OGJ Newsletter

Dec. 11, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


Chappal Energies to acquire Equinor’s Nigerian business

Nigerian-owned Chappal Energies has agreed to acquire Equinor’s Nigerian business, including its share in Agbami, Nigeria’s largest deep-water oil field. Terms of the deal, which will lead to Equinor effectively exiting the country, were not disclosed.

Chappal will acquire Equinor Nigeria Energy Co. (ENEC), which holds a 53.85% ownership in oil and gas lease OML 128, including the unitized 20.21% stake in Chevron Corp.-operated Agbami. Chevron holds 67.30% interest and Prime 127 holds the remaining 12.49%.

Agbami lies 110 km off the Nigerian coast in water depths of 1,500 m. It has been developed using subsea wells and is the world’s largest floating production, storage, and offloading (FPSO) vessel, according to Equinor’s website. The FPSO can store up to 2.2 million bbl of oil. The field has produced more than 1 billion bbl of oil since production started in 2008.

Equinor’s Nigerian business includes a 53.85% interest in exploration licenses OMLs 128 and 129. Six wells have been drilled in both, with two discoveries made. The Nnwa discovery is predominantly comprised of gas as well as some oil. Bilah is a gas and condensate discovery. Both remain undeveloped.

The deal’s closing is subject to certain conditions including all regulatory and contractual approvals.

SilverBow expects 70% y-o-y oil production increase as Eagle Ford deal closes

SilverBow Resources Inc., Houston, expects a  2024 capital expenditures budget of $550-580 million to support a three-rig drilling program and a preliminary 2024 production outlook of 551-611 MMcfed in the South Texas Eagle Ford.

The pure play company updated its 2023 guidance and provided a preliminary 2024 outlook upon closing of its acquisition of Chesapeake Energy Corp.’s oil and gas assets in South Texas for $700 million on Nov. 30 (OGJ Online, Aug. 14, 2023). SilverBow now holds over 220,000 net acres with 1,000 drilling locations identified, it said.

For 2024, SilverBow plans to operate three drilling rigs with one rig dedicated to the recently acquired assets. Oil production is expected to increase about 70% year-over-year and average 25,000 b/d. The full year production mix is expected to be more than 40% oil/NGLs.

For the remainder of 2023, there is no material change to SilverBow’s development plans as noted in early November. The company expects to continue operating two drilling rigs across its acreage and does not anticipate any incremental capex on the acquired assets. In its third-quarter update Nov. 1, SilverBow noted fourth-quarter 2023 production of 353-375 MMcfed was expected, with oil volumes comprising 16,400-17,000 b/d, or 28% of total production at the midpoint. The fourth-quarter and full year statistics do not factor in contributions from the Chesapeake deal.

Full year 2023 estimated production of 336-342 MMcfed is expected with oil volumes of 13,900-14,100 b/d, a 26% increase year-over-year. Full year 2023 capital budget range of $400-425 million remains unchanged.

Ecopetrol’s 2024 investment plan down more than 9%

The board of directors of Ecopetrol Group, controlled by the Colombian government, approved the company’s investment plan for 2024, with expenditures set at 23-27 trillion pesos ($5.685-6.674 billion), a more than 9% reduction from 2023. The company’s 2023 investment plan was set at 25.3-29.8 trillion pesos.

The new budget projects that 19.3 trillion pesos ($4.771 billion) will be allocated to maintaining crude production of 725,000-730,000 b/d and average refinery runs of 420,000-430,000 b/d, as stated by group president Ricardo Ro a in a video released Nov. 30. The 2024 plan establishes “360 development wells, 15 exploratory wells, and integrity investments to maintain the availability of refinery infrastructure and pipeline systems,” said executive vice-president of operations, Alberto Consuegra.

“Competitive returns will be ensured at Brent levels of $75/bbl, with a return on average capital employed of around 9%, an approximate EBITDA margin of 38%, and transfers to the nation exceeding 38 trillion pesos,” added the statement. The investment plan between 2024 and 2026 will total around 80 trillion pesos, equivalent to about $20 billion.

Consistent with guidelines defined by Colombian President Gustavo Petro and the framework of the country’s 2040 Strategy, more than 42% of the plan is expected to be invested in energy transition projects.

Exploration & Development   Quick Takes

Raia advances with topside modules fabrication contract

Equinor Energy AS contractor Offshore Frontier Solutions Pte. Ltd., a Modec Group company, has signed BrasFELS Shipyard, a Seatrium Group company, for work related the Raia project offshore Brazil.

BrasFELS will undertake portions of the topside modules fabrication of a floating production, storage, and offloading (FPSO) vessel that will be deployed in the presalt area at the southern part of Campos basin, about 200 km off the coast of Rio de Janeiro.

BrasFELS’ scope of work comprises fabrication of three modules: vapor recovery unit-flare knockout; oil separation and stabilization; and flowline circulation and metering and utility systems. The project will be undertaken by Seatrium’s BrasFELS shipyard in Angra dos Reis, Rio de Janeiro. Work is expected to begin in first-quarter 2024.

When completed, FPSO Raia will have capacity to process 126,000 bo/d and 16 million cu m/day (MMcmd) of natural gas. It will have oil storage capacity of 2 million bbl. Start-up is expected in 2028.

In September, Equinor submitted a declaration of commerciality and plans of development for Raia Manta and Raia Pintada fields in the BM-C-33 concession to Agência Nacional de Petróleo, Gás Natural e Biocombustíveis (ANP) (OGJ Online, Sept. 21, 2023). Expected recovery is over 1 billion boe.

Equinor is operator of BM-C-33 with 35% interest. Partners are Repsol Sinopec Brasil (35%) and Petrobras (30%).

UkrGasVydobuvannya discovers gas near depleted field

State-owned UkrGasVydobuvannya (UGV), a joint stock company of Naftogaz Group, discovered a Mesozoic play in a Carpathian field that was previously considered depleted.

A new 1,600 m well was drilled by the Ivan Bogun rig to explore near the mature field. The well’s location was chosen based on interpretation of new data from previous 3D seismic surveys.

The well tested at more than 200,000 cu m/d—the highest rate for fields in the western region in the last 20 years, the company said in a release Nov. 17. Based on these results, the company has identified additional pay horizons for drilling new wells. No timeframe for additional drilling was disclosed.

UGV is working to expand midstream technological capabilities to increase production.

Woodside Trion FPU project adds commissioning contract

Woodside contractor HD Hyundai Heavy Industries Co. Ltd. (HHI) has signed GATE Energy for commissioning of the 100,000 b/d Trion floating production unit (FPU) offshore Mexico.

GATE’s scope includes pre-commissioning and commis-sioning planning and execution at HHI’s fabrication yard in Ulsan, South Korea.

Woodside took final investment decision (FID) on Trion earlier this year and subsequently received approval for the project from Mexico’s Comision Nacional de Hidrocarburos (OGJ Online, Aug. 30, 2023; June 20, 2023). Trion is in the Perdido fold belt, Gulf of Mexico, 180 km off the Mexican coastline and 30 km south of the Mexico-US maritime border in water depths up to 8,200 ft.  

Trion will be developed with 18 wells (nine producers, seven water injectors, and two gas injectors) drilled in the initial phase and a total of 24 wells drilled over the life of the project. The FPU will connect to a floating storage and offloading (FSO) vessel with a capacity of 950,000 bbl of oil.

Its development is targeting 479 MMboe of best estimate (2C) contingent oil and gas. Pemex Exploración y Producción holds 40% interest.

First oil is targeted for 2028.

Buru Energy to appraise Rafael discovery

Buru Energy Ltd. will appraise the Rafael conventional gas and condensate discovery in EP 428 in Canning basin, Western Australia.

Buru has placed orders with Marubeni-Itochu Tubulars Oceania Pty Ltd. (Mito) for casing, Cactus Wellheads Australia for wellhead and XMT tree, and R&D Solutions for casing accessories as part of a long lead item package to support drilling of an appraisal well and recompletion and test of the Rafael 1 discovery well. Drilling is planned for the Kimberly region operating season in second-half 2024.

Detailed well design is progressing and discussions with potential rig providers is under way. Processing of Rafael 3D seismic data is progressing on schedule with observed data quality improvement from an extracted 30 sq km swath of data around the Rafael well location. Once processed and interpreted, the 3D volume will inform appraisal well locations and provide data to support ongoing strategic partner selection activities, the company said.

Canning basin is a geological unit in the southwest Kimberley region about 2,300 km north of Perth. The Rafael 1 well was drilled in 2021 on a large structure with gas encountered in three zones. A test of a portion of the lower Ungani Dolomite zone was successfully flow tested at 7 MMcfd confirming the conventional discovery.

Buru Energy is operator of the discovery with 100% interest.

Drilling & Production   Quick Takes

Shell UK to drill Southern North Sea appraisals

Shell UK Ltd. will drill Selene and Pensacola appraisal wells in the Southern North Sea in 2024, said partner Deltic Energy PLC in a Dec. 5 release. Preparatory works for both wells are progressing.

The first of the two wells to be drilled is an exploration on the Selene gas prospect on license P2437. The prospect is considered one of the largest unappraised structures in the Leman Sandstone fairway of Southern Gas basin. Selene JV partners estimate Selene to contain gross P50 prospective resources of 318 bcf of gas (with a P90 to P10 range of 132-581 bcf) with a 70% geological chance of success.

The initial geophysical site survey on Selene was completed during the summer and the acquired data informed the geotechnical survey which will begin in the first half of December. Site surveys ensure safe installation of the rig at the selected well location.

Following completion of the well design process, critical long lead items including casing have been identified and procurement processes are advanced. Selene remains on track to be drilled in third-quarter 2024, the company said.

An appraisal on the Pensacola discovery in License P2252 is planned for drilling after the Selene well in late 2024. Pensacola JV partners estimate that the Zechstein carbonate reservoir contains gross P50 ultimately recoverable oil and gas resources of nearly 100 MMboe. Site survey works for the well location are due to be carried out in first-half 2024. The Pensacola JV will formalize a well investment decision related to the appraisal well in December 2023.

The rig tendering process for Selene and Pensacola is ongoing.

Shell UK Ltd. is operator at Selene (50%) and Pensacola (70%). Deltic holds the remaining equity in both prospects.

CNOOC starts production at Bozhong 19-6

CNOOC Ltd. started production at the Bozhong 19-6 condensate gas field first phase development project in central Bohai Sea.

The main production infrastructure lies in 20 m of water and includes one newly built central processing platform, three unmanned wellhead platforms, and one gas process terminal. Sixty-five development wells are planned to be commissioned, including forty-two production wells, twenty gas injection wells, and three water source wells.

The project is expected to achieve peak production of about 37,000 boe/d in 2024.

Bozhong 19-6 is the first condensate gas field with a proved in-place volume of over 200 billion cu m of natural gas that has been put into operation in Bohai Bay, CNOOC said.

CNOOC is operator and holds 100% interest in the project.

Suncor restarts Terra Nova FPSO

Suncor Energy Inc. restarted the Terra Nova floating production, storage, and offloading (FPSO) following completion of the Terra Nova Asset Life Extension project offshore Newfoundland and Labrador. Production is expected to ramp up over the coming months.

The FPSO, which lies about 350 km offshore Canada and can store 960,000 bbl of oil, had been out of service since 2019 following the order by the Canada-Newfoundland and Labrador Offshore Petroleum Board for Suncor to suspend production-related operations due to a crack in the vessel’s hull. The Terra Nova Asset Life Extension project is expected to add 10 years and 70 million bbl of oil to the FPSO’s production capacity (OGJ Online, Nov. 9, 2023).

Suncor is operator of the Terra Nova project with 48% interest. Partners are Cenovus (34%) and Murphy Oil (18%).

PROCESSING   Quick Takes

TotalEnergies to shed interest in Natref refinery

TotalEnergies SE has agreed to sell subsidiary TotalEnergies Marketing South Africa (Pty) Ltd.’s minority ownership interest in National Petroleum Refiners of South Africa (Pty) Ltd.’s (Natref) 108,000-b/d refinery in Sasolburg, South Africa, to London-based Prax Group.

As part of the agreement, TotalEnergies will divest its 36.36% stake in Natref—a JV with Sasol Ltd. (63.64%)—to Prax, which intends for the refining JV to serve as a focal point for its expansion into the South African market in line with the operator’s ongoing international growth strategy, the companies said in separate releases.

Following close of the proposed transaction, Prax said it plans to improve the Natref refinery’s competitive position through future strategic investment.

The refinery will continue to operate while the sale progresses through the various regulatory approvals and closing conditions, Natref’s majority shareholder Sasol said in a separate Dec. 1 statement.

Sasol also confirmed it will continue to invest during the pending sale to help the refinery meet South Africa’s more stringent clean-fuels compliance specifications (CF2).

In its latest annual and climate change reports to investors for the year ending June 30, 2023, Sasol said it has undertaken a study to evaluate the potential repurposing of Natref’s manufacturing site into a hybrid refinery equipped to process both crude and biofeedstocks to meet customer demand for low-carbon intensity fuels.

Sasol said it originally estimated an initial investment of 9-11 billion rand ($478-584 million) to bring Natref’s refinery into CF2 compliance.

Innovation and technology, however, is enabling the potential hybrid refining solution to result in a reduced cost for Natref to meet CF2 specifications, Sasol said in the 2023 annual report.

Montana Renewables returns Great Falls plant to full operations

Calumet Specialty Products Partners subsidiary Montana Renewables LLC (MRL) has returned its renewable diesel manufacturing plant in Great Falls, Mont., to normal operations following completion of steam drum replacement and turnaround activity.

The plant is now processing over 12,000 b/d of renewable feedstock.

In October, Calumet noted plans to bring forward planned maintenance following a decision to replace equipment at the plant (OGJ Online, Oct. 20, 2023).

There are no planned turnarounds in 2024, said Bruce Fleming, chief executive officer, Montana Renewables, in a release Dec. 1. 

The plant operated at 50% utilization in August, September, and October, and was in complete shutdown for the turnaround most of November. Over the next 3 months, MRL will run off the renewable feedstock inventory built throughout the maintenance period and resume the normal procurement of advantaged feedstocks, the company said.

Montana Renewables is permitted to pretreat and convert 15,000 b/sd of renewable feedstocks.

Orlen to use novel technology for Kralupy refinery upgrade

Orlen Unipetrol SA subsidiary Orlen Unipetrol RPA SRO is building a grassroots heat recovery unit to improve energy efficiency and reduce operating costs at its 3.3-million tonne/year (tpy) refinery in Kralupy nad Vltavou, Czech Republic.

Already under construction, the more than 500-billion crown ($122 million) project involves installation of a new unit—based on proprietary, acid-resistant polymer heat exchanger technology developed and engineered by Orlen Unipetrol—designed to recover heat from flue gases generated in furnaces of the refinery’s crude distillation block that will be reused to reheat boiler feed water for production of steam at the site’s fluid catalytic cracking (FCC) unit, parent company Orlen SA and Orlen Unipetrol said in separate Dec. 5 releases.

Once operable, the new heat recovery unit will eliminate the refinery’s current need of sourcing the entirety of its boiler feed water from a municipal gas-fired combined heat and power (CHP) plant by enabling the refinery to produce about one third of its required boiler water in house using about 5 Mw of heat energy anticipated to be recovered from its own flue gases, according to the companies.

Scheduled for a mid-2025 startup, the new heat recovery unit will allow the refinery to reduce its CO2 emissions related to obtaining boiler water by 15,000 tpy, according to the companies.

The Kralupy refinery upgrade comes as part of Orlen Unipetrol’s more than 35-billion crown ($1.6 billion) proposed spending program on a series of initiatives to reduce the carbon footprint of its operations in the Czech Republic by 25% by 2030 from 2020 levels.


ExxonMobil, Sentinel form second last-mile crude pipeline JV

ExxonMobil Pipeline Co. LLC and Sentinel Midstream LLC have formed a second last-mile pipeline joint venture. Called Enercoast Midstream Louisiana LLC, the JV provides pipeline connectivity between crude oil terminals in Raceland, St. James, and Anchorage, La.

ExxonMobil contributed two crude oil pipelines into Enercoast: a 16-in. OD pipeline from St. James to Anchorage, and a second 16-in pipeline running from both Raceland and St. James with delivery at Anchorage. Via Anchorage, these pipelines provide connectivity to the 540,000-b/d ExxonMobil Baton Rouge refinery, Placid Refining Co. LLC’s 75,000-b/d refinery, and the 74,000-b/d Delek Krotz Springs refinery.

Sentinel contributed cash for a majority equity position in the JV and will be its operator. Enercoast began serving shippers as a common-carrier pipeline Dec. 1, 2023.

ExxonMobil and Sentinel’s first JV formed 2 years ago. ExxonMobil contributed two crude pipelines to it as well: a 16-in. OD pipeline originating at its Webster Terminal with delivery points at ExxonMobil’s 584,000-b/d Baytown refinery and Magellan Midstream Partners’ Seabrook export terminal and a 20-in. pipeline between Moore Road station and the Baytown plant (OGJ Online, Oct. 5, 2021).

Williams increase DJ basin gas gathering, processing assets through closed deals

Williams, Tulsa, Okla., closed two transactions that now position the company as the third largest gatherer in the Denver-Julesburg (DJ) basin, the company said in a release Nov. 30. The acquisitions have a combined value of $1.27 billion.

In one transaction, Williams acquired Cureton Front Range LLC, whose assets include gas gathering pipelines and two processing plants serving producers across 225,500 dedicated acres.

In a separate deal, Williams purchased KKR’s 50% ownership interest in Rocky Mountain Midstream Holdings LLC (RMM). Williams now holds 100% ownership of RMM.

“The combination of the Cureton and RMM assets will deliver tangible operational synergies that include increased volumes on our existing processing facilities, as well as increased revenues on our downstream NGL transportation, fractionation and storage assets,” said Alan Armstrong, president and chief executive officer of Williams.

The deals were first announced in third-quarter 2023 earnings materials.

Proceeds of $355 million from Williams’ recent sale of its Bayou Ethane Pipeline system along with $533 million in net proceeds now received from the Energy Transfer legal judgment of $627 million (including legal fees owed to others) partially funded the transactions.

ARC Resources signs natural gas supply agreement with Cheniere

ARC Resources Ltd., Calgary, through its subsidiary ARC Resources US Corp. has agreed to a long-term natural gas supply agreement with Sabine Pass Liquefaction Stage V LLC, a subsidiary of Cheniere Energy Inc.

The agreement, the second long-term deal with Cheniere, further progresses commercialization of the Sabine Pass Stage 5 Expansion Project (SPL Expansion Project) and enables delivery of increased quantities of Canadian natural gas to Europe, said Jack Fusco, Cheniere president and chief executive officer.

Under the agreement, ARC will supply 140,000 MMbtu/d of natural gas for 15 years beginning with commercial operations of the first train (Train 7) of the SPL Expansion Project in Cameron Parish, La., anticipated by 2029.

The project is being developed with a production capacity of up to 20 million tonnes/year (tpy) of total LNG capacity. In May 2023, certain Cheniere Partners subsidiaries entered the pre-filing review process with respect to the project with the Federal Energy Regulatory Commission.

ARC will utilize its existing contracted pipeline capacity to the US Gulf Coast to supply the natural gas volumes to Cheniere, it said in a release Nov. 29. Under the agreement, ARC will receive an LNG price based on the Dutch Title Transfer Facility (TTF) price, after fixed deductions for liquefaction, shipping, and regasification fees.

The agreement is subject to, among other things, a positive final investment decision on Train 7. LNG associated with this supply, about 0.85 million tpy, will be marketed by Cheniere Marketing International LLP.

ARC currently has an agreement to supply 140,000 MMbtu/d to Cheniere’s Corpus Christi Stage III expansion, and a non-binding memorandum of understanding to supply and liquefy 200 MMcfd of natural gas to Cedar LNG on Canada’s West Coast.

ARC’s first agreement with Cheniere, in 2022, provides exposure to LNG-pricing based on Platts Japan Korea Marker. With the supply to Cheniere’s SPL Expansion Project, ARC will supply about 20% of its current natural gas production to global markets with overseas pricing upon commencement of the contracts.