OGJ Newsletter

Jan. 17, 2011
International News for oil and gas professionals

Marathon Oil to spin off refining, pipeline assets

Marathon Oil Corp. will spin off its downstream business, forming an independent refiner to be named Marathon Petroleum Corp. based in Findlay, Ohio. The parent company, Marathon Oil, will remain in Houston.

Gary R. Heminger, now Marathon Oil downstream executive vice-president, will be president and chief executive officer of Marathon Petroleum. Clarence P. Cazalot Jr. remains Marathon Oil president and chief executive officer. Marathon Oil expects the transaction to be effective June 30.

Refinery locations and capacities to be operated by the spun-off company are Garyville, La., 464,000 b/d; Catlettsburg, Ky., 212,000 b/d; Robinson, Ill., 206,000 b/d; Detroit, 106,000 b/d; Canton, Ohio, 78,000 b/d; and Texas City, Tex., 76,000 b/d. Crude capacity of the Detroit refinery is being expanded by 15,000 b/d in a project that will increase heavy-oil processing capacity by about 80,000 b/d.

Marathon Petroleum also will operate wholesale and retail operations, including the Speedway retail chain, and Marathon Pipe Line LLC. Through the pipeline subsidiary, the new company will own, operate, lease, or have ownership interests in about 9,700 miles of oil and product pipelines.

Marathon Oil's core exploration and production areas are the US, Equatorial Guinea, Libya, and the North Sea. Other areas in which the company is active include Angola, Indonesia, the Iraqi Kurdistan region, and Poland.

The upstream company also holds a 20% interest in the Athabasca Oil Sands Project, a joint venture with Shell (60%) and Chevron (20%) that includes the Muskeg River and Jackpine mines, the Scotford upgraders, and more than 215,000 acres of potentially mineable land.

Marathon Oil also has an integrated gas unit that includes a 60% interest in a 3.7-million-tonne/year LNG plant and 45% in a methanol company in Equatorial Guinea.

Before the spinoff, Marathon Petroleum plans to borrow $2.5-3 billion to establish a cash balance of at least $750 million. It will use cash above that level repay intercompany debt with Marathon Oil. Remaining proceeds will be distributed to Marathon Oil before the spinoff date.

JP Morgan and Morgan Stanley will provide a $2.5 billion, 364-day bridge facility. The firms also will provide Marathon Petroleum a $2 billion, 4-year revolving credit facility.

Before the spinoff, Marathon Oil will reduce its long-term debt by about $2.5 billion through cash on hand and proceeds of the debt repayment from Marathon Petroleum. It will continue servicing the remaining $5 billion in long-term debt after the spinoff.

Cheaspeake Energy to cut spending, sell assets

Chesapeake Energy Corp. announced plans to reduce its long-term debt by 25% by substantially reducing leasehold spending and by reducing its 2-year production growth rate to 25% from its previously planned growth rate of 30-40% for 2011-12.

Aubrey K. McClendon, Chesapeake's chief executive officer, said the latest plan is a shift from Cheaspeake's "aggressive asset accumulation of the past few years." The growth plan reduction will be achieved "through asset monetizations," a news release said.

Chesapeake said its 2011-12 strategic plan update will not involve issuing any common or preferred stock to achieve its debt reduction objective. Chesapeake reported net debt of $11.4 billion as of Sept. 30, 2010.

The company did not specify which assets it might sell. Chesapeake of Oklahoma City said its full-year 2010 production of 2.8 bcfd of gas equivalent marked a 14% increase over its 2009 production.

US starts 2011 with 1,700 rigs drilling

US drilling activity increased slightly during the first week of 2011, up by 6 rotary rigs to 1,700 working, compared with 1,220 at work a year ago, Baker Hughes Inc. reported. The US rig count exceeded 1,700 units drilling in 4 of the last 5 weeks of 2010, finishing the year with 1,694 working the final week.

Land operations accounted for the bulk of the latest gain, up by 5 units to 1,661 working. Offshore drilling increased by 1 rig to 25, all in the Gulf of Mexico. Inland waters activity was unchanged with 14 rigs drilling.

Of the US rigs working, 914 were drilling for natural gas, 5 fewer than the previous week. The number drilling for oil increased by 12 to 777. There were 9 rotary rigs unclassified. Horizontal drilling increased by 19 to 966. Directional drilling dropped 1 to 211.

Among the major producing states, Oklahoma and Colorado had the biggest increases in their rig counts, up 4 each to 164 and 64, respectively. Texas and Wyoming gained 2 rigs each with respective counts of 733 and 47. North Dakota increased by 1 to 151. Pennsylvania, New Mexico, California, and Arkansas were unchanged at 103, 69, 38, and 37, respectively. West Virginia and Alaska were down 1 rig each to 20 and 5. Louisiana reported the biggest loss, down 8 rigs with 168 still drilling.

Exploration & DevelopmentQuick Takes

Shell Todd plans comprehensive review of Maui field

Shell Todd Oil Services Ltd. plans a major review of the Maui gas field region in the Taranaki basin off New Zealand.

The JV contracted drillship Noble Discoverer to drill an exploration well, Ruru-1, on the edge of the field in February to March. It also engaged Electromagnetic Geoservices ASA of Norway to conduct an electromagnetic survey (New Zealand's first) across the Maui field itself.

The Ruru prospect, previously known as Hohonu, was delineated in recent years and is believed to have potential to add large reserves—1 tcf was mentioned unofficially—to the Maui development. Depending on the result of the wildcat well, it may be developed as a separate project or as an adjunct to the existing Maui system.

Ruru is a fault trap prospect on the southeast boundary of the Maui production lease and crosses into adjoining permit PEP 381203, also operated by Shell Todd and in which Australian company OMV has an interest. The Eocene-age Kapuni formation reservoir target is the same as the producing horizon at Maui.

The multimillion dollar electromagnetic survey is being run by the Boa Galatea vessel and is expected to take a month to complete. It will begin with laying a grid of receivers on the seabed across production lease PEP 381012 before transmitting electromagnetic waves during the survey.

Maui field, discovered in 1969, had initial gas reserves of 3 tcf and once supplied 90% of New Zealand's demand that exceeded 200 petajoules/year. The field now supplies only about 30% of the current annual market of 150-170 petajoules.

However the new exploration initiative indicates Shell Todd thinks more reserves can be found to prolong the field's life and lead to renewing the production lease before it expires in June 2015.

Tweneboa appraisal well confirms potential

The Tweneboa-3 appraisal well on the Deepwater Tano block off Ghana encountered gas-condensate and confirmed the Greater Tweneboa area's resource base potential.

The group led by Tullow Oil PLC plans to evaluate development options for Tweneboa and Enyenra, formerly Owo, fields.

Tweneboa-3 well was drilled with two deviated boreholes. The first leg was drilled to calibrate the potential of an area that had a weak seismic response. This leg encountered 29 ft of gas-condensate pay, in line with expected results.

The well was then sidetracked 1,808 ft west to test an area of strong seismic response. This leg encountered a gross vertical reservoir interval of 214 ft and penetrated 112 ft of net gas-condensate pay in high-quality stacked reservoir sandstones in two zones.

Tweneboa-3 well is 7.5 miles southeast of the Tweneboa-1 discovery well. The Deepwater Millennium dynamically positioned drillship drilled Tweneboa-3 to a total depth of 12,816 ft in 5,253 ft of water. The well will be suspended for potential future use in field development.

The drillship will remain on the block to drill the top-hole section of the Tweneboa-4 appraisal well and suspend it. Then the drillship will drill the Enyenra-2A well, which will appraise the Owo-1 discovery well.

Deepwater Tano block interests are Tullow Oil 49.95%, Anadarko Petroleum Corp. and Kosmos Energy Inc. 18% each, Sabre Oil & Gas Holdings Ltd. 4.05%, and Ghana National Petroleum Corp. has a 10% carried interest.

Multizone gas find gauged off Mauritania

A group led by Korea National Oil Corp. subsidiary Dana Petroleum has tested gas from one of four separate gas columns in an exploratory well in the Atlantic off Mauritania.

Cormoran-1 is in Block 7 about 2 km south of the late 2003 Pelican-1 gas discovery (see map, OGJ, Oct. 23, 2006, p. 38).

Cormoran-1's main purpose was to test the Cormoran prospect, which adjoins but lies at a greater depth than Pelican. A secondary objective was the Petronia prospect beneath Cormoran. A further objective was to provide appraisal data on the Pelican gas discovery.

Cormoran-1 went to 4,695 m below sea level in 1,630 m of water. It encountered generally thin but good quality gas-bearing sands in the Upper Pelican Group at 3,376-3,420 m true vertical depth subsea (TVD ss) and in the Lower Pelican Group at 3,691-3,711 m TVD ss.

The well also encountered good quality gas-bearing sands in the Cormoran prospect in the gross interval from 4,351 m to 4,471 m TVD ss and at the top of the Petronia prospect in the gross interval from 4,660 m to 4,695 m TVD ss. Drilling stopped at 4,695 m due to elevated pore pressures, and the well was still in gas-bearing reservoir at total depth.

The well stabilized at 22-24 MMscfd of gas on a 32⁄64-in. choke on a drillstem test of the Lower Pelican Group at 3,679-3,712 m TVD ss. The flow rate was constrained by the need to avoid sand production. Substantially higher flow rates could have been achieved if not for this operational constraint, Dana Petroleum said. The company plugged and abandoned the well so that it can be reentered.

Participating interests in Block 7 are Dana Petroleum (E&P) Ltd. 36%, GDF Suez Exploration Mauritania BV 27.85%, Tullow Petroleum (Mauritania) Pty. Ltd. 16.2%, PC Mauritania Pty. Ltd. 15%, and Roc Oil (Mauritania) Co. 4.95%.

Drilling & ProductionQuick Takes

BP, CNPC increase production from Iraq's Rumaila field

Output at Iraq's giant Rumaila oil field has increased by more than 10% above the 1.066 million b/d target established in December 2009, when BP PLC and China National Petroleum Corp. (CNPC) signed a technical service contract to expand production.

"This production increase is an important step for Iraq and demonstrates the success of the contracts awarded," said Iraq's oil minister Abdul Kareem Luaibi, referring to the contract awarded to the two firms, along with Iraq's State Oil Marketing Co. (SOMO).

Management of the field's development has been carried out by the Rumaila Operating Organization (ROO), which was originally staffed by 4,000 employees from Iraq's state-owned South Oil Co. along with 100 technical experts and managers from BP and CNPC.

BP said that the pace of activity on Rumaila has built steadily over the past year, with 20 new rigs now mobilized in the field. Altogether over the past year, BP said 41 wells have been drilled, 103 workovers completed, and 122 km of flowlines laid. Employment has more than doubled to 10,000 workers.

On signing the TSC in 2009, BP and CNPC said they planned to invest $15 billion in cash over the 20 year lifetime of the contract with the intention of increasing plateau production to 2.85 million b/d during 2005-10.

"Once production has been raised by 10% from its current level of about 1 million b/d, costs will start to be recovered, and fees of $2/bbl earned on the incremental oil production," BP said at the time.

"Increasing production at Rumaila, the world's fourth largest oilfield, has been a massive undertaking," said BP Chief Executive Bob Dudley this week, adding that "We look forward to working with our partners to make Rumaila the world's second largest oil field."

In April 2010, BP let contracts worth about $500 million to three firms for drilling. Schlumberger, in partnership with Iraqi Drilling Co., received a contract for three rigs; Daqing Drilling a contract for three rigs; and Weatherford a contract for one rig (OGJ Online, Apr. 5, 2010).

The Rumaila consortium is comprised of BP, 38%, CNPC 37%, and SOMO, 25%.

Petrobras approves more FPSOs for Santos basin

Petroleo Brasileiro SA (Petrobras) approved the installation of two floating production, storage, and offloading vessels for installation on Guara Norte and Cernambi presalt Santos basin oil fields off Brazil.

Cernambi previously was known as the Iracema area.

The company said the FPSOs are part of the first production development phase of Guara Norte (Block BMS-09) and Cernambi (Block BMS-11) and will enable early production from these areas to start in 2014 compared with the previously proposed start of after 2014.

Each of the vessels will be designed to handle 150,000 bo/d and 8 million cu m/day of gas. The company expects to have the units converted and the modules built and integrated in Brazil with a target local content index above 65%.

Petrobras is the operator for both blocks and has a 45% interest in BMS-9 and a 65% interest in BMS-11.

BG Group 30% and Repsol Brasil SA 25% are its partneres in BMS-9. Its partners in BMS-11 are BG Group 25% and Galp Energia 10%.


Albemarle, Petrobras to build HPC plant in Brazil

Albemarle Corp., Baton Rouge, and Brazil's Petroleo Brazileiro SA (Petrobras) have signed a memorandum of understanding to construct a world-scale hydroprocessing catalyst (HPC) production plant in Santa Cruz, Brazil.

The new facility, to be constructed on the site of the two firms' existing joint venture Fabrica Carioca de Catalisadores SA (FCC SA), will complement existing production of fluid catalytic cracking (FCC) catalysts.

The two firms said the new plant will be constructed ahead of "significant demand growth for hydroprocessing catalysts" as Brazil begins to implement more stringent specifications for ultralow-sulfur diesel and Petrobras begins to introduce new hydrotreaters to existing and new refineries.

Albemarle said it will provide FCC SA with its leading technology for the manufacture of HPC, enabling the production of STARS catalysts, which have enabled the broad implementation of the most stringent sulfur specifications in fuels in North America, western Europe, and Japan.

"The plant will be ideally placed to serve growing needs for HPC in South America," the two firms said.

Petrobras and Albemarle said they also are enhancing their partnership by engaging into a joint technical cooperation aimed at the further development of advanced hydroprocessing catalysts.

In 2008, UOP LLC signed a technology cooperation agreement with Petrobras and Albemarle Corp. to demonstrate and further commercialize its catalytic crude upgrading (CCU) process technology (OGJ Newsletter, Oct. 13, 2008).

Last October, Albemarle said it completed the R&D laboratory facilities and begun construction on its Yeosu, South Korea manufacturing facility, which will begin intermediate commercial operations in mid-2011, with the commercial facility being fully operational in 2012.

Albemarle said the new site will produce finished catalysts, activators like methylaluminoxane (MAO) and metallocene components, as well as "High Purity Metal Organics for the HBLED market."

Dominion secures plant site for Marcellus gas

Dominion, Richmond, Va., has reached agreement with PPG Industries on an option for Dominion to buy land at PPG's Natrium, W.Va., site for construction of a 300 MMcfd natural gas processing plant.

Dominion Transmission, Dominion's natural gas pipeline and storage subsidiary, plans to process gas and separate NGLs at the 56-acre site as part of its previously announced Marcellus 404 Project (OGJ, June 7, 2010, p. 52). Engineering design and project planning for the plant are under way, said the Dominion announcement; financial terms were not disclosed.

The plant will also have fractionation capacity for up to 38,000 b/d of NGLs.

Natrium, on the Ohio River in Marshall County about 9 miles north of New Martinsville, W.Va., is close to Dominion's TL-404 pipeline, an existing transmission line in Ohio and West Virginia that Dominion plans to convert into wet-gas service. Natrium is also close to rail, pipeline, and barging for marketing NGLs.

Canada's Montney shale to get gas plant

AltaGas, Calgary, has let a contract to IMV Projects, a Wood Group company also based in Calgary, for the engineering, procurement, and construction management for the $235 million (Can.) Gordondale sour gas processing plant and associated gas gathering.

The 120-MMcfd plant will lie about 100 km northwest of Grande Prairie in the Gordondale area of the Montney shale gas play. It will include deep-cut liquids extraction to recover NGL before the gas enters the sales gas pipeline and will be on stream by fourth-quarter 2012, following regulatory approval.

IMV Projects has been involved with development of the project since its inception, performing the original scoping study and the front-end engineering design, said the company's announcement.

IMV Projects also designed the expansion of AltaGas Ante Creek processing plant, currently under construction, that includes a new amine train, refrigeration, and gathering.

Flint Hills to buy ethanol plants in Iowa

Flint Hills Resources LP plans to buy two ethanol plants in Iowa from Hawkeye Renewables LLC, which last year restructured its finances under bankruptcy protection.

Flint Hills will buy a 100-million-gal/year plant in Iowa Falls and a 115-million-gal/year plant in Fairbank.

The company, part of Koch Industries Inc., has more than 800,000 of distillation capacity in refineries in Texas, Alaska, and Minnesota.

The refiner already owns ethanol plants with capacities of 110 million gal/year each in Menlo and Shell Rock, Iowa.

In Iowa, it operates a fuel terminal and asphalt plants at Algona, Davenport, and Dubuque. It also distributes fuels in the state.

Flint Hills didn't disclose the purchase price.


Alyeska restarts TAPS while readying bypass

Alyeska Pipeline restarted the Trans Alaska Pipeline Jan. 11 following a 4-day shut down. The company's operations control center began the start-up sequence of opening valves and bringing pumps on line at 7 p.m. local time (OGJ Online, Jan. 10, 2011).

Alyeska shut down the pipeline at 8:50 a.m. on Jan. 8 after crews discovered a leak into containment in the basement of a booster pump building at Pump Station 1.

The restart is part of a multistep plan to restore pipeline operations. The pipeline will run at reduced rates for several days while a 157-ft bypass segment is staged for installation. Once staged, Alyeska will shut TAPS down again while crews complete the bypass project.

The restart will help increase temperatures in tanks and the pipeline, Alyeska explained, reducing the potential for wax in the oil to accumulate or for water in the oil to freeze. It also allows flowing oil to move a cleaning pig from its current location between Mileposts 419 and 420 to Pump Station 8.

The pig could affect the pump station equipment if left in the pipeline too long in cold temperatures. With the pipeline operating again, crews can trap the pig between two valves in the mainline and route crude oil around through bypass piping, Alyeska said.

Alyeska said the restart solves three problems: It avoids a more complex cold restart process, it avoids additional problems that would occur if the pig were in the line when the pipeline begins to get too cold, and it allows North Slope producers to increase production, which will help mitigate freeze concerns on the North Slope.

Harvest to build Eagle Ford crude oil pipeline

Harvest Pipeline Co. has started to construct a 25-mile crude oil pipeline from near Cotulla in LaSalle County, Tex., to an interconnect near Fowlerton, Tex., with its existing 140-mile Pearsall pipeline.

The lateral represents the next phase of Harvest's continuing expansion of its Arrowhead Pipeline in an effort to increase shipments of Eagle Ford crude to refining and terminal facilities in Corpus Christi.

Harvest expects the Cotulla line to enter service in the third quarter. The Cotulla line will be supported with volume commitments from large producers in LaSalle and Dimmit counties, according to Harvest.

Harvest operates pipeline systems running through the Eagle Ford trend from Maverick County to San Patricio County, Tex.

Harvest also operates oil and gas gathering and mainline systems across south Texas and Louisiana.

Koch Pipeline Co. LP received shareholder approval to build a 120,000-b/d Eagle Ford pipeline to Corpus Christi in December 2010 (OGJ Online, Dec. 17, 2010).

More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles
View Oil and Gas Articles on PennEnergy.com