Abstract

In July 1995 the first coiled tubing insert gas lift string (CTIGLS) to be run in the North Sea was installed in BP Exploration's Forties Field. Following 15 months of successful production the completion was worked over in November 1996. This is only the fifth completion of its kind to be run world-wide and the first to be worked over.

The project was a commercial success, even though production did not meet predicted targets.

Initial corrosion predictions suggested the completion should be pulled within six months. However due to good performance of the well and increasing confidence in the integrity of the completion the asset decided to continue production. The well was worked over some fifteen months into production.

As with all new projects problems were encountered, especially during the workover, which added to the cost of the operation. The lessons learned from our experiences will be invaluable in planning any future operations of this kind.

The complete operation was planned and executed by the Forties Well Engineering Alliance, involving extensive input from several service companies along with BP.

Introduction

The Forties Field has been producing since 1975. Initially all producing wells were installed with 7" completions and produced naturally at over 20 Mbd dry oil. As the reservoir pressure declined and water production commenced the completions were downsized to 4–1/2" tubing in order to continue natural flow (Fig 1). Again water cuts rose to the extent that natural flow was no longer possible for many wells and in 1989 an artificial lift programme was initiated to continue production.

Gas lift was the preferred method of artificial lift. Completions were redesigned to allow 5–1/2" production tubing to be run with 2–3/8" gas injection string in the casing (Fig 2). The original casing utilized buttress connections which required replacement with premium connections in order to provide a gas tight annulus for the injection gas. This operation was lengthy and expensive, requiring the old casing to be cut and pulled and new casing to be installed, also to allow room for the two strings.

Unfortunately the carbon steel tubulars which served so well for the first 15 years of the field life performed very poorly with the increased water cuts, CO2 and sand production. Within two years it became apparent that the completions and liners would have to be replaced with higher grade metallurgies. This resulted in suspension of the gas lift conversion programme to re-assess the way forward. The conclusion was that all future gas lift wells would require sidetracking to allow installation of a new 13% Chrome liner. Insert liners were not at the time acceptable due to the reduced ID and flow restrictions. For most wells the sidetracks were to a bottom hole location some 50m away from the original location. In some cases the oil remaining at that location did not justify the ca 2.5M cost of the sidetrack so the original hole would be abandoned and the well would be drilled to a new bottom hole location somewhere else in the field. This resulted in considerable amounts of oil left in place but un-produced. A cheaper method of artificial lift was required to access the remaining oil.

One option looked at by the Forties team was coiled tubing insert gas lift completions. The options available for installing an insert string and to change the lift mechanism of the well was:

  • Non-upset tubing

  • Flush pipe

  • Coiled tubing

  • Upset Tubing

P. 465^

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