Publications

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The objective of the autonomous micro-explosive subsurface tracing system is to image the location and geometry of hydraulically induced fractures in subsurface petroleum reservoirs. This system is based on the insertion of a swarm of autonomous micro-explosive packages during the fracturing process, with subsequent triggering of the energetic material to create an array of micro-seismic sources that can be detected and analyzed using existing seismic receiver arrays and analysis software. The project included investigations of energetic mixtures, triggering systems, package size and shape, and seismic output. Given the current absence of any technology capable of such high resolution mapping of subsurface structures, this technology has the potential for major impact on petroleum industry, which spends approximately $1 billion dollar per year on hydraulic fracturing operations in the United States alone.

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The recent development of downhole tiltmeter arrays for monitoring hydraulic fractures has provided new information on fracture growth and geometry. These downhole arrays offer the significant advantages of being close to the fracture (large signal) and being unaffected by the free surface. As with surface tiltmeter data, analysis of these measurements requires the inversion of a crack or dislocation model. To supplement the dislocation models of Davis [1983], Okada [1992] and others, this work has extended several elastic crack solutions to provide tilt calculations. The solutions include constant-pressure 2D, penny-shaped, and 3D-elliptic cracks and a 2D-variable-pressure crack. Equations are developed for an arbitrary inclined fracture in an infinite elastic space. Effects of fracture height, fracture length, fracture dip, fracture azimuth, fracture width and monitoring distance on the tilt distribution are given, as well as comparisons with the dislocation model. The results show that the tilt measurements are very sensitive to the fracture dimensions, but also that it is difficult to separate the competing effects of the various parameters.

Six hydraulic-fracture injections into a fluvial sandstone at a depth of 4300 ft were monitored with multi-level tri-axial seismic receivers in two wells and an inclinometer array in one well, resulting in maps of the growth and final geometry of each fracture injection. These diagnostic images show the progression of height and length growth with fluid volume, rate and viscosity. Complexities associated with shut downs and high treatment pressures can be observed. Validation of the seismic geometry was made with the inclinometers and diagnostic procedures in an intersecting well. Fracture information related to deformation, such as fracture closure pressure, residual widths, and final prop distribution, were obtained from the inclinometer data.

A series of hydraulic-fracture experiments using a downhole tiltmeter array, called an inclinometer array, was conducted at the Department of Energy (DOE)/Gas Research Institute (GRI) Multi-Site facility in Colorado. The inclinometer array was used to measure the deformation of the reservoir rock in response to hydraulic fracture opening and confirm microseismically measured results. In addition, the inclinometer array was found to be a useful tool for accurately measuring closure stress, measuring residual widths of both propped and unpropped fractures, estimating proppant distribution, and evaluating values of in situ moduli.

Austin chalk core has been tested to determine the effective law for deformation of the matrix material and the stress-sensitive conductivity of the natural fractures. For deformation behavior, two samples provided data on the variations of the poroelastic parameter, {alpha}, for Austin chalk, giving values around 0.4. The effective-stress-law behavior of a Saratoga limestone sample was also measured for the purpose of obtaining a comparison with a somewhat more porous carbonate rock. {alpha} for this rock was found to be near 0.9. The low {alpha} for the Austin chalk suggests that stresses in the reservoir, or around the wellbore, will not change much with changes in pore pressure, as the contribution of the fluid pressure is small. Three natural fractures from the Austin chalk were tested, but two of the fractures were very tight and probably do not contribute much to production. The third sample was highly conductive and showed some stress sensitivity with a factor of three reduction in conductivity over a net stress increase of 3000 psi. Natural fractures also showed a propensity for permanent damage when net stressed exceeded about 3000 psi. This damage was irreversible and significantly affected conductivity. {alpha} was difficult to determine and most tests were inconclusive, although the results from one sample suggested that {alpha} was near unity.

This study is a comparison of hydraulic fracture models run using test data from the GRI Staged Field Experiment No. 3. Models compared include 2D, pseudo-3D, and 3D codes, run on up to eight different cases. Documented in this comparison are the differences in length, height, width, pressure, and efficiency. The purpose of this study is to provide the completions engineer with a practical comparison of the available models so that rational decisions can be made as to which model is optimal for a given application.

This paper evaluates the correlation between values of minimum principal in situ stress derived from two different models which use data obtained from triaxial core tests and coefficient for earth at rest correlations. Both models use triaxial laboratory tests with different confining pressures. The first method uses a vcrified fit to the Mohr failure envelope as a function of average rock grain size, which was obtained from detailed microscopic analyses. The second method uses the Mohr-Coulomb failure criterion. Both approaches give an angle in internal friction which is used to calculate the coefficient for earth at rest which gives the minimum principal in situ stress. The minimum principal in situ stress is then compared to actual field mini-frac test data which accurately determine the minimum principal in situ stress and are used to verify the accuracy of the correlations. The cores and the mini-frac stress test were obtained from two wells, the Gas Research Institute`s (GRIs) Staged Field Experiment (SFE) no. 1 well through the Travis Peak Formation in the East Texas Basin, and the Department of Energy`s (DOE`s) Multiwell Experiment (MWX) wells located west-southwest of the town of Rifle, Colorado, near the Rulison gas field. Results from this study indicates that the calculated minimum principal in situ stress values obtained by utilizing the rock failure envelope as a function of average rock grain size correlation are in better agreement with the measured stress values (from mini-frac tests) than those obtained utilizing Mohr-Coulomb failure criterion.

Rock mechanisms parameters such as the in situ stresses, elastic properties, failure characteristics, and poro-elastic response are important to most completion and stimulation operations. Perforating, hydraulic fracturing, wellbore stability, and sand production are examples of technology that are largely controlled by the rock mechanics of the process. While much research has been performed in these areas, there has been insufficient application that research by industry. In addition, there are new research needs that must be addressed for technology advancement.

Gas conductivities of narrow natural fractures in sandstone and chalk were measured under varying stress and pore pressure conditions and showed a decrease in conductivity with increasing net stress. Natural fractures in mudstones exhibited continuously decreasing conductivity upon application of stress, so that correlatable conductivity data could not be obtained. Effective-stress-law behavior for the sandstone and chalk fractures were examined, giving α values in the range of 0.8-1.06, where α is the parameter in the effective-stress law, σ - αP. The value of α for the fracture in chalk was nearly constant, but the values for the fracture in sandstone tended to decrease with increasing stress. Transition Reynold's numbers and turbulence factors for flow through the chalk and sandstone fractures were determined, yielding turbulence factors ranging from 6.0-20×106 ft-1 (2.0-6.6×10-5 cm-1) for differently stressed fractures. The entire flow behavior of these natural fractures, including conductivity, effective-stress law, and turbulence, is controlled by stress and pore pressure. As a result, pressure depletion during production will significantly change the productivity of a reservoir with similar natural fractures.

A hydraulic fracture stimulation conducted during 1983-1984 in non-marine, deltaic, Mesaverde strata at a depth of 7100 ft (2164 m) was cored in a deviated well in 1990. The observed fracture consists of two fracture intervals, both containing multiple fracture strands (30 and 8, respectively). While the core had separated across many of the fracture strands during coring, the rock remained intact across 20 of the strands, preserving materials within the fractures. Nine of the remaining intact strands were split open, revealing abundant gel residue on the surfaces of every fracture examined. Of 7 strands associated with major bedding planes, 4 displayed offsets of 1-3 mm at the planes and 3 strands had their growth terminated at the planes, showing the importance of bedding (petrophysical heterogeneities) on fracture propagation. Implications of all these findings for hydraulic fracture design and analysis are also addressed.

There are tremendous resources of natural gas in tight fissured rocks, but these formations require special care for hydraulic fracturing to be successful. Serious problems include leakoff, damage and complex fracturing. Leakoff may be constant, pressure-sensitive, or accelerating. Leakoff becomes most severe when fissures begin to dilate and accept large volumes of fracture fluid, which may rapidly dehydrate a sandladen slurry. Determining values of pressure-sensitive and accelerated leakoff coefficients is difficult, and generally requires both a pressure-decline analysis (after a minifrac) and an analysis of the injection pressure. Fine-mesh sand, often used in fissured reservoirs, will help control leakoff. Damage to the natural fractures, due to leakoff of the fluid and gels and to mechanical types of damage, must be avoided, since the fissures are the production mechanism. It is particularly important to minimize the amount of liquid and gels, since the fissures are narrow and easily blocked. These concepts are also applicable to oil reservoirs.

A computer code for calculating hydraulic fracture height and width in a stressed-layer medium has been modified for easy use on a personal computer. HSTRESS allows for up to 51 layers having different thicknesses, stresses and fracture toughnesses. The code can calculate fracture height versus pressure or pressure versus fracture height, depending on the design model in which the data will be used. At any pressure/height, a width profile is calculated and an equivalent width factor and flow resistance factor are determined. This program is written in FORTRAN. Graphics use PLOT88 software by Plotworks, Inc., but the graphics software must be obtained by the user because of licensing restrictions. A version without graphics can also be run. This code is available through the National Energy Software Center (NESC), operated by Argonne National Laboratory. 14 refs., 21 figs.

A computer code for analyzing four-gage Anelastic Strain Recovery (ASR) data has been modified for use on a personal computer. This code fits the viscoelastic model of Warpinski and Teufel to measured ASR data, calculates the stress orientation directly, and computes stress magnitudes if sufficient input data are available. The code also calculates the stress orientation using strain-rosette equations, and its calculates stress magnitudes using Blanton's approach, assuming sufficient input data are available. The program is written in FORTRAN, compiled with Ryan-McFarland Version 2.4. Graphics use PLOT88 software by Plotworks, Inc., but the graphics software must be obtained by the user because of licensing restrictions. A version without graphics can also be run. This code is available through the National Energy Software Center (NESC), operated by Argonne National Laboratory. 5 refs., 3 figs.