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Multiphase Pumping as an Alternative to Conventional Separation, Pumping and Compression

Mack Shippen, Schlumberger - Baker Jardine Dr. Stuart Scott, Texas A&M University

Prepared for Presentation at the 34th Annual PSIG meeting

Portland, Oregon

October 25, 2002

Abstract This study explores the application of multiphase pumps as an alternative to conventional separation using rigorous steady-state simulation models incorporating a newly developed multiphase pumping model. The simulation results show that multiphase pumps are advantageous in not only reducing facilities, but can also increase production rates by lowering the backpressure on wells. Additionally, the complexities associated with multiphase flow through a single pipeline are compared to running dual single-phase pipelines and important considerations observed with the steady-state simulation are highlighted.

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1.0 Introduction Following it’s emergence from research labs a decade ago, multiphase pumping has become a viable solution to a wide number of field development plans. While the technology is seen to be particularly beneficial in remote locations such as the deepwater Gulf of Mexico, pumps have also been deployed to a number of onshore locations ranging from Alaskan North Slope to Columbia and from West Africa to the Middle East.

Multiphase production systems require the transportation of a mixture of oil, water and gas, often for many miles from the producing well to a distant processing facility. This represents a significant departure from conventional production operations in which fluids are separated before being pumped and compressed through separate pipelines. By eliminating this equipment, the cost of a multiphase pumping facility is about 70% that of a conventional facility (Dal Porto, 1996) and significantly more savings can be realized if the need for an offshore structure is eliminated altogether. However, multiphase pumps do operate less efficiently (30-50%, depending on Gas volume fraction and other factors) than conventional pumps (60-70%) and compressors (70-90%). Still, a number of advantages in using multiphase pumps can be realized, including: 1) Increased production through lowering backpressure on wells; 2) elimination of vapor recovery systems; 3) reduced permitting needs; 4) reduction in capital equipment costs; and, 5) reduction in “footprint” of operations. Interest in the subsea deployment of multiphase pumps has grown as operators search for methods to improve recoveries and economics for subsea completed wells. While subsea completed wells enable development of deepwater resources as well as marginal fields in normal water depths, without some form of subsea processing, these wells are expected to experience poor ultimate recoveries due to the high backpressures. For example, conventional production operations routinely drawdown wellhead pressures to 100-200 psig. A subsea completed well, however, may have abandonment wellhead pressures of 1,000-2,000 psig due to the backpressure added by the long multiphase flowline. In addition, operating as such a continual high backpressure has been shown to have a direct impact on production decline behavior, acting to reduce ultimate recovery (Martin & Scott, 2002). Maintaining a high backpressure can be viewed as a production practice that wastes reservoir energy. Energy that could be used to move reservoir fluids to the wellbore and out of the well is instead lost to flow through a choke or a long flowline. It is anticipated that some form of subsea boosting and/or processing of produced fluids will be necessary to improve efficiencies, allowing longer production from these wells and better recovery factors. Subsea processing covers a wide spectrum of subsea separation and boosting scenarios. Subsea multiphase pumping technology is perhaps a decade ahead of subsea separation and provides many advantages in terms of intervention when compared with wellbore artificial lift methods. Multiphase pumping is a relatively new technology and acceptance has been hampered by a lack of engineering design tools. Recently, pipeline simulation codes have incorporated the ability to model multiphase pump performance as part of the overall multiphase production system. This paper illustrates the use of such a model to evaluate the benefits of subsea multiphase pumping.

2.0 Multiphase Pumping Technologies Over the past decade, several multiphase pump technologies have emerged for gas-liquid multiphase flow in the petroleum industry. As shown in Figure 1, these methods fall into the broad categories of the positive displacement and rotodynamic pumps. Figure 2 shows that the number of multiphase pump installations has increased rapidly over the past 5-7 years (Scott, 2002). This figure also shows the breakdown between the different multiphase pump technologies. It should be noted that while the helico-axial technology only represents a small number of the total multiphase pump installations, they are used in the majority of offshore and subsea applications and have the capacity to pump much large volumes of fluids than the positive displacement technologies.

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Figure 1: Types of Multiphase Pumps

Figure 2: Worldwide Usage of Multiphase Pumps (MPUR Survey, Scott, 2002)

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A good summary of the development of multiphase pumping technology is given by Cooper et al (1996) and Scott & Martin (2001). Recently, a transient model has been proposed to describe the behavior of a rotodynamic pump (Ramberg and Bakken, 1997). Ideas on modeling the twin-screw pump have been presented by Vetter & Wincek (1993) and Egashira et al. (1996) and these pumps have been successfully incorporated into field use (Oxley & Shoup, 1994; Jaggernauth et al., 1996; Caetano et al., 1997; Guevara, 1999; and Giuggioli et al., 1999)). The following sections discuss the most commonly used types of multiphase pumps.

2.2 Positive Displacement Pumps Positive displacement pumps operate on the principal that a definite amount of fluid is transferred through the pump based on the volume created by the pumping chamber and the speed at which this volume is moved. The amount of differential pressure that develops in the pump is a function of the resistance to flow downstream of the pump - that is, the pressure losses that must be overcome to deliver the fluid to a set pressure downstream of the pump. For any positive (or near positive) displacement pump, the interaction between the pump and the adjacent pipeline segments determines pump performance. 2.2.1 Twin-Screw Pumps The twin-screw is by far the most popular multiphase pump in use and is manufactured by Bornemann, Flowserve and Nuovo Pignone. Twin-screws are particularly adept at handling high Gas Volume Fractions (GVF) and fluctuating inlet conditions. These pumps remain functional even at GVF’s of 95% and with re-circulation systems can function at 100% GVF for short periods of time.

Figure 3 gives a schematic of a twin-screw pump. The multiphase mixture enters one end of the pump and split into two flow streams that feed into inlets situated on opposite sides of the pump – a design that equalizes stresses associated with slugging. Flow then passes through a chamber (created by the interlocking screws) that moves along the length of the screws to the outlet. The volumetric flow rate is dependent on the pitch and diameter of the screws and the rotational speed. As the gas is compressed, a small amount of liquid will slip back through the small gaps between the screws and the containment chamber wall resulting in a reduced volumetric efficiency.

Figure 3: Twin-Screw Pump (after Bornemann)

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2.2.2 Progressing Cavity Pumps (Single-Screw) Widely used in shallow wells as an artificial lift method, the Progressing Cavity Pump (or Moyno pump) has been adapted for surface multiphase pumping. Note that the number of PCP pumps listed in Figure 2 represents only the surface installations of this technology. The PCP pump is comprised of a rubber stator and a rotating metal rotor (Fig. 4). This pump is effective for low flow rates (less than 30,000 bbl/day total volume of gas, oil and water) and for lower discharge pressures (maximum of 400 psig). This pump has the unique ability to tolerate considerable amounts of solids (sand). However, high sand production rates result in the need to replace the stator on a regular basis.

2.2.3 Piston Pumps One of the simplest forms of multiphase pumping is the use of a large double-acting piston to compress the multiphase oil, water and gas mixture. This approach is effective in the low and moderate flow rate ranges with a maximum capacity of approximately 110,000 bbl/day (total volume of gas, oil and water) and maximum discharge pressure of approximately 1,400 psig. The first type of piston pump, the “Mass Transfer Pump”, was installed June 1998 by National Oil Well in Canada. As shown in Figure 5, this pump makes use of the same gear box and prime mover that is utilized in conventional sucker rod pumping units. Also, the pumping chamber functions much like a downhole sucker rod pump. It is comprised of two check valve assemblies which operate is the same fashion as the standing valve and traveling valve in a downhole pump. There are currently 8 installations of this pump in Canada.

Figure 5: Mass Transfer Pump (after National Oil Well)

Figure 4: Progressing Cavity Pump (after R&M)

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In 1999, Weatherford Artificial Lift Systems introduced their “RamPumpTM” (Fig. 6) which is comprised of a hydraulically actuated vertical piston. This pump was first utilized in an on-shore installation, but has recently been applied offshore in the U.S.A. Gulf of Mexico (Sommer, 2002). Large clearances allow for moderate amounts of sand production. The vertical configuration of the piston provides an advantage for offshore installations where deck space is at a premium.

2.2.4 Diaphragm Pumps The diaphragm pump is a reciprocating pump consisting of two pumping chambers. The piston and motor are immersed in hydraulic oil supplied by a conventional axial-piston hydraulic pump. An elastomeric diaphragm separates the hydraulic oil from the pumped fluids. While these pumps have been primarily associated with the liquid-solids flow associated with deepwater drilling operations, they can be modified to accommodate 100% GVF fluids with high efficiency. Rates of up to 30,000 BPD and differential pressures of 550 psi have been achieved with prototype pumps (Beran, 1995).

2.3 Rotodynamic Pumps Dynamic pumps operate on the principal that kinetic energy is transferred to fluid which is then converted into pressure. In rotodynamic pumps, this occurs when angular momentum is created as the fluid is subjected to centrifugal forces arising from radial flow though an impeller. This momentum is then converted into pressure when the fluid is slowed down and redirected through a stationary diffuser. 2.3.1 Helico-axial pumps The Helico-axial pump is a type of rotodynamic pump developed by the Poseidon Group (IFP, Total and Statoil) and manufactured by Framo and Sulzer. The fluid flows horizontally through a series of pump stages, each consisting of a rotating helical shaped impeller and a stationary diffuser (Fig 7). This configuration is akin to a hybrid between a centrifugal

RAM (during upstroke)

Figure 6: RAMPump ™

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pump and an axial compressor. Each impeller delivers a pressure boost with the interstage diffuser acting to homogenize and redirect flow into the next set of impellers. This interstage mixing prevents the separation of the gas-oil mixture, enabling stable pressure-flow characteristics and increased overall efficiency. As the gas is compressed though successive stages, the geometry of the impeller/diffuser changes to accommodate the decreased volumetric rate. The impeller clearances are sufficient to allow production of small amounts of sand particles. While helico-axial pumps are more prone to stresses associated with slugging, installation of a buffer tank upstream of the pump is generally sufficient to dampen slugging effects such that they are not a problem.

2.3.2 Multistage Centrifugal Pumps Downhole Electric Submersible Pumps (ESP’s), manufactured by companies such as Schlumberger-Reda and Baker-Centrilift, are widely used as an artificial lift method in oil wells. So far, this technology has tended to focus on liquid pumping with incidental amounts of entrained gas. Recently, these pumps have been adapted for surface pumping applications and their ability to handle gas has been extended.

Figure 7: Helico-axial Pump (after Sulzer)

Figure 8: Multistage Centrifugal Pump

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3.0 Multiphase Pump Performance Analysis Unlike single-phase pumps and compressors, no generalized model exists that is able to accurately characterize the performance of multiphase pumps. This is due in part to complex and highly proprietary internal pump geometries. Additionally, the variety of fluid properties and in-situ phase distributions make it extremely difficult to rigorously describe the thermo-hydraulics occurring within the pump. For these reasons it is common practice to characterize multiphase pumps with performance curves of the type depicted in Figure 9. Such curves are constructed on the basis of specified gas volume fractions, suction pressures and liquid density and viscosity. As inlet conditions change, the curve becomes invalid and other curves must be applied.

Commercial simulators often base designs on boundary conditions established upstream of the pump inlet. For example, if a pressure is set at the reservoir or at a manifold located some distance upstream of the pump, the pressure at pump suction becomes flowrate dependant. Thus, it is not possible to move about the performance curve to explore different flowrates without affecting a change in the suction pressure, thereby invalidating the curve. In such cases, it becomes impractical to use series of individual curves to size pumps and explore the operational envelope for changing conditions. The need arises for a model that responds to these changes - not only during iterative calculations performed for one set of conditions, but for sensitivities performed on system parameters and analysis of overall system properties that change over time. The steady-state multiphase flow simulator used in this study (PIPESIM) addresses this issue with three types of pump performance models – a generic model, a twin-screw model, and a helico-axial model. The simplest approach is to use the generic model that treats the multiphase pump as a single-phase liquid pump and gas compressor operating in parallel. Conventional pump and compressor theory is used to calculate the shaft horsepower required. Efficiencies of the pump and compressor can be adjusted based on typical values taken from field conditions. Due to the limiting assumptions in this approach, use of the generic multiphase pump model is recommended only as a preliminary analysis. The twin-screw pump performance model is derived from empirical data covering wide range of gas volume fractions, suction pressures and pump speeds. Pump performance at specific inlet conditions is

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Figure 9: Typical multiphase pump performance curve

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calculated by a rigorous interpolation routine that determines differential pressure, flow rate, pump speed and power requirement. The test data is based on a liquid viscosity of 6 cSt. with corrections applied for different actual viscosities. Seven pump sizes are available and are characterized in terms of nominal capacity – that is, the theoretical rate at 100% speed, 0% GVF, zero differential pressure and with no internal leakage. Available nominal rates range from of 37,500 to 300,000 BPD (250-2000 m3/hr) of total suction flowrate. Additional pumps can be modeled with data supplied by the vendor or acquired in precomissioning tests. The helico-axial pump model characterizes pump performance using three correlating parameters. The flow parameter and the head parameter characterize the size of the impellers and the number of stages respectively, thus defining a specific pump. A speed parameter representing the percentage of maximum speed is then adjusted based on the desired differential pressure for a given rate (or vice-versa). The power requirement is calculated based on a combination of pump performance and drive mechanism. Drive type options include a hydraulic turbine drive, electric air-cooled drive and an electric oil-cooled drive. 4.0 Example The following example illustrates the benefits of a subsea twin-screw multiphase pump installation in comparison to a satellite platform with conventional separation facilities. Steady-state multiphase flow simulation models are used to evaluate the two alternatives. 4.1 System Models An oil well is planned to be drilled in a water depth of 3600’ and 8 miles from a host platform. In a traditional development, a satellite platform would be fixed directly above the wellhead with fluids producing up a riser to a separator operating at 200 psia (Fig. 10). Gas is compressed and liquid is pumped through separate lines to the host platform. Alternatively, a twin-screw multiphase pump can be installed subsea to facilitate full wellstream production through a single subsea tieback to the host platform at an arrival pressure of 200 psia. (Fig. 11).

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Figure 10: Schematic of Production System using satellite platform

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Pressure specified boundary conditions are set at the reservoir (which changes over time) and the separator (assumed constant at 200 psia for both cases). A simple productivity index is applied to determine pressure losses across occurring in the reservoir and the Hagedorn-Brown and Beggs-Brill flow correlations are used to calculate the two-phase pressure loss for vertical and horizontal flow respectively. The ambient temperature along the flowline is 38º F and the water current is 2ft per second, typical values for deepwater environments. 4.2 Initial Producing Conditions Initial producing conditions are represented with a nodal analysis plot (Fig. 12). The intersection of the well curve with the flowline curve shows that the well is capable of naturally flowing at 23,500 STBD with a wellhead pressure of 1100 psia. To achieve higher rates, a pressure boost is provided to reduce the wellhead pressure. The amount of differential pressure required for a specific rate is equivalent to the difference of these two curves and is represented as a single curve in Fig 13. The key difference between this figure and typical curves (Fig. 9) is that the different rates correspond with different suction conditions specific to the system being modeled. This allows one to determine the pump speed required for various rates and corresponding differential pressure required to meet the delivery pressure. As shown, at maximum speed, the pump is able to produce 33,100 STBD with a differential pressure of 937 psia. A marginally higher rate can be achieved using a larger pump, though at the expense of higher upfront capital costs and lower operating efficiencies later in life. The pressure profile for this case (shown in Figure 14) indicates that pressure losses in the 8 mile flowline are roughly equivalent to that in the 3600’ vertical riser. The pressure losses occurring in the flowline are 100% frictional, while the pressure losses occurring in the riser are 90% elevational. As rates decline over time, the elevational losses in the riser will become the dominant factor in the total pressure loss.

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Figure 11: Schematic of Production System using subsea multiphase pump

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4.3 Future Performance Forecast To account for system performance over time, a reservoir performance table is used which correlates pressure decline to cumulative production (Fig 13). The reservoir is initially undersaturated with a bubble point pressure of 3700 psia. As the reservoir depletes, the watercut and gas-oil ratio increase. Production continues until an economic watercut is 85% is reached.

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The performance of several twin screw pump models was considered on the basis of operational flexibility throughout the life of the well. The pump is designed to initially operate at maximum capacity while not exceeding a maximum pressure differential of 1000 psi. As rates decline and watercut and gas-oil ratio increase, the pump speed is reduced to maintain the wellhead pressure at 200 psia while still operating at an acceptable efficiency. In this example, a Nuovo Pignone PSP 210 having a nominal rate of 151,000 BPD (1000 m3/hr) was selected to best meet changing conditions. Table 1 shows pump performance over time. For the first year of production the pump operates at a speed of 100%, after which the pump speed is adjusted to maintain a wellhead (suction) pressure of 200 psia. The gas volume fraction increases as suction pressure drops then remains fairly constant with countering effects of increasing watercut and GOR. At initial conditions, the pump operates efficiently at 54% dropping off to 41% prior to abandonment. At a watercut of 50% a water-oil emulsion is present which significantly increases the overall liquid viscosity resulting in lower pump efficiency and a higher pump differential pressure to accommodate higher frictional pressure losses in the line.

Cum Liquid tot. suct. suction suction pump pump power pumpLiquid time rate vol. rate Wcut GVF liq. visc. pressure ∆P speed req. eff.

MMSTB (years) (STBD) (BPD) (%) (%) (cp) (psia) (psi) (%max) (HP) (%)0.0 0.0 33,100 121,800 10 70 1.2 403 937 100 2573 544.7 0.4 26,650 123,300 10 76 1.3 306 856 100 2365 509.5 0.9 21,320 123,300 15 81 1.6 225 848 100 2345 4417.0 1.8 14,770 100,400 50 84 8.3 200 906 86 2154 3921.7 2.7 13,500 102,000 70 86 0.3 200 600 85 1428 4424.6 3.3 11,000 77,600 80 85 0.3 200 591 68 1125 4227.4 4.0 10,000 73,500 85 86 0.3 200 566 66 1039 41

A forecast of both development scenarios (Fig. 16) was made based on the reservoir performance table. The higher rates achieved with the multiphase pump allow for a shorter production cycle (4 years vs. 6 years for conventional separation). Additionally, in the satellite platform scenario, the well is not able to naturally produce at reservoir pressures less than 3000 psia (wellhead pressure of about 520 psia) and must be abandoned. By lowering the backpressure on the wellhead, the multiphase pump is able to produce to the economic watercut (85%) which corresponds to a reservoir pressure of 2600 psia. The result is an overall recovery of 15.1 MMSTB vs. 13 MMSTB, or an increased recovery of 16%.

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Figure 16: Oil Rate Vs. Time

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4.4 Pump Operational Considerations To operate in a subsea environment, the pump must be marinized and designed to withstand external pressures of approximately 1600 psia. The most frequent operational issue is seal failure which requires intervention using service vessels equipped with Remotely Operated Vehicles (ROV’s) to conduct repairs. An umbilical must be installed to deliver power to the pump and significant voltage losses will occur in the line. The actual operating efficiency of the pump will be significantly less than calculated in the simulation because of the voltage losses in the umbilical and in the pump motor. 4.5 Additional Multiphase Flow Considerations While the multiphase pump improves recovery and eliminates the need for a satellite platform, a number of operational issues involving multiphase flow are introduced. The Taitel-Dukler (1976) flow regime map indicates that slug flow is the predominant flow regime throughout the producing life. A slug catcher located on the host platform must be sized to receive large slugs associated with long flowlines. Statistical analysis applied to the Scott (1986) slug length correlation indicates that the 1/1000 slug length, that is the longest slug of 1000 occurrences, is 3557 feet (221 bbl) and occurs at the highest (initial) flow rate. Should severe slugging occur, a larger slug catcher will be required. The Pots (1985) method suggests severe slugging at the riser base is likely for all cases in this example. This occurs when the length of the liquid slug exceeds the length of the riser causing liquid to accumulate at the riser base trapping gas upstream until the flowline pressure is high enough to drive the slug out of the riser. This results in unstable production rates and pressure control problems at the separator. Severe slugging can be mitigated by means of riser base gas lift injection with gas supplied from the topsides or through a mechanism that transfers in-situ pipeline gas to a point above the riser base (Sarica and Tengesdal, 2000). The formation of emulsions at watercuts in the range up to about 60% is also an issue. The viscosity of emulsions are significantly greater than oil or water alone and is calculated using the (Woelflin, 1942) correlation. The higher viscosity increases the frictional pressure losses in the flowline and reduces pump efficiency as shown in the pump performance table for the 50% watercut case. Finally, a detailed flow assurance study must be performed to ensure that that the temperature in the flowline does not fall below the cloud point for wax deposition or below the hydrate formation temperature. The low ambient temperature along the flowline (38º F) and a swift water current (2ft/s) leads to significant forced convection and heat loss especially at low rates when the fluid velocity is the lowest. It is therefore necessary to insulate the line and in this case 1” thick insulation having a conductivity of 0.1 BTU/hr/ft/ºF is sufficient to avoid hydrate formation. Still, it may be necessary to run a separate line to the pump outlet to perform pigging operations in order to remove hydrate or paraffin buildup that may occur during shut-in and start-up operations.

5.0 Conclusions Multiphase pumps have emerged as a viable alternative to conventional separation, pumping and compression. Significant cost savings can be realized through the reduction of conventional equipment. Additionally, the use of multiphase pumps can increase recoverable reserves, especially in remote operating environments. A variety of multiphase pumps technologies have been developed and the two most promising types, twin-screw and helico-axial, have been incorporated into multiphase flow simulation. Special considerations surrounding multiphase pumping operations include the need to handle produced slugs, flow assurance issues and pump operability.

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6.0 References Beran, W.T.: “On the Threshold – Subsea Multiphase Pumping,” Journal Of Petroleum Technology, pg

326 (April, 1995). Caetano, E.F, R.M. Silva , R.G. da Silva, R.M.T Camargo and G. Rohlfing: “Cooperation on Multiphase

Flow Pumping,” paper presented at the Offshore Technology Conference (May 1997). Cooper, P., et al.: “Tutorial on Multiphase Gas-Liquid Pumping,” presented at the 13th International Pump

Users Symposium, Houston (March 5-7, 1996). Dal Porto, D.F, Larson, L.A.: “Multiphase Pump Field Trials Demonstrate Practical Applications for the

Technology,” SPE paper 36590 presented at the Society of Petroleum Engineers (SPE) Annual Technical Meeting, Houston (Oct. 6-9, 1996).

Egashira, K., S. Shoda, T. Tochikawa and A. Furukawa: “Backflow in Twin-Screw-Type Multiphase Pump,” SPE paper 36595 presented at the Society of Petroleum Engineers (SPE) Annual Technical Meeting, Denver (Oct. 6-9, 1996).

Giuggioli, A., M. Villa, G. De Ghetto, P. Colombi: “Multiphase Pumping for Heavy Oil: Results of a Field Test Campaign,” SPE paper 56464 presented at the Society of Petroleum Engineers (SPE) Annual Technical Meeting, Houston (Oct. 3-6, 1999).

Guevara, E.: “Evolution of Multiphase Pumping in Venezuela,” presentation given at the Texas A&M Multiphase Pump User Roundtable, Houston (May 6, 1999).

Jaggernauth, J.U. Brandt and D. Muller-Link: “Offshore Multiphase Pumping Technology - Identifying the Problems; Implementing the Solutions - Part 1,” paper presented at the SPE/NFP European Production Operations Conference, Stavanger, Norway (April 16-17, 1996).

Martin, A.M. and S.L. Scott: "Modeling Reservoir/Tubing/Pump Interaction Identifies Best Candidates for Multiphase Pumping," SPE paper 77500 presented at the SPE Annual Technical Meeting & Exhibition, San Antonio (Sept. 29 - Oct. 2, 2002).

Oxley, K.C. and G.J. Shoup: “A Multiphase Pump Application in a Low-Pressure Oilfield Fluid-Gathering System in West Texas,” paper presented at the SPE Tulsa Centennial Petroleum Engineering Symposium, Tulsa, Oklahoma (August 29-31, 1994).

Pots, B. F. M., Bromilow, I. G. and Konijn, M. J. W.: "Severe Slug Flow on Offshore Flowline/Riser Systems," SPE paper 13723, (March 1985).

Ramberg, R.M. and L.E. Bakken: “Multiphase Pumps Operability in Petroleum Applications,” paper presented at the 8th International Conference on Multiphase ‘97, BHR Group Limited, No. 24 , Cannes, France (June 18-20, 1997).

Sarica, C., Tengesdal, J.Ø.: “A New Technique to Eliminate Severe Slugging in Pipeline/Riser Systems” SPE paper 63185 (2000).

Scott, S.L., “Multiphase Pump Survey,” presentation made at the 4th Annual Texas A&M Multiphase Pump User Roundtable, Houston (May 9, 2002).

Scott, S.L. and A.M. Martin: “Multiphase - The Final Pumping Frontier," Pumps & Systems Magazine, Randall Publishing (July 2001).

Scott, S. L., Shoham, O., and Brill, J. P.: "Prediction of Slug Length in Horizontal Large-Diameter Pipes," SPE paper 15103 (April 1986).

Sommer, R.: “RamPump – Dual Booster Presentation,” presentation made at the 4th Annual Texas A&M Multiphase Pump User Roundtable, Houston (May 9, 2002).

Taitel, Y., and Dukler, A.E.: “A Model for Predicting Flow Regime Transitions in Horizontal and Near Horizontal Gas-Liquid Flow,” AIChE Journal (1976) 22, 47.

Woelflin, W.: "The Viscosity of Crude-Oil Emulsions," Drill. and Prod. Prac., API (1942) 148. Vetter, G. and M. Wincek: “Performance Prediction of Twin Screw Pumps for two-Phase Gas/Liquid

Flow,” ASME Pumping Machinery, ed. P. Cooper; FED Vol. 154 pp 331-340 (1993). Wyborn, G.: “Multiphase Pumps Offer Alternative for Moving Wellhead Fluids”; presentation given at the

Texas A&M Multiphase Pump User Roundtable, Houston (May 6, 1999); Oil & Gas Journal, pp 56-63 (Sept. 6, 1999).

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About the Authors Mack Shippen is a Petroleum Engineer at Schlumberger-Baker Jardine in Houston, TX where he provides user support, training and consulting for multiphase flow simulation software. He is currently serving as chair of the SPE Reprint on Offshore Multiphase Production Operations. Shippen holds B.S. (1999) and M.S. (2001) degrees in Petroleum Engineering from Texas A&M University, where his research focused on the development of a neural network model for predicting liquid holdup in two-phase horizontal flow. Dr. Stuart L. Scott is an Associate Professor of Petroleum Engineering at Texas A&M University where he conducts research on a variety of aspects of multiphase flow including compact separation, multiphase leak detection and multiphase pumping. Scott holds a B.S.(1982) degree in Petroleum Engineering, an M.S.(1985) degree in Computer Science and a Ph.D.(1987) degree in Petroleum Engineering all from The University of Tulsa. He is currently the chair of the Production Committee for the ASME Petroleum Division. Before joining Texas A&M, he was an Assistant Professor at Louisiana State University and also worked nine years for Phillips Petroleum.