Proposed bill aims to speed drilling permit process
US Rep. Mike Coffman (R-Colo.) introduced legislation that would require quicker decisions by the US Department of the Interior on onshore oil and gas drilling permit applications on public lands.
HR 2375 would require DOI officials every year to identify 200 onshore leases with the highest energy potential on land the US Bureau of Land Management oversees each year and move them through the permitting process in 180 days. BLM says it takes an average 200 days to process a drilling permit application, but the actual waiting time for many permits is closer to 2 years, Coffman said.
Noting the Obama administration's June 23 announcement that it plans to release 30 million bbl of oil from the Strategic Petroleum Reserve in response to higher prices, Coffman said the administration should simply stop standing in the way of more US oil and gas development instead.
"We are sitting on enough of our own energy resources that we could lower energy costs, stimulate the economy, and promote energy independence in the US if the government only allowed us to produce them," he maintained.
Coffman, a member of the Natural Resources Committee, said a January BLM public lands statistical report showed more than 2,400 new oil and gas leases were issued and 2.6 million acres were leased on BLM land in 2008. In 2010, he continued, there were only 1,300 new leases and 1.3 million acres leased.
He said HR 2375 has the support of the Western Energy Alliance, which represents Rocky Mountain independent producers, and the Colorado Oil & Gas Association.
USGS releases Alaskan OCS knowledge gap study
The US Geological Survey released a study on June 23 identifying gaps in scientific knowledge about the Alaskan portion of the US Outer Continental Shelf, particularly the Beaufort and Chukchi seas. US Sec. of the Interior Ken Salazar ordered the study in March 2010 to better inform decisions regarding oil and gas development there.
"There is significant potential for oil and gas development in US Arctic waters, but this is a frontier area with harsh weather conditions as well as unique fish and wildlife resources that Alaska's indigenous people rely on for subsistence," Salazar said. "To make responsible decisions, we need to understand the environmental and social consequences of development and plan accordingly."
The 279-page report contains more than 50 findings and an equal number of recommendations. They include developing a better understanding of climate change effects on Arctic physical, biological, and social conditions as well as resource management strategies; developing geospatial data on the Arctic OCS; synthesizing existing scientific information; and building on advances in spill-risk evaluation and knowledge by developing better information on key inputs to spill models.
USGS Director Marcia K. McNutt said the team that prepared the study examined more than 400 scientific publications, workshop findings, and science policy documents; met with more than 40 individuals and organizations with research and science assessments in those areas; and held a series of discussions with oil and gas industry, North Slope and Native Alaskan interests, Alaska's state government, and nongovernmental organizations.
The report summarizes a large volume of existing scientific information about the area, much of which was conducted under the US Bureau of Ocean Energy Management, Regulation, and Enforcement's Environmental Studies Program.
EPA outlines schedule for updating boiler standards
The US Environmental Protection Agency plans to propose updated air emission standards for boilers and certain solid waste incinerators by Oct. 31. EPA intends to issue final standards by Apr. 30, 2012.
EPA outlined its schedule as part of a filing with the US Court of Appeals for the DC Circuit. Multiple industry groups had petitioned EPA to delay the effective date of updated standards. In May, EPA delayed the effective date, saying more public review and agency reconsideration was required.
Previously, EPA received more than 4,800 comments from businesses and communities, including the National Petrochemical & Refiners Association and the American Petroleum Institute, regarding boiler standards proposed during 2010.
The new boiler rule sets standards to reduce air emissions of mercury, organic air toxics, and dioxins (OGJ Online, Feb. 4, 2011).
Eight Scotian margin deepwater blocks offered
The Canada-Nova Scotia Offshore Petroleum Board has issued a call for bids on eight deepwater parcels in an unexplored area of the Atlantic off Nova Scotia, four of which were nominated by industry (see related article, p. 48).
The parcels cover 228,120-344,340 ha each in 950-4,100 m of water at least 200 km south-southeast of Halifax. The primary term is 6 years with a possible 1-year extension if a well is in progress. Bids are to be considered based on the amount of money to be spent. Minimum work expenditure is $1 million.
The board will only accept bids from companies that have experience drilling exploratory wells in more than 800 m of water in the past 10 years. Bid deadline is Jan. 10, 2012. The board is preparing an environmental assessment and seeks public comments by Dec. 20 on the lands offered.
A play fairway analysis by the Offshore Energy Technical Research Association provides strong evidence for early Jurassic restricted marine oil-prone source rock along the southwestern Scotian margin beneath the offered parcels. The parcels are located in a major salt basin with numerous untested salt-related turtles, salt flank, folds, and rotated block structures.
Repsol Sinopec has two-zone Campos basin find
Repsol Sinopec, Statoil, and Petroleo Brasileiro SA (Petrobras) have made an ultradeepwater, light oil discovery in the Campos basin presalt area off Brazil.
The companies said they had informed Brazilian authorities of the existence of traces of hydrocarbons in one formation in March and a second level in April. They didn't disclose the extent or other details of the apparent discovery of good-quality oil in the 1-REPF-11A-RJS well, informally known as Gavea.
However, they called the discovery "the most significant made in the presalt area of the Campos basin."
The well went to 22,477 ft in 8,885 ft of water 190 km off Rio de Janeiro. The companies are analyzing results before continuing with exploratory and evaluation work in the area. The Stena Drillmax I drillship drilled Gavea.
Repsol Sinopec, with a 35% stake, is the operator. Statoil has 35% and Petrobras has 30%.
Repsol Sinopec is the largest foreign owner of exploration rights in the Santos, Campos, and Espirito Santo basins, operating 6 of the 16 blocks in which it participates.
Oil find indicated south of Oseberg South
Statoil and two partners, after having drilled six exploratory wells on Block 30/11 south of Oseberg South field off Norway without commercial success, have proved a column of good-quality reservoir rock about 200 m thick.
Data are still being gathered at the Krafla exploratory well, but results so far clearly indicate that it is an oil discovery with 12.5 to 56.5 million bbl of oil equivalent recoverable and several follow-up opportunities, Statoil said. Krafla is Statoil's first operated well on the license.
The 30/11-8 S Krafla well went to 3,822 m true vertical depth below sea level in the Lower Jurassic Dunlin Group in 107.5 m of water in PL035. It proved hydrocarbons in the primary target Middle Jurassic Brent Group.
When Krafla is complete, the Ocean Vanguard semisubmersible will spud a planned sidetrack called Krafla West, also a Brent Group target. Krafla, 26 km south of Oseberg South, could be placed on production quickly and help extend the lift of existing installations. It likely will be tied back to a subsea installation in the Oseberg area.
Licensees in PL035/PL272 are Statoil operator with 50% interest and DNO ASA and Svenska Petroleum Exploration AS, 25% each.
Krafla is 16 km from the Katla prospect, proven in 2009, for which Statoil recently submitted a plan for development and production.
Southeast extension buoys Norway's Avaldsnes
Lundin Norway AS has confirmed a southeasterly extension of its Avaldsnes field in the North Sea off Norway and will sidetrack the 16/3-4 appraisal well to confirm the lateral continuity of the reservoir towards the west.
The 16/3-4 well, 6.5 km southeast of the 16/2-6 discovery well in PL501, proved an oil column of 13.5 m in Jurassic sandstone of excellent quality, Lundin said.
A high net to gross has resulted in net pay at the appraisal location in excess of that at the discovery well, the company said without giving pay thickness. Porosity averages 30%, and permeability is several darcies.
The production rate averaged more than 5,500 b/d of oil equivalent on a 60⁄64-in. choke. Total depth is 2,020 m.
The company said, "We will now sidetrack the appraisal well to provide information regarding the lateral continuity of the reservoir towards the part of the structure we had assumed in our previous resource estimates was nonhydrocarbon bearing. We will update our Avaldsnes resource estimates following the sidetrack and second appraisal well."
The Bredford Dolphin semisubmersible will spud the second appraisal well on Avaldsnes, 16/2-7, immediately after 16/3-4.
Lundin Norway is operator with 40% interest. Partners are Statoil Petroleum AS 40% interest and Maersk Oil Norway AS 20%.
North Falkland well yields oil at commercial rates
An appraisal well at Sea Lion field in the North Falkland basin has produced oil at commercially viable rates, said Rockhopper Exploration PLC.
The 14/10-5 appraisal well stabilized at 5,508 stb/d and achieved a maximum stabilized rate of 9,036 stb/d.
A total section of 86 m, incorporating 79 m of reservoir, was perforated at 2,379-2,465 m measured depth over the Sea Lion main fan complex. No lower fan sands were perforated on this test.
The well produced for a main 48-hr period at a stabilized rate of 5,508 stb/d of oil and 940 Mscfd of gas with 783 psi flowing wellhead pressure on a 48⁄64-in. choke with a gas-oil ratio of 170 scf/stb.
The well was produced through a separator under artificial lift by means of a downhole electric submersible pump. The producing wellhead temperature was 62° C., sharply higher than that achieved during the test of well 14/10-2, and demonstrates the highly effective nature of the vacuum insulated tubing (VIT) used during the test at 14/10-5. No wax inhibitors or pour point suppressants were used, and no water or hydrogen sulfide were produced during the test.
During a second main test period the final maximum rate was 9,036 stb/d at 625 psi wellhead pressure on a fixed 1-in. choke over a 2-hr period before the well was shut-in for a final build-up and injectivity tests. The GOR during this test period was 153 scf/stb. Surface and downhole crude oil samples were collected for analysis.
Downhole mini drillstem tests were also performed on two of the three sands making up the 14 m of net pay encountered in the well, which form part of the lower fan. These two sands had net pay of 8 m and 4.5 m.
Interpretation of the results of the mini DSTs indicate that these two sands could have contributed an additional 800 stb/d flow rate using the same test techniques (artificial lift by ESP and thermal insulation by VIT) as used during the main DST performed on the upper fan in well 14/10-5.
The company said, "Rockhopper's board views the flow rates achieved as being commercially viable." Further appraisal drilling is being progressed over the coming months to continue to define the extent of the Sea Lion resource.
The Ocean Guardian semisubmersible will now drill 14/10-6, third appraisal well in the Sea Lion discovery area and 4.5 km west of well 14/10-5.
Drilling & Production — Quick TakesHibernia South Extension oil production starts
ExxonMobil Canada Properties has started oil production from the Hibernia South Extension project on the Grand Banks off Newfoundland and Labrador.
Oil flowed from the Hibernia South Extension Unit KK well on June 25, said provincial energy firm Nalcor Energy Oil & Gas, which has a 10% working interest in the development.
Press reports said the well is the first of four production wells to be drilled from the Hibernia field platform. Hibernia South Extension ultimate recovery is expected to be 220 million bbl of oil (OGJ Online, June 16, 2009).
The four production wells will provide data about the formation's production characteristics, enabling ExxonMobil to optimize the number and placement of water injection wells. As many as five injection wells will be drilled later from a mobile offshore drilling unit.
Hibernia field, which started up in 1997, itself is averaging 175,000 b/d, surpassing its production averages for 2008, 2009, and 2010. The higher rate is attributable to an extended reach well which at more than 10,000 m is Canada's longest wellbore.
In addition to the Hibernia South Extension, Nalcor is a participant in two other offshore developments: the White Rose Growth Project and Hebron project.
First production from the White Rose Growth Project-North Amethyst field, in which Nalcor has a 5% working interest, began on May 31, 2010. Nalcor also has a 4.9% working interest in the Hebron project, which anticipates first oil production in 2017.
Nalcor's partners in the Hibernia South Extension are ExxonMobil Canada, Suncor, Chevron Canada Ltd., Murphy Oil, Canada Hibernia Holding Corp., and Statoil Canada Ltd.
Statoil to use big, new jack up off Norway
Statoil has let a 5-year contract for an ultralarge, high-specification, harsh-environment jack up rig for use on the Norwegian continental shelf.
The West Elara is under construction at Sembcorp Marine's Jurong Shipyard in Singapore for North Atlantic Drilling, a subsidiary of Seadrill Ltd.
Sembcorp said the rig will be Singapore's largest jack up newbuild.
The rig will be able to drill to 10,670 m in up to 150 m of water. It will have higher variable deckload and higher operating efficiency than jack ups of previous generations, Sembcorp said.
Sembcorp will build another jack up of the same class, the West Linus, for Seadrill at Jurong Shipyard.
Also planned or under construction for Seadrill at the Sembcorp subsidiary are the West Capricorn ultradeepwater semisubmersible, the West Leo semi, and the West Tucana and West Castor jack ups.
PROCESSING — Quick TakesDownstream cost index reaches record high
Design and construction costs for refining and petrochemical projects rose for the fourth consecutive 6-month period to a record high, according to the IHS CERA Downstream Capital Costs Index.
The proprietary index, which uses 2000 as the base year with a value of 100, rose to 192 in the first quarter of 2011 from 180 in the third quarter of 2010 (OGJ, Nov. 29, 2010, Newsletter).
The 6% increase was the largest rise since the previous peak in third-quarter 2008.
A 12% rise in steel costs strongly influenced the recent surge and helped push up equipment costs.
Other cost increases included construction labor 8% and engineering and project management 5%.
NGL fractionation scheduled for Texas production
Enterprise Products Partners LP, Houston, plans to build a 75,000-b/d NGL fractionator at its Mont Belvieu, Tex., site. The plant, sixth in the company's push, will accommodate continued growth of liquids-rich natural gas production from Texas's Eagle Ford shale basin, the company said.
Anticipating the expansion, Enterprise said it has already obtained necessary approvals and permits that will allow the partnership promptly to begin construction with a projected in-service date in early 2013.
At that time, Enterprise will be able to fractionate more than 450,000 b/d NGLs at Mont Belvieu. System-wide the partnership's net fractionation capacity will increase to more than 780,000 b/d.
A.J. Teague, executive vice-president and chief operating officer of Enterprise's general partner, noted that, as with the company's fifth Mont Belvieu fractionator, currently under construction and set for completion in this year's fourth quarter, the newly announced unit will be fully contracted when it begins service.
Additional capacity at Mont Belvieu, Teague said, will allow the Mont Belvieu complex to handle about 75,000 b/d of mixed NGLs currently being diverted to Louisiana for fractionating, as well as an incremental 30,000 b/d of y-grade from Phase II expansion of the company's Yoakum plant in Lavaca County, Tex.
Enterprise's current assets include about 50,200 miles of onshore and offshore pipelines; 192 million bbl of storage capacity for NGLs, refined products, and oil; and 27 bcf of gas storage capacity
TRANSPORTATION — Quick TakesIchthys LNG project gets environmental nod
Australia's Federal Environment Minister Tony Burke gave government approval for the proposed Ichthys LNG project provided strict conditions are met.
Operator Inpex Australia must develop a greenhouse gas management strategy outlining the measures and offsets the company proposes to reduce GHG emissions before LNG production can begin.
Inpex also must establish measures to minimize waste and noise, including noise generated by setting piling and blasting in Darwin Harbor.
Additionally there will be conditions imposed on dredging and spoil disposal to protect marine life.
Inpex must develop and implement a rigorous management plan with the help of an expert panel. The plan must include measures to prevent, detect, and respond to threats to marine life and enable dredging methods and mitigation measures to be changed or adapted to any new information.
The company is required permanently to protect and manage 2,000 hectares of vegetation at the plant site as well as marine habitat for inshore dolphins, turtles, and sea cows.
The Ichthys project is expected to produce 8.4 million tonnes/year of LNG, 1.6 million tpy of LPG, and 100,000 b/d of condensate. The on stream date is scheduled for 2016.
NuStar, Velocity partner to ship condensate
NuStar Logistics LP and Velocity Midstream Partners have signed a letter of intent to develop a pipeline system transporting west Eagle Ford shale condensate from Velocity's Gardendale hub to NuStar's North Beach Corpus Christi, Tex., terminal facility.
Velocity will build and operate a 70-mile, 12-in. OD pipeline with capacity to move more than 100,000 b/d of condensate from Gardendale to NuStar's new Oakville storage facility near Three Rivers, Tex. This storage facility will in turn be connected to an existing 16-in., 200,000 b/d NuStar pipeline running to its Corpus Christi North Beach Terminal.
The North Beach terminal has roughly 2 million bbl of storage capacity, large-scale marine loading facilities, and access to the Corpus Christi refinery market. NuStar also has a land lease option for 15 acres contiguous to the existing property, suitable for potential expansion.
Velocity is already building 65 miles of pipeline and 150,000 bbl of storage to transport condensate from producers including Shell E&P, Chesapeake, SM Energy, and Rosetta Resources, to its Gardendale terminal (OGJ Online, Dec. 8, 2010). The partnership with NuStar allows for both ready shipment of this production to end users and alleviation of truck-related bottlenecks in current transport schemes, the companies said.
Construction of Velocity's 12-in. pipeline and NuStar's Three Rivers storage facility will begin this summer, the joint venture expecting the system to be in service by April 2012.
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