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 properties is recommended. This ensures that the primary seal rings are operating in an adequately lubricated environment.
Corrosion and Erosion
The chemical composition of the process fluid can vary depending on the oil field and its location. Depending on the source, crude oil can contain water, salt, sour gas, carbon dioxide, wax, solids and cracked hydrocarbons.
Corrosion-Often, the effluent in a multiphase pumping environment contains hydrogen sulphides with water and chlorides, sometimes combined with high temperature. All wetted parts need to be constructed from a suitable alloy to resist this corrosion. In addition, as temperature increases, corrosion rates are accelerated. This is especially important to consider with sour crude oils pumped at temperatures greater than 450-deg F (230-deg C) as seal metallurgy may be subject to naphthenic and sulfidic corrosion.
Erosion-Sand and dirt is often entrained by the effluent. Hard faces need to be selected when abrasives are present in the pumped fluid.
Cavitation
Excessive cavitation can affect seal performance of all seal types. Cavitation in the pump is usually a good indicator that vaporization could be occurring at the seal interface, which can lead to episodic dry running. A multiple seal arrangement with its controlled environment will help provide cooling and lubrication for the mechanical seal during those periods. Cavitation, in general, usually indicates that there may be a vapor pressure issue that needs to be addressed.
Slip-Stick
Slip-stick can occur from poor lubrication, vibration, imbalanced impeller, wrong face load, flush pulses, pipe strain or coupling misalignment. Slip-stick is a function phenomenon which can be described as a jerky motion that sometimes results when one surface is dragged against another. Normally it is associated with non-lubricated or boundary lubricated seal types.
To avoid slip-stick phenomena, look at flashing and viscosity. If the vapor pressure is not above atmospheric and the viscosity is above 0.4 cp, then the likelihood of slip-stick is very low.
For a dual pressurized seal, the barrier fluid-not the process fluid-is the criteria. The typical cure for slip-stick is providing a good lubricating environment to the seal faces, which is enhanced with the selection of a dual seal arrangement.
Solids in Suspension
Because the fluid streams in multiphase pumping operations often contain solids in suspension, a rotating inner seal head (flexible element) should be selected. The pumped product remains at the OD (outside diameter) of the seal, allowing the centrifugal action to spin off any particles and keeping the seal head assembly clean and flexible. Particulate concentrations can be as high as 0.5 percent.
Temperature
Although most multiphase applications are below 300-deg F (150-deg C), the fluid stream can sometimes reach higher temperatures. When higher temperatures are encountered, an API 682 TYPE C seal should be selected. Higher temperatures can also impact the corrosiveness of the pumped fluid, so care should be taken to select the proper metallurgy for the mechanical seal.
Pump Shaft Speeds
Multiphase pumps are often equipped with variable frequency drives with shaft speeds adjusted as operators strive to maximize production. For example, an 1,800-rpm pump may run as low as 600-rpm depending on the requirements for production optimization. Screw pumps often operate in the range of 300- to 3,600-rpm, and helicoaxial pumps operate in the range of 1,800- to 6,000-rpm.
Seals equipped with rotating flexible elements (pending application review) are typically designed for speeds not to exceed 5,000-ft/min (25.4-m/s). Seal recommendations should be reviewed by the seal manufacturer for speeds exceeding 5,000-ft/min. A stationary seal design can be considered for speeds up to 10,000-ft/min (50.8-m/s).
Sealing Selection
Dual API 682 Seal Arrangements
The most common and most specified seal selection for multiphase pumping applications is the Category II and Category III Arrangement 3 contacting wet seals. Arrangement 3 seals are dual cartridge mechanical seals with a pressurized barrier fluid, which ensures that the lubricating barrier fluid is present in the primary seal interface. Dual seals are also used when the pumped fluid can be hazardous, as the well streams may contain H2S and CO2.
Per API 682/ISO 21049, these seals are inside mounted cartridge seals with two rotating flexible elements and two mating rings in series. The inner seal incorporates an internal (reverse) balance feature designed and constructed to withstand reverse pressure differentials without opening. The seal can be either a Type A, B or C seal.
Low Temperature Applications
Low temperature applications are typically defined to 350-deg F (175-deg C) although many O-ring seals are capable of handling temperatures to 500-deg F (260-deg C) depending on the type of elastomer selected as the secondary seal. Type A, Arrangement 3 Dual Pusher Seals consist of a multiple spring flexible element and O-ring secondary seals. The inner seal is double-balanced to provide a positive seal with pressure from either direction.
The process is maintained at the OD of the inner seal head and the barrier fluid is maintained at the inside diameter, in which any leakage that occurs is normally from barrier to process. Since the process is at the OD of the inner seal, contaminants are centrifuged and have less effect on the inner seal.
High Temperature Applications
For high temperature applications, an API 682, Type C, Arrangement 3 seal can be selected. This seal is a dual-pressurized rotating welded metal bellows cartridge seal using flexible graphite secondary seals. This seal is used in conjunction with API flush plan 53 or 54. Since multiphase pumping applications may have varying pressures, be sure to review the pressure handling capability of the bellows seal in accordance with the maximum pressure of the application.
API 682 specification designs inherently accommodate reverse pressure and will contain the process pressure in the event of a loss of barrier pressure. A pumping ring circulates the barrier fluid.
Recommended Piping Plans for Dual Seals with Pressurized Barriers
Plan 53A
This piping plan uses an external reservoir to provide barrier fluid for a pressurized dual seal arrangement. Reservoir pressure is produced by a gas, usually nitrogen, at a pressure greater than the maximum process pressure being sealed. The barrier fluid lubricates the inner and outer seals. During normal operation, an internal pumping ring maintains circulation. The inner seal of a dual pressurized arrangement can have its own flush plan such as 32/53A; however, the need for a separate flush on the inner seal varies with the seal type and physical orientation.
If using a Plan 32 in conjunction with a Plan 53, a close-clearance throat bushing is often installed in the bottom of the seal chamber to help isolate the pumped product from the seal chamber and to minimize the amount of flush fluid required. Compatibility with the pumped product must be considered when selecting a flush fluid. 
Barrier pressure should be maintained during both dynamic and static pump operation.
It is not recommended to use a gas blanket above 200-psig (13.7-bar g) since gas may be absorbed into the barrier fluid. As pressure is relieved or temperatures cool, gas may be released from the fluid and foaming occurs. The result is loss of lubrication, heat transfer and circulation. A Plan 53B, 53C or 54 could be used.
Barrier Fluids
An appropriate barrier fluid must be selected. Barrier fluids are mainly used as a safety barrier between the process and the atmosphere and must not create a hazard in the event of leakage. In multiphase pumping, lubricating properties of the barrier fluid are of key importance. The better the lubricating properties of the barrier fluid, the better the expected performance from the seal.
Plan 54
Plan 54 uses an external source to provide a clean, pressurized barrier fluid to a dual pressurized (double) seal. The Plan 54 system supplying the barrier fluid can range from a process pump in the unit providing clean, cool lubricant under pressure, to a simple lubrication system with minimal components, to an elaborate large system with many ancillary components and redundant systems to safeguard and alarm against malfunctions and process upsets, to a controlled process stream.
Single Seal Arrangement
The Type A, Arrangement 1 single cartridge seal can be used on multiphase applications. These seals typically require a Plan 32 flush plan to help keep the rotating flexible element and the seal faces free of debris. The clean fluid flush also helps to maintain face lubrication. Hard faces are recommended. The seals can also come equipped with a distributed flush feature and segmented, floating or fixed non-sparking carbon bushings.
Depending on the characteristics of the pumped fluid, a Plan 11 or Plan 13 can be used to lubricate the seal and remove any heat generated. These plans are often used when an external flush is not available.
Special features have also been utilized in single seal arrangements to help accommodate episodic dry-running and misalignment issues, usually in applications up to 70 percent GVP.
These features include:
- Stationary springs to minimize fatigue under high misalignment
- Substantial clearances to cater for misalignment
- Large cross-section o-ring secondary seal on rotating assembly to permit self alignment and to absorb the effect of shaft deflections
- Top-polished (surface textured) SiC/SiC or SiC/Hard carbon face materials
- Eccentric screwed stator and fluid retention reservoir for enhanced dry-running
- Self-cleaning sand expeller
Plan 32
Plan 32 involves the use of a flush stream brought in from an external source to the seal. The plan is almost always used in conjunction with a close-clearance throat bushing. Plan 32 is used when a process stream is difficult to condition in a way that will provide adequate cooling and lubrication to the mechanical seal.
Conclusion
Mechanical seals have met the many challenges in sealing multiphase pumping applications. Selecting the proper seal arrangement and supporting flush plan can help ensure the optimum performance from a mechanical seal, improve operating efficiencies and reduce maintenance costs. Keeping the seal faces clean, cool and lubricated can greatly enhance the performance from a properly specified mechanical seal.
Specifying a dual seal arrangement with a pressurized barrier helps to create a seal-friendly environment surrounding the seal and helps overcome the complications of moving a process stream that can transition from all liquid to all gas and every combination in between.
References
1. Buck, G., Fordyce, J., McManus, R., "Technical Report Mechanical Seals for High-Temperature Services", John Crane Inc. May 2006.
2. Buck, G., Fordyce, J., McManus, R., "API 682\ISO 21049 Seals for High-Temperature Services", John Crane Inc. May 2006.
3. de Salis, J., de Marolles, Ch., Falcimaigne, Durando, P.: "Multiphase Pumping - Operation & Control" paper SPE 36591 presented at the 1996 SPE Annual Technical Conference and Exhibition, Oct. 6-9, 1-6.
4. Evans, J., Janssen, S., "Developments in Sealing Technology Within Multiphase Pumps" presented at the 19th International Pump Users Symposium. February 25-28, 2002.
5. Heyl, R.: "Multiphase Pumping" tutorial presented at the 2007 Twenty-Third International Pump Users Symposium, March 5-7, slides 1 - 61.
6. "Pumps - Shaft Sealing Systems for Centrifugal and Rotary Pumps," ANSI/API Standard 682, Third Edition.
7. Scott, S., "Multiphase Pumping Addresses a Wide Rang of Operating Problems" Oil & Gas Journal, September 29, 2003.
8. Scott, S., Shippen, M. "Multiphase Pumping as an Alternative to Conventional Separation, Pumping and Compression" prepared for presentation at the 34th Annual PSIG meeting. October 25, 2002.