OGJ Newsletter

 GENERAL INTEREST Quick Takes

Williams to acquire Trace Midstream Haynesville assets

Williams, Tulsa, Okla., has agreed to acquire the Haynesville gas gathering and processing assets of Trace Midstream in a deal valued at $950 million.

The transaction, which expands the company’s footprint into the East Texas region of the Haynesville, increases Williams’ gathering capacity in the basin to over 4 bfcd from 1.8 bcfd.

Trace’s Haynesville assets include the Gemini Carthage Pipeline (GCP) system, Endeavor gathering, and Star gathering system. These pipeline systems span Panola and Harrison counties in East Texas and Caddo, Webster, and Bienville parishes in Louisiana, and include more than 240 miles of high and low-pressure pipelines as well as multiple treating and dehydration facilities.

In early 2020, Trace Midstream and Gemini Midstream, each a portfolio company of Quantum Energy Partners, agreed to combine and operate as Trace Midstream, expanding commercial presence in East Texas (OGJ Online, Jan. 31, 2020).

As part of the deal Williams deal, Trace customer and Quantum affiliate Rockcliff Energy agreed to a long-term capacity commitment in support of Williams’ Louisiana Energy Gateway (LEG) project. The project is designed to gather Haynesville natural gas and connect it to Transco natural gas pipeline system markets and Gulf Coast LNG markets.

Additionally, Williams signed a memorandum of understanding with Quantum to form a joint venture to enable Quantum to become a project equity investor and partner.

The transaction is expected to close in this year’s second quarter subject to regulatory approvals.

SandRidge to drill new Northwest Stack wells, continue well reactivation program

SandRidge Energy Inc., Oklahoma City, plans to spend $34-42 million in drilling and completions capital and $7-8 million in non-drilling and completions capital for 2022. Total production for the year is projected to be 5.6-6.8 MMboe.

In 2022, the operator plans to drill and complete 9 new wells on its previously delineated Northwest Stack acreage in Oklahoma. The company expects also to continue its well reactivation program throughout the year.

For fourth-quarter 2021, the operator had net income of $36.8 million and net cash provided by operating activities of $43.9 million. After adjusting for certain items, adjusted net income was $32.9 million, operating cash flow totaled $37.3 million, and adjusted EBITDA was $37.5 million for the quarter.

For full-year 2021, SandRidge had net income of $116.7 million, and net cash provided by operating activities of $110.3 million. After adjusting for certain items, adjusted net income was $96.3 million, operating cash flow totaled $112.7 million, and adjusted EBITDA was $113.5 million for the year.

Production totaled 1.697 MMboe (18,400 boe/d, 13% oil, 34% NGLs, 53% natural gas) for the quarter and 6.793 MMboe (18,600 boe/d, 14% oil, 33% NGLs, 53% natural gas) for full-year 2021. Total production includes North Park basin prior to Feb. 5, 2021. The company closed the sale of the Colorado asset for $47 million in February 2021.

Production in the Mid-Continent totaled 1.697 MMboe (18,400 boe/d, 13% oil, 34% NGLs, 53% natural gas) for the quarter and 6.726 MMboe (18,400 boe/d, 13% oil, 34% NGLs, 53% natural gas) for full-year 2021.

During the fourth quarter, SandRidge continued returning wells to production that were previously curtailed due to the commodity price downturn in first-half 2020. As of Dec. 31, 2021, the operator brought 129 wells back online. About 108 of these required workovers to return to service and accounted for capital expenditures of $7 million and expense dollars of $1.2 million.

Golden Beach gas project advances toward FID with government loan

The Australian government has granted a $32 million (Aus.) commercial loan to G B Holdings Ltd., Melbourne, to accelerate development of Golden Beach gas field in the offshore Gippsland basin of eastern Victoria. The loan is intended to speed the project towards a final investment decision.

The field, discovered by Burmah Oil Co. in 1967, lies in shallow Victorian State waters 3 km off the Ninety Mile beach near the hamlet of Golden Beach.

The project will tap a 32 m-thick gas column in a reservoir about 620 m below seabed and involves drilling two production wells tapped as subsea completions connected to a buried subsea pipeline to bring gas to shore and connect with existing infrastructure near ExxonMobil’s gas hub at Longford.

GB Energy will drill the wells, construct the pipeline, and build a compressor station to enable the gas to be injected into the Longford to Melbourne gas trunkline (OGJ Online, Apr. 3, 2020).

Gas production into the Victorian domestic market is expected to last for 2 years, after which the depleted reservoir will be converted into an underground gas storage facility with capacity of about 12.5 petajoules.

The project was identified in a government fund created in the 2021 budget to accelerate priority projects to alleviate the projected gas supply shortfall on Australia’s east coast.

Talos signs Texas carbon capture site lease

Bayou Bend CCS LLC, a joint venture of Talos Energy Inc. and Carbonvert Inc., executed definitive lease documentation with the Texas General Land Office, formalizing the carbon capture and sequestration (CCS) site offshore Jefferson County, Tex., near the Beaumont and Port Arthur industrial corridor (OGJ Online, Aug. 25, 2021).

The document establishes the first ever major offshore carbon sequestration site in the US, Talos said in a release Mar. 16. The lease comprises over 40,000 acres and maintains an estimated sequestration capacity of 225-275 million metric tons of CO2. Talos will be operator with 50% interest.

The company is seeking anchor industrial partners for the project as well as a midstream transportation solution in the region. The company’s CCS projects are organized under Talos Low Carbon Solutions LLC, the company’s CCS subsidiary.

In a separate deal, Talos established a CCS alliance with Core Laboratories NV to provide technical evaluation and assurance services for CCS subsurface analysis, including the company’s upcoming 2022 stratigraphic evaluation wells.

The alliance will aid to deliver technical assurance for Talos’ growing portfolio of sequestration sites and strengthens technical capabilities leading up to the filing of CO2 injection well permits this year, the company said.

Gorman to succeed Uhl as Shell CFO as role moves to the UK

Shell plc appointed Sinead Gorman as chief financial officer, effective Apr. 1, succeeding Jessica Uhl, who has served in the role for the last 5 years. Gorman will become a member of both Shell’s executive committee and board of directors.

Gorman serves as executive vice-president, finance in Shell’s global upstream business. She joined Shell in 1999.

Uhl spent 17 years with Shell. She will step down from her role as chief financial officer on Mar. 31, but remains available to assist with the transition until June 30.

The company recently simplified its share structure and relocated corporate headquarters. As part of that strategy, the roles of chief executive officer and chief financial officer have moved to the UK from The Netherlands. Due to family circumstances, a long-term relocation to the UK is not sustainable for Uhl, thus her departure from the group, Shell said.

 Exploration & Development Quick Takes

Eni, Sonatrach to appraise oil, associated gas discovery onshore Algeria

Italy’s Eni SPA and Algeria’s Sonatrach will appraise an oil and associated gas discovery in the Zemlet el Arbi concession in the Berkine North basin in the Algerian desert (OGJ Online, Oct. 29, 2018). Preliminary estimates put the size of the discovery at 140 million bbl of oil in place.

The HDLE-1 discovered exploratory well was drilled on the HDLE exploration prospect about 15 km from processing infrastructure of Bir Rebaa North field. Light oil in the Triassic sandstones of Tagi formation was found, confirming 26 m of net pay with excellent petrophysical characteristics, Eni said in a Mar. 20 release.

During the production test, the well delivered 7,000 b/d of oil and 5 MMscfd of associated gas. HDLE-1 is the first well of the new exploration campaign which will include drilling five wells in the Berkine North basin.

A second well, HDLE-2, will be drilled in April to confirm additional potential of the structure extending in the adjacent Sif Fatima 2 concession operated by an Eni-Sonatrach JV (50-50%).

With the appraisal program, Eni and Sonatrach will perform studies and analyses to accelerate the production phase of the new discovery through a fast-tracked development with startup expected in this year’s third quarter.

The concession is operated by a joint venture between Eni (49%), and Sonatrach (51%).

Shell submits amended environmental statement for Jackdaw

Shell has submitted an amended environmental statement (ES) to the Oil and Gas Authority (OGA) for Jackdaw gas condensate field development in Blocks 30/02a, 30/02d, and 30/03a on the UK Continental Shelf (UKCS), about 250 km east of Aberdeen in 256 ft of water.

The plan is to drill four wells, install a new wellhead platform, and tie back a new pipeline about 30 km to the existing Shearwater host platform where fluids will be processed before export via the Fulmar gas line and the Forties pipeline system. Drilling, installation, and commissioning will take place in 2023-2025.

Drilling is expected in third-quarter 2023 and fourth-quarter 2024. Platform jacket installation will be in third-quarter 2023, installation of topsides and export pipeline are expected to occur third-quarter 2023 to first-quarter 2025. First hydrocarbons are expected by fourth-quarter 2025.

Environmental impacts of the proposed project include the physical presence of vessels, WHP and infrastructure, atmospheric emissions, discharges to sea, impacts on the seabed, effects of underwater noise, production of waste, and an evaluation of the potential impacts from accidental events, as well as vulnerability of the proposed activities to natural disasters. In addition, potential impacts on designated protected sites, sensitive habitats, and cumulative and transboundary impacts are assessed.

Shell submitted its initial ES to UK authorities on May 6, 2021 and issued the ES for public consultation on May 10, 2021. This ES was an update to the original statement for the Jackdaw project submitted in January 2020. In October 2021 the Offshore Petroleum Regulator for Environment and Decommissioning (OPRED) declined to sanction the project. It did not disclose the reason for the rejection.

Jackdaw estimated reserves are 120-250 MMboe. At its peak, Jackdaw is expected to deliver 6.5% of UKCS gas production and produce energy equivalent to heating over 1.4 million UK homes.

BG International, an affiliate of Shell UK, is operator at Jackdaw (76%) with partner ONE-Dyas E&P holding the remaining 26%.

Bengal begins field operations at Cooper-Eromanga basin

Bengal Energy Ltd.’s Australian arm has started remedial field operations at its 100%-owned Wareena and Caracal fields in the Cooper-Eromanga basins of southwest Queensland with the aim of becoming an operator and producer.

At Wareena in production license PL1110 to the east of the company’s exploration permit ATP934, Bengal plans to restart two wells in the Permian-age Cooper basin field where it hopes to reduce or eliminate water production to promote gas production.

Cumulative historical production of gas from the two wells was more than 6 bcf, Bengal said.

The company plans to reactivate the associated pipelines to allow sales and export of gas via the Coonaberry compression station into the Santos gas infrastructure that links with Moomba processing plant in South Australia.

The Wareena wells will be ready for extended production testing in April. If successful, the company expects to begin gas production to market via the recommissioned pipeline near this year’s third quarter.

At Caracal, in the Tookoonooka permit ATP732 south of Wareena, Bengal plans to reinstate and stimulate discovery well Caracal-1, where it found light oil in Wyandra sandstones of Cretaceous age (Eromanga basin) in 2012.

The goal is to produce commercial volumes of oil via a refurbished Lufkin pumping unit. The oil would be gravity separated in a tank onsite and offloaded to road tankers for delivery to the small oil refinery in Eromanga, Queensland.

Once production is established, Bengal plans further exploration of surrounding prospects to augment oil flow.

 Drilling & Production Quick Takes

VAALCO reconfigures Etame field production unit

VAALCO Energy Inc. will replace the existing floating production, storage, and offloading unit (FPSO) with a floating storage and offloading vessel (FSO) for Etame field, offshore Gabon.

The Cap Diamant, a double-hull crude tanker built in 2001 that is being re-engineered as the new FSO, arrived at a shipyard in Bahrain in late February for the final modifications and certifications. Sea trials are expected to start in late June before being mobilized to Gabon.

Compared to the current FPSO agreement, the new FSO will reduce storage and offloading costs by almost 50%, increase effective capacity for storage by over 50%, and is expected to lead to an extension of the economic field life, resulting in a corresponding increase in recovery and reserves at Etame, the company said.

VAALCO anticipates that all associated engineering, long-lead equipment, and significant contracts are proceeding in-line with project timelines and expected delivery schedules for deployment of the FSO in third-quarter 2022. Field reconfiguration activities are expected to begin in March, as planned.

Current total field level capital conversion estimates are $40-50 million (gross). This capital investment is projected to save about $20-25 million/year (gross) in operational costs through 2030.

Etame Marin block is in Congo basin about 32 km off the coast of Gabon. The license area is spread over five fields covering a total area of about 187 sq km. VAALCO is operator in Etame Marin field (63.6%) with partners Addax Petroleum Co. (33.9%) and PetroEnergy Resources Corp. (2.5%).

Norway production up slightly in February, NPD says

Norway’s production averaged 1.980 million b/d in February, the Norwegian Petroleum Directorate (NPD) reported.

Norway’s production averaged 1.968 million b/d in January.

Average daily liquids production in February consists of 1.763 million b/o, 208,000 bbl of NGL, and 9,000 bbl of condensate.

Oil production in February is 3.7% lower than NPD’s forecast so far this year.

Enwell Energy restarts production in Ukraine

Enwell Energy PLC has partially restarted production operations in Ukraine. Production is about 1,600 boe/d and is expected to be maintained at this level for the immediate future. The company said Feb. 24 it had shut in production and drilling operations in Ukraine in response to war in the country.

Enwell currently operates four gas and condensate fields in the Dnipro-Donets basin in northeast Ukraine.

While partially restarted, operations are likely to be intermittent depending on circumstances in the country, the company said.

Enwell Energy holds two licenses in the Mekhedivsko-Golotvshchinske (MEX-GOL) and Svyrydivske (SV) fields in the Poltava region, with about 48 MMboe 2P gas and condensate reserves and large potential resources of unconventional gas, and a license in Vasyshchivske (VAS) field, with 2.8 MMboe 2P reserves and large quantities of unconventional gas.

The Svystunkivsko-Chervonolutske (SC) license, in a new field in the Poltava region, is prospective for natural gas and condensate.

Serica restarts Rhum production

Serica Energy PLC restarted production from Rhum field following an operation to replace a faulty component in the subsea control module which necessitated a temporary shutdown.

Rhum field lies in Block 3/29a, 44 km north of Bruce in the UK Northern North Sea and is a subsea development tied back to the Bruce platform via an insulated pipeline.

Production from Bruce field has continued throughout these operations and Serica’s other producing fields (Erskine and Columbus) were not impacted by the Rhum issue. During the Rhum outage, the company averaged net production over 15,000 boe/d.

Serica is operator of Bruce (98%), Columbus (50%), and Rhum (50%). IOC UK Ltd. holds the remaining 50% interest in Rhum. Serica holds 18% interest in Erskine with Ithaca Energy Ltd. as operator.  

SDX Energy ties back West Gharib infill development well

SDX Energy PLC tied back the MSD-25 infill development well on Meseda field in the West Gharib concession, Egyptian Eastern Desert.

The well, the second in a possible 13-well development campaign at Meseda and Rabul fields, spudded Jan. 23 and targeted the Asl formation. The primary top Asl formation reservoir was encountered at 4,109 ft MD (3,361 ft TVDSS) and reached 4,385 ft TD on Feb. 22 after drilling through 84.8 ft of good-quality, net oil pay sandstone with 26.1% average porosity.

The well has been perforated, tied-in to the existing facilities, and flow tested. It is expected that, post-clean up, the well will produce a stabilized rate of about 300 b/d, in line with pre-drill estimates.

The rig is in the process of moving to MSD-20, the next well in the campaign. A second rig also will begin operations to drill the MSD-24 well and accelerate the development plan, with a spud date planned for mid-April. SDX and its partner will continue to assess the performance of the rigs over the coming months to determine how long both rigs will remain operational on the concession.

The development drilling campaign is aimed at growing gross production to about 3,500-4,000 b/d by early 2023.

SDX holds 50% working interest in the well.

 PROCESSING Quick Takes

Marathon partnering with Neste on Martinez refinery-to-renewables project

Marathon Petroleum Corp. (MPC) is adding Neste Corp. as a partner on MPC’s previously announced strategic repositioning of its now-idled Martinez, Calif., refinery into a renewable fuels production site.

As part of definitive agreements signed in early March—and pending customary closing and regulatory approvals—Neste will join the Martinez Renewable Fuels project (MRFP) as a 50-50 joint-venture (JV) partner with a total investment of $1 billion, inclusive of half the total project development costs estimated through MRFP’s completion, MPC and Neste said in separate releases.

While MPC will continue to manage project execution and operate the renewables plant, both companies will be responsible for feedstock sourcing, and production output will be split evenly between the partners.

Each partner also will be responsible for marketing the proposed JV’s production of renewable products under its own brand, the companies said.

Neither MPC nor Neste revealed a definitive timeline for when they anticipate official closing of the JV other than to confirm precedent conditions include, among others, obtaining necessary permits following certification of MRFP’s final environmental impact report (EIR), a draft version of which remains under evaluation by California’s Contra Costa County Department of Conservation and Development (DCD) after closing of the public comment period in mid-December 2021, according to DCD updates.

Currently targeted to begin production of 260 million gal/year of renewable diesel in second-half 2022, MRFP is scheduled to bring pretreatment capabilities online in 2023 and reach full nameplate production capacity of 730 million gal/year by yearend 2023, MPC and Neste said.

Estimated total project costs for MRFP remain at about $1.2 billion, according to the companies.

In an Oct. 15, 2021, update on MRFP, MPC said it estimates the conversion project will reduce greenhouse gas emissions (GHGs) by 60%, criteria air pollutants by 70%, and water use by 1 billion gal/year compared to the site’s previous operations as a petroleum refinery.

Based on MRFP’s current draft EIR, the project will involve converting existing conventional units of the former Martinez refinery to process renewable feedstocks, such as soybean oil, corn oil, rendered fats, and other miscellaneous bio-based feedstocks—including used cooking oils and other vegetable oils—into renewable diesel, naphtha, propane, and treated fuel gas.

The conversion would involve adding new units and removing obsolete units that cannot be repurposed for processing of renewable feedstock. Proposed new units would include a renewable feedstock pretreatment unit, wastewater treatment equipment, and an advanced three-stage low-NOx thermal oxidizer. Equipment scheduled to be removed includes a crude unit, gasoline hydrotreater, alkylation unit, fluidized catalytic cracking unit, reformers, delayed coker, steam boilers, among others, according to DCD project documents.

 TRANSPORTATION Quick Takes

Cheniere gets DOE approval for expanded LNG exports

Cheniere Energy Inc. has received US Department of Energy (DOE) authorization to export the equivalent of an additional 720 MMcfd of natural gas from its 30-million tonne/year (tpy) Sabine Pass and 15-million tpy Corpus Christi LNG plants combined to any country with which the US does not have a free trade agreement, including all of Europe. US exporters are already shipping at or near maximum capacity, but the new authorizations make it so that every operating US plant now has DOE approval to export its full capacity to any country not prohibited by US law or policy.

The US is already the top global exporter of LNG and exports are set to grow an additional 20% by end 2022 as additional capacity comes online, according to DOE. The US was also Europe’s largest source of LNG in 2021, accounting for 26% of all LNG imported by European Union member countries (EU-27) and the UK, followed by Qatar with 24%, and Russia with 20%.

In January 2022, however, the US supplied more than half of all LNG imports into Europe for the month. Exports of LNG from the US to EU-27 and the UK increased from 3.4 bcfd in November 2021 to 6.5 bcfd in January 2022; the most LNG ever shipped to Europe from the US on a monthly basis, according to DOE’s ‘LNG Monthly’ reports and Energy Information Administration estimates based on LNG shipping data. Rising US LNG exports stem from both natural gas supply problems in Europe following Russia’s invasion of Ukraine and the sizable price differences between gas produced in the US and current prices at European trading hubs.

Cheniere earlier this month let a lump-sum, turnkey engineering, procurement, and construction contract to Bechtel for its 10-million tpy Corpus Christi Stage III project and expects to take final investment decision on the project third-quarter 2022 (OGJ Online, Mar. 7, 2022).

Venture Global awards Plaquemines LNG liquefaction to Baker Hughes

Venture Global LNG Inc. has awarded Baker Hughes Co. a contract to provide modular natural gas liquefaction for the first phase of its 20-million tonne/year (tpy) Plaquemines LNG plant in Louisiana. Baker Hughes will also assist in commissioning the supplied equipment. First deliveries are expected in 2023 to meet a 2024 start-up date.

The liquefaction train order builds on a fourth-quarter 2021 award for Baker Hughes to provide power generation and electrical distribution equipment for Plaquemines LNG. It also follows a similar contract to supply liquefaction technology to Venture Global’s 10-million tpy Calcasieu Pass LNG plant.

Baker Hughes completed delivery of the ninth and final two-train liquefaction block for Calcasieu Pass in 2021. The plant loaded its first LNG cargo earlier this year. Commercial operations are expected to begin mid-2022.   

Both contracts were awarded under a master equipment-supply agreement between Venture Global and Baker Hughes for 70 million tpy of production capacity.

Mountain Valley Pipeline petitions court to reconsider decisions

Mountain Valley Pipeline LLC has filed petitions with the US Court of Appeals for the Fourth Circuit asking the full court to reconsider decisions issued earlier in 2022 by a panel of the court vacating Mountain Valley’s biological opinion and authorization to cross the Jefferson National Forest (OGJ Online, Jan. 26, 2022).

In a letter to the Federal Energy Regulatory Commission (FERC), Mountain Valley accused the Fourth Circuit’s panel of “selectively disregarding long-settled rules governing the review of agency actions under the Administrative Procedure Act.”

The pipeline company said it would continue to work with all the agencies necessary to complete construction of the 303-mile, 2-bcfd natural gas project.

In response, the Sierra Club submitted almost 1,500 petitions “to remind the Commission that it may not grant Mountain Valley’s certificate amendment application in the absence of a valid biological opinion after consultation under the Endangered Species Act.” The club cited more than 100 variance requests filed by the pipeline’s developers which have “move[d] the project far from what FERC originally reviewed and approved…in 2017.”

Equitrans Midstream Corp. is Mountain Valley’s lead developer. The pipeline is more than 90% complete and Equitrans had hoped to put it in service during 2022, already 4 years later than originally planned. One of its partners in the project, NextEra Energy in February 2022 wrote of its entire $770-million investment in the pipeline.

Venture Global, New Fortress sign 2 million tpy of LNG offtake deals

Venture Global LNG Inc. has executed two new 20-year sales agreements with New Fortress Energy Inc., including 1 million tonnes/year (tpy) from 20-million tpy Plaquemines LNG and 1 million tpy from CP2 LNG. This is the first offtake agreement for the 20-million tpy CP2 LNG, sited in Cameron Parish, La., which the company expects to begin construction on in 2023.

The company has sold 14 million tpy of Plaquemines LNG’s capacity and expects to take final investment decision and close project financing “soon.” Construction started in August 2021.