Method and device for testing dynamic flowing capacity of pores of heavy oil reservoir

Abstract

The invention relates to the technical field of oil and gas field development, in particular to a heavy oil reservoir pore dynamic flow capacity testing method and device.The method comprises the steps that physical property parameters, mineral component percentage proportion and rock mechanical parameters of a standard rock sample of a target reservoir section and the viscosity of a crude oil sample at the target reservoir temperature are tested, and the reservoir coefficient of the tested rock sample is calculated; the method comprises the following steps: evaluating the flowing capacity of rock, calculating a fracture density coefficient of the target reservoir rock, evaluating the natural fracture development degree of the target reservoir rock, obtaining the thickness distribution of a longitudinal interlayer of the target reservoir, calculating a proportion coefficient of the longitudinal interlayer of the target reservoir, evaluating the longitudinal heterogeneity of the target reservoir, and calculating a dynamic flowing capacity coefficient of rock pores. And obtaining the rock pore flow capacity. The flow capacity coefficient is established for the first time to evaluate the dynamic flow capacity, the method is simple, feasible and high in operability, and the dynamic flow capacity of the pores of the heavy oil reservoir can be quantitatively evaluated, so that the purpose of efficiently developing the heavy oil reservoir is achieved.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, and is a method and apparatus for testing the dynamic flow capacity of pores in heavy oil reservoirs. Background Technology

[0002] China is the world's fourth largest producer of heavy oil, with proven onshore reserves of approximately 40 × 10⁻⁶. 8 Heavy oil, mainly distributed in the Liaohe, Xinjiang, and Turpan-Hami oil-producing regions, contains a large amount of gum and asphaltenes, resulting in high viscosity and extremely poor flow properties under formation conditions. Conventional development methods are difficult to implement in most heavy oil reservoirs. Therefore, current methods primarily employ steam injection, steam drive, conventional cold recovery, reservoir combustion, and thermal composite development to reduce crude oil viscosity and improve recovery rates. Reservoir flow properties are a core factor directly influencing the selection of development methods, optimization of process parameters, and development effectiveness; accurate quantitative evaluation is crucial for heavy oil development technology decisions. In particular, due to the extremely high viscosity of heavy oil, gravity-driven combined flow is the core mechanism of heavy oil development during thermal recovery, and vertical interlayers are a key factor affecting flow. However, due to heterogeneity, quantitative evaluation of pore flow in heavy oil is extremely difficult.

[0003] Currently, pore flow capacity is mainly evaluated from a static perspective or through experimental methods, but these methods do not fully consider all influencing factors. There are few studies on dynamic flow capacity evaluation methods for heavy oil reservoirs, and no relevant reports have been published.

[0004] Through research, current methods for evaluating the pore flow capacity of unconventional reservoirs include: Chinese patent document CN110886596B discloses an experimental apparatus and method for simulating carbon dioxide to improve the flow capacity of heavy oil. This method primarily compares the starting pressure gradient and oil-water two-phase displacement efficiency of crude oil before and after carbon dioxide injection, and simulates the flow state of crude oil under different permeability, viscosity, temperature, and pressure conditions. However, this experimental method does not consider natural fractures, a core factor affecting rock pore flow capacity, and its impact on reservoir interlayers and heterogeneity is also incomplete. Chinese patent document CN114252382A discloses a method for characterizing the oil-gas phase balance and flow capacity of porous rock media. This method uses the rock fractal dimension and pore size to obtain the relationship curve between oil-gas capillary force and gas saturation in the rock, establishes an oil-gas phase balance model, calculates the capillary force, obtains the distribution of oil and gas in pores of different sizes, and calculates the permeability of the oil and gas phases, thereby achieving the purpose of evaluating pore flow capacity. This method mainly evaluates flowability from a static perspective, without considering key influencing factors such as natural fractures, reservoir heterogeneity, and viscosity changes during development, and it also cannot evaluate the dynamic flowability of heavy oil during extraction.

[0005] Therefore, in order to efficiently exploit my country's heavy oil resources, it is urgent to establish a dynamic flow capacity evaluation method that comprehensively considers factors such as reservoir heterogeneity, natural fractures, and temperature-induced fluid viscosity changes. Summary of the Invention

[0006] This invention provides a method and apparatus for testing the dynamic flow capacity of pores in heavy oil reservoirs, overcoming the shortcomings of the prior art. It can effectively solve the problems in the development of existing heavy oil reservoirs where the influencing factors for flow capacity evaluation are not fully considered, resulting in low accuracy of flow capacity evaluation and high overall production costs.

[0007] One of the technical solutions of this invention is achieved through the following measures: a method for testing the dynamic flow capacity of pores in heavy oil reservoirs, comprising:

[0008] The first step is to obtain downhole cores from the target reservoir section and crude oil samples from production wells in the same block and at the same stratigraphic level, and to test the physical properties, mineral composition percentage, rock mechanics parameters, and viscosity of crude oil samples at the target reservoir temperature of the standard rock samples from the target reservoir section.

[0009] The second step is to calculate the reservoir coefficient of the test rock sample based on the physical property parameters of the standard rock sample of the target reservoir section, and evaluate the flowability of the rock itself.

[0010] The third step is to use the percentage of mineral composition and rock mechanical parameters of standard rock samples from the target reservoir section to calculate the fracture density coefficient of the target reservoir rock and evaluate the degree of development of natural fractures in the target reservoir rock.

[0011] The fourth step is to use the vertical well logging curves of the target reservoir to obtain the thickness distribution of the longitudinal interlayers in the target reservoir, calculate the proportion coefficient of the longitudinal interlayers in the target reservoir, and evaluate the longitudinal heterogeneity of the target reservoir.

[0012] The fifth step involves conducting flow experiments on rock samples under reservoir confining pressure and injected fluid temperature. The viscosity of the crude oil sample at the target reservoir temperature after the experiment is tested. Based on the rock's own flow capacity, the degree of development of natural fractures in the reservoir rock, the vertical heterogeneity of the target reservoir, and the viscosity of the crude oil sample at the target reservoir temperature before and after the experiment, the dynamic flow capacity coefficient of the rock pores is calculated, and the flow capacity of the rock pores is obtained. The larger the value of the dynamic flow capacity coefficient of the rock pores, the stronger the flow capacity of the rock pores.

[0013] The following are further optimizations and / or improvements to one of the above-mentioned technical solutions:

[0014] In the first step described above, the target reservoir standard rock sample has a diameter of 2.5 cm and a length of 5 cm. The physical properties of the target reservoir standard rock sample include its porosity and permeability. The rock mechanics parameter of the target reservoir standard rock sample is Young's modulus.

[0015] In the second step above, the formula for calculating the reservoir coefficient of the test rock sample is as follows:

[0016]

[0017] In the formula: R I is the reservoir coefficient of the rock sample, mD; k is the permeability of the standard rock sample, mD; is the porosity of the standard rock sample, in %; n is the number of rock samples; i is the rock sample number.

[0018] The evaluation process for the degree of development of natural cracks in the third step above includes:

[0019] First, based on the Young's modulus of a single mineral in the rock, and combined with the percentage of mineral composition in the standard rock samples from the target reservoir section, the mineral variability of the rock samples is calculated using the following formula:

[0020]

[0021] In the formula: E w Mineral variability in rock samples, MPa; E j The value represents the Young's modulus of a single mineral, in MPa; M j The percentage of mineral composition in the standard rock sample of the target reservoir section, %;

[0022] Then, based on the rock mechanics parameters Young's modulus and the mineral variability of the standard rock samples from the target reservoir section, the fracture density coefficient of the rock samples is calculated. A higher fracture density coefficient indicates a higher density of natural fractures and stronger flow capacity. The formula for calculating the fracture density coefficient of the rock samples is as follows:

[0023]

[0024] In the formula: F i E represents the rock sample fracture density coefficient, in percentages. i Young's modulus, MPa; E, a rock mechanical parameter. w Mineral variability in rock samples, MPa;

[0025] Finally, based on the fracture density coefficient of the rock samples, the overall fracture density coefficient of the evaluated reservoir section is calculated. A higher overall fracture density coefficient indicates more developed natural fractures in the reservoir rock. The formula for calculating the overall fracture density coefficient of the evaluated reservoir section is as follows:

[0026]

[0027] In the formula: F I To evaluate the overall fracture density coefficient of the reservoir section, %; F i denoted as the rock sample fracture density coefficient, %; n represents the number of rock samples.

[0028] In the fourth step above, the formula for calculating the proportion coefficient of the longitudinal interlayer of the target reservoir is as follows:

[0029]

[0030] In the formula: L I is the ratio of longitudinal interlayers in the target reservoir, dimensionless; h is the total thickness of longitudinal interlayers in the target reservoir, in meters; H is the thickness of the target reservoir, in meters.

[0031] In step five above, the formula for calculating the dynamic flow capacity coefficient of rock pores is as follows:

[0032]

[0033] In the formula: H of denoted as the dynamic flow capacity coefficient of rock pores, mD; μ0 and μ1 are the viscosities of crude oil samples at the target reservoir temperature before and after the experiment, mPa·s, respectively.

[0034] The viscosity of the crude oil sample at the target reservoir temperature after the above test experiment was obtained according to the following steps:

[0035] S1. Determine the experimental loading conditions of the rock pore flow capacity testing device based on the reservoir confining pressure and the temperature of the injected fluid.

[0036] S2, load the standard rock sample of the target reservoir section after testing in the first step into the core holder, and use the confining pressure pump to apply the reservoir confining pressure determined in step S1.

[0037] S3, heat and inject fluid, and pump the fluid into the core for reaction. After crude oil is produced at the outlet of the rock pore flow capacity testing device, the viscosity of the crude oil sample at the target reservoir temperature after the experiment is measured.

[0038] The second technical solution of the present invention is achieved through the following measures: an apparatus for implementing a method for testing the dynamic flow capacity of pores in heavy oil reservoirs, comprising a constant speed and constant pressure pump, a vacuum pump, an intermediate container, a core holder, and a confining pressure pump. A delivery pipeline is fixedly connected between the outlet of the constant speed and constant pressure pump and the bottom inlet of the intermediate container. A pumping pipeline is fixedly connected between the top outlet of the intermediate container and the first inlet of the core holder. A vacuum pumping pipeline is fixedly connected between the pumping pipeline and the inlet of the vacuum pump. A confining pressure loading pipeline is fixedly connected between the outlet of the confining pressure pump and the second inlet of the core holder. A drain pipeline is fixedly connected to the outlet of the core holder, and a beaker is provided at the outlet of the drain pipeline.

[0039] The following are further optimizations and / or improvements to the second technical solution of the above invention:

[0040] The outer wall of the aforementioned intermediate container is equipped with a heating jacket, and the core holder contains a core saturated with crude oil.

[0041] The first valve, the second valve, the third valve, and the fourth valve are fixedly installed sequentially on the above-mentioned delivery pipeline, pump inlet pipeline, vacuum pipeline, and drain pipeline.

[0042] This invention establishes a flow capacity coefficient for the first time to evaluate dynamic flow capacity. The method is simple, feasible, and highly operable, and can quantitatively evaluate the dynamic flow capacity of pores in heavy oil reservoirs, thereby achieving the goal of efficient development of heavy oil reservoirs. Attached Figure Description

[0043] Appendix Figure 1 This is a process flow diagram of the apparatus for implementing the method of dynamic flow capacity testing of pores in heavy oil reservoirs in Embodiment 8 of the present invention.

[0044] Appendix Figure 2 This is a comparison diagram of the mineral differences between rock samples from the main development layers J1 and J2 in Embodiment 11 of the present invention.

[0045] Appendix Figure 3 The figure shows the calculation results of the fracture density coefficient of rock samples J1-1 to J1-3 in Example 11 of the present invention.

[0046] Appendix Figure 4 The figure shows the calculation results of the fracture density coefficient of rock samples J2-1 to J2-3 in Example 11 of the present invention.

[0047] Appendix Figure 1 The codes in the diagram are as follows: 1 for constant speed and constant pressure pump, 2 for first valve, 3 for intermediate container, 4 for heating jacket, 5 for second valve, 6 for vacuum pump, 7 for third valve, 8 for core, 9 for core holder, 10 for confining pressure pump, 11 for fourth valve, 12 for beaker, 13 for delivery pipeline, 14 for pump inlet pipeline, 15 for vacuuming pipeline, 16 for confining pressure loading pipeline, and 17 for drain pipeline. Detailed Implementation

[0048] The present invention is not limited to the following embodiments, and the specific implementation can be determined according to the technical solution of the present invention and the actual situation.

[0049] The present invention will be further described below with reference to embodiments:

[0050] Example 1: A method for testing the dynamic flow capacity of pores in this heavy oil reservoir, comprising:

[0051] The first step is to obtain downhole cores from the target reservoir section and crude oil samples from production wells in the same block and at the same stratigraphic level, and to test the physical properties, mineral composition percentage, rock mechanics parameters, and viscosity of crude oil samples at the target reservoir temperature of the standard rock samples from the target reservoir section.

[0052] The second step is to calculate the reservoir coefficient of the test rock sample based on the physical property parameters of the standard rock sample of the target reservoir section, and evaluate the flowability of the rock itself.

[0053] The third step is to use the percentage of mineral composition and rock mechanical parameters of standard rock samples from the target reservoir section to calculate the fracture density coefficient of the target reservoir rock and evaluate the degree of development of natural fractures in the target reservoir rock.

[0054] The fourth step is to use the vertical well logging curves of the target reservoir to obtain the thickness distribution of the longitudinal interlayers in the target reservoir, calculate the proportion coefficient of the longitudinal interlayers in the target reservoir, and evaluate the longitudinal heterogeneity of the target reservoir.

[0055] The fifth step involves conducting flow experiments on rock samples under reservoir confining pressure and injected fluid temperature. The viscosity of the crude oil sample at the target reservoir temperature after the experiment is tested. Based on the rock's own flow capacity, the degree of development of natural fractures in the reservoir rock, the vertical heterogeneity of the target reservoir, and the viscosity of the crude oil sample at the target reservoir temperature before and after the experiment, the dynamic flow capacity coefficient of the rock pores is calculated, and the flow capacity of the rock pores is obtained. The larger the value of the dynamic flow capacity coefficient of the rock pores, the stronger the flow capacity of the rock pores.

[0056] This invention evaluates dynamic flow capacity by comprehensively considering factors such as the flow capacity of the original rock pores in heavy oil reservoirs, the degree of development of natural fractures in the reservoir rocks, the heterogeneity of longitudinal interlayers in the target reservoir, and the influence of temperature on fluid viscosity. This method offers a novel perspective on both dynamic and static factors, as well as efficient heavy oil development, representing a significant improvement over previous static evaluations and yielding results that better reflect reality. The calculation method is simple, feasible, and highly operable, enabling quantitative evaluation of the dynamic flow capacity of heavy oil reservoir pores. This effectively guides the development or adjustment of heavy oil reservoir development plans, achieving the goal of efficient heavy oil reservoir development. After applying this method, the accuracy of flow capacity evaluation is expected to increase to over 60%, and the overall cost to decrease by over 20%. Furthermore, this invention is also applicable to the evaluation of the flow capacity of other unconventional reservoirs.

[0057] Example 2: As an optimization of the above example, in the first step, the diameter of the standard rock sample of the target reservoir section is 2.5 cm and the length is 5 cm. The physical property parameters of the standard rock sample of the target reservoir section include the porosity and permeability of the standard rock sample of the target reservoir section. The rock mechanical parameter of the standard rock sample of the target reservoir section is Young's modulus.

[0058] Example 3: As an optimization of the above example, in the second step, the formula for calculating the reservoir coefficient of the test rock sample is as follows:

[0059]

[0060] In the formula: R Iis the reservoir coefficient of the rock sample, mD; k is the permeability of the standard rock sample, mD; is the porosity of the standard rock sample, in %; n is the number of rock samples; i is the rock sample number.

[0061] Example 4: As an optimization of the above examples, the evaluation process for the degree of development of natural cracks in the third step includes:

[0062] First, based on the Young's modulus of a single mineral in the rock, and combined with the percentage of mineral composition in the standard rock samples from the target reservoir section, the mineral variability of the rock samples is calculated using the following formula:

[0063]

[0064] In the formula: E w Mineral variability in rock samples, MPa; E j The value represents the Young's modulus of a single mineral, in MPa; M j The percentage of mineral composition in the standard rock sample of the target reservoir section, %;

[0065] Then, based on the rock mechanics parameters Young's modulus and the mineral variability of the standard rock samples from the target reservoir section, the fracture density coefficient of the rock samples is calculated. A higher fracture density coefficient indicates a higher density of natural fractures and stronger flow capacity. The formula for calculating the fracture density coefficient of the rock samples is as follows:

[0066]

[0067] In the formula: F i E represents the rock sample fracture density coefficient, in percentages. i Young's modulus, MPa; E, a rock mechanical parameter. w Mineral variability in rock samples, MPa;

[0068] Finally, based on the fracture density coefficient of the rock samples, the overall fracture density coefficient of the evaluated reservoir section is calculated. A higher overall fracture density coefficient indicates more developed natural fractures in the reservoir rock. The formula for calculating the overall fracture density coefficient of the evaluated reservoir section is as follows:

[0069]

[0070] In the formula: F I To evaluate the overall fracture density coefficient of the reservoir section, %; F i denoted as the rock sample fracture density coefficient, %; n represents the number of rock samples.

[0071] Example 5: As an optimization of the above example, in the fourth step, the formula for calculating the proportion coefficient of the longitudinal interlayer of the target reservoir is as follows:

[0072]

[0073] In the formula: L I is the ratio of longitudinal interlayers in the target reservoir, dimensionless; h is the total thickness of longitudinal interlayers in the target reservoir, in meters; H is the thickness of the target reservoir, in meters.

[0074] Example 6: As an optimization of the above example, in step 5, the formula for calculating the dynamic flow capacity coefficient of rock pores is as follows:

[0075]

[0076] In the formula: H of denoted as the dynamic flow capacity coefficient of rock pores, mD; μ0 and μ1 are the viscosities of crude oil samples at the target reservoir temperature before and after the experiment, mPa·s, respectively.

[0077] Example 7: As an optimization of the above examples, the viscosity of the crude oil sample at the target reservoir temperature after the test experiment was obtained according to the following steps:

[0078] S1. Determine the experimental loading conditions of the rock pore flow capacity testing device based on the reservoir confining pressure and the temperature of the injected fluid.

[0079] S2, load the standard rock sample of the target reservoir section after testing in the first step into the core holder 9, and use the confining pressure pump 10 to apply the reservoir confining pressure determined in step S1.

[0080] S3, heat and inject fluid, and pump the fluid into core 8 for reaction. After crude oil is produced at the outlet of the rock pore flow capacity testing device, the viscosity of the crude oil sample at the target reservoir temperature after the experiment is obtained.

[0081] Example 8: As Figure 1 As shown, the apparatus for testing the dynamic flow capacity of pores in heavy oil reservoirs includes a constant speed and constant pressure pump 1, a vacuum pump 6, an intermediate container 3, a core holder 9, and a confining pressure pump 10. A delivery pipeline 13 is fixedly connected between the outlet of the constant speed and constant pressure pump 1 and the bottom inlet of the intermediate container 3. A pumping pipeline 14 is fixedly connected between the top outlet of the intermediate container 3 and the first inlet of the core holder 9. A vacuum pumping pipeline 15 is fixedly connected between the pumping pipeline 14 and the inlet of the vacuum pump 6. A confining pressure loading pipeline 16 is fixedly connected between the outlet of the confining pressure pump 10 and the second inlet of the core holder 9. A drainage pipeline 17 is fixedly connected to the outlet of the core holder 9, and a beaker 12 is installed at the outlet of the drainage pipeline 17.

[0082] Unless otherwise specified, all equipment and devices used in this invention are existing and commonly known in the art.

[0083] Example 9: As an optimization of the above embodiments, such as Figure 1As shown, the outer wall of the intermediate container 3 is equipped with a heating jacket 4, and the core holder 9 contains a core 8 filled with saturated crude oil.

[0084] Example 10: As an optimization of the above embodiments, such as Figure 1 As shown, the first valve 2, the second valve 5, the third valve 7 and the fourth valve 11 are fixedly installed on the delivery pipeline 13, the pump inlet pipeline 14, the vacuum pumping pipeline 15 and the drain pipeline 17 in sequence.

[0085] Depending on the needs, the various pipelines and equipment of the apparatus for implementing the dynamic flow capacity test method for heavy oil reservoir pores may also be equipped with conventional valves, thermometers, and pressure gauges known and commonly used in the field, according to production requirements.

[0086] Example 11: The main development layers in Block J of the heavy oil reservoir are evaluated as J-1 and J-2. Previous drilling, downhole coring tests, and production well monitoring in this block show significant differences in the oil layer encounter rate and single-well production at the same platform and in the same formation, exhibiting strong heterogeneity. Based on the heavy oil reservoir pore dynamic flow capacity testing method of this invention, a targeted pore flow capacity evaluation is conducted for the development of this block. The specific steps are as follows:

[0087] I. Obtain downhole core 8 from the target reservoir section and crude oil samples from production wells in the same block and stratigraphic position. Test the physical properties, mineral composition percentage, rock mechanical parameters, and viscosity of the crude oil samples at the target reservoir temperature using standard rock samples from the target reservoir section. Specifically, this includes the following:

[0088] (1) The main development layers of the heavy oil reservoir J ​​block are J1 and J2. Continuous coring work is carried out at the corresponding depths. Three rock samples are continuously cored from each main development layer. Rock samples J1-1 to J1-3 belong to the main development layer J1, and rock samples J2-1 to J2-3 belong to the main development layer J2. The downhole rock samples are processed into standard rock samples with a diameter of 2.5 cm and a length of 5 cm.

[0089] (2) The porosity and permeability of the standard rock sample described in step (1) were tested using an automatic helium porosity tester and an ultra-low permeability tester, as shown in Table 1.

[0090] (3) Use an X-ray diffractometer to test the mineral composition of the rock sample in step (2), obtain the percentage of mineral composition of the standard rock sample in the target reservoir section, and use a triaxial rock mechanics testing system to obtain the rock mechanics parameter Young's modulus of the standard rock sample in the target reservoir section, as shown in Table 2.

[0091] (4) Crude oil samples were taken from the same production wells in the same block and layer of the main development layer J1 and J2 respectively. The viscosity of the crude oil samples at the target reservoir temperature of layer J1 and layer J2 was 31200 mPa.s and 45680 mPa.s respectively.

[0092] 2. Calculate the reservoir coefficient of the rock sample based on the physical property parameters of the standard rock sample in the target reservoir section, and evaluate the flowability of the rock itself;

[0093] By using the percentage of mineral composition and rock mechanical parameters of standard rock samples from the target reservoir section, the fracture density coefficient of the target reservoir rock is calculated to evaluate the degree of development of natural fractures in the target reservoir rock.

[0094] Based on this, the thickness distribution of vertical interlayers in the target reservoir is obtained using the vertical well logging curves of the target reservoir. The proportion coefficient of vertical interlayers in the target reservoir is calculated, and the vertical heterogeneity of the target reservoir is evaluated. Specifically, this includes the following:

[0095] (1) Based on the permeability and porosity of standard rock samples from the main development layers J1 and J2, the reservoir coefficients of the corresponding rock samples were calculated to be 765.5 mD and 208.2 mD, respectively, using the formula for calculating the reservoir coefficient of rock samples. The formula for calculating the reservoir coefficient of rock samples is as follows:

[0096]

[0097] In the formula: R I is the reservoir coefficient of the rock sample, mD; k is the permeability of the standard rock sample, mD; is the porosity of the standard rock sample, in %; n is the number of rock samples; i is the rock sample number.

[0098] (2) Based on the percentage of mineral composition and rock mechanical parameters of the standard rock samples of the target reservoir section, calculate the fracture density coefficient of the target reservoir rock to evaluate the degree of development of natural fractures in the target reservoir rock. The larger the fracture density coefficient value of the rock sample, the higher the density of natural fractures and the stronger the flow capacity. The formula for calculating the fracture density coefficient of the rock sample is as follows:

[0099]

[0100] In the formula: F i E represents the rock sample fracture density coefficient, in percentages. i Young's modulus, MPa; E, a rock mechanical parameter. w The evaluation process for the mineral variability of rock samples, MPa, and the degree of development of natural fractures includes:

[0101] ① The Young's modulus of single minerals in the rock was obtained using the *Handbook of Rock Physics*, as shown in Table 3. Combined with the percentage of mineral composition in the standard rock samples of the target reservoir section tested in step one, the mineral difference between the rock samples and those in the main development layer J1 and J2 was calculated using the formula for calculating the mineral difference. Figure 2 As shown, the formula for calculating the mineral variability of rock samples is as follows:

[0102]

[0103] In the formula: E w Mineral variability in rock samples, MPa; E j The value represents the Young's modulus of a single mineral, in MPa; M j The percentage of mineral composition in the standard rock sample of the target reservoir section, expressed as %.

[0104] ② Further combining the Young's modulus of the rock mechanics parameters of the standard rock samples from the target reservoir section in step one, and using the calculation formula for the fracture density coefficient of the rock samples, calculate the fracture density coefficient of the test rock samples from the main development layers J1 and J2, such as... Figure 3 and Figure 4 As shown, the formula for calculating the fracture density coefficient of the rock sample is as follows:

[0105]

[0106] In the formula: F i E represents the rock sample fracture density coefficient, in percentages. i Young's modulus, MPa; E, a rock mechanical parameter. w The value represents the mineral variability of the rock sample, expressed in MPa.

[0107] ③ After obtaining the fracture density coefficient of the test rock samples, the overall fracture density coefficients of the evaluation reservoir section were calculated using the formula for the overall fracture density coefficient of the evaluation reservoir section. The overall fracture density coefficients of the main development layers J1 and J2 were 0.852% and 0.450%, respectively. The formula for calculating the overall fracture density coefficient of the evaluation reservoir section is as follows:

[0108]

[0109] In the formula: F I To evaluate the overall fracture density coefficient of the reservoir section, %; F i denoted as the rock sample fracture density coefficient, %; n represents the number of rock samples.

[0110] (3) Using the logging curves of the main development layers J1 and J2 vertical wells, the longitudinal interlayer thicknesses of the target reservoirs were obtained as 3.0m and 6.9m, respectively. The evaluated target reservoir thicknesses were 15.8m and 18.7m, respectively. Using the calculation formula for the longitudinal interlayer ratio of the target reservoirs, the longitudinal interlayer ratios were calculated to be 0.19 and 0.36, respectively. The calculation formula for the longitudinal interlayer ratio of the target reservoirs is as follows:

[0111]

[0112] In the formula: L I is the ratio of longitudinal interlayers in the target reservoir, dimensionless; h is the total thickness of longitudinal interlayers in the target reservoir, in meters; H is the thickness of the target reservoir, in meters.

[0113] III. Utilizing a rock pore flow capacity testing device, flow experiments were conducted on rock samples under reservoir pressure and injected fluid temperature. The viscosity of the crude oil sample at the target reservoir temperature was measured after the experiments. Taking into account factors such as reservoir rock storage capacity, the degree of development of natural fractures in the reservoir rock, and the vertical heterogeneity of the target reservoir, the dynamic flow capacity coefficient of the rock pores was calculated to obtain the rock pore flow capacity. A higher value of the dynamic flow capacity coefficient indicates stronger rock pore flow capacity. Specifically, this includes the following:

[0114] (1) Using a rock pore flow capacity testing device, such as Figure 1 As shown, huff-and-puff experiments were conducted on rock samples under reservoir pressure and injected fluid temperature. The viscosity of the crude oil sample at the target reservoir temperature after the experiment was tested. The specific details are as follows:

[0115] ① Taking the J1 rock sample, the main development layer, as an example, the experiment was carried out. The reservoir confining pressure was 5MPa and the injected fluid temperature was 100℃.

[0116] ② The core 8 (original rock sample) loaded with saturated crude oil as described in step one is loaded into the core holder 9, and the confining pressure determined in step ① is applied using the confining pressure pump 10.

[0117] ③ Use vacuum pump 6 to purge the air from the pipelines and equipment in the rock pore flow capacity testing device. After purging, close the third valve 7. The fluid used in this experiment is deionized water, which is placed into the intermediate container 3. Use heating jacket 4 to heat the intermediate container 3 to the temperature of the fluid injected in step ①. Based on this, use constant speed and constant pressure pump 1 to pump the intermediate container 3 into the core 8 for reaction until crude oil is produced at the outlet of the drain pipeline 17. After the experiment, the viscosity of the crude oil sample at the target reservoir temperature is tested to be 895 mPa·s.

[0118] ④ Repeat steps ① to ③ to conduct a pore flow capacity test on the main open layer J2. The reservoir confining pressure is 5 MPa, the injected fluid temperature is 100℃, and the viscosity of the crude oil sample at the target reservoir temperature after the test is 1220 mPa.s.

[0119] (2) Based on the viscosity of the crude oil sample at the target reservoir temperature after the test experiment in step 1, and considering factors such as the reservoir rock storage capacity, the degree of development of natural fractures in the reservoir rock, and the vertical heterogeneity of the target reservoir, the dynamic flow capacity coefficient of the rock pores was calculated using the formula for calculating the dynamic flow capacity coefficient of the rock pores in the main development layers J1 and J2, which were 1196.6 mD and 97.4 mD, respectively. It can be seen that the dynamic flow capacity of the rock pores in the main development layer J1 of the heavy oil reservoir J ​​block is much greater than that in the main development layer J2. The formula for calculating the dynamic flow capacity coefficient of the rock pores is as follows:

[0120]

[0121] In the formula: H of denoted as the dynamic flow capacity coefficient of rock pores, mD; μ0 and μ1 are the viscosities of crude oil samples at the target reservoir temperature before and after the experiment, mPa·s, respectively.

[0122] In summary, this invention establishes a flow capacity coefficient for evaluating dynamic flow capacity for the first time. This method is simple, feasible, and highly operable, and can quantitatively evaluate the dynamic flow capacity of pores in heavy oil reservoirs, thereby achieving the goal of efficient development of heavy oil reservoirs.

[0123] The above technical features constitute the embodiments of the present invention, which have strong adaptability and implementation effect. Unnecessary technical features can be added or removed according to actual needs to meet the needs of different situations.

[0124] Table 1

[0125]

[0126] Table 2

[0127]

[0128] Table 3

[0129] Single mineral name Young's modulus (MPa) Pyrite 283056.36 dolomite 105309.01 quartz 95942.54 calcite 78010.81 Feldspar 64838.72 clay 21914.15

Claims

1. A method for testing the dynamic flow capacity of pores in heavy oil reservoirs, characterized in that, include: The first step is to obtain downhole cores from the target reservoir section and crude oil samples from production wells in the same block and at the same stratigraphic level, and to test the physical properties, mineral composition percentage, rock mechanics parameters, and viscosity of crude oil samples at the target reservoir temperature of the standard rock samples from the target reservoir section. The second step is to calculate the reservoir coefficient of the test rock sample based on the physical property parameters of the standard rock sample of the target reservoir section, and evaluate the flowability of the rock itself. The third step is to use the percentage of mineral composition and rock mechanical parameters of standard rock samples from the target reservoir section to calculate the fracture density coefficient of the target reservoir rock and evaluate the degree of development of natural fractures in the target reservoir rock. The fourth step is to use the vertical well logging curves of the target reservoir to obtain the thickness distribution of the longitudinal interlayers in the target reservoir, calculate the proportion coefficient of the longitudinal interlayers in the target reservoir, and evaluate the longitudinal heterogeneity of the target reservoir. The fifth step involves conducting flow experiments on rock samples under reservoir confining pressure and injected fluid temperature. The viscosity of the crude oil sample at the target reservoir temperature after the experiment is tested. Based on the rock's own flow capacity, the degree of development of natural fractures in the reservoir rock, the vertical heterogeneity of the target reservoir, and the viscosity of the crude oil sample at the target reservoir temperature before and after the experiment, the dynamic flow capacity coefficient of the rock pores is calculated, and the flow capacity of the rock pores is obtained. The larger the value of the dynamic flow capacity coefficient of the rock pores, the stronger the flow capacity of the rock pores.

2. The method for testing the dynamic flow capacity of heavy oil reservoir pores according to claim 1, characterized in that, In the first step, the standard rock sample of the target reservoir section has a diameter of 2.5 cm and a length of 5 cm. The physical properties of the standard rock sample of the target reservoir section include the porosity and permeability of the standard rock sample of the target reservoir section. The rock mechanical parameter of the standard rock sample of the target reservoir section is Young's modulus.

3. The method for testing the dynamic flow capacity of heavy oil reservoir pores according to claim 1 or 2, characterized in that, In the second step, the formula for calculating the reservoir coefficient of the test rock sample is as follows: In the formula: R I is the reservoir coefficient of the rock sample, mD; k is the permeability of the standard rock sample, mD; is the porosity of the standard rock sample, in %; n is the number of rock samples; i is the rock sample number.

4. The method for testing the dynamic flow capacity of heavy oil reservoir pores according to claim 1, 2, or 3, characterized in that, The third step, the evaluation process for the degree of development of natural cracks, includes: First, based on the Young's modulus of a single mineral in the rock, and combined with the percentage of mineral composition in the standard rock samples from the target reservoir section, the mineral variability of the rock samples is calculated using the following formula: In the formula: E w Mineral variability in rock samples, MPa; E j The value represents the Young's modulus of a single mineral, in MPa; M j The percentage of mineral composition in the standard rock sample of the target reservoir section, %; Then, based on the rock mechanics parameters Young's modulus and the mineral variability of the standard rock samples from the target reservoir section, the fracture density coefficient of the rock samples is calculated. A higher fracture density coefficient indicates a higher density of natural fractures and stronger flow capacity. The formula for calculating the fracture density coefficient of the rock samples is as follows: In the formula: F i E represents the rock sample fracture density coefficient, in percentages. i Young's modulus, MPa; E, a rock mechanical parameter. w Mineral variability in rock samples, MPa; Finally, based on the fracture density coefficient of the rock samples, the overall fracture density coefficient of the evaluated reservoir section is calculated. A higher overall fracture density coefficient indicates more developed natural fractures in the reservoir rock. The formula for calculating the overall fracture density coefficient of the evaluated reservoir section is as follows: In the formula: F I To evaluate the overall fracture density coefficient of the reservoir section, %; F i denoted as the rock sample fracture density coefficient, %; n represents the number of rock samples.

5. The method for testing the dynamic flow capacity of heavy oil reservoir pores according to any one of claims 1 to 4, characterized in that, In the fourth step, the formula for calculating the proportion coefficient of the longitudinal interlayer in the target reservoir is as follows: In the formula: L I is the ratio of longitudinal interlayers in the target reservoir, dimensionless; h is the total thickness of longitudinal interlayers in the target reservoir, in meters; H is the thickness of the target reservoir, in meters.

6. The method for testing the dynamic flow capacity of heavy oil reservoir pores according to claim 5, characterized in that, In step five, the formula for calculating the dynamic flow capacity coefficient of rock pores is as follows: In the formula: H of denoted as the dynamic flow capacity coefficient of rock pores, mD; μ0 and μ1 are the viscosities of crude oil samples at the target reservoir temperature before and after the experiment, mPa·s, respectively.

7. The method for testing the dynamic flow capacity of heavy oil reservoir pores according to any one of claims 1 to 6, characterized in that, The viscosity of the crude oil sample at the target reservoir temperature after the test experiment was obtained according to the following steps: S1. Determine the experimental loading conditions of the rock pore flow capacity testing device based on the reservoir confining pressure and the temperature of the injected fluid. S2, load the standard rock sample of the target reservoir section after testing in the first step into the core holder, and use the confining pressure pump to apply the reservoir confining pressure determined in step S1. S3, heat and inject fluid, and pump the fluid into the core for reaction. After crude oil is produced at the outlet of the rock pore flow capacity testing device, the viscosity of the crude oil sample at the target reservoir temperature after the experiment is measured.

8. An apparatus for implementing the method for testing the porosity dynamic flow capacity of heavy oil reservoirs according to claim 7, characterized in that, It includes a constant speed and constant pressure pump, a vacuum pump, an intermediate container, a core holder, and a confining pressure pump. A delivery pipeline is fixedly connected between the outlet of the constant speed and constant pressure pump and the bottom inlet of the intermediate container. A pump inlet pipeline is fixedly connected between the top outlet of the intermediate container and the first inlet of the core holder. A vacuum pumping pipeline is fixedly connected between the pump inlet pipeline and the inlet of the vacuum pump. A confining pressure loading pipeline is fixedly connected between the outlet of the confining pressure pump and the second inlet of the core holder. A drain pipeline is fixedly connected to the outlet of the core holder, and a beaker is installed at the outlet of the drain pipeline.

9. The apparatus according to claim 8, characterized in that, The outer wall of the intermediate container is equipped with a heating jacket, and the core holder is filled with a core saturated with crude oil.

10. The apparatus according to claim 8 or 9, characterized in that, The delivery pipeline, pump inlet pipeline, vacuum pipeline, and drain pipeline are sequentially fixed with a first valve, a second valve, a third valve, and a fourth valve.

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