Scott Field Associated Gas (7260 bytes)
Scott field (U.K.) operator Amerada Hess Ltd. was able to begin production offshore months before permanent gas processing was available ashore at Mobil North Sea Ltd.'s St. Fergus terminal by installing temporary gas sweetening on the platform,
Early in 1992, Amerada Hess recognized that the Scott platform would be ready to export oil and gas in late 1993, several months before gas processing would become available at St. Fergus. ICI Katalco's Puraspec 100 Process was selected to purify the associated gas to pipeline quality. The unit was installed in April 1993 and began treating gas in October.
St. Fergus processing became available Apr. 1, 1994, on schedule. Operation of the platform unit has continued since then, controlling H2S content as well as providing the flexibility of exporting on-specification gas for any feed rate and H,S content.
The Scott-field development is the largest U.K. offshore project in the 1990s. Located 130 miles northeast of Aberdeen, the field has recoverable reserves estimated at 450 million bbl of oil and 287 bcf of associated gas.
In addition to the subsea facilities, the development consists of twin steel platforms with connecting bridges. The process/drilling platform has a 74 x 30 m deck, drilling and gas-treatment modules, and a flare boom.
DESIGN
The design basis for the Scott field was normal production of 164,000 b/d of oil and 83 MMscfd of gas with peak capabilities of 194,000 b/d oil and 124 MMscfd gas.
Oil is exported by a 50-mile, 24-in. line to the BP Forties system which goes ashore at Cruden Bay, 30 miles north of Aberdeen.
Gas goes through an 8 mile, 10-in. line to the Mobil's Scottish Area Gas Evacuation (SAGE) pipeline to the new Mobil terminal at St. Fergus 10 miles north of Cruden Bay.
To permit early production, temporary gas sweetening was installed to treat gas with the composition and operating conditions shown in the accompanying table.
The sweetening unit consisted of a single, fixed-bed reactor at the discharge of the high-pressure compressors (Fig. 1) (9911 bytes).
It was fitted on a corner of the 1,000-ton glycol drier module which was fabricated by McNulty Offshore Services, Tyneside, U.K. This module was positioned offshore in April 1993.
The unit was designed for minimum space and weight and to make replacement of the absorbent easy. It was expected to have a total operating life of about 6 months until Mobil's facilities became available Apr. 1, 1994.
At normal design conditions, with 2 ppm (vol) outlet H2S, the expected life of one absorbent charge was 18 days. It was recognized that this figure was uncertain and likely to be variable, so a "call-off" contract was put in place between Amerada Hess and ICI Katalco which allowed for supply of up to 12 refill charges between September 1993 and March 1994.
A separate contract was established between Amerada Hess and ACI Industries Ltd. to cover collection and reprocessing for metal recovery of discharged absorbent.
OPERATIONS
Associated gas was first treated and exported from Scott to the SAGE pipeline on Oct. 17, 1993. First Scott gas was declared to have arrived at St. Fergus Nov. 2. Within a few days, production had reached design rate.
After some start-up delays, oil-production rate also built rapidly to the extent that more than 200,000 b/d oil and 100 MMscfd gas were being produced before the end of 1993.
Maximizing oil output required production from a sour well, the associated gas from which contained about 120 ppm (vol) H2S. After blending with gas from sweet wells, the H,S in the feed gas to the Puraspec unit was then about 30 ppm.
By appropriate by-pass control, the H,S content of export gas was always reduced to the required 2 ppm (vol), but the increased gas rate and higher sulfur content meant that catalyst changeout intervals were inevitably shortened.
Several absorbent charges were used before St. Fergus terminal sweetening became available, on schedule, Apr. 1. Routine analyses of samples of absorbent confirmed that it had performed as predicted.
Correlation with sulfur quantities calculated from process conditions was excellent.
Absorbent was delivered to Amerada Hess in bags each holding approximately I cu m. These or similar bags were used for collection of spent material which was discharged, by gravity, down the inclined pipe on the side of the reactor.
Including the essential steps of purging and cooling, the gas-to-gas time needed for an absorbent change was about 16 hr. During this time, gas would be flared, but the volumes were always within Amerada Hess' consent quantities.
The company operates under flare consents from the U.K. Department of Trade & Industry initially on a monthly basis but currently on 3-month consent periods.
Amerada Hess also operates under a self-imposed maximum daily flare rate of 50 MMscfd, but the actual average daily rate is only 6 MMscf. Of this amount, up to 2 MMscfd are necessary to ensure that the system is 100% gas and that there is no chance of air ingress caused by the flare-header pressure of about 1 barg.
One spare charge of absorbent is held on the platform to allow bed replacements even if inclement weather causes delays in delivery by the regular supply ship.
Amerada Hess' future operating plans have been modified in the light of experience to date. Oil production up to 208,500 b/d has been possible by including the sour well which increases the H2S content of the associated gas to about 40 ppm.
Since commissioning of Mobil's St. Fergus processing, the H2S specification in gas exported from Scott has been relaxed to 20 ppm (vol), maximum. This is provided by treatment of 50 MMscfd, one-half of the total gas volume of 100 MMscfd, in the sweetening unit.
Frequent analyses of gas received at St. Fergus confirm that the H,S content can be reliably controlled at 19 ppm (vol), thus meeting specification while minimizing absorbent consumption.
The unit provides the flexibility to export on-specification gas for any feed rate and H,,S content. At present, the unit will remain indefinitely a part of this production platform.
Copyright 1995 Oil & Gas Journal. All Rights Reserved.
