OFFSHORE ARTIFICIAL LIFT

Subsea ESPs gain acceptance via advancing technology

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

Graham Anderson, Technical Manager; Grant Harris, Project Manager; and John Pursell, Deployment Systems; Reda Production Systems

ubsea 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 subsea 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°F. Original reservoir pressure was 1,800 psig at 3,900 ft.

Fig. 1. At the Liuhua 11-1 field offshore China, 24 subsea wells incorporate ESPs that are powered from a floating production system in 1,020 ft of water.

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°F (internal motor winding temperature), while specialized ones are rated up to 550°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.

Scope of responsibility includes electrical simulation modeling and testing, system integration testing, and design and management of the ESP power and control system, including an onshore support station.

Long Distance Step-Outs

The efficiency of an ESP system is not adversely affected by distance from the well to the host platform, like other forms of artificial lift. One subsea ESP installation is approximately 15 km (9 mi) from the host platform and has produced at sustained rates of nearly 19,000 bopd, continually, for 18 months. Tests have determined the feasibility of ESPs in subsea wells as far away from the host platform as 20 km (12 mi) or greater.

The world’s longest subsea tie-back of an ESP was installed in the North Sea at Shell’s Gannet field, where the Gannet E Phase I single-well, subsea ESP development began flowing in January 1998, Fig. 2. In addition to being the longest ESP step-out at 14.75 km (9.2 mi), it was also the North Sea’s first subsea ESP application. Production is tied into the Gannet Alpha platform in the Central North Sea.

Fig. 2. A perfect example of the increasing use of ESPs in remote step-out wells is Shell’s Gannet field in the UK North Sea, site of the world’s longest, subsea ESP tie-back.

Scope of work included system design and supply; electrical simulation modeling; system integration testing; design of the ESP monitoring and control system, including specification of the seabed power cable; development of an onshore data monitoring support station; and ongoing management of system operations.

Shell set a stretch target of two years’ run life for the first pump as the basis for design development and testing. Shell sanctioned the project on the basis of two workovers during the first year and flowrates of 14,000 bopd. While the pump did not achieve the two-year run life, it exceeded expected production rates – the installation ran continually for 18 months at 19,000 bopd.

Subsea ESP installation at Gannet E Phase II is underway and will involve one additional subsea ESP that is similar to the first installation. Scope of work for Phase II includes design and construction of a variable speed drive (VSD) module with HVAC, fire and gas, and power to the VSD. Additionally, the ESP management system (EMS) was upgraded to include the second well. An operational philosophy was developed to accommodate interaction of the two systems, with co-mingled flow into a single 14.7-km (9.1-mi) flowline to the platform. The lessons learned from Phase I were taken into account at appropriate times during the project.

Installation and commissioning of the VSD module took place during the first week of November 2000. Installation of the subsea ESP completion occurred at year’s end – start-up was soon thereafter.

ESP Power Considerations

Subsea ESPs were not feasible until technological advancements were made in wet, mateable electrical connections (WMEC) that can be used on the seafloor. The standard, surface-type, wellhead penetrator system was modified to allow final coupling in a subsea environment. The connector alleviates the requirement to complete a dry electrical connection at the surface, eliminating topside considerations.

The wellhead penetrator safely transmits electrical power from the surface cable through the tubing hanger, to the main cable below the hanger. The WMEC is made up under water without flushing the connections. The same design philosophy was used for several years, but significant redesign was necessary to meet space requirements. A new deployment method through the tubing hanger also was created.

A further, related development was the in-water power cable (IWPC). In the case of Liuhua field offshore China, dynamic power cables are suspended from the floating production system and tied into the subsea wellheads through the WMEC in the tubing hanger. There was limited use of this type of cable until the Liuhua development, which is in waters about 305 m (1,000 ft) deep.

Power system considerations are critical in subsea ESP installations, as workovers are more costly than those incurred in traditional applications. Thus, subsea power systems must be optimized to enhance their run lives. Several subsea ESP completions have pushed electrical parameters with regard to length of step-out and motor size, such as the Gannet E step-out of 15 km (9.3 mi) and the use of a 1,200-hp motor in Visund field. Cables and power systems have been tested for step-outs as great as 20 km (12.4 mi).

A main consideration in subsea ESP installations has been the harmonics produced by variable speed drives (VSD) to control production rates. Various types of VSDs have been tested and modeled, including a medium-voltage system to reduce harmonics and negate problems associated with a voltage drop across long power cable runs. As a result, all possible harmonic problems can be predicted and eliminated when using VSDs, preventing detrimental effects on the ESP system.

A downhole monitoring tool (DMT) permits remote monitoring of the pumping system and reservoir. The DMT consists of a downhole sensor and a surface interface unit (SIU). Data is digitally transferred to the surface via the motor power cable, requiring no separate transmission wires. Data can be transferred to a PC or outputted to a SCADA system. An ESP management system can monitor both the DMT and the VSD data while controlling the VSD. Alarms and trips can be programed into the management system to protect the ESP installation.

A Maturing ESP Industry

The ESP industry has evolved dramatically in a relatively short time. It has been only about six years since the first subsea ESP was installed, in a Petrobrás well offshore Brazil in 1994.

RPS signed a production technology agreement with Petrobrás that year, providing technical support as a total system consultant for the world’s first subsea ESP system. The project goal was to develop and install a subsea ESP that could be run and be retrieved via a floating drilling rig. System engineering, procedures development, and factory acceptance and integration tests were provided, as well as ESP engineering and onsite support for installation, commissioning, startup and early system operation.

The ESP was installed in a moderately difficult environment. Operationally, there were many starts and stops, due to production and platform trips. Reservoir temperature was 212°F, but no sand or corrosive agents were present. This subsea ESP began operating on Oct. 10, 1994, and was operable for nearly three years. It was pulled in 1997 after an operational error caused a wellhead valve to be closed. Petrobrás regarded the installation a technical and economic success. Payback was achieved within months of startup.

Petrobrás has continued to move ahead with ESP development. The world’s first deepwater subsea ESP was installed for the company in its RJS-477 well, in about 3,637 ft of water in 1998. The well was a 6.5-km (4.0-mi) step-out from the Albacora L’este reservoir, which has viscous oil between 15° and 20°API. Pertrobrás found ESPs to be the most effective method of optimizing production from the well. The well was connected back to the P-25 floating production platform moored in the main Albacora field.

The system includes a subsea transformer located close to the spool tree. The transformer is designed to allow high-voltage transmission over the step-out distance of 7 km (4.3 mi), with a reduction in the required voltage to the ESP motor at the wellhead. Petrobrás celebrated the two-year operational anniversary of the well in July 2000.

Potential Subsea Completion Activity

It is estimated that as many as 25% of the 769 subsea completions planned during the next five years could have ESPs (see table). That would equal 190 subsea ESP installations during that period, or six times the number currently in use. Reservoir pressure, flow characteristics and the remoteness of upcoming wells will ultimately determine if subsea ESPs are selected. However, from an economic standpoint, subsea ESPs are essentially the only efficient means of sustaining production rates in fields with declining reservoir pressures.

Many wells will have ESPs installed at the outset, as operators require a rapid return on investment via increased production. The success of the pumping system will have major implications for the development of stranded reserves offshore. Many opportunities exist for subsea operation, including subsea transfer pumping, power networks and subsea processing. All will require pumps, monitoring and control systems, and electrical power transmission.

Satellite wells located far from the host facility will require extra pumping pressure to produce to the satellite facility. As the technology evolves, step-out wells will be placed farther away from the host platform, making small, marginal and remote fields more economical to produce. The longest step-out well is about 15 km (9.3 mi) currently, but surface testing has been conducted successfully at distances of 20 km (12.4 mi).

While the practical distance limit is yet unknown, modeling indicates that ESPs could be installed in wells as far as 40 km (24.8 mi) away from the host facility. Indeed, some installations are already planned for this distance. Power distribution systems are a main obstacle presently to long-distance step-outs, but this technology is evolving, as well.