GENERAL INTEREST Quick Takes
Oasis to acquire Williston basin assets from Diamondback for $745 million
Oasis Petroleum Inc., Houston, agreed to acquire Williston basin assets from Diamondback Energy in a cash transaction valued at $745 million.
Assets purchased include some 27,000 boe/d of production in first-quarter 2021 on a two-stream basis and 95,000 net acres.
Diamondback acquired Williston basin assets in its merger with QEP Resources announced in December 2020 and closed in March 2021 (OGJ Online, Dec. 23, 2020). Upon closing of the deal with Oasis—expected in July subject to closing conditions—Diamondback will exit the basin.
Oasis, in its May 3 release noting the deal and first quarter results, said the transaction lowers exploration and production cash G&A exit rate guidance to $1.25-1.35/boe from $1.60/boe prior to the transaction and provides opportunities for additional capital and operating cost savings.
First-quarter 2021 production for Oasis was 57,200 boe/d. The company raised its full-year guidance to 67,500-71,000 boe/d from its prior outlook of 57,000-60,000 boe/d.
Full year capital spending for exploration and production was increased to $230-245 million from $225-235 million (OGJ Online, Feb. 25, 2021). Full year 2021 capital spending was reaffirmed at $1.6-1.75 billion. Drilling and completion capital is expected on the acquired assets in 2022.
Full-year net production guidance was increased to 350,000-360,000 boe/d from 308,000-325,000 boe/d
Vencer Energy to acquire Midland basin assets from Hunt Oil
Vencer Energy LLC, the US upstream arm of oil trader Vitol, agreed to acquire Hunt Oil Co.’s Midland basin assets, the company said Apr. 30. Financial terms were not disclosed.
The assets comprise 44,000 acres across five counties in the Midland basin with current production of 40,000 boe/d.
The acquisition is the first for Houston-based Vencer, which was established in 2020, and both positions the company “as a significant shale producer in the US Lower 48,” and “represents an initial step to building a larger, durable platform in the US Lower 48,” said Ben Marshall, Head of Americas, Vitol in a prepared statement.
Santos, Eni looking to repurpose Bayu-Undan field
Santos Ltd. and Eni are considering options to repurpose and prolong the life of Bayu-Undan field infrastructure in the East Timor sector of the Timor Sea. Ideas include establishment of a carbon capture storage (CCS) scheme, a move that would require approval of the East Timor government.
The field joint venture partners signed a wide-ranging memorandum of understanding to cooperate on opportunities in northern Australia and East Timor.
Areas of cooperation include assessment of synergies of sharing possible infrastructures associated with Barossa and Evans Shoal gas fields, the undersea pipeline to Darwin, plus associated onshore gas processing that could lead to expansion of LNG infrastructure.
Santos said a CCS project at Bayu-Undan could create a revenue-generating industry for East Timor at a time when quality carbon credits are increasing in demand and value internationally.
Significantly, Santos needs to offset carbon emissions from the Barossa project which has a high percentage of carbon dioxide in the gas reservoir. Nearby Evans Shoal field also has a high CO2 content.
A final investment decision for the $3.6 billion Barossa project was announced at the end of March. That decision triggered the beginning of a $600-million investment in Darwin LNG and pipeline tie-in projects that will extend the life of the infrastructure for another 20 years.
The LNG plant, operated by Santos, can produce about 3.7 million tonnes/year of LNG. Santos has approval for two more LNG trains and said it is open to third party gas opportunities.
Other areas of collaboration include the possible development of Petrel and Tern gas fields in the Bonaparte Gulf through Eni’s existing 100%-owned Blacktip-Yelcherr gas plant infrastructure on the eastern Bonaparte coast in the Northern Territory.
Exploration & Development Quick Takes
ExxonMobil granted approval for Colombia research pilot project
ExxonMobil Exploration Colombia Ltd. has been granted approval by Colombia’s National Hydrocarbons Agency for a comprehensive research pilot project (Project Platero) in unconventional formations of Block VMM-37 in the Middle Magdalena basin.
The process should provide a path forward for testing and production of source rock hydrocarbons in future operations, Sinata Energy Inc. noted in a release Apr. 16.
Sintana Energy, via wholly owned Patriot Energy Sucursal Colombia, holds an undivided 30% participation interest in the block contract where ExxonMobil is operator with 70%.
In 2015, ExxonMobil drilled the A3 Manatí Blanco well into the block’s source rock. The well, which was never tested, was suspended for several years awaiting environmental permit approval.
ReconAfrica discovers petroleum system in Kavango basin, Namibia
Reconnaissance Energy Africa Ltd. (ReconAfrica) discovered a working conventional petroleum system in Kavango basin, northeast Namibia, based on data from the 6-2 well, the first of a three-well drilling program (OGJ Online, Feb. 17, 2020).
The well’s sample log shows over 200 m of oil and natural gas indicators or shows over three discrete intervals in a stacked sequence of reservoir and source rock. Extraction of oil from these samples and subsequent fingerprinting for key characteristics of the liquids supports an active petroleum system with multiple source intervals, the company said.
The shows are “indicative of migrated, thermogenic petroleum and occur over three different intervals” in the test well, said Dan Jarvie, petroleum systems chemist and member of ReconAfrica’s advisory board in a release.
“The intervals penetrated include highly porous, permeable sediments and marine source rocks as predicted, and an extensive marine carbonate lithofacies. Mud gas results indicate a high BTU gas with the presence of light oil in numerous cutting samples. Based on these initial results, the components and processes for a working petroleum system are all present,” he said.
With drilling, coring, and logging operations now complete, the rig is being moved to the 6-1 site 16 km north to evaluate the discovered systems in an area of maximum thickness.
ReconAfrica holds a 90% working interest in petroleum licenses in northeast Namibia comprising 6.3 million contiguous acres.
Achim Development continues Urengoyskoye field formations testing
Achim Development Ltd. started gas and gas condensate production from Block 5A in the Achimov formations of Urengoyskoye field in Western Siberia within the framework of comprehensive testing (hot commissioning) of the project equipment.
In January, hydrocarbon production began at Block 4A in the Achimov formations of Urengoyskoye field (OGJ Online, Jan. 20, 2021).
Both blocks are undergoing testing and gas is being fed into Gazprom’s gas transmission system.
Pre-development of the blocks is performed under harsh natural and climatic conditions and in complex geological structures. Hydrocarbons lie at a depth of about 4,000 m with high formation pressures (up to 62 MegaPascal or 8,992 psi).
Upon testing completion, production will be gradually ramped up to reach its design capacity by 2027. Production is expected to amount to over 14 billion cu m of natural gas and over 5 million tons of gas condensate.
Achim Development is a joint venture of Gazprom PJSC (74.99%) and Wintershall Dea GmbH (25.01%).
Santos group begins Bedout seismic programs
The Santos Ltd.-Carnarvon Petroleum Ltd. joint venture has begun the first of two extensive 3D seismic surveys in the Bedout subbasin permits off northwest Western Australia.
The Archer survey will cover Dorado oil and gas field in WA-437-P and continue southwest on-trend into adjoining permit WA-541-P taking about 40-50 days to complete. Santos intends to fast-track processing of the data to be available for interpretation later this year.
The Archer dataset is intended to complement two existing datasets in the region and provide support for development planning to ensure optimum well placement for maximum productivity.
The Shearwater Geo Coral seismic vessel will then move directly to acquire the Keraudren Extension 3D survey in permits WA-436-P and WA-438-P to the east of the Phoenix and Roc discoveries. The aim is to examine in more detail the more than 30 prospects and leads identified in the existing 2D data in the permits.
In total, the two surveys will cover an area of up to 4,800 sq km in a 3 1/2-month campaign. Apart from the Dorado development aspect, they will focus on near field exploration opportunities as well as exploration plays farther from the Dorado hub.
Drilling & Production Quick Takes
BHP produces first oil from Ruby in Trinidad and Tobago
BHP produced first oil from the Ruby project offshore Trinidad and Tobago in Block 3(a) within Greater Angostura field (OGJ Online, Aug. 8, 2019).
Ruby, discovered in November 2006, lies in 60-90 m of water about 40 km northeast of the twin-island nation’s coast. BHP made final investment decision (FID) on the $500-million project in August 2019 (OGJ Online, Aug. 8, 2019). Development of oil and gas production from Ruby and Delaware reservoirs consists of tie-back of five production wells and one gas injector well to existing operated processing infrastructure on Block 2C about 8 km east.
At completion, Ruby is expected to have capacity to produce up to 16,000 gross b/d of oil and 80 MMscfd of gas.
Drilling and completions activities at Ruby are ongoing, with subsequent wells to be placed into production in second- and third-quarter 2021. Completion is expected in third-quarter 2021.
Ruby is a joint venture between operator BHP (68.46%) and The National Gas Company of Trinidad and Tobago Ltd. (31.54%).
Aker BP granted consent to drill in King Lear
Aker BP has been granted consent by the Petroleum Safety Authority Norway (PSA) to use the Deepsea Nordkapp mobile drilling unit for a shallow gas pilot hole in Block 2/4-21 in the southern part of the Norwegian North Sea.
Well 2/4-U-77 will be drilled in the King Lear prospect in production license (PL) 146/333, 20 km north of Ekofisk field and 50 km north of Valhall field. Water depth is 70 m.
The discovery was proven in 2012 and delineated by appraisal wells 2/4-21 A in 2012 and 2/4-23 S in 2015. The reservoir contains gas and condensate in sandstone of Jurassic age in Ula and Farsund formations and has high pressure and high temperature. Development and operation plans are expected to be submitted by end-2022.
Aker BP is operator of the license with 77.8%. PGNiG Upstream Norway AS holds the remaining 22.2%.
PGNiG prepares to drill its first well in UAE
PGNiG has begun the second stage of exploration in Ras Al Khaimah Emirate with work beginning on design and location arrangements for the operator’s first exploration well on License Block 5.
The first phase consisted of a 3D seismic survey implemented by Geofizyka Toru´n, a PGNiG Group company.
The operator expects to drill the well to a maximum depth of 3,500 m at a location based on the seismic analysis. Preparations for tenders to select drilling and other service contractors has begun, and drilling is expected to begin in third-quarter 2022.
Work on PGNiG’s 619-sq km concession is being carried out over three 2-year exploration periods, with the possibility of an extension to the final exploration period if appraisal is ongoing. This is followed by a 30-year production period. After each exploration period, the license interest may be relinquished.
An exploration and production sharing agreement was signed with RAKPA and RAK GAS LLC in January 2019. A PGNiG branch was established in the Emirate and was granted an operating license in April 2019.
Equinor granted approval for pressure boosting pump on Vigdis field
Equinor Energy AS has been granted consent by the Petroleum Safety Authority Norway (PSA) for use of a pressure boosting pump on Vigdis field in production license (PL) 089 in the northern part of the North Sea.
The purpose of the boosting station is to accelerate oil production and increase oil recovery from Vigdis field (OGJ Online, Dec. 5, 2018).
Vigdis field lies in the Tampen area near Snorre, Statfjord, and Gullfaks fields. Water depth in the area is 280 m. Discovered in 1986, the plan for development and operation (PDO) was approved in 1994. The field has been developed with seven subsea templates and two satellite wells connected to the Snorre A platform. Production started in 1997.
PROCESSING Quick Takes
Piñon building Delaware basin sour gas treatment, carbon capture
Piñon Midstream LLC is building the greenfield Dark Horse sour gas treating and carbon capture site and associated pipeline infrastructure in northeastern Delaware basin, Lea County, NM. The project includes a centralized amine treating plant, an 18,000-ft deep acid-gas sequestration well (Independence AGI #1), and 30,000 hp of field compression.
Piñon expects Dark Horse to begin operations in July 2021, treating 85 MMcfd of sour gas. The company purchased a second amine treating plant that is scheduled to be installed and operational in fourth-quarter 2021, increasing capacity to 170 MMcfd. The site is expandable up to 400 MMcfd.
Treated gas will be delivered to multiple third-party gas processing plants.
Neste adding SAF production at Rotterdam renewables refinery
Neste Corp. is moving forward with a project to add production of sustainable aviation fuel (SAF) at its more than 1-million tonnes/year existing renewable diesel refinery at the Port of Rotterdam in Rotterdam, the Netherlands.
Requiring an estimated investment of about €190 million and slated for completion during second-half 2023, the project will involve modifications to the refinery that will allow the site to optionally produce up to 500,000 tpy of SAF, Neste said.
The operator disclosed no further details regarding specific modifications to be included in the addition, which comes as part of Neste’s broader program to expand its existing European feedstock and production platform for renewable products.
First announced in 2020, the Rotterdam SAF project initially was to add 450,000 tpy of SAF production at the refinery.
Once completed, the Rotterdam SAF addition—together with the company’s ongoing €1.4-billion, 1-million tpy SAF expansion at its 1.3-million tpy renewable diesel refinery in Singapore—by yearend 2023 will enable Neste to produce 1.5 million tpy of SAF, which reduces greenhouse gas emissions by up to 80% compared to fossil-based jet fuel, according to the operator.
Expansion of its renewable diesel and SAF production platform comes as part of Neste’s climate commitments, which include achieving carbon-neutral production by 2035 and reducing customers’ greenhouse gas emissions by at least 20 million tpy by 2030.
Neste also said it remains on track to reach final investment decision by yearend 2021 or early 2022 on its plan to build another renewables refinery in Rotterdam, which—if approved—could begin production in 2025.
SAPREF lets contract for Durban refinery
South African Petroleum Refineries (Pty.) Ltd. (SAPREF), a 50-50 joint venture of Shell Refining SA and BP Southern Africa, has let a contract to KBR Inc. to provide technology for an upgrade of the 33,000-b/d FCC unit at its 180,000-b/d refinery in Durban, South Africa.
KBR will license its Catalyst Regeneration technology as well as deliver basic engineering, detailed engineering, and proprietary equipment for the FCC regenerator project, which will enable SAPREF to improve the unit’s reliability and integrity by optimizing catalyst and air distribution, the service provider said.
While SAPREF itself has not revealed details on the proposed FCC regeneration project, BP Southern Africa said it planned to continue investing in upgrading SAPREF to ensure the refinery can meet domestic consumer demands for low-sulfur fuel, according to the company’s website.
In its most recent major maintenance shutdown, executed in 2019, SAPREF completed two upgrading projects at Durban to enable production of a low-sulfur fuel oil and low-sulfur diesel, the latter of which included installation of a new reactor in one of the plant’s diesel hydrodesulfurizing units, the operator said in its 2019 annual sustainability report.
TRANSPORTATION Quick Takes
MVP’s Southgate water-quality certification denied again
Mountain Valley Pipeline’s (MVP) 75-mile Southgate extension project has received notice that the North Carolina Department of Environmental Quality’s Division of Water Resources (DWR) reissued and supplemented its denial of MVP’s request for a Clean Water Act Section 401 water-quality certification and Jordan Lake Riparian Buffer Authorization, originally issued last year (OGJ Online, Aug. 11, 2020). MVP had appealed the 2020 denial to the US Court of Appeals for the Fourth Circuit.
In a Mar. 11 ruling, the Fourth Circuit upheld the state’s authority to determine that authorizing impacts from the Southgate extension at this time poses unnecessary risk to North Carolina’s streams, lakes, and wetlands. The Fourth Circuit only remanded the decision back to DWR to address certain statements made by the hearing officer and to “explain why the Department chose denial over conditional certification.”
The new denial reaffirmed DWR’s determination, concluding that a conditional approval would not provide reasonable assurance of compliance with water quality requirements.
MVP earlier this year received FERC permission to resume work on a limited portion of the main pipeline near Jefferson National Forest in Virginia. The pipeline is a joint venture of EQM Midstream Partners LP, NextEra Capital Holdings Inc., Con Edison Transmission Inc., WGL Midstream, and RGC Midstream LLC.
Equinor extends Hammerfest LNG restart timeline
Equinor has extended the estimated start-up of the Hammerfest LNG plant on Melkoya Island in northern Norway. The plant has been closed since a Sept. 28, 2020 fire on the air intake of one of its five gas turbines.
Based on analyses and mapping of damages, and due to the work scope and COVID-19 restrictions, the revised estimated start-up date is Mar. 31, 2022.
More than 70,000 unique equipment components were potentially exposed to seawater during the firefighting. The most time-consuming repair plan activity is replacement of more than 180 km of electric cables connected to the power station where the fire occurred, Equinor said. Ordered cables are expected to arrive this spring/summer.
Other components are being procured for delivery in this year’s summer/autumn timeframe. Several components, including compressors, must also be removed and sent to the supplier for repair.
Equinor’s internal investigation of the fire is ongoing.
Novatek completes 20-year Arctic LNG 2 sales
PAO Novatek joint venture OOO Arctic LNG 2 concluded 20-year LNG sales agreements with project participants for all anticipated production. Sales from the 19.8-million tonne/year (tpy) plant’s first 6.6-million tpy liquefaction train are expected to begin in 2023.
Agreements provide for LNG supplies on free-on-board (FOB) Murmansk and FOB Kamchatka bases, with pricing formulas linked to international oil and gas benchmarks. Offtake volumes are in proportion to participants’ ownership stakes.
Project participants include: Novatek (60%), Total SE (10%), China National Petroleum Corp. (10%), China National Offshore Oil Corp. Ltd. (10%), and the Japan Arctic LNG consortium of Mitsui & Co. Ltd. and Japan Oil, Gas and Metals National Corp. (10%).
Novatek will source gas from Utrenneye field in the northern part of the Gydan peninsula, Yamal-Nenets Autonomous District, on the shores of the Gulf of Ob. As of end-2020, Utrenneye’s 2P Petroleum Resources Management System reserves totaled 1.434 trillion cu m of natural gas and 90 million tons of liquids.