GENERAL INTEREST — Quick Takes
IPAA rejects CRUDE claim about oil export decision
The Independent Petroleum Association of America rejected claims a coalition of four independent US refiners made in a Sept. 4 letter to the US Department of Commerce that a late-June decision making two producers' crude oil condensates eligible for export was wrong.
The decision by DOC's Bureau of Industry and Security (BIS) (OGJ Online June 30, 2014) to allow Pioneer Natural Resources and Enterprise Product Partners to export upgraded condensate as a petroleum product did not meet exceptions in the 1975 Energy Policy and Conservation Act, which banned US crude exports, a lobbyist representing Consumers & Refiners United for Domestic Energy (CRUDE) said in the Sept. 4 letter.
CRUDE asked DOC to reexamine the decisions and announce there would not be similar rulings in the future, Jeffrey J. Peck, principal at Peck Madigan Jones, said in the letter to three DOC officials.
"CRUDE's depiction of the BIS actions inexplicably mischaracterizes the relevant facts of the decisions, while ignoring the broader benefits of the decisions to US national security and the economy," IPAA said in a Sept. 8 statement.
"Contrary to CRUDE's assertions, BIS did not create any 'exceptions or exemptions' from the regulations that govern the export of crude oil," it said. "BIS simply applied the existing regulations to two specific factual situations-an action that is fully within BIS's authority and responsibility. In fact, BIS makes such commodity classification decisions regularly under [federal Export Administration Regulations]."
By ignoring the fact that there are no limits on US refined product exports, CRUDE's real complaint about the BIS classification decisions is that producers have an alternative means to process crude and sell the resulting products outside the US, IPAA stated.
Eni acquisition of Nigerian stake probed
Eni SPA said it is cooperating with authorities in Milan investigating its 2011 acquisition of an interest in a block offshore Nigeria from a Royal Dutch Shell PLC subsidiary.
The investigation concerns the acquisition by Eni unit Nigerian Agip Exploration (NAE) of a 50% interest in OPL 245 from Shell Nigeria E&P Co. NAE became operator of the license, where it is appraising deepwater Zabazaba oil field. The Shell unit retained a 50% interest.
Eni denied illegal conduct in the acquisition, saying it entered into related agreements only with the Nigerian government and Shell.
"The entire payment for the issuance of the license to Eni and Shell was made uniquely to the Nigerian government," Eni said in a statement.
It said Chief Executive Officer Claudio Descalzi and Chief Development, Operations, and Technology Officer R. Casula are under preliminary investigation by the Milan prosecutor's office.
Miller seeks Buccaneer's Alaskan assets
Miller Energy Resources Inc., Knoxville, Tenn., has signed a nonbinding letter of intent to buy Alaskan operating assets of Buccaneer Energy for $40-50 million.
Buccaneer, based in Sydney, Aus., has been liquidating assets in a recapitalization program. It has onshore and offshore operations in Alaska's Cook Inlet and along the US Gulf Coast.
Miller Energy said the acquisition from Buccaneer, if completed, would involve about 1.9 MMboe of proved oil and gas reserves and 1,700 boe/d of production. It has existing producing and processing assets in the Cook Inlet.
Wintershall to acquire interests off Norway
Wintershall has agreed to acquire a package of production, development, and pipeline interests offshore Norway from Statoil for $1.25 billion.
The deal will increase Wintershall's interests in Gjoa oil and gas field to 20% from 5% and in Vega oil and gas field to 54.5% from 30%. Both fields are in the northern North Sea. Wintershall will become operator of Vega.
The deal also will provide the company new interests of 24% in the Aasta Hansteen gas field development in the Norwegian Sea and a 19% interest in the Asterix natural gas discovery in the Norwegian Sea. Wintershall will make an additional payment of as much as $50 million if Aasta Hansteen development proceeds according to the current project plan.
Wintershall also will gain a 13.2% interest in the Polarled gas-transport system in the Norwegian Sea and 10% interests in four licenses under exploration.
Wintershall estimated the interests represent reserves and reosurces of 170 million boe.
India okays sale of 5% interest in ONGC
The government of India has approved the public sale of a 5% interest in state-owned Oil & Natural Gas Corp. as part of a broader divestment program.
The Cabinet Committee on Economic Affairs approved the sale, along with interests of 10% in Coal India Ltd. and 11.36% in NHPC Ltd., which generates hydroelectricity.
The state holding in ONGC, India's largest state-owned producer of oil and natural gas, now is 68.94%. The government sold a 5% interest in the company in 2012.
The government also is selling interests in state-owned companies outside the energy industry.
Exploration & Development — Quick Takes
Eni makes major oil discovery offshore Angola
Eni SPA has made an oil discovery on Block 15/06 in the Ochigufu exploration prospect offshore Angola. It is the 10th commercial oil discovery for the block, and is estimated to hold 300 million bbl of oil in place.
The Ochigufu 1 NFW well was directionally drilled by the Ocean Rig Poseidon drilling unit in 1,337 m of water, reaching a total depth of 4,470 m. Eni says it found 47 m of proved net oil pay of 34° gravity in the Lower Miocene and Oligocene sandstones. Data acquired in Ochigufu 1 indicate a production capacity of more than 5,000 b/d of oil. Studies are under way to evaluate an early tie-in to the 100,000-b/d Ngoma FPSO vessel that lies in the nearby West Hub oil development project, which would enable Ochigufu 1 to be "brought into production in record time," the company says.
Separately, production startup of the West Hub project is expected by yearend. The East Hub oil development project has also been sanctioned.
Eni is operator of Block 15/06 with 35% interest. Partners are Sonangol P&P 30%, SSI Fifteen Ltd. 25%, Falcon Oil Holding Angola SA 5%, and Statoil Angola Block 15/06 5%. Eni also operates Block 35 in the deepwater Kwanza basin off Angola.
Senex, Beach JV makes oil discovery in Eromanga basin
A joint venture of Senex Energy Ltd. and Beach Energy Ltd. has made an oil discovery in its Martlet-1 wildcat in the Eromanga basin of South Australia.
The find, made in the Mesozoic age Namur Sandstone in permit PEL 104, intersected 6 m of net oil pay at 1454 m below the surface.
It is the first oil discovery in the permit and confirms the extension to the north of the play that has previously contained oil at fields such as Bauer, Callawonga, and others further south.
Martlet-1 also demonstrates the worth of the oil program in the Western Flank of the Cooper-Eromanga basin in South Australia.
Senex is operator of PEL 104 with 60% interest. Beach has the remaining 60%.
Drilling & Production — Quick Takes
Millionth barrel pumped from Prirazlomnoye field
JSC Gazprom Neft reports producing the millionth barrel of oil from the Prirazlomnoye field in the Pechora Sea, 60 km offshore in the Russian Arctic shelf.
Production began in December 2013, and the first delivery of oil by tanker to the global market occurred in April (OGJ Online, Apr. 21, 2014). The company said a second tanker is being loaded for consumers in northwestern Europe, and two additional shipments are expected by yearend, which would bring the total to 2.2 million bbl.
"Gazprom Neft is the first company to extract oil on Russia's Arctic shelf," said Alexander Dyukov, chairman of the company's management board. He said the production milestone is "further proof of the consistent development of the project and its final transition into full-scale development."
The Prirazlomnoye platform has one production well. An injection well is being drilled. The project will involve 19 production wells, 16 injection wells, and 1 absorption well.
AER okays low-pressure steamflood at Primrose East
Alberta Energy Regulator has approved an application by Canadian Natural Resources Ltd. to convert to low-pressure steamflooding at its Primrose East Area 1 bitumen project.
AER said the bitumen production method involves steam injection "at much lower pressures" than the previous method of high-pressure cyclic steam stimulation. The agency's approval followed "a comprehensive technical review."
AER's investigation continues into "flow-to-surface (FTS) events" at Primrose East and South on the Cold Lake Air Weapons Range. CNRL has reported four FTS releases of bitumen since May 2013, AER said (OGJ Online, Aug. 2, 2013).
AER directed CNRL in the summer of 2013 to enhance monitoring at Primrose. Monitoring remains in place and will assess any impacts of low-pressure steaming.
In July, AER released the results of an independent technical review of the 2013 incidents (OGJ Online, July 22, 2014). The main contributing factors were "the steaming strategy" and "wellbore issues."
Statoil to suspend second semi off Norway
Statoil ASA will lay up a second semisubmersible drilling rig that it says exceeds the needs of its current program offshore Norway.
It will suspend work by the COSL Drilling Europe Pioneer semi in the fourth quarter when the rig completes work in Visund oil and gas field in the Norwegian North Sea.
Statoil said the suspension period will be shorter than that of the Saipem Scarabeo 5 semi, which will begin at the end of this month and last through yearend.
The operator said the suspensions will not affect its production targets or plans to drill 20-25 exploration wells on the Norwegian shelf this year.
PROCESSING — Quick Takes
ESAI: Rising distillation capacity to hasten closures
A wave of new distillation capacity over the next year will lead to additional refinery closures, particularly for operators in Europe, according to a recent report from ESAI Energy LLC.
Compared with capacity growth of less than 300,000 b/d during the past year, the addition of nearly 2 million b/d in global distillation capacity over the next 12 months will undermine the profitability of marginal European refiners, who will be under pressure to reduce regional capacity by 250,000-300,000 b/d within the same period, ESAI Energy said in its recently published Global Outlook.
"The wave of new capacity makes 2015 a turning point for Europe's refining sector," said Christopher Barber, ESAI Energy's manager of refining.
Wider diesel spreads this fall might temporarily give European refiners some breathing space, but new capacity abroad in 2015 will make Europe's refineries even less profitable than during previous years, according to Barber (OGJ Online, Dec. 2, 2013).
By 2015, Europe will need to cut its refining capacity by more than 250,000 b/d simply to sustain minimal operating rates similar to those maintained over the past 4 years, Barber said.
The most substantial rise in distillation capacity will occur in Asia-Pacific, where rationalization in Japan and Australia over the last year led to capacity reductions that more than offset new regional capacity, according to ESAI Energy, who projects a 950,000-b/d net capacity for OECD Asia-Pacific during the coming year.
ESAI Energy said it also expects the completion of major refinery projects under way in Saudi Arabia and UAE within the next 12 months will add about 900,000 b/d of capacity in the Middle East, with additional capacity expansions also projected during the same timeframe for refineries in the Americas.
Qatar Shell lets contract for Pearl GTL
Qatar Shell Ltd., a unit of Royal Dutch Shell PLC, has let a contract to Cape PLC to provide multidisciplinary maintenance services for its Pearl gas-to-liquids (GTL) plant in Ras Laffan Industrial City, Qatar.
Under the 5-year contract, which includes a 1-year extension option, Cape's Qatar operations will provide the Pearl GTL plant scaffolding, painting, insulation, and refractory services, Cape said in a Sept. 10 release.
A value of the contract was not disclosed.
Shell is operator of the Pearl GTL plant under a development and production-sharing agreement with Qatar Petroleum.
Major construction on Pearl GTL, launched in July 2006 (OGJ Online, July 27, 2006), was completed in 2010, with the gas processing plant starting production of condensate, LPG, and sulfur in March 2011 (OGJ Online, Mar. 23, 2011).
The plant ramped up to its full GTL production of 140,000 b/d near the end of 2012.
In addition to producing kerosene, gas oil, and naphtha from GTLs, the Pearl GTL plant also uses Shell's patented process of converting natural gas into a clear base oil to produce Shell PurePlus technology base oils, which were formally introduced to the global market in a series of phased releases beginning in early 2014.
Pemex lets contract for Salamanca refinery
Mexico's Petroleos Mexicanos (Pemex) has let a contract to South Korea's Samsung Engineering Co. Ltd. for the execution of an ultralow-sulfur diesel (ULSD) project at its Antonio M. Amor refinery in Salamanca, in Guanajuato state.
The $80 million contract, awarded on an open-book cost estimation basis, covers Phase I of the project, which includes detail engineering and procurement of long-lead items, Samsung Engineering said.
Samsung Engineering's design will include a 38,000-b/d hydrodesulfurization (HDS) unit as well as the revamping of the refinery's existing 53,000-b/d HDS unit, the company said.
Initial engineering for Phase 1 of the project is scheduled to be completed in September 2015, Samsung Engineering said.
A second leg of the project, Phase 2, will include the rest of detail engineering, procurement, construction, and commissioning. Samsung Engineering, however, did not disclose further details regarding this stage of the project.
The Salamanca refinery upgrade is part of Pemex's $2.8 billion plan to increase ULSD production at five of Mexico's refineries. Upon unveiling details of the fuel quality project earlier this month, Pemex confirmed the total value of Samsung Engineering's contract for the Salamanca project at about $359 million (OGJ Online, Sept. 15, 2014).
TRANSPORTATION — Quick Takes
Uneven effects seen from new Appalachian lines
Producers in the Appalachian basin will benefit unevenly from markets opening for natural gas from the Marcellus and Utica shales, according to a Canaccord Genuity analyst.
Pipeline projects due on stream soon will alleviate a surplus in the southwestern part of the basin, wrote Karl Chalabala in a mid-September report on an updated supply-demand model.
But the gas price will remain weak in the northeastern Appalachian basin until markets begin opening for supply there in 2016-unless operators ease drilling or curtail production.
Chalabala said pipeline capacity will begin to exceed need in the southwestern Appalachian basin at the end of this year. Overall system expansions beneficial to northeastern operators won't occur until the second half of 2016, according to an analysis that focuses on takeaway capacity by omitting projects that will move gas largely within the region.
Most capacity expansions directly benefiting producers in the northeastern part of the play will occur after the first half of 2017, the analyst said.
Beyond 2016, new approvals for LNG exports, increased replacement of coal by natural gas in power generation, and growth in the industrial market paint "a robust and improving demand picture" for the basin, he said.
Utilities report New England gas line expansion
Spectra Energy Corp., Spectra Energy Partners, and Northeast Utilities (NU) plan to build the 1-bcfd Access Northeast natural gas pipeline expansion project, designed to increase gas supplies to New England. Spectra says the project will enhance the Algonquin and Maritimes pipeline systems, using existing routes. The companies expect Access Northeast to enter service November 2018. Spectra Energy and NU will be equal partners in the project, with the option of additional partners joining.
NU says that over the past 15 years, natural gas-fired generation has grown from serving 15% of New England's annual electric requirements to serving about half. The expansion includes:
• Scalable expansion of existing pipeline infrastructure, attached to roughly 60% of Independent System Operator-New England's natural gas generation capacity.
• Partnering with existing regional storage assets to provide firm services to electric power plants with guaranteed natural gas supplies on peak days and to enable rapid response to sudden changes in power output.
• Additional Algonquin and Maritimes delivery points for local distribution companies.
The companies describe Access Northeast as a compliment to Spectra's previously announced Algonquin Incremental Market (AIM) (OGJ Online, Sept. 26, 2013) and Atlantic Bridge projects. AIM will begin to debottleneck the pipeline system by first-quarter 2017, underpinned by long-term commitments from southern New England gas utility companies. Atlantic Bridge's proposed in-service date is November 2017, and it will be similarly supported by gas utilities, according to Spectra, delivering 100 MMcfd to more than 600 MMcfd depending on market commitments.
Access Northeast will cost roughly $3 billion.
Pembina adds more lines to Phase III expansion
Pembina Pipeline Corp. plans to enlarge its previously announced Phase III pipeline expansions by building a new 16-in. OD pipeline from Fox Creek, Alta., to Namao, Alta., and a new 12-in. OD pipeline from Wapiti, Alta., to Kakwa, Alta. The 16-in, pipeline will run 270 km in the same right-of-way as the previously proposed 24-in. OD pipeline from Fox Creek to Namao (OGJ Online, Sept. 5, 2014).
Pembina expects the two pipelines to have a combined initial capacity of 420,000 b/d, reaching more than 680,000 b/d with the addition of midpoint pump stations. Pembina has 289,000 b/d, or 69% of initial combined capacity, under contract and expects the lines to enter service late-2016 to mid-2017.
Completion of the lines will bring total capacity between Fox Creek and Namao to more the 1-million b/d, transporting propane-plus, ethane-plus, condensate, and crude oil in four separate pipelines. The expansions will also provide ratable delivery of propane-plus and ethane-plus to regional fractionators, including Pembina's own Redwater fractionator. Pembina earlier this year reaching binding commercial agreements to add a third fractionator-55,000 b/d propane-plus-at Redwater, boosting the site's eventual capacity to 210,000 b/d (OGJ Online, May 13, 2014).
The company intends the 70-km Wapiti-to-Kakwa Pipeline to debottleneck a portion of Pembina's existing pipeline system, adding an initial 95,000-b/d capacity and ultimately allowing deliveries into the core segment of the Phase III Expansion between Fox Creek and Namao. Pembina also plans to build two new pump stations as part of this project. Subject to regulatory approval, Pembina expects the Wapiti-to-Kakwa Pipeline enter service between late-2016 and mid-2017 as well.
Pembina expects the two new expansions to cost a total of $435 million, bringing overall estimated cost of the Phase III Expansion to $2.44 billion.
EIA: Gas storage deficit to 5-year average narrowing
Natural gas storage injections continued to outpace the 5-year (2009-13) average, with inventories as of Sept. 5 at 2.8 tcf, according to data from the Weekly Natural Gas Storage Report by the US Energy Information Administration.
Due to an unusually cold winter during 2013-14, gas inventories ended March 2014 almost 1 tcf lower than the 5-year average. As of Sept. 5, relatively higher weekly net injections into storage reduced that deficit to 463 bcf.
EIA's latest Short-Term Energy Outlook expects that this trend will continue, with forecast inventories of 3.47 tcf by the end of October, 355 bcf below the 5-year average and the lowest end-October level since 2008.
However, increasing new production is expected to mitigate the effect of these lower inventories on winter natural gas markets, as evidenced by decreasing seasonality in natural gas futures contracts.
"Although the injection season began slowly, injections have exceeded their average comparable-week levels in each week since Apr. 18," EIA said.
Strong US production growth and mild demand have supported strong injections through the summer. Dry natural gas production increased to 70.2 bcfd in June, up nearly 6% from a year earlier, while mild weather reduced natural gas use for electric generation.
Natural gas prices have also fallen during the injection season.
