ESP Economics as Applied to the Offshore Environment

Abstract Electric submersible pump (ESP) economics include capital expenditures (CAPEX) and operating expenditures (OPEX). Because workover rig and associated costs are high, run life can impact the OPEX tremendously. Offshore ESP/downhole separator economics can be significantly improved with consideration of deployment methods and of factors affecting reliability. Significant advances have been made in ESP deployment methods to reduce installation and retrieval costs and to increase reliability. This paper examines, from an economics viewpoint, the viability of both standard ESP and ESP-based downhole water separation units in the offshore environment in light of workover costs and reliability concerns. Several factors affect ESP infant mortality and general run life including handling and installation procedures, well environmental factors such as temperature, presence of H2S, CO2, solids, free gas, power quality, and startup/shutdown and operating procedures. With ESP-based downhole oil/water separation units, additional reliability issues come into question; namely those concerning the downhole separator and system instrumentation. Technology reliability is crucial if cost of ownership is to be minimized. High intervention costs often drive decisions pertaining to the implementation of a particular technology offshore, rather than the capital expense of the technology itself. A new ESP deployment method using coiled tubing has been employed, where power cable may be run either outside of the coiled tubing or encased within the coiled tubing. When cable is run inside of coiled tubing, an ESP unit can be run faster, with minimal risk of cable damage. Other advantages of coiled tubing deployment of ESPs are presented. Introduction In many offshore developments, artificial lift is required from the outset. In other mature offshore projects, operators are often compelled to deal with increasing volumes of water production, necessitating the introduction or upgrade of artificial lift capacity. Many offshore fields worldwide have approached or are approaching maturation. Despite a considerable CAPEX, the artificial lift method of choice offshore is often gas lift due to its reasonable OPEX. Gas lift negatives, often ignored, include hydrate formation, wax, emulsions, asphaltenes, and salt precipitation due to lowered temperatures. The ESP has its relative advantages including the ability to produce significantly large fluid volumes at near pump-off conditions. In fact, as water cut rises and reservoir pressure becomes depleted, gas lift provides only average performance whereas with ESP, well production rates can often be increased by a factor of 2. However, reliability concerns have restricted more widespread use of the ESP, particularly in high workover cost areas. This paper reviews economic considerations for ESP implementation in the offshore environment in light of some reliability issues, which may ultimately influence decisions concerning use of ESP artificial lift. Accessory technologies which may lead to increased ESP runtime are reviewed. A new deployment method is reviewed to see how some reliability concerns are lessened or alleviated, thus making ESP and ESP-based technologies such as downhole oil/water separation more tenable offshore. Offshore Economic Overview Offshore operations are more costly than onshore operations, in view of both capital and operating expenditures.