A method for evaluating cold damage of high-viscosity heavy oil reservoir

Abstract

The present application belongs to the technical field of oil production matching technology, and discloses a high-coagulation heavy oil reservoir cold damage evaluation method, which utilizes physical simulation and numerical simulation methods to analyze the reservoir cold damage degree, reversibility, the minimum temperature for avoiding cold damage and the reservoir temperature recovery time from quantitative and qualitative aspects, wherein the physical simulation firstly determines the crude oil properties through the crude oil viscosity-temperature and wax precipitation experiments, then utilizes the core to carry out breakthrough pressure experiments to determine the occurrence temperature of the reservoir cold damage, startup pressure experiments to determine the minimum temperature for avoiding damage, relative permeability experiments to determine the influence degree of the cold damage on the reservoir percolation capacity, mercury injection experiments to analyze the influence of the cold damage on the reservoir pore structure, and two-dimensional nuclear magnetic experiments and laser confocal experiments to determine whether the cold damage is reversible and the reversible temperature; the numerical simulation is utilized to analyze the recovery time required for different liquid amounts and different temperature working liquids to enter the formation, so as to finally achieve the purposes of reducing the development cost of the high-coagulation oil reservoir and improving the development effect.

Description

Technical Field

[0001] This invention relates to the field of oil production enhancement technologies, and in particular to a method for evaluating cold damage in high-pour-point-weight oil reservoirs. Background Technology

[0002] High-pour-point heavy oil reservoirs are an important resource for global economic development. According to statistics from 2019, the world's proven reserves of high-pour-point heavy oil are approximately 815 billion tons, accounting for 70% of the world's remaining oil reserves. High-pour-point heavy oil is characterized by high pour point, high viscosity, and poor fluidity. Some blocks of high-pour-point heavy oil also have high levels of wax and bituminous resin.

[0003] When ambient-temperature working fluids are introduced into high-viscosity oil reservoirs, they cause a drop in reservoir temperature, resulting in a significant increase in crude oil viscosity. This affects flow resistance and, in severe cases, causes the precipitation of asphaltenes and waxes from the crude oil, forming irreversible organic blockages and causing cold damage to the reservoir, leading to unsatisfactory development results. While using high-temperature working fluids can reduce crude oil viscosity and avoid cold damage, heating the working fluid is not only complex but also consumes a large amount of energy, increasing development costs. This is especially problematic during volumetric fracturing, where it is difficult to heat thousands of cubic meters of fracturing fluid in a short period.

[0004] It was discovered long ago that increasing the temperature of the working fluid injected into the well can improve the development effect of high-pour-point heavy oil. At the same time, injecting cold working fluid into high-pour-point heavy oil reservoirs can lead to cold damage, and this phenomenon has been studied. Specific research is as follows:

[0005] Tian Nailin et al. (Tian Nailin, Feng Jilei, Ren Ying et al., Cold damage to high wax content and high pour point oil reservoirs caused by early cold water injection [J], Journal of Petroleum University, 1997, 23; 1) described, through indoor displacement experiments and reservoir numerical simulation calculations, the phenomenon that due to early cold water injection, the oil layer temperature decreases, and high wax content and high pour point crude oil precipitates wax in the oil layer pores. The lower the temperature of the injected cold fluid, the more severe the cold damage.

[0006] Li Xiaoguang et al. (Li Xiaoguang, Chen Zhenyan, Hui Xuefeng et al., A review of exploration and development technologies for heavy oil and high-pour-point oil in Liaohe oilfield [J], Journal of China University of Petroleum, 2007, 28; 4) discussed the exploration and development history of heavy oil and high-pour-point oil, systematically summarized the exploration and development of heavy oil and high-pour-point oil in Liaohe oilfield over many years, and analyzed the existing difficulties.

[0007] Nie Xiangrong et al. (Nie Xiangrong, Yang Shenglai, Numerical simulation of cold damage characteristics in high-pour-point oil reservoirs[J], Oil Testing Drilling Technology, 2014, 42; 1) addressed the current lack of understanding of the cold damage in water injection development of high-pour-point oil reservoirs by establishing physical and mathematical models, forming a multi-field coupled mathematical model to describe the process of cold water injection development in high-pour-point oil reservoirs, and then numerically solving it.

[0008] Xu Zhengen et al. (Xu Zhengen, Xin Wenming, Liu Yu et al., CO2 flooding to water-gas alternating flooding and reservoir damage characteristics in high-pour-point oil reservoirs [J], Fault Block Oil and Gas Field, 2019, 26; 5) CO2 flooding and its water-gas alternating flooding (WAG) development will lead to the deposition of wax in high-pour-point oil reservoirs. The damage to the reservoir caused by CO2 flooding to WAG immiscible flooding mainly occurs in the middle section of the reservoir, with the highest permeability damage rate of 4.58%, while the damage to the reservoir caused by miscible flooding occurs in the middle and later sections of the reservoir, with the highest permeability damage rate of 6.72%.

[0009] Liu Lifeng et al. (Liu Lifeng, Ran Qiquan, Wang Zhiping et al., Prediction Method and Device for Cold Damage to Tight Oil Production Capacity of Fracturing Fluid, Patent No. CN 105550780A) provided a method and device for predicting cold damage to tight oil production capacity of fracturing fluid, which can predict the cold damage to tight oil production capacity of fracturing fluid.

[0010] An analysis of existing research and patents reveals that the depth of research and the technological system still need to be improved to address a series of issues, such as the inability to determine whether the damage is reversible, the degree of cold damage at different temperatures, and the minimum temperature to avoid reservoir cold damage. Summary of the Invention

[0011] This invention overcomes the shortcomings of existing technologies by providing a low-damage fracturing fluid for fracturing and stimulation of high-pour-point-weight oil reservoirs. Utilizing hot water for on-site preparation and fracturing operations, it offers advantages such as convenient preparation and application, rapid swelling, good temperature resistance, good proppant carrying capacity, thorough gel breaking, and good demulsification and drainage assistance. Using this system for proppant-added fracturing and stimulation of high-pour-point-weight oil reservoirs effectively avoids cold damage to the reservoir while significantly improving the conductivity of the fracturing support fractures. Furthermore, after the fracturing fluid breaks down the proppant, it acts as a cleaner, anti-wax agent and improves crude oil fluidity, facilitating the flow of high-pour-point-weight oil from the reservoir through the support and filling layers to the wellbore, significantly enhancing reservoir production.

[0012] This invention aims to overcome the shortcomings of existing technologies by providing a method for evaluating cold damage in high-pour-point oil reservoirs. It utilizes a combination of experimental physical simulation and numerical simulation to analyze the degree of cold damage, reversibility, minimum temperature to avoid cold damage, and reservoir temperature recovery time from both quantitative and qualitative perspectives. This determines the optimal working fluid temperature for developing high-pour-point oil reservoirs and the recovery time after the cryogenic working fluid enters the reservoir, ultimately achieving the goal of reducing development costs and improving development efficiency.

[0013] The overall technical solution of this invention is as follows: Using physical and numerical simulation methods, the degree of cold damage to the reservoir, its reversibility, the minimum temperature to avoid cold damage, and the reservoir temperature recovery time are analyzed from both quantitative and qualitative perspectives. Specifically, in terms of physical experiments, crude oil properties are first determined through viscosity-temperature and wax precipitation experiments; then, breakthrough pressure experiments are conducted using core samples to determine the temperature at which cold damage occurs; initiation pressure experiments determine the minimum temperature to avoid damage; relative permeability experiments determine the impact of cold damage on the reservoir's seepage capacity; mercury intrusion porosimetry analyzes the impact of cold damage on the reservoir's pore structure; and two-dimensional nuclear magnetic resonance (NMR) experiments and laser confocal microscopy experiments determine whether the cold damage is reversible and at what temperature. Numerical simulations are used to analyze the recovery time required for different volumes and temperatures of working fluid to enter the formation.

[0014] The specific technical solution is as follows:

[0015] A method for assessing cold damage to high-pour-point-weight oil reservoirs includes the following steps:

[0016] 1. Determine the physical properties of crude oil:

[0017] (1) Crude oil viscosity analysis: By analyzing the viscosity-temperature curve, the viscosity-temperature characteristics of crude oil can be obtained, and the flow properties of crude oil at different temperatures can be evaluated.

[0018] (2) Analysis of wax precipitation in crude oil: Compare and analyze the amount of wax melted at different temperature points to analyze the recoverability of cold damage to the reservoir.

[0019] (3) Analysis of crude oil thermal properties: The thermal conductivity of oil-bearing rocks is affected by the heat conduction between the solid phase of the rock and the oil phase in the pores. Through experiments measuring the thermal conductivity of oil-bearing rocks from natural cores, a basis is provided for numerical simulation to describe cold damage and well blockage time.

[0020] 2. Determine the reservoir property range:

[0021] Based on reservoir conditions, rock property tests are conducted using core samples obtained from drilling to determine the overall porosity and permeability of the core. Reservoir heterogeneity is calculated using formula 1 for the coefficient of variation of permeability, and reservoir properties are categorized into several classes, including high-permeability, medium-permeability, low-permeability, and ultra-low-permeability, based on permeability and coefficient of variation (generally, the coefficient of variation is set at 0.2).

[0022]

[0023] σ - Coefficient of variation of permeability, dimensionless and expressed as a decimal;

[0024] - Average permeability of all samples, mD;

[0025] k i - The permeability of the i-th sample, mD;

[0026] n - Number of samples, in units.

[0027] 3. Determine if cold injury will occur:

[0028] After classification, core samples were subjected to start-up pressure tests to analyze the changes in start-up pressure at different temperatures. The presence of an inflection point in the start-up pressure was used to determine whether cold damage would occur in the reservoir. Based on the reservoir overburden porosity and permeability test results, the flow-pressure gradient back-calculation method or the depressurization method was determined to be used to test the start-up pressure gradient (2.5cm×5cm column sample) at four temperatures for three permeability specifications.

[0029] 4. Determination of reservoir cold damage temperature:

[0030] When rock is saturated with a wetting fluid, the non-wetting fluid must overcome the capillary resistance of the rock to displace it. The smaller the capillary radius of the rock, the greater the resistance and the higher the required breakthrough pressure. The rock sample in the core holder is pressurized, and the test pressure at the inlet is gradually increased. When the pressure causes the fluid to form a continuous flow phase in the rock sample, the pressure difference between the inlet and outlet at this point is the breakthrough pressure. Natural core columns were used to conduct gas-phase breakthrough fracturing experiments using core holders. The breakthrough pressures at different permeabilities and temperatures were determined, revealing the extent of cooling damage from the fracturing fluid.

[0031] 5. Analysis of factors affecting seepage due to cold damage:

[0032] Relative permeability experiments were used to determine the oil-water flow capacity at different temperatures and to assess the impact of cold damage on reservoir flow capacity. In the experiment, instead of simultaneously injecting both fluids into the core sample, the core was pre-saturated with one fluid and then displaced by the other. During water-driven oil recovery, the distribution of oil-water saturation in the porous medium is a function of distance and time; this process is called an unsteady process. According to the simulation requirements, constant pressure differential or constant velocity water-driven oil recovery experiments were conducted on reservoir samples. The production rate of each fluid and the pressure difference between the two ends of the sample were recorded over time at the sample outlet. The oil-water relative permeability was calculated using the JBN method, and the relationship curve between the oil-water relative permeability and water saturation was plotted.

[0033] Calculation formula:

[0034] Relative permeability and water saturation (oil-water calculation formula)

[0035]

[0036]

[0037]

[0038]

[0039]

[0040] In the formula:

[0041] f o (S w — The oil content is expressed as a decimal.

[0042] —Dimensionless cumulative oil recovery is expressed as a fraction of pore volume;

[0043] —Dimensionless cumulative liquid volume, expressed as a fraction of pore volume;

[0044] K ro —The relative permeability of the oil phase is expressed as a decimal;

[0045] K rw —The numerical value of the relative permeability of the aqueous phase is expressed as a decimal;

[0046] I—A numerical value of relative injection capacity, also known as the flow capacity ratio;

[0047] Q o —The initial oil flow rate at the rock sample outlet face, in cm⁻¹ 3 / s);

[0048] Q(t) — the flow rate of the liquid produced at the outlet face of the rock sample at time t. In the constant-rate method experiment, Q(t) = Q o cm 3 / s;

[0049] Δp o —The initial driving pressure differential, in MPa;

[0050] Δp(t) — The value of the displacement pressure difference at time t. In the constant pressure method experiment, Δp(t) = Δp o MPa;

[0051] S ws —The numerical value of bound water saturation is expressed as a decimal;

[0052] S we —The water saturation value at the outlet end of the rock sample, expressed as a decimal.

[0053] 6. The impact of reservoir cold damage on pore structure:

[0054] CT experiments were used to clarify the changes in pore structure parameters caused by cold damage, including pore radius, throat radius, coordination number, and fractures. NMR experiments were used to analyze the changes in pore structure, specifically the degree of pore-throat binding and mobility caused by cold damage. Saturated oil cores with different permeabilities and temperatures were subjected to fracturing fluid displacement, and CT and NMR experiments were used to analyze the changes in pore-throat structure caused by cold damage.

[0055] 7. Numerical simulation of single-well cold damage and well blockage patterns:

[0056] (1) Numerical simulation of hydraulic damage during fracturing

[0057] Experimental Methods: Based on basic data from single wells in the reservoir, a reservoir geological model was established using PETRL software. Numerical simulation of cold damage from hydraulic fracturing in single wells was conducted using the reservoir numerical simulation software CMG, and the patterns of cold damage were analyzed. Numerical analysis was performed on the influencing factors of cold damage from hydraulic fracturing using fracturing fluid.

[0058] (2) Numerical simulation of the blockage law

[0059] Experimental Methods: Based on basic data from single wells in the reservoir, a reservoir geological model was established using PETRL software. After numerical simulation of cold damage caused by hydraulic fracturing in a single well using the reservoir numerical simulation software CMG, the recovery law of the temperature field after cold damage was analyzed, and the well-clogging law was numerically calculated. The numerical analysis examined the recovery law of the reservoir temperature field after cold damage from hydraulic fracturing and its impact on production capacity.

[0060] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0061] This research utilizes a combination of experimental physical simulation and numerical simulation to analyze the degree, reversibility, minimum temperature to avoid cold damage, and reservoir temperature recovery time from both quantitative and qualitative perspectives. In terms of physical experiments, breakthrough pressure experiments determine the initiation temperature of cold damage, initiation pressure experiments determine the minimum temperature to avoid damage, relative permeability experiments determine the impact of cold damage on reservoir seepage capacity, mercury intrusion porosimetry analyzes the impact of cold damage on reservoir pore structure, two-dimensional nuclear magnetic resonance (NMR) experiments and laser confocal microscopy (LCM) experiments determine whether cold damage is reversible and at what temperature. Numerical simulations analyze the recovery time required for different fluid volumes and temperatures to enter the formation. This research determines the optimal working fluid temperature for developing high-pour-point oil reservoirs and the recovery time after the introduction of low-temperature working fluids, ultimately aiming to reduce development costs and improve development efficiency in high-pour-point oil reservoirs. Attached Figure Description

[0062] Figure 1 This is a graph showing the oil phase initiation pressure curves of cores with different permeabilities;

[0063] Figure 2 It is a graph showing the relationship between seepage velocity and pressure gradient;

[0064] Figure 3 This is a graph showing the effect of temperature on different core initiation pressures;

[0065] Figure 4 It is a graph showing the relationship between temperature and different core breakthrough pressure gradients;

[0066] Figure 5 This is a technical roadmap of the present invention;

[0067] Figure 6 This is crude oil viscosity-temperature curve 1, which represents the viscosity variation pattern of crude oil without degassing.

[0068] Figure 7 This is crude oil viscosity-temperature curve 2, which represents the viscosity change pattern of crude oil after degassing.

[0069] Figure 8 It is a curve showing the cumulative amount of wax precipitation;

[0070] Figure 9 It is a graph showing the relationship between thermal conductivity and permeability;

[0071] Figure 10 It is a thermal conductivity-porosity relationship diagram;

[0072] Figure 11 It is the curve showing the relationship between the starting pressure gradient and temperature;

[0073] Figure 12 This is a graph showing the change in starting pressure gradient for different core samples at different temperatures;

[0074] Figure 13 It breaks through the pressure gradient versus temperature relationship curve;

[0075] Figure 14 This is a curve showing the formation temperature change caused by cold fluid injection;

[0076] Figure 15 This shows the change in the viscosity of crude oil in the formation 2 hours after fluids at different temperatures are injected.

[0077] Figure 16 This shows the changes in formation temperature 2 hours after fluids of different temperatures are injected. Detailed Implementation

[0078] The implementation of this invention is given in the following embodiments. Unless otherwise specified, the experimental methods used in this invention are all conventional methods, and the experimental equipment, materials, reagents, etc. used are all commercially available.

[0079] Example 1

[0080] This embodiment uses high-pour-weight oil and natural core samples from a block in the Liaohe Oilfield to conduct a cold damage experiment:

[0081] 1. Crude oil viscosity-temperature experiment:

[0082] By analyzing viscosity-temperature curves, the viscosity-temperature characteristics of crude oil can be obtained, and its flow properties at different temperatures can be evaluated. The oil sample is an extra-heavy oil sample, with a viscosity reaching 250,000 mPa·s at 30℃. The viscosity of the surface degassed crude oil sample at a reservoir temperature of 65℃ is 834.7 mPa·s. Above 41℃, the viscosity of the crude oil decreases sharply and tends to level off.

[0083] 2. Crude oil wax separation experiment:

[0084] The cumulative wax precipitation of crude oil samples from low to high temperatures (25-75℃) was measured, and the wax melting amount at different temperature points was compared and analyzed to reveal the recoverability of reservoir cold damage. Experimental analysis showed that the wax precipitation temperature of crude oil was 62.77℃. Below 40℃, the cumulative wax precipitation increased sharply. Above 55℃, the wax precipitation was zero. Therefore, the critical temperature for cold damage can be determined to be 55℃.

[0085] Table 1. Changes in Cumulative Wax Deposition Amount

[0086]

[0087] 3. Experimental equipment for oil-bearing thermal conductivity of natural rock cores

[0088] The thermal conductivity of oil-bearing rocks is affected by the heat transfer between the solid phase and the oil phase in the pores. Experiments measuring the thermal conductivity of oil-bearing reservoir cores provide a basis for numerical simulations describing cold damage and well blockage time. Based on different physical properties, the reservoir cores were divided into three groups: high, medium, and low permeability (low permeability: 25.75-56.74 mD, medium permeability: 121.72-271.11 mD, and high permeability: 325.91-452.24 mD). Their thermal conductivity was also measured.

[0089] Low-permeability, low-porosity rocks have high thermal conductivity, as do rocks with high oil saturation. The thermal conductivity of low-porosity, low-permeability natural cores ranges from 2.176 to 2.238 W / (m·K), medium-permeability, medium-porosity natural cores range from 2.002 to 2.167 W / (m·K), and high-permeability, high-porosity natural cores with oil content range from 2.081 to 2.281 W / (m·K).

[0090] Table 2. Experimental core physical properties data

[0091]

[0092] 4. Initiate the pressure gradient test

[0093] Cold damage causes a decrease in reservoir temperature and a decline in crude oil fluidity, increasing the difficulty of crude oil initiation. Based on the relationship between the reservoir oil-phase initiation pressure gradient and temperature, the temperature limit for cold damage is determined. When the fracturing fluid injection temperature is above 55℃, the decreasing trend of the oil-phase initiation pressure gradient with increasing temperature tends to level off, and the difference in initiation pressure gradient between different permeabilities is very small. Cold damage mainly affects medium- and low-permeability cores (<300mD), and the lower the permeability, the more pronounced the cold damage.

[0094] Table 3. Start-up pressure test data.

[0095]

[0096] The experiment analyzed the initiation pressure gradients of three core samples with high, medium, and low permeability, at core temperatures of 45, 50, 55, 60, 65, 70, and 75℃. The results show that the critical temperature for hydraulic fluid cooling damage is 55℃.

[0097] Table 4. Statistics of starting pressure gradient for different core samples at different temperatures.

[0098]

[0099] The cold damage process and the ease of fracturing fluid injection were clearly defined. When the reservoir temperature decreased from 65℃ to 55, 45, 35, and 25℃, the fracturing fluid breakthrough pressure increased by 1.8, 3.2, 4.6, and 7.1 times, respectively.

[0100] 6. Unsteady-state phase permeation experimental method

[0101] The study clarified the variation patterns of oil-water permeability parameters during the reservoir cold damage recovery process. During the wellbore stagnation process, the near-wellbore formation temperature increases, leading to reservoir cold damage recovery. At temperatures above 55℃, the oil-water two-phase permeability span increases, particularly noticeable in low-permeability reservoirs. Low-permeability reservoirs show an increase of 105.92%, while medium- and high-permeability reservoirs show an increase of approximately 30%.

[0102] Table 5. Statistical table of changes in oil-water phase permeability related parameters at different temperatures during the cold damage recovery process of low-permeability, medium-permeability, and high-permeability reservoirs.

[0103]

[0104] 7. Numerical Simulation

[0105] The grid in directions I and J consists of 50×50 grids, each 1m×1m in size. In direction K, eight perforated sections were simulated based on actual stratigraphic information, with cold fluids at temperatures of 25℃, 30℃, 35℃, 40℃, 45℃, and 55℃ injected, respectively. Two thermal boundaries were set above and below each layer. At a reservoir temperature of 65℃, the formation temperature recovered to 55℃ in 2 hours at injected cold fluid temperatures of 25℃, 35℃, and 45℃, respectively, requiring 6, 4, and 3 hours. Recovery to 60℃ required 12, 9, and 7 hours. At a cold fluid temperature of 55℃, recovery to 60℃ required 4 hours. The formation temperature changes due to cold water injection were mainly concentrated in the near-wellbore area, within a range of 5 meters.

[0106] Table 6. Statistical Table of Relationship between Inlet Fluid Temperature and Formation Temperature Recovery

[0107]

[0108] Conclusions: The viscosity-temperature curves of the crude oil samples show that below 41℃, viscosity increases sharply with decreasing temperature, while above 41℃, viscosity gradually levels off with increasing temperature. The pour point of the crude oil samples can be determined to be around 40℃. Wax precipitation experiments show that the wax precipitation temperature is 62.77℃, and the critical temperature for cold fluid is determined to be 55℃. Comparison of the cumulative wax precipitation increase shows that below 40℃, the degree of wax precipitation damage is aggravated; between 40℃ and 55℃, the degree of wax precipitation damage is significantly reduced; and above 55℃, the degree of wax precipitation damage is relatively small. When the fracturing fluid injection temperature is above 55℃, the decreasing trend of the oil phase initiation pressure gradient with increasing temperature becomes more gradual, and the difference in initiation pressure gradient between different permeabilities is very small. Cold damage mainly affects medium- and low-permeability cores (<300mD), and the lower the permeability, the more pronounced the cold damage. During the well shut-in process, the near-wellbore formation temperature increases, and the reservoir cold damage recovers. Above 55℃, the oil-water two-phase flow span increases, especially noticeable in low-permeability reservoirs. Low-permeability reservoirs saw an increase of 105.92%, while medium-to-high permeability reservoirs saw an increase of approximately 30%. As reservoir temperatures decreased from 65℃ to 55, 45, 35, and 25℃, the breakthrough pressure gradient of the fracturing fluid increased by 1.8, 3.2, 4.6, and 7.1 times, respectively. At a reservoir temperature of 65℃, with injected cold fluid temperatures of 25, 35, and 45℃, the formation temperature recovered to 55℃ in 2 hours, requiring 6, 4, and 3 hours, respectively. Recovery to 60℃ required 12, 9, and 7 hours, respectively. With injected cold fluid temperatures of 55℃, recovery to 60℃ required 4 hours. The formation temperature changes resulting from cold water injection were mainly concentrated in the near-wellbore zone, within a 5-meter range.

[0109] The present invention and its embodiments have been described above illustratively. This description is not restrictive, and the figures shown are only one embodiment of the present invention; the actual structure is not limited thereto. Therefore, if those skilled in the art are inspired by this description and design similar structures and embodiments without departing from the spirit of the present invention, such designs should fall within the protection scope of the present invention.

Claims

1. A method for evaluating the cold damage of highly viscous oil, characterized in that, Using physical and numerical simulation methods, this study analyzes the degree of cold damage to the reservoir, its reversibility, the minimum temperature to avoid cold damage, and the reservoir temperature recovery time from both quantitative and qualitative perspectives. The physical simulation first determines the properties of crude oil through viscosity-temperature and wax separation experiments. Then, breakthrough pressure experiments using core samples determine the temperature at which cold damage occurs, initiation pressure experiments determine the minimum temperature to avoid damage, relative permeability experiments determine the impact of cold damage on the reservoir's seepage capacity, mercury intrusion porosimetry analyzes the impact of cold damage on the reservoir's pore structure, and two-dimensional nuclear magnetic resonance (NMR) and laser confocal microscopy (LCM) experiments determine whether the cold damage is reversible and at what temperature. Numerical simulation is used to analyze the recovery time required for different volumes and temperatures of working fluid to enter the formation.

2. The method for evaluating the cold damage of high-pour-point-weight oil according to claim 1, characterized in that, Includes the following steps: Step S1. Determine the physical properties of crude oil: (1) Crude oil viscosity analysis: By analyzing the viscosity-temperature curve, the viscosity-temperature characteristics of crude oil are obtained, and the flow properties of crude oil at different temperatures are evaluated. (2) Crude oil wax separation analysis: Compare and analyze the amount of wax melted at different temperature points to analyze the recoverability of reservoir cold damage; (3) Analysis of crude oil thermal properties: The thermal conductivity of oil-bearing rocks is affected by the heat conduction between the solid phase of the rock and the oil phase in the pores. By measuring the thermal conductivity of natural rock cores, we can provide a basis for numerical simulation to describe cold damage and well blockage time. Step S2. Determine the reservoir property range: Based on reservoir conditions, rock property tests are conducted using core samples taken from drilling to determine the overall porosity and permeability of the core. The reservoir heterogeneity is calculated using the permeability coefficient of variation formula, and the reservoir properties are classified into several categories such as high permeability, medium permeability, low permeability, and ultra-low permeability according to permeability and coefficient of variation. Step S3. Determine if cold injury will occur: After classifying the core samples, start-up pressure tests were conducted to analyze the changes in start-up pressure at different temperatures. The presence of an inflection point in the start-up pressure was used to determine whether cold damage would occur in the reservoir. Based on the reservoir overburden porosity and permeability test results, the flow-pressure gradient back-inference method or the depressurization method was determined. Step S4. Determining the reservoir cold damage temperature: Pressurize the rock sample in the core holder and gradually increase the test pressure at the inlet. When the pressure causes the fluid to form a continuous flow phase in the rock sample, the pressure difference between the inlet and outlet ends at this time is the breakthrough pressure. Apply the core holder to conduct gas phase breakthrough fracturing experiments to clarify the breakthrough pressure at different permeabilities and temperatures, and reveal the degree of cooling damage of the fracturing fluid. Step S5. Analysis of factors affecting seepage due to cold damage: The relative permeability experiment was used to determine the permeability of oil and water at different temperatures and to assess the impact of cold damage on reservoir permeability. Step S6. The impact of reservoir cold damage on pore structure: CT experiments were used to clarify the changes in pore structure parameters caused by cold damage, and NMR experiments were used to analyze the changes in pore structure, as well as the degree of pore phase binding and mobility caused by cold damage. Saturated oil cores with different permeabilities and temperatures were subjected to fracturing fluid displacement, and CT and NMR experiments were used to analyze the changes in pore throat structure caused by cold damage. Step S7. Numerical simulation of single-well cold damage and well blockage patterns: Based on the basic data of single wells in the reservoir, the reservoir geological model was established using PETRL software, and the reservoir numerical simulation software CMG was used to conduct numerical simulation of cold damage from hydraulic fracturing in single wells. The cold damage law was analyzed, and the influencing factors of cold damage from hydraulic fracturing of fracturing fluid were numerically analyzed. Based on the basic data of single wells in the reservoir, a reservoir geological model was established using PETRL software. After numerical simulation of cold damage caused by hydraulic fracturing in a single well using CMG reservoir numerical simulation software, the recovery law of the temperature field under cold damage was analyzed, and the suffocation law was numerically calculated. The recovery law of the reservoir temperature field after cold damage caused by hydraulic fracturing of fracturing fluid and its impact on production capacity were numerically analyzed.

3. The method for evaluating the cold damage of high-pour-point-weight oil according to claim 2, characterized in that, The formula for the coefficient of variation of permeability in step S2 is: σ - Coefficient of variation of permeability, dimensionless and expressed as a decimal; - Average permeability of all samples, mD; k i - The permeability of the i-th sample, mD; n - Number of samples, in units.

4. The method for evaluating the cold damage of high-pour-point-weight oil according to claim 2, characterized in that, The S3 test used three permeability specifications and four starting pressure gradients at four temperatures.

5. The method for evaluating the cold damage of high-pour-point-weight oil according to claim 2, characterized in that, In step S4, the core holder uses Natural rock core column.

6. The method for evaluating the cold damage of high-pour-point-weight oil according to claim 2, characterized in that, In step S5, the relative permeability experiment does not involve simultaneously injecting two fluids into the core. Instead, the core is pre-saturated with one fluid and then displaced by the other. During water-driven oil recovery, the distribution of oil-water saturation in the porous medium is a function of distance and time. This process is called an unsteady process. According to the simulation requirements, constant pressure difference or constant velocity water-driven oil recovery experiments are conducted on the reservoir rock sample. The production of each fluid and the pressure difference between the two ends of the rock sample are recorded at the outlet end of the rock sample over time. The oil-water relative permeability is calculated using the "JBN" method, and the relationship curve between the oil-water relative permeability and water saturation is plotted.

7. The method for evaluating the cold damage of high-pour-point-weight oil according to claim 6, characterized in that, The formulas for calculating relative permeability and water saturation in step S5 are as follows: In the formula: f o (S w — The oil content is expressed as a decimal. —Dimensionless cumulative oil recovery is expressed as a fraction of pore volume; —Dimensionless cumulative liquid volume, expressed as a fraction of pore volume; K ro —The relative permeability of the oil phase is expressed as a decimal; K rw —The numerical value of the relative permeability of the aqueous phase is expressed as a decimal; I—A numerical value of relative injection capacity, also known as the flow capacity ratio; Q o —The initial oil flow rate at the rock sample outlet face, in cm⁻¹ 3 / s); Q(t) — the flow rate of the liquid produced at the outlet face of the rock sample at time t. In the constant-rate method experiment, Q(t) = Q o cm 3 / s; Δp o —The initial driving pressure differential, in MPa; Δp(t) — The value of the displacement pressure difference at time t. In the constant pressure method experiment, Δp(t) = Δp o MPa; S ws —The numerical value of bound water saturation is expressed as a decimal; S we —The water saturation value at the outlet end of the rock sample, expressed as a decimal.

8. The method for evaluating the cold damage of high-pour-point-weight oil according to claim 2, characterized in that, The pore structure parameters in step S6 include pore radius, channel radius, coordination number, and cracks.

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