OGJ Newsletter

Nov. 16, 2009

General Interest Quick Takes

EPA directs Texaco to resume Superfund cleanup

The US Environmental Protection Agency has ordered Texaco Inc., which Chevron Corp. acquired in 2001, to assess soil and ground water contamination and evaluate cleanup options for the Pacific Coast Pipeline Superfund site in Fillmore, Calif.

Texaco operated the 52-acre site northwest of Los Angeles as a refinery from 1920 to 1951, contaminating soil and ground water with heavy metals and volatile organic compounds, EPA said on Nov. 4. It said the company cleaned up on-site waste disposal pits in 1986 and, in 1993 under the chemical waste Superfund program, pumped and treated the ground water under EPA's direction.

Benzene is the primary contaminant in the ground water, the federal environmental regulator said in a unilateral administrative order. The benzene plume, which extends 100 yards off the site, does not threaten drinking water wells but concentrations remain above drinking water standards, it added.

The soil has low levels of lead and semivolatile chemicals, such as naphthalene, which also need to be addressed, according to EPA. It said it is updating the Pacific Coast Pipeline Community Involvement Plan to identify opportunities for communication with the public about upcoming activities at the site.

Industry extends funding for marine life research

Oil and gas producers have agreed to extend funding of a joint industry program (JIP) to support research into learning more about how sounds generated by upstream oil and gas activities affect marine life.

Much of the research has focused upon how various types of whales react to sounds and vibrations created by seismic survey equipment.

The JIP on Sound and Marine Life started with a 1-year scoping phase in 2005 followed by a 3-year phase that started in May 2006. The International Association of Oil & Gas Producers announced a 3-year funding extension on Nov. 11. OGP is based in London.

John Campbell, OGP technical director, said the extension will "enable us to continue supporting key research that assists regulatory and technical organizations in understanding the complex marine environment."

A core of 10 of the original JIP participants agreed to extend the fund. They are BG Group, BHP Billiton, Chevron Corp., ConocoPhillips, Eni SPA, ExxonMobil Corp., the International Association of Geophysical Contractors, Santos Ltd., Statoil ASA, and Woodside Petroleum Ltd.

One of the first JIP projects led to developing acoustic-monitoring software that helps operators detect the presence of marine mammals within exploration and development areas.

Since May 2006, the JIP has funded 62 projects, and various government groups worldwide have helped funded many of these projects. JIP research addresses:

• Sound source characterization and propagation in the ocean.

• Physical, physiological, and hearing effects of sound on marine life.

• Behavioral reactions and their biological significance to sound in the marine environmental.

• Mitigation, monitoring, data analysis, and management.

Oil and gas group forms in Greenland

Responding to "a continuously increasing focus on the possibilities for oil and gas production in Greenland," seven operators have formed a trade association anticipating industry development in the country.

Founding members of the Greenland Oil Industry Association are DONG E&P Greenland AS, Esso Exploration Greenland Ltd., Chevron Greenland Exploration AS, Husky Oil Operations Ltd., Capricorn Greenland Exploration Ltd. (a subsidiary of Cairn Energy PLC), PA Resources AB, and Nunaoil AS.

All the companies have interests in exploration licenses off western and southern Greenland (see map, OGJ, Aug. 24, 2009, p. 38). At present, Greenland produces no oil or gas.

In a press statement, DONG Energy said members of the group will pursue safety and environmental stewardship, knowledge sharing, public and governmental communications, and development of a competitive industry.

Industry Scoreboard

Exploration & Development Quick Takes

New Zealand's Maari-Manaia tops 100 million bbl

Estimated ultimate recovery of more than 100 million bbl of oil has been confirmed for OMV AG-operated Maari field and adjacent Manaia field in the offshore portion of New Zealand's Taranaki basin, two of the field's partners said.

OMV, which declined comment on reserves and production until a full evaluation is complete, plans to place on production an extended reach well that at 26,250 ft is New Zealand's longest penetration. That well, Manaia-1, penetrated a Mangahewa formation reservoir on the Manaia structure.

The new recovery figure is twice the volume initially estimated for the main Moki sands reservoir at Maari. New Zealand's next largest producing area is the Tui fields at an original 50 million bbl.

Recent additional discoveries at Manaia and the Maari M2A sands plus the main Moki reservoir together "amount to over 100 million bbl of recoverable oil," said Richard Tweedie, chairman of Maari minority partner Cue Energy. Maari field went on production in April.

The Manaia extended reach well is to be tied into Maari facilities and begin producing within months. Production from the M2A zone well in the Moki sands, 50 m above the main reservoir, is expected to start by yearend.

Another Maari partner, Horizon Oil, said the additional reserves will extend the field's production plateau. The MR9 well to the M2A zone will produce intermittently when capacity becomes available.

Horizon said the Manaia-1 horizontal well cut 1.5-km-long Mangahewa reservoir section with a net-to-gross pay factor of 60-70% and that logs and gas-oil ratio analyses confirm the presence of oil throughout.

There was no revision to the predrill oil in place estimate of 50-60 million bbl at this stage. Horizon said oil in place estimate for the Maari M2A zone is 30-40 million bbl (OGJ Online, Oct. 7, 2009).

Exploratory wells have penetrated two more oil zones at Maari that are not yet appraised, Horizon noted. They are the deeper Mangahewa formation at Maari and the shallower Moki formation at Manaia.

Maari-Manaia interests are OMV 69%, Todd Energy 16%, Horizon Oil International 10%, and Cue Energy Resources 5%. Todd Energy owns 27% of Cue.

EOG sees reserve hike in Barnett Combo play

Improved horizontal completion techniques in the North Texas Barnett Combo play have led EOG Resources Inc. to estimate that ultimate recoveries in one area will be 80% higher than the company's early 2008 estimates in the play.

The new EUR figure for wells in eastern Montague and western Cooke counties is 280,000 boe, EOG said.

The two recent horizontal wells, Christian A-1H and B-1H, had initial production of 1,000 b/d and 6,000 b/d of oil and 2.5 and 2 MMcfd of gas, respectively. EOG has 100% working interest.

Meanwhile, in the play's core area, where pay intervals are thickest, EOG has been developing its acreage with vertical wells that are expected to recover more than 220,000 boe. For example, the Fitzgerald-1 and Stephenson-1 vertical wells had initial rates of 1,100 b/d and 450 b/d of oil and 2.1 MMcfd and 700 Mcfd, respectively. EOG's interest is 100%.

The company, which rarely makes acquisitions, made a tactical purchase of 7,800 net acres in the two counties in the quarter ended Sept. 30.

Reliance reports Cambay oil discovery

Reliance Industries Ltd., Mumbai, reported a Miocene oil discovery in the Cambay basin southwest of Ahmedabad, India, that Reliance said "is expected to open future potential within the block."

CB10A-A1, Reliance's fifth well, went to a total depth of 1,451 m in Part A of the two-part block and flowed at a rate of 500 b/d of oil from the Babaguru formation of Miocene basal sand on a 6-mm bean with 360 psi flowing tubinghead pressure. The well has a gross reservoir thickness of 15 m.

Block CB-ONN-2003/1, won in India's fifth licensing round, has two parts in Gujarat. Part A to the west covers 570 sq km, and Part B to the east covers 65 sq km. Reliance, which holds 100% participating interest, named the discovery Dhirubhai-43.

Reliance has shot 3D seismic data over 80% of the block and 2D data over its entirety. Based on interpretation of the 3D data, Reliance has identified several prospects at different stratigraphic levels to fulfill the minimum work obligation under the production sharing contract.

GeoResources Bakken participation growing

GeoResources Inc., Houston, said the pace of activity in the Williston basin Bakken/Three Forks play is increasing in its joint venture with Slawson Exploration Co., private Wichita-based operator.

GeoResources expects to participate in 60 joint venture wells in the next 18 months and will hold minor interest in numerous other wells. The company has 10-18% working interest in 110,000 net acres in the Bakken and has a 100% success rate with 34 Slawson-operated wells.

GeoResources, which continues to acquire land, said 63,000 acres are in Mountrail County, ND, on the east side of the Nesson anticline.

The company also owns minor working interests with multiple operators in more than 125 wells in the Bakken/Three Forks play in different parts of the basin.

Most wells in which GeoResources participates will be on 640-acre units, but the company is scheduling 1,280-acre and some larger spacing units and has numerous locations that may result in or require the larger units.

Completed well costs for single-lateral wells on 640-acre units are $3-3.5 million. Initial production rates have improved as the number of frac stages increases, and recent wells have had 18 stages. Three rigs are running and a fourth rig joins in from time to time.

Drilling & ProductionQuick Takes

Rio Napo JV starts operations at Sacha field

Rio Napo, a 70-30 joint venture of Ecuador's state oil company Petroecuador and Venezuela's Petroleos de Venezuela SA (PDVSA), has begun operating Sacha oil field in Ecuador's Amazon.

Marco Nogera, Rio Napo's manager of planning, said the firm plans to reach output of 70,000 b/d of oil by 2014-15—an increase of 40% over the current 49,780 b/d—or about 10% of Ecuador's total oil production. Sacha field holds 491 million bbl of oil reserves.

According to Nogera, the JV plans to invest $621 million in exploration and production activities at Sacha over the next decade, with about 60% of the investment coming in the next 5 years. In September Rio Napo signed a service contract with Petroproduccion, a Petroecuador subsidiary, for Sacha field. PDVSA said the contact was to "manage, increase production at, develop, optimize, integrally improve, and exploit" the Sacha site.

Analyst BMI said Sacha is "one of the country's largest producing fields, but insufficient investment has meant that, as is the case with several other fields operated by Petroecuador, it has yet to reach its full potential."

BMI added that the Rio Napo JV is one of a series of accords reached between Ecuador and Venezuela since President Rafael Correa took power, in line with the strategy of the Venezuelan leader Hugo Chavez of offering "special treatment" to his leftist allies in the region.

In addition to Venezuela, Ecuador last month also signed an E&P contract for its Oglan field with a joint company of Petroecuador and China Petroleum & Chemical Corp. (Sinopec).

With the agreement, Sinopec joins a handful Chinese state oil companies that have positioned themselves in the Ecuadorian market as partners of Petroecuador, including China National Petroleum Corp., Andes Petroleum, Petroriental, Sinopec, and CPEB Changqing Petroleum.

Petroecuador also started talks with Angola's Sonangol, which is interested in Blocks 28 and 29 in the Amazon region as well as offshore Block 42. In April Petroecuador and Sonangol signed an agreement to cooperate in several blocks in Ecuador.

PSAC sees low 2010 Canadian drilling activity

The Petroleum Services Association of Canada (PSAC) expects the oil and gas industry to drill 8,000 wells in Canada during 2010.

This number of wells is about the same as its current forecast for 2009, which is 1,500 wells less than it expected in July and considerably less than the 16,000 wells it had forecast at yearend 2008.

PSAC's 2010 breakdown by province and change from 2009 is 5,095 wells in Alberta (a 5% decrease), 630 in British Columbia (a 7% increase), 1,935 wells in Saskatchewan (a 10% increase), and 300 wells in Manitoba (a 22% increase).

PSAC noted that it sees adequate oil prices in 2010 to sustain conventional drilling activity in areas such as Saskatchewan and northeast Alberta, but continued low gas prices that will reduce by 30% conventional shallow-gas drilling in southeast Alberta.

PSAC based its 2010 forecast on an average $5 (Can.)/Mcf gas price and a $72/bbl West Texas Intermediate oil price.

Contract let for coal gasification plant

Tenaska Energy Inc., Omaha, has let a contract to Siemens Energy for coal gasification technology at the planned Taylorville Energy Center (TEC), one of the first commercial-scale facilities of its kind in the US to use carbon capture and sequestration.

Siemens will provide equipment contracts and licensing agreements for four 500-Mw-class gasifiers.

TEC, in Taylorville, Ill., will have gross generating capacity of 730 Mw, and net capacity of 500-525 Mw.

It will use a hybrid integrated gasification combined-cycle process to convert coal into synthesis gas, which in turn will be converted into methane, called substitute natural gas (SNG) by project sponsors, to fuel power generation.

Officials of Tenaska, TEC managing partner, expect the facility to produce about 33 trillion btu of SNG/year.

Volumes not needed as fuel for two gas turbines will move to a connection with the interstate pipeline system. Amounts will depend on coal and gas prices. Officials say current modeling indicates the SNG pipeline volume will be about 10 trillion btu/year.

The project will capture as much as 3 million tons/year of carbon dioxide at the synthesis gas stage, more than half its output of the greenhouse gas. It will sequester the CO2 underground near the plant site or sell it for use in enhanced oil recovery.

Tenaska and Siemens officials say capturing that much CO2 will make the TEC comparable in greenhouse gas emissions to a power plant fueled by natural gas.

The facility is expected to cost $3.5 billion. The US Department of Energy has selected the project for negotiation of loan guarantees totaling as much as $2.579 billion under a program created by the Energy Policy Act of 2005.

DOE last month issued a notice of intent for the preparation of an environmental impact statement for the TEC loan guarantee.

Processing— Quick Takes

Western Refining trimming New Mexico units

Western Refining Inc., El Paso, is consolidating operations of its two small refineries in New Mexico to reduce operating costs in a period of shrunken refining margins.

To be consolidated at Gallup are the 23,000 b/d refinery there and the 17,000 b/d facility at Bloomfield, which will be idled. Western said total crude throughput will not decline from recent combined levels, which in the first 9 months of this year averaged 25,560 b/d.

The company said the move will cut operating costs by about $25 million/year beginning in the first quarter of 2010.

The Gallup refinery's processing capacities include 7,000 b/d of catalytic cracking, 8,000 b/d of catalytic reforming, 16,500 b/d of catalytic hydrotreating, 2,500 b/d of alkylation, and 5,000 b/d of isomerization.

Bloomfield's capacities are 5,000 b/d of catalytic cracking, 5,100 b/d of catalytic reforming, 8,300 b/d of catalytic hydrotreating, and 2,000 b/d of polymerization.

The refineries, about 95 miles apart, process mainly light sweet crude and natural gas liquids produced nearby. Western owns more than 250 miles of crude gathering lines.

"The company is evaluating alternative uses for the Bloomfield refinery, including the possibility of biofuels production," Western said in a press statement.

Western also operates a 128,000 b/d refinery in El Paso and a 70,000 b/d refinery in Yorktown, Va.

Citing the margin squeeze and low differentials between heavy and sour crude, the company reported a third-quarter loss of $4.8 million, compared to a profit of $109.2 million for the same period last year.

Three refineries pending for Pakistan

Three refineries with a total capacity of 465,000 b/d "are in the pipeline," Pakistan Minister for Petroleum and Natural Resources Naveed Qamar told the National Assembly.

Included are the 250,000-b/d Khalifa Coastal refinery and the 115,000-b/d Bosicor Oil Pakistan Ltd. facility, both in Hub, Balochistan Province; and the 100,000-b/d Trans-Asia Refinery Ltd. facility at Port Qasim in Karachi.

Existing refineries in Pakistan include the 100,000-b/d Pak-Arab refinery; the 62,050-b/d National refinery; the 47,110-b/d Pakistan Refinery Ltd. facility; the 42,000-b/d Attock refinery; the 30,000-b/d Bosicor Pakistan facility; the 2,500-b/d Dhodak Refinery Ltd. facility; and the 2,646-b/d Enar Petrotech Services Ltd. facility.

As an incentive to attract local and foreign investment, the current petroleum policy requires no prior government permission for a new refinery project.

The minister said refineries are free to sell their product to any marketing companies, or they can set up their own marketing firms. The Pakistan government recently approved additional incentives for all new megaprojects of minimum 100,000 b/d production capacity to be installed along the coastal belt of Balochistan, particularly Gwadar, with 20 years income-tax holiday, he added.

The terms and conditions contained in the Ministry of Commerce trade policy for 2008-09 will be applicable for import of second-hand refinery project in its letter and spirit. The sponsors shall ensure the design of second-hand refinery is thoroughly reviewed and verified by an independent engineering consultant.

TransportationQuick Takes

Transneft poses export tariff zones for ESPO line

Russia's OAO Transneft has proposed dividing its East Siberia-Pacific Ocean oil pipeline into three export tariff zones, according to a company official.

Spokesman Igor Dyomin said Transneft wants the ESPO line to be divided into the eastern, western, and central export tariff zones, with $34/tonne charged for oil transported via the eastern zone, $48/tonne via the western zone, and $42/tonne via the central zone.

The eastern zone will extract oil from Talakan field, the western zone from Vankor field, and the central zone from fields in the southern Krasnoyarsk territory, said Dyomin, who added that the proposals already have been filed with the Russia's Federal Tariffs Service.

Transneft expects the tariff for oil transportation through its system to increase in 2010 at a rate comparable with inflation, said Dyomin, who added that the state firm has no plans to increase its tariff proportionally to the growth of its expenses, which are expected to rise by 30%.

Russian authorities last month said oil for the line is to be branded Vsto, and will be light and medium-sour, superior to Urals export blend but inferior to Siberian Light (OGJ Online, Oct. 12, 2009).

Moldova to investigate gas pipeline explosion

Moldovan Prime Minister Vladimir Filat said his government has established a commission to investigate the cause of an explosion on a natural gas trunkline that supplied the Balkans with Russian gas.

A section of the line, about 70 km southeast of Moldova's capital Chisinau, burst on Nov. 8 and cut supplies to 34 Moldovan villages and towns but left gas transit to the Balkans unaffected.

MoldovaGaz Chief Executive Officer Alexander Gusev said the blast may have occurred due to wear-and-tear or even negligent work in its construction. Earlier this year, another blast occurred along the pipeline in the self-proclaimed Dniester Republic, and was attributed to wear-and-tear.

"The country's gas pipelines are ageing while no serious investment in upgrades has been made or is on the horizon," said analyst IHS Global Insight. "With the onset of winter and no imminent investment on the horizon for Moldova's gas pipeline network, further explosions and gas disruptions may well occur."

First phase finished for PNG LNG project

ExxonMobil Corp. and its joint venture partners completed the front-end engineering and design phase for their Papua New Guinea LNG project.

All that is needed before a final investment decision for the project are a benefit-sharing agreement with the Papua New Guinea government, expected in the next few weeks, and ExxonMobil finalizing loan finance as well as sales and purchase agreements with customers.

Papua New Guinea Prime Minister Michael Somare said the project would help transform the economy and raise living standards in the country.

About 60,000 landowners in remote rural areas will be direct beneficiaries of royalties and dividends in addition to the increased capacity of the national, provincial, and local governments to improve infrastructure and services.

ExxonMobil and its partners are already implementing a number of programs, including work on building training facilities for 1,000 people at Juni in the Southern Highlands and in Port Moresby.

Work will be carried out to help landowner companies via the provision of jobs and cash dividends.

The Papua New Guinea LNG project will cost $15 billion and have the capacity to produce 6.6 million tonnes/year of LNG. The country's Department of Environment and Conservation approved its environmental impact statement.

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