| Popis: |
ABSTRACT Installing and operating electric submersible pumps (ESP's) in an arctic environment presents new challenges for Operators and the ESP service industry. Relatively short run times prompted engineers and field personnel from Conoco and ESP vendors to critically examine all facets of our ESP operations. Equipment and procedures have been modified to address problem areas and initial run times are increasing. INTRODUCTION The Milne Point Unit is located on the shore of the Beaufort Sea, 240 miles north of the Arctic Circle on the north slope of Alaska. It is bounded by two of the nation's largest oilfields, the giant Prudhoe Bay Unit to the east and the Kuparuk River Unit to the south and west. Production from Milne Point is qUite small by North Slope standards, adding only 20,000 BOPD into the 1.8-million-BOPD Trans-Alaska pipeline. Conoco Inc. began operating submersible pumps in the Milne Point Unit in 1985. The first applications were in high-rate (12, OOO BWPD) water source wells. A program was started in 1989 to install ESP's to accelerate production in selected lower-rate (500-1500 BLPD) oil producers. These wells had previously been produced with gas lift. Submersible pumps are now being installed in all completions on new outlying wellsites. ESP's offer a variety of operational and logistical advantages over gas lift for the Milne Point Unit in particular, and the arctic environment in general. High failure rates in the initial installations raised serious concerns regarding the applicability of ESP lift in the Milne Point wells. Many problems have been encountered. Production of solids, improper operating practices, and design problems have all contributed to failures. The extreme cold and remote location have also had an effect on ESP operations. Pumps and cable have been subjected to months of sub-zero temperatures before installation. Equipment must often be installed when ambient temperatures are less than -30 °F. Low reservoir temperatures, coupled with permafrost cooling, have created hydrate problems in shallower wells. A comprehensive evaluation of all aspects of ESP lift was undertaken in response to the high failure rate. A work team was established including representatives from engineering, electrical systems, and field operations to research all submersible pump installations. The recommendations and guidelines they presented are being implemented and run times are increasing. This paper discusses lessons learned from this evaluation and from seven years of ESP lift production in Alaska. HISTORYAND APPLICATIONS Submersible pumps have been run in 36 wells in the Milne Point Unit since 1985. A total of 60 individual units have been run. ESP's have been used to lift fluids from three intervals: the Prince Creek water sands, and the Kuparuk and Schrader Bluff oil pools. The first applications involved lifting water from the Prince Creek formation to supply injection water for a waterflood. The Prince Creek zone is a large unconsolidated sandstone interval located from 2750' to 3250' TVD. Reservoir temperature averages 60°F. Wells are perforated in several sand lobes and then gravel-packed. Figure 1 shows a typical installation. |
