Application of Fracture Design Based on Pressure Analysis

Abstract

Summary. This paper describes case studies of fracturing pressure analysis for the Wattenberg field of the Denver basin and the Cotton Valley sand of east Texas. The studies show the benefits of pressure analysis and controlled pressure designs for fracture treatments. In addition, procedures for measuring fracturing pressures and considerations for the procedures for measuring fracturing pressures and considerations for the successful execution of minimal viscosity treatments are presented. Introduction In 1978, Amoco initiated a coordinated program of data collection and analysis to improve the understanding of the mechanics of the hydraulic fracturing process. A series of papers presented results from this program. These papers dealt with fracture height determination, fracture confinement by in-situ stresses, application of fracture azimuth measurements, and the interpretation of fracturing pressures during and after a treatment. In 1981, another group of papers was presented related to massive hydraulic fracturing (MHF) in the Cotton Valley in east Texas and the Mesaverde in southwestern Wyoming, and the design of precise-length treatments for a pilot flood in the Salt Creek field of precise-length treatments for a pilot flood in the Salt Creek field of Wyoming. Many of these papers were based on the use of the pressure response during and after fracturing to interpret the fracturing pressure response during and after fracturing to interpret the fracturing process and to change the design of subsequent treatments or a process and to change the design of subsequent treatments or a treatment in progress. A companion to this paper reviews the basis for interpreting and predicting fracturing pressures, outlines a fracturing-pressure simulator (FRAC), and describes the effect of height growth on pressures and fracture propagation. The companion paper concludes pressures and fracture propagation. The companion paper concludes that the analysis of fracturing pressures is analogous to the analysis of reservoir pressures; the interpretation and prediction of pressure during and after a treatment provides the basis for rational changes in subsequent treatments; the initial fracture height primarily determines fracturing pressure and penetration; the formation has a pressure capacity that, if exceeded, leads to inefficient fracturing; the pressure capacity that, if exceeded, leads to inefficient fracturing; the formation capacity should be determined early in a fracturing program to ensure realistic expectations and efficient results; the most program to ensure realistic expectations and efficient results; the most effective means of limiting the pressure in the fracture is by controlling the fluid viscosity to minimal levels. These conclusions were based on the Perkins and Kern geometry model for fractures in the horizontal plane with horizontal lengths exceeding the vertical height. This model will also be applied in this paper. The validity of this model was supported by two field experiments in which fracture widths and pressures were measured. Conditions for which this model may not be applicable are discussed in Ref. 10. The basic interpretive tool for pressures during fracturing is a log-log plot of net pressure vs. time or, equivalently, vs. injected volume. This plot and its interpretations are shown schematically in Fig. 1 with additional discussion in Refs. 5 and 10. Fig. 1 indicates the pressure capacity of the formation, Pfc' and the constant net pressure response (Type 2 slope) that characterizes the pressure capacity. The net pressure is defined as the excess fluid pressure in the fracture above the closure pressure. The closure pressure is equal to the in-situ horizontal rock stress acting to close the fracture. Considerations and procedures for measuring the fracturing pressures and closure pressure are given in Appendix A. pressures and closure pressure are given in Appendix A. Fig. 2 illustrates an example of the interpretive plot for a large treatment in the Wattenberg tight-gas field. As discussed in more detail later, this plot was interpreted to indicate essentially restricted height growth throughout the treatment with accelerated fluid loss to the opening of natural fissures (i.e., fractures) at the formation's pressure capacity of 1,700 psi [11.7 MPa] between 150 minutes pressure capacity of 1,700 psi [11.7 MPa] between 150 minutes and shut-in at 250 minutes. The subsequent decline after shut-in is also shown. Additionally, the figure indicates the pressures simulated by the FRAC program. The restricted height growth for this example has not been found to be the general case for large treatments of other formations. More typical is the example shown in Fig. 3, in which significant height growth-i.e., in excess of 450 ft [137 m]-was inferred from the simulation shown. This example is from a tight-gas field in the Cotton Valley formation of east Texas. For this case, the formation's pressure capacity is governed by height growth and is approximately 1,400 psi [9.7 MPa], which was reached after 200 minutes of the treatment. Fig. 3 also shows the calibrated profile for horizontal stresses that govern the height growth and the inferred relationship between net pressure, height, and stiffness. This relationship was used with the FRAC pressure, height, and stiffness. This relationship was used with the FRAC simulator to predict tie net pressures shown during the treatment. Because of the importance of fracture height in the design of treatments and the failure of postfracturing surveys (e.g., temperature logs) to indicate the total height if significant height growth occurs, a discussion of these surveys is given in Appendix B. These two examples, which will be expanded upon in this paper, illustrate that the formation's pressure capacity can differ in both magnitude and cause. Although these introductory examples are for large treatments of tight-gas sands, the same principles can be used for other applications-e.g, very small treatments in an oil reservoir. Considerations for Minimal-Viscosity Treatments The fluid pressure during fracturing governs the fracture geometry and potentially the efficiency of a treatment. The most realistic means of controlling the pressure is by using fluids with the minimal viscosity required to transport proppant and to control fluid loss effectively. Although minimal viscosity is obviously desirable for reducing pressure below the formation capacity, the use of minimal viscosity magnifies other aspects of a successful treatment relative to the use of excessive viscosity. The initial application of minimal-viscosity designs led to mixed results. The subsequent treatments for the examples in Figs. 2 and 3 were successfully executed with significant decreases in cost, but minimal-viscosity treatments in other fields experienced a high rate of premature screenouts. After the guidelines in Appendix C were applied, however, a very high rate of successful treatments resulted. For example, in the Wamsutter area of southern Wyoming, premature screenouts were averaging about 30%, but after these guidelines were instituted in early 1981, only one of 27 treatments prematurely screened out during the remainder of the year. The guidelines and considerations included in Appendix C are fluid viscosity; fluid loss; fluid degradation as a result of injection rates, perforation practices, and use of viscosity breakers; and proppant selection and scheduling. An example is given that uses the proppant selection and scheduling. An example is given that uses the guidelines and FRAC simulator. SPEPE P. 31