Abstract

ARCO's Kuparuk River Field on Alaska's North Slope is a high cost operating environment. In the face of declining reservoir pressures, ARCO began using electric submersible pumps to augment production. Installing and pulling these units carries a very high cost due to the need to use large, arctic workover rigs designed for major well completion operations. Confronted by the need to lower intervention costs, ARCO began investigating alternate deployment methods for submersible pumps. Coiled tubing rigs were available and less costly, so the idea of installing a pump using only a CT rig was developed. Working with Centrilift's cable and pump groups, a method of suspending power cable inside coiled tubing was developed 1. This ElectroCoil™ would allow installation or pulling of a pump using only a CT rig and crane. With the cable inside the coiled tubing, no banding is required. The concept was further developed to include a Baker packer and dual flapper assembly downhole to assist in shutting off reservoir pressure mechanically instead of using formation damaging and expensive kill fluid. Note - the packer is required to segregate pump suction and discharge. The dual flappers allow the well to be pulled without continuously adding kill weight fluid. With dual flappers, we would kill to unsting and run under-balanced to pull and run. This paper details the procedures used to install this system and discusses additional issues that must be addressed to help ARCO continue to lower intervention costs.

Introduction

The primary purpose of this paper is to explain the details of a new well intervention process, coiled tubing deployed electric submersible pumps. Although sub pumps have been deployed via coiled tubing in the past, this procedure incorporates coiled tubing with the pump power cable installed inside, eliminating the need for spooling and banding at the wellhead. This ElectroCoil™ mechanical support system has been detailed in other articles and will only be mentioned briefly in this discussion. We will, however, provide some field and system over-view information to familiarize you with the basics of the systems used. The bulk of the paper will explain the processes used, what worked well and what didn't, and a look forward into the continuous improvement process that is needed to help ARCO manage intervention and production costs.

Field Overview

The Kuparuk River field is located on the Arctic coast of Alaska, approximately 500 miles north of Anchorage (Fig. 1). The Kuparuk River field is North America's second largest oilfield, behind only Prudhoe Bay. The current production is 240,000 barrels oil per day, but had a peak rate of 333,000 barrels oil per day. The estimated original oil in place is 5.5 Billion barrels oil, and covers an area of approximately 115,000 acres. The field was discovered in 1969, but was not economic to develop until the completion of the Trans Alaska Pipeline System (TAPS) in 1977. Figure 2 shows the field location.

Field development occurs on gravel pads and roads which range from 6 to 8 feet thick, to protect the fragile tundra from mechanical and thermal damage. The central drill sites used directional and deviated wells to drain up to a four-section area (4 square miles). The initial development occurred on 160 acre spacing, but some in-fill drilling to 80 acres is now occurring.

The Kuparuk Reservoir is a naturally fractured sandstone and lies at a depth of approximately 6000 feet sub sea. Solution gas is the primary reservoir drive mechanism, but the reservoir is also currently receiving pressure support through a combination of waterflood and water alternating immiscible and miscible gas injection. The field is currently being gas lifted, but as water cuts are increasing, electric submersible pumps are being evaluated and installed in select areas of the field. Numerous papers have been written describing both the reservoir characteristics and geologic descriptions of the Kuparuk field. 2–6

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