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1. INTRODUCTION.................................................................................................32 THE POWER FLUID SYSTEMS......................................................................11
2.1 CPF System......................................................................................................122.1.1 Power Fluid Tank (CPF)...........................................................................13
2.2 OPF System......................................................................................................152.2.1 Power Fluid Tank (OPF)...........................................................................15
3 INDIVIDUAL WELL SITE POWER PLANT.................................................184 SURFACE PUMPS..............................................................................................235 CONTROL MANIFOLDS..................................................................................24
5.1 Manifolds..........................................................................................................245.2 Constant flow control valves...........................................................................25
6 WELL HEADS.....................................................................................................257 TUBING ARRANGEMENTS............................................................................26
7.1 Fixed insert.......................................................................................................277.2 Fixed casing......................................................................................................277.3 Parallel free......................................................................................................277.4 Casing free........................................................................................................277.5 Other Tubing Arrangements..........................................................................33
7.5.1 Reverse Circulation...................................................................................337.5.2 Dual Wells.................................................................................................337.5.3 Tandem Pump............................................................................................337.5.4 Safety Valves..............................................................................................34
8 DESIGN CONSIDERATIONS AND CALCULATIONS................................388.1 OPF or CPF......................................................................................................388.2 Vent gas or pump gas......................................................................................39
8.2.1 Venting Gas...............................................................................................398.2.2 Pumping Gas.............................................................................................39
8.3 Pumps................................................................................................................428.3.1 Pump Selection..........................................................................................428.3.2 Power Fluid Rate.......................................................................................438.3.3 Pump Friction............................................................................................448.3.4 Surface Pressure Calculations..................................................................498.3.5 Horsepower calculations...........................................................................52
9 DESIGN OF COMPLETE SYSTEM................................................................529.1 Procedure For The Design Of Equipment For One Well............................52
10 URFACE TROUBLESHOOTING GUIDE......................................................5411 ADVANTAGES AND DISADVANTAGES......................................................57
11.1 Advantages.......................................................................................................5711.2 Disadvantages...................................................................................................57
12 REFERENCES....................................................................................................58
1. INTRODUCTION
A subsurface hydraulic pump is a closely coupled reciprocating
engine and pump. The unit is installed below the working fluid level in a
well, high pressure power fluid is directed to the engine through one conduit
and spent power fluid and well production are directed to the surface
through another conduit. The high pressure power fluid causes the engine to
reciprocate much like a steam engine except the power fluid is oil or water
instead of steam. The pump, driven by the engine, pumps the fluid from the
well-bore. The pump can be circulated out for repairs, thereby eliminating
pulling unit operations. Some of its other advantages are:
1. has good flexibility on rates
2. can handle deviated wells
3. easily adapted to automation
4. easy to add inhibitor
5. is suitable for pumping heavy crudes
6. one well or multiple well units are available
7. simple well heads accommodate closely spaced wells, covered or
cellered well heads and wells in visually sensitive areas.
As shown in fig.1 (engine end), high pressure power fluid is directed to
the top of the engine piston while exhausted power fluid from the lower side
of the piston is directed to the relieved area of the engine valve where it is
discharged.
When the piston reaches the end of the down-stroke, the reduced
diameter at the top of the valve rod allows high pressure fluid to enter under
the engine valve, as shown in fig.2. Because the valve has a large area at its
top, it will move upwards.
With the engine valve in the up position, as shown in fig. 3, the flow
paths to the piston are reversed. The pump, therefore, begins its up-stroke.
When the piston reaches the end of the up-stroke, as shown in fig.4, the
reduced diameter near the lower end of the valve rod connects the area under
the valve to the discharge, or low pressure, side of the engine. With high
pressure on the top of the valve and only exhaust pressure at the bottom, the
valve will move to its down position and the cycle will be repeated.
The pump end of the pump is shown making down-stroke in fig. 5. This
pump is double acting (it pumps on the up and down-strokes). The arrows
show that the well fluid is entering on the left and filling the upper part of
the cylinder while the well fluid below the piston is being discharged
through the ball check valve at the lower right.
The complete pump is shown in fig.6. On the up-stroke well fluid enters
the lower part of the cylinder while being discharged from the upper part of
the cylinder. The purpose of the hollow lower rod is to balance the areas
(forces) on the up-stroke and the down-stroke.
Most hydraulic pumps are installed as free pumps, i.e., they are free to be
circulated in and out of the well, as the sequence in fig. 7 illustrated.
A complete hydraulic pumping system is shown in fig. 8. Power fluid
pumping systems consists of:
1) the tank at (A)
2) surface pumps (B)
3) control manifolds (C)
4) well heads (D)
5) tubing arrangements (E)
fig. 1 engine end fig. 2 engine end of down stroke
fig. 5 Pump end in down-stroke
fig 3 engine up-stroke fig. 4 engine – end of upstroke
fig. 6 complete pump
fig. 7 Free pump installation
fig.8 Complete hydraulic pumping system
2 THE POWER FLUID SYSTEMSThere are two basic types of power fluid systems:
1. The Closed Power Fluid (CPF) system where the surface and
subsurface power fluid stays in a closed circuit and does not mix with
the produced fluid.
2. The Open Power Fluid (OPF) system where the power fluid mixes
with the production down hole and return to the surface as
commingled power fluid and production.
The choice of oil or water for power fluid can be based on a number of
factors. Following is a list of most of the factors involved in this choice:
1. water is preferred for safety and environmental reasons.
2. for CPF installations the addition of chemicals to power water for
lubrication and corrosion is not large factor (fresh water is used).
3. for OPF installations the addition of chemicals to power water can be
a significant cost factor because the power water is commingled with
production. This requires continual injection of chemicals which will
add to the operating cost.
4. treating power oil is seldom a large cost factor mainly because it
seldom needs chemical additives for lubricity. One exception is when
high gravity oils are used at very high bottom hole temperatures.
5. maintenance on surface pumps is less when using oil because metal to
metal plungers and liners are usually used instead of packing. Also,
valves last longer and are usually the ball and seat type rather than the
disc or poppet type normally used for water. Additionally, the low
bulk modulus of water causes much larger pressure pulses than oil,
and these pulses are detrimental to pipe connections and contributing
to fatigue failures of pump components.
6. subsurface pumps are sensitive to viscosity and lubricating qualities of
the power fluid. Because water has practically no lubricating ability at
bottom hole temperatures, it can, if not adequately treated, contribute
to shorter pump life. Leakage of power fluid past the various sliding
fits in the pump is a function of the viscosity and is greater with water
than with most crude oils.
7. testing a well for production is subjected to an added source of error
when oil is used for power fluid. The power oil must be metered in
and small errors in metering can be significant when the ratio of
power oil to produced oil is large, as when the well is producing a
large percentage of water.
8. usually, the surface pressure required will be less when using power
water as compared to using power oil.
9. although hydraulic pumps handle viscous crudes very well, it has
sometimes served other purposes to use a higher gravity oil for power
fluid and use the OPF system. This commingles the two crudes at the
discharge of the pump, thus diluting the heavy oil for ease in
transporting it at the surface.
2.1 CPF System In the CPF system, an extra down hole conduit must be provided for
returning the spent power fluid to the surface. Thus, the system is more
expensive than the OPF system, so its use is not widespread. Because the
power fluid tanks are relatively small, this system is popular for urban
locations and offshore platforms where surface space is at a premium.
Frequently, CPF systems use water for the power fluid because:
1. it is less hazardous and
2. it presents fewer ecological problems than higher pressure oil.
Water, however, should have:
1. a lubricant added.
2. should be inhibited against corrosion.
3. all oxygen removed.
2.1.1 Power Fluid Tank (CPF)
In most down hole pumps, the pump end is lubricated with the power
fluid and part of the power fluid is purposely “leaked” to the production.
This loss of power fluid must be replaced with clean fluid. The power fluid
tank in fig. 9 remove abrasive particles form the make up fluid and part of
the re-circulated fluid.
One misconception concerning the CPF system is that the power fluid
will remain clean because it has no source for contamination. In actual
practice, three factors are constantly working together to corrupt this theory:
1. the power fluid tank does not completely remove all of the solid
particles from the make up fluid – cleanliness is relatively, not
absolute.
2. the power fluid is not completely non-corrosive. Again, this factor
is relative, not absolute, and the products of corrosion are generally
abrasive solids.
3. when fluid containing solids, even a very small percentage of
solids, is leak through a long closely fitted clearance space, as in a
down hole pump, the solids tend to be held back. This means that
the fluid emerging from the fit is cleaner than the fluid trying to
enter the fit. The tendency, then, is for the power fluid circuit. To
lose clean fluid and to retain the solid particles.
fig.9 surface facilities for a closed power fluid (CPF) system
Over a period of time these three factors allow the power fluid in the
closed circuit to become “dirtier” than the fluid emerging or the fluid
entering the closed circuit, unless a part of the re-circulated power fluid is
continually cleaned by the power fluid settling tank (fig. 1). This
“continuous cleaning of part of the re-circulating power fluid” is an
important feature in the design of the CPF system.
When water is used for power fluid, filters may be used instead of
settling tanks for the cleaning process. These filters should remove particles
down to 10 microns.
2.2 OPF System
In the OPF system only two down hole paths are needed: one for
conducting power fluid to the engine and one for conducting spent power
fluid plus production to the surface. These conduits can be two strings of
tubing or tubing string and the tubing/casing annulus. The bold lines on fig.
10 show the surface facilities for an OPF system with two wells. Central
plant of this type can be used for any number of wells.
Usually, the triplex pump and control manifold are located at the
central tank battery, but control manifold can be located at satellite locations.
Even triplex pumps can be located at satellite locations if a small pump is
used at the battery to get the fluid to the suction of the triplex pump.
2.2.1 Power Fluid Tank (OPF)
Oil generally enters the gas boot in surges and contains gas not
removed in the treater. The gas boot removes the last remnants of the gas
which would otherwise keep the tank stirred up. The top section of the boot
should be 36 in. to be effective and, even with this diameter, surges
frequently occur that cause the oil to be carried over the top through the gas
line.
Died oil (gas free) then enters the bottom of the tank which should
have a level spreader. The oil entering her is power oil plus production. At
the vertical mid-point, production is drawn off through the outside riser that
keeps the tank full. From the mid point up, the power oil settling process
takes place. The light solids settled out are carried with the production to
stock, while the heavier particles are settled to bottom and must be removed
periodically.
fig.10 Surface facilities for an open power fluid (OPF) system
fig. 11 schematic of OPF power fluid tank
3 INDIVIDUAL WELL SITE POWER PLANT A well site power plant is a package of components, installed at or
near a well site, that accomplishes the functions normally performed by a
central plant. The basic components consist of:
a) a liquid gas separator
b) centrifugal separators for removing solids from the power fluid.
c) and a surface pump.
These units have the advantages of:
1. portable 2. simple
3. flexible 4. compact
They are always used with an OPF tubing arrangement, but they have
one feature similar to a CPF system. The net production from the well goes
into the flow line while the power fluid is re-circulated at the well site. This
feature simplifies well testing and does not increase the load on the treating
system at the tank battery.
Generally, there will be a choice of either a central system or an
individual will site system. Some choices are obvious, such as:
1. a central system for an offshore platform
2. any cluster of wells, such as in a downtown area or island constructed
for that purpose.
For that wells that are isolated or on wide spacing, the individual well site
system will probably be preferred.
The following flow schematics (fig.’s 12, 13 and 14) show models of
Kobe (solo unit), fluid packed (Unidraulic) and Johnson-Fagg
(Econodraulic) well site power plants. These units must:
1. provide gas free fluid to the surface pump.
2. provide means to choose oil or water for the power fluid.
3. remove the solids from the power fluid.
4. provide surge and reserve capacity for circulating a subsurface pump
to the surface after a pump failure.
fig. 12 Kobe solo unit
Removing solids from the power fluid is usually accomplished by
cyclone centrifugal separators, fig 15. These cyclones require 30-60 psi
pressure drop from inlet (feed) to top outlet (overflow). The ratio of
overflow to underflow out the apex of the cone is controlled by the
relationship of overflow pressure to underflow pressure. Usually the
overflow pressure must be 5-10 psi greater than the underflow to insure a
positive rather than a negative underflow rate. The cyclone internals, feed
nozzle, vortex feeder and apex can be sized to accommodate various rates of
flow.
fig. 13 schematic diagram unidraulic system
fig. 14 Econodraulic fluid flow system
fig. 15 Cyclone centrifugal separator
4 SURFACE PUMPS the surface pumps commonly used are designed specifically for power
fluid service and are supplied by the down hole hydraulic pump
manufacturers. For high pressure clean oil services these pumps usually use
metal to metal plungers and liners, and ball type valves-components which
require little or no maintenance. For water services, plungers and liners with
packing are usually used. Most surface pumps are skid mounted with electric
motors or gas engines.
The discharge lines from the relief valve and back pressure control
valve should not be connected directly to the suction line of the pump but
should be connected to a separate line going back to the tank. The reason for
this is that when oil, even dead oil, is suddenly taken from high pressure to
low pressure, some gas will flash out of solution. This gas will cause a loss
of volumetric efficiency if allowed to enter the pump.
A pulsation dampener may be required in some cases. The pulsations
will be pronounced with water.
For long suction lines an accumulation chamber may be required to
prevent separating the liquid into slugs. A cross-section of a triplex pump is
shown in fig. 16.
fig.16 cross-section of surface pump
5 CONTROL MANIFOLDS 5.1 Manifolds
Power fluid distribution manifolds, used at central plants, are supplied
by the down hole pump manufacturers and are made in modular header
sections that can be added to or subtracted from the manifold easily. These
manifolds usually contain pilot-operated control valves that keep the volume
of power fluid going to each well constant, regardless of pressure changes in
the system. A pressure controller (back pressure regulator) is also used to
maintain a constant pressure on the surface pump. Additionally, high
pressure meters and gauges are included for each well.
The following summarize the purpose of these manifolds:
1. distribute the flow of power fluid to the individual wells
2. regulate the flow rate to individual wells
3. provide a means of metering the flow to each individual well
4. provide a means of measuring pressure to each individual well
5. provide a means for running soluble plugs in surface lines
6. provide a manual or automatic valve to control manifold pressure by
by-passing excess power fluid
Generally, 100 to 300 psi. more fluid pressure is brought to the manifold
than goes to the wells.
5.2 Constant flow control valves
constant flow valves used in these manifolds work on the principle of
a constant pressure drop across the main control valve as shown in fig. 17.
A spring/diaphragm/pilot valve combination maintains the constant
pressure differential across the main valve regardless of changes in the
upstream and downstream pressures.
6 WELL HEADS The well head for a free pump should provide the following functions:
1. direct the power fluid down the tubing for “pump in and operate”.
2. direct the power fluid down the proper conduit for “pump out”.
3. shut power fluid line and provide a means to bleed pressure from the
tubing.
4. catch and hold the pump.
5. be a safety device to prevent high pressure from accidentally being
applied to the casing.
7 TUBING ARRANGEMENTS When the pump is screwed onto the power tubing and lowered into the
well by that tubing, it is called a fixed type pump. When the pump fits inside
the power tubing and is free to be circulated to bottom and back out again,
fig.17 constant flow control valve
it is called a free pump. Either type can be a CPF or OPF system.
Hydraulic pumps are particularly suitable for:
1. deep wells
2. directionally drilled wells
3. multiple completed wells
4. offshore platform wells
7.1 Fixed insert
Fixed inserts is the name applied to the tubing arrangement shown in fig.
18. in this arrangement gas is vented through the casing.
7.2 Fixed casing
Fixed casing is the name applied to the arrangement shown in fig. 19,
where the casing is used for one of the flow paths. In this arrangement, the
gas must be handled by the pump. Installations of this type generally use
large pumps. Sometimes a separate tubing string is used to vent the gas from
beneath the packer, as shown in fig. 20. Venting is necessary for wells
producing below the bubble point with high gas-liquid ratios.
7.3 Parallel free
Parallel free installations are shown in fig. 21, 22 and 23. The pump in
fig. 23 is unseated through the power return tubing, hence it is referred to as
power return unseat (PRU). The pump in fig. 21 and 22 are the conventional
production unseat type gas is vented through the casing in these
arrangements.
7.4 Casing free
Casing installations are shown in figs. 24, 25, 26 and 27.
Fig. 25 is sometimes used instead of fig. 21 to reduce friction, since
the return column is the large annular flow area.
All of the gas must be handled by the pumps in figs. 24, 26 and 27.
More hydraulic pumps are installed, as shown in fig. 24, than any
other type of installation because it is the lowest-cost type.
When venting of gas is necessary, figs. 21 and 22 are the most popular
installations.
For large production rates in small casing, fig. 19 is the most popular.
fig.18 Fixed Insert Tubing Arrangement (OPF) fig.19 Fixed Casing Tubing Arrangement
fig. 20 Fixed Casing With Gas Vent (OPF) fig.21 Parallel Free Tubing Arrangements
fig. 22 Parallel Free Tubing Arrangement fig.23 Parallel Free Tubing Arrangement
fig. 24 Casing Free Tubing Arrangement fig. 25 Casing Free Tubing Arrangement
fig. 26 Casing Free Tubing Arrangements fig. 27 Casing Free Tubing Arrangements
7.5 Other Tubing Arrangements
7.5.1 Reverse Circulation
Fig. 28 shows the reverse circulation system where power fluid is
directed down the small string and production up the large string. This
system allows the largest flow rate, power fluid plus production, to use the
largest tubing string to reduce the overall fluid friction in the system. The
pump requires an automatic latching device to hold it down during the
pumping operation and requires a releasing tool to be dropped before the
pump can be pumped to the surface.
7.5.2 Dual Wells
when two zones have different reservoir pressures, it is not practical to
allow to allow communication between them because the higher pressure
zone will flow into the lower pressure zone . There are many variations
possible for dual wells. Two separate power fluid tubes are almost always
used because the separate zones will undoubtedly require different surface
operating pressures. If only one tube were to feed two pumps, speed control
would be hopeless. One possible tubing arrangement is shown in fig. 29.
7.5.3 Tandem Pump
when the well capacity requirements exceeds what can be produced by a
single pump, it is possible to install two pumps in parallel or tandem to
double the displacement of the downhole equipment. The pumps are
physically connected to form a single unit, but each pump is free to run
independently. Fig. 29 is a method of installing two pumps in a single zone
well to double the capability of the equipment.
7.5.4 Safety Valves
Offshore wells and urban town-site wells usually require subsurface
safety valves in the tubing. These valves require an auxiliary pressure source
to keep them open. If disaster strikes and the well head is broken off or
damaged these valves, set some distance down the tubing, close and keep the
well under control. Fig. 31 shows such a valve set between the packer and a
hydraulic pump. The actuating pressure is obtained from the high pressure
fig. 28 Reverse circulation tubing arrangement
fig. 29 Dual Well Tubing Arrangement fig. 30 Tandem Pump
power fluid. If disaster strikes at the surface, the power fluid pressure will be
released and the safety valve will shut in the tubing and the casing as well.
fig. 31 Safety Valve Arrangement
8 DESIGN CONSIDERATIONS AND CALCULATIONS When designing a hydraulic pumping installation the following
decisions must be made:
1. decide on an OPF or a CPF system.
2. decide whether to vent the gas or to pump the gas
3. choose a down hole tubing arrangement.
4. choose a pump to fit the tubing and the well requirements.
5. choose a central or a well site power plant.
6. choose a surface pump.
7. design the power fluid cleaning system.
8.1 OPF or CPF
If surface space at the battery is limited, as in a town-site
location or on an offshore platform, or if ecological factors are
important, choose a closed system.
Using water will minimize the hazard of leaks causing
ecological and fire problems but will cause the surface pump to
be more expensive and will require considerable operating
expense for additives (lubricant and oxygen scavenger) to the
power water.
If none of these factors are compelling, then choose an open
power fluid system (OPF). Oil should generally be chosen
because the chemical additives for water are lost in the open
power fluid system and require continuous injection.
8.2 Vent gas or pump gas
The lowest-cost installations are those that don’t vent the gas (figs. 19,
24, 26, 27) but these installations are undesirable in wells that have
both low producing bottom hole pressures and high gas-oil ratios.
Usually an installation that vents the gas (figs. 18, 20, 21, 22, 23 and
25) is a necessity when the gas-liquid ratio is over 500 SCF/b and the
pumping bottom hole pressure is lower than 400 psi.
Vent the gas to obtain greater efficiency values.
A hydraulic pump is well suited to pump the gas without gas locking
problems, but the efficiency is much better if the gas can be vented.
8.2.1 Venting Gas
Installation that vents the gas are shown in figs. 18, 20, 21, 22, 23, 25
and 28. If friction in the return tubing were too great for the simple parallel
free (fig. 21), then the casing free with gas vent (fig. 26), the reverse
circulation (fig. 28), or the fixed casing with gas vent (fig. 20) could be used.
Usually more gas will be vented through the casing than through a tubing
vent, but usually favor the tubing vent type of installation.
8.2.2 Pumping Gas
for installations that require the pump to compress free gas, fig. 32
gives the theoretical liquid pump and displacements at different gas-oil
ratios and bottom hole pressures. If the indicated displacement is low (30-
40%), the gas should be vented instead of pumped. At this point the IPR
curve for the well should be consulted to determine if a higher bottom hole
pressure can be allowed. If the well is being produced the bubble point,
Vogel’s reference curve (fig. 33) for solution gas drive well’s is used in
calculations.
fig. 32 Theoretical Volumetric Efficiencies Of Casing Pumps
fig. 33 Vogel’s Reference Curve
8.3 Pumps
The schematic drawings in appendix A show each pump making an
upstroke in an OPF casing free installation. Some of the pumps have two
engine pistons and some have two pump pistons. Engine reversing valves
are located at the top of some pumps, in the middle of some pumps, and in
the engine piston of other pumps.
8.3.1 Pump Selection
In many cases the proper pump for a given well can be chosen directly
from the specification tables. The first column lists the pump size, which
also identifies the tubing size that it will run in. The second column lists
values for quantity called P/E these values are related to the surface pressure
required for a given lift. To limit surface pressure to the generally acceptable
maximum of 5000 psi, use the following rule of thumb equation:
10000 Maximum P/E =
Net Lift, ft
The third column of the specification table lists the maximum pump
displacement. It is good practice to design for 85% or less of the pump’s
maximum rated capacity.
Usually when two or more pump sizes can be used, the one with the
greatest maximum fluid lift capability (lowest P/E value) will be chosen.
This is because it will require less surface power fluid pressure to operate.
This will be easier on the surface pump and will have less high pressure
power fluid slippage in the bottom hole pump itself.
The power fluid rate required to produce a given amount of production
depends on the values in columns four and five of the pump specification
tables.
8.3.2 Power Fluid Rate
Power fluid rate is a function of:
Pump end efficiency.
Engine end efficiency.
The displacement per SPM from the specification tables.
The following symbols will be used:
q1 = engine end displacement per SPM, b/d per SPM
Q’1 = theoretical power fluid rate, b/d(q1 x SPM )
Q1 = actual power fluid rate, b/d
q4 = pump end displacement per SPM, b/d per SPM
Q’4 = theoretical production rate, b/d (q4 x SPM)
Q4 = actual production rate, b/d (Q4 = Q5 + Q6)
Q5 = oil production rate, b/d
Q6 = water production rate, b/d
Q’1/Q1 = engine end efficiency
Q4/Q’4 = pump end efficiency
The values for q1 and q4 are obtained from columns four and five of the
pump specification tables. A new pump has an engine end efficiency around
95% and a pump end efficiency above 90%. Good design practice is to use
90% engine end and 85% pump end efficiencies and to select a pump that
will operate below 85% of its rated speed.
If the pump is pumping from beneath a packer and consequently
handling gas, the pump end efficiency should be obtained from fig. 32. The
above definitions can be written:
Q4 = Q’4 (Q4 / Q’4) = (q4 x SPM)(Q4 / Q’4)
Q’1 q1 x SPM Q1 = =
Q’1 / Q1 Q’1 / Q1
Overall volumetric efficiency, Nυ
Nυ = (pump end efficiency) x (engine end efficiency)
=Q4/Q’4 x Q’1 /Q1 = Q4/Q1 x Q’1/Q’4
= Q4/Q1 x q4/q1
8.3.3 Pump Friction
The pressure required to operate a hydraulic pump under “no load”
conditions is shown in fig. 34. This chart represent the mechanical and
hydraulic friction in the pump. From the curves in figs. 35 and 36, the power
fluid viscosity at the bottom hole temperature can be obtained to use with
the pump friction chart. The values obtained from fig. 34 show maximum
values based on the largest pump piston operating at 100 % pump end
efficiency. When the fluid rate through the pump end is reduced by smaller
piston or by gas, the total friction will be somewhat lower than the chart
predicts. This is because approximately 25% of the total friction is fluid
friction in the pump end of the pump. In equation form the ∆P from fig. 34
is:
∆P = FEE + FPE
where :
FEE = engine end friction = 0.75 ∆PFPE = pump end friction = 0.25 ∆P
fig. 34 Pressure Required To Operate A Hydraulic Pump Under No Load Conditions
fig. 35 Power Fluid Viscosity At Bottom Hole Temperature
fig. 36 Power Fluid (Water)Viscosity at Bottom Hole Temperature
fig. 37 Pressure and Friction Losses Affecting Hydraulic Pumps
8.3.4 Surface Pressure Calculations
The various pressures, friction losses, and fluid densities involved in
CPF and OPF systems are shown in fig. 37.
P1 = the total pressure available to drive the engine
P2 = the total pressure the engine must discharge against.
P3 = the pressure against which the pump end must discharge
P4 = the pressure by which the pump end being filled.
Fig. 38 illustrate those cross section areas of the Kobe A pump which
are involved with the various pressures.
To find Ps we must first find SPM, Fp, Q1, F1 (and F2 for the CPF
system), G3 and F3. the procedure in detail is:
1. from Q4, pump end efficiency, and pump displacement (from
specification tables, b/d per SPM) calculate SPM using equation:
Q4 = Q’4 (Q4/Q’4 ) = (q4 x SPM) ( Q4 / Q’4 )
2. follow the procedure in section 8.3.3 to find Fp. (use viscosity at
bottom hole temperature from figs. 36 or 37. specific gravity from
table
3. from SPM, engine end efficiency and engine displacement (b/d per
SPM) calculate Q1 using equation:
Q’1 q1 x SPM Q1 = =
Q’1 / Q1 Q’1 / Q1
4. using the tubing friction charts of appendix figs. 1B to 27B and Q1,
and F1 and F2. use average temperature of column for determining
viscosity.
5. Calculate G3 using:
Q1G1 + Q5G5 + Q6 G6
G3 =
Q1 + Q4
Where:
Q4 = Q5 ( oil production ) + Q6 ( water production )
6. Using the tubing friction charts of figs. 1B through 27B and Q4
(CPF) or Q3 (OPF) and F3, where the specific gravity of Q3 is obtained
by dividing G3 by 0.433. The viscosity is obtained by:
Q1υ1 + Q5 υ5 + Q6 υ6
υ3 = Q1 + Q4
7. substituting in the following equations and solve for Ps:
P1 – P2 – (P3 – P4)P/E – Fp = 0
P1 – P3 – (P3 – P4) P/E – Fp = 0
fig. 38 pressure acting on a Kobe type A pump
8.3.5 Horsepower calculations
A useful oil field hydraulic horsepower equation is:
Horsepower = ∆P x Q x 1.7 x 10-5
Where:
∆P = change in pressure, psi
Q = liquid rate, b/d
This equation can be used for surface horsepower and for work done by the
pump end of the down hole pump.
9 DESIGN OF COMPLETE SYSTEM 9.1 Procedure For The Design Of Equipment For One Well
this procedure serves as a guide to select a pump and determine the
surface pressure needed for one well.
1. determine the required flowing pressure for the desired rate.
2. decide upon the type of installation and whether or not to vent the
gas.
3. find the pump displacement to produce the desired rate. (find the
fluid displacement factor and use a pump efficiency of about 80
%).
4. select a tentative pump to handle the required displacement.
Normally we try to select a pump such that the desired
displacement rate is no greater than 85 % of the maximum pump
capacity.
5. check the required pump speed.
6. determine the power oil requirements assuming an engine
volumetric efficiency of 80 %.
7. determine the total volume of return fluid and the pressure exerted
by the return fluid column.
8. determine the friction loss of power fluid going downwards.
9. determine pressure loss due to friction for return fluid.
10.find total return fluid pressure.
11.find effective pressure of column of power oil.
12.determine pump friction.
13.determine surface operating pressure of power oil.
14.select an appropriate triplex pump.
10 URFACE TROUBLESHOOTING GUIDE the following listing will serve as a guide for analyzing and trouble-shooting the
subsurface pumping unit.
INDICATION CAUSE REMEDY
1) Sudden increase in the operating pressure – pump stroking
a) Lowered fluid level which causes more net left.
If necessary, slow pump down.
b) Paraffin build-up or obstruction in power oil line, flow lone or valve.
Run soluble plug, hot oil or remove obstruction.
c) Pumping heavy material, such as salt water or mud.
Keep pump stroking – don’t shut down.
d) Pump beginning to fail. Retrieve pump and repair.
2) Gradual increase in operating pressure – pump stroking
a) Gradually lowering fluid level. Standing valve or formation plugging up
Surface pump and check.Retrieve standing valve.
b) Slow build – up of paraffin. Run soluble plug or hot oil
c) Increasing water production Raise pump SPM and watch pressure.
3) sudden increase in operating pressure – pump not stroking
a) Pump stuck or stalled
Alternately increase and decrease pressure. If necessary, unseat and reseat pump. If this fails to start pump, surface and repair.
b) Sudden change in well conditions requiring operating pressure in excess of triplex relief valve setting.
Raise setting on relief valve.
c) Sudden change in power oil-emulsion, etc. Check power oil supply.
d) Closed valve or obstruction in production line Locate and correct.
4) sudden decrease in operating pressure – pump stroking. ( Speed could be
a) Raising fluid level – pump efficiency up.b) Failure of pump so that part of power oil is bypassed Surface pump and repair.
c) Gas passing through pump.
INDICATION CAUSE REMEDY
increased or reduced )
d) Tubular failure – downhole or in surface power oil lone. Speed reduced
Check tubular
e) Broken plunger rod. Increased speed Surface pump and repair
f) Seal sleeve in bottom hole assembly washed or failed. Speed reduced
Pull tubing and repair bottom hole assembly.
5) sudden decrease in operating pressure – pump not stroking.
a) Pump not on seat. Circulate pump back on seat b) Failure of production unit or pump seat. Surface pump and repair
c) Bad leak in power oil tubing string. Check tubing and pull and repair if leak
d) Bad leak in surface power oil line. Locate and repair
e) Not enough power oil supply at manifold.
Check volume of fluid discharged from triplex. Valve failure, plugged supply line, lower power oil supply, excess bypassing, etc., all of which could reduce available volume.
6) drop in production – pump speed constant
a) Failure of pump end of production unit Surface pump and repair
b) Leak in gas vent tubing string Check gas vent system c) Well pumped – off pump speeded up Decrease pump speed d) Leak in production return line Locate and repair e) Change in well conditions
f) Pump or standing valve plugging Surface pump and check.Retrieve standing valve.
g) Pump handling free gas Test to determine best operating speed
7) gradual or sudden increase in power oil required to maintain pump speed. Low engine efficiency
a) Engine wear Surface pump and repair
b) Leak in tubulars – power oil tubing, bottom hole assembly, seals or power oil line.
Locate and repair
INDICATION CAUSE REMEDY 8) erratic stroking at widely varying pressures
a) Caused by failure or plugging of engine Surface pump and repair
9) stroke “down-kicking” instead of “up – kicking”
a) Well pumped off – pump speeded up.
Decrease pump speed.Consider changing to smaller pump end
b) Pump intake or downhole equipment plugged.
Surface pump and up. If in down-hole equipment, pull standing valve and back flush well.
c) Pump failure (balls and seats). Surface pump and repair.
d) Inaccurate meters or measurement. Recheck meters.Repair if necessary.
10) apparent loss of, or unable to account for, system fluid.
a) System not full of oil when pump was started due to water in annulus U – tubing after circulating, well flowing or standing valve leaking.
Continue pumping to fill up system. Pull standing valve. If pump surfacing is slow and cups look good.
b) Inaccurate meters or measurement. Recheck meters. Repair if necessary.
c) Leaking valve, power oil or production line or packer. Locate and repair
d) Affect of gas on production metering. Improve gas separation
e) pump not deep enough. Lower pump.11) well not producing – (a) pressure increase, stroking. (b) pressure loss, stroking.
a) Engine plugging, flow line plugging, broken engine rod, suction plugged.
Surface unit and repair. Locate restriction in flow line.Pull standing valve.
b) Standing valve leaking. Tubular leaking.
Pull standing valve. Check tubulars.
11 ADVANTAGES AND DISADVANTAGES 11.1 Advantages
1. depth is not a limiting factor. Many installations are below 12,000 ft
producing rates of 150 – 300 b/d.
2. the speed and size of the pump can be easily changed to keep up with
well conditions.
3. highly viscous and heavy crudes benefit from mixing with a lighter
power oil.
4. the pump may be circulated to the surface without pulling the tubing.
Inspection, service, and replacement costs are usually low.
5. a central station at the surface may handle a number of wells. This
allows the wellsite landscaping or camouflage. Also, corrosion can be
minimized in a closed system if the oxygen is less than 50 b/d.
6. modern day one-well units offer a compact unit for isolated wells.
11.2 Disadvantages
1. initial capital cost is high. High pressure equipment, power fluid lines,
and wellheads are required. Facilities must be provided to filter, clean
and treat the power fluid. Tubulars must be of sufficient size and must
be of high pressure tight.
2. corrosion and abrasives will reduce operating life due to close
tolerances on the surface and downhole equipment.
3. for power oil systems the volume required may become highly
expensive at today’s crude prices and especially so if power fluid
losses are major.
4. since this is usually a high pressure operation, maintenance costs for
surface equipment may be quite high.
5. high temperatures can cause the packing cups to fail, thereby
preventing ease of pumping out the pump for repairs.
6. it needs well – trained people to operate efficiently.
7. fire hazard for gas engine operation – if there is a high pressure leak in
the power pump, a fire could burn up the whole installation including
power oil and stock tanks.
8. well testing in central systems is a problem if wells make water. For
accurate well tests, only one well at a time can be operated without
special metering, manifolding and test equipment, which ups the
initial cost.
9. corrosive production, in pumps set on packers, fixed or free , there is
no means of treating the pump end for corrosion inhibition. An
exception is when a vent string is installed and a chemical can be put
down the vent string to treat the pump end. Inhibitor is power fluid
only protects the engine and tubing.
12 REFERENCES
1. “The Technology Of Artificial Lift Methods” Vol. 2b.
2. “Petroleum Engineering Handbook” third printing, SPE.
