GENERAL INTEREST — Quick Takes
GOP senators: Stop attacks on OCS revenue-sharing
Seven Republican US senators asked US President Barack Obama to reconsider his proposal to deprive Gulf Coast states of a fair share of revenue from energy produced off their shores in federally controlled waters as promised under the 2006 Gulf of Mexico Energy Security Act (GOMESA).
"All energy producing states deserve to share the revenue derived from energy developed both onshore and offshore," Sens. Bill Cassidy (La.), John Cornyn (Tex.), Ted Cruz (Tex.), Lisa Murkowski (Alas.), Jeff Sessions (Ala.), David Vitter (La.), and Roger Wicker (Miss.) said in their Mar. 4 letter to the president.
Responsible revenue sharing allows states hosting federal energy production to mitigate impacts on their systems and make strategic investments to ensure that infrastructure will be resilient, the senators said.
"For these reasons, we not only oppose and reject your budget proposal eroding the revenue sharing provisions in GOMESA, but will actively pursue efforts to minimize the disparity by bringing equal treatment in revenue sharing among energy producing states," they said.
The administration's fiscal 2016 budget request to Congress proposed offshore revenue reforms that it said would save $367-475 million/year starting in 2017. This would raise federal OCS oil and gas revenue an estimated $1.77 trillion through 2020 and nearly $3.07 trillion through 2025, it said.
Outlook for US industrial gas use trimmed
Industrial demand for natural gas in the US will rise to 22.1 bcfd in 2020 from 19.8 bcfd in 2012, according to an updated analysis of projects in progress by the Center for Energy Economics (CEE), Bureau of Economic Geology at the University of Texas at Austin.
CEE maintains a database of projects in gas-intensive industries. Its first projection, in June last year, estimated industrial gas demand in 2020 of 23.5 bcfd in the reference case (OGJ Online, July 7, 2014).
The reference case includes projects completed, in front-end engineering and design, obtaining permits, under construction, or otherwise in progress.
In the update, CEE sees fewer projects completed or in progress during the study period: 83 vs. 103.
The biggest change, CEE says, is suspension of Sasol Ltd.'s plans for a gas-to-liquids (GTL) plant at Westlake, La. (OGJ Online, Jan. 28, 2015).
Total investment of projects expected through 2020 in the reference case has declined to $65 billion from $83 billion.
The new high case, which adds to projects in reference-case stages those under consideration or in planning, CEE identifies 112 projects representing total investment of $98 billion.
The high-case projects push 2020 industrial gas demand to 23.3 bcfd.
Plant types in the high-case total are fertilizer, 29; ethylene, 24; polyethylene, 15; methanol, 11; propylene, 9; chlor-alkali and methanol-to-gasolne, 6 each; hydrogen, 5; steel, 4; and GTL, 3.
Sasol cutting more costs amid lower oil prices
Sasol Ltd. hopes to cut $2.5-4.1 billion over a 30-month period, using Dec. 31 as the baseline, in response to what it describes as the "lower-for-longer oil price environment." The firm now expects to save $360 million by the end of financial year 2016.
Part of the firm's plan has included the reduction of 1,500 jobs through voluntary separations and early retirements in a scale-down that will last through June. Additional savings will come through a 30-month freezing of 500-1,000 vacancies.
Sasol in January delayed the final investment decision on its $11-14 billion gas-to-liquids plant near Westlake, La. (OGJ Online, Jan. 28, 2015). It was slated to sit adjacent to the company's $8.9-billion proposed integrated ethane cracker and downstream derivatives complex, for which a contract last month was let to GE Oil & Gas to provide the main-compression trains required for a low-density polyethylene (LDPE) plant (OGJ Online, Feb. 2, 2015).
A $4-billion credit facility was secured for the complex in December (OGJ Online, Dec. 23, 2014).
Cairn India cuts spending to $500 million
Cairn India Ltd. reported it will cut its capital spending to $500 million from the previously projected $1.2 billion for fiscal year 2016, which begins Apr. 1. The company said its capex for fiscal year 2015 will total about $1.1 billion.
Cairn will be undertaking projects that are "economically viable" at current oil prices. The company is reengineering projects and renegotiating contracts to improve project economics.
"Our cash-rich balance sheet and best-in-class cost profile provide a solid foundation to operate our high-margin core fields," said Mayank Ashar, managing director and chief executive officer. "This gives us the optionality to be selective about growth projects in these challenging times."
Cairn Energy disputing Indian tax claim
Cairn Energy PLC, Edinburgh, is disputing a tax claim by the Indian government for $1.6 billion related to the 2006 reorganization of its former Indian subsidiary.
The Scottish company said the Indian Income Tax Department is acting under retroactive provisions of a 2012 law.
The reorganization involved incorporation of Cairn India Ltd., controlling interest in which Cairn Energy sold in 2011 to Vedanta Resources, London, retaining 10% (OGJ Online, Dec. 6, 2011). Cairn Energy said the government, because of the tax dispute, is preventing its sale of its remaining Cairn India interest, which it estimates to be worth $700 million.
The company said it will file a notice of dispute under the UK-India Investment Treaty.
Exploration & Development — Quick Takes
BP makes another East Nile Delta discovery
BP PLC unit BP Egypt's Atoll-1 deepwater exploration well has penetrated 50 m of gas pay in high-quality Oligocene sandstones in the East Nile Delta's North Damietta Offshore Concession. Drilled by the 6th generation Maersk Discoverer semisubmersible rig, the well reached a depth of 6,400 m in 923 m of water. Atoll-1 will be drilled an additional 1 km to test the same reservoir section found to be gas bearing in BP's 2013 Salamat discovery, 15 km to the south (OGJ Online, Sept. 10, 2013).
The well, whose interest BP holds entirely, lies 80 km north of Damietta and 45 km northwest of Temsah offshore facilities.
"Success in Atoll further increases our confidence in the quality of the Nile Delta as a world class gas basin," said BP CEO Bob Dudley. "This is the second significant discovery in the license after Salamat," he said. "The estimated potential in the concession exceeds 5 tcf and we now have a positive starting point for the next possible major project in Egypt after BP's West Nile Delta project."
BP and a local partner recently agreed to invest $12 billion to develop 5 tcf of gas resources and 55 million bbl of condensates in the West Nile Delta gas project (OGJ Online, Mar. 6, 2015).
Gazprom Neft begins drilling on Kuvayskoye license
Gazprom Neft Orenburg has started drilling a wildcat well on the 140-sq-km Kuvayskoye license in Russia's Orenburg Oblast.
The well will reach a depth of 4,000 m, the deepest of any drilled on Gazprom Neft Orenburg fields.
Ongoing activity involves 3D seismic fieldwork to allow more detailed analysis and clarification of the geological structure of the area, along with the identification of promising deposits and their further study, the company says.
Similar studies have already been undertaken at neighboring Tsarichanskoye field. A single, comprehensive geological model will be constructed based on data from both fields.
Gazprom Neft Orenburg acquired the Kuvayskoye exploration and production license in October 2014. The area abuts the company's Orenburg Tsarichanskoye field, creating various synergies and economies of scale through the joint use of oil preparation and transportation infrastructure, along with the utilization of associated petroleum gas, the company says.
Gazprom Neft Orenburg operates five fields across the Orenburgsky, Novosergiyevsky, Perevolotsky, and Sorochinsky districts. The eastern area of Orenburgsky oil and gas condensate field has reserves of 100 million tonnes of oil equivalent.
The company also is active on Kapitonovskoye, Tsarichanskoye, Filatovskoye, and Baleykinskoye fields.
Consolidated production at Gazprom Neft Orenburg totaled more than 3.8 million tonnes of oil equivalent in 2014, a year-over-year increase of 29%.
No significant shows for Tullow well in Kenya
Tullow Oil PLC reported that its first well drilled in Kenya's North Turkana basin did not find significant oil or gas shows. The Engomo-1 exploration well, drilled west of Lake Turkana on Block 10BA, has been plugged after reaching 2,353 m.
Despite the lack of success, said Angus McCoss, Tullow exploration director, the firm still has "a vast amount of undrilled acreage with identified prospects and leads providing significant remaining exploration potential (OGJ Online, Oct. 23, 2014)."
In the South Lokichar basin, Tullow's activity includes preparation for extended well tests for its Amosing wells, beginning in mid-March. Amosing-1 and Amosing-2A were completed in five zones. Amosing-1 flowed at a combined maximum rate of 5,600 b/d from five zones, and Amosing-2A, 6,000 b/d from four zones. Pressure data shows connectivity between the wells in the upper three zones.
Also in South Lokichar, the Ngamia-7 appraisal well encountered up to 132 m of net oil pay in being drilled to 2,914 m to test the Ngamia field's eastern flank. Static pressure data from the Ngamia-1, 3, 5, 6, and 7 wells supports connectivity at multiple reservoir horizons. Extended well tests at Ngamia are planned.
The company also said the Ekales-2 appraisal well is at 2,817 m and has encountered up to 70 m of potential net oil pay. McCoss said results to date from Ekales are "very encouraging."
Drilling & Production — Quick Takes
Statoil to delay Johan Castberg, Snorre 2040 work
Statoil ASA and its respective partners have reported the postponement of the development of both the Johan Castberg and Snorre 2040 field projects to cut costs.
"We see that our efforts have yielded results, and we are focused on reaping the full benefits of this in a way that ensures a sustainable and profitable utilization of the resources in the Snorre and Johan Castberg fields," said Ivar Aasheim, Statoil's senior vice-president, field development, Norwegian continental shelf. "The recent decline in oil prices emphasizes this."
The Johan Castberg partnership has decided to postpone the decision to continue until second-half 2016, "with expectations for an investment decision in 2017," Statoil said.
The Statoil-operated discoveries Skrugard from 2011, Havis in 2012, and Drivis from 2014 comprise what is now the Johan Castberg project. Proved volumes in Johan Castberg are estimated at 400-650 million bbl of oil. Licensees in the Johan Castberg licence are Statoil, Petoro, and Eni.
Statoil said, "Studies are continuing on the alternatives for an oil infrastructure in the Barents Sea by a group of operators in the area including Statoil, Lundin Norway, Eni, and OMV."
The company said the aim is to "assess the foundation for an onshore terminal that could support multiple fields in the Barents Sea."
The Snorre 2040 partnership, meanwhile, has decided to extend the progress plan. The new schedule for the preliminary decision to implement is fourth-quarter 2016.
Snorre is one of the fields with the largest remaining oil resources on the NCS. The subsurface is complex, and major investments will be required to produce the resources, it said.
"The selected concept to construct a new platform, Snorre C, forms the basis for the work leading up to a new time for the decision point, which is fourth-quarter 2016. A final investment decision is scheduled for fourth-quarter 2017, with production start in fourth-quarter 2022," Statoil said.
Snorre field reserves are currently pegged at 1.63 billion bbl of oil. The original estimate, when the plan for development and operation was submitted in 1989, was 760 million bbl.
Snorre license partners include Statoil, Petoro, ExxonMobil, Idemitsu, RWE Dea, and Core Energy.
Husky reports start of production from Sunrise
Husky Energy Inc., Calgary, reported the start of production at the first of two 30,000-b/d plants at the in situ Sunrise Oil Sands Project in northeastern Alberta. Husky said it expects the project's total production to ramp up to its full 60,000 b/d capacity (gross) by yearend 2016.
Steam operations for the project began in December 2014 (OGJ Online, Dec. 12, 2014).
Husky is the operator of Sunrise, which lies 60 km northeast of Fort McMurray, with equal working interest with BP PLC, which operates the jointly-owned BP-Husky Toledo refinery.
Bitumen from Sunrise can be processed at that refinery.
Sunrise contains estimated reserves of 3.7 billion bbl (440 million proved, 2.4 billion probable, and 860 million possible) as of Dec. 31, 2013. Husky has a 50% working interest in these reserves.
Eagle Ford, Bakken oil production to fall in April
US shale oil production is expected to increase by a mere 1,000 b/d from March to April, according to the Energy Information Administration's Drilling Productivity Report (DPR), signifying a slowdown in growth caused by reduced company budgets and a shrinking rig count.
Total oil output from the most prolific shale areas in the Lower 48-the Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian, and Utica-will remain virtually unchanged at 5.6 million b/d in April.
The DPR focuses on those seven plays, which accounted for 95% of US oil production increases and all US natural gas production increases during 2011-13.
April growth will be pushed down by declines of 10,000 b/d in the Eagle Ford to 1.7 million b/d, 8,000 b/d in the Bakken to 1.3 million b/d, and 5,000 b/d in the Niobrara to 413,000 b/d. Production from the Permian, meanwhile, will expand 21,000 b/d to nearly 2 million b/d.
Baker Hughes Inc.'s most recent US oil rig count stood at 922, down 653 units since Dec. 5 (OGJ Online, Mar. 6, 2015). The Eagle Ford lost 61 oil rigs to 129 while the Niobrara lost 20 oil rigs to 23. The Permian lost 233 oil rigs to 328.
US gas production will rise 221 MMcfd from March to April, totaling 46.2 bcfd. The only declines will take place in the Niobrara and Bakken, falling 15 MMcfd and 8 MMcfd, respectively.
Premier starts gas production from Pelikan
Premier Oil PLC reported the start of natural gas production from Pelikan field on Natuna Sea Block A offshore Indonesia. This follows start of gas production in fourth-quarter 2014 from neighboring Naga field, also on the block.
Pelikan and Naga will deliver a total of about 200 MMcfd of gas production to Singapore under the company's long-term contracts, Premier said. Other fields on or near Natuna Sea Block A include Anoa and Gajah Baru, which have been supplying gas to Singapore since 2001 and 2011, respectively (OGJ Online, Mar. 5, 2012; Oct. 14, 2004).
Premier, operator of Natuna Sea Block A, holds 28.67% interest in the project. Partners include Kuwait Foreign Petroleum Exploration Co., Pertamina, PTT, and Petronas.
PROCESSING — Quick Takes
USW, Shell to resume talks amid continuing strike
The United Steelworkers union (USW) and Royal Dutch Shell PLC, which serves as lead company for National Oil Bargaining negotiations, have agreed to return to the bargaining table in an attempt to resolve USW's more than 5-week-long unfair labor practice strike in effect at US refineries and associated installations (OGJ Online, Feb. 2, 2015).
After an extended period of halted discussions, Shell and USW decided at a Mar. 4 meeting to resume the negotiation process during the week beginning Mar. 9, Shell said.
The announcement comes just days after Shell revealed its plan to return the company's strike-impacted sites to normal, full-rotation operations with the use of Shell-trained employees and without the use of union workers (OGJ Online, Mar. 3, 2015).
While Shell expressed hopes of reaching a mutually satisfactory agreement with USW upon renewed negotiations, the company also said it will continue to run its business, which includes the long-term goal of maintaining safe, reliable operations, with or without a union workforce, for as long as necessary.
Since negotiations began with USW following the Feb. 1 call to strike, Shell has put seven offers on the table, all of which have been rejected (OGJ Online, Feb. 23, 2015).
To date, USW has called its members to strike at a total of 15 US refineries and associated production sites operated by Shell, Motiva Enterprises, LyondellBasell, Marathon Petroleum Corp., Tesoro Corp., and BP PLC.
Kuwait lets storage contract for Clean Fuels Project
Kuwait National Petroleum Co. (KNPC), through its subcontractors, has let a contract to CB&I, Houston, to build petroleum product storage as part of KNPC's Clean Fuels Project (CFP), which aims to upgrade and expand its Mina Abdullah and Mina Al Ahmadi refineries in southern Kuwait (OGJ Online, Apr. 1, 2013).
CB&I's scope of work will include engineering, procurement, fabrication, and construction of 39 storage tanks and two spheres, CB&I said.
Awarded by JGSK JV, a joint venture of JGC Corp. and its partners GS Engineering & Construction and SK Engineering & Construction, the contract is valued at about $60 million, CB&I said.
In March 2014, KNPC let a $4.9 billion contract to the JGC-led consortium to provide engineering, procurement, construction, commissioning assistance, and testing services for CFP-related work at Mina Al Ahmadi (OGJ Online, Apr. 17, 2014).
Under the CFP, KNPC will integrate and upgrade the 270,000-b/d Mina Abdullah and 466,000-b/d Mina Al Ahmadi refineries and ultimately close the 200,000-b/d refinery at Shuaiba following the completion of the grassroots Al Zour refinery (OGJ Online, Dec. 3, 2013). The newly integrated refineries will operate as a merchant complex with total capacity of about 800,000 b/d, the company has said.
TRANSPORTATION — Quick Takes
Bear Head LNG requests DOE permits to export gas
Liquefied Natural Gas Ltd.'s wholly owned subsidiaries, Bear Head LNG Corp. and Bear Head LNG LLC (USA), have filed an application with the US Department of Energy requesting authorization to export as much as 440 bcf/year of US natural gas to Canada and 8 million tonnes/year of LNG from Canada to free-trade agreement and non-FTA nations. This application is in addition to one filed Jan. 23 to import gas from Canada and then re-export it back, and replaces the application submitted Dec. 9 to the DOE.
Bear Head has also requested authorization from Canada's National Energy Board to export up to 8 million tpy of LNG in 2019, with an expansion to 12 million tpy in 2024. This would require gas for at least 4 million tpy from Canadian sources, as Bear Head has only requested enough for 8 million tpy from the US.
Potential sources of domestic supply include western and central Canada, onshore in the Maritime provinces, and offshore Nova Scotia. John A. Godbold, Bear Head LNG chief operating officer and project director, addressing Platts annual LNG Conference, said the project could source gas from Alberta via underused TransCanada Corp. pipelines at the same price it would cost to send it to the Pacific Coast.
Bear Head is on the Strait of Canso in Point Tupper, NS, about half the distance to major European markets as US Gulf Coast ports, and is closer than other North American LNG projects to both Argentina and India, according to Godbold.
The company expects imminent approval of its permit to construct and to have all Canadian permitting in place this quarter, Godbold said. Bear Head plans a final investment decision next year to begin operations in 2019.
Wolf asks Obama for stronger crude-by-rail rules
Noting that 60-70 trains/week carry Bakken crude oil across Pennsylvania to the Philadelphia area or other East Coast refineries, Gov. Tom Wolf (D) asked US President Barack Obama for stronger federal regulations to prevent derailments and improve safety.
"I have already taken actions to address this issue including holding emergency trainings, participating in meetings with executives, and tasking my administration to put plans in place to both prevent accidents and mitigate impacts," Wolf separately said on Feb. 27.
"We also need expedited federal regulatory action in several areas along with a greater commitment to funding inspection and enforcement," Wolf said. "We cannot afford to wait for a major incident before taking action."
In his Feb. 26 letter to Obama, Wolf called for consistent national standards to reduce Bakken crude's volatility prior to transport, further reduction of trains' speed limits through urban areas, more federal inspections of rail infrastructure, better braking systems and tank car designs, and accelerated federal rail safety rulemaking.
Wolf sent his letter 10 days after a CSX train carrying Bakken crude derailed near Mount Carbon, W.Va. (OGJ Online, Feb. 17, 2015). The US Federal Railroad Administration announced on Feb. 22 that it was moving forward with a full-scale forensic investigation following a slow start hampered by weather and safety concerns. The US Department of Transportation, within which FRA and the US Pipeline and Hazardous Materials Safety Administration are agencies, submitted a draft final rule covering safe transportation of oil and other liquids by rail to the White House Office of Management and Budget on Feb. 5 for review.
