Hydraulic pumping

Chapter 6
Hydraulic Pumping
Hal Petrie, National-Oilwell*
Introduction
A well will flow if it has sufficient reservoir potential ener-
gy (pressure) to lift fluid to the surface. Artificial lift is
applied to a well if the reservoir pressure is not sufficient
to cause the well to flow, or when more production is
desired in a flowing well. In either case, energy must be
transmitted downhole and added to the produced fluid.
Hydraulic pumping systems transmit power downhole by
means of pressurized power fluid that flows in wellbore
tubulars. Hydraulic transmission of power downhole can
be accomplished with good efficiency. With 30”API oil
at 2,500 psi in 27/,-in. tubing, 100 surface hhp can be trans-
mitted to a depth of 8,000 ft with a flow rate of 2,353
B/D and with a frictional pressure drop of 188 psi. This
pressure loss is 7.5 % of the applied power. If the trans-
mission pressure is raised to 4,000 psi, the required flow
rate drops to 1,47 1 B/D and the frictional pressure loss
declines to only 88 psi. This is 2.2% of the applied sur-
face power. Even higher efficiencies can be achieved with
water as the hydraulic medium because of its lower vis-
cosity .
The downhole pump acts as a transformer to convert
the energy of the power fluid to potential energy or pres-
sure in the produced fluids. The most common form of
hydraulic downhole pump consists of a set of coupled
reciprocating pistons, one driven by the power fluid and
the other pumping the well fluids. Another form of
hydraulic downhole pump that has become more popular
is the jet pump, which converts the pressurized power
fluid to a high-velocity jet that mixes directly with the well
fluids. ‘.2 In the turbulent mixing process, momentum and
energy from the power fluid are added to the produced
fluids. Rotatin hydraulic equipment has also been tested
in oil wells. ‘,9 In this case, a hydraulic turbine driven
by the power fluid rotates a shaft on which a multistage
centrifugal or axial-flow pump is mounted. This type of
‘The origlnat chapter on this top% m the 1962 edltion was written by C J. Coberly and
F Barton Brown.
pump has not had widespread commercial use. The “free
pump” feature, common to most designs, allows the pump
to be circulated in and out of the well hydraulically without
pulling tubing or using wircline services.
The operating pressures used in hydraulic pumping sys-
tems usually range from 2,000 to 4,000 psi. The most
common pump used to generate this pressure on the sur-
face is a triplex or quintiplex positive-displacement pump
driven by an electric motor or a multicylinder gas or diesel
engine. Multistage centrifugal pumps have also been
used,5 and some systems have operated with the excess
capacity in water-injection systems. ’ The hydraulic fluid
usually comes from the well and can be produced oil or
water. A fluid reservoir at the surface provides surge ca-
pacity and is usually part of the cleaning system used to
condition the well fluids for use as power fluid. Appro-
priate control valves and piping complete the system. A
schematic of a typical hydraulic pumping system is shown
in Fig. 6.1.
A wide variety of well conditions can be handled by
hydraulic pumping systems. Successful applications have
included setting depths ranging from 1,000 to 18,000 ft. ’
Production rates can vary from less than 100 to more than
10,000 B/D. Surface packages are available in sizes rang-
ing from 30 to 625 hp. The systems are flexible because
the downhole pumping rate can be regulated over a wide
range with fluid controls on the surface. Chemicals to con-
trol corrosion, paraffin, and emulsions can be injected
downhole with the power fluid. Fresh water can also be
injected to dissolve salt deposits. When pumping heavy
crudes, the power fluid can serve as an effective diluent
to reduce the viscosity of the produced fluids. The power
fluid can also be heated for handling heavy crudes or low-
pour-point crudes. Hydraulic pumping systems are suita-
ble for wells with deviated or crooked holes that cause
problems for conventional rod pumping. The surface fa-
cilities have a low profile and can be clustered into a cen-
tral battery to service numerous wells. This can be

6-2 PETROLEUM ENGINEERING HANDBOOK
A. Power-fluid
tank
B. Multiplexhigh-pressurepump
C. Control manifold
D. Wellhead controlvalve
E. Downhole pump
Fig. &i-Typical hydraulicpumping system mstallation
advantageous in urban sites,offshore locations, and en-
VirOnmentally sensitive areas. Jet pumps can be circulated
around the 5-ft-radius loop of subsea through-flowline
(TFL) installations8 joining gas-lift valves as the only ar-
tificial lift devices suitable for these systems.
Downhole Pumps
Types of Installations
The two basic types of installations are the fixed pump
and the free pump designs. In the fixed installation, the
downhole pump is attached to the end of a tubing string
and run into the well, Free pump installations are designed
to allow downhole pump circulation into and out of the
well inside the power-fluid tubing string. The downhole
pump can also be installed and retrieved by wireline op-
erations.
Fixed Pump Installations (Conventional Installations).
In the fixed insert design, the pump lands on a seating-
shoe set in tubing that has a larger ID than the OD of the
pump. Power fluid is directed down the inner tubing
string, and the produced fluid and the return power fluid
flow to the surface inside the annulus between the two
tubing strings, as shown in Fig. 6.2a. This system pro-
vides a passage for venting free gas in the annular space
between the outer tubing string and the inside of the well
casing. To take full advantage of the gas venting passage,
the pump should be set below the perforations. The power-
Fig. 6.2-Downhole pump installations.
fluid string is usually ?4, I, or I U in., depending on the
size of the production tubing. This once-common system
is now used mainly to fit a large-diameter downhole pump
into restricted casing sizes and still retain the gas-vent fea-
ture. It can also be used to lift one or both zones of a dual
well with parallel strings.
In the fixed casing design, the tubing, with the pump
attached to its lower end, is seated on a packer, as shown
in Fig. 6.2b. With this configuration. the power fluid is
directed down the tubing string, and the mixed power fluid
and the produced well fluids return to the surface in the
tubing/casing annulus. Because the well fluids enter the
pump from below the packer, all the free gas must be han-
dled by the pump. This type of installation is normally

6-3
HYDRAULIC
PUMPING
Pump-in
When the handle is I” the
down positron. high
pressure power Huld Irom
the multiplex power pump
c~rculalesthelree hydraulic
pump down the tubing to
the bottom of the well
The pow&flu~d begIns lo
operate the pump once it’s
seated at the standing
valve Produced fluId and
exhaust power fluld then
return up the casing
annulus through the valve
and Into the flow Ilne.
Pump-out
With the selector handle in
the up posItion, power fluld
is drected down the casing
annulus and returned up
the tubing lifting the pump
as the fluid flows back to the
surface
Bypass. bleed, and pump
removal
The power fluld bypass
valve IS opened and the
selector handle IS placed I”
m!d-posItton This permits
the well to be bled dawn
and the pump to be
removed and replaced.
Fig. 6.3-Free-pump cycle.
used in wells without much gas and with large-diameter,
high-capacity pumps. If space permits, a gas-vent string
can be run from below the packer to the surface. As with
the fixed insert design, this installation is no longer com-
mon, and both types have been largely supplanted by the
various free pump installations. Note that in both of the
fixed-type installations, the power fluid mixes with the
produced fluids after passing through the pump.
Free Pump Installations. The free pump feature is one
of the most significant advantages of hydraulic pumping
systems. Free pump installations permit circulating the
pump to bottom, producing the well, and circulating the
pump back to the surface for repair or size change. Free
pump installations require that a bottomhole assembly
(BHA) be run in on the tubing string. The BHA consists
of a acating shoe and one or more seal bores above it and
scrvcs as a receptacle for the pump itself. BHA’s are of
robust construction and USCcorrosion-resistant sealing
bores to ensure a long life in the downhole environment.
Once run in on the tubing string. they normally remain
in place for years, even though the downhole pump may
be circulated in and out numerous times for repair or resiz-
ing. As shown in Fig. 6.3, a wireline-retrievable stand-
ing valve ib landed in the seating shoe below the pump.
The pump is run in the hole by placing it in the power-
fluid tubing string and circulating power fluid in the nor-
mal direction. When the pump reaches bottom, it enters
the seal bores. begins stroking. and opens the standing
valve. During normal pumping, this valve is always held
open by well fluids drawn into the pump suction. During
pump-out, the normal flow of fluids is reversed at the sur-
face with appr.opriate valving, and pressure is applied to
the discharge flow path of the pump. This reversal of flow
closes the standing valve and permits the pump to be cir-
culated to the surface. Circulating the pump out normal-
ly takes from 30 minutes to 2 hours. depending on the
well depth and the circulating flow rate.
The benefits of being able to circulate the downhole
pump in and out of the well include reduced downtime
and the ability to operate without a pulling unit for tubing.
cable, or rod removal. Another significant advantage is
that pressure and temperature recorders can be mounted
on the pump to monitor downhole conditions with differ-
ent pumping rates. At the conclusion of the test, circulat-
ing the pump to the surface also retrieves the recorder.
Leakage of tubing pressure can be checked by substitut-
ing a dummy pump for the normal production unit. Steam-
ing, acidizing, or other chemical treatment of the
formation can be done if the pump is circulated out and
the standing valve is wirelined out. A flow-through blank-
ing tool may be run instead of the pump for such treat-
ments if isolation of the power fluid and discharge flow
paths is desired.
The casing free installation, shown in Fig. 6.2~. is at-
tractive from an initial-cost standpoint because it uses only
one string of tubing. At first glance it seems to be the same
as the fixed casing design. The crucial difference is that,
instead of being attached to the end of the power-fluid
string, the pump fits inside it to allow circulation into and

Fig. 6.4-Free-pump, parallel,
closed-power BHA.
out of the well. For a given-diameter pump, this requires
a larger-diameter power-fluid string, which reduces the
annular flow path for the discharge fluids. In most cases,
more than adequate flow area remains. Tubing as small
as I % in. can be run in systems with 2%.in. tubing used
as casing. In 1‘/z-in. tubing, only jet pumps can be used.
In 2%.in. or larger tubing, either jet or reciprocating
pumps can be used. Usually, 26-m. power-fluid tubing
is used in 4-in. or larger casing, 2x-m. tubing in 5 %-in.
or larger casing, and 3%-in. tubing in 6X-in. casing or
larger. Only a very few free-pump installations have been
made for 41/2-in. or larger tubing strings. Because the
BHA sits on a packer, the pump must handle all the gas
from the well in addition to the liquids. A gas-vent string
can be run to below the packer if gas interference limits
pump performance. Such an installation ISshown rn big.
6.2d. In both the vented and unvented systems, the pow-
er fluid mixes with the produced fluids and returns to the
surface.
In wells where the produced fluids should be kept off
the casing wall or where gas venting is desired, the parallel
free installation should be considered. This installation,
which requires two parallel tubing strings, normally does
not require a packer. As shown in Fig. 6.2e, the BHA
is suspended on the power-fluid tubing string, and the
return string is either screwed into the BHA or is run
separately with a landing spear that enters a bowl above
the BHA. The tubing/casing annulus serves as a gas-vent
passage. and to take full advantage of this, the unit should
be set below the perforations.
If the well is not pumped off fully, well fluids will rise
above the BHA until the bottomhole pressure (BHP,
pump-suction pressure) increases to the point that the well
inflow rate and BHP match the inflow performance rela-
tionship (IPR) curve of the well. This will expose some
of the casing above the perforations to well fluids. In some
cases, this may be desirable to prevent collapse of the
casing, but in corrosive wells, such as those encountered
in CO2 flooding or with H2.S present, it may be undesira-
ble. In such a case, a packer may be set above the perfo-
rations, although the gas-vent feature is then lost unless
another gas-vent string is run to below the packer.
The size of the downhole pump dictates the power-tluid
tubing size, and the casing size dictates how large the
parallel return string can be. When the return string is
limited in size, fluid friction may restrict the obtainable
production or the practical setting depth.
Closed Power-Fluid Systems
All the installations discussed so far are open power-fluid
types. This means that the power fluid and the produced
fluid are mixed together after leaving the downhole pump
and return to the surface together in a common flow pas-
sage. Jet pumps are inherently open power-fluid pumps
because the energy transfer depends on mixing the power
fluid and produced fluid. Reciprocating pumps. however,
keep the power and produced fluids separate during the
energy transfer process because there is a separate piston
(or piston face) for each fluid. If the BHA has appropri-
ate seal bores and passages to keep the two tluids sepa-
rated, the power fluid can be returned to the surface in
a separate tubing string. The extra tubing string for the
power-fluid return classifies these installations in the

HYDRAULIC PUMPING
parallel free category. An example of a c,lo.r~dpo,l,~~~~~~;~~
instufhtion is shown in Fig. 6.4. The principal advan-
tage of closed power-fluid installations is that only the pro-
duced fluids need to go through the surface separating
facilities. and the power fluid remains in a separate, closed
loop. The resulting smaller surface facilities may be de-
sirable in certain areas, such as townsite leases and off-
shore installations. In principle, the power-fluid clean-
liness can be maintained better because it is not contami-
nated with well fluids. When water is used as the power
fluid, it is generally necessary to add small amounts of
corrosion inhibitors and lubricants. These would be lost
in the open system, but arc retained in the closed system.
Offsetting the advantages of the closed system are ti e
higher initial cost of the extra tubing string and more com-
plex pump and BHA. Most closed power-fluid installa-
tions are found in the urban and offshore wells of
California.
Reverse Flow Systems
Two considerations-the need to keep produced fluid off
the casing and to minimize fluid-friction losses-have led
to the use of reverse-flow installations (also known as
reverse-circulation installations) in some wells. A reverse-
flow casing installation is shown in Fig. 6.5. These sys-
tems are most commonly used with jet pumps, although
a few installations have been made with reciprocating
pumps. The casing system uses the tubing/casing annulus
for power fluid, and the tubing string, which contains the
pump, is used for the combined power fluid and produc-
tion. This protects the casing with inhibited power fluid
and is most useful when severe corrosion is anticipated.
It does require the use of a heavier wall casing to avoid
bursting it when power-fluid pressure is applied. The
parallel system uses the smaller-size string for power fluid
and the larger main string that contains the pump for the
combined power fluid and production. The primary ad-
vantages of this system are reduced friction, gas venting,
and protection of the casing. As discussed in the section
on the parallel free design. complete casing isolation re-
quires a packer below the BHA. Both types of reverse-
flow installations may require a latch or friction holddown
to position the pump in the BHA during startup or to re-
tain it in position during pumping, depending on the bal-
ance of forces on the downhole pump.
In reverse-flow installations. the pump is wirelined often
in and out of the well, but a modified form of the free
pump feature can be used. With jet pumps, the pump is
run in with a pusher-type locomotive, which then circu-
lates to the surface during pumping. To retrieve the pump,
a similar blanked-off locomotive with a fishing tool at-
tached is circulated down and latched to the pump. When
flow is established in the normal pumping mode direc-
tion, the pump will surface. This sequence of operations
is shown in Fig. 6.6. Fig. 6.7 shows a reverse-flow in-
stallation with a reciprocating pump. Because the engine
and pump valving in these pumps does not permit flow-
back to the pump suction for unseating the pump, a BHA
side line must be run to the bottom of the pump. The latch
assembly on top of the pump keeps it on seat during nor-
mal pumping. To retrieve the pump, a releasing tool is
dropped or wirelined before the pump is circulated to the
surface. Once the latch is released, the flow of fluid in
the normal pumping mode will surface the pump.
r Power
Discharge
6-5
fluid
-Lock A upper seal
~51 iding sleeve body
*SI iding sleeve
-Jet pump
-Lower sea I
Suet ion
tI
Fig. 6.5~-Reverse-flowjet-pump casing type in sliding
sleeve.

PETROLEUM ENGINEERING HANDBOOK
(1)Pump In.
(2)Seat Pump.
(4)Retrievewith
reversed flow and
fishinglocomotive.
(5)Pump Out.
(6)Bypass, bleed,and
pump removal.
(3)Operate-pusher locomotive
surfaces and standing
valve opens.
Fig. &B--Reverse-flow, free-pump cycle.
TFL Installations
TFL installations have been developed for offshore loca-
tions to allow circulation of various downhole tools to the
bottom of remote wells from a central platform. A typical
installation is shown in Fig. 6.8. Because a Sft-radius
loop is an integral part of the subsea wellhead installa-
tion, the size of the tools that can be circulated through
it is limited. Of the various artificial-lift tools, only gas-
lift valves and hydraulic jet pumps are sufficiently corn-
pact to be compatible with the system. When jet pumps
are used, they may be normal-flow or reverse-flow types.
Fig. 6.9 is an example of the reverse-flow installation used
with TFL. The normal-flow installation is the simplest
because it is essentially a parallel free installation and does
not require special latches or holddowns. However, the
pump has more complex internal fluid passages and the
discharge fluid passes through the crossover port of the
downhole H-member, which serves as a BHA. Because
of the potential for erosion and corrosion of the crossover
member, many operators prefer the reverse-flow instal-
lation shown in Fig. 6.9. Here, only the power fluid passes
through the crossover port, and the pump flow passages
are of a simpler design and can have a higher capacity.
Note the compactness of the pump and the use of univer-
sal joints that allow flexibility between the pump and the
lower seal section. Circulating the pump in and out. how-
ever, is more complex, and the procedures described for
non-TFL reverse-flow installations must be used.
The dual-sleeve side-door choke is probably the most
important item in the string other than the pump itself
when TFL operations are performed. This item is run
open as shown to allow bypass past the pump for circulat-
ing tools into and out of the hole because not much fluid
can be circulated through the pump nozzle. Once pump
operations are ready to begin, the sleeve is closed by pres-
suring both strings. When pulling the pump, the sleeve
is reopened by pressuring the tubing string that the pump
is landed in, and circulation is then re-established.

HYDRAULIC PUMPING
Dual Wells. Hydraulic pumps lend themselves to the com-
plex problem of the production of two separate zones in
a single wellbore. When the two zones have different
reservoir pressures. it is not practical to allow communi-
cation between them because the higher-pressure zone will
flow into the lower-pressure zone. To meet the artificial
lift requirements of the two distinct zones, two downhole
pumps are usually required. It would be highly unusual
if the same power-tluid pressure and rate were required
for each zone; consequently, a separate power-fluid line
for each pump is usually required. A number of plumbing
configurations are possible. One option is shown in Fig.
6.10. The two pumps are physically connected and are
run in and retrieved as a unit. In some cases, dual zones
have been produced separately by use of double pump
ends with a common engine.
Tandem Pumps. When the well capacity requirements
exceed what can be produced by a single pump, it is pas-
sible to install two pumps in parallel or tandem to double
the displacement of the downhole equipment. Again, the
pumps are physically connected to form a single unit, but
each pump is free to run independently.
Historically, tandem pump installations have used
reciprocating pumps. The downhole arrangement is simi-
lar to that of Fig. 6.10, but without the passages that route
fluid from two separate zones. It is possible to use jet
pumps in the same manner, but this is rarely done be-
cause it is usually possible to get sufficient capacity in
a single jet pump. Since the introduction of jet pumps
about 1970, high-volume hydraulically pumped wells have
generally used jet pumps instead of tandem reciprocating
pumps.
6-7
Fig. 6.7~-Reverse-flowtubing arrangement
(stroking
pump).
Lubr i cator
Manifold and instrumen
Pressure transducers
Entry loops
Subsea we I lhead
Circulation point
(H-member 1
Jet pump location
tat ion
Fig. 6.6-Typical offshoreTFL installation.

Production
Latch
Seals
Side door
choke
Universal
joint
Diffuser
Throat
Nozzle
Power
fluid
I
1'
1
;i
+ Suction
Production
discharge
Pump
-
plunger
Pump
- discharge
valve
Pump
- barrel
- Pump intake
valve
Fig. 6.9--Reverse-flowTFL jetpump. Fig. 6.10-Dual-zone installation
with two
free pumps operatingintandem, gas from
upper zone produced through casing.
Fig. 6.11--Single-acting
pump end
Principles of Operation-
Reciprocating Pumps
The pump end of a hydraulic downhole pump is similar
to a sucker-rod pump because it uses a rod-actuated plung-
er (also called the pump piston) and two or more check
valves. The pump can be either single-acting or double-
acting. A single-acting pump follows rod-pump design
practices closely and is called single-acting because it dis-
places fluid to the surface on either the upstroke or down-
stroke (but not on both). An example is shown
schematically in Fig. 6.11. Fig. 6.12 shows a double-
acting pump that has suction and discharge valves for both
sides of the pump plunger. which enables it to displace
fluidsto the surface on both the upstroke and downstroke.
With either system, motion of the plunger away from a
suction valve lowers the pressure that holds the valve
closed, it opens as the pressure drops, and well fluids are
allowed to enter the barrel or cylinder. At the end of the
stroke, the plunger motion reverses, which forces the suc-
tion valve to close and opens the discharge valving.
In a sucker-rod installation. the rod that actuates the
pump plunger extends to the surface of the well and con-
nects to the pumping unit. In hydraulic pumps. however,
the rod is quite short and extends only to the engine piston.
The engine piston is constructed similarly to the pump
plunger and is exposed to the power-fluid supply, which

-Engine piston
-Engine valve
-Engine cylinder
-Power fluid in
rPower fluid exhaust
i and production
discharge
-Pump plunger
-Pump d ischarge va Ive
-Pump barre I
-Pump intake valve
Type F
FEB, FE
Fig. 6.14--Single-acting
downhole unit
nears the ends of the upstroke and downstroke. Combi-
nations of mechanical and hydraulic shifting are possi-
ble. The engine valve may be located above the rod-and-
plunger system, in the middle of the pump, or in the en-
gine piston.
Note that the two designs illustrated and discussed do
not exhaust the design possibilities offered by the vari-
ous pump manufacturers. Examples of combinations of
these and other design concepts can be seen in the cross-
section schematics of the various pump types that accom-
pany the pump specifications in Tables 6. I through 6.4
and Figs. 6.15 through 6.18. Common to all the designs,
however. is the concept of a reversing valve that causes
an engine piston (or pistons) to reciprocate back and forth.
This strokes the pump plunger (or plungers) that lifts fluid
from the well.
Because the engine and pump are closely coupled into
one unit, the stroke length can be controlled accurately.
With a precise stroke length, the unswept area or clear-
ance volume at each end of the stroke can be kept very
small, leading to high compression ratios. This is very
Type VFR Type V Type 220
Fig.6.15-Manufacturer “A” pump types forTable 6.1
important in maintaining high volumetric efficiency when
gas is present and generally prevents gas locking in
hydraulic pumps. The engine valves and their switching
mechanisms usually include controls to provide a smooth
reversal and to limit the plunger speed under unloaded
conditions. The unloaded plunger speed control is often
called governing and minimizes fluid pound when the
pump is not fully loaded with liquid. In this way, shock
loads in the pump and water hammer in the tubing strings
are softened, which reduces stresses and increases life.
Pressures and Forces in Reciprocating Pumps
Reciprocating hydraulic pumps are hydrostatic devices.
This means that the operation of the unit depends on pres-
sures acting against piston faces to generate forces. and
that the fluid velocities are low enough that dynamic ef-
fects can be neglected. A pressurized fluid exerts a force
against the walls of its container. This force is perpen-
dicular to the walls regardless of their orientation. If the
pressurized container consists of a cylinder with one end
blanked off and the other end fitted with a movable plung-

HYDRAULIC PUMPING 6-11
TABLE 6.1~-RECIPROCATING PUMP SPECIFICATIONS. MANUFACTURER “A”
Puma
Type F, Fe, FEB
23/8-in.
tubing
F201311
F201313
F201611
F201613
FE8201613
FE6201616
27/g-h.
tubing
F251611
F251613
F251616
FE252011
FE252013
FE252016
Type VFR
23/8-h.
tubing
VFR201611
VFR201613
VFR201616
VFR20161613
VFR20161616
27/8-h.
tubing
VFR252015
VFR252017
VFR252020
VFR25202015
VFR25202017
VFR25202020
Type V
27/-/n.
tubing
V-25-11-1
i-8
V-25-11-095
V-25-11-076
V-25-11-061
V-25-21-075
V-25-21-063
V-25-21-050
V-25-21-041
Type 220
23/-h. tubing
330-201610
330-201612
530-201615
27/-h. tubing
348-252012
348-252015
548-252017
548-252019
536-252020
Note Pump Size
F. FE, FEB. VFR Types
F
Disolacement
B/D oer strokeslmin
Puma
3.0 4.2
4.2 4.2
3.0 6.4
4.2 6.4
6.2 9.4
9.4 9.4
3.3 7.0
4.6 7.0
7.0 7.0
5.0 16.5
7.0 16.5
10.6 16.5
2.12 4.24
2.96 4.24
4.49 4.24
2.96 6.86
4.49 6.86
5.25 8.89
7.15 8.89
9.33 8.89
5.25 15.16
7.15 15.16
9.33 15.16
6.31 5.33
6.31 6.66
3.93 5.33
3.93 6.66
6.31 8.38
6.31 10.00
3.93 8.38
3.93 10.00
4.22 8.94
5.46 8.94
7.86 8.94
8.73 22.35
12.57 22.35
17.11 22.35
20.17 22.35
25.18 25.18
V Types
v
220 Sertes
3 Number of seals
20 Nommal tubing (2 I” ) 25 Nommal tubmg (2% I” ) 48 Stroke length p,
13 Engme (1 3 I” ) 11 Single engme (double = 21) 25 Nomlnal tubing (2% in.]
XX Second engine (VFR only) 118PIE 20 Engine (2 000 IO.)
11 Pump (1 1 in ) 12 Pump (1 200 m.)
Types F. FE. FEB are slngle-seal, internal-portmg; 220, VFR, and V are multiple-seal, external-pomng.
Engine
Rated Speed (B/D)
Enaine Total PIE
Puma
204
285
204
285
340
517
214
299
455
255
357
540
318
444
673
444
673
630
8.58
1,119
630
858
1,119
1,229
1,299
550
550
1,173
1,072
550
550
422
546
786
629
905
1,232
1,452
2,014
286 490 0.71
286 571 1.00
435 639 0.47
435 720 0.66
517 857 0.66
517 1,034 1.00
455 669 0.47
455 754 0.66
455 910 1.00
842 1,097 0.30
842 1,199 0.42
842 1.382 0.64
636 954 0.62
636 1,080 0.87
636 1,309 1.32
1,029 1,473 0.54
1,029 1,702 0.81
1,067 1,697 0.74
1,067 1,925 1.00
1,067 2,186 1.32
1,819 2,449 0.41
1,819 2,677 0.56
1,819 2,938 0.73
1,098 2,397 1.18
1,372 2,671 0.96
746 1,296 0.76
932 1,482 0.61
1,559 2,732 0.75
I;700 23772 0.63
1,173 1,723 0.50
1,400 1,950 0.41
894 1,316 0.49
894 1,440 0.63
894 1.680 0.89
1,609 2,238 0.40
1.609 2.514 0.57
11609 2,841 0.78
1,609 3,061 0.93
2,014 4,028 1.00
Maximum Rated
Speed
(strokes/min)
68
68
68
68
ii;
65
65
65
51
51
51
150
150
150
150
150
120
120
120
120
120
120
206
206
140
140
186
170
140
140
100
100
100
72
72
72
72
80

TABLE 6.2--RECIPROCATING PUMP SPECIFICATIONS, MANUFACTURER “B“
Pump
Type A
23/8-in.
tubing
2x l-13/16
2x1-1
2x l-1$&
2x 13/16-l
2x 1%6-l%
2x13/16-1x1
2x13/16-13/16x1
2x 1%6-1%6x1%6
2x-in. tubing
2% x 1x-1
2% x IV-l'/8
2'/2
x IX-1%
2% x l'h-l'/,Fj
2% x l%e-1%
2% x 15/8-l%
2% x 15/s-15/8
2% x 1%6-l% x 1%
2% x 1%,-l%, x 1%
2% x i&-l'/,6x 1'/,6
2'/2
x 15/E-15/8x
15/s
3Yz-in.
tubing
3x 1%-l%
3x l'h-lJ/B
3 x 1%1%
3x 1'/2-1%
3 x 13/4-i%
3x 1%-l%
3 x 13/i-IV4
x 1%
3 x 13/4-l%x 1%
3x 13/i-13/9x 1%
3X 1%.-l% x 1%
4Win. tubing
4x2-1%
4x2-2
4X2-23/8
4X23/8-2
4 x23/0-23/s
4X2%-2X 1%
4x2$&2x2
4 X23/-23/n
x 2
4 x 23&23/g x 23/
We B
23/s-h.
tubing
2x 13/s-13/16
2x 13/s-13/s
2X13/-13/j~Xl3/,,6
2 x 13/a-13/8
x 1y,#j
2~13/g-i3/~13/g
Notes
Displacement
B/D per strokes/min Rated Speed (B/D)
Pump Engine Pump Engine Total PIE
-~__~
Maxlmum Rated
Speed
(strokeslmln)
1.15 2.15 139
2.10 2.15 255
3.25 2.15 393
2.10 3.30 255
3.25 3.30 393
4.20 3.30 508
5.35 3.30 647
6.50 3.30 787
260 399 0.545
260 515 1.000
260 653 1.546
399 654 0.647
399 792 1.000
399 907 1.290
399 1,046 1.647
399 1,186 2.000
121
121
121
121
121
121
121
121
2.56 5.02 256 502 758 0.520
3.67 5.02 367 502 868 0.746
4.92 5.02 492 502 994 1.000
7.03 5.02 703 502 1,205 1.431
4.92 7.13 492 713 1,205 0.700
7.03 7.13 703 713 1,416 1.000
7.03 9.27 703 927 1,630 0.770
7.45 9.27 745 927 1,672 0.820
9.09 9.27 909 927 1,836 1.000
9.84 7.13 984 713 1,697 1.400
11.95 7.13 1,195 713 1,908 1.701
14.06 7.13 1,406 713 2,119 2.000
18.18 9.27 1.818 927 2,745 2.000
100
100
100
100
100
100
100
100
100
100
100
100
100
5.59 9.61 486
7.43 9.61 646
9.44 9.61 821
14.00 9.61 1,218
9.44 14.17 821
14.00 14.17 1,218
11.18 14.17 973
18.18 14.17 1,642
23.44 14.17 2,093
28.00 14.17 2,436
836 1,322 0.592
836 1,482 0.787
836 1,657 1.000
836 2,054 1.480
1,233 2,054 0.676
1,233 2,451 1.000
1,233 2,206 0.800
1,233 2,875 1.351
1,233 3,326 1.675
1,233 3,669 2.000
87
87
87
87
87
87
87
87
87
87
14.40 21.44 1,109
21.00 21.44 1,617
32.50 21.44 2,503
21.00 32.94 1,617
32.60 32.94 2,503
35.40 32.94 2,726
42.00 32.94 3,234
53.50 32.94 4,120
65.00 32.94 5,005
1,651 2,760 0.687
1,651 3,268 1.000
1,651 4,154 1.541
2,536 4,153 0.649
2,536 5,039 1.000
2,538 5,262 1.094
2,536 5,770 1.299
2,536 6,656 1.650
2,536 7,541 2.000
77
77
77
77
77
77
77
77
77
3.15 4.54 381 549 930 0700 121
4.50 4.54 544 549 1,093 1.000 121
6.21 4.54 751 549 1,300 1.380 121
7.55 4.54 913 549 1,463 1.680 121
8.90 4.54 1,076 549 1,625 1.980 121
1 Pump sue nominalx
engine-pumpx
pump (in.).
2 Illustrations
for smgle-pump
end.
double
available
onA.S,and0.
3. Types-
All
double-aclmg.
A Smgleseal,
internal
poning
B Multiple
seal,
external
porting
D Muliple
seal,
external
porting,
double
engine
E MuWe seal.
external
porting,
opposed
pistons
with
central
engine

TABLE 6.2~-RECIPROCATING PUMP SPECIFICATIONS, MANUFACTURER “8" (continued)
Pump
Type 0
27/,-h.
tubing
2% x l%-1%
2% x 1%1%
2% x 13/4-1'/2
x 1%
2% x 1%1% x l'h
2% x 1%-1%x 1%
3%-h tubing
3 x21/g-17/
3 x 21/8-21/s
3x2'/,-1',f0xX17/8
3x21/8-21/8x17/
3x 21/8-21/,x
2'/,
Type D
23/8-in.
tubing
2 x 13/,6X
13/&i%
2x13/16x13/s-13/
2x13/,~xl3/~-13/,~xl3/,~
2 x 13&jx 13/s-13/8
x 1%
2x13/l~x13/8-13/8x13/8
27/-in.
tubing
2% x 17/,6X
l%-1%
2% x 1%6 x 1%-l %
2'/2xl~,~x13/4-1'/2x1'/2
2%x1~,~x13/4-13/qx1%
2%x17/,~x13hx13/4
3Win. tubing
3 x 1% x 21/,-l%
3x 1% x 2'/*-2'/8
3xl3/4x2'/~-17/8x17/~
3Xl%X2'/&2'/8X17/
3 x 1% x 2'/8-2'/8
x 2'/8
Type E
23/,-in.
tubing
2x13/8
27/8-in.
tubing
2% x 1%
3%In. tubing
3x21/8
BID per strokes/min
Enqine
Pump
A
Pump Engine Total PIE
7.44 10.96
10.86 10.96
14.52 10.96
17.94 10.96
21.36 10.96
15.96 21.75
21.55 21.75
31.34 21.75
36.94 21.75
42.53 21.75
3.15 7.79
4.50 7.79
6.21 7.79
7.55 7.79
8.90 7.79
7.44 17.99
1086 17.99
14.52 17.99
1794 17.99
21.36 17.99
15.96 35.74
21.55 35.74
31.34 35.74
36.94 35.74
42.53 35.74
20.27 17.59
40.63 35.45
71.70 62.77
1 Pump sue nomlnalrenglne-pumpxpump (in )
2 Itiustrat~onsfor Sinale~DumD end, double wallable on A, 8. and D
Displacement
Rated Speed (BID)
744
1,086
1,452
1,794
2,136
100
100
100
100
100
1,388
1,875
2,726
3,214
3,700
1,096 1,840 0.685
1,096 2,182 1.000
1,096 2,548 1.336
1,096 2,890 1.652
1,096 3,232 1.957
1,892 3,280 0.740
1,892 3,787 1.000
1,892 4,618 1.454
1,892 5,106 1.714
1,892 5,592 1.974
87
87
87
87
87
381 943 1,324 0.407 121
544 943 1,487 0.581 121
751 943 1,694 0.802 121
914 943 1,857 0.976 121
1,076 943 2,019 1.150 121
744
1,086
1,452
1,794
2,136
1,799 2,543 0.411
1,799 2,885 0.608
1,799 3,251 0.813
1,799 3,593 0.976
1,799 3,935 1.196
3,109 4,497 0.449
3,109 4,983 0.606
3,109 5,835 0.882
3,109 6,322 1.039
3,109 6,809 1.197
100
100
100
100
100
1,388
1,874
2,726
3,213
3,700
87
87
87
87
87
1,317 1,143 2,454 1.152
2,092 4,491 1.146
3,515 7,522 1.142
65
2,400 59
4,007 56
Maximum Rated
Speed
(strokes/min)
3. Types All double-&g
A Sinale seal, internal portina
B Muliple seal, exlernil p&g
D. Mulbple seal, ewlernal porting, double engme.
E Mulbpte seal. external pottmg. opposed pistons with central engine

Type “A” Type “6” Type “D”
Fig. 6.16-Manufacturer “B” pump types forTable 6.2
er, as shown in Fig. 6.19, a force will have to be applied W=FL, .,,...,...........................(2)
to the plunger to resist the force exerted by the pressur-
ized fluid. A force of 1,000 lbf will be required to re-
strain a plunger whose cross-sectional area is 1 sq in. if
where W=work, in.-lbf, and L=distance, in.
the pressure in the cylinder is 1,000 psi.
If the plunger moves 12 in., it will do 12,000 in.-lbf
of work (or 1,000 ft-lbf of work). Because the plunger
F=pA, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...(I)
is moving at 1 in./sec. it will take 12 seconds to com-
plete its travel. Power is defined as the rate of doing work.
where
F = force, Ibf, P=Wit, . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
p = pressure, psi, and where
A = area, sq in. P = power, ft-lbfisec,
This is the condition of static equilibrium for the plunger
t = time, seconds, and
when all forces balance and no movement is taking place. W = work, ft-lbf.
Suppose next that a supply line is connected to the
blanked-off end of the cylinder, as shown in Fig. 6.20, In this example, the power is 1,000 ft-lbf of work in
and that a pump supplies fluid at a rate of 1 cu in.isec 12 seconds, or 83.3 ft-lbf/sec. Horsepower is defined as
while maintaining the pressure at 1,000 psi. This will 550 ft-lbf/sec (or 6,600 in.-lbf/sec), which means that the
cause the plunger to move in the cylinder at the constant horsepower of this system can be represented as
speed of I’in./sec against the 1,OO&lbf restraining force.
In this condition of dynamic equilibrium. work can be
done by the system because work is defined as force times
Ph’&, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...(4)
distance. where Ph =horsepower, hp.

TABLE 6.3~RECIPROCATING PUMP SPECIFICATIONS, MANUFACTURER “C”
Puma
PowerliftI
23/&in.
tubing
2 x 15/B
X 1'/,6
2X15/X1'/4
2 x 15/8
X 1%
2X15/8X15/8
2%-in. tubing
2%X2X1%
2'/2X2Xl'h
2%X2X15/&
2%X2X13/4
2%X2X2
2% x 15/e
x l'/,fj
2'/2
x 15/gx1'/4
2’/2 x 15/8x1%
2% x 15/gx15/8
21/2x IS/*xI'/,6
2% x 15/e
x 1%
2% x IS/,x1%
2% x 15/gx15/s
31/z-in.
iubing
3 x 2'h x 2%
3 x 2% x 2%
3x2%x2
3x2'/zxl%
PowerliftII
23/8-in.
tubing
2X1%6
2 x 1%
2x 1%
27/8-in.
tubing
2% x 1%
2’i2 x I'/4
2% x 1'h
Disolacement
B/D oer strokeslmin
Pump
6.45 15.08 225 528 753 0.52 35
8.92 15.08 312 528 840 0.72 35
11.96 14.03 478 561 1,039 1.16 40
14.03 14.03 561 561 1,122 1.36 40
12.02
17.30
20.30
23.60
30.80
6.45
8.92
12.85
15.08
8.69
12.02
17.03
20.30
43.71 43.71 1,311 1,311 2,622 1.21 30
35.41 43.71 1,062 1,311 2,373 0.98 30
27.98 43.71 840 1,311 2,151 0.77 30
21.42 43.71 643 1,311 1,954 0.59 30
5.53 12.10 597 1,307 1,904 0.524 108
7.65 12.10 826 1,307 2,133 0.725 108
30.00 26.35 1,560 1,370 2.930 1.147 52
12.59 17.69 1,322 1,857 3,179 0.725 105
8.74 17.69 918 1,857 2,775 0.503 105
50.00 43.97 2,500 2,199 4,699 1.146 50
Engine
Rated Speed (B/D)
Pumo Enaine Total PIE
30.80 264
30.80 467
30.80 547
30.80 826
30.80 1,078
15.08 225
15.08 312
15.08 450
15.08 528
20.30 234
20.30 325
20.30 467
20.30 547
678 942 0.44
832 1,299 0.68
832 1,379 0.80
1,078 1,904 1.06
1,078 2,156 1.38
528 753 0.52
528 840 0.72
528 978 1.03
528 1,056 1.21
548 782 0.52
548 873 0.72
548 1,015 1.03
548 1.095 1.21
Maximum Rated
Speed
(strokes/min)
22
27
27
35
35
35
35
35
35
27
27
27
27
In our example, 83.3 ft-lbf/sec corresponds to 0.15 hp.
If we were to supply the pressurized fluid at 2 cu in./sec,
the plunger would move the 12 in. in 6 seconds. The work
done would be the same, but because it would be done
in half the time. the hp would be twice as great.
Note that we have interpreted the hp in terms of the
work done through the plunger per unit time. This power
is supplied by the pump pressurizing the fluid. The plunger
transforms the fluid power to mechanical. This is the ac-
tion of a hydraulic motor. The hydraulic equivalent of 0. I5
hp is a flow rate of 1 cu in./sec at 1,000 psi. If the flow
rate in cubic inches per second is multiplied by the pres-
sure in pounds force per square inch, the product will have
units of inch-pounds per second, which are the dimen-
sions of power. Conversion of units will show that 1 cu
in./sec is the same as 8.905 B/D. If 8.905 B/D at 1,000
psi is 0. IS hp. it follows that
P,,=yxpx0.000017; (5)
where q=flow rate, B/D, and p-pressure, psi.
Eq. 5 shows that the same power can be obtained with
high flow rates at low pressure, or with lower flow rates
at a higher pressure. This is a very useful feature of
hydraulic power transmission. Only the flow rate and the
pressure enter into this relationship; the density, or spe-
cific gravity, of the fluid does not.
The process described can be reversed. A force of 1,000
lbf applied to the plunger in Fig. 6.20 can force fluid out
of the line at a pressure of 1,000 psi. In this case, the
mechanical power of the plunger would be transformed
into fluid power as it is done in pumps.
A useful consequence of the relationship expressed in
Eq. 1 is demonstrated in Fig. 6.21. Two plungers of
different diameters are connected together by a rod. The
section of the assembly occupied by the connecting rod
is vented to the atmosphere. The face area of the larger
plunger is 2 sq in. and the face of the smaller plunger
is I sq in. Fluid at l,OOO-psi pressure is supplied to the
cylinder that contains the larger plunger. This causes the
plunger to push through the rod and against the smaller
plunger with a force of 2,000 lbf. To restrain the motion
of the rod-and-plunger system, an opposing force of 2,000

TABLE 6.4--RECIPROCATING PUMP SPECIFICATIONS, MANUFACTURER “D”
Displacement
BIDper strokes/min Rated Speed (B/D)
Maximum Rated
SDeed
Total PIE (strokeslmin)
Engine
Pump Engine Pump
Pump
900 Series
23/-in.
tubing
2x 1%
2x 1%6
2 x 1%
2 x l'h
3.5 6.65 95 180 275 0.66 27
7.0 13.30 189 359 548 0.66 27
9.6 13.30 259 359 618 0.93 27
13.8 13.30 372 359 731 1.33 27
2y8-in.tubing
2'/2
x l’h6
2% x 1'/j6
2% x 1%
2x! x 1'/2
2'/2
x 1%
2% x 2
3.5 10.6 95 266 381 0.43 27
7.0 21.2 189 572 761 0.43 27
9.5 21.2 256 572 828 0.58 27
13.7 21.2 370 572 942 0.83 27
18.6 21.2 502 572 1,074 1.13 27
24.2 21.2 654 572 1,226 1.47 27
3Win. tubing
3 x 1%
3x1%
3x2
3 x 2%
3 x 2%
4Win. tubing
4x2s
4~2%
4 x3%
924 Series
2%~in. tubing
7045-92-4210
7065-92-4210
7100-92-4210
15.5 36.1 419 975 1,394 0.53 27
36.1 570 975 1,545 0.72 27
36.1 743 975 1,718 0.94 27
36.1 940 975 1,915 1.20 27
36.1 1,160 975 2,135 1.47 27
21.1
27.5
34.8
43.0
34.8 63.5 940 1.715 2,655 0.68 27
52.0 63.5 1,404 1,715 3,119 1.01 27
72.6 63.5 1,960 1,715 3,675 1.41 27
4.7 7.25 287 442 729 0.65 61
9.4 14.5 574 885 1,459 0.65 61
14.5 14.5 885 885 1,770 1.00 61
Notes Pump SIX 900 Sews-nominal x pump plunger
diameter
Types 900-Smgle-seal, single-aclmg. Internal-portmg.
924-Single-seal. dO”bbact,ng, Internal-parling.
Ibf must be applied to the smaller plunger. This can be
accomplished with fluid in the smaller cylinder at 2.000
psi, If these pressures are maintained and fluid is sup-
plied to the larger cylinder at a constant rate, the rod-and-
plunger system will move to the right at a constant rate.
Fluid will be forced out of the smaller cylinder at half
the rate it is supplied to the larger cylinder, but with twice
the pressure. This hydraulic transformer process is rever-
siblc. which would entail supplying 2,(M)-psi fluid to the
smaller cylinder to make I.OOO-psifluid flow out of the
larger cylinder at twice the tlow rate supplied to the
smaller cylinder. In either case, the input and output
horsepowers are the same because no losses have been
considered.
The characteristics of such a rod-and-plunger system
can be used to advantage in hydraulic pumps. In shallow
wells where the pressure requirements of the pump arc
low. a large pump plunger can be used in conjunction with
a small engine piston without requiring cxccssivcly high
prcsaurcs to be supplied to the engine. In deeper wells,
where the discharge pressure of the pump will be high,
a small pump plunger is used in conjunction with a large
engine piston to reduce the power-fluid pressure require-
ment. The smaller pump plunger will, howev,cr. produce
less fluid at the same stroking rate than the larger pump
plunger. Hydraulic pump manufacturers otter a variety
of engine and pump combinations to meet the require-
ments of different flow rates and depth settings (see ex-
amples in Tables 6.1 through 6.4).
Pressures and Force Balance in Downhole Pumps
By looking at the pressures and forces in a downhole
hydraulic pump, a generalized equation can be developed
to predict the operating pressure required in a particular
well. Two pumps are analyzed to show the generality of
the solution. Fig. 6.22 shows a double-acting pump with
the various areas identified and the pressures labeled for
upstroke and downstroke conditions. In this design. both
the upper and lower rods are exposed to the power-fluid
pressure, pi,/. At the beginning and end of each half-
stroke, brief periods of decclcration and acceleration
occur, but the majority of the stroke is at constant veloci-
ty. For the constant-velocity condition. the sum of the
forces acting downward must equal the sum of the forces
acting upward. In the cast of a downstroke, the down-
ward forces arc
Fc/ =~,yAcr +P,>#,,, -A,., 1+p,,.,(A,,,, -A,,,), (6)

Powerlift
I Powerlift
II
Fig. 6.17-Manufacturer “C” pump types forTable 6.3
where
F,, = downward force, Ibf,
P,]~ = power-fluid pressure, psi,
A<‘r-
- cross-sectional area of engine rod, sq in.,
AL’,’= cross-sectional area of engine piston.
sq in.,
PP> = pump suction pressure, psi,
A PP = cross-sectional area of pump plunger,
sq in., and
AP’ = cross-sectional area of pump rod, sq in.
The upward forces are
where
F,, = upward force, Ibf,
pcl/ = engine discharge pressure, psi, and
p,,‘l = pump discharge pressure. psi.
900 Series
Fig. &la-Manufacturer “D” pump types forTable 6.4
924 Series
Equating the upward and downward forces and solving
for the power-fluid pressure at the pump gives
P,,~=P<,<I
+P~JA,,~ -A,rY(A,, -A,,.)
-p,u(A, -A,,Y(A, -A<,,). . .(8)
If PPCi
=pF/, as is the case in open power-fluid systems,
then
~,>t.=~,d’ +(A, -A,,V(*,,,, -*,,)I
-P,JA, -A,,V(A, -A,,). .(9)
Eq. 8 can also be written as
P/~=P~,~/+(P~~-P,,~)[(A,,~ -A,,V(A, -Aw)l.
. . . . . . . . . . . . . . . . . . . . . ..__.. (10)

-Force : lb
/
L Area of face of plunger : I in2
f!Fluid pressure = 1000 psi i Fluid pressure : 1000 psi
Fig. 6.19-Pressure and force ina static
plunger and cylinder
assembly.
Fig. 6.20-Pressure, force,and flow ina dynamic plunger and
cylinderassembly.
The same analysis for the upstroke would give the same
answer because this double-acting pump is completely
symmetrical.
Fig. 6.23 shows a balanced downhole unit with a single-
acting pump end. First, for the downstroke. the down-
ward forces are
F,I =P,>~(A,,J +p,,, (A,,,, -A,,), __, .(]I)
and the upward forces arc
F,, =P,,/(A,,, -A,,-) +/~,,/(A,,. -AP’.)+p,dA,,,‘)
. . . . . . . . . . . . . . . . . . . . . . . . . . (12)
In this pump. the areas of the engine and pump rods are
half that of their respective pistons and plungers:
A,,.=A,,/2 . . ..(13)
and
A,],.=A,,,J2. (14)
Equating the upward and downward forces, substituting
Eqs. 13 and 14, and solving for the power-fluid pressure.
P,,/ 8 g*ves
~,,~=~,dl +A,~,,IA,)-p,,,(A,,IA,). (15)
Evaluating the force balance for the upstroke gives
F,/ =P c,r/
(Ac,>
)i-p,> (A,,,I-A,,.) _. (16)
and
..,....,,....,,,,.,.,.,.,,, (17)
Eqs. 13. 14, 16, and 17 give
~pr = 21’,></
-p,d 1-A ,,,I/A e,,)-I’,” (A,,, /Ac/l). (18)
Note that if prcf =ppn, which is the case in an open
power-fluid installation, Eqs. 1.5and 18 become the same:
p,,/=~,x/(l +A,/*,,,)-p,,,,(A,,,,IA,). .(19)
Eq. 19 for the single-acting pump shown in Fig. 6.23 can
be made identical to Eq. 9 for the double-acting pump
shown in Fig. 6.22 by observing that, because of Eqs.
13 and 14,
A,/A, =(A,,,, -A,,)/(A, -A,,). . (20)
Because it appears frequently in pressure calculations
with hydraulic pumps, the term (A,,p -A,,,.)/(A,,,l -A,,)
is frequently simplified to P/E. This is sometimes called
the “P over E ratio” of the pump and is the ratio of the
net area of the pump plunger to the net area of the engine
piston. With this nomenclature. Eq. 8 for a closed power-
fluid installation becomes
P/f=Ped +p~d(PIE)-p,,,~(PIE), (21)
where PIE=(A, -*,,.)/(A, -A,,.).
Eq. 9 for an open power-fluid installation becomes
~,,~=p,,(,[ 1+ (PIE)] -pps(PIE). . . (22)
This approach has found widespread acceptance among
the manufacturers of downhole pumps, and the ratio P/E
is included in all their pump specifications (see examples
in Tables 6.1 through 6.4).
P/E values greater than 1.Oindicate that a pump plunger
is larger than the engine piston. This would be appropri-
ate for shallow, low-lift wells. P/E values less than 1.0
are typical of pumps used in deeper. higher-lift wells. In
some pumps, the P/E value is also the ratio of pump dis-
placement to engine displacement, but corrections for fluid

Eischarge f IbId
press,re : 2000 PSI
Area of
plLnger face = 2 In*
Area of
plL;nger face: I in’
Discharge flow rate : I/Z %pply flow rate
Discharge fIbid pressure : Twice supply fILid pressure
Fig. 6.21-Pressures, forces,and flows in a hydraulictransformer
volumes to actuate engine valves and corrections for dis-
placement volumes on the unloaded half-stroke of some
single-acting pumps are necessary. Reference to specific
displacement values for the engine and pump ensures
proper determination of the respective flow rates.
Fluid Friction and Mechanical
Losses in Hydraulic Pumps
In deriving Eqs. 9 and 19, we assume there are no fluid
friction or mechanical losses. In practice, to maintain the
stroking action of the pump. an additional pressure over
and above the values for p,,f calculated with these equa-
tions is required. The largest portion of this extra pres-
sure is a result of fluid-friction losses in the engine and
pump. Because higher stroking rates require higher fluid
velocities, this friction loss increases as the pump speed
increases. Because of the effect of approximately constant
dead times for the pump reversals, the rate of increase
in pump friction with respect to increases in stroking rate
tends to be higher than expected from simple pipe fric-
tion calculations based on average velocities. It has been
found through testing that, for a given pump, the friction
pressure can be represented by
pf,.=50eK(N’Nn,,,), . (23)
where
pfr = friction pressure, psi,
K = experimentally determined constant for the
particular pump,
N = pump operating rate, strokesimin., and
Nmax = rated maximum pump operating rate.
strokesimin.
Note that the pfri,,,,,,) is 50 psi, which occurs at zero
strokes per minute. The value of P.~,.~,,,~~,
occurs when
N=N,,, and is
~/j.(,,,~~)
=50fK, . . .(24)
where P,-,.(~~~)
=maximum friction pressure, psi.
The value of pfrcmdx) usually falls between 500 and
1.250 psi. depending on the particular pump.
If the manufacturers’ reported values for pfrcmaxj for
each of their pumps are plotted vs. the maximum total
flow rate of the engine and pump ends for the units. a
correlation becomes apparent. For pumps designed to fit
in a specific size of tubing string, the value of P,,-,,,,~~,
increases with the maximum rated total fluid through the
engine and pump ends. The form of the equation that gives
a good fit is
p,Mmaxj=A&,,,, . . (25)
Here A and B are constants that depend on the tubing
size for which the pump is designed. and LJ,,,,is the max-
imum rated total flow through the engine and pump of
a particular unit.
Eqs. 24 and 25 can be used to determine the value of
K, which can then be substituted into Eq. 23 to give
p/,. =50(AeB4~~”
/50)N’N”~‘~~
. . (26)
The value of A in Eq. 26 is the same for all sizes of
tubing-i.e.. A=355. Eq. 26 can therefore be written as
pfr =50(7. leBY~~~I
)N’Nmdr
. (27)
The values for B for different sizes of tubing are given
in Table 6.5.

6-20 PETROLEUM ENGINEER!NG HANDBOOK
Pressure
Downstroke
Fig. 6.22-Pressures actingon a double-acting downhole unit.
Eq. 27 is based on data accumulated from laboratory
tests on water or on light test oils with viscosities less than
10 cSt and corrected to water properties. Because 75 to
80% of the losses are in the engine end of the downhole
unit, specific gravity and viscosity corrections are neces-
sary for different power fluids. To correct for density
differences, the value of pk should be multiplied by the
specific gravity of the power fluid, y. A multiplying fac-
tor, F,, , which corrects for different viscosities, is given
by
F,.=vpf./100+0.99, . . . . . . . . . . . . . . . . . . . . . ..(28)
where ~,,f=power-fluid viscosity, cSt.
With both of these corrections, Eq. 27 becomes
P~~=~F(~O)(~.~~~Y~~I)~'~I,I,,. . . . . . . . . . . . . ..(29)
Curves plotted from Eq. 29 are shown in Fig. 6.24.
The specific gravity of different API-gravity crudes can
be determined from Table 6.6. Fig. 6.25 gives the vis-
cosity of a variety of crudes as a function of temperature,
and Fig. 6.26 gives the viscosity of water as a function
of temperature with varying salt concentrations.
TABLE 6.5-TUBING
SIZE VS. CONSTANT B
Tubing Size
(in.) B
2% 0.000514
2% 0.000278
3% 0.000167
4% 0.000078
Fig. 6.23-Pressures actingon a single-acting
downhole unit.
Example Problem 1. Consider Manufacturer B’s Type
D pump-double engine, single pump end-for which the
specifications are in Table 6.2. For the 2 % x 1x6 x 1% -
1% size unit for 2 s-in. tubing, the maximum rated en-
gine flow rate is 1,799 B/D and the rated displacement
of the pump end is 1,086 B/D for a total of 2,885 BID.
At rated speed of 100 strokes/min and using water pow-
er fluid with a specific gravity of 1.O and a viscosity of
1 cSt, Eq. 29 gives
If the pump speed is reduced to 60 strokes/min,
~f~=5~[7,1e(0.~0278)(2X85)160!100=2
psi,
These examples are shown in Fig. 6.24.
With this same unit. if the 1%-in. pump end is fitted,
or if gas interference reduces the pump end volumetric
efficiency of the 1X-in. pump end to 69 %. the maximum
rated flow through the pump end will be 744 B/D instead
of 1,086 B/D, and the total flow will be reduced to 2,543
BID. At rated speed, the friction pressure loss will then be
If a 0.9-specific-gravity power fluid that has a viscosity
of 10 cSt at bottomhole conditions was used in the last
example, then
=706 psi.

HYDRAULIC
PUMPING 6-21
Fig. 6.24-Friction and mechanical loss in downhole pumps
(specific gravity= 1.O,viscosity= 1.OcSt).
Displacement of Downhole Pumps
Downhole pumps are normally rated by their theoretical
displacement per stroke per minute on both the engine
and pump ends. The theoretical displacement is the net
area of the plunger times the distance traveled in a working
stroke. There is also a maxlmum rated speed for each
pump. Because of the tendency of inconsistent engine
valve operation at very low stroking rates. and because
of shorter pump life at very high stroking rates, down-
hole units are normally chosen to operate between 20 and
80% of their rated maximum speed. Choosing a pump
that will meet the displacement requirements of a well at
less than rated speed allows for later speed incrcascs to
offset normal pump wear. New engine efficiencies of
about 9.5% may decline to 80% with wear. A value of
90% is often used for design purposes. New pump end
efficiencies arc typically high, but a worn pump end may
have a volumetric efficiency as low as 70%. The specifi-
cations for downhole pumps from some ma.jor manufac-
turers are given in Tables 6. I through 6.4. There are no
API standards for hydraulic pumps. Consequently, there
is considerable variation in designs. sizes. stroke lengths.
and rated speeds. and parts are not interchangeable be-
tween brands.
At bottomhole conditions, however, the oil, water, and
gas phases occupy different volumes than on the surface
where flow measurements are made. Vented systems will
allow significant portions of the free gas to vent to the
surface. while unvented systems route all the free gas
through the pump. The volume occupied by the free gas
and the downhole volume of the oil with gas dissolved
in it dcpcnd on several factors, including the crude gravity,
gas gravity. temperature. and pressure.
The term “gas interference” has been used to describe
the phenomenon of greatly reduced actual fluid displace-
ment when gas and liquid phases are pumped at the same
time, The gassy tluid is drawn into the pump suction at
a low pressure and is discharged from the exhaust at a
high pressure. The pump plunger. however. does not com-
plctcly purge the pump barrel of fluid because of practi-
cal design and manufacturing considerations. The unswept
volume is called the clearance volume. The clearance
volume contains liquid and gas at pump discharge prcs-
sure at the end of the discharge stroke. As the plunger
reverses and moves in the suction stroke, the clearance-
volume gas expands and its pressure declines. The suc-
tion valving will not open until the clearance-volume gas
pressure drops below pump intake pressure. This phenom-
enon clearly reduces the effective stroke length of the
pump, and in severe cases, the suction valves will not open
for one or more pump cycles. This extreme case is re-
ferred to as “gas locking.”
Hydraulic pumps usually have small clearance volumes
because the engine and pump ends are very closely cou-
pled, and control of stroke length is precise. Also, gradual
leakage of power fluid or pump discharge fluid back into
the pump barrel will eventually help purge clearance-
volume gas, Specially designed discharge valve seats
called “gas lock breakers” can be used to preclude gas
lock by allowing a controlled leakage back into the pump
barrel during the suction stroke. For these reasons, it is
uncommon for hydraulic pumps to actually “gas lock,”
but the volumetric efficiency of the pump end is always
reduced by the presence of gas. Even if the gas is all in
solution, as when pumping above the bubblepoint of the
crude, the liquid phase will occupy more volume down-
hole than it does in the stock tank because of dissolved
gas. and this reduces the effcctivc pump end volumetric
efficiency.
Fig. 6.27. based on relationships from Standing’ and
API Manual 14 BN, ” gives a means for determining the
maximum volumetric efficiency of a pump from consid-
erations of liquid- and gas-phase volumes. The equations
used to generate Fig. 6.27 are listed in Appendix A. The
gas interference effect depends on the compression ratio
of the particular unit and will change with plunger size.
It also depends on the ratio of intake to discharge pres-
sure and whether the pump barrel is discharged at the top
or the bottom. The magnitude of the gas interference cf-
feet is not well documented for all units. Therefore. it
is common practice to assume that this effect and normal
fluid leakage past tits reduces the displacement of the
pump end to about 85% of the manufacturers’ ratings.
The pump suction rate is then
Y =4,~~~,,,,,~ E
,Nrn‘iX, 00)
,I(,,‘,, _

TABLE &L-SPECIFIC GRAVITIES AND UNIT PRESSURE OF FLUID COLUMNS*
Degrees
API 0.1 0.6 0.7 0.9
0
1.0000
0.4331
0.9930
0.4301
0.9861
0.4271
0.9792
0.4241
0.9725
0.4212
0.9659
0.2 0.3 0.4 0.5
0.9986 0.9979 0.9972 0.9965
0.4325 0.4322 0.4319 0.4316
0.9916 0.9909 0.9902 0.9895
0.4295 0.4292 0.4289 0.4286
0.9847 0.9840 0.9833 0.9826
0.4265 0.4262 0.4259 0.4256
0.9779 0.9772 0.9765 0.9759
0.4235 0.4232 0.4229 0.4226
0.9712 0.9705 0.9698 0.9692
0.4206 0.4203 0.4200 0.4198
0.9646 0.9639 0.9632 0.9626
0.8
0.9944
0.4307
0.9874
0.4276
0.9806
0.4247
0.9738
0.4218
0.9672
0.4189
0.9606
10
11
0.9993
0.4328
0.9923
0.4298
0.9854
0.4268
0.9786
0.4238
0.9718
0.4209
0.9652
0.9958 0.9951
0.4313 0.4310
0.9888 0.9881
0.4282 0.4279
0.9820 0.9813
0.4253 0.4250
0.9752 0.9745
0.4224 0.4221
0.9685 0.9679
0.4195 0.4192
0.9619 0.9613
0.9937
04304
0.9868
0.4274
0.9799
0.4244
0.9732
0.4215
0.9665
0.4186
0.9600
12
13
14
15
16
17
0.4183 0.4180 0.4178 0.4175 0.4172 0.4169 0.4166 0.4163 0.4160 0.4158
0.9593 0.9587 0.9580 0.9574 0.9567 0.9561 0.9554 0.9548 0.9541 0.9535
0.4155 0.4152 0.4149 0.4146 0.4143 0.4141 0.4138 0.4135 0.4132 0.4130
0.9529 0.9522 0.9516 0.9509 0.9503 0.9497 0.9490 0.9484 0.9478 0.9471
0.4127 0.4124 0.4121 0.4116 0.4116 0.4113 0.4110 0.4106 0.4105 0.4102
0.9465 0.9459 0.9452 0.9446 0.9440 0.9433 0.9427 0.9421 0.9415 0.9408
0.4099 0.4097 0.4094 0.4091 0.4088 0.4085 0.4083 0.4080 0.4078 0.4075
0.9402 0.9396 0.9390 0.9383 0.9377 0.9371 0.9365 0.9358 0.9352 0.9346
0.4072 0.4069 0.4067 0.4064 0.4061 0.4059 0.4056 0.4053 0.4050 0.4048
0.9340 0.9334 0.9328 0.9321 0.9315 0.9309 0.9303 0.9297 0.9291 0.9285
0.4045 0.4043 0.4040 0.4037 0.4034 0.4032 0.4029 0.4027 0.4024 0.4021
18
19
20
0.9273 0.9267 0.9260 0.9254 0.9248 0.9242 0.9236 0.9230 0.9224
0.4016 0.4014 0.4011 0.4008 0.4005 0.4003 0.4000 0.3998 0.3995
0.9212 0.9206 0.9200 0.9194 0.9188 0.9182 0.9176 0.9170 0.9165
0.3990 0.3987 0.3985 0.3982 0.3979 0.3977 0.3974 0.3972 0.3969
0.9153 0.9147 0.9141 0.9135 0.9129 0.9123 0.9117 0.9111 0.9106
0.3964 0.3962 0.3959 0.3956 0.3954 0.3951 0.3949 0.3946 0.3944
0.9094 0.9088 0.9082 0.9076 0.9071 0.9065 0.9059 0.9053 0.9047
0.3939 0.3936 0.3933 0.3931 0.3929 0.3926 0.3923 0.3921 0.3918
0.9036 0.9030 0.9024 0.9018 0.9013 0.9007 0.9001 0.8996 0.8990
0.3913 0.3911 0.3908 0.3906 0.3904 0.3901 0.3898 0.3896 0 3894
0.8978 0.8973 0.8967 0.8961 0.8956 0.8950 0.8944
0.3888 0.3886 0.3884 0.3881 0.3879 0.3876 0.3874
0.8922 0.8916 0.8911 0.8905 0.8899 0.8894 0.8888
0.3864 0.3862 0.3859 0.3857 0.3854 0.3852 0.3849
0.8866 0.8860 0.8855 0.8849 0.8844 0.8838 0.8833
0.3840 0.3837 0.3835 0.3833 0.3830 0.3828 0.3826
0.8811 0.8805 0.8800 0.8794 0.8789 0.8783 0.8778
0.3816 0.3813 0.3811 0.3809 0.3807 0.3804 0.3802
0.8756 0.8751 0.8745 0.8740 0.8735 0.8729 0.8724
0.3792 0.3790 0.3787 0.3785 0.3783 0.3781 0.3778
0.8939 0.8933
0.3871 03869
0.8883 0.8877
0.3847 0.3845
0.8827 0.8822
0.3823 0.3821
0.8772 0.8767
0.3799 0.3797
0.8718 0.8713
0.3776 0.3774
21
0.9279
0.4019
22
0.9218
0.3992
23
0.9159
0.3967
24
0.9100
0.3941
25
0.9042
0.3916
26
0.8984
0.3891
27
0.8927
0.3866
28
0.8871
0.3842
29
0.8816
0.3818
30
0.8762
0.3795
31
0.8708 0.8702
0.3771 0.3769
32
0.8654 0.8649
0.3748 0.3746
33
0.8602 0.8597
0.3726 0.3723
34
0.8550 0.8545
0.3703 0.3701
35
0.8498 0.8493
0.3680 0.3678
0.8697 0.8692 0.8686 0.8681 0.8676 0.8670 0.8665 0.8660
0.3767 0.3765 0.3762 0.3760 0.3758 0.3755 0.3753 0.3751
0.8644 0.8639 0.8633 0.8628 0.8623 0.8618 0.8612 0.8607
0.3744 0.3742 0.3739 0.3737 0.3735 0.3732 0.3730 0.3728
0.8591 0.8586 0.8581 0.8576 0.8571 0.8565 0.8560 0.8555
0.3721 0.3719 0.3716 0.3714 0.3712 0.3710 0.3707 0.3705
0.8540 0.8534 0.8529 0.8524 0.8519 0.8514 0.8509 0.8504
0.3699 0.3696 0.3694 0.3692 0.3690 0.3687 0.3685 0.3683
0.8488 0.8483 0.8478 0.8473 0.8468 0.8463 0.8458 0.8453
0.3676 0.3674 0.3672 0.3670 0.3667 0.3665 0.3663 0.3661
,,fy at 60°F.

TABLE 6.6--SPECIFIC GRAVITIES AND UNIT PRESSURE OF FLUID COLUMNS’ (continued)
API 0
36
0.8448
0.3659
37
0.8398
0.3637
38
0.8348
0.3616
39
0.8299
0.3594
40
0.8251
0.3574
41
0.8203
0.3553
42
0.8155
0.3532
43
0.8109
0.3512
44
0.8063
0.3492
45
0.8017
0.3472
46
0.7972
0.3453
47
0.7927
0.3433
48
0.7883
0.3414
49
0.7839
0.3395
50
0.7796
0.3376
51
52
53
54
55
56
57
58
59
60
0.7753
0.3358
0.7711
0.3340
0.7669
0.3321
0.7628
0.3304
0.7587
0.3286
0.7547 0.7543 0.7539 0.7535 0.7531 0.7527 0.7523 0.7519 0.7515 0.7511
0.3269 0.3267 0.3265 0.3263 0.3262 0.3260 0.3258 0.3256 0.3255 0.3253
0.7507 0.7503 0.7499 0.7495 0.7491 0.7487 0.7483 0.7479 0.7475 0.7471
0.3251 0.3250 0.3248 0.3246 0.3244 0.3243 0.3241 0.3239 0.3237 0.3236
0.7467 0.7463 0.7459 0.7455 0.7451 0.7447 0.7443 0.7440 0.7436 0.7432
0.3234 0.3232 03230 0.3229 0.3227 0.3225 0.3224 0.3222 0.3221 0.3219
0.7428 0.7424 0.7420 0.7416 0.7412 0.7408 0.7405 0.7401 0.7397 0.7393
0.3217 0.3215 0.3214 0.3212 0.3210 0.3208 0.3207 0.3205 0.3204 0.3202
0.7389 0.7385 0.7381 0.7377 0.7374 0.7370 0.7366 0.7362 0.7358 0.7354
0.3200 0.3198 0.3197 0.3195 0.3194 0.3192 0.3190 0.3188 0.3187 0.3185
0.1 0.2 0.3 0.4 0.5 0.6
0.8443 0.8438 0.8433 0.8428 0.8423 0.8418
0.3657 0.3654 0.3652 0.3650 0.3648 0.3646
0.8393 0.8388 0.8383 0.8378 0.8373 0.8368
0.3635 0.3633 0.3631 0.3629 0.3626 0.3624
0.8343 0.8338 0.8333 0.8328 0.8324 0.8319
0.3613 0.3611 0.3609 0.3607 0.3605 0.3603
0.8294 0.8289 0.8285 0.8280 0.8275 0.8270
0.3592 0.3590 0.3588 0.3586 0.3584 0.3582
0.8246 0.8241 0.8236 0.8232 0.8227 0.8222
0.3571 0.3569 0.3567 0.3565 0.3563 0.3561
0.8198
0.3551
0.8151
0.3530
0.8104
0.3510
0.8058
0.3490
0.8012
0.3470
0.8193
0.3546
0.8146
0.3528
0.8100
0.3508
0.8054
0.3488
0.8008
0.3468
0.8189 0.8184 0.8179 0.8174 0.8170
0.3547 0.3544 0.3542 0.3540 0.3538
0.8142 0.8137 0.8132 0.8128 0.8123
0.3526 0.3524 0.3522 0.3520 0.3518
0.8095 0.8090 0.8086 0.8081 0.8076
0.3506 0.3504 0.3502 0.3500 0.3498
0.8049 0.8044 0.8040 0.8035 0.8031
0.3486 0.3484 0.3482 0.3480 0.3478
0.8003 0.7999 0.7994 0.7990 0.7985
0.3466 0.3464 0.3462 0.3460 0.3456
0.7967 0.7963 0.7958 0.7954 0.7949 0.7945 0.7941 0.7936 0.7932
0.3451 0.3449 0.3447 0.3445 0.3443 0.3441 0.3439 0.3437 0.3435
0.7923 0.7918 0.7914 0.7909 0.7905 0.7901 0.7896 0.7892 0.7887
0.3431 0.3429 0.3426 0.3425 0.3424 0.3422 0.3420 0.3918 0.3416
0.7879 0.7874 0.7870 0.7865 0.7861 0.7857 0.7852 0.7848 0.7844
0.3412 0.3410 0.3408 0.3406 0.3405 0.3403 0.3401 0.3399 0.3397
0.7835 0.7831 0.7826 0.7822 0.7818 0.7813 0.7809 0.7805 0.7800
0.3393 0.3392 0.3389 0.3388 0.3386 0.3384 0.3382 0.3380 0.3378
0.7792 0.7788 0.7783 0.7779 0.7775 0.7770 0.7766 0.7762 0.7758
0.3375 0.3373 0.3371 0.3369 0.3367 0.3365 0.3363 0.3362 0.3360
0.7749 0.7745 0.7741 0.7736 0.7732 0.7728
0.3356 0.3354 0.3353 0.3350 0.3349 0.3347
0.7707 0.7703 0.7699 0.7694 0.7890 0.7686
0.3338 0.3336 0.3334 0.3332 0.3331 0.3329
0.7665 0.7661 0.7657 0.7653 0.7649 0.7645
0.3320 0.3318 0.3316 0.3315 0.3313 0.3311
0.7624 0.7620 0.7616 0.7612 0.7608 0.7603
0.3302 0.3300 0.3298 0.3297 0.3295 0.3293
0.7583 0.7579 0.7575 0.7571 0.7567 0.7563
0.3284 0.3282 0.3281 0.3279 0.3277 0.3276
0.7 0.8 0.9
0.8413 0.8408 0.8403
0.3644 0.3642 0.3639
0.8363 0.8358 0.8353
0.3622 0.3620 0.3618
0.8314 0.8309 0.8304
0.3601 0.3599 0.3596
0.8265 0.8260 0.8256
0.3580 0.3577 0.3576
0.8217 0.8212 0.8208
0.3559 0.3557 0.3555
0.8165
0.3536
0.8118
0.3516
0.8072
0.3496
0.8026
0.3476
0.8160
0.3534
0.8114
0.3514
0.8067
0.3494
0.8022
0.3474
0.7981 0.7976
0.3457 0.3554
0.7724 0.7720
0.3345 0.3344
0.7682 0.7678
0.3327 0.3325
0.7640 0.7636
0.3309 0.3307
0.7599 0.7595
0.3291 0.3289
0.7559 0.7555 0.7551
0.3274 0.3272 0.3270
0.7715
0.3341
0.7674
0.3324
0.7632
0.3305
0.7591
0.3288

Fig. 6.25-Viscosity of oils.
The pump displacement required to achieve a desired
pump suction rate is therefore
qp =4sl[NINmaxEp(max)Ep(i”l)l, . . . . (31)
where
qs = pump suction rate, B/D,
qp = rated pump displacement, B/D,
ENmx) = maximum pump efficiency from Fig.
6.27, fraction, and
Ep(int) = pump efficiency for gas interference and
pump leakage (normally =0.85),
fraction.
Example Problem 2. Consider a case where one desires
to produce 250 B/D of 35”API crude at a pump intake
pressure of 500 psi. The gas/oil ratio (GOR) is 500 : 1and
the water cut is 40%. Fig. 6.27 gives 41% theoretical
volumetric efficiency. The required pump displacement
at 80% of rated speed is therefore given by
qp =250/(0.8x0.41 x0.85)=897 B/D.
When the maximum volumetric efficiency from Fig.
6.27 is below about SO%, an installation design that in-
Fig. 6.26-How temperature affectsviscosityofsalt
water(these
curves indicate
the effect
of temperature on viscose-
tyof saltwater solutions
ofvariousconcentrations).
eludes the extra cost and complexity of a gas vent should
be considered. A number of factors affect the perform-
ance of gas-vent systems. However, the saturated oil-
volume line in Fig. 6.27 (the upper boundary of the down-
hole shaded area) can be used to account for the increased
downhole volume of the oil caused by gas that remains
in solution. In the previous example, saturated oil at 500
psi has a downhole volume that gives a maximum pump
efficiency of 95% when calculated on surface volume
where the solution gas has been liberated. The required
pump displacement at 80% of rated speed is therefore
given by
q,=250/(0.8x0.92x0.85)=400 B/D.
System Pressures and Losses in
Hydraulic Installations
The flow of fluid power in a hydraulic pumping system
starts with the high-pressure pump on the surface. The
power fluid passes through a wellhead control valve and
down the power-fluid tubing string. The power-fluid pres-
sure increases with depth because of the increasing hydro-
static head of fluid in the tubing. At the same time, some

of the power-fluid pressure is lost to fluid friction in the
tubing string. At the pump, most of the power-fluid pres-
sure is available for work in driving the downhole unit.
with the remainder lost in the friction pressure, pfr. Af-
ter the downhole unit is operated. the power fluid must
return to the surface. The pressure of the power fluid leav-
ing the downhole unit depends on the hydrostatic head
of fluid in the return tubing above the pump. In addition
to this pressure, the fluid friction pressure lost in getting
to the surface and the backpressure at the wellhead must
be considered. In an open power-fluid system, the pro-
duced fluid from the well will leave the downhole unit
and mix with the exhaust power fluid, thereby encoun-
tering the same pressure environment as the power fluid.
In a closed power-fluid system, the production will have
its own unique hydrostatic head, friction pressure loss,
and wellhead or flowline backpressure. In both cases, the
pump suction will be at a pump intake pressure from the
well that will vary with the production rate according to
the IPR of the well. Fig. 6.28 shows the system pressures
and losses for an open power-fluid installation, and Fig.
6.29 shows them for a closed power-fluid installation.
The relationships shown in Figs. 6.28 and 6.29 are sum-
marized below.
Open Power-Fluid System.
~,,~=p~<,-pb, +g,fo-pfr, ................. (32)
pBd =pfd +gdD+p,,zh, ..................... (33)
Fig. 6.27-Theoreticalvolumetric
efficiencies
ofunvented down-
hole pumps as affectedby high GOR’s (volume oc-
cupied by saturatedoiland free gas is based on
35OAPI oilat 160°F BHT). Example: To determine
maximum displacement of an unvented pump with
430-psipumping bottomholepressure,
250 gas/oil
ra-
tio,
and 50% water cut.Enter chart at 430 psi down
toGOR (250).
From intersectlon.
proceed horizontally
to read 44 + % oildisplacement. Strikea dragonal
from 44+ % on Lme A to Pointt3,
from intersection
with50% water cut,read 62% maximum displace-
ment of water and tank oil.
ppd ‘p@, . . . . . . . (34)
Note that Eq. 32 can be solved for the surface operating
and pressure (triplex pressure) to give
pps =gssp. . . . . . . . . (35) pso =P,,~ +pfi, -gPjD+pfr. . . . (36)
I
:
PP*
9s
wh
0 1 pump setting depth, ft
-p,, = surface operating pressure.
(triplex pressurel. ps
pfpt
: friction in power tubing. psi
gPf
Pfr
PPf
: gradient of power fluid, psi/ft
: downhole unit friction pressure, psi
= useful power fluid pressure
-Ppf
-pfd
gdo
pwh
Ppd
Ppd
-pad
at engine, psi
= pso - ptpt + gpfD - pfr
= friction in production tubing, psi
z gradient of mired power f’luid and
production in an open power fluid
system, psi/ft
= flow line pressure at wellhead, psi
= pump discharge pressure, psi
= Pfd + 9,jD + P,,+,
’ Ppd
= pump submergence, ft
2 gradient of production (suctIonI
fluid, psi/ft
= pump suction pressure. psi
= 9*sp
Fig. 6.28--System pressures and losses in an open power-fluid
mstallation

Closed Power-Fluid System. Produced fluid. The gradient of the produced well
fluids at the pump suction is given by
P,f=P >o-P,~, •g,,~D-p~~, (32)
PC</
=p,f<,,+g,fD+p ,,,,,
p, (37)
s,,=g,,(l-W,.)+KI,,W~. ,(40)
ppt, =P,~(,+~,,D+P,,,~, . . . (38)
and
where
Ro =
g,,. =
w,. =
pp. =gsp. . . . . (35)
gradient of produced oil, psiift,
gradient of produced water, psi/ft. and
water cut (0.5 for 50% water cut),
fraction.
As before, solving for the surface operating pressure
gives
This is also the value for the pump discharge gradient,
g,,, in a closed power-fluid system.
pso =pllf +pfi, -R,,~D+~P~~. (36)
Pump and Engine Discharge Gradient in an Open
Power-Fluid System.
Calculation of Fluid Gradients. Power EZuid. Proper
values for the various fluid gradients are necessary to cal-
culate the pressures that affect the pump. The power-fluid,
either oil or water, has a gradient, g,,~, in pounds per
square inch per foot. This is also the power-fluid exhaust
gradient in a closed power-fluid system. The gradient
values for different-API-gravity oils are given in Table
6.6. If water is used as power fluid, its gradient may vary
from the standard value of 0.433 psi/ft, depending on the
amount of dissolved salt. Corrections may be made by
use of the general relationship:
gd =[kfpfxg,f)+(q., xg,v)vq,i> ” ” . (41)
where
q,,f = power-fluid rate, B/D.
q, = production (suction) fluid rate, BID, and
Ed = discharge fluid rate. ypf+q,, BID.
g=y(O.433). . . . . ,(39)
Fluid Friction in Tubular and Annular Flow Passages.
Appendix B contains friction pressure-drop curves for a
variety of commonly used tubing and casing sizes. Also
included in Appendix B are the equations used to create
the curves. Note that the pressure drops are given in
pounds per square inch per 1,000 ft and that the values
PPS
9s
nhc
wh
/
D = pump setting depth, tt
-PEO = surface operating pressure,
ftriplex pressural. psi
pfpt = friction in power tubing, psi
gPf
= gradient of power fluid. psi/ft
pfr
= downhole unit friction pressure. psi
PPf
= useful pow.r fluid pr.ssur.
at engine, psi
-Ppf = pso. - pfpt + gpfD - ptr
‘pfat =
gpf =
pwhe =
pod q
-Ped =
-Pfd =
9* =
pwh =
ppd ’
-ppd =
friction in power exhaust tubing, psi
gradient of power fluid. psi/ft
power fluid wellhead back pressure, psi
engine discharge pressure. psi
Pfet + gpfD + pwhe
friction in production tubing, ps i
gradient of produced fluid, psi/ft
flow I ine pressure at weI Ihead. psi
pump discharge pressure. psi
pfd + g,D + P,,,
-c
sP
= pump submergence, ft
9, = gd = gradient of production Isuction)
fluid, psi/ft
PPS
= pump suction pressure. psi
PPS
q 9,sp
Fig. 6.29-System pressures and losses in a closed power-fluid
installation

must be multiplied by the specific gravity of the fluid.
The values for the power-fluid friction pressure, phi, the
power-fluid discharge pressure friction, pfer, and the pro-
duction discharge friction pressure, pfd, can be deter-
mined from the charts or the basic equations.
Fluid Viscosity. The viscosities of various crude oils and
waters are discussed in Appendix A. The viscosity of
water/oil mixtures is difficult to predict. In hydraulic
pumping calculations, a weighted average is normally
used. Water and oil viscosities are usually evaluated at
the average temperature between surface and downhole
temperatures.
v,,~=(I--~.~,)u,,+W~.~Y ,,‘, . (42)
where
lJ,,I = mixture viscosity, cSt,
Vfl = oil viscosity, cSt,
un = water viscosity, cSt, and
Wc.ll = water cut in discharge conduit to surface,
fraction.
In closed power-fluid systems,
Wrl,=Wc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..(43)
In open power-fluid systems using water as the power
fluid,
W,.,l=(q,S+W,.q.,)/q,,. . . (44)
For open power-fluid systems with oil as a power fluid,
w,.,,=w,.q,/q,,. . .(45)
These equations do not consider the formation of any
emulsions that only occasionally form in hydraulic pump-
ing systems. Water-in-oil emulsions can cause extremely
high apparent viscosities (Fig. 6.30) but the prediction
of when emulsions will form is difficult. The formation
of oil-in-water emulsions has been done deliberately in
heavy crude wells as a means of reducing viscosity. ”
Multiphase Flow and Pump Discharge Pressure
Eqs. 33 and 38 for the pump discharge pressure include
only the dead oil and water gradients. If the well produces
significant gas, the multiphase (gas plus liquid) flow to
the surface will result in pump discharge pressures lower
than predicted by Eqs. 33 and 38. The magnitude of this
effect on the operating pressure (and required horsepower)
depends on the P/E ratio ofthe downhole pump. Available
P/E ratios range from a low of 0.30 to a high of 2.00.
By referring to Eq. 22 for open power-fluid systems,
which are the most common, we can see that a change
in the pump discharge pressure affects the power-fluid
pressure by (I + P/E) times the change in discharge pres-
sure. Because (I +P/E) has a range of 1.30 to 3.00, de-
pending on the pump, a 500.psi reduction in the pump
discharge pressure caused by gas effects can change the
operating pressure required by 650 to 1,500 psi.
Percent brineIn emulsion
Fig. 6.30-Effect of emulsion on oilviscosity.
If the gas/liquid ratio FXL is less than about IO scfibbl
in the pump discharge flow path, the gas effects are
minimal and Eqs. 33 and 38 can be used directly. For
higher FRY values, it is suggested that a vertical mul-
tiphase flowing gradient correlation be used to calculate
the pump discharge pressure. (See Chap. 5~Gas Lift, for
a detailed discussion of these calculations.) Note that in
open power-fluid systems, the addition of the power fluid
to the production will make the discharge FcsLsubstan-
tially less than the formation producing GOR, R. In a
closed power-fluid system,
FgL=(l-IV,.)!?. . . . . . . . . . . . . . . . . . . . . . . . . . . (46)
In an open power-fluid system,
FR,=q,(l-W,.)RIqd. . .(47)
The appropriate water cuts for use in vertical multi-
phase flowing gradient calculations are given in Eqs. 43
through 45.
Gas/Liquid Ratio in Vented Systems
Vented systems allow most of the free gas to rise to the
surface without passing through the pump. The gas that
is still in solution in the oil at pump intake pressure con-
ditions, however, does pass through the pump. To deter-
mine solution GOR from Fig. 6.27, read down from the
pumping BHP to the saturated oil-volume line (the upper
boundary of the downhole volume shaded area). Inter-
polating between the intersections of the constant-GOR
curves with the saturated-oil-volume line gives the solu-
tion GOR. At 500-psi pump intake pressure, the solution
GOR is about 100 scfibbl. The solution GOR should be
used in Eqs. 46 and 47 when the installation includes a
gas vent.

Pressure Relationships Used
To Estimate Producing BHP
The pressure relationships of Eqs. 2 1and 22 can be rear-
ranged to give the pump intake pressure p,,, in terms of
the other system pressures and the PIE ratio of the pump.
For the closed power-fluid system,*
For the open power-fluid system,
j7,' =p,,‘/-(p,l,-p,,,,)/(P/E). (49)
If the appropriate relationships from Eqs. 32 through
38 are used. the equation for the closed power-tluid system
becomes**
-(plr,+X,,l.D+P,,h~,)]I(PIE), (50)
where g, =x(1 in a closed power-fluid system.
For the open power-tluid system, the relationship is
-(pf;,+g,,D+P,,,,)]/(P/E). ., ..(51)
These equations can be used directly. but several prob-
lems arise. Several friction terms must be evaluated, each
with a degree of uncertainty. The term p,. for the losses
in the pump is the least accurate number because pump
wear and loading can affect it. To avoid the uncertainty
in friction values. a technique called the “last-stroke
method” is often used. With this method. the power-tluid
supply to the well is shut off. As the pressure in the sys-
tem bleeds down. the pump will continue to stroke at slow-
er rates until it takes its last stroke before stalling out.
The strokes can be observed as small kicks on the power-
fluid pressure gauge at the wellhead. The power-fluid
pressure at the time of the last stroke is that required to
balance all the fluid pressures with zero flow and zero
pump speed. At zero speed. all the friction terms are zero,
cxccpt p/,., which has a minimum value of SOpsi. which
simplifies Eqs. 50 and 5 I. With the friction terms re-
moved, the last stroke relationship for the closed power-
fluid system becomes
(g,,tD+P,,,lrc,)]/(P/E). (52)
For the open power-fluid system the relationship is
-(,~I,D+l,,,.,,)II(PIE). (53)
‘Eq 48 IS dewed from Eq 21 and Eq 49 IS dewed from Eq 22
“Eq 50 IS dewed lrom Eq 21 and Eq 51 IS dewed from Eq 22
These relationships have proved to be very effective in
determining BHP’s. ” However, they are limited to wells
that produce little or no gas for the reasons discussed in
the section on Multiphase Flow and Pump Discharge Pres-
sure. Eqs. 50 and 51 can be used in gassy wells if the
hydrostatic-pressure and flowline-pressure terms arc re-
placed by a pump discharge pressure from a vertical mul-
tiphase flowing gradient correlation. The equations for
the last-stroke method, however, present a further prob-
lem because they require the gradient at a no-flow condi-
tion. The multiphase-flow correlations show a significant
variation of pressure with velocity. Wilson, in Brown,’
suggests subtracting the friction terms from the flowing
gradient for evaluating Eqs. 52 and 53 or attempting to
determine pf,. more accurately for use in the evaluation
of Eqs. 50 and 5 I, The method suggested here is to use
a multiphase-flow correlation for determining ~~~~1
at the
normal operating point of the pump. With the same cor-
relation for the same proportions of liquid and gas, de-
termine what the pPll pressure would be at a low tlow
rate, corresponding to the conditions when the pump is
slowing down to its last stroke. By plotting the two values
of p,,(/ obtained, we can extrapolate to what pprl would
be at zero flow. This value can be used to replace the
hydrostatic-head and flowline-pressure terms.
Selecting an Appropriate PIE Ratio. As previously dis-
cussed, large values of P/E are used in shallow wells and
small values in deeper wells. The larger the value of P/E,
the higher the surface operating pressure to lift fluid
against a given head will be. The multiplex pumps offered
by the manufacturers are rated up to 5,000 psi, but few
hydraulic installations use more than 4,000 psi except in
very deep wells. About 80 to 90% of the installations use
operating pressures between 2,200 and 3,700 psi. With
the simplifying assumptions of an all-water system, no
friction, 500-psi pump friction, 4,000-psi operating pres-
sure. and a pumped-off well, Eqs. 22, 33, and 36 lead to
(P/E),,,, =3,500/0.433/l,, =8.000/L,,, . . . . . . ..(54)
where L,, =net lift, ft.
Eq. 54 is useful in initial selection of an appropriate
PIE ratio in installation design. The actual final determi-
nation of the surface operating pressure will depend on
calculation of the actual gradients and losses in the sys-
tem and on the particular pump’s P/E ratio.
Equipment Selection and Performance Calculations
Equipment selection involves matching the characteris-
tics of hydraulic pumping systems to the parameters of
a particular well or group of wells. A worksheet and sum-
mary of equations are given in Table 6.7.
Once a downhole unit has been selected and its power-
fluid pressure and rate determined. an appropriate power
supply pump must be matched to it. The section on sur-
face equipment and pumps provides a detailed descrip-
tion of the types of pumps used for powering hydraulic
pumping systems. Specifications for some of the pumps
typically used can be found in Tables 6. I through 6.4
(Figs. 6.15 through 6.18).
A troubleshooting guide is provided in Tables 6.8
through 6. IO.

TABLE 6.7-WORKSHEET AND SUMMARY OF EQUATIONS FOR RECIPROCATING PUMPS
Well Identification
Example Problem 3
Vertical
setting
depth, ft 9,000
Tubing length,ft 9000
Tubing ID,in. 2.441
Tubrng OD, In. 2.875
Return ID, in. 4.892
Wellhead pressure,psi 100
Gas specific
gravity 0.75
011gravity,
“API 40
Power fluid
specific
gravity 0.82
Produced 011specific
gravtty 0.82
Water specific
gravity
Power fluid
gradient,
psiift
Produced oilgradient,psilft
Water gradient,psilft
Oilviscosity,
cSt
Water viscosity,
cSt
GOR, scflbbl
Water cut,%
Surface temperature, OF
Bottomhole temperature, OF
1.03
0.357
0.357
0.446
2
0.485
100
70
100
200
Expected net lift,
ft 7,800 Vented? Yes- No2
Desired production,B/D 250
Pump intakepressure at above rate,psi 500
Installation:
Casing i/ Parallel
_
OPF r, CPF
Step 1 -(P/O max
=8,000/L, = 1.03 (Eq. 54)
Step a--Maximum pump efficiency
Eprmax,
(Fig.6.27)
97
% (Vented)
% (Unvented)
Step 3-Minimum recommended pump displacement (Eq. 31):
qp =9,/; ~Epmax, xEp~,nt,
= 250/(0.8x0.97 x 0.85)= 379 B/D
max
Step 4-Select pump from Tables 6.1 through 6.4 with P/E lessthan or equal to value from Step 1 and a maximum rated
pump displacement equal to or greaterthan the value from Step 3
Pump designation:
Manufacturer B Type A 2% x 11/4-11/4
in.
PIE 1.oo
Rated displacement, B/D 492
Pump, BIDlstrokeslmin 4.92
Engine, BIDlstrokeslmin 5.02
Maximum rated speed, strokes/min 100
Step S-Pump speed:
N= qsW,~,,xl x Epc,ntr)l2WO.97xO.W
q,lN,,x =
= 61.6 strokes/min
4921100
Step B-Calculate power-fluid
rate(assume 90% engine efficiency,
E,)
qpf= N(q,/N,,,)/E, = 61.6(502/100)/0.90
= 344 B/D
Step 7-Return fluid
rateand properties-OPF system
a. Totalfluid
rate: power fluid
rate,
qp, = 344 BID
+ productronrate,9r = 250 BID
= totalrate,
qd = 594 BID
b.Water cut:
Water power fluid
(Eq. 44)
WC, = (9Pf+ W,q,)J9, =
Oil power fluid
(Eq. 45)
wcd=wcq,/q,=07x250/594=o.29
c. Vscosity (Eq.42)
v,,,
=(I - Wcd)vo + Wcdvw =(I -0.29)2+0.29x0.485= 1.56 cSt
d. Suction gradient(Eq. 40)
gs=g~(l-W,)+g,W,=0.357(1-0.7)+0.446x0.7=0.419psl/fi
e. Return gradient(Eq 41)
gd = [(9,(
xg,,) +(9s xg,)]/q, =[(344x 0.357)+(250 x0.419)1/594=0.383 psrlft
f. Gas/liquidratro
(Eq. 47)
F,, =q,(l - W,)R/q,=250(1 -0.7)100/594=12.6 scilbbl
Note: For vented installations,
use solutionGOR (Frg.6.27)

TABLE 6.7-WORKSHEET AND SUMMARY OF EQUATIONS FOR RECIPROCATING PUMPS (continued)
Step B-Return fluid
ratesand properties-closed power-fluid
systems. Because the power fluid
and produced fluid
are kept
separate,the power returnconduit carriesthe flow ratefrom Step 6, with power-fluid
gradientand viscosity.
The production
returnconduit carriesthe desired production ratewith productiongradient,
water cut,viscosity,
and GOR.
a. Power-fluid
returnrate BID
b. Production returnrate BID
Step g--Return friction:
Ifa gas lift
chart or vertical
multiphase flowinggradientcorrelation
(see Chap. 5) isused forreturn
flow calculations,
itwill
already includefriction
values and the flowline
backpressure. Use of gas lift
chartsor correlations
is
suggested if
the gas/liquid
ratio
from Step 7 isgreaterthan IO.The value from such a correlation
can be used directly
in Step
llc withoutcalculating
friction
values. Ifa gas-lift
chart or vertical
flow correlation
isnot used, then with the values from Steps
7 and 8, as appropriate,
determine the returnconduit friction(s)
from the chartsor equations inAppendix 6.
1.Open power-fluid
friction
pfd = psi.
2. Closed power-fluid
friction
a. power returnpter
=- psi.
b. production returnptd=- psi.
Step lo-Power-fluid friction:
With the power-fluid
ratefrom Step 6, use the appropriatechartsor equations in Appendix B to
determine the power-fluid
friction
loss.
Power fluid
friction
prpt= 4.4 psi.
Step 11-Return pressures:
a.Open power-fluid
system (Eq. 33)
Ppd=Pfd+i?dD+P,= psi.
b.Closed power-fluid
system (Eqs. 37 and 38)
1.P ed=Plet+!?~D+Pwhe=--- psi
2.P,d=P,+!7,D+P,= psi
c. Ifa vertical
multiphase flowinggradientcorrelation
ISused insteadof Eqs. 33, 37, or 38, then ppd =3,500 psi,
Step 12-Required engine pressure ppf:
a. Open power-fluid
system (Eq. 22)
p,,=ppd[l+(P/E)]-pps(P/E)=3,500[1+1]-500(1)=6,500psi.
b.Closed power-fluid
system (Eq. 21)
Ppf ‘Ped +Ppd(PIE)-Pp,(PIE)= psi
Step 13-Calculate pump friction
a. Rated pump displacement,qp =492 B/D
b. Rated engine displacement,qe = 502 B/D
c.Totaldisplacement,qtm = 994 B/D
d. “8” value (Table 6.5)= 0.000278
e. N/N,,, = 61.61100=0.616
f.f,=~/100+0.99=2/100+0.99=1.01 (Eq. 28)
g. Pump friction
(Eq. 29 or Fig.6.24)
pb =yF,(50)(7.1ee9” jNINmax
plr=0.82(1.01)(50)[7.1eoooo278~994~]06’6
= 164 psi.
Step 14-Required surface operatingpressure p, (Eq. 36):
pso =pp, +ptpf-gprD+pr, =6,500+4.4-0.357(9,000)+ 164=3:455 psi
Step 15-Required surface horsepower, assuming 90% surface efficiency
(Eq. 5):
P, =qp,xp,, x0.000017/E, =344x3,455x0.000017/0.9=22.4 hp.
Step 16-Summary:
Pump designation-Manufacturer B Type A 21/z
x 1X-1% in.
Pump speed, strokeslmin 61.6
Production rate,B/D 250
Power fluid
rate,B/D 344
Power fluid
pressure,psi 3,455
Surface horsepower 22.4
Step 17-Triplex options (from manufacturer specification
sheet,Tables 6.16 through 6.18):
Type
J-30 D-323-H
Plunger size,in. 1% 1‘/a
Revolutionslmin 450 300
Flow rateat revolutionslmin
(B/D) 400 399
Maximum pressure rating,
psi 3,590 4.000
Horseoower 26 26

HYDRAULIC PUMPING
TABLE 6.6~-SUBSURFACE TROUBLESHOOTING GUIDE-RECIPROCATING PUMP
Indication
1.Sudden increase in
operatingpressure-
pump stroking.
2. Gradual increase in
operatingpressure-
pump stroking.
3. Sudden increase in
operatingpressure-
pump not stroking.
4. Sudden decrease in
operatingpressure-
pump stroking.
(Speed
could be increased or
reduced.)
5. Sudden decrease in
operatingpressure-
pump not stroking.
6. Drop in production-
pump speed constant.
7.Gradual or sudden
increase in power oil
requiredto maintain
pump speed. Low
engine efficiency.
8. Erratic
strokingat
widely varying-
pressures.
9. Stroke “downkicking”
insteadof
“upkicking.”
IO.Apparent lossof,or
unable to account for,
system fluid.
Cause
(a)Lowered fluid
level,
which causes more net
lift.
(b)Paraffin
buildup or obstructioninpower-oil
line,
flow line,
or valve.
(c)Pumping heavy material,
such as saltwater
or mud.
(d)Pump beginning to fail.
(a)Gradually loweringfluid
level.
Standing valve
or formationplugging up.
(b)Slow buildup of paraffin.
(c)Increasingwater production
(a)Pump stuck or stalled.
(b)Sudden change in wellconditionsrequiring
operatingpressure in excess of triplex
relief
valve setting.
(c)Sudden change in power-oilemulsion, etc.
(d)Closed valve or obstruction
in production
line.
(a)Rising fluld
level-pump efficiency
up.
(b)Failureof pump so thatpartof power
oilisbypassed.
(c)Gas passing through pump.
(d)Tubular failure-downhole or in surface
power-oilline.
Speed reduced.
(e)Broken plunger rod.Increased speed.
(f)Seal sleeve in BHA washed or failed.
Speed
reduced.
(a)Pump not on seat.
(b)Failureof productionunitor
externalseal.
(c)Bad leak in power-oiltubing string.
(d)Bad leak in surface power-oilline.
(e)Not enough power-oilsupply at manifold.
(a)Failureof pump end of productionunit.
(b)Leak in gas-vent tubing string.
(c)Well pumped off-pump speeded up.
(d)Leak in productionreturnline.
(e)Change in wellconditions.
(f)Pump or standing valve plugging.
(g)Pump handling freegas.
(a)Engine wear.
(b)Leak in tubulars-power-oiltubing,BHA
seals,or power-oilline.
(a)Caused by failure
or plugging of engine.
(a)Well pumped off-pump speeded up.
(b)Pump intakeor downhole equipment
plugged.
(c)Pump failure
(balls
and seats)
(d)Pump handling freegas.
(a)System not full
of oilwhen pump was started
due to water in annulus U-tubingafter
circulating,
wellflowingor standing valve
leaking.
(b)Inaccuratemeters or measurement.
6-31
Remedy
(a)Ifnecessary, slow pump down.
(b)Run solubleplug or hot oil,
or remove
obstruction
(c)Keep pump stroking-do not shut down.
(d)Retrievepump and repair.
(a)Surface pump and check. Retrievestanding
valve.
(b)Run solubleplug or hot oil.
(c)Raise pump strokes/minand watch pressure.
(a)Alternately
increaseand decrease pressure.
Ifnecessary, unseat and reseatpump. Ifthis
fails
to start
pump, surface and repair.
(b)Raise settingon relief
valve.
(c)Check power-oilsupply
(d)Locate and correct.
(a)Increase pump speed ifdesired.
(b)Surface pump and repair.
(d)Check tubulars.
(e)Surface pump and repair.
(f)Pulltubing and repairBHA.
(a)Circulatepump back on seat.
(b)Surface pump and repair.
(c)Check tubing and pulland repairifleaking.
(d)Locate and repair.
(e)Check volume of fluid
discharged from
triplex.
Valve failure,
plugged supply line,
low
power-oilsupply,excess bypassing, etc.,
all
of which could reduce available
volume.
(a)Surface pump and repair.
(b)Check gas-vent system.
(c)Decrease pump speed.
(d)Locate and repair.
(f)Surface pump and check. Retrievestanding
valve.
(g)Test to determine best operatingspeed.
(a)Surface pump and repair
(b)Locate and repair.
(a)Surface pump and repair.
(a)Decrease pump speed. Consider changing to
smaller pump end.
(b)Surface pump and clean up. Ifin downhole
equipment, pullstanding valve and backflush
well.
(c)Surface pump and repair.
(a)Continue pumping to fill
up system. Pull
standing valve ifpump surfacingisslow and
cups look good.
(b)Recheck meters. Repair ifnecessary.

6-32
Indication
operatingpressure-
pump taking power
fluid.
2. Slow increase in
operatingpressure-
constant power-fluid
rateor slow decrease
in power-fluid
rate,
constant operating
pressure.
operatingpressure-
pump not takingpower
fluid.
4.Sudden decrease in
operatingpressure-
power-fluid
rate
constant or sudden
increase in power-fluid
rate,
operating
pressure constant.
5.Drop in production-
surface conditions
normal.
6. No production
increasewhen
operatingpressure is
increased.
7.Throat worn-one or
more dark, pitted
zones.
6.Throat worn-
cylindrical
shape worn
to barrelshape,
smooth finish.
9. New Installation
does
not meet prediction
of
production.
TABLE 6.9-SUBSURFACE TROUBLESHOOTING GUIDE-JET PUMPS
Cause
(a)Paraffin
buildup or obstruction
in power-oil
line,
flowline,
or valve.
(b)Partial
plug in nozzle.
(a)Slow buildup of paraffin
(b)Worn throator diffuser.
(a)Fullyplugged nozzle.
(a)Tubular failure.
(b)Blown pump seal or broken nozzle
(a)Worn throator diffuser.
(b)Plugging of standing valve or pump
(c)Leak or plug in gas vent.
(d)Changing wellconditions.
(a)Cavitationin pump or high gas production
(a)Cavitation
damage.
(a)Erosion wear
(a)Incorrect
welldata.
(c)Tubular leak.
Remedv
(a)Run solubleplug or hot 011,
or remove
obstructton.
Unseat and reseat pump.
(b)Surface pump and clearnozzle.
(a)Run solubleplug or hot 011.
(b)Retrievepump and repair.
(a)Retrievepump and clearnozzle
(a)Check tubing and pulland repairIfleaklng.
(b)Retrievepump and repair.
(a)Increase operatingpressure.Replace throat
and diffuser.
(b)Surface pump and check. Retrievestanding
valve.
(c)Check gas-vent system.
(d)Run pressure recorderand resizepump.
(a)Lower operatingpressure or install
larger
throat.
(b)Surface pump and check Retrievestanding
valve.
(a)Check pump and standlng valve forplugging.
Install
largerthroat.
Reduce operating
pressure.
(a)Replace throat.
Install
premium-material
throat.
Install
largernozzle and throatto
reduce velocity.
(a)Run pressure recorderand resizepump.
(b)Check pump and standing valve.
(c)Check tubing and pulland repairifleaking.
(d)Side stringin parallel
installation
not landed. (d)Check tubing and restab ifnecessary

6-33
HYDRAULIC PUMPING
TABLE B.lO-POWER OIL PLUNGER PUMPS TROUBLESHOOTING GUIDE
Possible Cause Correction
Knocking or Pounding in FluidEnd and Piping
Suction hne restricted
by
a.Trash, scale build-up,
etc. Locate and remove.
b. Partially
closed valve in suctionline. Locate and correct.
c. Meters, filters,
check valves,non-full- Rework suctionlineto eliminate.
opening, cut-off
valves or other
restrictions.
d. Sharp 90° bends or 90“ blindtees.
Airenteringsuctionlinethrough valve
stem packing.
Airenteringsuctionlinethrough loose
connection or faulty
pipe.
Airor vapor trapped in suction.
Low fluid
level.
Suction dampener not operating.
Worn pump valves or broken spring.
Entramed gas or airin fluid.
Inadequate size of suctionline.
Leaking pressure relief
valve thathas
been piped back intopump suction.
Bypass piped back to suction.
Broken plunger.
Worn crosshead pm or connecting rod.
Knock in Power End
Worn crosshead pin or connecting rod.
Worn main bearings.
Loose plunger-intermediate rod-
crosshead connection
Rapld Valve Wear or Failure
Cavitation
Corrosion.
Abrasives in fluid.
Rework suctionlineto eliminate.
Tighten or repack valve stem packing.
Locate and correct.
Locate riseor trap and correctby straightening
line,
providingenough slope to
permit escape and prevent buildup.
Increase supply and install
automatic low-level
shutdown switch.
Inspectand repairas required.
Inspectand repairas required.
Provide gas boot or scrubber forfluid.
Replace with individual
suctionlineor next size largerthan inlet
of pump.
Repair valve and rework pipingto returnto supply tank-not suction line.
Rework to returnbypassed fluid
back to supply tank-not supply line.
Inspectwhen rotating
pump by hand and replaceas required.
Locate and replace as required.
Locate and replaceas required.
Check oilquality
and level
Replace as required.Check oilquality
and level
Inspectfordamage-replace as requiredand tighten.
Predominant cause of shortvalve life
and ISalways a resultof poor suction
conditions.
This situation
can be correctedby following
appropriate
recommendations as listed
under No. 1.
Treat fluid
as required.
Treat to remove harmful solids.
FluidSeal Plunger Wear, Leakage, or Failure
Solidsin power oil
Improper installation.
Reduced Volume or Pressure
Bypassing fluid.
Air influid
end of triplex.
Inaccuratemeter or pressure gauge.
Pump suctioncavitation
due to improper
hook-up, suctionrestriction
or entrained
gas.
Valves worn or broken.
Plungers and liners
worn.
Reduced prime mover speed because of
increased load,fuelor other conditions.
This islikely
to cause greatestamount of wear. Power oilshould be analyzed for
amount and type of solidscontent.Proper treating
to remove solidsshould be
instigated.
Follow writteninstructions
and use proper tools.
Remember, plunger and liner
are
matched sets.Ensure proper lubrication
at startup.
(Be sure airisbled out of
fluid
end before starting
up.)
Locate and correct.
Bleed off.
Check and correct.
Locate and correct.
Replace.
Replace.
Determine cause and correct.
(May be increased pressure caused by paraffin
temperature change, etc.)

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