GENERAL INTEREST Quick Takes
bp, Linde plan Texas Gulf Coast carbon capture project
bp and Linde have partnered to advance low-carbon hydrogen and provide carbon capture and storage solutions in Texas, bp said in a release May 17.
With potential start-up by 2026, the project aims to enable low-carbon hydrogen production at the company’s existing infrastructure in the Houston, Tex., area support storage of carbon dioxide (CO2) captured from other industrial facilities along the Texas Gulf Coast.
The low carbon hydrogen would be sold to customers along Linde’s hydrogen pipeline network under long-term contracts to enable production of low carbon chemicals and fuels.
The overall development will also enable capture and storage of CO2 from other large industrial facilities in the region and could ultimately store up to 15 million tonnes/year across multiple onshore geologic sites, the equivalent of taking about 3 million cars off the road each year, bp said.
bp will appraise, develop, and permit geological storage sites and its trading and shipping business aims to bring custom low carbon solutions to the project, including renewable power and certified natural gas, along with commodity trading and price risk management experience.
Tullow Oil, Capricorn Energy agree to merge
Tullow Oil and Capricorn Energy PLC have agreed to merge in an all-share combination, Tullow Oil said in a June 1 announcement.
The combine would result in a diversified pan-African upstream portfolio with low-cost producing assets and a deep portfolio of incremental high-return investment opportunities in Ghana, Egypt, Gabon, and Côte d’Ivoire, Tullow said.
Capricorn holds development, production, and exploration assets with interests in the UK, Egypt, Israel, Mauritania, Mexico, and Suriname.
The combined company would hold reserves and resources of 343 MMboe and 696 MMboe, respectively, with 2021 production of 96,000 boe/d.
Capricorn shareholders will receive 3.8068 new Tullow shares for each Capricorn share held, with Capricorn shareholders owning 47% and Tullow shareholders owning 53% of the combined company on completion. The combination is expected to be implemented through a court-sanctioned arrangement.
The combined group is expected to realize pre-tax net cash cost savings of $50 million on an annual run-rate basis by the second anniversary of the deal completion through the reduction of duplicate costs, Tullow said.
Rahul Dhir, chief executive officer of Tullow, will become chief executive officer of the combine and James Smith, chief financial officer of Capricorn, will become chief financial officer.
Simon Thomson, chief executive officer of Capricorn, will step down and become chair of the integration steering committee.
Headquarters is expected to be at Tullow’s existing offices in London with a retained premise in Edinburgh.
Completion of the deal is subject to, amongst other things, receipt of necessary antitrust or regulatory consents, governmental approvals or consents, and material pre-emption rights or similar in various jurisdictions.
EIA: Global oil production returns to within 1% of pre-pandemic levels
Although crude oil prices remain high because of low oil inventories and significant geopolitical uncertainty, the US Energy Information Administration (EIA) estimates that world production of petroleum and other liquids averaged 99.5 million b/d in May, which has returned to within 1% of its pre-pandemic level in March 2020.
In its June Short-Term Energy Outlook (STEO), EIA estimates that US production of crude oil and other liquids averaged 19.9 million b/d in May, which was within 3% of January 2020’s record high production of 20.5 million b/d. EIA also estimates that the Organization of the Petroleum Exporting Countries (OPEC) crude oil and other liquids production has returned to pre-pandemic levels. May OPEC production was 33.7 million b/d, 1% higher than OPEC production of 33.4 million b/d in the first quarter of 2020.
Furthermore, OPEC+ announced on June 2 that it will increase crude production targets by 50% for July and August. EIA then forecasts that OPEC crude oil and total liquid fuels production will increase to 34.6 million b/d in third-quarter 2022, the highest since second-quarter 2019.
However, in response to the European Union (EU) ban on seaborne imports of crude oil from Russia and previous sanctions on Russia, in this issue’s STEO, EIA now forecasts that Russia’s oil production will decrease from 11.3 million b/d in 2022 first quarter to 9.3 million b/d in 2023 fourth quarter.
“Our forecast reflects the EU’s announcement that it will impose its crude oil import ban in 6 months. We assume that about 80% of the crude oil subject to the EU import ban will find alternative buyers, mainly in Asia. Our forecast does not reflect restrictions on shipping insurance, as details regarding such restrictions were not available when we finalized this forecast on June 2. The possibility that these sanctions or other potential future sanctions reduce Russia’s oil production by more than expected creates upward risks for crude oil prices during the forecast period,” EIA explained.
After seven consecutive quarters of global oil inventory draws from third-quarter 2020 to first-quarter 2022, EIA forecasts that oil stocks in Organization for Economic Cooperation and Development (OECD) countries will generally increase but remain below 5-year average levels until fourth-quarter 2023.
Brent crude oil spot prices averaged $113/bbl in May. EIA expects the Brent price will average $108/bbl in second-half 2022 and then fall to $97/bbl in 2023.
“Current oil inventory levels are low, which amplifies the potential for oil price volatility. Actual price outcomes will largely depend on the degree to which existing sanctions imposed on Russia, any potential future sanctions, and independent corporate actions affect Russia’s oil production or the sale of Russia’s oil in the global market,” EIA said.
The US average retail price for regular grade gasoline averaged $4.44/gal in May, and the average retail diesel price was $5.57/gal. Rising prices for gasoline and diesel reflect refining margins for those products that are at or near record highs amid low inventory levels.
EIA expects gasoline wholesale margins (the difference between the wholesale gasoline price and Brent crude oil price) to fall from $1.17/gal in May to average $0.81/gal in third-quarter 2022, and expects retail gasoline prices to average $4.27/gal in third-quarter 2022. Diesel wholesale margins fall from $1.53/gal in May to $1.07/gal in third-quarter 2022, and retail diesel averages $4.78/gal in third-quarter 2022.
EIA forecasts US refinery utilization to average 94% in third-quarter 2022, up from 89.5% in first-quarter 2022 and 93% in the second quarter.
“Despite our expectation that refinery utilization will be at or near the highest levels in the past 5 years, operable refinery capacity is about 900,000 b/d less than at the end of 2019, and as a result, we do not expect total refinery output of products to reach its highest level in the past 5 years. Although we expect high refinery utilization will help bring wholesale margins down from record levels,” EIA said.
PTTEP to develop Thailand’s first CCS
PTT Exploration and Production Public Co. Ltd. (PTTEP) will develop Thailand’s first carbon capture and storage (CCS) project at Arthit offshore gas field, 230 km from Songkhla province in the Gulf of Thailand.
The feasibility study of the project recently concluded. The study covered several aspects including preliminary assessment of carbon storage capacity of targeted geological formations and corresponding conceptual development. The project is in preliminary front-end engineering and design (Pre-FEED) and is expected to start operations by 2026.
The company has set forth an emissions reduction target of net zero greenhouse gas (GHG) emissions by 2050 via its Exploration and Production (EP) Net Zero 2050 concept. This plan covers both direct emissions (Scope 1) and indirect emissions (Scope 2) of exploration and production under PTTEP’s operational control. PTTEP also has set interim targets to reduce GHG emission intensity by at least 30% within 2030 and 50% within 2040 (from base year 2020).
In addition to CCS, PTTEP is exploring opportunities in renewable energy, hydrogen, and carbon capture and utilization.
Arthit field is in Block 16A, Block 14A, Block 15A, and G8/50, with water depth of 276 ft. PTTEP is operator (80%) with partners Mitsui & Co. Ltd. (16%) and Chevron Corp. (4%).
Saudi Arabia raises July crude prices for most regions
Amid expectations of strong demand this summer and tight supply, Saudi Arabia raised July prices for its crude in most regions except the US.
Prices have risen the most for Asian buyers. Saudi Arabia raised the July official selling price (OSP) for its flagship Arab Light crude to Asia by $2.1/bbl from June, a $6.5/bbl premium above the Oman-Dubai benchmark it uses. The increase was well above the $1.5/bbl rise forecasted by most market analysts.
Oil demand in Asia is expected to increase. Saudi crude will be particularly popular with Asian refiners such as Japan and South Korea, which shunned Russian oil after the Ukrainian invasion. Meanwhile, China, the world’s largest oil importer, is expected to boost demand as it reopens some cities, including Shanghai, after a prolonged COVID-19 lockdown. However, some Asian demand for Saudi oil may be offset by continued Russian oil flows to India and China, which have been ramping up their purchases of Russian cargoes at bargain prices.
For the European market, the price of the Arab Light will also be higher. Saudi Arabia raised European buyers’ prices for grades similar to Russia’s Urals by $2.2/bbl to a $4.3/bbl premium over Brent.
Prices for US customers were kept unchanged for the second straight month.
The increase in prices for July shipments resumes a streak of hikes that started in February, which was only broken when Saudi Aramco cut June prices from record levels.
The price increase also followed the decision by the Organization of Petroleum Exporting Countries and allies (OPEC+) to boost output for July and August by 648,000 b/d, or 50% more than previously planned (OGJ Online, June 2, 2022).
Exploration & Development Quick Takes
ConocoPhillips advances delineation of Norwegian Sea discovery
ConocoPhillips Skandinavia AS drilled appraisal well 6507/5-11 in Norwegian Sea production license (PL) 891 to help delineate oil discovery 6507/5-10 S (Slagugle) (OGJ Online, Dec. 22, 2020). Collected data will be analyzed and future delineation and possible development will be considered, according to a May 30 release from the Norwegian Petroleum Directorate.
The well was drilled by the Transocean Norge drilling rig about 22 km northeast of Heidrun field, and about 270 km north of Kristiansund in 351 m of water. The well was drilled to a vertical depth of 2,273 m subsea. It was terminated in the Red Beds in the Triassic.
The primary exploration target was to delineate the discovery and achieve a better understanding of in-place and recoverable volumes for the hydrocarbon-bearing layers encountered in the well. The secondary target was to prove petroleum in Palaeocene reservoir rocks in the Tang formation.
In the primary target, the well encountered sandstone layers in the Åre formation in Lower Jurassic and Grey Beds in Upper Triassic totaling 122 m with very good reservoir quality, NPD said. No reservoir was encountered in the secondary exploration target in the Tang formation. The well is dry.
Three successful injectivity tests were conducted. Injection rate was about 1,000 standard cu m/d for each test. The tests showed good flow properties in all zones and communication in the Grey Beds between wells 6507/5-10 S and 6507/5-11.
Preliminary estimates indicate that the size of the discovery is 6-13 million standard cu m of oil equivalent.
Data acquisition and sampling have been carried out, and the well has been permanently plugged.
Transocean Norge is now drilling wildcat well 6507/4-3 S in production license 1064 in the Norwegian Sea, where ConocoPhillips Skandinavia AS is the operator.
ConocoPhillips is operator of PL 891 (80%) with partner Pandion Energy AS (20%).
SapuraOMV to plug dry well off Western Australia
SapuraOMV will plug the Kanga-1 wildcat in Dampier subbasin permit WA-412-P offshore Western Australia. The well is dry.
The company, targeting the Jurassic-age Legendre formation, held hopes for success given the prospect was on trend and to the northeast of Woodside Group’s Goodwyn-Perseus-North Rankin gas and condensate fields and to the west of Mutineer and Exeter oil fields.
Pre-drill estimates held suggested potential for up to 170 million bbl of oil.
Kanga-1 was drilled by Diamond Offshore’s Ocean Apex semisubmersible rig. The well fulfills the exploration permit work program obligations.
SapuraOMV is operator with 70% interest. Finder Energy Holdings Ltd. and Fugro Exploration Pty Ltd. each hold 15%.
Drilling & Production Quick Takes
Invictus to start Cabora Bassa drilling in July
Invictus Energy Ltd. has let an integrated well services contract to Baker Hughes for drilling operations at Cabora Bassa basin in the Muzarabani-Mbire area of Zimbabwe, scheduled to begin in July 2022, the company said in a release May 26.
Baker Hughes will provide cementing, mudlogging, wireline, drilling fluids and mud engineering, tubular running, finishing and abandonment, directional drilling and logging, liner hangers, drill bits, reservoir technical services, and project management. The scope of the contract also includes the supply and installation of wellhead equipment.
The contract comes after Invictus signed a letter of intent with Baker Hughes in February for well services in support of the company’s upcoming two-well exploration campaign at Cabora Bassa.
In March, the company signed a rig contract for Exalo Rig 202, which is expected to mobilize to Zimbabwe from Tanzania in early June.
Cabora Bassa is one of the last untested large frontier rift basins in onshore Africa (OGJ Online, Apr. 30, 2018). Invictus Energy’s principal asset is SG 4571 which contains the Mukuyu prospect, which is the largest undrilled prospect onshore Africa and is independently estimated to contain 8.2 tcf and 247 million bbl gas condensate (gross mean unrisked basis). Invictus is awaiting an updated independent prospective resources estimate incorporating new CB21 seismic results.
Invictus Energy is operator at Cabora Bassa with 80% interest.
Equinor lets contract for semisubmersible Transocean Spitsbergen
Equinor Energy AS has let a contract for the harsh environment semisubmersible Transocean Spitsbergen to Transocean Ltd. for work offshore Norway.
The firm part of the contract extension, with an estimated backlog of $181 million, is expected to begin in October 2023 and conclude in April 2025.
The estimated firm backlog excludes revenue associated with performance incentives, additional services, and option periods provided for in the contract.
This contract follows contract extensions Equinor granted in May for integrated drilling and well services as well as additional services for work on Equinor-operated fields on the Norwegian continental shelf (OGJ Online, May 9, 2022).
PROCESSING Quick Takes
Plock Olefins 3 complex to feature enhanced automation, efficiency controls
Polski Koncern Naftowy SA (PKN ORLEN) has let a contract to ABB Ltd. to provide a suite of automation and safety systems to improve production, energy, and environmental efficiency at the proposed Olefins 3 complex to be built as part of the operator’s Petrochemicals Development Programme (PDP) at the existing 16.3-million tonnes/year (tpy) dual refining and petrochemical manufacturing site in Plock, Poland.
As part of the contract, ABB will install its proprietary ABB Ability System 800xA distributed control system (DCS) across the entire Olefins 3 project to enable PKN ORLEN’s constant monitoring and analysis of plant productivity, the service provider said in a June 1 release.
Use of the ABB Ability System 800xA control architecture will allow PKN ORLEN, in real time, to maximize asset performance, increase production yield, manage power consumption, ensure product quality, and optimize process efficiency throughout the new complex, ABB said.
In line with PKN ORLEN’s objective to achieve a 30% reduction in carbon dioxide emissions per tonne of product at the site, the continuous stream of data delivered by the DCS additionally will equip the operator to make more informed, accurate decisions that drive efficient use of energy across the complex, including maintaining tight controls over raw-material consumption, plant energy levels, and waste by-products, according to ABB.
Alongside the DCS, ABB said it will also deliver several systems aimed at ensuring the Olefins 3 complex operates at optimum safety levels. These new systems—which will be complemented by an unidentified industrial cybersecurity solution focused on mitigating cyberthreats to the complex—include a burner management system, an emergency shutdown system, and a high-integrity pressure protection system.
Working alongside the Olefins 3 complex’s main engineering, procurement, construction, and commissioning contractors Hyundai Engineering Co. Ltd. and Técnicas Reunidas SA to complete installation of the new systems, ABB said it will employ its proprietary Adaptive Execution project methodology, which harnesses virtual engineering and digitalization elements to deliver a streamlined, standardized process that can lower delivery time by up to 30%, startup hours by up to 40%, and overall automation-related capital costs by up to 40%.
Europe’s largest petrochemical project in 20 years, as well as PKN ORLEN’s largest capital investment ever, the 13.5-billion zloty Plock Olefins 3 expansion comes as an initiative to advance a pillar under the operator’s ORLEN 2030 strategy specifically involving maximizing profitability of its existing operations to increase overall competitiveness and improve energy efficiency.
The grassroots Olefins 3 complex will include construction of a new 740,000-tonnes/year (tpy) steam cracker, the upgrade of an existing 300,000-tpy ethylene unit, and the shuttering of Plock’s more than 40-year-old, original 340,000-tpy ethylene unit.
Designed to increase Plock’s ethylene production capacity by 60% to 1.04 million tpy from 640,000 tpy, the Olefins 3 project also will include construction of five additional units for production of ethylene oxide, ethylene glycols, pyrolysis gasoline, ethyl tertbutyl ether, and styrene to expand the site’s repertoire of derivates supply to domestic and export markets.
Once in operation, the Olefins 3 expansion will increase the ORLEN Group’s share in the broader European petrochemical market to 6.4% from a current 5%, according to the operator’s website.
Due for mechanical completion in 2024, PKN ORLEN said the Olefins 3 complex remains on schedule for start of commercial production in early 2025.
TRANSPORTATION Quick Takes
Equinor restarts production at Hammerfest LNG
Equinor Energy AS has restarted production at Hammerfest LNG nearly 2 years after a fire broke out at the plant in September 2020, and during which time extensive repairs and improvement work were completed, the company said in a release June 2. The first liquified natural gas is on tank at the liquefaction plant on Melkoya Island in northern Norway, the operator continued.
Citing “continuing consequences from COVID-19 and operational restrictions,” the operator had previously moved the anticipated start date a number of times to allow more time to prepare for safe start-up and operations.
Norway supplies gas to Europe, and the volumes from Hammerfest LNG account for more than 5% of Norwegian gas exports, the company said. During normal production, Hammerfest LNG delivers around 6.5 billion cu m/year, equivalent to the annual gas demand of 6.5 million European households, according to Equinor.
Repairs of sophisticated equipment and compressors have been performed, in addition to a scheduled turnaround and ordinary maintenance. More than 22,000 components have been checked, and 180 km of electric cables have been replaced.
The plant receives gas through a 143-km pipeline from Snøhvit field in the Barents Sea. Arctic Voyager, Arctic Lady, and Arctic Princess LNG tankers are anchored outside Melkøya, ready to receive new cargoes from Hammerfest LNG, Equinor said. In full production, a ship is expected to leave Melkøya about every 5 days.
Partners at Hammerfest LNG are Petoro AS, TotalEnergies EP Norge AS, Neptune Energy Norge AS, and Wintershall Dea Norge AS.
Freeport LNG requests Train 4 in-service date extension
Freeport LNG Development LP has requested a 26-month extension from the US Federal Energy Regulatory Commission (FERC) to place its 5.1-million tonne/year (tpy) Train 4 in service. The request was made well in advance of the already established May 17, 2026, deadline, Freeport having recognized that the project’s 48-56 month construction timeline would prevent meeting that date.
The company also noted that its inability to meet the 2026 deadline was impeding efforts to structure project financing and reach a final investment decision. The requested new deadline is Aug. 1, 2028, with Freeport LNG asking that FERC grant the extension by Sept. 15, 2022.
Construction of Train 4 has not yet begun, due in large part to delays stemming from the COVID-19 pandemic, Freeport LNG said. As these effects have waned, however, and LNG demand picked up, the company says it has begun actively marketing Train 4 capacity to potential off-takers, particularly in European markets, and is in negotiations with “several” potential customers.
Freeport LNG had originally selected KBR Inc. for Train 4’s engineering, procurement, and construction (EPC) after conducting a year-long competitive bidding and bid evaluation process. KBR’s decision to exit the LNG EPC business, however, has forced Freeport LNG to begin a new EPC bidding process, which it did earlier this month. The company expects to receive firm price and schedule proposals for the Train 4 project in early fourth-quarter 2022 and make a final award shortly thereafter.
Train 3 began commercial operation in May 2020, bringing the plant’s total capacity to 15.3 million tpy. Train 4’s original in-service deadline was May 17, 2023, but in September 2020 it received the extension to May 2026.
Freeport LNG is on Quintana Island, Tex.
Sempra to sell RWE 2.25 mtpy of LNG from Port Arthur
Sempra Infrastructure has agreed to sell RWE Supply & Trading 2.25 million tonnes/year (tpy) of LNG on a 15-year, free-on-board basis from Sempra’s 13.5-million tpy Port Arthur LNG Phase 1 project under development in Jefferson County, Tex. Sempra and RWE also agreed to work toward a broad framework for reduction, mitigation, and reporting of greenhouse gas emissions associated with deliveries of LNG from Port Arthur LNG, including the use of responsibly sourced natural gas as part of the project’s feed gas supply and renewable energy as part of its power mix.
Phase 1 of Port Arthur LNG is fully permitted and will include two liquefaction trains and two 160,000-cu m LNG storage tanks.
The heads of agreement reached between the two companies are preliminary, non-binding arrangements, and the development of Port Arthur LNG remains subject to reaching definitive agreements, maintaining all necessary permits, finalizing engineering and construction arrangements, obtaining financing and incentives, and reaching a final investment decision.
Sempra has also entered an MoU with Entergy Louisiana, a subsidiary of Entergy Corp., to develop options to accelerate deployment of renewable energy to power its US Gulf Coast operations. Sempra’s proposed Hackberry Carbon Sequestration site in southwest Louisiana will have the potential to sequester up to 2 million tpy of carbon dioxide from LNG plants and other industrial sites in the region (OGJ Online, May 23, 2022).
Argentina tenders EPC for Vaca Muerta gas pipeline
State-owned Energia Argentina has launched an engineering, procurement, and construction tender for the 563-km (350-mile) Nestor Kirchner natural gas pipeline.
The 24-million cu m/day (847-MMcfd) pipeline would move gas from Vaca Muerta shale in Neuquen province to Salliquelo, Argentina, west of Buenos Aires.
Bids for Stage 1 of the project, which the Argentine government says would increase transport capacity from Vaca Muerta by 25%, are due July 8, 2022.
State-owned Integracion Energetica Argentina SA earlier this year tendered for pipe to build Stage 1 (OGJ Online, Feb. 24, 2022).
ADNOC orders three more newbuild LNG carriers
ADNOC Logistics & Services, the shipping and maritime logistics arm of the Abu Dhabi National Oil Co. (ADNOC) has purchased three additional 175,000-cu m newbuild LNG vessels. ADNOC announced in April 2022 that it would acquire two newbuild vessels, bringing the total number ordered to five, with delivery scheduled 2025-26.
All five vessels will be built at Jiangnan Shipyard in China. Jiangnan Shipyard was previously commissioned by ADNOC in 2020 to build five very large gas carriers (VLGC) for AW Shipping, ADNOC L&S’s joint venture with China’s Wanhua Chemical Group.
ADNOC L&S’s current LNG vessels have a capacity of 137,000 cu m.
Over the past 24 months, ADNOC L&S has acquired 16 deepsea vessels, including eight 2-million bbl very large crude carriers in 2021 (OGJ Online, Apr. 14, 2021). The company also acquired six product tankers, and the five VLGC for AW Shipping.
ADNOC last month awarded McDermott International a front-end engineering and design contract for its planned 9.6-million tonne/year LNG plant in Fujairah, UAE (OGJ Online, May 13, 2022).