Permeability Estimation from Fracture Calibration Test Analysis in Shale and Tight Gas

Han, Xue; Ehlig-Economides, Christine

doi:10.1190/urtec2013-023

Cited by 8 publications

References 22 publications

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Permeability Estimation from Fracture Calibration Test Analysis in Shale and Tight Gas

Han

Ehlig-Economides

2013

Unconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013

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Permeability estimation in tight and shale reservoirs is challenging because little or no flow will occur without hydraulic fracture stimulation. In the pressure falloff following a fracture calibration test (FCT), radial flow after the fracture closure can be used to estimate the reservoir permeability. However, for very low permeability, the time to reach radial flow can exceed any practical duration. This study shows how to use the reservoir pressure to estimate the maximum reservoir permeability when radial flow is missing in the after-closure response. The approach is straightforward and can also be used for buildup tests. It applies whenever the well completion geometry permits radial flow before the pressure response encounters a real well drainage limits. Recent developments have blurred the boundary between fracture calibration test analysis and classic pressure transient analysis. Adapting the log-log diagnostic plot representation to the FCT analysis has made it possible to perform before and after closure analysis on the same diagnostic plot. This paper also proposes a method for diagnosing abnormal leakoff behavior using the log-log diagnostic plot as an alternative method for the traditional G-function plot. The results show the relationship between reservoir permeability and pressure can be used effectively for both estimation of the permeability upper bound when there is no apparent radial flow and for confirming the permeability estimated from apparent late time radial flow. Numerous field examples illustrate this simple and powerful insight.

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Permeability Estimation from Fracture Calibration Test Analysis in Shale and Tight Gas

Han

Ehlig-Economides

2013

Unconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013

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Actual and Optimal Hydraulic Fracture Design in a Tight Gas Reservoir

Zhang

Pang

et al. 2014

All Days

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Designing hydraulic fracture stimulation to optimize well productivity requires knowledge of the initial reservoir pressure and permeability, the closure stress magnitudes in the reservoir and in bounding formations, a carrier fluid with a suitable leakoff coefficient, and rock properties such as the Young's modulus and the Poisson ratio that can be determined from a core sample. When key parameters are left unknown, the hydraulic fracture stimulation is likely to be severely suboptimal.This study integrates pressure buildup and production transient analyses with microseismic surveys and the recorded pumping schedule to estimate the above-mentioned parameters in previously fractured wells on production for up to 7 years from a tight gas reservoir.The first well drilled and completed in the block included a pressure buildup test that enabled accurate estimation of the initial reservoir pressure and permeability. A post-fracture buildup test was also conducted, and annual pressure buildup tests in 6 subsequent years showed continuous changes in the fracture morphology with fracture conductivity decreasing by a factor of 3 and fracture length increasing by about 50%. Many of the subsequent wells were drilled in 2 pattern well clusters, each designed to account for fracture propagation behavior indicated from a microseismic survey. A comparison with an optimal hydraulic fracture design intended to maximize well productivity indicates that most of the well stimulations were suboptimal with rate and cumulative production about ½ that of an optimized design based on the same proppant mass.The observed changes in fracture conductivity and length over time were unanticipated. Because such data are rarely recorded the variations in fracture morphology may be fairly typical and should be of considerable interest to pressure transient analysts. The production data analysis shows the difficulties in determining formation and fracture parameters when the transient response lacks radial flow. The fracture treatment analysis shows a comparison between the actual fracture treatment and one designed to maximize well productivity and clearly illustrates the potential for well improvement using modern hydraulic fracture design principles.

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Actual and Optimal Hydraulic-Fracture Design in a Tight Gas Reservoir

Pang

Zhang

et al. 2016

SPE Production &Amp; Operations

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Designing hydraulic-fracture stimulation to optimize well productivity requires a carrier fluid with a suitable leakoff coefficient and knowledge of the initial reservoir pressure and permeability, the closure-stress magnitudes in the reservoir and in the bounding formations, and rock properties such as the Young's modulus and the Poisson's ratio, which can be determined from cores. When key parameters are left unknown, the hydraulic-fracture stimulation is likely to be severely suboptimal.This study integrates pressure-buildup and production transient analyses with microseismic surveys and the recorded pumping schedule to estimate the aforementioned parameters in previously fractured wells in a tight gas reservoir that have been on production for up to 8.5 years.The first well drilled and completed in the block included a pressure-buildup test that enabled accurate estimation of the initial reservoir pressure and permeability. A post-fracture buildup test was also conducted, and annual pressure-buildup tests in the subsequent 6 years showed continuous changes in the fracture morphology, with fracture conductivity decreasing by a factor of three and fracture length increasing by approximately 50%. Many of the subsequent wells were drilled in two patterned well clusters, each designed to account for fracture-propagation behavior indicated from a microseismic survey. A comparison with an optimal hydraulic-fracture design that was intended to maximize well productivity indicates that most of the well stimulations were suboptimal, with rate and cumulative production approximately one-half that of an optimized design on the basis of the same proppant mass.The observed changes in fracture conductivity and length over time were not anticipated. Because such data are rarely recorded, the variations in fracture morphology may be fairly typical and should be of considerable interest to pressure-transient analysts.The production-data analysis shows the difficulties in determining formation and fracture parameters when the transient response lacks radial flow. The fracture-treatment analysis shows a comparison between the actual fracture treatment and one designed to maximize well productivity, and clearly illustrates the potential for well improvement through the use of modern hydraulic-fracture-design principles.

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Permeability Estimation from Fracture Calibration Test Analysis in Shale and Tight Gas

Cited by 8 publications

References 22 publications

Permeability Estimation from Fracture Calibration Test Analysis in Shale and Tight Gas

Permeability Estimation from Fracture Calibration Test Analysis in Shale and Tight Gas

Actual and Optimal Hydraulic Fracture Design in a Tight Gas Reservoir

Actual and Optimal Hydraulic-Fracture Design in a Tight Gas Reservoir

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