Improved Coiled-Tubing Squeeze-Cementing Techniques at Prudhoe Bay
Authors: Hornbrook P. Rosemary , Mason Clifton M. 
Published: December 2007

This paper presents major changes in coiled-tubing squeeze-cementing techniques used in the Prudhoe Bay Unit Western Operating Area (PBUWOA). Changes include introduction of a polymer diluent to replace borax contamination, increased differential pressures placed on squeeze and coil, reduced cement volumes, and incorporation of an inflow test and resqueeze procedure. These changes resulted in increased squeeze effectiveness by reducing equipment and engineering time requirements and by shortening well shut-in time after the workover.

Introduction

Coiled tubing was introduced to the Alaskan North Slope because it is fast, mobile, relatively inexpensive, and well suited to subzero conditions. It is used extensively for a variety of purposes, including logging high-angle and horizontal wells, perforating, underreaming, cleaning out fill, squeeze cementing, and stimulating with acid. This paper focuses on squeeze cementing, also referred to as coiled-tubing unit (CTU) workovers. Techniques and data apply only to the PBUWOA. The primary objective of the original coiled-tubing squeeze-cement program, from late 1985 through mid-1988, was to extend plateau oil production. The anticipated decline point was delayed by working over wells that had the greatest potential for increasing oil rate and reducing excess gas. Reducing gas production from the worst offenders freed facility gas capacity to handle oil production from other wells with high producing GOR. These other high-GOR wells produced gas at rates greater than the acceptable field average, but not nearly as high as the wells with the highest priority for workovers. Freeing up facility gas capacity was then equivalent to bringing on shut-in oil wells. Coiled tubing is a continuous string of 1.5- or 1.75-in.-nominal-OD pipe wrapped around a reel and secured to a mobile control unit. Coil is threaded through an injector head (Fig. 1), pulled off the reel, and fed through well-control equipment (including pipe blind, shear and slip rams, and hydraulic control system) and into the well. Currently, about 10 CTU's are available for use on the North Slope, and BP Exploration (Alaska) has four on contract. Fig. 2 depicts a representative wellbore in the PBUWOA. It includes a 9 5/8-in. production casing set just above the Sag River formation and a 7-in. production liner set through 40 to 50 vertical ft of the Sag River formation and about 500 vertical ft of Ivishak formation, the primary productive interval in the field. Most of the wells are completed with a 9 5/8-in. packer with 4 1/2-in. tailpipe set immediately above the 7-in. liner top. The packer and tailpipe assembly are generally completed to the surface with 4 1/2- 51/2, or 7-in. tubing.

Original CTU Squeeze Technique

The original Prudhoe Bay Unit CTU squeeze technique was developed to reduce reservoir control costs compared with those of an arctic-rig workover. The CTU is mobile and requires less well preparation than an arctic rig.

Arctic Conditions.

The first technical issue resolved during development of the original program was year-round operating flexibility. Temperatures on the North Slope often dip below -40F and wind speeds reach 60 miles/hr during the winter. An individual on-site laboratory, manifold system, and tank farm were designed and constructed to be mobile and enclosed for heat. Air compressors are used to blow most soft lines dry, and a supply of methanol is kept on location to protect hard lines, coil, and the well, if necessary, from freezing. The CTU itself is well-suited to arctic conditions with an enclosed operating cab, no tubing joints to break or make up, and therefore no rig floor to heat.

Removal of Excess Cement.

The second major issue concerned removal of excess cement without drilling. In areas other than Alaska, the oil industry uses coiled tubing to squeeze cement into perforations or other liner breaches. In most cases, cement is cleaned out of the wellbore by moving in a rig and drilling out hard cement. Coil can be used to reverse out excess cement after a squeeze. However, special care must be taken with rates and pressures during the reverse-out because coil collapse is a major concern. Coiled tubing is thin-walled, flexible, and relatively fragile compared with jointed pipe. Because several coil collapses occurred early in the program, and published test data were lacking, differential pressures across the coil were limited to 1,500 psi until 1989. To avoid drilling and to reverse out cement within pressure guidelines for the coil and formation, a cement dilution and retardation fluid was developed.

JPT

P. 455^