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Corallian is looking to farm out its interests in the Unst and Dunrobin prospects in the Inner Moray Firth ahead of a planned IPO next year. The farmin offer will be presented at the Prospex venue next month in London.

Corallian is looking to farm out its interests in the Unst and Dunrobin prospects in the Inner Moray Firth ahead of a planned IPO next year. The farmin offer will be presented at the Prospex venue next month in London.

Trinidad and Tobago's Ministry of Energy and Energy Industries opened on 2 March 2020 the invitation to companies to participate in the Nomination of Deep-Water Blocks for Competitive Bidding. The 28 blocks offered are in the Deep Water and nominations close on 30 June 2020. Companies can nominate any number of blocks, which are listed below: Deep Water Blocks Available For Nomination Block 24 TTDAA 16 Block 25 (a) TTDAA 17 Block 25 (b) TTDAA 18 Block 26 TTDAA 19 Block 27 TTDAA 20 TTDAA 1 TTDAA 21 TTDAA 2 TTDAA 22 TTDAA 4 TTDAA 23 TTDAA 8 TTDAA 24 TTDAA 9 TTDAA 25 TTDAA 10 TTDAA 26 TTDAA 11 TTDAA 27 TTDAA 12 TTDAA 30 TTDAA 13   TTDAA 31   Any questions should be addressed to [email protected] Kimberlee London                               Keon Dube Senior Geologist (Ag.)                        Senior Geophysicist (Ag.) [email protected]                         [email protected] 225-4EEI ext. 2360                             225-4EEI ext. 2371 The last deepwater bid round offered 36 open deepwater blocks on 5 January 2012. On 4 September 2012 the Trinidad Minister of Energy received 12 bids from industry on 6 deepwater blocks on offer: TTDAA 1, TTDAA 5, TTDAA 6, TTDAA 28, 25(a) and TTDAA 29, and then closed out Competitive Bid Order 2012. Each block receiving a bid received multiple bids, and one block, 25(a) did not receive any bids. The bid round opened on 5 April 2012, and the original bid deadline of 30 July 2012 was extended to 4 September 2012 at the request of several industry players to allow them more time to evaluate data. BHP Billiton was the most active company in the sale bidding on a 100% basis for four of the six blocks on offer (TTDAA 5, TTDAA 6, TTDAA 28 and TTDAA 29). Three new entrants for Trinidad placed bids including Kosmos Energy, Cairn Energy and a consortium led by an Israeli firm, Elenilto which includes partners, Socar and Caspian Drilling. The ministry will now evaluate all the bids and it plans to complete the evaluation by 16 November 2012. Another deepwater sale is being planned for 2013.

Trinidad and Tobago's Ministry of Energy and Energy Industries opened on 2 March 2020 the invitation to companies to participate in the Nomination of Deep-Water Blocks for Competitive Bidding. The 28 blocks offered are in the Deep Water and nominations close on 30 June 2020.

Effective today, Strike acquired a 50% interest + operatorship from Warrego Energy in EP 469, 224 sq km onshore Perth Basin, for AUD 600,000 + funding an explo/appr well (presumably) in the West Erregulla / West Erregulla field area within 24 months, capped at AUD 11 MM. A joint operating agreement will now be set up.

Strike acquired a 50% interest + operatorship from Warrego Energy in EP 469, 224 sq km onshore Perth Basin, for AUD 600,000

According to official reports in mid-April 2019, the Argentine government has granted an offshore exploration permit for the E-1 block (formerly ENARSA 1) to state company YPF via Resolution 196/2019 issued by the Secretary of Energy. YPF will operate the block with 100% interest, following a period of negotiation that began in December 2017 when the company notified the Secretary of Energy (Ministry of Energy then) of its intention to negotiate the conversion of association agreement related to the E-1 block as well as its decision not to convert the association agreements for E-2 and E-3. The contract reportedly will include two phases of exploration with the possibility of a five-year extension and the rights to convert into an exploitation concession. Work commitments consist of 1,500 sq km of 3D seismic and 2,168 km of 2D seismic in the first phase, and the drilling of a well below 1,500 m in the second phase. The latest version of E-1 block covers 14,770 sq km of deepwater acreage with over 4,000 m of depth in Argentina Basin, after 20,294 sq km of the original 35,064 sq km block was relinquished during the negotiation process in late-2017/early-2018. The relinquished area had since been divided into several blocks and offered in Round 1 of the country’s offshore bid round that was launched in November 2018 as CAN-105, CAN-106, CAN-107, CAN-108, CAN-109, and CAN-110. In mid-April 2019, CAN-107 and CAN-109 were in the process of being awarded to a consortium of Shell and Qatar Petroleum, while CAN-108 was in the same process for Equinor following the end of the round on 16 April 2019. YPF has been the operator of the E-1 block since 2006, although originally joined by partners Pampa Energia (formerly Petrobras Argentina), Petrouruguay, and state energy company IEASA (formerly ENARSA) which previously held the licenses over majority of offshore acreage in the country. Background Information ENARSA relinquished its 313,517 sq km of offshore blocks held in 2015, following over a decade of low activity.

The Argentine government has granted an offshore exploration permit for the E-1 block (formerly ENARSA 1) to state company YPF via Resolution 196/2019 issued by the Secretary of Energy. YPF will operate the block with 100% interest

Further to DEA 15 Dec ’17, Levant offshore blocks 4 (1,911 sq km) and 9 (1,742 sq km) have been officially awarded to Total (op), partnered with Eni and Novatek. The JV was the sole bidder for the licences in Lebanon’s 1st round in Oct ‘17. Commitments call for 1 well in each of the 1st + 2nd explo terms.

Lebanon, not found

WPX Energy has closed an agreement to sell its holdings in the San Juan Basin’s Gallup oil play to Enduring Resources IV for $700 million prior to closing adjustments.A significant portion of the proceeds are slated for debt reduction. WPX now believes it can reduce its net debt/EBITDAX to a target level of 1.5x during 2019.The transaction completes WPX’s exit from operations in the San Juan Basin, signaling the company’s confidence in its two remaining core positions in the Delaware (Permian) and Williston basins.'Our path forward is clear and compelling. It’s about consistent execution, sticking with our multi-year plan and continuing to create value by looking ahead,' said Rick Muncrief, WPX chairman and CEO.WPX’s production is now approx. 80 percent liquids (oil and NGL) and 20 percent natural gas. Five years ago, it was the opposite at 80 percent gas and 20 percent liquids. WPX has aggressively transformed its portfolio through nearly $8 billion of transactions.CIBC Griffis & Small provided advisory services to WPX for the transaction. Holland & Hart LLP served as WPX’s external legal counsel.Original articleWPX Energy

WPX Energy has closed an agreement to sell its holdings in the San Juan Basin’s Gallup oil play to Enduring Resources IV for $700 million

East Damanhour Onshore bidding block: Former operators: IEOC (Eni), Conoco, Western Atlas & RWE Part of former Disouq exploration licence (RWE Dea op 50%, INA 50%), relinquishment at expiry of contract (July 2013). Wells drilled in the block (see map below): Sidi Salim 1 (gas shows) and Qawasim 1, Tida 1, Qallin 1, Qallin Southwest 1 and Itai El Barud 1 dry holes. The Disouq, Sidi Ghazy Northwest and Sidi Salem Southeast fields are not part of the block.

East Damanhour Onshore bidding block: Former operators: IEOC (Eni), Conoco, Western Atlas & RWE

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

Cairn is exchanging a non-operating 50% stake with Shell in so far wholly-owned P2379 (Diadem prospect) in return for 50% in Shell’s P2380 (Jaws prospect). Partnership to become 50:50 in both.

On 10 July 2018 the Neuquen provincial government awarded a 35 year unconventional production concession for the 867 sq km Sierra Chata Block, Neuquen Basin. Partners Pampa, ExxonMobil and Total will invest US$ 520 million in a five year unconventional gas project. They will spud 24 horizontal wells, 15 of which target the Vaca Muerta Shale and 9 the Mulichinco Formation. The expansion of facilities and a 3D seismic survey are also planned during the first five years. Interesting volumes of tight gas have been produced from the Mulichinco Formation and the Sierra Chata 130(h) horizontal well was fractured at 1,300m on its horizontal leg to stimulate tight gas objectives with successful results. Tight and shale gas projects are currently ongoing in the Pampa operated Parva Negra and El Mangrullo fields as well. The Rincon del Mangrullo and Rio Neuquen licenses, where YPF shares interest with the company, have been producing increasing volumes of gas. Pampa and ExxonMobil have also fracked the Parva Negra Este x-1001 (h) horizontal well in the Vaca Muerta on the Parva Negra Block. Pampa operates the Sierra Chata with 51%, ExxonMobil holds 45.55% and Total has a 3.45% interest in the block.<P />

Exxon 51%, Pampa 45.6%, Total 3.4% have been awarded 35-year rights to unconventional hydrocarbon exploitation for Sierra Chata block

Samson Offshore LLC has exited the Samurai prospect in Green Canyon block 432 (G32504), selling its 33.33% participating interest, held by its affiliate Samson Offshore Samurai LLC, to BHP Billiton Petroleum (Deepwater) Inc. The Bureau of Ocean Energy Management (BOEM) approved the equity transfer on 24 January 2018 in a transaction that takes effect on 1 December 2017. Samurai is a 2009 subsalt Middle Miocene oil discovery. Former operator Anadarko E&P Company LP made the original find and now owns a 25% stake through its subsidiary Anadarko US Offshore Corporation. Murphy Exploration & Production Company – USA took over as operator in 2013 and hold a 41.67% working interest. The discovery’s G32504 lease is set to expire in May 2018 and the oil find has not yet seen its first delineation well. However, the addition of BHP and other actions taken by Murphy appear to signal that the prospect’s appraisal is forthcoming. The Samurai project lies in some 3,500 feet (1,067 m) of water in the northeast quadrant of the Green Canyon (GC) protraction area, approximately 100 miles (160 km) due south of the coastal support base at Port Fourchon, Louisiana. GC block 432 is a standard-sized 5,760-acre (23.31 sq km) deepwater tract. The lease’s 10-year primary term is on a short fuse, having an expiry date scheduled to expire on 31 May 2018. Samurai has an approved exploration plan on file and Murphy has reportedly awarded a contract to retain the services of the Transocean “Deepwater Asgard” for work in the second quarter of 2018. Given the Samurai lease’s imminent expiration, the ultra-deepwater rig is likely headed to the prospect to commence appraisal drilling of the discovery. The Samson website also notes that the Samurai discovery was to be appraised in early 2018.

BHP acquired Samson’s 33,33% participating interest in the Samurai prospect in GC 432 block (G32504).

According to official reports in late-August 2019, Bolivian subsidiary of Occidental Petroleum, Vintage Petroleum Boliviana, has signed a study agreement with state company YPFB to evaluate the potential of the Cedro, Florida Oeste, La Guardia, and Rodeo blocks. No details are available currently regarding the planned work commitment or amount of investment for the blocks. Cedro, Florida Oeste, La Guardia, and Rodeo blocks are located on the Foothill Belt of Chaco Basin in the western part of Santa Cruz Department, covering 1,002 sq km, 153 sq km, 921 sq km, and 983 sq km of land, respectively. Background Information In 2019, Vintage Petroleum has been focusing on the Chaco Este area on the Foothill Belt of Chaco Basin in the northern part of Tarija Department after the company completed its Chaco Este X1 NFW well as an oil and gas discovery in the Chorro, Tupambi and Iquiri formations in December 2018.

Bolivian subsidiary of Occidental Petroleum, Vintage Petroleum Boliviana, has signed a study agreement with state company YPFB to evaluate the potential of the Cedro, Florida Oeste, La Guardia, and Rodeo blocks. No details are available currently regarding the planned work commitment or amount of investment for the blocks.

Repsol + LLOG are pooling their efforts for projects in several DW GoM blocks. The agreement covers Keathley Canyon blocks 642, 643, 686, 687 + 736, and comprises the Leon + Moccasin nearby discoveries. LLOG will operate Leon with 33% (Repsol 50%), appraisal drilling planned 2H ‘19. Leon will operate Mocassin with 31.35% (Repsol farmed in with 30%).

Repsol + LLOG are pooling their efforts for projects in several DW GoM blocks. The agreement covers Keathley Canyon blocks 642, 643, 686, 687 + 736, and comprises the Leon + Moccasin nearby discoveries. LLOG will operate Leon with 33% (Repsol 50%), appraisal drilling planned 2H ‘19. Leon will operate Mocassin with 31.35% (Repsol farmed in with 30%).

On 2 July 2018, the Federal Agency for Subsoil Use announced an auction for the Nikolskiy-1 block in Tomsk Oblast (Western Siberia). The auction is scheduled on 28 August 2018. Applications have to be submitted by 30 July. The winner of the auction will obtain a 25-year E&P license.  Tomsknedra 634021, Tomsk Frunze Prospekt, 232, office 204 Details of the offer are as follows: The Nikolskiy-1 block covers 1,040 sq km in the Kaymys-Vasyugan Province and encompasses the Lyukpayskoye discovery and a part of the Vakhskoye field, and the Ostrovistaya and Nanyakhskaya Severnaya prospects with combined resources (category D0) estimated at 53 MMbbl of oil. Combined 3P oil reserves of the discoveries are estimated at 5 MMbbl. Hydrocarbon resources (categories D1+D2) of the block are estimated at 92 MMbbl of oil. Seismic coverage amounts to about 1,830 km of 2D data. Five exploratory wells have been drilled within the block. The starting price amounts to RUB 210.678 million (USD 3.3 million).

On 2 July 2018, the Federal Agency for Subsoil Use announced an auction for the Nikolskiy-1 block in Tomsk Oblast (Western Siberia).

Chaotai (Chao-Tai) block, Chaoshan Depression, frontier deepwater E. PRMB, WD 1,000m+, target possibly Mesozoic, ops terminated results n/a early Nov ’17, COSL Prospector SS. 

ST 18-6 (Pr) 1 op. by CNOOC (100%) in PSCA Chao-Tai 1, DW=1000m+, target possibly Mesozoic, ops terminated results n/a.

On 27 August 2019, as part of an announcement related to Total and Qatar Petroleum signing agreements to strengthen partnerships, Total E&P Namibia B.V. (Total) will transfer a 30% interest in PEL 56 (Block 2913B) and 28.33% interest in PEL 91 (Block 2912) to Qatar Petroleum. Block 2913B: the 8,252 sq km Orange Sub-basin block is located to the west of Shell’s Blocks 2913A, 2914B (PEL 039). Water depths across the acreage range from rough 2,500 m in the north east to more than 3,400 m in the south west. Total plans to drill its first Namibian exploration well within the block in 2020, targeting the Venus prospect. Subject to government approval the interest in the block will be Total with a 40% interest. Partners are Qatar Petroleum with a 30% stake, Impact Oil and Gas via its wholly owned subsidiary Impact Oil and Gas Namibia (Pty) Ltd. (Impact) with a 20% stake and NAMCOR with the reaming 10% interest.  Block 2912: the 7,900 sq km Orange Sub-basin block is located adjacent to the west of Block 2913B. Water depth range between 3,000 m and 4,000 m. Subject to government approval Total will operate the block with a 37.78% interest, Qatar Petroleum holds a 28.33 % stake, Impact holds an 18.89% stake and NAMCOR holds the remaining 15% interest.

Total is farming out to Qatar Petroleum a 30% interest in block 2913B (8,251 sq km, Total op, drilling planned in 2020), and 28.33% in block 2912 (7,841 sq km, Total op), deepwater Orange Basin.

Unofficial Mendoza province reports indicate that YPF decided to pay US$ 7 million for non fulfilled exploration commitments to the government on the San Rafael and Nacunal blocks, Cuyo Basin. These licenses were recently relinquished by YPF and government sources said they will be included as an offering for future Technical Evaluation Agreements (TEA). Companies participating in these deals do not have full rights as operators and can make investments but the areas must be retendered before commercial rights are assigned. They have a first refusal option in this case. These blocks were awarded in 2008 to former Kilmer-Ketsal (Vila-Manzano Group), then Andes and currently Phoenix, and were sold to YPF in 2012.

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Press of 15 January 2019 reported that Shell has not received the requested extension for Block 4, therefore, the company lost the asset in October 2017. Shell’s Block 01 is still valid until 2020 has the company was granted a validity extension in 2017. Shell operates the two licences through BG Group plc (60%), which was acquired by Shell in February 2016. Partners are Pavilion Energy and Ophir Energy with 20% interest each. The licences are located in the Mafia Deep Sub-basin (Tanzania Basin). Discussions were ongoing for the development of the discoveries made in the blocks 01, 02 and 04 between the various partners. One of the options in discussion was the construction of an onshore LNG plant. Four discoveries were made in Block 04 between 2010 and 2014 for a total of approximately 5.5 Tcf. The Block 01 holds five discoveries for 1.8 Bcf while the Block 02, operated by Equinor holds seven discoveries for a total of about 17 Tcf.

Shell has not received the requested extension for Block 04, therefore, the company lost the asset in October 2017. Four discoveries were made in Block 04 between 2010 and 2014 for a total of approximately 5,5 Tcf.

PEMEX suspended as an oil and gas discovery the Hok 1 new-field wildcat (NFW) in the AE-0019 block in the Sureste Basin during late-September 2017.  The CNH reported in mid-October 2017 that the well was an oil and gas discovery from the Upper Miocene formation which wasn’t the primary objective.  PEMEX is planning an appraisal well but has yet to make any announcement regarding the discovery.  The NFW reached a total depth (TD) of 6,766 m in early June.  The well was spudded on 1 February 2017.   The NFW had a proposed total depth of 6,750 m.  It was drilled by the “West Oberon” J/U in a water depth of 18 m.  The Middle Cretaceous and Jurassic formations were the primary objectives. The Middle Cretaceous Formation target is located from 5,560 m to 5,600m to 6,000 m while the Upper Jurassic target is located from 6,250 m to 6,750 m. On 15 August 2016, the CNH approved plans by PEMEX to drill the Hok 1. The original plans were to spud the well in September 2016 with conclusion estimated to be in April 2017. The well is a high temperature, high pressure well with temperatures estimated at about 192° C and surface pressures of 9,625 psi.  The structure is a north south trending anticline influenced and partly trapped by a salt diaper and a related reverse fault. The drilling cost for the well is estimated at USD 53.03 million with exchange rate of 18.5 MXN to 1 USD and completion costs are estimated to be USD 19.3 million. The reported reserve estimates for the prospect are 95 MMboe. The well is located in the central area of the block. The nearest well is the Oktan 1A located 7.2 km south-east in the central southern border of the block. SENER awarded the AE-0019-Okom-02 entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 976.40 sq km.  

Hok 1 op. by Pemex (100%) in AE-0019 block area, oil and gas discovery from the Upper Miocene formation

According to local reports in August 2018, Zeus Ol has reached the total depth of 3,900 m (12,795 ft) on the Don Juan 2 stratigraphic well on its 100%-held Boqueron block (formerly known as Cerro Leon) in late-June 2018. The well was spudded in March 2018 with the original planned TD of 4,200 m (13,780 ft). The Boqueron block covers approximately 23,500 sq km of onshore land in the Izozog High and Chaco Sub-basin area of Chaco Basin. Prior to Don Juan 2, Zeus has previously plugged and abandoned the Don Juan 1 earlier in March 2018 at the depth of 2,780 m (9,121 ft) due to technical reasons. The well was spudded in January 2018, after it was originally planned for May 2017, as the program was met with multiple delays due to weather conditions and contract restraints. Planned total depth (PTD) of the well was said to be 3,500 m (11,483 ft), with the purpose of investigating Upper Silurian sandstones as a conventional target and possibly lower Devonian shales for unconventional. Don Juan 2 is the third stratigraphic well in the Boqueron block following Mariscal Estigarribia 1 in 1969, and also only the second well drilled in the block, after Don Juan 1, since Parapiti 1 new-field wildcat (NFW) was plugged and abandoned in July 1977 with oil and gas shows in the same objectives. Background Information According to reports from January 2017, Zeus Ol officially received the Concession Law Contract rights for the Boqueron block by resolution of law No 5761/16 dated 2 December 2016. Prior to the new rights, Zeus Ol has performed a 2D seismic survey covering 1,350 km in 2015 during the Prospection Permit stage.

According to local reports in August 2018, Zeus Ol has reached the total depth of 3,900 m (12,795 ft) on the Don Juan 2 stratigraphic well on its 100%-held Boqueron block (formerly known as Cerro Leon)

On 28 October 2019, the Federal Agency for Subsoil Use announced an auction for six blocks in Yamalo-Nenets Autonomous Okrug (Western Siberia). The auction is scheduled on 18 December 2019 with its application deadline on 26 November. On 13 November, the Agency changed starting prices for the offered blocks and extended an application deadline until 3 December. The winners of the auction will obtain 25-year E&P licenses with a seven-year exploratory stage. Additional information may be requested from: Uralnedra 620014, Yekaterinburg, Vaynera str., 55, office 425, [email protected] The Milisskiy block covers 429 sq km in the Ural-Frolov Province and encompasses the Milisskoye oil discovery with 3P reserves estimated at 10 MMbbl and the Milisskaya prospect (deeper reservoirs) with oil resources estimated at 1 MMbbl. Seismic coverage amounts to 374 km. Six wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 24 MMbbl of oil, 38 Bcf of gas and 1 MMbbl of condensate. The starting price amounts to RUB 121.278 million (USD 1.89 million). The Sopochnyy block covers 2,506 sq km in the South Kara-Yamal Province and encompasses the Sopochnaya prospect with resources estimated at 8.939 Tcf of gas and 79 MMbbl of condensate. Seismic coverage amounts to 1,616 km. No wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 289 MMbbl of oil, 6.418 Tcf of gas and 240 MMbbl of condensate. The starting price amounts to RUB 380.428 million (USD 5.9 million). The Tiltimskiy block covers 2,453 sq km in the Ural-Frolov Province. Seismic coverage amounts to 115 km. No wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 28 MMbbl of oil, 186 Bcf of gas and 4 MMbbl of condensate. The starting price amounts to RUB 8.58 million (USD 0.13 million). The Tydeottinskiy Yuzhnyy block covers 494 sq km in the Nadym-Taz Province. Seismic coverage amounts to 824 km of 2D data and 7 sq km of 3D data. No wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 209 MMbbl of oil, 5.371 Tcf of gas and 82 MMbbl of condensate. The starting price amounts to RUB 88.594 million (USD 1.38 million). The Yampinskiy block covers 1,808 sq km in the Ural-Frolov Province and encompasses several prospects with combined resources estimated at 198 MMbbl of oil. Seismic coverage amounts to 3,178 km. Four wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 140 MMbbl of oil, 247 Bcf of gas and 4 MMbbl of condensate. The starting price amounts to RUB 265.923 million (USD 4.16 million). The Tiltimskiy Severnyy block covers 2,579 sq km in the Ural-Frolov Province. Seismic coverage amounts to 79 km. No wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 30 MMbbl of oil, 195 Bcf of gas and 5 MMbbl of condensate. The starting price amounts to RUB 9.019 million (USD 0.14 million).

On 28 October 2019, the Federal Agency for Subsoil Use announced an auction for six blocks in Yamalo-Nenets Autonomous Okrug (Western Siberia). The auction is scheduled on 18 December 2019 with its application deadline on 26 November. On 13 November, the Agency changed starting prices for the offered blocks and extended an application deadline until 3 December.

Chevron appears to have reversed an earlier decision to sell its local subsidiaries to China’s Himalaya Energy Co for ab. USD 2 bn. Three gas fields are involved which account for 58% of local gas production (Bibiyana field in block 12 and Jalalabad + Moulavi Bazar fields in blocks 13 + 14 in the Northeast). Chevron will reportedly invest USD 400 MM at its Bibiyana field (1.25 MMcf/d).  

Chevron appears to have reversed an earlier decision to sell its local subsidiaries to China’s Himalaya Energy Co for ab. US$2 billion. Three gas fields are involved which account for 58% of local gas production (Bibiyana in block 12 and Jalalabad + Moulavi Bazar in blocks 13 + 14 in the Northeast). Chevron will reportedly invest USD 400 MM at Bibiyana (1,25 MMcf/d).

Expanding its footprint in the highly productive Llanos Basin, Geopark, on 17 December 2019, noted that it, in partnership with Ecopetrol's Hocol subsidiary, was awarded the LLA-124 Block from the Agencia Nacional de Hidrocarburos (ANH) Phase II of the Permanent Process of Assignment of Areas (PPPA). The LLA-124 Block is located adjacent to GeoPark's prolific LLA-34 tract. There, GeoPark operates the LLA-34 Block with 45% interest under its GeoPark Colombia SAS subsidiary and Parex Resources holds 55% WI under its subsidiaries Parex Resources Colombia Ltda (45%) and Verano Energy Barbados Ltd (10%). As for LLA-124, GeoPark will be the operator with a 50% WI and Hocol will hold the remainder. Both Hocol and Geopark bid on another block, LLA-123, at the PPAA Phase II round. In addition to its planned 50% WI acquisition in Parex's LLA-94 Block, GeoPark and its partners have preliminarily identified multiple oil prospects and leads in these blocks. "Geoscience evaluation is ongoing and field operations are expected to start in 2020," GeoPark said.

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23 June 2020, KazMunayGaz (KMG) reports an oil discovery at Bekturly East onshore the Mangyshlak-Central Caspian Basin. Exploration well BV-1 flowed oil naturally at a rate of up to 100 cu m/day (629 b/d) through a 12 mm choke from a Middle Jurassic interval. The crude's specific gravity is 0.82-0.85 g/cu cm (35-41 deg. API). In addition, oil was obtained by sampling other Middle Jurassic as well as Lower Jurassic intervals (unspecified), and oil shows have been registered in the Triassic. Geophysical and hydrodynamic operations are currently underway in the well in order to obtain additional information on the reservoir properties. The contract area is located between the Bekturly field and the large Zhetybay field’s south-eastern flank. The contract is operated by Bekturly Energy Operating LLP, a joint venture company between KMG (50%) and Kokel Munay LLP (50%). The latter finances the exploration operations on a risk basis. Background Information KMG was awarded a contract for Bekturly East in June 2015 and farmed out 50% of its 100% interest to Kokel Munay LLP in December 2015. Kokel Munay is a private Kazakh company which does not appear to have been involved in E&P operations prior to signing the agreement with KMG. At least one exploration well was previously drilled in the Bekturly East contract area – well Bekturly East 90 was P&A’d dry. The neighbouring Bekturly field has eight oil and gas-condensate accumulations in Jurassic sandstones and Lower-Middle Triassic carbonates in a depth range of 1,820-2,860 m. The field was discovered in 1963, its initial 2P recoverable reserves were 6.1 MMb of oil, 4.7 Bcf of non-associated gas and 88 Mb of condensate.

(Mangyshlak-Central Caspian B.) Bekturly East-1 (BV-1) expl op. by KOKEL MUN (50%), KMG (50%) in 4152R Bekturly East block tested up to 629 b/d of 35-41° API oil on 12mm choke from the Middle Jurassic

Siccar Point has sold its 26% interest in the Shell-operated Jackdaw HPHT field to Dyas effective 22 Dec ‘17. Jackdaw lies in P98 (30/2a [Pre + Post-Tertiary areas]), P111 (30/3a Lower) and P672 (30/2d). Partnership now Shell (op), Dyas 26%.

Siccar Point has sold its 26% interest in the Shell-operated Jackdaw HPHT field (P98 & P111 & P672) to Dyas.

An auction is planned 20 Nov ’18 for 25-year  rights to the 506-sq km Promyslovskiy-1 block in the Kalmykia Republic, North Caucasus. Applications are by 11 Oct ‘18. Starting price USD 35,000. Contact: Yugnedra, email [email protected].

An auction is planned 20 Nov ’18 for 25-year rights to the 506-sq km Promyslovskiy-1 block in the Kalmykia Republic, North Caucasus. Applications are by 11 Oct ‘18. Starting price USD 35,000. Contact: Yugnedra, email [email protected].

Point Resources is on the lookout for partners in its wholly-owned PL 001 + 027 (Balder, Ringhorne + Ringhorne East fields) whilst retaining operatorship.

Norway (Utsira High (Horda Platform)) Ringhorne

Reabold Resources plc announced on the 26 May 2020 that it signed a Sale and Purchase Agreement with Humber Oil and Gas to acquire Humber's 16.665% interest in PEDL 183 which contains the West Newton field. The deal completed on 29 July 2020. Consideration for the deal comprised GBP 1.4 million and the issue of 350,000,000 ordinary shares of 0.01p in the capital of Reabold. The acquirer's effective economic interest in the licence increased from 39% to 56% where the interest comprises a 16.665% direct interest and a 39.66% indirect interest via the company's 59.48% shareholding in operator of West Newton, Rathlin Energy which holds 66.67% interest in the licence. Rathlin is planning on drilling two wells at its West Newton B site in PEDL 183, the first is planned to spud in August 2020. Operations are planned to appraise the Kirkham Abbey Formation and also test the deeper Cadeby Formation. One well is planned to be vertical whilst the other will be horizontal. On 15 April 2020 it was reported that Rathlin had commenced preparatory work at its site in compliance with the landowner and regulatory agreements and keeping with the government guidance regarding COVID-19. Operations involve the completion of the access track and site along with tasks in line with the pre-operational conditions set out by Rathlin's Environment Agency and East Riding of Yorkshire Council permissions. On 4 May 2020 it was confirmed that construction of the access track has begun and will five to six weeks to complete. In April 2019 Rathlin drilled appraisal well L46/05-4 (West Newton A-2). The well was successful encountering hydrocarbons (including a significant liquids component) across a 65 m (net) interval in the Kirkham Abbey Formation along with shows in the Cadeby Reef Formation. Drilling operations were concluded after reaching a TD of 2,061 m and a total of 28 m of core was cut and recovered from the Kirkham Abbey reservoir. In an update on 29 August 2019 it was confirmed that testing operations which had kicked-off had been suspended in order to review the well test to investigate an oil column that has been identified through petrophysical evaluations. It is understood that a gross oil column of 45 m had been encountered underlying a 20 m gross gas column in the Kirkham Abbey interval. The Petrophysical studies on core and information from the logs indicates encouraging porosities seen in the oil zone, the core also exhibited natural fracturing. The Extended Well Test was paused to allow for the equipment to be reconfigured to implement a revised production test which will better reflect the oil zone. In 2013 Rathlin 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. It 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 Cadeby 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. Following the completion of the deal interest in the licence is held by Rathlin Energy (UK) Limited (66.67% + operator), Reabold Resources plc (16.665%) and Union Jack Oil Plc (16.665%).

(Anglo-Dutch B.) Reabold Resources plc announced on the 26 May 2020 that it signed a Sale and Purchase Agreement with Humber Oil and Gas to acquire Humber's 16.665% interest in PEDL 183 which contains the West Newton field. The deal completed on 29 July 2020. PEDL 183 op. by CONNAUGHT (42%), REABOLD (41%), UNION JACK (17%).

Petrobras in late March 2020 received approval from the ANP board of directors in its divestment process for producing fields in Rio Grande do Norte called Polo Macau. The sale involves seven onshore and offshore fields in the Potiguar Basin where Petrobras signed a contract with Brazilian operator, SPE 3R Petroleum, a wholly-owned subsidiary of 3R Petroleum e Participacoes. The agreement was for US$ 191.1 million, to be paid in two installments. US$ 48 million was due at the signing in August 2019 and US$ 143.1 million at the close of the transaction after approval by the ANP. The blocks and fields involved are Aratum, Lagoa Aroeira, Macau, Porto Carao, Salina Cristal, Sanhacu and Serra. Petrobras has 100% in all these concessions except Sanhacu where it has 50% and partner Petrogal has the remaining 50%. Petrobras also noted the total oil and gas production in these fields is 5,800 boe/day at the time of the divestment agreement.Petrobras in mid-June 2018 noted the company had advanced to the binding phase for four of its onshore production complexes offered for divestment in northeastern Brazil. The Macau Group was included in this. Petrobras on 25 September 2017 began the launch process by publishing a teaser for the sale of five groups of onshore fields located in the Ceara, Sergipe and Rio Grande do Norte states and totaling 19 concessions. The fields for sale represented a part of the original Topazio project, which planned to divest 104 onshore blocks in nine production groups. Unlike the previous Topazio sales process, the current sales process was approved by the TCU court. <P />

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Kotri North 2568-21 EL, Kirthar Fold Belt, TD 4,340m, susp. late Feb ’18 (tested). Target Lower Goru, Hilong rig 5.

Aliabad 1 op. by UEPL (50%, PPL 40%, Asia Res. 10%) in Kotri North 2568-21 EL, TD=4340m, susp. tested. Target Lower Goru, results n/a.

REC-T-141, NE of Canario field in Recôncavo Basin, assumed P&A dry 25 Nov '19 (no shopws report by then), TD 2,041m, target Agua Grande fm.

Brazil, Agua Grande

Local reports suggest Iran will launch a tender for 14 explo blocks next month, acreage spread out over several basins.  in a variety of basins and comprise both on and offshore opportunities. This follows plans, first aired in 2015, that Iran would tender 18 blocks – meaning that 4 blocks have not made the grate: Withdrawn:

Local reports suggest Iran will launch a tender for 14 explo blocks next month, acreage spread out over several basins. in a variety of basins and comprise both on and offshore opportunities.

The Oil & Gas Authority (OGA) intends to announce the awards of the 30th Seaward Licensing Round in Q2 2018. The Round closed on 21 November 2017 with 96 applications covering 239 blocks received from 68 companies, under the new innovate licence structure. The round launched on 25 July 2017, offering 114,426 sq km of mature acreage, which includes 150 undeveloped discoveries. 820 blocks and part blocks were available for bidding, consisting of 205 in the Southern North Sea, 231 in the Central North Sea, 108 in the Northern North Sea, 195 West of Shetland, and 81 in the Irish Sea. Details at: https://www.ogauthority.co.uk/

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Kazakhstan’s energy minister, KazMunayGaz and Lukoil signed a protocol for direct negotiations on the granting of E&P rights under the banner of joint activities in the Zhenis block, Caspian Sea, for which an E&P contract is yet to be signed. Several key items are included, such as a subscription bonus payment and the use of local workforce and equipment.

Kazakhstan’s energy minister, KazMunayGaz and Lukoil signed a protocol for direct negotiations on the granting of E&P rights under the banner of joint activities in the Zhenis block, Caspian Sea, for which an E&P contract is yet to be signed. Several key items are included, such as a subscription bonus payment and the use of local workforce and equipment.

On 10 October 2017, Stamper Oil & Gas Corp. (Stamper) announced that it had entered into a MOU with State Oil Corp. (State) for the acquisition of the latter’s 100% shares. The MOU is non-binding and subject to State’s final signatures with Sudapet regarding the fam-in of 50% working interest in Block 25 (see here for more information). Following the agreement with Sudapet, Stamper will issue 25,000,000 shares in exchange for 100% of the shares of State and then will be responsible to complete the transactions.

Sudan, Block 25

75% of the blocks on offer in Colombia's 2nd round of the' permanent offer' failed to attract bids, only 15 blocks ended up finding a taker, none offshore. Ecopetrol went for 5 (Llanos-121 + 122, the latter 50:50 with Parex. Hocol (Ecopetrol sub) bid for LLA-100 (100%), LLA-123 + 124 (50:50 with GeoPark). Amerisur, Canacol/CNE, Unión Temporal La Luna Captiva and Gran Tierra also applied, of which VIM-3 (by CNE) and Sinú-26 (by Unión Temporal la Luna Captiva). The official list of bids is expected from ANH on Friday. Deadline for counteroffers is 5 Dec '19, another week then provided to fight it out. Contract signatures as of 11 Dec '19.

75% of the blocks on offer in Colombia's 2nd round of the' permanent offer' failed to attract bids, only 15 blocks ended up finding a taker, none offshore.

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%).

As announced on 27 November 2017, Eni and Sonangol E&P signed a Memorandum of Understanding (MOU) to define joint projects throughout the energy sector value chain. Eni and Sonangol will assess associated and non-associated offshore gas resources to be traded both locally and internationally and identify new opportunities for joint exploration. In addition the MOU provides for the study of optimization measures in the refining and trading sector in Angola and the evaluation of opportunities in the renewable energy sector (in particular photovoltaics).  

Angola, not found

Murphy Oil Corp and Mitsui & Co Ltd are looking to farm out equity in two Bonaparte Basin permits.  Murphy is the operator with 60% interest in AC/P57 and AC/P59, which are located in the Vulcan Sub-basin and cover a total of 1,508 sq km. Joint venture partner Mitsui holds the remaining 40% interest in the permits. Both companies are looking to farm-down around half of their respective interests in return for assistance in funding the future exploration programmes. As of early January 2019 it is thought the companies were looking to conclude the farm-out process. No deals have yet been announced for the acreage. Murphy had been finalising prospect mapping across the acreage before releasing the permits for farm-in early-2018. A data room was opened in Perth from March 2018. Interested parties must book to access and sign a confidentiality agreement. Both areas are fully covered by 3D seismic data with tie-in wells. AC/P59 crosses the Caswell and Vulcan sub-basins between the Crux gas discovery, the Sinopec operated Puffin field and PTTEP operated Montara, Skua and Swift oil fields. AC/P57 lies directly east of the Puffin field within the Vulcan Sub-basin. Murphy considers the permits to be prospective for oil accumulations. Through 18 oil discoveries across the Sub-basin, around 380 MMb oil on a 2P recoverable basis has already been discovered, primarily in the Plover, Vulcan and Puffin sandstones across both stratigraphic plays and structural plays, including unconformities, tilted fault blocks and anticlines. Gas reserves in the basin are around 6 Tcf. In AC/P57 leads have been identified with the potential for recoverable resources of 160 MMb. Murphy has suspended the AC/P57 permit work programme twice since being awarded in 2014 to facilitating time to licence 284 sq km of New Broadband Long Cable Cygnus 3D seismic data over the south east of the permit, at a cost of around AUD 1.97 million, and reprocess the data at an additional cost of AUD 250,000. One exploration well is scheduled in term six in 2021/22. AC/P59 has the primary two prospects in the assets, with Hawking, an anticlinal prospect, and Fisher, a tilted fault block.  Murphy reports it has estimated potential recoverable resources of 350 MMb. The joint venture has made three variations to the work programme since being awarded in 2015. During 2016 Murphy suspended the programme, allowing time to conduct PSTM and PSDM 3D seismic processing of the Cygnus 3D MSS seismic data at an estimated cost of AUD 585,000. During the latest suspension in 2019, Murphy will interpret the data under the original work terms and added a series of seismic related activities, including: reprocessing, AVO analysis and PSDM velocity studies. The first exploration well is scheduled in term 5 – to be drilled in 202/22, at a forecasted cost of AUD 60 million. The Cygnus 3D MSS seismic survey was conducted by Polarcus between December 2015 and December 2017, in three phases.  Polarcus reported that it considered previous seismic acquisition had been sub-optimal and that it did not fully addressed the geological and geophysical challenges within the units of the basin. Subsequently, over 7,000 sq km of data was acquired during the Cygnus survey to address this. The permits were awarded to Murphy with joint venture partner Mitsui on a 50% equity split, in 2014/15. Murphy increased its holding to 60% in 2015. Water depths across the permits range from around 50 to 500 m. Murphy holds 60% interest and operatorship in AC/P57 and AC/P59 through subsidiary company Murphy Australia Oil Pty Ltd. Joint venture partner Mitsui holds the remaining 40% interest in each permit through its subsidiary Mitsui E&P Australia Pty Ltd. Both companies have been seeking to farm-down equity since early 2018. AC/P58 was originally included in the farm-out, but the JV applied to surrender the permit in June 2019. AC/P58 lies north of the PTTEP operated Oliver and Audacious oil fields within the northern extent of the Vulcan Sub-basin. In AC/P58, it was planned to extend the seismic coverage to identify further prospects and leads. Companies interested in pursuing this opportunity should contact: Paul Carroll, Exploration Manager – Murphy Oil Corp Tel: +61 8 6313 5200 Email: [email protected]

Murphy Oil Corp and Mitsui & Co Ltd are looking to farm out equity in two Bonaparte Basin permits. Murphy is the operator with 60% interest in AC/P57 and AC/P59, which are located in the Vulcan Sub-basin and cover a total of 1,508 sq km.

Larich block, Ghadames basin in S. Tunisia, TD 3,572m (Tannezuft fm), 2016 well re-entered for completion (oil) Apr '20, ops concluded early May '20 and rig released. Sodeps = Eni-Etap JV.

Tunisia (Ghadames B.) Laarich E.-3 appr op. by ENI SPA (50%), ETAP (50%), ENI SPA (50%), ETAP (50%) in Laarich block in S. Tunisia, TD 3,572m (Tannezuft fm), 2016 well re-entered for completion (oil) Apr '20, ops concluded early May '20 and rig released.

Pakistan Petroleum Ltd (PPL) has been awarded the Musa Khel 3069-10 EL (Sulaiman Fold Belt) exploration licence on 20 June 2019. The licence, located in the Musa Khel and Zhob districts of Balochistan province, covers an area of 2,176 sq km. Oil and Gas Development Company Ltd (OGDCL) is the partner in this licence with 49% interest, whereas the operator, PPL, holds 51% equity. The block was offered under the ‘Onshore Bid Round 2018’ and PPL-OGDCL joint venture was declared as the successful bidder. The bidding round was launched from 13 September 2018 to 26 November 2018 under which 10 onshore blocks were offered.

Pakistan, Musa Khel 3069-10 EL

Brazil's first pre-salt oil auction on 30 May failed to gather any offers. The auction had future oil output from the Mero (Libra project), Lula and Sapinhoá areas on offer, but only one company showed some interest and failed to turn up at the sale.  Oil from the Tartaruga Verde area was due to be offered too but was not be released since the percentage of govt profit oil is still under negotiation.

Brazil's first pre-salt oil auction on 30 May failed to gather any offers. The auction had future oil output from the Mero (Libra project), Lula and Sapinhoá areas on offer, but only one company showed some interest and failed to turn up at the sale. Oil from the Tartaruga Verde area was due to be offered too but was not be released since the percentage of govt profit oil is still under negotiation.

Guyana continues delivering the goods, this time Tripletail NE of Longtail discovery in the Stabroek deepwater block, WD 2,003m, 33m high-qual reservoir, Noble Tom Madden DS then to Uaru-1 nfw. Meanwhile Ranger-2 appr is drilling using the Stena Carron DS, and will follow with a Yellowtail test. The Noble Bob Douglas DS is at work on Liza devt, and the Noble Don Taylor DS will be brought in next month. ExxonMobil (op), partners Hess + CNOOCI.

Tripletail 1 (ExxonMobil 45% op, Hess 30%, CNOOC-Nexen 25%) NE of Longtail discovery in the Stabroek DW block, 33m oil-bearing, high-qual sst. reservoir. WD=2003m.

On 30 November 2017, Neuquen province governor, Omar Gutierrez, presided over the award of two blocks from the Neuquen Province V Ronda (New Horizons Plan) by provincial company Gas y Petroleo del Neuquen. Norwegian operator, Statoil, was awarded the 133 sq km Bajo del Toro Este Block. US Retamco subsidiary, Retama, was granted rights to the 143 sq km Parva Negra Oeste license. The Statoil offer for Bajo del Toro Este was US$ 14.89 million. It is the first presence of Statoil in the Neuquen Basin which also offered a US$ 2 million entry fee. Retama offered US$ 76.25 million for Parva Negra Oeste and a US$ 10 million entry fee. Last week Petrolera Pampa, was awarded the 120 sq km Las Tacanas Norte Block based on the round.

Argentina, Bajo del Toro

Lufeng Sag, PRMB, South China Sea, WD 150m, ops terminated late Apr '20, results n/a, Nanhai 2 SS. Target Oligo-Miocene clastics.

Lufeng 9-8-1 (LF 9-8-1) nfw Lufeng Sag, PRMB, South China Sea, WD 150m, ops terminated late Apr '20, results n/a, Target Oligo-Miocene clastics.

On 17 June 2019, Ratio Oil Exploration Ltd Partnership entered into an agreement whereby it will sell a 10% interest in the Royee (399) offshore exploration licence to private company, Unibin Capital Ltd. Ratio had previously agreed in March 2019 to sell a 24.99% interest in the licence to Delek Drilling Ltd Partnership. Following receipt of necessary approvals for both transactions, interests in Royee (399) will be Ratio Oil (35.01%), Delek Drilling (24.99%), Edison International SpA (20%, operator), Israel Opportunity Oil & Gas Exploration Ltd Partnership (10%) and Unibin Capital Israel (10%). Ratio has stated that is continuing to negotiate with additional companies for a share of the exploration licence. A new work programme for Royee (399) offshore exploration licence is understood to have been approved by the Petroleum Commissioner on 17 March 2019. The licence has been extended until 14 April 2020 on condition that a drilling contract is signed by 15 June 2019 and that exploration drilling in the licence commences no later than 30 September 2019. The well is expected to be drilled by the Ensco “DS-7” drillship. On 23 May 2017, the Minister of National Infrastructures, Energy and Water Resources approved a boundary change for the exploration licence. The revised licence covers an area of 399.1 sq km. No wells have previously been drilled on the acreage. In late May 2017, the partners released a resources report for the Royee prospect in the Royee (399) licence. According to the report by NSAI, the prospect has best estimate potential resources of 3.4 Tcf of gas with low and high estimates of 2.0 Tcf and 5.5 Tcf respectively.

Ratio Oil Exploration Ltd Partnership entered into an agreement whereby it will sell a 10% interest in the Royee (399) offshore exploration licence to private company, Unibin Capital Ltd. Ratio had previously agreed in March 2019 to sell a 24.99% interest in the licence to Delek Drilling Ltd Partnership.

Tarba Energia has conditionally agreed to purchase the El Romeral-1, 2 and 3 production concessions from Naturgy subsidiary Petroleum Oil & Gas Espana for EUR750,000 (US$ 836,045), as announced on 17 December 2019. Tarba is a joint venture (JV) between Warrego Energy and Prospex Oil and Gas, currently held on an 85/15 split, however Prospex has an option to increase to 49.9% ownership. Warrego will fund the initial consideration for the El Romeral deal and Prospex has 90 days to decide if it will take up to 49.9% share in the project, subject to refunding Warrego the corresponding proportion of the transaction fee. It is not yet clear if Prospex will also be required to pay additional past costs on other Tarba projects in order to exercise its option to increase to 49.9% in the JV. The concessions cover 311 sq km in Andalucia and within Alentejo-Guadalquivir Basin. The acreage contains an integrated gas production and power station where three wells supply gas (gross 2P reserves of 0.3 Bcf) to an 8.1 MW power station (100% owned). The El Romeral area also includes two development locations and 11 very low risk prospects with gross contingent resources of 5 Bcf and prospective resources of 90 Bcf. On completion of the deal a three well drilling campaign is planned to scale up production with planning and permitting work to begin in H1 2020. The production concessions were awarded in July 1994 for a 30-year period and Naturgy currently operates them with 100% equity, held through Petroleum Oil & Gas Espana SA. Gas Natural Fenosa rebranded as Naturgy in June 2018.

Spain, El Romeral-1

Oranje-Nassau, Neptune Energy and Spirit Energy have agreed a deal involving licences P2133 and P2126 which contain the Darach and Aurora prospects respectively. Neptune acquired a 30% interest and Spirit acquired a 35% interest in licence P2133 from Oranje-Nassau which held 100% interest. In P2126 Oranje-Nassau acquired a 15% interest from Spirit and a 20% interest from Neptune. The deals completed in December 2018. The partnership is planning to drill an exploration well targeting the Darach prospect in P2133 in April 2019. Licence P2133 is located approximately 20 km north of the Crosgan discovery. Crosgan was appraised in 2014 by RWE Dea (INEOS). The company encountered gas bearing sands in the Carboniferous Yoredale Formation with 35 ft (11 m) of pay in the targeted Whitby Sandstone and another 26 ft (8 m) of pay in various shallow sands within the overlying Upper Carboniferous section. To the north of P2133 lies acreage operated by partner Spirit Energy from the 29th Frontier Licensing Round and the drilling of Darach could de-risk some of the prospectivity in this area to the north. Licence P2126 is comprised of five blocks – 42/2b, 42/3b, 42/7, 42/8b and 42/9b and covers an area of approximately 825 sq km. The licence was awarded in the 27th Offshore Licensing Round. A 3D seismic shoot was undertaken over the Aurora structure in 2013. Interest in P2133 is held by Oranje-Nassau Energie Resources Limited (35% + operator), Spirit Energy Resources Limited (35%) and Neptune E&P UK Limited (30%). Interest in P2126 is held by Spirit Energy Resources Limited (35% + operator) Oranje-Nassau Energie Resources Limited (35%) and Neptune E&P UK Limited (30%).

Oranje-Nassau, Neptune Energy and Spirit Energy have agreed a deal involving licences P2133 and P2126 which contain the Darach and Aurora prospects respectively. Neptune acquired a 30% interest and Spirit acquired a 35% interest in licence P2133 from Oranje-Nassau which held 100% interest. In P2126 Oranje-Nassau acquired a 15% interest from Spirit and a 20% interest from Neptune.

Caofeidian 22-1-3 (CFD 22-1-3) was suspended (results TBC) on or around 2 November 2019 after having been spudded on or around 16 October 2019, using the "Haiyangshiyou 937" jack-up. The oil and gas exploration/appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations. Caofeidian 22-1-3 is in the CNOOC operated Chengbei Oil Field Block in the offshore Bohai Gulf Basin.

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Wellesley acquired 40% interest from Total and 20% interest from Spirit in PL 685 with effect from 1 July 2018. Four months later, in the same licence, Wellesley then transferred 40% of its equity to Aker BP with effect from 30 November 2018. Both deals were announced on 6 December 2018. The licence covers a 407 sq km area over parts of blocks 34/6, 35/1 and 35/4. The acreage covered by the licence has yet to be drilled. It lies in between the Peon and Garantiana discoveries. The Peon discovery well was located on the apex of a mound structure and targeted a Pleistocene fluvio-glacial / glacio-marine sand body at a very shallow level. A 38 m thick, homogenous, unconsolidated sand was encountered at 574 m (named the Peon Sandstone of the Nordland Group) and 19 m of this contained very dry gas (99.5 vol% methane). The well was re-entered for testing in 2006 but the planned test could not be carried out. Equinor is currently considering developing Peon. If the development of Peon does go ahead it is likely to use an unmanned, remotely operated, stand-alone platform. Estimated recoverable reserves are approximately 690 Bcfg. Total discovered Garantiana in 2012 with 34/6-2 S. The Cook Formation was oil-bearing (gross oil column of 100 m) and was tested at a rate of 4,300 bo/d through a 28/64” choke. Downdip sidetrack 34/6-2 A found the OWC which had not been encountered in the original hole. In 2014 the find was appraised by 34/6-3 S. This well proved a 120 m gross oil column in a very good quality Cook Formation reservoir with no OWC. On test the well flowed at a stable rate of 5,912 bo/d through a 24/64” choke and a maximum rate of 6,919 bo/d through a 28/64” choke. Recoverable reserve estimates were increased to 38-88 MMbo. The reservoir lies at a depth of approximately 3,810 m and has a porosity of 20%. Garantiana partner Point Resources confirmed in April 2018 that the Equinor-operated field will be developed as a subsea tie-back. The host facility was due to be chosen later in 2018. Earlier reports from Wood Group in 2017 showed that the hosts which were being considered were Equinor’s Gullfaks B and Visund facilities. Following the completion of both deals, interests in PL 685 are divided between Aker BP ASA (40% + operator), Wellesley Petroleum AS (40%) and Petoro AS (20%).

Norway (Tampen Spur (Viking Graben Province)) Visund

Twinza is on the lookout for a partner to share in the planned costs of the probable devt of the Pasca A gas + liquids field in PPL 328, offshore Papuan Basin. Twinza is currently sole holder of the 85-sq km permit. Background from GEPS. Contact: Huw Evans, [email protected].

Twinza is on the lookout for a partner to share in the planned costs of the probable devt of the Pasca A gas + liquids field in PPL 328, offshore Papuan Basin. Twinza is currently sole holder of the 85-sq km permit.

On 11 June 2020, Reconnaissance Energy Africa (ReconAfrica) announced it has been granted the PEL 001/2020 petroleum licence in northwestern Botswana, Okavango Basin, for 9,921 sq km. Following this announcement, the company also stated that it has entered into a farm-out option agreement on these lands. This new licence is contiguous to the company's 25,362-sq-km petroleum acreage (PEL 73) in northeast Namibia. Terms of the new licence are as follows: 100% working interest in all petroleum rights from surface to basement, An initial 4-year exploration period, with renewals up to an additional 10 years, in accordance with the Botswana Petroleum (Exploration and Production) Act, Upon declaration of commercial production, the operator holds the right to enter into a 25-year production licence with a 20-year renewal period, in accordance with the Botswana Petroleum (Exploration and Production) Act, Royalties associated with the production licence will be subject to negotiation, in accordance with the Botswana Petroleum (Exploration and Production) Act, and generally range from 3 to 10% of gross revenue from production, The company has committed to a minimum work program of USD 432,000 over the first 4-year exploration period, The corporate tax rate in Botswana is 22%. ReconAfrica also announced that it has already entered into a farm-out option agreement on these lands with an unquoted private company, speculated to be fellow Canadian company Renaissance Oil Corp. The option agreement carries a three-year term, granting the farminee rights to acquire a 50% interest in the licence for an initial payment of CAD 100,000 (USD 74,000), with a further CAD 1 – 1.5 million (USD 740,000 – 1.1 million) due upon final entry, pending approval from the Botswana authorities. In northeast Namibia, ReconAfrica operates the PEL 73 licence with a 90% interest, Namcore holds the remainder.

Botswana, (Okavango B.), ReconAfrica's award of sole rights to 9,921 sq km of Okavango (Kavango) Basin acreage last month at the start of the panhandle in NW Botswana is now named as PEL 001/2020. The contract runs 4+10 years, plus 25+20 years production if warranted.

OMV New Zealand was offering 30 - 60% interest in its 100% owned offshore exploration permits PEP 51906 and PEP 57075, located Taranaki Basin. However, on 26 March 2018 OMV completed a farm-in deal with Sapura Exploration and Production Sdn Bhd for Sapura to acquire 30% interest. The deal also included interest in three OMV/Mitsui joint venture permits in the offshore Taranaki Basin. It is thought that OMV could be seeking to farm-down further interest in the permits. OMV reported that it would ideally like a deal with a partner which would include all assets, but was also considering individual bids, to provide a balanced position as a non-operator within the blocks. OMV continues to operate the permits with 70% remaining interest. OMV reports that PEP 51906 has potential for petroleum systems similar to those seen in the nearby Maui and Maari fields.  The Kaka 3D seismic was undertaken in 2013 in the southeast of the permit, and OMV reported that processing was almost complete in April 2015.  Over half the permit area is covered by seismic data. The Matuku 1 well has also been drilled in the permit. OMV spudded the exploration well on 30 November 2013. The well failed to encounter commercial hydrocarbons, though oil shows were observed.  OMV reports evaluation of the well results is ongoing.   A further drill or drop decision is required by the joint venture by 18 November 2016, with a well to be drilled by November 2017 if opted.  Further to this, an additional drill or drop decision is scheduled for November 2019, which will include a 25% permit area reduction, with a subsequent well required by 19 November 2020. The PEP 57075 area is a favourable structural and depositional geologic setting, on the flanks of the Kora and Pohokura kitchens. There are two historical wells within the permit area – Arawa 1, drilled in January 1992, and Kanuka 1, drilled in October 2007.  Neither encountered significant hydrocarbons. Over 50% of the PEP 57075 permit is covered by seismic data, with reprocessing of 830 sq km 3D and 930 km 2D included as part of the first year work commitments.  A seismic acquisition commitment, of 700 sq km 3D, is required by 31 May 2017.  A drill or drop decision is scheduled by 31 March 2019, with drilling to take place by 31 March 2020 if a well is opted for.  At this point a 50% area reduction is also required. Interested parties can make expressions of interest and sign a confidentiality agreement.  Once this is complete, virtual summary presentations and a physical dataroom will be made available. PEP 51906 was awarded on 19 November 2009 and covers an area of 805 sq km. PEP 57075 was awarded on 1 April 2015 and covers an area of 1,365 sq km. OMV holds 70% interest and operatorship in both permits after farming-down 30% to Sapura in March 2018. Interested parties should contact: Simon Lang, Head of Exploration, Development and Production Address: Level 10, Deloitte House, 10 Brandon Street, Wellington CBD, New Zealand Email: [email protected]   Tim Allan, Exploration and Appraisal Manager Address: Level 10, Deloitte House, 10 Brandon Street, Wellington CBD, New Zealand Email: [email protected]    

New Zealand, PEP 57075

On 22 July 2020, the National Oil and Gas Agency (ANPG) hosted a live broadcast to provide information on several topics related to the 2020-2021 Onshore Bid Round which is expected to open in Q1 2021. Information on the legal and contractual framework, the certification of companies, access to land, environmental considerations, the data package, tax and contractual terms, the promotion of local content and on the bidding process was provided. For example, ANPG will put in place some contractual incentives for the local companies that apply to the licensing round, like reduced rate of petroleum income tax (from 50% to 30%) and exemptions from signature bonuses. However, local firms will not be allowed to cede any part of their ownership to foreign entities while holding the licenses, or they will lose the incentives. The entry fee has been fixed at USD 1 million (non-refundable). The timetable for the 2020-2021 Onshore Bid Round is: 1 October 2020: Pre-announcement of the launch 6 to 22 October 2020: Roadshows 29 January 2021: Launch of the Bidding Round 10 March 2021: Deadline for submission of the bids 11 March 2021: Opening of the bids 26 April 2021: Qualification of the winners 15 May 2021: Attribution of the contracts (and negotiations) 20 August 2021: Signature of the contracts  Paulino Jerónimo, President of ANPG mentioned that “The tenders, which we will start in the last quarter of 2020, are aimed at all companies interested in the development and profitability of the Angolan oil sector. We want to receive proposals from domestic companies as much as we want to receive proposals from foreign companies - those that already collaborate with us and those that have the capacity and look to our country as a good destination for their investments. The Executive and ANPG are committed to this dynamic and to maintaining the relevance of the oil sector in Angola, which is why we are fully available to listen to all stakeholders who come to us”. Given the cancelled 2014/2015 onshore round in which licences were only granted to local companies, Paulino Jerónimo's comment bodes well for the 2020 bid. On 28 May 2020, the ANPG announced that the Data Package related to the Onshore bidding blocks within the Lower Congo (CON1, CON5 and CON6) and Kwanza (KON5, KON6, KON8, KON9, KON17 and KON20) is available. Parties interested in the data package and in participating in a Data Show Room to be carried out by the ANPG, should express their interest via the (www. anpg.co.ao). For additional information: Email: [email protected] Steps taken towards the 2020 Onshore bidding round thus far: On 22 July, the ANPG announced that the bid would open in Q4 2020 and that proposals from both local and international companies would be well received. On 28 May 2020, the ANPG announced that the Data Package related to the Onshore bidding blocks was available. On 10 March 2020, the ANPG announced that it would hold a clarification session related to the 2020 onshore licencing round (this was later postponed due to the COVID-19 pandemic). The aim of the session was to inform interested companies about the legal and contractual framework ahead of the upcoming licencing round (this is assumed to relate to a new model Onshore PSA). It's worth noting that in February 2018, during its annual press conference Sonangol E.P announced that it would develop a new model Production Sharing Agreement (PSA) for Onshore Exploration and Production. The announcement seemed to suggest that no new onshore bidding rounds will take place until the new model Onshore PSA was completed (this seems to be the case). On 4 November 2019, bids are understood to have been opened relating to accessibility studies related to the blocks which will be on offer. The tender was made public on 18 October 2019. On 17 September at the London roadshow event for the 2019 offshore Namibe licencing round, members of the ANPG mentioned that a pre-announcement for the 2020 Onshore Licencing round would be made in November 2019. The plan was to launch the bid in March 2020 and have contracts signed by the end of the year. The 18 February 2019, Presidential Decree No 52/19 set out governments’ general strategy for awarding acreage between 2019 and 2025. According to Presidential Decree No 52/19 a public tender for onshore blocks will take place in 2020, and the ANPG will offer the following blocks: Within the Lower Congo Basin: CON1, CON5 and CON6 Within the Kwanza Basin KON5, KON6, KON8, KON9, KON17 and KON20 Background Information Except for KON20 all the proposed blocks were offered in the cancelled 2014/2015 onshore bidding round. It seems likely that the blocks that attracted most attention then will attract most of the attention in this round. 40 companies submitted bids (predominantly local and with very little or no oil and gas experience). The three Lower Congo Basin blocks (CON1, 5 and 6) are understood to have received 41 bids, whilst the seven Kwanza Basin blocks (KON3, 5, 6, 7, 8, 9, and 17) attracted 43 bids. The most contested blocks were as follows: CON 1: 21 bids CON 6: 16 bids KON 5: 16 bids KON 6: 8 bids KON 17: 8 bids

Angola, not found

An auction is planned 23 Dec '19 for 25-yr rights to the 2,913-sq km Sylvinskiy block in Sverdlovsk Oblast, Ural Foredeep, Volga-Urals. Application deadline 22 November. Starting price USD 110,000. Contact: Uralnedra, [email protected].

Russia, not found

Total has signed an agreement to sell a 25% interest in the Exploration Block 11B/12B, offshore South Africa, to Qatar Petroleum. The transaction remains subject to regulatory approval.   'This transaction enhances the partnership on Block 11B/12B in preparation for the high potential exploration well scheduled to be drilled on the block at the end of 2018. Total is delighted to broaden its long-standing relationship with Qatar Petroleum and combine efforts to explore this promising region offshore South Africa,' commented Arnaud Breuillac, President, Exploration & Production at Total. Commenting on the agreement, Mr. Saad Sherida Al-Kaabi, the President & CEO of Qatar Petroleum said 'We are pleased to join our long-time partner Total in exploration activities in this frontier block offshore South Africa. This is an important milestone in our strategy to expand our international upstream footprint. We hope that the exploration efforts are successful, and we look forward to collaborating with Total, CNR, Main Street, and the South African authorities on this project.'   The Block 11B/12B is located in the Outeniqua Basin, around 175 kms off the southern coast of South Africa, and covers an area of 19,000 sq kms with water depths ranging from 200 to 1,800 meters. Upon receiving all regulatory approvals the new partnership structure will be as follows: Total (operator, 45%), Qatar Petroleum (25%), CNR international (20%) and Main Street (10%). Note: Total acquired its original interest in Block 11B/12B from CNR International in 2013: See: Total acquires offshore exploration interests in South Africa Original article link Source: Total / energy-pedia

Qatar, not found

It was announced on 19 January 2020 that Turkiye Petrolleri A.O. (TPAO) has been awarded the G16-C onshore exploration licence (Thrace Basin) on 9 January 2020 for a period of five-year. The licence, covering an area of 348 sq km, is located towards northwest of the country and TPAO will be 100% owner and operator of the licence. TPAO had filed the application on 2 August 2019. Arar Petrol ve Gaz Arama Uretim Pazarlama A.S was also interested in G16-C block and, as announced on 7 May 2019, the company had submitted an exclusive application for the exploration licence on 24 April 2019.

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

On 28 November 2018 Petrobras announced a final agreement with French operator Perenco for US$ 370 million to divest three oil fields in the Polo Nordeste package on the Campos Basin shelf. The three oil fields Pargo, Carapeba and Vermelho began production in 1988 and are Round Zero concessions from 1998 producing a combined 9,000 bo/d, according to Petrobras. Currently, the fields have an integrated production system consisting of seven jacket fixed platforms which goes onshore by pipeline from the Garoupa platform to the Cabiunas Terminal. Regarding the transaction, 20% will be paid at the deal signing (US$ 74 million) with the rest to be paid upon final approval and closing of the transaction, subject to adjustments. The transaction is subject also to the usual approval by the ANP and other regulatory agencies. Perenco will operate the concessions with 100% working interest after the deal is closed. The divestment was the result of a competitive bid process by Petrobras as reflected in the company's 2018-2022 Business and Management Plan.

Perenco, acquired the Pargo, Carapeba and Vermelho shallow-water fields from Petrobras for US$370 MM.

Faroe Petroleum reported on 12 February 2017 that it has sold 17.5% of its 25% interest in PL 586, which contains the Fenja field, to Suncor for a sum of USD 54.5 million. The Fenja PDO was submitted in December 2017 and this deal is subject to the PDO being approved. Fenja contains recoverable reserves of 97 MMboe and is due onstream in 2021. Faroe has aligned its equity holding across the greater Njord area with this deal and Suncor reports that the asset is a strategic fit within its offshore portfolio. The deal is awaiting government approval and is expected to close in Q2 2018. Fenja consists of the Pil and Bue accumulations. Operator VNG will develop Pil initially, using a subsea tieback to the Njord A platform. The development will use two subsea templates hosting three horizontal producers, two water injectors and a single gas injector. Bue represents upside and will be confirmed by Pil development wells before it is potentially brought into production at a later date. Oil will be processed on Njord A before being transferred to Njord B for onward export via shuttle tanker. Gas will initially be re-injected into the Pil reservoir and will later be exported via Njord’s connection to the Asgard Transport System. According to the impact assessment from June 2017, oil production is expected to peak at approximately 42,000 bo/d in 2023 with gas production expected to peak at approximately 100 MMcf/d between 2025 and 2036. Total investment costs are approximately NOK 10.2 billion (USD 1.22 billion), with a 16 year field life forecast. Interest in PL 586, following the completion of this deal, will be divided between VNG Norge AS (30% + operator), Point Resources AS (45%), Suncor Energy Norge AS (17.5%) and Faroe Petroleum Norge AS (7.5%).

Suncor Energy has acquired 17,5% stake from Faroe Petroleum (-> 7,5%, VNG 30% op, Point Resources 45%, ) in -operated PL 586 (Fenja field) for US$54,5 MM.

Add. DEA 21 Dec ’17 (status) : SW part of AE-0094-Cinturon Plegado Perdido-12 block, GoM Basin, WD 1,317m, P+A dry at TD 6,510m in late Dec ’17, Centenario GR SS. Target Wilcox.  

Mexico (Tampico-Misantla B.) ? op. by PEMEX (50.0%, RWE 50.0%) in 2 block

Local sources report ExxonMobil has been awarded sole rights to 2 offshore blocks, North Marakia, 4,860 sq km in the Herodotus Basin off the N. coast, and NE El Amriya, 2,200 sq km in the Nile Delta. Seismic is expected to start in 2020.

ExxonMobil (100%) has awarded in a non-competitive way 2 offshore blocks : the North Marakia Offshore (block 4) and NE El Amriya block 3, (2,200 sq km) in deepwaters of the Nile Delta and offered by EGPC in its 2018 round..

Lindero Atravesado block, Neuquén Basin, TD 5,292m, susp w.o. test mid-Oct ‘18. Target Vaca Muerta. PAE (op), partner YPF.

Argentina, Lindero Atravesado (Unconventional)

Shaya High of Tabei Uplift, near Yara field in Tarim Basin, tested 1.7 MMcfg/d from the L. Tertiary Kumugeliemu fm, 1st commercial find in area.

(Tarim B.) Xinghuo 6 nfw, operated by Sinopec – Xibei (100%) in Tianshan Southern Margin block, tested gas which flowed 1.7 MMcf/d of gas in the Lower Tertiary Kumugeliemu Formation. This nfw is located in Shaya High of the Tabei Uplift, the success of the well indicated prospective exploration potential in this area.

On 15 December 2017, the Federal Agency for Subsoil Use held an auction for the Lepchinskiy block in Krasnoyarsk Kray (Eastern Siberia). Fund Energy-subsidiary NovoKhim won the contest with the offer of RUB 25.3 million (USD 0.43 million). The winner of the auction will obtain a 27-year E&P license including a 7-year exploratory stage. The Lepchinskiy block covers 3,379 sq km in the Baykit Basin. Seismic coverage amounts to 600 km. No wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 175 MMbbl of oil and 1,199 Bcf of gas. The starting price amounted to RUB 23 million (USD 0.39 million).  

Russia, not found

Santos Ltd increased its interest holding in exploration permit WA-01-P, located in the North Carnarvon Basin, on 22 December 2017.  Santos has acquired an additional 22.44% interest from joint venture partner and operator Quadrant Northwest Pty Ltd. Santos previously held a 22.56% interest in the permit. This has been transferred to subsidiary Santos Offshore Pty Ltd and an additional 22.44% interest acquired from Quadrant to take Santos’ holding to 45%. At the time of this deal, Santos also acquired a 45% interest in a number of other Quadrant permits within the North Carnarvon Basin – WA-43-R, WA-50-R, WA, 55-R WA-499-P and WA-501-P.  Santos previously had no holding within these permits. WA-01-P, which covers an area of 402 sq km, was awarded on 15 November 1968.  Now that Santos has increased its interest holding, participants in the permit are Quadrant Northwest Pty Ltd (55% + Operator) and Santos Offshore Pty Ltd (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%).

Hugrijan ML, Assam-Arakan Basin, drilled 13 Mar – May ’18, TD 2,741m, target Barail fm.

Lohali W.-1 expl Hugrijan ML, Assam-Arakan Basin, drilled 13 Mar – May ’18, TD 2,741m, target Barail fm.

Shuangyushi prospect in the Jiange area, Sichuan Basin, compl. 20 Feb ’18 at TD 7,641m (Devonian Jinbaoshi fm).  Main targets Permian Qixia + Maokou fm’s.

Shuangtan-10 China, Shuangyushi prospect in the Jiange area, Sichuan Basin, compl. 20 Feb ’18 at TD 7,641m (Devonian Jinbaoshi fm). Main targets Permian Qixia + Maokou fm’s.

GeoPark has agreed to acquire LG Intl Corp’s interests in GeoPark’s Colombian and Chilean operations and subsidiaries, boosting the latter’s interest to 100% throughout. The key prize is LLA 34 (GeoPark operated, 45%). The deal is valued at USD 81 MM on closing + USD 30 MM by 2020, as well as 3 USD 5 MM contingent payments. The deal closes today.

GeoPark (->100%) announced acquisition of 55% interest in LLA 34 Block from LGI (LG International).

W-C part of AE-0007-2M-Amoca-Yaxche-05 block, offshore Sureste Basin, WD 94m, P&A dry at TD 2,374m mid-Jan ‘19, West Titania JU. PTD was 6,540m, target Cretaceous + Jurassic, a sidetrack is planned.

Pox 101EXP (NFW) (Pemex 100%) in AE-0007-2M-Amoca-Yaxche-05 entitlement block, The well had a proposed total depth (PTD) of 6540 m and the primary targets were the Cretaceous and Jurassic formations. P&A dry.

BP and ConocoPhillips are said to be discussing a possible asset swap which would see BP take on COP’s stake in the Clair field in exchange for BP assets in Alaska. COP had been seeking to sell its 24% in the 8-bn bo field West of Shetlands since 2014. It lies in PL 169 / blocks 206/7a, 206/12, 206/8, 206/11a, 206/13a + 206/9a.

United Kingdom, Clair

WHg-2 field area, AESHE 1 (Dev) block, Abu Gharadiq Basin, compl. oil at TD 3,400m, to be placed on stream. Targets Abu Roash G + Bahariya.

Alam El Shawish E.-1 1/1ST expl. WHg-2 field area, AESHE 1 (Dev) block, Abu Gharadiq Basin, compl. oil at TD 3,400m, to be placed on stream. Targets Abu Roash G + Bahariya.

Baratai 3371-17 EL, so far-undrilled, Potwar Basin, TD 5,014m (Paleocene) in Nov ‘17, gas-cond. discovery, tested 15.4 MMcfg/d + 360 bc/d on 1/2” choke, TCPDC-II rig. OGDC (op), partner Khyber Pakhtunkhwa O&G.

Dhok Hussain 1 op. by OGDCL (97,5%, KPOGCL 2,5%) in Baratai 3371-17 EL block, g & cond. disc.15,4 MMscf/d and 360 bc/d [32/64" choke].

1st well in PL 751, ab. 17km SE of Njord in WD 314m, P&A’ing dry at TD 2,152m (Åre fm), Deepsea Bergen SS then off to 35/11-22 S (Bergand) in PL 248 C. Targets Tofte, Tilje + Åre fm’s. Equinor (op), partner Petoro.

Norway (Donna and Halten Terraces (Voring B.)) Njord

1st of 3 planned wells in the area of PL 869 Alvheim area), o&g encountered, 45-153 Mmboe est. as per pre-drill, a part may straddle the UK-Norwegian border. Drilling continues, Scarabeo 8 SS. Aker BP (op), partners Lundin + VÃ¥r Energi.

024/09-14 (Froskelaar Main) (AkerBP 65%, Point Res. 20%, Lundin 15%) in PL 340 licence, uncovered a sizeable discovery, hit oil and gas shows in the targeted reservoir that has estimated gross resources of between 45-153 MMboe, in line with a pre-drill estimate.

Pandion has agreed with Equinor to acquire a 20% stake in PL 263 D + E (Appolonia prospect) in the Haltenbanken area, blocks 6407/1 + 6507/10. PL 263 E is a new area to be carved out from PL 263. Resulting partnership Equinor (op), partners Spirit Egy + Pandion. The deal is contingent on completion of the carve-out of PL 263 E from PL 263 and is subject to customary conditions for completion.

Norway, PL 263 D

On 20 December 2017, Eni SpA announced that it had signed a Petroleum Agreement with Morocco national company, ONHYM, to enter the Tarfaya Offshore Shallow exploration permits I-XII.  According to the agreement, which is subject to the approval of the Moroccan authorities, Eni will be the Operator of the license with a 75% interest, while ONHYM will retain the remaining 25% interest. The permits cover an area of 23,900 sq km, with a water depth ranging from 0 to 1,000 m. The licence covers 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.  

Morocco, not found

S. part of G-13 oil discovery area in block S, offshore Rio Muni Basin, WD 800m, TMD 4,400m in late Oct '19, 39m net oil pay in the Santonian, Maersk Voyager DS. The scale of the resources is under evaluation, well in tieback range of the Ceiba FPSO. G-13 'ILX' stands for Infrastructure-Led Exploration.

S-5 (G-13 ILX) expl. (Kosmos ) S. part of G-13 oil discovery area in block S, 39m net oil pay in the Santonian, The scale of the resources is under evaluation, well in tieback range of the Ceiba FPSO. G-13 'ILX' stands for Infrastructure-Led Exploration. WD=800m, TMD= 4400m.

In August 2019, Parex Resources reported oil in the Cepsa-operated Tamariniza 1 new-field wildcat (NFW) on the Merecure Block of the Llanos Basin. Tests yielded some 800 bo/d gross. The well was spudded on 12 March 2019 and reached a total depth (TD) of some 1,577 m (5,173 ft) on 25 March 2019. Cespa operates the Merecure Block with 70% interest, while partner Perenco holds the remaining 30%. Acquired in Q1 2019, Parex’s 35% operating interest on the Merecure is subject to terms of regulatory approvals.   Background information In mid-May 2014, industry sources reported that Cepsa is testing the Alazan Norte 1 new-field wildcat (NFW) well in the Merecure Block, located in the Llanos Basin. The well was spudded on 5 April 2014, and reached total depth (TD) of 1,860 m (6,102.6 ft) - however details have not been released. The C7 is the main target. The operator drilled one well in the block, Alazan 1 NFW, in early 2012, which was plugged and abandoned (P&A) dry. The interest holders in the block, located in the Llanos Basin, are the operator Cepsa with 70% and Petrobras with the remaining 30%. Cepsa announced on 26 March 2013 its plans to farm out 25% of the block. In December 2014, Cepsa continues plans for a 3D seismic program over the Merecure Block, located in the Llanos Basin. The Yarumo 3D acquisition will include some 150 sq km and is slated to commence in January 2015. The operator completed a 330 sq km 3D seismic survey over the block in 2012. The interest holders in the Merecure Block are operator Cepsa with 70% and Perenco with the remaining 30%. In November 2008, Cepsa farmed-out a 30% interest in the block to Petrobras. On 15 September 2008, Cepcolsa signed an Exploration & Production contract with ANH for the 2,383.89 sq km Merecure Block, approval was received on 8 August 2008. The block is located in the Llanos Basin in the Casanare Department and was carved out of the Agua Verde TEA. During the 16-month Phase I, the company was required to acquire 170km of new 2D seismic data. On 21 February 2008, prior to the 21 August 2008 expiry of the Agua Verde Technical Evaluation Agreement (TEA), Cepsa filed an application for an E&P contract (Merecure) over a portion of the area.

Tamariniza 1 new-field wildcat (NFW) (Cepsa 70% op., Perenco 30%) on the Merecure Block, oil disc. tests yielded some 800 bo/d gross. TD=1577m 25 March 2019. Cespa operates the Merecure Block with interest, while partner Perenco holds the remaining 30%.

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

Botswana, Kalahari

Hurricane Energy announced on 3 September 2018 that it had agreed a deal for Spirit Energy to farm-in to licences P1368 and P2294 taking a 50% interest in the licences through acquiring Hurricane subsidiary Hurricane Resources Limited. Licence P1368 contains the Lincoln discovery and P2294 contains the Warwick prospect, jointly the area is known as the Greater Warwick Area (GWA). Hurricane report that itself and Spirit Energy is looking towards a Final Investment Decision (FID) for full development on the GWA by 2021 with a view to start drilling operations in 2019 with first oil with the Transocean Leader (S/S) (following early production phase in 2020). To potentially unlock 500 MMboe the companies will approach the project in two phases. The first Phase in 2019 will see Hurricane fully carried through USD 180.6 million (gross) programme to drill, log and test three exploration and appraisal wells on the Lincoln discovery and Warwick prospect. In addition to this, the money will be used to tie-back one or more of the GWA wells back to the Floating, Production, Storage and Offloading vessel the “Aoka Mizu” in 2020 along with carrying modifications to the FPSO. The second phase in 2020, assuming phase 1 is successful and FID is made, the GWA wells will be tied-back to the FPSO, and tie-in to the West of Shetland Pipeline system for gas export allowing for first oil via an Early Production System by Q4 2020. There is a further contingent payment in the region of USD 150 – 200 million by Spirit Energy for Hurricane’s carry of full field development costs. It was confirmed by the OGA that the deal completed on 22 August 2018. Hurricane is in the process of nearing its first Early Production System on the Lancaster field. The company focuses on Fractured Basement in the West of Shetlands. It had been looking for partners for the Lancaster development but still remains 100% in the project. In early August 2018 Hurricane announced that it was nearing the end of the offshore installation process at Lancaster. Once all infrastructure is in place the company hopes to achieve first oil by early 2019. Following completion of the deal interest in P1368 and P2294 will be held by Hurricane Energy Plc (50%) and Spirit Energy (50%).

Hurricane Energy announced on 3 September 2018 that it had agreed a deal for Spirit Energy to farm-in to licences P1368 and P2294 taking a 50% interest in the licences through acquiring Hurricane subsidiary Hurricane Resources Limited.

Further news regarding wildcat Selnica 1 IS (Istok - East) in the Zebanec mining plot, enclave within the Sjeverozapadna Hrvatska 1 (SZH-1) block in northern Croatia, states that the well was abandoned dry in the Mesozoic limestone series. INA Industrija Nafte d.d. (INA) was the sole operator of the well. Selnica 1 IS was spudded on 24 December 2019, using the National 402 drilling unit from Crosco Zagreb. The Zebanec mining plot is located close to the border with Hungary and Slovenia. It falls within the Mura Sub-basin, tectonic unit of the Pannonian Basin. The well was targeting the Lower/Middle Miocene sandstone successions, with secondary target in the Mesozoic karstic series. The initial planned total depth was 1,750 m. On 15 January 2020, INA reached the final depth of 1,739 m (TVD 1,693 m) in Selnica 1 IS. News is that the well encountered wellbore stability issues/circulation losses and the operation was suspended. It is understood, the well was deepened to reach the final depth of 2,081 m (TVD 2,053 m) in the Mesozoic limestone series. Some sources suggest the well was with oil and gas shows. Background Information The Selnica field is the second oldest commercial oil field in the country. Oil seeps have been recorded from the nearby Peklenica region since 1788 and commercial exploitation from shallow mineshafts began in 1868. The first commercial oil well in this field was drilled in 1885. Between 1954 and 1956 Singer drilled the Selnica 1 exploration well to a total depth of 2,814 m and found oil in the Abichi Mb. The field was abandoned in 1965. News in 2018 was that INA is planning to drill appraisal Selnica 1 IS, but the project was deferred.

Further news regarding wildcat Selnica 1 IS (Istok - East) in the Zebanec mining plot, enclave within the Sjeverozapadna Hrvatska 1 (SZH-1) block in northern Croatia, states that the well was abandoned dry in the Mesozoic limestone series.

Bengal has an agreement with Santos + Beach to take on full ownership of PL 114 (Wareena field), 157 (Ghina), 188 (Ramses) + 411 (Karnak), total 267 sq km in the Cooper-Eromanga as well as related infrastructure. The deal is subject to usual approvals:

Bengal Energy acquired 100% interest in four petroleum leases PL 114, PL 157, PL 188 and PL 411 from Santos and Beach Energy, which hold the four licences currently.

Lundin was awarded the first CarbonClear certification by Intertek on 29 July 2020 for its Edvard Grieg field. The award recognises Edvard Grieg as one of the least carbon intensive fields globally and acknowledges the company's commitment to a low carbon energy future. The certification is designed to provide independent verification of carbon emission performance across all stages of exploration and production whilst driving a reduction of the energy sectors carbon footprint. On 31 March 2020 Lundin approved the name change, proposed in January 2020, from Lundin Petroleum AB to Lundin Energy AB. Whilst proposing the name change the company simultaneously launched its decarbonisation strategy, aiming to result in carbon neutrality by 2030. As part of this strategy it intends to limit its operated and non-operated portfolio carbon intensity to under 4kg of CO2 per boe from 2020 and to under 2kg per boe from 2023. The full electrification of Edvard Grieg and Johan Sverdrup from 2022 will enable carbon intensity at both fields to be less than 1kg per boe. As part of Johan Sverdrup Phase II, due in 2022, a power-from-shore solution had been designed to supply the Edvard Grieg, Gina Krog and Ivar Aasen fields in addition to Johan Sverdrup. On 28 October 2019 Equinor announced that the reach of this solution, known as the Utsira High Area power grid, had been expanded to include six more fields: Gudrun, Gungne, Sigyn, Sleipner, Solveig and Utgard by way of a connection from Gina Krog to the Sleipner field centre. The power-from-shore solution for the first phase of Johan Sverdrup was switched-on on 9 October 2018, replacing the temporary generators which had been working at the field previously. Johan Sverdrup came onstream on 5 October 2019. Interest in Edvard Grieg is held by Lundin Norway AS (65% + operator), OMV (Norge) AS (20%) and Wintershall Dea Norge AS (15%).

Norway (Utsira High (Horda Platform)) Edvard Grieg

Ramba Energy Limited announced on 12 June 2018 that the company-owned subsidiary PT Hexindo Gemilang Jaya’s farm-out deal in Lemang PSC to Mandala Energy, has received approval from SKK Migas on 5 June 2018. With the closing of the deal, Mandala has 50% operating interest, while Hexindo and Eastwin Global hold 16% and 34% participating interest respectively. Mandala also holds an option to acquire an additional 6% interest from Hexindo. The option can be exercised by Mandala within 30 days from completion of the farm-out deal. The block produced approximately 1,000 bo/d in February 2018. On 18 September 2017, Hexindo came into agreement to farm-out 15% of its participating interest in the PSC to Mandala Lemang Singapore Pte. Ltd. In the farm-out deal, Hexindo also offered an option to acquire additional 6% of its participating interest to Mandala. Mandala had the right to acquire the additional 6% within the offer period, beginning on the completion date of the farm-out agreement or one business day after 1 January 2018, and ending on 31 March 2018. On 14 March 2018, Mandala Energy and Hexindo Gemilang agreed to extend the option period until 30 days after completion of the farm-out. In case of Mandala exercising the option, its interest would further increase to 56% and Hexindo would retain 10%. The decision for the farm-out was made to maintain the company’s cash flow despite the current oil and gas economic situation. On 24 May 2017, Ramba Energy announced the transfer of operatorship for the block from its subsidiary Hexindo to Mandala. Transfer of the operatorship was approved by SKK Migas on 17 May 2017. The block started producing oil in November 2016, from the Akatara field. As of late February 2017, production was reported to be reaching 300 bo/d, plus around 2 MMcf/d of flared gas. It is targeted to increase production rate to 1,500 bo/d for the year. Background Information First oil production from the Akatara field in the Lemang PSC was achieved on 16 November 2016. The milestone was reached following to the issuance of the necessary forestry lease permit by Indonesian Ministry of Forestry and Environment. Initial production is expected to reach 500 bo/d from the Akatara 2 well. The operator plans to increase output with additional production from other existing wells and from new development wells to be drilled from 2017 onwards. The development plan for the block includes the recompletion of exploration wells Selong 1, Akatara 1 and Akatara 2, followed by eight new development wells and two step-out wells. Production was initially achieved through temporary facilities (Early Production Facilities). In this early stage, oil is transported by truck to the Tempino field and from there is pipelined to the Plaju refinery. In a later phase, the operator plans to install permanent facilities, possibly with a higher production capacity. A new pipeline is also planned to be built, in order to connect the block directly with the Plaju refinery. The block is expected to produce up to 4,000 bo/d during the early production phase. Commercial gas production is expected to commence at a later stage. According to local media, quoting the operator in late February 2017, the block could potentially produce approximately 10,000 bo/d by 2022 if further development activities are conducted.

Ramba Energy Limited announced on 12 June 2018 that the company-owned subsidiary PT Hexindo Gemilang Jaya’s farm-out deal in Lemang PSC to Mandala Energy, has received approval from SKK Migas on 5 June 2018.

On 1 January 2018, Pakistan Petroleum Ltd (PPL) announced further details about the successful Naushahro Firoz Hor 1 (NF-Hor 1) tight gas appraisal well drilled within the Naushahro Firoz 2668-9 EL (Middle Indus Basin) onshore concession. The well was drilled to a TD of 4,940 m (3,521 m TVD) using the Hilong Oil Service’s ‘HL-17’ land rig and it include 1.3 km horizontal section in the carbonates of Jurassic Chiltan Formation. The well was completed with 10-stage open hole packers and fracking sleeves within the Chiltan limestone – all 10 stages were tested which after fraccing and acidisation flowed 4.5 MMcfg/d with 1,850 psi flowing wellhead pressure. This is considered as one of the deepest and longest horizontal well in tight carbonate reservoir within the country. It was drilled as a sidetrack from the company’s Naushahro Firoz X-1 (NF X-1) discovery well after re-entering on 11 May 2017. A 7” liner was set at 3,653 m. On 20 July 2017, PPL had announced the successful drilling of Naushahro Firoz Hor 1 (NF-Hor 1) tight gas well. The preliminary results indicated that the well flowed 1.3 MMcfg/d and 9 bc/d through 32/64” choke. This flow rate was from stage 1 whereas PPL had a plan to carry out 10 stage multi frac job which could significantly increase the flow potential. PPL had announced the Naushahro Firoz X-1 tight gas discovery in March 2014 which was drilled to a TD of 3,773 m in the Chiltan Formation. A cased hole drill stem test (CHDST) was carried out and flow rates from the well, after acidisation, varied from a maximum of 11.2 MMcfg/d (along with 120 bc/d) at flowing wellhead pressure (FWHP) of 2,635 psia to a minimum of 1.7 MMcfg/d at FWHP of 375 psia through a 32/64” choke. The block, which covers an area of 2,494 sq km, is located in the Naushahro Feroz and Nawabshah districts of the Sindh province. It was exclusively awarded to PPL on 4 June 2010. PPL then assigned 10% working interest in the block to Asia Resource Oil Ltd with effect from 26 May 2011, as a result, the current equity split is as follows: Pakistan Petroleum Ltd (90%, operator) and Asia Resource Oil Ltd (10%).  

Pakistan (Indus B.) ? op. by PPL (90.0%, ASIA RES 10.0%) in Naushahro Firoz 2668-9 EL block

On 27 September 2018 GSNZ SPV1 Ltd completed the acquisition of interest and operatorship of the Ahuroa asset, located in the Eastern Taranaki Mobile Belt, from Contact Energy Ltd.  GSNZ has purchased the Ahuroa production permit, PMP 52278, as well as the Ahuroa Gas Storage Facility. Contact Energy reported that it had reached the agreement to sell the asset in December 2017.  It was reported that the sale of the Gas Storage Facility was for NZD 200 million.  The deal was subject to relevant authority approvals, but was completed as planned, being expected to be finalized before end 2018.  It was reported that Contact Energy has retained the right to use the facility for future needs. The Ahuroa production permit contains the Ahuroa UGS field, which was discovered in 1987.  It is a gas and condensate producing field, that also has an underground gas storage element to its development, which commenced activity in 2011. PMP 52278, which covers an area of 11 sq km, was awarded on 16 December 2010.  It is scheduled to expire in December 2050.  GSNZ SPV1 Ltd now holds 100% interest and operatorship of the permit.

GSNZ SPV1 completed the acquisition of interest and operatorship of the Ahuroa asset (Ahuroa production permit, PMP 52278) from Contact Energy.

An auction was held 19 Sep '19 for the 114-sq km Selli block in the Terek-Caspian Basin, Dagestan, North Caucasus. Infiniti Neftegaz won the 25-year rights with a USD 20,000 offer (starting price USD 10,000). The block contains the depleted Selli oilfield + Ulluchayevskaya lead.

Infiniti Neftegaz won the Selli block in Dagestan Republic

Shijiutuo High, north of the Bozhong Depression, Bohai Gulf Basin, WD 20m, ops terminated 5 Dec ’17, results n/a. Targets Minghuazhen + Guantao fm’s, Bohai 7 JU.   

China (Bohai Gulf B.) Qinhuangdao 31-2 (Bo) 1 op. by CNOOC TJ (100.0%) in Bohai 06/17 block

On 17 January 2020, Gazprom Neft announced a new deal with Royal Dutch Shell plc in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Their joint venture Salym Petroleum Development (SPD) will acquire a 100% stake at newly created company Salymskiy-2 LLC from Gazprom Neft-Khantos. Prior to the deal, license KhMN02196NR shall be transferred from Gazprom Neft-Khantos, the current license operator, to Salymskiy-2. The Salymskiy-2 license covers 376 sq km in the Ural-Frolov Province and it is adjacent to the Salymskoye Zapadnoye, Vadelypskoye and Verkhnesalymskoye fields developed by SPD. Two wells have been drilled in the license. Also, the operator is in the process of interpretation of recently acquired 3D seismic data. SPD is equally owned by Gazprom Neft and Shell. It must be noted that Gazprom Neft invited Shell to join several projects in Russia. In Western Siberia, two companies may team for development of the Achimov reservoirs in the Yamburgskoye field where Gazprom Neft operates as a contractor for Gazprom. In the Okhotsk Sea (offshore Sakhalin), Shell is invited to explore and develop the Ayashskiy license including the recent Neptune and Triton oil discoveries.

Salym Petroleum, has agreed to buy a 100% stake in Salymskiy 2 (380km²) block from Gazprom Neft’s regional subsidiary, Gazprom Neft Khantos

Encouraged by the country's new hydrocarbons law, state Sonatrach and Chevron have reportedly signed an MoU to evaluate local E&P opportunities with a view to possible partnerships.

Algeria, not found

On 1 May 2019, domestic operator UNIGEO a.s. was granted the Janovice permit in eastern Czech Republic. The contract, granted until 31 December 2020 and licenced for oil and gas exploration, is solely operated by UNIGEO. The Janovice area is located in northern Moravia, about 20 km south of the city of Ostrava. The area is situated within the Carpathian Flysch Zone. It is believed, the company is seeking to explore for a satellite of the Janovice gas field. Background Information The Janowice area is known for gas production from the Karpatian-age clastic series. Although tectonics of the area is intrinsic, a total of ten wells - Janovice 1 to 10 - had been drilled by Geologicky Pruzkum Ostrava (GPO) near Janovice during the period the 1967-1990. Two of the wells encountered gas in the Miocene (Karpatian) series: Janovice 3 (1967) and Janovice 9 (1984). The former well tested 2 MMcf/d in the Karpatian strata, but the tests were interrupted due to technical problems. The latter well started testing the 886-920 m interval (Karpatian) but the formation was soon flooded so the results obtained were rather poor. As the gas-bearing horizon of the Janovice pool is approximately 4 m thick, some local sources indicate that it was questionable if the well was positive and the production was going to be commercial. In early 2000s, Australia-based Carpathian Resources Ltd farmed in into the Janowice area and intended to bring the field into production - information from 22 January 2004 stated that the Carpathian/UNIGEO group was granted a 4 sq km development contract covering the Janovice field. In 2004, sidetrack well Janovice 3a was drilled and, in late May 2004, after two weeks of production testing, development well Janovice 3a was suspended as a gas producer after testing gas in the Karpatian (Miocene) at rates of 1,519 Mcf/d. According to Carpathian the well encountered a 35 m-thick gas column (gross). On 9 November 2005 Carpathian announced that the unsuccessful well Janovice 11 was drilled to a final depth of 944.5 m, bottoming in the Paleozoic series, and was about to be abandoned. On 3 March 2006, Carpathian announced that following a second pressure test carried out in January 2006, the reserves of the Janovice field were upgraded from the initial 1.2-1.3 Bcf to 3.8 to 4.0 Bcf (80% recovery factor). In April 2006, Carpathian announced that following an upgrade of the reserves of the Janovice field, the partners we mulling a plan to develop the field to increase recovery - acquisition of a 3D seismic survey was planned. Janovice gas field (Janovice 3a well) delivered on average 14,000 cubic metres per day (approximately 0.50 million cubic feet) during 2009, but on 6 July 2009 Carpathian advised that the company was shifting its principal interest from exploration to investment and the Janovice project was suspended. With the acquisition of the new permit in 2019, UNIGEO is returning to the area after a period of hiatus.

domestic operator UNIGEO a.s. was granted the Janovice permit in eastern Czech Republic.

Pertamina Hulu Energi Siak (PHE Siak), operator of the Siak PSC located onshore in the Central Sumatra Basin, signed the Transfer Agreement and Management of 10% Participating Interest (PI) with PT Riau Petroleum, a company controlled by the regional government, on 7 August 2018. The signing ceremony was held at the Pauh Janggi Hall, located in the district of Pekanbaru, witnessed by the Governor of Riau and Head of SKK Migas of North Sumatra. The allocation of the 10% PI is in compliance with Ministerial Regulation No. 37/ 2016, aimed at providing direct benefits from oil and gas activity to the local administrations. PHE Siak will retain operatorship and 90% interest in the block. The company has been operating the block since May 2014, after the previous PSC with Chevron expired in November 2013. In November 2014, PHE commenced its cooperation with PT Riau Petroleum in the block. As of September 2015, the discussion to define the share composition between PHE and Riau Petroleum was ongoing. PHE is targeting to produce approximately 1,800 bo/d from the block in 2018. Production comes from the Lindai, Manggala South and Batang fields. The latest activity in the block is the drilling of exploration well Kumis 2, in March 2018. The well is intended to re-investigate shallow oil potential in the Kumis structure located within the southern portion of Siak PSC Area III. The first well drilled in the structure, Kumis 1 (Chevron, 1996), encountered oil shows. Background Information The 12,328 sq km C&T "A, B & C Blocks" COW was awarded to Caltex, a joint-venture of Chevron subsidiary California Asiatic Oil Co (or Calasiatic) and Texaco subsidiary Texaco Overseas Petroleum Co (or Topco), on 28 November 1963 and covered areas previously lightly explored by Stanvac and Caltex under earlier concessions. Caltex paid signature bonus of USD 5 million and committed to work programmes amounting to USD 14 million. On 28 March 1991, the COW was converted to PSC terms and re-named as Siak PSC under newly established subsidiaries Chevron Siak Inc and Texaco Siak Inc. Signature bonus paid was USD 5.2 million and the work commitment was USD 38 million for 10 years. In September 2010, Chevron submitted to regulator BPMIGAS a letter expressing its intent to pursue an extension. BPMIGAS said in mid-January 2011 that Chevron had until November 2011 to submit a formal proposal for the extension. According to the national upstream oil and gas regulator, the previous letter was not valid as it did not include specific plans about development plans and investment commitments for the block. The PSC with Chevron expired on 27 November 2013 and was not extended by the government, which opted to award the block to Pertamina for a new 20-year term.

Pertamina Hulu Energi Siak (PHE Siak), operator of the Siak PSC located onshore in the Central Sumatra Basin, signed the Transfer Agreement and Management of 10% Participating Interest (PI) with PT Riau Petroleum, a company controlled by the regional governmentLindai

Basin-centered gas accumulation play in block F18-C (deep), W. Thrace Basin / NW Turkey, TD 4,796m, 1,066m gross of Teslimkoy + Kesan fm’s interpreted as gas-bearing down to TD, 3 intvs stimulated between 4,640-4,765m, 1.6 MMcf/d, 1.3 MMcf/d + 1.3 MMcf/d dry gas resp. for 24 hrs, best rates so far in region. Release here. Valeura (op), partners Equinor + Pinnacle.

Devepinar-1 nfw Basin-centered gas accumulation play in block F18-C (deep), W. Thrace Basin / NW Turkey, TD 4,796m, 1,066m gross of Teslimkoy + Kesan fm’s interpreted as gas-bearing down to TD, 3 intvs stimulated between 4,640-4,765m, 1.6 MMcf/d, 1.3 MMcf/d + 1.3 MMcf/d dry gas resp. for 24 hrs, best rates so far in region. Release here. Valeura (op), partners Equinor + Pinnacle.

Bualuang field area in B08/38, location 5km N. of A & B platforms in WD ~60m, Gulf of Thailand, P&A oil shows at TD 2,328m on 21 Oct ’18, West Cressida JU. Target M. Miocene.

B08/38-11 (Ophir 100%) in the B08/38 concession, P&A with oil shows.

On 17 July 2020 the Western Australian State Government opened the 2020 Western Australian State Acreage Release (1 of 2020) offering four blocks, one each over the North Carnarvon and South Carnarvon basins, and two over Perth Basin. The total area on offer covers over 11,300 sq km both onshore and offshore. The round will close on 19 October 2020. Under the conditions set by the Western Australia Government, the applicants must submit a clear and specific work programme for the proposed acreage. This should include justification of expenditure for each element of the programme, and the identification of key risks and uncertainties, and how they will be addressed. Native Title agreements will also be necessary before the award of any permit can be made. Companies who are looking to apply for a block in the latest round, are to do so online via the PGR online submission portal. Applicants are required to register for the PGR online services at least one month prior to the closing date. Hand delivered or postal applications will not be accepted. Block Basin Area (sq km) Prospectivity L20-1 North Carnarvon 6,292 Conventional oil and gas L20-2 South Carnarvon 2,583 Conventional oil and gas/shale gas L20-3 Perth Basin 148 Conventional oil and gas L20-4 Perth Basin 2,289 Conventional oil and gas Source: IHS Markit     © 2020 IHS Markit

(North Carnarvon, South Carnarvon & Perth b.) The Western Australian State Government opened the 2020 Western Australian State Acreage Release (1 of 2020). The release (made up of four blocks) will close on 19 October 2020. The total area on offer covers over 11,300 sq km both onshore and offshore. Blocks on offer are: L20-1 North Carnarvon 6,292 sq km Conventional oil and gas

Europa Oil and Gas plc is offering interested parties to farm-in to Licence Option (LO) 16/20. Europa has identified 3 Tcf undiscovered GIIP on LO 16/20 in the Triassic and Jurrasic gas hydrocarbon play. In February 2019, Europa announced an updated gross mean un-risked prospective resource estimate of 1.5 Tcf for the Inishkea prospect with a 33% chance of success. Furthermore, subject to meeting commercial and regulatory criteria, Europa have a site survey planned for summer 2019 for an exploration well (18/20-H) to be drilled on the Inishkea prospect in 2020. The company is currently progressing farm-in negotiations with a major oil and gas company for licences LO 16/20, FEL 1/17 and FEL 3/13.    The current inventory includes the Inishkea prospect (1,528 Bcf), Inishkea NW prospect (1,094 Bcf), Inishkea W prospect (212 Bcf), Bofin lead (69 Bcf), Corrib North discovery (40 Bcf) and Corrib NW prospect (26 Bcf). The inventory has been mapped by Europa on legacy 3D seismic data originally acquired in 2002. Europa completed the process of merging and PSDM reprocessing existing 3D seismic. The additional clarity should enable some of the prospects to be upgraded to a drillable status during H1 2019. The targeted Triassic gas play comprises of Triassic Sherwood sandstone reservoirs, Carboniferous source rocks, Triassic Mercia mudstone seal and structural traps. The play is well understood and proven to work both technically and commercially by the Corrib gas field. Europa believe the play risk is lower than in other Atlantic Ireland basins where play risk remains to be conclusively proven by a commercially successful exploration discovery. Europa has interpreted the Inishkea prospect complex to have been less deeply buried than the Corrib field and therefore recovery factors should be at least as good as Corrib. The water depths are relatively shallow (400 - 600 m) and do not require harsh environment sixth generation drillships, reducing drill costs. Europa conducted a drill cost estimate for a well on the Inishkea prospect and a dry hole cost including mobilisation and demobilisation of USD $28 million using a prevailing rig rate of USD 120,000 per day. Gas infrastructure is already present nearby at Corrib therefore a fast track path to commercialisation is potentially available, subject to negotiation and cooperation with the current infrastructure owners. Interest in LO 16/20 is held solely by Europa Oil & Gas (Inishkea) Ltd. For further information please contact: Murray Johnson Email: [email protected]

Europa Oil and Gas plc is offering interested parties to farm-in to Licence Option (LO) 16/20. Europa has identified 3 Tcf undiscovered GIIP on LO 16/20 in the Triassic and Jurrasic gas hydrocarbon play.

South Sumatra Block PSC in S. Sumatra, TMD 1,478m (Basement), currently testing, Dreco 750 rig.  Targets possibly Batu Raja carbs, fractured Basement and/or Talang Akar.

Nowera-1 South Sumatra Block PSC in S. Sumatra, TMD 1,478m (Basement), currently testing, Dreco 750 rig. Targets possibly Batu Raja carbs, fractured Basement and/or Talang Akar.

OGDC has assigned a 25% stake to PPL in the Khuzdar North 2866-3 EL, 2,452 sq km in Balochistan, retro-effective 1 Jan '16. Partnership now OGDC (op), PPL + GHPL.

OGDC has assigned a 25% stake to PPL in the Khuzdar North 2866-3 EL (2452km²).

Eni (as the Operator of the Block), BP and Total (as Contractor members) have successfully tested the well drilled on the prospect called Bashrush, in the North El Hammad concession, in the conventional Egyptian waters of the Nile Delta. The well has been opened to test potentiality of production, and it delivered up to 32 MMscfd of gas. The test rate was limited by surface testing facilities. The well deliverability in production configuration is estimated at up to 100 MMscf of gas and 800 barrels of condensate per day. Eni, together with its partners BP and Total and in coordination with Egyptian Natural Gas Holding Company, will continue screening the development options of Bashrush, with the aim of fast tracking production through synergies with the area's existing infrastructures. In the North El Hammad concession, which is in participation with the Egyptian Natural Gas Holding Company (EGAS), Eni through its affiliate IEOC holds 37.5% interest and the role of Operator, BP holds the 37.5%, and Total holds the 25% of the contractor share. Eni has been present in Egypt since 1954, where it operates through IEOC Production. The current equity production of IEOC is above 300,000 boepd. Original article link Source: Eni

Egypt (Nile Delta B.)? op. by ENI SPA (75%), BP (25%), EGPC (0%) in Nile Delta (Dev) contract

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

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

Lion Energy announced on 12 December 2018 a conditional sale and purchase agreement for the acquisition of the 16.5% stake owned by Gulf Petroleum Investment Company (GPI) in the Seram (Non-Bula) PSC, located in onshore/offshore Seram island. Upon completion, Lion will have increased its participating stake in the block from 2.5% to 19%, via wholly-owned subsidiary Seram Energy Pte Ltd. The total purchase price is USD 44 million, subdivided into USD 32 million upfront payment and contingent payments of USD 7.2 million (within four months from Plan of Development approval for the Lofin gas discovery) and USD 4.8 million (within four months from first commercial gas production). Lion is in discussions to secure funding towards the upfront payment prior to obtaining shareholders’ approval. Completion of the deal is likewise subject to other conditions to be met by 11 December 2019, including customary approvals from Indonesian regulator and PSC partners, as well as Lion providing a corporate guarantee for the contingent payments. Upon completion, the effective date of the transaction will be 1 November 2018. The proposed transaction will strengthen Lion’s position in the area, as the company was also awarded 100% interest in the East Seram exploration block in May 2018, following Indonesia’s Conventional Oil and Gas Bidding First Round 2018. The other partners in the Seram (Non-Bula) PSC are CITIC (41%, operator), PT Petro Indo Mandiri (30%) and PT GHJ (10%). The PSC is due to expire on 31 October 2019, however on 31 May 2018 the partners signed a new gross split contract to continue operations in the block for a new 20-year term. Signature bonus for the new contract was USD 1 million. The operator has committed to invest approximately USD 49 million for the first five years of the new contract. The Lofin discovery is estimated to contain 2 Tcfg in place within Manusela carbonates. The 20-year contract extension is expected to allow for full development of the discovery. Additionally, the block is producing oil from the Oseil and satellite fields, with a rate of approximately 2,000 b/d as of mid-2018. Background Information Seram (Non-Bula) PSC History Located onshore on the Seram island, the Seram PSC was awarded to Gulf and Western Indonesia Inc (G&W) on 1 November 1969 in order to re-habilitate the Bula oil field which had been damaged during World War II. After drilling nine unsuccessful shallow exploration wells and carrying out re-habilitation work and limited development drilling on the Bula field, G&W assigned the PSC to Associated Australian Oilfields NL (AAR) in 1972. AAR shot seismic but did not drill and CSR acquired AAR in 1978. CSR drilled seven exploration wells and undertook development work at Bula. A Kufpec-led group farmed-in for exploration rights in 1985 but the Bula field, covered by an area of 35 sq km to a sub-sea level of 600m, was excluded from the deal. Kufpec concentrated on the deeper potential of the PSC. On 11 July 2006, CITIC announced that it had entered in a USD 97.4 million sales purchase agreement to acquire a 51% operating stake in the Seram PSC Extension from operator Kufpec. In February 2018, CITIC agreed to sell a 10% participating interest to PT GHJ, an independent local company. Later, in Q2 2018, Kufpec divested its interest in the block to another local company, PT Petro Mandiri. Lofin gas discovery CITIC suspended Lofin 1 ST1 wildcat as a gas with oil/condensate discovery in mid-December 2012. The well encountered more than 160 m of hydrocarbon column in the Jurassic carbonates of the Manusela Formation. The well flowed at a final rate of 15.7 MMcf/d with 171 bbl/d cumulative oil/condensate (36.1° API). Lofin 1 was spudded on 17 January 2012. Appraisal well Lofin 2 was spudded on 31 October 2014. The well had initial PTD of 5,425 mMD/5,321 mSSTVD, targeting the Manusela Formation. The well was drilled to a final TD of 5,861 mMD (5,686 mSSTVD). In an attempt to collect good reservoir data, a seven days multi-rate test using different choke sizes was conducted by the operator. The test recorded 17.8 MMcf/d of gas with 2,634 b/d of water and completion fluid and 54 b/d of 34.4º API condensate/oil with a flowing wellhead pressure of 2,250 psi over 96 hours flow period on 52/64” choke. A 12 hours flow period on 16/64” choke was also conducted which has recorded 4.95 MMcf/d of gas with 12 b/d of condensate with 280 b/d of water with wellhead pressure of 5000 psi. Lofin 2 intersected a total gas column of up to 1,300 m.

Indonesia, Seram (Non-Bula) PSC Extension