Trinidad's giant Amherstia field began production in October 2000. Eight gas wells and two oil wells have now been drilled and completed, with production capability in excess of 700 MMscf/d. Well performance has far surpassed pre-field development predictions, with current forecasts indicating that the current platform capacity of 825 MMscf/d will be exceeded. The paper describes the many innovative steps taken by the Trinidad based, Amherstia team, bringing world-class technology to Trinidad and developing some of its own, including:Completing the largest gas well operated by bp (225 MMscf/d peak rate) and the largest in Trinidad, achieved by drilling Trinidad's first horizontal gas well and using 7" tubing as the production string;Introducing the use of near bit, hole opening reamers to eliminate back reaming;Extending the step out capability of the in house drilling fleet, developing distant oil reserves in an area formerly deemed unreachable.Introducing Shunt tube open hole gravel pack technology to Trinidad;The use of 4 Component, Ocean bottom Seismic and Pre Stack Depth migration to obtain clear and undistorted images of strata below shallow gas. Due to the risk of sand production all wells are fitted with Acoustic sand detectors and flowlines operated with erosion limits for nominally sand free production. Permanent downhole pressure gauges are used to ensure pressure build up data is collected whenever a well is shut in. This data, together with the "wet gas" meters used at the surface, mean that the well is, in effect, permanently being tested. Plans are under way to increase platform capacity to 1.1 bscf/d. Introduction The Amherstia platform produces a giant gas field located 40 miles off the Southeast coast of Trinidad (see Figure 1). Initial reserves in the Amherstia area were 2.27 Tcf of gas and 23.7 mstb of crude and condensate, which is distributed over 11 different accumulations. The crude oil is associated with thin oil columns below large gas caps. Amherstia started up production on 15 October 2000 and currently supplies about 700 MMscf/d of gas to the domestic gas market and to Train 2 of Atlantic LNG. Development of Amherstia prior to start up was described in an earlier paper1 which proposed the use of completion techniques new to Trinidad, such as the use of 7" tubing and multilaterals to drain the oil column. The development strategy was to:Complete wells in the deeper 23 and 24 gas sands to satisfy immediate gas requirements;Develop the thin oil column in the 22 sand;Exploit various shallower gas horizons;And finally blowdown the gas cap of the 22 sand when the oil had been depleted. The present paper describes what happened in the first two years of production, the many successes, and some lessons learnt.
Selective acid stimulation has been performed effectively to treatcompletion damage, scale buildup and remove calcium-based drilling fluidfiltrate with the use of inflatable straddle packers run on coiled tubing, inboth horizontal and deviated sand control completions. Production resultsindicate that mechanical method of treatment diversion is extremely effectiveand provides information of formation response in discrete intervals. Two casehistories are discussed which resulted in a 100% production gain and acorresponding injectivity increase from 0 to -16 bbls/day/psi for somesections. A horizontal completion had 980 ft treated in 20 ft sections and a 70degrees deviated wellbore had over 300 ft of interval stimulated using the sametechnique. Stimulation pressure limitations are discussed with respect to theinflation ratio of the packer elements and the deformation, after use.
Two coiled tubing conveyed concentric gravel packs were performed to repair screen damage of existing open hole gravel packs. Both completions were initially drilled and underreamed to 1!" with a polymerized calcium carbonate drill-in fluid and gravel packed using water pack techniques. Case histories are presented with pre/post production data for this remedial operation which utilized recent technological developments of the circulating gravel pack packer and sand screen. A risk sharing alliance was employed to meet the needs of the operator while providing incentive to the service sector for the first operation of its type in Trinidad. Cumulative production gain of 500 BOPD from both wells was obtained at a cost savings of approximately $1.8 MMUSD when compared to conventional rig repair options. The payout time for each well was approximately 4 months. These two operations were major achievements in coiled tubing sand control technology for the following reasons:Well E-ll: Longest circulating gravel pack assembly (480’) installed to date.Well E-19: Most sand placed through the gravel pack packer (12,800 lb.).Clarified xanthan gum was used for the first time in this type of operation as a carrying agent due to its shear thinning properties to reduce friction pressure under circulating conditions and provide gravel suspension when static.
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