Tubing Anchor Catcher

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PRODUCTION

Tubing Anchor Catcher Application andOperationSEPTEMBER/OCTOBER 2013 ISSUE

Understanding the basic aspects of TACsand their application, operationalprocedures and tubing stretch is necessaryfor efficient artificial lift.by Jyothi Swaroop Samayamantula, Don-Nan Pump & Supply

From the selection process to installation and continuedmaintenance, a tubing anchor catcher (TAC) is one of the

most important tools for achieving efficient pumpingoperation. The upstream oil and gas sector continues toevolve with new methods morphed from old methods as itpertains to artificial lift systems. Since the people and partscontinue to change for oil companies, understanding thebasic, yet important, aspects of TACs and their application,operational pro cedures and tubing stretch is necessary. Incovering this tool’s basics and importance, the scope of this

article will expand on tubing stretch, shear values, dragspring usage, troubleshooting and other installationtechniques.

What Is a TAC?A TAC is a device used to anchor tubing string to the casingat a desired depth. It pulls and maintains tension in thetubing string during pumping while simultaneously catching

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and preventing any parted pipe from falling into the well. Itis used in most rod pumping applications in whichmaintaining tubing tension is necessary.

When set with proper tension to overcome breathing andbuckling, the TAC effectively cuts operating costs incurredfrom excessive rod, tubing and casing wear, which results infewer pulling jobs. The elimination of breathing andbuckling increases production by lengthening the effectivestroke 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, increasedrequirements of power consumption

Tubing buckling because of piston effects such asbreathing (also referred to as plugging), buoyancy andballooning effects

The movement of the bottom portion of the freely suspendedtubing string along with the plunger as the pump strokes isreferred 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, thetubing carries the fluid load, and on the up stroke, the rodscarry the fluid load. During the down stroke, the tubingelongates and the rods shorten. During the up stroke, therods elongate and the tubing shortens. The elongation andcontraction of the tubing string along with the rod stringreduces the effective pump stroke and, as a result, reduces theproduction. This also creates tubing buckling, which results


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in tubing and casing wear; tubing collar leaks; and metalfatigue, causing the tubing to part. Buoyancy and ballooningeffects cause the tubing string to change length.

In practice, tubing undergoes bending or buckling, which ischaracterized by a sudden failure of a tubing membersubjected to high compressive stress in which the actualcompressive stress at the point of failure is less than theultimate compressive stress that the tubing material is able towithstand. Because the tubing string is set free from tension,

nothing restrains the buckling forces. The rods remainstraight, supporting the fluid load. The tubing string bendsand coils helically (see Figure 1), rubbing against both therods and casing. The rods are forced out of alignment whilethe pump barrel wear is accelerated. In this case, the rods,tubing, casing and pump are subjected to extreme wear. Thisalso causes the pump to consume more lifting power toovercome the added friction.

Some of the means by which the tubing buckling can behandled are tension anchors, tail pipe, sucker rod guides andcorrosion inhibitors. To keep the tubing string frombuckling, the structural member/tubing string should besubjected to tension. Using a TAC to anchor the tubingstring at the bottom permits the tubing to stretch beyond thepoint that it would be stretched by the fluid load and

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Figure 1. Helical bending of the tubingstring

temperature variations. TheTAC at the bottom of thetubing string will help holdthe tubing string straightand keep its length fromchanging during the pumpstroke.

Installation and OperationMany factors—wellheadtype, proper installation,running and setting, andnormal and emergency

releasing—must beconsidered when using aTAC.

Selection of WellheadThe type of wellhead is animportant factor inobtaining proper stretch in

the tubing string.Determining the type of wellhead to be used beforeinstalling the TAC isimportant. Screw type (seeImage 1) and slip type (seeImage 2) are two commonly used wellhead devices. Both have advantages and

disadvantages.


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Image 1. A screw type wellhead

Image 2. A slip type wellhead

In a slip type wellhead, the tubing is stretched and allows thetapered slips to catch the tubing string. The teeth on the slipsprovide the necessary friction to keep the tubing stringstretched. To have proper friction between the slips and the


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load acts on the seating nipple. If the TAC is anchored abovethe seating nipple, the TAC mandrel is subjected to the fluidload.

Figure 2 shows the assembly of a TAC. It shows the positionof the drag springs, which create friction between the anchorand 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.


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The assembly of a TAC

Drag springs should not be used as a handle for carrying ortailing in tubing. This would bend the drag springs andimpair their function. In deep installations (8,000 feet or2,438 meters), two or more drag springs should be used oneon top of the other.

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

Running and Setting To prevent the slips from becoming dulled before reachingthe setting depth, it is advisable to put a right hand turn intothe 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 handtorque 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 tothe final strain that will be applied when the tubing is landedand full set-down weight will be applied. The torque shouldbe released until all the residual torque is removed. Apply the

required amount of tubing tension that should always beapplied in inches of stretch rather than in pounds of pullbecause of the probable friction between the tubing and thecasing. First, the weight of the tubing needs to be applied andthen the actual stretching begins.

When the TAC is run at some distance above the pump, themaximum allowable load below the TAC must not exceed

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the maximum load values. This load is a combination of theweight of the fluid inside the tubing (from the surface to thepump) and the tubing weight below the TAC.

Normal and Emergency Releasing A TAC should be released with the tubing in slightcompression because the upper cone is spaced so that thelower cone will be completely retracted when the slips losetheir grip on the casing. Incomplete retraction of the lowercone will cause the slips to drag and dull the teeth. Thetubing should be rotated to the right so that five to eightrevolutions at the anchor are obtained. This will retract bothcones and allow the slips to retreat into their housing. Whenthe anchor is free, a few more right-hand turns should be putin before removing it. Additional right hand rotation is notharmful to the anchor. As an added precaution to avoiddulling 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 normalreleasing procedure as described above fails), picking upagainst the TAC will induce an up-strain sufficient enough toshear the emergency pins in the lower cone. In practice, theamount of up-strain exerted should be greater than the totalshear strength of the shear pins, plus the weight of thetubing. Shearing the shear pins will release the TAC.

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Tubing StretchTubing strings are affected by mechanical, pressure andtemperature changes. In tubing string, different factors causelength and force changes. These factors depend on wellconditions, tubing anchor/casing configuration and tubingrestraint. Each factor acts independently and may either addto or nullify the effects of the other factors.

Therefore, keeping the direction of the length changes andforces correct is important. Furthermore, mechanically applied tension or compression may be used to negate thecombined effect of the pressure and temperature changes.When discussing tubing stretch and the use of a TAC for

efficient pumping conditions, certain factors must beconsidered. The piston effect (breathing and buoyancy),temperature effect and ballooning effect should be factored inwhile calculating the right amount of tubing pickup fortension anchor installation. These axial loads cause thetubing to be in compression and tension alternately on freely suspended tubing, which causes the tubing string toexperience buckling. The pickup load in pounds is

determined first. Then the calculated load is converted totubing stretch in inches.

These hand calculations discuss four types of axial loads towhich the tubing string is exposed during installation andoperations. 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)


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Picking up the tubing string to the calculated stretch,anchored by the TAC, will keep the tubing in tensionthroughout the pumping cycle. The calculated stretch valuesare the minimum values required to keep the tubing string intension. Since some of these factors are dynamic—that is,they change during the service of the well—calculating thestretch at different scenarios (such as, during the time of installation and during the time of pumped off condition) isrecommended. Also, the scenario that requires the maximumstretch as the minimum required stretch should beconsidered. These stretch values should be reevaluatedperiodically during the well service. The tubing string can bestretched more than the calculated minimum value by findingout the maximum tensile strength of the weakest joint.

References1. Lubinski, A., W.S. Althouse, J.L. Logan. “Helical

Buckling of Tubing Sealed in Pacer,” PetroleumTransactions - Society of Petroleum Engineers, 1962.

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, ASMInternational, April 1990.

4. TECH FACTS Engineering Handbook - TechnicalInformation for Completion, Workovers and Fishing,

Baker Hughes, July 2011.5. Editor’s Note: For full calculations and technical paper,

email the author at [email protected] .

ABOUT THE AUTHOR

mailto:[email protected]


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Jyothi Samayamantula has a bachelor’s in mechanical engineering and a master’s inindustrial engineering. He specializes in downhole applications regarding beam androd artificial lift with Don-Nan Pump & Supply Co. For more information, visitwww.don-nan.net.

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