GENERAL INTEREST Quick Takes
Whiting, Oasis to merge
Whiting Petroleum Corp. and Oasis Petroleum Inc. have agreed to merge to create an oil producer with a Williston basin acreage position of 972,000 net acres across North Dakota and Montana and combined fourth-quarter 2021 production of 167,800 boe/d (3-stream, 97,300 b/d oil).
The combine will be based in Houston, retain an office in Denver “for the foreseeable future,” and will operate under a new name, yet to be disclosed. Lynn Peterson, Whiting’s president and chief executive officer, will serve as executive chair of the board of the combined company. Danny Brown, Oasis’ chief executive officer, will serve as president and chief executive officer and as a member of the board.
In 2022, the combine expects to produce 164,000-169,000 boe/d and generate $1.2 billion of free cash flow and a reinvestment rate below 40% at $85/bbl WTI and $3.50/MMbtu NYMEX gas with investment of $655-695 million. The combine plans to run four rigs and target 108-110 gross operated well completions with a focus on South Nesson, Sanish, Indian Hills/City of Williston, FBIR, Foreman Butte, and Cassandra areas.
Administrative and operational cost synergies of $65 million on an annual basis are expected by second-half 2023.
Upon closing, expected in second-half 2022, the board of directors will consist of 10 directors, comprising four independent directors from the current Whiting board, as well as Peterson, and four independent directors from the current Oasis board, along with Brown.
The remainder of the company’s leadership team includes Michael Lou, Oasis’ chief financial officer, Chip Rimer, Whiting’s chief operating officer, and Scott Regan, Whiting’s general council, who will serve in their respective capacities in the combined company.
Under terms of the agreement, Whiting shareholders will receive 0.5774 shares of Oasis common stock and $6.25 in cash for each share of Whiting common stock owned. Oasis shareholders will receive a special dividend of $15.00/share. The combined company will have an enterprise value of about $6.0 billion. Whiting shareholders will own about 53% and Oasis shareholders will own about 47% of the combined company on a fully diluted basis.
Wintershall to write off Nord Stream 2 financing, will cease additional projects in Russia
Wintershall Dea will not advance or implement any additional gas and oil production projects in Russia and will write off its financing of Nord Stream 2 totaling around 1 billion euros, in response to the war in Ukraine.
In April 2017, Nord Stream 2 AG signed the financing agreements for the Nord Stream 2 gas pipeline project with ENGIE, OMV, Royal Dutch Shell, Uniper, and Wintershall for long-term financing of 50% of the total cost of the project. The viability of the 55-billion cu m/year natural gas pipeline, and the operating company, are now in question. Payments to Russia have ceased, Wintershall said.
The company remains active in GASCADE Gastransport GmbH. GASCADE operates a 3,200-km gas pipeline network in Germany. The European infrastructure is connected to the major European transit lines from Russia and the North Sea.
It also remains involved in the existing Yuzhno Russkoye and Achimov natural gas production projects in Siberia. The projects produce natural gas for European energy supply, the company said.
Yuzhno-Russkoye field was discovered in 1969 and is one of the largest in Russia. The Severneftegazprom joint venture started to operate the field in 2007 and has been producing around 25 billion cu m/year of natural gas at plateau level since 2009. Wintershall holds a 35% interest in the economic success of the field, with Gazprom as the lead project partner. Natural gas is produced from the reservoir’s Cenomanian layer. To extend the life cycle of the field and secure the production plateau for several years, Severneftegazprom is developing the Turonian deposits. The first Turonian well clusters of the full field development came on stream in 2020 and acceleration is ongoing (OGJ Online, Jan. 20, 2022).
The Achim development joint venture was founded for the further field development of the Achimov formations. The joint venture with Gazprom, in which Wintershall Dea has a 25.01% stake, is developing Area 4A/5A of Urengoyskoye field. The first development phase started in 2018. In early 2021, Achim development started commissioning of Area 4A/5A and produced first gas and gas condensate from the license block.
ExxonMobil to cease operations at Sakhalin-1, make no new investments in Russia
ExxonMobil said it plans to discontinue operations at Sakhalin-1 in northeastern Russia and will develop steps to exit the venture in response to Russian military action in Ukraine. The company said it is fully complying with all sanctions and will not invest in new developments in Russia given the current situation, it said in a release Mar. 1. Statements from partners were not made prior to press time.
Exxon Neftegas Ltd., an ExxonMobil Corp. (USA) subsidiary, is operator of Sakhalin-1 project with 30% stake. As such, the process to discontinue operations will need to be carefully managed and closely coordinated with the co-venturers to ensure it is executed safely, the company said.
The first Sakhalin-1 production wells were drilled at the offshore Chayvo field in 2003 and early oil production began in 2005. In 2010, Odoptu field was put on stream, and 5 years later first oil flowed from the Berkut platform in Arkutun-Dagi field (OGJ Online, Jan. 19, 2015). Currently, all the Sakhalin-1 license blocks are producing. Planned peak production of 34,000 tonnes/day was achieved in 2007 (OGJ Online, Feb. 22, 2007). Sakhalin-1 reached a new peak of 41,000 tonnes/day in 2018.
Project partners are two Rosneft affiliates: RN-Astra (8.5%) and Sakhalinmorneftegaz-Shelf (11.5%), the Japanese SODECO Consortium (30%), and India’s ONGC Videsh Ltd. (20%).
Exploration & Development Quick Takes
TotalEnergies lets contract for Tilenga onshore oil development in Uganda
TotalEnergies has let a service contract to Schlumberger for drilling, completions, and production services for the Tilenga onshore oil development in Uganda.
The scope of the contract includes the provision of directional drilling services, upper completions, lower completions, artificial lift solutions, and wellheads for the development, which comprises six fields, which will be developed across 31 well pads connected to a 190,000-b/d central processing facility in Kasenyi, Uganda. A planned 426 wells will be in use at full production: 200 water-injection wells, 196 production wells, two polymer-pilot wells, and 28 reference wells (OGJ Online, June 11, 2021).
Final investment decision on the project was made in February 2022 (OGJ Online, Feb. 1, 2022).
Drilling activities are expected to begin in in this year’s fourth quarter.
Energean connects Karish field to Israel’s gas network
Energean plc has connected Karish gas field to the Israel National Gas Line (INGL), moving the project close to first gas, expected mid-2022. Once onstream, the Mediterranean Sea field offshore Israel will produce and provide natural gas to Israel and, in time, the wider Eastern Mediterranean region, the company said in a Mar. 2 release.
The connection between Energean’s land-based system at Dor Beach in northern Israel and the INGL delivery system was completed by welding together two 30-in. diameter pipe sections. Gas from Karish field will flow to the Energean Power FPSO 90 km offshore where production output will be processed and separated. Treated gas will be delivered from an underwater pipeline to the system at the Dor Station before entering the national pipeline.
In August 2020, the company progressed development with FPSO work with installation of mooring lines.
Capital expenditure for the Karish development is estimated at $1.7 billion.
Emperor seismic analysis could add to Judith field reserves
Emperor Energy Ltd., Sydney, said new amplitude versus offset (AVO) analysis of Kipper and Golden Beach sands overlying its Judith gas field in permit Vic/P47 in Bass Strait indicates the potential for additional gas play across the permit and the field.
Analysis was carried out with new fully processed 3D seismic data run on the two potential reservoir sands that lie above the Judith gas sands that currently comprise Judith field prospective resources.
Results indicated strong AVO response in the Kipper sand as well as three zones within the Golden Beach sands.
The results correlate against reservoir gas in the nearby ExxonMobil-operated Kipper-1 well where the Kipper and Golden Beach sands are the principal reservoirs in Kipper field.
Initial calculations of rock volumes indicate the four intervals have the potential to contain significant gas in place to add to the existing P50 unrisked prospective gas resource of 1.226 tcf within the permit area, Emperor said.
The company is now working on new gas in place calculations prior to upgrading prospective resources.
Emperor’s focus is the development of Judith field 40 km offshore from the Orbost gas plant in eastern Victoria. The objective is to establish a sales gas capacity of 80 terajoules/day (28 petajoules/year) over a minimum of 15 years.
Drilling & Production Quick Takes
Repsol Norge to extend Blane field production
Repsol Norge has been granted consent by the Petroleum Safety Authority Norway for life extension of Blane field. The field is part of production license (PL) 143 BS, 35 km southwest of Ula field in the southern part of the Norwegian sector of the North Sea in 70 m of water.
The license, previously valid until this year’s fourth quarter, had been extended to July 8, 2027. Until 2019, the field was produced with pressure support from injection of produced water from Blane, Tambar, and Ula fields. It is now produced by pressure depletion. Gas lift is also used.
Blane produces from Paleocene sandstone in the Forties formation. The reservoir is of moderate to good quality and lies at a depth of 3,100 m. The well stream is transported by pipeline to Aker BP-operated Ula field for processing, and oil is exported further to Teesside in the UK.
Equinor spuds Kveikje exploration well
Equinor Energy AS has started drilling operations on Kveikje exploration well 35/10-8S in Block 35/10 in the Norwegian North Sea.
The well is being drilled by the Deepsea Stavanger semisubmersible drilling rig in production license (PL) 293B, north of Troll field, about 8 km from the Swisher discovery, and about 10 km from the Toppand discovery (OGJ Online, Feb. 7, 2022).
The prospect is an Eocene Balder formation injectite with seismic amplitude support. Injectite reservoirs are typically characterized by excellent reservoir properties, with recent exploration successes of this type including the King and Frosk discoveries in the Balder and Alvheim area, respectively. The exploration well has further potential upside in the underlying Paleocene Rokke and Late Cretaceous n’Roll secondary prospects.
Drilling is expected to take up to 4 weeks. If successful, Kveikje could potentially form part of an area cluster development.
Kveikje is estimated to contain gross mean prospective resources of 36 MMboe with further potential upside estimated at 79 MMboe on a gross basis. The chance of success is 55% with key risks being trap presence and seal integrity.
Rokke and n’Roll have an additional 127 MMboe gross mean prospective resource with chances of success around 14-34% based on operator estimates.
Equinor is operator at PL 293B (51%) with partners DNO Norge AS (29%), INPEX Idemitsu Norge AS (10%), and Longboat Energy Norge AS (10%).
SilverBow plans 15% year-over-year production growth in 2022
SilverBow Resources Inc., Houston, plans to increase South Texas Eagle Ford and Austin Chalk drilling in 2022 with a capital budget of $180-200 million (some 92% allocated to drilling and completion activity).
The budget provides for 39 gross (33 net) operated wells drilled, compared to 20 gross (18 net) operated wells drilled in 2021. The company intends to run one full rig in 2022, as compared to a 3/4 rig average in 2021, which supports production growth of about 15% year-over-year while maintaining a re-investment rate of about 70%.
In first-quarter 2022, SilverBow completed one La Mesa Austin Chalk well and is currently completing an eight-well La Mesa pad which is expected to come online in the second quarter. After drilling the La Mesa pad, the company’s drilling rig will shift to its liquids-weighted assets which is expected to encompass 14 net wells.
About half of the liquids wells to be drilled are a result of new areas and more contiguous acreage positions acquired by SilverBow in 2021. During the third quarter, the company intends to return to its Webb County Gas area and drill its gas-weighted assets through yearend.
For first-quarter 2022, SilverBow is estimating production of 220-232 MMcfed, with gas volumes of 167-177 MMcfd.
For full-year 2022, the company expects production of 235-255 MMcfed, with gas volumes of 180-195 MMcfd.
During fourth-quarter 2021, SilverBow completed and brought online five net wells and had net production of 250 MMcfed (74% natural gas). For the full year, the company drilled 18 net wells, completed 24 net wells, and brought 24 net wells online.
The company had net income of $114 million for fourth-quarter 2021 and full-year 2021 net income of $87 million.
The company holds about 153,000 net acres in the Eagle Ford with an average 81% average working interest, with increased scale from 2021 acquisitions.
ConocoPhillips granted Norwegian Sea drilling permit
ConocoPhillips has been granted a drilling permit for Norwegian Sea exploration by the Norwegian Petroleum Directorate.
ConocoPhillips Skandinavia AS, as operator, will drill exploration well 6507/5-11 in PL 891 in March using the Transocean Norge semisubmersible drilling rig.
ConocoPhillips holds 80% interest in the license. Pandion Energy AS holds the remaining 20%.
In December 2020, the operator drilled discovered oil in the license on the Slagugle prospect with well 6507/5-10, 14 miles north-northeast of Heidrun field. Preliminary estimates of the discovery’s size are between 75 million and 200 million boe recoverable.
PROCESSING Quick Takes
Chinese operator lets contract for proposed SAF production plant
Oriental Energy Co. Ltd. has let a contract to Honeywell UOP LLC to license process technology for a grassroots sustainable aviation fuel (SAF) production plant the operator will build in Maoming, Guangdong Province, China.
Alongside licensing of its UOP-Eni SPA codeveloped proprietary Ecofining process, Honeywell UOP’ also will provide engineering services, catalysts, proprietary equipment, startup services, and training for the newly proposed plant that will produce 1 million tonnes/year of SAF, the service provider said.
Intended to help Oriental Energy meet rising SAF demand as well as support China’s goals of reducing carbon dioxide (CO2) emissions to achieve carbon neutrality by 2060, the two-unit SAF plant will be built in two phases, with each phase to include construction of one UOP Ecofining unit to enable production of SAF from a feedstock of used cooking oils and animal fats.
Slated to become one of the world’s largest sites for SAF production using cooking oil and animal fat feeds upon startup, the new plant will produce Honeywell Green Jet Fuel, a renewable jet fuel that can be seamlessly blended up to a 50% blend with petroleum-based jet fuel without requiring any changes to aircraft technology and meeting all critical specifications for flight.
Upon reaching full production capacity, Oriental Energy’s use of used cooking oils and animal fats feedstocks—which help to reduce lifecycle greenhouse gas (GHG) emissions by about 80% compared with traditional fuels—will result in a 2.4-million tpy reduction in lifecycle GHGs, according to Honeywell UOP.
Further details regarding a timeline for the proposed Maoming SAF plant or contract award were not disclosed.
This latest contract for the Maoming production site follows a December 2021 award by Oriental Energy—one of China’s leading propylene producers and LPG distributors—to W.R. Grace & Co. for licensing of the service provider’s proprietary Unipol polypropylene (PP) process technology to outfit a new 400,000-tpy PP line the operator plans to build at Maoming, according to a Dec. 7, 2021, release from Grace.
Par Pacific’s Kapolei refinery suspends Russian crude imports
Par Pacific Holdings Inc. has temporarily halted purchases and imports of Russian crude oil for subsidiary Par Hawaii Refining LLC’s 94,000-b/sd Par East refinery—Hawaii’s only—in Kapolei, on the island of Oahu, in response to Russian military action in Ukraine.
“[Par Pacific] recognizes its important role in Hawaii’s energy security. We intentionally diversify our crude oil sources from locations around the globe to enable us to meet the state’s ongoing demand for fuels. However, in light of recent geopolitical events, we have decided to suspend purchases of Russian crude oil for our Hawaii refinery,” the company said in a Mar. 3 statement.
Acknowledging the rapidly changing nature of both the geopolitical landscape and energy markets, the operator did not commit to permanently discontinuing Russian imports into the refinery but will instead monitor and evaluate its posture crude supplies from the region in the coming weeks and months.
During the provisional ban on Russian crude deliveries, Par Pacific said the Par East refinery will seek replacement crude options from destinations primarily in North and South America to meet its fuel production requirements.
According to the latest company-level crude oil import data made available by the US Energy Information Administration for the month ending December 2021, the Par Pacific Kapolei refinery received at least one shipment of Russian crude from August-December 2021:
- August—One shipment; 704,000 bbl.
- September—Two shipments; 945,000 bbl total.
- October—One shipment; 700,000 bbl.
- November—One shipment; 706,000 bbl.
- December—One shipment; 705,000 bbl.
Based on its location in the central Pacific Ocean and equipped with its own offshore mooring terminal, the Kapolei refinery is positioned to source a variety of crude oil imports via tanker delivery from producers in North America, the Asia Pacific, Latin America, Africa, the Middle East, as well as Russia.
Viva lodges Geelong LNG terminal EES
Viva Energy has lodged an environment effect statement (EES) for its proposed LNG reception terminal at the former Shell oil refinery in Geelong 50 km west of Melbourne for public comment.
The project is the first stage in Viva’s vision to convert the refinery into an energy hub for Victoria and eastern Australia.
Viva estimates construction and commissioning of the LNG terminal will take up to 18 months, while the project is anticipated to operate for 20 years.
The plan involves importing up to 160 petajoules/year of gas via LNG from other parts of Australia and overseas which will then be regassified and sent into the Victorian grid.
Construction includes localized dredging at the refinery pier in Corio Bay to allow sufficient depth for new berthing facilities and for a turning circle for incoming LNG carriers.
It also will include excavation of a shallow trench in the seabed for the seawater transfer pipe from the pier to the refinery seawater intake, as well as construction of the refinery pier extension and supporting infrastructure.
Other work includes installation of a 3 km aboveground gas pipeline and a treatment facility within the refinery boundary, and the trenching and installation of a 4 km underground gas transmission pipeline to connect to the existing southwest gas pipeline that runs through to the Otway basin and South Australia as part of the Victorian gas network.
Regasification will be via a floating storage and regasification unit (FSRU) that will be built and commissioned elsewhere and brought to the site intact.
The project is expected to operate 24 hr/day and up to 45 LNG carriers/year will berth and offload at the FSRU.
The EES is open for public comment until Apr. 11.
ExxonMobil considers hydrogen-CCS project for Baytown integrated project
ExxonMobil Corp. plans to add a grassroots hydrogen production plant and carbon capture and storage (CCS) project at its 561,000-b/d integrated refining and petrochemical complex in Baytown, Tex.
The proposed Baytown hydrogen plant would be equipped to produce up to 1 bcfd of blue hydrogen, or hydrogen produced natural gas and supported by CCS, ExxonMobil said in early March.
Related CCS infrastructure to be built as part of the project would give the complex the capability to transport and store up to 10 million tonnes/year (tpy) of CO2, more than doubling the company’s current CCS capacity, the operator said.
Use of hydrogen produced by the planned project as a fuel at the Baytown olefins plant could reduce the integrated complex’s CO2 emissions as defined by Scope 1 and Scope 2 of the Greenhouse Gas (GHG) Protocol Corporate Accounting and Reporting Standard by up to 30%, supporting ExxonMobil’s ambition to achieve net-zero GHG emissions from operated assets by 2050, according to the company.
ExxonMobil said the project also would enable the complex to make access to surplus hydrogen and CO2 storage capacity from the project available to nearby industry.
The Baytown project would form ExxonMobil’s initial contribution to a broad, cross-industry effort to establish a Houston CCS hub with an initial target of about 50 million tpy of CO2 by 2030, and 100 million tpy by 2040, according to the operator.
ExxonMobil said it expects to reach final investment decision on the proposed project in 2-3 years subject to stakeholder support, regulatory permitting, and market conditions.
The company said it currently produces about 1.5 bcfd of hydrogen and holds an equity share of nearly one-fifth of the world’s CCS capacity, which amounts to about 9 million tpy.
TRANSPORTATION Quick Takes
Germany accelerates LNG terminal plans
Germany will accelerate plans to build two LNG terminals. The terminals will be sited in Brunsbuttel (8 million tonne/year (tpy)) and Wilhelmshaven (7 million tpy). Chancellor Olaf Scholz announced the move in an address to the German Bundestag.
German LNG Terminal GmbH will build the terminal at Brunsbüttel. It will include a jetty with two berths for ships up to Q-Max size (266,000 cu m), distribution infrastructure for trucks, rail tank cars, and smaller ships, and two 165,000-cu m storage tanks.
Uniper SE in 2021 said it would repurpose its planned LNG terminal at Wilhelmshaven to hydrogen, under the name Green Wilhelmshaven. The changed natural gas supply dynamics on the European continent have altered these plans.
Scholz addressed this change in plans during his Feb. 27 remarks to the German Bundestag, noting that “an LNG terminal that today receives gas can tomorrow be used to import green hydrogen.”
In late February, Germany stopped the certification process for the Nord Stream 2 gas pipeline from Russia in response to its Feb. 24 invasion of Ukraine. Scholz opened his statement by describing the act as “a watershed in the history of our continent. With the attack on Ukraine, the Russian President Putin has started a war of aggression in cold blood.”
Nord Stream 2 is mechanically complete and filled with gas but was awaiting certification to begin deliveries.
Cheniere lets EPC contract for Corpus Christi Stage III project
Cheniere Energy Inc. subsidiary Cheniere Corpus Christi Liquefaction Stage III LLC (CCL Stage III) has let a lump sum, turnkey, engineering, procurement and construction (EPC) contract with Bechtel for the Corpus Christi Stage III project. CCL Stage III has released Bechtel to begin early engineering, procurement, and other site work at the project under a limited notice to proceed.
The Corpus Christi Stage III project is a fully permitted project consisting of up to seven midscale trains, each with an expected liquefaction capacity of about 1.49 million tonnes/year (tpy) with a total production capacity over 10 million tpy, bringing Corpus Christi LNG’s total capacity to 25 million tpy.
The work advances the LNG project toward final investment decision (FID), expected this summer, said Jack Fusco, Cheniere’s president and chief executive officer in a Mar. 7 release. The project is expected to begin providing customers with LNG starting in 2025, he continued.
Energy Transfer sells Canadian midstream assets to Pembina-KKR joint venture
Energy Transfer LP is selling its 51% interest in Energy Transfer Canada (ETC) ULC to a joint venture which includes Pembina Pipeline Corp. and global infrastructure funds managed by KKR & Co. Inc. ETC’s assets include six natural gas processing plants a combined operating capacity of 1.29 bcfd and an 848-mile natural gas gathering and transportation network in Western Canadian Sedimentary basin.
Pembina and KKR will combine their western Canadian natural gas processing assets into a single, new joint venture entity (Newco), owned 60% by Pembina and 40% by KKR’s funds. Pembina will serve as operator and manager of Newco. Included in the assets are Pembina’s field-based natural gas processing, the Veresen Midstream business (currently owned 55% by funds managed by KKR and 45% by Pembina), and the business acquired from ETC, already owned 49% by KKR funds.
Pembina’s field-based gas processing assets subject to the deal include the 360-MMcfd Cutbank complex in west-central Alberta, the 200-MMcfd Saturn complex in northern Alberta, the 300-MMcfd Resthaven plant, the 200-MMcfd Duvernay complex, and the 5,000-b/d Saskatchewan ethane extraction plant, as well as its 45% interest in Veresen Midstream.
Pembina’s Empress, Younger, and Burstall assets will be excluded from the transaction and Pembina will retain its current ownership position.
Collectively, the ascribed value of these transactions is $11.4 billion, excluding the value of assets under construction related to Newco’s 50%, non-operated interest in the Key Access Pipeline System (KAPS). Following closings, Pembina and KKR intend to dispose of Newco’s non-operated interest in KAPS, subject to receiving acceptable purchase terms. Energy Transfer’s stake in ETC was valued at $1.3 billion, including debt and preferred equity.
The contribution of Pembina’s and KKR’s assets to Newco, and Newco’s acquisition of 51% of ETC from Energy Transfer, are cross-conditional and will occur concurrently. Closing is expected by third-quarter 2022.