OGJ Newsletter

June 28, 2021


Beaudreau confirmed as Interior deputy secretary

Tommy Beaudreau, a former high-level official in the Interior Department under President Obama, won broad bipartisan support as the Senate voted 88-9 June 17 to approve his nomination to No. 2 spot in Interior.

Beaudreau especially had drawn praise from Sens. Joe Manchin (D-W.Va.) and John Barrasso (R-Wyo.), respectively the chairman and top minority member of the Senate Energy and Natural Resources Committee.

“During his confirmation hearing, he clearly demonstrated that he understands the role of the Department of the Interior in striking the balance in its dual mission of preserving and protecting our national parks and public lands and providing a large part of the energy and mineral resources that we need to power the nation,” Manchin said June 17.

The previous day, Barrasso said of the nominee, “He can serve as a voice of reason in an administration that is waging a war on American energy workers.”

Beaudreau became director of the newly organized Bureau of Ocean Energy Management in 2011. He was promoted to Interior chief of staff in 2016.

In Interior he contributed to development of the tougher offshore well control regulations for oil and gas companies that were written over the course of several years in the wake of the 2010 Deepwater Horizon disaster. He also helped advance offshore wind project development.

In 2017, Beaudreau went to work as an attorney at the law firm Latham & Watkins, where his colleagues included several other veterans of Interior during the Obama administration.

Some environmental activists voiced opposition to his nomination a few months ago because they disapproved of his Latham & Watkins client list, which included oil and gas companies and a coal company. They were not mollified that his clients also included the National Audubon Society, nor that promoters of offshore wind energy lavished praise on him.

Lime Petroleum to acquire Brage field interest from Repsol

Lime Petroleum AS, a 90% subsidiary of Rex International Holding Ltd., conditionally agreed to acquire Repsol Norge AS’s 33.84% interests in the producing Brage field and the five licenses on the Norwegian Continental Shelf over which the field straddles for $42.6 million.

Wintershall Dea-operated Brage field lies in the northern part of the North Sea, 10 km east of Oseberg field in water depth of 140 m. Discovered in 1980, production started in 1993. It has been developed as a fixed integrated production, drilling, and accommodation facility with a steel jacket.

Brage produces oil from sandstone of Early Jurassic age in the Statfjord Group, and sandstone of Middle Jurassic age in the Brent Group and the Fensfjord formation. There also is oil and gas in Upper Jurassic sandstone in the Sognefjord formation. The reservoirs, which vary in quality from poor to excellent, lie at a depth of 2,000-2,300 m. The main drainage strategy is water injection, with gas lift used in most wells. Brage oil is exported via the Oseberg Transport System to the Sture terminal. Gas is exported via pipeline to Kårstø.

In 2020, about 1.38 MMboe (3,800 boe/d) were produced from the field, net to Repsol’s working interest.

Based on Norwegian Petroleum Directorate website data, Brage field produced 3,440 boe/d (net) for March 2021 and some 21.52 MMboe of reserves remain.

Lime believes there is further upside from future in-fill drilling of high value near-field prospects.

Repsol has agreed to pay to (or on behalf of) Lime Petroleum, the Brage Decommissioning Carry limited to 95% of decommissioning costs for the current Brage field infrastructure with respect to its 33.84% interest in the field.

Independence Energy, Contango Oil & Gas to combine

Independence Energy LLC and Contango Oil & Gas Co. have agreed to combine in an all-stock transaction. The combined company expects to have 2022 production of 108,000-114,000 boe/d.

Upon completion of the transaction, Independence shareholders will own about 76% and Contango shareholders roughly 24% of the combined company, which will have an initial equity market capitalization of $4.8 billion and enterprise value of $5.7 billion.

The companies expect the deal to close late third-quarter or early fourth-quarter 2021, subject to shareholder and regulatory approvals.

 Exploration & Development Quick Takes

BP starts Manuel project at Na Kika platform in Gulf of Mexico

BP has advanced work to add 900,000 boe/d of global production from new projects by yearend with startup of the Manuel project in the US Gulf of Mexico.

Manuel, in Mississippi Canyon block 520 in 6,625 ft of water, is the fourth of five major projects expected to be delivered this year. Development includes a new subsea production system for two new wells tied into the Na Kika platform. The wells are expected to increase gross platform production by an estimated 20,100 boe/d.

The BP-operated wells, drilled to a depth of 21,000 ft, lie southeast of the platform, some 140 miles off the coast of New Orleans. Drilling encountered oil pay in Miocene sandstone reservoirs.

BP and Shell each hold a 50% working interest in Manuel development.

BP operates four production platforms in the deepwater Gulf of Mexico—Thunder Horse, Atlantis, Mad Dog, and Na Kika—with a fifth platform, Argos, expected to come online in 2022.

The operator expects its US Gulf of Mexico production to grow to more than 400,000 boe/d by the mid-2020s.

Aker BP starts Gråsel production

Aker BP ASA and partners started production from Gråsel in the Skarv area, about 210 km west of Sandnessjøen in the Norwegian Sea, 4 months ahead of schedule.

Development consists of a new producer drilled from an existing well slot on Skarv field, with pressure support from a shared injector for Gråsel and Tilje.

An injection well is still required to maintain pressure in the Gråsel reservoir. It is planned for third-quarter 2021.

The Gråsel reservoir is over the Skarv reservoir and contains around 13 MMboe. Oil and gas are produced using available capacity on the Skarv floating production and storage unit (FPSO).

Total investment costs for the Gråsel project are around $140 million with a $15/bbl breakeven.

Aker BP is operator at Skarv (23.835%) with partners Equinor Energy AS (36.165%), Wintershall Dea Norge AS (28.0825%), and PGNiG Upstream Norway AS (11.9175%).

LLOG produces first oil from Gulf of Mexico Praline field

LLOG Exploration Co. LLC has started oil production from Praline field, a discovery in Gulf of Mexico Mississippi Canyon Block 74.

The Praline well was drilled in 2,600 ft of water to 13,400 ft TD and discovered over 125 ft of net hydrocarbons. It was completed in August 2020 and has been tied back to the Talos Energy-operated Pompano platform. LLOG is operator with a 27.25% working interest. Partners are entities managed by Ridgewood Energy Corp., including ILX Holdings, Red Willow Offshore, Houston Energy, and CL&F Offshore.

Coming in 20% under budget, Praline, the company’s first pipe-in-pipe tieback, is the first of four tieback projects expected online in the next year, said Philip LeJeune, LLOG president and chief executive officer, in a statement June 23.

TPAO discovers more Black Sea natural gas

Turkish state oil company TPAO has discovered a natural gas deposit in the Black Sea with estimated in-place volumes of 135 billion cu m (bcm). The Amasra-1 well was spudded on North Sakarya field in April 2021 by Turkish Petroleum Corp. drillship Fatih in the Turkish sector.

The discovery increased TPAO’s Black Sea gas volumes to 540 bcm following last year’s Sakarya discovery. First gas from Sakarya is expected by early 2023.

 Drilling & Production Quick Takes

PetroNeft increases Tomsk Oblast activity

PetroNeft Resources PLC has increased production from well C-4 in Cheremshanskoye field, and workover operations have concluded at well L-2a in Ledovoye field, both at license 67 in the Tomsk Oblast, Russian Federation.

Production from C-4 increased from to 320 b/d from 300 b/d by raising the choke size to 10 mm. The well is on the northern margin of Cheremshanskoye field and is producing from upper Jurassic J1-1 and J1-3 clastic reservoirs.

The well produced more than 27,000 bbl from February through May. Production in May was more than 9,000 bbl. Oil produced from this field benefits from a partial exemption of the Mineral Extraction Tax, estimated to be over $4/bbl in May.

Forward plans are to continue monitoring reservoir performance and install a pump to optimize production at an appropriate time.

Cheremshanskoye reserves are 19.26 million bbl C1+C2, approv-ed by GKZ (Russian State Reserves Committee) in January 2019.

L-2a was successfully reentered in June and a liner cemented in place. Upper Jurassic J1-1 and J1-2 intervals were perforated from 2,645.5 m to 2,627.5 m and 2,630 m to 2,632 m. During several swabbing cycles the well started to flow a mixture of oil and water. A total of about 132 bbl of oil was recovered with 33° API gravity along with 306 bbl of water from four swab cycles. Inflow from the formation was 100-300 b/d.

The high water content precludes oil from being produced at this field as there is no separation on site. The well is suspended until separation equipment can be installed.

PetroNeft is operator in the Tomsk Oblast. The company recently increased its interest in the license to 90% from 50%.

FAR contracts rig for Gambia drilling

FAR Ltd., Melbourne, has let a contract to Stena Drilling for use of the Stena Icemax mobile offshore drilling unit in this year’s fourth quarter for a well offshore Gambia.

Bambo-1 in Block A2 is designed to drill into three prospects—Soloo, Bambo, and Soloo Deep—with total potential recoverable reserves of over 1 billion bbl of oil.

The Soloo prospect is an extension of the hydrocarbon-bearing reservoirs in Sangomar oil field offshore Senegal while Bambo and Soloo Deep are additional prospects with target horizons not drilled during the Senegal campaigns.

FAR said the latter two carry a lower chance of success, but they have potential for a higher volume of hydrocarbons. Technical assessment of Bambo has been enhanced with FAR’s database and experience in the region, including success at Sangomar and the drilling of Samo-1 in 2018, the company said.

Bambo-1, 85 km offshore and 500 m south of the Senegal-Gambia marine border, is expected to spud between Oct. 1 and Nov. 30, subject to rig schedules. Drilling time is 1 month with a planned total depth of 3,266 m in water depths of 993 m.

Long lead-time items have been ordered and tendering for remaining key services is under way.

The drilling campaign has been approved by Gambia’s national environmental agency and FAR has engaged Exceed Energy, Aberdeen, to provide engineering and well management.

FAR is operator of the coming program and has a 50% interest in Blocks A2 and A5. JV partner PC Gambia Ltd., a subsidiary of Petronas, holds the other 50%.

Equinor extends Heimdal gas center operations to 2023

Equinor Energy AS will extend operations at the Heimdal gas center in northeastern North Sea production license 036 to 2023.

Production from Valemon gas and condensate field, which is processed by Heimdal, is expected to increase as 3-4 new gas wells are to be drilled in 2021 and 2022. Thus, Heimdal will maintain profitable operations longer than 2021 or 2022 as originally planned.

When Heimdal operations end in 2023, remaining gas reserves at Valemon will be transferred to Kvitebjørn and Kollsnes for processing. Gassled, a joint venture operated by national company Gassco, will reconnect the dry gas pipelines currently passing over Heimdal to a subsea bypass.

After shut-down, Heimdal platforms are scheduled to be removed from 2025-2027 and brought ashore at Eldøyane, Stord, for scrapping, reuse, and recirculation.

Since start-up in 1985, Heimdal has produced 46 billion std cu m of gas and 7 million cu m of liquid (oil-condensate), corresponding to 332 MMboe. Additionally, Heimdal has processed similar volume from satellite fields Huldra, Skirne, Atla, Vale, and Valemon.

Equinor is operator at Hemdal with 29.4% interest. Partners are Petoro AS (20.0%), TotalEnergies SE (16.7%), Spirit Energy AS (28.8%), and Lotos Exploration and Production Norge AS (5.0%).


ExxonMobil takes FID on Baton Rouge refinery modernization program

ExxonMobil Corp. is moving forward with its previously proposed plan to invest more than $240 million in modernization projects aimed at ensuring long-term competitiveness of subsidiary ExxonMobil Fuels & Lubricants Co.’s 520,000-b/d integrated refining and petrochemical complex in Baton Rouge, La. (OGJ Online, Dec. 17, 2020).

The operator has reached final investment decision on a suite of projects that, among other upgrades, will reduce volatile organic compound emissions at the site by 10%, Louisiana Gov. John Bel Edwards, the Louisiana Economic Development (LED), and David Oldreive—ExxonMobil Baton Rouge’s refinery manager—said June 9.

LED said it expects project construction will begin later this year.

To secure the Baton Rouge refinery investment, LED provided ExxonMobil the labor solutions of its FastStart state workforce training program as well as access to Louisiana’s Industrial Tax Exemption Program. As part of the incentivization program, ExxonMobil has agreed to focus on providing supplier opportunities specifically to North Baton Rouge businesses, according to LED.

Alongside saving 1,300 existing jobs at the refinery, the modernization program will support more than 600 on-site construction jobs during its 3-year execution period.

In its first-quarter 2021 earnings presentation to investors on Apr. 30, ExxonMobil said construction continues to progress on a 450,000-tonnes/year polypropylene unit at the Baton Rouge complex, which most recently was scheduled for startup sometime in 2021.

Lukoil’s Nizhny Novgorod refinery starts up new isom plant

PJSC Lukoil subsidiary LLC Lukoil Nizhegorodnefteorgsintez (NNOS) has commissioned a new isomerization unit at its 17-million tonne/year (tpy) Kstovo refinery in central Russia’s Nizhny Novgorod region (OGJ Online, Jan. 29, 2021).

Officially entered into service on June 18, the new 800,000-tpy Penex isomerization plant—which includes a hydrotreater for NK-85° C. light fractions, a naphtha splitter, and a deisopentanizer—will enable the refinery to produce isomerate—a high-octane blending component—to improve the quality and quantity of gasoline production at the site, Lukoil said.

The project, which required an overall investment of 12 billion rubles, will increase the Kstovo refinery’s Euro 5-quality gasoline output by 400,000 tpy, according to the operator.

Lukoil also confirmed on June 18 that NNOS has completed construction of the refinery’s long-planned deep conversion, delayed coking (OGJ Online, Mar. 24, 2021).

Scheduled for commissioning in fourth-quarter 2021, the new complex will enable the Nizhny Novgorod refinery to slash its production of fuel oil by 2.6 million tpy and increase annual output of Russian Class 5 (equivalent to Euro 5)-quality diesel fuel by 700,000 tpy.

Additionally, the refinery’s overall product yield will increase to 97%, with yield of light products reaching 74-75%. Total fuel oil production from the refinery simultaneously will drop to less than 4%, Lukoil said.

Nizhny Novgorod’s deep conversion, delayed coking complex will include the following major units: a 2.11-million tpy delayed coker; a 1.5-million tpy combined diesel fuel and gasoline hydrotreater; a 50,000-cu m/hr hydrogen production unit; a 425,000-tpy gas fractionator; and an 81,000-tpy combined elemental sulfur-sulfuric acid production unit.

ADNOC lets contract for Shah gas plant expansion

Abu Dhabi National Oil Co. (ADNOC) Sour Gas—a joint venture of ADNOC (60%) and Occidental Petroleum Corp. (40%)—has let a contract to Saipem SPA to deliver engineering, procurement, and construction services for the upgrading and expansion of its Shah gas processing complex at Shah sour gas-condensate onshore field, southwest of Abu Dhabi City, UAE.

As part of the $510-million contract, Saipem will provide engineering, supply of materials, construction, and commissioning of new but yet-to-be-identified components designed to increase the plant’s daily gas treatment capacity by 13%.

The expanded daily gas treatment capability will lift gas production capacity to 1.45 bcfd from a current output of 1.28 bcfd.

Officially commissioned in April 2016 as the first project to produce and safely process more than 1 bcfd of ultra-sour gas—which has a hydrogen sulfide content of more than 23%—from a single plant, the Shah gas plant also produces 4.2 million tonnes/year of sulfur.

The plant also is equipped with capacity to produce condensate, ethane, and NGL, which—alongside its gas production—are delivered to ADNOC group companies for further processing or distribution to domestic consumers. Granulated sulfur produced at the site is shipped to fertilizer manufacturers worldwide.


Tellurian applies for FERC permit to build Line 200, 300 gas pipelines

Tellurian Inc. wholly owned subsidiary Driftwood Pipeline LLC has applied with the US Federal Energy Regulatory Commission to build and operate Line 200 and Line 300, dual 42-in. OD interstate natural gas pipelines starting near Ragley, Beauregard Parish, La., and ending near Carlyss, Calcasieu Parish. The new pipeline has been designed and routed to move Haynesville shale production from an interconnection with Texas Eastern Transmission Co.’s pipeline 21 miles north of Lake Charles to demand within and south of Lake Charles, bypassing what Tellurian describes as a “constrained, complex, and expensive transportation pathway.”

The company plans to begin construction in 2022 and put the lines in service during 2023. Line 200 is the project’s Phase 1. Line 300, 30 miles long, is Phase 2. Line 300 extends 7 miles east and north from the planned starting point of Line 300 at Indian Bayou.

Line 200 will use one compressor station and eight interconnects to ship 2.4 bcfd. Line 300 will expand the compressor station to bring total capacity to 4.6 bcfd.

Driftwood Pipeline plans to use Baker Hughes-supplied electric-drive compression, which it says will reduce the pipelines’ carbon dioxide emissions by more than 99%.

Pieridae to build 3-million tpy Alberta CCS complex

Pieridae Energy Ltd. plans to develop a 3-million tonne/year (tpy) carbon sequestration project, Caroline Carbon Capture Power Complex, in conjunction with its Goldboro LNG project. The complex, sited at Pieridae’s Caroline gas processing plant in Alberta, will be a combination of large-scale carbon capture and sequestration and powerplant.

Carbon capture will pull from three sources: CO2 generated by the gas processing plant, from power production, and produced by third parties. It will be stored in one of Caroline’s depleted gas reservoirs in an amount equal to Goldboro’s anticipated emissions.

The complex will produce as much 800 Mw/year of electricity. Phase 1 will sequester 1 million tpy and produce about 200 Mw/year.

Caroline can process 300 MMcfd of sour gas and includes 4,100 tonnes/day of sulfur forming and storage and two compressor stations. Gas processed at Caroline and two other nearby plants will be used to feed Goldboro LNG. The three plants combined can process as much as 750 MMcfd but have been operating at 330 MMcfd (OGJ Online, Dec. 8, 2020).

Kinder Morgan to acquire Stagecoach Gas Services

Kinder Morgan Inc. has agreed to acquire Stagecoach Gas Services LLC, a natural gas pipeline and storage joint venture of Consolidated Edison Inc. and Crestwood Equity Partners LP, for $1.225 billion to help connect natural gas supply sources and Northeast demand areas.

In New York and Pennsylvania, Stagecoach consists of four natural gas storage facilities (Stagecoach, Thomas Corners, Steuben, and Seneca Lake) with a total working gas capacity of 41 bcf and three natural gas pipelines (MARC I, North/South, and Twin Tier) with a combined throughput capacity of about 3 bcfd with multiple interconnects to major interstate natural gas pipelines, including Tennessee Gas Pipeline (TGP), a KMI subsidiary.

The deal is expected to close in this year’s third quarter subject to regulatory approval.