Reservoir permeability prediction method in oil reservoir development process

Abstract

The invention discloses a reservoir permeability prediction method in an oil reservoir development process, and the method comprises the following steps: carrying out the statistics of mine field production data, and obtaining the real overlying rock pressure of an oil reservoir; drilling a standard plunger rock sample of the oil reservoir, loading pressure to age the rock sample, and recovering the stress condition of the rock sample reservoir; real conditions of an oil reservoir are simulated, a permeability test experiment with constant confining pressure and variable pore pressure is carried out, and a curve that the permeability of the rock sample changes along with the pore pressure is obtained; establishing a function relationship of reservoir permeability changing along with pore pressure; based on mine field statistical data, the change relation of pore pressure along with time in the actual production process is obtained, a reservoir real permeability time-varying model is established, and the reservoir permeability in the actual production process is predicted. The reservoir permeability prediction method provided by the invention is reliable, can restore the real conditions of the reservoir, accurately predicts the reservoir permeability change in the actual production process, and provides technical support for efficient development of oil reservoirs.

Description

Technical Field

[0001] The present invention relates to a method for predicting reservoir permeability during reservoir development, belonging to the technical field of oil and gas field development. Background Art

[0002] Permeability is an important physical property of reservoir rocks in oil reservoirs, indicating the property of rocks allowing fluids (oil, gas, water) to pass through under a certain pressure difference. The magnitude of permeability is represented by permeability. When reservoir rocks in an oil reservoir are buried underground in the original formation state, the stress they are subjected to is in equilibrium, and the physical properties of the reservoir rocks are relatively stable. However, as reservoir fluids are continuously produced, the internal seepage channels of the rocks begin to close, the permeability of the reservoir rocks decreases, making fluid flow difficult and affecting the production of oil and gas reservoirs, resulting in a reduction in production. At this time, reservoir evaluation and adjustment of the development plan are required to improve the recovery rate of the oil reservoir. Accurately obtaining the true permeability of the reservoir rocks during the development process is the key to reservoir evaluation and adjustment of the development plan.

[0003] Currently, the permeability of reservoir rocks in oil reservoirs is mainly obtained through well logging interpretation inversion, well testing calculation, high-pressure mercury injection experiment calculation, and nuclear magnetic resonance response inversion. However, the obtained permeabilities are all the permeabilities of reservoir rocks in the initial stage of development or in the undeveloped stage, and cannot accurately reflect the true permeability of oil and gas reservoirs during the development process, and have no guiding significance for the evaluation of oil and gas reservoirs and the adjustment of the development plan during the development process. For example, the Chinese patent "A method and device for calculating nuclear magnetic permeability of shale reservoirs" with the publication number CN118131342A provides a method and device for accurately calculating the permeability of shale reservoirs based on nuclear magnetic well logging data, and proposes a permeability calculation model suitable for dual media. However, the calculated permeability is the original permeability of the reservoir, which does not match the true permeability of the reservoir during the development process and is only applicable to shale reservoirs, having certain limitations.

[0004] The Chinese patent "A method for calculating the permeability of carbonate rock reservoirs" with the publication number CN118094366A combines high-pressure mercury injection experiments with machine learning to calculate the permeability of carbonate rock reservoirs with complex reservoir spaces and combined characteristics. However, the obtained permeability is the original permeability of the reservoir, which does not match the true permeability of the reservoir during the development process and is only applicable to carbonate rock reservoirs, having certain limitations.

[0005] The Chinese patent "A method, device, electronic device and storage medium for determining formation permeability" with the publication number CN119129253A obtains the reservoir permeability based on the mud invasion process and rock sample electrical experiments. However, the obtained permeability is still the original permeability of the reservoir, which does not match the true permeability of the reservoir during the development process, having certain limitations. Summary of the Invention

[0006] In view of the above problems, the present invention provides a method for predicting reservoir permeability during the reservoir development process.

[0007] The purpose of the present invention is to carry out indoor experiments by simulating reservoir production conditions, establish a permeability prediction model during the development process of the reservoir, accurately predict and calculate the reservoir permeability at any time during the development process, guide the adjustment of the reservoir development plan and reservoir evaluation, and improve the reservoir development effect.

[0008] To achieve the above purpose, the present invention adopts the following technical solutions:

[0009] Step 1: Select a production well in the reservoir, count the production data of the well, and obtain the reservoir pore pressure data during the production process of the well and the true overlying rock pressure P of the reservoir controlled by the well p ;

[0010] Step 2: Based on the production well selected in Step 1, drill a standard plug rock sample of the reservoir of the well, load pressure to age the rock sample, and restore the reservoir stress conditions of the rock sample;

[0011] Step 3: Based on the true overlying rock pressure P of the reservoir obtained in Step 1 p and the standard plug rock sample drilled in Step 2, simulate the true pressure conditions of the reservoir and the pressure reduction production process, conduct permeability tests on the plug rock sample, calculate the permeability of the plug rock sample, and obtain the curve of the permeability of the rock sample varying with the pore pressure at the inlet end of the rock sample under the true conditions of the simulated reservoir;

[0012] Step 4: Based on the curve of the permeability of the rock sample varying with the pore pressure of the rock sample under the true conditions of the simulated reservoir obtained in Step 3, establish a functional relationship between the permeability and the pore pressure;

[0013] Step 5: Based on the reservoir pore pressure data during the production process of the well obtained in Step 1, obtain the relationship between the pore pressure and time during the actual production process, and combine with the functional relationship between the permeability and the pore pressure obtained in Step 4 to establish a time-varying model of the reservoir permeability, and predict the reservoir permeability during the actual production process.

[0014] Advantages of the Invention

[0015] The present invention provides a method for predicting reservoir permeability during the reservoir development process. By combining the actual production dynamics of the reservoir and indoor permeability test experiments, the true permeability change of the reservoir during the reservoir development process is obtained, and a time-varying calculation and prediction model of the reservoir permeability is established. The calculated permeability is true and reliable, solving the problem of the mismatch between the permeability obtained in previous studies and the true formation permeability during the development process. It has important guiding significance for the design of various reservoir development plans, the adjustment of development plans, reservoir dynamic evaluation, the study of remaining oil distribution, and the study of production decline, and can greatly improve the development effect of various reservoirs. Brief Description of the Drawings

[0016] Figure 1 is the abstract drawing;

[0017] Figure 2 is the calculation result of nitrogen viscosity correction;

[0018] Figure 3 is the schematic diagram of the loading and unloading pressure setting during the aging process of the rock sample;

[0019] Figure 4 is the schematic diagram of the experimental pressure setting for the constant confining pressure and variable pore pressure permeability test under the simulated real reservoir conditions;

[0020] Figure 5 is the curve of the permeability changing with the pore pressure at the inlet end of the rock sample holder under the simulated real reservoir conditions;

[0021] Figure 6 is the schematic diagram of the function relationship between the reservoir permeability and the pore pressure at the inlet end of the rock sample holder fitted by MATLAB;

[0022] Figure 7 is the curve of the pore pressure changing with time during the production process of Well A1 in Reservoir A;

[0023] Figure 8 is the schematic diagram of the function relationship between the reservoir pore pressure and time during the production process of Well A1 in Reservoir A fitted by MATLAB. Detailed implementation manners

[0024] In order to enable those skilled in the art to better understand the technical solution of the present invention and be able to implement it, the present invention will be described in detail below with reference to the accompanying drawings and specific embodiments. The following embodiments are only used to more clearly illustrate the technical solution of the present invention and cannot be used to limit the protection scope of the present invention.

[0025] In one embodiment, a method for predicting reservoir permeability during the development process of an oil reservoir is specifically described taking Reservoir A in a certain place as an example, and includes the following steps:

[0026] Step 1: Select Well A1 in Reservoir A, count the production data of this well, obtain the reservoir pore pressure data during the production process of this well, and obtain the true overlying rock pressure P of the reservoir controlled by this well p is 45 MPa.

[0027] Step 2: Drill a standard plug rock sample with a diameter L of 2.5 cm and a length d of 5 cm from the reservoir of Well A1 in Reservoir A, wash the oil, dry it and measure the porosity φ and mass m to complete the pretreatment of the plug rock sample;

[0028] Put the pretreated rock sample into the rock sample holder, and check the experimental equipment to ensure that there is no leakage in the experimental equipment and pipelines;

[0029] Load the confining pressure P of the rock sample holder c After reaching 5 MPa, load the pore pressure P at the inlet end of the rock sample holder f To 1 MPa. Keep the pore pressure at the inlet end of the rock sample holder unchanged at 1 MPa. Load the confining pressure of the rock sample holder in the order of 10 MPa, 15 MPa, 20 MPa, 25 MPa, 30 MPa, 35 MPa, 40 MPa, 45 MPa. Wait for 20 minutes at each confining pressure to reach a stable state. The highest pressure loaded, 45 MPa, is the actual overlying rock pressure of the reservoir in Well A1;

[0030] Subsequently, keep the pore pressure at 1 MPa and unload the confining pressure in the loading order. During the unloading process, wait for 50 minutes at each confining pressure to reach a stable state. Until the confining pressure is unloaded to 5 MPa, complete the stress aging cycle of the rock sample and restore the true reservoir stress conditions of the rock sample. The pressure settings during the aging process are as Figure 1 shown

[0031] Step 3: Keep the confining pressure P of the rock sample holder c At 5 MPa, load the pore pressure P at the inlet end of the rock sample holder f To 3 MPa. After loading, wait for 50 minutes so that the pore pressure at the inlet end of the rock sample remains at 3 MPa and a stable displacement pressure difference is established;

[0032] Load the confining pressure to 10 MPa, load the pore pressure at the inlet end of the rock sample holder to 8 MPa. After loading, wait for 50 minutes so that the pore pressure at the inlet end of the rock sample remains at 8 MPa and a stable displacement pressure difference is established;

[0033] Load the confining pressure to 15 MPa, load the pore pressure at the inlet end of the rock sample holder to 13 MPa. After loading, wait for 50 minutes so that the pore pressure at the inlet end of the rock sample remains at 13 MPa and a stable displacement pressure difference is established;

[0034] Load the confining pressure to 20 MPa, load the pore pressure at the inlet end of the rock sample holder to 18 MPa. After loading, wait for 50 minutes so that the pore pressure at the inlet end of the rock sample remains at 18 MPa and a stable displacement pressure difference is established;

[0035] Load the confining pressure to 25 MPa, load the pore pressure at the inlet end of the rock sample holder to 23 MPa. After loading, wait for 50 minutes so that the pore pressure at the inlet end of the rock sample remains at 23 MPa and a stable displacement pressure difference is established;

[0036] Load the confining pressure to 30 MPa, load the pore pressure at the inlet end of the rock sample holder to 28 MPa. After loading, wait for 50 minutes so that the pore pressure at the inlet end of the rock sample remains at 28 MPa and a stable displacement pressure difference is established;

[0037] Apply confining pressure up to 35 MPa, apply pore pressure at the inlet end of the rock sample holder up to 33 MPa, and wait for 50 min after loading so that the pore pressure at the inlet end of the rock sample remains at 33 MPa and a stable displacement pressure difference is established;

[0038] Apply confining pressure up to 40 MPa, apply pore pressure at the inlet end of the rock sample holder up to 38 MPa, and wait for 50 min after loading so that the pore pressure at the inlet end of the rock sample remains at 38 MPa and a stable displacement pressure difference is established;

[0039] Apply confining pressure up to 45 MPa, apply pore pressure at the inlet end of the rock sample holder up to 43 MPa, and wait for 50 min after loading so that the pore pressure at the inlet end of the rock sample remains at 43 MPa and a stable displacement pressure difference is established. At this time, stop loading, record the gas flow rate value q0 of the flowmeter at the outlet end of the rock sample holder, and record the pore pressure P at the outlet end of the rock sample holder simultaneously e 、experimental temperature T, pore pressure P at the inlet end of the rock sample holder f 、confining pressure P of the rock sample holder c , and calculate the permeability of the rock sample under this condition;

[0040] Keep the confining pressure of the rock sample holder at 45 MPa, and unload the pore pressure at the inlet end of the rock sample holder in the order of 38 MPa, 33 MPa, 28 MPa, 23 MPa, 18 MPa, 13 MPa, 8 MPa, 3 MPa. The pressure settings during the entire loading and unloading process are as Figure 2 shown. Wait for 50 min at each pore pressure value P at the inlet end of the rock sample holder f so that the pressure remains constant at the set value and a stable displacement pressure difference is established. Record the gas flow rate value q0 of the flowmeter at the outlet end of the rock sample holder in each state, and record the pore pressure P at the outlet end of the rock sample holder simultaneously e 、experimental temperature T, pore pressure P at the inlet end of the rock sample holder f 、confining pressure P of the rock sample holder c , and calculate the permeability of the rock sample under different pore pressures under the condition of simulating the true overlying rock pressure of the reservoir;

[0041] Taking the pore pressure P at the inlet end of the rock sample holder f as the independent variable and the rock sample permeability k as the dependent variable, plot the curve of permeability changing with pore pressure under the condition of simulating the true conditions of the reservoir, as Figure 3 shown;

[0042] The above permeability calculation process:

[0043] Conduct viscosity correction on the experimental gas nitrogen to obtain the true viscosity of the experimental nitrogen at different pressures, as Figure 4 shown. The viscosity correction calculation formula is as follows:

[0044] When p ≤ 9 MPa:

[0045]

[0046] When p > 9 MPa:

[0047] μ = (0.0377×p + 1.576)×10 -2

[0048] where μ is the viscosity of the experimental gas nitrogen after correction, mPa·s; T is the experimental temperature, °C; P f is the pore pressure at the inlet end of the rock sample holder, MPa; P e is the pore pressure at the outlet end of the rock sample holder, MPa; P0 is the atmospheric pressure, MPa;

[0049] After completing the viscosity correction of the experimental gas, calculate the permeability k of the experimental rock sample:

[0050]

[0051] where k is the permeability of the experimental rock sample, mD; P0 is the atmospheric pressure, MPa; P f is the pore pressure at the inlet end, MPa; P e is the pressure at the outlet end, MPa; q0 is the gas volume flow rate recorded by the gas flow meter, mL / s; μ is the viscosity of nitrogen after correction, mPa·s; L is the length of the experimental rock sample, cm; d is the diameter of the experimental rock sample, cm.

[0052] Step 4: Import the experimental data points of the change in rock sample permeability with the pore pressure at the inlet end of the rock sample holder into the MATLAB numerical modeling software. Select linear function, polynomial, exponential function, power function, and logarithmic function to fit the experimental data. Select the function with a fitting accuracy greater than 99% to establish the functional relationship between the rock sample permeability and the pore pressure at the inlet end of the rock sample holder, which is the functional relationship between the reservoir permeability and the pore pressure at the inlet end of the rock sample holder. The fitting curve is as Figure 4 shown. The fitting accuracy of the exponential function is 99.3%, with a high fitting accuracy and meeting the requirements. The obtained function is:

[0053]

[0054] where k is the permeability of the experimental rock sample, which is the reservoir permeability, mD; P f is the pore pressure at the inlet end of the rock sample holder, MPa;

[0055] Step 5: According to the production data statistically in Step 1, obtain the curve of the change in reservoir pore pressure P f1 with time during the actual production process of Well A1, as Figure 5As shown, the MATLAB numerical modeling software is used to fit the curve to obtain the functional relationship between the reservoir pore pressure and time in the actual production process. The fitted curve is as Figure 6 shown. A functional relationship is established by selecting a function with a fitting accuracy greater than 99%. The polynomial fitting accuracy is 99.08%, which has a high fitting accuracy and meets the requirements. The obtained function is:

[0056] P f1 =-1E -11 t 6 +6E -9 t 5 -1E -6 t 4 +0.0001t 3 -0.0059t 2 +0.0263t+18.165

[0057] where P f1 is the reservoir pore pressure in the actual production process, MPa; t is the production time of the oil reservoir, d;

[0058] Substitute the functional relationship between the reservoir pore pressure and time in the actual production process into the functional relationship between the reservoir permeability and the pore pressure at the inlet end of the rock sample holder obtained from the experiment to obtain the prediction calculation formula for the reservoir permeability in the actual production process. The specific formula is as follows:

[0059]

[0060] where k is the reservoir permeability, mD; t is the production time of the oil reservoir, d;

[0061] In the above substitution process, the pore pressure at the inlet end of the rock sample holder is equal to the reservoir pore pressure in the actual production process;

[0062] Select different time points, and the true permeability of the reservoir of Well A1 in Reservoir A at any time can be predicted and calculated according to the above formula.

[0063] The above is only a preferred embodiment of the present invention, and it does not impose any form of limitation on the present invention. Although the present invention has been disclosed above with a preferred embodiment, 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 make equivalent embodiments of equivalent changes within the scope of the technical solution of the present invention. However, as long as it does not depart from the content of the technical solution of the present invention, any simple modification, equivalent change, and modification made to the above embodiments based on the technical essence of the present invention still fall within the scope of the technical solution of the present invention.

Claims

1. A method for predicting reservoir permeability during the oil reservoir development process, characterized in that, It includes the following steps: Step 1: Select a production well in the reservoir, count the production data of the well, and obtain the reservoir pore pressure data during the production process of the well and the true overburden rock pressure P of the reservoir controlled by the well p ; Step 2: Based on the production well selected in Step 1, drill a standard plug rock sample of the reservoir of this well, age the rock sample under pressure loading, and restore the reservoir stress conditions of the rock sample; Step 3: Based on the true overburden rock pressure P obtained in Step 1 p and the standard plunger core samples drilled in Step 2, simulate the true pressure conditions of the reservoir and the pressure reduction production process, conduct permeability tests on the plunger core samples, calculate the permeability of the plunger core samples, and obtain the curve of the permeability of the core samples varying with the pore pressure at the inlet end of the core samples under the true conditions of the simulated reservoir. Step 4: Based on the curve of the permeability of the rock sample varying with the pore pressure of the rock sample under the true conditions of the simulated reservoir obtained in Step 3, establish the functional relationship between the permeability and the pore pressure; Step 5: Based on the reservoir pore pressure data during the production process of this well obtained in Step 1, obtain the relationship between the pore pressure and time during the actual production process, and combine the functional relationship between the permeability and the pore pressure obtained in Step 4 to establish a time-varying model of the reservoir permeability, and predict the reservoir permeability during the actual production process.

2. The reservoir permeability prediction method during the reservoir development process according to claim 1, characterized in that, The characteristic steps of the pressure setting during the aging of the rock sample in Step 2 include: Step S2-1: Load the confining pressure P c After loading to 5 MPa, load the pore pressure P at the inlet end of the rock sample f to 1 MPa, keep the pore pressure at the inlet end of the rock sample unchanged at 1 MPa, load the confining pressure, load 5 MPa each time, and stabilize for 20 min under each confining pressure until the confining pressure is loaded to the true overburden rock pressure P of the reservoir p value, then stop loading, and wait for the time T 1， Ensure that the confining pressure has been loaded to the true overburden rock pressure P of the reservoir p value and remains in a stable state; The value of the waiting time T1 is: 30 min to 150 min; Step S2-2: Keep the pore pressure at the inlet end of the rock sample at 1 MPa, unload the confining pressure in sequence according to the loading order, and wait for the time T2 under each confining pressure during the unloading process to ensure that the confining pressure is unloaded to the predetermined value and remains stable until the confining pressure is unloaded to 5 MPa, then complete the aging cycle of the rock sample and restore the true reservoir stress conditions of the rock sample; The value of the waiting time T2 is: 30 min to 150 min.

3. A method for predicting reservoir permeability during the oil reservoir development process according to claim 1, characterized in that The characteristic steps of the pressure setting during the permeability test of the plug rock sample in Step 3 include: Step S3-1: Keep the confining pressure P c at 5 MPa, and load the pore pressure P at the inlet end of the rock sample f to 3 MPa. After loading, wait for a time T3 until the pore pressure at the inlet of the rock sample remains at 3 MPa and a stable displacement pressure difference is established; The value of the waiting time T3 is: 30 min to 150 min; Step S3-2: Continue to load the confining pressure, with each loading value of 5 MPa; for each loading of the confining pressure, load the pore pressure at the inlet of the rock sample correspondingly, and each loading value of the inlet pore pressure is 2 MPa lower than the confining pressure value, and wait for the time T4 after each loading until the pore pressure at the inlet end of the rock sample remains at the set value and a stable displacement pressure difference is established; The value of the waiting time T4 is: 30 min to 150 min; Step S3-3: Load the confining pressure to the actual overlying rock pressure value P of the reservoir p The loading is stopped when the pore pressure at the inlet of the rock sample is P f =P p -2, record the gas flow value q0 at the outlet of the rock sample, and record the pore pressure P at the outlet of the rock sample e , experimental temperature T, pore pressure at the inlet of the rock sample P f , rock sample confining pressure P c , calculate the permeability of the rock sample in this state; Step S3-4: Maintain the confining pressure P c as the true overburden rock pressure P of the reservoir p , unload the pore pressure at the inlet end of the rock sample, unload 5 MPa each time, wait for time T5 at each pore pressure until the pore pressure at the inlet end of the rock sample remains constant at the set value and a stable displacement pressure difference is established, record the gas flow rate value q0 at the outlet end of the rock sample, and at the same time record the pore pressure P e at the outlet end of the rock sample, the experimental temperature T, the pore pressure P f at the inlet end of the rock sample, the confining pressure P c of the rock sample, and the gas flow rate value q0 at the outlet end of the rock sample; The value of the waiting time T5 is: 30 min to 150 min.

4. The reservoir permeability prediction method during reservoir development according to claim 1, characterized in that The steps of calculating the permeability of the plug rock sample in Step 3 include: Perform viscosity correction on the experimental gas nitrogen: When p ≤ 9 MPa: When p > 9 MPa: μ = (0.0377×p + 1.576)×10 -2 Formula 2 where μ is the viscosity of the experimental gas nitrogen after correction, mPa·s; T is the experimental temperature, °C; P f is the pore pressure at the inlet end of the rock sample, MPa; P e is the pore pressure at the outlet end of the rock sample, MPa; P0 is the atmospheric pressure, MPa; After completing the viscosity correction of the experimental gas, calculate the permeability k of the rock sample: Among them, k is the permeability of the rock sample, in mD; P0 is the atmospheric pressure, in MPa; P f is the pore pressure at the inlet end of the rock sample, in MPa; P e is the pressure at the outlet end of the rock sample, in MPa; q0 is the gas flow rate, in mL / s; μ is the corrected nitrogen viscosity, in mPa·s; L is the length of the experimental rock sample, in cm; d is the diameter of the experimental rock sample, in cm.

5. A method for predicting reservoir permeability during the oil reservoir development process according to claim 1, characterized in that Step 4 includes: Import the data points of the curve of the permeability varying with the pore pressure obtained from the experiment into the MATLAB numerical modeling software, select polynomial, exponential function, power function and logarithmic function to fit the experimental data, and select the function with a fitting accuracy greater than 99% to establish the functional relationship between the permeability of the rock sample and the pore pressure at the inlet end of the rock sample, that is, the reservoir permeability with: k = f(P f ) Equation 4 where k is the permeability of the rock sample, which is the reservoir permeability, in mD; P f is the pore pressure at the inlet end of the rock sample, in MPa; The above-obtained functional relationship between the permeability of the rock sample and the pore pressure at the inlet end of the rock sample is the functional relationship between the reservoir permeability and the pore pressure at the inlet end of the rock sample.

6. The reservoir permeability prediction method during reservoir development according to claim 1, wherein Step 5 includes: Based on the reservoir pore pressure data during the production process of a certain well, obtain the reservoir pore pressure P during the actual production process f ’ relationship curve with time. Use the MATLAB numerical modeling software to fit the curve to obtain the function of the reservoir pore pressure changing with time during the actual production process. Select the function with a fitting accuracy greater than 99% to establish the functional relationship between the reservoir pore pressure and time: P f1 = f(t) Equation 5 Among which P f1 is the pore pressure of the reservoir during the actual production process, MPa; t is the production time, d; Substitute the functional relationship between the pore pressure and time during the production process into the obtained functional relationship between the reservoir permeability and the pore pressure at the inlet end of the rock sample to obtain the time-varying calculation model of the reservoir permeability during the actual production process. The specific formula is as follows: k = f(P f ) = f(P f ) = f(t) Equation 6 During the substitution process, the pore pressure P at the inlet end of the rock sample f is equal to the reservoir pore pressure P during the actual production process f '; the true permeability of the reservoir at any time can be predicted according to Formula 6.

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