FMC Kongsberg Subsea
Multiphase pumps have been available for several decades for onshore and topside applications in the upstream petroleum industry as well as in the process industries. However, the number of field installations have been limited.
Only in the last 10 years, has there has been a significant number of developments focusing on subsea (shallow and deepwater) multiphase pumping applications. Most of these applications are still considered pilot applications in the field in order to demonstrate the technology.
Downhole pumping systems have been widely used in onshore and offshore (surface wellheads) for many years. These include electric submersible pumps (ESP), progressive cavity pumps, and water-driven multiphase pumps. With the exception of progressive cavity pumps, these downhole pumps have been applied in a limited number of applications in subsea wells at moderate water depths and offset distances. Deepwater combined with long-offset applications present unique challenges.
The benefits of this technology include the following:
- Accelerate production rate and improve field development economics
- Enable production of low-energy fields
- Allow longer subsea tiebacks by boosting the flowing wellhead pressure
- Boost remote fields to an existing or central host and eliminate the need for surface facilities in the field
- Potential reduction in total number of wells
- Reduce likelihood of liquid slugging
- Reduce or eliminate topside facilities for other competing technologies - gas lift, or water injection.
There are several methods available to enhance the flow of oil and gas in subsea production systems. The following are possible approaches:
- Gas lift (downhole, at subsea wellhead, riser base)
- Injection (gas, water, simultaneous)
- Seabed multiphase boosting
- Subsea separation and boosting (2-phase, 3-phase, 4-phase)
- Downhole separation
- Downhole booster pumps.
In a comprehensive analysis of field development approaches, all or most of the above options must be evaluated on the basis of capital and operational expense, plus impact on net present value (NPV), in addition to other considerations such as system reliability, flow assurance, and others.
Downhole pumps/subsea wells
Downhole pumps have been widely used involving low-reservoir energy. Fundamentally, the same technology could potentially be applied in subsea wells. However, industry has only applied this technology in a limited number of subsea field developments.
Two types of pump technologies are available: downhole ESPs - single phase and multiphase pumps. Downhole electrical motors can be used to drive three types of downhole pumps: (1) centrifugal and (2) progressive cavity and (3) gas well dewatering.
Downhole ESPs are basically multi-stage centrifugal pumps driven by a submersible downhole electric motor. An advantage with downhole pumps is that energy is added at a point close to the perforations where the flow conditions may be above the bubble point.
Single-phase boosting is generally more energy efficient than multiphase boosting. The centrifugal pump has several limitations: (1) solids handling and (2) gas-volume fraction at the inlet is limited to 10%. Another limitation is that pump volume capacity, size, pressure boost and power capacity is limited due to the constraints of the wellbore dimensions. At least one pump is required for each production well.
Three downhole pumps
There are at least three types of downhole pumps currently available in the industry to handle multiphase flow: progressive cavity pumps, water-driven multiphase pumps, and gas-well dewatering pumps.
Progressive cavity pumps consist of a stator and a rotor. When the two are assembled, they form a helical pocket of fluid that is displaced from the suction to the discharge. It is a positive-displacement type pump. Progressive cavity pumps generally use a surface-mounted motor, which is connected to the pump via a rotating shaft between the wellhead and the downhole pump.
Downhole water-driven multiphase pumps use a hydraulic turbine for the power section. High-pressure water is supplied from the topsides to operate the turbine motor. The pump section uses a modified axial flow impeller, designed to handle high gas-void fractions up to 90%. The discharged water from the hydraulic turbine section mixes with the produced fluid on the suction side.
The power water and produced fluids (oil, gas and produced water) are mixed together and pumped to the surface. The advantage of this pump is that it can handle high gas-void fraction downhole. The disadvantages are that: (1) one pump is needed for each well, (2) it requires water injection in the same well as the production well, (3) and a large quantity of water is produced along with the produced fluids. High water production has several disadvantages: high quantities of hydrate inhibitor consumption, corrosion, scale, high pressure drop in the flowline, and others.
In gas wells with a high water cut, the separated water downhole can be pumped and disposed into a separate zone. This approach requires a single-phase water pump. Using this method reduces water production and increases gas production to the surface. Operating costs associated with produced water handling, hydrate, corrosion and scale management can be significantly reduced.
Downhole pumping systems have been on the market for several decades and are installed worldwide. A number of these are installed on land-based wells, a smaller number on offshore dry well completions and only a few on subsea, wet completed wells. As development is ongoing, improvements are enhancing the reliability of the components.
There are several critical design issues that must be considered when evaluating the use of downhole pumps. One important issue with downhole pumps is that maintenance and servicing requires a full well intervention. Subsea well intervention requires a drilling rig or a large intervention vessel.
The subsea tree is normally a horizontal type to enable easier retrieval of the pump without retrieving the subsea christmas tree. Based on field experience in onshore and conventional platform applications, downhole electric motors are also subject to potential failure.
Failure rate and reliability of such motors must be thoroughly evaluated for any deepwater subsea applications. Use of downhole pumps in subsea production systems requires planning and capital expense investment in the early phase of the project because downhole electrical penetrations, hydraulic supply, and downhole completions must be designed and fabricated at the beginning of the project. Downhole pumping approach requires one pump per each well, which would increase the total number of pumps required in the field compared to seabed pumping systems.
Subsea pumping systems
Subsea pumps and pumping systems have been available for some years. However, the number of pump installations is limited. In addition, there are some test installations, which have accumulated a significant number of operating hours. The number of installations in actual production application is relatively limited, but some of these installations have accumulated a relatively high number of operating hours, and report a successful operation of these pumps.
One limitation that applies to all electrically driven pumps is the motor rating, which are about 2.5 MW. However, topsides motor technology is available for larger motors, which could be adopted for subsea use. Several multiphase pump options available to be considered for subsea use are as follows:
- Helico axial: This type of pump generates pressure boost by spinning the multiphase fluid at a high RPM, typically 4,000-6,000 RPM, using helico axial impellers. Helico axial pumps can handle gas volume fractions (GVF) from 0 to 95%, but the differential pressure drops towards higher GVF. The increase in fluid velocity increases the kinetic energy. The high speed fluid passes through a diffuser, which converts kinetic energy to pressure.
This process is repeated through multiple stages to generate the required head. This design was developed in the 1980s by the Poseidon project conducted by Institute Francais Petrol in a joint industry project with Total and Statoil as partners. Helico axial pumps have been installed in two subsea field applications to date.
- Twin screw: In a twin-screw pump, fluid is pumped by counter-rotating screws that enclose a constant volume of fluid. Similar to a positive displacement pump, the fluid is displaced from the suction end to the discharge end. Generally, 5 vol-% liquid is necessary to form a seal betwee clearances. These pumps operate at much lower speed than helico axial pumps, typically 1500-3000 RPM, and have a differential pressure of up to 100 bars.
- Piston: The mechanical design of these pumps are very similar to the piston pumps for other fluids, slurries, and others. This type of pump is generally tolerant to solids. These units have been applied in a limited number of onshore applications. The flow rate capacity of each pump is highly limited. While these pumps have been used in a limited number of onshore applications, they have not been applied either offshore (topsides) or subsea.
- Progressive cavity: In a progressive cavity pump, a helix-shaped rotor inside a specially shaped stator forms fluid cavities. Rotor motion causes the fluid trapped in the cavities to be displaced to the discharge end. Similar to other positive displacement type pumps, the head is generally independent of gas-void fraction. It handles sand, abrasives, and high viscosity fluids. It runs at a low RPM. The disadvantage is that it is designed for relatively low total flow rates (30,000 b/d of gas, oil, and water). The achievable differential pressure is low, approximately 500 psi. No experience exists on offshore topside facilities or subsea with progressive cavity pumps.
Based on a review of the current status of various seabed multiphase pumping technologies, there appears to be only two candidate technologies available for subsea use: twin-screw and helico axial pumps. Both of these pumps are field proven in a wide range of environments (onshore, topside, and subsea). They are also capable of pumping at high required flow rates and at the required differential pressures (depending on the field developments).
Additional benefits in a multiphase boosting/pumping scenario are as follows:
- Reduces or eliminates liquid slugging in the riser (this results in significant economic benefits by eliminating the need for large slug catchers)
- Improved flow assurance performance are higher flow rates result in higher flowing temperatures in the wellbores, flowlines, and risers
- Reduces the field life and allows the opportunity for portions of facilities to be re-used sooner for another field development (this also reduces operating costs such as personnel, consumables, and equipment maintenance)
- Eliminates the need for subsea separation and processing to achieve similar recovery.
Several types of downhole and seabed pumping solutions are available for deepwater subsea field developments. Various pump options are available today for single-phase or multiphase flow for a range of applications. The current state-of-the-art of these pumps has been reviewed.
Twin-screw and helico-axial pumps are currently the only recommended candidate technologies for seabed multiphase boosting. Each of these pumping scenarios involve several system components such as pumps, motors, controls, flow bases, flowlines, manifolds, power supply chain, and umbilicals.
A rigorous analysis of the qualification status, reliability and availability of the system and components should be made in order to optimize lifecycle performance.
Based on a generic West Africa case study, significant economic benefits can be achieved by using a subsea multiphase pumping system. If identified early in the system selection phase, the subsea pumping system can be effectively integrated with the subsea production system.