Completions Evaluation in the Eagle Ford Shale

Neuhaus, Carl Wilbur

doi:10.15530/urtec-2014-1921549

Cited by 4 publications

(2 citation statements)

References 10 publications

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“…16f, requires that there should be at least d sep;min separation distance between the tips of two fractures created from neighboring wells to avoid fracture overlapping. 80 In this work, we consider d sep;min 525 m. In the maximization problem, Eq. 16a, the essential part of the work is done by computing the objective function, that is the first eigenvalue.…”

Section: J5mentioning

confidence: 99%

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Feedback control of proppant bank heights during hydraulic fracturing for enhanced productivity in shale formations

et al. 2017

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In hydraulic fracturing of shale formations, compared to conventional reservoirs, the fracturing fluid injected is of lowviscosity and hence during pumping the proppant settles significantly, forming a proppant bank. Motivated by this consideration, we initially develop a high-fidelity process model of hydraulic fracturing to describe the dominant proppant settling behavior during hydraulic fracturing process. Second, a novel remeshing strategy is developed to handle the high computational requirement due to moving boundaries. Third, a section-based optimization method is employed to obtain key fracture design parameters for enhanced productivity in shale formations subject to given fracturing resources. Fourth, a reduced-order model is constructed to design a Kalman filter and to synthesize a real-time model-based feedback control system by explicitly taking into account actuator limitations, process safety and economic considerations. We demonstrate that the proposed control scheme can regulate the uniformity of proppant bank heights along the fracture at the end of pumping.

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Section: J5mentioning

confidence: 99%

“… The other constraint, Eq. , requires that there should be at least

d_{sep, min}

separation distance between the tips of two fractures created from neighboring wells to avoid fracture overlapping . In this work, we consider

d_{sep, min} = 25 m

.…”

Section: Computation Of Optimal Fracture Configuration In Unconventiomentioning

confidence: 99%

Feedback control of proppant bank heights during hydraulic fracturing for enhanced productivity in shale formations

et al. 2017

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Discrimination of Microseismicity Caused by Proppant Injection Using Microseismic Waveform Clustering: The Horn River Basin Case Study

Ishikawa

Shimoda

Tokunaga

2019

Proceedings of the SPE/AAPG/SEG Asia Pacific Unconventional Resources Technology Conference

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A Validation Assessment of Microseismic Monitoring

Warpinski

Wolhart

2016

Day 2 Wed, February 10, 2016

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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.

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Completions Evaluation in the Eagle Ford Shale

Cited by 4 publications

References 10 publications

Feedback control of proppant bank heights during hydraulic fracturing for enhanced productivity in shale formations

Feedback control of proppant bank heights during hydraulic fracturing for enhanced productivity in shale formations

Discrimination of Microseismicity Caused by Proppant Injection Using Microseismic Waveform Clustering: The Horn River Basin Case Study

A Validation Assessment of Microseismic Monitoring

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