GENERAL INTEREST Quick Takes
Chevron signs MOU to join Talos, Carbonvert Bayou Bend CCS project
Chevron USA Inc., through its Chevron New Energies division, signed a memorandum of understanding (MOU) with Talos Energy Inc., through its Talos Low Carbon Solutions division, and Carbonvert Inc. to join the companies in an expanded joint venture to develop the Bayou Bend CCS offshore carbon capture and sequestration (CCS) hub.
In 2021, a joint venture between Talos and Carbonvert (Bayou Bend CCS) won the bid for the Texas General Land Office’s (GLO) Jefferson County, Tex. carbon storage lease in state waters offshore Beaumont and Port Arthur (OGJ Online, Aug. 25, 2021). Based on Talos’s preliminary understanding of the rock and fluid properties of 40,000-gross acre site’s saline reservoirs, it expects to ultimately sequester 225-275 million tonnes of carbon dioxide from industrial sources in the area.
Under the terms of the MOU, Talos and Carbonvert would contribute the Bayou Bend CCS lease to an expanded JV including Chevron in exchange for consideration of cash at closing and capital cost carry through final investment decision (FID). Upon closing of the JV, equity interests would be 25% Talos, 25% Carbonvert, and 50% Chevron. Talos would remain as operator.
Creation of the proposed JV is subject to negotiation of definitive agreements with customary closing conditions, including regulatory approval.
ExxonMobil earnings down on $3.4-billion Russian asset impairment
Exxon Mobil Corp. released its first-quarter 2022 earnings estimate of $5.5 billion, compared with $8.9 billion in fourth-quarter 2021. Results included an unfavorable identified item of $3.4 billion associated with the company’s planned exit from Russia Sakhalin-1 in response to Russia’s war in Ukraine. First-quarter capital and exploration expenditures were $4.9 billion.
First-quarter 2022 upstream earnings were $4.5 billion compared with $6.1 billion in fourth-quarter 2021. Excluding identified items, earnings were $7.7 billion, an increase of $1.1 billion from the previous quarter, primarily due to higher liquids prices and lower expenses, partly offset by lower volumes driven by weather-related impacts, fewer days in the quarter, price entitlement effects, and divestments.
First-quarter 2022 downstream earnings were $300 million compared with $1.5 billion in fourth-quarter 2021. Improved industry fuels refining margins and lower expenses were partially offset by lower basestock margins and lower volumes, driven by higher turnaround activity.
Global refining margins improved from the fourth quarter despite softening seasonal demand, higher natural gas prices in Europe, and lagging jet demand recovery. By the end of the first quarter, industry margins improved to levels above the 10-year range, with the tight supply/demand balance expected to persist. While average basestock margins declined from the prior quarter, pricing in April is catching up to rising feedstock costs.
First-quarter 2022 chemical earnings were $1.4 billion compared with $1.9 billion in fourth-quarter 2021.
Production was 3.7 MMboe/d, down 4% from fourth-quarter 2021 due to weather-related unscheduled downtime, planned maintenance, lower entitlements associated with higher prices, and divestments. Excluding entitlement effects, government mandates, and divestments, oil-equivalent production was down 2%.
Liquids volumes were down 119,000 b/d, while natural gas volumes were down 132 MMcfd.
Production in the Permian basin reached 560,000 b/d at the end of the quarter. The company said it remains on track to deliver a production increase of 25% this year versus full-year 2021, and to eliminate routine flaring by yearend.
Pioneer exec: Many US output forecasts are way too high
Pioneer National Resources Co. Chief Executive Officer Scott Sheffield said May 5 he is growing more convinced that oil prices will remain high for the foreseeable future because companies won’t be able to grow production at the pace some observers are expecting.
Asked on Pioneer’s first-quarter earnings call about his outlook for US oil production at end 2022, Sheffield told analysts and investors he isn’t in the camp that is forecasting a year-over-year increase of 1 million b/d or more. Pointing to data that shows rig counts are climbing but overall production is flat, Sheffield said too many factors are conspiring to keep output from growing as much as some in the market and watching the market would like.
“We should have already seen some production growth…I think too many think tank firms are way too high on US production,” he said. Add on “what’s happening now in regard to labor constraints, frac fleet constraints, inflation constraints…I just think it’s going to be tough to hit some of the numbers,” he continued.
Sheffield characterized Pioneer’s production levels – nearly 638,000 boe/d in the first quarter versus 687,143 in a bumper fourth quarter, and an expected 623,000-648,000 boe/d in the second quarter – as “resilient” and said he and his team remain focused primarily on returning capital to the company’s shareholders. The board authorized a base-plus-variable quarterly dividend totaling $7.38/share, which was nearly double first-quarter’s payout and which represents an annualized yield of about 13%. For the quarter, Pioneer posted a net profit of $2.0 billion compared to a small loss in the prior-year period and generated nearly $2.6 billion from operations versus $377 million in early 2021.
Pioneer’s production was disrupted in the first quarter by the outage of a supplier’s sand mine, an event that has carried over to the second quarter. To help offset those shortfalls and stay on track with annual goals, the company has temporarily added a frac fleet. For the year, it plans to run an average 22-24 rigs in the Midland basin and place 475-505 wells on production.
Petronas, PTTEP to withdraw from Yetagun field, offshore Myanmar
Petronas Carigali Sdn. Bhd. and PTT Exploration and Production Public Co. Ltd. (PTTEP) will withdraw from Blocks M12, M13, and M14 in Yetagun gas field, offshore Myanmar, and from the Taninthayi Pipeline Co. LLC (TPC).
The Yetagun project is in the Gulf of Moattama. Total sales volume from the project in 2021 averaged 17 MMscfd natural gas and about 560 b/d condensate. TPC delivers gas from the Yetagun project to Thailand.
PTTEP said the withdrawal is part of the company’s portfolio management to refocus on projects that support energy security for the country. Petronas decided to withdraw following a techno-commercial review in alignment with asset rationalization for a portfolio that fits growth ambitions amid the changing industry environment and accelerated energy transition.
Petronas subsidiary PC Myanmar (Hong Kong) Ltd. (PCML) was operator of the Yetagun gas project since 2003, where it held 40.9% participating interest. Other partners included Myanma Oil & Gas Enterprise (20.5%), Nippon Oil Exploration (Myanmar) Ltd. (19.3%), and PTTEP (19.3%).
PTTEP’s 19.31% shares in TPC will be allocated proportionately to the remaining shareholders with no commercial value and will be effective upon regulatory approval.
Exploration & Development Quick Takes
ConocoPhillips submits PDO for Eldfisk North project
ConocoPhillips Skandinavia AS submitted a plan for development and operation (PDO) for the Eldfisk North project to the Ministry of Petroleum and Energy. First production is expected in 2024.
The project is targeting additional resources in Eldfisk field. Development concept is a three-by-six slot subsea production system (SPS) with 14 wells, where nine are producers and five are water injectors. Eldfisk North will be tied back to the Eldfisk complex in the North Sea.
Resource potential of 50-90 MMboe is estimated. The new greenfield infrastructure will lie about 7 km north of the Eldfisk complex.
Total capital investment is estimated to be $1.2 billion.
Eldfisk field was discovered in 1970 and original PDO was approved in 1975. A new PDO was approved for the Eldfisk II redevelopment project in 2011. The reservoir is comprised of fractured chalk containing mainly oil, similar to surrounding fields in the Greater Ekofisk area.
ConocoPhillips Skandinavia AS is operator with 35.11% interest. Partners are TotalEnergies EP Norge AS 39.896%, Vår Energi AS 12.388%, Equinor Energy AS 7.604%, and Petoro AS 5%.
Energean makes gas discovery offshore Israel
Energean plc is evaluating development options for a commercial discovery made at the Athena exploration well, offshore Israel. Preliminary analysis shows recoverable gas volumes of 8 bcm (283 bcf, 51 MMboe) on a standalone basis, while the discovery also derisks an additional 50 bcm (1.8 tcf, 321 MMboe) of mean unrisked prospective resources across Energean’s greater Olympus area (total 58 bcm, 372 MMboe including Athena), the company said in a May 9 release. The well has been suspended as a future producer.
The Athena exploration well was drilled on Block 12 (Energean Israel, 100%), about 20 km from Karish and 20 km from Tanin A, in a water depth of 1,769 m.
A gross hydrocarbon column of 156 m was encountered in the primary target (A, B, and C sands). Commercial hydrocarbons were not discovered in the deeper secondary target (D sands).
Additional analysis will be undertaken to refine the full resource potential (including volumes within thinner sands between the main reservoir units) and to confirm the liquids content.
The well could be commercialized in the near-term via tie-back to the Energean Power FPSO, or it could form part of a new Olympus area development, the company said. Olympus is Energean’s newly defined area which includes Athena, plus the undrilled prospects on Block 12 and the adjacent Tanin lease.
The Stena IceMAX drilling rig has moved to the Karish Main-04 appraisal well, of which the top hole has already been drilled. The rig will then complete the Karish North development well. A decision on whether to drill the optional wells (Hermes, Hercules) is expected at the end of this year’s second quarter.
Vali partners execute gas tie-in agreement
The joint venture operated by Vintage Energy Ltd. has executed a tie-in agreement with the South Australian Cooper basin JV headed by Santos Ltd. that provides for connection of the Vali gas flowline into the Cooper basin pipeline network.
The agreement also provides for ongoing receipt of Vali gas to the Moomba processing plant in South Australia.
The agreement marks completion of all commercial arrangements required for gas produced from Vali field in southwest Queensland permit ATP2021 to flow to Moomba to be processed and supplied for sale to AGL Energy under the sales agreement signed in March.
The signing triggered the first $5 million (Aus.) prepayment of three equal tranches to the Vintage JV from AGL (totaling $15 million) due on achievement of milestones as the project moves to first gas.
These funds will be applied to the work program to bring Vali on stream, scheduled for mid-2022.
Vali field was discovered in 2020 and has independently assessed 2P reserves of 101 petajoules of gas.
Vintage is operator with 50% interest. Metgasco Ltd. and Bridgeport (Cooper basin) Pty Ltd. each hold 25% interest.
Drilling & Production Quick Takes
LLOG to repurpose GoM floating production unit
LLOG Exploration Co. LLC will develop the Salamanca floating production unit (FPU) by refurbishing a previously decommissioned Gulf of Mexico production unit, the company said in a release May 4.
The FPU will be on Keathley Canyon (KC) 689 in about 6,400 ft of water and serve as the collection point for production from the joint development of the Leon discovery in KC blocks 642, 643, 686, and 687, as well as from Castile discovery in KC 736.
By modifying a previously built unit instead of constructing a new one, the company bypasses emissions of new construction, and reduces the time and cost to bring the discoveries online, LLOG said.
The Leon and Castille discoveries are expected to be jointly developed through a total of three subsea wells with initial production tied back to the Salamanca FPU, with design capacity of 60,000 b/d and 40 MMcf natural gas. Two of the initial three development wells are planned for Leon field and one for Castile field. Initial production from the joint development is expected mid-2025.
Major topside repurposing and modifications will be done in the US. Regulatory approvals to proceed with development have been received.
Leon was discovered by Repsol in 2014 on KC 642, about 250 miles southwest of New Orleans in 6,000 ft of water. The discovery well was drilled to a total depth of 32,000 ft and encountered nearly 700 ft of high-quality net oil pay in multiple sands in the Lower Tertiary.
The Castile discovery was drilled on KC 736 in over 6,500 ft of water to a total of over 31,000 ft and encountered nearly 400 ft of high-quality net oil pay, also in the Lower Tertiary.
LLOG will be operator. Partners are Repsol E&P USA Inc. and Beacon Offshore Energy LLC.
Apex connects Fajr well in southeast Meleiha concession
Apex International Energy Management LLC connected the Fajr-8 development well in the southeast Meleiha (SEM) concession in Egypt’s Western Desert to production infrastructure after the well tested at a rate of 2,440 b/d with negligible water. Production began May 8.
The well, the fifth producing well in Fajr field since the commercial discovery was approved for development by the Minister of Petroleum and Mineral Resources in 2021, encountered 98 ft of high-quality oil pay in sandstone of the Bahariya formation.
Together with three producing Farah wells and one Mashreq well, total SEM production is expected to increase to 6,000 b/d from 4,300 b/d. All wells produce from intervals less than 5,000 ft.
Farah Petroleum Co., the joint venture operating company of Apex and the Egyptian General Petroleum Co., is operator.
Origin Energy JV outlines Stage 3 Beetaloo program
The joint venture of Origin Energy Ltd. and Falcon Oil & Gas Ltd. modified the work program for Stage 3 of the Beetaloo basin project onshore Northern Territory.
The program now includes:
- Acquisition of a 58 km line of high spec 2D seismic on the Amungee NW-1H well lease area.
- Drilling of one 1,000 m horizontal well on the Amungee NW-1H pad targeting the Amungee Member (formerly the mid-Velkerri B shale).
- A step out location about 10 km from the pad to drill a vertical pilot well and a 1,000 m horizontal well also targeting Amungee Member B shale.
- A 15-stage fracture stimulation on both horizontal wells.
- An extended production test of 90-180 days on each well.
There will be follow-up core and log analysis of the preliminary evaluation of 2021 Velkerri 76 well results and further evaluation of Kyalla 117 N2-1H well results to better understand issues encountered during the 2021 test program.
The primary objective of the new wells is to obtain a production rate over the first 30 days of 2-3 MMcfd of gas to support a multi-well pilot program in 2023-2024.
Secondary objectives include characterizing the natural fracture network and its complexity as well as integrating the well data and seismic data to assess the merits of future 3D surveys in the Beetaloo.
PROCESSING Quick Takes
Contra Costa County gives green light for refinery conversions
Marathon Petroleum and Phillips 66 can move ahead with plans to convert existing refineries to produce renewable fuels.
California’s Contra Costa County Board of Supervisors approved land use permits May 3 for both companies, and approved Marathon’s final environmental impact report (FEIR), concluding the required environmental review process under the California Environmental Quality Act. Phillips 66 was granted FEIR approval in March.
The county’s Planning Commission voted 6-0 on Mar. 30 to approve the permit but appeals by project opponents triggered a special meeting and final vote by the Board of Supervisors.
Marathon Petroleum has plans to convert its now-idled Martinez, Calif., refinery into a renewable fuels production site. The reconfigured refinery is expected to produce 260 million gas/year of renewable diesel in second-half 2022, with pretreatment capabilities to come online in 2023, and expanded production capacity to 730 million gal/year by end 2023.
Phillips 66’s Rodeo Renewed project envisions converting the 120,000-b/d portion of its San Francisco refining complex in Rodeo, Calif., into a renewable fuels refinery. Following the vote, the Phillips 66 said it expects to make final investment decision on the project “in the coming weeks.”
With Rodeo Renewed, Phillips 66 intends to use a variety of renewable raw materials—fats, oils, and greases—to produce lower-carbon transportation fuels beginning in early 2024.
The converted refinery stands to have an initial production capacity of 800 million gas/year (50,000 b/d) of renewable diesel, renewable gasoline, and sustainable aviation fuel.
Angola’s new Cabinda refinery passes equipment testing phase
Core equipment for the first phase of a grassroots modular refinery under development by the government of Angola’s Sonangol EP and partner Gemcorp Capital LLP has completed necessary testing for approved delivery to and setup at its final destination on the Malembo plain, 30 km north of Cabinda, in the country’s province of Cabinda.
Completed on May 2 at VFuels LLC’s fabrication site in Houston, factory acceptance testing verified the modular equipment produced and packaged meets functionality and intended objectives for the refinery, clearing the way for shipment to and assembly at the project site.
Tested equipment included the newly constructed 30,000-b/d crude oil distillation unit— the largest single-train modular unit of its kind built to date globally—which forms an integral part of the refinery’s $350-million first phase. Alongside a kerosine treating unit, Phase 1 also will feature a desalinator, pipelines, a conventional float anchoring system, and a more than 1.2-million bbl crude oil storage terminal, according to Sonangol and VFuels.
Atanas Bostandjev, Gemcorp’s chief executive officer, confirmed the refinery is scheduled for startup this year.
Approved in November 2020 at a Phase 1 investment of $220 million, the overall $1-billion Cabinda refinery project will involve future 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.
The fully completed 60,000-b/d Cabinda refinery—the first private investment of its kind in Angola—will be jointly owned by Gemcorp (90%) and Sonangol (10%).
Once fully operable, the refinery will produce gasoline, diesel, LPG, fuel oil, Jet A1, and kerosine.
TRANSPORTATION Quick Takes
Genesis to expand CHOPS GoM crude pipeline, build new 105-mile system
Genesis Energy LP plans to invest about $500 million over the next 3 years to expand its pipeline system and build a new pipeline in the deepwater Gulf of Mexico (GoM). The company plans to expand capacity of its 600,000-b/d Cameron Highway Oil Pipeline System (CHOPS) and build a new 105-mile pipeline, known as SYNC.
SYNC will connect the Walker Ridge area of the GoM directly to CHOPS, the Garden Bank 72 platform in Beacon Offshore Energy (BOE) LLC’s Shenandoah development serving as the anchored production site. Shenandoah is in Walker Ridge Blocks 51, 52, and 53 and Genesis expects first deliveries of about 100,000 b/d in late 2024 or early 2025. The second upstream development to be served by SYNC, Salamanca, is operated by LLOG Exploration Co. LLC across multiple blocks in the deepwater area of Keathley Canyon, with first deliveries of oil anticipated in early to mid-2025.
Genesis says it is also in early talks with undisclosed operators to transport incremental production of nearly 150,000 b/d. These operators would consider accessing a portion of capacity from the company’s new pipeline, effective as early as 2024.
Extending along the Outer Continental Shelf of the Gulf of Mexico, the 380-mile CHOPS pipeline delivers crude oil from deepwater oil fields to markets on the Texas Gulf Coast.
Golden Pass, Magnolia LNG get additional export authorizations
The US Department of Energy (DOE) has issued two long-term orders authorizing a total of 500 MMcfd of additional natural gas exports from 18-million tonne/year (tpy) Golden Pass LNG in Sabine Pass, Tex., and 8.8-million tpy Magnolia LNG in Lake Charles, La. The orders allow Golden Pass to export an additional 350 MMcfd and Magnolia to export an additional 150 MMcfd to any country not prohibited by US law or policy.
DOE had previously issued long-term non-free trade agreement (FTA) export orders for the majority of the projects’ capacities: Magnolia LNG’s 1.08 bcfd in 2016 and Golden Pass LNG’s 2.21 bcfd in 2017. The new orders align the projects’ respective export authorizations to additional capacity the Federal Energy Regulatory Commission approved for the projects.
Golden Pass, jointly owned by ExxonMobil Corp. and Qatar Petroleum International Ltd., is under construction, with first exports expected in 2024. Magnolia LNG, owned by the Glenfarne Group LLC, is still in its planning stages but expected to begin production by 2026.
US LNG exports have recently reached new highs of about 12 bcfd and are expected to grow to more than 13 bcfd by end 2022 as additional export capacity comes online. In 2024, when construction on Golden Pass LNG—the eighth US LNG export plant—is completed, US LNG peak export capacity will further increase to an estimated 16.3 bcfd.
Second Wilhelmshaven LNG terminal begins open season
Tree Energy Solutions (TES) GMBH is holding an open season to fast-track LNG imports into Europe through its planned Wilhelmshaven regasification terminal. The open season runs through May 25, 2022.
TES is planning for initial capacity to import as much as 16-20 billion cu m/year starting in 2025. The terminal will be connected by Open Grid Europe (OGE) GMBH’s 42-in. OD pipeline to the European natural gas grid. Terminal and pipeline capacity may be expanded through integration of further LNG tanks and commissioning of a second export pipeline, TES said.
The Wilhelmshaven terminal will include six ship berths and 1.6 million cu m of storage using eight onsite tanks, of which four will be available during the initial stage. In addition to the OGE connection, the terminal will offer direct access to salt cavern storage options at Etzel, Germany, and proximity to the grid currently delivering production from Groningen field, which is in the process of being retired.
To help decarbonize Germany and neighboring markets, from 2027-28 TES’s Wilhelmshaven regasification terminal will, as part of the Green Wilhelmshaven energy hub, increasingly be reserved for imports of fossil-free green gas such as hydrogen, according to the company. Green hydrogen produced by TES at Wilhelmshaven would be transported through connections with the H2Ercules project.
OGE is developing H2Ercules with RWE AG as a series of hydrogen production, storage, and import terminals in northern Germany to be connected with consumers in the west and south. The project plans for as much as 1 Gw of electrolyzer capacity and 1,500 km of pipeline.
TES will also build carbon export infrastructure as part of the hub, connecting it to OGE’s CO2 transportation network.
TES’s project is separate from Uniper SE’s LNG and hydrogen development, also in Wilhelmshaven.
Tellurian posts first-quarter net loss of $67 million
Tellurian Inc. incurred a net loss of about $67 million for first-quarter 2022, but generated $26 million in revenues from natural gas sales in the quarter on a production increase of about 24% compared to the previous quarter. Revenues from natural gas sales for the year-ago period were $8.7 million.
The company produced 6.1 bcf of natural gas for the quarter compared to 4.9 bcf in fourth-quarter 2021. Tellurian’s upstream assets include 13,521 net acres and interests in 82 producing wells as of Mar. 31.
The company said Driftwood LNG, the company’s flagship 27.6 million tonne/year liquefaction plant in Calcasieu Parish, La., is on schedule for LNG production in 2026. No other updates were given. Bechtel Oil, Gas, and Chemicals Inc. was previously given notice to proceed, and construction has begun.
In February, Executive Chairman Charif Souki said the project would begin construction regardless of whether full Phase 1 financing was in place. A final investment decision is pending.