OGJ Newsletter

April 11, 2005
Estimates of US natural gas reserves for yearend 2004 are expected to exceed 190 tcf for the first time since 1986, yet producers still are "running in place" to keep up with demand, the American Gas Association said.

General Interest—Quick Takes

AGA: Gas reserves additions exceed output

Estimates of US natural gas reserves for yearend 2004 are expected to exceed 190 tcf for the first time since 1986, yet producers still are "running in place" to keep up with demand, the American Gas Association said.

In its Preliminary Findings Concerning 2004 Natural Gas Reserves, AGA said US producers added 24.1-32.7 tcf last year while producing 18.8 tcf.

The study calculated US reserves addition and production estimates from financial reports from 30 publicly traded companies that hold large gas reserves.

More than 23,000 gas wells were completed in the US last year, a record. Of 2004 gas production, the 30 holders of large reserves accounted for 48% while the rest came from thousands of independent producers, AGA said.

Independent producers completed most of their wells in shale, tight sands, and coal seams. This trend raises future supply questions because unconventional reservoirs tend to add small increments of production capability, AGA said. Exploration targeting higher-yield reservoirs has languished.

Beaufort Sea OCS sale draws strong bidding

Outer Continental Shelf Lease Sale 195 attracted strong bidding for blocks in the Beaufort Sea off Alaska.

"The Beaufort Sea contains the best near-term potential for offshore petroleum reserves on the Alaska Outer Continental Shelf," said US Minerals Management Service Alaska Regional Director John Goll.

Companies submitted bids totaling $46,735,081 for 127 blocks covering 618,751 acres. For the first time ever in a Beaufort Sea sale, MMS said, each block drew a single bid.

The highest bid was $12,220,173, submitted by Shell Offshore Inc. for Block 6708.

MMS offered 1,794 whole and partial blocks encompassing 9.4 million acres in 25-3,000 ft of water from the Canadian border on the east to Barrow, home of the Inupiat people, on the west.

Leases impose seven stipulations aimed at controlling effects on native people and the environment. The stipulations include requirements for protection of biological resources and spectacled and Steller's eiders, bowhead whale monitoring, use of pipelines rather than tankers, and booming for fuel transfers (OGJ Online, Nov. 1, 2004).

Prior Kyrgyzstan regime saw flat oil flow

Prior to the outbreak of domestic political troubles in March, Kyrgyzstan planned first quarter oil production of 17,300 tonnes, unchanged from 2004, and natural gas production of 7.5 million cu m, down 6.2%.

In January and February, state-owned Kyrgyzneftegaz produced 10,600 tonnes of oil, up 2% year-on-year, while natural gas production dropped 7.4% year-on-year in the 2-month period to 5 million cu m.

Kyrgyzstan increased oil production by 5.8% last year to 72,900 tonnes and raised natural gas production by 4.8% to 29.1 million cu m.

In mid-March, a popular uprising ended President Askar Akayev's regime and installed former Prime Minister Kurmanbek Bakiyev as interim head of state, pending elections.

Penn West starts CO2 pilot project in Alberta

Penn West Petroleum Ltd. has started an enhanced oil recovery pilot project at Pembina Cardium field near Drayton Valley, Alta.

The first phase will test the use of CO2 capture and injection to improve recovery from the field. If successful, the pilot program could lead to a large-scale project that would capture and sequester CO2 from heavy industry in Alberta to reduce emissions of the greenhouse gas.

The $15 million cost of the project's initial phase is shared by the governments of Canada and Alberta and Penn West through incentive programs to assess the potential and benefits of CO2 capture and storage.

Gorgon combine to speed Jansz development

ChevronTexaco Corp., ExxonMobil Corp., and Royal Dutch/Shell Group agreed to a new ownership structure for the Gorgon gas development off Western Australia, enabling early development of Jansz gas field 50 km north-northwest of Gorgon.

The three Gorgon stakeholders said they agreed to combine their interests in other nearby gas fields into a Greater Gorgon joint venture having reserves of more than 40 tcf. ChevronTexaco will have 50% interest, while Shell and ExxonMobil each will have 25%.

Greater Gorgon involves nearly a dozen fields, including Jansz, Chrysaor, Dionysus, West Tryal Rocks, and Spar. The new arrangement allows Gorgon and Jansz, the two major accumulations, to be developed simultaneously via two LNG trains of 5 million tonnes/year at an LNG liquefaction plant to be built on Barrow Island, which lies between the Gorgon gas fields and the Australian mainland (OGJ Online, Sept. 9, 2003).

ChevronTexaco will operate all the fields except for Jansz field, which ExxonMobil will continue to operate.

It will be necessary to accelerate engineering plans for deepwater Jansz to catch up to Gorgon, but the joint venture partners said they already are moving to design for a probable subsea development.

Aramco, IOC study future collaboration

Saudi Aramco and Indian Oil Corp. Ltd. signed a memorandum of collaboration to evaluate cooperation in petroleum research and development and the commercial production of any resulting technologies.

The agreement includes teamwork in the production of cleaner fuels, refinery process improvements, corrosion control, and bioremediation.

Industry Scoreboard

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Exploration & Development—Quick Takes

Apache makes two discoveries in Egypt

Apache Corp., Houston, has made two new oil and gas discoveries in Egypt—the Syrah 1X wildcat on the 2 million-acre Khalda Offset concession, which the company operates with a 100% contractor interest, and the Tanzanite 1X discovery, on Apache's onshore West Mediterranean concession.

Syrah 1X flow-tested at 46.5 MMcfd of natural gas through a 48/64-in. choke with 3,980 psi of flowing wellhead pressure. It was drilled to 14,445 ft TD and logged 266 ft of net pay.

The new-field discovery is the third-largest Jurassic gas field found to date in the Western Desert. Apache will produce Syrah gas through its new Qasr field production facility starting this summer.

The Tanzanite 1X discovery, drilled to 12,440 ft TD, flow-tested at a rate of 5,296 b/d of oil and 7.4 MMcfd of gas through a 1-in. choke with 814 psi of flowing wellhead pressure. The well logged a combined 207 ft of net pay.

It will be connected to North Alamein's processing facilities. Production will begin following Egyptian General Petroleum Corp.'s approval of a development lease. Apache holds a 65% contractor interest in the West Mediterranean concession and RWE DEA AG, Hamburg, 35%.

Apache will drill the Tanzanite 2 appraisal well 0.4 of a mile northeast of the Tanzanite 1X to test the Alamein Dolomite.

Nexus eyes Longtom gas field development

Nexus Energy Ltd., Melbourne, said it believes Longtom gas field, on Permit Vic/P54 in the Gippsland basin off Victoria, contains commercial gas reserves.

The company's mapping and engineering studies, since confirming the reservoir with the Longtom-2 appraisal late last year, suggest proved-plus-probable gas reserves could exceed 300 bcf. Adding possible reserves pushes the potential to 500 bcf, Nexus said.

The figures are predicated on a successful Longtom-3 appraisal well to be drilled in September. The company aims for an early field development, with Longtom-3 to be suspended as a future commercial gas producer that quickly could be brought on stream.

Core analysis from Longtom-2 indicates that the upper sands in the prospect could produce gas at rates above the 19 MMcfd obtained from lower sands during tests in November 2004, Nexus said.

Apache Energy Pty. Ltd., Perth, has operated the discovery since farming into the permit in 2003 with a 62.5% interest. Nexus holds 37.5%.

Under a joint-venture agreement, Apache has until mid-April to decide whether to participate in the appraisal program. If Apache withdraws, Nexus will proceed on a sole risk basis to obtain 100% of any Longtom production.

Gas from Longtom could be brought on stream by late 2006.

Vaalco to drill exploration well off Gabon

Vaalco Energy Inc., Houston, plans to use the GSF Aleutian Key semisubmersible to drill an exploration well on the Avouma South prospect off Gabon. The rig is expected on site Apr. 27.

The prospect is about 2 km south of the Avouma exploration well, which flow-tested at a stabilized rate of 6,600 b/d of 37-38° gravity crude (OGJ Online, July 21, 2004).

Drilling should take 30 days, after which the rig will move to Etame field for the drilling and completion of the ET-6H development well, scheduled for production in July.

BP makes sixth find on Block 31 off Angola

BP Exploration (Angola) Ltd. has made its sixth deepwater discovery on Block 31, about 170 km off Angola and 31 km northwest of the recent Palas discovery (OGJ Online, Feb. 15, 2005).

On test, the Ceres-1 well, drilled to 4,334 m TD in 1,633 m of water, flowed at a maximum rate of 5,644 b/d of oil through a 44/64-in. choke.

Ceres, the second discovery in the southeastern portion of Block 31, is 32 km southeast of the planned Northeast Development Area, where four discoveries have been made.

BP operates the block with a 26.67% interest.

Unocal has Northwest Territories strike

Unocal Corp. subsidiary Northrock Resources Ltd., Calgary, made a hydrocarbon discovery on the Summit Creek prospect in the Central Mackenzie Valley area of the Northwest Territories in Canada.

Tests of the Summit Creek B-44 well confirmed several productive intervals in a gross hydrocarbon column of more than 600 ft. Each of two perforated intervals flowed on test at the rate of 10 MMcfd of natural gas and more than 3,000 b/d of light oil or condensate with flowing wellhead pressures of 900-1,100 psi. One zone also produced 1,000 b/d of water.

Northrock drilled Summit Creek B-44 in January 2004 to 10,053 ft and suspended it until a $16 million completion and testing program during first quarter 2005 (OGJ Online, Oct. 4, 2004).

The Sah Cho L-71 well, drilled to 12,050 ft TD on a separate structure encountered hydrocarbons but didn't test at commercial rate. The well has been cased to TD and suspended.

The play requires further appraisal. It's 35 miles south-southwest of Tulita and 45 miles from the Enbridge Oil Pipeline and the proposed Mackenzie Valley Gas Pipeline route.

Northrock Resources is operator with a 32.5% working interest in the Summit Creek and Sah Cho prospects. Other interest owners in the Summit Creek well are Husky Oil Operations Ltd. 29.478%, EOG Resources Canada Inc. 26.398%, Pacific Rodera Energy Inc. 6.625%, and International Frontier Resources Corp. 5%.

Partners in the Sah Cho well are Husky 32.5%, EOG Resources 23.38%, Pacific Rodera 6.63%, and International Frontier 5%.

Europa notes Romania wildcat, UK completion

Falcon Oil & Gas, operator, spudded the Fratauti-1 exploration well 6 km from Radauti in northern Romania, reported stakeholder Europa Oil & Gas (Holdings) PLC, London.

Europa holds a 28.75% stake in the well.

The Fratauti prospect comprises three seismic anomalies similar to those in the nearby Bilca-1 and Bilca-2 gas wells. If successful, Fratauti-1 will be suspended for tie-in with Bilca production, due on stream at yearend.

In the UK, Europa has completed the West Firsby 8 well on its wholly-owned West Firsby oil field in Lincolnshire. The well reached 6,297 ft MD in Zone 1 of the reservoir with a total drilled net reservoir section of 330 ft.

Well production is scheduled to begin after installation of a jet pump assembly.

Sibneft wins licenses in Western Siberia

Russia's Sibneft has won development rights for the Salymskiy-2 and Salymskiy-3 blocks in the Khanty-Mansiisk Autonomous District of Western Siberia.

Sibneft paid $12.37 million for Salymskiy-2, which has recoverable oil estimated at 25.94 million tonnes, and $7.23 million for the Salymskiy-3 Block, which has an estimated 23.42 million tonnes of recoverable oil.

Sibneft receives exploration rights for 5 years and a guaranteed option to obtain production licenses.

KNOC seeks FSO for fields off Viet Nam

Korea National Oil Corp. (KNOC) signed a letter of intent with Modec Inc., Japan, as part of a consortium with Mitsui & Co. Ltd. and Petroleum Technical Services Co., a subsidiary of Vietnam Oil & Gas Corp. (Petrovietnam), for a floating storage and offloading (FSO) vessel for KNOC's Rong Doi and Rong Doi Tay fields off Viet Nam.

The consortium will be responsible for the engineering, procurement, construction, installation, commissioning, and operation of the FSO including the external turret mooring system. It will own and operate the FSO for 7 years with 23 additional 1-year options.

The Rong Doi (Twin Dragon) and Rong Doi Tay (Twin Dragon West) fields are 320 km southeast of Vung Tau on Block 11-2 of the Nam Con Son basin. The FSO is to be installed in 85 m of water and is designed with a receiving capacity of 18,000 b/d of condensate and storage capacity of 300,000 bbl. Condensate processed at Rong Doi platforms will be loaded into the FSO via flexible riser.

With the completion of this project, Modec will be operating three FSOs or floating production, storage, and offloading vessels in Viet Nam.

Total wins block off Cameroon

Total SA has received the Dissoni exploration block in the Rio del Ray basin off Cameroon under a restricted tender by the government.

The exploration block covers 143 sq km near other Total concessions.

Total operates the block and holds a 50% interest. Partners are state-owned Société Nationale des Hydrocarbures and Pecten Cameroon Co.

Drilling & Production—Quick Takes

Santos starts Mutineer-Exeter production

Santos Ltd., Adelaide, has begun production from the Mutineer-Exeter oil fields off northwestern Australia, 150 km north of Dampier.

The fields' initial output is expected to be 70,000-90,000 b/d of oil with dual electric submersible pumps (OGJ Online, Feb. 17, 2005).

Production from seven wells will be tied to a 930,000-bbl floating production, storage, and offloading (FPSO) facility, with provision for up to nine wells in Mutineer field and five in Exeter field (see photo, next page).

The FPSO, owned and operated by Modec Inc., Tokyo, has an oil processing capacity of 100,000 b/d, gas handling capacity of 2-3 MMcfd, produced water treatment capacity of 125,000 b/d, and topsides water injection facilities for 150,000 b/d.

Santos, 33.4%, is operator of the Mutineer-Exeter project on behalf of partners Kufpec Australia Pty. Ltd. 33.4%, Nippon Oil Exploration Pty. Ltd. 25%, and Woodside Energy Ltd. 8.2%.

US drilling activity dips by two rigs

US drilling dipped by 2 rotary rigs to 1,329 active units, Baker Hughes Inc. reported Apr. 1. That compared with 1,160 units working during the same period a year ago.

Land operations reflected the loss, down by 2 rigs to 1,206 drilling. Activity in inland waters increased by 1 unit to 29 rigs. Offshore operations lost 1 rig to 90 in the Gulf of Mexico and 94 in US waters as a whole.

With the seasonal thaw, Canada's weekly rig count plunged by 86 to 230 units drilling. That is up from 194 during the same period last year.

Processing—Quick Takes

Electric failure triggers Amuay shutdown

An electrical system failure caused an operational shutdown Mar. 31 at Petróleos de Venezuela SA's Amuay refinery.

The refinery is a major part of the 940,000 b/d Paraguaná Refining Center (CRP) in western Venezuela.

Alejandro Granado, vice-president of PDVSA refining, said the shutdown was caused by a breakdown in the supply system to steam-generation boilers, which resulted in disturbances to the electricity generation system. The disturbances affected output of industrial services (steam, water, nitrogen, and electric power) at Amuay and caused shutdown of the processing units. Officials reported no injuries to personnel or damage to installations or the environment.

The refinery's management immediately activated a safe start-up plan together with the CRP emergency and contingency plan.

"The continued supply of fuel to domestic and international markets remains guaranteed," Granado said. "There are sufficient product inventories in the fuel distribution systems, as well as in the various refineries, terminals, and storage installations throughout Venezuela."

Hovensa adds FCC at St. Croix refinery

Hovensa LLC, a 50:50 joint venture of Venezuela's state-run oil company Petroleos de Venezuela SA and Amerada Hess Corp. has awarded a lump-sum turnkey contract to Technip for a fluid catalytic cracker gasoline hydrotreating unit to be installed at its 495,000 b/sd refinery at St. Croix, US Virgin Islands. The refinery already operates a 140,000 b/d FCC unit, and a 58,000 b/d coking unit.

The new 50,000 b/sd low-sulfur FCC unit will produce low-sulfur gasoline using ExxonMobil Research & Engineering Co.'s SCANfining process technology. Project completion is scheduled for November 2006.

The contract, to be carried out at Technip's Rome engineering center, covers front-end and detailed engineering, procurement and supply of equipment and materials, construction, precommissioning, commissioning, and start-up assistance.

Transportation—Quick Takes

Oman gets loan for third Qalhat LNG train

Oman will fund a third LNG train for Qalhat LNG SAOC through a $688-million loan from 13 international banks.

The new train, which will produce 3.7 million tonnes/year (tpy) of LNG, is under construction at Qalhat near Sur on Oman's northeastern coast, adjacent to the existing Oman LNG plant.

Officials said Qalhat LNG and Oman LNG will operate as an integrated complex in order to generate economies of scale, improved efficiency, and lower production costs.

Sheikh Alfadhel bin Mohammed Al Harthy, chairman of Qalhat LNG, said the new plant, which is about 90% complete, would begin start-up operations before yearend, with commercial production under way by January 2006.

Qalhat LNG has signed three long-term agreements for a total of 3.3 million tpy of LNG.

OSC recently signed an agreement to finance two 145,000 cu m LNG carriers and hopes to sign another financial agreement for two more, now under construction in Japan and South Korea.

Two of the vessels are expected to join OSC in the fourth quarter and the other two in second quarter 2006, bringing the fleet total to six carriers.

Qalhat LNG stakeholders are Oman 56%, Union Fenosa 36.8%, and Oman LNG 7.36%.

GDF secures LNG capacity at UK terminal

Gaz de France, through an agreement with National Grid Transco PLC subsidiary Grain LNG Ltd., has booked 2.4 million tonnes/year of LNG regasification capacity for 20 years, starting in 2008-09, at the Isle of Grain terminal in the UK.

The terminal, at the Thames Estuary, is due on stream shortly with 3.3 million tonnes/year of LNG capacity, to be increased to 9.8 million tonnes/year by yearend 2008. This will account for about 12% of the UK's gas needs.

The UK gas market, the largest in Europe, is set to grow by 2%/year, making the country a net gas importer as its North Sea gas production declines.

The LNG will come from Gaz de France gas production, but the source has not yet been determined.

ONGC lets pipeline-replacement contract

Global Industries Offshore LLC and Larsen & Toubro Ltd., Mumbai, have received notification of a $422 million contract from India's Oil & Natural Gas Corp. to replace offshore oil and gas pipelines totaling 185 km.

The replacement pipelines, all off Mumbai, will have diameters of 4-16-in. Operations are scheduled to begin later this year. In the 2005 work season, 14 lines will be replaced for a total of 78.3 km; in 2006, 12 pipelines for 60.6 km; and in 2007, 14 pipelines for 46.1 km.

Tokyo Gas buys into Brazil's Malhas pipeline

Japan's Tokyo Gas Co. has bought a 15% stake in the specific-purpose companies Nova Transportadora do Nordeste SA (NTN), and Nova Transportadora do Sudeste SA (NTS), created by Brazil's state-owned Petroleo Brasileiro SA (Petrobras) to operate and maintain two natural gas pipelines in the $3 billion Malhas project in southeastern and northeastern Brazil (OGJ Online, July 11, 2003).

NTN will operate an 820-km expansion of existing pipelines in the northeast, while NTS will build a 440-km pipeline in the southeast to link Campinas in Sao Paulo state to Japeri in neighboring Rio de Janeiro state.

The NTN line will transport natural gas produced in Bolivia, and the NTS line will carry natural gas produced off northeast Brazil. Both pipelines are expected to start operating in July. Brazilian utilities will buy the gas.

The NTS and NTN lines will be linked by the $1.3 billion, 1,200-km Gasene pipeline, which will connect Macae in Rio de Janeiro, where offshore oil and gas pipelines reach land from Campos basin oil platforms, and Salvador, terminus of an existing gas pipeline that cuts across seven northeastern states to Ceara state (OGJ Online, Sept. 16, 2004).

The Malhas project aims to transport supplies from Brazil's gas-producing southeast to its energy-deficient northeast.

In addition to Tokyo Gas, other NTN-NTS stakeholders include Japanese firms Mitsui & Co. Ltd. 35%, Mitsubishi Corp. 25%, and Itochu Co. 25%. The Japanese companies plan to transfer their pipeline assets to Petrobras after providing technical service for 10 years.

Brazilian officials hope to have the entire Malhas system in service by 2010.

Mutineer-Exeter FPSO off northwestern Australia. Photo courtesy of Modec Inc.
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