OGJ Newsletter

Oct. 23, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


EIA: US crude oil exports hit record high in first-half 2023

US crude oil exports in first-half 2023 averaged 3.99 million b/d, which is a record high for the first half of a year since 2015 when the US lifted its ban on most crude oil exports, according to US Energy Information Administration (EIA) data. In first-half 2023, crude oil exports were up 650,000 b/d (+19%) compared with first-half 2022.

Europe was the largest regional destination for US crude oil exports by volume, at 1.75 million b/d, led by exports to the Netherlands and the UK. Asia accounted for the next-highest volume, receiving 1.68 million b/d, driven by exports to China and South Korea. The US exported smaller volumes of crude oil to Canada, Africa, Central America, and South America.

Despite the surge in exports during first-half 2023, the US maintains its status as a net crude oil importer. The US continues to import crude oil despite rising domestic crude oil production in part because many US refineries are configured to process heavy, sour crude oil rather than the light, sweet crude oil typically produced in the US.

US crude oil imports predominantly originate from historical trading partners such as Mexico and Canada. Heavy, sour crude grades often receive discounts compared to their light, sweet counterparts due to the increased complexity required by refineries to produce profitable refined products like gasoline, diesel, and jet fuel. Consequently, most US crude oil imports occur when it is more economically viable for US refiners to process discounted heavy grades, as these refineries have already invested in the necessary complexity for their refining operations, EIA said.

While some US refiners on the Gulf Coast have invested in expanding their light, sweet crude oil processing capacity, but for many refiners, particularly in the Midwest and along the Gulf Coast, refining discounted heavy, sour crude oil grades remains more profitable.

Operator plans CCS expansion in Texas Permian

San Antonio-based Ozona CCS LLC has entered a deal to expand its carbon capture sequestration (CCS) capabilities for oil and gas operators in the Permian basin of West Texas.

Ozona has signed a definitive agreement with a private landowner in Loving County, Tex., to lease about 5,723 contiguous acres of pore space for the purpose of drilling multiple commercial CO2 sequestration wells to increase its Permian lease position to more than 10,000 contiguous acres with estimated pore space capacity of 120 million tonnes, the company said on Oct. 4.

With the agreement now in place, Ozona said it will start the federal and state permitting process to drill and operate multiple CO2 disposal wells across its acreage position, with each to have an initial injection rate of 25,000 b/d.

Initial anchor customers will include existing Permian natural gas processing plants, other regional oil and gas operators, as well as industrial and power generation under development in the area.

Projects seeking to inject CO2 into formations for permanent storage are subject to the Environmental Protection Agency’s (EPA) Class VI Rule and must obtain a Class VI permit.

Pending requisite EPA permitting approvals, Ozona anticipates the target in-service date for its Class VI wells sometime during first-quarter 2026.

This latest land-lease agreement follows Ozona’s previous deal signed earlier this year with Texas Pacific Land Corp. (TPL) to lease about 5,173 contiguous acres of land in the Permian for drilling one of the first commercial CO2 sequestration wells in the region, Ozona said on Jan. 31.

The operator said its proposed COdisposal well on TPL land—scheduled to be in-service during third-quarter 2024—is to have an estimated initial injection rate of up to 25,000 b/d and an estimated total storage capacity of at least 40,000,000 metric tons of CO2.

Repsol, Wintershall add respective interests in Reggane Nord gas field onshore Algeria

Repsol and Wintershall Dea have closed a deal with Edison SPA to increase respective interests in the Reggane Nord natural gas project onshore Algeria.

Following Algerian regulatory approvals, Repsol increased its interest by 6.75% and Wintershall has increased its share by 4.5%.

In May 2022, Wintershall agreed to acquire Edison SPA’s 11.25% participating interest in the Reggane Nord natural gas project in Algeria as part of a plan to grow its participation in the country (OGJ Online, May 5, 2022).

In June 2022, Edison said Repsol exercised its joint operating agreement preemption right to a portion of the interest. Thus, Edison signed an amendment to the agreement to reflect the disposal of Edison’s stake in the field (equal to 11.25%) in part to Repsol (6.75%) and in part to Wintershall Dea (4.50%).

The value of the transaction remained at an estimated $100 million, and all other terms and conditions were unchanged.

Reggane Nord production began in December 2017 and consists of 19 currently productive wells which provide about 2.8 billion cu m/year of gas sold entirely to Sonatrach in Algeria based on a long-term contract.

With the closure of the deal, Edison confirms its exit from oil and gas exploration and production activities, a process the company started in 2019.

The Groupement Reggane Nord, operator of the project, now consists of Sonatrach (40%), Repsol (36%), and Wintershall Dea (24%).

Exploration & Development Quick Takes

ExxonMobil Guyana lets FEED contract for Whiptail development project

ExxonMobil Guyana Ltd. has let a contract to SBM Offshore to perform front-end engineering and design (FEED) for a floating production, storage, and offloading vessel (FPSO) for the Whiptail development project in Guyana.

Following FEED and subject to government approvals in Guyana of the development plan, project sanction including final investment decision by the ExxonMobil Corp. affiliate to release the second phase of work, SBM Offshore will construct and install the FPSO, the service provider said in a release Oct. 13.

ExxonMobil discovered oil at Whiptail in 2021, adding to the block’s previous recoverable resource estimate of 9 billion boe.

SBM Offshore will design and construct the FPSO using its seventh new build, multi-purpose floater hull, combined with several standardized topsides modules. The FPSO will be designed to produce 250,000 b/d of oil, will have associated gas treatment capacity of 540 MMcfd, and water injection capacity of 300,000 b/d.

The FPSO will be spread moored in water depth of about 1,630 m and will be able to store around 2 million bbl of crude oil.

FPSO ownership is expected to be transferred to ExxonMobil at the end of the construction period and before start of operations in Guyana. Construction costs are expected to be partially funded by senior loans which will be repaid at the time of the FPSO’s transfer.

This is the fifth FPSO awarded to SBM Offshore by ExxonMobil, following FPSOs Liza Destiny, Liza Unity, Prosperity, and ONE GUYANA.

Equinor lets EPCI contract for Eirin gas field tie-back

Equinor has awarded Ocean Installer an engineering, procurement, construction, and installation (EPCI) contract for the Eirin subsea tie-back development.

The award also constitutes an option for a new gas export solution from Troll B via the existing Kvitebjørn export pipeline.

The scope covers installation of structures, flexibles, umbilical, seabed rectification, tie-ins, and commissioning. It also includes design, fabrication, and installation of glass reinforced plastic (GRP) covers and spool bringing gas volumes to the European market.

Engineering will begin immediately and both projects are expected to be completed by 2025.

Eirin is a gas field in the North Sea that was originally discovered in 1978 and that now will be developed with a 2-slot template with an integrated manifold where the well stream will be connected to the existing Gina Krog platform through a 9.5-km flexible flowline and integrated service umbilical.

The optional scope on Troll B includes a new 2.5-km flexible flowline from an existing pipeline end manifold (PLEM) on Troll B to a new PLEM close to the Kvitebjørn hot-tap. A rigid spool will also be fabricated and installed between the new PLEM and the Kvitebjørn hot-tap.

Petrobras obtains license to drill on Brazil’s Equatorial Margin

Petróleo Brasileiro SA (Petrobras) has been granted an environmental license from the Brazilian Institute of Environment and Renewable Natural Resources (Ibama) to drill two exploratory wells in Block BM-POT-17, in deep waters of Potiguar basin, on the Brazilian Equatorial Margin.

The project, to evaluate the Pitu discovery, is expected to begin with drilling of the first well 52 km off the coast in the coming weeks pending arrival of the drilling rig, Petrobras said in a release Oct. 2.

With the exploratory survey, the company intends to obtain more geological information to assess the economic feasibility and extent of the oil discovery made in 2013.

In 2014, the operator said the discovery well reached a total depth of 5,353 m and encountered a 188-m column of intermediate 24º gravity API oil. In 2015, the company said it confirmed the presence of oil in the Pitu area after drilling the Pitu North 1 extension well offshore Rio Grande do Norte state.

There is no oil production currently.

Potiguar basin covers maritime portions of the states of Rio Grande do Norte and Ceará and is part of the Brazilian Equatorial Margin, which stretches between the states of Amapá and Rio Grande do Norte.

Petrobras intends to drill 16 exploratory wells in the Equatorial Margin over 5 years. Investment in research to investigate the region’s oil potential is expected to reach about $3 billion, the company said. 

Drilling & Production Quick Takes

ConocoPhillips starts up North Sea Tommeliten A field

ConocoPhillips Skandinavia AS started natural gas production from Tommeliten A field in the Greater Ekofisk area in the North Sea. Natural gas from the new field is being produced and delivered nearly 6 months earlier than planned, the operator said in a release Oct. 13.

Tommeliten A is a fractured chalk field containing gas condensate and volatile oil. The field consists of an Ekofisk formation and a Tor formation, similar to surrounding fields in the Greater Ekofisk Area. The field is a UK-Norway trans-boundary field as it extends from Norwegian Block 1/9 into UK Block 30/20. The development plan is based on the Norwegian plan for development and operation.

The development concept comprises a two-by-six slot subsea production system with an electrically heated flowline tied back to the Ekofisk complex. A new processing module has been installed on Ekofisk 2/4 M and an electrical heating module on Ekofisk 2/4 Z, as well as upgrades to the existing gas train on Ekofisk 2/4 J.

Two pilot holes have been drilled during field development, which have allowed for one additional production well, ConocoPhillips said, increasing the total number of production wells to 11. A twelfth well may be drilled later, the operator said.

Production is expected to ramp up to a peak of 35,000-48,000 boe/d, with further upside potential dependent on processing capacity and well streams assessed over time, the company said.

Total resource potential for Tommeliten A field is estimated at 120-180 MMboe (70% gas, 30% condensate).

Total capital investment for the project is about NOK 13 billion.

Perenco starts production from Hylia South West discovery offshore Gabon

Perenco Oil & Gas Gabon (POGG) has started production from the Hylia South West discovery offshore Gabon.

The discovery was in December 2022 through the drilling of the HYSM-01 exploration well on the Mono permit in 40 m water depth 10 km south of Hylia field. The well encountered a 40 m net oil-bearing column in the NTO reservoir.

In addition to this primary target, the well also encountered another column, currently being tested, in the Madiela carbonate reservoir, the company said.

In this year’s first quarter, POGG installed a 10-km pipeline and a proprietary design, self-elevating production platform to fast-track production testing through Hylia platform infrastructure, the company continued.

HYSM-01 was completed this summer and equipped with an electrical submersible pump. It is currently producing 3,000 b/d of oil.

POGG will begin additional testing in the coming weeks to evaluate the full potential of the discoveries in both the Madiela and NTO reservoirs, currently estimated to be 20-100+ million bbl in place.

Additionally, studies have been launched ahead of additional appraisal and development drilling within the next 18 months.

The discovery comes just a few months after the Wamba discovery, which is still producing 2,000 b/d of oil. More exploration wells are planned both offshore and onshore Gabon in the coming months, including at both Wamba and Igonguino.

TotalEnergies flows discovery offshore Namibia

TotalEnergies EP Namibia BV confirmed flow in the Venus-1X discovery in Block 2913B (PEL 56) offshore Namibia, said partner Impact Oil & Gas Ltd. in a Sept. 28 release.

The Deepsea Mira semisubmersible drilling rig re-entered and side-tracked the Venus-1X discovery. Flow tests showed positive results which are expected to be confirmed with the flow test of Venus-1A in fourth-quarter 2023. TotalEnergies is interpreting the results for development studies.

In February 2022, TotalEnergies drilled the Venus-1X to a total depth of 6,296 m, discovering light, sweet oil, with associated gas within an Albian basin floor fan deposit, Impact Oil & Gas said. In a July 2023 earnings call, TotalEnergies chief executive officer Patrick Pouyanné said the company was continuing to test its Venus discovery noting that that “the oil column is very big” (OGJ Online, July 1, 2023).

The Venus-1A appraisal well drilling results were positive, having been successfully drilled, cored, and logged by the Tungsten Explorer to a total depth of 6,146 m, about 13 km north of the Venus discovery well. The Deepsea Mira will re-enter Venus-1A to undertake a drill stem test.

Tungsten Explorer will now drill the Mangetti-1X exploration well in the northern part of Block 2913B.

TotalEnergies is operator at PEL 56 (40%) with partners Impact Oil & Gas (20%, through its wholly owned subsidiary, Impact Oil and Gas Namibia (Pty) Ltd., QatarEnergy (30%), and NAMCOR (10%).


Vertex’s Alabama refinery ramps up conventional crude processing

Vertex Energy Inc. said measures undertaken during second-quarter 2023 to improve feedstock sourcing and enhance operational efficiencies likely will result in higher-than-anticipated crude oil throughputs during third-quarter 2023 at subsidiary Vertex Refining Alabama LLC’s 75,000-b/d refining and petrochemical complex in Mobile, Ala.

In an Oct. 13 update ahead of official third-quarter 2023 results on Nov. 7, Vertex said it expected the Mobile refinery’s quarterly crude throughputs between July-September averaged about 80,000 b/d, up from the operator’s previous forecast of 74,000-77,000 b/d.

Alongside increased crude throughputs, the yield of finished fuel products during the third quarter likely will account for 65-67% of the refinery’s total quarterly production volumes, higher than the previously forecasted range of 59-63%, according to the operator.

Vertex said higher-than-forecasted crude throughputs during third-quarter 2023 reflected the company’s continued focus on strengthening its conventional feedstock procurement program, which the operator initiated during the previous quarter in response to third-party disruptions to feedstock supply by certain vendors earlier in the year.

The refinery’s increased yield of finished fuel products during July-September resulted from implementation of a site-wide yield optimization initiative introduced early in second-quarter 2023, the operator said.

Production rates for renewable diesel during third-quarter 2023 from the Mobile refinery’s Phase 1 renewables unit averaged about 5,200 b/d, down from the second-quarter 2023 achievement of its nameplate 8,000-b/d Phase 1 capacity, according to the operator.

bp’s Archaea Energy starts up Indiana renewable gas plant

bp PLC-owned Archaea Energy Inc. has officially commissioned a first-of-its-kind renewable natural gas (RNG) plant designed to process by-product gas from landfill decomposing waste in Medora, Ind.

Located adjacent to Rumpke Consolidated Companies Inc.-owned Rumpke Waste & Recycling’s landfill and in service as of Oct. 4, the new Medora RNG plant—which is based on Archaea Energy’s proprietary Archaea Modular Design (AMD)—is equipped to capture and process 3,200 cu ft/min. of landfill biogas into RNG, bp said.

Based on the US Environmental Protection Agency’s Landfill Gas Energy Benefits Calculator, RNG production from the new plant will provide enough gas to heat around 13,026 homes annually, the company said.

Able to convert its waste gas feedstock into electricity, heat, or RNG, the AMD Medora plant’s design helps to further reduce greenhouse gas emissions (GHG) of processing activities as well as production, leading to cleaner air, less odor, and more sustainable energy when compared with traditional fossil fuel energy, according to bp and Archaea.

The Medora plant marks the first implementation of Archaea’s original AMD RNG plant design, which the company plans to replicate at additional US plants to be commissioned by yearend.

Unlike traditional RNG plants that, to date, have been custom built, Archaea Energy’s AMD standardized modular design streamlines and accelerates RNG plant build times by allowing plants to be built on skids with interchangeable components, the company said.

“Our goal is to safely bring several AMD plants online [across the US] this year,” said Starlee Sykes, chief executive officer of Archaea Energy.

With addition of the Medora plant, Archaea Energy now operates more than 50 RNG and landfill gas-to-energy sites across the US, producing more than 6,000 boe/d of RNG, according to the company’s website.

The Medora RNG plant is the first plant Archaea Energy has started up since the company’s acquisition by bp in late 2022.

Now the largest US RNG producer following its close of the Archaea Energy deal, bp said it plans to increase biogas supply volumes to about 70,000 boe/d by 2030.


Keyera completes KAPS condensate-NGL pipeline system

Keyera Corp. has completed its 575-km Key Access Pipeline System (KAPS). KAPS will transport 350,000 b/d of NGL and condensate from the Montney and Duvernay basins to Keyera’s liquids processing and storage hub at Alberta’s Industrial Heartland in Fort Saskatchewan.

“As natural gas continues to be a key contributor to the global energy mix and energy transition, especially in East Asia, we believe that KAPS has a critical role to play,” said Anthony Borreca, senior managing director at Stonepeak Partners LP, 50% owner of the system with operator Keyera.

Keyera operates 65,200 b/d of fractionation and a 30,000-b/d de-ethanizer at Fort Saskatchewan where it has a combined 15.5 million bbl of underground cavern and surface tank storage. In addition to shipping separated liquids by pipeline, Keyera operates rail and truck terminals as part of its Industrial Heartland infrastructure.

Stonepeak aquired its share of KAPS from Pembina Pipeline affiliate Pembina Gas Infrastructure earlier this year.

Venture Global requests FERC permission to place final Calcasieu Pass LNG blocks in service

Venture Global LNG Inc. has requested authorization from the US Federal Energy Regulatory Commission (FERC) to place Blocks 7-9 of its 10-million tonne/year (tpy) Calcasieu Pass LNG plant in service. The plant, sited in Cameron Parish, La., was designed to use 18 modular liquefaction trains configured in nine two-train blocks.

FERC last year issued approval to Venture Global to introduce hazardous fluids to the blocks. First LNG was produced from each between June 1, 2022 (Block 7A), and July 30, 2022 (Block 9B).

Venture Global said that it plans to increase its total nameplate LNG export capacity to more than 100 million tpy from 70 million tpy. In addition to Calcasieu Pass, which began production in January 2022, it is developing Plaquemines LNG, Delta LNG, and CP2 LNG, each with 20-million tpy capacity and also to be built in Louisiana.

The company has taken final investment decision on Plaquemines LNG, which is on target to produce first LNG in 2024. CP2 construction is expected to begin this year, with early site work at a location adjected to Calcasieu Pass LNG already under way. To date, 9.25 million tpy of CP2 LNG’s 20-million tpy capacity has been sold under 20-year agreements.

New Fortress advancing Brazil, Mexico LNG projects

New Fortress Energy Inc. expects to begin commercial operations at its two 6-million tonne/year (tpy) LNG terminals in Brazil over the next 3 months. Its terminal in Barcarena, at the mouth of the Amazon River on the country’s northern coast, is set for December 2023 startup, with Santa Catarina in southern Brazil set to follow in January 2024.

Barcarena will be the sole natural gas supplier in the region, according to New Fortress. Norsk Hydro ASA is the anchor customer, having signed a 15-year agreement to supply 81 MMcfd of natural gas to its Hydro Alunorte alumina refinery in Para, Brazil. New Fortress is building a 624-Mw power plant at the same site for 2025 startup and will use the regasified LNG to fuel it.

Santa Catarina will be connected to an existing gas distribution pipeline to help replace declining gas imports from Bolivia.

The third and final rig of New Fortress’ 1.4-million tpy Fast LNG (FLNG 1) plant offshore Altamira, Mexico, has arrived on station. The company now plans to build FLNG 2 onshore, according to its third-quarter 2023 earnings report, having set aside land for a 1.4-million tpy train adjacent to 300,000 cu m of storage. New Fortress plans to bring FLNG 2 online in 2025, using 200 MMcfd of feedgas supplied by pipeline from Texas.