GENERAL INTEREST Quick Takes
Equinor to acquire Suncor Energy UK
Equinor UK Ltd. agreed to acquire the UK exploration and production business of Suncor Energy, Suncor Energy UK Ltd., for $850 million.
The deal includes a non-operated interest in the producing Buzzard oil field (29.89%), an additional operated interest in the Rosebank development (40%), and Suncor employees based in the UK who work with the assets.
Equinor said $250 million of the North Sea asset deal consideration is contingent upon a final investment decision for Rosebank, which is targeted for this year subject to the UK Government’s and partners’ approval.
Rosebank oil and gas field lies about 130 km west of the Shetland Islands on the UK Continental Shelf. Development has been optimized to reduce carbon emissions and the FPSO will be prepared for future electrification in line with the North Sea Transition Deal, Equinor said. Expected recoverable resources are about 300 million bbl of oil.
Production from the field will be through subsea wells tied back to a redeployed FPSO for processing and offloading at the field.
CNOOC-operated Buzzard field consists of four fixed platforms and three subsea manifolds. The field is producing about 60,000 boe/d. Liquids are exported via the Forties Pipeline system to Hound Point Terminal where the crude is lifted and sold in the open market. Gas volumes are exported via the FUKA system.
With the deal, Equinor adds about 15,000 boe/d in equity share in 2023, the company said in a release Mar. 3.
The transaction, subject to relevant regulatory approvals, is expected to close mid-2023. Post close, Equinor’s share in Rosebank would increase to 80% with Ithaca Energy holding the remaining 20%.
Shell completes withdrawal from Salym project, Russia
Shell Salym Development BV, a Shell plc subsidiary, completed the withdrawal from its 50% interest in the Salym project, which had been jointly developed with Gazprom Neft, a subsidiary of Gazprom.
In March 2022, Shell said it was undertaking a complete but phased withdrawal from all Russian-related oil and gas activities, including the Salym development in the Khanty Mansiysk Autonomous District of western Siberia (OGJ Online, Mar. 8, 2022).
The withdrawal follows the receipt of all necessary regulatory approvals, the company said in a release Mar. 3.
Shell’s share in the venture in Western Siberia, along with other associated interests, has been acquired by Gazprom Neft. Additional details were not disclosed.
Gulfport plans 2-6% net production increase
Gulfport Energy Corp., Oklahoma City, expects to deliver full year 2023 net production of 1.00-1.04 bcfed, an increase of 2-6% compared to 2022, driven by the Utica development plan.
Total capital expenditures of $450 million are expected, including $50-75 million on leasehold and land investment, with drilling and completion capital spend expected to decrease about 6% compared to 2022 with minimal inflationary impact, the company said in a release Feb. 28.
In 2023, the company expects 22-24 gross wells turned to sales, including two wells targeting the Marcellus, two in the SCOOP in central Oklahoma, and the remaining wells targeting the Utica.
In the Marcellus shale, Gulfport plans a delineation test in Belmont County, Ohio, which aims to unlock inventory underlying the company’s current acreage position.
In fourth-quarter 2022, the company delivered total net production of 1.052 bcfed. Net income was $748.6 million and $188 million of net cash provided by operating activities.
For full year 2022, the company delivered total net production of 983.4 MMcfed, primarily consisting of 692.9 MMcfed in the Utica and 290.5 MMcfed in the SCOOP. For the full year, Gulfport’s net daily production mix was comprised of about 90% natural gas, 7% NGLs, and 3% oil and condensate.
Total proved reserves for the year were 4.0 tcfe, an increase of 4% compared with 2021.
Exploration & Development Quick Takes
Shell makes third oil discovery offshore Namibia
Shell and partners discovered light oil in deep-water offshore Namibia. Further appraisal activities with dynamic data gathering are required to characterize the variability of rock properties and to determine the size and recoverable potential of the discovery.
The company began drilling operations on the Jonker-1X in December 2022. The exploration well lies 270 km offshore Namibia in the PEL 0039 license and was drilled to 6,168 m total depth in 2,210 m water depth. Drilling operations established the presence of a reservoir with light oil.
“We are encouraged by a further deep-water discovery, our third in Namibia, and pleased to confirm the safe conclusion of the well,” said Dennis Zekveld, Shell’s country chair in Namibia.
The Deepsea Bollsta semi-submersible drilling rig will remain in the license to drill further wells as part of the joint venture’s ongoing exploration and appraisal campaign, Shell said in a release Mar. 6.
Shell is operator of PEL 0039 with 45% working interest. Partners are QatarEnergy (45%) and the National Petroleum Corp. of Namibia (NAMCOR) (10%). PEL 0039 covers about 12,000 sq km in deep water, 250 km off the southern coast of Namibia.
The discovery follows those of Shell and partners in the Graff-1 deep-water exploration well and the La Rona-1 (OGJ Online, Feb. 4, 2022).
Lukoil to develop Eridu field in southern Iraq
PJSC Lukoil and INPEX South Iraq Ltd. will develop Eridu oil field, targeting production of 250,000 b/d, having received approval from Iraqi state-owned Thi-Qar Oil Co. (TOC) for declaration of commerciality of reserves of Block 10 in Iraq.
Geological exploration at Block 10 started in 2012. Since then, 2D and 3D seismic surveys have been carried out and three exploration and six appraisal wells have been drilled, resulting in the Eridu oil field discovery, which is estimated to contain reserves of 12.9 billion bbl, Lukoil said in a release Mar. 6.
Block 10, with an area of 5,800 sq km, lies in the southern part of Iraq, 120 km west of Basra and 150 km from West Qurna-2 field.
In March 2019, Lukoil reported the fifth well in Eridu oil field flowed more than 9,000 b/d of oil from Middle Cretaceous Mishrif pay (OGJ Online, Mar. 26, 2019). Earlier that year, Lukoil said testing of its fourth well in the field confirmed the geologic model (OGJ Online, Jan. 24, 2019).
Lukoil is operator of the project with 60% interest. Japan’s Inpex holds 40%. The contract party from Iraq is state-owned TOC.
Vår Energi confirms oil discovery near Goliat, updates volume estimates
Vår Energi ASA will evaluate appraisal well drilling after confirming an oil discovery 13 km northeast of Goliat field in Barents Sea production license (PL) 229 (OGJ Online, Feb. 9, 2023). A tie-back to the Goliat FPSO will be considered.
The 7122/8-1S Countach well was drilled to respective vertical and measured depths of 2,639 and 2,957 m subsea by the Transocean Enabler semi-submersible drilling rig. It was terminated in the Kobbe formation. Water depth at the site is 399 m.
The primary target was to prove petroleum in the Kobbe formation in Middle Triassic reservoir rocks. The secondary target was to prove petroleum in the Realgrunnen subgroup in Lower/Middle Jurassic reservoir rocks.
The well encountered an oil column of 13 m in the Realgrunnen subgroup in sandstone layers totaling 29 m with moderate to good reservoir quality. The oil-water contact was encountered at 1,650 m subsea.
In the Kobbe formation, the well encountered gas and oil columns of about 240 m, a total of 55 m of which were sandstone layers with poor to moderate reservoir quality. The oil-water contact was not encountered.
Preliminary estimates place the size of the discovery in the tested segment at 0.5-2.1 million std cu m (3-13 million bbl) of total recoverable oil equivalents. The potential of the Countach prospect, in the undrilled segments, is estimated at up to 3.7 million std cu m (23 million bbl) of total recoverable oil equivalents.
Due to late arrival of the rig, the company has not yet carried out the planned sidetrack as environmental drilling restrictions began Mar. 1, said Rune Oldervoll, executive vice-president, exploration and production. The company will continue to “explore the area around Goliat” at a later time, he continued.
Vår Energi is operator at PL 229 (65%) with partner Equinor Energy AS (35%).
Drilling & Production Quick Takes
Enauta restricts production from Atlanta field
Enauta Participações SA temporarily halted production from the 7-ATL-2HP-RJS well in Atlanta field in Santos basin, Block BS-4, about 185 km southeast of Rio de Janeiro.
Preliminary assessments indicate failure in the surface equipment (topside). A spare pump is available in case it requires replacing, the company said in a release Mar. 3.
Enauta began a three-well drilling campaign late 2022. The first well is expected to begin producing to the Petrojarl I FPSO in April, increasing field production to more than 20,000 b/d of oil from the current 7,000 bo/d.
Last year, Enauta acquired the FPSO Atlanta for Atlanta’s full development, which is expected online by mid-2024 with production from six wells, increasing to 10 wells by 2029.
Atlanta field, operated by Enauta Energia SA, a wholly owned subsidiary of Enauta (100%), lies in 1,500 m of water and has estimated reserves of 106 million bbl.
Aker BP to move on from dry well near Edvard Grieg, drill new North Sea well
Aker BP ASA will move to drill a new North Sea well having concluded drilling exploration well 16/1-35 S—the first in production license 1141—and finding no hydrocarbons.
The well was drilled by the Scarabeo 8 semi-submersible drilling rig about 6.5 km west of Edvard Grieg field in the central part of the North Sea and 208 km west of Sandnes in water depth of 109 m. Drilled to a vertical depth of 3,150 m subsea, the well was terminated in the Skagerrak formation from the Triassic.
The primary exploration target was to prove petroleum in Upper Jurassic reservoir rocks in the Draupne formation. The secondary target was to prove petroleum in Middle Jurassic reservoir rocks from the Vestland group.
The well encountered the Draupne formation at about 520 m, including a total of 298 m of sandstone layers with good reservoir quality.
In the secondary target, the well encountered the Vestland group of 174 m, 114 m of which was a sandstone reservoir with moderate to good reservoir quality.
The well is dry. Data acquisition has been carried out and the well has been permanently plugged.
The rig will now drill wildcat well 25/4-15 in production license 919 in the North Sea, where Aker BP is operator.
Block encounters hydrocarbons, wellbore challenges in Georgia
Block Energy PLC, London, encountered oil and gas during initial development of West Rustavi-Krtsanisi field (Project I), onshore Georgia, but encountered wellbore issues that may require changes to completion design.
Well WR-B01Za was drilled into the Middle Eocene reservoir, targeting lineations interpreted on the 3D seismic survey to represent productive sweet spots with high density of oil-bearing natural fractures, the company said in a release Feb. 28.
The well’s planned trajectory consisted of a long horizontal reservoir section intersecting the fault-fracture system. Total depth was called at 2,372 m MD, instead of the intended 2,682 m MD, due to unstable wellbore conditions across a suspected fault at about 2,275 m MD which caused escalating tool failure and lost-in-hole risk. Significant drilling fluid losses and gas and oil shows were observed while drilling beyond the problem zone, indicating a potentially productive but constrained well due to the wellbore failure.
Intermittent testing produced some dry oil with zero water cut and high gas volumes, despite the wellbore issue. “Drilling data indicates a good reservoir containing oil with significant gas,” said Paul Haywood, chief executive officer.
The well will enter an extended well test period during which oil and gas will be sold while data is acquired to optimize the completion design, which may require further drilling operations to remedy or bypass the wellbore failure and improve overall wellbore connectivity to the productive zones, the company said.
Block Energy is reviewing data gathered during drilling and testing to optimize its second Project I development well, the KRT-45ST.
PROCESSING Quick Takes
China’s 2022 refinery activity down on domestic policy, geopolitics
In 2022, Chinese refineries processed less crude oil than in 2021, the first year-on-year decline since 2000, according to the US Energy Information Administration (EIA).
Chinese refineries processed an average of 13.5 million b/d of crude oil in 2022, down 4% from the record high of 14 million b/d set in 2021, according to China’s General Administration of Customs. The sharpest reduction in crude oil processing occurred between April and August 2022, when refiners in China processed an average of 12.5 million b/d.
Chinese refineries processed more crude oil at the beginning and end of 2022. In July, refiners processed the lowest volume of crude since January 2018 (11.3 million b/d). Refining in China hit an all-time monthly high of 15.1 million b/d in September 2022, then fell slightly before rising to more than 14 million b/d in November and December.
Demand for petroleum products in China declined in 2022 in response to COVID-19 outbreaks and related mobility restrictions in major cities, including Shanghai. These restrictions significantly slowed China’s economic activity.
Lower petroleum product export quotas also reduced refining activity in China last year. China sets fuel export quotas each year, allocating a fixed amount of exports to a select few refineries, most of them state-owned. China began issuing lower export quotas around second-half 2021, and the low export quotas continued through most of 2022. The quotas kept China’s petroleum product exports below 1.5 million b/d between July 2021 and August 2022, subduing refinery demand.
According to EIA, China’s crude oil processing hit a record high in September, most likely because refiners expected China to issue new petroleum product export quotas to promote economic growth, which it did on Sept. 30. China’s petroleum product exports also increased sharply in September, possibly because the expectation of new quotas prompted refiners to use up existing export quota allocations. Once new export quotas were in place, refinery activity rose significantly during the fourth quarter. The increase in China’s refinery activity at end-2022 was partially due to increased exports, which averaged 1.7 million b/d from September through December, up an average 600,000 b/d from the first 8 months of the year.
TRANSPORTATION Quick Takes
Golar secures vessel for conversion into third FLNG
Golar LNG Ltd. has secured an option to acquire a 148,000-cu m Moss-design LNG carrier for a 3.5-million tonne/year (tpy) MKII floating LNG (FLNG) conversion. The company reports “significant progress” having been made with the conversion shipyard, procurement of long lead items, and financing as well as “strong client engagement…for potential deployment.”
The LNG carrier will cost $78 million and the converted vessel would be Golar’s third FLNG, following Hilli and Gimi. Golar expects delivery in 2025.
Conversion of the 2.5-million tpy FLNG Gimi for its 20-year contract with bp PLC in developing Greater Tortue Ahmeyim offshore Mauritania and Senegal was 92% technically complete as of Feb. 12, 2023, with the vessel on track for a first-half 2023 sail away. The bp-owned floating production, storage, and offloading vessel which needs to be commissioned ahead of Gimi is now in Singapore, having left COSCO Shipping Heavy Industry Co. Ltd.’s Qidong, China, yard last month en route to West Africa (OGJ Online, Feb. 27, 2023). It is expected to arrive on station second-quarter 2023.
Golar is in talks with prospective clients for a potential redeployment of the 2.4-million tpy FLNG Hilli once its current contract with Perenco SA and Cameroon’s state oil firm Société Nationale des Hydrocarbures offshore Cameroon ends in July 2026. On Feb. 6, 2023, Golar agreed to acquire New Fortress Energy (NFE) Inc.’s interest in Hilli for the return of 4.1 million NFE shares and $100 million in cash.
A combination of upstream technical issues and maintenance caused Hilli’s 2022 LNG production to fall 3.5% below the annually contracted 1.4-million tpy. The issues that resulted in the reduced production were resolved in fourth-quarter 2022 and FLNG Hilli has been producing to schedule since, Golar said.
Golar reported 2022 net income of $788 million, a 90% increase from the $414 million it earned in 2021.
Venture Global to sell 0.7 mtpy of Plaquemines LNG output to Excelerate
Venture Global LNG Inc. and Excelerate Energy Inc. have executed a 20-year LNG sales agreement, with Excelerate purchasing 0.7 million tonnes/year (tpy) on a free-on-board basis from Venture Global’s 20-million tpy Plaquemines LNG plant in Plaquemines Parish, La.
Ealier in February, Venture Global executed two 20-year agreements with China Gas Hongda Energy Trading Co. Ltd., one for 1 million tpy from Plaquemines LNG and another for 1 million tpy from the company’s 20-million tpy CP2 LNG plant, under development in Cameron Parish, La.
Venture Global also successfully raised the roof for the first of four 200,000-cu m LNG storage tanks at Plaquemines LNG, 9 months after final investment decision on the project. Chicago Bridge & Iron Co. performed the work.
The roof weighs 900 tons and is 294 ft in diameter. Air raising it allowed for better and safer access as well as a faster construction schedule, Venture Global explained, as the roof was erected concurrently with the 130-ft. tall shell. Eventually, the tank will include a 9%-nickel alloy inner tank and an outer wall and outer roof made from concrete to provide full containment of the LNG.
DNV launching H2Pipe Phase 2 to develop offshore hydrogen pipeline standard
DNV is launching the second phase of H2Pipe, a joint industry project (JIP) aiming to develop a new code for the design, requalification, construction, and operation of offshore pipelines to transport hydrogen, either pure or blended with natural gas. Industry is exploring ways to transport hydrogen as an additive or replacement for natural gas, but current offshore pipeline codes insufficiently address the topic, the standards and assurance body said.
Phase 2 of H2Pipe is planned to start in first-quarter 2023 and last 2 years. It will consist of a comprehensive experimental test program to enhance the understanding of the governing hydrogen embrittlement mechanisms and how hydrogen affects the integrity of the line pipe material. In addition to the experimental test campaign, Phase 2 will also include tasks such as a feasibility level design of offshore hydrogen pipelines and a risk assessment study to look at safety aspects of offshore hydrogen pipelines. DNV expects the primary outcome of Phase 2 of the JIP to be a detailed guideline offering specific guidance for use in design and repurposing of offshore pipelines for hydrogen transport.
DNV started the first phase of H2Pipe in 2021. An initial test program looking into potential degradation of steel pipe mechanical properties was carried out to fill gaps in existing knowledge and explore various test parameters and narrow down the number of variables as preparation for the main test program planned for Phase 2. The first revision of the guideline was delivered to participants the same year.
The guideline is currently at a high level, and more work is needed to develop more specific acceptance criteria, according to DNV. Phase 1 participants included Vallourec SA and Wellspun Corp.
The DNV standard for submarine pipeline systems (DNV-ST-F101) includes hydrogen as a listed transport product, but additional considerations are required to meet the target safety level for an increased use of hydrogen. A special concern in this respect is the potential detrimental influence of hydrogen on resistance to cracking in carbon steels, DNV said, explaining that to support the uptake of hydrogen as an energy carrier, it is imperative to update the standard to a level of design and material requirements that do not compromise pipeline integrity and safety.
DNV’s ‘Hydrogen Forecast to 2050’ anticipates that more than 50% of hydrogen pipelines globally (and as much as 80% in some regions) will be repurposed from existing natural gas pipeline networks, as doing so is expected to cost less than 35% of new builds.