Multiphase pumping applications, also referred to as tri-phase, have been growing during the past several years, especially due to increased oil drilling activity. For example, in Canada the drilling and refining of tar sands often requires the use of multiphase pumps since the fluid stream can be a mixture of gas, liquids and solids. In addition, the economics of multiphase production is attractive to upstream operations as it leads to simpler, smaller in-field installations, reduced equipment costs and improved production rates.
Conventional methods of pumping usually involve a separator as part of the production process. A separator divides the fluid stream into liquids, gases and solids. Utilizing a separator requires pumps to handle the liquids and compressors to handle the gas. Multiphase pumps are typically utilized when a separator is not part of the process flow. In essence, the multiphase pump can accommodate all fluid stream properties with one piece of equipment, which has a smaller footprint. Often, two smaller multiphase pumps are installed in series rather than having just one massive pump.
For midstream and upstream operations, multiphase pumps can be located onshore or offshore and can be connected to single or multiple wellheads. Basically, multiphase pumps are used to transport the untreated flow stream produced from oil wells to downstream processes or gathering facilities. This means that the pump may handle a flow stream (well stream) from 100 percent gas to 100 percent liquid and every imaginable combination in between. The flow stream can also contain abrasives such as sand and dirt. Multiphase pumps are designed to operate under changing/fluctuating process conditions.
Multiphase pumping also helps eliminate emissions of greenhouse gases as operators strive to minimize the flaring of gas and the venting of tanks where possible.
Typical Services for Multiphase Pumps
- Untreated fluid- As an alternative to separating the gas from the liquids, treating the various phases and then compressing and pumping the various phases, multiphase pumps can handle an untreated fluidstream. A high volume of gas mixed with oil, water and solids is common.
- Flow rate optimization- Regardless of the system pressure, multiphase pumps deliver a constant flow at a given speed. Operators can change the pump speed and optimize the flow rate and inlet pressure.
- Wellhead pressure- As reservoirs mature and their natural pressure declines, multiphase pumps are used to boost the flow line pressure.
Typical Upstream Applications
- Increase production and reduce backpressure at wellhead
- Pump liquid and gas mixtures up to 100 percent GVF (Gas Volume Fraction)
- Eliminate flaring and venting at reduced costs
- Reduced installed cost versus traditional systems
Typical Downstream Applications
- Highly gaseous liquid streams
- Flare knock-out drums
- Pumps with a history of cavitation problems from excess gas
Types and Features of Multiphase Pumps
There are many types of multiphase pumps. The more popular ones are described below:
Helico-Axial Pumps (Centrifugal)
A rotodynamic pump with one single shaft requiring two mechanical seals. This pump utilizes an open-type axial impeller. This pump type is often referred to as a "Poseidon Pump" and can be described as a cross between an axial compressor and a centrifugal pump.
Twin Screw (Positive Displacement)
Twin screw pumps have gained popularity in both upstream and midstream (pipeline) operations. The twin screw pump is constructed of two intermeshing screws that force the movement of the pumped fluid. Twin screw pumps are often used when pumping conditions contain high gas volume fractions and fluctuating inlet conditions. Four mechanical seals are required to seal the two shafts.
Progressive Cavity Pumps (Positive Displacement)
Progressive cavity pumps are single-screw types typically used in shallow wells or at the surface. This pump is mainly used on surface applications where the pumped fluid may contain a considerable amount of solids such as sand and dirt.
Electric Submersible Pumps (Centrifugal)
These pumps are basically multistage centrifugal pumps and are widely used in oil well applications as a method for artificial lift. These pumps are usually specified when the pumped fluid is mainly liquid.
Buffer Tank
A buffer tank is often installed upstream of the pump suction nozzle in case of a slug flow. The buffer tank breaks the energy of the liquid slug, smoothes any fluctuations in the incoming flow and acts as a sand trap.
The Mechanical Seal Challenge
As the name indicates, multiphase pumps and their mechanical seals can encounter a large variation in service conditions such as changing process fluid composition, temperature variations, high and low operating pressures and exposure to abrasive/erosive media.
The challenge is selecting the appropriate mechanical seal arrangement and support system to ensure maximized seal life and its overall effectiveness.
Sealing Considerations
Be sure to review process fluid criteria, pressure and temperature combinations in all possible eventualities. This is especially true in upstream (wellhead) operations as actual operational criteria such as pressure and flow rates are often different than the predicted values. In addition, these values tend to change over time.
Important Application Criteria
- Particulate-measured in percentage
- Viscosity
- Gas composition
- Temperature
- Gas Volume (Void) Fraction (GVF) at suction conditions-measured in percentage (GVF value of 0 = 100 percent liquid and a GVF value of 1 = 100 percent gas)
- Maximum particle size and distribution
- Suction pressure
- Discharge pressure
- Seal chamber pressure
- Potential for slug flow, gas locks and pressure surges
Operating Parameters
When selecting a seal for multiphase applications, the selection cannot be made on one defined operating point since conditions can vary and also change over time, particularly in a wellhead. The seal needs to be capable of facing different operating parameters. Upstream fluids are typically a mixture of oil and gas, sour water and solids.
Dry-running conditions
A pressurized barrier system (Plans 53A, B, C or 54) is required to ensure that the sealing faces remain lubricated as dry-running conditions are often encountered.
The most common mode of mechanical seal failure is loss of lubricating film between the seal faces. Typically, when the pumped fluid is a poor lubricant, enters a vapor phase or flashes, a dual seal using a pressurized barrier fluid of good lubricating
