OGJ Newsletter
GENERAL INTEREST Quick Takes
Court nixes challenge to Alberta export bill
The government of British Columbia has received a setback to its challenge of legislation that would empower the Alberta energy minister to require licenses for the transport of energy away from the province (OGJ Online, May 23, 2018).
Because the bill has not become law, BC’s claim is “premature and inappropriate for consideration by the court,” a Calgary justice ruled.
The Alberta General Assembly passed the legislation last May in response to BC opposition to the expansion by Kinder Morgan of the Trans Mountain Pipeline between Edmonton and Burnaby, BC. Since then, the Canadian government has acquired the Trans Mountain system and expansion project.
Targa divests Badlands assets for $1.6 billion
Targa Resources Corp., Houston, agreed to sell a 45% interest in Targa Badlands LLC, the entity that holds Targa’s North Dakota oil and gas assets, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities for $1.6 billion in cash. Targa will continue to operate and hold majority rights.
The Badlands assets and operations, in the Bakken and Three Forks shale plays of the Williston basin, include some 480 miles of oil gathering pipelines, 125,000 bbl of operational oil storage, about 260 miles of gas gathering pipelines, and the Little Missouri gas processing plant with a current gross processing capacity of 90 MMcfd. Additionally, Badlands owns a 50% interest in the 200 MMcfd Little Missouri 4 Plant anticipated to be completed in this year’s second quarter.
Future growth capital is expected to be funded on a pro rata basis. Badlands will pay a minimum quarterly distribution to Blackstone and to Targa based on their initial investments, and Blackstone’s capital contributions will have a liquidation preference upon a sale of Badlands.
RockRose Energy to buy Marathon Oil’s UK business
Marathon Oil Corp. will exit the UK with a sale of its UK businesses Marathon Oil UK LLC (MOUK) and Marathon Oil West of Shetland Ltd. (MOWOS) to RockRose Energy PLC to further concentrate on its high margin, high return US resource plays.
MOUK holds a 37-40% operated interest in fields in the Greater Brae Area, and MOWOS holds a 28% interest in the BP PLC-operated Foinaven field unit and 47% in Foinaven East. The deal includes interests in the SAGE, Brae-Forties, and WASPS infrastructure. At yearend 2018, Marathon Oil carried 21.4 million boe of proved reserves in the UK. Anticipated production is 13,000 boe/d in 2019, taking RockRose’s total net anticipated production to 24,000 boe/d for the year.
Subject to adjustments, closing consideration payable to Marathon Oil will be $140 million, which reflects the assumption by RockRose of MOUK and MOWOS working capital and cash equivalent balances of some $350 million as of Dec. 31, 2018.
The MOUK and MOWOS assets and teams in Aberdeen, Peterhea, and offshore will transfer with MOUK and MOWOS to RockRose upon the deal’s completion—expected in this year’s second half with an effective date of Jan. 1.
Devon to shed assets, focus on US oil
Devon Energy Corp. plans by yearend to sell or spin off its heavy oil properties in Canada and gas production in the Barnett shale to focus on US oil. The company has hired advisors for each group of assets to be separated. It will open data rooms by this year’s second quarter.
In Canada, Devon in 2017 produced 131,000 boe/d net to its interests (98% liquids) via steam-assisted gravity drainage in the Athabasca region of Alberta and cold flow in Saskatchewan.
Its average 2017 net production from the Barnett shale of North Texas was 153,000 boe/d, of which 27% was liquids.
The moves will help Devon meet a cost-cutting target of at least $780 million/year by 2021. Concentrating on US oil, Devon expects to achieve growth of 13-18% in 2019 with 10% less upstream capital than in 2018, self-funded at an oil price of $46/bbl if service and supply prices don’t increase.
The company’s core properties in the Delaware basin and Eagle Ford play of Texas, STACK play in Oklahoma, and Powder River basin of Wyoming produced an average 296,000 boe/d of oil and gas in the fourth quarter last year.
QEP reviews options after Williston deal falls through
QEP Resources Inc., Denver, has started a comprehensive review of strategic alternatives that could result in a merger or sale of the company or its assets and intends to engage in discussions with parties that have expressed interest, including Elliott Management Corp. The hedge fund manager made an unsolicited cash offer to buy QEP for $8.75/share in January.
Also, given the deterioration in commodity prices, QEP said that it was unlikely to meet conditions to close the $1.7-billion deal to sell its Willison basin assets to Vantage Acquisition Operating Co. LLC and the parties agreed to terminate the transaction (OGJ Online, Nov. 7, 2018). QEP will continue to operate and develop the assets consisting of more than 100,000 net acres currently producing 46,000 boe/d (67% oil, 83% liquids), including the company’s South Antelope and Fort Berthold leaseholds.
As the firm has reduced its operational footprint over the last year, QEP said it intends to reduce its general and administrative expense by about 45%, when comparing 2018 to 2020.
Netherlands becomes a net gas importer
The Netherlands became a net importer of natural gas last year for the first time since the commissioning in 1963 of giant Groningen gas field, production of which is being phased out by the government. GasTerra, which markets Groningen gas for NAM, the ExxonMobil-Shell joint venture that operates the field, reported the shift in Dutch gas trade in a financial report.
GasTerra said NAM produced 20.1 billion cu m of gas from Groningen in 2018, 1.5 billion cu m below a ceiling set by the government, which began limiting output several years ago because of earthquakes (OGJ Online, Feb. 18, 2015). The government last year called for the termination of Groningen output.
“Safety perception as well as actual safety can only be guaranteed for the near future in Groningen by fully eliminating the source of the earthquake risk,” it said in a March 2018 announcement. It set an output cap of 12 billion cu m in 2022, to be followed by a phaseout of Groningen production.
Exploration & DevelopmentQuick Takes
ExxonMobil makes gas discovery offshore Cyprus
ExxonMobil Corp. announced a natural gas discovery offshore Cyprus in the Eastern Mediterranean on Block 10. The Glaucus-1 well cut 436 ft of reservoir rock. Evaluation of the potential of Block 10 continues. The well was drilled to 13,780 ft in 6,769 ft of water. ExxonMobil said preliminary interpretation of the well data indicates gas resources of 5-8 tcf although additional analysis will determine resource potential.
Glaucus-1 was the second well drilled on Block 10. The first well, Delphyne-1, did not encounter commercial quantities of hydrocarbons. Block 10 covers 635,554 acres. ExxonMobil Exploration & Production Cyprus (Offshore) Ltd. operates the block with 60% interest. Qatar Petroleum International Upstream holds the remaining interest.
Official: Thai licensing round due in June
Thailand will open its 21st round of bidding for offshore oil and gas licenses in June, according to Energy Minister Siri Jirapongphan. The official said terms will be production-sharing with 25% ownership reserved for Thai state enterprises, the Bangkok Post reported.
Jirapongphan spoke at the signing by PTTEP Energy Development Co. Ltd. of PSCs covering Erawan and Bongkot natural gas fields in the Gulf of Thailand.
Those contracts became available as concession expirations approached for Erawan in 2022 and Bongkot in 2023 (OGJ Online, Dec. 14, 2018).
PTTEP is the current Bongkot operator and will be sole stakeholder. It will replace a Chevron Corp. subsidiary as Erawan operator with a 60% interest. Mubadala Petroleum holds the remaining Erawan interest.
The Thai company has committed to holding production at 800 MMcfd at Erawan and 700 MMcfd at Bongkot.
The 21st licensing round had been scheduled in 2014 but was delayed by an economic lull and political instability.
Thailand closed its 20th licensing round in 2008.
Contracts let for gas fields off Sarawak
Sarawak Shell Bhd. and Sapura Exploration & Production have let contracts to McDermott for work related to the linked development of three natural gas fields offshore Malaysia.
The Shell unit’s contract covers transportation and installation of jackets, topsides, and pipelines for Gorek field. The Sapura contract is for the same work for Larak and Bakong fields. McDermott also will fabricate risers and spools under both contracts.
The fields are on the 4,400-sq-km SK408 production-sharing contract area in the Central Luconia Gas Province in shallow water off Sarawak. The area is 130 km northwest of Miri.
Each field will have a wellhead platform tied back to an existing processing facility.
Shell, with a 30% interest in the PSC, is development and production operator for Gorek field. Sapura, with 40%, is development and production operator for Larak and Bakong fields. Petronas Carigali holds the remaining SK408 interest.
Sapura discovered the fields in Late Miocene carbonate build-ups during a drilling campaign that began in 2014.
Drilling & ProductionQuick Takes
Woodside-led group lets Senegal SNE field contract
The Woodside Energy Ltd.-operated development phase of the SNE oil field offshore Senegal has let the front-end engineering and design contract for the floating production, storage, and offloading facility to MODEC International Inc.
This follows award of the subsea FEED scope to Subsea Integration Alliance last December. Woodside said that following FEED and subject to necessary government and joint venture approvals, it anticipated that further contracts will be awarded to MODEC to supply, charter, and operate the FPSO facility.
CEO Peter Coleman said securing an FPSO facility is a huge step for the joint venture and will allow the project team to complete the technical and commercial activities required to support a final investment decision, targeted for midyear.
The development concept is a stand-alone FPSO facility with 23 subsea wells comprising 11 producers, 10 water injectors, and 2 gas injectors plus supporting subsea infrastructure.
The FPSO is expected to have a capacity of about 100,000 b/d to be brought on stream in 2022.
The FPSO will be designed to allow for the integration of subsequent SNE development phases, including gas export to shore and future subsea tie-backs from other reservoirs and fields.
Phase 1 of the SNE development is targeting an estimated 230 million bbl of oil reserves.
Equinor lets contract to boost Vigdis field output
Norway’s Equinor has let a $13-million engineering, procurement, construction, and installation contract to Wood for the boosting station to increase production from Vigdis subsea field in the Tampen area on Block 34/7 in the Norwegian North Sea.
Under the contract, Wood will provide topside modifications to enable the tie-in of subsea equipment to the Snorre A and B offshore platforms, which process oil from Vigdis.
This contract follows Wood’s completion of the front-end engineering design and concept study for the asset. Wood currently provides maintenance, modification, and operations services on Snorre A and B under a framework agreement with Equinor.
In late 2018 Equinor and its partners reported plans to invest some 1.4 billion kroner in the boosting station for the field, which has been producing oil through Snorre field for more than 20 years (OGJ Online, Dec. 5, 2018). Equinor expects to bring the station online in first-quarter 2021.
On completion of the project, production from Vigdis field will be increased by almost 11 million bbl.
Vigdis field came on stream in 1997 and it was estimated at the time that the field would produce 200 million bbl of oil. The field has now produced 394 million bbl and recoverable resources have been increased to 455 million bbl of oil.
Neptune plans Gjoa tie-back developments
Neptune Energy and partners plan to develop in parallel Duva oil and gas field and an extension designated P1 of Gjoa oil and gas field in the Norwegian North Sea with subsea completions tied back to the Gjoa platform on PL153 (OGJ Online, Oct. 2, 2019).
Neptune Energy Norge operates both fields, where water depth is about 360 m.
It seeks to develop Gjoa P1 under the plan for development and operation (PDO) covering the Gjoa license, for which it is operator, as a northern extension. Neptune said in a news release it plans to install a subsea template but didn’t specify drilling. An image with the news release indicates two oil and one gas well.
Neptune estimates Gjoa P1 recoverable resources at 32 million boe and expects the extension to produce at a maximum rate of 24,000 boe/d.
Neptune has applied for a PDO for Duva field, formerly Cara, on PL636, 6 km northeast of Gjoa field and 12 km northeast of the Gjoa platform.
It plans to install a flour-slot subsea template and drill two oil production wells, one gas producer, and possibly another oil producer.
Duva is to produce at a peak rate of 30,000 boe/d from recoverable resources of 88 million boe.
Algeria’s Touat gas project on track for exports
Neptune Energy Group, London, and Algeria’s Sonatrach have started natural gas production as part of the commissioning of the partnership’s Touat project in the Sbaa basin, 1,500 km southwest of Algiers, near Adrar.
The development, which will produce about 450 MMcfd of gas at plateau, remains on track to begin gas export production by the end of this year’s first half, Neptune Energy said.
Touat comprises eight gas fields and a gas processing plant.
Project development involved drilling 18 development wells, along with building a road, aircraft runway, living quarters, gathering network, and gas treatment complex, as well as installation of a connection to the main GR5 pipeline, built by Sonatrach, to collect the gas from southwest Algeria to bring to Hassi R’Mel, about 800 km north.
Aramco lets contracts for Marjan oil field work
Saudi Aramco has let two contracts to McDermott International Inc. for engineering, procurement, construction, and installation services for Marjan oil field offshore Saudi Arabia. Aramco is expanding production capacity of Marjan field, now 500,000 b/d, by 300,000 b/d.
One contract—valued at $50-100 million—is for services for the upgrade of two existing platforms related to the installation of associated equipment for electrical submersible pumps and space for a future high integrity pressure protection system, subsea composite cable lay, and topside cable tie-ins.
The project is scheduled to be fully executed from McDermott’s Al Khobar office and Dammam fabrication facility.
A second contract—valued at $500-700 million—includes the design, procurement, fabrication, and installation, testing and precommissioning of the TP-10 tie-in platform, six gas lift topside modules, and associated pipeline and subsea cables. The total weight of the structures will exceed 27,000 tonnes and pipelines totaling more than 65 km.
PROCESSINGQuick Takes
IOC inks term contract for US crude supplies
Indian Oil Corp. Ltd. has finalized a term contract to import as much as 3 million tonnes/year of crude oil from the US as part of the operator’s strategy to diversify its term crude sources.
IOC finalized the contract—valued at $1.5 billion—on Feb. 15, the company said. This is the first term contract for US crude grades secured by any Indian state-run refining company.
IOC did not confirm a duration of the contract or the producers from which it has secured the term shipments.
With an overall group refining capacity of more than 1.6 million b/d, IOC controls 11 of India’s 23 refineries to account for a 35% share of total national refining capacity.
ADNOC Refining lets contract for Ruwais refinery
Abu Dhabi National Oil Co. (ADNOC) subsidiary ADNOC Refining (formerly Takreer) has let a contract to John Wood Group PLC to deliver preliminary front-end engineering and design (pre-FEED) for a refinery to be built in Ruwais, in the western region of Abu Dhabi (OGJ Online, May 14, 2018).
With a proposed nameplate capacity of 600,000 b/d, the new refinery will be designed to have full-conversion capability as well as the ability to be integrated with existing petrochemical infrastructure in Ruwais, Wood said.
As part of the contract—valued at $8 million—Wood will also provide services, including licensor selection, site master-plan development, scope of work for the FEED phase, as well as a schedule and cost estimate for the engineering, procurement, and construction phase.
Wood said it expects to complete the pre-FEED phase by yearend. Once completed, the new refining and petrochemicals complex will become the world’s largest.
The latest contract follows ADNOC’s May 2018 announcement that it would expand refining capacity at Ruwais, now a combined 817,000 b/d, with the addition of a 600,000-b/d refinery and to expand petrochemical capacity at the complex as part of its broader $45-billion program to become a global downstream leader under a new combined model of strategic partnerships and investments (OGJ Online, Jan. 28, 2019).
A cornerstone of the downstream investment plan is expansion of the company’s existing refining capacity by more than 65% to 1.5 million b/d by 2025, ADNOC said.
Aramco, Total form Saudi retail venture
Saudi Aramco and Total SA have signed an agreement to form a 50-50 joint venture that will invest $1 billion to develop a network of fuel and retail services in Saudi Arabia.
Total will be the first major international oil company to invest in the kingdom’s fuel retail network.
The companies also agreed to acquire Tas’helat Marketing Co. and Sahel Transport Co., owners of 270 service stations and a fuel tanker fleet.
TRANSPORTATIONQuick Takes
NEB recommends approval of Trans-Mountain pipeline
Canada’s National Energy Board recommended the approval of the Trans-Mountain Pipeline expansion project as it delivered its reconsideration report with 156 conditions and 16 new recommendations to the federal government on Feb. 22. NEB’s recommended approval came despite the board’s conclusion that project-related marine shipping would likely cause adverse environmental effects on the southern resident killer whale and on indigenous cultural uses associated with the animal. It also found that greenhouse gas emissions from project-related marine vessels would be substantial.
NEB carried out the reconsideration and met a 155-day deadline after a federal appeals court cancelled the crude oil and products pipeline project’s 2016 authorization last year (OGJ Online, Aug. 31, 2018). The proposed $7.4-billion (Can.) crude oil and products pipeline would be near one that was built in 1953 and increase capacity to 890,000 b/d from 300,000 b/d.
While a credible worst-case spill from the project or a related marine vessel is not likely, environmental effects would be weighty if one occurred, the report said. “While these effects weighed heavily in the NEB’s consideration of project-related marine shipping, the NEB recommends that the government of Canada find that they can be justified in the circumstances, in light of the considerable benefits of the project and measures to minimize the effects,” it said.
These benefits include increased access to diverse markets for Canadian oil; jobs created across Canada; the development of capacity of local and indigenous individuals, communities, and businesses; direct spending on pipeline materials in Canada; and considerable revenues to various levels of government.
ADNOC completes pipeline system investment deal
Abu Dhabi National Oil Co. (ADNOC) entered into a landmark multibillion-dollar midstream pipeline infrastructure partnership with institutional investors KKR and BlackRock. Newly formed ADNOC Oil Pipelines will lease ADNOC’s interest in 18 pipelines transporting stabilized crude oil and condensate across ADNOC’s offshore and onshore upstream concessions for a 23-year period. The entity will, in turn, receive a tariff payable by ADNOC, for its share of volume of crude and condensate that flows through the pipelines, backed by minimum volume commitments.
The 18 pipelines leased by ADNOC Oil Pipelines have a total length of more than 750 km and a total aggregate capacity of about 13 million b/d. These assets move most of Abu Dhabi’s crude oil production to sites for either conversion to other products or shipment to global energy markets. The pipelines have underlying long-term minimum volume commitments and are supported by stable crude oil production from ADNOC Onshore and ADNOC Offshore with global international oil companies as joint-venture partners, each with an average remaining concession life greater than 35 years.
ADNOC plans oil storage in Fujairah
Abu Dhabi National Oil Co. plans to build in Fujairah what it calls “the world’s largest single underground project ever awarded for oil storage.” It let an engineering, procurement, and construction contract to SK Engineering & Construction Co. Ltd., Seoul, for three underground storage caverns with capacities of 14 million bbl each.
ADNOC said the $1.21-billion contract is “the largest for a single project award for underground crude oil storage in the world.”
Completion is due in 2022.