OGJ Newsletter

Aug. 3, 2009

General InterestQuick Takes

Court lets MMS sales outside Alaska proceed

A federal appeals court clarified its order vacating the current federal offshore oil and gas leasing program on July 28 by saying that the ruling applies only to the Alaska portion of the plan.

The action clears the way for the US Minerals Management Service to proceed with lease sales on other areas of the Outer Continental Shelf. “We are moving forward with the planned Aug. 19 Gulf of Mexico lease sale,” US Interior Secretary Ken Salazar said on July 29.

He sought the clarification on May 11 after the US District Court of Appeals for the District of Columbia decided on Apr. 17 that the Bush administration did not use sound science when it expanded leasing areas in the Beaufort, Bering, and Chukchi seas for the 2007-12 OCS plan. It issued an order vacating the program and ordered a rewrite after more thorough studies had been conducted.

Through the US Department of Justice, Salazar asked the court to clarify that the order applied only to the Alaskan parts of the 5-year plan, and that sales in other areas could proceed. The American Petroleum Institute also sought a similar clarification.

The new order stated that relief granted in the Apr. 17 opinion applied only to Alaska, “specifically leasing in the Chukchi, Beaufort, and Bering seas.”

Salazar said, “I am pleased with the court’s decision. With respect to the Arctic Ocean and Alaska, we will continue to work expeditiously to address the environmental issues identified by the court in the existing 2007-12 5-year plan.”

In a July 29 statement, API encouraged DOI “to move quickly to redo the environmental sensitivity analysis and maintain all scheduled past and future leasing in Alaska so that exploration and production activity and future leases sales under the 2007-12 plan can take place in that state.”

ICE agrees to be regulated after CFTC ruling

The InterContinental Exchange (ICE) agreed to be regulated after the US Commodity Futures Trading Commission (CFTC) effectively ruled that one of ICE’s natural gas contracts should no longer be exempt.

The ruling came July 24 when CFTC, using new authority to apply regulatory and reporting requirements to exempt commercial markets with significant price discovery functions, ruled that ICE’s Henry Financial LD1 Fixed Price Contract fit that description.

ICE declared itself a registered CFTC entity on July 27 and announced that it would begin submitting enhanced market statistics for its cash-settled Henry Hub gas swap market to the commission immediately. It said that clearing firms will begin providing large insider trading data to the CFTC, that ICE’s data will be incorporated in the commission’s weekly Commitment of Traders Report, and that the Henry Hub swap will be subject to position limits and accountability levels.

CFTC announced on June 9 that it would review the contract to determine whether it performed a significant price discovery function and should no longer be exempt, exercising authority for the first time which it received when the 2008 farm bill became law.

It based its July 24 decision on further analysis of the contract and its characteristics, including its high average daily trading volume, its reliance on the New York Mercantile Exchange’s physically delivered gas futures contract, and trader usage of the ICE contract’s prices.

With clear indications that the ICE contract satisfied these three conditions, the commission did not analyze possible material price reference and consequently reached no conclusion on this fourth qualifying condition, CFTC said.

ICE noted that it has worked with CFTC since October 2006 in developing regular over-the-counter market reporting, including large trader information.

“We appreciate the CFTC’s use of its broad powers in the OTC markets to provide regulatory certainty and to underscore the integrity of these important contracts,” said Jeffrey C. Sprecher, the exchange’s chairman and chief executive.

NARUC backs regulation of hydraulic fracturing

State utility regulators approved a resolution at their summer convention in Seattle urging Congress to leave regulation of hydraulic fracturing to the states.

The resolution by the National Association of Regulatory Utility Commissioners’ gas committee said the organization “has observed with great concern the current debate in Congress over the appropriate method for regulating the use of hydraulic fracturing to complete oil and gas wells.”

US Reps. Diana DeGette (D-Colo.) and Maurice D. Hinchey (D-NY) introduced a bill on June 4 which would bring the process, which is used to recover gas from shale formations, under the Safe Drinking Water Act. US Sen. Robert P. Casey Jr. (D-Pa.) introduced similar legislation in the Senate the same day.

Doing so, NARUC’s resolution said, “would add burdensome and unnecessary regulatory requirements to the drilling and completion of oil and gas wells, thereby increasing costs of producing domestic natural gas resources without any ancillary benefit to public health, safety, or the environment.”

The resulting increased cost of producing domestic gas resources would reduce domestic supplies; raise costs to consumers; raise utility prices for consumers; reduce tax and royalty revenue for local, state and federal governments; and increase US dependence on foreign energy imports, it continued.

Oil and gas reservoirs are highly variable geologically and separated geographically across producing states in a manner that makes state regulatory agencies best suited by local expertise to regulate hydraulic fracturing and other exploration, development and production activities, the resolution observed.

It noted that the Interstate Oil & Gas Compact Commission urged Congress on Jan. 9 to not remove hydraulic fracturing’s exemption from regulation under the SDWA after a survey of IOGCC’s members found no known cases of groundwater contamination associated with hydraulic fracturing.

Industry Scoreboard

Exploration & Development —Quick Takes

Anadarko finds oil at Vito in deepwater gulf

A group led by Anadarko Petroleum Corp. said the Vito exploration well cut more than 250 net ft of oil pay in subsalt Miocene sands and plans to drill two other prospects along trend in the deepwater Gulf of Mexico.

Vito went to 32,000 ft in 4,038 ft of water 170 miles south-southeast of New Orleans in Mississippi Canyon Block 984. The partners will evaluate data from Vito and set the timing for an appraisal well.

Anadarko plans to drill its Haleakala prospect to the west and Silverado to the east in 2010. Both target similar subsalt Miocene objectives.

Anadarko will move the Noble Amos Runner semisubmersible to the Caesar/Tonga development in the Green Canyon area.

Anadarko operates Vito with 20% working interest. Shell Offshore Inc. owns 55%, and StatoilHydro USA E&P Inc. has 25%. Shell will become Vito operator after the rig is released.

Mexico institute recommends upstream opening

The Mexico Competitiveness Institute (IMCO) has called for dramatic policy steps to confront Mexico’s decline in the world economy.

The institute, which studies the relative competitiveness of 48 countries, reported that Mexico had fallen two places in the ranking to 32nd in the 3 years ended in 2007. Worse, it said that Mexico had retreated in eight of the 10 key variables that matter most.

Regarding energy policy liberalization, Mexico was the only country that scored zero on IMCO’s index scale of zero to three.

The institute also took note of the fall in Mexican oil production, which since 2004 represented a 700,000 b/d drop that has been a severe blow to public finances.

Mexico may be facing its last opportunity to counter the trend—that is, before the aging of the Mexican population and the spread of poverty render societal changes irreversable.

With this dark landscape in view, it may not be surprising that IMCO should propose a course of action to maximize Mexico’s potential petroleum rent by inviting private industry to take part in exploration and production activities and to be compensated on a competitive basis. Every year of delay in reversing the fall in oil production and fiscal flow costs the Mexican economy $40 billion, IMCO estimated.

Each section of IMCO’s report contained an invited essay. Preparing the essay on energy was George Baker of Houston, the only non-Mexican among 23 contributors. That essay focused on the natural gas value chain in Mexico.

ECA presses Pennsylvania Marcellus work

Energy Corp. of America, a private Charleston, W.Va., operator, is developing gas production from Devonian Marcellus shale in Greene County in the southwest corner of Pennsylvania.

In May, the company began a 3-year program to develop 10,000 acres it holds in the county. It is producing 8 MMcfd of gas from wells completed only in the Marcellus and more than 15 MMcfd from vertical wells in which it has commingled Marcellus gas with output from other formations.

Two rigs are drilling horizontal wells to the Marcellus, which lies at about 8,000 ft true vertical depth in Greene County. The company holds more than 1 million acres in the Appalachian basin on which the Marcellus varies in depth from 3,000 ft to 8,000 ft.

ECA has drilled 155 Marcellus vertical and horizontal Marcellus wells, and initial potentials of the completed wells have ranged from 500 Mcfd to 3 MMcfd. The wells produce little condensate.

ECA drilled one of the first horizontal wells in Greene County in 2007 as part of a joint venture with an industry partner, but it operates and wholly owns almost all of its wells.

The company owns more than 40 miles of pipeline and has sufficient capacity available on interstate systems to market its production.

CNX Gas expands Marcellus shale position

CNX Gas Corp., Pittsburgh, leased nearly 40,000 acres with Marcellus shale gas potential in Pennsylvania and West Virginia, bringing its total Marcellus position to 230,000 acres.

In one transaction, CNX leased 20,000 largely contiguous acres from NiSource Energy Ventures LLC, a subsidiary of Columbia Energy Group, in Washington and Greene counties, Pennsylvania, and Marshall County, West Virginia.

In a second deal, CNX leased 20,000 acres from its majority owner, CONSOL Energy Inc. These acres, though not contiguous, are generally located in and around CONSOL’s coal operations in Washington and Greene counties, Pennsylvania, and Marshall, Monongalia, and Wetzel counties, West Virginia. CONSOL acquired the lands in connection with its mining operations, after the sale of CNX common stock in 2005.

The acreage in the two transactions have the potential to provide CNX with hundreds of Marcellus shale drillsites in an area where the company has averaged 3.5 bcf/well recoverable at its first eight horizontal wells.

Results of microseismic data analysis have enabled CNX to begin using 40-acre well spacing for the horizontal Marcellus shale program. It will be able to accelerate drilling once gas prices rebound.

Cabot nails vertical Marcellus-Purcell interval

Cabot Oil & Gas Corp., Houston, is producing 39 MMcfd of Marcellus shale gas from seven horizontal and 20 vertical wells in northeastern Pennsylvania, where it notched a critical success with one of its latest vertical completions.

Cumulative recovery is 5.8 bcf since the company’s first Marcellus well came on line a year ago in Susquehanna County.

A ninth rig is preparing to spud, and 18 more horizontal wells are to be drilled this year. Three other wells are completing, and 12 are waiting on completion or pipeline hookup.

The most recent horizontal completion, Teel-8H, flowed at an initial 10.3 MMcfd with a maximum spot rate of 12 MMcfd, and its 30-day average is 9.8 MMcfd.

The vertical Teel-6 had initial flow of 4.2 MMcfd from 370 ft of lower and upper Marcellus, and Cabot believes the stimulation contacted most of that interval including the gassy Purcell limestone that separates them.

Cabot called Teel-6 “a critical event in the development of our Marcellus acreage” because the size and shape of its individual leases on its large acreage block limit much of the drilling to vertical wells.

The $1.4 million well is also the first at which the company stimulated the entire column, whereas it has fract its horizontal wells entirely in the lower Marcellus and only slightly in the curved section has it treated the upper Marcellus.

Cabot is hiking takeaway capacity at its Teel compression station to 70 MMcfd on Aug. 1 and 100 MMcfd a year later.

Drilling & Production —Quick Takes

Tuned water may improve Saudi waterflooding

Minimal chemical alteration to injection water may help increase oil recovery, researchers at Saudi Aramco’s EXPEC Advanced Research Center say.

“If the current lab results are demonstrated in the field, it will change the way we conduct waterflooding in the company,” said Amin H. Nasser, senior vice-president of exploration and producing for Aramco. “The application of this approach will not be limited to mature fields but also to fields in early development stages.”

At the laboratory scale, early tests indicate significant incremental oil recovery from Arab-D carbonate reservoirs, the company says.

Aramco’s main seawater treatment facility, Qurayyah, processes millions of barrels per day of water for injection into the giant Ghawar and Khurais oil fields.

The research focuses on optimizing water properties such as salinity and ionic interactions without adding foreign fluids or chemicals.

“This research seems to have changed our perception of waterflooding from being a mere physical process—increasing reservoir energy and sweeping oil toward producers—to one that also entails chemical interactions between reservoir fluids and rocks,” said Mohammed Y. Al-Qahtani, executive director of petroleum engineering and development for Aramco.

Indonesia wants lower cost-recovery write-offs

Members of Indonesia’s House of Representatives, in a move to head off a potential budget shortfall, have urged the government’s upstream watchdog BPMigas to reduce the cost recovery given to oil and gas contractors.

“For now, BPMigas should limit the amount of cost recovery,” to $10 billion from $11.05 billion said Suharso Manoarfa, vice-chairman of the House’s budget committee, in a hearing with the government and the central bank.

The move aims to decrease the budget deficit in case the Indonesian Crude Price (ICP) falls to $58/bbl at yearend or oil lifting is lower than the 960,000 b/d level set in the planned revision of the 2009 budget.

“If the ICP is $58/bbl [during this year’s second half], there will be a 9 trillion rupiah deficit in state revenue,” said Suharso, who also noted that during January-June, oil production reached 953,000 b/d and will need to reach 967,000 b/d for the remainder of the year to achieve the government target of 960,000 b/d for 2009.

Finance Minister Sri Mulyani Indrawati said she would ask the energy and mineral resources ministry to balance the amount of cost recovery spent and the amount of oil sold in order to prevent a negative net income in oil and gas revenue.

In April, the Indonesian government drafted new rules aimed at reducing national expenditure by redefining some cost components as downstream instead of upstream.

At the time, Indonesia’s energy and mineral resources minister Purnomo Yusgiantoro said, “We hope that this will decrease spending on cost recovery in our state budget (OGJ, Apr 27, 2009, p. 37).

Shell orders pumps for St. Joseph field off Sabah

Shell Malaysia Exploration & Production BV placed an $8 million order for Flowserve Corp. barrel-type injection pumps for its waterflood development in St. Joseph field, off Sabah.

Shell operates St. Joseph field under the North Sabah 1996 production-sharing contract with coventurer Petronas.

Shell expects water injection to start in 2010, according to a presentation to the International Petroleum Technology Conference, Kuala Lumpur, Dec. 3-5, 2008.

The presentation, “St. Joseph Field Waterflood Project: Fractured Water Injection Using Smart Well Technology,” by Darryl Harris, Nicolette G. Du Rieu, and Keith Ian Rollett of Sarawak Shell Bhd., describes St. Joseph as a mature oil field that has been on production since 1981, with gas injection starting in 1996.

It says the scope of the waterflood development includes installation of a new offshore living quarters platform and seawater treatment and injection facilities plus drilling of six horizontal water injection wells and five infill wells.

The presentation says that the flood will involve the injection of treated seawater at a rate of 60,000 bw/d into a laminated reservoir with historical problems of controlling water and gas breakthrough through high permeability streaks.

It adds that smart technology will facilitate the injection under fracturing conditions into five completed zones. It says injection will proceed simultaneously in two zones with zones being alternated several times a year.

Processing —Quick Takes

Plans suspended for New Brunswick refinery

Irving Oil and BP PLC have suspended plans to build a 300,000-b/d refinery at St. John, NB (OGJ, Mar. 24, 2008, Newsletter).

The companies said an 18-month feasibility study determined the Eider Rock project “was not viable at a time of global economic recession and dampening forecasts for petroleum product demand in North America.” Privately held Irving operates a 250,000-b/d refinery at St. John.

French crude oil imports down in first half

During the first half of 2009, France’s hydrocarbon port of Fos-sur-Mer on the French Riviera posted a 7% drop in oil imports intended for both for French and European refineries. By the end June, 30.06 million tons of hydrocarbons—both liquids and gases—were traded at Fos, 4% less than over the same 2008 period.

Input into French refineries suffered a drop as well, falling 3% vs. the same half in 2008. Besides the economic slump, this was also due to the technical shutdown of Total’s Feyzin refinery and the Petroplus refinery at Reichstett for turnaround maintenance.

However, stockdraw that was carried out over the last month or two pushed up imports of refined products by 16% in June, stabilizing the first half’s overall totals.

Transportation —Quick Takes

Europe’s LNG imports for July, August to set mark

LNG shipments to Europe will increase by more than 40% in July and August, according to the latest edition of European LNG Report from market analysis firm Waterborne, Houston. This development, says Waterborne, will continue to depress natural gas prices on the continent. “We are adjusting our forecast numbers upward for European LNG imports in July and August based on strong import growth expected in the UK and Belgium,” says Steve Johnson, Waterborne president.

Under shipment scenarios devised by Waterborne, total European LNG imports for July will exceed 4.5 million tonnes, setting a record for 1-month imports and representing a 40% increase over July 2008. For August, total European imports will reach nearly 4.2 million tonnes, a 45% jump over the same month last year.

Shipments to Spain will lead European importing countries in both months, reaching more than 1.8 million tonnes in July and more than 1.6 million tonnes in August, according to Waterborne. France will import 804,000 tonnes in July and 844,000 tonnes in August.

The UK will receive 732,000 tonnes of LNG in July followed in Augsut by 552,000 tonnes. Dragon LNG’s terminal at Milford Haven, Wales, received its first commissioning cargo on July 14, weeks earlier than expected. “We are also projecting increased LNG shipments from Qatar into Milford Haven’s South Hook terminal, which opened in May,” says Johnson.

The July edition of the European Waterborne LNG Report looks at the effect of the Medgaz pipeline on Europe’s LNG markets, if planned, new pipeline connections are built across the Pyrenees.

Woodside opts for Broome support base

Woodside Energy Ltd., Perth, has signed an option agreement with the Broome Port Authority to lease 15 hectares of land as a service and support base for its proposed Browse LNG development off Western Australia.

Woodside has an option period of 3 years in which to execute the minimum 25-year lease.

The Browse fields include Torosa, Brecknock, and Calliance, which lie about 425 km north of Broome. Combined contingent resources are estimated at 14 tcf of dry gas and 370 million bbl of condensate. Woodside is still considering the type of facilities it will need to develop the field and where they will be located.

Santos issues FEED contract for Gladstone LNG

Santos Ltd., Adelaide, has issued a contract to Fluor Corp. for the front-end engineering and design of Santos’s Gladstone LNG coalseam gas project in Queensland.

When completed, Gladstone LNG will produce 3-4 million tonnes/year of LNG from a gas supply of about 5.4-7 million cu m/year from Santos-operated coalseam gas fields in Queensland’s Bowen and Surat basins.

The scope of the work for this contract, according to Fluor, includes preparation of an execution plan and cost estimate for engineering, procurement, and construction of upstream facilities required to deliver coalseam gas from Santos-operated, coalseam gas fields in central Queensland to the proposed Gladstone liquefaction plant near Gladstone. As operator of Gladstone, Santos has a 60% share of the project.

Malaysian state oil company Petronas holds 40% (OGJ Online, June 18, 2009). The joint venture will develop and operate the 435-km gas pipeline to Gladstone and the LNG liquefaction plant on Curtis Island at Gladstone.

Reward for help solving Dawson Creek bombings

EnCana Corp., Calgary, has doubled its reward offer to $1 million for help in solving six bombings of its natural gas facilities in the Tomslake area near Dawson Creek, BC.

The company says the Royal Canadian Mounted Police is investigating the six bombings that occurred between October 2008 and July 2009 at three pipeline locations, a metering shed on an EnCana wellsite, and two wellheads.

The most recent attack on a wellhead occurred on July 1 and took 4 days to bring under control, EnCana says.