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Stephen H. Hickman - One of the best experts on this subject based on the ideXlab platform.
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Stress‐induced, time‐dependent Fracture Closure at hydrothermal conditions
Journal of Geophysical Research, 2004Co-Authors: N. M. Beeler, Stephen H. HickmanAbstract:[1] Time-dependent Closure of Fractures in quartz was measured in situ at 22–530°C temperature and 0.1–150 MPa water pressure. Unlike previous crack healing and rock permeability studies, in this study, Fracture aperture is monitored directly and continuously using a windowed pressure vessel, a long-working-distance microscope, and reflected-light interferometry. Thus the Fracture volume and geometry can be measured as a function of time, temperature, and water pressure. Relatively uniform Closure occurs rapidly at temperatures and pressures where quartz becomes significantly soluble in water. During Closure the aperture is reduced by as much as 80% in a few hours. We infer that this Closure results from the dissolution of small particles or asperities that prop the Fracture open. The driving force for Closure via dissolution of the prop is the sum of three chemical potential terms: (1) the dissolution potential, proportional to the logarithm of the degree of undersaturation of the solution; (2) the coarsening potential, proportional to the radius of curvature of the prop; and (3) the pressure solution potential, proportional to the effective normal stress at the contact between propping particles and the Fracture wall. Our observations suggest that Closure is controlled by a pressure solution-like process. The aperture of dilatant Fractures and microcracks in the Earth that are similar to those in our experiments, such as ones generated from thermal stressing or brittle failure during earthquake rupture and slip, will decrease rapidly with time, especially if the macroscopic stress is nonhydrostatic.
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stress induced time dependent Fracture Closure at hydrothermal conditions
Journal of Geophysical Research, 2004Co-Authors: N. M. Beeler, Stephen H. HickmanAbstract:[1] Time-dependent Closure of Fractures in quartz was measured in situ at 22–530°C temperature and 0.1–150 MPa water pressure. Unlike previous crack healing and rock permeability studies, in this study, Fracture aperture is monitored directly and continuously using a windowed pressure vessel, a long-working-distance microscope, and reflected-light interferometry. Thus the Fracture volume and geometry can be measured as a function of time, temperature, and water pressure. Relatively uniform Closure occurs rapidly at temperatures and pressures where quartz becomes significantly soluble in water. During Closure the aperture is reduced by as much as 80% in a few hours. We infer that this Closure results from the dissolution of small particles or asperities that prop the Fracture open. The driving force for Closure via dissolution of the prop is the sum of three chemical potential terms: (1) the dissolution potential, proportional to the logarithm of the degree of undersaturation of the solution; (2) the coarsening potential, proportional to the radius of curvature of the prop; and (3) the pressure solution potential, proportional to the effective normal stress at the contact between propping particles and the Fracture wall. Our observations suggest that Closure is controlled by a pressure solution-like process. The aperture of dilatant Fractures and microcracks in the Earth that are similar to those in our experiments, such as ones generated from thermal stressing or brittle failure during earthquake rupture and slip, will decrease rapidly with time, especially if the macroscopic stress is nonhydrostatic.
Omar Abou-sayed - One of the best experts on this subject based on the ideXlab platform.
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Development of an Empirical Equation To Predict Hydraulic-Fracture Closure Pressure From the Instantaneous Shut-In Pressure Using Subsurface Solids-Injection Data
SPE Journal, 2018Co-Authors: S. M. Kholy, I. M. Mohamed, Mehdi Loloi, Omar Abou-sayed, Ahmed S. Abou-sayedAbstract:Summary During hydraulic-fracturing operations, conventional pressure-falloff analyses (G-function, square root of time, and other diagnostic plots) are the main methods for estimating Fracture-Closure pressure. However, there are situations when it is not practical to determine the Fracture-Closure pressure using these analyses. These conditions occur when Closure time is long, such as in mini-Fracture tests in very tight formations, or in slurry-waste-injection applications where the injected waste forms impermeable filter cake on the Fracture faces that delays Fracture Closure because of slower liquid leakoff into the formation. In these situations, applying the conventional analyses could require several days of well shut-in to collect enough pressure-falloff data during which the Fracture Closure can be detected. The objective of the present study is to attempt to correlate the Fracture-Closure pressure to the early-time falloff data using the field-measured instantaneous shut-in pressure (ISIP) and the petrophysical/mechanical properties of the injection formation. A study of the injection-pressure history of many injection wells with multiple hydraulic Fractures in a variety of rock lithologies shows a relationship between the Fracture-Closure pressure and the ISIP. An empirical equation is proposed in this study to calculate the Fracture-Closure pressure as a function of the ISIP and the injection-formation rock properties. Such rock properties include formation permeability, formation porosity, initial pore pressure, overburden stress, formation Poisson's ratio, and Young's modulus. The empirical equation was developed using data obtained from geomechanical models and the core analysis of a wide range of injection horizons with different lithology types of sandstone, carbonate, and tight sandstone. The empirical equation was validated using different case studies by comparing the measured Fracture-Closure-pressure values with those predicted by using the developed empirical equation. In all cases, the new method predicted the Fracture-Closure pressure with a relative error of less than 6%. The new empirical equation predicts the Fracture-Closure pressure using a single point of falloff-pressure data, the ISIP, without the need to conduct a conventional Fracture-Closure analysis. This allows the operator to avoid having to collect pressure data between shut-in and the time when the actual Fracture Closure occurs, which can take several days in highly damaged and/or very tight formations. Moreover, in operations with multiple-batch injection events into the same interval/perforations, as is often the case in cuttings/slurry-injection operations, the trends in Closure-pressure evolution can be tracked even if the Fracture is never allowed to close.
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A New Technique to Predict In-Situ Stress Increment due to Biowaste Slurry Injection into a Sandstone Formation
Journal of Energy Resources Technology-transactions of The Asme, 2018Co-Authors: S. M. Kholy, Ahmed G. Almetwally, I. M. Mohamed, Mehdi Loloi, Ahmed S. Abou-sayed, Omar Abou-sayedAbstract:Underground injection of slurry in cycles with shut-in periods allows Fracture Closure and pressure dissipation which in turn prevents pressure accumulation and injection pressure increase from batch to batch. However, in many cases, the accumulation of solids on the Fracture faces slows down the leak off which can delay the Fracture Closure up to several days. The objective in this study is to develop a new predictive method to monitor the stress increment evolution when well shut-in time between injection batches is not sufficient to allow Fracture Closure. The new technique predicts the Fracture Closure pressure from the instantaneous shut-in pressure (ISIP) and the injection formation petrophysical/mechanical properties including porosity, permeability, overburden stress, formation pore pressure, Young's modulus, and Poisson's ratio. Actual injection pressure data from a biosolids injector have been used to validate the new predictive technique. During the early well life, the match between the predicted Fracture Closure pressure values and those obtained from the G-function analysis was excellent, with an absolute error of less than 1%. In later injection batches, the predicted stress increment profile shows a clear trend consistent with the mechanisms of slurry injection and stress shadow analysis. Furthermore, the work shows that the injection operational parameters such as injection flow rate, injected volume per batch, and the volumetric solids concentration have strong impact on the predicted maximum disposal capacity which is reached when the injection zone in situ stress equalizes the upper barrier stress.
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A New Technique to Predict In-Situ Stress Increment due to Slurry Injection into Sandstone Formations: Case Study from a Biosolids Injector in Los Angeles, California, USA
Day 4 Wed April 25 2018, 2018Co-Authors: S. M. Kholy, Ahmed G. Almetwally, I. M. Mohamed, Mehdi Loloi, Ahmed S. Abou-sayed, Omar Abou-sayedAbstract:Abstract Underground injection of slurry in batches or cycles with shut-in periods allows Fracture Closure and pressure dissipation which in turn prevents pressure accumulation and injection pressure increase from batch to batch. The "G-function" technique is a well-known method for analyzing the pressure fall off data and has been used in monitoring the evolution of formation stress and to identify the Fracture Closure point after each injection batch. However, in many cases the accumulation of solids on the Fracture faces slows down the leak off which can delay the Fracture Closure up to several days. Well shut-in for such a long time between the batches is impractical. The objective of this work is to develop a new predictive method to monitor the stress increment evolution when well shut-in time between injection batches is not sufficient to allow the Fracture to close. The new technique predicts the Fracture Closure pressure based on the knowledge of the instantaneous shut-in pressure (ISIP) and the injection formation petrophysical and mechanical properties including: porosity, permeability, overburden stress, formation pore pressure, Young's modulus, and Poisson's ratio. The injection pressure data from actual biosolids injection operations in Los Angeles, California has been used to validate the new predictive technique. The G-function analysis method was used to identify the Fracture Closure pressure in the early well life before solids accumulation on the Fracture faces slowed the leak off rate. In later injection batches, solids accumulation did not allow Fracture Closure to occur during the well shut-in. Hence, the new technique was successfully used to build the stress increment profile of the injection formation. During the early well life, the match between the predicted Fracture Closure pressure values and those obtained from the G-function analysis was excellent, with an absolute error of less than 1%. In later injection batches, the predicted stress increment profile shows a clear trend consistent with the mechanisms of slurry inj ection and stress shadow analysis. Furthermore, the work shows that the inj ection operational parameters such as injection flow rate, injected volume per batch, and the volumetric solids concentration have strong impact on the predicted maximum disposal capacity which is reached when the injection zone in-situ stress equalizes the upper barrier stress. In addition, the results show that the formation disposal capacity increases when the injection flow rate and the injected volume per batch increase. The new technique helps in predicting the stress increment over time even when the well shut-in duration is shorter than the Fracture Closure time. As a result, safe injection operations can be conducted by assuring that stress increments are within allowable limits without extending the shut-in period after each injection. Another advantage of the technique is that it assists in optimization of the injection parameters to achieve the maximum possible injection capacity of the formation/well.
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Development of an Empirical Equation to Predict Hydraulic Fracture Closure Pressure from the Initial Shut-in Pressure after Treatment
Day 1 Wed September 13 2017, 2017Co-Authors: S. M. Kholy, I. M. Mohamed, Mehdi Loloi, Omar Abou-sayed, Ahmed S. Abou-sayedAbstract:Abstract During hydraulic fracturing operations, conventional pressure fall-off analyses (G-Function, Square Root of Time, and Diagnostic Plots) are the main methods for predicting Fracture Closure pressure. However, there are situations when it is not practical to determine the Fracture Closure pressure using these analyses. These conditions occur when Closure time is long, such as in mini-frac tests in very tight formations, or waste fluid injection in reservoirs where there is low native permeability or where there is significant near wellbore damage. In these situations, it can take several days for the shut-in pressure to stabilize enough for conventional pressure fall-off tests analyses to be used. Thus, the objective of the present study is to attempt to correlate the Fracture Closure pressure to the early time fall off data using the field-measured Initial Shut-in Pressure (ISIP), rock properties and pumped / injection volumes. A study of the injection pressure history of many injection wells with multiple hydraulic Fractures in a variety of rock lithologies shows an interesting relationship between the Fracture Closure pressure and the initial shut-in pressure. An empirical equation has been created to calculate the Fracture Closure pressure as a function of the instantaneous shut-in pressure (ISIP) and the injection formation rock properties. Such rock properties include formation permeability, formation porosity, reservoir pressure, overburden pressure, Poisson's ratio, and Young's modulus. An empirical equation was developed using the injected volumes combined with data obtained from geomechancial models and core analysis of a wide range of injection horizons in terms of lithology type: Sandstone, Carbonate, and Shale. The empirical equation was validated using different case studies by comparing the predicted Fracture Closure pressure calculated using the developed empirical equation to the measured Fracture Closure pressure value. The reported correlation predicted the Fracture Closure pressure with a relative error of less than 6%. Also, the empirical equation was used to predict the Fracture Closure pressure in a shale formation with less than 3% error. The new empirical equation predicts the Fracture Closure pressure using a single point of falloff pressure data, the ISIP, without the need to conduct a conventional Fracture Closure analysis. This allows the operator to avoid having to collect pressure data between shut-in and until the actual Fracture Closure point which can take several days in highly damaged, very tight, and/or shale formations. Moreover, in operations with multiple batch injection events into the same interval / perforations, as is often found cuttings / slurry injection operations, the trends in Closure pressure evolution can be tracked even if the Fracture is never allowed to close.
Jonny Rutqvist - One of the best experts on this subject based on the ideXlab platform.
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Fractured rock stress permeability relationships from in situ data and effects of temperature and chemical mechanical couplings
Geofluids, 2015Co-Authors: Jonny RutqvistAbstract:The purpose of this paper is to (i) review field data on stress-induced permeability changes in Fractured rock; (ii) describe estimation of Fractured rock stress-permeability relationships through model calibration against such field data; and (iii) discuss observations of temperature and chemically mediated Fracture Closure and its effect on Fractured rock permeability. The field data that are reviewed include in situ block experiments, excavation-induced changes in permeability around tunnels, borehole injection experiments, depth (and stress) dependent permeability, and permeability changes associated with a large-scale rock-mass heating experiment. Data show how the stress-permeability relationship of Fractured rock very much depends on local in situ conditions, such as Fracture shear offset and Fracture infilling by mineral precipitation. Field and laboratory experiments involving temperature have shown significant temperature-driven Fracture Closure even under constant stress. Such temperature-driven Fracture Closure has been described as thermal overClosure and relates to better fitting of opposing Fracture surfaces at high temperatures, or is attributed to chemically mediated Fracture Closure related to pressure solution (and compaction) of stressed Fracture surface asperities. Back-calculated stress-permeability relationships from field data may implicitly account for such effects, but the relative contribution of purely thermal-mechanical and chemically mediated changes is difficult to isolate. Therefore, it is concluded that further laboratory and in situ experiments are needed to increase the knowledge of the true mechanisms behind thermally driven Fracture Closure, and to further assess the importance of chemical-mechanical coupling for the long-term evolution of Fractured rock permeability.
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Crustal Permeability - Fractured rock stress–permeability relationships from in situ data and effects of temperature and chemical–mechanical couplings
Geofluids, 2014Co-Authors: Jonny RutqvistAbstract:The purpose of this paper is to (i) review field data on stress-induced permeability changes in Fractured rock; (ii) describe estimation of Fractured rock stress-permeability relationships through model calibration against such field data; and (iii) discuss observations of temperature and chemically mediated Fracture Closure and its effect on Fractured rock permeability. The field data that are reviewed include in situ block experiments, excavation-induced changes in permeability around tunnels, borehole injection experiments, depth (and stress) dependent permeability, and permeability changes associated with a large-scale rock-mass heating experiment. Data show how the stress-permeability relationship of Fractured rock very much depends on local in situ conditions, such as Fracture shear offset and Fracture infilling by mineral precipitation. Field and laboratory experiments involving temperature have shown significant temperature-driven Fracture Closure even under constant stress. Such temperature-driven Fracture Closure has been described as thermal overClosure and relates to better fitting of opposing Fracture surfaces at high temperatures, or is attributed to chemically mediated Fracture Closure related to pressure solution (and compaction) of stressed Fracture surface asperities. Back-calculated stress-permeability relationships from field data may implicitly account for such effects, but the relative contribution of purely thermal-mechanical and chemically mediated changes is difficult to isolate. Therefore, it is concluded that further laboratory and in situ experiments are needed to increase the knowledge of the true mechanisms behind thermally driven Fracture Closure, and to further assess the importance of chemical-mechanical coupling for the long-term evolution of Fractured rock permeability.
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normal stress dependence of Fracture hydraulic properties including two phase flow properties
Hydrogeology Journal, 2013Co-Authors: Jonny RutqvistAbstract:A systematic approach has been developed for determining relationships between normal stress and Fracture hydraulic properties, including two-phase flow properties. The development of a relationship between stress and Fracture permeability (or Fracture aperture and Fracture Closure) is based on a two-part Hooke’s model (TPHM) that captures heterogeneous elastic-deformation processes at a macroscopic scale by conceptualizing the rock mass (or a Fracture) into two parts with different mechanical properties. The developed relationship was verified using a number of datasets in the literature for Fracture Closure versus stress, and satisfactory agreements were obtained. TPHM was previously shown to be able to accurately represent testing data for porous media as well. Based on the consideration that Fracture–aperture distributions under different normal stresses can be represented by truncated-Gaussian distributions, closed-form constitutive relationships were developed between capillary pressure, relative permeability and saturation, for deformable horizontal Fractures. The usefulness of these relationships was demonstrated by their consistency with a laboratory dataset.
N. M. Beeler - One of the best experts on this subject based on the ideXlab platform.
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Stress‐induced, time‐dependent Fracture Closure at hydrothermal conditions
Journal of Geophysical Research, 2004Co-Authors: N. M. Beeler, Stephen H. HickmanAbstract:[1] Time-dependent Closure of Fractures in quartz was measured in situ at 22–530°C temperature and 0.1–150 MPa water pressure. Unlike previous crack healing and rock permeability studies, in this study, Fracture aperture is monitored directly and continuously using a windowed pressure vessel, a long-working-distance microscope, and reflected-light interferometry. Thus the Fracture volume and geometry can be measured as a function of time, temperature, and water pressure. Relatively uniform Closure occurs rapidly at temperatures and pressures where quartz becomes significantly soluble in water. During Closure the aperture is reduced by as much as 80% in a few hours. We infer that this Closure results from the dissolution of small particles or asperities that prop the Fracture open. The driving force for Closure via dissolution of the prop is the sum of three chemical potential terms: (1) the dissolution potential, proportional to the logarithm of the degree of undersaturation of the solution; (2) the coarsening potential, proportional to the radius of curvature of the prop; and (3) the pressure solution potential, proportional to the effective normal stress at the contact between propping particles and the Fracture wall. Our observations suggest that Closure is controlled by a pressure solution-like process. The aperture of dilatant Fractures and microcracks in the Earth that are similar to those in our experiments, such as ones generated from thermal stressing or brittle failure during earthquake rupture and slip, will decrease rapidly with time, especially if the macroscopic stress is nonhydrostatic.
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stress induced time dependent Fracture Closure at hydrothermal conditions
Journal of Geophysical Research, 2004Co-Authors: N. M. Beeler, Stephen H. HickmanAbstract:[1] Time-dependent Closure of Fractures in quartz was measured in situ at 22–530°C temperature and 0.1–150 MPa water pressure. Unlike previous crack healing and rock permeability studies, in this study, Fracture aperture is monitored directly and continuously using a windowed pressure vessel, a long-working-distance microscope, and reflected-light interferometry. Thus the Fracture volume and geometry can be measured as a function of time, temperature, and water pressure. Relatively uniform Closure occurs rapidly at temperatures and pressures where quartz becomes significantly soluble in water. During Closure the aperture is reduced by as much as 80% in a few hours. We infer that this Closure results from the dissolution of small particles or asperities that prop the Fracture open. The driving force for Closure via dissolution of the prop is the sum of three chemical potential terms: (1) the dissolution potential, proportional to the logarithm of the degree of undersaturation of the solution; (2) the coarsening potential, proportional to the radius of curvature of the prop; and (3) the pressure solution potential, proportional to the effective normal stress at the contact between propping particles and the Fracture wall. Our observations suggest that Closure is controlled by a pressure solution-like process. The aperture of dilatant Fractures and microcracks in the Earth that are similar to those in our experiments, such as ones generated from thermal stressing or brittle failure during earthquake rupture and slip, will decrease rapidly with time, especially if the macroscopic stress is nonhydrostatic.
S. M. Kholy - One of the best experts on this subject based on the ideXlab platform.
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Development of an Empirical Equation To Predict Hydraulic-Fracture Closure Pressure From the Instantaneous Shut-In Pressure Using Subsurface Solids-Injection Data
SPE Journal, 2018Co-Authors: S. M. Kholy, I. M. Mohamed, Mehdi Loloi, Omar Abou-sayed, Ahmed S. Abou-sayedAbstract:Summary During hydraulic-fracturing operations, conventional pressure-falloff analyses (G-function, square root of time, and other diagnostic plots) are the main methods for estimating Fracture-Closure pressure. However, there are situations when it is not practical to determine the Fracture-Closure pressure using these analyses. These conditions occur when Closure time is long, such as in mini-Fracture tests in very tight formations, or in slurry-waste-injection applications where the injected waste forms impermeable filter cake on the Fracture faces that delays Fracture Closure because of slower liquid leakoff into the formation. In these situations, applying the conventional analyses could require several days of well shut-in to collect enough pressure-falloff data during which the Fracture Closure can be detected. The objective of the present study is to attempt to correlate the Fracture-Closure pressure to the early-time falloff data using the field-measured instantaneous shut-in pressure (ISIP) and the petrophysical/mechanical properties of the injection formation. A study of the injection-pressure history of many injection wells with multiple hydraulic Fractures in a variety of rock lithologies shows a relationship between the Fracture-Closure pressure and the ISIP. An empirical equation is proposed in this study to calculate the Fracture-Closure pressure as a function of the ISIP and the injection-formation rock properties. Such rock properties include formation permeability, formation porosity, initial pore pressure, overburden stress, formation Poisson's ratio, and Young's modulus. The empirical equation was developed using data obtained from geomechanical models and the core analysis of a wide range of injection horizons with different lithology types of sandstone, carbonate, and tight sandstone. The empirical equation was validated using different case studies by comparing the measured Fracture-Closure-pressure values with those predicted by using the developed empirical equation. In all cases, the new method predicted the Fracture-Closure pressure with a relative error of less than 6%. The new empirical equation predicts the Fracture-Closure pressure using a single point of falloff-pressure data, the ISIP, without the need to conduct a conventional Fracture-Closure analysis. This allows the operator to avoid having to collect pressure data between shut-in and the time when the actual Fracture Closure occurs, which can take several days in highly damaged and/or very tight formations. Moreover, in operations with multiple-batch injection events into the same interval/perforations, as is often the case in cuttings/slurry-injection operations, the trends in Closure-pressure evolution can be tracked even if the Fracture is never allowed to close.
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A New Technique to Predict In-Situ Stress Increment due to Biowaste Slurry Injection into a Sandstone Formation
Journal of Energy Resources Technology-transactions of The Asme, 2018Co-Authors: S. M. Kholy, Ahmed G. Almetwally, I. M. Mohamed, Mehdi Loloi, Ahmed S. Abou-sayed, Omar Abou-sayedAbstract:Underground injection of slurry in cycles with shut-in periods allows Fracture Closure and pressure dissipation which in turn prevents pressure accumulation and injection pressure increase from batch to batch. However, in many cases, the accumulation of solids on the Fracture faces slows down the leak off which can delay the Fracture Closure up to several days. The objective in this study is to develop a new predictive method to monitor the stress increment evolution when well shut-in time between injection batches is not sufficient to allow Fracture Closure. The new technique predicts the Fracture Closure pressure from the instantaneous shut-in pressure (ISIP) and the injection formation petrophysical/mechanical properties including porosity, permeability, overburden stress, formation pore pressure, Young's modulus, and Poisson's ratio. Actual injection pressure data from a biosolids injector have been used to validate the new predictive technique. During the early well life, the match between the predicted Fracture Closure pressure values and those obtained from the G-function analysis was excellent, with an absolute error of less than 1%. In later injection batches, the predicted stress increment profile shows a clear trend consistent with the mechanisms of slurry injection and stress shadow analysis. Furthermore, the work shows that the injection operational parameters such as injection flow rate, injected volume per batch, and the volumetric solids concentration have strong impact on the predicted maximum disposal capacity which is reached when the injection zone in situ stress equalizes the upper barrier stress.
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A New Technique to Predict In-Situ Stress Increment due to Slurry Injection into Sandstone Formations: Case Study from a Biosolids Injector in Los Angeles, California, USA
Day 4 Wed April 25 2018, 2018Co-Authors: S. M. Kholy, Ahmed G. Almetwally, I. M. Mohamed, Mehdi Loloi, Ahmed S. Abou-sayed, Omar Abou-sayedAbstract:Abstract Underground injection of slurry in batches or cycles with shut-in periods allows Fracture Closure and pressure dissipation which in turn prevents pressure accumulation and injection pressure increase from batch to batch. The "G-function" technique is a well-known method for analyzing the pressure fall off data and has been used in monitoring the evolution of formation stress and to identify the Fracture Closure point after each injection batch. However, in many cases the accumulation of solids on the Fracture faces slows down the leak off which can delay the Fracture Closure up to several days. Well shut-in for such a long time between the batches is impractical. The objective of this work is to develop a new predictive method to monitor the stress increment evolution when well shut-in time between injection batches is not sufficient to allow the Fracture to close. The new technique predicts the Fracture Closure pressure based on the knowledge of the instantaneous shut-in pressure (ISIP) and the injection formation petrophysical and mechanical properties including: porosity, permeability, overburden stress, formation pore pressure, Young's modulus, and Poisson's ratio. The injection pressure data from actual biosolids injection operations in Los Angeles, California has been used to validate the new predictive technique. The G-function analysis method was used to identify the Fracture Closure pressure in the early well life before solids accumulation on the Fracture faces slowed the leak off rate. In later injection batches, solids accumulation did not allow Fracture Closure to occur during the well shut-in. Hence, the new technique was successfully used to build the stress increment profile of the injection formation. During the early well life, the match between the predicted Fracture Closure pressure values and those obtained from the G-function analysis was excellent, with an absolute error of less than 1%. In later injection batches, the predicted stress increment profile shows a clear trend consistent with the mechanisms of slurry inj ection and stress shadow analysis. Furthermore, the work shows that the inj ection operational parameters such as injection flow rate, injected volume per batch, and the volumetric solids concentration have strong impact on the predicted maximum disposal capacity which is reached when the injection zone in-situ stress equalizes the upper barrier stress. In addition, the results show that the formation disposal capacity increases when the injection flow rate and the injected volume per batch increase. The new technique helps in predicting the stress increment over time even when the well shut-in duration is shorter than the Fracture Closure time. As a result, safe injection operations can be conducted by assuring that stress increments are within allowable limits without extending the shut-in period after each injection. Another advantage of the technique is that it assists in optimization of the injection parameters to achieve the maximum possible injection capacity of the formation/well.
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Development of an Empirical Equation to Predict Hydraulic Fracture Closure Pressure from the Initial Shut-in Pressure after Treatment
Day 1 Wed September 13 2017, 2017Co-Authors: S. M. Kholy, I. M. Mohamed, Mehdi Loloi, Omar Abou-sayed, Ahmed S. Abou-sayedAbstract:Abstract During hydraulic fracturing operations, conventional pressure fall-off analyses (G-Function, Square Root of Time, and Diagnostic Plots) are the main methods for predicting Fracture Closure pressure. However, there are situations when it is not practical to determine the Fracture Closure pressure using these analyses. These conditions occur when Closure time is long, such as in mini-frac tests in very tight formations, or waste fluid injection in reservoirs where there is low native permeability or where there is significant near wellbore damage. In these situations, it can take several days for the shut-in pressure to stabilize enough for conventional pressure fall-off tests analyses to be used. Thus, the objective of the present study is to attempt to correlate the Fracture Closure pressure to the early time fall off data using the field-measured Initial Shut-in Pressure (ISIP), rock properties and pumped / injection volumes. A study of the injection pressure history of many injection wells with multiple hydraulic Fractures in a variety of rock lithologies shows an interesting relationship between the Fracture Closure pressure and the initial shut-in pressure. An empirical equation has been created to calculate the Fracture Closure pressure as a function of the instantaneous shut-in pressure (ISIP) and the injection formation rock properties. Such rock properties include formation permeability, formation porosity, reservoir pressure, overburden pressure, Poisson's ratio, and Young's modulus. An empirical equation was developed using the injected volumes combined with data obtained from geomechancial models and core analysis of a wide range of injection horizons in terms of lithology type: Sandstone, Carbonate, and Shale. The empirical equation was validated using different case studies by comparing the predicted Fracture Closure pressure calculated using the developed empirical equation to the measured Fracture Closure pressure value. The reported correlation predicted the Fracture Closure pressure with a relative error of less than 6%. Also, the empirical equation was used to predict the Fracture Closure pressure in a shale formation with less than 3% error. The new empirical equation predicts the Fracture Closure pressure using a single point of falloff pressure data, the ISIP, without the need to conduct a conventional Fracture Closure analysis. This allows the operator to avoid having to collect pressure data between shut-in and until the actual Fracture Closure point which can take several days in highly damaged, very tight, and/or shale formations. Moreover, in operations with multiple batch injection events into the same interval / perforations, as is often found cuttings / slurry injection operations, the trends in Closure pressure evolution can be tracked even if the Fracture is never allowed to close.
