WELL COMPLETIONS

Problems Related to Squeeze Cementing

S. H. SHRYOCK HALLIBURTON CO. MEMBER A/ME LOS ANGELES, CALIF. K. A. SLAGLE DUNCAN, OKLA.

Abstract Terminology Downloaded from http://onepetro.org/JPT/article-pdf/20/08/801/2221721/spe-1993-pa.pdf by guest on 27 September 2021 Causes of problems relating to squeeze cementing oper­ Breakdown ations are presented. Much has been written on materials' The language used in squeeze cementing is rather loose and techniques"" that have been used in particular areas, and .subsequently leaves much to the imagination of those but little mention is made of some problems that occur expected to execute the job. During training sessions held during the operation. by one of the major oil companies the past 2 years, drill­ ing people were presented with the question, "What is Introduction your definition of a breakdown?" Recognizing that a ma­ jority of those present were from California oil fields, and Squeeze cementing generally can be described as the that the major application for squeeze cementing is that process of forcing a cement slurry into holes in the casing of supplementing a faulty primary job to obtain 1solation and cavities behind the casing. These operations are usu­ of an oil zone from adjacent water zones as required by ally performed during drilling and completion of a well, the California Division of Oil and Gas, the type of squeeze or for repairing or altering a well at some later date. job that was foremost in their minds was that of squeezing Squeeze cementing is necessary for many rellisons, but prob­ water-shut-off holes. There were two definitions expressed ably the most important use is to segregate hydrocarbon most frequently: producing zones from those formations producing other fluids. The key factor on a squeeze cementing job is that (1) That pressure necessary to break down or fracture of placing the cement at the desired point or points neces­ the formation so that it will accept fluid. sary to accomplish the purpose. (2) That which must be done before one can attempt Squeeze cementing problems are closely related to man's a squeeze cementing job. ability to understand the earth's properties once its crust Breakdown actually is a poor name for what really needs has been penetrated. It is often difficult to determine why to be attained on most squeeze jobs since the prominent some wells can be squeezed successfully with one job while problem is in the well bore, and the desired performance others in the same field require four or five jobs. There is for the perforations and cavities to accept fluid without seem to be a number of opinions as to the proper method fracturing. Fractures normally will accept the cement of squeeze cementing. We are not attempting to argue or slurry and often great volumes of it, but not necessarily in find fault with these opinions; rather we hope to approach the area that needs repair. Obtaining a fracture on the alnd recognize problems that do occur in such a manner breakdown will more often than not cause extra rig time, that we might learn to consider ways in which to solve require greater volumes of cement, and create lost time them. waiting on cement-all of which are costly. Applications of Squeeze Cementing Fracture Gradient A term closely related to breakdown and one that needs Some of the most pertinent applications for squeeze to be understood is formation fracture gradient, which is cementing that need consideration are: (1) supplementing a the pressure! foot of depth required to create a fracture. primary cementing job that may be deficient because of Also of interest is the fact that propagation and extension channeling or insufficient fillup (Fig. 1); (2) reduction or of a fracture usually require a lower pressure than was elimination of water intrusion from above or below the needed for its creation. Too often it is assumed that over­ hydrocarbon producing zone (Fig. 3); (3) reduction of the burden lifting is necessary for a fmcture to occur. Also, GOR by isol3!ting the oil zone from an adjacent gas zone; due to average formation density, the fracturing gradient (4) repair of a casing leak that might have deVeloped due to is anticipated to be at least 1 psi! ft of depth. This is a corrosion, pressure parting or joint leaks (Fig. 2); and (5) good round number and easy to use in calculations, but abandoning of old perforations or plugging of a depleted or experience has indicated that due to structural stresses in watered-out producing zone. the earth and elasticity of the earth's formations, fractures usually occur at less than 1 psi! ft and often as low as 0.6 psi! ft. Original manuscript received in Society of Petroleum Engineers office Oct. 9. 1967. Revised manuscript received June 20. 1968. Paper (SPE 1993) was presented at SPE 38th Annual California Regional Meeting Downhole Treating Pressure held in Los Angeles. Calif.• Oct. 26-27. 1967. © Copyright 1968 Ameri­ can Institute of Mining. Metallurgical, and Petroleum Engineers, Inc. After it is recognized that the formation may fracture 'References given at end of paper. at a pressure lower than may be generally anticipated, the

AUGUST, 1968 801 problem becomes one of defining a maximum pressure that pressure was applied in an attempt to obtain 7,400 psi on can be used safely. Since the fracture gradient is pertinent the pumps at the surface. At a pressure of 4,350 psi, the to the subsurface formation in question, and the allowable perforations broke down and again started taking fluid pressure to avoid fracturing equals the gradient times the quite readily. The entire 100 sacks of cement was displaced depth, we are concerned with the downhole treating pres­ without obtaining any indication of another buildup. 1ihree sure. This is a combination of hydrostatic pressure and additional squeeze cement jobs using 475 sacks of cement surface pump pressure less whatever may be lost as fric­ were needed before a job was successful. tion due to velocity during pumping. Because this latter What happened? Pressure of 4,350 psi at the surface factor probably will be relatively small during a squeeze added to a hydrostatic pressure of 3,700 psi exerted by job-approaching zero as the pumping rate is decreased-it 7,400 ft of 72 lb/ cu ft mud created a pressure of 8,050 psi might be advisable to consider frictional pressure loss as a at the perforations, in contrast with 5,800 psi downhole portion of the safety factor, minimizing fracture potential. On breakdown pressure. The explanation for this relatively this basis the maximum surface pump pressure would be high pressure is loss of filtrate from the high fluid loss the allowable downhole treating pressure (fracture gradient slurry during the hesitation period and deposition of im­ times depth) minus the hydrostatic head of cement slurry mobile cement filter cakes in the perforations. However, and other fluids in the tubing, and less whatever ,safety since a WSO test normally is made in a shale section, only factor is considered desirable. In some areas the safety a limited quantity of filter cake was formed because there factor used is 300 psi. was no place for large volumes of filtrate to go. The squeeze We might consider a case to illustrate more clearly this pressure increased enough to move the filter cake; pres­ terminology confusion. An oil company manual on meth­ sure was applied directly on the formation at a gradient Downloaded from http://onepetro.org/JPT/article-pdf/20/08/801/2221721/spe-1993-pa.pdf by guest on 27 September 2021 ods of cementing oil wells stated that a pressure gradient of about 1.09 psi/ft; and a fracture was created and ex­ of 1.0 psi/ ft should be used in calculating pressures for a tended away from the wellbore with the remainder of the squeeze job. Personnel responsible for directing and super­ slurry. In all probability the application of pressure suffi­ vising the job calculated what WClJS thought to be an accept­ ciently weakened the formation around the wellbore so able squeeze pressure in accordance with the manual and that two additional squeezes were required to re-stabilize proceeded with the job to squeeze off water-shut-off the area before the operation was satisfactory. (WSO) holes that had tested wet. The depth at which the What might have been done to reach this excessively squeeze job was to be performed was 7,400 ft, and the hole high pressure that was mistakenly calculated? Allowing contained drilling mud with a density of 72 Ib/ cu ft (hy­ time for the cement either to set or dehydrate more ex­ drostatic gradient of 0.5 psi/ft), which also was to be used tensively probably would have produced a very high final as the displacement fluid. A breakdown was obtained squeeze pressure. However, only limi,ted value would result when the surface pressure reached 2,100 psi (downhole because all this pressure would have been contained with­ treating pressure of 5,800 psi) with the perforations ac­ in the casing and would not apply to the annular area. cepting fluid at a rate of 25 cu ft! min. One hundred sacks This squeeze job was probably a success when only 20 of neat cement (hydrostatic gradient of 0.82 psi/ ft) were sacks were displaced and pressure began to rise, but it mixed, injected into the tubing and displaced to just below degenerated rapidly into an expensive failure. the packer. Initially it was difficult to obtain any pressure buildup, and not until 20 sacks had been displaced did any Job Design indication of a buildup occur. After a wait of 10 min­ utes, pressure was applied, and a buildup to 2,700 psi Before a squeeze cementing operation is begun, several surface pressure was obtained. According to the calcula­ questions must be answered if the operation is to be suc­ tions made prior to the start of the job, the final squeeze cessful. It is important to anticipate situations differing pressure was to be 1 psi/it of depth or 7,400 psi. More from the expected and to select alternatives to meet abnor-

Fig. l-Channel behind the casing on primary job. Fig. 2-Casing leak-split pipe.

802 JOURNAL OF PETROLEUM TECHNOLOGY mal performance characteristics. Questions to be consid­ pair corrosion holes or split pipe, or where insufficient ce­ ered are: ment volumes were used may be appropriate. Normally, it 1. Should mud, water or some other fluid be used as is not necessary to displace the breakdown fluid into re­ the breakdown fluid? stricted areas or into the formation in these cases, but 2. What type of squeeze packer should be used? rather to move it up or down where the annular space between the casing and hole may be relatively large and 3. Where should the squeeze packer be set? contains drilling mud anyway. Generally, it is recom­ 4. What should the maximum squeeze pressure be? mended that water or acid be used for squeezing, and 5. What type of cementing composition would be best drilling fluids for repair jobs. suited for the job? Type of Squeeze Packer Obviously the answers to some of these questions are not too amenable to change during the course of a job, Two basic types of squeeze packers available are the but the first and third items should be flexible within prac­ drillable and the retrievable. The drillable is sold and left tical limits until just before cement mixing begins. Maxi­ in the well as a permanent plug, or is drilled out after the mum squeeze pressure should be subject to reinterpretation job. The retrievable is rented on a job basis and is removed following the job. throughout the job. Drillable packers are supplied with backpressure valves Breakdown Fluids and are best suited for cases where the cement may have The breakdown fluid chosen should be one that will a tendency to flow back after the job. An example is a help the perforatio;ll or void area accept fluid without poor primary cement job behind the pipe that requires Downloaded from http://onepetro.org/JPT/article-pdf/20/08/801/2221721/spe-1993-pa.pdf by guest on 27 September 2021 fracturing." 5 It is suggested that an aqueous solution­ squeezing of a long channel. The backpressure valve will either salt water, an acid solution, or a very low water hold the cement once it is in place to allow the tubing or loss cementing slurry-be used for initial pumping into the drill pipe to be washed and pulled before the cement sets. faulty area. Generally, it is not advisable to obtain a break­ Use of the drillable squeeze packer has become rather down using drilling mud while squeezing perforations for popular because the cement slurry can be trapped under isolation or water shut off, or for any condition where the pressure, maintaining a full system below it and in the void area has relatively restricted flow channels. area being squeezed. They are used quite successfully in It is not uncommon in California, on high angle holes, squeezing high angle holes for both water shut-off and for the squeeze packers to be set 150 to 300 ft above the large volume jobs for completing a faulty primary job. perforations. Common problems are (1) failure to estab.lish The modern drillable packers are easily drilled out. Per­ a suitable buildup, (2) inability to displace the deSifed haps their greatest advantage is the confidence that those volume of cement slurry into the cavity or void area, (3) using them have in setting the packer closer to the per­ channeling of cement through the mud, leaving a "c\onut foration. This lessens considerably the volume of break­ ring", and (4) dilution of the cement slurry with mud .to down fluid or fluid trapped below the packer that has to such an extent that it fails to set hard enough for a satIs­ be displaced through the perforations before the cement factory pressure test. slurry gets there. One method, which has been used with fair success, is Retrievable squeeze packers are designed to be run in to run the squeeze packer to within 10 to 20 ft of the per­ the well, used for the squeeze cementing operation, and forations, to circulate salt water through the tool while retrieved. The retrievable has a number of applications and bringing it up to the desired point, and to 'set the tool to some advantages over drillable packers. This type of packer trap the salt water below it. This practice contains the can be set and released many times to allow greater flex­ drilling mud above the tool. ibility in its use, such as locating and squeezing one or A breakdown with drilling mud when squeezing to re- more holes in the casing with only one trip. The packer is

GAS.

OIL

WATER

PRESENT FUTURE

Fig. 3-Water or gas intrusion into oil zone.

AUGUST, 1968 803 a little less expensive to run; less rig time is required if Squeeze Pressures the cement is to be drilled out. One of the major prob­ Cement is not a true fluid on any type of cement squeeze lems in using a retrievable is to keep the cement slurry job. Cement is a Islurry of solid particles surrounded by from flowing back so that the pressure can be released and water; tests generally indicate that permeability must be at the tool pulled. Another problem sometimes occurs when least 100 darcies before cement can be displaced into the the excess cement is reversed out by pumping down the formation, although pore size will, of course, be an im­ casing around the tool and out the tubing or drill pipe. The portant controlling factor. When cement dehydrates against squeeze cement, if not sufficiently dehydrated, may be a permeable face, the water is pumped out and a cement disturbed by reversing or by a swabbing effect created by filter cake of solid particles forms on the face of the for­ pulling the tool and the slurry back into the hole. mation. If excessive pressures are exerted at the surface, the formation will fracture, and any cement pumped into Well conditions and squeeze pressure requirements usu­ . the formation will enter these fractures. ally determine the choice of a retrievable or a drillable It is important to select the final pressures to be reached squeeze packer. When the operator is unfamiliar with the when squeezing because this selection will determine when area or lacks confidence in the fluidity life of the cement the job is completed. There are many ways to estimate final slurry, a drillable is recommended. In some areas the drill­ pressures, and past experience in a given field is probably abIes are run 70 percent of the time: If there is doubt as the best, especially where zones of extremely high or low to the choice, service companies doing this type of work pressures are encountered for a particular well depth. Field should be consulted. experience with exceptional wells has led to the practice of selecting a final pressure too high for a given area. This Downloaded from http://onepetro.org/JPT/article-pdf/20/08/801/2221721/spe-1993-pa.pdf by guest on 27 September 2021 Location of Squeeze Packer can be extremely expensive. If cement inside the casing Where to set the squeeze packer usually depends on the dehydrates, pressure is applied only against the casing. If type of squeeze job and previous experience in the area. the squeeze is successful and the pressure applied is high Operators often tend to be over-cautious and set the packer for the depth, there is a tendency to set this as a minimum too far from the holes. This allows a large volume of final pressure. However, a considerably lower final pressure breakdown fluid below the packer that must be displaced often can result in a successful squeeze job. before the cement slurry gets to the perforations (Fig. 4). A final pressure that is too high for the depth also may In shallow, low pressure zones in particular, multiple result in the use of excessive amounts of cement. The for­ squeeze jobs are necessary when the squeezer packer is set mation has only a certain amount of strength to with­ 200 to 300 ft above the perforations. This is expensive and stand the pressure applied. Excessive pressure will cause time-consuming. the formation to part and take cement until the friction of the cement increases, causing pressure buildup and addi­ We recommend that the retrievable be set no more than tional formation fracturing. Vertical depth of the well 75 ft above the perforations. Full knowledge of the avail­ should be considered in setting the final pressure. A drilled able pumping time of the cementing composition being depth of 10,000 ft that has deviated 60 degrees should not used is necessary. Leaving 50 ft of cement inside the cas­ be considered the same as a 1O,000-ft straight hole. Gen- ing does not accomplish a successful job if good cement . erally, the required final pressure is based on depth or fill into the perforations and voids has not been obtained. initial breakdown pressure, and most oil companies have When this cement is drilled out and a pressure test is their own formula for figuring this final pressure. made, the holes generally will break down because a per­ A survey was made of successful squeeze jobs, and a foration containing cement cannot hold much pressure summary of the average pressure gradients employed is differential unless the cement is against, and receiving sup­ shown in Table 1. These data do not indicate the extreme port from, the formation. high or low pressures that some zones occasionally require.

Fig. 4--Squeezing perforations with packer set high. Possible mud contamination of cement slurry. Channeling of cement through the mud.

804 JOURNAL OF PETROLEUM TECHNOLOGY For safety it is also necessary to assume that any pres­ TABLE I-PRESSURE GRADIENTS* sure exerted below the packer is applied to the outside of psi/ft of depth the casing, because a channel may exist that would allow this pressure to be transmitted against the casing above Breakdown Final Squeeze Depth Range Gradient Gradient the packer. The maximum safe collapse pressure that the casing will withstand should be determined, and the differ­ San Joaquin Valley ence between this pressure and the maximum final squeeze 1500-3000 0.65 1.15 pressure is the amount of backup pressure required on the 3000·5000 0.70 1.40 tubing-casing annulus to protect the casing. This calcula­ 5000·6500 0.64 1.10 tion should be made using downhole treating pressure. 6500·8000 0.63 1.14 Selection of Cementing Composition Ventura and Coastal 1500-3000 0.78 1.62 Three major factors must be considered in selecting a 3000-5000 0.725 1.275 5000·6500 0.67 1.083 cementi.ng composition for remedial operations. The first 6500-8000 0.69 1.17 factor is the thickening time of the cementing slurry, which is initially governed by the botJtom-hole temperature and Los Angeles Basin depth of the well. The cement must remain in a fluid 600- 1500 0.90 2.18 state, not only for proper placement, but also for the time 1500- 3000 0.85 1.25 3000- 5000 0.86 1.07 necessary to achieve the remedial operations. The second 5000- 6500 0.83 1.10 Downloaded from http://onepetro.org/JPT/article-pdf/20/08/801/2221721/spe-1993-pa.pdf by guest on 27 September 2021 factor is the role of cement slurry. Unless the ,slurry can 6500- 8000 0.83 0.99 penetrate the area necessary to effect a good seal, it can be 8000·11000 0.85 1.13 of no value even though a good pressure buildup was ob­ "These data represent the average gradients used and tained. If a fractured or poorly consolidated zone is being specific wells may require either a lower or higher pressure squeezed, the slurry has to dehydrate or bridge within the for satisfactory results. close proximity of the borehole, or it may be necessary to repeat the operation. The third factor is its effect on the formation behind the perforations. Is a high or low filtra­ TABLE 2-COMPARATIVE PROPERTIES tion-rate cement slurry needed?' Will the dehydrated cement Low Fluid Loss Slurries bond satisfactorily with that part of the formation to which it will be adjacent?' Compressive Slurry Strength It is often necessary to use a controlled fluid loss slurry Weight Thick- as well as retardation to obtain adequate cement penetra­ (Ib/ Fluid ening psi @ 170F tion. Essentially there are two mechanisms by which fluid Additive (percent) cu ft) Loss* Time'~* 16 hrs 24 hrs loss is controlled on the job, and sometimes it is desirable to 0.8 Low Fluid Loss 116 88 2:52 3265 4000 attempt to balance these mechanisms. Additives can be used 1.0 Low Fluid Loss 116 52 3:27 2550 3300 1.0 Dispersant 118 184 3:18 3200 4910 with the cement to provide low fluid loss; and low perme­ 1.0 Dispersant 130 128 2:31 9320 10090 ability formations can control fluid loss by their inability to accept filtrate. Present field practices indicate a thick­ ~'cc/30 min, 325 mesh screen, 1,000 psi pressure. ening time of 2 to 4 hours, with a fluid loss of 100 to 150 '~*Hours: Minutes, API Schedule 15, 6,000-ft squeezeS ee/30 min at 1,000 psi differential pressure on the API test,' to be adequate for a successful squeeze. However, when squeezing against shales and dense limestones or lbl cu ft (13.4 lbl gal) slurry contributes about 700 psil dolomites with formation permeability essentially zero, 1,000 ft while the above slurry weight produces about 900 there probably is no significant need to control fluid loss psill,OOO ft, and 200 psi rarely will be of major conse­ within the slurry by additives. ln fact, if a low fluid loss quence before the final squeeze pressure is actually applied. slurry is used in this situation and sufficient pressure is applied to fracture the formation, a ,satisfactory squeeze While recognizing that improvements i.n cementing com­ is extremely difficult because filtrate cannot be lost to positions, particularly in the properties of fluid loss control immobilize the slurry and stop the fracture extension. and formation compatibility, can be helpful in remedial When a fracture is anticipated, a fast-sett1ng, high-water­ cementing, it should be remembered that proper applica­ loss slurry often can be used. tion techniques are very important. Even the best mate­ rials may not provide satisfactory results when subjected During the past 2 years considerable success has been to 1ncorrect operating procedures. Proper mixing of the achieved by incorporating fluid loss control into a slurry cement slurry is another factor that should receive atten­ through use of a dispersing agent 'and reduced water ratio tion when using cement additives. The compositions con­ to produce a high density slurry. The dispersing agent tiining retarder, low-fluid-Ioss or dispersant additives gen­ maintains low viscosity and low fluid loss to implement erally will not have their properties influenced significantly slurry penetration into channeled areas or other passage­ by slurry weights that vary from designed weight as much ways that are permitting production of unwanted fluids. as 3 Ib/cu ft (0.4 Ib/gal). However, for small volumes Because these compositions have relatively low water ra­ of slurry it may be desirable to consider batch mixing to tios, they are capable of developing substantially higher achieve better uniformity of the slurry before pumping it compressive strengl1h (Table 2) than conventional slurries. into the well. Also, they can withstand higher differential pressures and perform more competently in the event of contamination Application Techniques or dilution by other fluids in the well. Since most squeeze jobs require rather small volumes of these slurries, which Abandoning a depleted or wet zone is a difficult squeeze weig~t about 130 lbl cu ft (17.4 lbl gal), hydrostatic pres­ cementing job. This can occur in cemented pipe that has been sure IS a matter of no great concern. A column of 100 perforated or in an uncemented slotted liner that has been

AUGUST. 1968 805 gravel packed. The nrst operation might call for squeez­ the entire length of a 6-in. bed without dehydrating. At­ ing olI several feet of perforations, with many holes to bc tempts have been made to squeeze off top or intermediate plugged by cement. Penetration of cement into and through water with very little success. Without some means of iso­ these holes is a necessity. and it is not practical to helievc lalting the area being squeezed, it is difficult to get the slurry that all of them will accept cement slurry at the same at the desired point. time. One of the most important steps in this sort of squeeze job is to insure that drilling mud is not used as Squeezing casing leaks or holes is probably one of the the breakdown fluid. Cement penetration into a perfora­ most difficult squeeze jobs. It is not uncommon to attempt tion containing drilling mud is poor and generally ineffec­ a job in a portion of the annulus that was left uncemented. tive. Salt water or preferably weak acid is a much better The squeeze cement has many avenues, and accomplishing choice for pumping into the perforations. It is important a pressure buildup can be most difficult. Even when a pres­ that a low-water-Ioss cement slurry with 3 to 6 hours' sure buildup does occur, and a pressure test is performed thickening time be utilized because it might take 2 or 3 after cleaning out the casing (when the cement has had hours for some of these perforations to accept the cement. opportunity to cure for several hours), the hole can break A problem that often occurs on such a job involves buildup down at relatively low pressure. Sometimes we can account of pressure before all the perforations have accepted ce­ for this by incomplete fill of the void area immediately ment. The cement bridges high in the perforated casing surrounding the hole or split (Fig. 5). However, indications because of excessive water loss, thus blocking movement of are that poor formation bonding, or none at all, has de­ the fluid part of the slurry into the remaining open per­ veloped adjacent to the area being squeezed, or there has forations. Another problem is the use of an excessive been incomplete penetration around the pipe. As many as Downloaded from http://onepetro.org/JPT/article-pdf/20/08/801/2221721/spe-1993-pa.pdf by guest on 27 September 2021 breakdown pressure that initially creates a fracture, which 5 to 8 squeeze jobs may be required to repair this casing. might accept several hundred 'sacks of cement before de­ After failing to accomplish satisfactory results on the first veloping a suitable pressure buildup. Unless the low fluid job, additional attempts should not be made unless changes loss, low pressure hesitation method is used, one or both of are initiated. A neat slurry can be changed to one con­ the problems mentioned likely will occur. taining a bridging agent; the slurry can be preceded with Squeezing in an uncemented slotted liner is not 'So diffi­ a chemical wash; the type of tool can be changed from a cult, but it is difficult to obtain the desired results. Gen­ retrievable to a drillable; the cement can be given a longer time to cure; or, most importantly, the pressures being used erally, this type of job is done to eliminate the intrusion of water or gas restrioting oil production. This is easiest to can be rechecked to make sure the pressures at the point being squeezed are reasonable. accomplish when this intrusion comes from the bottom or near the bottom. Excellent results have been achieved with Remedial operations to control formation waters in a low viscosity, controlled water loss slurry that utilizes a many areas (particularly in California) indicate that cement method referred to as a "braden head" squeeze for elimina­ fails to bond when using conventional fresh water slurries tion of bottom water. Practice has been to fill a portion of because of formation sensitivity to filtrate water from the the liner with gravel (6 X 9 mesh), then place a 50 to 100 cement. Most WSO tests are made in a shale bed imme­ cu ft volume of this low viscosity slurry on top of the diately above or below a water zone. Many of these shales gravel, pull the tubing above the calculated fill point of the exhibit a sensitivity to the fresh water cement filtrate to cement slurry and apply a braden head. Laboratory tests the extent that they begin deteriorating from a hard dense give evidence that a neat cement slurry would penetrate this substance to a soft clay-like putty in a matter of a few 6 X 9 gravel bed less than 2 in. before dehydration, while hours. This problem is not recognized easily because the this low viscosity, controlled water loss slurry penetrated cement squeeze job might initially shut off the water. How-

Fig. 5-Squeezing corrosion holes. Possible behavior of fluids behind the casing. Incomplete coverage of annulus around holes.

806 JOuRNAl. OF PETROLEUM TECIINOLOGY eVer, at some later date this deterioration again may allow References water breakthrough. WSO tests reveal that a good squeeze I. Montgomery, P. C. and Smith, D. K.: "Oil Well Cementing job and a wet test occurred within a 2-ft space. This pat­ Practices and Materials", Modern Well Completion Series, tern continued until the shale body was passed. The fresh Parts 12A and 12B, Pet. Eng. (May and June, 1961). water filtrate of the cement caused the shale to deteriorate 2. Hodges, J. W.: "Squeeze Cementing Methods and Materials": so quickly that, before the next test was made, any prior Oil Well Cementing Practices in the United States, Division bond between the primary cement and shale zone was of Production, API (1959) Chapter 14. destroyed. The use of salt in cement in these areas has 3. Howard, G. C. and Fast, C. R.: "Squeeze Cementing Opera­ practically eliminated this problem and has reduced forma­ tions", Trans., AIME (1950) 189, 53-64. tion damage in sands containing bentonite. The salt also 4. Young, V. R.: "Well Workover with Remedial Rig", Petro­ causes cement expansion, yielding a tighter seal to improve leum Engineer Refresher Course No.4-Individual Well the cement formation bond. Analysis, Los Angeles Basin Section of SPE (1967). 5. Harris, F. N. and Carter, L. G.: "Use a Chemical Wash and Conclusions Low Fluid Loss Cement", Drill. (Jan., 1964) 25, No.3. 6. Beach, H. J., O'Brien, T. B. and Goins, W. C., Jr.: "Forma­ The problems existing in squeeze cementing operations tion Cement Squeezes by Using Low-Water-Loss Cements", are present today as they were 30 years ago. Some solu­ Oil and Gas J. (May 29 and June 12, 1961). tions are offered that give excellent indications of being 7. Slagle, K. A. and Smith, D. K.: "Salt Cement for Shale and better methods. Recognizing that a problem exists and try­ Bentonitic Sands", J. Pet. Tech. (Feb., 1963) 187-194. ing to do something about it is the first step. Attempting 8. API RP lOB: "Recommended Practice for Testing Oil Well Downloaded from http://onepetro.org/JPT/article-pdf/20/08/801/2221721/spe-1993-pa.pdf by guest on 27 September 2021 squeeze cementing jobs with only partial success in the Cements and Cement Additives", Division of Production, same manner over and over again hinders progress and API. *** is very expensive. The use of new methods and selection of cementing compositions that are more compatible with K. A. Slagle is a research engineer for formation characteristics might prove quite surprising. The the Chemical and Development Dept. calculation and use of proper breakdown and final squeeze of Halliburton Co. Slagle received his pressures is probably the most important aspect of squeeze . BS degree in chemical engineering from cementing. Additional rig time and loss of available pro­ The U. of Oklahoma in 1948. Since duction could be avoided if proper pressures were used. that time he has been employed by It is almost without doubt that this alone could eliminate Halliburton, working with oilwel! ce­ the need for several squeeze jobs and reduce the cost of menting materials and techniques. A completing or repairing a well. The time required for picture and biographical sketch of S. H. practical contemplation and visualization of downhole con­ Shryock can be found in the July, 1968, ditions can often produce substantial savings. issue of JOURNAL OF PETROLEUM TECHNOLOGY.

AUGUST,19611 807