Production Optimization of SRP wells using PROSPER software

Pandit Deendayal Petroleum University
Gandhinagar
Summer Internship Project
Essar Oil and Gas Exploration & Production Limited
Mehsana
PRODUCTION OPTIMIZATION OF SRP WELLS USING
PROSPER
10 June 2019 – 15 July 2019
Under The Mentorship Of
Mr. Sagar Ranjan
Installation Manager
EOGEPL, Mehsana
Submitted By
Ronak M. Pandya
16BPE072
B. Tech Petroleum Engineering - Upstream

CERTIFICATE
This is to certify that the report titled “ PRODUCTION OPTIMIZATION OF SRP WELLS
USING PROSPER " submitted by Ronak Pandya to Essar Oil & Gas Exploration &
Production Ltd.(EOGEPL), for the award of degree of Bachelor Of Technology in Petroleum
Engineering is a bonafide record of Project work carried out by him under my supervision and
guidance. The content of this project, in full or parts have not been submitted to any other
Institute for award of any other degree or diploma.
Mr. Sagar Ranjan
(Manager - Production)

ACKNOWLEDGEMENT
I am really grateful to all personnel who have facilitated and helped me in undertaking and
fulfilling my internship here at EOGEPL, Mehsana.
I would like to thank Mr. Vijay Vispute and Management of EOGEPL to provide me an
internship opportunity.
I would also like to thank Mr. Chalapathy Rao, Deputy General Manager, EOGEPL, Mehsana
who helped me in my project by teaching and providing with necessary information and
guidance wherever required. I would like to extend my thankfulness to Mr. Sagar Ranjan,
Manager - Production, EOGEPL, Mehsana because of whom I was able to envisage and
implement this project and who guided me to the successful completion of this project by
mentoring me and honing my skills wherever required. I would also like to thank Mr. Pankaj
Grover, Manager- Production, EOGEPL, Mehsana who showed me the workings and
complexities involved in the oil field. I would also like to thank Mr. Subramaniam Rao,
Manager- Finance, EOGEPL, Mehsana who helped me in understanding the financial aspect of
the oil and gas industry.
I am grateful to Essar Oil & Gas Exploration & Production Ltd. for providing me an opportunity
to pursue my project and providing me with the necessary help wherever required. It is my
radiant sentiment to place on record my best regards, deepest sense of gratitude to my
seniors and coworkers for all the help and support provided by them, without whom, this
project would not be possible.
I am also grateful to Pandit Deendayal Petroleum University for providing me with an
opportunity to pursue my project and for providing me with the necessary help
wherever required.

Page | 1
Contents
1 Introduction to Artificial Lift Methods:.................................................................................................3
1.1 PURPOSE OF ARTIFICIAL LIFT ........................................................................................................4
1.1.1 GAS LIFTING..........................................................................................................................4
1.1.2 Electric Submersible Pumps.................................................................................................5
1.1.3 Beam Pumps.........................................................................................................................5
1.1.4 Progressing Cavity Pumps....................................................................................................5
1.1.5 Plungers ................................................................................................................................5
1.1.6 Hydraulic Pumps...................................................................................................................6
1.2 INITIAL SCREENING CRITERIA........................................................................................................7
2 Sucker Rod Pumping ..........................................................................................................................10
2.1 Components of Sucker Rod Pumping System.............................................................................11
2.1.1 Prime Movers .....................................................................................................................13
2.1.2 Speed Reducer....................................................................................................................13
2.1.3 The Pumping Unit...............................................................................................................13
2.1.4 Wellhead Equipment..........................................................................................................14
2.1.5 Subsurface Pumps ..............................................................................................................16
2.2 TYPES OF SUCKER ROD PUMP.....................................................................................................21
2.2.1 Class I lever system or conventional type: ........................................................................21
2.2.2 Air Balanced Type...............................................................................................................21
2.2.3 Mark II Unit.........................................................................................................................21
2.3 THE PUMPING CYCLE ..................................................................................................................23
2.4 Different problems associated with SRP.....................................................................................24
2.4.1 Fluid Pound.........................................................................................................................24
2.4.2 Gas Interference.................................................................................................................25
2.4.3 Gas Lock..............................................................................................................................25
3 OPERATING PARAMETERS IN SUCKER ROD PUMPING System ..........................................................26
3.1 Approximate Calculation Models (Jennings & Texas, 1989).......................................................26
3.1.1 Polished Rod Loads.............................................................................................................27
3.1.2 Peak Net Torque.................................................................................................................28
3.1.3 Effective Plunger Stroke.....................................................................................................29
3.1.4 Pump displacement............................................................................................................31

pg. 2Summer Internship Report-2019
3.2 API recommended design procedure (Jennings & Texas, 1989) ................................................32
4 ANALYSIS OF THE SUCKER ROD PUMPING UNITS...............................................................................36
4.1 Dynamometers & Dynagraphs (Liquid & Pump, 2014)...............................................................36
4.1.1 Basic dynamometer types..................................................................................................36
4.1.2 Uses of dynamometer cards ..............................................................................................38
4.1.3 Analysis of dynamometer shape cards..............................................................................38
4.2 Determination of Annular Liquid Levels .....................................................................................43
4.2.1 Echometer...........................................................................................................................44
5 Optimization of Sucker rod Pumping System .....................................................................................47
5.1 Optimization using PROSPER ......................................................................................................50
5.1.1 About PROSPER: (Manual, 2010) .......................................................................................50
5.1.2 Applications........................................................................................................................50
5.2 Optimization of Well#01 using PROSPER : a case study .............................................................52
Step by step design and optimization.....................................................................................................52
Input Data forSRP-Design .......................................................................................................................53
5.3 Conclusion...................................................................................................................................64
6 Appendix-1..........................................................................................................................................65
6.1 API Surface Pumping Unit Designation.......................................................................................65

1 Introduction to Artificial Lift Methods:
Most of the oil wells, at the early stages of their life, flow naturally to the surface. These wells are
called self-flowing wells. In these wells, the reservoir fluids flow to the surface due to the natural
energy of the reservoir. But due to continuous production of the well fluids, there is depletion of
the natural energy of the reservoir and subsequently some kind of man made efforts have to be
applied to bring the well fluids to the surface facilities.
Artificial lift refers to the use of artificial means to increase the flow of liquids, such as crude oil
or water, from a production well. This is generally achieved by means of a downhole pump or by
injection of natural gas to the bottom of the fluid column to decrease the specific gravity of the
fluid column.
The earliest documented reciprocating walking beam artificial lift system described in the
Egyptian historical writing dated 476 AD and called Shadof as shown in figure 1. It was limited
to lift low volume of water from shallow depth.
With the time, the new discovered oil reservoirs become harder in production as fluid type,
production rate, reservoir pressure, well depth, hole characterizations etc. This push the
manufacturer to present and develop different forms of surface and subsurface equipment in order
to produce these reservoir.
Artificial lifting methods are used to produce fluids from wells that are already dead or to increase
the production rate from flowing wells. The importance of artificial lifting is clearly seen from the
total number of installations: according to one estimate there are approximately two million oil
wells worldwide, of which about 50% are placed on some kind of artificial lift.
There are several lifting mechanisms available for the production engineer to choose from. One
widely used group of artificial lift methods uses some kind of a pump set below the liquid level to
increase the pressure of the well stream so as to overcome the pressure losses occurring along the
Figure 1 First Artificial lift system unit in history

flow path. Other lifting methods use compressed gas, injected from the surface into the well tubing
to help the lifting of well fluids to the surface.
1.1 PURPOSE OF ARTIFICIAL LIFT
Any system that adds energy to the fluid column in a wellbore with the objective of initiating and
improving production from the well. Artificial lift systems use a range of operating principles,
including rod pumping, gas lift and electrical submersible pumps.
Artificial lift is required in the following situations
i) If there is not enough natural energy in the form of reservoir pressure to overcome surface
and hydrostatic head pressure, petroleum liquid will not flow to the surface regardless of
the volume of oil in the reservoir.
ii) In some of the wells, the natural energy of the reservoir may not drive the well fluids to the
surface in sufficient quantities.
iii) In some of the gas wells, when water enters the well, it generally creates a hydrostatic head
which opposes the flow of the free gas to the surface facilities. Thus, water has to be
removed by artificial lift and this operation is called dewatering of the gas wells.
Thus, the purpose of artificial lift is to maintain or create a steady low pressure or reduced pressure
in the well bore against the sand face, so as to allow the well fluid to come into the well bore
continuously. Thus, maintaining a steady low pressure against the sand face, which is called the
flowing bottom hole pressure is the fundamental basis for the design of any artificial lift
installation.
1.1.1 GAS LIFTING
All versions of gas lifting use high-pressure gas (in most cases natural gas, but other gases like N2
or CO2 can also be used) injected in the well stream at some downhole point. In continuous-flow
gas lift, a steady rate of gas is injected in the well tubing, aerating the liquid and thus reducing the
pressure losses occurring along the flow path. Due to the reduction of flow resistance, the well’s
original bottom hole pressure becomes sufficient to move the gas/liquid mixture to the surface and
the well starts to flow again. Therefore, continuous-flow gas lifting can be considered as the
continuation of flowing production. In intermittent gas lift, gas is injected periodically into the
tubing string whenever a sufficient length of liquid has accumulated at the well bottom. A
relatively high volume of gas injected below the liquid column pushes that column to the surface
as a slug. Gas injection is then interrupted until a new liquid slug of the proper column length
builds up again. Production of well liquids, therefore, is done by cycles. The plunger-assisted
version of intermittent gas lift, a.k.a. plunger lift, uses a special free plunger traveling in the well
tubing and inserted just below the accumulated liquid slug in order to separate the upward-moving
liquid from the gas below it. These versions of gas lift physically displace the accumulated liquids
from the well, a mechanism totally different from that of continuous-flow gas lifting.

1.1.2 Electric Submersible Pumps
Perhaps the most versatile AL systems are electric submersible pumps (ESPs). These pumps
comprise a series of centrifugal pump stages contained within a protective housing. A submersible
electric motor, which drives the pump, is deployed at the bottom of the production tubing and is
connected to surface controls and electric power by an armored cable strapped to the outside of
the tubing.
An ESP derives its versatility from a wide range of power output drives and from variable speed
drives that allow operators to increase or decrease volumes being lifted in response to changing
well conditions. Additionally, modern ESPs are able to lift fluids with high gas/oil ratios (GORs),
can be designed using materials and configurations able to withstand corrosive fluids and
abrasives and can operate in extreme temperatures.
1.1.3 Beam Pumps
A beam pump system is composed of a prime mover, a beam pump, a sucker rod string and two
valves. The gas- or electric-driven prime mover turns a crank arm, which causes a beam to
reciprocate. The resulting up and down movement lifts and lowers a rod string attached to one end
of the beam. The motion of the rod string opens and closes traveling and standing ball valves to
capture fluid or allow fluid to flow into the wellbore. In some configurations, the valves are part
of an integrated assembly called an insert pump, which can be retrieved using the rods while
leaving the production tubing in place.
Beam pump equipment and parameters valves, prime mover, rod and tubing diameter, and stroke
length are determined according to reservoir fluid composition, depth to the fluid top and reservoir
productivity. The systems are typically equipped with timers that turn the pumps off to allow fluid
time to flow through the formation and into the wellbore. The timer then restarts the pump for a
period calculated to produce the fluid that has accumulated in the well.
1.1.4 Progressing Cavity Pumps
The progressing cavity pump consists of a rotor placed inside a stator. The rotor is a screw that has
deep round threads and extremely long pitch the distance between thread tops. The stator has a
longer pitch and one more thread than the rotor. When the rotor turns inside the stator, the thread
and pitch differences create a cavity within the pump barrel that is filled by formation fluid. The
rotor is turned by a rod string connected to a motor at the surface or by an electric-drive motor
located downhole at the pump moving the fluid up hole.
1.1.5 Plungers
Plunger lift systems, the simplest form of artificial lift, consist of a piston, or plunger, that has only
small clearance through the production tubing and is allowed to fall to the bottom of the well. They
are used primarily in high GOR wells to lift liquids out of the well to allow the gas to be recovered.
A valve on the surface is closed, which causes natural pressure from the reservoir to build in the
casing annulus. At a preset pressure level, the valve on the surface opens and pressure from the
annulus enters the tubing below the plunger, which forces it upward. The plunger pushes the fluid
column above it to the surface. When it reaches the surface, the plunger enters the lubricator, a

Figure 2 Different artificial lift system
short section of pipe, which extends above the wellhead. Because the plunger is no longer in the
flow path, the gas that provided the lifting energy can pass beneath it and along the flow line.
When the pressure at the wellhead has dropped to a predetermined level, the surface valve closes,
the plunger falls from the lubricator to the bottom of the well, and the cycle is repeated.
1.1.6 Hydraulic Pumps
In some situations, operators may install a hydraulic pumping system that pumps a fluid, called a
power fluid, from the surface through tubing to a subsurface pump. The subsurface pumps, which
may be jets, reciprocating pistons or rotating turbines, force the formation fluids and the power
fluid up a second tubing string to the surface.
Hydraulic pumping systems offer two specific advantages. Because the subsurface pump is free
floating, it can be circulated out of the hole for repair with little intervention cost. And the power
fluid, which is typically refined oil, mixes with the produced fluid; the resulting fluid column exerts
a lighter hydrostatic pressure than does the formation fluid alone, reduces the resistance to flow
and lessens the work required of the downhole pump. As a consequence, hydraulic pumps are
frequently chosen for use in heavy oil operations.

1.2 INITIAL SCREENING CRITERIA
Artificial lift consideration should ideally be part of well planning process. Future lift requirements
will based on the overall reservoir exploitation strategy, and will have a strong impact on the well
design.
Table 1 and 2 below summarize some of the key factors that influence the selection of an artificial
lift method
Table 1
Reservoir Characteristics (Brown, 1982)
IPR Defines its production potential
Liquid
Production
Rate
The anticipated production rate is a controlling factor in selecting a lift method;
Positive displacement pumps are generally limited to rates of 4000-6000B/D
Water Cut High water cuts require a lift method that can move high volume of fluid
Gas liquid
ratio
A high GLR generally lowers the efficiency of pump- assisted lift
Viscosity Viscosities less than 10 cp are generally not a factor in selecting a lift method;
High viscosity fluid can cause difficulties, particularly in sucker rod pumps
Formation
volume factor
Ratio of reservoir volume to surface volume; determines how much total fluid
must be lifted to achieve the desired surface production rate
Reservoir
drive
mechanism
Depletion drive: Late stage production may require pumping to produce low
fluid volumes or injected water
Water drive: High water cuts may cause problems for lifting systems
Gas cap drive: Increasing gas liquid ratios may affect lift efficiency.
Other
reservoir
problems
Sand, paraffin, or scale can cause plugging and/or abrasion. Presence of H2S,
CO2 or salt water can cause corrosion. Downhole emulsions can increase
backpressure and reduce lifting efficiency. High bottomhole temperatures can
affect downhole equipment.
Hole characteristics
Well depth The well depth dictates how much surface energy is needed to move the fluids
to surface, and may place limit of sucker rod and other equipment
Completion
type
Completion and perforation skin affects inflow perforation
Casing and
tubing size
Small diameter casing limits the production tubing size and constrain multiple
options.
Small diameter tubing will limit production rate, but larger tubing may allow
excessive fluid fallback.
Wellbore
deviation
Highly deviated wells may limits bean pumping or PCP because of drag,
compressive force and potential of rod and tubing wear

Table 3 summarizes typical characteristics and applications for each artificial lift. These are
general guidelines, which vary among manufacturers and researchers. Each application need to be
evaluated on a well-by-well basis.
Table 2
Surface and Field Operation Considerations in Selecting an Artificial Lift Method
(Brown, 1982)
Surface characteristics
Flow rates Flow rates are govern by well head pressures
and backpressures in surface production
equipment (i.e, separator, chock and flowlines)
Flowline size and length Flowline length and diameter determines
wellhead pressure requirement and affects
overall performance of the production system.
Fluid contamination Scale, paraffin and salt may increase back
pressure on a well
Power sources The availability of electricity or natural gas
governs the type of artificial lift selected.
Diesel, propane or other source may be
considered.
Field location In offshore field, availability of space and
placement of directional wells are primarily
considerations.
Climate and physical environment Affect the performance of surface equipment
Field operating characteristics
Long range recovery plans Field condition may change over time.
Pressure maintenance operations Water or gas injection may change artificial lift
requirement for a field.
Enhanced oil recovery project EOR process changes reservoir fluid property
and required to change artificial lift system.
Field automation If the surface control equipment will
electrically powered , an electrically powered
artificial lift system should be considered
Availability of operating and service
personnel and support services
Some artificial system are low maintenance;
others require regular monitoring and
adjustment. Service requirement should be
considered. Familiarity with field personnel
with equipment should be taken into account.

Table 3- Artificial lift Method-Characteristics and Area of Application
(Brown, 1982)
Operating
parameters
Positive displacement pumps Dynamic
displacement pumps
Gas lift Plunger
lift
Rod
pump
PCP Hydraulic
piston
ESP Hydraulic
jet
Maximum
operating
volume
6000
BFPD
4500
BFPD
4000
BFPD
4000
BFPD
>15000
BFPD
30000
BFPD
200
BFPD
Typical
operating
temperature(
◦C)
40-177 24-65 40-120 40-120 40-120 40-120 50
Typical
wellbore
deviation
0-20
degree
landed
pump
N/A 0-20
degree
landed
pump
0-20
degree
landed
pump
0-50
degree
landed
pump
N/A
Corrosion
handling
Good to
excellen
t
Fair Good Good Excellent Good to
excellent
Excelle
nt
Gas handling Fair to
good
Good Fair Fair Good Excellent Excelle
nt
Solid
handling
Fair to
good
Excelle
nt
Poor Fair Good Good Poor to
fair
Fluid Gravity >8◦ API <35◦
API
>8◦ API >10◦
API
>8◦ API >15◦ API >8◦
API
Servicing Workov
er or
pulling
rig
Workov
er or
pulling
rig
Hydraulic
or wireline
Workov
er or
pulling
rig
Hydraulic
or wireline
Wireline
or
hydraulic
Wellhe
ad
catcher
or
wirelin
e
Prime
movers
Gas or
electric
Gas or
electric
Multicylin
der or
electric
Electric
motor
Multicylin
der or
electric
Compress
or
Well’s
natural
energy
Offshore
application
Limited Good Good Excelle
nt
Excellent Excellent N/A
System
efficiency
45-60% 40-70% 45-55% 35-60% 10-30% 10-30% N/A

2 Sucker Rod Pumping
The history of artificial lifting of oil wells began shortly after the birth of the petroleum industry.
In the earlier times, cable tools were used to drill the wells, and this technology relied on a wooden
walking beam which lifted and dropped the drilling bit hung on a cable. When the well ceased to
flow, it was quite simple to use the walking beam to operate a bottom hole plunger pump and thus
lift the well fluids out to the surface. Thus, the sucker rod pump was born and its operational
principles have not changed yet.
Although, nowadays, the sucker rod pumping equipment does not rely on wooden materials and
steam power, its basic parts are still the same. The most basic part is the walking beam which is
used to convert the rotary motion of the prime mover to reciprocating motion needed to drive the
pump. The second basic part is the rod string, which connects the surface pumping unit to the
downhole pump. The third basic element is the pump itself which works on the positive
displacement principle and consisted of a stationary cylinder and a moving plunger.
The production capacities of rod pumping installations range from very low to high production
rates. As lifting depth increases, a rapid drop in available production rates can be observed. At any
particular depth, different volumes can be lifted depending on the strength of the rod material used.
Stronger material grades allow greater tensile stresses in the string and thus permit higher liquid
production rates. These facts lead to the conclusion that the main factors limiting liquid production
from sucker rod pumping are lifting depth and rod strength. With the latest developments in
pumping technology such as special geometry pumping units, special high-strength rods or
composite rod strings, ultra high slip electric motors etc. can substantially increase the depth range
and the production capacity of this artificial lift system.
The main advantages and disadvantages of the sucker rod pumping are given below:
ADVANTAGES
i) It is a well-known lifting method to field personnel everywhere and is simple to operate
and analyze.
ii) Proper installation design is relatively simple and can also be made in the field.
iii) Under average conditions, it can be used until the end of a well’s life.

iv) Pumping capacities within limits, can easily be changed to accommodate changes in
well inflow performance. Intermittent operation is also feasible using pump-off control
devices.
v) System components and replacement parts are readily available and interchangeable
worldwide.
DISADVATAGES
i) Pumping depth is limited, mainly by the mechanical strength of the sucker rod material.
ii) Free gas present at pump intake drastically reduces liquid production.
iii) In deviated wells, friction of metal parts can lead to mechanical failures.
iv) Surface pumping units requires a large space and it is also heavy and obtrusive.
2.1 Components of Sucker Rod Pumping System
The individual components of a sucker-rod pumping system can be divided in two major groups:
surface and downhole equipment.
The surface equipment includes:
• The prime mover that provides the driving power to the system and can be an electric motor or a
gas engine.
• The gear reducer or gearbox reduces the high rotational speed of the prime mover to the required
pumping speed and, at the same time, increases the torque available at its slow speed shaft.
• The pumping unit, a mechanical linkage that transforms the rotary motion of the gear reducer
into the reciprocating motion required to operate the downhole pump. Its main element is the
walking beam, which works on the principle of a mechanical lever.
• The polished rod connects the walking beam to the sucker-rod string and ensures a sealing surface
at the wellhead to keep well fluids within the well.
• The wellhead assembly contains a stuffing box that seals on the polished rod and a pumping tee
to lead well fluids into the flowline. The casing-tubing annulus is usually connected, through a
check valve, to the flowline.
The downhole equipment includes:
• The rod string composed of sucker rods, run inside the tubing string of the well. The rod string
provides the mechanical link between the surface drive and the subsurface pump.

• The pump plunger, the moving part of a usual sucker-rod pump is directly connected to the rod
string. It houses a ball valve, called traveling valve, which, during the upward movement of the
plunger, lifts the liquid contained in the tubing.
• The pump barrel or working barrel is the stationary part (cylinder) of the subsurface pump.
Another ball valve, the standing valve, is fixed to the working barrel. This acts as a suction valve
for the pump, through which well fluids enter the pump barrel during upstroke.
Figure 3 Different components of SRP

2.1.1 Prime Movers
During the early part of the sucker rod pumping units, they were usually powered by steam engines,
and then the slow speed gas engines became standard. The use of electric motors came into
existence only in the late 1940s and nowadays a majority of the pumping units are run by
electricity. Originally, the main advantages of electric motors were the low cost of electric power,
lower investment costs due to low price of electric motors, and the easy adaptation of motors to
intermittent pumping. The other advantages still exist except the cost of electricity which has
substantially increased through the years.
The choice between electric and gas power is based on several factors. The availability of gas or
electricity at the wellsite has prime importance, but the proper decision cannot be reached without
an analysis of the operating costs involved. The investment cost of a gas engine is much higher
than that of an electric motor, but, on the other hand, gas engines have a much longer service life.
The energy costs when using electric motors have steadily increased during the last few years due
to increased power costs. The gas engines can thus be much more economical if available. Thus,
to decide on the type of prime mover to be used in a given installation, an anticipation of the
operating costs is required.
2.1.2 Speed Reducer
The speed reducer which is also known as the gear reducer is used to reduce the high rotational
speed of the prime mover to the pumping speed required. The usual speed reduction ratio is about
30:1, the maximum output speed is about 20 strokes per minute. Here, two types of speed reducers
are used: geared and chain reducers.
Gear reducers utilize double or triple reduction gearing. In the double reduction unit, there are
three shafts: the high speed input shaft, an intermediate, and a slow speed shaft. The high speed
shaft is driven by the prime mover through a V belt sheave, and the slow speed shaft drives the
crank arms of the pumping unit. The shafts run in bearings mounted in the reducer housing. Sleeve
bearings are commonly used at the slow speed shaft; the other shafts are usually equipped with
anti-friction roller bearings. The tooth for most frequently used on the gears is the herringbone or
double helical tooth, which provides uniform loading and quite operation. The proper operation
and the life of the gear reducer depends mainly on the proper lubrication of the moving parts.
Chain reducers use sprockets and chains for speed reduction and are available in double or triple
reduction configurations. The chains used are double, or more frequently triple, anti-friction roller
bearings. However, the use of chain reducers is not very common and most pumping units are
equipped with geared speed reducers called gearboxes.
2.1.3 The Pumping Unit
The pumping unit is the mechanism that converts the rotary motion of the prime mover into the
reciprocating vertical motion required at the polished rod. The beam type sucker rod pumping units
are basically a four-bar mechanical linkage. The main elements are:
1. The crank arm which rotates with the slow speed shaft of the gear reducer.

2. The pitman which connects the crank arm to the walking beam.
3. The portion of the walking beam from the equalizer bearing to the center bearing.
4. The fixed distance between the saddle bearing and the crankshaft.
The operation of the above linkage ensures that the rotary motion input to the system by the prime
mover is converted into a vertical reciprocating movement, output at the horsehead. The sucker
rods, attached to the horsehead, follow this movement and drive the bottomhole pump.
The whole structure is built over a rigid steel base, which ensures the proper alignment of the
components and is usually set on a concrete foundation. The Samson post may have three or four
legs and is the strongest member of the unit, since it carries the greatest loads. On top of it is the
center or saddle bearing, which is the pivot point for the walking beam. The walking beam is a
heavy steel beam placed over the saddle bearing, with a sufficiently great metal cross section to
withstand the bending loads caused by the well load and the driving force of the pitman. The well
side of the walking beam ends in the horsehead, which through a wireline hanger, moves the
polished rod. The horsehead has a curvature to ensure that the polished rod is moved in a vertical
direction only, otherwise the resulting bending forces would break the polished rod. In the
conventional units, the other end of the walking beam carries an equalizer bearing to which the
equalizer is connected. The equalizer is a short section of a lighter beam set across the walking
beam and transmitting polished rod loads from the walking beam evenly to the two pitman. The
pitman are steel rods that connect at their lowest ends to the crank arms with the wrist pins. These
pins are mounted on the wrist pin bearings, which allow the required rotary movement between
the parts. The cranks are situated on both sides of the gear reducer and are driven by the slow speed
shaft of the gear reducer. The counter weights of the conventional units are attached to the crank
arms, allowing for adjustment along the crank arm axis.
The proper operation of the pumping unit requires that the frictional losses in the structural
bearings should be minimum. Earlier sliding bearings made of bronze were used. Nowadays, anti-
friction roller bearings are used, which are grease lubricated and sealed (See appendix for API
surface pumping unit designation)
2.1.4 Wellhead Equipment
The wellhead arrangement of a typical sucker rod pumped well is shown in the figure 4.
The polished rod, the uppermost part of the rod string, reciprocates with the movement of the
walking beam that is transmitted to the rods by the wireline hanger. The polished rod moves inside
the tubing head, on top of which a pumping tee is installed, which leads the fluids produced by the
pump into the flowline. Usually, the flowline and the casing vent line are connected with a short
pipe section, enabling the gas that separates in the casing-tubing annulus to be led into the flowline.
A check valve is installed on this line to prevent the fluids already produced to flow back into the
well. Above the pumping tee, a stuffing box is installed to eliminate leaking of well fluids into the
atmosphere.
The polished rod is a steel rod available in different standard sizes and lengths and equipped with
proper connections on both ends. Since it carries the greatest pumping loads, the polished rod must

be stronger any rod in the string. Its size is thus selected to be larger than the size of the top rod
section. In addition to transmitting the pumping movement to the rods, the polished rod’s other
function is to permit a seal to be formed against the leaking of well fluids. For this reason, its
outside surface is polished thus enabling a leak-free seal in the stuffing box. A clamp installed at
the right height on the polished rod allows the carrier bar to lift the rod string. The carrier bar is
directly connected to the horsehead of the pumping unit via a flexible wireline hanger.
The stuffing box is installed just above the pumping tee. Its main purpose is to prevent the leakage
of the well fluids around the polished rod. The figure 5 shows a common type of stuffing box.
Its operation is simple: by turning the handle on the cap, the resilient packing rings are squeezed
against the polished rod. The packing rings are usually made of rubber or Teflon to offer low
friction while providing the required sealing action. It is important to periodically adjust the
tightness of the packing rings to prevent leakage. At the same time, it is equally important not to
over tighten them, in order to minimize the friction forces that arise in the packing elements.
Normally oil produced in the well stream lubricates the sealing surfaces, but intermittent pimping
or a heading fluid production can result in the drying out of the packing which may burn easily.
Thus, a special lubricator with an oil reservoir, mounted above the stuffing box, provides a
continuous lubrication on the polished rod in such situations.
Figure 4 Wellhead Equipment Figure 5 Stuffing Box

2.1.5 Subsurface Pumps
When reservoir pressure is too low to permit a well to flow by its own energy, some artificial
means of supplementing that energy is required to lift the fluid to the surface. This can be
accomplished by subsurface pumps, divided into four designs,
1) Rod drawn pumps
2) Hydraulic subsurface pump
3) Submerged centrifugal pumps
4) Sonic Pumps
Rod drawn pumps can be divided into three basic types;
1) Tubing pumps
2) Insert (rod) pumps
3) Casing pumps (a larger version of insert pumps)
All of these pumps are actuated by sucker rod and surface pumping unit.
Any rod drawn pumps consists four essential elements:
1) A Working barrel
2) A plunger
3) A travelling valve (intake valve)
4) An standing valve (exhaust valve)
The main difference of tubing pump and insert pump is that in tubing pump barrel is connected
with the bottom of the tubing and is essential part of tubing whereas in case of insert pump,
essential part of subsurface pump and is run as a unit of sucker rod string inside of the tubing (or
casing) string.
2.1.5.1 Tubing Pumps:
Main advantage of tubing pump over insert pump is that it can displace large amount of fluid
volume as compare to insert pump as the diameter of tubing pump plunger is large within the larger
pumping barrel. For this reason only, tubing pumps are used when desired production is not
archived by insert pump at available stroke length and speed combination on the pumping unit
selected. However, disadvantage of this pump is that entire tubing must be pulled out in order to
service the working barrel. Selection also depends on the economy and operating efficiency of
pump.
Different types of tubing pumps can be classified:
1) In relation to the type of working barrel used
2) In relation to standing valve arrangement

3) In relation to the type of plunger used
2.1.5.2 Insert Pumps:
The main advantage is that the working barrel is directly connected with sucker rods, so whenever
required to service the barrel or during any well intervention no need to pullout entire tubing
string.
Some means must be provided to the barrel in order to fix into the bottom of the tubing string and
seal off the fluids and facilitate the relative motion of plunger. Downhole catcher is used for this
purpose, which consist a seat for working barrel; whose inner diameter is equal to the outer
diameter of working barrel, and which is actuated by applying some additional load. This catcher
is run with the tubing string and it is a part of tubing string. Because of some mechanical failure
happens and sucker rod break down, no effect on downhole pump as the catcher catches the pump.
Sand screen (Which has micro holes) is another equipment lowered with tubing string to prevent
sand production.
From the standpoint of operation, insert pumps can be divided into two groups:
1) Inverted pump (travelling pump):
As the name suggests, in this case plunger is stationary and working barrel moves. Main
advantage is that it prevents sand settling between the tubing strings and working barrel. However,
frictional wear can be considerable.
2) Stationary insert pump:
In this type of pump stationary part is barrel and moving part is plunger.
2.1.5.3 Casing Pump:
This group of pumps include all pumps which uses casing instead of tubing through which fluid
is pumped to the surface. A casing pump is run into the well on sucker rod, packer either on the
top or bottom of working barrel, providing fluid pack off between the casing and working barrel.
No tubing is used in this type of installation. Basically, casing pumps are larger version of insert
pums and set and operated in the same manner. The casing pumps are mainly used at shallow
depth with requirement of high production rate.

2.1.5.4 Classification of Pumps
Most of the sucker rod pumps used in the world petroleum industry conform to the specifications
of the American Petroleum Institute (See appendix for API downhole pump designation) The
pumps standardized in API specification have been classified and given a letter designation by
API as shown in the table given below:
Type of Pump
Letter Designation
Metal Plunger Soft-packed Plunger
Barrel Wall Barrel Wall
Heavy Thin Heavy Thin
ROD PUMPS
Stationary Top
Anchor
RHA RWA - RSA
Stationary Bottom
Anchor
RHB RWB - RSB
Traveling Bottom
Anchor
RHT RWT - RST
TUBING PUMPS TH - TP -
Figure 6 Tubing Pump Figure 7 Insert Pump

An explanation of these letter codes is as follows:
1. The first letter refers to the basic type:
- R for rod pumps
- T for tubing pumps
2. The second letter stands for the type of barrel, whether it is heavy to thin wall barrel.
Different code letters are used for pumps with metal plungers and for pumps with soft-
packed plungers:
- Metal plungers
H for heavy wall
P for heavy wall
- Soft-packed plungers
W for thin wall
S for thin wall
3. The third letter shows the location of the seating assembly for rod pumps.
The seating assembly or holddown is always at the bottom of a traveling barrel pump; other rod
pumps can be seated at the top or bottom as given below:
- A for top hoddown
- B for bottom holddown
- T for traveling barrel, bottom holddown.
2.1.5.5 The Sucker Rod String
The sucker rod string is the most vital part of the pumping system, since it provides the link
between the surface pumping unit and the subsurface pump. It is a piece of mechanical equipment
and has almost no analogies in man-made structures. It is several thousands of feet long and has a
maximum diameter of slightly more than an inch. The behavior of this string can have a
fundamental impact on the efficiency of fluid lifting and its eventual failure leads to a total loss of
production.
The rod string is composed of individual sucker rods that are connected to each other until the
required pumping depth is reached. Nowadays, the sucker rods are made up of steel. These are
solid steel bars with forged upset ends to accommodate male or female threads. The most important
improvement in sucker rod manufacturing methods through the years were the application of heat
treatment to improve corrosion resistance, better pin constructions and the use of rolling instead
of cutting for making the necessary threads. Steel rods, other than the solid type were also made
available, such as the hollow sucker rod or rod tube, the continuous and the flexible rod.

Steel rods have some common drawbacks, first of all their relatively high weight increases the
power needed to drive the pump, and secondly, their high susceptibility to corrosion damage in
most well fluids. Both of these problems are eliminated by the use of the latest addition to the
arsenal of rod pumping, the plastic sucker rods. The utilization of fiberglass reinforced plastic
materials in rod manufacture decreases total rod string weight, improves corrosion resistance and
has other additional benefits as well. Due to these numerous advantages, fiberglass sucker rods are
increasingly favored by operators.
2.1.5.6 Downhole Gas Separators or Gas Anchors
The downhole gas separators used in sucker rod pumping are often called gas anchors. All gas
anchors operate on the principle of gravitational separation, because the pumping system does not
allow the use of other separation methods. The force of gravity is utilized to separate the gas,
usually present in the form of small gas bubbles, from the liquid phase. Liquids, being denser than
gas, flow downwards, but gas, due to its lower gravity, tends to rise in the liquids. In order that
this natural process can take place, the well stream has to be led into a space of sufficient capacity,
from where the liquid is directed into the pump. The casing-tubing annulus offers an ideal way to
lead the separated gas to the surface.
Figure8 Downhole gas anchor

2.2 TYPES OF SUCKER ROD PUMP
There are several pumping units for sucker rod pumping. These units are divided depending upon
their geometric configurations as:
 Class I lever system – Conventional type
 Class III lever system – Air balanced type
 Class III lever system- Mark II of Lufkin
2.2.1 Class I lever system or conventional type:
In this type of unit, the walking beam is supported at and moves about its centre. The walking
beam here acts as a double arm lever on the two sides of the pivot i.e. the Sampson post where
pivot is near to the middle of the walking beam. The rear end of the walking beam is the driving
end and the front end of the walking beam is the driven end. This is also called a “pull-up” leverage
system. The counterweights are positioned either at the rear end of the walking beam or at the
crank arm depending on the load at the well to reduce the torque and horsepower of the prime
mover of the pumping unit. For fewer loads, counterweights are placed on the beam and for the
moderate to heavier loads, counterweights are placed on the cranks.
2.2.2 Air Balanced Type
This unit acts as a single arm lever (Class III) system where the horsehead and the Pitman arm are
on the same side of the beam and the pivot at the extreme end of the beam. This is also called
“push-up” leverage system. The counterbalance is ensured by the pressure force of compressed air
contained in a cylinder which acts on a piston connected to the bottom of the walking beam.
2.2.3 Mark II Unit
This unit was developed in the late 1950’s by J.P. Byrd. This is also called a Class III lever system
where the pivot is at one extreme end of the walking beam. The main advantage of this unit is to
decrease the torque and power requirements of the pumping units. It implies that the pumping unit
of this type having less torque and power requirement can work for operating the pump at deeper
depth in contrast to the heavier capacity conventional pumping unit required to operate at that
depth. In Mark II Unit the counterweights are placed on the counter balance arm that is on other
side of the crank arm. This feature also ensures a more uniform net torque variation throughout
the complete pumping cycle.

Figure 9 Conventional unit Figure 10 Air balanced unit
Figure 12 Mark II unit

2.3 THE PUMPING CYCLE
The subsurface pumps used in sucker rod pumping work on the principle of positive displacement
and are of the cylinder and the piston type. Their basic parts are the working barrel, the plunger
and the two ball valves. The barrel acts as the cylinder and the plunger as the piston. The valve
affixed to the working barrel acts as a suction valve and is called the standing valve. The other
valve, contained in the plunger, acts as a discharge valve and is called the traveling valve. These
valves operate like check valves and their opening and closing during the alternating movement of
the plunger provides a means to displace well fluids to the surface.
The barrel is connected to the lower end of the tubing string, while the plunger is directly moved
by the rod string. The positions of the barrel and the plunger, as well as the operation of the standing
valve and the traveling valve are shown at the two extreme positions of the up and down stroke.
At the start of the upstroke, after the plunger has reached its lowermost position, the traveling valve
closes due to the high hydrostatic pressure in the tubing above it. Liquid contained in the tubing
above the traveling valve is lifted to the surface during the upward movement of the plunger. At
the same time, the pressure drops in the space between the standing and traveling valves, causing
the standing valve to open. Wellbore pressure drives the liquid from the formation through the
standing valve into the barrel below the plunger. Lifting of the liquid column and filling of the
barrel with formation fluid continues until the end of the upstroke. During the whole upstroke, the
Figure 12 Pumping Cycle

full weight of the liquid column in the tubing string is carried by the plunger and the rod string
connected to it. The high pulling force causes the rod string to stretch, due to its elasticity.
After the plunger has reached the top of its stroke, the rod string starts to move downwards. The
downstroke begins, the traveling valve immediately opens, and the standing valve closes. This
operation of the valves is due to its incompressibility of the liquid contained in the barrel. When
the traveling valve opens, liquid weight is transferred from the plunger to the standing valve,
causing the tubing string to stretch. During downstroke, the plunger makes its descent with the
open traveling valve inside the barrel filled with formation fluid. At the end of the downstroke, the
direction of the rod string’s movement is reversed and another pumping cycle begins. Liquid
weight is again transferred to the plunger, making the rods stretch and the tubing to return to its
unstretched state.
The pumping cycle described above, however, assumes certain idealized conditions:
 Single-phase liquid is produced
 The barrel is completely filled with well fluids during the upstroke
If any of these conditions are not met, the operation of the pump can seriously be affected. All
problems occurring in such situations relate to changes in the valve action during the cycle. Both
of these valves are simple check valves, which open or close, according to the relation of the
pressures above and below the valve seat. Thus, the valves may not necessarily open or close at
the two extremes of the plunger’s travel. The effective plunger stroke length can thus often be less
than the total plunger stroke length.
2.4 Different problems associated with SRP
2.4.1 Fluid Pound
A phenomenon that occurs when the downhole pump rate exceeds the production rate of
the formation. It can also be due to the accumulation of low-pressure gas between the valves. On
the down stroke of the pump, the gas is compressed, but the pressure inside the barrel does not
open the traveling valve until the traveling valve strikes the liquid. Finally when the traveling valve
opens, the weight on the rod string can suddenly drop thousands of pounds in a fraction of a second.
This condition should be avoided because it causes extreme stresses, which can result in premature
equipment failure. Slowing down the pumping unit, shortening the stroke length or installing a
smaller bottom hole pump can correct this problem.

2.4.2 Gas Interference
A phenomenon that occurs when gas enters the subsurface sucker-rod pump. After the down stroke
begins, the compressed gas reaches the pressure needed to open the traveling valve before the
traveling valve reaches liquid. The traveling valve opens slowly, without the drastic load change
experienced in fluid pound. It does not cause premature equipment failure, but can indicate poor
pump efficiency. A bottomhole separator or a gas anchor can correct gas interference.
2.4.3 Gas Lock
A condition sometimes encountered in a pumping well when dissolved gas, released from solution
during the upstroke of the plunger, appears as free gas between the valves. On the down stroke,
pressure inside a barrel completely filled with gas may never reach the pressure needed to open
the traveling valve. In the upstroke, the pressure inside the barrel never decreases enough for the
standing valve to open and allow liquid to enter the pump. Thus no fluid enters or leaves the pump,
and the pump is locked. It does not cause equipment failure, but with a nonfunctional pump, the
pumping system is useless.
A decrease in pumping rate is accompanied by an increase of bottomhole pressure (or fluid level in
the annulus). In many cases of gas lock, this increase in bottomhole pressure can exceed the
pressure in the barrel and liquid can enter through the standing valve. After a few strokes, enough
liquid enters the pump that the gas lock is broken, and the pump functions normally.
Figure 13 Fluid pound

3 OPERATING PARAMETERS IN SUCKER ROD PUMPING
System
The accurate prediction of the operating conditions of a rod pumping system has a vital importance
of the design of new installations and also for the analysis, as well as the optimization of the
existing installations. There are some very basic operational parameters, most of the additional
data required for design or analysis can be derived from:
1. The polished rod loads occurring during pumping.
2. The downhole stroke length of the plunger.
3. The torques required at the speed reducer.
Due to the importance of the above parameters, several approximate formulae and calculation
methods have been developed in the past to find their values. Of these, early procedures that give
fairly good estimations for shallow wells when pumping light fluid loads. Under such
circumstances, the rod string can be treated as a concentrated mass, and this assumption leads to
quite simple physical and mathematical models. As well depth increases, however, the
assumptions of these conventional predictions are no longer valid, and the calculation accuracies
attained rapidly deteriorate.
A detailed treatment of the API RP 11L procedure gives a much higher degree of accuracy in the
calculation of pumping parameters than the simple formulas. This calculation model is more
general, can be used under widely varying conditions, and is considered to be the standard way of
finding the operational conditions of sucker-rod pumping installations in the last twenty years.
3.1 Approximate Calculation Models (Jennings & Texas, 1989)
A common feature of the simple predictions available for the determination of pumping parameters
is that they treat the elastic behavior of the rod string using simplified mechanical models. The
reason for the need of simplification lies in the complexity of describing the actual behavior of the
pumping system. Most of the approximate formulae were derived from the assumption that the rod
string is a concentrated mass that is moved by the polished rod in simple harmonic motion. With
this approach the performance of the pumping system is simulated by its analogy to a spring
moving on a concentrated mass. Such models usually allow for easy mathematical solutions and
result in simple formulae for the calculations of the main parameters of pumping.
In addition to the crude description of the rod string’s elastic behavior, the approximate
calculations employ further simplifying assumptions. Conventional pumping unit geometry is
usually assumed; the kinematics of the polished rod’s movement is approximated by a simple
harmonic motion.

3.1.1 Polished Rod Loads
The components of the polished rod load, in general, are:
 A buoyant force that decreases the rod weight
 The weight of the rod string
 Mechanical and fluid friction forces along the rod string
 Dynamic forces occurring on the string
 The fluid load on the pump plunger
The sum of the rod string weight and the buoyant force is usually expressed by the “wet weight”
of the rods which is quite simple to calculate. The effects of the friction forces are not included in
most calculation procedures because they are difficult or impossible to predict.
Dynamic forces at the polished rod are also easy to find if the concentrated mass model is used.
The inertia forces are calculated by multiplying the mass being moved with the acceleration at the
polished rod. It is customary to utilize the “acceleration factor” formula of Mills:
𝛼 =
𝑆 𝑁2
70,500
Where,
𝛼 = acceleration factor
S= polished rod stroke length, in
N= pumping speed, spm
The term (1+𝛼) refers to impulse factor. Mill’s applied that factor on static weight of rods not on
fluid. The dynamic forces stem from the inertia of the moving masses: the rod string and the fluid
column. They are addictive to the static loads during the upstroke and must be subtracted from
the static rod weight on the downstroke. The dynamic loads calculated by the above procedure
do not include the effects of the stress waves occurring in the rod string. They only represent the
forces required to accelerate the rods and the fluid column, which are assumed to be
concentrated, inelastic masses.
An expression to approximate the peak polished rod load (PPRL) can be written as the sum of
the fluid load on the plunger and the static plus dynamic loads. In the Mills formula, the buoyancy
of the rods is neglected to account for the friction forces:

𝑃𝑃𝑅𝐿 = 𝑊𝑓 + 𝑊𝑟(1 + 𝛼)
Where,
PPRL= peak polished rod loads, lbs
𝑊𝑓 = fluid load on the plunger, lbs
𝑊𝑟 = total rod string weight in air, lbs
Fluid load on the plunger is found from:
𝑊𝑓 = 0.433 × 𝐻 × 𝐴𝑝 × 𝑆𝑝𝐺𝑟
Where,
H= depth of the dynamic fluid level, ft
Ap = plunger area, sq. in
SpGr = specific gravity of the produced fluid
During the downstroke, the buoyant weight of the rod string must be decreased by the dynamic
force to find the minimum polished rod load, because they act in opposite directions:
𝑀𝑃𝑅𝐿 = 𝑊𝑟(1 − 𝛼 − 0.127𝐺)
Where,
G = Specific gravity
3.1.2 Peak Net Torque
The net crankshaft torque on the speed reducer of a pumping unit is the sum of the torques required
to move the polished rod and the counterweights. Thus, actual torque loading heavily depends on
the counterbalancing of the unit. The approximate calculation models are all based on the
assumptions that:
 The unit is perfectly counterbalanced.
 Maximum and minimum polished rod loads occur at crank angles where the torque factor is at
a maximum.

An approximate ideal counterbalance effect i.e., the force required at the polished rod to perfectly
counterbalance the unit, can be found as the rod string weight plus half the fluid load. This can also
be expressed with the use of the polished loads:
𝐶𝐵𝐸 =
𝑃𝑃𝑅𝐿 + 𝑀𝑃𝑅𝐿
2
The torque refers to the number of inch-pounds of force applied to the crank by the low speed shaft
of the gear reducer, it is created by the pitman pull due to well loads and opposing effect of
counterbalance moments and by the prime mover.
The net crankshaft torque of a beam pumping unit is the difference between well load torque and
counterbalance torque at any position of the crank. This net crankshaft torque is the actual torsional
load seen by the prime mover and the gear reducer is designed. Thus, in any pumping installation
the actual peak torque occurring during the pumping cycle must not exceed the maximum torque
rating of the gear box or speed reducer.
On the conventional unit, the peak torque generally occurs twice during each revolution of the
crank where the difference between the well load moment and the counterbalance moment (or vice
versa) is maximum. This normally occurs near the middle of the stroke (S/2). Consequently, the
gear reducer must be designed to handle this peak torque. All else equal, peak net torque is a
function of the difference between peak and minimum polished rod load, i.e., the rod load range.
A simple relationship for approximate peak torque on the upstroke is
𝑃𝑇 =
(𝑃𝑃𝑅𝐿 − 𝐶𝐵𝐸)𝑆
2
A simple relationship for approximate peak torque on the downstroke is
𝑃𝑇 =
(𝐶𝐵𝐸 − 𝑀𝑃𝑅𝐿)𝑆
2
PT = peak net torque, in lbs
3.1.3 Effective Plunger Stroke
A considerable difference is exist between polished rod stroke surface length and downhole
plunger stroke length. The point of interest is the distance that the plunger travels relative to the

working barrel. This relative motion between the plunger and working barrel results in net or
effective plunger stoke, which differs from the motion of the polished rod because of rod and
tubing stretching and contraction results from the imposition and release of loads during pumping
cycle.
Most formulas commonly used for determining effective stroke length consider only the rod and
tubing stretch and plunger overtravel. The effect of rod and tubing stretch decreases the plunger
stroke, and the effect of plunger overtravel increases the plunger stroke. A simple approximation
for effective plunger stroke is given by:
𝑆 𝑝 = 𝑆 + 𝑒 𝑝 − (𝑒𝑡 + 𝑒 𝑟)
Where, 𝑆 𝑝 = 𝐸𝑓𝑓𝑒𝑐𝑡𝑖𝑣𝑒 𝑝𝑙𝑢𝑛𝑔𝑒𝑟 𝑠𝑡𝑟𝑜𝑘𝑒, 𝑖𝑛𝑐ℎ𝑒𝑠
𝑆 = 𝑃𝑜𝑙𝑖𝑠ℎ𝑒𝑑 𝑟𝑜𝑑 𝑠𝑡𝑜𝑘𝑒 𝑙𝑒𝑛𝑔𝑡ℎ, 𝑖𝑛𝑐ℎ𝑒𝑠
𝑒 𝑝 = 𝑃𝑙𝑢𝑛𝑔𝑒𝑟 𝑜𝑣𝑒𝑟𝑡𝑟𝑎𝑣𝑒𝑙, 𝑖𝑛𝑐ℎ𝑒𝑠
𝑒𝑡 = 𝑡𝑢𝑏𝑖𝑛𝑔 𝑠𝑡𝑟𝑒𝑡𝑐ℎ, 𝑖𝑛𝑐ℎ𝑒𝑠
𝑒 𝑟 = 𝑟𝑜𝑑 𝑠𝑡𝑟𝑒𝑡𝑐ℎ, 𝑖𝑛𝑐ℎ𝑒𝑠
Plunger overtravel mainly occurs because of dynamic load imposed by rod string during pumping
cycle. In this situation when upstroke begins at surface, the downhole pump maybe still by moving
downwards or vice versa. Many formulas have been presented with varying results because of
complexity of pumping system, particularly in deep wells. Most commonly used method to
calculate it is Coberly’s method
𝑒 𝑝 = 1.93 × 10−11
× (𝐿𝑁)2
× 𝑆
Rod and tubing stretch, or elongation is caused by the cyclic transfer of fluid load from the standing valve
to the traveling valve. Rod stretch is the result of the rod weight and the imposition of the weight of the
fluid column in the tubing onto the rod string when the traveling valve closes at the bottom of the stroke.
At the top of the stroke, the traveling valve opens and the weight of the fluid column is shifted back to the
standing valve (thus back to the tubing). Rod stretch and tubing stretch is given by;
𝑒 𝑟 =
12𝑊𝑓 𝐿
𝐴 𝑟 𝐸
Where,
L = length of sucker rod string, ft
𝐴 𝑟 = average cross section area of rods, sq. in.
E = modulus of elasticity for steel (approximately 30× 106
𝑝𝑠𝑖)

For the case of a tapered rod string, i.e., a string which contains several sections of different size
above equation can be applied to each section. The total rod stretch of tapered string is then written:
𝑒 𝑟 =
12𝑊𝑓
𝐸
(
𝐿1
𝐴1
+
𝐿2
𝐴2
+ ⋯ +
𝐿 𝑛
𝐴 𝑛
)
Tubing stretch can be determined in a similar manner. In shallow wells the tubing stretch may be
small compared to the rod stretch and is frequently ignored. In particular, if the tubing is properly
anchored, then the tubing stretch is zero. Use tubing anchors to prevent unnecessary wear of tubing
and casing at point of contact with casing.
𝑒𝑡 =
5.20𝐺(𝐴 𝑝 − 𝐴 𝑟)𝐿2
𝐴𝑡 𝐸
Where, 𝐴 𝑡 = average cross section area of metal in tubing
3.1.4 Pump displacement
For a given pumping depth and volume of fluid to be produced, there is an optimum size of pump
bore which will result in effective pump plunger travel and maintain moderate speed of operation.
If the plunger is too large unnecessarily high loads imposes on the equipment and plunger
undertravel can result in inefficient operation. On the other hand, if the plunger is too small,
pumping speed becomes too high and the increased acceleration effect can results in increased
peak loads on the equipment. The basic factor for selecting the pump size is the amount of volume
of fluid to be displaced by the pump per inch of each stock. This volume displacement will depend
upon the diameter of the pump bore.
The total theoretical pump displacement can be determined by;
𝑃𝐷 = 𝐴 𝑝(𝑖𝑛.2 ) × 𝑆 𝑝 (
𝑖𝑛.
𝑠𝑡𝑟𝑜𝑐𝑘
) × 𝑁(𝑆𝑃𝑀) ×
1440 𝑚𝑖𝑛/𝑑𝑎𝑦
970
𝑖𝑛3
𝑏𝑏𝑙
𝑃𝐷 = 0.1484𝐴 𝑝 𝑆 𝑝 𝑁
Where;
PD= total displacement by pump in B/D
Ap = crossection area of the pump plunger in square inch
Sp = The effective plunger stroke, in
N = The pumping speed in number of strokes per minute
A pump constant K for any pump can be determined from:
𝐾 = 0.1484 𝐴 𝑝
Thus, Pump displacement for a given plunger size and for a combination of pumping speed and a
stroke can be determined from:

𝑃𝐷 = 𝐾𝑆 𝑝 𝑁
The actual production rate Q at the surface may be less than the actual theoretical pump
displacement because of the volumetric efficiency of pump (Ev)
𝐸𝑣 =
𝑄
𝑃𝐷
𝑄 = 𝐸𝑣 × 𝑃𝐷
Volumetric efficiency may vary over a wide range but are commonly 70-80%. Volumetric
efficiencies are affected by pump slippage and fluid properties. Consideration of pump size, speed,
and stroke combination will not necessarily insure that proper size pump has been selected for a
given pumping installation. The selection of optimum size plunger for a desired production rate
from some given depth is important in obtaining high efficiencies and preventing un-necessary
high loads on the string and the surface equipment.
3.2 API recommended design procedure (Jennings & Texas, 1989)
The API recommended detailed design procedure for conventional unit sucker rod pumping
system is detailed in API RP11L. The method is based upon correlations for research test data, and
the results are presented in terms of nondimensional parameters which may be determined from a
series of curves.
The design procedure is a trial and error method. These steps are generally required in the
procedure.
1) A preliminary selection of components for the installation must be made.
2) The operating characteristics of the preliminary selection are calculated by use of the formulas,
tables and figures in the API RP11L
3) The calculated pump displacement and loads are compared with the volumes, load ratings,
stresses and other limitations of the preliminary selection.
The minimum amount of information which must either be known or assumed is follows:
1) Fluid Level, ft
2) Pump depth, ft
3) Pumping speed, SPM
4) Length of Surface stroke, in.
5) Pump plunger diameter, in.
6) Specific gravity of fluid
7) The nominal tubing diameter and whether it is anchored or unanchored
8) Sucker rod size and design

9) Unit Geometry
With these factors, the designer should be able to calculate, with some degree of reliability, the
following:
1) Plunger stroke length, 𝑆 𝑝, in
2) Plunger displacement, PD, (B/D)
3) Peak polished rod load, PPRL, lb
4) Minimum polished rod load, MPRL lb
5) Peak (Crank) torque, PT, in-lb
6) Polished rod horsepower, PRHP
7) Counter weight required, CBE, lb
These design factors are determined from the following equations
𝑆 𝑝 = [(
𝑆 𝑝
𝑆
) × 𝑆] − [ 𝐹𝑜 ×
1
𝑘 𝑡
]
When tubing is anchored, 1/kt is zero. The term 𝐹𝑜 is the gross plunger load. The value of
𝑆 𝑝
𝑆
is determined
from graph 1(in Appendix)
𝐹𝑜 = 0.340 × 𝐷 𝑝
2
× 𝐷 × 𝐺
1
𝑘 𝑡
= 𝐸𝑡 × 𝐿
Where, 𝐸𝑡 is elastic constant of the tubing and may be determined from table 2(In Appendix)
The pump displacement PD is given by,
𝑃𝐷 = 0.1166𝑆 𝑝 × 𝑁 × 𝐷 𝑝
2
Peak polished rod load, PPRL is given by:
𝑃𝑃𝑅𝐿 = 𝑊𝑟𝑓 + [(
𝐹1
𝑆𝑘 𝑟
⁄ ) × 𝑆𝑘 𝑟]
Where, 𝑊𝑟𝑓 is weight of rod in fluid and is determined by:
𝑊𝑟𝑓 = 𝑊𝑟 × 𝐿 × (1 − 0.128)𝐺
The weight of rod 𝑊𝑟 is determined from table 2 (in Appendix)
The nondimensional parameter (
𝐹1
𝑆𝑘 𝑟
⁄ ) is determined from graph 2 (in Appendix)
The value of (
1
𝑘 𝑟
) for tapered string is given by,

1
𝑘 𝑟
= ∑ 𝐸𝑖𝑟 × 𝐿𝑖
𝑁
𝑖=1
Where, elastic constant 𝐸𝑟 of a rod is determined from table 2 (in Appendix)
Minimum polished rod load, MPRL is given by
𝑀𝑃𝑅𝐿 = 𝑊 𝑟𝑓 − [( 𝐹2
𝑆𝑘 𝑟
⁄ ) × 𝑆𝑘 𝑟]
The parameter
(𝐹2
𝑆𝑘 𝑟
⁄ )is determined from graph 3 (in Appendix)
Peak torque PT, is given by
𝑃𝑇 = (
2𝑇
𝑆2 𝑘 𝑟
) × 𝑆𝑘 𝑟 × 𝑇𝑎 × 𝑆
2⁄
Where 𝑇𝑎 is an adjustment for peak torque for values of (
𝑊𝑟𝑓
𝑆𝑘 𝑟
⁄ ) other than 0.3. These
adjustment obtained from graph 6 (in Appendix). The value of (
2𝑇
𝑆2 𝑘 𝑟
)is obtained from graph 5.
Polished rod horse power PRHP, is given by;
𝑃𝑅𝐻𝑃 = (
𝐹3
𝑆𝑘 𝑟
⁄ ) × 𝑆𝑘 𝑟 × 𝑆 × 𝑁 × 2.53 × 10−6
The parameter (
𝐹3
𝑆𝑘 𝑟
⁄ ) is determined from graph 4.
Finally, the counterweight required is determined by,
𝐶𝐵𝐸 = 1.06(𝑊𝑟𝑓 +
𝐹𝑜
2⁄ )
In the graphs, the value of the term (
𝑁
𝑁 𝑂
) is determined by
𝑁
𝑁 𝑂
=
𝑁𝐿
2450000
The term (
𝑁
𝑁 𝑂′
) is determined from:
𝑁
𝑁 𝑂′
= (
𝑁
𝑁 𝑂
)/𝐹𝐶
Where 𝐹𝐶 (frequency factor) is a constant of proportionality which depends upon the rod string
design. The dimensionless pumping speed (
𝑁
𝑁 𝑂′
) is an important index of the behavior of the rod
string. The frequency factor can be determined from table 2 (in Appendix)

Nomenclature
N= pumping speed, spm
PPRL= peak polished rod loads, lbs
𝑊𝑓 = fluid load on the plunger, lbs
𝑊𝑟 = total rod string weight in air, lbs
H= depth of the dynamic fluid level, ft
Ap = plunger area, sq. in
SpGr = specific gravity of the produced fluid
G = Specific gravity
CBE = Counter weight required, lbs
PT = peak net torque, in lbs
Sp = Effective plunger stroke, inches
ep = Plunger overtravel, inches
et = tubing stretch, inches
er = rod stretch, inches
L = length of sucker rod string, ft
𝐴 𝑟 = average cross section area of rods, sq. in.
E = modulus of elasticity
𝐴 𝑡 = average cross section area of metal in
tubing
PD= total displacement by pump in B/D
Q= Actual surface production rate, B/D
𝐸𝑣 = volumetric efficiency of pump
PRHP = Polished rod horse power
𝐹𝑜= Gross plunger load
𝑘 𝑟 = spring constant of the rod string, lbs/in
No = synchronous pumping speed for a straight
rod string, SPM
No'= synchronous pumping speed for the tapered
rod string, SPM
𝑊𝑟𝑓 = buoyant rod string weight, lbs
(
𝑁
𝑁 𝑂
) = dimensionless pumping speed
(
𝑁
𝑁 𝑂′
) = dimensionless pumping speed
(
𝐹0
𝑆𝑘 𝑟
⁄ ) = dimensionless rod stretch due to
fluid load

4 ANALYSIS OF THE SUCKER ROD PUMPING UNITS
After the proper designing of the sucker rod pumping units and successful installation of the unit,
proper analysis of the operation of the unit has to be done regularly. This analysis of the unit helps
us to determine the performance of the different components of the sucker rod pumping
installation. The determination of the inflow performance relationship of the well put under sucker
rod pump provides valuable information for the analysis of the system. However, the testing
procedure for a well under sucker rod pump is different from those under normal operations.
Among these, the acoustic determination of the annular fluid levels is important. The most
common procedure for measuring and analyzing the operating conditions of rod pumping uses a
polished rod dynamometer which records rod loads against rod displacement.
Since a packer is not usually installed in a rod pumped well, the well fluids may enter the casing-
tubing annulus freely. The height above the formation of the fluid column is a direct indicator of
the well’s actual bottom hole pressure. This fact is utilized in most of the well testing procedures
developed for pumping wells, which basically rely on the measurement of the annular liquid levels.
After the annular liquid level is known, static and flowing bottom hole pressures can be found by
calculation.
4.1 Dynamometers & Dynagraphs (Liquid & Pump, 2014)
The most valuable tool for analyzing the performance of the pumping system is the dynamometer,
which records the loads occurring in the rod string. These loads can be measured either on the
surface with a polished rod dynamometer or at pump depth with a special downhole measuring
devices. However, in both the cases, the rod loads are recorded vs. the rod displacement or
pumping time, during one or more complete pumping cycles. Since the variation of the rod loads
is a result of all the forces acting along the rod string and reflects the operation of the pump as well
as the surface pumping unit, an evaluation of these loads reveals valuable information on downhole
and surface conditions.
Accordingly, performance analyses of the downhole and surface equipment are usually conducted
by running a dynamometer survey on the well. The proper use of dynamometry techniques and the
correct interpretation of the cards taken are of utmost importance for the production engineer when
he tries to increase the profitability of sucker rod pumping. Proper interpretation of surface and
downhole dynamometer cards reveals a wealth of information on the operation of the rod pumping
system.
4.1.1 Basic dynamometer types
The dynamometers generally used in the analysis of various sucker rod installations are mainly of
two types. One type is the polished rod dynamometer and the other type is the downhole
dynamometer.
4.1.1.1 Polished rod dynamometers
These types of dynamometers are instruments that record polished rod loads during the pumping
cycle. The most common types are the mechanical and the hydraulic dynamometers, both of which
produce a continuous plot of polished rod load vs. polished rod displacement. This plot is
commonly known as the dynamometer diagram or dynamometer card.

a) Mechanical dynamometer:
It employs a steel ring as its load measuring device, which when placed between the carrier bar
and the polished rod clamp, carries the full load. The ring’s deflection is directly proportional to
the load applied, which is recorded on paper attached to a rotating drum. Since the rotation of the
drum is controlled by the polished rod’s vertical movement, the resultant record is a trace of
polished rod loads against displacement. The major disadvantage of the mechanical dynamometer
is the need to stop the pumping unit before the dynamometer can be installed on the polished rod.
b) Hydraulic dynamometer:
It can be installed without the need to stop the pumping unit and thus, has a definite advantage
over its mechanical counterpart. Before the first application on a well, a special spacer is installed
on the polished rod between the carrier bar and the polished rod clamp. The dynamometer’s two
load sensing hydraulic pistons can be installed easily, even while the unit is pumping, between the
shoulder of the spacer and the carrier bar. After the dynamometer is in place, hydraulic pressure is
applied to the pistons by activating the hand pump connected to the system. The pistons lift the
spacer off the carrier bar, and the polished rod load hereafter is fully supported only by the
hydraulic pistons. Thus, the changes in polished rod loads entail changes in the hydraulic pressure,
which are then recorded. The record is made on a paper attached to a drum, by a stylus that
magnifies the displacement of a spring-retarded piston. This drum is rotated by a pull cord, one
end of which is affixed to a stationary point. The rotational angle of the drum, therefore, is directly
proportional to the polished rod’s instantaneous position, and the record obtained is a plot of
polished rod load vs. polished rod displacement.
c) Electronic type:
The main parts of this type of dynamometer unit are the load transducer, the position transducer,
and the electronics, which provide interfacing, signal recording and processing. The load
transducer is placed between the carrier bar and the polished rod clamp and usually employs strain
gauges to sense polished rod loads. The position transducers include a potentiometer or other
device that produces a signal directly proportional to polished rod displacement. The signals of
both transducers, in the form of electric potential changes, are connected to data acquisition
circuitry which produces smoothed electric signals for recording and further processing. Polished
rod load and the position of the polished rod can thus be recorded on the portable recorder as a
function of time.
4.1.1.2 Downhole Dynagraphs
As the dynamometers used at the surface reflect basically the conditions at the surface, it cannot
directly reflect the downhole conditions. This happens because the cards recorded at the surface,
in addition to the downhole forces, also reflects all the forces, both static and dynamic, that occur
from the pump up the string. When a dynamometer is placed just above the pump, the recorded
card gives a true indication of the pump’s operation. The Gilbert’s dynagraph, which is basically
a mechanical dynamometer, is used for this purpose. The pump dynagraph is an instrument which
provides indicator diagrams analogous to the indicator diagrams ordinarily obtained for engines,
compressors, and surface pumps-with, the principal distinction that no zero-pressure line is traced

on the record. Indication of the plunger loading is obtained by recording the stretch in a calibrated
length of the sucker rods immediately above the pump, a stylus which bears on a cylindrical tube
being used for this purpose. At the same time, the plunger motion is recorded by rotational
oscillations of the stylus. The rod loads immediately above the pump, recorded as a function of
pump position, give the dynamometer diagram. The downhole dynamometer cards are called
dynagraph cards. Although the application of Gilbert’s dynagraph allowed a direct investigation
of pumping problems, the practical implications of running the instrument in the well caused a lot
of disadvantages which far exceeded the advantages obtained from the dynagraph. Thus, the most
practical way to investigate pumping conditions is by calculating a downhole pump card based on
the surface dynamometer measurements.
4.1.2 Uses of dynamometer cards
The most important uses of the dynamometer cards are as follows:
1. Determination of the loads acting on the pumping unit structure and in the rod string.
2. Based on the dynamometer card data, the torsional loading on the pumping unit’s speed reducer
can be calculated.
3. From the area of the card, the power required to drive the pumping unit can be found.
4. By checking the actual counterbalance effect, the degree of the unit’s counterbalancing can be
determined.
5. The condition of the sucker rod pump and its valves can be determined.
6. Many downhole problems can be determined by studying the shape of the dynamometer card,
making the analysis of the dynamometer cards a powerful troubleshooting tool.
4.1.3 Analysis of dynamometer shape cards
Ideal: This is the case for assumed ideal conditions wherein we have assumed
i) Inelastic rods.
ii) No time lag in transmission of motion from surface to plunger
iii) No dynamic effects
iv) No vibrations
v) System is working with 100% efficiency

At point a), the upstroke begins, and the traveling valve closes immediately. The polished rod load,
equal to the buoyant weight of the string at point a), suddenly increases to the load indicated by
point b), as the fluid load is transferred from the standing valve to the traveling valve. The plunger
and the polished rod move together until point c) is reached, while a constant load is maintained.
In point c), the end of the upstroke is reached, and the downstroke is begun with the immediate
opening of the traveling valve. Rod load suddenly drops to point d), since fluid load is no longer
carried by the traveling valve. The rod string, with the open traveling valve at its lower end, falls
in well fluids from point d) to a), while polished rod load equals the buoyant weight of the rod
string. At point a), a new cycle begins.
Elastic rods: This is for when we have elastic rods.
It is due to rod stretch that, from point a), rod load only gradually reaches its maximum value at
point b), while the pump ascends with a closed traveling valve. Similarly, at the end of the
upstroke, the transfer of fluid load from the traveling valve to the standing valve is also gradual
from point c) to d), since the rod string contracts to its original length.
In a real well, the previous simplifying assumptions are seldom met because of the following
reasons:
1. Dynamic rod loads occur due to the acceleration pattern of the rod string’s movement.

2. Stress waves are induced in the rod string by the polished rod’s movement and by the operation
of the downhole pump. These waves are transmitted and reflected in the rod string and can
considerably affect the polished rod loads measured.
3. The frequency of the induced stress waves can coincide with the resonant frequency of the rod
string causing considerable changes in the rod loads.
4. The action of the pump valves is heavily affected by the compressibility of the fluids lifted.
5. Downhole problems can exist which alter rod loads.
The combined effect of these conditions changes the shape of the dynamometer card very
significantly, as shown in the figure:
 Point A- indicates the end of the down stroke and beginning of the upstroke for the polished
rod.
 Line A to B- The travelling valve closes due to the fluid load on it, as the plunger starts its
upward journey and the polished rod begins to pick up the fluid load. This accounts for
increase in polished rod load from A to B.
 Line B to C- The momentary decrease in polished rod load from B to C is the result of rod
stretch that occurs, when rod takes over the fluid load completely.
 Line C to D- As the rod moves upward in approximately SHM, the acceleration load is
increased until it reaches a maximum point D which is theoretically near middle of up
stroke.
 Line D to E- From point D to E the acceleration load decreases, as rod velocity decreases
to zero.
 Point E- represents end of up stroke and beginning of downstroke.
 Line E to F- As the rod falls, the fluid pressure in the barrel increases which opens the
travelling valve and closes the standing valve. At point F the fluid load is transferred on to

the standing valve, i.e., the fluid load is transferred on to the tubing. This is marked by
decrease in polished rod load from E to F.
 Line F to G- This represents the negative acceleration load as a result of the action of the
surface unit, which decreases the polished rod load further, G is the point where minimum
polished rod load occurs and this point is approximately near the middle of down stroke.
 Line G to A- This represents the decrease of negative acceleration load due to action of
surface unit. This affects an increase in polished rod load.
Various other types of surface cards for different type of downhole problems which can be
diagnosed from the surface card:
Anchored Tubing Description Unanchored Tubing
Full pump with unaccounted
friction
Extra friction along the rod string is
not removed by the wave equation
used to calculate the pump card
Plunger tagging
Plunger hits up or down because of
improper spacing of the pump
Tubing anchor slipping
Malfunctioning tubing anchor
allows tubing to stretch.
Bent or sticking barrel
Load increases on upstroke,
decreases on downstroke in
defective section of barrel.
Worn or split barrel
Rod load decreases in defective
section of the barrel.
Sticking plunger
Load spike shows where plunger
stopped; extra load is needed to
overcome friction in the pump at
this position.

Slight fluid pound
Fluid level falling to pump intake
Severe fluid pound
Barrel incompletely filling with
liquid due to limited well inflow.
Well pumped off
Pump displacement much greater
than well inflow.PIP, pump fill age
are low.
Gas interference
Mixture of liquid/gas fills barrel.
PIP is high, pump fill age is low.
Unstable operation.
Gas-locked pump
Barrel filled with gas, valves
remain closed, no liquid
production. Low PIP.
Choked pump
Intake plugged, barrel incompletely
fills during upstroke. PIP is high,
pump fill age is low.
Leaking TV or pump
TV leak or pump slippage causes
delay in picking up and premature
unloading of fluid load.
Badly leaking TV or pump
TV or plunger/barrel completely
worn out.
Leaking SV
Premature loading at start of
upstroke and delayed unloading at
start of downstroke

Badly leaking SV
SV completely worn out.
Worn-out pump
TV & SV valves and barrel/plunger
completely worn out.
Delayed closing of TV
TV ball does not seat as soon as
upstroke starts
Hole in barrel or plunger pulling
out of barrel
Load drops as plunger reaches hole
or pulls out.
4.2 Determination of Annular Liquid Levels
The most common method of finding the liquid level in a pumping well’s annulus is by conducting
an acoustic well survey which is also known as well sounding. This survey is based on the
principles of propagation and reflection of pressure waves in gases. Using a wave source, a
pressure pulse is produced at the surface in the casing-tubing annulus, which travels in the form of
pressure waves along the length of the annular gas column. These pressure waves are reflected
from every depth where a change of cross-sectional area occurs, caused by the tubing collars,
casing liners, well fluids etc. The reflected waves are picked up and converted to electrical signals
by a microphone, also placed at the surface, and recorded on paper or by electronic means. An
evaluation of the reflected signals allows the determination of the depth to the liquid level in the
well.
The acoustic well sounder consists of two basic components, i.e., the well head assembly and the
recording and processing units. The wellhead assembly is easily connected to the casing annulus
by means of a threaded nipple. It contains a mechanism that creates the sound wave and a
microphone that picks up the signals. Modern well sounder units employ “gas guns” which provide
the required pressure impulse by suddenly discharging a small amount of high pressure gas, usually
CO2 or N2, into the annulus. The recording unit processes the electric signals created by the
microphone by filtering and amplification. The processed signals are then recorded on a chart
recorder as a function of time. The depth of the liquid level is found by proper interpretation of the

acoustic chart. If the reflection time and the acoustic velocity are known, then the liquid level depth
is found from the formula given below:
𝐿 =
∆𝑡𝑉𝑠
2
Where,
L= depth to the liquid level from surface, ft
∆𝑡 = time between wave generation and reflection, sec
𝑉𝑠= acoustic velocity in the gas, ft/sec
The accuracy of acoustic liquid level surveys is highly dependent on an accurate knowledge of the
acoustic velocity valid under the actual conditions. The advantages of acoustic well surveys over
the direct determination of bottom hole pressures are the much lower costs involved, the
elimination of well killing and workover operations, and the reduced time requirement. However,
in cases where the annular fluid level has a high tendency to foam, no firm signals can be attained.
The latest developments in acoustic survey techniques include the automatic liquid level monitor,
which automatically runs acoustic surveys and can also conduct pressure buildup and drawdown
tests on pumping wells. The modern acoustic units employ microcomputers, advanced digital data
acquisition techniques, and ensure high accuracy and reliability of liquid level determination.
The modern well analysis equipment used in wells employing sucker rod pumps are known as the
well analyzers. One of the important well analyzers commonly used is the Echometer Digital Well
Analyzer. It is generally a portable computerized instrument for obtaining a complete well
analysis.
The Well Analyzer is an integrated artificial lift data acquisition and diagnostic system that allows
an operator to maximize oil and gas production and minimize operating expense. Well
productivity, reservoir pressure, overall efficiency, equipment loading and well performance are
derived from the combination of measurements of surface pressure, acoustic liquid level,
dynamometer, power and pressure transient response. This portable system is based on a precision
analog to digital converter controlled by a notebook computer with Windows-based application.
The Well Analyzer acquires, stores, processes, displays and manages the data at the well site to
give an immediate analysis of the well's operating condition.
4.2.1 Echometer
An echometer is a computerized instrument for acquiring liquid level data, acoustic pressure
transient data. In its essence, an Acoustic Fluid Level Survey determines the depth to the Fluid
Level by generating an Acoustic Pressure Pulse (or Wave) that travels down the well, reflects off
the Fluid Level, and then returns back to surface where it is recorded by a sensitive internal
microphone inside the Fluid Level Gun.

4.2.1.1 Basic echometer components
1. Gas gun- It consists of an air/volume chamber which releases compressed gas into the well in
the case where we do not have sufficient casing head pressure of at least 5 kg/𝑐𝑚2
. If we have
sufficient gas pressure for the pressure/acoustic wave to travel then we can use the ‘implosion’
method. We do not need to charge the volume chamber with any gas and can directly proceed
on to take the acoustic shot. But if we do not have sufficient casing pressure (<5 kg/𝑐𝑚2
) then
we will use the ‘explosion’ method. We will pressurize the annulus region using N2 /CO2 gas
till we get required pressure and then take the shot.
2. Microphone cable- records the time taken by the wave after the shot till it returns back after
reflecting off the fluid level.
3. Sensor cable- records the pressure wave
4. Solenoid sensor- converts pressure signal to analog electrical signal
5. Transducer- converts the electrical signal to a digital(computer readable) signal
Echometer's TWM (Total Well Management) or TAM (Total Asset Management) is the software
platform through which the data is acquired and analyzed.
 After isolating the gun to the well, data acquisition is initiated and the casing pressure and the
background noise of the well are recorded for 20-seconds to acquire a baseline.
 A shot is then “fired” which generates the pressure pulse (acoustic wave) that begins traveling
down the tubing/casing annulus.
 As the acoustic wave travels downhole and encounters any abrupt changes in the cross-
sectional area of the tubing-casing annulus (for example: tubing collars, perforations, TAC's,
liner tops, or other obstructions), the cross-sectional changes cause part of the acoustic wave
to be reflected back towards surface. These reflections indicate "disturbances" to the acoustic
wave and the reflections are picked up and recorded by the sensitive internal microphone in
the gun. A plot of the microphone's acoustic recordings is known as the Fluid Level/Acoustic
Trace. Eventually the pressure pulse encounters the top of the liquid level (or some other
complete obstruction) and the entire remaining acoustic wave is reflected back to the surface
microphone (creating the large fluid level “kick” at the right end of the trace). This fluid level
kick represents the top of the "gaseous fluid level".
The plot of the acoustic reflections recorded by the microphone is known as the Acoustic Trace.
The shot is generated on the left side, the kicks of decreasing amplitude along the trace are the
tubing collars, and the fluid level "kick" is on the right side.

Figure 14 Echometer for measuring dynamic fluid level
Figure 15 Echometer graph

5 Optimization of Sucker rod Pumping System
Direct energy cost for sucker rod pumping can be optimized by selecting the right pump size, stroke length,
and pumping speed for the required liquid production rate. Calculation procedure for a computer program
are developed for optimizing the design of conventional pumping units. The developed program is an
alternative to API RP 11L and improves the accuracy of pumping system design.
The aim of artificial lift design is to ensure the most economic means of liquid production within the
constraints imposed by the given well and reservoir. For sucker rod pumping unit this usually means
selecting the right size of pumping unit and gear reducer as well as determine the pumping mode to be
used. Pumping mode variables include pump size, stroke length, and pumping speed.
To optimize the existing system, the crank radius, the speed of the pump, and the position of the
counterbalance are alterable values. The following steps form an optimizing procedure: (Miska, Tulsa,
Khodabandeh, & Rajtar, 1994)
1) Change the speed of the pumping unit, keeping a preselected crank radius. Do not allow the PPRL and
the peak net torque to exceed the rating of the pumping unit. The upper limit for the pumping speed
(strokes/min) will then be determined.
2) Calculate the production rate, PPRL, peak torque, polished-rod horsepower, and output energy of the
prime mover at each pumping speed not exceeding the upper pumping speed limit.
3) Change the crank radius and repeat Steps 1 and 2. As usual, the number of crank radii is limited. This
task can he accomplished in a relatively short time.
4) Select the optimum pumping speed for each radius (stroke length) that yields the desired oil production
rate. Then, construct the net torque diagrams for the selected speeds for further analysis.
5) Typically, a few combinations of different pumping speeds and stroke lengths will result in a desired
production rate. Discard the combinations that do not meet the specifications and rating of the system. The
optimal choice is determined by calculating the efficiency and operational costs associated with
combinations. The parameters corresponding to the minimum cost are optimal.
6) Change the direction of crank rotation, if permissible, and repeat Steps 1 through 5. This is not required
if the optimum direction of rotation is known from the past experience.
7) Check the final results against the limitations of the surface and downhole equipment. The optimal
production practices, as determined in the steps above, may require some modifications or adjustment to
the equipment. If the cost associated with the modifications is lower than the benefits of optimization the
practical implementation of the results is justified and will result in production cost decrease.
It is evident that increasing the plunger size increases the attainable maximum lifting efficiencies for all
rod tapers. Therefore, use of bigger plunger diameters with correspondingly slower pumping speeds is
always advantageous, because these result in lower energy requirements. Another observation, in line with
practical experience, is that use of the heavier rod strings (85 or 86 instead of 75 or 76) can increase greatly

the power requirements for smaller pumps. The difference is not so pronounced for larger pumps, because
in those cases rod string weight becomes a smaller fraction of the total pumping load.
The power costs of driving the prime mover constitute a significant part of the operating costs in rod
pumping. This is mainly due to the cost of electricity, which, compared to earlier years, has increased
extensively. Thus, the importance of the proper selection of the pumping mode that achieves minimum
energy requirements cannot be overestimated. As discussed before, the optimization procedure just
detailed provides the least amount of power requirement at the polished rod. Since total energy usage of
the pumping system is directly related to polished rod horsepower (PRHP), the optimization model
automatically arrives at the most energy-efficient pumping system.
In order to show the merits of the optimization procedure discussed, an economic evaluation of two wells
in a Unava oil field is presented. Actual conditions of the wells are compared to calculated ones in Table
4. The rows with the well numbers contain the measured parameters; the subsequent rows display
calculated pumping modes. In every case, annual energy cost savings in percentages, related to present
conditions, are given also. Evaluation of the results permits the following conclusions to be drawn
In Well#01, the one-taper 7/8 in string is oversized with a low average loading and consequently has a
high total weight. Decreasing the string weight and/or increasing the pump size (not considered here)
ensures annual savings from 13% to 49% theoretically. The same considerations apply to Well#02. Actual
saving may be upto 30% of current cost.
40
50
60
70
80
90
100
1.25 1.5 1.75 2 2.25 2.5 2.75
Liftingefficiency%
Pump size
Rod 75
Rod 76
Rod 85
Rod 86
Figure 16 Maximizing lifting efficiencies for different rod tapers versus pump size

Well
no
Setting
(ft)
Dynamic
level (ft)
Liqui
d rate
(B/D)
Rod
no.
Pump
size
(in.)
Stroke
length
(in.)
Pumping
speed
(SPM)
PRHP
(HP)
Lifting
efficien
cy (%)
Annual
savings
(%)
#01 3801 3567 158 77 1.75 102 4 3.92 67
65 1.75 120 4 3.39 69.25 13.29
66 1.75 86 3 1.97 76.52 49.74
65 1.75 86 3.5 2.009 72 48.75
77 1.75 120 3 3.27 68 16
66 1.75 102 3.5 2.85 74 37.54
87 1.75 86 4 2.34 75.54 40.306
#02 3953 3903.2 148 77 1.75 120 4 4.84 69
65 1.75 102 4 2.97 75.4 38
66 1.75 102 3 3.02 74.21 37.6
65 1.75 86 3.5 3.19 73.058 34.09
77 1.75 86 3 2.31 52.27 52.27
66 1.75 86 3.5 2.93 80 39.4
87 1.75 72 2.5 2.65 76 45.24
Table 4 The Effect of Pumping Mode Optimization on the Energy Costs of Pumping in an Example Field
It can be observed, in general, that rod string oversizing results in heavier strings, which in turn requires more
power from the prime mover. The use of larger pumps, on the other hand, decreases energy costs as an effect of
the lower pumping speeds required. Therefore, significant operating cost savings can be realized by using the
optimum pumping mode that ensures maximum lifting efficiency.(Byrd, 1971)
Figure 15 Comparison of Production Rate and Energy Requirements
0
19
38
57
76
95
114
10
30
50
70
90
110
130
0 2 4 6 8 10 12
EnergyconsumptionKwh/day
Liquidproductionrate,B/D
Pumping speed, SPM
102_Q 120_Q 86_Q 102_E 120_E 86_E

Figure 15 represents energy consumption (Orange curves) and actual liquid production (Blue curves) at
different pumping speed and different surface stoke length of Well#02. According to conventional mill’s
method calculation, as stroke length and pumping speed increases both energy consumption and liquid rate
will increases. For any particular higher (>5 SPM) pumping speed value, as stroke length is increased, 20%
of liquid production increases along with same amount of energy consumption. Contrary to that, if SRP
runs at a speed of <5 SPM, 30% liquid production increased as surface stroke length increases along with
17% energy consumption increment. Therefor optimum condition for Well#02 is running SRP at 4 SPM
with 102 inch surface stroke length.
5.1 Optimization using PROSPER
5.1.1 About PROSPER: (Manual, 2010)
PROSPER is a well performance, design and optimization program which is part of the Integrated
Production Modelling Toolkit (IPM). This tool is the industry standard well modelling with the major
operators worldwide.
PROSPER is designed to allow the building of reliable and consistent well models, with the ability to
address each aspect of well bore modelling viz, PVT (fluid characterization), VLP correlations (for
calculation of flow-line and tubing pressure loss) and IPR (reservoir inflow).
PROSPER provides unique matching features, which tune PVT, multiphase flow correlations and IPRs to
match measured field data, allowing a consistent well model to be built prior to use in prediction
(sensitivities or artificial lift design). PROSPER enables detailed surface pipeline performance and design:
Flow Regimes, Hydrates Flag, Pipeline Stability Studies, Slug Size and Frequency.
5.1.2 Applications
1) Design and optimize well completions including multi-lateral, multi-layer and horizontal wells
2) Design and optimize tubing and pipeline sizes
3) Design, diagnose and optimize Gas lifted, Hydraulic pumps, PCP, Jet Pump, SRP and ESP wells
4) General lift curves for use in simulators.
5) Calculate pressure losses in well, flow lines and across chokes
6) Predict flowing temperatures in wells and pipeline
7) Monitor well performance to rapidly identify wells requiring remedial action
8) Unique black oil model for retrograde condensate fluids, accounting for liquid dropout in the wellbo

Page | 51
VLP
consistent
VLP
consistent
SRP Lift Pump design
Generate
report
Stop Review design
Calculate system
sensitivity
Start
Model option selection
Set up the model
PVT data input
Match PVT model
Select the best correlation
System
Equipment data IPR
Artificial
lift
Data
input
New
design
New
design
Match IPR & VLP
Correlation compression
NoYes
No
Yes
Yes No
No

5.2 Optimization of Well#01 using PROSPER : a case study
Using previously acquired data (confirmed data such as reservoir pressure=1354 psig, flowing bottomhole
pressure=687 psig and test flow rate=20barrels)
Statement of the Problem
 Given PVT data, Reservoir data, SRP design parameters and well completion data, it is required to:
 Design a sucker rod pump (SRP) for a low rate oil well with a target liquid rate of 20 stb/d.
 Predict the well performance under changing operating conditions
Step by step design and optimization
The step-by-step will take the reader through all necessary stages required to:
 Build a PROSPER well model,
 Design a Sucker Rod Pump for the wellUse the well model to predict the well performance under
changing operating conditions.
Figure 16 System interface

Select | Done to complete this task.
Input Data forSRP-Design
For a SRP- design, the following data sets are needed:
 PVT data,
 Well equipmentdata
 Reservoir data
 SRP- designparameters
Fluid Properties
Solution GOR: 550 scf/stb
Oil Gravity: 36 API
Specific gas gravity: 0.5537
Water salinity: 3000 ppm
Pb at 130 degF: 1300 psig
Bo @ Pb and 130 degF: 1.06 rb/sb
µ0 @ Pb and 130 degF: 8.87 cp

Equipment Data
Select | System | Equipment (Tubing etc) | All | Edit to enter the deviation survey

Deviation Survey
Downhole Equipment
Measured Depth in ft True Vertical Depth in ft
0 0
4192 4192
Equipment
Type
Measured
Depth
Tubing
ID
Tubing
Inside
Roughness
Tubing
OD
Tubing
Inside
Roughness
Casing
ID
Casing
Inside
Roughness

Inflow Performance Relation
Inflow Performance Data
Reservoir model: Vogel
Reservoir pressure: 1354 psig
Reservoir Temperature: 170◦F
Water Cut: 19 %
Total GOR: 550 scf/stb
Compaction Permeability model: NO
Relative Permeability: NO
Test Rate: 20 STB/day
Test Bottom hole Pressure 687 psi
Xmas tree N/A N/A N/A N/A N/A N/A N/A
Tubing 4036 2.441 0.012 2.625 0.012 4.441 0.012

Select | Input Data and enter the test rate and test flowing bottom hole pressure

Select | Finish to return to the previous screen
SRP-Design parameters
Anchored Tubing: Yes
Pump depth: 3500 ft
Pump Diameter: 1.75 inches

Surface stroke length: 48 inches
Pump Speed: 12 strokes / minutes
Rode Selection - Rod type: Steel Rods
Rod Number: ROD99/04
Further deign parameters are
Calculation mode: Enter Production Rate, Estimate Stroke Rate
Pumping Unit Selection: LUFKIN C-220-213-120 LC036
Rod Grad: D
Service Factor: Non-corrosive
Pump Intake Pressure Method: Entered
Mid Perforation Depth: 4139 ft
Design Input - Unit type: Conventional Clockwise
Design Input - Anchored tubing: Yes
Design Input MidPoint Perforation depth: 4139 ft
Design Input - Pump Depth: 3953 ft
Design Input - Pump Volumetric
Efficiency:
80%
Design Input - Unit Efficiency: 75%
Design Input - Pump Diameter: 1.75-in
Design Input - Surface Stroke length: 86"
Design Input - Bottom Hole Temperature: 170 ◦F
Design Input - Well Head Temperature: 60 ◦F
Design Input - Well Head Pressure: 100 psig

Results:

One the data have been properly entered, select | Calculate to complete the design.
It is possible to run sensitivity on the rod with | Rod Sensitivity | Calculate and the following screen
shows:

Production rate by rod type Horse Power Required By
Rod Type
Production Rate Per Horse
Power By Rod Type:
Dynagraph for given conditions Calculated torque plot Calculated pump velocity

Total system analysis (IPR + VLP) gives operating condition for given condition.
Variable system analysis gives idea about liquid production rate at various conditions. Here,
Pumping speed is taken as variable. As pumping rate increases production rate also increases with
decreasing flowing BHP. The cutting point gives maximum possible liquid production rate at
particular condition.

5.3 Conclusion
From the IPR curve we can see that when we assume the reservoir pressure to 1100 psig and the
current flowing bottomhole pressure is 200 psig then we get an AOF (Absolute Open Flow) of
15.3 bopd when we are currently producing 14.5 bopd. The IPR curves for other reservoir pressures
has also been plotted and shown above. This data helps us in understanding that the field is quite
matured which has already past its peak production. One influx study report also indicates near
wellbore formation damage due to entry of cement slurry and mud into the formation which has
also reduced the formations ability to give up fluids easily even after maintaining a higher
drawdown rate. Such problem is commonly encountered in fractured basement reservoirs where
there are many other complex fractures and there is a sharp decline in reservoir pressure in a short
time period such as in the Gamij field (Limited, 2012) and Pannonian Basin. Open hole
completions is recommended for such type of basins rather than cemented.
The SRP data and specifications were input into the PROSPER software which yielded results
considering different parameters such as production rate for different stroke length, pumping
speed, rod type etc. The results as per simulation with prosper were accurate regarding the peak
and minimum polished rod loads, polished rod horsepower, etc which can be confirmed by using
equation API RP 11L. But due to a high GOR and such near formation wellbore damage the
calculated output liquid rate was found near from the actual/practical liquid production rate. But
nonetheless, the results yielded important information regarding the different rod types available,
different power consumption and the power consumption per barrel produced for different rod
types and the current rod configuration (API 77/04) was found to be suitable in line with the
available rod types.
The dynagraph also indicated very little tagging/friction during the end of upstroke and
downstroke.

6 Appendix-1
6.1 API Surface Pumping Unit Designation
X – XXXX – XXX – XX
C – 228D – 200 – 144
C – Crank balanced conventional Unit
228 – Peak torque of gear box is 228,000 in-lbs
D – Double reduction gear box
200 – Peak polished rod load is 20000 lbs
144 – Maximum available stroke length
Type of pumping unit:
A- Air Balanced
B- Beam Counterbalanced
C- Conventional
M- Mark II Unit
Peak torque rating in thousands of Inch Pound
D – Double reduction gear reducer
Polished rod load rating in hundreds of Pounds
Stroke length in Inches

pg. 66
API Downhole Pump Designation
XX – XXX – X X X X – X – X – X - X
Tubing Size; 15 (1.90” OD, 48.3mm)
20 (2 3/8”OD, 60.3mm)
25 (2 7/8”OD, 73.0mm)
30 (3 1/2”OD, 88.9mm)
40 (4 1/2”OD, 114.3mm)
Pump Bore; 106 (1 1/6”, 27.0mm)
125 (1 1/4”, 31.8mm)
150 (1 1/2", 38.1mm)
175 (1 3/4", 44.5mm)
200 (2” , 50.8mm)
225 (2 1/4", 57.2mm)
250 (2 1/2", 63.5mm)
275 (2 3/4", 69.9mm)
325 (3 1/4", 82.6mm)
375 (3 3/4", 95.3mm)
Type of pump; R - Rod
T - Tubing
Type Barrel; H – Heavy wall
W – Thin wall
S – Thin wall
P – Heavy wall
For metal plunger pumps
For soft packed plunger
pumps
Location of seating assembly; A – Top
B - Bottom
T – Bottom, travelling barrel
Type seating assembly; C – Cup type
M – Mechanical type
Barrel length in feet
Nominal plunger length in feet
Length of upper extension in feet
Length of lower extension in feet

pg. 67
Graph 01 Graph 02
Graph 03 Graph 04

pg. 68
Reference of all graph: API RP 11L Recommended practice for design calculations for
sucker rod pumping systems (conventional units). 4th ed. Washington, D.C: American
Petroleum Institute; 1988.
Tubing size Outside
diameter
Inside
diameter
Metal area Elastic
constant
in in in Sq.in. in /(lb ft)
1.9 1.900 1.610 0.800 0.500 E-6
2 3/8 2.375 1.995 1.304 0.307 E-6
2 7/8 2.875 2.441 1.812 0.221 E-6
3 1/2 3.500 2.992 2.590 0.154 E-6
4 4.000 3.476 3.077 0.130 E-6
4 1/2 4.500 3.958 3.601 0.111 E-6
Table 1 Basic data of API tubing [1]
Graph 05 Graph 06

pg. 69
Table 2 Rod and Pump data [1]

pg. 70
Table 3 Rod and Pump data (Cont.) [1]

pg. 71
Flow diagram of EOGEPL EPS Bokarwada

pg. 72
References:
1. API RP 11L Recommended practice for design calculations for sucker rod pumping
systems (conventional units). 4th ed. Washington, D.C: American Petroleum
Institute; 1988.
2. PROSPER User Manual
3. Brown, K. E. (1982). Overview of Artificial Lift Systems.
4. Byrd, J. P. (1971). PERFORMANCE OF A BEAM PUMPING SYSTEM, (1).
5. Fundamentals, P. E., & Pumping, L. R. (n.d.). Sucker-Rod Pumping Handbook.
6. Jennings, J. W., & Texas, A. (1989). The Design of Sucker Rod Pump Systems.
7. Limited, G. (2012). HYDROCARBON PRODUCTION FROM FRACTURED
BASEMENT FORMATIONS GeoScience Limited FRACTURED BASEMENT
RESERVOIRS - DEFINITION AND HISTORICAL BACKGROUND, (October).
8. Liquid, G. F., & Pump, A. (2014). Pump & Dyno, 2, 1–6.
9. Manual, U. (2010). Petroleum Experts User Manual, (January).
10. Miska, S. Z., Tulsa, U., Khodabandeh, A., & Rajtar, J. M. (1994). SPE 26966
Computer-Aided Design and Optimization of Sucker Rod Pumping Systems.

Production Optimization of SRP wells using PROSPER software

More Related Content

What's hot (20)

Similar to Production Optimization of SRP wells using PROSPER software (20)

Recently uploaded (20)

Production Optimization of SRP wells using PROSPER software