Summary Stress testing (micro-hydraulic fracturing) is recognized by the petroleum industry as the most direct method of determining the minimum in situ (closure) stress for a given reservoir rock and the surrounding formations. In general, it is variations of in situ stress between formations that dominates hydraulic fracture height growth and overall fracture geometry. Misleading interpretations of stress test data (cased or open hole) can lead to significant errors m the prediction of stress contrast between the producing and bounding rock layers as well as an erroneous estimation of closure stress in the productive interval. In either case, hydraulic fracture treatment designs based on this information may not be designed optimally and the subsequent interpretation of the fracturing treatment pressure response may not be correct. This paper presents an evolutionary approach in the analysis of stress test data which leads to more consistent results that relate directly to actual fracture treatment pressure responses. Although the emphasis in this paper is on cased hole stress test data interpretation, the methodology presented is also applicable to open hole stress testing and larger scale pump-in/shut-in (i.e. calibration or minifrac) pressure falloff responses. Introduction The interpretation of stress test data is generally considered the basis by which other stress interpretation techniques and pressure analysis methods are compared and/or calibrated. Unfortunately, the interpretation of stress data does not appear to be as straight forward as initially perceived. Many of the same phenomena observed during large scale pump-in/shut-in and pump-in/flow-back treatments (i.e. minifracs or calibration treatments) as discussed by Nolte also complicate the analysis of stress test data. Some of these phenomena include:continued fracture tip extension;pressure dependant leakoff; andadjacent barrier effects. Other effects which tend to complicate analyses include:near-wellbore closure;multiple fractures; andnear-wellbore pressure drop (i.e. tortuosity). Generally, a simplistic approach to analyzing stress test data (especially in cased hole) is pursued without regard to any of the previously mentioned phenomena. Ironically, these phenomena may have a larger impact on the interpretation of stress test data than on "minifrac" data. Standard modern well test pressure transient analysis techniques are the most commonly used methods for analyzing pressure falloff data from stress tests.

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Completion Optimization Through Advanced Stimulation Technology and Reservoir Analysis: A Case Study in the Red Fork Formation, Okeene Field, Major County, Oklahoma J.D. Harkrider, SPE, M.L. Middlebrook, SPE, C.H. Huffman, SPE, W.W. Aud, SPE, Integrated Petroleum Technologies, Inc.; G.A. Teer, SPE, Lomak Petroleum, Inc.; and J.T. Hansen, SPE, Gas Research Institute Abstract This paper illustrates the use of advanced stimulation technologies coupled with reservoir analysis to improve gas production from a low permeability formation. Modern stimulation techniques used include real-time treatment data analysis, stress profiling, three dimensional fracture modeling and fluid quality control procedures. Implementation of these technologies was based on an evaluation of previous and current completion and stimulation approaches in the study area. A statistical review was performed to characterize the reservoir and establish a baseline from which to compare results and quantify benefits of the completion optimization process. Part of the project was performed under the Gas Research Institute Advanced Stimulation Technology Deployment Program. Through the use of modern completion and stimulation practices, the operator was able to nearly double the average initial production rate in the Red Fork formation from 300 Mscf/d to over 600 Mscf/d. Ten year reserve estimates have increased about 38% from 390 MMscf to over 540 MMscf. Acceleration of reserves has allowed the operator to produce in less than 5 years the same amount of gas that was previously recovered in 13 years. The combination of improved reserve recovery and accelerated production has increased the discounted cashflow about 43%. Introduction This project, from the beginning to the end, attempted to integrate the complete package of engineering practices to optimize costs and results. A multi-phase program was outlined and included an initial phase of evaluating previous completion and stimulation approaches in the area. The following technologies and techniques were implemented in baselining previous results:–Integration of practical and theoretical considerations to evaluate prior completions.–Advanced 3-D fracture modeling of breakdown and fracture treatment pressure responses.–Reservoir simulation of production and pressure responses.–Iteration between fracture treatment and production response on all wells to achieve consistency of overall interpretation.–Establishment of a production response baseline from offset well history. Once the baseline analysis was completed, field deployment was implemented and included a continued evaluation and evolution of approaches. This phase employed the following technologies and techniques:–Intense surface and in-situ fluid and equipment quality control before and during each fracture treatment.–Advanced real-time evaluation of the treating pressure response on all treatments.–On-site, real-time integration of fluid and equipment quality control with pre-treatment diagnostics and main fracture treatment execution.–Pre-treatment diagnostics to identify closure pressure of the Red Fork and adjacent layers, observe the leakoff response of various fluids and determine the quality and complexity of the near-wellbore and far-field fracture geometry.–Real-time execution of fracture treatments to optimize near-wellbore and far-field proppant placement/conductivity.–A coupled approach to acquire both post-treatment pressure decline data, which yields a better understanding of the fracture treatment, and rapid flowback to enhance fracture conductivity and minimize formation damage. The final phase of the project was a cost benefit analysis. This comparative analysis of wells using modern completion practices to the offset production baseline quantified the benefits of optimization. The following were used in this phase of the project:–Comparison of long-term production response on new wells to previous wells. P. 357^

The Gas Research Institute (GRI) initiated a data acquisition and analysis project in 1990 with the goal of evaluating the applicability of horizontal well completions In various gas-productive reservoirs. One of the target gas reservoirs in this study was the Mancos B interval of the Mancos Shale located in the Southwest Rangely Field in northwest Colorado. The overall objectives of the project were to determine reservoir characteristics from a vertical well, model the reservoir, design an appropriate horizontal well completion and compare the production economics of the horizontal well to the economics of the standard vertical well completion.Data were initially acquired from a vertical well completion in the Mancos B to evaluate the extent and strike of natural fractures, insitu stress magnitude and direction, log-derived reservoir characteristics, pre-and post-frac production rates and hydraulic fracture dimensions. A horizontal well was subsequently designed to intersect the interpreted primary set of natural fractures in the Mancos B. The horizontal well was air-drilled and intersected approximately 1,500 ft of the Mancos B "main porosity zone."Borehole image log data indicated that no significant natural fractures were intersected by the horizontal wellbore. A 4-1/2-in. liner was cemented in the well to facilitate hydraulic fracturing after only minimal gas was produced from the open-hole during a 3-week production test. Reservoir modeling and economic forecasting Indicated that 2 hydraulic fracture treatments over the 1 ,500-ft interval would be the most economical. Two fracture treatments were attempted but both resulted in screenouts during the early sand stages. The early screenouts were believed to be directly related to the higher than normal in-situ stresses that were observed during breakdowns and injection tests. Due to the limited vertical extent of natural References and illustrations at end of paper.fractures and the lack of vertical permeability, horizontal well completions in this area of the Mancos B reservoir do not appear to be a viable completion alternative to hydraulically fractured vertical wells.

This paper presents the basic methodology for real-time evaluation and execution of hydraulic fracture treatments and attempts to address some of the current perspectives about the subject. It is important to realize that only a small part of real-time hydraulic fracturing is model specific. The brunt of this technology is encompassed in the techniques used to optimize the diagnostics and actual execution of the fracture treatment. A precise methodology for performing real-time evaluation and execution of hydraulic fracture treatments is discussed. Recommendations are provided to specifically tailor the design of the pre-treatment diagnostic injections to the wellbore geometry, reservoir, and fracturing characteristics. From these diagnostic injections stages, critical fracturing mechanisms such as perforation friction, near-well bore tortuosity, leakoff, fracture geometry, multiple fracturing, closure stress, pipe friction, etc. can be determined. The important consideration is that the engineer be trained to take a methodical approach to ensure the diagnostics acquire the desired information. Too often today, diagnostic injections are executed without any consideration for wellbore or formation characteristics and are consequently, in many cases, ineffective. Once these diagnostic injections are evaluated, the treatment is re-designed based upon the actual fracturing character of the formation. It is virtually impossible to predict how a reservoir will hydraulically fracture without first pumping into the interval. Real-time evaluation and execution reaches the pinnacle of technological use during the actual pumping of the fracture treatment. A variety of modern techniques exist to continue the characterization of the fluid and fracture to minimize risk of premature screenouts and optimize the proppant distribution within the fracture. Introduction Real-time hydraulic fracturing was first introduced in 1986 and has been successfully established through many successful case histories. In general, real-time evaluation and execution involves the collection and interpretation of hydraulic fracture treatment data while the treatment is in progress. Through a series of pre-treatment diagnostic injections and co-treatment execution techniques, the fracturing character of the rock is diagnosed and subsequently addressed allowing the treatment to be optimized. The overall approach is interactive, with the engineer determining the diagnostic design, data analysis technique, fracture model and evaluation criteria. Since the beginning of this modem technological evolution, many technical papers have specifically discussed various real-time data acquisition and analysis methods. New methods for determining fracture closure pressure in both the pay interval and adjacent layers have been developed. Several papers have been presented for characterizing the near-wellbore fracture geometry components and addressing them during the fracture treatment. History matching of the actual pressure response allows tangible determination of the fracture geometry and leakoff response so the treatment can be re-designed quickly based on the actual fracturing character of the rock. Recently, the recognition of multiple far-field fracture propagation has resulted in the development of predictive models and methods for remediating and addressing these complex fracture geometries. Aside from the actual mechanistic aspects previously mentioned, probably the most fascinating part of real-time execution is the integration of all data that allows every variable, either raw or calculated, to be tracked, in real-time, without processing delay. The fracture treatment response can be represented on any graph type, scale and/or with any variable. This allows a level of scrutiny of what is occurring during a job that has never before been available. The "catch 22" is that specific training, expertise and experience are necessary to achieve full benefit using this modern technology because of the fast moving process that occurs during the execution of any fracture treatment. The fracture entry character of a fluid type or proppant concentration can be observed with high resolution graphics early in the treatment, providing information on how the rock is fracturing. Associated improvements can be made to remediate pre-mature screenouts and optimize proppant distribution. P. 117^