GENERAL INTEREST Quick Takes
Lukoil to acquire Cairn’s 40% stake in project offshore Senegal
PJSC Lukoil has agreed to acquire Cairn Energy PLC’s 40% interest in the Rufisque, Sangomar, and Sangomar Deep (RSSD) project offshore Senegal for $300 million in cash.
The agreement also provides for potential bonus payment to Cairn of up to $100 million after production begins.
The blocks, covering 2,212 sq km, lie on the deepwater shelf of the Republic of Senegal 80 km from shore with the sea depth of 800-2,175 m and include Sangomar and FAN fields.
Final investment decision on Sangomar field was taken early this year and field development has begun (OGJ Online, Jan. 10, 2020). Lukoil estimates field recoverable hydrocarbon reserves of 500 million boe. First oil is expected in 2023 with a designed production level of 5 million tons/year of crude oil.
The RSSD project is being implemented under a production sharing agreement with Woodside as operator with 35%. Other partners are FAR (15%) and Petrosen (10%).
Subject to JV partner and government of Senegal consents, as well as customary conditions, the deal is expected to close in this year’s fourth quarter with an effective date of Jan. 1.
Woodside Burrup gas hub concept moves forward
Woodside Petroleum Ltd. is gradually moving forward with its Burrup gas hub concept in Western Australia.
The company revealed in its second quarter 2020 report that it has applied for production licenses to cover the Calliance and Torosa gas and condensate fields in Browse basin off the northwest coast of Western Australia.
The fields, originally discovered in the early 1970s, have been held under retention leases for more than 15 years.
At the same time, the company applied for a renewal of the retention lease over nearby Brecknock gas field.
Woodside said its responses to agency and public comments on the draft environmental impact statement for the Browse development project are now being finalized for submission to the state and federal authorities.
A final investment decision on the Browse is targeted for 2023. The development plan is to pipe gas south from the fields to the Woodside-operated LNG-domestic gas plants on the Burrup Peninsula near Karrartha as part of the proposed $40-billion (Aus.) Burrup gas hub.
Other components include construction of a second LNG train at the Pluto LNG plant, development of Scarborough gas fields, and a pipeline interconnector between the Pluto plant and the North West Shelf gas plant (OGJ Online, Nov. 11, 2019).
Woodside has applied to convert the current retention licenses WA-1-R and WA-62-R over Scarborough field into production licenses. It also has applied for retention lease renewals for WA-61-R (Jupiter field) and WA-63-R (Thebe field), both of which are earmarked for future development through the proposed Scarborough infrastructure.
A final investment decision for Scarborough development is now scheduled for second-half 2021.
OKEA acquires Aurora discovery interest from Equinor
Norwegian oil company Okea ASA has acquired Equinor Energy AS’s 40% operated working interest in PL195 and PL195 B in the North Sea, which includes the small Aurora gas discovery west of Gjøa oil and gas field.
Okea aims to become operator of the licenses and pursue development of Aurora as a tie-in to Neptune Energy-operated Gjøa (in which Okea holds 12% interest) without further appraisal drilling, which along with the transaction, is subject to approval by the Ministry of Petroleum and Energy. Okea estimates recoverable volumes of 12-28 MMboe. The effective date of the transaction is Jan. 1, 2020.
Partners in the license are Wintershall DEA (25%) and Petoro (35%).
Exploration & Development Quick Takes
NIOC awards Yaran joint field development to POGIDC
The National Iranian Oil Co. (NIOC) plans to add 39.5 million bbl cumulative over 10 years in Yaran joint oilfield by signing a development contract with Persia Oil and Gas Industry Development Co. (POGIDC).
Development of the field, which lies 130 km southwest of Ahvaz and west of South Azadegan field and is shared with Majnoon field in Iraq, has been pursued in south and north sections.
South Yaran was previously developed by Petroleum Engineering and Development Co. (PEDEC), and North Yaran was developed by POGIDC. The two contracts have been merged under POGIDC.
The project includes drilling of six new wells (three in North Yaran and three in South Yaran), drilling a descriptive well, drilling a well for water injection, workover operations in five wells, equipping 27 production wells in Sarvak Layer with ESP pump, constructing and upgrading ground facilities, conducting laboratory studies, and designing the enhanced oil recovery method.
Direct capital expenditures will be $227 million and operating costs will be about $236 million. All financial resources will be provided by POGIDC.
Senex increases Surat basin gas reserves by 21%
Senex Energy Ltd., Brisbane, released an independent assessment of its gas reserves and contingent resources that increases the company’s Surat basin 2P gas reserves by 21% to 739 petajoules.
Senex says the increase has been driven by a successful appraisal and development drilling campaign at its Atlas Project along with continued over-performance at its Roma North project.
The Atlas project saw a 62% (90 petajoules) increase in 2P reserves to 234 petajoules while Roma North production drove a 10% (25 petajuoles) increase in 2P reserves to 238 petajoules.
Senex said its Surat 1P reserves had risen by 109 petajoules to 210 petajoules; the 2P reserves up by 127 petajoules to 739 petajoules; and the 3P reserves up by 105 petajoules to 995 petajoules.
The company said that it achieved a 100% reserves replacement ratio in its Cooper basin fields during the 2020 financial year, making the 2P reserves figure there steady at 7.3 MMboe.
Gazprom, Shell to study Gydan Peninsula cluster development
Gazprom Neft and Shell established a joint venture to study and develop a large, promising cluster in the northeastern portion of the Leskinsky and Pukhutsyayakhsky license blocks on the Gydan Peninsula.
Upon completion, expected this year following receipt of corporate and regulatory approvals, the partners will each hold 50% interest in the capital of the joint venture, which will be managed by Gazprom Neft and Shell on a parity basis.
The 3,000-sq km Leskinsky license block lies in the Taymyr district of the Krasnoyarsk Krai. Hydrocarbon resources may exceed 100 million tonnes of oil equivalent, Gazprom said. The adjoining 800-sq km Pukhutsyayakhsky block lies in the Tazovsky district of the Yamal-Nenets Autonomous Okrug. Its resources are estimated at 35 million tonnes of oil equivalent, Gazprom said.
Currently, 2D seismic surveys have been completed on both blocks. Drilling of the first prospecting well is expected to begin in the Leskinsky area by yearend. Data will be used to refine the geological concept and prepare a future project development plan.
Gazprom Neft-GEO will operate exploration works for the first stage.
Drilling & Production Quick Takes
Eni adds production from Egypt’s western desert
Eni added production from the South West Meleiha development and exploration concession by successfully drilling SWM-A-6X in the Egyptian western desert. The well is about 130 km north of the Siwa oasis and is close to existing production facilities.
Drilled in Faghur basin and to 15,800 ft TD, the well hit 130 ft net oil pay in the Paleozoic sandstones of the Dessouky formation. It is on stream producing 5,000 bo/d.
Production from South West Meleiha began in July 2019 and ramped up to 12,000 bo/d in 1 year due to contribution of new discoveries (OGJ Online, July 24, 2019).
Eni’s subsidiary Egyptian Oil Co. (IEOC) holds 100% stake in South West Meleiha. Operatorship is through AGIBA, a joint venture operating company equally held by IEOC and Egyptian General Petroleum Corp. (EGPC).
UKOG to begin Turkey drilling program
Partners in the Resan license, southwest Turkey, will perform a 5-well oil appraisal and step-out exploration program, set to begin before yearend, COVID-19 restrictions and weather permitting.
UK Oil & Gas PLC (UKOG), which signed an agreement with operator Aladdin Middle East Ltd. (ALM) for 50% non-operated working interest, will take an active technical role. The agreement must be approved by the Turkish government, which is expected to take 2 months.
The license covers 305 sq km of the southeast Anatolian basin, a geological continuation of the Zagros fold-belt petroleum system within the foothills of the Taurus-Zagros mountains in Iraq, Iran, and Turkey. Multiple producing oil fields containing proven recoverable reserves lie to the immediate west and southeast of the license.
The undeveloped Basur oil discovery and Resan oil pay, both within the license’s Cretaceous Mardin limestones, contain an aggregate unrisked gross mean oil in place (OIP) of about 253 million bbl, with a significant high case (P10) gross aggregate OIP of 495 million bbl.
An undrilled exploration target in the shallower Garzan limestones, Prospect A, adds further unrisked upside OIP potential of 68-112 million bbl in the mean and high case (P10).
Future oil production will be exported via road tanker to the nearest oil refinery at Batman, 80 km from the license.
UKOG will fund 100% of the first commitment well plus a small 2D seismic survey, capped at $5 million. Thereafter, the company will fund its 50% interest share, expected to be about $1.5 million per well.
Production capacity at Manora increases
Production capacity at Mubadala Petroleum-operated Manora field in the Gulf of Thailand has increased by 4,500 b/d following conclusion of a $15.08-million 2020 development drilling and workover program.
Four new development wells and two completed workovers are now on stream making Manora field capable of producing a total of about 9,500 bo/d.
JV partner, Tap Oil Ltd., Perth, said the highlights of the program included the MNA-28 development well intersecting and high quality 490 series reservoirs high to prognosis making it a key additional oil producer, while the MNA-25 well has become the new crestal development well for the 600 series reservoirs in the central fault block of the structure.
MNA-27 development well is now the crestal well for the 490 series reservoirs in the eastern fault block and the MNA-26H horizontal well will produce otherwise undrained oil in the high quality 370-10 reservoir in the eastern fault block.
Of the workovers, Tap said the previously shut-in MNA-15 had a new electrical submersible pump installed and is now producing 500 b/d, while MNA-7 was converted to a water injection well to add 8,000 b/d of water disposal capacity required for the forecast ramp up in production.
Tap said that total oil liftings of 1.46 million bbl of oil have been scheduled between July and December, adding that production is currently constrained to about 7,000 b/d until early September due to the floating storage and offtake vessel’s oil storage constraints. After September the production will be increased to full field capacity.
PROCESSING Quick Takes
Cooper Energy JV commits to upgrade, re-start Minerva gas plant
Cooper Energy Ltd., Adelaide, and its Japanese JV partner Mitsui Group made a $37-million (Aus.) final investment decision to upgrade and re-start the Minerva gas plant near Port Campbell in western Victoria.
The JV has already spent $17.8 million (Aus.) purchasing the plant last December and performing a front-end engineering and design program aimed at upgrading the facility and connecting it to process gas produced from the JV’s existing offshore Otway basin gas fields at Casino, Henry, and Netherby in licences L24 and L30.
Cooper is operator with 50% interest. Mitsui has the remaining 50% interest in the plant and the gas fields.
The new infrastructure work at the plant will enable it to receive 16 petajoules of gas that has yet to be developed.
Cooper managing director, David Maxwell said Minerva was a “shovel-ready” project that will see Cooper and Mitsui upgrade the idle plant to be a processing hub for local production and new discoveries in the offshore Otway basin.
The investment follows the successful exploration by the JV that resulted in the recent Annie-1 gas discovery–the first offshore discovery in southeast Australia in 7 years.
The project will initially connect gas from offshore wells Casino-4, Casino-5, Henry-2, and Netherby-1, to the plant via pipeline tie-in and minor modifications, allowing for improved recovery due to a lower plant inlet pressure and a firm supply of gas to the Victorian market.
First gas is expected during the September quarter of 2021. The Minerva plant has the capacity to process up to 150 terajoules/day of gas.
Maxwell said the plant will be renamed Athena.
Petrobras’s REPLAN refinery restarts units
Petróleo Brasileiro SA’s 434,000-b/d Paulínia Refinery (REPLAN) refinery in Paulínia, São Paulo, has once again broken its record for monthly production of low-sulfur fuel oil (LSFO) that complies with the International Marine Organization’s (IMO) new regulations requiring ships to use marine fuels with a sulfur content below 0.5% (OGJ Online, June 25, 2020).
In June, REPLAN’s production of IMO 2020-compliant LSFO—or Bunker 2020—reached 148,000 cu m, which was 20% higher from the refinery’s previous production record of 123,000 cu m in May, Petrobras said July 8.
During the first 5 months of 2020, REPLAN was responsible for 12% of all Bunker 2020 fuel produced by Petrobras refineries, the operator said.
REPLAN’s Bunker 2020 production is transported by pipeline to the Barueri onshore terminal, where it is stored to be sent via pipeline to the Porto de Santos in Santos, São Paulo, for loading to ships.
Alongside announcing the June IMO 2020-compliant fuel production record, Petrobras also confirmed it resumed operations in June at one of REPLAN’s crude distillation units (U-200A) as well as at the refinery’s catalytic cracking unit (UU-220). Restart of the units restores the refinery—the largest in Petrobras’s refining system—to its full processing capacity, according to the operator.
Basic design wrapped for BPGIC’s Fujairah refining, storage project
Brooge Energy Ltd. subsidiary Brooge Petroleum & Gas Investment Co. FZE (BPGIC) is nearing full completion of preliminary technical studies for the proposed Phase 3 refinery and storage expansion at BPGIC’s existing terminal operations in Fujairah, UAE, outside the Strait of Hormuz, adjacent to the East coast port of Fujairah on the Gulf of Oman.
MUC Oil & Gas Engineering Consultancy LLC (MUC) has issued the final basic design for BPGIC’s planned Phase 3 180,000-b/d refinery and associated storage terminal with up to 3.5 million cu m (22 million bbl) of capacity, and is progressing with the project’s front-end engineering design (FEED) study, which is scheduled to be completed in the coming weeks, Brooge Energy said July 15.
“Once Phase 3 is completed, this would bring our total storage capacity [for crude oil, fuel oil, and clean products] up to 4.5 million cu m, which is the equivalent of 28.3 million bbl of oil,” said Nicolaas L. Paardenkooper, chief executive officer of Brooge Energy and BPGIC.
Brooge Energy and BPGIC are in discussions with global oil majors that have expressed interest in contracting portions of the facility, Paardenkooper said, noting it plans to ensure Phase 3 capacity is fully contracted through a multiyear take-or-pay contract [before starting] construction.
In April, BPGIC’s awarded a contract to MUC for delivery of design and FEED for the project, both of which were due within 3 months. MUC also previously served as technical advisor and designer of storage installations for Phase 1 and Phase 2 terminals.
The Phase 3 expansion will include the same—though unspecified—technology, technical features, and tank diversification MUC employed in the first two phases, Paardenkooper said in April.
BPGIC signed a land lease agreement in February with Fujairah Oil Industrial Zone for an additional 450,000 sq m of land on which it could carry out the Phase 3 storage and refining expansion.
TRANSPORTATION Quick Takes
Golar, Norsk Hydro ink MoU for Para LNG terminal
Golar Power Ltd., a joint venture between Golar LNG Ltd. and Stonepeak Infrastructure Partners, has executed a memorandum of understanding with Norsk Hydro to develop the first LNG regasification terminal in northern Brazil. The 2-million tonne/year project will supply natural gas to Norsk Hydro’s Alunorte refinery, close to Vila do Conde Port in Barcarena, State of Pará, Brazil.
Alunorte will be the first operational customer for the Barcarena floating storage and regasification unit Golar Power plans to bring into operation first-half 2022. Concluding final agreements with Norsk Hydro will therefore be an important step toward a final investment decision (FID) within the next 4-6 months.
The LNG terminal will also supply gas to the Centrais Elétricas Barcarena 605-Mw thermal power plant, a subsidiary of Golar Power. Once the terminal becomes operational, Golar Power expects to operate a comprehensive LNG distribution network across the state of Pará and the region. This LNG supply chain will consist of thousands of kilometers of river and road transportation, serving industrial, commercial, and transportation customers.
Golar Power estimates a potential for replacing 1.8 million tons of LNG equivalents/year of LPG, diesel, fuel oil, and coal with the terminal. The project will fulfill Norsk Hydro’s 2017 commitment to the Pará state government to pursue a natural gas-based energy solution for one of the world’s largest aluminum plants.
Volumes rise on Crestwood’s Bakken gathering system
Crestwood Equity Partners LP’s Bakken shale Arrow gathering system ran at higher-than-expected volumes in second-quarter 2020. Arrow averaged second-quarter 2020 crude oil volumes of 87,000 b/sd, natural gas volumes of 90 MMcfd, water volumes of 73,000 b/sd, and natural gas processing volumes of 87 MMcfd.
These average quarterly volumes exceeded both initial forecasts by Arrow producer customers and Crestwood’s revised guidance issued in May, which assumed 50% of volumes on the system would be shut-in through July. Instead about 90% of estimated available Arrow production is flowing and, based on producer plans for second-half 2020, Crestwood expects the Arrow system to return to 100% flow rates then. The company also expects its larger producer customers to bring back completion crews starting third-quarter 2020. Crestwood Arrow-system customers include WPX Energy Inc., XTO Energy Inc., Enerplus Corp., RimRock Oil & Gas LP, Bruin E&P Partners LLC, PetroShale Inc., and QEP Resources Inc.
Following the announcement of possible curtailments on Energy Transfer Partners’ Dakota Access (DAPL) crude pipeline, Crestwood says it has engaged with Arrow’s producer customers to ensure downstream market access for 100% of available crude. Arrow connects to Kinder Morgan’s Hiland gathering system and Tesoro Logistics LP’s pipelines in addition to DAPL.
Crestwood can also transport Arrow-system crude by pipeline or truck to its crude-oil loading terminal (COLT) on the BNSF rail line in Epping, ND. COLT has multiple pipeline connections, storage capacity of 1.2-million bbl, and rail loading capacity of 160,000 b/d.
Mozambique LNG awards marine terminal contract
Mozambique LNG has contracted Besix Group, in partnership with Mota-Engil SA, to design and build the project’s marine terminal infrastructure. Works, which will begin imminently, include construction of quay walls, the LNG load-out jetty, wharf, berths, and moorings.
The combined jetty and wharf will stretch 4,600 m out to sea and include five berths (four for LNG and one for condensate) as well as moorings for the largest LNG carriers (two Q-Max, 266,000 cu m; and two Q-Flex, 216,000 cu m). The LNG load-out jetty and wharf comprise a 2,700 m long access jetty, with a width varying between 34-90 m, leading to a 1,900 m long wharf out at sea. Work will be carried out using Besix’s own marine construction, comprising two self-elevating platforms and crane barges.
Besix is conducting the work under an engineering, procurement, and construction contract signed between the Mozambique LNG partners and CCS JV in April 2020.
Mozambique LNG is in Cabo Delgado Province, near the Indian Ocean coastal town of Palma. Project developers expect to bring a two-train plant producing 13 million tonnes/year (tpy) online by 2024, expandable to 43 million tpy.
CCS JV is a partnership of McDermott International Inc., Saipem SPA, and Chiyoda Corp. Mozambique LNG is a joint venture of Total SA, Mitsui & Co., ONGC Videsh, Mozambican-state Empresa Nacional de Hidrocarbonetos, PTTEP, Bharat Petroleum, and Oil India Ltd.