Knowledge of in-situ stress distribution within reservoir sandstones and the surrounding formations is recognized as one of the most important factors in the design and analysis of hydraulic fractures. Stress contrast between various layers of rock ultimately controls the vertical fracture growth and, thus, directly affects fracture length and width. Even though the importance of stress distribution is evident, these data are rarely measured due to the associated expense, interpretation problems and mechanical risks.
Currently, there are log analysis techniques available which can provide calculated values for mechanical properties and in-situ stresses. These techniques are based on classic theories of elastic stress-strain relationships and appear to be reliable in tectonically relaxed areas. In geologically active areas, however, external horizontal stresses may be present which cannot be calculated by these static techniques. In such formations, empirical field corrections must be included to accurately determine the in-situ stresses.
This paper summarizes the results from a study where actual field-measured values of in-situ stress have been compared to log-derived values. The study was conducted on wells completed in the Travis Peak (Hosston) formation of east Texas. A discussion of the regional geology is presented which describes how fluvial-deltaic depositional patterns and local facies variations control patterns and local facies variations control sandstone geometry and distribution of possible fracture barriers.
In-situ stresses within sandstones, siltstones and shales were actually measured on three wells. Empirical corrections to the log-derived values were necessary in order to fit the measured data. The resulting correlations between log-derived values of stress and field-measured values of stress should be of benefit to the industry. The ultimate goal for all concerned with the problem is to learn how to reliably evaluate stress distribution from logs for fracture treatment design purposes. purposes
For several years, research has been conducted which is directed at reducing the cost of producing gas from low permeability reservoirs. Large volumes of gas-in-place are contained in tight reservoirs, but current technology is not adequate to allow development of these formations. The Gas Research Institute (GRI) manages a program that is specifically targeted at increasing gas reserves by improving the technology used in developing tight reservoirs.
The primary goal of GRI's research in tight gas reservoirs is fracture technology enhancement. A better understanding of the hydraulic fracturing process is the most important key to improving process is the most important key to improving recovery efficiency. If the petroleum industry can substantially improve its ability to control fracture growth, chances of achieving the designed propped fracture length are increased, thereby propped fracture length are increased, thereby improving the economic incentive for developing tight gas reservoirs.
The ultimate objective of the GRI Tight Gas Sands Research Program is to learn how to analyze a fracture treatment in real-time (i.e., while the treatment is being pumped) and to predict the shape of the hydraulic fracture. However, it is first necessary to improve our understanding of both the reservoirs that are being fracture treated and the rock layers surrounding the main, productive interval.