GENERAL INTEREST Quick Takes
EQT plans to write down up to $1.8 billion for 4Q19
EQT Corp., Pittsburgh, expects to write down $1.4-1.8 billion in asset value for fourth-quarter 2019, the company said in a Jan. 13 regulatory filing.
The non-cash impairment charge is due in part to the weakness in the natural gas market, the company said.
Spending for 2020 will be $1.25-$1.35 billion, down about $500 million from capital expenditures in 2019.
Moody’s cut EQT’s rating to junk status because of the “persistent weak natural gas price environment” and its “intent to refinance its 2020 maturities in lieu of debt reduction through repayment.”
EQT’s share price is down by more than half since last January, settling at $8.56/share on Jan. 15.
Twenty-eight firms awarded stakes in Norway
Twenty-eight companies have been awarded production licenses on the Norwegian continental shelf as part of Norway’s Awards in Predefined Areas (APA) 2019 licensing round. A total of 69 production licenses were on offer by Norway’s Ministry of Petroleum and Energy to oil and gas firms – 33 in the North Sea, 23 in the Norwegian Sea, and 13 in the Barents Sea. The authorities assessed applications from a total of 33 companies through autumn 2019 (OGJ Online, Sept. 4, 2019).
The awardees represent a mix of small and medium-sized companies as well as large international players—a combination important for continued value creation on the Norwegian continental shelf, said Norwegian Petroleum Directorate Exploration Director Torgeir Stordal. The awarded companies show a willingness to test new exploration concepts, and many focus on demonstrating resources close to existing infrastructure, he said.
Equinor was awarded 23 new production licenses comprising 14 solely-operated and nine partner-operated licenses. Eight production licenses are in the North Sea, eight are in the Norwegian Sea, and seven are in the Barents Sea. Earlier this year, Equinor was awarded five licenses in the UK North Sea by the Oil and Gas Authority (OGA) – four as operator and one as partner.
The top 10 awarded companies for 2019 (by units) are: Equinor (23), Var Energi (17), Aker BP (15), Neptune (13), Lundin (12), DNO (10), Wintershall Dea (9), Chrysaor (8), Wellesley (7), and Spirit Energy (6).
Var Energi, jointly owned by Eni (69.6%) and HitecVision (30.4%), was part of 7 production licenses in the North Sea, 3 in the Norwegian Sea, and 7 in the Barents Sea. Seven of the total license awards are Var Energi-operated and 10 are partner-operated. In September 2019, Var Energi—already a large independent exploration and production company on the Norwegian continental shelf—purchased from ExxonMobil ownership interest in more than 20 Norwegian producing fields increasing its presence in the area (OGJ Online, Sept. 26, 2019).
Aker BP was part of 11 production licenses in the North Sea, 3 in the Norwegian Sea, and 1 in the Barents Sea. Nine of the total licenses are Aker BP-operated and 2 are partner-operated.
Many licenses require new 3D seismic and geological and geophysical work and possible well evaluation to determine resource potentials. The work programs vary in length depending on work scope needed to obtain data to submit development plans or relinquish the license.
Auchincloss to succeed Gilvary as BP CFO
Murray Auchincloss, currently chief financial officer of BP PLC’s upstream segment, will succeed Brian Gilvary as BP chief financial officer and join the board, effective July 1. Gilvary plans to retire from the company and step down from the board on June 30 following a 34-year career with BP, which includes 8 years as chief financial officer.
Auchincloss has served as chief financial officer for BP’s upstream segment since 2015 after 2 years as upstream deputy CFO and head of business development for the segment.
CNOOC reports 2020 strategy, development plans
CNOOC Ltd. plans to steadily increase its oil and gas reserves and production through 2022, the company said Jan. 13.
The company’s targeted net production for 2020 is 520-530 MMboe, of which, production from China and overseas accounts for 64% and 36%, respectively. The company’s net production for 2019 is expected to be 503 MMboe. Net production for 2021 and 2022 are estimated to be around 555 MMboe and 590 MMboe, respectively.
In 2020, CNOOC plans to drill 227 exploration wells and collect 27,000 sq km of 3D seismic data. Within the year, 10 new projects are expected to come on stream, namely Penglai 19-3 oil field block 4 adjustment/Penglai19-9 oil field phase II, Qinhuangdao 33-1 South oil field phase I, Bozhong 19-6 gas field pilot area development project, Luda 16-3/21-2 joint development project, Nanbao 35-2 oil filed S1 area, Jinzhou 25-1 oil field 6/11 area, Liuhua 29-1 gas field development project, and Liuhua 16-2 oil field/20-2 oil field joint development project offshore China; Liza oil field Phase 1 in Guyana; and Buzzard oil field Phase II in the UK. Liza oil field Phase 1 has come on stream ahead of schedule.
The company’s total capital expenditure for 2020 is budgeted at 85-95 billion yuan. The capital expenditure for exploration, development, production, and others will account for 20%, 58%, 20%, and 2% of the total capital expenditure, respectively.
Exploration & Development Quick Takes
Lakes Oil finds gas column in Otway basin well
Lakes Oil NL, Melbourne, confirmed the presence of a minimum 65 m thick gross gas column in its Nanggarry-1 wildcat in the onshore Otway basin of South Australia.
The company reported that the gas is at the top of the Pretty Hill formation and has been confirmed by wireline logging comprising petrophysical logs, formation pressure data, and gas sampling.
The lower Pretty Hill gas interval identified during earlier drilling operations has not been definitively logged because of difficult down-hole conditions. The interval will be evaluated once the hole has been cased and suspended.
The well was drilled to a total depth of 4,300 m. A full flow-testing program is expected as soon as approvals are obtained, and the test equipment is in place.
The program will provide the basis for a development decision. Gas samples obtained have already been sent for analysis.
Nangarry-1, in permit PEL 155, is operated by Lakes with 50% interest. Vintage Energy Ltd., Adelaide, holds the other 50%.
The cost of the well was partially funded through a $4.95 million (Aus.) grant under the South Australian Government’s Petroleum Accelerated Exploration (PACE) program. The JV hopes to supply gas to the South Australian market by the end of this year.
Sangomar partners sign joint FID for field development
Cairn Energy PLC, along with its joint venture partners, Woodside Petroleum Ltd. (operator) and FAR Ltd., has signed a joint Final Investment Decision (FID) statement, in agreement with Petrosen and the Government of Senegal, for Sangomar field development. First oil is expected in early 2023.
FID on Phase 1 development offshore Senegal follows the receipt of the 25-year Exploitation Authorization from the Government of Senegal (OGJ Online, Jan. 9, 2020; Jan. 10, 2020).
Phase 1 will target estimated 2P recoverable oil reserves of 231 MMbbl (gross). Over the life of the field, total recoverable oil resources are estimated to be 500 MMbbl with the development also planning gas export to shore.
The current shareholding is Cairn Energy PLC with 40%, Woodside 35% and operatorship of the development phase, FAR Ltd. 15%, and Senegal national company Petrosen 10%.
Eni reenters Albania to explore Dumre Block
Eni has re-entered Albania with a production sharing contract to explore, with a 100% equity interest, the Dumre Block onshore Albania, following a competitive bid launched in September 2019 by the Albanian National Agency for Natural Resources (AKBN), Eni reported Dec. 20. As operator through a new subsidiary, Eni Albania, the company committed to drill an exploration well on the 587-sq km block, which lies 40 km south of the capital Tirana. No timeframe was reported.
Eni was present in Albania in the early ‘90s. It was awarded two offshore exploration blocks, Adriatiku-2 and Adriatiku-4, where, after drilling 3 wells with non-commercial results, the company left the country in 1999.
Drilling & Production Quick Takes
Eni starts production from Agogo field offshore Angola
Eni SPA has started production from Agogo oilfield offshore Angola 9 months after its discovery in Block 15/06 (OGJ Online, May 13, 2019). Production is tied back to the N’Goma floating production, storage, and offloading vessel about 15 km from the field.
Start-up was carried out with the drilling of Agogo-1 well at a water depth of around 1,700 m. Current production is around 10,000 b/d and is expected to reach 20,000 b/d in the coming weeks, the company said Jan. 17.
Preliminary estimates indicate the field holds over 650 million bbl of oil in place with further potential to be verified after the drilling of new delineation wells.
Discoveries in Block 15/06 during the exploration periods 2006-2011 and 2011-2014 led to the execution of two projects, the West Hub and East Hub, with the installation of two FPSO platforms. The platforms started production in 2014 and 2017, respectively. The production hubs comprise eight fields developed through 42 underwater wells with total production of more than 180 million bbl of oil by year-end 2019.
In second-half 2018, Eni Angola and JV partners Sonangol and SSI Fifteen Ltd. launched a new exploration campaign in Block 15/06 that led to the discovery of five new fields estimated to contain about 2 billion bbl of oil in place.
Eni Angola operates the block with a 36.8421% interest. Sonangol P&P has 36.8421% and SSI Fifteen Ltd. has 26.3158%.
Norway production increased in December, NPD says
Norway’s daily production averaged 2.082 million b/d in December, an increase of 95,000 b/d compared to November, the Norwegian Petroleum Directorate reported.
The preliminary liquids total included 1.759 million b/d of oil, 269,000 b/d of natural gas liquids, and 27,000 b/d of condensate.
Oil production for December was 12.7% higher than NPD’s estimates, 4.3% higher than November 2019, and 17% higher than December 2018.
Total gas sales in December were 10.7 billion standard cu m.
Final liquids production of 1.987 million b/d in November included 1.687 million b/d of oil.
SapuraOMV reports first production from SK408
SapuraOMV Upstream, Kuala Lumpur, reported first production following the late December 2019 start-up from Larak gas field offshore Malaysia under the SK408 production sharing contract.
The SK408 gas fields are part of discoveries made by SapuraOMV Upstream in Late Miocene carbonate build-ups during a drilling campaign that began in 2014. The fields are tied back to an existing processing facility and gas is transported through existing pipelines for onward gas processing at Petronas LNG complex in Bintulu. Development of SK408 aims to commercialize gas reserves from Gorek, Larak, and Bakong fields to help meet growing gas demand in Asia. 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.
SapuraOMV’s partners under SK408 PSC are Sarawak Shell Berhad (30%) and Petronas Carigali Sdn. Bhd (30%).
Following the full ramp-up of the first phase of SK408, comprising Gorek, Larak, and Bakong fields, SapuraOMV’s production is expected increase to more than 30,000 boe/d, with the majority being gas.
SapuraOMV Upstream is a partnership between Sapura Energy Bhd. and OMV Exploration & Production GmbH, a subsidiary of OMV Aktiengesellschaft.
Processing Quick Takes
Phillips 66, partner cancel Washington renewable diesel project
Phillips 66 and Renewable Energy Group Inc. (REG) have withdrawn a previously proposed joint project to build the largest renewable diesel refinery on the US West Coast.
The companies have cancelled construction of the planned 250 million-gal/year diesel plant in Ferndale, Wash., due to permitting delays and uncertainties, Phillips 66 said on Jan. 21.
In expressing thanks to Washington state, Whatcom County, local officials, and other stakeholders for their advice and support during the process, both Phillips 66 and REG confirmed they will work with all parties involved to wind down the ongoing permitting process.
Despite the project’s cancellation, Phillips 66 will continue to progress its portfolio of renewable diesel projects and evaluate new opportunities to provide consumers with renewable fuels that comply with low-carbon fuel standards, said Robert Herman, Phillip 66’s executive vice-president of refining.
REG also plans to continue developing numerous opportunities to grow its renewable diesel production to positively impact the environment and reduce the carbon intensity of transportation fuels through application of the operator’s proprietary technologies, said Cynthia Warner, REG’s chief executive officer.
The proposed Ferndale renewable diesel plant was to be built adjacent to Phillips 66’s 105,000-b/d Ferndale refinery to access the site’s existing infrastructure, including tank storage, a dock, as well as rail and truck rack access, Phillips 66 said in a Nov. 1, 2018, release.
The plant was to be equipped with REG’s proprietary BioSynfining technology for production of renewable diesel fuel, with planned feedstocks to include a mix of waste fats, oils, and greases, including regionally sourced vegetable oils, animal fats, and used cooking oil.
REG, which uses an integrated procurement, distribution, and logistics network to operate 14 biorefineries in the US and Europe, produced 502 million gal of cleaner fuel in 2018 to deliver more than 4 million tonnes of carbon reduction, the operator said.
Enterprise starts up new unit at Mont Belvieu complex
Enterprise Products Partners LP has commissioned a new isobutane dehydrogenation (iBDH) unit at the US Gulf Coast as part of a strategy to boost utilization capacity at the company’s existing downstream octane-enhancement and petrochemical operations in the region (OGJ Online, Jan. 30, 2017).
Located in Mont Belvieu, Tex., the new iBDH plant recently entered service, with volumes scheduled to continue ramping up during the next 2 weeks, EPP said on Jan. 13.
Supported by long-term, fee-based contracts with investment grade customers, the iBDH unit—once at full rates—will have the capability to process about 25,000 b/d of butane into nearly 1 billion lb/year of both high and low-purity isobutylene for use primarily as feedstock at EPP’s olefins assets to expand production of lubricants, rubber products, alkylate for gasoline blendstock, and methyl tertiary butyl ether (MTBE) for meeting growing demand on export markets.
The new Mont Belvieu unit comes as supplies of isobutylene—also a byproduct of ethylene production plants—have decreased as a result of increased use of low-cost, light-end feedstocks, specifically ethane, instead of more expensive crude oil derivatives, EPP said.
The iBDH unit is equipped with Honeywell UOP LLC’s proprietary C4 Oleflex technology (OGJ Online, Feb. 27, 2017).
EPP will also use UOP’s Oleflex technology at a second propane dehydrogenation (PDH) plant currently under construction at the Mont Belvieu complex (OGJ Online, Sept. 26, 2019).
The new PDH plant, which will have the capacity to process up to 35,000 b/d of propane to produce up to 1.65 billion lb/year of polymer-grade propylene, remains on schedule for completion in first-half 2023, EPP said.
Turkmenistan commissions new methanol plant
State-owned Turkmengaz has started up the world’s largest methanol plant based on Haldor Topsoe AS’s proprietary SynCOR autothermal reforming methanol-conversion technology at the operator’s recently commissioned natural gas-to-gasoline complex at Ovadan-Depe near Ashgabad, Turkmenistan (OGJ Online, Apr. 29, 2016; Aug. 26, 2014).
Located within the gas-to-gasoline complex, the 5,225-tonne/day methanol plant has progressively ramped up production as planned, with all performance targets met, since the complex’s official commissioning in mid-2019, Topsoe said on Jan. 14.
Officially entered into operation in June 2019, Turkmengaz’s gas-to-gasoline complex uses Topsoe Improved Gasoline Synthesis (Tigas)—involving a combination of SynCOR Methanol technology with a gasoline synthesis loop—to produce 15,500-b/d of synthetic gasoline conforming to Euro 5-quality standards, according to the service provider.
Late in 2019, Turkmengaz signed a memorandum of understanding with Kawasaki Heavy Industries Ltd. and Sojitz Corp. for design and construction of a second gas-to-gasoline complex, also presumably to be based on Topsoe’s Tigas technology, the government of Turkmenistan said in Nov. 11, 2019, and Oct. 24, 2019, releases.
In 2016, the government of Turkmenistan valued the cost of the Ovadan-Depe gas-to-gasoline complex at $1.7 billion.
TRANSPORTATION Quick Takes
Freeport LNG Train 2 begins commercial operations
Train 2 of Freeport LNG Development LP’s project on Quintana Island in Freeport, Tex., began commercial operations with the commencement of gas deliveries from BP PLC under its 20-year tolling agreement (OGJ Online, Feb. 11, 2013).
The project includes three pretreatment trains, a liquefaction plant with three trains, a second loading berth, and a 165,000-cu m full-containment LNG storage tank.
Michael Smith, Freeport LNG founder, chairman, and chief executive officer said the performance test on Train 2 was completed in 37 days after first gas was delivered to the liquefaction facilities, down from 107 days on Train 1.
Eagle LNG lets contract for Jacksonville export facility
Eagle LNG Partners LLC has selected Matrix Service Inc., a subsidiary of Matrix Service Co., for the engineering, procurement, fabrication, and construction of a liquefied natural gas (LNG) export facility to be built in Jacksonville, Florida.
The export facility also will utilize technology from Chart Industries. The facility will have a production capacity of approximately 1.65 million gpd with 12 million gal of LNG storage plus marine and truck-loading capabilities located on-site.
At a construction cost of $500 million, in addition to providing US gas to the Caribbean basin, once the facility is completed and its operations combined with Eagle LNG’s Maxville LNG facility and the Talleyrand LNG bunker station, Eagle LNG will be providing the lowest cost LNG for bunkering in the US Southeast, the company said.
Eagle LNG received both FERC authorization and Department of Energy LNG export approvals for the Jacksonville LNG export facility in late 2019 (OGJ Online Oct. 4, 2019; Sept. 23, 2019).
EPP exports first ethylene cargo from Morgan’s Point
Enterprise Products Partners LP (EPP) and Navigator Holdings Ltd. have exported the first cargo of ethylene from their 50-50 joint venture marine terminal at Morgan’s Point, Tex., along the Houston Ship Channel. The Navigator Europa departed the terminal carrying 25 million lb of ethylene for Marubeni Corp.
The new terminal features two docks and the capacity to load 2.2 billion lb/year of ethylene. A 66-million lb refrigerated storage tank is also being built onsite and will increase loading rates to 2.2 million lb/hr. Tank construction is expected to be completed in fourth-quarter 2020.
The export terminal is pipeline-connected to Enterprise’s Mont Belvieu, Tex., complex, where the company is in the process of commissioning a 600-million lb high-capacity ethylene salt dome storage well. Enterprise has designed the system to serve as an open market storage and trading hub for the ethylene industry through storage, connections to multiple ethylene pipelines, and high-capacity export capabilities.
EPP expects total Gulf Coast ethylene production to exceed 100 billion lb/year by 2025.
In addition to the new ethylene export terminal and storage infrastructure, EPP is developing a 24-mile pipeline between Mont Belvieu and Bayport, Tex., routed through Morgan’s Point and expected to begin service fourth-quarter 2020. EPP is also building the 90-mile Baymark Pipeline from Bayport to Markham, Tex., for fourth-quarter 2020 completion. Both pipelines are supported by long-term customer commitments and will enable producers and consumers to access the Enterprise open market ethylene storage and trading hub.
NGPL gets nod for Permian Lockridge extension
Natural Gas Pipeline Co. of America LLC (NGPL) received US Federal Energy Regulatory Commission (FERC) approval on Jan. 22 to begin building its 500,000-MMcfd Lockridge Extension Pipeline Project in Ward, Reeves, and Pecos Counties, Tex. The extension project will directly connect NGPL’s system to the Waha hub in Pecos County, the company’s first Waha connection.
The 16.84-mile, 30-in. OD pipeline will provide southbound capacity on NGPL’s existing Lockridge pipeline and link the system to a new bidirectional interconnect with Trans-Pecos Pipeline LLC (TPP) at Waha.
NGPL plans to begin preconstruction mobilization Mar. 10 to start construction May 4. Construction will be complete by Aug. 29 for a Sept. 12 in-service date. Final cleanup and restoration will be done by Nov. 30, according to NGPL plans filed with FERC.