A kinetic model for the reaction of Hydrochloric acid with limestone bas been determined. Reaction order and rate constant for this model were calculated from experiments where acid reacted with a single calcium carbonate plate. Experiments were performed so that acid flow past the plate and mass transfer rate to the rock surface could be calculated theoretically. The resulting model, therefore, accurately represents the acid reaction process at the rock surface and is independent of mass transfer rate. Combination of this model with existing theory allows prediction of acid reaction during acid fracturing operations. A model for acid reaction in wormholes created during matrix acidization treatments is presented along with data for reaction of hydrochloric, formic and acetic acids in a wormhole. Factors limiting stimulation in acid fracturing or matrix acidizing treatments are then discussed. Introduction To predict the stimulation ratio resulting from acid fracturing or matrix acidizing treatments it is necessary to know the rate of acid reaction under field conditions. In acid fracturing treatments, for example, reaction occurs as acid flows through a narrow fracture. Reaction in a matrix treatment occurs during flow through wormholes (channels of roughly circular cross-section) created by acid reaction. In both treatments, a large amount of mixing occurs during flow through the fracture or channel as a result of tortuosity and wall roughness. Reaction rate can be obtained from experiments, or predicted by theoretical calculations that accurately model field conditions. In general a theoretical procedure is preferred since it can be used without recourse to laboratory testing. Acid-reaction-rate data have been reported from a number of experiments intended to simulate acid reaction in field treatments. Tests most often used are:the static reaction rate test, in which a cube of limestone is contacted with unstirred acid at a known ratio of rock surface area to acid volume;flow experiments, where acid is forced to flow between parallel plates of limestone; anddynamic tests, whine limestone specimens are rotated through an agitated acid solution. In general, these tests model some aspects of the reaction process, such as area to volume ratio, or acid flow velocity, but do not accurately model all field conditions. To obtain an accurate mathematical model for field treatments, assuming fracture or wormhole geometry is known, it is necessary to characterize acid reaction kinetics at the limestone surface, rate of acid transfer to the surface, and rate of fluid loss from the fracture or wormhole. (Each of these processes is shown schematically in Fig. 1.) processes is shown schematically in Fig. 1.) Reaction kinetics are independent of the geometry in which reaction occurs; therefore, once kinetics have been determined for a given acid-rock system field treatments can be simulated by prediction of the rate of acid transfer to the surface and fluid loss to the formation. Unfortunately, experiments reported to dare do not allow determination of a kinetic model. SPEJ P. 406

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF 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 An evaluation of acid additives and retarded acid systems indicates that the stimulation resulting from acid fracturing can be increased when effective fluid loss additives used in HC1, or when the acid viscosity is increased significantly. Acid emulsions were found to have a low fluid loss rate and to be retarded, whereas oil wetting surfactants gave no retardation at typical field injection rates. Conductivity studies show that, in general, the fracture flow capacity resulting from acid reaction is very high, except when rock embedment strength and/or rock solubility is low, or the closure stress is high. Introduction In an acid fracturing treatment, either acid alone is injected into the formation at a high rate, or the acid is preceeded by a viscous fluid (the pad fluid) to form a long, wide fracture. When acid is used without a pad fluid, the fracture will generally be short and narrow since the rate of fluid loss for acid is high. If a viscous pad fluid is used, the long, wide fracture that is formed will begin to close as acid is injected, and will approach the geometry expected if acid alone had been used. This decrease in fracture volume occurs because the acid wormholes through the region invaded by the viscous fluid and thereby increases the rate of fluid loss. The stimulation obtained in an acid fracturing treatment is controlled by the length of the fracture that is effectively acidized, not by the induced fracture length. The distance reactive acid moves along the fracture (the acid penetration distance) is governed by the acid penetration distance) is governed by the acid flow rate along the fracture, the rate of acid transfer to the fracture wall, and the reaction rate at the rock surface. It has been shown that under most circumstances, the reaction rate between acid and rock is very fast, and that the rate of mass transfer to the rock face controls the overall acid reaction rate. A design procedure that combines the previously discussed fracturing aspects with previously discussed fracturing aspects with the reaction behavior of acid has been recently developed and compared with field treatment results. The design method considers the bounds on the acid penetration distance (the fluid loss limit and the reaction rate limit) shown in Fig. 1. The fluid loss limit is estimated assuming the benefits of the pad fluid are lost instantaneously through the formation of wormhole channels and is identical to the penetration calculated if no pad fluid is used. The reaction rate limit is the theoretical maximum acid penetration distance.

A model has been developed that accurately predicts acid penetration distance; it allows the effects of fracture geometry, acid injection rate, formation temperature, acid concentration, and rock type to be included in the treatment design. Results predicted by the model can be used in modifying acid treatments to maximize the stimulation ratio. Introduction Acid fracturing is a production stimulation technique that has been widely used by the oil industry. In such a treatment, acid or a fluid used in a pad ahead of the acid, is injected down the well casing or tubing at rates greater than the rate at which the fluid can flow into the reservoir matrix. This injection produces a buildup in wellbore pressure sufficient to overcome compressive earth stresses and the formation's tensile strength. Failure then occurs, forming a crack (fracture). Continued fluid injection increases the fracture's length and width. Acid injected into the fracture reacts with the formation to create a flow channel that remains open when the well is put back on production. To achieve reservoir stimulation, an acid fracturing treatment must produce a conductive flow channel long enough to alter the flow pattern in the reservoir from a radial pattern to one that approaches linear flow. McGuire and Sikora conducted an analog simulation of the productivity of a fractured well that serves as the basis productivity of a fractured well that serves as the basis for predicting the stimulation achievable with vertical fractures. Their study indicated that the variables that determine stimulation ratio are the ratio of fracture length to drainage radius, L/re, and the ratio of fracture conductivity to formation permeability, wkf/k. To design an acid fracture treatment, therefore, it is necessary to predict the fracture geometry during the treatment, the predict the fracture geometry during the treatment, the conductive fracture length, and the fracture conductivity created by acid reaction. A number of authors have studied various aspects of acid fracturing treatment design. Methods for predicting fracture geometry were first proposed by Howard and Fast. Techniques that give improved results have recently been presented by Keel and Geertsma and de Klerk. Although presented by Keel and Geertsma and de Klerk. Although these last two calculation procedures differ somewhat in formulation, the resulting geometry predictions are in agreement. Either procedure, therefore, can be used to predict the dynamic fracture geometry in acid fracturing predict the dynamic fracture geometry in acid fracturing treatments. Acid reaction characteristics have been studied in static reaction tests by several authors and design procedures using data from these tests were proposed procedures using data from these tests were proposed by Hendrickson et al. Use of the static test to design acid fracturing treatments is of marginal value since the test models only the ratio of fracture area to acid volume. An improved design procedure was presented by Barron et al., who studied acid reaction by flowing acid through a channel between limestone plates and derived a correlation to relate acid penetration distance along a fracture to treatment variables. The usefulness of the correlation is limited, however, since the experiments were run in a smoothwalled fracture, at room temperature, and with the fracture oriented in a horizonal plane. Smith et al. studied acid reaction at high temperatures in a reaction cell where reactive plates of limestone were rotated through acid and noted the effect of velocity on acid spending time and acid penetration. JPT P. 849

A procedure for predicting the stimulation ratio that will result from an acid fracturing treatment is presented. This procedure combines a theoretical model for acid reaction during flow along the fracture and experimentally determined rates of acid transfer to the fracture wall to predict the distance that reactive acid can move along the fracture. This distance, called the acid penetration distance, combined with the fracture conductivity allows the stimulation ratio to be predicted. Stimulation ratios predicted using this procedure are compared to results of acid fracturing treatments in limestone and dolomite formations. Included are treatments in Imperial's Boundary Lake and Quirk Creek fields. The predicted stimulation ratio is in general agreement with observed field results, thereby validating the procedure. Introduction ACID FRACTURING is a production stimulation technique that has been widely used by the oil industry. In an acid fracturing treatment, acid, or a fluid used in a pad prior to the acid, is injected down the well casing or tubing at rates greater than the fluid can flow into the reservoir matrix. This injection produces a buildup in wellbore pressure sufficient to overcome compressive earth stresses and the formation's tensile strength. Failure then occurs and a crack (fracture) is formed. Continued fluid injection increases the fracture's length and width. Acid injected into the fracture reacts with the formation to create a flow channel which remains open when the well is placed back on production. To achieve reservoir stimulation, an acid fracturing treatment must produce a conductive flow channel long enough to alter the flow pattern in the reservoir from a radial pattern to one which approaches linear flow. McGuire and Sikora(1) conducted an analog simulation of the productivity of a fractured well which serves as the basis for predicting the stimulation achievable with vertical fractures. Their study indicated that the variables which determine stimulation ratio are the ratio of fracture length to drainage radius, L/r and the ratio of fracture conductivity to formation permeability, wkr/k. To design an acid fracture treatment, therefore, it is necessary to predict the fracture geometry during the treatment, the fracture conductivity created by acid reaction and the conductive fracture length. A number of authors have studied various portions of the over-all problem of acid fracturing treatment design. Techniques for predicting fracture geometry were first proposed by Howard and Fast(2). Techniques which give improved results have been presented by Kiel(3) and Geertsma and deKlerk(4). Although the formulation of these last two calculation procedures is somewhat different, the resulting geometry predictions are in agreement. Either procedure can therefore be used to predict the dynamic fracture geometry in acid fracturing treatments. Broaddus and Knox(15,23) have carried out experiments to determine the conductivity resulting from acid reaction with different formations and have shown that conductivity is a function of formation type, acid concentration, and contact time between acid and rock. The conductivity which will result from an acid treatment, however, cannot be predicted with certainty.

Gidley, J.L., SPE-AIME, Exxon Co. U.S.A. Mutti, D.H., SPE-AIME, Exxon Co. U.S.A. Nierode, D.E., SPE-AIME, Exxon Production Research CO. Kehn, D.M., SPE-AIME, Exxon Production Research Co. Muecke, T.W., SPE-AIME, Exxon Production Research Co. The performance of several wells completed in tight gas sands that have been stimulated by massive hydraulic fracturing is compared with predicted performance. Results agree when the net sand thickness available in the performance. Results agree when the net sand thickness available in the wellbore of the fractured wells is reduced by a factor of 4. Sand discontinuity is used to explain this result. Introduction Even though gas has been produced in limited quantities from tight gas sands in the Rocky Mountain area for the last several decades. development of this area as a significant source of gas production has occurred only since the early 1970's. Efforts intensified with the growing awareness of the domestic energy shortage. The Federal Power Commission estimates that about 600 Tcf gas reserves can be found in this area. A National Gas Survey indicates that these reserves can be exploited. Interest in the area has revived. Recent increases in federally regulated interstate natural gas prices have provided an economic incentive for developing these provided an economic incentive for developing these reserves. Both nuclear stimulation and massive hydraulic fracturing (MHF) have been suggested as methods for producing this latent gas. Fig. 1 shows the geographical producing this latent gas. Fig. 1 shows the geographical locations of several tests of both methods and also identifies the principal geologic basins of interest. This paper does not deal with the results of nuclear stimulation experiments because these results are covered elsewhere. Applications for that technology are now dormant. Rather, we examine the results of several MHF treatments in the area to see how the production rate from fractured wells compares with predicted performance. The size and calculated geometry of the fracture and known reservoir properties of the sands are used for these comparisons. With a few noteworthy exceptions, the MHF results for the Mesaverde and Fort Union sands (the major gas sands in the Rocky Mountain area) have been largely disappointing. Although the problem originally was attributed to certain deficiencies problem originally was attributed to certain deficiencies in the hydraulic fracturing technique, it now appears that this response is inherent in the nature of the formations. This study was not limited to Exxon Co. U.S.A. wells alone, since our involvement in the Rocky Mountain area has been minimal. We also looked at the performance of other operator's wells. For the latter wells, most data were obtained from trade journals, publications of the federal government (since most of the wells are on federal leases), local newspaper articles, or other sources. Some of these companies have not been contacted directly regarding the data used on their wells or this analysis of well performance. Other companies are mentioned in this paper performance. Other companies are mentioned in this paper for well identification only, and no concurrence on their part is implied with the conclusions drawn. part is implied with the conclusions drawn. Type of Treatments Examined The term massive hydraulic fracturing used here refers simply to very large fracturing treatments, generally an order of magnitude larger than conventional fracturing procedures. Typically, an MHF involves more than procedures. Typically, an MHF involves more than 100,000 gal fracturing fluid and more than 200,000 lb sand. JPT P. 525