OGJ Newsletter

General Interest Quick Takes

Abu Dhabi awards offshore block to Pakistani consortium

A consortium led by Pakistan Petroleum Ltd. (PPL) was awarded exploration rights for Abu Dhabi’s offshore Block 5, 100 km northeast of Abu Dhabi city, concluding the second block bid round launched by Abu Dhabi National Oil Co. (ADNOC) in 2019 (OGJ Online, May 1, 2019).

The block covers an offshore area of 6,223 sq km. Under terms of the agreement, the consortium will hold a 100% stake in the exploration phase, investing up to $304.7 million towards exploration and appraisal drilling.

The consortium will have the right to a production concession to develop and produce any commercial discoveries made during the exploration phase with ADNOC holding the option for a 60% stake. The term of the production phase is 35 years from the commencement of the exploration phase.

In addition to drilling exploration and appraisal wells, the consortium will contribute financially and technically to ADNOC’s 3D seismic survey within the block area.

The consortium consists of PPL, Mari Petroleum Co. Ltd. (MPCL), Oil and Gas Development Co. Ltd. (OGDCL), and Government Holdings (Private) Ltd. (GHPL).

As part of Abu Dhabi’s second block bid round, ADNOC awarded offshore Block 4 to a wholly-owned subsidiary of Cosmo Energy Holdings Co., Ltd.; offshore Block 3 to a consortium led by wholly-owned subsidiaries of Eni and PTT Exploration and Production Public Co. Ltd. (PTTEP); and onshore Block 5 to Occidental Petroleum Corp.

Following ADNOC’s recent discoveries of 22 billion stock tank barrels of recoverable unconventional oil resources and 160 trillion standard cu ft of recoverable unconventional gas resources, it was decided not to award an exploration license for onshore Block 2. ADNOC intends to engage with potential partners for unconventional resource licensing opportunities around the geographical area.

Talos wins Texas offshore CCS contract

Talos Energy Inc. with partner Carbonvert Inc. was the sole winning bidder partnership for the Texas General Land Office’s (GLO) Jefferson County, Tex., carbon storage site offshore near Beaumont and Port Arthur. Talos’s bid was the only successful proposal among twelve submissions and the Texas School Land Board (TSLB) unanimously approved awarding the lease to Talos and Carbonvert, subject to finalization of terms.

Based on Talos’s preliminary understanding of the rock and fluid properties of the project site’s saline reservoirs, it expects to ultimately sequester 225-275 million tonnes of carbon dioxide from industrial sources in the area. Talos will operate the project.

The project site encompasses a total land area of more than 40,000 gross acres offshore in Texas state waters in the Gulf of Mexico. It is 100% covered by Talos’s existing seismic database and is close to a large concentration of industrial emitters along the Texas and Louisiana Gulf Coast.

Talos and Carbonvert now will negotiate a lease agreement with GLO staff based on the terms of the Talos bid and the terms included in the original request for proposal from the GLO. Final terms are subject to the approval of the TSLB.

This bid submission predated Talos’s exclusive joint venture with Storegga Geotechnologies Ltd. to pursue carbon capture and sequestration (CCS) throughout the US Gulf Coast (OGJ Online, June 9, 2021). Talos said it continues to work with both landowners and emitters across the Gulf Coast regarding additional CCS sites.

Diversified adds to central region focus with Tanos deal

Diversified Energy Co. PLC completed its co-investment with funds managed by Oaktree Capital Management LP to acquire certain Cotton Valley and Haynesville upstream assets and related facilities in Louisiana and Texas from Tanos Energy Holdings III LLC.

Oaktree Capital Management is co-investing under an October 2020 joint participation agreement. Total cash consideration for the acquisition is $308 million.

The deal is the third in Diversified’s new central regional focus area where it expects to replicate its Appalachia business.

Current production of the acquired assets is 14,000 boe/d (82 MMcfed) with 92% from 390 net operated wells with an average production-weighted well age of 9 years, and PDP reserves of 40 MMboe (241 bcfe), Diversified said in an Aug. 18 statement.

The assets are in addition to Diversified’s second central region deal to acquire Cotton Valley assets from Indigo Minerals LLC, and includes additional working interest in 42 wells previously acquired from Indigo (OGJ Online, May 4, 2021). In another deal, the company acquired Barnett shale upstream assets from Blackbeard Operating LLC (OGJ Online, May 28, 2021).

Diversified Energy will retain about 55 Tanos field personnel and previous contractors.

 Exploration & Development Quick Takes

Shell takes FID on renewable-powered Timi development

Sarawak Shell Berhad (SSB), a subsidiary of Royal Dutch Shell PLC, has taken a final investment decision (FID) on the Timi gas development project offshore Malaysia.

Timi is a sweet gas field discovered in 2018. It lies about 200 km off the coast of Sarawak. Development features SSB’s first wellhead platform in Malaysia that is powered by a solar and wind hybrid renewable power system. The unmanned platform is about 60% lighter than a conventional tender-assisted drilling wellhead platform. The project also includes the drilling of two wells.

The Timi development is designed to reach up to 50,000 boe/d peak production and will evacuate its gas to the Shell-operated F23 production hub via an 80 km pipeline while supporting the future growth in the central Luconia area, off the coast of Sarawak, Shell said in an Aug. 30 release.

Timi will be developed as part of the SK318 production sharing contract with SSB as operator with 75% equity. Partners are PETRONAS Carigali Sdn Bhd (15%) and Brunei Energy Exploration (10%).

Senex increases Surat basin gas reserves

Senex Energy Ltd., Brisbane, has increased its independently assessed estimated gas reserves in the Surat basin of southeast Queensland by 24% for 1P reserves to 261 petajoules.

The company also achieved a rise in 2P reserves to 767 petajoules which is up 4%, while 3P reserves have moved up by 2% to 1,016 petajoules.

Senex production from the region now exceeds 52 terajoules/day (19 petajoules/year) and it is on the way to its targeted five-fold growth in annual production of more than 60 petajoules/year by the end of the 2025 financial year.

The company’s Atlas project led the way, recording a 46 petajoule (15%) increase in 2P gas reserves to 270 petajoules, largely attributable to the award of high-value acreage in ATP 2059 adjacent to, and extending, the Atlas development, said Ian Davies, managing director and chief executive officer.

The Roma North development achieved a 2P reserves replacement ration of 100%. The project area holds 2P reserves of 497 petajoules and 3P gas reserves of 746 petajoules.

Commissioning of the expanded processing infrastructure to 9 petajoules/year represents the first phase of the wider Roma North development, and a final investment decision for the second phase of expansion to 18 petajoules/year is expected in the coming months, Davies said.

Planning for the third expansion phase has begun which aims to bring annual Roma North production up to 27 petajoules/year.

The independent assessment of reserves was performed by Netherland Sewell & Associates.

Spirit Energy finds additional gas at Grove field

Spirit Energy Ltd. discovered gas at the Grove North East development well (49/10a-G7) on the UK Continental Shelf, close to the UK–Netherlands median line.

The well was drilled by Maersk Drilling’s Maersk Resolve heavy-duty jack up and targeted an unappraised north eastern segment of the field. It encountered carboniferous reservoir units at the target depth, with around 250 ft (gross) gas-bearing B & C sandstones present. The reservoir quality, sand thickness, and gas column height are within predrill expectations and G7 was completed for production.

Gas from Grove field is processed at the Markham J6-A infrastructure operated by Spirit Energy and transported via the West Gas Transport pipeline to the Den Helder terminal in the Netherlands for further processing.

Spirit Energy is operator at Grove field and Grove North East (92.5%) with partner RockRose Energy PLC (7.5%).

Chevron advances Jansz-Io compression project

Chevron Australia Pty Ltd. and Aker Solutions have let contracts to ABB to provide power from shore and subsea long step-out to Jansz-Io field.

The order, worth about $120 million, is for supply of the overall electrical power system (EPS) for the multi-billion-dollar Jansz-Io compression (J-IC) project, which moves gas from the deep seas to shore. Chevron took FID on the project in July.

Jansz-Io lies about 200 km off the northwestern coast of Australia in the Carnarvon basin at water depths of about 1,400 m. The field is part of the Chevron-operated Gorgon natural gas project.

The project includes construction and installation of a 27,000-tonne (topside and hull) normally unattended floating field control station, about 6,500 tonnes of subsea compression infrastructure, and a 135-km submarine power cable linked to Barrow Island.

ABB will provide most of the electrical equipment, both topside and subsea, for J-IC. The project will combine two ABB technologies—power from shore and variable speed drive long step-out subsea power—for the first time, the service provider said Aug. 19. The electrical system will be able to transmit 100 megavolt-amperes over a distance of about 140 km.

The contract was awarded following concept development and a front-end engineering and design study. Work will begin immediately. The subsea compression system is expected to be in operation in 2025.

 Drilling & Production Quick Takes

Equinor starts Troll Phase 3 offshore Norway

Equinor Energy AS started production on Aug. 27 from the Troll Phase 3 project in the North Sea.

Phase 3 consists of eight wells in two templates, a new pipeline, and umbilical connecting the templates to Troll A as well as a new gas processing module on the platform (OGJ Online July 2, 2021). Phase 3 involves producing the gas cap overlying the oil column in Troll West, while simultaneously continuing to produce the oil. Produced gas goes to Troll A and onward in existing infrastructure.

The phase is expected to extend the life of Troll A and the Kollsnes processing plant beyond 2050, and the plateau period by 5-7 years, Equinor said. Recoverable volumes from Phase 3 are estimated at as much as 347 billion cu m of gas (2.2 billion boe).

Investment in Phase 3 is NOK 8 billion. Emissions of CO2 will be less than 0.1 kg/boe based on power supplied from shore.

Equinor is operator at Troll (30.58%) with partners Petoro AS (56%), AS Norske Shell (8.10%), TotalEnergies EP Norge AS (3.69%), and ConocoPhillips Skandinavia AS (1.62%).

CNOOC starts production from Bozhong 26-3 expansion project

CNOOC Ltd. has started production at the Bozhong 26-3 oil field expansion project.

The project lies in the south of Bohai Sea, with average water depth of about 21 m. In addition to fully utilizing existing processing infrastructure, the project included construction of a new unmanned wellhead platform and a power platform.

A total of 8 development wells are planned, including 5 production wells, 2 water injection wells, and 1 development and appraisal well. The project is expected to reach peak production of 2,670 b/d of crude oil in 2021.

CNOOC Ltd. is operator of the expansion project with 100% interest.

ExxonMobil spuds Sapote-1 well, offshore Guyana

ExxonMobil has spudded the Sapote-1 well, offshore Guyana.

The prospect lies in the southeastern section of the Canje block, some 50 km north of the Haimara discovery in the Stabroek block which encountered 63 m of high-quality, gas-condensate bearing sandstone reservoir and about 60 km northwest of the Maka Central discovery in Block 58 which encountered 50 m of high-quality, oil-bearing sandstone reservoir.

The well is designed to test Upper Cretaceous reservoirs in a stratigraphic trap. Drilling is expected to take up to 60 days. The well is about 225 km northeast of Georgetown in 2,550 m of water and is being drilled with the Stena DrillMax drillship.

The block is operated by ExxonMobil subsidiary Esso Exploration & Production Guyana Ltd. (35%) with partners TotalEnergies E&P Guyana BV (35%), JHI Associates (BVI) Inc. (17.5%), and Mid-Atlantic Oil & Gas Inc. (12.5%).

Eni starts production from Cuica field, offshore Angola

Eni SPA started production from Cuica field, Block 15/06 in deepwater Angola. The field is in 500 m of water about 3 km from the Armada Olombendo FPSO.

Cuica was discovered by exploration well Cuica 1 in March 2021. Development includes an oil producer well and a water injection well, tied back to the existing Cabaça North subsea production system. Production will be via the Olombendo FPSO.

The FPSO has a production capacity of 100,000 b/d and is designed to operate with zero discharge. Besides Cuica, Olombendo is receiving and treating production from Cabaça, Cabaça South East, and UM8 fields for a total of 12 wells and 5 manifolds at 400-500 m water depths. The FPSO also will receive production from Cabaça North field in fourth-quarter 2021.

Eni Angola is operator with 36.84% interest. Partners are Sonangol Pesquisa e Produção (36.84%) and SSI Fifteen Ltd. (26.32%).

 Processing Quick Takes

REG inks deal for Geismar renewable fuels expansion

Renewable Energy Group Inc. (REG), Ames, Iowa, has entered a long-term lease agreement with International-Matex Tank Terminals LLC (IMTT) under which IMTT will build out storage and logistics infrastructure at its bulk-liquid storage and marine terminal in Geismar, La., to support REG subsidiary REG Geismar LLC’s expansion of its 90-million gal/year renewables diesel plant, also in Geismar (OGJ Online, Oct. 6, 2020).

Alongside providing bulk-liquid storage, handling, dock usage, and other transshipment services to REG Geismar, IMTT also has agreed to permit, build, and own six new bulk liquid storage tanks for biodiesel, renewable diesel, and certain plant feedstocks, as well as related dock and loading infrastructure, all of which will accommodate the plant’s project to expand aggregate production of finished renewable diesel products by 250 million gal/year, IMTT said.

The terminal expansion also will include construction of two pipeline enabling connectivity to the Geismar renewable fuels plant, according to the service provider.

Scheduled to be completed and ready for service 24 months from execution of the Aug. 3 agreement, IMTT said its expansion plan will nearly double current storage capacity of the terminal.

While IMTT did not disclose further details regarding the project, REG said in its recently released second-quarter earnings report that it expects to spend about $22 million annually on the 15-year storage agreement, which is slated to automatically renew for subsequent terms of 10 years.

The storage and logistics agreement follows REG’s Aug. 4 confirmation that its board has approved moving forward with construction of Geismar’s planned production capacity expansion, as well as with additional works to enhance the plant’s operational and logistics capabilities not included in the original project plan.

Previously estimated to require a minimum $825-million capital investment, REG in early August estimated overall cost of its revised Geismar project at about $950 million.

With all required funding and permits to proceed now secured, REG said the Geismar improvement and expansion project—which will increase the plant’s overall production capacity to 340 million gal/year—is scheduled to reach mechanical completion in 2023, with full commissioning of the expanded plant to follow in 2024.

Imperial weighs renewable diesel complex at Strathcona refinery

ExxonMobil Corp.’s majority owned affiliate Imperial Oil Ltd. is considering construction of a grassroots renewable diesel production complex at its nameplate 200,000-b/d Strathcona refinery near Edmonton, Alta., in western Canada.

If approved, the proposed new complex would produce about 3 million l./day—roughly 20,000 b/d—of renewable diesel using proprietary process technology, ExxonMobil’s recently formed ExxonMobil Low Carbon Solutions business, Imperial, and ExxonMobil said in separate releases on Aug. 25.

The planned complex would process an unidentified mix of locally sourced and grown renewable feedstocks, according to Imperial.

Under development as part of Imperial’s commitment to supporting Canada’s transition to lower-emission fuels and the country’s ambition to achieve net-zero emissions by 2050, the renewable fuels production complex, if realized, would combine a proprietary catalyst with renewable feedstocks and blue hydrogen—or hydrogen produced from natural gas with carbon capture and storage (CCS) technology—to produce its premium low-carbon diesel fuel, the annual production volume of which would equate to removing more than 650,000 passenger vehicles/year from the road, Imperial said.

Alongside reducing greenhouse gas (GHG) emissions in Canada’s transportation sector by 3 million tonnes/year (tpy), Imperial said it expects the project would also capture about 500,000 tpy of carbon dioxide annually.

Currently in partnership discussion with the government of Alberta, industry, and the government of British Columbia—the latter of which has agreed to support the project in the form of credits under its provincial low carbon fuel standard—Imperial said final investment decision on the potential complex will be based on several factors, including government support, regulatory approvals, market conditions, and economic competitiveness.

Imperial provided no indication of when it might take FID on the proposed project, but confirmed that, if approved, the complex would begin production of renewable diesel in 2024.

In third-quarter 2020, Imperial commissioned a new cogeneration unit at the Strathcona refinery to increase the site’s overall energy efficiency and help contribute to further reductions in Alberta’s provincial GHG emissions.

 Transportation Quick Takes

Colonial shuts Houston-to-NC refined products pipeline as precaution

Colonial Pipeline Co. on Sunday afternoon, Aug. 29, temporarily shut down refined product Lines 1 and 2 from Houston to Greensboro, NC, in what it described as a precautionary and routine safety measure, following the landfall of Hurricane Ida. The company said that fuel supply continues to be available throughout the southeast from terminals along the pipelines’ route. Lines 3 and 4, which run from Greensboro to Linden, NJ, continue to operate as normal.

Lines 1 and 2 and have a combined capacity of about 2.5 million b/d. Minimum batch size is 75,000 bbl.

Colonial expects full operations to resume following evaluation of infrastructure and successful execution of its startup plan.

ExxonMobil Pipeline Co. on Aug. 27 demobilized all pipeline maintenance crews in the greater Baton Rouge, La., area in preparation for Ida’s landfall.

Nord Stream 2 receives German legal setback

Germany’s Higher Regional Court has rejected Nord Stream 2 AG’s application to be excluded from European Union rules requiring natural gas pipeline operators be companies other than those who supply the gas shipped. Polish state gas company PGNiG SA and its affiliate PGNiG Supply & Trading GMBH (PST) had argued that Nord Stream 2 did not qualify for derogation from this EU requirement because it had not been completed before the amendment enacting it had come into force, May 23, 2019.

Germany’s Federal Network Agency on May 15, 2020, used the same grounds to reject Nord Stream 2’s request for exemption, with the pipeline company then appealing to the Higher Regional Court. The court’s ruling can be appealed.

On June 11, 2021, Nord Stream 2 applied to the German regulatory authority for certification under the preferential independent transmission operator (ITO) model. PGNiG and PST have submitted an application for admission to the procedure as well, presenting preliminary arguments that there are likewise no legal grounds for granting certification under ITO.

The Gas Transmission System Operator of Ukraine LLC (GTSOU) has subsequently called on the EU to thoroughly review Nord Stream 2’s ITO application, alleging anticompetitive behavior. GTSOU earlier this month said that Poland and Ukraine could ensure Eastern European energy security without Nord Stream 2, citing 100 billion cu m/year (bcmy) of spare capacity without the project.

Nord Stream 2 is a twin pipeline intended to run on the bed of the Baltic Sea 764 miles from Vyborg, Russia, to Lubmin, Germany, with a capacity of 55 bcmy, the same as Nord Stream 1 which it would generally parallel.