39707748 How to Run and Cement Liners

How to Run and Cement Liners

A nine part series reprinted from

World Oil magazine, May 1988 with permission from the authors

Preface

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. 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.

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. 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.

FOR MORE INFORMATION Regarding high rpm liner rotation, centralization, and primary cementation please contact us or visit our website at www.linertools.com.

Liner Tools LC

Specializing in Liner Primary Cementing

Table of Contents

How

Liner Tools LC

1

Producing Better Results Over The Long Haul

2

Getting to the Bottom in the First Place

................................ page 1.1

.................................... page 2.1

to Run .............................. page 3.1

3

A Few Precautions to Reduce the Risk of Flash Setting

4

Procedures and Recommendations for Preparing the Liner for Testing

..... .......... page 4.1

and ............... page 5.1

5

Preferred Methods of Testing Liner Tops With or Without Packers

6

Annular Gas Flow Prevention: Special Cements and Other Methods for Controlling the Problem ......................................................

page 6.1

Cement 7

Several Alternatives for Cementing Liners During Lost Circulation ................

page 7.1

8

Correct Techniques for Getting a Cement Squeeze on the Liner Top Top the First Time ...................................................... .......

page 8.1

Liners 9

5 Case Histories Detailing Field Procedures Providing Acceptable Results

................ page 9.1

Chapter

1.

Producing Better Results Over The Long Haul

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 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.

Cement from the top of the Liner Shoe

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

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.

Liner 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 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:

Intermediate Casing 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.

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 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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be achieved, displacing at a maximum flowrate was more effective than plug flow displacement.

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.

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 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 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. 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

Long 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.

Stabilizers

Bit Short or Long Drill Colar

Drill Collars

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.

Reamers Keyseat

Stabilizers

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

Packed Hole Assembly Vibration Dampener

Drill Collars

Bit

Pendulum

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. 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.

LITERATURE CITED FOR CHAPTER 1:

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.

For the references cited in this chapter, please refer to the back page, (all references for the entire document).

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Chapter

2.

Getting to the Bottom in the First Place

The most important aspect in setting a liner is

collar OD/2 (Figs. 10 and 11). Since most liners are characterized by close tolerances between the pipe and hole, it is essential that good stabilization be used while drilling to give adequate hole diameter and fewer doglegs.

getting to the bottom in the first place. Operators must drill a usable hole, prevent differential sticking by proper centralization and minimize wellbore collapse. The right kind of equipment is critical.

X = Bit diameter X ’= Effective hole diameter

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

Bit

FAILING TO GET A LINER TO BOTTOM can be very costly. A lost circulation zone or pay zone may not get covered, and another string of pipe or a liner may be required. As long as the liner is put in place successfully, almost any remedial work can be done on it, so getting to bottom in the first place is of the highest priority.

Path traveled by bottom of bit Path traveled by top of bit

In Part 1 of this series, (see World Oil, April 1988) the authors discussed the importance of rotating and reciprocating liners while cementing. In this part, aspects of creating proper hole conditions are examined, along with a discussion of different kinds of centralizer equipment and correct ways to install and run them.

Drift diameter =

Bit OD = Collar OD

Figure 11 - A spiral hole, caused by an unstabilized bit drilling in non-dipping formations will have a lower effective diameter than actual bit OD. (After Wilson)29

2

The authors strongly believe in packed hole assemblies to achieve this. According to Wilson29, a good assembly requires three stabilization points. As shown in Fig. 12, two points can contact and follow a curved line, but adding one more point eliminates this tendency.

Figure 10 - While drilling with an unstabilized bit, an abrupt change in hole angle can occur if hard ledges are encountered. To correct this, the minimum drill collar OD should be larger than twice the casing coupling OD minus the bit size. 28

GETTING LINER TO BOTTOM Liners don’t make it to bottom mainly due to four reasons: x A “usable” hole has not been drilled, i.e., the drift diameter of the hole is not equal to the bit diameter. x Differential sticking occurs because the liner was not centralized and became embedded in wall cake. x The wrong type centralizers and/or collar stops were used. x A “dirty” hole has been drilled , i.e., one full of bridges or fill.

PROPER HOLE CONDITIONS ARE CRITICAL There are many things that can be done to ensure that the liner reaches bottom in close tolerance holes (meaning holes with 1½ in. of of clearance or less). The first and foremost criterion is to drill a “usable” hole. Woods and Lubinski28 pointed out that in drilling slick (drill collars in the bottomhole assembly without stabilizers), the usable diameter of a hole is equal to the bit OD/2 plus drill Reprinted from World Oil magazine, May 1988 with permission from the authors.

Figure 12 - The packed bottomhole assembly results from the basic idea that three points cannot contact and follow a curved hole (After Wilson)29

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By using the maximum safe OD drill collars (drill collars increase in stiffness by the fourth power of the diameter) that can be used as a packed hole assembly (Fig. 13), the usable diameter of the hole approaches the bit size. The pony drill collar should not be too long, as shown in Fig 13. Mild

Medium

to minimize wallcake thickness. Not only will this improve hole diameter where every 1/16 in. can be vital, but it will also decrease the likelihood of differential sticking (Fig. 14). Low Water-Loss Mud

High Water-Loss Mud

Severe Thick Filtercake

Zone 3

String stabilizer

Contact Area

30-ft Large-diameter drill collar. Use short collar in 8¾” and smaller holes.

Thin Filtercake Formation

Vibration dampener (When Used)

Zone 2

String stabilizer

A

B A

C B A

A thin wall cake keeps the pipe from becoming deeply embedded, resulting in less torque and drag.30 Emulsified oil and dispersed gilsonite particles can help provide better particle size distribution, thus reducing its permeability and consequently the wall cake thickness. The goal should be to do whatever it takes to obtain a mud that gives a slick, thin, tough, low-permeability filter cake.

String stabilizer String stabilizer Bottomhole stabilizer

Bit

Another consideration that affects hole diameter is mud weight. If mud weights are below the pore pressures of certain hole sections sections, the wellbore diameter can be reduced by the plastic inflow or heaving deformation of the well bore. This can cause shale sloughing, which can cause bridges to be formed and ruin the chance of getting the liner to bottom. The causes for sloughing shales due to underbalanced drilling are analyzed and explained in great detail by Gill.31 This is a problem not recognized by many in the drilling industry. The “heaving” well bore problem is usually blamed on mud chemistry, which mainly affects dispersion or washing out of the well bore. This causes ledges and bridges, not well bore collapse.

Figure 13 - Additional string stabilizers are added to the packed hole assembly as deviation conditions increase from mild to medium to severe. The short drill collar size, located between zones 1 and 2, is determined by hole size. The hole size in inches should approximate the short drill collar length in feet, plus or minus two feet. (After Wilson.29) Also, the bottom two stabilizers should be full gauge. With the advent of oil-base muds and inhibited water-base mud systems that reduce washouts, the importance of stiff bottom hole assemblies cannot be overemphasized. This is the highest priority in getting a liner down. The operator can be assured that if a full-gauge stiff-packed BHA will go to bottom on trips, a liner with a smaller OD than the bit size will go unless the liner sticks differentially. The authors consider the use of too flexible BHA’s as the most common reason why some liners never make it to bottom. Centralizers (if they are used) or differential sticking are usually blamed. The authors have seen numerous 5 in. flush joint liners without centralizers stuck in 6 or 6 1/8 in. holes drilled with 4 1/8 in. drill collars without stabilizers. By applying Wood’s and Lubinski’s formula, the drift diameter of the hole is only 5.13 in. If a 5 in. liner is centralized, its maximum OD can become 5 ½ in or more.

WELLBORE COLLAPSE IN DEVIATED HOLES Drilling underbalanced is not the only cause of sloughing shall or well bore collapse. As stated by Aadnov and Chenevert,32 “by rotating the well bore from a vertical to a horizontal position, the analysis shows that the borehole becomes more sensitive towards collapse. For laminated sedimentary rocks, a plane of weakness may subject the well toward collapse for hole angles between ten and forty degrees.” According to the authors, this phenomenon can also be affected by the direction of the borehole. According to Bradley, the change in hole angle from vertical can necessitate an increase in mud weight as much as 2.5 ppg to prevent wellbore collapse.33 In deviated holes, therefore, often mud weights much higher than the highest pore pressures in the hole are needed to maintain wellbore stability. This is frequently not recognized, and pressure is sometimes applied to drilling supervisors to hole down mud density. Insufficient mud densities can cause difficulties during trips, showing up as fill or bridges when tripping into the hole or increased torque and drag while drilling or coming out of the hole.

Ashland considers it an acceptable risk to run a large-OD pony drill collar above a near bit stabilizer that cannot be washed over or caught with an overshot. We consider the chance that the pony drill collar alone will become stuck to be remote. If it does, it can be retrieved with a taper tap, or the hole can be sidetracked. In any event, the stiffer the pony drill collar, the closer the effective hole diameter is to the bit size. This may also cause a slightly larger hole if a roller cone bit is used. Another, but less obvious, method to ensure a usable hole is proper solids and rheological control of the drilling fluid. Good solids control results in a high native colloidal clay-to-silt ratio that produces a slick, thin wall cake. These type wallcakes will not only be thin, but should also have a low permeability. High native solids contents in the mud causes thick spongy wall cakes and a diminished hole diameter. Fluid-loss control agents should be used generously Reprinted from World Oil magazine, May 1988 with permission from the authors.

Borehole Wall

Figure 14 - A spiral hole, caused by an unstabilized bit drilling in non-dipping formations will have a lower effective diameter than actual bit OD. (After Wilson)29

Large-diameter short drill collar

Zone 1

Increased Contact Area

When sloughing occurs, the hole is washed out. The annular velocity in the washed out sections can become so low that the cuttings can be isolated from the annular mudflow and can not be circulated out. If the edges of cuttings coming over the shale shaker are rounded, this is indicative that they have been tumbled in the hole are not being lifted efficiently.

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The same problems can occur even though sufficient mud density has been used. Water-base lignosulfonate muds and other uninhibited muds can disperse and wash out the shales so that removal of drill cutting becomes inefficient. This can become more exasperating as wells become deeper and more thinners are added to the mud to control rheology. For instance, in a llignosulfonate mud system, it has been the authors’ experience that the well bore shales dispuerse along with the desired dispersing of the drill solids. The more the hole is washed out, the lower the cleaning efficiency of wellbore cuttings. The more thinner that is added to the mud to control its rheological properties, the lower its cleaning ability. Fill, bridges or increased torque and drag cannot be tolerated before a liner is run.

With all of these solutions, the cost involved must be considered. In any event, the hole has to be in proper condition to ensure getting the liner down. If it cannot be cleaned of bridges or fill, one last remedy is to run a mechanical set liner hanger with the slips removed or a hydraulic set liner hanger. This facilitates washing and reaming the liner down through bridges or fill. A special fishtail float shoe with cutting edges or a roller cone bit should be installed installed on the bottom of this type of liner job. The disadvantage of running a mechanical set liner with no slips is that the liner cannot be set on slips in tension. The full weight of the liner sets on bottom and can create a buckling problem. Generally speaking, this should only be a concern if there are plans to drill out below the liner, especially if there are major washed-out sections in the open hole. Wear points could be established that may develop into casing leaks. For production liners, the buckling could prevent the proper installation of packers, especially wireline set packers. If the buckling is severe, the packer problem usually may be resolved by merely running the packer on a workstring. Normally, this should not present a problem. For example calculations on this phenomenon, see papers by Durham,21 and Vangolen and Robertson.20 A hydraulic set hanger has the disadvantage of possibly setting prematurely due to high circulating pump pressures if reaming and circulating are required.

The best solution to a hole that cannot be cleaned adequately is to drill as close to a gauge hole as possible. This can be approached in water-base mud systems such as KCl muds, KLM muds, and other polymer muds that are available. Oil-base muds generally cause very low washing out of the well bore. Prevention of washed out areas is the best way to ensure adequate hole cleaning. If these muds can’t be justified because of environmental, economical or other concerns, the only recourse is to increase the lifting capacity of the mud. This can be done by increasing the pump rate, but this will only increase the hole washout. If the fracture gradient is high enough, increased pump rate could be used to clean the hole on the conditioning trip before running the liner. The yield point or viscosity of the mud could be raised, generally from two to four times the normal value. According to Hopkins,34 it is sometimes necessary to raise mud viscosity to 200 seconds per quart to clean well bores with near-water muds, depending upon the size and density of the pieces of cuttings. He also shows that a mud’s hole-cleaning capability for near-water muds is not significantly improved until the yield point is raised to above 15 LB per 100 sq. ft. Circulating the mud system until there are no more cuttings coming over the shale shaker may not mean that the hole is clean of cuttings, however. Early indications of inadequate hole cleaning, if sufficient mud densities are used, are increased torque and drag, bridges going in the hole or fill on bottom.

Finally, drill bits have been developed that will drill a hole larger than the ID of the previous casing string.35 The bit’s axis of rotating is different from its axis of symmetry. The eccentricity of the bits tried was fairly large, and in some cases they increased well-bore diameter between 1 and 2 in. This can be the critical difference in getting liners down in holes with tolerances of 1 in. or less.

CENTRALIZERS ARE VITAL Once optimum hole conditions to achieve a “usable hole” havebeen achieved, the next best insurance an operator should invest in is to equip all liners with centralizers, if the right kind are used and they are installed properly. In the authors’ opinion, centralizers do more to assure that a liner gets to bottom in high differential pressure, high permeability, long liner job environments than anything else except possibly oil-based muds or underreaming. In fact, it is nearly impossible to differentially stick a liner with centralizers on every joint of the liner if the centralizers are allowed to float (allowed to travel between stop collars or connections on the liner). If differential sticking does occur, it should be very easy to work the liner free. Most operators take the opposite view, however, because they feel that running centralizers in close-tolerance holes means that more steel has to be crammed into an already tight hole. There are plenty of stories about problems with centralizers, 14,16,17 but contrary to some of the literature, the authors have proven that this does not have to be a problem if proper preparations have been made. Slimhole centralizers (Fig. 15) are available specifically for these small clearances, and they greatly reduce the likelihood of differential pressure sticking between the liner and open hole. The forces at work with differential sticking are far higher than those from centralizers rubbing against the well bore. If the hole is prepared properly, there should be less drag in he open hole than in casing because of a lower coefficient of friction between the wellbore and centralizers, all other variables being equal.

If the well bore condition is such that the rheological properties of the mud cannot be raised without risking lost circulation (this increases the equivalent circulating mud density), then viscous sweeps can be considered. The larger the mud volume in the hole, the less of a chance the viscous sweeps will do much good. Once the viscous sweep starts going up the annulus, it will begin to channel and become diluted with the rest of the mud system, thus reducing its higher rheological properties and increased cleaning. Consequently, more than one sweep will be needed, as one sweep will only move part of the cuttings part may out of the hole. If sweeps are used, they should have a funnel viscosity and yield values of at least 200 seconds per quart and 45 LB per 100 sq ft, respectively. They should be spaced out so all cutting are not accumulated in one place at the same time in the annulus, which could cause packing off. They should definitely be used to clean a dirty hole if the liner makes it to bottom to avoid bridging over in the annulus (see Fig. 3, Part 1) before cementing begins. This problem can become expensive and very time consuming. The cheapest method may be in prevention of washouts. Inhibited mud systems and correct mud densities (within economical and ecological limits) are the best ways to avoid a dirty hole. On an offset well, if hole cleaning is known to be a problem, consideration could also be given to setting the last string of casing at a greater depth to achieve more fracture gradient. This will allow more viscous muds to be pumped around when it comes time to log the well and run the liner. Alternatively, the liner could be set shallower if the hole becomes dirty and the wellbore cannot be prevented from collapsing due to drilling underbalanced. It may also be solved by planning an extra liner or casing string. Reprinted from World Oil magazine, May 1988 with permission from the authors.

For illustration, assume two different operators are preparing to run a 5-in., 18-ppf liner from 10,000 to 11,000 ft. One intends to use centralizer and the other does not. Assume that drilling mud hydrostatic pressure exceeds formation pressure by 1,000 psi and the sand/shale content is 10% sand and 90% shale. The pull required to free the liner if differentially

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stuck can be calculated as follows:

F = (Δ P ) ( A c ) ( C f )

Figure 15 Slim-hole centralizers should be used in all close-tolerance holes. If designed and constructed properly, the bow springs will fully collapse in a tight hole environment, making them flush with the end collar of the centralizer. This is not true for casing centralizers (see Fig. 17). These type of centralizers generally add less than one-half in. to the casing OD. (Photo courtesy Gemoco Catalog.)

Where

F = F o r c e , l b

ΔP = D i f f e r e n tial pressure, psi Ac = C o n t a c t area, sq in. C f = C o e f f i c i ent of Friction (use 0.25) . It is assumed that a 2-in.-wide strip of the pipe wall is in contact with the borehole. Therefore, the contact area equals 1,000 ft of open hole multiplied by 2 in. and then by 0.1 to adjust for the amount of shale present where differential sticking is not occurring. This converts to 2,400 sq. in. For the liner run without centralizers, required force to pull it free once differentially stuck would be:.

F = (1,000 psi) (2.400 sq in) (0.25) = 600,000 lb: Assume that the increase in drag due to running API centralizers (the maximum starting force for any API centralizer will be less than the weight of 40 ft of medium weight casing of the subject size) is equal to the weight of the liner. This gives a total drag of only 18,000 lb. This is equal to only 3% of the total differential sticking force possible. Centralizers appear on the surface to hinder running the liner, but in the open hole, where it counts, they are essential. They can be a hindrance in holes drilled without stabilizers or where the wrong type of centralizers and/or stop collars were used.

Figure 16 Rigid centralizers can be run in place of bow spring centralizers. They are primarily recommended in high-angle holes to keep casing from touching between support points in the well bore. This positive standoff cannot always be achieved with bow spring centralizers if lateral forces exceed the bow’s strength. Another advantage is that cuttings cannot be trapped under the centralizer. (Photo courtesy Gemoco Catalog.)

On a well drilled and operated by Ashland in 1986 in Wharton County, Texas, an attempt was made to run 5-in. LT&C casing with the following conditions. A 7 ⅝-in. liner was set from 7,299 to 11,154 ft. A 6 ½-in. hole was drilled to 14,465 ft. Due to a problem with lost returns, the mud weight had to be reduced from 17.9 to 17.6 ppg to maintain full circulation. Some shale sections had pore pressure in excess of 17.6 ppg mud. This created sloughing shale problems and bridges on trips in and out of the hole. A decision was made to try and run the 5-in. liner and mechanical set liner hanger so that the liner (because of its length) could be set on slips to reduce buckling. Slim hole centralizers (Fig 15) were run one per joint and allowed to float. Liner length was 3,614 ft. The liner hit a bridge at 13,665 ft while going in the hole and could not be washed or reamed any deeper, leaving it 2,511 ft into the open hole. However, the liner was successfully pulled back out of the hole. It is doubtful that a liner run without centralizers could have been pulled back out without sticking. All of the centralizers were still intact and in place.

Figure 17 Casing centralralizers should not be run in close-tolerance holes. They are constructed for larger clearances to achieve maximum centering of casing. The bow springs are welded to and overlap the centralizer collar, creating an OD equal to the sum total of the casing OD, centralizer wall thickness, and bow s p r i n g t h i c k n e s s . ( Ph o t o courtesy Gemoco Catalog.)

A conditioning trip was made and the bridge at 13,665 ft was reamed numerous times. It was then decided to run the liner without a hanger but with a 6 ½-in roller cone bit made up on bottom. Free-floating centralizers with near gauge solid bodies (Fig 16) were run, one per joint, because it was felt that sloughing cuttings in the hole may have gotten under the bow springs on the slim hole centralizers and prevented them from collapsing completely in tight spots. The liner was rerun and went to bottom without washing or reaming. The authors are convinced this liner job could not have been accomplished without differential sticking of the liner had centralizers not been used. The liner was successfully cemented and 100% bonding achieved across the three zones to be tested. The liner was rotated at 40 rpm while cementing. It is imperative that the right centralizers be selected and that they are installed properly. Slim-hole centralizer must be used in close-tolerance holes. These centralizers are constructed so that when the bow springs are fully collapsed, they will be flush with the end collar of the centralizer. Casing centralizers (Fig. 17) are constructed such that the bow spring attached to the centralizer collar overlaps the centralizer end band, creating an OD equal to the total of Reprinted from World Oil magazine, May 1988 with permission from the authors.

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the casing OD, the centralizer end band thickness plus the bow spring wall thickness. The authors know of jobs where casing centralizers were called for and installed on flush joint liners that never made it below the previous string of casing. The centralizers bunched up on the liner because of too much friction, and the inferior stop devices allowed them to slip off the liner when pulling it out of the hole. Casing centralizers are for larger tolerance holes, while properly selected slim-hole centralizers generally add add only ½ in. to the minimum OD of the casing. Be certain that slim-hole centralizers are used in all close tolerance liner jobs.

desires to run a stationary centralizer above the float shoe, for instance. On flush joint or near-flush joint pipe, it is imperative that the proper stopping devices be used. Failure to do so can be disastrous. On one job, slim hole centralizers were run one per joint on a flush joint string of 5-in. 18.0-ppf P-110 Atlas Bradford FL4S casing with inferior stop collar devices. The casing was run to a TD of 14,950 ft in a 6 ½-in hole. It was found from a casing-hole collar log (a radioactive centralizer was used on the casing to help prevent perforating out of zone) that the radioactive centralizer had moved up the hole over 300 ft.

Not all slim-hole centralizers are of equal quality and design. Hinged type latches on slim-hole centralizers should not be used in closer tolerance holes. Use only slip-on close tolerance centralizers. Hinged on centralizers are weaker than the solid end band slim-hole centralizers and can spread or break if the centralizer band is wedged against the upset or collared casing. Hinge latches protrude more than solid end band centralizers, causing additional annular restring when space is already limited. If hole clearances allow the use of collared liners, installing hinged slim-hole centralizers around the casing collar, casing upset or stop collar is also a poor practice. This causes an additional restriction, because the bow spring thickness is then added to the casing collar OD, upset or stop collar. There is also the additional hazard of the tapered underside of the bow spring wedging against the coupling, upset, or stop collar, causing multiplied stresses to split apart the hinged end band. Should the liner have upsets on both the pin end and box end (which precludes slipping on solid end bands), then a certified welder at the well site should split the end bands and re-weld them after they are slipped on. This would be required for liners with Exline connections, for instance. A good welder must be used to ensure that the hardness of the casing is not adversely affected.

On another job, an operator had 9 5/8-in. casing set at 12,940 ft. An 8 ½-in. hole was drilled to 13,300 ft with 14-ppg mud and a pendulum drilling assembly with the first stabilizer 71 ft above the bit. Due to lost circulation, mud weight could not be increased high enough to eliminate fill. Plans were made to set a 7 5/8-in., 33.7-ppf, P-110, flush joint liner to at least 13,283 ft. An 857-ft liner assembly was picked up with slim-hole centralizers installed one per joint on the bottom seven joints. Two more centralizers were ran in the overlap area. The liner could not be run below 13,179 ft. While attempting to wash the liner down, it became stuck. Attempts to jar it free with spotting agents proved futile. The liner was subsequently fished out to 13,060 ft. Two of the five centralizers that should have come out with the fished out liner were left in the hole. It was also theorized that the bottom centralizers may have bunched up together, and that this was the reason the liner did not go to 13,283 ft. This liner probably became differentially stuck, since it was not centralized across known sands. The remainder of the liner was milled up and the hole reconditioned with a packed hole assembly. A different collar stop was used on the next 7 5/8-in. liner attempt with the same centralizer arrangement and was ran successfully to the desired depth.

After the correct slip-hole centralizers have been selected, it is imperative that they be installed properly so they can be used to the maximum advantage and not interfere with getting the liner to bottom. As mentioned previously, centralizers should not be installed over collars, upsets, or stop collars to minimize annular restriction. Rather, centralizers should be allowed to travel freely between stop collars or casing collars. Other authors have shown this same preference with good results.16,19 This also allows the liner to be reciprocated or rotated without movement of the centralizer. The centralizer acts as a downhole bearing bushing. This increases (rather than decreases, as stated by some) the chances of rotation or reciprocation. Some operators have concerns about running centralizers in this manner. They fear that by allowing the centralizer to float, the bottom edge of the centralizer collar may hit an obstruction, collapsing the centralizer and breaking the bow springs. The authors cannot envision any open hole scenario where this would occur, but it could occur while the centralizer is going through an existing liner top or in a blowout preventer cavity. But if the proper slim-hole centralizers are used that have a taper on the bow spring and precautions are taken to slow down the running speed when entering the top of another liner or window, this concern is not valid, as evidenced on many liner jobs.19 Free-traveling centralizers help reduce the drag and torque for reciprocating or rotating the liner. Centralizers not allowed to slide up and down or rotate are going to increase drag while reciprocating and increase torque while rotating. Centralizers, if run the entire length of the liner and the correct number are used, can greatly reduce buckling in washed-out holes. Some slim-hole centralizers, for instance on a 5-in. liner, can add over 2 in. to the minimum OD if they are not collapsed once the liner is in place. This will reduce wear points while drilling and difficulty in running tools inside the liner.

Centralizers can bunch together in close tolerance holes with flush joint liners if inferior stop collar devices are utilized. Friction lock or bolt and nut clamp stops are not desirable for liners because of their limited holding capacity and tolerance (their bolt and nut section protrudes approximately 0.75 in. from the casing surface). Hinged or latch-on stop collars should not be used on liners for the same reasons mentioned concerning latch-on type centralizers (strength and tolerance). Some set screw type stop collars have too low a wall thickness, which limits the amount of torque that can be applied to the set screws. The less torque that can be applied, the less force required to move the stop collar. Properly selected set screw type stop collars have more wall thickness, which allows more torque to be applied to the set screws without stripping. The more torque that can be applied, the more force required to move the stop collar. The authors recommend that even the best set screw type stop collars be used on flush joint or near flush joint liners only in straight holes and where good hole conditions are evident on trips. Their use could be extended to critical wells if liner connections are Hydril’s Triple Seal or SFJ-P (Fig. 18) or similar, since the upsets would serve as a backup should the set screw stop collars start to slide. Premium stop collar devices are those that have slip segments which grip the casing in opposing directions at four points. Slips are carburized and heat treated, resulting in a hard, tough surface. This hardness allows the slips to bite deeply into the casing. These lath-turned collars are streamlined and are only ⅝ in. over pipe size.

Once the proper centralizer has been selected, the next critical choice is to select the proper mode of keeping the centralizers from bunching together on the liner while it is being run. This is especially critical on flush joint or near-flush joint liners. Stop collar devices are not needed on liners with collared connections such as 8 round, except when the operator Reprinted from World Oil magazine, May 1988 with permission from the authors.

Proper installation of these type stop collars is more “weevil-proof” when the opposing slip connectors only have to be hammered down flush with the stop collar to hold. The only exception to this would be if the casing joint

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was measurably undersized. Set screw stop collars would be best if this rare condition exists. If goes without saying, that all areas of the liner where the stop collars are to be installed should be checked out for roundness. Noticeably less distortion occurs in the roundness of slip type stop collars after installation. Set screw type stop collars, however, have high points at each set screw position, which make them more vulnerable to drag forces and restrictions going into the hole. The less experience the person installing the stop collars, the more aggravated this situation becomes. Slip-type stop collars have been used successfully to keep centralizers from sliding up flush joint casing in 72º holes offshore Louisiana. On one deviated well, a flush joint liner failed to make it to TD. Maximum hole angle was 61º. The liner had to be pulled back out of the hole. And the operator was convinced that the centralizer had bunched together and would not be on the liner when it was pulled. However, all centralizers were found intact and all the slip-type stop collars were still in place. The liner was rerun successfully after a conditioning trip by picking up some drill collars to run on top for more weight. This liner would never have gone down without centralizers due to the high mud weight and numerous permeable sands.

Note Upset

Figure 18 - Liners with slightly upset connections should help ensure that stop collars and, consequently, centralizers will not bunch up downhole. Shown is the Hydril Triple Seal connection.(Courtesy Hydril.)

Slip-type stop collars are not recommended for flush joint casing grades above S-125. Grades such as V-150 are too hard for for the slip segments to get a sufficient grip. If super high-grade liners have to be centralized, then near flush joint pipes with a slight upset should be used. If tolerances are too close for the operator’s comfort, consideration should be given to a smaller liner with collars or larger upsets to allow centralizers.

“In the above case, it takes 700 ft-lb, (4,200 minus 3,500) to overcome bearing friction, plus 1,000 ft-lb to rotate only the drill string. All 1,700 ft-lb of torque is above the top liner joint and must be added to the maximum permissible liner joint torque of 5,500 ft-lb. Therefore, maximum allowable joint torque surface torque to initiate rotating, and for the duration of the job is 7,200 ft-lb—not 5,500 ft-lb. Even though torque during rotation will probably be much less, required starting torque can approach the maximum level. Stopping at any lower torque figure at any point would be considered an unsuccessful job— a failure to rotate.”

Safely installing close tolerance centralizers and stop collars on flush joint casing grades above S-125 is still a challenge to the manufacturers because of its extreme hardness or brittleness. If super high grade liners have to be centralized, then consideration should be given to running a smaller liner with collars or larger upsets. If liner size cannot be reduced, then consideration should be given to using connections such as Triple-Seal to provide a backup stopping device for the stop collar or centralizer.

If the operator has a rig that is not equipped with a torque indicator, there are ways to estimate the downhole torque from the number of rounds of turn to start rotation of the drill pipe.This data was compiled from API Bulletin RP 5C-1 (See Table 1).

Many liners have been rotated successfully or reciprocated without running any centralizers, or by running a few of them near the bottom of the liner.15 This can be accomplished in areas of long shale sections or across sands that have low permeability or low differential pressures. The authors strongly believe in running centralizers on all liners from top to bottom. It is doubtful that a long liner run in South Louisiana type environments or directional holes could be rotated or reciprocated for long without centralizers. High sand-to-shale ratios, hydrostatic mud pressures about 3,300 psi30 higher than formation pressures, and sands with good permeability are highly likely to cause liners without centralizers to become stuck. Centralizers should be run on all liners to ensure getting the liner to bottom, being able to move the liner, and to improve the chances of a cement job. The authors have typically observed a reduction in torque of 50% to 100% when rotating liners on bottom versus rotating the drill string on bottom at the same rotary speed. In a recent liner job in Cameron Parish, LA, backlash was reduced from three-fourths of a round of backlash with the drill string at 40 rpm to less than one-eighth of a round of backlash with the liner on bottom at 40 rpm, because centralizers reduce the amount of liner area rubbing against the irregularities of the wellbore.

TABLE 1:

Liner Allowable Size make-up torque (in) API threads ft-lb

The inability to rotate liners, according to Lindsey,16 often is due to insufficient starting torque: “For example, assume a liner joint has a maximum allowable torque rating of 5,500 ft-lb and that rotating drill pipe and liner before hanging requires a torque of 3,500 ft-lb. After hanging the liner and releasing the setting tool, torque required to rotating only the drill pipe is 1,000 ft-lb, and rotating drill pipe and liner totals 4,200 ft-lb. To calculate maximum allowable surface torque, the torque required to rotate drill pipe only and the torque to overcome bearing friction must be added to the maximum permissible liner joint torque of 5,500 ft-lb.” Reprinted from World Oil magazine, May 1988 with permission from the authors.

Estimating downhole torque from drill pipe windup Source

Turn wind-up in drill pipe for given torque 10,000 ft. string 3 4 3½ - in drill pipe

4½ - in drill pipe

9.5 ppf 13.3 ppf 15.5 ppf 13.75 ppf 16.6 ppf 20.0 ppf

13½

2.550

1

6.7

5.2

4.5

2.9

2.3

2.0

14

2.900

1

7.1

5.9

5.4

3.3

2.7

2.3

14½

3.250

1

8.6

6.6

5.8

3.7

3.0

2.6

15

3.600

1

9.5

7.3

6.4

4.0

3.3

2.8

15½

4.000

2

10.6

8.1

7.1

4.5

3.7

3.1

16⅝

4.700

2

12.4

9.5

8.4

5.3

4.3

3.7

17

5.700

2

15.1

11.6

10.2

6.4

5.3

4.5

Notes: 1 Projected from datea, API Bulletin RP 561 and plotted graphically 2 API Bulletin RP 501 3 These values computed without allowance for friction. As an example: With 5½ - in liner and 4½ - in 13.75-ppt drill pipe at 4.5 turns, you will not reach the allowable make-up torque of 4,000 ft.-lb due to friction of the drill pipe in the hole. Therefore, the above number of turns are very safe practice for a 10,000-ft. string 4 Based on ( ) = TL/KG string 95% drill pipe and 5% tool joints. Friction-less conditions Effect of drill pipe tension not computed Stresses not computed

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To expand on the example, assume that 2,800 ft-lb is the maximum torque to be applied to a 4 ½-in. liner at 10,000 ft. By using the chart, it is estimated that 7 1/8 (2800/2.550*6.7) rounds of backlash would be required at the surface to impose 2,800 ft-lb on a 4 ½-in. liner at 10,000 ft using 3 1/2”-in. drill pipe. Friction could cause an increase in torque at the surface several times that at the bottom of the drill pipe. This should be kept in mind when initiating liner rotation. The authors have been unable to find any operator that has ever twisted off a liner connection. We have heard this concern raised many times, but have been unable to substantiate that it has happened. We do not consider this a serious concern if good hole conditions and proper centralizer installation exists. If a packed hole assembly described earlier and the right centralizers and stop collars are used and installed properly, the liner will go to bottom. Centralizers are vital to liner reciprocation or rotation. Admittedly lots of liners don’t make it to bottom. In every case investigated, an unusable hole was drilled or the wrong centralizer equipment was used. It’s a high-risk task to try and run a liner with centralizers in a hole drilled without stabilizers. If the friction doesn’t grab the liner due to increased wall contact from a hole drilled spirally without stabilizers, then differential sticking can occur.

OTHER MECHANICAL AIDS Scratchers and coating materials (used to improve hydraulic bonding strength of the casing) applied to the exterior of the pipe are not recommended in long, high differential pressure, high permeability, close tolerance environments. Scratchers and rough coating material tend to scrape off wall cake, thereby communicating hydrostatic well bore pressures to formation pressures. This can cause differential sticking. Since scratchers have proven to be beneficial to cementing, they should be used in hard rock, low permeability areas. Cable wipers can be run across pay zones in Gulf Coast environments if the hydrostatic pressure of the mud is not 3,300 psi or higher than reservoir pressure. 12 They should only be used a maximum of 40 ft above, through and below pay zones.

SPIRAL GROOVED CASING Another technique for getting a liner to bottom when differential sticking is a concern is to use pipe with spiral grooves on the O.D. The helical grooves reduce pipe contact with the wellbore by as much as 40 to 50%, reducing the potential for differential sticking, and also helping reduce torque and drag during rotation and reciprocation.

OTHER TECHNIQUES Another approach for consideration is to spot an oil-base agent in the open hole on the last conditioning trip before running the liner. The oil-base mud does not form a wall cake and reduces friction. The authors recommend this procedure if the drill string has experienced differential sticking in the open hole where the liner will be located. Chemical spacers should be used ahead and behind the oil mud to avoid an oil-base-water-base interface. Walnut hulls or beads (glass or polymer) may also be added to the oil mud to reduce friction. A final technique that should be used on all jobs is to keep the liner moving once it gets into the open hole. The drill string should not be stopped to fill up the inside of the drill pipe. This is especially critical when differential sticking is a problem, since it generally occurs when the pipe is not moving. Of course, collapse values of the drill pipe and liner should be checked to ensure that they’re not exceeded when drill pipe filling is halted. Reprinted from World Oil magazine, May 1988 with permission from the authors.

LITERATURE CITED FOR CHAPTER 2: For the references cited in this chapter, please refer to the back page, (all references for the entire document).

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Chapter

3.

A Few Precautions to Reduce the Risk of Flash Setting

Flash setting of cement around the drill pipe

by a buildup of cuttings that are carried by an annular velocity that that is higher around the liner (due to its larger OD) than around the drill string.

is a serious hazard, leading some operators to abandon the idea of single-stage cementing or to disengage the setting tool prematurely. But a few precautions can reduce the risk of flash setting to a minimum.

x Superior hole cleaning ability of cement compared to drilling fluid, which causes a cuttings accumulation in the annulus and subsequent bridging in the annulus or around the liner hanger and sudden dehydration of the cement (See Figure 3, Part 1).

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

There are several measures that can be taken to minimize some of these problems. The first is to ensure that the hole has been circulated clean (this should also include lost circulation material). In the authors’ opinion, inadequate hole cleaning is the primary reason for premature setting of cement. This is especially true in hard rock areas where drilling frequently is done underbalanced and with near-water muds that have little buoyancy for cleaning.1

WITH ALL THE MODERN TECHNOLOGY of equipment and cements, there is still the fear of cement “flash setting” around the drill pipe and cementing it in the hole. This can lead to the “management out of fear” philosophy that no cement will be circulated on top of liners. Some operators have not surrendered completely on the idea of cementing a liner in one stage, but they do disengage from the liner before cementing. It seems it is okay to take the risk that the cement might flash set around the drill pipe, but not to take the risk of being unable to disengage the setting tool from the liner hanger. The authors do not agree with either philosophy.

Heaving shales cause large washed out sections, and if the shale section is above a consolidated formation, ledges are formed where cutting tend to be isolated from the annular mud flow. The washed out areas can become so large that annular velocities as low as 20 to 30 fpm are not uncommon. Circulating the mud system for days will not clean this type of well bore. Thus, when a liner is run and cemented in this environment, it is readily apparent that the superior hole sweeping efficiency of the cement (due to its higher density and higher rheological values) can cause a cuttings accumulation that can choke off the annulus or bridge against the liner hanger where a circulating restriction exists.

The problem with using a planned squeeze program on all liners is that a necessarily small volume of cement must be pumped (especially if there is a low displacement efficiency ratio) to avoid getting cement on top of the liner. Unless the liner is relatively long (which means more cement could be used safely, and consequently contact time around the shoe would be increased), chances are that not just the liner top will have to be squeezed, but also the liner shoe. If it is a production liner, a squeeze may have to be performed opposite the pay interval. If there are multiple pay zones, then multiple squeeze jobs could be required. This is a high price to pay for a timid approach to liner cementing. But this is done routinely.

To ensure better hole cleaning by the drilling fluid, its density could be raised to limit the heaving shale problem (this would also limit gas influx if there are right gas zones present that are being drilled underbalanced), which should give closer-togauge hole and consequently a higher annular velocity. The higher density mud would also reduce the slip velocity of the cuttings. The yield point, and consequently, marsh funnel viscosity of the system, also could be raised to reduce cuttings slip velocity, as described earlier.

As for single-stage cementing after disengaging from the liner, there is very little insurance gained with this approach. The fear of flash setting cement may be the reason for getting off the hanger before cementing, but very little time is gained by being detached from the liner. If the cement flash sets, the drill pipe will be cemented in the well in either case.

Another prudent practice to reduce cementing problems is to batch mix all cements used for liners. Batch mixing should be insisted on for all critical jobs. This should eliminate fluctuations in the water-to-cement ratio that is so vital for predictable times and water loss values. Also, the cement and mix water used for lab testing should be the same as that used on location. Under no circumstances should circulation be stopped with the liner in the hole before all of the cement and spacer is mixed and ready to be pumped down the hole. On one job, the chemical wash spacer was pumped into the drill pipe before all the cement was batch mixed. A problem developed in mixing all of the cement. While trying to remedy the problem, circulation was held up for 20 minutes. After deciding that the liner could become stuck, we aborted trying to fix the mixing problem and proceeded with the job. Less than half of the cement got mixed, and consequently squeeze work had to be done on the liner top. This is especially critical on long liners where mixing of cement is still going on after the cement turns the float shoe to ensure continuous circulation to help maintain liner movement.

PREVENTING FLASH SETTING A flash set liner job does not go wrong because the operator failed to get off the liner, but because the cement set up before it should have. Industry accepts the fact of flash setting cement but does not accept getting caught attached to the liner. Getting off the liner first gains very little and gives up a lot. Disengaging from a liner hanger normally will take less than 5 minutes. One author does it routinely in less than a minute. With no liner movement, the chances for a channeled cement job increase, probably necessitating a squeeze inside the liner if it is a production liner. With proper planning, the problem of flash setting cement can be minimized. Flash setting cement is a problem that cannot be overlooked, but neither should it be debilitating. There are no mysterious reasons that cause cement to flash set. Do cements mysteriously flash set in the lab? Of course not. It is believed that cements flash set for one of four reasons:

Use low-water-loss cement to minimize circulating pressures on the formation and the chances for sudden dehydration in the narrow annulus or across permeable zones. With regular cement, growth of the cement cake may cause an increase in circulation pressure (See Figure 20). On wells with lost circulation potential, the authors do not encourage density differences of over 0.1 to 0.2 ppg between mud and cement, if possible. This limits free fall, which could cause the fracture gradient to be exceeded, and also make latching up of the drill pipe dart to the liner wiper plug easier to detect. There should then be a pressure decrease when shear occurs. Under no conditions should lost circulation material be added to liner cement, as this could also cause bridging in the annulus.

x Improper pump times due to improper cement testing. x Incorrect density of the cement mixed on location, which varies pumping times and water loss properties. x Plugging, and thus elimination of flow, in the annulus caused Reprinted from World Oil magazine, May 1988 with permission from the authors.

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Once the liner is in position, mud should be circulated around twice surface to surface. During this circulating period, the rheological properties of the mud should be lowered to a safe minimum to increase the mud’s fluidity. In particular, the 10 minute gels and fluid loss properties should be minimized.25 Liner movement or rotating improves the rate and efficiency of moving out dehydrated gelatinous mud. A high-water-loss mud located across permeable zones will dehydrate and become harder to move by spacers and cement. If the mud system is a water-base lignosulfonate, water should be used as much as possible to achieve the desired thinning of the mud, since lignosulfonates act as a retarder to cement. If the well is close to losing returns, we also take this opportunity, while treating the mud, to lower the mud weight by 0.2 to 0.3 ppg (normal trip margin built into the mud density). Screen out all lost circulation material. This increases the chances of circulating cement (if lost circulation is a concern) and should increase the mud’s mobility and the displacement efficiency ratio of the cement to mud.25 Another advantage of conditioning the mud system is to check for washouts that may be developing in the drill string or liner. The authors know of one job where a washout developed in the drill string and cement was returning to surface while cement was still being mixed. The primary cement job had to be abandoned and numerous squeezes performed to cement the production liner adequately. Once the liner is in place, bottoms up should be closely monitored for trip gas, (if any) and that it doesn’t arrive much later than it should have. A large delay could be indicative of a washout developing. Of course, pump pressures and pump rates should be continuously monitored while circulating for evidence of a washout. If numerous washouts have been developing in the drill string during the course of drilling the well, consideration should be given to hydrostatically testing the drill string before running the liner.

Cement Filter Cake Begins to Form

Permeable Zone

Cement Filtrate Lost to Permeable Formation

The authors also believe in generous amounts of chemical spacers. We normally run a minimum of 700 to 1,000 ft annular volume of spacer to displace as much mud as possible.12 This is done to increase contact time around the liner without using a lot of cement so as to limit the height of the cement on top of the liner. If the mud is high density or an oil-base mud, the mud displaced out of the hole by the spacer may also partially offset part of the spacer cost. Money for spacers is money well spent. If all these precautions are taken, there should be very little likelihood the cement will flash set (or suddenly dehydrate) due to bridging in the annulus or having insufficient pump time. In the discussion of possible reasons for flash setting cement, one very interesting probability is disguised. Of all the problems that can lead to flash set cement, they should all occur inside the drill pipe, liner or annulus. If precautions described earlier are taken before the liner is cemented, this is extremely unlikely. If cement is going to flash set, then it should happen before it reaches the top of the liner, assuming it was batch mixed, tested properly, the hole cleaned properly, and the cement given adequate pump time.

Permeable Zone

Another variable that reduces the likelihood of cement flash setting on the liner top is that this is the lead slurry, and thus should be the most contaminated by drilling fluids. Also, the pump time for the lead cement was probably designed for higher bottomhole temperatures and pressures at the bottom of the liner. If the mud is water-based with lignosulfonates as a thinner, then lignosulfonates act as a retarder to the cement’s pumping time, further reducing the chances of flash setting. All other cementing problems most likely would occur before the cement gets to the liner top if the pump time was sufficient for the job.

Displacement Pressure Rises

Once cement has been pumped into place properly and the operator has reciprocated or rotated the liner, the next crucial step is to disengage the setting tool from the liner hanger. Together, the authors have had no problem since 1966 of cementing drill pipe in the hole. This includes over 300 liner jobs run by one of the authors. Reprinted from World Oil magazine, May 1988 with permission from the authors.

Figure 20 - Low-water-loss cements minimize circulation pressure on the formation and reduce the chances of sudden dehydration. With regular cement the growth of a cement cake can cause circulation pressure to increase. (After Syker)37

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If a problem should occur, there are two remedies that should have been planned for before the job. Pressure relief subs can be run on the top of the liner hanger and set to open with a pressure above the pressure needed to bump the plug, but below the burst rating of the work string. This will allow reversing out of cement in an emergency. We do not recommend this approach because they can pre-shear at too low a pressure, making this approach too risky.

As mentioned previously, liner cement jobs are especially susceptible to channeling. The authors have reviewed liner jobs in different areas and calculated the percent of displacement efficiencies (cement volume divided by annular hole volume).25 It is seen that the higher the displacement efficiency, the less channeling has occurred, and the lower the displacement efficiency, the more channeling has occurred. We have found displacement efficiencies as low as 20% on some liner jobs and as high as 100% on one job (there was 100% bonding to the top of the cement). One study showed displacement efficiencies between 60% and 93% despite rotation of the liner on most jobs.18 The authors witnessed a job in which cement was reversed close to 2,000 ft above the top of the liner when the job had been planned for only 200 ft of cement on top of the liner. As can be seen, accurate prediction of where cement is going to end up can be very difficult. Of course, the higher the displacement efficiencies, the better the chances for a primary cement job in the appropriate places and the better the chances the cement top will be where it was planned.

Another alternative is to bullhead a proper amount of mud down the intermediate casing-drill string annulus and force cement through the liner overlap. Care must be taken that enough mud is pumped to clear the annulus around the drill string of cement. The latter procedure is recommended if the pressure integrity of the intermediate string is felt to be sufficient to allow breaking down the intermediate casing shoe (a leak-off test would be advisable to help in planning). If there is serious doubt about the pressure integrity of the intermediate casing, a pressure relief sub could be considered, but the authors have never deemed well conditions critical enough to justify their use.

Hard and fast rules are hard to quantify when figuring percent excess of cement to pump on liner jobs. As reported by Arceneaux,14 cement volumes for the one-stage technique are determined from the caliper or integrated hole volume., with an excess of 15% to 30% added, the volume in the liner overlap and 200 to 300 ft above the liner top. This goes along with Graves13 post cement findings. Two other large variables should be considered—the displacement efficiency and the length of the liner.

On all high-pressure gas production liners, some means of releasing casing pressure should be provided should the liner top fail at a later time1 (in fact, the precaution should be taken for any string of casing that might not be able to withstand packer or tubing leaks). A choke and bursting-disc type arrangement including pop valves and regulators installed on the casing annulus would be desirable to avoid bursting the intermediate casing should the liner top give way.

For instance, assume we wish to cement a 500-ft 7 5/8-in liner in a 8 ½-in hole that is washed out to an average hole size of 9 ½-in. Assume a 200-ft overlap inside of 9 5/8-in 47.0 ppf casing and 200 ft of cement is desired on top of the liner when the job is complete. Assume also that the liner can be rotated and that a displacement efficiency of 80% can be achieved in the open hole. Add 30% excess to the open hole volume for cementing the open hole. Assume the volume of cement left inside the liner is negligible. With 80% displacement efficiency, the top of the cement calculated to end up +255 ft above the top of the liner. Not too bad!

Another situation that could arise at a later time on an unattended well is a failure at the liner top that would leak gas but not accept the fluid in the annulus. This could allow the trapped pressure of a gas bubble to rise to the surface and subject the wellhead and intermediate string to a pressure equal to BHP at the liner top. As pointed out by Goins,37 if gas is not allowed to expand, BHP is on the wellhead at the time the gas reaches the surface. The cause of liner top leaks and the problems they present will be discussed in greater detail in a future article.

Assume the same variables above except that the length of the liner in the open hole is 4.000 ft. Assume a displacement efficiency of 60% in the open hole (not at all unrealistic on a long liner). This will put the calculated top of the cement at +1.086 ft above the top of the liner. If a loss of circulation potential exists, returns will probably be lost on this well and the amount of pump time needed to safely “run” from the cement if it can’t be circulated out increases.

CALCULATING CEMENT VOLUMES Calculating how much cement to use on a liner job is much more complex than just reading a caliper. In fact, this can be the most difficult part of the liner design. The combination of both small clearances and large, washed out sections, low displacement rates needed to minimize equivalent circulating densities and the inability on most liner jobs to put heavy cements in turbulent flow makes channeling of cement likely. This makes it nearly impossible to plan the placement of cement columns precisely.

As noted previously, one well had a calculated displacement efficiency of 20%. The range of displacement efficiencies from 20% to 100% are dependent upon many variables. Common sense must necessarily dictate what percent excess to use. On deep, hot directional wells with no pipe movement anticipated, and where low displacement are dictated because of lost-circulation fears, very low displacement efficiencies can be anticipated and cement volumes should be reduced accordingly. If the holes are straight, the liner can be reciprocated or rotated, and the well allows a pump rate sufficient to put the cement in turbulent flow, an 80% or higher displacement efficiency can be anticipated.

Of course, caliper logs should be the first bit of information gathered before calculating cement volumes. Caliper logs can be run using two-, three-, or four-arm devices, all of which will read the same in round holes, but not in elongated or elliptical holes. For calculating cement volumes, four-arm calipers should be utilized to give the best estimate of hole volume since, according to various logging service companies, hole volumes measured by two-arm and four-arm calipers can vary by as much as 25%. A recent study showed variations in hole volumes between caliper surveys anywhere from 9.41 to 49.86%.13 This same author came up with some other noteworthy observations. Graves showed that hole volumes after logging can increase on the average as much as 31%.13 Based on this excellent study, it is easy to conclude that four-arm dipmeters should be run on all liner cement jobs, and that much more cement may be required than calculated hole volumes from calipers would suggest. The economics are there to have as accurate of an estimated hole volume as possible. Equally important is the need to estimate accurately the amount of channeling that may occur. This further illustrates how difficult pumping the right volume of cement can be. Reprinted from World Oil magazine, May 1988 with permission from the authors.

On liners 500 ft or less, we normally recommend 100% excess over calculated hole volume. On long liners, 3,000 ft or more, we would not recommend over 30% excess. Unfortunately, educated guesses are the best we can hope for on some jobs, as they do not always lend themselves to analytical evaluations.

LITERATURE CITED FOR CHAPTER 3: For the references cited in this chapter, please refer to the back page, (all references for the entire document).

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Chapter

4.

Procedures and Recommendations for Preparing the Liner for Testing

L iner running procedures are outlined and

8. If unable to continue circulation while cementing, due to plugging or bridging in liner and hole wall annular area, pump on annulus between drill pipe and liner to maximum _____ psi and attempt to remove bridge. Do not overpressure and fracture the formation. If unable to regain circulation, pull out of liner and reverse out any cement remaining in drill pipe.

recommendations are given for preparing the liner for testing.

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

9. Slow down pump rate just before pump down plug reaches liner wiper plug. Drill pipe capacity is _____ bbl. Watch for plug shear indication, recalculate or correct cement displacement, and continue plug displacement plus _____ bbl maximum over displacement.

ASSUMING A USABLE HOLE has been drilled and correct equipment has been selected, as discussed in the first three installments of this series, it is now time to run and cement the liner. In this installment a recommended running procedure is given in addition to the description of an unusual phenomenon that can occur and possibly startle the rig site supervisor. Finally, preparations for testing the liner are discussed.

10. If no indication of plug shear is apparent, pump calculated displacement volume plus _____ bbl (100% + 1 to 3%). 11. Pull out 8 to 10 drill pipe stands or above top of cement, which ever is greatest. Hold pressure on top of cement to prevent gas migration until cement sets. (Note: The authors recommend circulating out at this point for reasons described late in this article.)

LINER RUNNING PROCEDURES The following procedure is taken from API Bulletin D17. The reader will note that it should be modified if the intent is to reciprocate or rotate the liner. The procedure is as follows:

12.

Trip out of hole.

13. Wait-on-cement _______ hours.

1. Run drill pipe and circulate to condition hole for running liner. Temperature subs should be run on this trip if bottomhole circulating temperatures are not known. Drop hollow rabbit (drift) to check drill pipe ID for proper pump down plug clearance. On trip out of hole, accurately measure and isolate drill pipe to be used to run the liner. Tie off remaining drill pipe on other side of the racking board.

14. Run ______ in. OD bit and drill cement to top of liner. Test liner overlap with differential test, if possible. Trip out of hole. 15. Run ______ in. OD bit or mill and drill out cement inside liner as necessary. Displace hole for further drilling. Spot perforating fluid (if in production liner) or other conditioning procedures as desired.

2. Run ______ ft of _____ liner with float shoe and float collar spaced _____ joints apart. Run liner plug landing collar _____ joints above float collar. Volume between float shoe and plug landing collar is _____ bbl. Sandblast joints comprising the lower 1,000 ft and upper 1,000 ft of the lner. Run thread locking compound on float equipment and bottom eight joints of liner. Pump through the bottom eight joints to be certain that float equipment is working.

If reciprocation or rotation of the liner is planned, the authors recommend the following additional practices: Generally speaking, drag19 starts becoming excessive in wells whose maximum angle exceeds 35˚ and rotation should be planned for these holes if liner movement is desired.

3. Fill each 1,000 ft of the liner while running, if automatic fill up type equipment is not used.

x For wells with hole deviation 35˚ or less, one floating slim hole centralizer per joint is adequate to give the necessary standoff to minimize differential pressure sticking and the torque and drag reduction required.

4. Install liner hanger and setting tool assembly. Fill dead space (if pack-off bushing is used in lieu of liner setting cups) between liner setting tool and liner hanger assembly with inert gel to prevent solids from settling around the setting tool.

x For wells with hole deviation over 35˚, two floating slim hole centralizers are recommended for every other joint with one floating slim hole centralizer on the other joints. x For wells with hole angles over 60°, the authors recommend two floating centralizers on every joint. However, starting forces of the centralizers should be checked when running this many centralizers. Consideration may have to be given to running drill collars on top of the liner in these type holes to provide sufficient weight to get them down. One of the authors has successfully rotated mechanically set liners in the 60° holes offshore Louisiana with this centralizer arrangement. (As discussed by Smith9, in direction holes the resistance to flow is the lowest on the upper side, but on the lower side, mud channels are formed. If during cementing on a long liner, the liner contains a rather heavy cement compared to the mud, the total load on the centralizers becomes greater than the simple weight of the liner. Since the heavy cement fills the annulus and the lighter displacing fluid is in the casing, this can cause the liner to float against the upper portion of the hole. The more centralizers that are used, the better the chances of having the liner centered in the annulus).

5. Run liner on _____________ (size, type connection, weight, and grade) drill pipe with _____________ pounds minimum over pull rating. Run in hole at 1 to 2 minutes per stand in casing and 2 to 3 minutes per stand in open hole. Circulate last joint to bottom with cement manifold installed. Shut pump down. Hang liner five feet off bottom. Release liner setting tool and leave 10,000 pounds of drill pipe weight on setting tool and liner top. 6. Circulate bottoms-up with _____ barrels per minute to achieve _____ feet per minute annular velocity (approximately equal to previous annular velocities during drilling operations). 7.

Cement liner as follows: __________________________

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

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the tieback string around the bottom if plans are to fracture down the casing , for instance. Cementing liners in potential lost circulation areas will be discussed later in more detail.

The authors firmly believe that if the drill string can be turned to drill the well, a liner can be turned with less torque and drag with centralizers. Other authors report doing this successfully in horizontal and high angle wells at Prudhoe Bay, Alaska.19 The authors have found that many more liners can be rotated than reciprocated and prefer rotation because of the possibility of sticking the liner off bottom (i.e., the pay zone or lost circulation zone could be left uncovered, or the mud and cement in the rathhole could flip flop due to density differences and ruin the liner shoe job). Liner reciprocation also surges and swabs the hole while moving up and down. The liner could also become stuck while going down, leaving it frozen in a buckled position due to compression from the slackoff weight of the workstring. The authors normally use reciprocation to help initiate circulation and on some jobs have found that by working the liner, it has been possible to reduce torque and consequently begin rotating the liner again. One last point should be mentioned: If the liner is reciprocated, then plans should be coordinated so that the float shoe is on the bottom and stays on the bottom until the spacer is all the way out of the liner and cement has started filling the annulus. Otherwise, one could end up with cement, mud, and cement in the annulus, in that order.

PREPARATION FOR LINER TESTING Once everything has been done to ensure a good liner cement job, the next crucial operation is to prepare for testing the liner. Often, this is not done correctly. The first procedure is to check for any cement that may be on top of the liner. Indication of cement may be noted when the setting tool is pulled out of the top of the liner and flow back occurs on the drill pipe. This may result from heavy cement on the outside of the drill pipe causing the annulus hydrostatic pressure to be higher than the hydrostatic pressure of the mud inside the drill pipe. If there is a lot of cement on top of the liner, this flow back can be very strong and for a few moments, one might think that the well may be trying to come in or that the float equipment has given away. If the float equipment has given way or there is cement on top of the liner around the drill pipe, the flow should decrease and the mud in the annulus should be falling (U-tubing) until equalization occurs. If the well is trying to kick, both the drill pipe and annulus side should be trying to flow.

The authors recommend that extremely careful considerations be given to what type of float equipment is used on a liner job. With the authors’ practice of conditioning the mud for at least two complete circulations before cementing, the float equipment must be the best available, especially when using high density muds or cements with silica sand as an additive. Float equipment must also be both temperature and pressure resistant. The detrimental effects of mud abrasiveness can be reduced by using “state-of-theart” solids control systems. Percent and size of solids in the mud must be minimized. One cannot afford to have float equipment fail after cementing after cementing a liner since it’s failure could ruin the cement job in the liner overlap, across a pay zone, around the shoe and necessitate the drilling of cement inside of the liner because of U-tubing. The longer the liner and the greater the density difference between mud and cement, the more U-tubing there will be. For any deep, hot, high pressured, high-mud density well in which a large amount of circulating time is expected, the authors recommend that two float collars be run with the float shoe and that they be the best float equipment available. If float equipment fails on a liner job, one does not have the luxury of closing the well in at the surface to prevent U-tubing and then waiting on the cement to set. Pressure integrity requirements of float equipment may be reduced by keeping the density difference between mud, cement and spacers as low as possible.

This same kind of situation can occur if the well is “giving back mud.” This is a common occurrence in open-hole sections where mud weight approached the fracture gradient and the exposed sections are shale or tight sands. When this occurs the author feels that the hydrostatic pressure increases due to circulating initiates a fracture and the hole takes mud until the pressure loss down the face of the fracture is equal to the increase of pressure loss up the annulus. Once this balance is reached, the fracture quits extending and the hole quits taking mud. When circulation is stopped and the circulating pressure on the induced fracture is removed, the fracture closes and gives back to the mud. The lost mud volume is gotten back in full because of the zone’s lack of permeability to dehydrate the mud. Dehydrated mud would not be able to flow back into the well bore and would probably help keep the fracture open. Thus, no mud would be gotten back in this scenario. “Getting back mud” is a common occurrence in Central and South Texas and if it occurs while drilling, it can certainly occur while cementing a liner. That is why it is so important to observe the annulus if the well is flowing on the drill pipe side. If the well flows on the annulus and cement density is as heavy or heavier than the mud, then the well is probably “giving back mud” and not trying to kick. In this event, cement in the overlap area can be displaced up the hole after circulation is stopped. That is why the authors believe in “running from the cement” and then circulating out. Running from the cement a “safe” distance, closing the well in, and not circulating out is considered very risky.

Finally, should circulation be lost while running the liner, the annulus should immediately be filled with water as soon as possible. In addition to leading to the possibility of a well kick, when returns are lost, a falling mud column can also reduce the hydrostatic pressure enough to let shales slough, which can impede getting the liner bottom. Filling the hole with heavy mud is a waste of valuable mud and may only aggravate the problem. The same bottomhole pressure will result whether water or mud is used.38 Using water enables the actions of the well to be observed sooner (whether the loss is continuing or the well has begun to flow).

On a well (Fig. 21) in Wharton County, Texas, Ashland ran a 75/8” in. liner from 7,299 to 11,154 ft. Mud weight was 16.6 ppg. While running the liner, complete returns were lost, but the annulus was kept full of water and it took a total of 40 bbl before the liner reached bottom, partial returns were gotten back and eventually, full returns were achieved after reducing mud weight to 16.5 ppg. The liner was cemented with 450 sacks of Class H cement, plus additives, with apparent full returns until the final 75 bbl of displacement. (Note: slurry weight of the cement was 16.8 ppg.)

The bypass area around liner hangers should be checked on wells that have the potential for losing returns or wells that have not been adequately cleaned of cuttings that could cause bridging. There is quite a diversity of liner hanger by-pass areas that should be compared. This should also include a comparison of the lengths and ODs of the tieback receptacles immediately above the hanger. Some liner hangers have been redesigned to improve the bypass area around the hanger slips, but still have as great or greater circulating restriction around the tieback receptacle. Tieback receptacles can vary in length from 9 in. to 6 ft. Long tieback receptacles with large ODs can add significantly to the equivalent circulating density or the chances of bridging off in the overlap. This is often overlooked. This difference in restriction becomes even more pronounced if the hanger is hung off before cementing. Short tieback receptacles can be used by simply cementing Reprinted from World Oil magazine, May 1988 with permission from the authors.

The Liner was rotated at 30 rpm while cementing and hung off with its top at 7,299 ft. The drill pipe was pulled up the hole 7,010 ft. There was good backflow on the drill pipe while pulling the first two strands. The annulus was not monitored as it should have been. No one checked to see if it was flowing. Circulation was initiated the

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Estimated top of cement @ 6,500 ft 5-in. drill pipe

16.5 ppg mud

16.5 ppg mud being pumped down drill pipe

Heavier cement U-tubes into drill pipe

Cement circulated out “longway” from 5,200 ft

16.5 ppg mud

No cement found on top of liner with 8½ - in. bit

Bottom of liner running tool @ 7,010 ft

Top of liner 7,299 ft

9⅝ - in., 47ppf casing 7,589 ft.

Assumed induced fracture near 9⅝ - in. csg shoe when losing returns

Cement

Depth of induced fracture. Top of cement probably at point of loss

7⅝ - in. liner wiper plug 11,072 ft 8½ - in. hole 7⅝ - in. FJ liner 11,154 ft

A

C

B

Figure 21 - Sequence of liner job: A - Liner wiper plug is displaced to float collar at 11, 072 ft. Returns are lost during the final 75 bbl of displacement. B - Liner is hung off after cementing and the drillstring is disengaged. Strong flowback is noted on the drill pipe indicating that cement was probably was on top of the liner and is equalizing due to the cement’s higher density. Condition of the annulus (whether flowing or failing) was not monitored. C - The 5-in. drill pipe is pulled to 7,101 ft to circulate out any excess cement the “long way” (down the drill string and up the annulus). By monitoring volume of mud pumped, cement returns were noted at the surface from a calculated depth of about 5,200 ft. D - While going in the hole to drill cement on top of the liner, no cement was found. Apparently an induced fracture that took mud while cementing closed up and gave back the mud after cementing was completed. This inflow of mud must have displaced the cement up the hole through the liner overlap. If the drillstring had been pulled to a calculated “safe” distance above the cement top, say 6,000 ft for instance, and left there while waiting on cement to set without circulating out, the drill pipe would have been cemented in the well.

ization to occur before “running from the cement” if plans are to not reverse out cement due to fear of breaking down the liner top. If well conditions permit, cement can be reversed out near the top of the liner to save time. When reversing out, it should not be done too fast because excessive pump pressures could be created that exceed the burst rating of the intermediate casing or breakdown the liner top. Pressure can become excessive for two reasons. First of all, the hydraulic area of the work string is smaller, thus causing a higher circulating pressure loss. Secondly, the density difference between mud and cement can contribute to a higher reversing pressure because the height of the cement column is increased inside the drill pipe. For example, a 500-ft column of cement on the outside of 41/2 –in. drill pipe in 95/8-in casing will become a 1,962-ft column once it is completely reversed into the drill pipe. If the cement slurry weighs 6 ppg more than the mud, the increase in reversing pressure from this alone will be 600 psi or more. For this reason, if there is excessive backflow, the authors recommend “running from the cement” to a safe distance above the top of cement (the backflow should cease once the liner running tool is above the top of cement unless the spacer density is heavier than the mud density.

“long way” (down the drill pipe and up the annulus) and cement returns arrived at the surface from a calculated depth of 5,200 ft. After going back in the hole to check for cement, there was none found on top of the liner. Apparently, this well had given back the mud it had taken during the final 75 bbl of displacement while cementing. This apparently moved the cement up the hole at least 5,200 ft while the drill pipe was being pulled. If the drill pipe had only been pulled part way out of the hole, say to 6,000 ft, and the well closed in while waiting on cement without circulating out, it is most certain that the drill pipe would have cemented the hole.

This is also why the authors recommend that the spacer be mixed at no more than 0.1 to 0.2 ppg heavier than the drilling fluid. The authors have seen no adverse affects by keeping this density difference low when using heavy muds. Others have reported the same results.25 The lower the spacer density, the lower the pump rate are needed to get in turbulent flow. If lost returns are a concern, circulation again should be done the long way, if pumping time permits, to ensure that cement around the drill pipe, if any, is circulated out. The well should then be closed in and cement allowed to set for the specified period (pressure may be put on the top of the cement, but it should not be high enough to break down the formation at the intermediate casing shoe nor exceed the burst rating of the casing). This is done to keep the well from flowing while drill pipe is being pulled out of the hole. As pointed out by Goins,27 gas is no respecter of the mud’s hydrostatic pressure above it once it enters the wellbore. (The well is monitored while closed in. Should pressure develop, it may not necessarily mean that the well is trying to kick. Rather, it may be trapped pressure due to heat expansion. This can be checked by bleeding off small amounts (¼ to ½ bbl) at a time. (Note: This should be done only after cement has had time to set. Continue to alternate the bleeding and subsequent pressure observation

Anytime cement is circulated out above the liner top with full returns, and no cement is found on top of the liner, then this type problem should be suspected, especially when the mud weight is near the estimated fracture gradient and no permeability exists in the open hole where the fracture occurred. Also, it is felt that circulating out should be done the “long way” and the drill pipe rotated to ensure that cement lying on the low side of the hole is displaced by mud-to-cement drag forces while rotating. This is especially crucial in directional holes over 40°. Reversing out would require rotating the drill pipe with the annulus packed off. If there is flowback and mud in the annulus is falling, it is safe to assume that the well is not trying to kick. The authors allow some equal Reprinted from World Oil magazine, May 1988 with permission from the authors.

D

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procedures as would indicate that the well is most likely dead.)39 The gas, due to its lower density, can lubricate up through the mud and cause the well to unload mud as the gas expands near the surface. With the drill string in the hole rather than in the derrick, a kick, should one occur, can be circulated out and the well killed. Because of recent studies showing how cements may not transmit hydrostatic pressures effectively, it is considered a prudent practice to wait six to eight hours while monitoring the well before pulling the drill pipe out of the hole. After pulling out of the hole, the normal procedure is to pick up a bit and drill collars and go in the hole to look for the top of the cement using the weight indicator.

(when thought to be good hard cement) because of confusion on drill string measurements. Once the top of cement is located, it should be drilled until it is determined to be hard. If cement is soft, drill to within 100 ft. of the liner top and then allow remaining cement to harden before it is drilled out. x Wait on cement longer to allow it to harden more. One author recommends waiting on cement 18 to 24 hours, while circulating and rotating, before drilling it.14 After all cement above the liner has been drilled, a trip with a packer can be made to pressure-test the liner overlap, but a packer is not always necessary. This decision should depend on the estimated burst rating of the intermediate casing after it has been drilled through. A packer is recommended on all liner top tests in high permeability areas such as the Gulf Coast, regardless of intermediate casing burst strength.

The authors consider looking for the top of cement an important operation that should be carefully planned. There have been three different jobs in which the bit and drill collars were cemented in the well because the bit was run into contaminated cement before the operator noticed any change in bit weight indicator. Attempts to break circulation through the bit failed in all three cases and the strings could not be moved. On one job, 97 rig days were spent cleaning out a drill string that was run into the cement accidentally. The authors use four techniques to guard against this eventuality:

If a packer is not used, the following problems could occur. If the intermediate casing shoe breaks down while the liner top is being tested and the mud level drops, the hydrostatic pressure of the mud column could be reduced enough to let sand (not isolated by cement) feed in from behind the liner. The amount the mud level can drop varies tremendously from area to area. This is due to a large divergence sometimes between rupture pressures and fracture extension pressures. Generally speaking, there are larger divergences in Texas and hard rock areas. The smaller divergences occur in South Louisiana type environments. The larger the divergence, the more the mud level can drop.

x Assume a 20 to 30% displacement efficiency (cemented area divided by annular area) on all liner jobs, which gives a possible top of cement that is most probably to high, but theoretically possible (channeling was discussed earlier in this series along with possibility that when liners are hung off before cementing, packoff bushings or swab cups have been known to leak cement).

A potential kick should not necessarily be a concern if sands behind the liner have pressures well below the mud weight being used, if long shale sections exist above the top of cement behind the liner or if the liner is run in hard rock, low-permeability areas. But if there is a gas sand near the liner top or near the bottom of the liner, but not isolated properly, and its reservoir pressure is close to mud hydrostatic pressure, the well could kick if a formation breakdown occurs and the mud level drops. If the kick is a gas sand, pressures resulting from circulating to kill the well could easily exceed intermediate casing burst pressure. If the well kicks with a packer, however, it is “bottled up” and can be killed without putting potentially serious pressures on the intermediate casing. The authors prefer that packers be used on all liner top and shoe tests. This affords testing the liner top with both positive and negative differential pressures.

x With a conservatively high estimate of the top of cement, lay down enough drill pipe (during the trip out for a bit) to enable washing and reaming one joint at a time during the trip back into the hole. This keeps the bit from plugging and the drill pipe from sticking while looking for the cement top using the weight indicator only, without washing. This also allows more time for the cement to set. x To avoid losing track of drill pipe measurements, use the same pipe used to run the liner for drilling cement. No drill collars are used since the cement is relatively “green” anyway, and this also minimizes any chance of pipe measurement errors. More than one liner top has been drilled on inadvertently

LITERATURE CITED FOR CHAPTER 4: For the references cited in this chapter, please refer to the back page, (all references for the entire document).

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

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Chapter

5.

Preferred Methods of Testing Liner Tops With or Without Packers

L iner tops can be tested with or without

If a leak does exist in a liner and the decision is made to squeeze the shoe, there is a risk of setting the packer below the leak, which could cause one of three things to happen. Either squeeze cement will be applied to the shoe where it is not needed; or cement could channel around the liner and through the leak back into the pipe putting cement on top of the packer; or the packer (if set below the leak) would effect a good leakoff test, thus hiding the leak. The latter possibility could be avoided by pressuring up on the annulus above the packer to the fracture gradient of the shoe. This will also help avoid collapsing the casing above the packer with high squeeze pressures.

packers, but there are times one method is is preferred over the other.

Glenn R. Bowman, Regional Drilling Superintendent, Ashland Exploration, Houston, and Bill Sherer, Operations Manager, Liner Tools LC and formerly Alexander Oil Tools, Houston TESTING THE TOP of a liner after it has been cemented is necessary to ensure a wall’s integrity. However, whether done with or without packers there are potential problems attendant with either method that can occur if the tests are not properly engineered. A discussion of these problems and ways to avoid them follows.

Since the test pressure inside a liner should at least exceed the fracture gradient at the shoe, it would be prudent to apply this same pressure to the liner overlap before it is drilled out and the shoe tested without a packer. Otherwise, a leakoff test on the shoe (if it is a drilling liner) may breakdown the overlap and the operator will again not know for sure where the leak occurred.

TESTING LINER TOPS AND SHOES WITHOUT PACKERS If packers will not be used to test a liner, the following considerations should be kept in mind. The positive pressure test of the liner top should be enough to exceed the fracture gradient at the liner shoe by at least one ppg. It should be even higher with heavy, solids laden, less penetrating type test fluids. This high of a test pressure may not seem necessary at first glance, but many liner tops have been tested at pressures even less than the fracture gradient at the intermediate casing shoe, and the cement job on the overlap was considered good. This can give a false sense of security. If there is communication between the liner top and the intermediate casing shoe due to a bad cement job and the pressure applied to the liner top is below that required to rupture the formation the intermediate casing shoe, false positive test will be achieved. The one ppg or more is added to ensure that the fracture gradient has been exceeded and to overcome possible inaccuracies of the pressure gauges. In addition, barite and other mud solids could plug up very small channels in the liner overlap and mask a leak. Barite and gel can cause small channels to hold positive differential pressures of up to 5,000 psi. The extra test pressure may enable the channel to be ruptured enough to cause it to take fluid. Pressures required to “crack the rock” are generally higher than those required to extend the fracture, especially if the fracturing fluid is solids laden.

Another negative aspect of testing liners without packers is that test pressure must not exceed the unknown burst rating of the intermediate casing, especially if mud density is greater inside the intermediate than outside (this is the case when most liner are set). If substantial casing wear is suspected, testing without packer should be considered risky. Wear would be suggested in directional holes when long periods of time are spent drilling inside casing; when intermediate casing is through high dog-legs; and when internal mud weights and circulating temperatures are high while drilling below intermediate casing,1,21,23, etc. In addition, the increase in tension due to ballooning during pressure testing should be checked to ensure that tensile rating of the intermediate casing is not exceeded. The following example illustrates the calculations that should be made before pressure testing without a packer.

The slurry stage

For the same reasons, pressure tests inside a liner should exceed the fracture gradient at the liner shoe by one ppg or more. A leak near the bottom of a liner could go undetected if the breakdown pressure of the formation adjacent to the leak was not achieved. Consequently, when “bumping the plug” after cementing a liner, the pressure should be increased to the maximum that will be imposed on the liner while testing its top. Otherwise, if the plug fails and cement in the shoe joints was contaminated and did not set up, it would be possible to pump through the float equipment and fill the liner with cement if its top has to be squeezed. This is especially true for short liners where fracture gradients at the liner top and shoe may be close. Also, if the liner wiper plug is effective, does not bump up during primary cementing and cement in the shoe joints is green, part of the squeeze job could go down the inside of the liner until the plug bumps. To be sure that the breakdown pressure is not moving the liner wiper plug down, it is good practice to pump in 10 barrels after breaking down the liner top to bump the wiper plug is case it had not bumped during primary cementing.

Casing

Cement slurry in annulus

The set stage

Casing

Formation

Casing

Formation

Gas flowing through setting cement

Formation

Gas or oil in set cement

Figure 22 - How honeycombed cement occurs. In the slurry stage (left), the cement column exerts the necessary hydrostatic pressure on the formation to prevent gas or fluid flow. In the intermediate or self-supporting stage (center) hydrostatic pressure is reduced and formation fluids begin to move through the cement. Also in this stage, the cement cannot transmit hydrostatic pressure from above. In the fully set stage (right), cement is permeated with formation fluids or gas, and often cannot be squeezed. (World Oil, January, 1982.)

These pressure considerations are especially critical for drilling liners whose shoe will be tested to leakoff. If a liner shoe does leak off at some value below expected fracture gradient, the operator will not know whether it is caused by a bad cement job around the shoe, an inherently weak formation at shoe or a leak in the liner string or top. Reprinted from World Oil magazine, May 1988 with permission from the authors.

The intermediate stage

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WELL CONDITIONS

leakoff test will not exceed the burst safety factor of the intermediate casing.

A well in South Louisiana had 9 5/8-in., 47 ppf. N-80. LT&C casing set at 10,0000 ft.in 12 ppg mud. An 8 1/2 –in hole was drilled to 13,000 ft. Other pertinent data include the following:

What pressure will be needed to test liner overlap to same pressure equivalent using 16ppg that will be imposed on liner overlapwhile testing the 7-in. liner shoe to leakoff with 16.5 ppg mud?

x Pore pressure at 13,000 ft is equivalent to 15.5 ppg mud x Increase mud weight to 16.5 ppg before drilling out of 7-in liner

Surface pressure needed to test overlap to equivalent pressure with 16 ppg = (16) (0.052) (10,000) = 8,320 psi.

x Test 7-in. liner shoe to leakoff with 16.5 ppg mud in hole

8,580 psi (pressure at 10,000 ft with 16.5 ppg mud) – 8,320 psi = 260 psi

x Operator policy stipulates that no more than 80% of burst rating will be imposed on intermediate casing.

Surface pressure required to test overlap with 16 ppg mud to a sufficient pressure to support a leakoff test on 7-in. liner shoe with a 16.5 ppg mud) = 260 + 1,900 = 2,160 psi.

x Burst rating of 9 5/8-in., N-80 casing is 6,870 psi, tension rating is 905,000 lb x Cement has been drilled to the top of the liner

Will the SFT of 1.7 on 9 5/8-in. casing be exceeded while running the leakoff test without a packer?

x The 7-in. liner top is ready to be tested with 16 ppg mud in the well

Casing tension increase at surface due to ballooning while testing 7-in. liner to leakoff will be:23

x The 9 5/8-in. casing is hung off at surface with 400,000lb

Fa = 0.6 (P14 A1 – P04 A 0) Where:

x Operator does not want to exceed SFT (Safety factor of tension) of 1.7 on 9 5/8 in. intermediate casing while running the leakoff test on the liner.



 PROBLEM.

What positive pressure should be used to test the liner overlap with 16 ppg mud to be sure it will support a leakoff test on the 7-in. liner shoe with 16.5 ppg mud? Should a packer be employed for the leakoff testing?

8 SOLUTION.

The highest pressure imposed on the 9 5/8-in. casing will be the leakoff test pressure used on the 7-in. liner shoe. The anticipated surface pressure to conduct a leakoff test is calculated as follows:

If 9⅝-in. casing is hung off at surface with 400,000 lb, and the increase in tension at the surface due to ballooning is added, then total tension at surface while pressure testing 7-in. liner shoe to leakoff with no packer will be 467,433 lb.

Estimated fracture gradient at 13,000 ft (15.5 ppg pore pressure) = 18.3 ppg (After Eaton).

SFT = Tensile rating of 9⅝-in. casing¸ total tension at surface = 905,000 ÷ 467,433 = 1.94. Thus the SFT of 1.7 is not exceeded and it is possible to do all positive pressure testing of the 7-in. liner without a packer.

Fracture gradient + 1 ppg (safety factor to assure initiating rupture) = 19.3 ppg. Bottomhole pressure required to initiate rupture for leakoff at 13,000 ft = (19.3) (13,000) (0.052) = 13.047 psi.

A final word of caution when working with large OD flush joint liners whose connection strength in tension is a percentage of the tension rating of the pipe body – careful consideration should be given to what pressure limitation should be imposed for bumping the plug. For example, bumping the liner wiper plug with 2,00 psi on an 11¾-in., 60 ppf FJ liner can increase tension load on the liner connection by over 1800,00 lb. If the liner is not hung off first, this tension is also added to the tension load on the drill string. This added tension will not be seen on the weight indicator. Safety factors of tension should be checked for both tubulars before deciding what pressure to use when bumping the plug.

Mud hydrostatic at 13,000 ft with 16.5 ppg mud = 11.154 psi. Maximum surface pressure = bottomhole pressure minus mud hydrostatic = 13.047 – 11.154 = 1.893 psi. Therefore use 1,900 psi as maximum surface pressure required to run leadoff test. Can 1,900 psi with 16.5 mud be safely imposed on the 9⅝ in. casing? Burst rating of 9⅝-in. = 6,870 psi.

As stated earlier, the vast majority of liners are not pressure tested properly. Most are tested below the fracture pressure of the formation with which a leak could be in communication. It would be a low risk procedure to just test the overlap of a production liner to the fracture gradient at the intermediate casing shoe, with the plausible assumption that the newly run liner will have no leaks. A drilling liner should, at the minimum, have the overlap tested to the fracture gradient at the liner shoe to assure that the overlap will hold if a leakoff test is run on the liner shoe without using a packer.

6,870 psi x 80% (Arbitrary safety factor imposed by operator) = 5,496 psi. Since 9⅝-in. casing was set in 12 ppg mud, burst pressure due to difference in mud densities alone at 10,000 ft = (0.052) (10,000ft) (16.5 – 12 ppg) = 2,340 psi. Maximum burst load on the 9⅝-in. at 10,000 ft = 2,340 psi + 1,900 psi = 4,240 psi. Therefore, maximum burst load during the 7-in. liner shoe

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

P14 = Pressure inside tube = 1,900 psi P04 = Annulus pressure outside tube = 0 psi. A1 = area of tube ID = 59.19 sq in. A 0 = Area of tube OD = 72.76 sq in. Fa = Axial force, lb (Increase in tension) Fa = 0.6 [1,900 x 59.19) – 72.76 x 0 psi)] Fa = 67.433 lb

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TESTING LINERS WITH A PACKER Gas channels in cement mixture

The authors recommend testing all liner tops and shoes with a squeeze packer because of all of the potential problems stated above. Normally, an operator will immediately pull out of the hole after squeezing to pick up a bit and scraper. The retainer, if used for squeezing, and cement has to be drilled before he liner top can be tested. Another trip has to be made to squeeze the top or do a negative test on it.

Formation

Cement Micro-annulus between formation and cement (shrinkage)

A negative pressure test should be run on liner tops because of the possibility of mud solids plugging up a small channel or the existence of “honeycombed” cement or a micro-annulus (see Fig. 22). These type environments often cannot be pumped into and give a false sense of security. A negative pressure test should be equal to any negative differential pressure that the well may encounter late in drilling or completion.

Figure 23 - Gas migration routes in a cemented annulus (after Stewart and Schouten51).

If a production liner is run in a high pressure gas environment where gas leakage problems are known to occur, it would be prudent to consider running a drillstem test assembly (with BHP bombs) that is capable of closing the bottom of the well to test the liner top. This is recommended because gas leakage around liner tops has been reported to produce as little as 40 Mcf of gas per month from shale gas. Leaks of this size may not be detected by a differential test conducted using a packer but no BHP bombs for a short period of time in which the differential column is opened to the atmosphere. Slight gas seepage through the liner overlap could easily be disregarded as air working out of the test fluid of temperature expansion of the test fluid. Thorough testing of the liner top is recommended for production liners when the liner top is left exposed since, during the well’s producing life, there is sufficient time for pressure to build up from a small gas leak. Often drilling is resumed when leaks like these exist in drilling liners and some have considerably affected mud log evaluations.1

Annulus not vented. A closed system

7-in. protection casing

Tubing

Gas percolating through packer fluid

Annulur gas flow through liner top @12,888 ft

Another tool the author consider superior for identifying a small gas leak is the gas detector. Liner top leaks have been experienced that kept background gas reading from dissipating during drilling operations even though mud density was greater than any pore pressure in the open hole behind the cemented liner. This was due to a gas leaking through honeycombed cement, which cannot be killed with any mud density.

Honeycombed cement

Production packer

Since honeycombed cement will not accept fluids nor transmit hydrostatic pressure because it is solid, an increase in mud density on top of it will not be transmitted to the source of the gas. And increased hydrostatic pressure at the liner top imposed by heavier mud will not stop the gas flow because the gas, due to its lower density, will lubricate through the mud. As each bubble of gas lubricates up through the mud, pressure in the honeycombed channel is decreased and more gas is allowed in to fill the void. Thus there is a continuous gas feed-in that will be detectable by a gas detector. It may have been attributed to background gas while circulating, or as unexplained early trip gas readings during bottoms up from trips. A good time to run a gas detector in the liner is before drilling out of it. This provides a test in a closed system, and any gas readings would be suspected of being a leak.

7-in. casing set @13,097 ft Gas migration behind liner through cement High pressure gas zone

Perforated interval (Cotton Valley Lime) (@14,699 - 14,725 ft)

REPAIRING LINER TOP LEAKS

5-in. liner set @15,140 ft

There are different types of liner top leaks. The most difficult and costly to repair are those due to honeycombed cement or a micro-annulus (see Figs. 22 and 23). Many times these type leaks cannot be pumped into for squeezing.1 There has been much published on why has migrates through cements,40-53 but to explain briefly how this occurs, Christian, Chatterji, and Ustroot40 showed that excessive fluid losses with cement mixtures can cause dehydration in the annulus and produce a bridge that will interfere with pressure transmission from above to the rock formation. If the drop in hydrostatic pressure below the bridge Reprinted from World Oil magazine, May 1988 with permission from the authors.

Micro-annulus between casing and cement (due to pressure inside casing)

Casing

Figure 24 - This completion had a liner top leak that the operator was unaware of until pressure built up on the intermediate casing. Although the liner passed an interval positive test of 3,000 psi with 16.2 ppg mud in the hole, it still leaked gas. And after traveling through the honeycombed cement, the gas was able to lubricate through the mud regardless of the hydrostatic pressure on the liner top. Because the annulus is a closed system, the gas bubbles were not allowed to expand and pressure built up on the 7-in. casing until it burst. (World Oil, January, 1983.)

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a function of several slurry and well parameters but is governed primarily by (1) the rare of static gel strength development of the cement, (2) volume of fluid loss from the cement slurry, and (3) compressibility of the cement slurry.52 Other authors also point out that even with no fluid loss, volumetric changes and pressure restrictions caused by the hydration of the cement can also allow gas migration.50 Stewart and Schouten51 show that gas migration can occur from casing contraction also. Most cement companies now have proprietary anti-migration gas cements that reduce or stop gas migration by casing the cement to develop quick gel strengths (by limiting cement hydration shrinkage) or by causing the cement to lose its permeability on contact with gas. A liner top gas leak can create serious problems. The following case history gives a graphic example. 15,900

Case 1: Land-based production liner, East Texas field, Leon County, Texas. This well was drilled to the Cotton Valley Lime and reached a TD of 15,147 ft. A string of 7-in casing was set at 13,097, Fig 24. Due to the existence of fractures in the Cotton Valley, mud weight at TD could not be raised above 15.9 ppg without a loss of returns. But with 15.9 ppg mud, the background gas would not drop below 125 units and the mud weight was continuously being cut from 15.9 to 15.6 ppg. A reasonable assumption was that formation pressure in the Cotton Valley Lime exceeded 16.3 ppg.

Monitor curve

Gamma Ray

Casing collars Correct depth

The well was safely logged and the decision made to run a 5-in production liner. The liner was run to 15,140 ft with its top located at 12,888 ft. It was cemented using 90 bbl of 17 ppg, low fluid loss cement displaced by 15.9 ppg mud. Full returns were achieved while cementing. Top of cement was found at 12,753 ft or 135 ft above the liner top.

Cement bond curve 16,000

While drilling cement on top of the liner, the well kicked momentarily and then died. Mud weight was increased to 16.2 ppg and the operator tested the liner top with 3,000 psi on the mud with no leakoff. This was an equivalent mud weight test of 20.6ppg. Thus, the liner overlap cement job was believed to have been successful. No negative test was performed. The well was completed with a production packer inside the top of the 5-in. liner, leaving the overlap in communication with the 7-in. intermediate casing.

Casing collars recorded 15.5 ft deep

Later during production, pressure built up on the 7-in. casing from gas percolating through the honeycombed cement in the overlap, rupturing the 7-in. and causing an underground flow. A total of 156 rig days and $2,565,000 (1977 dollars) were required to repair the well and place it back on production.

GR FR

The authors have had very little experience with special cements to control gas migration. When attempts were first made to control gas migration with a “compressible” type cement, the job was successful. A description of it follows.

Figure 25 - Portion of a cement bond log showing excellent bonding of a special cement used to control annular gas migration.

Case 2: Land-based production liner, Hemphill County, Texas.

reduces the pressure below formation pressure and if the formation contains gas, then it can feed in and percolate up through the cement causing microcapillaries that will allow passage of gas but not fluids. If the top of the cement is not fully set before the migrating gas reaches it, the result is an entire column of honeycombed cement. This occurs as the cement slurry undergoes transition form a liquid to a solid.

The Anadarko basin is noted for problems of gas leakage through liner tops5,6 when high-pressure gas zones such as the Morrow are encountered. The well was drilled to a TD of 16,100 ft using 14.2 ppg oil base mud. A string of 7-in. casing was set to 13.922 ft and a 6⅛-in hole drilled. There were mud seepage losses at about 10 bbl per hour while drilling the 6⅛-in hole. The well was logged and a decision made to run a 5-in. completion liner. Due to excellent well bore conditions, it was decided that it would be feasible to reciprocate the liner.

This can create a liner top leak (if cement was circulated above the liner top) that often cannot be squeezed. Kulakofsky goes on to show that the likelihood for this occurrence is Reprinted from World Oil magazine, May 1988 with permission from the authors.

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A 5-in. LT&C liner was run with one centralizer allowed to float on every joint and four wireloop cable wipers on every joint 40 ft above, through, and below the pay interval. The liner was cemented with 93 bbl of 16.8 ppg, low water loss compressible cement followed by a 25-bbl, 14.5 ppg mud spacer. The liner was reciprocated 32 ft throughout the entire job until the plug was bumped. The liner was set from 13,596 to 16,098 ft.

Top of cement was found above the liner at 13,140 ft. After drilling cement to the top of the liner, the liner top was tested successfully and the well completed in the Morrow formation from 15,777 to 16,038 ft. The well produced 1.5 MMcfd with no annular gas flow through the liner top. No squeezes were necessary prior to perforating for production. A portion of a bond log was run is shown in Fig. 25.

LITERATURE CITED FOR CHAPTER 5: For the references cited in this chapter, please refer to the back page, (all references for the entire document).

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

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Chapter

6.

Annular Gas Flow Prevention: Special Cements and Other Methods for Controlling the Problem

S pecial cements are available to prevent

annular gas flow, but if a leak still occurs, there are other methods for controlling the problem.

Glenn R. Bowman, Regional Drilling Superintendent, Ashland Exploration, Houston, and Bill Sherer, Operations Manager, Liner Tools LC and formerly Alexander Oil Tools, Houston SINCE THE AUTHORS admittedly have limited experience with fighting annular gas flow problems, this article will deal mainly with design considerations extracted from current literature on the subject. It seems rather obvious to assume that to achieve both anti-gas migration success and zonal isolation that the appropriate special cement has to be used and effective mud displacement has to be achieved . 51 Again, this comes back to the necessity of good cementing practices talked about in earlier installments.

Receptacle

LEAK PREVENTION METHODS

Liner Packer

If a production liner is to be run, and the pay zone near the bottom is known to have annular gas flow potential, then consideration could be given to cementing around the bottom of the liner while rotating or reciprocating. The liner top could then be squeezed with an anti-gas migration cement if gas shows up in the mud when circulating bottoms up. If there is no gas feeding in, then the top could be squeezed with regular low water loss cement. (Gas migration could be determined by monitoring gas in the mud with a gas detector while waiting on cement. As discussed in an earlier article, the drill pipe should not be pulled out of the hole for six to eight hours after the primary job in the event that gas gets through the cement and the well kicks.)

Gas trapped under packer

Liner hanger

The above technique may not be a good idea on a drilling liner with gas pay behind it. If accurate prediction of the cement top can be made (i.e., liner was cemented while achieving all known good cementing criteria discussed earlier), then it could be tried. There are two risks involved in doing a drilling liner this way. First, if the special cement does not work properly (due to channeling, etc.) and cement is accidentally circulated on top of the liner, the liner overlap may end up containing honeycombed cement that leaks gas and cannot be squeezed off. If the volume of gas is too high, the liner top may have to be isolated with a liner tie-back packer or a tie-back string before proceeding. Secondly, if the cement volume estimated is too low (or returns are lost) and the top of the cement ends up lower than expected, the result could be a large uncemented interval that could buckle and create wear spots after the liner tope is squeezed and drilling proceeds.1,21,23.

High-pressure gas

Another way to attempt control of annular gas flow is to run a packer on the top of the liner to seal the annulus between liner and casing,1 (Fig. 26). These packers can be run in conjunction with the liner hanger and can be set before cementing or after cementing is complete. Any gas present is therefore trapped below the packer if the overlap has no cement. These type packers are set by weight and held down by internal and external slips. This would be a viable method of lost circulation is not a concern (the packer is a circulating restriction that causes higher equivalent circulating densities and surge pressures) and the operator was certain that he could achieve a good cement job in the liner overlap. Otherwise, a serious problem could develop during completion of the well or later in the life of the well if the packer failed. Also the main sealing element could be damaged by mud and cutting circulating past the packer. 1 These type packers Reprinted from World Oil magazine, May 1988 with permission from the authors.

Figure 26 - Liner packers can be run in conjunction with the liner hanger and set before cementing or after cementing. A polished bore receptacle may be run above the packer to provide tie-back capabilities. (Courtesy of Texas Iron Works.)

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Caution should be used with certain anti-gas migration cements. If the proprietary slurry relies on a cement that develops high thixotropic properties to control gas flow, it should not be circulated on top of the liner. Its quick forming gel strengths may make reversing out or circulating excess cement out the long way impossible. Also, the cement may not fall out of the drillstring. On one job, we could not reverse excess cement with 2,500 psi and could no circulate out the long way with 3,500 psi. We ran from the cement. After pulling out of the hole, we had 1,961 ft. of drill pipe cemented on the inside. These type cements also can cause severe swabbing difficulties when pulling the liner running tool through the cement if is on top of the liner because of low clearance between the liner running tool an intermediate casing.

are not recommended on drilling liners for these reasons. Another alternative when running a liner through known highpressure gas sands is to run external casing packers.3,5 These too cause circulating restrictions and are very expensive. They can be run in the open hole (preferably an inguage part of the hole) or in the liner overlap. They should be considered more reliable than packers run in conjunction with liner hangers.

Back-up ring

If the liner top is squeezed with thixotropic cement, then cement should be displaced below a squeeze packer and into the overlap before attempting to obtain a squeeze pressure. Cement should also be batch mixed since any pumping problems that may occur will make it unpumpable. This will also help prevent high thixotropic cement from gelling up inside the drillstring as it develops high gel strengths and cannot be pumped. Squeeze techniques will be discussed in more detail in future articles.

Casing

Sealing elements

Cement in annulus

One last comment should be made about predicting annular gas flow. The authors feel that there must be a certain gas-oil ratio at certain temperatures and pressures at which annular gas flow is not a problem. It appears that the higher the yield of a potential pay zone, the less likelihood there is for annular gas flow problems or, conversely, the “dryer” the gas, the more likely there will be annular gas flow. More research needs to be done to better predict this problem. The bubble point of the reservoir probably has a bearing on annular gas flow potentials, for instance.

Back-up ring

Figure 27 - Seal ring device consists of two opposing deformable cup-type sealing elements. As pressure develops at the casing-cement interface, it causes the inner seal to expand and seal against the casing. This can help guard against micro-annulus communication. (Courtesy Gemoco.)

MECHANICAL TECHNIQUES If, despite the best efforts, the liner top still leaks, there are several options available. One is to set a production packer above the liner top and produce the liner top gas with the completed interval. However, gas flow through the channel could get worse as pressure on the top of the liner is reduced to the flowing BHP of the producing zone. This could eventually allow movement of fluids behind the liner and through the liner top. A second option is to run a liner tie-back packer. The packer is landed and set in a receptacle at the top of the liner. When set, the packer seals in the liner receptacle and packs off in the casing to isolate the liner top against pressures from above or below. These type packers are also available to be set hydraulically in high angle holes where drag causes difficulties in applying weight to them.

Lastly, concerning prevention of gas leaks in the liner top, two more techniques will be discussed. Stewart and Schouten51 report that gas migration, resulting from casing contraction, is a common problem. They recommend that mechanical seal ring devices be used to prevent this even though casing contraction is not expected under initial production conditions (Fig. 27 shows a type of seal ring device of deformable rubber used for this purpose). We agree with this precautionary installation for wells in which the internal pressure in the casing will be reduced substantially later while drilling or during production. As reported by Suman and Ellis,5 thermal expansion of the casing while cement sets and subsequent temperature reduction, mill varnish, etc., can all cause a micro-annulus. This situation is also created by water base drilling fluids exerting less hydrostatic pressure as they are heated up. A micro-annulus also affects cement bond log evaluations. This will be discussed later in more detail.

The most expensive option is isolating a liner top leak is to run a tie-back string or scab liner.6 Even then, the same design problem of controlling gas migration still exists with the scab liner as when the first liner was run. A tie-back string has a better chance of success than the scab liner because the cement column can be located much higher above the top of the leaking liner than a scab liner can. The amount of cement is limited with a scab liner to whatever the operator wishes to impose as the maximum amount to be circulated around the workstring on top of the liner. Thus, limited cement volumes mean more channels, less chance for isolation bonding and a shorter distance for the gas to migrate and honeycomb the entire cement column. The tie-back string can be cemented as high as the operator desires. By varying cement thickening time, the operator should be able to contain gas migration to the lower part of the tie-back string before gas can channel the whole cement column. The only hope for success with the scab liner remedial approach is to use an anti-gas migration cement since the short cement column provides no latitude for varying thickening times.

A final, more radical technique to consider is the use of a very short overlap of, say, 50 to 75 ft. If the liner leaks gas and it cannot be broken down, than an extremely high breakdown pressure may be tried. If this does not break down the liner top, a tailpipe below the packer could be used to spot acid on top of the liner. The squeeze packer would be reset and an attempt made to break down the liner top once again with an extremely high breakdown pressure. (Note: Aluminum or PVC pipe should be used as tail pipe in the event, while squeezing, the annulus fluid around the tailpipe compresses enough to allow cement to “creep” up around it. This pipe is easily drilled or pulled in two.) The authors know of one liner top successfully broken down with 5,000 psi surface pressure. If a breakdown is not achieved, the work string could be jetted, or swabbed in for cleaning out restricted flow channels in the cement. Acid could then be respotted and an attempt made to breakdown the liner top again. If the top can be broken down, it should be squeezed with an anti-gas migration cement. Reprinted from World Oil magazine, May 1988 with permission from the authors.

Packers can be run in conjunction with the tie-back string or scab liner. Circulating restrictions through the packer are

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Intermediate Casing Piggyback packer (set position) Drill String

Piggyback packer (unset)

Piggyback packer (unset)

Liner setting tool

Top of Cement Liner top

Liner top

Drillable packoff

Liner

1

Cement

2

3

4

Figure 28 - Sequence used to squeeze a liner using a piggyback backer. 1) Piggyback backer is run with drillstring, liner hanger and liner. 2) The first stage is cemented around the bottom and the wiper plug is bumped. 3) Setting tool is pulled out of liner, packer is set and the liner top is squeezed. Cement is held in the overlap and on top of the liner. 4) Piggyback packer is unset and the drillstring is pulled out of the hole. (Courtesy of Texas Iron Works, Inc.)

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

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not a design problem since the leaking micro annulus of the liner top will not accept fluids. Thus, there is no danger of creating a lost circulation problem resulting from a higher equivalent circulating density or the bridging off of cuttings. (Note: the intermediate casing should have been circulated clean of cuttings before cementing). The packer also can be expected to achieve a high rate of success because it will be set in the intermediate casing and not in an irregular open hole. Another advantage of the packer is that if it is successfully set after the cement is in place and can trap gas pressure long enough to let the cement column above it solidify, then the cement above the packer will not transmit gas should the packer fail later. Since the operator cannot

know for sure that the packer will set ahead of time, it would still be prudent to run an anti-gas migration cement slurry to guard against this eventuality. High pump rates to put cement in turbulent flow should also be possible in this “closed” system to ensure no channeling One last point should be made on liner top repairs. Polished bore receptacles (PBR’s) leave open the option of running a scab liner or tie-back string to cover up a hole in the intermediate string or a loner top leak. Since it cannot be assured the there will never be a liner top leak or that a problem will not develop with the intermediate casing later in the life of the well, PBRs should be run on all liners.

LITERATURE CITED FOR CHAPTER 6: For the references cited in this chapter, please refer to the back page, (all references for the entire document). Reprinted from World Oil magazine, May 1988 with permission from the authors.

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Chapter

7.

Several Alternatives for Cementing Liners During Lost Circulation

S everal alternatives are given for

x Spotting cement around the drill pipe, pulling the pipe out of the cement and then squeezing the top of the liner would probably result in a squeeze in which the cement was contaminated with mud.

cementing liners when lost circulation is occurring and a case history shows how one was successful.

Another alternative to consider is running a packer on the top of the liner to seal the annulus between liner and casing. As mentioned previously, these packers can be run in conjunction with the liner hanger and set before cementing or can be set after after cementing is complete (see Fig. 26 of last months installment). However, the authors do not consider the use of liner packers as the best alternative to choose for a well with lost circulation. Run with the liner, they impose a circulating restriction causing higher equivalent circulating densities and surge pressures.1 And should returns be regained there will be an increase in the likelihood that drill cuttings ahead of the cement will bridge in the annulus and squeeze off circulation. A positive pressure test would not be indicative of an isolating cement job in the overlap with a packer. It is possible that the packer could give way at a later time,1 communicating zones behind the liner with the uncemented liner top. This could present serious problems while drilling is underway or later during the production phase of the well.1

Glenn R. Bowman, Regional Drilling Superintendent, Ashland Exploration, Houston, and Bill Sherer, Operations Manager, Liner Tools LC and formerly Alexander Oil Tools, Houston MANY LINERS are run in environments in which the drilling fluid cannot be circulated, or in which the increased hydrostatic pressure of the cement column could cause lost circulation. This situation makes primary cementing difficult, but there are some measures that can be taken to enhance the chance success. Every effort should be made, if practical, to cure the lost circulation problem. If returns are lost while cementing, the liner top will have to be squeezed. If it is a production liner and the lost circulation problem is below the potential producing zone, additional squeezing may be needed to isolate the productive intervals. If it is a drilling liner, it could buckle later due to higher temperatures and higher internal mud weights in washouts that were inadequately filled with cement.1,20,21,23

For wells in which the mud in the hole can be circulated but cannot be weighted up without losing returns, some operators design cement slurries to precisely control the height of the cement column. The idea is to keep the hydrostatic pressure of the heavier cement below the hydrostatic pressure required to break down the lost circulation zone. This is a difficult task because of the problem of cement channeling on the vast majority of liner jobs. Cement tops, and consequently cement heights, almost invariably end up higher than expected. One way to improve the chances for success with this type procedure is to reduce mud weight by something close to the trip margin being carried with the mud density and mixing spacer cement at the same density as the drilling mud.

The biggest danger is that circulating surges could aggravate the lost circulation problem to the point that the mud’s hydrostatic pressure is lowered enough to allow the well to kick. If lost circulation cannot be cured, then every attempt should be made to at least minimize the problem (i.e., cutting mud weight, spotting LCM (lost circulation material) pills, open hole squeezes, etc.). Having to kill a well while running a liner can pose serious problems. Due to complications in cementing liners with lost circulation problems, it is very important that good intermediate casing points be selected. The fracture gradient at an intermediated casing point may be sufficient to allow safe drilling, but insufficient to allow cement to be circulated around the liner. Thus a later liner cement job should be kept in mind when picking intermediate casing points.

Other considerations must be borne in mind if the operator wishes to use a packer run piggyback in conjunction with the liner hanger (see Fig. 28). This enables precise placing of the cement in the overlap during squeezing and means that the well can be controlled downhole should a kick occur while cementing. Although the piggyback packer causes some circulation restrictions, and therefore surging, this surging is minimized by packers that have large circulating bypasses, which are left open while the liner is being run. Some precaution should be taken when piggyback packers are used, including:

ALTERNATIVES FOR HANDLING LOST CIRCULATION If well conditions mechanically or economically dictate that the lost circulation cannot be cured, the authors consider four alternatives. One is to run a piggyback packer above the liner hanger (see Fig. 28) and to cement the liner around the bottom conventionally. The piggyback packer then is set in intermediate casing and the top of the liner is squeezed. This allows running the liner, cementing it and squeezing the top all in one trip. Another technique is to run the liner, cement conventionally around the bottom and then make a trip to pick up a packer for squeezing the top.

x Liner should not be reciprocated or rotated. x Hydraulic set, right-hand release liners should be run and the packer should have a left-hand set mechanism. x There are tension limits to these packer that will preclude their use on long liners.

A similar technique (that the authors have not tried to date) is to bradenhead squeeze the liner top after completing the bottom after the liner top after completing the bottom stage, rather than make an extra trip to pick up a squeeze packer. Three disadvantages of this method are:

x It is recommended that cement or mud flushes be prevented from getting on top of the packer because of the potential of sticking or cementing the packer. This means limited cement volumes and mud spacers, which means lower contact times and lower degrees of cementing success.

x Squeeze pressure is imposed on the entire intermediate string and if it has been worn by previous drilling, it could rupture below the calculated burst rating.

x Unlike a liner packer, a piggyback packer can be used to squeeze the top of the liner.

x Breaking down the intermediate casing shoe for squeezing could momentarily drop the mud level, and consequently, the hydrostatic pressure of the mud column, letting the well come in with no control of the well on bottom. If a gas kick occurs, excessive casing pressures could occur while killing the well. Reprinted from World Oil magazine, May 1988 with permission from the authors.

x When the top has been squeezed, the possibility exists that there may be an uncemented interval left between the top of cement from the primary cementing and the bottom of cement from the squeeze on the liner top.

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Intermediate Casing Piggyback packer (set position) Drill String

Piggyback packer (unset)

Piggyback packer (unset)

Liner setting tool

Top of Cement Liner top

Liner top

Drillable packoff

Liner

1

Cement

2

3

4

Figure 28 - Sequence used to squeeze a liner using a piggyback backer. 1) Piggyback backer is run with drillstring, liner hanger and liner. 2) The first stage is cemented around the bottom and the wiper plug is bumped. 3) Setting tool is pulled out of liner, packer is set and the liner top is squeezed. Cement is held in the overlap and on top of the liner. 4) Piggyback packer is unset and the drillstring is pulled out of the hole. (Courtesy of Texas Iron Works, Inc.)

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

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The last point merits further discussion. Since the authors try to to get a complete liner cement job in one trip, the question arises as to how this can be done with limited cement volumes. One solution is to increase the distance that the piggyback packer is run above the liner. On jobs in which the critical isolation is zones is needed most at the bottom, less cement is needed to achieve proper contact time in the area of need and the piggyback packer can be run close to the liner top. The small amount of cement needed should bet be enough to circulate above the liner top.

was well below the pressure integrity of the 7-in. casing.

If lost circulation cannot be cured, then every attempt should be made to at least

If the critical area of isolation is near the top of the liner, the piggyback packer can be run father above the liner top to reduce the danger of cement getting on top of the packer while still providing a sufficient amount of contact time. Since a piggyback packer is run when a well is experiencing lost returns, chances are low that returns will be regained sufficiently to allow cement to be circulated to the liner top with this higher spacing of the packer. If returns are regained during cementing, the volume of mud gained in the pits after the cement turns the shoe should be closely monitored. This gain should be compared to the pre-job calculation of the cement volume needed to get it above the liner top. If returns are regained and calculation show the possibility that cement did reach the top of the packer, then drill pipe should be pulled a calculated safe distance above where cement should be. Any cement that may be outside of the drill pipe is circulated out the long way (if pumping time permits) as a precautionary measure. Cement should not be reversed out to avoid breaking down the liner top and losing returns again. The bottom stage of cement then is allowed sufficient time to set before the liner top is squeezed.

minimize the problem since having to kill a well while running a liner can pose serious problems. CEMENT TYPE.

Since the pay zone was determined to be oil, an anti-gas migration cement slurry was not deemed necessary, but rather, a low water loss, regular cement was to be used.

CEMENT VOLUMES.

With an average hole size of 7¾ in., a 5-in. liner and a 20% excess added to the caliper calculated volume, the volume of cement needed is determined as follows:

LINER JOB DESIGN FOR LOST CIRCULATION

Volume per linear foot of hole = 0.912 ft 3 /ft

A well in Calcasieu Parish, Louisiana, was to be completed using a 5-in. liner. Well conditions included 7-in. casing set at 9,624 ft, a 6 1/8-in. hole drilled to 10,457 ft TD and mud weights higher than 15.2 ppg could not be circulated—returns were lost twice with 15.3 ppg mud and lost circulation could not be cured. Logs showed a pay zone with an oil-water contact, the productive interval being from 10,019 to 10,022 ft on top of water. Average open hole size from the caliper was 7¾ in.

Length of liner in open hole = 10,456 (TD) - 9,624 (7-in. setting depth) = 832 ft Volume to fill annulus + 20% excess = (832)(0.1912)(1.20) = 191 ft3. Due to the severity of lost circulation, it was decided that there was almost no chance of circulating cement on top of the liner. Since the liner could not be rotated or reciprocated because of the piggyback packer, the chances for good cement bonding across the pay zone were reduced unless cement pump rates were high and the contact time increased. Therefore, cement volume was increased to 250 sacks (375 ft 3 ) of class H cement with low water loss additive to give more contact time across the pay zone.

 PROBLEM.

Run a 5-in. production liner and do a maximized liner cement job tailored to well conditions using a 16.5 ppg slurry in a well that had lost circulation problems.

8 SOLUTION.

Since the lost circulation could not be cured, it was decided that a piggyback packer would be run in conjunction with the liner hanger for three reasons:

This was 560% excess over gauge hole volume based on the 6 1/8-in. hole drilled. The plan was to reduce the cement volume if returns were regained once the liner was on bottom or while mixing cement. It should be noted that 50% excess over the gauge hole volume often is recommended by the cement service company.

x The piggyback packer provided the option of closing the well on bottom should it kick while running the liner. It was felt that this was a possibility because pressure surges running the liner or lost circulation problems while cementing could drop the mud level and let the well come in. Also, the pay interval’s pore pressure was estimated to be close to hydraulic mud pressure.

 PROBLEM.

Calculate volume gain needed in pits after cement turns the liner shoe to get cement on top of the piggyback packer. Assume a 30% displacement efficiency.

x With the severity of the lost circulation problem, it was felt that there was only a slight chance that cement could be circulated to the liner top. Thus the need for squeezing the top was thought to be inevitable.

8 SOLUTION.

As calculated earlier, 191 ft 3 of cement is needed to fill the annular volume based on the caliper, plus 20%. Assuming a 30% displacement efficiency (due to no planned liner movement) of cement volume to annular volume, the calculation is:

x Being able to close in the well on bottom was considered more important than being able to rotate or reciprocate the liner. A pressure relief sub run above the liner hanger for circulating out cement was ruled out since the pressure integrity of the intermediate casing and the known low fracture gradient of the 7-in. casing shoe (resulting from the lost circulation problem) meant that the cement could be bullheaded at a relatively low surface pressure should an emergency need arise. This pressure Reprinted from World Oil magazine, May 1988 with permission from the authors.



(0.30)(191 ft 3 ) /5.6 ft 3 /bbl = 10.2 bbl

Thus, a ten barrel pit gain is needed after cement turns the shoe to get cement on top of the packer. Any returns at the

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surface in excess of this amount would mean that the packer will need to be pulled clear of the cement before it is set to squeeze the liner top.

contact and was completed as a water-free oil well. The authors considered this successful liner job as an example of turning a problem (lost circulation) into an advantage by allowing more cement (560% excess) to be run past the productive interval. Chances of obtaining a good cement job using only 50% excess of over-gauge hole volume (as was recommended) would have been very low. When cementing with a piggyback packer, high pump rates should be utilized while pumping cement around the bottom of a liner since by this time it is too late to worry about lost returns. In fact, lost returns should be encouraged as long as the lost circulation zone is above the zone of interest. This technique is also worthy of consideration for long liners when there are large differences in bottomhole temperatures between the top and bottom of the liner since it would enable mixing one for the bottom stage and another slurry for squeezing the top which would have lower pump times due to less temperature and pressure.

 PROBLEM.

Select cement volume for squeezing the liner top.

8 SOLUTION.

The lost circulation zone was assumed to be close to the 7-in. casing shoe where theoretically the lowest fracture gradient should occur. Due to the severity of lost circulation, the desire to fill the entire 5-in. open hole annulus with cement, and the desire to get a good contact time through the liner overlap while squeezing, 200 sacks (1.50 ft3 per sack) of low water loss cement were planned to be used for squeezing the liner top. All cement was planned to be batch mixed.

 PROBLEM.

Due to the better cement jobs achieved by liner rotation, the authors recommend that piggyback packers be run in conjunction with liner hangers only when there is almost no chance of returns (as was the case with the above well) or when a well has a gas sand that could come in and that could potentially create excessive casing pressure while killing the well. If the operator is confident of a high burst rating of the intermediate casing, then this should not be a factor. Otherwise, the authors recommend that a mechanical set hanger (All liner hangers should be checked for the maximum bypass area. There is a large difference among different brands) be run to enable rotation or reciprocation. This will reduce the equivalent circulating density while cementing13 (see Fig. 29). If the liner can be run without losing returns and circulation can be established by reducing the mud weight by a fraction of the trip margin, chances will be good that a primary cement job can be obtained in one trip.

Determine cement pumping rate for first stage.

8 SOLUTION.

The decision was made to pump cement as fast as possible once once it turned the shoe to improve displacement efficiency. A limit of 5,000 psi pump pressure was imposed. Since returned had already been lost, controlling the equivalent circulation density while cementing was not a concern since the lost circulation problem was thought to be close to the 7-in. casing shoe. Consequently, losing returns while cementing would not affect the amount of cement contact time across the pay zone, which was, in this case, most probably below the lost circulation zone.

CENTRALIZERS AND SCRATCHERS The authors run centralizers on all liner jobs. Scratchers were not used due to the high differential pressures involved and high permeabilities of sands exposed. Scratchers would have decreased the chances of getting the liner to bottom by scraping off wall cake, thus exposing the liner to formation faces, and subsequent possible differential sticking. It was decided to run one centralizer per joint and to allow them to float in the event the liner would not go to bottom. This would help ensure the liner could be pulled back out of the hole.

20.0

Equivalent circulation density at 9.716 ft. ppg

Well conditions

RUNNING THE JOB The liner was run slowly into the well an hung off in full tension from 9,208 to 10,455 ft. Returns could not be obtained while trying to circulate with the liner in place. The mud stayed level at the surface while going in the hole. There were no mud returns while running the liner. The cement job began with 10 bbl of 15.5 ppg mud flush followed by 250 sacks (375 ft3) of low water loss cement. Cement was pumped at an average rate of eight barrels per minute. The liner wiper plug was bumped up with 1,800 psi. There were no returns through the whole job. Five stands of drill pipe were pulled for safety reasons and the piggyback packer set at 8,743 ft. No circulation was done because without returns, cement could not have gotten on top of the packer (unless a leak developed in the drill string, but bumping the plug and holding pressure was reassurance that this did not happen). The liner top was squeezed with 200 sacks (300 ft3) of low water loss cement. Final squeeze pressure was 1,200 psi on 15.2 ppg mud. A total of 8 bbl (209 ft) of cement was left on the top of the liner. Pressure was held on top of cement for eight hours to be sure the well was not going to come in. The piggyback packer was then released and pulled out of the hole.

19.5

19.0

7-in. casing at 9.715 ft 5-in liner at 10.326 ft 17.5 ppg mud. 18.0 ppg cement 115 ft overlap 6-in bit Washed to 6.875-in hole

8 bbl/min

Equivalent fracture density at 9.716 ft

6 bbl/min

4 bbl/min 18.5

2 bbl/min 18.0

17.5 5

5.1

5.2

5.3

5.4

5.5

5.6

5.7

5.8

5.9

6.0

Equivalent liner hanger slip OD in Figure 29 - The equivalent circulating density imposed at the intermediate casing shoe can be increased by setting the liner hanger before cementing. This added restriction can cause lost circulation or bridging over of cuttings in the hanger area. (After Graves13).

RESULTS The liner top was successfully pressure tested, both positively and negatively. The cement bond log run showed good bonding across the zone of interest. No uncemented gap was found between the bottom stage cementing and the squeezing done on the top of the liner. The well was perforated from 10,019 to 10,022 ft just above the water Reprinted from World Oil magazine, May 1988 with permission from the authors.

LITERATURE CITED FOR CHAPTER 7: For the references cited in this chapter, please refer to the back page, (all references for the entire document).

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Chapter

8.

Correct Techniques for Getting a Cement Squeeze on the Liner Top the First Time

f correct techniques are followed, Ioperators can usually get a cement

stop the well from taking fluid by reducing the hydrostatic pressure. If the loss of returns is severe enough, the operator can simply set the packer and “bullhead” the entire squeeze job, rather than spotting the cement close to the packer before commencing squeezing.

squeeze on the liner top the first time.

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

Once cement is spotted near the packer, it can be set and squeezing begun. The water and cement should then be pumped through the casing above the liner and through the overlap at as high a pump rate as possible to ensure that all of the mud is displaced efficiently from the casing above the liner an the liner overlap. This eliminates the possible mud contamination problem as described by Shyrock and Slagle55 (see Fig. 30). Water goes into turbulent flow when moving at close to 44 fpm. Minimum pump rate while squeezing should be high enough to put the water in turbulent flow in the casing above the liner top. The cement is then simply pumped into place.

WHEN LOST CIRCULATION OCCURS, a cement squeeze may be necessary on the top of the liner. If the liner top can be broken down, there are certain procedures the authors take to get a successful squeeze on a liner top the first time.

SQUEEZE TECHNIQUES First, a breakdown pressure should be obtained to aid in deciding how much cement should be used. (Anti-migration cement should be used if there is a possibility of annular gas flow.) Attempt to pump through the liner top at 6 to 10 bbl per minute to create a larger fracture. The goal is to lower squeeze pressures to achieve a higher pump rate. The reason for this will be explained later. A high pump rate with low pressures through the liner overlap would require a squeeze with more cement than if the pump rates were low and pump pressures were high. (As discussed in an earlier installment, it is harder to obtain a breakdown pressure with mud than with an aqueous solution such as salt water or acid.5,55 If necessary, by using a tailpipe below the packer, water, saltwater or acid could be spotted on the liner top for easier penetration.)

As stated so aptly by Crenshaw,56 a fallacy of squeeze cementing is the idea that high squeeze pressures are required to obtain a satisfactory squeeze. In fact, the slurry simply needs to stay in place until it hardens. Dehydration does not have to occur to get a cement job in the overlap. As also stated by Crenshaw,56 “the routine method of testing cement compressive strength in the lab does not allow any loss of mix water from the slurry. So, it sets in the lab without being dehydrated.” Squeezing the liner top should be treated like a primary cement job. Squeezing a 200-ft overlap is not like squeezing perforations. The authors have seen liner tops squeezed three of four times before getting a test on the liner top.

Calculate the BHP with the pump shutdown (this takes friction loss while pumping out of the calculation). Based on this BHP calculation, the job is planned to “chase” the mud with a partial water cushion to give a final hydrostatic pressure on bottom with the cement in place 1,000 psi less than the original BHP with the pump shutdown. This keeps the cement (which is usually heavier than the mud) from further opening the induced rupture to such a degree that the squeeze string goes on a vacuum and the cement stops falling below the liner overlap. This also guards against a second zone breaking down, which has a higher rupture pressure but a lower propagation pressure so that it too won’t allow the work string to go on a vacuum. This also lowers reversing–out pressures if this becomes necessary.

In all cases of observed failures, the hesitation squeeze technique (alternation pumping and shutdown periods) was used along with low-water-loss cement slurries. Low pump rates of no more than ½ to 1 bbl per minute were normally used. It is felt that the situation depicted in Fig. 30 also occurs on top of the cement slurry when it gets below the squeeze packer, and that trying to obtain a squeeze pressure pumps a “mud core” through the cement because the low intermittent pump rates cause part of the cement slurry to gell and become less pumpable. To illustrate, most overlap volumes are less than 5 barrels. If cement was circulated on top of the liner, but the liner top leak is caused by a channel (say a displacement efficiency of 80% was achieved in the overlap), this means that only one 1 bbl of cement is needed to fill the channel. This small volume of cement does not require much extraneous material to contaminate it. Also, as mentioned earlier, if the first squeeze is not successful and the squeeze is overdisplaced for another squeeze, a mud core or channel is pumped through the cement rather than the entire cement slurry being displaced. This is surely magnified on directional holes. Consequently, if the operator tries to leave the top of the cement in the same place during the second squeeze, there is a greater chance that mud will be left in the channel and overlap again. Some would argue that a hesitation squeeze ensures that sufficient pressures are achieved to break down other channels that require more pressure to pump through. Consequently, it is reasoned, all the cement goes through the least resistive channel as long as the pumping pressure and rate do not change. This argument does have merit. But the authors do not feel that liner tops that had to be squeezed three times had three separate channels. If this was the problem, then the hesitation squeeze should have done the job the first time.

The packer is set for squeezing 8 to 10 bbl above the top of the liner. The authors recommend leaving this much volume between the squeeze packer and liner top so that in the event a squeeze is not obtained (i.e., the pressure cannot be bled off), the operator can overdisplace the first squeeze and do a second squeeze. In the event the first squeeze has a channel through it and the top of the channeled cement is 3 to 4 bbl above the top of the liner, there will be sufficient volume to underdisplace the cement and still leave it in place below the squeeze packer, say 3 to 4 bbl below the packer and 6 to 7 bbl above the liner top. Try to plan the job to leave 3 to 4 bbl of cement on top of the liner on the first squeeze. This allows for errors in the calculation of displacement volumes to avoid over or underdisplacing cement. A low-water-loss cement slurry is always mixed. A minimum 20-bbl water spacer is pumped down the work string ahead of the cement. The cement is pumped, followed by a 5-bbl chemical spacer, drilling mud and the appropriate amount of water cushion behind the mud. The water is pumped ahead of the cement for two reasons: First, to displace out as efficiently as possible any mud above the liner top and in the overlap; and because the water helps ensure that the cement is not overdisplaced, ending up around the squeeze packer. The authors feel this is the number one reason squeeze packers are cemented in the hole. This is especially possible if the well is taking mud. The spearheaded water should also help Reprinted from World Oil magazine, May 1988 with permission from the authors.

Generally, there is not more than one or a maximum of two channels through liner overlaps except on “honeycombed” cement. For honeycombed cement, there are many “microchannels.” For this problem, the authors recommend getting acid in the overlap area and keeping it in place until the acid is spent.

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This may need to be done more than once. A hesitation squeeze with low-water-loss anti-gas-migration cement should be used to help ensure pumping into all the microchannels.

fluid back out of the channel. When pressuring back up on the cement, the operator may pump back in 1 bbl less than was bled off, in which case there could still be mud, cement filtrate or saltwater in the channel. Although often decried by efficiency experts, it is cheap insurance to take extra rig time to wait on cement until it is certain there will be no flowback. The cement must not be “disturbed,” so to speak. Remember also that the larger the water cushion, and consequently the differential pressure, the longer the operator should wait on cement

One more recommended precaution if a hesitation squeeze is deemed necessary: Use a cement retainer set within 50 to 75 ft of the top of the liner for reasons shown in Fig. 30. This means squeezing with cement in the workstring above the retainer, which some operators are reluctant to do. But the main objective is to avoid getting mud below the squeeze tool, which can allow a mud core to be pumped through the cement. This is less likely to occur inside the workstring above the squeeze tool. The retainer has the disadvantage that it must be drilled out. Nevertheless, cement has to be drilled out in either event, and the retainer allows the workstring to be pulled out of the hole immediately.

EVALUATING CEMENT JOB BEHIND LINER Once primary liner cementing has been completed and the liner top has been tested and cement has cured, the next step is to determine if the zone of zones of interest have been isolated. A bond log is normally run to determine this. Proper precautions should be taken to run a bond log. Any pressure decrease inside the liner after the cement has cured allows the casing to contract and can break the cement/casing bond, creating a micro-annulus. A cement bond recorded under these conditions of a microannulus will not represent the annular cement fill accurately. A micro-annulus cannot be distinguished from a channel with a high degree of certainty.

Casing

Packer

According to Fitzgerald, McGhee and McGuire,57 unless a cement bond log (CBL) is recorded with the correct fluid pressure of the interval to be logged, the log has little chance of correctly defining the amount of annular cement fill. According to the authors, any increase in pressure applied to the casing, such as pressure testing or squeezing the liner top, can create a micro-annulus. They go on to explain that casing will return to its original configuration after a pressure increase/decrease cycle. Cured cement does not. They recommend that well history be researched to ascertain the maximum pressure exerted on the casing after the annular cement cured, and then running the CBL under that same pressure. For instance, if final bottomhole squeeze pressure while squeezing the ling top was 2,000 psi over mud hydrostatic pressure, then the CBL should be run under 2,000 psi with the original mud weight. Some log “scholars” say they can factor out a micro-annulus when evaluating a bond log, but this is less reliable. The referenced authors claim 90% accuracy in zone isolation decisions when applying the appropriate pressure to the casing.

Cement Slurry

Cement Channelled Through Mud Mud

Figure 30 - Packer location is important. In this example, packer is set too high, allowing cement slurry to be contaminated as it channels through mud to reach perforations or holes (after Shyrock and Slagle,55 graphic after Suman and Ellis 5 ).

Pressuring up to run a CBL can present a problem if bottomhole squeeze pressures are high and the burst rating of the intermediate casing is unknown. There are two solutions to this problem. The first and best way is to run the CBL before testing or squeezing the liner top. If this is not palatable to the operator, and the zone of interest is near the bottom of the liner, then consideration could be given to leaving the top float collar above the zone of interest to isolate it from squeeze of surge pressures during trips. The liner top could then be squeezed and tested and then the float equipment drilled out and the CBL run. Another option would be to set a retrievable bridge plug inside the liner while squeeze work or testing of the liner top is going on.

The worst scenario would be for the cement to set up prematurely in the workstring while squeezing. This would mean having to clean out the cement from inside the workstring, which is not very expensive when compared to the cost of redoing a squeeze. The time saved from waiting on cement with a retrievable packer is about the same time required to drill the retainer. There is also always the danger of cementing a retrievable squeeze packer in the hole. As discussed earlier, if the antigas-migration cement depends on quick thixotropic properties to prevent gas flow and a retrievable squeeze packer is used, the cement should be displaced below the packer before doing a hesitation squeeze. Otherwise the quick-forming gel strengths of the cement could cause it to become unpumpable.

The authors believe that all CBLs should be run in liners with 500 psi over the maximum hydrostatic pressure that the cement was cured under, if well conditions permit. This should remove any doubt about a micro-annulus and compensate for any surge pressures created while tripping in the hole and hydrostatic pressure reduction caused by mud heating and expanding. Two words of caution should be noted if the decision is made not to squeeze the linger top before running the CBL and if the zone of interests below the float or landing collar. First, if the plug is drilled up before squeezing the liner top (to enable running the CBL across the pay zone), there is a possibility that when testing the liner top, the operator could pump through the float equipment if the cement has not set up, due to contamination, and the plug was not bumped, or if it leaks. This could result in all of the squeeze cement going inside the liner. Second, drilling crews tend to

One final field practice needs to be mentioned: It is common practice to bleed off squeeze pressure after a certain amount of time to check for backflow. If the pressure will not bleed off, pressure is reapplied to the same shut-in pressure, and waiting on cement is continued. An effort is made to pump back in precisely the same volume of fluid that was bled off. It is felt that this process can also ruin a squeeze job on a liner top. If the cement has not set, bleeding off the workstring presents the potential of allowing mud, cement filtrate or saltwater to flow back into the overlap from the open hole. In the example shown earlier, 1bbl of flowback is enough to displace all of the cement out of the channel from the first squeeze. Repressuring back up to shut-in pressure may not necessarily displace all the foreign Reprinted from World Oil magazine, May 1988 with permission from the authors.

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The operator then made a trip for an 8½-in. bit. No cement was found on top of the liner. A 9⅝-in. squeeze packer was run and the liner top was broken down with 400 psi pump pressure and 16.8-ppg, and then squeezed with 250 sacks of 16.4-ppg low-water-loss cement. The final shut-in squeeze pressure was 280 psi with 16.8-ppg mud. A hesitation squeeze method was utilized.

relax filling up the hole on trips once cementing operations are completed. They should be reminded that zones behind the liner could still come in through the overlap. As always, the hole fillup should be monitored on trips and the hole kept full of mud.

REMEDIAL CEMENT WORK BEHIND LINERS Once the decision has been made that a squeeze is necessary inside the liner, the breakdown pressure should be such that perforations will take fluid without fracturing the rock.55 As pointed out by Murphy58 though, in almost all instances a fracturing pressure must be reached to get the perforations to take fluid. The highpermeability, low-pressure or least mud-filled perforations will take fluid while other, more severely plugged, perforations may never be broken down. This can occur even if low-water-loss cement, and good hesitation squeeze procedures, are applied. According to Rike,58 most squeeze failures can be attributed to subsequent cleanup of previously plugged perforations (see Fig. 31). He goes on to say that mud filter cake has demonstrated it is capable of withstanding pressure differentials up to 5,000 psi, especially in the direction from wellbore to formation. A solids-free fluid is necessary for squeezing off all the perforation channels, not just some of them. The authors have seen operators attempt to break down squeeze perforations with 4,000 to 5,000-psi surface pressure in heavy muds and then complain that the CBL is unreliable, the primary cement job declared good, and the squeeze called off. They are consequently surprised when the well is tested and produces extraneous gas, oil or water.

The first squeeze job did not hold, and the liner top was resqueezed with 450 sacks of 16.4-ppg low-water-loss cement. (Note that the liner overlap volume was less than 2½ bbl. The cement volume used was over 120 bbl for the second squeeze.) The hesitation squeeze technique was used again with maximum pump rates of two barrels per minute. The final shut-in squeeze pressure was 800 psi. Firm cement was drilled to the liner top at 8,665 ft. The operator then made a prudent decision to test the liner top with a squeeze packer to enable both a positive and negative differential test with a 16.7-ppg mud. The liner top was tested to an equivalent mud weight (EMW) of 19 ppg, and it held. (Remember, the leakoff test on the 9⅝-in casing shoe held an EMW of 16.2ppg.) The drill pipe was displaced with water for a negative test to an EMW of 14.7 ppg. The packer was set and an attempt was made to bleed off the drill pipe pressure. The well began to flow. The well was shutin and drill pipe pressure built up to 300 psi. The liner top was resqueezed a third time with 76 bbl of cement. The preceding case history shows how a solids-laden mud can plug a channel of perforations with positive pressure differentials. It also goes without saying that negative differential pressure tests should always be done on liner tops, especially when solids-laden muds are used. If the operator has to work with heavy mud weights, and does not want to change to a brine system to squeeze, consideration should be given to spotting a heavy brine or viscous polymer (to stop barite settling between the solids-laden mud and spotting agent interface) across the interval to be squeezed in the following manner:58 x Lower retrievable packer to the bottom of existing of proposed perforations. Spot a solids-free fluid or acid (acid density can be increased to approximately 12 ppg).

Mud or Debris

x Pull packer back up to the packer seat and set. x Pump into formation and flow back a couple of times to allow mud to be back-flushed if casing is already perforated. Use a 90° phased perforating gun, since a channel may only be on one side of the casing and the chances of perforating into such a channel with a single-phase gun are minimal5 (see Fig. 32). Ideally, the solids-free fluid should be spotted before perforating and then the perforations shot under balanced through tubing. (This would preclude using a cement retainer because of its restrictive ID.) Otherwise, if the liner is perforated with a casing gun, the hydrostatic of the mud will necessarily be overbalanced. With a solids-free fluid, the perforations could break down at reservoir or slightly higher pressure and create a well-control problem as the fluid level drops below reservoir pressure due to momentum. Or the perforations could “drink” the solids-free fluid until mud gets to the perforations and plugs them with wall cake. In this event, the operator has gained nothing for his trouble.

Figure 31 - When perforating with mud in the hole, the more severely plugged perforations may never be broken down. They have demostrated the ability to withstand differential pressures from the wellbore to formation of up to 5,000 psi.59 Squeeze failures can probably be attributed to subsequent cleanup of previously plugged perforations (after Rike59). The following case history will be used to show how barite and gel can plug perforations or channels when positive pressure (wellbore to formation) is applied. On a well on which Ashland was a partner in Cameron Parish, La., the operator had set 9⅝-in casing at 8,838 ft. The shoe had a leakoff test of 16.2 ppg. An 8½-in hole was drilled to 12,225 ft. Lost return problems were occurring with 16.3-ppg mud. Therefore, the decision was made to run a 7⅝-in liner. The liner was run to 12,225 ft. The hole took mud while the liner was being run. The liner hanger was set with the liner top at 8,665 ft. The liner was cemented with full returns with 360 sacks (540 ft 3 ) of 16.8-ppg low-water-loss cement. Reprinted from World Oil magazine, May 1988 with permission from the authors.

If the operator insists on working with mud, then the only viable option is the “high-pressure” squeeze operation. The first requirement is to break down the perforations. As pointed out by Rike,59 the volume of cement required is a function of the width and depth of the fracture generated. It can be kept low by easing up to the breakdown pressure. To help ensure break down of all perforations, the authors recommend running acid or chemical washes ahead of the cement. Once cement arrives at the perforations, a high squeeze pressure is essential to

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getting a successful squeeze job in a single stage. Beach, O’Brien and Goins point out that only by following the p r o c e s s o f h e s i t a t i o n c a n e n o u g h p r e s s u re be built to force cement into mud-plugged holes. 60 As discussed earlier, squeezing with heavy muds may mean that the final bottomhole squeeze pressure may need to be 5,000 psi higher than the bottomhole breakdown pressure.

Final bottomhole squeeze pressures should be as high as possible. Conversely, if the perforations had been clean, a squeeze could most probably be attained with a bottomhole squeeze pressure above the pump in pressure of 500 to 1,000 psi with no bleedoff or flowback for 10 to 15 minutes.58 Again, in the authors’ opinion, the cement should still be in the workstring while squeezing to avoid pumping a mud core through the cement during a high-pressure hesitation squeeze. Also, according to Murphy, the job should be designed so that the hydrostatic head of cement slurry at any time during the job will not exceed wellhead equipment or maximum casing pressure limitations. This is a minimum pressure limitation since some pressure will be required to start the slurry moving depending on the delay and gel strength of the slurry. 58 This is another good reason to go with a partial water cushion. It lowers the reversing pressure required if reversing out is deemed necessary.

Entrance Hole Entrance Hole Casing

90° Phased Gun

One final recommendation: If squeeze packers are used, only those that have concentric bypasses through the tool that ensure that reversing is accomplished around the bottom of the tool should be used. This helps guard against leaving cement around a squeeze packer that may have gotten there during squeezing.

Mud Channel

Cement

Entrance Hole

Figure 32 - Chances of shooting into a channel are much improved when using a 90º phased gun to perforate (after Suman and Ellis5).

LITERATURE CITED FOR CHAPTER 8: For the references cited in this chapter, please refer to the back page, (all references for the entire document).

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

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Chapter

9.

Five Case Histories Detailing Field Procedures Providing Acceptable Results

Five case histories of recent drilling and

cement started filling the annulus. Rotation was increased to 40 rpm until the end of the job. Cement was pumped a 3 bpm to minimize the equivalent circulating density.

production liner jobs detail field procedures that provided acceptable results. Included are solutions used to solve operational problems encountered.

No cement was circulated on top of the liner because hole volume was underestimated, probably due to pressured shale sections washing out while circulating. The liner top had to be squeezed. Three zones were tested below 13,800 ft with no squeezing required. The bond log showed 95 to 100% bonding across test zones an estimated displacement efficiency to top of cement was 87%.

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

Case 2: Production Liner, Cameron Parish, Louisiana.

IN THE PREVIOUS EIGHT INSTALLMENTS of this series, the authors have discussed many practical and theoretical aspects of liner cementing, such as rotation and reciprocation, getting liners to bottom, dealing with flash setting cement, preparing liners for testing, using packers, preventing annular gas flow, remedying lost circulation and cement squeeze techniques.

Ashland Exploration drilled Sweetlake Land and Oil Co, No. 4 to a TD of 12,500 ft; 9 5/8-in. casing was set at 8,900 ft. An 8 ½-in. hole was drilled to TD with 17.0-ppg mud and frequent lost returns. Even with 17.0-ppg mud, mud showed a gradual chloride increase and high background and connection gas.

In this final part, five case histories are discussed where good liner cementing practices were used. Four wells are located on shore the Texas-Louisiana Gulf Coast and one on-shore California.

A 4,007-ft 5 ½-in., LT&C liner was run with one slim-hole centralizer per joint. Centralizers were allowed to float to facilitate reciprocation or rotation. The liner was run successfully to bottom. Mud was conditioned two complete rounds. Mud weight was not reduced because of gas and a slow high pressure saltwater sand feed-in. The liner was reciprocated while conditioning.

Case 1: Production Liner, Wharton County, Texas.

The liner was cemented with 30 bbl of 17.0-ppg spacer followed by 630 sacks of anti-gas-migration cement mixed at 17.5 ppg. The liner was rotated at 50 rpm after the cement began filling the annulus. Cement was pumped at a high rate of 6 bpm because of the large annulus.

Ashland Exploration drilled its R. L. Fields No. 1 to a TD of 14,465 ft 9 5/8-in. casing was set to 7,589 ft, and a 7 5/8-in. drilling liner to 11,154 ft. A 6 ½-in. hole was drilled to 14,465 ft. Numerous lostreturns were encountered while drilling with 17.6-ppg mud to control shale. Reaming was necessary on all trips to go back to bottom. The well was logged and a decision made to run a mechanical set 5-in. liner. A “piggyback packer” was not run because this would preclude rotating or reciprocating. Since three zones close to bottom were to be tested, the operator decided it would be more economical to have a squeeze only the top of the liner if returns were lost. By rotating, it was felt that three or more squeeze jobs on the test intervals could be saved.

Since the zone of interest was a gas sand, no effort was made to get cement on top of the liner in the event the anti-gas-migration cement did not work. This would facilitate a liner top squeeze with anti-gas-migration cement, if needed. There was no annular gas flow, and the liner top was squeezed with 30 bbl of water followed by 300 sacks of low-water-loss cement pumped in place below the squeeze packer at 8 bpm. Cement was displaced to 8,393 ft, or 100 ft above liner top.

A pore pressure plot indicated no exposed sand had pressures close to the mud density, so no potential well control problems existed if returns were lost. A 3,614-ft, 5-in. LT&C liner was run with one slim-hole centralizer on every joint. Centralizers were allowed to float. As noted earlier, the heaving shale problem due to being underbalanced in pressured shales could not be solved. The liner was run to 13,665 ft, could not be washed deeper by rotating, and was pulled. All centralizers are intact. A conditioning trip was made, and the hole was reamed from 13,482 to 14,465 ft.

Breakdown pressure before squeezing the overlap was only 50 psi with 17.0 ppg mud. Final SI squeeze pressure was 1,300 psi as a 2.500 partial water cushion was utilized to assure that cement would stay in place when pumping stopped. The liner top was successfully tested both positively to an EMW of 19.0 ppg and negatively to an EMW of 9.0 ppg. The bond log confirmed a satisfactory job. Estimated displacement efficiency to the top of the cement was estimated at 81%.

Case 3: Production Liner, Cameron Parish, Louisiana.

The hole was still making excess shale. It was believed heaving shale may have been trapped under bow springs on certain centralizers, preventing one of them from collapsing fully in a tight spot. To combat this, rigid body centralizers were run and allowed to float. This allows rotation but will not let hole debris become wedged under a centralizer. Hanger slips were removed and a 6 ½-in. bit was made up on the bottom of the liner.

Ashland Exploration’s Sweetlake Land and Oil Co. No. 2 developed a sand-control problem that collapsed its 5 ½-in liner. A window was cut in the 7 5/8-in. liner set at 12,225 ft from an anchored whipstock with its top at 11,944 ft. A 6 ½-in. hole was drilled to 12,460 ft. with 16.7-ppg mud. A packed hole assembly was used to ensure the replacement liner would to through the window and into the 6 ½-in. hole.

The 5-in. liner was rerun. The hole had to be reamed numerous times at 13,665 ft. Mud was conditioned and the liner reciprocated. Mud weight was not reduced while circulating to prevent aggravation the heaving shale problem, and possibly pack off the annulus. When getting bottoms up, excess shale was again coming over the shaker.

A 729-ft, 5-in., LT&C liner was run with one slim hole cetralizer per joint, which were allowed to float between collars. Four seal rings of deformable rubber were run in the overlap area to allow use of a 9.0-ppg brine packer fluid, which would cause the liner to contract.

The liner was cemented with 40 bbl of 17.6-ppg spacer followed by 140 sacks of batch mixed anti-gas-migration cement mixed at 17.9 ppg. The liner was rotated at 20 to 30 rpm until Reprinted from World Oil magazine, May 1988 with permission from the authors.

Liner and centralizers were run slowly through the window and 6 ½-in. hole to 12,460 ft. with no problems. Centralizers did

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not bunch up, as many have claimed they will do. Mud was conditioned while reciprocation the liner. Mud weight was cut from 16.7 to 16.5 ppg to lower equivalent circulating density and im- prove chances for circulating cement on the liner top.

A large volume of cement was mixed in case the weakest formation was well below the 9 5/8-in. casing shoe to cover as much of the back side of the liner as possible with cement. Cement was displaced with 88 bbl of 16.6-ppg mud and 14 bbl of fresh water.

The cement job began with 38 bbl of 16.5-ppg spacer. After batch mixing 67 of the 155 sacks of cement on location to 17.2 ppg, a P-tank valve twisted off and the remaining 88 sacks could not be mixed. Because the liner might stick while waiting on more cement, the job proceeded with the 67 sacks mixed.

After eight hours WOC, pressure was bled off and the drill pipe reversed out. An 8 ½-in. bit was run and found top of cement at 7,185 ft. Firm cement was drilled to the top of the liner at 7,299 ft. Liner top an liner shoe were successfully tested to an EMW of 21.8 ppg. Because this was a drilling liner, no bond log was run.

When cement started to fill the annulus, the liner was rotated at 40 rpm. Cement was pumped at 3 bpm. Due to insufficient cement being mixed, it was not circulated on top of the liner.

Case 5: Production Liner, Lake Tulare Field, Kings County, California.

The liner top was squeezed with 150 sacks of low-water-loss cement, and then tested to an EMW of 18.6 ppg and 9.0 ppg, respectively. The 16.5-ppg mud was replaced with 9.0-ppg brine. No gas was detected from the 5-in. liner top, and no squeezes were needed across the pay despite only 5 min of contact time. The bond log again confirmed a good job. Estimated displacement efficiency across the payzone was 95 to 98%.

KCDC 17-9 was directionally drilled to measured TD of 13,550 ft. A string of 9 5/8-in.casing was set to 11,342 ft. and 8 ½-in. hole was drilled to 13,550 ft. Maximum angle was 14 1/2° and hole angle was gradually brought back to 2° at TD. Mud weight at TD was 10.4 ppg. A decision was made to run a 7-in. production liner. Operators of other wells drilled in this field had never been able to rotate or reciprocate liners. All previous liners had been run without centralizers, because everyone was convinced they would keep the liner from reaching bottom. Total rounds of backlash from the drill string with 5-in. drill pipe and 6 ½-in. drill collars was eight at 40 rpm.

Case 4: Drilling Liner, Wharton County, Texas. Ashland Exploration drilled 8 ½-in. hole in its R. L. Fields No.1 to 11,154 ft with 16.5 ppg inhibited water base polymer mud. A “packed pendulum”29 with stabilizers 66 ft and 80 ft above the bit was used to control deviation. Thus, only the bottom 66 ft of hole required reaming with a short pony drill collar above the near-bit stabilizer.

The authors decided to run slim hole centralizer on every joint, and, because of liner length, planned only 50% excess cement over the hole caliper. Centralizers were allowed to float between collars. A 2,686 ft. 7-in. 32-ppf, P-110, LT&C liner was run to TD. Backlash with liner in the hole was only 3 ¼ rounds at 40 rpm.

After logging, the BHA was modified to have a near-bit stabilizer, pony drill collar and another stabilizer 9 ft above the bit. It again was considered imperative that a packed hole assembly be used to ensure getting a 7 5/8-in. FJ liner with centralizers to bottom. A four-arm dipmeter showed hole was nearly gauge. The bottom 93 ft was reamed with the packed hole assembly in case of hole spiralling due to drilling with a pendulum hookup.

The liner was cemented with 100 bbl of 11.0 –ppg spacer followed by 650 sacks of low-water-loss cement. A large spacer was used because of liner length and the directional hole. There was concern about pumping too much cement and having it channel 2,000 or 3,000 ft above the top of the liner. It was considered prudent to use excess spacer to achieve adequate contact time across payzones and the liner overlap. The liner was rotated at 40 rpm throughout the job, and full circulation was maintained.

A string of 9 5/8-in. intermediate pipe was set at 7,589 ft. A 3,855-ft, 7 5/8-in., 39-ppf P-110 FJ liner with one slim-hole centralizer per joint, free to float between slip type stop collars, was used. The hole began taking mud when the liner was at 9,100 ft. The hole was kept filled with water on the backside, while running the liner. Fill was washed from 11,146 to 11,154 ft. Circulation was started with partial returns, then increased to full returns by rapidly picking up the liner and swabbing the hole. Full returns would not have been achieved had the liner been hung off before cementing. Mud was conditioned for two complete circulation to minimize rhelolgical properties.

Due to a low mud weight and high fracture gradient at the 9 5/8 shoe, cement was reversed out at the top of the liner. About 10 bbl of cement were reversed out. Top of cement was left at 10,852 ft. Hard cement was drilled to top of the liner at 10,863 ft. (The liner top was found at 10,869 ft, or 6 ft deeper. This occurs on all liners because the drill pipe stretches while it is being run due to the added weight of liner. Once the liner was hung off, stretch in the drill pipe was reduced approximately 6 ft. This should be kept in mind when spacing out, for instance, a tie-back stinger. New pipe measurements should be obtained or stretch calculations made after liner is hung off. This is more pronounced the longer an heavier the liner is.) The liner was both positively and negatively tested to EMWs of 20.0 and 8.3 ppg, respectively, as per state regulations. A bond log was run and showed good bonding for the entire length of the liner. A test set of perforation did have to be squeeze later at 13,401 ft due to extraneous water production during a flow test. Estimated displacement efficiency was 73%.

The liner was reciprocated to help displace all dehydrated mud while conditioning, and then was cemented with 30 bbl of 16.6-ppg spacer and 450 sacks of batch-mixed low-waterloss cement mixed at 16.8 ppg. Full returns occurred throughout the entire displacement until the final 75 bbl of mud were pumped. No cement was found on top of the liner. (This job was described in Part 4, July 1988). Since this was a drilling liner, and higher mud weights and temperatures were expected, it was important not to leave a large uncemented interval behind the pipe because of potential buckling. A retrievable squeeze packer was run and set at 7,047 ft to test the liner top at 7,299 ft. The liner top had to be pressured to an EMW of 19.1 ppg to breakdown the formation. After break down, the formation bled off to an EMW of 18.1 ppg. The liner top was squeezed with 20 bbl of fresh water followed by 400 sacks of batch-mixed low-water-loss cement. Pumping rate was 7 bpm, final squeeze pressure was 1,300 psi, and SI dill pipe pressure was 1,025 psi. Reprinted from World Oil magazine, May 1988 with permission from the authors.

LITERATURE CITED FOR CHAPTER 9: For the references cited in this chapter, please refer to the back page, (all references for the entire document).

9.2

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

31 Gill, James A., “Hard rock drilling problems explained by hard rock pressure plots.” IADC/SPE 11377. February 1983.

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

32 Aadnov, B.S. and Chenevert, M.E. “Stability of highly inclined boreholes.” SPE/ AIDC 16052. March 1987.

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

33 Bradley, W.B. “Mathematical concept—stress cloud—can predict borehole failure.” Oil & Gas Journal. February 19, 1979.

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

34 Hopkin, E.A. “Factors affecting cuttings removal during rotary drilling.” Journal of Petroleum Technology. 1967.

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.

35 Dunbar, M.E., Warren, T.M., and Kadaster, A.G. “Theory and solutions to bit sticking caused by borehole deformation.” SPE 14179. Las Vegas, Nevada, September 1985.

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

36 Syker, Ron. “Control of filtrate loss critical to cementing success.” Petroleum Management, October 1985.

February 1, 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.

37 Goins, W.C., “Blowout Prevention,” Gulf Publishing Company, June 1973, Houston, Texas. 38 Goins, W.C., “Lost circulation remedial action,” Internal Memo, Gulf Oil Co.

Doherty Fund of AIME, 1976.

39 Adams, Neal, Well control problems and solutions, The Petroleum Publishing Co., 1980.

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

40 Christian, W. W., Chatterji, J., and Ostroot, G. W., “Gas leakage in primary cementing- A field study and laboratory investigation.” SPE Paper 8257, 1979.

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

41 Tinsley, J. M., Miller, E., Sabine, F. L., and Sutton, D. L., “Study of factors causing annular gas flow following primary cementing,” J. Pet. Tech., August 1980.

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

42 Sabins, Fred l., Tinsley, John M., and Sutton, David L., “Transition time of cement slurries between the fluid and the set state,” SPE 9285, Dallas, Texas, 1980.

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

43 Cheung, P. R., and Beirute, Robert M., “Gas flow in cements,” SPE 11207, Dallas, Texas, September 1982.

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

44 Levine, D. C., Thomas, E. W., Bezner, H. P., and Tolle, G. C., “How to prevent annular gas flow cementing operations,” World Oil, October 1980.

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.

45 Cook, Clyde and Carter, L. G., “Gas communication in directional wells.” DrillingDCW, February 1976.

16 Lindsey Jr., H.E. “Rotate liners for a successful cement job.” World Oil. October 1986.

46 Cook, Clyde and Carted, L. G., “Gas leakage associated with static cement,” Drilling-DCW, March, 1976.

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., “Cementing 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.

47 Sykes, R. L., and Logan, J. L., “New technology in gas migration control,” SPE 16653, September 1987. 48 Sutton, David L., Sabins, Fred, and Faul, Ronald, “Preventing annular gas flow— two parts,” Oil and Gas Journal, Dec. 1984. 49 Stehle, Don, Sabins, Fred, Gibson, Jim, Theis, Karl, and Venditto, J.J., “Conoco stops annular gas flow with special cement” April 1985. 50 Bannister, C. E., Shuster, G. E., Wooldridge, L. A., Jones, M. J., and Birch, A. G., “Critical design parameters to prevent gas invasion during cementing operations,” SPE 11982, San Francisco, California, October 1983. 51 Stewart, R. B., and Schouten, F. C., “Gas invasion and migration in cemented annulus: Causes and cures” IADC/SPE 14779. Dallas, Texas. February 1986. 52 Kulakofskv, David S., “Cement leakage diminished,” Gulf Coast Oil Reporter, July 1982.

23 Goins, W.C., “Better understanding prevents tubular buckling problems.” World Oil. February 1980.

53 Hartog, J. J., Davies, D. R., and Stewart, R. B. “An integrated approach for successful primary cementations,” September 1983.

24 Jones, P.H. and Berdine, D. “Oil well cementing.” Oil & Gas Journal. March 21, 1940.

54 Herbert, R. N. “Liner cementing techniques and case histories offshore western Gulf of Mexico,” IADC/SPE 14777 Dallas, Texas, February 1986.

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 Publishing Company 1982.

55 Shyrock, S. H., and Slagle, K. A., “Problems related to squeezing cementing,” JPT, August 1968. 56 Crenshaw, Paul L., “How to avoid myths of squeeze cementing,” Oil and Gas Journal, April 22, 1985.

28 Woods, H.B. and Lubinski, A., “Use of stabilizers in controlling hole deviation.”

57 Fitzgerald, D. D., McGhee, B. F., and McGuire, J. A., “Guidelines for 90% accuracy in zone isolation decision,” JPT, November 1985.

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

58 Murphy, W. C., “Squeeze cementing requires careful execution for proper remedial work,” Oil and Gas Journal, February 16, 1976.

Drilling and Production Practices. 1954. September 1976.

30 Adams, Neal, “How to control differential pipe sticking.” Petroleum Engineer.

September 1977.

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

59 Rike, J. L., “Obtaining success squeeze cementing results,” Drilling-DCW, September 1975. 60 Beach, H. J., O’Brien, T. B., and Goins, W. C., Formations cement squeezes by using low-water-loss cement, Oil and Gas Journal, June 12, 1961.

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Casing Size &

Weight Chart

Specializing in Liner Primary Cementing

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

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