GENERAL INTEREST Quick Takes
EQT to buy Chevron Appalachia assets
EQT Corp. has agreed to acquire Appalachian basin upstream and midstream assets from Chevron USA Inc. for $735 million.
The assets have current net production of about 450 MMcfed (75% gas, 25% liquids) from 125,000 core net Marcellus acres with 335,000 total net Marcellus acres. About 100 wells are work-in-progress. Two water systems and associated infrastructure in Pennsylvania and West Virginia are included, as well as 31% ownership in Laurel Mountain Midstream.
The transaction is expected to close late in this year’s fourth quarter with effective date of July 1.
Equinor appoints Skeie acting CFO
Equinor ASA has appointed Svein Skeie to serve as acting executive vice-president and chief financial officer, effective Nov. 1, following the resignation of executive vice-president and chief financial officer Lars Christian Bacher. Bacher will remain employed with the company until May 31, 2021.
Skeie becomes a member of Equinor’s corporate executive committee, reporting to the chief executive officer.
Bacher joined Equinor in 1991. He had been the chief financial officer since August 2018 (OGJ Online, Apr. 27, 2018).
Skeie previously served as senior vice-president for chief financial officer performance management and control. He joined Equinor in 1996.
ExxonMobil to cut 1,900 jobs primarily from Houston
ExxonMobil plans to cut jobs in the United States that will primarily impact management offices in Houston, Tex., the company said Oct. 29. Some 1,900 employees will be affected through voluntary and involuntary programs.
The reductions are the result of ongoing reorganizations and work-process changes made over the past several years to improve efficiency and reduce costs, the company said Oct. 29. The actions will improve the company’s long-term cost competitiveness and ensure the company manages through the current unprecedented market conditions, the company said.
Employees separated through involuntary programs will be provided with support, including severance and outplacement services, the company said.
IPR acquires onshore Egypt assets from Dana Gas
IPR Energy Group (IPR) member IPR Wastani Petroleum Ltd. has agreed to acquire onshore Egyptian producing oil and gas assets from Dana Gas PJSC, Sharjah, UAE, for a consideration of up to $236 million including contingent payments.
Assets include Dana Gas’ 100% working interests in the El Manzala, West El Manzala, West El Qantara and North El Salhiya onshore concessions, operated through the WASCO JV, an operating joint venture with EGPC, as well as associated development leases. In first-half 2020, the concessions produced 30,950 boe/d.
Dana Gas Egypt will retain its interests in its onshore and offshore exploration concessions, respectively El Matariya (Block 3) and North El Arish (Block 6).
Terms of the deal include a base cash consideration of $153 million, including the net working capital associated with the assets and before any closing adjustments, and contingent payments of up to $83 million subject to average Brent prices and production performance between 2020-2023 as well as the realization of potential third party business opportunities.
With the acquisition of the DG assets, IPR will have 14 concessions including the current portfolio of 9 petroleum concessions in the Western Desert, Eastern Desert, Gulf of Suez, and Nile Delta. In March, the company acquired a 40% working interest in the Alamein concession increasing its operated position to 100%.
Subject to customary regulatory approvals, the Dana Gas deal is expected to close in early 2021.
Exploration & Development Quick Takes
Total discovers gas, condensate offshore South Africa
Total and partners will evaluate various development options to commercialize a new gas and condensate discovery in the Luiperd prospect, Block 11B/12B, Outeniqua basin, 175 km off the southern coast of South Africa, said partner Qatar Petroleum in an Oct. 28 release.
The discovery is the second of significance in the block. A gas-condensate discovery at the Brulpadda prospect was noted in February 2019 (OGJ Online, Feb. 7, 2019).
The Luiperd-1X well was drilled to a total depth of 3,400 m and encountered 73 m of net gas-condensate-bearing reservoir in Lower Cretaceous Paddavissie reservoirs (OGJ Online, Aug. 31, 2020).
Following a comprehensive coring and logging program the well will be tested to assess the dynamic reservoir characteristics and deliverability, Total said in a separate release Oct. 28.
The block, in Outeniqua basin 175 km off the southern coast, covers an area of some 19,000 sq km in water depths of 200-1,800 m. It is operated by Total with a 45% working interest, alongside Qatar Petroleum (25%), CNR International (20%) and Main Street (10%).
Empire finds liquids-rich gas in Beetaloo well
Empire Energy Group Ltd. intersected a thick interval of liquids-rich gas in its ongoing Carpentaria-1 well in Beetaloo basin permit EP187 in the Northern Territory.
The find was made in Velkerri shale at a depth shallower than expected.
Information about the liquids content in the gas and possible flow rates is unknown. Completion of a fracturing and testing program is set for second-quarter 2021.
The well targeted a potential 2.4 tcf of gas in two target shale zones – the Velkerri and the Kyalla. The Kyalla shale was not present at Carpentaria-1, but the company is pleased with the result as the presence of liquids will enhance the economics of any future production and the shallower depths to the Velkerri will reduce future development costs.
Empire, with 100% interest, will move to further appraise the Velkerri sequences with an extensive formation evaluation program.
Velkerri was intersected at 833-1,831m. Peak mudlog gas readings were encountered at 1,105-1,160 m, again at 1,320-1,372 m, and at 1,490-1,544 m.
Carpentaria-1 is now drilling ahead and is expected to reach a revised total depth of 2,200 m, some 700 m shallower than the pre-drill target TD.
Once reached, the program will revert to detailed logging, large diameter rotary sidewall coring and DFITs.
The well will then be cased, cemented, and suspended in preparation for re-entry and fracturing and testing programs following the 2021 wet season.
Petrobras delays Parque das Baleias first oil
Petróleo Brasileiro SA (Petrobras) has postponed the Campos basin Parque das Baleias integrated project by about 1 year and cancelled the FPSO charter bidding, granting the start of a new bidding process.
The operator, citing the economic context of COVID-19 in its decision, now expects first oil from the project in 2024.
Four FPSOs connected to 44 producing wells and 21 injectors are currently operating in the field cluster of Jubarte, Baleia Anã, Cachalote, Caxaréu, and Pirambú. In May, aggregate production from the area offshore Brazil reached 1 billion bbl.
In 2019, Petrobras invited tenders as part of a plan to install a fifth FPSO to be connected to 19 wells.
Drilling & Production Quick Takes
Wintershall granted Dvalin startup approval
Wintershall DEA Norge expects startup of Dvalin natural gas field in the Norwegian Sea in November-December. Startup approval from authorities has been granted, the Norwegian Petroleum Directorate said Oct. 21. The field, in PL435, is estimated to hold recoverable gas reserves of 18 billion standard cu m.
The field consists of two structures 3.5 km apart. Dvalin east was proven in 2010 and Dvalin west in 2012.
Development includes four vertical production wells—two in the east and two in the west. Drilling and completion started in August 2019 and is now complete (OGJ Online, Aug. 13, 2019). Production will be transported southeast to Heidrun field for further processing and export. Gas will be exported via the Polarled pipeline into Nyhamna in central Norway. Condensate will be routed to the existing process plant on Heidrun and onward via the Heidrun storage ship to tankers for further transport to an oil refinery.
Wintershall’s development investment projection is about 11 billion kroner.
Wintershall is operator of the license with 55%. Partners are Petoro AS 35% and Edison Norge AS 10%.
Norway production decreased in September
Norway’s daily liquids production averaged 1.772 million b/d in September, the Norwegian Petroleum Directorate reported. Norway’s daily liquids production averaged 2.019 million b/d in August.
On Apr. 29, the government decided to implement a cut in Norwegian oil production. The production figures for oil in September include this cut of 134,000 b/d in second-half 2020. Oil production in September was 13.8% lower than the NPD’s forecast, and 1.61% below the forecast so far this year.
The average daily liquids production in September included 1.486 million b/o, 268,000 bbl of NGL, and 18,000 bbl of condensate.
Lower September production is mainly due to maintenance work and technical problems on some fields, NPD said. Total petroleum production for the first 9 months of the year is about 170.4 million standard cu m oil equivalents.
CNOOC starts Bozhong 19-6 in Bohai
CNOOC Ltd. started production at Bozhong 19-6 condensate gas field pilot area development project in central Bohai (OGJ Online, Mar. 25, 2020).
A new wellhead platform has been built in about 23 m of water and will fully utilize existing processing facilities of Bozhong 13-1. Eight development wells (7 production and 1 water source) are planned for development. Expected peak production is about 35.32 MMcf of natural gas and 5,720 b/d of condensate by end 2020.
CNOOC holds 100% working interest in Bozhong 19-6 and is operator.
Neptune considers tie-in for minor Norwegian Sea discovery
Neptune Energy Norge AS will consider tying recent minor Norwegian Sea discoveries into existing infrastructure on Fenja field. Well 6406/12-G-1 H—the seventh in PL 586 and an extension of an observation well for 6406/12-3 A (Bue) oil discovery—was drilled 120 km north of Kristiansund by the West Phoenix drilling facility in 322 m of water.
The primary objective was to reduce resource estimate uncertainty. The secondary objective was to prove petroleum in Middle Jurassic reservoir rocks (sandstone in the lower part of the Melke formation).
The well was drilled to measured and vertical depths of 4,235 m and 3,695 m subsea, respectively. It terminated in the Melke formation. The well did not encounter reservoir rocks in either the primary or secondary target, but encountered a 38-m oil column just above the secondary target in the lower part of the Intra-Melke formation, of which about 20 m were moderate to good reservoir quality. The well will be temporarily plugged.
The Bue oil discovery was proven in 2014 in Upper Jurassic reservoir rocks (the Rogn formation) (OGJ Online, July 14, 2014). Before 6406/12-G-1 H was drilled on the discovery, resource estimate was 1-4 million standard cu m recoverable oil equivalent. That estimate has now been reduced to 0.2-1.6 million standard cu m, while the estimate for the new oil discovery is 0.5-3.2 million standard cu m.
The West Phoenix is headed to Ølen for a stay at the shipyard.
Neptune Energy is operator of PL 586 (30%) with partners Var Energy AS (45%), Suncor Energy AS (17.5%), and DNO Norge AS (7.5%).
PROCESSING Quick Takes
BP to close Kwinana oil refinery
BP will cease production from its Kwinana oil refinery south of Perth and convert the facility into a fuel import terminal.
Oversupply in Asia and sustained low refining margins have made the refinery uneconomical, and—after exploring numerous options—conversion to a fuel terminal is the best alternative, the company said.
Refining operations will be wound down over the next 6 months. First imports of fuel to the converted terminal are expected in first-half 2021.
In operation for 65 years, Kwinana is the only refinery on Australia’s west coast. Its closure leaves Australia with three remaining refineries – Ampol at Lytton in Brisbane, Queensland; ExxonMobil at Altona in Melbourne, Victoria; and Viva at Geelong in Victoria.
Of these, Ampol and Viva are conducting reviews about the future of their plants, having also suffered from falling demand and refining margins, exacerbated by the COVID-19 pandemic. ExxonMobil in September said its Altona facility had been under pressure, but no plan to review operations was announced.
The Australian government has expressed disappointment at BP’s decision after revealing in October a proposed $2.5 billion (Aus.) fuel security package that included measures to buffer against potential supply shocks and help keep refineries open where commercially possible. Under the plan, refiners will receive a direct payment of 1.15 cents (Aus.)/l. for locally made fuel.
Refiners warned the government that the measures may not be sufficient to support the viability of their businesses amid the unprecedented pressure caused by the pandemic-driven fuel oversupply.
Australia’s refining industry has been halved during the last decade with the closure of refineries in Sydney (Ampol and Shell), Brisbane (BP), and Adelaide (ExxonMobil).
Imperial commissions cogeneration unit at Strathcona refinery
Imperial Oil Ltd. has started operation of a newly constructed cogeneration unit to increase increasing energy efficiency and help reduce provincial greenhouse gas (GHG) emissions at its 191,000-b/d Strathcona refinery—the largest in western Canada—near Edmonton, Alta.
Capturing heat generated from the production of electricity that would normally go to waste and using it to produce steam for use in refining operations, the Strathcona cogeneration unit produces about 41 Mw/day of electricity to meet about 75-80% of the refinery’s power needs, greatly decreasing the site’s energy consumption from the Alberta grid, the operator said Oct. 28.
The unit also reduces province-wide GHG emissions by about 112,000 tpy, which is the equivalent of taking nearly 24,000 vehicles off the road annually, according to Imperial.
The Strathcona cogeneration unit is now Imperial’s third in Alberta, with cogeneration technology used at its Kearl and Cold Lake oil sands facilities, the two of which reduced GHG emissions by about 860,000 tonnes/year during 2019, or the equivalent of 186,000 fewer passenger vehicles on the road each year, the operator said.
Imperial said it also uses cogeneration at its 119,000-b/d refinery in Sarnia, Ont., and 113,000-b/d refinery in Nanticoke, Ont.
In a previous project update issued midway during project construction, Imperial said startup of the new Strathcona cogeneration unit also would allow the refinery to retire one of its four existing boilers.
PetroChina lets contract for Jinzhou, Jinxi refineries
PetroChina Co. Ltd.—the publicly listed arm of state-owned China National Petroleum Corp. (CNPC)—has let a contract to Chevron Lummus Global LLC (CLG)—a partnership of Chevron USA Inc. and Lummus Technology LLC—to license technology for atmospheric residuum desulfurization (RDS) units at subsidiaries Jinzhou Petrochemical Co.’s 130,500-b/d refinery in Guta District, Jinzhou City, and Jinxi Petrochemical Co.’s 130,500-b/d refinery in Huludao City, both in China’s province of Liaoning.
As part of the contract, CLG will supply its proprietary ISOMIX-e reactor internals for the refineries’ RDS units which, alongside allowing the PetroChina subsidiaries to maximize use of catalysts in their RDS reactors due to uniform process distribution and better product yield structure, also will enable safer operations with improved reactor temperature management to increase catalyst life and reduce turnaround times, the service provider said.
The contract comes as part of PetroChina’s project to install locally designed, identical RDS units—equipped with CLG’s internals in their reactors—at the two refineries, CLG told OGJ via e-mail on Oct. 30.
Use of the ISOMIX-e reactor internals will allow the refineries to improve product yields and achieve longer run times per catalyst fill.
Further details regarding the project—including a value of the contract or timeframe for its implementation—were not disclosed.
Keyera commissions Pipestone gas plant
Keyera Corp., Calgary, has started up its Pipestone natural gas processing and liquids stabilization plant located west of Grande Prairie, Alta.
Developed in joint effort with Ovintiv Inc. (formerly Encana Corp.) to support its condensate-focused Pipestone Montney development, the 200-MMcfd Pipestone gas plant—which also features 24,000-b/d of condensate processing and associated water-disposal installations—entered operation 5 months ahead of its original schedule and at budgeted costs on Oct. 13, Keyera said.
“This project aligns with Keyera’s strategy of building a stronger presence in the liquids-rich Montney development, which is one of the most economic developments in the Western Canada Sedimentary Basin,” said David Smith, Keyera’s chief executive officer.
With commissioning of the Pipestone plant, and including its existing Wapiti and Simonette gas plants, Keyera now has infrastructure in the area providing 950 MMcfd of gas processing capacity and 90,000 b/d of condensate processing capacity.
“In the future, this [processing] capacity will be connected to our [Key Access Pipeline System (KAPS)] natural gas liquids and condensate pipeline that we expect to have in service in 2023,” Smith said.
Keyera along with its partner, SemCAMS Midstream ULC, previously agreed to defer construction of the KAPS for 1 year, with all transportation agreements amended to align with the deferral (OGJ Online, May 13, 2020).
Designed to transport NGL from the Montney shale to Keyera’s liquids infrastructure in Fort Saskatchewan, Alta., KAPS will consist of a 16-in. OD pipeline for condensate and a 12-in. OD pipeline for NGL mix. The system will run from northwest of Grande Prairie to Keyera’s Fort Saskatchewan fractionation and storage site. KAPS will initially be connected to Keyera’s Pipestone, Wapiti, and Simonette gas plants and several third-party gas plants with volume commitments to KAPS. Shippers will also have direct access to Keyera’s condensate hub.
TRANSPORTATION Quick Takes
TC Energy to expand ANR gas pipeline system
TC Energy Corp. will develop the Wisconsin Access Project to increase natural gas capacity on a highly utilized segment of its ANR Pipeline system. The project will add about 72 MMcfd of firm transportation service under long-term contracts to utilities serving the midwestern US. All work will occur on ANR’s existing line in Wisconsin, Illinois, Iowa, Missouri, and Kansas.
The Wisconsin Access Project involves meter station upgrades, compressor station modifications for enhanced flexibility, and emissions-cutting horsepower replacements. The project is targeted to be brought in service second-half 2022 at a cost of $200 million.
Announcement of the Wisconsin Access Project follows TC Energy’s July 2020 sanctioning of the Elwood Power-ANR Horsepower Replacement Project, providing as much as 125 MMcfd of firm delivery to an existing power plant. Elwood is also expected to enter service second-half 2020.
Dakota Access expansion approved by Illinois
Energy Transfer LP has received approval from the Illinois Commerce Commission (ICC) to expand its 570,000-b/d Dakota Access crude oil pipeline to 1.1-million b/d. The ICC said the project would promote both security and convenience for the general public.
Energy Transfer expects to have the expansion complete by third-quarter 2021. Earlier in October, the company began work on a new pumping station in Emmons County, ND.
Both the approval and ETP’s planned schedule come despite on ongoing suit in US District Court for the District of Columbia attempting to force Dakota Access to cease operations while its environmental permitting is reviewed (OGJ Online, Aug. 27, 2020).
Dakota Access runs more than 1,000 miles from Bakken shale in North Dakota to a pipeline and refining hub at Patoka, Ill. Connections there take oil as far as the US Gulf Coast.
Enbridge Line 5 tunnel design 90% complete
Enbridge Inc. has completed about 90% of initial design work on its 4.5-mile Great Lakes Tunnel under the Straits of Mackinac in Michigan. The tunnel will house its 540,000-b/d Line 5 liquids pipeline.
The company expects to begin tunnel construction in 2021 for 2024 completion.
Enbridge received a favorable ruling from the Michigan Court of Appeals earlier this year allowing construction of the tunnel (OGJ Online, June 12, 2020).
Line 5 is a 645-mile, 30-in. OD pipeline crossing the Upper and Lower Peninsula’s of Michigan and the straits that separate them as it moves light crude oil, synthetic crude, and NGL from Superior, Wisc., to Sarnia, Ontario, Canada. The line splits into two 20-in. pipes for the crossing between the peninsulas.