EP 24-2 field was discovered in August 2010, and on stream in October 2014 with Initial production at 8,000 bo/d from two wells. By December 2017, the field has cumulative production of 36.6 MMbbl

EP 21-3-1 was completed in late September 2019 without result reported.

PRL 3, Papuan Fold Belt, S. of P’nyang gas find, P&A’ing TD 2,725m on 7 Jan ’18, gas in the targets Toro + Digimu fm’s, Emuk dry, Oil Search rig 103. ExxonMobil (op), partners Oil Search, Ampolex, Merlin Petr. The group is working on a devt licence application (APDL 13) and the optimal devt concept for the field is under study.

P'Nyang South 2ST1 appraisal well by Oil Search (38,5%) on behalf of field operator ExxonMobil (49%, JX Nippon 12,5%) in PRL 3, had been drilled through the objective Toro, Digimu and Emuk formations to a total depth of 2275m. Toro and Digimu Fm. sands were interpreted to be gas saturated with good reservoir quality, in line with its pre-drill prognosis. This is the first appraisal well on the P’nyang field, which is reserved as feedstock into one or more expansion trains at the ExxonMobil-led Papua New Guinea LNG project.

Equinor spudded an exploration well targeting the Sputnik prospect in PL 855 on 18 June 2019 using the “West Hercules” S/S. 7324/6-1 is located approximately 30 km northwest of the Wisting discovery and approximately 6 km from the Gemini North discovery, drilled in 2017, in the same licence. The well was targeting a large channel system in the Upper Triassic Snadd Formation and the Middle Jurassic Sto Formation was a secondary target. Gas above oil was expected in the Sto Formation while just oil was expected in the Snadd Formation. Equinor drilled to 746 m and, for a period of around two weeks, temporarily suspended the well whilst waiting for BOP repairs and maintenance to be completed. The well was then drilled to TD at 1,600 m in the Snadd Formation. A 15 m oil column has been proven in the middle part of the Snadd Formation with an OWC at 1,354 m. The reservoir quality is poor. The upper and lower parts of the Snadd Formation also contained sandstones (60 m and 45 m respectively), but again quality was poor and both sands were water-wet. The Sto Formation contained a good quality, water-bearing sandstone which was 20 m thick. Estimated recoverable reserves are 20-65 MMboe. The well was abandoned on 31 July 2019. 7325/4-1 was drilled in 2017 targeting the Gemini North prospect. The well had objectives in the shallow Jurassic Realgrunnen Group (743 m) and the Upper Triassic Snadd Formation (812 m). Both were expected to contain oil similar to nearby Wisting. However, instead of the anticpated oil, gas was discovered in the main objective. A 19 m gas column (no GWC) was proven in the Middle Jurassic Sto Formation, which had good reservoir quality, and a 5 m oil column was encountered in a poor quality Snadd Formation. Estimated recoverable reserves were reported to be 14 – 35 Bcfg and 0.6 – 1.9 MMbo and the find was declared non-commercial. Equinor Energy AS operates PL 855 with a 55% interest. It is partnered by OMV (Norge) AS (25%) and Petoro AS (20%).

7324/06-01 (Sputnik) (Equinor 55% op. OMV 25%, Petoro 20%) in PL 855 (30 kms NE of the Wisting disc.), P&A, oil disc. encountered poor reservoir quality sands in various parts of the Snadd Fm and 20m of good quality aquiferous sands in the Sto Fm, preliminarily discovery size estimated at 19 – 63 MMbbbl of oil. Fluid samples from the well contained light oil and water. TD=1569m, WD=449m.

In late May 2020, Tomskneft-VNK reported the discovery of a new oil pool at the Pavlovskoye field in Tomsk Oblast (Western Siberia). New-pool wildcat Pavlovskaya 8, drilled in 2019, tested oil from reservoir Vasyugan Formation Unit Yu1/3+4 (Oxfordian) in the eastern part of the field. Recoverable oil reserves of the pool are estimated at 3.7 MMbl of 2P and 6.6 MMbbl of 3P. Before the reported pool, reserves of Pavlovskoye located in the Karaysko-Moiseyevskiy license (Kaymys-Vasyugan Province) were estimated at 10 MMbbl of 2P and 11.5 MMbbl of 3P. Tomskneft-VNK is equally owned by Gazprom Neft and Rosneft.

Russia (Volga-Urals B.) Pavlovskoya 8 op. by LUKOIL (100%) in Pavlovskoye block , npw in Pavlovskoye field area in licence Karaysko-Moiseyevskiy, Kaymys-Vasyugan Province, Tomsk Oblast. 2019 well, now reported to have tested oil from the Vasyugan Fm Unit Yu1/3+4 reservoir in the E. part of field. Recoverable oil est. 3.7 MMbo of 2P / 6.6 MMbo 3P.

The NPD confirmed, on 5 November 2019, that Var has taken a 20% interest in PL 901 from operator Equinor, adding to the 30% interest that Var already held in the licence. 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 Equinor Energy AS (30% + operator), Var Energi AS (50%) and Concedo ASA (20%).

VÃ¥r (->50%) acquired 20% stake in PL 901 from Equinor (-> % op, Concedo%) The 278-sq km licence comprises part-blocks 7122/5, 7122/6 + 7123/4, Tornerose area.

On 4 March 2020, SDX Energy Inc. (SDX) reported the Beni Malek-1 (BMK-1) new field wildcat completion, after finding commercial quantities of natural gas in both targeted Lower and Upper Guebbas Tortonian units, in the Gharb Centre permit. The well spudded on 25 October 2019 and it was drilled to a TD of about 1,550 m, targeting a mean of about 15 Bcfs of gross unrisked prospective resources in the licence. BMK-1 is the first of SDX's twelve exploration well campaign in the Gharb Centre permit, expected to be completed in Q2 2020. SDX operates the block since June 2017, with a 75% interest, while ONHYM holds the remaining 25%. The gross CapEx for the drilling campaign is estimated at USD 14 million with SDX’s share being USD 12 million. USD 3.4 million are related to long term items for the twelve wells and USD 6 million relates to four wells expected to be drilled by the end of 2019. The remaining USD 2.6 million are related to SDX share of facilities and maintenance CapEx. Background Information The Gharb (Rharb) is a foreland basin that developed during the Miocene and Pliocene on the northern termination of the Paleozoic basement of the Central Meseta and was covered by thin Mesozoic series. The source rocks, generating the gas in the Rharb basin consist mainly of clay and marl with age of Tortonian, Messinian. The reservoir is composed of turbidite sands with an average porosity of 25 to 30%. The permeability could reach up to 400 md in the region. The seal rocks are provided by clay formations deposited during the Tortonian and Messinian. The traps are mainly stratigraphic (sand lenses). ONHYM estimates the Rharb Center Area to hold in-place reserves of 1.5 Bcm (53 Bcf) of gas. The previous work in the area includes a total of 1,620 km of 2D seismic data, 527 sq km of 3D seismic data (acquired between 2012 and 2013) and 57 drilled wells. On 1 June 2017, SDX Energy was awarded the onshore Gharb Centre permit for a period of eight years. The company is committed to acquire a minimum of 200 sq km of 3D seismic data and drill two exploration wells during the first four- year period. In November 2018, SDX Energy completed its 240 sq km 3D seismic survey over the onshore Gharb Centre permit. The survey started in mid-July 2018. The acquisition, processing, and interpretation of the 3D seismic data are estimated at a total cost of USD 6 million.

Morocco, Gharb Centre

In mid-May 2018 Hunt Oil reported that the Traian Nord 1 exploration well drilled in the VIII Urziceni Est permit was plugged and abandoned as a non-commercial gas discovery. The well was drilled during July 2017 to a total depth of 1,725 m (TVD). The permit is located in the eastern part of the country. Traian Nord 1 was drilled in the southern part of the permit, to the west of the Jugureanu-Odaieni field. The VIII Urziceni Est licence contains the Padina Nord 1 discovery made in 2014. The well was drilled to a depth of 2,640 m and estimates from production tests from two geological sections indicated a potential production ranging from 1,200 to 2,100 boe/d. OMV Petrom reported at that time that this discovery was potentially the largest made in the region of Muntenia in the last 30 years. In 2016 Hunt Oil conducted a 260 sq km 3D seismic survey in the area of Padina Nord 1. Interest in the 2,360 sq km permit is divided between Hunt Oil Co of Romania Srl (50% + operator) and OMV Petrom SA (50%).

In mid-May 2018 Hunt Oil reported that the Traian Nord 1 exploration well drilled in the VIII Urziceni Est permit was plugged and abandoned as a non-commercial gas discovery.

Larus Energy Ltd is looking for a joint venture partner in its wholly owned and operated exploration licence PPL 579, located in the south-east of Papua New Guinea in Larus’ newly defined Torres Basin.  Larus Energy reports it is offering significant equity in the permit, with a farminee to take part in an upcoming exploration programme. Larus has contracted Moyes & Co. to assist in the divesture process.  A data room is open for interested parties.  In August 2017 Larus reported that it was increasing its efforts in the farm-out process, with results of seismic now available and the discovery of an oil seep within the licence area. In Q4 2017 it was reported that discussions were ongoing with a number of potential partners, with new confidentiality agreements signed in November. Moyes & Co is being utilised in an advisory capacity during the process, in which interested parties have been outlined since 2015 and have been conducting geological, geophysical and commercial due diligence as is required for farminees. In August 2015 Larus reported that discussions and due diligence was continuing, with 14 companies interested in the asset.   In February 2017 Larus was awarded PPL 579 to replace PPL 326 which expired in September 2016. The newly awarded licence covers 9,257 sq km across both onshore and offshore Papuan Plateau/Aure Fold Belt. PPL 579 has been awarded for a period of 11 years and is scheduled to expire in February 2028. Larus is looking for a partner to assist with the ongoing work programme in the permit, although Larus has reported that the first two years is already fully funded. In the first two years, Larus will undertake work to develop the shallow Miocene play potential which includes the Vekwala and Sunday prospects. In 2015 and 2016, the Haere and Hahonau 2D seismic surveys have been completed from which the data will now be processed to facilitate lead and prospect mapping. Further, smaller surveys have also been completed over the asset. A study of the petroleum systems within the permit are expected to be expanded into the Tertiary.  Larus is planning to conduct additional seismic over the permit area. Larus reports that there is potential for both Mesozoic and Tertiary targets within the permit area.  Potential reservoirs include a Mesozoic Puri Limestone equivalent, the Tertiary Talama and Lavao units and also a potential Toro sandstone equivalent. The early – mid Jurassic Manil Shale and Miocene-Pliocene Aure Beds Shale are thought to form potential source rocks, with the Orubadi Shale and intraformational units possible as seals. The Vekwala prospect has been reported to potentially contain reserves of 13 Tcfg and 180 MMb liquids.  Previously the Sunday Prospect was outlined as the main target in the licence, which could contain 13.5 Tcfg with 160 MMb liquids. The Sunday Prospect lies in the offshore section of the licence and is thought to be a 40 km long anticline. There are also several other prospects and leads present. The prospects and leads in the licence are thought to be part of a Mesozoic petroleum system.  Drilling, once initial exploration and analysis is complete, would be scheduled for 2020 – 2021. PPL 579 covers an area of 9,257 sq km and was awarded in February 2017. Larus Energy holds 100% interest and is looking to divest its interest. Parties interested in pursuing this opportunity should contact: Ian Cross, Managing Director Moyes & Co Tel: +1 281 501 7110 Email: [email protected]   Andy Melvin, Managing Director Moyes & Co Tel: + 44 7702 855895           Email: [email protected]

Larus Energy Ltd is looking for a joint venture partner in its wholly owned and operated exploration licence PPL 579, located in the south-east of Papua New Guinea in Larus’ newly defined Torres Basin.

KazMunayGaz and Lukoil have signed a Joint Operations Agreement and a Finance Agreement with regard to the Zhenis offshore project. The agreements were signed in Moscow on 30 November 2018. They set out the terms and conditions for both companies to implement the project. Signing these documents opens the way for the participants to negotiatiate a final exploration and production contract with the Ministry of Energy of Kazakhstan. KazMunayGaz and Lukoil signed an agreement on principles on the Zhenis offshore project in June this year. Zhenis is situated at the southern margin of the Kazakh Caspian sector, on the border with Turkmenistan. Currently there are no discoveries in this block. Background Information In April 2018, Energy Minister Mr. Bozumbayev announced that KazMunayGaz (KMG) and Lukoil were negotiating two offshore Caspian E&P blocks, Zhenis and I-R-2. Earlier this year Lukoil’s President Mr. Alekperov said the company was looking at offshore blocks in Kazakhstan in light of the new subsurface and tax legislation which makes investment in the country’s E&P projects more attractive. Both blocks are located in the Mangyshlak-Central Caspian Basin. I-R-2 lies west of the Tsentralnoye discovery that is shared by Russia and Kazakhstan. The Russian part in the Tsentralnoye development is represented by Lukoil and Gazprom. The field’s 3P recoverable reserves are estimated at 664 MMbbl of oil, 1.7 Tcf of gas (mainly gas-cap) and 20 MMbbl of condensate. There are no discoveries in I-R-2. Kazakhstan does not hold offshore bidding rounds, and several blocks off Kazakhstan are available for direct negotiations with the government/national oil company KMG. Kazakhstan legislation stipulates that KMG must have at least 50% interest in offshore projects. Lukoil has been negotiating new projects in Kazakhstan for the last several years, however, none have been finalised due to unattractive economics. Lukoil has been involved in Kazakhstan’s E&P for a long period of time, both on- and offshore. However, its previous exploration projects in the country’s Caspian sector have been unsuccessful. The company has drilled dry wells in the Tyub-Karagan and Atash blocks, and has had to relinquish the Zhambay block due to unavailability of a drilling rig capable of operating in the block’s super-shallow waters at that time. All these blocks were in the Northern Caspian. The company has made several important oil and gas/condensate discoveries in the Russian sector of the Caspian.

KazMunayGaz, Lukoil sign agreement on Zhenis offshore block

Further to DEA 1 Jul '20, Leigh Creek was selected as preferred applicant for CO2019-A + CO2019-B, now PELA 675 + 676 in the Cooper-Eromanga, released under the 2019 SA acreage release. 5-yr commitments for PELA 675 (9,900 sq km) include 150km of 2D, 150 sq km of 3D seismic + 2 wells. PELA 676 (2,011 sq km) calls for 150 sq km of 3D seismic + 3 wells.

Australia (Cooper-Eromanga B.), Leigh Creek was selected as preferred applicant for CO2019-A + CO2019-B, now PELA 675 + 676 in the Cooper-Eromanga, released under the 2019 SA acreage release. 5-yr commitments for PELA 675 (9,900 sq km) include 150km of 2D, 150 sq km of 3D seismic + 2 wells. PELA 676 (2,011 sq km) calls for 150 sq km of 3D seismic + 3 wells.

On 1 October 2018 ConocoPhillips announced that it had reached an agreement to sell its share in the Greater Sunrise assets to the East Timor Government.  Under the terms of the sale agreement, the East Timor Government will make a payment of USD 350 million, and in return will take on ConocoPhillips’s 30% share in the project. The deal is subject to relevant authority approvals and partner pre-emption options, as well as the government acquiring funding approval.  If these are received the parties expect to complete the deal in Q1 2019. Upon completion of the deal, ConocoPhillips will assign its 30% interest in permits JPDA 03-19, JPDA 03-20, NT/RL2 and NT/RL4 to the East Timor Government.  The JPDA contracts are, at this stage, within the previous-Joint Petroleum Development Area (JPDA) waters.  These will be renegotiated as East Timor PSCs, after the new maritime boundary was outlined in March 2018. These are expected in late 2018/early 2019. The permits contain the Sunrise and Troubadour discoveries, that make up the Greater Sunrise assets.  The discoveries were made in 1975 and 1974 respectively and contain over 5 Tcf gas and 225 MMb condensate. ConocoPhillips reported that it differed in opinion with the East Timor Government over how the Greater Sunrise fields should be developed. It has been long debated, with the Greater Sunrise joint venture (JV) preferring a Floating LNG (FLNG) scenario, over the East Timor Government’s suggestion to pipe the hydrocarbons back to an onshore plant in East Timor.  The JV have indicated this would be more costly, but also difficult as a development due to the bathymetry between the discoveries and East Timor. The deal will have significance, as the East Timor Government has outlined that its preference remains, and with interest in the project it will have a greater input into the development decisions. Upon announcement of the transaction, the East Timor Government reported that it would proceed with further discussions with the JV to evaluate the future development.  Woodside, operator of the assets, has indicated that the project falls under its “Horizon III” planned developments, which are scheduled for post-2027.   The Great Sunrise fields have been under discussion for development for some time, with Woodside initially planning to make a decision in 2009.  However a number of issues, including differing opinions in the development scenario, disputes around the maritime boundary and drop in oil price have pushed the development back a number of times.  Woodside has had several discussions with the East Timor government over the development, looking to come to an agreement. However the maritime boundary dispute put this on hold with Woodside reporting that it would wait for a resolution.   A new maritime boundary was agreed and the initial documents signed in March 2018.  The boundary is expected to be finalized and put in place in late 2018/early 2019.  The new maritime arrangement has included a “Special Regime” for Sunrise, which will see East Timor get at least 70% of the government revenues from the development, with the split to be 70:30 (in favour of East Timor) if the development sees a pipeline to East Timor, and split 80:20 if a pipeline to Australia is utilised.  It is not known if this will alter if the government has a stake in the project. Participants in the Greater Sunrise assets are: Woodside Petroleum Ltd (27.67% + Operator), Shell Australia Ltd (32.33%), OG ZOKA Ltd, a wholly owned subsidiary of Osaka Gas Co Ltd (10%) and ConocoPhillips, selling its share to the East Timor Government, (30%).

East Timor, not found

In early July 2020, Sasol Ltd reportedly finalized the sale of its 10% stake in the Escravos GTL (EGTL) plant to operator Chevron Corp, part of a larger divestment program. The effective date of the deal is understood to be 1 September 2019. The resulting ownership of the project, located about 100 km southeast of Lagos, is therefore Chevron with 85% operated interest and Nigerian National Petroleum Corp (NNPC) with 15%. Industry sources explained that "Sasol will continue to support Chevron in the performance of the EGTL plant through ongoing catalyst supply, technology and technical support". The USD 9.5 billion Escravos gas-to-liquids plant was brought onstream in June 2014. Although the plant was designed to convert up to 325 MMscf/d of natural gas into 33,000 bbl of liquids (synthetic diesel), the annual production in 2019 was less than 102 MMscf/d. In an effort to improve this production rate, Chevron has intensified its infill drilling and field development in the past years in the vicinity of Escravos, in fields like Sonam, Okan, Gbokoda or Dibi.

Nigeria (Niger Delta), In early July 2020, Sasol Ltd reportedly finalized the sale of its 10% stake in the Escravos GTL (EGTL) plant to operator Chevron Corp, part of a larger divestment program.

NSE has agreed to take over Montajes’ 100% interest in the 307-sq km VMM-18 block, Middle Magdalena. The deal calls for NSE to take on commitments pegged at USD 3 MM by Aug ’19. It remains subject to ANH approval.

NSE has agreed to take over Montajes’ 100% interest in the 307-sq km VMM-18 block, Middle Magdalena. The deal calls for NSE to take on commitments pegged at USD 3 MM

On 21 May 2018, Buru Energy Ltd reported that it has entered into two agreements with Roc Oil Company Ltd (Roc), for Roc gain access to Buru’s conventional oil portfolio in the Canning Basin. Roc, through its subsidiary company Rock Oil (Canning) Pty Ltd, has agreed to purchase 50% interest in the Ungani oil field production licences L20 and L21 for a cash payment of AUD 64 million. A second agreement has been made for Buru’s surrounding exploration licences, in which Roc has also agreed to acquire 50% interest in return for paying AUD 20 million of a forthcoming AUD 25 million exploration programme, which could include up to four wells between 2018 and 2019. Buru currently holds 100% interest in all transacted licences and will only be farming down the conventional oil component. Buru’s unconventional gas assets and exploration potential of the Laurel Formation will remain with Buru. Buru already holds success in the Yulleroo shale gas discovery, located in EP 391. Buru will remain operator of the production and exploration licences. The Ungani field sale has now completed. The final payment by Roc to Buru will take place once transfer approvals and the establishment of a joint venture agreement have been finalized. The transaction of the exploration licence interest was conditional of the Ungani field sale. Once the initial exploration programme has concluded, of which Roc is to fund 80% of total drilling costs, the partnership will split future related costs respective of interest levels held in the licences (50% split). Roc has previously held interest in Australia within the Gippsland, Perth, South Carnarvon and North Carnarvon basins. This is the first entrance for Roc into the Canning Basin.

Buru Energy Ltd reported that it has entered into two agreements with Roc Oil Company Ltd (Roc), for Roc gain access to Buru’s conventional oil portfolio in the Canning Basin. Roc, through its subsidiary company Rock Oil (Canning) Pty Ltd, has agreed to purchase 50% interest in the Ungani oil field production licences L20 and L21 for a cash payment of AUD 64 million.

Bozhong Depression in Bohai Gulf Basin, WD 20m, ops terminated results n/a early Jan '20, Bohai 5 JU. Targets Guantao + Minghuazhen fm's.

LK25-2-1 nfw Bozhong Depression in Bohai Gulf Basin, WD 20m, ops terminated results n/a early Jan '20, Bohai 5 JU. Targets Guantao + Minghuazhen fm's.

M-11, offshore Moattama and Andaman Sea basins, S. of Zawtika prod area, PTTEP seeking potential partners to share expl risk, drilling campaign with Noble Clyde Boudreaux SS expected to begin in the coming months. More from GEPS.

M-11, offshore Moattama and Andaman Sea basins, S. of Zawtika prod area, PTTEP seeking potential partners to share expl risk, drilling campaign with Noble Clyde Boudreaux SS expected to begin in the coming months.

SOCO International has announced that SOCO Exploration and Production ('SOCO EPC'), the Operator of the Marine XI Block, offshore the Republic of Congo (Brazzaville), has been informed that the applications for a 25-year exploitation permit ('PEX') over each of the Viodo, Lideka and Loubana areas have now been adopted by the Council of Ministers of the Republic of Congo (Brazzaville) and await publication in the Official Gazette. These applications covered areas that were previously part of the shallow water Marine XI permit, which expired at the end of March 2017 following a one-year extension. These applications are in addition to the Lidongo PEX, also formerly part of Marine XI, which was validated on 26th September 2016 by the Council of Ministers. The Lidongo PEX was published in the Official Gazette N°40 dated 6th October 2016, which is consequently the commencement date of the licence. SOCO EPC holds a 40.39% interest and is designated Operator of each of the Lidongo, Viodo, Lideka and Loubana permit areas. Project partners in each permit are WNR, SNPC, AOGC and PetroVietnam Exploration and Production. SOCO will assess the future programme in line with wider strategy and update the market in due course. Original article link Source: SOCO International

Congo, not found

Green Canyon block 821 (lease G34561), WD 1,249m, ops terminated and West Auriga DS released 12 Jan '20. Target Miocene akin to that at Mad Dog, BP (op), partner Talos.

GC 821 002S0B0 (Puma West) expl. (BP 75% op, Talos 25%) in Green Canyon block 821 (lease G34561), ops terminated, results n/a. Target Miocene akin to that at Mad Dog. WD=1249m.

ANH has extended the pre-qualification deadline for the 2nd round of its permanent offer of E&P rights (PPAA), from 21 Oct to 31 Oct '19. The definitive list of approved companies is promised for 19 Nov '19. Proposals and financial guarantees are due on 26 Nov '19 and the release of initial offers on 29 Nov. Competing applications by 5 Dec '19, to which a week is allowed for tug-of-war between applicants. The contracts could be signed from 11 Dec on. The round offers 59 blocks (35 for oil, the rest gas) in the Cesar and Mid-Magdalena, eastern Llanos and offshore in the Atlantic. Round announcement here.

Colombia, not found

Eni said on 29 August 2018 that it is in the process of acquiring 124 exploration leases 1,416 sq km (~350,000 acres), located onshore in the Eastern North Slope region, from Caelus Alaska Exploration. The 124 leases encompass the following ADLs: 392677-392682, 392684, 392687-392702, 392834-392865, 392875-392876, 392878-392889, 392892-392897, 392899-392919, 392921-392944 and 392953-392957. Following the completion of the transaction, Eni will hold all the leases with a 100% WI. The Eastern Exploration Area (EEA) is sited to the southeast of the Prudhoe Bay oilfield, close to existing infrastructures and to the Trans-Alaska Pipeline System (TAPS). "The EEA is considered a prime area with high potential and multiple proven plays, between two of the largest hydrocarbon discoveries in North America," stated Eni, referring to Prudhoe Bay and Point Thompson. "Eni will apply its business model and experience through a fast-track exploration with a short time to market of the potential new discoveries, aimed at generating long-term value for all stakeholders and shareholders." <P />Eni has recently ramped up its activity on the North Slope, spudding the extended reach Nikaitchuq North 1 exploration well in late December 2017, due-north of the state leases in the Nikaitchuq Field, offshore the central North Slope and west of Prudhoe Bay. Eni is the first the company to drill a well in US waters off the north coast of Alaska since 2015. The AOGCC drilling permit states that the directional well heads north from Eni's Spy Island drill site and involves state leases ADL 388571, ADL 388574, ADL 388583 and ADL 391283 -- plus the Harrison Bay Block 6423 that lies in the Beaufort Sea federal outer continental shelf. Well results will determine whether Eni proceeds with a sidetrack this winter and a second well next winter. <P />Eni has been present in Alaska since August 2005, following the acquisition of 103 leases from Armstrong Oil & Gas in the North Slope area. In the Gulf of Mexico and in Alaska Eni currently holds a total of 109 leases. In Alaska, Eni is the operator (w/ 100% WI) of the Nikaitchuq Field, which commenced production in February 2011. Nikaitchuq produces from the same oil-bearing sands of the Late Cretaceous-aged Schrader Bluff Formation found at Prudhoe Bay, Kuparuk River and Milne Point. Eni also has a 30% participation in the Oooguruk Field, with a total net production of ~20,000 boe/d.

Eni (100%) has picked up 124 explo blocks from Caelus, totalling 1400km² on the Eastern North Slope. The area is known as the Eastern Exploration Area, located SE of the Prudhoe Bay oilfield and close to the Trans-Alaska Pipeline System.

Block 12/11, offshore Nam Con Son Basin, P&A 3 Mar '20, gas possibly tested in the Dua + Cau sst, Murmanskaya JU. ST1 TD 4,131m, DST's (4) the Cau sst in the Hai Au structure. ST2 TD 4,049m, DST'd tha Cau sst in the Thien Nga structure, results n/a.

Thien Nga 4X ST1 /ST2 (12/11-TN 4X ST1/ST2) appr Block 12/11, offshore Nam Con Son Basin, P&A 3 Mar '20, gas possibly tested in the Dua + Cau sst, Murmanskaya JU. ST1 TD 4,131m, DST's (4) the Cau sst in the Hai Au structure. ST2 TD 4,049m, DST'd tha Cau sst in the Thien Nga structure, results n/a.

The prequalification deadline for companies interested in the DR's 1st round has been pushed back from 11 Oct to 5 Nov '19. Publication of the list of qualified participants on 8 Nov, bid deadline 3rd week Nov, any winners announcement 27 November. 14 blocks are on offer: Onshore: Cibao Basin (6 blocks), Enriquillo Basin (3 blocks), Azua Basin (1 block). Offshore: San Pedro Basin (4 blocks). Official map below via www.bndh.gob.do/en.

The prequalification deadline for companies interested in the DR's 1st round has been pushed back from 11 Oct to 5 Nov '19. Publication of the list of qualified participants on 8 Nov, bid deadline 3rd week Nov, any winners announcement 27 November. 14 blocks are on offer: Onshore: Cibao Basin (6 blocks), Enriquillo Basin (3 blocks), Azua Basin (1 block).

On 19 January 2020, the General Directorate of Mining and Petroleum Affairs (MAPEG) awarded Turkish Petroleum Corp (TPAO) three new and exclusive exploration licences for blocks N39-a, N39-b and N39-c. The onshore areas are located in the SE Turkish provinces of Gaziantep and Urfa (District XII), in close proximity to various exploration and production licences already held by the company. They will be valid for an initial five-year exploration term, which can be extended up to a maximum period of nine years after extensions.<P />The acreage covers a total area of 1,845 sq km. Parts of the acreage have been previously licenced and more than a dozen wells have been drilled. TPAO submitted the applications for the licences in May 2019 and now operates them with 100% equity.

TPAO has been awarded the N39-B, N39-C, N39-A onshore exploration licence (Western Arabian Province)

Crown Point Energy reported in early-December 2019 that it was evaluating a gas zone in the Sur Rio Malargue x-1001D directional new-field wildcat (NFW) in the Cerro Los Leones block. The operator perforated a 5 m zone in the Tertiary Agua de Piedra Formation from 1,021 m to 1,026 m true vertical depth (TVD) and began testing gas from the zone. The operator will test and evaluate the zone to see if it is commercial. The NFW reached a final total depth (TD) of 1,333 m measured depth on 29 October 2019 after spudding the well on 20 October 2019. The well is located in the north-eastern area of the northern block approximately 10 km south of the Lindero de Piedra Sur Field. The well was deviated 40° to reach the top of the target structure under the Malargue river. Crown Point Energy holds 100% working interest in the Cerro de los Leones permit. The permit is separated into two blocks, covering a total of 409 sq km in Mendoza Province of the Neuquen Basin. Crown Point is currently in the final, second extension of its exploration period and was granted a third four-month extension to 23 February 2020 to evaluate the wells it drilled.

Crown Point Energy Inc - Neuquen Basin - Cerro de los Leones - evaluating possible gas discovery - Sur Rio Malargue x-1001D

On 2 October 2019, Shell was granted approval by the CNH to farm-out 40% working interest to Chevron in the CNH-R02-L04-AP-CS-G01/2018, CNH-R02-L04-AP-CS-G02/2018, CNH-R02-L04-AP-CS-G04/2018 contracts in the ultra-deep-water Campeche Deep Sea Basin. Shell held 100% in all the contracts. Shell remains the operator and holds 60% working interest and Chevron has 40% working interest after the formal approval. The CNH was first notified regarding the deal on 3 July 2019. Shell has been granted approval for all of the exploration plans associated with these three contracts in June 2019. There are three firm commitment wells for these contracts and three contingent commitment wells. On 13 June 2019, Shell was granted approval by the CNH for the first exploration plan related to the CNH-R02-L04-AP-CS-G02/2018 contract, Area 21, AP-CS-G02 block that includes geophysical and geological studies as well as the drilling of one firm commitment exploration well with an incremental case of drilling a second exploration well. On 13 June 2019, Shell was granted approval by the CNH for the first exploration plan related to the CNH-R02-L04-AP-CS-G04/2018 contract, Area 23, AP-CS-G04 block that includes geophysical and geological studies as well as the drilling of one firm commitment exploration well with an incremental case of drilling a second exploration well. On 11 June 2019, Shell was granted approval by the CNH for the first exploration plan related to the CNH-R02-L04-AP-CS-G01/2018 contract, Area 20, AP-CS-G01 block that includes geophysical and geological studies as well as the drilling of one firm commitment exploration well with an incremental case of drilling a second exploration well. On 7 May 2018, Shell was granted an official award for the CNH-R02-L04-AP-CS-G01/2018 contract, the 2,079.50 sq km Area 20, AP-CS-G01 block. For the Area 20 block, the company bid 20% of additional royalties over the minimum of 5%, 2.0 work units factor equivalent to two wells, and a tie-break bonus of USD 90.15 million. There was one other bid for the block by PEMEX who bid 6.11% additional royalties and no additional work units factor. On 7 May 2018, Shell was granted an official award for the CNH-R02-L04-AP-CS-G02/2018 contract, the 2,029.74 sq km Area 21, AP-CS-G02 block. For the Area 21 block, the company bid 20% of additional royalties over the minimum of 5%, 2.0 work units factor equivalent to two wells, and a tie-break bonus of USD 110.15 million representing the second highest tie-break bonus in the round. There were four other bids for the block.The second-place bid was made by the consortium of Chevron, PEMEX, and ONGC who bid the maximum additional royalties and 2.0 additional work units factor but lost the tie-break bonus offering USD 42.1 million. On 7 May 2018, Shell was granted an official award for the CNH-R02-L04-AP-CS-G04/2018 contract, the 1,852.86 sq km Area 23, AP-CS-G04 block. For the Area 23 block, the company bid 10.08% of additional royalties over the minimum of 5%, 1.0 work units factor equivalent to one well. There was one other bid for the block by the consortium of Chevron, PEMEX, and Inpex who bid 13.44% additional royalties but no additional work units factor.

Shell farm-out 40% WI to Chevron in the CNH-R02-L04-AP-CS-G01/2018, CNH-R02-L04-AP-CS-G02/2018, CNH-R02-L04-AP-CS-G04/2018 contracts in the ultra-DW Basin. Shell held 100% in all the contracts. Shell remains the operator and holds 60% working interest and Chevron has 40% working interest after the formal approval.

Total has sold its 100% interest in P2158 (Yeoman discovery) to Ithaca effective 27 Mar '20. Yeoman (23 MMboe) lies adjacent to Hibiscus' P198 (Marigold find, possibly extending into P2158), that company progressing on an area-wide devt study which Total believed could encompass Yeoman.

United Kingdom, P2158

It was announced on 19 January 2020 that Turkiye Petrolleri A.O. (TPAO) has been awarded the G17-C1,C4 onshore exploration licence (Thrace Basin) on 9 January 2020 for a period of five-year. The licence, covering an area of 146 sq km, is located towards northwest of the country and TPAO will be 100% owner and operator of the licence. TPAO had filed the application on 2 August 2019. Arar Petrol ve Gaz Arama Uretim Pazarlama A.S was also interested in G17-C1,C4 licence and, as announced on 7 May 2019, the company had submitted an exclusive application for the exploration licence on 24 April 2019.

TPAO has been awarded the N39-B, N39-C, N39-A onshore exploration licence (Western Arabian Province) and G17-A, G17-D1,D2,D4, G17-C1,C4, G16-D, G16-C, G16-B onshore exploration licence (Thrace Basin)

Chariot has renewed an offer for its 4 blocks in the Barreirinhas Basin, namely wholly-owned shelf-deepwater BAR-M-292, BAR-M-293, BAR-M-313 and BAR-M-314 totalling 768 sq km. Commitments have been met and several potential targets identified, drilling tentatively in 2020. A data room is open. It is recalled AziLat had agreed to a 25% stake in 2015 but the deal fell through after inconclusive negotiations.

Chariot has renewed an offer for its 4 blocks in the Barreirinhas Basin, namely wholly-owned shelf-deepwater BAR-M-292, BAR-M-293, BAR-M-313 and BAR-M-314 totalling 768 sq km. Commitments have been met and several potential targets identified, drilling tentatively in 2020. A data room is open. It is recalled AziLat had agreed to a 25% stake in 2015 but the deal fell through after inconclusive negotiations.

Round CNH-RO3-LO1/2017 (Ronda 3.1) was held yesterday for 35 shelf blocks. Preliminary awards were made for 16 blocks totalling 11,158 sq km.  36 bids were filed, all of the Sureste Basin blocks securing offers with Pemex a prime contender. Other applicants include BP, Cepsa, Citla, DEA, Eni, Lukoil, Pan American, Premier, Repsol, Sapura, Shell and Total.  Blocks and winners below, more details from GEPS:

Round CNH-RO3-LO1/2017 (Ronda 3.1) was held yesterday for 35 shelf blocks. Preliminary awards were made for 16 blocks totalling 11,158 sq km.

Shahbazpur gasfield area / block, onshore Bengal Basin, TD 3,500m, tested 30 MMcfg/d from near TD, WHP 5,500 psi. Gazprom rig. To be followed by Bhola N.-1 and a couple of workovers by Gazprom.

Bangladesh (Bengal B.) ? op. by PETROBANGL (100.0%) in Shahbazpur block

Serica Energy plc announced on 5 November 2018 that it has signed a sale and purchase agreement to acquire further interest in the Bruce and Keith fields along with the associated infrastructure. Under the agreement Serica will take a 16% interest in the Bruce field and a 31.83% interest in the Keith field from BHP Billiton Petroleum Great Britain Limited (BHP) for a cash consideration of GBP 1 million to be adjusted for working capital and 40% of post-tax cashflows. This deal follows two previously announced transactions between Serica and BP and Serica and Total to acquire interest in the Bruce, Keith and Rhum fields. The transactions have an effective date of 1 January 2018 and completion of the BHP deal is subject to regulatory approval and the completion of the deal with BP. BHP will retain liability of the costs of decommissioning facilities and wells already in place. All three deals between Serica and BP, Total and BHP are expected to complete on 30 November 2018. Also on 5 November 2018 Serica announced that all the conditions relating to the licence of the Rhum field issued by the U.S. Office of Foreign Assets Control (OAFC) have now been met. This means that all benefits relating to the Iranian Oil Company (IOC) from the Rhum field (which IOC is a partner) will be held in escrow for such a period as US scantions apply and ensure that neither IOC directly or any indirect parent company of IOC will derive any economic benefit from the Rhum field. IOC will also have no decision making powers with regards to Rhum. On 9 October 2018 Serica announced that it, along with BP, received a conditional licence and assurance from the UK Office of Foreign Assets Control (OFAC) relating the UK North Sea Rhum field. The licence will allow US or US-owned entities to provide goods, services and support involving the Rhum field. Also, non-US entities providing goods, services and support will not be exposed to US Secondary sanctions. Therefore, production from Rhum can now continue unaffected. The newly awarded licence is available until 31 October 2019. The initial deal between BP and Serica was announced in November 2017 in which it agreed to sell 36% interest in the Bruce field, 34.84% interest in the Keith field and 50% interest in the Rhum field to Serica. Under the terms of that deal Serica was to pay an initial consideration of GBP 12.8 million along with a share of cash flows over the next four years, a consideration equivalent to 30% of BP’s post-tax decommissioning costs and several contingent payments of future asset performance and product prices. BP expects to receive an overall payment in the region of GBP 300 million. In addition to the interest approximately 110 staff working for BP on the Bruce assets are also expected to make the transition to Serica. BP is to retain a 1% interest in Bruce to oversee its future operational and financial performance. In an update on 22 May 2018 Serica confirmed that amidst the decision by the US Government to withdraw from the Joint Comprehensive Plan of Action (JCPOA) and reintroduce US Sanctions on Iran, the company remains committed to complete the deal with BP which is partnered by the Iranian Oil Company (U.K) Limited in the Rhum field. The second deal involved Serica and Total. Under the deal, Serica was to acquire a further 42.25% interest in the Bruce field and a further 25% interest in the Keith field. Initial consideration for the interests is USD 5 million payable on deal completion then a deferred consideration of USD 15 million to be paid in three USD 5 million instalments, payable every 8 months following completion of the acquisition and subject to continued production from the nearby Rhum field. Total will retain a 1% interest in the assets. Bruce is a middle Jurassic gas, condensate, oil field discovered in 1974 by Hamilton Brothers Oil Co with well 9/8-1. It is a complex structure comprising three reservoirs - Bruce sandstone (oil and gas condensate), Statfjord sandstone (oil and gas condensate), and Turonian limestone (gas condensate). Appraisal drilling was largely unsuccessful until 1981. The field was not developed until 1990 and was developed using two bridge-linked platforms D and PUQ. It was brought onstream on 19 May 1993. During Phase II of the Bruce development a third platform was added to accommodate additional gas compression facilities. This CR platform, is bridge linked to the two original Bruce Field Platforms. Improved recovery commenced in 1997 with produced water being re-injected into the reservoir. The Keith field was discovered initially in 1983 by well 9/8a-8 which was drilled as a Bruce outpost. The field was not brought onstream until 2000. It has been developed as tie-back to Bruce. The Rhum field was discovered in 1977 with well 3/29-2 by a Joint Operating Agreement between BP and Iranian Oil. It was not initially developed due to the HP/HT nature of the reservoir. In 2002 the field development plan was submitted to the then Department of Trade and Industry. It was developed as a subsea tie-back to the Bruce field with two production wells and the completion of an appraisal well. Production commenced in 2005. Following completion of the deal, interest in Bruce (lying in licences P90, P209 and P276) will be held by Serica Energy plc (94.25% + operator), Marubeni Oil and Gas (U.K.) Limited (3.75%), Total E&P UK Ltd (1%) and BP Exploration and Operating Company (1%). Interest in Keith (P209) will be held by Serica Energy plc (91.67% + operator), Marubeni Oil and Gas (U.K.) Limited (8.33%) and Total E&P UK Ltd (1%). Interest in Rhum (P198, P566 and P975) will be held by Serica Energy plc (50% + operator) and Iranian Oil Company (U.K.) Limited (50%).

Serica Energy has acquired 16% interest in Bruce (->94,25% ) and 31,83% in Keith (->91,67%) fields from BHP Billiton, following acquisitions of interests in the two fields from BP and Total in the past year.

Santos Ltd spudded the Cogydd 1 exploration well in ATP 1189-P, located in the Cooper-Eromanga Basin, on 24 September 2018.  The well was drilled by the “Ensign 970” land rig.  On 3 October 2018 the operator plugged and abandoned the well, after failing to encounter hydrocarbons, at a total depth of 2,558 m. The well was part of an ongoing exploration campaign within ATP 1189-P. ATP 1189-P, which covers an area of 9,151 sq km, was awarded on 1 January 2015.  The well was drilled in block Aquit.B(a) which is held by Santos Ltd (25% + Operator), Santos subsidiaries Santos Petroleum Pty Ltd (25%) and Vamgas Pty Ltd (5%) and Beach Energy subsidiaries Lattice Energy Ltd (25%) and Delhi Petroleum Pty Ltd (20%).

Australia, ATP 1189-P

Al Norte de la Dorsal block, Neuquén Basin, TD 4,026m, testing in June, w.o. results.

Barda Gonzalez del Medio-1 nfw Al Norte de la Dorsal block, Neuquén Basin, TD 4,026m, testing in June, w.o. results.

Murphy is offering up to 25.5% in SK-405B,  2,352 sq km astride the Balingan and Tatau provinces off Sarawak, WD 10-50m. Murphy currently 59.5% (op), partners MOECO + Petronas.

Murphy is offering up to 25.5% in SK-405B, 2,352 sq km astride the Balingan and Tatau provinces off Sarawak, WD 10-50m. Murphy currently 59.5% (op), partners MOECO + Petronas.

Canacol Energy has provided the results of the Pandereta 2 appraisal well located on its 100% operated VIM 5 block in the Lower Magdalena Valley Basin of Colombia. Pandereta 2 encountered 130 feet true vertical depth ('ft tvd') of net gas pay within the Cienaga de Oro ('CDO') reservoir, twice the amount encountered within the CDO in the Pandereta 1 discovery well, thus confirming a significant new gas discovery on the VIM 5 block. The Pandereta 2 well tested an absolute open flow ('AOF') rate of 140 million standard cubic feet per day ('MMscfpd') from the upper part of the CDO sandstone reservoir. The Corporation also provides details of its 2018 gas exploration, appraisal and development drilling programs. Pandereta 2 Gas Appraisal Well - VIM 5 Exploration and Production Contract - CNE Oil and Gas S.A.S, 100% Operated Working Interest The Pandereta 2 appraisal well is located approx. 1 km to the west of the Pandereta 1 exploration well. As disclosed in November 2017, the Pandereta 1 wildcat exploration well encountered 64 ft tvd of net pay and tested 29 MMscfpd of gas from the CDO sandstone reservoir. Using the Pioneer 302 drilling rig, Pandereta-2 was spud on December 3, 2017, and reached a total depth of 9,641 ft md in 18 days, a new drilling record for the CDO target. The well encountered 130 ft tvd of net gas pay with average porosity of 23% within the CDO sandstone reservoir target. Two separate production tests were performed in the CDO sandstone reservoir. The upper part of the CDO was perforated between 8,505 to 8,612 ft md and flowed at a final stable rate of 35 MMscfpd at a 57/64 inch choke and a flowing tubing head pressure of 1,438 pounds per square inch over a test period of 55 hours. Based upon this result, management has calculated an absolute open flow rate of 140 MMscfpd for the upper CDO reservoir in the Pandereta 2 well. The AOF potential is the rate at which the well would produce against an atmospheric sand face back pressure and is used as a measure of gas well performance because it quantifies the ability of a reservoir to deliver gas to the wellbore and to the surface. The lower part of the CDO was perforated between 8,674 – 8,684 ft md and flowed at a final stable rate of 16 MMscfpd at a 32/64 inch choke and a flowing tubing head pressure of 2,446 pounds per square inch over a test period of 47 hours. The test was terminated prematurely due to a mechanical failure in the testing string, and does not represent a complete test. 2018 Drilling Program The Corporation has decided to use two drilling rigs to execute its 2018 drilling program in an accelerated program, the objectives of which are to 1) achieve 230 MMscfpd of productive capacity by mid-year 2018 to allow sufficient time for all the necessary tie-backs to Jobo plant, and well in advance of the Corporation’s objective to exit 2018 with 230 MMscfpd of production, and 2) add new gas reserves to allow the Corporation to plan future pipeline projects to increase production above 230 MMscfpd. The Corporation is currently drilling the Pandereta 3 appraisal well, which spud on January 12, 2018. The Pandereta 3 bottom hole location is situated approx. 1.5 kms to the northeast of the Pandereta 2 location and 1 km north of the Pandereta 1 discovery location, and is targeting the reservoir sands within the primary CDO reservoir target. The Pandereta 3 well is anticipated to take approx. 4 weeks to drill and test. Using the Tuscany 109 drilling rig, the Corporation is planning to spud the Gaiteros 1 exploration well on its VIM 5 contract on January 18, 2018. Gaiteros 1 is targeting potential gas bearing sandstones within the CDO Formation. Over the remainder of 2018, the Corporation’s exploration and appraisal drilling program includes the Breva 1 exploration well on the VIM 21 contract, and the Borojo 1 exploration well and Canahuate 3 appraisal well on the Esperanza contract. In addition to Pandereta 3, two development well locations will be selected and confirmed as the company’s drilling program progresses. The Corporation will provide regular updates on drilling results as they become available. Original article link Source: Canacol Energy

Pandereta 2 op. by Canacol (100%) in VIM 5 block, encountered 42m of net gas pay within the Cienaga de Oro ('CDO') reservoir, tested an absolute open flow ('AOF') rate of 140 MMscf/d from the upper part of the CDO sst. reservoir (from 2658-2691m flowed at a stable rate of 35 MMscf/d [0.89”choke] over a 55-hour period, and from between 2710-2713m, stable rate of 16 MMcfd [0.5-inch choke] over a 47-hour period).

As of early July 2020, the Nigerian Department of Petroleum Resources (DPR) declared that over 600 companies have applied to be prequalified for the 2nd Marginal Fields Bid Round launched on 1 June. The initial registration period lasted until 21 June, after a short extension period. The DPR is now evaluating the applications and is understood to be able to announce the prequalified bidders On 16 July (originally planned on 5 July). The full revised schedule of the auction is detailed in a separate article. Interested parties are invited to visit the DPR portal for the exercise (https://marginal.dpr.gov.ng/). Further enquiries will be sent to [email protected] and [email protected] or asked through phone at +234 (1) 27 900 00 or +234 (1) 90 371 50. Although the process is primarily designed for Nigerian oil companies in order to acquire petroleum permits, foreign companies can also apply as long as 51% operated interest is kept by an indigenous party. The contributors of the 57 marginal fields (undeveloped assets) are mainly the five Majors ExxonMobil, Shell, Chevron, Total and Eni, active in Niger Delta for decades. They were requested by the authorities to release some of their non-core business assets. In April 2020, the DPR also revoked ten permits operated by indigenous companies with intention to put them on offer in the bid round, considering the companies were inactive. However, these companies are now contesting this decision and secured in early June a joint order of the Federal High Court of Nigeria. The below map provides with a visual representation of the Nigerian marginal blocks offered in 2020 (the small red outlines). They are located onshore, in swamps and in the shallow waters of Niger Delta. This image also indicates the existing blocks of the five Majors from which most of the marginal fields were carved out.

Nigeria (Niger Delta), As of early July 2020, the Nigerian Department of Petroleum Resources (DPR) declared that over 600 companies have applied to be prequalified for the 2nd Marginal Fields Bid Round launched on 1 June. The initial registration period lasted until 21 June, after a short extension period. The DPR is now evaluating the applications and is understood to be able to announce the prequalified bidders On 16 July (originally planned on 5 July).

UKOG has agreed to acquire Doriemus’ 6% in Horse Hill Devt Ltd (HHDL), operator of the Horse Hill-1 discovery and PEDL 137 + 246, West Sussex. After the GBP 2.1 million deal is completed, UKOG will hold a 77.9% in HHDL, or 50.635% beneficial interests in the PEDLs.

UKOG has agreed to acquire Doriemus’ 6% in Horse Hill Devt Ltd (HHDL), operator of the Horse Hill-1 discovery and PEDL 137 + 246. After the GBP2,1 MM deal is completed, UKOG will hold a 77,9% in HHDL, or 50,635% beneficial interests in the PEDLs.

Ref. DEA 20 Oct ’17, Schlumberger secured 2-year prospecting permit PPP 60409, 18,722 sq km in the Taranaki Basin, on 28 Nov ‘17.  Commitments call for 4,000 sq km of 3D seismic.  

New Zealand (Taranaki B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: PPP 60409 op. by SCHLUMB (100.0%) to be check.

MLHP-7 (Etinde EA), original hole reached TD 3,375m, sidetracked at 2,900m to 3,270m, preliminary logging and fluid sampling identified oil rather than gas, Topaz Driller JU. New Age (op), partners Lukoil, Bowleven, SNH carried. 1st of 2 appr wells planned in the shallow water block around the Isongo M2 gas-cond discovery area.

MLHP-7 (Etinde EA), original hole reached TD 3,375m, sidetracked at 2,900m to 3,270m, preliminary logging and fluid sampling identified oil rather than gas, Topaz Driller JU. New Age (op), partners Lukoil, Bowleven, SNH carried. 1st of 2 appr wells planned in the shallow water block around the Isongo M2 gas-cond discovery area.

On 10 July 2020 Beach Energy Ltd via wholly owned subsidiary Beach Energy (Operations) Ltd was awarded offshore exploration license VIC/P7192(V) in the Inner Otway Sub-basin, Otway Basin. The permit has been granted for an initial period of six years and is scheduled to expire or be renewed on 9 July 2026. The license is located within State Waters, in close proximity to Beach's Halladale-Speculant gas facility. Under the conditions of the award, Beach is required to work with local communities, the local commercial fishing industry and relevant local government authorities. It will be possible to drill any required wells from onshore to offshore, with any petroleum discovered prioritised for the Victorian domestic market. On 16 June 2020 the Victorian Government lifted the moratorium on conventional gas exploration, which will be effective as of June 2021. VIC/P7192(V), which covers an area of 49.10 sq km is one of two permits awarded on this date, with VIC/P7191(V) awarded to Bridgeport Energy. Beach Energy (Operatiosn) Ltd holds 100% interest and operatorship in the permit.

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

Subsequent to a portfolio review, Heritage Oil Ltd no longer sees Papua New Guinea as a core growth region. The company is looking to exit the country by divesting its entire PNG portfolio which includes exploration assets in the Western Forelands and the Southern Highlands (PPL 437 & PPL 486), and a gas field (Kuru, PRL 13). Heritage entered PNG in 2013 by acquiring operated interest in PPL 319 from Esrey Resources for around USD 4 million. The permit was later renewed in 2014 as PPL 486, which is still operated by Heritage. PPL 486 covers an area of 2,130 sq km in the Fly Platform, between the recently appraised, Oil Search operated, Barikewa gas field in the Papuan Fold Belt and the Total’s operated Elk-Antelope field in a carbonate platform, Fly Platform. The committed work programme was amended in October 2015 to move required 2D seismic acquisition from years 1&2, to years 3&4. However, after 11 lines were shot by Telemu (an Esrey subsidiary) in 2011, no known further ground works have taken place. The remaining programme includes three exploration wells by June 2020. Given the commitment from Heritage to exit the country, it is unlikely that the work programme will be altered again. Heritage reports two prospects and six leads within the permit area. The Tuyuwopi Prospect is considered ‘drill-ready’ by Heritage in a four-way dip closed drape structure which is thought to be on a direct migration pathway from a Jurassic source kitchen. Tuyowopi was the likely target for the first well to be funded by Heritage in the original farm-in agreement and site clearance work had commenced. It has the potential for gas within the Imburu, Iagifu and Koi Iange units, with Heritage reporting that it could contain 2P prospective recoverable resources of 600 Bcf in a gas case or 125 MMbo and 375 Bcfg in an oil and gas case. Both the Kutubu oil export pipeline and the PNG LNG natural gas pipeline run through the acreage which could aid in bringing resources to market in the case of a discovery with third-party pipeline access. Retention Lease PRL 13 is located directly east of PPL 486 and covers the Kuru gas discovery. Containing an estimated 30 – 50 Bcf gas, commercializing the field would benefit from aggregated resources of new finds. Discovered in 1956 after ground seepage was observed, Kuru 1 well blew out after penetrating around 12 m of the Puri Limestone. Kuru 2 was later drilled to test deeper targets including Miocene sandstones and the Darai Limestone. PRL 13 was set to expire on 15 June 2017. It is not thought that Esrey Resources applied for a licence renewal before exiting PNG. Pending confirmation, the licence could be inactive, meaning Kuru would no longer be under licence. Exploration licence PPL 437 is located immediately north of the Elevala and Ketu fields in Horizon’s operated PRL 21. It contains the drill ready Malisa Prospect, along with Ebony, Mango and Ketu North prospects. Partner and operator Kina Petroleum is also looking to farm-down interest in the licence which is currently under application for an extension. Malisa has the potential for gas within the Kimu and Elevala/Toro formations, with Heritage reporting that it could contain 2P prospective recoverable resources of 280 Bcf gas. The licence lies in close proximity to the Elevala, Ketu, Stanley, P’nyang and Juha discoveries, meaning opportunities for development could run through proposed Western LNG infrastructure or through third party access to the considered P’nyang to Kutubu pipeline. A total 170 km of 2D seismic was acquired over Malisa in 2014 during the Gosur Survey. Interpretation of this data was reported to be nearly complete in 2H 2017, along with integrated aerogravity data. Initial results showed significant prospectivity in the east of the permit. In addition, vintage seismic data was reprocessed within the licence and pending full interpretation. Under the work commitments, the option existed to either drill one well or complete an additional phase of seismic in place of the well, if the identification of a suitable drilling target had not been successful. Drilling targets could potentially be identified through interpretation of reprocessed vintage 2D seismic data. A seismic programme was expected in 2018 which did not materialize but could be included in the permit extension application programme. Heritage farmed into PPL 437 in 2013 with the condition that Kina would be free-carried through the first seismic programme. Additional interest could have been earned by Heritage (up to 50%) if the option to drill an exploration well was taken, in which Kina would also have been free carried. PPL 437, which covers an area of 1,537 sq km, was awarded on 19 February 2013. Heritage Oil is looking to divest its entire 42.5% interest. Operator Kina Petroleum is also looking to farm down its 57.5% interest. Companies interested in pursuing this opportunity should contact: Krey Stirland – Heritage Oil, Vice President Business Development Email: [email protected]

Heritage Oil Plc is looking to divest its entire PNG portfolio

VIM-5, Lower Magdalena, 10km E of Clarinete + Oboe fields, TD 2,849m, 59m of gas pay within the Lower Tubara, Cienaga de Oro, and fractured basement reservoirs. The CDO test-flowed 29 MMcfg/d on 44/64” choke, WHFP 2,136 psi, from 2 perforated intvs for 32 hrs.  The fractured basement was perforated over a small interval and flowed only low volumes of gas. Pandereta-2 appr has since spudded (2 Dec ’17), 5-week well, target CDO. Pioneer 302 rig. 

Colombia (Lower Magdalena B.) Pandereta 1 op. by CANACOL EN (100.0%) in VIM 5 block

PL 170, Eromanga Basin (Queensland), TD 1,118m, final well of Santos’ recent 4-well appr campaign, intersected 4.4m of net oil pay in Wyandra sands, suspended as future producer in mid-Jan ‘18. Santos (op), partner Beach.

PL 170, Eromanga Basin (Queensland), TD 1,118m, final well of Santos’ recent 4-well appr campaign, intersected 4.4m of net oil pay in Wyandra sands, suspended as future producer in mid-Jan ‘18. Santos (op), partner Beach.

A farm-in agreement between Finder Exploration Pty Ltd and Sapura Energy Bhd was completed, with the transfer of interest in the final two permits approved, on 12 March 2019.  The deal between the companies saw Sapura entering Australian exploration for the first time, acquiring interest in offshore permits AC/P61, WA-412-P and TP/25, and onshore permit EP 483. The first part of the farm-in agreement was completed on 23 November 2018, when the National Offshore Petroleum Titles Administrator (NOPTA) registered the dealing within AC/P61 and WA-412-P.  Subsequently, on 12 March 2019, the Western Australian Government approved and registered the change in interest in permits EP 483 and TP/25. Sapura has entered the permits by acquiring interest through its wholly owned subsidiary Sapura Exploration and Production (Western Australia) Pty Ltd.  Sapura has acquired 70% interest and assumed operatorship in Bonaparte Basin permit AC/P61 and the three North Carnarvon Basin permits: EP 483, TP/25 and WA-412-P in the deal.  Finder, which previously held 100% interest, has retained 30% interest. The company had been looking for a farm-in partner for some time along with eight other Australian exploration licences. AC/P61 - Sapura reports that the newly formed joint venture will look to acquire seismic data within the permit area in 2019 to mature possible drilling targets. Both Upper Jurassic and Upper Cretaceous fan sandstones have been proven within the Vulcan Sub-basin and the permit is surrounded by the Oliver, Tenacious and Audacious oil discoveries. In May 2017 Finder outlined that the Gem Prospect had been identified for potential drilling, with a possible 130 MMb oil in place.  A development option for Gem, and possible discoveries from surrounding prospects, has been formulated for commercialisation. AC/P61, which covers an area of 335 sq km, was awarded on 22 June 2016. EP 483 & TP/25 - Finder has considered the permits as one with the split representing a transition from coastal, state waters of Western Australia (within 3 nm of land) to territorial waters (within 12 nm of land/islands - the Serrurier and Bessieres islands). Finder has delayed exploration to gain a financial partner and exploration wells are now due by 2019/2020. Finder has highlighted the Eagle Prospect for potential drilling, which lies in the centre of TP/25. The prospect is located in shallow water within the Mungaroo Formation at around 2,500 m below surface. Interpretation of the Numbat 3D seismic reveals a trap size of around 33 sq km within which, Finder reports the potential for mean gas-in-place of 2 Tcf. EP 483 and TP/25 cover a combined area of 1,076 sq km and were awarded in 2013. WA-412-P - The permit contains the Kanga prospect, which has highside potential of 220 MMb oil in place, within a structure at around 3,170 m depth.  Targeted reservoirs would be in the mid to late Jurassic, sealed by the Muderong Shale or Forestier Claystone.  Finder reports Kanga as a “drill ready prospect”.  Oil shows were encountered in the Lacerta 1 well, which is located to the south and was drilled in 1998. The Ironbark Prospect (high impact well) lies 20 km to the north of WA-412-P which is estimated to contain 15 Tcf (2C) in the Mungaroo Formation and is scheduled to be drilled by June 2020. WA-412-P, which covers an area of 387 sq km, was awarded on 13 June 2008.

A farm-in agreement between Finder Exploration Pty Ltd and Sapura Energy Bhd was completed, with the transfer of interest in the final two permits approved, on 12 March 2019. The deal between the companies saw Sapura entering Australian exploration for the first time, acquiring interest in offshore permits AC/P61, WA-412-P and TP/25, and onshore permit EP 483. The first part of the farm-in agreement was completed on 23 November 2018, when the National Offshore Petroleum Titles Administrator (NOPTA) registered the dealing within AC/P61 and WA-412-P

Faroe Petroleum is selling 17.5% interest in PL586 containing the pre-development Fenja Field to Suncor Energy as announced on 12 February 2018. Cash consideration is US$ 54.5 million and Faroe Petroleum will retain 7.5% in PL586. Fenja incorporates the Pil & Bue discoveries, and the Plan for Development and Operation (PDO) was submitted on 19 December 2017. Investment is expected to total NOK 10 billion (US$ 1.2 billion) and development will be through two seabed templates with production and gas & water injection wells, and 32km subsea tie-back to Njord A facility. Recoverable reserves are 97MMbo with production to commence in Q4 2020. Pil will be developed first and Bue secondly as an upside that will be confirmed through Pil production drilling. Pil and Bue were discovered in Late Jurassic Rogn and Melke Formation sandstones by 6406/12-3 S (2014, VNG, 3,788m) and 6406/12-3 A (2014, VNG, 4,356m). A subsequent nearby discovery was made in the Rogn Formation by Boomerang NFW 6406/12-4 S (2015, VNG, 4,318m) 1.8km SE of Pil, and may offer further upside. PL586 was awarded in APA2010 and covers 287 sq km in blocks 6406/11 & 12. Prior to completion of the Faroe/Suncor deal PL586 licence partners are VNG Norge AS (30% + Op), Point Resources AS (45%), and Faroe Petroleum Norge AS (25%).

Faroe Petroleum is selling 17.5% interest in PL586 containing the pre-development Fenja Field to Suncor Energy

It is understood that Vermillion Energy Ireland Ltd has picked up a further 18% and 7% interest in the Corrib field from Equinor Exploration (Ireland) Ltd and Nephin Energy Holdings Ltd respectively. The deal now provides Vermillion with a total of 45% interest in the field. Corrib is located 70 km from Achill Island off the west coast of Ireland in a water depth of 336 m in the Slyne Trough. The 18/20-1 discovery well was suspended in November 1996 and reached 4,372 m and although substantial quantities of gas were encountered in the Triassic section, it was not tested for technical reasons. It is in relatively deep water (335 m) with the gas reservoir 3,500 m below sea level. The estimated reserves prior to production commencing were approximately 1 Tcf gas and the field has an expected field life of around 15 - 20 years. First gas was achieved on 30 December 2015. At peak production Corrib supplied Ireland with over 60% of its domestic gas needs. Following completion of the transaction interest in the Corrib Gas Project is divided between Vermilion Energy Ireland Ltd (45% + operator), Nephin Energy Holdings Limited (36.5%) and Equinor Exploration Ireland Ltd (18.5%).

Vermillion has picked up a further 18% and 7% interest in the Corrib field from Equinor and Nephin respectively. The deal now provides Vermillion with a total of 45% interest in the field.

On 27 December 2019, Petrobras issued a press release indicating it closed the sale with Petronas for 50% non-operated working interest in the BM-C-036 contract, Tartaruga Verde production concession and the Espadarte production concession Module III. Petronas made a final payment of USD 691.9 million as the balance of the total transaction amount of USD 950.6 million. A preliminary payment of USD 258.7 million was paid on contract signature date of 25 April 2019. The total transaction amount was lowered due to adjustments from the originally reported USD 1.293 billion. The ANP also announced on 27 December 2019 that it approved of the working interest transfer from Petrobras to Petronas. Petrobras remains the operator of both contracts with 50% working interest and Petronas holds a 50% non-operated working interest. On 25 April 2019, Petrobras issued a press release indicating it signed a sales and purchase agreement with Petronas for 50% non-operated working interest in the BM-C-036 contract, Tartaruga Verde production concession and the Espadarte production concession Module III. The transaction is pending formal ANP and CADE approvals. The terms of the deal were reported to be a total consideration of USD 1,293.5 million to be paid in two installments. A payment of USD 258.7 million was paid on contract signature date of 25 April 2019.There will be a USD 1,034.8 million payment made on closing date with adjustments. On 3 April 2018, Petrobras published on its website the teasers for the sale of 50% non-operated working interest in the BM-C-036 contract, Tartaruga Verde production concession and the southwestern portion of the Espadarte production concession that it has denominated Module III. Tartaruga Verde Fields - General Summary Production and Reserves Basin Field Oil Prod bo/d 02/2019 Gas Prod mcfg/d 02/2019 Water Prod bw/d 02/2019 Wells VOIP_MMbbl 12/31/2018 cumulative Oil Prod MMbbl 12/31/2018 Percent Recovery % VGIP_MMm3 12/31/2018 cumulative Gas Prod MMm3 12/31/2018 Percent Recovery % Campos Tartaruga Verde 92,978.05 38,901.46 6,713.38 9 1071.35 25.47 2.38% 11306.48 279.19 2.47% Campos Tartaruga Verde Sudoeste 11,933.74 4,503.02 2,929.42 3   Totals 104,911.79 46,978.93 25,581.43 18 1,071.35 25.47 2.38% 11,306.48 279.19 2.47% Source: IHS Markit                   © 2019 IHS Markit

On 27 December 2019, Petrobras issued a press release indicating it closed the sale with Petronas for 50% non-operated working interest in the BM-C-036 contract, Tartaruga Verde production concession and the Espadarte production concession Module III. Petronas made a final payment of USD 691.9 million as the balance of the total transaction amount of USD 950.6 million.

Mundiregina is looking to partner on 12 permits totalling 2,220 sq km mainly on the Gaspe Peninsula (Quebec). www.mundiregina.com, access + offer details via GEPS, contact [email protected].

Canada, not found

On 4 December 2018, CGX Energy and Frontera Energy announced a letter agreement to advance exploration opportunities in the Corentyne and Demerara blocks offshore Guyana. The company deal includes CGX Resources Inc, a wholly-owned subsidiary of CGX, and Frontera entering into a farm-in joint venture (JV) agreement for both offshore blocks. Subject to government approval, terms of the JV include Frontera paying a USD 33.3 million signing bonus to acquire a 33.33% interest in each of the two shallow water blocks. Frontera will also pay one-third of applicable costs plus an additional 8.333% of CGX’s direct drilling costs for initial commitment wells on each block. CGX will remain operator of both blocks. The Corentyne Block is adjacent and south of the prolific Stabroek Block, and the December 2018 Pluma 1 discovery is located near the border of the CGX-operated acreage.

CGX Energy and Frontera Energy announced a letter agreement to advance exploration opportunities in the Corentyne and Demerara blocks offshore Guyana.

Inpex has been granted 35-year rights to ADNOC onshore block 4  (6,116 sq km), the ops to be run by subsidiary Jodco Exploration. Inpex will hold a 100% stake in the explo phase, ADNOC retaining a 60% back-in right in a production phase. Block 4 contains the undeveloped Hudairiat and Ramhan o&g fields.

Inpex has been awarded an onshore Block 4 (6116km²) exploration block as part of Abu Dhabi’s first ever competitive bid round for new licensing opportunities.

VIM-5, SE of Clarinete field in Lower Mag, target Ciénaga de Oro + Porquero gas, drilled 11-25 May ’19, TMD 2,591m,  128m gross gas pay between 2,331-2,459m TVD,  18% avg porosity in the Ciénaga de Oro sst, tested 33 MMcfg/d from 2,349-2,396m on 60/64+ choke, WHFP 1,476 psi, well to be tied-into the Jobo facilities via the Pandereta flow line, on stream by late July. Pioneer 53 rig off to Ocarina-1.

Acordeón 1 (Canacol 100%) in VIM-5 block, SE of Clarinete field, target Ciénaga de Oro + Porquero gas, TMD=2591m, 128m gross gas pay between 2331-2459m TVD, 18% avg porosity in the Ciénaga de Oro sst, tested 33 MMscfg/d from 2349-2396m [60/64+ choke], well to be tied-into the Jobo facilities via the Pandereta flow line.

ExxonMobil has been cleared for its acquisition of 50% + operatorship from Queiroz Galvão in Round 13 blocks SEAL-M-351 + SEAL-M-428, total 1,513 sq km in the Sergipe-Alagoas deepwaters. Once Murphy, a 20% farminee, has been also cleared, QG will retain 30%. The deal will include reimbursement to QG of 70% of the bonus paid made for the farmin blocks (ab. USD 31.6 MM).

Brazil, not found

Huizhou 25-7-4 (HZ 25-7-4) was plugged and abandoned (results TBC) on or around 25 August 2018 after having been spudded in mid-July 2018 using the "Haiyangshiyou 943" jack-up. The oil appraisal well is in Block 16/25 PSC in the offshore Pearl River Mouth Basin. Husky is the operator and sole rightholder of Block 16/25 PSC, with CNOOC having the rights to back-in for 51% interest in the development and production phase.

Not Found

Shell is reportedly selling its 6.45% in the Kvitebjørn field and pipeline as well as its 3.225% in the Valemon Unit and pipeline. Kvitebjørn lies in block 34/11f operated by Equinor, partners Shell, Petoro, Total + Spirit Energy, wheras Valemon is in 34/11e run by Equinor (op), Shell + Petoro.

Norway (Viking Graben Province) PL 193 op. by EQUINOR (40%), PETORO (30%), CENTRICA (13%), SHELL (6%), TOTAL (5%), MUNCHEN ST (5%), BAYERNGAS (1%), Tigas (0%), Shell is reportedly selling its 6.45% in the Kvitebjørn field and pipeline as well as its 3.225% in the Valemon Unit and pipeline. Kvitebjørn lies in block 34/11f operated by Equinor, partners Shell, Petoro, Total + Spirit Energy, wheras Valemon is in 34/11e run by Equinor (op), Shell + Petoro.

OMV took on a 6% interest from Equinor in PL 050 FS effective 29 Oct '19. The diminutive licence (2 sq km) lies east of Rimfaks and permits ops between the Top Brent and the Base Statfjord. Partnership Equinor (op), Petoro, Spirit Ergy + OMV.

Equinor has transferred 6% of its interest in PL 050 FS to OMV.

On 14 July 2020, SDX Energy (SDX) announced the selling of its working interest in the Al-Amir JV operating the NW Gemsa concession, onshore Gulf of Suez Basin, to Gulf Energy. Following this USD-3-million transaction, SDX will use USD1.4 million to discharge its remaining liabilities on the concession. SDX decided in May 2020 to sell its stake in the NW Gemsa concession. The latter comprises three production fields, each located in a development block: North West Gemsa (Dev) Geyad, North West Gemsa (Dev) Al Amir and North West Gemsa (Dev) Al Ola. The Geyad field discovered in 2009 includes three wells and has a daily production rate of 670 bbls. The Al Amir and Al Amir Southeast/Al Ola fields discovered in 2005 and 2008 have combined gross production of 3,060 bbl/d with 11 wells. All three fields have operating costs of approximately USD 10/bbl and are fully developed. GANOPE (50%) and North Petroleum (25%, operator) are expected to remain partners with Gulf Energy (25%) in the JV.

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

Woodside and partner Mitsui secured WA-93-R + WA-94-R, 159 sq km each in the Exmouth sub-basin, North Carnarvon Basin on 29 Apr '20 for 5 years. Both permits covers part of WA-430-P, WA-93-P containing the 2014 Toro gas discovery, whereas WA-94-R contains the 2012 Ragnar 1A gas discovery.

Australia (North Carnarvon B.) ? op. by WOODSIDE (70%), MITSUI (30%) in WA-430-P (b) block

Add. DEA 29 Apr ’19: Block 15-1/05, Cuu Long Basin, TD 4,297m,  98m net oil pay in the Late Oligocene Tra Tan ‘G’ target,  19m net oil pay in the secondary D sequence, est. 39 MMboe resources, P&A on 25 Apr ’19, PV Drilling I JU. Murphy (op), partners PVEP + SK Inno.

15-1/05-LDT 1X (Lac Da Trang-1X) (Murphy 40% op, PVEP 35%, SK Inno. 25%) in Block 15-1/05, P&A encountered 98m of net oil pay in the primary objective and an additional 19m of net oil pay in a secondary objective, target Late Oligocene Tra Tan ‘G’.

SE part of Urmanskoye field, Archinskiy licence in Tomsk Oblast, W. Siberia, TD 3,660m, tested 670 bo/d from Paleozoic carbs, 37 MMbbl OIP, 11 MMbbl recoverable. Horiz drilling is planned. Gazprom Neft-Vostok = Gazprom Neft - Mubadala JV.

Urmanskaya 26 npw. (Gazprom Neft-Vostok 100%) in the SE extension of the field Urmanskoye field in the Archinskiy license in Tomsk Oblast, discovery of a new pool, tested oil at a rate of 670 b/d from carbonate reservoirs of the Paleozoic basement. The company estimated 3P oil reserves of the pool at 37 MMbbl in-place and 11 MMbbl of recoverable. TD=3 660 m.

The application deadline for Uganda's 2nd round, open since May, has been extended from 22 Nov to 31 Dec '19. 5 blocks totalling 4,928 sq km are on offer (DEAs 13 May, 16 Sep ’19 + map). Data room + contact: Ikechi Vera Maduako (Schlumberger), email [email protected].

Uganda, not found

In early April 2018, Tecpetrol Colombia SAS abandoned the Tillava Sur-1H horizontal appraisal well in a southeast portion of the heavy oil Llanos Basin CPO-13 Block, according to industry sources. The appraisal well was spudded in mid-March 2018 to target the basal sands of the Carbonera Formation. It reached a final TD of 1,370m, about 800m NE of its surface location, in late March 2018. Initial production testing yielded 2,047 bo/d with 13.8deg gravity oil but with a 97% water cut and therefore the well was abandoned. This is similar to the Tillava Sur-1 NFW drilled in early 2015 which found oil in the Carbonera Formation. Then-partner PetroNova reported in February 2015 that Tecpetrol has recorded surprisingly low flow rates of good-quality oil with a 96% water cut in the well. Once the borehole was gravel packed, cased and cemented at an interval of 814-817m in the Carbonera Formation, tests were conducted using a jet pump. Upon completion of flow tests, the jet pump was found to be choked with viscous heavy oil. CPO-13 is operated 100% by Tecpetrol.

Colombia, CPO 13

On 3 November 2017 Key Petroleum Ltd reported that its purchase of Beach Energy’s interest in ATP 783-P, ATP 920-P and ATP 924-P, located in the Cooper Basin, had been officially registered by the Queensland Department of Natural Resources and Mines (DNRM).  Key reported that it will now commence discussion with the DNRM around the work programme assigned to the permits, which will focus on conventional gas exploration within the Permian gas fairway. The deal, which was completed via Key’s subsidiary company Key Cooper Basin Pty Ltd, was reported to have been finalised between the companies on 28 June 2017.  The agreement was first announced on 22 February 2017. Beach had been offering equity in the permits as part of a farm-out offer but under the agreement, Key has agreed to purchase 100% interest for an immediate payment of AUD 125,000, plus a royalty of 1.5% of the wellhead value for all future petroleum produced, to Drillsearch Energy (a subsidiary of Beach). The finalisation of the transaction now remains only subject to Ministerial approvals. Beach currently participates in 442 permits and licences within the Cooper-Eromanga Basin and is the operator in 108 permits and licences. Upon completion of the deal, Key will be entering the basin for the first time at low cost. Key currently operates in the Canning and Perth basins and has been seeking opportunities to expand its portfolio to add value to the company. Beach Energy currently holds 100% interest in all three permits which cover a total area of 6,764 sq km. The permits have little time remaining before renewals must be approved as they were scheduled to expire in February 2017 (ATP 920-P, and ATP 924-P) and May 2017 (ATP 783-P). Only one well has been drilled during the validity periods: Maroochydore 1, in ATP 924-P, which was plugged and abandoned in November 2015 with oil shows. A five well drilling campaign formed part of the work commitments between 2013 and 2017 along with two in ATP 783-P and five in ATP 920-P. Key reports that a number of leads and prospects across the permits have been mapped from seismic data facilitating an exploration strategy over the remaining permit terms. Key Petroleum Ltd has completed purchase agreement with Beach Energy for three Cooper-Eromanga Basin permits. Once the transaction has been fully approved, Key will hold 100% interest in ATP 783-P, ATP 920-P and ATP 924-P.

Key Petroleum reported that its purchase of Beach Energy’s interest in ATP 783-P, ATP 920-P and ATP 924-P.

3rd sidetrack of deep (pre-salt) well in BNG (Yelemes-Ayirshagyl) block, TD 4,421m, flowed initial 3,500 bo/d from between 4,335-4,420m on 11mm choke for 4 hours on 21 Oct ’17, WHP 2,321-4,351 psi, well now shut-in for pressure build-up, already at 6,887 psi.  Of note, the original PTD 4,700m has not been reached owing to HPHT at depths.

Kazakhstan, not found

P1368, Greater Warwick area  West of Shetlands, TVD 1,780m, 720m horiz section in fractured basement reservoir, DST’ing, oil to surface resulting in a flare, now shut-in for pressure bulid, too early for results. Transocean Leader SS. Hurricane (op), partner Spirit Energy.

United Kingdom, not found

Cairn announced on 10 September 2019 that DNO has farmed into licence P2312 which contains the Chimera prospect. DNO has acquired a 15% interest in the licence in which Cairn plans to spud an exploration well on Chimera in Q4 2019. The deal is pending regulatory approval. Licence P2312 was awarded in the 29th Frontier Licensing Round in 2016. The licence covers an area of approximately 220 sq km. The nearest discovery is 3/17-2 (Tryfan) located roughly 3 km to the east. Chimera has an amplitude and AVO supported trap comprising a 3-way dip closure with up-dip stratigraphic pinch-out. Cairn estimate Chimera to hold 154 MMboe recoverable resources (>1 Bboe in place).  If successful the prospect could be developed via a standalone FPSO. Suncor completed the farm-in taking a 40% interest in the licence in December 2018. Pending completion of a deal between Cairn and DNO interest in the licence will be held by Cairn subsidiary Nautical Petroleum Limited (45% + operator), Suncor Energy UK Limited (40%) and DNO (15%).

United Kingdom, not found

Block 15/06, Congo Fan, WD 1,699m, ops terminated Feb '20, understood successful, Sonangol Libongos DS. PTD was 2,668m. Eni (op), partners Sonangol P&P + Sonangol Sinopec Intl 15.

Agogo 3 appr. (Eni 36,84% op. Sonangol 36,84%, SSI Fefteen 26,32%) in Block 15/06, ops. terminated. Sources indicated that the appraisal was successful and will result in an upward revision of the reveres number (currently estimated at some 150 MMboe). WD=1 699m, PTD was 2 668m.

INPEX has acquired its first Norwegian licence through a deal with Bayerngas. The company confirmed on 15 September 2017 that it would take Bayerngas’ 40% interest in PL 767 which lies to the north of Snohvit and southeast of Alta. The NPD reported on 1 December 2017 that the deal had completed (effective from 27 November 2017). PL 767 covers an area of 211 sq km over parts of blocks 7120/3, 7121/1, 7121/2 and 7121/4. INPEX was pre-qualified as an NCS licensee in 2014 but until now had not acquired any assets. INPEX is headquartered in Tokyo and is active globally with assets in areas including Japan, Indonesia, Australasia, the Caspian region, the UAE, West Africa and the Americas. It was part of the consortium of 33 companies, led by Statoil, which jointly acquired seismic in the Southeast Barents Sea in summer 2014 prior to the 23rd Licensing Round. Although it applied for acreage in the 23rd Round it was unsuccessful. Following completion of the deal interest in PL 767 is held by Lundin Norway AS (60% + operator) and INPEX Norge AS (40%).

Norway (Hammerfest Sub-basin (Barents Sea Platform)) Snohvit

Armour secured ATP 2032-P,  318 sq km on the Roma Shelf, Bowen-Surat Basin, on 11 Sep ’18 for 12 years. It lies adjacent to Armour’s PL 22 which contains a number of o&g discoveries.

Armour secured ATP 2032-P, 318 sq km on the Roma Shelf, Bowen-Surat Basin, on 11 Sep ’18 for 12 years. It lies adjacent to Armour’s PL 22 which contains a number of o&g discoveries.

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

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

Australia’s 2018 Offshore Petroleum Exploration Acreage Release was announced today. A total of 21 areas is available in the Bonaparte, Browse, North Carnarvon, Bight, Victoria Otway + Gippsland basins – 16 for work programme bidding and 5 for cash bidding. The table below is also available from www.petroleum-acreage.gov.au (as is a synoptic map):

Australia’s 2018 Offshore Petroleum Exploration Acreage Release was announced today. A total of 21 areas is available in the Bonaparte, Browse, North Carnarvon, Bight, Victoria Otway + Gippsland basins – 16 for work programme bidding and 5 for cash bidding. The table below is also available from www.petroleum-acreage.gov.au

Roc Oil Co Ltd is seeking joint venture partners for Block 03/33 PSC in the offshore Pearl River Mouth Basin. Roc Oil is offering up to 50% interest in the Block 03/33 Area A, which contains the Huizhou 12-5 oil discovery and is estimated to contain recoverable reserves of 22 MMbo. The company is also offering up to 25% interest in the Block 03/33 Area B where a two well exploration drilling programme is planned in 2H 2020/early 2021. Roc Oil is the operator and sole rightholder of Block 03/33 Area A and holds a 50% operating interest of Block 03/33 Area B with joint venture partner CNOOC holding the remaining 50% interest. CNOCC also have the rights to participate in up to a further 51% interest in any field development.<P />

Roc Oil Co Ltd is seeking joint venture partners for Block 03/33 PSC in the offshore Pearl River Mouth Basin. Roc Oil is offering up to 50% interest in the Block 03/33 Area A, which contains the Huizhou 12-5 oil discovery and is estimated to contain recoverable reserves of 22 MMbo.

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

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

Predator and partner Theseus have applied for Celtic Sea Licensing Option (LO) 16/30 to be converted to an Exploration Licence (EL), following LO16/30 expiry on 30 November 2019. LO16/30 (799 sq km) was awarded on 1 December 2016 via the Celtic Sea open door policy, and had a one year extension granted in 2018. Predator has agreed a work commitment of purchasing and reprocessing existing 2D seismic data and to continue desk-top studies focusing on the Ram Head gas discovery 49/19-1 (1984, Marathon, 3,602m) in Middle and basal Upper Jurassic sandstones, with potential oil upside in Cretaceous Upper Purbeck sands. SLR Consulting has estimated gross best case resources of 1 Tcfg and 189 MMbo. It is located 40km E of the producing Kinsale Head Field and 70km from shore. The acreage also contains the Ardmore gas discovery made with the NFW 49/14-1 (1975, Marathon, 2,427m). LO16/30 is operated by Predator Oil and Gas Ventures Ltd (50%) and partner Theseus Ltd (50%).

Predator (50% op, Theseus 50%) has applied to convert its LO16/30 to a full explo licence (EL). The permit covers the L. Cretaceous Nemo + Ardmore discoveries.

Puguang field area, Sichuan Basin, TD in Nov '19, earlier this month tested 4.6 MMcfg/d on 10 mm choke from between 3,545-3,945m in the Jurassic Qianfoya fm.

Pulu 3 npw, (Sinopec – Zhongyuan 100%) achieved an important breakthrough in the Puguang prod. block, well tested 4,6 MMscf/d of gas, through a 10 mm choke, at an interval between 3545 and 3945 m in the Jurassic Qianfoya Fm. The success of Pulu 3 demonstrated gas exploration prospective on the Jurassic play in this area and indicated 4.4 Tcf of geological gas resources. Pulu 3 was drilled in the outside of the Puguang field area with non-marine play target in the Jurassic Qianfoya Fm.

Campo Bremen, Chorrillos, Moy Aike, Oceano + Palermo Aike are identified as the prod. leases interOil farmed-into from Roch in the Austral Basin. An 8.34% interest changed hands in the so-called Santa Cruz Sur Assets.

Interoil closed an agreement with Roch under which it acquired an 8.34% interest from the latter in 5 mature prod. leases designated Santa Cruz Sur Assets (Campo Bremen, Palermo Aike, Moy Aike, Oceano, Chorillos).

An explo well has been drilled in the Hoffe Park field area in Mississippi Canyon block 122, WD 1,218m, reportedly oil in multiple zones, Deepwater Asgard DS still on location.

An explo well has been drilled in the Hoffe Park field area in Mississippi Canyon block 122, WD 1,218m, reportedly oil in multiple zones,

By September 2018, Apache was understood to have successful completed its North Ras Qattara 255 18 (NRQ 255 18) appraisal/development well as an oil producer. The well was drilled on the NRQ Part B development lease (DL) of the NRQ concession in the Alamein Basin. It reached 2,529m TD in the Cretaceous Kharita Formation, with operations carried out by the Egyptian Drilling Company #61 rig. NRQ 255 18 is understood to have been an appraisal of the 2016 NRQ 9X discovery (TD 2,583m), located ~1km SE. It tested 1,080 bo/d from the Cretaceous Abu Roash. The well is one of two drilled on the block in 2018. Apache operates NRQ with 23.45% equity, in partnership with Sinopec (11.55%), IPR (15%) and EGPC (50%, carried).

Apache was understood to have successful completed its North Ras Qattara 255 18 (NRQ 255 18) appraisal/development well as an oil producer. The well was drilled on the NRQ Part B development lease (DL) of the NRQ concession in the Alamein Basin. It reached 2,529m TD in the Cretaceous Kharita Formation

Lion Energy signed a farm-out agreement for the transfer of a 40% participating interest in the East Seram PSC, located in onshore/offshore North Seram Basin, to Taiwan's CPC Corporation (via subsidiary OPIC East Seram Corporation), on 25 September 2019. OPIC has agreed to the following: Pay 80% of Lion's historical costs in the block until 31 August 2018 (approximately USD 0.94 million) and its 40% share of the performance bond collateral (USD 0.15 million). Fund 80% of seismic cost, capped to USD 8.5 million, towards exploration commitments in the block. Any additional seismic cost will be allocated on the basis of participating interest. Fund its 40% share of all other joint venture costs, starting from 1 September 2018, under a Joint Operating Agreement (JOA) to be agreed upon. Carry 20% of Lion's drilling cost for any follow up exploration well in the block, repayable from future production. According to Lion, the above financial terms imply an approximate value of USD 8.4 million for the remaining 60% interest in the block. Upon signing of the JOA, Lion will receive a cash amount of approximately USD 1.3 million (inclusive of OPIC's 40% share of joint venture costs since 1 September 2018). The deal is subject to government approval and to signing of the JOA. Upon completion, participants in the block will be Balam Energy Pte Ltd (a wholly-owned subsidiary of Lion) with 60% operating interest, and OPIC East Seram Corporation (a wholly-owned subsidiary of CPC) with 40%. Lion initially offered a farm-in opportunity for the block in May 2018, shortly after the official award. The main exploration targets in the area are Jurassic Manusela Formation carbonates and Pliocene Fufa Formation sandstones. The operator estimates unrisked prospective resources (P50) of 1,238 MMboe in the block, from a total of 18 prospects and leads. Key leads and prospects will be further delineated by a 500-km commitment seismic survey planned in 2020. CPC Corporation is a Taiwan-based company which focuses on natural gas, petrochemicals and gasoline. The company holds upstream interests in Taiwan, Australia and Africa. In Indonesia, the company was holding a 16.67% participating interest in the Sanga-Sanga PSC until 2018, when the contract expired and the block was awarded to Pertamina. Background Information The East Seram block was offered on 19 February 2018 under the Conventional Oil and Gas Bidding First Round 2018, under the Direct Offer mechanism. Lion Energy was announced as the winner for the East Seram block on 2 May 2018. The gross split contract was signed on 17 July 2018, with Signature Bonus amounting to USD 500,000. Firm commitments for the first three years of exploration consist of 500 km 2D seismic acquisition. The 6,500 sq km East Seram block is located in the Seram Basin, a structurally complex area with major structural highs related to the Seram Fold Belt. Historically, oil and gas seeps have also been identified. The basin is estimated to contain approximately 60 MMbo and 2 Tcf of gas discovered to date (2019). According to Lion, the analogy with fold belt plays in other regions indicates significant upside potential in the Seram Basin. The majority of the block area is located onshore in the eastern Seram Island, while a small portion is offshore. The block is surrounding the Seram (Non-Bula) PSC operated by CITIC Resources. Wells located within the block boundary are Wahai 1 (new field wildcat, shelf), Wahai 2 (new field wildcat, onshore), Ceram B 1X (new field wildcat, water depth of 115 m) and Belis 1 (new field wildcat, onshore). Other onshore wells located near the eastern side of the shore area (within the Seram (Non-Bula) PSC) are Metafoten 1, Salas 2, and Salas Barat 1. Two main plays have been proven in the area: a Mesozoic fold belt play, centered on carbonate reservoirs of the Jurassic Manusela Formation, and a shallow Plio-Pleistocene foreland play, with clastic reservoirs in the Fufa Formation.

Lion Energy (-> 60%, op.) had signed a Farmout Agreement with CPC Corp, through wholly owned subsidiary OPIC East Seram Corp, for the latter to acquire a 40% non-operating working interest in the on/offshore East Seram GSPSC.

On 16 July 2019 OKEA tendered its resignation of operatorship (pending management approval) from PL 973. The APA 2018 licence, covering a 166 sq km area over the central part of block 15/12, was awarded in March 2019. It contains three oil prospects (Jerv, Ilder and Mar) which could be drilled in 2020 / 2021 if the partnership moves past the initial two-year drill-or-drop phase. OKEA had previously stated that these were potential tie-back options to its adjacent Grevling development to the north. It is assumed that operatorship will be transferred to partner Chrysaor which operates the UK licences immediately west of PL 973, although Chysaor is not yet pre-qualified as an operator on the NCS. Jerv is a Paleocene Ty Formation prospect with a 57% chance of success and potential recoverable reserves of 60 MMboe. It could be drilled in 2020. Ilder is a Middle Jurassic Hugin Formation prospect with a 34% chance of success. Recoverable reserves could be 40 MMboe and drilling may take place in 2021. The Mar prospect also has a Hugin Formation target. Chance of success is lower at 18%, but potential recoverable reserves are 70 MMboe. It could also be drilled in 2020. Chrysaor holds 100% of the Armada area (Drake, Fleming, Hawkins, Maria, Seymour) across the border in the UK. Before any change of operatorship is effective, interest in PL 973 is held as follows: OKEA ASA (30% + operator), Chrysaor Norge AS (50%) and Petoro AS (20%).

Norway (South Viking Graben (Viking Graben Province)) Maria

According to local reports in early-September 2017, the Province of Santa Cruz has awarded license for the Tapi Aike block in Austral Basin to Cia General de Combustibles (CGC). No details are available at this time regarding the work commitments or amount of investment for the block. Background Information In June 2017, the Province of Santa Cruz reportedly issued a call for tenders for the Tapi Aike, Paso Fuhr, El Turbio, and El Turbio Este in its Licitacion Publica Nacional e Internacional call. All of the areas were relinquished to the province in 2015 due to lack of investments.

(Austral b.), Tapi Aike block was awarded to CGC (81%, op.) and ECHO EN (19%).

Assignments are understood to have been made under Colombia’s 20-block offer, aka Permanent Process of Assignment of Areas (PPAA). Ref. DEA 5 Jun ’19 (applicants), all blocks bar one (VIM 22) have been handed out. The VIM 22 outcome should be announced on 8 July:

Assignments are understood to have been made under Colombia’s 20-block offer, aka Permanent Process of Assignment of Areas (PPAA). Ref. DEA 5 Jun ’19 (applicants), all blocks bar one (VIM 22) have been handed out. The VIM 22 outcome should be announced on 8 July:

NE corner of block Z-38, offshore Tumbes Basin, WD ca. 360m, TMD 3,021m (top Cardalitos fm), P&A’ing minor gas shows in the target Tumbes fm, Stena Forth DS. Karoon (op), partner Tullow + Pitkin.

Marina 1 nfw (Karoon 40% op, Tullow 35%, Pitkin 25%), NE corner of block Z-38, offshore, P&A’ing minor gas shows in the target Tumbes Fm, WD ca. 360m, TMD=3021m (top Cardalitos Fm.).

Yetagun D&PA, offshore Mergui Terrace, P&A mid-Mar ’19, Hakuryu 5 SS to be released. Target Mergui Group (L.-M. Miocene fluvial sst). Petronas (op), partners Premier, MOGE, Nippon Oil + PTTEP.

Yetagun Southeast 1 (YTG SE-1) (Petronas 30% op, Myanmar O&G Enterprise 20,45%, Nippon Oil Explo. 19,32%, PTTEP 19,32%, Premier Petr. 10,91%) in the Yetagun Development & Production Area, P&A with results unreported.

Cabot Energy announced on 28 September 2018 that it was in discussions with potential farm-in partners for the F.R 39.NP and F.R 40.NP exploration permits in the Adriatic Zone F ahead of a 3D seismic acquisition and the drilling of an appraisal well on the Giove 2 discovery in the F.R 40.NP permit. The 670-sq km survey, planned for Q1 2019, will allow the company to mature the Cygnus prospect for drilling and to define an appraisal well location for the Giove 2 oil discovery. The 3D data will also help defining new drilling locations on some of the 10 mapped prospects in the Durres Basin acreage (southern Adriatic). Data integration in the analysis of the potential of the Medusa prospect in the F.R 39.NP highlighted a significant potential for the Cretaceous series. In March 2013 the mean prospective resources for the Cygnus prospect were evaluated by ERC Equipoise Ltd (ERCE) at 446 MMbbl of oil, of which 401 MMbbl lie within the F.R 39.NP permit area. The prospect trap is predominantly stratigraphic and the reservoir is the same as Aquila, i.e. the Paleocene-Jurassic carbonates (Scaglia, Maiolica and Aptici formations). Based on the assumption that the Cygnus prospect shares a common oil-water contact with the nearby Aquila oil field in Eni's F.C 2.AG concession, high case (P10) resources are estimated at 978 MMbbl of oil, of which 790 MMbbl lie in the F.R39.NP permit. The chance of success for the Cygnus prospect is estimated at 12%. In addition, ERCE assigned 2C contingent resources of 26 MMbbl of oil for Giove 2. Northern Petroleum (now Cabot Energy) was awarded the adjoining F.R 39.NP and F.R 40.NP contracts on 21 and 22 June 2007. Both blocks are covering 735 sq km and are sited in water depths between 150 m and 500 m in the southern Adriatic Sea. The company completed the acquisition of 600 km of 2D seismic over the two permits in November 2011. Due to the lengthy approval process relating to the 3D seismic program, the contracts were suspended on seven occasions between 2012 and 2017 for a total of five years and six months (as of November 2017). In November 2016 Northern Petroleum announced that it had agreed to farm-out a 10% interest in both permits to High Power Petroleum LLC (subject to approval). Northern Petroleum (UK) Ltd, a wholly-owned subsidiary of Cabot Energy Plc, holds a 100% interest in the F.R 39.NP and F.R 40.NP exploration permits. For further information please contact the following: Keith Bush:  [email protected] Carlo Caldarelli: [email protected] Cabot Energy Plc Chester House, Kennington Park, 1-3 Brixton Road, London SW9 6DE Tel: +44 7469 2900 Fax: +44 7469 2901

Italy (Apulian Platform - South Adriatic-Durres B.) Giove 2

Genel has agreed to acquire an interest from Chevron in the latter’s Sarta and Qara Dagh blocks in Kurdistan.  Genel will get 30% in Sarta by paying 50% of ongoing field devt costs until a specific production target is reached. Chevron retains a 50% and the KRG 20%. It will get 40% in the Qara Dagh appraisal licence as well as operatorship through a carry arrangement. Chevron retains 40% and the KRG 20%. Closing is pending KRG approval.

Genel will gain a 40% stake in the Qara Dagh exploration licence, as well as take over operatorship from Chevron (->40%, KRG 20%). Genel has also acquired a 30% interest in the Sarta licence in return for paying 50% of ongoing field development costs, with Chevron retaining a 50% operating stake and the KRG on the remaining 20%.

In April 2018, Khalda Petroleum Co. (Khalda) suspended the Bravo South 1 exploration well in the Khalda Offset (New) A-East (Khalda Offset Ext III) as an oil & gas well. The well was spudded on 31 March 2018, using “EDC-57” land rig and drilled to a depth of 4,572 m in the Ras Qattara formation. The well had a PTD of 4,572 m and objectives in the Aptian Alam El Bueib 6 Unit, Middle Jurassic Lower Safa Unit and the Upper Jurassic Massajid formation. Background Information In May 2012, Khalda suspended the Bravo 1 wildcat after the well reached TD of 4,932 m in the Lower Safa Unit. The well was spudded on 25 January 2012 using “EDC-41” with a PTD of 4,877 m and Safa Member, Alam El Bueib "5" and Alam El Bueib "6" units as the objectives.

Bravo South 1 ( ) in the Khalda Offset (New) A-East (Khalda Offset Ext III) as an oil & gas well, objectives in the Aptian Alam El Bueib 6 Unit, Middle Jurassic Lower Safa Unit and the Upper Jurassic Massajid formation.

The NPD confirmed on 9 June 2018 that DEA has transferred its 30% interest in PL 771 to operator MOL with effect from 31 May 2018. This deal follows two earlier deals relating to PL 771 and also PL 617: in April 2018 Fortis withdrew from both licences, transferring its 30% interest to MOL. MOL then passed this equity to OMV with effect from 22 May 2018. The licences are located immediately east of Valhall on the Norwegian / Danish border. PL 617 covers 112 sq km over part of block 2/9 and PL 771 covers 260 sq km over parts of blocks 2/8 and 2/9. Valhall was discovered in 1975 by well 2/8-6 drilled by Amoco and first oil was produced in October 1982 from the field’s Upper Cretaceous chalk reservoir (Tor and Hod formations). By January 2017 the field, together with Hod, had produced 1 Bboe, more than three times what was expected in the original PDO. The operator has ambitions to produce at least another 500 MMboe over the field’s lifetime. Following completion of all deals, MOL Norge AS operates both PL 617 and PL 771 with a 70% interest and is partnered by OMV (Norge) AS (30%).

DEA has transferred its 30% interest in PL 771 to operator MOL with effect from 31 May 2018. This deal follows two earlier deals relating to PL 771 and also PL 617:

Spirit acquired a 40% stake from Suncor in undrilled PL 780 / part-block 16/1 effective 14 Aug ‘19. Spirit is now sole holder of the 18-sq km licence.

Norway, PL 780

Makori D&PL, Potwar onshore, TD 3,916m (Paleocene), DST on since early August, flowed 1,844 b/d and 18.25 MMcf/d on a 32/64” choke from Lockhart fm, to be put on production in Dec ’19, KCA T-72 rig. MOL (op), partners OGDC, PPL, POL + GHPL.

Makori Deep 2 (MOL 8,43% op, PPL 27,76%, OGDCL 27,76%, POL 21,05%, GHPL 15%) on the Tal (3370-3EL) block in the Kohat plateau of Khyber Pakhtunkhwa (KP) province, significant hc discovery, initial DST of the Lockhart Fm. delivered 1844 bo/d and 18,25 MMscf/d [32/64-inch fixed choke].

On 28 December 2017, Belorusneft reported two new oil discoveries in the Pripyat Graben. An exploratory well, drilled at the Makanovichskiy Vostochnyy prospect, tested oil at a rate of 63 b/d from a reservoir in the Semiluki Formation at a depth of 4,200 m. The operator estimated 2P reserves of the discovery at 6.4 MMbbl in-place and 2.8 MMbbl of recoverable. The discovery belongs to the Azeretsko-Khobninskaya structural zone of the central Pripyat Graben. In 2018, Belorusneft plans to record 353 sq km of 3D seismic over the zone. In the Northern Structural Zone of the Pripyat Graben, Belorusneft drilled an exploratory well at the Girovskiy Zapadnyy prospect. The well encountered 6 m of oil pay in the Semiluki Formation. Oil saturation is estimated at 74%. The operator plans to test and complete the well in the first quarter of 2018.

An exploratory well, drilled at the Makanovichskiy Vostochnyy prospect, tested oil at a rate of 63 b/d from a reservoir in the Semiluki Formation at a depth of 4,200 m. The operator estimated 2P reserves of the discovery at 6.4 MMbbl in-place and 2.8 MMbbl of recoverable.

Sapura Energy (previously known as SapuraKencana Petroleum) has plugged and abandoned new-field wildcat Jarak 1 in SK-408, located in the offshore Central Luconia Province, on or around 23 January 2018. Results have not been released. The well, spudded on 29 November 2017 using the Transocean “Deepwater Nautilus” S/S, tested the Middle Miocene Cycle IV / V carbonate play. The well was part of a three well exploration campaign. Remunjung 1 (first well in the campaign) and Pepulut 1 (third well in the campaign) was drilled between mid November 2017 and mid January 2017. Both wells were drilled using the “Hakuryu-11” J/U and tested the Middle Miocene Cycle IV / V carbonate play. Results have not been released. The last activity in the block was the Luconia Terumbu 3D survey acquired using the CGG’s “Geo Caspian” S/V between October 2015 and May 2016. The survey covered an area of approximately 12,500 sq. km over the blocks SK-320, SK-408, SK-319 and SK-318 in the Central Luconia Province. It was a joint acquisition by Mubadala Petroleum, Sapura Energy and Sarawak Shell Berhad. Sapura Energy is the operator of SK-408 with 40% interest. Partners include Shell (30%) and Petronas Carigali (30%). The gas discoveries made by Sapura Energy are Teja 1 (2014), Gorek 1 (2014), Legundi 1 (2014), Larak 1 (2014), Bakong 1 (2014), Jerun 1 (2015) and Jeremin 1 (2015).

Jarak 1 op. by Sapura (40% op, Shell well op 30%, Petronas 30%) in SK-408 block, off Central Luconia, P+A results n/a.

Following the ratification on 21 June 2020 of 8 agreements signed earlier in the year between IOCs and Egyptian state-agency EGAS for the exploration of hydrocarbon in the Mediterranean Sea (separate article), it is understood that Total has been awarded the North Ras Kanayes offshore concession. The block, which is of 6,217 sq km is located along the Egyptian coastline, extending across boundary between the Northern Egypt and Herodotus basins. In June 2020, North Ras Kanayes was the single block Total hold as operator in Egypt.

(Northern Egypt and Herodotus basins) Following the ratification on 21 June 2020 of 8 agreements signed earlier in the year between IOCs and Egyptian state-agency EGAS for the exploration of hydrocarbon in the Mediterranean Sea (separate article), it is understood that Total has been awarded the North Ras Kanayes offshore concession. The block, which is of 6,217 sq km is located along the Egyptian coastline, extending across boundary between the Northern Egypt and Herodotus basins. In June 2020, North Ras Kanayes was the single block Total hold as operator in Egypt.

Kosmos Energy has completed drilling the Lamantin-1 exploration well located in Block C-12 offshore Mauritania in approx. 2,200 meters of water. Lamantin-1 was drilled to a total depth of 5,150 meters and was designed to evaluate a previously untested Lower Campanian base of slope fan supplied from the Nouakchott River system, trapped in a combination structural-stratigraphic feature, and charged from underlying, oil-prone Cenomanian/Turonian and Albian source rocks. As interpreted from logs and samples collected during drilling and wireline operations, the Company's evaluation suggests the Campanian reservoir objective was water bearing with some residual hydrocarbons. Kosmos believes the prospect failed due to a lack of trap, related to a combination of up-dip sand pinch-out and top / base seal effectiveness. The well will now be plugged and abandoned and the well results integrated into the ongoing evaluation of the significant remaining prospectivity in Kosmos’ large acreage position. Andrew G. Inglis, chairman and chief executive officer, said: 'We are still in the early stages of exploring this newly emerging basin and our forward drilling program remains unchanged given the independent nature of the prospects. The drillship will now proceed as planned to test the independent Requin Tigre prospect offshore Senegal, which will be followed by two high-impact oil tests offshore Suriname in mid-2018.' The Requin Tigre prospect is a Cenomanian/Albian base of slope fan supplied from the proven Senegal River system, and is located approx. 150 kms offshore, 60 kms west of the Tortue discovery, and 80 kms north of the Yakaar discovery in approx. 3,100 meters of water. It is estimated that drilling will take approx. sixty days. Kosmos holds rights in the C-6, C-8, C-12, C-13, and C-18 contract areas under production sharing contracts with the Government of Mauritania’s Société Mauritanienne Des Hydrocarbures et de Patrimoine Minier (SMHPM). The blocks range in water depth between 100 and 3,000 meters, and have combined acreage of over 40,000 sq kms gross. Kosmos is the exploration operator of Block C-12 with 28 percent equity and is joined by its partners BP (62 percent) and SMHPM (10 percent). Original article link Source: Kosmos Energy

Lamantin 1 op.by Kosmos (28%, BP 62%, state SMHPM 10%) in C-12 block, P&A, after encountred, previously untested, Lower Campanian water-bearing reservoir with some residual hydrocarbons. Kosmos said that “the prospect failed due to a lack of trap, related to a combination of up-dip sand pinch-out and top/base seal effectiveness”. TD=5150m.

On 7 December 2018, the State Agency for Geology and Subsoil Use of Ukraine announced an auction for ten licenses. The auction is scheduled for 6 March 2019 with its application deadline on 5 March. Additional information can be requested from: Kiev Antona Tsedika Str., 16, offices 415 & 416 Tel: (044) 536 1320 and 456 6085 The Suvorivska block covers 463 sq km on the south-western edge of the Moldavskaya depression in Odeska Oblast. Reservoirs of the Jurassic and Triassic sections (2,000-4,500 m) are the main target for exploration. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounts to UAH 9.221 million (USD 0.33 million). The winner of the auction will obtain a 5-year exploration license. The Zakhidnotokarsko-Krasnyanska block covers 91 sq km in Luhanska Oblast (Dnieper-Donets Basin). Seismic coverage amounts to about 500 km. Gas resources of the block are estimated at 31 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounts to UAH 4.596 million (USD 0.16 million). The winner of the auction will obtain a 20-year E&P license. The Dykhtynetska block covers 74 sq km in Chernivtsi and Ivano-Frankivsk Oblasts (Western Ukraine). Seismic coverage amounts to about 200 km. Oil resources of the block are estimated at 3 MMbbl of oil. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounts to UAH 10.099 million (USD 0.36 million). The winner of the auction will obtain a 20-year E&P license. The Pivdenno-Kobzivska block covers 368 sq km in Kharkiv Oblast (Dnieper-Donets Basin). Seismic coverage amounts to about 1,000 km. Oil resources of the block are estimated at 24 MMbbl. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounts to UAH 9.623 million (USD 0.34 million). The winner of the auction will obtain a 20-year E&P license. The Kniazhynska block covers 75 sq km in Kharkiv Oblast. Seismic coverage amounts to about 250 km. Hydrocarbon resources of the block are estimated at 107 MMbbl of oil, 2.1 Tcf of gas and 30 MMbbl of condensate. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounts to UAH 498.43 million (USD 17.8 million). The winner of the auction will obtain a 20-year E&P license. The Saltivska block covers 26 sq km in Kharkiv Oblast. Seismic coverage is limited to a single regional line. One well has been drilled in the block. Gas resources of the block are estimated at 0.2 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounts to UAH 18.319 million (USD 0.65 million). The winner of the auction will obtain a 20-year E&P license. The Pechenizko-Kochetkivska block covers 263 sq km in Kharkiv Oblast. Seismic coverage is limited to about 900 km. Gas resources of the block are estimated at 63 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounts to UAH 11.701 million (USD 0.4 million). The winner of the auction will obtain a 20-year E&P license. The Svitankovo-Lohinska block covers 197 sq km in Kharkiv Oblast and it encompasses three structures. Seismic coverage amounts to about 700 km. One well has been drilled in the area. Hydrocarbon resources of the block are estimated at 6 MMbbl of oil and 122 Bcf of gas. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounts to UAH 498.43 million (USD 17.8 million). The winner of the auction will obtain a 20-year E&P license. The Dubrivsko-Radchenkivska block covers 65 sq km in Poltava Oblast (Dnieper-Donets Basin) and it encompasses the Radchenkivske and Radchenkivske Zakhidnyy fields. Seismic coverage amounts to about 800 km. About 100 wells have been drilled at the fields. Hydrocarbon 3P reserves of the fields are estimated at 12 MMbbl of oil and 17 Bcf of gas. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounts to UAH 17.502 million (USD 0.63 million). The winner of the auction will obtain a 20-year E&P license. The Vatazhkivska block covers 182 sq km in Poltava Oblast and it encompasses the Vatazhkivska prospect with gas resources estimated at 106 Bcf. Seismic coverage amounts to about 500 km. One well has been drilled in the area. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounts to UAH 18.178 million (USD 0.65 million). The winner of the auction will obtain a 20-year E&P license.

Ukraine (Dnieper-Donets Graben (Dnieper-Donets B.)) Radchenkivske

Obiafu-Obrikom fields area, OML 61, onshore Niger Delta, TD 4,374m, Oligocene gas-cond find in deeper sequences, >130m high quality hc-bearing sands accounting for ab. 1 Tcfg + 60 MMbc.  There is also further potential that will be assessed with the next appraisal campaign. The well can deliver >100 MMcfg/d + 3,000 bc/d, on stream immediately.

Obiafu 41 deep well (NAOC 100% = Eni 20% op. NNPC 60%, Nigerian independent 20%) in OML61 block, hit more than 130m of high quality hydrocarbon-bearing sands. “The find amounts to about 1 Tcf of gas and 60 MMb of associated condensate in the deep drilled, Oligocene sequences,” Eni said. According to the operator, the well can deliver in excess of 100 MMscf/d of gas and 3000 b/d of associated condensates, on stream immediately. TD=4374m.

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

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

Exxon has acquired Suncor’s 35% in EL 1134, 2,089 sq km in the Flemish Pass Basin. Exxon is now sole holder:

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

During June 2018, a new company named Dragon Oil (registered in Nigeria and Cote d’Ivoire) was awarded coastal block CI-24. The company (not to be mistaken with Dubai-based Dragon Oil Ltd) not only intends to re-develop and bring back the Belier oil field into production, but also has plans to explore the surrounding areas and develop the gas reserves in the block. Belier is the first commercial discovery and the first field to come onstream in Cote d'Ivoire. ExxonMobil (Esso) produced almost 20 MMbbl of oil for 12 years from the Belier field, before abandonment in 1992. Two other discoveries were made in the mid-1970s, but never developed (Ivco 6 and Ivco 8). The 839 sq km block CI-24 is located offshore Abidjan. The northern limit of the block is the coastline and it adjoins to the east Vitol’s block CI-202. Water depth varies from 0 m in the north to 1,500 m in the southwest corner of the tract.

Ministry of Energy awards 9 blocks from 11 E&P blocks proposed for the last auction that took place on 27 June 2018.