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Collaborating Authors
United States
Abstract In this paper, the results of laboratory studies of hydraulic fracture in homogeneous sandstone blocks with man-made interfaces and heterogeneous shale blocks with weak natural interfaces are reported. Tests were conducted under similar stress conditions, with fluids of different viscosity and at different injection rates. The measurements and analysis allows the identification of fracture initiation and behavior. Fracturing with high viscosity fluids resulted in stable fracture propagation initiated before breakdown, while fracturing with low viscosity fluids resulted in unstable fracture propagation initiated almost simultaneously with breakdown. Analysis also allows us to measure the fluid volume entering the fracture and the fracture volume. Monitoring of Acoustic Emission (AE) hypocenter localizations, indicates the development of created fractured area including the intersection with interfaces, fluid propagation along interfaces, crossing interfaces, and approaching the boundaries of the block. We observe strong differences in hydraulic fracture behavior, fracture geometry and fracture propagation speed, when fracturing with water and high viscosity fluids. We also observed distinct differences between sandstone blocks and shale blocks, when a certain P-wave velocity ray path is intersected by the hydraulic fracture. The velocity increases in sandstones and decreases in shale.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.68)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Colorado > Laramie Basin > Niobrara Formation (0.99)
Abstract Microseismic monitoring of hydraulic fracturing has provided great value for understanding hydraulic fracturing in unconventional reservoirs, including measurement of fracture geometry and optimization of stimulations, completions, and field development. Nevertheless, microseismic monitoring is a complex endeavor and many issues of fielding, analysis, uncertainty, and geophysics should be carefully assessed. The geomechanics of the generation of microseismicity are still being investigated, as well as the source mechanisms and how it all relates to the fracturing process. Besides the value for field development and resource recovery, microseismic monitoring has also proved useful for evaluating environmental and safety issues. Data from thousands of fractures show that the levels of induced seismicity in typical relaxed sedimentary basins are well below any levels that would be of concern for safety or damage. Similarly, data from thousands of fractures show that hydraulic fractures in shale reservoirs do not propagate into aquifers.
- North America > United States > Texas (1.00)
- North America > Canada (1.00)
- North America > United States > Colorado (0.69)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.70)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.47)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (19 more...)
The Evolution of Polygonal Fault Systems: Insights from Geomechanical Forward Modeling
Roberts, D.T. (Cardiff University) | Crook, A.J.L. (Three Cliffs Geomechanical Analysis) | Cartwright, J.A. (University of Oxford) | Profit, M.L. (Rockfield Software Limited,) | Rance, J.M. (Rockfield Software Limited,)
Abstract Polygonal Fault Systems (PFS) are increasingly observed in seismic data of the subsurface. These unusual networks of normal faults are known to develop over vast areas in fine-grained sequences which in many cases may form the regional caprock. Consequently, there is the potential for PFS to compromise the integrity of these sequences with obvious implications for subsurface fluid migration. The processes leading to the formation of PFS remain poorly understood, although their confinement to particular sediment packages and spatial extent are powerful arguments for a constitutive control. The work presented here attempts to progress recent efforts examining a diagenetic trigger for polygonal fault genesis. More specifically, investigations of diagenetically sourced structure development in mudstones have been undertaken in order to formulate a geomechanical argument to explain their formation. This argument is tested in finite strain computational models using the geomechanical code ELFEN, so that the formation over geological time can be studied. Prediction of PFS in both two and three dimensions are presented that demonstrate that this modelling approach can predict realistic PFS geometries including the observed transition from random to preferential fault alignment with increasing degree of stress anisotropy.
- Africa (0.93)
- North America > United States > California (0.46)
- Europe > Norway > North Sea (0.46)
- Europe > United Kingdom > North Sea (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.50)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Normal Fault (0.48)
- North America > United States > California > Monterey Formation (0.99)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > Norway > Norwegian Sea > Vøring Basin (0.99)
- (10 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (0.91)
Abstract Re-Injection is one of the most important methods to dispose fluid associated with oil and natural gas production. Disposed fluids include produced water, hydraulic fracture flow back fluids, and drilling mud fluids. Several formation damage mechanisms are associated with the injection including damage due to filter cake formed at the formation face, bacteria activity, fluid incompatibility, free gas content, and clay activation.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Escondido Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (2 more...)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (4 more...)
Abstract Crushed salt is being considered as a backfilling material to place around nuclear waste within a salt repository environment. In-depth knowledge of salt thermal and mechanical properties as it reconsolidates is critical to thermal and mechanical modeling of the reconsolidation process. An experimental study was completed to quantitatively evaluate the thermal conductivity of consolidated crushed salt as a function of porosity. Temperature dependence of this thermal conductivity was also determined. Porosities ranged from 1% to 40%, and temperatures ranged from ambient up to 300°C. This range of conditions is expected to more than cover those that might be encountered in a radioactive waste disposal facility. Two different experimental devices were used to measure these values. The thermal conductivity of reconsolidated crushed salt decreases with increasing porosity or increasing temperature; conversely, salt thermal conductivity increases as the salt consolidates. Thermal conductivity of experimentally deformed bedded salt cores was shown to be related to fracture density, as a type of porosity. Crushed salt for this study came from the Waste Isolation Pilot Plant (WIPP). Salt was observed to dewater during heating, and the weight loss from dewatering was quantified. A simple mixture theory model is presented to represent the data developed in this study.
- Europe (1.00)
- North America > United States > New Mexico (0.29)
- Water & Waste Management > Solid Waste Management (1.00)
- Energy > Power Industry > Utilities > Nuclear (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.69)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Abstract We present in this paper two examples on two different scales (in borehole and regional), in which stress magnitudes might be influenced by the presence of fractures and faults. Hydraulic fracturing in situ stress measurements conducted in a borehole showed a large fluctuation of the maximum horizontal principal stress (SHmax) at an order of ~10 MPa over few tens of meter depth. Numerous wide aperture fractures are abundant around depths where S Hmax are relatively low, whereas such fractures are scarce at depths where S Hmax are relatively high. Such wide fractures are oriented optimally for slip under the in situ stress condition, playing a role of limiting stress magnitudes by slippage along the fractures and consequent release of excessive stress. A similar observation was made at a much larger scale. Collected stress data in Gyeongsang Basin, Korea show inhomogeneous horizontal stresses with their magnitudes varying laterally. The lateral variation of horizontal stress magnitudes appears to be related to regional scale fault density. This result also suggests that excessive stress might possibly be released by slippage along faults. This study demonstrates that stress magnitudes can be constrained by natural fractures and faults quite locally (at a scale of few tens of meters) and also quite regionally (over km scales).
- North America > United States (0.94)
- Asia (0.67)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.48)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Asia > South Korea > Gyeongsang Basin (0.99)
- North America > United States > Utah > Island Field (0.97)
Abstract The challenge of scales posed by geometry of tabular excavations which have great lateral extent relative to mining height is addressed with a dual node–dual mesh finite element technique that allows for whole-mine analysis including surface subsidence and interactions between various sections of the mine at a kilometer scale, effect of joints at an excavation scale, and details of stress concentrations about a longwall panel face at the meter scale. Spatial variability in strata properties and joint set effects are included for greater realism. Examples demonstrate accuracy and reliability of the technique. Application to an underground coal mine in central Utah then illustrates usefulness of the technique for obtaining design guidance. A 10.6 million node, three-dimensional mesh is used for computations that run overnight. Comparisons of measured with calculated surface subsidence including maximum subsidence of 2.4 m (8 ft) and subsidence "trough" shape confined to areas directly over four major mine sections including 13 sequentially mined longwall panels are in reasonable agreement.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.91)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Metals & Mining > Coal (0.91)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
Abstract The laboratory testing described here can be seen as the first step in investigating potential thermal effects leading to the creation of a leakage pathway at or in the vicinity of a CO2 injection well. The occurrence of thermal stresses in metal casing, cement and formation can lead to either one or more of these materials developing cracks, or debonding between pairs of materials at their interface. A first investigation is thus concentrating on the rock immediately above the injection reservoir; this sealing rock is most often some variant of shale formation. Here we look at the required temperature contrast between the injected CO2 (or for that matter any other liquid) and the shale formation, in order to initiate tensile fracturing due to the development of tensile stresses exceeding the rock's tensile strength. Finite element simulations suggest that significant fracturing may occur for a temperature contrast of 80° C. An accompanying series of laboratory tests showed that for the chosen shale specimen, fracturing should only be of concern for much higher temperature contrasts.
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
Abstract Successful production of oil and gas from shale reservoirs and other tight reservoirs largely depends on the artificially-created fractures. The quality of the artificial fractures is determined by the geomechanical properties of the formation. Ductile behavior of the formation rocks presents a challenge in hydraulic fracturing, while sections with brittle behavior are the priority for fracturing operation. If the mechanical properties of the formation can be predicted without additional drilling, the hydraulic fracturing process can be better optimized economically. Utilizing the example of the Bakken formation, this paper investigated the regularity of the geomechanical properties and its correlation with the stratigraphic sequence. More than 160 Bakken samples of different depths from 8 wells were collected and used in laboratory tests. Geomechanical properties of these samples were measured. Based on the test results, these samples were categorized either as ductile or brittle. Then the variation of their geomechanical properties was correlated with the stratigraphic sequence. This correlation was established in order to provide an explanation to the variation of the brittle characteristic of the rocks. Since the general stratigraphic sequence model of the Bakken formation is already identified and mapped by previous researchers, this correlation provides an approach to predict the geomechanical properties in different intervals of the formation, and offers support in selecting, designing, and optimizing the hydraulic fracturing operation. The methodology developed in this paper can be also applied in other tight reservoirs and formations.
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- North America > Canada > Saskatchewan (1.00)
- North America > Canada > Manitoba (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.38)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (6 more...)
Abstract High injection rates in water injectors leads to mobilization of particles in unconsolidated formations and creates preferential flow paths within the porous medium. Channelization in porous medium occurs when fluid-induced stresses become locally larger than a critical threshold (rock stress); grains are then dislodged and carried away, hence porosity and permeability of the medium will be altered along the induced flow paths. Additionally, rapid shut-ins result in pressure imbalance between the wellbore and formation. Flowback of the particles results in sand accumulation, and consequently loss of injectivity, which is a common problem in unconsolidated formations like the ones in deep water Gulf of Mexico. Experimental studies have confirmed the presence of dependent and independent flow patterns; however, there is no integrated model to describe flow patterns and predict probable issues for water injection at the reservoir scale. The objective of this study is to provide a model for a channel initiation/propagation during injection and flowback in injection wells. A finite volume model is developed based on multiphase fraction volume concept that decomposes porosity into mobile and immobile phases where these phases change spatially and evolve over time that leads to development of erosional channels in radial patterns depending on injection rates, viscosity, magnitude of in situ stresses and rock properties. The model accounts for both particle releasing and suspension deposition. The developed model explains injectivity change with injection rates observed in unconsolidated reservoirs.
- North America > United States > Texas (0.93)
- Europe (0.93)
- North America > United States > Colorado > Piceance Basin > Buzzard Field > Mesaverde Formation > Williams Fork Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Buzzard Field > Mancos Formation > Williams Fork Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Buzzard Field > Iles Formation > Williams Fork Formation (0.99)
- (3 more...)