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This page discusses the specific artificial-lift technique known as beam pumping, or the sucker-rod lift method. Many books, technical articles, and industry standards have been published on the sucker-rod lift method and related technology.<ref name="r1">Zaba, J. 1943. Oil Well Pumping Methods: A Reference Manual for Production Men. Oil & Gas J. (July).</ref><ref name="r2">Zaba, J. 1962. Modern Oil Well Pumping. Tulsa, Oklahoma: Petroleum Publishing Co.</ref><ref name="r3">Donnelly, R.W. 1986. Oil and Gas Production: Beam Pumping. Dallas, Texas: PETEX, University of Texas.</ref><ref name="r4">Takács G., 1993. Modern sucker-rod pumping. PennWell Books, Tulsa Oklahoma, 230p. http://www.worldcat.org/oclc/27035195</ref><ref name="r5">Frick, T.C. 1962. Petroleum Production Handbook, Vol. 1 . Dallas, Texas: Society of Petroleum Engineers.</ref><ref name="r6">Bradley, H.B. 1987. Petroleum Engineering Handbook. Richardson, Texas: SPE.</ref><ref name="r7">Gipson, F.W. and Swaim, H.W. 1988. The Beam Pumping Design Chain. Paper presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.</ref>Additionally, the other components of a sucker-rod pumping installation are discussed, including applicable engineering and operating information. The complete operating system should be understood and addressed to properly design, install, and operate this or any other type of [[Artificial_lift|artificial lift]] system. The Gipson and Swaim “Beam Pump Design Chain” is used as a foundation and built upon using relevant, published technology.<ref name="r5">Frick, T.C. 1962. Petroleum Production Handbook, Vol. 1 . Dallas, Texas: Society of Petroleum Engineers.</ref><ref name="r6">Bradley, H.B. 1987. Petroleum Engineering Handbook. Richardson, Texas: SPE.</ref><ref name="r7">Gipson, F.W. and Swaim, H.W. 1988. The Beam Pumping Design Chain. Paper presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.</ref>
This page discusses the specific artificial-lift technique known as beam pumping, or the sucker-rod lift method. Many books, technical articles, and industry standards have been published on the sucker-rod lift method and related technology.<ref name="r1">Zaba, J. 1943. Oil Well Pumping Methods: A Reference Manual for Production Men. Oil & Gas J. (July).</ref><ref name="r2">Zaba, J. 1962. Modern Oil Well Pumping. Tulsa, Oklahoma: Petroleum Publishing Co.</ref><ref name="r3">Donnelly, R.W. 1986. Oil and Gas Production: Beam Pumping. Dallas, Texas: PETEX, University of Texas.</ref><ref name="r4">Takács G., 1993. Modern sucker-rod pumping. PennWell Books, Tulsa Oklahoma, 230p. http://www.worldcat.org/oclc/27035195</ref><ref name="r5">Frick, T.C. 1962. Petroleum Production Handbook, Vol. 1 . Dallas, Texas: Society of Petroleum Engineers.</ref><ref name="r6">Bradley, H.B. 1987. Petroleum Engineering Handbook. Richardson, Texas: SPE.</ref><ref name="r7">Gipson, F.W. and Swaim, H.W. 1988. The Beam Pumping Design Chain. Paper presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.</ref>Additionally, the other components of a sucker-rod pumping installation are discussed, including applicable engineering and operating information. The complete operating system should be understood and addressed to properly design, install, and operate this or any other type of [[Artificial_lift|artificial lift]] system. The Gipson and Swaim “Beam Pump Design Chain” is used as a foundation and built upon using relevant, published technology.<ref name="r5">Frick, T.C. 1962. Petroleum Production Handbook, Vol. 1 . Dallas, Texas: Society of Petroleum Engineers.</ref><ref name="r6">Bradley, H.B. 1987. Petroleum Engineering Handbook. Richardson, Texas: SPE.</ref><ref name="r7">Gipson, F.W. and Swaim, H.W. 1988. The Beam Pumping Design Chain. Paper presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.</ref>


== Beam-pumping systems ==
==Beam-pumping systems==


Beam pumping, or the sucker-rod lift method, is the oldest and most widely used type of artificial lift for most wells. A sucker-rod pumping system is made up of several components, some of which operate aboveground and other parts of which operate underground, down in the well. The surface-pumping unit, which drives the underground pump, consists of a prime mover (usually an electric motor) and, normally, a beam fixed to a pivotal post. The post is called a Sampson post, and the beam is normally called a walking beam. '''Figs. 1 and 2''' present a detailed schematics of a typical beam-pump installation.
Beam pumping, or the sucker-rod lift method, is the oldest and most widely used type of artificial lift for most wells. A sucker-rod pumping system is made up of several components, some of which operate aboveground and other parts of which operate underground, down in the well. The surface-pumping unit, which drives the underground pump, consists of a prime mover (usually an electric motor) and, normally, a beam fixed to a pivotal post. The post is called a Sampson post, and the beam is normally called a walking beam. '''Figs. 1 and 2''' present a detailed schematics of a typical beam-pump installation.
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<gallery widths="300px" heights="200px">
<gallery widths="300px" heights="200px">
File:Vol4 Page 458 Image 0001.png|'''Fig. 1—Schematic of conventional pumping unit with major components of the sucker-rod-lift system.'''
File:Vol4 Page 458 Image 0001.png|'''Fig. 1—Schematic of conventional pumping unit with major components of the sucker-rod-lift system.'''
File:Vol4 Page 415 Image 0001.png|'''Fig. 2—Schematic of a beam-pumping system. (Courtesy of Harbison-Fischer.)'''
File:Vol4 Page 415 Image 0001.png|'''Fig. 2—Schematic of a beam-pumping system. (Courtesy of Harbison-Fischer.)'''
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Linked rods attached to an underground pump are connected to the surface unit. The linked rods are normally called sucker rods and are usually long steel rods, from 5/8 to more than 1 or 1 1/4 in. in diameter. The steel rods are normally screwed together in 25- or 30-ft lengths; however, rods could be welded into one piece that would become a continuous length from the surface to the downhole pump. The steel sucker rods typically fit inside the tubing and are stroked up and down by the surface-pumping unit. This activates the downhole, positive-displacement pump at the bottom of the well. Each time the rods and pumps are stroked, a volume of produced fluid is lifted through the sucker-rod tubing annulus and discharged at the surface.
Linked rods attached to an underground pump are connected to the surface unit. The linked rods are normally called sucker rods and are usually long steel rods, from 5/8 to more than 1 or 1 1/4 in. in diameter. The steel rods are normally screwed together in 25- or 30-ft lengths; however, rods could be welded into one piece that would become a continuous length from the surface to the downhole pump. The steel sucker rods typically fit inside the tubing and are stroked up and down by the surface-pumping unit. This activates the downhole, positive-displacement pump at the bottom of the well. Each time the rods and pumps are stroked, a volume of produced fluid is lifted through the sucker-rod tubing annulus and discharged at the surface.


== Selecting the sucker-rod pumping method ==
==Selecting the sucker-rod pumping method==


Many factors must be considered when determining the most appropriate lift system for a particular well. [[Artificial_lift_selection_methods|Artificial lift selection methods]] presents a discussion of the normally available artificial-lift techniques, their advantages and disadvantages, and the selection of a method for a well installation.
Many factors must be considered when determining the most appropriate lift system for a particular well. [[Artificial_lift_selection_methods|Artificial lift selection methods]] presents a discussion of the normally available artificial-lift techniques, their advantages and disadvantages, and the selection of a method for a well installation.
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== Understanding the reservoir ==
==Understanding the reservoir==


Understanding the makeup of the producing reservoir, its pressure, and the changes that occur in it are important to attain maximum production. Because reservoir conditions change as fluids are produced, ongoing measurement of the reservoir conditions is necessary. The main considerations in measuring and understanding the reservoir are the types and volumes of reservoir fluids being produced, their pressures in both the reservoir and at the wellbore or pump intake, and the effects these fluids have as they pass through the producing system.
Understanding the makeup of the producing reservoir, its pressure, and the changes that occur in it are important to attain maximum production. Because reservoir conditions change as fluids are produced, ongoing measurement of the reservoir conditions is necessary. The main considerations in measuring and understanding the reservoir are the types and volumes of reservoir fluids being produced, their pressures in both the reservoir and at the wellbore or pump intake, and the effects these fluids have as they pass through the producing system.
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A variety of well tests and measurements may be used to determine production rates for oil-, gas-, and water-supply wells and to observe the status of the reservoir. Each test reveals certain information about the well and the reservoir being tested. The main reservoir considerations are determining bottomhole pressure and the inflow relationship of the fluids with changing reservoir and pump-intake pressure.
A variety of well tests and measurements may be used to determine production rates for oil-, gas-, and water-supply wells and to observe the status of the reservoir. Each test reveals certain information about the well and the reservoir being tested. The main reservoir considerations are determining bottomhole pressure and the inflow relationship of the fluids with changing reservoir and pump-intake pressure.


=== Bottomhole pressure determination ===
===Bottomhole pressure determination===


Bottomhole pressure measuring equipment (pressure bombs) makes it possible to determine reservoir and tubing intake pressures within the desired range of accuracy. When this test is conducted at scheduled intervals, valuable information about the decline or depletion of the reservoir from which the well is producing can be obtained. However, it is difficult to obtain either bottomhole reservoir or operating pressures while the rod-pump system is installed and operating.
Bottomhole pressure measuring equipment (pressure bombs) makes it possible to determine reservoir and tubing intake pressures within the desired range of accuracy. When this test is conducted at scheduled intervals, valuable information about the decline or depletion of the reservoir from which the well is producing can be obtained. However, it is difficult to obtain either bottomhole reservoir or operating pressures while the rod-pump system is installed and operating.
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Knowing the reservoir and pump intake pressures during static and operating conditions will allow a determination of the well's production capacity. This is required to optimize the artificial-lift equipment and properly size the equipment that is installed. The well productivity under varying production conditions must then be known.
Knowing the reservoir and pump intake pressures during static and operating conditions will allow a determination of the well's production capacity. This is required to optimize the artificial-lift equipment and properly size the equipment that is installed. The well productivity under varying production conditions must then be known.


=== Inflow performance relationship (IPR) ===
===Inflow performance relationship (IPR)===


One of the most critical decisions in an artificial-lift system is the selection and design of equipment appropriate for the volume of fluid the reservoir produces. [[Reservoir_inflow_performance|Reservoir inflow performance]] detaisl the productivity index and IPR of fluids with changes in reservoir pressure. Because most fluid produced by an artificial lift method is not single phase, it is not in a steady-state condition. Also, because most pumping operations occur after the fluid is below the [[Glossary:Bubblepoint|bubblepoint]] pressure, the IPR method is usually considered. This technique takes into account various fluid phases and flow rates. It was originally devised by Vogel<ref name="r12">Vogel, J.V. 1968. Inflow Performance Relationships for Solution-Gas Drive Wells. J Pet Technol 20 (1): 83–92. SPE 1476-PA. http://dx.doi.org/10.2118/1476-PA</ref> and described by Eickmeier. <ref name="r13">Eickmeier, J.R. 1968. How to Accurately Predict Future Well Productivities. World Oil (May): 99.</ref> Each revision increased the accuracy of estimating flow rates from a well.
One of the most critical decisions in an artificial-lift system is the selection and design of equipment appropriate for the volume of fluid the reservoir produces. [[Reservoir_inflow_performance|Reservoir inflow performance]] detaisl the productivity index and IPR of fluids with changes in reservoir pressure. Because most fluid produced by an artificial lift method is not single phase, it is not in a steady-state condition. Also, because most pumping operations occur after the fluid is below the [[Glossary:Bubblepoint|bubblepoint]] pressure, the IPR method is usually considered. This technique takes into account various fluid phases and flow rates. It was originally devised by Vogel<ref name="r12">Vogel, J.V. 1968. Inflow Performance Relationships for Solution-Gas Drive Wells. J Pet Technol 20 (1): 83–92. SPE 1476-PA. http://dx.doi.org/10.2118/1476-PA</ref> and described by Eickmeier. <ref name="r13">Eickmeier, J.R. 1968. How to Accurately Predict Future Well Productivities. World Oil (May): 99.</ref> Each revision increased the accuracy of estimating flow rates from a well.
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Producing rates can be estimated within the desired range of accuracy using the IPR technique with two stabilized producing rates and corresponding stabilized producing pressures. This makes it possible to use the IPR without needing to shut in the well and lose production to obtain shut-in information. Obtaining a bottomhole pressure equal to 10% of the shut-in reservoir pressure is recommended for determining maximum production rates for sucker-rod lifted wells. At this pressure, the maximum well productivity will be 97% of the well's theoretical maximum production rate. However, the maximum lift-design rate should, in most cases, be slightly higher to permit some downtime and decreased pump efficiency.
Producing rates can be estimated within the desired range of accuracy using the IPR technique with two stabilized producing rates and corresponding stabilized producing pressures. This makes it possible to use the IPR without needing to shut in the well and lose production to obtain shut-in information. Obtaining a bottomhole pressure equal to 10% of the shut-in reservoir pressure is recommended for determining maximum production rates for sucker-rod lifted wells. At this pressure, the maximum well productivity will be 97% of the well's theoretical maximum production rate. However, the maximum lift-design rate should, in most cases, be slightly higher to permit some downtime and decreased pump efficiency.


=== Gas production ===
===Gas production===


In any artificial lift system, the volume of gas produced should be considered in designing the system and in analyzing the operation after the system has been installed. A complete analysis requires knowing the volume of gas in solution, the volume of free gas, the formation volume factors, and whether gas is produced through the pump or is vented. If PVT analyses of reservoir fluids are available, they are the most accurate and easiest to use as a source of solution gas/oil ratio (GOR), formation volume factors, etc. The next best source is an analysis from a nearby similar reservoir.
In any artificial lift system, the volume of gas produced should be considered in designing the system and in analyzing the operation after the system has been installed. A complete analysis requires knowing the volume of gas in solution, the volume of free gas, the formation volume factors, and whether gas is produced through the pump or is vented. If PVT analyses of reservoir fluids are available, they are the most accurate and easiest to use as a source of solution gas/oil ratio (GOR), formation volume factors, etc. The next best source is an analysis from a nearby similar reservoir.
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*Chart 3: The formation volume factor of the bubblepoint liquid.
*Chart 3: The formation volume factor of the bubblepoint liquid.


=== Gas venting ===
===Gas venting===


When pumping through tubing in the absence of a production packer, free gas, which breaks out of the oil, should be vented up from the casing/tubing annulus. However, when it is necessary to produce from beneath a production packer, a vent string can be installed. The possibility of needing a vent string should be considered when planning casing sizes for a new well.
When pumping through tubing in the absence of a production packer, free gas, which breaks out of the oil, should be vented up from the casing/tubing annulus. However, when it is necessary to produce from beneath a production packer, a vent string can be installed. The possibility of needing a vent string should be considered when planning casing sizes for a new well.
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=== Effects of gas on pump performance ===
===Effects of gas on pump performance===


Gas that remains in solution when the liquid enters the pump increases the volume of total fluid through the pump compared to the liquid measured at the surface by the formation volume factor at pump-intake conditions. The gas also decreases the density of the fluid and, thus, the head or pressure to be pumped against in the tubing. Free gas that enters the pump must be compressed to a pressure equivalent to the head required to lift the fluid. This free gas will reduce the volume of both the produced liquid that enters the pump and the liquid measured at the surface. Any time the pump does not compress the free gas to a pressure greater than that exerted on the pump by the fluid column in the producing string, production ceases and the pump is said to be "gas locked." This condition can exist in both plunger and centrifugal pumps.
Gas that remains in solution when the liquid enters the pump increases the volume of total fluid through the pump compared to the liquid measured at the surface by the formation volume factor at pump-intake conditions. The gas also decreases the density of the fluid and, thus, the head or pressure to be pumped against in the tubing. Free gas that enters the pump must be compressed to a pressure equivalent to the head required to lift the fluid. This free gas will reduce the volume of both the produced liquid that enters the pump and the liquid measured at the surface. Any time the pump does not compress the free gas to a pressure greater than that exerted on the pump by the fluid column in the producing string, production ceases and the pump is said to be "gas locked." This condition can exist in both plunger and centrifugal pumps.


=== Intake pressure ===
===Intake pressure===


Intake pressure is the pressure in the annulus opposite the point at which the fluid enters the pump. If the pump intake pressure is increased by increasing the pump submergence, the free gas volume decreases because the fluid retains more gas in solution. Reducing the pressure drop in the pump-suction piping also reduces the free gas to be produced. The pump intake should not be deeper than is necessary to maintain the desired intake pressure. A pump intake that is too deep results in unnecessary investment and increased operating costs.
Intake pressure is the pressure in the annulus opposite the point at which the fluid enters the pump. If the pump intake pressure is increased by increasing the pump submergence, the free gas volume decreases because the fluid retains more gas in solution. Reducing the pressure drop in the pump-suction piping also reduces the free gas to be produced. The pump intake should not be deeper than is necessary to maintain the desired intake pressure. A pump intake that is too deep results in unnecessary investment and increased operating costs.
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Gas bubbles entrained in the produced liquid(s) tend to rise because of the difference in the liquid and gas densities. The rate of bubble rise depends on the size of the bubbles and the physical properties of the fluid. The size of the bubbles increases as the pressure decreases. At low pump-intake pressures, the rate of gas-bubble rise in low-viscosity fluids will approximate 0.5 ft/sec, assuming a 400-μm bubble rise in water. The increase in bubble size and rate of rise as the pressure decreases causes the reversal in curves B–D and B–E in '''Fig. 3'''.
Gas bubbles entrained in the produced liquid(s) tend to rise because of the difference in the liquid and gas densities. The rate of bubble rise depends on the size of the bubbles and the physical properties of the fluid. The size of the bubbles increases as the pressure decreases. At low pump-intake pressures, the rate of gas-bubble rise in low-viscosity fluids will approximate 0.5 ft/sec, assuming a 400-μm bubble rise in water. The increase in bubble size and rate of rise as the pressure decreases causes the reversal in curves B–D and B–E in '''Fig. 3'''.


=== Downhole gas separators and anchors ===
===Downhole gas separators and anchors===


Downhole gas separators are used in gassy wells to increase the volume of free gas removed from the liquids before reaching the pump. However, they are not 100% effective in separating the gas. In sucker-rod-pumped wells, these separators are normally called "gas anchors." Gas anchors are usually designed and built in the field; '''Fig. 4''' contains schematic drawings of six common types. The most commonly used are the "natural" gas anchor (A) and the "poor boy" gas anchor (C). Typically, there are two major components for these gas anchor assemblies, the mud anchor run on the bottom of the tubing string and the dip tube or strainer nipple run on the bottom of the pump.
Downhole gas separators are used in gassy wells to increase the volume of free gas removed from the liquids before reaching the pump. However, they are not 100% effective in separating the gas. In sucker-rod-pumped wells, these separators are normally called "gas anchors." Gas anchors are usually designed and built in the field; '''Fig. 4''' contains schematic drawings of six common types. The most commonly used are the "natural" gas anchor (A) and the "poor boy" gas anchor (C). Typically, there are two major components for these gas anchor assemblies, the mud anchor run on the bottom of the tubing string and the dip tube or strainer nipple run on the bottom of the pump.
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Example calculations of the gas capacity of various casing/tubing annuli vs. different intake pressures have been presented in 'Hein.<ref name="r9">Hein Jr., N.W. 1996. Beam-Pumping Operations: Problem Solving and Technology Advancements. J Pet Technol 48 (4): 330-336. SPE-36163-MS. http://dx.doi.org/10.2118/36163-MS</ref> This reference also discusses the types of downhole separators and emphasizes the need to run a natural gas anchor assembly whenever possible. <ref name="r9">Hein Jr., N.W. 1996. Beam-Pumping Operations: Problem Solving and Technology Advancements. J Pet Technol 48 (4): 330-336. SPE-36163-MS. http://dx.doi.org/10.2118/36163-MS</ref> Detailed discussions on design of the different types of separators, the arrangement of components, and example calculations for sizing components are presented by Gipson and Swaim. <ref name="r7">Gipson, F.W. and Swaim, H.W. 1988. The Beam Pumping Design Chain. Paper presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.</ref> Improved gas separators with decentralized intakes have been introduced. <ref name="r16">Podio, A.L. et al. 1995. Field and Laboratory Testing of a Decentralized Continuous Flow Gas Anchor. Presented at the 1995 Annual Technical Meeting of the Petroleum Soc. of CIM, 14–17 May.</ref><ref name="r17">McCoy, J.N. and Podio, A.L. 1998. Improved Downhole Gas Separators. Paper 11 presented at the 1998 Southwestern Petroleum Short Course, Lubbock, Texas, 7–8 April.</ref> This design aids in separation efficiency because it increases the local distance from the casing's inner diameter (ID) to the mud anchor, which results in an increased separation area. However, as with all specialty devices, the need to run this new design should be demonstrated by ensuring that the appropriate, standard systems have been properly installed and operated.
Example calculations of the gas capacity of various casing/tubing annuli vs. different intake pressures have been presented in 'Hein.<ref name="r9">Hein Jr., N.W. 1996. Beam-Pumping Operations: Problem Solving and Technology Advancements. J Pet Technol 48 (4): 330-336. SPE-36163-MS. http://dx.doi.org/10.2118/36163-MS</ref> This reference also discusses the types of downhole separators and emphasizes the need to run a natural gas anchor assembly whenever possible. <ref name="r9">Hein Jr., N.W. 1996. Beam-Pumping Operations: Problem Solving and Technology Advancements. J Pet Technol 48 (4): 330-336. SPE-36163-MS. http://dx.doi.org/10.2118/36163-MS</ref> Detailed discussions on design of the different types of separators, the arrangement of components, and example calculations for sizing components are presented by Gipson and Swaim. <ref name="r7">Gipson, F.W. and Swaim, H.W. 1988. The Beam Pumping Design Chain. Paper presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.</ref> Improved gas separators with decentralized intakes have been introduced. <ref name="r16">Podio, A.L. et al. 1995. Field and Laboratory Testing of a Decentralized Continuous Flow Gas Anchor. Presented at the 1995 Annual Technical Meeting of the Petroleum Soc. of CIM, 14–17 May.</ref><ref name="r17">McCoy, J.N. and Podio, A.L. 1998. Improved Downhole Gas Separators. Paper 11 presented at the 1998 Southwestern Petroleum Short Course, Lubbock, Texas, 7–8 April.</ref> This design aids in separation efficiency because it increases the local distance from the casing's inner diameter (ID) to the mud anchor, which results in an increased separation area. However, as with all specialty devices, the need to run this new design should be demonstrated by ensuring that the appropriate, standard systems have been properly installed and operated.


=== Fishing ===
===Fishing===


It is often recommended that the outside diameter (OD) of the gas anchors' steel mud anchor be less than the ID of the largest overshot or wash pipe that can be run in the well casing. This limits the gas-anchor separation capacity that can be secured in wells with small casings. Reinforced plastic mud anchors that can be drilled up, or steel designs that can be recovered with spears, should be considered when mud anchor OD must approach casing-drift diameter. This design would then be considered the "modified poor boy." Agreement should be obtained from the field before installation to ensure acceptance of the possible problems when trying to pull this type of installation.
It is often recommended that the outside diameter (OD) of the gas anchors' steel mud anchor be less than the ID of the largest overshot or wash pipe that can be run in the well casing. This limits the gas-anchor separation capacity that can be secured in wells with small casings. Reinforced plastic mud anchors that can be drilled up, or steel designs that can be recovered with spears, should be considered when mud anchor OD must approach casing-drift diameter. This design would then be considered the "modified poor boy." Agreement should be obtained from the field before installation to ensure acceptance of the possible problems when trying to pull this type of installation.


== Components of sucker-rod lift system ==
==Components of sucker-rod lift system==


The major components of a sucker-rod lift system are discussed in separate articles:
The major components of a sucker-rod lift system are discussed in separate articles:
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*[[Surface_equipment_for_sucker_rod_lift|Miscellaneous surface equipment]]
*[[Surface_equipment_for_sucker_rod_lift|Miscellaneous surface equipment]]


== Design guidance ==
==Design guidance==
 
In 1954, an in-depth study of the complex aspects associated with sucker rod pump design was started. Through this effort, Sucker Rod Pumping Research, Incorporated, a non-profit organization was created. The services of the Midwest Research Institute at Kansas City were retained to perform the work necessary to achieve the objectives of the organization. Midwest Research Institute published its report in 1968, which was then used to create the industry standard API ''RP 11L''. Gipson and Swaim did an excellent job of summarizing a sucker-rod lift-system design in The Beam Pump Design Chain<ref name="r7">Gipson, F.W. and Swaim, H.W. 1988. The Beam Pumping Design Chain. Paper presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.</ref> with the API ''RP 11L'' approach. API ''RP 11L'' is superseded by API ''TR 11L''. This recommended practice should be consulted for continued discussion of this equipment, along with a review of a sample problem and a recommended solution. Prior to this, Gibbs (1963) introduced a solution for wave equation that simulates force wave propagation through sucker rod string. The approach has been enormously updated since then by multiple authors to consider further details of the physics of the phenomena and to enhance capturing the effect of fluid properties. . The approach has become the base for multiple commercial beam pump design software.
 
In summary, use the design procedure presented in API ''TR 11L'' or a suitable wave equation. Several commercial wave-equation computer programs are available that many operators have successfully used. In the following, the beam pump design procedure based on API ''TR 11L'' is introduced. Further details are found in Takacs (2015).
 
==Sucker Rod Pump Design Based on API ''TR 11L''==
 
''Downhole Pump Displacement''
 
Due to the elasticity of the rod, the rod string might strength or contract through the pumping cycle. This results in a downhole stroke length at the plunger "''S''<sub>p</sub>" that slightly differs from the design stroke length ''S''. This difference results in an actual flow "''q<sub>a</sub>''" that is different from the design flow rate ''"q"''. Based on API TR 11L, the rod stretch is predicted. "''q<sub>a</sub>''" is then calculated and is compared to the desired ''"q"''. The optimum ''"q"'' can then be reached with an iterative procedure. The procedure or this calculation stats with determining the theoretical flow rate ''"q"'' from the pump speed "''N''", surface stroke length "''S''" , and plunger size "''d''<sub>p</sub>" as follows,
 
''q'' = (π/4''d''<sub>p</sub><sup>2</sup>''S'')''NF'',   (1)
 
where the term between brackets represents the volume displaced by the pump during a single cycle, while ''F'' is downhole pump efficiency.
A primary selection of rod string design is required. Firstly, the total length of rod string approximately equals the pump setting depth ''L'' in non-literal wells. Moreover, the configuration of rod string diameters is determined from a standard set of configurations provided in API RP 11L. The standard provides a table of the characteristics of the tapered rod string. Figure 1 shows a portion of table 4.1 provided for rod string configuration and properties. The figure is a snapshot of the digitized table provided by the Petroleum Extension (PETEX®) of The University of Texas at Austin, which can be found [https://petex.utexas.edu/publications/600-beamlift-toolbox here] under the title “Beam Lift System Design Calculators.” In Figure 1, the last six columns are API sizes of rod diameters. The table numbers represent the percentage of each size in the making of the rod string. the first column is a list of configuration identifiers. Based on ''d''<sub>p</sub> determined in the previous step, a rod configuration is selected. The other information provided by the table for each rod configuration is
 
a. Rod weight ''W''<sub>r</sub>  (lb/ft).
 
b. Elastic Constant ''E''<sub>r</sub>  (in/lb.ft).
 
c. Frequency Factor ''F''<sub>c</sub>  (-).
 
 
<gallery>
File:Figure1.png|Figure 1. A snapshot of the digitized table 4.1 of API RP 11L provided by the Petroleum Extension (PETEX®) of The University of Texas at Austin.
</gallery>
 
The dimensionless number ''S''<sub>p</sub>/''S'' is defined in API TR 11L as a function of two other dimensionless numbers, namely ''N''/''N''<sub>o</sub>' and ''F''<sub>0</sub>/''Sk''<sub>r</sub>. ''N''/''N''<sub>o</sub>' condenses the effect of pumping speed and natural frequency in the tapered rod strings. The natural frequency of non-tapered rod string ''N''<sub>o</sub> is defined by Griffin (1968) as the number of strokes that propagates through the rod string at four times the velocity of sound during the unit time. Therefore, it takes the frequency unit, namely, strokes per unit time. It is mathematically written as,
 
''N''<sub>o</sub> = ''v''<sub>s</sub>/4''L'',         (2)
 
 
where ''v''<sub>s</sub> is the velocity of sound and ''L'' is the rod string length. API RP 11L suggests the following formula based on a typical value for ''v''<sub>s</sub> in steel, the formula results require ''L'' in ft and results in ''N''<sub>o</sub> in strokes per minute Takacs (2015).
 
''N''<sub>o</sub> = 245,000/''L''.         (3)
 
Although rod string diameter is not involved in Eq. (3), the variation of diameter in tapered string affects the natural frequency. For a tapered rod string, the natural frequency ''N''<sub>o</sub>' is defined as,
 
''N''<sub>o</sub>' =  ''F''<sub>c</sub>''N''<sub>o</sub>.         (4)
 
Recall that ''F''<sub>c</sub> is the frequency factor found in Rod table 4.1 of the standard (Figure 1).
''F''<sub>0</sub>/''Sk''<sub>r</sub> condenses the effects of elastic rod stretch due to fluid load. ''F''<sub>0</sub> is the fluid load on the plunger defined as (lbs),
''F''<sub>0</sub> =  0.052''ρ''<sub>L</sub>''L''(π/4''d''<sub>p</sub><sup>2</sup>) (5)
 
where ''ρ''<sub>L</sub> is liquid density (lb/ft3), ''L'' is in ft and ''d''<sub>p</sub> is in inch. ''k''<sub>r</sub> is the Spring Constant of the total rod string and represents the load required to stretch the total rod string for unit length. ''k''<sub>r</sub> is defined as,
 
''k''<sub>r</sub> = 1/''E''<sub>r</sub>''L'',         (6)
 
where ''E''<sub>r</sub> is the elastic constant of the tubing. It takes the dimension  1/''F''<sub>u</sub> , where ''F''<sub>u</sub> is unit force.
Based on an enormous number of experiments, ''S''<sub>p</sub>/''S''=''f''(''N''/''N''<sub>o</sub>',''F''<sub>0</sub>/''Sk''<sub>r</sub>) is constructed as a plot at discrete values of the independent parameters (Figure 2).
 
 
<gallery>
File:Figure2.png|Figure 2. Figure 4.1 of API TR 11L plotted from the digitization of Petroleum Extension (PETEX®) of The University of Texas at Austin
</gallery>
 
 
As seen from the figure, the downhole stroke ''S''<sub>p</sub> resulted from rod strain is always less than the design stroke ''S''. If tubing is not anchored, tubing strain is suspected.  The resultant ''S''<sub>p</sub> should be corrected for tubing strain as follows,
 
''S''<sub>p</sub>/''S'' = ''S''<sub>p</sub>/''S''|<sub>rod strain</sub> - ''S''<sub>p</sub>/''S''|<sub>tubing strain</sub> = ''S''<sub>p</sub>/''S''|<sub>rod strain</sub> - ''F''<sub>0</sub>/''Sk''<sub>t</sub> (7)
where  ''k''<sub>t</sub> is the Spring Constant of the unanchored tubing and represents the load required to stretch the unanchored portion of the tubing, between the anchor and the pump, unit length. Similar to Eq. (6), ''k''<sub>t</sub> is defined as
  ''k''<sub>t</sub> = 1/''E''<sub>t</sub>''L'',   (8)
where ''E''<sub>t</sub> is the elastic constant of the tubing. It takes the dimension  1/''F''<sub>u</sub> , where ''F''<sub>u</sub> is unit force.
 
From ''S''<sub>p</sub>/''S'' = ''S''<sub>p</sub>/''S'' x ''S'', "''q<sub>a</sub>''" is calculated using Eq. (1). If not acceptable, "''N''", "''S''" , or "''d''<sub>p</sub>" are changed and and an iterative procedure is started from step 1. Increasing "''N''" to compensate for stroke length loss does not come free of expense. The more "''N''" is increased, the shorter the rod string and pump fatigue life will be. Moreover, increasing "''d''<sub>p</sub>" results in a shorter ''S''<sub>p</sub> due to inertia effects. Therefore, an optimum selection of these parameters is needed.
 
''Range of Polished Rod Loads''
 
Throughout the pump cycle, the polished rod exhibits varying loads that swing between two extremities, namely, the Maximum Polished Rod Load ''PPRL'' and the Minimum Polished Rod Load ''MPRL''. ''PPRL'' and ''MPRL'' are found as follows,
 
  ''PPRL'' = ''W''<sub>rf</sub> + [(''F''<sub>1</sub>/''Sk''<sub>r</sub>) x ''Sk''<sub>r</sub>], and   (9)
 
  ''MPRL'' = ''W''<sub>rf</sub> - [(''F''<sub>2</sub>/''Sk''<sub>r</sub>) x ''Sk''<sub>r</sub>],   (10)
 
where ''W''<sub>rf</sub> is the buoyant weight of the rod string. while ''F''<sub>1</sub>/''Sk''<sub>r</sub> and ''F''<sub>2</sub>/''Sk''<sub>r</sub> are functions of ''N''/''N''<sub>o</sub> and ''F''<sub>0</sub>/''Sk''<sub>r</sub> and are found from Figures 4.2 and 4.3 of API TR 11L, respectively (Figure 3 and Figure 4).
 
 
<gallery>
File:Figure 3.jpg|Figure 3. Figure 4.2 of API TR 11L plotted from the digitization of Petroleum Extension (PETEX®) of The University of Texas at Austin
File:Figure 4.jpg|Figure 4. Figure 4.3 of API TR 11L plotted from the digitization of Petroleum Extension (PETEX®) of The University of Texas at Austin
</gallery>
 
''W''<sub>rf</sub> for a steel rod is extimated from the following,
 
  ''W''<sub>rf</sub> = ''W''<sub>r</sub> (1-0.128''γ''),   (11)
 
''Peak Torque of The Crank''
 
Peak torque ''T'' is required to properly select the surface pump. The following formula is proposed in API TR 11L,
 
  ''T'' = (2''T''/''S''<sup>2</sup>''k''<sub>r</sub>) x ''S''<sup>2</sup>''k''<sub>r</sub> x ''S''/2 x ''T''<sub>a</sub>,   (12)
 
where the dimensionless property 2''T''/''S''<sup>2</sup>''k''<sub>r</sub> is obtained from the figure 4.4 of API TR 11L (Figure 5). It is a function of ''N''/''N''<sub>o</sub> and ''F''<sub>0</sub>/''Sk''<sub>r</sub>. ''T''<sub>a</sub> is a correction factor that is function of ''N''/''N''<sub>o</sub>', ''F''<sub>0</sub>/''Sk''<sub>r</sub> and ''W''<sub>rf</sub>/''Sk''<sub>r</sub>. A percentage ''p'' is found from figure 4.6 of API TR 11L based on ''N''/''N''<sub>o</sub>' and ''F''<sub>0</sub>/''Sk''<sub>r</sub>. Then, ''T''<sub>a</sub> is found from,
 
  ''T''<sub>a</sub> = 1 + ''p'' x (''W''<sub>rf</sub> - 0.3)/0.1.   (13)
 
<gallery>
File:Figure 5.jpg|Figure 5. Figure 4.4 of API TR 11L plotted from the digitization of Petroleum Extension (PETEX®) of The University of Texas at Austin
</gallery>
 
References
 
American Petroleum Institute. 2008. API ''TR 11L'':Recommended Practice For Design Calculations For Sucker Rod Pumping Systems (Conventional Units).
American Petroleum Institute. 1988. API ''RP 11L'': Recommended Practice For Design Calculations For Sucker Rod Pumping Systems (Conventional Units).
Gibbs, S. G. 1963. Predicting the Behavior of Sucker-Rod Pumping Systems. Journal of Petroleum Technology, 15(7), 769-778. https://doi.org/10.2118/588-PA.
Griffin, F. D. 1968. Electric Analog Study of Sucker-Rod Pumping Systems. Paper presented at the Drilling and Production Practice, New York, New York.
Takacs, G. 2015. Sucker-Rod Pumping Handbook. Gulf Professional Publishing.


Gipson and Swaim did an excellent job of summarizing a sucker-rod lift-system design in The Beam Pump Design Chain<ref name="r7">Gipson, F.W. and Swaim, H.W. 1988. The Beam Pumping Design Chain. Paper presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.</ref> with the API ''RP 11L'' approach. This recommended practice should be consulted for continued discussion of this equipment, along with a review of a sample problem and a recommended solution. In summary, use the design procedure presented in API ''RP 11L'' or a suitable wave equation. Several commercial wave-equation computer programs are available that many operators have successfully used.


== Nomenclature ==
==Nomenclature==


{|
{|
|-
|-
| ''Q''/''aP''<sup>0.4</sup>
|''Q''/''aP''<sup>0.4</sup>
| =
|=
| parameter from Gilbert used to determine gradient correction factor, where Q is gas flow rate, Mscf/D; a is the casing-tubing cross-sectional area, in.2; and p is the producing pressure, psia
|parameter from Gilbert used to determine gradient correction factor, where Q is gas flow rate, Mscf/D; a is the casing-tubing cross-sectional area, in.2; and p is the producing pressure, psia
|}
|}


== References ==
==References==


<references />
<references />


== Noteworthy papers in OnePetro ==
==Noteworthy papers in OnePetro==


McCoy, J.M., Patterson, J., and Podio, A.L. Downhole Gas Separators-A Laboratory and Field Study. [http://dx.doi.org/10.2118/07-05-05 http://dx.doi.org/10.2118/07-05-05]. (p20-40)
McCoy, J.M., Patterson, J., and Podio, A.L. Downhole Gas Separators-A Laboratory and Field Study. http://dx.doi.org/10.2118/07-05-05. (p20-40)


McCoy, J.M., Patterson, J., and Podio, A.L. Downhole Gas Separators-A Laboratory and Field Study. [http://dx.doi.org/10.2118/07-05-05 http://dx.doi.org/10.2118/07-05-05]. (p48-55)
McCoy, J.M., Patterson, J., and Podio, A.L. Downhole Gas Separators-A Laboratory and Field Study. http://dx.doi.org/10.2118/07-05-05. (p48-55)


Podio, A.L., Rowlan, L., McCoy, J.N. et al. Evaluation and Performance of Packer-Type Downhole Gas Separators. Presented at the 2013/3/23/. [http://dx.doi.org/10.2118/164510-MS http://dx.doi.org/10.2118/164510-MS].
Podio, A.L., Rowlan, L., McCoy, J.N. et al. Evaluation and Performance of Packer-Type Downhole Gas Separators. Presented at the 2013/3/23/. http://dx.doi.org/10.2118/164510-MS.


== Other noteworthy papers ==
==Other noteworthy papers==


McCoy J. N. – Rowlan, O. L. – Becker, D. - Podio, A. L.: “Downhole Diverter Gas Separator.” Proc. 59th Annual Southwestern Petroleum Short Course, 2012, 103-114. [http://www.worldcat.org/oclc/794584179 Worldcat]
McCoy J. N. – Rowlan, O. L. – Becker, D. - Podio, A. L.: “Downhole Diverter Gas Separator.” Proc. 59th Annual Southwestern Petroleum Short Course, 2012, 103-114. [http://www.worldcat.org/oclc/794584179 Worldcat]
Line 170: Line 275:
McCoy, J. N. – Rowlan, O. L. – Becker, D. - Podio, A. L.: “Optimizing Downhole Packer-Type Separators.” Proc. 60th Annual Southwestern Petroleum Short Course, 2013 91-113. [http://www.worldcat.org/oclc/853495838 Worldcat]
McCoy, J. N. – Rowlan, O. L. – Becker, D. - Podio, A. L.: “Optimizing Downhole Packer-Type Separators.” Proc. 60th Annual Southwestern Petroleum Short Course, 2013 91-113. [http://www.worldcat.org/oclc/853495838 Worldcat]


== External links ==
==External links==


Downhole Diagnostic. "Sucker Rod Pumping Wells: Design, Operation, & Optimization." Scribd. [http://www.scribd.com/doc/238486620/Sucker-Rod-Pumping-Wells-Design-Operation-Optimization http://www.scribd.com/doc/238486620/Sucker-Rod-Pumping-Wells-Design-Operation-Optimization].
Downhole Diagnostic. "Sucker Rod Pumping Wells: Design, Operation, & Optimization." Scribd. http://www.scribd.com/doc/238486620/Sucker-Rod-Pumping-Wells-Design-Operation-Optimization.


== See also ==
==See also==


[[Operation_of_sucker-rod_lift_systems|Operation of sucker-rod lift systems]]
[[Operation_of_sucker-rod_lift_systems|Operation of sucker-rod lift systems]]
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[[PEH:Sucker-Rod_Lift]]
[[PEH:Sucker-Rod_Lift]]


== Page champions ==
==Page champions==


[http://e8llc.com/john-g-svinos/ John G. Svinos]
[http://e8llc.com/john-g-svinos/ John G. Svinos]


== Category ==
==Category==
[[Category:Pages with broken file links]] [[Category:3.1.1 Beam and related pumping techniques]] [[Category:YR]]
[[Category:Pages with broken file links]]  
[[Category:3.1.1 Beam and related pumping techniques]]  
[[Category:YR]]
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