how to run and cement liners part 1

P a r t 1 H o w t o R u n a n d C e m e n t L i n e r s

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Glenn R. Bowman, Regional Drilling Superintendent, Ashland Ex-ploration, Houston: and Bill Sherer, Operations Manager, LinerTools LC and formerly Alexander Oil Tools, Houston

EVEN BEFORE SUCH straightforward procedures as calculatingcement volume or designing liner strings are performed, thedrilling/completion engineer should evaluate well conditions tomake sure all contingencies have been considered. This articlediscusses benefits of pipe movement during cementing, but pointsout the impracticality in some cases. When impractical, othermeans can be applied to optimize the job. Also included are currentindustry practices that can cause trouble and the advantages toreciprocating or rotating a liner.

KNOW WHEN TO TAKE A RISK Effectively cementing liners, (Fig. 1), continues to be a difficulttask in most areas since many operators continue to avoid applyingknown cementing principles, mechanical aids and pipe movement.This becomes more ingrained if the operator has had or heard ofa bad experience with a liner. Therefore, most operators haveceased attempting to balance risk with cost efficiency in cementingliners. This can result from company policy or fear of failure. Lackof pipe movement, small amounts of cement and expensive rem-edial squeezing therefore are planned for and expected in mostjobs.

The authors do not settle for this low-risk attitude, which inher-ently produces a low degree of success. Instead, we try to applyall known cementing principles and available mechanical techniquesto every liner job, modified as necessary for individual wellconditions. There is not just one company policy for all liners assome operators have adopted. By maximizing the engineeringapplied to each well, large economical and technical rewards canbe achieved in an industry characterized by risk.

This article will not describe any new technology in liner ce-menting or equipment, but rather will show how existing methods are realistically and practically applied. Some case histories and solutions to problems will also be presented in future articles.

CURRENT INDUSTRY PRACTICES There probably is nothing more controversial in industry thanhow a liner should be cemented, and many excellent articles havebeen written on this subject.1-22 These articles describe in detailhow liner cementing is performed in certain areas with specificwell conditions. The authors applaud the new boldness in industryto challenge timid philosophies on cementing liners. As pointedout so aptly by Lindsey.8 Two widely accepted cementing methods are performed as follows:

x Single stage cement job in which the operator plans tocirculate cement to the top of the liner.

x Planned squeeze program in which the lower part of theliner is cemented and the top of the liner is squeezed later.

Unfortunately, the second procedure is more widely accepted.In addition, the practice of disengaging from the liner hangerbefore cementing is almost universal. According to Lindsey,16

less than 20% of all liner jobs include plans to move the linerduring cementing. There are many reasons for this including:

x It eliminates the risk of being unable to detach from the liner once cement is in place. This can be a serious problem if cement is brought above the liner top and around the drill pipe and then allowed to set. In some instances, this resulted in wells being junked, or at the very least, in costly repair. Most operators consider it an unacceptable risk to stay connected tothe liner during cementing.

x It may be necessary to change to a higher strength drill stringto enable reciprocation or rotation with drag or torque.

x If centralizers or scratchers are used they may become en-tangled with the liner hanger during movement and interferewith its use.

x Swab or surge pressures while moving the liner could cause either lost circulation or formation flow if mud weight is close to exceeding the fracture gradient or only slightly overbalanced, respectively.

x Movement of the liner during cementing may knock debris off into the annulus that may form a bridge and cause circulation and placement problems, or cause the cement to squeeze off in the annulus.

x If the liner sticks during movement while cementing, then it will have to be set in compression. This can cause the liner to buckle (Fig. 2), which can lead to drill string torque and subsequent wear on the liner if it is a drilling liner. For a production liner, the buck-ling could make it difficult or impossible to set a packer. Bucklingproblems can be aggravated even more by higher temperaturesand pressures during deeper drilling.1, 20, 21, 23

x No liner reciprocation reduces the likelihood that it will be stuck off bottom above a critical pay or lost circulation zone. Another problem with sticking the liner off bottom is the potential that rat-hole mud and cement may change places (flip flop) due to densitydifferences once the cement is in place. This could ruin the quality of the cement job around the bottom of the liner.

Figure 1 - An effective cemented liner is one cemented con-centrically in the hole, with all critical zones isolated fromone another and from the liner top and shoe by competent cement.

w w w . l i n e r t o o l s . c o m Reprinted from World Oil magazine, May 1988 with permission from the authors.

Liner Hanger

Protective Casing

LinerTop

Cement fromthe top of the Liner Shoe

Operators trying to minimize risk by refusing to rotate or reciprocate liners while cementing often cost themselves money to repair poor cement jobs. However, practices commonly viewed by some as being risky actually produce better results over the long haul


x Fear that the drill string may part during reciprocation or twist off during rotation of the liner is eliminated.

Despite the disadvantages of moving the liner by staying attachedwhile cementing, the authors believe that there are many more serious economic disadvantages with releasing from the liner before cementing. They include:

x When hanging off the liner before cementing, seals are disturbed that isolate the pressures inside the liner hanger setting tool from pressures on top of the liner, this despite good improvement in seal design and packoff bushings. Many liners have had all or part of the cement pumped around the liner setting tool. The same problem canoccur with downhole rotating liner hangers. By staying attached to the liner while cementing, the problem essentially becomes non-existent.

x By hanging off first, the bypass area around the liner becomes a greater restriction, potentially causing lost circulation orbridging in the annulus with cuttings or wallcake, causing suddendehydration of the cement (Fig. 3). Graves has quantified theamount reduced liner hanger areas can also increase equivalent circulation densities. 13

x With downhole rotating liner hangers (the liner is hung off first, the setting tool released and rotation initiated), more torque isis required to initiate rotation to overcome bearing friction.16 The liner may become stuck in close tolerance, high differentialpressure, high permeability, or deviated type holes while releasing from the liner hanger. By hanging off first, a circulating restriction is created that increases the equivalent circulating density. Another disadvantage of these type hangers are that rotation requirements are controlled by the load on, and consequently, the life of thethe bearings.16, 18 The heavier the liner, the shorter the bearinglife and the slower the liner has to be rotated. Lower rpm meanslower cement-to-mud drag forces. Mechanically set liner hangers (see Fig. 4) are routinely rotated at 40-45 rpm for as long as thejob takes. On one job, a mechanically set liner hanger was rotatedat 120 rpm after the cement turned the shoe. Unquestionably,higher rpm greatly increases the chances for a cement job in any

type of hole. The displacement efficiently on this job wasover 92%. There are no bearings to restrict rotation speed or time. Also, with these type hangers, once the liner is on bottom, the operator can access hole conditions and then have the option to reciprocate, rotate, or do both. Staying attached can also let the operator alternate between reciprocation (if torque is too high or the rig rotary table goes out) and rotation (if there is too much drag). Downhole rotating liner hangers do not provide this option.

x The liner running tool stinger cannot be pulled out of the liner hanger during cementing as a result of temperature contraction, differential pressure or the liner hanger sliding down the hole.7 This concern becomes more real if high pump rates are desired, which means higher pump pressures.

x Potential for the annulus packing off with shale and subse-quent loss of returns is lessened when the operator canalternate between rotation and reciprocation.

x Premature shearing of retaining pins holding the linerwiper plug is less likely because there is no relative movementbetween the liner and setting tool.7

x If cement channels severely and there is a large hydrostatic difference between the inside and outside of the running tools, the cups or seals can give way before cementing of the liner is complete. In this event, the plug will never be full displaced, leaving cement to be drilled inside the liner and little or nocement around the back of the liner.

As shown above, there are many advantages to working a linerby staying attached while cementing. During the two authors’ com-bined experience in over 300 jobs, the inability to release the linersetting tool has only occurred twice. One was caused by premature setting of cement. The other involved mechanical failure during the earlier development in the 1960s of the hanger shown in Fig. 4. This has not occurred since the hanger was redesigned.

Liner Top Squeezed

Buckled Interval

Washed Out Hole

Liner

Intermediate Casing

UncementedInterval

Cement Top from First Stage

Cement Bottom from Squeeze

Figure 2 - If it is necessary to squeeze the top of a liner, there is a possibility that there will remain an uncemented interval that could lead to later pipe buckling (especially if there are major washed out sections). For a drilling liner, this could establish wear points that may develop into casing leaks. For production liners, the buckling could prevent the proper installation of packers.

Figure 3 - Due to cement’s superior hole cleaning ability (espec-ially if it is in turbulent flow), an accumulation of drilled cuttingsnot circulated out during drilling could cause a bridge ahead ofthe cement in a narrow annulus. The cement then may suddenly dehydrate and set prematurely. Some may call it “flash setting.”

Drill Cuttings

Liner

IntermediateCasing Liner Hanger

(circulating restriction) Drill Cuttings

from Washout

Cement

Drill String

Cement

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Reprinted from World Oil magazine, May 1988 with permission from the authors. w w w . l i n e r t o o l s . c o m

be achieved, displacing at a maximum flowrate was more effect-ive than plug flow displacement.

In the experimental studies cited,25 displacement was not app-reciably affected by the amount of fluids pumped at low flowrates. Apparently, once cement determined a flow path, it contin-ued to follow that path with little or no deviation. The chemical reaction between cement and mud may have created a contact region that could not be eroded away.

The lab investigation also showed that increasing the density difference between the fluid mud and cement by as much as 3 ppg did not improve overall displacement. The buoyancy force did not aid in removing the non-circulatable mud because the fluid that had lost its mobility had a greater density than the cement, even when the fluid mud was lighter than the cement. The mud mustbe mobile to let density have an effect.25

The relative importance of the displacement factors may berealized by considering the mud mobility factor defined in thispaper25 and the fluid velocity of cement. There appeared to be two major opposing factors in the cement/mud displacement process identified in the lab investigation, namely: immobility of thedrilling fluid (being resisting force) and flow energy of the displacing fluid. Displacement was improved by either increasing the mud mobility (the more effective method) or increasing the flow energy.

Of particular note in the preceding is that plug flow and densitydifferences between cement and mud do not affect sweepefficiency to any degree. Cement should be pumped as fast as possible, be it turbulent or laminar flow. Large density differences between mud and cement aggravate a lost circulation problem when cementing liners already burdened by close tolerancesand higher equivalent circulat ing densities. For long liners withlow mud weights and high cement densities, keeping the cement inplug flow would entail circulating he well on a choke to slow free fall of the cement. Not many operators will be inclined to circu-late a well on a choke while cementing and then rotate orreciprocate the liner with a bag type preventer closed around the work string.

McLean, Manry and Whitaker,26 showed how importantpipe movement is - either pipe rotation or reciprocation is verybeneficial to obtaining a primary cement job.

RECIPROCATING AND ROTATING LINERS Getting the best possible liner cement job in one trip isthe primary goal of liner movement. Unnecessary, costly tripsand squeezing can be avoided in numerous instances by applying known cementing and engineering principles with minimum risk. The authors view liner cementing as a better opportunityfor obtaining a primary cement job than in cementing casing. Many more good cementing practices can be accomplishedwhile cementing liners than cementing casing. The foremostprinciple not being applied is pipe movement, and without it, thedisadvantage is that effective mud removal from the annulus is decreased.

According to McLean, et al.,26 without pipe movement, there isno way cement can get between the pipe and hole where they arein contact due to casing-hole eccentricity. Bare casing will rest against the wall of the hole causing the annular cross-section ofcement to be a half-moon instead of a uniform ring. This problem becomes more severe in a directional hole in which mud channels are usually adjacent to the casing on the narrow side of the ann-ulus. Reciprocation helps because it produces lateral pipe move-ment that causes the pipe to change sides (lowside to highside, etc.)in the wellbore while it is put in compression when slacked offand tension when picked up. Rotation helps by pulling thecement into wellbore irregularities and displacing the mud due to cement-to-mud drag forces (see Fig. 5).

Before describing the design criteria for a liner job, it is neces-sary to first discuss the advantages of getting an optimum cement job and how pipe movement weighs heavily in achieving this end.

Figure 4 - Example of a mechanically set rotatinging or reciprocating liner hanger. The design ofthe setting tool is such that after cementing, thetool is rotated 18 rounds to the right, which allowsthe slips to be set by slacking off weight with 8 in.of downward movement. In addition, a jaw arrange-ment of the setting tool slips inside the releasingnut so that further rotation releases the liner. Re-ciprocation or rotation can be performed beforereleasing from the hanger while cementing.

GOOD CEMENTING CRITERIAS Displacement efficiency of cement aroundtubulars when the pipe is not moved dependshighly on the following:24

x Good rheological properties of the drillingfluid.

x Pipe centralization.

x High pump rates.

x The highest possible contact time of ce-ment pumped by critical pumped by criticalintervals.

x The use of cement that exceeds mud density by maximum amount that the conditions will allow.

Another study reconfirmed for the most part, the above as good cementing principles.25 They also concluded the following:

x During test sections simulating realistic downhole permeab-ilities, 100% displacement was never achieved.

x Downhole mobility of the mud system was highly dependent on its thixotropic properties and filter cake disposition characteristics and this was a major factor in how effectively mud was displaced.

x In a narrow annulus, the slightest decentralization was enough to allow a channel of mud to be bypassed. This was caused by the loss of mud fluidity and the resulting nonuniform pressure distribu-tion in the annulus.

x High cement flowrates appeared to favorably influence the mud displacement process. In lab investigations of mud removal, total fluid flow energy appeared to be more important than turbulent energy transfer, particularly in a narrow annulus.

x Within the realistic range of cement and mud rheological proper-ties studied, given in terms of yield point and plastic viscosity, the rheological differences did not have a measurable effect on the displacement process. However, for equivalent flow pressures, a cement with a low yield point may be pumped at a higher flow raterate than one with a high yield point. Therefore, when a low yieldpoint cement was used, the displacement process was favorably influenced by employing a higher flow rate.

x Throughout the experimental studies, pumping a high yield point cement at low flowrates was not an effective method of mud displacement.

x To maximize mud displacement in the lab, cement had to be pumped as fast as possible. Even when turbulent flow could not

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is always some drag when pulling pipe out of the hole, with thetotal amount of drag indicative of hole condition. Drag should reduce at a constant rate as pipe is pulled, but if it decreases more in one section it can be anticipated that this section is somewhat crooked and may have a keyseat. This section of hole in this case would correspond to the hole depth from the top of the drill collars to the bottom of the bit at the point where drag decreased (see Fig 7).

Figure 7 - Keyseats in layered formation. (After Short 27)

Keyseats must be avoided while both drilling and running casing. There are some things that can be done to minimize keyseats. The first is to minimize sudden changes in hole an-gle and consequently reduce dog-leg severity. This can be ac-complished by running stiff bottomhole assemblies. A second method is to always run spiral rib stabilizers or keyseat wipers on top of the top drill collars on bottomhole assemblies. Stabi-lizers and keyseat wipers help “steer” the drill collars out of the keyseat “groove” and “wipe” them out. Keyseat wipers should also be used if the possibility exists that the drill string may become stuck during a trip. Keyseat wipers not only wipe out the keyseat and steer the collars away from the keyseat groove, but also provide a means of jarring the drill string free if it becomes stuck. Keyseat wipers are available that can jar up or down. If the drill string sticks in a keyseat while pulling out the hole, then normally the drill string should be jarred down. If the drill string becomes stuck in a keyseat while going in the hole, it should be jarred up. On most liner jobs, keyseat problems that occur while pulling out of the hole will not cause a problem with getting a liner in the hole and rotating it, but could cause problems during reciprocation.

If keyseats become severe, another alternative is to reamthe section with a drill collar keyseat wiping assembly (Fig. 8).This is a rather drastic procedure and has its risks. Not onlyis this procedure very hard on drill collar tool joints, buta packed hole assembly such as this can be “jammed” intoany part ofthe open hole that was drilled with a more flexible bottomhole assembly. Because of this, consideration should be given to reaming all of the open hole down to the keyseat section. The best way to avoid this time consuming operation is to drill all the open hole with a stiff bottomhole

Figure 5 - Various forces acting to displace, and resist dis-displacement, of by-passed vertical mud column during primarycementing. (After McLean, et al. 26)

Although liner movement should always be the goal, wellconditions may dictate that it should not be tried. For instance,excessive drag may preclude liner reciprocation. If torque is not excessive, then liner rotation may be planned. If good operational practices are followed, however, the authors feel that liner move-ment can be achieved in over 90% of all liner jobs. But certain precautions need to be followed.

Questions that need to be considered before planning a liner job are as follows: x Is the hole in good condition? x If not, can it be improved economically? x Should plans call for working the liner?

The answer to these questions should be easy to determine before a job begins. Drag or torque problems with the drill string have already been noted. Drag problems can often, and should be, cleared up before running the liner. A short, small liner (3 ½-in. or smaller) in a deep well should be hung off first because it would be impossible to tell from the weight indicator if it had been released or not.

There are two main causes of excessive drag or torque, the first being dog-legs in the well bore that can lead to the formation of keyseats (Fig. 6).

Figure 6 - Shaded area shows amount of material that must be removed to wipe out the keyseat completely. (After Short 27)

As stated by J.A. “Jim” Short27, “Keyseats can be prevented; they can be detected; and they can be removed.” The best method of detecting keyseats is to observe the weight indicator and drill pipe on trips, especially when pulling pipe out ofhe hole. There

EarlyStage

MiddleStage

LateStage

DrilledHole Stages of Keyseat Growth

Soft Formation

Soft

Formation

Drill Pipe

Hard

Formation

Hard

Formation

SoftFormation

Soft Formation

Hard Formation

Hard

Formation

CrossSection

of DrilledHole

CrossSection

of DrilledHole

Top of Drill Collarin a Keyseat

Bit in Keyseat

Drill Collar

Bit

Keyseat

Keyseat

Hard

Formation

Drag force from casing movement (Pos.)

Drag force, mudon wall (Neg.)

Pressure due to mud column weight (Neg.)

Buoyancy effect ofdenser cement (Neg.)

Eccentric annulus

Cement slurry

Drag force cement on mud (Pos.)

Differential pressuremoving cement alsoacts on mud (Pos.)

Bypassed mud channel

Casing

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Figure 8 - Examples of drill collar keyseat wiping assemblies(After Short )27

assembly from the beginning. For those who like to drill witha pendulum assembly in soft formations to hold down holedeviation, a packed pendulum can be run (Fig 9). Once TD isreached, the pendulum hookup is moved down to the bit. This means that only the length of the pendulum collars will have to be reamed.

Figure 9 - A packed pendulum assembly is used to decrease holehole angle especially when a packed hole assembly is required after hole angle is reduced. (After Wilson )29

The importance of packed hole assemblies as they apply torunning liners will be discussed later in more detail. Care also has to be taken to assure that the well is not sidetracked while reaming. According to Short,27 the best practice is to ream withthe heaviest weight possible and use high rotary speed. If thereis drag or the hole is taking weight while tripping in the hole,under-reaming may be necessary. Drag problems or torque problems also can be caused by having a “dirty” hole. This, along with other variables will be discussedin a future article on getting liners to bottom.

If drag and torque problems occur simultaneously and cannotbe decreased, plans should not be made to move the liner once it has been run. Instead, once the liner is in place, leave it

there and hang it off immediately in full tension. When an appro-priateliner hanger is run and if drag is the only problem, then plans could be made to rotate the liner. If torque is a problem, plans can be made to reciprocate the liner. This is often the case in directional wells with high differential pressures and exposedsands with high permeabilities. A hydraulic hanger should be con-sidered when severe torque problems are present and cannot be remedied. Ashland does not necessarily attempt to rotate or reciprocatedrilling liners since a maximized cement job in this case is one inwhich the liner top and the liner shoe do not have to be squeezed with an additional trip of the drill string. This philosophy should change if large mud weight increases and significantly higher temperatures can be expected during later drilling. These variables may increase buckling tendency1,21,23 of tubulars (Fig. 2)and may dictate the necessity of cementing as much of the liner’slength as possible. A bad cement job may not provide enough lateral support (especially in large washouts) to keep the liner from buckling. This becomes more important as drilling time and amount of buckling aggravates casing wear during trips or rotation.In extreme well conditions, consideration should be given todrilling with oil base mud or an inhibited water base mud to achieve a closer-to-gauge hole. This will provide more lateral support and aslicker hole for liner movement while cementing. Liner bucklingwill not be a problem in a close tolerance hole even if there is almost no cement behind the liner as long as the hole is in gauge. Other good cementing criteria beside rotation and recipro-cation, will be discussed in more detail in future articles

ACKNOWLEDGEMENT The authors thank their respective managements for permissionand encouragement to publish this article and for their progressive management philosophy that encourages maximized engineering efforts on all field operations. The authors also thank drillingforeman Leon Pate and Ray Guidry, and Tim Alexander Jr. for sharing their expertise and Judy BenSreti for typing the manuscript. The authors would also like to state that they have read somuch literature and talked to so many people concerning the subject matter that they realize that the manuscript does not completely constitute original thinking. Any credit not given toprevious authors where credit is due is regretted and uninten-tional. THE AUTHORS Glenn R. Bowman is the regional drilling superintendent for Ashland Exploration’s Houston Region. He graduated from Mari-etta College with a BS degree in petroleum engineering and has held various drilling engineering positions before joining Ashland in 1984. He was most recently drilling manager for Wainoco Oil and Gas in Houston. Mr. Bowman is a member of SPE and has authored several other papers for World Oil on liners and bottom-hole drilling semblies.

Bill Sherer is the operations manager for Liner Tools LC inHouston, and worked for Alexander Oil Tools from 1984-2001 con-centrating on the B&W liner hanger line. Mr. Sherer worked forB&W from 1965 to 1979 and later as a consultant for runningliners from 1979 until 1984. Mr. Sherer specializes in optimization

techniques for cementing liners and has personally supervisethe running of over 300 liners.

For more information regarding high rpm liner rotation,centralization, and primary cementation please contact us or visit our website shown below.

Short or High Angle Keyseat

BitStabilizers

Long Keyseat

Keyseat

Reamers

Drill Collars

Short or LongDrill Colar

Stabilizers

Packed HoleAssembly

Pendulum

VibrationDampenerDrill Collars

Bit

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LITERATURE CITED

1 Lindsey, H.E. and Bateman, S.J. “Improve cementing of drilling liners in deep wells.” World Oil. October 1973.

2 Gibbs, Joe. “How to rotate and reciprocate while cementing your liner.” Drilling-DCW. June 1974.

3 West, E.R. and Lindsey, H.E. “How to run and cement liners in ultra-deep wells.” World Oil. June 1966.

4 Lindsey, H.E. “Running and cementing deep well liners.” World Oil. November 1974.

5 Suman, G.O., and Ellis, R.C. “Cementing Handbook.” World Oil. 1977.

6 Lindsey, H.E. “How deep Anadarko wells are designed and equipped.” World Oil. February 1, 1979.

7 Howell, Frank R. “Liner reciprocation while cementing.” Drilling-DCW. July 1979.

8 Lindsey, H.E. “New tools make liner rotation during cementing prac-tical.” World Oil. October 1981.

9 Smith, Dwight K. Cementing Society of Petroleum Engineers of AIME and Henry L. Doherty Fund of AIME, 1976.

10 Hyatt, C.R. and Partin Jr., M.H. “Liner rotation and proper planning improves primary cementing success.” SPE 12607, April 1984, Ama-rillo, Texas.

11 Spradlin, Jr., W.N. “Operators tackle Anadarko cementing prob-lems.” Petroleum Engineer International. June 1983.

12 Landrum, W.R. and Turner, R.D. “Rotating liners during cementing in the Grand Isle and West Delta Area.” IADC/SPE 11420. 1983.

13 Graves, Kyle S. “Planning would boost liner cementing success.”Oil and Gas Journal. April 1985.

14 Arceneaux, Mark A. “Liner operations made easy.”PetroleumEngineer International. September 1986.

15 Arceneaux, M.A. and Smith, R.L. “Liner rotation while cementing: An operator’s experience in South Texas.” SPE/IADC 13448. New Orleans, La.

16 Lindsey Jr., H.E. “Rotate liners for a successful cement job.” World Oil. October 1986.17 Lindsey Jr., H.E. and Durham, K.S. “Field results of liner rotation during cementing.” SPE Production Engineering. February 1987.

18 Garcia, Juan A. “Rotating liner hanger helps solve cementing problems.” Petroleum Engineer International. September 1985.

19 Reiley, R.H., Black, J.W. Stagg, T.O., and Walters D.A., “Cement ing of liners in horizontal and high-angle wells at Prudhoe Bay, Alaska.” SPE 16682. September 1987. Dallas, Texas.

20 Vangolen, Tracy Smink and Robertson, Wilton G. “Remedial liners repair EOR field casing damage.” Oil & Gas Journal. Oct. 12, 1987.21 Durham, Kenneth S. “How to prevent deep well liner failure,” Parts 1 & 2. World Oil. October and November 1987.22 Lindsey, H.E. and Durham, K.S. “Field results of liner rotation during cementing.” SPE 13047, Houston, Texas, Sept. 1984.23 Goins, W.C., “Better understanding prevents tubular buckling problems.” World Oil. February 1980.24 Jones, P.H. and Berdine, D. “Oil well cementing.” Oil & Gas Journal. March 21, 1940.

25 Haut, Richard C. and Cook, Ronald J. “Primary cementing Optimizing for maximum displacement.” World Oil. 1980.26 McLean, R.H., Manry, C.W, and Whitaker, W.W. “Displacement mechanics in primary cementing.” Journal of Petroleum Technology. 1967.27 Short, J.A. Drilling and casing operations. PennWell Publish- ing Company 1982.28 Woods, H.B. and Lubinski, A., “Use of stabilizers in controlling hole deviation.” Drilling and Production Practices. 1954.29 Wilson, Gerald E. “How to drill a usable hole.” Parts 1 and 2. World Oil. September 1976.

Showcase: The Mechanical Rotating Liner Hanger Optimal for medium to long length liners with severe down-hole conditions requiring high burst and collapse.

Applications: Used to run, cement, and rotate a liner at high RPM. Can be drilled into the hole. Optimum for all wells including deviated and S curved wells.

Features: Recessed, tongue and groove slips are pro- tected. Unique design allows rotation and reciprocation while cementing. High burst and collapse provided by a casing barrel. Resists hostile down-hole environments with optimum material selection. Controlled and evenly timed slips load the casing uniformly, eliminating casing failures due to point loading. Optimum slip angle maximizes the hanging capacity of the liner hanger. Simple to operate, requiring multiple right hand rotations to set the hanger.

Liner Tools LC

Specializing in Liner Primary Cementing

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