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Sucker rods

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Sucker rods are a key component of a sucker-rod lift type of artificial lift system. This page discusses rod types, design of the rod string, couplings, maintenance and replacement.

Steel sucker rods

API Spec. 11B[1] provides the industry requirements for sucker rods and some related sucker-rod lift equipment. The three main grades of steel rods follow:

  • Grade C rods that have minimum and maximum tensile strengths of 90,000 and 115,000 psi, respectively.
  • Grade K rods that have a minimum tensile strength of 90,000 psi and a maximum strength of 115,000 psi. These rods are made with 1.65 to 2.00% nickel and are, therefore, more expensive than Grade C rods, but may have improved corrosion-related properties.
  • Grade D rods that have a minimum tensile strength of 115,000 psi and a maximum strength of 140,000 psi. Three types of this grade are covered by Spec. 11B: plain-carbon, alloy, and special-alloy steels.

Spec. 11B allows for rod lengths of 25 or 30 ft and pony rods in six lengths (i.e., 20, 44, 68, 92, 116, and 140 in. measured from contact face of pin shoulder to contact face of pin shoulder). The acceptable rod diameter goes from 5/8 to 1 1/8 in. in 1/8-in. increments. The most common rods in use will meet API specifications and will probably be in 25-ft lengths. The most important selection requirement is that the pulling rig can accommodate single-, double-, or triple-length rod segments.

The API does not specify the minimum yield strength for sucker rods. Where the yield strength of a rod string is necessary in calculations, it is recommended that if the manufacturer is not known, a minimum yield of 60,000 psi for Grade C and K and of 100,000 psi for Grade D should be used. If the manufacturer and rod type are known, the actual yield-strength values should be used. For good operating practices, the minimum yield strength should not be exceeded.

API RP 11BR[2] provides industry recommendations on the selection and use of API-grade rods.

Pony rods

Pony rods are sucker rods shorter than 25 ft, and they vary in length. They are most commonly placed adjacent to the polished rod at the top of the rod string, on top of the downhole pump for handling purposes, and on top of the polished rod with appropriate couplings to prevent the string from falling downhole if the polished-rod clamp slips. Old pony rods normally should not be used in the load-carrying part of a new rod strings. Thus, when placing the rod string with new suckers, new pony rods should be used.

Fiber-reinforced plastic sucker rods

Fiber-reinforced plastic (FRP) sucker rods may be used instead of metal under certain conditions. These rods are normally made from protruded fiberglass. They also are standardized in size and performance by API Spec. 11B. Reviewing this standard shows that temperature, load reversals, and fatigue life have a bigger effect on FRP rods than on steel rods. It is important to keep the following in mind when screening a well for FRP-rod use:

  • FRP-rod bodies will not corrode, but the rest of the steel components, including the fiberglass pin connectors and couplings, the steel rods making up the rest of the string, the pump, tubing, casing, flowlines, etc., still have to be protected if producing a corrosive fluid. Thus, fiberglass rods should not be used alone to prevent rod-string corrosion or system failures or to eliminate the need for an effective corrosion-inhibition program.
  • FRP rods should be considered when the pumping-unit gear-reducer torque or structure rating exceed design limitation and need to be decreased. Reducing the weight of the sucker-rod string reduces the torque measured at the polished rod. However, if the well is expected to produce long term, it may be more cost effective to upsize the pumping unit.
  • It should be determined if it will be possible to stroke the subsurface pump plunger because of the increased elasticity and effect on Sp .
  • If the well deviation is very large at any point, the increased friction may cause buckling and compressive stresses on the sucker rods. Increased buckling is very damaging to FRP rods; thus, these probably should not be run in deviated wells.
  • Allowing fluid or gas pounding may produce damaging compressive forces in the FRP rods; thus, maximum drawdown is not possible.

Currently, there is no recognized formula for calculating overtravel when a mixed FRP and steel rod string is used. An attempt was made by an API task group to try modifying API RP 11L[3] to include a FRP-rod-string analysis, but this was not accepted by the industry. A study of several FRP string-design analyses indicate that rod-string overtravel may be approximately equal to the following:


where S = stroke length, in.; N = pumping speed, spm; and LPSD = seating nipple/pump depth, ft. This overtravel approximately equals twice the expected value when using steel sucker-rod strings.

Non-API sucker rods

Non-API sucker rods generally fall into two groups: one contains rods with a higher strength than API Grade D, and the other contains rods made of alloys that are less susceptible to corrosion or that have received a special heat treatment.

The high-strength group is generally harder and higher strength than Grade D and may be more susceptible to hydrogen embrittlement and notch effects that may then decrease run life.

Those rods that have a special heat treatment or are made of special alloys are normally premium-priced items. Thus, a full economic analysis should be conducted and good operating records obtained to determine if use of these rods is cost effective.

Flexible strand

Approximately 40 years ago, a top steel manufacturer experimented with the use of plastic-coated wire cable instead of sucker rods. This cable was a continuous strand that required special pulling equipment. Sufficient sinker bars or a special pull-down pump had to be used to keep any compressive force from acting on the strand. The connectors used at the pump or at the top of the sinker bars were the weakest portion of the flexible strand. If any of the strands furnished the weight that was required to help open the traveling valve, the strands immediately above the sinker bars failed in short order because of the compressive forces. This type of rod string was less expensive than a normal API steel string and was found useful for unloading gas wells. The biggest disadvantages that restricted the use of this type of string were lack of service-company support and the inability to make field repairs.

Continuous rod

COROD is the name used by Weatherford Inc. for the continuous solid rod. The advantage of this rod is its ability to pull the entire rod string in one piece with a special pulling unit. These rods are available in either round or elliptical configurations and vary in size from 12/16- to 18/16-in. diameter. 

A continuous strand of composite materials, called "ribbon rods," was developed and field tested. [4] This type of special rod contained carbon composite with a polymer wrap. Despite having high strength and a small cross-sectional area, it was expensive and ran into field support problems similar to those of flexible strands and CORODs.

"Electra" sucker rods

Another type of non-API sucker rod is the Electra (ELTM) rod. These currently are available only in 3/4-, 7/8-, and 1-in. diameters. They should be selected for wells in which operating stresses do not exceed 50,000 psi. These rods have a special heat treatment that should put the surface in a compressive set. Thus, they could be used in a hydrogen sulfide (H2S) environment in which the strength of Grade C rods is exceeded. These rods have been effectively used to produce approximately 150 BFPD from a depth of approximately 14,500 ft.

High-strength, low-alloy rods

A number of manufacturers have developed higher-strength steel rods to compete with other specialty rods. These rods take advantage of the newer alloys and heat-treating procedures currently available and are based on American Iron and Steel Inst. (AISI) 8630- or 4130-type steels, which have high tensile strengths. The tensile strength is generally greater than 140,000 psi, while the yield strength is generally greater than 100,000 psi; therefore, these rods could not be classified as API Grade D. The fine-grain heat treatment done on these alloys theoretically should provide increased fatigue life. However, this rod type may be more notch-sensitive and may require better handling and corrosion protection than normal API-type rods.

As with any specialty equipment, good field testing and records for several years in which good handling and operating practices were followed are required to prove the benefit for any of these non-API rods.

Criteria for rod-string design

Rod stress

In a noncorrosive environment, the endurance limit of steel is primarily determined by the maximum stress, the range of stresses, and the number of stress reversals. This is often illustrated by the use of a Goodman diagram, as discussed in API RP 11BR.[2] Derating, or service, factors also are discussed to allow potential decreasing of the load range for different service/corrosive environments. If the environment is corrosive and not properly treated, the sucker rods and their associated downhole equipment life is minimal. In such cases, corrosion-fatigue failures occur frequently in the rod string.

Effectively inhibited systems may be considered noncorrosive, which would limit the surface pitting of the steel rods or components. However, in the presence of H2S and a corrosive environment, steel may become susceptible to hydrogen embrittlement/sulfide-stress cracking. Steels that have a Rockwell C hardness greater than ≈ 23 (Brinell hardness number 237) are susceptible to embrittlement. The harder the steel is, the more susceptible it becomes. API Grade C sucker rods normally have a Rockwell C hardness < 23, while API Grade D sucker rods normally have a Rockwell C hardness > 23. Thus, API Grade D rods should be used with caution in the presence of hydrogen sulfide. Chemical inhibition may not prevent embrittlement. This results in a significantly decreased run life.

Stress raisers cause areas of concentrated stresses and may be caused by a number of things. Corrosion pits are one type of stress raiser. Stress raisers may be notches caused by improper handling, tool cuts, bending, and subsequent cold straightening, for example, and may also result from the manner in which the threads are formed on the rod pin (i.e., cutting vs. the now-required cold rolling). Corrosion pits may have rounded or notched shape; notch-shaped pits are more serious and are more likely to occur in Grade D rods than in Grade C rods.

API RP 11BR recommends using the modified Goodman diagram for determining the allowable stress on API steel-grade sucker rods, while API Spec. 11B[1] covers FRP rods. Manufacturers of non-API rods should specify the rod's allowable stress. An allowable load or stress curve should be developed to discern during the design of a rod string if it is overloaded, and adjustments should be made to prevent this. Recent discussions have promoted a hyperbolic relationship for allowable load using the Gerber parabola, rather than a straightline relationship.[5] This loading criterion, coupled with cleaner steels and better-quality sucker-rod manufacturing, should enable higher allowable loads to be applied to the rod strings, provided that good sucker-rod handling practices are followed. Rod strings that are considered "overloaded" by more than 20%, according to the straightline method, have been successfully run in the Permian Basin fields in the U.S.A. and provided adequate run time. Additionally, RP 11L,[3] discusses the need to reduce the allowable load or stress on used rods. Recommendations are presented for derating based on the class of the inspected rod, according to the inspection-criteria classes in API RP 11BR.

Rod-string selection

The primary factors affecting the selection and sizing of rods and the rod system are as follows:

  • Size of pump and tubing
  • Liquid viscosity and pourpoint
  • Kind of corrosion [e.g., H2S, carbon dioxide (CO2), or saltwater]
  • Conditions for unseating the downhole pump
  • Pump setting depth
  • Production rate
  • Sand, paraffin, salt crystals, scale, foam, and GLR

These factors should be considered when manual (according to API RP 11L[3]) or computer design calculations are performed to size the rod string and the related production equipment for a specific well.

Size designation

Sucker-rod strings may be composed of a single size or may be tapered, typically to include rods of two and three sizes. Using four or more sizes of rods in a taper is not normally recommended. The primary factor determining the proportion of each size of rod in the rod string is the size of the pump. However, typically only one grade of rod is used in the string to avoid mixing during running and pulling operations.

API RP 11L contains recommended rod-string design data. The first column of Table I in this reference contains the rod-string size designation. The first number in the column refers to the largest rod size in the string, while the second number refers to the smallest rod size in the string, both representing the size in eighths of an inch. An example rod number of 76 is a two-way taper of 7/8- and 6/8 -in. rods. Rod number 86 is a three-way taper of 8/8 -, 7/8-, and 6∕8 -in. rods. The taper percentages published in RP 11L were calculated from the Neely, [6] procedure by assuming several parameters like pumping speed, polished rod stroke length, etc. not given in the publication. The tables gained wide acceptance, and thousands of rod strings have been installed since then that used these recommended taper lengths. The use of the API taper lengths, of course, saves the time of a detailed string design, but the wide availability of personal computers today has eliminated the need to resort to such a shortcut method. The need for carrying out actual rod designs is further augmented by limitations of the published taper percentages; note that taper lengths are the sole function of plunger size which is oversimplification of the design. As presented by Gault & Takacs [7] and Gault [8] the API taper percentages do not vary with well depth, polished rod stroke length, or pumping speed. The differences lead to the conclusion that an accurate rod string design should be based on calculations using actual pumping conditions.

Pump unseating

Rod strings should be designed to enable the operator to unseat the pump without yielding any rod in the rod string. The diameter of the pump plunger determines the fluid load lifted during the pumping cycle. However, the ID of the seating nipple determines the fluid load that must be lifted to unseat the pump. Friction in the pump holddown plus sediments in the pump-tubing annulus increases the required pump-unseating force. However, a high tubing-casing-annulus fluid level decreases the load on the rod string when attempting to unseat a pump. Normally, the pulling-rig weight indicators are not accurate enough to use as the only tool to prohibit yielding the sucker rods. The rod string's stretch in Table 4.1, Column 4, of API RP 11L, gives elastic constants (Er) for sucker rods that can be used to indicate rod load.

The top rod in the bottom section normally has the highest stress in the string because it has the smallest cross-sectional area. This is because it has to support the weight of the rest of the small-diameter rod load, the pump and the very large fluid load on the gross seating nipple area. The weak point in the string is this rod. A free-body diagram can be used to determine the loads acting on this rod; an allowable unseating load or stretch can then be determined so that the rods are not yielded or damaged when trying to unseat the pump.

To taper or not to taper a rod string

Tapered rod strings that use different segments of different-sized rods are commonly used to save unnecessary weight and to distribute the loading on long strings of rods used in deep wells. The proper design will decrease the stress on the rods above the bottom section. This allows pumps to be run deeper than would be possible if just one size of rod was run. Tapered rod strings can be operated at a higher pumping speed (N) than straight rod strings. This may reduce the required pumping-unit gearbox size and increase rod stretch because stretch is proportional to rod-string weight. Thus, more production may be possible from the well with a tapered string than a straight string using the same-diameter pump.

Ideally, a rod string should be a continuous taper from top to bottom. This is impractical, not only because of the manufacturing difficulties involved, but also because the lower rods must have sufficient stiffness to support the entire string in the tubing if failures occur high up in the string. For this reason, 75 to 85 strings are not normally recommended because, if the rod string parts high in the well, close to the surface, the 5/8-in. rods may be permanently damaged when the upper rods fall on them. Coupled sucker rods come in diameter variations of 1/8 in. With the introduction of the continuous sucker rod, the opportunity for a greater number of tapers is possible because these rods may be manufactured in size variations of 1/16 in. or even smaller.

The primary factor in determining the proportion of each size of rod in the rod string is the size of the pump. Columns 6 through 11 in Table D.1 of API RP 11L contain the percentages of the various sizes to be placed in a tapered rod string with various pump sizes. Before 1977, percentages were calculated so that the unit stress on the top rod of each section from the weight of the rods in air plus the weight of the produced fluids on the gross plunger area is equal. This is calculated as a static load. Work done by API and Shell in 1977 resulted in the percentages shown in API RP 11L. This work used the dynamic effects on the rod's upstroke and downstroke, along with assumed pumping speeds for varying stroke lengths. Currently, most operators and rod manufacturers have proprietary rod-string design programs that include these data.

One of the earliest means used for designing tapered sucker-rod strings is in the Sucker Rod Handbook.[9] This design is based upon equal stress in the top of each size of rod, assuming a static condition and pumping water (specific gravity = 1.0) with the well pumped off. Buoyancy of the rod string is not taken into account. However, continued work suggested adopting a "modified-stress" approach in which the stress from the dynamic loads at the top of each size of rod is equalized.[6][8] Computer programs are available to perform the calculations on this complex process of assessing stress for various rod-string designs.

Rod couplings

API Spec. 11B[1] contains requirements for the rod couplings, as well as the rods, and recommends minimum tubing sizes. The current edition provides for two classes of couplings: Class T (through hardened coupling) has a Rockwell C hardness range of minimum 16 and maximum 23, and Class SM (surface hardened) has a minimum Rockwell C surface hardness of 50. This hardness is normally accomplished by the spray-metal process. Care should be taken when recommending the SM couplings, even though they have longer wear life than T couplings. Because of the increased hardness and lower coefficient of friction, if properly surface treated, coupling-on-tubing wear is transferred from the rods—which are easy and less expensive to replace—to the softer tubing, which is more expensive to replace. Thus, while the SM couplings help to increase rod-string life, the tubing life may be decreased. API Spec. 11B also standardizes "full-sized" coupling in both grades and a "slimhole" coupling in Class T. Tables 4.1 and 4.2 from API Spec. 11B shows recommendations for the minimum tubing sizes for the various couplings.

Slimhole couplings for 5/8- to 1-in. rods can be run and fished in one-size-smaller tubing than the respective full-sized coupling. This enables operators to run 1-in. rods in 2 7/8-in.-OD tubing and 7/8-in. rods in 2 3/8-in.-OD tubing. This coupling type, however, decreases the coupling area available for supporting the pumping loads. Thus, slimhole couplings are not as strong as the full size. Original work by Gipson and Swaim[10] recommended derating these couplings on the basis of the assumption that the 1-in. slimhole coupling has an acceptable minimum decreased area. Further work by Hermanson[11] using the area relationships and allowable strength of the different grades of steel rods resulted in different derating factors, which are included in API RP 11BR.[2] Note that the use of 7/8-in. slimhole couplings results in the highest derating factor for all rod strengths and sizes.

Sucker-rod maintenance

Well equipment, including sucker rods, must be in good working condition. The sucker-rod string is often highly stressed and usually fails because of the repeated load reversals. Corrosion, scale, and paraffin deposits may accelerate such failures. Tubing and rods will wear because of the reciprocating movement in the well caused by pounding fluid, buckling because of unanchored tubing, and/or bad wellbore deviation that allows contact.

Sucker-rod strings are lifting a great deal of weight every cycle. They are under stress on both the downstroke and the upstroke. Combining this with the normally corrosive environmental conditions of water, H2S, CO2, etc. may mean that one of the greatest expenses of a producing beam-pump system is replacing the sucker rods. Carrying out the various procedures described in this section can greatly reduce operating costs and make production more efficient and economical.

Care and handling of sucker rods

Proper running, handling, and makeup procedures should be followed to secure maximum service from a rod string. API RP 11BR contains the practices recommended by the industry.

Torque measurement has been discredited as a sucker-rod-connection makeup method. When the threads are properly lubricated, an estimated 10% of the applied torque turns the coupling relative to the pin, and 90% of the torque is consumed by friction. Any variation in lubricants or in the surface finish of the threads or mating surfaces drastically changes these percentages, indicating that torque could never be a precision makeup method for sucker rods.

API RP 11BR recommends circumferential displacement (CD) for making up sucker-rod joints, and it should also be used for calibrating power tongs. To make up a sucker-rod joint using CD, the pin and coupling threads should be cleaned and lubricated with a lubricant that has passed the NACE MR-01-74 screening test.[12] This test states that an acceptable lubricant will allow the lubricated pin to be made up hand tight, then fully made up and broken out 10 times without galling the threads. A hand-tight position is attained when full shoulder abutment is made and a 0.002-in.-thick feeler gauge cannot enter into this interface between the rod and coupling face. The coupling should then be turned by the amount specified in API RP11BR or by the rod manufacturer, relative to the pin. The manufacturer of specialty or non-API rods should be consulted for their recommended CD values and makeup procedures.

Rod-string equipment failure

The downhole production strings may fail for a variety of reasons, some of which have been discussed previously. Steward[13] and Moore[14] discuss reasons for common sucker-rod string failures and provide discussion and pictures of the failures. Additionally, Hermanson[11] provides discussion and photographs of different rod failures. The following is a summary of the normal rod-string equipment and typical reasons for failure:

  • Polished rods
    • Not in center of tee throughout pumping cycle
    • Smaller than recommended by API
    • Top of carrier bar not horizontal
    • Crooked—not vertical—wellhead
    • Crooked hole near surface, with pony rods below the polished rod
    • Corrosion
    • Abrasion
    • Excessive heat
    • No lubrication
    • Packing too tight
  • Pony rods (rod subs)
    • Old subs used with new rod string
    • Improper API-grade rod
    • Sub directly below polished rod
  • Rod couplings (boxes)
    • Slim-hole couplings used
    • Hammered-on boxes
    • Insufficient circumferential displacement
    • Dirty or improperly cleaned threads
    • Improper or no lubricant (should be a properly screened inhibitor, not tubing or drillpipe dope)
    • End face not perpendicular to the threads
    • Oxygen in system
    • Couplings made from free-machining steels
  • Rod pins
    • Old-style, nonundercut pins
    • Incorrect circumferential displacement
    • Box and pin not made up, but broken out and remade on new C and K rods
    • Box shoulder and pin shoulder not parallel
  • Rod upsets
    • Worn elevators
    • Rod bent while tailing out or in
    • Rods corkscrewed above the pump during normal pumping
    • Rods corkscrewed after parting
    • Vibrations
    • Manufacturer's marks
    • Running too fast in the hole
  • Rod body
    • Inadequate/ineffective corrosion inhibition
    • Hydrogen embrittlement
    • Overload
    • Nicks
    • Service time exceeds fatigue life
    • Rough surface
    • Yield strength exceeded while attempting to unseat pump
    • Defective material
    • Oxygen allowed in the pumping system
    • Bends
  • Valve rod (stationary barrel pump)
    • Pump not centralized in tubing
    • Improper material
    • Plunger too short and pump not centralized
    • Crooked hole at pump setting depth
    • Pounding fluid
  • Pull tube (traveling barrel pump)
    • Pump not centralized in tubing
    • Pull tube buckling on downstroke
    • Improper material
    • Pump set too deep for pull-tube length
    • Pounding fluid

String replacement

Replacing a rod string one rod at a time is not normally a good operating practice; thus, the economic life of a rod string needs to be considered if rods start to fail. Typically, the rod-string section will be replaced after two or three failures, while the entire rod string may be replaced after three or four failures. However, the reasons for failures need to be investigated and the root cause for this failure must be determined to extend the rod life in the future.

An SPE paper by Powers[15] considers the factors that enter into the decision about when to replace the entire rod string after sustaining the calculated number of failures. Usually, wells of the same type in a field can be grouped together and the necessary calculations do not have to be performed for each well. Sufficient calculations need to be done to assess the economic impact for all wells in a field.

Designing sucker-rod strings

There has been a long history of work trying to model or design sucker-rod strings. This includes the original work from Slonneger[16] and Mills[17] on vibration effects of rod strings. Fatigue of rods also was considered in 1940. [18] These effects helped develop the Slonneger, Mills, [19] and Langer[20] formulas for rod loads. A detailed discussion and development of these formulas is provided by Zaba. [21]

Zaba[22] detailed the next refinement of sucker-rod loading, which was the organization of the Sucker Rod Pumping Research Inc. in 1954, and the development of an analog computer model to simulate the elastic behavior of rod strings. This method was provided to the industry in the 1960s, and the design results were developed into the hand-calculation and graphical method in API RP 11L. [3]

Companies used this graphical chart and calculation method for many years, with some refinements and changes to the practice, to account for tapered-rod strings and rod percentages, that provide equal loading in each section of a string. The development of the wave equation for sucker-rod lift by S.G. Gibbs[23] in 1961 was a major step forward because its use permitted design or analysis for all types of units and rod strings. The advent of the personal computer and its continued developments of power and speed allowed more developments of rod-string simulators, including:[23][24][25][26][27][28][29][30][31][32][33][34][35][36][37][38][39][40][41][42]

  • Extending the API simulator using a next-order wave equation
  • Pumping units different than conventional ones
  • Mixed-steel and fiberglass-rod strings
  • Frictional effects of the fluid and wellbore deviation
  • Current models that address very viscous fluids and 3D horizontal wells

Regardless of what method or program is used to predict loads, once the equipment is installed and the well has stable production and fluid levels, it is recommended that a dynamometer survey be run with a load-capable dynamometer attached to the polished rod. The predicted loads should be compared to the actual loads and the associated fluid production. Adjustments to the predictions should be made for future troubleshooting and any further design changes.

Sucker rod string predictable control

Although sucker rod string designs provide predictive insight to sucker rod string dynamics in well, it is far understood and known that these programs may not accurate depict rod string dynamics in deviated and horizontal rod-pumped wells. Mathematical advancements have been made to extend beyond single-wave equations and move toward 3D predictive sucker rod string design (

Further, mechanical and physical products now allows complete sucker rod control and the elimination of bending moments and buckling in rod lift applications. By constant co-axial alignment of the rod to the tubing and reinforcement of the sucker rod beyond the critical buckling load achievable (weight of the sucker rod string above the rod in question), rod string designs can be completely guided, controlled, and accommodate compressive moments and tendencies, disallowing the sucker rod to buckle which leads to pre-mature failure (

These two solutions for unconventional pumping are leading to a new era of sucker rod lift and control.


LPSD = seating nipple/pump depth, ft
N = pumping-unit speed, spm
S = surface stroke length, in.


  1. 1.0 1.1 1.2 API Spec. 11B, Specification for Sucker Rods, 26th edition. 1998. Washington, DC: API.
  2. 2.0 2.1 2.2 API RP 11BR, Recommended Practice for Care and Handling of Sucker Rods, eighth edition, Supplement 1. Washington, DC: ANSI/API.
  3. 3.0 3.1 3.2 3.3 API RP 11L, Recommended Practice for Design Calculations for Sucker Rod Pumping Systems, fourth edition, Errata 1. Washington, DC: API, Washington DC.
  4. Hensley, H.N. et al. 1994. Ribbon Rod Development for Beam Pumping Applications. Paper 05 presented at the 1994 Southwestern Petroleum Short Course, Lubbock, Texas, 20–21 April.
  5. Hein Jr., N.W. and Hermanson, D.E. 1993. A New Look at Sucker Rod Fatigue Life. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1993. SPE-26558-MS.
  6. 6.0 6.1 Neely, A.B. 1976. Sucker Rod String Design. Petroleum Engineer (March): 58.
  7. Gault, R.H. and Takacs, G. (1990) Improved Rod String Taper Design. Paper SPE 20676 presented at the 65th Annual Technical Conference and Exhibition of SPE, New Orleans, 605-14
  8. 8.0 8.1 Gault, R.H. 1990. Rod Stresses from RP11L Calculations. Paper 25 presented at the 1990 Southwestern Petroleum Short Course, Lubbock, Texas, 18–19 April.
  9. Sucker Rod Handbook. 1953. Bethlehem, Pennsylvania: Bethlehem Steel Co.
  10. Gipson, F.W. and Swaim, H.W. 1988. The Beam Pumping Design Chain. Presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 23–25 April.
  11. 11.0 11.1 Hermanson, D.E. 1987. Sucker Rods. In Petroleum Engineering Handbook, ed. H.B. Bradley, Ch. 9. Richardson, Texas: SPE.
  12. NACE MR 01–74, Recommendations for Selecting Inhibitors for Use as Sucker Rod Thread Lubricants. 2001. Houston, Texas: NACE.
  13. Steward, W.B. 1984. Sucker Rod Failures. Oil & Gas J (4 April).
  14. Moore, K.H. 1981. Stop Sucker Rod Failures to Save Money. Petroleum Engineer International (July).
  15. Powers, M.L. 1971. Optimization of Sucker Rod Replacement. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, New Orleans, Louisiana, 3-6 October 1971. SPE-3470-MS.
  16. Slonneger, J.C. 1937. Vibration Problems in Oil Wells. Drilling and Production Practices, 179. Washington, DC: API.
  17. Mills, K.N. 1940. Effects of Rod Vibration on Dynamometer Cards. Oil Weekly (June): 23.
  18. Dale, D.H. and Johnson, D.O. 1940. Laboratory and Field Endurance Values of Sucker Rod Materials. Drilling and Production Practices Dallas, Texas: API.
  19. Mills, K.N. 1939. Factors Influencing Well Loads Combined in a New Formula. Petroleum Engineering J. (April): 37.
  20. Langer, B.F. and Ianbergg, E.H. 1942. Calculation of Load and Stroke in Oil Well Pumping Rods. Oil & Gas J (2 June): 27-32.
  21. Zaba, J. 1943. Oil Well Pumping Methods: A Reference Manual for Production Men. Oil and Gas J (July).
  22. Zaba, J. 1962. Modern Oil Well Pumping. Tulsa, Oklahoma: Petroleum Publishing Co.
  23. 23.0 23.1 Gibbs, S.G. 1963. Predicting the Behavior of Sucker-Rod Pumping Systems. J Pet Technol 15 (7): 769-778. SPE-588-PA.
  24. Nolen, K.B. 1969. Deep High Volume Rod Pumping. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, Denver, Colorado, 28 September-1 October. SPE-2633-MS.
  25. Gibbs, S.G. 1977. A General Method for Predicting Rod Pumping System Performance. Presented at the SPE Annual Fall Technical Conference and Exhibition, Denver, Colorado, 9-12 October 1977. SPE-6850-MS.
  26. Gibbs, S.G. 1982. A Review of Methods for Design and Analysis of Rod Pumping Installations. J Pet Technol 34 (12): 2931-2940. SPE-9980-PA.
  27. Doty, D.R. and Schmidt, Z. 1983. An Improved Model for Sucker Rod Pumping. Society of Petroleum Engineers Journal 23 (1): 33-41. SPE-10249-PA.
  28. Clegg, J.D. 1986. Rod Pump Design Using Personal Computers. Paper 021 presented at the 1986 Southwestern Petroleum Short Course, Lubbock, Texas, 23–24 April.
  29. Clegg, J.D. 1988. Improved Sucker Rod Pumping Design Calculations. Paper 019 presented at the 1988 Southwestern Petroleum Short Course, Lubbock, Texas, 20–21 April.
  30. Schmidt, Z. and Doty, D.R. 1989. System Analysis for Sucker-Rod Pumping. SPE Prod Eng 4 (2): 125-130. SPE-15426-PA.
  31. Brunings, C.A. and Castillo, V. 1989. BOMEC: A New Artificial-Lift Design Method for Producing Heavy Crudes. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-11 October 1989. SPE-19716-MS.
  32. Lekia, S.D.L. and Evans, R.D. 1995. A Coupled Rod and Fluid Dynamic Model for Predicting the Behavior of Sucker-Rod Pumping Systems - Part 1: Model Theory and Solution Methodology. SPE Prod & Oper 10 (1): 26-33. SPE-21664-PA.
  33. Lekia, S.D. and Evans, R.D. 1995. A Coupled Rod and Fluid Dynamic Model for Predicting the Behavior of Sucker-Rod Pumping Systems - Part 2: Parametric Study and Demonstration of Model Capabilities. SPE Prod & Oper 10 (1): 34-40. SPE-30169-PA.
  34. Lukasiewicz, S.A. 1991. Dynamic Behavior of the Sucker Rod String in the Inclined Well. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 7-9 April 1991. SPE-21665-MS.
  35. Gibbs, S.G. 1992. Design and Diagnosis of Deviated Rod-Pumped Wells. J Pet Technol 44 (7): 774-781. SPE-22787-PA.
  36. Cortines, J.M. and Hollabaugh, G.S. 1992. Sucker-Rod Lift in Horizontal Wells in Pearsall Field, Texas. Presented at the SPE Annual Technical Conference and Exhibition, Washington, D.C., 4-7 October 1992. SPE-24764-MS.
  37. Laine, R.E. 1993. Conceptual Sucker-Rod Design: An Unsolved Problem. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 21-23 March 1993. SPE-25419-MS.
  38. Xu, J. 1994. A New Approach to the Analysis of Deviated Rod-Pumped Wells. Presented at the International Petroleum Conference and Exhibition of Mexico, Veracruz, Mexico, 10-13 October 1994. SPE-28697-MS.
  39. Jennings, J.W. 1994. QRod, A Practical Beam Pumping Design Program. Paper 006 presented at the 1994 SPE Southwestern Petroleum Short Course, Lubbock, Texas, 20–21 April.
  40. Gibbs, S.G. 1994. Assumptions of the API Rod Pumping Design Method as Related to Practical Applications and Wave Equation Techniques. Presented at the University of Tulsa Centennial Petroleum Engineering Symposium, Tulsa, Oklahoma, 29-31 August 1994. SPE-27988-MS.
  41. Cullen, R.P. and Mansure, A.J. 1999. Fluid Dynamics in Sucker Rod Pumps. Paper 003 presented at the 1999 Southwestern Petroleum Short Course, Lubbock, Texas, 21–22 April.
  42. Xu, J., Doty, D.R., Blais, R. et al. 1999. A Comprehensive Rod-Pumping Model and Its Applications to Vertical and Deviated Wells. Presented at the SPE Mid-Continent Operations Symposium, Oklahoma City, Oklahoma, 28-31 March 1999. SPE-52215-MS.

Noteworthy papers in OnePetro

Takacs, G., & Gajda, M. 2017. An Enhanced Model for the Design of Tapered Sucker-Rod Strings. SPE Production and Operations Vol. 32 Issue 1, p1-6. Society of Petroleum Engineers.

Other noteworthy papers

Moore, K. (1973, April 9). Learn to Identify and Remedy Sucker-Rod Failures. OGJ, pp. 73-76.

Moore, K. (1981, July). Stop Sucker Rod Failures to Save Money. PEI, pp. 27-42.

Steward, W. (1973, April 9). Sucker Rod Failures. OGJ, pp. 54-68.

Takacs, G., & Gajda, M. (2013). Critical Evaluation of Sucker Rod String Design Procedures. Proc. 60th Annual Southwestern Peroleum Short Course, (pp. 213-222).

West, P. (1973). Improved Method of Sucker Rod String Design. Proc. 20th Southwestern Petroleum Short Course, (pp. 157-163).

West, P. (1973, July). Improving Sucker Rod String Design. PE, pp. 68-77.

Noteworthy books

API Bull. 11L3, Sucker Rod Pumping System Design Book, first edition. 1970. Washington, DC: API.

Takács G.: Sucker-rod pumping manual. ISBN 0-87814-899-2 PennWell Books, Tulsa Oklahoma, 2003, 395p.

Takács G.: Sucker-rod pumping handbook. ISBN 978-0-12-417204-3. Gulf Professional Publishing, An Imprint of Elsevier. 2015, 585p.

External links

See also

Sucker-rod lift

Downhole sucker-rod pumps

Subsurface equipment for sucker-rod lift


Page champions

John G. Svinos

Gabor Takacs