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Microseismic monitoring of hydraulic fracturing in unconventional reservoirs is a valuable tool for delineating the effectiveness of stimulations, completions, and overall field development. Important information, such as fracture azimuth, fracture length, height growth, staging effectiveness, and many other geometric parameters, can typically be determined from good quality data sets. In addition, there are parameters now being extracted from microseismic data sets, or correlated with microseismic data, to infer other properties of the stimulation/completion system, such as stimulated reservoir volume (SRV), discrete fracture networks (DFNs), structural effects, proppant placement, permeability, fracture opening and closure, geohazards, and others. Much of the information obtained in this way is based on solid geomechanical or seismological principles, but some of it is speculative as well.This paper reviews published data where microseismic results have been validated by experiments using some type of ground-truth or alternative measurement procedure, discusses the geomechanics and seismological mechanisms that can be reasonably considered in evaluating the likelihood of inferring given properties, and appraises the uncertainties associated with monitoring and the effect on any inferences about fracture behavior. Considerable data now exist from tiltmeters, fiber-optic sensing, tracers, pressure sensors, multi-well-pad experiments, and production interference that can be used to aid the validation assessment.Relatively limited microseismic results have actually been validated in any consistent manner. Fracture azimuth from microseismic has been verified across a wide range of reservoir types using multiple techniques. Good validation of fracture length and height were performed in sandstones for planar fractures; fracture length and height in typical horizontal completions with multiple fractures or complexity have a lesser degree of verification. Other parameters, such as complexity, discrete fracture networks, source parameters, and SRV, have little supporting evidence to provide validation, even though they might have sound physical principles underlying their application. It is clear that microseismic monitoring would benefit from more attention to validation testing. In many cases, the data might be available but have not been used for validation purposes, or such results have not been published.
Microseismic monitoring of hydraulic fracturing in unconventional reservoirs is a valuable tool for delineating the effectiveness of stimulations, completions, and overall field development. Important information, such as fracture azimuth, fracture length, height growth, staging effectiveness, and many other geometric parameters, can typically be determined from good quality data sets. In addition, there are parameters now being extracted from microseismic data sets, or correlated with microseismic data, to infer other properties of the stimulation/completion system, such as stimulated reservoir volume (SRV), discrete fracture networks (DFNs), structural effects, proppant placement, permeability, fracture opening and closure, geohazards, and others. Much of the information obtained in this way is based on solid geomechanical or seismological principles, but some of it is speculative as well.This paper reviews published data where microseismic results have been validated by experiments using some type of ground-truth or alternative measurement procedure, discusses the geomechanics and seismological mechanisms that can be reasonably considered in evaluating the likelihood of inferring given properties, and appraises the uncertainties associated with monitoring and the effect on any inferences about fracture behavior. Considerable data now exist from tiltmeters, fiber-optic sensing, tracers, pressure sensors, multi-well-pad experiments, and production interference that can be used to aid the validation assessment.Relatively limited microseismic results have actually been validated in any consistent manner. Fracture azimuth from microseismic has been verified across a wide range of reservoir types using multiple techniques. Good validation of fracture length and height were performed in sandstones for planar fractures; fracture length and height in typical horizontal completions with multiple fractures or complexity have a lesser degree of verification. Other parameters, such as complexity, discrete fracture networks, source parameters, and SRV, have little supporting evidence to provide validation, even though they might have sound physical principles underlying their application. It is clear that microseismic monitoring would benefit from more attention to validation testing. In many cases, the data might be available but have not been used for validation purposes, or such results have not been published.
Summary The effect of well interference through fracture hits in shale reservoirs needs to be investigated because hydraulic fracturing is abundantly used in the development of unconventional oil and gas resources. Although numerous pressure tests have proved the existence of well interference, relatively few physical models exist to quantitatively simulate the pressure response of well interference. The objective of the present study is to develop a numerical compositional model in combination with a fast embedded-discrete-fracture-model (EDFM) method to simulate well interference. Through nonneighboring connections (NNCs), the fast EDFM method can easily and properly handle complex-fracture geometries, such as nonplanar hydraulic fractures and a large amount of natural fractures. Using public data for Eagle Ford tight oil, we build a reservoir model including up to three horizontal wells and five fluid pseudocomponents. The simulation results show that the connecting hydraulic fractures play a more-important role than natural fractures in declining bottomhole pressure (BHP) of the shut-in well. Matrix permeability has a relatively minor effect on pressure drawdown, and well productivity remains only slightly affected by the overall low permeability used. The BHP pressure-decline profiles change from convex to concave when the conductivity of the connecting fractures increases. At early times, the BHP of the shut-in well decreases when the number of natural fractures increases. At later times, the natural-fracture density has a lesser effect on the pressure response and no clear trend. The opening order of neighboring wells affects the well-interference intensity between the target shut-in well and the surrounding wells. After a systematic investigation of pressure drawdown in the reservoir, we formulate practical conclusions for improved production performance.
Summary Well interference is a common phenomenon between wells observed in unconventional reservoirs, which has received significant attention. It plays an important role in well-spacing considerations. Massive hydraulic fractures are generated in horizontal wells by multistage hydraulic-fracturing treatments and result in well interference between adjacent wells. However, very little work has been completed to understand how massive fractures cause well interference. In this study, we analyzed dynamic-stress evolution and multiple-fracture propagation from two horizontal wells to improve understanding of fracture hits. We used our newly developed nonplanar hydraulic-fracturing model that couples rock deformation and fluid flow in the fracture and horizontal wellbore. Fracture propagation in a stage is controlled by stress-shadow effects and flow-rate distribution between fractures. Fracture interaction within a stage and from adjacent wells is considered through a simplified 3D displacement discontinuity method. Well interference is well communication caused by fracture hits. Because of varying stress reorientation, fractures propagate toward each other from two adjacent wells, and fracture tips always tend to converge with each other and decrease fracture distance, which promotes fracture coalescence. For plug-and-perforate completion, multiple fractures in a stage generally cannot uniformly develop. Dominant fractures with extremely long length are often generated and hit fractures from adjacent wells. Fracture hits and well interference are induced by these two mechanisms, which are affected by fracture spacing and the differential stress (DS) of reservoirs. Results show that the larger the fracturing spacing is, the smaller the likelihood is to induce fracture connection. A large DS can prevent fractures from deviating from their original paths. For a reservoir with a large DS, fracture hits can be decreased with a stagger distance of fractures between two wells. This work uses a hydraulic-fracturing model to analyze fracture geometry between two horizontal wells and offers improved understanding of fracture connection. The results of the study provide critical insights to improve well interference and to optimize well spacing and design of multiwell completion techniques.
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