Understanding the basic aspects of TACs and their application, operational procedures and tubing stretch is necessary for efficient artificial lift.
by Jyothi Swaroop Samayamantula, Don-Nan Pump & Supply
October 10, 2013

From the selection process to installation and continued maintenance, a tubing anchor catcher (TAC) is one of the most important tools for achieving efficient pumping operation. The upstream oil and gas sector continues to evolve with new methods morphed from old methods as it pertains to artificial lift systems. Since the people and parts continue to change for oil companies, understanding the basic, yet important, aspects of TACs and their application, operational procedures and tubing stretch is necessary. In covering this tool’s basics and importance, the scope of this article will expand on tubing stretch, shear values, drag spring usage, troubleshooting and other installation techniques.

What Is a TAC?

A TAC is a device used to anchor tubing string to the casing at a desired depth. It pulls and maintains tension in the tubing string during pumping while simultaneously catching and preventing any parted pipe from falling into the well. It is used in most rod pumping applications in which maintaining tubing tension is necessary.

When set with proper tension to overcome breathing and buckling, the TAC effectively cuts operating costs incurred from excessive rod, tubing and casing wear, which results in fewer pulling jobs. The elimination of breathing and buckling increases production by lengthening the effective stroke of the pump, thereby increasing volumetric efficiency.

Why Use a TAC?

The alternative to TAC use would be allowing the tubing to hang free. This leads to a few problems, such as:

  • Excessive wear of the rods, tubing, casing and pump
  • Reduced pumping efficiency
  • Increased operating costs—for example, increased requirements of power consumption
  • Tubing buckling because of piston effects such as breathing (also referred to as plugging), buoyancy and ballooning effects

The movement of the bottom portion of the freely suspended tubing string along with the plunger as the pump strokes is referred to as breathing. This movement is caused by alternately transferring the load of the fluid column from the rod string to the tubing string. On the down stroke, the tubing carries the fluid load, and on the up stroke, the rods carry the fluid load. During the down stroke, the tubing elongates and the rods shorten. During the up stroke, the rods elongate and the tubing shortens. The elongation and contraction of the tubing string along with the rod string reduces the effective pump stroke and, as a result, reduces the production. This also creates tubing buckling, which results in tubing and casing wear; tubing collar leaks; and metal fatigue, causing the tubing to part. Buoyancy and ballooning effects cause the tubing string to change length.

In practice, tubing undergoes bending or buckling, which is characterized by a sudden failure of a tubing member subjected to high compressive stress in which the actual compressive stress at the point of failure is less than the ultimate compressive stress that the tubing material is able to withstand. Because the tubing string is set free from tension, nothing restrains the buckling forces. The rods remain straight, supporting the fluid load. The tubing string bends and coils helically (see Figure 1), rubbing against both the rods and casing. The rods are forced out of alignment while the pump barrel wear is accelerated. In this case, the rods, tubing, casing and pump are subjected to extreme wear. This also causes the pump to consume more lifting power to overcome the added friction.

Helical bending of the tubing stringFigure 1. Helical bending of the tubing string

Some of the means by which the tubing buckling can be handled are tension anchors, tail pipe, sucker rod guides and corrosion inhibitors. To keep the tubing string from buckling, the structural member/tubing string should be subjected to tension. Using a TAC to anchor the tubing string at the bottom permits the tubing to stretch beyond the point that it would be stretched by the fluid load and temperature variations. The TAC at the bottom of the tubing string will help hold the tubing string straight and keep its length from changing during the pump stroke.

Installation and Operation

Many factors—wellhead type, proper installation, running and setting, and normal and emergency releasing—must be considered when using a TAC.

Selection of Wellhead

The type of wellhead is an important factor in obtaining proper stretch in the tubing string. Determining the type of wellhead to be used before installing the TAC is important. Screw type (see Image 1) and slip type (see Image 2) are two commonly used wellhead devices. Both have advantages and disadvantages.

A screw type wellheadImage 1. A screw type wellhead
A slip type wellheadImage 2. A slip type wellhead

In a slip type wellhead, the tubing is stretched and allows the tapered slips to catch the tubing string. The teeth on the slips provide the necessary friction to keep the tubing string stretched. To have proper friction between the slips and the tubing, the tubing must be straight. Only a part of the slips will be in contact with the tubing string if it is crooked. This will cause the tube to stress and result in a tubing failure at the point of contact.

When a screw type wellhead is used, the tubing is screwed into the bottom of the flange. To use a screw type wellhead, the tubing must be overstretched 18 inches (457 millimeters) or more to install the pulling unit slips under the top tubing collar. The installation of a screw type wellhead might introduce some slack in the tubing string if the tubing is not overstretched. At the same time, use of a higher shear value to overstretch the tubing could be detrimental to the low-strength tubing.


In the tubing string, the TAC should be positioned immediately below the pump. The seating nipple should be screwed into the top sub of the anchor. If the pump must be located below the TAC, special consideration must be given to the bore through the anchor and the tensile strength of the anchor mandrel. For the pump to be installed below the TAC, the pump has to go through the mandrel’s internal diameter (ID). In this case, the ID of the mandrel should be equal to or more than the ID of the tubing for that pump. When the TAC is installed below the seating nipple, the fluid load acts on the seating nipple. If the TAC is anchored above the seating nipple, the TAC mandrel is subjected to the fluid load.

Figure 2 shows the assembly of a TAC. It shows the position of the drag springs, which create friction between the anchor and the casing ID. This will hold the TAC cage stationary while allowing the upper and lower cones to expand the slips. The drag springs also help guide the TAC through the casing.

The assembly of a TACThe assembly of a TAC

Drag springs should not be used as a handle for carrying or tailing in tubing. This would bend the drag springs and impair their function. In deep installations (8,000 feet or 2,438 meters), two or more drag springs should be used one on top of the other.

TACs should not be used in wells that have bad casings. The bad casing could cause a problem in wells that produce sand or scale buildup unless the casing is redressed.

Running and Setting

To prevent the slips from becoming dulled before reaching the setting depth, it is advisable to put a right hand turn into the tubing every five or 10 stands while running in.

Upon reaching the desired depth, rotate the tubing to the left with hand wrenches until the slips contact the casing (approximately five to eight turns). Maintain a left hand torque while alternately pulling strain and setting down a few times to work all the play out of the tool. During this slip-setting operation, the strain pulled should be at least equal to the final strain that will be applied when the tubing is landed and full set-down weight will be applied. The torque should be released until all the residual torque is removed. Apply the required amount of tubing tension that should always be applied in inches of stretch rather than in pounds of pull because of the probable friction between the tubing and the casing. First, the weight of the tubing needs to be applied and then the actual stretching begins.

When the TAC is run at some distance above the pump, the maximum allowable load below the TAC must not exceed the maximum load values. This load is a combination of the weight of the fluid inside the tubing (from the surface to the pump) and the tubing weight below the TAC.

Normal and Emergency Releasing

A TAC should be released with the tubing in slight compression because the upper cone is spaced so that the lower cone will be completely retracted when the slips lose their grip on the casing. Incomplete retraction of the lower cone will cause the slips to drag and dull the teeth. The tubing should be rotated to the right so that five to eight revolutions at the anchor are obtained. This will retract both cones and allow the slips to retreat into their housing. When the anchor is free, a few more right-hand turns should be put in before removing it. Additional right hand rotation is not harmful to the anchor. As an added precaution to avoid dulling the slips, a few right-hand turns are occasionally added on the way out of the hole.

In case of an emergency release (for example, if the normal releasing procedure as described above fails), picking up against the TAC will induce an up-strain sufficient enough to shear the emergency pins in the lower cone. In practice, the amount of up-strain exerted should be greater than the total shear strength of the shear pins, plus the weight of the tubing. Shearing the shear pins will release the TAC.

Tubing Stretch

Tubing strings are affected by mechanical, pressure and temperature changes. In tubing string, different factors cause length and force changes. These factors depend on well conditions, tubing anchor/casing configuration and tubing restraint. Each factor acts independently and may either add to or nullify the effects of the other factors.

Therefore, keeping the direction of the length changes and forces correct is important. Furthermore, mechanically applied tension or compression may be used to negate the combined effect of the pressure and temperature changes. When discussing tubing stretch and the use of a TAC for efficient pumping conditions, certain factors must be considered. The piston effect (breathing and buoyancy), temperature effect and ballooning effect should be factored in while calculating the right amount of tubing pickup for tension anchor installation. These axial loads cause the tubing to be in compression and tension alternately on freely suspended tubing, which causes the tubing string to experience buckling. The pickup load in pounds is determined first. Then the calculated load is converted to tubing stretch in inches.

These hand calculations discuss four types of axial loads to which the tubing string is exposed during installation and operations. They are:

  • Piston effect on the tubing string because of buoyancy (FPB)
  • Piston effect from plugging (Fpp)
  • The ballooning effect (FB)—the indirect effect of pressure on axial loads via radial forces
  • The temperature effect on the tubing string (FT)

Picking up the tubing string to the calculated stretch, anchored by the TAC, will keep the tubing in tension throughout the pumping cycle. The calculated stretch values are the minimum values required to keep the tubing string in tension. Since some of these factors are dynamic—that is, they change during the service of the well—calculating the stretch at different scenarios (such as, during the time of installation and during the time of pumped off condition) is recommended. Also, the scenario that requires the maximum stretch as the minimum required stretch should be considered. These stretch values should be reevaluated periodically during the well service. The tubing string can be stretched more than the calculated minimum value by finding out the maximum tensile strength of the weakest joint.


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  2. Bellaryby, Jonathan. Well Completion Design, Elsevier, Oxford, U.K., April 2009.
  3. ASM Handbook, Volume 1, Properties and Selection: Irons steels and High Performance Alloys, ASM International, April 1990.
  4. TECH FACTS Engineering Handbook - Technical Information for Completion, Workovers and Fishing, Baker Hughes, July 2011.
  5. Editor’s Note: For full calculations and technical paper, email the author at jsamayamantula@don-nan.net.