GENERAL INTEREST — Quick Takes
Trump picks Oklahoma AG for EPA administrator
President-elect Donald J. Trump has appointed E. Scott Pruitt, Oklahoma's attorney general, as the next US Environmental Protection Agency administrator. He was one of 27 states' AGs who sued in federal court earlier in 2016 to overturn the Obama administration's Clean Power Plan.
"This administration continues to treat states as mere vessels of federal will, abusing and disrespecting the vertical separation of powers defined by our Constitution," Pruitt, who is a Republican, said outside US District Court for Washington, DC, on Sept. 27 where the case was being argued.
"That is why attorneys general, senators, and congressmen from across the country have joined together to maintain rule of law and checks and balances in this very process. I am committed to ensuring the ultimate payer in this matter is not overlooked-the consumers," he said.
Oklahoma Independent Petroleum Association Chairman Jeffrey McDougall, president and principal owner of Oklahoma City's JMA Energy Co., applauded the Dec. 7 appointment. "For the past 8 years, we've seen executive overreach put increased, unnecessary, and burdensome regulations in place to the detriment of not just Oklahoma's oil and gas industry, but industries across the state and nation," he said.
Another Oklahoman, Continental Resources Inc. Chief Executive Harold G. Hamm, was an advisor during Trump's 2016 presidential campaign and is said to be among those being considered to be US Secretary of Energy in the next administration.
Cantwell states concern over Trans-Mountain line
US Sen. Maria E. Cantwell (D-Wash.) expressed concern over a possible crude-oil spill in waters between her state and British Columbia after Canada's federal government approved Kinder Morgan Canada's proposed pipeline from Alberta to Burnaby, BC, near Vancouver (OGJ Online, Nov. 30, 2016).
"Given the importance of the Pacific Coast to the United States, I urge you to engage with Prime Minister [Justin] Trudeau and take action to protect the Puget Sound," she said in a Dec. 7 letter to US President Barack Obama. "It is critical that sufficient policies, response resources, and regulations are in place before moving forward with construction of the Kinder Morgan Trans-Mountain Pipeline Expansion Project."
Cantwell, who is the Senate Energy and Natural Resources Committee's ranking minority member, said the Canadian government based its decision solely on the basis of the pipeline's impact on Canada and did not consider its possible risks to the US.
"Project approval was rendered without consideration of the best available science on oil properties and interactions with the marine environment, and ignored significant known deficiencies in tar sands oil spill prevention and response capabilities," she said.
Oil spills have the potential to collapse Pacific Northwest fisheries, devastate its tourism, and pose a direct threat to key species such as the endangered Southern resident orcas, the senator noted. A spill in the Strait of Juan de Fuca or the transboundary Salish Sea could restrict vessel traffic to a point that ports' operations could be brought to a grinding halt, with devastating impact on both the state and national economies, she warned.
Origin Energy plans oil, gas business spinoff
Sydney-based Origin Energy Ltd. has announced plans to sell its $1.8-billion conventional upstream oil and gas assets so that it can focus on the wholesale and retail energy markets as well as its LNG business in Queensland.
The company plans to float its upstream business and list it on the Australian Stock Exchange in 2017 with the aim of reducing its debt of about $9 billion and reduce spending obligations.
The $25-billion LNG project at Curtis Island near Gladstone and its supply from the coal seam gas fields in the Bowen and Surat basins will be retained.
Chief Executive Officer Frank Calabria, who took over from long-time CEO Grant King just a few months ago, said his focus was on accelerating debt reduction and improving returns.
Calabria added that the move to an IPO for the oil and gas business was one of many options considered by Origin Energy's board. "In the end we thought that's where the most value is created," he said.
The company did not value the assets to be sold, but analysts believe they are worth upwards from $1.8 billion and could reach $3.7 billion.
The assets include gas projects in the Otway, Cooper, Bass, Browse, and Bonaparte basins in Australia, as well as the Kupe gas project offshore Taranaki basin and the Canterbury basin project, both in New Zealand.
The spinoff does not require shareholder approval. Macquarie Capital and UBS are advisors on the proposed IPO. The new company will have 2P reserves of 948 petajoules of gas and production of about 75 petajoules/year, based on 2015-16 figures.
Origin Energy will establish contracts to buy gas from the new company so that it secures its own supplies and provides near-term revenue certainty for the new company, which will have an independent board and management.
Shell confirms MOU with Iran
Royal Dutch Shell PLC confirmed it has signed a memorandum of understanding with state-owned National Iranian Oil Co. "to further explore areas of potential cooperation" but Shell declined to discuss likely fields or possible investment levels.
Total SA in November reported it was negotiating an investment reportedly worth billions of dollars to develop South Pars natural gas field offshore Iran. Total said it is negotiating for a final deal.
The pending transaction marked the first Western energy investment in Iran since international sanctions were lifted earlier this year (OGJ Online, Nov. 8, 2016).
Details on Shell's plans were limited on Dec. 7. A Shell spokesman in London only told OGJ that the agreement is "nonbinding."
Exploration & Development — Quick Takes
UK opens extra offshore licensing round
The UK government is offering 14 offshore blocks for licensing in a supplementary round following the closing last month of its 29th licensing round (OGJ Online, Nov. 2, 2016).
Operators have until Mar. 7 to apply for licenses at the Oil & Gas Authority (OGA).
Supplemental-round blocks lie outside areas covered by the 29th round. Block locations vary, ranging from the southern North Sea to the East of Shetland area.
The supplemental round uses the "innovate license" approach introduced in the 29th round. The concept enhances work-program flexibility for UK Continental Shelf exploration and production licenses, which are issued separately.
OGA Chief Executive Andy Samuel called the supplemental round "an important part of our approach to facilitate exploration across the whole of the UKCS."
In the 29th round, 24 companies filed 29 applications for 113 blocks.
BP well to target carboniferous gas in North Sea
BP North Sea reported it will begin drilling on a potential carboniferous natural gas play on Block 43/26a in the southern North Sea that, if successful, "could open up a new phase of development in the region."
The well, being drilled with partners Perenco and Premier, will test the potential of a deep carboniferous age horizon several hundred meters beneath the mature reservoirs now produced by the Ravenspurn ST2 platform.
"This play warrants further exploration as we know the reservoir sands exist. What we don't know is whether, if gas is found, long-term production can be proven economic from this deeply buried reservoir horizon," said Mark Thomas, BP North Sea regional president.
During the drilling and testing phase, Perenco, as operator of existing (and producing) Ravenspurn field, will act as substitute operator on behalf of BP and the other license owners.
BP holds 85% equity stake in the prospect. Perenco holds 10% and Premier 5%.
BP North Sea expects to increase production from its UK assets to about 200,000 b/d by 2020. In 2016, BP is expected to spend about $2 billion in capital investment and $1.6 billion running its operations, the company said. Over the next 18 months, BP plans to participate in as many as five exploration wells in addition to potentially drilling 50 developments wells in the North Sea over the next 3-4 years.
Centrica submits PDO for Oda field off Norway
Centrica PLC has submitted the plan for development and operation (PDO) for Oda oil field in the North Sea to Norway's Ministry of Petroleum and Energy.
The partnership will invest about £510 million in the development, which is scheduled to start production in 2019.
Previously known as Butch, Oda was discovered in 2011 via well 8/10-4S in the southern part of the Norwegian North Sea, about 13 km east of Ula field (OGJ Online, Oct. 18, 2011). Oda lies in 65 m of water and the reservoir is 2,900 m subsea.
Oda will be developed with a seabed template, tied into the Ula platform. Parts of Oselvar field's subsea facility and processing equipment on the Ula platform will be reused for Oda. Production on Oselvar will be shut down in 2017 or 2018.
Oil from Oda will be exported to Ekofisk and onward via Norpipe to the Teesside terminal in the UK. Produced gas will be injected in the Ula reservoir to improve oil recovery.
Oda's recoverable reserves are estimated at 48 million boe, of which 95% is oil. Peak production is expected at 35,000 boe/d.
Centrica is operator for Oda with 40% interest. Partners are Suncor Energy Norge AS 30%, Faroe Petroleum PLC 15%, and Tullow Oil Norge AS 15%.
Drilling & Production — Quick Takes
BP sanctions Mad Dog Phase 2 in Gulf of Mexico
BP PLC has sanctioned the Mad Dog Phase 2 project, which will include a floating production platform with the capacity to produce as much as 140,000 b/d of crude oil from as many as 14 production wells. Production is scheduled for late 2021.
"This announcement shows that big deepwater projects can still be economic in a low-price environment" provided designed in a smart, cost-effective way, said Bob Dudley, BP Group chief executive officer.
In 2013, BP and its partners decided to reevaluate the Mad Dog Phase 2 project after initial design plans proved too costly. BP is the operator with 60.5% working interest.
BHP Billiton Ltd. holds 23.9% and Unocal, an affiliate of Chevron USA Inc., holds 15.6%. BHP and Unocal have yet to announce a final investment decision on Mad Dog Phase 2.
BP worked with co-owners and contractors to simplify and standardize the earlier platform's design, reducing the overall project cost by 60%.
Plans now call for a $9-billion project, which also includes capacity for water injection. Executives believe Phase 2 can be profitable at or below current oil prices.
Mad Dog was discovered in 1998 with production starting in 2005 (OGJ Online, Jan. 19, 2005).
Continued appraisal drilling in the field during 2009-11 doubled the resource estimate of Mad Dog field to more than 4 billion boe, which would require another platform. A second Mad Dog platform will be moored 6 miles to the southwest of the existing Mad Dog platform in 4,500 ft of water about 190 miles south of New Orleans.
The current Mad Dog platform has the capacity to produce up to 80,000 b/d of oil and 60 MMcfd of natural gas. BP plans to add 800,000 b/d net of new production globally from projects starting up during 2016-20.
Statoil begins Mariner production drilling
Statoil ASA has commenced production drilling in Mariner heavy oil field from the East Shetland Platform in the UK North Sea, 150 km east of the Shetland Isles.
Hookup and commissioning of the Mariner A platform will begin next summer. Production startup is expected in 2018. The field has estimated oil reserves of 250 million bbl, with projected average plateau production of 55,000 b/d.
Noble Corp.'s Lloyd Noble jack up rig is positioned over the Mariner jacket, which was installed in 2015. The first production wells will be drilled through a well deck on the jacket. As many as five wells will be drilled before the platform topside modules arrive during mid-2017. In total, as many as 100 reservoir targets could be drilled over the lifetime of Mariner based on the current development strategy.
"Predrilling enables production to reach plateau levels more quickly after the start of operations on Mariner A," said Hedda Felin, managing director of Statoil Production UK. "It will also be an important learning period for us in terms of understanding the reservoir and identifying potential efficiencies for future wells, with safety and the protection of the environment being our fundamental priorities."
The rig contract was let to Noble in 2013 (OGJ Online, May 14, 2013). The contract award for integrated drilling and completion services was awarded to Schlumberger Ltd. in 2014 (OGJ Online, Dec. 19, 2014). The Mariner topside modules are under construction by Daewoo Shipbuilding & Marine Engineering Co. Ltd. in South Korea and sail away is expected in first-half 2017.
Statoil (UK) Ltd. is operator of Mariner with 65.11% equity. Partners are JX Nippon Exploration & Production (UK) Ltd. 20%, Siccar Point Energy 8.89%, and Dyas Mariner Ltd. 6%.
Devon reports Delaware basin stacked-spacing test
Devon Energy Corp., Oklahoma City, reported that it increased its risked drilling inventory in the Delaware basin following a successful Leonard shale stacked spacing test in southeast New Mexico.
The Thistle spacing pilot tested 400-ft vertical spacing between the B and C intervals in the Leonard shale in the southwest corner of Lea County, NM.
Initial 30-day production rates from a two-well pilot averaged 1,800 boe/d/well, of which 75% was light oil. The Thistle wells, drilled with 7,000-ft laterals, cost about $6 million each.
Early results from the Thistle pilot indicated minimal interference between wells, suggesting potential for joint development of multiple intervals in this part of the Leonard play, Devon said.
Devon raised its risked inventory in the Leonard shale to 950 gross locations, up about 20% from earlier estimates. The updated estimate conservatively assumes 6 wells/surface section. The company expects its risked inventory in the Leonard play will expand with additional delineation work.
Overall, Devon has 60,000 net surface acres in the Leonard play, with gross pay ranging up to 1,100 ft and up to three landing intervals.
The company plans to continue to accelerate drilling in the Delaware basin and also in its STACK assets in Oklahoma.
PROCESSING — Quick Takes
Unit shuttered at Sardinian refinery's CCR plant
Italy's Saras SPA, which operates a 300,000-b/d, high-conversion refinery in Sarroch on the southwestern coast of Sardinia has temporarily shuttered one of two units at the refinery's catalytic reforming (CCR) plant following an operational upset in early December.
The necessary shutdown took place on Dec. 5 after an unidentified "failure" occurred at the unit, Saras said, without commenting further on the nature of the incident.
While Saras confirmed the upset did not result in any injuries or impacts to the environment, the company said it expects the unit to remain offline for about 15 days.
The extended shutdown likely will result in an overall economic impact of about €25 million stemming from reduced production of gasoline and gas oil, costs to repair the unit, as well as potential limitations to the company's ability to achieve normalized levels of product inventories at yearend, the operator said.
Contrary to current capacity data posted to Saras' web site, the Sarroch refinery's CCR plant includes two units with a combined capacity of 50,000 b/d, the company said in a November presentation to investors.
Serbia's NIS lets contracts for Pancevo refinery
Serbia's Naftna Industrija Srbije (NIS) JSC Novi Sad has let a contract to CB&I, Houston, for engineering, procurement, and construction management (EPCM) of a delayed coker unit to be added as part of an ongoing modernization program at its 4.8 million-tonne/year refinery in Pancevo. The contract follows NIS's previous award to CB&I and Chevron Lummus Global, a CB&I-Chevron Corp. joint venture, for the coker's front-end engineering design and technology licensing, CB&I said.
The delayed coker will be integrated with the refinery's existing CB&I fluid catalytic cracking unit as well as the plant's existing Chevron Lummus Global-licensed hydrocracker, the service provider said.
This latest contract award at Panevo follows NIS's September completion of a month-long, €7-million turnaround of the refinery that involved planned maintenance and upgrading projects at nearly all of its primary and secondary processing units as part of the company's broader plan to improve energy efficiency, boost production of higher-quality products, and ensure operational reliability at the site.
ExxonMobil lets contract for Beaumont PE expansion
ExxonMobil Corp. has let a contract to Mitsubishi Heavy Industries Ltd. to supply equipment and services for the operator's current project to add a unit that will expand production of granular and pelletized polyethylene (PE) by 65% from current rates at its 1-million tonne/year PE plant in Beaumont, Tex.
MHI will deliver the reaction, finishing, and shipping equipment for the plant's PE production train, as well as associated water, air, and steam utility installations for the expansion project, the service provider said.
This latest contract for the Beaumont PE expansion follows ExxonMobil's earlier contract let to MHI for construction of a two-unit PE plant at the company's concurrent 1-million tpy expansion of its PE production site in Mont Belvieu, Tex.
MHI also completed delivery of two grassroots 650,000-tpy PE units for ExxonMobil's addition of a second petrochemical complex at its operations on Singapore's Jurong Island in 2011.
Already under construction and slated for startup in 2019, the 650,000-tpy PE unit comes as part of ExxonMobil's strategy to capitalize on lower feedstock prices resulting from rising supplies of US shale gas and associated liquids, the company said upon announcing the project in early November.
TRANSPORTATION — Quick Takes
DOE okays Magnolia LNG exports to non-FTA countries
The US Department of Energy has approved Magnolia LNG LLC's application to export LNG to countries that do not have a free-trade agreement with the US, DOE's Fossil Energy Office said in a Dec. 6 Federal Register notice.
Exports would be for as much as 1.08 bcfd over a 25-year period from Magnolia's proposed facility near Lake Charles, La., according to a Nov. 30 order that FEO issued.
FEO's authorization is subject to terms and conditions that the US Federal Energy Regulatory Commission imposed when it previously gave Magnolia approval to construct the proposed liquefier and terminal (OGJ Online, Apr. 18, 2016).
FERC also said that Kinder Morgan Louisiana Pipeline LLC could install compression and other related equipment on the KMLP system, allowing transportation of full feed-gas volumes to Magnolia LNG.
Port Arthur LNG files FERC application
LNG subsidiaries of Sempra Energy, San Diego, have filed applications with the US Federal Energy Regulatory Commission seeking authorization to site, construct, and operate the proposed Port Arthur LNG liquefaction facility along the Sabine-Neches Waterway in Southeast Texas.
The filing for the proposed project covers two natural gas liquefaction trains capable of producing, under optimal conditions, 13.5 million tonnes/year in the aggregate or 698 bcf/year; three LNG storage tanks; NGL and refrigerant storage; feed gas pretreatment facilities; and two berths with associated marine and loading facilities.
A separate application was filed with FERC seeking authorization to construct pipelines to deliver gas to the project.
Sempra LNG & Midstream and Woodside Energy (USA) Inc. signed a project development agreement in February that provides a framework for the sharing of costs related to the development, technical design, permitting, and marketing of the proposed liquefaction project.
Sempra also is involved in the Cameron LNG project currently under construction in Hackberry, La. Operations are expected to begin in 2018 (OGJ, Nov. 7, 2016, p. 22).
Medallion to build Delaware basin crude pipeline
Medallion Midstream LLC and its affiliate Medallion Midstream Services LLC have signed a letter of intent to construct a Delaware basin crude oil pipeline system to provide gathering and transportation services for Parsley Energy Inc.
The pipeline will be anchored by Parsley's long-term dedication to Medallion of 35,000 acres held under lease or mineral interest in Pecos and Reeves counties in Texas.
Medallion's Delaware basin pipeline system will initially consist of 45 miles of 16-in. mainline and 25 miles of smaller-diameter gathering lines along with a crude station in Pecos County consisting of storage and truck unloading facilities.
The pipeline, which is expected to have an initial capacity of 100,000 b/d, will originate within the Parsley leases and will end in Crane County, Tex., at an interconnection into Medallion Pipeline Co.'s existing 600-mile Midland basin header system, accessing multiple Permian basin long-haul takeaway pipelines. The line is expected to start service in June 2017.
