OGJ Newsletter
GENERAL INTEREST Quick Takes
ConocoPhillips sets preliminary 2022 capex at $7.2 billion
ConocoPhillips expects companywide 2022 capital expenditures of $7.2 billion, which reflects the addition of Shell’s Permian basin properties, including the previously announced expected 2022 capital expenditures and production associated with that $8.6-billion transaction (OGJ Online, Sept. 20, 2021).
Expected 2022 annual average production is 1.8 MMboe/d, representing low single-digit percentage underlying growth versus pro forma 2021, and including expected annual production from the recent Permian transaction of about 200,000 boe/d. Guidance also includes the impact of the conversion to 3-stream from 2-stream reporting for volumes acquired from Concho Resources and a planned convention change to include production from Libya in guidance beginning in 2022.
The 2022 capital expenditures include $700 million associated with the Permian transaction. Some 60% of total planned capital will be directed to the Lower 48 for short-cycle investment across the company’s extensive, high-quality unconventional asset base. About 40% will be allocated toward mid- and longer-cycle projects across the company’s Alaska and international regions, including ongoing project and development activity in Alaska, a second central processing facility in the Montney play, bolt-on developments in Asia Pacific, and both project and development activity in Norway.
Some $200 million will be allocated toward energy transition efforts aimed at accelerating the reduction of the company’s Scope 1 and 2 emissions and evaluating potential investments in end-use (Scope 3) emissions-reduction investments. The planned expenditures include production efficiency measures, methane and flaring intensity-reduction initiatives, asset electrification projects, and investments in several early-stage low-carbon technology opportunities such as CCUS and hydrogen.
Return of capital to shareholders in 2022 is expected to reach $7 billion, representing a 16% increase versus 2021.
Additional 2022 guidance is expected with the operator’s fourth-quarter 2021 earnings release in early February 2022.
Esso lets subsea contract for Stabroek block project
ExxonMobil Corp. affiliate Esso Exploration and Production Guyana Ltd. has let a contract to TechnipFMC to supply the subsea production system for the Yellowtail development in the Stabroek block offshore Guyana.
Subject to government approvals and final project sanction, TechnipFMC will provide project management, engineering, manufacturing, and testing capabilities to deliver the overall subsea production system. The scope includes 51 enhanced vertical deepwater trees and associated tooling, as well as 12 manifolds and associated controls and tie-in equipment.
Yellowtail-1 was the fifth discovery in the Turbot area that includes Tilapia, Turbot, Longtail, and Pluma discoveries. It is expected to become a major development hub (OGJ Online, Apr. 18, 2019). The well encountered 292 ft of oil-bearing sandstone reservoir and was drilled to 18,445 ft in 6,046 ft of water.
The service provider values the contract between $500 million and $1 billion.
Exploration & Development Quick Takes
Siccar Point to review Cambo development options as Shell opts out
Siccar Point Energy E&P will review options for development of Cambo oil and gas field in the West of Shetlands area off the UK following partner Shell UK Ltd.’s decision not to progress its investment, the operator said in a release Dec. 3. Siccar Point operates the project with a 70% interest. Shell UK Ltd. holds 30%.
Discovered in 2002, Cambo field is on the Corona Ridge structural feature 30 km southwest of Rosebank oil field and 50 km north Schiehallion oil field. Siccar Point describes it as a large basement high with sedimentary sequences draped over the top of the structure (OGJ Online, Nov. 8, 2019). Siccar Point envisions developing the field with two subsea drill centers and a dedicated floating production, storage, and offloading vessel.
The project “remains critical to the UK’s energy security and economy,” said Jonathan Roger, chief executive officer of Siccar Point. The company remains confident in the job-creating project aimed to “ease the UK’s transition to a low carbon future through responsibly produced domestic oil instead of becoming even more dependent on imports, with a relatively higher carbon intensity,” he said.
Cambo would help to reduce imports by delivering up to 170 MMboe during its 25-year operational life and provide a further 53.5 bcf of gas—enough to power 1.5 million homes for a year, the company said.
Earlier this year, Cambo underwent a Net Zero Stewardship Expectation review by OGA, which informed the field development plan. The development is expected to be on average 50% lower in emissions from the outset than existing fields through various measures and will be built electrification ready to take power from renewable energy when feasible, the operator said.
Strike Energy finds Perth basin gas in Walyering-5
Strike Energy Ltd., operator of onshore North Perth basin permit EP447, confirmed a high-quality conventional gas accumulation at Walyering gas field with the Walyering-5 appraisal well.
The results exceed pre-drill expectations with the encounter of a higher quality reservoir and the presence of two additional net gas pay zones in deeper sands within the field, the operator said.
Mud logs, logging-while-drilling, and wireline logging tools were used to evaluate four quality coarse grained conventional gas-charged sands throughout the Jurassic-age Cattamarra Coal Measures.
The sands are interpreted to be regional A, B, and C sands seen in the historic Walyering wells as well as in nearby Jurassic gas discoveries Gin Gin, Red Gully, and Ocean Hill, the company said.
Pressure date was measured at about 4,386 psi with permeabilities of 274 md. Porosity averaged 15.4%. Gas samples indicate a low carbon dioxide content of less than 0.69%.
Walyering-5 will now be production tested.
Four historical Walyering wells have been drilled in the field first discovered by Walyering-1 in 1971.
This well encountered a 30 m-thick sand with good quality conventional reservoir development (A-sand) and a second, deeper, thinner gas-charged sand (B-sand). A-sand flowed 13.5 MMcfd of gas on test.
Subsequently, three further Walyering wells were drilled on the 2D seismic data in the surrounding area.
Walyering-2 and -3 encountered non-commercial hydrocarbon saturated reservoir at about the same level as the Walyering-1 A-sand, but flowed only small amounts of gas on test.
Walyering-4 was drilled in 2001 just updip of Walyering-1 and encountered commercial-grade conventional reservoir similar to Walyering-1, but was water saturated.
Strike holds a 55% interest in the permit. Talon Energy Ltd. holds 45%.
Exploration efforts will now move to other targets within the permit.
Aramco starts development of 200-tcf Jafurah field
Saudi Arabian Oil Co. (Aramco) has awarded 16 subsurface and engineering, procurement and construction (EPC) contracts worth $10 billion to start development of its 200-tcf Jafurah unconventional onshore natural gas field, the largest non-associated gas field in the Kingdom. The company is targeting 200 MMscfd of production by 2025 and a sustained 2 bcfd of sales gas output by 2030. Aramco also plans to produce 418 MMscfd of ethane and around 630,000 b/d of NGL and condensates, which it has designated as feedstock for its petrochemical industry.
Work covered by the contracts includes gas processing, gas compression, and a network of around 1,500 km of main transfer pipelines, flow lines, and gas gathering pipelines. The program also includes construction of the Jafurah Bulk Supply Point, transmission lines, power interconnection for the Jafurah gas plant, and new cogeneration capacity.
Aramco expects capital expenditure at Jafurah to reach $68 billion over the first 10 years of development and to exceed $100 billion over its lifecycle.
Samsung Engineering won an EPC contract for the 1.1-bcfd Jafurah Gas Process Package #1, which the companies expect to be complete in 2025. Samsung will build a gas treatment plant which will use two 550-MMcfd trains to remove sulfur and other substances from Jafurah gas as part of producing sales gas, NGL, ethane, sulfur, and stabilized condensate. Scope of the $1.23-billion contract also includes a slug catcher, acid gas removal unit, NGL recovery, mercury removal, and dehydration.
Aramco also awarded an EPC contract to Saipem SPA for 835 km of pipeline as part of Jafurah’s development. The contract involves construction of a hydrocarbon collection system and the transport of natural gas and condensate to the Jafurah plant. Saipem will also build a system to transport water separated from the treated gas.
The contract is worth $750 million.
Aramco received regulatory approval last year to develop Jafurah field in phases (OGJ Online, Feb. 24, 2020).
Drilling & Production Quick Takes
TotalEnergies starts CLOV Phase 2 production off Angola
TotalEnergies, together with the Angolan National Oil, Gas and Biofuels Agency (ANPG), started production of CLOV Phase 2, a project connected to the existing CLOV floating production, storage and offloading (FPSO) unit. The tie-back project is expected to reach production of 40,000 boe/d in mid-2022.
Comprising four oil fields (Cravo, Lirio, Orquidea, and Violeta), CLOV is the fourth TotalEnergies-operated production hub in Block 17 in the Angolan deep offshore. It came on stream in 2014 (OGJ Online, June 12, 2014). Phase 2—which lies about 140 km from the Angolan coast in water depths of 1,100-1400 m—was launched in 2018 and contains resources estimated at 55 MMboe.
The four oil fields are developed simultaneously, and their production is fed into a single all-electric FPSO. They are grouped into two secondary production hubs: Cravo-Lirio, which only contains Oligocene oil, and Orquidea-Violeta, which produces mixed Oligocene and Miocene oils. The reservoirs consist of unconsolidated turbidite sandstone.
Phase 2 production start follows that of the Zinia Phase 2 short-cycle project on the same block in May (OGJ Online, May 26, 2021).
Block 17 is operated by TotalEnergies with a 38% interest. Partners are Equinor (22.16%), ExxonMobil (19%), BP Exploration Angola Ltd. (15.84%), and Sonangol P&P (5%). The contractor group operates four FPSOs in the main production areas of the block, namely Girassol, Dalia, Pazflor, and CLOV.
TotalEnergies’s equity production in Angola averaged 212,000 boe/d in 2020 from operated Blocks 17 and 32, and from non-operated assets 0, 14, 14K, and Angola LNG.
Ranger Oil increases oil sales guidance for fourth quarter
Ranger Oil Corp., Houston, increased its oil sales guidance for fourth-quarter 2021 to 26,700-28,000 b/d of oil from 25,700-27,700 b/d due to outperformance of existing wells, faster cycle times, and less anticipated downtime, the company said in a release Dec. 6 (OGJ Online, Nov. 5, 2021).
Given continued operating efficiencies driving the revised guidance, the company said, it does not anticipate a change to its previously disclosed capital expenditure guidance of $65-75 million for the quarter.
bp begins production from Platina project
bp Angola has started production from the Platina project in Block 18 of the ultra-deep waters of the Lower Congo basin, offshore Angola (OGJ Online, Mar. 10, 2020).
Platina is a subsea tie-back development to the existing Greater Plutonio floating production, storage and offloading (FPSO) vessel. It will access an estimated 44 million bbl of oil reserves and, at peak, is expected to add 30,000 b/d of oil to the block’s production.
The project was delivered 44 days ahead of schedule and 25% below the original budget. Its development increased expected recoverable resilient reserves by 10%.
Platina, the development of which was approved in December 2018, is the first new development on Block 18 since Greater Plutonio started up in 2007. It is bp’s first new operated development in Angola since the start of production from the PSVM development in Block 31 in 2012.
Platina is the seventh new project to start production for bp worldwide in 2021. It follows new projects in Egypt, India, Trinidad, two in the US Gulf of Mexico, and an earlier project on Block 17 offshore Angola.
bp Angola is the operator of the block with a 46% stake. Partners are Sinopec (37.72%) and Sonangol P&P (16.28%).
CNOOC begins production at Lufeng oil fields regional development project
CNOOC Ltd. has started production of its Lufeng oil fields regional development project.
The fields lie in the Eastern South China Sea and mainly include Lufeng 14-4, Lufeng 14-8, Lufeng 15-1, and Lufeng 22-1 fields, in an average water depth of 140-330 m.
Main production facilities include two drilling production platforms and one subsea production system. Thirty-five development wells are expected to be put into production, including 26 production wells and nine water injection wells. The project is expected to achieve peak production of about 46,000 b/d of crude oil in 2023.
CNOOC owns 100% interest in the development.
PROCESSING Quick Takes
Plans launched for Australia’s first renewable diesel, storage complex
Sherdar Australia Bio Refinery Pty. Ltd., a specialty company of privately held TransAsia Minerals Ltd., plans to develop Australia’s first renewable diesel processing and storage plant.
Once in operation, the planned renewable fuels refinery will be equipped to produce 500,000 tonnes/year of renewable diesel and sustainable aviation fuel (SAF) using Royal Dutch Shell PLC’s proprietary hydrotreated vegetable oil (HVO) process technology, Sherdar said on Dec. 6.
While an exact location will be forthcoming, the proposed $600-million project will be sited on more than 20 hectares located close to adequate port infrastructure to enable exports to US and European destinations to help meet rising demand for renewable fuels in those regions, according to the operator.
Feedstock for the refinery will include a wide range of animal fat, seed oil, and waste greases.
While Sherdar confirmed final stages of engineering, governmental discussions, and receiving relevant approvals for the project are currently under way, the operator did not reveal an anticipated timeline for the project’s completion.
Gazprom Neft lets contract for new complex at Moscow refinery
PJSC Gazprom Neft subsidiary JSC Gazpromneft-MNPZ has let a contract to Lummus Technology LLC to provide technology and equipment to further expand production of Euro 5-quality fuels while improving operational efficiency and environmental performance as part of the operator’s ongoing modernization and upgrade of its 12-million tonnes/year Moscow refinery (OGJ Online, May 5, 2017).
As part of the Dec. 2 contract, Lummus will design, manufacture, and supply two fired heaters based on its proprietary advanced heater technology to be installed at the delayed coking section of a new deep oil processing complex now under construction at the refinery, Gazpromneft-MNPZ and Lummus Technology said in separate releases.
The heaters will be added to enhance efficiency and reduce environmental impacts of a delayed coking unit that will be equipped with technology licensed by Chevron Lummus Global (CLG)—a Chevron USA Inc.-Lummus Technology JV—to process heavy oil fractions at the deep oil processing complex for increased output of lighter, cleaner fuels and production of petroleum coke for use in the metallurgical industry, the operator and service provider said.
The contract follows Gazpromneft’s earlier $240-million contract award to Técnicas Reunidas SA to provide provide engineering, procurement as well as project management and startup services for the proposed 2.4-million tpy delayed coking unit.
Gazpromneft, which began construction of the deep oil processing complex on Sept. 1, also previously awarded a contract to DL E&C Co. Ltd. and its subsidiary Daelim RUS LLC to deliver services on construction of the complex’s hydrocracking plant.
The new hydrocracking unit planned for the Moscow refinery follows Gazpromneft-MNPZ’s July 2020 commissioning of its 98-billion rubles Euro+ combined oil refining unit, an integral element of the manufacturing site’s second-phase modernization designed to improve the manufacturing site’s overall environmental performance as well as its yield of light-end, Euro 5-quality petroleum products, including gasoline, diesel, and aviation kerosine.
Scheduled for startup in 2025, the deep oil processing complex—including the hydrocracking and delayed coking plants—comes as part of a third phase of the Moscow refinery’s modernization program that was initiated in 2011 and is scheduled for completion in 2025 at a final estimated cost of 350 billion rubles.
TRANSPORTATION Quick Takes
Pembina cancels Jordan Cove LNG plant
Pembina Pipeline Corp. has halted its 7.8-million tonne/year Jordan Cove LNG liquefaction project in Coos Bay, Ore., requesting that the US Federal Energy Regulatory Commission (FERC) vacate permissions granted for the plant. Pembina had paused development earlier this year citing difficulties obtaining permits from the State of Oregon (OGJ Online, Mar. 1, 2021).
FERC in March 2020 approved Jordan Cove and the associated 229-mile Pacific Connector natural gas pipeline. A series of lawsuits followed, with the US Appeals Court for the DC Circuit first denying a request that FERC approval be vacated pending resolution of the legal actions and then on Nov. 1, 2021, remanding the proceeding to FERC in part “to consider whether the imposition of a stay” of the certificate was “appropriate.”
Pembina, however, has still not obtained the necessary state-issued permits and authorizations from various Oregon agencies, nor been able to determine a timeline in which same might be forthcoming, and has decided not to move forward.
Jordan Cove LNG was initially proposed in 2007 but has faced resistance from environmental groups, property owners, and Indigenous communities ever since. Landowners are now likely to ask the DC Circuit to remand the project’s certificate as a necessary step towards FERC vacating it.
Venture Global files FERC application for CP2 LNG plant
Venture Global LNG Inc. has applied with the US Federal Energy Regulatory Commission (FERC) to develop its fourth LNG liquefaction plant in Louisiana, the 20-million tonne/year (tpy) CP2 LNG. The new project will be built in Cameron Parish, adjacent to Venture Global’s 10-million tpy Calcasieu Pass LNG plant.
The company will also build the 48-in. OD, 87.5-mile CP Express pipeline, which will provide natural gas to the plant from an interconnect in Jasper County, Tex. Total cost of the project is expected to be more than $10 billion.
Venture Global’s 20-million tpy Plaquemines LNG plant is under construction in Plaquemines Parish. It’s also developing the 20-million tpy Delta LNG plant in Plaquemines Parish, having filed its application for the project with FERC fourth-quarter 2019. Delta would be built in two 10-million tpy phases, and would be supplied by the planned 42-in. OD, 283-mile Delta Express pipeline from interconnections near Alto, La.
The company plans to capture and sequester a total of 1-million tpy of carbon dioxide between the Calcasieu Pass, CP2, and Plaquemines plants (OGJ Online, May 27, 2021).
Calcasieu Pass LNG is the furthest advanced of Venture Global’s projects, with test production expected by end-2021 or early 2022 and commercial service by mid-2022.
Aramco signs $15.5 billion gas pipeline deal
Saudi Arabian Oil Co. (Aramco) signed a $15.5 billion lease and leaseback deal involving its gas pipeline network with a consortium led by BlackRock Real Assets and Hassana Investment Co., the investment management arm of the General Organization for Social Insurance in Saudi Arabia.
A new subsidiary, Aramco Gas Pipelines Co., will lease usage rights in Aramco’s gas pipelines network and lease them back to Aramco for a 20-year period. The subsidiary will receive a tariff payable by Aramco for gas products that will flow through the network, backed by minimum commitments on throughput.
Aramco will hold a 51% stake in Aramco Gas Pipeline Co. and will retain full ownership and operational control of its gas pipeline network. The deal will not impose restrictions on Aramco’s production volumes.
The transaction is expected to close as soon as practicable, subject to closing conditions, including any required merger control and related approvals.
This is Aramco’s second such infrastructure deal this year after closing of the $12.4 billion lease and leaseback transaction with an EIG Global Energy Partners-led consortium, which involved Aramco’s crude oil pipeline network.