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Multiphase Pumping as an Alternative to ConventionalSeparation, Pumping and Compression
Mack Shippen, Schlumberger - Baker JardineDr. 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 conventionalseparation using rigorous steady-state simulation models incorporating a newly developedmultiphase pumping model. The simulation results show that multiphase pumps areadvantageous in not only reducing facilities, but can also increase production rates by loweringthe backpressure on wells. Additionally, the complexities associated with multiphase flow througha single pipeline are compared to running dual single-phase pipelines and importantconsiderations observed with the steady-state simulation are highlighted.
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1.0 Introduction
Following its 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 particularlybeneficial 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 fromconventional 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 lessefficiently (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 infootprint of operations.
Interest in the subsea deployment of multiphase pumps has grown as operators search for methods toimprove 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 to100-200 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 aproduction 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 improveefficiencies, allowing longer production from these wells and better recovery factors. Subsea processing
covers a wide spectrum of subsea separation and boosting scenarios. Subsea multiphase pumpingtechnology is perhaps a decade ahead of subsea separation and provides many advantages in terms ofintervention 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 modelmultiphase 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 multiphaseflow in the petroleum industry. As shown in Figure 1, these methods fall into the broad categories of thepositive 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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0
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100
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250
300
350
400
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
Piston
Helico-Axial
Single-Screw (PCP)
Twin-Screw
Positive Displacement
Twin Screw
Progressing Cavity (PCP)(Single Screw)
Piston
Diaphram
Rotodynamic
Helico-axial(Poseidon type)
Multi-Stage Centrifugal(ESP type)
Multiphase Pumps
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 successfullyincorporated 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 toflow 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 GVFs 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 theinterlocking 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 statorand 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 hasthe unique ability to tolerate considerable amounts of solids (sand). However, high sand production ratesresult 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 themultiphase 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) andmaximum 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 pumpingunits. 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 foroffshore 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 motorare 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 primarilyassociated 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 thenconverted 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/diffuserchanges 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 tankupstream 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 (ESPs), 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 havebeen 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 proprietaryinternal pump geometries. Additionally, the variety of fluid properties and in-situphase 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 typedepicted 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 theperformance 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 thatresponds 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. Thesimplest 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 calculatethe 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
Increasing powerrequirement
increasing speed
P
Total volumetric suction flowrate
Valid for given:
Gas volume fraction
Suction pressure
Liquid viscosity
Liquid Density
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 nointernal 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 maximumspeed 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 incomparison 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 pumpedthrough 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).
8 mile gas line
Host platform
36008 riser
8 mile liquid line
compressor
pump
Satellite platform
Psep = 200psia
wellhead
Figure 10: Schematic of Production System using satellite platform
38F 2 ft/s
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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 ambienttemperature along the flowline is 38 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 thewellhead 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 conditionsspecific 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. Amarginally 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 flowlineare 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.
8 mile 8 subsea tieback
Host platform
3600 8 riser
wellhead
Multiphasepump
Psep = 200 psia
Figure 11: Schematic of Production System using subsea multiphase pump
38F 2 ft/s
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Pr = 6000 psi, GOR = 400, wcut = 10%
Stock-tank Liquid (STB/d)35,00030,00025,00020,00015,00010,0005,0000
Pressure(psia)
3,200
3,000
2,800
2,600
2,400
2,200
2,000
1,800
1,600
1,400
1,200
1,000
800
600
400
200
PumpP
Flowline & riser resistance curve
Well curve
Increased rate
Pump Performance
PumpDP(psi)
1,000
950
900
850
800
750
700
650
600
550
500
450
400
350
300
250
200
150
100
50
Stock-tank Liquid (STB/d)35,00030,00025,000
60%
70%
80%90%
100%speed
Pump P = 937 psi
33,100
Figure 13: Twin screw pump performance at initial Producing Conditions
System curve
Figure 12: Nodal Analysis at Initial Producing Conditions
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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. Productioncontinues until an economic watercut is 85% is reached.
0
1
2
3
4
5
6
7
8
9
0 5 10 15 20 25
% WC X 10
Pres X 1000 (psia)
GOR X1000
(scf/STB)
Pressure Profile
Total Distance (ft)40,00030,00020,00010,0000
Pressure(psia)
1,300
1,200
1,100
1,000
900
800
700
600
500
400
300
200
P Pump
Wellhead pressure
P flowline
P riser
Arrival pressure
Figure 14: Pressure Profile at Initial Producing Conditions
Bubble point
Figure 13: Reservoir Performance Table
Cumulative Liquid (MMSTB)
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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 anacceptable 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 speedof 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 offto 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 pump
Liquid t ime rat e vol. rat e Wcut GVF liq. visc. p ressure 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 50
9.5 0.9 21,320 123,300 15 81 1.6 225 848 100 2345 44
17.0 1.8 14,770 100,400 50 84 8.3 200 906 86 2154 39
21.7 2.7 13,500 102,000 70 86 0.3 200 600 85 1428 44
24.6 3.3 11,000 77,600 80 85 0.3 200 591 68 1125 42
27.4 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. 6years 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%.
0
5000
10000
15000
20000
25000
30000
0 1 2 3 4 5 6
Time (yrs)
Oil
Rate(STB/D)
Boosted
Cum Oil = 15.1 MMSTB
Unboosted
Cum Oil = 13 MMSTB
Table 1: Pump Performance Over Time
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 requiresintervention using service vessels equipped with Remotely Operated Vehicles (ROVs) 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 mapindicates 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 theliquid slug exceeds the length of the riser causing liquid to accumulate at the riser base trapping gasupstream 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 thattransfers 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 (38 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 thereforenecessary to insulate the line and in this case 1 thick insulation having a conductivity of 0.1 BTU/hr/ft/F
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-inand 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 operatingenvironments. 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 producedslugs, 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 PumpUsers 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) AnnualTechnical 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&MMultiphase Pump User Roundtable, Houston (May 6, 1999).
Jaggernauth, J.U. Brandt and D. Muller-Link: Offshore Multiphase Pumping Technology - Identifying theProblems; Implementing the Solutions - Part 1, paper presented at the SPE/NFP EuropeanProduction 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/RiserSystems," 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..: A New Technique to Eliminate Severe Slugging in Pipeline/Riser SystemsSPE paper 63185 (2000).
Scott, S.L., Multiphase Pump Survey, presentation made at the 4 th Annual Texas A&M Multiphase Pump
User Roundtable, Houston (May 9, 2002).
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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 aschair 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, multiphaseleak 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 alsoworked nine years for Phillips Petroleum.