General Interest— Quick Takes
Landrieu lists alternatives to drilling ban
US Sen. Mary L. Landrieu said there are eight ways offshore energy production could move safely forward without imposing a 6-month drilling moratorium in water deeper than 500 ft that could cost Gulf Coast residents tens of thousands of jobs.
In a June 11 letter to US President Barack Obama, Landrieu urged him to reconsider the moratorium that he ordered on May 27 and instead evaluate "a series of fundamental changes to offshore drilling practices that will serve to demonstrably reduce the risk of deepwater drilling while sparing the Gulf Coast's economic vitality."
Her suggestions included allowing deepwater operators to resume "drilling through dirt"—that is, drilling through the targeted oil and gas reservoirs without allowing the hydrocarbon reservoirs to be penetrated. Critical processes associated with drilling and completing deepwater wells based on systemic risk analysis could also be identified, and federal inspectors to examine all surface and subsea well-control equipment currently being used could also be deployed, she said.
She also recommended rigorous inspections of each operator's drilling and casing and completion practices to ensure that well control contingencies are not compromised at any point, and compelling rig operators to demonstrate that they have the emergency power equipment necessary to ensure proper operation.
"I understand and respect your efforts to reduce the risk of a second massive blowout in the Gulf of Mexico," Landrieu said in her letter. "However, I believe that we can demonstrably improve the safety of deepwater drilling without shutting down the Gulf Coast economy for more than 6 months. The proposals will not eliminate all risk, but there are no risk-free ways of producing the energy we rely on today."
Groups say EPA moved too fast on RFS rule
The US Environmental Protection Agency violated the 2007 Energy Independence and Security Act by not meeting the law's deadlines or giving refiners and oil product importers enough time before making the latest federal renewable fuel standard final, two major oil and gas trade associations said on June 10.
"EISA requires that EPA not impose renewable fuel volume obligations without giving producers and importers of gasoline and diesel the full month of lead-time and the full period for compliance specified by the statute," the American Petroleum Institute and National Petrochemical & Refiners Association argued in the brief they filed in the US appeals court for the District of Columbia.
"Here, obligations began to accrue in January, but the RFS2 rule was not published until March and becomes effective only in July," they continued.
The groups said that Congress specifically instructed EPA to set a biomass-based diesel fuel requirement for 2010 at 650 million gal, and that EPA violated this mandate by imposing a "combined" 2009-10 biomass-based diesel requirement of 1.15 billion gal after it was unable to meet the deadline for imposing a 500 million gal biomass diesel obligation for 2009.
"Although the RFS2 rule does not take effect until July 1, 2010, it nevertheless imposes obligations on transactions that occurred before that data," the brief continued. "By imposing such obligations, the RFS2 rule violates the prohibition against retroactive rulemaking, and therefore is invalid."
It said that EPA also did not meet deadlines which Congress adopted to give obligated parties the necessary lead-time to prepare for the RFS2 rule's requirements and a specified period to comply with those requirements. Congress expressly required EPA to promulgate the rule by Dec. 19, 2008, and to publish each year's renewable fuel standard by Nov. 30 of the preceding year, the brief said.
EPA published the RFS2 rule and 2010 renewable fuel standard in late March, nearly 3 months after obligated parties began to accrue obligations under the rule, API and NPRA argued. "Consequently, obligated parties have less than the full year specified by Congress to meet their requirements for 2010," they said.
Senate defeats Murkowski's EPA resolution
The US Senate narrowly defeated a resolution by Lisa Murkowski (R-Alas.) aimed at halting the US Environmental Protection Agency's effort to regulate greenhouse gases under the Clean Air Act. Six Democrats joined all of the Senate's Republicans in supporting the measure, which lost by 47 to 53 votes.
"I had hopes, for the security of our economy, that we would prevail today," Murkowski said following the June 10 vote on whether to consider the resolution. "But regardless of the outcome, I believe it's important that every member of the Senate is on the record on whether they think the EPA regulation is the appropriate way to address climate issues."
EPA began formulating regulations to limit GHG emissions after the US Supreme Court ruled in 2007 that it had the authority to do so. Murkowski, who is the Senate Energy and Natural Resources Committee's ranking minority member, and others in Congress have said that this should be handled legislatively. She introduced her disapproval resolution on Jan. 21 after EPA issued a finding on Dec. 7 that GHGs pose a significant danger to human health and the environment.
"Opponents and supporters of this resolution should agree on one thing: It is the Senate's job to put America on the path to a clean energy future," Sierra Club Executive Director Michael Brune said. "Instead of challenging EPA's authority to keep the air clean and reduce global warming pollution, the Senate must challenge itself to take responsibility and pass strong, comprehensive climate and energy legislation this year and end our oil dependence."
In a statement following the resolution's defeat, the American Petroleum Institute reiterated that the CAA was never intended to address climate change because it was designed to address traditional pollution sources. "EPA's approach could not only discourage investments in domestic oil and gas projects—limiting US production and increasing import dependence—but it is also likely to delay business expansion, hurt job creation and throw state economies into slow motion as they are inundated with added permitting work," it warned.
API urged the Senate to quickly consider a resolution by US Sen. John D. Rockefeller IV (D-W.Va.) which would delay EPA's rulemaking process for 2 years so Congress would have time to address the climate change issue.
Exploration & Development — Quick Takes
Shell, PGS eye fiber optic land seismic gains
Royal Dutch Shell PLC and Petroleum Geo-Services will collaborate to develop an ultrahigh channel count fiber optic land seismic system for exploration and reservoir monitoring.
The quality of land seismic data is inadequate for exploration or reservoir monitoring, said Wim Walk, Shell manager of geophysical technologies.
For example, the ability to obtain profitable recovery factors from complex, low permeability, compartmentalized reservoirs in North America requires a high-resolution view of the subsurface, including the location of fractures, in order to optimize well trajectories, Walk said.
Brazil's Petroleo Brasileiro SA (Petrobras) and PGS signed an agreement June 14 for PGS to install a permanent seabed seismic monitoring system to map fluid flow in Jubarte oil field in the northern Campos basin 77 km off Espirito Santo state. Shell said its technologists recognized the potential of adapting the technology, known as OptoSeis, for use onshore.
It will take several years to develop the onshore system. Shell and PGS will test several prototypes and plan to deploy the first version soon. Location is undecided but probably will be in a Middle Eastern desert basin such as Oman, Walk said.
The scalable system will integrate lightweight cable and fiber optic sensors with 1 million channels compared with about 100,000 channels with existing copper onshore cable, Shell said. Power will not be needed at the nodes. And the sensors can recover a much greater portion of the seismic signal and help cancel noise.
PGS, which recently sold its land seismic acquisition operations, said the Shell collaboration is not a sign PGS is returning to the land seismic business.
The initial Petrobras deployment will cover part of Jubarte field, where the reservoir areal extent exceeds 245 sq km in 1,240-1,350 m of water. Depending on results, the project can grow to cover the entire field, PGS said. The technology involves applying time lapse, four-component seismic.
The data from the system will enable better decisions on well placement and improved-enhanced oil recovery programs, Petrobras said.
Appalachian Weir sandstone lateral cased
NGAS Resources Inc., Lexington, Ky., set pipe on its first horizontal well for oil in Mississippian Weir sandstone in Letcher County, Ky., in the southern Appalachian basin.
The well, with a 2,040-ft lateral at 3,600 ft true vertical depth, is to receive a 10-stage water frac in July. A second well is drilling, and the company is permitting five more for drilling this fall.
The first well, which had oil and gas shows while drilling, offsets six NGAS vertical Weir wells that came on line in early 2010 and are producing oil and gas.
The Weir sandstone, 170-180 ft thick in the area, is the main producing formation in Roaring Fork field on the Kentucky-Virginia line, where 500 Weir wells produce oil and gas. In Amvest field to the southwest, NGAS has 78 vertical Weir producing wells.
The company holds more than 70,000 undeveloped acres in the two fields and plans to develop the Weir horizontally with 100-acre spacing upon successful completion of the initial test wells.
In addition to its Weir tests, the company has completed 55 horizontal Devonian shale wells with laterals as long as 4,500 ft throughout its Appalachian acreage. All 55 wells are connected and producing high-btu gas.
Vaalco oil find off Gabon may be commercial
A group led by Vaalco Energy Inc., Houston, is sidetracking the ETSEM-1 discovery well off Gabon to determine commerciality after the initial wellbore logged oil and said a further sidetrack may be needed.
The Southeast Etame-1 (ETSEM-1) well went to 9,045 ft total depth and cut 16 ft of Gamba sandstone that logged oil full to base. It is in the Etame Development Area 3 miles southeast of Etame field.
The sidetrack under way will seek the oil-water contact, and another sidetrack may be needed to further delineate the prospect, Vaalco said. If Southeast Etame proves commercial, it is expected it can be tied back to the company's existing floating production, storage, and offloading vessel.
ETSEM-1 also found oil shows in deeper Dentale sand reservoirs, but the sands are judged primarily water-bearing at this location. Logging is under way to further evaluate the Dentale sands.
Vaalco will next move the rig to drill a horizontal development in Etame field. A Vaalco subsidiary operates the Etame Marin permit with 28.07% net interest in Etame field. Other permit participants are Addax Petroleum Etame Inc. 31.36%, Sasol Petroleum Etame Ltd. 27.75%, Sojitz Etame Ltd. 2.98%, PetroEnergy Resources Corp. 2.34%, and Tullow Oil Gabon SA 7.5%.
Drilling & Production— Quick Takes
Gjoa platform moves to field off Norway
The semisubmersible production and processing platform for Gjoa oil and gas field off Norway has been towed out after delays related to weather and hull modifications.
The platform, powered by electricity from shore, will handle production from five subsea templates installed on North Sea Blocks 35/9 and 36/7. Production is to start at undisclosed rates in the fourth quarter.
Gjoa, discovered in 1989, has reserves estimated at 82 million bbl of oil and condensate and 40 billion cu m of gas. The gas overlies thin oil pay in several tilted fault segments of Jurassic Viking, Brent, and Dunlin sands at an average depth of about 2,200 m.
Stabilized oil will move through a new 55 km pipeline to the Troll II pipeline and on to the 203,000 b/d Mongstad refinery north of Bergen. A new 130-km gas pipeline will connect Gjoa with the FLAGS pipeline system in the UK sector for transport to St. Fergus, Scotland.
Gjoa, development of which includes the Vega and South Vega satellites, will be the first production in the Sogn area of the Norwegian North Sea. Vega reserves are estimated at 26 million bbl of oil and condensate and 18 billion cu m of gas.
Statoil, with a 20% interest, is operator during development. GDF Suez E&P Norge AS, 30%, will become operator when production starts. Other interests are Petoro 30%, Shell 12%, and RWE Dea 8%.
Saskatchewan carbon dioxide pilot responds
Production has increased to 200 b/d of oil from 48 b/d from an immiscible carbon dioxide pilot flood in Battle Creek field in southwest Saskatchewan, said operator and 100% working interest owner Second Wave Petroleum Inc., Calgary.
The Mississippian Madison reservoir produces 11° gravity oil and associated gas. It averaged 30 b/d in 2009 before flooding began in this year's first quarter. The project is the only natural source immiscible CO2 flood in western Canada.
Source of the flood gas is the Devonian Duperow formation in Battle Creek field, which produces high rates of natural gas with 84% CO2. The pilot area has four producing oil wells that surround a single injector. Pressure response came in early May.
First phase capital spending totaled $1.3 million because existing facilities were used. Project payout is projected in 175 days if production continues at the current level.
The company is moving ahead with second and third stages that will involve two more pilots in geologically similar areas at even lower cost due to use of existing facilities. The company believes it has far more CO2 in Duperow than required to fully flood the Battle Creek Madison pool.
Processing — Quick Takes
Sunoco continues to restructure, sees profit
Sunoco Inc., Philadelphia, is taking another restructuring step and expects its refining business to report a profit for the quarter ending June 30.
The company plans to separate SunCoke Energy Inc. in a transaction, still under study, that might include a tax-free spinoff to Sunoco shareholders.
SunCoke Energy has capacity to make 3.67 million tons/year of metallurgical coke from coal in plants in Virginia, Indiana, Ohio, Illinois, and Brazil.
"The fuels and coke units are distinct businesses with different business models, said Lynn L. Elsenhans, chairman and chief executive officer.
Sunoco last year shut its 150,000-b/d refinery at Eagle Point, NJ, and sold an 85,000-b/d refinery in Tulsa to a unit of Holly Corp., focusing operations on refineries in Philadelphia and Marcus Hook, Pa., and Toledo, Ohio. It also sold its polypropylene business, Sunoco Chemicals Inc., to Braskem SA, and shut down a PP plant in Texas.
Along with poor processing economics facing all refiners, Sunoco faces extra problems, says a report by Deutsche Bank Research.
"Sunoco is a light sweet refinery in a coastal market that is subject to external supply pressure both from Gulf Coast refineries linked to the East Coast by pipelines and imports from European refiners that have excess capacity, excess gasoline production, sufficient diesel margin to keep running," Deutsche Bank says. "Sunoco's crude diet, relatively limited to lighter crudes, over half of which is sources from potentially volatile West Africa, typically prices at a premium, directly reducing margin."
In addition to shedding physical assets, Sunoco has aggressively cut costs and staff.
"We are beginning to see the results of our business improvement initiatives positively impact our performance," Elsenhans said. "The actions we've taken, coupled with a slight improvement in market conditions, have brightened our immediate outlook for Sunoco's refining and supply business. Nevertheless, business conditions remain difficult, requiring our continued focus on operating excellence and achieving a sustainable, lower cost structure."
Spectra announces Montney gas processing plant
Spectra Energy announced June 10 it is building a 200 MMcfd natural gas processing plant west of Dawson Creek to service the Montney shale in northeast British Columbia.
Construction of the Dawson processing plant, pending regulatory approval, will take place in two phases, with the first 100 MMcfd available in late 2011 and the remaining capacity available in early 2013.
Spectra said capacity at the plant had already been fully contracted by long-term agreements with customers.
Canada's National Energy Board in late March approved construction by Spectra's BC Field Services subsidiary the 250-MMcfd Fort Nelson gas processing plant 75 km northeast of Fort Nelson, BC. The plant will serve increased shale gas production from the Horn River basin (OGJ Online, Apr. 6, 2010).
NEB forecast in April that deliverability from the Montney play would increase to 1.5 bcfd from 387 MMcfd by 2012, even following the middle of three pricing scenarios it used in the forecast (OGJ Online, Apr. 26, 2010). Horn River deliverability using the same pricing would rise to 462 MMcfd from 41 MMcfd by 2012, according to the forecast.
Transportation — Quick Takes
Peru LNG undergoes commissioning
Inauguration of South America's first LNG plant took place earlier this month. At $3.8 billion, Peru LNG represents the largest investment in a single project ever made in Peru, according to the announcement by the owning consortium.
Start-up of the Melchorita plant, at KP 170 of the South Pan American Hwy, also incorporated commissioning a 253-mile pipeline and a marine terminal. The plant has a nominal capacity of 4.4 million tons/year and will process 620 MMcfd of natural gas.
In addition, at the plant site are the two largest storage tanks in Peru (130,000 cu m of LNG each) and a marine terminal that stretches more than 1 km long and will receive tankers of 90,000 to 173,000 cu m each.
The consortium reported the project includes installation of pipeline infrastructure to serve the Peruvian market. Under an agreement, recently approved by Peru's Ministry of Energy and Mines, with Transportadora de Gas del Perú SA, which operates the Camisea natural gas and NGL pipelines, the Peru LNG pipeline will provide up to 550 MMcfd of capacity for the Peruvian market, said the announcement. That, it said, will debottleneck gas transportation to "bring more gas to power generation companies, industrial companies, vehicles running on natural gas, and Peruvian homes using natural gas for heat."
Four energy companies form Peru LNG: Hunt Oil Co. (US; 50%), SK Energy (South Korea; 20%), Repsol-YPF (Spain; 20%), and and Marubeni Corp. (Japan; 10%). This consortium was specifically set up to develop, build, and operate Peru LNG.
Among construction contractors were CB&I, Houston, in charge of the plant's engineering, procurement, and construction; CDB consortium (Saipem, Jan de Nul, and Odebrecht), in charge of marine terminal EPC, and Techint, responsible for installing the pipeline.
Such Peruvian companies as Graña & Montero, Cosapi, Translei, Minera San Martin, Cosmos, Aceros Arequipa, Tecnicas Metalicas, Esmetal and Sima, among many others, also contributed to the project, said the consortium.
KMEP launches Marcellus NGL line open season
Kinder Morgan Energy Partners LP launched a 30-day nonbinding open season June 14 to further gauge shipper interest for its Marcellus lateral project, providing Marcellus shale natural gas liquids transportation to fractionation plants and petrochemical facilities near Sarnia, Ont.
The initial project would include about 230 miles of new pipeline from the Marcellus shale in southern Pennsylvania to the Cochin interconnect at Riga, Mich. From Riga, the company anticipates product will travel through its existing Cochin system to Windsor, Ont., and then through the Windsor-Sarnia Pipeline to Sarnia.
KMEP, however, also anticipates reversing the eastern leg of its Cochin line to move NGL from Riga to Chicago, where it expects to build an additional pipeline to connect to existing fractionation facilities, refineries, and chemical plants (OGJ Online, Apr. 21, 2010).
Subject to regulatory approvals and necessary investments, KMEP says Marcellus NGL shipments could begin as soon as mid-2012. KMEP anticipates moving more than 150,000 b/d through the system at a rate as low as 9¢/gal, given sufficient shipper support.
Cochin is a 1,900-mile, 12-in. OD multiproduct pipeline operating between Fort Saskatchewan, Alta., and Windsor, passing through the Chicago market on the way. The pipeline, with a capacity of 70,000 b/d, includes 31 pump stations spaced at 60-mile intervals and five US propane terminals. It currently transports only propane. Underground storage, owned by third parties and KMEP, is available at Fort Saskatchewan and Windsor.
CPGT starts Carthage-to-Perryville open season
CenterPoint Energy Gas Transmission Co. (CEGT), an indirect, wholly owned interstate natural gas pipeline subsidiary of CenterPoint Energy Inc., started a nonbinding, 3-week open season June 14 to gauge market interest in an additional expansion of its nearly 1.9 bcfd, 42-in. OD Carthage-to-Perryville (Line CP) pipeline.
The expansion would support shipment of gas produced from the Haynesville shale for delivery into the Perryville Hub and Carthage area delivery points.
CenterPoint says it could have the expansion in service by fouth-quarter 2012 depending on shipper interest and regulatory approvals.
In addition to supplying Midwest and Northeast markets via Perryville Hub the expansion could move incremental gas into southeast markets through the Southeast Supply Header. CenterPoint said it will also evaluate options for deliveries and interconnectivity of natural gas at Carthage, providing access to Texas markets.
In April 2010 CenterPoint Energy Field Services Inc. announced a 250-MMcfd expansion of its Magnolia gathering and treating system to process production being developed by subsidiaries of Encana and Shell, adding to a 750-MMcfd expansion of the system announced in September 2009 (OGJ Online, May 3, 2010).
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