OGJ Newsletter

Jan. 3, 2022


Chevron sets $15 billion capex budget for 2022

Chevron Corp. has set a 2022 organic capital and exploratory spending program of $15 billion, at the low end of its $15-17 billion guidance range and up more than 20% from 2021 expected levels.

This program supports the operator’s objective of higher returns and lower carbon, including about $800 million in lower carbon spending, the company said in a release Dec. 1

The program excludes expected inorganic capital of $600 million in anticipation of the formation of a renewable fuel feedstocks joint venture with Bunge.

In the upstream business, about $8 billion is allocated to currently producing assets, including about $3 billion for Permian basin unconventional development and about $1.5 billion for other shale and tight assets worldwide.

Additionally, $3 billion of the program is planned for major capital projects under way, of which about $2 billion is associated with the growth and wellhead pressure management project at Tengiz field in Kazakhstan.

Some $1.5 billion is allocated to exploration, early-stage development projects, midstream activities, and carbon reduction opportunities.

About $2.3 billion of planned organic capital spending is associated with the company’s downstream businesses.

Senex agrees to takeover by POSCO International

Senex Ltd., Brisbane, entered into a binding scheme implementation agreement with South Korean group POSCO International where POSCO will acquire 100% of Senex’s shares for $4.60/share (Aus.).

The price values Senex at around $900 million.

The offer comes months after POSCO made its initial offer of $4/share at end July. That offer was followed by three subsequent non-binding proposals: Aug. 27 ($4.20/share), Sept. 2 ($4.40/share), and Nov. 8 ($4.60/share).

The scheme is conditional on the approvals of Senex shareholders, Australian Foreign Investment Review Board, the South Korean foreign exchange and an independent expert’s report concluding the offer is fair and reasonable.

The deal also is contingent on completion of the proposed acquisition of Australia Pacific LNG’s natural gas fields in Queensland production licenses PL209 and PL445 for $80 million (Aus.). The gas fields are adjacent to Senex’s Atlas gas development which will increase Atlas production to 30 petajoules/year in 2024.

Senex directors have recommended that shareholders vote in favor of the scheme provided there is no superior proposal.

A meeting is likely to be scheduled for March 2022 and, if approved, the deal is expected to be completed by the end of that month.

POSCO has said that if its acquisition is successful, Hancock Energy, run by Australian magnate Gina Rinehart, will acquire 49.5% indirect interest in Senex.

In a separate announcement Dec. 13, Senex said it made a domestic sales agreement with Shell Energy for the supply of eight petajoules of natural gas over 4 years beginning in 2022.

The gas will be supplied from Wallumbilla hub in southeast Queensland at a fixed price in line with current market levels.

Phillips 66 sets 2022 capital program

Phillips 66 expects a 2022 capital program of $1.9 billion. The plan includes $992 million for sustaining capital and $916 million for growth capital. Some 45% of growth capital supports lower-carbon opportunities, the operator said in a release Dec. 10.

The midstream capital plan of $703 million, which includes Phillips 66 Partners, comprises $426 million for growth projects and $277 million for sustaining projects. Growth capital will be directed toward completing construction of Sweeny Frac 4 and repayment of its 25% share of the Bakken Pipeline joint venture’s debt due in 2022. Midstream growth capital also includes emerging energy opportunities to advance the company’s lower-carbon efforts.

In refining, the operator plans to invest $896 million, with $488 million for reliability, safety, and environmental projects. Refining growth capital of $408 million is primarily for the reconfiguration of the San Francisco refinery in Rodeo, Calif., as part of the Rodeo Renewed project. Upon expected completion early 2024, the project

will initially have over 50,000 b/d of renewable fuel production capacity. The conversion will reduce emissions and produce lower-carbon transportation fuels. Refining growth capital will also support opportunities for high-return, low-capital projects.

Phillips 66’s proportionate share of capital spending by joint ventures Chevron Phillips Chemical Co. LLC (CPChem), WRB Refining LP and DCP Midstream LLC is expected to total $1.1 billion and to be self-funded.

CPChem’s growth capital will fund expansion of its normal alpha olefins production, optimization, and debottleneck opportunities in the olefins and polyolefins chains, as well as continuing development of petrochemicals projects in the US Gulf Coast and Qatar.

WRB’s capital spending will be directed to sustaining projects, crude flexibility, and enhancing clean product yield.

Including Phillips 66’s proportionate share of capital spending for these large ventures, the company’s total 2022 capital program is projected to be $3.0 billion.

 Exploration & Development Quick Takes

Shell makes deepwater discovery in Perdido Corridor

Shell Offshore Inc., a subsidiary of Royal Dutch Shell PLC, made an oil discovery at the Blacktip North prospect in the US Gulf of Mexico in OCS block Alaminos Canyon (AC) 336, about 220 miles south-southeast of Houston.

The well was drilled to a total measured depth of 27,770 ft and encountered about 300 ft net oil pay at multiple levels. Evaluation is ongoing to further define development options.

The discovery is in the Perdido Corridor about 4.5 miles northeast of the recently appraised Blacktip discovery, 25 miles northeast of the recently announced Leopard discovery, 30 miles northeast of the planned Whale host, and 42 miles from the Perdido host (OGJ Online, Apr. 24, 2019). In 2021, Shell made final investment decision for the Whale deepwater development (OGJ Online, July 26, 2021).

Shell is operator at Blacktip North (89.49%) with partner Repsol E&P USA LLC (10.51%).

Aker BP to tie back Hanz discovery to Ivar Aasen

Aker BP and partners have sanctioned development of the Hanz oil and gas discovery in production license (PL) 028 B in the Norwegian North Sea. The discovery will be tied into the Ivar Aasen platform about 12 km further south.

Development will include one production well and one water injection well, and reuse of the subsea production systems from Jette field.

Total investment is estimated at NOK 3.3 billion. Startup is expected in first-half 2024. Total reserves are estimated at around 20 MMboe.

Aker BP is operator (35%). Partners are Equinor (50%) and Spirit Energy (15%).

Inpex discovers hydrocarbons onshore Abu Dhabi

Inpex Corp., through its subsidiary JODCO Exploration Ltd. (JEL), discovered multiple conventional oil, condensate, and gas columns in an exploration well at Onshore Block 4 in a coastal area in the central part of the Emirate of Abu Dhabi which includes Abu Dhabi City.

JEL conducted drilling operations based on the evaluation of 3D seismic exploration data and will conduct data analysis from crude oil and natural gas production tests. This is the first oil discovery of mainly Murban grade from this concession area as well as from a new geological formation. The provisional oil, condensate, and gas in place combined discoveries totals up to 1 billion boe.

Further exploration activities will pursue potential commercial development of the block in close collaboration with the Abu Dhabi National Oil Co. (ADNOC). The block covers a surface area of about 6,116 sq km in the vicinity of existing oil and natural gas production infrastructure, aiding early-stage development and production of crude oil and natural gas.

JEL is operator of the block and has 100% interest in the exploration phase (OGJ Online, Mar. 18, 2019).

 Drilling & Production Quick Takes

Alberta’s oil production curtailment policy ends

Alberta’s provincial policy on restraining oil production, a strategy to reduce price-depressing gluts, ended Dec. 31, 2021.

Energy Secretary Sonya Savage said Dec. 9 that no production limit had been set or enforced since December 2020. By ending the curtailment policy, the provincial government is eliminating one source of investment uncertainty for the oil industry, the energy secretary said.

“Oil production limits were intended to be a temporary measure when storage levels were high and there were significant pipeline constraints,” Savage said. “This meant our province’s resources were being sold at an extreme discount.”

Alberta oil production has recovered from the COVID-19 pandemic levels, she said. But that apparently does not create the risk that production will exceed export capacity and strain storage capacity.

“This is in large part because Enbridge’s Line 3 is now online and operational and the Trans Mountain Expansion is expected to come online in early 2023,” she said.

The problem developed over a few years as litigation and political opposition stalled or threatened to stall pipeline plans, including Enbridge Inc.’s Line 3 through Minnesota, Enbridge’s Line 5 through Michigan, TC Energy Corp.’s Keystone XL project, and the Trans Mountain Expansion, now government-owned.

Curtailment was scheduled to end Dec. 31, 2019, but in the middle of that year the ongoing concern about high volumes of oil lingering in Alberta storage led to an extension of the curtailment policy (OGJ Online, Aug. 29, 2019).

Now, “storage levels are expected to remain within the normal range of operations,” Savage said.

The Alberta government reported the province’s total production of both conventional and unconventional oil reached 18.9 million cu m (about 119 million bbl) in October, higher than the highest monthly total in 2019, before the pandemic hit.

ExxonMobil spuds well offshore Cyprus

ExxonMobil Exploration and Production Cyprus (Offshore) spudded the Glaucus-2 well in Block 10, in the Exclusive Economic Zone of the Republic of Cyprus. The block borders Egypt’s Shorouk concession and covers 2,572 sq km.

The well is being drilled by the Stena Forth drilling rig to confirm the extent of a large gas discovery ExxonMobil made in the block in 2017. Drilling will be monitored on a continuous basis by the staff of the Hydrocarbon Service of the Cyprus Ministry of Energy, Trade, and Industry.

ExxonMobil is operator (60%) with partner Qatar Petroleum International Upstream OPC (40%).

PGNiG drills dry well near Fenja field in Norwegian Sea

PGNiG Upstream Norway will plug Norwegian Sea well 6306/3-1 S. The well is dry, with no traces of petroleum. Data acquisition has been carried out.

The well, the first in license 937, was drilled about 15 km south of Fenja field and 100 km northwest of Kristiansund by the Borgland Dolphin drilling rig to a vertical depth of 2,353 m below sea level. It was terminated in basement rock. Water depth at the site is 241 m.

The objective was to prove petroleum in a project consisting of sandstones in the Lyr formation from the Early Cretaceous, as well as in the Rogn formation from the Late Jurassic.

The well encountered the Lyr formation with a thickness of about 5 m, consisting of calcite-cemented clay, silt, and extremely fine-grained sandstone with poor reservoir quality. The well encountered the Rogn formation with about 27 m of calcite-cemented sandstone with poor to moderate reservoir quality.

PGNiG Upstream Norway acquired the asset as part of a deal in 2021 to purchase all assets of INEOS E&P Norge for $323 million, nearly half of the original $615 million consideration (OGJ Online, Sept. 13, 2021).

Norway production decreased in November, NPD says

Norway’s liquids production averaged 1.999 million b/d in November 2021, the Norwegian Petroleum Directorate reported Dec. 21, 2021. Norway’s liquids production averaged 2.062 million b/d in October.

Oil production in November is 5.0% lower than the NPD’s forecast, and 0.5% higher than the forecast so far this year.

The average daily liquids production in November consists of 1.729 million b/o, 257,000 bbl of NGL, and 13,000 bbl of condensate.

Total petroleum production recorded for 2021 as of Dec. 21, 2021 is about 210.8 million standard cu m oil equivalents.

The total volume is 2.8 higher than the 2020-figures.


Sinopec JV starts up new unit at Fujian integrated refining complex

Fujian Refining and Petrochemical Co. Ltd. (FREP) has commissioned a new alkylation unit at its 12-million tonnes/year (tpy) integrated refining and chemical production complex at the southern coast of Meizhou Bay in Quanzhou, Fujian Province, China.

As of mid-December, FREP had started up and completed performance the performance test of the new STRATCO alkylation unit, certifying that the unit is meeting performance guarantees, technology licensor E.I. DuPont de Nemours & Co.’s DuPont Clean Technologies said in a release.

The STRATCO alkylation unit will process a mixed-butylene FCC feedstock into 7,700-b/sd (300,000-tpy) of low-sulfur, high-octane, low-rvp alkylate, enabling the complex to ensure its fuel production complies with the current China VI-A (equivalent to Euro 6) emission standard, which limits sulfur content in gasoline to a maximum of 10 ppm to help reduce automobile-generated pollution, according to the service provider.

Alkylate production from the unit also will comply with the pending China VI-B standard that—scheduled to take full effect in 2023—will further reduce levels of benzene, aromatics, and olefins in the gasoline pool, DuPont said.

Startup of FREP’s alkylation unit follows commissioning of six previous STRATCO units at China Petroleum & Chemical Corp. (Sinopec) refineries (OGJ Online, Apr. 21, 2021).

Alongside Fujian Petrochemical Co. Limited (50%)—a joint venture of Sinopec and the Fujian government—FREP’s other shareholders include ExxonMobil China Petroleum & Petrochemical Co. Ltd. (25%) and Saudi Aramco Asia Co. Ltd. (25%).

Sinclair’s Wyoming refinery lets contract for renewable feedstock pretreater

Sinclair Cos.’ Sinclair Oil Corp. subsidiary Sinclair Wyoming Refining Co. (SWRC) has let a contract to Applied Research Associates Inc. (ARA) to license technology for a new feedstock pretreatment unit under construction at the operator’s renewable diesel refinery collocated at the company’s 94,000-b/sd refinery in Sinclair, Wyo.

As part of the December contract, ARA will license its proprietary Hydrothermal Cleanup feedstock pretreatment (HCU Pretreat) technology for the 7,500-b/sd renewable feedstock pretreatment unit, which will enable the refinery to expand its feedstock slate to include lower-cost, lower-carbon intensity feedstocks for production of renewable diesel, the service provider said.

Specifically, HCU Pretreat technology allows efficient removal of phosphorous, metals, and other contaminants from fat, oil, and grease feedstocks, said Chuck Red, vice-president and director of ARA’s Better Fuels group.

According to ARA’s website, the HCU Pretreat process involves the following steps:

  • Renewable feedstock and water are pumped separately at system pressure and then mixed in a static mixer.
  • The mixture is heated by a feed-effluent heat exchanger and hot oil heater or refinery high-pressure steam.
  • The mixture is maintained at the desired cleanup temperature for about 2 minutes in turbulent flow conditions.
  • Clean product is then cooled via a feed-effluent heat exchanger and trim cooler.
  • Pressure is reduced to near ambient.
  • The clean organic and the aqueous phases readily separate using traditional oil-water separation techniques.

With detailed design of the HCU Pretreat project completed and construction already under way, the new renewable feedstock pretreatment unit is scheduled for startup in 2022, ARA said.

Upon announcing its agreement to purchase Sinclair’s downstream and midstream assets in a deal slated to close in mid-2022, HollyFrontier Corp. said SWRC’s new feedstock pretreatment unit will enable the 10,000-b/sd renewable diesel production refinery—which currently processes soybean oil and tallow—to expand its renewable feedstock slate to include distillers corn oil, as well as tallow and degummed soybean oil (OGJ Online, Aug. 4, 2021).


Gazprom commissions 20-bcmy Novoportovskoye subsea gas pipeline

Gazprom Neft has commissioned a 20-billion cu m/year (bcmy) subsea natural gas pipeline in the Russian Arctic, connecting production from Novoportovskoye field on Yamal Peninsula to the Yamburg-Tula gas trunk pipeline, part of Russia’s Unified Gas Supply System (UGSS). The company said that commissioning the 115.5-km pipeline opens opportunities for developing a major oil and gas cluster in the southern Yamal Peninsula, projecting potential incremental production of as much as 20 bcmy of gas and 10 million tonnes/year (tpy) of oil.

The pipeline will run 58.4 km across the Gulf of Ob, 5 m below the seabed. Novy Port residents will be connected to the UGSS as part of the project.

Gazprom is also building a gas processing plant. In addition to natural gas, it will process condensate and associated petroleum gas (APG). The company expects to be able to use up to 95% of produced APG.

The project’s total cost is more than ₽150 billion ($2 billion).

Novoportovskoye field is in the Yamalsky District of the Yamalo-Nenets Autonomous Okrug, 30 km from the coast of the Gulf of Ob. Recoverable reserves stand at 248 million tonnes of oil and condensate, and 266 bcm of gas, according to Gazprom. A total 14.87 million tonnes of oil equivalent were produced in 2020, 5% more than in 2019.

Full-scale production drilling at Novoportovskoye field started third-quarter 2014. Gazprom describes oil produced at Novoportovskoye field, Novy Port crude, as a unique light (35° API) low-sulfur (~0.1%) grade.

Venture Global LNG gets FERC approval for Calcasieu Pass Block 2 commissioning

Venture Global LNG has received US Federal Energy Regulatory Commission (FERC) permission to start Block 2 commissioning at its 10-million tonne/year (tpy) Calcasieu Pass LNG liquefaction plant in Cameron Parish, La. The plant is expected to start test production end-2021 or early 2022 and enter commercial service by mid-2022.

Calcasieu Pass will use 18 0.6-million tpy trains arranged in two-train blocks. Block 1 received FERC commissioning approval in early November 2021. 

Venture Global in December 2021 applied with FERC to develop its fourth LNG plant in Louisiana, the 20-million tpy CP2 LNG. The new project would be built adjacent to Calcasieu Pass LNG (OGJ Online, Dec. 3, 2021).

The company is also developing the 20-million tpy Plaquemines LNG and 20-million tpy Delta LNG plants, both in Plaquemines Parish, La. First production from Plaquemines LNG is expected in 2024.

Viva Energy signs MoU with Woodside for potential LNG supply

Viva Energy, operator of the Geelong refinery near Geelong in Victoria, and Woodside Petroleum Ltd., Perth, signed a memorandum of understanding (MoU) to engage in discussions that could lead to Woodside supplying LNG to Viva’s proposed regasification terminal at the Geelong site.

The agreement could result in Woodside gaining regasification rights for supply of gas to Australian east coast markets. The MoU provides a framework and timeline to negotiate binding regasification capacity commitments.

The agreement could underpin Viva’s plan for regasification at Geelong which includes a moored floating LNG reception terminal, extensions to the existing refinery jetty, and additional pipelines.

Scott Wyatt, Viva’s chief executive officer, said that Woodside’s participation in the gas terminal project highlights the value of LNG terminals as ‘virtual pipelines’ to deliver LNG from Australia and other sources to the country’s east coast domestic market.

In a parallel announcement Viva said it signed a heads of agreement (HoA) with global infrastructure and transport group Höegh LNG Ltd. to charter a floating storage and regasification unit for the proposed Geelong terminal.

The HoA sets out a framework and key terms for the negotiation of a binding time charter party agreement.

Viva is aiming to make a final investment decision to proceed with the Geelong project by third-quarter 2022.

Viva’s agreement is the second to involve Höegh in Australia’s race for construction of east coast LNG reception terminals.

In November 2021, Australian Industrial Energy (AIE) signed a long-term charter party agreement for its proposed terminal at Port Kembla on the New South Wales coast south of Sydney (OGJ Online, Nov. 30, 2021).