May 2001 Vol. 222 No. 5  Production

Perry A. Fischer,  Engineering Editor

Really big projects and investments

Ras Laffan LNG Co. Ltd. II (RasGas), a joint venture between Qatar Petroleum (70%) and ExxonMobil, has signed the first phase of the world’s largest LNG Sale and Purchase Agreement (SPA) with Petronet Ltd. of India. Petronet is a JV between the Indian Oil Corp., Bharat Petroleum Corp., the Gas Authority of India Ltd., and The Oil and Natural Gas Corp. The agreement will eventually add more than 3 Bcfgd of gas production in Qatar, beginning with construction of additional offshore producing facilities in North Field, and building the world’s largest and most cost-efficient LNG train at Ras Laffan. The SPA covers LNG supply for 25 years.

Deliveries of 5 million metric t/yr (MMTA) will be made to a new import terminal at Dahej, Gujarat State. Construction of the terminal began earlier this year, and deliveries are slated to begin in late 2003. An additional 2.5 MMTA, shipped to an import terminal at Cochin, Kerala State, is in the planning stage.

The final Conditions Precedent for the SPA enabled RasGas to sign two world-scale Engineering, Procurement and Construction (EPC) contracts. The first, with a JV comprising Chiyoda Corp., Mitsui Co. Ltd. and Snamprogetti S.p.A., is to build a record 4.7 MMTA LNG train. The second contract, with J. Ray McDermott Middle East Ltd., covers offshore and gathering facilities, allowing daily production of 800 MMcfg for supply of the new LNG train, along with 30,000 bbl of condensate. The EPC contracts provide terms for construction of another 4.7 MMTA LNG train and development of offshore and onshore facilities for domestic and export-pipeline gas sales. The two new trains follow two existing RasGas LNG trains with a combined capacity of 6.6 MMTA. The first phase of onshore and offshore development could allow ExxonMobil to book more than 350 million net boe of reserves.

Huge field, huge investment. Formed in 1997, the Karachaganak consortium comprises British Gas (operator, 32.5% stake), Agip (32.5%), Texaco (20%) and LUKoil (15%). Partners in the gas and condensate field are planning further investment of about $2.5 billion for field development and infrastructure in 2001 – 2003. Dow Jones reported that investment this year should exceed $1 billion, followed by $965 million in 2002 and $447 million in 2003. These investments are in addition to the $2.26 billion invested last year.

Daily gas production at Karachaganak will more than triple by 2003, to 1,370 MMcf from 375 MMcf this year. Condensate production will rise to 10.4 million t from 4.6 million t last year. Development during the next two years will involve building a refinery to process crude and a pipeline linking the field with the Tengiz-Novorossiisk pipeline, recently opened by the Caspian Pipeline Consortium. Completion of the refinery and pipeline are scheduled for 2003.

Currently, all gas and condensate produced at Karachaganak is shipped to the Russian city of Orenburg, where a Gazprom-owned gas refinery processes it.

Risky Malampaya guarantees. Shell Philippines Exploration (SPEX) wants government guarantees before investing some $600 million to develop an offshore oil field in the Malampaya project. The field, which lies in 850-ft deep water, has estimated oil reserves of 35 to 50 million bbl – Philippines’ largest oil discovery. Gas production would begin in October, and would be independent. Cost of the gas-to-power project would be around $4.5 billion.

Shell and its partners, Texaco and government-owned PNOC Exploration Corp., need to drill at least four wells to establish economics of the oil reservoir. SPEX wants the government to allow extended well tests (EWTs) from these wells, with proceeds from the produced oil applied to recover costs before the government would get a share. Regardless of the government’s decision, SPEX intends to conduct an EWT to produce 3 million bbl of oil over 150 days. The government says it will have much to consider before granting incentives to SPEX, since there is a risk of depletion before the production tests are concluded.

DOE successes. The U.S. has more than 96,000 oil reservoirs. To demonstrate reservoir life-extension technologies that are cost-effective alternatives to abandonment, DOE launched the Reservoir Class Field Demonstration Program and selected the first group of projects in 1992. Of the original 10 depositionally similar reservoir classes identified for testing, available funds have allowed DOE cost-sharing support for three reservoir classes and 29 projects.

Fluvial-deltaic reservoirs (Class I) originally contained about 70 billion bbl of crude nationwide and still contain over 5 billion bbl of potentially recoverable oil; half of this oil is at risk of abandonment by 2010. A successful EOR example is the Inland Resources / Lomax Project, which added 2.4 MM bbl of oil in reserves. Because of this demonstration, neighboring companies initiated 11 new waterfloods with more than 300 wells, which are expected to add 45 MM bbl of oil.

Shallow-shelf carbonate reservoirs (Class II) and slope-basin clastic reservoirs (Class III) originally contained more than 68 and 60 billion bbl of crude, respectively. Most of the remaining 92 billion bbl in these reservoir classes are at risk of abandonment, but EOR technologies have the potential to recover an additional 10 billion bbl.

For example, an abandoned Class III California oil lease, brought back into operation in 1995 by a DOE technology-demonstration project has, to date, produced over a million additional bbl of oil – 9% more of OOIP. Current production exceeds 1,500 bopd at the Pru Fee lease, a previously idle, 40-acre portion of California’s Midway-Sunset heavy-oil field. The lease had averaged only about 70 bopd – a total of only 2 MM bbl during its 80 years of production – before being closed down in 1985 with production at just 10 bopd.

A Reservoir Class Revisit Program (and its projects) will be much smaller than its predecessor. There will be 10 to 20 additional field-test projects, but total DOE funding is about half of the previous Class budgets, and new projects will be considerably shorter in duration (3 to 5 years). Industry cost-share will be increased to 90%, from 55%.

Comments? Write: fischerp@gulfpub.com