Vol 6 Remedial Cementing Practices

CHEVRON DRILLING REFERENCE SERIES VOLUME SIX REMEDIAL CEMENTING PRACTICES GUIDE

SECTION A

INTRODUCTION

Table of Contents

1. Purpose 2. Basic Information 3. Reasons for Remedial Cementing 4. Recementing Casing

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SECTION A:

1.0

INTRODUCTION

PURPOSE

Since the earliest beginnings of the oil and gas industry, there has been a need for performing remedial work in order to create a usable wellbore or extend the productivity of the same. Records indicate that shortly after the turn of the 20thcentury, operators had turned to cement as the media for such repairs. Over the years, more and more remedial cement work was attempted, with “hit or miss” success. By the mid-1930's, most remedial cementing was referred to as squeeze cementing and was used extensively in the repair of a wide variety of downhole problems.

In the early 1950's, some recognized a need to control the fluid loss rate of squeeze slurries; bentonite was used as a fluid loss control additive as it was readily available. Later that decade several fluid loss control additives that were not extenders came on the market. A division in the thinking of squeeze cementing developed. Traditional thinking led toward using neat cement, while controlled water loss (CWL) squeezing gained a considerable following.

This manual explores these ramifications of remedial cementing and meshes practices with current technological information. This blend of techniques and technology provides for achieving of remedial cementing success greater than ninety percent on the first attempt. The objective of this manual is to supply to Chevron personnel, who direct remedial cementing operations, guidelines for continuous improvement in meeting their remedial expectations. In addition to an extensive treatment of squeeze cementing, other methods of remedial cementing are explored.

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BASIC IN INFORMATION

Over the years, the expressions Remedial and Squeeze cementing have been used interchangeably and incorrectly. Remedial cementing refers to any attempt to repair or improve a downhole condition with cement slurry; therefore, squeeze cementing would be a form of remedial cementing, but not the only form. An accurate definition of Squeeze cementing is the placement of a cement slurry under pressure against a permeable formation causing the slurry to dehydrate and create a cementitious seal across the formation face.

The setting of a cement plug inside an open borehole or inside a cased hole is a remedial cementing procedure that is applicable for a variety of downhole conditions. The placement of a cement slurry between casing and borehole or between casings is also a remedial cementing procedure, but may not involve either squeezing or cement plugs.

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This procedure is usually utilized when it is necessary to recement a string of casing due to the top of the primary cement column being less than desired or planned. Finally, a remedial cement job could and often does include a combination of any or all of the above situations.

There are many components of any cement job where difficulties could arise. For the most part, problems that jeopardize the cement job usually come from an unsuspected area. During the planning of a job, if a problem is anticipated, solutions and contingency plans are formulated, thereby eliminating it as a problem. The situation may still occur but it is effectively dealt with and does not compromise the outcome. The single best practice to resolve potential problems is to conduct a pre-job meeting of all personnel involved in the cementing process.

The Chevron representative directing the job should be sure that each one knows the planned procedure and what is expected of him during the job. Sometimes there is the tendency to rely on the cementing service company to make the right decisions. Generally, Chevron uses the services of reputable experienced companies. They do not intentionally come to location to sabotage our well. Without proper leadership from Chevron, sometimes, the end result is the same.

Another good habit to develop, for improvement of future cement jobs, is the practice of good record keeping. Detailed records of pressures, times, densities, rates, volumes, etc. (including pressure recorder charts, with notations where different phases of the job occurred) are invaluable when reviewing a job for opportunities of improvement (Figure 1 is an example of a squeeze data record form). Each business unit may prefer to tailor a form to their particular needs. These records should become a part of the permanent well files.

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3.

REASONS FOR REMEDIAL CEMENTING

As mentioned, remedial cementing has been used for correcting a large number of undesirable downhole conditions. Often this includes repair of a faulty primary cement job, repair of damaged casing, halting lost circulation, eliminating fluid intrusion or migration, improvement of gas / oil ratio, and the abandonment of a well or a portion of a well (see example illustrations in Figure 2).

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Remedial cementing has become an accepted and frequent practice. All too often, the decision for remedial work has been hastily made, and many times, the decision was made with little or no evaluation. Excessive amounts of cement have been bought and shipped to location for squeezing, only to be thrown away because the decision was based solely on a poor interpretation of a bad cement bond log. Upon perforating, attempts to pump into the formation were futile due to the presence of a better bond than indicated by the CBL. The decision to perforate good casing should be made only after extensive evaluation of all data.

The planning of remedial cement work should include a review of the primary cement job and/or previous remedial work, identifying affected formations, and a clear objective of what needs to be accomplished. Proper running and interpretation of wireline cement evaluation tools should be an option for acquiring data, but not used exclusively. The Cement Evaluation Manual offers valuable guidelines for this purpose. When repairing casing leaks, reliable casing integrity logs can be run to aid in determining the remedial procedure most likely to succeed.

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RECEMENTING CASING

There are occasions when the primary cement job is terminated prematurely and the casing is left with little or no cement behind the pipe. When this happens, the casing can usually be recemented in a manner very similar to an original primary job. The casing must be cleaned out, usually by drilling out the excess cement inside the casing. Determine the top of the cement column (TOC) in the annulus and perforate above it to reestablish circulation. A cement retainer can be set inside the casing above the perforations. The cement slurry is pumped through a workstring and stinger, below the retainer and out the perforations. After the cement is displaced from the workstring, the stinger is removed from the retainer closing the retainer valve. The cement retainer acts as a float collar, keeping the cement in place until it sets. When recementing a primary cement job, the integrity of the original slurry design must be reconfirmed. If it was not the cause of the problem, the original slurry design can usually be used in the repair. If the top of cement on the original job is some distance up the hole, adjustment of the slurry may be necessary for the new depth and temperature.

Another scenario is when the job appears to go well, but upon investigation, it is discovered that the annulus cement column did not extend high enough to provide the protection desired. Again, we could perforate at the top of cement, reestablish circulation, and set a cement retainer to keep the new slurry in place. Because of the distance from the casing shoe, the slurry may have to be redesigned and tested. Sometimes a slurry performance problem is identified after the cement job commences. The job could be aborted and the inferior slurry circulated out of the hole, provided the top wiper plug has not been released from the cementing head. The job could be resumed when the problem is alleviated.

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Note: When designing for the above situations, refer to the Chevron Primary Cementing Practices Guide.

Annulus Cementing ("One inch Job") - Pumping cement down the annulus using a small diameter Spaghetti String is the method commonly used to bring cement to surface on conductor and surface casings; this is also referred to as a Top Job (see Figure 3). The use of a spaghetti string has the advantage over pumping down a wellhead valve in that the slurry is circulated up the annulus with very little pressure on the formation, rather than Bullheaded into a weak zone. It is a common misconception that Bullheading the slurry will result in a uniform cement sheath in the annulus. In reality, the formation will be broken down at it weakest point (usually the previous casing shoe), and a gap of exposed casing will be left. A one-inch job may not give a uniform sheath, but it is less likely to fracture the formation.

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SECTION B

CEMENT PLUGS

Table of Contents 1.0

Reasons for Setting Cement Plugs

2.0 Slurry Design for Cement Plugs Slurry Density Thickening Time Fluid Loss Control Free Water Rheology Compressive Strength Slurry Design Considerations 3.0 Downhole Conditions Washouts Lost Circulation Mud Density Control Cement Slurry Density Control Slurry Contamination Differences in Fluid Densities Yield Point Relationship of the Fluids Rate of Displacement Geometry of the Hole Angle of the Wellbore Decontaminants Mud Kil I and Mud Kil II Spacers 4.0 Placement Procedures

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Small Plugs Balanced Plugs Plugging Tool Advantages Operation Tailpipe Scratchers and Centralizers Coil Tubing Drillable Bridge Plugs and Drillable Squeeze Packers 5.0 Calculations

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SECTION B:

1.0

CEMENT PLUGS

REASONS FOR SETTING CEMENT PLUGS

The setting of a cement plug inside a well borehole (or cased hole) is a remedial cementing procedure that is sometimes needed in the drilling or during the useful life of a well to facilitate a variety of tasks. It is a practical and economical aid when:

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Changing the hole direction.

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Setting casing off the bottom of the hole.

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Shutting off the lower portion of an open-hole completion.

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Protecting lower pay zones while squeezing higher up the hole.

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Sealing off the lower end of stuck pipe before backing off.

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Sealing off lower portion of hole while drill stem testing an upper zone.

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Combating lost circulation problems.

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Abandoning the well or a portion of the well.

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Containing a well control problem and for numerous other operations.

SLURRY DESIGN FOR CEMENT PLUGS

Slurry design considerations for a cement plug must take into account the purpose of the cement plug. Some plugs require very little in terms of slurry design. Many times sufficient thickening time is the only design criteria. Good slurry design lies along a narrow path between a safe placement time and strength development. A small number of cement plugs require exacting design performance in a number of areas. Unfortunately, these plugs usually receive no more attention than any other.

Slurry Density The slurry should be designed so that the density is at least one-half pound per gallon heavier than the well fluid. This is the minimum difference if the well fluid is a drilling mud; however, the slurry design could be greater with a clear well fluid. Slurries designed with API recommended water usually have more than sufficient density.

There are times when a higher density cement plug is required for heavier density mud systems, hence, higher bottom hole pressures. Sidetrack plugs need a higher density for increased compressive strength. An increase in density can be accomplished by

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reducing the amount of mixing water. For slight increases, this may be all that is necessary. For any appreciable increase, the addition of a dispersant will be required to maintain the fluidity needed for proper mixing and pumping of the slurry. (Also, see Compressive Strengths below.)

Increase in density above 17.5 pounds per gallon usually require that a weighting material be added to the slurry composition. Iron ore materials, hematite and ilmenite, are effective and readily available weighting materials. Although used interchangeably, there is a slight difference in specific gravities. Barite is not normally used as a weighting material because it has a water requirement to keep it mixable. The additional water reduces the effect of the barite causing the necessity of even more barite for the desired density. With heavier weight muds and oil base muds, there should be at least one pound per gallon difference in density to allow for a compatible, weighted spacer between the cement slurry and mud.

Lower density cement plugs are useful when used for lost circulation or for setting across or above a weak zone. The addition of an extender, such as bentonite, is the best way to reduce slurry density. Bentonite has the advantage of giving some fluid loss control and aids in the prevention of free water in the slurry. Other extenders may not have these controls. Lower density slurries also have lower compressive strengths. [For more information on extenders, see Volume 7, Section F, Low and High Density Cements in the Chevron Primary Cementing Practices Guide].

Small volume water spacers are usually sufficient for water base muds with a density of less than 14.0 ppg for separation inside the workstring is important, but formation contact time is not a major factor.

Thickening Time The thickening time test is run in the lab on a machine called a consistometer. The thickening time is the period of fluidity between wetting the cement solids and the slurry attaining a consistency of 70 Bearden units (Bc's) under simulated well conditions. Refer to API Specification 10; Section 8, Thickening Time Tests. The thickening time is commonly referred to, in the field, as “pump time”. Above 70 Bc's, planned movement of the slurry becomes doubtful.

A thickening time test is conducted by continuously stirring the slurry and recording its consistency while uniformly increasing the applied temperature and pressure until the appropriate bottomhole circulating conditions are reached in the appropriate time. Once bottomhole conditions are reached, they are held constant until the slurry reaches 70 Bc's. The slurry should be designed to have a thickening time equal to anticipated job time, plus a reasonable safety factor. The thickening time should not be excessive. It is undesirable to allow the cement to remain fluid in the wellbore any longer than is necessary.

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The thickening time can be extended, as desired, by adding materials to the blend that retard the setting of the slurry. Most retarders are lignosulfonate materials and can have a detrimental effect on the development of compressive strength. Other retarders, such as some fluid loss additives or some dispersants, should be considered to avoid this. When cement plugs are desired, a minimal thickening time may be preferred, and additives that accelerate can be added to the blend. The most common accelerators are potassium chloride, sodium chloride, or calcium chloride. Offshore, the substitution of sea water for sodium chloride, is a convenient and natural choice. Caution should be used when the chloride accelerators are used in combination with each other or with sea water due to the adverse reactions in slurry performance that have occasionally been experienced. Although many cement plugs are set without conducting a thickening time test, the Cementing Services Division recommends a thickening time test BEFORE any slurry is pumped.

Fluid Loss Control The fluid loss test of a slurry is a measure of the rate at which filtrate is forced from a cement slurry when the slurry is subjected to differential pressure. Generally, slurries can dehydrate (lose filtrate) if, while being circulated in place, resistance to flow is encountered. When a restriction in the flow stream (resistance) creates a pressure drop, a differential pressure is exerted across the barrier. This resistance to flow can separate the solids from the fluid phase. In the process of placing cement slurry downhole, there are many restrictions in the flowstream capable of forcing filtrate from the slurry. The amount of filtrate actually separated depends upon the differential pressure exerted and the fluid loss control inherent in the slurry design. In slurry design, fluid loss control is matched to the anticipated resistance to flow while placing the slurry downhole. Adequate fluid loss control will prevent premature dehydration of the slurry. Fluid loss values are relative, and there is no correlation between a given fluid loss value and the actual loss downhole.

Slurry gelation is a premature increase in viscosity due to the attraction between the hydrating cement particles. Gelation is a characteristic of neat cement. Fluid loss control reduces the effect of this attraction, thereby eliminating gelation as a cause for the slurry to flash set. The term “flash set” is used to describe the unplanned and unexplainable situation of the slurry becoming too viscous to pump at allowable pressures. By identifying the characteristics that induce viscosity, selecting additives to alter those characteristics, and testing under connections that best duplicate the downhole environment, flash set becomes non-existent. Gelation and premature dehydration are two main reasons for flash setting and occur when there is insufficient fluid loss control. A fluid loss value to attain when designing and testing, hence, should be on the conservative (lower) side when in doubt.

When pumping slurry through a restriction, such as a small stinger for a cement retainer, some fluid loss control should be used. When placing a cement plug across a lost circulation zone, a weak formation, or a highly permeable formation, caution should be exercised to have good fluid loss control. A permeable formation is a restriction in the flow since the slurry solids cannot go into the matrix of the formation and the filtrate can.

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While fluid loss control is not necessary for plug performance in hafting lost circulation, it is needed when spotting cement around the end of a workstring to assure its removal. Under these conditions, fluid loss control may not prevent differential sticking but can prevent premature dehydration until the workstring is withdrawn above the plug, if it is not stuck. Free Water Generally, free water is not a problem in cement plugs except for low density slurries or when set in deviated wellbores. In low density slurries, free water results from the increased volume of mixing water and/or the quality of the extender materials used. Free water can more readily breakout of a slurry in an angled wellbore than in a vertical one. Free water breakout downhole may cause a continuous water channel to form on the high side of the hole and compromise the integrity of the plug. In Chevron's cement laboratory, all free water tests are run, positioned at a 45 ° angle rather than by API specifications. A well designed cement plug slurry will exhibit zero free water when measured at a 45 ° angle after subjecting the slurry to downhole conditions of temperature and pressure.

Rheology Rheological properties for plug slurries are not a factor in the quality of the set cement plug due to the short duration of dynamic contact with the formation. A look at plug slurry rheology can be beneficial in designing a slurry that is easily mixable with available equipment. Slurries with high rheological readings warn of potential problems when mixing with less than well maintained equipment.

Compressive Strength Rapid compressive strength development after the expiration of the thickening time is important. As said before, the slurry should not remain fluid in the wellbore any longer than is necessary. Low density and over retarded slurries may take considerable time developing strength.

Sidetrack plugs require rapid and high strength development. Ideally, the sidetrack plug should have greater strength than the formation. While the strength does not have to be greater than the formation strength to sidetrack, it is important to attain considerable strength. Strength development of about 3500 psi is usually sufficient for sidetracking. When sidetracking through hard formations, 4000 to 5000 psi strengths may be desirable. The way to design for compressive strength is to increase the density of the slurry. The least complicated and most economical way to achieve this is to reduce the amount of mixing water. The addition of a dispersant may be necessary to control viscosity. Most cement slurries can be densified to about 17.0 pounds per gallon without difficulty. Slurry densities above 17.5 ppg are more easily attained by adding weight materials, such as hematite or ilmenite. (Also see Slurry Density above).

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Adding sand to the cement blend is another way to improve the compressive strength of a cement plug. The addition of about 35 percent, by weight of cement (BWOC), of Oklahoma #1 sand, coarse silica, or frac sand is a common procedure of many cementing service companies. Tests conducted by Chevron Cementing Services Division do not indicate that the addition of sand attains higher strengths than the reduction of mixing water for equivalent densities. When using a combination of added sand and reduced water, higher strengths are possible.

While most plugs are set without testing, the lab can render valuable assistance in strength development of plug slurries. The Ultrasonic Cement Analyzer (UCA) is a nondestructive compressive strength tester that continuously monitors strength development of cement compositions. A single sample of cement slurry is placed in the instrument; pressure and heat are then applied to simulate downhole conditions. Measurements of the cement's ultrasonic velocity are started during the fluid state and continue through initial set to any desired point of partial or final strength development.. Strength values are continuously computed and displayed until the test is terminated. The result is a complete and precise history of initial set and strength development. The principal advantage of the UCA has been to speed the collection of reliable compressive strength data. The strength development can be intermittently relayed to the rig to allow for sufficient waiting on cement time before further work commences.

If the cement plug will be exposed to high temperature conditions, it will be necessary to add silica to the slurry for the prevention of strength retrogression (or decline). A volume of fine silica equal to 35 percent by weight of cement (BWOC) is usually added when the temperature reaches the range of 250 °F (121°C) to 400°F (204°C). Above this, fifty percent silica (BWOC) will likely be necessary. The exact temperature where retrogression becomes a problem varies with cement from mill run to mill run. The UCA can show where retrogression becomes a problem if a long term test (30 days or longer) is run.

Slurry Design Considerations DENSITY - An increase in density can be accomplished by reducing the amount of mixing water per sack and adding a dispersant.

THICKENING TIME - The slurry should be designed to have a thickening time equal to anticipated job time plus a safety f actor.

FLUID LOSS - When placing a cement plug across a loss circulation, weak, or highly permeable formation, caution should be exercised to have good fluid loss control.

FREE WATER - A well-designed cement plug slurry will exhibit zero free water when measured at a 45 ° angle after subjecting the slurry to downhole conditions of temperature and pressure.

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RHEOLOGY - Slurries with high Theological readings warn of potential problems when mixing.

COMPRESSIVE STRENGTH - Rapid compressive strength development after the expiration of the thickening time is important. The slurry should not remain fluid in the wellbore any longer than is necessary.

3.0

Downhole Conditions

Planning a cement plug job should involve understanding existing well conditions and the detrimental effects (if any) on the plug. Some well conditions may be improved before the job, and others may be fixed. Other conditions to be aware of are induced conditions, whether intentional or accidental.

Washouts Rarely will a gauge hole exist when setting a cement plug in an openhole section of the well. Consistent washout over a long section of openhole can be detected easily enough while drilling by comparing calculated hole volume to actual hole volume. Offset data from nearby wells, using similar mud properties and having equivalent drilling parameters, can be useful in validating this information.

Excessive washout in the area where the plug is to be set is a more difficult situation. Running a hole caliper before setting the plug is a luxury option not usually available. Often when a caliper is run, the arms extend to their limit and valid data is still not obtained. Excessive washout over a short section is usually reflected by such indicators as geological and offset data, a change in penetration rate, volume and type of solids returned over the shale shaker, and a review of work performed in that section of the hole (fishing, extended circulation, etc.). The most effective measure in dealing with washouts in openhole sections is to use more slurry volume than calculated. A best guess percentage of excess slurry often works well for consistent washout over a long section of hole. Large washouts in short sections are more elusive, but the approach is the same: more slurry volume.

When setting a balanced plug, any washout that can not be calculated will cause an imbalance condition due to the cement height in the annulus being less than the height inside the workstring. Use of excess cement slurry, based upon a review of available data, should be used. Displacement calculations should be made from known factors such as caliper or bit size used to drill the hole. When the calculated displacement volume to balance is pumped, the pump should be stopped, but the displacement tank should be left open to the pump. The longer column of slurry inside the workstring will continue to fall, seeking the balance point. An imbalance toward the annulus, unless

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extreme, will not adversely affect the cement plug. An imbalance toward the workstring can be damaging due to a greater risk of contamination.

Setting plugs in extremely oversized holes, such as cavernous areas or in “shot holes” may call for a different method of placement than the balanced plug. Shot holes, in this case, are wells that have been stimulated by exploding nitroglycerine or other high explosives in the wellbore to fracture the rock and increase production.

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Lost Circulation The naturally occurring high fluid loss rate of a neat cement slurry make it an ideal lost circulation material. Neat slurries or slurries containing lost circulation material, such as Gilsonite, will enter the loss zone and plug the voids. When lost circulation or the potential for lost circulation is present, both slurry design and placement procedure must be carefully selected. Zones of severe lost circulation have little resistance to flow and a high differential toward the formation. It would seem, little or no fluid loss control would be needed, but the high differential will allow rapid dehydration even with the low resistance.

Selecting a placement procedure, like a balanced plug, that places downhole tools or drillpipe in the vicinity of the rapidly dehydrating slurry could jeopardize the safe removal of the tools or pipe from the well. Reducing the fluid loss value of the slurry can slow the dehydration process sufficiently to remove the workstring and/or other equipment. Reducing the density of the cement slurry can significantly reduce the hydrostatic pressure created by long columns of cement. Density reduction results in very little change in overall hydrostatic pressure for short columns of slurry, as with most cement plugs.

Mud Density Control Often when the necessity for setting a cement plug arises, the drilling mud may have density variations within the wellbore and circulating mud pit. When the balanced plug method of placement is selected, conditioning the hole to ensure that the well fluid will have an even density throughout is important to successful plug setting. It is also important that the mud used for displacement is included in the circulation cycles. In the case of a well with a high thermal gradient, circulating will provide cooler downhole temperatures during the job.

Cement Slurry Density Control The cement slurry should be designed for performance characteristics needed to meet the well conditions and then tested under simulated well conditions to verify performance. Once the cement and additives have been blended in the service company bulk plant, blend samples can be obtained at the bulk plant and/or after delivery to the wellsite. The samples can then be tested to confirm performance and to detect possible contamination. If using liquid additives, they should be carefully measured into the mixing water.

Once the mixing of slurry on location begins, there is only one change the cementing equipment operator can make. During the mixing of slurry, the ratio of mixing water to dry solids is variable. The density of the slurry will fluctuate accordingly. Fluctuating slurry density causes different performance characteristics than those which were designed and tested. An even density throughout the slurry is also necessary to balance the cement plug in the wellbore. All efforts should be expended to ensure the slurry is mixed to the designed density.

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The utilization of a batch mixer or blender to ensure uniformity of the slurry is encouraged (see Figure 1). Although the batch mixer has inlets for dry cement and water, they should be used for making slight adjustments in density, if necessary, after the slurry is mixed with a recirculating type mixer and placed into the batch mixer for equalization of density before going downhole. The slurry should NOT be mixed by placing the mixing water in the batch mixer and blowing the dry cement into it. This is the slowest, dirtiest, and most ineffective way to mix cement.. Rapid settling of heavy weight materials in the blend will occur as the dry cement is blown into the water. When mixing a small volume of slurry, as with plugs, squeezes, and some liners, batch mixing quality can be obtained within the capacity of the mixing tub on many recirculating mixers.

The most accurate method of measuring density is with a pressurized balance. This is slow due to the time needed to seal and pressurize the cup, but the accuracy is worth the time. Intermediate checks can be made with a regular mud balance if it is correlated to the pressurized balance. For a permanent record, a copy of the strip chart from a densometer should be retained with other cementing records. The densometer is

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sufficiently accurate if calibrated at the beginning of the job, and the recording is scaled to show small variations. When the slurry is in the batch mixer, the pressurized balance should be used to check the density and to make adjustments, if needed, before going downhole with the slurry.

Slurry Contamination A major downhole concern is the mixing of well fluid (usually drilling mud) into the slurry when placing a cement plug in the wellbore. Different fluids in a wellbore will commingle at an interface, unless a mechanical barrier is placed between them. The extent of the interface is contingent upon the difference in fluid densities, the yield point relationship of the fluids, the rate of displacement, the geometry, and angle of the hole. The mixing of other fluids into a slurry adversely affects the setting and strength development of a cement plug through dilution and contamination.

Dilution is the volumetric: substitution of a portion of the slurry by the non-cementitious fluids and solids in the well. Dilution is always present when an interface exists. If during the placement process, the length of the interface reaches or exceeds the length of the slurry column, the cement plug is lost. Contamination of cement results from the chemical reaction of the slurry when in contact with the well fluid, usually due to mud treating additives. Often this causes over-retardation and occasionally an acceleration of the slurry thickening time.

DIFFERENCES IN FLUID DENSITIES - It is easier to remove a fluid from the wellbore with a higher density fluid than vice versa. The density of the heavier fluid scours and removes the lighter fluid with a minimal interface. Increasing the difference in densities improves the effectiveness of the removal process. Designing the slurry heavier than the well fluid shortens the extent of the interface, thereby reducing the dilution and contamination.

YIELD POINT RELATIONSHIP OF THE FLUIDS - Volumes have been written that expound at length about such things as plastic viscosity, yield point, apparent viscosity, consistency curves and other such things. The purpose of this manual is not to create redundancy or argument in these areas. For our use, Yield Point is the measure of the inter-particle forces exerted within a particular fluid. When shear stress exceeds this particle attraction, flow is initiated. The point where flow is initiated is considered the yield point and is measured in lb/100 square feet. Progressive yield points are desirable when displacing one fluid with another, or the particle attraction within a displacing fluid should be greater than that of the displaced fluid to reduce dilution and contamination from interfacing.

RATE OF DISPLACEMENT - The effect of the rate of displacement on dilution and contamination will depend on the method of plug placement selected, but is usually minimal. When using the balanced plug method, it is important to select a rate equivalent to or higher than the rate at which the slurry is falling. Once slurry starts out

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the end of the workstring, any rate change should be a reduction. An increase in rate will allow deeper jetting action, picking up additional well fluid within the slurry.

GEOMETRY OF THE HOLE - Another consideration when controlling dilution and contamination is the size of the wellbore where the plug is to be placed and the size of the workstring used for placement. Generally speaking, the more confined the slurry, the shorter the interface. Less interface will occur when placing slurry downhole through 23/8 or 2-7/8 inch tubing than if using larger drillpipe. Even with 4-1/2 or 5 inch drillpipe, the interface is usually marginal. Pumping fluid down the wellbore, through tubulars, meets with some resistance to flow which depresses the interface to some extent. Most of the dilution from interfacing occurs when the slurry enters the annulus. The increased contact area between the well fluid and the slurry enhances and extends the interface. With the balanced plug technique, the return up the annulus meets with very little resistance and allows the interface to spearhead into the displaced fluid. The eccentricity of the workstring in the wellbore promotes flow in the larger portion of the annulus as this is the path of least resistance. The slurry commingles with the well fluid in the narrow portion, contributing to extended interface.

ANGLE OF THE WELLBORE - In a deviated well, the end configuration of the wellbore tends to be elliptical. Additionally, the angled hole contributes to a path of least resistance up the high side of the hole. In an angled hole with an eccentric workstring, the high side of the hole is the large portion of the annulus. As a result, large-angled boreholes, containing eccentric workstrings, subject the slurry to considerable dilution and contamination by creating a path of least resistance on the high side of the hole.

Decontaminants By the selective use of additives, it is possible to reduce the contamination effect. A cement slurry to be used in a well with lignosulfonate mud that is retarded with a lignosulfonate additive would intensify contamination logarithmically. In the presence of lignosulfonate treated mud, a greater tolerance for contamination would be designed into the cement plug if it were retarded with a cellulose material. However, if the components in the mud include carboxymethyl cellulose, cellulose retarders should be avoided.

MUD KIL I AND MUD KIL II - Mud Kil I is a two component system of 60 percent paraformaldehyde and 40 percent sodium chromate tetrahydrate by weight. The components are stored separately and added to the cement no earlier than 36 hours before mixing the slurry for the plug. Sodium chromate increases the decontaminating reactivity of paraformaldehyde and broadens its well temperature range. It causes paraformaldehyde to confine its reactivity to tannin, lignin, starch, modified celluloses, and monovalent contaminants, including sodium lignosulfonate. Divalent calcium lignosulfonate is not treated and can be used to retard Mud Kil I plugs, if necessary. Mud Kil 11 is simply paraformaldehyde. It neutralizes multi-valent type lignosulfonates. Below 160°F, Mud Kil II treats calcium and ferrochrome lignosulfonate, chrome lignins, and chrome lignites. Above 160 °F, it also neutralizes the contaminants that Mud Kil I treats. Diacel LWL should be used as a retarder when necessary.

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Spacers One way to reduce contamination when setting a cement plug is to use a spacer fluid between the cement slurry and the well fluid. Flow regimes and formation contact time are meaningless due to the small volumes and short distance for placement in the annulus. The purpose of a spacer in this case is to separate the incompatible fluids with a fluid that is compatible with both the slurry and the well fluid. Compatibility means there is no adverse reaction of the slurry to the additives in the adjoining fluid whether it is a spacer or well fluid. This reduces or eliminates the contamination but not the dilution.

The most frequent spacer used in setting plugs is fresh water. Fresh water is generally compatible with cement slurry and water base drilling fluids. It is also compatible with most other well fluids. It is not compatible with oil base muds or some formations. Fresh water is a very effective spacer against low density muds (less than 14.O ppg), within the confines of a workstring. Its successful use as a spacer in the annulus is due to the short slurry column height usually associated with plugs. The volume of fresh water spacer should be equal to or greater than the volume of slurry because the drilling mud/fresh water interface will be extensive due to the spearheading of the water into the mud.

Spacers other than fresh water should be considered when:

•

using muds heavier than 14.0 ppg.

•

circulating long columns of slurry up the annulus.

•

using oil base muds.

•

spacer height is enough to reduce hydrostatic pressure to a point of concern.

•

formations are incompatible with fresh water.

Weighted spacers with a density and yield point between the mud and slurry should be used. [A detailed procedure for testing the compatibility of these fluids is found in Appendix P of API Specification 10.]

It is important that all rheological values be determined under temperatures and pressures that resemble downhole conditions as closely as possible. It is especially important that oil mud and spacer rheological values be measured on a Fann Model 70 or similar instrument capable of confining the fluid under pressure. This is because an oil mud will tend to thicken under increasing pressure due to pressure effects on the oil continuous-phase while the spacer will tend to thin because of the negation of the viscosity-building effect of entrained air bubbles. The rheology of the cement slurry should be determined after conditioning on the high temperature, high pressure consistometer.

Page B - 15

Rev. 9/92


The Cementing Services Division has developed a Caustic Cement Spacer as an alternative to service company spacers. Caustic Spacer has a pH of about 13, is stable to 190°F and uses mud products commonly found in the field. The basic formulation is as follows: Fresh Water Caustic Soda XC Polymer CIVIC Barite to Weight

(5 pounds per barrel) (1.5 pounds per barrel) (1 pound per barrel)

[Additional information is contained in the technical memorandum, Caustic Spacer Chevron's Alternative to High Price Cement Spacers (89-03)].

4.0

PLACEMENT PROCEDURES

Small Plugs A minimum order of bulk cement is usually about 35 to 5O sacks. Any less than this amount becomes difficult to mix and pump downhole without the fluid interface easily overcoming the length of the cement column. In other words, it would string out and become lost during the placement process. At best, its competency would suffer due to the large percentage of dilution by the well fluid.

When the setting of a cement plug requires a small volume of slurry, the use of a dump bailer may be the most practical way of placing the slurry downhole. A dump bailer is a bucket or bailing device with a door on the bottom, usually a disk or a flapper valve. The bailer is filled with slurry and lowered into the well. When the bailer reaches the desired depth, the slurry is released through the door and the bailer is retrieved. When less than 25 sacks of cement are needed, it can be ordered in sacks (94 lb bags) instead of in bulk, and no cement unit is required. The slurry is mixed, by hand, in a tub, and loaded in the bailer. Several runs with a dump bailer can be made, if necessary, when only a few sacks of cement are needed.

Balanced Plugs The placement procedure used most often for setting cement plugs is the balanced plug method (see Figure 2). This involves displacing the slurry until it is “balanced” around the end of the workstring. Theoretically, the height of the slurry columns inside and outside the workstring would be equal, as well as any other fluids in the wellbore, so there would be no U tubing effect when pumping ceased. This method is used quite extensively throughout the industry, though not without problems. Placement is made through a workstring, generally drillpipe or tubing, which is run in the hole until the end of the workstring is at the desired bottom of the cement plug. After mixing and pumping the slurry into the workstring, displacement of the slurry should be made with the well fluid.

Page B - 16

Rev. 9/92


Calculations should be made to allow the height of the column of cement left inside to be equal to the height of the cement column on the outside.

Any spacer fluid used between the well fluid and the cement must also be calculated for equal column heights. Both the leading and the following spacer columns are immediately above the cement when balanced. Once the cement slurry is spotted at the bottom of the workstring and is balanced, the workstring is pulled out of the cement plug.

The fall of cement from the workstring is sluggish due to the cohesion characteristics of the slurry. Cohesion is the molecular attraction exerted between the surfaces of bodies in contact. If a neat or near neat cement is used, gelation of the slurry can also increase this sluggishness. To help overcome the sluggishness, the well fluid displacement volume can be cut short by 1 to 1-1 /2 barrels. This will slightly increase the hydrostatic head of the slurry column inside the pipe, allowing it to continue to fall as the pipe is pulled. The pipe should be withdrawn slowly after the plug is in place. The columns of cement become one as the pipe is removed. The leading and following spacers combine at the top of the plug.

Plugging Tool Several companies offer plugging tools to aid in the uncertainties such as a washed-out openhole displacement calculation errors, etc. exist. Commonly plug catcher sub is attached at or near the lower end of be pumped ahead and behind the cement slurry.

setting of cement plugs where section, contamination/dilution, referred to as a plug cutter, the the workstring. Wiper plugs can

ADVANTAGES - Important advantages are:

•

Balance calculations are eliminated.

•

Uncertainties of hole size are of less consequence.

•

Accurate location of cement top.

•

Wiper plugs used, reducing contamination.

•

Pressure build-up at surface, indicating when cement is in place.

•

Flow back of cement and displacing fluid is prevented.

Page B - 17

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Page B - 18

Rev. 9/92


OPERATION (Figure 3) - Place the plugging tool at or near the lower end of the workstring. CAUTION: Be sure any crossover subs above the tool have sufficient ID to allow passage of the plugs. Run in hole until the end of workstring is at desired bottom of cement plug. Launch the bottom wiper plug ahead of the cement slurry. Pump the cement, and then launch the top wiper plug behind. Pump the top plug down with well fluid. The bottom plug, if used, goes out the end of the workstring and is left in the well. It is drillable if the cement plug is drilled out.

The top plug has a metal nose that lands and seals in a baffle inside the catcher sub. Pressure buildup at the surface indicates that the cement is in place. A pressure limit (usually 1500 psi or less) should be observed at this point. The required amount of pipe is pulled until the workstring is above the cement plug. With the plug latched up in the catcher sub, it is a closed system and will pull “wet”. Additional pressure is then applied to shear the retaining pins and move the plug and baffle down in the catcher, returning the workstring to open-end status. There are no external ports and fluid must go around the lower-most end of the workstring. The top wiper plug stays in and is retrieved with the catcher sub.

Tailpipe When the workstring is large as with 4-1/2 or 5 inch drillpipe, better results may be obtained by using a tubing tailpipe below the catcher sub. The slurry is spotted across the smaller tailpipe. The tailpipe is pulled out of the cement, causing less “damage" to the plug than the larger drillpipe. When a tailpipe is used, the bottom wiper plug cannot be used. Tailpipe is also effective without the plugging tool. In situations where a large workstring is used with a small ID wellbore, the possibility of causing damage to the cement plug while removing the workstring increases. To reduce this damage, a small tailpipe can be run below the workstring. The length of the tailpipe should be longer than the height of the planned cement column, so the plug can be placed around the tailpipe. The tailpipe is then removed from the cement plug with a minimal amount of damage.

Scratchers and Centralizers Another aid to setting plugs is to run the tailpipe with scratchers and centralizers attached and rotate the pipe while cementing. The use of scratchers and centralizers can also be run on drillpipe or tubing when not using a tailpipe. They should be run through the interval in which the plug is set to assist in the removal of drilling mud and soft, developing mud cake. The rotational scratchers are preferred due to the increased scratching possible during the short plug placement time. Centralizers are needed to protect the scratchers and prevent whipping during rotation. Remember, these tools must be pulled through the plug slurry at the end of placement.

Page B - 19

Rev. 9/92


Coil Tubing The use of coil or reeled tubing for setting cement plugs has several advantages. Small coil tubing can be run inside conventional tubing for setting plugs below production equipment (see Figure 4). This prevents the necessity of killing the well and removing this equipment before setting a cement plug. These operations could be expensive, time consuming and, in some cases, detrimental to the zone of interest.

With proper calculations, the tubing can be reeled up as the cement slurry exits, thereby laying the plug in the hole as the tubing is extracted. This prevents having to pull the tubing through a long cement plug after it is in place, assuring the tubing can be removed, and avoiding disturbance of the plug after placement. The slurry must be displaced from the entire reel of tubing. Due to the increased frictional forces in the smaller tubing and the added length of the workstring, sufficient dispersant and fluid loss additive/retarder must be used.

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Rev. 9/92


Drillable Bridge Plugs and Drillable Squeeze Packers The setting of a cement plug may incorporate the use of a drillable cast iron bridge plugs (CIBP) or a drillable squeeze packer (cement retainer). When setting plugs in a cased hole, a drillable bridge plug can be used as the primary plug with a cement plug spotted on top of it as a backup seal. Where downhole conditions present a zone of lost circulation or weak zone below a cement plug in casing, the bridge plug can be set to assure that the cement does not move downhole due to loss of fluid below it.

Page B - 21

Rev. 9/92


Although openhole bridge plugs are available, they are not frequently used. The uncertainty of the hole size, sloughing conditions, and unconsolidated formations contribute to ineffective sealing of the packer elements. The availability of an adequate packer seat in the openhole section is a prime consideration when deciding to use an openhole bridge plug.

Often it is desirable, or required, to set a cement plug in combination with a squeeze job. The use of a drillable squeeze packer (cement retainer) offers the ability to squeeze or just place cement below the packer and leave a volume of slurry above it. The drillable squeeze packer serves as a bridge plug, while allowing slurry to be placed and retained below it through a valve mechanism. Set in cased hole, it is useful when squeezing and abandoning a depleted zone. It is also used in permanent abandonments where a cement plug is set across the shoe of a surface casing extending in the openhole below and inside the shoe. The retainer prevents the cement plug from moving and offers a backup seal.

5.0

CALCULATIONS

The balanced plug is the most common procedure used to set a cement plug. Hydrostatically balancing the cement, spacer, and wellbore fluid inside and outside of the workstring is the key to obtaining a balanced plug. In order to hydrostatically balance the plug, the height of the column of cement and spacer inside and outside of the workstring needs to be equal. Since the wellbore geometry has a dramatic effect on this calculation, it is critical that hole size over the area of where the plug will be set is known. Also, it is important that drillpipe capacity and displacement factors -include tool joints. Tool joint corrected capacity and displacement factors can be obtained from Chevron's drillpipe tables (included in Appendix).

The following example illustrates the calculation process used to hydrostatically balance a cement plug. Calculations using both Chevron's drillpipe tables and uncorrected capacity and displacement factors are presented to illustrate tool joint effect. Drillstring became stuck while drilling an 8-1/2" hole at 15,100 ft. A free point indicated that the pipe was free at 13,500' and the pipe was backed-off at this point. The revised procedure calls to set a 200 sack, Class H plug on top of the fish utilizing the balanced plug technique. A five-barrel, fresh water spacer will be pumped ahead of the cement.

Example Pertinent Data

Page B - 22

Last Casing Shoe Cement Density Cement Yield Drillpipe

10,000 ft 16.7 ppg 3 1.02 ft /sx 4-1/2” 16.60 S-135 NC46 (IF)

Rev. 9/92


Page B - 23

Rev. 9/92


Displacement and Capacity Data Drillpipe Capacity

•

Drillpipe Capacity

•

Drillpipe Displacement

•

Hole Volume

.013593 bbl/ft (Chevron tables) .01423 bbl/ft (Uncorrected) .006906 bbl/ft (Chevron tables) .00545 bbl/ft .0702 bbl/ft

Determine the total slurry volume in barrels.

•

Slurry Volume in BBLS

ft3

No. Sacks x Yield /sx 3

5.615 ft /bbl

•

Slurry Volume

3

200 sx x 1.02 ft /sx

= 36.3 bbl

3

5.615 ft /bbl

Determine the depths of the cement tops before and after the drillpipe is pulled.

Chevron Tables

•

Height in Feet

Slurry bbl Hole Volume bbl/ft - DP Displacement bbl/ft

•

Before Pipe is Pulled

36.3

= 573.5 ft

.0702 bbl/ft - .006906 bbl/ft

•

Height

13,500 ft - 573.5 ft - 12926.5 ft

•

After Pipe is Pulled

36.3

= 517.1 ft

.0702 bbl/ft

•

Height

Page B - 24

13,500 ft - 517.1 ft - 12982.9 ft

Rev. 9/92


Uncorrected

•

Before Pipe is Pulled

36.3 bbl

= 560.6 ft

.0702 bbl/ft - .00545 bbl/ft

•

Height

13,500 ft - 560.6 ft - 12939.4 ft

•

After Pipe is Pulled

36.3 bbl/ft

=517.1 ft

.0702 bbl/ft

•

Height

13,500 ft - 517.1 ft - 12982.9 ft

Determine the volume of water to follow the cement.

Chevron Tables

•

Height of FW in Annulus

FW Volume bbl Hole Volume bbl/ft - DP displ bbl/ft - DP cap bbl/ft

•

Height

5 bbl .0702 bbl/ft - .006906 bbl/ft - 0.13593 bbl/ft = 100.6

•

Volume of FW Behind Cement Height of FW in Ann ft x DP cap bbl

•

Volume

100.6 ft x .013593 bbl/ft

= 1.4 bbl

Uncorrected

•

Height

5 bbl .0702 bbl/ft - 0.1423 bbl/ft - .00545 bbl/ft = 100.6

•

Volume

99 ft x .01423 bbl/ft

Determine the volume of wellbore fluid needed to place the cement on spot.

Chevron Tables

•

Displacement

Height of Wellbore Fluid x DP cap bbl/ft

•

Displacement

(12926.5ft - 100.6 ft) x .013593 bbl/ft

Page B - 25

= 174.3 bbl

Rev. 9/92


Uncorrected

•

Displacement

(12939.4 ft - 99 ft) x .01423 bbl/ft

= 182.7 bbl

In the previous example, the use of uncorrected drillpipe capacity and displacement factors would have resulted in an over-displacing of the plug by 8.4 barrels. The plug would not have been hydrostatically balanced and would have U-tubed towards the workstring.

The following example illustrates how wellbore geometry can affect the balanced plug calculations. Tubing is used as workstring in this problem. Using tubing capacity and displacement factors which have not been corrected for upsets and couplings will not result in an appreciable amount of error.

The subject well is equipped with 5-1/2”, #17 production casing set at 7000' and is completed open hole from 7000-7250'. The procedure calls to spot a Class C balanced plug from 6900-7250' utilizing the balanced plug technique. A 5-barrel, fresh water spacer will be pumped ahead of the cement.

Example Pertinent Data 5-1/2", #17 casing Cement Density Cement Yield Workstring Avg. Openhole Size

set at 7000' 14.8 ppg 1.32 ft3/sx 2-3/8” , #4.7 8rd EUE tubing 6-1/2”

Displacement and Capacity Data Tubing Capacity Tubing Displacement Casing Capacity Openhole Volume

.00387 bbl/ft .00161 bbl/ft .0232 bbl/ft .0410 bbl/ft

Determine the total slurry volume in barrels.

•

Slurry Volume

Hole Capacity bbl/ft x Height ft

•

Volume

(250 ft x .0410 bbl/ft) + (100 ft x .0232 bbl/ft) = 12.6 bbl

Page B - 26

Rev. 9/92


Determine the depth of the cement top before the workstring is pulled.

•

Slurry Volume In OH Prior to Pulling Pipe

Height ft x (OH Volume bbl/ft - WS displ bbl/ft)

•

Volume

250 ft x (.0410 bbl/ft - .00161 bbl/ft = 9.9 bbl

•

Slurry Volume In Casing

•

Before Pulling Pipe

12.6 bbl - 9.9 bbl = 2.7

Height of Cement In Casing

Slurry bbl Hole Volume bbl/ft - WS displ bbl/ft

•

Height

2.7 bbl

= 125.1 ft

.0232 bbl/ft - .00161 bbl/ft

•

Depth

7000 ft - 125.1 ft

= 6874.9 ft

Determine the volume of water to follow the cement.

•

Height of FW in Annulus

FW Volume bbl Casing Vol. bbl/ft - WS displ bbl/ft - WS cap bbl/ft

•

Height

5 bbl .0232 bbl/ft - .00161 bbl/ft - .00387 bbl/ft = 282.2 ft

•

Volume of FW Behind Cement

Height of FW in Ann ft x WS cap bbl

•

Volume

282.2 ft x .00387 bbl/ft

= 1.1 bbl

Determine the volume of wellbore fluid needed to place the cement on spot.

•

Displacement

Height of Wellbore Fluid x WS cap bbI/ft

•

Displacement

(6874.9 ft - 282.2 ft) x . 00387 bbl/ft = 25.5 bbl

Page B - 27

Rev. 9/92


Page B - 28

Rev. 9/92


SECTION C

SQUEEZE SLURRY DESIGN AND TESTING


Slurry Design Designing for Small Tubing Squeezes

2.0

Laboratory Testing Thickening Time Test Fluid Loss Test Free Water Test Rheology Compressive Strength Test

Page C - 1

Rev. 9/92


Page C - 2

Rev. 9/92


SECTION C

1.0

SQUEEZE SLURRY DESIGN AND TESTING

SLURRY DESIGN

Early in the development of the Controlled-Water-Loss (CWL) squeeze cementing technique, laboratory and field experiments substantiated the idea that conventional, neat cement slurries were unsatisfactory. The extremely high filtration rate of neat cement slurries caused the deposition of a compacted mass of cement inside the casing (as shown in Figure 1).

Page C - 3

Rev. 9/92


This meant the squeeze job was being performed on the inside of the casing instead of against the problem zone. The need for cements with a reduced filtration rate was obvious and urgent. Bentonite was first used to lower the fluid loss until more efficient additives were developed. Neat cement almost never makes a suitable squeeze slurry. The following description is a field validation of this concept. It describes an examination of cement core recovered following a squeeze job and illustrates the problems associated with neat cement and squeeze cementing.

[Taken from “The Role of Filtration in Cement Squeezing” by H. J. Beach, T. B. O'Brien and W. C. Goins, Division of Production, American Petroleum Institute, Spring Meeting of the Southern District, Shreveport, La., March 8-10, 1961.]

The well cored is in Wadsworth Field, Texas. It contained a 26-ft perforated interval from 9,744 to 9,770 feet. The formation broke at 8,670-1b calculated bottomhole pressure (CBHP) and accepted fluid at 7,400-lb CBHP. The squeeze slurry consisted of 100 sacks of API Class E cement mixed to an average density of 16.1 lb per gal Continuous and progressively slower pumping displaced 93 sacks through a retrievable tool set at 9,635 ft. One pressure break back from 9,470 to 9,070-lb CBHP occurred about the middle of the squeeze. Maximum and final squeeze pressure was 11, 000-1b CBHP (6000 psi surface pressure). After pulling the squeeze tool, the top of the cement was found with a rock bit at 9,640 ft and dressed to 9,724 feet.

Coring began with a 6-1/2 in. OD, 3-1/2 in. ID diamond bit at 9,724 ft, 24 hours after squeezing. This was continual for 34 feet with the rate of penetration remaining fairly constant at 1 ft per 15 minutes. At 9,758 ft, the core barrel apparently jammed and 11/2 hours elapsed in drilling 2 ft of hole. It was decided to pull the barrel and bit to utilize the available core. These operations recovered approximately 28 ft of the 36 ft cored. The core pieces were sealed in plastic tubes to prevent loss of water and transported to the laboratory for study. A subsequent trip in the hole with a rock bit revealed that the next 4 ft of casing contained solid cement but that the last 6 ft of perforations contained no cement.

A well-defined flow channel extended through the cored interval. This passed outside the recovered material in places where it flowed through the cutting circle of the bit. Soft mudcake filled the channel for the first foot, soft cement the next 8 foot, and hard cement, the remainder.

Short plugs of 3/4-inch diameter were cut through the core. Some were taken in the flow channel, others were taken in a line across the core. The plugs were cut or faced to give pieces 3/4 to 1-1/2-in long and vacuum saturated to replace waterlog during examination and cutting. Densities were determined. A few plugs were dried for porosity and airpermeability measurements. Figure 2 shows the positions of the plugs in the core, the location of the channel, the data obtained, and other pertinent items. Figure 3 shows graphically the data obtained.

Page C - 4

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Rev. 9/92


Page C - 6

Rev. 9/92


At the top of the recovered core the density was 17.3 lb per gal. This indicates that partial dehydration occurred at this point 20 to 2l feet above the perforations. The density increased slightly to a point about 6 ft above the perforations and then sharply from about 17.7 to 19.7 lb per gal in the next 3 ft. From this point, 3 ft above the perforations to the bottom of the recovered core (17 ft), the average density gradually increased to 20.3 lb per gal. Some samples measured as high as 20.7 lb per gal. In contrast, cement filter cake prepared in the laboratory with 1,000-lb differential had a density of only 19.05 lb per gal. This indicates that the interval of high density in the core was compressed filter cake.

Calculations showed that 3,600 lb of cement solids were present in 37cu.ft. of slurry that either remained in the casing or that were reversed from the tubing. There were 5,800 lb of cement solids in 67.8 cu.ft. of slurry that were forced into and through the perforations. Only 3.2 cu.ft. of water filtered from the cement remaining in the casing in the course of a density increase to the values found.

It is clear that the casing in the perforated interval and 3 to 4 ft above contained filter cake. Initially, the flow of cement was into some or all of the upper 20 ft of perforations, but cake began to form in the interval and to close it off. This increasing restriction in the perforations narrowed the area of flow until only the cement in the thin channel was flowing. When this finally closed through dehydration, overburden pressure could be and was developed at the surface; but the presence of cake prevented the application of high pressure to the lower 6 ft of perforations!

These perforations were not broken down and did not receive cement; in fact, no cement flowed into the bottom 6-ft interval. Above the perforations, there was some dehydration through all the core recovered, and apparently the thickening cement caused a small flow channel to develop also in this interval. The presence of mudcake in the channel at the top of the core indicates that the channel, filled with mud solids from drilling-fluid water, probably existed through the 84 ft of cement drilled before coring and also extended through the cement in the packer and drillpipe at the time of reversing excess slurry.

The drilling-fluid water, which was red-colored from the mud solids, was pushed down the slurry column and tended to travel in a channel through the cement cake while the mud solids were filtering out. Considering the very high strengths of conventional cement slurries almost motionless when obtaining final squeeze pressure, the explanation of gelled slurry and flow in a channel in the upper un-dehydrated part of the core appears reasonable.

The explanation of the core appears reasonable when one views a simple filtration test on a cement slurry containing no water-loss control additives. Under a pressure differential of 100 psi and against a medium of filter paper or fine mesh screen, separation of water from, cement solids is almost instantaneous. A rate extrapolation indicates a total volume of filtrate in the order of 1,000 to 2,000 cc in 30 minutes and a cake thickness of several inches.

Page C - 7

Rev. 9/92


The core examination explains why conventional squeezes tend to support criteria of high pressure, substantial quantities, and continuous pumping:

1. High pressure prolongs the movement of rapidly-caking cement to a maximum number of perforations.

2. Substantial quantities of dehydrating cement must be sacrificed quickly to accepting perforations while the slurry following is still fluid enough to move to more resistant perforations.

3. Continuous pumping naturally results in following the first two expediencies.

As can be seen from the above field case history, when building cement filter cake, slurry filtration rate and cake placement time are inter-related and vary inversely. When the filtration rate is at a maximum, as in traditional neat cements, placement time is at a minimum. As the filtration rate is reduced, the time available for adequate cake deposition is lengthened. Placement times can be standardized only if filtration rates are adjusted to all (often unknown) formation conditions.

This would require a vast number of slurry compositions to anticipate all formations. However, it is simple and practical to standardize filtration rate and then take whatever time is necessary to build filter cake. Using a standard filtration rate, jobs have been completed in two hours against highly porous sand and in less than six hours against almost impermeable, fractured limestone. For most situations, filtration control for squeeze slurries should be 100 mls or less, in the standard 30 minute test.

Any cement slurry being pumped past a restriction should have fluid loss control to assure that premature dehydration does not occur. Any time a slurry encounters a pressure differential, dehydration is likely. The restriction can be a 325-mesh screen in a fluid loss cell in the laboratory, a perforation downhole, hanger equipment in a liner overlap, or a highly permeable zone in the annulus.

Even though the proper squeeze slurry design for a given situation can best be determined after a properly executed injection, or feed-in, test (described in Section IV: Injection Rates and Placement Techniques), the cement generally needs to be delivered to location before the infection test is conducted. The more information available, enhanced by experience in the particular field, is valuable when designing for a squeeze job. Without the information and experience, a two slurry design concept, based solely on information gleaned from a proper injection test, will provide slurries to meet almost any squeeze situation. Based on the premise that a proper injection test will indicate a loose or tight injection, or something in between, two slurries can be pre-designed that can be

Page C - 8

Rev. 9/92


applied in all but the most extreme cases (see Figure 4). (A loose or tight injection may or may not be the same as a loose or tight formation).

A thorough analysis of the injection test is valuable for fine tuning squeeze slurry designs, and reference is again made to Section IV. A loose injection indicates that the formation is fractured, vugular, or has an extremely high permeability. Filter cake is not deposited easily against such a formation. In fact, the formation often takes whole slurry before the filter cake can start to form. Something is needed to serve as the base for filter cake deposition. That something is a cement slurry designed with a short thickening time and a moderate fluid loss value that is pumped as a lead slurry, ahead of a longer-pumping tail slurry with a low fluid loss value. The shorter-pumping lead slurry should:

•

have a thickening time of 1 to 2-1/2 hours

•

have moderate filtration control (300-500 mls in 3O minutes)

The short thickening time and moderate filtration rate allow the slurry to dehydrate and set rapidly providing abase upon which to deposit the filter cake which will result in the final seal. This slurry will flow to the areas where it is needed most: large fractures, vugs, or any other area that takes fluid easily. Once these areas are sealed, the injection is converted from loose to tight, and this slurry should be followed by the tail slurry, designed for a tight injection. If the injection is tight, a single slurry design is required or, if the squeeze started as a loose injection and was converted to a tight injection, this slurry design should be the tail slurry mentioned above. For such a slurry, the following design parameters should be met:

Page C - 9

Rev. 9/92


•

thickening time of 3-5 hours

•

fluid loss of 00 mls or less

When the squeeze is very shallow, the thickening time can be reduced below the 3 hours but MUST remain longer than the lead slurry thickening time in all cases. In order to control the squeeze development, the increased pump pressure must be transmitted to the exposed formation face. Dehydration and setting must begin at the formation face. For most squeeze slurries, both the thickening time and filtration control can be obtained with fluid loss additives and dispersants. Lignosulfonate retarders should not be used unless the slurry will be exposed to temperatures in excess of 210 °F. (See the explanation of laboratory testing in this section for a description of the thickening time test schedule).

Neat cement is virtually NEVER a satisfactory design choice for this slurry. A moderate degree of filtration control is still required so the slurry can pass through any restrictions, such as perforations or liner laps, that may be present without dehydrating prematurely. In extreme lost circulation situations, a sodium silicate pre-flush may be added to the job design. The sodium silicate is not added to the cement. Instead, it is pumped as a preflush ahead of the cement. Sodium silicate pre-flushes are marketed under several names:

•

Flo-Chek

(Halliburton)

•

Flow-Guard

(BJ Services)

•

Zone Lok

(Dowell Schlumberger)

•

Aqua-Fix

(Western)

++

++

The sodium silicate reacts with divalent cations (especially Ca and Mg ) to form a very stiff gel. The gel serves as a base for both slurry one and slurry two. The cations may be present in the connate (formation) water, or they may be contained in pads of calcium chloride water pumped ahead of and behind the sodium silicate pre-flush. Any calcium chloride pad MUST, of course, be separated from the sodium silicate pre-flush with a freshwater spacer.

Note: Sodium silicate pre-flushes MUST NEVER BE USED -across any productive or potentially productive interval. The sodium silicate gel is not acid soluble, and there is no means of removing it.

Designing for Small Tubing Squeezes

Page C - 10

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A few words need to be said about designing squeeze slurries to be placed downhole through small tubing, particularly when using coiled tubing. Fluid loss control will be the most crucial value and should be 50 mls in 30 minutes, or less, when the tubing frictional pressure is critical. The amount of fluid loss control needed is still dependent upon the resistance encountered in the flowstream. However, the small diameter of the coiled tubing makes the slurry rheology a critical factor, and low shear rheology slurries are recommended. The slurry must be thin enough not to cause excessive pressure drops in the coiled tubing. The slurry must also have enough consistency to prevent the settling of cement solids. It is difficult to make a general statement about the proper rheology because of the differences in additive performance, tubing length, and inside diameter, but Fann rheometer 600 rpm reading less than 250 will usually suffice.

Thickening times generally should be somewhat longer when using coiled tubing or other small tubing, particularly when slurry must be circulated out of the well. Reverse circulating is not a good idea when using coiled tubing. When squeezing “live” wells, the tubing will have a back pressure valve that prevents reversing. While some operators prefer to chemically contaminate the slurry left inside the casing, the Cementing Services Division prefers to design the thickening time long enough to allow for circulating the excess slurry out of the well immediately after obtaining a squeeze. The slurry MUST be tested by the proper schedule for hesitation squeezes as discussed next.

2.0

LABORATORY TESTING

Successful CWL squeezing must rely on laboratory guidance. Even relatively new handbook data is not reliable. Variances in materials, their combinations, and squeeze targets require well-by-well refinements in slurry composition. Slurries should be tested using accurate simulations of true well conditions, including pump hesitations and the slow rise in temperature which occurs while holding a small batch of cement on bottom. There is a reluctance to stop the movement of cement during a squeeze job because of the gelling properties of neat cement. Fluid-loss-controlled slurries avoid this gelling problem and should be tested using schedules that simulate the following hesitation placement method.

Thickening Time Test The thickening time is established using a stringent test schedule that simulates a rapid temperature increase as the slurry is pumped down the workstring. This is followed by a more gradual temperature increase that simulates holding the slurry on bottom. The slurry is first brought to the circulating temperature, and then the temperature is allowed to continue increasing at the rate of 1 °F/5minutes until the bottomhole static temperature (BHST) is reached. The BHST should be reached in about 4 hours.

FLUIDITY - The slurry must remain fluid until near the time of initial set. This property can be measured during the thickening time test as follows: the stirring of the slurry is stopped for a 10 minute period, then resumed for a 5 minute period, followed by another

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10 minute shutdown, and so on. These stopping and starting cycles are continued until the cement sets. A gelling of the slurry, sufficient to cause an instantaneous and sustained rise to more than 60 Bearden units of slurry consistency (60 BC) upon resumption of stirring is cause enough to suspect its immobility in the workstring. Properly selected water loss additives reduce rather than intensify the tendency of cement to gel. The reported thickening time is the maximum time a slurry will remain fluid inside the closed testing equipment at a given temperature. It has no relationship to the time a slurry will remain fluid when placed against a porous formation, but reflects the minimum time the slurry in the workstring and (or) casing will remain moveable.

BATCH MIXING - This is best defined as a refinement in any type of squeezing, especially CWL. One-hour of surface mixing is equivalent to no more than a few minutes of downhole thickening time, so anxiety should not be a cause of short cutting uniform mixing. If desired, the thickening time test schedule may be modified to include a period of conditioning at ambient temperature and pressure to simulate retention in a batch mixer. Unless the final test temperature is very close to surface conditions (less than 100°F), batch mixing will not greatly affect the thickening time.

HESITATION SQUEEZE - The hesitation squeeze schedules were invented by the predecessor of the Cementing Services Division, and subsequently accepted by the American Petroleum Institute as an operating test procedure. The Chevron laboratory easily runs more hesitation squeezes in a given year than any service company laboratory. [An example of a hesitation squeeze schedule is shown in Figure 5.]

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Figure 5 Hesitation Squeeze-Cementing Well Simulation Tests 1 Time (min)

2

psi

Mud Density: 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 34 35 36 37 38 48 53 63 68 78 83 93 98 108 113 123 128 138 143

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3 Temperature (kPa) °F Alternate Schedule 17 - 1 0,000 ft (3050 m) 12 lb/gal (1.4 kg/L)

4

Pressure

1300 1700 2000 2400 2800 3100 3500 3800 4200 4600 4900 5300 5700 6000 6400 6700 7100 7500 7800 8200 8200 8500 8800 9100 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400

(9000) (11700) (13800) (16600) (19300) (21400) (24100) (26200) (29000) (31700) (33800) (36500) (39300) (41400) (44100) (46200) (49000) (51700) (53800) (56500) (56500) (58600) (60700) (62700) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800)

80 86 91 97 102 108 113 119 125 130 136 141 147 153 158 164 169 175 180 186 186 186 186 186 186 188 189 191 192 194 195 197 198 200 201 203 204 206 207

(° C)

(27) (30) (33) (36) (39) (42) (45) (48) (52) (54) (58) (61) (64) (67) (70) (73) (76) (79) (82) (86) (86) (86) (86) (86) (86) (87) (87) (88) (89) (90) (91) (92) (92) (93) (94) (95) (96) (97) (97)

String

on on on on on on on on on on on on on on on on on on on on on on on on off on off on off on off on off on off on off on off

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Figure 5 Hesitation Squeeze-Cementing Well Simulation Tests (continued) 1 Time (min)

2

psi

Mud Density: 153 158 168 173 183 188 198 203 213 218 228 233 243 248 258 263 273

9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400

3 Pressure Temperature (kPa) °F Alternate Schedule 17 - 1 0,000 ft (3050 m) 12 lb/gal (1.4 kg/L) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800) (64800)

209 210 212 213 215 216 218 219 221 222 224 225 227 228 230 230 230

4 (° C)

(98) (99) (100) (101) (102) (102) (103) (104) (105) (106) (107) (107) (108) (109) (110) (110) (110)

String

on off on off on off on off on off on off on off on off on

A complete set of test schedules is contained in the latest edition of API RP 10B, Recommended Practice for Testing Well Cements. Service company laboratories not familiar with hesitation schedules commonly make several errors regarding selection of a test schedule by:

•

Choosing a schedule that gets too hot too quickly. A wellbore takes a long time to return to static temperature. The four-hour guideline mentioned above is already quite conservative so when choosing between two schedules, it is more representative to choose the longer heat-up.

•

Failing to continue the On-Off cycles until the cement sets. Service company labs sometimes stop the hesitations and allow the machine to run continuously after reaching the end of the printed schedule. The on/off cycles must be continued until the cement sets.

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•

Failing to modify the schedule to match the calculated bottomhole static temperature. The schedule should be either lengthened or shortened, so the final temperature programmed into the schedule matches the calculated BHST.

The regular squeeze schedules for running squeezes in the API RP 1OB call for continuous stirring of the slurry and duplicate temperatures to bottomhole circulating temperature (BHCT). This is only representative of actual conditions, if a squeeze is not accomplished. When, in fact, a running squeeze is obtained (maximum allowable pressure is reached while continuously pumping), the next step is to stop pumping, release the pressure, and start pumping again (reverse out any excess slurry). If there is any doubt concerning the proper schedule for Chevron wells, the service company representative should feel free to discuss the selection with the Cementing Services Division. The main switchboard number is (713) 230-2600.

As noted above, for highly vugular, or lost circulation zones, indicated by a loose injection, a two-slurry squeeze design has been developed and successfully used. A lead slurry with a short pump time and moderate fluid loss (300-500 mls in 30 minutes) is pumped first. This is followed by a tail slurry with a longer pump time and a characteristic low fluid loss (80-120 mls in 30 minutes) to use for hesitation. The lead slurry sets and dehydrates rapidly forming a base to squeeze against with the tail slurry.

Fluid Loss Test The fluid loss test of a slurry is a measure of the rate at which filtrate is forced from a cement slurry when the slurry is subjected to differential pressure. Generally, slurries can dehydrate (loose filtrate) if, while being circulated in place, resistance to flow is encountered. When a restriction in the flowstream (resistance) creates a pressure drop, a differential pressure is exerted across the barrier. This resistance to flow can separate the solids from the fluid phase. The amount of filtrate actually separated depends upon the differential pressure exerted and the fluid loss control inherent in the slurry design. In the fluid loss test, the conditioned slurry is placed in a pre-heated cell, and 1000 psig is exerted by nitrogen to force the slurry against a 325-mesh screen barrier. The filtrate that passes through the screen in a 30-minute interval is measured. With high fluid loss slurries, all available filtrate is usually forced through the screen before the 30-minute period. In this case, the filtrate measured to termination is extrapolated to obtain a rate/30 minutes value. Fluid loss values are relative, and there is no correlation between a given fluid loss value and the actual loss downhole.

Free Water Test Free water tests are not normally performed on squeeze slurries because the differential pressure exerted during the squeeze job will force water from the slurry. Most slurries acceptable for squeezing do not have free water present. When squeezing with a low density or highly dispersed slurry, settling tendency is the critical characteristic. Free water tests do reveal settling problems. All free water tests should be run by placing the

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graduated cylinder at a 45 ° angle, as this is the more strenuous test for both free water and settling.

Rheology Rheological properties of a slurry are not a factor in squeeze slurry performance except when tubing frictional forces are critical, as mentioned above for small tubing workstrings. As with all slurries, high rheological readings warn of potential problems when mixing with less than well-maintained mixing equipment.

Compressive Strength Test Compressive strength tests also have little meaning in relation to squeeze slurries and are not normally run. Forcing water from a squeeze slurry will result in a set cement that has a compressive strength much higher than anything that can be easily duplicated in the laboratory. Conventional compressive strength tests only have meaning for the parent slurry remaining in the casing that has not appreciably dehydrated.

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REFER TO BOOK

SPECIFICATION FOR MATERIALS AND TESTING FOR WELL CEMENTS

API SPECIFICATION 10 (SPEC 10) FIFTH EDITION, JULY 1, 1990

American Petroleum Institute 1220 L Street, Northwest Washington, DC 20005

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SECTION D:

INJECTION RATES AND PLACEMENT TECHNIQUES


Squeeze Applications Perforation Squeeze Open-Hole Squeeze Casing Leak Squeeze Top of Liner Squeeze Casing Shoe Squeeze

2.0

Well Bore Characteristics

3.0

Geological Considerations

4.0

Injection Rates/Pressures Improving Injectivity Injection Profile Analysis

5.0

Squeeze Placement Methods Bullhead Squeeze Method Spotting Fluid Bradenhead Method Through Tubing Squeeze Method

6.0

Pressure Building Techniques Running Squeezes Hesitation Squeezing

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SECTION D:

INJECTION RATES AND PLACEMENT TECHNIQUES

The use of pressure to force a cement slurry into specific locations in a well in order to obtain a seal is called “squeeze cementing”. There are a wide variety of reasons for performing a squeeze job on a well, but most of those reasons are to change undesired conditions in the well. The descriptive name “remedial cementing” is sometimes used synonymously with “squeeze cementing”. However, previous sections have already discussed several other corrective processes which can also be described as remedial cementing. Frequently, there is a sense of urgency while performing a squeeze job, and critical details are sometimes overlooked or forgotten. We hope this section of the manual will help lessen those occurrences by providing a clearer understanding of the elements of successful cement squeezing.

Remedial squeeze cementing techniques can offer a wide variety of "cures" to problems related to fluid movement behind the casing and/or in the wellbore. Where possible, prevention is a more effective, less expensive solution than squeeze cementing. Squeezing is a remedial tool. It should never be routinely regarded as a planned supplement to primary cementing. For example, careful design and executing of primary cementing is a much better way to obtain zone isolation than relaying on “block squeezing” above and below the pay zones. In fact, as we will discuss below, highpressure block squeezing may actually aggravate fluid communication between zones.

1.

SQUEEZE APPLICATIONS

The reasons for squeezing job can usually be placed into one of the following categories:

Perforation Squeeze When cement is placed through or left in perforations, such as for: 1. repairing a faulty primary cement job due to channeling, 2. excluding formation water from the wellbore, 3. abandoning (permanently) a nonproductive zone, 4. abandoning (temporarily) a productive zone, 5. filling annular voids left due to inadequate fill by the primary cement job, or 6. assuring adequate zonal isolation (also called block squeezing).

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Open-hole Squeeze When cement is placed in the uncased wellbore for: 1. sealing off low-pressure formations that have broken down (lost circulation), or 2. shutting off the flow of oil, gas, or water into the well (also called a kill squeeze).

Casing Leak Squeeze When cement is used to repair damaged casing caused by: 1. abrasion wear from downhole equipment and/or operations, 2. corrosion from formation fluids or (improperly treated) completion fluids, 3. physically parted casing strings, or 4. exposure to excessive pressures.

Top of Liner Squeeze When cement is used to seal around liner tops that fail due to: 1. channeling caused by poor primary cement job, 2. inadequate fill from the primary cement job, 3. annular gas flows, or 4. formation breakdown during primary cement job.

Casing Shoe Squeeze When a casing seat fails to hold necessary pressure after being drilled out. causes of this are:

Some

1. over-displacing primary cement, 2. cement channeling during primary cement job, or 3. setting the casing shoe in a weak or unconsolidated formation (usually sand).

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Figures 1-5 are illustrations of some typical situations where squeeze cementing is used to correct undesired downhole conditions.

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What follows here is a discussion and explanation of “Controlled Water-Loss” (CWL) squeezing. The most obvious and fundamental difference from other, more traditional methods of squeeze cementing is the use of fluid-loss control agents in the squeeze slurries. The greatest contrast between CWL squeezes and more traditional methods is in the rate that their respective slurries lose filtrate to permeability. It is only by controlling the filtration rate that relatively small quantities of cement can be directed to small squeeze targets in a well. The existing conditions for squeezing cement can vary widely, and those factors will affect the actual placement of a cement slurry. In spite of the wide range of circumstances that make a squeeze job necessary, there are surprisingly few pieces of information needed to accomplish a successful cement squeeze.

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2.

WELL BORE CHARACTERISTICS

Specific information should be obtained before designing a squeeze cement slurry or planning the steps of a squeeze procedure. Useful information includes: a) the formation fracture gradient at the depth of interest, b) the nature of the formation at the target depth (e.g., matrix permeability, fractures,

etc.), c)

the maximum bottomhole temperature to which the slurry could be exposed,

d) the top of cement circulated on the primary cement job and/or any subsequent

remedial work, e) the calculated hydrostatic pressures exerted by the well fluid(s) and cement slurry at

the squeeze depth, f)

the formation pore pressure and fluid characteristics at the target depth, and

g) the expected pressure differentials at the depth of the squeeze.

All of these items should be available from the records on file for a well, or can be estimated from nearby (off set) wells.

3.

GEOLOGICAL CONSIDERATIONS

A fundamental misconception among engineers and geologists is that basic geological concepts, (i.e., an understanding of formation characteristics), are a necessary element of successful squeeze cementing. While this knowledge may be an advantage, it does not replace information gleaned from a proper injection profile test. A cementer, tool operator, or rig supervisor, with little knowledge of geology, can be successful at squeezing if they can correctly conduct and analyze the injection profile test. This is contingent upon them also having input into the slurry design, slurry testing, and the execution of the squeeze job.

Another misconception is that cement solids enter the matrix of the formation. Usually, it is reported that whole cement can enter a formation that has a permeability of so many millidarcies. The darcy is the unit of permeability measurement, not of the pore throat size. It is determined by the rate at which a fluid of standard viscosity can move a given distance through a given interval of time. The degree of permeability depends upon the size and shape of the pores and the size, shape, and extent of their interconnections. Cement solids plug the pore throat at the face of the formation toward which they are being pumped. This plugging effect creates the filter cake as the liquid is squeezed from the solids-laden fluid into the interconnection system.

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Sandstones are characterized by a porous matrix, and flow of fluids occurs through the interconnected pores which constitute the permeability. Carbonates, such as limestone and dolomites, typically have a less porous matrix and, unless fractured, have permeabilities much lower than sandstones. A formation with matrix porosity and permeability can easily be squeezed so long as the fracture gradient is not exceeded.

A massive shale section can be regarded as impermeable, as can massive salt. Shales have very little or no interconnected pore spaces and allow only a negligible fluid leak-off into the actual rock. If a sustained injection rate is obtained opposite a massive salt or a shale zone, annular cement bonding should be reviewed to determine whether the injected fluids are migrating uphole or downhole. That determination (and the probable probable migration distance) will have a bearing upon the volume of slurry required to fill the channel and/or the void annular space to achieve a squeeze.

4.

INJECTION RATES / PRESSURES

If you have only the bottom hole static temperature (BHST), a successful squeeze is still possible. Correct interpretation of a properly executed “two-rate” injection profile test yields the most important data for any squeeze job. Nearly all the information needed needed to conduct a squeeze job can be obtained from a properly executed injection profile test, but only a very small percentage of injection profile tests are executed properly. This is a physical measurement made at the well site; whereby, well fluid is injected into the formation at controlled rates, and the corresponding pressures are recorded. The two rates to record are the lowest rate at which the formation will “take" fluid, and the minimum rate you anticipate is needed to displace the slurry to the first hesitation cycle.

The purpose for establishing an injection rate is to determine a safe rate that fluid can be placed into the formation, IF a safe rate exists in a particular situation. “Safe” means a pump rate with a pressure BELOW the formation fracture gradient. After studying and correlating well data and physically measuring the fluid injection profile, a cement slurry and squeeze procedure can be designed which will have a high probability of success.

There exists a widespread misunderstanding (some people call this a "rule of thumb') that the minimum acceptable injection rate is two barrels per minute without regard to the pressure needed to achieve this rate. This mistake occurs on a global scale. In order to place slurry against the formation, it may be necessary to exceed the fracture gradient. If the injection pressure exceeds the fracture gradient, excessive rates will create excessive fractures.

The test should begin by pumping at a constant, slow rate until injection is established. The slowest rate practical for a cement unit pump is about 1/4 barrel per minute (bpm). After confirmation of injection, the pump speed can be increased to a rate needed for cement slurry placement. In most instances, a rate high enough to allow sufficient time for the cement slurry to be mixed and placed to the target depth should be attained

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before starting to mix cement. This minimum rate to place cement downhole may well be the same as the slowest rate (1/4 bpm). The pressure at this rate may be near the fracture gradient. Again, when injection profiles are established at excessively high pressures and/or rates, damage to the well is either created or perpetuated.

Many things will affect the rate choice, including the cement thickening time, the squeeze depth, the packer setting depth, the size of the workstring, the size of the casing, the volume of the slurry, etc. Many of these things are adjustable. If the desired rate of cement slurry placement requires a pressure that is well above the fracture gradient, careful consideration should be given to changing one or more of the adjustable factors. If it is not feasible to change any of these variables, a squeeze job can still be performed. However, the surrounding formation will be damaged in the process, and the squeeze may be more difficult to achieve as a result. Be conservative, when damage is unavoidable, try to keep the rates, pressures, and volumes injected to the minimum necessary.

When property obtained, a high injection rate will have a low pump pressure. Likewise, a high pump pressure will have a low injection rate. If the slurry designed for a particular job has a long enough enough thickening thickening time time to allow pumping pumping it below below the squeeze packer packer at a rate of 4 bpm, it will not be necessary to obtain an injection rate of 8 bpm. A 2 bpm rate is not needed if 1/2 to 1 bpm is adequate. Figure 6 illustrates these two extremes. Normally, squeeze rates and pressures will fall somewhere between these ranges. As shown, a HIGH rate, LOW pressure test is termed "loose injection"; while a LOW rate, HIGH pressure test is termed "tight injection”.

"LOOSE" injection rates occur on the left side of the scale in Figure 6, and may be as high as 6 to 8 barrels per minute with pressures ranging from a vacuum to a few hundred psi. A well being on a vacuum would be the extreme on the loose injection side. “TIGHT” injection rates occur on the right of the scale indicated in the figure. They are illustrated there with a pressure of 3,500 - 4,000 psi and an injection rate of just 1/4 to 1/2 bpm. The extreme on the tight injection side would be when a constant rate is not achievable within the pressure limitations. There is no justification for obtaining an injection with a high rate and a high pressure. The reason is that excessive formation fracturing is caused by these conditions. As already explained, the squeeze job should be re-designed instead of following a course that has a high likelihood of failure.

Other elements of a properly executed injection profile test involve the choice of fluid pumped and the total volume of fluid injected, as well as the pressures and rates that have already been discussed. For squeeze cementing, a clear well fluid, such as water or brine, is best. Keep in mind that drilling fluids (mud) are designed to plug exposed permeability with a filter cake and contain mud solids to achieve this end. When squeezing with drilling mud as the well fluid, applied pressure can induce fracturing when a mud filter cake blocks formation permeability. As already explained, induced fracturing is usually best avoided when trying to achieve a successful squeeze. In some cases, circumstances dictate that using clear water is impractical.

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Simply be aware that using drilling mud runs the risks of fracturing during an injection profile test and during the squeeze, and make allowances for that occurrence.

A sufficient volume of fluid to pump when obtaining an injection rate must also be considered. Plastic formation behavior and aerated wellbore fluids can distort the results of some tests. If only one or two barrels of fluid are used, misinterpretation is a greater risk than if ten barrels of fluid are used. It is impossible to say that any one volume will be adequate in every squeeze situation. The fundamental principle is to always use a volume sufficient to know beyond any doubt that injection was definitely established. Relatively deep squeezes will require an even greater volume than shallow ones because of the additional hole volume.

Improving Injectivity Occasionally, the injection profile will be so tight that economics will favor steps taken to improve injectivity. The reasons may be diverse, but they will be focused around the desirability of achieving a successful squeeze on the first attempt. The steps which can be attempted to increase the chances of success will be familiar to production engineers, but the more commonly used methods here will briefly be discussed.

Perforation Penetration: Improved perforation penetration is the first measure that can improve the chances of obtaining the goals of the squeeze job. Factors that will influence penetration are: a) perforating in a solids-free environment, b) perforating with a pressure imbalance towards the well bore, c) perforation shot phasing, and d) perforation charge size.

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Perforation Washing: Another improvement to injectivity may be to use one of a variety of perf washing tools. Surge tools and cup-type perf washers both have merit under differing circumstances. The wash tools allow for the washing of individual or “sets” of perforations. Also a variation is to spot a wash (usually water) across the perforations to be squeezed and conduct an injection profile test. This does not force a volume of water into individual perforations. Another variation used quite successfully is to run a liberal volume of water pre-flush ahead of the squeeze slurry.

Acid Treatments: In conjunction with a perforation washing, an acid soak may improve injectivity. This would most definitely increase the penetration of the squeeze slurry and improve the chances of success. Just keep in mind that spent acid will contaminate cement unless it is flushed with water afterwards.

This discussion is NOT a recommendation for using acid prior to every squeeze job. The only wells where acid should be used are those with insufficient injectivity and are judged likely to have their injectivity increased by acid. While acid may improve injectivity, acid is specifically inhibited NOT to attack steel, so a hole in the casing being squeezed will not be enlarged by the injection of acid. Scale buildup could be removed with acid, provided it is an acid soluble scale. Perforations plugged by drilling fluid solids (filter cake) can be aided by a light treatment of mud acid. Once again, this is not a blanket endorsement of acid before every squeeze job, but a discussion of just what can be done to improve a well's injectivity profile before attempting a squeeze.

Always get the total picture clearly in focus before attempting remedial steps that may not always be cost-effective solutions.

Injection Profile Analysis Once an injection profile test has been conducted, it should be analyzed carefully for data that can be used for making the right decisions throughout the squeeze job. The discussion here will deal mostly with the ends of the scale in Figure 1 (loose or tight injection). Interpolation can be made for injection rates/pressures that fall in between the end points of the scale.

Downhole Conditions: A "loose injection' is caused by either a high permeability formation or voids. Voids are: vugs, fractures, channels, uncemented casing, depleted zones, etc. At this point, without additional data, all loose injections should be approached in the same manner. A “light injection" is caused by either a low permeability formation or restriction in the flowstream. Restrictions are such things as a hole in the casing, a minute channel in a liner overlap, clogged perforations, etc. Again, without additional data, all tight injections should be approached the same.

Slurry Volume: In Section A, BASIC INFORMATION, a squeeze was defined as placing cement slurry under pressure against a permeable formation, causing the slurry to

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dehydrate and create a cementitious seal across the formation face. Unless there is data to support a loose injection being due to a high permeability formation, it is most likely due to voids. Slurry must fill the voids, or seal the entrance to the voids, before it can be placed against the formation face. The exact volume is dependent upon the extent of the voids but a good guideline when the injection is on the loose side is about 200 sacks of cement. A review of additional data may indicate a larger volume is more realistic. Tight injections, being caused by restricted areas, either restrictions in the flow stream or limited exposure of permeable formation, call for small volumes of slurry (35 - 50 sacks).

Slurry Design: High permeability formations and voids are indicated by a loose injection. In squeezing voids, including fractured formations, a greater emphasis must be placed on effectively sealing the fracture network or void area behind the casing. In squeezing a fractured formation, it is important that the cement seals the entrance to the fractures or voids. Larger volumes of slurry are required than for squeezing permeable formations. The most successful squeezes in such cases use a two slurry design. A highly accelerated lead slurry with moderate fluid loss will go into the areas of least resistance, is designed to set quickly, and start dehydrating shortly after reaching the formation.

After it fills the entrance to the voids (fractures, vugs, etc.), the setting and dehydrating will seal these voids and actually convert from a loose to a tight injection. The volume of the lead slurry should be from one-half to two-thirds of the total volume. It is followed immediately by a tail slurry with a low fluid loss and a longer thickening time. The tail slurry is used to build filter cake and seal the more resistant areas. It is also the slurry that is left in the casing when and if hesitation is necessary. For reliable performance, both slurries must be tested on an alternate schedule for hesitation squeezes.

IMPORTANT: For the operator to always be in control of the squeeze process, it is imperative that the tail slurry always have a lower fluid loss and a longer thickening time than the lead slurry. When the operator applies extra pressure at the surface, he must be certain that it is transferred to the formation or to the cementitious seal.

When a “tight” injection is obtained, it is due to a low permeability formation or else to a restriction in the flowstream (like a leak). A low fluid loss slurry similar to the tail slurry above should be used for tight injections. While there could be a highly permeable formation behind the restriction in the flow stream, the low fluid loss is needed to assure that the slurry will get past the restriction without dehydrating. This slurry must also be tested on an alternate schedule for hesitation squeezes.

Slurry Performance: A review of the injection profile will reveal the slurry performance that can be anticipated. A loose injection due to voids will most surely require the application of hesitation periods to build sufficient squeeze pressure. With little or no resistance, the lead slurry will be placed far from the wellbore if pumping is continued. It must be placed in the least restrictive voids and allowed to dehydrate and start setting. Hesitation provides time for this to occur. Dehydration and setting is evidenced by an

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increase in pressure when pumping resumes. More discussion on hesitation is presented later under “Slurry Placement Techniques”.

A tight injection due to low permeability is a likely candidate for obtaining a running squeeze, provided the fracture gradient is not exceeded by any great amount. A loose injection due to high permeability is also a good candidate for a running squeeze. A running squeeze occurs when the cementitious seal is created without stopping the pump. When this happens, the pressure will not bleed off when the pumps are shut down at the maximum allowable pressure.

Regarding slurry preparation, a batch mixing procedure is strongly advised. Batch mixing ensures that the properties of the slurry pumped into the well are as close as possible to those of the slurry designed and tested in the cement lab. On most squeeze jobs, the volume of slurry required is quite small, but the requirements for its quality are quite high. For this reason, extra care taken to assure the slurry quality is justified. The batch mixing refinement is especially critical in CWL squeezing. Because of temperature differences between the surface and downhole formations in most wells, the additional time spent on the surface assuring slurry uniformity (as much as 1 hour) will be equivalent to no more than a few minutes of downhole thickening time, provided that temperature differences between ambient surface temperature and the downhole circulating temperature are at least 20 °F. Anxiety should not be a reason for cutting short mixing time in the batch mixer to assure slurry uniformity.

Reserve Slurry Volume: Since hesitations may be necessary with a loose or tight injection, a volume of slurry should be reserved inside the casing for that purpose. A look at the injection profile will give a clue as to how much should be reserved to use for hesitations. If it is a loose injection, a large volume should be reserved. If it is a tight injection, a smaller volume will do. A small volume for a tight injection, within most casing sizes, would be about 2 barrels. Many squeezes are conducted using only 1 barrel or less but 2 barrels volume should be the minimum reserved when working inside conventional size casing.

It is better to drill out the excess than to need it and not have it. A large volume, in this case, could be from 2 to 6 barrels depending upon the capacity of the casing. While 6 barrels may be appropriate inside 9-5/8 inch or larger casing, it would be an unrealistic volume for 4-1/2 inch casing. Even in larger casing, 6 barrels is usually more than enough but the same applies as above. It is easier to drill out than to have to re-squeeze because you did not allow a sufficient reserve. An exception to the above would be when working with smaller than normal tubing (i.e., coil tubing). When drilling out is not an option, the reserve would be dependent on the volume that could be safely circulated out of the hole.

Hesitation Duration: The injection profile will also give an indication of the length of time needed for the first hesitation. When the injection is loose and does not increase significantly during the placement of cement against the formation, it will be necessary for

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a long first hesitation to allow time for setting and dehydration. A long first hesitation would be about thirty minutes. If the injection is tight, or has developed considerable pressure during placement, a short first hesitation of from 10 to 15 minutes is more in order. This is for the first hesitation only, subsequent hesitation periods will be dependent upon subsequent pressure increases.

Expected Final Pressure: Expected final pressure should be relative to the well conditions. The well conditions are clear in the injection profile. A tight injection indicates that any pressure below equipment limitations may be achievable, but a pressure that is realistic is a pressure that is 200 - 300 psig above the fracture gradient. This is sufficient to determine that the cementitious seal has been created. Exceeding the fracture gradient without losing pressure to the formation indicates that a seal has been created.

Final pressure above the fracture gradient, while showing that the seal has been created, is not required for a successful squeeze. What is required to build the cementitious seal is a pressure differential toward the formation. Any pressure increase may be sufficient when squeezing a loose injection situation. The pressure increase should be considered at the point of squeeze, and a well that started on a vacuum could have zero on the cement unit pressure gauge and have sufficient pressure if it would hold a column of fluid.

5.

SQUEEZE PLACEMENT METHODS

Cement slurries for squeezing are usually placed downhole using a variation of one of four basic methods: 1. the bullhead squeeze method, 2. the spotting method, 3. the Bradenhead squeeze method, or 4. the through tubing squeeze method.

Bullhead Squeeze Method In this method, a packer is set above the zone to be squeezed to isolate the wellhead and casing above the tool setting depth, from the squeeze pressure. Pressure is applied to the annulus to monitor possible communication. The injection profile test is run, with either well fluid or water. The cement is mixed and pumped down the workstring, forcing the well fluid in the casing (between the packer and point of squeeze) and in the workstring into the formation ahead of the squeeze slurry. Sufficient displacement fluid must be available as none of the well fluid will be recovered. While well conditions will sometimes favor using this method, it may require pumping a large volume of fluid into the formation ahead of the cement slurry. Bullhead squeezing has limited application,

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but it is a viable option in some situations. Figure 7 illustrates the bullhead squeeze method.

Spotting Method The spotting method uses a packer set near the top of the zone to be squeezed. This method also isolates the wellhead and casing, above the tool setting depth, from the squeeze pressure. After the tool is set in the casing and the injection test has been run, slurry placement involves the opening of a bypass/circulating valve (on retrievable packers) to circulate down the work string, “Spotting” the slurry in the workstring just above the too. Continue circulation through the squeeze tool until the leading edge of the cement nears the tool. If a cement retainer is being used, the workstring is simply pulled up until the stinger is out of the seal bore to allow circulation. To begin injecting cement,

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lower the workstring, re-insert the stinger in the seal bore, or close the bypass/circulating valve of the squeeze tool. Trap the cement/mud differential pressure on the workstring annulus or apply pressure as needed to monitor in the event of communication. Continue displacing the squeeze slurry, which will now be injecting into the formation again.

DO NOT allow any of the spacer fluid (especially water) to escape the work string prior to closing the valve in the squeeze tool. This is to prevent the creation of a fluid interface zone between the spacer fluid and the annular well fluids. Such an interface could cause the squeeze tool to become stuck by solids settling in the interface above the tool. See Figure 8 for the spotting method.

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Refer to the section on tool selection considerations.

Bradenhead Method This was the earliest recorded method of placing squeeze slurry downhole. It is accomplished through a workstring without the use of downhole tools. Two primary variations are in wide use today. Usually the slurry is mixed and spotted, much like a balanced plug is set, across the zone to be squeezed. Then the workstring is pulled up and out of the slurry. After closing in the wellhead around the workstring, squeeze pressure is applied to the workstring. This will force the slurry against the formation, causing it to dehydrate. After the squeeze pressure is achieved, excess cement remaining in the casing or workstring can be reversed out, or the cement can be left to be drilled out, if so desired. The other popular variation is to set the total depth of the workstring just above the point of squeeze and close in the wellhead. The slurry is then "bullheaded" down the workstring, forcing the well fluid in the workstring into the formation ahead of the slurry.

Bradenhead squeezing should be reserved for shallow, low pressure squeezes as it is difficult to control the flow of fluids without a packer, and maximum pressures are limited by the casing and wellhead equipment. This method is used extensively to squeeze wells generally less than 5,000 feet deep, in well plugging, and occasionally in squeezing off zones of partially lost circulation while drilling. Figure 9 illustrates a typical Bradenhead squeeze sequence.

Through Tubing Squeeze Method As the name implies, this type of squeeze is performed through tubing in producing wells. The -technique has application where rig mobilization costs are high, such as offshore or remote locations, like in the Arctic. In more accessible areas, the removal of production equipment from the well, and replacement after squeezing, is still costly, and frequently drilling muds induced into the formation during killing, squeezing, and drilling out cause damage to production. Through tubing squeezes are performed on "live" wells and are generally done with coiled tubing units or snubbing units, with appropriate well control equipment to allow for running small tubing through conventional production tubing.

Coiled tubing units have a reel of continuous tubing mounted on a trailer or skid with necessary lubricator, injector, and power equipment to unroll and run the coil of tubing into the well, through the existing production tubing, to the point of squeeze. It provides a connection for the cementing unit to pump the slurry down the continuous tubing. Snubbing units run small jointed tubing into the well, through the existing production tubing, to the point of squeeze and can handle wells with greater working pressures. Placement of slurry is similar to Bradenhead squeezing with a balanced plug of squeeze slurry set across the point of squeeze.

The workstring is pulled above the cement, and hesitation squeeze techniques are applied. The coiled tubing unit has the ability, with proper calculations, to reel up the

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continuous tubing as the slurry is exiting the lower end so that it does not have to be pulled through a significant column of cement.

The well control equipment could include a back pressure valve installed at the bottom of the workstring, which would prevent the reverse circulation of excess slurry back to the surface. If it does not, reversing still may apply considerable pressure on the formation and on the workstring above the slurry being reversed out. Since no retrievable tools are affected, it is generally recommended (for through tubing squeezes) to circulate out the excess slurry by going “the long way” up the workstring/production tubing annulus. Slurries designed for through tubing squeezes should include time to do this in the labtested thickening time. Circulation may be slower than in conventional squeeze

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situations due to restrictions from the smaller tubulars, the necessity of routing through a manifold, and possibly a choke to maintain well control.

Squeeze jobs done by this method rely even more on a properly designed slurry combined with laboratory verification of actual slurry performance. Fluid-loss control will be crucial (as low as 25 to 50ml/30 min), and attention to the low-shear rheology is also recommended. The slurry should have a long thickening time (as much as from 4 to 8 hours). This is due to the low pump rate necessary when using small tubing. The long thickening time also allows time for circulating excess if it needs to be removed from the well. The slurry should exhibit NO setting. This can best be verified during a free water test. The practice of lowering the coil tubing back into the excess slurry after the squeeze for the purpose of commingling a contaminate with it and then waiting an additional time period before circulating the excess out of the well is not recommended by the Cementing Services Division. A well designed slurry, properly tested, can be circulated out without problems. Figure 10 shows the through tubing method using a coiled tubing unit.

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6. PRESSURE BUILDING TECHNIOUES Many individuals debate the merits of the "running” squeeze or the hesitation squeeze. Neither method has any inherent advantages that make it the best" method for every squeeze job. Before proceeding any further, a clarification of what is meant by each of these terms may prevent miscommunication. A running squeeze is one conducted without stopping the fluid movement by the pump until you achieve a predetermined pressure limit.

A hesitation squeeze is one during which the slurry movement is interrupted, after slurry reaches the formation, by stopping the pumps to allow time for dehydration and setting. In reality, the formation being squeezed will determine which method is most likely to occur, and the properly executed injection test will reveal this. A high rate/low pressure (LOOSE) profile will indicate that hesitation periods may be necessary. A loose injection can be a candidate for a running squeeze in cases when the injectivity is the consequence of high permeability.

Frequently, it is difficult to distinguish between permeability and fractures from the surface. A low rate/high pressure (TIGHT) profile will indicate a running squeeze is likely. However, these trends are not hard and fast rules. A competent hesitation designed and tested slurry can easily obtain a running squeeze, if the formation is conducive to a running squeeze AND you do not damage the formation in the process. Slurries without sufficient fluid loss control and/or not tested on a hesitation schedule are not effective when hesitating and may dehydrate prematurely.

The hesitation test verifies that the slurry can be stopped and started again any number of times while remaining fluid and pumpable. Even when it is certain that a running squeeze is going to occur, the first thing that is done after reaching the maximum pressure limit is to stop the pump. The pressure is monitored to see if it is going to hold or leak off. If it holds, a running squeeze has occurred, and it is time to reverse out the excess in the workstring. These static periods take some time yet they have not been simulated unless a hesitation test was run. The best results will be obtained by always planning for a hesitation squeeze, and being prepared for a running squeeze.

Running Squeezes Some proponents of running squeezes wrongly believe that the descriptive name “running” means exactly that. They will try to achieve formation lockup (final squeeze pressure) at the high pump rate induced during the injection test. Usually those who think more in terms of "walking" squeezes are more successful by being willing to reduce the pump rate when the slurry reaches the formation. High pump rates perpetuate the fracturing process. Slurries pumped at slow rates are more likely to dehydrate and seal the entrance to the fractures.

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The most accurate name for successful running squeezes may be “walking” squeezes or even “creeping” squeezes. A low permeability formation is a likely candidate for a running squeeze. The first opportunity that a running squeeze can occur is when the slurry first contacts the perforations. In order to be prepared for this occurrence, you should calculate the volume of the cement slurry that will be inside the workstring at this point. By converting this volume to a height, you can obtain the hydrostatic pressure. The differential between this and an equal height column of well fluid will be the surface pressure needed to begin reverse circulating the maximum amount of cement. Another calculation made prior to beginning any squeeze job should be the hydrostatic differential for just one barrel of slurry in the workstring.

By always knowing the exact volume of slurry left inside the workstring during the squeeze, it will be possible to know quickly just what surface pressure is needed to reverse out anytime a running squeeze develops.

If the pressure drops during the final waiting period, you did not obtain a running squeeze and should re-apply the pump to increase the static pressure back to the previously determined squeeze pressure. You have now switched to hesitation squeezing.

Hesitation Squeezing This method is applied by intermittently pumping and stopping the slurry for irregular periods that are determined at the time of performing the squeeze in response to the conditions encountered. Hesitation proponents are sometimes obsessed with clearing the squeeze tool and will refuse to slow the pump until this is done. There exists a rather widespread reluctance to stop the movement of cement during a squeeze job because of the gelling behavior of neat cement. This arises by not understanding the condition of the slurry inside the workstring.

Fluid loss controlled slurries avoid this problem altogether. They are lab tested according to “hesitation" schedules where they are alternately stirred and motionless, under simulated downhole conditions. Laboratory reported thickening times indicate the maximum time a slurry will remain fluid at a given temperature inside the closed test cell. It has absolutely NO relationship to the time a slurry will remain fluid when placed against a porous formation. Thickening time does reflect the time that planned movement of the slurry inside the workstring and/or casing becomes doubtful.

If the injection rate was loose, the reason was probably either voids behind the casing, high formation permeability, or induced fractures. With any of these conditions, there will be little resistance to flow. No matter what causes it, a low injection pressure on a well makes it a candidate for a hesitation squeeze approach with a two slurry design in order to build up to a higher squeeze pressure. A short thickening time lead slurry, with a fairly high fluid loss (300-500 ml/ 30 min) will allow the slurry to dehydrate, set quickly to seal the voids and allow tail slurry to be placed against more resistant areas of the exposed formation.

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The slurry that is left inside the casing string to use during the hesitation stages must remain fluid and pumpable at all times during the squeeze job. Since cement fluid loss control prevents gelation and premature dehydration of the slurry, it is important to follow the high fluid loss, short thickening time slurry with a lower fluid loss (50-100 ml/30 min), and longer thickening time “tail" slurry. This sequence is mandatory to be able to transfer progressively higher pump pressures from the surface unit to the formation. Only tail slurry is left inside the casing for hesitation purposes.

One of the best explanations of the hesitation method of squeezing is a selective stimulation job done utilizing diverting balls. In both instances, the zone with the lowest resistance will take the majority of the fluid being injected. Just as a diverting ball forms a seal on that zone, stopping the slurry while keeping pressure applied allows a seal to form. Subsequent pumping periods will experience progressively progressively higher injection pressures (squeeze pressures) as more resistant intervals are forced to take the fluid being pumped. Pressure charts recorded during hesitation squeezes typically display a "stair step" pattern as a result of this kind of formation response.

Whether or not a hesitation technique is being used, successful squeeze jobs will usually include a reduction of the pump rate as cement contacts the formation. Once the slurry actually contacts the face of the formation, filter cake can begin to build immediately. The pump rate should be reduced to allow this buildup without unnecessary fracturing. The pump should be progressively slowed so that it is at the lowest rate it can sustain at the time the retrievable packer is clear of cement. Slowing the pump allows the possibility of a running squeeze. After displacing the slurry clear of the tool by a safety margin that you are comfortable with, begin the hesitation phase if you have not achieved the desired pressure.

Another concern is how long to wait between pumping sessions while performing a hesitation squeeze. Time and volumes are not indicators for determining waiting and pumping cycles. All that is required is an understanding of how how to interpret surface pressures in response to what is occurring in the well. A loose injection, with no appreciable build up of pressure during displacement, will need a long hesitation period in order to begin begin building squeeze pressure. A first hesitation period of 30 minutes or longer is not unreasonable. A tight injection, or when there has been considerable increase in pressure during displacement, calls for a shorter first waiting period (10 to 15 minutes). Pumping should be resumed at the slowest rate sustainable. Do not worry about rates or volumes at this point.

Continue to watch the pressure gauge, and pump only as long as the pressure steadily increases. When the rate of increase drops or the pressure decreases, stop pumping, and begin the second hesitation period. Now you can check the volume pumped while the pressure is stabilizing. Compare the stabilized pressure with that of the previous hesitation. If there is little or no pressure increase over the last time, the waiting period needs to be extended. You are injecting slurry with the same resistance and quite possibly in the same area. Should there be a substantial increase, the waiting periods can be shortened. You have

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sealed the least resistant area and are now applying additional pressure, forcing slurry in a new direction.

Continue the cycle of pump-hesitate-pump until the final squeeze pressure is attained. When you reach the maximum allowable pressure, without bleed off , you have sealed all the exposed formation possible within these pressure limits. Remember, with no pressure increase, the waiting period should be lengthened. With a pressure increase, the waiting periods should be shortened. Figures 11 and 12 show examples of time/pressure plots of typical hesitation squeezes.

When using a slurry with controlled fluid loss, each pressure break is usually a new perforation (or area) taking slurry that was not receptive previously. Pumping slowly as in a leakoff test allows the slurry filter cake to form and support the higher pressures needed to open the next more resistant perforation (or area). We utilize a low fluid loss slurry and hesitation procedure to assure that each perforation receives slurry or each section of the exposed formation is covered. Pumping at higher rates increases the risk of unintended fracturing. Even if a high pressure squeeze is being performed, slower pump rates are desirable. The slower rates allow time for the cement solids to either develop a cake on the fracture faces and/or bridge the fracture.

Occasionally, all of the prepared slurry will be fully expended without attaining the desired final squeeze pressure. In such cases, a volume of cement sufficient to cover the perforations should be left inside the casing. There is a nearly overpowering urge to admit defeat and overflush the perforations in such instances, but frequently a successful squeeze will develop if the perforations remain covered. The requirement is only a pressure differential toward the formation, not a specified differential.

Higher pressure will build the filter cake faster but not necessarily better. Field results have verified success after drilling out the cement and pressure testing the squeeze. At the worst, if another squeeze is necessary, there will be set cement just behind the casing to support the second cement slurry. If you feel there is strong justification for overflushing, just overflush slightly. By "slightly", we mean just clear the top perforations by one to two barrels rather than the customary ten to twenty barrels. Doing so will leave some support for a subsequent squeeze attempt.

You can determine a final squeeze pressure by utilizing the injection profile as a guide. A loose injection will usually result in a low final pressure. On shallow wells, or highly fractured ones, practically ANY squeeze pressure will be satisfactory. Many lost circulation squeezes are successful when they only conclude with a full column of well fluid and NO pump pressure. A tight injection will require a high final squeeze pressure. Some people attempt to obtain 1000 psi above the injection pressure for a final squeeze pressure. This may be a valid approach on some moderately deep wells provided that the injection rate was properly obtained.

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Tight injections may require a pressure higher than 1000 psi above the injection rate. If the injection is tight, due to a restriction of mud solids compacted in perforations, a higher pressure may be required. The final pressure may also be limited by your best estimate of the remaining casing integrity, potential channels in the cement behind the casing, etc. Once again, the minimum final pressure need only provide a differential toward the formation.

Regardless of how it is chosen, after reaching the maximum squeeze pressure, there needs to be a monitoring period from ten to fifteen minutes before pressure is bled off and ending the squeeze job. There have been many instances when a perforation plugged by mud solids or other debris has opened after seven to twelve minutes of sustained high pressure. A successful squeeze may not be obtained when the job is terminated after just five minutes of applied maximum pressure.

Truly, patience is a virtue when cementing, especially when squeeze cementing. There have been more cement jobs ruined by haste and impulsiveness than by waiting. Excess cement in the workstring can be safely reversed out anytime within the thickening time period of a correct hesitation test schedule. After the workstring and squeeze packer are cleared of cement, there is absolutely no reason for impatience. If it does become necessary to reverse out unused cement slurry, the previously calculated pressures will demonstrate the benefits of advance planning.

Low Pressure Squeezes: In the process of applying pressure to the cement slurry, the aim is to fill the perforation cavities and/or interconnected void spaces with cement. Control of the hydrostatic pressure of the cement column in the workstring is important. Excessive pressure could result in breakdown of the formation, with all the attendant problems already discussed in previous sections. For example, to squeeze perforations at 6250 feet through 2-7/8” tubing inside 7" (29 lb/ft) casing with a packer set at 6150 feet, using a fracture gradient of 0.7 psi/ft and a displacement brine of 8.6 ppg for 15.8 ppg Class G slurry, only 80 sacks of cement will create a column with a hydrostatic pressure within 500 psi of the formation fracture limit. Any larger squeeze slurry could exceed the fracture strength of the formation.

In low-pressure squeezes, it is beneficial that all perforations and channels to be squeezed are clear of mud or other solids. If the well has been on production, such openings may already be free of obstructions; however, for newly completed wells, it may be necessary to clean the perforations before attempting to perform the squeeze job. This was discussed previously.

High Pressure Squeezes : In instances when the bottomhole treating pressure exceeds the formation fracturing pressure, a squeeze job is termed “high pressure". In some cases, a low pressure squeeze of the perforations will simply not achieve the objective of the job. Channels in the primary cement job may not be directly connected to the perforations being squeezed. Small cracks or micro-annuli that may allow the flow of gas do not allow the passage of a cement slurry. In such cases, these channels must be

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enlarged enough to accept a viscous, solids-laden fluid. Many low-pressure squeezes cannot be performed if it is impossible to remove plugging fluids, or debris, from ahead of the cement slurry.

Placement of the cement slurry behind the casing is accomplished by breaking down the formation. Fluids ahead of the slurry are displaced in the fractures, allowing the slurry to fill the desired spaces. The further application of squeeze pressures causes the dehydration of the slurry against the formation walls, leaving perforations and entrances to fractures filled with cement.

During a high-pressure squeeze, the location and orientation of the created fractures cannot be controlled. Sedimentary rocks usually have an inherently low tensile strength. They are held together primarily by the weight or the compressive forces of overlying formations. These cohesive forces act in all directions to hold the rock together, but do not have the same magnitude in all directions. When sufficient hydraulic pressure is applied against a formation, the rock fractures along the plane perpendicular to the direction of the least principal stress.

A horizontal fracture is created if the fracturing pressure is greater than the overburden pressure. A vertical fracture occurs if overburden pressure is greater. Thus, fractures induced in formations deeper than about 3000 feet are nearly always vertical. This is one major reason for NOT using high-pressure squeeze techniques. Even if the annulus between casing and formation is sealed, vertical communication between zones may be established in the squeeze fracture. Horizontal fractures containing cement “pancakes" cannot be generated by high-pressure squeezing In deep wells (depths > 3,000 feet).

Once a fracture is created, whether intentionally or not, it must be sealed-off with cement, particularly if it is vertical and extends into a zone being isolated. However, sealing-off the fracture may be difficult because fracturing is usually initiated with drilling mud. Attempts to purge the fractures may only extend them. Thus, the necessary volume of cement can be large. The extent of the induced fracture is a function of the pump rate applied after the fracture is initiated. The amount of slurry used depends on the way the operation is performed. High pump rates generate large fractures; thus, large volumes of cement are required to fill them. A properly performed high-pressure squeeze should utilize a low rate to leave the cement as close to the wellbore as possible.

For the reasons mentioned above, problems caused by mud-filled fractures can be minimized by using water for the injection test by providing a lower fracture initiation pressure fluids. Another problem in squeezing a perforated interval is that mud-filled perforations can withstand large pressure differentials, especially toward the formation. Also, all perforations may not be forced open when the formation is fractured by the application of high pressure. These problems may warrant the use of efforts mentioned earlier under “Improving Injectivity”.

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In summary, it is sometimes not possible to remain below the fracture pressure when conducting squeeze jobs. The inherent problems associated with high-pressure squeezing complicate the task of obtaining a successful job. Even though fracturing may be unavoidable sometimes, the best chances for success occur by keeping injection rates as low as possible. Hesitation techniques will improve the likelihood of success in high pressure squeezing just as in low-pressure jobs, and for the same reasons.

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SECTION E

TOOL SELECTION CONSIDERATIONS

Table of Contents

1.0

Retrievable Squeeze Tools

2.0

Drillable Squeeze Tools

3.0

Selecting Squeeze Packer Setting Location

4.0

Circulating Valves and Other Downhole Tools

5.0

Surface Equipment

6.0

Tubular Pressures

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SECTION E

TOOL SELECTION CONSIDERATIONS

Remedial cementing tools are mechanical and/or hydraulic devices which are used downhole to assist in the placement of cement during squeeze operations. They are generally used to isolate areas of the casing from squeeze pressures or cement. Remedial cementing tools are most commonly provided with a service man. The basic types of downhole squeeze tools are retrievable and drillable (non-retrievable) tools. Each category of downhole tools has advantages in specific applications. The choice between drillable or retrievable squeeze tools is primarily dependent on individual well conditions and on the squeeze technique being planned. Details on the specific performance operational capabilities or the design limitations of specific tools need to be obtained directly from the service supplier or the manufacturer.

Retrievable squeeze packers are sometimes referred to simply as “packers". Drillable squeeze packers are commonly called "cement retainers". Bridge plugs are mechanical isolation tools that are available in retrievable or drillable models. Bridge plugs cannot be pumped through. Different companies will use slightly different names for tools that perform the same functions, so care must be exercised to prevent the misapplication of a particular tool.

1.0

RETRIEVABLE SQUEEZE TOOLS

Retrievable tools are made of mostly non-drillable materials to allow for the running, retrieving, maintaining, and re-running over an extended tool life of many years. Retrievable tools are preferred to minimize drillout time, for squeezing multiple zones, for block squeezing, for squeezing liner tops, and when perforating through the tool. Since retrievable packers can be moved and reset multiple times, they allow several operations in a single trip. Versatility is another advantage of using retrievable tools because the tools may be configured in a wide range of combinations.

Retrievable squeeze packers are always run and set on the workstring. Both tension set and compression set designs are made, but compression set versions are more versatile. Whenever the weight of the workstring is sufficient, the use of compression set squeeze tools is advised. Tension set tools are usually only considered for very shallow squeeze applications. Unless otherwise noted, further discussions of retrievable squeeze tools in this section will be understood to mean compression set packers. Some people may term these "set down" packers. Both types of retrievable squeeze packers are illustrated in Figure 1.

Retrievable tools are generally used in situations where the potential for backflow after the squeeze is thought to be low. However, backflow into the wellbore may be induced by the swabbing effect created as the tool is released and pulled. Another potential

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problem may occur when the tool is released after the job if differential pressure from the formation causes backflow that disturbs the cement filter cake forming the wellbore seal.

Generally, retrievable tools are less expensive to run. Less rig time is required if the cement is to be drilled out. Many accessories, such as retrievable bridge plugs, have been developed for use with the retrievable squeeze packer. These can be run below the squeeze packer and set at any point below the packer. An application that involves squeezing off an upper set of perforations while leaving a lower set open is one in which a retrievable bridge plug can be used to isolate the lower perforations. While set, a retrievable bridge plug will hold pressure from either above or below.

This isolation technique is most commonly required for high pressure squeezes to minimize the amount of casing exposed to the squeeze pressure. It can be effectively used on low pressure squeezes when highly accurate cement placement is desired. In low pressure jobs, it is possible to run and retrieve the bridge plug on the same trip with the retrievable squeeze packer, if the squeezed zone is washed through before the cement sets. With this equipment, it is also possible to squeeze multiple zones on the same trip. A job sequence in this case might call for the bridge plug to be run and set between the lowermost two zones in a well where three zones are open. The upper two sets of perforations could each be squeezed individually before retrieving the bridge plug. Differential pressures between casing and the formations must be carefully watched to prevent the displacement of any unset cement filter cake from the zones just squeezed.

The retrievable packers available for squeeze cementing operations have two basic design types. The two types are integral bypass packers and concentric bypass packers. The bypass in a squeeze packer serves three purposes in the workstring:

1. It helps the wellbore fluids to bypass the larger diameter packer elements as the tools are run in the hole. When the bypass is open, part of the annular fluid comes up through the center of the tool and out the bypass ports. This serves to reduce wellbore surge and swab pressures.

2. The bypass provides a means of equalizing the pressure above and below the packer. This feature helps to prevent pressure surges in the well when releasing the tool after a squeeze.

3. The bypass feature provides greater control of slurry placement by allowing ordinary circulation (with returns) without having to unseat the squeeze tool, hence circulating valve.

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Concentric bypass packer systems are designed for specific applications, such as horizontal or deviated wells. The Concentric bypass packer minimizes the torque required to operate the packer and, more important, ensures circulation around the slips during cleanup steps after a squeeze job. The Halliburton CHAMP packers utilize a concentric bypass system. The RTTS packer (also from Halliburton) has an integral bypass valve.

Most compression set tools (regardless of bypass type) are engaged by slightly lifting the tool, rotating a quarter turn to the right (at the tool), and slacking off the workstring weight by whatever amount is required by the tool manufacturer. This operation will free the lower slip assembly to slide over the lower cone and engage the casing wall. As the pipe is lowered, the sealing elements are compressed until they are packed off against the casing. The mechanism used to select and hold the safety (running) or set position is

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called a “J-slot". It consists of a lug confined to a slot shaped like the letter "J". The lug is typically mounted on the mandrel of the tool, whereas the slot is milled into the lower slip assembly. Figure 2 illustrates the positions and operation of both manual (or "straight") and automatic "J" slots. The automatic “J" places the packer in the running (or safety) position automatically. The straight “J" requires left hand rotation to position the safety. Compression packers are released by simply raising the workstring and eliminating the compression.

Bridge plugs are employed normally to isolate portions of a well below a zone being squeezed. When set, a bridge plug acts as a solid barrier to flow, resisting pressure from both above and below. Retrievable bridge plugs are quite frequently used in wells where multiple zones are perforated and open. They can be set and released as often as necessary. They enable single trip straddle operations when run in tandem with a retrievable packer. Tension packers are not recommended for tandem running operations with certain models of bridge plugs because their combined operations may prevent freeing the tension packer. The entire assembly may be locked in place in the

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well. Retrievable bridge plugs can be run in one trip below a retrievable squeeze packer. They are retrieved after the slurry has been reversed or drilled out. In some circumstances, a bridge plug is used below the perforations being squeezed to isolate a deeper interval. Dropping one or two sacks of frac sand on top of it will prevent the settling of cement over the releasing mechanism.

Retrievable bridge plugs are made in cup type or packer type configurations. For shallow, moderate pressure applications, some people prefer cup type bridge plugs. They are simpler and more economical than packer type bridge plugs. Since the sealing cups are in constant contact with the casing while being run in the hole, they are subject to accelerated failure, as well as increased surge and swab pressures. Cup type bridge plugs are both run and retrieved by a retrieving sleeve. They are set by the application of pressure from either direction (differential pressures), and only remain set while a pressure differential exists across the plug. Cup type plugs may be used in tandem with a tension set packer. They are not feasible to use on squeeze jobs below liner tops, because the sealing cups may be damaged working through the liner hanger. The essential working parts of a cup type bridge plug are illustrated in Figure 3.

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Packer type retrievable bridge plugs employ a design that is better suited to squeeze operations in deep and high pressure situations, as well as squeezes inside liners. They have smaller external diameters than the other style bridge plugs. This feature enables faster running and retrieval because surge and swab conditions are greatly reduced. Packer type bridge plugs are connected to the pipe by a retrieving sleeve. They are most commonly set by rotating to the right while lowering the pipe to apply weight to the plug in order to energize the seals in the plug. A typical minimum recommended setting weight is about 10,000 pounds. Some designs also offer a left hand rotational set which does not require any additional setting weight, for use in shallow applications. The basic mechanisms of a retrievable, packer-type bridge plug are illustrated in Figure 4, along with the tool used to retrieve it.

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They are released f mm the pipe by pulling up slightly while simultaneously rotating to the left a quarter turn at the tool. Packer type bridge plugs are retrieved by lowering the retrieving sleeve while circulating to remove any sand or other debris from above the plug. When solid contact is made, the workstring is raised slightly to pull a small up strain while rotating to the right slowly. Once free, the bridge plug may be retrieved to the surface or moved to another location in the well and reset. This type of bridge plug should definitely NOT be run in tandem with tension set squeeze tools. In order to prevent cement and assorted well debris from interfering with or preventing retrieval, frac sand should be placed on top of retrievable bridge plugs.

2.0

DRILLABLE SQUEEZE TOOLS

Drillable packers are preferred in any situation where there exists a possibility of placing cement around the tool. Another commonly used name for a drillable squeeze packer is a cement retainer. An illustration of a typical cement retainer is included as Figure 5.

Squeezes designed with multiple stages and squeezes during abandonment operations also are typical applications for drillable squeeze tools. Drillable tools may also be used in combination with retrievable ones.

An illustration of an application for both drillable and retrievable tools is a well having two zones to be squeezed. The workstring would have the drillable tool below the retrievable tool. The drillable tool would be set first and used to perform the squeeze on the lower zone. Then, without having to trip out of the hole, the drillable tool can be separated from the workstring, and the upper zone squeezed with the retrievable tool. This situation is depicted in Figure 6.

Drillable squeeze packers are best applied where backflow after cementing is probable, (e.g. recementing casing, open perfs, casing leaks, weak casing, etc. exist above the set point of the cement retainer).

Drillable squeeze packers can be obtained with ether of two different valve systems. The one-way type of back pressure valve will prevent backflow only. The two-way valve will retain pressure from either above or below. Manufacturers have devised two different configurations of a one-way valve. “Flapper” valves are one such variety, “poppet” valves are the other. The most common configuration of a two-way valve is a sliding sleeve. Such a valve closes when the workstring is removed from the seal bore of the packer. The two-way valve system makes it possible to reverse circulate any excess cement slurry remaining in the workstring without exerting any pressure below the tool.

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Cement retainers do not feature "by pass valves" per se, but when they are being run into the well on a workstring, the stinger pipe will cause any type of valve to be open. This open valve will afford some fluid entry into the workstring, lowering the surge and swab effects. Since most cement retainers do not include built-in fluid bypass valves, the squeeze job sequence is varied somewhat from the steps followed with retrievable tools. During the time that the actual slurry is being mixed and pumped down the workstring, the pipe is picked up enough to remove it from the seal bore and allow fluid returns to the surface. When the slurry reaches the lower end of the workstring, the pipe is lowered again into the retainer mandrel (also termed “stinging into” the retainer).

Drillable tools are often set on wireline to get closer to the perforations than retrievable tools. Cement can not be spotted across the entire interval to be squeezed when drillable tools are used, as it can be when retrievable tools are used with a tailpipe assembly. Drillable tools are also used in applications when there is a high risk of getting cement above the tool during the job or when there is weak casing (which could collapse) above the tool. In both cases, it may not be possible to remove the tool after the job is complete.

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One other instance of using drillable tools is when attempting one type of “circulation" squeeze, also known as a suicide (or kamikaze) squeeze, illustrated in Figure 7. In this method, a tool is set between two sets of perforations that are known to be connected by a channel in the annulus. To assure proper cleanup of the interval to be cemented, a clear fluid and/or acid solution as a spearhead is used to establish communication between the perforations. Cement is then circulated through the bottom set of perforations. Since there is a high likelihood of getting cement above the tool, a drillable squeeze packer is used instead of risking the chance of cementing a retrievable packer in place. This placement technique is not normally recommended because pumping a cement slurry through a flow restriction can cause unpredictable results. Two such restrictions in this type of squeeze job are the perforations and annular channel connecting each set of perforations.

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A different "circulation squeeze" generally involves a situation in which there is no cement present in the annulus. One example of such a condition is an inadequate cement top caused by lost circulation occurring during the primary cement job. In such a situation, the casing is perforated above the cement top, and circulation is established to the surface. The annulus is cemented by using a drillable tool set above the perforations to serve the same function as a float collar does during a primary cement job.

Drillable bridge plugs are most often used to create a temporary or permanent plug for squeezing or plugback applications. They can be used to seal off nonproductive zones or wells to be abandoned. They are made of cast iron and feature similar construction to cement retainers. The basic design difference is that their mandrels are solid (or plugged) and thus cannot contain any type of check valve. A typical drillable bridge plug is shown in Figure 8. A drillable bridge plug may be set either by wireline or on a workstring. The setting tools and techniques are often the same as used for cement retainers. Some manufacturers design their drillable bridge plugs to allow pressures above and below the plug to equalize before drilling through the top set of slips. This feature is most important when high pressures or free gas may be encountered below the tool during drill out.

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3.0

SELECTING SQUEEZE PACKER SETTING LOCATION

Several factors influence the choice for the depth of the squeeze tool in the well, regardless of the type of tool used. Tools should not be set in worn, damaged, or corroded casing. Slips on the tool may puncture the casing, or the tool may not seat because of pipe enlargement. Pipe enlargement could occur as the slips are set or when pressure is applied to the casing during the squeeze job. Also, tools should not be set in casing collars or across joint connections. The interior surface of the casing where a squeeze tool is set should be free of any burrs or deposits which could damage elastomeric sealing elements or prevent slips from setting or sealing. Wherever possible, the squeeze tool should be set in a casing section surrounded by a well-bonded cement sheath.

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The safest location for a tool would be at a point which would allow all the cement slurry to fully clear the workstring before injection into the squeeze zone occurs. This may not be feasible in small diameter casing or when pumping a large volume of cement. It would result in placing the squeeze tool a considerable distance above the injection point(s). Setting the tool too far from the injection zone also exposes a greater section of casing to pressure during the squeeze. If set too far above the zone to be squeezed, excessive volumes of well fluids (either workover fluid or drilling mud) must be displaced into the formation ahead of the cement.

Well conditions, such as corroded or split casing, affect tool placement by increasing the distance from the target zone to the squeeze tool. It is usually advisable to pressure test the casing annulus (the backside) above the squeeze packer and then maintain some amount of pressure while squeezing. Observation of this pressure can be used effectively as a check for leaks in the workstring, the squeeze packer, or the casing. Annulus pressure can also help to reduce the risk of casing collapse during high-pressure jobs. Another consideration when choosing the packer setting point must be the cemented condition of the casing being squeezed. It is possible to collapse the casing during a squeeze job.

When mud is in the well and must be pumped into the squeeze zone ahead of the cement, minimizing the volume of mud pumped into the zone is important. The distance between the tool location and injection point represents the volume of fluid which will be pumped ahead of the cement and often represents the cement that must be drilled out after the job. A tailpipe may be used below some tools to allow such tools to be set farther above the injection point, but still permit spotting of cement nearer to the target interval. When used, tailpipes made of fiberglass or aluminum are recommended. These materials can easily be parted and drilled out should the tailpipe become cemented in the well.

Contamination of the cement by mud can affect rheological properties, thickening time, and compressive strength. Tests have shown that oil-based mud contamination can reduce compressive strength by 75 percent or more. Oil muds are thickened by waterwet solids and can produce a viscous mass which is hard to inject into the target zone. The calcium chloride brine internal phase of oil muds can cause a dramatic reduction in thickening time. The lignosulfonates used in water based muds are strong retarders for most cement slurries.

4.0

CIRCULATING VALVES AND OTHER DOWNHOLE TOOLS

Circulating valves are offered by tool companies to be run above the packer in the workstring when squeezing with a packer that does not feature a built in bypass valve. They can be known by many names such as equalizing valves, circulating valves, tubing unloaders, and fluid bypass valves. In each case, they provide an alternate passage for spotting or circulating fluids. They are designed to be operated in conjunction with

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retrievable squeeze packers and are available for both tension set and compression set operations.

When the valve is used as a bypass, fluid passes around the packer as it is being run in or out of the hole. Some of the annular fluid passes through the center of the packer and out through the bypass ports (if they are open). The same valve can be used to equalize pressures around the packer. It can also be used to spot fluids around the packer without unsetting the packer.

Tubing testers are fundamentally downhole valves made up in the lower end of the workstring to check the pipe for leaks. During squeezes, it is always advisable to test the pipe before mixing cement because of the potential problems that exist when pumping cement under moderate to high differential pressures. A leaking connection may permit localized cement dehydration and create false squeeze indications at the surface, or even completely plug the tubing at that point.

Tubing test valves are typically equipped with a full opening mechanism. The full opening bore permits the use of “through tubing” perforating guns or other wireline tools. They are placed in the workstring above the packer and are commonly run in the open position to allow filling the pipe. They are typically closed by rotating the pipe to the right a quarter turn (at the valve) and lifting the pipe. They are reopened by simply lowering the pipe. As an alternative to these valves, a simple ball-seat sub or seating nipple may also be used to test the pipe string for leaks. Drawbacks to this method are the slight internal restriction caused by the sub, and the ball must be reverse-circulated completely to the surface prior to pumping through the sub after a test.

There are large selections of auxiliary tools available to the rig supervisor to compliment the squeeze packers. Some have been implemented by the rig supervisor in a time of need - such as standing valves, seating nipples, etc. Others have been developed by tool manufacturers for unique tasks such as jars, safety joints, mechanical collar locators, etc. Except for specific applications, most tools should not be run routinely in bottomhole assemblies for squeezing. Squeeze packers with a circulating/bypass valve used in conjunction with bridge plugs for additional isolation (when needed) and a tubing tester (if you have doubts about the integrity of your workstring) should be all the downhole tools necessary for most squeeze work.

5.0

SURFACE EQUIPMENT

A squeeze manifold offers significant advantages and is recommended for most squeeze operations. There are two general designs: upright and flat. Both types perform the same function. Treating lines are run to the manifold from the pumping equipment and from the workstring, annulus, and waste pit. Pressure gauges located on the manifold indicate workstring pressure and annular pressure.

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The advantages of the squeeze manifold are that fluid paths maybe diverted or controlled from one central location. The squeeze manifold should be placed in a position where the operator can easily communicate with the cementer, the company representative, and downhole tool operator. The cementing service company should be informed prior to the job when a squeeze manifold will be used. Extra joints of pipe may be needed to run all the required lines from the manifold to the wellhead, cement pump, and waste pit. Extra double wing and regular chicksans are generally needed for a proper hookup.

Squeeze manifolds contain multiple valves which are critical to the diversion of fluid flow. All valves need to be tested for proper working condition, and the entire manifold should be pressure-tested before each job. Figure 9 offers a somewhat idealized schematic of a squeeze manifold that may be clearer. Once in place, all parts of the squeeze system should be pressure tested. The system is composed of the workstring, the treating lines, manifold, and (in some situations) the annulus. The pressures applied will depend upon the injection pressures and the target (final) squeeze pressure.

Cement mixing and pumping equipment should be situated within easy view of each other. This will facilitate the use of hand signals or other visual exchanges of important information throughout the squeeze job. Each piece of cement mixing and pumping equipment should be thoroughly inspected and tested for proper operation prior to the start of the job. Job monitoring equipment should be set up and tested for proper calibration and operation before the job.

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6.0

TUBULAR PRESSURES

The safest assumption to make is that pressures applied during the squeeze will also be applied to the outside of the casing at some point during the operations. Collapse of the casing should always be considered a definite possibility while planning every squeeze job. Burst pressure of the casing should not be exceeded during the squeeze job since a split in the casing or between perforations may cause a greater problem than originally existed. The physical condition of the casing must be taken into account when determining the burst and collapse strength remaining in a casing string before beginning a squeeze job.

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Applied annular pressures must not exceed the collapse rating of the workstring or the burst rating of the casing. This should not deter the maintenance of annular pressure. Applied annular pressure is recommended for nearly every squeeze job that uses a squeeze tool for three reasons: 1. the pressure integrity of the annulus can be determined, 2. annular pressure can be monitored during the job, and 3. applied pressure pressure offers additional casing support to prevent prevent collapse.

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SECTION F:

CALCULATIONS AN AND D HYDRAULICS

Table of Contents

1.0

Forces on the Casing at the Packer

2.0 2.0

Surf Su rfac ace eP Pre ress ssur ure eS Saf afel ely y App Appli lied ed to the the Ann Annul ulus us

3.0 3.0

Maxi Ma xim mum Allo Allowa wabl ble e Squ Squee eeze ze Pres Pressu sure re

4.0 4.0

Maxi Ma ximu mum m Al Allowa lowabl ble e Rev Rever ersi sing ng Pres Pressu sure re

5.0 5.0

Squ Sq uee eez ze Too Tool Hydr ydrau aullics

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SECTION F

CALCULATIONS AND HYDRAULICS

Performing the calculations necessary to ensure a successful squeeze is an integral step in designing the job. In addition to the calculations done while formulating the slurry, there are two other sets of calculations needed to complete the squeeze design work: a calculation of volumes during the squeeze treatment and the pressures at various points in the wellbore during the different phases of the squeeze.

The volumes calculated for a squeeze job include: a) cement slurry volume (from either the presumed void space to be filled and/or experience), b) volume (capacity) to the end of the workstring, c)

casing volume between the end of the workstring and the squeeze target,

d) volume needed to spot water (for injection) or cement (for squeeze) to the perforations or target zone, and e) volume to spot cement to the tool.

These are simple pipe volume calculations, taking into account the various fluids that are in the pipe. They have already been adequately described in other writings and are not repeated here. The interested reader is directed to Volume 7 of this series entitled Primary Cementing Practices Guide.

In squeeze work, pressure calculations are necessary to ensure the safety of the well and to determine the anticipated pressure to squeeze the well. These include: a) pressure needed to kill the well (if on production), b) pressure to inject into the void (either the maximum pressure limit to avoid fracturing, or to fracture if desired), c)

downhole pressure (at various stages during the squeeze) created by the sum of hydrostatic pressure and applied pump pressure,

d) maximum squeeze pressure, e) maximum surface pressure safely applied to the annulus, f)

forces on the casing at the tool (and workstring buckling dynamics),

g) maximum allowable squeeze pressure, and

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h) maximum allowable pressure to reverse out.

Most phases of a squeeze involve low pump rates; hence, friction-pressure losses may usually be ignored while computing downhole pressures. Ideally, fracturing will not be required. Downhole pressure is the operative concept, because hydrostatic pressures may vary widely as different fluids are pumped into the workstring during a squeeze job.

Most squeeze cementing calculations involve simple volumetrics or hydrostatics, but some require further explanation. Those special calculations are demonstrated with an example wellbore situation illustrated in Figure 1.

1.0

FORCES ON THE CASING AT THE PACKER

During the squeeze job, there are pressures at the packer from two directions. The greatest pressure is on the outside of the casing (P E) tending to collapse it. This pressure (PE) is a combination of the hydrostatic pressure plus the applied squeeze pressure. Sometimes it is necessary to offset PE by the application of pump pressure (PA) to the annulus between the casing and the workstring. This pressure P A must be sufficient to prevent the collapse of the casing (taking into account its condition). The external pressure (P E) can be calculated by:

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PE = Psq + ( 0.052 x D 1 x ρ1 ) - ( 0.052 x D 2 x ρ2 ) where:

ρ1 ρ2

= = = = =

D1 D2 Psq

density of fluid in the casing/hole annulus in ppg density of lightest fluid pumped during the squeeze in ppg true vertical depth, in feet, to the packer, and distance from packer to squeeze zone in feet squeeze pressure experienced by the formation.

P1 is the sum of the pressure applied to the annulus and the hydrostatic pressure of the fluid in the workstring/casing annulus. This pressure must be at least as large as the difference between the adjusted collapse pressure of the casing and the external pressure PE.

In this example, for a squeeze job (refer to Figure 1) requiring a final, formation squeezepressure (Psq) OF 3900 psi and a completion fluid of 8.5 lb/gal brine (annular fluid and preflush).

PE = 3900 + ( 0.052 x 4200 x 11.0 ) - ( 0.052 x 300 x 8.5 ) PE = 6170 psi

With a casing collapse pressure rating of 4910 ;psi, there must be at least 1260 psi on the inside of the casing (P 1) at the packer to prevent collapse (assuming new casing). The hydrostatic pressure of the 8.5 lb/gal brine is 1856 psi, so P 1 is exceeded by 596 psi and should be safe if the casing is new. Depending on the condition of the casing, you may desire to have a larger safety margin. This could be provided by holding pressure on the workstring annulus. To make the appropriate calculation, the extent of casing deterioration should be determined.

2.0

SURFACE PRESSURE SAFELY APPLIED TO THE ANNULUS

In some squeeze treatments, as already discussed, it is helpful or necessary to apply surface pressure to the annulus between the workstring and the casing to avoid collapsing the casing at the squeeze tool during the job. If improperly applied, this pressure can burst the casing string. The burst rating of the casing string must be evaluated (and perhaps downgraded for work done in old or used casing) to ensure that no damage will be done by the application of this “backup” pressure. For safety, it should always be assumed that any pressure exerted below the squeeze is also applied to the outside of the casing. A channel could exist that would allow this pressure to be transmitted against the outside of the casing above the squeeze tool.

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One should always consider the external pressure that the casing at that depth could safely withstand. When the squeeze pressure exceeds the external pressure, the difference is the amount of backpressure needed to be exerted on the casing/workstring annulus in order to protect the casing. This backup pressure should always be calculated on the basis of downhole treating pressure, NOT the applied surface pressure.

3.0

MAXIMUM ALLOWABLE SQUEEZE PRESSURE

Prior to performing the squeeze job, the maximum allowable pressure to be applied must be evaluated. The bottomhole squeeze pressure must be determined by considering the squeeze placement technique selected for this job and the overall integrity of all the pipe in the well. It the placement technique involves fracturing the formation to be able to place the cement, then the pipe condition becomes the main concern. If the squeeze is planned to be done without fracturing, the formation fracturing pressure must be checked to ensure that it is not exceeded during any step of the squeeze.

When maximum allowable squeeze pressure is achieved, the squeeze job will be considered to be complete. Of course, the pressure to which the pipe and the formation are exposed is the sum of the applied pump pressure and the hydrostatic pressure in the workstring. Once this pressure has been determined, then the hydrostatic pressure of the displacing fluids (including any cement in the pipe) must be subtracted, to determine the maximum allowable surface pressure during the squeeze.

In a low-pressure squeeze, the margin for safe operation can be small enough to limit the slurry volume. The following equation will allow the calculation of the maximum length (x in ft) of a cement column the formation can safely withstand:

X =

[( ( FG × h )

- SM

( 0.052

) - ( 0.052

×

(P

c

- Pf

× h × Pf )

))

]

where: FG h SM Pf Pc

= = = = =

formation fracture gradient, in psi/ft depth to zone being squeezed, in ft safety margin to remain below the fracturing pressure limit, in psi fluid density of fluid in wellbore, in lb/gal cement slurry density, in lb/gal

For example, for perforations to be squeezed at 6250 ft through 2-7/8 in OD, 7.90 lb/ft 3 3 tubing (capacity = 0.02943 ft /ft) inside 7-in (30-lb/ft, 0.2065 ft /ft) casing. The squeeze packer will be set at 6150 ft, and the fracture gradient is estimated to be 0.7 psi/ft. The wellbore is full of 8.6 lb/gal brine, and the cement slurry is planned to have a density of 3 15.8 lb/gal and a yield of 1.1 5 ft /sk. Using the formula above:

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[( ( 0.7 psi / ft

X =

× 6250 ft ) - 500 psi ) -

( 0.052

X =

Using this result:

×

( 15.8 lb / gal

3.875 psi - 2.795 psi 0.3744 psi / ft

( 0.052

× 6250 ft × 8.6 lb / gal )

- 8.6 lb / gal

=

3

))

]

2885 ft

3

2,885 ft x 0.02943 ft /ft = 85 ft of slurry.

Converting to sacks of cement:

3

3

85 ft + 1.15 ft /sk = 74 sacks.

This demonstrates that all of the well conditions should be considered when designing a squeeze job. A slurry volume of 80 sacks would risk fracturing the formation and could compound the size of the problem being solved.

There are many ways to determine the final squeeze pressure. Experience in a specific field is probably the preferred method, especially where zones of extremely high or low pressure are encountered for a particular well depth. No single “rule of thumb” guideline will be universally applicable.

4.0

MAXIMUM ALLOWABLE REVERSING PRESSURE

The final pressure calculations required for squeezing are those to determine just what the well may experience when reversing out fluids after the squeeze. In some instances, the only fluid reversed out may be completion fluid. In other instances, cement slurry may be reversed out. During this procedure, the critical areas to consider are the surface casing burst, the workstring collapse, and the actual squeezed zone itself. If cement is to be reversed, the most conservative (safest) assumption to make is that all of the cement mixed is still inside the pipe and none was injected into the formation. The calculations are simply a matter of calculating the filled volume of the workstring and the hydrostatics of the fluids in the pipe and in the annulus. Their difference of the is the pump pressure required, and it is also the pressure to which the casing will be exposed.

It must be compared to the burst rating of that casing (appropriate to its condition). The total hydrostatic pressure in the workstring (all cement in the workstring) must be considered. The hydrostatic friction pressure inside the workstring may be significant, especially in the case of small diameter workstrings, depending on the rate chosen to reverse out. If the friction pressure is appreciable, then it should be evaluated. Consideration should be given to reducing the rate. The most convenient way is to use a

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cement placement simulation (computer program), but the rheological calculations may also be done by hand. At any rate, a limit needs to be set on the pump pressure to use to reverse. This pressure limit must protect the casing.

5.0

SQUEEZE TOOL HYDRAULICS

The following is adapted from a text presented by A. G. Edwards of Halliburton Services. The word “hydraulics” is a rather vague term used in the oil field to describe a number of reactions that occur downhole any time a string of drillpipe, tubing, or a tool is run in a wellbore. Many steps in the ordinary squeeze will change the downhole hydraulics. There is not really any difficult concept in hydraulics. Most often, problems occur when the subject is overlooked or ignored during the planning and/or execution of a squeeze job. Simply being aware of wellbore dynamics and the associated hydraulic changes that affect downhole equipment can greatly aid the planning and execution of successful squeezes.

BACKGROUND CONCEPTS The fundamentals of hydraulics were observed in ancient times by Archimedes and described mathematically by Pascal more than 300 years ago. The basic formula:

FORCE = ( PRESSURE x AREA )

Where: FORCE is expressed in pounds (lb) PRESSURE is expressed in pounds per square inch (psi), and AREA is expressed in square inches (sq in)

The pressure required to offset a force or the pressure created by applying a force to a hydraulic cylinder can be calculated by rearranging that formula above:

PRESSURE = ( FORCE + AREA )

Since most downhole equipment, seals, etc. have a round cross-section, the area found in both formulas is the area of a circle. That formula is easily calculated by the formula:

AREA = Pi x RADIUS x RADIUS

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Perhaps more familiar to some as the "Pi R squared formula”, with AREA expressed in square inches (sq in), Pi about 3.1415 (a constant), and RADIUS is expressed in inches (in). Pi is also expressed as π in many formulae. Since many deal more with diameter than with radius, an equivalent form of the last formula is:

AREA = (0.7854) x DIAMETER x DIAMETER

where the constant Pi is replaced with 0.7854, which is numerically equal to Pi divided by 4.

In downhole applications, it is frequently necessary to calculate hydrostatic pressures. Hydrostatic pressure is the pressure created by a column of fluid, exerted equally in all directions. The taller the column of fluid, or the more dense ("heavier”) the fluids are, the greater the hydrostatic pressure. It is essential to always calculate hydrostatic pressure using true vertical depth rather than total (measured) depth. In wells that do not stand full of fluid, the hydrostatic pressure has to be calculated on the height of the fluid column, rather than depth. The long familiar “0.052 formula" is used to calculate hydrostatic pressures:

HYDROSTATIC PRESSURE = 0.052 x MUD WEIGHT x DEPTH

where HYDROSTATIC PRESSURE is expressed in pounds per square inch (psi), 0.052 is a constant, MUD WEIGHT is expressed in pounds per gallon (lb/gal), and DEPTH is expressed in feet (ft) TVD (true vertical depth). Many may be familiar with the use of fluid gradient tables in which the part of the equation (0.052 x MUD WEIGHT) has been calculated and presented in a tabular format. If so, the hydrostatic pressure formula becomes simply:

HYDROSTATIC PRESSURE = FLUID GRADIENT x DEPTH

where all the variables are expressed as in previous formulas, and the FLUID GRADIENT is expressed in pounds per square inch per foot (psi/ft). A word of caution needs to be extended to the users of fluid gradient tables printed in some handbooks, because they are expressed in psi per 100 feet, instead of psi/ft.

Buoyancy is also a relevant concept in squeeze hydraulics. It is the same property that makes ships float, or a tubing string which has an air weight of 23,500 lb appear to weigh only 19,907 in a well full of 10.0 lb/gal brine. Buoyancy may be defined as a fluid property that exerts an upward force on an object submerged in the fluid. Buoyancy may be calculated by several different methods, but in this discussion, only two ways will be presented. They are: the Buoyancy Factor Method and the Area/Hydrostatic Pressure Method. Knowing two ways allows the selection of the simplest method for a particular

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situation, canceling out opposing forces when possible, and it helps to prevent the consideration of buoyancy twice in a single job.

BUOYANCY FACTOR METHOD Many feel the Buoyancy Factor Method is the simplest one to use. Tables of buoyancy factors are prepared in advance, usually for steel pipe that is submerged open-ended (within the same fluid on the inside of the pipe as on the outside). In the absence of a prepared table, or to verify the accuracy of a value taken from a table, the “buoyancy factor” is calculated from the simple formula:

BUOYANCY FACTOR

=

1 -

( MUD WEIGHT ) 65.4

MUD WEIGHT is expressed in lb/gal and the constant 65.4 is the average density of steel, in lb/gal. Using the buoyancy factor approach, an indicated weight on a driller’s weight indicator can be calculated by the formula:

INDICATED WEIGHT = PIPE WEIGHT IN AIR X LENGTH X BUOYANCY FACTOR

with the INDICATED WEIGHT expressed in pounds (lb), the PIPE WEIGHT IN AIR expressed in pounds per foot (lb/ft), and the LENGTH of the pipe in fluid is expressed in feet (ft). The BUOYANCY FACTOR is without any units (unitless).

Example 1: What does the weight indicator read if 5000 feet of 2-7/8”, 6.5 lb/ft tubing is run in a well filled with 9.4 lb/gal brine (use a buoyancy factor of 0.8563)?

INDICATED WEIGHT = 6.5 lb/ft x 5000 ft x 0.8563 INDICATED WEIGHT = 27,830 lb ↓ For comparison: WEIGHT IN AIR = 6.5 lb/ft x 5000 ft WEIGHT IN AIR = 32,500 lb ↓

In wells where the fluid level is not at the surface, the buoyancy factor approach must be modified to only apply to that length of pipe that is actually submerged in fluid. The indicated weight of the upper segment of pipe (above the fluid level) is calculated by simply using the air weight of the pipe.

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Example 2: What will the weight indicator read if 5000 ft of 2-7/8”, 6.5 lb/ft tubing is run in a well where the fluid level stands at 3000 feet? The well fluid is 9.4 lb/gal salt water.

WEIGHT OF PIPE NOT IN FLUID = 6.5 lb/ft x 3000 ft WEIGHT OF PIPE NOT IN FLUID = 19,500 lb ↓

LENGTH OF PIPE IN FLUID = 5000 ft - 3000 ft = 2000 ft

WEIGHT OF PIPE IN FLUID = 6.5 lb/ft x 2000 x 0.8563 WEIGHT OF PIPE IN FLUID = 11,132 lb ↓

INDICATED WEIGHT = ( 19,500 + 11,132 ) lb ↓ INDICATED WEIGHT = 30,632 lb ↓

AREA/HYDROSTATIC PRESSURE METHOD To determine buoyancy effects using this method, first calculate the pipe weight in air, then calculate the actual upward buoyant force, and subtract it from the pipe weight in air. The next example illustrates this approach.

Example 3: What does the weight indicator read if 5000 feet of 2”, 6.5 lb/ft tubing is run in a well filled with 9.4 lb/gal brine (the same as Example 1)?

Hydrostatic pressure is pushing upward across the exposed pipe end (the area from the pipe OD to the pipe ID). The hydrostatic pressure gradient of 9.4 lb/gal is (0.052 x 9.4), or 0.4888.

PIPE WEIGHT IN AIR = 6.5 lb/ft x 5000 ft PIPE WEIGHT IN AIR = 32,500 lb

HYDROSTATIC PRESSURE = 0.4888 psi/ft x 5000 ft HYDROSTATIC PRESSURE = 2444 psi

TUBING OD AREA = 6.492 sq in MINUS TUBING ID AREA = 4.680 sq in EFFECTIVE AREA = 1.812 sq in

UPWARD BUOYANT FORCE = HYDROSTATIC PRESSURE x AREA UPWARD BUOYANT FORCE = 2444 psi x 1.812 sq in

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UPWARD BUOYANT FORCE = 4429 lb T

INDICATED WEIGHT = PIPE WEIGHT IN AIR - UPWARD BUOYANT FORCE INDICATED WEIGHT = 32,500 lb ↓ - 4429 lb ↑ INDICATED WEIGHT = 28,071 lb ↓

Comparing the answers to Examples 1 and 3, the answers differ by only 241 lb, due to round-off of the decimal points in the various factors. It is doubtful that most weight indicators will show any difference between these two calculated values.

HYDRAULICS of DRILLABLE SQUEEZE PACKERS After this background on the fundamental concepts, specific downhole hydraulics can be examined. To illustrate the hydraulics principles of the tools, we will look at a series of brief examples.

Example 4: Referring to Figure 2, a 5-1/2” drillable squeeze packer has been set at 5000 ft on 2-3/8", 4.7 lb/ft tubing. The well is full of 10.0 lb/gal brine. What does the weight indicator show when the stinger is pulled out of the packer? (Use 1.485 sq in for the stinger OD area and a buoyancy factor of 0.8471.) The stinger pipe is only 2 ft long.

PIPE WEIGHT IN AIR = 4.7 lb/ft x 5000 ft PIPE WEIGHT IN AIR = 23,500 lb ↓

HYDROSTATIC PRESSURE = 0.5200 psi/ft x 5000 ft HYDROSTATIC PRESSUE = 2600 psi

TUBING OD AREA = 4.430 sq in MINUS TUBING ID AREA = 3.126 sq in EFFECTIVE AREA = 1.304 sq in

UPWARD BUOYANT FORCE = HYDROSTATIC PRESSURE x AREA UPWARD BUOYANT FORCE = 2600 psi x 1.304 sq in UPWARD BUOYANT FORCE = 3390 lb ↑

INDICATED WEIGHT = PIPE WEIGHT IN AIR - UPWARD BUOYANT FORCE INDICATED WEIGHT = 23,500 ↓ - 3390 lb ↑ INDICATED WEIGHT = 20,110 lb ↓

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Because the stinger is so short, differences in hydrostatic pressure acting at the top of the bottom of the stinger pipe can be neglected (see Figure 3). Example 3 (illustrated in Figure 4) showed that the buoyancy force is calculated from the hydrostatic pressure acting on the difference in the tubing OD area and the tubing ID area, and that is (about) equal to the answer obtained by using the buoyancy factor method.

INDICATED WEIGHT = PIPE WEIGHT IN AIR x LENGTH x BUOYANCY FACTOR INDICATED WEIGHT = 4.7 lb/ft x 5000 ft x 0.8471 INDICATED WEIGHT = 19,907 lb

Example 5: Under the same conditions as in the preceding example, the annular preventer is closed and the tubing is filled with a 15.0 lb/gal cement slurry. How much pressure must be held on the annulus to keep the cement slurry inside the tubing while the pumps are stopped and lines are washed out (see Figure 5)?

The total pressure on the casing at the bottom must be equal to the hydrostatic pressure of a full column of cement. If this is so, the surface pressure on the annulus must be equal to the difference in the hydrostatic pressure of the two fluids. This is also the same as the change in the tubing hydrostatic pressure. First, find the gradients for the two fluids:

minus

15.0 lb/gal gradient = 15.0 x 0.052 = 0.7800 psi/ft 10.0 lb/gal gradient = 10.0 x 0.052 = 0.5200 psi/ft total change in fluid gradients = 0.2600 psi/ft

change in hydrostatic pressure = 0.2600 psi/ft x 5000 ft change in hydrostatic pressure = 1300 psi

Therefore, the annular pressure is the same, or 1300 psi.

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Since the stinger pipe diameter is less than the tubing OD, the removal of the applied pressure at the surface caused a reduction in the hydraulic force acting upwards at the end of the tubing. Since the upward force was present when the weight was applied to the packer, removing it acts just the same as adding a downward force. Because it is at the bottom of the well, removing it does not have any evident effects on the indicated workstring weight at the surface, but it will add effective weight to the packer.

Example 6: Continuing with the same well data, what is the indicated weight when the pump is shut down to clean the surface lines?

The application of pressure on the annulus makes the hydrostatic pressure at the squeeze tool the same as if the annulus were filled with the 15.0 lb/gal cement slurry. Examples 1 and 3 demonstrated that the AREA/HYDROSTATIC METHOD and the BUOYANCY FACTOR METHOD are equivalent. We have just said that the hydrostatic pressure is equivalent to the 15.0 lb/gal slurry, so the indicated weight will be the same as if the pipe were suspended in a 15.0 lb/gal fluid. The buoyancy factor of 15.0 lb/gal is (1 - 15.0/65.4) = 0.7706.

INDICATED WEIGHT = PIPE WEIGHT IN AIR x LENGTH x BUOYANCY FACTOR INDICATED WEIGHT = 4.7 lb/ft x 5000 ft x 0.7706 INDICATED WEIGHT = 18,109 lb ↓

Example 7: Continuing to look at the same well conditions as in the previous three examples, the stinger is lowered into the squeeze packer, and 10,000 lb of pipe weight set down on the packer. What is the indicated string weight?

From the previous example, the string weight appears to be 18,109 lb. If 10,000 lb is transferred from the hoisting equipment to the squeeze packer, that indicated weight will become 8,109 lb ↓.

Example 8: In the same sample well, with the stinger in the packer to isolate annular fluids from the slurry inside the pipe, the annular pressure of 1300 psi is bled off as in Figure 6. What does the weight indicator read now? How much force is actually applied to the packer?

Since the stinger pipe diameter is less than the tubing OD, the removal of the applied pressure at the surface caused a reduction in the hydraulic force acting upwards at the end of the tubing. Since the upward force was present when the weight was applied to the packer, removing it acts just the same as adding a downward force. Because it is at the bottom of the well, removing it does not have any evident effects on the indicated workstring weight at the surface, but it will add effective weight to the packer.

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The tubing OD area is 4.430 sq in, and Example 4 gave the stinger OD area as 1.485 sq in. Their difference is the area affected by the annular pressure removal, or (4.430 1.485) = 2.945 sq in. The ↑ force lost is equal to the pressure lost (1,300 psi), times the area affected (2.945 sq in). The actual ↑ force removed is 3,829 lb, which, by the preceding discussion, adds to the weight set on the squeeze packer. The effective packer set-down weight is then the sum of the applied 10,000 lb and the 3,829 lb, or 13,829 lb ↓. Since the indicated weight is unchanged, it remains 8,109 lb.

Just as it is sometimes possible to “pump" open-ended tubing out of the hole, it is sometimes possible to pump the stinger out of a drillable squeeze packer. The effective area is less with stinger pipe than with open-ended tubing. It will require more pressure to pump the stinger out of a drillable squeeze packer than it takes to pump an equal length of open-ended tubing out of the ground.

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When pump pressure is applied to a tubing string stung into a drillable squeeze packer, it acts on the string on three different areas (see Figure 7).

1. At the surface, tubing pump pressure acts upwards across the entire tubing ID. 2. At the top of the stinger, pump pressure is acting downward on the area equal to the tubing ID minus the stinger ID. 3. At the end of the stinger pipe, pump pressure is acting upward on the effective area of the stinger OD minus the stinger ID.

The upward force from the end of the stinger pipe will cancel out an equal amount of downward force at the top of the stinger pipe. The slight amount of remaining downward force at the top of the stinger pipe will cancel out an equal amount of upward force acting at the surface. The only remaining area affected by the application of pump pressure is equal to the stinger OD area. It acts in an upward direction, illustrated in Figure 8.

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The downward force available to counteract the effects of tubing pressure is the tubing weight (the weight indicator reading at the time weight was set on the packer) plus or minus any hydraulic force changes made since that time. The amount of weight setting on the packer is not a particularly important, because the tubing pressure would have to lift all of the tubing weight combined with any induced hydraulic forces. Induced forces may be up or down, depending on the circumstances that create them.

Example 9: In our sample well, after setting the 10,000 lb on the packer and bleeding off the 1300 psi of casing pressure, how much pressure can be applied to the tubing to displace the cement without pumping the stinger out of the squeeze packer.

The indicated weight (from Example 6) is 18,109 lb ↓ . The force lost when bleeding off the casing pressure is 3829 lb ↓ . The available force to counteract the effects of tubing pressure is the combined total of these, or (18,109 lb ↓ + 3829 lb ↓ ) = 21,938 lb ↓ . Stinger OD area = 1.485 sq.in. (from Example 4). Using the basic equation to calculate pressure by dividing force by area: MAXIMUM PUMP PRESSURE = AVAILABLE FORCE + SINGER OD AREA MAXIMUM PUMP PRESSURE = (21,938 lb ↓ ) + 1.485 sq in) MAXIMUM PUMP PRESSURE = 14,773 psi

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Obviously, there is very little risk of pumping the stinger out of the squeeze tool while doing the job. A Bradenhead squeeze, on the other hand, would pump the tubing out of the hole at a pressure below 5000 psi. The main reason for the difference is because of the differences between diameters of the areas exposed to the squeeze pressure.

Example 10: Continuing with the squeeze job in progress during other examples, 10.0 lb/gal brine is used to displace the cement slurry. When all of the cement is below the squeeze tool and the tubing is full of just 10.0 lb/gal brine, how much pump pressure will it require to pump the stinger out of the packer?

After displacing the cement from the tubing bore, the hydrostatic pressure is less. That change will affect two locations in the well, shown in Figure 9. At the top of the stinger, the decreased hydrostatic reduces the downward force acting on the area from the tubing ID to the stinger ID. At the end of the stinger, the reduction lessens the upward force acting on the area between the stinger OD and the stinger ID. Since the stinger is so short, the difference in hydrostatic pressure from the top and bottom of the stinger is negligible. Thus, the reduction of the upward force at the bottom of the stinger will cancel out an equal amount of downward force (from the stinger OD to the stinger ID), making the change in tubing hydrostatic pressure actually only a reduction in the downward force acting on the area difference between the tubing ID and the stinger OD, as in Figure 10.

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Since this is a reduction in downward force, it will make the workstring appear to be lighter, thus reducing the available weight and hence lowering the pressure needed to pump the stinger out of the packer. The tubing ID area = 3.126 sq in, and the stinger OD area was given in Example 4 as 1.485 sq in. The difference between these is the area affected, or 1.641 sq in. Example 5 found the change in hydrostatic gradients to be 0.2600 psi/ft, which equals 1300 psi at 5000 ft. The reduction in downward force is found by multiplying the hydrostatic pressure change by the area affected by the change, or 1300 psi x 1.641 sq. in = 2,133 ↑ lb. With cement in the pipe, the available force was found to be 21,952 ↓ lb in the previous example. With brine in the pipe, the available force is reduced to (21,952 ↓ lb - 2133 lb ↑ ) = 19,819 lb ↓ .

MAXIMUM PUMP PRESSURE = AVAILABLE FORCE + STINGER OD AREA MAXIMUM PUMP PRESSURE = 19,819 lb + 1.485 sq in MAXIMUM PUMP PRESSURE = 13,346 psi

ALTERNATIVE SOLUTION, USING BUOYANCY FACTOR METHOD The available force is just the buoyed weight of the tubing at the squeeze packer, or 4.7 lb/ft x 5000 ft x 0.8471 l= 19,907 lb ↓ . Using this value in the formula above:

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MAXIMUM PUMP PRESSURE = AVAILABLE FORCE + STINGER OD AREA MAXIMUM PUMP PRESSURE = 19,907 lb ↓ + 1.485 sq in MAXIMUM PUMP PRESSURE = 13,405 psi

In this particular example, there was very little possibility of pumping the stinger out of the squeeze packer (or cement retainer). Comparing the last two examples, you can note that displacing the workstring with brine reduced the maximum amount of pump pressure on the tubing by about 1400 psi. Pumping the stinger out of the retainer can be much more critical than the conditions of this particular data appeared to indicate. In most instances, there is very little reason to calculate that maximum pressure with the pipe full of cement, since the purpose of squeezing is to pump away cement. In addition, so long as the stinger OD is smaller than the tubing ID, the lowest “pump-out pressure” will occur when the tubing is full of the lightest fluid used during the squeeze job.

Example 11: The workstring is displaced with 10.0 lb/gal brine. What will the weight indicator show when the stinger is pulled out of the retainer in the sample squeeze problem?

This is merely a return to the original conditions of this problem. The indicated weight to remove the stinger from the retainer will be the same as the indicated weight before stinging into the retainer. Example 4 calculated that value as 19,907 lb ↓ .

Job procedures play a major role in calculating squeeze hydraulics. The weight on the packer frequently becomes pivotal, since most drillable squeeze packers are made from cast ion, which is inherently weak in tension. For this reason, the total weight (slack off weight plus any imposed tension sleeve used to set the retainer originally. This becomes more critical when bullheading cement through a retainer because the increase in hydrostatic pressure acting from the tubing ID to the stinger OD adds set-down force (weight) to the packer.

In situations where the job involves a “big” packer with a “small” workstring, like 2-3/8” tubing with a 9-5/8” squeeze tool, the direction of the force created by hydrostatic changes is reversed. It may facilitate understanding to sketch a diagram of the well conditions.

A good squeeze-tool operator is always is aware of how much pressure is required to equalize the two columns of fluids if the squeeze “occurs" while cement is still in the workstring. The following example shows just how this can be done.

Example 12: A squeeze packer is set at 5000 ft with 2-3/8", 4.7 lb/ft tubing. The cement slurry for this job is to weigh 15.0 lb/gal, while the fluid in the well is a 10.0 lb/gal brine.

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What is the minimum pressure to reverse out (ignoring friction pressure), if the squeeze is obtained with: (a) 15 bbl (b) 10 bbl (c) 3 bbl of cement remaining inside the tubing?

Using a cementing handbook to find the tubing fillup factor (2-3/8”, 4.7 lb/ft) of 258.65 ft/bbl. The difference in fluid gradients has been found to be 0.2600 psi/ft in Example 5. The differential pressure per barrel can be calculated from these by multiplication:

258.65 ft/bbl x 0.2600 psi/ft = 67.249 psi/bbl

For quick calculations, this can be rounded to 67 psi/bbl.

MINIMUM PRESSURE TO REVERSE = 67 psi/bbl x 15 bbl = 1005 psi MINIMUM PRESSURE TO REVERSE = 67 psi/bbl x 10 bbl = 670 psi MINIMUM PRESSURE TO REVERSE = 67 psi/bbl x 3 bbl = 201 psi

The pressures calculated in the previous example are actually just the casing pressures need to balance the hydrostatic pressure differential between the inside and outside of the workstring. Friction would make it necessary to apply additional pressure to the casing/tubing annulus to actually move the cement.

The sample calculations examined here in this brief discussion covered some of the fundamental principles involving drillable tools. Hopefully, each reader will realize that the best approach to squeeze hydraulics starts at the point where the weight indicator is observed while the workstring is hanging free in the well. Changes should be calculated as the job progresses. When combined with an appropriate schematic diagram, this approach and a careful analysis of the changes made in the system will definitely help to understand squeeze hydraulics.

Most readers are aware of “Lubinski-type" tubular buckling (stability) analyses. Such calculate are routinely performed prior to stimulation jobs. The same concepts apply to squeeze jobs, but the conditions are frequently not as extreme. In squeeze-job situations, flow rates are less, pressures are often lower, fluid density differences less, and tubulars are stronger or heavier-walled than in well stimulation applications. A retrievable squeeze tool acts the same as a fully-restraining packer. A cement retainer behaves as a non-restraining packer. On occasion, a squeeze job may be subject to buckling conditions, wherefore It should be examined for that likelihood during planning. The Chevron publication "TUBING EFFECTS", by K. P. Redmon, contains the complete treatment of these concepts, and the interested reader is directed there to check a squeeze situation for buckling. A copy is included in this manual as Appendix A.

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Vol 6 Remedial Cementing Practices

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