A method for determining the dosage of plugging agent for CO2-driven gas channel blocking

Abstract

The application discloses a method for determining the amount of a CO2 flooding plugging agent for gas channeling channels, and particularly relates to the technical field of oil and gas field development engineering. The method comprises the following steps: establishing a corresponding mathematical model by using geological parameters of an oil reservoir, wherein the geological parameters include top structure, bottom structure, sand body thickness, effective thickness, permeability, porosity, saturation, fluid high-pressure physical property, temperature and pressure; performing history matching by using development dynamic data to obtain gas channeling channel parameters, including channel type and thickness; selecting gas channeling channels with a gas saturation greater than 0.65, and determining the positions of the gas channeling channels; calculating the total gas channeling volume Q according to the parameters of the gas channeling channels; and finally optimizing the injection amount of the plugging agent. The method can accurately and quickly determine the positions and volumes of the gas channeling channels, and can also optimize and calculate the amount of the plugging agent. Compared with the prior art, the method can improve the CO2 flooding recovery rate of the oil reservoir, has high testing precision, is simple to operate and low in cost.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development engineering technology, and more specifically, to a method for determining the dosage of a plugging agent used to block gas channeling pathways via CO2 flooding. Background Technology

[0002] In recent years, CO2 flooding technology has received increasing attention both domestically and internationally. Injecting CO2 into reservoirs can dissolve in crude oil, reducing its viscosity, expanding its volume, and increasing formation energy, thus significantly improving oil recovery. However, during CO2 flooding, the much lower viscosity of CO2 compared to crude oil leads to viscous fingering, resulting in early gas breakthrough and a high gas-to-oil ratio. The low viscosity also facilitates CO2 penetration into high-permeability layers, negatively impacting field displacement efficiency and economic benefits. Furthermore, the density difference between CO2 and crude oil causes gravity separation, with the less dense gas rising and only affecting a small portion of the upper reservoir. Therefore, CO2 gas flooding suffers from problems such as viscous fingering, gravity separation, and gas channeling due to formation heterogeneity. To address these issues, channeling prevention measures are needed to improve the effectiveness of CO2 flooding.

[0003] The identification of gas channeling pathways and their volume is crucial for implementing gas channeling control measures and guiding the dosage of plugging (displacement) agents in oilfields. Currently, the identification of gas channeling pathways mainly relies on tracers, well logging data, and well test data. While tracer testing yields relatively accurate results, it is expensive and time-consuming. Simply relying on well logging and well test data to identify gas channeling pathways is inaccurate. Commonly used methods for determining plugging agent dosage include empirical analogy, production dynamic data, and simplified modeling. However, these methods are prone to errors because they do not consider the actual situation of gas channeling in oil reservoirs. This error can lead to insufficient plugging agent injection, resulting in ineffective sealing and failing to achieve the goal of improving oil recovery; while excessive injection can cause unnecessary damage to the formation, reducing the recovery rate. Summary of the Invention

[0004] To overcome the aforementioned deficiencies of the prior art, this invention provides a method for determining the amount of plugging agent used to seal gas channeling pathways using CO2. The technical problem this invention aims to solve is that in the prior art, the amount of plugging agent is generally calculated based on the pore volume in the near-wellbore zone of the injection well. For example, if the amount of plugging agent is calculated based on a 5m radius near the well, then the pore volume within that radius is... However, this method is only a simplified calculation method. Gas channel is generally located between the injection well and the production well, and it is an irregular three-dimensional shape. The current calculation method cannot accurately reflect the actual location and volume of the gas channel in the reservoir. Therefore, the calculated plugging agent volume is also inaccurate, which leads to the problem that the implementation effect of sealing the gas channel does not meet expectations.

[0005] To achieve the above objectives, the present invention provides the following technical solution: a method for determining the dosage of a plugging agent for CO2-driven gas channel blocking, comprising the following steps:

[0006] Using the reservoir numerical simulation model and calculation results, gas channeling channels with a gas saturation greater than 0.65 were selected, and the total volume of these gas channeling channels was calculated. The amount of plugging agent injected was 0.8-1.5 times the total volume of the gas channeling channels.

[0007] The method for determining the dosage of CO2-based plugging agent to block gas channel passages is as follows:

[0008] (1) Using seismic attributes as constraints, a single sand body level structural model and a bedding model of the study area were established. A porosity model was established through phase control constraints. The porosity simulation results were used as the second variable to perform co-simulation with Gaussian in situ to establish a permeability model. A saturation model was established by using the J-function fitting method based on well logging curves.

[0009] (2) The established model is historically fitted based on the development dynamics of CO2-driven oil reservoirs. The oil production of the entire reservoir area and single wells, as well as the water cut of the entire reservoir area and single wells, are simulated to simulate the reservoir development. The simulation results are compared with the dynamic history of the actual oil field to ensure that the fitting error is within the range and the fitted numerical model is obtained.

[0010] The analysis methods for the numerical model include:

[0011] S1. Analyze the gas channel using the fitted numerical model, keep other parameter values ​​unchanged, and analyze the characteristic parameters of the gas channel by changing the production dynamic parameters to obtain the characteristic parameters of the gas channel with a gas saturation greater than a certain value.

[0012] S2. Calculate the volume V of each gas channel using the parameters of each gas channel obtained from the inversion.

[0013]

[0014] in:

[0015] V represents the volume of the gas channel, and its unit is m. 3 ;

[0016] A represents the planar area of ​​the gas channel, with units of m². 2 ;

[0017] h represents the thickness of each air channel, measured in meters (m).

[0018] Reservoir porosity;

[0019] n is the number of gas channeling layers.

[0020] S3. Calculate the total gas channel volume Q based on the gas channel volume of each reservoir, according to formula (1-2).

[0021]

[0022] in:

[0023] Q represents the total volume of multiple gas channeling channels;

[0024] m represents the number of airflow channels, and the total volume is calculated by weighting several airflow channels.

[0025] S4. Determination of the amount of plugging agent injected.

[0026] The amount of plugging agent injected is 0.8-1.5 times the total gas channel volume Q. The larger the multiple, the greater the possibility of plugging the gas channel. However, it may also plug parts that do not need to be plugged, resulting in a decrease in recovery rate. Then, inversion is performed.

[0027] This invention establishes a corresponding mathematical model using reservoir geological parameters, including top and bottom structures, sand body thickness, effective thickness, permeability, porosity, saturation, high-pressure fluid properties, temperature, and pressure. Historical data is fitted using development dynamics data to obtain gas channel parameters, including channel type and thickness. Gas channels with a gas saturation greater than 0.65 are selected, along with their locations. The total gas channel volume Q is calculated based on these channel parameters, and finally, the plugging agent injection rate is optimized.

[0028] Compared with the prior art, the present invention has the following advantages and beneficial effects:

[0029] This method utilizes numerical simulation to accurately and quickly determine the location and volume of gas channeling, and can optimize the calculation of plugging agent dosage. Compared with existing technologies, it can improve the recovery rate of CO2 flooding in oil reservoirs, with high testing accuracy, simple operation, and low cost. Attached Figure Description

[0030] Figure 1 This is a graph showing the change in oil recovery rate of Block A1CO2 flooding in Example 1 of the present invention as a function of plugging agent injection amount;

[0031] Figure 2 This is a schematic diagram showing the location of the gas channel in block A1 of Embodiment 1 of the present invention;

[0032] Figure 3 This is a production gas-oil ratio curve calculated by the method for determining different plugging agents in Block A1 CO2 flooding of the present invention. Detailed Implementation

[0033] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and 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.

[0034] This invention discloses a method for determining the dosage of a plugging agent used to block gas channeling using CO2, comprising the following steps:

[0035] Using the reservoir numerical simulation model and calculation results, gas channeling channels with a gas saturation greater than 0.65 were selected, and the total volume of these gas channeling channels was calculated. The amount of plugging agent injected was 0.8-1.5 times the total volume of the gas channeling channels.

[0036] The method for determining the dosage of CO2-based plugging agent to block gas channel passages is as follows:

[0037] (1) Using seismic attributes as constraints, a single sand body level structural model and a bedding model of the study area were established. A porosity model was established through phase control constraints. The porosity simulation results were used as the second variable to perform co-simulation with Gaussian in situ to establish a permeability model. A saturation model was established by using the J-function fitting method based on well logging curves.

[0038] (2) Based on the production and pressure data obtained from actual production and testing, considering the characteristics of multiphase fluid and stress-sensitive complex seepage, the well test analysis (PTA) and unstable production analysis (RTA) methods are used to dynamically invert different types of wells under different reservoir and fluid conditions, quantitatively obtain local well area reservoir parameters, and provide a basis for adjusting historical fitting parameters.

[0039] (3) Based on the development dynamics of CO2-driven oil reservoirs, the established model is historically fitted. Based on the oil production of the entire reservoir area and single wells, as well as the water cut of the entire reservoir area and single wells, the reservoir development is simulated. The simulation results are compared with the dynamic history of the actual oil field to ensure that the fitting error is within the range, and the fitted numerical model is obtained.

[0040] Preferably, the analysis method of the numerical model includes:

[0041] S1. Analyze the gas channel using the fitted numerical model, keep other parameter values ​​unchanged, and analyze the characteristic parameters of the gas channel by changing the production dynamic parameters; obtain the characteristic parameters of the gas channel with a gas saturation greater than a certain value.

[0042] S2. Calculate the volume V of each gas channel using the parameters of each gas channel obtained from the inversion.

[0043]

[0044] in:

[0045] V represents the volume of the gas channel, and its unit is m. 3 ;

[0046] A represents the planar area of ​​the gas channel, with units of m². 2 ;

[0047] h represents the thickness of each air channel, measured in meters (m).

[0048] Reservoir porosity;

[0049] n is the number of gas channeling layers;

[0050] S3. Calculate the total gas channel volume Q based on the gas channel volume of each reservoir, according to formula (1-2);

[0051]

[0052] in:

[0053] Q represents the total volume of multiple gas channeling channels;

[0054] m is the number of air channeling channels, and the total volume is calculated by weighting several air channeling channels;

[0055] S4. Determination of plugging agent injection volume;

[0056] The amount of plugging agent injected is 0.8-1.5 times the total gas channel volume Q. The larger the multiple, the greater the possibility of plugging the gas channel. However, it may also plug parts that do not need to be plugged, resulting in a decrease in recovery rate. Then, inversion is performed.

[0057] Preferably, the quantitative acquisition of local well area data includes permeability, controlled reserves, control radius, and skin coefficient reservoir parameters.

[0058] In this invention, preferably, the characteristic parameter of the gas channel with a gas saturation greater than a certain value in S1 is 0.64-0.66.

[0059] Preferably, the inversion in S4 is a parameter characterizing the gas channel characteristics based on the gas channeling results, including the planar area of ​​the gas channel, the thickness of the gas channel, and the reservoir porosity.

[0060] In this invention, preferably, the reservoir parameters include top surface structure, bottom surface structure, sand body thickness, effective thickness, permeability, porosity, saturation, high-pressure fluid properties, temperature, and pressure; the geological model is a three-dimensional reservoir grid model, considering multiple gas channeling channels.

[0061] In this invention, preferably, the historical fitting parameters include fluid distribution differences, injection-production well spacing, injection method, gas production rate of production wells, injection-production pressure difference, gas injection time, gas injection volume, gas channeling time, and production gas-oil ratio curve.

[0062] Preferably, the fitting error range includes oil and fluid production data for the entire region and oil and fluid production data for a single well, with an error of less than 10%.

[0063] In this invention, preferably, the production dynamic parameters include the injection plugging dose, the gas injection volume, and the daily output.

[0064] Preferably, the optimal injection amount of the plugging agent is 1.2-1.4Q; more preferably, the optimal injection amount of the plugging agent is 1.2Q.

[0065] The technical solution of the present invention will be further described below with reference to the embodiments.

[0066] Example 1

[0067] A method for improving CO2 flooding recovery by calculating plugging agent dosage using numerical simulation is proposed. This method is applied to Block A1 of the Shengli Oilfield, a high water-cut block with a permeability of 1.5 × 10⁻⁶. -3 μm 2 The oil-bearing area is 1.94 km². 2 .

[0068] The implementation steps are as follows:

[0069] (1) A geological model was established using the collected geological parameters of the CO2 flooding reservoir to simulate the CO2 flooding process. The reservoir parameters include top surface structure, bottom surface structure, sand body thickness, effective thickness, permeability, porosity, saturation, high-pressure fluid properties, temperature and pressure. The model is a three-dimensional reservoir grid model, considering multiple gas channeling channels.

[0070] The established model was historically fitted based on the development dynamics of CO2-driven oilfields. This was mainly achieved by utilizing differences in fluid distribution, injection-production well spacing, injection method, gas production rate of production wells, injection-production pressure difference, gas injection time, gas injection volume, gas channeling time, and production gas-oil ratio curve. Based on reservoir parameters, the model simulated oilfield development, including the overall area and single-well oil production, as well as the overall area and single-well water cut. The results were compared with the dynamic history of the actual oilfield to ensure that the model remained within the set error range, thus obtaining the fitted numerical model.

[0071] (2) The gas channel was analyzed using the fitted numerical model. Other parameter values ​​were kept constant, and the characteristic parameters of the gas channel were analyzed by changing the production dynamic parameters. The characteristic parameters of the gas channel with a gas saturation greater than 0.65 were obtained, mainly including the gas channel type, thickness, and permeability, thus determining the location of the gas channel. Figure 2 The middle arrow indicates the location of the gas leakage channel.

[0072] (3) Based on the obtained gas channel parameters, the volume V of each gas channel is calculated, and the formula used is shown in (1-1):

[0073]

[0074] Where V is the volume of the gas channel, m 3 ;

[0075] A is the planar area of ​​the gas channel, m 2 ;

[0076] h is the thickness of the gas channel, in meters (m).

[0077] Reservoir porosity;

[0078] n is the number of gas channeling layers.

[0079] (4) Calculate the total volume Q of the gas channel based on the volume of the gas channel, according to formula (1-2).

[0080]

[0081] in:

[0082] Q represents the total volume of the gas channel;

[0083] m represents the number of gas leakage channels.

[0084] In the same block, wells 17-X11, 11-X28, 14-X121, and 15-X9, with similar production conditions, were injected with 875m of plugging agent. 3 1293m 3 1367m 3 1512m 3 During the effective period of the injected plugging agent, the increased crude oil production was 1632t, 1552t, 1331t, and 1162t, respectively, with recovery rates increasing by 16.1%, 15.9%, 15.2%, and 14.3%. Based on the numerical simulation method described above, the total gas channel volume Q of each well was 729, 862, 854, and 840 m³, respectively. 3 The ratios between the plugging agent injection amount and Q were approximately 1.2, 1.5, 1.6, and 1.8, respectively. This indicates that the oil recovery rate increases most when the plugging agent injection amount is between 1.2 and 1.5Q. When it exceeds 1.5Q, the recovery rate tends to decrease because excessive plugging agent damages the reservoir, thus reducing the rate of increase in oil production.

[0085] To verify the correctness of this invention, the relationship between the plugging agent injection volume and the enhanced oil recovery effect calculated using reservoir numerical simulation methods based on the established mathematical model is as follows: Figure 1 As shown. By Figure 1 It can be seen that when the amount of plugging agent injected is greater than 1.2Q, the recovery rate remains basically unchanged. If the amount of plugging agent is further increased, the recovery rate will decrease when the amount of plugging agent exceeds 1.5Q. The simulation results are consistent with the amount of plugging agent used in the method of this invention.

[0086] For comparison, different plugging agent dosages were calculated for two oil wells, 17-X11 and 11-X28, in the same block of the reservoir, and the calculations were carried out in the field. For oil well 17-X11, the plugging agent injection volume was determined to be 875 m³ using the method of this invention. 3 Another oil well, 11-X28, used conventional methods to determine the amount of plugging agent required. This well had similar production conditions to oil well 17-X11, and the amount was determined based on the pore volume within 5 meters of the wellbore. r is the sealing radius of the plugging agent around the oil well; h is the thickness of the oil layer. The porosity of the oil reservoir is calculated to be Q1, which is 376 m. 3 .

[0087] 376m of plugging agent was injected into well 11-X28. 3 During the effective period of the injected plugging agent, the well only increased crude oil production by 879 tons after implementation, and the actual reduction in the gas-oil ratio was not significant. Figure 3 This indicates that the amount of plugging agent injected was too small and did not achieve the expected plugging effect. However, after the plugging agent was injected into well 17-X11, crude oil production increased by 1632t within the effective period, achieving a very good production increase effect.

[0088] Example 2

[0089] A method for improving CO2 flooding recovery by calculating plugging agent dosage using numerical simulation is proposed. This method is applied to Block A2 in the Shengli Oilfield, a high water-cut block with a permeability of 1.2 × 10⁻⁶. -3 μm 2 The oil-bearing area is 3.2 km². 2 .

[0090] The implementation steps are as follows:

[0091] (1) A geological model was established using the collected geological parameters of the CO2 flooding reservoir to simulate the CO2 flooding process. The reservoir parameters include top surface structure, bottom surface structure, sand body thickness, effective thickness, permeability, porosity, saturation, high-pressure fluid properties, temperature and pressure. The model is a three-dimensional reservoir grid model, considering multiple gas channeling channels.

[0092] The established model was historically fitted based on the development dynamics of CO2-driven oilfields. This was mainly achieved by utilizing differences in fluid distribution, injection-production well spacing, injection method, gas production rate of production wells, injection-production pressure difference, gas injection time, gas injection volume, gas channeling time, and production gas-oil ratio curve. Based on reservoir parameters, the model simulated oilfield development, including the overall area and single-well oil production, as well as the overall area and single-well water cut. The results were compared with the dynamic history of the actual oilfield to ensure that the model remained within the set error range, thus obtaining the fitted numerical model.

[0093] (2) The gas channel is analyzed by fitting the numerical model. Other parameter values ​​are kept unchanged. The characteristic parameters of the gas channel are analyzed by changing the production dynamic parameters. The characteristic parameters of the gas channel with gas saturation greater than 0.65 are obtained, mainly including the gas channel type, thickness and permeability, thus the location of the gas channel.

[0094] (3) Based on the obtained gas channel parameters, the volume V of each gas channel is calculated, and the formula used is shown in (1-1):

[0095]

[0096] Where V is the volume of the gas channel, m 3 ;

[0097] A is the planar area of ​​the gas channel, m 2 ;

[0098] h is the thickness of the gas channel, in meters (m).

[0099] Reservoir porosity;

[0100] n is the number of gas channeling layers.

[0101] (4) Calculate the total volume Q of the gas channel based on the volume of the gas channel, according to formula (1-2).

[0102]

[0103] in:

[0104] Q represents the total volume of the gas channel;

[0105] m represents the number of gas leakage channels.

[0106] In the same block, wells 24-Y12, 24-Y21, 24-Y23, and 24-Y19, with similar production conditions, were each injected with 740m³ of plugging agent. 3 892m 3 1170m 3 1296m 3During the effective period of the injected plugging agent, the increased crude oil production was 1865t, 1758t, 1567t, and 1395t, respectively, with recovery rates increasing by 15.2%, 16.7%, 18.0%, and 15.6%. Based on the numerical simulation method described above, the total gas channel volume Q of each well was 925, 892, 975, and 810 m³, respectively. 3 The ratios between the plugging agent injection amount and Q were approximately 0.8, 1.0, 1.2, and 1.6, respectively. This indicates that the oil recovery rate increases most when the plugging agent injection amount is between 0.8 and 1.5Q. When it exceeds 1.5Q, the recovery rate tends to decrease because excessive plugging agent damages the reservoir, thus reducing the rate of increase in oil production.

[0107] Example 3

[0108] A method for improving CO2 flooding recovery by calculating plugging agent dosage using numerical simulation is proposed. This method is applied to Block A3 in the Shengli Oilfield, a high water-cut block with a permeability of 1.1 × 10⁻⁶. -3 μm 2 The oil-bearing area is 3.5 km². 2 .

[0109] The implementation steps are as follows:

[0110] (1) A geological model was established using the collected geological parameters of the CO2 flooding reservoir to simulate the CO2 flooding process. The reservoir parameters include top surface structure, bottom surface structure, sand body thickness, effective thickness, permeability, porosity, saturation, high-pressure fluid properties, temperature and pressure. The model is a three-dimensional reservoir grid model, considering multiple gas channeling channels.

[0111] The established model was historically fitted based on the development dynamics of CO2-driven oilfields. This was mainly achieved by utilizing differences in fluid distribution, injection-production well spacing, injection method, gas production rate of production wells, injection-production pressure difference, gas injection time, gas injection volume, gas channeling time, and production gas-oil ratio curve. Based on reservoir parameters, the model simulated oilfield development, including the overall area and single-well oil production, as well as the overall area and single-well water cut. The results were compared with the dynamic history of the actual oilfield to ensure that the model remained within the set error range, thus obtaining the fitted numerical model.

[0112] (2) The gas channel is analyzed by fitting the numerical model. Other parameter values ​​are kept unchanged. The characteristic parameters of the gas channel are analyzed by changing the production dynamic parameters. The characteristic parameters of the gas channel with gas saturation greater than 0.65 are obtained, mainly including the gas channel type, thickness and permeability, thus the location of the gas channel.

[0113] (3) Based on the obtained gas channel parameters, the volume V of each gas channel is calculated, and the formula used is shown in (1-1):

[0114]

[0115] Where V is the volume of the gas channel, m 3 ;

[0116] A is the planar area of ​​the gas channel, m 2 ;

[0117] h is the thickness of the gas channel, in meters (m).

[0118] Reservoir porosity;

[0119] n is the number of gas channeling layers.

[0120] (4) Calculate the total volume Q of the gas channel based on the volume of the gas channel, according to formula (1-2).

[0121]

[0122] in:

[0123] Q represents the total volume of the gas channel;

[0124] m represents the number of gas leakage channels.

[0125] In the same block, wells Z-2, Z-5, Z-7, and Z-12, with similar production conditions, were each injected with 1250m of plugging agent. 3 1548m 3 2208m 3 2763m 3 During the effective period of the injected plugging agent, the increased crude oil production was 2150t, 2703t, 2323t, and 2425t, respectively, with recovery rates increasing by 16.3%, 16.8%, 17.6%, and 17.2%. Based on the numerical simulation method described above, the total gas channel volume Q of each well was 1250, 1290, 1472, and 1625 m³, respectively. 3 The ratios between the plugging agent injection amount and Q were approximately 1.0, 1.2, 1.5, and 1.7, respectively. This indicates that the oil recovery rate increases most when the plugging agent injection amount is between 1.0 and 1.5Q. When it exceeds 1.5Q, the recovery rate tends to decrease because excessive plugging agent damages the reservoir, thus reducing the increase in oil production.

[0126] Example 4

[0127] A method for improving CO2 flooding recovery by calculating plugging agent dosage using numerical simulation is proposed. This method is applied to Block A4 in the Shengli Oilfield, a high water-cut block with a permeability of 1.0 × 10⁻⁶. -3 μm 2 The oil-bearing area is 5.3 km². 2 .

[0128] The implementation steps are as follows:

[0129] (1) A geological model was established using the collected geological parameters of the CO2 flooding reservoir to simulate the CO2 flooding process. The reservoir parameters include top surface structure, bottom surface structure, sand body thickness, effective thickness, permeability, porosity, saturation, high-pressure fluid properties, temperature and pressure. The model is a three-dimensional reservoir grid model, considering multiple gas channeling channels.

[0130] The established model was historically fitted based on the development dynamics of CO2-driven oilfields. This was mainly achieved by utilizing differences in fluid distribution, injection-production well spacing, injection method, gas production rate of production wells, injection-production pressure difference, gas injection time, gas injection volume, gas channeling time, and production gas-oil ratio curve. Based on reservoir parameters, the model simulated oilfield development, including the overall area and single-well oil production, as well as the overall area and single-well water cut. The results were compared with the dynamic history of the actual oilfield to ensure that the model remained within the set error range, thus obtaining the fitted numerical model.

[0131] (2) The gas channel is analyzed by fitting the numerical model. Other parameter values ​​are kept unchanged. The characteristic parameters of the gas channel are analyzed by changing the production dynamic parameters. The characteristic parameters of the gas channel with gas saturation greater than 0.65 are obtained, mainly including the gas channel type, thickness and permeability, thus the location of the gas channel.

[0132] (3) Based on the obtained gas channel parameters, the volume V of each gas channel is calculated, and the formula used is shown in (1-1):

[0133]

[0134] Where V is the volume of the gas channel, m 3 ;

[0135] A is the planar area of ​​the gas channel, m 2 ;

[0136] h is the thickness of the gas channel, in meters (m).

[0137] Reservoir porosity;

[0138] n is the number of gas channeling layers.

[0139] (4) Calculate the total volume Q of the gas channel based on the volume of the gas channel, according to formula (1-2).

[0140]

[0141] in:

[0142] Q represents the total volume of the gas channel;

[0143] m represents the number of gas leakage channels.

[0144] In the same block, wells YE-5, YE-12, YE-21, and YE-25, with similar production conditions, each had 817m³ of plugging agent injected. 3 1052m 3 1196m 3 2062m 3 During the effective period of the injected plugging agent, the increased crude oil production was 1456t, 1567t, 1260t, and 1182t, respectively, with recovery rates increasing by 16.3%, 17.2%, 18.5%, and 15.8%. Based on the numerical simulation method described above, the total gas channel volume Q of each well was 1021, 956, 920, and 1213 m³, respectively. 3 The ratios between the plugging agent injection amount and Q were approximately 0.8, 1.1, 1.3, and 1.7, respectively. This indicates that the oil recovery rate increases most when the plugging agent injection amount is between 0.8 and 1.5Q. When it exceeds 1.5Q, the recovery rate tends to decrease because excessive plugging agent damages the reservoir, thus reducing the rate of increase in oil production.

[0145] Example 5

[0146] A method for improving CO2 flooding recovery by calculating plugging agent dosage using numerical simulation is proposed. This method is applied to Block A5 in the Shengli Oilfield, a high water-cut block with a permeability of 1.8 × 10⁻⁶. -3 μm 2 The oil-bearing area is 4.7 km². 2 .

[0147] The implementation steps are as follows:

[0148] (1) A geological model was established using the collected geological parameters of the CO2 flooding reservoir to simulate the CO2 flooding process. The reservoir parameters include top surface structure, bottom surface structure, sand body thickness, effective thickness, permeability, porosity, saturation, high-pressure fluid properties, temperature and pressure. The model is a three-dimensional reservoir grid model, considering multiple gas channeling channels.

[0149] The established model was historically fitted based on the development dynamics of CO2-driven oilfields. This was mainly achieved by utilizing differences in fluid distribution, injection-production well spacing, injection method, gas production rate of production wells, injection-production pressure difference, gas injection time, gas injection volume, gas channeling time, and production gas-oil ratio curve. Based on reservoir parameters, the model simulated oilfield development, including the overall area and single-well oil production, as well as the overall area and single-well water cut. The results were compared with the dynamic history of the actual oilfield to ensure that the model remained within the set error range, thus obtaining the fitted numerical model.

[0150] (2) The gas channel is analyzed by fitting the numerical model. Other parameter values ​​are kept unchanged. The characteristic parameters of the gas channel are analyzed by changing the production dynamic parameters. The characteristic parameters of the gas channel with gas saturation greater than 0.65 are obtained, mainly including the gas channel type, thickness and permeability, thus the location of the gas channel.

[0151] (3) Based on the obtained gas channel parameters, the volume V of each gas channel is calculated, and the formula used is shown in (1-1):

[0152]

[0153] Where V is the volume of the gas channel, m 3 ;

[0154] A is the planar area of ​​the gas channel, m 2 ;

[0155] h is the thickness of the gas channel, in meters (m).

[0156] Reservoir porosity;

[0157] n is the number of gas channeling layers.

[0158] (4) Calculate the total volume Q of the gas channel based on the volume of the gas channel, according to formula (1-2).

[0159]

[0160] in:

[0161] Q represents the total volume of the gas channel;

[0162] m represents the number of gas leakage channels.

[0163] In the same block, wells Q-3, Q-12, Q-15, and Q-21 with similar production conditions were each injected with 1264m³ of plugging agent. 3 2185m 3 2660m 3 3292m 3 During the effective period of the injected plugging agent, the increased crude oil production was 1560t, 1987t, 2263t, and 1595t, respectively, with recovery rates increasing by 17.3%, 17.8%, 18.8%, and 15.3%. Based on the numerical simulation method described above, the total gas channel volume Q of each well was 1580, 1821, 1773, and 1829 m³, respectively. 3The ratios between the plugging agent injection amount and Q were approximately 0.8, 1.2, 1.5, and 1.8, respectively. This indicates that the oil recovery rate increased most when the plugging agent injection amount was between 0.8 and 1.5Q. When it exceeded 1.5Q, the recovery rate tended to decrease because excessive plugging agent damaged the reservoir, thus reducing the increase in oil production.

[0164] Example 6

[0165] A method for improving CO2 flooding recovery by calculating plugging agent dosage using numerical simulation is proposed. This method is applied to Block A6 of the Shengli Oilfield, a high water-cut block with a permeability of 0.8 × 10⁻⁶. -3 μm 2 The oil-bearing area is 8.7 km². 2 .

[0166] The implementation steps are as follows:

[0167] (1) A geological model was established using the collected geological parameters of the CO2 flooding reservoir to simulate the CO2 flooding process. The reservoir parameters include top surface structure, bottom surface structure, sand body thickness, effective thickness, permeability, porosity, saturation, high-pressure fluid properties, temperature and pressure. The model is a three-dimensional reservoir grid model, considering multiple gas channeling channels.

[0168] The established model was historically fitted based on the development dynamics of CO2-driven oilfields. This was mainly achieved by utilizing differences in fluid distribution, injection-production well spacing, injection method, gas production rate of production wells, injection-production pressure difference, gas injection time, gas injection volume, gas channeling time, and production gas-oil ratio curve. Based on reservoir parameters, the model simulated oilfield development, including the overall area and single-well oil production, as well as the overall area and single-well water cut. The results were compared with the dynamic history of the actual oilfield to ensure that the model remained within the set error range, thus obtaining the fitted numerical model.

[0169] (2) The gas channel is analyzed by fitting the numerical model. Other parameter values ​​are kept unchanged. The characteristic parameters of the gas channel are analyzed by changing the production dynamic parameters. The characteristic parameters of the gas channel with gas saturation greater than 0.65 are obtained, mainly including the gas channel type, thickness and permeability, thus the location of the gas channel.

[0170] (3) Based on the obtained gas channel parameters, the volume V of each gas channel is calculated, and the formula used is shown in (1-1):

[0171]

[0172] Where V is the volume of the gas channel, m 3 ;

[0173] A is the planar area of ​​the gas channel, m 2 ;

[0174] h is the thickness of the gas channel, in meters (m).

[0175] Reservoir porosity;

[0176] n is the number of gas channeling layers.

[0177] (4) Calculate the total volume Q of the gas channel based on the volume of the gas channel, according to formula (1-2).

[0178]

[0179] in:

[0180] Q represents the total volume of the gas channel;

[0181] m represents the number of gas leakage channels.

[0182] In the same block, wells M-11, M-12, M-16, and M-21 with similar production conditions were each injected with 1408m of plugging agent. 3 2042m 3 3260m 3 4091m 3 During the effective period of the injected plugging agent, the increased crude oil production was 1925t, 2150t, 2523t, and 1890t, respectively, with recovery rates increasing by 17.1%, 18.0%, 19.3%, and 17.0%. Based on the numerical simulation method described above, the total gas channel volume Q of each well was 1760, 1856, 2173, and 2557 m³, respectively. 3 The ratios between the plugging agent injection amount and Q were approximately 0.8, 1.1, 1.5, and 1.6, respectively. This indicates that the oil recovery rate increased most when the plugging agent injection amount was between 0.8 and 1.5Q. When it exceeded 1.5Q, the recovery rate tended to decrease because excessive plugging agent damaged the reservoir, thus reducing the increase in oil production.

[0183] Example 7

[0184] A method for improving CO2 flooding recovery by calculating plugging agent dosage using numerical simulation is proposed. This method is applied to a CO2 flooding block in the Shengli Oilfield with a permeability of 5.1 × 10⁻⁶. -3 μm 2 The oil-bearing area is 2.34 km². 2 .

[0185] The implementation steps are as follows:

[0186] (1) A geological model was established using the collected geological parameters of the CO2 flooding reservoir to simulate the CO2 flooding process. The reservoir parameters include top surface structure, bottom surface structure, sand body thickness, effective thickness, permeability, porosity, saturation, high-pressure fluid properties, temperature and pressure. The model is a three-dimensional reservoir grid model, considering multiple gas channeling channels.

[0187] The established model was historically fitted based on the development dynamics of CO2-driven oilfields. This was mainly achieved by utilizing differences in fluid distribution, injection-production well spacing, injection method, gas production rate of production wells, injection-production pressure difference, gas injection time, gas injection volume, gas channeling time, and production gas-oil ratio curve. Based on reservoir parameters, the model simulated oilfield development, including the overall area and single-well oil production, as well as the overall area and single-well water cut. The results were compared with the dynamic history of the actual oilfield to ensure that the model remained within the set error range, thus obtaining the fitted numerical model.

[0188] (2) The gas channel was analyzed by fitting the numerical model. Other parameter values ​​were kept unchanged. The characteristic parameters of the gas channel were analyzed by changing the production dynamic parameters. The characteristic parameters of the gas channel with gas saturation greater than 0.65 were obtained, mainly including the gas channel type, thickness and permeability. Thus, the location of the gas channel was found to be near oil well 2-X91.

[0189] (3) Calculate the volume V of each gas channel based on the obtained gas channel parameters, using the formula (1-1).

[0190] (4) Calculate the total volume Q of the gas channel based on the volume of the gas channel, according to formula (1-2).

[0191] 1035m of plugging agent was injected into well 2-X91 in this block. 3 During the effective period of the injected plugging agent, the increased crude oil production was 1412 tons. According to the numerical simulation method described above, the total gas channel volume Q of each well was 796 m³. 3 The ratio between the plugging agent injection volume and Q is approximately 1.3. This indicates that when the plugging agent injection volume is 0.8-1.5Q, the plugging agent can effectively seal the gas channel between wells, resulting in a good increase in crude oil production after the measure.

[0192] Example 8

[0193] A method for improving CO2 flooding recovery by calculating plugging agent dosage using numerical simulation is proposed. This method is applied to a CO2 flooding block in the Shengli Oilfield with a permeability of 3.9 × 10⁻⁶. -3 μm 2 The oil-bearing area is 1.43 km². 2 .

[0194] The implementation steps are as follows:

[0195] (1) A geological model was established using the collected geological parameters of the CO2 flooding reservoir to simulate the CO2 flooding process. The reservoir parameters include top surface structure, bottom surface structure, sand body thickness, effective thickness, permeability, porosity, saturation, high-pressure fluid properties, temperature and pressure. The model is a three-dimensional reservoir grid model, considering multiple gas channeling channels.

[0196] The established model was historically fitted based on the development dynamics of CO2-driven oilfields. This was mainly achieved by utilizing differences in fluid distribution, injection-production well spacing, injection method, gas production rate of production wells, injection-production pressure difference, gas injection time, gas injection volume, gas channeling time, and production gas-oil ratio curve. Based on reservoir parameters, the model simulated oilfield development, including the overall area and single-well oil production, as well as the overall area and single-well water cut. The results were compared with the dynamic history of the actual oilfield to ensure that the model remained within the set error range, thus obtaining the fitted numerical model.

[0197] (2) The gas channel was analyzed by fitting the numerical model. Other parameter values ​​were kept unchanged. The characteristic parameters of the gas channel were analyzed by changing the production dynamic parameters. The characteristic parameters of the gas channel with gas saturation greater than 0.65 were obtained, mainly including the gas channel type, thickness and permeability. Thus, the location of the gas channel was found to be near oil well 4-X101.

[0198] (3) Calculate the volume V of each gas channel based on the obtained gas channel parameters, using the formula (1-1).

[0199] (4) Calculate the total volume Q of the gas channel based on the volume of the gas channel, according to formula (1-2).

[0200] 659m of plugging agent was injected into well 4-X101 in this block. 3 During the effective period of the injected plugging agent, the increased crude oil production was 307 tons. According to the numerical simulation method described above, the total volume Q of the gas channel in each well was 906 m³. 3 The ratio between the plugging agent injection amount and Q is approximately 0.73. This indicates that when the plugging agent injection amount is less than 0.8Q, the injection amount is too small to effectively block the gas channel, resulting in a reduced increase in oil production and an insignificant decrease in the gas-oil ratio.

[0201] The method of this invention can intuitively, quickly, and accurately pinpoint the location of gas channeling and determine the amount of plugging agent, thereby improving CO2 flooding recovery.

[0202] Finally, it should be noted that: the accompanying drawings of the embodiments disclosed in this invention only involve structures related to the embodiments disclosed in this invention, and other structures can be determined by reference to general principles. In the absence of conflict, the same embodiment and different embodiments of this invention can be combined with each other.

[0203] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, substitutions, or improvements made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A method for determining the dosage of a plugging agent used to block CO2-driven gas channel blockage, characterized in that, Includes the following steps: Using the reservoir numerical simulation model and calculation results, gas channeling channels with a gas saturation greater than 0.65 were selected, and the total volume of these gas channeling channels was calculated. The amount of plugging agent injected was 0.8-1.5 times the total volume of the gas channeling channels. The specific steps of the determination method are as follows: (1) Based on the seismic attributes, a single sand body level structural model and a bedding model of the study area were established. A porosity model was established through phase control constraints. The porosity simulation results were used as the second variable to conduct co-simulation with Gaussian in situ to establish a permeability model. A saturation model was established by using the J-function fitting method based on well logging curves. (2) Based on the production and pressure data obtained from actual production and testing, considering the characteristics of multiphase fluid and stress-sensitive complex seepage, we comprehensively use well test analysis and unstable production analysis methods to dynamically invert different types of wells under different reservoir and fluid conditions, quantitatively obtain local well area reservoir parameters, and provide a basis for adjusting historical fitting parameters. (3) Based on the dynamic development of CO2 flooded oil reservoirs, the established model is historically fitted. Based on the oil production of the entire reservoir area and single wells, as well as the water cut of the entire reservoir area and single wells, the reservoir development is simulated. The simulation results are compared with the dynamic history of the actual oil field to ensure that the fitting error is within the range, and the fitted numerical model is obtained.

2. The method for determining the dosage of the plugging agent for CO2-driven gas channel blocking according to claim 1, characterized in that: The analysis methods for the numerical model include: S1. Analyze the gas channel using the fitted numerical model, keep other parameter values ​​unchanged, and analyze the characteristic parameters of the gas channel by changing the production dynamic parameters; obtain the characteristic parameters of the gas channel with a gas saturation greater than a certain value. S2. Using the parameters of each gas channel obtained from the inversion, calculate the volume of each gas channel. ; （1-1） in: This refers to the volume of the gas channel, measured in meters (m). 3 ; The area of ​​the gas channel is expressed in m². 2 ; The thickness of each air channel is expressed in meters (m). Reservoir porosity; The number of gas-channeling layers; S3. Calculate the total gas channel volume based on the gas channel volume of each reservoir. Calculate according to formula (1-2); （1-2） in: The total volume of multiple gas channeling channels; The total volume is calculated by weighting several gas channel channels to determine the number of gas channel channels. S4. Determination of plugging agent injection volume; The amount of plugging agent injected is the total volume of the gas channel. 0.8-1.5 times.

3. The method for determining the dosage of the plugging agent for CO2-driven gas channel blocking according to claim 2, characterized in that: The quantitative acquisition of local well reservoir parameters includes permeability, controlled reserves, controlled radius, and skin coefficient reservoir parameters.

4. The method for determining the dosage of the plugging agent for CO2-driven gas channel blocking according to claim 2, characterized in that: The characteristic parameter of the gas channel in S1 with a gas saturation greater than a certain value, wherein the certain value is 0.64-0.

66.

5. The method for determining the dosage of the plugging agent for CO2-driven gas channel blocking according to claim 1, characterized in that: The historical fitting parameters include fluid distribution differences, injection-production well spacing, injection method, gas production rate of production wells, injection-production pressure difference, gas injection time, gas injection volume, gas channeling time, and production gas-oil ratio curve.

6. The method for determining the dosage of the plugging agent for CO2-driven gas channel blocking according to claim 1, characterized in that: The fitting error range includes oil and fluid production data for the entire region and oil and fluid production data for individual wells, with an error of less than 10%.

7. The method for determining the dosage of the plugging agent for CO2-driven gas channel blocking according to claim 2, characterized in that: The production dynamic parameters include the injection plugging dosage, gas injection volume, and daily output.

8. The method for determining the dosage of a CO2-based plugging agent for blocking gas channel passages according to claim 2, characterized in that: The optimal injection volume of the plugging agent is 1.2-1.

4. .

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