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Downhole sucker-rod pumps
- 1 Pump components
- 2 Types of pumps
- 3 API pumps and nomenclature
- 4 Non-API and specialty pumps
- 5 Materials selection
- 6 Slippage past plungers
- 7 Compression ratio
- 8 Selection of subsurface rod pumps
- 9 Pump operating problems and solutions
- 10 Pump shop, repair, and audit
- 11 Nomenclature
- 12 References
- 13 Noteworthy papers in OnePetro
- 14 External links
- 15 See also
There are seven major components for downhole rod pumps: standing and traveling valves, plunger, barrel, seating assembly, pull tube or valve rod (for insert pump), and the fittings that hold the assembled pump together. The most common of these components and the final types of assembled pumps are covered by American Petroleum Institute (API) Specification 11AX. 
Types of pumps
API recognizes two main types of pumps: rod and tubing. Rod pumps also are called insert pumps because they are run (inserted) in the production tubing. Tubing pumps are so named because the working barrel of this pump is coupled with the production-tubing string.
There is a wide range of plunger (or pump-bore) sizes standardized by the industry. The API pump-bore sizes that are currently available range from 1 1/16 to 3 3/4 in. in diameter. This 1 1/16-in. size has been added back in the latest edition of the standard. Additionally, a new barrel type has been accepted in the latest API Spec. 11AX. This is the "X-type" barrel. It has a thin-walled barrel configuration for threads on either end of the heavy-walled barrel and is available for metal plungers only. This type of pump does not require the extension couplings normally needed for heavy-walled barrel pumps. Thus, this pump reduces the burst or collapse concerns of the thin-walled extension couplings and allows deeper producing depths to be attained.
API pumps and nomenclature
While there are only two main types of pumps standardized by API, there are four different types of rod pumps. These are classified by the type of barrel (standing or traveling) and where the pump is anchored (top or bottom). API Spec. 11AX. shows the letter designations for the various types of rod and tubing pumps that are available for different barrel thicknesses and either metal or soft-packed plungers.
The complete pump designation of an API pump adds dimensional diameters and lengths to the letter designations. This has been modified in the latest revision to incorporate all approved sizes and barrel types along with separating the extensions into the top and bottom lengths, if required. The complete API designation includes the following:
- Nominal tubing size (from 1.9- to 4.5-in. OD) - represented with 2 digits
- Basic bore diameter (from 1.0625 to 3.75 in.) - represented with 3 digits
- Type of pump (rod or tubing) - R or T to indicate type
- Type of barrel (heavy, thin, or X type) - single alpha character to represent the barrel type
- Seating-assembly location (top or bottom) - A (for top), B (for bottom), or T (for bottom, traveling barel)
- Type of seating assembly (cup or mechanical) - C or M to indicate type
- Barrel length (ft) - single digit length
- Nominal plunger length (ft.) - single digit length
- Length (in.) of upper extension (if required)- single digit length
- Length (in.) of lower extension (if required)- single digit length
API Spec. 11AX. shows that, for example, a 1¼-in. bore-rod-type pump with a 10-ft heavy-walled barrel, a 2-ft upper extension, a 2-ft lower extension, a 4-ft plunger, and a bottom-cup-type seating assembly that will be used in 2 3/8-in. tubing would be designated as 20-125-RHBC-10-4-2-2.
It is important to know that the users of API pumps need to provide, along with the pump nomenclature, the following ordering information: barrel and plunger material, plunger clearance (or fit tolerance), and valve (ball and seat) and fittings material. The materials normally available for each of these components also are now included in the latest edition of API Spec. 11AX.
Non-API and specialty pumps
The types of pumps, sizes, and component materials that are included in the API standards are based on the best industry practices that meet widespread industry needs. While API standardizes the majority of pumps and components that are used in sucker-rod lift, there are special parts and pumps that have been developed by manufacturers to try to solve specific pumping problems. This specialty equipment should be considered when best industry practices and standardized components have proved unacceptable. However, the manufacturer of these components should create all parts to the same quality level required in API Spec. 11AX. Useful specialty pumps include the following:
- Casing pump for production without tubing
- Pumps with two plungers that act in series to increase displacement
- High-compression plunger assembly or pump for handling gas-interference problems
- Three-tube pump for handling fines or solids
- Pumps with a shorter barrel than normally recommended, so that the plunger completely wipes solids free of the barrel and prevents sticking.
Additionally, there are special pump components, such as valve rods, valves, and tubing drains, that are sometimes beneficial in situations in which the capabilities of normal API pumps and components have been exceeded. The manufacturer of special, non-API pumps and components should be contacted to determine the working capabilities and limitations of any of these specialty components. However, these items should be selected with care and used only after the best production effort has been thoroughly tested with standard components.
API Spec. 11AX was modified to add not only new sizes and types of pumps with new quality, inspection, and tolerance requirements, but also standardized, widely used pump-component materials. Various material descriptions, their API identification symbol, surface condition, base core hardness, base material, and base-material minimum yield strength for plated barrels, are shown in Table A of Spec. 11AX. Similar tables in Spec. 11AX (B through I) are incorporated for case-hardened barrels, nonhardened barrels, balls and seats, cages, pull tubes, valve rods, fittings, seating cups, spray-metal plungers, and plated plungers. These changes have incorporated the prior information in API RP 11AR and the NACE International MR 01-76 for materials to be used in most production environments.
Allowable setting depth
In the early 1990s, an industry task group analyzed the stresses that react on a downhole rod pump. This was required to determine if there were recommended allowable loads that could be subjected to rod pumps of different types, sizes, and metallurgy. This group developed the burst, collapse, and axial-loading equations to determine these limits and the associated maximum recommended setting depth for sucker-rod lift pumps,  published in API RP 11AR. The depth limitation and stresses on the downhole pump barrel and components should be considered when selecting the size, type, and metallurgy for a downhole pump.
Slippage past plungers
The slippage or leakage past a plunger on a closely fitted sucker-rod pump is an important factor in properly designing and operating a well. Slippage or leakage can be calculated using the following equation, adapted from the 1987 edition of the Petroleum Engineering Handbook.
in which Q = slippage or leakage loss, in.3/min; D = plunger diameter, in.; P = differential pressure across plunger, psi; C = diametrical clearance between plunger and barrel, in.; μ = absolute viscosity of fluid, cp; and Lp = plunger length, in.
Tight clearances (less than 0.003 in.) may cause producing problems, whereas loose clearances (greater than 0.008 in.) may result in excessive leakage by the pump. Good field-pump records are essential to make good pump recommendations.
Slippage in sucker-rod pumps takes two forms: static and dynamic slippage. • Static slippage is the dominant factor and occurs only during the upstroke of the pump; it is caused by the pressure differential across the plunger-barrel fit. The high hydrostatic pressure present in the tubing string, acting on top of the plunger with the traveling valve closed, forces liquid to slip past the plunger into the pump chamber between the traveling and the standing valves. • Dynamic slippage, on the other hand, takes place both on the up-, and the downstroke of the pump and is caused by the plunger’s movement; its magnitude being proportional to the plunger velocity i.e. the pumping speed used. The direction of liquid slippage is different for the up-, and downstroke: during upstroke liquid falls below the traveling valve while during the downstroke liquid flows upwards and decreases the amount of liquid passing through the traveling valve. An extensive series of theoretical and experimental investigations [ 13 – 16 ] on pump slippage resulted in the following main conclusions. • Early formulas greatly overestimate the amount of liquid slippage. Typical values, based on experimental data are about two times greater for plunger fits less than 0.006” and more than three times greater for fits larger than 0.006”. This implies that pumps with fits larger than those selected on the basis of earlier predictions can be used without experiencing too high pump leakages. • The eccentricity of the plunger’s lateral position in the barrel has a great effect on liquid slippage (also proved by [ 17 ]), a fact that most previous formulas disregarded. For a completely eccentric position leakage rates 2.5 times greater than for concentric cases can be expected. • Most previous correlations disregarded the effect of dynamic leakage in the pump.
Increasing the "compression ratio" of a plunger pump may reduce the effects of free gas and help prevent gas locking. The compression ratio is the volume of the pump chamber at the start of the downstroke divided by the volume at the end of the stroke. This ratio is fixed by the manufacturer on the basis of the design of the rod pump's components and the fit of the plunger to the pump barrel. Varying the sucker-rod pump components and close spacing will alter the compression ratio; however, some of these components are not standardized by the API Spec. 11AX. This can increase waste space in the pump, resulting in a decreased compression ratio. The importance of the compression ratio and associated waste space may prevent a new pump from being able to pump down a well.  This work by McCafferty is further discussed in Hein , which also presents different pump manufacturers' normal compression ratios for similar pump types.
Selection of subsurface rod pumps
Pumps for sucker-rod lifted wells should be selected on the basis of numerous variables that are provided by the well, the operating conditions, and the life of the pump. The main variables to consider are as follows:
- Well depth
- Bottomhole temperature
- Fluid viscosity
- Amount and size of particulates in the produced fluids
- Produced-fluids corrosivity
- Required production rate vs. pump capacity
- Fluid-specific gravity
- Casing/tubing size
- Well-completion type
- Gas/liquid ratio (GLR)
- Pump-intake pressure vs. fluid bubblepoint
- Spare/surplus pumps and components
- New purchase and repair costs
These variables influence:
- Stresses on the pump
- Type of pump used
- Component metallurgy
- Pump size
- Internal-fit tolerance
- Ability to handle solids/gas
Discussing these parameters with the pump manufacturer and local pump shop should help determine the proper pump to ensure acceptable pump life.
There are two aspects to consider when sizing the downhole pump for an installation. The first is that the pump capacity should be related to the well capacity. The pump displacement is determined on the basis of the pumping speed, unit stroke length, and plunger diameter. This general equation is
in which PD = pump displacement, BFPD; 0.1166 = a volumetric conversion; S = stroke length, in.; N = pumping speed, spm; and D = diameter of the pump plunger, in.
The stroke length should be the expected downhole stroke or plunger stroke (Sp) that is calculated from a sucker-rod string calculation or sizing computer program. However, the surface stroke length may be considered an approximation of the maximum capacity for a given pumping situation.
The recommended relationship of pump displacement to well capacity (WC), as discussed in Hein, is as follows:
Thus, for a well that produces 100 BFPD, the various pumping parameters should be selected to provide a pump displacement of between 118 and 154 BFPD. Because the pump displacement is greater than the well capacity, the system will require some type of well control to prevent constant operation and overpumping of the well. This increased capacity accommodates pump wear and loss of efficiency with time. As this occurs, system control should be adjusted to continue producing as required, without overpumping by running the pump more often. It should be considered that as the pump diameter increases, the efficiency of the system increases. However, this also increases the load on the rod string and the peak torque for the pumping unit. Thus, reasonable selection of these pumping parameters should be considered that results in extended run time.
The second aspect of pump sizing, once the pump diameter is selected, is ensuring that the downhole pump is properly built. The main component that needs to be sized is the barrel length, which should be long enough to accommodate the plunger length, the downhole stroke length, all fittings, and a rounding factor.
The minimum plunger length recommended is normally 3 ft. It is recommended that the length of the plunger is increased 1 ft/1,000 ft of well depth, up to a 6-ft maximum length. Plunger lengths longer than 6 ft have not shown to be an advantageous, while specialty pumps may have a plunger shorter than 3 ft.
When determining the barrel length, normally the maximum pumping-unit stroke length is considered to allow pump displacement to be increased with the existing downhole pump without pulling the downhole pumping equipment to change the capacity. However, this extra length and the pump-displacement option increase the price of the pump. Thus, the downhole Sp length should be considered the stroke measurement to use in the barrel-length calculation.
The types of fittings and their respective lengths depend on the type of pump being used. Normally, 12 to 18 in. covers the length range for various pump types.
The final factor in determining the barrel length is a rounding factor. Once the previous factors are added together, the length-of-barrel calculation is normally increased to the next available whole-foot standard length for a pump according to API Spec. 11AX.  Using the surface stroke length vs. the downhole Sp length, and designating this length as the rounding factor, may provide sufficient barrel length to accommodate the spacing length some operators or pump shops suggest.
This spacing factor is normally a minimum of 24 in. for wells up to 4,000 ft deep, then increases 6 in. in length per 1,000 ft of increased well depth. These rules are recommended for all steel sucker-rod strings. When fiber-reinforced plastic (FRP) rods are used, additional increased spacing may be required because of the increased "stretch" or elongation of the rod string under the load. The FRP-rod manufacturer should have, or have access to, a sucker-rod-string design program that will estimate the increased plunger travel. This length then should be used in the barrel-length determination. Thus, for a 5,000-ft-deep well, with a required 74-in. surface stroke, a 48-in.-long plunger with a steel rod string and a designated 2 7/8 × 1½-in. RHB pump, the displacement length must be greater than 152 in. to permit adequate spacing. A standard 12-ft barrel with 1-ft top and bottom extension couplings should be considered.
Pump operating problems and solutions
There are four common ways subsurface rod pumps are abused. These problems may also be applicable to other downhole pumps, and thus, these related solutions probably are applicable to other artificial-lift techniques. The four common abuses follow:
- Overpumping the well
- Gas interference
- Pump hitting up or down
- Trash entering the pump
Because the recommended pump-displacement design is for the pump to have greater capacity than the well, an overpumping condition may occur if the well is not properly controlled. An overpumping condition is indicated when there is a fluid pound more than one-quarter of the way down on the downstroke because of insufficient fluid in the well to charge or fill the downhole pump. This condition may be seen on the surface if the pound is very severe, but the best way to detect this is with the use of a dynamometer. Other indications of overpumping are if the pump volumetric efficiency is less than 70% or if a downhole fluid-level survey shows that the normal operating fluid level is at or very near the pump intake. Overpumping may cause mechanical damage to the pump or cause damage uphole to the rod/tubing because of increased buckling and wear. Properly setting a well controller will help reduce severe overpumping.
Indications of gas interference include low volumetric efficiency, while the fluid-level survey shows apparent, adequate pump submergence and a polish rod that is excessively hot to the touch. A dynamometer survey, when combined with the precalculated well loads for the applicable design conditions, may indicate gas pound, gas lock, or inconsistency with the assumed conditions. The gas-interference condition may be remedied by increasing the pump compression ratio, if possible. This may be as simple as respacing the pump as the fluid level decreases in the well annuli or changing the stroke length for the pump downhole, or it may require pulling the pump and altering its design. The compression ratio of the replacement pump should be determined to ensure adequate lift capabilities. Additionally, a pump with tighter fit tolerance/waste space, smaller pump diameter, increased stroke length, adequate downhole separation, and properly designed pump gas anchor should be considered along with properly placing the pump intake above or below the perforations as discussed in Sucker-rod lift. Finally, if these normal solutions do not resolve the problem, then special pumps or specialty components may be considered.
A pump component hitting on the up- or downstroke is indicated by an instantaneous load change and can be shown with a load-capable dynamometer. This condition normally occurs because of inadequate pump spacing as the fluid level pumps down or because the pump has inadequate compression ratio/excessive waste space for the seating depth for the designed pumping parameters. While severely “tapping,” or “tagging,” the pump may be heard, felt, or seen, the smashed pump components obtained during a pump teardown will show the damage this condition causes. This condition may also be magnified for tubing that does not have an anchor, or if the anchor is not properly set. Other conditions that may cause this problem include if the pump-intake piping is plugged or not properly designed, if the pump has inadequate compression ratio, if the polished-rod clamp is not sufficiently tightened, and/or if the pump barrel is not properly sized.
The last normal operating problem is caused by solids entering the pump. There are many reasons for these particulates. The particulates may be caused by well conditions such as producing the fracturing sand back into the wellbore, very fine powder from the formation, iron sulfide scale from the downhole equipment because of inadequate corrosion inhibition, iron sulfide or other scales from the formation because of incompatible fluids, or from overpumping the well. Solutions include using different types of pumps designed to handle fines and solids, such as three-tube pumps or soft-packed plungers, and using harder materials or coatings for the pump components. Filters or downhole, wire-wrapped screens have been used with limited success until they plug. In the past, tighter fit tolerances (< 0.003 in.) for the plunger-barrel annuli have been considered; however, recent work done in both the laboratory and the field, has shown the benefit of increasing these tolerances to greater than 0.005 in. when solids are a problem.  This work has resulted in the variable-slippage pump that would be useful for conditions in which solids are present in the produced fluids and gas interference is also a problem. 
Pump shop, repair, and audit
The pump manufacturer typically machines or obtains subcontract pump components for future assembly of the pump by a pump shop. The shop, the knowledge of the design, selection of pump types, and associated component metallurgies become critical to long well life and a decreased failure frequency. API RP 11AR provides useful information on pump types, component and metallurgy selection, pump-setting-depth calculation, and pump assembly/teardown.
While the pump manufacturers usually produce their pump components with an acceptable quality program (such as ISO 9001 or API Spec. Q1), most pump shops are not covered under these rigorous plans. Thus, it becomes critical to have the pump shop and its employees audited by qualified personnel to ensure that training, workmanship, safety, and environmental considerations are adequate. On the basis of many shop audits, assembly and teardown observations, requirements and recommendations in API standards, and performance quality requirements, a checklist that should be used as a first step in obtaining an acceptable pump shop has been developed and published.  Once the audit is performed and the checklist completed, the findings should be discussed with the appropriate pump-shop personnel and a time line developed detailing when changes to resolve any problem areas will be made.
|C||=||diametrical clearance between plunger and barrel, in.|
|D||=||plunger diameter, in.|
|Lp||=||plunger length, in.|
|N||=||pumping-unit speed, spm|
|p||=||differential pressure across plunger, psi|
|PD||=||pump displacement, BLPD|
|Q||=||slippage or leakage loss, in.3/min|
|S||=||surface stroke length, in.|
|WC||=||well production capacity, BFPD|
|μ||=||absolute viscosity of fluid, cp|
- API Spec. 11AX, Subsurface Sucker Rod Pumps and Fittings, eleventh edition. 2001. Washington, DC: API.
- API RP 11AR, Recommended Practices for Care and Use of Subsurface Pumps, fourth edition. 2000. Washington, DC: API.
- MR01-76, Metallic Materials for Sucker Rod Pumps for Hydrogen Sulfide Environments, Natl. Assn. of Corrosion Engineers (NACE), Houston.
- Hein Jr., N.W. and Loudermilk, M.D. 1992. Review of New API Pump Setting Depth Recommendations. Presented at the SPE Annual Technical Conference and Exhibition, Washington, D.C., 4-7 October 1992. SPE-24836-MS. http://dx.doi.org/10.2118/24836-MS
- Bradley, H.B. ed. 1987. Petroleum Engineering Handbook. Richardson, Texas: SPE.
- McCafferty, J.F. 1993. Importance of Compression Ratio Calculations in Designing Sucker Rod Pump Installations. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 21-23 March 1993. SPE-25418-MS. http://dx.doi.org/10.2118/25418-MS
- 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
- Patterson, J. et al. 2000. Fluid Slippage in Down-Hole Rod-Drawn Oil Well Pumps. Paper 16 presented at the 2000 Southwestern Petroleum Short Course, Lubbock, Texas 12–13 April.
- Williams, B.J. 2001. Summary of Testing of Variable Slippage Pump (VSP) for Gas Locking Conditions in Down-Hole Sucker Rod Pump. Paper 22 presented at the 2001 Southwestern Petroleum Short Course, Lubbock, Texas, 24–25 April.
- Quality Systems—Model for Quality Assurance in Design, Development, Production, Installations, Servicing. 1987. ISO 9001, Intl. Organization for Standardization (ISO), Geneva, Switzerland.
- API Spec. Q1, Specification for Quality Programs for the Petroleum and Natural Gas Industry, sixth edition. 1999. Washington, DC: API.
- Hein, N.W. Jr. and Thomas, S. 2000. Rod Pump Shop Audits and Performance Requirements. Paper 6 presented at the 2000 Southwestern Petroleum Short Course, Lubbock, Texas, 12–13 April.
Noteworthy papers in OnePetro
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read Muth, G. M. – Walker, T. M., 2001: Extending Downhole Pump Life using New Technology. Paper SPE 68859 presented at the Western Regional Meeting held in Bakersfield, March 26-30. Parker, R. M. – Wacker, J. – Watson, B. – Dimock, J., 2002: The Panacea Pump Tool. Proc. 49th Annual Southwestern Petroleum Short Course, 88-95. Williams. B., 2007: Sand-Pro Sucker Rod Pump for Fluid with Sand Production Conditions in Down-Hole Sucker Rod Pumps. Proc. 54th Annual Southwestern Petroleum Short Course, 172-174.
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