Use of Electric Submersible Pumping Systems in Offshore and Subsea Environments

Abstract

Abstract Electrical submersible pumping (ESP) systems have been an efficient method to boost production of oil wells for over half a century. In the past few years, ESP systems have been accepted for use in what once was considered unconventional types of applications, pushing the technology further than ever before. This technology push has encouraged ESP suppliers to devote more time and energy to research and development in order to meet the needs of the expanding application envelope. This paper will outline the results of the research and development as well as the advancements that have been made or are likely to be made to various components of an ESP system. New and innovative ways in which ESP systems have been deployed as well as the positive effects that these techniques will have on the ultimate well recovery and customer's return on investment for deepwater projects will be reviewed and discussed. We will highlight the specifics of ESP applications in off-shore and subsea projects, including seabed boosting. History of ESP system An ESP system is made up of a multi stage centrifugal pump; a seal section which protects the motor from well fluid, ab-sorbs the thrust from the pump and provides pressure equalization between the motor and the wellbore; and a three-phase induction type motor of a HP large enough to drive the pump. An ESP system is lowered into the wellbore on the end of a tubing string which is hung off at the wellhead. The ESP unit is self-contained and requires no additional lines for lubrication or cooling. While ESP technology may seem like an emerging area to some in the oil industry, ESP systems have been in use since 1926, when the first unit was installed near Burns, Kansas for the Phillips Petroleum Company. This unit was deemed to be a success because it ran 24 hours a day for 16 days before a failure. If you were to study some of the early patents, you would find that the basic technology hasn't changed much over the years. Today, the overwhelming majorities of systems are in-stalled in land based applications, with an average ESP in an oil application at a setting depth of approximately 5000 ft, and an average run life of between two and three years. It will typically produce at a flow rate range from less than 1000 BFPD to 30,000 BFPD or more. Contrast the above with the opportunities that we are being presented with today. ESP systems are now being deployed in offshore wells where extra lift or drawdown is required to maximize production. ESPs have been deployed and will continue to be deployed in subsea applications with ever increasing stepouts and water depths. Operators are being faced with increa-singly stringent HS&E requirements, economics are tighter, and return on investment is critical. We are constantly being pushed to new limits with water depths of 8,000 to 10,000 ft or possibly greater. What has changed over time to give us the confidence to install an ESP system in a well with extremely high cost of fail-ure, and where the cost of a workover will be in the millions of dollars? It is worth noting that for most of the world an ESP with a service life of two to three years is considered to be acceptable. While most operators will ask for longer run lives, when they weigh that against the additional cost of procuring such a sys-tem, the economics will not justify the added expense. However, when we look at the offshore—and particularly the sub-sea—environments, the economics drastically change. The cost of an ESP system is relatively small vs. the cost of a workov-er, so the additional upfront cost associated with a higher-end ESP becomes less significant. Additionally, the technology involved in the design, engineering and deployment of ESP systems has changed dramatically over the past few years. These changes have been driven by operators asking the ESP companies to push the equipment toward its operational limits and at the same time asking for longer run lives.