Datasets:

nathanlsl

/

news

like 0

Talon Petroleum is searching for farm-in partners to fund a well to drill the Rocket prospect in licence P2392 (blocks 28/8b & 28/9b) in return for significant equity. The prospect is located in the Central Graben near the Catcher Area where Palaeocene aged Cromarty Sandstone reservoirs are trapped stratigraphically to form the AVO anomaly supported Rocket prospect. Encounter estimate Rocket to hold most likely STOIIP of 68 MMbo with an upside of 150 MMbo. The well cost is estimated at GBP 7 million. Talon acquired the previous licence holder Encounter Oil on 15 May 2019 and announced that it had received strong interest from potential partners and is confident in securing partners in the near term. As of 21 July 2020 the opportunity was confirmed to be still available and it recently signed a confidentiality agreement with new parties to commence a data room technical review. Talon did not disclose which of its two farm-in opportunities were being reviewed. The Cromarty B1 Sands are expected to be present at the Rocket prospect with the sands having similar characteristics to the Bonneville field 4 km to the east of the prospect. Encounter estimate net to gross to be within the region of 90 metres, porosities of 32% and the sands are interpreted to be ponded in the hanging wall of the N-S fault system. A salt high in the north and east creates a drape structure providing dip closure. In the west and south dip closure is formed from a combination of an upthrown closure and a stratigraphic pinch-out at the base of the depositional slope. The crest of the structure lies at 3,050 feet with a maximum closing contour of 3,400 feet. The API is estimated to range between 24° and 31° with GOR’s of 200-300 scf/stb. The licence was awarded on 1 October 2018 in the 30th Seaward Licensing Round. Interest in P2363 is held solely by Talon Petroleum Ltd (100% + operator). For further information please contact: Matt Worner 0061 429 522 924 [email protected]

(Central Graben Province) P2392 op. by TALON (100%), Talon Petroleum is searching for farm-in partners to fund a well to drill the Rocket prospect in licence P2392 (blocks 28/8b & 28/9b) in return for significant equity. The prospect is located in the Central Graben near the Catcher Area where Palaeocene aged Cromarty Sandstone reservoirs are trapped stratigraphically to form the AVO anomaly supported Rocket prospect. Encounter estimate Rocket to hold most likely STOIIP of 68 MMbo with an upside of 150 MMbo. The well cost is estimated at GBP 7 million.

CNOOC announced on 8 December 2017 to confirm a medium-size gas field discovery, BZ 19-6, in Bohai offshore, Bohai Gulf Basin. BZ 19-6-1, discovery well, completed in April 2017 and has a TD of 4,180 m. During drilling the well penetrated 25 m oil pay and 348 m gas pay in the pre-Tertiary buried hill reservoir. The following appraisal well, BZ 19-6-2 and BZ 19-6-3, achieved average testing rate of 1,000 b/d of oil and 6.4 MMcf/d of gas. BZ 19-6 field discovery demonstrates the good prospects of buried hills for future gas exploration in this area of Bohai offshore. Currently most fields in the Bohai area have reservoir in the Tertiary, few fields has reservoir in buried hill, and also no significant gas field has been found in Bohai offshore. Bozhong 19-6-1 (BZ 19-6-1), a new-field wildcat, is drilled in the Bozhong Depression in 20 m of water. The well is located in the east of BZ 19-4 field and drilling target is mainly at the Upper Tertiary Minghuazhen and Guantao formations. “Bohai 4” J/U is used for drilling operation.   BZ 19-6-1 was spudded in December 2016 and completed in April 2017. It was reported as discovery well in the company 2017 mid-year review in August 2017.    Background information The BZ 19-4 fields is comprised of three fault blocks, BZ 19-4, BZ 19-4N and BZ 19-4S. The discovery of the field actually can be traced back to 2003 when BZ 19-4-1 tested oil flow from the Dongying Formation of the Lower Tertiary. In 2005, BZ 19-4N-1, north of the BZ 19-4-1, tested oil from the Guantao and Minghuazhen formations of the Upper Tertiary, the following appraisal well BZ 19-4N-2D confirmed the reservoir. Again in 2005, BZ 19-4S-1, south of the BZ 19-4-1, tested oil from the Guantao and Minghuazhen formations as well. The field overall holds about 300 MMbbl of oil in place. BZ 19-4 block was first put on stream in 2010 and followed by BZ 19-4N and BZ 19-4S. The whole field produced at a rate of 8,000 b/d of oil. BZ 19-4 is jointly developed by CNOOC US supermajor Chevron. Operator CNOOC holds 83.8% interest, while Chevron holds the remaining 16.2% interest.  

China (Bohai Gulf B.) ? op. by CNOOC TJ (100.0%) in Bozhong block

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

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

Highlights   Ivory prospect estimated to contain 420 million barrels of mean recoverable oil over 2 levels Total of over 1.5 billion barrels of recoverable prospective resource identified in the permit to date Carnarvon uniquely positioned to draw on proprietary data from the successful Roc and Phoenix discoveries on trend in the neighbouring permits   Carnarvon Petroleum has provided an update on the prospective resources in the Labyrinth project (WA-521-P exploration permit) based on the completion of detailed petrophysical analysis leveraging the learnings from the successful Roc and Phoenix South wells in the adjacent permits.   The Labyrinth project is located in the Rowley Sub-basin, offshore Western Australian on the North West Shelf, north of Carnarvon’s Roc and Phoenix South hydrocarbon discoveries, with water depths between 200 and 500m (See map below).Labyrinth is located to the North West of the play opening Roc and Phoenix South discoveriesProspect and lead inventory for Labyrinth project Prospects- Multiple stratigraphic levels   Using knowledge gained from the hydrocarbon discoveries at Roc and Phoenix South extensive technical work has been recently completed in order to refine the understanding of the hydrocarbon potential of the Labyrinth project.  In particular, revised petrophysical analysis has resulted in updated prospective resource estimates of the most significant prospects and leads. (Refer to map above for the prospect and leads maps).   The total unrisked prospective resource of the eight most highly ranked prospects is over 1.5 billion barrels recoverable at the Pmean confidence level (Refer table below).  A number of other leads have also been identified.   The Ivory prospect in particular is the standout target within the Labyrinth project with significant oil prospectively over two levels with a total mean prospective resource of over 420 million barrels.    Play level risks have also been evaluated for these prospects and leads based on the current 2D seismic data with a resultant 1 in 5 chance of success for the shallower prospects.  3D seismic, expected to be acquired as part of the ongoing work program, will refine potential drilling locations and is also expected to enhance the chance of success of this play.   Carnarvon’s Managing Director, Mr Adrian Cook said:   'The results of the thorough technical work on this project has upgraded the prospective identified to date, making the Labyrinth project a very attractive asset in the Carnarvon portfolio.'Prospective resources of high-graded prospects in the Labyrinth project * Note the Labyrinth prospect has been renamed Ivory About the Labyrinth Project (WA-521-P Exploration Permit)   Carnarvon acquired the exploration permit in March 2016 by committing to undertake a work program that included the reprocessing of existing 2D seismic data and geological / geophysical studies. The permit is located in the Roebuck Basin in the North West Shelf of Western Australia and covers an area of approximately 5,000 km2.   Carnarvon holds the permit 100% and is the operator. Original article link Source: Carnarvon Petroleum

Australia, not found

Goshawk Energy Pty Ltd was awarded special prospecting authority permit SPA 31 AO, located in the Canning Basin, on 3 December 2018.  The permit has been awarded for a period of six months and will expire on 2 June 2019. The permit is valid for surface exploration and work commitments outlined during the six months include completing the Coastal Canning Survey. The SPA was applied for in October 2016, as STP-SPA-0072.  It is the fifth awarded to Goshawk in recent months with SPA 28 AO, SPA 29 AO, SPA 30 AO and SPA 32 AO awarded in early November 2018, covering a combined total area of 41,725 sq km, also within the Canning Basin. SPA 31 AO, which covers an area of 15,943 sq km, was awarded on 3 December 2018.  Goshawk Energy (Canning Basin) Pty Ltd holds 100% interest and operatorship of the permit.

Australia, SPA 32 AO

An oil and gas round will launch next year, with details to be provided at the Africa Oil & Power and the South Sudan Oil & Power conferences in October. Some 11 blocks were open as of mid-2019. More from GEPS.

An oil and gas round will launch next year, with details to be provided at the Africa Oil & Power and the South Sudan Oil & Power conferences in October. Some 11 blocks were open as of mid-2019.

Mubadala Petroleum plugged and abandoned the second well under the G01/48 exploration drilling campaign, Yothaka East 1, located in the Kra Sub-basin, Gulf of Thailand, on 5 December 2019, with minor oil. Located around 6 km southeast of Manora platform, the well was drilled to a total depth (TD) of 3,367 m within 6 days. The well encountered only thin sands (2-3 m) in the 600 series while there was no hydrocarbon show observed in the shallower 490 and 500 series. The three-well drilling campaign commenced with the drilling of the Inthanin-1 well using "Valaris 115" J/U (formerly Ensco 115) on 20 November 2019. Located 3.7 km south-southwest of the Manora platform, the well was targeting the 400, 500 and 600 series sands. The Inthanin 1 well reached its TD of 2,528 m within four days, prior to being plugged and abandoned on 27 November 2019, as a dry well. The third exploration well, Krissana 1, has been cancelled due to no shows in the shallower targets of 300, 400, 500 and 600 series sands. Priority is given to the prospects that are low cost to drill, quick to be developed, reachable from the existing platform and able to extend field life for several years. Another high graded prospect within the North Kra block, namely Manora DEFVX, is planned to be drilled in 2020. The G01/48 concession is operated by Mubadala Petroleum with 60% interests through its subsidiary MP G1 (Thailand) Limited, partnered with Tap Oil (30%) and Northern Gulf Petroleum Pte Ltd (10%). Background Information The G01/48 concession was officially awarded to Occidental Exploration Pte Ltd (50%, operator) and partner Syarikat Borcos Shipping Sdn Bhd (50%) in December 2006. In 2007, Occidental was renamed to Northern Gulf Petroleum (NGP) Pte Ltd. Subsequently, Pearl Oil (later acquired by Mubadala Petroleum) acquired the entire 50% stake of Syarikat Borcos plus an additional 10% and operatorship from NGP. In October 2010, Tap Oil acquired an indirect 30% interest in the block via the acquisition of a 75% share of NGP. In 2012, Tap’s indirect interest was converted into direct interest through transfer to subsidiary Tap Energy (Thailand) Pty Ltd. NGP retained the remaining 10% direct interest. Tap Oil elected to retain its stakes in the block after the completion of a full asset review conducted in 1H 2015. From 2009 until 2017, six newfield-wildcats were drilled within the G01/48 concession, with three oil discoveries in Manora (2009), Malida 1 (2013) and Sri Trang 1 (2016). The Manora oil field was discovered via Manora 1 wildcat in December 2009. The discovery was appraised by six oil wells and one dry well. Hydrocarbon discovery from Malida 1 enhances exploration potential between the new discovery and Manora field. A net pay of 9.5 m oil-bleed sandstone reservoir in the primary target between 2,396 to 2,412 m. The last new-field wildcat in the G01/48 concession was drilled at the northern of the block, in late 2017. Ladawan-1 well was drilled to a total depth of 2,175 m TVDss, after having encountered an interpreted 3.3 m oil column at the 500 Sand Series. The well result is considered non-commercially viable and no well test has been carried out. In mid-2018, Manora 8 ST1 well had successfully appraised the oil zones along the Manora East bounding fault. Located 2.2 km southwest of the Manora A platform, the well encountered a total net oil pay of around 93 m (based on logs interpretation) from the primary objective of the 490-60 Series sands, as well as new pools in the secondary objectives, 300 and 500 Series sands, plus minor pay in the 400 Series sands. The well result has contributed additional volumes of 1.1 and 1.9 MMbbl to the 1P and 2P reserves within the Manora field, respectively.

Yothaka E. 1 expl, 2nd of 3 wells planned, SE of Manora platform in G01/48, Pattani Tough / Kra Sub-basin, TMD=3367m, sidetrack planned as Yothaka E-2. A thin oil pay was interpreted on logs in the 600 series sands, however the other 400 + 500 target sands were dry.

Rosneft is assumed to have plugged and abandoned dry the 1-RNB-004-AM (1-RNB-004-AM) new-field wildcat (NFW) in the BT-SOL-004A contract, SOL-T-191 block in the onshore Solimoes Basin during on 30 June 2019. The ANP has not reported any show reports filed for the well through mid-August 2019.   The NFW reached a final total depth (TD) of 2,090 m. The NFW was spudded on 14 May 2019.   The well has a proposed total depth (PTD) of 2,150 m with the Carboniferous Jurua Formation as the primary target and the Devonian Uere Formation as a possible secondary target. The outpost is located in the south-eastern area of the block approximately 19.2 km south south-east of the 1-MV-2-AM new-field wildcat plugged by Petrobras in August 1980. Rosneft has 100% working interest in the contract that expired on 16 February 2014. The PAD evaluation approval by the ANP was pending for two years and has a final expiry date of 19 January 2022.

1-RNB-004-AM nfw (Rosneft 100%) in SOL-T-191. onshore block, P&A assumed dry as no shows reports to ANP, TD=2090m. Target Jurua + possibly Uere fm’s.

Committed well in S. part of AE-0008-4M-Amoca-Yaxche-06 block, offshore Sureste Basin, WD 26m, P&A dry 21 Jul ’19, TD 3,690m, Cantarell I JU.

Mexico, not found

Pancontinental Oil & Gas NL is offering a farm-in opportunity for interest parties for exploration permit EP 447, located in the Perth Basin. The permit contains the Walyering gas field, which was discovered in 1971 and produced a total of 261 MMcf of gas from the Lower Jurassic Cattamarra Coal Measures over a four-month period before the reservoir was considered depleted and production ceased. Currently, UIL Energy holds 100% interest in the licence but initiated a farm-in agreement with Pancontinental’s subsidiary company Bombora Natural Energy Ltd in 2016. The agreement is for an area over the Walyering asset, with Bombora negotiating 70% interest and operatorship. The companies have extended the farm-in agreement negotiations to end 2018. Evaluation of Walyering is ongoing as part of the agreement, with a planned 3D seismic survey scheduled. Conventional sandstone reservoirs of Jurassic age, similar to the Gingin West and Red Gully gas and condensate trend, have been identified in the permit area over a structure area of approximately 10 sq km. It’s considered that original drilling failed to target the highs due to poorly positioned 2D seismic data and that there’s a 57% chance of success in the Central High. Additional 3D seismic data is required to provide better definition at the gas reservoir levels. Pancontinental, as part of the farm-in agreement, is planning to conduct the Walyering 3D seismic survey in late 2018.  The survey is planned to commence in November, covering 90 sq km. Pancontinental will fund the survey, up to a capped amount of AUD 2.5 million, to earn the 70% interest in the Walyering, southern section, of the EP 447 permit.  The survey is being scheduled to be undertaken in conjunction with other seismic plans in the Perth Basin. In May 2018 Pancontinental released upgraded gas and condensate volumes for the Walyering field to gross figures of 100 Bcf gas and 2.5 MMbbl condensate. In the case that new 3D seismic data supports the current mapping and size of the undrilled compartments, Pancontinental reports that it will consider an appraisal / development well in 2019. Pancontinental, through its subsidiary company Bombora Natural Energy, is offering a farm-in opportunity for the Walyering field area of EP 447. The offer is reliant on Pancontinental completing a farm-in deal with UIL which will establish permit interests as: Bombora Natural Energy Ltd (70% & operator) and UIL Energy (30%). Parties interested in this opportunity should contact - John Begg, Pancontinental CEO Phone: +61 8 636 7090 Email: [email protected]

Pancontinental Oil & Gas NL is offering a farm-in opportunity for interest parties for exploration permit EP 447, located in the Perth Basin.

On 20 July 2018, the Bureau of Land Management (BLM) issued a notice in the Federal Register calling for nominations and comments on available tracts within the National Petroleum Reserve-Alaska (NPR-A). The comment period runs until 20 August 2018. The 30-day notice allows interested parties to nominate or comment on available tracts with the area. The notice is the first step in the process leading to a potential 2016 oil & gas lease sale. Tract selection for the sale will be consistent with allocations and stipulations identified in the NPR-A 2013 Record of Decision for the Integrated Activity Plan, BLM said, with 11.8 million acres identified available for leasing in the IAP. The 895 tracts available for nomination and comment cover some 10.25 million acres. There are currently 196 active oil and gas leases, 1,452,686 acres, in NPR-A. ConocoPhillips has been the most active company in leasing over the last few years as it sought to expand its holdings following the recent Nanushuk trend oil discoveries made in the region. A sale date has yet to be announced but as in years past it will likely be held at the same time as the annual North Slope Areawide Lease Sales which usually falls in the October/December timeframe.

On 20 July 2018, the Bureau of Land Management (BLM) issued a notice in the Federal Register calling for nominations and comments on available tracts within the National Petroleum Reserve-Alaska (NPR-A). The comment period runs until 20 August 2018.

Alaminos Canyon block 728, OCS lease G31195, sidetrack of plugged back AC 728 2S0B0 appr, KOP 4,660m, cleared to P&A by the BOEM on 24 Mar ’18, Deepwater Pontus DS. Results + depths remain n/a.    

AC 728 002S1B0 (Whale) op. by Shell (60%, Chevron 40%) in OCS lease G31195, P&A, Results unreported.

Rabul discovery area in West Gharib block H, onshore Gulf of Suez, TD 1,563m, encountered 35m net heavy oil pay in the Yusr + Bakr fm's, to be completed as a producer in April at ab. 300 bo/d. SDX (op), partner EGPC. www.sdxenergy.com.

Rabul discovery area in West Gharib block H, onshore Gulf of Suez, TD 1,563m, encountered 35m net heavy oil pay in the Yusr + Bakr fm's, to be completed as a producer at ab. 300 bo/d. SDX (op), partner EGPC.

M-09, Moattama Basin, drilled + P&A results n/a late during March, TMD 2,240m, Noble Clyde Boudreaux SS off to Zawtika 21A, spudded early Apr ’19.

Myanmar, Zawtika

A result of the 2018 round opening today, NZP&M has now opened the nomination period for its planned block offer 2019, acreage limited to Taranaki onshore. Nominations are invited until 28 Jun ’19, whilst the offer 2019 should be announced in 2020. Contact [email protected].

A result of the 2018 round opening today, NZP&M has now opened the nomination period for its planned block offer 2019, acreage limited to Taranaki onshore. Nominations are invited until 28 Jun ’19, whilst the offer 2019 should be announced in 2020.

Tulip Oil confirmed on 30 October 2018 that it has been awarded an exploration licence covering blocks Q8, Q10b and Q11 effective from 29 September 2018. Tulip’s application was published in the Official Journal of the European Union on 8 October 2015. The 13-week period during which competing bid could be received ended on 7 January 2016. Q8 contains the abandoned Q8-A and Q8-B gas fields which were operated by Wintershall. Both fields have Permian Zechstein carbonate and Triassic Bunter Sandstone reservoirs. Q8-A was in production between 1986 and 2004 and Q8-B started production in 1994 and was abandoned in 2001. Q10b contains three wells – Q10-1 (dry, NAM), Q10-3 (gas shows, Mobil) and Q10-4 (dry, Amoco) drilled between 1962 and 1990. There are also three wells in Q11 - all dry holes. NAM drilled the first two (1969 and 1982) and Wintershall drilled the third (1992). Interest in the licence is divided between Tulip Oil Netherlands BV (operator) and Energie Beheer Nederland BV.

Netherlands, not found

Hugrijan ML, Assam Shelf (onshore), TD 2,741m, gas discovery during 3Q, tested 4.06 MMcf/d from a 13m intv at 2,357m in the Barail fm.

Lohali W.-1 Hugrijan ML, Assam Shelf (onshore), TD 2,741m, gas discovery during 3Q, tested 4.06 MMcf/d from a 13m intv at 2,357m in the Barail fm.

An auction is planned 28 Nov ’18 for the Obskoy Yuzhnyy block, 321 sq km in the Ob Estuary, Kara Sea (W. Siberia). Applications by 26 Oct ‘18. Starting price USD 2.31 MM. Contact: Rosnedra, [email protected].

Russia, not found

Ref. DEA 11 Jul ’19 (round launch), procedures for submission and verification of pre-qual docs have reportedly been published for the 14 blocks on offer*. The qualification process ends on 11 Oct ’19, bids will be accepted until the 3rd week of November, winners on 27 November. * Onshore: Cibao Basin (6 blocks), Enriquillo Basin (3 blocks), Azua Basin (1 block).  Offshore: San Pedro Basin (4 blocks). Official map below via www.bndh.gob.do/en.

procedures for submission and verification of pre-qual docs have reportedly been published for the 14 blocks on offer*. The qualification process ends on 11 Oct ’19, bids will be accepted until the 3rd week of November, winners on 27 November. * Onshore: Cibao Basin (6 blocks), Enriquillo Basin (3 blocks), Azua Basin (1 block). Offshore: San Pedro Basin (4 blocks).

Reports as of 5 November 2019, suggest that Equinor is looking at a potential farm in to Orange-Sub-basin Block 5/6/7 and Block 2C. The report indicated the Central Energy Fund (CEF) was in discussions with Equinor regarding the potential farm in (PetroSa is a subsidiary of the CEF). The Orange Sub-basin is attracting the attention of several large IOC's. Both Shell and Total are expected to drill within the Namibian portion of the basin in 2020 and have been securing additional acreage in South Africa. Block 5/6/7: covers some 73,000 sq km primarily atop the Orange Sub-basin in water ranging between 150 m and 4,000 m. Anadarko operates the tract with a 40% stake, Shell holds a 40% stake and PetroSA holds the remaining 20% stake. Its worth noting that Total will operate the block in accordance with the deal between Occidental and Total (See: Anadarko Petroleum Corp to be acquired by Occidental (Total will take Anadarko's African assets). Block 2C: covers some 6,223 sq km in water depth ranging in depths between 300 and 1,500 m. Soekor drilled two exploration wells in the area in 1979 and 1981, K-B 1 and K-E 1. Both were plugged and abandoned with gas shows. Anadarko had operated the tract with a 65% interest with PetroSA holding the remainder however, PetroSA is understood to be the sole applicant in the renewal.

Equinor looking to acquire interests in west offshore blocks 5/6/7 + 2C

Cuba's 1st offshore licensing round was launched in London on 3 Jun ‘19,  24 blocks (N9-18, N21-22, N25-29, N31-32, N43-44, N50) offered under PSC terms in Cuba’s EEZ in the Thrust & Fold Belt, Sigsbee Basin, Yucatan Platform, Central Basin, Foreland Basin + Florida-Bahamas Platform. Data packages available from BGP, data rooms available online. Although tangible devt’s are pending finalisation of a new legislation, a promotional meeting (after London on 3 June) is planned in Havana on 26 Nov ’19. Round registration by 10 Jan ’20, clarifications by 31 Jan ’20, qualifications + bid deadline by 29 May ’20, bid opening 29 Jun ’20, awards Sep ’20. Suitors so far rumoured CNPC, Eni + Premier.

Cuba's 1st offshore licensing round was launched in London on 3 Jun ‘19, 24 blocks (N9-18, N21-22, N25-29, N31-32, N43-44, N50) offered under PSC terms in Cuba’s EEZ in the Thrust & Fold Belt, Sigsbee Basin, Yucatan Platform, Central Basin, Foreland Basin + Florida-Bahamas Platform. Data packages available from BGP, data rooms available online. Although tangible devt’s are pending finalisation of a new legislation, a promotional meeting (after London on 3 June) is planned in Havana on 26 Nov ’19. Round registration by 10 Jan ’20, clarifications by 31 Jan ’20, qualifications + bid deadline by 29 May ’20, bid opening 29 Jun ’20, awards Sep ’20. Suitors so far rumoured CNPC, Eni + Premier.

Bounty Oil and Gas NL is seeking a farm-in partner in its 100% owned and operated AC/P32 exploration permit, located in the Vulcan Sub-basin, Bonaparte Basin.  The permit contains the Azalea Prospect, which has been successfully delineated and de-risked. Bounty hopes to drill Azalea 1 by 2019.  In mid-2018 Bounty reported that it had been in discussion with several possible interested parties. Bounty is looking for a partner to fund a one + one well programme in return for acquisition of interest in the permit. Bounty reports it will farm-out 50% interest, with operatorship available, in return for well funding of Azalea 1 and one appraisal well (upon success).  The Azalea Prospect was first mapped on the Onnia 3D seismic survey in 1997 and remapped on reprocessed data in 2010/11. The primary target lies in the Puffin Formation containing high porosity/permeability in deepwater sands, which forms the reservoir at a number of nearby fields in the basin, including the Puffin, Skua and Swift/Swallow fields. The source (with direct indications of hydrocarbon charge) and strike/up-dip seal are within the Plover Formation Bounty estimates Azalea to contain in-place Prospective Resources of 511 MMbo with recoverable resources of around 113 MMbo (at ~43° API).  The target reservoir lies at around 1,800 m depth and is thought to be in high quality sands, with 24% porosity and excellent permeability expected. The location lies up-dip from the Birch 1 well which produced oil and gas shows in 1990.  Drilling would be in water depths of approximately 100 m, suitable for a jack up rig to undertake operations. Bounty entered the well planning and approvals phase in June 2014 with the first exploration well initially due in the permit by 23 June 2016. Bounty altered the work commitment conditions of the permit in August 2015 by combining the first three years into one term (1-3), which must be completed by 23 June 2017.  A subsequent work commitments change was granted in July 2017, which sees the requirement for the well to be drilled extended to 2019.  The well is expected to cost around AUD 25 million and is likely to target the Azalea Prospect. After the initial new three-year work programme in AC/P32, permit terms four and five will follow with the work requirements to be completed on a year-by-year basis. Once a permit term has commenced, the work specified must be completed. The first exploration well (Azalea 1) has been scheduled to be drilled within the first term (years 1-3) at an estimated cost of AUD 25 million. The commitment to drill the well has already been entered into. The commitment to drill a second well (Azalea appraisal) in the permit in term five must be made prior to the commencement of that term, now on 24 June 2020. By combining the first term, the first well commitment was effectively suspended by 12 months allowing other structural and stratigraphic leads to be studied at multiple levels within the permit. Bounty has reported that the structural leads have a potential of between 10 and 40 MMbo of recoverable resources. AC/P32, which covers an area of 333 sq km, was awarded on 28 February 2001.  The permit was renewed for a further five year period on 24 June 2014 and after the subsequent work commitment changes will now expire on, or be eligible for renewal by, 23 June 2021. Bounty holds 100% interest and operatorship in AC/P32 and is seeking a farm-in partner to drill the Azalea Prospect. Companies interested in pursuing this opportunity should contact: Phillip F Kelso, CEO Phone: +61 2 9299 7200 Email: [email protected] Malcolm Lennox, Exploration Manager Phone: +61 439 777 743 Email: [email protected]

Bounty Oil and Gas NL is seeking a farm-in partner in its 100% owned and operated AC/P32 exploration permit, located in the Vulcan Sub-basin, Bonaparte Basin. The permit contains the Azalea Prospect, which has been successfully delineated and de-risked.

SK-320, off Central Luconia Sarawak, P&A results n/a around 25 Feb ’18, Hakuryu-5 JU now heading for Vung Tau Vietnam. The Middle Miocene Cycle IV carbonate target was apparently tested. Mubadala (op), partners Petronas + Shell. 

Buah Keras 1 op. by Mubadala (55%, Petronas 25%, Shell 20%) in SK-320 block, Mid. Miocene Cycle IV carb. target was apparently tested. P&A, results n/a.

Licensing authority is the Ministry of Petroleum.  Contracts are normally of concession type, but the Government of The Gambia is open to PSCs if so desired. Rights are normally granted for a six-year exploration period (+10 years) with the state having up to a 15% back-in right. Most of the terms and conditions under the Petroleum Act and Model Contract of 2004, amended in 2007, are negotiable. Licensing is to be through direct negotiations with the country's Petroleum Commission. Interested companies are invited to contact: Jerreh Barrow Commissioner for Petroleum Ministry of Petroleum & Energy Petroleum House Brusubi Roundabout Bijilo The Gambia Tel: +220 996 33 13 e-mail: [email protected]   The available blocks as of April 2018 are understood to be as listed below. Four blocks are available. There was no change in the list compared to the previous one. Total open acreage amounts to 14,119 sq km, of which 11,443 is onshore and 2,676 is offshore. There have been small adjustments to the areas of the onshore blocks.   Open blocks       Block Name Area (sq km) Situation Block Basin Block A3 1323 offshore Senegal (M.S.G.B.C.) Basin Block A6 1353 offshore Senegal (M.S.G.B.C.) Basin Lower River 6475 onshore Senegal (M.S.G.B.C.) Basin Upper River 4968 onshore Senegal (M.S.G.B.C.) Basin

Gambia, not found

On 9 March 2020, Petrobras reported it signed a sales agreement with Eagle Exploracao de Oleo e Gas Ltda for the Tucano Sul cluster of four producing gas fields in the onshore Tucano Basin that includes the Conceicao, Fazenda Matinha, Fazenda Santa Rosa, and Querera production concessions. The total consideration for the sale is USD 3.01 million which is to be paid in two installments, USD 602,000 on 9 March 2020 and USD 2.41 million on the official closing date of the transaction which is pending various governmental approvals. On 9 July 2019, Petrobras published its teaser to sell the Tucano Sul cluster of four producing gas fields in the onshore Tucano Basin. Interested companies must submit the customary manifestation of interest by 19 July 2019 and qualification documents by 23 July 2019 to [email protected] sale will also include the shared production installations for oil and gas processing and delivery to sales. Petrobras holds 100% working interest in all of the production concession contracts.

Petrobras has agreed to sell a quartet of onshore natural gas fields (Conceicao, Fazenda Matinha, Fazenda Santa Rosa and Querera) to local company Eagle for US$3 MM.

The Ministry of Energy and Petroleum is offering 29 open blocks on an open-door policy. The open blocks were:  Basin Names Block Name Block Sqkm Chad Basin~Termit Trough - Chad Basin Aborak 24,760 Chad Basin~Grein-Kafra Trough~Tenere Rift - Chad Basin Achegour 17,012 Iullemmeden Basin~Tahoua Depression (Iullemmeden Basin) Ader 31,174 Chad Basin~Bilma Trough - Chad Basin~Djado Basin Araga 28,196 Iullemmeden Basin~Mantass Depression (Iullemmeden Basin) Azawak 29,085 Chad Basin~Iullemmeden Basin Damagaram 29,680 Chad Basin~Termit Trough - Chad Basin Dibella 1 20,418 Djado Basin~Chad Basin Dissilak 19,924 Djado Basin Djado 1 14,121 Djado Basin Djado 2 12,694 Djado Basin Djado 3 11,288 Djado Basin Djado 4 11,981 Chad Basin~Tenere Rift - Chad Basin~Grein-Kafra Trough Grein 16,010 Chad Basin Homodji 33,118 Tamesna-Talak Depression (Iullemmeden Basin) ~Iullemmeden Basin Irhazer 25,758 Djado Basin~Chad Basin Karama 30,347 Chad Basin~Termit Trough - Chad Basin Manga 1 12,258 Chad Basin~Termit Trough - Chad Basin~Ngel Edji Trough - Chad Basin Manga 2 11,712 Chad Basin~Djado Basin~Grein-Kafra Trough~Hoggar Massif Seguedine 22,570 Iullemmeden Basin~Tahoua Depression (Iullemmeden Basin) Tadarast 39,972 Chad Basin~Hoggar Massif Tafassasset 21,965 Iullemmeden Basin~Tamesna-Talak Depression (Iullemmeden Basin)~Tahoua Depression (Iullemmeden Basin)~Air Massif Talak 30,120 Iullemmeden Basin~Tamesna-Talak Depression (Iullemmeden Basin) Tamesna 25,711 Tahoua Depression (Iullemmeden Basin)~Iullemmeden Basin~Nigerian Shield Tarka 43,342 Djado Basin Tchigai 21,160 Iullemmeden Basin~Chad Basin~Nigerian Shield Tegama 32,193 Chad Basin~Termit Trough - Chad Basin~Tefidet Rift - Chad Basin~Tenere Rift - Chad Basin Tenere Ouest 22,367 Iullemmeden Basin~Mantass Depression (Iullemmeden Basin)~Voltaian Basin Tounfalis 37,741 Mantass Depression (Iullemmeden Basin)~Iullemmeden Basin Yaris 30,807 Source, IHS Markit 2018

The Ministry of Energy and Petroleum is offering 29 open blocks on an open-door policy.

Deepwater Tano / Cape Three Points block, deepwater Tano-Côte d’Ivoire Basin, WD 2,674m, TD 4,870m, deep OWC proven in reservoir, w.o. confirmation + results. Maersk Viking DS under a 4-month contract involving 6 optional wells too. Aker Energy (op), partners Lukoil, FuelTrade + GNPC.

Aker Energy (40% op, Lukoil 38%, Fuel Trade Ghana 2% d GNPC 20%) has successfully drilled the Pecan 4A appraisal well on the Deepwater Tano / Cape Three Points (DTCTP) block. The well fulfilled its key purpose of confirming Aker Energy’s geological understanding in the area and identifying the deep oil/water contact in the Pecan reservoir.

On 7 May 2018, SDX Energy Inc. (SDX) announced that it had discovered gas in the LMS-1 exploration well in the Lalla Mimouna permit. The well encountered 16.4 m of net gas pay sands in the H-9 sequence of a Miocene shallow marine deposit with an average porosity of 32%. LMS-1 was spudded on 27 April 2018 and drilled to a TD of 1,158 m. SDX said the well had encountered heavier gas shows similar to LNB-1 well, indicating the presence of a deeper thermogenic source rock. It had also reported that the cuttings had shown evidence of fluorescence indicating the potential presence of liquid hydrocarbons in the encountered section. This rig has left the location and returned to the contractor as LMS-1 was the last well of SDX’s nine-well drilling campaign. SDX is the operator of the permit with a 75% interest and Office National des Hydrocarbures et des Mines (ONHYM), the national company, holds the remaining 25% (carried). Background Information On 1 February 2010, Circle Oil announced that it had signed a Petroleum Agreement with ONHYM the for the Lalla Mimouna area covering the Exploration and Exploitation of Hydrocarbons for the Lalla Mimouna Nord and Lalla Mimouna Sud exploration permits in the Rharb Basin. The permits cover an area of over 2,200 sq km and are issued for an initial period of 8 years with the right of automatic conversion to a minimum 25-year exploitation period in relation to areas where it is agreed that commercially exploitable hydrocarbons have been discovered. Under the terms of the agreement the percentage interest in the permits is Circle Oil 75% and ONHYM 25%. Circle Oil has agreed to carry out an initial targeted 80 sq km 3D seismic survey to assist in the assessment and ranking of prospects already identified in the area and to assess any newly identified prospects. The agreement also requires the completion of a minimum 2 well drilling programme in the first 3 years of the permits. In August 2015, Circle Oil Plc plugged and abandoned the new-field wildcat NFA-1 in the Lalla Mimouna permit after reaching a TD of 1,077 m. The well recorded gas shows at the targeted Miocene sands. NFA-1 is the third well drilled din the permit. The new-field wildcat El Anasba 2 (ANS-2) was suspended in early July 2015 after it encountered gas shows. The well is located on the northern flank of the East-West trending Anasba ridge. The Lalla Mimouna 1 (LAM 1) exploration well yielded 1.9 MMscf/d and 1.1 MMscf/d through 16/64" choke from a 1,261-1,272 m (primary target) and a 1,181-1,183 m (secondary target) respectively. The well is located on the central part of the permit on the east-west trending Anasba Ridge. On 27 January 2017, SDX announced that it had completed the acquisition of Circle Oil plc’s Egyptian and Moroccan assets. The company entered into heads of terms to finalise the acquisition for total cash of USD 30 million on 24 January 2017.  On 20 April 2018, SDX announced that it had hit a new play in the LNB-1 exploration well in the Lalla Mimouna permit. The well encountered 300 m of over pressured section in the gas bearing horizon in the primary Lafkerena sequence. The well also hit 2.6 m of net gas pay sands in the secondary Upper Dlalha target with an average porosity of 33%.  SDX Energy has been granted a four-month extension period for Lalla Mimouna permit through 22 July 2018.

Morocco (Rharb Sub-basin (Rharb-Prerif B.)) Lalla Mimouna 1

Block 5046, Dist. X, SE Turkey Zagros Fold Belt, TD 3,141m, tested 700 bo/d from the Bedinan fm, currently flowing 390 b/d on temp prod facility, logs suggest prospective pay also in the Hazro + Mardin fms.

Yeniev 1 (Transatlantic 100%) in M44-B2-1. Initial log analysis indicates prospective pay in Bedinan, Hazro & Mardin zones. Bedinian tested at 700 bo/d & is currently flowing 390 bo/d on a 16/64-inch choke to temporary production facilities.

On 25 March 2020, the Federal Agency for Subsoil Use held an auction for the Kostovatovskiy Yuzhnyy block in Udmurtia Republic (Volga-Ural Province). Competing against four companies, UDS Neft won the contest with the offer of RUB 850.63 million (USD 10.6 million). The winner of the auction will receive a 25-year license. The Kostovatovskiy Yuzhnyy block covers 16.2 sq km. Oil resources of the block (category D1) are estimated at 10.2 MMbbl. The starting price amounted to RUB 3.7 million (USD 0.05 million).

UDS Neft won the Kostovatovskiy Yuzhnyy block in Udmurtia Republic.

Eni has agreed to sell Neptune Energy a 20% interest in the East Sepinggan block, 2,771 sq km off East Kalimantan, whilst retaining operatorship and 65% (partner Pertamina 15%). This includes the Merakes East discovery + Merakes devt project. The deal is subject to usual approvals.

Indonesia (Kutei B.) Merakes

Perupetro intends to offer a single block for bidding in the Ucayali Basin sometime before end 2019. Designated 201, the block will be located in the central part of the basin north of TEA Area LXVI and just west of the Peru/Brazil border.

Perupetro intends to offer a single block for bidding in the Ucayali Basin sometime before end 2019. Designated 201, the block will be located in the central part of the basin north of TEA Area LXVI and just west of the Peru/Brazil border.

Among the recent exploration agreements signed between the Egyptian state-agency EGAS and IOCs for the exploration of gas in the Med. Sea, BP (90%) with partner Tharwa (10%) has been awarded the North El Sallum Offshore block. It is understood that the block corresponds to Block 1 expected to be on offer as part of the West Med. Sea Bid Round canceled in early Q1 2020 (separate articles). The block, which lies at the junction between the Northern Egypt Basin, Herodotus Basin, Mediterranean Ridge and Jabal Akhdar Uplift is a frontier area. It only includes one exploratory well, Sidi Barani 1, P&A as a dry hole, spudded by Phillips in 1976 in 50 m of water depth. The well reached a TD of 4,394 m and had objectives in the Cretaceous and Jurassic series.

Among the recent exploration agreements signed between the Egyptian state-agency EGAS and IOCs for the exploration of gas in the Med. Sea, BP (90%) with partner Tharwa (10%) has been awarded the North El Sallum Offshore block. It is understood that the block corresponds to Block 1 expected to be on offer as part of the West Med. Sea Bid Round canceled in early Q1 2020. The block, which lies at the junction between the Northern Egypt Basin, Herodotus Basin, Mediterranean Ridge and Jabal Akhdar Uplift is a frontier area.

Mari has secured sole rights to the Sujjal D&PL, 47 sq km excised from the Sujawal EL in the Lower Indus Basin around the Sujjal-1 gas-cond discovery. The lease lies in the Sujawal district of Sindh and is retro-effective 3 May ‘16.

Mari has secured sole rights to the Sujjal D&PL, 47 sq km excised from the Sujawal EL in the Lower Indus Basin around the Sujjal-1 gas-cond discovery.

Europa Oil and Gas is offering interested parties to farm-in to Frontier Exploration Licence – FEL 4/19 which contains the Inishkea prospect. Europa has identified 3 Tcf undiscovered GIIP in Triassic and Jurassic gas plays. In October 2019 Europa announced negotiations were still ongoing regarding the farm-in agreement with a major oil and gas company concerning licences FEL 4/19, FEL 1/17 and FEL 3/13. However, on 23 January 2020 Europa announced that negotiations with the major have fallen through but the company is still undertaking discussions with a number of other parties. With respect to Inishkea Europa hopes to obtain permission for a site survey to be commissioned for summer 2020 to enable drilling to take place in 2021. In February 2019, Europa announced an updated gross mean un-risked prospective resource estimate of 1.5 Tcf for the Inishkea prospect with a 33% chance of success. The prospect has been de-risked through the PSDM reprocessing of 770 sq km of 3D seismic over Inishkea and the Corrib gas field. Reprocessing was benchmarked and calibrated against Ocean Bottom Cable 3D seismic data over the Corrib gas field. Inishkea is defined as a large Triassic structure that lies 11 km from Corrib. The targeted Triassic gas play comprises of Triassic Sherwood sandstone reservoirs, Carboniferous source rocks and the combination of a Triassic Uilleann Halite top seal and fault seal providing the trapping mechanism. The water depths are relatively shallow (400 - 600 m) and do not require harsh environment sixth generation drillships, reducing drill costs. Europa conducted a drill cost estimate for a well on the Inishkea prospect and a dry hole cost including mobilisation and demobilisation of USD 28 million using a prevailing rig rate of USD 120,000 per day. Gas infrastructure is already present nearby at Corrib therefore a fast track path to commercialisation is potentially available, subject to negotiation and cooperation with the current infrastructure owners. The remaining inventory in FEL 4/19 includes the Inishkea NW prospect (1,094 Bcf), Inishkea W prospect (212 Bcf), Bofin lead (69 Bcf), Corrib North discovery (40 Bcf) and Corrib NW prospect (26 Bcf). Interest in FEL 4/19 is held solely by Europa Oil & Gas (Inishkea) Ltd. For further information please contact: Murray Johnson Email: [email protected]

Europa Oil and Gas is offering interested parties to farm-in to Frontier Exploration Licence – FEL 4/19 which contains the Inishkea prospect. Europa has identified 3 Tcf undiscovered GIIP in Triassic and Jurassic gas plays.

Comet Ridge secured sole rights to ATP 2048-P (Mahalo North), 451 sq km in the Denison Trough, Bowen-Surat Basin, on 29 Apr '20 for 6 years. The block was offered as PLR2019-1-2 under the 2019 QLD acreage release.

Comet Ridge was officially awarded exploration permit ATP 2048 (Mahalo North), 451 sq km in the Denison Trough, located in the in Queensland.

In Repsol’s Q2 2020 conference call, which took place in late July 2020, the company highlighted its recent successes in the US frontier region, particularly the recent Monument discovery in deepwater Gulf of Mexico, and the Mitquq and Stirrup discoveries in Alaska. Test results from the original Mitquq 1 bored indicate further enhance prospectivity along the trend between Mitquq and the core Pikka development on the North Slope. Mitquq 1 NFW, sited on North Slope ADL 393876, encountered 16m of hydrocarbon pay in its secondary Alpine C target after being drilled to a TD of 2,472m. 10m of this is net oil pay and six metres of net gas pay. In January 2020, Mitquq 1 encountered 60m of hydrocarbon pay within the primary objective Nanushuk interval (separate from the Pikka Development Nanushuk reservoir). The well intersected 5m of net gas pay, and 55m of net oil pay. No oil-water contact was encountered.The recent Stirrup 1 discovery represents one of the highest flow rates ever achieved from a Nanushuk single-stage stimulation of a vertical well on the North Slope. The NFW, sited in North Slope ADL 392044, intersected the targeted Cretaceous Nanushuk sandstone reservoir at 1,322m - encountering 23m of net oil pay - and was subsequently fracture stimulated and flowed at a stabilised rate of 3,520 bo/d over a one-hour period, with a gas:oil ratio of 560 scf/stb and less than 14.5% water cut on a 128/64” choke. Stirrup 1 NFW was P&A'd during April 2020. The well was targeting a large Cretaceous Nanushuk sandstone structure - west of the Horseshoe discovery and south-west of the Pikka Unit, in a similar geological setting. Stirrup 1 has the potential, together with Horseshoe, to be able to underwrite a standalone development. The results from both wells will be evaluated over the remainder of 2020.

Not Found

AE-0056-2M-Mezcalapa-06 block, onshore Sureste Basin, P&A dry at TD 4,525m on 15 Jul ’19. Target U. Miocene.

Mexico, not found

Petrobras in November 2017 confirmed a new oil discovery in pre-salt for the Marlim Field Block in the Campos Basin. According to Petrobras Exploration and Production director, Solange Guedes, the discovery had 196m column of good quality oil in carbonate reservoirs, making it the largest oil column ever found in the Campos Basin pre-salt. Little was disclosed about the discovery, which will require further testing for a better assessment. Guedes pointed out that discoveries in the Campos Basin pre-salt have high value because often production infrastructure is already in place. This is the second recent pre-salt discovery in area since August, when Petrobras announced the deeper pool wildcat 6BRSA1349RJS had found oil in Marlim Sul. The well involved in the most recently announced discovery was not disclosed. However, Petrobras on 20 October 2017 filed an oil show report with the ANP for the 9MRL231DRJS special well on the northern part of the Marlim Block. It seems likely that this is the well Petrobras was talking about. Petrobras also previously filed an oil show with the ANP on this well in June. It was drilled in water depth of 604m and is located 1.4 km north of the currently mapped field boundary and about 550m south of the concession's northern boundary line. However, it is not classified as an outpost well. The well was spud in January 2017 with a planned total depth of 4,539m and believed to be targeting the pre-salt. In late April 2016, the ANP extended concession contract renewals for the Marlim and Voador fields, granting Petrobras an additional eleven years to operate the concessions. The ANP board of directors accepted the terms requested by Petrobras extending the contracts to 2052, as well as dropping a requirement that would have raised the royalty rate. The decision by the ANP dropped that requirement as well as an additional one, which previously was set as a condition for contract renewal, to pay a special added tax on oil production from Marlim. The original Marlim and Voador concessions ran through 2025. With the contract extensions Petrobras is now expected to produce an additional 900 MMbo from the concessions before they are abandoned.

Brazil, Marlim

China’s CCCC* reportedly intends to take on a majority stake from Poly-GCL Petroleum in the pending, USD 4 bn Calub-Hilala gas devt project in Ogaden, the latter retaining a minority participation. Plans include local facilities, a 750km, 5.2 Bcum/yr pipeline to Djibouti where infrastructure (FLNG) will also be required. The fields are thought to hold 4.7 Tcfg + 13.6 MMbbl liquids,  1st gas hoped in 2021. * so far more involved in infrastructure construction, offshore engineering, procurement + construction.

China’s CCCC* reportedly intends to take on a majority stake from Poly-GCL Petroleum in the pending, USD 4 bn Calub-Hilala gas devt project in Ogaden, the latter retaining a minority participation.

Pacora-1 well encounters approx. 65 feet of high-quality, oil-bearing sandstone High quality resources to be integrated into giant Payara field development Further drilling on the Stabroek Block planned in 2018 ExxonMobil has announced its seventh oil discovery offshore Guyana, following drilling at the Pacora-1 exploration well. ExxonMobil encountered approx. 65 feet (20 meters) of high-quality, oil-bearing sandstone reservoir. The well was safely drilled to 18,363 feet (5,597 meters) depth in 6,781 feet (2,067 meters) of water. Drilling commenced on Jan. 29, 2018. 'This latest discovery further increases our confidence in developing this key area of the Stabroek Block,' said Steve Greenlee, president of ExxonMobil Exploration Company. 'Pacora will be developed in conjunction with the giant Payara field, and along with other phases, will help bring Guyana production to more than 500,000 barrels per day.' The Pacora-1 well is located approx. four miles west of the Payara-1 well, and follows previous discoveries on the Stabroek Block at Liza, Payara, Liza Deep, Snoek, Turbot and Ranger.The Pacora-1 well is located approx. four miles west of the Payara-1 well in the Stabroek block Following completion of the Pacora-1 well, the Stena Carron drillship will move to the Liza field to drill the Liza-5 well and complete a well test, which will be used to assess concepts for the Payara development. ExxonMobil announced project sanctioning for the Liza phase one development in June 2017. Following Liza-5, the Stena Carron will conduct additional exploration and appraisal drilling on the block. The Stabroek Block is 6.6 million acres (26,800 sq kms). Esso Exploration and Production Guyana is operator and holds 45 percent interest in the Stabroek Block. Hess Guyana Exploration holds 30 percent interest and CNOOC Nexen Petroleum Guyana holds 25 percent interest. Original article link Source: ExxonMobil

Pacora 1 op. by ExxonMobil (45%, Hess 30%, CNOOC Nexen 25%) in the Stabroek block, reportedly discovery (7th in block), struck 20m of what Hess termed "high-quality, oil-bearing sandstone reservoir".

Central part of Lindero Atravesado block, Neuquén Basin, drilled Dec '19 – Mar '20, TMD 5,817m (2,883m TVD), fracked over 3,165-5,776m in the Vaca Muerta, since compl. oil. PAE (op), partner YPF.

Argentina (Neuquen Embayment (Neuquen B.)) Lindero Atravesado Occidental

(Frontier) Margand 2866-4 EL, Kirthar Fold Belt in Balochistan, TD 4,500m, gas discovery in the Chiltan fm, DST'd 10.7 MMcfg/d + 132 b/d liquids on 1" choke, WHFP 516 psi. WDI-812 rig.

Margand X-1 nfw. (PPL 100%) in Margand 2866-4 EL block, in Balochistan, TD=4500m, gas discovery in the Chiltan Fm, DST'd 10,7 MMcfg/d + 132 b/d liquids [1" choke].

ExxonMobil Guyana has discovered more oil offshore Guyana after another major exploration campaign and exercise. The discovery was made in the Pacora-1 well offshore. This announcement was made by Minister of Natural Resources, Raphael Trotman after today’s Cabinet meeting, according to the Department of Public Information (DPI). The Pacore-1 drill site is 107 miles from the coast of Guyana. The oil find now represents the seventh major find by Exxon since May 2015. The Pacora-1 well discovery adds to previous world-class discoveries at Liza, Payara, Snoek, Liza Deep, Turbot and Ranger-1, which are estimated to total more than 3.2 billion recoverable oil-equivalent barrels. Original article link Source: INEWS GUYANA

Pacora 1 op. by ExxonMobil (45%, Hess 30%, CNOOC Nexen 25%) in the Stabroek block, reportedly discovery (7th in block), struck 20m of what Hess termed "high-quality, oil-bearing sandstone reservoir".

In early February 2018, Cobalt International Energy farmed out of Green Canyon contiguous leases GC 675 and GC 676, in which the company had previously held 19.5%. The transactions are effective as of 1 May 2017. GC 767 lies 4km due-north from the 2017 new-field wildcat G35679 1, targeting the Gator Lake prospect. The Lower Tertiary well was spudded on 8 May 2017, utilising the "Discoverer Clear Leader" drillship and had a permitted depth of ~10,670m. Chevron originally anticipated that it would take 170 days to drill the well. The drillship moved off location by late August 2017. The Gator Lake prospect had a pre-drill resource estimate pegged at between 400-500 MMboe. The results from this well are not yet known. Following completion of the transactions, equity in the southern halves of GC 675 and GC 676 is now shared between Chevron USA (50% WI + Op), Shell Offshore (25%) and Total E&P USA (25%). Equity in the northern halves of both leases remains unchanged: Chevron USA (30% WI + Op), Cobalt International Energy (19.5%), Total E&P USA (13%), Venari Offshore (12.5%) and Shell Offshore (25%).

Cobalt International Energy farmed out of Green Canyon contiguous leases GC 675 and GC 676, in which the company had previously held 19.5%.

The ANP board of directors on 23 August 2018 approved a new development plan for the Marlim Leste Field in the Campos Basin. Included in the approved plan was extending the production phase of the contract until 2052. The ANP also established guidelines for Petrobras as the operator of the field. The guidelines include: that the operator should carry out actions and investments to guarantee the maintenance and improvement of operational efficiency of the installations throughout the contract period. Maintain the injection of water into the reservoirs that have this secondary recovery method to maintain reservoir pressure. Conduct periodic studies on the obsolescence of critical equipment and the automation system, analysis of the adequacy of the security philosophy, extension of the life of the facilities and integrity of the platform. Direct investments for technical feasibility studies and projects for the implementation of improved recovery methods. Intensify the application of new technologies and methods for seismic monitoring of reservoirs. If Petrobras fails to adequately implement the development plan per CNPE Resolution 02/2016 and does not fully comply with the investment and production commitments after review by the ANP, proceeding can be started by the ANP to revoke the extension. Petrobras announced its expectation to finish negotiations in 2018 with the ANP for contract extensions for many of its major Round Zero fields in the Campos Basin. Some of the included fields were Albacora Leste, Marlim Sul, Marlim Leste, Roncador, Barracuda and Caratinga. The contract extensions are critical for Petrobras to continue investing in the Campos Basin, which still accounts for almost half of the Petrobras production. Petrobras currently is conducting 91 projects to boost the recovery factor in the Campos and between 2018 and 2022, the company is expected to invest US $ 18.9 billion and install four new FPSOs there. The Round Zero contracts were signed on 6 August 1998 and the production phase ends on that date in 2025. The ANP is advancing the negotiations with Petrobras on these fields since they require investments to develop production beyond 2025 and failure to extend the contracts would lead to declines in both investment, production and recovery factors for these important fields.

Brazil, Marlim

OGDC secured rights to the Khuzdar South 2667-9 EL, 2,493 sq km in the Kirthar Fold Belt, on 20 Jun ’19. It had been offered under the 2018 round.

OGDC secured rights to the Khuzdar South 2667-9 EL, 2493km².

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

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

Buru Energy Ltd spudded the Miani 1 oil exploration well in L 08, located in the Canning Basin, on 2 October 2019. The well was drilled by the "NGD 405" land rig and had a revised planned total depth (TD) of 3,000 m. On 4 November 2019 Buru reported that it was plugging and abandoning the well, after logging indicated the hydrocarbon shows encountered were within tight reservoir units, and therefore immovable. Analysis will be undertaken to determine the significance of the shows observed. TD was reached on 29 October 2019, at 3,006 m in the Frasnian Clastics section. Elevated mud gas readings and oil shows were observed in a section of dolomitised limestone between 2,970 and 2,990 m. Buru ran logging operations over the interval to assess the hydrocarbon indications. On 23 October 2019 Buru reported that it was running a wiper trip over the Anderson Formation shales, to condition the hole for logging. The wiper trip was required as the first attempt at a logging run was unable to pass below 1,650 m. On 29 October, Buru further reported that wireline logs were not possible in the formation due to poor hole conditions. The lower section was evaluated with LWD tools. Initial log results indicated the lower Nullara Carbonate may be prospective, though the well had not yet penetrated this unit. Therefore, it was planned that once the wiper trip was completed, the well would be deepened to around 3,000 m to evaluate this section. Logging would then be undertaken at the new total depth. Buru reported that thick units of tight limestones, with dolomite sections, were encountered during drilling. However, the expected vuggy porosity zones were not encountered. Miani 1 was targeting what was previously known as the “Hotdog” prospect, which is a carbonate sag feature, with a reservoir target in the Nullara Reef unit, sourced by the Laurel Carbonates. The prospect is well defined from 3D seismic. Estimated recoverable reserves, best case, are reported at 17 MMbo. The well was spudded as planned, being scheduled to spud in early-October 2019. Site construction was reported to be well advanced as of late-July 2019. Environmental clearances and heritage approvals were achieved by July 2019. The well lies in the L 08 permit, which contains the Sundown, Terrace West and Lloyd oil fields, discovered in 1982, 1985 and 1987 respectively. All three have ceased production or are shut-in. L 08, which covers an area of 326 sq km, was awarded on 22 October 1984. Buru Energy Ltd holds 100% interest and operatorship of the licence.

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.

Mirach is selling off its subsidiary PT Prima Petrolium Service (ex-PT Kampung Minyak Energy), production operator at the Kampung Minyak field. The buyer is reportedly a yet-unnamed individual, deal subject to authority approval. The company will otherwise retain its stake in its other Indonesian asset (Sungai Taham-Batu Keras-Suban Jeriji KSO).   Of note, Mirach last year said it was in the process of returning the Kampung Minyak field to Pertamina.

Mirach is selling off its subsidiary PT Prima Petrolium Service (ex-PT Kampung Minyak Energy), production operator at the Kampung Minyak field.

As announced on 15 July 2019, PNOC-EC and Ratio Petroleum signed a Memorandum of Understanding (MOU) to permit PNOC’s entry to SC 76, located in the northeastern flank of the East Palawan Basin. Both parties are bound to establish cooperation in research and feasibility studies and exchange of technical information, starting with SC 76. The terms of PNOC’s participation in the block are to be agreed upon at a later date. On 17 October 2018, Ratio Petroleum officially signed a service contract for SC 76 with the Philippines’ government for the Philippine Energy Contracting Round V (PECR V – Area 4). This is the only service contract awarded under PECR V. On 30 June 2015, the Department of Energy (DOE) received bid applications for only four areas out of the total 11 areas offered. Local company Colossal Petroleum has put in bids for Area 5 and 7 (East Palawan and Recto Bank) whilst Area 1 (Southeast Luzon) received bid from Yulaga Oil. However, application from Yulaga Oil was disqualified while awards for Colossal petroleum were cancelled due to requirement issue with Commission on Audit (COA). The state-owned Philippines national oil and gas company, PNOC has been continuously looking for partners in petroleum exploration and development to secure a sufficient energy for local consumption. Israel-based Ratio Petroleum Ltd. is a subsidiary of Ratio Oil Exploration. The E&P company also holds interests in Guyana, Suriname, Ireland and Malta. Background Information The 4,160 sq km of SC 76 is covered by a 540 line km of 2D seismic data. The block lies at water depth of around 200 m to 2,000 m. To date, no wells have been drilled within the service contract. Nearby wells are Cuyo 1, Paly 1, Dumaran-1 and Silangan 1. The last two wells have exhibited oil and/or gas shows. The western portion of the block was previously held by Phillips Petroleum Co. and partner Shell Philippines BV from June 1978 to July 1983 as block SC33 East Palawan. SC 76 is also part of Area 8 which was offered during PECR IV in 2011. Play types identified in the block are the reef build-up, anticline, stratigraphic and possible fault block play (from recent studies). The area consists of sedimentary thickness of around 3,000 to 5,000 m. Reservoir target: Cretaceous sandstones, Oligocene to Middle Miocene Carbonates and Middle Miocene to Upper Pliocene sandstones. Source rock – Hydrocarbon was generated by the Oligocene to Miocene shales. Seal – Intraformational seal would be provided by Oligocene to Pliocene mudstones and shales. DOE estimated resources potential of 1.23 Bbbl of oil and 2.06 Tcf of gas.

PNOC-EC and Ratio Petroleum signed a MOU to permit PNOC’s entry to SC 76.

The DGH announces that 26 contract areas, covering 60 discovered small fields/fallow discoveries, will be offered under the upcoming Discovered Small Fields bid round II (DSF-II) in May-Jun ‘18. The 26 contracts cover 3,100 sq km in 8 basins. 15 are onshore and 11 offshore. The full list of fields/discoveries can be viewed in GEPS.

The DGH announces that 26 contract areas, covering 60 discovered small fields/fallow discoveries, will be offered under the upcoming Discovered Small Fields bid round II (DSF-II) in May-Jun ‘18. The 26 contracts cover 3,100 sq km in 8 basins. 15 are onshore and 11 offshore. The full list of fields/discoveries can be viewed in GEPS.

Hutan 1 is presumably completed in June 2020 without result reported. PetroChina – Xinjiang spudded a deep NEW in the Junggar Basin. Hutan 1, located in the eastern part of the south basin margin, was spudded in 14 May 2019 with a PTD of 7,280 m and has target on deep play in the Cretaceous. The south margin of the Junggar Basin, geologically, has developed a 400 km long thrusting structure belt. A few small oil and gas fields have been found, such as Dushanzi, Mahe and Hutubi fields, with reservoir in the shallow Tertiary and Cretaceous. In January 2019, PetroChina made a significant discovery in the western part of south margin. Gaotan 1 tested 7,630 b/d of oil and 11 MMcf/d of gas in the Lower Cretaceous Qingshuihe Formation. PetroChina has identified 21 prospects with the deep play target on the basin south margin thrust belt and it indicated great exploration potential in this area. Hutan 1 is the second well for the deep play after Gaotan 1. The Junggar Basin is one of the key exploration and production base for PetroChina. The company has approved more than 25 oil and gas fields by 2018 with total of 22 bn bbls of oil and 6 Tcf of gas in place reserves. In 2018 PetroChina produced 11.47 million tons of oil (229,000 b/d) and 2.9 Bcm of gas (290 MMcf/d). The company plans to increase oil production to 260,000 b/d by 2020.

China (Junggar B.) Hutan (Ju) 1 op. by PETROCHINA (100%) in Southern Margin East I block, Hutan 1 is presumably completed in June 2020 without result reported. PetroChina

On 22 September 2017, Delonex Energy Limited (Delonex) announced that the Share Purchase Agreement (SPA) with United Hydrocarbon International (UHI)’s wholly owned subsidiary United Hydrocarbon Chad Ltd. (UHCL) was closed, approved and completed. Terms of the agreement -          Delonex paid USD 35 Million to UHI. -          An additional payment of USD 50 Million will be made in case of successful drilling (USD 30 Million at Doba B, USD 20 Million at Block H). -          UHI will retain a 10% royalty of Cost Oil and Profit at Doba and a 5% royalty on Block H, payable unless Brent Crude Oil < USD 45 for a quarter.   Delonex commitments -          To spend USD 65 Million on exploration in two years including 2D and 3D seismic surveys -          To drill at least three exploration wells in the blocks area. -          Further payment of USD 35 Million on development in Doba region if commercial success. On 10 May 2017, UHI announced that it entered into an agreement with Delonex for the latter to acquire UHI Chad. UHI Chad operates the Largeau III, Lake Chad, Doba B license with a 75% interest. Partner is the state company Société des Hydrocarboures du Tchad (SHT) that holds the remaining 25%.  

Chad (Chad B.) ? op. by CNPC (90.0%, SHT 10.0%) in Lake Chad block

Pertamina has signed to acquire a 27% stake from optr Repsol in the Southeast Jambi block, 1,121 sq km in South Sumatra. So far Repsol (will retain operatorship), partner MOECO.

Pertamina has signed to acquire a 27% stake from optr Repsol in the Southeast Jambi block, 1,121 sq km So far Repsol (will retain operatorship), partner MOECO.

Larus Energy Ltd is looking for a joint venture partner in its wholly owned and operated exploration licence PPL 579, located in the south-east of Papua New Guinea in Larus’ newly defined Torres Basin.Larus Energy reports it is offering significant equity in the permit, with a farminee to take part in an upcoming exploration programme. Larus has contracted Moyes & Co. to assist in the divesture process.A data room is open for interested parties.In August 2017 Larus reported that it was increasing its efforts in the farm-out process, with results of seismic now available and the discovery of an oil seep within the licence area. In Q4 2017 it was reported that discussions were ongoing with a number of potential partners, with new confidentiality agreements signed in November. Moyes & Co is being utilised in an advisory capacity during the process, in which interested parties have been outlined since 2015 and have been conducting geological, geophysical and commercial due diligence as is required for farminees. In August 2015 Larus reported that discussions and due diligence was continuing, with 14 companies interested in the asset. In February 2017 Larus was awarded PPL 579 to replace PPL 326 which expired in September 2016. The newly awarded licence covers 9,257 sq km across both onshore and offshore Papuan Plateau/Aure Fold Belt. PPL 579 is scheduled to expire in March 2023. Larus also holds 100% interest in the neighbouring application APPL 580 which was submitted for approval consideration in December 2015. Larus is looking for a partner to assist with the ongoing work programme in the permit, although Larus has reported that the first two years was already fully funded. In the first two years, Larus undertook work to develop the shallow Miocene play potential which includes the Vekwala and Sunday prospects. In 2015 and 2016, the Haere and Hahonau 2D seismic surveys were completed from which the data will was processed to facilitate lead and prospect mapping. Further, smaller surveys have also been completed over the asset by Larus. In December 2018, Larus received approval to vary the work commitments for the third and fourth years. The requirement to dill an exploration well has bene replaced with the acquisition of a high resolution airborne magnetics and gravity survey. Larus plans to acquire around 7,250 sq km at a cost of USD 2.5 million. The survey is required by March 2021. Suitable partners will be asked to fund 3D seismic data acquisition to help further define Vekwala and Sunday prospects which is required prior to drilling. The first exploration well is currently due by March 2023. Larus reports that there is potential for both Mesozoic and Tertiary targets within the permit area.Potential reservoirs include a Mesozoic Puri Limestone equivalent, the Tertiary Talama and Lavao units and also a potential Toro sandstone equivalent. The early – mid Jurassic Manil Shale and Miocene-Pliocene Aure Beds Shale are thought to form potential source rocks, with the Orubadi Shale and intraformational units possible as seals. The Vekwala prospect has been reported to potentially contain resources of 13 Tcfg and 180 MMb liquids within a Jurassic reservoir. Water depth at location is approximately 42 m and the main target is at a depth of approximately 3,600 m below seabed. Previously the Sunday Prospect was outlined as the main target in the licence. The Sunday Prospect lies in a water depth of approximately 600 m and the main target is at a depth of approximately 3,000 m below seabed in a Cretaceous reservoir. Sunday is considered to be a 40 km long anticline which could contain 13.5 Tcfg with 160 MMb liquids. There are also several other prospects and leads present. The prospects and leads in the licence are thought to be part of a Mesozoic petroleum system. In August 2016 onshore oil seeps were invested by Larus. This was followed up by further sampling of light crude oil near the Imila village, north of Kapiano, withinAPPL 580. Geochemical analysis has confirmed that the oil has been generated in the Torres Basin. Analysis will now be undertaken to understand the source rock and maturity to further validate the hydrocarbon system model being constructed by Larus. PPL 579 covers an area of 9,257 sq km and was awarded in February 2017. Larus Energy holds 100% interest and is looking to divest its interest. Parties interested in pursuing this opportunity should contact: Ian Cross, Managing Director Moyes & Co Tel: +1 281 501 7110 Email: [email protected]   Andy Melvin, Managing Director Moyes & Co Tel: + 44 7702 855895            Email: [email protected]

Papua New Guinea (Papuan B.) PPL 579 op. by LARUS EN (100%), Larus is on the lookout for a partner in its wholly-owned PPL 579, 9,257 sq km on/offshore in the Torres Basin, SE PNG, in exchange for participation in an upcoming explo programme comprising 3D seismic acquisition to help further define the Vekwala + Sunday prospects required prior to drilling.

Ecopetrol has been granted sole explo rights to the COL 5 unit in the Caribbean, where it now has rights to 6 blocks. Ecopetrol will be seeking to farmout the 4,000-sq km permit, which is adjacent to its Purple Angel and Fuerte Sur blocks in the Sinú Basin. COL 5 had earlier been held under TEA terms. This is the 1st contract signed under the revamped regulatory framework for offshore ops, signed into law last week. Up to another 9 contracts are hoped to be signed in the near future, with TEA conversions likely for Anadarko, Exxon, Repsol + Shell.

Ecopetrol has been granted sole explo rights to the COL 5 unit in the Caribbean.

Plans are announced for the 3rd round of Open Acreage Licensing Programme (OALP-III), hoped to be launched in the next couple of weeks. It is understood that 23 blocks (including CBM) totalling nearly 32,000 sq km will be offered. Tentative block inventory:

Plans are announced for the 3rd round of Open Acreage Licensing Programme (OALP-III), hoped to be launched in the next couple of weeks. It is understood that 23 blocks (including CBM) totalling nearly 32,000 sq km will be offered.

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

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

In July 2017 Conoco Phillips and Canacol subsidiary CNE Oil and Gas signed a non-traditional exploration agreement with the National Hydrocarbon Agency (ANH) for further exploration on the VMM-2 Block of the Middle Magdalena Basin. Conoco operates the acreage with 80% and partner Canacol Energy holds 20% interest. On 28 March 2017 Canacol Energy announced successful test results in its Mono Capuchino 1 ST outpost well located in the VMM-2 Block. The test interval between 1,735 m (5,691 ft) and 1,793 m (5,884 ft ) within the Lisama sandstone reservoir yielded 1,013 bo/d of 18° API gravity oil, 70 bw/d and 300 Mscf/d of gas at an injection pressure of some 3,000 psi during a 34-hour test. According to the composition of water recovered during the test it is related to the drilling operations but formation water. The operator tested some 234 m (769 ft) of open hole section in the La Luna Formation which showed non-commercial quantities of heavy oil. The Mono Capuchino 1 outpost well was spudded on 17 December 2016 targeting the La Luna Formation at a proposed total depth (PTD) of 3,658 m (12,000 ft). The operator had reached a depth of 3,055 m (10,023 ft) prior to mechanical failure. Sidetrack operations were commenced in January 2017 and on 22 February 2017 the Mono Capuchino 1ST reached a total depth (TD) of 3,123 m (10,245 ft). The well intersected some 32 m (103 ft) of net oil pay and some 124 m (406 ft) of net oil pay within the Lisama and the La Luna Formations, respectively. The Mono Capuchino 1ST is expected to be placed on permanent production from the Lisama reservoir via Mono Arana field facilities in the 2Q 2017. Canacol holds a 66.7% interest in the block with partner Vetra operating with 33.3% interest. Mono Capuchino 1 ST is located some 500 m south of the Mono Arana 1 discovery made in 2012 which tested at some 600 bo/d with no water in 2014. Canacol hoped to encounter some 610 m (2,000 ft) of the La Luna Formation in the Mono Capachino 1 and if successful, 11 additional locations on the prospect were identified for possible future drilling. The Mono Arana 1 NFW was the first well drilled on the block, which had oil and gas shows in the La Luna Formation. The Mono Arana 1 encountered approximately 232 m (760 ft) of the Upper Cretaceous La Luna Formation, with good oil and gas shows. Additional deeper prospective zones in the La Luna and Tablazo sections were not penetrated due to high pressure encountered while drilling, and casing was set within the La Luna. Canacol has a 66.7% working interest on the block where fractured shale potential will be tested. Vetra is operator with 33.3% interest in unconventional targets. Background information In March 2008 Vetra Energy Group signed an option agreement with Petrotesting Holding Limited to acquire a 78% stake (and operatorship) in Petrotesting Colombia S.A. Vetra also had the option to purchase the remaining 22% stake. On 18 July 2008 Vetra acquired 100% of local company Petrotesting Colombia S.A. On 4 December 2008, Petrotesting was awarded an exploration and production contract with state licensing agency National Hydrocarbon Agency (ANH) for the VMM-2 Block. On 18 February 2009, Petrotesting Colombia S.A signed the contract. The 36 month-long first exploration phase required the acquisition of 62 sq km of 3D seismic data and the drilling of one exploration well. On 10 December 2010 Vetra Energy Group commenced the acquisition of a 121 sq km 3D seismic survey over the onshore VMM-2 Block. Geoespecto SAS was contracted to shoot the survey. In May 2011 Vetra finished processing the seismic. On 4 April 2012 Canacol Energy Ltd. announced that its subsidiary Carrao Energy Sucursal Colombia farmed out half of its 40% interest in the VMM 2 Block to ExxonMobil Exploration Colombia Limited. Canacol received USD 2.2 million upon execution of the farmout agreement for costs related to the 3D seismic acquisition in 2011. ExxonMobil carried the cost of the drilling and testing of up to three wells to test conventional and unconventional targets in the La Luna and Rosablanca Formations. In late June 2012 the operator Vetra planned an exploration well (vertical well) to be drilled in late 2012 and two wells in 2013 (vertical, horizontal and multi-stage fractured) in the VMM-2 Block. The Mono Arana 1 NFW was spudded on 23 September 2012 using the SAI 31 rig to test both conventional shallow light oil target in the Tertiary Liasama sandstone, and a deeper non-conventional light oil target in the fractured oil shale of the Cretaceous La Luna oil source rock. The Lisama reservoir was penetrated as anticipated at a measured depth (MD) of approximately 1,460 m (4,800 ft). Based on Canacol's petrophysical analysis of the open hole logs run across the interval, the Lisama contains approximately 26 m (85 ft) of potential net oil pay with an average porosity of 21%. Colombia’s first fracking job was planned for 2016 by Conoco Phillips. On 3 December 2015 Conoco Phillips and Canacol subsidiary CNE Oil and Gas signed a non-traditional exploration agreement with the National Hydrocarbon Agency (ANH) for further exploration on the VMM-3 Block of the Middle Magdalena Basin. This represents the country’s first additional contract for expanding hydrocarbon prospectivity as a result of implementing the government’s Accord No 3. Project investments on the Additional Contact VMM-3 are estimated at over USD 85 million, adding to the development of unconventional reservoirs and increasing Colombia’s reserves. Shell was the former operator of VMM-3 Block  

ConocoPhillips (op 80%, Canacol 20%) signed with the ANH (National Hydrocarbon Agency) an unconventional hc. E&P contract for VMM-2.

On 16 August 2018 Falcon Oil and Gas reported that it and farm-in partner Origin Energy Ltd had signed an agreement to mark Stage 1 of Origin’s farm-in to Falcon’s Beetaloo Basin assets as complete.  The signing was an amendment to the original agreement, reducing the work commitments planned under stage 1. The joint venture has drilled three vertical wells and fracture stimulated one horizontal well as part of the stage one programme. One further horizonal well was planned to be included in stage one, but the joint venture has determined that it is more beneficial to move onto phase two of the farm-in.  Therefore stage one has been signed as complete, though remains subject to government approval. The farm-in is seeing Origin acquiring 70% interest in three exploration permits within the Beetaloo Sub-basin: EP 117, EP 76 and EP 98. The farm-in is being conducted over three stages, with stage one complete as announced on 16 August 2018. The farm-in agreement was entered into in 2014, at which time both Origin and Sasol Petroleum were to acquire interest. However in May 2017 Sasol announced it would withdraw from the farm-in, and Origin took its share of the deal.   The first phase well results were better than anticipated and drilling and fracture stimulation of Amungee Northwest 1 was brought forward in the programme, being originally planned for after all the vertical holes that had been drilled. The full programme is to consist of nine exploration and appraisal wells. In phase two further wells will be drilled and stimulated. The budget has been increased by AUD 15 million, after the removal of the additional well in phase one, and will now be completed at a capped cost of AUD 65 million.  Any of the additional AUD 15 million not utilized, will be rolled over to phase 3. In phase 2, planned for 2019, an additional vertical well will be drilled as well as drilling and stimulation of two horizontal wells.  Preparation is ongoing as of August 2018. Once stage 2 is complete, drilling locations targeting the most prospective play will be outlined for stage 3. Origin has estimated total contingent resources within the permits of 6.6 Tcf gas. The Beetaloo Basin Project covers a total of 18,618 sq km through permits EP 117, EP 76 and EP 98 which are scheduled to expire on 29 April 2019.  Origin now holds 70% interest and operates the project. Falcon Oil & Gas Australia Pty Ltd holds the remaining 30%.

On 16 August 2018 Falcon Oil and Gas reported that it and farm-in partner Origin Energy Ltd had signed an agreement to mark Stage 1 of Origin’s farm-in to Falcon’s Beetaloo Basin assets as complete.

DEA Norge has acquired an additional 13% in Norwegian Sea Production Licences (PL) 211 and 211 B from operator Total, effective 27 June 2018. It contains the Victoria gas discovery NFW 6506/6-1 (2000, Mobil, 5,491m TVD), encountering dry gas in Middle Jurassic Ile and Lower Jurassic Tilje Formations with the Middle Jurassic Garn Formation and Lower Jurassic Upper Are Formation sandstones also thought to be gas charged. PL211 was awarded on 2 February 1996 in the 15th Round and now covers 241.8 sq km of blocks 6506/6 and 6507/4 and was converted to a production licence on 2 February 2002. PL211 B was awarded in APA 2006 on 16 February 2007 now covering 37.3 sq km over blocks 6506/9 and 6507/7. In PL211 B the Victoria appraisal well 6506/9-1 (2009, Total, 5,659m TVD) was drilled proving gas in the Tilje and Ile formations. Post appraisal well drilling and a successful flow test, Victoria was estimated to hold recoverable gas resources of 0.7-2.1 Tcf, although the size of the discovery is not fully understood. In December 2017 DEA (LetterOne) and Wintershall (BASF) agreed to merge subsidiaries. Total acquired Maersk in May 2018 increasing its stake in the two licences from 40% to 70%. PL11 and PL211 B partners are now Total Norge AS (57% + Op) and DEA Norge AS (43%).

DEA Norge has acquired an additional 13% in Norwegian Sea Production Licences (PL) 211 and 211 B from operator Total,

As of 1 Sepetember 2019, Lagniappe Alaska LLC has been officially awarded 119 oil and gas leases on which it bid at the North Slope Areawide 2018W sale held on 15 November 2018. The tracts are located in the eastern North Slope area, southwest of the Point Thomson gas field.  Lagniappe Alaska is owned by Armstrong Oil & Gas of Denver, Colorado. Lagniappe spent USD 14.14 MM submitting sole bids on 120 blocks covering 195,200 acres (790 sq km) in the sale. In the entire North Slope sale, 133 blocks were bid on, with the sum of high bids coming to USD 27.32 MM. Two other companies submitted high bids at the sale: Repsol E&P USA (12 blocks, USD 13.07 MM) and Regenerate Alaska (1 block, USD 104,870). A map showing the location of the blocks is available at the Alaska Department of Natural Resources Division of Oil & Gas website https://dog.dnr.alaska.gov/Documents/Leasing/SaleResults/NorthSlope/2018W/NorthSlope_ApparentHighBidder_Fall2018.pdf

United States (Barrow Arch (North Slope B.)) Point Thomson

In March 2018, Rosneft discovered a new oil pool at the Tarasovskoye field in Yamalo-Nenets Autonomous Okrug (Western Siberia). In September 2017, the company re-entered development well Tarasovskaya 3290 drilled to 2,700 m and completed on reservoir BP10-11 (2,612-2,635 m). The well was side-tracked from 2,650 m and drilled to 3,373 m at the Tyumen Formation (Middle Jurassic). Oil and formation water at rates of 30 b/d and 75 b/d, accordingly, were tested from reservoir Yu3 perforated at 3,285-3,293 m. A new oil pool was reported after testing reservoir Yu2 perforated at 3,210-3,216 m and 3,225-3,228 m. The reservoir flowed with oil, gas and water at rates of 637 b/d, 1.2 MMcf/d and 49 b/d, accordingly, through a 10 mm choke. Tarasovskoye, discovered in 1967, is located in the central part of the Nadym-Taz Province. Its initial 2P reserves are estimated at 1,269 MMbbl of oil, 2.4 Tcf of gas and 36.6 MMbbl of condensate. The field has been producing since 1986.

Rosneft discovered a new oil pool at the Tarasovskoye field in Yamalo-Nenets Autonomous Okrug (Western Siberia). In September 2017, the company re-entered development well Tarasovskaya 3290 drilled to 2,700 m and completed on reservoir BP10-11 (2,612-2,635 m). The well was side-tracked from 2,650 m and drilled to 3,373 m at the Tyumen Formation (Middle Jurassic). Oil and formation water at rates of 30 b/d and 75 b/d, accordingly, were tested from reservoir Yu3 perforated at 3,285-3,293 m

Weizhou 11-2-12d (WZ 11-2-12d) was suspended on or around 28 March 2020, having intersected oil in the target reservoirs. The deviated oil appraisal well was spudded on or around 8 March 2020, using the “Haiyangshiyou 931” jack-up. Weizhou 11-2-12d had a PTD of 3,200m and was likely targeting the Weizhou and Liushagang formations. Weizhou 11-2-12d is in the CNOOC operated Yulin 35 Block in the offshore Beibuwan Basin.

Weizhou 11-2-12d (WZ 11-2-12d) was suspended on or around 28 March 2020, having intersected oil in the target reservoirs. The deviated oil appraisal well was spudded on or around 8 March 2020, using the “Haiyangshiyou 931” jack-up. Weizhou 11-2-12d had a PTD of 3,200m and was likely targeting the Weizhou and Liushagang formations. Weizhou 11-2-12d is in the CNOOC operated Yulin 35 Block in the offshore Beibuwan Basin.

Oranje-Nassau has taken over from Hansa Hydrocarbon as optr of N4, N5 + N8 licences in the Gems area (Apatiet, Ruby, Saphir + Tanzaniet structures), preceding Discover Exploration’s subsequent acquisition of the share capital of Hansa. Oranje-Nassau (op), partner EBN.

Oranje-Nassau has taken over from Hansa Hydrocarbon as optr of N4, N5 + N8 licences in the Gems area (Apatiet, Ruby, Saphir + Tanzaniet structures), preceding Discover Exploration’s subsequent acquisition of the share capital of Hansa. Oranje-Nassau (op), partner EBN.

On 17 November 2017, local press reported that A&V Oil and Gas Ltd's (A&V Oil) sale of the Moruga East Block to Chinese buyer Shandong Deshi Petroleum Engineering Group Co Ltd (Shandong Deshi) has hit the buffers. The company has been trying to sell the block to Shandong Deshi since 2015 with a formal agreement signed on 11 November 2016. Shandong Deshi's payments were to be US$ 19.5 million in four tranches or US$ 14 million in five tranches. State NOC Petrotrin apparently gave conditional approval for the commercial terms of the sale in August 2015 subject to the fulfilment of certain conditions. Petrotrin hasn't fully approved the deal due to some of these conditions not being met, and so the deal still hasn't completed. The block is held through a 10-year Incremental Production Sharing Contract (IPSC), also known as a Trinidad Sub-Licence Agreement, with Petrotrin which is due to expire in November 2019. A&V Drilling & Workover Ltd was awarded the IPSC in November 2009. There is some question mark as to whether this was transferred to an affiliate A&V Oil and Gas Ltd. Both are owned by Haniff Nazim Baksh, a local businessman who is friends with Prime Minister Keith Rowley. He appears to share ownership of A&V Drilling & Workover Ltd with his senator daughter Allyson Baksh and A&V Oil and Gas Ltd with his other daughter Vivian Baksh. A&V Oil has other troubles as it is part of an ongoing investigation by Canadian consulting firm Krall at the behest of Petrotrin, regarding discrepancies in oil sold to the state-owned firm from its Catshill IPSC.

Moruga (Rock Dome)

In July 2020 Tangram Energy was still offering a farm-in opportunity for licence P2359 (blocks 13/30c and 14/26d), which contains the 13/30-2 (Samedi) discovery, to interested parties. The opportunity was previously announced in December 2019. The company has conducted seismic interpretation and depth conversion of newly purchased seismic along with petrophysical analysis and reservoir analysis of the discovery. Tangram is looking to progress towards appraisal of the discovery once entering Phase C of the licence (between 2021 and 2023). The Samedi discovery was discovered by Britoil in 1984 with well 13/30-2. The discovery was within the Buzzard B2 unit and was a surprise with the first core missing the interval. Samedi is thought to be an analogue of Buzzard. P50 resources for Samedi are estimated at 33.4 MMbbl (STOIIP) for the B2 sands. Tangram believes that the discovery pinches out at multiple points and petrophysical analysis on wells 13/30-2, 14/26b-5 and 14/26a-9 identify a good trend of thick Buzzard sands pinching against the Grampian Arch which is the main trap. The reservoir sands are confined between Jurassic age faults which crosscut the basin in a West Northwest – East Southeast trend. Licence P2359 is located north of Golden Eagle with Samedi approximately 12 km north west of the Golden Eagle platform. Interest in P2359 is held solely by Tangram Energy Limited. For further details please contact Martin Smith Technical Director (Tel - +44 (0) 2031 676401) [email protected]

In July 2020 Tangram Energy was still offering a farm-in opportunity for licence P2359 (blocks 13/30c and 14/26d), which contains the 13/30-2 (Samedi) discovery, to interested parties.

On 24 October 2019, Italian Eni SpA, part of the Petrobel Belayim Petroleum Co (Petrobel) company with Egyptian General Petroleum Co (EGPC), announced that a new appraisal well, Sidri 36, was completed positive in the Sidri B11 block, onshore/offshore Gulf of Suez Basin. Sidri 36 was drilled to appraise the Sidri South field, a structure south of the Abu-Rudeis Sidri field. The appraisal well was drilled westward in a down dip position compared to the new field wildcat Sidri 23 drilled in Q2 2019 (separate article). Sidri 36 reportedly encountered a 200-m hydrocarbon column in the clastic sequence of the Cretaceous Nubia Formation. It is expected to be brought onstream shortly, at a rate of 5,000 bo/d. According to Eni, this result continues the positive track record of the “near field” exploration in its historical concessions in Egypt and proves that the development of new play concepts combined with the use of the latest technology allows to re-evaluate areas already explored. Background Information The Sidri South field was discovered in July 2019 after the new field wildcat Sidri 23 encountered oil in the Oligocene clastic units. According to Eni, the field's total in place resources may reach up to 200 MMbbl of oil. The Sidri B11 block was granted to Petrobel, a JV between Eni and EGPC in December 1975. It comprises also the southern structure of the Abu-Rudeis Sidri field.

Egypt (Gulf of Suez B.) October

On 5 July 2017 New Zealand Oil and Gas Corp (NZOG) reported that initial approvals and waivers had been granted with regards to its acquisition of Mitsui E&P Australia’s 4% interest in the Kupe oil and gas field, located in the Eastern Taranaki Mobile Belt, Taranaki Basin.  The New Zealand Stock Exchange (NZX) has granted the waiver required for the interest change and the joint venture has not exercised its pre-emptive rights to the interest.  Some additional approvals remain required for the transaction to be completed and it was reported in December 2017 that these remained pending. The agreement between NZOG and Mitsui was first announced on 18 May 2017.  NZOG will pay NZD 35 million in the deal, upon completion of the transaction. NZOG will acquire Mitsui’s full interest in the field, which is located in licence PML 38146, and will hold interest with Origin Energy (operator with 50% interest) and Genesis Energy (46% interest).  The purchase by NZOG is subject to joint venture and regulatory approvals.  If completed, it will have an effective date of 1 January 2017.  NZOG reported that the acquisition supported its current strategy. The Kupe field was discovered in December 1986 and has been producing since December 2009. The field life has been previously estimated at around 20 years, however NZOG reports that it believes there is additional undeveloped potential within the field.

New Zealand (Taranaki B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: PML 38146 (Kupe) op. by ORIGIN EN (32.1875%, ORIGIN EN 17.8125%, GENESIS EN 16.0%, GENESIS EN 12.75%, GENESIS EN 11.0%, NZOG 4.0%, GENESIS EN 4.0%, GENESIS EN 1.25%, GENESIS EN 1.0%) to be check.

HIGHLIGHTS:Strata-X Energy has acquired two new Prospecting Licenses for its Serowe CSG Project covering 406,735 acres. The new licenses offset those already held by the Company in addition to offsetting lands of ASX listed peers. The Serowe CSG Project now spans 680,000 acres in heart of the Botswana CSG fairway, that are 100% owned and operated by the Company.With the goal of developing the CSG resource, the Company has selected a Botswana environmental firm to seek the necessary environment approvals required before the appraisal program can begin. The environmental approvals are expected in the third quarter of 2018. The proposed appraisal programme is designed to prove commercial completion methods and convert resources to reserves. To achieve this, the Company plans to apply the latest completion and production methods to yield commercial gas flow rates. Once that is achieved, the Company can convert resources into reserves.Ron Prefontaine, Chairman of the Board, stated that, 'With the new licenses, Strata-X now has 680,000 acres in its 100% owned Serowe CSG Project, which is located within the Kalahari Basin CSG fairway.The new additions provide our shareholders material upside for our proposed appraisal programmes in Botswana.'The new acreage lies adjacent to a bitumen highway between Serowe, the regional capital, and Orapa, the site of the world’s largest diamond mine and large potential energy market.Tenement Renweal Terms The new Prospecting Licenses known as PL016-2018 and 017-2018 carry a primary term of 3 years with two, 2- year extensions. To complete the issuance of the PL016-2018 and 017-2018 Prospecting Licenses, Strata-X Australia, owner of the existing Republic of Botswana subsidiary’s Rhino CBM and Sharpay Enterprises, created a new wholly owned Republic of Botswana subsidiary to hold Licenses called Jab Right Pty Ltd.Original article linkSource: Strata-X

Botswana, Kalahari

DEA has assumed full ownership of PL 211 after the withdrawal of Total (57%) effective 6 Mar ‘19. PL 211 lies over 60 sq km in the SE part of block 6507/4 between the Ærfugl + Dvalin fields.

DEA has assumed full ownership of PL 211 after the withdrawal of Total (57%) effective 6 Mar ‘19. PL 211 lies over 60 sq km in the SE part of block 6507/4 between the Ærfugl + Dvalin fields.

PetroChina – Tarim made an important discovery in the Tarim Basin. Luntan 1 tested 934 b/d of oil and 1.7 MMcf/d of gas in the deep sub-salt Wusongger Formation of the Cambrian on 19 January 2020, as a play opener well in the basin. PetroChina – Tarim spudded this ultra-deep NFW in the Tarim Basin on 28 June 2018. Luntan 1, located in Luntai area of the Tabei Uplift, has a PTD of 8,500 m with target in the Cambrian carbonate play. Luntan 1 was completed reaching a TD of 8,882 m by 17 July 2019. It was said this well has set a record of ultra-deep wells onshore in Asia. Sinopec drilled another ultra-deep well Ying 1 with a depth of 8,588 m in Shunbei oil/gas field in February 2019. There are limited wells drilled in this part of the basin, and only several small discoveries in the Tertiary formations have been made in the early 1990s. PetroChina started commercial exploration activities 30 years ago in the Tarim Basin, by end 2017 the company has approved about 7 bn bbls of oil and 60 Tcf of gas in place. In 2019 PetroChina made a significant achievement oil and gas production and produced at 113 Mb/d of oil and 2.8 Bcf/d of gas, comparing 110 Mb/d and 26 Bcm in 2018. PetroChina has a plan to produce at 120 Mb/d of oil and 3 Bcf/d of gas by 2020 in the Tarim Basin.

Luntan 1 (PetroChina 100%) in Dongqiu-Luntai block o&g disc, considered a play opener, flow tested approximately 934 bo/d and 1,72 MMcfg/d from the sub-salt Cambrian Wusongger Fm. with the objective of exploring the hc potential of the dolomite reservoir of the Lunnan-Gucheng platform margin.

On 16 December 2019, the Federal Agency for Subsoil Use held an auction for the Ilinskiy block in Rostov Oblast. Two local companies submitted bids and Regionalnaya Neftegazovaya Kompaniya won the contest with the offer of RUB 313,200 (USD 5,000). The winner of the auction will be awarded a 25-year E&P license. The Ilinskiy block covers 377 sq km. No hydrocarbon fields have been discovered within the block. Gas resources of the block are estimated at 41 Bcf. The Skosyrskoye discovery with gas reserves within the Carboniferous section is located south of the Ilinskiy block. The Romanovskoye discovery with oil reserves within the Carboniferous section is located east of the Ilinskiy block. The starting price amounted to RUB 261,000 (USD 4,150).

Regionalnaya Neftegazovaya Kompaniya won Ilinskiy block in Rostov Oblast.

Investicijos has received an exploration & production (E&P) licence in the Klaipedos-Silute area of W Lithuania, within the Baltic Basin. The new award was approved on 7 March 2018 and covers 17.5 sq km, located adjacent to the W of Rietavas block, which Investicijos operates and where it acquired 2D and 3D seismic during 2014/15. Chevron was previously a 50% stakeholder in Investicijos but exited in 2014. Three exploration wells were drilled on Rietavas during 2013, including the Silale 5 appraisal well which encountered oil in Cambrian sandstones and was completed as a potential future producer. UAB LL Investicijos is sole licensee for Klaipedos-Silute.<P />

Investicijos has been awarded Klaipedos-Silute E&P licence

1 August 2018, Turkmennebit national oil trust is continuing appraisal drilling at the Altyguyi field onshore western Turkmenistan. Well Altyguyi 34 has been drilled to a TD of 4,100 m. A test at a depth of 4,060 m has flowed unspecified volume of oil. Although no further details have been provided, it could be assumed, by analogy with well Altyguyi 22, that the successful test comes from the Lower Red Beds, the main play in the Turkmen part of the South Caspian Basin. The Altyguyi discovery is located south-west of the Korpeje oil field in Western Turkmenistan. Turkmennebit (Turkmenneft) discovered Altyguyi in December 2008 with the Altyguyi 1 wildcat. The well’s first successful test flowed oil from the interval of 3,670-3,680 in the Lower Red Bed Series (Pliocene) at a rate of 100 t/d (ca. 750 bo/d). A second test discovered gas in the interval of 3,616-3,625 also in the Lower Red Beds. The gas flowed at 15.4 MMscf/d. Background Information In April 2010, Turkmennebit reported a flow of oil and gas in the appraisal well Altyguyi 4. The well had tested 75 t oil/day (ca. 560 bo/d) and 100,000 cu m/day (3.4 MMscf/d) gas from a reservoir at 3,700 m. In late October 2014, well Altyguyi 14 tested a flow of oil in excess of 100 tonnes/day (750 b/d) from a depth of 3,800 m in the Lower Red Bed Series. The company did not provide any further details of the test/well. In March 2014, Turkmennebit tested oil in the appraisal well Altyguyi 22. The well had been drilled to a TD of 4,100 m. It was tested between 4,012-4,018 m in the Lower Red Bed Series and flowed oil. No further details were reported.

Turkmennebit national oil trust is continuing appraisal drilling at the Altyguyi field onshore western Turkmenistan. Well Altyguyi 34 has been drilled to a TD of 4,100 m. A test at a depth of 4,060 m has flowed unspecified volume of oil. Although no further details have been provided, it could be assumed,

ON has taken over as sole holder of P1630 / blocks 42/10a, 42/15a + 42/15c (Crosgan gas discovery) through the acquisition of Ineos’ 30% in April.

United Kingdom, P1630

South Australia's 2019 South Australian acreage release closes for bidding today. The round opened on 27 May. Available blocks / basin / sq km were:

South Australia's 2019 South Australian acreage release closes for bidding today. The round opened on 27 May.

Some industry noises suggest the schedule of Moz's delayed 6th round could be aired before the end of March. So far it is understood that 9 offshore blocks could be offered in the Zambezi Deep Sea Fan and the Zambezi Delta, and one onshore North of Maputo, in the Mozambique Basin.

Some industry noises suggest the schedule of Moz's delayed 6th round could be aired before the end of March. So far it is understood that 9 offshore blocks could be offered in the Zambezi Deep Sea Fan and the Zambezi Delta, and one onshore North of Maputo, in the Mozambique Basin.

Chevron Australia Pty Ltd has announced that is has made the decision to market its non-operated 1/6th interest in the North West Shelf (NWS) project, located in the North Carnarvon Basin. The decision was made after Chevron received unsolicited offers from a range of buyers. The deal has been reported to be worth around USD 3.5 billion. With the NWS Project moving focus from an independent LNG project to a competitive third-party tolling facility, Chevron believes this represents a good time to exit the joint venture by considering proposals by potential buyers. Since the Woodside operated NWS Project commenced in 1989, Chevron has maintained its position, which is currently holds at 16.67%, alongside equal share with partners Woodside Energy Ltd, BHP, BP, Japan Australia LNG (MIMI) and Shell. Over the coming years, it's planned that the Pluto LNG Plant will be tied into the NWS Project's Karratha Gas Plant – creating the "Burrup Hub" as part of an expansion concept. The Browse LNG Project could also see LNG tolled through the facilities via a 900 km long pipeline, in which, Chevron does not hold position. Overall, the NWS Project comprises 19 licences (JV 15.78% share, with 5.32% held by CNOOC) and 20 gas and 7 oil discoveries. Initially the project produced from foundation fields: North Rankin, Goodwyn, Angel and Perseus. Two completed expansion phases extended production through the tie in of second-tier fields. The third expansion phases reach a financial investment decision in January 2020. Chevron has reported that it intends to maintain its position in its Gorgon and Wheatstone Projects.

Australia (Exmouth Plateau (North Carnarvon B.)) Pluto, Chevron Australia Pty Ltd has announced that is has made the decision to market its non-operated 1/6th interest in the North West Shelf (NWS) project, located in the North Carnarvon Basin.

Perenco has exercised its pre-emption right on a January Wytch Farm deal between Ithaca and Verus Petroleum (DEA 18 Jan ’18). The latter had agreed to buy Ithaca’s 7.5% in the Wytch Farm field for GBP 53 MM. Involved are PL 089, P 534 + PEDL 328 across Poole Harbour. Partnership will therefore become Perenco (op) 95% + Repsol Sinopec 5%, effective 1 Jul ’17.

United Kingdom, Wytch Farm

POSCO International has suspended wildcat Mahar 1 in block A-3, offshore Rakhine Basin, around early December 2019. The well has been drilled to a TD of approximately 1,960 m, using the "Maersk Viking" D/S. Preliminary results have not been reported, and operations on the well may continue at a later date for testing. Meanwhile, the rig has been mobilized to drill exploration well Kissapanadi 1 in the same block, approximately 17 km northeast of Mahar 1. Mahar 1 was spudded in late November 2019 and is part of a three-well drilling plan (plus one optional well). The firm drilling programme is scheduled to last until April 2020 for a total duration of approximately 155 days. Mahar 1 is situated at a water depth of approximately 1,100 m, targeting biogenic gas in the proven Pliocene turbidite play. The structure, located about 20 km southwest of the Mya South production facilities, was initially defined by the operator as "Prospect G". The other wells in the programme are Yan Aung Myin 1 (formerly "Prospect A-South") and Kissapanadi 1 ("Mya Channel Fill"). The exploration campaign is aimed at finding additional gas resources for the Shwe Gas Project. The operator is planning to complete Phase II and Phase III of the project between 2022 and 2024, in order to maintain gas sales volume of 500 MMcf/d. Maersk reported that the drilling contract is valued approximately USD 33 million, including mobilization fee. The last exploration activity in the block was a 1,900 sq km 3D seismic survey covering both blocks A-1 and A-3. The survey was likely completed around early March 2015, using PGS’s “Ramform Titan” survey vessel. The survey commenced on 27 January 2015 with the first part of acquisition in block A-1, followed by block A-3. Block A-3 is operated by POSCO International with 51% interest alongside partners ONGC Videsh (17%), MOGE (15%), Gail (India) (8.5)% and Kogas (8.5%). Background Information The 6,779 sq km block was awarded to Daewoo (100%) in February 2004. OVL and Daewoo had applied separately for the block, both seeking a 100% equity. Block A-3 lies adjacent and south of Block A-1, where operator Daewoo made a gas discovery with the sidetrack of its first wildcat Shwe 1, marking the first discovery in Myanmar waters in the Rakhine Basin. The well, drilled from November 2003 to January 2004, flowed 32 MMcfg/d from Lower Pliocene basin floor fan sandstones upon testing. On 1 November 2004 Daewoo entered into the exploration phase of the block by paying an agreed signature bonus of US$ 2.5 million. Subsequently, during February-April 2005, the company acquired 7,797 line km of 2D seismic over the block at an estimated cost of US$ 2.2 million. Interpretation of the new seismic data has led to the identification of undisclosed number of prospects including Mya (Emerald). On 3 October 2005, Daewoo finalised a deal with ONGC Videsh Ltd (OVL), Gas Authority of India Ltd (GAIL) and Korea Gas Corporation (Kogas) to acquire stakes of 20%, 10% and 10%, respectively in Block A-3. The two Indian state firms, OVL and GAIL, paid premiums of US$ 2.88 million and US$ 1.44 million, respectively. It followed a Memorandum of Understanding (MOU) signed on 5 October 2004 to finalise the farm-in agreement, where a combined 30% equity was offered to the two Indian firms against their request for 50% equity. Daewoo drilled four exploration wildcats in the block and discovered the Mya field in 2005. In 2007, two appraisal wells were drilled, Mya 2 and Mya 3, and successfully appraised gas. Three wildcats, Mya West 1, Kyauk-Seine 1 and Thandar 1, were drilled between 2007 and 2008 but did not have favorable results. In January 2008, the operator completed a 1,006 sq km 3D seismic survey using CGGVeritas’s “CGG Harmatan” survey vessel.

Mahar 1 nfw. (Posco 51% op , ONGC Videsh 17%, MOGE 15%, Gail 8,5%, Kogas 8,5%), 1st of 3 wells planned in ex-prospect G in Andaman Sea block A-3, WD=1100m, ops. concluded at TD ca. 1950m, results n/a, target gas in Pliocene turbidites,.

One of several discoveries reported to the CNH recently by Pemex (others have been carried in these lines since 2018), E. part of AE-0021-3M-Okom-04 block, offshore Sureste Basin, WD 35m, 2018-2019 discovery, 25 API oil find in the U. Cret. PTD was 4,985m, target Cretaceous + Jurassic, Cantarell I JU.

Tokhin 1AEXP one of several discoveries reported to the CNH recently by Pemex 100% (others have been carried in these lines since 2018), E. part of AE-0021-3M-Okom-04 block, offshore, 2018-2019 discovery, 25° API oil find in the U. Cret. PTD was 4985m, target Cretaceous + Jurassic. WD=35m.

Tapir block, Llanos Basin, TD ca. 3,000m, oil in multiple conventional reservoirs within the C7 (15m), Gacheta (11m) + Ubaque (3.6m) fm’s, testing of the C7 A sand (31m) gauged 613 b/d of 28.3 API oil -peak 1,172 b/d-, pressure buildup required, Weatherford rig 839. Farmin commitment for Arrow to gain 50% + operatorship through Carrao Energy. Partner Petrocol.

Rio Cravo E.-1 (RCE) (Arrow 50% op. Petrocol 50%) in Tapir block, LWD logs indicate 31m oil pay in multiple conventional reservoirs within the C7 (15m), Gacheta (11m) + Ubaque (3.6m) fm’s, The well tested an average of 613 bo/d of 28.3° API oil, with a peak rate of 1172 bo/p, over a production test period. Additional minor potential net pay was identified in the C3 + Mirador fm’s. TD ca. 3000m.

In early December 2019, Energy Resources of Ukraine (ERU) acquired Carpathian Industrial Group 2014 LLC, licensee for the Byblivska special permit, before divesting a partial stake to PGNiG. It is understood that PGNiG is now a 49% holder of the Carpathian Industrial 2014 joint venture (JV) with ERU retaining 51% majority stake. Byblivska covers 85 sq km in the North Carpathian Basin of western Ukraine, and lies adjacent to the S & SW of Khidnovytske Field, and S of PGNiG's Przemysl Field. Przemysl has produced 2.3 Tcfg from 30 Badenian-Sarmatian (Miocene) sandstone reservoir horizons since 1960, and current output averages just under 50 MMcfg/d, with estimated remaining recoverable reserves of over 320 Bcfg plus further contingent resources of 700 Bcfg (2C) subject to appraisal. This includes the VIIIa horizon discovered by the Przemysl 290 development well (2018, PGNiG, 2,030m), which tested up to 7.5 MMcfg/d. These new resources will likely focus planned exploration on the Ukrainian side, and the Byblivska partners have indicated they will shoot seismic and drill a well to 2,500m, potentially in 2020. Byblivska was offered in the Third Auction 2015, won with an offer of approximately US$ 31,000, and awarded from 22 January 2016 for 20 years. Licensees are Energy Resources of Ukraine and PGNiG, via joint venture Carpathian Industrial Group 2014 LLC.

Not Found

On 23 May 2019 Sino Industrial Energy Ltd was awarded exploration licence PPL 645, located onshore Fly Platform. Sino has been awarded the licence for an initial period of six years with the expiry date set as 22 May 2025. This is the third application and award by Sino alongside PPL 646 and PPL 647, which were also awarded on the same date. The company applied for the licence areas to the Department of Petroleum and Energy (DPE) on 25 July 2018. Given successful completion of the allocated work programme, Sino may be eligible to renew the licence for a further 5 years, with an associated 50% area reduction. PPL 645 covers an area of 1,440 sq km and covers most of the South Pacific Resources (SPR) licence PPL 366 area, which was awarded in 2010. The licence reached the end of its validity period in 2016 with no known successful renewal applications. SPR now plans to exit PNG and will be offloading their remaining assets. It's thought that PPL 366 will formally be registered as expired. Over the first two years of the PPL 645 work programme, Sino are required to complete several studies including seismic reprocessing if required, play and concept analysis, and review all offset wells. The second term programme over years 3-4 is yet to be confirmed, but a minimum of 20 km of new 2D seismic data acquisition is outlined ahead of possibly drilling an exploration well in years 5-6. One well has been drilled within the permit area: Goari 1, 1978. The well targeted Mesozoic Sands in a faulted anticline of the Omati Trough. The sands were poorly developed and the well was drilled within a complex fault zone, probably off structure. Minor oil shows in Lower Imbru were encountered.  Sino Industrial Energy Ltd was awarded 100% interest in exploration licence PPL 645 on 23 May 2019.

Papua New Guinea, PPL 646

L-II ML block, Cauvery Basin onshore, TD 1,292m, 4Q ’17 o+g discovery, tested up to 208 bo/d + 124 Mcfg/d from below 959m in the Nannilam fm on 6mm choke.

MT-14 (MTAN), renamed Mattur West 1 (MTW-1) op. by ONGC (100%) in L-II ML, flowed from the Precambrian Basement 130bo/d and from the sand interval in Upper Cretaceous Nannilam Fm flowed approx 1165bo/d [6 mm choke].

Novo-Bogolyubovskiy block (licence ORB02957NR), Orenburg, o&g tested in U. Devonian + L. Carboniferous reservoirs, results justify plans for 18 devt wells at the field now designated Novosibirskoye.

Novosibirskaya 1 (Rosneft subs. Orenburgneft 100%) in Novo-Bogolyubovskiy block (licence ORB02957NR), Orenburg, o&g tested in U. Devonian + L. Carboniferous reservoirs, results justify plans for 18 devt wells at the field now designated Novosibirskoye

Vermilion has entered into an agreement to acquire an undisclosed private southeast Saskatchewan Bakken producer in a share deal valued at CD 90.8 MM. The agreement is subject to customary closing conditions. Involved are 172 sq km and light oil producing fields (1,150 b/d) in the Sinclair and Fertile areas across the Saskatchewan/Manitoba border, NE of Vermilion’s existing assets in SE Saskatchewan. www.vermilionenergy.com.

Vermilion Energy has entered into an arrangement agreement to acquire a private southeast Saskatchewan producer ('Privateco') for US$91 MM. Acquisition is comprised of high netback, low base decline, light oil producing fields in the Sinclair and Fertile areas.

1st well in PL 814, NE of Gina Krog in WD 109m, P&A’ing dry at TD 3,761m (Skagerrak), main targets Hugin + Sleipner fm’s, Deepsea Stavanger SS. Aker BP (op), partners MOL + OMV.

15/06-15 (Freke-Garm) (Aker BP 40% op, MOL 30%, OMV 30%), 1st well in PL 814, NE of Gina Krog in WD=109m, P&A’ing dry at TD =3761m (Skagerrak), main targets Hugin + Sleipner fm’s.

In July 2018, it was reported that INEOS left licences P1026, P1191 and P1272 which contain the Rosebank discovery. Suncor acquired its 10% interest increasing its interest to 40% in each licence. Further to this deal INEOS also left licence P1830 which contains the Blackrock prospect on 29 June 2018 with Suncor acquiring its entire 25% interest in the licence. It is understood that Chevron has extended its re-tender for the Rosebank field development drilling campaign. The plan is to drill 11 top holes commencing in 2020 until 2021 lasting approximately 120 days. The main drilling programme will commence in 2022 with the drilling of 17 subsea wells – nine producers and eight water injectors. The field will be developed via a Floating Production, Storage and Offloading unit. A Final Investment Decision for the project is planned for early 2019. Seismic interpretation is ongoing over the entire licence, the results of which will be used in final prospect definition. An exploration well is planned to drill Blackrock in 2019. Rosebank was discovered in August 2004 by well 213/27-1Z which encountered two reservoirs – Rosebank and Lochnagar - with a total net pay of 52 m. Rosebank has a Paleocene reservoir and Lochnagar has an Upper Jurassic reservoir. Appraisal well 205/1-1, drilled in 2007 on the Rosebank structure, tested 6,000 b/d of good quality oil with API values of 37°. The field is situated in water depths of approximately 1,100 m. Between April and August 2011 a 350 sq km High Density 3D OBN survey was performed over Rosebank with SeaBird’s “Munin Explorer”. This was the second phase of the Rosebank High Density 3D survey. The first stage was shot in 2010 and covered an area of 256 sq km. Front End Engineering Design studies commenced in 2012. In 2013 Chevron submitted and Environmental Statement for the project. The produced oil was to be shuttled by tanker, while gas will be exported via a newly installed pipeline. Back when the Environmental Statement was submitted it was thought that peak oil production was expected to reach 82,000 b/d with peak gas production, expected three years after the initial oil production, at 134 MMcf/d. The Blackrock prospect is situated between the Cambo and Rosebank fields and has a Colsay / Hildasay reservoir target. The licence, P1830, was awarded in the 26th Offshore Licensing Round. The planned 2019 exploration well, if successful, could add substantial resources to the planned area development. Interest in P1026, P1191 and P1272 is held by Chevron North Sea Limited (40% + operator), Suncor Energy (40%) and Siccar Point Energy (20%). Interest in P1830 is held by Siccar Point Energy (52.5% + operator), Suncor Energy (25%) and Shell UK Ltd (22.5%).

Ineos has withdrawn from P1026, P1191 + P1272 containing the Rosebank discovery, its 10% going to Suncor (->40%). Ineos also left P1830 (Blackrock prospect), Suncor also taking on its 25%.

Tawke block in Kurdistan, tested 10 oil zones + 1 gas zone over a 1,200m horizl section in the Cret + Jurassic reservoirs. The oil zones gauged up to 7,200 b/d / zone, avg 5,340 b/d. An aggr. 12,500 b/d was obtained from 5 zones. DNO (op), partner Genel.

Iraq (Zagros Province) Peshkabir 3 op. by DNO (75.0%, GENEL EN 25.0%) in Tawke PSC block

Add. DEA 22 Jan ’18 (discovery): SK-408 off Central Luconia Sarawak, 3rd in 3-well programme, P+A gas around 19 Jan ’18, TD 2,640m, Hakuryu-11 JU. Targets Middle Miocene Cycle V carbs. Sapura (op), partners Shell + Petronas. The other 2 wells were abandoned (Remujung-1 dry, Jarak-1 non-comm. gas).

Pepulut 1 op. by Sapura (40% op, Shell well op 30%, Petronas 30%) in SK-408 block, gas discovery, targets Middle Miocene Cycle V carbs. TD=2640m.

Service well in Albacora lease, Campos pre-salt, WD 450m, 214m light oil column, test at 4,630m likely in the Aptian Macabu fm, Norbe VIII DS. Release + map here. Petrobras is reportedly laying out an appraisal plan to access those pre-salt reservoirs in the area.

9-AB-135D-RJS (Petrobras 100%), Service well in Albacora lease, Campos pre-salt, WD 450m, 214m light oil column, test at 4630m likely in the Aptian Macabu fm, Norbe VIII DS. Petrobras is reportedly laying out an appraisal plan to access those pre-salt reservoirs in the area.

MB-OSN-2005/3, Bombay offshore, WD 125m, drilled 14 Jan – mid-Mar '20, TD 1,317m, Sagar Vijay DS. Likewise MBS053NAD A nfw fin the same area, WD 240m, drilled 3 Jan - 27 Feb '20, TD 1,497m, Aban Ice DS.

MBS053NAC A nfw MB-OSN-2005/3, Bombay offshore, WD 125m, drilled 14 Jan – mid-Mar '20, TD 1,317m,

In early May 2019, industry sources suggested that Kosmos withdrew from block C-18, deep waters of the Senegal (M S G B C) Basin, northern offshore Mauritania. It is assumed that BP which is the strategic partner of Kosmos in the region took over the 15% offloaded by Kosmos. The new right-holding situation would thus be: Total, operator with 45%, BP with 30%, Tullow with 15% and state company SMHPM with 10%. Shortly after completing a 3D seismic survey on block C-18 in May 2017, Tullow farmed out a stake in the permit to Kosmos. In late 2017, Total farmed into C-18 and took operatorship from Tullow. Block C-18 is on the Upper Cretaceous slope and basin floor which have yielded the very large Tortue (Ahmeyim) and Marsouin gas fields in block C-8. C-18 is also further north in the basin, just next to the C-6 / C-12 boundary where Kosmos drilled the Lamantin wildcat in December 2017. The Lamantin results were disappointing as the well only found oil shows.

In early May 2019, industry sources suggested that Kosmos withdrew from block C-18, deep waters of the Senegal (M S G B C) Basin, northern offshore Mauritania. It is assumed that BP which is the strategic partner of Kosmos in the region took over the 15% offloaded by Kosmos. The new right-holding situation would thus be: Total, operator with 45%, BP with 30%, Tullow with 15% and state company SMHPM with 10%.

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

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

Further to DEA 18 May ’18, Tullow’s award of 5 offshore blocks was reportedly cancelled by the govt of President Vizcarra yesterday on grounds that his predecessor had awarded the permits before resigning and inadequate consultations with local communities. Blocks involved are Z-64 through Z-68, WD 50-3,500m (DEA 10 Jan ’18). Tullow is considering its next move.

The new president of Peru has repealed five offshore oil contracts include Z-64, Z-65, Z-66, Z-67 and Z-68 awarded in March to Tullow Oil.

SE of Jacana field in LLA-34, Llanos Basin, target N. extent of the Totoro discovery in the adjacent Cabrestero block, drilled 2Q ’18 to TD 3,565m, tested 1,100 b/d of 17 APOI oil on ESP. Winchester (op), partner Parex. Meanwhile Tigui Sur-1 expl south of above was drilled to TD 4,049m, test during 3Q. Explo plans for remainder of 2018 include Buco-1 nfw +  Chirioca-2 appr in LLA-34, as well as a series of devt wells therein.

Tigui 1 (Winchester 45% op, Parex 55%), SE of Jacana field in LLA-34 block, target N. extent of the Totoro discovery in the adjacent Cabrestero block (Guadalupe Mirador Fms) and tested 1 100 b/d of 17°API oil on ESP. TD=3565m.

On 26 July 2019, Indonesian Ministry of Energy and Mineral Resources (MEMR) offered the West Tanjung I exploration block, located onshore in the Barito Basin, under the Conventional Oil and Gas Bidding Third Round 2019. Access to bid documents is scheduled from 26 July 2019 to 18 October 2019. Submission of participating documents is from 18 October 2019 to 25 October 2019 at 2.30 pm (Western Indonesian Time). The data package for the West Tanjung I block comprises approximately 2,850 km of 2D seismic data (vintage from 1974 to 1986) and five well data. As an incentive to participate to the bidding exercise, free access to the data package will be granted to all companies that purchase the bid document for the related block. The data package will be only charged to the eventual winner of the block. The minimum signature bonus for the block will be USD 2.5 million. Minimum firm commitments for the first three-year exploration period include G&G studies and 600 km of 2D seismic acquisition and processing. The contract will require a mandatory relinquishment of 25% of the block area at the end of the third year. The block, covering an area of approximately 5,460 sq km, is situated onshore in the North Barito Deep Sub-basin. Seven wells have been drilled within the offered acreage but none of them was successful. BPM drilled two shallow wells that were dry, Rudji 1 (922 m) in 1938 and Buntok 1 (863 m) in 1939. Union Oil under the Teweh PSC drilled three wells, Montalat 1 (1,055 m, oil shows) in 1979, Panran 1 (1,698 m, oil & gas shows) in 1980, and Perigi 1 (824 m, dry) in 1980. Unocal in 1989 under the Teweh PSC drilled Ahmatan 1 (3,054 m, dry) and Buntok Baru 1 (1,530 m, oil shows). The majority of the West Tanjung I block was previously covered by the West Tanjung PSC operated by PT Karya Inti Petroleum between 2011 and 2018. Typical source rocks identified in the Barito Basin are coals and shales from the Tanjung Formation and Lower Warukin Formation. The Total Organic Carbon (TOC) in these formations ranges from 0.6 to 5.4 wt% in the shales, and from 43.6 to 65.9 wt% in the coals. The main reservoir in the basin is provided by clastic sediments of Upper Paleocene to Middle Eocene Lower Tanjung Member, with porosity ranging between 15% and 26%. The pre-Tertiary basement has also been identified as an oil reservoir in the Tanjung field. Another potential reservoir is the Upper Oligocene-Lower Miocene carbonates of the Berai Formation Reportedly, several prospects and leads have been identified, likely from previous seismic data. The most prospective lead identified in the area is the Palas Dua lead, with P50 resources (unrisked) of 44.3 MMbo or 213 Bcfg and P50 (risked) of 5.4 MMbo or 26.5 Bcfg within Lower and Upper Tanjung members. Background Information West Tanjung PSC The previous West Tanjung block was offered on 20 May 2011 as part of the First Petroleum Bidding Round 2011 under the direct offer mechanism. The preliminary award/announcement of winning bidder was made on 21 September 2011, when the block was awarded to PT Karya Inti Petroleum. Firm commitments for the first three years of exploration included G&G studies (USD 1.1 million) and 250 km 2D seismic acquisition (USD 2.5 million). Signature bonus paid for the block was USD 1.0 million. The block was also subjected to partial acreage relinquishment of 25% of the total acreage size after the expiry of the first exploration period. The block covered an area of 6,095 sq km in the North Barito Deep Sub-basin (Barito Basin). Portions of the block were previously covered by the UEP IV contract (Pertamina) from 1966 to 1992, Teweh PSC (Union Oil) from 1974 to 1983, Teweh PSC (Unocal) from 1985 to 2000 and North Tanjung PSC (PerminTracer) from 1993 to 2002. In mid-September 2013, PT Karya Inti Petroleum offered farm-in opportunity up to 49% participation interest in the block. A 200 km 2D seismic acquisition was being planned in 2016, subject to outcome of the drilling results in 2015. In case of unsuccessful drilling results, the operator could have acquired 2D seismic data focused on different prospects in 2016. An additional exploratory well was planned to be drilled in 2017, with an estimated cost of around USD 5 million. The plan was later cancelled as the block was reported by SKK Migas to be under relinquishment in January 2018. The seismic survey would have focused on the limestone of Upper Oligocene to Lower Miocene Berai Formation and syn-rift stratigraphic play of Eocene Tanjung Formation. The pre-Tertiary Basement could have provided an additional exploration target for the survey.

On 26 July 2019, Indonesian Ministry of Energy and Mineral Resources (MEMR) offered the West Tanjung I exploration block, located onshore in the Barito Basin, under the Conventional Oil and Gas Bidding Third Round 2019.