GENERAL INTEREST — Quick Takes
Continental to buy Wheatland, Bakken interests
Continental Resources Inc., Oklahoma City, will buy the assets of Wheatland Oil Inc., Enid, Okla., which consist of 5% of the interest acquired by Continental Resources in all leases and wells in a defined part of the Bakken play pursuant to a participation agreement effective Jan. 1.
The purchase price of $340 million is anticipated to result in the issuance of 3.9 million to 4.25 million Continental Resources common shares, subject to customary purchase price adjustments.
Wheatland's assets include 37,900 net acres in the North Dakota and Montana Bakken play and interests in more than 1,000 gross wells. The assets have net proved reserves of 17 million bbl of oil equivalent as of the end of 2011 and produced 2,500 boe/d in December 2011.
Wheatland is owned 75% by the revocable trust of Harold G. Hamm, of which Harold Hamm is sole trustee and beneficiary, and 25% by Jeff Hume. Hamm is chairman, chief executive officer, and majority shareholder of Continental Resources, and Hume is its president and chief operating officer.
Total shuts in gas production from North Sea fields
Production was shut in from Elgin, Franklin, and West Franklin natural gas and condensate fields in the UK North Sea following a Mar. 25 gas leak on the wellhead platform on Elgin field 240 km east of Aberdeen, Total SA reported.
The leak continues, Total said Mar. 27. The company launched internal emergency procedures, and crisis management teams were mobilized in Aberdeen and Paris. No injuries were reported; 238 people were evacuated.
"Investigations are ongoing to analyze the causes and to determine the remediation of the gas leak," Total said. The leak reportedly was detected during work to plug and abandon a well.
A surveillance aircraft confirmed a sheen on the water from drilling mud and light condensate. Preliminary assessments indicate no significant environmental damage, and dispersants are not considered necessary at this stage, Total said.
Oil Spill Response Ltd. was alerted. Total E&P UK Ltd. is cooperating fully with authorities including the Department of Energy and Climate Change, the Health and Safety Executive, and the Scottish Environmental Protection Agency.
Elgin and Franklin are high-pressure, high-temperature gas and condensate fields in the North Sea's Central Graben area.
Total E&P UK owns 46.17% and operates both fields. Its share of production was around 60,000 boe/d in 2011.
The Elgin-Franklin complex involves two wellhead platforms, one on Elgin and one on Franklin along with a production-utilities-quarters (PUQ) platform. The PUQ is on Elgin field and is linked to the Elgin wellhead platform by a 90-m bridge.
Hydrocarbons produced from Elgin, Franklin, and West Franklin fields are collected, separated, and treated on the PUQ. Liquid hydrocarbons are exported through the Forties Pipeline System via Cruden Bay to Kinneil for processing and then exported through the Shearwater Elgin Area Line (SEAL) pipeline to Bacton in Norfolk.
EPA finds no health concern in well samples
Initial results from samples of the first 11 of 60 water wells in Dimock, Pa., did not show contamination levels that could present a health concern, the US Environmental Protection Agency's Region 3 office in Philadelphia said on Mar. 15. Samples from 6 of the 11 wells showed the presence of methane, sodium, chromium, or bacteria, but in concentrations within the range for safe drinking water, it said.
Houston independent Cabot Oil & Gas Corp., which operates several natural gas wells in the area, said in a statement that it was pleased EPA's data confirmed earlier findings that Dimock well water meets all regulatory standards.
"As one of the first developers in the Marcellus shale to recognize the importance of this exceptional resource for our nation's future, Cabot has, and will continue, to work closely with the Dimock community, state, and local regulators on concerns in the area," Cabot said.
EPA said it announced on Jan. 19 that it would perform tests on the 60 homes' water wells after receiving requests from residents and reviewing data it already had. Of the 11 homes that were initially tested, three are receiving water from an alternate supply provided by EPA, it indicated. The agency will continue supply that water as it takes more samples to determine that the wells' water quality remains consistent and acceptable over time, the federal agency said.
Last year, Cabot said results from more than 1,700 water wells sampled and tested before proposed gas drilling in Susquehanna County, Pa., show methane to be ubiquitous in shallow groundwater, with a clear correlation of methane concentrations with surface topography (OGJ, Dec. 5, 2011, p. 54).
Exploration & Development — Quick Takes
Davy Jones well flaring gas from Wilcox D zone
The Davy Jones-1 ultradeep shelf wildcat on South Marsh Island Block 230 has begun to flow natural gas from the Wilcox D sand at an undetermined rate, said operator McMoRan Exploration Co., New Orleans.
McMoRan had reported a positive pressure response from the Wilcox D, perforated on Mar. 24. On Mar. 26, the company attempted to perforate the Wilcox C sand.
As the perforating gun was being removed from the hole, the well began to flow. When the gun was brought to the surface, it was determined that the gun did not fire in the Wilcox C from what appears to be a simple disconnection of the detonator cord. McMoRan plans to use a new perforating gun to complete testing the Wilcox C.
Currently, the test is ongoing from only the Wilcox D sand with hydrocarbons being flared. The flow from the D sand is being affected by considerable debris in the 5-in. liner, from what McMoRan believes to be residual drilling fluid from drilling of the well.
Results of a clean flow test, as opposed to the current test hampered by debris, will be announced as further progress is achieved and flow rates are measurable. McMoRan will provide updates as completion operations progress.
Ultra eyes Niobrara in southern Denver basin
Ultra Petroleum Corp., Houston, whose major assets produce natural gas in the Green River basin and Pennsylvania Marcellus, is making a play for liquids in the Niobrara formation in Colorado in the southern Denver-Julesburg basin.
The company has 131,000 net acres in the basin, anchored in El Paso County around Colorado Springs, where it plans to drill and complete four vertical wells in the first half of 2012. Horizontal drilling could begin in the second half of the year.
The industry Niobrara play is moving toward Ultra's position from recent discoveries in northeastern Colorado and southeastern Wyoming and across giant Wattenberg oil and gas field, the company said.
Ultra said it sees potential in the A, B, and C benches of the Niobrara formation, which the early vertical wells are expected to encounter at 5,000-7,500 ft. The company said it has 21 sq miles of 3D seismic to aid in the exploration program.
GeoPark acquires Hupecol assets in Colombia
GeoPark Holdings Ltd. has made a second acquisition in Colombia with the $75 million purchase of Hupecol Cuerva LLC, a private explorer that holds two Llanos basin blocks.
The La Cuerva and Llanos 62 blocks total 90,000 acres and are operated with 100% working interests, GeoPark said.
La Cuerva is producing 2,000 b/d of oil from 8 million bbl of proved and probable reserves by GeoPark's estimate. Two independent reserve evaluators estimated the proved and probable oil reserves attributable to the block at 16 million bbl and 10.8 million bbl in March and October 2011, respectively.
Llanos 62, adjacent to La Cuerva, is an exploratory block on which a 110 sq km 3D seismic survey is in progress. Its transfer to GeoPark is subject to regulatory approval.
The Hupecol assets generated $68 million in revenues and $21 million in net income in the 12 months ended Dec. 31, 2011. GeoPark will fund the acquisition from existing cash.
GeoPark in February acquired the Winchester Oil & Gas and La Luna Companies. The combined acquisitions give GeoPark 5-100% interests in 10 blocks, four operated, totaling 220,000 acres in the Llanos, Magdalena, and Catatumbo basins. GeoPark plans to drill 18-22 exploratory and development wells in Colombia this year.
Drilling & Production — Quick Takes
Lukoil Overseas to ramp up Uzbekistan gas flow
The Uzbek subsidiary of Lukoil Overseas started gas production at the end of 2011 at Dzharkuduk-Yangi Kyzylcha, largest field in the company's Southwest Gissar block in the Kashkadarya region of southeastern Uzbekistan.
Initial stage production is projected to reach 39 bcf/year (OGJ Online, Feb. 8, 2008). The field is in the Amu Darya basin (see map, OGJ, Aug. 5, 1996, p. 19).
In reporting its yearend operating results, Lukoil Overseas said that 2011 seismic surveying and exploratory drilling led discovery of Kyzylbairak-Southeast and Shamoltegmas gas fields and identification of several prospects. The year's work also resulted in an unspecified reserves increase above the block's 1.4 tcf of gas and 23 million bbl of oil and condensate at the beginning of 2011.
The company matured two other prospects for drilling, and it also confirmed the presence of commercial gas volumes in the unexplored area of large Adamtash field, 50 miles north of the border with Afghanistan.
The next steps are to activate a gas processing facility and place Adamtash and Gumbulak fields on production. The $1.2 billion project to establish output of 565 MMcfd includes drilling more than 40 producing wells, building external power supply lines, a gas gathering and processing system, commercial gas pipeline, condensate pipeline, shift camp, field base, and engineering infrastructure.
In early 2011, Lukoil Overseas started production in an initial operating area in the western part of Shady field in the company's Kandym-Khauzak-Shady-Kungrad project. The project consists of five wells making a combined 140 MMcfd of gas, production, gathering, and metering facilities, and a 21-km pipeline. Khauzak-Shady cumulative production reached 350 bcf of gas in mid-2011.
Lukoil Overseas completed a feasibility study and detailed design for integrated facilities for the Kandym group of fields. The project provides that Kuvachi-Alat field will begin operation in 2014 and Kandym field and the Kandym gas processing plant are to start up in 2016.
The company shot 2D seismic and drilled four exploratory wells in Kuvachi-Alat and Parsankul fields, making it possible to expand the fields' design area and increase C1 reserves by 12 million tons of oil equivalent.
CERI: Oil sands profitable and promising
Oil sands projects remain highly profitable for operators and governments and highly promising as a source of oil supply, according to an annual study by the Canadian Energy Research Institute.
The study estimated the constant-dollar oil price needed to recover all capital expenditures, royalties, and taxes calculated at a real discount rate of 10%/year, which it called equivalent to a nominal return of 12.5%/year based on an inflation rate of 2.5%/year.
For hypothetical projects in the study, that price, which CERI calls supply cost, is $44.75(Can.)/bbl of bitumen for steam-assisted gravity drainage, $89.62/bbl for mining integrated with upgrading, and $61.05/bbl for mining alone.
The supply costs, in prices equivalent to West Texas Intermediate crude oil after adjustments for blending and transportation, are $64.62/bbl for SAGD, $91.07/bbl for integrated mining and upgrading, and $81.51/bbl for stand-alone mining.
The study said the province of Alberta receives an average royalty of $8.50-12.20/bbl over the life of an oil sands project.
It projected bitumen production in three scenarios.
In the high case, production from mining and in situ operations increases from 1.5 million b/d in 2010 to 3.9 million b/d by 2020 and to 6.2 million b/d by 2045.
In the reference case—"a more plausible view," according to CERI—production grows to 3.3 million b/d by 2020 and 5.4 million b/d by 2045.
And in a low case, bitumen production is 4.1 million b/d by 2030 and 4.6 million b/d by 2045.
Bounty-Surmont eye Alberta SAGD application
Private Calgary independent Surmont Energy Ltd. said it earned an 80% working interest in 12,000 acres of leases 70 km southwest of Fort McMurray, Alta., that contain an estimated 1.49 billion bbl of discovered and undiscovered bitumen in place.
A winter program carried out by Bounty Developments Ltd., Surmont's operating partner, consisted of a $3 million, 13 sq km 3D seismic shoot followed by a $5.5 million program of drilling 10 core holes on seismically defined locations. A cap rock core was also acquired as part of the program.
Surmont has now earned an 80% working interest in the 19 contiguous sections, and Bounty holds the other 20%. Surmont will use the results of the winter program, together with core hole and seismic data from prior years, to commission an updated resource report by an independent evaluation firm.
Surmont also started work intended to lead to submission later this year of regulatory applications for the first phase of a steam-assisted gravity drainage project. The first phase would be designed to produce 10,000-12,000 b/d of oil starting in 2015. Surmont and Bounty will assess plans to explore the rest of the lands in coming seasons to develop more project phases to increase overall reserves and peak production rates.
BP taps Technip for Schiehallion subsea work
BP PLC has let a contract to Technip for subsea work in its redevelopment of Schiehallion and Loyal oil fields in the West of Shetland area offshore the UK.
The project, which BP calls Quad 204, includes replacement of the Schiehallion floating production, storage, and offloading vessel with a unit under construction by Hyundai Heavy Industries (OGJ Online, July 13, 2011). The fields, on production since 1998, are in 350-500 m of water.
Under a contract worth about €600 million, Technip will remove the existing FPSO and mooring system; recover existing flexible risers and dynamic umbilical systems; position and install the new FPSO and associated mooring system and anchor piles; supply and install 21 dynamic flexible risers; install four static and dynamic umbilicals; coat, weld, and install 15 steel pipelines totaling 50 km; supply and install numerous flexible jumpers; and install various manifolds, jumpers, and infrastructure associated with field development.
The new FPSO will be 270 m long and 52 m wide, with capacity to handle production of 130,000 b/d and store more than 1 million bbl.
New facilities are to start production in 2016.
PROCESSING — Quick Takes
EPA proposes uniform emissions standards
The US Environmental Protection Agency proposed national uniform emissions standards for hazardous air pollutants at refineries and petrochemical plants' storage vessel and transfer operations, equipment leaks, or control devices. The proposals are flawed solutions looking for a problem, an American Petroleum Institute official immediately observed.
"Instead of developing the standards based on emissions data and other relevant facts from a particular industry, these standards are 'reverse engineered' to require the most stringent control requirement without adequate consideration of costs," Howard Feldman, API's regulatory and scientific affairs director, said on Mar. 26.
"At a time when the president has called on federal agencies to take into account the impacts of regulations on jobs and the economy, the last thing US industries need are more complex, stringent and burdensome regulations," he maintained.
EPA said in its Mar. 26 Federal Register notice that having uniform standards would help it meet required statutory stringency tests as it periodically reviews and, if necessary, revises new source performance standards and national emissions standards for hazardous air pollutants as required under the Clean Air Act.
"The proposed uniform standards would ensure consistency and streamline record-keeping and reporting requirements for facilities with storage vessels and transfer operations, equipment leaks, and process vents that must comply with multiple regulations," it said. Comments on the proposals will be accepted through June 25, EPA indicated.
More Texas fractionation on tap for shale gas liquids
Chevron Phillips Chemical Co. LP, Houston, will expand the its NGL fractionator at its Sweeny, Tex., plant in Old Ocean, Tex. Construction is to start next month and be completed in February 2013.
With the expansion, the NGL fractionator will be able to accommodate an additional 22,000 b/d, or a 19% increase over current capacity, the company said.
"One of the main drivers for the project is the rapid development of natural gas, crude oil, and NGLs from the shale formations in the region," said Martin Dale, feedstock procurement manager for Chevron Phillips Chemical.
The fractionator at Sweeny was built in the 1960s and consists of two trains currently with a capacity of 116,000 b/d.
Contract let for Cilacap refinery upgrade
PT Pertamina has let a contract to Foster Wheeler AG's Global Engineering & Construction Group for management of an upgrade of its 348,000 b/d Cilacap refinery on Java, Indonesia.
The project includes construction of a 62,000 b/d resid catalytic cracking complex, to include a resid fluid catalytic cracker, an LPG Merox unit, and propylene recovery and gasoline hydrotreating units.
The Foster Wheeler unit will manage the engineering, procurement, and construction contractor.
The upgrade will enable the refinery to meet Euro 4 fuel quality specifications. It will boost production of LPG by 350,000 tonnes/year and enable the refinery to produce more than 140,000 tpy of propylene.
Completion is due in 2014.
Pertamina earlier planned to perform the upgrade in a joint venture with Mitsui & Co. Ltd., but the companies ended the agreement citing disagreement over the business model (OGJ Online, Mar. 23, 2010).
TRANSPORTATION — Quick Takes
India dedicates 2,200-km GAIL natural gas pipeline
Indian Prime Minister Manmohan Singh dedicated GAIL (India) Ltd.'s 2,200 km Dahej-Vijaipur-Dadri-Bawana-Nangal-Bhatinda natural gas pipeline, which extends through northwestern India. GAIL said the project will spur industrial development across 40 industrial hubs, with the potential to supply 3,500 Mw of power, 1.8 million tonnes/year of urea production, and cities along the pipeline with natural gas for industrial and domestic applications.
Dahej-Vijaipur-Dadri-Bawana-Nangal-Bhatinda crosses Gujarat, Madhya Pradesh, Rajasthan, Uttar Pradesh, Haryana, Delhi (UT), Punjab, and Uttarakhand states, both interconnecting with the existing network and meeting unsupplied demand northern India.
Singh also expressed his hopes the pipeline's extension would soon carry the gas from the proposed Turkmenistan-Afghanistan-Pakistan-India pipeline into rural parts of the country. The pipeline cost roughly Rs. 13,000 crores.
GAIL has been taking a multipronged approach to meeting India's growing natural gas demand, developing domestic fields (OGJ Online, Feb. 22, 2012), buying shares in producing overseas properties, including the Eagle Ford shale in southern Texas, and reaching a variety of LNG supply agreements, including sourcing material from the US (OGJ Online, Dec. 12, 2011).
Partners to proceed with Seaway expansion
Enbridge Inc. and Enterprise Products Partners LP said they have secured capacity commitments from shippers enabling them to proceed with expansion of the Seaway Pipeline, flow of which they're reversing to carry crude oil from Cushing, Okla., to the Texas Gulf Coast (OGJ Online, Jan. 5, 2012).
Enbridge also said it will increase the size and capacity of its Flanagan South Project between Flanagan, Ill., and a connection with the Seaway system at Cushing.
The pipeline now will have a 36-in. diameter and initial capacity of 585,000 b/d. Additional pumping stations could boost capacity to 800,000 b/d. Enbridge now operates the 650-mile Spearhead pipeline between Flanagan and Cushing, with capacity of 193,300 b/d.
The Seaway project will more than double capacity of the pipeline to 850,000 b/d by mid-2014. It includes construction of a 512-mile, 30-in. twin along the route of the existing pipeline, which will add 450,000 b/d of capacity.
Enbridge and Enterprise said they have nearly completed the first phase of the Seaway reversal, which will provide 150,000 b/d of takeaway capacity at Cushing by June 1. Addition of pump stations and modifications will boost capacity to 400,000 b/d of a mix of light and heavy crude oils by the first quarter of 2013.
An Enbridge unit bought ConocoPhillips's share of the Seaway system for $2 billion late last year (OGJ Online, Nov. 16, 2011).
The companies are holding an open system for a new 85-mile, 30-in pipeline to carry about 200,000 b/d of crude from Enterprise's ECHO terminal southeast of Houston to refineries in Beaumont and Port Arthur, Tex. (OGJ Online, Feb. 28, 2012).
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