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Cairn confirmed in its full year announcement in March 2020 that it had agreed an asset exchange agreement with Shell involving two licences P2379 (blocks 22/11b, 22/12b, 22/16b and 22/17c) and P2380 (block 22/12d). The exchange concerning the two licences was complete on 23 June 2020. In the UK, Cairn operates through its wholly owned subsidiary - Nautical Petroleum. Shell has acquired a 50% interest in licence P2379 which contains the Diadem prospect, the licence has a firm well commitment that is expected to be drilled in 2022. In exchange for the P2379 interest, Cairn has acquired a 50% interest in licence P2380 from Shell. The P2380 licence has a firm well commitment well on the Jaws prospect, which is expected to be drilled in 2H 2021. The Jurassic Fulmar sandstone play is prolific in the area and if the wells are successful then they could be tied into the Nelson facilities. The commitment well for Jaws is required to be drilled to a depth of 3,730 m or the base of the Upper Jurassic. P2380 was awarded in the 30th Offshore licensing round which focussed on ‘mature’ areas of the North Sea and comprises of just one block – 22/12d. Any potential discoveries could be used to extend the field life at Nelson. Shell also picked up licence P2377 in the 30th Round which also contains a firm commitment well on a prospect known as Orlov and is within reach of a tie-back to Nelson. In September 2019 Zennor Petroleum and ONE-Dyas pulled out of licence P2379 leaving Cairn as the sole participant. The licence comprises of four blocks – 22/11b, 22/12b, 22/16b and 22/17c and contains three discoveries 22/11b-3 (Lima), 22/12a-10 (Phoenix) and 22/16-6 (Dalziel). The first of the three discoveries was 22/12a-10 (Phoenix) back in 2004. The discovery was made by Shell as a near field exploration project for the Nelson facilities. The discovery was appraised in 2010 with well 22/12a-12 which confirmed oil bearing sands within the Forties Sandstone Member within a relatively simple and low risk 4-way dip closed structure. A sidetrack of the appraisal well 22/12a-12Y was kicked-off and penetrated the reservoir outside of the structure and did not encounter any hydrocarbons. 22/11b-13 (Lima) was discovered in 2008. The well targeted three Jurassic pods. Of the three pods, only one (Fulmar 1) contained oil which is stratigraphically trapped within thin sandstones pinching out before the pod. The most recent discovery was 22/16-6 (Dalziel) in 2015. This was drilled by ENGIE targeting the Upper Jurassic Fulmar prospect. It encountered oil and tested in excess of 8,000 boe/d. Following completion of the deals interest in the licences will be held by 50% each between Cairn and Shell.

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

Peruvian sources in early December 2017 indicate that Spain's Repsol received a new technical evaluation award (TEA) for Block LXIII in the Ucayali Basin. The block is located between Gran Tierra blocks 133 and 107 and Cepsa Block 131 with the southern portion of the block reaching the northern edge of Pluspetrol Block 108 in the Ene Basin. The block is similar to the previous Block 195 at 3,400 sq km. However, Block LXIII extends much further to the south adding about 40% more area from the existing open area in the south. The newly awarded block is believed to have high potential for gas and oil discoveries. Only about one month earlier, Peru awarded 15 TEA contracts. Seven of the TEA's were awarded to Repsol for blocks LIII, LIV, LV, LVI, LVII, LXI and LXII with a total area of 48,842 sq km. Blocks LXI (7382 sq km) and LXII (7456 sq km) were awarded to Repsol as partially explored blocks in the Ucayali Basin. <P />

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Villamontes district in Gran Chaco, Chaco Basin, spudded 25 Oct ’18, shallow o&g discovery. Reserves pegged at 0.2 Tcfg + 11 MMbbl liquids in the Chorro, Tupambi + Iquiri fm’s. Some 35 MMcfg/d + 5,000 bo/d are thought achievable.

Chaco E. X-1 (Occidental Petroleum 51% op, YPFB 49%) in Block XIX-Chaco-Naranjillos, shallow o&g discovery. Reserves pegged at 0,2 Tcfg + 11 MMbbl liquids in the Chorro, Tupambi + Iquiri fm’s. Some 35 MMcfg/d + 5000 bo/d are thought achievable.

Coastal has taken over full rights to blocks TP/27, EP 475, 490 + 491 (aka Cerberus blocks) from Tanami Energy (Skye Energy Ventures sub) retro-effective 7 Sep '19 for AUD 1.2 MM. Cerberus totals 3,832 sq km on the Enderby Terrace + Peedamullah Shelf, N. Carnarvon Basin. Coastal is now looking to farmout to complete the remaining work programmes – 7 wells are required before the permits expire.

Coastal has taken over full rights to blocks TP/27, EP 475, 490 + 491 (aka Cerberus blocks) from Skye Energy Ventures for AUD 1.2 MM, Cerberus totals 3,832 sq km on the Enderby Terrace + Peedamullah.

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

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

Petrel Energy Ltd announced on 19 November 2018, that it and Warrego Energy Ltd had signed a non-binding term sheet for the merger of the companies, via a reverse takeover.  Under the terms of the deal, Petrel will acquire Warrego Energy.  It remains subject to customary, relevant authority approvals. A binding sale and purchase agreement will be the next steps in the transaction, which is expected to be signed in the coming weeks.  Under the initial terms outlined, Warrego shareholders will receive shares in Petrel, representing around 77% of the company.  A new listing of the combined company will be issued after the completion of the merger. Warrego holds interest in exploration permit EP 469, located in the Perth Basin, which covers an area of 224 sq km and was awarded on 16 April 2010. In June 2018 Strike Energy Ltd completed an agreement to acquire a 50% interest and operatorship in EP 469 from Warrego.  The companies will form a joint venture holding the permit, and a joint operating agreement will be signed. A well was included in the farm-in deal, which must be drilled within 24 months of the commencement of the joint venture.  It is thought that it would target the Erregulla West field, which lies in the south-west of the permit. No wells have been drilled under the permit’s validity to date, but it does contain the Erregulla oil and Erregulla West gas discoveries, made in 1966 and 1990 respectively.

Petrel Energy Ltd announced on 19 November 2018, that it and Warrego Energy Ltd had signed a non-binding term sheet for the merger of the companies, via a reverse takeover. Under the terms of the deal, Petrel will acquire Warrego Energy.

SE part of CNH-R03-L01-AS-CS-15/2018 contract, offshore Sureste Basin, WD 19m, drilled early Jul - early Aug ’19, DST planned, Odin JU then to drill Tolteca prospect in the same block. PTD was 910m. Hokchi (op), partner Talos.

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

PSCA 17/03, E. Lufeng Sag, WD 100m, target Miocene + Oligocene clastics, ops terminated early Jul ’19, results n/a, Kantan 4 SS.

Lufeng 11-2-1 (LF 11-2-1) nfw PSCA 17/03, E. Lufeng Sag, WD 100m, target Miocene + Oligocene clastics, ops terminated early Jul ’19, results n/a,

Cue Energy, partner of Ophir Energy in the Sampang PSC, located in the offshore East Java, reported on 7 December 2018 that the wildcat Paus Biru 1 has flowed at a maximum rate of 13.8 MMcfg/d of gas from a drill stem test (DST) over the 576 m – 605 m (MD) interval. The net gas pay zone is estimated to be around 29 m, which is from the primary objective target in the Mundu Formation. The gas was flowing via a 120/64” choke for a period of 55 minutes. Initial test result from the gas sample has shown a clean gas. The initial DST flow rate was 11.2 MMcfg/d over a five-hour period through a 64/64” choke, at a pressure of 525 psi. Reportedly, the well was shut in for a total of nine days for pressure build up prior to reaching the maximum flow rate. Ophir reported a cost of USD 15 million for the well, which has been plugged and abandoned as planned. The company’s next step is to prepare a plan of development for the discovery to be submitted for approval. On 4 December 2018, Cue announced the completion of the flow testing campaign on Paus Biru 1. Test results were not released due to pending confirmation from the operator and from Indonesian authorities. Preparations for testing were underway as of 13 November 2018, according to Cue’s earlier announcement. Three DSTs were planned to be carried out over the primary objective, the Pliocene Mundu Formation, to assess reservoir extent and productivity. The testing programme was expected to be completed within approximately two weeks. The well reached TD at 710 m on 3 November 2018. The initial planned total depth of 650 m TVDSS was extended due to formation observation. Logging while drilling has shown high gas readings in several zones within the target formation. Positive indications were also provided by further wireline logging and testing, which included fluid sampling and pressure data collection. Paus Biru 1 was spudded in mid-October 2018, using COSL’s “Hai Yang Shi You 937” J/U rig. The rig reached the drilling location around 6 October 2018. Drilling operations were ongoing on 18 October 2018, with the 30” conductor installed to 105 m. At the time, drilling of the 26” hole was expected to commence on or around 20 October 2018. Paus Biru 1 tested a four-way dip structure closure, targeting the Pliocene Mundu Formation, analogue to the Wortel and Oyong producing gas fields. Secondary objective was the Paciran Limestone Member. The initial plan was to conduct up to two DSTs in case of significant hydrocarbon indications during drilling and logging. The Paus Biru structure is located approximately 27 km east of the Oyong gas field. Typical water depth in the area is less than 50 m. After closing acquisition of the PSC from Santos on 6 September 2018, Ophir confirmed that drilling of Paus Biru 1 would take place in late 2018. The company has identified the Paus Biru prospect as a near field exploration target, with high chance of success. The drilling program was expected to last around 15 to 30 days. In case of success at Paus Biru 1, a horizontal development well will be drilled at a later stage and tied-in to the Oyong field and Grati onshore gas processing facilities. Geotechnical and geophysical site surveys were conducted to determine the final well location, in parallel with sourcing for a drilling rig for the upcoming drilling campaign. In late June 2018, the asset sale from previous operator Santos to Ophir was reported to be ongoing, and this was understood to have a possible impact on the drilling program being delayed to early 2019. The initial search by Santos for a suitable jackup rig was not successful at the time, and a new rig tender will be required. After completion of the asset sale in early September 2018, Ophir may have accelerated the drilling plan, in line with the new corporate strategy to pursue near-field exploration with potential for near-term development. The block is operated by Ophir with 45% interest. The other partners are Singapore Petroleum (40%) and Cue Energy (15%). Partner Cue Energy reported in late May 2018 that drilling preparations were ongoing, after the completion of site surveys to identify the drilling location. In late April 2018, the operator was assessing well site location and was also in discussion with nearby operators for a potential rig sharing opportunity, while working on the procurement process. Drilling of Paus Biru 1 was approved by the joint venture partners in late December 2017. On 25 October 2017, Santos was reportedly waiting for the joint venture approval for the Final Investment Decision (FID) on the well. The company has likely received approval for its site surveys in early Q4 2017. Paus Biru 1 was previously identified as the prospective target for a low-risk exploration opportunity, based on 3D seismic mapping with visible amplitude anomalies. In case of success, it could further extend production life of the block. Santos agreed to sell its entire interests in the Sampang PSC to Ophir Energy on 3 May 2018. The sale is part of a larger transaction by which Santos intends to divest its Asian portfolio, comprising exploration and production assets in Indonesia, Malaysia, Vietnam and Bangladesh, for a total consideration reported by Ophir at USD 205 million pre-capital adjustments. The sale of Santos’ production assets (Sampang PSC, Madura Offshore PSC, and Block 12W in Vietnam) was closed on 6 September 2018 after approval from Ophir’s shareholders. The interest transfer is back dated with an effective date of 1 January 2018. Background Information The Sampang PSC was awarded to Santos (Sampang) Pty Ltd (45%) and partners Coastal Indonesia Sampang Ltd (40%) and Cue Sampang Pty Ltd (15%) on 4 December 1997 upon payment of bonuses totalling USD 1 million and with a firm work obligation of USD 12.155 million in three years and USD 39.555 million in 10 years. Partial relinquishments have reduced the block to 532.5 sq km. Santos' initial exploration effort was the acquisition of a 560km 2D seismic survey between 11 August and 30 August 1998. Santos announced the commencement of gas production from the Wortel field, also located in the Sampang PSC, on 1 February 2012. The field is developed through two horizontal production wells and an unmanned wellhead platform tied-in to the Oyong field facilities via a 10km gas pipeline. Combined production from Wortel and Oyong is expected to be 90 TJ/d (84.9 MMscf/d of gas). Gas produced from Wortel is sent to the processing plant of Grati, in onshore East Java, via the 60-km Oyong gas pipeline, and then allocated domestically to local electricity company PT Indonesia Power (at about 30 MMscfg/d) and to two regional government-controlled companies. The price for gas produced in the block, initially set at USD 2.14 per MMBtu, was revised to USD 5 per MMBtu in November 2011. Oyong field The Oyong field was discovered in mid-2001 after the drilling of the Oyong 1 well which encountered a 120m gas column in the Pliocene Mundu Formation, underlain by a 38m oil column. The Oyong 2 and 3 wells successfully appraised the field and confirmed its potential for economic development. The field produced first oil on 24 September 2007, and first gas on 2 October 2009. Wortel field Wortel gas field was discovered in September 2006 through drilling of Wortel 1 (W-ITB 1). The TD at the well reached 1,464 m with significant hydrocarbons found in the Lower Pliocene Mundu Formation limestone. Following the success of Wortel 1, Wortel 2 (W-ITB 2) was spudded in late-September 2006 with a TD of 1,421 m. It was later plugged and abandoned as dry hole. The company acquired 395 km of 2D seismic in 2007 in Q4 2007. The survey is intended to provide additional infill exploration data over the Wortel gas discovery and three nearby additional prospects. Development wells, Wortel 3 (W-ITB 3) and Wortel 4 (W-ITB 4) were spudded in January 2012, drilled to a depth of 2,020m and 2,277 m respectively. Drilling was conducted using a COSL Boss rig with hook-up and commissioning work completed later in the same month.

Indonesia (South Madura Deep (East Java B.)) Oyong

Pursuant to the recent sale of 7 marginal fields to Perenco in Gabon (DEA 30 Jul '20), word on the street is that Total could also sell interests in Congo at some point in time. The company has substantial interests here, of which the Moho-Bilondo deepwater field or the Nanga + Mokelembembe onshore blocks. Meanwhile the Kombi-Likalala-Libondo II two-block unit, 165 sq km in shallow waters, expired end July and is to be re-assigned to a Perenco, PetroCongo, Africa O&G + SNPC group (DEA 25 May '20). It is recalled (DEA 23 Jul '20) that Eni is rumoured to be looking to sell unspecified assets in Congo. Eni is involved in 19 operated blocks and partners in another 11.

(Congo Fan) Moho-Bilondo op. by TOTAL (45%), CVX (32%), SNPC (15%), GOVT QA (8%) Word on the street is that Total could also sell interests in Congo at some point in time. The company has substantial interests here, of which the Moho-Bilondo deepwater field or the Nanga + Mokelembembe onshore blocks. It is recalled that Eni is rumoured to be looking to sell unspecified assets in Congo. Eni is involved in 19 operated blocks and partners in another 11.

It was reported in October 2019 that Oil and Gas Development Company Ltd (OGDCL) has been awarded the Jarwar D&PL (development and production lease) over its Jarwar 1 oil discovery in Lower Indus Basin and it has been made effective retrospectively from 30 June 2016. The lease, which has been excised from the Nim EL concession, covers 1.63 sq km area and is located in the Tando Allah Yar district of the Sindh province. The equity split is as follows: OGDCL 77.50% (operator) and Government Holdings Pvt Ltd (GHPL) 22.50%. OGDCL had announced the Jarwar 1 oil discovery on 6 November 2014. The well flowed 480 bo/d, through a downhole jet pump, from the ‘B-Sand’ interval in the Upper Sands of the Cretaceous Lower Goru Formation. It was drilled to a TD of 1,473 m. It was reported in November 2018 that OGDCL had submitted the application for Jarwar D&PL.

OGDCL (77,5% op. GHPL 22,5%) has been awarded the Jarwar D&PL

On 29 March 2018, the consortium of Repsol with 40% working interest, Chevron with 40%, and Wintershall with 20%, was granted preliminary awards for the C-M-821 and C-M-823 blocks in the offshore Campos Basin through the ANP Round 15. For the C-M-821 block the consortium offered a bonus of USD 15.64 million and 225 work units. For the C-M-823 block the consortium offered a bonus of USD 12.11 million and 225 work units.    There were no other bids for either of the blocks.  

the consortium of Repsol with 40% working interest, Chevron with 40%, and Wintershall with 20%, was granted preliminary awards for the C-M-821 and C-M-823 blocks in the offshore Campos Basin through the ANP Round 15.

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

Timor Sea JPDA, JPDA 03-20

Chevron has reportedly embarked on the sale process of its entire central North Sea holdings. The assets will include the Alba, Alder, Captain, Elgin/Franklin, Erskine + Jade fields, and the Britannia platform and satellites.

Chevron has reportedly embarked on the sale process of its entire central North Sea holdings. The assets will include the Alba, Alder, Captain, Elgin/Franklin, Erskine + Jade fields, and the Britannia platform and satellites.

On 11 December 2019, the Federal Agency of Subsoil Use held an auction for the Arakanskiy block in Krasnoyarsk (Eastern Siberia). Krasnoyarsk Oil & Gas Company (KNK) emerged as the winner and will obtain 27-year E&P license including a 7-year exploratory stage. The Arakanskiy block covers 3,984 sq km in the Angara-Yenisey Basin. No wells have been drilled in the block. Reservoirs of the Riphean-Cambrian section are the main exploratory targets. Hydrocarbon resources (categories D1+D2) of the block are estimated at 26 MMbbl of oil and 3.425 Tcf of gas. The starting price amounted to RUB 15.7 million (USD 0.25 million). KNK offered RUB 17.27 million (USD 0.275 million).

KNK won Chunskiy Severnyy (4,250 sq km), Kimchunskiy (2,706 sq km) and Arakanskiy block (3,984 sq km) in the Angara-Yenisey B. Krasnoyarsk Kray.

TWhite Petroleum Pty Ltd is seeking to farm-down interest in two exploration licences located in the Fly Platform, along the Stanley-Elevala/Ketu wet gas trend. Farm-in terms remain negotiable with the company looking to retain around 20% non-operated interest in both PPL 537 and PPL 566.  It is likely that farm-in agreements will include minimal back payments for work already completed in the licence areas by TWhite but could include submissions to alter the commitment work programmes. TWhite was awarded the licences, with 100% interest, in 2015 for a period of six years. The licences are located south, and adjacent to, the Stanley gas/condensate field. One well is located across the shared licence boundary which was drilled by Gulf Oil Corp in 1980. The Kiunga 1 well targeted the Toro Sandstone within a faulted anticline and encountered 28m of sandstone with a 14.5% average porosity. The Middle Toro sandstone which is 4m thick, is very tight with almost no porosity. Despite oil and gas shows in the targeted formation at around 2,900 m depth, the licence was relinquished. Santos held licence between 1987 and 2005 before the entrance of Austral Pacific Energy and Horizon Oil. No further exploration drilling has taken place within the licence areas. Given the proximity to the Stanley field, obvious routes to market for hydrocarbons in the case of success would be through the proposed Stanley to Elevala-Ketu pipeline. Operator Repsol of the Stanley field, located in PDL 10, has received two notifications by the Minister for Petroleum for the intent to cancel the licence given that the field is yet to be developed. An early liquids production phase has been proposed to fast track production, yet, since the award of PDL 10 in 2014, no developments have taken place. The Stanley field was discovered in March 1999 and is planned to be developed as part of the Western LNG Project, which could see a number of Horizon and Repsol operated fields being developed as a mid-scale LNG Project on the coast. The proposed development scheme is for a 1.5 MMtpa mid-scale project, which would involve the piping of gas from the associated fields in the Western Foreland, to a modular LNG facility near Daru Island.  The project involves the Stanley field (PDL 10), Elevala/Tingu and Ketu fields (PRL 21), Ubuntu discovery (PRL 28) and the Puk Puk and Douglas discoveries (PRL 40). The coordinated gas aggregation is hoping to monetise 2 – 2.5 Tcf gas and 60 – 70 MMb of associated condensate.  PPL 537 was awarded on 14 September 2015 covering an area of 1,020 sq km. PPL 566 was awarded on 24 December 2015 covering an area of 255 sq km. The work programmes for each licence includes geological and geotechnical studies such as geological reviews and airborne gravity gradiometry surveys and magnetic data in the first two-year term. The subsequent work programmes include 2D seismic data acquisition and one exploration well in each licence at a combined cost of around USD 40 million. TWhite has contracted Gaffney, Cline and Associates to carried out resource assessments across PPL 537, 566 and 656. The assessment is ongoing as of early-November 2018. The results will be made available to interested parties upon access to the available data room. TWhite is seeking to farm-down around 80% interest with available operatorship in PPL 537 and PPL 566, located in the Fly Platform. TWhite is also looking to farm-down interest in its 100% owned and operated exploration licence PPL 538 which is located in the Papuan Fold Belt along the Hides, Muruk and P’nyang trend.

Twhite Petroleum Pty Ltd looking to farm-down interest in the Fly Platform, along the Stanley-Elevala/Ketu wet gas trend. Farm-in terms remain negotiable with the company looking to retain around 20% non-operated interest in both PPL 537 and PPL 566.

On 11 September 2018, the Federal Agency for Subsoil Use announced an auction for two blocks in Tomsk Oblast (Western Siberia). The auction is scheduled on 14 November 2018. Applications must be submitted by 16 October. The winners of the auction will obtain 25-year E&P licenses.  Tomsknedra 634021, Tomsk Frunze Prospekt, 232, office 204 Details of the offer are as follows: The Nikolskiy-3 block covers 1,623 sq km in the Kaymys-Vasyugan Province and encompasses the Nikolskoye oil discovery with 3P reserves estimated at 24 MMbbl and several prospects with combined oil resources estimated at 37 MMbbl. Hydrocarbon resources (categories D1+D2) of the block are estimated at 47 MMbbl of oil. Seismic coverage amounts to about 1,500 km of 2D data. Five exploratory wells have been drilled within the block. The starting price amounts to RUB 430.524 million (USD 6.15 million). The Chvorovyy-2 block covers 554 sq km in the Kaymys-Vasyugan Province and encompasses the Chvorovoye oil discovery with 2P reserves estimated at 2 MMbbl. Hydrocarbon resources (categories D1+D2) of the block are estimated at 58 MMbbl of oil. Seismic coverage amounts to 725 km of 2D data. Five exploratory wells have been drilled within the block. The starting price amounts to RUB 56.93 million (USD 0.8 million).

Government of Russia auctions two licenses Chvorovyy-2 block and Nikolskiy-3 block in Tomsk on 14 November

Ahead of drilling, Europa is looking to farmout Licence Option 16/22,  993 sq km in WD 800-2,000m, Padraig Basin (E. Rockall Trough).  Contact Murray Johnson, [email protected].

United Kingdom, Europa

Andalas Energy and Power PLC announced on 21 September 2018 that through its subsidiary, Resolute Oil and Gas (UK) Ltd, it has entered into an agreement with Corallian Energy Limited to acquire an 8% interest in licence P1918 which contains the Colter prospect and onshore licences PEDL 330 and 345. In return for its 8% interest, Andalas is funding 10.67% of the well costs up to a maximum of GBP 8 million. The deal is subject to regulatory approval. Corallian is planning to drill an appraisal well on the 98/11-2 (Colter) discovery in licence P1918. The discovery was made by BP in 1986 where 41.9° API was recovered on test from a 10.5 m oil column. Through the merging and reprocessing of 3D seismic Corallian has mapped 100 m of vertical relief up-dip of 98/11-2. The appraisal well is planned to spud in Q4 2018 and the well requires a Jack-up rig for operations. Well costs are in the region of GBP 7 million. Licence P1918 was initially awarded to Infrastrata from the 26th Seaward Licensing Round prior to Corallian taking the acreage. The company reprocessed 156 km of 2D seismic and 33.5 sq km of 3D seismic over the licence. It is thought that Colter could hold mean prospective resources of 22 MMbo (recoverable). Interest in P1918 following completion of two deals will be held by Corallian Energy Limited (34% + operator), Corfe Energy Limited (40%), United Oil and Gas Plc (10%), Andalas Energy and Power PLC (8%),  and Baron Oil Plc (8%).

Andalas subsidiary Resolute O&G has agreed with Corallian Energy to acquire an 8% interest in the latter’s coastal offshore P1918 (Colter prospect), along with PEDL 330 + 345, total 65 sq km off the Dorset coast. Andalas will fund 10.67% of the Colter well (scheduled 4Q ’18) up to GBP 8 MM and 8% beyond. P1918 is otherwise held by Corallian (op), partners Baron Oil, Corfe Egy + United O&G

In early October 2017, Occidental de Colombia (OxyCol) tested approximately 548 bo/d in the Cosecha V-01 NFW, on the Cosecha Block (Llanos Basin). The short-term testing results were from the Lower Carbonera Formation between 2,652m-2,653m. The next testing will take place on the adjacent interval above. OxyCol in September 2017, was planning to test three intervals in the Cosecha V-01 NFW, on the Cosecha Block (Llanos Basin). Two of the intervals are in the Upper Cretaceous (likely to be K1 or K2) and two in the Early Tertiary (Lower Carbonera Formation -possibly C5). The well was spudded on 31 July 2017 with the H&P "152" land rig to a TD of 3,003m, on 13 August 2017, according to local sources. The NFW was targeting the Carbonera Formation. The well is located about 2km southwest of the Rex Field (which is producing in the K3 Cretaceous Formation, and approximately 7km north east of the Cosecha Field, (producing in the Carbonera Formation). The Occidental de Colombia JV (Occidental Oil and Gas 75% and Repsol 25%) operates the Cosecha Block with 70% WI. Ecopetrol holds the remaining 30% WI.<P />

Cahua 1 op. by Pemex (100%) in AE-0009-M-Tucoo-Xaxamani-01 contract area, finds natural g&cond. No test results were available for the well, bat it has however, been classified as a producer, indicating that the reserves are commercial.

SMART OIL signed a PSCA with CNOOC on block 09/17 in Bohai offshore on 12 April 2019. The block is located in the Qikou sag, Bohai Gulf Basin. It covers a total area of 509.3 sq km with a water depth of 5-10 meters. According to the terms of the PSC, Smart Oil shall act as the Operator during the exploration period and conduct exploration activities in the block mentioned above, in which all expenditures incurred will be borne by Smart Oil. Once entering the development phase, CNOOC has the right to participate in up to 51% of the participating interest in any commercial discoveries of the Bohai 09/17 Block. The block was offered for bid by CNOOC in 2018 bidding round. Bohai - Block 09/17 Block 09/17 is located in the west part of the Bohai offshore and surrounded by Qikou Field Group. It is a relatively exploration mature area, the main targets in the block are Tertiary clastic and pre-Tertiary basement plays. The block covers most area of 09/05 PSCA which was operated by Roc Oil.   In May 2012, Roc Oil signed 09/05 PSCA with CNOOC in Bohai offshore. The 335 sq km Bohai block is located approximately 15 km north of ROC’s existing Zhao Dong production and appraisal blocks in water depths of 4-10 m. Roc Oil completed a 162 sq km 3D seismic survey over Block 09/05 in September 2013. In 2014, Roc Oil drilled the QK11-1-1 well without commercial discovery in this block. In 2015 Roc Oil completed QK12-3-1D. The well penetrated good quality sands in the targeted zones but without hydrocarbon shows. It is believed that the reason for failure is relating to hydrocarbon charging issue. In 2016, after two dry holes drilled, Roc Oil decided to relinquish Bohai offshore PSC 09/05 block in the Bohai Gulf Basin. Background Information Smart Oil also has a PSCA 05/31 with CNOOC in the Bohai offshore, which was signed in 2013. The company has completed four wells in the block and made two discoveries, CFD 1-2-1 and CFD 2-4-1. In addition, Smart Oil together with Roc Oil signed a production sharing contract (PSC) with CNOOC in July 2018 for Weizhou 10-3W oilfield and Block 22/04 in the Beibu Gulf Basin, South China Sea.

China (Beibu Gulf B.) Weizhou 10-3W

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

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

On 10 October 2019, the consortium of Repsol and Chevron bid on and were granted a preliminary award for the 699.60 sq km C-M-825 block in the deep-water offshore Campos Basin from the ANP Round 16. There were no other bids for the block. The consortium bid a bonus of USD 3.01 million at 1 USD to 4.11 BRL and USD 4.67 million in minimum work commitments.  Repsol is operator with 60% working interest and Chevron holds 40% working interest.

Brazil, not found

W&T Offshore was the successful bidder to acquire Cobalt Energy's entire interest in the Heidelberg Field, according to reports in mid-March 2018. Heidelberg, which encompasses Green Canyon blocks GC 859 (G24194), GC 903 (G24197) and GC 904 (G26346). Tracy Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "We are pleased that W&T was the successful bidder on this quality asset that meets all of our acquisition criteria. It is being acquired at an attractive valuation and will contribute solid production and reserves, as well as offer upside potential. Finally, this transaction meets an additional objective of being accretive to W&T on a flowing barrel of production." The transaction is anticipated to close in April 2018. Gross production from the Heidelberg Field totalled 33,513 bo/d and 16.7 MMcfg/d (36,300 Boe/d) in February 2018. Cobalt's production from the field, net to its interest, was 2,749 bo/d and 1.4 MMcfg/d in February 2018 (~3,000 boe/d from five wells). The wells flow to the Heidelberg Spar, which is located in GC 860. Prior to the closing of this transaction, equity in GC 859, GC 903 and GC 904 is currently shared between Anadarko US Offshore (44%), Statoil USA E&P (12%), Eni Petroleum US (12.5%), Cobalt GOM #1 (9.375%), ExxonMobil (9.375%) and Marubeni Oil & Gas (USA) (12.75%).

W&T Offshore made the top offer of US$31MM for 9, 375% Cobalt's share in the Anadarko-operated Heidelberg field.

On 10 February 2019, at the India Petrotech event 2019, Indian Government, launched the third round of Open Acreage Licensing Programme (OALP-III). Of the offered 23 blocks, two blocks (one onshore block and one deepwater block) are located in the Mahanadi Basin.    At the event, the Directorate General of Hydrocarbons (DGH) issued the Notice Inviting Offers (NIO) and Model Revenue Sharing Contract (MRSC) for OALP-III, offering a total of 23 blocks, including 14 onshore, three shallow water, one deepwater and five coalbed methane (CBM) blocks, covering a combined area of around 31,700 sq km. Bidders were invited to submit their bids via the e-bidding portal from 11 February 2019, until the bid closing deadline on 10 April 2019. It is understood that of the 23 blocks offered, five CBM blocks have been carved out by the Directorate General of Hydrocarbons (DGH). The Mahanadi Basin covers an onshore area of around 15,500 sq km, shallow water offshore area of around 14,211 sq km and deepwater offshore area of around 69,789 sq km. It is understood from DGH that the Mahanadi Basin has discovered resources of around 77 MMtoe and undiscovered resources of around 574 MMtoe. The Mahanadi Basin is a pericratonic rift type basin. As of February 2019, it is understood from DGH report that so far around 65 exploratory wells (onshore: 5 and offshore: 60) have been drilled in the Mahanadi Basin. Around 6,152 km 2D onshore and 67,850 km 2D offshore, and 61,330 sq km 3D offshore seismic data has been acquired in the basin.  Cretaceous to Eocene and mid-Miocene to Pliocene are the targeted plays in the Mahanadi basin. It is understood that to date, there is no discovery in onshore area of the Mahanadi Basin. Earlier in 1980s, Oil India Ltd (OIL) had drilled wells in onshore area of Mahanadi Basin, having TD from 2,000 m to 3,000 m, targeting upper Mesozoic-Neogene formations. However, all onshore wells were understood as dry and subsequently plugged and abandoned. The deepwater offshore block offered in the Mahanadi Basin comprises Oil and Natural Gas Corp (ONGC)’s MDW 21 and MDW 2A discoveries of Mio-Pliocene age.  The table below lists the details of two blocks on offer under OALP-III in Mahanadi Basin:      Block name Approx. area (sq km) Target depth for wells to be drilled (m) Minimum net worth requirement  (USD million) Requisite bid bond (USD) Block history Onshore MN-ONHP-2018/5 2,299.74 2,500 11.17 1,000,000 582.16 km 2D seismic data and 1 well drilled Deepwater MN-DWHP-2018/1 2,491.31 2,750 76.80 1,158,000 744.72 km 2D, 680.25 sq km 3D seismic data and 11 wells drilled Source: DGH, India                                                      © 2019 IHS Markit     For more details on bidding terms and conditions for OALP-III, please refer to main OALP-III bidding article in GEPS.  https://pgeps.ihsenergy.com/GEPS/Display/c08aaae4-1e04-4685-9bd7-5fc853b25dcd

On 10 February 2019, at the India Petrotech event 2019, Indian Government, launched the third round of Open Acreage Licensing Programme (OALP-III). Of the offered 23 blocks, two blocks (one onshore block and one deepwater block) are located in the Mahanadi Basin. At the event, the Directorate General of Hydrocarbons (DGH) issued the Notice Inviting Offers (NIO) and Model Revenue Sharing Contract (MRSC) for OALP-III, offering a total of 23 blocks, including 14 onshore, three shallow water, one deepwater and five coalbed methane (CBM) blocks, covering a combined area of around 31,700 sq km. Bidders were invited to submit their bids via the e-bidding portal from 11 February 2019, until the bid closing deadline on 10 April 2019. It is understood that of the 23 blocks offered, five CBM blocks have been carved out by the Directorate General of Hydrocarbons (DGH). The Mahanadi Basin covers an onshore area of around 15,500 sq km, shallow water offshore area of around 14,211 sq km and deepwater offshore area of around 69,789 sq km.

39/94 plot enclaved within the 24/99/p Przeworsk-Jaroslaw-Stubno permit, Outer Carpathian Foredeep in SE Poland, ops terminated results n/a late Dec '19, PTMD was 1,500m (ca. 1,300m TVD), target Sarmatian-Badenian.

Mirocin-69K appr 39/94 plot enclaved within the 24/99/p Przeworsk-Jaroslaw-Stubno permit, Outer Carpathian Foredeep in SE Poland, ops terminated results n/a late Dec '19, PTMD was 1,500m (ca. 1,300m TVD), target Sarmatian-Badenian.

Eni has been pre-awarded the South East Siwa block, following the announcement of the winners of the EGPC 2018 International Bid Round on 12 February 2019. The 3,013 sq km area comprises of two separate blocks in an under-explored part of the Western Desert. The acreage lies immediately south of the company's South West Meleiha concession, awarded in 2015. Work commitments include expenditure of US$ 17 million and four wells in the initial exploration period. A US$ 1.15 million signature bonus will be paid. Upon PSC signature, Eni will operate the concession with 100% equity.

Eni has been pre-awarded the South East Siwa block, following the announcement of the winners of the EGPC 2018 International Bid Round on 12 February 2019. The 3,013 sq km area comprises of two separate blocks in an under-explored part of the Western Desert. The acreage lies immediately south of the company's South West Meleiha concession, awarded in 2015. Work commitments include expenditure of US$ 17 million and four wells in the initial exploration period. A US$ 1.15 million signature bonus will be paid. Upon PSC signature, Eni will operate the concession with 100% equity.

BP Developments Australia Pty Ltd, a subsidiary company of BP plc, was awarded exploration permit WA-535-P, located in the Exmouth Plateau, North Carnarvon Basin, on 30 October 2018.  The permit has been awarded for a period of six years and will expire, or be eligible for renewal, on 29 October 2024.  The permit was applied for as block W17-7 in the 2017 Offshore Acreage Release and was awarded in Round two. The Department of Industry, Innovation and Science reports that no other bids had been received for the offered area. Work commitments have been assigned for the duration of the permit’s validity. The guaranteed work programme within the first three years includes licensing Olympus 3D seismic data, totaling AUD 6.4 million. The secondary programme of terms four to six, which totals AUD 68 million, includes one exploration well. WA-535-P is located around 3km, at its closest point, to the Goodwyn and Perseus fields. Four wells are located in the permit area. Gas show and oil shows were observed at Zeus 1 and Gandara 1, respectively. The La Rocca 1 and Eastbrook 1 wells were both dry at location. The area was last held by MEO, Mineralogy and Cue Exploration through exploration licence WA-361-P. The permit expired on 17 January 2014. WA-535-P, which covers an area of 1,615 sq km, was awarded on 30 October 2018.  BP Developments Australia Pty Ltd holds 100% interest and operatorship in the permit.

Australia (Rankin Platform (North Carnarvon B.)) Perseus

Juzni Banat field/block, Banat sub-basin in NE Serbia, targets assumed Badenian and/or Paleozoic below 805m, compl. gas between Jun-Jul ’18. Likewise Kikinda Zapad X-3 appr in the Severni Banat block, also in NE Serbia.

Lokve X-1 appr Juzni Banat field/block, Banat sub-basin in NE Serbia, targets assumed Badenian and/or Paleozoic below 805m, compl. gas

Ref. DEA 5 Dec '19: Committed well in AC/P64, Caswell sub-basin (Browse), WD ca. 155m, significant gas-cond find, ops terminated 4 Dec '19, Ocean Apex SS. PTD was 4,750m.

Bratwurst 1 nfw. (Shell 100%), committed well in AC/P64, Caswell sub-basin, ops terminated. significant gas-cond find. WD ca. 155m, PTD was 4750m.

On 29 October 2018 Eni announced that it signed an exclusive partnership agreement with Sonatrach and Total for offshore exploration in Algeria. The agreement was signed by the CEO’s of Sonatrach, Eni and Total, Abdelmoumen Ould Kaddour, Claudio Descalzi and Patrick Pouyanné, respectively. Total and Eni will pursue obtaining exploration permits that will allow for rapid completion of the hydrocarbon potential assessment. The exploration wok will take place on two large offshore blocks. One in the east will cover 15,000 sq km in the region of the former Bejaia-Annaba block and one in the west will cover 10,000 sq km in the region of the former Mostaganem-Tenes block. Eni will operate in the east while Total will operate in the west. The work program on each block includes acquisition of 3D seismic, reprocessing of existing seismic data and the drilling of one exploration well. Total CEO Patrick Pouyanné pointed out that the Algerian offshore is difficult to explore as the water depths are considerable. This has an impact on drilling costs and it is estimated that a typical exploration well offshore Algeria will cost between EUR 50 and 60 million. Partners in the two blocks will be Sonatrach with a 50% interest, Eni and Total with 25% each. On 7 October 2018, Ould Kaddour, said that the company is in talks with Eni on offshore exploration. He indicated that offshore drilling will start in the first half of 2019. On 24 September 2018, Ould Kaddour, said that offshore exploration drilling could start in 2019. According to him, preliminary studies are promising but he gave no details on the region where the drilling could take place or the partners which were selected. In mid-July 2017 it was reported that Sonatrach is still in talks with international oil companies on hydrocarbon exploration offshore Algeria. Ould Kaddour said that his company is discussing the project with Eni, Total, Anadarko and Shell. Earlier, ExxonMobil and Statoil had also been presented as potential partners. On 27 February 2017 it was reported that Sonatrach is in talks with international oil companies on hydrocarbon exploration offshore Algeria. The company has reportedly approached potential partners to carry out exploration offshore Bejaia and Oran. Sonatrach operated one large exploration permit in each of the targeted areas: Bejaia-Anaba/145 and Mostaganem-Tenes/143. The drilling of an exploration well offshore is planned since 2014 but was postponed most probably due to the crash in the oil price in late 2014. According to the local press, Eni was selected as Sonatrach’s partner to work on one of the two offshore blocks. Sonatrach completed two 3D surveys totalling 5,000 sq km over offshore permits, Bejaia-Anaba/145 and Mostaganem-Tenes/143 in the Tellian and Sud-Tellian Atlas. Both surveys were run with the CGG’s Viking Vanquish S/V. The first survey of 1,000 sq km was acquired over the 21,390 sq km Mostaganem-Tenes/143 permit between beginning of March 2013 and beginning of July 2013. The second survey of 4,000 sq km was acquired over the 32,058 sq km Bejaia-Anaba/145 block between mid-July 2013 and mid-August 2013. In November 2012, Northern Algeria Exploration Director, Mohand Said Mala, re-emphasised the interest of Sonatrach to promote offshore exploration in joint venture with International Oil Companies, identifying Repsol and Statoil as potential partners. In the case IOC are not interested, Sonatrach could drill alone with the support of major service companies, such as CGG Veritas or Schlumberger. First well was planned for 2014. Critical for this offshore exploration drilling is data quality and availability and drilling costs. The potential hydrocarbon zones are located at 2,000 to 2,500 m water depths.  In mid-May 2011, Sonatrach completed a 5,000km 2D seismic survey offshore Algeria. The BGP “Challenger” vessel started acquiring seismic data over the Bejaia- Anaba prospecting permit, offshore eastern Algeria on 1 April 2011 and then moved over to the Mostanagem-Tenet prospecting permit, offshore western Algeria in late April 2011. Algeria has a very narrow continental shelf with a steep continental slope, the water depth reaches 2,000m at just 25km from the shore line.

Algeria, Atlas

In November 2017, the Venezuelan Popular Power Petroleum Ministry (MinPetroleo) awarded state-run petrochemical company Pequiven a non-associated natural gas contract, covering the 86.53 sq km LL-652 Block. The award was made official via the publication of Official Gazette No 438.518. State oil producer PDVSA previously held the gas contract for the block. Petroindependiente, the mixed company that includes Chevron (25.2%) operates the LL-652 Field's oil contract. MinPetroleo said the non-associated gas award was two-fold, as the mature field's high natural gas content was impeding petroleum production. The award will also aid Venezuela in increasing natural gas production for the domestic petrochemical industry.

Venezuela, LL-652

Todd Petroleum Mining Co Ltd. is offering a farm-in opportunity in exploration permit PEP 60094, located in the Eastern Taranaki Mobile Belt, Taranaki Basin.  Todd reported that equity is available in the permit, in which it holds 100% operated interest and is looking for a partner to participate in future work commitments. Todd reports that a number of various prospects have been identified with potential conventional structural and stratigraphic targets.  Todd outlines the Victor prospect as a potential first target.  The prospective reservoir at Victor is within turbidite sands of the Miocene Moki Formation, with a possible Kauri Sandstone secondary target.  It is a rollover anticline with three-way dip closure, with the Miocene Manganui Formation shales forming the seal and hydrocarbon charge from the Cretaceous Rakopi coals.  A potential 111 MMb oil resource is present within the Moki target. PEP 60094 is close to the producing Kupe, Rimu, Kauri and Manutahi fields. The Tahi 1 well lies within the permit boundary, drilled in February 1984.  The well was plugged and abandoned after encountering oil and gas shows. The permit was awarded in December 2015, with the first term commencing on 1 April 2016.  Following the completion of the first stage of work commitments which included the reprocessing of 550 km of 2D seismic data and various technical studies, the operator is required to acquire 770 km of new 2D seismic or 40 sq. km of new 3D seismic data before 1 April 2019 at which point a drill or drop decision is required. The first well under the current work commitments is scheduled between April 2021 and end March 2022, however Todd has two drill or drop decisions prior to this PEP 60094, which covers an area of 2,153 sq km, was awarded on 16 December 2015 after being applied for in the 2015 Blocks Offer. The farm-in opportunity was first announced in June 2016. Interested parties should contact: Tim Carter - Todd Energy      Email: [email protected] Ian Brewer - Todd Energy      Email: [email protected]                   Tel: 0064 27 5345 548

Todd Petroleum Mining Co Ltd. is offering a farm-in opportunity in exploration permit PEP 60094, located in the Eastern Taranaki Mobile Belt, Taranaki Basin. Todd reported that equity is available in the permit, in which it holds 100% operated interest and is looking for a partner to participate in future work commitments.

Canacol's CEO Charle Gamba commented in late January 2018 that the sale of its Ecuadorian assets is expected to formally close this month. Canacol, in December 2017, agreed to sell its 25% WI in the Pardaliservices venture which operates the Libertador Field service contract in Ecuador for US$ 36.4 million, in order to focus efforts on developing Colombian natural gas production. The deal is with TecpetrolLibertador BV and Sertecpet E&P SL. It calls for an initial payment of US$ 30.4 million in January 2018, with the balance to be paid in July 2019. Canacol also said it would receive an immediate reimbursement of US$ 5.58 million related to a cash call it recently paid to the joint venture. Ecuadorean state-run Petroamazonas must approve the deal. "Funds from this transaction will be used to execute our gas focused exploration and development projects as we move toward our goal of exiting 2018 with 230 MMcf/d of gas sales, making us the largest supplier of gas to the Caribbean coast of Colombia," Canacol Charle Gamba said. Ecuador renegotiated the per-barrel-rate for the contract it has with Pardaliservices SA, covering the Liberator Field in the Oriente-Maranon Basin, state-run Petroamazonas said in late July 2017. Pardaliservices is the consortium that includes Tecpetrol, Schlumberger, and Sertecpet. The rates were renegotiated after oil prices began to fall in 2014. The new rate will be US$ 25.50/barrel from US$ 38.54/barrel. Moreover, Pardaliservices will invest an additional US$ 140 million in the 12,285 bo/d field. That will generate an additional US$ 166 million in revenue for the state through 2030, according to the Hydrocarbons Ministry. Pardaliservices was awarded the service contract in the Oriente-Maranon Basin on 31 January 2012 under the Mature Fields Special Tender Round.

Canacol sold its Ecuadorian assets to TecpetrolLibertador BV and Sertecpet E&P SL for US$ 36.4 million

ATP-744-P (Deep), Galilee Basin, some gas (230 Mcf/d dry) flowed stable for 24 hrs from between 2,582-2,595m in the Lake Galilee sst, notable as the first measurable gas tested from this zone in the basin. A larger rig is now sought to complete drilling,  PTD 2,775m. Farmin well for Vintage Energy into the sandstone section of the block (the Deeps), who is funding the first A$3.35 MM to earn 15%. Vintage can also earn another 15% by funding phase 2 of the programme.

Albany 1 (Comet Ridge 100%) in ATP 744-P (Deep) block, some gas (230 Mscf/d dry) flowed stable for 24 hrs from between 2582-2595m in the Lake Galilee sst (Up. Permian), notable as the first measurable gas tested from this zone in the basin.

Further to DEA 20 Feb ’19, Lukoil, KMG and the authorities signed an E&P contract for the Zhenis block in the Kazakh sector of the Caspian Sea on the border with Turkmenistan. This will be operated by Zhenis Operating LLP, a 50:50 Lukoil-KMG JV. Commitments include 3D seismic + 1 explo well.

Lukoil, KMG and the authorities signed an E&P contract for the Zhenis block in the Kazakh sector of the Caspian Sea on the border with Turkmenistan. This will be operated by Zhenis Operating LLP, a 50:50 Lukoil-KMG JV. Commitments include 3D seismic + 1 explo well.

On 6 December 2019, PEMEX issued a press release indicating that the company has confirmed that the Quesqui Field is the most important discovery in the onshore Sureste Basin since 1987 with estimated 3P reseves of 500 MMboe. President Obrador and PEMEX Director General Octavio Romero made the announcement at the location of the Quesqui 1DEL outpost currently drilling in the AE-0053-3M-Mezcalapa-03 (Campo Quesqui), Quesqui Oriental evaluation entitlement block during early-December 2019. The PEMEX press release further stated that with the results of the Quesqui 1EXP discovery and seismic data, the company has determined that the Quesqui Field holds 3P reserves of 500 MMboe up from its original 3P estimates of 40 MMboe. It is speculated that information from the Quesqui 1DEL has improved the seismic interpretation of the structure or the Cretaceous secondary target in the Quesqui 1DEL had strong shows and may also be productive. Mr Romero indicated that the field covers 34 sq km and it will be developed with 11 wells. Production estimates are for 300 MMcfg/d and 69 Mbc/d in 2020 and 410 MMcfg/d and 110 Mbc/d in 2021. PEMEX was drilling below 4,400 m on the Quesqui 1DEL directional outpost in the AE-0053-3M-Mezcalapa-03 (Campo Quesqui), Quesqui Oriental evaluation entitlement block during late-November 2019. The outpost was spudded on 7 August 2019. This is the first appraisal well for the Quesqui 1EXP discovery. PEMEX is drilling the Quesqui 1DEL from the Quesqui 1EXP discovery well pad as the surface location (SL). The 1DEL is being drilled directionally north-west of the discovery with the bottom-hole location (BHL) landing point approximately 1,700 m north-west. It has a proposed total depth (PTD) of 7,700 m measured depth (MD) and 7,316 m true vertical depth (TVD). The primary target for the outpost is the Upper Jurassic Kimmeridgian from 6,556 m to 6,571 m true vertical depth (TVD) and a secondary target is the Middle and Lower Cretaceous from 6,322 m to 6,406 m TVD. The outpost has unrisked prospective resources estimated to be 10 MMboe. The total estimated budget for drilling the well is USD 26.98 million and USD 10.17 million allocated for completion operations. On 6 August 2019, the CNH approved the drilling permit submitted by PEMEX for the Quesqui 1DEL outpost. SENER granted the AE-0053-3M-Mezcalapa-03 to Pemex 100% through Ronda 0 on 27 August 2014 and the (Campo Quesqui) evaluation block on 29 July 2019. The entitlement has been modified three times, the latest was 29 July 2019 when the Quesqui evaluation block was granted. The evaluation plan also included the designation of the 87.41 sq km AE-0053-3M-Mezcalapa-03 (Campo Quesqui) evaluation block that was modified on 27 August 2019 creating the AE-0053 Quesqui Oriente block that covers an approximate area of 60.98 sq km carved and the AE-00045 Quesqui Occidente block carved out of the AE-0045-5M-Agua Dulce-04 entitlement block that covers an approximate area of 26.01 sq km. On 27 August 2019, the AE-0053 and AE-0045 entitlements expired and was superseded by the AE-0143-Comalcalco entitlement on 28 August 2019 that covers the entire area of the Campo Quesqui evaluation area. The Quesqui development block will still be linked to the old entitlements and this area will be carved out of the new AE-0143-Comalcalco entitlement. On 25 July 2019, the CNH approved the evaluation-development plan submitted by PEMEX for the Quesqui 1EXP new-field wildcat (NFW) Jurassic gas and condensate discovery in the AE-0053-3M-Mezcalapa-03 entitlement block. The Quesqui 1EXP is a significant discovery with PEMEX estimating original gas in place (OGIP) of 3.4 Tcfg and original condensate in place of 923 MMbc. The evaluation plan will prove up the volumes with five appraisal wells planned. The evaluation plan also included the designation of the 87.41 sq km AE-0053-3M-Mezcalapa-03 (Campo Quesqui) evaluation block that also includes area carved out of the AE-0045-5M-Agua Dulce-04 entitlement block. The primary purpose of the evaluation plan is to fast-track development of the new discovery through the drilling of five outpost wells and six long term production tests including the discovery well and construction of several pipelines to flow the test production to market. This will allow PEMEX to appraise and produce the wells at the same time prior to full commerciality declaration. PEMEX reported that the Quesqui 1EXP discovered gas and condensate in the Upper Jurassic Kimmeridgian dolomites. The condensate has a gravity of 44° API. The reservoir tested 16.67 MMcfg/d and 4,478 bc/d through a 32/64” choke from 6,256 m to 7,047 m. The reservoir pressure is reported to be 12,578 psi and the temperature 153° C. PEMEX reported that it estimated the reserves for the Quesqui 1EXP discovery after drilling and testing of the discovery well and its geophysical evaluation. PEMEX estimates original gas in place (OGIP) of 3.4 Tcfg and original condensate in place of 923 MMbc. PEMEX completed as an oil and gas discovery the Quesqui 1EXP new-field wildcat (NFW) in the AE-0053-3M-Mezcalapa-03 entitlement block during mid-May 2019. The well reportedly tested approximately 800 bo/d and large volumes of natural gas from the HPHT reservoir. The NFW was spudded on 22 July 2018 and reached a final total depth (TD) of 7,047 m in May 2019. The well had a proposed total depth (PTD) of 7,526 m and the primary targets were the Cretaceous and Jurassic formations. The NFW will attempt to extend the successful deeper Jurassic plays in the area like Bricol, Chinchorro, Palangre, Pareto, and the most recent discovery Chocol in March 2017. The drilling cost estimate was reported to be USD 24.81 million at an exchange rate of 1USD = 18.5 MXN and the completion cost is USD 5.24 million. The NFW has prospective resources of 63 MMboe. The prospect is located in the north-western area of the block, approximately 7.8 km northwest of the A-0168-M-Campo Jujo-Tecominoacan. The operator was granted a permit to drill the well by the CNH on 22 June 2018.

Quesqui 1EXP (Pemex 100%) in NW part of AE-0053-2M-Mezcalapa-03 block, onshore in Tabasco, compl o&g, testing ab. 800 bo/d + gas from an HPHT reservoir. Targets Cret. (npw) + Jurassic (dpw). Initial tests produced 4,478 bc/d of 43.8° API and 16.67 MMcfg/d from the Late Jurassic Kimmeridgiano Fm. Discovery looking to be the largest onshore Sureste discovery since 1987, est. 3P reserves 500 MMboe (up from erstwhile 40 MMboe).

Changshen 40 flow tested at a stabilized rate of approximately 4 MMcfg/d from the Cretaceous Shahezi Formation tight gas clastic reservoir on 26 April 2020, after having undergone fracture stimulation in March 2020. The success of Changshen 40 has boosted the exploration potential of the tight gas reservoir in the Songliao Basin with PetroChina completing Changshen 40 as a production well and two further wells Changshen 39 and Changshen 41 to be drilled. Changshen 40 was spudded in Q2 2019 and was drilled to a TD of 5,428m MD in the Cretaceous Shahezi Formation on 16 September 2019. Data from wireline logging confirmed that Changshen 40 encountered 81m of strong gas shows in the Yingcheng volcanic reservoir and a further 75m of strong gas shows in the Shahezi Formation. Changshen 40 is in the PetroChina operated Chaganhua Block in the Songliao Basin.

Changshen 40 flow tested at a stabilized rate of approximately 4 MMcfg/d from the Cretaceous Shahezi Formation tight gas clastic reservoir

TTK was awarded sole rights for 25 years to the E30-C1,D2 CBM licence on 24 Jun ’19, a small 2.2-sq km area in the Pontides Basin in NW Turkey.

TTK was awarded sole rights for 25 years to the E30-C1,D2 CBM licence on 24 Jun ’19, a small 2.2-sq km area in the Pontides Basin in NW Turkey.

Heritage Petroleum Company launched in late July 2020 an invitation for Expression of Interest (EOI) for joint-venture partner for the North West District (NWD) located in acreage onshore Trinidad, in order to identity and explore opportunities in deeper reservoirs within the NWD, specifically below the Mid-Miocene unconformity and engage in join studies for potential acreage acquisition. More details regarding the area, have not been released. The application should show: Strong Field exploration capabilities in the domains of subsurface Wells Construction Express their interest to participate in an RFP Process that will seek to general proposals for exploration partnerships on existing Heritage acreage and join study opportunities for the acquisition of acreage Need to demonstrate strong and integrated capabilities, as well as past experience of executing similar projects Interested parties, should bend detailed EOI to: [email protected] The North West District of onshore Trinidad is geologically associated with the Caroni sub-basin (Trinidad Basin). The potential petroleum system for further exploration would focus on the sandstone reservoirs of either the Cipero and/or Karamat formations. The shales and clays of the Cipero and Karamat formations are interpreted to act as the regional and local seals to the interbedded reservoirs. The source rocks in the region are estimated to be primarily Cretaceous-aged with a possible alternative being the Lower-Middle Miocene-aged Brasso Formation. The Caroni sub-basin was formed via a significant syncline that formed in an extensional system where inversion occurred along the northern and southern basin flanks. To the north, the basin is bounded by the El Pilar Fault.

(Trinidad B.) Heritage Petroleum Company launched in late July 2020 an invitation for Expression of Interest (EOI) for joint-venture partner for the North West District (NWD) located in acreage onshore Trinidad.

Todd Petroleum Mining Co Ltd. is offering a farm-in opportunity in exploration permit PEP 60094, located in the Taranaki Basin.  Todd reported that equity is available in the permit, in which it holds 100% operated interest and is looking for a partner to participate in future work commitments. Todd reports that a number of various prospects have been identified with potential conventional structural and stratigraphic targets.  Todd outlines the Victor prospect as a potential first target.  The prospective reservoir at Victor is within turbidite sands of the Miocene Moki Formation, with a possible Kauri Sandstone secondary target.  It is a rollover anticline with three-way dip closure, with the Miocene Manganui Formation shales forming the seal and hydrocarbon charge from the Cretaceous Rakopi coals.  A potential 111 MMb oil resource is present within the Moki target. PEP 60094 is close to the producing Kupe, Rimu, Kauri and Manutahi fields. The Tahi 1 well, drilled in February 1984, lies within the permit boundary.  The well was plugged and abandoned after encountering oil and gas shows. The permit was awarded in December 2015, with the first term commencing on 1 April 2016.  Following the completion of the first stage of work commitments which included the reprocessing of 550 km of 2D seismic data and various technical studies, the operator is required to acquire 770 km of new 2D seismic or 40 sq. km of new 3D seismic data before 1 April 2019 at which point a drill or drop decision is required. The first well under the current work commitments is scheduled between April 2021 and end March 2022, however Todd has two drill or drop decisions prior to this. PEP 60094, which covers an area of 2,153 sq km, was awarded on 16 December 2015 after being applied for in the 2015 Blocks Offer. Todd Petroleum Mining Co Ltd. holds 100% operated interest in the permit. Interested parties should contact: Tim Carter - Todd Energy      Email: [email protected] Ian Brewer - Todd Energy      Email: [email protected] Tel: 0064 27 5345 548

Todd Petroleum Mining Co Ltd. is offering a farm-in opportunity in exploration permit PEP 60094, located in the Taranaki Basin. Todd reported that equity is available in the permit, in which it holds 100% operated interest and is looking for a partner to participate in future work commitments. Todd reports that a number of various prospects have been identified with potential conventional structural and stratigraphic targets.

PNOC-EC has reportedly taken on a 4.5% interest from UC Malampaya Philippines (UCMP) in Shell-operated SC 38, NW Palawan Basin, for USD 56.5 MM. Partnership now Shell (op) 45%, UCMP 40.5%, PNOC 14.5%. SC 38 contains the producing Malampaya ga-cond field.

PNOC-EC has reportedly taken on a 4.5% interest from UC Malampaya Philippines (UCMP) in Shell-operated SC 38, NW Palawan Basin, for USD 56.5 MM. Partnership now Shell (op) 45%, UCMP 40.5%, PNOC 14.5%. SC 38 contains the producing Malampaya ga-cond field.

On 11 July 2019, the Ministry of Industry and Small & Medium Enterprises launched the third bid round for electricity production from renewables. The offers are as follows: 60 MW in individual projects not exceeding 10 MWc and 10 MW in individual projects not exceeding 1 MWc. A procedure manual for potential bidders can be obtained from Tunisian utility STEG at the following link: https://www.steg.com.tn/ministere/ipperautorisation_2019.php Further clarifications can be obtained at the following address:  [email protected] Bids should be submitted before noon (Tunis time) on 26 November 2019. Bids should be sent to the following address: Ministère de l’Industrie et des Petites et Moyennes Entreprises 86 Avenue Mohamed V 1002 Tunis Tunisie

On 11 July 2019, the Ministry of Industry and Small & Medium Enterprises launched the third bid round for electricity production from renewables.

An EPSA was signed yesterday for onshore block 12, 10,000 sq km in central Oman, considered of high gas potential. HoA had been signed last April for this contract-to-be, Total 100% at the time, therefore PTTEP has now joined-in. Plans include G&G, 3D seismic + drilling in the 1st 3 years. Total (op, map extract below) 80%, partner PTTEP 20%.

An EPSA was signed yesterday for onshore block 12, 10,000 sq km in central Oman, considered of high gas potential. HoA had been signed last April for this contract-to-be, Total 100% at the time, therefore PTTEP has now joined-in.

Bridgeport Energy Ltd was awarded exploration permit ATP 2022-P, located in the Cooper-Eromanga Basin, on 4 December 2019. The permit has been awarded for a period of six years and will expire, or be eligible for renewal, on 3 December 2025. The permit was applied for in 2015 as block PLR2015-2-10, after being offered in the Queensland State 2015 Acreage Offer. The round was open between 14 May and 8 October 2015. After application, Bridgeport was required to complete native title agreements, with the permit then granted as an Authority to Prospect (ATP) exploration areas. The permit contains part of the Inland oil field, which was discovered in 1994. It also contains four wells – Morney North, which was dry, and the Morney 1,2 and 3 wells, all of which encountered oil and gas shows. ATP 2022-P, which covers an area of 438 sq km, was awarded on 4 December 2019. Bridgeport Energy (QLD) Pty Ltd holds 100% interest and operatorship of the permit.

Bridgeport secured sole rights to ATP 2022-P, 438 sq km around the Inland field in the Cooper-Eromanga,

Further to DEA 2 Jan ’19 (content): Atwater Valley block 23 adjacent to Gunflint field, OCS lease G35015, WD ~1,650m, non-commercial hc (15m net o&g pay) cleared to P&A on 23 Dec ’18, Deepwater Asgard DS. Murphy (op), partners Ridgewood King Cake, ILX Prospect King Cake, Talos Res. + Fieldwood Energy.

AT 023 001S0B0 (King Cake) (Murphy 35% op, Ridgewood 21,25%, ILX 21,25%, Talos 13,89%, Fieldwood 8,61%) in Atwater Valley block 23 (G35015), encountered “non-commercial quantities of hydrocarbons” and was plugged and abandoned.

Shell has sold out to Equinor in PL 878, part-blocks 30/2 + 30/3. The 30% involved brings Equinor to sole ownership of the 361-sq km licence and the deal is retro-effective 8 Feb ‘19.

Norway, not found

On 11 May 2020, Petrobras issued a press release indicating that the 9-AB-135D-RJS well, in the Albacora production concession in the Campos Basin, encountered 214 m of reservoirs, with light oil, as indicated by test made at 4,630 m. The reservoir rocks are most likely Pre-salt microbialites of the Aptian Macabu Formation. The 9-AB-135D-RJS service well spudded on 15 February 2020. The well is assumed to continue to be drilled by the Ocyan NORBE VIII drillship at a water depth of 450 m. The Albacora Block is owned and operated 100% by Petrobras since August 1998 when it was officially awarded during the ANP Round 0. The ANP approved a modified development plan for the contract in November 2014 requiring the company to develop the pre-salt Macabu Formation reservoir. The Albacora Field was discovered in 1984 by the 1-RJS-297-RJ new field wildcat (NFW) spudded in August 1984 and completed in September 1984 as an oil discovery. The NFW found oil in the post-salt Albian sandstones of the Namorado Formation. In November 1984, well 1-RJS-305-RJ discovered 2,800 bo/d in Post-salt sandstones of the Carapebus Formation, and 640 bo/d in the Namorado reservoir. The well spudded in September 1984 and it was completed in November of the same year. In April 2011, Petrobras announced the discovery of Pre-salt carbonates of the Macabu Formation by well 6-BRSA-899D-RJS, Forno prospect, located in the south-central area of the Albacora Block. The well spudded in April 2010 and it was completed in October 2011. The discovery was originally reported to have 104 m of pre-salt Macabu Formation pay.  However, in its June 2015 environmental permit the company indicated that the well had 255 m of gross pay from 4,458 m to 4,713 m with 31° API oil and 40 PPM H2S. Petrobras has drilled three other outpost wells to the Forno discovery.  The first was the 3 km northeast outpost 3-AB-125-RJS (3-BRSA-1123-RJS) suspended as an oil producer on 30 July 2013. The second 9.4 km southwest outpost was the 3-AB-126-RJS (3-BRSA-1238-RJS) suspended as an oil producer in early November 2014.  The third 5.7 km north northwest outpost was the 3-AB-128-RJS (3-BRSA-1316-RJS) suspended as a potential oil producer on 17 June 2016 with an early-October 2016 press reports indicating it had 45 m net pay section below 4,600 m. The Albacora Field currently produces only from the Post-salt reservoirs. As of December 2019, the field has produced 909.17 MMbo and 590.29 Bcfg. The 2019 ANP BAR reserves report estimates original oil in place (OOIP) of 4.35 Bbo and original gas in place (OGIP) of 3.39 Tcfg. Assuming a 35% recovery factor (FR), the recoverable oil is estimated at 1.52 Bbo and assuming a 43% RF for the gas, a 1.46 Tcfg is estimated for the recoverable gas.

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

A gas find has reportedly been made of late in the Kharkiv area, E. Ukraine. This would be the 4th in the area this year, w.o. confirmation / details if possible.

A gas find has reportedly been made of late in the Kharkiv area, E. Ukraine. This would be the 4th in the area this year, w.o. confirmation / details if possible.

88 Energy has provided an update on its projects, located onshore North Slope of Alaska. Highlights Announced high bidder on two parcels of acreage totalling ~32,800 gross acres Bid Details 88 Energy via its subsidiary companies, Accumulate Energy Alaska Inc and Regenerate Alaska Inc, was announced high bidder on 32,800 gross acres on 6th December (AK time) as part of the North Slope Areawide 2017W lease sale. The two parcels are subject to regulatory approvals and formal award, expected in 2018. Joint Venture Partner Burgundy Xploration has a right to back in to ~2,590 acres contained within Parcel 1, adjacent and to the west of the existing Project Icewine leases. Additional detail will be provided on the new leases in due course. *approximate outline of existing acreage currently under award Managing Director, Dave Wall, commented: 'This result is a continuance of our acreage expansion plan on the North Slope and the Company is very pleased to be announced high bidder at the recent lease sale. Additional details in relation to both parcels will be announced in due course.' Original article link Source: 88 Energy

United States, not found

Central part of Bassein field, Bombay offshore, P&A'ing believed disappointing at TD 2,171m, Vivekanand 2 JU.

BB-SS 1 (Bassein) appr Central part of Bassein field, Bombay offshore, P&A'ing believed disappointing at TD 2,171m,

On 5 June 2019 the NPD confirmed that Equinor has taken 60% of Suncor’s interest in PL 375 and has assumed operatorship of the licence (effective from 29 May 2019). PL 375 covers part of block 34/4 and contains the Beta and Beta Brent discoveries where development studies are ongoing. Suncor confirmed that submission of the PDO has been postponed by two years and is now due in February 2022. Previously, a tie-back to Snorre had been considered but had been deemed uneconomic. In 2000 Saga made the Middle Jurassic Brent Group Delta oil discovery with 34/4-10 R. This has now been re-named Beta Brent. Ten years later Petro-Canada (now Suncor) drilled 34/4-11 to the northeast and encountered oil in the Brent and Statfjord formations in the Beta structure. The find was appraised in early 2011 by 34/4-13 S and oil was tested from the Statfjord Formation at 10,064 b/d through a 28/64” choke. In 2012 Suncor drilled appraisal well 33/6-3 S 9 km southwest of 34/4-11 targeting Beta Statfjord South but although the Lower Jurassic Statfjord Formation objective was encountered it was dry. Its Beta Statfjord North appraisal well 34/4-14 S, drilled in 2015, was also a dry hole. The NPD (December 2018) quotes recoverable volumes of 24 MMbo plus 11 Bcfg in Beta but does not provide a figure for Beta Brent (it considers that production is unlikely). Interest in PL 375 is held by Equinor Energy AS (60% + operator), Suncor Energy Norge AS (20% + operator) and Var Energi AS (20%).

Suncor has assigned 60% + Op from its 80% stake to Equinor (->60% + Op, VÃ¥r Energi 20%, Suncor 20%) in PL 375.

As of 14 December 2018, Cia Espanola de Petroleos SA (CEPSA) has received approval for the formation technical evaluation area (TEA) LXXIII from Perupetro in early December. Worked program has been submitted and approved by Perupetro. In September 2018, CEPSA submitted a request to Perupetro for the formation of a new technical evaluation area (TEA) called LXXIII. Perupetro has tentatively approved the TEA and is awaiting the submittal of a planned program which is currently being prepared by CEPSA.

Cia Espanola de Petroleos SA (CEPSA) has received approval for the formation technical evaluation area (TEA) LXXIII from Perupetro in early December. Worked program has been submitted and approved by Perupetro. In September 2018, CEPSA submitted a request to Perupetro for the formation of a new technical evaluation area (TEA) called LXXIII. Perupetro has tentatively approved the TEA and is awaiting the submittal of a planned program which is currently being prepared by CEPSA.

Following the award of the F.R 43.GM exploration permit in December 2018, Global MED is seeking partners for its Ionian Sea acreage composed of the F.R 41.GM, F.R 42.GM and F.R 43.GM contiguous exploration permits ahead of a 676-km 2D seismic survey. The company is also seeking partners for its freshly awarded (December 2018) blocks located on the maritime border with Greece in the Ionian Sea (F.R 44.GM and F.R 45.GM) to finance a 300-km 2D seismic survey. Global MED was awarded the 748-sq km F.R 41.GM and the 749-sq km F.R 42.GM blocks on 15 December 2016 for six years and the F.R 43.GM block on 7 December 2018 . The main objectives in the area are the Mesozoic carbonates (Upper Cretaceous), thermogenic gas within the tertiary flysch (foredeep) being a secondary objective. Water depths are ranging from 1,000 m to 2,000 m. The 745-sq km F.R 44.GM and the 749-sq km F.R 45.GM exploration permits were awarded to Global MED on / December 2018. The contiguous blocks are adjacent to Block O2 operated by Total in the Greek waters. Objectives in the area are the Cretaceous to Eocene carbonates of the Apulian Platform. Water depths range from 400 m to 1,100 m. Global MED LLC holds a 100% operating interest in the five exploration permits. For further information please contact the following: Randall Thompson, Managing Director Global MED LLC 6901 So. Pierce St., Suite 390 Littleton, Colorado 80128 USA Tel: +1 303 507 8886 [email protected]

Following the award of the F.R 43.GM exploration permit in December 2018, Global MED is seeking partners for its Ionian Sea acreage composed of the F.R 41.GM, F.R 42.GM and F.R 43.GM contiguous exploration permits ahead of a 676-km 2D seismic survey.

Tethys Petroleum reports the results of testing the exploration well Klymene KBD-02 drilled in the company’s Kul-Bas contract area (block 1897RD Kul-Bas), North Ustyurt Basin. The test period for the first zone (Jurassic) has been completed and the testing for the second potential zone has been initiated. The test in the first zone (possibly in the Cretaceous) was done using different choke sizes between 5 and 11 mm. The 11 mm choke increased production to over 700 bo/d from 400 bo/d on 9 mm choke achieved in June. Tethys has now tested a second zone at depths of 2127.4 - 2145.4 m. The test produced at an average rate of 15.5 tonnes/hour or 372 t/day (approximately 2,700 bo/d) using an 11 mm choke. On a 9 mm choke, the average production rate was 276 t/day (2,000 bo/d). The oil quality is high, the pressure is very good and currently there is no water present. Over the next 10-12 days, wireline logging, work with different chokes and pressure tests will be carried out. The current storage and distribution capacity on the site is limited and this may affect Tethys' ability to run tests with larger choke sizes. The well has been drilled to a TD of 2,750 m, it was spudded in summer 2019. The well was originally supposed to take between 3 and 4 months to complete but took longer time due to a combination of circumstances including finance, harsh weather and the pandemic. Background Information Klymene is located to the west of the current producing fields in Tethys’ Akkulka exploration contract (Kyzyloy, Doris, Akkulkovskoye and others). The prospect was identified from seismic acquired and interpreted by Tethys in 2013 and indicates a four-way dip closure with bright spots at 2 of 3 prospective stratigraphic levels within the Cretaceous and Jurassic sequences, both of which are productive in the Doris oilfield some 60 km to the east. The Klymene prospect has the potential to be an order of magnitude bigger than the Doris oil discovery and surrounding prospects (the geographical area of the prospect is up to 10 times the areal extent of the Doris oil field). Klymene has been independently estimated to hold 422 MMb of unrisked mean recoverable oil resources. Tethys has previously drilled one exploration well, Kalypso KBD 01, in the Kul-Bas contract area. The well has not been completed. In February 2020, the company received confirmation of an extension of the Kul-bas Exploration Contract until December 31, 2022.

Kazakhstan (North Ustyurt B.), Klymene-2 (KBD) expl, operated by TETHYS PT (100%) in 1897RD Kul-Bas block, testing completed of Jurassic between 2127.4-2145.4m, ab. 2,700 bo/d on 11 mm choke, no water, testing continues (2nd zone of interest identified). PTD was 2,500m.

Europa has been assigned an 8-yr contract to the Inezgane block, 11,228 sq km in the Agadir Basin, WD 600-2,000m, as per the Europa map below. A farmout is not ruled-out at a later stage (phase 2). Europa (op) 75% partner Onhym.

Europa Oil & Gas (75% op, ONHYM 25%) has awarded Inezgane Offshore permit (11228km²) in WD 600-2000m.

In May 2018 Overgas was still offering the opportunity for interested parties to farm-in to licences Provadia and 1-18 Trakiya. The Provadia licence is located in the eastern part of the country while the 1-18 Trakiya licence is situated in southern Bulgaria. The company started looking for partners in May 2016. Between 2011 and 2014 Overgas conducted two 2D seismic surveys and one 3D seismic survey totaling respectively 812 km and 55 sq km in the Provadia licence. No fields are situated within the permit area. The last known drilling activity consists of Krivnya 12 which was drilled to a total depth of 2,769 m in the Lower Triassic and abandoned as a dry hole in 1984. In the 1-18 Trakiya licence, the company drilled the Trakiya 1 exploration between 2014 and 2015. The hole reached a total depth of 1,717 m bottoming in metamorphic rocks without reaching the targeted Jurassic sediments. It was subsequently re-entered for testing and recovered only gas shows. In late 2012 Overgas conducted a 474 km 2D seismic survey in the permit. For further information please contact: Dimitar Merachev Tel - +359 2 865 11 99 [email protected]

In May 2018 Overgas was still offering the opportunity for interested parties to farm-in to licences Provadia and 1-18 Trakiya. The Provadia licence is located in the eastern part of the country while the 1-18 Trakiya licence is situated in southern Bulgaria.

Further to DEA 4 Jan ’18, PEL 650, Adelaide Fold Belt, TD 630m, suspended on 16 Jan ’18, reported dry but evaluations underway.

Australia (Adelaide Fold Belt) Playford 2B op. by ARP TRIEN (100.0%) in PEL 650 block reported dry but evaluations underway.

As of March 2020, China Congo Wing Wah Petrochimie SA (Wing Wah) is understood to have completed drilling operations at the Ngoubili 1 exploration well within the Kayo Bloc Nord (Kayo permit, in Lower Congo Basin). The well was plugged and abandoned as dry. Wing Wah is understood to target the Barremian Mengo Sandstone Formation and Barremian to Aptian Toca Carbonate Formation as Pre-salt objectives. The planned was 2,800 m. The well appears to have been spudded in September 2019 (original planned spud date was 19 June 2019). On 26 November 2018, the company completed a 5-well drilling programme: HOL-1, HOL-2, HOL-3, HOL-4 and HOL-5 all have been positive except for HOL-1. Wing Wah operates the tract with an 85% interest. SNPC holds the remaining 15% carried interest as partner.

Ngoubili 1 nfw (Wing Wah 85% op, SNPC 15%) Kayo Bloc Nord (Kayo permit), onshore, P&A dry, PTD was 2800m, targets believed pre-salt Mengo + Toca Fm's.

Capachos block, Llanos Basin, TD 5,476m, oil in the Guadalupe + Une fm’s, tested avg 2,785 b/d of 40 API oil + 4.3 MMcfg/d unassisted for 81 hrs from the target Guadalupe, 2% water cut, WHP 1,420 psi,  and 621 b/d of 37 API oil, 1.5 MMcfg/d + 446 bw/d from the secondary Une target, avg flow for 63 hrs. The Une fm requires isolation from the water production and could be produced later.   Well suspension and rig to drill Andina-3 appr from the same pad.

Andina Norte 1 (Ecopetrol op. 50%, Parex Res. 50%) in Capachos onshore block, reached an average output of 2785 bo/d and 4,3 MMscf/d in the Guadalupe Fm. during a test (2% water cut). In the Une Fm, average production hit 621 bo/d and 1,5 MMscf/d + 446 bw/d. The block currently produces 5100 bo/d, and Parex has said it expects the field’s output to hit 10 000 boe/d by the fourth quarter of 2019.

On 4 November 2019, Hungarian Magyar Olaj- és Gázipari Nyrt. (MOL) announced it signed an agreement to acquire Chevron's 9.57% stake in the Azeri-Chirag-Guneshli field (ACG) and 8.9% stake in the Baku-Tbilisi-Ceyhan (BTC) pipeline. The transaction is valued at USD 1.57 billion (subject to adjustments at closing). After closing of the deal, MOL will be the third largest stake holder in ACG and BTC, after BP and SOCAR. In 2018, approximately 212 MMbbl (580,000 b/d) of oil were produced at ACG, which represents about 80% of Azerbaijan’s oil production. In December 2018, media reported Chevron’s and ExxonMobil’s intends to exit ACG. Background Information The ACG fields are located 60 kms east of the Absheron peninsula, in the Caspian Sea, on the regional Absheron-Pribalkhan zone of uplifts. This zone represents a string of structures running from the Absheron Peninsula to the Cheleken Peninsula in Western Turkmenistan. Initial 2P Reserves are estimated at 6.8 Bbbl of oil. On 31 October 2017, the Azeri Parliament ratified the new Azeri-Chirag-Guneshli (ACG) field PSA signed by partners on 14 September. SOCAR increased its take from 11.645% to 25%, while other participants decreased their stake. New ownership: BP-operator (30.37%), SOCAR (25%), Chevron (9.57%), INPEX (9.31%), Statoil (now Equinor) (7.27%), ExxonMobil (6.79%), TPAO (5.73%), ITOCHU (3.65%) and ONGC Videsh Limited (2.31%). In addition, Azerbaijan would receive 75% of production after cost recovery (currently 80%) and USD 3.6 billion in bonuses. Plans foresee investments in the amount of USD 40 billion during the next 32 years. The PSA is valid until 31 December 2049. The previous ownership in the PSA was: BP - operator (35.795%), SOCAR (11.645%), Chevron (11.27%), INPEX (10.96%), Statoil (now Equinor) (8.56%), ExxonMobil (8%), TPAO (6.75%), ITOCHU (4.3%), ONGC Videsh Limited (OVL) (2.72%). The contract was signed on 20 September 1994 for duration of 30 years. The BTC pipeline has a capacity of over 1 MMb/d for a total length of 1,768 km, crossing Azerbaijan (443 km), Georgia (249 km) and Turkey (1,076 km). BTC shareholders are BP (30.1%), SOCAR (25%), Chevron (8.9%), Statoil (now Equinor) (8.71%), TPAO (6.53%), ENI (5%), Total (5%), Itochu (3.4%), ExxonMobil (2.5%), Inpex (2.5%) and ONGC Videsh (2.36%).

Azerbaijan MOL (BP op 30.37%, Socar 25%, Inpex 9.31%, Equinor 7.27%, ExxonMobil 6.79%, TPAO 5.73%, Itochu 3.65% and OVL 2.31%) has agreed to acquire Chevron's 9,57% stake in the Azeri-Chirag-Guneshli (ACG) field, for US$ 1.57 billion (comprises an 8.9% stake in the Baku-Tbilisi-Ceyhan (BTC) pipeline).

Effective 1 October 2017 Hilcorp Alaska LLC was officially awarded 14 tracts covering about 76,682 acres (310 sq km) off Alaska’s south-central coast from the Cook Inlet Lease Sale 244 held by the Bureau of Ocean Energy Management (BOEM) on 21 June 2017. The company placed high bids in the amount of USD 3,034,815 and was the sale’s lone bidder. Sale 244 was the thirteenth and final OCS lease sale held under the 2012-2017 Five-Year Program. It offered some 1.09 million acres (4,410 sq km) for leasing and consisted of 224 blocks that stretched roughly from Kalgin Island in the north to Augustine Island in the south. Each bid went through a 90-day evaluation process to ensure the public received fair market value before a lease was awarded. All materials and statistics for Lease Sale 244 are available at: http://www.boem.gov/ak244. Hilcorp Official Awards               Contract Company Name WI Bonus USD Acre Sqkm Lease Sale Award Date Basin   Y02434 Hilcorp Alaska 100 $62,208.00 5,184.26 20.98 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02435 Hilcorp Alaska 100 $37,416.00 3,118.47 12.62 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02436 Hilcorp Alaska 100 $68,376.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02437 Hilcorp Alaska 100 $142,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02438 Hilcorp Alaska 100 $111,606.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02439 Hilcorp Alaska 100 $313,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02440 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02441 Hilcorp Alaska 100 $203,319.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02442 Hilcorp Alaska 100 $111,606.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02443 Hilcorp Alaska 100 $256,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02444 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02445 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02446 Hilcorp Alaska 100 $152,019.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02447 Hilcorp Alaska 100 $152,019.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Totals     $3,034,815.00 76,681.62 310.32         Source: IHS Markit               © 2017 IHS  

United States, Y02440

E-C part of AE-0073-M-Puchut-01 block, onshore Tampico-Misantla Basin, horiz well from Llano Lindo-1 drillpad, completing at TMD 4,940m (3,269m TVD), target Pimienta fm.

Kaneni 1EXP (Pemex 100%) in E-C part of AE-0073-M-Puchut-01 block, onshore horiz well from Llano Lindo-1 drillpad, completing at TMD=4940m, target Pimienta fm. results n/a yet.

Inpex has been awarded WA-533-P over 12,439 sq km in WD 50-600m, offshore Canning Basin, offered in the 2016 block release as W16-6. Commitments include G&G, and one well by March 2024.

Australia, not found

1st of 2 committed wells in PSCA 16/25, Huizhou Sag in PRMB, South China Sea, WD 100m, ops terminated late Aug ’18, HYSY 943 JU. Target Lower Tertiary Enping-Wenchang fm.

Huizhou 25-7-4 (HZ 25-7-4) appr, 1st of 2 committed wells in PSCA 16/25, Huizhou Sag in PRMB, South China Sea, WD 100m,

The result of recent testing, Waitsia 2P reserves have been increased by 78% to 811 PJ (gross, 770.5 Bcfg) from the previous estimate on 30 Jun ’17. The independent review results by RISC Operations thus more than doubles the amount of gas required for Waitsia Stage 2 project.  The field lies in L1/L2, northern Perth Basin. Detailed results from AWE.  AWE (op) 50%, Origin 50%.

Waitsia 2P reserves have been increased by 78% to 811 PJ (gross, 770.5 Bcfg) from the previous estimate on 30 Jun ’17.

Geonadr is offering 10 onshore blocks in the first licensing round to be held using the new ProZorro online bidding system. Eight blocks are available in the Dnieper-Donets Basin - Dubrivsko-Radchenkivska, Kniazhynska, Pechenizko-Kochetkivska, Pivdenno-Kobzivska, Saltivska, Svitankovo-Lohivska, Vatazhkivska, and Zakhidnotokarsko-Krasnianska, plus Dykhtynetska in the Carpathian Basin and Suvorivska in the Predobrogea Basin. Companies must register before the auction takes place on 6 March 2019. A further 20 onshore and 14 offshore blocks are earmarked for release in the coming year. Full details at http://www.goukrainenow.com/ and https://prozorro.sale/

Geonadr is offering 10 onshore blocks in the first licensing round to be held using the new ProZorro online bidding system. Eight blocks are available in the Dnieper-Donets Basin - Dubrivsko-Radchenkivska, Kniazhynska, Pechenizko-Kochetkivska, Pivdenno-Kobzivska, Saltivska, Svitankovo-Lohivska, Vatazhkivska, and Zakhidnotokarsko-Krasnianska, plus Dykhtynetska in the Carpathian Basin and Suvorivska in the Predobrogea Basin. Companies must register before the auction takes place on 6 March 2019

In late April 2020, the General Directorate of Mining and Petroleum Affairs (MAPEG) approved the transfer of Valeura Energy Inc’s and Petrako Ltd’s respective 35% and 10% interests in the E17-b4-1, E17-c1-1 and E17-c2-1 production leases (collectively known as Edirne) to Petrogas Petrol Gaz ve Petrokimya Ürünleri Ins San ve Tic AS (Petrogas Petrol Gaz), a subsidiary of Reform Oil & Gas. The companies had applied for the transfer in late March 2020. Following the transaction Reform Oil & Gas operates the acreage with a 100% interest. <P />The Edirne leases are located in the Thrace Basin in NW Turkey, around 190km NW of Istanbul. They contain a number of gas accumulations, which according to Valeura have not seen any production or activity for several years. It therefore deemed the leases to be no longer prospective.<P />Reform Oil & Gas only recently acquired the Edirne production leases, after purchasing all shares in Petrogas Petrol Gaz from TransAtlantic in Q1 2020. In consideration for the sale, which also included several other production leases in NW Turkey, TransAtlantic received US$ 1.5 million and a release of all plugging and abandonment obligations for 65 wells.

General Directorate of Mining and Petroleum Affairs (MAPEG) approved the transfer of Valeura Energy Inc’s and Petrako Ltd’s respective 35% and 10% interests in the E17-b4-1, E17-c1-1 and E17-c2-1 production leases (collectively known as Edirne) to Petrogas Petrol Gaz ve Petrokimya Ürünleri Ins San ve Tic AS (Petrogas Petrol Gaz), a subsidiary of Reform Oil & Gas.

NE part of WA-404-P, Exmouth Plateau, WD 1,495m, P&A at TD ~5,300m on 18 Jun ’18, Ensco MS-1 SS released.

Ferrand 1 (Woodside 100%) in WA-404-P block, P&A, results n/a. Well was targeting a ‘large’ volume of gas, within an anticlinal trap, which is considered to be over 100 MMboe. The well targeted a structural trap within Triassic units.

Abu Dhabi National Oil Company (ADNOC) announced on 11 March 2018 that it has signed two agreements awarding Eni stakes in two offshore concessions. Under the terms of the agreements, Eni has received a 10% interest in the Umm Shaif & Nasr concession and a 5% interest in the Lower Zakum concession, for participation fees of US$ 575 million and US$ 300 million respectively. The awards mark the first time an Italian company has been granted concession rights in Abu Dhabi.<P />Both concessions are operated by ADNOC subsidiary ADNOC Offshore (60%) and will be valid for a 40-year term, backdated to 9 March 2018. In the Lower Zakum concession Eni is also joining an ONGC-led Indian consortium (10%) and INPEX Corp (10%), whereas in the Umm Shaif & Nasr concession Eni is ANDOC's first partner to be assigned a stake. For both assets ANDOC is in the process of finalising the potential partners for the remaining interests.<P />Umm Shaif & Nasr and Lower Zakum are two of three new separate concession areas which have replaced the offshore concession operated by the Abu Dhabi Marine Operating Co (ADMA-OPCO). The ADMA offshore concession expired on 8 March 2018, after ADNOC chose not to extend it. The move followed the company's decision to expand its strategic partnership model, as well as the active management of its portfolio of assets. The company stated that the new approach, which builds on its flexible and enhanced operating model as well as its 2030 growth strategy, will enable it to gain greater market access, broaden the partner base, expand technical expertise and maximize value<P />ADMA-OPCO, a JV comprised of ADNOC (60%), BP (14.67%), Total (13.33%) and INPEX Corp (12%), was established in 1977 to operate the ADMA concession, which among others included the Lower Zakum, Umm Shaif, Umm Lulu, Satah Al Razboot and Nasr fields. The current production of the Lower Zakum Field stands at around 400,000 bo/d, with the aim of reaching a production plateau of 450,000 bo/d by 2025. The field was discovered in 1963 and began production in 1967. The Umm Shaif and Nasr Fields have a production target of 460,000 bo/d. As ADNOC looks to boost the country's oil production capacity to 3.5 MMbo/d in 2018, the development of its offshore fields is of strategic importance. The former ADMA concession area, which produces around 700,000 bo/d, is planned to have a production capacity of about 1.0 MMbo/d by 2021.

Eni has signed in Abu Dhabi 2 Concession Agreements for the acquisition of a 5% stake in the Lower Zakum offshore oil field and of a 10% stake in the oil, condensate and gas offshore fields of Umm Shaif and Nasr, for US$875 MM.

On 14 October 2017, Occidental together with Oman Oil Co Exploration & Production LLC (OOCEP), a wholly-owned subsidiary of state company Oman Oil Co SAOC (OOC), signed an Exploration & Production Sharing Agreement (EPSA) with the Omani Government for Block 30 (Hafar). The onshore block (1,185 sq km) is located in northern Oman and adjoins Occidental's Block 27 (Wadi Aswad) and Block 62 (Habiba).<P />The block has been awarded following the country's 2016 Licensing Round, which was launched in October 2016 and closed in February 2017. It was among a total of four blocks on offer, which are located in different parts of the country. <P />To date, gas has been discovered in four separate structures with reservoirs in the Cretaceous Natih and/or Shuaiba formations. These discoveries have not been fully appraised and adjacent structures remain undrilled. Altogether nine wells have been drilled, with six of those having encountered gas. Gas rates from DSTs and during long-term tests ranged from 7 MMcfg/d to 19 MMcfg/d. The last well, Hamrat Duru 4, was drilled by RAK Petroleum in 2010. It is understood that tight gas is the predominant play within the block and that there are currently two gas prospects mapped within the block.<P />Occidental operates the acreage with a 72.86% interest, with OOCEP holding the remaining 27.14%.

Oman, Block 30 (Hafar)

The joint venture partnership of Metgasco Pty Ltd, Vintage Energy Pty Ltd and Bridgeport Energy Ltd has entered into an agreement with Senex Energy Ltd to enter PRL 211, located in the Cooper-Eromanga Basins. The joint venture already has ownership of adjacent exploration licence ATP 2021-P, which is on the Queensland side of the basin (subject to relevant authority approvals and registration of the interests). PRL 211, located in South Australia, is currently 100% owned by Senex's subsidiary Stuart Petroleum Pty Ltd. Entry into the retention lease provides the joint venture with complete access to the Odin Prospect which straddles both ATP 2021-P and PRL 211. The Vali Prospect, located solely in ATP 2021-P, is scheduled to be drilled in December 2019 which could provide significant de-risking of the Odin Prospect. Under the terms of the initial farm-in agreement, a term sheet has been executed with a 90-day exclusivity period for the companies to negotiate a final farm-in agreement. Upon completion, it's proposed that Vintage will acquire operatorship of the licence with 42.5% interest. The remaining interest will be split between Bridgeport (21.25%), Metgasco (21.25%) and current holder Senex (15%). A number of conditions must be satisfied by 31 January 2020 including Ministerial approvals, a demonstration of sufficient funds being available to drill a well and the execution of a formal farm-in agreement. With the Odin structure being the main target, the terms extend to specifically drilling the prospect, for which, Vintage will be liable for 50% of the costs to acquire its 42.5% equity. The remaining costs will be split evenly between Bridgeport and Metgasco. It's expected that the initial well costs will be around AUD 4 million. Subsequent well testing costs will reflect the equity share in the licence once the farm-in deal is completed. PRL 211 was awarded over exploration licence PEL 637 (replacement of PEL 516, 2010), which was awarded in 2014 to Stuart Petroleum. Origin entered in 2015 forming the subsequent partnership for PRL 211, which was awarded on 25 October 2017. PRL 211 now covers nearly 100 sq km. The joint venture partnership ended on 26 June 2018 with Stuart acquiring Origin's 40% interest. The Odin Prospect comprises an anticlinal structure on the eastern boundary of the permit with an independent closure at a depth of around 2,300 m. The Strathmount 1 exploration well, which was drilled in 1987, lies within the extent of the prospect. The well encountered 21 m of reservoir sands and 13.7 m of interpreted gas pay. Gas flow testing indicated returned gas to surface, but rates were too small to measure. On the 2016 Snowball 3D seismic data, Metgasco reports that the well appears to have intersected the sands outside of the Toolachee and lower Patchawarra level. Odin has been assigned gross P50 recoverable resources of 12.6 Bcf, a 3.9 Bcf upgrade from estimates released in 2018. Across the state and licence boundary, ATP 2021-P is mainly prospective for Permian gas and Jurassic oil accumulations. The Vali Prospect could be tested in December 2019 which comprises an anticlinal structure at the Toolachee and lower Patchawarra levels with independent closure at a depth of around 2,250 m. Metgasco has reported that the prospect is likely to contain reservoir characteristics similar to that of the nearby Kinta 1 gas discovery. The Kinta 1 well intersected 37 m of interpreted gas pay but did not retuned hydrocarbons to surface. Vali has been assigned P50 recoverable resources of 19 Bcf.

Bridgeport Energy Ltd, Metgasco Pty Ltd, Vintage Energy Pty Ltd extend their JV partnership to PRL 211, Cooper-Eromanga Basins

On 16 April 2019, the Argentine government announced the winning bids for Round 1 of its offshore bid round, which included offers from 13 companies for 18 blocks (out of 38) in the Austral, Malvinas, and Argentina Basin with a total investment USD 995 million. According to official sources, preliminary awards are scheduled for 16 May 2019, to be followed by issuance of permits on 1 August 2019. Official awards are expected within 15 days after the permits are granted. In Austral Basin, two shallow water blocks (out of six offered) will be assigned to Equinor with a total investment of USD 38.1 million. Meanwhile in Malvinas Basin, nine deepwater blocks (out of 18 offered) will be assigned to five different operators (Eni, Equinor, ExxonMobil, Total, and Tullow Oil) with a total investment of USD 776 million. In Argentina Basin, seven deepwater and ultra-deepwater blocks (out of 14 offered) will be assigned to four different operators (Equinor, Shell, Total, and YPF) with a total investment of USD 181.1 million. Fifteen companies were previously qualified to participate in the round in mid-March 2019. Complete results with known information so far: The exploration target for blocks in the Austral and Malvinas basins is expected to be oil and gas in the Springhill Formation. The formation has been proven to be a producer in several gas fields in the Austral Basin, although no discoveries have been made in any of the areas covered by the bid blocks. In comparison, Springhill Formation has not produced from any fields on the Malvinas Basin side, although the bid blocks area includes 3 discoveries: Ciclon 1 oil discovery by YPF in MLO-122 in 1980, along with Salmon 2 gas discovery in MLO-117 by Esso (ExxonMobil) in 1981 and 1982, respectively. Most recently, MLO-117 was part of the Calamar block, where state energy company ENARSA conducted a study with Venezuelan state company PDVSA in 2015 with potential of the area said to be at 3.6 Tscf of gas. Meanwhile, the deepwater and ultra deepwater blocks in the Argentina Basin are relatively unexplored. There are no discoveries or significant drilled wells in the bid blocks area, other than two wells that were drilled and P&A’d with oil & gas shows by Union Texas in CAN-109 in the mid-1990’s. Most of the blocks will include a 13 years exploration period (4 years each in the first and second phases with 5 years in the third) with no drilling commitments until the second exploration period, and followed by 30 years of production period with unlimited possibility of 10 years extension, except for shallow water blocks which will have shorter exploration phases of 11 years (4+4+3) with the same length of production period. The government reportedly require that 50% acreage must be relinquished after the 2nd exploration phase. Royalties will start at 5%, but will increase to 12% depending on performance. It was also said that there will be an option for suspension of development plan, where if a discovery was made but found to be non-economical a suspension of five years is available and can be renewed one additional time for another five years. Background Information Round 1 of Argentina offshore bid round was officially launched in November 2018 for 38 blocks in the Austral, Malvinas, and Argentina Basin with the publication of Resolution 65/2018 on 6 November 2018. Prior to the launch of Round 1, the Argentinean government has assigned Spectrum Geo to acquire 2D seismic lines in late-2017. In Malvinas Basin, 13,784 km of acquisition was completed in March 2018, while in Argentina Basin, 37,900 km was completed in May 2018.

Argentina, not found

On 27 April 2018, the Federal Agency for Subsoil Use held an auction for the Khasanovskiy block in Samara Oblast (Volga-Ural Province). Aloil won the auction with the offer of RUB 24 million (USD 0.38 million). The winner of the auction will obtain 25-year E&P license. The Khasanovskiy block covers 397 sq km in the southwestern flank of the Tatarskiy Yuzhnyy Dome and encompasses the Anlinskiy Zapadnyy prospect with oil resources estimated at 3 MMbbl. Seismic coverage amounts to 225 km. Two exploratory wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 54 MMbbl of oil and 3 Bcf of gas. The starting price amounted to RUB 16 million (USD 0.28 million).

Russia, not found

It is understood that Repsol has agreed to farm out a participating interest in the Andaman III PSC, in offshore North Sumatra Basin, to Petronas Carigali. Repsol was offering up to 49% interest in the block, with a data room opened in September 2018. The new partner will support the drilling of high-impact wildcat Rencong 1X, planned for 2020. Local media in early November 2019 also reported that Repsol will likely receive a two-year extension for the exploration period in the PSC. The extension was recommended by BPMA, the Aceh upstream regulator, for final approval by the Ministry of Energy and Mineral Resources. Rencong 1X will target Upper Eocene-Lower Oligocene carbonates of the Tampur Formation. The well will fulfill the exploration commitments for the PSC. In late November 2017, the operator completed the seismic commitment with a 3D seismic survey covering more than 3,000 sq km. The survey, acquired using Elnusa’s “Elsa Regent” vessel, was reported as the largest 3D seismic survey acquired in Indonesia at the time. The block is operated by Repsol’s fully owned subsidiary Talisman (Andaman) BV, with 100% interest prior to the farm-in by Petronas. The Andaman III PSC, awarded in 2009, covers approximately 8,500 sq km and lies between shelf and over 1,300 m water depth. Background Information The Andaman III block was offered during Phase II 2008 Tender Round under the regular tender mechanism and was officially awarded to Talisman (100%, operator) on 30 November 2009. The company paid a signature bonus of USD 7.5 million for the block. Firm commitments for the initial three-year exploration period included G&G studies worth USD 2 million, acquisition of 2,500 sq km 3D seismic (USD 15 million) and drilling one well (USD 30 million). The seismic acquisition commitment was initially planned in 2010 but was pushed back to a later date. Second exploration phase commitments (Year 4 to 6) include G&G studies (USD 0.6 million), acquisition of 500 sq km 3D seismic data (USD 3 million) and drilling one exploration well, likely carried over from the first exploration phase (USD 30 million). Multiple play types exist in the area, including carbonate build-up on a basement high or on an anticline, syn-rift clastics with combined stratigraphic-structural trap component, inverted syn-rift clastics close to the Mergui Ridge, carbonate build-ups on flanks of the Mergui Ridge and Barisan fold-belt anticlines. Potential source rocks in the area in include the shales of the Eocene Parapat (lacustrine syn-rift), Oligocene Bampo, Lower Miocene Peutu/Belumai and Middle Miocene Baong formations. Potential reservoirs which could have commercial accumulations in this deepwater area are the Belumai carbonates and Parapat syn-rift sandstones. Shales of the Bampo and Baong formations would be the likely seals.

Petronas has agreed with Repsol (->51% op.) to farmin to the Andaman III PSC (8523km²) permit from Repsol, the latter having offered up to 49%.

Petrobras was drilling with oil shows on the 3-SPS-106 (3-BRSA-1370-SPS) outpost of the Sagitario prospect discovery in the BM-S-050 contract, S-M-623 block during early-January 2020. The operator filed an oil show report for the well with the ANP on 6 January 2020. The outpost was spudded on 12 September 2019. The outpost has a proposed total depth (PTD) of 6,665 m and is targeting the Early Cretaceous Barra Velha Formation as the primary target. The ODN I” S/S is drilling the well in a water depth of 1,841 m. The outpost is located approximately 3.6 km north of the 1-SPS-098 (1-BRSA-1063-SPS) new-field wildcat (NFW), Sagitario prospect discovery well. Petrobras is operator of the 324.91 sq km BM-S-050 contract PAD with a 60% working interest and partners are Shell with 20% and Repsol Sinopec with 20%. On 30 May 2018, the ANP granted Petrobras approval for an extension to its discovery evaluation plan (PAD) it filed for the 1-SPS-098 (1-BRSA-1063-SPS) wildcat, Sagitario prospect in the BM-S-050 contract, S-M-623 block.The official PAD name is the PA_1BRSA1063SPS_S-M-623.The final PAD expiry date has been extended from 31 October 2018 to 31 October 2020.Previously in 2015, Petrobras was granted an extension to have time to shoot 3D seismic which was concluded through a multi-client shoot by Polarcus in December 2017.On 24 June 2013, Petrobras suspended as a pre-salt Barra Velha Formation oil discovery the 1-SPS-098 (1-BRSA-1063-SPS) new-field wildcat (NFW), Sagitario prospect. It was drilled to a final total depth (TD) of 7,110 m. The operator filed three oil show reports and announced the well was a discovery in March 2013. Background Information On 24 June 2013, Petrobras suspended as an oil discovery the 1-SPS-098 (1-BRSA-1063-SPS) wildcat, Sagitario prospect, drilled to a final total depth of 7,110 m in the S-M-623 block, after filing three oil shows and announcing the well as a discovery during March 2013. Petrobras filed a third and final oil show report with the ANP on 15 May 2013 for the wildcat. A second oil show report was filed with the ANP on 28 March 2013 and with the release of its new business plan in mid-March 2013, Petrobras announced that the well was a discovery from the first oil show report it filed on 22 February 2013. Petrobras temporarily suspended drilling operations in mid-September 2012 after the Sevan Marine “Sevan Brasil” drillship encountered problems with its BOP system. The operator concluded repairs and re-commenced drilling this pre-salt wildcat well on 15 November 2012. Petrobras spudded the Sagitario prospect well on 31 August 2012 in a water depth of 1,871 m. The new field wildcat had a proposed total depth (PTD) of 6,920 m with the Barra Velha Formation as its primary target. It is located near the plugged geotechnical well 1-SPS-098i (1-BRSA-1063i-SPS) in the southwest part of the block and about 37 km southeast of the non-commercial 6-BG-006P-SPS Corcovado oil, gas and condensate field, previously operated by BG in the northwesterly adjoining, but now relinquished BM-S-052 contract, S-M-508 block. The 1-SPS-098 (1-BRSA-1063-SPS) well is also located about 37 km northwest of the 4-SPS-086B (4-BRSA-971B-SPS) new pool wildcat that Petrobras suspended as an oil discovery in the BM-S-008 block. On 4 December 2013, the ANP granted Petrobras approval for a discovery evaluation plan (PAD) it filed for the 1-SPS-098 (1-BRSA-1063-SPS) wildcat, Sagitario prospect in the Santos Basin, BM-S-050 contract, S-M-623 block. The PAD is now called the PA_1BRSA1063SPS_S-M-623. The PA_1BRSA1063SPS_S-M-623 PAD has the following conditions and stipulations. As a firm commitment the operator is required to conduct one extended cased hole production test, assumed to be of the discovery well. The contingent commitments include acquisition of new multi azimuth 3D seismic covering 500 sq km and the drilling of one appraisal well. The contingent commitments have to be agreed to by 30 June 2014 or the PAD will expire and if the commitments are agreed to and the contingent commitment seismic and exploration well is carried out then the PAD will expire on 31 August 2017. The PAD approval also included a part relinquishment retroactive to the PAD approval date. Petrobras relinquished 373.31 sq km of the northern and eastern areas of the block and retained 324.91 sq km of the southwestern area of the block around the discovery well. The PAD is now called the PA_1BRSA1063SPS_S-M-623 and covers the retained area. The block originally covered 698.22 sq km.Petrobras is operator of the contract with a 60% working interest and partners are BG with 20% and Repsol Sinopec with 20%. On 20 May 2014, Petrobras issued a press release indicating that it concluded a drillstem test (DST) on the 1-SPS-098 (1-BRSA-1063-SPS) new-field wildcat (NFW), Sagitario prospect oil discovery in the S-M-623 block. The operator reported that it tested 32° API oil from a 159 m pre-salt reservoir below 6,144 m with good porosity and permeability. There was no report of actual test volumes of oil and gas. Petrobras moved the “Sertao” drillship to the NFW location in March 2014 and testing operations lasted through mid-May 2014.

Petroleo Brasileiro SA (Petrobras) - Santos Basin - BM-S-050 contract, S-M-623 block - drilling with oil shows 3-SPS-106 (3-BRSA-1370-SPS)

PSCA 03/33, W. Lufeng Sag, PRMB, WD 100m, oil pay in the target Miocene-Oligocene (w.o. details), ops terminated end May ‘18, Nanhai 6 SS.

Huizhou 12-5 (Pr) 1 (Roc Oil 100%) in PSCA 03/33 (Lufeng Sag), Completed with oil pay, in the target Miocene-Oligocene (w.o. details), ops terminated.

On 3 August 2018 Black Sea Oil & Gas (BSOG) announced the completion of the operations in the Iulia 1 exploration well. Iulia 1 is situated in the XV-Midia West block about 115 km east of the coast. It was spudded on 8 May 2018 in a water depth of 73 m using the GSP “Saturn” J/U. The well reached a total depth of 2,110 m in mid-June 2018. The Upper Pontian objective was dry and the well was plugged and abandoned. The block includes the Ana and Doina fields. The Ana (previously named Doina Sister) and Doina fields are located about 105 km from the coast. The Doina field was discovered in 1995 while the Ana field was discovered in 2007. Both are located along the same fault trend with the same reservoir horizon in the Dacian to Recent Series (Dacian to Holocene) below 766 m. Interest in the XV-Midia West block is divided between Black Sea Oil & Gas SRL (65% + operator), Petro Ventures Europe BV (20%) and Gas Plus International BV (15%).

Black Sea Oil & Gas (BSOG) announced the completion of the operations in the Iulia 1 exploration well. Iulia 1 is situated in the XV-Midia West block about 115 km east of the coast. It was spudded on 8 May 2018 in a water depth of 73 m using the GSP “Saturn” J/U. The well reached a total depth of 2,110 m in mid-June 2018. The Upper Pontian objective was dry and the well was plugged and abandoned.

A set of agreements have been signed between Pertamina and ExxonMobil over the Jambaran Tiung Biru (JBT) unitisation project straddling the Cepu PSC and the Jawa Bagian Timur 3 PPC, E. Java. They are the Joint Operation Agreement, Unitisation Agreement, Unitisation Operation Agreement, Cepu Gas Marketing Agreement and Settlement Agreement, all marking the finalisation of 41.4% interest transfer from ExxonMobil to Pertamina, now 90.8% in partnership with the local govt (9.2%).  

ExxonMobil has tranfered its interest in Jambaran Tiung Biru to Pertamina (->90,8%, Local gvt. 9,2%).

On 1 July 2020, Eni announced to have successfully drilled Bashrush 2bis, its exploration wildcat in the North El Hammad Offshore block, Nile Delta Basin. The well encountered a single 152-meter thick gas column within the Messinian sandstones of the Abu Madi Formation at an estimated depth of 3,000 m. The company, which reported excellent petrophysical properties for the reservoir will conduct production testing soon. Bashrush 2bis is a sidetrack of the new field wildcat Bashrush 2 suspended by the Eni in early April 2020 after 3 months of operations. It was spudded in 20 m of water depth, 11 km from the coast, 12 km northwest from the Nooros field and about 1 km west of the Baltim Southwest field. In collaboration with partners BP and Total and in coordination with the Egyptian authorities, Eni also announced that it will review the development options of this new discovery with the aim of “fast tracking” production by using the existing infrastructures in the area. The North El Hammad Offshore block was awarded to Eni with 37.5% interest through its Egyptian subsidiary IEOC in October 2015. Partners BP and Total hold 37.5% and 25%, respectively. The acreage which covers an area of 1,925 sq km includes 3 other exploration wildcats. Baltim Mare 1 and Baltim West 1, drilled respectively in 1968 and 2007, reported as dry. The last well, Bashrush 1, was suspended by IEOC in December 2019 without further disclosed information, after few days of operations.

Bashrush-2bis nfw 1st well in North El Hammad block (7), WD 22m, Nile Delta west of the Abu Madi West + Baltim-Baltim South devt areas (Greater Nooros area), 152m gas column in the target Abu Madi fm, testing planned and probably fast-track devt. Eni (op), partners BP + Total.

DNO ASA confirmed on 26 November 2018 that it has announced the terms of an offer to be made for the whole of the issued and to be issued share capital of Faroe Petroleum Plc. The offer stands at 152 pence in cash per Faroe share which values Faroe’s existing share capital at approximately GBP 608 million (USD 781 million). Faroe responded to the announcement by DNO stating that DNO did not engage with Faroe before making the announcement of its unilateral offer. Further announcements will follow once the Board of Faroe has met with its advisers. DNO already holds 28.22% of Faroe Petroleum’s issued share capital.

Norway, not found

Coro's 2018 conditional agreements to acquire a 42.5% stake from AWE in the Bulu PSC off East Java is in limbo. The 2 Dec '19 deadline for govt acceptance has passed without news, and a 6-month 'force majeure' extn is now sought to complete the USD 10.96 MM deal (+ re-imbursements of USD 1.04 MM debt). The 698-sq km block contains the Lengo gasfield, for which an FDP has already been approved by the authorities. Partners yet-to-be KrisEnergy (op), Coro, Satria Energindo + Satria Wijaya Kusuma. KrisEnergy is seeking to dilute its 42.5% stake.

Indonesia (South Sumatra B.) Bulu

On 18 December 2017 Ping Petroleum completed its acquisition of an 80% interest in licence P2157 from Summit E&P. Ping now holds 100% interest in the licence. In 2017 Summit drilled exploration well 15/16d-27 targeting the Ranger prospect. However, operations were unsuccessful and the well was plugged and abandoned as a dry hole. Ranger was a Tertiary Balmoral target comprised of Ranger Main, East, Southeast and South. It sat above a major Basement horst with the depositional setting believed to be part of a delta slope environment. STOIIP for the prospect was in the region of 314 MMbo. The licence was awarded to Summit in December 2014 as a part of the 28th Seaward Licensing Round. Block 15/16d lies between the Piper and Tartan fields and the Lowlander discovery in the Moray Firth Province. Following completion of the deal interest in the licence is held solely by Ping Petroleum UK Limited.

Ping Petroleum completed its acquisition of an 80% interest in licence P2157 from Summit E&P.

The Ministry of Economic Affairs and Climate announced in early January 2019 that an application was made for the G16c & M1b exploration licence. ONE-Dyas was revealed as the applicant after no competing bids were received. On 9 March 2020 the Dutch Ministry announced that the licence had been granted, effective from 6 March 2020. The G16c block has an area of 176 sq km and the M1b licence has an area of 193 sq km. A total of four exploration wells have been drilled between 1985 and 1996 in the area covered by the application. Three wells were in the G16c block and one was drilled in M1b block. All of the wells were dry holes. In the adjacent block to the south of M1b is the M1a production licence which contains the M1-A gas field. It was discovered in 1993 with the M1-2 well. Its reservoir is below 3,918 m in Scythian Lower Volpriehausen Sandstone Member. The discovery was successfully appraised with the M1-3 well in 1998 and the decision to develop the field was taken in 2006. The G16a block, adjacent to the north of G16c, contains for producing fields: G16a-A, G16a-B, G16a-C and G16a-D. The fields were discovered between 1985 and 2012 and the reservoirs are in reservoirs between a depth of 2,460 m and 3,010 m. The licence is held by ONE-Dyas BV (60% + operator) and Energie Beheer Nederland BV (40%).

Explo rights were granted to ONE-Dyas op. (EBN) over licence G16c & M1b

Husky is looking to farmout block DW 1 in the South China Sea. The 7,705-sq km PSCA area lies in WD 400-2,500m in the Tainan Basin. Husky has a single well commitment under phase 3 by 2022. Contact: [email protected].

Taiwan, not found

Europa announces the conditional acquisition of FEL 3/19, Erris Basin off NW Ireland, from DNO. The 956-sq km permit contains the 1.2 Tcf Edge prospect, adding onto Europa's other regional assets. It is being acquired for a nominal upfront fee and the granting of a 5% net profits interest over future production to DNO. The deal is pending authority approval.

(Northwest Ireland Offshore B.), FEL03/19 Europa announces the conditional acquisition of FEL03/19, off NW Ireland, from DNO. The 956-sq km permit contains the 1.2 Tcf Edge prospect, adding onto Europa's other regional assets.

Medco Energi has completed its wildcat Nowera 1 in the South Sumatra PSC EXT, located in the South Sumatra Basin, around end-April 2018. The well was drilled to a TD of 1,478 m MD (4,850 feet), with bottom hole in the Basement, and it has been suspended as a gas discovery after testing. The company also reported in June 2018 that it continued land clearance in preparation to spud its next well, Flamboyan 1. Total cost for the Nowera 1 operation is approximately USD 4.35 million. As of end-March 2018, the company reported to have carried out well testing operations at Nowera 1. Nowera 1 was spudded on 10 February 2018, using the “Dreco 750 Hp” land rig. Drilled depth was approximately 556 m (1,826 feet), as of end-February 2018. Nowera 1 is the second of a three-well exploration drilling campaign in the block. In late December 2017, Medco plugged and abandoned wildcat Cempaka 1 as a dry hole. The well was spudded on 20 November 2017, using a Medco-owned land rig, and had a PTD of approximately 304 m (996 ft) MD/TVD. The targets for the wells could be the Lower Miocene Batu Raja carbonates which is the most prolific reservoir in the Musi platform area. Secondary targets could be the fractured Basement and the Upper Oligocene-Lower Miocene Talang Akar Formation. The final drilling cost for Cempaka 1 was reported at approximately USD 2.6 million. Cempaka 1 was the first of a three-well drilling campaign in the block. After the completion of Cempaka 1, the operator began well site construction for Nowera 1, while land clearance was ongoing for the final well (Flamboyan 1). Preparations for the campaign, including land clearance, licensing and environmental studies, were first reported in late January 2017. Medco was also planning to acquire 330 km of 2D seismic data in the block, in Q1 2017, however the plan was postponed to Q4 2018. The company has received SKK Migas approval for the survey. The previous exploration activity in the block was a 3D seismic survey covering 110 sq km in the Temelat area, completed in April 2015. Medco is operator and sole interest holder in the South Sumatra PSC Extension which received a 20-year extension on 28 October 2010. Background Information Medco was previously planning to drill appraisal well Rambutan Deep 2 in 2015, but the plan likely did not push through. According to operator’s report in late July 2014, the purpose of the well was to explore gas play in the deeper reservoir of Rambutan field, which has estimated unrisked resources of 277 Bcfg. Rambutan Deep 2 was planned to be drilled to a TD of 3,000 m, targeting Upper Oligocene to Lower Miocene Talang Akar Formation. Medco spudded Lagan Deep 1A on 22 August 2013, with a PTD of 3,444 m, primarily targeting the Upper Oligocene to Lower Miocene Talang Akar Formation. The well was temporarily shut-in for future testing in February 2014. The company reported that total drilling cost for Lagan Deep 1A until end of June 2014 was USD 27,661,111. In late September 2011, the operator conducted preparations to kill the Lagan Deep 1 deeper pool wildcat in the South and Central Sumatra PSC, as there was unintended gas and fluid flow to the surface within the vicinity of the well. The unintended flow started on 13 September 2011 (2300H) after the well reached a depth of 816 m. Loss circulation material has been pumped but well has continued to flow. There were no fatalities, injuries, facilities damage and fire related to this incident. Safety measures have been performed and will continue to be conducted until well has been controlled. The Test was also conducted on the gas and fluid flowing and were deemed non-toxic., drill site location is about 2 km away from the nearest communities. Lagan Deep 1 was spudded on 7 September 2011 using the “Antareja-8” rig. The well lies in the Kebur I sub-block and is located 13 km south of Rambutan Deep 1. It has a PTVD of 3,505m and it will primarily target gas bearing sandstones of the Upper Oligocene to Lower Miocene Talang Akar Formation. Possibly secondary targets were the Lower to Middle Miocene Gumai sandstones and Lower Miocene Batu Raja carbonates. Drilling was expected to take 75 days and in the event of a success, the well will be put onstream via existing facilities in the area and gas will be delivered to the nearby Rambutan station. The main Lagan field was discovered in 1941 by Stanvac. It has gas with condensate reservoirs in the sandstones of the Middle to Upper Miocene Air Benakat Formation, at depths of around 600 to 1,200m. Estimated 2P recoverable reserves for the field were around 285 Bcfg plus 5.5 MMbc. Production commenced in 1986 and the field has produced more than 100 Bcfg and 2 MMbc.

Nowera 1 (Dart Egy 50% op, PT Medco 50%) in South Sumatra PSC EXT drilled to a TD=1478m MD, with bottom hole in the Basement, and it has been suspended as a gas discovery after testing.

By H2 2019, Sonatrach had concluded drilling operations in its El Hafair 1 (EHF 1) NFW, located on the under-explored Taghit exploration licence in the Bechar Basin. Results are not available. EHF 1 was spudded on 10 February 2019, with operations carried out utilising the ENTP #228 rig. The well had a PTD of 3,050m and was targeting gas in the Visean, in a prospect lying 19km west of the 1960 Meharez 1 (MR 1) gas discovery. The well was the first to be spudded on the block since the June 2018 Bouibet Rahil 1 (BIR 1) oil discovery, made in the far NE of the 19,015 sq km licence. Sonatrach operates Taghit with 100% equity.<P />

Sonatrach had concluded drilling operations in its El Hafair 1 (EHF 1) NFW, located on the under-explored Taghit exploration licence in the Bechar Basin. Results are not available.

Africa Oil Corp has entered into a strategic partnership with Eco (Atlantic) Oil and Gas for exploration in West Africa and Guyana. Under the terms of an investment agreement, AOC has agreed to acquire a 19.77% shareholding in ECO through the purchase, by way of private placement, of 29.2 million common shares at CAD$0.48 per share for a total consideration of CAD$14.0 million (approx. US$10.9 million). The Investment Agreement also provides the Company with the right to participate in any future ECO equity issuances, on a pro rata basis, and to appoint one nominee to ECO's board of directors. Keith Hill, President and CEO of AOC, will join the ECO board of directors as soon as practicable. As part of the Investment Agreement, the parties have also entered into a Strategic Alliance Agreement (the 'SAA'), whereby they will jointly pursue new exploration projects. Pursuant to the terms of the SAA, AOC will be entitled to bid jointly on any new assets or ventures proposed to be acquired by ECO, on the same terms as ECO and for an interest at least equal to the Company's percentage holding of the common shares in ECO from time to time. Additionally, under the terms of the SAA, AOC will also have a right of first offer on the farmout of exploration properties currently held by ECO. ECO has been able to assemble an extensive exploration portfolio in two countries that are at the forefront of exploration, including four blocks in Namibia and one block in Guyana. The Namibia blocks are located in an area of proven source rocks and large, seismically-defined stratigraphic traps where upcoming wells by neighboring operators will be drilled in the near future to derisk the play. In Guyana, ECO holds a block directly updip from the Stabroek block on which Exxon estimates resources of 2.5 billion to 2.8 billion oil-equivalent barrels, including the supergiant Liza field. The ECO block exhibits good evidence of slope fan prospects and is expected to be fully delineated after processing and interpretation of the 2,550km2 3D seismic survey recently completed in September. ECO also recently announced it has entered into an option agreement for a farmin by TOTAL on this Guyana acreage. This new investment is a good complement to the Company's existing investment in Africa Energy Corp in which the Company holds a 28.5% shareholding interest. AFE holds blocks in Namibia adjacent to the ECO acreage and a block offshore South Africa. Together, the two companies represent significant holdings in several of the most attractive exploration areas in the world. Africa Oil CEO Keith Hill commented: 'We are very excited to be joining this talented group of explorers who have been able to secure top quality blocks in prime exploration areas. We look forward to realizing the value of this acreage and believe we will be able to play a positive role in the expansion of their portfolio. The pace of exploration is increasing in these regions with large indepedents and even super-majors taking big acreage positions with aggressive drilling plans over the next few years. This alliance will help us take advantage of this upswing in activity.' PillarFour Securities is acting as financial advisor to Africa Oil in connection with the transaction. Click here for Eco (Atlantic) announcement: CAD $14m subscription by Africa Oil Corp Strategic Alliance Agreement on Current and New Ventures Original article link Source: Africa Oil Corp

Guyana (Guyana B.) Liza

Sinopec completed a mini fracture stimulation programme and test operations over the Permian Longtan Formation Shale at Dawan 4 in mid-April 2020. The testing operation was carried out between 5,840-5,886.1m and resulted in gas flame of 0.3m in height. The objectives of the testing operations were to test the commerciality of the shale gas in the deeper Permian Longtan Formation and refine techniques for further development of production testing in the deep shale gas intervals. Dawan 4 was drilled to a TD of 6,241m MD (TVD 5,997m) in the Silurian Hanjiadian Formation on 24 July 2019 and was suspended for testing in early August 2019. Wireline logging data confirmed that Dawan 4 encountered gas reservoirs in the Feixianguan, Changxing, Longtan and Maokou formations. Gas exploration well, Dawan 4, was spudded on 10 November 2018 to drill to a PTD of 6,218m (PTVD 6,040m) and was targeting the Changxing and Feixianguan formations with the objective of exploring the gas potential of the Dawan Structure to expand the Puguang gas field. Dawan 4 is in the Sinopec operated Daxian-Xuanhan Block in the Sichuan Basin and is geographically located within Sichuan Province, Xuanhan County, Maoba Town Luwang Village.<P /><P />

China (Sichuan B.) ? op. by SINOPEC (100%) in Daxian-Xuanhan block Sinopec completed a mini fracture stimulation programme and test operations over the Permian Longtan Formation Shale at Dawan 4 in mid-April 2020. The testing operation was carried out between 5,840-5,886.1m and resulted in gas flame of 0.3m in height.

IGas subsidiary Island Gas Limited and Egdon Resources have acquired a 3.67% interest and 1.33% interest respectively in licence PEDL 070 from Brigantes Energy. The licence contains one block – SU/52a which hosts the Avington field. The deal completed in early May 2018. The Avington field is a composite structure comprising a northern footwall fault block and a southern hanging wall inversion anticline, covering 23 sq km. The Middle Jurassic Great Oolite reservoir is mapped juxtaposed across the fault separating the two structural elements of the field. The field was discovered in 1987 and was brought onstream in 2009. The field is expected to produce until 2022. Interest in the licence is now held by IGas subsidiary Island Gas Limited (53.67% + operator), Egdon Resources U.K. Limited (28%), Aurora Production (U.K.) Limited (8.33%), Corfe Energy Limited (5%) and UKOG (GB) Limited (5%).

United Kingdom, PEDL 070

Petro-Victory Energy has announced the discovery of oil at the 1-VID-1-ES (Vida) exploration well located in Block ES-T-487 Espírito Santo Basin, Brazil. This is the company’s first exploration well in Brazil. The Vida exploration well was drilled to a Total Depth of 1,890 meters in the onshore portion of the Espírito Santo Basin, Brazil. Evaluation of logging, pressure, and fluid data confirms that Vida comprises of high-quality oil-bearing Cretaceous sandstone reservoirs. The well encountered 49 meters of net oil pay, exceeding Petro-Victory’s pre-drill forecast of 855,000 barrels of mean recoverable resource. Oil was successfully recovered to surface during fluid sampling from a sandstone reservoir at 1,600m and preliminary observations of the oil sample show similar qualities to a nearby oil field (24 API, low BSW). Oil pay was encountered across the Vida well, with the majority of oil pay occurring between 1560-1660m. The Company will now suspend the well, evaluate the data from the Vida oil discovery, update the recoverable oil resource, determine an appropriate testing program, and source a workover rig to conduct a detailed testing program and put the Vida well on production in Q3. Upon completion, the Company projects ongoing OPEX to be in the US$10-12 per BO range, generating positive cash flow and profitable netbacks in the current price environment. This oil discovery significantly de-risks other Cretaceous age prospects on the ES-T-487 license and the Company’s other nearby licenses, ES-T-477, ES-T-373, ES-T-354, including our next well, the Sintonia prospect located on ES-T-441. Richard F. Gonzalez, Chief Executive Officer of Petro-Victory commented: 'I would like to thank our operating partner, Imetame Energia, for their hard work and dedication in drilling the Vida well during these turbulent times. Making a significant oil discovery in our first Brazil exploration well is an excellent result for our shareholders. We will now work steadfastly to bring our Vida well online while preparation commences for the drilling of our second exploratory well, Sintonia.' Original article link Source: Petro-Victory Energy

Brazil, not found

S-C part of Uirapuru_P4 contract, BLC_Uirapr block not far from Equinor's Bacalhau field, Santos Basin, WD 1,995m, TD 5,033m, oil shows report to ANP on 1 Apr '20, ops terminated 15 Apr '20, West Tellus DS. Targets Barra Velha + Itapema fm's. Petrobras (op), partners Equinor, ExxonMobil + Petrogal.

Brazil (Santos B.) 1-SPS-107B-SPS op. by PETROBRAS (30%), EXXONMOBIL (28%), EQUINOR (28%), GALP (10%), SINOPEC (4%) in BLC_Uirapr block, WD = 1994 m, S-C part of Uirapuru_P4 contract, BLC_Uirapr block not far from Equinor's Bacalhau field, Santos Basin, WD 1,995m, TD 5,033m, oil shows report to ANP on 1 Apr '20, ops terminated 15 Apr '20, West Tellus DS. Targets Barra Velha + Itapema fm's.

Römerberg-Speyer block near Speyer in Rheinland-Pfalz, Upper Rhine Graben, multilateral well from Römerberg-7 (2014), TD 3,607m, compl oil (Buntsandstein) in Aug '19. Neptune (op), partner Palatina GeoCon.

Römerberg-7M1 npw (Neptune (op), partner Palatina GeoCon) Römerberg-Speyer block near Speyer in Rheinland-Pfalz, Upper Rhine Graben, multilateral well from Römerberg-7 (2014), TD 3,607m, compl oil (Buntsandstein)

A partner is sought by year-end to take on operatorship of the so far wholly-owned, 22,812-sq km Mazenga block on the Nhachengue-Domo High (Mozambique Basin) in S. Mozambique:

A partner is sought by year-end to take on operatorship of the so far wholly-owned, 22,812-sq km Mazenga block on the Nhachengue-Domo High (Mozambique Basin) in S. Mozambique

The “Leiv Eiriksson” S/S has been used by Lundin to drill an appraisal well at Alta with a 720 m horizontal section through the Permo-Carboniferous Falk and Orn formation (Gippsdalen Group) reservoir (32 m below the GOC and 12 m above the assumed OWC). 7220/11-5 S is located in PL 609 approximately 1.5 km west of 7220/11-3 and 3 km southwest of 7220/11-4 and was spudded on 6 April 2018. TD is 3,057 m (1,912 m TVDSS) in the Orn Formation and well results are better than expected with excellent reservoir quality, productivity and connectivity. A completion string was run and a two-month extended well test was carried out to monitor reservoir performance, with pressure gauges having already been installed in 7220/11-4 so that the pressure communication across the field could be observed during the testing. Over the two month period two tests were performed. A 30 day test flowed at a constrained rate of 7,500 bo/d through a 60/64” choke and a 25 day test flowed at rates of up to 18,000 bo/d through a 118/64” choke. In total 675,000 bo was produced and shipped, using the “Teekay Scott Spirit” tanker, to Mongstad. As a result of the well reserves are expected to be upgraded, with the update due to be published in early 2019. If development of Alta goes ahead Lundin is likely to use subsea wells tied-back to an FPSO. On 25 September 2018 the well was being abandoned. Alta was discovered in 2014 by exploration well 7220/11-1. The objective was a composite section of Triassic Kobbe Formation sandstones and Permo-Carboniferous weathered carbonates, sandstones and intrusives in a four-way dip closed structure. A 46 m oil column with an 11 m gas cap was proven in good quality carbonates of the Gipsdalen Group. Two tests were performed in the oil zone and flowed at a maximum rate of 3,260 bo/d plus 1.7 MMcfg/d through a 36/64” choke. Recoverable reserves were estimated at 125-400 MMboe (85-310 MMb of this being oil) at the time of discovery. However, an update in January 2018 led to a downgrading of reserves for the combined Alta and Gohta project to 115-390 MMboe (at discovery Gohta was estimated to contain reserves of 91-184 MMboe). Two successful appraisal wells and two sidetracks were drilled at Alta in 2015, all confirming communication with the discovery well. The sidetrack of the second appraisal well, 7220/11-3 A, was re-entered in 2016 and was deepened and tested at a rate of 21 MMcfg/d through a 64/64” choke. Additionally, seawater was injected into the carbonate Falk and Orn Formations at rates of 5,000 b/d and 18,200 b/d respectively. Appraisal well 7220/11-4 was drilled in 2017 and encountered a 4 m gas column and a 44 m oil column in Permo-Triassic clastic carbonates. Good communication with the previous Alta wells was confirmed from pressure data, with the same fluid contacts and gradients. The well was tested and flowed at a constrained rate of 6,050 bo/d through a 56/64” choke, indicating very good reservoir quality and lateral continuity through the reservoir. Sidetrack 7220/11-4 A deviated 900 m to the north and proved a 10 m gas column and a 44 m oil column in the Orn Formation with the same hydrocarbon contacts. The sidetrack was intended to help as a calibration point for 7220/11-5 S. Interest in PL 609 is divided between Lundin Norway AS (40% + operator), DEA Norge AS (30%) and Idemitsu Petroleum Norge (30%).

7220/11-05 S (Alta) pos. appr. (Lundin op, 40%, Idemitsu 30%, DEA 30%) in PL 609, was drilled 700m horizontally in the oil zone, encountering all targeted reservoir intervals (Late Permian - Early Triassic Kobbe conglomerates and Ørn carbonates), before an extended production test was carried out. The well flowed at a constrained rate of about 7500 bo/d for 30 days [60/64” choke], and then flowed at a maximum rate of up to 18000 bo/d for 25 days (118/64” choke - constrained by surface facilities).

The Chadian Ministry of Petroleum and Energy is promoting the country’s open acreage which is available to companies for direct negotiations. As of December 2019, the free blocks were: CHAD Open Acreage Basin Names Block Name Block Sqkm Main Political Province Borkou-Ennedi Sub-basin (Al Kufra Basin)~Djado Basin~Tibesti Massif~Chad Basin Djado Block II 13,848 Tibesti Borkou-Ennedi Sub-basin (Al Kufra Basin)~Faya Sub-basin (Chad Basin) Largeau Block I 11,706 Borkou Chad Basin Moussoro Block 11,927 Kanem Chad Basin Lac Chad Block 11,900 Kanem Chad Basin Lac Chad Block I 3,783 Kanem Chad Basin~Bodele Sub-basin (Chad Basin) Siltou Block II 17,800 Borkou Chad Basin~Bodele Sub-basin (Chad Basin) Siltou Block I 11,803 Tibesti Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Manga Block 16,759 Tibesti Chad Basin~Bornu Trough - Chad Basin~Termit Trough - Chad Basin LC-2008 10,988 Hadjer-Lamis Chad Basin~Darfur - Ouaddai Massifs~Bongor Trough MD-2008 11,725 Ville de Ndjamena Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block IV 17,709 Borkou Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block VII 11,815 Batha Chad Basin~Faya Sub-basin (Chad Basin) Largeau Block III 10,623 Borkou Darfur - Ouaddai Massifs~Doba Trough~Bongor Trough Chari-Ouest Block III 4,681 Tandjile Darfur - Ouaddai Massifs~Doseo Trough~Doba Trough~Salamat Basin BDS-2008 41,887 Mayo-Kebbi Est Djado Basin~Tibesti Massif Djado Block I 21,569 Tibesti Doba Trough~Darfur - Ouaddai Massifs WD 1-2008 2,029 Mayo-Kebbi Ouest Faya Sub-basin (Chad Basin)~Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Largeau Block VI 11,770 Ennedi-Ouest Faya Sub-basin (Chad Basin)~Chad Basin~Borkou-Ennedi Sub-basin (Al Kufra Basin) Largeau Block II 11,739 Borkou Source: IHS Markit © 2019 IHS Markit   The latest version of the Hydrocarbon Law in Chad was translated into English in August 2008. On 27 August 2007, Chad's Prime Minister M. Nouradine Delwa Kassiré Comakye announced that the country had promulgated legal texts and implemented mechanisms relating to the specific management of its oil incomes in order to adhere to the Extractive Industries Transparency Initiative (EITI). The Government solemnly declared that the principles of this initiative from that moment on would be applied to Chad and the incomes drawn from the extractive industries would be declared and used in total transparency. The Al Kufra Basin is better known as Erdis Basin in Chad. The south extension in Niger and Chad of the Murzuq Basin is called Djado Basin (or Jadu Basin) and has seen no hydrocarbon exploration in the past. The Faya-Largeau area is poorly explored, with only a few low-quality seismic lines acquired in the 1980s. The Lake Chad area was one of the first regions to be explored in Chad, but unlike the Doba Trough, it has not been intensively explored. Three discoveries have been made: Kanem-1 in 1974, Sedigi in 1975 and Kumia-1 in 1976.

Chad, Sedigi (Dev)

Deepwater Tano / Cape Three Points block, deepwater Tano-Côte d’Ivoire Basin, WD ca. 2,700m, oil encountered and reportedly preparing to sidetrack before moving on to Pecan SE. Aker intends to file the FDP with the authorities by end March and has an option on the Dhirubai I vessel as a possible FPSO. Aker Energy (op), partners Lukoil, FuelTrade + GNPC.

(Cote d'Ivoire B.) Cape Three Points

L8 (L 08), Canning Basin, target L. Laurel Shale, P&A'ing o&g shows at TD 3,008m, reservoir tight, NGD rig 405. It is recalled the 326-sq km block is open for farmin, contact: [email protected].

Miani 1 expl. (Buru Energy) in L 08 block, TD=3006 m in the Frasnian Clastics section. Elevated mud gas readings and oil shows were observed in a section of dolomitised limestone between 2970 and 2990m. P&A oil shows.

The Sitra Petroleum Company (Sipetco) has made an oil & gas discovery in its Sitra C 30 1 NFW, located on the Sitra PSC in the Abu Gharadig Basin. The well tested 687 bo/d and 10.3 MMcfg/d from the Cretaceous Bahariya & Kharita formations. It has now been brought onstream. The discovery lies ~3km SE and on trend with, the Sitra 3 1 Field. Sitra C 30 1 reached 3,020m TD in Q3 2019, with operations being carried out by the Egyptian Drilling Company #51 rig. It is the second discovery made on the Sitra concession in 2019, following the Q2 2019 Sitra C18 1 ST oil discovery, also made in the Bahariya. Sipetco is a 50/50 JV between Shell and EGPC.

The Sitra Petroleum Company (Sipetco) has made an oil & gas discovery in its Sitra C 30 1 NFW, located on the Sitra PSC in the Abu Gharadig Basin. The well tested 687 bo/d and 10.3 MMcfg/d from the Cretaceous Bahariya & Kharita formations.