GENERAL INTEREST Quick Takes
House votes to roll back methane rules
The House voted 229-191 to nullify a rule written by the Trump administration that largely rolled back Obama administration regulations on control of methane from oil and gas production, processing plants, storage, and transportation.
The June 25 vote also meant that regulations for emissions of volatile organic compounds (VOCs) will be applied to storage and transportation, as intended by the Obama administration.
The Environmental Protection Agency (EPA) in 2020 agreed with the industry view that separate methane regulations were redundant, given that VOC controls would also control methane. The Trump EPA also agreed that VOC and methane regulations for storage and transportation were improper because EPA had never studied the matter to make a finding that emissions from those segments of the industry were significant enough to merit the regulations.
The Trump EPA estimated its 2020 changes should provide net savings of $750-850 million over the 10 years starting with 2021. That would average about $80 million a year for the industry.
The Trump EPA’s rule on those subjects was published Sept. 14 in the Federal Register. In April, the Senate, through use of the Congressional Review Act, voted 52-42 to rescind that rule. The House took the resolution and approved it mostly along party lines, though 12 Republicans joined Democrats in agreeing to rescind the rule.
President Biden, who has made much of his hopes to reduce greenhouse gas emissions, can be expected to sign the resolution into law.
The Obama EPA put in place rules in 2012 and 2016 for control of methane emissions, under its authority to set new source performance standards.
Rep. Raul Grijalva (D-Ariz.), chairman of the House Natural Resources Committee, issued a statement June 25 saying the rollback of the Trump EPA rule needs to be followed by legislation requiring tighter controls on oil and gas operations on federal land.
Grijalva’s committee in late April and early May approved several bills by Democrats to require tighter regulation of methane not only by EPA but the Interior Department’s Bureau of Land Management.
Seven companies land interests in Norway licensing round
The Ministry of Petroleum and Energy awarded offers of ownership interests to seven companies on a total of four production licenses on the Norwegian Shelf in the 25th licensing round.
Of the nine areas on offer, three areas in the Norwegian Sea and one in the Barents Sea were offered to A/S Norske Shell, Equinor Energy AS, Idemitsu Petroleum Norge AS, Ineos E&P Norge AS, Lundin Energy Norway AS, OMV (Norway) AS, and Vår Energi AS (OGJ Online, Nov. 20, 2020).
Equinor was awarded production licenses PL 1133 (Block 7324/4) and PL 1134 (Blocks 7323/2,3; 7324/1; 7423/12; 7424/10,11,1 2; 7425/10) in the Hoop area of the Barents Sea where tie-in of any discoveries to Wisting field is possible. Final investment decision for the Wisting license is planned for end 2022.
Equinor will serve as operator of PL 133 with 50% interest. Partners are Lundin Energy (20%), Petororo AS (20%) and Idemitsu (10%). Equinor also will serve as operator (50%) of PL 1134 with partners Lundin Energy (30%) and Petoro AS (20%).
Other license awards are PL 1055 B (Blocks 6204/2, 6204/3), where Ineos E&P Norge will serve as operator (60%) with partner A/S Norsk Shell (40%), and PL 1072 B (Blocks 7118/11,12), where Vår Energi will serve as operator (70%) with partner OMV (Norge) (30%).
Talos, Storegga Geotechnologies form GoM CCS JV
Talos Energy Inc. formed a joint venture with Storegga Geotechnologies Ltd. to source, evaluate, and develop carbon capture and storage (CCS) on the US Gulf Coast and Gulf of Mexico (GoM), including state and federal waters offshore Texas, Louisiana, Mississippi, and Alabama.
Under the joint venture framework, partners will originate and mature CCS ventures with emitters, infrastructure providers, service companies and financing partners, among others. Under terms of the agreement, as individual CCS projects are matured in the future, each will be ring-fenced with separate operating agreements, financing structures, and the possibility of additional working interest partners. The agreement requires no up-front capital commitments, and the partnership will equally share costs in initial phases. Talos is designated as the operating partner of the joint venture.
Storegga is lead developer of the Acorn CCS and Acorn Hydrogen projects and is actively developing a direct carbon air capture (DAC) project. Acorn is the most advanced large-scale CCS project in the UK with final investment decision expected in 2022. Talos said its core skill set fits with CCS project requirements, particularly with respect to CO2 injection and storage, including geology and geophysics, reservoir engineering, drilling and completion operations, regulatory processes, and inland water and offshore logistics.
The US Gulf Coast hosts more than 100 facilities emitting more than 1,000,000 tons/year of CO2. It is also immediately adjacent to a large natural carbon storage province offshore in the shallow waters of the GoM Shelf, potentially holding more than 30 gigatons of available storage in geological structures with the necessary rock properties and fluid type to effectively store CO2.
Exploration & Development Quick Takes
Equinor granted approval for Breidablikk development
Equinor and partners received approval from Norwegian authorities for development of Breidakblikk field in the North Sea. Production is scheduled to start in first-half 2024.
The plan for development and operation (PDO) was submitted in September 2020 (OGJ Online, Sept. 28, 2020).
Field investments are about 18.6 billion kroner.
Development will include a subsea solution of 23 oil producing wells from four subsea templates. The field, which lies northeast of Grane field in 130 m of water, will be tied back to the Grane platform for processing before the oil is piped to the Sture terminal. Production will be monitored by digital tools from an operations center at Sandsli. Estimated recovery from the field is 200 million bbl of oil.
Contracts totaling 8 billion kroner have been awarded to companies in Norway.
Aker Solutions has been awarded the contract for subsea production facilities. The contract covers the delivery of four subsea templates and up to 23 subsea trees and associated components.
Wood has been awarded the contract for required modifications and upgrade of the Grane platform to be able to receive oil from the Breidablikk subsea facilities.
TechnipFMC has been awarded a contract for pipelaying and subsea installation services.
Odfjell Drilling and the Deepsea Aberdeen rig have signed an agreement for drilling wells on Breidablikk.
Schlumberger Norge has been awarded a letter of intent for integrated drilling and well services.
Alcatel Submarine Networks has been awarded a contract for fiber-optic and electrical infrastructure from the Grane platform to the subsea production facility.
Floatel International has been awarded the contract for floatel services.
H. Butting GmbH & Co. KG and Mitsui & Co. Norway AS has been awarded the contracts for linepipe deliveries.
Equinor operates Breidablikk with 47.5%. Partners are Petoro AS 30%, Vår Energi 10%, and ConocoPhilips Skandinavia AS 12.5%.
West Erregulla-5 confirms large, high-quality gas resource
Strike Energy Ltd. has confirmed a large, high-quality gas resource in the main Kingia formation reservoir of West Erregulla gas field, with initial well results in line with expectations.
The West Erregulla-5 appraisal well in the onshore North Perth basin of Western Australia was drilled to 5,015 m total depth in the Holmwood shale. Kingia was encountered at 4,771 m, which was shallower than expected. The formation had a gross thickness of 183 m and comprised almost one single unit of very clean sand displaying thick blocky porosity.
Gas was observed throughout the Kingia which is interpreted to have a net pay of 32 m and an average porosity of 10% with highs of 15%. Reservoir pressures will be captured in forthcoming wireline runs.
The underlying High Cliff sandstone was observed to have negligible reservoir development, but additional pay was identified in shallower Permian reservoirs that will be subject to further testing.
West Erregulla-5 lies about 1.7 km due north of the West Erregulla-2 discovery well and is the third appraisal in the field in permit EP469.
Strike will conduct additional wireline logging to gather fluid samples, pressures, and other data prior to running production casing and a flow test of the reservoir.
The appraisals were designed to test reservoir distribution in the field, and all will be completed as future producers across the Kingia Sandstone for the proposed Phase 1 production operations.
Strike is operator with 50% interest. Warrego Energy Ltd. holds the remaining 50%.
Vintage continues successful run in Cooper basin permits
Vintage Energy Ltd., Adelaide, has seen continued success in adjoining Cooper basin permits across the South Australian and Queensland borders.
The Vali-3 appraisal well in Queensland permit ATP 2021 is drilling ahead at 2,774 m towards its primary objective in the Permian age Patchawarra formation having already recorded gas shows in the overlying mid-Nappamerri formation and gas with minor oil shows in the Toolachee formation.
Vintage said it is unlikely the Toolachee oil will be recoverable, but it is an encouraging sign for other leads in the area. It is possible for oil migration to shallower Jurassic (Eromanga basin) prospects in the permit which is analogous to the Cooper basin Western Flank fairway in South Australia, the company said.
Vali-3 is intended to appraise the extent of the deeper Patchawarra gas accumulation discovered in Vali-1 ST1 and confirmed recently in Vali-2.
Additionally, the company has received a gas composition analysis for the Odin-1 discovery in adjoining South Australian retention lease PRL 211.
Vintage estimates that 172.5 m of net gas pay exists within the various sections of the well made up of 37 m in the Toolachee, 4.5 m in the Epsilon, 126 m in the Patchawarra, and 5 m in the Tirrawarra.
The richest hydrocarbon content was recorded in a gas sample from the Toolachee: 79% methane, 3% ethane, 1% other, and 17% inerts.
The Epsilon samples recorded 75% methane, 2% ethane, and 23% inerts, values similar to Patchawarra formation samples from previous wells.
Data will be independently evaluated to provide resource numbers for the Odin field along with a reserve certification. Odin is a fault-bounded Patchawarra formation closure up-dip from 1987 wildcat Strathmount-1 that found what was then considered non-commercial gas.
Vintage is operator for both permits. Interest holders in ATP 2021 are Vintage 50%, Metgasco Ltd. 25%, and Bridgeport (Cooper Basin) Pty Ltd. 25%. Interest holders in PRL 211 are Vintage 42.5%, Metgasco 21.5%, Bridgeport 21.25%, and Impress (Cooper Basin) Pty Ltd. 15%
Drilling & Production Quick Takes
CNOOC starts production at Lingshui deepwater gas field
China National Offshore Oil Corp. Ltd. (CNOOC) started production at Lingshui 17-2 deepwater gas field in the northern sea of Qiongdongnan basin.
A new semisubmersible production platform has been built, with condensate oil storage capacity, a mooring system, a set of underwater production system, and subsea pipeline. A total of 11 production wells are planned. It is expected to reach peak production of 328 MMcfd natural gas and 6,751 b/d condensate in 2022, with a 10-year stable production period.
Natural gas will be connected to the national gas pipeline network through submarine pipelines and will become one of the important sources of stable natural gas supply for Guangdong-Hong Kong-Hainan area.
The field is in about 1,560 m of water. It is China’s first independent deepwater gas field and has 100 billion cu m proven natural gas resources.
CNOOC is sole owner and operator of Lingshui 17-2.
Johan Sverdrup partners raise production capacity
Equinor ASA and partners expect increased full field gross production capacity at Johan Sverdrup. Once Phase 2 is on stream—expected by fourth-quarter 2022—full field gross production capacity of 755,000 b/d of oil is expected, up from 720,000 b/d.
Execution of Phase 2 has proceeded with jacket installation offshore and full assembly of the second processing platform in Norway. Completion activities ahead of offshore installation in second-quarter 2022 are ongoing.
Costs are unchanged from the PDO estimate of $1.68 billion. Full field breakeven oil price for Johan Sverdrup has been reduced to $15/boe from $20/boe.
Johan Sverdrup is the third largest oil field on the Norwegian continental shelf, with expected recoverable reserves of 2.7 billion boe. It is powered from shore with low CO2 emissions per bbl. Emissions during the field life are estimated at less than 0.7kg CO2 per produced bbl.
Equinor is operator (42.6%) with partners Lundin Energy Norway (20%), Petoro (17.36%), Aker BP (11.57%), and TotalEnergies (8.44%).
Lundin increases 2021 production guidance
Lundin Energy AB has increased its 2021 production guidance to 180,000-195,000 boe/d from the original guidance of 170,000-190,000 boe/d based on better-than-expected production performance.
Production year-to-date (end May 2021) is 185,000 boe/d, above the mid-point of the original guidance range, driven by production efficiency across all assets, an earlier than forecast increased plateau rate of 535,000 b/d of oil gross at Johan Sverdrup Phase 1, and additional capacity available at Edvard Grieg field.
Additional facilities capacity at Edvard Grieg is due to Ivar Aasen field not utilizing contractual capacity, which is expected to continue for the remainder of the year.
PROCESSING Quick Takes
PBF Energy weighs renewables project at Louisiana refinery
PBF Energy Inc. is considering a major investment to implement a renewable diesel project at subsidiary Chalmette Refining LLC’s 185,000-b/d dual-train coking refinery in Chalmette, St. Bernard Parish, La., outside of New Orleans.
As part of the potential project to ensure ongoing competitiveness and employment for the refinery’s current 516 employees, PBF Energy would invest $550 million to retrofit an existing hydrocracking unit idled since 2010 with new technology to enable renewable diesel production at the site, Louisiana Economic Development (LED) and the operator said.
The project, which would support an additional 200 jobs during its execution, also would include construction of a pretreatment unit at the manufacturing site to allow Chalmette Refining to process renewable materials such as soybean oil, corn oil, and other biogenically derived fats and oils into feedstocks for the revamped unit.
To secure the project, which aligns with goals of Louisiana’s Climate Initiatives Task Force initiative to pursue lower greenhouse gas emissions, the LED has offered PBF Energy incentives that include solutions of its FastStart state workforce training program, as well as access to Louisiana’s Industrial Tax Exemption Program (ITEP).
Granting of ITEP incentives, however, remain subject to final approval of the project by St. Bernard Parish local officials, which is due sometime later this summer, LED said.
The Chalmette refinery—which PBF Energy acquired from ExxonMobil Corp. and Petroleos de Venezuela SA (PDVSA) in 2015—is equipped with flexibility to source and process a mix of light and heavy crudes to produce mostly gasoline, distillates, and specialty chemicals for distribution locally and abroad via connecting pipeline and maritime assets.
Chevron Phillips lets contract for new unit at Old Ocean
Chevron Phillips Chemical Co. LP (CPChem), a joint venture of Chevron Corp. and Phillips 66, has let a contract to S&B Engineers and Constructors Ltd. to build a grassroots on-purpose 1-hexene plant near the operator’s Sweeny petrochemical complex in Old Ocean, Tex. (OGJ Online, June 1, 2021).
As part of the contract, S&B will deliver engineering and construction (EC) on the new 1-hexene unit that—equipped with CPChem’s proprietary technology—will use a feedstock of ethylene to produce 266,000 tonnes/year of high-purity, comonomer-grade 1-hexene, a critical component used in producing polyethylene (PE), the service provider said on June 22.
Scheduled for startup in 2023, the planned Old Ocean 1-hexene project comes as part of CPChem’s program to help meet customers’ needs as global PE demand continues to grow, the operator said upon announcing the project in late May.
Following commissioning of the Old Ocean plant, CPChem said it will have a total US 1-hexene capacity of 650,000 tpy.
TRANSPORTATION Quick Takes
Spire STL pipeline FERC certificate vacated
Spire STL Pipeline LLC’s US Federal Regulatory Commission (FERC) certificate of public convenience and necessity, the document approving the project, has been revoked by the US Court of Appeals for the District of Columbia. Spire STL began operations in November 2019, transporting as much as 400 MMcfd natural gas 65 miles from Illinois to Missouri.
The court ruled that the contract between Spire STL and an affiliate establishing the latter as the line’s primary customer did not constitute necessity, and chastised FERC for failing to conduct independent analysis of need and instead relying on Spire STL’s assessment. “We find that the Commission ignored…evidence of self-dealing and failed to seriously and thoroughly conduct the interest-balancing required by its own Certificate Policy Statement. Therefore, FERC’s Certificate Order and Order on Rehearing do not survive scrutiny under the applicable arbitrary and capricious standard of review,” the court said in issuing its ruling.
FERC granted the certificate in 2018 despite an open season for the project having failed to receive any third-party interest in shipping on the pipeline and Spire STL subsequently granting Spire Missouri Inc. 87.5% of its capacity.
The court vacated FERC’s orders and remanded the case back to FERC for further action. The court cancelled the certificate even though the pipeline is operational, noting that “remanding without vacatur under these circumstances would give the Commission incentive to allow ‘build[ing] first and conduct[ing] comprehensive reviews later’ (Standing Rock Sioux Tribe v. Army Corps of Eng’rs, 985 F.3d 1032, 1052 (D.C. Cir. 2021). We certainly do not wish to encourage such an approach given the significant powers that accompany a certificate of public convenience and necessity.”
Neptune Energy, DNV partner on North Sea CCS
Neptune Energy Netherlands has awarded assurance and risk management company DNV the contract for a carbon capture and storage (CCS) pipeline materials study to assess the fracture and suitability of offshore pipelines for reuse in CO2 transport.
The pipeline materials analysis is part of a wider feasibility study being conducted by Neptune, in cooperation with its license partners and CO2 emitters, to review plans for a large-scale offshore CCS project at the Neptune-operated 10-area in the Dutch North Sea. If the project is developed, it will be one of the largest CCS sites in the Dutch North Sea and could meet more than 50% of CO2 reductions targeted by the Dutch industrial sector.
The first phase of the DNV study will identify advanced approaches to ductile fracture assessments in dense-phase CO2 pipeline systems and the applicability of such assessments to both welded and seamless subsea line pipe. This phase will involve technical literature reviews to understand the most appropriate approach to characterize material failure behavior.
The most suitable approach identified in Phase One will be used in Phase Two of the study to assess the likely suitability of existing pipelines for dense-phase CO2 transport at up to 120 bar.
The output of the study will inform the ongoing Neptune feasibility study to provide an increased level of confidence in the suitability, or otherwise, of existing pipelines which would be used to inject 5-8 million tonnes/year of CO2 into depleted gas fields.
“Given the existing infrastructure that connects offshore with onshore, there is real potential for the Dutch North Sea to develop new energy faster, more efficiently, and in a safe way,” said René van der Meer, head of new energy at Neptune. “With support from partners, such as the experienced team of DNV, we are well placed to enable offshore CCS and offshore green hydrogen production using existing infrastructure. Using what is already there, will not only speed up new energy projects, but will cost significantly less and it doesn’t unnecessarily disturb the surroundings like the seabed.”
