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ABSTRACT: Comparisons of stress directions and orientations of flow-controlling fractureshow that open fractures in the subsurface are not necessarily parallel to maximum compressire stress (SHm?) and that fractures perpendicular to this direction may be open. Moreover, sealed fractures parallel to Snma? are numerous. Parallelism of SHm? and open fractures is not good evidence, by itself, that modem-day stress controls the orientation of open fractures. A determining factor for fluid flow is the degree of mineral cement within fractures, which is a function of fracture size and the rock's diagenetic history. In most subsurface opening-mode fracture systems, fractures are partly filled with cement deposited at the time of fracturing. This cement forms strong mineral bridges that prop the fracture open. The remaining part of the fracture may be open or filled with cements precipitated after fractures ceased opening. For the many reservoirs in which opening-mode fractures are the key flow pathways, cement patterns rather than stress data may provide the insight needed to determine which fractures are open to fluid flow. INTRODUCTION A widely held belief in the petroleum industry is that modem state of stress determines which natural fractures are important for fluid flow at the reservoir scale. Fractures that strike parallel to present-day maximum horizontal compression (SHm?) and perpendicular to the horizontal direction of current minimum compression (Shm?n) are inferred to have a greater likelihood of being open (e.g. Queen & Rizer 1990, Parks & Gale 1999). A recent survey of operators and industry structural geologists overwhelmingly rated present-day SHm? as the factor dictating strike of open fractures (AAPG Reservoir Deformation Group, 1999 pers. comm.). In seismic shear-wave analysis a basic assumption is that open fractures are preferentially oriented by the current stress field acting on the rock mass (Crampin 1987). In production analysis engineers frequently assume that fractures are the most compliant part of the rock mass and are susceptible to closure with increasing effective normal stress (Warpinski et al. 1991). A wide spectrum of rock-mechanics observations and model studies demonstrate compliant fractured rock masses and individual joints (nonmineralized fractures) (Barton et al. 1985). An opening-mode fracture is expected to close when pore pressure falls below the minimum stress, unless there is some mismatch or propping of the fracture. However, these contemporary views derive in part from influential studies that show that critically stressed faults in crystalline rock are the locus of fluid flow (Barton et al. 1995). The contrary view (e.g. Dyke 1995) that natural-fracture aperture and permeability are not highly sensitive to changes in effective normal stress has largely been neglected. Considering the importance of natural fracture systems in this era of deep directional drilling and challenging fracture targeting, we examine the validity of the contemporary stress/open fracture paradigm and its implications for exploration risk and reservoir management.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.49)
- North America > United States > Wyoming > Wind River Basin (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Green River Basin (0.99)
- (16 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
Abstract The quantification of fracture spacing and length are crucial for determination of effective block sizes to be used in reservoir simulation. Outcrop and modeling studies have shown that average values of these parameters do not adequately describe a fracture pattern, however. Observational work suggests that the cumulative number of fractures larger than a given size (in length or aperture) can be described with power-law relationships, and these empirical models are used to extrapolate from the observational scale to other scales of interest. Fracture spacing distributions are commonly described relative to their "saturation level," a measure of the regularity of the spacing between fractures of a given set that is thought to be related to strain level. As a spacing population approaches a normal distribution it is said to become more saturated or "well-developed," and this progression is assumed to be related to increasing strain imparted to a rock layer. A complication observed in sandstone outcrops from Oil Mountain, a Laramide anticlinal structure in Wyoming, is that fracture sets can reach saturation at different levels of strain even in the same bed. Assuming that average spacing indicates the level of strain accommodated by a given fracture set, the cross-fold fracture set from Oil Mountain requires very high strain to become saturated (spacing on the order of ift for a 30 ft thick bed). In contrast, the fold-parallel set displays a very high saturation at extremely low strain level (30 ft average spacing for a 30 ft thick bed). With a geomechanical model, we investigate the flindamental processes that control fracture propagation to explain spacing variability and suggest how to develop predictive models of fracture spatial arrangement. In addition to discussing the mechanics of fracture network development, we address the sampling problems inherent in reservoir characterization. For subsurface fractures, measuring the saturation, length distribution, or connectivity is highly problematic because boreholes rarely encounter the fractures of interest. This is a serious impediment to acquiring sufficient data to constrain predictive characterization models that feed into reservoir simulations. Using Oil Mountain as an outcrop analog of a sandstone reservoir, we explore the use of microfractures as indicators of the attributes of large fractures. The advantage of microfractures is they are so much more abundant than macrofractures that they can be readily sampled from weilbores (a single thin section can produce thousands of measuments). If microfractures can be used as proxies for large fractures, then the results of predictive characterization modeling can be applied to subsurface cases much more effectively and accurately than has hitherto been possible. P. 221
- North America > United States > Wyoming (0.34)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Natural Fractures in Sonora Canyon Sandstones, Sonora and Sawyer Fields, Sutton County, Texas
Marin, B.A. (Bureau of Economic Geology, U. of Texas) | Clift, S.J. (Bureau of Economic Geology, U. of Texas) | Hamlin, H.S. (Bureau of Economic Geology, U. of Texas) | Laubach, S.E. (Bureau of Economic Geology, U. of Texas)
Abstract The Sonora Canyon is one of several "Canyon Sands" (Virgilian-Wolfcampian) intervals that exist in the Val Verde Basin of southwest Texas. This paper describes the presence and attributes of natural fractures in Sonora Canyon sandstones in Sutton County, Texas. Data obtained from three cored wells through a cooperative research program conducted by the Gas Research Institute and industry show that natural fractures are locally abundant. At least three distinct natural fracture classes coexist that have contrasting distributions, characteristic sizes, and/or mineral fills. The most abundant fracture class consists of clay- or clay- and carbonate- filled fractures existing only in siderite-cemented zones in sandstones. Owing to their clay content, these fractures locally may be barriers to fluid flow and their presence could cause reservoir heterogeneity and anisotropy. Calcite- and quartz-cemented fractures are less common fracture classes. These fractures are larger than those in siderite layers and are partly open as a result of propping by diagenetic minerals. Our results show that fractures in Sonora Canyon sandstones should be considered in completion and stimulation design. For example, high treatment pressures observed in some Canyon Sandstone stimulations may be due to natural fractures promoting propagation of multiple fracture strands near the wellbore. Inconsistencies between hydraulic fracture strike and maximum horizontal stress may be due to natural fractures guiding hydraulic fracture growth. A KEY RESERVOIR ELEMENT In rock having low matrix permeability, natural fractures can significantly affect reservoir properties. Open fractures can enhance and filled fractures can impede fluid flow, and fractures in many cases produce anisotropic and heterogeneous rock permeability. When hydraulic fracture treatments are performed to stimulate gas reservoirs, treatment design should take into account the presence of natural fractures because these fractures can cause high treatment pressures by promoting development of multiple fracture branches. Because they are commonly planes of low tensile strength, natural fractures can also cause treatment fractures to grow in a direction that differs from that predicted from analysis of principal stress directions. Sonora Canyon sandstones, a gas play in western Sutton County in the Val Verde Basin of southwest Texas (Figure 1), have yielded almost 2 trillion cubic feet (Tcf) of gas. Several trillion cubic feet of recoverable gas are thought to remain. Canyon gas reservoirs lie at depths between about 3,000 and 8,000 ft. Clean, matrix-free reservoir sandstones generally have less than 5% effective porosity and 0.1 md permeability. Hamlin and others summarized recent work on the stratigraphy and diagenesis of Sonora Canyon reservoirs, and aspects of Sonora Canyon reservoir engineering and hydraulic fracture treatment are described in recent Gas Research Institute topical reports. Natural fractures in Sonora Canyon sandstones have not previously been described. In this study, we document the occurrence and attributes of 191 natural fractures in 842.5 ft of Sonora Canyon core from 3 wells. Our discovery of natural fractures in Canyon sandstones and our descriptions of fracture attributes are useful for improving exploration and development strategies and the design and modeling of hydraulic fracture treatments in the Canyon Sandstone. SEDIMENTARY FRAMEWORK In the northern Val Verde Basin, the Sonora Canyon is a wedge-shaped interval composed primarily of coalesced submarine fans forming a slope apron. P. 523^
- Phanerozoic > Paleozoic > Permian > Cisuralian (0.54)
- Phanerozoic > Paleozoic > Carboniferous > Pennsylvanian > Upper Pennsylvanian > Kasimovian (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- North America > United States > Texas > Permian Basin > Val Verde Basin (0.99)
- North America > United States > Texas > Fort Worth Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Val Verde Basin (0.99)
- (7 more...)
ABSTRACT: Systematic fracture (face cleat) strikes in Upper Cretaceous Fruitland Formation coal (San Juan Basin, Colorado and New Mexico) delineate two domains of regional extent that are separated by a boundary of variable cleat orientation near the Colorado-New Mexico border. South of the boundary, face cleats strike predominantly northward or northeastward; north of the boundary they strike northwestward. Such domains may determine fracture permeability pathways in coal seams. Prevalence of two directions of strongly developed fractures in the domain boundary region, close cleat spacing related to northward increase in coal rank, and resulting increased coal friability may enhance the success of well completion by open-hole cavity methods in the north-central part of the basin. 1 INTRODUCTION With the increasing importance of coalbed methane as a natural gas source, information on coal fracture (cleat) patterns is becoming critical for planning coalbed methane well placement. Fracture patterns in coal and adjacent rocks affect completion and stimulation techniques such as horizontal drilling, open-hole cavitation, and hydraulic fracture treatment. Regional mapping of coal fractures using outcrop and core data delineates important variations in fracture patterns that in turn affect the physical/mechanical properties of the coal. 2 GEOLOGIC SETTING The San Juan Basin of the east-central Colorado Plateau, New Mexico and Colorado, is a Late Cretaceous to early Tertiary structural basin that contains >4000 m of Paleozoic to Cenozoic marine and continental rocks. As defined by the Upper Cretaceous (Campanian) Fruitland Formation outcrop, the basin is roughly circular and~17,000km2 in area (Fig. 1). Over 1000 coalbed methane wells have been drilled in the Fruitland Formation in the past decade, making it one of the most important coalbed-methane-producing units in the country. The Fruitland consists of coastal plain deposits composed of sandstone, mud- stone, coal, and carbonaceous shale. It is > 100 m thick in the northwestern part of the basin, but it thins and disappears in the eastern part of the basin as a result of depositional thinning and erosion. 3 CHARACTERISTICS OF COAL FRACTURES Fruitland Formation coal fractures include systematic and nonsystematic fractures and faults. Cleats are the systematic fractures in coal that are equivalent to joints in other sedimentary rocks. Fruitland cleats are extension fractures that are perpendicular to bedding, generally planar but locally strongly curved, commonly uniform in strike within an outcrop or core, and arranged in subparallel sets. Two cleat sets in an orthogonal pattern are designated face and butt cleat. Face cleats are planar, smooth- sided fractures that usually comprise the most prominent fracture set. Based on abutting relations, they are the earliest formed fractures. In the Fruitland Formation, they may be as much as several meters long in plan view. Butt cleats formed later and in most cases intersect and terminate against face cleats at 80 to 90ยฐ angles. A single face cleat set and an associated butt cleat set are present in most exposures. Their surfaces are irregular and rough, and they are less continuous and less well developed than associated face cleats.
- North America > United States > New Mexico (1.00)
- North America > United States > Colorado (1.00)
- North America > United States > Texas > Travis County > Austin (0.28)
- North America > United States > New Mexico > San Juan Basin > Fruitland Formation (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
- North America > Canada > Alberta > Colorado Field > Bonavista Colorado 6-32-90-4 Well (0.97)
Abstract Fracture permeability is of primary importance to producibility of gas from many low-permeability-sandstone producibility of gas from many low-permeability-sandstone gas reservoirs in the western United States, but the location, orientation, spacing, and connectedness of fractures in the subsurface is difficult to measure directly. The Upper Cretaceous Pictured Cliffs Sandstone (San Juan Basin, Colorado and New Mexico) and Frontier Formation (Green River Basin, Wyoming) form low-permeability gas reservoirs for which production data indicate locally important fracture permeability. In the wells studied, fractures are present in core or visible on borehole-imaging logs. Insight into the types of fracture patterns that may occur in these rocks could help guide exploration, completion, and stimulation strategies. Maps of fractures provide the most accurate representation of fracture spatial distribution, trace length, connectivity, and size and shape of fracture-bounded blocks. In this study, fracture patterns were characterized by mapping large exposures of Pictured Cliffs and Frontier sandstone along the margins of the San Juan and Green River Basins. A set of fractures is recognized in both formations that is interpreted as having formed in flat-lying rocks prior to local Tertiary folding and uplift. In contrast to the conventional map pattern of regional fractures, in which fractures are arranged in regularly spaced, orthogonal arrays, these fractures occur in discrete swarms separated laterally by domains that either lack fractures or that have only rare fractures. These less fractured domains may be as much as several hundreds of meters wide. Within swarms, fractures are well interconnected along the length of the swarm, but poorly interconnected across the width of the swarm. Fractures between swarms are commonly isolated. For the Pictured Cliffs and Frontier outcrops that were studied, the fracture pattern is self-similar over scales ranging from outcrop to pattern is self-similar over scales ranging from outcrop to interwell scale with fractal dimension D=1.2. In the low-permeability sandstones of the Rocky Mountain region, irregularly spaced fracture swarms are potential targets for gas exploration and should be incorporated into fractured-reservoir models. Introduction With the increasing importance of low-permeability sandstones as natural gas reservoirs, information on their fracture patterns is becoming critical for design of exploration, development, and completion strategy, including application of horizontal drilling. Accurate determination of subsurface fracture pattern is difficult in mildly deformed sedimentary rocks because fracture detection methods, such as geophysical well logs and core (particularly from vertical wells), may fail to detect fractures and at best sample only a small part of the fracture network. In conjunction with subsurface investigations, outcrop studies can provide insight into fracture patterns that can be used to guide exploration and help understand hydrocarbon production patterns. P. 501
- North America > United States > New Mexico (1.00)
- North America > United States > Colorado (1.00)
- Geophysics > Seismic Surveying (0.88)
- Geophysics > Borehole Geophysics (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
- North America > United States > Utah > Green River Basin (0.99)
- North America > United States > New Mexico > San Juan Basin > Fruitland Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- (5 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Abstract Geological knowledge of low-permeability (permeability less than 0.1 md) hydrocarbon-bearing sandstone reservoirs enhances exploration and exploitation strategies. Structural, stratigraphic, and petrographic analyses are required to interpret trap style, reservoir quality, and porosity and permeability distribution. Information porosity and permeability distribution. Information compiled in such studies facilitates (1) the estimation of reservoir volume and drainage area, (2) the design of drilling and completion programs, (3) the location of development wells, and (4) the calibration of logs. At North Appleby field, data from cored wells in the lower Travis Peak Formation have established a foundation for predictions about reservoir geometry, occurrence of natural fractures, and the degree and type of diagenesis that the reservoir has undergone. Only after integrating structural, stratigraphic, and petrographic data on the evolution of these low-permeability sandstones can relationships among sand-body geometry and orientation, diagenesis, and natural fractures be discerned. Broad, tabular reservoirs were deposited by braided- to meandering-fluvial systems. Reservoir seals and internal fluid-flow barriers consist of mudstones and porosity-occluding quartz cement. Pore types range from porosity-occluding quartz cement. Pore types range from micropores to primary and secondary macropores. Vertical natural fractures are macropores that are oriented at approximately right angles to sandstone trends. Natural fractures are abundant in sandstone with very extensive quartz cement (greater than 17%); in these rocks natural fractures should be considered in reservoir evaluations and hydraulic-fracture treatment design. Geometry and quality of Travis Peak reservoirs vary with depositional environment and degree of diagenesis. Reservoirs at the top of the formation are thin and separated by mudstones; few natural fractures occur in these sandstones. Productive sandstones at the base of the formation, however, are thicker and more sand rich; these contain a greater percentage of quartz cement and are naturally fractured. Introduction Since 1982, the Gas Research Institute (GRI) has supported geological investigations that are designed to develop knowledge necessary to efficiently produce low-permeability gas-bearing sandstones. Research efforts have focused on the Travis Peak Formation in the East Texas Basin. The Travis Peak is a Lower Cretaceous terrigenous-clastic sediment wedge that rims the Gulf of Mexico Basin from Texas through Arkansas, Louisiana, and Mississippi. This research represents one part of a broader, multidisciplinary program designed to increase knowledge and ultimate recovery of unconventional gas resources through integration of geology, log analysis, and reservoir engineering. At present, many low-permeability, gas-bearing sandstones are not being exploited or efficiently evaluated because the geologic, engineering, and petrophysical understanding of these reservoirs is poor. petrophysical understanding of these reservoirs is poor. This has limited development and implementation of new technology that would enable economic gas production. production. P. 355
- North America > United States > Texas > Upshur County (0.50)
- North America > United States > Texas > Smith County (0.50)
- North America > United States > Texas > Rusk County (0.50)
- (2 more...)
- Research Report (0.46)
- Overview (0.34)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Travis Field (0.99)
- North America > United States > Texas > East Texas Salt Basin > Whelan Lease > Waskom Field > Lowe Paluxy Formation (0.99)
- (7 more...)
Abstract Detection and characterization of fractures in low-permeability reservoirs is an important goal of reservoir analysis. Natural fractures may increase porosity in low-permeability rock and may enhance porosity in low-permeability rock and may enhance or limit the success of hydraulic fracture treatment. Two logging tools used for fracture detection are the borehole televiewer (BHTV), an acoustic device that maps the smoothness of the borehole wall, and the Formation Microscanner (FMS*), a resistivity tool that produces a conductivity map of two 2.8-inch-wide strips of the borehole wall. Our analysis compares BHTV and FMS logs to 1,028 ft of core from three wells in the 2,000-ft-thick Lower Cretaceous Travis Peak Formation, a sandstone and shale unit that produces gas from low-permeability sandstone in East Texas. Core was obtained from depths of 5,900 to 9,900 ft. The Travis Peak provides a good test of fracture-imaging logs because provides a good test of fracture-imaging logs because natural fractures have complex geometry and variable mineral fill and because there are borehole breakouts, drilling-induced fractures, and vertical sedimentary structures that must be distinguished from natural fractures for successful fracture analysis. Vertical extension fractures in Travis Peak sandstone usually are visible on BHTV and FMS logs, but some fractures were missed by FMS pads. Low-angle natural shear fractures observed in core were not seen on either log. Both BHTV and FMS represent fracture shape and distinguish fractures from borehole breakouts. FMS gives a high-resolution image of fracture shape, but natural fractures could not be distinguished from drilling-induced fractures on either log. Existing commercial BHTV and FMS techniques do not give a quantitative measure of fracture aperture. Fracture orientation is readily obtained for inclined fractures from either BHTV or FMS logs, but the orientation of vertical fractures is commonly ambiguous on both logs. These results show that BHTV and FMS logs are useful adjuncts to core-based fracture studies for evaluation of fractured reservoirs. Introduction Natural fractures may enhance accumulation and production of hydrocarbons from reservoir rock. production of hydrocarbons from reservoir rock. Many problems in exploiting reservoir fractures stem directly from difficulties in characterizing fracture orientation, geometry, width, and type. Hydraulic fracture treatments, which are required in many low-permeability reservoirs, can be significantly influenced by natural fractures. Whole core provides the most direct information on fractures and their relation to reservoir rock, but core recovery in fractured rock is commonly poor and core orientation methods may fail. Geophysical logs that image the borehole can provide information on some critical aspects of provide information on some critical aspects of reservoir fractures. As part of research in hydraulic fracture treatment technology, the Gas Research Institute sponsored a coring and logging program in Travis Peak Formation reservoirs in program in Travis Peak Formation reservoirs in East Texas. P. 129
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.90)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Texas > Sligo Field > Sligo Formation (0.99)
- North America > United States > Mississippi > Travis Peak Formation (0.99)
- (6 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract Efficient hydraulic fracture treatment of low-permeability reservoirs depends on reliable prediction of the stimulation fracture strike, which generally is parallel to the maximum horizontal stress. parallel to the maximum horizontal stress. Coring-induced fractures can be used to predict the strike of stimulation fractures if coring-induced fractures are aligned with the maximum horizontal stress. Our studydetermines the orientation of coring-induced fractures in East Texas and compares the strike of coring-induced fractures to indicators of stress direction and stimulation fracture strike. We used descriptions of 565 fractures in 1,802 ft (549 m) of core from seven wells in the Lower Cretaceous Travis Peak Formation, a low-permeability sandstone and shale unit approximately 2,000 ft (609 m) thick that produces gas in much of East Texas. Fracture imaging logs were available from three study wells. Stimulation fracture azimuth was independently determined by monitoring microseismicity during fracture treatment. Mean strike of coring-induced petal and petal-centerline fractures is parallel to the east-northeast azimuth of maximum horizontal stress determined from core strain recovery, borehole breakouts, and strike of fractures created in stress tests and hydraulic fracture treatments. Natural and coring-induced fractures are not parallel, but the difference in strike is generally small (<10 degrees). Petal and petal-centerline fractures are useful for predicting the petal-centerline fractures are useful for predicting the strike of stimulation fractures. Their usefulness is limited by the precision of core orientation methods. Introduction Knowledge of the strike of fractures created during hydraulic fracture treatment for reservoir stimulation is important for fracture treatment design and reservoir development. Stimulation-fracture strike can be measured directly by a variety of techniques, or fracture strike can be predicted from knowledge of maximum horizontal stress direction, which stimulation fractures tend to parallel. Methods for determining horizontal stress parallel. Methods for determining horizontal stress directions include an elastic strain recovery (ASR), differential thermal expansion analysis, and sonic velocity measurements of core and borehole breakout directions. The strike of extension fractures created in front of the drill bit during coring is another potentially useful indicator of horizontal stress anisotropy that is easily obtained from oriented core. Coring-induced extension fractures with distinctive geometry and surface structures are common. These fractures should parallel maximum horizontal stress unless parallel maximum horizontal stress unless near-wellbore stress perturbations or mechanical anisotropy in the rock have a significant effect on fracture strike. Our study evaluates coring-induced fractures as predictors of stimulation-fracture strike in the Lower predictors of stimulation-fracture strike in the Lower Cretaceous Travis Peak Formation in East Texas. We document the orientation of coring-induced fractures and the relation of coring-induced to natural fractures and compare coring-induced fracture strike to other stress-direction indicators and to stimulation-fracture strike. Results show that two common types of coring-induced fractures are useful predictors of stimulation-fracture strike. predictors of stimulation-fracture strike. P. 587
- Research Report > Experimental Study (0.66)
- Research Report > New Finding (0.48)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.36)
- Geophysics > Borehole Geophysics (0.93)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.68)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Texas > Sligo Field > Sligo Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Whelan Lease > Waskom Field > Lowe Paluxy Formation (0.99)
- (10 more...)