A numerical simulation method for enhancing oil recovery by injecting carbon dioxide into coalbed methane

Abstract

This invention belongs to the field of numerical simulation technology for oil and gas reservoir development, specifically relating to a numerical simulation method for enhanced oil recovery (EOR) through carbon dioxide injection into coalbed methane. The method includes: establishing a three-dimensional geological model, a three-dimensional geomechanical model, and a fracture network model using Petrel; establishing a numerical simulation model of coalbed methane components including fractures using the Intersect simulator, and performing historical data fitting based on historical production data; importing the geological attribute field, pressure field, and saturation field at the end of the historical data fitting into the CMG-GEM simulator to conduct thermal simulation of carbon dioxide injection into coalbed methane; importing the simulated pressure and temperature fields back into Petrel, and then using the Intersect simulator to complete the dynamic prediction of thermal drive production. This invention can consider the influence of temperature on CH4 and CO2 adsorption / desorption, improving model accuracy and significantly enhancing the accuracy of production prediction.

Description

Technical Field

[0001] This invention relates to a numerical simulation method for enhancing oil recovery by injecting carbon dioxide into coalbed methane, belonging to the field of numerical simulation technology for oil and gas reservoir development. Background Technology

[0002] my country is rich in coalbed methane resources, with geological reserves of over 30 trillion cubic meters in coal seams shallower than 2,000 meters, and recoverable reserves of over 12.5 trillion cubic meters, accounting for about a quarter of conventional natural gas, making it an important supplement to my country's natural gas resources.

[0003] Gas injection displacement technology has become one of the main methods for solving the problem of low-permeability coalbed methane development in recent years. Among them, CO2 injection can achieve the dual benefits of improving coalbed methane recovery rate and reducing greenhouse gas emissions. Injecting thermal CO2 can improve displacement efficiency because the thermal effect causes a large number of pores and throats to be created and merged inside the coal sample, improving pore connectivity and thus increasing CH4 production and CO2 sequestration.

[0004] Most current CO2 thermally driven coalbed methane models only consider the effects of temperature on permeability and porosity. However, CH4 desorption and CO2 adsorption are endothermic and exothermic reactions, respectively, and are significantly affected by temperature. Furthermore, traditional integrated commercial simulation software such as Petrel cannot account for the impact of temperature changes on gas adsorption / desorption during the simulation process. Simulation software that can consider the effects of temperature changes on gas adsorption / desorption has significant limitations when simulating fracturing production in complex multi-well areas. Summary of the Invention

[0005] The purpose of this invention is to address the problems existing in the prior art by providing a numerical simulation method for enhancing oil recovery of coalbed methane by injecting thermal carbon dioxide. This method achieves numerical simulation of coalbed methane by injecting thermal carbon dioxide, taking into account the effects of thermal injection on the desorption / adsorption of CH4 and CO2, through staged simulation.

[0006] The technical solution provided by this invention to solve the above-mentioned technical problems is: a numerical simulation method for enhancing oil recovery by injecting carbon dioxide into coalbed methane, comprising the following steps: Step S1: Use Petrel to establish a three-dimensional geological model and a three-dimensional geomechanical model. Based on the three-dimensional geomechanical model, set up two sets of orthogonal natural fractures and carry out the simulation of the fracture network of each well to obtain the fracture network model. Step S2: Based on the three-dimensional geological model and the fracture network model, a numerical simulation model of coalbed methane components containing fractures is established using the Intersect simulator, and historical fitting is performed based on historical production data. Step S3: Import the geological property field, pressure field, and saturation field at the end of the historical fitting of the Intersect simulator in step S2 into the CMG-GEM simulator. Based on the Langmuir isothermal adsorption model parameters of carbon dioxide and methane at different temperatures, carry out thermal simulation of carbon dioxide injection into coalbed methane. Step S4: Import the pressure field and temperature field obtained from the CMG simulation in step S3 back to Petrel, and modify the Langmuir volume constant, Langmuir pressure constant, and free gas saturation in the main temperature rise region based on the simulated pressure field and temperature field. Then use the Intersect simulator to complete the dynamic prediction of thermal drive production. The formulas for calculating the Langmuir volume constant and Langmuir pressure constant in the main temperature rise region are modified as follows:

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[0010] In the formula: , , , It is a constant; Let m be the initial Langmuir volume constant. 3 / t; Let m be the Langmuir volume constant after temperature change. 3 / t; The initial Langmuir pressure constant is given in MPa. The initial Langmuir pressure constant is given in MPa. The average temperature of the initial strata is given in °C. The average temperature of the formation after the temperature change is expressed in °C. The formula for calculating free gas saturation is:

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[0014]

[0015] In the formula: This represents the change in free gas saturation. To bind water saturation; This represents the initial free gas saturation value. This represents the free gas saturation value after temperature change. Porosity; The change in free gas volume, m 3 ; Pressure under standard conditions, MPa; It is the compression factor; The change in adsorbed gas volume is m. 3 ; The density of the coal seam is t / m³. 3 ; The volume of the region where the coal seam temperature rises, in meters. 3 ; m represents the change in adsorbed gas content due to temperature variation. 3 / t; ρ represents the formation pressure, in MPa.

[0016] A further technical solution is that the three-dimensional geological model is established using a Gaussian stochastic simulation method based on well logging interpretation data.

[0017] A further technical solution is that the three-dimensional geomechanical model is established based on well logging data and three-dimensional finite element stress simulation technology.

[0018] A further technical solution is that the historical fitting process in step 2 is as follows: based on historical production data, adjust the gas-water phase permeability curve, capillary pressure, NTG, reservoir horizontal and vertical permeability ratio, and permeability parameters near the production well to fit the parameters of reserves, gas production, water production, and bottom hole flowing pressure.

[0019] A further technical solution is that the specific process of step S3 is as follows: Step S31: Export the model containing the geological attribute field, pressure field, and saturation field at the end of the historical fitting as RESQUE format and then import it into the CMG-GEM simulator. Step S32: Add thermodynamic parameters in the CMG editor Ceidt, set different injection and production regimes, and conduct thermal simulation of coalbed methane injection with carbon dioxide.

[0020] A further technical solution is that, in step S31, the permeability, porosity, gas saturation, and pressure parameters are set in the CMG-GEM simulator to the same values ​​as those in the numerical simulation model of coalbed methane components.

[0021] A further technical solution is that the thermodynamic parameters include coal and rock heat capacity, thermal conductivity, and CH4 and CO2 diffusion coefficients.

[0022] The beneficial effects of this invention are as follows: Compared with previous numerical models for enhanced oil recovery (EOR) using thermal carbon dioxide injection in coalbed methane, this invention considers the influence of temperature on the adsorption / desorption of CH4 and CO2, improving model accuracy and significantly enhancing the accuracy of production prediction. This invention innovatively employs a multi-numerical simulation platform to simulate the thermal carbon dioxide injection process in coalbed methane in stages, solving the problem that traditional commercial software does not consider the impact of thermal injection on gas adsorption / desorption. Attached Figure Description

[0023] Figure 1 A cumulative gas production fitting plot for the production history during the coal seam depletion development stage. Figure 2 A daily gas production fitting plot for the production history during the coal seam depletion development stage. Figure 3 A cumulative water production fitting plot for the production history during the coal seam depletion development stage. Figure 4 A daily water production fitting plot for the production history during the coal seam depletion development stage. Figure 5 A diagram showing the temperature field variation at different injection temperatures in CMG simulations; Figure 6 A graph showing the predicted daily and cumulative gas production under different injection volumes; Figure 7 To predict the distribution of adsorbed gas at the end of the period. Detailed Implementation

[0024] The technical solution of the present invention will now be clearly and completely described with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the invention, not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0025] like Figure 1 As shown, the present invention provides a numerical simulation method for enhancing oil recovery of coalbed methane through carbon dioxide injection. The specific objectives of this method are as follows: Step S1: Use Petrel to establish a three-dimensional geological model and a three-dimensional geomechanical model. Based on the three-dimensional geomechanical model, set two sets of orthogonal natural fractures (adjust the Length, Orientation, and Spacing parameters) to simulate the coal seam cleavage structure. Then, use UFM to simulate the propagation of fracturing fractures in each well and compare it with the fracturing monitoring results of fracturing coal seams in adjacent wells in the well area. Modify the natural fractures appropriately to obtain the fracturing fracture network model. Among them, a three-dimensional geological model (including properties such as porosity, permeability, water saturation, rock density, and gas content) was established using Gaussian stochastic simulation based on well logging interpretation data. Based on well logging data and three-dimensional finite element stress simulation technology, a three-dimensional geomechanical model (including properties such as Young's modulus, Poisson's ratio, maximum / minimum horizontal principal stress, pore pressure, and overburden stress) is established. Step S2: Based on the three-dimensional geological model and the fracture network model, a numerical simulation model of coalbed methane components containing fractures is established using the Intersect simulator, and historical fitting is performed based on historical production data. Step S21: Use the Intersect simulator to establish a numerical simulation model of coalbed methane components including fractures. In the Reservoir Engineering module, select the Compositional type in the Fluid Models module, and add CH4 and CO2 in Components. In the Initial Conditions module, set the reference depth, reference pressure, gas-water interface, and gas-water interface capillary pressure. In the Make rock physical functions module, set parameters such as the gas-water two-phase interpenetration curve, CH4, and CO2 adsorption / desorption curves. Step S22: In the depletion development stage of the numerical simulation model of coalbed methane components, the equilibrium initialization method is used to establish the initial pressure distribution field and saturation distribution field; based on historical production data, parameters such as gas-water permeability curves, capillary pressure, NTG (net-to-gross ratio), reservoir horizontal and vertical permeability ratio, and permeability near production wells are adjusted to fit parameters such as reserves, gas production, water production, and bottom hole flowing pressure. Figures 1-4 As shown; Step S3: Import the geological property field, pressure field, and saturation field at the end of the historical fitting of the Intersect simulator in step S2 into the CMG-GEM simulator. Based on the Langmuir isothermal adsorption model parameters of carbon dioxide and methane at different temperatures, carry out thermal simulation of carbon dioxide injection into coalbed methane. Step S31: Export the model containing the geological attribute field, pressure field, and saturation field at the end of the historical fitting as RESQUE format and import it into the CMG-GEM simulator. In the CMG-GEM simulator, set the permeability, porosity, gas saturation, and pressure parameters to the same values ​​as in the numerical simulation model of coalbed methane components. Step S32: First, enable the thermal simulation option in the editor Cedit using the keywords *THERMAL *ON. Then, add thermodynamic parameters such as coal and rock heat capacity (*CP-ROCK), thermal conductivity (*THCONRO), and CH4 and CO2 diffusion coefficients (*DIFFC-GAS) using keywords. In the Wells & Recurrent module, set different injection and production regimes (different injection temperatures, injection rates, well-closing times, etc.). Figure 5As shown, a thermal simulation of carbon dioxide injection into coalbed methane was conducted. Step S4: Import the pressure and temperature fields obtained from the CMG simulation in Step S3 back to Petrel, and modify the Langmuir volume constant, Langmuir pressure constant, and free gas saturation in the main temperature rise region based on the simulated pressure and temperature fields. Then, use the Intersect simulator to complete the dynamic prediction of thermal drive production, that is, set the corresponding production regime (different injection temperatures, injection rates, well simmering times, etc.) to start the numerical simulation of production prediction, and realize the dynamic prediction of coalbed methane heat injection carbon dioxide production, such as... Figure 6 , Figure 7 As shown; The formulas for calculating the Langmuir volume constant and Langmuir pressure constant in the main temperature rise region are modified as follows: (1) (2) (3) (4) In the formula: , , , It is a constant; Let m be the initial Langmuir volume constant. 3 / t; Let m be the Langmuir volume constant after temperature change. 3 / t; The initial Langmuir pressure constant is given in MPa. The initial Langmuir pressure constant is given in MPa. The average temperature of the initial strata is given in °C. The average temperature of the formation after the temperature change is expressed in °C. The change in adsorbed gas content caused by temperature change is as follows: (5) In the formula: m represents the change in adsorbed gas content due to temperature variation. 3 / t; Formation pressure, MPa; The change in adsorbed gas volume is as follows: (6) In the formula: The change in adsorbed gas volume is m. 3 ; The density of the coal seam is t / m³. 3 ; The volume of the region where the coal seam temperature rises, in meters. 3 .

[0026] The change in adsorbed gas in the coal seam is converted into a change in free gas in the reservoir: (7) In the formula: The change in free gas volume, m 3 ; Pressure under standard conditions, MPa; It is the compression factor; Therefore, the free gas saturation after the temperature change is: (8) (9) In the formula: This represents the change in free gas saturation. To bind water saturation; This represents the initial free gas saturation value. This represents the free gas saturation value after temperature change. Porosity.

[0027] The above description is not intended to limit the present invention in any way. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some changes or modifications to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the present invention. Any simple modifications, equivalent changes and modifications made to the above embodiments based on the technical essence of the present invention without departing from the scope of the present invention shall still fall within the scope of the present invention.

Claims

1. A numerical simulation method for enhancing oil recovery by injecting thermal carbon dioxide into coalbed methane, characterized in that, Includes the following steps: Step S1: Use Petrel to establish a three-dimensional geological model and a three-dimensional geomechanical model. Based on the three-dimensional geomechanical model, set up two sets of orthogonal natural fractures and carry out the simulation of the fracture network of each well to obtain the fracture network model. Step S2: Based on the three-dimensional geological model and the fracture network model, a numerical simulation model of coalbed methane components containing fractures is established using the Intersect simulator, and historical fitting is performed based on historical production data. Step S3: Import the geological property field, pressure field, and saturation field at the end of the historical fitting of the Intersect simulator in step S2 into the CMG-GEM simulator. Based on the Langmuir isothermal adsorption model parameters of carbon dioxide and methane at different temperatures, carry out thermal simulation of carbon dioxide injection into coalbed methane. Step S4: Import the pressure field and temperature field obtained from the CMG simulation in step S3 back to Petrel, and modify the Langmuir volume constant, Langmuir pressure constant, and free gas saturation in the main temperature rise region based on the simulated pressure field and temperature field. Then use the Intersect simulator to complete the dynamic prediction of thermal drive production. The formulas for calculating the Langmuir volume constant and Langmuir pressure constant in the main temperature rise region are modified as follows: In the formula: , , , It is a constant; Let m be the initial Langmuir volume constant. 3 / t; Let m be the Langmuir volume constant after temperature change. 3 / t; The initial Langmuir pressure constant is given in MPa. The initial Langmuir pressure constant is given in MPa. The average temperature of the initial strata is given in °C. The average temperature of the formation after the temperature change is expressed in °C. The formula for calculating free gas saturation is: In the formula: This represents the change in free gas saturation. To bind water saturation; This represents the initial free gas saturation value. This represents the free gas saturation value after temperature change. Porosity; The change in free gas volume, m 3 ; Pressure under standard conditions, MPa; It is the compression factor; The change in adsorbed gas volume is m. 3 ; The density of the coal seam is t / m³. 3 ; The volume of the region where the coal seam temperature rises, in meters. 3 ; m represents the change in adsorbed gas content due to temperature variation. 3 / t; ρ represents the formation pressure, in MPa.

2. The numerical simulation method for enhanced oil recovery by injecting carbon dioxide into coalbed methane according to claim 1, characterized in that, The three-dimensional geological model was established using Gaussian stochastic simulation based on well logging interpretation data.

3. The numerical simulation method for enhanced oil recovery by injecting carbon dioxide into coalbed methane according to claim 1, characterized in that, The three-dimensional geomechanical model is established based on well logging data and three-dimensional finite element stress simulation technology.

4. The numerical simulation method for enhanced oil recovery by injecting carbon dioxide into coalbed methane according to claim 1, characterized in that, The historical fitting process in step 2 is as follows: based on historical production data, adjust the gas-water phase permeability curve, capillary pressure, NTG, reservoir horizontal and vertical permeability ratio, and permeability parameters near the production well to fit the parameters of reserves, gas production, water production, and bottom hole flowing pressure.

5. The numerical simulation method for enhanced oil recovery by injecting carbon dioxide into coalbed methane according to claim 1, characterized in that, The specific process of step S3 is as follows: Step S31: Export the model containing the geological attribute field, pressure field, and saturation field at the end of the historical fitting as RESQUE format and then import it into the CMG-GEM simulator. Step S32: Add thermodynamic parameters in the CMG editor Ceidt, set different injection and production regimes, and conduct thermal simulation of coalbed methane injection with carbon dioxide.

6. The numerical simulation method for enhanced oil recovery by injecting carbon dioxide into coalbed methane according to claim 4, characterized in that, In step S31, the permeability, porosity, gas saturation, and pressure parameters are set in the CMG-GEM simulator to the same values ​​as those in the numerical simulation model of coalbed methane components.

7. The numerical simulation method for enhanced oil recovery by injecting carbon dioxide into coalbed methane according to claim 4, characterized in that, The thermodynamic parameters include coal heat capacity, thermal conductivity, and CH4 and CO2 diffusion coefficients.

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