OGJ Newsletter

April 19, 2010

General InterestQuick Takes

BLM, MMS to review federal royalty regime

The two US Department of the Interior agencies that handle federal oil and gas leasing will jointly review federal royalty policies, their directors announced. The study conducted by the Bureau of Land Management and the Minerals Management Service will examine other countries' fiscal systems and compare them with those in the US, BLM and MMS said Apr. 12.

The study is a response to a 2008 Government Accountability Office report that suggested returns from federal oil and gas leases are lower than what other countries receive, MMS Director S. Elizabeth Birnbaum said. "We need to consider international comparisons in selecting fiscal parameters for our leases," she explained.

BLM Director Robert V. Abbey added, "We are assessing the federal oil and gas fiscal systems because the department does not routinely monitor fiscal systems in other countries. This study will provide some common-sense grounds for comparison as we evaluate our royalty rates and our oil and gas fiscal policies in the context of global markets."

They said the study will explain the methods and appropriate uses of international comparisons, collect data and construct consistent comparisons, and apply that information to current federal lease term issues. Comparison of the US government's return with that of other countries may reveal a potential for greater revenues, they suggested. The study's final report should be completed 9 months after the contract is awarded, Birnbaum and Abbey said.

BLM seeks comments on Fram's proposal

The US Bureau of Land Management is seeking public comment on Fram Operating LLC's proposal to develop oil and gas resources near Grand Junction, Colo.

The US subsidiary of Oslo-based Fram Exploration AS submitted a master development plan for up to 492 wells on 46 proposed and 9 existing well pads within the 90,400-acre Whitewater Unit between Grand Junction and Delta beginning in 2011, BLM's Grand Junction and Uncompahgre, Colo., field offices said in a joint announcement.

They said Aspen Operating LLC submitted a proposed Whitewater master development plan in 2008, which was not approved since it sold the leases to Fram. The new owner subsequently revised the plan.

The new proposed plan includes construction of up to 15 miles of new roads, upgrading of up to 48 miles of existing 2-track roads, and maintenance of about 23 miles of existing roads, the BLM field offices said. The proposal also includes construction of a new compressor in addition to two existing compressor stations, they added.

They said Fram plans to drill directionally most of the wells, minimizing surface disturbance from new roads and pads.

BLM said it is seeking public comment as it begins an environmental assessment of the proposal. Public comments will be accepted at its Grand Junction field office until May 5, it indicated.

EPA issues Shell second Alaska air permit

The US Environmental Protection Agency issued Shell Offshore Inc. a second federal air-quality permit on Apr. 9 to operate this summer off Alaska's coast, this time in the Beaufort Sea. The permit is similar to one EPA's Region 10 district office issued to Shell Offshore on Apr. 1 for Chukchi Sea operations.

Like the earlier Arctic Ocean permit, this one will regulate emissions from Shell Offshore's Frontier Discoverer drillship and support vessels during the 2010 drilling season from July to December. "We've listened closely to the Arctic communities of Kaktovik, Nuiqsut, and Barrow in our effort to craft a permit that is both effective and enforceable," said Rick Albright, director of the air, waste, and toxics office at EPA's Region 10 office in Seattle.

The permit must ensure that operations meet prevention of significant deterioration requirements under the federal Clean Air Act in addition to US Minerals Management Service regulations because the drillship operations are considered a major air pollution source under EPA regulations, Albright said. Approval was partly based on installation of pollution-reduction controls implementing the best available control technology on the Frontier Discoverer, he said.

The permit also requires Shell Offshore to reduce air emissions by using selective catalytic reduction on one of the icebreakers, a catalytic diesel particulate filter on the Nanuq, and ultralow-sulfur diesel fuel on all vessels involved in the project, EPA said.

It noted that it proposed the permit for public comment on Feb. 17 and held informational meetings and public hearings in Kaktovik on Mar. 17, Nuiqsut on Mar. 17, and Barrow on Mar. 18. EPA said that petitions for review must be received by May 12.

Exploration & DevelopmentQuick Takes

US gas reserves reached 250 tcf at yearend 2009

Known US natural gas reserves likely increased for an 11th consecutive year at the end of 2009 to 250 tcf, their highest level in 35 years, the American Gas Association said on Apr. 6. Increased production from shale, tight sands, and other unconventional sources contributed to supply optimism, it added.

"Natural gas supply in this country remains bullish," AGA Pres. David N. Parker said. "Production is also up, underpinned by the recent development of secure, domestic gas resources in deep water offshore, as well as unconventional gas in the Lower 48 states."

AGA believes supply and production levels will hold stead for the foreseeable future "unless significant policy decision restrict access to potential resources," he added.

The report, "Preliminary Findings Concerning 2009 Natural Gas Reserves," identified BP America Inc. as the year's largest US producer, representing less than 5% of the national total. It said that other leading domestic gas producers ranged from ExxonMobil Corp. to large independent producers such as Chesapeake Energy Corp., Devon Energy Corp., Anadarko Petroleum Corp., and EOG Resources Inc.

"In fact, thousands of other large, midsize, and small producers provided the bulk of domestic gas to local distribution companies last year," Parker said.

Appraisal results spur Perla development

Eni SPA, Repsol-YPF SA, and Petroleos de Venezuela SA are considering rapid development of the giant Perla gas discovery in the Gulf of Venezuela after better-than-expected results in an appraisal well.

The Cardon IV SA Perla 2 well, drilled in 60 m of water, cut 840 ft of net pay in Oligocene carbonates with reservoir characteristics Eni described as "excellent."

The results "largely exceeded predrill expectations," the company said.

Cardon IV SA, a 50-50 combine of Eni and Repsol-YPF, operates the Cardon IV Block during exploration. PDVSA has a 35% back-in right for development, during which Eni and Repsol-YPF will hold 32.5% interests each. The three companies will jointly operate the project during development.

On production tests, the Perla 2 well flowed 1.4 million cu m/day of gas and 1,500 b/d of condensate. Eni said normalized gas production can exceed 70 MMscfd/well with 2,000 b/d of condensate.

The operators recovered 700 ft of bottomhole cores in the appraisal well.

On the basis of Perla 2 results, Repsol-YPF increased the estimate of field reserves by 30% to 1.6-1.85 billion boe of gas and condensate.

The Spanish company said the combine will drill two more wells this year.

Eni said fast-track development under discussion would target early-phase production of 300 MMscfd, starting by mid-2013.

Eni and Repsol-YPF drilled the discovery well, Perla 1X, last year to 2,147 m TD in 60 m of water, encountering 240 m of net hydrocarbon pay. The well flowed on production tests at equipment-limited rates of 570,000 cu m/day of gas with 620 b/d of condensate (OGJ, Oct. 26, 2009, Newsletter).

Levant basin given 122 tcf, 1.7 billion bbl

The mean undiscovered, technically recoverable resource in the Levant Basin Province in the easternmost Mediterranean region is estimated at 122 tcf of natural gas and 1.7 billion bbl of oil and natural gas liquids.

The US Geological Survey, assessing the province for the first time, put the ranges of producible resources at 50-227 tcf of gas and 483-3,759 million bbl of oil and NGL.

The Levant basin covers 83,000 sq km bounded to the east by the Levant Transform Zone, to the north by the Tartus fault, to the northwest by the Eratosthenes Seamount, to the west and southwest by the Nile Delta Cone Province boundary, and to the south by the limit of compressional structures in the Sinai.

USGS defined three assessment units: The mostly onshore Levant Margin Reservoirs AU with four oil and four gas fields, the offshore Plio-Pleistocene Reservoirs AU with eight gas fields, and the offshore Levant Sub-Salt Reservoirs AU with two gas discoveries, Tamar and Dalit off Israel. Tamar and Dalit were used in the assessment but are so new that there is no independent reference as to their size.

The Plio-Pleistocene Reservoirs AU is thought to be sourced mainly by biogenic gas, but the assessment includes the possibility of thermogenic gas and oil that migrated vertically from subsalt source rocks, the USGS said. USGS Energy Resources Program Coordinator Brenda Pierce said Levant's gas resource is larger than anything the survey has assessed in the US.

Compared with Levant, Russia's West Siberian basin resource is estimated at 643 tcf. The Middle East Rub Al Khali basin has 426 tcf, the Greater Ghawar uplift 227 tcf, and the Zagros fold belt 212 tcf. In the US, the Southwestern Wyoming Province has 85 tcf, the National Petroleum Reserve Alaska Province 73 tcf, and the Appalachian Basin Province and the Western Gulf Basin Province of Texas and Louisiana each 70 tcf.

World gas consumption and production were 110 tcf in 2008, including 23 tcf in the US, 17 tcf in Russia, and 4 tcf in Iran, the three largest consuming countries.

Another OMV Tunisian well tests condensate

OMV AG has suspended for future production the sixth successive well to encounter hydrocarbons in a development play 700 km south of Tunis, Tunisia (OGJ Online, Feb. 16, 2009).

The Ahlem-2 appraisal well, drilled to 4,060 m TD on the Nawara production concession, flowed at a maximum stabilized rate of 3,300 boe/d of gas condensate from two condensate-bearing sandstone reservoirs. The condensate/gas ratio was 8 bbl/MMcf measured.

OMV (Tunesien) Exploration GMBH and its 50-50 partner in the concession, state-owned ETAP, have spudded another exploration well, Ritma-1.

Industry Scoreboard

Drilling & ProductionQuick Takes

Japanese agency to invest in Orinoco belt

Japan's government-backed Japan Oil, Gas & Metals National Corp. (Jogmec) said it will invest up to ¥32 billion by yearend 2017 in an extra-heavy Orinoco crude oil project in Venezuela, in which two Japanese companies are involved.

Jogmec said it decided to provide equity capital finance to a subsidiary of Inpex Corp. and Mitsubishi Corp., which is participating along with subsidiaries of Chevron Corp. and Suelopetrol CA in an extra-heavy oil development project on three blocks of the Venezuela's Carabobo area.

The four firms jointly participated in the bidding for development of Carabobo projects held in January, and were selected to develop Project 3a—development, production, and upgrading in Carabobo Block 5, Block 2 South, and Block 3 North.

The consortium is now studying feasibility with a plan to form a joint venture with Venezuela's state-owned Petroleos de Venezuela SA to produce as much as 400,000 b/d of oil at the project.

Jogmec said it will invest the ¥32 billion once the joint venture is established.

PDVSA expects to take a 60% stake in the JV, while Chevron will own 34%. Mitsubishi and Inpex will jointly hold 5%, while Suelopetrol will have the remaining 1%.

Rubiales pilot fireflood could start in June

Colombia's Ecopetrol SA and Pacific Rubiales Energy Corp. expect to commence the implementation of a pilot fireflood at Rubiales field in June.

Rubiales field is in the Llanos basin, 465 km from Bogota. The sands in Rubiales produce heavy 12.5° gravity oil.

Current production from the field, discovered in 1982, is about 116,000 bo/d.

The pilot will use a synchronized thermal additional recovery (STAR) process.

The companies said that the process has been successfully tested at the University of Calgary's research laboratories. Tests included three combustion tube tests, two ramped temperature oxidation tests, and numerical simulations.

These tests determined that the Rubiales crude has a stable and controllable ignition point at reservoir conditions, that the fire front thereby generated is stable, and that there is evidence of significant additional recovery potential by using the STAR process, the companies said.

Prior to implementing the pilot the companies said they would:

• Design the duration and scope of the pilot and onsite testing.

• Determine the technical and economic conditions under which the pilot project will be considered successful.

• Execute a definitive agreement between the parties.

• Determine the basic terms and conditions, both volumetric and economic, that will frame the definitive agreement for implementing a commercial fireflood at Rubiales.

Ecopetrol holds a 60% interest in the field with the remaining interest held by Pacific Rubiales Energy.

Meta Petroleum Corp., a 100% owned unit of Pacific Rubiales Energy, operates the field.

ADCO operates first Middle East CO2-EOR pilot

Since Nov. 9, 2009, Abu Dhabi Co. for Onshore Oil Operations (ADCO) has injected carbon dioxide in a pilot enhanced oil recovery project in Northeast Bab's Rumaitha field.

The pilot project involves injecting 1.2 MMscfd of dry, more than 99% pure CO2 at 3,300 psi and 35° C.

ADCO's Al Waha magazine, November-December 2009, noted that this is the first CO2-EOR project in the Middle East and that ADCO has plans for more pilots in several of its other major reservoirs.

The pilot includes one injection, one observation, and one producing well. The reservoir is at 9,450-9,500 ft and its pressure and temperature is 4,560 psia and 265° F.

Praxair Gulf Industrial Gases LLC supplies the CO2 for the project.

Processing Quick Takes

Tesoro curtails Anacortes crude processing

Tesoro Corp. will shut down crude processing at its 120,000-b/d refinery at Anacortes, Wash., where an explosion in a naphtha hydrotreater killed three workers and injured four others on Apr. 2.

The refinery has been producing mainly unfinished intermediate products since the accident, which occurred while the hydrotreater was undergoing maintenance (OGJ Online, Apr. 5, 2010).

In a statement, the company said it couldn't predict when operations would resume. It said it would supply customers from its other refineries and third-party purchases.

Refinery in Ghana idle for lack of crude

Ghana's 45,000-b/cd Tema refinery has ceased operation because of a lack of crude, according to Reuters.

An Apr. 14 report said the refinery had been unable to operate for about 10 days.

State-owned Tema Oil Refinery Co. Ltd. relies on a contract for purchases by Ghana National Petroleum Corp. from Nigerian National Petroleum Corp. for 30,000 b/d of crude. The rest of the crude it needs comes from purchases by the National Petroleum Authority.

The refinery has a hydroskimming train and a 14,000 b/d resid catalytic cracker.

Petrom advances Petrobrazi refinery upgrade

Petrom SA, OMV AG's Romanian subsidiary, has let key contracts in its delayed modernization of the 4.5-million tonne/year Petrobrazi refinery in Ploesti (OGJ, June 15, 2009, p. 22).

Foster Wheeler AG will provide front-end engineering and design (FEED) modification services and engineering, procurement, and construction management (EPCM) for the revamp of an atmospheric/vacuum distillation unit.

Foster Wheeler also received an EPCM contract for a new amine unit and a FEED contract for revamp of a delayed coking unit.

The company plans this year to increase Petrobrazi capacity to 6 million tpy, expand the refinery's coker, add a hydrocracker, and increase integration with the nearby Arpechim refinery.

Petrom said it is proceeding with the Petrobrazi upgrade after modernizing the Arpechim refinery, which has nameplate capacity of 3.5 million tpy but is operating this year only as needed.

Enbridge to build cryogenic plant in West Texas

Enbridge Energy Partners LP, Houston, will add a cryogenic gas processing plant on its Anadarko natural gas gathering system in the Texas Panhandle, the company reported.

The 150-MMcfd capacity plant, Enbridge said, is needed to handle a resurgence of horizontal drilling the NGL-rich Granite Wash.

Enbridge Pres. Terrance L. McGill said the Granite Wash has been a vertical play in the Texas Panhandle and western Oklahoma for several years, has seen a large increase in drilling based on "more sophisticated horizontal drilling and completion techniques" and strong NGL prices. When operating in first-quarter 2011, the new plant will increase the Anadarko system's total processing capacity to more than 650 MMcfd. In addition to this cryogenic plant, the company will also add field compression and pipeline to accommodate increasing Granite Wash gas volumes.

Enbridge's Anadarko System operates gathering and processing the Texas Panhandle including Roberts, Hemphill, and Wheeler counties in Texas and western Oklahoma.

Petroplus to buy Delaware City refinery

Petroplus Holdings AG has agreed to buy Valero Energy Corp.'s idle refinery at Delaware City and said it plans to resume refining operations after performing "major" maintenance work over the next 9 months.

Valero closed the refinery, capacity of which Petroplus reported as 190,000 b/d, last year after failing to find a buyer (OGJ Online, Nov. 20, 2009).

Through subsidiaries, Petroplus will pay $170 million for the refinery and related assets and $50 million for an affiliated, 218 Mw power plant complex.

The refinery has fluid coking, fluid catalytic cracking, hydrocracking, continuous catalytic reforming, alkylation, and hydrotreating units.

Valero and Petroplus subsidiary PBF Energy Partners LP have been negotiating the transaction since early this year (OGJ, Feb. 1, 2010, Newsletter).

Transportation — Quick Takes

Nord Stream gas pipeline construction begins

Construction of the 1,200-km Nord Stream natural gas pipeline, which will extend through the Baltic Sea from Vyborg, Russia, to Greifswald, Germany, began Apr. 9. Russia's Gazprom projects completion of the first 27.5 billion cu m/year Nord Stream line in 2011, with a parallel line of the same capacity to follow in 2012. The line will pass through Russian, Finnish, Swedish, Danish, and German waters.

Nord Stream AG says pipe laying for the line's first construction phase will be carried out through April 2011 by Saipem SPA's Castoro 6 and Castoro 10 as well as Allseas Group SA's Solitaire.

The Castoro 6 semi will execute the bulk of pipe laying operations at an average of 2.5 km/day. It will be joined in September by the dynamically positioned Solitaire. Castoro 10 will operate near landfall in Germany during this year's second half.

In February, Gazprom announced a 3-year production delay to 2016 from its Shtokman gas field (OGJ Online, Feb. 8, 2010). Shtokman is to be one of the supply sources for Nord Stream.

Russia is building 900 km of surface pipelines to feed Nord Stream, with the 470-km Opal connection pipeline also under construction in Germany. The Czech Republic is reinforcing its gas transmission system to accommodate Nord Stream supplies (OGJ, Apr. 5, 2010, p. 62).

Nord Stream AG is a joint venture of Gazprom 51%, Wintershall Holding 20%, E.On Ruhrgas 20%, and Gasunie 9%. On Mar. 1, Gazprom and GDF Suez signed a memorandum by which the French company will also acquire a 9% interest in Nord Stream. The interest will be pulled equally from Winterhall and E.On Ruhrgas (OGJ, Mar. 8, 2010, p. 11).

ETP receives FERC approval for Tiger gas line

Energy Transfer Partners LP reported that the US Federal Energy Regulatory Commission has approved construction and operation of its planned Tiger natural gas pipeline, which will serve the Haynesville shale and Bossier sands producing regions in Louisiana and East Texas.

FERC's approval and issuance of Tiger Pipeline's certificate authorizes construction of the roughly 175-mile, 42-in. OD, 2 bcfd interstate line. A planned expansion announced in February and subject to FERC approval, would increase capacity to 2.4 bcfd, already sold out under 10-15 year contracts.

Construction is expected to begin in June, with 2 bcfd entering service first-half 2011 and the 0.4 bcfd expansion following in second-half 2011. ETP is also expanding takeaway capacity from Haynesville and Bossier, the 42-in. OD Haynesville extension of its Acadian gas pipeline system expected to be completed in third-quarter 2011 (OGJ Online, Apr. 1, 2010).

Denali Alaska gas line files open season plan

Denali, the Alaska natural gas pipeline project put forward by BP PLC and ConocoPhillips, filed its open season plan Apr. 7 with the US Federal Energy Regulatory Commission.

Denali comprises a gas treatment plant (GTP) on the Alaska North Slope, transmission lines from Prudhoe Bay and Point Thomson fields to the GTP, and a mainline crossing Alaska into Canada and terminating at Blueberry Hill, Alta. En route off-take points are also included in the plan.

The 48-in. OD mainline will ship 4.5 bcfd with 15 compressor stations, 6 in Alaska. The pipeline will extend 730 miles through Alaska and 1,020 miles through Canada before interconnecting at its terminus with pipelines to transport the gas to end markets.

Denali plans to start its open season July 6, pending FERC approval, and let it and a simultaneous open season overseen by the National Energy Board in Canada run for at least 90 days.

Denali expects the $35 million mainline and GTP to enter service in 2020. TransCanada Alaska Co. LLC received FERC approval of its open season plan Mar. 31 and plans to begin the open season no later than Apr. 30.

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