OGJ Newsletter

June 21, 2021


Occidental to sell Delaware basin assets

Occidental Petroleum Co. will sell non-strategic acreage in the Permian basin to an affiliate of Colgate Energy Partners III LLC for $508 million, subject to adjustments for an effective Apr. 1, 2021 closing date.

The transaction is expected to close third-quarter 2021 and includes about 25,000 net acres in Texas’ Southern Delaware basin. Current production is about 10,000 boe/d from about 360 active wells. Proceeds from the sale will be applied to debt reduction.

President and Chief Executive Officer Vicki Hollub said that the transaction “brings our post-Colombia divestiture total to over $1.3 billion of the planned $2 billion to $3 billion, and since August 2019 we have divested more than $9 billion of assets.”

Colgate Energy is based in Midland and is a private, independent exploration and production company focused on acquiring and developing conventional and unconventional oil properties in Delaware basin.

Oil sands producers form Pathway to Net Zero initiative

Canadian Natural Resources Ltd., Cenovus Energy Inc., Imperial, MEG Energy, and Suncor Energy have allied in the Oil Sands Pathways to Net Zero initiative. The group’s goal is to work collectively with the federal and Alberta governments to achieve net zero greenhouse gas (GHG) emissions from oil sands operations by 2050. Member companies operate about 90% of Canada’s oil sands production.

Pathways is anchored by a major carbon capture, utilization, and storage (CCUS) pipeline connected to a carbon sequestration hub to enable multi-sector tie-in projects for expanded emissions reductions. The companies described the proposed CCUS system as similar to the multi-billion dollar Longship-Northern Lights project in Norway as well as other CCUS projects in the Netherlands, UK, and US, all of which involve significant collaboration between industry and government.

The proposed CO2 trunkline would link oil sands infrastructure in the Fort McMurray and Cold Lake, Alta., regions to a carbon sequestration hub near Cold Lake. The trunkline would also be available to other regional industries and could be extended to the Edmonton region.

The companies also plan to deploy existing and emerging GHG reduction technologies such as clean hydrogen, fuel switching, and electrification, and to accelerate application of potential emissions-reducing technologies like direct-air capture and small modular nuclear reactors.

“The Oil Sands Pathways to Net Zero initiative is an industry driven, made-in-Alberta solution which will strengthen our position as global ESG leaders,” said Sonya Savage, Alberta’s Minister of Energy. “Every credible energy forecast indicates that oil will be a major contributor to the energy mix in the decades ahead and even beyond 2050. Alberta is uniquely positioned and ready to meet that demand. This initiative will also pave the way for continued technological advancements, ultimately leading to the production of net zero barrels of oil.”

Civitas to boost DJ-basin holdings with Crestone acquisition

Civitas Resources Inc., to be formed upon closing of the recently announced merger of Bonanza Creek Energy Inc. and Extraction Oil & Gas Inc., has agreed to acquire Denver-Julesburg basin producer Crestone Peak Resources (OGJ Online, May 10, 2021). The acquisition will give Civitas more than 500,000 net acres and an estimated production base of 160,000 boe/d from year-end 2020 US Securities Exchange Commission proved reserves of more than 530 MMboe.

Civitas expects to have an enterprise value of about $4.5 billion after the all-stock transaction, which it anticipates closing in fourth-quarter 2021.

Crestone’s primary shareholder is Canada Pension Plan Investment Board, which will become Civitas’ largest shareholder and will designate one member to the Civitas board upon closing.

Civitas also noted that, inclusive of the Crestone assets, it will be Colorado’s first carbon-neutral oil and gas producer (Scope 1 and Scope 2) upon closing, advancing its net-zero goals.

Scope 1 emissions are direct greenhouse (GHG) emissions that occur from sources controlled or owned by an organization (e.g., emissions associated with fuel combustion in boilers, furnaces, vehicles), according to the Environmental Protection Agency. Scope 2 emissions are indirect GHG emissions associated with the purchase of electricity, steam, heat, or cooling. Although Scope 2 emissions physically occur at the site where they are generated, they are accounted for in an organization’s GHG inventory because they are a result of the organization’s energy use.

Earthstone adds Eagle Ford assets in separate transactions

Earthstone Energy Inc. has acquired working interests in Eagle Ford assets it operates in southern Gonzales County, Tex., from four separate sellers for an aggregate purchase price of $48 million in cash. The largest of the acquisition components, comprised of working interests owned by two affiliates of Titanium Exploration Partners LLC, constituted most of the total consideration.

Recent net production of the assets is about 1,150 boe/d (89% oil). The deals increase Earthstone’s working interest to 96% from 34%.

The company expects a second-quarter 2021 production impact of 400 boe/d (89% oil) and a second-half 2021 production impact of 1,000 boe/d (89% oil).

 Exploration & Development Quick Takes

Equinor considers minor North Sea oil discovery development

Equinor Energy AS and partners will consider developing a minor oil discovery in northern North Sea production license PL 554 as a tie-in to the planned development of the Garantiana oil discovery. Exploration well 34/6-5 S—the sixth in the license—was drilled 10 km northeast of Visund field and 120 km west of Florø in 385 m water depth. Preliminary estimates place the size of the discovery at 1.3-3.6 million std cu m recoverable oil equivalent.

The well was drilled by the West Hercules drilling rig to respective vertical and measured depths of 3,952 m and 4,005 m below sea level. It was terminated in the Nansen formation.

The primary exploration target was to prove petroleum in reservoir rocks of Early Jurassic age (Cook formation). The secondary exploration target was to prove petroleum in reservoir rocks of Early Jurassic age (Nansen formation).

The well encountered an 86-m oil column in the Cook formation, of which about 60 m are sandstones with moderate to good reservoir quality. Oil-water contact lies 3,672-3,674 m below sea level. The well encountered water-bearing sandstones in the Nansen formation.

Extensive data acquisition and sampling have been carried out. A well test yielded stable production of 550 std cu m/d oil and 22,000 std cu m/d gas through a 20/64-in. choke. Maximum production rates were 1,180 std cu m/d oil and 38,000 std m/d gas through a 28/64-in. choke. Tests revealed good flow properties with stable flow pressure, low pressure decline, and consistent pressure build-up.

The well has been permanently plugged.

The rig will now drill pilot holes in PL 272 and 035 (near the 30/11-8 S (Krafla) and 30/11-9 S (Askja) discoveries in the North Sea), where Equinor is operator.

Equinor is operator at PL 554 with 40% interest. Partners are Aker BP (30%) and Vår Energi AS (30%).

Vintage confirms commercial CO2 in Nangwarry-1

Vintage Energy Ltd., Adelaide, has flowed carbon dioxide (CO2) at commercial rates in a production test of its Nangwarry-1 wildcat in former permit PEL 155 in the Otway basin of southeast South Australia.

The company perforated the well across the top of the Pretty Hill formation and produced gas at 10.5-10.8 MMcfd through a 48/64-in. choke at a flowing pressure of 1,415 psi over a 36-hr period.

Analysis during a choked-back extended time showed the well to be highly productive and more than previous commercial flow rates in the region. There was no significant pressure drop in the reservoir after the test flow.

Current recoverable reserve estimates for the carbon dioxide (certified by ERC Equipoise) are 7.8-82.1 bcf with a median best case of 25.1 bcf. The estimates were made before the production test based on a gas column of 98 m thickness.

The recent test indicates a gas column of at least 120 m which could result in an increase in reserves.

Vintage has been granted a retention lease (PRL 249) surrounding the discovery and the company will establish a case for commercial development.

Karoon takes FID for Patola development offshore Brazil

Karoon Energy Ltd., Melbourne, has taken final investment decision for development of Patola oil field in the Santos basin offshore Brazil.

Patola lies within Karoon’s 100%-owned and operated production license BM-S-40 and is adjacent to the company’s producing Bauna and Piracaba fields 200 km off the coast of Sáo Paulo.

The plan is to tie the field back to the existing Bauna floating production storage and offtake (FPSO) vessel Cidade de Itajai.

Development will include two near-vertical subsea production wells to be drilled and completed with the Maersk Developer semisubmersible rig immediately after completion of the four-well Bauna intervention program.

An integrated engineering, procurement, construction, and installation contract was let to TechnipFMC for design, manufacture, and installation of subsea infrastructure.

Of the expected US$175-195 million development cost, $17 million has already been invested to ensure long-lead items are available to meet the project timeline, the company said.

Karoon will fund remaining costs through a combination of a newly arranged US$160 million reserve-based non-recourse loan, syndicated facility agreement, and cash flows from operations.

Terms of the syndicated facility include a requirement to hedge a portion of future oil production to protect cash flows in the event of lower oil prices. Karoon anticipates that about 40% of the forecast production in the first year of the loan and 30% in the second year will be hedged.

Patola is expected to produce at an initial rate in excess of 10,000 b/d from the same reservoirs as Bauna and Piracaba fields. Production is expected in first-quarter 2023.

Patola has 2C contingent resources of 14.7 million bbl, comprising 13.2 million bbl in Patola plus another 1.5 million bbl from Bauna that will come from injection of Patola gas into the Bauna reservoir.

Together with expected production from the Bauna intervention project, Karoon expects total output from the licence to reach 30,000 b/d in early 2023, more than double the current production.

 Drilling & Production Quick Takes

Central Petroleum brings Range CSG pilot online

Central Petroleum Ltd., Brisbane, has begun production at its Range coal seam gas pilot project in the Surat basin of southeast Queensland.

The development in exploration permit ATP 2031 is based on three wells—Range-6, 7, and 8—which have been successfully drilled and completed. Surface facilities have been installed and commissioned.

Pumps have been started at low speeds and the wells are currently producing water to the storage tank. The company plans to ramp up the pumps before July to gradually increase water rates and control well drawdown.

The three-well pilot will be operated for about 3 months subject to storage tank capacity.

The project is a 50-50 joint venture between Central Petroleum and fertilizer company Incitec Pivot Ltd. aimed to tap an estimated 270 petajoules of 2C contingent resources with full commercial production expected in 2024 to help meet the expected shortfall of gas supply in eastern Australia.

Eni’s Maha 2 West Ganal well successful

Eni SPA has successfully drilled and tested the Maha 2 appraisal well in West Ganal block offshore East Kalimantan, Indonesia. The field is 16 km southeast of Jangkrik floating production unit, operated by Eni.

The well, drilled to a depth of 2,970 m in 1,115-m water depth, encountered 43 m of gas-bearing net sands with excellent reservoir characteristics in levels of Pliocene age, Eni said. The production test, limited by surface infrastructure, recorded gas flows of 34 MMscfd.

Eni plans to drill two other appraisal wells for Maha field. It will use test results and reservoir cores to prepare a field development plan, most likely using subsea completion and a tie-in to Jangkrik.

The company operates West Ganal through its affiliate Eni West Ganal Ltd. (40%), while Neptune West Ganal BV and PT Pertamina Hulu West Ganal hold 30% stakes each.

Eni earlier this year began production from its Merakes project offshore East Kalimantan (OGJ Online, Apr. 26, 2021). The company produces about 80,000 boe/d in Indonesia. 


Raízen lets contract for Buenos Aires refinery

Raízen Argentina SA—a subsidiary of Royal Dutch Shell PLC and Cosan SA 50-50 joint venture Raízen Energia SA—has let a contract to Axens Group to supply technology licensing and equipment for a new unit to be installed at the operator’s 108,000-b/d refinery at Dock Sud in Avellaneda County, Buenos Aires Province, Argentina (OGJ Online, Apr. 24, 2018).

As part of the June contract, Axens will deliver a modular 10,200-b/sd FCC gasoline hydrodesulfurization unit outfitted with Prime-G+ process technology that will enable the refinery to upgrade the quality of its gasoline pool production to comply with more stringent Euro 5-quality fuel specifications in Argentina taking effect on Jan. 1, 2024, the service provider said.

Axens said its scope of delivery under the contract also will include supply of high-performance catalysts for the unit.

The service provider did not reveal a value of the contract or a definitive timeframe for the project’s scheduled completion.

The new modular FCC gasoline hydrodesulfurization unit is one of several projects included under Raízen Argentina’s $715-million investment program to modernize and expand operations at the Buenos Aires refinery during the 2020-23 period, according to a series of posts to the operator’s official social media accounts.

First announced in October 2020, the investment program will include works to increase the refinery’s processing capacity, upgrade existing units and processes, as well as improve energy efficiency and environmental practices at the site, the government of Argentina said in an Oct. 13, 2020 release.

Earlier this year, Raízen Argentina—which under a licensing agreement continues to market Shell-branded fuels in the country—completed an $8-million investment at the refinery included as part of the 2020-23 investment plan with commissioning of a new plant that will produce 14,000 tonnes/year of aerosol propellant for domestic and export markets, the operator said in a post to its official LinkedIn account.

In a separate release on Mar. 29, the government of Argentina confirmed Raízen Argentina was advancing development of $71-million worth of new units for the refinery under the 2020-23 program, including construction of a new naphtha hydrotreater, diesel hydrotreater, hydrogen production plant, and water treatment plant.

The spending program also includes plans for installation of a new crude distillation column at the site, according to local media reports out of Argentina.

Jizzakh Petroleum inks MOU for financing of Uzbekistani complex

Jizzakh Petroleum JV LLC, a joint venture of JSC Uzbekneftegaz and Gazprom International SA subsidiary Gas Project Development Central Asia AG, has entered a memorandum of understanding (MOU) with Russia’s Gazprombank (Joint Stock Company), State Development Corporation VEB.RF, and the Russian Agency for Export Credit and Investment Insurance (EXIAR) for financial backing of the operator’s proposed grassroots gas-to-chemicals complex based on methanol-to-olefins (MTO) technology in the Karakul area of southwestern Uzbekistan’s Bukhara region.

Signed on June 4, the four-sided MOU establishes a framework for potential future cooperation between the parties that covers an initial $800-million financing of the planned $2.8-billion MTO complex, including insurance of risk related to the project, Jizzakh Petroleum said.

Support from Gazprombank, VEB.RF, and EXIAR comes amid the operator’s plan to source a considerable volume of equipment, materials, and services for the project from Russia, according to Nigora Ibadova, Jizzakh Petroleum’s director for strategic development.

The MOU follows the early-2021 contract award to Versalis SPA—the chemical subsidiary of Italy’s Eni SPA—to provide licensing of its proprietary low-density polyethylene (LDPE)-ethylene vinyl acetate (EVA) technology for the MTO complex’s LDPE-EVA swing unit, which will be designed for a maximum EVA-equivalent production capacity of up to 180,000 tonnes/year.

Selected for siting in Bukhara due to its proximity to competitive feedstock, energy supplies, suitable infrastructure, and key export markets across Europe and the Asia Pacific, the proposed complex will process 1.5 billion cu m/year of domestic Uzbek natural gas to produce 500,000 tpy of high-quality polymers, including LDPE, EVA, polyethylene terephthalate (PET), and polypropylene (PP).

To become the core of Uzbekistan’s future gas chemical cluster—which will be Central Asia’s first special economic zone—the MTO complex forms part of Uzbekistan’s plan to diversify its economy, develop domestic industries, reduce product imports, and enable the country to monetize its natural gas resources via production of export-oriented, high-value products, according to Jizzakh Petroleum.


Net-zero emissions imposed on Woodside’s Pluto LNG project

The Western Australian government has imposed a net-zero emissions condition on approval of Woodside Petroleum’s proposed expansion of the Pluto LNG project on the Burrup Peninsula near Dampier.

The ruling follows advice to the government from the Environmental Protection Authority and imposes the emissions requirement on the existing Pluto LNG plant as well as the proposed second train which is part of the plan for development of Scarborough field.

Woodside has agreed to the requirements and will need to cut emissions from Pluto by 30% by 2030 to reach net zero by 2050. The company is targeting final investment decision on the project by yearend.

The new requirements are in line with the State government’s greenhouse gas emissions policy for major projects.

Acting chief executive Meg O’Neill said Scarborough has a very low carbon dioxide content and is a resource well suited to low-cost, low-carbon development.

The emission targets are the first for Woodside specific to a production project as opposed to those applied at the corporate level.

Gazprom advances pipelines, natural gas fields

OAO Gazprom is continuing predevelopment operations at 1.2-trillion cu m (tcm) Chayandinskoye natural gas field in Yakutia. Chayandinskoye is the primary resource base for the 38-billion cu m/year (bcmy) Power of Siberia gas trunkline to China. As many as six compressor stations also are being built along the pipeline, increasing its ability to move Chayandinskoye gas. In 2020, Gazprom brought a Chavandinskoye gas pretreatment unit and more than 100 wells onstream and it plans to bring additional wells online in 2021.

By late 2022, Kovyktinskoye field will be connected to Power of Siberia. Gazprom is building a pipeline section from this field to Chayandinskoye, with 261 out of 803.4 km welded, laid, and backfilled. Infrastructure under development at Kovyktinskoye includes foundation works and steel structure installation for Comprehensive Gas Treatment Unit No. 2 (CGTU-2). The site for CGTU-3 also is being prepared and development drilling continues.

Start-up and commissioning is in progress on two production trains of the 42-bcmy Amur gas processing plant’s (GPP) first complex. Amur GPP will treat Kovyktinskoye production. Installation of process equipment is nearly finished on the third and fourth trains, and large equipment for gas separation is being prepared for assembly on the fifth and sixth trains. The project is 76.1% complete, according to Gazprom.

A total of 333 km have been welded, laid, and backfilled as part expanding the 5.5-bcmy Sakhalin – Khabarovsk – Vladivostok gas pipeline between Komsomolsk-on-Amur and Khabarovsk. The work is nearing completion, Gazprom said.

Development of the gas production on Yamal Peninsula also continues. At Bovanenkovskoye field, Gazprom plans to put additional compressors at gas production Site No. 3 and six gas wells into operation in 2021. At 2-tcm Kharasaveyskoye field, production wells are being drilled, and the construction of access roads for motor vehicles, sites for a CGTU and a booster compressor station, and a connection gas pipeline is in progress.