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Roberto Aguilera - One of the best experts on this subject based on the ideXlab platform.

  • Use of Dynamic Data and a New Material-Balance Equation for Estimating Average Reservoir Pressure, Original Gas in Place, and Optimal Well Spacing in Shale Gas Reservoirs
    SPE Reservoir Evaluation & Engineering, 2018
    Co-Authors: Daniel Orozco, Roberto Aguilera
    Abstract:

    Summary The average reservoir pressure is a key parameter in Material-Balance calculations, but its determination is challenging when dealing with shales because of their low and ultralow permeabilities. This paper presents an easy-to-reproduce methodology for calculating the average reservoir pressure from flowing data, and its use in a new Material-Balance Equation (MBE) that considers the simultaneous contribution of free, adsorbed, and dissolved gas. The procedure developed in this paper uses a modified gas-compressibility factor (Z′) introduced in the new MBE. Because Z′ accounts for the combined effect of free, adsorbed, and dissolved gas, then total original gas in place (OGIP) can be determined from extrapolation of the MBE straight line to an average reservoir pressure equal to zero. Drainage area can be estimated on the basis of calculated OGIP and volumetric Equations. As such, the methodology offers the potential to help improve well spacing in shale gas reservoirs in such a way that no stranded gas is left in the reservoir, or that excess wells are not drilled in the field. This can help to improve recoveries from shales by assisting in the determination of the optimal number of wells needed to drain a given play efficiently. In conventional reservoirs, a well is shut in, and the average reservoir pressure is determined from the corresponding pressure-buildup test. But, for the case of unconventional shale gas reservoirs, shutting the wells in is unacceptable because of the long time it would require for estimating average reservoir pressure. The methodology developed in this paper for shale gas reservoirs circumvents this problem by using dynamic data. Production data from multistage hydraulically fractured horizontal wells completed in a Canadian shale gas reservoir are used for testing the effectiveness of the new methodology. Comparison of typical well-spacing values vs. the drainage area calculated with the new methodology leads to the conclusion that, probably, only 40% of the gas is being drained efficiently. The novelty of this work relies on the development of a methodology for calculating average reservoir pressure, OGIP, drainage area, and optimal well spacing in shale reservoirs through the combination of dynamic data and a new MBE that considers simultaneously the effects of free, adsorbed, and dissolved gas.

  • A Material-Balance Equation for Stress-Sensitive Shale-Gas-Condensate Reservoirs
    SPE Reservoir Evaluation & Engineering, 2016
    Co-Authors: Daniel Orozco, Roberto Aguilera
    Abstract:

    Summary During the last few years, production of liquid hydrocarbons has been reported from the gas-condensate window of the Eagle Ford, Barnett, Niobrara, and Marcellus shale plays in the US. This paper presents a new Material-Balance Equation (MBE) for estimation of original gas in place (OGIP) and original condensate in place (OCIP) in shale-gas-condensate reservoirs. This Material-Balance methodology allows estimating the critical time for implementing gas injection in those cases in which condensate buildup represents a problem. In addition, the proposed MBE considers the effects of free, adsorbed, and dissolved gas-condensate production, and also takes into account the stress-dependency of porosity and permeability. An extension of the methodology is implemented for estimating the optimum time for hydraulically refracturing shale-condensate reservoirs. The new MBE applies to shale-gas-condensate reservoirs by incorporating a two-phase gas-deviation factor (Z2) and total cumulative gas production (Gpt) that includes both gas and condensate. If a crossplot of P/Z2 (pressure/Z2) vs. Gpt is prepared for a conventional gas-condensate reservoir, a single straight line is obtained. However, when the single-phase gas-compressibility factor (Z) is used, a deviation from the linear behavior is observed after the reservoir pressure falls below the gas dewpoint. This methodology is applied in this study to unconventional shale-gas condensate. Because there are three characteristic stages of production in a shale-gas reservoir (production of free, adsorbed, and dissolved gas), the location of the aforementioned deviation will provide a hint of the production stage that will be affected by condensate buildup. For example, if the deviation point is in the region where production of free gas is predominant, then the production caused by desorption mechanisms will be negatively affected because condensation will have already occurred in the reservoir, resulting in reduction of effective permeability to gas. This methodology then allows estimating the critical time for implementing gas injection on the basis of the total cumulative gas production. The method also permits estimating the optimum time for refracturing. The refracturing can be of a normal size for a given shale (similar to the original fracturing job), or it can be a superfrac job. Results are presented as crossplots of (1) P/Z2 vs. Gpt, (2) Gpt vs. time, and (3) gas rate vs. time. It is concluded that estimation of the critical time for implementing gas injection is useful for improving the performance of those shale-gas-condensate reservoirs in which condensate buildup represents a threat that can negatively affect the gas-production rate. The novelty of this work resides on the fact that the combined effect of free, adsorbed, and dissolved gas-production mechanisms on stress-sensitive shale-gas-condensate reservoirs had not been considered previously in the literature for estimation of OGIP, OCIP, and reservoir performance with an analytical MBE. The inclusion of gas injection and refracturing had not been considered either.

  • A Material Balance Equation for Stress-Sensitive Shale Gas Condensate Reservoirs
    Day 1 Wed November 18 2015, 2015
    Co-Authors: Daniel Orozco, Roberto Aguilera
    Abstract:

    Abstract During the last few years, production of liquid hydrocarbons has been reported from the gas-condensate window of the Eagle Ford, Barnett, Niobrara and Marcellus shale plays in the US. This paper presents a new Material Balance Equation (MBE) for estimation of Original Gas in Place (OGIP) and Original Condensate in Place (OCIP) in shale gas condensate reservoirs. This Material Balance methodology allows estimating the critical time for implementing gas injection in those cases where condensate buildup represents a problem. Additionally, the proposed MBE considers the effects of free, adsorbed and dissolved gas condensate production, and also takes into-account the stress-dependency of porosity and permeability. An extension of the methodology is implemented for estimating the optimum time for hydraulically re-fracturing shale condensate reservoirs. The new MBE applies to shale gas condensate reservoirs by incorporating a two-phase gas deviation factor (Z2) and total cumulative gas production (Gpt) that includes both gas and condensate. If a crossplot of P/Z2 (pressure/Z2) vs. Gpt is prepared for a conventional gas condensate reservoir, a single straight line is obtained. However, when the single-phase gas compressibility factor (Z) is used, a deviation from the linear behavior is observed once the reservoir pressure falls below the gas dew-point. This methodology is applied in this study to unconventional shale gas condensate. Since there are three characteristic stages of production in a shale gas reservoir (production of free, adsorbed and dissolved gas), the location of the aforementioned deviation will provide a hint of the production stage that will be affected by condensate buildup. For example, if the deviation point is located in the region where production of free gas is predominant, then the production due to desorption mechanisms will be negatively impacted because condensation will have already occurred in the reservoir, resulting on reduction of effective permeability to gas. This methodology allows then estimating the critical time for implementing gas injection on the basis of the total cumulative gas production. Results are presented as crossplots of 1) P/Z2 vs. Gpt, 2) Gpt vs. time and 3) gas rate vs. time. It is concluded that estimation of the critical time for implementing gas injection is useful for improving the performance of those shale gas condensate reservoirs where condensate buildup represents a threat that can negatively impact the gas production rate. The novelty of this work resides on the fact that the combined effect of free, adsorbed and dissolved gas production mechanisms on stress-sensitive shale gas condensate reservoirs has not been considered previously in the literature for estimation of OGIP and OCIP using an analytical MBE.

  • A Material Balance Equation for Stress-Sensitive Shale Gas Reservoirs Considering the Contribution of Free, Adsorbed and Dissolved Gas
    Day 2 Wed October 21 2015, 2015
    Co-Authors: Daniel Orozco, Roberto Aguilera
    Abstract:

    Abstract Unconventional shale gas reservoirs around the world have been proven to store gigantic volumes of natural gas. It has been demonstrated with both laboratory and mathematical work that these reservoirs can be represented by a quintuple porosity formulation plus an additional storage mechanism provided by dissolved gas in kerogen. All these storage mechanisms must be considered for estimation of original gas in place (OGIP). Otherwise pessimistic values of OGIP and recoveries will be obtained by ignoring any of these mechanisms. This paper presents a new easy-to-use Material Balance Equation (MBE) for shale gas reservoirs that considers the contribution of free, adsorbed and dissolved gas and their effects on cumulative gas production. Furthermore the proposed MBE takes into account the stress-dependency of permeability and porosity as the reservoir is depleted. Aguilera (2008) formulated a MBE to account for the effect of fracture compressibility on OGIP determination in stress-sensitive naturally fractured reservoirs. Cabrapan et al. (2014) extended the method by incorporating adsorption in shale gas reservoirs. The authors used the Langmuir Adsorption theory for quantifying the adsorbed gas volume as a function of average reservoir pressure. In this paper, the method is further extended to include the effect of production by diffusion of dissolved gas from kerogen. The volume of dissolved gas depends on the total fractional volume of kerogen in shale and the methane concentration in the kerogen body, which is in turn a function of pressure and temperature, as proposed by Swami et al. (2013). Results are presented as crossplots of P/Z (pressure/gas deviation factor) vs. Gp (cumulative gas production), Gp vs. time and gas rate vs. time. The plots allow detecting four stages of production in a shale gas reservoir: 1) production of free gas from fractures and organic porosity, 2) production of free gas from the inorganic matrix when fractures start closing, 3) production by desorption from the organic Material and 4) production by diffusion of dissolved gas. The same trends have been observed in Devonian Shales of the Appalachian Basin where long production histories are available. It is concluded that dissolved gas is not only an additional storage mechanism but it also provides an important pressure and production contribution in shale reservoirs. The new consideration introduced in the MBE proposed in this paper is of importance because although diffusion from kerogen in shale gas reservoirs is by nature a slow process, it provides long term production rates with relatively small declines. To the best of our knowledge, an analytical MBE that includes simultaneously stress-dependent porosity and permeability, free gas, adsorbed gas and dissolved gas has not been published previously in the literature.

Daniel Orozco - One of the best experts on this subject based on the ideXlab platform.

  • Use of Dynamic Data and a New Material-Balance Equation for Estimating Average Reservoir Pressure, Original Gas in Place, and Optimal Well Spacing in Shale Gas Reservoirs
    SPE Reservoir Evaluation & Engineering, 2018
    Co-Authors: Daniel Orozco, Roberto Aguilera
    Abstract:

    Summary The average reservoir pressure is a key parameter in Material-Balance calculations, but its determination is challenging when dealing with shales because of their low and ultralow permeabilities. This paper presents an easy-to-reproduce methodology for calculating the average reservoir pressure from flowing data, and its use in a new Material-Balance Equation (MBE) that considers the simultaneous contribution of free, adsorbed, and dissolved gas. The procedure developed in this paper uses a modified gas-compressibility factor (Z′) introduced in the new MBE. Because Z′ accounts for the combined effect of free, adsorbed, and dissolved gas, then total original gas in place (OGIP) can be determined from extrapolation of the MBE straight line to an average reservoir pressure equal to zero. Drainage area can be estimated on the basis of calculated OGIP and volumetric Equations. As such, the methodology offers the potential to help improve well spacing in shale gas reservoirs in such a way that no stranded gas is left in the reservoir, or that excess wells are not drilled in the field. This can help to improve recoveries from shales by assisting in the determination of the optimal number of wells needed to drain a given play efficiently. In conventional reservoirs, a well is shut in, and the average reservoir pressure is determined from the corresponding pressure-buildup test. But, for the case of unconventional shale gas reservoirs, shutting the wells in is unacceptable because of the long time it would require for estimating average reservoir pressure. The methodology developed in this paper for shale gas reservoirs circumvents this problem by using dynamic data. Production data from multistage hydraulically fractured horizontal wells completed in a Canadian shale gas reservoir are used for testing the effectiveness of the new methodology. Comparison of typical well-spacing values vs. the drainage area calculated with the new methodology leads to the conclusion that, probably, only 40% of the gas is being drained efficiently. The novelty of this work relies on the development of a methodology for calculating average reservoir pressure, OGIP, drainage area, and optimal well spacing in shale reservoirs through the combination of dynamic data and a new MBE that considers simultaneously the effects of free, adsorbed, and dissolved gas.

  • A Material-Balance Equation for Stress-Sensitive Shale-Gas-Condensate Reservoirs
    SPE Reservoir Evaluation & Engineering, 2016
    Co-Authors: Daniel Orozco, Roberto Aguilera
    Abstract:

    Summary During the last few years, production of liquid hydrocarbons has been reported from the gas-condensate window of the Eagle Ford, Barnett, Niobrara, and Marcellus shale plays in the US. This paper presents a new Material-Balance Equation (MBE) for estimation of original gas in place (OGIP) and original condensate in place (OCIP) in shale-gas-condensate reservoirs. This Material-Balance methodology allows estimating the critical time for implementing gas injection in those cases in which condensate buildup represents a problem. In addition, the proposed MBE considers the effects of free, adsorbed, and dissolved gas-condensate production, and also takes into account the stress-dependency of porosity and permeability. An extension of the methodology is implemented for estimating the optimum time for hydraulically refracturing shale-condensate reservoirs. The new MBE applies to shale-gas-condensate reservoirs by incorporating a two-phase gas-deviation factor (Z2) and total cumulative gas production (Gpt) that includes both gas and condensate. If a crossplot of P/Z2 (pressure/Z2) vs. Gpt is prepared for a conventional gas-condensate reservoir, a single straight line is obtained. However, when the single-phase gas-compressibility factor (Z) is used, a deviation from the linear behavior is observed after the reservoir pressure falls below the gas dewpoint. This methodology is applied in this study to unconventional shale-gas condensate. Because there are three characteristic stages of production in a shale-gas reservoir (production of free, adsorbed, and dissolved gas), the location of the aforementioned deviation will provide a hint of the production stage that will be affected by condensate buildup. For example, if the deviation point is in the region where production of free gas is predominant, then the production caused by desorption mechanisms will be negatively affected because condensation will have already occurred in the reservoir, resulting in reduction of effective permeability to gas. This methodology then allows estimating the critical time for implementing gas injection on the basis of the total cumulative gas production. The method also permits estimating the optimum time for refracturing. The refracturing can be of a normal size for a given shale (similar to the original fracturing job), or it can be a superfrac job. Results are presented as crossplots of (1) P/Z2 vs. Gpt, (2) Gpt vs. time, and (3) gas rate vs. time. It is concluded that estimation of the critical time for implementing gas injection is useful for improving the performance of those shale-gas-condensate reservoirs in which condensate buildup represents a threat that can negatively affect the gas-production rate. The novelty of this work resides on the fact that the combined effect of free, adsorbed, and dissolved gas-production mechanisms on stress-sensitive shale-gas-condensate reservoirs had not been considered previously in the literature for estimation of OGIP, OCIP, and reservoir performance with an analytical MBE. The inclusion of gas injection and refracturing had not been considered either.

  • A Material Balance Equation for Stress-Sensitive Shale Gas Condensate Reservoirs
    Day 1 Wed November 18 2015, 2015
    Co-Authors: Daniel Orozco, Roberto Aguilera
    Abstract:

    Abstract During the last few years, production of liquid hydrocarbons has been reported from the gas-condensate window of the Eagle Ford, Barnett, Niobrara and Marcellus shale plays in the US. This paper presents a new Material Balance Equation (MBE) for estimation of Original Gas in Place (OGIP) and Original Condensate in Place (OCIP) in shale gas condensate reservoirs. This Material Balance methodology allows estimating the critical time for implementing gas injection in those cases where condensate buildup represents a problem. Additionally, the proposed MBE considers the effects of free, adsorbed and dissolved gas condensate production, and also takes into-account the stress-dependency of porosity and permeability. An extension of the methodology is implemented for estimating the optimum time for hydraulically re-fracturing shale condensate reservoirs. The new MBE applies to shale gas condensate reservoirs by incorporating a two-phase gas deviation factor (Z2) and total cumulative gas production (Gpt) that includes both gas and condensate. If a crossplot of P/Z2 (pressure/Z2) vs. Gpt is prepared for a conventional gas condensate reservoir, a single straight line is obtained. However, when the single-phase gas compressibility factor (Z) is used, a deviation from the linear behavior is observed once the reservoir pressure falls below the gas dew-point. This methodology is applied in this study to unconventional shale gas condensate. Since there are three characteristic stages of production in a shale gas reservoir (production of free, adsorbed and dissolved gas), the location of the aforementioned deviation will provide a hint of the production stage that will be affected by condensate buildup. For example, if the deviation point is located in the region where production of free gas is predominant, then the production due to desorption mechanisms will be negatively impacted because condensation will have already occurred in the reservoir, resulting on reduction of effective permeability to gas. This methodology allows then estimating the critical time for implementing gas injection on the basis of the total cumulative gas production. Results are presented as crossplots of 1) P/Z2 vs. Gpt, 2) Gpt vs. time and 3) gas rate vs. time. It is concluded that estimation of the critical time for implementing gas injection is useful for improving the performance of those shale gas condensate reservoirs where condensate buildup represents a threat that can negatively impact the gas production rate. The novelty of this work resides on the fact that the combined effect of free, adsorbed and dissolved gas production mechanisms on stress-sensitive shale gas condensate reservoirs has not been considered previously in the literature for estimation of OGIP and OCIP using an analytical MBE.

  • A Material Balance Equation for Stress-Sensitive Shale Gas Reservoirs Considering the Contribution of Free, Adsorbed and Dissolved Gas
    Day 2 Wed October 21 2015, 2015
    Co-Authors: Daniel Orozco, Roberto Aguilera
    Abstract:

    Abstract Unconventional shale gas reservoirs around the world have been proven to store gigantic volumes of natural gas. It has been demonstrated with both laboratory and mathematical work that these reservoirs can be represented by a quintuple porosity formulation plus an additional storage mechanism provided by dissolved gas in kerogen. All these storage mechanisms must be considered for estimation of original gas in place (OGIP). Otherwise pessimistic values of OGIP and recoveries will be obtained by ignoring any of these mechanisms. This paper presents a new easy-to-use Material Balance Equation (MBE) for shale gas reservoirs that considers the contribution of free, adsorbed and dissolved gas and their effects on cumulative gas production. Furthermore the proposed MBE takes into account the stress-dependency of permeability and porosity as the reservoir is depleted. Aguilera (2008) formulated a MBE to account for the effect of fracture compressibility on OGIP determination in stress-sensitive naturally fractured reservoirs. Cabrapan et al. (2014) extended the method by incorporating adsorption in shale gas reservoirs. The authors used the Langmuir Adsorption theory for quantifying the adsorbed gas volume as a function of average reservoir pressure. In this paper, the method is further extended to include the effect of production by diffusion of dissolved gas from kerogen. The volume of dissolved gas depends on the total fractional volume of kerogen in shale and the methane concentration in the kerogen body, which is in turn a function of pressure and temperature, as proposed by Swami et al. (2013). Results are presented as crossplots of P/Z (pressure/gas deviation factor) vs. Gp (cumulative gas production), Gp vs. time and gas rate vs. time. The plots allow detecting four stages of production in a shale gas reservoir: 1) production of free gas from fractures and organic porosity, 2) production of free gas from the inorganic matrix when fractures start closing, 3) production by desorption from the organic Material and 4) production by diffusion of dissolved gas. The same trends have been observed in Devonian Shales of the Appalachian Basin where long production histories are available. It is concluded that dissolved gas is not only an additional storage mechanism but it also provides an important pressure and production contribution in shale reservoirs. The new consideration introduced in the MBE proposed in this paper is of importance because although diffusion from kerogen in shale gas reservoirs is by nature a slow process, it provides long term production rates with relatively small declines. To the best of our knowledge, an analytical MBE that includes simultaneously stress-dependent porosity and permeability, free gas, adsorbed gas and dissolved gas has not been published previously in the literature.

Shedid A. Shedid - One of the best experts on this subject based on the ideXlab platform.

  • Improved Material Balance Equation (MBE) for gas-condensate reservoirs considering significant water vaporization
    Elsevier, 2018
    Co-Authors: Ahmed H. Ramada, Shedid A. Shedid
    Abstract:

    The phenomenon of retrograde condensation occurs when the reservoir pressure declines below the dew-point pressure causing gas condensation and developing two-phase flow. Material Balance Equation (MBE) of gas condensate reservoirs is a real challenge because of the change in fluid composition and complexity of phase behavior.Neglecting the effect of water vaporization may lead to inaccurate predictions of the Material Balance Equation. Therefore, the main objective of this study is to develop an improved MBE model capable to describe gas condensate reservoirs under significant vaporization of connate water and water influx driving mechanism.A new parameter is developed to consider water vaporization. This parameter is used to derive Equations for gas condensate reservoirs considering vaporization effect with and without consideration of water influx. Numerical examples have been developed and used to compare the accuracy of the newly-developed model with conventional ones using actual reservoir depletion and production data.The results indicated that water vaporization has an important effect and should be considered for accurate MBE predictions. Error analysis showed that the newly-developed Equations are more accurate than previously-developed models. The accuracy of the new MBE is attributed to the additional parameter introduced considering high pressure and high temperature conditions.The application of the new Material Balance Equation will have important impact on predictions of initial gas in place, reserve calculation and future simulation studies. Keywords: Gas condensate, Material Balance, Gas predictions, Gas reserve

  • Improved Material Balance Equation (MBE) for gas-condensate reservoirs considering significant water vaporization
    Egyptian Journal of Petroleum, 2018
    Co-Authors: Ahmed H. Ramadan, Shedid A. Shedid
    Abstract:

    Abstract The phenomenon of retrograde condensation occurs when the reservoir pressure declines below the dew-point pressure causing gas condensation and developing two-phase flow. Material Balance Equation (MBE) of gas condensate reservoirs is a real challenge because of the change in fluid composition and complexity of phase behavior. Neglecting the effect of water vaporization may lead to inaccurate predictions of the Material Balance Equation. Therefore, the main objective of this study is to develop an improved MBE model capable to describe gas condensate reservoirs under significant vaporization of connate water and water influx driving mechanism. A new parameter is developed to consider water vaporization. This parameter is used to derive Equations for gas condensate reservoirs considering vaporization effect with and without consideration of water influx. Numerical examples have been developed and used to compare the accuracy of the newly-developed model with conventional ones using actual reservoir depletion and production data. The results indicated that water vaporization has an important effect and should be considered for accurate MBE predictions. Error analysis showed that the newly-developed Equations are more accurate than previously-developed models. The accuracy of the new MBE is attributed to the additional parameter introduced considering high pressure and high temperature conditions. The application of the new Material Balance Equation will have important impact on predictions of initial gas in place, reserve calculation and future simulation studies.

Wang Chen - One of the best experts on this subject based on the ideXlab platform.

  • A New Material Balance Equation for Dual-Porosity Media Shale Gas Reservoir
    Energy Procedia, 2019
    Co-Authors: Shuyong Hu, Xinrui Hu, Lang He, Wang Chen
    Abstract:

    Abstract Shale gas reserves is enormously abundant in the world and has considerable prospects for exploration. Therefore, how to accurately calculate the dynamic reserves of shale gas reservoirs is very important. In recent years, scholars have proposed a variety of Material Balance Equations for shale gas reservoirs to calculate dynamic reserves. However, only parts of factors were considered. Based on previous research, a new dual-porosity media Material Balance Equation is established to more accurately calculate the dynamic reserves of gas reservoirs. In the new Material Balance Equation, the critical desorption pressure, the adsorbed phase porosity, the change in the volume of the adsorbed phase, the dissolved gas in kerogen and water are all taken into consideration. The rock compressibility is revised as well. The cases analysis show that different factors exert a certain influence on the calculation results of reserves. Therefore, to effectively predict the dynamic reserves and guide the exploitation of shale gas reservoirs, all factors should be comprehensively considered to establish the correct Material equilibrium Equation.

Dan Deng - One of the best experts on this subject based on the ideXlab platform.

  • The Material Balance Equation for fractured vuggy gas reservoirs with bottom water-drive combining stress and gravity effects
    Journal of Natural Gas Science and Engineering, 2017
    Co-Authors: Zhouhua Wang, Zidun Wang, Fanhua Zeng, Ping Guo, Dan Deng
    Abstract:

    Abstract Compared with conventional porous-water-drive gas reservoirs, calculating the reserve of a fractured vuggy with water driving is a more difficult and challenging task because of its complex matrix types (matrix, fracture and cavity) and strong rock compressibility. Based on the principles of mass conservation, the Material Balance Equation (MBE) for a fractured vuggy gas reservoir with bottom-water driving is established, and the effects of stress sensitivity and gravity segregation are both considered in the proposed model. The original gas in place (OGIP) and the distribution of the reserve in matrix, fracture and cavity can be determined with the proposed MBE. To test the validity of the model, a depletion test simulating the depleting process of fractured vuggy water-drive gas reservoirs and permeability stress sensitivity experiments with actual full-diameter cores under reservoir conditions are conducted. Then, validation and analysis of the model are compared with the experimental data. It is observed that the water production rate shows a stepped increasing trend instead of a gradually increasing trend during the depletion test. The reserve calculated with the proposed model has the lowest error (1.68%) compared with the experimental data, in which the reserve in the cavity is dominant. Thus, gravity and stress should not be neglected when calculating the reserve of a fractured vuggy gas reservoir with bottom water driving; otherwise, a lower accuracy would be introduced.