OGJ Newsletter

March 27, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


Russia extends output cuts into June

Russian Deputy Prime Minister Alexander Novak said on Mar. 21 that Russia was close to completing the plan to reduce crude oil production by 500,000 b/d in March and that the country would reach the intended cut in a matter of days. Considering the current market situation, Russia decided to keep the reduced output until the end of June.

Novak gave no details of the planned production cuts but said Russia would not accept any external restrictions that posed “significant risks for the energy security of the whole world.” 

On Feb. 10, Russia announced plans to voluntarily cut production in March in response to the price cap imposed by the West. At that time, the Russian statement said that the price cap was an intervention in market relations and Russia’s output cut would contribute to restoration of market relations.

Crude oil futures had just come off 15-month lows before Novak announced the production cut extension. As the banking crisis in Europe and the US exacerbated the market’s worries about economic recession, it dampened the outlook for oil market demand. 

DNV approves FPSO-based green ammonia production concept

DNV has granted approval in principle (AiP) for the NH3 floating production, storage, and offloading (FPSO) concept developed by Netherlands-based SwitchH2 and BW Offshore Ltd. The concept involves converting either a very large crude carrier or a dedicated newbuild vessel to produce hydrogen by electrolysis of seawater and nitrogen through an air separation unit, using both as feedstock for ammonia synthesis.

The AiP covers all aspects of the integrated vessel concept including structural integrity, mooring, ammonia production, ammonia storage, and cargo handling. With the approval in place the project can now begin basic design.

Produced ammonia would be condensed, with the liquid ammonia stored in the hull for subsequent offloading to an ammonia carrier. The FPSO would receive most of its power from a wind farm.

In January 2023 Norway-based H2Carrier AS (H2C) signed an MOU with Larsen & Toubro (L&T) for cooperation in development of a separate floating green ammonia project, P2xFloater. Under the MOU, L&T also will become an engineering, procurement, construction, installation, and commissioning partner for the vessel’s topsides process plant, designing and fabricating the modules to produce green hydrogen and green ammonia, including the system’s electrolyzers, nitrogen generation, and ammonia synthesis.

H2C plans to build the P2XFloater hulls in yards in Asia. Installation and integration of the topsides modules could occur in India or elsewhere.

Bayou Bend expands carbon capture project with onshore Texas acreage

Bayou Bend CCS LLC, a carbon capture and sequestration project sited along the Texas Gulf Coast, is expanding its CO2 storage footprint through acquisition of nearly 100,000 acres onshore Chambers and Jefferson Counties, Tex., bringing gross storage capacity to more than one billion metric tons, Talos Energy said in release Mar. 6

The expanded project now encompasses nearly 140,000 acres of pore space for permanent CO2 sequestration when added to the existing 40,000 acres offshore Beaumont and Port Arthur, Tex.

Bayou Bend is a joint venture of Chevron USA Inc. through Chevron New Energies (operator, 50%), Talos Energy Inc.  through Talos Low Carbon Solutions (25%), and Carbonvert Inc. (25%).

“With the expansion, Bayou Bend is positioned to offer CCUS solutions across a broad region of the Gulf Coast, from Houston to Orange and into western Louisiana,” said Chris Powers, vice-president, CCUS, Chevron New Energies.

In 2021, Talos and Carbonvert were selected as the winning bidders for the Texas General Land Office’s Jefferson County, Tex., carbon storage lease, located in state waters offshore Beaumont and Port Arthur, Tex. Chevron joined the joint venture in May 2022.

Occidental hires Siemens to provide Permian DAC compression

Occidental Petroleum Corp. subsidiary 1PointFive will use Siemens Energy compressors at its 500,000-tonne/year (tpy) direct air capture (DAC) CO2 plant in Texas’ Permian basin. Siemens will supply a motor-driven 13,000-hp fully modular wet gas compressor package and a motor-driven 8,500-hp dry gas compressor for the DAC plant.

The equipment will compress the captured CO2 for additional processing and pressurize the final product into a pipeline for injection into underground reservoirs. Start-up is expected in late 2024.

1PointFive last year began early site construction on the DAC plant in Ector County, Tex., near Occidental’s Permian acreage. It will be scalable to 1 million tpy if demand warrants.

In a separate project, 1PointFive leased 55,000 acres along the Texas Gulf Coast to develop a 1.2-billion tonne carbon capture and sequestration hub (OGJ Online, Mar. 3, 2023).

Riley Permian to acquire New Mexico Yeso Trend assets

Riley Exploration Permian Inc., Oklahoma City, agreed to acquire Yeso Trend oil and gas assets in New Mexico from Pecos Oil & Gas LLC, an affiliate of Cibolo Energy Partners LLC, for $330 million.

The deal includes 11,700 total contiguous net acres in Eddy County (99% held by production), over 100 gross horizontal development drilling locations, and current production of 7,200 boe/d and 4,200 b/d of oil. Primary geologic targets include the Blinebry, Glorieta, and Paddock formations.

The deal includes 100% ownership of water gathering and disposal infrastructure including nearly 70 miles of water gathering pipelines, multiple saltwater disposal wells, and frac ponds.

The drilling economics compete with Riley Permian’s existing core asset focused on the San Andres formation in the northwest shelf of the Permian basin, with overall lower drilling and completion costs for shallower, conventional source rock as compared to deeper shale wells, the company said in a release Feb. 28.

The acquisition is expected to close early in second-quarter 2023.

Exploration & Development Quick Takes

Eni makes new oil discovery offshore Mexico

Eni SPA made a discovery on the Yatzil exploration prospect in Block 7 in the mid-deep water of the Cuenca Salina in Sureste basin, about 65 km offshore Mexico. The discovery may contain about 200 MMboe in place.

Yatzil-1 EXP is the second commitment well of Block 7 and the eighth successful one drilled by Eni in Sureste basin. It is about 25-30 km away from other discoveries.

The well was drilled by the Valaris DPS5 semisubmersible rig in 284 m of water and reached total depth of 2,441 m. Yatzil-1 EXP found in excess of 40 m net pay sands with good quality oil in the Upper Miocene sequences, with excellent petrophysical properties confirmed by an extensive subsurface data collection.

Eni is operator at Block 7 (45%) with partners Capricorn Energy PLC (30%) and Citla Energy (25%).

Chariot completes FEED for gas development offshore Morocco

Chariot Ltd. completed front-end engineering and design (FEED) on key components of the Anchois gas development project within the Lixus offshore license area, offshore Morocco.

The FEED was initiated in June 2022. In conjunction with subsurface development studies, FEED confirms individual components of the initial development. These components include three initial subsea producer wells, one of which is Anchois-2 drilled by Chariot in 2022 with multi zone completions enabling gas recovery across multiple stacked sands.

Other components in the FEED include subsea infrastructure (SURF and SPS) to deliver hydrocarbons from wells to onshore through a subsea flowline with control via an umbilical, future expansion capabilities to tie-back additional wells, onshore central processing and delivery of treated gas and condensate with an initial capacity of 105 MMscfd, and an onshore gas pipeline to deliver gas via the Maghreb Europe gas pipeline (GME). A tie-in agreement to GME has been signed.

In addition to the FEED, an environmental and social impact assessment is progressing, with onshore and offshore environmental baseline surveys finalized. The development drilling plan is ongoing with the aim of evaluating the potential of an additional 754 bcf of 2U prospective gas resources. A field development plan is being finalized for award of the production concession.

Chariot is operator of Lixus (75%). Office National des Hydrocarbures et des Mines (ONHYM) holds the remaining 25%.

Shell to tie back Dover to Appomattox

Shell PLC subsidiary Shell Offshore Inc. has taken final investment decision to tie back Dover to the offshore Appomattox production hub in Mississippi Canyon, 170 miles southeast of New Orleans in about 7,500 ft of water.

Dover will have two production wells producing through a 17.5-mile flowline and riser and is expected to produce up to 21,000 bo/d at peak rates.

Shell has 100% working interest in Dover. Shell is operator at Appomattox (79%) with partner Chinese National Offshore Oil Corp. (CNOOC, 21%).

Drilling & Production Quick Takes

Norway production up in February, NPD says

Norway’s production averaged 1.994 million bbl in February, the Norwegian Petroleum Directorate (NPD) reported. The figure is up from the 1.979 million bbl produced in January.

Average daily liquids production in February consists of 1.776 million b/o, 194,000 bbl of NGL, and 24,000 bbl of condensate. Oil production in February is 2.8% lower than NPD’s forecast and 2.5% lower than the forecast so far this year.

Tlou Energy begins drilling at the Lesedi gas-to-power project, Botswana

Tlou Energy Ltd. started the next phase of drilling at its Lesedi gas-to-power project in Botswana. Operations have begun on a core-hole and will be followed by drilling of the next gas production well.

Lesedi 6 is the first well of a planned drilling program to expand gas production at the Lesedi project. Gas flows from Lesedi 6 are planned to be converted to electricity for the existing 10-Mw power-purchase agreement with Botswana Power Corp. (BPC) once the transmission line, substations, and associated electrical infrastructure are in place.

The objective of the core-hole is to provide additional geological control in the vicinity of the planned Lesedi 6 gas-production pod. The core-hole, designated C8-1X, is at a depth of about 200 m with a proposed total depth of about 550 m.

Spudding of the Lesedi 6 gas production pod is expected by end-March. The pod consists of three wells, one vertical production well and two intersecting lateral wells. Lesedi 6 is about 500 m west of the existing Lesedi 4 production pod.

The transmission line for grid connection from the Lesedi project to Construction of BPC’s Serowe substation is about 60% copmplete with anticipated completion midyear. Stringing of the power poles has begun.

2P gas reserves at the field are about 41 bcf, 3P gas reserves are about 427 bcf, and 3C contingent resources are about 3,043 bcf.

Tlou Energy is operator and 100% owner of the project.

Norwest Energy spuds Perth basin well

Norwest Energy NL spudded the Lockyer-2 gas appraisal well in EP368, onshore Perth basin, Australia, according to a Mar. 15 release by partner Energy Resources Ltd.

Lockyer-2 is a downdip step-out appraisal well to the Lockyer Deep-1 discovery, aimed at confirming the extension of the discovery to the northeast within the northern segment of the greater Lockyer structure (segment defined due to the possibility of faulting across the structure).

Lockyer-2 has a planned total depth (TD) of 4,451 m TVDSS and the time required to reach TD is estimated at 35 days from spud.

In September 2021 the EP368 joint venture drilled the Lockyer Deep-1 gas discovery well, resulting in a conventional gas discovery that flowed up to 117 MMscfd on test.

Energy Resources Ltd. is operator at EP368 (80%). Northwest Energy holds the remaining 20%.

Kuwait Energy brings Abu Sennan well online

Kuwait Energy Egypt brought the ASH-8 development well onstream in the Abu Sennan license, 7 km north of the producing Al Jahraa field in Egypt’s Western Desert, partner United Oil & Gas PLC said in a Mar. 21 release.

The well, the fifth in ASH field, targeted an undrilled area of the license and encountered 22 m net oil pay in the primary Alam El Bueib (AEB) reservoir target, in line with pre-drill expectations. After reaching TD, the well was completed and tested on chokes from 24/64-in. (2,177 boe/d) to 64/64-in (7,663 boe/d). These rates are above pre-drill expectations.

The well has been tied into existing infrastructure and brought on stream at an initial rate of about 2,980 bo/d and 2.64 MMscfd gross on a 32/64-in. choke.

The ST-1 rig is moving to the ASD-3 location to drill the second development well in the 2023 drilling program, which is expected to spud in the coming weeks. 

Abu Sennan is operated by Kuwait Energy Egypt (25%). Joint venture partners are United Oil & Gas (22%), Global Connect Ltd. (25%), and Dover Investments (28%).


ExxonMobil commissions Beaumont refinery expansion

ExxonMobil Corp. has started up its project to expand light crude oil processing capacity by 250,000 b/d at ExxonMobil Product Solutions Co.’s integrated refining and petrochemicals complex in Beaumont, Tex. (OGJ Online, July 29, 2022).

Officially in operation as of Mar. 16, the $2-billion expansion increases the refinery’s overall crude processing capacity to more than 630,000 b/d, the operator said.

Proposed in 2018 and formally approved in early 2019, the expansion added a third crude unit and hydrotreaters to accommodate the operator’s growing Permian light crude production, to which the refinery is linked via pipeline.

ExxonMobil said the Beaumont refinery’s new crude unit also will be positioned to further capitalize on segregated crude from the Permian’s Delaware basin. Delaware production will be delivered via the ExxonMobil Pipeline Co.-operated 650-mile, 36-in. Wink-to-Webster pipeline that delivers to Webster, Baytown, and the Enterprise Crude Houston Oil terminal, in addition to providing connectivity to Texas City and Beaumont (OGJ Online, Oct. 16, 2020).

An ExxonMobil spokesperson told OGJ the refinery also has completed connecting pipeline additions at the site to accommodate the expansion’s increased intake and offtake of crude and finished products, respectively.

“ExxonMobil maintained its commitment to the Beaumont expansion even through the lows of the pandemic, knowing consumer demand would return and new capacity would be critical in the post-pandemic economic recovery,” said Karen McKee, president of ExxonMobil Product Solutions.

The recent expansion adds the equivalent capacity of a medium-sized refinery, she said.

Technip Energies provided engineering, procurement, and construction (EPC) of four units added as part of the expansion—including an atmospheric pipe still, kerosine hydrotreater, diesel hydrotreater, and benzene recovery unit—while KBR Inc. delivered EPC services for the project offsites and interconnecting units (OGJ Online, Feb. 25, 2019).

Permian growth

In its fourth-quarter and full year 2022 earnings presentation, the operator said it increased Permian net production by about 90,000 boe/d to about 550,000-560,000 boe/d year-over-year, with overall production from its regional operations anticipated to reach more than 600,000 boe/d during 2023.

By 2027, ExxonMobil said it plans to grow Permian output to about 1 million boe/d.

BPCL adding new unit to Mumbai refinery

Bharat Petroleum Corp. Ltd. (BPCL) let a contract to Chevron Lummus Global LLC (CLG) to deliver technology licensing for a processing unit to be installed at the operator’s 12-million tonne/year (tpy) refinery in Mumbai, Maharastra, India.

As part of the contract, CLG will provide its proprietary Isofinishing hydrofinishing technology for a new 200,000-tpy catalytic processing unit that—once completed—will become India’s first to produce specialty de-aromatized solvents and premium industrial white oils conforming to the most stringent international aromatic and color specifications, the service provider said.

CLG said its scope of work includes delivery of engineering services as well as supply of proprietary equipment and noble-metal catalysts—which provide higher activity at lower temperatures than base-metal catalysts—for the planned unit.


Equinor, Shell, Tanzania complete LNG plant negotiations

Equinor ASA and Shell PLC completed negotiations with the Tanzanian government for construction of an LNG plant in the country, according to the Tanzanian Ministry of Energy. Contracts to formalize the agreement are now in development.

When last discussed in detail, the 10-million tonne/year plant was to have been built near Lindi on the Tanzanian coast. The Tanzanian government hopes to reach final investment decision on the project in 2025.

Topics included in contract development are terms for “joining Blocks 1, 2, and 4,” which will provide natural gas for the project. Equinor’s nine gas discoveries in Block 2 northeast of Lindi hold total in-place volumes of roughly 22 tcf. Shell-operated Blocks 1 and 4 hold an estimated combined total of 16 tcf of recoverable gas.

ExxonMobil awards Papua LNG FEED, EPC estimation contracts

ExxonMobil Corp. has awarded JGC Holdings Corp. and Hyundai Engineering & Construction Co. Ltd. the front-end engineering design (FEED) and engineering, procurement, and construction (EPC) estimation contracts for the 4-million tonne/year (tpy) Papua LNG plant in Papua New Guinea. Papua LNG will be built within the boundaries of ExxonMobil’s existing 8.3-million tpy PNG LNG plant, 20 km northwest of Port Moresby, and use 2 million tpy of PNG LNG’s capacity.

A final investment decision (FID) for Papua LNG is expected at end-2023 or early 2024 with construction to begin in 2024. The new plant will use four electrical LNG trains instead of trains powered by gas turbines for compression.

Natural gas will come from the onshore Elk-Antelope field, which holds roughly 6.5 tcf of natural gas and 57 million bbl of condensate. The fields could be brought on stream by late 2027 or early 2028.

ExxonMobil holds 37.1% of Papua LNG. Its partners are TotalEnergies SE (40.1%) and Santos Ltd. (22.8%). The Papua New Guinea government can exercise a back-in right of up to 22.5% at FID.

Botas leases FSRU from Swan Energy

Turkish-state Botas has leased 180,000-cu m floating storage and regasification unit (FSRU) Vasant One from Swan Energy Ltd. subsidiary Triumph Offshore Pte. Ltd. The 5-million tonne/year FSRU is being rented at a rate of $250,000/day for 1 year and will be stationed in Saros Bay.

Triumph let Vasant One as a bareboat charter, with Botas assuming all operational expenses. The vessel was built by Hyundai Heavy Industries and delivered to Swan in 2020 for use as part of an LNG import terminal at Jafrabad, Gujurat, India.

Botas commissioned Turkey’s first FSRU, the 170,000-cu m, 28-million cu m/day Ertug˘rul Gazi, at Dörtyol terminal in 2021. The terminal unloads two ships each month and can meet more than 10% of the country’s natural gas demand, according to Botas.

German LNG awards tank-design contract

German LNG Terminal GMBH engineering, procurement, and construction (EPC) contractor Sener Group awarded TGE Gas Engineering GMBH-Technodyne International Ltd. a contract for the outer tank design for two 165,000-cu m LNG storage tanks at the 8-billion cu m/year German LNG onshore terminal under development in Brunsbüttel, Germany. The companies plan to complete construction of the terminal in 2026.

In 2022, German LNG awarded the EPC contract to a consortium of Sener and Cobra IS, a Vinci Group company. The terminal developer is a consortium of NV Nederlandse Gasunie (40%), RWE AG (10%), and the German government (50%).

German LNG has agreed with foundation customers INEOS Group Ltd., ConocoPhillips Co., and RWE Supply & Trading for long-term regasification capacity at the terminal.

While the German LNG terminal is being built, RWE has chartered the Hoegh Gannet floating storage and regasification unit (FSRU) on behalf of the German government. The FSRU, stationed in Brunsbüttel as the Elbehafen LNG terminal, received its commissioning cargo in February.