Abstract A measurable improvement in productivity can be achieved using xanthan gelled acid to stimulate carbonate formations. Well productivity results were compared to conventional acid fracture treatments. The significant improvements over classical acid fracturing techniques are due to the improved control of acid leakoff rates, retarded reaction rate and improved fracture width maintenance. The difficulties involved in acid fracturing massive Middle East carbonate formations are discussed and solutions are proposed using gelled acid technology. Some limitations in computer predictions of acid fracturing results are also discussed. predictions of acid fracturing results are also discussed Introduction In order to stimulate the production of oil or gas wells, it is necessary to penetrate the drainage area with a fracture that will allow a relatively unrestricted flow of fluids to the wellbore. McGuire and Sikora described the interrelationship between fracture conductivity and penetration in obtaining productivity increases. For the maximum response productivity increases. For the maximum response from stimulation, it is necessary to optimize both the effective fracture penetration and the flow capacity or conductivity. In fracture acidizing, the primary limiting factors for obtaining a maximum penetration of live acid are the inefficiency of acid as a fracturing fluid and its intrinsic rapid rate of reaction. A viable approach to effectively controlling these factors is to develop viscosity in the acid. Numerous polymers, such as guar gum, gum Karaya and polysaccharides, have polymers, such as guar gum, gum Karaya and polysaccharides, have been used to thicken acids in the past. The benefits derived from these gelled acids were limited by the instability of the polymers in acid at treating temperatures. The introduction polymers in acid at treating temperatures. The introduction of xanthan polymer as a thickening agent for acid was a recent innovation. This polymer, combined with other essential proprietary ingredients, can produce a thickened acid with relatively long-term temperature stability. Acid gelled with this formulation will hereafter be referred to as xanthan gelled acid. During the past three years, the xanthan gelled acid has been used to stimulate numerous carbonate formations with success. The unique characteristics of the xanthan gelled acid have provided improved results from treatments of low-permeability provided improved results from treatments of low-permeability carbonates. These characteristics should also prove useful in treating more permeable carbonates, such as those common to the Middle East. CHARACTERISTICS Acid thickened with the xanthan polymer formulation at a concentration of 60 lb/1,000 gal (7,190 g/m3) of 15% HCl, has a viscosity of 41.8 cp (0.0418 Pa sec) at 170 sec-1 and 50C. In contrast, ungelled 15% HCl has a viscosity of 1.5 cp (0.0015 Pa sec) at the same temperature. The viscosity of the xanthan Pa sec) at the same temperature. The viscosity of the xanthan gelled acid is compared to ungelled acids at various temperatures in Figure 1. By increasing the viscosity of the acid, fluid efficiency is improved and reaction rate is reduced. In order to obtain the maximum benefit from a gelled acid, the viscosity must be stable under downhole conditions for the duration of the treatment. The xanthan gelled acid is relatively stable at temperatures up to 105C. At temperatures below 40C, there is virtually no degradation of viscosity with time (Figure 2). At a treating temperature of 70C, Figure 2 shows that there is some reduction in viscosity over a one-hour period. However, the viscosity stability is also affected by the degree of acid spending. Under acid fracturing conditions, the time that the polymer will be required to survive degradation in 15% HCl is polymer will be required to survive degradation in 15% HCl is limited. p. 499

Abstract The productivity of many old producing wells can be increased by the use of a properly designed stimulation treatment. The majority of these wells, both pumping and nonpumping, are fractured. Partial pumping and nonpumping, are fractured. Partial healing of the hydraulic fracture may occur as pressure declines in the reservoir. In addition, other common forms of formation damage occur with time. An accurate evaluation of the existing conditions in the well is required for proper design of the stimulation treatment. In this paper, an attempt has been made to utilize production data and pressure transient test data simultaneously to evaluate the existing condition of the well. The use of published type-curve techniques for unfractured, fractured and decline curve analyses has been emphasized to eliminate ambiguities and to arrive at a reliable conclusion. Both conventional pressure data and liquid-level measurement data have pressure data and liquid-level measurement data have been used in this study. A two-dimensional simulator has also been used to aid stimulation treatment design and performance evaluation. Introduction An increase in production from existing wells in developed reservoirs is often possible by the use of a properly designed stimulation treatment. Although the properly designed stimulation treatment. Although the production from older wells is relatively small in production from older wells is relatively small in comparison with the newly drilled infill wells, their vast number as a group holds potential to make significant contribution toward increasing the national daily production. However, these wells are usually associated with more than a single, well-defined problem Success in increasing production from these problem Success in increasing production from these wells depends largely on properly defining the major problem associated with them. problem associated with them. The productivity of a stimulated well is viewed not only from its production rate but also indirectly includes the duration through which the increased rate would be maintained. The concern here is obviously to justify the additional cost of the stimulation treatment. Regardless, whether a well is new or old, it can be stated in a very general way that its productivity depends on two groups of factors —formation characteristics, and drilling, completion and stimulation practices followed. The individual factors under the "formation characteristic group" include porosity, permeability, average reservoir pressure, net formation thickness, oil saturation, reservoir fluid properties, well spacing or areal extent of lease or reservoir. It is obvious that for all practical purposes these factors are uncontrollable. The factors under the "drilling, completion and stimulation group" are controllable. Although the very process of drilling or completing a well is damaging A nature to the producing formation, adequate care and design considerations can reduce the adverse effects and improve the results of the stimulation treatment. Quantitatively, the combined influence of drilling, completion and stimulation on the rate of production is expressed by the van Everdingen and Hurst skin factor. The value of the skin factor is obtained from transient pressure or rate tests and can be used in designing and evaluating the stimulation treatment. Therefore, it is very important to conduct appropriate tests before and after a stimulation treatment for an effective design and evaluation. This approach, on a field-wide basis, reduces the number of available options A stimulation design and thus improves the chances of success of forthcoming treatments. The term "stimulation" in this paper refers to hydraulic fracturing in a low-permeability formation unless mentioned otherwise. P. 101

Summary This paper focuses on prevention of well completion damage through proper choice of working fluids, pressure balance, and lost circulation material. Field pressure balance, and lost circulation material. Field applications are described, and damage prevention is advocated wherever possible. Extensive references are provided for those seeking greater detail on low-density provided for those seeking greater detail on low-density fluids, clear fluids, and nondamaging lost circulation material. Introduction Completion fluids are being considered more widely both for their impact on well productivity and for their efficiency in accomplishing a defined objective in a well. The importance of the growing awareness of this should not be understated, since the ultimate measure of the petroleum industry's success is its ability to maximize petroleum industry's success is its ability to maximize productivity and total recovery economically. productivity and total recovery economically. In the widest sense, any fluid that contacts or enters a productive zone during a well job is a completion productive zone during a well job is a completion fluid. Hence, completion fluids include those used in such well activities as pay zone drilling and/or under- reaming, perforating, gravel packing, chemical treatments, hydraulic fracturing, cleanout, well killing, zone selective operations, and tubing and hardware replacement. Some often conflicting considerations involved in selecting a completion fluid for a particular job are listed in Table 1. A completion fluid is a compromise--a practical balance between safety, efficiency, cost, and practical balance between safety, efficiency, cost, and minimum adverse impact on productivity. No one fluid system is universally optimal. The purpose of this paper is to summarize state-of-the- art considerations relating to selection and use of completion fluids, with the objective of maximizing productivity. productivity. Completion Damage Items listed under Completion Damage in Table 1 are major concerns when a completion fluid is chosen. The significance of completion damage has been documented by many field and research studies in the past decade. The potential reward for avoiding past decade. The potential reward for avoiding completion damage is illustrated in Fig. 1. This example shows a nearly 100-fold productivity loss resulting from completion damage sustained during attempts to remedy in-well mechanical problems. That the problem was a completion problem, rather than a reservoir problem, is shown by the result of a redrill, where use of a nondamaging completion fluid returned the well to its natural decline. Defining potential completion damage problems and selecting fluids to avoid such problems generally is done through laboratory testing. Fig. 2 shows a typical apparatus capable of simulating flow of several fluids past, into, and/or out of the wellbore/formation interface. The accuracy of results from such testing depends on the use of representative, nondamaged core material. It may be necessary to perform this kind of flow test on location in the field, where there is no question that the fluids are representative of those to be used in subsequent actual well work. Avoiding Completion Damage The overriding trend in recent efforts toward improved completion fluid systems and operating procedures is to minimize the potential for foreign solids and adversely reactive liquids being introduced into productive formations. Three basic techniques are used. Underbalanced Operation Where safety and job objectives permit use of underbalanced fluid systems, they completely avoid the problem of formation invasion. problem of formation invasion. JPT P. 47

Abstract Generally speaking, organizations monitor the effectiveness of performance through semi-annual or annual reviews. This article presents an argument in favour of day-to-day feedback both for improving productivity as well as motivating staff. Such interactions have been shown to be superior to the appraisal interview approach in that they provide a more effective, meaningful and informative approach to the interview itself. By providing the complete and prompt feedback, selling goals and personally rewarding good work, the manager assists subordinates in identifying expectations as well as the ways to accomplish the goals and obtain the rewards. Successful achievement of goals requires interest, ability and aptitude on the part of the manager on an on-going as well as on an annual basis. Introduction The author has been involved over the past ten years in a program of research examining characteristics of effective performance review interviews. Most large organizations have personnel policies requiring managers to appraise job performance and contributions of their staff on semi-annual or annual bases. Such interviews are difficult to conduct. Most firms have mixed success in achieving a constructive dialogue between manager and staff, and both appraiser and appraiser enter the interview with trepidation. The author's research, and that of others, has identified characteristics of effective performance review interviews (Burke, Weitzel & Weir, 1980; Lathan & Wexler, 1981). These studies indicate that particular activities enacted during the interview by supervisors (and subordinates) are more likely to be associated with a mutually helpful interaction. These activities can be acquired through skill development sessions (Kellogg, 1967). However, con- sideration of the semi-annual or annual performance review interview which ignores the day-to-day interactions between supervisor and staff is of limited effectiveness. In fact, managers can have greater impact on their staff's performance and contributions through their daily interactions with their staff. In addition, these daily interactions will result in a more effective and easier way to conduct annual appraisal interviews. Some Examples Of the Problem Fred Emery, a distinguished colleague from Australia, described some projects in which he was involved. Over the past decade, Australian citizens have developed a preference for purchasing goods made elsewhere rather than those made domestically. One reason for this was their belief that Australian products were of poorer quality. In addition, the quality of services provided by nurses, salesclerks and government officials were seen as deteriorating during the same time period. All of this was aggravated by England's decision to join the European Common Market, of which Australia was not a member. This weakened Commonwealth ties, did away with preferential treatment for Commonwealth members and increased competitive pressures on Australia. These factors made goods and services less competitive, arousing concern both in government and in the manufacturing and production sectors. Several research projects were carried out to help understand this situation and offer recommendations. · In one, a team of social scientists undertook a study of a large number of employees at all levels from a wide range of occupations and organizations.

Abstract The paper presents a case history study of Exxon's high volume artificial lift program at Talco Field in Franklin and Titus Counties, Texas. The field, discovered in 1936, produces heavy crude oil from the Paluxy Sandstone at an approximate depth of 4200 feet. All wells required artificial lift installation soon after the field was discovered due to rapid salt water breakthrough. Primary recovery efficiency is expected to be only about 35 percent of the original oil in place, attributed to reservoir heterogeneity and the adverse water-oil mobility ratio. Through installation of high volume artificial lift equipment, current data indicate that significant additional recovery benefits may be realized. The paper details the practical experience Exxon has gained since the first high volume electric submersible pump was installed at Talco in 1974. Included are screening parameters used to optimize the selection of particular high volume artificial lift equipment. Also included are representative production flowstreams to quantify the additional recovery expected of typical electric submersible pump and large capacity beam pumping unit pump and large capacity beam pumping unit installations. An analysis of the incremental expenses and costs associated with electric submersible pumps and large capacity beam pumping units is presented. Also discussed are case production histories and operational problems encountered with actual installations. Introduction Exxon has increased ultimate recovery from the Talco Field through installation of high volume pumping equipment (HVPE). Increased fluid withdrawal has improved sweep efficiency, thus reducing the adverse effects of Talco's reservoir heterogeneity and high water-oil mobility ratio. Wells converted from conventional lift equipment to large capacity beam pumping units (LCBPU's) have averaged an initial buildup of 35 barrels of oil per day (BOPD) and approximately 84 thousand barrels of increased oil recovery per installation. Electric submersible pump (ESP) installations have averaged an initial buildup of 87 BOPD and an expected recovery increase of 114 thousand barrels of oil (MBO) per installation. Exxon chose LCBPU's and ESP's over other types of HVPE because of their simpler design and operation and also their lower investment and lifting costs. HVCE greatly increases salt water production, utility costs, and well servicing; therefore, operating costs must be considered when evaluating HVPE installations. Accurate design, proper installation, and continual monitoring of HVPE proper installation, and continual monitoring of HVPE minimizes operating problems and costs. At Talco Exxon generally uses LCBPVs for wells with desired producing rates within the unit's range (700 – 900 producing rates within the unit's range (700 – 900 barrels of fluid per day maximum). For wells capable of higher fluid rates, ESP's are used. TALCO FIELD Location and Development Talco Field is located in Franklin and Titus Counties, Texas (Figure 1). The field trends 13 miles East to West and is 1 – 2 miles across at its widest point.

INTRODUCTION This paper presents the basic principles which must be followed to create a truly inherently safe mining system. The need to relate the support mechanism to be employed to the ground reaction curve and basic rock mechanics principles will be pointed out. The support system must function in concert with the deformations that are inherent in the selected mining system. Following the support selection, the mechanics for installing support must be developed. This is best done through a cooperative effort between mine engineers, mine operators, safety personnel, equipment suppliers, and government inspectors, both state and federal. Accident statistics, near miss statistics, review of equipment used by others, geologic features, etc. will necessarily have to be studied. The goal of equipment development and selection should be to develop inherent safety by removing the miner from the hazard area or by providing absolute protection for the miner if he must work in close proximity to the potential fall of ground. The role of good productivity in reducing the numbers of men exposed to hazards is emphasized as a good safety measure. ROCK MECHANICS PRINCIPLES A thorough understanding of the ground reaction curve surrounding openings to be created is essential in the process of designing ground control methods. See figure 1. It is first necessary to investigate the geologic conditions at the site as this is the one thing that cannot be changed. Secondly, the deformation associated with the presently mined openings should be measured and plotted on time deformation plots. It may also be necessary to measure absolute stress conditions to determine whether or not regional tectonics play a role in ground stability. Third, based on the above investigations, the best shape of opening should be decided upon. The shape being predicated upon location and orientation of geolooic flaws, the effects of loading, time dependent creep of the opening and the shape necessary to allow mining equipment to operate. Lastly, with the above information, the mining system can best be designed. The orientation and span of openings, pillar sizes and shapes can be determined. The major goal in the design process will be to produce a stable opening which uses no artificial support. A field example of this is the use of the boring machines in potash or trona which cut an ovaloidal opening and often can be mined without use of roof fixtures. In the same formation, if conventional ripper miners are used to cut rectangular openings with sharp corners, which produce stress concentrations, roof fixtures are often necessary to keep the openings safe. The first support used in a mine opening should be installed quickly as the face advances and may be temporary in nature. If interior rock supports are to be used, the host rock must have sufficient strength so that the fixture placed can reinforce the media. The simplest form of quick support may be mechanical roof bolts, Friction Rock Stabilizers, resin or cemented rebars. Figure 2 is a table showing the commonly available fixtures.

Abstract This paper discusses the principle of plunger lift and its possible applications. Typical applications are:Removal of Liquids from Gas Wells Hi-Ratio Oil Well Production Paraffin and Hydrate Control Increased Efficiency of Intermittent Gas Lift Wells Some advantages of this system are low initial cost, very little maintenance and that there is no external source of energy required in most cases. Limitations such as mechanical conditions, gas and liquid volumes and depths are also discussed. There will be a brief section concerning the various types of equipment available. Introduction The principle of the plunger is basically the use of a free piston acting as a mechanical interface between the formation gas and the produced liquids, greatly increasing the well's lifting efficiency. The successful operation of these systems is predicated on the assumption that the wells have no packer or have communication between the tubing and the casing at the bottom of the production string. The purpose of this paper is to describe the applications of this system to certain production problems. production problems. A typical installation consists of a stop and spring set at the bottom of the tubing string and a lubricator and catcher on the surface acting as a shock absorber at the upper end of the plunger's travel. The plunger runs the full length of the tubing between the stop and lubricator. The system is completed with the addition of a controller (time and/or pressure) and motor valve with the ability to open or close the flowline pressure) and motor valve with the ability to open or close the flowline (see Fig. 1). Operation of the system is initiated by closing in the flowline and allowing formation gas to accumulate in the casing annulus through natural separation. The annulus acts primarily as a reservoir for storage of this gas. After pressure builds up in the casing to a certain value, the flowline is opened. The rapid transfer of gas from the casing to the tubing in addition to gas from the formation creates a high instantaneous velocity that causes a pressure drop across the plunger and the liquid. The plunger then moves upward with all of the liquids in the tubing above it. Without this mechanical interface, only a portion of the liquids would have been recovered. APPLICATION Removal of Liquids from Gas Wells Almost all gas wells at some time during their flowing life are subject to producing liquids. As long as the conditions are such that wells are able to sustain a sufficient velocity in the tubing, liquids are carried out with the gas as multiphase flow. Below a certain "critical velocity," liquids tend to migrate down the tubing and start to collect at the bottom. Turner, et al, shows that this critical velocity is a function of flowing well head pressure, type of liquid (water, condensate, etc.) temperature and conduit size (see Fig. 2). For a while the well is able to unload the small slugs on its own. The surface indications are "heading" recorded on the sales chart. If no remedial measures are taken, the problem will worsen until the well loads up and dies. Other indications of liquid loading problems are sharply decreasing production decline curves for both gas and liquids. Any well that must be production decline curves for both gas and liquids. Any well that must be "blown down" periodically is most certainly experiencing liquid loading.

Member SPE-AIME Abstract The Steinle Ranch Field was initially developed in the mid-1970's. Wells were drilled, cased, perforated, and treated by chemical injection with lease-crude or condensate carriers to restore oil saturation to the formation, which is suspected to be hydrophobic. Stimulation by hydraulic fracturing of four wells was attempted from 1975 through 1977 with mixed results and no particular success. These treatments used sand and glass beads for proppant. A fifth hydraulic fracture treatment, in which sintered bauxite was used as the proppant was very successful. As a result, all wells in the field have been fractured. This program, in a mature field in late stages of depletion, at intermediate depth (10,600 ft.), has been very successful; approximately 940,000 barrels of additional reserves have resulted for a total cost of approximately $2,000,000, a return on investment of 9.4:1. Comparing these reserves to estimated reserves if the wells had been propped with sand shows a 23:1 return by the incremental reserves on the incremental cost of the bauxite. Introduction The Steinle Ranch Unit of Converse County, Wyoming, consists of 19 wells completed in the Muddy Formation. The field was initially produced with the Steinle Ranch Unit No. 1 which was completed August 30, 1973. Most of the wells were drilled in 1974 and 1975 although development continued through 1978. The field is operated by the Inexco Oil Company. Top of the pay interval ranges from 10,452 feet to 10,704 feet of depth. The producing intervals are thin, with 5 to 11 feet of net pay in 7 to 14 feet of gross pay. All wells were completed initially by casing and perforating. Initial flow rates from the first wells were in the range of 680 to 810 barrels of oil per day. Porosity is in the range of 9% to 14% and the permeability is between 10 and 20 millidarcies, Core permeability is between 10 and 20 millidarcies, Core and log analysis indicated original interstitial water saturation between 15% and 20% and flood pot tests indicated a residual oil saturation of 53% to 54%. These two results indicated a hydrophobic reservoir rock. Early treatments with water-base fluids, emulsions, and acids were all unsuccessful and confirmed the sensitivity of the formation to contact with water. Several wells were treated successfully with condensate or lease crude containing surfactants injected at low rates and pressures to restore oil permeability near the wellbore after invasion by permeability near the wellbore after invasion by waterbase fluids used in drilling and completion activities. These treatments increased production significantly in several wells by removing damage but were not stimulation treatments. Production rates declined rapidly; as is typical of thin reservoirs in general and Muddy reservoirs in particular. A means of stimulating production was desired. On initial completion, the Steinle Ranch Unit No. 25 well failed to respond to a chemical injection treatment and would not produce at commercial rates. An attempt to stimulate production with a fracture treatment with a small amount of a gelled-water-base emulsion containing proppant sand was also unsuccessful. Then, on April 11, 1975 the SRU 25 well was fracture-treated with 45,000 gallons of gelled oil containing 31,000 lbs of proppant: 12,000 lbs of 100-mesh sand, 14,850 lbs of 20/40 mesh sand, and 4,150 lbs of 12/20 mesh glass beads. After this treatment, the well produced 132 bopd and was placed on production. Cumulative production from the well is 128,816 barrels. After the success of this first treatment, the SRU No. 3 well was treated with a similar treatment. Results of this treatment were disheartening, however, as production was reduced from 108 bopd to 48 bopd, quickly declined, and the well was shut-in. After approximately six months of shut-in, this well was put back on production and continued to produce at put back on production and continued to produce at low rates. It was re-treated on March 21, 1981, without any appreciable change of productivity, positive or negative. positive or negative.

Abstract Soon after start-up of the Prudhoe Bay Field in mid-1977, a number of wells with abnormal productivity decline were recognized. Research into the problem was undertaken as a coordinated effort of the Prudhoe Bay Unit Owners involving engineering, laboratory and geological studies concurrent with an extensive field work program. Investigations over the past three year have defined a major damage mechanism and efforts are continuing toward solutions for effective long-term production capacity maintenance. production capacity maintenance Introduction The Prudhoe Bay Field is located approximately 250 miles north of the Arctic Circle on Alaska's North Slope on the edge of the Beaufort Sea. Discovered in 1968, it is the largest oilfield in North America with an estimated ultimate recovery of 9.6 billion barrels. The field is unitized, owned by 16 working interest owners. Due to its size, it is divided into two operating areas, with Sohio Alaska Petroleum Company in the west and ARCO Alaska, Inc. in the east acting as operators for the Unit. Production from the field began in June, 1977, after construction of the Trans Alaska Pipeline connecting Prudhoe Bay with the ice free Port of Valdez, 800 miles to the south. Six major production facilities process the oil for transfer to the pipeline and process the oil for transfer to the pipeline and separated gas is currently being reinjected into the gas cap. Present field offtake is approximately 1.5 million BOPD. A well damage problem was first recognized as production history became available in 1978, about six production history became available in 1978, about six months after start-up. A number of wells exhibited capacity decline much greater than the anticipated 10-20 percent per annum. In order to investigate the problem on a field-wide basis and pool the resources of problem on a field-wide basis and pool the resources of the Working Interest Owners, a study group was formed with representatives of the three major owners: Sohio, ARCO and Exxon. A preliminary engineering study generated a comprehensive data base of individual well drilling, completion and production histories which a, used to categorize each well. Few wells could be classed as initially damaged, that is damaged by certain drilling or completion techniques, thereby resulting in lower than expected capacities. Customarily it should be possible to identify this group by high residual damage possible to identify this group by high residual damage ratio. Due to the complexity of pressure build-up interpretation at Prudhoe Bay, and uncertainity in these values, the selection was made using expected initial capacities from porosity-permeability correlations in conjunction with residual damage ratios. Of the wells with high production decline rates, two groups became evident. Group I consisted of seventeen wells where decline was directly attributable to invasion of the formation by calcium chloride brine. This had occurred either after initial perforation of the well or during a later workover. The high decline of wells in Group II could not be attributed to calcium chloride and they became known as the "unknown cause damage" group. Thirty-six wells were included in this category in September, 1978, making a total of fifty three high decline wells. During the past three years, this high decline problem has been investigated through field and problem has been investigated through field and laboratory work and geological study coordinated by the Well Damage Study Group. Although calcium chloride was recognized as damaging and its use discontinued in 1979 an effective remedial treatment was required for affected wells. A potentially serious problem still existed with older wells completed using calcium chloride where it remained as the inner annulus packer fluid. Several hypotheses were postulated for the unknown cause mechanism. This has received the most attention, affecting the larger number of wells, with additional wells joining the group as they came on stream and their production characteristics became known. PRUDHOE BAY RESERVOIR PRUDHOE BAY RESERVOIR The producing reservoir at Prudhoe Bay is the Sadlerochit formation named for the Sadlerochit Mountains where the formation outcrops to the southeast of the field.

Abstract If properly designed and implemented, acid stimulation treatments provide a method for improving the productivity of oil and gas wells. The success of these treatments depends to a great extent upon proper acid selection and good treatment design. This can be accomplished only with a good understanding of the fundamental principles of acid stimulation. This paper reviews these important principles and includes descriptions of the basic concepts of damage removal, reservoir stimulation, acid reaction mechanisms, job design and diversion technology. Example field case histories are included to illustrate the benefits that can be derived from properly administered acid treatments. Introduction Productivity improvement is the process of increasing production from oil or gas wells by removing flow restrictions that exist near the wellbore and/or by altering the pattern of flow towards the wellbore. Basically, there are two causes of impaired productivity which can be improved by acid treatments. First, near-wellbore formation damage can cause a well to produce at a rate lower than the true reservoir flow capacity. This type of problem can be remedied by a matrix acidizing treatment. The second cause of low productivity is poor reservoir permeability. productivity is poor reservoir permeability. This limitation can be diminished through the use of a different acid stimulation technique known as acid fracturing. The distinction between matrix acidizing and acid fracturing is an important one. Matrix acidizing treatments are performed by injecting appropriate acids into the near-wellbore region of the formation at rates low enough to avoid fracturing, thus allowing the fluids to permeate the rock matrix. Such treatments are performed with HF-HCl acid in sandstone reservoirs and HCl acid in carbonate reservoirs. Fracturing, on the other hand, is the practice of generating a large crack within the practice of generating a large crack within the formation that extends perhaps one hundred meters from the wellbore. By altering the reservoir flow pattern toward the well, a fracturing treatment pattern toward the well, a fracturing treatment can improve the flow rate of an undamaged well. Thus, the principal application of fracturing is to stimulate low permeability reservoirs, although additional benefit can be realized by removing near-wellbore damage that might be present. The final result from both damage removal and fracture stimulation treatments depends on the successful injection of the treating fluids into the zone(s) where they are needed. Accordingly, a review of modern fluid diversion techniques has been included to demonstrate the amount of well productivity improvement which can be realized productivity improvement which can be realized when acid treatments are successfully injected into all zones. Finally, several field case histories are included to point out the benefits that can be derived from properly designed and implemented treatments. FORMATION DAMAGE REMOVAL Description of Formation Damage Formation damage refers to a region of reduced permeability that can exist near the wellbore and which usually extends less than one meter into the reservoir. This damaged region occurs when formation pore spaces become blocked by mineral deposits (such as clay particles) or organic deposits (such as asphalt). In this paper, discussion will be restricted to mineral paper, discussion will be restricted to mineral damage which can be removed by a properly designed acid treatment. Sandstone formations are composed of a framework of quartz and feldspar grains with varying amounts of clay, silica fines and carbonates lining the pore spaces.