Abstract Crystal modifier chemistry is fast becoming very important in the enhanced production capacity of crude oil fluids. These products have been used for many years in offshore and refinery applications with a high degree of success. However, the broad usage of these chemicals in production areas has been spotty at best and often underutilized. Because of the incentive of increased fluid production resulting from crystal modifier application, producers have been more receptive to the usage of these types of treatment chemical applications. Considering this increased willingness of producers to incorporate these chemicals in their treating chemical programs it was important to study the various application methods by which these products can be introduced into the systems requiring treatment. Since, not all wells are equipped with capillary injection strings, or have backside access to chemical injection other methods such as squeeze applications are considered. Thus, laboratory testing and field test results are discussed in this paper. Background 1Considerable research and development have gone into the development of chemicals to address the problems of paraffin wax accumulation in oilfield production and transport operations. Development of these specialty chemicals requires that meaningful methods of testing be undertaken that will accurately predict the effectiveness of these chemicals in an application. To this end many testing methods have been developed to closely approximate field conditions of temperature, pressure pipeline configuration and pumping requirements. The degree to which these methods correspond to actual field and equipment conditions determines the reliability of such tools as predictive means by which field behavior can be determined. Although the theoretical justifications for the use of these measurement techniques are well founded the acceptance of them, by oil companies, as reliable methods must be thoroughly documented. Documentation of the reliability of these methods requires considerable effort by the service companies who employ them. Many times the documentation is found lacking by the oil companies, and the acceptance of the data generated by these tools and techniques is discounted as virtually meaningless. Thus, service companies are challenged to compare the predictions derived from these laboratory techniques to the effects experienced in field applications. The following discussion will cover some of the laboratory testing conducted, and relate it to the results obtained in field applications of the product chosen from these laboratory tests. Discussion Pour Point and Viscosity Testing ASTM D-97 Pour Point Testing (see figures 1 and 2) has been used for many years as a means of determining the effectiveness of chemical additives on the behavior of waxy crude oils. Can this method be used as the sole criteria for effectiveness? The answer is generally no, however when a crude oil shows a high tendency to congeal or gel and little or no tendency to deposit this test might serve quite well as means of determining an effective treatment. However, viscosity measurements should be conducted in combination with the pour point tests to determine the magnitude of a chemically induced physical change. Why is it necessary to add viscometry measurements to the ASTM D-97 Pour Point data? Pour point measurements involve periodically tilting a tube containing a thermometer and treated or untreated oil samples over a progressively declining temperature range, and observing for movement. The shear imparted by this technique is extremely low, and can represent very small changes in viscosity. Therefore, viscosity measurements avoid the ambiguity introduced by this method. Additional information that is of value in determining the behavior of waxy crude oils under various conditions is also obtainable by the use of viscometry (e.g., yield point, shear stress vs. temperature, and shear stress vs. viscosity etc.).

Abstract Iron sulfide (FeS) and hydrogen sulfide (H 2 S) pose serious operational and safety problems in water injection systems. While H 2 S can cause corrosion and toxicity problems, the most common problems associated with iron sulfide are plugging of equipment, filters, injection lines and the formation face. Iron sulfide is frequently formed under oilfield conditions from the interaction of iron with hydrogen sulfide in produced water. Different forms of iron sulfide are produced as a result of both chemically and biologically mediated complex reactions. Furthermore these different forms of iron sulfide undergo various transformations as they are subjected to different environmental conditions. Acrolein acts on H 2 S and iron sulfide through an irreversible chemical reaction with the sulfide entity, producing nontoxic, water soluble, low molecular weight products. Acrolein is being used successfully in oilfield applications both land-based and offshore for removing H 2 S and iron sulfide from produced water. Acrolein treatments have been shown to be highly effective in terms of cost and performance. This paper presents field data on the performance of acrolein in mitigating iron sulfide and H 2 S problems in water injection systems and compares acrolein performance to that of other chemicals. The parameters monitored in the field to determine performance were frequency of injection filter replacement, water quality, and Millipore filtration times. Results from extended field tests demonstrated that acrolein was the most efficient and cost effective chemical of those tested in removing iron sulfide and hydrogen sulfide from the injection water system. Introduction The presence of Iron sulfide (FeS) and hydrogen sulfide (H 2 S) can cause several operational problems in water injection systems. H 2 S can cause corrosion of pipelines and equipment and formation of iron sulfide and creates safety and toxicity concerns. Iron sulfide in injection water results in corrosion and plugging of the lines and formation, lower water throughput, and/or resulting in higher injection pressures and frequent filter changes at the well head, plant and other locations in the system. An operator of a large water injection system in West Texas was injecting approximately 14.78×10 6 liters of water per day using 11 different plants. H 2 S and FeS were present in varying concentrations in the water system at different locations, which if left untreated, resulted in corrosion and plugging of the lines and marginal performance of injection wells. Acrolein had provided an effective solution to the aforementioned problem in the existing water system for several years. However in 1998, the operator wanted to evaluate available technology to identify a cost-effective replacement for acrolein in the water injection system. This paper discusses the selection and performance of new and existing chemistries from a series of field trials conducted at two different locations in this water injection system. Iron Sulfide Overview. Iron sulfide is frequently formed under oil field-related conditions from interaction of iron with H 2 S in produced water. The stability of various iron sulfides depends on conditions such as pH, availability of oxygen, concentration of sulfur-bearing species, composition of the aqueous electrolyte environment and mechanism of biological activity [1] . It has been demonstrated that bacterially produced ferrous sulfides are identical with chemically prepared ferrous sulfides. The initial iron sulfide, stable at pH 7, formed by either bacterial or chemical action, is mackinawite. This is a sulfur-deficient tetragonal crystalline compound, FeS 1-x where x = 0 to 0.11. In acid conditions or in the presence of free sulfide ions, mackinawite is converted to greigite, Fe 3 S 4 , and eventually to pyrrhotite, Fe 1-x S, where x = 0 to 0.125 [2] . For the purpose of this study it was assumed that iron sulfide present in the water injection system was mackinawite based on literature review [1–3] , laboratory experience, and field observations. Iron Sulfide Overview. Iron sulfide is frequently formed under oil field-related conditions from interaction of iron with H 2 S in produced water. The stability of various iron sulfides depends on conditions such as pH, availability of oxygen, concentration of sulfur-bearing species, composition of the aqueous electrolyte environment and mechanism of biological activity [1] . It has been demonstrated that bacterially produced ferrous sulfides are identical with chemically prepared ferrous sulfides. The initial iron sulfide, stable at pH 7, formed by either bacterial or chemical action, is mackinawite. This is a sulfur-deficient tetragonal crystalline compound, FeS 1-x where x = 0 to 0.11. In acid conditions or in the presence of free sulfide ions, mackinawite is converted to greigite, Fe 3 S 4 , and eventually to pyrrhotite, Fe 1-x S, where x = 0 to 0.125 [2] . For the purpose of this study it was assumed that iron sulfide present in the water injection system was mackinawite based on literature review [1–3] , laboratory experience, and field observations.

Abstract Xanthan gum has been used extensively in the oil industry as a viscosifier for different applications due to its unique rheological properties. In this paper we explore how the rheological behavior of xanthan-based fluids can be used to control fluid loss. Linear and radial flow tests were performed in 100–1,00 md rocks. The rheological characteristics of xanthan gum were measured in linear core flow tests. This constitutive flow behavior was used in a radial flow simulator to predict the invasion profile of xanthan gum in the formation. Radial flow tests were performed to validate the predictions from the simulator and to observe the effect of fluid loss additives such as starch and ground Berea. A laboratory scale drilling simulator was used to determine the leakoff and formation damage of xanthan-based drilling fluids. The fluid was circulated through tubing and cuttings were removed from the annulus. Thin section analysis and environmental SEM were performed on rock samples taken at different distances from the wellbore to determine the nature and depth of the damage. Results show that fines generated during the drilling process form an external filter cake which in combination with xanthan gum results in considerable fluid loss reduction. Damage due to xanthan gum is small and limited to a narrow thickness around the wellbore, resulting in negligible skin factors. The use of starch can lead to considerable damage and large skin factors if allowed to invade the formation. Introduction The rate of leakoff is of critical importance during drilling, completion operations (i.e. sand control) and stimulation treatments, such as acid treatments and hydraulic fracturing. In all of these cases, fluid loss control has been achieved by two basic mechanisms: 1 Increasing the overall viscosity of the fluid using high polymer concentrations or by crosslinking the polymer. 2,3 Developing an internal and/or external filter cake using fluid loss additives (starch, sized CaCO 3 , mica, silica flour, oil soluble resins, etc.) to plug the pore-throats of the formation. 4 Both fluid loss control mechanisms may result in a loss of permeability when flow is initiated in the production mode. Furthermore, if fluid loss additives are not used properly, they can cause significant loss of permeability due to their plugging mechanism if they enter the formation. 5,6 Xanthan gum has been used extensively as a viscosifier in the oil field for drilling, drill-in and completion fluids due to its unique rheological properties. 7 In this paper we explore the rheological properties of xanthan-based fluids in Berea sandstone rocks and how these properties can be used to control fluid loss. Prior attempts to simulate the flow of non-Newtonian fluids in porous media have not been entirely satisfactory because of the lack of an adequate correlation between the deformation rates inside the pore-throats and the velocity of the fluid. 3,8,9 Linear and radial flow tests were performed in 100 to 1,000 md rocks. The rheological behavior of xanthan gum was measured in linear core flow tests. This constitutive flow behavior was used in a radial flow simulator to predict the invasion profile of xanthan gum in the formation. Radial flow tests were performed to validate the predictions from the simulator. Simulations of field scale wellbore invasion profiles are presented using both xanthan gum and HEC. The effect of fluid loss additives, such as starch and sized CaCO 3 was also studied in radial flow leak-off tests. The damage left over associated with those additives was quantified and compared to pure xanthan-based fluids.

Abstract The Wickett Field in the Permian Basin, located 40 miles West of Odessa in Ward County, Texas, is a mature field where squeeze operations occur approximately once per week on each workover rig. Historically, squeeze designs and success ratios have been evaluated individually on a "job by job" basis; this has maintained squeeze cementing costs at a very high level for both the operator and the service company. These costs can include factors such as initial and repeated cement laboratory testing on varying cement slurries, on-site pumping services, cementing additives, surface and down hole equipment, administrative and engineering time of both the operator and service company personnel, rig time, and repeated costs with each squeeze attempt. For some operators, additional factors can contribute to the complexity of this process such as limitations on a consistent methodology or organized approach to the operational aspects of a squeeze operation. Variations can exist within engineering, field supervisory, and service company personnel as to proper on-site pumping techniques, cement slurry design, or necessary volumes of cement for initial or subsequent attempts. Often times, a very limited established or organized method is in place for "looking back" on the success or failure of any particular cement slurry or operational technique. Finally, an overwhelming amount of selections are available in the design process concerning slurry design and operational techniques. We will show how an operator, in close association with a service company can establish specific guidelines to manage these complex variations. We will present the methodologies that have reduced the complexity and increased the manageability of an ongoing process. Through these efforts, laboratory testing, administrative and engineering time commitment by the operating and service company personnel, and overall costs in remedial squeeze cementing have been reduced. In addition, these methodologies have improved communications, helped standardized operational considerations, and have increased the probability of successful squeezes on the first attempt. P. 155

SPE 35227 Predicting the Fluid Loss of Drilling, Workover, and Fracturing Fluids into a Formation With and Without Filter Cake E.S. Carlson, SPE, M. Venkataraman, P.E. Clark, SPE, The University of Alabama, T.R. Sifferman, SPE, M.D. Coffey, SPE, J.M. Seheult, Kelco, A Unit of Monsanto Company Copyright 1996, Society of Petroleum Engineers, Inc. Introduction An evaluation of the tests described in the American Petroleum Institute's Recommended Practice "Standard Procedure for Testing Drilling Fluids" would probably lead to the conclusion that the control of fluid loss during drilling or completion operations requires the use of a wall-building fluid. As we will show in this paper, this is not a valid conclusion because power-law fluids can be very effective for invasion control. The lack of a standard test for the invasion characteristics of a power-law fluid is understandable, because the invasion behavior for these fluids depends on both fluid and formation properties. In this paper, we describe the theory of non-Newtonian fluid invasion from a wellbore to a formation, and discuss a computer model that we developed which is based on this theory. We present computational results which validate the model against analytical and experimental results. Using average parameters that were determined from experiments, we show that formation invasion can be effectively controlled using power-law fluids. We also show that the power-law fluid characteristics which lead to good invasion control do not necessarily lead to long-term restrictions to well productivity. Theory We have searched exhaustively to find invasion models which are comparable to the those presented in the following sections. Many models exist which describe invasion characteristics of wall-building fluids. There are papers which discuss the flow of power-law fluids through linear cores, and other papers which discuss transient pressure behavior of power-law fluids in a reservoir. However, we have not found any which rigorously evaluate the invasion behaviors of power-law fluids. Flow of Non-Newtonian Fluids in Porous Media Unlike Newtonian fluids, which exhibit a constant apparent viscosity, general non-Newtonian fluids have an apparent viscosity which depends on the shear rate, and the shear rate depends on the fluid velocity. For power-law fluids, the apparent viscosity can be given by (1) where app is the apparent viscosity in cp, n is the flow behavior index, K is the consistency index in dyne.sn/cm2, and is the shear rate in s-1. For a given power-law fluid, it is a routine matter to measure n and K. When a rotational viscometer is used, shear stress is measured as a function of rotational speed. The shear rate is directly proportional to the rotational speed, and the apparent viscosity is the ratio of shear stress to the corresponding shear rate. P. 643

Abstract Wireline formation testers are increasingly being used to obtain formation pressure and permeability measurements which in turn are used in geological evaluations and in designing well completions. It is generally assumed that the pressure measured by the tester probe is near formation pressure. Unfortunately, in many instances such as in low permeability formations, the mudcake is not adequate to isolate the hydrostatic pressure from the formation near the wellbore As a result, the sandface pressure measured with the formation tester is "supercharged" and not the formation pressure after all. This sandface pressure may be as much as 1,000 psi over the actual formation pressure of interest. This paper demonstrates that a new analytical model can be used along with a new testing technique to correct the measured pressure to actual formation pressure. Supercharging The Formation The wellbore is normally filled with a water or oil-based drilling fluid (mud) to maintain a pressure gradient substantially greater than the normal overburden formation pressure gradient. A mudcake is formed when drilling fluid flows into the formation and solids are deposited on the surface of the wellbore When the mudcake formation approaches a steady-state condition, a pressure gradient is established in the formation such as that illustrated in Figure 1. The pressure drops rapidly across the mudcake from (rw-lmc) to rw and then gradually reduces in the formation and approaches formation pressure at the boundary radius rf. This pressure gradient can be predicted using the familiar steady-state Darcy radial flow equation. Where: Psi = supercharge pressure differential (psi) Pf = formation pressure (psi) Pss = steady state sandface pressure (psi) Kf = formation permeability (mdarcy)= fluid viscosity (cp) qm = mud flow loss rate (cm3/sec) h = formation thickness (cm) rw= well bore radius (cm) rf= formation radius (cm), typically rf=1000 rw Mudcake Transmissibility Constant Assuming that the mudcake is relatively small compared to the well bore diameter the mudcake flow is modeled as a Darcy flow with the following filtrate loss rate: Where: Sm = mud flow velocity at the sandface (cm/sec) Kmc = mudcake permeability (md) lmc = mudcake thickness m = (Kmc/lmc), mudcake transmissibility (md/cm) Pmh = borehole mud hydrostatic pressure (psi) The mudcake transmissibility m is defined to include the mudcake permeability and thickness and represents the resistance to mud filtrate invasion. Wireline Formation Supercharge Testing The basic components of a typical formation tester are illustrated in Figure 2. Initially, the probe measures the mud hydrostatic pressure (Pmh). P. 301

Abstract Particle transport in vertical fractures has always been assumed to be controlled by particle settling. Recently, comments have appeared in the literature that suggest that segregation by convection may be more important in a class of fractures where the perforation height is small relative to the fracture height Unfortunately, this proposition has not been substantiated with experimental data or other observations. In order to test the concept two small slot flow models have been constructed that allow the visualization of flow from a point source into a fracture. To be classified as a point source the height of the fracture must be large relative to the height of the perforations. The models can be used over a wide range of entrance and fracture shear rates. One of the models represents a parallel-sided, uniform fracture while the other contains a non-uniformity below the fluid entrance. Little is known about the effect of non-uniformities on fracture flow especially with non-Newtonian fluids. Introduction A recent paper by Cleary and Fonseca suggested that density differences between the stages in a fracturing treatment could result in segregation of the segments by a convection and encapsulation mechanism that would dominate particle settling (Stokes' settling) in determining the final placement of proppant. An illustration of this is given in Figure 1. Their study was based on computer and conceptual models and was not supported by strong experimental evidence. Encapsulation refers to a state where the particles have concentrated near the center of the fracture and there is a relatively thin layer of fluid next to the wall. This allows the particles to settle in mass and fluid without particles to flow up the outside of the particle mass. In this work, encapsulation was not studied. However, it is difficult to believe that this mechanism would be a major contributor to settling in a non-uniform fracture with fluid loss. There is a great deal of literature on particle settling and proppant transport in hydraulic fractures, including reports of data from large fracture models. For a more complete review see Clark. The model studies have not reported convection as a major factor in particle transport, but most, if not all, of these models were not designed to study proppant transport in point source fractures. A point source fracture is a fracture that has a height that is large relative to the height of the perforated interval. Flow into this type of fracture can be modeled as if the inlet flow comes from a single point. This type of fracture can be found in the tight gas sands of East Texas where fracture heights can be large relative to the perforated interval. P. 617^

SPE Members Abstract Permian Basin operators who need to seal casing leaks to pass Permian Basin operators who need to seal casing leaks to pass Texas Railroad Commission mechanical integrity tests have successfully applied small particle-sized cements, which penetrate casing cracks and very small channels to effect a penetrate casing cracks and very small channels to effect a seal. Small casing leaks plague injection operations when integrity testing results in pressure bleedoff, which indicates presence of leaks. A batch-mixed volume of 25 to 75 sacks of fine particle cement is the typical application used to seal these particle cement is the typical application used to seal these leaks. There are some critical steps that must be taken to help ensure job success; these are discussed. The paper also presents a discussion of small particle-size cements, including presents a discussion of small particle-size cements, including accounts of laboratory testing. Case histories describing techniques of casing leak repair with small particle cements are recounted. Introduction The Permian Basin area of West Texas is known for many waterfloods, H2S problems, and weak formations. The Permian Basin has a long drilling history, and it therefore Permian Basin has a long drilling history, and it therefore contains numerous old wells (up to 50 years old), the casings of which are subject to corrosion degradation. These characteristics make Permian Basin wells subject to casing leaks and cause wells to fail casing integrity tests established by the Texas Railroad Commission for injection wells. Most casing leaks in the Permian Basin that have been repaired with small particle-size cement have ranged from 2000 to 12,000 ft in depth. Most of these have been shallow repairs, 5000 ft and above with some as shallow as 100 ft. Squeeze cementing with small particle-size cement has proved to be an excellent way to seal casing leaks without requiring perforating. Small particle-size cement squeeze jobs do not perforating. Small particle-size cement squeeze jobs do not just patch the damaged area but penetrate to create a seal, Because the need to perforate is eliminated, many small particle-size cement squeeze jobs are less costly than squeeze particle-size cement squeeze jobs are less costly than squeeze jobs involving standard cement. Many successful squeeze sealing jobs using small particle-size cement have been performed in the Permian Basin, The likelihood of a successful small particle-size cement squeeze job is enhanced by incorporating certain preparatory and procedural steps advocated within this paper. procedural steps advocated within this paper. Small Particle-Size Cements There are two types of small particle-size cement available; within this paper they are referred to as "fine" and "ultrafine." Both fine and ultrafine cements are very finely ground cements with average particle sizes much smaller than standard API cement. The small particle size of these cements make them well suited for all squeeze jobs, especially casing and collar leaks in which cement must penetrate very narrow or "tight" areas. Table 1 compares physical properties of fine, ultrafine, and standard cements. properties of fine, ultrafine, and standard cements. Fine cement is a very finely ground cement with an average particle size of 8 microns and a maximum particle size of 15 particle size of 8 microns and a maximum particle size of 15 microns. Fine cement consists of 20 to 30% finely ground cement and 70 to 80% slag material. Ultrafine cement consists of 100% very finely ground Portland cement and has an average particle size of 4 microns. Its extreme fineness makes it very reactive but provides it with excellent penetration capabilities. The benefits of small particle-size cements have been proven in hundreds of jobs which required sealing a casing collar leak or other very narrow area. In these cases, traditional API cements bridge on the affected area, but small particle-size cements penetrate to provide a much more complete seal without requiring perforating. Other applications of small particle-size cements include penetration of gravel packs, particle-size cements include penetration of gravel packs, sealing highly permeable zones, stopping unwanted water or gas production in behind-pipe channels, and squeezing small channels. P. 429

Abstract The process of foaming oil well cements entails the injection of a known quantity of nitrogen gas into a given volume of bent slurry and foaming agent. The amount of nitrogen injected at surface, to produce a foamed cement of a desired density in situ, is a function of the temperature and pressure conditions in the annulus where the slurry will reside when pumping ceases. pumping ceases. Pressure and temperature variations between the Pressure and temperature variations between the point of injection of nitrogen into the slurry point of injection of nitrogen into the slurry and its final annular location create a system that will fluctuate in density, viscosity, volume, and rate depending on the downhole conditions at the moment of observation. This inherent variability in the gas fraction (quality) of a nitrified cement is an important engineering consideration since formations will be exposed to fluids whose dynamic properties are different than those anticipated when in place. These variances can profoundly impact place. These variances can profoundly impact the success of the cementing operation. Mathematical solutions originally developed for foam fracturing treatments have been applied to nitrified cements. This paper provides a method of quantifying the dynamic and static properties of a nitrified cement at any point in its pumping history. pumping history Introduction The main objective of any primary cementing operation is the successful placement of a cement slurry over a specific interval in the casing-wellbore annulus. Once hardened, the cement will support and protect the casing while prohibiting interzonal fluid movement by prohibiting interzonal fluid movement by isolating fluid bearing strata. Central to the success of the cementing operation is the maintenance of a hydrostatic pressure that does not exceed formation fracture pressure that does not exceed formation fracture pressure. When pressure exerted by the fluids pressure. When pressure exerted by the fluids exceed the fracture gradient of a given formation, loss of slurry will occur. The occurrence of lost circulation during slurry placement may lead to a variety of undesirable events. Consequences may include (1) an incomplete or absent cement sheath across a zone of interest, (2) a bridging of the annulus and subsequent flow restriction, or (3) catastrophic job failure. Accordingly, pressure considerations will often necessitate the use of lightweight cement slurries. Traditional materials used to reduce the density of oilwell cements include betonite, metasilicates, gilsonite, diatomeceous earth and others. By incorporating these extenders in a cement system, a reduction in density to approximately 11.5 1bm/gal [1378 kg/m] may be achieved. P. 255

Abstract A novel foamed acid treatment has proven effective in the workover of more than 20 wells in the Permian Basin Delaware, Grayburg, and Upper Clearfork formations. The treatment described uses a foaming mutual solvent/acid system. This system provides the desirable wetting and solubilization properties of a mutual solvent and acid along with the inherent advantages of foam. The uniqueness of this treatment is derived from the prolonged stability of the foam, a property not characteristic of foamed mutual solvent systems. Data is presented from both laboratory and field tests comparing this procedure to conventional foamed acid techniques. Detailed treatment designs are presented which are applicable in coiled tubing and workover strings. These procedures have been used in treatment of injection and producing wells. The treatment described is especially effective in low pressure wells where previous workovers have resulted in poor performance. Introduction For over 20 years, foam has been used in the production of oil and gas. Foam is used in all phases of oil recovery including drilling, stimulation (acidizing and fracturing) and in secondary and tertiary recovery operations. Foam also finds use for diverting during workover, stimulation, enhanced recovery and completions (gravel packing). The initial attraction to foam for drilling and wellbore cleanout was due to its usefulness in low pressure situations. The good mechanical properties of foam: low hydrostatic head, ability to support fines, low leak-off rates, and shear thinning rheological behavior, made it an ideal fluid for completion of low pressure gas zones and fracturing low permeability formations. These properties, plus low liquid content and energized fluid return facilitated the use of foam in water sensitive formations. All of these benefits have made foam a common treatment fluid. Similarly, the benefits of mutual solvents are well known and well documented. In acidizing, these chemicals are used to reduce surface tension which improves acid penetration and promotes cleanup. Due to the "mutual solubility" of these materials, they are effective in penetrating and removing oily coatings on acid-soluble material. This provides for more complete acid spending, thus a more cost-effective job. The surface tension reduction properties of a mutual solvent also assist in removal of water blocks. Some mutual solvents are effective in reducing the possibility of forming an emulsion during acidizing. The use of mutual solvents is also advocated to aid in solubilization of other fluid additives and prevent their adsorption onto the formation. The exact mechanism and the extent to which any given mutual solvent performs any of these tasks is a subject of discussion and experimentation. However, their usefulness as a group is accepted, and depending on the exact application, one mutual solvent might be more suitable than another. A foamed acidizing system including a mutual solvent is not new, and foaming solvents have been in use for several years. P. 249^

Abstract A problem that has existed in oil well drilling operations is the successful placement of competent cement plugs at desired well depths. Repetitive attempts and failures in obtaining good cement plugs have cost many oil companies a considerable amount of capital both in extra rig time and service company expenses. This problem has recently been investigated with a unique 1/3 scale test model that allows visual observation of cement flow path and behavior of various well fluids during an actual job simulation. Test procedures and results are presented and discussed. Included in the results is a newly developed method which provides for successful plug jobs in severe well conditions. Field results of this method, which are also presented, confirm the results and demonstrate its value in field operations. Introduction Plugging oil wells is a common cementing operation practiced for a variety of reasons - for example (1) whipstocking, (2) abandonment, or (3) recompletion - but plugging operations can be unsuccessful. These failures are due primarily to migration of cement slurry downward through well fluid upon which it is placed (Fig. 1). Ideally, cement slurry should â??balanceâ?¿ on top of the well fluid until it develops sufficient gel strength to hold it in place. However, in many cases cement has a higher density than the fluid upon which it will be placed. As a result the higher density cement slurry may fall through well fluid due to the density difference driving force. Recent investigation of plug cementing techniques and materials has produced methods for placing competent cement plugs precisely in a downhole interval. These techniques rely on a reactive chemical fluid system which gels downhole, after leaving the drill pipe, to provide support for cement slurry until it develops adequate gel strength to counteract the density difference driving force. An examination of findings reported in this paper, including plug job case histories, will provide operators with methods of successfully placing cement plugs, even in severe well conditions. Background In oilfield cementing operations a number of different types of cement jobs are routinely performed. One of these types, a plug-back cement job, will be performed at least once in the lifetime of every well. Placement techniques commonly used are (1) balanced, (2) two-plug, and (3) dump bailer methods. 1 Balanced and two-plug methods are employed while trying to place a relatively large plug 100 to 200 ft long in an open hole some distance from the hole's bottom and without a mechanical or physical bridge. For the purpose of this paper, only these two methods will be considered. Suggested procedures for placing cement plugs have been presented in a number of publications and papers. 1–4 These papers cover laboratory testing, spacer and slurry design, placement techniques, and how long to wait before testing a plug. Placement techniques recommended for plugging are similar for casing and liner jobs, and include (1) mud conditioning, (2) use of spacers, (3) pipe movement, and (4) use of scratchers and centralizers. In addition to these factors, cement slurry volume is an especially important consideration. The volume of cement slurry used should be sufficient to offset the inevitable commingling of well fluids during slurry placement to minimize contamination effects.

Member SPE-AIME Abstract Squeeze cementing is, by historical definition, the application of differential pressure across a cement slurry to accomplish the process of cement dehydration. The primary purpose of the dehydration is to create immobility of the cement slurry until some compressive strength can be developed. Current cementing technology and additives have improved the process sufficiently that the term "squeeze" may no process sufficiently that the term "squeeze" may no longer be applicable. It is felt that "Remedial Cement Placement" may be more appropriate, and may more accurately define the process. The success of a remedial cementing operation depends on a finite definition of the existing problem and the results expected from the operation. If the purpose of the squeeze is not definable, a squeeze purpose of the squeeze is not definable, a squeeze job may not be necessary. Significant completion dollars are wasted annually on unnecessary squeezes, poorly designed squeeze slurries, and/or improper poorly designed squeeze slurries, and/or improper slurry placement. Many of the various applications of squeeze cementing may be classifiable as one purpose, i.e., repairing the primary cement sheath to purpose, i.e., repairing the primary cement sheath to isolate producing intervals and protect the casing string. Proper placement of a low-water loss cement slurry, at minimal surface pressure, into the casing-open hole annulus can satisfy most requirements of squeeze cementing. Initial breakdown pressures and pump-in rates prior to squeeze operations pressures and pump-in rates prior to squeeze operations should be conducted at less than Bottom Hole Fracturing Pressure, (surface pressure [or ISDP] + hydrostatic pressure = bottom hole frac pressure). This will insure the placement of the slurry into the annulus, not into the formation. High pressure squeezes are not required, and are in fact, discouraged. Placement of large volumes of cement slurries into Placement of large volumes of cement slurries into the formation via created fractures, natural fractures, vugs, or zones with worm holes seldom satisfies any squeeze performance criteria; including improvement of GOR, WOR, or isolating a zone for stimulation (block squeeze). If the initial breakdowm and pump-in test cannot be performed at subfracturing pressure, the cement sheath is competent and the squeeze operation is not required. Introduction The definition of squeeze cementing preferred by Shryock, et. al., is the process of forcing a cement slurry into a hole in the casing and cavities behind the casing. Squeeze cementing may be historically defined as the application of pressure across a cement slurry to accomplish the process of dehydration of the slurry to create immobility until some finite compressive strength can develop. Current technology and cement fluid loss additives for squeeze cementing have altered the concept of the procedure so that the term may no longer be applicable to the actual operation. Placement of the cement slurry into problem areas, Placement of the cement slurry into problem areas, i.e., primary cement channels, casing splits or corrosion holes, etc., is of much greater importance than dehydration of the slurry against the formation face, in the perforation tunnels, or in created fractures. The loss of large quantities of cement filtrate into the, rock matrix can cause excessive formation damage', and the creation of fractures, or filling of natural fractures with cement slurries can compound the damage problems due to the area of exposure to filtrate leak-off. The penetration distance of large volumes of cement slurries into naturally fractured formations can be significant, and can cause severe decreases in production. MISCONCEPTIONS OF SQUEEZE CEMENTING Many misconceptions concerning squeeze cementing and its effects on the formation persist. Early work on placement of a cement slurry into a formation fracture illustrated the creation of a horizontal fracture, or a horizontal "pancake" of cement. These "pancakes" would be of immense value for decreasing or stopping the production of bottom water (coning water) or coning gas. However, current fracturing technology illustrates that most fractures created are vertical, or near vertical, at most producing horizons. P. 233

Abstract Fracture acidizing of deeper Delaware Basin gas producing carbonate rocks, employs a number of techniques and acid formulations. A recently developed technique makes use of a stabilized foamed acid to achieve increased stimulation along with fast clean up. The quick recovery of treating fluids results in early stabilized flow permitting accurate testing and early gas sales. Deeper gas zones with abnormally low bottom-hole pressures present a special problem when acid fracturing. New replacement wells and new wells drilled in older producing reservoirs, such as those in the deep Gomez Ellenberger Field, encounter partially depleted pressure conditions. Conventional fracture acidizing requires extensive, costly jetting with nitrogen and coil tubing to remove treating fluids and 'kick off' the well. Foamed acid stimulation treatments have not required jetting to initiate gas production. Once acid in a stable foamed conditions gets into the created fracture it provides reduced leak off and reduced acid reaction rate with the soluble carbonate formation. This allows greater fracture penetration along with increased fracture conductivity throughout the fracture length. Adequate injection rates are possible, even with the reduced hydrostatic pressure of the foam column because of the low friction properties and reduced frac gradients in these reservoirs. A number of foamed acid stimulation treatments in carbonate formations are detailed along with tabulation of production increases. Introduction The stimulation of deep carbonate reservoirs is greatly affected by acid spending times and fluid leakoff rates. To achieve adequate stimulation, a deep penetrating fracture with high conductivity must be created. Abnormally low bottom-hole pressure conditions, relative to depth, present a special problem for the return of stimulation fluids. Foamed acid provides a new approach to reducing acid reaction rates with highly soluble carbonate rocks, along with achieving control of acid leakoff into existing hairline fractures. A great deal of energy, in the form of nitrogen gas, is induced into the reservoir to aid in the return of fluids to the well bore. A foamed flush fluid will greatly reduce the hydrostatic pressure of the fluid column in the tubing. Wells under these conditions will 'kick off' and flow, where otherwise they would not. Fracture Aciding with Foamed Acid The deeper gas zones with abnormally low bottom-hole pressures present a special problem when fracture acidizing. Fracture acidizing with conventional fluids requires jetting with coil tubing and nitrogen to remove treating fluids and 'kick off' the well. This involves a great deal of time and money. The evaluation of the well is delayed due to long cleanup time. Gas sales and subsequent revenues are delayed. If the rig is still on the well, costs are increased even more.

Abstract The purpose of this paper is to reevaluate the stimulation procedures used in the Morrow Sand formation of Southeast New Mexico, and to improve these techniques based on current and new information. This study considers the geological aspects of the Morrow Sand using the scanning electron microscope to investigate each Morrow rock type to determine rock properties and composition. The use of DST information is employed to establish pre-stimulation conditions involving transmissibility, BHP, damage ratio and productivity. A study of fracturing fluids is presented investigating adsorption, clay presented investigating adsorption, clay swelling, compatibility and regained permeabilities with various Morrow rock permeabilities with various Morrow rock types. Fracturing techniques are evaluated using reservoir, DST, log, and fluid data to compare sand placement with thin and viscous fluids, sand concentrations, fracture length, fracture length and stabilized production increases. production increases. Conclusions based on previous work and this study indicate fracture stimulation with viscous gels improves Morrow Sand production. Introduction Prior to the late 1960's, the only morrow production in Southeast New Mexico was from wells having sufficient permeability to be completed naturally. permeability to be completed naturally. Stimulation attempts during this period utilized oil-base fluids or saturated brines with little or no increase in production. The first successful production. The first successful stimulation treatments consisted of aqueous potassium chloride solutions gelled with potassium chloride solutions gelled with guar, buffered for low pH, and incorporated a surfactant for low surface tension. The proppant used in these treatments was 20–40 mesh sand and 20–40 mesh glass beads. In the early 1970's, use of a viscous crosslinked gel system and large sand concentrations proved successful for penetrating through wellbore damage. A typical treatment was 10,000 gallons of crosslinked guar carrying 18,000 pounds 20–40 mesh sand at 10 BPM. pounds 20–40 mesh sand at 10 BPM.

This paper was prepared for the Permian Basin Oil Recovery Conference of the Society of Petroleum Engineers of AIME, to be held in Midland, Tex., March 11–12, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication is the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication is the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Attempts to stimulate marginal gas producers in Sutton County, Texas, has provided an producers in Sutton County, Texas, has provided an opportunity to evaluate several types of stimulation fluids on a comparative basis. The fluids used here included water base, oil base, and acid base fluids. A thorough study of the production history of wells following treatment production history of wells following treatment demonstrates the effectiveness of the different fluids on a long term basis. Conclusions drawn from this study provide a guide to selection of fracture fluids for tight gas sands. Cost-performance factors are explored as they apply to stimulation of marginal gas production and further conclusions are drawn production and further conclusions are drawn concerning the importance of formation damage as a function of formation petrophysical properties. Examples are shown to indicate formation damage is a factor to consider in fracturing tight sands but performance compromises may be made in the choice of fluid to obtain maximum frac penetration. penetration Introduction Shortages of many chemicals used in well stimulation treatments has led to re-evaluation of many gas well treating techniques. Nowhere has this been more the case than in the Canyon play of Sutton County, Texas. A previous paper play of Sutton County, Texas. A previous paper (SPE 4678) describes the treating methods used in the initial development of the Sawyer Field. This study has been continued and cost effective fracturing has resulted. The results of the fracturing development may serve as a model for gas well stimulation in other areas with production from similar zones. production from similar zones. FORMATION The Canyon, a Pennsylvanian Age sand, is generally found at approximately 6500 feet and is produced to about 8200 feet. The zone is massive with many "ratty" sections. These sections are low in permeability (1 md) and porosity (8–12 per cent). When contacted by fresh water there is a noticeable clay migration. Acid response tests indicate migration damage accounts for about 35–40 per cent loss in permeability. Formation liquid saturation is low and any liquid entering the formation may cause further loss in relative permeability. Gas-oil ratios indicate an essentially dry gas formation.

The use of fresh water as a fracturing fluid in oil reservoirs became widespread in the Permian Basin in 1956,following its earlier introduction in the San Juan Basin. Although water was first used because of its economy, it soon became apparent that water often gave better production increases than oil-base fracturing fluids. Investigations showed that these improved results were caused by the action of fresh water in dissolving and removing salt from treated formations. Salt occurs in reservoir rocks as matrix material, pore-filling material, fracture-filling material and as fall-out or precipitate from crude oils or brines. The salt content of a core sample can be determined by petrographic study or by chemical tests. Examinations of thin sections of cores show not only how much halite [salt] is present, but also whether the halite is in the form of cementing material, individual crystals, or secondary deposition in pores, channels, or natural fractures. Fig. 1 is a photomicrograph [X300] of a halitic sandstone thin section from an upper Permian formation. Halite is the cementing material binding together chert and quartz grains. At the upper left hand corner, marked "C", is a chertgrain. The grains marked "Q" are quartz, and the black grains at upper right are magnetite or ilmenite. The arrows point to characteristic cubic openings in the halite. Others are between the arrows and below them. The opening at the right arrow contains a gas bubble. Although many more such openings are in the sample, they cannot be brought into focus at such high magnification. Fig. 2 is a photomicrograph [x69] of loose quartz sand grains from the same core sample after the cementing halite was removed. This is the effect that can be expected when fresh water is used in treating such a formation. The presence of halite as individual crystals in the formation is shown in Fig. 3, a photomicrograph [X300] in which both halite and quartz grains are prominent. It is apparent that halite grains may be as large as or larger than quartz grains. Dissolving and removing many such halite grains during a fracturing treatment using fresh water will substantially increase formation permeability.