Archive  February 1998 Vol. 219 No. 2  Production

Thomas R. Wright, Jr.,  Editorial Director

Field development could ease Alaska's falling production

Alaskan production, which has been declining, will get a boost as a new North Slope field goes onstream. ARCO Alaska, Inc. began commercial production from West Sak oil field's first well last December. Now producing 200 bopd, the well's rate will be increased slowly and is expected to reach the project's production target of 300 bopd per well.

Work began last October. Fifty wells, including production and injection, are scheduled for completion by early 1999. Nine wells have been drilled and cased and will soon be in operation.

The company says its phase 1 West Sak development program is on budget, on time and will contribute to achieving the company's North Slope production goal of "No Decline After 99," says ARCO Alaska President Ken Thompson. "This effort will develop 51 million bbl of new reserves and add near term production of 4,000 bpd gross in 1998, increasing to 7,000 bpd day in early 1999."

Phase 2 development would require 500 additional wells, yield additional reserves of 400 million barrels and push production to 37,000 bpd in 2002, increasing to 70,000 bpd by 2005.

The West Sak development hinged on the ability to develop and operate the field at low cost. Low cost drilling and completion technologies, and extensive use of existing Kuparuk infrastructure have kept estimated phase 1 development at only $98 million.

West Sak is a relatively shallow viscous oil accumulation that overlies much of Kuparuk field. Oil in place has been estimated at more than 15 billion bbl. West Sak is owned by ARCO Alaska, Inc., BP Exploration Alaska, Unocal, Mobil and Chevron.

Meanwhile, ARCO British Limited (ABL) has received approval from the UK Department of Trade and Industry to develop a western extension of Bure field and the new Deben field in the Southern Gas basin. Both developments are located in Block 49/28 and are due onstream in October 1998.

Each will be developed via one subsea well tied back to the new Thames AR platform, which will be bridge-linked to ARCO's existing Thames complex. The AR platform will provide metering and separation for gas from the two new developments prior to processing and export via the Thames platform's existing facilities.

Again, existing infrastructure has allowed the company to devise and implement a very fast and economic plan for these two new developments. The well on the Western extension of Bure field (seven mi northwest of Thames complex) will increase recovery from this field by an estimated 31 Bcf of gas. Deben (four mi northwest of Thames) was discovered in 1974 and has estimated recoverable reserves of 33 Bcf of gas.

Deepwater GOM development. Elf Exploration, Inc. says it will develop its Virgo discovery on Viosca Knoll Block 823, offshore Louisiana in 1,132 ft of water.

The discovery well, Viosca Knoll 823-2, was begun last March, and found 376 ft of hydrocarbon-bearing sands. The Viosca Knoll 823-3 appraisal confirmed the discovery and encountered a new reservoir with 32 ft of pay sands.

Elf and partners will install a conventional four-leg, 14-slot drilling and production platform in 1,132 ft of water. Production capacity will be 120 MMcfd of gas and 15,000 bpd of oil and condensate. Production is expected by year-end 1999.

New Dutch Production. Elf Petroland announced three new operations aimed at maintaining its position as the Netherlands' number two operator.

The first is the production start-up from K4aD gas field on Block K4a of the Dutch OCS. A subsea well began production last October at about 25 MMcfgd. It is linked to nearby Markham field.

In K5E North field, gas production commenced from an unmanned platform designed to handle up to 105 MMcfgd. A second field, which overlaps Blocks K4b/K5a and K5b, will follow later.

On its Block K6 Central Complex platform, the company installed a compression module that will increase the block's gas reserves by 250 Bcf to a total of 810 Bcf.

SPR degassed. U.S. DOE says the Strategic Petroleum Reserve (SPR) has been restored to full drawdown readiness, with completion of a two-year program to remove excess natural gas that had accumulated in some of the oil. In 1993, DOE found that some of the longest-stored oil had an excessive gas content, which DOE says came from naturally occurring methane in surrounding salt formations.

Overall, some 172 million bbl of SPR's 563 million bbl of crude required treatment since DOE felt the dissolved gas posed a safety problem when crude was pumped to surface. Exposed to atmospheric pressure, methane could escape from the oil and, mixed with air, could create a potentially explosive hazard, says DOE.

Now to us, this doesn't sound much different from any typical oil field operation, which is routinely handled by a "novel" device called a separator! In fact, DOE's corrective actions included the use of two mobile gas separation units. Crude was pumped from the caverns, through the degasification units and reinjected.

Begun in August 1995, degassing lasted 28 months, and took place at all four of the currently active SPR sites. DOE says it may need to routinely degass the oil in the future, possibly as often as every 10 years.

No telling what this all costs.

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