GENERAL INTEREST Quick Takes
Pres. Biden signs Mountain Valley pipeline legislation
US Pres. Joe Biden on June 3, 2023, signed legislation that raised the nation’s debt limit and ratified and approved all permits and authorizations necessary for the construction and initial operation of Equitrans Midstream Corp.’s 303-mile Mountain Valley (MVP) natural gas pipeline. The legislation directs applicable federal officials and agencies to maintain such authorizations and requires the Secretary of the Army not later than June 24, 2023, to issue all permits or verifications necessary to complete project construction and allow for MVP’s operation and maintenance.
The legislation also divested courts of jurisdiction to review agency actions on approvals necessary for MVP construction and initial operation. The Senate passed the bill June 1 (OGJ Online, June 2, 2023).
Equitrans said it will continue to work closely with all relevant agencies in reissuing the 2-bcfd project’s few outstanding permits and “will maintain its steadfast commitment to environmental protection to ensure the responsible completion of the project’s remaining construction.” The company intends to complete construction of MVP by end-2023 at an estimated cost of $6.6 billion.
“The MVP project has gone through more environmental review and scrutiny than any natural gas pipeline project in US history, having been issued the same state and federal authorizations two and three times, only to have those authorizations be routinely challenged and vacated in court,” said Thomas F. Karam, chairman and chief executive officer of Equitrans. “Congressional involvement to legislate the approval of this project only magnifies the critical need for more robust and comprehensive permitting reform that goes beyond the important initial steps in this legislation.”
Kasawari CCS commissioning contract awarded to Petra Energy
Petronas Carigali Sdn. Bhd. contractor Malaysia Marine and Heavy Engineering Sdn. Bhd. has awarded Petra Energy Bhd.’s Petra Resources subsidiary the hook-up and commissioning contract for Petronas’s 3.3-million tonne/year Kasawari offshore carbon capture and storage (CCS) project. The contract will run from March 2023 through December 2025.
Petronas last year took final investment decision on the Kasaswari CCS project in Block SK316 200 km offshore Bintulu, Sarawak, in 108 m of water (OGJ Online, Nov. 30, 2022). Worley earlier this month won the detailed engineering and design contract for the project’s 14,000-tonne topside, jacket, bridge to the central processing platform, and subsea pipeline. Baker Hughes at the start of the year won Kasawari CCS’s compression contract (OGJ Online, Jan. 4, 2023).
Captured carbon dioxide will be injected into the depleted M1 field, 138 km from the platform. The 3-tcf Kasawari natural gas development project is expected to start production this year, with Kasawari CCS to follow in 2025.
Pembina, Marubeni advance low-carbon ammonia supply chain
Pembina Pipeline Corp. has signed a memorandum of agreement (MOA) with Marubeni Corp. to progress an end-to-end, low-carbon ammonia supply chain from Western Canada to Japan and other Asian markets. The project includes the joint development of a world-scale, low-carbon hydrogen and ammonia plant to be sited on Pembina-owned lands adjacent to its Redwater Complex in the Alberta Industrial Heartland near Fort Saskatchewan, Alta.
The companies have completed initial feasibility studies for the plant and anticipate a design capacity of up to 185,000 tonnes/year (tpy) of hydrogen, which will be converted into about 1 million tpy of low-carbon ammonia. They plan to capture “a significant amount of the CO2 emissions” with an eye towards integrated transportation and sequestration on the proposed Alberta Carbon Grid being developed by Pembina and TC Energy Corp. (OGJ Online, Oct. 19, 2022). Ammonia would be transported via rail to Canada’s West Coast for shipment.
Under the MOA, Pembina and Marubeni will focus on completing preliminary front-end engineering and design (pre-FEED), engagement with various stakeholders, including governments in Canada and Japan, and beginning talks with potential customers. Pre-FEED is expected to be completed by early 2024.
Pembina expects demand for low-carbon ammonia in Japan and other Asian markets to grow substantially, citing its efficiency as a carrier of hydrogen and use as a low-carbon fuel source.
The new project would potentially serve as an anchor development to advance the Pembina Low Carbon Complex (PLCC) planned for more than 2,000 undeveloped acres in the Alberta Industrial Heartland. Pembina describes PLCC as focused on “attracting and developing investment for innovative and emerging energy transition technologies, sustainable fuels, and chemicals, specifically low-carbon hydrogen and hydrogen carriers such as ammonia and methanol.” Within PLCC, Pembina would lease land to third parties and provide infrastructure, logistics, and shared services to tenants, including carbon capture and sequestration, depending on their needs.
Jadestone granted title transfer to NW Shelf oil
Jadestone Energy, Singapore, has received official approval from Australia’s National Offshore Petroleum Titles Administrator (NOPTA) for title transfer regarding its acquisition of bp plc’s interest in Woodside Energy-operated Cossack, Wanaea, Lambert, and Hermes oil fields on the North West Shelf offshore Western Australia.
Jadestone finalized acquisition of the 16.67% working interest in November 2022.
The fields, known collectively as CWLH fields, are part of Woodside’s North West Shelf oil project and the acquisition includes bp’s former stake in the fields, the subsea infrastructure, the Okha floating production, storage, and offtake vessel (FPSO), and a share in all abandonment liabilities estimated at $82 million.
With it, Jadestone acquires 10.4 million bbl of remaining oil reserves and resources as of Jan. 1, 2020.
Production from CWLH fields averaged 14,200 b/d for the 3 months ended 2022 (2,360 b/d net to Jadestone).
Exploration & Development Quick Takes
Petrobras finds hydrocarbons in Aram block in Santos basin presalt
Petróleo Brasileiro SA (Petrobras) found hydrocarbons through an appraisal well in the Aram block in Santos basin presalt, offshore Brazil, and will use data gathered to evaluate the discovery’s potential and assess next step activities in the area.
Well 3-BRSA-1387D-SPS, 260 km from Santos, São Paulo, at a water depth of 1,979 m, presented “a fluid of excellent quality, confirming low levels of contaminants,” the operator said. The discovery also strengthens a potential expansion of the accumulation discovered by exploration well 1-BRSA-1381-SPS in the block.
An oil-bearing interval was verified through wireline logging and fluid samples, which will be further characterized through laboratory analyses, Petrobras said in a release May 17.
Operations to drill the well to the expected depth, verify the extent of the new discovery, and characterize reservoir conditions are ongoing.
Petrobras is operator of Aram block with 80% interest. CNPC holds the remaining 20%.
Equinor drills dry hole near Troll
Equinor Energy AS drilled a dry hole in wildcat well 31/2-23 S in North Sea production license (PL) 923, according to a release by the Norwegian Petroleum Directorate June 1. The well was drilled about 3 km west of Troll field and about 120 km northwest of Bergen.
The well, the fifth in the license, was drilled in 343 m of water by the Deepsea Stavanger drilling unit to a vertical depth of 2,333 m subsea. It was terminated in the Drake formation in the Lower Jurassic.
The objective of the well was to prove petroleum in Middle Jurassic reservoir rocks in the Brent Group. The well encountered the Brent Group with a thickness of about 135 m, including sandstone layers of around 80 m with good reservoir quality. The well is dry and has been plugged. Data acquisition has been carried out.
The rig is now drilling wildcat well 31/2-24 in the same production license.
Equinor is operator at PL 923 (40%) with partners Petoro AS (20%), DNO Norge AS (20%), and Wellesley Petroleum AS (20%).
Trio Petroleum confirms oil, gas accumulation in Presidents field
Trio Petroleum Corp., Bakersfield, Calif., encountered accumulations of oil and gas in Presidents field in its 9,267-acre South Salinas project in Monterey County, Calif.
Confirmation comes from the HV-1 well, a two-mile step-out from Trio’s HV-3A discovery well that found high-quality, mid-gravity oil at depths of 3,750-5,100 ft, the company said in a release May 16.
HV-1 drilled through about 1,800 ft of the Monterey formation with major indications of oil and gas prior to reaching total depth at 6,631 ft, the company said (OGJ Online, May 1, 2023).
Well casing is being run from surface to total depth to complete the well, and well data evaluation has begun. The company expects to put HV-1 on production after finalizing completion operations and evaluation of the new data, after which it expects to have a better understanding of production rates, said Frank Ingriselli, Trio’s chief executive officer.
The HV-1 well location was chosen based on interpretation of 3D seismic data. Trio owns 85.75% working interest in the field.
Drilling & Production Quick Takes
Chevron produces first gas from Gorgon Stage 2
Chevron Australia has begun producing gas from its Gorgon Stage 2 development project offshore Western Australia.
Chevron said that the development expands the existing subsea gas gathering network of the Gorgon project and involved installation of 11 additional wells in the Gorgon and Jansz-Io fields along with offshore production pipelines and subsea infrastructure with the aim of maintaining gas supply to the LNG and domestic gas processing infrastructure on Barrow Island.
The development adds to the initial $40 billion (Aus.) spend on Australian goods and services from the project since 2009 and supports the longevity of the LNG and domestic gas production, the company said.
Chevron is operator with 47.3%. Partners are ExxonMobil (25%), Shell (25%), Osaka Gas (1.25%), Tokyo Gas (1%), and JERA (0.417%).
NuVista revises down full year production guidance on wildfire impacts
NuVista Energy Ltd., Calgary, has revised down its full year production guidance to 76,000-79,000 boe/d from 79-000-83,000 boe/d due to the impacts of the Alberta-area wildfires.
The company’s capital execution plans remain unchanged with a net capital expenditures guidance of $425-450 million, the company said in a release June 5.
Production of 71,000 boe/d is expected in this year’s second quarter, including the overall impact of the wildfires of about 11,000 boe/d. Over the year’s second half, NuVista expects an additional impact of about 1,000 boe/d due to capital project schedule delays associated with the wildfires.
Production was temporarily impacted by the wildfires in the Grande Prairie region of Alberta, as certain of the company’s fields were shut in May 5 as a precautionary measure. A gradual restart began the week of May 22 as conditions improved. Production has now reached a new record of about 80,000 boe/d, the company said.
Beach Energy delivering gas from Otway basin
Beach Energy Ltd. is now delivering additional gas into the Australian east coast gas market after connecting the offshore Otway basin Thylacine North 1 and 2 development wells to the Otway gas plant.
Four of the six Otway development wells drilled in FY2022 are now connected and have increased well deliverability for the Otway gas plant. Beach is currently reviewing its preferred approach to connect the final two wells, which will require either repair or replacement of a flowline.
The offshore Victorian-Tasmanian Otway basin drilling campaign provided a new gas discovery in the Artisan prospect along with six successful development wells—four on Thylacine gas field and two on Geographe gas field. Maximum tested flow rates in the two producing fields averaged 61 MMcfd of gas (OGJ Online, July 12, 2022).
Trillion delivers gas from fifth well on SASB field
Trillion Energy International Inc.’s Bayhanli-2 well is producing gas from SASB gas field, offshore Turkey, after a successful flow test.
Eight intervals of gas pay with a true thickness of about 21 m were perforated and tested and now are producing gas to the sales pipeline. The eight intervals within the E, D, C, A, and AA gas sand reservoirs produced at a combined rate of 11.9 MMcfd for the final flow test. The well is expected to be produced to pipeline with initial flow rates of 8-9 MMcfd.
On May 13, Bayhanli-2 reached 3,425 m total measured depth (TMD) and true vertical debt (TVD) of 1,231 m (OGJ Online, May 17, 2023).
The Uranus rig will now be moved to the Akkaya tripod to start drilling the next well, Alapli-2. Alapli-2 is a twin of a previously discovered gas pool never put onto production.
PROCESSING Quick Takes
Par Pacific takes ownership of Billings refinery
Par Pacific Holdings Inc., Houston, has completed its purchase of a 63,000-b/d refinery located along the Yellowstone River just outside of Billings, Mont., as well as certain associated midstream assets in Montana and Washington, from ExxonMobil Corp. and subsidiaries ExxonMobil Oil Corp. and ExxonMobil Pipeline Co. LLC.
Par Pacific takes full ownership of the Billings refinery, which will be operated by newly formed subsidiary Par Montana LLC, Par Pacific said.
Alongside 100% interest in the high-conversion, complex refinery that processes Western Canadian and regional US Rocky Mountain crudes, Par Pacific also acquired a 65% interest in an adjacent cogeneration plant, as well as:
- 100% interest in 2.848 million bbl of storage tankage at Billings.
- 100% interest in the 70-mile, 55,000-b/d Silvertip crude oil pipeline that allows the refinery direct access to Rocky Mountain crude grades and—via its connection to the Express pipeline—nearly all Western Canadian crudes from Hardisty and Edmonton trading hubs.
- 40% interest in the 750-mile, 65,000-b/d Yellowstone refined products pipeline to serve clean-product markets from Billings to eastern Washington.
In a late-September 2022 presentation, Par Pacific said its then-proposed acquisition would additionally include interest in the following six storage terminals that provide advantaged access to key market areas throughout Upper Rockies and Pacific Northwest:
- 100% interest in the Bozeman terminal; 89,000 bbl.
- 100% interest in the Helena terminal; 89,000 bbl.
- 50% interest in the Missoula terminal; 368,000 bbl.
- 50% interest in the Thompson Falls terminal; 140,000 bbl.
- 100% interest in the Spokane terminal; 350,000 bbl.
- Variable interest between 0-100% across six tanks in the Moses Lake terminal; 171,000 bbl.
Combined storage capacity across the refinery and logistics locations totals 4.1 million bbl.
Par Pacific also agreed to a long-term marketing arrangement under which it will supply fuel to about 250 ExxonMobil-branded retail locations.
With the acquisition now completed, Par Pacific is focusing on small-scale projects to improve throughput and reliability at the refinery to increase rates closer to nameplate capacity.
Par Pacific confirmed it continues to evaluate unidentified renewable fuels opportunities to supplement the refinery’s conventional fuel production.
LyondellBasell to test electric furnace technology for olefins production
LyondellBasell has signed a memorandum of understanding (MOU) with Chevron Phillips Chemical and Technip Energies to potentially design, construct, and operate a demonstration unit using Technip Energies’ electric steam cracking furnace technology to produce olefins.
The demonstration unit will be sited at LyondellBasell’s Houston-area petrochemicals complex in Channelview, Tex., and designed to prove Technip Energies’ technology at industrial scale. The parties expect to assemble a development team and sign a joint development agreement later this year, LyondellBasell said in a release June 1.
“Deployment of an industrial-scale electric cracking furnace is one option we are considering in this space because of its ability to reduce furnace GHG emissions by up to 90% compared to a conventional furnace,” said Peter Vanacker, chief executive officer, LyondellBasell.
Steam cracking furnaces play a significant role in the production of basic chemicals by breaking down hydrocarbons into olefins and aromatics. This cracking process requires a temperature of more than 1,500°F (850°C).
The electric steam cracking furnace technology could enable LyondellBasell to use renewable electricity as a heat source for olefins cracking in the future, reducing the greenhouse gas (GHG) footprint of its olefins production process, LyondellBasell said.
LyondellBasell said its Channelview site offers an optimal environment for the demonstration unit, in part, due to its feedstock flexibility and electric grid infrastructure.
Two olefin units at the north side of the Channelview complex manufacture ethylene, propylene, butadiene, and benzene. The south side plant uses the products to produce propylene oxide, styrene monomer, other derivatives, and gasoline-blending products.
Construction of the demonstration unit is a pre-condition for potential future construction of a full-scale unit.
TRANSPORTATION Quick Takes
Production halted at Hammerfest LNG following gas leak
Production at the Equinor Energy AS-operated Hammerfest LNG plant on the Island of Melkøya, outside Hammerfest, Norway, has stopped following a gas leak that occurred and was remedied the same day. The operator said it is “too soon” to say when production at the plant can be resumed.
The leak occurred May 31 in connection with a valve in one of the plant’s cooling circuits. The gas that leaked is used for cooling during production of LNG. The leak has been stopped, and normalization is under way, the operator said at the time.
Equinor’s emergency response organization was mobilized, and the incident was handled in collaboration with emergency services. Relevant authorities were notified. There were 98 people present at the plant when the incident occurred. All personnel are accounted for, and no injuries were reported.
Equinor’s emergency response organization has been demobilized and emergency services have since left Melkøya, the company said.
Production at the 6.5 billion cu m/year plant began in 2007 (5% of Norway’s gas export capacity). In September 2020, a turbine fire at the plant caused a 2-year shutdown during which time Equinor said extensive repairs and improvement work were completed (OGJ Online, June 2, 2022). In early May, Hammerfest LNG was offline for about 20 days “due to a problem with a heat exchanger,” Evercore ISI analysts noted in a report May 31.
Partners at Hammerfest LNG are Petoro AS, TotalEnergies EP Norge AS, Neptune Energy Norge AS, and Wintershall Dea Norge AS.
Grande Isle LNG proposes 4.2-mtpy offshore liquefaction plant
Grande Isle LNG has proposed a 4.2-million tonne/year (tpy) offshore liquefaction plant in federal waters on West Delta blocks 13 miles offshore Plaquemines Parish, La. The company expects to start Phase 1 deliveries in 2026.
The proposed port will use a platform-based modular design in 68-72 ft water depths and have natural gas pipeline access to its nearshore location. The plant will be built in two phases and consist of a crew quarters platform, two gas treatment platforms, two 2.1-million tpy liquefaction platforms, two loading platforms, one thermal oxidizer platform, and two 155,000-cu m storage and offloading vessels.
Pipeline tie-ins will be with a 20-in. OD High Point Gas Transmission LLC line and 24- and 20-in. Kinetica Partners LLC lines.
Licensing for the deepwater port will be overseen by the US Maritime Administration, with required reviews conducted by appropriate federal and state agencies.
All platforms and many of the other components will be made in Louisiana, according to the company.
New Fortress Energy Inc. last year applied for a deepwater port license to build the 2.8-million tpy Louisiana FLNG plant off Grand Isle (OGJ Online, Apr. 28, 2022).
NFE receives Mexico export authorization for Altamira Fast LNG project
New Fortress Energy Inc. (NFE) received an export permit for its Altamira floating LNG (FLNG) hub from Mexico’s Ministry of Energy (Secretaría de Energía (SENER)).
In partnership with Comisión Federal de Electricidad, Mexico’s state-owned electric utility, NFE is developing a new floating hub off the coast of Altamira, Tamaulipas. NFE will deploy multiple 1.4-million tonnes/year (tpy) FLNG units using CFE’s existing firm pipeline transportation capacity on TC Energy’s Sur de Texas-Tuxpan Pipeline to deliver feedgas volumes to NFE (OGJ Online, Nov. 2, 2022; Feb. 14, 2023).
Construction of the first unit is over 90% complete. Deployment to Altamira is expected to begin in June with operations slated to begin in this year’s third quarter.
With the permit, NFE is now authorized to export up to 7.8 million tpy of LNG through April 2028, providing ample capacity to support operations of the 1.4-million tpy FLNG LNG unit through the permitted period, the company said in an update June 2.
NFE previously received authorization from the US Department of Energy to export US-sourced LNG to Mexico and other FTA countries.
KMI to expand Gulf Coast natural gas storage
Kinder Morgan Inc. (KMI) plans to expand working natural gas storage capacity at its Markham Storage site in Matagorda County, Tex., by 6 bcf, reaching an agreement with Underground Services Markham LLC, a subsidiary of Texas Brine Co. LLC, to lease an additional cavern. The new storage will add 650 MMcfd of incremental withdrawal capacity on KMI’s nearly 7,000-mile Texas intrastate pipeline system.
Before expansion, Markham, sited near the Texas Gulf Coast, had 21.8 bcf of working gas storage capacity with peak delivery of 1.1 bcfd.
Anchor shippers have subscribed to roughly half the available capacity under long-term agreements, and the company expects commercial in-service for the project in January 2024.
Texas Brine’s site is an offshoot of its production from natural salt deposits and stores NGLs and olefins as well as natural gas for a variety of companies.
