Publications of year 1999

Conference articles

S. Akin, L. M. Castanier, and W. E. Brigham. Effect of Temperature on Heavy Oil/Water Relative Permeabilities. In , Bakersfield, CA, USA, March 1999.
[pdf]
Keywords: Relative Permeability, JBN Model, Experimental Work.

Abstract

In the first part of this study, the accuracy of the JBN technique for the determination of heavy oil/water relative permeabilities, and the effect of temperature on relative permeabilities is examined by giving numerical as well as experimental examples. Using the JBN technique leads to a false temperature dependence of relative permeability curves. In the second part, we present unsteady state relative permeability experiments with initial brine saturation at differing temperatures conducted using South Belridge sand and heavy oil. A new three step experimental technique and an analysis procedure were developed to test the effect of temperature on relative permeabilities. In this technique, an ambient temperature unsteady-state relative permeability run is conducted in the first stage, and following that the temperature is increased twice (i.e. 122°F and 150°F). Two phase saturation profiles along the sand pack are measured using a CT scanner. A commercial black oil simulator, coupled with a global optimization code is then used to estimate two phase relative permeabilities. Experimental saturation profiles, differential pressure and recovery data collected from both the ambient and higher temperature data are used in the numerical model. It has been observed that a single set of relative permeability curves can represent both the ambient and high temperature parts of the experiment. This suggests that relative permeability is not a function of temperature at least for the system tested.

BibTex Entry:

@CONFERENCE{SPE54120,
TITLE ={Effect of Temperature on Heavy Oil/Water Relative Permeabilities},
AUTHOR ={S. Akin and L. M. Castanier and W. E. Brigham},
JOURNAL={SPE International Thermal Operations Symposium},
year ={1999},
month =mar,
address ={Bakersfield, CA, USA},
KEYWORDS ={Relative Permeability, JBN Model, Experimental Work},
URL ={http://ekofisk.stanford.edu/supria/publications/public/spe54120.pdf},
ABSTRACT ={In the first part of this study, the accuracy of the JBN technique for the determination of heavy oil/water relative permeabilities, and the effect of temperature on relative permeabilities is examined by giving numerical as well as experimental examples. Using the JBN technique leads to a false temperature dependence of relative permeability curves. In the second part, we present unsteady state relative permeability experiments with initial brine saturation at differing temperatures conducted using South Belridge sand and heavy oil. A new three step experimental technique and an analysis procedure were developed to test the effect of temperature on relative permeabilities. In this technique, an ambient temperature unsteady-state relative permeability run is conducted in the first stage, and following that the temperature is increased twice (i.e. 122°F and 150°F). Two phase saturation profiles along the sand pack are measured using a CT scanner. A commercial black oil simulator, coupled with a global optimization code is then used to estimate two phase relative permeabilities. Experimental saturation profiles, differential pressure and recovery data collected from both the ambient and higher temperature data are used in the numerical model. It has been observed that a single set of relative permeability curves can represent both the ambient and high temperature parts of the experiment. This suggests that relative permeability is not a function of temperature at least for the system tested.},

}

S. Akin and A. R. Kovscek. Imbibition Studies of Low-Permeability Porous Media. In , Anchorage, AK, USA, May 1999.
[pdf]
Keywords: Imbibition, Diatomites, Experimental Work.

Abstract

A systematic investigation of capillary pressure, relative permeability, and fluid flow characteristics within diatomite (a high porosity, low permeability, siliceous rock) is reported. Using an X-ray computerized tomography (CT) scanner, and a specially constructed imbibition cell, we study spontaneous cocurrent water imbibition into diatomite samples at various initial water saturations. Air-water and oil-water systems are used. Despite a marked difference in rock properties between diatomite and sandstone, including permeability and porosity, we find similar trends in saturation profiles and dimensionless weight gain versus time functions. Diatomite is roughly 100 times less permeable than sandstone, yet it imbibes water at rates rivaling sandstone. Importantly, the spontaneous imbibition data when combined with CT-scan images provides a means to determine dynamic relative permeability and capillary pressure functions.

BibTex Entry:

@CONFERENCE{SPE54590,
TITLE ={Imbibition Studies of Low-Permeability Porous Media},
AUTHOR ={S. Akin and A. R. Kovscek},
JOURNAL={SPE Western Regional Meeting},
year ={1999},
month =may,
address ={Anchorage, AK, USA},
KEYWORDS ={Imbibition, Diatomites, Experimental Work},
URL ={http://ekofisk.stanford.edu/supria/publications/public/tr118.pdf},
ABSTRACT ={A systematic investigation of capillary pressure, relative permeability, and fluid flow characteristics within diatomite (a high porosity, low permeability, siliceous rock) is reported. Using an X-ray computerized tomography (CT) scanner, and a specially constructed imbibition cell, we study spontaneous cocurrent water imbibition into diatomite samples at various initial water saturations. Air-water and oil-water systems are used. Despite a marked difference in rock properties between diatomite and sandstone, including permeability and porosity, we find similar trends in saturation profiles and dimensionless weight gain versus time functions. Diatomite is roughly 100 times less permeable than sandstone, yet it imbibes water at rates rivaling sandstone. Importantly, the spontaneous imbibition data when combined with CT-scan images provides a means to determine dynamic relative permeability and capillary pressure functions.},

}

K. T. Elliot and A. R. Kovscek. A Numerical Analysis of the Single-Well Steam Assisted Gravity Drainage Process (SW-SAGD). In , Enghien-les-Bains, France, September 1999.
[pdf]
Keywords: SAGD, Thermal Recovery, Analytical Work.

Abstract

Steam assisted gravity drainage (SAGD) is an effective method to produce heavy oil and bitumen. In a typical SAGD approach, steam is injected into a horizontal well located directly above a horizontal producer. A steam chamber grows around the injection well and helps displace heated oil toward the production well. Single-well (SW) SAGD attempts to create a similar process using only one horizontal well. This may include steam injection from the toe of the horizontal well with production at the heel. To improve early-time response of SW-SAGD, it is necessary to heat the near-wellbore area to reduce oil viscosity and allow gravity drainage to take place. Ideally heating should occur with minimal circulation or bypassing of steam. Since project economics are sensitive to early production response, we have investigated early-time processes to improve reservoir heating. A numerical simulation study was performed to gauge combinations of cyclic steam injection and steam circulation prior to SAGD in an effort to better understand and improve early-time performance. Results from this study, include cumulative recoveries, temperature distributions, and production rates. Variances are displayed within the methods. It is found that cyclic steaming of the reservoir prior to SAGD offers the most favorable option for heating the near-wellbore area to create conditions that improve initial SAGD response. Additionally, a sensitivity analysis was performed with regard to reservoir height, oil viscosity, horizontal to vertical permeability anisotropy, and dead versus live oil. More favorable reservoir conditions such as low viscosity, thick oil zones, and solution gas, improved reservoir response. Under unfavorable conditions, response was limited and could prove to be uneconomical in actual field cases.

BibTex Entry:

@CONFERENCE{S-10,
TITLE ={A Numerical Analysis of the Single-Well Steam Assisted Gravity Drainage Process (SW-SAGD)},
AUTHOR ={K. T. Elliot and A. R. Kovscek},
JOURNAL={20th Annual Workshop and Symposium Collaborative Project on Enhanced Oil Recovery, International Energy Agency},
year ={1999},
month =sep,
address ={Enghien-les-Bains, France},
KEYWORDS ={SAGD, Thermal Recovery, Analytical Work},
URL ={http://ekofisk.stanford.edu/supria/publications/public/ieaswsagd.pdf},
ABSTRACT ={Steam assisted gravity drainage (SAGD) is an effective method to produce heavy oil and bitumen. In a typical SAGD approach, steam is injected into a horizontal well located directly above a horizontal producer. A steam chamber grows around the injection well and helps displace heated oil toward the production well. Single-well (SW) SAGD attempts to create a similar process using only one horizontal well. This may include steam injection from the toe of the horizontal well with production at the heel. To improve early-time response of SW-SAGD, it is necessary to heat the near-wellbore area to reduce oil viscosity and allow gravity drainage to take place. Ideally heating should occur with minimal circulation or bypassing of steam. Since project economics are sensitive to early production response, we have investigated early-time processes to improve reservoir heating. A numerical simulation study was performed to gauge combinations of cyclic steam injection and steam circulation prior to SAGD in an effort to better understand and improve early-time performance. Results from this study, include cumulative recoveries, temperature distributions, and production rates. Variances are displayed within the methods. It is found that cyclic steaming of the reservoir prior to SAGD offers the most favorable option for heating the near-wellbore area to create conditions that improve initial SAGD response. Additionally, a sensitivity analysis was performed with regard to reservoir height, oil viscosity, horizontal to vertical permeability anisotropy, and dead versus live oil. More favorable reservoir conditions such as low viscosity, thick oil zones, and solution gas, improved reservoir response. Under unfavorable conditions, response was limited and could prove to be uneconomical in actual field cases.},

}

K. T. Elliot and A. R. Kovscek. Simulation of Early-Time Response of Single-Well Steam-Assisted Gravity Drainage. In , Anchorage, AK, USA, May 1999.
[pdf]
Keywords: SAGD, Thermal Recovery.

Abstract

Steam assisted gravity drainage (SAGD) is an effective method of producing heavy oil and bitumen. In a typical SAGD approach, steam is injected into a horizontal well located directly above a horizontal producer. A steam chamber grows around the injection well and helps displace heated oil toward the production well. Single-well (SW) SAGD attempts to create a similar process using only one horizontal well. This may include steam injection from the toe of the horizontal well with production at the heel. Obvious advantages of SW-SAGD include cost savings and utility in relatively thin reservoirs. However, the process is technically challenging. To improve early-time response of SW-SAGD, it is necessary to heat the near-wellbore area to reduce oil viscosity and allow gravity drainage to take place. Since project economics are sensitive to early production response, we are interested in optimizing the start-up procedure. An investigation of early-time processes to improve reservoir heating will be discussed. We performed a numerical simulation study of combinations of cyclic steam injection and steam circulation prior to SAGD in an effort to better understand and improve early-time response. Results from this study, including cumulative recoveries, temperature distributions, and production rates display variances within the methods. It is found that cycling steaming of the reservoir prior to SAGD offers the most favorable option for heating the near-wellbore area and creating conditions that will improve initial SAGD response.

BibTex Entry:

@CONFERENCE{SPE54618,
TITLE ={Simulation of Early-Time Response of Single-Well Steam-Assisted Gravity Drainage},
AUTHOR ={K. T. Elliot and A. R. Kovscek},
JOURNAL={SPE Western Regional Meeting},
year ={1999},
month =may,
address ={Anchorage, AK, USA},
KEYWORDS ={SAGD, Thermal Recovery},
URL ={http://ekofisk.stanford.edu/supria/publications/public/spe54618.pdf},
ABSTRACT ={Steam assisted gravity drainage (SAGD) is an effective method of producing heavy oil and bitumen. In a typical SAGD approach, steam is injected into a horizontal well located directly above a horizontal producer. A steam chamber grows around the injection well and helps displace heated oil toward the production well. Single-well (SW) SAGD attempts to create a similar process using only one horizontal well. This may include steam injection from the toe of the horizontal well with production at the heel. Obvious advantages of SW-SAGD include cost savings and utility in relatively thin reservoirs. However, the process is technically challenging. To improve early-time response of SW-SAGD, it is necessary to heat the near-wellbore area to reduce oil viscosity and allow gravity drainage to take place. Since project economics are sensitive to early production response, we are interested in optimizing the start-up procedure. An investigation of early-time processes to improve reservoir heating will be discussed. We performed a numerical simulation study of combinations of cyclic steam injection and steam circulation prior to SAGD in an effort to better understand and improve early-time response. Results from this study, including cumulative recoveries, temperature distributions, and production rates display variances within the methods. It is found that cycling steaming of the reservoir prior to SAGD offers the most favorable option for heating the near-wellbore area and creating conditions that will improve initial SAGD response.},

}

E. R. Rangel-German, S. Akin, and L. M. Castanier. Multiphase Flow Properties of Fractured Porous Media. In , Anchorage, AK, USA, May 1999.
[pdf]
Keywords: Fractures, Experimental Work, Imbibition.

Abstract

The fluid transfer parameters between matrix and fracture are not well known. Consequently, simulation of fractured reservoirs uses, in general, very crude and unproved hypothesis such as zero capillary pressure in the fracture and/or relative permeability functions that are linear with saturation. In order to improve the understanding of flow in fractured media, an experimental study was conducted and numerical simulation used to interpret experimental results. A laboratory flow apparatus was built to obtain data on water-air imbibition and oil-water drainage displacements in fractured sandstone systems. During the experiments, porosity and saturation were measured along the core utilizing a Computerized Tomography (CT) scanner. Saturation images were reconstructed in 3-D to observe how matrix-fracture interaction occurred. Differences in fluid saturations and relative permeabilities caused by changes of fracture width have also been analyzed. In the case of water-air imbibition, fracture systems with narrower fracture apertures showed more stable fronts and slower water breakthrough than the wide fracture systems. However, the final water saturation was higher in wide fracture systems, thus showing that capillary pressure in the narrow fracture has more effect on fluid distribution in the matrix. During oil-water drainage, oil saturations were higher in the blocks near the thin fracture, again showing the effect of fracture capillary pressure. Oil fingering was observed in the wide fracture. Fine-grid simulations of the experiments using a commercial reservoir simulator were performed. Relative permeability and capillary pressure curves were obtained by history matching the experiments. The results showed that the assumption of fracture relative permeability equal to phase saturation is incorrect. We found that both capillary and viscous forces affect the process. The matrix capillary pressure obtained by matching an experiment showed lower values than reported in the literature.

BibTex Entry:

@CONFERENCE{SPE54591,
TITLE ={Multiphase Flow Properties of Fractured Porous Media},
AUTHOR ={E. R. Rangel-German and S. Akin and L. M. Castanier},
JOURNAL={SPE Western Regional Meeting},
year ={1999},
month =may,
address ={Anchorage, AK, USA},
KEYWORDS ={Fractures, Experimental Work, Imbibition},
URL ={http://ekofisk.stanford.edu/supria/publications/public/tr118.pdf},
ABSTRACT ={The fluid transfer parameters between matrix and fracture are not well known. Consequently, simulation of fractured reservoirs uses, in general, very crude and unproved hypothesis such as zero capillary pressure in the fracture and/or relative permeability functions that are linear with saturation. In order to improve the understanding of flow in fractured media, an experimental study was conducted and numerical simulation used to interpret experimental results. A laboratory flow apparatus was built to obtain data on water-air imbibition and oil-water drainage displacements in fractured sandstone systems. During the experiments, porosity and saturation were measured along the core utilizing a Computerized Tomography (CT) scanner. Saturation images were reconstructed in 3-D to observe how matrix-fracture interaction occurred. Differences in fluid saturations and relative permeabilities caused by changes of fracture width have also been analyzed. In the case of water-air imbibition, fracture systems with narrower fracture apertures showed more stable fronts and slower water breakthrough than the wide fracture systems. However, the final water saturation was higher in wide fracture systems, thus showing that capillary pressure in the narrow fracture has more effect on fluid distribution in the matrix. During oil-water drainage, oil saturations were higher in the blocks near the thin fracture, again showing the effect of fracture capillary pressure. Oil fingering was observed in the wide fracture. Fine-grid simulations of the experiments using a commercial reservoir simulator were performed. Relative permeability and capillary pressure curves were obtained by history matching the experiments. The results showed that the assumption of fracture relative permeability equal to phase saturation is incorrect. We found that both capillary and viscous forces affect the process. The matrix capillary pressure obtained by matching an experiment showed lower values than reported in the literature.},

}

Internal reports

W. E. Brigham, A. R. Kovscek, and L. M. Castanier. Research on Oil Recovery Mechanisms in Heavy Oil Reservoirs, Final Report 1996 to 1999.. Technical report, Stanford University, CA, USA, 1999.
[pdf]
Keywords: Reservoir Definition, In-Situ Combustion, Heavy Oil, Steam, EOR, Thermal Recovery.

Abstract

Supri-A yearly research report.

BibTex Entry:

@TECHREPORT{TR121,
TITLE ={Research on Oil Recovery Mechanisms in Heavy Oil Reservoirs, Final Report 1996 to 1999.},
AUTHOR ={W. E. Brigham and A. R. Kovscek and L. M. Castanier},
YEAR ={1999},
INSTITUTION ={Stanford University, CA, USA},
KEYWORDS ={Reservoir Definition, In-Situ Combustion,Heavy Oil,Steam,EOR, Thermal Recovery},
URL ={http://ekofisk.stanford.edu/supria/publications/public/tr121.pdf},
ABSTRACT ={Supri-A yearly research report.},

}

W. E. Brigham, A. R. Kovscek, and L. M. Castanier. SUPRI Heavy Oil Research Program Twenty Second Annual Report.. Technical report, Stanford University, CA, USA, 1999.
[pdf]
Keywords: Reservoir Definition, In-Situ Combustion, Heavy Oil, Steam, EOR, Formation Evaluation.

Abstract

Supri-A yearly research report.

BibTex Entry:

@TECHREPORT{TR117,
TITLE ={SUPRI Heavy Oil Research Program Twenty Second Annual Report.},
AUTHOR ={W. E. Brigham and A. R. Kovscek and L. M. Castanier},
YEAR ={1999},
INSTITUTION ={Stanford University, CA, USA},
KEYWORDS ={Reservoir Definition, In-Situ Combustion,Heavy Oil,Steam,EOR,Formation Evaluation},
URL ={http://ekofisk.stanford.edu/supria/publications/public/tr117.pdf},
ABSTRACT ={Supri-A yearly research report.},

}

U. K. Diwan and A. R. Kovscek. An Analytical Model for Simulating Heavy-Oil Recovery by Cyclic Steam Injection Using Horizontal Wells. Technical report, Stanford University, CA, USA, July 1999.
[pdf]
Keywords: Thermal Recovery, Steam, Analytical Work, Horizontal Wells.

Abstract

In this investigation, existing analytical models for cyclic steam injection and oil recovery are reviewed and a new model is proposed that is applicable to horizontal wells. A new flow equation is developed for oil production during cyclic steaming of horizontal wells. The model accounts for the gravitydrainage of oil along the steam-oil interface and through the steam zone. Oil viscosity, effective permeability, geometry of the heated zone, porosity, mobile oil saturation, and thermal diffusivity of the reservoir influence the flow rate of oil in the model. The change in reservoir temperature with time is also modeled, and it results in the expected decline in oil production rate during the production cycle as the reservoir cools. Wherever appropriate, correlations are incorporated to minimize data requirements. A limited comparison to numerical simulation results agrees well, indicating that essential physics are successfully captured. Cyclic steaming appears to be a systematic method for heating a cold reservoir provided that a relatively uniform distribution of steam is obtained along the horizontal well during injection. A sensitivity analysis shows that the process is robust over the range of expected physical parameters.

BibTex Entry:

@TECHREPORT{TR118,
TITLE ={An Analytical Model for Simulating Heavy-Oil Recovery by Cyclic Steam Injection Using Horizontal Wells},
AUTHOR ={U. K. Diwan and A. R. Kovscek},
YEAR ={1999},
MONTH =jul,
INSTITUTION = {Stanford University, CA, USA},
KEYWORDS ={Thermal Recovery, Steam, Analytical Work, Horizontal Wells},
URL ={http://ekofisk.stanford.edu/supria/publications/public/tr118.pdf},
ABSTRACT ={In this investigation, existing analytical models for cyclic steam injection and oil recovery are reviewed and a new model is proposed that is applicable to horizontal wells. A new flow equation is developed for oil production during cyclic steaming of horizontal wells. The model accounts for the gravitydrainage of oil along the steam-oil interface and through the steam zone. Oil viscosity, effective permeability, geometry of the heated zone, porosity, mobile oil saturation, and thermal diffusivity of the reservoir influence the flow rate of oil in the model. The change in reservoir temperature with time is also modeled, and it results in the expected decline in oil production rate during the production cycle as the reservoir cools. Wherever appropriate, correlations are incorporated to minimize data requirements. A limited comparison to numerical simulation results agrees well, indicating that essential physics are successfully captured. Cyclic steaming appears to be a systematic method for heating a cold reservoir provided that a relatively uniform distribution of steam is obtained along the horizontal well during injection. A sensitivity analysis shows that the process is robust over the range of expected physical parameters.},

}

K. E. Elliot and A. R. Kovscek. Computer Simulation of Single-Well Steam Assisted Gravity Drainage (SW-SAGD). Technical report, Stanford University, CA, USA, July 1999.
[pdf]
Keywords: SAGD, Thermal Recovery, Heavy Oil.

Abstract

Steam assisted gravity drainage (SAGD) is an effective method of producing heavy oil and bitumen. In a typical SAGD approach, steam is injected into a horizontal well located directly above a horizontal producer. A steam chamber grows around the injection well and helps displace heated oil toward the production well. Single-well (SW) SAGD attempts to create a similar process using only one horizontal well. This may include steam injection from the toe of the horizontal well with production at the heel. Obvious advantages of SW-SAGD include cost savings and utility in relatively thin reservoirs. However, the process is technically challenging. To improve early-time response of SW-SAGD, it is necessary to heat the nearwellbore area to reduce oil viscosity and allow gravity drainage to take place. Ideally heating should occur with minimal circulation or bypassing of steam. Since project economics are sensitive to early production response, we are interested in optimizing the start-up procedure. An investigation of early-time processes to improve reservoir heating will be discussed. We performed a numerical simulation study of combinations of cyclic steam injection and steam circulation prior to SAGD in an effort to better understand and improve early-time response. Results from this study, including cumulative recoveries, temperature distributions, and production rates, display variances within the methods. It is found that cyclic steaming of the reservoir prior to SAGD offers the most favorable option for heating the near-wellbore area and creating conditions that will improve initial SAGD response.

BibTex Entry:

@TECHREPORT{TR119,
TITLE ={Computer Simulation of Single-Well Steam Assisted Gravity Drainage (SW-SAGD)},
AUTHOR ={K. E. Elliot and A. R. Kovscek},
YEAR ={1999},
MONTH =jul,
INSTITUTION ={Stanford University, CA, USA},
KEYWORDS ={SAGD, Thermal Recovery, Heavy Oil},
URL ={http://ekofisk.stanford.edu/supria/publications/public/tr119.pdf},
ABSTRACT ={Steam assisted gravity drainage (SAGD) is an effective method of producing heavy oil and bitumen. In a typical SAGD approach, steam is injected into a horizontal well located directly above a horizontal producer. A steam chamber grows around the injection well and helps displace heated oil toward the production well. Single-well (SW) SAGD attempts to create a similar process using only one horizontal well. This may include steam injection from the toe of the horizontal well with production at the heel. Obvious advantages of SW-SAGD include cost savings and utility in relatively thin reservoirs. However, the process is technically challenging. To improve early-time response of SW-SAGD, it is necessary to heat the nearwellbore area to reduce oil viscosity and allow gravity drainage to take place. Ideally heating should occur with minimal circulation or bypassing of steam. Since project economics are sensitive to early production response, we are interested in optimizing the start-up procedure. An investigation of early-time processes to improve reservoir heating will be discussed. We performed a numerical simulation study of combinations of cyclic steam injection and steam circulation prior to SAGD in an effort to better understand and improve early-time response. Results from this study, including cumulative recoveries, temperature distributions, and production rates, display variances within the methods. It is found that cyclic steaming of the reservoir prior to SAGD offers the most favorable option for heating the near-wellbore area and creating conditions that will improve initial SAGD response.},

}

E. R. Rangel-German, L. M. Castanier, and S. Akin.. An Experimental and Theoretical Investigation of Multi- Phase Flow in Fractured Porous Media. Technical report, Stanford University, CA, USA, June 1999.
[pdf]
Keywords: Experimental Work, Fractures, Tomography.

Abstract

The fluid transfer parameters between rock matrix and fracture are not well known. Consequently, simulation of fractured reservoirs uses, in general, very crude and unproven hypotheses such as zero capillary pressure in the fracture and/or relative permeability linear with saturation. In order to improve the understanding of flow in fractured media, an experimental study was conducted and numerical simulations of the experiments were made. A laboratory flow apparatus was built to obtain data on water-air imbibition and oil-water drainage displacements in horizontal single-fractured block systems. For this purpose, two configurations have been used: a two-block system with a 1mm spacer between the blocks, and a two-block system with no spacer. During the experiments, porosity and saturation measurements along the cores have been made utilizing an X-ray Computerized Tomography (CT) scanner. Saturation images were reconstructed in 3-D to observe matrix-fracture interactions. Differences in fluid saturations and relative permeabilities caused by changes in fracture width have also been analyzed. In the case of water-air imbibition, the thin fracture system showed a more stable front and faster breakthrough than the wide fracture system. However, the final water saturation was higher in the blocks near the wide fracture, thus showing that capillary pressure in the narrow fracture has more effect. During oil-water drainage, oil saturations were higher in the blocks near the thin fracture, again showing the effect of fracture capillary pressure. Oil fingering was observed in the wide fracture. Simulations of the experiments have been performed using a commercial reservoir simulator. Relative permeability and capillary pressure curves were obtained by history matching the experiments. Sensitivity analysis of parameters such as fracture relative permeability, capillary pressure in the fracture, and fracture width were also conducted. The results showed that the assumption of fracture relative permeability equal to phase saturation is incorrect. Moreover, higher resistance in the fractures was observed by comparing the experiments with numerical simulation work. We found that the processes are dominated by both capillary and viscous forces.

BibTex Entry:

@TECHREPORT{TR116,
TITLE ={An Experimental and Theoretical Investigation of Multi- Phase Flow in Fractured Porous Media},
AUTHOR ={E. R. Rangel-German and L. M. Castanier and S. Akin.},
YEAR ={1999},
MONTH =jun,
INSTITUTION = {Stanford University, CA, USA},
KEYWORDS ={Experimental Work, Fractures, Tomography},
URL ={http://ekofisk.stanford.edu/supria/publications/public/tr116.pdf},
ABSTRACT ={The fluid transfer parameters between rock matrix and fracture are not well known. Consequently, simulation of fractured reservoirs uses, in general, very crude and unproven hypotheses such as zero capillary pressure in the fracture and/or relative permeability linear with saturation. In order to improve the understanding of flow in fractured media, an experimental study was conducted and numerical simulations of the experiments were made. A laboratory flow apparatus was built to obtain data on water-air imbibition and oil-water drainage displacements in horizontal single-fractured block systems. For this purpose, two configurations have been used: a two-block system with a 1mm spacer between the blocks, and a two-block system with no spacer. During the experiments, porosity and saturation measurements along the cores have been made utilizing an X-ray Computerized Tomography (CT) scanner. Saturation images were reconstructed in 3-D to observe matrix-fracture interactions. Differences in fluid saturations and relative permeabilities caused by changes in fracture width have also been analyzed. In the case of water-air imbibition, the thin fracture system showed a more stable front and faster breakthrough than the wide fracture system. However, the final water saturation was higher in the blocks near the wide fracture, thus showing that capillary pressure in the narrow fracture has more effect. During oil-water drainage, oil saturations were higher in the blocks near the thin fracture, again showing the effect of fracture capillary pressure. Oil fingering was observed in the wide fracture. Simulations of the experiments have been performed using a commercial reservoir simulator. Relative permeability and capillary pressure curves were obtained by history matching the experiments. Sensitivity analysis of parameters such as fracture relative permeability, capillary pressure in the fracture, and fracture width were also conducted. The results showed that the assumption of fracture relative permeability equal to phase saturation is incorrect. Moreover, higher resistance in the fractures was observed by comparing the experiments with numerical simulation work. We found that the processes are dominated by both capillary and viscous forces.},

}

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Publications of year 1999

Conference articles

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Internal reports

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