Strong heterogeneous conglomerate oil reservoir gas injection displacement physical model manufacturing method

Abstract

The invention belongs to the technical field of oil and gas field development, and particularly provides a strong heterogeneous conglomerate oil reservoir gas injection displacement physical model manufacturing method which comprises the steps that (1) an actual oil reservoir is reduced to the size needed by the model; 2) determining model parameters, and testing physical property parameters of rock debris and a glue solution in an actual oil reservoir under the condition that the rock debris and the glue solution are mixed according to different proportions; 3) setting a model well position, and filling and ramming the model; 4) testing the physical property and pore structure of the model rock core, and performing comparison verification after testing; and 5) performing a gas injection oil displacement experiment on the model, and comparing a displacement experiment result with an actual oil reservoir production result to complete model manufacturing. The problems that due to the fact that an existing conglomerate oil reservoir is high in heterogeneity, a small-scale rock core gas injection oil displacement experiment result is different from an actual reservoir gas injection oil displacement result, and a conventional large physical model modeling method is poor in conformity with the actual pore structure and heterogeneity of the reservoir are solved, the theory is combined with reality, and the testing result is more accurate and reliable; the modeling process is simple, and use is convenient; and the generalizability is high.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, specifically relating to a method for creating a physical model of gas injection displacement in a strongly heterogeneous conglomerate reservoir. Background Technology

[0002] With the continuous increase in China's demand for oil and gas resources, gas injection to enhance reservoir recovery has become a research focus. Many scholars have used indoor plunger samples or full-diameter samples to conduct gas injection experiments to study the optimal parameters for gas injection to enhance reservoir recovery. However, conglomerate reservoirs are highly heterogeneous, and small-scale samples cannot accurately characterize the impact of heterogeneity on gas injection to enhance recovery. This results in inconsistencies between small-scale core gas injection and actual reservoir gas injection results. Conventional large-scale physical modeling methods have poor consistency with the actual pore structure and heterogeneity of the reservoir. Therefore, there is an urgent need for a method to construct a physical model for gas injection displacement in highly heterogeneous conglomerate reservoirs to establish a more comprehensive experimental model for gas injection to enhance recovery in actual mining operations.

[0003] Extensive research has led to the development of a visualized fractured-vuggy reservoir displacement physical model, driving device and manufacturing method, based on patent number CN202111463410.6. This model utilizes transparent plexiglass, laser-cut according to the fractured-vuggy model design, and incorporates a base plate, cover plate and sealing silicone rubber sheet. The patent number CN202310056672.3, "Manufacturing Method of Artificial Three-Dimensional Simulation Physical Model Based on Composite Sand Body Configuration Characteristics," involves preparing different single sand body models according to their thickness ratios, then placing these models into a mold using composite sand body stacking characteristics. The different single sand body models are filled with interlayer material, and the mixture is heated and cured to form an artificial three-dimensional simulation physical model with composite sand body configuration characteristics. None of the aforementioned literature addresses the problem that the strong heterogeneity of conglomerate reservoirs leads to discrepancies between small-scale core gas injection and actual reservoir gas injection results, and that conventional large-scale physical modeling methods have poor consistency with the actual pore structure and heterogeneity of the reservoir. Summary of the Invention

[0004] The present invention provides a method for creating a physical model of gas injection displacement in strongly heterogeneous conglomerate reservoirs. The purpose is to overcome the problems in the prior art where the results of small-scale core gas injection displacement experiments differ from the actual reservoir gas injection displacement results due to the strong heterogeneity of conglomerate reservoirs, and the conventional large-scale physical modeling method has poor consistency with the actual pore structure and heterogeneity of the reservoir.

[0005] Therefore, the present invention provides a method for preparing a physical model of gas injection displacement in strongly heterogeneous conglomerate reservoirs, comprising the following steps: 1) Scale down the actual reservoir to the size required for the model; 2) Determine model parameters using actual reservoir physical property parameters, and test physical property parameters of rock cuttings and colloids mixed in different proportions in actual reservoirs; 3) Set up model well locations according to the actual reservoir well location distribution. Based on the vertical and horizontal heterogeneity of the actual reservoir, use actual reservoir rock cuttings and adhesives with different mixing ratios to fill and compact the model. 4) Drill model cores from the filled and compacted model, test the physical properties and pore structure of the model cores, and compare and verify them with the physical properties and pore structure of the actual reservoir; when the test results of the physical properties and pore structure of the model cores are within the target range of the physical properties and pore structure of the actual reservoir, proceed to step 5); when the test results of the physical properties and pore structure of the model cores are not within the target range of the physical properties and pore structure of the actual reservoir, repeat steps 1) to 4) until the test results of the physical properties and pore structure of the model cores are within the target range of the physical properties and pore structure of the actual reservoir. 5) Conduct gas injection and oil displacement experiments on the model, compare the results of the displacement experiments with the actual reservoir production results, and complete the model production when the results of the displacement experiments match the actual reservoir production results. Preferably, step 1) includes the following steps: 1.1) Determine the geometric scale of the model based on the ratio of the actual reservoir length to the length of the displacement equipment containment model; 1.2) Based on the geometric scale of the model, the relevant parameters of the actual reservoir are scaled down proportionally; the relevant parameters of the actual reservoir include the size, thickness, and angle of the actual reservoir.

[0006] Preferably, step 2) includes the following steps: 2.1) Determine model parameters using actual reservoir physical property parameters, including porosity, permeability, and oil saturation. 2.2) Mix actual reservoir cuttings and adhesives in different proportions, and use the mixtures in different proportions to build core samples. Test the relationship between different porosities, permeabilities and adhesive content in the mixtures in different proportions. By controlling the adhesive content, simulate different permeability and porosity values.

[0007] Preferably, step 3) includes the following steps: 3.1) Based on the actual well location distribution, well radius, and well depth of the actual oil reservoir, scale down the model proportionally according to the geometric scale; 3.2) Based on the actual reservoir planar and vertical heterogeneous parameters, and combined with the relationship between porosity, permeability and colloid content, multiple vertical layers that conform to the actual reservoir properties are determined. The physical property parameters of each layer in the model are the same as those of the actual conglomerate reservoir, and the model is then compacted.

[0008] Preferably, in step 4), the physical properties and pore structure of the tested material are compared and verified with those of the actual reservoir. Specifically, the porosity and permeability values ​​of the tested model core are compared and verified against the upper and lower limits of porosity and permeability of the actual reservoir.

[0009] Preferably, step 5) involves conducting a gas injection displacement experiment on the model and comparing the displacement experiment results with the actual reservoir production results, including the following steps: 5.1) Convert the displacement parameters of the actual oil reservoir into experimental test parameters; the displacement parameters include gas injection rate, well production, and gas injection time; 5.2) Conduct gas injection oil displacement experiments on a model under actual reservoir temperature and pressure conditions, and compare the results with those of actual reservoir production.

[0010] Preferably, step 1.1) specifically involves dividing the actual reservoir length by the length of the displacement device-accommodated model to obtain the geometric scale of the model.

[0011] Preferably, in step 3), the vertical and planar heterogeneity of the actual reservoir is: the heterogeneity of the physical properties of each layer in the vertical direction of the actual reservoir and the heterogeneity of the physical properties of each layer in the planar direction. The well logging data of the reservoir are statistically analyzed, and the model parameters are determined based on the actual logging physical property parameters to ensure that the vertical and planar physical property heterogeneity of the model is consistent with that of the actual reservoir.

[0012] Preferably, in step 4), when verifying the pore structure, mercury intrusion porosimetry is used. The results of mercury intrusion porosimetry on the model core are compared with the results of mercury intrusion porosimetry on the actual reservoir to verify the pore structure.

[0013] Preferably, in step 5.1), a similarity criterion is used to calculate the proportion of all displacement parameters based on geometric ratios, thereby converting the displacement parameters of the actual reservoir into experimental test parameters.

[0014] The beneficial effects of this invention are: The present invention provides a method for constructing a physical model of gas injection displacement in a strongly heterogeneous conglomerate reservoir, comprising the following steps: 1) scaling down the actual reservoir to the required model size; 2) determining model parameters using the actual reservoir's physical properties, and testing the physical properties of rock cuttings and colloids mixed in different proportions in the actual reservoir; 3) setting model well locations according to the actual reservoir's well location distribution, and filling and compacting the model with actual reservoir rock cuttings and colloids mixed in different proportions based on the vertical and planar heterogeneity of the actual reservoir; 4) drilling model cores from the filled and compacted model, testing the physical properties and pore structure of the model cores, and comparing and verifying the results with those of the actual reservoir; 5) conducting gas injection displacement experiments on the model, comparing the displacement experiment results with the actual reservoir's production results, and completing the model construction when the displacement experiment results match the actual reservoir's production results. This method combines theory with practice, resulting in more accurate and reliable test results; the modeling process is simple and convenient to use; and it has strong scalability. Attached Figure Description

[0015] The present invention will now be described in further detail with reference to the accompanying drawings.

[0016] Figure 1 This is a flowchart of the present invention; Figure 2 It is the geometric appearance drawing of the design model; Figure 3 This is a graph showing the relationship between adhesive content and permeability; Figure 4 This is a view of the model after the rammed earth construction is completed; Figure 5 This is a comparison chart of the model displacement experiment results and the actual oil production results from the reservoir; Figure 6 This is a comparison chart of the model displacement experiment results and the actual reservoir water production results.

[0017] Explanation of reference numerals in the attached diagram: 1. Left baffle; 2. Right baffle; 3. Front baffle; 4. Rear baffle. Detailed Implementation

[0018] The principles and features of the present invention are described below with reference to the accompanying drawings. The examples given are only for explaining the present invention and are not intended to limit the scope of the present invention.

[0019] Example 1: like Figure 1 As shown, a method for creating a physical model of gas injection displacement in a strongly heterogeneous conglomerate reservoir includes the following steps: 1) Scale down the actual reservoir to the size required for the model; 2) Determine model parameters using actual reservoir physical property parameters, and test physical property parameters of rock cuttings and colloids mixed in different proportions in actual reservoirs; 3) Set up model well locations according to the actual reservoir well location distribution. Based on the vertical and horizontal heterogeneity of the actual reservoir, use actual reservoir rock cuttings and adhesives with different mixing ratios to fill and compact the model. 4) Drill model cores from the filled and compacted model, test the physical properties and pore structure of the model cores, and compare and verify them with the physical properties and pore structure of the actual reservoir; when the test results of the physical properties and pore structure of the model cores are within the target range of the physical properties and pore structure of the actual reservoir, proceed to step 5); when the test results of the physical properties and pore structure of the model cores are not within the target range of the physical properties and pore structure of the actual reservoir, repeat steps 1) to 4) until the test results of the physical properties and pore structure of the model cores are within the target range of the physical properties and pore structure of the actual reservoir. 5) Conduct gas injection and oil displacement experiments on the model, compare the results of the displacement experiments with the actual reservoir production results, and complete the model production when the results of the displacement experiments match the actual reservoir production results. This invention combines theory with practice, employing novel methods to characterize the reservoir features of highly heterogeneous oil reservoirs in gas injection experiments. These methods differ significantly from current related technologies, resulting in more accurate and reliable test results. The modeling process is simple and easy to use, and it has strong scalability and broad application prospects.

[0020] Preferably, step 1) includes the following steps: 1.1) Determine the geometric scale of the model based on the ratio of the actual reservoir length to the length of the displacement equipment containment model; 1.2) Based on the geometric scale of the model, the relevant parameters of the actual reservoir are scaled down proportionally; the relevant parameters of the actual reservoir include the size, thickness, and angle of the actual reservoir.

[0021] Specifically, the model dimensions determined through this step better match the actual shape of the reservoir, resulting in higher accuracy.

[0022] Preferably, step 2) includes the following steps: 2.1) Determine model parameters using actual reservoir physical property parameters, including porosity, permeability, and oil saturation. 2.2) Mix actual reservoir cuttings and adhesives in different proportions, and use the mixtures in different proportions to build core samples. Test the relationship between different porosities, permeabilities and adhesive content in the mixtures in different proportions. By controlling the adhesive content, simulate different permeability and porosity values.

[0023] Specifically, the model parameters determined in this step are designed based on the actual values ​​of the actual reservoir, which is the same as the actual situation and easy to operate.

[0024] Preferably, step 3) includes the following steps: 3.1) Based on the actual well location distribution, well radius, and well depth of the actual oil reservoir, scale down the model proportionally according to the geometric scale; 3.2) Based on the actual reservoir planar and vertical heterogeneous parameters, and combined with the relationship between porosity, permeability and colloid content, multiple vertical layers that conform to the actual reservoir properties are determined. The physical property parameters of each layer in the model are the same as those of the actual conglomerate reservoir, and the model is then compacted.

[0025] Specifically, this operation ensures that the model better matches the actual reservoir.

[0026] Preferably, in step 4), the physical properties and pore structure of the tested material are compared and verified with those of the actual reservoir. Specifically, the porosity and permeability values ​​of the tested model core are compared and verified against the upper and lower limits of porosity and permeability of the actual reservoir.

[0027] Reduce workload during operation and improve work efficiency.

[0028] Preferably, step 5) involves conducting a gas injection displacement experiment on the model and comparing the displacement experiment results with the actual reservoir production results, including the following steps: 5.1) Convert the displacement parameters of the actual oil reservoir into experimental test parameters; the displacement parameters include gas injection rate, well production, and gas injection time; 5.2) Conduct gas injection oil displacement experiments on a model under actual reservoir temperature and pressure conditions, and compare the results with those of actual reservoir production.

[0029] The model displacement test is conducted according to the actual conditions of the reservoir, which is consistent with the actual situation.

[0030] Preferably, step 1.1) specifically involves dividing the actual reservoir length by the length of the displacement device-accommodated model to obtain the geometric scale of the model.

[0031] Specifically, the geometric proportions of the model determined in this way can better meet the requirements of the displacement equipment to accommodate the model for displacement testing, thus improving its practicality.

[0032] Preferably, in step 3), the vertical and planar heterogeneity of the actual reservoir is: the heterogeneity of the physical properties of each layer in the vertical direction of the actual reservoir and the heterogeneity of the physical properties of each layer in the planar direction. The well logging data of the reservoir are statistically analyzed, and the model parameters are determined based on the actual logging physical property parameters to ensure that the vertical and planar physical property heterogeneity of the model is consistent with that of the actual reservoir.

[0033] Preferably, in step 4), when verifying the pore structure, mercury intrusion porosimetry is used. The results of mercury intrusion porosimetry on the model core are compared with the results of mercury intrusion porosimetry on the actual reservoir to verify the pore structure.

[0034] Specifically, this operation allows for a more accurate description of the actual void structure.

[0035] Preferably, in step 5.1), a similarity criterion is used to calculate the proportions of all displacement parameters based on geometric ratios, thus converting the actual reservoir displacement parameters into experimental test parameters. This ensures that the model displacement test is conducted according to the actual reservoir conditions, conforming to real-world scenarios.

[0036] Example 2: Based on Example 1, taking a low-permeability, highly heterogeneous conglomerate reservoir as an example, this conglomerate reservoir is highly water-sensitive. To improve the oil recovery rate, CO2 injection was used. Carbon dioxide flooding experiments were carried out using plunger cores and full-diameter cores. However, these experiments could not be well integrated with the actual field conditions, and the gas injection results differed significantly. Therefore, a physical model for gas injection displacement was developed, and the actual gas injection block was selected as the research object.

[0037] Includes the following steps: 1) Scale down the actual reservoir to the size required for the model; The study area has a diameter of 7.7 km, and the model has a diameter of 44 cm, therefore the design geometric scale is 17500. 2) Determine model parameters using actual reservoir physical property parameters, and test physical property parameters of rock cuttings and colloids mixed in different proportions in actual reservoirs; 3) Set up model well locations according to the actual reservoir well location distribution. Based on the vertical and horizontal heterogeneity of the actual reservoir, use actual reservoir rock cuttings and adhesives with different mixing ratios to fill and compact the model. Specifically, the model is scaled proportionally according to the reservoir well location distribution, and the well locations are set. The geometric appearance of the model is designed as follows: Figure 2 As shown, actual reservoir cuttings and adhesives were mixed and tested to measure the physical properties of the mixtures at different proportions. The test results are as follows. Figure 3 As shown, based on the actual reservoir heterogeneity, the model is designed with three layers. The planar heterogeneity is controlled by the actual permeability range of the reservoir. Based on the logging results of each well, the physical properties of each layer of the model are shown in Table 1 below.

[0038] Table 1. Physical properties of each layer of the model

[0039] Based on the vertical and planar heterogeneity of the reservoir, different actual reservoir rock cuttings and colloid mixing ratios were used for model filling and compaction.

[0040] 4) Drill model cores from the filled and rammed model, test the physical properties and pore structure of the model cores, and then compare and verify them with the physical properties and pore structure of the actual oil reservoir. The model after ramming is as follows Figure 4As shown, core samples of the model plunger were drilled to test physical properties and pore structure, and compared with the actual reservoir for verification. The porosity-permeability comparison results are shown in Table 2 below. The porosity-permeability values ​​are basically consistent with the actual reservoir results, and the heterogeneity of the rock sample is consistent with the actual reservoir conditions.

[0041] Table 2 Comparison of porosity and permeability between the model and actual reservoirs

[0042] Mercury intrusion porosimetry was conducted on the second layer of rock samples to obtain the pore structure. The results of the comparison with the actual pore structure of the reservoir are shown in Table 3 below. The pore structure parameters of the three rock samples are all within the range of the actual reservoir pore parameters.

[0043] Table 3. Comparison of pore structure between the second layer rock sample from the model and the actual reservoir pore structure.

[0044] 5) Conduct gas injection and oil displacement experiments on the model, compare the results of the displacement experiments with the actual reservoir production results, and complete the model production when the results of the displacement experiments match the actual reservoir production results.

[0045] The model flow is Darcy flow. Based on geometric scaling, the Reynolds similarity criterion is selected to calculate the proportions of other parameters. Then, parameters are transformed according to the actual reservoir and transferred to the model for displacement experiments. The model displacement uses a mixture of crude oil from the oilfield and formation water, with temperature and pressure values ​​matching those of the actual reservoir. Carbon dioxide displacement experiments are conducted, and the results are compared with the actual reservoir production results (after similarity scaling). The oil production comparison results are as follows: Figure 5 As shown in the figure, the comparison results of water production are as follows: Figure 6 As shown, the fitting accuracy of water production and oil production reaches over 90%, indicating high reliability of the results.

[0046] In the description of this invention, it should be understood that if terms such as "front," "inside," or "right" indicate an orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, it does not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, the terms used to describe positional relationships in the accompanying drawings are for illustrative purposes only and should not be construed as limiting the invention.

[0047] The above examples are merely illustrative of the present invention and do not constitute a limitation on the scope of protection of the present invention. All designs that are the same as or similar to the present invention are within the scope of protection of the present invention.

Claims

1. A method for constructing a physical model for gas injection displacement in a strongly heterogeneous conglomerate reservoir, characterized in that: Includes the following steps: 1) Scale down the actual reservoir to the size required for the model; 2) Determine model parameters using actual reservoir physical property parameters, and test physical property parameters of rock cuttings and colloids mixed in different proportions in actual reservoirs; 3) Set up model well locations according to the actual reservoir well location distribution. Based on the vertical and horizontal heterogeneity of the actual reservoir, use actual reservoir rock cuttings and adhesives with different mixing ratios to fill and compact the model. 4) Drill model cores from the filled and compacted model, test the physical properties and pore structure of the model cores, and compare and verify them with the physical properties and pore structure of the actual reservoir; when the test results of the physical properties and pore structure of the model cores are within the target range of the physical properties and pore structure of the actual reservoir, proceed to step 5); when the test results of the physical properties and pore structure of the model cores are not within the target range of the physical properties and pore structure of the actual reservoir, repeat steps 1) to 4) until the test results of the physical properties and pore structure of the model cores are within the target range of the physical properties and pore structure of the actual reservoir. 5) Conduct gas injection and oil displacement experiments on the model, compare the results of the displacement experiments with the actual reservoir production results, and complete the model production when the results of the displacement experiments match the actual reservoir production results.

2. The method for creating a physical model for gas injection displacement in a strongly heterogeneous conglomerate reservoir as described in claim 1, characterized in that: Step 1) includes the following steps: 1.1) Determine the geometric scale of the model based on the ratio of the actual reservoir length to the length of the displacement equipment containment model; 1.2) Based on the geometric scale of the model, the relevant parameters of the actual reservoir are scaled down proportionally; the relevant parameters of the actual reservoir include the size, thickness, and angle of the actual reservoir.

3. The method for creating a physical model for gas injection displacement in a strongly heterogeneous conglomerate reservoir as described in claim 1, characterized in that: Step 2) includes the following steps: 2.1) Determine model parameters using actual reservoir physical property parameters, including porosity, permeability, and oil saturation. 2.2) Mix actual reservoir cuttings and adhesives in different proportions, and use the mixtures in different proportions to build core samples. Test the relationship between different porosities, permeabilities and adhesive content in the mixtures in different proportions. By controlling the adhesive content, simulate different permeability and porosity values.

4. The method for creating a physical model for gas injection displacement in a strongly heterogeneous conglomerate reservoir as described in claim 2, characterized in that: Step 3) includes the following steps: 3.1) Based on the actual well location distribution, well radius, and well depth of the actual oil reservoir, scale down the model proportionally according to the geometric scale; 3.2) Based on the actual reservoir planar and vertical heterogeneous parameters, and combined with the relationship between porosity, permeability and colloid content, multiple vertical layers that conform to the actual reservoir properties are determined. The physical property parameters of each layer in the model are the same as those of the actual conglomerate reservoir, and the model is then compacted.

5. The method for creating a physical model for gas injection displacement in a strongly heterogeneous conglomerate reservoir as described in claim 1, characterized in that: In step 4), the physical properties and pore structure of the tested model core are compared and verified with those of the actual reservoir. Specifically, the porosity and permeability values ​​of the tested model core are compared and verified against the upper and lower limits of porosity and permeability of the actual reservoir.

6. The method for creating a physical model for gas injection displacement in a strongly heterogeneous conglomerate reservoir as described in claim 2, characterized in that: Step 5) involves conducting a gas injection oil displacement experiment on the model and comparing the experimental results with the actual reservoir production results. This includes the following steps: 5.1) Convert the displacement parameters of the actual oil reservoir into experimental test parameters; the displacement parameters include gas injection rate, well production, and gas injection time; 5.2) Conduct gas injection oil displacement experiments on a model under actual reservoir temperature and pressure conditions, and compare the results with those of actual reservoir production.

7. The method for creating a physical model for gas injection displacement in a strongly heterogeneous conglomerate reservoir as described in claim 2, characterized in that: Step 1.1) specifically involves dividing the actual reservoir length by the length of the displacement equipment-accommodated model to obtain the geometric scale of the model.

8. The method for creating a physical model for gas injection displacement in a strongly heterogeneous conglomerate reservoir as described in claim 1, characterized in that: In step 3), the vertical and planar heterogeneity of the actual reservoir is as follows: the heterogeneity of the physical properties of each layer in the vertical direction of the actual reservoir and the heterogeneity of the physical properties of each layer in the planar direction. The well logging data of the reservoir are statistically analyzed, and the model parameters are determined based on the actual logging physical property parameters to ensure that the vertical and planar physical property heterogeneity of the model is consistent with that of the actual reservoir.

9. The method for creating a physical model for gas injection displacement in a strongly heterogeneous conglomerate reservoir as described in claim 5, characterized in that: In step 4), when verifying the pore structure, mercury intrusion porosimetry is used. The results of mercury intrusion porosimetry on the model core are compared with the results of mercury intrusion porosimetry on the actual reservoir to verify the pore structure.

10. The method for creating a physical model for gas injection displacement in a strongly heterogeneous conglomerate reservoir as described in claim 6, characterized in that: In step 5.1), the similarity criterion is used to calculate the proportion of all displacement parameters based on the geometric ratio, and the displacement parameters of the actual reservoir are converted into experimental test parameters.

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