OGJ Newsletter

GENERAL INTEREST Quick Takes

ExxonMobil lets contract for LaBarge CCS expansion

ExxonMobil has let a contract to Technip Energies, in consortium with Saulsbury Industries, for engineering, procurement, and construction (EPC) to expand carbon capture and storage (CCS) at its LaBarge, Wyo. plant, according to a May 12 release from Technip.

Expansion of the plant—which currently has capacity to capture more than 6 million metric tonnes/year (tpy) of carbon dioxide (CO₂)—will increase capacity by 1 million tpy.

Expansion will consist of modification of the existing gas treatment infrastructure to increase carbon capture capacity and installation of pipeline to transport CO₂ to the reservoir for storage. Technip Energies will be responsible for engineering and procurement services, while Saulsbury Industries will perform construction and the pipeline installation, the service providers said.

In October, ExxonMobil said a final investment decision is expected in 2022 and will be based on several factors, including regulatory approvals. Operations could start as early as 2025.

The operator put the cost of the latest expansion project at $400 million.

Interior cancels GoM offshore lease sales, Cook Inlet sale

The Interior Department released word May 11 that it will not hold oil and gas lease sales 259 and 261 in the Gulf of Mexico “as a result of delays due to factors including conflicting court rulings.”

The unspecified court rulings “impacted work on these proposed lease sales,” said an Interior statement released to reporters.

The department also said it will not move forward with proposed oil and gas lease sale 258 in Cook Inlet, Alaska, “due to lack of industry interest.”

The three canceled sales were the last three on the list of sales scheduled as part of the 2017-2022 5-year leasing program, which ends June 30.

Given that lease sale 257 was vacated and remanded by a January court ruling, it appears likely that no more sales will be held before the end of the current program, and the next 5-year program has not been taken through the necessary steps of a rulemaking (OGJ Online, Jan. 28, 2022).

The government statement about conflicting court rulings did not sit well with the National Ocean Industries Association (NOIA).

“The administration absolutely has the ability to hold these lease sales,” said NOIA President Erik Milito in a statement released May 12. “They also have the ability to prepare a new leasing program for the 2022-2027 program.”

Milito suggested it was a strategy to carry out President Biden’s political wishes.

The Biden administration has given no indication of when it will take the necessary steps for developing a new 5-year leasing program for offshore oil and gas, a program that is mandatory under the Outer Continental Shelf Lands Act.

Sval Energi to acquire Martin Linge, Greater Ekofisk Area interests

Sval Energi AS has agreed to acquire Equinor ASA’s non-operated share in the Greater Ekofisk Area, and a minority share in Martin Linge (19%).

The agreement includes 7.604% of Ekofisk area licenses PL018, PL018B, and PL275 (including Ekofisk, Eldfisk, and Embla fields, and 6.63922% in the Tor Unit).

With the deal—expected to close in this year’s second half subject to customary government and license approvals—Equinor will no longer have ownership in the Greater Ekofisk Area but will retain a 51% share in Martin Linge and continue as operator. Petoro holds the remaining 30% interest.

The deal also includes Equinor’s interest in Norpipe Oil AS (18.5%), part of the infrastructure transporting oil from the Greater Ekofisk Area to land.

The agreement includes cash consideration of $1 billion and a contingent payment structure linked to realized oil and gas prices for both assets for 2022 and 2023.

With the acquired assets, privately held Sval (backed by HitecVision), will add 30,000 boe/d to its portfolio.

Ekofisk was the first producing field on the Norwegian Continental Shelf in 1971 and is expected to still be producing in 2050.

Martin Linge came onstream in 2021, is electrified with power from shore, and has a low carbon footprint of 3 kg CO₂/boe.

Wintershall expands Algerian Reggane Nord gas project interest

Wintershall Dea 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, citing major potential for enhanced energy partnership with Europe. 

Edison retained the project interest following an amendment to exclude its Algerian assets from a July 2019 purchase agreement with Energean Oil and Gas PLC as the two companies were unable to obtain consent of Algerian authorities (OGJ Online, July 8, 2019; Apr. 3, 2020).

Wintershall has been active in Algeria since 2002 and noted the country’s energy potential in a May 5 press release announcing the deal. Algeria is the third largest exporter of gas to Europe, after Russia and Norway, and is the largest natural gas producer in Africa. The country has well developed infrastructure connections to Europe including two subsea gas pipelines and LNG infrastructure at two locations, the company said.

Wintershall holds a 19.5% share in the concession and in 2020 signed a 2-year term memorandum of understanding with Sonatrach aimed at strengthening cooperation in the country (OGJ Online, Aug. 20, 2020).

Reggane Nord (Blocks 351c, 352c) comprises six gas fields (Azrafil Sud-Est, Kahlouche, Kahlouche Sud, Tiouliline, Sali, and Reggane) over an 1,800 sq km area in the Sahara Desert of southwestern Algeria. Central processing facilities include a gas treatment plant, a gathering network, and a 74-km pipeline connecting the treatment plant to a new transmission line.

Consortium Groupement Reggane Nord (GRN), operator of the project, marked first gas in 2017. The project is expected to be in production until at least 2041 (OGJ Online, Dec. 19, 2017).

Upon closing—subject to authority approvals—the consortium will comprise Sonatrach (40%), Wintershall Dea (30.75%), and Repsol (29.25%).

 Exploration & Development Quick Takes

Carnarvon provides Pavo resource assessment

Carnarvon Energy Ltd., a partner in the Pavo-1 oil discovery offshore Western Australian permit WA-438-P in the Bedout subbasin, has estimated contingent resources in the discovery of 43 million bbl.

Additional prospective resources are estimated at 55 million bbl gross.

The Pavo-1 discovery was made earlier this year in the northern part of the greater Pavo structure. The prospective additional resource is in the southern structure separated from the north by a narrow syncline.

The depth of the syncline is shallower than an interpreted residual oil-water contact at Pavo-1, supporting the position that Pavo South is likely filled with the same oil as Pavo-1, the company said.

Pavo-1 is being assessed for production through planned infrastructure at Dorado oil field about 46 km to the west in production permit WA-64-L.

Infrastructure at Dorado will comprise a wellhead platform connected to a floating production, storage, and offtake vessel about 2 km away.

During Phase 1 initial oil production, gas will be reinjected to enhance oil recovery. Infrastructure will be designed to handle up to 100,000 b/d.

Dorado oil production rates are expected to decline after a plateau period of 1-2 years creating spare capacity in the crude handling, the company said.

Pavo oil could then be delivered to Dorado at a rate that enables efficient utilization of Dorado infrastructure and extends the time that the Dorado project can maintain high production capacity.

Both Dorado and Pavo are operated by Santos Ltd. with 80% and 70% interests, respectively. Carnarvon has 20% in Dorado and 30% in Pavo.

IEC discovers oil in onshore Sumatra block

Indonesia Energy Corp. (IEC) discovered oil in the Kruh 27 well at its 63,000-acre Kruh block on Sumatra Island, Indonesia, where IEC is already producing oil from five existing wells, the company said in a May 11 release.

The well was spudded Apr. 7, 2022. On May 9, 2022, drilling reached the final total depth (TD) at 3,359 ft.

About 132 ft of oil sands were encountered at 3,058-3,190 ft. This oil-bearing interval was 14 ft thicker than anticipated, and total reserve potential for Kruh 27 could be larger than anticipated, the company said. Based on drilling results, IEC expects production to begin at Kruh 27 by end May 2022.

Kruh 27 is the first of two back-to-back wells being drilled by IEC during in first-half 2022. The rig will move to the next location to start drilling Kruh 28. A third new well at Kruh block is anticipated to begin drilling in July-August. A fourth new well is likely to be drilled before yearend. 

Production from each well is expected to reach 100 b/d or more over the first year.

Out of the total eight proved and potentially oil bearing structures in Kruh, three structures (North Kruh, Kruh, and West Kruh fields) have combined proved developed and undeveloped gross crude oil reserves of 4.99 million bbl (net crude oil proved reserves of 2.13 million bbl) and probable undeveloped gross crude oil reserves of 2.59 million bbl (net probable crude oil reserves of 1.12 million bbl) as of Jan. 1, 2019, IEC said.

IEC holds 100% participating interest in the block.

Aker BP, Equinor put Krafla operatorship transfer plans in motion

Aker BP and Equinor signed a memorandum of understanding (MoU) for transfer of Krafla operatorship from Equinor to Aker BP, making Aker BP operator of all discoveries in the Norwegian continental shelf (NCS) NOAKA area—Krafla, Fulla, and North of Alvheim.

Equinor is presently operator of Krafla in the north and Aker BP is operator of NOA Fulla in the south.

“The best solution for the future is that Aker BP takes over the operatorship for project execution and operation of Krafla, based on the concept developed by Equinor,” said Geir Tungesvik, executive vice-president for projects, drilling and procurement, Equinor, in a May 5 release.

The license owners will apply to the ministry for change of operator. Operatorship transfer will be carried out when the investment decision has been approved and the plan for development and operation (PDO) has been submitted to authorities.

Equinor will retain its 50% interest in Krafla and 40% in the Fulla license. The companies will jointly submit PDOs for NOA Fulla and Krafla, as planned, by yearend.

The NOAKA area is between Oseberg and Alvheim in the North Sea. Distribution of shares in the area is Krafla (Equinor 50%, Aker BP 50%), Fulla Aker BP (47.7%, Equinor 40%, LOTOS Exploration and Production 12.3%), and NOA (Aker BP 87.7%, LOTOS 12.3%).

Total recoverable resources in the area are estimated at 600 MMboe. The partners plan to drill about 45 wells to reach resource potential. Preliminary calculation of planned investments is $10 billion.

The concept covers a production, drilling, and living quarter platform on NOA that periodically will have little or no staff. Frøy field is being redeveloped with a normally unmanned wellhead platform to be tied back to NOA. An unmanned production platform on Krafla will be tied back to NOA for processing of oil and produced water.

The concept also covers development on the seabed, including nine subsea templates in the area. Plans call for an area development with power supply from shore. Production start is scheduled for 2027.

 Drilling & Production Quick Takes

PAO NOVATEK starts Russian pilot production

PAO NOVATEK subsidiary OOO NOVATEK-Yurkharovneftegas started pilot production from gas condensate deposits at the Yevo-Yakhinskiy cluster in Russia including the Yevo-Yakhinskoye and Ust-Yamsoveyskoye fields, as well as part of the Urengoyskoye field (within Olimpiyskiy license area boundaries). Annual production at the cluster is 4 bcm of natural gas and 1.3 million tonnes of gas condensate.

PGNiG to add production for delivery to Poland

PGNiG Upstream Norway AS expects to produce an additional 0.5 billion cu m (bcm) of natural gas from Norway operations this year with plans to transport gas through the 10-bcmy Baltic Pipe for delivery to Poland following the pipeline launch (due to come online in October 2022).

In late April, Gazprom halted natural gas supplies to Poland under the Yamal contract after PGNiG said it would not pay for gas in rubles. Poland’s 10 bcmy contract with Gazprom expires yearend, and Poland said it will not renew.

The increased gas will be produced from three reservoirs: Skarv, Gina Krog, and Duva.

In the case of the first two fields, increased production will be possible with modifications to each field’s plan for development and operation (PDO) to discontinue gas injection into the reservoirs. The PDO modifications were approved by the Norwegian Petroleum Directorate. An additional 300 million cu m is expected from Gina Krog and almost 150 million cu m from Skarv field by yearend.

A production increase at Duva is possible based on free capacity at the production installation serving Gjøa field, to which Duva is tied in. The spare capacity will be available until end August, when Nova field, also a Gjøa tie-in, will come online. Until then, PGNiG Upstream Norway plans to produce an additional 30 million cu m from Duva.

PGNiG Upstrem Norway holds 11.3% interest in the Gina Krog license, 11.92% interest in the Skarv license, and a 30% interest in Duva license. License partners are Equinor and KUFPEC (Gina Krog), AkerBP, Equinor and Wintershall DEA Norge (Skarv), and Neptune Energy, INPEX Idemitsu Petroleum Norge, and Sval Energi (Duva).

Karoon begins intervention drilling in Bauna field

Karoon Energy Ltd. has begun the first of its planned four-well intervention campaign in Bauna oil field in the southern Santos basin offshore Brazil.

The Maersk Developer semisubmersible drilling rig began operations at PRA-2 early May.

The intervention campaign aims to add 5,000-10,000 b/d of oil to Bauna production. It will comprise the installation of new electric submersible pumps in the Pr-2 and SPS-92 wells along with installation of gas-lift equipment in SPS-56 and reopening the lower zone of the BAN-1 well.

The rig will then drill two new development wells on the nearby Patola field and, dependent on the required regulatory licenses, it will move to drill 1-2 control wells on the Neon oil discovery.

The light oil discovery (39 degrees API) was made through the Echidna-1 wildcat in licence BM-S-1037 in May 2015. A production test flowed 4,650 b/d with the flow constrained by testing equipment. The discovery was renamed Neon. Karoon has 100% interest in the projects.

 PROCESSING Quick Takes

Brazilian regulator approves REMAN refinery sale

The Brazilian government has approved Petróleo Brasileiro SA’s (Petrobras) previously proposed sale of its 46,000-b/d Isaac Sabbá refinery (REMAN)—including a storage terminal—in Manaus, Amazonas, to Atem’s Distribuidora de Petróleo SA (Atem) subsidiary Ream Participações SA.

Brazil’s Administrative Council for Economic Defense (CADE) granted its approval May 13 in line with a June 2019 agreement between Petrobras and CADE governing the operator’s ongoing program to divest most of its Brazilian refining and related logistics assets, as well as the opening of Brazil’s refining sector to increased competitiveness and transparency, Petrobras said in a release.

Approval of the deal follows Petrobras’s warning earlier this year the original timeline for the proposed transaction could be delayed amid a March order from CADE requiring execution of additional diligence activities involving further analyses of REMAN’s operations, including the refinery’s effects and possibly competitive impacts on the downstream refining market.

Part of Petrobras’s broader downstream divestment program, the REMAN sale, once completed, will include Ream Participações’s purchase all of Petrobras’s ownership interest in the REMAN refinery and associated logistics assets for $189.5 million, $28.4 million of which is to be immediately paid as a security deposit, with the remaining $161.1 million to be collected a closing subject to adjustments.

Closing of the REMAN transaction would follow Petrobras’s most recent downstream divestment completed in 2021, which involved the sale of its former 333,000-b/d Refinaria Landulpho Alves (RLAM) refinery—now renamed Refinaria de Mataripe—in São Francisco do Conde in the Recôncavo Baiano region of Bahia, Brazil, to Mubadala Capital, an arm of Abu Dhabi-based Mubadala Investment Co.

Turkmenistan to expand capacity of Kiyanly petrochemical complex

State-owned TurkmenGaz is expanding production capacity at the operator’s Kiyanly gas chemical complex in the Turkmenbashi district of Balkan Province in western Turkmenistan.

Per a resolution signed by Turkmenistan President Serdar Berdimuhamedov in May, the operator will build a grassroots unit for production of isobutane at the Kiyanly complex, Turkmengaz said in an official government release May 12.

Obtained from a feedstock of natural gas, the proposed unit will produce high-octane isobutane that can be used by oil refineries as fuel-blending component, as well as a refrigerant to reduce energy consumption in modern refrigerators, according to the operator.

The isobutane recovered from the new unit also can be used as a filler in aerosol cans, gas lighters, and gas-lighter refills, the government of Turkmenistan said in a separate official release on May 10.

While neither Turkmengaz nor the Turkmen government revealed details regarding the proposed capacity or timeline for startup of the new unit, both parties said the unit will contribute to further maximizing the complex’s range of production of high-value products from a hydrocarbon feedstock.

The complex’s production of isobutane will contribute to helping Turkmenistan fulfill its national obligation—as part of the country’s broader project jointly implemented with the United Nations Industrial Development Organization—under the Montreal Protocol to the Vienna Convention for the Protection of the Ozone Layer, which aims to safeguard the ozone layer by reducing use of ozone-depleting chemicals in favor of more environmentally friendly substances, Turkmengaz and the Turkmen government said.

Initially commissioned in October 2018, the $3.4-billion Kiyanly gas chemical complex—the largest in the region—processes 5 billion cu m/year natural gas via a gas separation unit equipped with Toyo Engineering Corp.’s Coreflux technology and BASF SE’s Oase technology to produce 386,000 tonnes/year (tpy) of polyethylene and 81,000 tpy of polypropylene, with up to 4.5 billion cu m/year of remaining marketable gas shipped via pipeline for commercial use.

In July 2021, the government of Turkmenistan said the Kiyanly complex would be one of two petrochemical complexes it was transferring ownership and operation of from Turkmengaz to fellow state-owned operator Türkmenhimiýa, or Turkmenchemistry. Scheduled to occur at the time of the announcement “in a short time” following finalization of necessary documents, confirmation of that transfer, to date, has yet to officially surface.

Petrobras lets EPC contract for unit at Replan

Petróleo Brasileiro SA (Petrobras) has let a contract to a consortium of Toyo Setal Empreendimentos Ltda. (TSE) and Toyo Engineering Corp. for construction of a new diesel hydrotreater at the operator’s 434,000-b/d Refinaria de Paulínia (Replan) refinery in Paulínia, São Paulo, Brazil.

As part of the May 9 contract, Consórcio Toyo Setal HDT Paulínia will provide engineering, procurement, and construction (EPC) services for the proposed $458-million diesel hydrotreating unit that, upon commissioning in 2025, will enable Replan to produce 100% low-sulfur Diesel S10 (10 ppm sulfur), as well as increase the refinery’s current production volumes by 63,000 b/d, Petrobras said on May 11.

The planned unit also will increase Replan’s production of jet fuel by 12,500 b/d to help meet more stringent specifications and increased future demand for economically and sustainably produced cleaner fuels, according to the operator.

The EPC contract award follows Petrobras’ first announcement of the project in June 2021, at which time the company said the proposed diesel hydrotreater would have an anticipated production capacity of 10,000 cu m/day.

Replan’s diesel hydrotreating project comes as part of the $6.1 billion Petrobras intends to spend on its refining business under the company’s 2022-26 strategic plan, as well as its previously announced RefTOP program, which aims to prepare the operator’s remaining refining assets both for an open, more competitive market in the country and the transition to a low-carbon economy.

 TRANSPORTATION Quick Takes

Equitrans targets second-half 2023 Mountain Valley gas pipeline startup

Equitrans Midstream Corp. is now targeting a full in-service date of second-half 2023 for its 303-mile, 2-bcfd Mountain Valley natural gas pipeline (MVP), at a total project cost of about $6.6 billion. Through Mar. 31, 2022, Equitrans had funded about $2.6 billion of the project, which was originally expected to cost $3.5 billion and be completed in 2018.

The most recent delays in construction and cost overruns are related to first-quarter 2022 decisions by the US Court of Appeals for the Fourth Circuit vacating and remanding, on specific issues, MVP’s permit related to crossing the Jefferson National Forest by the US Forest Service and Bureau of Land Management and the biological opinion and incidental take statement issued by the US Fish and Wildlife Service. After evaluating legal options and consulting with the relevant federal agencies, MVP plans to pursue new permits from the agencies.

In April, the US Federal Energy Regulatory Commission approved MVP’s certificate amendment, primarily related to changing the method of crossing certain waterbodies and wetlands to trenchless construction from open-cut (OGJ Online, Apr. 11, 2022).

The MVP JV continues to evaluate the 75-mile, 900-MMcfd MVP Southgate extension, including discussions with the shipper regarding options for the project, the timing and design of which has been affected by changes to the main pipeline’s schedule. As originally designed, MVP Southgate was estimated to cost $450-500 million, backed by a 300-MMcfd firm capacity commitment from Dominion Energy North Carolina.

ADNOC awards Fujairah LNG FEED contract to McDermott

Abu Dhabi National Oil Co. (ADNOC) has awarded McDermott International Ltd. a front-end engineering and design (FEED) contract for its planned 9.6-million tonne/year (tpy) LNG plant in Fujairah, UAE. The project will consist of two 4.8-million tpy trains.

FEED will be followed by award of an engineering, procurement, and construction contract in 2023.

ADNOC already produces 6 million tpy of LNG from a plant on Das Island off the coast of Abu Dhabi.

The company’s shipping and maritime logistics arm, ADNOC Logistics & Services, in April contracted with Jiangnan Shipyard in China for construction of two 175,000-cu m LNG vessels to join its fleet in 2025. 

Nigeria-Morocco natural gas pipeline awards FEED to Worley

Morocco’s Office National des Hydrocarbures et des Mines (ONHYM) and Nigerian National Petroleum Corp. (NNPC) have awarded Worley a front-end engineering and design (FEED Phase II) services contract for the more than 7,000-km Nigeria-Morocco Gas Pipeline (NMGP). Worley describes NMGP as the longest offshore pipeline in the world and second longest pipeline overall.

Intecsea BV, Worley’s offshore engineering consultancy, will manage the overall FEED, including development of the project implementation framework and supervision of the engineering survey. The onshore FEED scope, environmental and social impact assessment, and land acquisition studies will be delivered by Worley’s London office.

Worley said that Advisian, its global consulting business, would explore acceleration of electrification and the feasibility of energy self-sufficiency in the region and that its UK and Madrid offices would set out the potential use of renewable energy to power the pipeline and reduce the project’s carbon footprint.

Budget for FEED Phase II is $90.1 million, $14.3 million of which was supplied to ONHYM by the Organization of Petroleum Exporting Countries (OPEC) Fund for International Development. The OPEC contribution will specifically co-finance survey works for NMGP’s North Area, comprising Senegal, Mauritania, and Morocco.