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Subsurface equipment for sucker-rod lift

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While downhole pumps and sucker rods are the chief components of a sucker-rod lift type artificial lift system, a number of other components are also used in the subsurface portion of the system. These include tubing, tubing anchor-catchers, tubing rotators, sinker bars, rod centralizers, and paraffin scrapers. This page discusses each of these components.


Tubing provides detailed information on the design, selection, and use of tubing for production wells. As related to most sucker-rod-lifted wells, the standard weight of external-upset-end, API tubing[1] should be used because of the increased wall thickness in the threaded ends. Thus, if there is rod coupling-on-tubing wear, more life and fewer leaks will be realized than if nonupset API tubing is used. Using API Grade J55 tubing, consider full-body normalizing after upsetting to prevent "ringworm corrosion" in the heat-affected upset region when the tubing is placed in corrosive (H2S or CO2) service. If the production application is noncorrosive, then this extra heat treatment may not be required.

Tables 4.1 and 4.2 from API Spec. 11B[2] include minimum tubing size for each size of full-sized and slimhole rod couplings. There should be sufficient clearance between the tubing and the rod box for fishing tools.

The yield strength of the tubing must be sufficient to support the weight of the tubing in air, the weight of the rods and of the fluid in the tubing, plus an overpull allowance that will allow the tubing to be pulled. Normally, API Grade J55 is acceptable for most rod-pumped wells to a depth of approximately 9,500 ft. However, with greater well depths and higher production rates, API Grade N80 or L80 (if H2S is present) and, in some cases, P110 should be considered.

It is recommended that API tubulars be drifted to ensure equipment can be run without problems.

Thread dope must be used on API tubing threads to keep the joints from leaking, but it does not have an infinite life. If collar- or tubing-connection leaks begin to appear in tubing strings, it may be necessary to remove all collars (if applicable), clean the threads on the tubing and the collar or upset connection, and apply new thread dope. Additionally, tubing that has been in storage should at least be visually inspected, and the threads cleaned and freshly doped, following API recommendations, before running.

Most wells will be able to use normal torque makeup requirements for tubing. A guideline for appropriate makeup of oil-country tubular goods is found in API RP 5 C1. [3] This Recommended Practice also includes care and handling along with running casing and tubing information.

Hydraulic testing of tubulars in the well will determine only whether, under that circumstance, the tubing and couplings are leak free. Once the well is put back on pump, rod-on-tubing wear may reduce the wall thickness, causing a split. Additionally, hydrotesting itself may provide sufficient pressure to fail a worn tubular that may have had acceptable pressure retention to handle the pumping pressures. Thus, if tubing wear is a problem, downhole tubing-caliper surveys or surface tubular inspection should be done to separate unacceptably worn tubing before it leaks. Fig. 1 presents an example of a downhole tubing-caliper survey. [4] It should be noted that the major wear is approximately midway between rod couplings because of rod buckling from pounding fluid. The chart also shows that there was wear caused by the couplings themselves contacting and wearing the tubing. Sucker rod buckling, and the direction of deflection of the sucker rod, is unpredictable. In 2020, advancements were made related to rod string protection devices and providing predictable sucker rod control and behaviors. Black Mamba Rod Lift has patented a stabilization tool and rod guide which is proven to provide rod control.

New developments have been made in using internally plastic-lined tubing in rod-pumped wells. Such tubing has been beneficial in preventing erosion at the pump discharge and/or wear along the inside of the tubing. [5] One west Texas operator dramatically reduced the field failure frequency from 0.42 to less than 0.25 in the Howard Glasscock field[6][7] by running full and partial strings and, in many cases, just a few joints of this poly-lined tubing on the bottom of the tubing string. Monitoring of these lined tubing joints should continue to ensure that the liner does not wear or degrade with time.

The failure frequency is a dimensionless number found by dividing the total downhole well failures by the total number of producing wells in a field. This failure frequency can be further described by dividing the number of sucker-rod, tubing, or pump failures in a year by the total number of sucker-rod-lifted wells to determine which equipment is causing the most failures in the field. Similar calculations can be done for other lift methods that are used in the field.

Tubing-anchor catchers (TACs)

Tubing anchors are used to prevent movement of the tubing during the pumping cycle. Fig. 2 shows an example of the recommended mechanical-type TAC for rod-pumped wells. During pump operation, part of the fluid load is transferred from the tubing to the sucker rods, alternately. This causes the tubing to elongate on the downstroke when it supports the fluid load and to shorten when the rods carry the fluid load on the upstroke. This action shortens the effective plunger stroke and decreases the pump displacement. This load transfer also causes helical buckling in the bottom portion of the tubing string, which, in turn, causes additional rod-on-tubing wear. The recommended TAC has two-way slips; these prevent parted tubing from falling in addition to preventing movement during the pumping cycle.

Tubing anchors are normally placed within 30 to 100 ft above the pump’s seating nipple. The tubing is set in the surface hanger with tension equal to the sum of the tensions required to overcome the stretch, because of:

  • Load transfer
  • Helical buckling
  • The anticipated temperature change between producing the shut-in conditions
  • The change in fluid level

A calculation procedure from the manufacturer should be followed to properly set the TAC “total stretch,” rather than pounds of pull from the rig. Further consideration should be given for adequate settings, if the downhole pump diameter exceeds the tubing diameter, as in the case of oversized tubing pumps (sometimes called casing pumps). When this occurs, the normal applied stretch or load for the tubing has shown to be inadequate, requiring increased stretch-setting inches.

This equipment can be difficult to remove; care should be taken using a TAC in wells having scale, heavy paraffin, sand production, and/or bad casing. The TAC release method should be considered before this equipment is installed.

Several of the tubing anchors available have shear pins to release the slips if the normal releasing mechanism fails. Varying the material type and number of shear pins can vary the amount of necessary pull; this is called the “shear-out value.” The tubing must have sufficient yield strength to support the weight of the tubing in air, the weight of the rods, and the weight of the fluid in the tubing as well as to shear the pins left in the tubing anchor. These factors will limit the pumping depth to which a TAC can be used. However, the running depth can be increased with stronger tubing and/or tapered tubing strings and with the required minimum strength and number of shear pins. Care should be used to ensure that the design shear out or production loads do not exceed the tubing-grade yield strength. If this possibility exists, the tubing should be cut rather than pulled apart.

Tubing rotators

Tubing rotators may be used to spread tubing wear because of rods and/or rod couplings around the entire diameter instead of being concentrated in one spot. They may be used in conjunction with rod rotators to even out the wear on both the tubing and rod coupling.

Tubing rotators come in more than one size. The manufacturer should be consulted when selecting these items to ensure the rotators purchased are sufficiently strong for the particular job. In most cases, the use of a TAC, coupled with rod centralizer and possibly a rod rotator, will prevent sufficient wear such that a tubing rotator is not required.

Sinker bars

A sinker (or heavy-weight) bar is normally a special steel bar or large-diameter sucker rod placed directly above the downhole pump. Such bars may be used polished rods or a rod specifically standardized by API Spec. 11B.

During the pumping cycle, these bars help to open the traveling valve because a portion of the pressure required to open the valve on the downstroke must be obtained from the weight of the sucker-rod string pushing down on the top of the plunger. This places the lower portion of the rod string in reduced tension. Rod buckling will result unless properly sized and centralized sinker bars are used immediately above the pump to provide the additional needed weight. Sinker rods (guided heavy sucker rods) are available for use in adding tension to the string design and are another avenue to evaluate for rod string control. Sucker-rod buckling will cause excessive rod- and/or coupling-on-tubing wear above the pump. The buckling at the bottom of the rod string also may cause premature valve-rod or pull-tube failures. Specific rod-string protection devices exist for the control of sucker rod, eliminating the possibility of sucker rod buckling by constant control and reinforcement of the sucker rod.

Advantages of using sinker bars in a sucker-rod string:

  • Keeps tension on the sucker-rod string
  • Increases the minimum polished-rod load
  • Decreases polished-rod horsepower (HP)
  • Decreases low tubing leaks
  • Decreases valve-rod or pull-tube pump failures if caused by buckling or bending
  • Increased production
  • Overall decrease in operating costs

Disadvantages of using sinker bars:

  • Creates added mechanical problems when the production equipment is allowed to pound fluid more than one-quarter of the way down on the downstroke
  • Increases operating expense if purpose-manufactured rods are purchased
  • Inadequate coupling makeup and pounding fluid can cause the connection to unscrew, if polished rods are used

The theoretical sinker-bar weight required in a rod string depends on the specific gravity of the produced fluids, the size and type of downhole pump, the associated valve-seat contact area, and the depth of the well. There are differing thoughts on the minimum amount of sinker bars required. Some operating companies and sinker-bar manufacturers use a weight equal to the buoyant weight of the rod string in the produced fluid. Others use only 20% of the well depth or no sinker bars—only a few sucker-rod centralizers or guides near the bottom. Some operating companies use a sinker-bar factor (SBF) for the various types of pumps. Gipson and Swaim developed the SBF for stationary barrel pumps in the "Beam Pumping Fundamentals" (April 1969) and published them in Gipson and Swaim [8] . Traveling-barrel pumps normally have a traveling valve one size larger than stationary barrel pumps; thus, these SBFs need to be increased.

The SBF process is to determine the theoretical weight of sinker bars in the produced fluids. Then, 20% of this theoretical weight is the recommended starting point for the actual weight or length of sinker bars used to replace the lowest rods in a rod string. This was recommended because sinker bars act dynamically to help valve action and to help keep the rods in tension. Once sinker bars are run, an optimization to increase the number of bars or weight can be conducted. However, there is a minimum point of benefit at which adding more sinker bars will not provide the useful dynamic effects. When this occurs, the extra bars or weight will be detrimental to rod-string loading.

An SBF summary for the theoretical weight for the various-diameter stationary and traveling barrel pumps is presented in Table 1.

With these values, the recommended starting sinker-bar weight is as follows:


The resulting sinker-bar weight to install is as follows:


where LPSD = seating nipple depth, ft, and G = specific gravity of the combined fluid in the tubing. [8]

Rod centralizers

[See also PetroWiki's Rod Guides page]

Sucker-rod centralizers also may be called paraffin scrapers or rod guides. They keep the rods and couplings away from the tubing to decrease wear. However, special mechanical paraffin scrapers have been developed to also aid in keeping paraffin off the tubing and most of the sucker-rod length.

Rod centralizers with full-bore-fluted centralizers should be placed on or between the pump-handling pony rod, the sinker bars used above the pump, and the first two sucker rods above the sinker bars. Rod centralizers in these locations help stabilize the pump and valve rod and prevent valve-rod bending or breakage. When a tubing anchor is not used, rod centralizers will reduce tubing wear because of tubing helical buckling on the upstroke. Rod centralizers also may be used in crooked holes in which there are areas of concentrated tubing wear.

Sucker-rod-guide placement

When setting rod guides, it is necessary to determine the correct spacing when the tubing anchor is set several hundred feet above the seating nipple or when a tubing anchor-catcher (TAC) is not run. It is recommended as a starting point to use the Lubinski curve to determine guide spacing; Fig. 1 provides the minimum guide-spacing curves for 2- and 2½-in. tubing.

The formulas for determining the distance that unanchored tubing will buckle above the seating nipple are as follows:

  • RTENOTITLE....................(3)
  • RTENOTITLE....................(4)
  • RTENOTITLE....................(5)

where Fo = 0.34 × G × D2 × H, which is the fluid load on the gross plunger area, G = specific gravity of the mixed fluid in the tubing string, D = pump-plunger diameter, and H = pump-seating depth in ft.


As an example problem, solve the following:

Given: tubing = 2 7/8-in. OD API, D = 1.50 in. (pump plunger diameter), L = H = 8,000 ft (pump-seating-nipple depth and assumed pumped-off fluid level), and G = 1.03 (specific gravity of the liquid in the tubing). A TAC is to be set at 7,450 ft, which is 15 ft above the top casing perforation.

Find: (a) the buckling distance and (b) the recommended spacing for sucker-rod guides.


  1. Buckling distance = Fo / 5.7 = [0.34 × 1.03 × (1.5) × 8,000] / 5.7 = 6,304 / 5.7 = 1,106 ft.
  2. Fig. 1 indicates that when the neutral point is 1,106 ft above the seating nipple, the first guides should be approximately 15 ft apart, or approximately two guides are recommended per 25-ft-long sucker rod in 2 7/8-in. OD.

In summary, there will be 8,000 – 7,450 = 550 ft from the seating nipple to the anchor. The anchor will be 1,106 – 550 = 556 ft below the neutral point. Fig. 1 indicates that guides should not be less than 25 ft apart until approximately 380 ft below the neutral point; therefore, it is recommended that two guides be placed on each 25-ft-long sucker rod, between the seating nipple at 8,000 ft and the TAC at 7,450 ft. This is the minimum number of guides per rod.

If continued rod and/or coupling-on-tubing wear is a problem, more centralizers should be considered. Wellbore deviation is one of the biggest problems for sucker-rod-lifted wells. If the deviation is 0 to 3°/100 ft, there should be no pumping problem. A deviation of 3 to 5°/100 ft is a bearable problem, and it usually can be handled by properly locating the rod guides. A deviation greater than 5°/100 ft is a definite problem. An increased number of guides per rod, tubing anchors, and/or special roller rod guides may be necessary within the local deviation region.

Sucker rod helical stabilizers

Recent advancements in manufacturing and product design have introduced real solutions related to sucker rod buckling. These patented products (namely, The Black Mamba) allow complete sucker rod control and complete elimination of bending moments and buckling in the rod string by occupying the free space around the sucker rod from end-to-end. In lieu of sucker rod guides, helical stabilizers can provide complete, predictable behavior in rod string dynamics for no additional costs to operators. Further, the designs inherent nature provides paraffin movement, centralization, and prevention of steel-on-steel rod-on-tubing wear.

Rod-centralizer types and materials

There are two main types of sucker-rod centralizers:

  • Field installable
  • Molded on

The field-installable guides can be hammered on, twisted on, or (with two pieces) slid together on the rod. Usually, these field-installable guides do not grip the rod area very well. Often, they do not stay where they are required. However, guide manufacturers continue to develop these field installable guides to increase their holding power. A word of caution is necessary, especially with the field-installable guides, to make sure the rods are slowly run in or out of the well to decide if a wellhead running guide is necessary.

Molded-on rod guides are the recommended type, especially for new sucker rods, if continued rod coupling/tubing wear is a problem. This type of guide is also recommended if the well is allowed to pound fluid or if the well-servicing contractor is not properly trained to run rods with field-installable guides.

There are varieties of materials that can be used for rod centralizers, including steel paraffin scrapers. Modern product manufacturing for centralizers typically is limited to polymers / plastics.


  • Nylons (not manufacturer advised for immersion service applications, ie: down-hole)
  • PPA (polyphathalmide, not manufacturer advised for immersion service applications, ie: down-hole)
  • PPS (polyphenylene sulfide)
  • PAEK
  • PEEK
  • Combinations of the above.


  • Rubbers (EPDM, Viton, Nitrile, Buna)
  • Glass and Mineral Reinforced Phenolic (RFG Petro Systems' Martin Polymer, name changed to MP Polymer in 2018)
  • Proprietary in-house developed resin systems (Black Mamba Rod Lift,

Guide manufacturers continue to develop new guide materials and designs that will provide:

  • The needed centralizing capabilities
  • Buckling inhibition
  • Rod-gripping strength
  • Long wear life (material science improvements)
  • Ability to function in increasingly hostile down-hole environments (wear, friction, chemical, immersion)

All these materials have chemical compatibility, temperature, and applied-stress limitations. The manufacturer should be consulted for their recommended service limitations.

Paraffin scrapers

Mechanical scrapers fastened to the rod string through the zone of paraffin deposition (normally near the surface) have been used to keep the tubing and most of the rod bodies free of paraffin. Paraffin-scraper systems have proved to be effective in reducing, if not eliminating, hot-oiling or watering treatments in both Canada and in the US. Additionally, a Canadian operator has shown that, along with the mechanical scraper system, internal plastic tubing coating has been beneficial in preventing paraffin buildup.[9] However, it is recommended that paraffin scrapers be used only when necessary.


G = specific gravity of the mixed fluid in the tubing string
D = pump-plunger diameter
H = pump-seating depth in ft.
Fo = 0.34 × G × D2 × H, which is the fluid load on the gross plunger area


  1. API Spec. 5CT, Specification for Casing and Tubing, sixth edition. 1998. Washington, DC: API.
  2. API Spec. 11B, Specification for Sucker Rods, 26th edition. 1998. Washington, DC: API.
  3. API RP 5C1, Recommended Practice for Care and Use of Casing and Tubing, 18th edition. 1999. Washington, DC: API.
  4. Lincicone, E.A. 1980. Reduced Tubing Failures in Rod Pumped Wells Utilizing Downhole Caliper Surveys. Petroleum Engineer Intl. 34.
  5. Sirgo, E.C., Gibson, E.D., and Jackson, W.E. 1998. Polyethylene Lined Tubing in Rod Pumped Wells. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 23-26 March 1998. SPE-39815-MS.
  6. Hickman, J. 2003. Polylined Tubing Reduces Downhole Failures. World Oil (January): 51.
  7. Bowerman, J. et al. 2006. Seven+ Years Review of Poly-lined Production Tubing in the Howard Glasscock Field. Paper presented at the 2006 Southwestern Petroleum Short Course, Lubbock, Texas, 20–26 April.
  8. 8.0 8.1 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.
  9. Hanson, D.G. 1983. Pembina Cardium Beam Pumping Equipment - Case Histories. Presented at the Annual Technical Meeting, Banff, May 10 - 13, 1983 1983. PETSOC-83-34-42.

Noteworthy papers in OnePetro

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External links

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See also

Sucker-rod lift

Downhole sucker-rod pumps

Sucker rods


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John G. Svinos