OGJ Newsletter

Jan. 3, 2011
International News for Oil and Gas professionals

GENERAL INTEREST - Quick Takes

US court denies NPRA-API challenge of RFS changes

The federal appeals court for the District of Columbia rejected the National Petrochemical & Refiners Association's and American Petroleum Institute's petition to set aside changes the US Environmental Protection Agency made in the federal renewable fuels standard.

NPRA and API argued the changes violated 2009 and 2010 biomass-based diesel fuel requirements, were impermissibly retroactive, and did not comply with statutory lead time and compliance provisions for renewable fuels established by the 2005 Energy Policy Act and expanded by the 2007 Energy Independence and Security Act.

"EPA had clear albeit implicit authority under EISA to apply both the 2009 and 2010 volume requirements in the 2010 calendar year in order to achieve the statutory purpose," Judge Judith W. Rogers wrote in her Dec. 21 opinion. "The structure of EISA demonstrates that Congress anticipated the possibility of some retroactive impacts in the first year of the expanded renewable fuel program."

NPRA President Charles T. Drevna expressed disappointment and concern over the ruling. "The legal petition before the court did not seek to challenge or call into question the important role biofuels play in our nation's transportation policy," he said. "Rather, the issue is one of fundamental fairness in EPA's rulemaking process. This retroactive regulation by a federal agency establishes a deeply troubling and potentially far-reaching precedent."

"This is a disappointing decision. Setting requirements to blend certain biofuels for the previous year is a legally questionable retroactive action," said Patrick Kelly, a senior policy advisor in API's downstream fuels issues group.

API supports a realistic and workable RFS and its members are committed to meeting the regulatory requirements, he continued. "This decision significantly complicates compliance and may set a dangerous precedent allowing retroactive requirements for past compliance periods," Kelly said.

Sasol to buy stake in Montney shale gas

Sasol Ltd. agreed to buy a 50% stake in Talisman Energy Inc.'s Montney shale gas play in the Farrell Creek project in northeastern British Columbia for $1.05 billion (Can.), and the two companies plan a Farrell Creek area partnership that Talisman will operate.

Talisman Pres. and Chief Operating Officer John A. Manzoni said Sasol's expertise will help Talisman decide whether to build a gas-to-liquids plant in western Canada. Terms of the transaction call for an economic feasibility study regarding a GTL plant.

"This could provide a strategic alternative to traditional North American pipeline or liquefied natural gas marketing," Talisman said. Sasol uses its Fischer-Tropsch technology to transform natural gas into gasoline and diesel in South Africa and Qatar.

"The outlook for GTL could be very positive if North American natural gas prices continue to decouple from oil prices," Talisman said.

Closing, subject to regulatory approval, is expected during the first half of 2011.

The 51.6 acre site holds an estimated 9.6 tcf, said Sasol, which agreed to pay $260 million upon closing and carry 75% of Talisman's future capital commitments in Farrell Creek up to $790 million total.

Farrell Creek production is expected to reach 40-60 MMcfed by yearend. Previously, Talisman expanded its Farrell Creek processing facilities to 120 MMcfd.

Talisman and Sasol also agreed to collaborate on certain other western Canadian natural gas opportunities.

EXCO buying Marcellus assets from Chief

EXCO Resources Inc. will acquire Marcellus shale interests from Chief Oil & Gas LLC and related parties for $459.4 million, subject to price adjustments at closing. Both companies are based in Dallas.

The deal includes properties with gross production of 40 MMcfd of gas (16 MMcfd net) from 15 wells, 11 wells awaiting completion, and more than 50,000 net acres in northeastern Pennsylvania, primarily Lycoming and Sullivan counties.

BG Group, a partner of EXCO in an Appalachian basin joint venture, has the right to buy 50% of the acquisition.

Big Chief recently said that its Marcellus basin production had reached 100 MMcfd of gas equivalent from 42 wells and that it expected output to reach 115 MMcfd by yearend (OGJ Online, Nov. 10, 2010).

Range Resources responds to EPA

Range Resources Corp.'s activities have not had any impact on the water aquifer in southern Parker County, Tex., the company said in a news release regarding the US Environmental Protection Agency's expressed concerns about possible natural gas migration.

EPA officials have noted methane contamination of two water wells in southwest Parker County. The Texas Railroad Commission scheduled a Jan. 10 hearing on the issue.

Range said it has been working with the Texas Railroad Commission staff, engineers, and field inspectors for several months and has conducted extensive testing of both Range-operated gas wells and the water wells of concern.

"We've provided those findings to the landowner, the Railroad Commission and the EPA," Range said. "Range's wells are completed in the Barnett shale formation, which is over a mile below the water zone. The investigation has revealed that methane in the water aquifer existed long before our activity and likely is naturally occurring migration from several shallow gas zones immediately below the water aquifer."

Range said it remains committed to working with regulators and residents to determine the cause and to assist with any remediation the Texas Railroad Commission determines is warranted. Range also will offer to provide drinking water to residents in the area while the investigation continues.

The company said it is working with the Railroad Commission to perform soil gas surveys that may lead to additional environmental investigation activities and to assist with monitoring gas concentrations.

Exploration & Development - Quick Takes

Statoil awarded four licenses off Newfoundland

The Canada-Newfoundland and Labrador Offshore Petroleum Board has awarded Statoil interests in four new licenses off eastern Canada.

The board awarded a Significant Discovery Licenses in an extension area of Statoil's Mizzen discovery in the Flemish Pass basin to Statoil as operator with 65% interest and Husky Energy Inc. 35%.

The board awarded two exploration licenses in the Flemish Pass basin/Central Ridge area 500 km off Newfoundland. One near the Mizzen license went to Statoil and Husky at the same interests as the SDL extension license. The other license, in the northern part of the basin, went to Statoil 75% and operator and Repsol E&P Canada Ltd. 25%.

The fourth license, in the Jeanne d'Arc basin 250 km off Newfoundland, went to Husky Energy operator with 50% interest and Statoil 50%.

Statoil is partner in the ongoing drilling of the Suncor Energy operated Ballicatters M-96Z exploratory well in the Jeanne d'Arc basin. Statoil plans to drill one well on its Mizzen discovery and another on its Fiddlehead license in the Jeanne d'Arc basin in 2011-12.

Statoil is a partner in Terra Nova and Hibernia producing fields and in the pending Hibernia Southern Extension and Hebron field developments.

Mitsubishi commits to Canning basin 2011 program

Japan's Mitsubishi Corp. has exercised an option to participate in Buru Energy Ltd.'s 2011 exploration program in the Canning basin of Western Australia.

Mitsubishi joined Perth-based Buru earlier this year by committing to spend $22.4 million (Aus.) to fund 80% of the 2010 work program (OGJ Online, June 15, 2010). It had until Nov. 30 to decide whether to take the partnership further.

Under the extended deal, Mitsubishi has committed to fund $40 million (Aus.) of a planned $50 million (Aus.) exploration program in the Canning region next year and up to $50 million (Aus.) of Buru's development costs for any major oil and gas development infrastructure.

The 2010 program has seen a successful appraisal of the Yulleroo gas discovery and lent credence to Buru's broader vision of a Canning Superbasin as a significant supplier of energy.

The 2011 program is still subject to review, but is likely to include appraisal of the Pictor oil and gas discovery in permit EP431, two more wells in the Yulleroo exploration province as direct appraisals of Yulleroo-2 or wildcats on the Yulleroo trend. There will also be two wells in the Acacia field exploration area targeting oil prospects and a well to evaluate one of Buru's unconventional play types in the region.

As well as earning an equal interest to Buru in the majority of Buru's permits, the new deal also gives Mitsubishi the right to earn an interest in the unconventional program by carrying out a further $40 million (Aus.) of unconventional exploration costs in 2012.

In addition, Mitsubishi has the right to acquire a 50% interest in Buru's production permits in exchange for another cash payment priced by an independent expert and based on proved and probable reserves.

Buru will continue as operator in all its permits, but Mitsubishi will lead any LNG commercialization plans.

Falkland log results disappoint Desire

Desire Petroleum PLC plans to drill the 100% interest Dawn/Jacinta prospect in the North Falkland basin as the company expressed "extreme disappointment" at log results from the 14/15-2 Rachel North well that it had proclaimed as an oil discovery.

Desire will plug and abandon Rachel North as an oil show well. It summarized the latest log results as follows:

  • Preliminary results from interpretation of initial log data indicated that the well had encountered a 349-m gross interval of sands and shales with hydrocarbons, of which 57 m was net pay in multiple zones. However, sampling of the main sand has shown that the hydrocarbons are residual and that the mobile fluid is water.
  • Analysis of the formation water recovered by sampling indicates much lower salinity than anticipated, and when this value is incorporated into a revised log interpretation it is confirmed that the sands are water-bearing. The salinity impacts the resistivity of the formation water that is used to calculate the saturation of hydrocarbons in sands.
  • Using industry standard procedures, the initial interpretation was based on a calculated value from a clear water sand only 55 m above the target sand of the same stratigraphic age and depositional setting. This calculated value was consistent with measurements from other wells in the basin. Unexpectedly, the actual resistivity value in the sample taken from the main sand turned out to be markedly different, and that sand is now interpreted to be water-bearing.
  • Formation pressures and sampling confirm the presence of good reservoir quality in the upper sands. A deeper target is still interpreted to be oil-bearing, but the interval is thin and reservoir quality is poor.

The wells Desire drilled in the Rachel area have identified five fan systems of varying areal extent and reservoir properties. Good reservoir development has been recorded in a number of the fans. Some of the sands are of a similar age to the sands in Rockhopper Exploration's Sea Lion discovery.

All fans will be remapped incorporating data from the wells to identify areas where better quality reservoir can be expected and stratigraphic traps developed. As these fans can only be mapped on 3D seismic, final mapping will await the new 3D survey, to start shortly.

The Dawn/Jacinta prospect in Tranche I is independent of Rachel. Targets are sands at a number of levels. The well will explore the prospectivity on the southern margin of the basin immediately updip from the main oil source rock (see map, OGJ, Nov. 1, 2010, p. 61).

After Dawn/Jacinta, Desire is likely to drill another well at a location to be decided. The forward drilling schedule is still to be finalized.

POL encounters oil and gas in Makori well

Pakistan Oilfields Ltd. (POL) encountered both oil and gas in its exploratory Makori East-1 well in Tal Block.

The upper 50 m of the drilled section in the Lockhart formation produced 3,209 b/d of 37° gravity oil and 10.7 MMcfd gas during an open-hole DST at 32⁄64-in. fixed choke size at flowing wellhead pressure of 3,179 psi, POL executives said.

Drilling will continue to test deeper prospective horizons, the company said. It is expected to reach the planned total depth within 3 months. MOL Pakistan is operator. POL's working interest is 25%.

The initial test was more encouraging with oil and gas flows at 3,209 b/d and the gas flow at 10.7 MMcfd. The well would increase POL's oil production to 5,800 b/d, the highest level since December 2007.

The Makori East-1 well was spudded Aug. 30 with a target depth of 4,169 m in Tal block in the North-West Frontier Province. Other joint venture partners include Oil & Gas Development Corp (OGDC) and Pakistan Petroleum Ltd. (PPL) both having 27.7% stakes.

Drilling & Production - Quick Takes

Guara extended well test starts off Brazil

Petroleo Brasileiro SA (Petrobras) on Dec. 25 started the Guara area extended well test from the presalt layers of Block BM-S-9 in the Santos basin, 300 km off Brazil's Sao Paulo state.

The company expects the test on Well SPS-55 to last 5 months and produce a 30° gravity oil at 14,000 b/d to Dynamic Producer, a dynamically positioned floating, drilling, production, storage, and offloading vessel.

Petrobras estimates that the Guara area contains 1.1-2 billion boe of recoverable oil and gas.

Following the test, the company will start a pilot project that will connect Guara wells to the Cidade de Sao Paulo floating production, storage, and offloading vessel. It expects production from the pilot to start by 2013 at 120,000 bo/d and 5 million cu m/day of gas.

Petrobras is the operator and holds a 45% interest in Block BM-S-9. Its partners are the BG Group 30% and Repsol-YPF SA 25%.

Contract awarded for Ekofisk platform

ConocoPhillips has conditionally awarded a contract for the topsides module of the Ekofisk 2/4 Z production platform in the Norwegian North Sea.

Subject to approvals by license partners and the Norwegian government, Aker Solutions will perform engineering, procurement, and construction.

Ekofisk production this year is expected to average 176,000 b/d of oil with gas totaling 1.72 billion standard cu m and gas liquids totaling 230,000 tonnes.

The field, in 70-75 m of water, has produced since 1971 from Paleocene and Late Cretaceous Ekofisk and Tor chalk at 2,900-3,250 m below sea level. It has been on waterflood since 1987.

Another new installation, the Ekofisk VB template for water injection wells, is planned.

Indonesia approves Abadi development plan

Indonesia has approved the Inpex development plan for its Abadi natural gas field on Masela block in the northern Arafura Sea. The field was discovered in 2000. Six appraisal wells prompted Inpex and partners to report estimated reserves of more than 10 tcf in the field.

Inpex and joint venture partner PT Energi Mega Persada will move into the front-end engineering and design phase of the project. The plan calls for a floating LNG facility capable of producing 2.5 million tonnes/year of LNG, which is considerably less than the original concept of 4.5 million tpy.

Inpex said the project size was reduced to benefit from the technical references available from other similar-sized FLNG projects. Inpex holds 90% of the Masela block.

PROCESSING - Quick Takes

Turkmen gas project starts second phase

State-owned Turkmengas has begun the $3.4 million second phase of its South Yoloten project, according to international oil and gas service company Petrofac, London. Petrofac will perform the engineering, procurement, and commissioning on the project. The work follows completion of the first phase.

When complete, South Yoloten field, which lies about 250 miles southeast of the Turkmen capital of Ashgabat, will export 20 billion cu m/year. Under the 32-month second phase of the lump-sum contract, Petrofac will provide a 10 bcm/year gas processing plant along with infrastructure and pipelines for the entire 20-bcm/year development.

Feed gas from the field contains up to 6% hydrogen sulfide, said the Petrofac announcement, and development will include gas treatment and sulfur handling, along with well pad, gathering, infrastructure and utilities, condensate processing, storage, and export.

Sipchem announces EPC for new plant

Saudi International Petrochemical Co. (Sipchem) announced earlier this month that affiliate International Polymers Co. has awarded the engineering design, procurement, and construction work for an ethylene vinyl acetate (EVA) plant to G.S. Engineering & Construction Corp., South Korea.

The 200,000-tonne/year plant will produce EVA and low-density polyethylene at the industrial complex in Jubail Industrial City. The plant is to start operation in second-quarter 2013 and cost an estimated 3 billion Saudi riyals ($800 million).

The Saudi Ministry of Petroleum and Minerals said the announcement has allocated the main ethane feedstock for the project to be cracked and treated to ethylene by one SABIC company and vinyl acetate monomer, as secondary feedstock, to be supplied by International Vinyl Co., a Sipchem affiliate.

International Polymers was founded in 2009 with Sipchem owning 75% and Hanwha Chemicals-Korea owning 25%.

Marcellus play to get gas plant

Magnum Hunter Resources Corp., Houston, announced earlier this month that it will build a 200-MMcfd cryogenic natural gas processing plant to serve production moved on its Eureka Hunter pipeline in northwestern West Virginia. A company spokesman declined to pinpoint the plant's planned location.

Installation and hook-up of the plant will begin once it is delivered in October 2011. The spokesman also declined to disclose the construction cost or what construction contracting company is in charge of engineering and construction.

Gary C. Evans, Magnum Hunter chairman and chief executive officer, noted that natural gas produced from its 50,000 net acres in the Marcellus shale in northwestern West Virginia and Ohio is "highly liquids rich," 1,200-1,400 btu.

He said the company intends to drill at least "horizontal Marcellus shale wells in fiscal year 2011."

TRANSPORTATION - Quick Takes

Chevron, Shell let contract for JSM export line

Amberjack Pipeline Co. LLC, a partnership between Chevron Pipe Line Co. and Shell Pipeline Co. LP, let a contract to Saipem for the Walker Ridge export pipeline, which will transport crude from the offshore Jack and St. Malo (JSM) fields about 280 miles south of New Orleans.

Scope of work includes transportation and installation of a 24-in. OD oil export pipeline, extending 136 miles from a maximum water depth of 7,000 ft and connecting the JSM floating production unit to a Shell-owned and operated platform on Green Canyon Block 19 (OGJ Online, Dec. 15, 2010).

Marine activities will be performed by the newbuild pipelay vessel Castorone starting first-quarter 2013.

The contract is the first award for Castorone, which currently under construction. The 1,083-ft dynamically positioned vessel is designed to lay pipes up to 60-in OD.

Shell invites tenders for CSG-LNG project

A joint venture of Royal Dutch Shell PLC and Petrochina has invited tenders for the front-end engineering and design (FEED) phase of its proposed CSG-LNG project at Curtis Island near Gladstone in Queensland.

Invitations to tender were sent to four Australian and international consortia. The successful group will be responsible for carrying out FEED for the LNG plant. A decision on who will construct the plant is to be made at a later date.

Shell and Petrochina completed a $3.4 billion (Aus.) takeover of Arrow Energy Ltd. earlier this year to secure CSG reserves for the planned four-train, 16 million tonne/year capacity plant on Curtis Island.

Stage 1 includes construction of two trains of 4 million tonnes/year each. A final investment decision is scheduled for 2012, leading to the project being brought on stream in 2017.

Tenders for the FEED phase close in February.

Australian officials support James Price Point LNG

The Western Australian Department of State Development submitted a draft report recommending approval of the planned LNG-natural gas hub at James Price Point 60 km north of Broome on the Kimberley coast.

The draft report covers 3 years of scientific investigations, studies, and consultations into developing a multiuser LNG hub on the site.

The document points out that a single LNG hub would minimize the environmental footprint of LNG gas processing in the Kimberley with a single shipping channel and port.

A supplementary document addressing marine waste discharge, oil spill modeling, marine benthic primary producer habitat and coastal processes is to be released early in 2011 when the studies into these issues are complete.

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