GENERAL INTEREST — Quick Takes
Murkowski: Highway bill report ensures SPR's stability
The joint US Senate-House federal highway bill conference report reduced crude oil sales from the US Strategic Petroleum Reserve to a level that ensures the US Department of Energy will be able to upgrade the reserve's infrastructure, US Sen. Lisa Murkowski (R-Alas.) said.
Congressional negotiators reached an agreement on Dec. 1 on the more than $300-billion measure that would fund improvements in highways and other transportation systems over 5 years. The House and Senate were expected to vote on the bill later in the week.
It retained a provision that would authorize $6.2 billion of SPR crude sales to partially pay for the highway projects. "The recent series of proposed and enacted drawdowns constitute a fundamental transformation in the purpose and function of the SPR," Murkowski said on Dec. 1. "I am encouraged that the compromise on the highway bill reflects my efforts to preserve [its] integrity."
The senator, who chairs the Energy and Natural Resources Committee, strongly expressed her concerns about the concept when it was first proposed (OGJ Online, July 29, 2015). It called for the sale of 101 million bbl of SPR crude for a projected $9 billion of revenue for highway projects in fiscal 2012-18.
That amount has been reduced to $6.2 billion, Murkowski said on Dec. 1 as she released a new report that the committee's majority staff prepared on cumulative impacts of SPR sales and other considerations.
"Through most of its history, the theme of the SPR was expansion and preparation for emergencies. In the present discussion, that theme has shifted to depletion and revenue-raising," the senator said. "The SPR was not designed to draw down so much oil so frequently over such a long period of time. All of these issues-the size of the reserve, the integrity of the reserve, and our global standing-should be considered in any discussion related to modernization of SPR."
Firms, people charged in 2012 gulf platform explosion
Three companies and three individuals face criminal charges stemming from a November 2012 offshore oil and gas platform explosion that killed three workers, injured several more people, and spilled crude oil into the Gulf of Mexico (OGJ Online, Nov. 16, 2012), the US Department of Justice and US Attorney's Office for eastern Louisiana jointly reported.
Indictments named Black Elk Energy Offshore Operations LLC, Grand Isle Shipyards Inc., and Wood Group PSN Inc., as well as Don Moss of Groves, Tex.; Curtis Dantin of Cut-Off, La.; and Christopher Srubar of Destrehan, La.
According to the Nov. 19 indictment, the defendants were involved in different capacities while construction work was being done of the West Delta 32 platform when it exploded.
Black Elk and Grand Isle Shipyards were charged with three counts of involuntary manslaughter, eight counts of failing to follow proper safety practices under the Outer Continental Shelf Lands Act (OCSLA), and one count of violating the Clean Water Act (CWA).
Wood Group PSN and individuals Moss, Dantin, and Srubar were charged with felony violations of OCSLA and the CWA, prosecutors said. They emphasized that indictments are only allegations, and defendants are presumed innocent unless found guilty at trial.
Black Elk failed to properly supervise its contactors, which contributed to a series of events and decisions leading up to the fire and explosion, the US Bureau of Safety and Environmental Enforcement previously said (OGJ Online, Nov. 5, 2013).
ATP Oil & Gas to pay $41.85 million to settle charges
Houston independent ATP Oil & Gas Corp., which went bankrupt in 2012, agreed to pay $41.85 million in fines to settle federal charges that it discharged crude oil and chemicals from its floating production platform into the Gulf of Mexico, federal officials reported.
The US Department of Justice, Bureau of Safety and Environmental Enforcement, and Environmental Protection Agency jointly said on Nov. 19 that two settlement agreements were filed in US District Court for eastern Louisiana and US Bankruptcy Court in San Antonio. They are subject to a 30-day comment period and court reviews and approvals.
The first agreement resolves federal claims against ATP in a 2013 case alleging crude and chemicals were discharged into the gulf from the ATP Innovator production platform. A March 2012 BSEE inspection revealed alleged unlawful discharges of oil and a piping configuration that routed an unpermitted dispersant into the facility's wastewater discharge pipe to mask excess oil being discharged into the ocean.
The platform was removed from the Mississippi Canyon deepwater block where it was operating and towed to Corpus Christi, Tex., in 2013. DOJ said the proposed settlement resolves judicial claims against ATP, which is in Chapter 7 bankruptcy and no longer operating, with a $38-million fine.
The other $3.85 million penalty was part of the bankruptcy court settlement of related violations of Outer Continental Shelf Lands Act regulations, it said. Through that settlement, ATP agreed to an allowed unsecured claim of $38 million for the judicial civil penalty judgment specified in the District Court Settlement Agreement, DOJ said.
API, ANGA agree to combine
The American Petroleum Institute and America's Natural Gas Alliance agreed to combine, with ANGA becoming a new market development group within API that will continue to promote gas as a clean, affordable energy resource. ANGA Pres. Martin J. Durbin, who worked previously at API, will head the new division there as executive director.
"There is a natural synergy between our organizations," API Pres. Jack N. Gerard said on Nov. 18 as the associations jointly announced their merger. "As a single organization, the combined skills and capabilities bring an enhanced advocacy strength to natural gas market development-ANGA's primary mission-and the combined association's expanded membership will provide additional lift to API's ongoing efforts on important public policy issues."
ANGA member companies that don't belong to API already will become full members there, the associations noted.
Moss Creek to buy Tall City's Midland basin assets
Moss Creek Resources LLC has closed a transaction in which it bought most of Tall City Exploration LLC's exploration and production operations in the northern Midland basin for $803 million. The deal involved oil and gas leases covering 71,000 acres in Texas' Howard and Borden counties.
The transaction concerned interests in 34 horizontal and six vertical wells that produce 3,750 boe/d. Tall City is based in Midland, Tex.
Moss Creek Resources of Dallas was formed by Blue Whale Energy North America Corp., which is a subsidiary of Blue Whale Energy Ltd., an energy investment company based in Beijing.
Exploration & Development — Quick Takes
Tullow to drill Etom-2 in Kenya's South Lokichar basin
Tullow Oil PLC said its Emesek-1 exploration well in the North Lokichar basin in northern Kenya reached 3,000 m "without encountering commercial hydrocarbons."
The well on Block 13T "provides valuable data as we assess the wider prospectivity of this basin," said Angus McCoss, Tullow's exploration director (OGJ Online, Mar. 11, 2015). McCoss said it was the first well to be drilled in the basin.
Tullow has 50% of Block 13T, and Africa Oil Corp. has 50%.
The PR Marriott 46 rig will move to the South Lokichar basin to drill the Etom-2 well, which is expected to spud in late November.
Onshore exploration enters Ghana after 40-year hiatus
EPI Group's Ghanian joint venture company EPI SonarTusk has signed a 2-year contract to support seismic exploration by Ghana National Petroleum Corp. in the Voltaian basin. The operator will acquire 2D seismic in the 104,000-sq-km basin, which covers about 40% of Ghana's land mass.
The Voltaian basin consists of sedimentary Neoproterozoic rocks with similarities to hydrocarbon producing areas in other parts of North Africa. Exploration in such a basin carries higher risk than most conventional plays due to age and probable geological history of the subsurface, the company said. Volta Lake, the world's largest man-made water body, also adds to the complexity of shooting seismic in the basin.
Ghana's exploration efforts shifted offshore in the mid-1970s with the discovery of South Tano field in 1978, by Phillips Petroleum. In late 2015, Erin Energy Corp. reported that Ghana's 373,000-acre Expanded Shallow Water Tano (ESWT) block holds 500 million bbl of oil and 282 bcf of natural gas in place (OGJ Online, Oct. 6, 2015).
The EWST block is north of giant Jubilee oil and gas field, which is operated by Tullow Oil PLC (OGJ Online, Aug. 17, 2015).
Alexander Kofi-Mensah Mould, acting chief executive of GNPC, said the operator wants to better understand the basin and its potential for development before inviting partners to join, given the associated risks of Ghana's onshore potential.
Ophir moves ahead on Fortuna project
Ophir Energy PLC has contracted Fugro NV to perform autonomous underwater vehicle (AUV) surveys as well as geotechnical, environmental, and metocean surveys at its Fortuna project, 140 km west of Bioko Island, where Ophir is planning a large floating LNG installation and associated subsea structures (OGJ Online, Nov. 7, 2014).
The surveys and offshore operations are scheduled for completion in January 2016. The Fugro Searcher, Fugro Scout, and Fugro Frontier vessels have been deployed for the work.
The Fortuna project lies on Block R offshore Equatorial Guinea in 1,600 m of water. The block borders Nigerian waters about 60 km southeast of Zafiro oil and gas field. Ophir has said the Fortuna complex's eastern lobe holds 553 bcf of mean in-place natural gas, of which 426 bcf is estimated as recoverable (OGJ Online, Aug. 27, 2012).
Block R is owned 80% by Ophir and 20% by the national oil company GEPetrol.
Drilling & Production — Quick Takes
Oil production starts from Edvard Grieg off Norway
Lundin Petroleum AB started oil production on Nov. 28 from Edvard Grieg field in PL338 on the Utsira High of the North Sea, about 180 km west of Stavanger.
The field, discovered in 2007 with Lundin's first operated exploration well in Norway, is estimated to contain gross 2P reserves of 187 million boe.
Lundin says a successful appraisal well in the southeast of Edvard Grieg-drilled earlier this year (OGJ Online, Aug. 5, 2015)-is anticipated to boost reserves once the yearend 2015 reserves certification process has been completed.
Edvard Grieg has been developed with a steel jacket platform resting on the seabed. The topsides weigh about 22,500 tonnes and include a processing facility, utility module, and living quarters (OGJ Online, Apr. 14, 2015).
Development drilling by the Rowan Viking jack up rig will resume shortly, says Lundin, which plans 10 production wells and four water injection wells. Plateau production is expected during the second half of 2016.
Drilling of the development wells is expected to continue into 2018. Edvard Grieg has been designed as a field center, and will receive oil and gas from neighboring Ivar Aasen field for further processing.
The Norwegian Petroleum Directorate at the beginning of this month greenlighted the Edvard Grieg crude pipeline and Utsira High gas pipeline that will respectively serve Edvard Grieg and Ivar Aasen fields on the Utsira High (OGJ Online, Nov. 6, 2015). About 10 days later it gave consent for production startup (OGJ Online, Nov. 16, 2015).
Eni signs Mexican PSC, plans four wells
Eni SPA will drill four delineation wells under a production-sharing contract it has signed with the National Hydrocarbons Commission for the block it won in the second tender of Round One licensing in Mexico (OGJ Online, Sept. 30, 2015).
The contract covers development of Amoca, Mizton, and Tecoalli oil fields in Area 1 close to shore in the Bay of Campeche.
HKN to increase Sarsang production in Kurdistan
The Kurdistan Regional Government (KRG) has approved a plan by HKN Energy Ltd. to increase production to 50,000 bo/d at its Sarsang Block north of Dohuk on the Zagros fold belt in Iraqi Kurdistan.
The operator recently conducted testing on the East Swara Tika-1 well, which produced 8,000 b/d of 37-39° gravity oil on a 72/64-in. choke with associated gas of 6.8 MMcfd and a wellhead pressure of 805 psi.
HKN began commercial production of the Swara Tika-1 in June 2014 and has since produced 1.5 million bbl of oil. HKN's Sarsang development plan was submitted to include this prospect.
PROCESSING — Quick Takes
EPA completes technical reviews for refinery rule
The US Environmental Protection Agency completed a residual risk review for refinery emissions covered under a final rule it issued at the end of September (OGJ Online, Sept. 29, 2015).
It also finalized technical corrections and clarifications for New Source Performance Standards for refineries to improve consistency and clarity and address issues related to a 2008 industry petition for reconsideration, the agency said in a Dec. 1 Federal Register notice.
"Implementation of this final rule will result in projected reductions of 5,200 tons/year of hazardous air pollutants, which will reduce cancer risk and chronic health effects," it indicated.
American Fuel & Petrochemical Manufacturers Pres. Chet Thompson said AFPM was pleased with EPA's multiyear assessment of its members' facilities that found them to be well-under the threshold level for causing risk and do not cause harm to surrounding communities.
"But, in spite of its findings, EPA did not take its own analysis into account when finalizing this rule," he told OGJ. "We are disappointed, however, that the agency felt compelled to require additional expensive and unnecessary controls, which won't result in any real benefits."
Asked for a comment on EPA's latest announcement, the American Petroleum Institute referred OGJ to its Sept. 29 statement when EPA announced the final rule.
Shell takes FID to expand AO production at Geismar plant
Shell Chemical LP reported taking the final investment decision (FID) to increase alpha olefins (AO) production at its chemical manufacturing site at Geismar, La., making the site the largest AO producer in the world, the company said. Shell will construct a fourth AO unit, which will add 425,000 tonnes/year of capacity.
Construction of the unit will begin in first-quarter 2016. The new capacity brings the total AO production at Shell's Geismar site to more than 1.3 million tpy. The site also produces alcohols, ethoxylates, ethylene oxide, and ethylene glycols.
Shell's Geismar chemical plant is next to the Mississippi River, about 20 miles south of Baton Rouge. It is a stand-alone chemicals manufacturing plant, operated by Shell Chemical.
In addition to Geismar, Shell produces AO at Stanlow in the UK, operated by Essar Oil (UK) Ltd. on Shell's behalf as part of an integrated oil refinery and petrochemicals site.
Ineos to supply US ethane to Scottish ethylene cracker
Ineos Europe AG, a unit of Ineos AG, Switzerland, has entered a deal for the long-term supply of US ethane supplies to ExxonMobil Chemical Ltd.'s 830,000-tonne/year Fife ethylene plant (FEP) at Mossmorran on Scotland's eastern coast near Braefoot Bay, about 25 miles north of Edinburgh.
Under the agreement, Ineos will deliver price-advantaged US shale ethane supplies from its new Grangemouth import terminal along an existing pipeline to FEP beginning in 2017, Ineos said.
The US-sourced ethane supplies are intended to supplement FEP's current supply of NGL feedstock from North Sea production by securing additional raw feed that to help the plant meet long-term needs of its domestic and international customers, according to FEP's owner and operator, ExxonMobil Corp., and Royal Dutch Shell PLC subsidiary Shell Chemicals Europe BV, which holds 50% capacity rights in the venture.
The supply deal follows Ineos' £450-million investment to build an import terminal and storage tank to store and process ethane from shale gas as part of a survival plan for its 210,000-b/d Grangemouth refinery that involves transforming the plant into a shale gas-based operation by 2016 in order for it to become a profitable business again (OGJ Online, July 17, 2014).
Ineos previously entered deals to secure US shale gas supplies for its European cracking operations with Consol Energy Inc., Pittsburgh, Range Resources-Appalachia LLC, and Enterprise Products Partners LP (OGJ Online, June 12, 2014).
TRANSPORTATION — Quick Takes
BG starts operations from QCLNG Train 2 in Australia
BG Group PLC reported that commercial operations have started from Train 2 at its Queensland Curtis LNG (QCLNG) plant. QGC, BG's Australian subsidiary, has also assumed control of Train 2 from Bechtel Australia, which built the facility.
BG now has full control of both LNG trains and associated facilities at QCLNG. By mid-2016 the integrated project is expected to reach plateau production, producing enough LNG to load a combined 10 vessels/month, which is equivalent to exporting 8 million tonnes/year. Since starting production in December 2014, 71 cargoes have been shipped, BG said.
Woodside JV given environmental nod for Browse FLNG
The Australian government has given environmental approval for the Woodside Petroleum Ltd.-led joint venture's proposed development of its Browse basin gas-condensate fields using floating LNG (FLNG) technology.
The approval under the Environmental Protection and Biodiversity Conservation Act 1999 is a major milestone on the way to the JV's scheduled final investment decision for the project in mid-2016.
Operator Woodside plans a total of 64 production wells involving eight drill centers across three gas fields-Torosa, Brecknock, and Calliance-in water ranging 350-700 m deep. The reservoir targets lie 3,500-4,500 m subsea.
The facilities will cover 67 hectares, and the design calls for as many as three FLNG vessels based on Royal Dutch Shell PLC technology, although this may be modified into a staged one-vessel-at-a-time approach, depending on market conditions.
Each vessel will have a capacity to produce 3.9 million tonnes/year of LNG. There will also be a floatel accommodation vessel moored away from the physical Scott Reef geographic feature. The first of the three fields was found in the early 1970s, the last in 2000. They have total estimated 2C contingent resources of 15.4 tcf of dry gas and 453 million bbl of condensate.
Snam to buy Statoil's stake in TAP system
Snam SPA will acquire from Statoil ASA its 20% stake in Trans Adriatic Pipeline AG (TAP) for €208 million (OGJ Online, Dec. 18, 2013). The transaction is expected to close by yearend. Statoil has been a stakeholder in TAP since 2008, but divested its share of the Shah Deniz gas field in Azerbaijan in 2014.
The 882-km TAP system will be the westernmost section of the Southern Gas Corridor, a 3,500-km gas system linking Shah Deniz Stage II to gas markets in Europe. TAP will connect with the Trans-Anatolian Natural Gas Pipeline (TANAP) at the Greece-Turkey border. It will cross northern Greece, Albania, and the Adriatic Sea before coming onshore in southern Italy, where it will link with the Snam-operated Italian natural gas network (OGJ Online, July 18, 2012).
"TAP is crucial in the diversification of gas sources in Europe through the development of the Southern Corridor from the Republic of Azerbaijan and potentially other countries," said Carlo Malacarne, Snam's chief executive officer.
AOPL-API report: US crude, liquids system growing
The US petroleum liquids pipeline network grew to more than 190,000 miles in 2014, 3.5% more than 2013's total, the Association of Oil Pipe Lines and American Petroleum Institute jointly reported. In 2014, crude oil pipeline mileage increased by more than 5,000 miles, or 9.1% year-to-year, AOPL and API added in their 2015 US Liquids Pipeline Usage & Mileage Report. From 2010 through 2014, US crude pipeline mileage grew more than 12,000 miles, or 22%, it said. "In the time the Keystone XL pipeline was under review, we built the equivalent length of 12 Keystone XL pipelines across the US," AOPL Pres. Andrew J. Black said.
Crude oil pipeline delivery volumes also maintained their strong growth in 2014, the report said. It said that crude pipelines delivered 9.3 billion bbl nationwide that year, nearly 1.1 billion bbl, or 11.8% more, than the previous year.
Other petroleum product deliveries through US pipelines grew by nearly 500 million bbl, or 7.6%, from 2010 through 2014 to 16.2 billion bbl in 2014, the report noted. It said total pipeline deliveries of crude, refined products, and natural gas liquids totaled 16.2 billion bbl in 2014, 8.1% more than in 2013.
"The fall in crude prices during 2014 and 2015 has led to a slowdown in US crude production growth," the report observed. "However, the advantages of pipeline delivery discussed above are fundamental. Operators are optimistic about maintaining existing throughput and constructing new pipelines. Over the long term, there will still be a need for pipeline growth to connect supply areas to demand locations. How these dynamics play out will be reflected in the 2016 usage and mileage report."
