Colleen A. Barton

Fluid flow along potentially active faults in crystalline rock

The relationship between in-situ stress and fluid flow in fractured and faulted rock is examined by using data from detailed analyses of stress orientation and magnitude, fracture geometry, and precision temperature logs that indicate localized fluid flow. Data obtained from three boreholes that penetrate highly fractured and faulted crystalline rocks indicate that potentially active faults appear to be the most important hydraulic conduits in situ. The data indicate that the permeability of critically stressed faults is much higher than that of faults that are not optimally oriented for failure in the current stress field.

Self‐similar distribution and properties of macroscopic fractures at depth in crystalline rock in the Cajon Pass Scientific Drill Hole

This study was conducted in order to characterize the frequency, orientation, and aperture of macroscopic fractures in the crust and their effect on physical properties over an appreciable depth interval (1829–3450 m). The following are our major findings: (1) Over the range of apparent apertures measured with confidence, the frequency of fractures with a given aperture decreases as aperture increases. With applied corrections for sampling bias, the observed distribution of fracture aperture has a power law form providing evidence of the self-similar nature of fractures in the crystalline crust. Fractal analysis of the fracture aperture data yields a fractal dimension of 1.4 over the range of reliable aperture measurements in this study from 15 to 100 mm. (2) Fracture frequency does not systematically decrease with depth in the study interval. (3) No significant correlation was found between fracture occurrence and lithology, and both fracture spacing and aperture are uncorrelated with fracture orientation or depth. (4) The majority of fractures encountered in the well strike NNW-SSE and dip steeply to the west. One set of steeply dipping fractures appears to be related to the NW striking San Andreas fault and appears to be related to steeply dipping, NW striking shear fractures observed in nearby outcrops that are characterized by laumontitic alteration. (5) The fractures bear no obvious relation to the current northeast direction of maximum horizontal compression but do correlate with anomalies in physical properties measurements of compressional and shear velocity, porosity, and resistivity. (6) Macroscopic fractures strike in a direction nearly orthogonal to the fast propagation direction of seismic wave anisotropy determined from vertical seismic profiling experiments in the well. These fractures appear to be unrelated to the observed seismic anisotropy. (7) Hydraulically conductive fractures and major faults indicate that fluid-conducting fractures are a subset of the overall statistically significant population and not related to the San Andreas fault or to the orientation of SHmax in an obvious way.

Stress perturbations associated with active faults penetrated by boreholes: Possible evidence for near‐complete stress drop and a new technique for stress magnitude measurement

Detailed studies of stress-induced wellbore breakouts in wells drilled through active faults reveal stress field discontinuities that are apparently associated with recent fault movements. These discontinuities are expressed as localized rotations in wellbore breakout orientation in the vicinity of the fault penetrated by the borehole. This phenomenon is observed in a variety of tectonic environments and rock types. Utilizing cases where relatively complete knowledge of the horizontal principal stresses is available from in situ measurements, we use three-dimensional dislocation modeling to demonstrate that these discontinuities can be explained as the superposition of a reference stress state and a perturbation caused by movement on preexisting faults. Case studies from normal, strike-slip and reverse faulting stress states indicate that nearly complete stress drop is required to match the observed breakout orientation anomalies. Hydraulic fracturing data independently confirm the occurrence of near-complete stress drop on some faults penetrated by drilling. Modeling of the observed interactions between breakouts and fractures can also be used to obtain information about the magnitude of in situ stress.

Relationships among in-situ stress, fractures and faults, and fluid flow; Monterey Formation, Santa Maria Basin, California

We used borehole televiewer (BHTV) data from four wells within the onshore and offshore Santa Maria basin, California, to investigate the relationships among fracture distribution, orientation, and variation with depth and in-situ stress. Our analysis of stress-induced well-bore breakouts shows a uniform northeast maximum horizontal stress (SH max) orientation in each well. This direction is consistent with the SH max direction determined from well-bore breakouts in other wells in this region, the northwest trend of active fold axes, and kinematic inversion of nearby earthquake focal plane mechanisms. In contrast to the uniformity of the stress field, fracture orientation, dip, and frequency vary considerably from well to well and within each well. With depth, fractures can be divided into distinct subsets on the basis of fracture frequency and orientation, which correlate with changes of lithology and physical properties. Although factors such as tectonic history, diagenesis, and structural variations obviously have influenced fracture distribution, integration of the in-situ stress and fracture data sets indicates that many of the fractures, faults, and bedding planes are active, small-scale strike-slip and reverse faults in the current northeast-trending transpressive stress field. In fact, we observed local breakout rotations in the wells, providing kinematic evidence for recent shear motion along fracture ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received April 15, 1996; revised manuscript received December 27, 1996; final acceptance July 15, 1997. 2Department of Geophysics, Stanford University, Stanford, California 94305-2215. We wish to thank Tom Zalan of the Chevron U.S.A. Production Company for providing the offshore well data, Unocal Corporation for providing the data on the onshore well, and Marcia McLaren from Pacific Gas and Electric Company for providing the earthquake focal mechanisms used in the stress inversion analysis. The data used as background seismicity in Figure 1 were extracted from the World Wide Web of the Southern California Seismic Network (SCSN) catalog operated jointly by the Seismological Laboratory at Caltech and the U.S. Geological Survey, both in Pasadena, California. We appreciate the comments and helpful discussions from Daniel Moos, Steve Graham, and Lev Vernik.

Reservoir-scale fracture permeability in the Dixie Valley, Nevada, geothermal field

Wellbore image data recorded in six wells penetrating a geothermal reservoir associated with an active normal fault at Dixie Valley, Nevada, were used in conjunction with hydrologic tests and in situ stress measurements to investigate the relationship between reservoir productivity and the contemporary in situ stress field. The analysis of data from wells drilled into productive and non-productive segments of the Stillwater fault zone indicates that fractures must be both optimally oriented and critically stressed to have high measured permeabilities. Fracture permeability in all wells is dominated by a relatively small number of fractures oriented parallel to the local trend of the Stillwater Fault. Fracture geometry may also play a significant role in reservoir productivity. The well-developed populations of low angle fractures present in wells drilled into the producing segment of the fault are not present in the zone where production is not commercially viable.

STRESS AND PERMEABILITY HETEROGENEITY WITHIN THE DIXIE VALLEY GEOTHERMAL RESERVOIR: RECENT RESULTS FROM WELL 82-5

We collected borehole televiewer, temperature and flowmeter logs and conducted a hydraulic fracturing test in a well (82-5) that penetrated the SFZ within the known boundaries of the geothermal field but which failed to encounter significant permeability. Although stuck drill pipe prevented direct access to the SFZ, borehole breakouts and cooling cracks indicated a {approximately}90 degree rotation in the azimuth of the least horizontal principal stress (Shmin) in well 82-5 at about 2.7 km depth. This rotation, together with the low (Shmin) magnitude measured at 2.5 km depth in well 82-5, is most readily explained through the occurrences of one or more normal faulting earthquakes in the hanging wall of the SFZ in the northern part of the reservoir. The orientation of (Shmin) below 2.7 km (i.e., {approximately}20 to 50 m above the top of the SFZ) is such that both the overall SFZ and natural fractures directly above the SFZ are optimally oriented for normal faulting failure. If these fracture and stress orient ations persist into the SFZ itself, then the existence of a local stress relief zone (i.e., anormalously high (Shmin) magnitude) is the most likely explanation for the very low fault zone permeability encountered in well 82-5.

Geomechanical Wellbore Imaging: Key to Managing the Asset Life Cycle

A field-specific geomechanical model serves as a platform for dramatically reducing costs and increasing production over the life of a field. The information contained in a geomechanical model makes it possible to assess exploration risk associated with fault-seal breach caused by fault slip. Using model-specific stress, pore pressure, and rock properties information, drilling engineers can provide recommendations for efficient well design and placement to reduce adverse events such as stuck pipe and lost circulation. A geomechanical model also makes it possible to design completions to avoid or manage solids production and to extend the productive life of wells. In addition, the effects of reservoir depletion and injection can be predicted to enable optimal exploitation that avoids excessive reservoir damage, casing collapse, and hazards related to leakage of produced or injected fluids. The essential contribution of wellbore image technologies to these exploration and production challenges is illustrated through recent case studies that apply wellbore imaging technologies to the detection, access, and recovery of hydrocarbons. Future reservoir development and management practice will demand an increased use of imaging techniques to ensure successful production in risky drilling environments, reduce the costs associated with drilling, and increase the economic lifetime of mature reservoirs.

Geomechanical wellbore imaging: Implications for reservoir fracture permeability

A field-specific geomechanical model serves as a platform for greatly reducing costs and increasing production over the life of a field. The information contained in a geomechanical model makes it possible to reduce drilling costs and production losses through fieldwide well planning that can optimize production and minimize risk. A significant value of the geomechanical model is its application to the efficient exploitation of fractured reservoirs. The essential contribution of wellbore image technologies to this exploration and production challenge is illustrated through a case study of a compartmentalized fractured gas reservoir located in Hokkaido, Japan. A growing body of evidence reveals that, in many fractured reservoirs, the most productive fractures are those that are optimally aligned in the current stress field to fail in shear. Thus, it is necessary to obtain knowledge of both the stress magnitudes and orientations and the distribution of natural fractures to determine the optimal orientations for wells to maximize their productivity. The best well intersects the maximum number of stress sensitive fractures. Applying geomechanics and the reservoir fracture distributions to model shear-enhanced permeability as the mechanism for reservoir production appears to be a promising improvement to existing reservoir flow models. Using quantitative risk assessment and realistic uncertainties in the critical parameters, it is possible to estimate the uncertainty in predictions of optimal well trajectories and of stimulation pressures to enhance natural fractures. The results indicate that the critical parameters are not always those with the most uncertainty, and that the most effective way to reduce prediction uncertainties is to calibrate against the productivity of a preexisting well.

In‐situ stress measurements can help define local variations in fracture hydraulic conductivity at shallow depth

Fractures and faults provide permeable pathways for fluids throughout the crust, from aquifers in the shallow subsurface to crustal depths where they can control production in geothermal fields and hydrocarbon reservoirs. Fracture‐enhanced permeability depends on fracture density, connectivity and, most importantly, the hydraulic conductivity of the different fracture and fault planes.

A case study of hydrocarbon transport along active faults and production-related stress changes in the Monterey Formation, California

Abstract Recent field studies show that critically stressed faults, that is, faults that are close to frictional failure in the current stress field, serve as conduits for fluid flow. Similarly, geological field studies of the low permeability siliceous shales in the Monterey Formation, California, clearly indicate that faults influence hydrocarbon transport. We report here a study of the Antelope Shale, a low permeability siliceous shale hydrocarbon reservoir in the Buena Vista Hills field in the southern San Joaquin Valley to determine the influence of the stress state on the relative hydraulic conductivity of the fractures and faults present in the subsurface. Because production has both lowered reservoir pressure and the horizontal stresses, it was necessary to “restore” the reservoir stress state to initial conditions in order to identify correctly the most highly productive intervals. This analysis demonstrates that prior to production, faults in the reservoir were active in a transitional reverse/strike-slip faulting stress state, consistent with regional tectonics. Initial production rates in the field were 2000 barrels of oil per day, principally from intervals where critically stressed faults were encountered.