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In recent years, the deployment of intelligent completion technology has increased as has the range and functionality of the systems available. The focus has been on developing intelligent completions that will allow a greater degree of controlling reservoir inflow. Improvements in the methods that could be used to model the values of these complex completions have in general lagged behind. In this paper, a phased process for evaluating the productivity benefit offered by an intelligent completion system for a multi-layered, shallow gas reservoir system is described in detail. To start the process, an intelligent completion system was selected that was compatible with the well architecture and would provide maximum flow control capability (infinitely variable choke). Analytical methods where then used to conduct a screening exercise in order to evaluate the production benefit this high-end intelligent completion could offer. This screening exercise provided a fuller understanding of the hydraulic interactions occurring within the wellbore. As such, it was possible to tailor the level of intelligent completion functionality to the production benefits derived. A detailed study was then carried out using dynamic 3D-simulation modelling, which incorporated the selected intelligent completion components as a part of the reservoir simulation. This phased approach helped in determining the optimum intelligent completion configuration taking into account the time related reservoir performance changes.

Abstract Gas wells completed in prolific reservoirs before the advent of bigbore completions do not produce to full potential due to tubing constraints. This phenomenon was observed in several mature, carbonate gas fields offshore Malaysia developed back in the early 1980s. At that time, tubing configuration was limited to 7" completion run in 9 5/8" production casing. Given the size of the production casing, any workover option to enhance outflow performance was limited to recompletion with 7 5/8" tubulars which would result in a 10% gain in well capacity through improved outflow performance. The advent of solid expandable tubular technology in the new millenium has opened up a revolutionary possibility for transforming a conventional well with 7" tubing to a bigbore producer. The concept involves installing and expanding extended lengths of 7 5/8" solid tubulars inside 9 5/8" casing. This will yield a production conduit with a larger internal diameter than conventional 7 5/8" tubulars. Thereafter, gas production occurs through the solid expandables based on a philosophy similar to long casing flow monobores. A field trial to test this novel re-completion concept was carried out in a gas field offshore Sarawak in December 2001. Expected benefit of a re-completion to solid expandable tubulars is a 40-50% increase in well deliverability from prolific reservoirs previously tubing constrained. If proven successful, this novel recompletion design will be extended to other tubing constrained gas wells in the area. The paper will present the results of this field trial, which is the first of its kind in the world. Details encompassing the conceptual solid expandable completion design, modifications and improvisation required for a SET gas well workover, the SET installation sequence and results from the trial will be presented. Introduction Field Background. The E11 field, located offshore Sarawak in a water depth of 233 ft, is a low relief, pinnacle carbonate buildup of Miocene Age (Fig. 1). The field was discovered in 1971 and covers an area of approximately 12 sq.miles with a gas-bearing interval of up to 1700 feet thick. The carbonate reservoir is characterised by porosities ranging from 5 to 25% and permeabilities ranging from 10 to 400 mD. The field was developed 10 years later from a 20-slot drilling platform with first gas production in August 1982. A total of 10 deviated development wells were drilled and completed using 7" carbon steel tubing tapered to a 4" string from Chrome 13 material with a 7" carbon steel liner cemented and perforated in the reservoir section. Historical Workover. In 1997, seventeen years after the initial development drilling, five of the ten wells were worked over replacing the 7" carbon steel production tubing with 7 5/8" Chrome 13 tubing. The two main factors driving the workover requirement at the time were corrosion and well capacity. First and foremost, the workover was intended to address concerns of galvanic corrosion by replacing the entire completion string withChrome 13 material.