Coiled-Tubing Intervention Results in Substantial Savings

Abstract

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 130682, ’High-Risk Coiled-Tubing Intervention Results in Substantial Savings,’ by F.N. Thom, SPE, and M.J. Taggart, SPE, BJ Services; J.D. Murdoch, SPE, Shell; and B. Ewing, Welltonic, originally prepared for the 2010 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 23-24 March. Problems with the tubing-retrievable subsurface safety valve (TRSSSV) and the subsea-tree valves resulted in a completion workover being scheduled. Before pulling the production tubing, the A-annulus was pressurized to 3,500 psi to reduce the differential pressure across the tubing. At 2,850 psi, there was a sudden loss in pressure, indicating a leak in the outer casing string. The workover was suspended and the well left in a safe condition. Planning for a full abandonment then was implemented. Introduction Teal P1 is a subsea well in the central North Sea. It was completed in July 1996 and had a peak production rate of 40,000 BOPD. During the completion stage, operational difficulties in setting the production packer in the wellbore resulted in several failed setting attempts. This resulted in a larger-than-expected volume of debris in the well. Because this debris had the potential to damage the turret seals in the floating production, storage, and offloading vessel into which the well produced, a debris-barrier assembly was designed and installed in a short time period. This debris-barrier assembly consisted of a preperforated tail pipe with a 3½-in. bridge plug installed in the base, all hung off with a packer in the 5½-in. production tubing at 945.5 ft measured depth (MD). In 2002, the TRSSSV failed to close during a routine test, and in 2005, the integrity of one of the subsea-tree valves could not be established because it failed a pressure test. A workover to replace the completion-tubing assembly was scheduled in an attempt to regain well integrity. Before pulling the completion tubing from the polished-bore receptacle (PBR) in the production packer, a caliper survey was conducted down to 972 ft MD, which showed a 1-in.-thick scale buildup in the completion. The wellbore then was bullheaded with 830-lbm/1,000 ft oil-based mud (OBM) to overcome the reservoir pressure, followed by approximately 23 bbl of seawater to occupy the top 1,000 ft of completion tubing. At this point, the completion tubing contained 830-lbm/1,000 ft (16-lbm/gal) mud, while the A-annulus contained 8.52-lbm/gal inhibited seawater equivalent to a hydrostatic differential pressure of 3,344 psi at the PBR at 10,195 ft MD. Because of the completion design consisting of two tubulars (one as the main production bore, and the other as a short tail pipe to access the A-annulus) a tubing-hanger-running orientation tool (THROT) was required to retrieve the tubing hanger. With an underbalanced fluid in the annulus and to provide adequate overbalance during unstabbing of the PBR, the drilling blowout preventers (BOPs) would need to remain closed, which could not be achieved with the THROT in place. Therefore, coiled tubing (CT) was rigged up to mill the scale deposits in the completion tubing down to 760 ft MD to permit access for a tubing cut in the 5½-in. tubing.