OGJ Newsletter

June 27, 2022
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


bp to exit oil sands, increase offshore Canadian acreage

bp PLC will increase its acreage position offshore Eastern Canada and sell its 50% non-operated interest in the Sunrise oil sands project in an agreement reached with Calgary-based Cenovus Energy Inc.

bp will no longer have interests in Canadian oil sands production and will shift its focus to potential offshore growth. The company currently holds an interest in six exploration licenses offshore Eastern Newfoundland.

Total consideration for the transaction includes $600 million (Can.) cash, a contingent payment with a maximum aggregate value of $600 million (Can.) expiring after 2 years, and Cenovus’s 35% position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. bp’s non-operated stake in the Bay du Nord project will expand its position offshore Eastern Canada.

Saudi Arabia raises July crude prices for most regions

Amid expectations of strong demand this summer and tight supply, Saudi Arabia raised July prices for its crude in most regions except the US.

Prices have risen the most for Asian buyers. Saudi Arabia raised the July official selling price (OSP) for its flagship Arab Light crude to Asia by $2.1/bbl from June, a $6.5/bbl premium above the Oman-Dubai benchmark it uses. The increase was well above the $1.5/bbl rise forecasted by most market analysts.

Oil demand in Asia is expected to increase. Saudi crude will be particularly popular with Asian refiners such as Japan and South Korea, which shunned Russian oil after the Ukrainian invasion. Meanwhile, China, the world’s largest oil importer, is expected to boost demand as it reopens some cities, including Shanghai, after a prolonged COVID-19 lockdown. However, some Asian demand for Saudi oil may be offset by continued Russian oil flows to India and China, which have been ramping up their purchases of Russian cargoes at bargain prices.

For the European market, the price of the Arab Light will also be higher. Saudi Arabia raised European buyers’ prices for grades similar to Russia’s Urals by $2.2/bbl to a $4.3/bbl premium over Brent.

Prices for US customers were kept unchanged for the second straight month.

The increase in prices for July shipments resumes a streak of hikes that started in February, which was only broken when Saudi Aramco cut June prices from record levels.

The price increase also followed the decision by the Organization of Petroleum Exporting Countries and allies (OPEC+) to boost output for July and August by 648,000 b/d, or 50% more than previously planned (OGJ Online, June 2, 2022).

BKV, EnLink form Barnett-focused CCS partnership

BKV Corp. and EnLink Midstream LLC have reached a Phase I final investment decision and agreed to develop a carbon capture and sequestration (CCS) project in the Barnett shale region of North Texas. The companies plan to begin injecting carbon dioxide (CO2) by end 2023.

Under the agreement, EnLink will use modified infrastructure to transport natural gas produced by BKV’s Barnett shale operations to an EnLink gas processing plant in Bridgeport, Tex. At the Bridgeport plant, the CO2 waste stream will be captured, compressed, and then disposed of through permanent sequestration via BKV’s nearby injection well.

BKV said the project will offset its emissions by about 10%. It has a goal of reaching net-zero Scope 1-2 emissions by 2025.

EnLink has targeted a 30% reduction in CO2-equivalent emissions intensity by 2030 over its 2020 Scope 1 emissions intensity. The company is working with Honeywell International Inc. to develop CCS solutions along the Louisiana Gulf Coast between New Orleans and Baton Rouge. 

Wentworth to acquire interest in Tanzanian gas development project

Wentworth Resources, a Tanzania-focused natural gas production company, agreed to acquire Scirocco Energy plc’s 25% non-operated working interest in the Ruvuma Production Sharing Agreement in Tanzania.

The 1.9 tscf (mean GIIP) Ntorya gas discovery within Ruvuma is operated by ARA Petroleum Tanzania (50% working interest, Aminex plc 25%) and is adjacent to Wentworth’s Mnazi Bay gas producing asset (31.94% non-operated). The discovery well is 30 km west of the Madimba gas plant.

Consideration is comprised of an initial cash payment of $3 million, with further deferred and contingent cash payments of up to $13 million dependent on certain development and production milestones.

The work program is in progress with completion of the 3D seismic acquisition expected in this year’s second half.

Drilling of the Chikumbi-1 well is expected late this year or early 2023, Wentworth noted in a June investor presentation. First gas is expected from Ruvuma in 2024 with initial production of up to 140 MMscfd (gross).

Completion is subject to Scirocco shareholder approval, government approval, and the waiver of partner pre-emptions.

 Exploration & Development Quick Takes

ConocoPhillips makes minor gas discovery southwest of Skarv

ConocoPhillips Skandinavia AS made a minor gas discovery in the Norwegian Sea. Preliminary estimates place the size of the discovery at less than 0.1 million std cu m of recoverable oil equivalent, but results will be considered for further license prospectivity, the Norwegian Petroleum Directorate said in a release June 16.

Well 6507/4-3 S, the first exploration in PL 1064, was drilled by the Transocean Norge rig in 436 m of water 30 km southwest of Skarv field and 240 km west of Brønnøysund.

The well was drilled to a vertical depth of 3,914 m subsea. It was terminated in the Lange formation from the Late Cretaceous.

The well encountered sandstone layers in the Lange formation totaling about 55 m with poor reservoir quality. The well encountered a 1-m gas column in the shallowest part of the sandstone layers, but no contacts could be proven.

The well was not formation-tested, but extensive data acquisition and sampling were carried out. The well will be permanently plugged.

Transocean Norge will drill wildcat well 6306/3-2 S in production license 935 in the Norwegian Sea, where ConocoPhillips Skandinavia AS is operator.

ConocoPhillips is operator at PL 1064 (40%) with partners Aker BP (20%), Equinor Energy AS (10%), and PGNiG Upstream Norway AS (30%).

Aker BP to assess minor discovery near Valhall field

Aker BP ASA and partners will assess a minor Norwegian Sea oil and gas discovery regarding potential further delineation. Preliminary estimates place the size of the discovery at 0.6-1.9 million standard cu m recoverable oil equivalent, according to a June 1 release from the Norwegian Petroleum Directorate (NPD).

Wildcat well 2/8-19 was drilled by the Maersk Invincible drilling rig in PL 1085, about 10 km north of Valhall field and 270 km southwest of Lista in 69 m of water.

The well, the first in the license, was drilled to a vertical depth of 806 m subsea. It was terminated in the Nordland Group in the Pliocene.

The primary exploration target was to prove petroleum in reservoir rocks in Lower Pliocene clinoforms (Nordland Group). The secondary target was to prove petroleum in reservoir rocks in Middle Pliocene clinoforms (Nordland Group).

In the primary exploration target, the well encountered a 9-m oil column in a sandstone reservoir totaling 56 m in the Nordland Group. The oil column was in a reservoir with moderate to good reservoir quality. The oil-water contact was proven at 703 m subsea. Traces of petroleum were also observed in sandstone with moderate to poor reservoir quality deeper than the proven oil-water contact, NPD continued.

In the secondary exploration target, the well encountered a 15-m gas column in a sandstone reservoir. The reservoir totaled 68 m, and reservoir quality varied from good (top) to poor (bottom). The gas-water contact was proven 563 m subsea.

The well was not formation-tested, but extensive data acquisition and sampling were carried out. The drilling rig is now headed to Denmark for classification.

Aker BP is operator of the license with 55% interest. Partners are DNO Norge AS (25%) and Petoro AS (20%).

TotalEnergies lets subsea contract for CLOV development offshore Angola

TotalEnergies EP has let a subsea production systems contract to TechnipFMC PLC for the CLOV3 development in Block 17, offshore Angola.

The contract is the first under the companies’ new framework agreement covering subsea trees for brownfield developments in the block. The CLOV3 contract includes subsea trees and associated controls, umbilical termination assemblies, jumpers, and services.

Comprising four oil fields (Cravo, Lirio, Orquidea, and Violeta), CLOV is the fourth TotalEnergies-operated production hub in Block 17 in the Angolan deep offshore. The fields are developed simultaneously, and their production is fed into a single all-electric FPSO.

Block 17 is operated by TotalEnergies (38%) Partners are Equinor (22.16%), ExxonMobil (19%), BP Exploration Angola Ltd. (15.84%), and Sonangol P&P (5%). The contractor group operates four FPSOs in the main production areas of the block, namely Girassol, Dalia, Pazflor, and CLOV.

 Drilling & Production Quick Takes

Santos to drill 130 new wells in Fairview gas field

Santos Ltd. plans this year to drill and connect more than 130 new production wells in the Fairview coal-seam gas field in Bowen basin, north of Roma in central eastern Queensland. Work is scheduled to begin in June with first gas in October 2022, the company said. Santos will spend $360 (Aus.) million on the drilling program.

Peak production of about 78 terajoules/day of gas is expected. The gas will feed the Santos-operated 8.6-million tonne/year Gladstone LNG plant on Curtis Island via an existing 420-km buried gas pipeline.

Santos managing director and chief executive officer Kevin Gallagher said that while the gas will feed the Gladstone plant and bring in export revenue, the investment will help free up other gas supply sources for the Australian domestic gas market. Fairview’s expected production would meet roughly 25% of Queensland’s demand.

So far, 600 wells have been drilled at Fairview out of a total of 1,122 approved.

Fairview field, about 30 km northeast of Injune, was discovered in 1994. Santos bought into the field in 2005 with the US$466-million acquisition of US-listed Tipperary Corp. to gain a 75% interest and operatorship.

Gladstone LNG’s concept was revealed in 2007 and first LNG was shipped to Asia from the plant in 2015.

Norway production down slightly in May, NPD says

Norway’s production averaged 1.831 million b/d in May, the Norwegian Petroleum Directorate reported.

Norway’s production averaged 1.871 million b/d in April.

Average daily liquids production in May consists of 1.62 million b/o, 200,000 bbl of NGL, and 11,000 bbl of condensate.

Oil production in May was 2.4% lower than the NPD’s forecast and 4.8% lower than the forecast so far this year.

Shell lets Mars Corridor engineering and procurement contract

Shell Offshore Inc., a subsidiary of Shell PLC, has let a 3-year brownfield engineering and procurement (EP) services support contract to Audubon Engineering Co. LP for Shell’s Mars Corridor, about 124 miles southeast of New Orleans.

The contract, which comes with two 1-year options to extend, covers some of Shell’s offshore assets in the US Gulf of Mexico, including Mars, Olympus, Ursa, and Vito tension leg platforms. The water depths for this portfolio are 3,000-4,000 ft.

Contract scope spans topside engineering and procurement services encompassing single-well subsea tiebacks, replacements to cranes, lifeboats and high-volume air conditioning, upgrades to controls, firewater systems and utilities, gas-lift installation, and prefabricated skid packages.

Audubon’s operating centers in New Orleans and Houston will execute the contract.

Equinor drills dry hole in Cambozola well

Equinor Energy AS drilled a dry well in license PL1049 in the Northern North Sea, according to a June 2 release by Longboat Energy Norge AS.

Cambozola exploration well 34/9-1S targeted Lower Cretaceous turbidite sand lobes and had the potential to be a play opener. The well was drilled to a total vertical depth of 4,393 m below sea level. Background gas readings were recorded throughout the overlying section, but the well failed to encounter any effective reservoir. Analysis of the data collected remains ongoing to understand the observed bright seismic amplitude anomaly and any remaining Lower Cretaceous prospectivity in the area.

Equinor is operator at PL1049 (35%) with partners Longboat Energy (25%), Petoro AS (20%), and Sval Energi AS (20%).  

Obsidian Energy returns to Viking play drilling

Obsidian Energy Ltd., Calgary, has returned to development drilling in its Viking area in central Alberta.

Citing higher commodity prices, the company returned to the light oil, horizontal development play for the first time since 2017, licensing eight 100% working interest wells and spudding the first well mid-May as part of a development program to revitalize the asset, the company said in a release.

Overall, the eight wells are expected to add 1,000 boe/d on a 30-day, initial production basis (67% light oil).

Capital expenditures for the project are about $12.5 million (Can.) with first production expected early in this year’s third quarter.

Because the light oil focused play holds a material degree of associated natural gas, the asset “offers highly economic returns with current commodity prices while providing the company with the opportunity to continue drilling through the typical spring break-up period due to favorable ground conditions in the area,” the company continued.

Obsidian operations are focused in the Esther area.


Cooper Energy buys Orbost gas processing plant

Cooper Energy Ltd., Adelaide, has agreed to acquire the Orbost gas processing plant in east Gippsland from the APA Group for $270-330 million (Aus.).

The plant processes Cooper’s production from Sole gas field in Bass Strait.

APA will remain plant operator for the period between financial close and the date on which the Major Hazard Facilities License is transferred, which is expected to take up to 12 months.

The deal accelerates Cooper’s position in the Gippsland basin and strengthens the end-to-end capability to produce, process, and deliver gas to domestic customers and the spot market, said David Maxwell, managing director.

Following the acquisition, Cooper will operate three gas fields and two gas plants supplying gas into the southeast Australian market.

The Orbost plant is about 14 km from the Gippsland town of Orbost and is connected to the Eastern Gas Pipeline from Gippsland to Sydney.

The plant’s performance has varied during the last 18 months, but it can deliver at average rates of 55 terajoules/day of gas following upgrades in March and April this year. Further improvements are planned, the company said.

Deal closing, conditional on completion of a minimum capital raise by Cooper, it expected late July 2022.

Newfoundland operator advances refinery-to-renewables conversion project

Dallas-based private equity firm Cresta Fund Management’s Braya Renewable Fuels has let a contract to ABB Ltd. to provide a suite of automation and digital technologies to support the operator’s ongoing conversion of NARL Refining LP’s former 130,000-b/d refinery at Come-by-Chance, Newf., into a production hub for renewable diesel and sustainable aviation fuel (SAF) (OGJ Online, Feb. 14, 2022).

Already under way and scheduled to begin producing 18,000 b/d of renewable diesel in third-quarter 2022, Phase 1 of Braya’s Come-by-Chance conversion project will use a feedstock of used cooking oil, corn oil, and animal fat, according to ABB and the operator.

While a definitive timeframe has yet to be confirmed for a proposed second phase of the project to double production capacity to about 36,000 b/d, Cresta and the government of Newfoundland and Labrador previously said the project also will enable the site’s potential expansion into producing other forms of energy such as green hydrogen.

Cresta said in 2021 the converted refinery will be equipped to allow future modification to expand production as global renewable fuel demand grows.

Alongside upgrading the site’s automation technology by implementing its proprietary ABB Ability System 800xA distributed control system (DCS), ABB will supply its ABB Ability Connected Worker application suite, the service provider said in a release.

ABB also said it will supply its high-fidelity process simulator to enable efficient commissioning and startup of the plant’s new hydroisomerization (HI) and hydrodeoxygenation (HDO) units, as well as a fourth ABB Extended Operator Workplace (EOW) platform to support dedicated operator training.

Project scope includes installation, commissioning, and user training services for all new equipment supplied under the agreement.

Chevron completes acquisition of Renewable Energy Group

Chevron Corp. has completed its purchase of Iowa-based Renewable Energy Group Inc. (REG).

Completion of the transaction follows REG shareholders’ approval of the proposed merger agreement at the renewable diesel producer’s May 17 annual meeting, Chevron and REG said in releases.

Closing follows Chevron’s announcement earlier in the year that it would purchase REG in an all-cash deal valued at $3.15 billion as part of Chevron’s broader aim to grow its renewable fuels production capacity to 100,000 b/d by 2030, as well as bring additional feedstock supplies and pretreatment infrastructure into its system (OGJ Online, Feb. 28, 2022).

To remain headquartered in Ames, Iowa, REG is working to complete a 250-million gal/year capacity expansion and improvement project now under way at its existing 90-million gal/year renewable diesel refinery in Geismar, Ascension Parish, La. (OGJ Online, Nov. 3, 2021).

Estimated at an overall cost of about $950 million, the Geismar improvement and expansion project remains on schedule to reach mechanical completion by 2023, with full commissioning of the expanded plant to follow in 2024.

Fuel produced at REG’s expanded Geismar plant will reduce carbon dioxide (CO2) emissions by up to 2.8 million tonnes/year, or the equivalent to greenhouse gas emissions from 7.1 billion miles driven by average passenger vehicles, according to the operator.


QatarEnergy selects three additional NFE expansion project partners

QatarEnergy has selected its second, third, and fourth partners in the $28.75 billion North Field East (NFE) expansion project.

Eni was selected as the second partner in the project, the operator said in a release June 19. The two companies will partner in a new joint venture company in which QatarEnergy will hold a 75% interest and Eni will hold 25% interest. The JV will own 12.5% of the entire NFE project, which has a total LNG capacity of 32 million tpy, the operator said. 

In its third agreement, QatarEnergy partnered with ConocoPhillips in a new joint venture company. QatarEnergy will hold a 75% interest and ConocoPhillips will hold the remaining 25% interest, the company said in a release June 20. The JV will own 12.5% of the entire NFE project.

The company signed ExxonMobil as its fourth partner. Under the terms, the companies will partner in a new JV, in which ExxonMobil will hold 25%. The JV will own 25% of the entire North Field East project. ExxonMobil’s participation in Qatar LNG volumes is expected to increase total capacity to 60 million tpy from 52 million tpy, ExxonMobil said in a release June 21.

NFE, launched by QatarEnergy in third-quarter 2019, is under construction and intended to increase Qatar’s total LNG export capacity to 110 million tonne/year (tpy) from 77 million tpy by 2027 via four new 8.25-million tpy trains. The offshore upstream part of the project will develop the southeastern area of North field using 8 platforms and 80 wells.

In its first partnership deal earlier in June, QatarEnergy selected TotalEnergies SE to hold a 25% interest in a JV to develop the LNG project.

In April, QatarEnergy awarded an engineering, procurement, and construction contract to a JV between Técnicas Reunidas SA and Wison Engineering Services Co. for work on the project (OGJ Online, Apr. 28, 2022). 

Energía Argentina signs Tenaris to supply Vaca Muerta pipes

Energía Argentina has signed Tenaris to supply welded pipes for Stage 1 construction of the 563-km (350-mile) Presidente Nestor Kirchner Gas Pipeline (GPNK), which will move Vaca Muerta shale natural gas from Tratayén, Neuquén province, to Saliquelló, in Buenos Aires province. Construction of the roughly 850-MMcfd pipeline is expected to take 18 months.

The state company will buy 582 km of 36-in. OD pipe and 74 km of 30-in OD pipe, covering both the first stage of GPNK and associated projects. Tenaris’s mill in Valentín Alsina, Buenos Aires, will manufacture the pipes.

Earlier in June Energía Argentina launched an engineering, procurement, and construction tender for the pipeline (OGJ Online, June 7, 2022).

The Neuquén government earlier this year granted Chevron Corp. a hydrocarbon concession for unconventional exploitation that could open new development in the northern area of the Vaca Muerta shale formation (OGJ Online, Apr. 12, 2022).

Natural gas production from the Late Triassic-Late Cretaceous Vaca Muerta peaked in August 2021 at almost 1.6 bcfd, according to Rystad Energy, before slipping to roughly 900 MMcfd.

In 2019 Vaca Muerta had technically recoverable natural gas resources of 308 tcf.

Cheniere to sell Equinor 1.75-million tpy of LNG

Cheniere Energy Inc. subsidiary Cheniere Marketing LLC has agreed to sell Equinor ASA 1.75 million tonnes/year (tpy) of LNG on a free-on-board basis for 15 years. Sales would start second-half 2026 and reach the full 1.75-million tpy rate one year later.

Half of the volume, about 900,000 tpy, is subject to Cheniere making a positive final investment decision (FID) to build additional liquefaction capacity at its 15-million tpy Corpus Christi LNG plant beyond the seven-train, 10-million tpy Corpus Christi Stage III project already in development.

Estonia begins building LNG terminal infrastructure

Estonian gas system operator Elering AS contractor, Connecto AS, has begun building the pipeline that will connect the planned floating 5-billion cu m/year (bcmy) Paldiski LNG terminal in Estonia to the regional Balticconnector natural gas network. Construction is divided into four major components:

  • Pipeline from landfall to the onshore compressor station.
  • Subsea pipeline from the coast to the floating storage and regasification unit’s (FSRU) mooring quay.
  • Equipment on the mooring quay.
  • Connection between the quay and the FSRU.

The pipeline’s route has been marked and site preparation is under way. Directional drilling between the terminal’s compression and the coast is expected to begin in July.  

Elering has already acquired the project’s line pipe and stopcocks. Total length of the pipe between the compressor station and mooring quay is 1.2 km.

Estonia’s use of the FSRU is a temporary measure until a permanent terminal site can be built in Finland. Elering and Gasgrid Finland in May 2022 signed a cooperation agreement for the joint lease and management of the FSRU to ensure the security of gas supply to the two countries and to end the need for Russian pipeline gas.

According to the cooperation agreement between Elering and Gasgrid, the parties each will develop the necessary infrastructure for the terminal and bear the related costs. But FSRU rental costs will be covered jointly in proportion with Estonian and Finnish gas consumption, 20% and 80% respectively.

The FSRU will arrive in Estonia by end-2022 and remain there until work at the Finnish site is completed. Once the FSRU is stationed in Finland, Estonia will have two potential gas supply directions, Balticconnector and the FSRU in the north, and Latvian underground gas storage, the 3.7-bcmy Klaipeda LNG terminal, and Polish-Lithuanian gas connector in the south.