GENERAL INTEREST Quick Takes
BLM prepares for ‘upcoming’ leasing on ANWR coastal plain
The Trump administration is asking companies to nominate tracts for an “upcoming” oil and gas lease sale on the coastal plain of the Arctic National Wildlife Refuge (ANWR), a step that would seem to prepare the way for a sale in January.
The Alaska state office of the Bureau of Land Management (BLM) has released a “call for nominations and comments on the lease tracts considered” in a notice set for publication in the Nov. 17 Federal Register.
The notice, including a map of tracts, gives companies 30 days to submit their nominations and comments, in keeping with established BLM procedures.
If the BLM gives itself a few hours consider nominations and comments, it could announce Dec. 17 a lease sale date and possibly get it published in the Dec. 18 Federal Register, to be followed by another 30-day period, again in keeping with BLM practice. Jan. 17 will fall on a Sunday, and Jan. 18 will be a federal holiday.
That would leave one day, Jan. 19, for a lease sale before Joe Biden is inaugurated as president. Biden is opposed to allowing exploration leasing for oil and gas in ANWR.
An added complication comes from litigation. There are four or five lawsuits challenging the record of decision on the leasing plan, said Kara Moriarty, president of the Alaska Oil and Gas Association. Her group has filed to intervene in the cases in defense of the plan.
Environmental activists are pursuing that legal avenue presumably with the hope that the plan will be remanded to BLM for changes, which would put the plan in the hands of a Biden administration.
The Tax Cuts and Jobs Act of 2017 requires an ANWR lease sale no later than Dec. 22, 2021, 4 years after the act was signed into law. It is common for agencies to miss deadlines, but that does not mean courts would allow delays to continue indefinitely.
Tethys Oil signs deal to increase Block 56 interest, assume operatorship
Tethys Oil, through subsidiary Tethys Oil Oman Onshore Ltd., will become increase its holdings and become operator in the exploration and production license covering Block 56 onshore Oman in a farm-in agreement with Medco Arabia Ltd., a subsidiary of PT Medco Energi Internasional Tbk of Indonesia.
The transaction will increase Tethys’ interest to 65% from 20%. Medco will retain a 5% interest (OGJ Online, Oct. 31, 2019).
Tethys will pay $5 million to Medco and carry up to $2 million of future expenditure. The deal includes additional consideration if the in the case a declaration of commerciality is made.
The 5,808-sq km block lies in the southeastern part of Oman some 200 km south of Blocks 3&4. Testing operations of three previously drilled wells were completed in this year’s first quarter. One well confirmed the presence of an active petroleum system with a crude oil quality of 20-25 degrees API and medium viscosity, although the commercial viability is yet to be determined.
The exploration phase for the block has been extended until December 2023.
Upon completion deal, subject to government approval, Tethys will be the operator with a 65% interest in the block with partners Biyaq Oilfield Services 25%, and Intaj LLC and Medco Arabia Ltd. each holding 5%.
Petrobras starts binding phase of Ceará cluster sale, releases teaser of Bahia assets
Petróleo Brasileiro SA (Petrobras) has started the binding phase of its sale of its entire stake the Ceará cluster in the state of Ceará and started the process to sell its interests in the Bahia Terra cluster in different municipalities of the state of Bahia.
The operator started the binding phase of its sale of its entire stake in shallow water fields Tuna, Curimã, Espada, and Xaréu (Ceará Cluster) in the state of Ceará (OGJ Online, June 19, 2020).
The Ceará Cluster has been in operation since the 80s, and comprises the fields of Tuna, Curimã, Espada and Xaréu, which lie 30 km from the coast of Ceará in water depth of 30-50 m. Average production in 2019 was 4,200 b/d of oil and 76,900 cu m/d of gas, through nine fixed platforms.
Petrobras is operator of the fields with 100% interest on the exploration and production rights of the concession contracts.
The company also entered the teaser stage to sell its total interests in a set of 28 onshore production field concessions, with integrated facilities, in the Recôncavo and Tucano basins, in different municipalities of the state of Bahia (the Bahia Terra cluster).
The Bahia Terra cluster has about 1,700 wells in operation, 19 collection stations, 12 collection points, 2 oil treatment stations, 6 collection and compressor stations, 4 water injection stations, 980 km of gas and oil pipelines, and administrative bases of Taquipe, Santiago, Buracica, Araçás, and Fazenda Balsamo.
There are also two oil storage and handling parks at the Bahia Terra cluster with all the infrastructure for receiving, storing, and draining oil for the Landulfo Alves Refinery (RLAM). In addition, the cluster includes the NGPU of Catu and 10 electrical substations.
Average production of the cluster from January to August was around 14,000 b/d of oil and 642,000 cu m/d of gas. Petrobras is operator of the fields with 100% interest.
The company noted that the concessions corresponding to the Miranga and/or Recôncavo clusters may be included in the sale process of the Bahia Terra cluster.
Exploration & Development Quick Takes
ExxonMobil makes non-commercial discovery off Guyana
ExxonMobil and Kaieteur block partners will evaluate data from a discovery offshore Guyana currently considered non-commercial as a stand-alone development, partner Ratio Petroleum Energy LP said Nov. 17. The 13,535-sq km block lies 250 km offshore in water depth of 2,800-3,800 m.
Tanager-1 well—the deepest drilled in Guyana-Suriname basin to date—was spudded Aug. 11 by the Stena Carron drillship, and reached 7,633 m TD (OGJ Online, Aug. 13 ,2020). Evaluation of LWD, wireline logging, and sampling data confirm 16 m net oil pay in high-quality sandstone reservoirs of Maastrichtian age. Preliminary evaluation of fluid samples from the Maastrichtian reservoir indicates heavier oil than is reported from Liza Phase I producing field crude assays. The samples will be analyzed over the coming months.
Although high quality reservoirs were also encountered at deeper Santonian and Turonian intervals, interpretation of reservoir fluids is reported to be equivocal at this stage and requires further analysis. The well will be plugged.
Tanager-1 results confirm continuance of a Cretaceous petroleum system and the Liza play fairway onto Kaieteur block, down dip from the discoveries on neighboring ExxonMobil-operated Stabroek block. Kaieteur partners will evaluate data collected at Tanager-1 with a view to understanding the well result, recalibrating the seismic model for the basin segment, and high grading the next potential drilling targets on the block. A prospect inventory has been mapped across the 5,750-sq km 3D seismic survey, which was acquired in the southern part of the block in 2017.
Esso Production & Exploration Guyana Ltd., an ExxonMobil subsidiary, is operator of the block with 35% interest. Pastners are Cataleya Energy Ltd. (25%), Ratio Guyana Ltd. (25%), and Hess (15%).
Chevron advances Gorgon, Jansz-Io Stage 2 development
Chevron Australia and its joint venture partners received regulatory approval for Stage 2 development of Gorgon and Jansz-Io gas-condensate fields offshore northwest Western Australia. Work is expected to begin immediately.
Plans include expansion of the subsea gathering network within the existing field infrastructure. Work includes installation of infield flowlines, pipelines, and umbilicals, as well as installation of subsea structures, jumpers, tie-in spools, and flying leads. This will be followed by leak testing, pre-commissioning, inspection, as well as any required maintenance and repair. Some infill drilling is included.
Stage 2 work is being done to ensure continuation of gas delivery to the three-train, 15.6 million tpy LNG plant and 300 terajoules/day domestic gas plant on Barrow Island. (OGJ Online, Mar. 14, 2019).
Jansz-Io fields lies within production licences WA-36-L, WA-39-L, and WA-40-L about 200 km off the coast in water depths of about 1,350 m.
Gorgon field lies within production licences WA-37-L and WA-38-L about 130 km off the coast in 200 m of water.
Subsea infrastructure for Stage 2 lies in pipeline licences WA-19-PL and WA-20-PL.
Equinor makes new Flemish Pass basin oil discoveries
Equinor has made two oil discoveries in the Flemish Pass basin offshore Newfoundland but said it cannot yet judge the resource potential.
Two wells at the Cappahayden and Cambriol prospects were drilled this summer by the Transocean Barents semi-submersible drilling rig about 500 km east of St. John’s, Newf.
The Cappahayden well has a water depth of about 1,000 m and the Cambriol well has a depth of 600 m.
As part of the 2020 exploration campaign, Equinor has also drilled a top-hole at the Sitka prospect.
Equinor operates three discoveries in the Flemish Pass basin: Bay du Nord and Harpoon (discovered in 2013), and Mizzen (discovered in 2010). The basin offers Jurassic reservoirs with high porosity, high permeability, and mature source rocks, and the geology is similar to its findings in the NCS. The discoveries at Bay du Nord and Harpoon offer light, high-quality crude oil, according to the company’s website.
Equinor is operator with 60%. BP Canada holds the remaining 40%.
Drilling & Production Quick Takes
Total, ADNOC deliver first UAE unconventional gas
Total and Abu Dhabi National Oil Co. (ADNOC) have produced the first unconventional gas from the United Arab Emirates.
Delivery from the Ruwais Diyab unconventional gas concession 200 km west of Abu Dhabi is a step toward future full field development as well as ADNOC’s target of producing 1 billion scfd of gas from the concession before 2030, ADNOC said Nov. 11.
In November 2018, the companies signed a deal to launch the unconventional gas exploration program in the Diyab play that covers more than 6,000 sq km west of the ADNOC Onshore concession (OGJ Online, Nov. 12, 2018).
The development builds on ADNOC’s efforts to derisk unconventional gas resources across Abu Dhabi since 2016 and comes 1 year after Abu Dhabi’s Supreme Petroleum Council (SPC) noted the discovery of 160 trillion scf of unconventional gas recoverable resources, ADNOC said.
The unconventional gas is delivered through a purpose-built gas pipeline and centralized early production facility in Diyab field which enables distribution through ADNOC’s gas network. The unconventional gas concession lies near ADNOC’s Ruwais industrial area, providing market access and allowing operations access to ADNOC’s existing infrastructure.
Total operates the exploration phase with 40% interest. ADNOC hold the remaining 60%.
Neptune achieves first gas from Adorf Carboniferous development
Neptune Energy achieved first gas from the Adorf Carboniferous development, the company said Nov. 2.
Results from appraisal well Adort Z15 in the municipality of Emlichheim, northwestern Germany, underline “the great potential for future gas production within this region,” said Andreas Scheck, Neptune’s managing director in Germany. “It is one of the most promising gas discoveries in Germany in recent years,” he said.
Adorf Z15 reached final depth of 3,500 m in February 2020 (OGJ Online, Apr. 22, 2020). Production tests indicated flow rates of up to 1,700 boe/d (gross). A modern processing plant for treatment of the natural gas has since been constructed at the site.
Neptune is operator of Adorf field with joint venture partner Wintershall Dea. Neptune’s share in Adorf Z15 is 67%.
Equinor lets additional contracts for Bacalhau
Equinor has let contracts to Baker Hughes, Halliburton, and Schlumberger for drilling and well services on Bacalhau field in the Santos basin off Brazil.
The contract scope awarded to Baker Hughes covers drilling services and completion. Halliburton’s scope of work will include intervention services and liner hanger, while Schlumberger will deliver wireline services. The contracts have a firm period of 4 years and two 2-year options. The total value of the three contracts is estimated at $455 million.
Front end engineering and design (FEED) contracts with early commitments and pre-investments for Phase 1 development were awarded in January (OGJ Online, Jan. 30, 2020).
Bacalhau, 185 km from the coast of Sao Paulo, in 2,050 m water depth, will be the first greenfield development in the presalt by an international operator. A final investment decision is planned in 2021 with first oil expected in 2024. Phase 1 development capacity is 220,000 b/d.
Equinor is operator in Bacalhau (40%) with partners ExxonMobil (40%), Petrogal Brasil (20%), and Pré-sal Petróleo SA (PPSA, non-investor government agency).
PROCESSING Quick Takes
Sri Lanka renews effort to expand Sapugaskanda refinery
The government of Sri Lanka has approved Ceylon Petroleum Corp. (CPC) to restart the process for a long-planned project to expand crude oil processing capacity of its 40,000-b/d refinery at Sapugaskanda, in the Indian Ocean island country’s Western Province.
In a Nov. 2 meeting, Sri Lanka’s Cabinet of Ministers approved a proposal for CPC to initiate a new feasibility study to determine the scope, technical, operational, and financial feasibility of the planned 100,000-b/d expansion with a focus on several alternative proposals to enhance the refinery’s existing capacity, according to documents released by the country’s Department of Government Information (DGI).
Approval for the new feasibility study follows a previous study conducted in 2010 for the refinery’s renovation and expansion. Subsequent technological changes in the sector, however, have made it impossible to proceed on results of the earlier 2010 feasibility study, DGI said.
Currently, the Sapugaskanda refinery—the largest of the country’s two refining sites—meets only 25% of local demand for refined petroleum products, requiring the remaining 75% to be imported, according to DGI.
In its latest available report for yearend 2018, CPC said it had selected an unidentified firm to execute front-end engineering design for the proposed expansion based on the 2010 feasibility study. That project was to include replacement of the refinery’s crude distillation column, gas oil hydrotreater unit reactor, and platforming unit.
Angola strikes deal for grassroots Cabinda refinery
The government of Angola, through state-owned Sonangol EP, and new partner Gemcorp Capital LLP, a London-based investment management firm, have taken final investment decision (FID) to proceed with the country’s long-planned project for construction of a greenfield refinery on the Malembo plain, 30 km north of Cabinda, in the country’s province of Cabinda (OGJ Online, June 4, 2019).
As part of the FID reached in late October, Gemcorp (90%) and Sonangol (10%) will invest $220 million to build Phase 1 of the proposed refinery, which alongside a 30,000-b/d crude distillation unit, desalinator, kerosine treating unit, and auxiliary infrastructure, also will include construction of a conventional float anchoring system, pipelines, and a more than 1.2-million bbl storage terminal, Sonangol said.
The FID also covers a $700-million investment for construction of Phases 2 and 3, which will add another 30,000 b/d of crude processing capacity, as well as units for catalytic reforming, hydrotreating, and catalytic cracking that will transform the site into a full-conversion refinery, according to the operator.
With formal construction of the site—including land clearing and preparation—started in March 2020 and completed in August 2020 and long-lead items for the project ordered in November 2020, Phase 1 of the 60,000-b/d refinery is scheduled to enter operation in first-quarter 2022, Sonangol and Gemcorp said.
Phases 2 and 3 of the refinery are scheduled to be completed in second-quarter 2023 and second-quarter 2024, respectively, according to Sonangol’s 2019 annual report released in late-September 2020.
As the first private investment of its kind in Angola, the FID for the refinery aligns with the Angolan government’s main strategic objectives of increasing domestic crude processing capacity to help considerably reduce the country’s dependence on expensive imports of refined products, encouraging increased foreign investment, and creating employment opportunities for Angolans, said Sebastião Gaspar Martins, Sonangol’s chairman.
The revised partnership for the Cabinda refinery follows Sonangol’s June 2019 agreement with the United Shine consortium for the project, which Sonangol terminated later in the year following a contractual breach by the consortium, Sonangol said in its 2019 annual report.
Once fully operable, the Cabinda refinery will produce gasoline, diesel, LPG, fuel oil, Jet A1, and kerosine, according to Sonangol and Gemcorp.
TRANSPORTATION Quick Takes
Energia Costa Azul LNG takes FID
Sempra Energy subsidiary ECA Liquefaction (ECA LNG), a joint venture between Sempra LNG and Infraestructura Energética Nova SAB de CV (IEnova), has reached a final investment decision (FID) for development, construction, and operation of the 3.25-million tonne/year (tpy) Energia Costa Azul LNG Phase 1 natural gas liquefaction-export project in Baja California, Mexico. First production is expected late-2024, with Sempra describing it as the first LNG export plant on the Pacific Coast of North America.
Sempra LNG and IEnova will build and operate Phase 1 as a single-train liquefaction plant with initial offtake capacity of 2.5 million tpy. ECA LNG has secured definitive 20-year sale and purchase agreements with Mitsui & Co. Ltd. and an affiliate of Total SE for the purchase of this production.
ECA LNG and Total SE are negotiating a potential equity investment in the project by Total SE. In February 2020, ECA LNG executed a lumpsum, turnkey engineering, procurement, and construction contract with an affiliate of TechnipFMC PLC for Phase 1.
Phase 1 will cost roughly $2 billion.
Sempra LNG is developing additional LNG export plants on the Gulf Coast and Pacific Coast of North America, including a potential 12-million tpy Phase 2 of the ECA LNG project. Phase 2 will include two additional trains and one LNG storage tank. ECA LNG has US Department of Energy (DOE) authorization to export LNG produced from US-sourced natural. Phase 2 of the project will require additional DOE approval to export at its full expected capacity.
Sempra has proposed a new two-train 13.5-million tpy export plant in Port Arthur, Tex. The company also owns a 50.2% interest in the three-train 12-million tpy Cameron LNG plant in Hackberry, La., and has begun permitting for Phase 2, which will include two additional liquefaction trains and one additional storage tank. Sempra commissioned the third Phase 1 train earlier this year (OGJ Online, May 11, 2020).
Calcasieu Pass receives first two liquefaction trains
Venture Global LNG Inc. has taken delivery of the first two 0.6-million tonne/year (tpy) liquefaction trains at its 10-million tpy Calcasieu Pass LNG plant in Cameron Parish, La. Each train—the first two of 18—is positioned on its foundation. The trains will now be connected to their respective brazed aluminum heat exchangers, eight of which are already installed on site (OGJ Online, June 19, 2020).
Delivery from Baker Hughes’s manufacturing assembly and fabrication site in Avenza, Italy, occurred less than 15 months after the project’s final investment decision and more than 2 months ahead of the contractual delivery date. Venture Global expects to complete construction in 2022.
Gas for the Calcasieu Pass plant will be delivered from the Texas Eastern pipeline by Enbridge Inc.’s Cameron Extension project.
Venture Global also plans to use 36 of the modular trains at its Plaquemines LNG plant.
NEP to develop UK North Sea CO2 storage
BP, Eni SPA, Equinor ASA, National Grid PLC, Royal Dutch Shell PLC, and Total SA have formed the Northern Endurance Partnership (NEP) to develop offshore CO2 transportation and storage infrastructure in the UK North Sea.
NEP, to be operated by BP, will serve the proposed Net Zero Teesside (NZT) and Zero Carbon Humber (ZCH) projects to establish decarbonized industrial clusters in Teesside and Humberside on the northeast coast of England. Both projects could be commissioned by 2026, targeting net zero emissions by 2030 through a combination of carbon capture, hydrogen, and fuel-switching.
If successful, NEP, working in tandem with NZT and ZCH, could decarbonize almost 50% of the UK’s industrial emissions, according to BP. NEP has submitted an application for funds through Phase 2 of the UK government’s £170-million Industrial Decarbonisation Challenge (IDC).
IDC is intended to hasten development of an offshore pipeline network to transport captured CO2 emissions from both NZT and ZCH to offshore geological storage beneath the UK North Sea. The application follows approval by the UK Oil and Gas Authority for BP and Equinor joining National Grid in the carbon storage licence for Endurance reservoir.
