'Documents.mx How to Run and Cement Liners Part 1.PDF'

Part 1

How to Run and Cement Liners

perators trying to minimize risk by refusing to O 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

Protective Casing

Glenn R. Bowman, Regional Drilling Superintendent, Ashland Exploration, Houston: and Bill Sherer, Operations Manager, Liner Tools LC and formerly Alexander Oil Tools, Houston

Liner Top Liner Hanger

EVEN BEFORE SUCH straightforward procedures as calculating cement volume or designing liner strings are performed, the drilling/completion engineer should evaluate well conditions to make sure all contingencies have been considered. This article discusses benefits of pipe movement during cementing, but points out the impracticality in some cases. When impractical, other means can be applied to optimize the job. Also included are current industry practices that can cause trouble and the advantages to reciprocating or rotating a liner.

KNOW WHEN TO TAKE A RISK

Cement from the top of the Liner Shoe

Effectively cementing liners, (Fig. 1), continues to be a difficult task in most areas since many operators continue to avoid applying known cementing principles, mechanical aids and pipe movement. This becomes more ingrained if the operator has had or heard of a bad experience with a liner. Therefore, most operators have ceased attempting to balance risk with cost efficiency in cementing liners. This can result from company policy or fear of failure. Lack of pipe movement, small amounts of cement and expensive remedial squeezing therefore are planned for and expected in most jobs.

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

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 to the liner during cementing.

The authors do not settle for this low-risk attitude, which inherently produces a low degree of success. Instead, we try to apply all known cementing principles and available mechanical techniques to every liner job, modified as necessary for individual well conditions. There is not just one company policy for all liners as some operators have adopted. By maximizing the engineering applied to each well, large economical and technical rewards can be achieved in an industry characterized by risk.

x It may be necessary to change to a higher strength drill string to enable reciprocation or rotation with drag or torque. x If centralizers or scratchers are used they may become entangled with the liner hanger during movement and interfere with its use.

This article will not describe any new technology in liner cementing 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.

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.

CURRENT INDUSTRY PRACTICES There probably is nothing more controversial in industry than how a liner should be cemented, and many excellent articles have been written on this subject.1-22 These articles describe in detail how liner cementing is performed in certain areas with specific well conditions. The authors applaud the new boldness in industry to challenge timid philosophies on cementing liners. As pointed out so aptly by Lindsey.8 Two widely accepted cementing methods are performed as follows:

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 buckling could make it difficult or impossible to set a packer. Buckling problems can be aggravated even more by higher temperatures and pressures during deeper drilling.1, 20, 21, 23

x Single stage cement job in which the operator plans to circulate cement to the top of the liner. x Planned squeeze program in which the lower part of the liner is cemented and the top of the liner is squeezed later.

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 rathole mud and cement may change places (flip flop) due to density differences once the cement is in place. This could ruin the quality of the cement job around the bottom of the liner.

Unfortunately, the second procedure is more widely accepted. In addition, the practice of disengaging from the liner hanger before cementing is almost universal. According to Lindsey,16 less than 20% of all liner jobs include plans to move the liner during cementing. There are many reasons for this including: Reprinted from World Oil magazine, May 1988 with permission from the authors.

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Liner Top Squeezed

Buckled Interval Washed Out Hole Liner

type of hole. The displacement efficiently on this job was over 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.

Intermediate Casing

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.

Cement Bottom from Squeeze Uncemented Interval

x Potential for the annulus packing off with shale and subsequent loss of returns is lessened when the operator can alternate between rotation and reciprocation.

Cement Top from First Stage

x Premature shearing of retaining pins holding the liner wiper plug is less likely because there is no relative movement between 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 no cement around the back of the liner.

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

Drill String

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

Liner Hanger

(circulating restriction)

Drill Cuttings from Washout

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 can occur with downhole rotating liner hangers. By staying attached to the liner while cementing, the problem essentially becomes non-existent.

Cement Liner

Drill Cuttings

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

Cement

x With downhole rotating liner hangers (the liner is hung off first, the setting tool released and rotation initiated), more torque is is required to initiate rotation to overcome bearing friction. 16 The liner may become stuck in close tolerance, high differential pressure, 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 the the bearings.16, 18 The heavier the liner, the shorter the bearing life and the slower the liner has to be rotated. Lower rpm means lower cement-to-mud drag forces. Mechanically set liner hangers (see Fig. 4) are routinely rotated at 40-45 rpm for as long as the job takes. On one job, a mechanically set liner hanger was rotated at 120 rpm after the cement turned the shoe. Unquestionably, higher rpm greatly increases the chances for a cement job in any Reprinted from World Oil magazine, May 1988 with permission from the authors.

Intermediate Casing

Figure 3 - Due to cement’s superior hole cleaning ability (especially if it is in turbulent flow), an accumulation of drilled cuttings not circulated out during drilling could cause a bridge ahead of the cement in a narrow annulus. The cement then may suddenly dehydrate and set prematurely. Some may call it “flash setting.”

As shown above, there are many advantages to working a liner by staying attached while cementing. During the two authors’ combined experience in over 300 jobs, the inability to release the liner setting 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.

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

be achieved, displacing at a maximum flowrate was more effective than plug flow displacement. In the experimental studies cited,25 displacement was not appreciably affected by the amount of fluids pumped at low flow rates. Apparently, once cement determined a flow path, it continued 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.

Figure 4 - Example of a mechanically set rotating ing or reciprocating liner hanger. The design of the setting tool is such that after cementing, the tool is rotated 18 rounds to the right, which allows the slips to be set by slacking off weight with 8 in. of downward movement. In addition, a jaw arrangement of the setting tool slips inside the releasing nut so that further rotation releases the liner. Reciprocation or rotation can be performed before releasing from the hanger while cementing.

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 must be mobile to let density have an effect.25

GOOD CEMENTING CRITERIAS

The relative importance of the displacement factors may be realized by considering the mud mobility factor defined in this paper25 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 the drilling 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.

Displacement efficiency of cement around tubulars when the pipe is not moved depends highly on the following:24 x Good rheological properties of the drilling fluid. x Pipe centralization.

Of particular note in the preceding is that plug flow and density differences between cement and mud do not affect sweep efficiency 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 tolerances and higher equivalent circulat ing densities. For long liners with low mud weights and high cement densities, keeping the cement in plug flow would entail circulating he well on a choke to slow free fall of the cement. Not many operators will be inclined to circulate a well on a choke while cementing and then rotate or reciprocate the liner with a bag type preventer closed around the work string.

x High pump rates. x The highest possible contact time of cement pumped by critical pumped by critical intervals. 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 permeabilities, 100% displacement was never achieved.

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

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.

RECIPROCATING AND ROTATING LINERS

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 distribution in the annulus.

Getting the best possible liner cement job in one trip is the primary goal of liner movement. Unnecessary, costly trips and squeezing can be avoided in numerous instances by apply ing known cementing and engineering principles with minimum risk. The authors view liner cementing as a better opportunity for obtaining a primary cement job than in cementing casing. Many more good cementing practices can be accomplished while cementing liners than cementing casing. The foremost principle not being applied is pipe movement, and without it, the disadvantage is that effective mud removal from the annulus is decreased.

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 properties 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 rate rate than one with a high yield point. Therefore, when a low yield point cement was used, the displacement process was favorably influenced by employing a higher flow rate.

According to McLean, et al.,26 without pipe movement, there is no way cement can get between the pipe and hole where they are in contact due to casing-hole eccentricity. Bare casing will rest against the wall of the hole causing the annular cross-section of cement 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 annulus. Reciprocation helps because it produces lateral pipe movement that causes the pipe to change sides (lowside to highside, etc.) in the wellbore while it is put in compression when slacked off and tension when picked up. Rotation helps by pulling the cement into wellbore irregularities and displacing the mud due to cement-to-mud drag forces (see Fig. 5).

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 Reprinted from World Oil magazine, May 1988 with permission from the authors.

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is always some drag when pulling pipe out of the hole, with the total 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).

Casing

Drag force from casing movement (Pos.)

Eccentric annulus

Drag force, mud on wall (Neg.)

Differential pressure moving cement also acts on mud (Pos.)

Pressure due to mud column weight (Neg.)

Bypassed mud channel

Hard a ti o n

Drag force cement on mud (Pos.)

Buoyancy effect of denser cement (Neg.)

Form

S o ft

Cement slurry

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

Hard a ti o n

Keyseat Drill Collar Cross Section of Drilled Hole

S o ft a ti o n Form Keyseat

Hard a ti o n Form S o ft

Form

Bit

a ti o n

Bit in Keyseat

Hard Formation

Figure 7

- Keyseats in layered formation. (After Short27)

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 angle and consequently reduce dog-leg severity. This can be accomplished 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. Stabilizers 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.

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).

Late Stage

Stages of Keyseat Growth

If keyseats become severe, another alternative is to ream the section with a drill collar keyseat wiping assembly (Fig. 8). This is a rather drastic procedure and has its risks. Not only is this procedure very hard on drill collar tool joints, but a packed hole assembly such as this can be “jammed” into any 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 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 Reprinted from World Oil magazine, May 1988 with permission from the authors.

P ip e

Cross Section of Drilled Hole

Hard a ti o n Form

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.

Drilled Hole

D r il l

S o ft a ti o n Form

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?

Middle Stage

a ti o n

Top of Drill Collar in a Keyseat

Form

Although liner movement should always be the goal, well conditions 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 movement can be achieved in over 90% of all liner jobs. But certain precautions need to be followed.

Early Stage

Form

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Short or High Angle Keyseat

there and hang it off immediately in full tension. When an appropriateliner 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 exposed sands with high permeabilities. A hydraulic hanger should be considered when severe torque problems are present and cannot be remedied.

Long Keyseat Stabilizers

Bit

Short or Long Drill Colar

Ashland does not necessarily attempt to rotate or reciprocate drilling liners since a maximized cement job in this case is one in which 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’s length 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 to drilling with oil base mud or an inhibited water base mud to achieve a closer-to-gauge hole. This will provide more lateral support and a slicker hole for liner movement while cementing. Liner buckling will 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.

Drill Collars Reamers Keyseat

Stabilizers

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

Other good cementing criteria beside rotation and reciprocation, will be discussed in more detail in future articles

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

ACKNOWLEDGEMENT The authors thank their respective managements for permission and encouragement to publish this article and for their progressive management philosophy that encourages maximized engineering efforts on all field operations. The authors also thank drilling foreman Leon Pate and Ray Guidry, and Tim Alexander Jr. for sharing their expertise and Judy BenSreti for typing the manuscript.

Packed Hole Assembly Vibration Dampener

Drill Collars

Bit

The authors would also like to state that they have read so much 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 to previous authors where credit is due is regretted and unintentional.

Pendulum

THE AUTHORS Glenn R. Bowman is the regional drilling superintendent for Ashland Exploration’s Houston Region. He graduated from Marietta 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 bottomhole drilling semblies.

Figure 9 - A packed pendulum assembly is used to decrease hole hole 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 to running 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 with the heaviest weight possible and use high rotary speed. If there is drag or the hole is taking weight while tripping in the hole, under-reaming may be necessary.

Bill Sherer is the operations manager for Liner Tools LC in Houston, and worked for Alexander Oil Tools from 1984-2001 concentrating on the B&W liner hanger line. Mr. Sherer worked for B&W from 1965 to 1979 and later as a consultant for running liners from 1979 until 1984. Mr. Sherer specializes in optimization techniques for cementing liners and has personally supervise the running of over 300 liners.

Drag problems or torque problems also can be caused by having a “dirty” hole. This, along with other variables will be discussed in a future article on getting liners to bottom.

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

If drag and torque problems occur simultaneously and cannot be decreased, plans should not be made to move the liner once it has been run. Instead, once the liner is in place, leave it Reprinted from World Oil magazine, May 1988 with permission from the authors.

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LITERATURE CITED

25

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

26

Haut, Richard C. and Cook, Ronald J. “Primary cementing Optimizing for maximum displacement.” World Oil. 1980.

1

McLean, R.H., Manry, C.W, and Whitaker, W.W. “Displacement mechanics in primary cementing.” Journal of Petroleum Technology. 1967.

2

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

27

Short, J.A. Drilling and casing operations. PennWell Publishing Company 1982.

3

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

28

Woods, H.B. and Lubinski, A., “Use of stabilizers in controlling hole deviation.” Drilling and Production Practices. 1954.

4

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

29

Wilson, Gerald E. “How to drill a usable hole.” Parts 1 and 2. World Oil. September 1976.

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.” DrillingDCW. July 1979. 8

Lindsey, H.E. “New tools make liner rotation during cementing practical.” 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, Amarillo, Texas.

Liner Tools LC Specializing in Liner Primary Cementing

11

Spradlin, Jr., W.N. “Operators tackle Anadarko cementing problems.” 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.

Showcase:

14

Arceneaux, Mark A. “Liner operations made easy.”Petroleum Engineer 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.



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



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.



Recessed, tongue and groove slips are protected. 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.

Applications:

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.

Features:

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.

Reprinted from World Oil magazine, May 1988 with permission from the authors.

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