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Sonatrach has made an oil & gas discovery in its Hassi Berkine Sud Ouest 1 (HBSW 1) NFW. The well tested from what is understood to have been a Palaeozoic interval, at ~1,989 bo/d & 9.6 MMcfg/d, at a WHP of 1,750 psi. HBSW 1 is located in the west of the Ourhoud II exploration licence, in the Berkine Basin. It was spudded on 14 January 2017, with operations being carried out using the Dalma Energy #12 rig. The well reached a TD of 4,900m in April 2017. HBSW 1 is the third successful exploration well to target the deeper Palaeozoic on the block since 2015. In August 2016, the Hassi Berkine Nord Est Profond 3 (HBNEP 3) appraisal well was completed, having tested oil, gas & condensate from the Silurian and Siegenian. In December 2016, Hassi Berkine Centre 1 (HBKC 1) encountered gas & condensate in a Siegenian-Gedinnian interval. Sonatrach operates the Ourhoud II exploration licence, which confers exploration rights across the Groupement Berkine-operated Hassi Berkine Sud Field, with 100% equity.

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PDO reports significant reserves at the Mabrouk field area (Mabrouk Deep & Mabrouk NE) in the N. part of block 6, Makarem-Mabrouk High. Over 4 Tcfg + 112 MMbc est. recoverable, 5 gas wells drilled to ab. 5,000m to date, one on stream from the Barik and Miqrat reservoirs which tested up to 42 MMcfg/d after a frac job. Further prospects are being drilled.

Oman (Ghaba Salt Sub-basin (Oman B.)) Mabrouk

At the Africa Oil Week conference held in Cape Town on 5-7 November, Ernest Rubondo, executive director of the Petroleum Authority of Uganda announced plans to launch a new Bid Round in May 2019. The Bid Round will follow road show.

At the Africa Oil Week conference held in Cape Town on 5-7 November, Ernest Rubondo, executive director of the Petroleum Authority of Uganda announced plans to launch a new Bid Round in May 2019. The Bid Round will follow road show.

OGDC secured the Saand D&PL, 1.6 sq km around the Saand-1 gas-cond discovery within the Nim 2568-9 EL block, Lower Indus onshore, retro-effective 11 Jan ‘16. OGDC (op), partner Govt Holdings.

OGDC secured the Saand D&PL, 1.6 sq km around the Saand-1 gas-cond discovery within the Nim 2568-9 EL block, Lower Indus onshore, OGDC (op), partner Govt Holdings.

As of March 2019, Primoil is farming out a stake in its El Kef permit, onshore Diapir Zone, north-western Tunisia. The company is offering a 40% interest in the block in exchange for a USD 14 million investment. Primoil and former partner Oil Search (Tunisia) Ltd were awarded the permit in May 2008. In November 2012, Primoil was granted a two-year validity extension of the first exploration period and in August 2015, the company entered into the second exploration period. Primoil holds a 50% interest in the permit. The Tunisian state company Etap holds a 50% carried interest. El Kef covers 2,836 sq km. Commitments of the first exploration period were the drilling of one exploration well to a depth of 3,000 m, the acquisition of 200 km of 2D seismic or 3D equivalent and the reprocessing of 600 km of existing 2D seismic data for a total expenditure of USD 5 million.  The seismic acquisition was completed in 2010. Primoil has drilled one well in its permit in 2014: Secca Veneria 1 (SCV-1). The well had a planned TD of around 3,500 m and targeted reservoirs in the Lower Cretaceous. Industry sources indicated that in November 2017 Primoil re-entered SCV-1. The company intended to side-track the well for testing as during the initial drilling technical difficulties prevented a test. It is assumed that operations were completed in the second quarter of 2018 and that the test was not a success. The Le Kef block is located in a geologically complex area renowned for numerous oil seeps. Cretaceous and Tertiary reservoirs are present and form trap geometries as a result of folding, thrusting and Triassic salt movement. Mature Cretaceous and Tertiary source rocks are present to charge the reservoirs with oil.

Primoil is farming out a stake in its El Kef permit, onshore Diapir Zone, north-western Tunisia. The company is offering a 40% interest in the block in exchange for a USD 14 million investment. Primoil and former partner Oil Search (Tunisia) Ltd were awarded the permit in May 2008.

Block 23(a), Tobago Basin, WD ca, 2,000m, ‘hydrocarbons’ reportedly encountered as in earlier Belé-1 in same block, still no details (or too early thereto), Deepwater Invictus DS. Hi Hat-1 is also planned, likely an appraisal to Bongos-2 in the TTDAA 14 block. BHP (op), partner BP.

Tuk 1 (BHP op. 70%, partner BP 30% in Block 23(a), Tobago Basin, WD ca, 2,000m, ‘hydrocarbons’ reportedly encountered as in earlier Belé-1 in same block, still no details (or too early thereto). Operator, has not commented on the well, nor has it confirmed a discovery.

On 15 June 2018, the State Agency for Geology and Subsoil Use of Ukraine announced an auction for two blocks in Lviv and Sumska Oblasts. The auction is scheduled for 25 October 2018 with its application deadline on 28 August. The winners of the auction will obtain 20-year E&P licenses. Additional information can be requested from: Kiev Antona Tsedika Str., 16, offices 415 & 416 Tel: (044) 536 1320 and 456 6085 The Surmachivska block with oil, gas and condensate resources covers 1.46 sq km in Sumska Oblast (Dnieper-Donets Basin). The starting price amounts to UAH 7.620 million (USD 0.29 million). The price for the auction documentation and geological data package is UAH 0.527 million (USD 0.02 million). The Yavorivska block with oil, gas and condensate resources covers 43.8 sq km in the North Carpathian Basin. The starting price amounts to UAH 25.964 million (USD 1 million). The price for the auction documentation and geological data package is UAH 0.211 million (USD 0.01 million).

On 15 June 2018, the State Agency for Geology and Subsoil Use of Ukraine announced an auction for two blocks in Lviv and Sumska Oblasts

Medco agreed to acquire 100% interest in the North Sokang PSC, located in the East Natuna Sea, from previous operator Black Platinum Energy, on 23 July 2019. The deal is subject to government approval. This acquisition will expand Medco’s acreage East Natuna, which also includes the South Sokang PSC and a part of the South Natuna Sea Block B PSC. In early August 2019, the company reported plans to conduct exploration activities in the area in 2019/2020. The North Sokang PSC includes the Dara 1 gas discovery. Black Platinum was previously planning to drill up to two wells to appraise the discovery, subject to finding a farm-in partner. As of March 2018, the discovery was estimated to contain in-place resources of 1,495 Bcfg. A major risk associated with exploration in the area is the high CO2 content in the gas, however the shallower reservoirs (above 800 m) have been found to contain low contamination. According to a Preliminary Plan of Development released by Black Platinum in 2018, potential commercial scenarios for future gas production from the Dara field include the domestic market via a Floating LNG (FLNG) facility or a new-build pipeline to Natuna island. Another option under consideration was sale to Singapore via the West Natuna Transportation System. Background Information On 22 September 1997, the North Sokang block, with an area of 10,260 sq km, was awarded to Total after a period of direct negotiations and upon payment of bonuses of USD 1.25 million. The PSC carried a firm Work Obligation of USD 24.8 million in the first three years and USD 64 million in 10 years. Prior to Total, the block was part of the South Natuna Sea Block B, awarded to Conoco in 1968. Only two wells had been drilled within the block limits at that time, both on its southern margin by Conoco in 1974 and 1975. The first, Antoni 1, was abandoned as a sub-commercial gas discovery but the second, Teri 1, flowed 7.2 MMcf/d. It is believed that the gas in both wells contained a high CO2 ratio. Total completed a 67 km 2D seismic survey over the block in August 1998 following the completion of an earlier 3D programme in July 1998. In 2000, Total conducted a two-well drilling campaign with Dara 1 and Dara 2. Both wells encountered gas which was deemed non-commercial due to the high CO2 content. Total relinquished the block in September 2001. The North Sokang block was again offered on 20 May 2010 as part of the First Petroleum Bidding Round 2010 under the direct offer mechanism. The block covered an area of 5,466 sq km in shelf waters, with maximum depths of around 130 m. The block was officially awarded on 26 November 2010. Firm commitments for the first three years of exploration included G&G studies (USD 0.70 million), 800 km 2D seismic acquisition (USD 1.5 million) and drilling of one exploration well (USD 8.0 million). Dara exploration history Dara 1 was plugged and abandoned on 12 May 2000 by Total as a non-commercial gas discovery with 12-88% CO2. About 25.5m of net gas pay was encountered and it targeted Upper Miocene deltaic sands. The well was spudded on 19 March 2000 and was drilled to a TD of 2,375m, short of the PTD at 3,036 m. Dara 2, located 25 km west of Dara 1, was abandoned by Total on 17 June 2000 with non-commercial gas volumes encountered. Gas is believed to have contained 70-80% CO2. The well was spudded on 15 May 2000 and was drilled to a TD of 1,500 targeting Pliocene deltaic sands. Black Platinum’s first well Dara 3 well was a successful gas appraisal well drilled in the block during 2012. The well was plugged and abandoned in late November 2012. The well intersected 18m of net gas pay and tested 9 MMcfg/d, with 1.9% CO2 and no water, from stacked Upper Pliocene deltaic sandstones of the Muda Formation. Bypassed gas was targeted from these sands, which could have thicknesses of 1 to 10 m each, and Dara 3 has proven the viability of this play, with low CO2, in the area. Dara 3, located within the vicinity of the Dara 1 discovery well, was spudded on or around 31 October 2012 and was drilled to a TD of 970 m, slightly deeper than the PTD of 960 m, using the using the Diamond Offshore “Ocean General” S/S. It is the second of two planned appraisal well campaign in the block, immediately following the Dara 4 well. Dara 4 appraisal well was plugged and abandoned in late October 2012. Net gas pay of 5 m was encountered from the primary Pliocene sand objective but it was likely non-commercial as no DST was conducted. A gas sample with 1.3% CO2 was recovered from one of the Pliocene sand units. The well, located 2.7km southeast of the Dara 2 appraisal and 18km west of the Dara 1 gas discovery, was spudded on or around 11 October 2012 and was drilled to a TD of 770 m. It had a PTD of around 740 m and had similar targets as with the Dara 3 appraisal well. Dara 4 fulfilled the firm one well drilling commitment for the block. Dara is a large four-way dip structure. The Dara 2 and Dara 4 wells were drilled in the central part of the structure, while Dara 1 and Dara 3 were drilled in the eastern part.

Medco agreed to acquire 100% interest in the North Sokang PSC, located in the East Natuna Sea, from previous operator Black Platinum Energy,

Cooper Energy (MGP) Pty Ltd was awarded exploration permit VIC/P76, located in the Otway Basin, on 17 September 2019.  The permit has been granted for an initial six year period and will expire, or be eligible for renewal, on 16 September 2025. Work commitments have been assigned for the duration of the permit’s validity. In the initial three years, which form the guaranteed work commitment period, Cooper Energy will undertake well planning and the drilling of one exploration well, at an estimated cost of AUD 30 million.  Geological and geophysical studies, including well analysis, are scheduled for year four. Additional geological and geophysical studies are outlined for year five, between September 2023 and September 2024.  In the final year, another exploration well, also at a cost of AUD 30 million, is scheduled. The total estimated cost for the six year work programme is AUD 61.4 million. VIC/P76 was awarded after being offered as block V18-1 in the 2018 Offshore Federal Acreage Offer. It is the second permit awarded to Cooper Energy from the 2018 Acreage Offer, with VIC/P75, located in the Gippsland Basin, awarded on 2 September 2019. The VIC/P76 permit lies adjacent to VIC/P44, in which Cooper made the Annie gas discovery in September 2019. VIC/P76, which covers an area of 162 sq km, was awarded on 17 September 2019.  Cooper Energy (MGP) Pty Ltd holds 100% interest and operatorship of the permit.

Australia (Otway B.) Cooper secured sole rights to VIC/P76 (162km²) undrilled offshore block, WD=60-70m. It is surrounded by the Minerva, Casino, Henry and Netherby gasfields and abuts the recent Annie discovery.

Deep shale gas well in Dazu-Rongchang block, Sichuan Basin, tested 16 MMcfg/d from below 3,900m in the Longmaxi fm.

Zu 202-H1 Deep shale gas well in Dazu-Rongchang block, tested 16 MMcfg/d from below 3,900m in the Longmaxi fm.

On 12 November 2018, Abdallah Azhari, oil minister of Sudan reportedly announced that a bid round for 30 to 35 blocks is in preparation and that it would be launched in the third quarter of 2019. The authorities hope that thanks to improved relations with the United States, interest of foreign oil companies in Sudan will increase. Azhari pointed out that the ministry will welcome E&P players without discrimination and with policies that will facilitate their investments. Currently, the oil ministry applies a first come first served policy for exploration acreage. Sixteen blocks are available, see separate article.

Sudan, not found

On 3 October 2018 Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd had signed a Heads of Agreement with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.665% interest each in PEDL 183. The licence is located in East Yorkshire and contains the West Newton A-1 gas discovery. There are also plans to drill the West Newton B appraisal well in Q1 2019. The deal was announced to have been completed on 3 December 2018. West Newton B will be located approximately 1.5 km south of the 2013 West Newton well. It is planned to target three potential Permian reservoirs in the Brotheran, Kirkham Abbey and Cadeby formations. The well has a planned TD of 2,000 m to the base of the Permian section. It was initially planned to be drilled with the KCA Deutag T-61 rig. In November 2017 Rathlin confirmed that it still plans to drill the well and in December the company stated that it is currently out to assess and determine rig availability. Drilling is planned to take 6 - 12 weeks where the company is not planning to test any shale horizons (TD likely to be 1,000 m above the Bowland Shale) estimated to be deeper than its Permian targets. It is hoped that the well will determine the commerciality of the discovery. In an update from the company on 17 June 2015 it confirmed that East Riding of Yorkshire Council has granted planning permission for the well. On 26 November 2015 Rathlin announced that it was pleased that the planning committee has unanimously approved the planning application for an extension at West Newton A. Following the well encountering gas the company can move forward with investigating the commerciality of the discovery within the Permian Kirkham Abbey Formation. On 26 July 2016 the OGA confirmed that the Environment Agency has granted a permit for the drilling of the well. In 2013 Rathlin Energy drilled with West Newton 1 (A) well. The well was drilled to a TD of 3,150 m into the Dinantian Carbonate section in the Carboniferous and was tested. The well was located north of West Newton and east of Marton in the parish of Aldbrough, East Riding Yorkshire. It had a primary target based from 2D mapping and is a Permian aged Caedby Carbonate reef. The source rock potential is present within the Permian basinal sediments, the Westphalian coal measures and the Bowland shale sequence. PEDL 183 was awarded in the 13th Onshore Licensing Round and covers an area of 913 sq km. Interest in the licence following the deal is held by Rathin Energy (66.67% + operator), Humber Oil and Gas (16.665%) and Union Jack Oil Plc (16.665%).

Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd had signed a Heads of Agreement with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.665% interest each in PEDL 183.

LLA-32, Llanos Basin, drilled and abandoned this summer, no further details. Parex (op), partner Winchester O&G.

Herradura 1 (Parex (op), partner Winchester O&G) in LLA-32 block, P&A this summer, no further details.

Hitherto unreported, Anadarko and Cove Energy have withdrawn from the deepwater Lamu Basin blocks L11A, L11B and L12. Anadarko withdrew as of 31 May ’17, leading to Eni taking over operatorship. Cove withdrew in 3Q ’17. The partners had been planning to drill the Mlima prospect in in L11B. Current interests: Eni (55%, op), partner Total (45%).

Total has agreed to acquire interests in 3 offshore Guyana Basin blocks, marking its entry into the country: -Canje ,to acquire 35% from JHI Associates - remaining partners ExxonMobil (35%, op) and Mid-Atlantic O&G (30%)

Service well in SE Búzios field area, Santos pre-salt, WD 2,104m, oil encountered in May (DEA 12 May) (208m column below 5,400m), oil shows report again to ANP on 10 June, ops continue, ODN I DS. Petrobras (op), partners CNOOC + CNODC. Map here.

9-BUZ-39DA-RJS (Petrobras 90% op., CNOOC 5%, CNODC 5%), Service well in SE Búzios field area, southeastern part of the Buzios block, Santos pre-salt, WD 2104m, oil encountered (208m column below 5400m), ops continue, shows report again to ANP on 10 June.

Lundin Petroleum has acquired a further 10% interest in PL539 from exiting partner Fortis Petroleum, effective on 15 February 2018. At the same time Lundin has acquired an additional 10% interest in PL860, adjoining NW of PL539. Lundin previously acquired its 10% interest in PL539 from Fortis Petroleum on 19 October 2017, alongside its initial acquisition of 10% interest in neighbouring PL860. The North Sea licence is 5km W of Trym gas and condensate field on the Central Graben South, and adjacent to the maritime boundary with Denmark. Awarded in APA2009 on 19 February 2010, PL539 originally covered 191 sq km over block 3/7, latterly reduced to 123 sq km. The licence contains the Myrhauk NFW 3/7-10 S (2015, Premier, 3,511m) which was P&A dry after it failed to encounter its primary objective the late Jurassic to Early Cretaceous Ula/Vyl Formation, whilst the Middle Jurassic Bryne Formation secondary objective was uncharged. Det norske acquired previous operator Premier Oil Norge in January 2016. MOL entered the licence in September 2015 via its purchase of Ithaca Petroleum Norge, then acquired the PL539 interests previously held by Suncor (20%), KNOC/Dana (12%), Statoil (20%), and Aker BP (previously Det norske) (40 + Op). On 18 May 2017 then 100% operator MOL, farmed out 20% to Fortis Petroleum. Revised PL539 licence participants are MOL Norge AS (80% + Op) and Lundin Norway AS (20%).

Lundin Petroleum has acquired a further 10% interest in PL539 from exiting partner Fortis Petroleum,

From 6 November to 9 to 27 January 2018, Oil & Gas Development Central Kft (OGD), subsidiary of Sand Hill Petroleum BV, drilled and abandoned unsuccessful new-field wildcat Derecske Nyugat 1 in the Berettyóújfalu concession in eastern Hungary. The well, solely drilled by OGD, reached the final depth of 2,428 m, failed to encounter hydrocarbons and was plugged. The well Derecske Nyugat 1 is located in the northwestern sector of the Berettyóújfalu block. The tract is located in the Hajdú–Bihar political province, close to the border with Romania, within the Hajdusag Sub-basin, tectonic unit of the Pannonian Basin. The well likely had a planned final depth of approximately 2,430 m, targeting gas-charged units of the Lower Pannonian succession. Background Information The 825.2 sq km Berettyóújfalu block was awarded to OGD on 15 February 2016, upon the signing of the contract by the Minister of National Development. The award was the result of 2015 bidding round (the tender was opened on 14 April 2015 and closed on 23 September 2015). The Berettyóújfalu contract is valid for twenty years from the effective date, with one possible 10-year extension.

Derecske Nyugat 1 (Sand Hill Petroleum 100%) in Berettyóújfalu concession, P&A, unsuccessful.

M Vest Energy has exited Norwegian Sea PL796 assigning its 20% to Equinor effective 29 June 2018. PL796 covers 253 sq km over blocks 6407/2, 3, 5 & 6, and surrounds the Mikkel Field. The PL796 acreage contains dry well 6407/3-1 S (2011, Statoil) in the N, and the non commercial Cortina gas discovery well 6407/5-2 S (2011, OMV) in Jurassic Rogn, Melke and Garn formations in the SW. It was awarded on 6 February 2015 in APA 2014 with a drill or drop option which was confirmed in February 2018. The enclosed Mikkel Field is licensed via PL121 (Equinor Op), came online in August 2003 and produces gas and condensate from Jurassic sandstones in the Garn, Ile and Tofte formations. M Vest Energy entered PL796 and six other licences when it acquired Atlantic Petroleum's Norwegian subsidiary on 22 January 2017. Revised PL796 partners are Equinor Energy AS (60% + Op), EDF subsidiary Edison Norge AS (20%) and Point Resources AS (20%).

Equinor (->60% op, Edison 20%, Point Res. 20%) has acquired 20% interest in PL 796 from M Vest (->0%)

On 5 March 2020, Frontera Energy Corp indicated that the Contrapunteo 1 outpost well on CPE 6 Block in the Llanos Basin found oil and that it has been completed. The Contrapunteo 1 outpost well spudded on 13 November 2019 and it reached a total vertical depth (TVD) of 3,038 ft (926 m) presumably in December 2019. The well was targeting the “C7” Oligocene sandstones of the Carbonera Formation, and it is the second appraisal well drilled to delineate the Coplero 1 discovery. The first one was the Galope 1 outpost well. The 2,399.85 sq km CPE 6 Block is owned and operated by Frontera with 50% working interest and Repsol with the remaining interest. The block was officially awarded in September 2011 to operator Meta Petroleum Ltd with 50% working interest and partner Talisman Oil & Gas Ltd with the remaining interest. In May 2015, Repsol acquired Talisman and therefore became partner in the CPE 6 Block, and in December 2017 Meta Petroleum changed its name to Frontera Energy. Background Information The CPE 6 Block is located along the heavy oil trend, about 70 km southwest of the Rubiales/Quifa Fields. The block has relatively good 2D seismic coverage and 3D only to the northern part where the Hamaca field and Coplero discovery are located. The Hamaca field was discovered by the Manacacias 1 new-field wildcat (NFW) spudded on 19 April 1989 and completed on 10 May 1989. The NFW reached a total depth (TD) of 3,925 ft (1,196 m) and the main target were the Oligocene sandstones of the Carbonera Formation. The Hamaca field is online since December 2013 and as of end of 2019 it has produced 2.3 MMbo. In August 2019 Frontera confirmed oil in the Coplero 1 NFW well on the CPE 6 Block, about 6 km southeast of the Hamaca field. The NFW spudded on 27 July 2019 and on 30 July 2019, it reached a TD of 3,150 ft (960 m). The Coplero 1 encountered 8 ft (2.4 m) oil pay in the Oligocene sandstones of the “C7” Member of the Carbonera Formation where logging revealed a clean sand system with 32% porosity. On 27 September 2019, Frontera spudded the Galope 1 outpost, on the CPE 6 Block, to evaluate the Coplero discovery. The well reached a TD of 8,126 ft (2,477 m) and encountered 10.5 ft (3.2 m) of net oil pay in the Oligocene sandstones of the “C7B” Member of the Carbonera Formation. The well is assumed to have been completed and tested in December 2019.

Contrapunteo 1 (Frontera Energy 50% op. Repsol 50%) on CPE 6 Block disc oil in “C7” Oligocene sst. of the Carbonera Fm.

Ascent Resources announced on 14 April 2020 the acquisition of Energetical Limited, a UK company. It will issue six million new ordinary shares to the selling shareholders and pay USD 566,718 (£450,000) upon execution of the Production Sharing Contract (PSC) for the onshore Block 9B with CUPET. Energetical has a Memorandum of Understanding (MOU) with the NOC for the PSC, but not official date as to when it will be signed has been announced. The operator is currently in negotiations with CUPET to participate in more onshore blocks, more details have not been released. Block 9B: holds fields Majaguillar and San Anton, located on the North coast of Cuba, some 120 km East of Havana and currently produces 190 bbls/d gross from three wells, eight have been drilled, another three wells are shut in due to the lack of basic equipment such as pumps. Part of the wells have deteriorated with age due to old completion techniques and lack of investment. Wells have not produced any water and no oil water contact has been found. According to the press release, the operator evaluated that the addition of basic equipment and reservoir management will improve recovery rates. Possibly new deviated wells in the crest of the fields could flow around 1,000 bo.d. There are no plans for seismic, and not need is foreseen.

Ascent Resources announced on 14 April 2020 the acquisition of Energetical Limited, a UK company. It will issue six million new ordinary shares to the selling shareholders and pay USD 566,718 (£450,000) upon execution of the Production Sharing Contract (PSC) for the onshore Block 9B with CUPET.

On 8 June 2017 ADX Energy reported it has agreed to buy the 4.7 sq km DEE V-19 Iecea Mare licence from Amromco Energy.  This licence is situated within ADX Energy’s E X-10 Parta exploration licence. The deal is valued at USD 35,393 + 5% royalty on production. The company’s plan is to re-drill two wells - Carpinis 55 and Iecea Mare 35 - to test 33 Bcfg of prospective and contingent resources. The re-drill of Carpinis 55 – which will be named Iecea Mica 2 - is engineered as a simple vertical well. The drilling is planned to start during Q4 2018. The permit is located in western Romania. Amromco was awarded to the company in 2004. The licence contains the Iecea Mare oil and gas field which was discovered in 1985 and put onstream in 1986. Its reservoir is situated below 2,000 m in the Paleozoic. In 1998 the field considered as depleted was shut-in. In 2005 Amromco started gathering information in order to launch field enhancement programme but finally the production at the Iecea Mare field did not resume. Interest in the DEEV-19 Iecea Mare licence will be held solely by ADX Energy Panonia SRL.

ADX Energy reported it has agreed to buy the DEE V-19 Iecea Mare licence from Amromco Energy.

Cluff advises it has extended by a week an exclusivity agreement with an unknown farminee to complete negotiations around P2252 in the SNS. The farmout has npw to be registered by 6 Feb ‘19. P2252 contains the Pensacola prospect.

Cluff advises it has extended by a week an exclusivity agreement with an unknown farminee to complete negotiations around P2252 in the SNS. The farmout has npw to be registered by 6 Feb ‘19. P2252 contains the Pensacola prospect.

Pan Orient has completed a well test on a discovery well L53 DD1 in the L53/48 concession, onshore Chao Phraya Basin. The well has been converted to a producer after the completion of the 90-days production testing on the new-field wildcat on 18 February 2019. The daily oil production for L53 DD1 is around 530 barrels, based on the reported cumulative production from 21 November 2018 to 10 February 2019. L53 DD1 was temporarily shut-in until Production License was granted on 25 April 2019. The well was reported to have flowed at an average rate of 645b/d of oil within the “DD” sand, from 21 November to 9 December 2018, prior to shut-in for a workover. On 12 December 2018, production commenced from the “CC” sand using a beam pump with average oil production of 504 b/d. The oil production from “CC” sand increased to 756 b/d using an electrical submersible pump from 16 January to 10 February 2019. Located 5 km south of the U Thong oilfield, the deviated wildcat was drilled to a total depth of 1,373 m (1,323 m TVD) on 22 October 2018. The well was immediately appraised by L53 DD2 well, which has also temporarily shut-in after a completion of 90-day production test. The measured density of the oil in L53 DD1 is approximately 24 degrees API gravity with Basic Sediment and Water (BS&W) of 0.4%. The DD sand is the deepest of three oil bearing sands and represents 8 m of the 26 m of total interpreted net oil pay encountered in the well. The well encountered a combined 26 m of net oil pay from three zones across 165 m interval (960-1,125 m TVD), interpreted from wireline logs. The other two reservoirs, “BB sand” and “CC sand” share the same oil-water contact with the L53-DD2, which is 24 – 29 m structural high than those in L53-DD1. The reservoirs quality is excellent with high permeability which was confirmed by pressure data and oil samplings from each of the zones. The completion of L53 DD1 has fulfilled the USD 600,000 minimum annual expenditure that is required to retain the 214 sq km of the L53/48’s ‘Exploration Reserved Area’. The previous exploratory well, L53-AC-C1 was abandoned on 31 December 2017, with oil shows. A fluid sampling determined the oil shows area to be dominantly water-bearing reservoir. The L53/48 concession produced at approximately 455 b/d of oil in October 2018, as compared to 505 b/d of oil in late 2017. The concession holds a 2P crude oil reserves of 546,500 barrels from the Lower Miocene sandstone reservoir, excluding the exploration area (As of 31 December 2017). The L53/48 concession is fully owned and operated by Pan Orient (Siam) Ltd, which is in turn controlled by Pan Orient Energy Corp (50.01%) and Sea Oil Public Company (49.99%). The exploration Area A and B will expire in January 2021, after which the production areas (A, B, D and G) will be retained. Background Information The L53/48 block lies onshore in the Kamphaeng Saen Sub-basin of the Chao Phraya Basin, around 50km WNW of Bangkok. The area is covered by at least 580 sq km of 3D seismic data which were acquired since 2007. Seven minor oil discoveries were encountered from 2009 to 2013 with estimated total recoverable reserves of approximately 25 MMbbl. As of December 2018, a total of three fields are producing (L53-A, L53G, L53-D East), two are developing (L53-B and L53-DD) and another two fields are appraising (L53-D and L53-D C-EXT). The oils were trapped in the Lower to Middle Miocene structural play sealed by Middle Miocene Series mudstone. The reservoirs were deposited in lacustrine environment. The block also covers an area that was previously partially covered by BP’s B04/27 and Britoil’s Block BT concessions. It encompasses and excludes the Kampheang Saen field (previously called Neung), which was discovered by BP in February 1987. The original 3,997 sq km L53/48 block was awarded to Pan Orient Energy on 8 January 2007 as the operator and sole interest holder, under the 19th Licensing Round. The concession agreement allows Pan Orient to explore for hydrocarbons over a period of six years with a minimum three years first phase commitment of approximately US$ 2.1 million, which includes 3D seismic acquisition and two exploratory wells. On 2 February 2015, Pan Orient Energy Corp closed the sale of 49.99% of its own equity interest in Pan Orient (Siam) Ltd, which is in turn operator of the concession, to Sea Oil Public Company. With all conditions being met, Sea Oil transferred a consideration of USD 38.5 million to Pan Orient. Pan Orient (Siam) Ltd remained operator of the block with 100% interest, as an equally controlled subsidiary of Pan Orient Energy Corp and Sea Oil Public Company. In October 2016, the operator completed a five wells workover program which has increased production from 192 bo/d in August 2016 to 303 bo/d. The December 2016 production from L53-G1 was substantially reduced to approximately 100 bo/d, as a result of a replacement of downhole pump. The focus for the 2017 was to maximize production from the existing wells. In late 2016 and 2017, the operator attempted to find several upside potentials within the Miocene sandstone reservoirs by drilling L53-ANE-A1 and L53 AC C1 in the Reserve Area A. The wells failed to encounter hydrocarbons within the target intervals, which were determined to have excellent quality of sandstones.

Thailand (Chao Phraya B.) L53-D

Retention lease TR/07, 14 sq km in the Caswell sub-basin, and TR/08 (80 sq km) were awarded to COP on 3 Mar '20 for 5 years, the joint area formerly TP/28 containing the 2009 Greater Poseidon gas-cond discovery. COP (op), partners Origin + PetroChina.

Retention lease TR/07, 14 sq km in the Caswell sub-basin, and TR/08 (80 sq km) were awarded to COP on 3 Mar '20 for 5 years, the joint area formerly TP/28 containing the 2009 Greater Poseidon gas-cond discovery. COP (op), partners Origin + PetroChina.

On 3 February 2018 Fogelberg appraisal well 6506/9-4 S was spudded by Spirit Energy. The company used the “Island Innovator” S/S to drill the well in PL 433. 6506/9-4 S is located in a down-dip position, approximately 1 km to the west of the discovery well, with the aim of adding 2P reserves, reducing volume uncertainty and confirming reservoir quality before the licence group commits to a FEED project. The well was drilled to TD at 4,738 m and encountered a 63 m gross hydrocarbon column in the Middle Jurassic Garn Formation and gas in the Middle Jurassic Ile Formation. Reservoir quality is better than that seen in the discovery well and the GWC is deeper. On 28 April 2018 sidetrack 6506/9-4 A was kicked-off from the 14” casing. Two cores were cut (around 4,288 m and 4,316 m) and the well reached TD at 4,497 m. After setting a 7” liner, the company started testing on 25 June 2018. The licence term for PL 433 was extended in February 2017 with a deadline to submit a PDO by July 2019. The PDO was originally expected to be submitted in February 2017. Centrica (now Spirit) received MPE approval for the Environmental Impact Assessment (EIA) for Fogelberg in early 2014. The proposed plan (given at that time) included the installation of a four-slot subsea template (with three producers to be drilled initially) tied-back to either Asgard B or Heidrun. Costs were estimated at either NOK 7 billion (USD 1.18 billion) or NOK 11 billion (USD 1.86 billion) depending on which host facility was chosen. The Fogelberg discovery well (6506/9-2 S) was Centrica’s first as an operator on the NCS and was drilled in 2010. Gas and condensate was confirmed in the Garn and Ile formations with no OWC indentified. The field is HPHT. It lies between Victoria and Smorbukk on the Halten Terrace and has estimated recoverable reserves of approximately 105 – 530 Bcfg. Pending completion of three deals in PL 433 interest will be divided between Spirit Energy Norge AS (51.7% + operator), PGNiG Upstream Norway AS (20%), Faroe Petroleum Norge AS (15%) and Dyas Norge AS (13.3%).

6506/09-04S, 04A (Fogelberg) appr. pos. by Spirit (51,7%, Dyas 13,3%, PGNiG 20%, Faroe Petr.15%) in PL 433 block, N. of Smørbukk field + Åsgard complex, target Garn + Ile fm’s penetrated, 62,5m gross hc reservoir in the Garn + gas recorded in the Ile, reservoir quality better than that encountered in the discovery (6506/09-02S) with deeper GWC, preparing to test, TMD=4738m.

Pursuant to a deal on 25 Oct ’17, Dana has acquired a 50% stake from Dyas in P1896 / blocks 42/27a, 47/2c + 47/3i, total 73 sq km west of Tolmount. P1986 is now held solely by Dana.

United Kingdom, P1896

Petrel has acquired a 10% interest in LO 16/14,  1,579 sq km over blocks 54/11, 54/12, 54/13, 54/16, 54/17 & 54/18 in the Porcupine Basin off SW Ireland, and currently Woodside 100%. The partners have applied to convert the LO into a Frontier Exploration Licence.

Ireland, not found

Acer Energy Ltd, a wholly owned subsidiary of Beach Energy Ltd, acquired a 20% increase in interest in retention leases PRL 173 and PRL 174, located in the Cooper-Eromanga Basin, on 10 September 2018. Acer Energy acquired all of previously joint venture partner Mid Continent Equipment (Australia) Pty Ltd’s interest in the permit, increasing its holding to 100% interest.  The companies had held joint interest since the award of the permits in February 2015. PRL 173 contains the Ginko and Willow fields, which were discovered in 2005 and 2016 respectively.  PRL 174 contains the Crocus 1 discovery, which was made in 2004. PRL 173 and PRL 174 cover a combined area of 154 sq km.  Acer Energy Ltd now holds 100% interest in both permits.

Australia, PRL 173

Mubarak (block 20) 2769-4 EL, Middle Indus onshore, TD 3,610m late August, gas discovery (tested), w.o. results, SLR-15 rig. OMV (op), partners Eni + Govt Holdings.

Pakistan, not found

Saif Energy assigned its 100% interest in the Sari South 2467-9 EL,  535 sq km in the Kirthar Foldbelt, to Zaver Petroleum retro-effective 1 Jan ’18:

Pakistan (Kirthar Fold Belt) Sari

On 10 November 2019, the Iranian Government announced that Iran had made a new discovery named "Namavaran" in Khuzestan Province, south-west Iran. The find, at this time, is presumed to be oil in the Oligo-Miocene Gachsaran or Asmari formations with a thickness of ~80 m which encompass parts of existing fields including Mansuri, Sepehr, Susangerd and Ab-E-Teimur. The new reservoir is understood to have been first encountered by the Ab-E-Teimur 35 outpost well which was drilled in 2016/2017 and then has been subsequently appraised by the recently drilled Mansuri West 1, Sepehr East 1 and Susangerd East 1 exploration wells. Iran has announced additional "reserves" of 22.2 billion barrels of oil, this is believed to be an in-place figure and recovery factors are expected to be low at ~10%.

Press has been rife with reports of a super-discovery in Khuzestan, designated Namavaran and assumed made by NIOC. The fields reservoir reportedly sits at a depth of 3100m with an average thickness of approximately 80m. The massive reserves quoted (53 Bbo) are thought to be attributable to parts of the Mansuri, Sepehr, Susangerd and Ab-E-Teimur fields, in the Oligo-Miocene Gachsaran or Asmari Fm's. The new reservoir would feature an already-respectable 22.2 Bbo of additional reserves, assumed to be in-place, possibly ~10% recovery factor.

PRL 154, Cooper-Eromanga, drilled 24 – 30 Mar '20, TD 1,803m, susp. oil.

Australia, PRL 154

Eni's PSC to the Dumre block was officially awarded on 4 Mar '20 upon gazetting, the assignment having been made last year (DEA 20 Dec '19). Dumre covers 587 sq km south of Tirana in the Ionian Zone, central Albania. An explo well is committed.

Eni's PSC to the Dumre block was officially awarded on 4 Mar '20 upon gazetting, the assignment having been made last year

BP Exploration & Production was awarded Mississippi Canyon blocks MC 956 (G36263) and MC 1000 (G36264) on 1 June 2018. The blocks were originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, BP Exploration & Production is now the operator and sole interest-holder (100% WI + Op) in both MC 956 and MC 1000.

BP Exploration & Production was awarded Mississippi Canyon blocks MC 956 (G36263) and MC 1000 (G36264) on 1 June 2018. The blocks were originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, BP Exploration & Production is now the operator and sole interest-holder (100% WI + Op) in both MC 956 and MC 1000.

In late-July 2018, the government of Rio Negro Province launched a call for tenders for six blocks situated in the Neuquen Basin through a bid round called Concurso Publico Nacional & Internacional 01/2018. The offered areas include the producing blocks of Catriel Oeste and Puesto Prado, which are currently being managed by the provincial company EDHIPSA, along with the blocks of Catriel Viejo, Tres Nidos, Las Bases, and Loma Guadalosa, which currently have no activities due to lack of investment in recent years. Offers will be accepted until 31 August 2018, with the minimum expected investment of USD 60 million over a period of five years for each block. The plan to put the Catriel Oeste (45.24 sq km) and Puesto Prado (43.17 sq km) blocks up for bids was previously announced in February 2018. The former is located in the Northeast Platform part of Neuquen Basin, while the latter is in the Neuquen Embayment part. Both blocks were previously operated by Central Resources before the contracts expired in February 2017 and November 2017, respectively. The Catriel Oeste block includes the field with the same name that was discovered in 1959 by YPF. The field has been in production from a shallow Quintuco reservoir since 1965 with an approximate depth of 850 m. The field has 110 producing wells with about 50 water injection wells and two salt water disposal wells. Meanwhile the Puesto Prado field in the Puesto Prado block was discovered in July 1989 and put on-stream later in the same year as a producer from the Punta Rosada and Lajas Formation within the Cuyo Group. Catriel Viejo (287.4 sq km) and the adjacent Tres Nidos block (89.14 sq km) are both situated in the Northeast Platform part of Neuquen Basin, and previously operated by Medanito up until early-2016 and late-2017, respectively. The Catriel Viejo area includes the Loma Montosa oil and gas field (shut-in in 1989), Barda Alta oil and gas field (shut-in in 2008), Chanar Brea oil discovery (2013), and Catriel Viejo oil and gas field (shut-in in 2015), while the Tres Nidos area includes the field with the same name which was shut-in in 2014. Las Bases block (153.94 sq km) is also situated in the the Northeast Platform part of Neuquen Basin, and included the Las Bases gas and condensate field, which has not reported production since March 2017. The area also included Estancia El Colorado gas and condensate field which was shut-in in 2009. The block was formerly operated by Central Resources up until approximately mid-2017. Loma Guadalosa block (102 sq km) is located in the Neuquen Embayment part of the Neuquen Basin, and includes the oil and gas field of the same name which was temporarily shut-in from 1985 through 2007, and has not reported production since August 2016. The block was formerly operated by Pluspetrol up until late-2016. More information on the bid round process can be obtained from the Rio Negro Province’s Secretary of Energy, with the contact information of [email protected] or +54 0299 4773371. Background Information In mid-June 2018, the government of Rio Negro Province granted an official award to state company YPF for the Cerro Manrique block, following the preliminary award for the block that was granted in late-April 2018. The call for tenders on the block was launched through a round called Concurso Publico Nacional & Internacional No 1/2017 in mid-November 2017.

In late-July 2018, the government of Rio Negro Province launched a call for tenders for six blocks situated in the Neuquen Basin through a bid round called Concurso Publico Nacional & Internacional 01/2018. The offered areas include the producing blocks of Catriel Oeste and Puesto Prado, which are currently being managed by the provincial company EDHIPSA, along with the blocks of Catriel Viejo, Tres Nidos, Las Bases, and Loma Guadalosa, which currently have no activities due to lack of investment in recent years.

Messoyakhskoye Vostochnoye field area, Yamal-Nenets AO, W. Siberia, spudded May ‘17, TD 3,190m (L. Cretaceous), tested up to 11.1 MMcfg/d + 698 bc/d on 14mm choke in reservoir BU21/0 between 2,904-2,909m and likewise from the upper part of BU21/0 between 2,893-2,903m. Meanwhile in July Messoyakhskaya Zapadnaya-203 (spudded Apr ’17) TD’d at 2,600m (M. Jurassic), tested 3.3 MMcfg/d + 15 bc/d, followed by Messoyakhskaya Vostochnaya-309, spudded Jun ’17, PTD 3,200m, currently suspended.  

Russia (West Siberian B.) Messoyakhskaya Vostochnaya 309 op. by MESSOYA (100.0%) in Messoyakhskoye Vost. block

On 21 December 2017 Eni Australia Ltd (Eni) reported that the 32.5% operated interest held by Shell Australia Pty Ltd (Shell) in NT/RL7, covering the Evans Shoal 1 discovery located in the Bonaparte Basin, had been transferred to Eni. All relevant approvals from the Government and joint venture partners, which include Petronas Carigali (Australia) Pty Ltd (25%) and Osaka Gas Australia Pty Ltd (10%), have been granted, taking Eni’s operated interest to 65%. The deal was lodged by the companies on 14 December 2017, and was subsequently completed and registered with the National Offshore Petroleum Titles Administrator (NOPTA) on 21 December 2017. The retention lease covers the 1988 Evans Shoal 1 discovery, estimated to have 2P recoverable wet gas reserves of 6.6 Tcf and 31 MMbc. The lease elapses on 18 August 2019 and, following a variation of conditions that was approved on 18 December 2017, includes approximately AUD 12.5 million of expenditure from the date of award. NT/RL7, which covers an area of 1,764 sq km, was awarded on 19 August 2014.  Participants in the permit are now Eni Australia Ltd (65% + Operator), Petronas Carigali (Australia) Pty Ltd (25%) and Osaka Gas Australia Pty Ltd (10%).  

Eni has taken 32,5% stake from Shell in retention lease NT/RL7 (Evans Shoal gas field) for an undisclosed sum.

On 30 November 2019, SODEPS spudded the Debbech B 1 exploration well in the Debbech permit, Ghadames Basin, southern Tunisia. In early December, the well had reached a depth of 1,068m in the Continental Intercalaire formation and in late December it reached a depth of 2,016m. On 27 February 2020, the well reached its TD at 4,260m in the Lower Ordovician Sanrhar Formation. The well is being logged. Objectives were the Silurian Acacus and Tannezuft formations which were intersected at 3,473m and 3,708 m, respectively. In early November 2019, industry sources indicated that Eni, through the joint venture company SODEPS plans to drill an exploration well in the Debbech permit. The company was to use the rig which was working on the Hawa 1 well in the nearby Adam permit. This is likely to be the continuation of a near-field exploration campaign which saw Sodeps drilling three wells in 2017, one in each concession (Makhrouga, Laarich and Debbech). At least two of these wells were successful. Due to the low oil price environment prevailing since 2015, ENI concentrates on near-field exploration which is less risky and less costly than frontier wildcatting. The well in the Debbech concession was KRDSW-1, it found gas shows and oil in the Acacus A and B sandstones and in the Trias Argilo Greseux Inférieur (TAGI) sandstones. Light oil was also found in the Ordovician. The Debbech permit is operated by Sodeps with a 100% interest. Sodeps, is held by Eni 50% and Etap 50%. In 2012 Sodeps made a discovery with new-field wildcat Kothbane Ramlia Debech 1 (KRD-1) in the Debbech concession. The well was completed as a producer. Oil was encountered in the Acacus and Jeffara formations. KRD-1 had the Triassic TAGI (Kirchaou) and Silurian Acacus as targets. The well was drilled to a TD of 4,302m in the Ordovician Sanrhar Formation.

Debbech B 1 explo. (Societe de Develop. et d'Exploit. du Permis du Sud 100% = JV Eni/ETAP 50:50) in the Debbech permit, reached TD=4260m in the Lwr Ordovician Sanrhar Fm. The well is being logged. Objectives were the Silurian Acacus and Tannezuft Fms which were intersected at 3473m and 3708 m, respectively, no further results were available.

On 4 May 2018, the Federal Agency for Subsoil Use held an auction for the Achi-Su block in Dagestan Republic (North Caucasus). Two local companies submitted bids and Delta-E won the contest with the offer of RUB 13.2 million (USD 0.2 million). The winner of the auction will obtain a 20-year E&P license. Details of the offer are as follows: The Achi-Su block covers 7.6 sq km in the Terek-Caspian Basin and encompasses the depleted Achi-Su gas/condensate field with remaining 1P reserves estimated at 9 Bcf of gas. Available seismic data amounts to 45 km. Achi-Su discovered in 1934 was producing until 2002. In 2003, a previous operator drilled well 150 to 3,112 m aimed at depletion of remaining reserves in the Upper Cretaceous reservoir penetrated at 3,078 m. During an open-hole test (3,066-3,112 m), the well flowed with gas and condensate at rates of 2.9 MMcf/d and 113 b/d through a 5-mm choke. Reservoir pressure was measured at 5,349 PSI indicating a possible separated fault block isolated from producing parts of the field. The well was suspended and it can be completed as a producer by the winner of the auction. The starting price amounted to RUB 12 million (USD 0.19 million).

Russia, not found

Petrosen could be looking to exercise a right to increase its stake in the Sangomar project, in deepwaters of the MSGBC Basin. It currently has a 10% stake in the field project, alongside partners Woodside (op), Capricorn, + FAR. Petrosen could boost up to 18%.

Petrosen could be looking to exercise a right to increase its stake in the Sangomar DW project. It currently has a 10% stake in the field project, alongside partners Woodside (op), Capricorn, + FAR. Petrosen could boost up to 18%.

United today announces the completion of its 20%, Nov ’17  farmin to Tullow’s Walton Morant offshore licence comprising blocks 6, 7, 9, 10, 11, 12, 17, 25, 26, 27, total ab. 32,000 sq km in WD 20-1,000m plus a piece of shallow-water block 1 south of the island, Walton Basin. The deal is effective 1 Mar ’18. Plans include some 2,000 sq km of 3D seismic over the Colibri lead, to start shortly. www.uogplc.com.    

United Oil & Gas has announced the completion of the farm-in and the transfer of the 20 per cent interest in the Walton-Morant Licence, offshore Jamaica from Tullow Jamaica to UOG.

Mumbai High NW Extn. (Add.) ML-Saurashtra block, Bombay offshore, susp. at TD 2,675m, Sagar Vijay released from location 3 Jan '20.

B-218 A expl Mumbai High NW Extn. (Add.) ML-Saurashtra block, Bombay offshore, susp. at TD 2,675m.

Vic/P70, offshore Gippsland Basin / Bass Strait, WD 359m, ops terminated (results yet n/a) on 28 Sep ’18, Ocean Monarch SS off to Hairtail-1 in same block, WD 359m, 45-day well.

Baldfish-1 nfw Vic/P70, offshore Gippsland Basin / Bass Strait, WD 359m, ops terminated (results yet n/a)

On 30 October 2019, the Russian Government published a decree announcing an auction for the Bukharinskiy block of the State Significance in Yamalo-Nenets Autonomous Okrug (Western Siberia). All deadlines and date of the auction will be published shortly. Ownership of licenses in the region and existing or planned LNG facilities are the pre-conditions for applicants. Only Novatek meets the requirements. The winner of the auction will receive a 30-year license with a 10-year exploratory stage. Additional information can be requested from: Rosnedra, 123995, Moscow B.Gruzinskaya Str., 4/6 Tel/Fax: +7 (499) 254-29-11 Email: [email protected] The Bukharinskiy block covers 2,447 sq km including 1,608 sq km in the south-western part of the Gydan Peninsula and 839 sq km in the Ob and Taz estuaries (South Kara-Yamal Province). It encompasses the Bukharinskaya prospect with D0 resources estimated at 33.464 Tcf of gas and 237 MMbbl of condensate. Hydrocarbon resources (categories D1+D2) of the block are estimated at 7.292 Tcf of gas and 351 MMbbl of condensate. The starting price amounts to RUB 2,133.2 million (USD 33 million).

On 30 October 2019, the Russian Government published a decree announcing an auction for the Bukharinskiy block of the State Significance in Yamalo-Nenets Autonomous Okrug (Western Siberia). All deadlines and date of the auction will be published shortly

Santos has increased its interest in WA-01-P by acquiring 22.44% from partner Quadrant in the 402-sq km permit, N. Carnarvon Basin. Equity now Quadrant (op) 55%, Santos 45%.

Santos (-> 45%) has acquired an additional 22, 44% interest in exploration permit WA-01-P from joint venture partner and operator Quadrant NW (-> 55%).

Beach Energy Ltd announced on 19 December 2019 that it had reached an agreement with OMV to farm-in to exploration permit PEP 50119, located in the Great South Basin. Beach is to acquire 30% interest in the permit, in which Mitsui is also a joint venture partner. The deal is subject to various approvals, including that of the New Zealand Government and regulatory bodies. Beach will acquire the 30% interest by funding 30% of the well – and associated operations – costs for the Tawhaki 1 well, which is planned for early 2020. The well will target the Tawhaki oil prospect, which lies in the east of the permit area. The prospect is a basement drape structural trap, with reservoirs thought to be in the Cretaceous Kawau Sandstones. The operator has outlined potential target resources of 1 Bb oil. Tawhaki is planned to be drilled in early 2020 as part of a wider OMV operated drilling programme. OMV was granted marine consent for the well, and others in the programme, as of 16 December 2019. PEP 50119 covers an area of 16,760 sq km and was awarded on 11 July 2007. OMV has been a participant since the permit's award, but increased its interest in 2018 after Shell withdrew from its New Zealand acreage. Once the farm-out to Beach is complete, participants in the permit will become OMV (52.93% + Operator), Beach Energy Ltd (30%) and Mitsui E&P Australia Pty Ltd (17.07%).

New Zealand, PEP 50119

Early November 2017, Tullow Oil plc completed the drilling of the appraisal well Amosing-7 in the Block 10BB. Amosing -7 was the last well of the 2017 drilling programme. Therefore the Marriott-46 rig was demobilised. The well encountered 25 m of net oil and gas pay. No further information was disclosed. Tullow Oil operates blocks 10BB with a 50% interest partnered with Africa Oil with 25% and Maersk Oil & Gas with 25%. Gross unrisked oil resources (2C) South Lokichar Basin are estimated at 754 MMbbl. Tullow and its partners signed the Early Oil Pilot Scheme (EOPS) agreement to transport oil from the South Lokichar fields to Mombasa on 14 March 2017. The EOPS represents an immediate step on the road to full commercialization of the oil resources and it will be followed by a full-scale Field Development Plan. In mid-March 2017, Tullow Oil completed the appraisal well Amosing 6 that encountered 35 meters of net gas and oil pay. The well was drilled near a bounding fault and was spudded early February 2017 with the “PR Marriot 46” land rig. The Amosing 6 was the second well in a four-well drilling campaign in the South Lokichar Basin (Blocks 10BB and 13T), which started in December 2016 and led to the Erut 1 oil discovery in January 2017. The Amosing field has recoverable resources estimated at 151.1 MMbbl of oil, whereas the Ngamia field has 296.7 MMbbl of oil.

Kenya (East African Rift System, Eastern Branch) Erut 1 op. by TULLOW (50.0%, MAERSK 25.0%, AFRICA OIL 25.0%) in Block 13T

On 29 June 2019, Novatek announced that it had signed a Sales and Purchase Agreement with Japanese Mitsui and JOGMEC for a 10% stake in Arctic LNG 2 project in Yamalo-Nenets Autonomous Okrug (Western Siberia). The agreement also foresees a long-term LNG offtake of 2 MMtpa of LNG by Japanese partners. The deal will be finalized after regulatory approvals. Note that on 5 March 2019, Novatek and Total SA signed a Sales and Purchase Agreement transferring to Total a 10% stake at the Arctic LNG 2 followed, on 7 June 2019, by the signature of Sales and Purchase Agreements with CNODC and CNOOC regarding the sale of 10% stakes in the Arctic LNG 2 project to each of Chinese companies. (CNODC is a wholly owned subsidiary of CNPC). Arctic LNG 2 will include three liquefaction trains with capacity of 6.6 MMtpa each installed on gravity-based platforms in the Ob Estuary. The Salmanovskoye (Utrenneye) gas/condensate discovery is the feedstock for the LNG plant. In 2014-2017, Novatek-subsidiary Arctic SPG2 drilled six appraisal wells that resulted at extension of the discovery’s productive area and increase of its reserves. As the end of 2018, the company estimated 3P reserves of the discovery at 67.7 Tcf of gas and 840 MMbbl of condensate and oil. Salmanovskoye, discovered in 1979, is located in the South Kara-Yamal Province in the Gydan Peninsula with a minor extension to the Ob estuary. About 60 identified hydrocarbon accumulations are distributed within the 2,100 m sedimentary section aging from Valanginian to Cenomanian.

Novatek announced that it had signed a Sales and Purchase Agreement with Japanese Mitsui and JOGMEC for a 10% stake in Arctic LNG 2 project in Yamalo-Nenets Autonomous Okrug (Western Siberia).

An oil find was made perhaps a year ago in NW Cuba designated Bacuranao 300L, this reportedly producing 22 API oil since Dec ’17. No further info.

Bacuranao 300L (CUPET 100%) in North Cuban Province, an oil find was made perhaps a year ago in NW Cuba, reportedly producing 22° API oil since Dec ’17. No further info.

CNH-R01-L03-A13/2015 contract, Mayacaste block, onshore Sureste Basin, PTD 2,700m, P&A dry in mid-Jan.

Mayacaste 101EXP npw. (Mayacaste O&G 100%) in CNH-R01-L03-A13/2015 contract, Mayacaste onshore block, PTD=2 700m, P&A dry.

Block 15/06, $Deepwater Congo Fan, WD 1,076m, TD 4,050m, light oil discovery, 65m gross, 45m net pay of 35 API oil in Oligocene sst, up to 250 MMbbl OIP with further upside, Poseidon DS. Estimated production capacity >10,000 b/d. Of note, Ndungu is the 1st significant oil discovery inside an already-existing devt area, promoted last year using a favourable legal framework on additional exploration activities within existing devt areas. Eni (op), partners Sonangol P&P + SSI Fifteen Limited.

N’Dungu 1 (Eni 36,84% op. Sonangol 36,84%, SSI Fefteen 26,32%) in Block 15/06, light oil discovery, 65m gross, 45m net pay of 35° API oil in Oligocene sst. with excellent petrophysical properties, up to 250 MMbbl OIP with further upside. Estimated production capacity >10 000 bo/d. Of note, Ndungu is the 1st significant oil discovery inside an already-existing devt area, promoted last year using a favourable legal framework on additional exploration activities within existing devt areas. WD=1076m, TD=4050m.

Todd Petroleum Mining Co Ltd and partner Beach Petroleum (NZ) Pty Ltd, wholly owned subsidiaries of Todd Petroleum Mining Co. Ltd and Beach Energy Ltd respectively, are offering a farm-in opportunity for exploration permit PEP 57080, located in the offshore Taranaki Basin. The companies each hold 50% interest and are offering up to 33% equity to assist in funding the Stage 2 work commitments, due before 1 April 2020. A contingent well is due to be drilled before 1 April 2021. Under the renegotiated terms of the work commitments assigned to the permit which were approved on 12 October 2018, the commitments for Stage 2 includes the requirement to purchase 250 km of multi-client 2D seismic data, the reprocessing of a minimum of 75 km of 2D seismic data for AVO, a fault seal study for prospects within the Nimitz 3D data, as well as completing charge and flow path modelling for leads within the Nimitz 3D data, a lead prospectively study, a structural reconstruction study, and to test post-processing techniques on full and angle stack volumes of the Nimitz 3D as secondary deliverables. Todd has expressed potential willingness to farm-down a portion of PEP 38602, which contains the Karewa discovery, to progress exploration and appraisal of the Northern Taranaki Graben The primary plays in the permit are fault bounded Eocene Tangaroa Formation basin-floor fan sands, with secondary targets in the Paleocene and Cretaceous stratigraphy. Regional data suggests porosity values of 13-22%, average permeabilities of 83 mD and a net to gross of 50-85% can be expected within the Tangaroa Formation sandstones. One of the principal prospects is the Kokako structure, a three-way dip closed target with 360 m of structural closure.  The Korimako structure, a three-way dip closed and fault bounded structure, is also prospective at the Tangaroa Formation level. Both prospects have thrust closures. Mean prospective resources for Kokato and Korimako prospects are 500 Bcf of gas and 25 MMbbl of condensate, and 684 Bcf of gas and 34 MMbbl of condensate respectively. Syn-rift coals and mudstones of the Cretaceous Taniwha Formation are the inferred source of hydrocarbons. The formation is expected to be approximately 1,000 m thick below Kokako and Korimako which have access to a large source kitchen located to the south of the permit. Potential seal is provided by tight carbonates and marls of the latest Oligocene to earliest Miocene Tikorangi Formation, the latter a proven sealing lithology in the basin. The formation is expected to be at least 50 m thick over Kokako and Korimako and is considered low risk. Todd reported that velocity analysis has suggested overpressure at the Kokako prospect. The D1 and D2 deepwater Eocene slump leads offer further upside. These were originally estimated to contain P50 oil originally in-place of 650 MMbbl and 495 MMbbl respectively. In the event of a success, the development and facilities concept may include a fixed platform, deviated development wells, co-mingled production piped to shore, horizontal directional drilling shore crossing, a high capacity onshore processing facility, onshore compression and tie-in to the Maui Pipeline. PEP 57080 covers an area of 2,446 sq km and was awarded on 1 April 2015 after being applied for in the Block Offer 2014.  Participants in the permit are Todd Exploration Management Services Ltd (50% plus operatorship) and Beach Petroleum (NZ) Pty Ltd (50%). Interested parties should contact: Ian Brewer - Todd Energy      Email: [email protected]                   Tel: 0064 27 5345 548

Todd Petroleum Mining Co Ltd and partner Beach Petroleum (NZ) Pty Ltd, wholly owned subsidiaries of Todd Petroleum Mining Co. Ltd and Beach Energy Ltd respectively, are offering a farm-in opportunity for exploration permit PEP 57080, located in the offshore Taranaki Basin.

Equinor confirmed on 8 June 2018 that it has agreed a deal to transfer 20% of its interest in PL 167 to Spirit Energy. The deal follows the announcement of the successful Lille Prinsen exploration well (16/1-29 S) in the same licence. The licence also contains the 2003 Verdandi oil and gas discovery directly above Lille Prinsen. Lille Prinsen was discovered by exploration well 16/1-29 S which had Triassic / Lower Jurassic objectives. The well encountered a 95 m oil column in the main segment (17 m was in clastic rocks of moderate to good reservoir quality) with a OWC at 1,947 m TVDSS. A separate 30 m oil and gas column was proven in the Eocene Grid Formation. Thin sandstone layers (totalling 10 m) of very good reservoir quality comprise the main reservoir with a GWC at 1,436 m TVDSS and a OWC at 1,472 m TVDSS. Volumes in this segment were not evaluated however estimated recoverable reserves for the main segment, which is considered to be commercial, range from 16-35 MMbo. The well was abandoned on 3 June 2018. Verdandi was drilled by Statoil with exploration well 16/1-6 S. Oil and gas were proven in the Eocene Grid Formation, gas was present in the Paleocene Heimdal Formation and the well reached TD at 1,997 m in the Ekofisk Formation. A sidetrack was drilled to further delineate the Heimdal Formation downdip but the reservoir was significantly deeper and thinner than expected and the well was abandoned as a dry hole. The discovery was appraised by the Lille Prinsen discovery well (16/1-29 S). It encountered a 15 m gas column in the Paleocene Heimdal Formation but no GWC was penetrated. The results were as prognosed and the estimated recoverable reserves for Verdandi remain unchanged. Following completion of the deal interest in PL 167 will be divided between Equinor Energy AS (60% + operator), Lundin Norway AS (20%) and Spirit Energy Norge AS (20%).

Equinor confirmed that it has agreed a deal to transfer 20% of its interest in PL 167 to Spirit Energy. The deal follows the announcement of the successful Lille Prinsen exploration well (016/01-29 S) in the same licence.

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%).

On 15 February 2018, Doriemus Plc announced that is has completed its due diligence relating to the acquisition of interest in Rey Resources Ltd’s production licence L 15 (West Kora). The company now plans to seek finalisation of the previously reported farm-in agreement and joint operating agreement. Dorieums also reported that it has been concurrently completing due diligence on exploration licence EP 487, which is also aims to enter. The due diligence period expires at the end of February. Doriemus announced on 31 December 2018 that it had entered into a farm-in deal with Rey Resources for the two Canning Basin permits: exploration permit EP 487 (Derby Block) and production licence L 15 (West Kora). The companies signed two independent binding letters of intent for Doriemus to acquire 50% interest and operatorship in both assets. To acquire 50% interest and operatorship in L15, Doriemus must fund up to AUD 1 million in development costs associated with bringing the Kora West field back into production over the first 12 months. Doriemus reported that funds were already available to complete due diligence, which has now been completed. The additional spend could be raised from a combination of cash reserves and production revenue from its 20% interest in the Lidsey oil field, located in the Wessex Basin, UK. L 15 is 100% by Gulliver Productions Pty Ltd and covers an area of 165 sq km over the Kora West field. The field was discovered in 1984 and produced around 20,000 bbl oil between 1989 and 1992. With 2P recoverable reserves of nearly 400,000 bbl, Doriemus plans to bring the Kora West field back into production by around May 2019. To acquire 50% interest and operatorship in EP 487, Doriemus must first engage an independent consultant to reassess the volumetrics of the Butler Prospect and look at drill options to test the play down to around 4,000 m, in Q3 2019. Doriemus has a 60-day due diligence period before entering into a joint operating agreement. After 12 months, and completion of agreed deal terms, Doriemus will be assigned 50% interest in EP 487. EP 487 is 100% owned by Rey Resources’ subsidiary company Gulliver Productions Pty Ltd and covers an area of 5,000 sq km. It is considered to host predominantly a Wet Laurel Basin Centred Gas Play, on trend with Mitsubishi’s Valhalla and Asgard gas fields, located approximately 55 km to the southeast. In 2017, 3D-GEO reported the permit area, including the Butler Prospect, contains estimated gas in place of 169.6 Tcf, on a P50 basis. Recoverable resources were estimated as 28.4 Tcf gas with 707 MMb of associated condensate. Doriemus currently holds minority, non-operated interest in three licences in onshore United Kingdom. Upon completion of the deal with Rey will see Doriemus enter Australia for the first time. EP 487 and L 15 were awarded on 14 March 2014 and 1 April 2010, respectively. Should both deals be completed, interests will become: Doriemus Plc (50% + operator) and Gulliver Productions Pty Ltd (50%). Until this time, Gulliver Productions remains as operator with 100% interest.

Doriemus Plc announced that is has completed its due diligence relating to the acquisition of interest in Rey Resources Ltd’s production licence L 15 (West Kora).

In mid-April 2019, Gazprom Neft Khantos reported that it booked a new oil pool at the Priobskoye field in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). The pool belongs to the Achimov Member (Berriasian-Valanginian). Its 3P oil reserves are estimated at 73 MMbbl in-place and 18 MMbbl of recoverable. The discovery was made by new-pool wildcat Priobskaya Yuzhnaya 615 drilled and tested in the southeastern part of the field in 2018. The well was drilled to 3,382 m at Paleozoic. No hydrocarbons were tested from reservoirs Yu10-Yu11 (Lower Jurassic), Yu2 (Middle Jurassic) and Yu0 (Upper Jurassic). Oil flow at a rate of 81 b/d was tested from the interval 2,772-2,799 m in the Achimov Member.

Russia (Ural - Frolov Province (West Siberian B.)) Priobskoye

On 31 January 2018, the CNH concluded the successful CNH-RO2-LO4/2017 Bid Round or Ronda 2.4 for 29 deep water blocks granting preliminary awards for 19 blocks out of 29 on offer covering a total of 44,177.89 sq km.  There were six of nine blocks in the Perdido area bid on, four out of 10 blocks on offer in the Mexican Ridges Province, and nine out of the 10 blocks on offer in the Salina Basin and these had the two most contested blocks in the bid round.  Total work commitments estimated from the 23 wells bid is USD 1.3 bilion and there were two tie-break bonus bids that resulted in a total of USD 525.03 million offered to the state.  A total of 39 bids were made for the 19 blocks bid on by 18 out of 21 companies that were qualified to participate in the round.  There were 14 blocks with additional bids, most with just two bids, but two blocks had five and four bids, and one block had three bids.  Some companies were very aggressive in the round bidding the maximum additional royalties and significant bonus while others were very cautious.  The most aggressive bidders in the round were Shell, Repsol, and PC Carigali and PEMEX.  PEMEX won four blocks individually or in consortium with another six bids that did not win a block.  Shell placed the most bids in the round with 13, nine as winning bids.  See tables and map below.    Preliminary Results for Ronda 2.4 with Estimated Working Interest for Companies in Consortia – 31 January 2018   Basin CNH - Block - Area CNH - Block - Area Nomenclature from Shapefile Area sq km Awarded Area sq km CNH - Basin Nomenclature Winning Company or Consortium, Est WI% Royalties Bid % Add Work Factor Bid No of Wells:    0, 1 = 1 well, 1.5 = 2 wells Total Estimated Work Commitments USD Bonus Offered in Tie Situations USD Number of Bids 2nd Bid Consortium 2nd Bid Add Royalties % 2nd Bid  Additional Work Factor Bonus 2nd Bid Deep Water Gulf of Mexico (Perdido Area) Area 1 AP-P-G01              1,988.01                                  -    Perdido No Bids         0         Deep Water Gulf of Mexico (Perdido Area) Area 2 AP-P-G02              2,146.19                       2,146.19 Perdido Shell (50%), PEMEX (50%) 15.02 1  $                                        58,900,000   3 CNOOC 11.45 0   Deep Water Gulf of Mexico (Perdido Area) Area 3 AP-P-G03             2,061.82                      2,061.82 Perdido Shell (50%), QPI (50%) 10.03    $                                         10,400,000   2 PEMEX  (50%), CNOOC (50%) 7.01 0   Mexican Ridges Province Area 4 AP-P-G04              1,900.18                       1,900.18 Perdido Shell (50%), QPI (50%) 10.03 1  $                                        58,900,000   2 PEMEX 5.95 0   Mexican Ridges Province Area 5 A&B AP-P-G05-A&B            2,732.72                     2,732.72 Perdido PEMEX (100%) 6.23 1  $                                        58,900,000   1         Mexican Ridges Province Area 6 AP-P-G06             1,890.63                      1,890.63 Perdido Shell (50%), QPI (50%) 20 2  $                                      107,400,000  $                 10,030,382 1         Mexican Ridges Province Area 7 AP-P-G07             1,967.93                      1,967.93 Perdido Shell (50%), QPI (50%) 20 2  $                                      107,400,000  $          90,030,382.00 2 CNOOC (50%), PC Carigali (50%) 5.01 0   Mexican Ridges Province Area 8 AP-P-G08             2,061.73                                  -    Perdido No Bids         0     0   Mexican Ridges Province Area 9 AP-P-G09            2,008.66                                  -    Perdido No Bids         0         Mexican Ridges Province Area 10 AP-CM-G01             1,999.29                      1,999.29 Cordilleras Mexicanas Repsol (33.34%), PC Carigali (33.33%), Ophir (33.33%) 20 2  $                                      103,500,000  $          30,247,805.67 2 Shell (50%), QPI (50%) 11.03 1   Mexican Ridges Province Area 11 AP-CM-G02             2,001.53                                  -    Cordilleras Mexicanas No Bids         0         Mexican Ridges Province Area 12 AP-CM-G03            3,099.43                     3,099.43 Cordilleras Mexicanas PC Carigali (33.34%), Ophir (33.33%), PTTEP (33.33%) 20 1  $                                        54,800,000   2 Shell (50%), QPI (50%) 9.03 1   Mexican Ridges Province Area 13 AP-CM-G04             1,967.02                                  -    Cordilleras Mexicanas No Bids         0         Mexican Ridges Province Area 14 AP-CM-G05             2,241.83                      2,241.83 Cordilleras Mexicanas Repsol  (50%), PC Carigali  (50%) 19.98    $                                           6,100,000   2 Shell (50%), QPI (50%) 5.03     Mexican Ridges Province Area 15 AP-CM-G06             2,041.92                                  -    Cordilleras Mexicanas No Bids         0         Mexican Ridges Province Area 16 AP-CM-G07            2,047.37                                  -    Cordilleras Mexicanas No Bids         0         Mexican Ridges Province Area 17 AP-CM-G08             3,009.71                                  -    Cordilleras Mexicanas No Bids         0         Mexican Ridges Province Area 18 AP-CM-G09             2,917.09                      2,917.09 Cordilleras Mexicanas PEMEX (100%) 7.11 1  $                                        54,800,000   1         Mexican Ridges Province Area 19 AP-CM-G10            3,003.07                                  -    Cordilleras Mexicanas No Bids         0         Campeche Deep Sea Basin Area 20 AP-CS-G01            2,079.50                     2,079.50 Salina Shell (100%) 20 2  $                                      106,700,000  $            90,154,514.03 2 PEMEX 6.11     Campeche Deep Sea Basin Area 21 AP-CS-G02            2,029.74                     2,029.74 Salina Shell (100%) 20 2  $                                      106,700,000  $           110,154,514.03 4 Chevron (33.34%), PEMEX (33.33%), ONGC (33.33%) 20 2  $                  42,100,101.00 Campeche Deep Sea Basin Area 22 AP-CS-G03            2,878.99                     2,878.99 Salina Chevron (33.34%), PEMEX (33.33%), Inpex (33.33%) 18.44 1  $                                        59,200,000   2 BHP 6.55     Campeche Deep Sea Basin Area 23 AP-CS-G04             1,852.86                      1,852.86 Salina Shell (100%) 10.08 1  $                                        59,200,000   2 Chevron (33.34%), PEMEX (33.33%), Inpex (33.33%) 13.44     Campeche Deep Sea Basin Area 24 AP-CS-G05              1,921.93                       1,921.93 Salina ENI  (50%), QPI  (50%) 9.53 1  $                                        59,200,000   1         Campeche Deep Sea Basin Area 25 AP-CS-G06             2,106.97                      2,106.97 Salina PC Carigali (100%) 19.98    $                                          11,700,000   1         Campeche Deep Sea Basin Area 26 AP-CS-G07            2,030.40                     2,030.40 Salina PC Carigali (100%) 20 1  $                                        59,200,000   2 BP (50%), Statoil  (50%) 13.37     Campeche Deep Sea Basin Area 27 AP-CS-G08               2,118.14                                  -    Salina No Bids         0         Campeche Deep Sea Basin Area 28 AP-CS-G09            3,066.83                     3,066.83 Salina Shell (100%) 20 2  $                                      106,700,000  $            43,154,513.03 2 PC Carigali 19.98     Campeche Deep Sea Basin Area 29 AP-CS-G10            3,253.64                     3,253.64 Salina Repsol (25%), PC Carigali (25%), Sierra Nevada (25%), PTTEP (25%) 20 2  $                                      106,700,000  $         151,253,352.89 5 ENI (33.34%), QPI (33.33%), Citla Energy (33.33%) 20 2  $               86,723,456.00 Totals                         44,177.98       23  $                             1,296,400,000.00  $       525,025,463.65 39         Source: IHS Markit           © 2018 IHS Markit                     Preliminary Results for Ronda 2.4 – Companies - with Estimated Working Interest for Companies in Consortia – 31 January 2018 Company Net to WI Area sq km Net to WI Commitments plus Bonus USD Block Won as Operator or Partner Company/Consortia - Winning Bidders Blks Won Chevron                               959.86  $                                       19,737,280.00 1 Chevron (33.34%), PEMEX (33.33%), Inpex (33.33%) 1 ENI                               960.96  $                                      29,600,000.00 1 ENI  (50%), QPI  (50%) 1 Inpex                               959.57  $                                        19,731,360.00 1 PC Carigali (100%) 2 Ophir                             1,699.40  $                                      62,842,983.63 2 PC Carigali (33.34%), Ophir (33.33%), PTTEP (33.33%) 1 PC Carigali                             7,771.42  $                                      201,286,801.85 5 PEMEX (100%) 2 PEMEX                            7,682.47  $                                      162,881,360.00 4 Repsol  (50%), PC Carigali  (50%) 1 PTTEP                             1,846.45  $                                       82,753,178.22 2 Repsol (25%), PC Carigali (25%), Sierra Nevada (25%), PTTEP (25%) 1 QPI                             4,871.24  $                                     221,680,382.00 2 Repsol (33.34%), PC Carigali (33.33%), Ophir (33.33%) 1 Repsol                            2,600.89  $                                       112,129,856.63 3 Shell (100%) 4 Shell                            14,012.31  $                                    844,293,923.09 9 Shell (50%), PEMEX (50%) 1 Sierra Nevada                                 813.41  $                                      64,488,338.22 1 Shell (50%), QPI (50%) 4 Grand Total                          44,177.98                                       1,821,425,463.65     19 Source: IHS Markit © 2018 IHS Markit     Source: IHS Markit © 2018 IHS Markit      

Mexico (Sureste B.) ? op. by ENI SPA (100.0%) in Area 1 (Amoca) block

Eni spudded exploration well 22/19c-7 in licence P1620 (block 22/19c) targeting the HP/HT Rowallan prospect on 31 December 2018. In February 2019, Equinor acquired 8% interest from Eni. Rowallan is a large structural closure thought to hold P50 gross prospective resources of 220 MMboe. It was thought to be an analogue to the large Culzean field. The company used the “Ensco 121” for operations. On 4 April 2019 partner Serica announced that the well was drilled to a TD of 4,641 m and encountered a 182 m section of sandstones and shale but no hydrocarbons were encountered. As of 7 May 2019 it is understood the rig was still on location having carried out plug and abandonment work. Serica was officially awarded the licence under the 25th Offshore Licensing Round back in 2010. Following a deal in 2012 with JX Nippon, the Japanese company farmed in taking an 85% interest operatorship. Then in May 2014 Eni farmed into the licence taking a 50% interest and operatorship. The licence is located near the Eastern Trough Area Project (ETAP) which involves the joint development of the Marnock, Skua, Egret, Heron, Machar, Mungo, Madoes and Mirren fields. Interest in the licence is held by ENI UK Limited (32% + operator), JX Nippon Exploration and Production (U.K.) Limited (25%), Mitsui E&P UK Ltd (20%), Serica Energy (UK) Limited (15%) and Equinor (UK) Ltd (8%).

022/19c-07 (Rowallan) HPHT gas/cond expl.well (Eni 32% op, JX Nippon 25%, Mitsui 20%, Serica 15%, Equinor 8%) in P1620 / block 22/19, encountered a 182m section of Fluvial sst. and shale after being drilled to a TD=4641m into Middle Jurassic and Triassic strata but “was not found to be hydrocarbon-bearing”, P&A dry at TD=4651m.

Hitherto-unreported, Chi bagged ATP 2039-P, 5,263 sq km in the Adavale-Eromanga Basin, south-central QLD, back on 29 Nov '19 for 6 years. It was applied for as PLR201718-2-1 under the March 2017 QLD acreage offer.

Chi O&G was awarded ATP 2039-P, 5,263 sq km in the Adavale-Eromanga Basin, south-central QLD.

NE part of SEAL-T-050 block, Sergipe-Alagoas onshore, P&A dry late Jul ’18, TD + status yet to be reported. PTD was 2,850m, target L. Cret. Penedo fm.

1-BON-001-AL (1-IMET-024-AL) (Imetame 100%) in the SEAL-T-050 block, P&A dry.

Top manager at SNGN ROMGAZ SA, partner in the operation, disclosed to the press in early May 2020 that the new-field wildcat Trinity 1X in the E X-30 Trident permit came out short on the pre-drill expectations. The well, operated by Lukoil Overseas Holding Ltd in late 2019 and aiming at confirming interpreted resource potential of the Trinity prospect, in excess of 1 Tcf of gas, is said to be a geological success. Preliminary analysis of the drilling and geophysical data shows that the well encountered a gas-saturated interval with an effective thickness of 46 m in the Miocene-Pliocene series. The operator is assessing the data in early 2020, updating the geological model and financial estimates of the find and the final results if the operation expected mid-year (the well may turn non-commercial in the price scenario prevailing on the markets in 2020). Reliant on the results of Trinity 1X well, Lukoil was planning to drill two additional exploration wells in the Trident block in 2020 and 2021. The Trinity 1X well, drilled by the “Scarabeo 9” S/S (mobilized to the well location on 13 November 2019, departed on 25 December 2019), is located in the southeastern sector of the tract, close to the border with Ukraine, in water depth of approximately 700 m. The well had a planned TD of 3,250 m (TVD) with the objective to find gas in Tortonian-Messinian sand intervals at depths between 2,500 m and 3,100 m (four intervals were targeted). The E X-30 Trident block is situated in the eastern part of the Romanian waters of the Black Sea. The permit includes the Lira 1X gas discovery made in October 2015. Lukoil estimated that the gas reserves of the Trident prospect could exceed 1 Tcf. The well operations were expected to last 90 days (including mobilization and demobilization of the rig). Interest in the E X-30 Trident permit is divided between Lukoil Overseas Holding Ltd (87.8% + operator) and Romgaz SA (12.2%). It is understood, the group active in the block intends to acquire further seismic in the area - contracts with CGG and Schlumberger are said to be arranged - to better determine the exploration potential of the series straddling the area between the Lira and Trinity locations.

Romania (Black Sea B.) Trinity 1X op. by LUKOIL (88%), ROMGAZ (12%) in E X-30 Trident block, water depth 1076 m geologically successful however less so commercially, although a 46m gas-saturated intv was encountered in Miocene-Pliocene series. PTD was 3,250m, target gas in Tortonian-Messinian sands.

Shell Brasil Petroleo, a subsidiary of Royal Dutch Shell has won four additional deep-water exploration blocks in the Campos and Potiguar basins, bringing its total operated presence offshore Brazil to 18 blocks. In the 15th deep-water bid round organized by the Brazilian National Petroleum Agency (ANP), Shell secured one exploration block on its own, and three in joint-bids with Chevron Brazil, Petrobras, and Petrogal Brasil. Of the newly acquired blocks today, Shell will operate two.Shell will pay its share of the total signing bonuses, equating for all bids to approx. USD $70-million (R$ 235-million).'We continue to demonstrate our commitment to growing our production in Brazil and our strong belief in the value deep-water resources brings to our global portfolio,' said Andy Brown, Upstream Director, Shell. 'This bid round offers significant potential for additional deep-water discoveries. These lease commitments fall within our agreed capital ceiling and are consistent with our value-based approach.'Globally, Shell plans to invest $5-6 billion each year through 2020 into its deep water business to strategically grow production and returns for the company. The business is on track to deliver annual, free cash flow of $6-7-billion by 2020 (at $60/barrel Brent RT 2016).New Acreage added to Shell Brasil’s PortfolioCampos Basin:Potiguar Basin:Original article linkSource: Shell

Shell Brasil Petroleo, a subsidiary of Royal Dutch Shell has won four additional deep-water exploration blocks in the Campos and Potiguar basins, bringing its total operated presence offshore Brazil to 18 blocks. In the 15th deep-water bid round organized by the Brazilian National Petroleum Agency (ANP

In May 2019 Telpico continues to offer interest in its VSM-3 Block of the Upper Magdalena Basin. Producing formations in the area are the Caballos and Monserrate, and Tertiary production is located north of the VSM-3 Block. The conventional play type includes structural closures and vintage 2D (1990) has identified multiple leads. Estimated reserves from the Caballos prospects are reported at some 100 MMbo. Telpico is offering a 65% working interest and terms are negotiable. Interested parties should visit the website at www.telpico.com.

Telpico continues to offer interest in its VSM-3 Block of the Upper Magdalena Basin. Producing formations in the area are the Caballos and Monserrate, and Tertiary production is located north of the VSM-3 Block.

On 29 November 2018, Discover Exploration Ltd announced that it has signed a binding agreement with Bahari Resources Ltd to acquire its entire issued share capital. Bahara Resources holds a 40% interest in the Blocks 35, 36 and 37 licence. At the same time, Discover Exploration and Tullow Oil announced a deal whereas Discover Exploration agreed to farm-out 35% interest of its initial 60% interest in the licence to Tullow Oil. Following the governmental approval of both deals, Tullow will operate the licence with a 35% interest and Discover Resources will hold the remaining 65% (25% through its local subdisiary Discover Exploration Comoros B.V. and 40% through Bahari Resources Ltd. The 17,853 sq km acreage is located in the Outer Rovuma Fan, in water depth between 2,500 and 3,000 m about 100 km to the east of the Mozambique large gas discoveries. The licence is in its second exploration period that is valid until April 2021. Commitments calls for the acquisition of some 2D or 3D seismic data as well as for the drilling of an exploration well. Earlier in 2018, Discover Exploration released its plans to drill the first exploration well in 2019/2020. The well will test two large stratigraphic prospects that are partially overlapping. The mid-Eocene prospect has a Pmean prospective reso5rce of 5.8 Bbbl (for the oil case) or 3.7 Bboe (for the gas case). The Cenomanian prospect has a Pmean prospective resource of 3.5 Bbbl (oil) or 2.5 Bboe (gas). Background Information The companies were awarded the licence in March 2014. In May 2014 the companies started the acquisition of a 2,330 km 2D infill seismic survey being part of the GX Technology (ION Geoventures) East Africa SPAN programme. The survey was completed in early August 2014. The seismic survey fulfilled the commitments for the initial period that ended in March 2018. The data were reported of excellent quality, and initial interpretation suggested an extension of the Mozambican reservoir play beneath the Comoro acreage. Vast areal extend of Paleocene fan has been interpreted over Blocks 35, 36 and 37, with possible source rock in the oil window. The previous 2D seismic survey in the area was shot in 1H 2011, also part of the East Africa SPAN programme. Commitment for the second exploration phase (2018 to 2021) is to acquire either 2D or 3D seismic data. Commitment for the last and third exploration phase is to drill one exploration well. The Comoros’ acreage is a frontier area. The main potential for O&G business appears to be the eastern extension of the Rovuma Delta where deepwater fan stratigraphic plays are expected to be found. Faulting along the ridge separating the Comoros from East Africa Continent is also known to have created large anticlinal structures

Comoro Islands Discover Exploration Ltd announced that it has signed a binding agreement with Bahari Resources Ltd to acquire its entire issued share capital. Bahara Resources holds a 40% interest in the Blocks 35, 36 and 37 licence. At the same time, Discover Exploration and Tullow Oil announced a deal whereas Discover Exploration agreed to farm-out 35% interest of its initial 60% interest in the licence to Tullow Oil.

Solo Oil Plc announced on 9 March 2018 that it has completed the acquisition of an additional 5% interest in Horse Hill Developments Limited (HHDL). Solo has acquired the 5% interest in the company in return for a cash consideration of GBP 650,000. Solo now holds a 15% stake in HHDL which is the equivalent of 9.75% interest in Horse Hill licences PEDL 137 and PEDL 246 which contain the Horse Hill Discovery. Testing of the discovery is scheduled to commence in Q2 2018 which it is hoped will determine the commerciality of the Portland sandstone reservoir. Additional testing of the Kimmeridge fractured Limestone section will also be carried out. The testing process is expected to last approximately 150 days. The Horse Hill-1 discovery was flow tested during Q1 2016. Operations commenced on 8 February 2016. On 16 February 2016 Solo announced that light 40° API oil has flowed to surface from an 80 ft zone within the Lower Kimmeridge Limestone at a depth of 900 m. Initial 700 bo/d flowed through a 1” choke with a mix of 50:50 water and oil. A 32/64” choke was used resulting in a steady flow of 460 bo/d with a 99% oil to 1% water mix. The following day Solo confirmed that production has continued at a stable rate of 450 bo/d through a smaller 28/64” choke. The company then moved to test the Upper Kimmeridge Limestone. On 1 March 2016 Solo reported that water-free 40° API, light, sweet oil has flowed naturally to surface at a stabilised rate of 900 bo/d. The production test was undertaken over 88 ft perforated zone at approximately 840 m depth. Initially the flow was restricted using a 1” choke and commenced with a rod pump with an initial flow of 700 bo/d before the pump was stopped and natural flow increased to 900 bo/d. The following day it was reported that oil flow continued at an average rate of 838 bo/d. On 9 March 2016 partner Solo reported on the testing of the shallower Portland Sandstone. The well tested 37° API and flowed to surface via rod pumping at a stabilised rate of 168 bo/d over a nine hour period from a 31 m aggregate perforated zone at a depth of 615 m. On 21 March 2016 Solo announced that testing continued on this section using the same pump, located immediately above the perforated zone and resulted in stable flow over a two day period. A larger stroke pump was installed resulting in a maximum rate in excess of 360 bo/d over eight and a half hours. Interest in the licences is held by Horse Hill Developments Limited (65% + operator) and Magellan Petroleum (UK) Limited (35%).  

Solo Oil (->9,75%) has completed the acquisition of an additional 5% interest in HHDL (Horse Hill Developments Limited - 65% + operator, Magellan Petr. 35%). Concerning are licences PEDL 137 and PEDL 246.

Alto CF Oeste P3 contract, ALTO_CF_O block, Santos Basin, WD 1,720m, PTD 5,200m, target Barra Velha, oil shows report to ANP on 8 Nov '19, Brava Star DS. Shell (op), partners CNOOCI + Qatar Petr.

ACFO (1-SHEL-031-RJS) nfw (Shell 55% op, CNOOCI 20%, Qatar Petr 25%) in Alto CF Oeste P3 contract, ALTO_CF_O block, target Barra Velha, oil shows report to ANP on 8 Nov '19. WD=1720m, PTD=5200m.

Further to DEA 19 Mar ’19 (farmin offer) GV has agreed to dispose of its 100% interest in EP 127, 14,280 sq km in the Georgina Basin, NT, to Westmarket Oil & Gas Pty Ltd.  The move is subject to usual conditions. * Global Vanadium, ex-Baraka Energy.

Westmarket will acquire 100% operating interest in EP 127 from Global Vanadium for A$1.5 MM.

Gazkop secured sole rights on 21 Jan '20 to the 1/2020 Mszana extraction lease SW of Katowice in the Upper Silesian Basin, S. Poland. Gazkop specialises in methane extraction from abandoned coal mines.

Gazkop secured sole rights on 21 Jan '20 to the 1/2020 Mszana extraction lease SW of Katowice in the Upper Silesian Basin, S. Poland. Gazkop specialises in methane extraction from abandoned coal mines.

PL 51, Cooper-Eromanga, drilled 25-29 Nov '19, TD 1,168m, P&A oil shows.

Dilkera-5 appr PL 51, Cooper-Eromanga, TD 1,168m, P&A oil shows.

The Dutch Ministry reported on 11 July 2019 that it has awarded exploration blocks G7, G10, G11 and G13a (1,079 sq km) to NAM and block G13b (16 sq km) to Neptune Energy effective from 3 July 2019. The Dutch Ministry decided to split the G13 block into two separate blocks following the competing bid from Neptune. The G13b block cover a small area in the eastern and/or southern part of the G13 block which neighbours Neptune’s operated blocks G14, G16 and G17. NAM made the original application for all the blocks on 17 September 2016. The 13-week period during which competing bids could be received ended on 19 December 2016. The blocks lie on the border with the German Continental Shelf. Eleven exploration wells were drilled within the surface area covered by the blocks between 1990 and 1998. All the wells were unsuccessful. On 9 June 2010 GDF SUEZ relinquished its exploration licences for blocks G10, G11 and G13. The licences were awarded in June 2008 and the company did not drill any wells during its tenure. Interest in blocks G7, G10, G11 and G13a will be held by Nederlandse Aardolie Mij BV (operator) and Energie Beheer Nederland BV and interest in block G13b will be held by Neptune Energy Netherlands BV (operator) and Energie Beheer Nederland BV.

The Dutch Ministry reported on 11 July 2019 that it has awarded exploration blocks G7, G10, G11 and G13a (1,079 sq km) to NAM and block G13b (16 sq km) to Neptune Energy

On 13 March 2019, Eni SpA was reported to have farmed out a 30% interest in the Tarfaya Offshore Shallow exploration permits I-XII to Qatar Petroleum. The permits cover an area of 23,900 sq km, with a water depth ranging from 0 to 1,000 m. Eni was awarded the permits in December 2017 and it stays the Operator of the permits with a 45% interest, Qatar Petroleum will hold a 30% interest, while ONHYM will retain the remaining 25% interest. The permits arear in in the northern part of Aaiun-Tarfaya Basin (also known as the Laayoune-Tarfaya-Dakhla Basin), which is considered as one of the most prospective in Atlantic waters of Morocco. The Aaiun-Tarfaya Basin is a Mesozoic rift basin located both on and offshore the passive Atlantic margin of southern Morocco and extends southwards throughout Western Sahara. That basin, which can be considered so far as almost unexplored, is formed of a faulted basement made of Precambrian and Paleozoic rocks, overlain by a Triassic-Liassic sequence composed mainly of clastics, including microconglomerates, sandstones, red shales with evaporites and lagoonal deposits. The shaly and saliferous plastic formations should have generated halokinetic structures. The post-rift sequence starts with the Liassic-Dogger sub-sequence related to the opening of the Atlantic and to the progressive setting of a marine environment and carbonate sedimentation. In wells MO-2, MO-8 and Cap Juby 1 located in the northern part of the basin, the Liassic and Dogger sections are made of limestones with sandy and shaly intervals. The second post-rift sub-sequence is a true passive margin basin formed in Late Jurassic time, with a carbonate platform to the east and an open marine domain to the west. Reefal build-ups are present along the edge of this platform. During the Cretaceous, sands and conglomerates were deposited in the east of the basin, and thick shaly and silty rocks to the west, and a fourth post-rift sequence started at the end of Albian time, with marls, shaly limestones, shales, organic rich bituminous chalks and shaly limestones with chert and phosphates. Phosphates series were deposited during a regression period starting during the Coniacian. Alpine movements have produced regional unconformities during the Oligocene and Miocene times along the shelf break. Tertiary erosion has formed canyons later filled by Cenozoic turbiditic deposits.

Qatar Petroleum has entered into an agreement with Eni (->45% op, ONHYM 25%) to acquire a 30% share in the Tarfaya shallow exploration permit, which comprises 12 explo blocks, covers a total area of approximately 23 900km² in WD of up to 1000m.

On 12 June 2019, North Sinai Petroleum Co spudded the Kamose Main 1 exploration well in the Kamose (Dev) concession, offshore Nile Delta Basin. The well reached a TD of 2,664 m and was completed as a gas producer. Kamose Main 1 came on-stream on 29 August 2019 at a rate of 20 MMcf/d of gas. The Kamose (Dev) concession was awarded originally in 1998. It covers 161 sq km and is now operated by North Sinai Petroleum, a joint venture between EGPC (50%) and MOG Energy (50%). Egypt Kuwait Holding is a participant in MOG Energy.

Kamose Main-1 expl. (North Sinai Petr = MOG Egy-EGPC 50:50) in Kamose (Dev) block, offshore, compl. gas at TD=2664m, on stream (20 MMcfg/d).

Ref. DEA 14 Feb ’18, BHP has waived its pre-emption rights over Woodside’s agreement to acquire ExxonMobil’s 50% in the Scarborough gasfield, Carnarvon Basin off WA. The USD 744 MM deal will result in Woodside holding a 75% interest in WA-1-R (most of the field) and 50% in WA-61-R, WA-62-R + WA-63-R, BHP holding the balance (and pre-emptive rights). Woodside has not ruled out a farm-down at a later stage, and has granted BHP an option to purchase an additional 10% interest in Scarborough on equivalent consideration and terms to the Exxon deal.

Australia (North Carnarvon B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: WA-61-R op. by WOODSIDE (50.0%, BHP BILLIT 50.0%) to be check.WA-62-R op. by WOODSIDE (50.0%, BHP BILLIT 50.0%) to be check.WA-63-R op. by WOODSIDE (50.0%, BHP BILLIT 50.0%) to be check.

On 20 July 2019, SOCAR announced the completion of appraisal well Absheron Garbi 10 at its offshore Absheron Garbi oil field (Caspian Sea). Absheron Garbi 10 reached a TD of 770 m in the Kirmaku Formation. The well was spudded from platform N°10 in mid-June 2019.

Azerbaijan, Absheron

On 18 February 2020, Genel Energy was awarded the Lagzira Offshore reconnaissance licence, located in the Tarfay Basin. The block is understood to be valid for a minimum one-year term, with activity to include G&G studies. There are no well commitments for the reconnaissance licences. The block is understood to be an effective re-award of the company's Sidi Moussa Offshore exploration permit (5,018 sq km) which was relinquished upon expiry on 16 February 2020. Sidi Moussa lay in WD between 40-1,500m. It was originally awarded to Island Oil & Gas with 50% equity in June 2009. Partners at the time were Serica (25%) and ONHYM (25%, carried). In 2010, Longreach Oil & Gas (now Wolverine) farmed-in, acquiring 10% equity from Island. In the same year San Leon acquired operatorship, through the acquisition of Island. In May 2013, Genel completed its US$ 51.3 million farm-in, acquiring 60% operated equity pro-rata from the existing partners. In 2014 the Sidi Moussa 1 (SM 1) NFW was drilled, reaching 2,825m TD (983m WD) in mid-October 2014. An unsuccessful test of fractured and brecciated Late Jurassic carbonates resulted in it being P&A with oil shows. In October 2015, Wolverine (as PetroMaroc) exited, assigning its equity to San Leon. Genel commenced a farm-out process in 2016, seeking partners to drill the Nour Deep well, which would target a 350 MMbo early Jurassic clastics prospect. Following a licence extension in Q4 2017, which saw the well commitment being replaced by the seismic campaign, partners San Leon (10%) and Serica (5%) also exited the permit. A 2,000 sq km 3D seismic survey was subsequently acquired between August-November 2018. Equity in Lagzira Offshore is understood to be split: Genel (75% +Op) and ONHYM (25%, carried).

Genel Energy (75%,op ONHYM 25%, carried) was awarded the Lagzira Offshore reconnaissance licence. The block is understood to be valid for a minimum one-year term, with activity to include G&G studies. There are no well commitments for reconnaissance licences. The block is understood to be an effective re-award of the company's Sidi Moussa Offshore exploration permit (5018km²) which was relinquished upon expiry on 16 February 2020.

Naushahro Firoz 2668-9 EL, Middle Indus onshore, TMD 4,940m (3,521m TVD), 1.3 km horiz section in Jurassic Chiltan fm, susp. gas on 2 Jul ’17 after testing 1.3 MMcfg/d + 9 bc/d on a 1/2” choke. A subsequent 10-stage frac job was performed within the Chiltan limestone, 4.5 MMcfg/d obtained at 1,850 psi WHP. PPL (op), partner Asia Resource.

Naushahro Firoz Hor 1 (NF-Hor 1) 1.3 km horiz section in Jurassic Chiltan fm, susp. gas on 2 Jul ’17 after testing 1.3 MMcfg/d + 9 bc/d on a 1/2” choke. A subsequent 10-stage frac job was performed within the Chiltan limestone, 4.5 MMcfg/d

Esperanza block, Lower Magdalena, drilled and P&A dry during Jun ’18, Pioneer 302 rig. Target CDO.

Borojo 1 (Canacol 100%) in Esperanza block, P&A, dry.

Pancontinental is looking to dilute its 75% in block 2713 / PEL 87,  10,947 sq km astride the Lüderitz + Orange basins, a partner sought to fund 3D seismic survey over a Late Aptian ‘super fan’ identified. Pancontinental (op), partners Investments + Namcor (both carried).

Pancontinental is looking to dilute its 75% in block 2713 / PEL 87, 10,947 sq km astride the Lüderitz + Orange basins, a partner sought to fund 3D seismic survey over a Late Aptian ‘super fan’ identified. Pancontinental (op), partners Investments + Namcor

On 25 March 2020 Perenco completed the acquisition of interest from BP in a number of blocks across the following licences in the Southern North Sea - P001, P133, P138, P016, P024, P028, P030, P302, P380, P005 and P050. A complete list of interest exchanged is in the table below. All of the blocks involved were classed as 'Carboniferous Areas' by the OGA. The deal is in line with BP's planned programme to divest USD 10 billion worth of assets by the end of 2020. The major is in the process of reshaping its portfolio in the North Sea and is concentrating on the core hubs of Clair, Quad 204 and ETAP. Asset Percent Seller Buyer Date completed P001                                            048/06a Hyde Field (CA)                                          048/06a Rest of Block Excluding Hyde (CA)                           042/30a All (CA)                                                042/29a Cleeton Subarea Inc Cleeton Field (CA)                    042/29a Neptune Area (CA)                                     042/29a Ravenspurn (CA)                                       047/10b Hyde Field (CA)                                           047/010b Rest of Block Excluded Hyde and Disc (Rest) (CA)          90% BP Perenco 25-03-20 P133 047/15a Amethyst Field (CA) 047/15a Rest of Block (CA) 75% 90% P138 048/07b (CA) 90% P016 047/03b (CA) 58.50% P024 048/07a (CA) 90% P028 047/05a Hyde (CA) 047/05a (Rest1) (CA) 047/05a (Rest2) (CA) & 047/05c Neptune (CA) 047/04a (CA) 047/05c Rest of Block (CA) 90% 58.5% 16.85% P030 047/09a (CA) 047/08a (CA) 69.23077% P302 047/03c (CA) 047/04c (CA) 047/04b Rest of Block SW (E) (CA) 047/04b Rest of Block NE (CA) 047/04b Neptune Field Area C (CA) 047/09b (CA) 58.55% 90% 65.997% P005 047/14a (CA) 75.6% P050 047/13a (CA) 90% P380 043/26a Ravenspurn North (CA) 90.00%

United Kingdom, P138

On 8 December 2017, the consortium of Iberoamericana de Hidrocaruburos, S.A. de C.V. and Servicios PJP4 de Mexico S.A. de C. V. signed the contract with the CNH and was granted official final awards for the CNH-RO2-L02-A1.BG/2017 contract from the CNH-RO2-LO2/2016 Bid Round.  The CNH-RO2-L02-A1.BG/2017 contract is also known as the Area 1 block.  The consortium formed a separate subsidiary, Iberoamericana de Hidrocaruburos CQ, Exploracion & Produccion de Mexico, S.A. de C.V. with 100% working interest as the official designated operating company for the block.  The 360.3 sq km CNH-RO2-L02-A1.BG/2017 contract has a total financial commitment of USD 14.2 million, all for work commitments that includes one extra well. On 12 July 2017, the consortium of Iberoamericana and Servicios PJP4 was the high bidder in the CNH-RO2-LO2/2016 Bid Round for the Area 1 block in the Burgos Basin and was granted a preliminary award.   For the 360.30 sq km Area 1 block the Iberoamericana consortium offered the minimum additional royalties of 3.91% and 1.0 work unit factor equivalent to one additional well.  There were no other bids for the block.  It is estimated that the winning consortium is split 50%-50% but the final official equity breakdown will only be reported at a later date. The general license contract terms include a 1st exploration period of two years with the possibility of a two-year extension.  In the case of a discovery the operator can request a two-year evaluation phase for oil and a three-year evaluation phase for non-associated gas discoveries once the evaluation plan is approved.  The total contract term is for 30 years with the possibility of two five year extensions for a 40-year total contract term from signature date. The base royalty rate is a sliding scale royalty depending on type of hydrocarbon and oil price.  The values for oil range from 5% for USD 40/bbl oil to 25% for USD 200/bbl oil.  The relinquishment schedule is tied to exploration well commitments.  If the exploration period ends but the operator offers to drill an additional well it doesn’t have to relinquish any area.  If the exploration period ends and the contractor doesn’t have any discoveries it must relinquish 100%.  If the exploration period ends and the operator doesn’t offer to drill an additional exploration well it will have to relinquish 50% of the area.  Local content during the exploration period is 26% for the exploration and evaluation period, and varies from 27% to 38% in the development period.

Mexico (Sureste B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: 12 op. by LUKOIL (100.0%) to be check.14 op. by ENI SPA (60.0%, CITLA 40.0%) to be check.Area 1 (Tecoalli A) op. by ENI SPA (100.0%) to be check.Area 1 (Tecoalli B) op. by ENI SPA (100.0%) to be check.6 op. by PETRONAS (50.0%, ECOPETROL 50.0%) to be check.Area 1 (Mizton) op. by ENI SPA (100.0%) to be check.Area 1 (Amoca) op. by ENI SPA (100.0%) to be check.

1st of 3 wells planned in Uzhgorod prod. licence, Transcarpathian Basin in W. Ukraine, PTDs 1,500-1,900m, target Triassic reservoir found water-wet + traces of gas. Cub (op), partner NAFTA Intl carrying Cub through drilling under a 2016 farmin agreement.

Uzhgorod 101 expl (Cub op, partner NAFTA Intl carrying Cub through drilling under a 2016 farmin agreement) 1st of 3 wells planned in Uzhgorodska 6104 licence, in W. Ukraine, PTDs 1,500-1,900m, target Triassic reservoir, P&A found water-wet + traces of gas.

S-C part of Uirapuru_P4 contract, BLCUirapr block, Santos Basin, WD 1,994m, junked in favour of a sidetrack (1-SPS-107A (1-BRSA-1373A-SPS)) on 25 Nov '19. PTD 5,915m, targets Barra Velha + Itapema, West Tellus DS. Petrobras (op), partners Equinor, ExxonMobil + Petrogal.

Junked: 1-SPS-107 (1-BRSA-1373-SPS) nfw

Repsol intends to back-out of the Total-run, 14,220-sq km 1-21 Han Asparuh block in the Black Sea, Total and OMV retaining their interests, which, if pro-rata'd, would become 57% + 43%. It is recalled 5,500 sq km of planned 3D seismic starts anytime now in the E. part of the block, Oceanic Vega SV. So far Total (op), partners OMV + Repsol.

Repsol intends to back-out of the Total-run, 14,220-sq km 1-21 Han Asparuh block in the Black Sea, Total and OMV retaining their interests, which, if pro-rata'd, would become 57% + 43%. It is recalled 5,500 sq km of planned 3D seismic starts anytime now in the E. part of the block, Oceanic Vega SV. So far Total (op), partners OMV + Repsol.

Add. DEA 21 Aug '19 (completion): South Natuna Sea block B Extn / sector IV, P&A gas in mid-Aug '19, tested ab. 4 MMcf/d biogenic gas, COSL Boss JU. Medco (op), partner Prime Natuna.

Tuna 1 (Medco 75% op, Prime Natuna Energy 25%) in South Natuna Block B PSC Extension in the unexplored Area VI of the PSC., P&A as a gas disc. was likely targeting Pliocene sst of the Muda Fm. According to sources, well testing indicated biogenic gas with a flow rate of 4 MMcfg/d. The operator will conduct further study by running a series of lab analysis.

Sonatrach has been awarded the Rezkallah exploration and exploitation licence, effective from 11 October 2017. The 20,843 sq km block lies in the south of the under-explored Reggane Basin. It was originally offered as part of the 4th National and International Bid Round in 2014, but failed to attract any successful bids. A two-year prospecting permit was subsequently awarded to Sonatrach in Q1 2015. An application for a full exploration licence was submitted upon the permit expiry. The block is understood to potentially contain a southern extension of the Azrafil Sud Est gas field, located on the adjacent Reggane Nord production concession. Just seven wells have been drilled on the licence to date. The last, EGBN 1 (TD 1,995m) in the east of the block, was abandoned in Q1 2017. Sonatrach will operate the licence with 100% equity.

Not Found

Cabot is discussing the farmout of its so far wholly-owned F.R 39.NP + F.R 40.NP, 725 sq km apiece in the Adriatic Zone F (Durres Basin), ahead of 670 sq km 3D seismic and an appraisal to the Giove-2 discovery. Seismic will, inter alia, help mature the Cygnus prospect for drilling. Of note, similar talks had been held in 2016 with High Power Petroleum. Contact: Keith Bush [email protected], or Carlo Caldarelli: [email protected].

Cabot is discussing the farmout of its so far wholly-owned F.R 39.NP + F.R 40.NP, 725 sq km apiece in the Adriatic Zone F (Durres Basin), ahead of 670 sq km 3D seismic and an appraisal to the Giove-2 discovery. Seismic will, inter alia, help mature the Cygnus prospect for drilling. Of note, similar talks had been held in 2016 with High Power Petroleum. Contact: Keith Bush [email protected], or Carlo Caldarelli: [email protected].

Wellesley has acquired Equinor’s 20% in PL 871 (recent Balcom well) effective 30 Apr ‘19. Wellesley (op), partner Lotos.

Wellesley has acquired Equinor’s 20% in PL 871 (recent Balcom well) effective 30 Apr ‘19. Wellesley (op), partner Lotos.

Official information, recently disclosed, states that in early July 2019, Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) abandoned new-field wildcat Radew 1 in the 48/2009/L Tychowo permit in northwestern Poland. The well, drilled to the final depth of 3,400 m in the Lower Carboniferous series, was solely operated by PGNiG. The Radew 1 well was spudded on 9 April 2019, using the Masseranti 6000E drilling unit. The well is located some 15 km southwest of the city of Koszalin. In a geological term, it is falling within the Pomeranian High, tectonic unit of the NE German-Polish Basin. The Tychowo permit is located in the Zachodnio-Pomorskie political province, some 100 km north-east of the city of Szczecin. It covers now the western part of the country's national grid block 65 and the northwestern sector of the block 85. Radew 1 had a planned final depth of 3,400 m, targeting the Carboniferous and Devonian series. On 30 April 2019, the well reached a depth of 2,286 m in the Lower Triassic series. By the end of May, Radew 1 reached a depth of 3,037 m in the Permian (Zechstein) succession. The final depth was reached on 16 June 2019. Background Information The Tychowo contract was granted to PGNiG on 20 August 2009. The contract had a six-year validity term. On 20 August 2015, the 48/2009/p Tychowo contract was prolonged until 31 December 2016. Concurrently, the permit was diminished in its eastern part and reduced from 807 sq km to 315 sq km. In 2016, the tract was extended and the operator commenced procedure for changing the rights in the tract from exploration to exploration-production. The process was concluded on 3 July 2018 and the designation of the tract was changed from 48/2009/p to 48/2009/L. At the same time, the contract received a new exploration term of five years, until 3 July 2023, and the production term of subsequent 25 years. The latest exploration activity in the area dates back to late 2015/early 2016, when PGNiG completed the acquisition of Drzewiany 3D seismic programme. Earlier, in December 2012/January 2013, PGNiG acquired a 3D seismic survey Rabino, partly covering the Tychowo contract. Targets in the area are related to the presence of the Lower Permian (Rotliegend) sandstone successions and the Upper Permian (Zechstein) carbonate series, proven hydrocarbon series. The latest exploration concepts include also the distribution of the underlaying Upper Palaeozoic - Devonian-Carboniferous - series in the subsurface, with the Carboniferous series being the most promising. Since 2016, PGNiG is progressing a new petroleum concept related to potential presence of hydrocarbon-charged syn-rift structures in the structurally lower parts of the basin. To the west and northwest of the Tychowo region, there are the Daszewo oil, as well as the Bialogard and Daszewo North gas fields. Only a few wells are known to have been drilled within the area of the block, most of them during the 1960s and 1970s. The latest drilling operation in the area dates back to December 2014, when PGNiG abandoned new-pool wildcat Daszewo 27k in the 15/2008/p Bardy permit. The well was drilled to the final depth of 3,727 m in the (undisclosed) Devonian series.

Poland (Pomeranian Trough (Danish-Polish Marginal Trough)) Tychowo

PetroChina – Sichuan achieved a record high shale gas rate in Lu 203 in the Sichuan Basin. This horizontal shale gas appraisal well is located in Luxian County, south of Sichuan province, and has target to assess the Longmaxi shale in deep horizon (>4,000 m). The well completed with a 1,500 m horizontal section and tested 48.7 MMcf/d of gas after fracking under a well head shut-in pressure of 57.1 Mpa and bottom hole temperature of 140 dgr C. PetroChina has completed two shale gas exploration wells in this area. Lu 201 and Lu 202. Lu 202 has been reported to test gas from the Longmaxi shale in 2018.  The company also achieved commercial gas flow from deep Longmaxi shale in Zu 202-H1 and Huang 202 in the south Sichuan province. PetroChina currently has three shale gas field production blocks in the Sichuan Basin - Changning, Weiyuan and Zhaotong blocks with main shale gas production zone in the Silurian Longmaxi Formation, in addition to several exploration blocks in the basin. Overall the company has approved 11 Tcf of gas in place and has completed total 419 shale gas wells, of which 337 wells on stream by end 2019. In 208 PetroChina produced 4.2 Bcm of shale gas from three fields in the Sichuan Basin. The company has target to produce 12 Bcm by 2020 and 24 Bcm by 2025 in the Sichuan Basin.

Lu 203 (PetroChina – Sichuan 100%) horizontal shale gas appraisal well is located in Luxian County. The well completed with a 1500 m horizontal section in Silurian Longmaxi shale in deep horizon (>4000 m) and tested 48,7 MMcf/d of gas after fracking under a well head shut-in pressure of 57.1 Mpa and bottom hole temperature of 140°C.

Ecopetrol has agreed with Shell to acquire a 30% interest in the BM-S-054 contract / S-M-518 block (366 sq km) and Sul Gato do Mato_P2 contract / S_GATO_MAT block (129 sq km), deepwater Santos Basin. The deal is pending necessary approvals. Shell will retain operatorship, Total is otherwise a 20% partner.

Shell (->50% op, Total 20%) has agreed to farm down a 30% WI in the Gato do Mato pre-salt development Block BM-S-54 to Ecopetrol.

Videnska panev VIII block, Vienna Basin, near Lednice field in SE C.R., drilled 24 Jan – 20 Feb ’19, TD 1,450m (Badenian), gas encountered and LT testing over 1,271-1,750m.

Charvatska Nova Ves-10 appr, Videnska panev VIII block, Vienna Basin, near Lednice field in SE C.R, TD 1,450m (Badenian), gas encountered and LT testing over 1,271-1,750m.

On 22 February 2018, the Federal Agency for Subsoil Use held an auction for three blocks in Samara Oblast (Volga-Ural Province). The winning bids were submitted by Rosneft-subsidiary Samaraneftegaz and local companies Nedra and Ekoinveststroy. The winners of the auction will obtain 25-year E&P licenses. Details of the offer are as follows: The Uspenskiy block covers 399 sq km in the conjunction zone of the Tatarskiy Yuzhnyy Dome and the Sokskaya Depression and encompasses unlicensed parts of the Radayevskoye and Oboshinskoye fields with combined 2P reserves estimated at 1.2 MMbbl of oil. Oil resources (category D1) of the block are estimated at 29 MMbbl. The starting price amounted to RUB 23.4 million (USD 0.42 million). Samaraneftegaz offered RUB 1,004 million (USD 17.9 million). The Novogubinskiy block covers 171 sq km in the Zhigulevsko-Pugachevskiy Dome. Seismic coverage amounts to 222 km. Oil resources (category D1) of the block are estimated at 15 MMbbl. The starting price amounted to RUB 3 million (USD 0.05 million). Nedra offered RUB 3.3 million (USD 0.06 million). The Alkinskiy block covers 14 sq km in the Tatarskiy Yuzhnyy Dome. Seismic coverage amounts to 2 km. Oil resources (category D1) of the block are estimated at 2 MMbbl. The starting price amounted to RUB 0.2 million (USD 0.003 million). Ekoinveststroy offered RUB 0.22 million (USD 0.004 million).  

Samaraneftegaz (Rosneft-subsidiary) was awarded Uspenskiy block (399km²) in the conjunction zone of the Tatarskiy Yuzhnyy Dome and the Sokskaya Depression.

The P’nyang South 2 ST1 well, located in PRL 3 in the North-West Highlands of Papua New Guinea, reached a total depth of 2,725 metres on 7 January 2018. As previously reported, the well, which is being operated by Oil Search on behalf of the PRL 3 joint venture, has encountered gas in good-quality Toro and Digimu sands, while the Emuk sands appear to be largely water-bearing. Peter Botten, Oil Search’s Managing Director said: 'We are pleased with the P’nyang South 2 ST1 results, which confirm the extension of the P’nyang field to the south-east. The PRL 3 joint venture is evaluating the well results, including the implications for 1C and 2C gas resource volumes in the field. Oil Search is confident that the well’s primary objective, to migrate 2C contingent gas resource to 1C contingent resource in this area, to support market ing and financing activities for LNG expansion, will be met.' A recertification of the field’s gas resources by an independent expert is underway and is expected to be completed in the second quarter of 2018. The joint venture is also working with the Department of Petroleum to progress the offer of a Petroleum Development Licence (APDL 13) over P’nyang, currently subject to an application. In addition, work is continuing on selecting the optimal development concept for the field. The well is presently being plugged and abandoned, as planned. Original article link Source: Oil Search

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

Pertamina has likely completed operations on wildcat West Gantar 1 in the Jawa Bagian Barat (JBB) PPC, located in the onshore West Java Basin, with results unreported. The well was planned to be drilled to a TD of approximately 3,100 m. Drilling was possibly completed around late August 2017. The well could have targeted Eocene-Oligocene clastics of the Jatibarang Formation in a stratigraphic play. This underexplored deep play is considered as a potential target for future exploration in the mature West Java Basin. As of mid-June 2017, the well was operating at a depth of approximately 2,800 m. The well was spudded in early February 2017, using a land rig operated by Pertamina Drilling Services Indonesia (PDSI). West Gantar 1 was one of three wells drilled by Pertamina in the block during early/mid-2017. The other two wells were Haur Gede 1 and Pondok Makmur Indah 1. Aside from exploration drilling, a 3D seismic survey was completed in the block in December 2016, over the Akasia Besar area. Approximately 99% of the planned area of around 1,120 sq km has been covered by seismic data recording. Pertamina is operator and sole interest holder in the JBB PPC.

Indonesia (West Java B.) Pondok Makmur Indah 1 op. by PERTAMINA (100.0%) in Jawa Bagian Barat (JBB) block

Advent has agreed to the sale of a 90% stake in its subsidiary Onshore Energy, sole holder of EP 386 + RL 1, total 2,722 sq km onshore in the Bonaparte Basin, to an unnamed buyer. Onshore Energy will drill at least 1 explo well and shoot min. 50km 2D seismic data by EP 386 expiry in Mar ’20.

Bonaparte Petroleum has acquired a 90% share in Onshore Energy (OE) subsidiary of Advent Energy which holds a 100% interest in EP386 and RL1.

According to local media reports in mid-February 2020, quoting a senior official at the General Department of Petroleum, Cambodian Ministry of Mines and Energy (MME) has awarded Cambodian Resources Energy Development Co Ltd a petroleum exploration contract for Block D, located offshore in the Khmer Trough. The company is expected to commence studies in the new acreage within 2020, prior to proceeding to potential drilling at a later stage. The contract will have a three-year initial exploration period. The contract agreement was reportedly signed in December 2019. Cambodian Resource Energy Development is a Chinese private company which was registered with Cambodian Ministry of Commerce in April 2017. Preliminary contract negotiations with MME were reported in March 2018. Block D has an area of approximately 5,300 sq km, entirely in shallow water. The block was previously operated by China Petrotech Holdings Limited (CPHL) Cambodia, a subsidiary of Mirach Energy. The PSC for the block was terminated in May 2016. No exploration drilling has been conducted in the block to date, but CPHL acquired a 3D seismic survey in 2006. Block D is located immediately northeast of KrisEnergy-operated Block A (Apsara field), which is expected to come onstream in 2020 as the first oil development in the country. The Cambodian government is targeting to attract new investors to advance the national oil and gas sector. As of February 2020, negotiations were underway with EnerCam Resources Co Ltd for a Production Sharing Agreement over onshore Block VIII. EnerCam is a subsidiary of Canadian company Angkor Resources Corp. Background Information Block D is located north of Kris Energy’s Block A. CPHL completed a 363 sq km 3D seismic survey over Block D in late December 2006. Data acquisition started in mid-November 2006, using the PGS “Nordic Explorer” S/V, but operations were delayed by mechanical problems with the vessel and high seas and strong winds caused by typhoon “Durian”. The company was planning to drill a well in the permit, however the plan did not materialize. CPHL contracted EPRI Bohai to undertake a Petroleum Resources Assessment of Block D and on 16 April 2007, announced that the block could contain up to 226.88 MMbbl (P50) in the oil case or 496.2 Bcf (P50) in the gas case. The assessment also included a comprehensive risk analysis with respect to the oil source, reservoir, migration and preservation and concluded that an exploration drilling programme was required to firm up the reserves.

The authorities have reportedly granted block D, offshore to (Chinese) Cambodian Resource Energy Development Co, the agreement signed in Dec '19. The 5,300-sq km unit (outline yet n/a) lies west of KrisEnergy's block A in shallow waters, previously run by Mirach Energy.

Lesedi CBM project, dual lateral pods (vertical well intersected by 2 laterals), both wells completed with ab. 20 MMcfg/d/pod sustained, co. rig to the Mamba project area. Some 200 km of 2D seismic are planned at Lesedi in 1Q '20.

Lesedi-3 & 4 CBM Lesedi CBM project, dual lateral pods (vertical well intersected by 2 laterals), both wells completed with ab. 20 MMcfg/d/pod sustained, co. rig to the Mamba project area. Some 200 km of 2D seismic are planned at Lesedi in 1Q '20.

Discover Exploration is embarking on a farmout offer for its 25% in the Tullow-operated blocks 35, 36 + 37, total 17,853 sq km in Indian Ocean deepwaters. Drilling is tentatively planned in 2021. Tullow (op), partners Discover + Bahari Res.

Discover Exploration is embarking on a farmout offer for its 25% in the Tullow-operated blocks 35, 36 + 37, total 17,853 sq km in Indian Ocean deepwaters. Drilling is tentatively planned in 2021. Tullow (op), partners Discover + Bahari Res.

AWE Petroleum Pty Ltd commenced flow testing on the Waitsia 4 gas appraisal well in L01, located in the Perth Basin, on 20 November 2017.  Initially well clean-up operations were undertaken, begoe gas flows commenced from a 50 m interval within the Kingia Sandstone.  AWE reported that instantaneous maximum flows of 90 MMcf/d, the highest so far observed from Waitsia wells, occurred. Average flows of 89.6 MMcf/d continued, through a 96/64” choke at 2,395 psi pressure. The well has now been shut-in to allow pressure build up surveys to take place before a series of further flow tests.  The test at Waitsia 4 is being conducted over the 3,370 – 3,420 m interval within the Kingia Sandstone, which was perforated prior to testing.  The strong initial flow rates indicate excellent reservoir quality.  The test is the final one in this appraisal phase, which also saw Waitsia 2 and Waitsia 3 tested. AWE reported that this is the final well test prior to Final Investment Decision (FID) for Phase 2 of production from Waitsia.  The full testing programme was designed to evaluate reservoir flow potential in the southern extent of the field. 

Australia (Beharra Springs Terrace (Perth B.)) Waitsia

Leigh Creek has agreed a 20% farmin to ATP 2023 + 2024 (under appl., resp. 434 sq km + 421 sq km in the Cooper Eromanga, SW Qld) from Bridgeport Energy, the deal subject to govt approval. Leigh Creek has an option to acquire an extra interest in either of both permits by satisfying the funding of 40% of year 1 + 2 activity, and 20% of year 3 + 4 activity.

Leigh Creek confirmed it had signed a farm-in agreement with Bridgeport covering the latter’s ATP 2023 and 2024 permits.