Nov. 2000 Vol. 221 No. 11  Production

Perry A. Fischer,  Engineering Editor

U.S. oil/gas reserves up, but not for the right reasons

U.S. proved crude reserves grew 3.5% in 1999 after an unusually large 6.7% decline in 1998. More than 137% of 1999 oil production was replaced by proved reserve additions. According to Advance Summary: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1999 Annual Report, released by the Energy Information Administration, improved economics due to crude prices resulted in the largest positive net revisions to proved reserves in over a decade.

Reserves did not grow because of increased drilling, dramatically improved technology or more-successful exploratory drilling. The rebound in 1999 crude reserves was driven by oil price increases, just as the declines of 1998 had been driven by low prices that stifled U.S. production. In December 1998, the average wellhead price of U.S. crude stood at an inflation-adjusted 53-year low of $8.03/bbl, but by December 1999 it had increased to $22.55/bbl.

Reserve additions are the sum of total discoveries and the net of revisions and adjustments. For crude, the net of revisions and adjustments was the highest in over a decade and replaced 100% of 1999 oil production.

U.S. dry gas reserves increased 2% in 1999, reversing the 2% decline of 1998. Natural gas reserve additions in 1999 replaced 118% of gas production. U.S. natural gas proved reserves have increased in five of the past six years.

Gas reserve additions were higher in 1999, because the net of revisions plus adjustments to reserves (11,486 Bcfg) was more than twice as high as in 1998 and 70% higher than the prior 10-year average. Yet in 1999, natural gas prices were only up 7% to $2.08/Mcf. The gas reserve revisions were mostly due to associated gas gains – when crude reserves were adjusted upward – rather than non-associated gas increases. Total U.S. gas discoveries actually declined in 1999.

SPR politics and prices. Well, after it was agreed by the presidential candidates that further use of the U.S. Strategic Petroleum Reserve (SPR) to ease supply problems (lower prices?) would not likely be effective, Bill Clinton did just that. The measure was aimed at increasing winter fuel-oil reserves in the Northeast.

The arguments against the release were that it would be temporary and that OPEC could easily nullify the crude-supply increase. In a column in The Bakersfield Californian, California IPA spokesman Dan Kramer was quoted, saying it was "irresponsible public policy and disastrous energy policy for the U.S. and California." Casper Zublin, a Bakersfield energy consultant, said "no one should be under the illusion that the extra oil will make a meaningful difference over the long haul." Taken together, these statements epitomize the range of political rhetoric: It is both disastrous and will not make a meaningful difference.

Both Republican and Democratic congressmen from the Northeast – where winter fuel-oil inventories are 70% below year-ago levels – support the oil swap. Outside of the Northeast, support splits along party lines. Such is politics.

This plan is similar, in effect, to a futures contract used as a hedge. The 30 million bbl of oil – about 5% of the SPR total – must be paid back within a year with interest – also paid in oil. For buyers, the hope is that oil prices will be lower when payback time comes.

On October 4, 11 companies collectively promised to exchange 31.56 million bbl within a year for 30 million bbl now. The largest takers were BP Oil Supply Co. (6 million bbl) and Lance Stroud Enterprises (4 million bbl). DOE has left open an option that would allow another 45 million bbl to be swapped in the future.

All of this is in addition to an earlier SPR swap of 2.8 million bbl to create a dedicated, 2-million-bbl emergency-heating-oil reserve in the Northeast.

Production begins at Muni field. Unocal’s Spirit Energy 76 business unit has brought its Muni discovery onstream ahead of schedule and under budget; production should exceed 120 MMcfd by year-end. Unocal holds a 100% working interest in the new field.

One well is currently producing, and two additional wells should be flowing gas by November 1. Muni is one of the largest natural gas discoveries made in the Gulf of Mexico Shelf in recent years, with a gross resource potential between 100 to 160 Bcfg.

The company acquired Ship Shoal Block 295, in OCS Lease Sale 172, in March 1999. First production at Muni came just 10 months after field discovery in December 1999.

Spirit Energy used a project-team approach to work on fast-track field development; it wanted to benefit from rising natural gas prices. In March 2000, Unocal decided to move ahead with development, and the company awarded contracts to design and fabricate production facilities for a planned December 2000 startup.

The platform, facilities and export pipeline were installed and tested about two months ahead of schedule. Unocal expects project-development costs for Muni will total less than $50 million through year-end.

First dirt. PanCanadian Petroleum Ltd. hosted a ground-turning ceremony and Aboriginal blessing on the site of the company’s Christina Lake Thermal Oil Project, located about 106 mi south of Fort McMurray in northeastern Alberta. This begins a three-phase development that will produce a multi-billion-barrel oil resource, beginning with 10,000 bopd in phase one.

PanCanadian will use steam-assisted gravity-drainage (SAGD) technology, developed and proven in Alberta and Saskatchewan, to produce the heavy-oil sands. SAGD recovery involves the use of two horizontal wells drilled in parallel, with the producing well located about 16 ft below the steam-injection well.

The $400-million project received regulatory approval from Canadian agencies in August of this year. The $70-million first phase will begin production in 2002 and ramp up to 10,000 bopd by 2004.

Comments? Write: fischerp@gulfpub.com