Historically, electrical submersible pumping (ESP) systems were not considered the optimum artificial lift option for the Gulf of Mexico. However, in recent years the reservoir characteristics of maturing shelf fields, market forces and technology advancements have changed that attitude. Today, ESP systems are increasingly important for extending the life of these fields and capturing additional reserves.

Crew members prepare an electric submersible pump for deployment in the Gulf of Mexico. (Photo courtesy of Centrilift)
The most prevalent form of artificial lift in the Gulf of Mexico is gas lift, which is a fairly simple process, making it relatively fast to install and economic. Also, years ago, completions did not include the level of sand control available today, and gas lift systems are not as adversely impacted by sand or solids in the fluid.

Gas lift
Plus, in the past, gas lift was preferred since a field’s natural gas production could be used in the system. For years gas production was plentiful and not worth a great deal in the market, even if there was a gas pipeline available, so using the gas to lift more oil from the reservoirs was an overall good option. Gas lift basically involves injecting gas down the annulus of the tubing to lighten the fluid column, allowing fluid to flow to the surface.

But that was then, and this is now. Many of the Gulf of Mexico shelf fields have matured to the point that producing enough natural gas to fuel the platform facilities as well as inject for artificial lift is a serious concern. Even if a field is generating significant gas production today, natural gas prices have increased, making it a valuable commodity to offshore operators, and a pipeline infrastructure has built up on the shelf to deliver the gas to market.

Reservoir conditions in these maturing fields are increasingly becoming the most significant stumbling block to continued gas lift. As fields mature, the bottomhole pressure declines, and under these conditions gas lift systems hold pressure against the sand face, which raises the abandonment pressure significantly above the abandonment pressures possible with ESP technology. Bottomhole abandonment pressure in many gas lift cases is 750 to 1,000 psi, which can leave a significant amount of recoverable oil in the reservoir.

Electric submersible pumps
In the past, conventional wisdom held that ESP systems were not reliable enough to make the technology cost-effective when the higher offshore intervention costs were factored into the overall economics. However, in the past 10 years, dramatic advancements in ESP technology have boosted the reliability of these systems to a level that competes with any form of artificial lift. These advances in run life, coupled with the increased production possible with ESP systems, make this an attractive artificial lift alternative in the Gulf of Mexico today.

One of the major advancements in ESP technology has been in the area of gas handling capabilities.

Multiphase fluids are the norm in the Gulf of Mexico, and Centrilift has made major advancements in the arena of gas handling that allow wells with standard ESP systems to operate with up to 45% free gas at the pump intake with separation efficiency up to 90% with the newest generation of the company’s GM gas separator. The handling company also has developed a gas pump stage that significantly increases the amount of gas that can be produced through the pump. The special design prevents gas from accumulating in the pump, which can cause gas locking of the system.

Abrasives and solids were historically a reliability issue with ESP systems, but pump technology — like the newest pump line that offers special abrasion-resistant designs and proprietary coatings to enhance the life of the systems — has overcome these issues. The new pump designs also have wider vane openings to more effectively handle solids in the fluid.

Historically, offshore operators erroneously thought electrical issues with ESP systems were a cause of short runs. While that may be true onshore due to lightning strikes and other issues with the overhead distribution lines, it is not the case offshore where power is provided by a contained power system (generator or rig power). Most offshore applications include a variable speed drive (VSD) surface system to control the downhole equipment. A VSD allows the operator to adjust the speed of the downhole motor to changing well conditions, keeping the ESP system operating at the best efficiency point.

Production climbed sharply when an operator switched out an old gas lift operation for an electric submersible pump in a Gulf of Mexico field. (Graph courtesy of Centrilift)
Monitoring and automation technology for ESP systems has also increased the reliability of ESP systems. The service company’s downhole sensor is highly reliable and provides pressure and temperature readings, allowing operators to monitor the condition of the downhole system. For applications requiring additional readings, the higher end sensor monitors vibration readings and additional temperature and pressure parameters as well as a suite of exclusive surface diagnostic capabilities.

Monitors
The remote data acquisition device can deliver data from downhole sensors and the VSD on wells with no monitoring system in place or enhance data recovery from wells with existing SCADA systems. espVision takes monitoring and automation a step further, providing Web-based monitoring in wells with or without a SCADA system.

In addition to these specialty technologies, the basic motor, seal and pump ESP technology has advanced to provide much higher reliability. Special metallurgies and advanced elastomers have been particularly important in increasing system run life, as have epoxy encapsulation and proprietary winding techniques incorporated into the submersible motor design.

While not every well in the Gulf of Mexico will support an ESP system, a growing number of operators are recognizing that with longer run life and the significant production increases experienced with state-of-the-art ESP systems, the economics can be extremely attractive. The first ESP system was installed in the Gulf in 1984, and since that time a total of 89 wells have used ESP technology. Today there are 34 known active ESPs operating in the Gulf. The average run life of the company’s ESPs in the Gulf is more than 3 years, and the longest run is over 6 years.

Gas lift replacement
A well in a 30-year-old field was nearing the end of its life with a gas lift system, producing an average of just 11 b/d of oil and virtually no gas. The well was recompleted with a new frac pack, and an ESP system was installed. Initial production increased from 11 to 400 b/d of oil and 6 months later settled out at 300 b/d. Natural gas production also climbed from negligible amounts to over 300 Mcf/d. The dramatic production increase made ESP technology extremely economic in this well, with the ESP system paying out in 23 days at $40/bbl of oil.

Another older well in the Gulf was nearing gas lift abandonment pressure limits, but reservoir and production engineers identified three key areas where an ESP solution could potentially benefit the well: further reducing the bottomhole pressure, gas handling capabilities and extended run life. An ESP system with a special recirculation unit and enhanced gas handling was installed in the well. A VSD was used to allow adjustments to the bottomhole pressure level and to keep the ESP system operating at optimum efficiency. The ESP solution increased production 75% from about 210 b/d of oil to approximately 375 b/d, while gas production increased 156%. At US $40/bb of oil the ESP system paid out in just over 3 months. The ESP system was able to reduce the abandonment pressure from about 600 psi to 100 psi, capturing significant additional reserves.

New well case history
Recently the manufacturer installed an ESP system in a newly drilled well in a Gulf of Mexico shelf field that that illustrates some of the advantages of ESP technology. The compartmentalized field was originally held by a major oil company that chose not to exploit additional pockets of reserves and sold the property to a large independent operator. ESP technology was chosen because this field did not have enough gas production to support gas lift and with anticipated production of 1,500 b/d, the high volume capabilities of ESPs were necessary.

The well bore was designed for an ESP installation at 11,300 ft (3,446 m) vertical depth. The ESP system included a special abrasion-resistant pump design and a gas separator to handle the anticipated increase in the gas-to-oil ratio over time. The well came on stream with initial production of just over 1,500 b/d of oil and almost 200 b/d of water with more than 300 Mcf/d of gas. The ESP system was sized to handle both the current and future fluid volumes and the anticipated increase in gas production.

The ESP system was holding oil production at more than 1,400 b/d while water production had increased by almost 200 b/d.