GENERAL INTEREST — Quick Takes
Shell group sells another Nigerian stake
Shell Petroleum Development Co. of Nigeria has completed its eighth sale of onshore interests in Nigeria with the transfer of a 30% stake in Oil Mining Lease 30 in the Niger Delta to Shoreline Natural Resources Ltd. (OGJ Online, Sept. 7, 2012).
Total cash proceeds to Shell are $567 million.
OML30, covering 1,097 sq km, includes Kokori, Afiesere, Oweh, Olomore, Eriemu, Evwreni, Oroni, and Isioka fields, which produce about 35,000 b/d of oil and condensate. The sale includes most of the Trans Forcados crude oil pipeline between OML30 and the Forcados River manifold.
The SPDC joint venture—including Nigerian National Petroleum Corp. 55%, Shell 30%, Total E&P Nigeria Ltd. 10%, and Nigerian Agip Oil Co. Ltd. 5%—retains an 8-km pipeline link to the Forcados terminal.
Total E&P Nigeria and Nigerian Agip have assigned their interests in the lease to Shoreline, which now holds a 45% interest. Shoreline is a Nigerian joint venture of Shoreline Power Co. Ltd. and Heritage Oil PLC.
Hess considers selling Russian interests
Hess Corp. said it is considering whether to sell its Russian subsidiary, Samara-Nafta, which produces 50,000 boe/d in the Volga-Urals region.
Samara-Nafta produces crude oil from fields in the Mamurinsky license in the southern Samara region.
Previously, Hess announced plans to divest mature, small working-interest assets.
Hess announced Nov. 12 that it has hired Goldman Sachs Group Inc. as a financial adviser regarding the potential Samara-Nafta sale. Hess first acquired interest in the Russian firm in 2005 (OGJ Online, Mar. 24, 2005).
Continental Resources to buy more Bakken assets
Continental Resources Inc. has agreed to buy certain Bakken formation producing and undeveloped properties for $650 million. The property includes leasehold of 120,000 net acres, primarily in the North Dakota counties of Divide and Williams.
The Bakken acquisition involves production of 6,500 boe/d, said Continental Resources, which already is the largest single leaseholder in the Bakken with 984,040 net acres as of Sept. 30. If completed, the proposed acquisition will increase the total to 1.1 million net acres.
In addition, Continental Resources agreed to sell producing crude oil and natural gas properties and supporting assets in its east region for $125 million.
The divestiture mainly includes properties east of the Mississippi River, including the Illinois basin and the state of Michigan. Production from the properties included in the sale agreement averaged 1,100 boe/d for the 3 months ended Sept. 30.
"We are divesting noncore, conventional assets and reinvesting the proceeds in an attractive acquisition that further builds our strategic, core position in the Bakken," said Harold Hamm, Continental Resources chairman and chief executive officer. "Continental operates a large portion of the acreage that we are acquiring, and more than half of it is held by production."
If the Bakken acreage acquisition is completed as planned, Continental Resources expects additional 2013 drilling capital expenditures will be largely offset by incremental cash flow from the properties.
Both transactions are expected to close before Dec. 31, subject to customary closing conditions and adjustments.
Antero Resources agrees to sell Piceance basin assets
Antero Resources of Denver agreed to sell all of its natural gas and pipeline assets in the Piceance basin to a private company for $325 million in cash plus the assumption of all of Antero's Rocky Mountain firm transportation obligations. The buyer was not identified.
Closing, subject to customary conditions, is expected next month with an effective date of Oct. 1. The transaction does not include Antero's 78 bcf of natural gas hedges through 2016.
Terms include firm transportation obligations through 2021 that have an undiscounted liability of $91 million based on the difference between the pricing upgrade that can be obtained in the futures market at the tailgate of the pipelines and the fixed fee pipeline tariffs.
Assuming the current monetization of Antero's Rockies gas hedges, the total Piceance proceeds will include $325 million for the upstream and pipeline assets before customary post-closing adjustments.
The assets consist of 61,000 net acres of leasehold and 30 miles of gathering pipeline in western Colorado. The assets contain an estimated 205 bcf of gas equivalent of proved developed reserves as of Sept. 30 and 59 MMcfd net production from 284 gross operated wells.
Paul M. Rady, Antero chairman and chief executive officer, said, "The Piceance asset sale allows Antero to redeploy capital and human resources to its Marcellus and Utica Shale projects where we are focused on the development of liquids-rich natural gas and oil reserves."
With the closing of the Piceance transaction, and the company's exit from Arkoma basin earlier in 2012, Antero will complete its transformation into "a pure-play Appalachian basin shale producer," Rady said.
Exploration & Development — Quick Takes
BOEM releases draft SEIS for gulf lease sales
The US Bureau of Ocean Energy Management completed a draft supplemental environmental impact statement covering two proposed federal oil and gas lease sales in the Gulf of Mexico. BOEM plans to hold public hearings and is seeking comments on the proposed sales, which are tentatively scheduled for 2013 and 2014, BOEM said.
It said hearings will be held Dec. 3 in Houston; Dec. 4 in New Orleans; Dec. 5 in Gulfport, Miss.; and Dec. 6 in Mobile, Ala. Comments will be accepted until Dec. 24, 45 days after the scheduled Nov. 9 publication of the draft supplemental EIS notice in the Federal Register.
The draft SEIS covers Lease Sale 233 in 2013 in the western gulf off Texas and Lease Sale 231 in 2014 in the central gulf off Louisiana, Mississippi, and Alabama, BOEM said.
It said the western gulf sale will build on two major gulf sales in the past year: one covering 21 million acres in December 2011 and a second covering 39 million acres in June 2012.
Total acquires 75% of two Kazakh blocks
Total SA will shoot a seismic survey and drill a well next year on acreage in Kazakhstan in which it acquired a 75% interest.
Total will be operator of two onshore blocks, called North and South, covering 14,500 sq km in the southwestern part of the country. Kazakh Co. Nurmunai Petrogas LLP was the previous operator.
Ecopetrol has gas find in Caribbean off Colombia
Colombia's state Ecopetrol said its Equion Energia affiliate, operator of the Mapale-1 exploratory well in the Caribbean Sea offshore Colombia, has indicated that fluid tests and recordings carried out on the well show the presence of dry natural gas.
The company provided no depths or other details of the indicated discovery.
With exploratory drilling complete, Equion Energia will begin the technical evaluation phase, which will take into account the well's results and previously shot seismic data in the area in order to determine the discovery's potential.
Equion Energia drilled Mapale-1 on Block RC5, awarded by Colombia's ANH in 2007. Equion Energia is operator with a 40.56% stake. Ecopetrol has 32%, and Brazil's Petrobras has 27.44%.
Statesman sees potential on northwest Sudan block
An independent consultant has identified the potential for a 1.5 billion bbl gross unrisked prospective resource on Block 14 in northwestern Sudan, said Statesman Resources Ltd., Vancouver, BC.
Statesman's main asset is a 50.1% shareholding in Statesman Africa Ltd. that in turn beneficially holds a 75% working interest in Block 14. Statesman also has oil and gas interests in Kansas and California.
The consultant found potential on Block 14 for a portfolio of prospects that could have a gross unrisked total prospective resource of 1.5 billion bbl, Statesman said. This resource is based on 30 potential traps containing a best estimate of 50 million bbl each.
The study identified the gross resource range of each trap to be from 20 million bbl to 200 million bbl each, with the best estimate being 50 million bbl/trap.
The consultant determined the block to be frontier hydrocarbon exploration acreage. It placed the chance of success at 4.5% but said seismic acquisition and geological mapping could raise it to 7-8% and said it could improve to 30% if a petroleum system were proven by nearby drilling in the Mourdi or Mesaha subbasins.
Block 14 also borders Libya, where the historical chance of success in the Murzuk basin farther to the west is above 40%. Murzuk is considered an analog to Block 14, Statesman said.
The consultant noted that drilling is picking up in the region. Just south of Block 14, scout reports indicate that a well recently drilled by Sahara Oil Co. and the Al Qahtani joint venture had intermittent oil shows over a 300-m interval possibly in Devonian sandstones. If accurate, this could indicate a viable source. It is believed that a second well is planned in the block.
In Egypt just north of Sudan Block 14, Petroceltic-Melrose have spudded a well in the Mesaha basin that is expected to take 45-60 days to drill.
Drilling & Production — Quick Takes
BP lets deepwater-technology contracts
BP PLC has let contracts to KBR and FMC Technologies in a program it calls Project 20K targeting "next-generation systems and tools to help unlock the next frontier of deepwater oil and gas resources currently beyond the reach of today's technology."
The KBR and FMC Technologies contracts, the first awarded in the program, focus on technologies needed for development and production of oil and gas from reservoirs with pressures up to 20,000 psi and temperatures as high as 350º F.
KBR will develop program execution and management plans for the project, including capital cost and schedule estimates, risk assessments, and technical designs.
FMC Technologies will participate in a technology-development agreement in which it will work with BP to design and develop 20,000-psi-rated subsea production equipment, including a subsea production tree and a subsea high-integrity pressure protection system.
Project 20K focuses on technologies for well design and completions; drilling rigs, risers, and blowout preventers; subsea production systems; and well-intervention and containment.
Current equipment has technical pressure and temperature limits of 15,000 psi and 250º F.
Total starts work on South Mahakam project
Total SA has started work on its South Mahakam gas-condensate project aimed at offsetting production declines on its Mahakam production-sharing contract block offshore Indonesia.
In the first phase, Total and 50-50 partner Inpex will install three platforms and drill 19 wells in 45-60 m of water in the phased development of Stupa, West Stupa, and East Mandu gas-condensate fields and of Jempang and Metulang gas fields.
The fields are 35 km southeast of Balikpapan.
Total, the PSC operator through its Total E&P Indonesie unit, expects production to ramp up to reach an average 69,000 boe/d, including 18,000 b/d of condensate, yearend 2013.
Gas and liquids will flow through a new pipeline from the Stupa platform to the Senipah onshore terminal operated by Total. Some of the gas will move to the Bontang LNG plant, and some will be sold domestically.
Laricina seeks single-well SAGD at Saleski
Laricina Energy Ltd. has amended its application for first-phase commercial development of its Saleski oil sands acreage in Alberta to use cyclic steam-assisted gravity drainage in a single horizontal well.
Most SAGD projects use parallel horizontal wells, one for steam injection and the other for production. Earlier this year, Laricina said it was considering development via cyclic steam stimulation (OGJ Online, July 11, 2012).
The first phase of the Saleski project targets the Upper Devonian Grosmont carbonate reservoir.
"The Saleski pilot has shown the unique character of the Grosmont, specifically the high level of permeability and rapid mobilization of bitumen," said Glen Schmidt, Laricina president and chief executive officer.
Among other changes to the application, Laricina will focus initial commercial development on the Grosmont C zone. It continues to test the D zone.
It also seeks to increase steam capacity to reflect a steam-oil ratio of 3.9, with a projected operating cumulative SOR of 3.5, to accommodate higher injection pressure for a cyclic process. The initial application was based on an SOR of 2.6.
The company has cut the number of wells in its application to 32 single wells in the Grosmont C to be drilled from a single well pad. It originally applied for 40 wells-10 well pairs each in the Grosmont C and D zones.
It now targets initial steaming in Saleski Phase 1 in the third quarter of 2015. First-phase production capacity remains 10,700 b/d, and solvent-cyclic SAGD remains in the development plan.
The Saleski pilot has production capacity of 1,800 b/d of bitumen.
Gazprom approves Eastern Gas Program step
Gazprom managers have approved investments for an important step in the Eastern Gas Program integrating field developments, pipeline, and natural gas production centers in East Siberia and Russia's Far East (OGJ Online, Sept. 17, 2012).
The investments will cover predevelopment of Chayandinskoye gas and condensate field, transmission pipelines, and a gas production center at Yakutia in the Republic of Sakha.
In the next stage, Gazprom will fully develop Kovyktinskoye gas field, which is southwest of Chayandinskoye in the Irkutsk Oblast, and lay an 800-km pipeline between a production center there and Yakutia. Gazprom estimates Chayandinskoye reserves at 1.2 trillion cu m of natural gas and 79.1 million tonnes of oil and condensate.
The Eastern Gas Program includes plans for additional production centers and a pipeline connecting at Khabarovsk with an existing pipeline between Sakhalin and Vladivostok.
PROCESSING — Quick Takes
First phase of Sturgeon refinery approved
Partners in the North West Redwater Partnership have approved construction of the first phase of the Sturgeon bitumen refinery in the Industrial Heartland area of Alberta (OGJ Online, Jan. 28, 2010). The facility will be the world's first refinery integrating gasification of residual oil with carbon-dioxide capture in its initial design.
Capacity of the first phase, estimated to cost $5.7 billion, will be 50,000 b/d. The facility will capture 1.2 million tonnes/year of CO2 to be sold for use in enhanced oil recovery. Construction is to start in spring of 2013 and take 3 years.
Partners are North West Upgrading Inc. and Canadian Natural Upgrading Ltd., a wholly owned subsidiary of Canadian Natural Resources Ltd.
Under 30-year processing agreements, Alberta Petroleum Marketing Commission, an agent of the province of Alberta, will supply 75% of the feedstock. CNRL will supply the rest. The suppliers will receive proportionate shares of the products.
Two further phases with capacities of 50,000 b/d each are envisioned for the refinery, near Redwater in Sturgeon County, about 45 km northeast of Edmonston.
The main product will be ultralow-sulfur diesel. CO2 capture is planned in each phase.
Aramco lets contract for Jazan IGCC plant
Saudi Aramco has let a contract to KBR for front-end engineering and design of an integrated gasification combined-cycle power plant in conjunction with a 400,000-b/d refinery under development at Jazan Economic City, Saudi Arabia (OGJ Online, Oct. 22, 2012).
The IGCC plant, which KBR says will be the world's largest such facility, will gasify vacuum residue to supply electricity to the refinery and make 2.4 Gw available to Jazan and the surrounding region.
More gas processing on tap for Marcellus production
MarkWest Energy Partners, Denver, will install more processing at Mobley in Wetzel County, W.Va.
The 200-MMcfd Mobley 3 gas plant will join two other plants under construction there and serve development of rich-gas acreage in the Marcellus shale by EQT Corp., Pittsburgh, and other producers, the company said. MarkWest has underpinned the new plant with long-term, fee-based contracts.
This month, MarkWest expects to finish building its 200-MMcfd Mobley 1 plant, which is supported by rich-gas development of EQT, Magnum Hunter Resources Corp., Houston, and other producers (OGJ, May 7, 2012, p. 88).
EQT gas will flow to the plant by pipelines owned and operated by subsidiaries of EQT. Magnum Hunter Resources' gas will arrive by pipelines owned and operated by Eureka Hunter Pipeline LLC, a unit of Magnum Hunter Resources. Both pipeline systems will also deliver third-party gas to Mobley.
The second, 120-MMcfd plant will begin operating by first-quarter 2013, taking rich gas from Magnum Hunter Resources and other third parties. MarkWest's planned construction of Mobley 3 targets completion in fourth-quarter 2013.
When all plants are operating, Mobley will be able to process about 520 MMcfd.
According to MarkWest, NGLs recovered at Mobley will be fractionated and marketed at MarkWest's 60,000-b/d Houston, Pa., plant in Washington County. Mobley NGLs will move to Houston through MarkWest's Marcellus NGL gathering system (OGJ, May 7, 2012, p. 104).
By mid-2013, the company says will add C2 extraction capacity by completing 78,000 b/d of combined de-ethanization at Majorsville, W.Va., and Houston.
"Ethane recovered by MarkWest will have access to all of the planned ethane pipeline projects" that will originate from its Houston complex, said the announcement.
TRANSPORTATION — Quick Takes
Oneok begins Bakken NGL pipeline open season
Oneok Partners LP is holding an open season for its previously announced 600-mile Bakken NGL Pipeline, which will transport unfractionated natural gas liquids from the Bakken shale in the Williston basin to an interconnection with its 50%-owned Overland Pass Pipeline in northern Colorado. Oneok expects the 60,0000-b/d pipeline—now under construction—to enter into service in first-quarter 2013.
The partnership expects to complete a previously announced expansion of Bakken NGL to 110,000 b/d in third-quarter 2014. The open season ends Dec. 17.
The open season for Oneok's Bakken Crude Express Pipeline, a 1,300-mile oil pipeline with initial capacity to ship 200,000 b/d of light-sweet crude from the Bakken shale to Cushing, Okla., concluded Nov. 20.
Mexico's CFE lets contract for gas pipeline
Mexico's federal power company Comision Federal de Electricidad (CFE) awarded TransCanada Corp. Mexican subsidiary Transportadora de Gas Natural del Noroeste the contract to build, own, and operate the El Encino-to-Topolobampo Pipeline. The 30-in. OD pipeline will extend 329 miles from El Encino, in Chihuahua state, to Topolobampo in Sinaloa, at a contracted capacity of 670 MMcfd.
TransCanada described the project as part of Mexico's continuing efforts to expand its electrical grid and generating capacity. The pipeline will interconnect with other pipelines expected to be built as a result of separate CFE bid processes.
TransCanada said it expects there will be additional opportunities to participate in the build-out of Mexico's natural gas pipeline system and that these opportunities would be consistent with its strategy to build long-life infrastructure underpinned by long-term contracts. TransCanada has already built and is operating the Guadalajara and Tamazunchale pipelines and will soon break ground on a Tamazunchale Pipeline Extension (OGJ Online, Feb. 24, 2012).
TransCanada expects to invest $1 billion in the Topolobampo line, supported by a 25-year natural gas transportation service contract with CFE. The company anticipates the pipeline will enter service in third-quarter 2016.
EPP's Echo storage terminal begins receiving crude oil
Enterprise Products Partners LP (EPP) reported that Phase 1 of its Enterprise Crude Houston (Echo) storage terminal in Harris County, Tex., is complete and receiving deliveries of crude oil. The first three tanks total 750,000 bbl.
The next phase of the Echo terminal expansion includes adding up to 900,000 bbl storage as early as first-quarter 2014. EPP estimates that Echo could have as much as 6 million bbl of crude oil storage when completed.
EPP described Echo, its recently completed Eagle Ford shale pipeline (OGJ Online, June 8, 2012), and the reversal of the Seaway oil pipeline as projects benefiting both producers and consumers of crude by providing pipeline and waterborne access to more than 7 million b/d of Gulf Coast refining capacity.
The New York Mercantile Exchange is considering using Echo as a regional pricing point for the US Gulf Coast crude market. Through Seaway, Echo is connected to the storage hub in Cushing, Okla., the NYMEX benchmark pricing point for its West Texas Intermediate crude oil contract.