Subsea ESPs gain acceptance via advancing technology

World Oil, May, 2001 by Graham Anderson, Grant Harris, John Pursell

A growing number of ESP systems are being installed in subsea facilities worldwide, including remote tie-backs and difficult environments. Greater subsea usage signals operators' increased confidence in ESPs, prompted by improved longevity and reliability

Subsea Electric Submersible Pumps (ESPs) are gaining acceptance as their reliability improves, reducing installation costs and the number of interventions--planned or otherwise. Evolving ESP technology is enabling longer step-out wells to be tied back to a host platform, making marginal and distant fields economic to exploit. Additional benefits include improved energy efficiency and reduced environmental impact.

Approximately 30 successful subsea ESP installations have been performed worldwide to date. Each was installed on jointed tubing by Schlumberger's Reda Production Systems (RPS). An increasingly large margin of the 800 subsea completions planned or under construction worldwide (as of late September 2000) will contain ESPs.

CONCERNS ADDRESSED BY INDUSTRY

Three primary concerns historically have limited operators' selection of subsea ESP installations. However, these concerns have been addressed and alleviated by industry. A main concern was reliability, or the perception that subsea ESPs had a short run life. A second was the perception that ESPs are only for high-watercut or high-flowrate wells. A third has been the amount of gas produced through an ESP. ESPs have been limited in the amount of vapor that can be produced with liquid. Lift performance deteriorates, when gas is present in the fluid. The pump eventually becomes "gas-locked" and fails to produce lift, resulting in premature pump failure and limited or lost production.

As detailed in the following examples, each of these issues has been alleviated through application of advanced technology. The result is ESP run lives of years, instead of months, and thus increased applicability and reliability in the field. These concerns solved, plus the ability of ESPs to successfully run in deep or long-reach wells, makes them today's solution-of-choice in many situations.

RECORD ESP RUN TIME

While the oil industry cannot be faulted for believing that ESPs have short life spans--a few months' run time was the norm in the late 1980s--the run lives of some subsea ESPs today actually total years. For example, a subsea ESP installed in one South China Sea well has been running continuously for nearly four years. Other subsea ESPs have logged two to three years of operation.

All 24 wells in Amoco Orient Petroleum's Liuhua 11-1 field went onstream, using sub sea ESPs. The field is in 310 m (1,020 ft) of water in the South China Sea. Work on this installation began in 1994, when RPS and Amoco signed a performance-based agreement that was designed to eliminate early system failures and extend time between failures. Scope of work included all ESP system engineering, including power system modeling and integration testing; monitoring system development; and downhole completion design. The contractor also was responsible for providing experienced support personnel, ongoing training, and recruitment and training of personnel in line with China's nationalization program.

The field's 24 ESPs are powered from a floating production system (FPS) via dynamic, in-water power cables to each well, Fig. 1. They produce via a subsea manifold system into a subsea pipeline, to a floating production, storage and offloading (FPSO) vessel about 2.4 km (1.5 mi) from the FPS. The reservoir is carbonate, with a temperature of 135[degrees]F. Original reservoir pressure was 1,800 psig at 3,900 ft.

First oil was March 29, 1996. By July 14, 2000, the ESPs had posted a record run life, averaging 750 days per pump, with one pump running continuously for 1,384 days. Workover frequency in the field is significantly lower than initially expected, averaging about one workover annually.

DEEP WELLS WITH HIGH FLOWRATES

High-temperature, high-horsepower motors geared specifically to ESP applications have been developed to handle the requirements of deeper wells and high flowrates with less water cut. Several wells with subsea ESP installations are virtually 100% oil, requiring high-temperature motors. Standard motors are rated at 400[degrees]F (internal motor winding temperature), while specialized ones are rated up to 550[degrees]F. In addition, an advanced gas handler (AGH) has been developed that significantly increases the allowable vapor that can be produced with ESPs. The AGH can make a well more economical by increasing the drawdown and amount of oil produced.

When Norsk Hydro's Visund field comes on stream in the North Sea, it will be a system rated to 1,200 hp and 60,000 bpd of production. The high-horsepower, aquifer lift, subsea ESP system will be installed below the converted semisubmersible unit that contains workover facilities and the power control system. The surface power and control system integration testing was carried out successfully. The downhole equipment will be installed during first-quarter 2001.