OGJ Newsletter

July 10, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


Saudi Arabia, Russia to make additional oil supply cuts

Saudi Arabia and Russia, renowned as the largest oil exporters globally, have intensified their oil supply reductions.

Saudi Arabia said July 3 that it will prolong its voluntary production reduction of 1 million b/d for an additional month to include August and expressed the possibility of extending the reduction even further.

The country, on June 4, committed to reduce its oil output by 1 million b/d for the month of July (OGJ Online, June 5, 2023). This reduction is in addition to the broader OPEC+ agreement aimed at limiting the supply of oil until 2024, as the group endeavors to uplift declining oil prices.

Following Saudi Arabia’s declaration, Russian Deputy Prime Minister Alexander Novak stated that Moscow would cut its oil exports by 500,000 b/d during the month of August.

“Within the efforts to ensure the oil market remains balanced, Russia will voluntarily reduce its oil supply in the month of August by 500,000 b/d by cutting its exports by that quantity to global markets,” Deputy Prime Novak said. No information was provided on whether Russian oil output would also decline by the same amount.

Although Novak’s statement pertained to exports, Russia earlier this year committed to decrease its oil production by 500,000 b/d based on a February baseline. Russia pledged to sustain the reduced production level until 2024.

Centrica, Wood evaluating converting Easington gas terminal to low-carbon hub

Centrica Storage Ltd. is working with John Wood Group PLC to evaluate the feasibility of transforming Centrica’s Easington gas processing terminal to a low-carbon production hub. Centrica Storage last year partnered with Equinor ASA to explore developing such a hub in the region as part of the UK’s Zero Carbon Humber initiative.

Based in East Yorkshire, the hub would be integrated with Centrica’s Rough field redevelopment, as well as the Easington Terminal’s hydrogen fuel switching project, both of which Wood is executing parallel studies for.

Centrica said that development of the Easington low-carbon hub over the next 10 years supports the company’s goal to achieve net zero by 2045. “We are excited to continue our collaboration with Wood as we explore opportunities to fulfil our pledge of facilitating the UK’s transition to net zero,” added Martin Scargill, Centrica Storage managing director, “with our goal [being] to establish 1 Gw+ of green and blue low-carbon hydrogen [production] at Easington.”

Centrica Storages’s parent company, Centrica PLC, last month was granted a carbon storage license by the North Sea Transition Authority, advancing its plans to repurpose North and South Morecambe natural gas as a UK carbon capture and storage hub. The license was granted to Spirit Energy Ltd., Centrica’s (69%) partnership with Stadtwerke München GMBH SWM (31%). The planned hub could initially store more than 5 million tonnes/year (tpy) of CO2, with potential to store as much as 25 million tpy.

TotalEnergies, Petronas to collaborate on renewable projects in Asia-Pacific region

TotalEnergies and Gentari Renewables Sdn Bhd, a Petronas company, have agreed to develop renewable energy projects in the Asia Pacific region.

The first material implementation of the agreement will be to jointly develop the 100Mw Pleasant Hills solar project in Queensland, Australia, to supply low-carbon electricity to Roma field gas production and processing infrastructure, TotalEnergies said in a release June 26.

The project is expected to lower emissions of Gladstone LNG (GLNG) on Curtis Island, the company said.

GLNG converts natural gas, including coal seam gas from the Bowen and Surat basins, into LNG for export to Asia.

TotalEnergies and Gentari’s parent company, Petronas, each hold a 27.5% stake in GLNG, along with partners Santos Ltd. and Kogas. 

Exploration & Development Quick Takes

Frontera, CGX discover hydrocarbons at Wei-1, Corentyne block

Frontera Energy Corp. discovered oil at the Wei-1 well on Corentyne block, about 200 km offshore from Georgetown, Guyana. The company successfully finished drilling operations and expects to release the drilling rig in early July 2023.

The well targeted Maastrichtian, Campanian, and Santonian aged stacked sands within channel and fan complexes in the northern section of the block and encountered 210 ft of hydrocarbon bearing sands in the Santonian horizon (OGJ Online, Jan. 23, 2023). Frontera acquired wireline logs and extensive core samples from the Santonian, however, due to a tool failure downhole and a new tool not being available, oil samples were not obtained. The rock and fluid properties of the Santonian will be analyzed by an independent third-party laboratory over the next 2-3 months to define net pay and a basis for the evaluation of this interval.

The previously announced discovery in the Maastrichtian and the Campanian intervals has been updated to 77 ft of net pay. Fluid samples were retrieved from the Campanian and Maastrichtian indicating the presence of light crude in the Campanian and sweet medium crude oil in the Maastrichtian.

The data acquisition program included wireline logging, MDT fluid samples, and sidewall cores throughout the various intervals. Over the next few months, results will be integrated into the geologic and geophysical models to form an updated view of the entire northern portion of the Corentyne block.

The northern portion of the block includes the channel complexes discovered by the Kawa-1 and Wei-1 wells, and a prospective central channel complex, which is yet to be evaluated.

Frontera is majority shareholder of CGX Energy Inc. and joint venture partner with CGX in the block.

Azule Energy lets subsea contract for Block 18 offshore Angola

Azule Energy has let a contract to TechnipFMC to supply subsea production systems for the Block 18 infills development, offshore Angola.

The existing field layout will be reconfigured to accommodate new equipment to support the planned production increase. TechnipFMC will design and manufacture subsea trees, a manifold, subsea distribution equipment, and topside controls, as well as jumpers, flowlines, and umbilicals.

This contract follows a flexible pipe supply contract for Azule’s Agogo Integrated West Hub Development (OGJ Online, Feb. 28, 2023). The subsea production contract will be included in TechnipFMC’s inbound orders in second-quarter 2023.

Azule Energy is a joint venture between bp PLC (50%) and Eni SPA (50%) and is operator at Block 18.

Aker BP approved for Symra, Solveig Phase 2 development

Aker BP ASA received approval from the Ministry of Petroleum and Energy (MPE) for development of Symra and Solveig Phase 2 in the Utsira High area of the North Sea.

Symra field will be a tie-in to the Ivar Aasen production platform. Production is expected to begin in first-quarter 2027. Aker BP and partners Equinor Energy AS and Sval Energi AS submitted the PDO in December 2022 (OGJ Online, Dec. 16, 2022).

Development of Solveig Phase 2 is an extension of the PDO for Solveig’s first development phase. It will be connected to the Edvard Grieg platform. Phase 2 production is expected to start in first-quarter 2026. Aker BP is operator at Solveig, with OMV Norge AS and Wintershall Dea AS as license partners.

The two developments comprise a total 93 MMboe in estimated recoverable resources and will be carried out as a joint project. Drilling operations will begin in third-quarter 2025. Total investments are estimated at NOK 16 billion.

Drilling & Production Quick Takes

ExxonMobil plans 35-well drilling campaign offshore Guyana

ExxonMobil has been granted environmental authorization by the Environmental Protection Agency (EPA) of Guyana for a 35-well exploration and appraisal drilling campaign on Guyana’s offshore Stabroek block.

The agency approved the multi-well project following review of the Environmental Impact Statement and Environmental Impact Assessment of the Cumulative Effects related to the project. The EPA “is satisfied that the project can be conducted in accordance with good environmental practices, and in a manner that avoids, prevents and minimizes any adverse effects which could result from the activity,” it noted in a statement July 2.

Esso Exploration and Production Guyana Ltd. (EEPGL), an ExxonMobil affiliate and operator of the block, plans to further explore and appraise the block’s hydrocarbon reserves.

The project scope includes 35 exploration and appraisal wells. Exact locations have not been finalized. Work is currently scheduled from third-quarter 2023 through 2028.

If discoveries are found, subsequent wells could be drilled to further assess potential commerciality. Thus, priorities and schedules could change, and EEPGL will continue to submit necessary well information to obtain operations permit approval from the EPA prior to the respective spud dates.

For the analysis, EEPGL noted use of two full-time drill ships working concurrently on project development wells. Additional drill ships may be used to accelerate the drilling schedule, as allowed by simultaneous operations.

EEPGL is operator of the block with 45% interest. Hess Guyana Exploration Ltd. holds 30% interest and CNOOC Petroleum Guyana Ltd. holds 25% interest.

Po Valley Energy readies Selva field well for production start

Following regional flooding issues that caused delays, Po Valley Operations Pty Ltd. has been granted approval to start gas production at Selva field in the Po Valley region of northern Italy.

Final safety checks conducted by UNMIG and the local fire department have been completed and the Italian Energy Ministry, the Ministry of Environment and Energy Security, has issued formal documentation, enabling production start from the Podere Maiar-1 (PM-1) well, according to a release from Prospex Energy LLC.

Po Valley Operations, operator of the Selva Malvezzi production concession, expects gas production ramp-up at PM-1 will begin in early July 2023.

A slickline unit has been moved to the well site and has started necessary activities to allow gas production to start.

Po Valley Operations Pty Ltd., a wholly owned subsidiary of Po Valley Energy Ltd., is operator with 63% interest. Prospex holds the remaining 37%.

RIL-bp consortium brings deepwater India gas-condensate field online

Reliance Industries Ltd. (RIL) and bp PLC started production from MJ field in Krishna Godavari (KG) D6 block off the east coast of India following testing and commissioning activities.

MJ field is a high pressure and high temperature (HPHT) gas-condensate field. It will produce from eight wells and reach a peak gas production of about 12 std cu m/d of gas and 25,000 b/d of condensate.

Ruby, a new FPSO, will process and isolate condensate, gas, water, and contaminants before bringing gas onshore for sale. Condensate is held on the FPSO before being offloaded to shuttle tankers for delivery to Indian refineries.

MJ field lies in water depths up to 1,200. It’s start follows that of of R-Cluster field in December 2020 and Satellite Cluster in April 2021. All three utilize existing hub infrastructure for the block.

Together, the three fields are expected to produce about 1 bcfd when MJ field reaches peak production, which is expected to account for about one third of India’s current domestic gas production and meet about 15% of India’s demand.

RIL is operator of the block with 66.67% interest. bp holds the remaining 33.33% interest.

TotalEnergies to start drilling offshore Namibia

TotalEnergies SE has started drilling offshore Namibia with Northern Ocean Ltd.’s Deepsea Mira semisubmersible drilling rig.

The drilling contract has a firm duration of 300 days with two unexercised options which would extend the term through all of 2024. Odfjell Drilling AS prepared and mobilized the rig to Namibia and is providing operations management for the duration of the contract.

TotalEnergies SE has plans for a multi-well drilling program offshore Namibia following the Venus light oil discovery in Block 2913B (PEL 56), according to a Feb. 22 release by Impact Oil & Gas Ltd. (OGJ Online, Feb. 22, 2023).

Deepsea Mira will re-enter and side-track Venus-1X well and conduct a flow test. The objective is to further evaluate the Venus reservoir and deliver dynamic data.

TotalEnergies and partners will also explore the Venus accumulation into Block 2912 (PEL 91) to provide an understanding of the structure and reservoir quality. The block covers about 7,884 sq km in water depths of 3,000-3,900 m.


Eni-PBF Energy joint venture begins renewable diesel production in Louisiana

PBF Energy Inc. and partner Eni SPA subsidiary Eni Sustainable Mobility SPA (ESM) have started production at 50-50 joint venture (JV) St. Bernard Renewables LLC’s (SBR) new biorefinery co-located at PBF Energy subsidiary Chalmette Refining LLC’s 185,000-b/d dual-train coking refinery in Chalmette, St. Bernard Parish, La.

SBR’s biorefinery has started operations of its main unit, which began commercial production of renewable diesel in June, Eni and PBF Energy said in separate releases on June 28.

With an associated pretreatment unit at the site designed to process 1.1 million tonnes/year (tpy) of renewable materials such as soybean oil, corn oil, and other biogenically derived fats and oils into feedstocks also now mechanically completed and due for startup in the coming weeks, SBR’s Chalmette plant remains on track to ramp up to its full renewable diesel production capacity of 306 million gal/year this year, the partners said.

Confirmation of the biorefinery’s main unit startup follows mechanical completion earlier this year on project involving retrofitting of an idled, conventional hydrocracking unit at the refinery with the Eni-Honeywell UOP LLC codeveloped proprietary Ecofining process technology to enable production of renewable diesel.

ADNOC lets contract for Habshan gas processing complex

Abu Dhabi National Oil Co. (ADNOC) subsidiary ADNOC Gas PLC has let a contract to Petrofac Ltd. to provide engineering, procurement, and construction (EPC) of a new plant as part of a broader project to expand capacity at its multi-train natural gas processing complex at Habshan, in Al Gharbia, Abu Dhabi Emirate, southwestern UAE.

As part of the estimated $700-million contract, Petrofac Emirates will deliver EPC services for a planned gas compression plant comprised of three compressor trains, associated utilities, and power systems, the service provider said June 30.

Petrofac said the new plant will support ADNOC’s aim of increasing gas output from the onshore Habshan complex.

Featuring a combined gas processing capacity of 6.1 bcfd, the 14-train Habshan hub currently includes five plants that receive offshore gas produced from Umm Shaif Khuff and Umm Shaif reservoirs via Das Island for further processing and subsequent distribution to mostly utilities and industrial companies throughout the UAE, according to the operator’s website.

In a May 2023 investor presentation, ADNOC Gas confirmed two ongoing major projects involving the Habshan complex, including Integrated Gas Development Expansion Phase 2 (IGD-E2) and Project 5.0.

Scheduled to come onstream in 2024, IGD-E2 is designed to enable supply of an additional 370 MMcfd of gas from Das Island to Habshan to bring total gas export capacity to nearly 1.97 bcfd, ADNOC Gas said.

The separate Project 5.0 involves modifications at the Habshan 1 and Habshan 5 plants, as well as plants at Asab, Bu Hasa, and Ruwais, that will bring more than 1 bcfd of gas—including additional rich-gas volumes—onshore once completed.

Slated for phased commissioning from 2027 onwards, Project 5.0 will also simultaneously help increase regional oil production to 5 million b/d, according to the presentation.

Petrofac did not specify to which project its latest contract award is associated.

IGD-E2 will involve construction of grassroots installations on Das Island, including a new booster compression train, two feed-gas compression and dehydration trains, and two amine-based fuel gas treatment units.

Initiated in 2009 and completed in 2013, the initial IGD program was designed to enable transfer of 1 bcfd of high-pressure gas from Umm Shaif field, via Das Island, to Habshan and Ruwais.

In 2015, ADNOC Gas launched IGD-E1—the first-phase expansion—to boost offshore gas processing capacity by 400 MMcfd to 1.4 bcfd by 2018.

IGD-E1 specifically entailed:

  • Construction of a fourth gas dehydration unit and dry gas compression aftercooler on Das Island.
  • New gas pipelines, including a 117-km offshore segment and 114-km onshore segment.
  • New condensate pipelines.
  • Unidentified modifications to the Habshan gas processing complex.


Mountain Valley pipeline authorized to resume construction

Equitrans Midstream Corp. received US Federal Energy Regulatory Commission (FERC) authorization to move forward with all remaining construction associated with its 2-bcfd Mountain Valley natural gas pipeline project (MVP). MVP had requested FERC approval on June 26, 2023, for the pipeline that first got its certificate of public convenience and necessity Oct. 13, 2017.

The 303-mile pipeline, construction of which is 94% complete, will carry Marcellus shale gas production from Wetzel County, W. Va., to Transcontinental Pipe Line Co. LLC’s Compressor Station 165 in Pittsylvania County, Va. Construction began in February 2018.

In July 2018, the Court of Appeals for the Fourth Circuit vacated the Forest Service’s record of decision and the Bureau of Land Management’s right-of-way grant that authorized the project to cross Jefferson National Forest. MVP has been the subject of legal wrangling ever since.

In its most recent authorization FERC noted specifically that Mountain Valley is authorized to proceed with construction in the Jefferson National Forest, and all remaining waterbody crossings, including waterbody crossings previously approved through the commission’s variance process.

Pres. Joe Biden has signed legislation approving all necessary permits and authorizations required for the pipeline’s construction and operation. Equitrans intends to complete construction by end-2023 at an estimated cost of $6.6 billion.

Gassco gains consent for first phase Valemon pipeline disposal

Norway’s Gassco AS has been granted consent by the Petroleum Safety Authority for disposal of the Valemon rich gas pipeline in the North Sea.

Consent applies to phase 1 disposal of the 177-km, 22-in. OD pipeline, which has been used to transport gas to Heimdal riser platform from Valemon field.

Decommissioning and disposal of pipeline will be carried out in three phases. Phase 1 involves the removal of hydrocarbons and water filling (activity period 2023), while phase 2 and phase 3 include the disconnection of the pipeline from Heimdal platform, removal of remaining structures, and other activities in preparation for permanent abandonment of the field and safety zone (activity period 2024-2028).

Leviathan partners take FID on third natural gas pipeline

NewMed Energy LP and its partners in Leviathan natural gas field offshore Israel have taken final investment decision (FID) on a third subsea transmission pipeline from Leviathan’s deepwater wells to its production platform about 10 km from shore. The pipeline will allow expansion of the maximum gas supply capacity from Leviathan to Israel Natural Gas Lines Ltd.’s transmission system to 1.4 bcfd from 1.2 bcfd by mid-2025 and cost $568 million.

Project partners earlier this year approved a 2023 budget to advance Phase 1B development of Leviathan. Expansion plans include a 4.6-million tonne/year floating LNG plant.

Leviathan produces roughly 12 billion cu m/year (bcmy) for sale to Israel, Egypt, and Jordan. Plans call for adding 9 bcmy, to include shipments to Europe. The field holds estimated in-place gas volumes of 934 bcm (33 tcf) and estimated recoverable reserves of 605 bcm (22 tcf).

NewMed’s (45.34%) partners in Leviathan are Chevron Mediterranean Ltd. (operator, 39.66%) and Ratio Energies LP (15%).

ADNOC to expand UAE gas pipeline network

ADNOC Gas PLC awarded contracts to Petrofac Emirates LLC and a consortium of National Petroleum Construction Co. PJSC and CAT International Ltd. for a 300-km expansion of its natural gas pipeline network. The sales gas pipeline network enhancement program (ESTIDAMA) will increase ADNOC Gas’s existing pipeline network to more than 3,500 km, boosting volumes delivered to northern portions of the UAE.

ESTIDAMA consists of several packages, the first of which was awarded in 2021 and completed this year for early modification works on existing pipelines. The second and third, being awarded now, include construction of new pipelines and a previously awarded gas compression plant in Habshan.

The pipeline program’s cost is an estimated $1.34 billion.