GENERAL INTEREST Quick Takes
FAR loses Senegal arbitration
FAR Ltd., Melbourne, has lost its arbitration against Woodside Petroleum Ltd., Perth, over the dispute arising from Woodside’s acquisition of ConocoPhillips’s stake in the joint venture covering three blocks, including the Sangomar oil discovery, offshore Senegal.
The arbitration, initiated by FAR in June 2017 against Woodside subsidiary Woodside Energy (Senegal) BV in the International Court of Arbitration of the International Chamber of Commerce in Paris, was heard in July 2019 and the decision handed down in mid-February.
The tribunal found in favor of Woodside and declared that FAR did not have a pre-emption right over Woodside’s 2016 transaction to enter the Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore (RSSD) joint venture.
Woodside acquired a 35% share in the joint venture from ConocoPhillips for $350 million, but FAR maintained that a valid pre-emptive rights notice had not been issued to the JV partners by ConocoPhillips.
ConocoPhillips rejected this at the time, saying it had complied with all applicable laws and the venture’s Joint Operating Agreement.
As part of the deal to buy into the region, Woodside also made plans to become operator of the SNE development, taking over from Cairn Energy. This too was challenged by FAR.
The tribunal has ordered the parties to provide their views on the next procedural steps arising from its decision within 45 days.
In response to the Tribunal decision, FAR said it is analyzing the lengthy document and evaluating its position.
Woodside said it is committed to working with the RSSD joint venture to progress the $4.2-billion Sangomar field development which achieved a final investment decision in January 2020.
With the arbitration decision handed down, the shareholding in the RSSD joint venture remains at status quo: Edinburgh-headquartered Cairn Energy PLC with 40%, Woodside 35% and operatorship of the Sangomar development phase, FAR 15% and Senegal national oil company Petrosen 10%. Petrosen also has the right to increase its equity to 18% on development.
Centennial makes CEO, COO appointments
Centennial Resource Development Inc., Denver, has appointed Sean R. Smith, currently vice-president and chief operating officer, to succeed Mark G. Papa as chief executive officer, effective June 1. Papa, who has served as the company’s chairman and chief executive officer since 2016, will retire effective May 31. Smith is expected to be appointed to the board.
Smith has over 24 years of technical experience in the oil and gas industry. He joined Centennial in 2014.
Matt R. Garrison has been appointed to serve as vice-president and chief operating officer, also effective June 1. Garrison currently serves as the company’s vice -president of geosciences.
The company will separate the roles of chairman and chief executive officer. Current director Steven J. Shapiro will succeed Papa as non-executive chairman of the board. Shapiro has more than 40 years of financial and operational experience within the energy industry. Previously, he held various leadership positions at Burlington Resources Inc., including chief financial officer and a member of its board of directors.
Woodside writes down Kitimat LNG project
Woodside Petroleum Ltd., Perth, a partner in the proposed Kitimat LNG project on the coast of British Columbia in Canada, will record a $720 million after-tax writedown on its investments in western Canada.
The charge against its 2019 earnings reflects uncertainty in the timing of when it will be able to develop its Liard natural gas fields in northern British Columbia to supply the planned LNG export terminal, the company said.
The proposal is to process and ship up to 2.3 bcfd of gas.
Woodside added that Kitimat remains a world-class project and the company will continue to actively evaluate future development opportunities. These include the optimization of gas supply into the processing facilities.
Timing of the development of Liard upstream resource has been affected by sustained depressed gas market conditions in western Canada.
In December, the Kitimat operator Chevron Corp. said it is trying to sell its 50% stake in Kitimat LNG.
Exploration & Development Quick Takes
ENI finds oil offshore Mexico
Eni SPA and its Block 10 joint venture partners will appraise a recent discovery that has opened a potential commercial outcome of the block and other nearby prospects. Oil was discovered in the Saasken Exploration Prospect in the mid-deep water of the Cuenca Salina in the Sureste basin, offshore Mexico. Preliminary estimates indicate the discovery may contain 200-300 million barrels of oil in place.
The discovery was led by the Saasken-1 NFW well, the sixth consecutive successful well drilled by Eni offshore Mexico in the basin. Drilled by the Valaris 8505 semisubmersible 65 km off the coast in 340 m of water to 3,830 m TD, the well discovered 80 m of net pay in the Lower Pliocene and Upper Miocene sequences. Indications for the production capacity for the well is in excess of 10,000 b/d.
Eni is currently producing 15,000 boe/d from Area 1 and expects to reach a plateau of 100,000 boe/d in the first half of 2021. Eni is also planning exploration in other licenses held in Mexico.
ENI operates Block 10 with a 65% interest. Lukoil has 20% and Capricorn has 15%.
Europa, Cairn to relinquish offshore Ireland license
Europa Oil & Gas (Holdings) Plc and a Cairn Energy Plc unit will relinquish interest in Licensing Option (LO) 16/19 in South Porcupine basin, offshore Ireland, after a work program and full technical assessment concluded limited prospectivity on the license.
Capricorn Oil Ltd., a wholly owned subsidiary of Cairn Energy, become operator of LP 16/19 after acquiring a 70% interest from Europa Oil & Gas in March 2017. Europa retained a 30% interest (OGJ Online, Apr. 27, 2017). As part of the farm-out, Cairn funded a seismic acquisition program which covered the 976-sq-km licensing option on the western flank of South Porcupine basin and was completed in 2018.
Following the relinquishment, Europa’s license position offshore Ireland comprises five 100%-owned licenses. Multiple targets have been identified on seismic data across the licenses, the company said.
Africa Oil gains operatorship of South Africa deepwater block
Africa Oil SA Corp. gained operatorship and a 20% interest in Block 3B/4B offshore South Africa from Azinam Ltd. following government approval.
Block 3B/4B—covering an area of 17,581 sq km—lies in Orange basin in water depths of 300-2,500 m along-trend of an emerging Mid-Cretaceous oil play where operators are planning to drill exploratory wells that have the potential to be play-openers for a world-class petroleum province, the company said in a release.
The partners have identified an inventory of leads and prospects from an existing 10,020-sq km 3D survey that covers most of the block.
During the initial 3 years, Africa Oil and its partners are to carry out regional subsurface review of existing seismic, geological, and engineering data, and may also include some select reprocessing of the existing 3D data.
Separately, Africa Oil said it would participate in a $40 million capital raising by Impact Oil & Gas Ltd., the privately-owned, African-focused exploration company, on or about Feb. 14. The company will subscribe for 45.0 million ordinary shares for an investment of $12.0 million. Impact expects to use the proceeds to fund its interest in 2020 drilling campaigns that include drilling the Venus-1 exploration well on Block 2913B offshore Namibia, and Luiperd-1 well on Block 11B/12B offshore South Africa. Venus-1, which is partially carried by the operator, Total, is expected to spud during this year’s first half. Luiperd-1 is the second exploration well on Block 11B/12B following the Brulpadda discovery in 2019 and is also expected to be spudded during the first half of the year.
Drilling & Production Quick Takes
Equinor abandons Great Australian Bight drilling plans
Equinor ASA has abandoned plans to drill in the Great Australian Bight offshore South Australia despite having recently received environmental approval from the Australian Government’s offshore regulator to drill the proposed Stromlo-1 wildcat.
Jone Strangeland, the company’s country manager in Australia, said that the decision was taken following a holistic review of its worldwide exploration portfolio.
“Equinor concluded that the (Stromlo) project’s potential is not commercially competitive compared with other exploration opportunities in the company,” he said.
The $200 million (Aus.) plan was for the drilling of Stromlo-1 in 2,200 m of water in permit EPP39 about 370 km south of the coastline of the Nullarbor Plain using a mobile rig supported by three service vessels and two helicopters.
In giving its approval in mid-December, Australian National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) said it has imposed stringent conditions to ensure a high level of protection to the environment in recognition of the region’s unique values and sensitivities.
The approval enabled the company to drill 24-hours/day for 60 days between November and April in either 2020-21 or 2021-22.
The exploration program sparked opposition from environmental groups and in January the Wilderness Society launched legal action challenging NOPSEMA’s decision.
Equinor is the third major company to withdraw from drilling plans in the Bight following BP’s exit in 2016 and Chevron in 2017.
Equinor took an interest in the Bight permits in 2012 and moved to 100% in 2013. Australian Government Resources Minister Keith Pitt said Equinor’s decision to withdraw was disappointing, but he expressed support for future exploration in the Bight.
There are now calls from environmental groups to protect coastal communities and the area’s marine life by permanently ruling out drilling programs and proposing the Great Australian Bight for World Heritage listing.
Equinor will maintain a presence in Australia through its interest in permit WA-542-P in the north Carnarvon basin offshore Western Australia.
Norway production decreased in January, NPD says
Norway’s daily production averaged 1.963 million b/d in January, a decrease of 111,000 b/d compared to December 2019, the Norwegian Petroleum Directorate reported.
The preliminary average liquids production included 1.636 b/d of oil, 300,000 b/d of NGL, and 27,000 b/d of condensate.
Total gas sales in December were 10.4 billion standard cu m.
Oil production in January was 6.6% lower than the NPD’s forecast, due mainly to technical problems and maintenance work on some fields, the agency said.
Final liquids production of 2.074 million b/d in December included 1.755 million b/d of oil.
CNOOC starts oil production at Bozhong 34-9 field
CNOOC Ltd. has begun production from Bozhong 34-9 oil field in southern Bohai Bay. Average water depth at the site is 18.1 m.
The state-owned company said that in addition to fully utilizing existing facilities of Kenli oil field, the major production facilities include a central platform and a wellhead platform. A total of 57 producing wells are planned, including 38 production wells and 19 water injection wells.
The project is expected to reach peak production of 22,500 b/d of crude oil in 2022.
CNOOC Ltd. is operator of Bozhong 34-9 with 100% interest.
Kuwait, Saudi Arabia start Wafra, Khafji production
Kuwait and Saudi Arabia will start trial oil production from the jointly operated Wafra and Khafji oilfields. Both countries agreed in December to end a 5-year dispute over the border area known as the Neutral Zone, allowing production to resume (OGJ Online, Dec. 6, 2019).
Kuwait state news agency KUNA, citing Kuwait’s oil minister Khaled al-Fadhel, said the production, divided between Kuwait and Saudi Arabia, will increase gradually until it reaches normal levels and that production from the zone is expected to reach 550,000 b/d before the end of the year.
The fields produce heavy, high-sulfur crude and can pump up to 0.5% of the world’s oil supply. Kuwait aims to boost its oil production capacity to 4 million b/d by 2040.
PROCESSING Quick Takes
ADNOC lets contracts for Abu Dhabi gas mega project
Abu Dhabi National Oil Co. (ADNOC) has let two contracts to Petrofac Ltd. subsidiary Petrofac Emirates LLC and a joint venture of Petrofac and Sapura Energy Bhd. to provide engineering, procurement, and construction (EPC) for ADNOC’s Dalma gas development project 90 km northwest of Abu Dhabi City, UAE, a key part of the Ghasha Concession portfolio of projects encompassing Hail, Ghasha, and Dalma ultra-sour gas fields in the Emirate of Abu Dhabi (OGJ Online, Aug. 15, 2017).
The two EPC contracts, which have a total combined value of more than $1.65 billion, cover EPC services—including novated long-lead items, transportation, offshore installation, and commissioning—for Dalma gas field development, as well as offshore packages at Arzanah island and surrounding offshore fields about 140 km off Abu Dhabi’s northwest coast, ADNOC and Petrofac said in separate Feb. 18 releases.
As part of the first $1.065-billion, 33-month, lump-sum contract, Petrofac will provide EPC services for gas processing installations at Arzanah island, including inlet facilities with gas processing and compression units, power generation units, utilities, and other associated infrastructure, the service provider said.
Under the second 30-month, lump-sum contract—valued at $591 million—the Petrofac-led JV with Sapura Energy will deliver EPC services for three new wellhead platforms, removal and replacement of an existing topside, new pipelines, subsea umbilicals, composite, and fiberoptic cables, according to Petrofac.
Scheduled to be completed in 2022, work under both contracts will enable the Dalma gas development project—which is central to ADNOC’s strategic objective of enabling the UAE’s gas self-sufficiency—to produce around 340 MMcfd of natural gas, ADNOC said.
The Hail, Ghasha, and Dalma ultrasour gas development project will tap into Arab basin, which is estimated to hold multiple trillions of standard cu ft of recoverable gas, according to ADNOC’s website. More than 120,000 b/d of oil and condensates also are expected to be produced when the project is fully on stream.
ADNOC most recently let a contract to KBR Inc. to provide project management consultancy (PMC) services for the Ghasha Concession portfolio of projects (OGJ Online, Feb. 3, 2020).
Sibur lets contract for Amur gas chemical complex
PJSC Sibur Holding has let a contract to Linde PLC to provide technology for the cracker at its long-planned Amur gas chemical complex (GCC), an integrated 1.5 million-tonnes/year polyethylene and polypropylene production complex to be built near Svobodny in Russia’s far-east Amur region (OGJ Online, Sept. 14, 2015).
As part of the contract awarded under a consortium with Sibur subsidiary and project contractor NIPIgazpererabotka (Nipigaz), Linde will deliver engineering, procurement, and site services based on its proprietary technology for the GCC’s cracker, Linde said on Feb. 7.
The service provider disclosed neither a value of the contract nor further details regarding the specific technology it will provide for the project.
Sibur’s GCC will receive LPG and ethane fraction feedstock under a long-term contract from PJSC Gazprom subsidiary OOO Gazprom Pererabotka Blagoveshchensk’s (GPB) nearby 42 billion-cu m/year grassroots Amur natural gas processing plant (GPP) now under construction (OGJ Online, Dec. 26, 2019).
Sibur expects a proposed increase in the overall amount of ethane fraction and LPG feedstock supplies of up to 3.5 million tpy over time from GPB’s GPP to the Amur GCC will allow the complex to expand design capacities at the site from an initial 1.5 million tpy of polyethylene to about 2.3 million tpy of polyethylene and 400,000 tpy of polypropylene (OGJ Online, Oct. 4, 2019).
About 54% completed as of late 2019, GPB’s GPP includes six production lines, with the first two lines slated for commissioning in 2021 and remaining lines to be consecutively put in operation before yearend 2024. GPP is scheduled to reach full operational capacity by 2025, Gazprom said.
While Sibur has completed preliminary design development and approved configuration as well as capacities of the Amur GCC’s proposed units, its decision to move forward with project implementation was due in second-half 2019 pending completion of front-end engineering design (FEED) and clearance of applicable corporate procedures, according to Sibur’s website.
Sibur has yet to confirm either completion of FEED for the Amur GCC or its final approval for implementation of the project.
LyondellBasell progresses Gulf Coast PO-TBA plant
LyondellBasell Industries NV is progressing with construction of what it is calling the world’s largest propylene oxide (PO) and tertiary butyl alcohol (TBA) plant at the company’s Houston-area complex in Channelview, Tex. (OGJ Online, Sept. 3, 2018; June 3, 2016).
Installation of several large pieces of process equipment, including a 601-tonne, 25 stories-high distillation tower was under way as of Feb. 21, marking a shift from infrastructure work to vertical assembly, LyondellBasell said.
Over the next few months, manpower will continue to ramp up at both the Channelview and associated Pasadena, Tex., site as more large pieces of equipment are delivered and installed.
Construction on the overall project has now surpassed 30%, the operator confirmed.
Heading into yearend 2019, LyondellBasell completed the first phase of project construction, which included pouring nearly 83,000 cu yards of concrete and installing 160 miles of pipe at two construction sites (OGJ Online, Nov. 11, 2019).
Once in operation, the 140-acre PO-TBA plant in Channelview will produce 1 billion lb/year of PO and 2.2 billion lb/year of TBA, the latter of which will move to an associated 34-acre ethers unit to be built at the company’s Bayport complex near Pasadena for conversion into high-octane gasoline components methyl tertiary butyl ether and ethyl tertiary butyl ether.
LyondellBasell plans to sell PO and derivative products from the new Channelview plant to both domestic and global customers, while MTBE and ETBE oxyfuels from the associated Bayport unit will be primarily sold to buyers in Latin America and Asia.
A portion of TBA production, however, will remain in the US market as high-purity isobutylene for use in tires and lubricants, the company said.
Most production from the dual-location project will be exported via the Houston Ship Channel.
TRANSPORTATION Quick Takes
Williams cancels Constitution natural gas pipeline
Williams Cos. canceled plans for its Constitution natural gas pipeline. The 125-mile, 30-in. OD line, approved by the US Federal Energy Regulatory Commission in 2014, would have carried 650 MMcfd from northeastern Pennsylvania to existing transmission systems in Schoharie County, NY.
Environmental protests, eventually bleeding over into permitting issues, had slowed its progress for years.
Williams announced a $354-million write-down of Constitution as part of its 2019 earnings reporting, of which its share was $145 million.
Williams’s partners in the project were Duke Energy Corp., Cabot Corp., and AltaGas Ltd.
Qatargas signs another deal to supply LNG to Kuwait
Qatargas has signed a long-term LNG sale and purchase agreement with Shell to deliver 1 million tonnes/year of LNG to the State of Kuwait, beginning this year.
The SPA provides for the supply of LNG from Qatargas 4, a joint venture of Qatar Petroleum (70%) and Royal Dutch Shell PLC (30%).
The deal follows the early-Jan. supply agreement signed by Qatar Petroleum and Kuwait Petroleum Corp. for the supply of up to 3 million tons per year of LNG to the State of Kuwait.
Petronas’s second FLNG vessel sets sail for Rotan field
Malaysia’s state-owned Petronas reported Feb. 19 its second floating liquefied natural gas vessel, PFLNG Dua, set sail from South Korea to Rotan Gas field in deepwater Block H, 140 km offshore Kota Kinabalu, Sabah. The 1,840 nautical mile journey will take some 2 weeks to complete.
Upon arrival at the field, PFLNG Dua will commence its installation, hook-up, and commissioning with the ready-for-start-up date earmarked for midyear and provisional acceptance of the PFLNG Dua by the end of the year.
PFLNG Dua can produce 1.5 million tonnes/year of LNG and will be one of the world’s first floating deep-water LNG vessels capable of reaching remote, stranded, and marginal gas reserves in waters up to 1,500 m deep.
PFLNG Dua was delivered by Petronas and partners, JGC Corp. and Samsung Heavy Industries, the consortium responsible for the engineering, procurement, construction, installation, and commissioning of the floating LNG facility.
