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Abstract This paper demonstrates our methodology and capabilities for effective on-site real-time analysis, re-design and execution of hydraulic fracturing treatments. This unique technology has been developed over many years of research and development, sponsored primarily by the Gas Research Institute (GRI). Ten years of field implementation in the stimulation of gas- and oilwell production have led to conclusions and recommendations which involve major changes from conventional concepts about hydraulic fracturing. Most of our recommendations are relatively simple, low-cost procedures for adequate data collection, such as the use of flow-rate changes and/or multiple injection/shut-in cycles for stringent model evaluation of recorded data. Proper implementation of our recommendations is demonstrated by a case study in a commercial field situation, where the fracture treatment was drastically redesigned as a result of on-site analysis, and executed on the same day. This job showed that treatment cost/benefit optimization can be achieved by careful on-site analysis and more flexible field execution schedules. Introduction Many man-years have been invested in theoretical and laboratory investigations of hydraulic fracturing, as well as in R and D and commercial field efforts aimed toward advancing the technology. These efforts have led to a number of conclusions and recommendations, and they have also produced a unique technology (i.e., the Gas Research Institute fracture simulator, a true 3-D, real-data, real-time hydraulic-fracture simulator for design and analysis) that has made significant benefits and cost savings possible for many users on both oil and gas applications, even without on-site implementation. R and D efforts have included the analysis of many fracturing jobs, including those pumped as part of experimental investigations, and also many "routine" commercial fracture treatments. Our conclusions from such data analysis have included: shorter, wider fractures than those predicted by other simulators, which do not consistently match measured pressures; frequent occurrence of a significant level of near-wellbore friction, due to near-wellbore fracture tortuosity, which must be subtracted from measured (downhole) pressure data for correct interpretation; relative insensitivity of fracture width to frac-fluid rheology; and dangerously fast convection (versus settlement) of proppant in imperfectly-contained fractures. We have recommended that many of the existing approaches to fracture design and execution be reconsidered. We have also demonstrated, with numerous case studies, that a higher degree of treatment optimization can be achieved by more careful on-site analysis; our approach is to arrive at the optimum fracture-treatment design by making use of flexible field operations, and real-time, real-data analyses of suitably-designed tests with an appropriate engineering-oriented software package, incorporating at least a realistic reservoir/fracture simulator interfaced to data-acquisition. Our normal requirement is to match measured net fracture pressure (on-site, real-time), on carefully designed minifracs with the GRI simulator, then continuously redesign the main frac as needed, e.g. to achieve pack-off, understanding that details may change as larger injection volumes experience new reservoir conditions. The purpose of this paper is to provide a simple description and a unique case study illustrating our approach to on-site fracture redesign, and to document some primary conclusions and recommendations (App. 1), as well as benefits and cost-savings (App. 2) which our GRI/industry co-operative efforts have generated. P. 725^

Abstract Over 300 matrix and fracture acidizing treatments, utilizing a thermally stable acid gelling agent, were performed in carbonate formations, worldwide. The initial results of several treatments were presented earlier (Ref. 1). Since then, trends toward sustained increases in production have been documented and are presented. Reductions in production decline rates have resulted in improved recovery of reserves. Improved live acid penetration results from the effects of stable viscosity, retarded reaction rate and proper treatment design. In addition, the gelling agent must be non-damaging, requiring tolerance to calcium and magnesium ions in the spent acid during cleanup. A gelling agent is described that provides the features of thermal stability and solubility in the live and spent acid. Introduction Commercial utilization of hydrochloric acid for stimulating oil and gas production from carbonate reservoirs began in the early 1930's. The beauty of using acid in treating carbonates lies in it's utter simplicity. Injected at matrix rates, significant amounts of new permeability are generated, thus removing the effects of formation damage near the wellbore. Under fracturing conditions, substantial fracture conductivity is created through the dissolution of the fracture face. This apparent simplicity, however, belies a complexity of interrelated and interdependent factors that determine the success of it's application. During the past fifty six years, much of the technological developments in acidizing have focused on the understanding of the processes limiting treatment results, and on methods and materials that could be used to overcome these limitations. In particular, recent years have seen the development of viscosifiers for acid, which are intended to impart characteristics that, if present, would enhance treatment results by increasing live acid penetration. Many of these materials have been used with only limited success, due to their inherent instability in live or spent acid, or incompatibility with common additives and contaminants. In 1983, a polymer was introduced, which provides the desired characteristics of stable viscosity, acid retardation and compatibility with most of the common acid additives. It has since been successfully applied in more than 300 matrix and fracture acidizing treatments. This paper provides a description of this gelling agent and details of several case histories. Discussion A synthetic polymer has been developed for use as a viscosifying agent for hydrochloric acid, tested under extremes of field conditions and found to be successful in enhancing the results of carbonate acidizing treatments. This material (Polymer A) was originally developed as a thermally stable viscosifier for brine solutions containing calcium and magnesium ions. It's composition is designed to resist thermal degradation and hydrolysis at high temperatures. Early in it's development, it was recognized that Polymer A also resisted acid hydrolysis and could be effectively employed as an acid gelling agent. Polymer A is readily soluble in hydrochloric acid, and develops viscosity rapidly. Figure 1 illustrates the relationship between the polymer concentration and fluid viscosity. As would be expected, the relationship is non-linear, with viscosity increasing rapidly at the higher polymer concentrations. Polymer A is effective in all commonly used hydrochloric acid systems, and the viscosity is independent of acid concentration. It's resistance to thermal degradation and acid hydrolysis provides stable viscosity and continued solubility at elevated temperatures. P. 259^