Jerry Lee investigates the use of hydraulic submersible pumps as an alternative to the common ESP for artificial lift operations.
An ultra-high reliability hydraulic submersible pump. Photos from ClydeUnion Pumps - an SPX brand.
Extracting hydrocarbons from a reservoir is an energy intensive process, and when the natural drive mechanisms become uneconomic for producing a well, artificial lift systems become necessary. Submersible pumping systems are commonly chosen because these tools boost production rates by adding energy into the system. The pump translates mechanical power into fluid dynamic producing pressure and “head,” a measure of the distance that a pump can produce, to push the formation fluid to the surface, says Michael Davis, senior technical instructor at Halliburton.
Electric submersible pumps (ESPs) are widely used, however, they have been criticized for breaking down a few years after installation (see Panel). For those operators requiring artificial lift, an alternative already exists in the form of the hydraulic submersible pump (HSP).
“The HSP technology was initially developed to overcome several limitations associated with electrically powered ESPs,” says William Harden, director, consulting engineer, Oil & Gas, ClydeUnion Pumps, an SPX brand.
Much like an ESP, the HSP is a downhole pump that provides pressure to boost formation fluids to the surface. Both use a mechanism to rotate a shaft, which powers the pump stages that pressurize the fluid to assist production.
An HSP consists of a power fluid flowline, multistage hydraulic turbine, shaft, and multistage pump impellers, and at the surface, separation and filtering facilities, and power fluid pressurizing pumps are required. An ESP, however, is modularly designed, and consists of at least one motor, at least one seal or protector, a shaft, an intake or gas separator, multistage pumps and electricity cable, and at the surface a transformer, junction box, switchboard or variable speed drive.
A hydraulic submersible pump.
Operationally, the technologies are also very different. For HSPs, the flowline, which connects the surface equipment to the downhole pump set, is used to supply the pressurized power fluid to the multistaged axial flow turbine. The fluid (seawater or produced water) passes through the turbine stages, generating torque to drive the multistage pump impeller stack, and produce at an economic rate. The system can be either open or closed looped.
“In the ‘open loop’ configuration the produced fluid at pump discharge subsequently commingles with the exhausted turbine power fluid and flows up to the surface facilities where the power fluid is separated and recirculated back into the HSP power fluid supply,” Harden says.
Formation fluid commingling and exhausted power fluids can have a positive impact on flow assurance by providing viscosity and emulsion management in heavy oil applications as well as reducing flow line friction losses. Additionally, if heated power fluids are used, the increased temperature and heat capacity of the commingled fluid can prevent gelling in hydrocarbon fluids and mitigate wax deposition.
“In ‘closed loop,’ the majority of the power fluid does not commingle with the formation fluids and, therefore, requires two dedicated flowlines and concentric annuli for the independent supply and return of power fluid. In this arrangement, power fluid returns to the surface separately where it is filtered and re-pressurized by the surface pump for re-use.”
HSPs are controlled through a combination of regulating the power fluid in the flowline and managing the back pressure in the production tubing. Operational control is affected by variable speed pump drive motors on the power fluid supply pumps, which generate the pressurized drive fluid delivered to the turbine, and by fine tuning the local choke valve on the production tree to regulate flow and create back pressure.
“Optimal performance can be set through monitoring and adjustment of the volumetric ratios of the turbine and pump flows, and instrumentation systems are available for the downhole monitoring of speed, vibration and fluid pressure and temperatures, for additional visibility of well and pump performance,” Harden says. In lieu of reliance on downhole sensors or electrics, HSPs would still be operational in the event of a downhole instrumentation failure. ESPs, however, use a downhole cable to supply electricity from the surface equipment to the motor, which rotates the shaft and transmits its mechanical power to the pump. The downhole pump set is controlled either with a switch board, which has a basic start and stop function, or a variable speed drive, which can adjust the speed of the motor to change the pressure head.
As a hydraulically driven system, the HSP is not a constant speed machine. Its speed will increase as pumped fluid density decreases and will decrease as density increases. By virtue of the rotor accelerating when presented with increased gas content in the reservoir fluids, gas bubbles are less able to aggregate and reduce pumping effectiveness, but rather are maintained in a homogenous suspension. This ability to automatically react to rapid changes in fluid density greatly reduces the HSPs susceptibility to gas locking and enhances its ability to maintain continuous production, Harden says.
For ESPs, a gas separator module can be attached above the intake to deal with gassy fluids. Unlike conventional surface separators, this module actively separates gas from the fluid utilizing a centrifugal spinning force. “The formation fluid is spun within the system, pushing the oil and water against the wall of the separator and up through the tool. The gas comes together in the middle and is vented out into the wellbore,” says Raj Naicker, technical sales advisor at Halliburton.
Reliability is an important consideration, particularly in offshore environments where daily rates greatly exceed those for onshore projects. In its design, the HSP eliminates the potential failure modes associated with electric motors, cabling, glanding, penetrators, and insulators. Furthermore, the power fluid that drive the turbines serves a dual purpose by providing a positive, outward clean flush to the pump end bearing system and obviates the need for complex thrust carrying seal protector systems. The combination of these factors have resulted in a system, which has achieved a mean-time-to-failure of over 11 years, which is about three times the industry average for conventional ESPs, Harden says.
Current HSP technology is limited to fluid temperatures up to 220°C. However, thermal production operations, such as steam assisted gravity drainage, would require a system designed for temperatures up to 300°C.
The Captain field
The Chevron-operated Captain field is a heavy oil asset, 130km off Aberdeen in the UK North Sea, with some areas that are known to have a gas cap. ESPs are used at 36 platform wells at the field, while HSPs are used on 21 subsea wells.
The HSPs were selected due to the ability to handle high levels of gas reliably, which is facilitated by a multiphase helicon-axial pump stage design, enabling continued operations under slugging conditions and provides the headroom to increase production rates*.
Since installation in the early 2000s, HSPs have been operated at gas volume fractions of up to 70%, although usually in the 5-40% range. Designed using the open loop configuration, the HSPs have been producing from 1500-18,750 b/d.
With over 15 years in operation, the HSP units have achieved a mean-time-to-failure (MTTF) that is typically three times the current level for conventional electric motor driven systems; in 2010, MTTF was recorded at 11.76 years, with some units in operation for nearly 10 years. The key to maintaining uptime was the performance of the topside desanding and power water supply system.
Some failures have occurred, due to erosive wear by sand ingestion, or ingestion of debris from well completion or by tubing corrosion. However, these have subsequently been mitigated.
In defense of ESPs
As a modular system, ESPs can be individualized for each well. If the well requires multiple motors, seals, and pumps, the entire system does not need to be redesigned; the operator can simply request a system with those features. Additionally, if the reservoir begins to produce gas, the intake can be switched out for a gas separator. The system can operate in deep and deviated wells, and requires minimum maintenance. ESPs can be assembled, set downhole, turned on, and if left alone to run, it can actually run better, says Michael Davis, senior technical instructor at Halliburton. Also, for operations where there are visual and audio regulations from municipalities, the surface impact is very small, consisting of the wellhead, drive, and transformer.
However, the reliability of ESPs has been criticized. Though failures have been observed, the cause may not stem from the ESP itself. The ESP can only perform as it was designed to perform, if the criteria of the well changes, the design of the ESP must be adapted; if the ESP is forced to function in a way other than the way it was designed to, the ESP will develop problems as a result of misuse.
“If we are given all the information from the operator to size the equipment correctly and run it in the correct operating mode, the ESP can run for 10 years without any intervention,” says Raj Naicker, technical sales advisor at Halliburton.
The system must also be serviced properly on the wellhead. If shortcuts are taken or if there is pressure to run the tool, then reliability is sacrificed for rig time. “Everything goes hand in hand. Doing everything right in the front will result in a longer run life,” Naicker says.
* Mali, G. A., Morrison, A. K., Green, A., Graham, R., & Harden, W. G. (2010, January 1). Hydraulic Submersible Pumps: 10 Years Experience on a Heavy-Oil Field in the North Sea. Society of Petroleum Engineers. doi:10.2118/135234-MS