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Coro's 15% farmin to the 911-sq km Duyung PSC, W. Natuna Sea, agreed upon early 2019 is still pending final govt approval. Coro and seller West Natuna Exploration (Conrad + Empyrean) have agreed to extend the deadline 6 months to Jun '20.

Coro's 15% farmin to the 911-sq km Duyung PSC, W. Natuna Sea, agreed upon early 2019 is still pending final govt approval. Coro and seller West Natuna Exploration (Conrad + Empyrean) have agreed to extend the deadline 6 months to Jun '20.

Vintage has reached an agreement with Firetail Energy Services for the latter to acquire a 10% stake in EP 126,  6,740 sq km mostly onshore in the Bonaparte Basin. The deal is in exchange for Firetail to provide AUD 850,000 of services towards the testing of Cullen-1 nfw (Beach, 2014, TD 3,325m, gas shows). Vintage retains 90%.

Firetail Energy Services acquired a 10% interest in EP 126 from Vintage (->90%).

The Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) has issued a Call for Bids for Exploration Licences in the Eastern Newfoundland Region. Call for Bids NL20-CFB01 (Exploration Licences, Eastern Newfoundland Region) consists of 17 parcels and a total of 4,170,509 hectares. Interested parties will have until 12:00 p.m. NST on November 4, 2020 to submit sealed bids for the parcels offered in this Call for Bids. Notification of any changes to the Call for Bids will be posted on the C-NLOPB’s website. The sole criterion for selecting a winning bid will be the total amount of money the bidder commits to spend on exploration of the parcel during Period I (the first period of a nine-year licence). The minimum bid for the parcels offered is $10,000,000 in work commitments. Planning, monitoring and assessment of offshore petroleum activities will ensure they occur in an environmentally responsible way. Required regional and/or site-specific mitigation measures will be undertaken before any petroleum-related operations can begin within a licence area, as conditions of C-NLOPB approvals and authorizations. The timing, spatial extent, and nature of proposed oil and gas activities, in addition to mitigations already prescribed by legislation or regulation, will determine the level of restriction or mitigation that may be required. A Regional Assessment of Offshore Oil and Gas Exploratory Drilling East of Newfoundland and Labrador was recently completed, which included extensive stakeholder engagements. Pursuant to the Regional Assessment, on June 4, 2020 the Government of Canada announced the coming into force of a Ministerial Regulation that improves the efficiency of the assessment process for oil and gas exploration drilling projects in the relevant part of the Canada-Newfoundland and Labrador Offshore Area, while at the same time protecting the environment. Seismic programs to be undertaken on these parcels will also be subject to rigorous, science-based Accord Act Environmental Assessments undertaken in close consultation with government subject matter experts and others. A number of the parcels in this 2020 Call for Bids overlap in part with areas of fish harvesting activity. The C-NLOPB fully appreciates the importance of both the fisheries and petroleum sectors and will continue to engage with fisheries stakeholders and Fisheries and Oceans Canada (DFO) throughout the land tenure process. Any companies acquiring Exploration Licences pursuant to this Call for Bids will be required to engage with fishing interests before any oil and gas activities are authorized. Some of the parcels in this 2020 Call for Bids also overlap the Northeast Newfoundland Slope Marine Refuge. The C-NLOPB is focused on the protection of environmentally significant and sensitive areas and will also continue to work closely with DFO and others in this regard. For any lands entirely or partially beyond Canada’s 200 nautical mile zone, additional terms and conditions may be applied (e.g. through legislation, regulations, amendments to licences or otherwise) to any resulting licence from a Call for Bids in order to meet obligations arising pursuant to article 82 of the United Nations Convention on the Law of the Sea. Based on an assessment of nominations and land tenure considerations, the C-NLOPB has decided not to proceed with a Call for Bids in the Jeanne d’Arc Region in 2020. This is the only land tenure region designated as Mature and has had an annual Call for Bids since the C-NLOPB Land Tenure System was introduced in 2013. Decisions about future Call for Bids in the Jeanne d’Arc Region will be made on an annual basis, per the C-NLOPB’s Scheduled Land Tenure System. The issuance of this Call for Bids has received C-NLOPB Board approval, along with ratification by the federal and Newfoundland and Labrador governments. Those steps will also be required in the awarding of any Exploration Licences. Further detailed information about these Calls for Bids is available here. Any parties interested in receiving email notifications on Scheduled Land Tenure related announcements can contact Shannon Bulger at [email protected]. Original article link Source: C-NLOPB

C-NLOPB has issued a Call for Bids for Exploration Licences in the Eastern Newfoundland Region. Call for Bids NL20-CFB01 (Exploration Licences, Eastern Newfoundland Region) consists of 17 parcels and a total of 4,170,509 hectares.

PetroChina – Xinjiang made an important breakthrough in the Junggar Basin. Chetan 1, a NFW, tested commercial oil flow in the Carboniferous Tailegula Formation on 22 October 2019. The well was drilled in the Chepaizi High in the west margin of the basin. There are several oil fields found in this area, such as Chepaizi, Chunguang and Chunfeng fields, which has main reservoir in the Tertiary, Jurassic and Permian. A few wells penetrated Carboniferous reservoir, but no commercial oil has been achieved. Chetan 1 is the first well which makes a breakthrough in the Carboniferous and it indicates a significant potential prospective for carboniferous play in this area. The Junggar Basin is one of the key exploration and production base for PetroChina. The company has approved more than 25 oil and gas fields by 2018 with total of 22 bn bbls of oil and 6 Tcf of gas in place reserves. In 2018 PetroChina produced 11.47 million tons of oil (229,000 b/d) and 2.9 Bcm of gas (290 MMcf/d). The company plans to increase oil production to 248,000 b/d in 2019 and 260,000 b/d by 2020. Background Information Several exploration successes have been achieved recently in the Junggar Basin. In June 2019, PetroChina made an important breakthrough at Qianshao 2, which tested 7.18 MMcf/d of gas plus 280 b/d of condensate from the Jurassic Sangonghe Formation. The well was drilled in the northeast slope of the Shawan Sag. There are several small-medium size oil and gas fields found on local structure highs in this area, such as Mosuowan gas field, Mobei and Shixi oil and gas fields, which has main reservoir in the Sangonghe Formation. Qianshao 2 is the first well which makes a breakthrough down to slope area and it indicates a significant potential prospective for gas exploration. In January 2019, PetroChina has made a significant discovery at Gaotan 1 in the south margin of the basin, and the well tested 7,630 b/d of oil and 11 MMcf/d of gas in the Cretaceous Qingshuihe Formation. The south margin of the Junggar Basin, geologically, has developed a 400 km long thrusting structure belt. Several wells have been drilled in this area with oil tested from the Cretaceous and Tertiary clastic rock, such as Xihu 1, Dushan 1 and Dafeng 1, but without commercial value. Gaotan 1 is believed to achieved commercial oil and gas flow from the deeper formations. In December 2018, PetroChina made an oil discovery in Shatan 1. The well tested 190 b/d of oil from 5,344 to 5,375 m in the Permian Wuerhe Formation. Shatan 1 is drilled in the northwest Shawan Sag. The well also encountered good oil shows in other formations during drilling, such as Triassic Baikouquan and Karamay formations. The success of the well indicated a new exploration potential prospective area for the Wuerhe play fairway.

PetroChina – Xinjiang made an important breakthrough in the Junggar Basin. Chetan 1, a NFW, tested commercial oil flow in the Carboniferous Tailegula Formation

GAZKOP has been issued two new Coal Bed Methane (CBM) permits in Katowice County, within the Upper Silesian Coal Basin (UCSB). 1/2020 Mszana (16 sq km) is effective from 21 January 2020 until 10 February 2037, whilst 2/2020 Wilchwy (18 sq km) is valid from 22 January 2020 to 10 February 2036. The blocks overlap the Marcel coal deposit, which forms part of PGG's ROW (Rybnicki Okreg Weglowy) coal mine. At least 31 wells have been drilled on the acreage, mainly in the 1950s and 1960s related to coal exploration or stratigraphic tests. Wilchwy was previously licensed for CBM exploration under 63/2009/p concession, which was surrendered in October 2017. The licences are located proximate to a number of existing CBM permits, notably 4/2016/p Anna (licensed to Termospec), 3/2016 Jankowice-Wsonod (CETUS), 12/2011 Zory (GAZKOP), 10/2015/p Zory M (PWiK Zory M), and 2/2019/p Ruptawa (JSW). The blocks lie 40km W of the 0.9 MW Tauron Dystrybucja power plant at Gilowice, which commenced generation in April 2019. The facility is powered by CBM extracted from PGNiG's 2/2017/L Miedzyrzecze, under the Geo-Metan project with coal miner PGG, and the Polish Geological Institute (PGI). This is part of PGNiG's greater plan to utilise an estimated 6 Tcfg recoverable CBM in the USCB which extends to further co-operation with two more coal miners, JSW and Tauron. GAZKOP operates both licences with 100% interest held via two subsidiaries - Gazkop-1 Sp in 1/2020 Mszana, and Gazkop-Wilchwy Sp zoo in 2/2020 Wilchwy.

GAZKOP has been issued two new Coal Bed Methane GAZKOP has been issued 2 new CBM permits in Katowice County, within the Upper Silesian Coal Basin. 1/2020 Mszana (16 sq km) and 2/2020 Wilchwy (18 sq km).

BT-PN-001 contract, PN-T-102 block P&A assumed dry early Nov ‘18. PTD was 1,622m, targets Cabeças + Poti fm’s.

3-PGN-ARAGUAINAD-MA (3-PGN-029-MA) (Parnaiba Gas Natural 100%) in PN-T-102 block P&A assumed dry.

Wintershall Dea has been unsuccessful with its appraisal of the 2018 Balderbra gas discovery in PL 894. 6604/5-2 S was spudded on 22 January 2020 using the “Scarabeo 8” S/S. It targeted three Upper Cretaceous Springar Formation sandstones, with the first mapped at 3,633 m (3,389 m TVD), and was also designed to locate the GWC. However, although a total of 210 m of Springar Formation was present in the well (with 140 m of this being poor quality sandstone) there were only traces of gas and the well is classed as a dry hole. Pressure communication with the discovery was also not established. Recoverable reserves for Balderbra have been reduced from 247-671 Bcfg plus 6-19 MMbc (at discovery) to 106-283 Bcfg plus 1-6 MMbc. On 26 February 2020 the well was abandoned, with TD at 4,155 m (3,816 m TVDSS) in the Springar Formation. Two sidetracks had been planned for 6604/5-2 S – one to the southwest (TD 4,120 m, 3,808 m TVD) and the other to the east (TD 4,258 m, 3,878 m TVD) – and Wintershall Dea had also intended to carry out two DSTs. Balderbra discovery well 6604/5-1 targeted a robust structural closure (Maastrichtian sand drape over older tilted fault blocks) with an amplitude anomaly between the Gullris (6604/2-1) and Gro (6603/12-1) wells. A gross gas column of 190 m across three separate sandstones totalling 90 m was encountered in the Springar Formation. The upper sandstone unit is thin with variable permeability, the middle sand is thicker (56 m gross) and laminated with 21% porosity, and the lower sand has a gross thickness of 129 m and 15% porosity. The three units are not in pressure communication and no GWC was encountered. The find could be developed as a tie-back to Aasta Hansteen. Interest in PL 894 is held by Wintershall Dea Norge AS (40% + operator), Equinor Energy AS (40%) and Petoro AS (20%).

6604/05-02 S (Balderbrå) appr. (Wintershall Dea 40% op, Equinor 40%, Petoro 20%) in PL 894, 15km E. of discovery, P&A dry, encountered only traces of gas across 3 intervals spanning 210m in the U. Cretaceous Springar Fm, of which 140m of sst was of poor reservoir quality and has significantly downgraded the resource estimate for Balderbra g&c disc.The GWC was not found.

German Genexco GmbH is to take over operatorship of the Reudnitz, Reudnitz Nordost + Reudnitz Südost contracts from Bayerngas. Official clearance is due shortly. The contiguous blocks lie over 555 sq km SE of Berlin in Brandenburg, close to the Polish border. Genexco intends to offer equity in the acreage:

Germany (NE Brandenburg Sub-basin (NE German-Polish B.)) (It's a petroleum rights. Please summarize by yourself). In IHS database: Reudnitz Nordost op. by BAYERNGAS (100.0%) to be check.Reudnitz op. by BAYERNGAS (100.0%) to be check.

In October 2017, Surgutneftegaz completed testing of a new exploratory well in the Tundrinskoye license in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Verkhnesolkinskaya 50, spudded in August 2017, reached 2,980 m in September. Oil flows were tested from the Sortym (Neocomian) and Tyumen Formations. Reservoir BS10 perforated at 2,436-2,443 m flowed with oil at a rate of 28 b/d. The interval 2,865-2,892 m (Yu2-3) tested oil at a rate of 16 b/d. Based on primary data, 2P reserves of the discovery were estimated by IHS Markit at 3 MMbbl. Tundrinskoye license (KhMN00422NE) covers 973 sq km in the southwestern part of the Middle Ob Province and encompasses the Tundrinskoye field and the Malo-Komaryinskaya prospect.  

Verkhnesolkinskaya 50,Surgutneftegaz completed testing of a new exploratory well in the Tundrinskoye license Oil flows were tested from the Sortym (Neocomian) and Tyumen Formations. Reservoir BS10 perforated at 2,436-2,443 m flowed with oil at a rate of 28 b/d. The interval 2,865-2,892 m (Yu2-3) tested oil at a rate of 16 b/d.

P1918 / block 98/11a off the Dorset coast, sidetrack north completed at TMD 1,910m and demonstrates that the majority of the potential resource lies within the Colter South section of the play. Results will be used to determine the forward plan to maximise the potential value associated with the Colter South prospect. The 98/11a-6 (Colter) appr TD’d at 1,870m (Sherwood sst), o&g shows over a 9.4m intv, 3m net pay, Ensco 72 JU. Well to P&A and rig released. Corallian (op), partners Baron Oil, Corfe Egy, Resolute O&G + United O&G.

098/11a-06 Z (Colter ST) (Coralian op. 49%, Corfe Egy. 25%, UOG 10%, Resolute O&G 8%, Baron Oil 8%) in P1918 / block 98/11a off the Dorset coast, intersected the target Sherwood sst. fm below the oil-water contact. In addition, the side-track encountered oil and gas shows in the Jurassic Cornbrash-Lower Oxfordian interval, the producing reservoirs in the Kimmeridge oilfield, and this provides an interesting potential target on trend to the west within the onshore licences

On 18 May 2020, French Major TOTAL SA entered a farm-out agreement with Qatar Petroleum in which the latter will acquire 45% participating interest in coastal to deepwater blocks CI-705 and CI-706, within the Cote d’Ivoire Basin. The blocks were awarded to TOTAL in May 2019. Upon governmental approval, the ownership will be shared between TOTAL (operator with 45%), Qatar Petroleum (45%) and PETROCI holding the remaining 10% interest. CI-705 covers some 1,160 sq km in water ranging in depths between 0 and 700 m. To date, two exploratory wells have been drilled within the area, both in 1984 within the shelf portion of the block by Tenneco Oil Co (K1 1 and K1 2), and both were plugged and abandoned as dry. CI-706 covers some 753 sq km in water ranging in depths between 1,000 and 2,500 m. To date, three exploratory wells have been drilled within the area. Ocean Energy Cote d'Ivoire Corp drilled Grand Lahou East 1 in 1999 (P&A dry), Anadarko drilled South Grand Lahou 1 in 2009 (P&A dry) and Kosrou 1 in 2009 (P&A with oil shows).

Qatar Petroleum to acquire 45% equity from Total in CI-705 and CI-706 blocks who will be held by Total (45% + Operator), Qatar Petroleum (45%) and Petroci (10%).

Add. DEA 20 Jan '20: Palermo Aike block, Magallanes Basin in Santa Cruz, TMD 2,247m, top Springhill ab. 28m above pre-drill prognosis + 58m above interpreted regional water contact, suggesting larger volumes across the Campo Limite area. Testing to start 2H Fb '20. Roch (op), partner Echo Egy (carried by Petrolera El Trebol thru this well).

Campo Limite X-1001 (CLix) nfw Palermo Aike block, Magallanes Basin in Santa Cruz, TMD 2,247m, top Springhill ab. 28m above pre-drill prognosis + 58m above interpreted regional water contact, suggesting larger volumes across the Campo Limite area. Testing to start 2H Fb '20. Roch (op), partner Echo Egy (carried by Petrolera El Trebol thru this well).

Aker BP has taken a 23.835% interest in PL 159 D from operator Equinor. The deal was reported by the NPD on 5 June 2018 and it is effective from 31 May 2018. PL 159 D covers a 7 sq km area over part of block 6507/3 to the east of Aerfugl. It contains the 2009 Idun North gas discovery. Aker BP operates the neighbouring licences (PL 212, PL 212 B and PL 262) which contain the Aerfugl and Skarv fields and it is assumed that the company is interested in developing Idun North along with Aerfugl. Idun North discovery well 6507/3-7 proved gas in the Middle Jurassic Fangst Group with estimated recoverable reserves given at the time of 20-105 Bcfg. The Aerfugl field is in development, with the PDO being approved in April 2018. Aerfugl will be a phased development using a total of six subsea wells tied-back to the Skarv FPSO. Phase I (three producers in the southern part of the field) passed concept selection in March 2017. The development will utilise electrically heated flowlines, chemical pumps and scale inhibitor packages for flow assurance and first gas is due in October 2020. Test production from the field was carried out in advance of the PDO submission in order to provide in depth knowledge of the reservoir. The plan for Phase II is yet to be finalised but is likely to consist of two wells in the northern part of the field together with a well on Snadd Outer (PL 212 E) and is tentatively due onstream in Q3 2023. Following completion of the deal, interest in PL 159 D is divided between Equinor Energy AS (36.165% + operator), DEA Norge AS (40%) and Aker BP ASA (23.835%).

Aker BP acquired 23,835% interest in the licences PL 159 D from Equinor (->36,165% + Op, DEA 40%)

As of 5 July 2020, Equinor Canada has completed drilling in the sidetrack and moved the rig off location of new-field wildcat Cappahayden K-67Z located in EL 1156 offshore in the deepwater area of the Flemish Pass Basin. The company has not yet released an update on the final outcome of the well. The company reported in the press that hydrocarbons were encountered in the original hole in what is believed to be the same formation as the Bay du Nord discovery located 16 km to the east. Equinor Canada sidetracked out of the Cappahayden K-67 original hole on 21 June 2020. It is believed the pay was discovered at a depth around 4,000 m. The rig has been moved to the Cambriol G-92 new-field wildcat prospect located 42 km west of the Bay du Nord Field in 612 m of waters on EL 1156. The Cambriol G-92 is the third and final well under the current rig contract with Equinor. If successful the well will increase the probability of a future development and extend the play to the west which has resulted in multiple oil discoveries in the Flemish Pass Basin which include the Mizzen, Bay du Nord, Bay de Verde, Baccalieu and Harpoon oil discoveries. The Cappahayden K-67 was spud using the Transocean Barents Rig on 24 April 2020. The proposed total depth of the well is probably between 3,500 m to 4,000 m. The well was sidetracked on 21 June 2020 for the Cappahayden K-67Z. The wells main objective being targeted is likely an Upper Jurassic age Tithonian sandstone within a faulted horst block. The fault block is part of a complexly faulted structure that stretches the border area between the Flemish Pass and Orphan basins. In January 2019, Equinor Canada and partner BP Canada were awarded an exploration license called EL 1156 resulting from the consolidation of two former licenses which included EL 1125 and EL 1126. As a result of the consolidation both EL 1125 and 1126 have been cancelled. As part of the consolidation a reduction of area from the total between the two former blocks was made making the size of EL 1156 1,903.33 sq km. Most of the surrendered area in the former license EL 1125 which was located west of the Mizzen discovery in SDL 1048. Equinor Canada will hold a 60% working interest in the new block with BP Canada holding the remaining 40%. Approximately 60% of the block falls in the Flemish Pass Basin with the remainder located in the Central Ridge and Orphan basins. Background Information 15 January 2012 - EL 1125 (2,470.16 sq km) awarded to Statoil (now Equinor Canada) and partners for a work commitment bid of CAD 202,171,394 from the Call for Bids NL11-02. Statoil as operator for the partnership has a 50% working interest, Chevron held a 40% working interest and Repsol held the remaining 10% 15 January 2012 - EL 1126 (1,867.80 sq km) awarded to the same Statoil (now Equinor Canada) group for a work commitment bid of CAD 145,603,270 also from the Call for Bids NL11-02. In September 2015 - Repsol transferred its working interest in both blocks to BG International who transferred the interest to Anadarko Canada in November 2016 who subsequently transferred the interest to BP Canada in in January 2018. In December 2018 Chevron Canada transferred its interest in the blocks to Equinor Canada and BP Canada leaving the current partnership of Equinor Canada 60% and BP Canada 40%. 14 January 2019 - Equinor Canada and partner BP Canada awarded an exploration license called EL 1156 resulting from the consolidation of two former licenses which included EL 1125 and EL 1126. The term of the new license is from the award date of 14 January 2019 through 15 January 2021 and consist of a Period I which will last 364 days and a Period II will contain the remainder of the time left. Fitzroya A12 (3,190 m (10,466 ft) and A12Z (3,860 m (12,664 ft) both wells were plugged and abandoned in 2016 and located some 15 km to the northwest from the Cappahayden K-67.

Canada (Flemish Pass B.), Cappahayden K-67Z, operated by Equinor (60%), BP (40%), EL 1156, WD 972m, TD ca. 4,000m, reportedly potential commercial oil find (34 API), sidetrack concluded 5 Jul '20, w.o. results. Target assumed Tithonian as in BdN (43 API oil).

In late March 2018, Repsol was reported to have intersected a 78 m gross column of oil in the Ivela 1 wildcat, Luna Muetse permit (Block E13). Though the reservoir has very good proprieties, the discovery is non-commercial. The well was spudded on 27 January 2018 with the Seadrill’s “West Capella” Ultra-deepwater drillship in 2,662 m of water. The well has a planned TD of 6,200 m and targets in the early Cretaceous Gamba-Dentale pre-salt formations. Repsol operates the block with a 60% interest and partner Woodside holds the remaining 40% interests. Background information In mid-2015, CGG completed a 35,000 sq km 3D and 9,900 km 2D seismic multiclients surveys offshore south of Gabon. The survey covers F12, E12, F13, E13, D13, G13, D14, G14, F14 and F15 blocks. The data acquisition started in late September 2014 using the “Oceanic Endeavour”, the “Oceanic Endeavour”, “Geowave Voyager” and “Geo Caribbean” vessels. Repsol was among the seven companies selected on 21 July 2014 by Gabonese Government as the winners of its offshore licensing round and on 8 August 2014, Repsol was awarded the Block E13 (Luna Muetse).

Ivela 1 (Repsol 60% op, Woodside 40%) in Luna Muetse (E13) block, P&A, dry well, ca 8m net over 78 gross column, defined from gas shows and pressure gradient. Gamba and Dentale sst have been found of good quality but water-bearing, with some oil shows (fluorescence).

Add. DEA 18 Dec ’18 : AE-0028-2M-Cotaxtla-01 block, SE of Ixachi find in onshore Veracruz Basin, confirmed P&A dry, but on 2 Feb ’19 at TD 7,868m. Target M. Cret. Orizaba carbs.

Cruver 1EXP (Pemex 100%) in the AE-0028-2M-Cotaxtla-01 entitlement onshore block, P&A dry. PTD of the well was 7,722 m and the fractured Middle and Lower Cretaceous Orizaba Fm was the main objective.

In Q3 2017, Agiba Petroleum completed for production the Meleiha Deep South West 1X ST 2 appraisal/development well. It was drilled on the Meleiha Deep licence, located in the Shushan Basin. The well was spudded on 22 May 2017 and drilled to a TD of ~3,480m (TVD ~3,220m) in the Jurassic. Operations were carried out using the SinoTharwa Drilling #8 rig. The well was drilled as a sidetrack to the Meleiha Deep South West 1X discovery, which encountered oil in the Jurassic Masajid limestones, below the main Cretaceous reservoir of the Meleiha Field. The Agiba consortium operates the PSC, with equity split between Eni (38%), Lukoil (12%) and EGPC (50%, carried).

Egypt, Meleiha (Dev)

Armstrong Oil & Gas announced in late February 2020 that it had acquired a 72% interest in Borealis Alaska's Castle West prospect in the National Petroleum Reserve – Alaska (NPR-A), through its subsidiary North Slope Energy. Borealis owns 18 leases covering 205,966 ac (834 sq km) in the Nanushuk play fairway. Armstrong farmed into eight of those leases covering 91,521 ac (370 sq km) along the far western edge of Borealis' acreage: leases AA093758 – AA093765. The Castle West acreage is directly east of the eastern edge of the 85 leases Armstrong picked up in the recent NPR-A sale held by the Bureau of Land Management (BLM) in December 2019. It is also directly southwest of the Willow oil discovery operated by ConocoPhillips.

Armstrong O&G announced that it had acquired a 72% interest in Borealis Alaskas Castle West prospect in the National Petroleum Reserve (AA093758 – AA093765).

Pursuant to the opening of the round process for the Erawan field in G1/61 and Bongkot field in G2/61 (DEA 25 Apr ’18), qualified bidders now include: G1/61 area (Erawan field): Chevron, PTTEP, Mubadala, Total, OMV. G2/61 area (Bongkot field): Chevron, PTTEP (no longer teamed with Total), Mubadala, OMV.

Pursuant to the opening of the round process for the Erawan field in G1/61 and Bongkot field in G2/61 (DEA 25 Apr ’18), qualified bidders now include: G1/61 area (Erawan field): Chevron, PTTEP, Mubadala, Total, OMV. G2/61 area (Bongkot field): Chevron, PTTEP (no longer teamed with Total), Mubadala, OMV.

On 21 January 2020, the ANP granted operator Petroil to farm-out 40% working interest to Oil Group and 20% working interest to Teknobras in the REC-T-109, REC-T-119, and REC-T-120 blocks it acquired in the ANP Round 14. The new working interest breakdown for the three contracts is Petroil operator with 40% working interest, Oil Group Exploracao e Producao SA 40%, and Teknobras Empreendimentos e Participacoes Ltda with 20% working interest. On 29 January 2018, Petroil with 100% working interest was granted official awards by the ANP for the REC-T-109, REC-T-119, and REC-T-120 blocks in the onshore Reconcavo Basin from the ANP Round 14. The company paid a total signature bonus of USD 81,025.24 for the three blocks and has work commitments of USD 829,337.54. The blocks cover a total area of 71.87 sq km. The contracts have one five-year exploration period and 7.5% royalties. The rentals for the blocks are USD 14.15/sq km/year. The local content is stipulated as 50% in the five-year exploration phase and 50% in the development production phase.

Oil Group Exploracao e Producao and Teknobras Empreendimentos e Participacoes will each have 20% in REC-T-109, REC-T-119 and REC-T-120 blocks, after Petroil Oil e Gas 40% (->60%) farm-out.

SK-318 off Central Luconia Sarawak, P&A gas around 10 Apr ‘18, TD 7,575m, Deepwater Nautilus SS. Gas was tested in the Middle Miocene Cycle IV carbs. Shell (op), partners Petronas + PetroBrunei.

Timi 1 op. by Shell (75%, Petronas 15%, PetroBrunei 10%) in SK-318 block, gas disc. Unofficial reports indicated that the well had intersected a gross gas column of more than 800m. Target assumed Middle Miocene Cycle IV/V carbs.

Abu Dhabi National Oil Company (ADNOC) approved the transfer of a 4% interest in the Lower Zakum field and Central Offshore Concession ( Umm Shaif and Nasr fields) from China National Petroleum Corporation’s (CNPC) publicly listed subsidiary PetroChina Company Limited (PetroChina) to China National Offshore Oil Corporation (CNOOC) on 27 July 2020. ADNOC Offshore issued tender documents during 2Q 2020 for the main Long-Term Development Plan (LTDP-1) EPC contract which is intended to sustain oil production capacity at 275,000 barrels a day (b/d) from the Umm Shaif field from 2024 to 2028. It is focused upon de-bottlenecking capacity constraints in the existing Umm Shaif infield pipelines network and includes several new offshore facilities. McDermott International announced on 9 May 2019 that ADNOC had awarded it a front end engineering design (FEED) services contract as the initial phase of the Umm Shaif Gas Cap Condensate Development Project. The scope of work includes preparation and submission of an engineering, procurement, construction and installation proposal (EPCI) proposal reflecting the design of the offshore facilities developed by McDermott through its FEED work. ADNOC had awarded China National Petroleum Corporation’s (CNPC) publicly listed subsidiary PetroChina Company Limited (PetroChina) the final 10% participating interest in its new oil development contact for the offshore Nasr and super giant Umm Shaif oil fields on 21 march 2018. The company paid a US$ 570 million (AED 2.1 billion) signature bonus, proportionally in line with the cash sums paid by its coventurers Eni SpA (10%) and Total SA (20%). ADNOC subsidiary ADNOC Offshore retains a 60% government working interest in the oil development consortium. Total announced on 18 March 2018 that it had paid US$ 1.15 billion for a 20% stake in the new 40-year concession agreement to operate both the Nasr and Umm Shaif oil fields. Eni had acquired an initial 10% holding on 11 March 2018. The Supreme Petroleum Council (SPC) approved the creation of a new operating consortium prior to the expiry of the former Abu Dhabi Marine Operating Co (ADMA-OPCO) contract for the ADMA Central Block. The remaining 10% interest has yet to be awarded. ADNOC had confirmed in October 2016 that it planned to combine its two largest offshore operating companies, namely ADMA-OPCO and Zakum Development Company (Zadco) into a single operating unit. It subsequently announced on 15 October 2017 that it had established a new subsidiary “ADNOC Offshore” to be responsible for the development and delivery of oil and gas resources in Abu Dhabi waters. In launching its new unified brand in line with a 2030 smart growth strategy, ADNOC entered a transition period during which former company names are hereby being referenced for the purposes of clarity and historical integrity. ADMA-OPCO shareholders were ADNOC 60%, BP 14.66%, Total 13.33% and JODCO 12%. ADMA-OPCO was 100% right holder in the ADMA Central Block up until the point that its 45-year ADMA contract expired on 18 March 2018. The 1,303 sq km former ADMA Central concession encompassing both the giant Nasr and super-giant Umm Shaif oil fields expired in March 2018. Although discovered in 1971, the Nasr oil field was only brought onstream during 2015. Early production averaged around 22,000 bo/d during 4Q 2017, but the field is being developed to reach a peak plateau rate of 65,000 bo/d in 2H 2019. Umm Shaif was producing at a rate of around 250,000 bo/d during 4Q 2017. A new oil gathering network is to be commissioned during 2H 2019, which will allow an average production rate of 275,000 bo/d to be sustained until the year 2031. The original Abu Dhabi offshore concession was awarded to D'Arcy Exploration Company in 1953. In 1955 the concession was assigned to ADMA, a company owned by BP and CFP. BP assigned 45% of its interest to Japan Oil Development Company Limited (JODCO) in 1972. In January 1973 ADNOC acquired 25% interest in ADMA Limited. The following January ADNOC increased its shareholdings in ADMA to 60%. ADMA-OPCO was subsequently incorporated in 1977 to operate the ADMA concessions on behalf of the interest holders, ADNOC (60%) and ADMA (40%). In early November 2010, ADMA-OPCO CEO Ali Rashid Al Jarwan re-affirmed the fact that his company intended to increase its offshore oil production capacity to 1.75 million barrels a day (MMbbl/d) by 2019. Partners in the Central Offshore concession effective 27 July 2020 are ADNOC Offshore (60%) Total (20%) Eni (10%), PetroChina (6%) and CNOOC (4%).

UAE, not found

Petoro has exited licences PL018 C & DS, assigning its 5% interest to Petrolia effective 30 November 2018. Petrolia acquired its initial 6.654% interest from exiting Equinor (previously Statoil), on 31 October 2018. PL018 C & DS cover the same area (24 sq km) in block 1/5 but are split stratigraphically. PL018 DS applies to levels between top of the Early Paleocene Ekofisk formation and down to the base of Late Cretaceous Hidra Formation. PL018 C contains the cross border Total-operated Flyndre oil field which mainly (93%) lies on the UK continental shelf (UKCS), however Petoro has retained its 0.354% share in the Flyndre Business Unit. Flyndre was discovered in the Norwegian sector by 1/5-2 (1974, Phillips, 4,287m), within Palaeocene Balmoral sands with a secondary Late Cretaceous Tor Formation chalk reservoir, and production commenced on 26 March 2017. Reserves are likely to be in the order of 10 MMboe recoverable and oil production is tied-back to the Clyde platform (24km SW) and liquids via the Fulmar platform (30km SW), both on the UKCS. Total gained its stake when it acquired Maersk on 14 May 2018. PL018 DS was awarded on 29 November 2011 in the production phase and partners are Total E&P Norge AS (60.008% + Op), Skeie Energy subsidiary Production Energy Company AS (15%), Aker BP (13.338%) and Petrolia NOCO AS (11.654%). PL018 C was awarded on 20 December 2002 in the production phase and partners are Total (88.346% + Op) and Petrolia (11.654%). Flyndre Unit participants are Total (72.196%), Repsol Sinopec (26.979%), Petrolia (0.471%) and Petoro (0.354%).

Petoro has exited licences PL018 C & DS, assigning its 5% interest to Petrolia effective 30 November 2018. Petrolia acquired its initial 6.654% interest from exiting Equinor (previously Statoil), on 31 October 2018. PL018 C & DS cover the same area (24 sq km) in block 1/5 but are split stratigraphically.

On 31 October 2018, the Federal Agency for Subsoil Use announced an auction for the Tazovskiy Zapadnyy block in Yamalo-Nenets Autonomous Okrug (West Siberia). The auction will be held on 20 December 2018 with its application deadline on 26 November. The winner of the auction will obtain a 25-year E&P license with a seven-year exploratory stage. Additional information regarding the auction may be requested from: Yamalnedra 629008, Salekhard Mira St., 40, office 2.1 Tel: +7 (34922) 4-72-74 Fax: (34922) 4-40-32 E-mail: [email protected]  Details of the offer are as follows: The Tazovskiy Zapadnyy block covers 1,170 sq km in the eastern part of the Nadym-Taz Province and encompasses the Tazovskaya Zapadnaya prospect with hydrocarbon resources estimated at 8.6 Tcf of gas and 316 MMbbl of condensate. Seismic coverage amounts to 1,921 km of 2D data and 28 sq km of 3D data. Five exploratory wells have been drilled in the area. Hydrocarbon resources (categories D1+D2) of the block are estimated at 72 MMbbl of oil, 9.4 Tcf of gas and 38 MMbbl of condensate. The starting price amounts to RUB 503.096 million (USD 7.57 million).

Russia, not found

The (expected) farmout process has kicked off for block SL10B / SL13, Stellar Egy Advisors retained. Explo drilling is planned contingent on the successful farmout. The 18,290-sq km licence lies E. of Hargeysa in the Somali Basin, Somaliland. Genel (op), partner East Africa Res.

The (expected) farmout process has kicked off for block SL10B / SL13, Stellar Egy Advisors retained. Explo drilling is planned contingent on the successful farmout. The 18,290-sq km licence lies E. of Hargeysa in the Somali Basin, Somaliland. Genel (op), partner East Africa Res.

In mid-May 2018 Clara Petroleum confirmed it is looking for partners for the E X-4 Tulca permit in return for a contribution to past costs, the funding of a focused 3D seismic survey, two wells and surface production facilities. The block situated along the border with Hungary contains - in addition to the Ciumeghiu West field and the Discovery 11 - twenty leads and prospects. The company’s plan is to acquire two 3D seismic surveys and to drill two to three wells starting in 2019. Five fields are excluded from the area covered by the E X-4 Tulca permit: the Arpasel gas field, the Ciumeghiu oil field, the Ciumeghiu Est gas and condensate field, the Ciumeghiu Nord gas field, the Salonta gas and condensate field and the Tinca oil field. The Arpasel structure is a part of the Ciumenghiu structure. The Salonta field represents the easternmost extension of the Sarkadkeresztur oil and gas field in Hungary (which is one of the main producing gas fields of Hungary). Interest in the 1,120 sq km E X-4 Tulca permit is 100% held by Clara Petroleum Ltd.

In mid-May 2018 Clara Petroleum confirmed it is looking for partners for the E X-4 Tulca permit in return for a contribution to past costs, the funding of a focused 3D seismic survey, two wells and surface production facilities.

BP Exploration & Production was officially awarded Green Canyon Block GC 365 (G36431) as of 1 November 2018. The block is expected to expire on 31 October 2025. The block, situated in the East Texas Coastal Basin, was originally offered as part of OCS Lease Sale 251, which was held on 15 August 2018. The sale garnered 171 bids for 144 tracts in both shallow and deepwater from a total of 29 companies. According to officials, a total of US$ 178,069,406 was received in high bids. Following official award, BP Exploration & Production is the operator and sole interest-holder (100% WI + Op) in GC 365.

Not Found

Tunisian state company Etap is promoting the country’s open blocks that are available to companies for direct negotiations. The Department of Energy of Tunisia indicate that the bids relating to prospection and/or exploration permit granting should be submitted to the General Manager of Energy with the name and address of the tender. Bid opening and bid evaluation will be done during the fourth week following the considered quarter. The open blocks are in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored. Etap has a special data room for visiting companies wishing to explore in Tunisia. Data are available on blocks including geophysical data (seismic lines, airmag, and gravity surveys) and geological data well reports and studies may be accessed at free of charge. Visitors benefit from Etap's expertise in any area. Interested parties may contact Etap 54 Avenue Mohamed V 1002 Tunis Tunisia Tel : +216 71 28 53 00 Etap web site: http://www.etap.com.tn   The available blocks as of July 2020 are understood to be as listed below. There are 36 available blocks. There was one change from the previous list. The Zahret Midyen block is not any more under application and is understood to be available. Total open acreage amounts to 148,684 sq km of which 89,705 sq km is onshore and 58,981 sq km is offshore.   Open blocks       Block Name Area (sq km) Situation Block Basin Ain Soltane 552 onshore Sud-Tellian Atlas Al Mansoura 854 onshore Pelagian Basin Beni Khedache 4,421 onshore Dahar Uplift (Ghadames Basin) Bir Abdallah 2,045 onshore Dahar Uplift (Ghadames Basin) Bizerte 3,466 onshore Sud-Tellian Atlas Boughrara 3,346 onshore Djefara Basin Chaffar 5,724 offshore Pelagian Basin Chanchou 5,826 onshore East Tunisian Platform (Pelagian Basin) El Garsi 3,865 offshore Pelagian Basin El Rimel 326 onshore Dahar Uplift (Ghadames Basin) Ezzahra 4,419 offshore Pelagian Basin Jalta 7,784 offshore Tellian Atlas Jebil 2,228 onshore Dahar Uplift (Ghadames Basin) Jougar 3,942 onshore Central Atlas Graben Zone Kambout 2,995 onshore Dahar Uplift (Ghadames Basin) Korbous 4,070 offshore Sud-Tellian Atlas Ksar Ezzaouia 2,093 offshore Djefara Basin Ksour Essaf 6,753 offshore Pelagian Basin La Skhira 7,451 offshore Pelagian Basin Majoura 7,474 onshore Moroccan-Algerian-Tunisian Atlas Mellegue 5,571 onshore Central Atlas Graben Zone Mezzouna 6,029 onshore Kasserine Island Mrezga 4,748 offshore Pelagian Basin Ouedhref 2,650 offshore Ashtart Sub-basin (Pelagian Basin) Sidi Amor 5,841 offshore Sud-Tellian Atlas Sidi El Heni 5,181 onshore East Tunisian Platform (Pelagian Basin) Sidi Toui 3,065 onshore Dahar Uplift (Ghadames Basin) Smida 558 onshore Ghadames Basin Somaa 3,582 offshore Pelagian Basin Sufaitula 5,756 onshore Kasserine Island Tagueulmit 5,137 onshore Djefara Basin Tamazret 3,915 onshore Dahar Uplift (Ghadames Basin) Tebaga 4,947 onshore Dahar Uplift (Ghadames Basin) Tibar 4,411 onshore Diapir Zone Triaga 3,788 onshore Pelagian Basin Zahret Midyen 3,874 onshore Sud-Tellian Atlas

Tunisian state company Etap is promoting the country’s open blocks that are available to companies for direct negotiations.

AE-0032-2M-Joachin-02 block, NW of discovery, onshore Veracruz Basin, compl gas-cond at TD 7,874m mid-Nov ’18. Main target M + L Cretaceous Orizaba fm. This well, coupled to Ixachi-1DEL still drilling but in the reservoir section with shows, features a 1,000m pay section, with field reserves pegged at 1 Bboe.

Ixachi 1001EXP (Pemex 100%) in AE-0032-2M-Joachin-02 block, NW of discovery, onshore, compl gas-cond at TD=7874m. Main target M + L Cretaceous Orizaba fm. This well, coupled to Ixachi-1DEL still drilling but in the reservoir section with shows, features a 1,000m pay section, with field reserves pegged at 1 Bboe.

Hitherto unreported on 3 September 2019, the Petroleum Agency of South Africa (PASA) granted Afro Energy (Pty) Ltd (Afro Energy) a Karoo Basin Coal Bed Methane exploration right (270ER). The Application was lodged in November 2013.  270ER covers some 2,560 sq km within the Karoo Basin and is composed of two parts which straddle the provinces of Free State, KwaZulu-Natal and Mpumalanga. The work programme for the first three-year exploration period includes the following. Year 1: Drill 3 to 6 exploration core holes, Geophysical log of holes and the analysis of core sample gas content Year 2: Drill 3 to 6 exploration core holes, Geophysical log of holes, analysis of core sample gas content, design a pilot test well program and apply for approval to test. Year 3: Drill 2 to 4 pilot wells and analysis of pilot test programme results. Afro Energy operates the exploration right with a 100% interest.

Afro Energy has awarded a Coal Bed Methane exploration right in 270 and 271ER block.

The OGA has offered 123 licences over 229 blocks or part-blocks to 61 companies under the 30th offshore round. Commitments after awards would include 8 explo/appr wells, 9  3D seismic surveys and 14 licences to head to field devt planning under 2nd  term licences. Should all offers be taken up, additional licenced acreage will be an increase of 50% on existing acreage held. The list of awardees is available here from the OGA (map below refers).

The OGA has offered 123 licences over 229 blocks or part-blocks to 61 companies under the 30th offshore round. Commitments after awards would include 8 explo/appr wells, 9 3D seismic surveys and 14 licences to head to field devt planning under 2nd term licences. Should all offers be taken up, additional licenced acreage will be an increase of 50% on existing acreage held.

Aker BP has agreed to acquire Equinor's entire 77.8% operating stake in North Sea production licences PL146 and PL333 for a total consideration of US$ 250 million. The deal announced on 15 October 2018 is subject to regulatory and partner approvals. PL146 (59 sq km) and PL333 (28 sq km) were awarded during 1988 and 2004 respectively and cover part of block 2/4 on the Norwegian Continental Shelf, approximately 10km NW of the producing Ekofisk oil field. The acreage contains the King Lear gas and condensate discovery, thought to have been initially drilled by NFW 2/4-14 (1989, Saga Petroleum, 4,734m MD) which made a technical discovery encountering oil and gas in the high pressure Early Cretaceous Mandal Formation. However, a resultant blow-out incident caused the drilling of a relief well (2/04-15) and the abandonment of operations. The prospect was drilled again by Statoil in 2012, with NFW 2/4-21 (5,395m MD) encountering commercial volumes of gas and condensate in the Late Jurassic Intra-Farsund Formation sandstone. The discovery has been successfully appraised (2/4-21 A) with a reported net recoverable resource of 77 MMboe. Additionally, on PL146, NFW 2/4-23 S (2015, Statoil, 5,548m) made a gas and condensate discovery (Julius) in the Middle to Upper Jurassic Ula and Bryne formations, as well as a minor oil discovery (Romeo) by NFW 2/4-22 S (2015, Statoil, 4,889m). Pending approvals PL146 and PL333 are operated by Equinor Energy AS (77.8%) and Total E&P Norge AS (22.2%).

Aker BP has agreed to acquire Equinor's entire 77.8% operating stake in North Sea production licences PL146 and PL333 for a total consideration of US$ 250 million.

Total has completed the acquisition of a 40% interest in licences P1964, P1965 and P2443 from operator ENI. The licences are located in the Winterton High area across quads 53 and 54. There are a number of Dinantian carbonate build-up prospects in the acreage. The deal completed on towards the end of February 2019. Licences P1964 and P1965 were awarded in 2013. Licence P1964 comprises of blocks 53/5c, 53/10a and 54/1b. P1965 comprises of blocks 53/14a, 53/15a, 54/6a and 54/11a. Licence P2443 was awarded in 2018 and comprises of blocks 53/8a, 53/9a, 53/13a and 53/14b. Interest in the licences is now held by ENI UK Limited (60% + operator) and Total E&P UK Limited (40%).

Eni (->60%) has farmed out 40% to Total in Southern North Sea licences P1964, P1965 and P2443, The licences are located in the Winterton High area across quads 53 and 54. There are a number of Dinantian carbonate build-up prospects in the acreage.

Talos has reportedly bought the Antrim discovery in the W-C part of Green Canyon block 364, WD 950m, from ExxonMobil through a deal signed in January. Antrim well GC 364 GC001S0B0 was drilled late 2017 to a subsalt Miocene reservoir, results undisclosed at the time. An appraisal is now planned, which if successful would justify a tie-back to the Talos-owned GC 18 facility. Talos otherwise has plans to drill 2 deepwater prospects this year, Bulleit + Orlov, the latter Fieldwood-operated and pencilled for later this month.

Talos Energy (->100%) has acquired, with plans for an appraisal well, the Antrim discovery in a sub-salt Miocene reservoir (results undisclosed at the time), locates in Green Canyon Block 364 (G35660) from ExxonMobil.

Twinza Oil Ltd is considering seeking for a strategic partner in its 100% owned Pasca A gas and liquids field, located in PPL 328, offshore Papuan Basin. It is thought that Twinza is reviewing opportunities to attract financial support to reach the development phase of the project. Considerations by Twinza are likely to involve offering variable participating equity in the project. It is unknown if a full divestment of the asset or sale of the company is also on the table. It thought that Twinza has approached financial institutions over past 12 months to see what options could be available and that investment banks Goldman Sachs and UBS have been enlisted to commence promotion of the Pasca asset to interested parties such as financial organisations and possibly existing PNG energy companies. Twinza is a privately-owned company with major shareholders including Clough and Kerogen Capital which has provided a platform for moving forward on PNG’s first offshore development. On 6 March 2019, Twinza reported that it is also seeking fund raising through an Offer Information Statement Entitlement to its Shareholders, dated 26 February 2019. Twinza holds 100% interest in exploration licence PPL 328, which covers the Pasca A field and has remained as operator since 2011. Pasca is considered a Miocene Reef play in the Darai Limestone. The most recent Pasca A4 appraisal well drilled in 2017-18 encountered an over-pressured reservoir section which was found to contain good porosity and permeability. Post drill analysis enabled the Pasca field to reach new highs in certified resources. A 2018 Gaffney Cline and Associates report estimates liquids totalling 69 MMbbl which relates to an approximate 70% increase on pre-drill estimations by Twinza. Gas resources were estimated at around 320 Bcf. PPL 328 was scheduled to expire on 30 October 2017 but remains valid until a decision is made on the development licence application APDL 14, which was submitted by Twinza on 30 June 2015. The award is pending a Gas Agreement from the government which is expected once the development scheme for the second phase of gas production is finalised. The two-phase development plan, which was submitted to the government in 2015, includes an initial production of natural gas liquids, including condensate and LPG with the reinjection of dry gas. The second phase would then see the dry gas exported. As agreement was entered into between Twinza and Global Exploration Ventures (GEV) in August 2018 for GEV to undertake a Pre-Feasibility Study to assess the commerciality of gas production/export from the Pasca A field. The study was to evaluate a commercial plan for gas deliverability to market using a compressed natural gas (CNG) solution. Full stream support for the Pasca field is provided by an agreement with Baker Hughes GE which was entered into in In August 2017. The agreement includes a wide range of services in drilling, subsea equipment, gas compression, gas processing topside and turbomachinery, along with well installation and commissioning services. Following Financial Investment Decision (FID) Baker Hughes expects to provide an integrated gas processing solution from the wells through to the point of export. If a Gas Agreement is reached by mid-2019, which approves the development scheme and sets the fiscal and development terms for the project, Twinza expects to enter Front End Engineering and Design (FEED) phase by end-2019, preceding a FID and first production around 2023-24. If the timeline is realized, the first offshore production in PNG could commence ahead of the next phase of LNG expansion, providing LPG and condensate for domestic use. The second phase of gas production from Pasca could be strategically enhanced by aggregating resources from the neighbouring field, including Pandora, Flinders and Hagana. Twinza held 40% interest in the 900 Bcf Pandora field before the retention lease PRL 38 was allowed to expire by operator Repsol in November 2018. Twinza has subsequently submitted an application for a new lease over the field along with other competitive bids. After nearly eight years operating Pasca, Twinza is now considering obtaining a new strategic partner as the project nears receiving government approval for development. Interested parties in this opportunity should contact: Huw Evans Email: [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

Providence Resources has provided a commercial update on Standard Exploration Licence ('SEL') 1/11 that contains the Barryroe oil accumulation.  SEL 1/11 is operated by EXOLA (80%), a wholly-owned Providence subsidiary, on behalf of its partner Lansdowne Celtic Sea (20%), collectively referred to as the 'Barryroe Partners'. The area lies in c. 100 metre water depth in the North Celtic Sea Basin and is located c. 50 km off the south coast of Ireland.Standard Exploration Licence ('SEL') 1/11 Farm-Out The Company has announced that the Barryroe Partners have signed a Farm-Out Agreement ('FOA') with APEC in relation to SEL 1/11.  APEC is a privately owned Chinese company which has a strategic partnership with China Oilfield Services ('COSL') and JIC Capital Management ('JIC') for the investment and development of offshore oil and gas opportunities worldwide utilising Chinese drilling units, services and equipment.Under the terms of the FOA, in consideration for APEC being assigned a 50% working interest in SEL 1/11:Commercial TermsOperational TermsIssuance of Warrants to APECUpon completion of the Drilling Programme, APEC will be able to subscribe for warrants over 59.2 million shares in Providence at a strike price of £0.12 per share (the 'Warrants').   The Warrants, representing circa 9.9% of the current issued share capital of Providence, are exercisable for a period of 6 months following the completion of the Drilling Programme.Closing The Closing of the Farm-Out, which is expected to occur in Q3 2018, is conditional on completion of all ancillary legal documentation required to implement the terms of the FOA, and is subject to the approval of the Minister of State at the Department of Communications, Climate Action and Environment and the approval of the Chinese government.  In addition, the details of and schedule for the Drilling Programme are subject to further ongoing technical discussions between the Consortium, Exola and Lansdowne.  Subject to Closing, the revised equity in SEL 1/11 will be EXOLA (Operator, 40%), APEC (50%) & Lansdowne (10%). Further announcements on the transaction will be made in due course.Speaking today, Tony O'Reilly, Chief Executive of Providence said:'This is a significant transaction for Providence and Lansdowne which will deliver multiple new penetrations of the areally extensive Barryroe field.  In addition, it also provides for the acquisition of modern dynamic well test data that should assist in advancing the field to production.  Over the coming months, we will be working with the APEC Consortium to close the transaction and finalise the specific timeline and the precise details of the drilling programme.  We are very pleased to have agreed this deal, which will allow us to avail of 'state of the art' drilling units and technical capabilities in order to advance Barryroe to first oil.'Mr. Colin Lui, Chairman of APEC Energy Enterprise Limited commented:'APEC, supported by Jianyin Investment Company and China Offshore Services Ltd, are very pleased to have strategically joined forces with Providence and Lansdowne to develop the Barryroe field.  This field has significant recoverable resources and we look forward to jointly developing this opportunity.  Whilst the Farm-Out Agreement has been agreed specifically for Barryroe, the parties have also agreed to jointly investigate further opportunities in other licensed blocks offshore Ireland in the future.'Original article linkSource: Providence Resources

Providence (->50%) and Lansdowne (->0%) farm out a 50% WI in EL 01/11 (Barryroe) to a Chinese consortium led by APEC.

On 25 June 2020 Ithaca acquired 100% interest in licence P2494 (block 13/22c) from Chrysaor. The licence hosts the 13/22b-4 (Phoenix) discovery that was made in 1990 and two undrilled prospects in the north of the licence named Ensign and East. P2494 is adjacent and directly south of licence licence P324 which contains the Captain field. The 13/22b-4 (Phoenix) discovery is some 6 km south of Captain field. The P2494 licence was awarded to Chrysaor from the 31st licensing round in July 2019 as a straight to second term licence for the development of 13/22b-4 (Phoenix). The gas and condensate discovery is in the Burns Sandstone Member reservoir, trapped by a three-way dip closure and fault bound to the south. Chrysaor estimated GIIP volumes of 104 Bcf and 18 MMbbl of condensate. After the deal was complete, Ithaca Energy (UK) Ltd holds 100% interest in P2494.

United Kingdom (Moray Firth Province), Ithaca took over Chrysaor's 100% in P2494 (block 13/22c).

CNOOC announced on 10 July 2019 that it signed a Cooperation Framework Agreement with Sinopec, regarding the sea areas of Bohai, Beibu Gulf and South Yellow Sea, as well as North Jiangsu Basin. Under the framework, both parties have signed three joint study agreements, namely, “Joint Study Agreement on Bohai Gulf Basin”, “Joint Study Agreement on North Jiangsu Basin and South Yellow Sea Basin” and “Joint Study Agreement on Beibu Gulf Basin.” By further details, both parties will share data and carry out joint studies in the Yellow River Mouth Sag, the Qingdong Sag and the eastern part of Bodong Sag in the Bohai Gulf Basin, southwestern Weizhou and Xuwen areas of the Beibu Gulf Basin, as well as the Yancheng and Hai’an sags in the North Jiangsu Basin and the blocks in the eastern South Yellow Sea Basin. The study areas cover total 26,900 sq km involving 19 exploration concession blocks. The Cooperation Framework Agreement will be implemented in three years through joint study, joint exploration and facility sharing. The expenditures incurred for the joint studies shall not be recovered from the costs of any petroleum contract that may be signed in the future. During the joint study period, the exploration, development and production operation of both parties in their respective prospecting rights areas will not be affected. This cooperation will promote the distribution of sedimentary facies belts and enhance the understanding of the regularity of hydrocarbon accumulation in cooperative blocks and potential structures in the basins in order to make the optimization of potential exploration zones and targets more scientific, reduce exploration risks and improve the success rate of exploration wells. In earlier July 2019 Sinopec also signed a Joint Study Agreement with PetroChina covering operations in the Tarim, Junggar and Sichuan basins, involving 81 exploration concession blocks with total 305,800 sq km.

CNOOC announced on 10 July 2019 that it signed a Cooperation Framework Agreement with Sinopec, regarding the sea areas of Bohai, Beibu Gulf and South Yellow Sea, as well as North Jiangsu Basin. Under the framework, both parties have signed three joint study agreements, namely, “Joint Study Agreement on Bohai Gulf Basin”,

Harno prospect in Ghauri 3273-3 EL, Potwar onshore, Punjab, P&A late Jul '20 after testing, TD 4,934m in ST2, target Eocene + Cambrian, co. rig 3. MPCL (op), partner PPL.

(Potwar B.) Miraj 1 nfw, in Ghauri 3273-3 EL block, op. by MPCL (65%), partner PPL (35%), P&A after testing, results N/A, TD 4,934m in ST2, target Eocene + Cambrian.

Westmount Energy announced on 2 October 2018 that it had acquired minor net profit interests (NPI) from Infrastrata in licences P1918 (0.5%), P2222 (0.5%) and P2235 (1%). P1918 contains the Colter discovery where an appraisal well is planned for Q4 2018. Colter was discovered by 98/11-3 (1986, BG, 2,107m) and has mean prospective recoverable resources of 30 MMbo. P2222 contains the Oulton Discovery, discovered by 3/11-1 (1974, BP, 2,145m) having oil in Jurassic Emerald sandstones and with estimated recoverable 17MMbo. P2235 contains the Wick prospect planned for Q4 2018. Wick is targeting oil in Jurassic and Triassic sands, and the prospect has P50 estimated in place prospective resources of 250 MMboe. Infrastrata exited P1918, P2222 and P2235 to Corallian Energy in November 2015 but retained a 4% NPI.

Westmount Energy announced on 2 October 2018 that it had acquired minor net profit interests (NPI) from Infrastrata in licences P1918 (0.5%), P2222 (0.5%) and P2235 (1%).

As of 18 September 2018, Karoon Gas Australia Ltd has received approval for the formation of a technical evaluation area (TEA) called LXXIV. The block has been granted with the block coordinates being finalized. No other information is available at this time.

As of 18 September 2018, Karoon Gas Australia Ltd has received approval for the formation of a technical evaluation area (TEA) called LXXIV. The block has been granted with the block coordinates being finalized. No other information is available at this time.

New Zealand Oil & Gas Ltd, via wholly owned subsidiary NZOG 2013 O Ltd, is offering equity in exploration permit PEP 55794, located in the Great South Basin. A 50% area relinquishment was made at the end of March 2020 in line with the revised work programme commitments which was approved on 26 August 2019. A commit or surrender decision is now due to be made before 1 April 2022. Should the permit be retained, the first exploration well is due to be drilled before 1 April 2023 as part of the Stage 2 work obligations. A further contingent well is also due before the permit's expiry. NZOG have outlined the Kaipatiki prospect as the primary candidate for drilling. The prospect lies in the southern portion of the permit and comprises a four-way, dip closed, stratigraphic trap created by the injection of deep-water sands into overlying mudstones. The prospect has been mapped over an area of approximately 160 sq km using the Toroa 3D seismic data acquired in 2015. The sand injectites are likely to originate from the Wickliffe Formation (Pakaha Group), which includes the shoreface/nearshore Kawau Sandstone Member and the informal 'Wickliffe Coastal Facies', and are sealed by intraformational basinal mudstones. Modelling suggests that the prospect is well located to receive charge from mid to Late Cretaceous syn-rift Hoiho coals which are at the onset of liquids generation and at peak oil/liquids generation over much of the permit. Mean unrisked in-place resources of 7.3 Tcf of gas and 750 MMb of condensate have been estimated for the prospect. Potential development scenarios include a gas to shore option for which mean unrisked prospective recoverable resources of 5.6 Tcf of gas and 272 MMb of condensate have been estimated. The permit contains the Toroa 1 and Tara 1 wells that were drilled in 1976 and 1978 respectively. Both wells encountered oil and gas shows during drilling, proving the presence of a working petroleum system within the area. On 18 October 2018, NZOG officially increased its holding to 100% and operatorship in PEP 55794 by acquiring the 70% operated interest formerly held by Woodside Energy (New Zealand 55794) Ltd. PEP 55794, which now covers an area of approximately 4,918 sq km in both deep and shelfal waters, was awarded on 1 April 2014 after being applied for under the Block Offer 2013. NZOG 2013 O Ltd holds 100% operated interest in the permit. Interested parties are required to meet a confidentiality agreement prior to being allowed access to the data room and technical presentations. Parties interested in pursuing this opportunity should contact: Dr Chris McKeown, VP Business Development Tel: 0064 21 134 4953 Email: [email protected]   Bernice Herd, New Ventures Manager: Tel: 0064 21 135 7836 Email: [email protected]

New Zealand Oil & Gas Ltd, via wholly owned subsidiary NZOG 2013 O Ltd, is offering equity in exploration permit PEP 55794, located in the Great South Basin.

Nova Petroleo is assumed to have plugged and abandoned dry the 1-NOVA-2 (1-NOVA-003-AL) new-field wildcat (NFW) in the SEAL-T-291 block on 11 March 2020 after reaching a final total depth (TD) of 642 m on 10 March. The NFW was spudded on 5 March 2020. The NFW had a proposed total depth (PTD) of 450 m and is speculated to be targeting the Late Jurassic Serraria Formation. The well was a rank NFW located in the south-eastern area of the block with the nearest well located 3.1 km north-east, the 1-NOVA-3 (1-NOVA-001-AL) plugged and abandoned dry by the operator in February 2020. Nova Petroleo is operator of the ANP Round 12, 31.55 sq km SEAL-T-291 block and holds 50% working interest and Petrobras holds 50% non-operated working interest.

Nova Petroleo is assumed to have plugged and abandoned dry the 1-NOVA-2 (1-NOVA-003-AL) new-field wildcat (NFW) in the SEAL-T-291 block on 11 March 2020 after reaching a final total depth (TD) of 642 m on 10 March.

Statoil and Total have completed their previously announced transaction whereby Statoil has acquired Total’s equity stakes in, and taken over the operatorships of, the Martin Linge field and the Garantiana discovery on the Norwegian continental shelf.Statoil now has a 70% interest in Martin Linge and 40% in Garantiana. 121 employees from Total have been transferred over to Statoil in accordance with the Sale and Purchase Agreement and applicable legislation.Martin Linge is an oil and gas field under development west of the Oseberg field in the North Sea (Source: Statoil)Original article linkSource: Statoil

Statoil and Total have completed their previously announced transaction whereby Statoil has acquired Total’s equity stakes in, and taken over the operatorships of, the Martin Linge field and the Garantiana discovery on the Norwegian continental shelf.Statoil now has a 70% interest in Martin Linge and 40% in Garantiana.

The CNH has awarded 16 blocks from the CNH-RO3-LO1/2017 round (Ronda 3.1), this being now officially closed.  Pemex dominated the offer, placing the largest number of bids, winning 2 blocks as optr + 5 as partner. BP (Pan American), Cairn, Cepsa, Citla, DEA, Eni, Hockchi, Lukoil,  Premier, Repsol, Sapura, Shell and Total also participated. Participants ECP, Galem, Inpex and Petronas failed to win blocks. The roundup of awards is as follows (details from GEPS):

Mexico, not found

Luntai area of Tabei Uplift, Tarim Basin, TD 8,882m in Jul '19, tested 934 bo/d + 1.7 MMcfg/d from the sub-salt Cambrian Wusongger fm, considered play opener, well completed 19 Jan '20.

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

W-C part of Green Canyon block 364, OCS lease G35660, WD 950m, cleared to P+A by the BOEM after only 40 days of the planned 150 were spent on the well, resuts so far unknown. Noble Bob Douglas DS. The drillship was otherwise slated to head back south to Guyana for a 3-year campaign with ExxonMobil.

Green Canyon 364 GC001S0B0 (Antrim) op. by Exxon (100%) in OCS lease G35660 (Green Canyon block 364), P+A after only 40 days of the planned 150 were spent on the well, results so far unknown.

ExxonMobil will reportedly be signing tomorrow for PSC rights to the Deepwater Cape Three Points (DWCTP) block, WD 2,000-4000m in the Tano Basin. DWCTP was held in the past by Vanco and by Lukoil over 5,153 sq km and was under application by Clontarf in 2016. The area contains the Dzata-2A gas discovery (2011).

ExxonMobil signed for PSC rights to the Deepwater Cape Three Points (DWCTP) block.

On 3 February 2018 Fogelberg appraisal well 6506/9-4 S was spudded by Spirit Energy. The company has used the “Island Innovator” S/S to drill the well in PL 433. 6506/9-4 S is located in a down-dip position, approximately 1 km to the west of the discovery well, with the aim of adding 2P reserves, reducing volume uncertainty and confirming reservoir quality before the licence group commits to a FEED project. The well was drilled to TD at 4,738 m and encountered a 63 m gross hydrocarbon column in the Middle Jurassic Garn Formation and gas in the Middle Jurassic Ile Formation. Reservoir quality is better than that seen in the discovery well and the GWC is deeper. On 28 April 2018 sidetrack 6506/9-4 A was kicked-off from the 14” casing and on 8 May 2018 Spirit was drilling ahead 12-1/4” hole at 4,066 m. The licence term for PL 433 was extended in February 2017 with a deadline to submit a PDO by July 2019. The PDO was originally expected to be submitted in February 2017. Centrica (now Spirit) received MPE approval for the Environmental Impact Assessment (EIA) for Fogelberg in early 2014. The proposed plan (given at that time) included the installation of a four-slot subsea template (with three producers to be drilled initially) tied-back to either Asgard B or Heidrun. Costs were estimated at either NOK 7 billion (USD 1.18 billion) or NOK 11 billion (USD 1.86 billion) depending on which host facility was chosen. The Fogelberg discovery well (6506/9-2 S) was Centrica’s first as an operator on the NCS and was drilled in 2010. Gas and condensate was confirmed in the Garn and Ile formations with no OWC indentified. The field is HPHT. It lies between Victoria and Smorbukk on the Halten Terrace and has estimated recoverable reserves of approximately 105 – 530 Bcfg. Pending completion of three deals in PL 433 interest will be divided between Spirit Energy Norge AS (51.7% + operator), PGNiG Upstream Norway AS (20%), Faroe Petroleum Norge AS (15%) and Dyas Norge AS (13.3%).

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

Hitherto-unreported, on 23 May '19 Granite was awarded PPLs 638 + 639, total 1,650 sq km in the Eastern Fold Belt, Papuan Basin, for 6 yrs. These are Granite's 1st holdings in PNG:

Papua New Guinea, not found

An auction is planned for 20-year rights to the Surmachivska block, Dnieper-Donets Basin in the Sumska Oblast, on 12 Feb ’19, application deadline 12 Dec ‘18. Starting price USD 0.22 MM, documentation + geological data package USD 20,000 from Kiev, Antona Tsedika Str. 16, offices 415 & 416, tel: (044) 536 1320 + 456 6085.

Ukraine, not found

On 31 July 2019, the Australian Government, Department of Industry, Innovation and Science opened the federal 2019 Offshore Petroleum Exploration Acreage Release. A total of 64 blocks, covering approximately 120,000 sq km, have been opened for a single round of work programme bidding across the Browse, Bonaparte, Roebuck, North Carnarvon, Otway and Gippsland basins. All blocks are due to close on 5 March 2020 under a new system that is seeing one closing date (rather than the usual two tranches that had been previously used) as well as other changes to nomination, consultation and negotiation, with an aim to streamline the bidding process and make it more efficient. In the Otway Basin, two blocks have been released for bidding. One is within the Prawn Platform and the other is within the Mussel Platform and close to shore. V19-1 is in the Mussel Platform and covers an area of 121 sq km. There are no wells within the block area. It is adjacent to the three-nautical mile limit that marks the offshore/onshore legislation split. V19-2 is in the Prawn Platform and covers an area of 1,296 sq km.  It contains one dry well and one well – LochArd 1 – that encountered gas shows.  The block is adjacent to the Geographe and Thylacine fields, which were brought onstream, to supply domestic gas, in 2007. The round consisting of 64 blocks is considerably larger than in previous years, when between 20 and 40 blocks has been usual. However, the amount of acreage on offer (just over 120,000 sq km) has not seen a significant increase, and is in fact less than the total acreage offered each year in 2017 and 2018.

On 31 July 2019, the Australian Government, Department of Industry, Innovation and Science opened the federal 2019 Offshore Petroleum Exploration Acreage Release. A total of 64 blocks, covering approximately 120,000 sq km, have been opened for a single round of work programme bidding across the Browse, Bonaparte, Roebuck, North Carnarvon, Otway and Gippsland basins.

Energean has signed to acquire Total's 50% operating stake in offshore block 2, 2,422 sq km in the Ionian Sea and home to a Jurassic prospect straddling the Italian border (extending in adjacent 84F.R-EL). Commitments still include 1,800km of 2D seismic. Partners-to-be Energean (op, 75%), Hellenic + Edison (under buyout by Energean). Release here.

Energean has signed to acquire Total's 50% operating stake in offshore block 2, 2,422 sq km in the Ionian Sea and home to a Jurassic prospect straddling the Italian border (extending in adjacent 84F.R-EL). Commitments still include 1,800km of 2D seismic. Partners-to-be Energean (op, 75%), Hellenic + Edison (under buyout by Energean).

Fraccio´n C block, onshore Austral Basin, TD 2,460m, mechanical stimulation of a 4m interval in the target Tobifera fm now complete, with no recovered hydrocarbons. Will be shut-in as non-commercial. CGC (op), partner Echo Energy.

El Molino Sur-1001 (EMS) exp Fraccio´n C block, onshore Austral Basin, TD 2,460m, mechanical stimulation of a 4m interval in the target Tobifera fm now complete, with no recovered hydrocarbons. Will be shut-in as non-commercial. CGC (op), partner Echo Energy.

OGDCL has assigned a 2.5% interest to Govt Holdings and 1.7% to Sindh Energy Holding in the Zorgarh 2868-7 EL, 2,402 sq km in the Sulaiman Fold Belt. The contract area in SIndh is now shared by the 3 co’s.

OGDCL has assigned a 2.5% interest to Govt Holdings and 1.7% to Sindh Energy Holding in the Zorgarh 2868-7 EL, 2,402 sq km in the Sulaiman Fold Belt. The contract area in SIndh is now shared by the 3 co’s.

It was reported in early February 2020, that Staatsolie is likely to carve out and offer stakes in its shallow water "Staatsolie Study Area" in H2 2020. Staatsolie CEO , Rudolf Elias, revealed, "we want to put it on the market somewhere in the second half of 2020". He also added that the state-owned company will hold a stake in this area and will seek to form joint ventures (JVs) with interested parties. It is thought that a full blown Production Sharing Contract (PSC) may not yet be offered, but more of a study agreement or prospecting type licence. The study area is around 29,000 sq km and covers open blocks previously known as J,K,L,M,N,O,P,R,S,T,U,V,W & X, although the block arrangement may be changed. The study area borders Apache's Block 58 where the company recently made its significant Maka Central 1 discovery with around 73m of oil pay, and 50m of light oil and gas condensate pay discovered in multiple stacked reservoirs in Late Cretaceous-aged Campanian and Santonian intervals. ExxonMobil's prolific Stabroek Block in Guyana also borders the study area. The continued de-risking of the Guyana-Suriname Basin by ExxonMobil has made Staatsolie's proposition more inviting. Staatsolie has apparently identified a large source rock in the area. Companies which already hold equity in Suriname are gearing up to drill in Suriname, including Kosmos Energy in Block 42 immediately to the north of Apache's Block 58. Total recently farmed-in to Apache's Block 58 for US$100 million for a 50% stake and according to Elias, Apache has identified more than 50 drillable prospects on the block.Staatsolie has recently issued bonds for the third time, primarily to raise money this time for its 2020-2027 investment programme. The implementation of this programme is estimated to cost more than US$ 1 billion. The company carried out a Nearshore Drilling project (NSD Project) over three continuous blocks (A, B & C) in the ultra-shallow waters of the Guyana-Suriname Basin to the south of the Staatsolie Study Area. Four of the six wells demonstrated the presence of oil, although these were non-commercial. The NSD Project ran from April to November 2019 with the drilling of Marai, Electric Ray, Kankantrie, Powisi, Gonini and Tukunari in this order. The wells were drilled to depths ranging from 1,000 to 3,000m. The state-owned company describes the collection of data as a sub goal of the project and that this data is "very valuable". Staatsolie believes that "geological insights are sharpened and the chance of success in the further search for oil is increased" with this information. The well data collected can now be tallied with the seismic data. It is understood that Staatsolie may still seek partners for its shallow water blocks as it looks to finance any possible future exploration programmes. The company decided to go solo with the 2019 NSD Project after failing to find partners through a formal farm-out process that ended in July 2017. In the previous farm-out prior to the NSD Project, the state oil interest was offering up to 50% of its interests in Block B and Block C.<P /><P /><P /><P /><P /><P /><P /><P /><P /><P /><P /><P /><P />

It was reported in early February 2020, that Staatsolie is likely to carve out and offer stakes in its shallow water "Staatsolie Study Area" in H2 2020. Staatsolie CEO , Rudolf Elias, revealed, "we want to put it on the market somewhere in the second half of 2020". He also added that the state-owned company will hold a stake in this area and will seek to form joint ventures (JVs) with interested parties. It is thought that a full blown Production Sharing Contract (PSC) may not yet be offered, but more of a study agreement or prospecting type licence.

Eni and partners Mitsui + Tecpetrol were officially granted MLO-124, 4,421 sq km in the Malvinas Basin, from Argentina's 1st offshore round. Commitments/plans include 867km 2D seismic, 4,418 sq km 3D, 6,500km of gravity-magnetics within 4 yrs, 1 well within 8 yrs. An optional 3rd term would call for a 50% relinquishment.

Eni and partners Mitsui + Tecpetrol were officially granted MLO-124, (4421km²) from Argentina's 1st offshore round.

Gazkop secured sole rights on 22 Jan '20 to the 2/2020 Wilchwy extraction lease in the Upper Silesian Basin, S. Poland. Gazkop specialises in methane extraction from closed coal mines.

Gazkop secured sole rights on 22 Jan '20 to the 2/2020 Wilchwy extraction lease in the Upper Silesian Basin, S. Poland. Gazkop specialises in methane extraction from closed coal mines.

Europa Oil and Gas is offering interested parties to farm-in to Licence Option (LO) 16/20. Europa has identified 3 Tcf undiscovered GIIP in Triassic and Jurassic gas plays. In April 2019, Europa announced negotiations were still ongoing regarding the farm-in agreements with a major oil and gas company concerning licences LO 16/20, FEL 1/17 & FEL 3/13. Europa are expecting to be fully carried on a well on each licence and retain material interest in each licence with the final investment decision pending in the major’s head office. 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. This would ensure a well would be drilled at the earliest opportunity, if negotiations are successful. In February 2019, Europa announced an updated gross mean un-risked prospective resource estimate of 1.5 Tcf for the Inishkea prospect with a 33% chance of success. The prospect has been de-risked through the PSDM reprocessing of 770 sq km of 3D seismic over Inishkea and the Corrib gas field. Reprocessing was benchmarked and calibrated against Ocean Bottom Cable 3D seismic data over the Corrib gas field. Inishkea is defined as a large Triassic structure that lies 11 km from Corrib. The targeted Triassic gas play comprises of Triassic Sherwood sandstone reservoirs, Carboniferous source rocks and the combination of a Triassic Uilleann Halite top seal and fault seal providing the trapping mechanism. The water depths are relatively shallow (400 - 600 m) and do not require harsh environment sixth generation drillships, reducing drill costs. Europa conducted a drill cost estimate for a well on the Inishkea prospect and a dry hole cost including mobilisation and demobilisation of USD 28 million using a prevailing rig rate of USD 120,000 per day. Gas infrastructure is already present nearby at Corrib therefore a fast track path to commercialisation is potentially available, subject to negotiation and cooperation with the current infrastructure owners. The remaining inventory in LO 16/20 includes the Inishkea NW prospect (1,094 Bcf), Inishkea W prospect (212 Bcf), Bofin lead (69 Bcf), Corrib North discovery (40 Bcf) and Corrib NW prospect (26 Bcf). Interest in 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 is offering interested parties to farm-in to Licence Option (LO) 16/20. Europa has identified 3 Tcf undiscovered GIIP in Triassic and Jurassic gas plays.

In late August 2019, Badr El Din Petroleum Co (BAPETCO) successfully completed the appraisal well Sitra C03-2 at the Sitra C30-1 discovery, Sitra (Dev) block, Abu Gharadiq Basin. The well was spudded on 13 July 2019 with the “EDC-71” land rig and reached a TD of 3,100 m in the Albian-Lower Cenomanian Kharita Member of the Burg El Arab Formation. The Sitra C30-1 discovery was found in July 2019 after the new field wildcat Sitra C30-1 tested oil and gas in the Bahariya Formation (separate article). BAPETCO, also named Sitra Petroleum or SIPETCO, is a JV between the EGPC, Shell Australia AG and Shell Egypt NV. The Sitra (Dev) lease was granted to BAPETCO in December 1985. It includes six other fields (Sitra 1-1, Sitra 3, Sitra C18-1 ST, Sitra East C4, Sitra 5 and Sitra 8), all discovered by Shell between 1982 and 2019.

Badr El Din Petroleum Co (BAPETCO) successfully completed the appraisal well Sitra C03-2 at the Sitra C30-1 discovery, Sitra (Dev) block, Abu Gharadiq Basin.

Baraka block, Pelagian Basin, WD 90m, target Saouaf fm, drilled and susp. 29 Feb – 1 Apr '20, Key Singapore JU. Eni (op), partner ETAP.

(Pelagian b.) Baraka PC-1 explo well, operated by ENI (49%), partner ETAP (51%) was suspended without result reported. The well is located in the Baraka block, WD = 90 m and targets Saouaf formation.

Spirit Energy, the newly formed company as a result of the merger between Centrica and Bayerngas, has exited licence P2112 (blocks 43/29a, 43/40b, 48/4a, 48/4b and 48/5a). Following the company’s exit from the licence on 19 December 2017, Spirit Energy’s interest is divided by Holywell Resources 26.67% and Atlantic Petroleum 13.33%. The acreage is located in the Southern North Sea, west of the Schooner and Topaz fields. The licence covers an area of 484.5 sq km and was awarded in the 27th Licensing Round. Following the completion of the deal interest in the licence is held by Holywell Resources Ltd (66.67%) and Atlantic Petroleum UK Ltd (33.33%).

Spirit Energy, the newly formed company as a result of the merger between Centrica and Bayerngas, has exited licence P2112 (Holywell Res.(->66.67%) and Atlantic Petroleum (->33.33%).

Coastal Oil & Gas Pty Ltd is looking for a farm in partner in four exploration blocks TP/27, EP 475, EP 490 & EP 491, located in the Enderby Terrace and Peedamullah Shelf, North Carnarvon Basin. The company is looking to farm-down around 50% interest in return for assistance in drilling at least three exploration wells over the next three years which could target a Jurassic oil play and evolving play in the Permian and Triassic. The blocks have been collectively known as 'Cerberus' since being awarded in 2011-2014. Coastal Oil & Gas acquired the acreage in September 2019 from Tanami Energy Pty Ltd. Tanami Energy, a subsidiary of Skye Energy Ventures, briefly held the permits after acquiring them from Carnarvon Petroleum in 2018. With an abundance of 2D and 3D seismic data coverage, Carnarvon delineated multiple prospects on structures which they reported could be capable of holding, on average, 100 MMb oil. The new operator is now seeking a farm-in partner as it looks to complete the remaining work programmes and prove up existing and new prospects. EP 475, EP 490 and EP 491 cover areas of 651 sq km, 1,405 sq km and 1,441 sq km respectively, and TP/27 covers 335 sq km. Under the remaining work commitments, an ambitious seven exploration wells are required before the permits expire. EP 475 was awarded in 2011 and is due to expire on 27 May 2021. EP 490 & 491, and TP/27 were awarded in 2014 and are due to expire on 27 May 2023. For the latter permits, Carnarvon Petroleum had been granted several suspensions to provide additional time in the permits to find a farm-in partner. As of May 2018, the wells were contingent upon Carnarvon entering the fourth term of the permits prior to undertaking the drilling programmes. The fourth term commenced on 28 May 2020. Coastal Oil & Gas is aiming to farm-down and drill at least three wells. In shallow water depths, of around 50 m, the primary target depth range is from around 1,000 to 2,000 m, comprising multiple play types, including a Jurassic play and an evolving play in the Permian and Triassic, which was proven following the Phoenix South 1 well. In EP 475, the Kes Prospect is estimated to contain recoverable resources of 50 MMb oil (Pmean) in only 12 m water depth. EP 475 is in the vicinity of significant oil and gas shows and lies on-trend with undeveloped resources in Early Cretaceous sands. No oil or gas columns have been intersected from the three wells drilled within the permit boundaries, although Boyd 1, drilled in 2000 by Apache, recovered oil shows and observed reasonable reservoir characteristics in the Mardie Greensand and very good characteristics in the Mungaroo Formation. Recent leads identified from an extended 3D seismic survey include the Locker submarine canyon and fan traps, both have potential to trap hydrocarbons. Carnarvon has previously stated that recent technical work and the success within the Roebuck Basin significantly de-risked the Lower Triassic and Permian plays within the neighbouring North Carnarvon Basin. The play comprises a stratigraphic trap with good quality turbidite reservoirs, sealed by the proven Locker Shale. Two further prospects have bene identified in EP 490: Westy & Gallant, which have combined estimated recoverable resources of around 300 MMb oil (Pmean). Six prospects have been identified within EP 491 totaling around 280 MMb oil (Pmean). Four have been previously identified as being ready for near-term drilling, including – Honeybadger, a Triassic channel play system, recoverable resources 144 MMbo (Pmean), and Belfon, a Permian play system, recoverable resources 40 MMbo (Pmean). The Rudder and Sparrow prospects offer smaller targets at around 22-36 MMb oil. TP/27 lies just 12 km to the south of the Stag oil field which has produced in the region of 70 MMb oil since 1998 from an early Cretaceous sand. TP/27 is thought to extend this trend along the Enderby Terrace. The permits cover a combined area of around 3,200 sq km, offering potential farm in partners a significant acreage within the North West Shelf. Multiple development options are possible due to the shallow depths of the permits and their proximity to existing infrastructure.  Parties interested in this opportunity are asked to contact: Joseph Graham Phone: +61 (0) 417 592 555

Coastal Oil & Gas Pty Ltd is looking for a farm in partner in four exploration blocks TP/27, EP 475, EP 490 & EP 491, located in the Enderby Terrace and Peedamullah Shelf, North Carnarvon Basin. The company is looking to farm-down around 50% interest in return for assistance in drilling at least three exploration wells over the next three years which could target a Jurassic oil play and evolving play in the Permian and Triassic.

Aker BP has agreed to sell a 10% from its 100% stake in the producing Valhall + Hod fields in the Norwegian NS to Pandion Energy for an undisclosed sum. The deal is subject to usual approvals and is expected to close by end 2017. The fields lie in PL 006B, 033 + 033B, Hod S. of Valhall. It is recalled Aker BP took over full ownership of the fields after Hess’ withdrawal (DEA 24 Oct ’17).

Norway (Lindesness Ridge (Central Graben)) Valhall

Petrobras informs that it has identified the presence of oil in the pioneer well of the Uirapuru block, located in the Santos Basin pre-salt. The well is located about 200 km off the coast of the city of Santos, at a water depth of 1,995 meters, with the discovery of oil in porous reservoirs in the exploratory prospect known informally as Araucária. The well data will be analyzed to better target the exploratory activities in the area and assess the potential of the discovery. The Uirapuru block, acquired in the 4th Production Sharing Round in June 2018, is located in the so-called Pre-salt Polygon, under a production sharing regime, having Pré-sal Petroleo S.A. (PPSA) as manager. Petrobras is the operator of the block and holds a 30% stake, in partnership with ExxonMobil (28%), Equinor (28%) and Petrogal (14%). Original article link Source: Petrobras

Brazil (Southeast Reconcavo Sub-basin (Reconcavo B.)) Uirapuru

In mid-February 2020, industry sources reported that ExxonMobil was granted the Star Offshore Mediterranean concession, offshore Nile Delta. The block is located in deep waters in a distal position of the Nile's sedimentary system, within the Messinian salt extent. The concession includes the new filed wildcat Leil 1 spudded by Shell (with partner ExxonMobil) in 2001. The well which was drilled in 1,759 m of water to an unknown depth was abandoned after some gas shows in the Pliocene Kafr El Sheikh Formation. Background information On 19 December 2019, local media reported that the Egyptian Council of Ministers approved two new petroleum agreements that would allow the Egyptian Natural Gas Holding Company (EGAS) along with several NOCs and IOCs to explore and produce oil and gas in the Star offshore Mediterranean and in the West Sherbeen onshore Nile Delta concessions. As of mid-December 2019, it was understood that the two concessions had not been granted and their location and area of had not been publicly disclosed.

Exxon signed-off the contract for the Star Offshore Mediterranean DW concession. The coverage/outline has yet to be obtained. A similar move is yet to be reported for the West Sherbeen block.

On 9 August 2019, the Federal Agency for Subsoil Use held an auction for four blocks in Samara Oblast (Volga-Ural Province). The combined offers exceeded the starting price by five times.The winners of the auction will obtain 25-year E&P licenses. Details of the offer are as follows: The Gostevskiy block covers 105.5 sq km in the Buzulukskaya Depression and encompasses the Gostevskiy prospect with oil resources estimated at 15 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 9 MMbbl of oil. The starting price amounted to RUB 21.8 million (USD 0.34 million). Lukoil-subsidiary Ritek offered RUB 407.66 million (USD 6.4 million). The Otradnenskiy block covers 96 sq km in the Buzulukskaya Depression and encompasses a prospect with oil resources estimated at 4 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 9 MMbbl of oil. The starting price amounted to RUB 3.4 million (USD 0.05 million). Tatneft-Samara offered RUB 56.1 million (USD 0.9 million). The Vinogradovskiy block covers 15.8 sq km in the Zhigulevsko-Pugachevskiy Dome and encompasses the Vinogradovskiy prospect with oil resources estimated at 1 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil. The starting price amounted to RUB 1.7 million (USD 0.03 million). Region-Neft offered RUB 44.88 million (USD 0.7 million). The Pavlovskiy block covers 114 sq km in the Buzulukskaya Depression and encompasses unlicensed parts of the Bogatyrevskoye, Subbotinskoye, Rechnoye and Polovetskoye fields with combined 3P reserves estimated at 7 MMbbl of oil. Hydrocarbon resources (category D1) of the block are estimated at 11 MMbbl of oil. The starting price amounted to RUB 138.3 million (USD 2.13 million). Rosneft-Samaraneftegaz offered RUB 331.92 million (USD 5.2 million).

Lukoil sub Ritek was awarded Gostevskiy block (106km²) in the Buzulukskaya Depression, Tatneft-Samara Otradnenskiy (96km²) and Pavlovskiy (114km²) blocks, in the same area, Rosneft-Samaraneftegaz Vinogradovskiy (16km²) block on the Zhigulevsko-Pugachevskiy Dome.

South Disouq block, onshore Nile Delta, TMD 2,208m, 33m net gas sands near the base of the target Kafr el Sheikh fm, est. 24 Bcfe recoverable gas + cond resources, testing gauged max. 25 MMcf/d on 54/64" choke, 15 MMcf/d on a 28/64" choke and 10 MMcf/d on a 16/64" choke. Shut-in for 12 hours had pressure increasing to pre-test levels. An optimum prod. rate is expected at 10-12 MMcf/d of mostly dry gas pending results from more testing. Sobhi can be tied-in next year to the Ibn Yunus-1 facility nearby, itself connected to the South Disouq CPF. SDX (op, 100% in this well), partners IPR + EGPC.

Sobhi 12X expl. (SDX op, 100% in this well, IPR + EGPC) in South Disouq block, onshore, TMD=2208m, 33m net of high-quality gas-bearing sands, with an average porosity of 20%, near the base of the Kafr El Sheikh (KES) Fm. Testing gauged max. 25 MMcf/d [54/64" choke], 15 MMcf/d [28/64" choke] and 10 MMcf/d [16/64" choke]. Shut-in for 12 hours had pressure increasing to pre-test levels. An optimum prod. rate is expected at 10-12 MMcf/d of mostly dry gas pending results from more testing.

As of 1 February 2018, ExxonMobil Canada has acquired Husky Oil Operations Ltd 65% working interest and operatorship of offshore exploration license EL 1134 located in the Flemish Pass Basin. The 2,088.99 sq km block was awarded on 15 January 2013 from the NL12-02 Call for Bids held in 2011 for a work commitment bid of CAD 19,875,875. There were no details of the transfer of interest available. There have been no wells drilled in the block under the current contract however a 3D seismic program was acquired over a majority of the contract in 2016. The block originally had a partnership of Husky Oil (operator) 40%, Suncor 35%, and Repsol 25% however Repsol released their interest to Husky which left a working interest breakdown of Husky 65% and Suncor 35%. After the transaction, the block partnership is now ExxonMobil Canada 65% and Suncor 35%. ExxonMobil Canada and Suncor are partners along with Statoil Canada in the contract immediately to the north, EL 1135.

Canada (Central Ridge) (It's a petroleum rights. Please summarize by yourself). In IHS database: EL 1135 op. by EXXONMOBIL (40.0%, SUNCOR 30.0%, STATOIL 30.0%) to be check.EL 1134 op. by HUSKY (65.0%, SUNCOR 35.0%) to be check.

SW part of AE-0006-5M-Amoca-Yaxche-04 block, offshore Sureste Basin, WD 26m, o&g find, susp. at TMD 3,962m (3,610m TVD) mid-Oct '19. Targets L. Pliocene + U. Miocene, Campeche 9024 JU.

Mexico, not found

On 31 January 2020, Total is understood to have taken over as operator of the Orange Sub-basin Block 5/6/7. Total was expected to operate the acreage in accordance with the deal between Occidental and Total announced on 5 May 2019 (See: Anadarko Petroleum Corp to be acquired by Occidental (Total will take Anadarko's African assets). Block 5/6/7: covers some 73,000 sq km primarily atop the Orange Sub-basin in water ranging between 150 m and 4,000 m. Total operates the tract with a 40% stake, Shell holds a 40% stake and PetroSA holds the remaining 20% stake. At the time of writing Petroleum Geo-Services ASA (PGS) was acquiring 3D seismic data atop Block 5/6/7.

Total is understood to have taken over as operator of the Orange Sub-basin Block 5/6/7. Total was expected to operate the acreage in accordance with the deal between Occidental and Total5/6/7

PEMEX plugged and abandoned (P&A) dry the Zaziltun 1EXP directional new-field wildcat (NFW) in the AE-0155-Chalabil entitlement block during early-February 2020. The total unrisked prospective resources for the NFW was estimated at 45 MMboe. It is located in the southwestern area of the block approximately 70 m west of the Kaa 1 NFW, P&A by PEMEX in 2013. The NFW was spudded on 6 November 2019, with a proposed total depth (PTD) of 3,750 m measured depth (MD) and 3,390 m true vertical depth (TVD). The AE Campeche J/U is drilling the well in a water depth of 22 m. The prospect will target the Middle Miocene in a combination trap. On 24 October 2019, PEMEX was granted approval by the CNH to drill the Zaziltun 1EXP. The 599.95 sq km AE-0018-2M-Okom-01 entitlement block was granted by SENER to Pemex 100% through Ronda 0 on 27 August 2014. The entitlement expired on 27 August 2019 and replaced by the 831.50 sq km AE-0155-Chalabil entitlement block on 28 August 2019.

Zaziltun 1EXP nfw, SW part of AE-0155-Chalabil block, offshore, WD=22m, P&A dry, PTMD was 3,750m (3,390m TVD), target M. Miocene.

GeoPark signed on 10 March for a 50% farmin from PArex in the latter's 361-sq km LLA 94 in the Llanos Basin. The move is subject to ANH approval. GeoPark acquire and reprocess 3D seismic and drill 3 explo wells for USD 10.15 MM over 3 years.

Colombia, LLA 94

SW part of XX Kultak-Kamashi block, Amu-Darya Basin, flowed 17.25 MMcfg/d after fracking a 350m horiz section, presumably in Callovian-Oxfordian carbs. The discovery was made in 2010 by then-optr Zeromax, 3.4 MMcf/d on 8mm choke.

Hujum -3 appr SW part of XX Kultak-Kamashi block, Amu-Darya Basin, flowed 17.25 MMcfg/d after fracking a 350m horiz section, presumably in Callovian-Oxfordian carbs. The discovery was made in 2010 by then-optr Zeromax, 3.4 MMcf/d on 8mm choke.

On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the F20-C3,C4 offshore exploration licence in the Marmara Sea in Thrace Basin on 28 May 2019. The company had submitted the application on 26 July 2018. The licence covers around 108 sq km area and it has been granted for eight-year term with an expiry date of 27 May 2027. TPAO is 100% owner and operator of the licence.

TPAO has been awarded the F20-C3,C4 offshore exploration licence in the Marmara Sea in Thrace Basin

On 30 January 2019, the Federal Agency for Subsoil Use held an auction for three blocks in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). The winning bids were offered by Gazprom Neft/Shell’s joint venture Salym Petroleum Development (SPD), Rosneft and Lukoil-subsidiary Ritek. The winners of the auction will obtain 25-year E&P licenses. The Shapshinskiy Vostochnyy-1 block covers 197 sq km in the Ural-Frolov Province. Seismic coverage amounts to 156 km. No exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 71 MMbbl of oil. The starting price amounted to RUB 14.522 million (USD 0.22 million). SPD offered RUB 1,134.168 million (USD 17.2 million). The Shapshinskiy Vostochnyy-2 block covers 261 sq km in the Ural-Frolov Province. Seismic coverage amounts to 193 km. No exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 93 MMbbl of oil. The starting price amounted to RUB 18.887 million (USD 0.28 million). Rosneft offered RUB 200.096 million (USD 3 million). The Verkhnenazymskiy block covers 102 sq km in the Ural-Frolov Province and encompasses a part of the Verkhnenazymskoye discovery with proportional 3P reserves estimated at 8.5 MMbbl of oil. Seismic coverage amounts to 97 km. Two exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 17 MMbbl of oil. The starting price amounted to RUB 129.922 million (USD 1.94 million). Ritek offered RUB 142.914 million (USD 2.17 million).

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

In late February 2020, Khalda Petroleum Co (Khalda) successfully tested the outpost well Barakat Deep 2 at the Barakat Deep 1 discovery, Khalda Offset (New) A-West block, Northern Egypt Basin. The well flowed oil and gas presumably from the Lower Cretaceous Alam El Bueb Member of the Burg El Arab Formation. It was spudded on 29 November 2019 with the EDC-54 Land rig and drilled to a TD of 4,420 m in the D Unit of the Middle Cambrian-Middle Ordovician Shifah Formation. The Barakat Deep 1 discovery was made in late October 2019 by Khalda after the new field wildcat Barakat Deep 1 tested oil in the Burg El Arab Formation. The Khalda Offset (New) A-West block is a 3,271-sq-km acreage awarded to Khalda in January 1998. It includes the Nakhaw NW 1 oil field discovered in 2002. Khalda is a JV between EGPC (50%), Apache (33.5%) and Sinopec (16.5%).

Barakat Deep 2 appr. (Khalda 100% = JV between EGPC 50%, Apache 33.5%, Sinopec 16.5%) in Khalda Offset (New) A-West block, successfully tested the Alam El Bueb. TD=4420m (Shifah fm).

CCyB-17/B block, Cuyo Basin, Mendoza, drilled Apr-Aug ’18, susp w.o. test at TD 3,680m. Target Potrerillos fm.

CCyB-17/B block, Cuyo Basin, Mendoza, drilled Apr-Aug ’18, susp w.o. test at TD 3,680m. Target Potrerillos fm.

Santos Ltd was awarded production licence PL 1046, located in the Cooper-Eromanga Basin, on 8 May 2019.  The licence has been awarded for a 30 year period, and will expire on 12 May 2049. The licence is over the Hector and Hector South gas discoveries, which were made in 2004 and 2017 respectively.    PL 1046, which covers an area of 51 sq km, was awarded on 8 May 2019. Participants in the licence are Santos Ltd (70% + Operator), with 25% held through subsidiary Santos Petroleum Pty Ltd and 7.5% held through Vamgas Pty Ltd, and Beach Energy Ltd subsidiary Delhi Petroleum Pty Ltd (30%).

Santos (70% + Op. Beach 30%) was awarded production licence PL 1019, 1020, 1046.

Salta has issued a call for tenders on 12 blocks totalling 53,000 sq km in the province: Algarrobal, Guayacán, Ipaguazú, Las Cañitas, Ojo de Agua, Pichanal, Pocoy, San Carlos, San Ignacio, San Telmo, Santa Rosa, and Yariguarenda in the Noroeste and Tarija basins, as well as Argentinean sector of the Chaco-Parana Basin. Awards could be expected Sep-Oct ‘18. These 12 blocks were part of a 15-unit inventory earlier outlined (DEA 23 Mar ’18). The 3 blocks that weren’t included are Cuchuma + Lumbrera in the Noroeste Basin, and Tolar Grande in the under-explored Puna Basin. These will likely be offered in the near future.

Salta has issued a call for tenders on 12 blocks totalling 53,000 sq km in the province: Algarrobal, Guayacán, Ipaguazú, Las Cañitas, Ojo de Agua, Pichanal, Pocoy, San Carlos, San Ignacio, San Telmo, Santa Rosa, and Yariguarenda in the Noroeste and Tarija basins, as well as Argentinean sector of the Chaco-Parana Basin. Awards could be expected Sep-Oct ‘18. These 12 blocks were part of a 15-unit inventory earlier outlined (DEA 23 Mar ’18). The 3 blocks that weren’t included are Cuchuma + Lumbrera in the Noroeste Basin, and Tolar Grande in the under-explored Puna Basin. These will likely be offered in the near future.

Further to DEA 13 Sep ’18, the Río Negro authorities have now awarded 6 Neuquén Basin blocks offered through Concurso Público Nacional & Internacional 01/2018: - Aconcagua Energía bid for and secured the Catriel Oeste lease, 45 sq km, Catriel Viejo (287 sq km), Loma Guadalosa (102 sq km) and Tres Nidos (89 sq km), combined proposed investment USD 23 MM + USD 180,000 bonus each for the 1st  2 blocks + USD 100,000 for Tres Nidos. - President Energy bid and secured Puesto Prado lease (43 sq km) and Las Bases (154 sq km), proposed investment USD 29 MM. State company Edhipsa will be holding a 10% stake in each.

Río Negro authorities have now awarded 6 blocks offered through Concurso Público Nacional & Internacional 01/2018: Aconcagua Energía secured the Catriel Oeste lease, 45 sq km, Catriel Viejo (287 sq km), Loma Guadalosa (102 sq km) and Tres Nidos (89 sq km), President Energy secured Puesto Prado lease (43 sq km) and Las Bases (154 sq km). State company Edhipsa will be holding a 10% stake in each.

In early 2018, Canadian company, Touchstone Oil & Gas (Touchstone), and GOC were reported to have signed an agreement to allow Touchstone to take control of GOC's Remboue permit. The deal value was estimated at USD 23 million with a plan to produce 1,000 bo/d in January 2019. An initial deal was signed in March 2017, but the identity of the operator was kept secret. The deal was put on hold because of an audit launched by Direction Generale des Hydrocarbures (DGH) about the sale price and the investments made by GOC during its operatorship of the field, which were estimated at USD 40 million. Touchstone will operate the permit with 80% interest and Gabon Government will hold the remaining 20%. Background information By end July 1998, Chauvco "temporary' shut down all production from Remboue field in the Remboue permit blaming transportation difficulties and low oil price. In April 1999, the company announced that it was disposing of its Gabon assets. In October 2001, the new operator Pan-Ocean, announced that production resumed from Remboue field. In September 2006, Addax took over the operatorship and undertook re-development studies. The company relinquished the Remboue permit in February 2011. In December 2012, Gabon Oil Company took over the operatorship of the Remboue permit. The field had been developed by Schlumberger for GOC before stopping the field activities in October 2015.

Touchstone Oil & Gas (80%,op.), and GOC (20%) have signed an agreement to allow Touchstone to take control of Remboue permit.

In October 2017, O&G Development Kft (OGD), subsidiary of privately-held company Sand Hill Petroleum B.V., was testing gas in wildcat Mezotur Del 2 in the Mezotur V development/production contract (mining plot) in central-eastern Hungary. The well reached the final depth of approximately 2,600 m. Tests likely yielded commercial quantities of gas (rates undisclosed) and the well was completed as a producer. OGD is the sole rightholder of the tract. Mezotur Del 2 was started on 16 July 2017 and likely reached its final depth by the end of the month. The well, drilled on a prospect defined from the Mezotur 3D seismic programme, is located some 20 km south-east of the city of Szolnok in the southeastern part of the Körös permit. In a geological sense, it falls within the Nagykunsag Sub-basin, tectonic unit of the Pannonian Basin. The well was targeting multiple zones within the Lower Pannonian and Miocene clastic successions.

Hungary (Pannonian B.) Mezotur Del 2 op. by OGD (100.0%) in Mezotur V block

In late April 2019, Rosneft transferred two long-term licenses in Yakutia (Sakha) Republic (Eastern Siberia) to its joint venture with BP. Yermak Neftegaz (Rosneft 51% and BP with 49%) will operate the Sredne-Lenskiy and Olekminskiy blocks via its subsidiary Srednelenskoye. It marks the expansion of Yermak’s E&P activities outside its current presence in the Yenisey-Khatanga Basin and the Nadym-Taz Province (Western Siberia). Rosneft won the licenses at an auction on 1 December 2015. The Olekminskiy block covers 6,121 sq km in the Predpatom Basin. Seismic coverage amounts to 145 km. No wells have been drilled in the area. Hydrocarbon resources (category D2) of the block are estimated at 90 MMbbl of oil and 1,360 Bcf of gas. Exploration of the block must be completed within seven years. The starting price amounted to RUB 12 million (USD 0.18 million). Rosneft offered RUB 700.8 million (USD 10.8 million). The Sredne-Lenskiy block covers 9,834 sq km in the Predpatom Basin. Seismic coverage amounts to 722 km. Three wells have been drilled in the area. Hydrocarbon resources (categories D1+D2) of the block are estimated at 42 MMbbl of oil and 483 Bcf of gas. Exploration of the block must be completed within seven years. The starting price amounted to RUB 5.4 million (USD 0.08 million). Rosneft offered RUB 302.94 million (USD 4.7 million). On 9 January 2019, Interfax reported that Yermak Neftegaz registered its first subsidiary in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). The Rosneft/BP joint venture became the sole owner of Zapadno-Nikolskoye at the end of December 2018, according to Interfax. Since 2015, Zapadno-Nikolskoye has not been owning any licenses in Russia but still existing as a legal entity. In late January 2019, Zapadno-Nikolskoye was re-named to Srednelenskoye. Rosneft inherited Zapadno-Nikolskoye as the result of the TNK-BP acquisition in 2013.

Rosneft transferred 2 licences in Yakutia (Sakha) Republic, to its existing 51:49 JV with BP YermakNeftegaz, so far only present in W. Siberia. Involved are the Sredne-Lenskiy (9834km²) + Olekminskiy (6121km² undrilled) block, both in the Predpatom B.

8/2015/p Siennow-Rokietnica block, Outer Carpathian Foredeep SW of Jaroslaw in SE Poland, P&A gas shows late Nov '19. PTMD was ab. 2,000m, target Miocene + basement.

Poland (Outer Carpathian Foredeep (North Carpathian B.)) Jaroslaw

On 29 August 2019 ConocoPhillips spudded exploration well 25/7-7 in PL 782 S targeting the Busta gas condensate prospect. The “Leiv Eiriksson” S/S was used for the well which lies between Balder and Frosk. The licence is stratigraphically split, applying below the Base Cretaceous. TD was reached at 4,730 m in the Middle Jurassic Heather Formation and the well has made a new oil and gas discovery. Two separate gas condensate and oil-bearing zones were encountered in the Upper Jurassic Draupne Formation totalling 25 m. The secondary Heather Formation objective was thin, silty and water-wet. Estimated recoverable reserves are 6 - 63 MMboe (much lower than the pre-spud range given by partner Aker BP of 54-199 MMboe). On 9 November 2019 the well was abandoned. Aker BP has had recent success in the area with its 2018 Frosk discovery and the 2019 Froskelar discovery. At Frosk (24/9-12 S) a 10 m oil column was proven in a 40 m thick Eocene Hordaland Group sandstone injectite and a sidetrack confirmed a 30 m oil column in the Hordaland injectites. Estimated recoverable reserves are 30-60 MMboe. The Froskelar Main well (24/9-14 S) found a 38 m oil column plus a 30 m gas column, also in Hordaland injectites, and a horizontal sidetrack of this well confirmed 540 m of oil and gas-bearing injectite zones. Estimated recoverable reserves are 60-130 MMboe. Interest in PL 782 S is split between ConocoPhillips Skandinavia AS (40% + operator), Aker BP ASA (20%), Wintershall Dea through DEA Norge AS (20%) and Equinor Energy AS (20%).

025/07-07 (Busta) expl. (COP op, Aker BP, Wintershall Dea, Equinor) 1st well in PL 782 S, NW of Balder, small discovery, encountered 2 separate gas/cond + oil-bearing intvs totalling 25m in the Draupne fm, no hc/water contact, 6-60 Mmboe recoverable, WD=125m, TD=4705m (Heather fm).

Following unsuccessful tests on the Yamin 1 well during Q4 2019, CC Energy Development SAL (Oman) (CCED) has suspended the near-field exploration well to enable further work in the future if warranted. Located on Block 4 (Ghunaim) in eastern Oman, Yamin 1 exhibited oil shows while drilling, but no oil flowed to surface upon test. The well lies east of the Saiwan East and Erfan fields and was the third of the company's 2019 three-well exploration drilling programme on its Block 3 (Afar) and Block 4 (Ghunaim) acreage. It followed the Yusr 1 and Maather 1 wells.<P />Yamin 1 was spudded in early November 2019 and was designed to test the eastward potential of the Ediacaran Khufai Formation. Operations were concluded in mid-November after the well reached a TD of around 1,560m. CCED operates Blocks 3 and 4 with a 50% interest and is partnered by Tethys Oil Block 3 & 4 Ltd (30%) and Mitsui E&P Middle East BV (20%).

Yamin 1 Following unsuccessful tests has suspended CCED operates Blocks 3 and 4 with a 50% interest and is partnered by Tethys Oil Block 3 & 4 Ltd (30%) and Mitsui E&P Middle East BV (20%).

Aker BP has acquired a 10% stake in PL 1056, 4,549 sq km in the More Basin (blocks 6302/1 + 12, Tulipan discovery), in exchange for Shell getting 20% in PL 1005, 1,775 sq km over blocks 6404/9 + 12, 6405/4, 7 + 10 (Ellida discovery) in the deepwater Voring Basin. The deal is effective 30 Jun '20. PL 1005 partners now Aker BP (op), VÃ¥r + Shell and PL 1056 Shell (op), Petoro, DNO, Wintershall Dea + Aker BP.

Norway (More B.), PL 1056, Aker BP has acquired a 10% stake in PL 1056, 4,549 sq km in the More Basin (blocks 6302/1 + 12, Tulipan discovery), in exchange for Shell getting 20% in PL 1005, 1,775 sq km over blocks 6404/9 + 12, 6405/4, 7 + 10 (Ellida discovery) in the deepwater Voring Basin. The deal is effective 30 Jun '20. PL 1005 partners now Aker BP (op), VÃ¥r + Shell and PL 1056 Shell (op), Petoro, DNO, Wintershall Dea + Aker BP.

On 4 December 2017, Australian company African Petroleum Corp Ltd and the Petroleum Directorate of Sierra Leone ratified the company’s entry into the second extension period for offshore undrilled blocks SL-03 and SL-4A-10, as well as a modification of the work programmes for both licenses. Consequently, SL-03 will now expire on 23 April 2019, while SL-4A-10 will expire on 17 September 2019. These extensions are subject to African Petroleum’s decision to commit (prior to 1 November 2018) to drilling one exploration well per license within the permits’ new validity. In addition, African Petroleum has accepted to reduce both exploration blocks half-size while entering the second extension period. SL-03 will now cover an area of 962 sq km, while SL-4A-10 will be 995 sq km large. During 2018, the Australian company will therefore work on de-risking both licenses to be able to take the drilling decision by November 2018. This work will also help attracting partners, since African Petroleum is still understood to look for a farminee in its licenses. The company will be working with ERC Equipoise to re-assess the prospective oil resources of the permits, including two new prospects called Leo and Vega. The previous reserves update was made in April 2015, when Equipoise estimated the blocks to host net unrisked and risked mean prospective oil resources of 1,354 MMbbl and 223 MMbbl, respectively. Primary targets are reportedly Albian and Turonian fan systems with additional upside in the overlying Campanian section. The company was awarded SL-03 in April 2010, while licence SL-4A-10 was part of Sierra Leone’s third offshore licensing round in 2012. On 2 December 2015, African Petroleum entered into the First extension period on SL-03 permit and consequently reduced its area by 50%.

Sierra Leone, SL-03

Total has acquired Marathon Oil Libya which holds a 16.33% stake in the Waha Concessions in Libya. This acquisition will give Total access to reserves and resources in excess of 500 million barrels of oil equivalent, with immediate production of around 50.000 barrels of oil equivalent per day (boe/d) and a significant exploration potential across the area of 53.000 sq kms covered by the Concessions in the prolific Sirte Basin. The consideration payment for the transaction is US$450 million.   'This acquisition is in line with Total’s strategy to reinforce its portfolio with high quality and low-technical cost assets whilst bolstering our historic strength in the Middle East and North Africa region,' said Patrick Pouyanné, Chairman and CEO of Total. 'It builds on the Group’s long-term presence in Libya, a country with very large oil and gas resources, and demonstrates our commitment to continue supporting the recovering oil and gas industry of the country.'   The Waha Concessions currently produce around 300.000 boe/d. Thanks to the ongoing restart of the existing installations and the resumption of development drilling, the output is expected to ramp up and exceed 400.000 boe/d by the end of the decade.   The NOC (59.18%), Total (16.33%), ConocoPhillips (16.33%) and Hess (8.16%) jointly own the Waha Concessions. The Waha Oil Company, a 100% NOC owned entity, operates the asset. Click here for Marathon Oil's announcement: Marathon Oil Announces Libya Divestiture for $450 Million Original article link Source: Total

Marathon Oil has struck a deal which will see it sell its stake 16,33% in the Waha concession in Libya to Total for US$450 MM. (National Oil Corporation 59,18%, ConocoPhillips 16,33%) and Hess 8,16%).

Pursuant to a HoA on 3 Oct ’18, UJO has now signed the farmin agreement with Rathlin Energy for a 16.665% interest in PEDL 183, 703 sq km on the N. coast of the Humber Estuary in E. Yorkshire and home to West Newton A-1 gas find. An appraisal is planned 1Q ’19.  Following OGA approval, partners will be Rathlin (op), Humber O&G + UJO.

United Kingdom, PEDL 183

Partner Equinor withdrew from P2345 effective 18 May '20, its 50% going to Ithaca, now sole holder. The 856-sq km permit covers blocks – 14/23, 14/24, 14/28 + 14/29b.

Partner Equinor withdrew from P2345 effective 18 May '20, its 50% going to Ithaca, now sole holder. The 856-sq km permit covers blocks – 14/23, 14/24, 14/28 + 14/29b.

On 1 September 2018 Tailwind Energy completed the acquisition of Shell’s and ExxonMobil’s interest in the Triton Cluster in the Central North Sea. Under the deal Tailwind has acquired 29.26% in licence P361, 64.63% in the unitised Bittern licence, 100% interest in licences P1792 and P233 blocks (029/01a Bittern Area), P013 (021/25a Guillemot W / NW (Upper), 021/30a Guillemot W / NW (Upper), Gannet E and 50% interest in P215. The Triton Cluster comprises of Guillemot NW, Guillemot W, Bittern and Gannet E. Bittern was developed jointly with Guillemot West and Guillemot Northwest as part of the Triton project. The Triton project was initially a subject of controversy as the respective operators of the two blocks it straddled failed to agree on a development scheme. A joint development scheme for the field was finally agreed on 5 November 1997. The solution involved the development of Bittern jointly with Guillemot West and Guillemot Northwest as a subsea development tied back to a new-built FPSO vessel, moored mid-way between the fields. Bittern came on stream on 15 April 2000 and production commenced from the Guillemot Northwest and Guillemot West fields on 20 April 2000. Gannet E is in the process of being redeveloped via a tie-back to three existing wells to the Gannet Alpha platform and then on to the Titron FPSO. Gannet E was shut in, in 2011, but is expected back onstream later in 2018. Following the completion of this deal interest in P361 is held by Dana Petroleum (E&P) Ltd (65.90% + operator), Tailwind Energy Ltd (29.26%) and Endeavour North Sea Ltd (4.84%). In the Bittern unitised licence the interest is held by Dana Petroleum (E&P) Ltd (32.95% + operator), Tailwind Energy Ltd (64.63%) and Endeavour North Sea Ltd (2.42%). In Licences P1792 + P233 (029/01a Bittern Area), P013 (021/25a Guillemot W / NW (Upper) + 021/30a Guillemot W / NW (Upper) + Gannet E, Tailwind holds 100% interest. Lastly in P215 interest in the licence is now held by Dana Petroleum (E&P) Ltd (50% + operator), Tailwind Energy Ltd (50%).

Tailwind Energy has agreed to acquire the entire UK business of EOG Resources, which include 100% in the Conwy field and 110/12a-1 Corfe discovery in the East Irish Sea, a 25% interest in the Columbus gas development and also interest in number of Southern North Sea licences.

On 31 January 2019, the CNH approved the 30% working interest farm-out by operator CNOOC to PC Carigali in the CNH-R01-L04-A4.CPP/2016 contract, Area 4 block.  CNOOC remains the operator with 70% working interest and PC Carigali has 30% working interest.  CNOOC is planning the drilling of at least one commitment well in the block during 2019. On 24 April 2018, the CNH approved the exploration plan submitted by operator CNOOC for the CNH-R01-L04-A4.CPP/2016, Area 4 block that includes the drilling of one commitment well and conducting geological and geophysical (G&G) studies during the four year exploration phase.  The approved exploration plan includes the drilling of sub-salt new-field wildcat (NFW) Xakpun 1EXP provisionally scheduled for 1st quarter 2019.  The proposed total depth (PTD) is 5,500 m with the Wilcox formation being the primary target at approximately 5,000 m.   The prospect underlies a 2,000 m salt canopy in this area of the basin.  The prospective resources for the well have been estimated to be 323 MMboe with an estimated risked reserves to be incorporated of 135 MMboe.  The prospect water depth is 1,528 m which puts its location somewhere in the east central to southeastern area of the block.  Total well cost was estimated to be USD 160 million.  Total investment in the exploration plan was reported by the CNH to be approximately USD 172 million for 79,511 total work units, the well is 74,300 work units. On 10 March 2017, the CNH signed the official award for an exploration and production license contract with China Offshore Oil Corporation (CNOOC) 100% for the CNH-R01-L04-A4.CPP/2016, Area 4 block the company won through the CNH-R01-L04/2015 Bid Round. The official contract name is CNH-R01-L04-A4.CPP/2016. On 5 December 2016 China Offshore Oil Corporation (CNOOC) was granted a preliminary award as the high bidder for Area 4 - Perdido block through the CNH-R01-L04/2015 Bid Round.  The ratification of the preliminary award was approved by the CNH on 7 December 2016.  The company offered a total of 15.01% additional royalties and 1.00 as the additional work investment factor which is equivalent to one commitment well and a total minimum investment commitment of USD 33.61 million which also includes the minimum investment commitment of USD 3.61 million.  There were no additional bids for the block. The Area 4 - Perdido block covers an area of 1,876.70 sq km in the Deep-Water Gulf of Mexico, Perdido area and the minimum work commitments were set in the bid documents of 3,611 work units.

Mexico (Rio Grande Embayment (Gulf Coast B.)) China

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%).

Lundin Petroleum has agreed to acquire 30% interest in the Rolvsnes discovery licences PL338 C and pre-awarded PL338 E, and 20% interest in the Goddo prospect PL815 from Lime Petroleum for a cash consideration of US$ 43 million and a contingent payment of a further US$ 2 million. The transaction was announced on 28 January 2019 and will have an effective date of 1 January 2019, subject to regulatory approvals. Rolvsnes was discovered by 16/1-12 (2009, Lundin, 2,055m), which encountered a 42m oil column in porous/weathered pre-Devonian basement. Rolvsnes gross resource range is 14 -78 million after the successful drilling and production testing of appraisal well 16/1-28 S in 2017 which TD'd at 4,880m MD (1,918m TVD). Rolvesnes licence PL338 C covers 122 sq km in block 16/1 and was granted on 16 December 2014 for five years initial exploration period. It was carved out of PL338 which covers the Edvard Grieg Field adjacent to the N. The PL338 C partners have already drilled the dry Gemini well 16/1-24 (2015, Lundin, 2,299m) and successful Edward Greig South appraisal well 16/1-25 (2015, Lundin, 2,210m). PL338 C equity partners are Lundin Norway AS (50% + Op), Lime Petroleum Norway AS (30%), and OMV (Norge) AS (20%). PL338 E (block 16/4, 30 sq km) adjacent to the S of PL338 C has been pre-awarded in APA2018 with the same partnership as PL338 C. PL815 partners plan to drill NFW 16/5-8 S in Q1 2019 targeting the Goddo prospect, which has a similar reservoir to the Rolvesnes discovery. PL815 covers 111 sq km over block 16/5 and was awarded in APA 2015 on 5 February 2016. PL815 equity partners are Lundin (40% + OP), Lime (20%), Concedo ASA (20%) and Petoro AS (20%).

Norway, PL 815

Baraka Energy and Resources Ltd has reported that it is seeking a farm-in partner for exploration permit EP 127, located in the Georgina Basin. The permit is located in the Northern Territory, where discussion around the future of fracking was ongoing throughout 2017.  The ban on fracking was lifted in 2018 and Baraka reported in August that this has allowed it to continue seeking a farm-in partner within the permit.  While the moratorium on fracking activity was in place, Baraka commented that the lifting of this would a positive towards is future work on the permit. During the latter part of 2017 Baraka reported that it was continuing to plan a Resource Imaging Technology Survey, using Seismo-Electric technology. Baraka would like to acquire a trial survey close to existing wells in the permit, as it is a new technology in its infancy in Australia. In March 2016 it was reported that an offer of intent from the Northern Territory Department of Mines and Energy to renew the permit had been accepted.  This was approved on 6 April 2016, with the permit renewed for a further five years as of December 2015. In March 2015 Baraka announced that its joint venture partners in the permit, PetroFrontier and Statoil, would be withdrawing from the asset.  This will give Baraka a 100% interest position, and operatorship. Baraka reported on 18 March 2016 that the transfer of interest was underway. A recent unconventional exploration programme, undertaken over four permit areas, including EP 127, by Statoil as part of a farm-in, saw three wells drilled within the permit in 2014.  The wells were targeting shale liquids potential, alongside the other wells in the programme, though results were disappointing. This led to Statoil’s withdrawal from further work in the programme to farm-in and withdrawal from the permits. EP 128 was originally included in Baraka’s farm-in opportunity.  Initially, in 2015, Baraka had lodged for a renewal for EP 128, which was due to expire on 13 June 2015. However, the terms for renewal did not meet Baraka’s requirements and so the permit was subsequently relinquished in January 2015. EP 127 was due to expire on 13 December 2015, however Baraka applied for a renewal in early 2016.  This was granted and the permit is now valid until December 2020.  The permit covers an area of 14,280 sq km and was awarded on 19 December 2007. Baraka holds 100% interest and operatorship. Baraka reported in early 2016 that it had been approached by a Canadian company interested in pursuing the conventional potential within several Georgina Basin permits and reported that it would continue discussion during the renewal process, whilst looking for additional farm-in partners. However, in October 2016 Baraka reported that discussions with the Canadian company had ceased and it now would continue to market the opportunity to other interested companies.

Baraka Energy and Resources Ltd has reported that it is seeking a farm-in partner for exploration permit EP 127, located in the Georgina Basin. The permit is located in the Northern Territory, where discussion around the future of fracking was ongoing throughout 2017.

AWE Petroleum Pty Ltd commenced testing of the Waitsia 2 gas appraisal well on 7 November 2017.  Initially clean-up operations were completed, with subsequent gas flows of 38.7 MMcfg/d observed instantaneously.  On 10 November 2017 AWE reported that average gas flows of 38.5 MMcfg/d, with a peak flow of 38.7 MMcfg/d, had been observed through an 80/64” choke at a well head pressure of 1,315 psi.  The initial flow test was completed over a 2.1 hour period and the well has now been shut-in for pressure testing. Flow testing at Waitsia 2 is being undertaken over the Kingia Sandstone between 3,173 and 3,215 m.  It is designed to evaluate the gas deliverability from the southern section of the Waitsia field.  Gas samples will also be collected during testing for further analysis. Waitsia 2 is the second well to be tested in the programme, with Waitsia 3 tested first and delivering excellent results.  Testing of the Waitsia 4 appraisal well will follow, with the full testing programme expected to be complete by the end of November 2017. The Waitsia field was discovered in September 2014 by the Senecio 3 appraisal well, which was appraising an unconventional field. The Waitsia 1 to 4 appraisal wells were subsequently drilled.  The first phase of production from the field commenced in August 2016.  The testing phase ongoing forms part of the appraisal process in preparation for the second phase of production, which is planned to increase production ten-fold and commence in around 2020.

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

1st well within the Bazhenov Polygon (project), Khanty-Mansiysk AO, W. Siberia, TD 3,200m (basement) reached Oct ’18, testing started Feb ’19, Paleozoic perforated over 3,152-3,177m, testing planned of the Tyumen Yu2 + Bazhenov Yu0 fm’s.

Bazhenovskaya-1 1st well within the Bazhenov Polygon (project), Khanty-Mansiysk AO, W. Siberia, TD 3,200m (basement) reached Oct ’18, testing started Feb ’19, Paleozoic perforated over 3,152-3,177m, testing planned of the Tyumen Yu2 + Bazhenov Yu0 fm’s.

PPL has assigned a 2.5% interest in its Hisal 3372-23 EL,  1,056 sq km onshore Potwar Basin, Punjab, to Government Holding Pvt Ltd (GHPL) retro-effective 20 Jul ‘18. Partnership now PPL (op), partners POL, Attock Oil Co + GHPL.

Pakistan Petroleum Ltd (PPL) has assigned 2.5% working interest in Hisal 3372-23 EL (Potwar Basin) onshore licence to Government Holding Pvt Ltd (GHPL)