Quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs

Abstract

This invention discloses a quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs, implemented according to the following steps: Multiple rock samples from the tight carbonate gas reservoir are randomly acquired, and their porosity and permeability are measured using gas chromatography. The rock samples are then subjected to CT scanning and classified into three categories, and the proportion of each category in the total number of samples acquired is calculated. The damage rate of each category is calculated after processing with a displacement device. Based on the proportion of each category and its damage rate, the damage rate of the fracturing fluid to the tight carbonate gas reservoir is calculated. This quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs considers the characteristics of fractures, well-developed pores, and strong heterogeneity in tight carbonate gas reservoirs. It establishes a method for calculating a weighted damage rate through multi-sample classification testing, which can accurately reflect the degree of damage caused by fracturing fluid to tight carbonate gas reservoirs.

Description

Technical Field

[0001] This invention belongs to the field of unconventional oil and gas field development technology, and relates to a quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs. Background Technology

[0002] With the steady development of the global economy, the exploration and development potential of conventional oil and gas resources is decreasing, and with increasing environmental awareness, the global consumer market's demand for natural gas is gradually increasing. Therefore, it is essential to promote the exploration and development of unconventional and complex gas reservoirs in the oil and gas industry. The development of carbonate gas reservoirs is a typical example. Carbonate gas reservoirs are widely distributed globally, with huge reserves, and play an important role in global natural gas production and geological research. In my country, carbonate gas reservoirs are mainly distributed in the Tarim, Sichuan, and Ordos basins, and their development occupies an important position in my country's natural gas extraction. However, tight carbonate gas reservoirs are characterized by well-developed nano- and micropore throats, poor pore throat connectivity, well-developed fractures and dissolution pores, strong reservoir heterogeneity, and low matrix porosity and permeability. These unique reservoir properties result in low or no natural production capacity in tight carbonate gas reservoirs, requiring fracturing stimulation to achieve economical and industrialized development.

[0003] Under the action of high-pressure pumps on the ground, fracturing fluid enters the formation and opens fractures. Simultaneously, some fluid enters the reservoir and forms a filter cake on the fracture walls. After the fracturing fluid is flowed back, the fractures close on the proppant, completing the fracturing stimulation of the low-permeability reservoir. During this process, the intrusion of fracturing fluid and the retention of residue can cause some damage to the formation, reducing the effectiveness of fracturing in increasing production. Therefore, effectively and accurately evaluating the degree of damage caused by fracturing fluid to tight carbonate gas reservoirs is of paramount importance for optimizing fracturing fluid formulations, designing fracturing techniques, and guiding exploration and development decisions for tight carbonate gas reservoirs.

[0004] Currently, the evaluation method for the damage of fracturing fluids to tight carbonate gas reservoirs still relies on the traditional core displacement sampling method. This involves randomly drilling one or several rock samples from the target carbonate gas reservoir and directly determining the permeability of the samples before and after fracturing fluid intrusion through core displacement experiments, thereby calculating the damage rate. However, tight carbonate reservoirs are characterized by well-developed natural fractures and solution pores, exhibiting strong heterogeneity. Traditional evaluation methods do not consider the influence of these factors, resulting in highly random, unrepresentative, and inaccurate evaluation results that fail to accurately reflect the actual damage rate of fracturing fluids to the reservoir, often leading to incorrect conclusions. Therefore, it is urgent to consider the impact of fractures and solution pores on reservoir damage assessment and the heterogeneity of carbonate reservoirs, and to establish a representative, accurate, and rigorous quantitative method for evaluating the damage of fracturing fluids to tight carbonate gas reservoirs. Summary of the Invention

[0005] The purpose of this invention is to provide a quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs, which solves the problems of existing evaluation methods that do not consider the influence of fractures and dissolution pores on reservoir damage evaluation and the heterogeneity of carbonate reservoirs.

[0006] The technical solution adopted in this invention is a quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs, which is implemented according to the following steps:

[0007] Step 1: Randomly obtain multiple rock samples from tight carbonate gas reservoirs, and measure the porosity and permeability of each rock sample using gas logging methods.

[0008] Step 2: Perform CT scans on each rock sample and classify the multiple rock samples into three categories based on the CT scan results. Then calculate the proportion of the three categories of rock samples in the total number of rock samples obtained.

[0009] Step 3: After treating the three types of rock samples with a displacement device, calculate their damage rates respectively;

[0010] Step 4: Calculate the damage rate of fracturing fluid to tight carbonate gas reservoirs based on the proportion of the three types of rock samples in the total number of rock samples obtained and their damage rates.

[0011] The invention is further characterized by:

[0012] Step 1 is:

[0013] Step 1.1: Randomly obtain 15-30 rock samples from tight carbonate gas reservoirs;

[0014] Step 1.2: After standardizing the rock sample, dry it.

[0015] Step 1.3: The porosity and permeability of the dried rock sample were measured by gas analysis.

[0016] Step 2 is:

[0017] Step 2.1: Perform a CT scan on the rock sample;

[0018] Step 2.2: Based on the scanning results, the multiple rock samples are divided into three categories: rock samples without cracks or cavities, rock samples with cracks but without cavities, or rock samples with cavities.

[0019] Step 2.3: Calculate the proportions of rock samples without cracks or cavities, rock samples with cracks but without cavities, and rock samples with cavities in the total number of rock samples obtained, respectively: p1, p2, and p3.

[0020] Step 3 is:

[0021] Step 3.1: Sort the rock samples without cracks or cavities according to permeability from low to high, and select three rock samples with low, medium, and high permeability. The gas permeability of the three rock samples is recorded as K. a1低 K a1中 and K a1高 Then, using a displacement device, 1PV-3PV fracturing fluid filtrate was injected into the three rock samples respectively. After injection, the samples were allowed to stand for 0.5h-24h, followed by forward gas drive until the pressure stabilized. The permeability of the three rock samples was measured to be K. a2低 K a2中 and K a2高 The damage rate η1 of fracturing fluid filtrate to rock samples without fractures or cavities is:

[0022]

[0023] Step 3.2: Sort the fractured, non-porous rock samples according to permeability from low to high, and select three rock samples with low, medium, and high permeability. The gas permeability of the three rock samples is recorded as K. b1低 K b1中 and K b1高 Then, using a displacement device, 1PV-3PV of fracturing fluid was injected into the three rock samples respectively. After injection, the samples were allowed to stand for 0.5h-24h, followed by forward gas drive until the pressure stabilized. The permeability of the three rock samples was measured to be K. b2低 K b2中 and K b2高 The damage rate η2 of fracturing fluid to fractured but non-porous rock samples is:

[0024]

[0025] Step 3.3: Sort the rock samples with karst holes according to permeability from low to high, and select three rock samples with low, medium, and high permeability. The gas permeability of the three rock samples is recorded as K. c1低 K c1中 and K c1高 Then, using a displacement device, 1PV-3PV of fracturing fluid was injected into the three rock samples respectively. After injection, the samples were allowed to stand for 0.5h-24h, followed by forward gas drive until the pressure stabilized. The permeability of the three rock samples was measured to be K. c2低 K c2中 and K c2高 Then the damage rate η3 of fracturing fluid to the porous rock sample is:

[0026]

[0027] In step 4, the damage rate of fracturing fluid to tight carbonate gas reservoirs is calculated as follows:

[0028] η = η1×p1 + η2×p2 + η3×p3, where η is the damage rate of fracturing fluid to tight carbonate gas reservoirs, η1 is the damage rate of fracturing fluid filtrate to rock samples without fractures or cavities, η2 is the damage rate of fracturing fluid to rock samples with fractures but no cavities, and η3 is the damage rate of fracturing fluid to rock samples with cavities.

[0029] In step 3.1, the fracturing fluid filtrate is prepared by taking a rock sample without fractures or cavities, displacing the sample with fracturing fluid, and collecting the displacing tail fluid as the fracturing fluid filtrate.

[0030] The resolution of the CT scan in step 2.1 is no greater than 0.5 μm.

[0031] The beneficial effects of this invention are:

[0032] (1) The present invention provides a quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs. It takes into account the characteristics of fractures, pore development and strong heterogeneity of tight carbonate gas reservoirs, and establishes a method for calculating the weighted damage rate by multi-sample classification test. This method is more scientific and rigorous and can accurately reflect the degree of damage of fracturing fluid to tight carbonate gas reservoirs.

[0033] (2) The quantitative evaluation method of the damage of fracturing fluid to tight carbonate gas reservoirs of the present invention adopts the method of rock sample classification test damage rate, which can not only clarify the overall damage degree of the reservoir, but also clarify the local damage degree of fracturing fluid to various types of rocks.

[0034] (3) The quantitative evaluation method of fracturing fluid on tight carbonate gas reservoirs of the present invention is simple, effective and highly scalable. It can also be used in the evaluation and optimization of fracturing fluid formulations. Attached Figure Description

[0035] Figure 1 This is a flowchart of the quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs according to the present invention. Detailed Implementation

[0036] The present invention will now be described in detail with reference to the accompanying drawings and specific embodiments.

[0037] This invention provides a quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs, such as... Figure 1 As shown, please follow these steps:

[0038] Step 1: Randomly obtain multiple rock samples from tight carbonate gas reservoirs, and measure the porosity and permeability of each rock sample using gas logging methods.

[0039] Step 1 is:

[0040] Step 1.1: Randomly obtain 15-30 rock samples from tight carbonate gas reservoirs;

[0041] Step 1.2: After standardizing the rock sample, dry it.

[0042] Step 1.3: The porosity and permeability of the dried rock sample were measured by gas analysis.

[0043] Step 2: Perform CT scans on each rock sample and classify the multiple rock samples into three categories based on the CT scan results. Then calculate the proportion of the three categories of rock samples in the total number of rock samples obtained.

[0044] Step 2 is:

[0045] Step 2.1: Perform a CT scan on the rock sample;

[0046] Step 2.2: Based on the scanning results, the multiple rock samples are divided into three categories: rock samples without cracks or cavities, rock samples with cracks but without cavities, or rock samples with cavities.

[0047] Step 2.3: Calculate the proportions of rock samples without cracks or cavities, rock samples with cracks but without cavities, and rock samples with cavities in the total number of rock samples obtained, respectively: p1, p2, and p3.

[0048] The resolution of the CT scan in step 2.1 is no greater than 0.5 μm.

[0049] Step 3: After treating the three types of rock samples with a displacement device, calculate their damage rates respectively;

[0050] Step 3 is:

[0051] Step 3.1: Sort the rock samples without cracks or cavities according to permeability from low to high, and select three rock samples with low, medium, and high permeability. The gas permeability of the three rock samples is recorded as K. a1低 K a1中 and K a1高 Then, using a displacement device, 1PV-3PV fracturing fluid filtrate was injected into the three rock samples respectively. After injection, the samples were allowed to stand for 0.5h-24h, followed by forward gas drive until the pressure stabilized. The permeability of the three rock samples was measured to be K. a2低 K a2中 and K a2高 The damage rate η1 of fracturing fluid filtrate to rock samples without fractures or cavities is:

[0052]

[0053] Step 3.2: Sort the fractured, non-porous rock samples according to permeability from low to high, and select three rock samples with low, medium, and high permeability. The gas permeability of the three rock samples is recorded as K. b1低 K b1中 and K b1高Then, using a displacement device, 1PV-3PV of fracturing fluid was injected into the three rock samples respectively. After injection, the samples were allowed to stand for 0.5h-24h, followed by forward gas drive until the pressure stabilized. The permeability of the three rock samples was measured to be K. b2低 K b2中 and K b2高 The damage rate η2 of fracturing fluid to fractured but non-porous rock samples is:

[0054]

[0055] Step 3.3: Sort the rock samples with karst holes according to permeability from low to high, and select three rock samples with low, medium, and high permeability. The gas permeability of the three rock samples is recorded as K. c1低 K c1中 and K c1高 Then, using a displacement device, 1PV-3PV of fracturing fluid was injected into the three rock samples respectively. After injection, the samples were allowed to stand for 0.5h-24h, followed by forward gas drive until the pressure stabilized. The permeability of the three rock samples was measured to be K. c2低 K c2中 and K c2高 Then the damage rate η3 of fracturing fluid to the porous rock sample is:

[0056]

[0057] In step 3.1, the fracturing fluid filtrate is prepared by taking a rock sample without fractures or cavities, displacing the sample with fracturing fluid, and collecting the displacing tail fluid as the fracturing fluid filtrate.

[0058] Step 4: Calculate the damage rate of fracturing fluid to tight carbonate gas reservoirs based on the proportion of the three types of rock samples in the total number of rock samples obtained and their damage rates;

[0059] In step 4, the damage rate of fracturing fluid to tight carbonate gas reservoirs is calculated as follows:

[0060] η = η1×p1 + η2×p2 + η3×p3, where η is the damage rate of fracturing fluid to tight carbonate gas reservoirs, η1 is the damage rate of fracturing fluid filtrate to rock samples without fractures or cavities, η2 is the damage rate of fracturing fluid to rock samples with fractures but no cavities, and η3 is the damage rate of fracturing fluid to rock samples with cavities.

[0061] Example 1

[0062] This invention provides a quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs, such as... Figure 1 As shown, please follow these steps:

[0063] Step 1: Randomly drill 15 carbonate rock samples from a tight carbonate gas reservoir in the Ordos Basin. The samples are columnar rock samples with a diameter of 25 mm and a length of 40 mm. After drying the carbonate rock samples, the porosity and permeability of the carbonate reservoir rock samples are measured by gas, as shown in Table 1.

[0064] Step 2: Perform CT scans on the rock samples after gas analysis. Based on the CT scan results, and using the presence or absence of cracks and pores as indicators, classify the rock samples into three categories: rock samples without cracks or pores, rock samples with cracks or pores, and rock samples with pores. The calculated proportions of the three categories of rock samples are 33.33%, 40%, and 26.67%, respectively.

[0065] Step 3: Prepare fracturing fluid according to 0.3% guar gum + 2% crosslinking agent; take a rock sample C-13 without fractures or cavities, use fracturing fluid to displace the rock sample without fractures or cavities, and collect the displacement tail fluid as fracturing fluid filtrate;

[0066] The damage rate η1 of fracturing fluid filtrate to rock samples without fractures or cavities is calculated as follows:

[0067] Rock samples without fractures or cavities were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected: samples C-8, C-12, and C-1, with gas permeability of 0.081 mD, 0.230 mD, and 0.464 mD, respectively. Then, 1 PV of fracturing fluid filtrate was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 0.5 h, followed by forward gas displacement until the pressure stabilized. The gas permeability of the three samples was 0.039 mD, 0.129 mD, and 0.298 mD, respectively. The damage rate η1 of the fracturing fluid filtrate to the rock samples without fractures or cavities was calculated.

[0068]

[0069] The damage rate η2 of fracturing fluid to fractured but non-porous rock samples is calculated as follows:

[0070] Fractured, non-porous rock samples were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected: samples C-9, C-2, and C-14, with gas-measured permeabilities of 1.525 mD, 1.892 mD, and 2.300 mD, respectively. Then, 1 PV of fracturing fluid was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 0.5 h, followed by forward gas displacement until the pressure stabilized. The gas-measured permeabilities of the three samples were 1.049 mD, 1.333 mD, and 1.704 mD, respectively. The damage rate η2 of the fracturing fluid to the fractured, non-porous rock samples was calculated.

[0071]

[0072] The damage rate η3 of fracturing fluid to the rock sample with solution pores is calculated as follows:

[0073] Porous rock samples were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected: samples C-10, C-11, and C-6, with gas-measured permeabilities of 6.931 mD, 8.165 mD, and 10.544 mD, respectively. Then, 1 PV of fracturing fluid was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 0.5 h, followed by forward gas displacement until the pressure stabilized. The gas-measured permeabilities of the three samples were 5.844 mD, 7.306 mD, and 9.088 mD, respectively. The damage rate η3 of the fracturing fluid to the porous rock samples was calculated.

[0074]

[0075] Step 4: Calculate the damage rate η of fracturing fluid to the target tight carbonate gas reservoir in the Ordos Basin:

[0076] eta=43.85%×33.33%+28.89%×40%+13.34%×26.67%=18.26%.

[0077] Table 1. Porosity, permeability, and CT scan results of various rock samples from the Ordos Basin.

[0078]

[0079] Example 2

[0080] Step 1: Sixteen carbonate rock samples were randomly drilled from a tight carbonate gas reservoir in the Ordos Basin. The samples were columnar, 25 mm in diameter and 30 mm in length. After drying, the porosity and permeability of the carbonate reservoir samples were measured by gas analysis, as shown in Table 2.

[0081] Step 2: Perform CT scans on the rock samples after gas analysis. Based on the CT scan results, and using the presence or absence of cracks and pores as indicators, classify the rock samples into three categories: rock samples without cracks or pores, rock samples with cracks or pores, and rock samples with pores. The calculated proportions of the three categories of rock samples are 18.75%, 37.5%, and 37.5%, respectively.

[0082] Step 3: Prepare fracturing fluid according to 0.4% guar gum; take a rock sample C-1 without fractures or cavities, use fracturing fluid to displace the rock sample without fractures or cavities, and collect the displacement tail fluid as fracturing fluid filtrate;

[0083] The damage rate η1 of fracturing fluid filtrate to rock samples without fractures or cavities is calculated as follows:

[0084] Rock samples without fractures or cavities were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected, namely C-3, C-8, and C-9, with gas permeability of 0.034 mD, 0.060 mD, and 0.083 mD, respectively. Then, 2 PV of fracturing fluid filtrate was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 2 hours, followed by forward gas displacement until the pressure stabilized. The gas permeability of the three samples was 0.013 mD, 0.047 mD, and 0.062 mD, respectively. The damage rate η1 of the fracturing fluid filtrate to the rock samples without fractures or cavities was calculated.

[0085]

[0086] The damage rate η2 of fracturing fluid to fractured but non-porous rock samples is calculated as follows:

[0087] Fractured, non-porous rock samples were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected: samples C-4, C-13, and C-14, with gas-measured permeabilities of 1.292 mD, 1.392 mD, and 1.832 mD, respectively. Then, 2 PV of fracturing fluid was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 2 hours, followed by forward gas displacement until the pressure stabilized. The gas-measured permeabilities of the three samples were 1.157 mD, 1.186 mD, and 1.701 mD, respectively. The damage rate η2 of the fracturing fluid to the fractured, non-porous rock samples was calculated.

[0088]

[0089] The damage rate η3 of fracturing fluid to the rock sample with solution pores is calculated as follows:

[0090] Porous rock samples were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected, namely C-5, C-6, and C-11, with gas-measured permeabilities of 8.361 mD, 8.870 mD, and 10.543 mD, respectively. Then, 2 PV of fracturing fluid was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 2 hours, followed by forward gas displacement until the pressure stabilized. The gas-measured permeabilities of the three samples were 5.932 mD, 6.326 mD, and 6.836 mD, respectively. The damage rate η3 of the fracturing fluid to the porous rock samples was calculated.

[0091]

[0092] Step 4: Calculate the damage rate η of fracturing fluid to the target tight carbonate gas reservoir in the Sichuan Basin:

[0093] eta=18.75%×36.24%+37.5%×10.8%+37.5%×30.96%=22.46%.

[0094] Table 2. Porosity, permeability, and CT scan results of various rock samples from the Ordos Basin.

[0095]

[0096]

[0097] Example 3

[0098] Step 1: Eighteen carbonate rock samples were randomly drilled from a tight carbonate gas reservoir in the Sichuan Basin. The samples were columnar, 25 mm in diameter and 35 mm in length. After drying, the porosity and permeability of the carbonate reservoir samples were measured by gas analysis, as shown in Table 3.

[0099] Step 2: Perform CT scans on the rock samples after gas analysis. Based on the CT scan results, the rock samples are divided into three categories according to the presence or absence of cracks and pores: rock samples without cracks and pores, rock samples with cracks and pores, and rock samples with pores. The calculated proportions of the three categories of rock samples are 27.78%, 16.67%, and 55.56%, respectively.

[0100] Step 3: Prepare fracturing fluid according to 0.2% guar gum; take a rock sample C-13 without fractures or cavities, use fracturing fluid to displace the rock sample without fractures or cavities, and collect the displacement tail fluid as fracturing fluid filtrate;

[0101] The damage rate η1 of fracturing fluid filtrate to rock samples without fractures or cavities is calculated as follows:

[0102] Rock samples without fractures or cavities were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected, namely C-7, C-8, and C-16, with gas permeability of 0.037 mD, 0.162 mD, and 0.286 mD, respectively. Then, 1.5 PV of fracturing fluid filtrate was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 4 hours, followed by forward gas displacement until the pressure stabilized. The gas permeability of the three samples was 0.026 mD, 0.123 mD, and 0.263 mD, respectively. The damage rate η1 of the fracturing fluid filtrate to the rock samples without fractures or cavities was calculated.

[0103]

[0104] The damage rate η2 of fracturing fluid to fractured but non-porous rock samples is calculated as follows:

[0105] Fractured, non-porous rock samples were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected: samples C-5, C-10, and C-4, with gas-measured permeabilities of 2.438 mD, 2.644 mD, and 3.800 mD, respectively. Then, 1.5 PV of fracturing fluid was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 4 hours, followed by forward gas displacement until the pressure stabilized. The gas-measured permeabilities of the three samples were 2.222 mD, 2.276 mD, and 3.054 mD, respectively. The damage rate η2 of the fracturing fluid to the fractured, non-porous rock samples was calculated.

[0106]

[0107] The damage rate η3 of fracturing fluid to the rock sample with solution pores is calculated as follows:

[0108] Porous rock samples were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected: samples C-14, C-1, and C-11, with gas-measured permeabilities of 10.376 mD, 12.676 mD, and 13.994 mD, respectively. Then, 1.5 PV of fracturing fluid was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 4 hours, followed by forward gas displacement until the pressure stabilized. The gas-measured permeabilities of the three samples were 8.543 mD, 9.281 mD, and 9.839 mD, respectively. The damage rate η3 of the fracturing fluid to the porous rock samples was calculated.

[0109]

[0110] Step 4: Calculate the damage rate η of fracturing fluid to the target tight carbonate gas reservoir in the Sichuan Basin:

[0111] eta=27.78%×20.62%+16.67%×14.14%+55.56%×24.71%=21.81%.

[0112] Table 3. Porosity, permeability, and CT scan results of various rock samples from the Sichuan Basin.

[0113]

[0114]

[0115] Example 4

[0116] Step 1: 30 carbonate rock samples were randomly drilled from a tight carbonate gas reservoir in the Sichuan Basin. The samples were columnar, 25 mm in diameter and 50 mm in length. After drying, the porosity and permeability of the carbonate reservoir samples were measured by gas analysis, as shown in Table 4.

[0117] Step 2: Perform CT scans on the rock samples after gas analysis. Based on the CT scan results, and using the presence or absence of cracks and pores as indicators, classify the rock samples into three categories: rock samples without cracks or pores, rock samples with cracks or pores, and rock samples with pores. The calculated proportions of the three categories of rock samples are 23.33%, 46.67%, and 30.00%, respectively.

[0118] Step 3: Prepare fracturing fluid according to 0.5% anionic polyacrylamide; take a rock sample C-15 without fractures or cavities, use fracturing fluid to displace the rock sample without fractures or cavities, and collect the displacement tail fluid as fracturing fluid filtrate.

[0119] The damage rate η1 of fracturing fluid filtrate to rock samples without fractures or cavities is calculated as follows:

[0120] Rock samples without fractures or cavities were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected: samples C-5, C-23, and C-4, with gas permeability of 0.077 mD, 0.505 mD, and 0.661 mD, respectively. Then, 3 PV of fracturing fluid filtrate was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 24 hours, followed by forward gas displacement until the pressure stabilized. The gas permeability of the three samples was 0.052 mD, 0.328 mD, and 0.543 mD, respectively. The damage rate η1 of the fracturing fluid filtrate to the rock samples without fractures or cavities was calculated.

[0121]

[0122] The damage rate η2 of fracturing fluid to fractured but non-porous rock samples is calculated as follows:

[0123] Fractured, non-porous rock samples were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected: samples C-22, C-28, and C-19, with gas-measured permeabilities of 1.246 mD, 2.029 mD, and 3.075 mD, respectively. Then, 3 PV of fracturing fluid was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 24 hours, followed by forward gas displacement until the pressure stabilized. The gas-measured permeabilities of the three samples were 1.003 mD, 1.792 mD, and 2.886 mD, respectively. The damage rate η2 of the fracturing fluid to the fractured, non-porous rock samples was calculated.

[0124]

[0125] The damage rate η3 of fracturing fluid to the rock sample with solution pores is calculated as follows:

[0126] Porous rock samples were sorted by permeability from low to high. Three samples with low, medium, and high permeability were selected: samples C-18, C-11, and C-13, with gas-measured permeabilities of 7.593 mD, 10.508 mD, and 11.614 mD, respectively. Then, 3 PV of fracturing fluid was injected into each of the three samples using a displacement device. After injection, the samples were allowed to stand for 24 hours, followed by forward gas displacement until the pressure stabilized. The gas-measured permeabilities of the three samples were 5.282 mD, 8.373 mD, and 9.938 mD, respectively. The damage rate η3 of the fracturing fluid to the porous rock samples was calculated.

[0127]

[0128] Step 4: Calculate the damage rate η of fracturing fluid to the target tight carbonate gas reservoir in the Sichuan Basin:

[0129] eta=28.46%×23.33%+12.44%×46.67%+21.73%×30.00%=18.96%.

[0130] Table 4. Porosity, permeability, and CT scan results of various rock samples from the Sichuan Basin.

[0131]

[0132]

[0133] This invention provides a quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs. First, a certain number of target reservoir rock samples are drilled. Then, porosity and permeability are measured, and CT scans are performed. The rock samples are classified according to the presence or absence of fractures and pores. Within each category, samples are ranked according to permeability from highest to lowest. For each category, three rock samples with high, medium, and low permeability are selected for displacement experiments to determine the fracturing fluid damage rate. Finally, the measured damage rates are weighted and calculated to obtain the final damage rate. Compared with existing technologies, this quantitative evaluation method fully considers the characteristics of fractures, pore development, and strong heterogeneity in tight carbonate gas reservoirs. The results are more scientific and rigorous, more accurately reflecting the degree of damage caused by fracturing fluid to tight carbonate gas reservoirs. Furthermore, it is simple, effective, and widely applicable, and can also be used in fields such as the evaluation and optimization of fracturing fluid formulations.

Claims

1. A quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs, characterized in that, The specific steps are as follows: Step 1: Randomly obtain multiple rock samples from tight carbonate gas reservoirs, and measure the porosity and permeability of each rock sample using gas logging methods. Step 2: Perform CT scans on each of the rock samples, and divide the multiple rock samples into three categories based on the CT scan results. Then calculate the proportion of the three categories of rock samples in the total number of rock samples obtained. Step 2.1: Perform a CT scan on the rock sample; Step 2.2: Based on the scanning results, the multiple rock samples are divided into three categories: rock samples without cracks or cavities, rock samples with cracks but without cavities, and rock samples with cavities. Step 2.3: Calculate the proportions of unfractured and non-porous rock samples, fractured and non-porous rock samples, and porous rock samples in the total number of rock samples obtained, respectively: , and ; Step 3: After treating the three types of rock samples with a displacement device, calculate their damage rates respectively; Step 3.1: Sort the fracture-free and pore-free rock samples according to permeability from low to high, and select three rock samples with low, medium, and high permeability. The gas permeability of the three rock samples is recorded as follows: , and Then, using a displacement device, 1PV-3PV fracturing fluid filtrate was injected into the three rock samples respectively. After injection, the samples were allowed to stand for 0.5h-24h, followed by forward gas drive until the pressure stabilized. The permeability of the three rock samples was measured as follows: , and The damage rate of fracturing fluid filtrate to rock samples without fractures or cavities is... for: ； Step 3.2: Sort the fractured, non-porous rock samples according to permeability from low to high, and select three rock samples with low, medium, and high permeability. The gas permeability of the three rock samples is recorded as follows: , and Then, using a displacement device, 1PV-3PV of fracturing fluid was injected into the three rock samples respectively. After injection, the samples were allowed to stand for 0.5h-24h, followed by forward gas drive until the pressure stabilized. The permeability of the three rock samples was measured as follows: , and The damage rate of fracturing fluid to fractured but non-porous rock samples is... for: ； Step 3.3: Sort the porous rock samples according to permeability from low to high, and select three rock samples with low, medium, and high permeability. The gas permeability of the three rock samples is recorded as follows: , and Then, using a displacement device, 1PV-3PV of fracturing fluid was injected into the three rock samples respectively. After injection, the samples were allowed to stand for 0.5h-24h, followed by forward gas drive until the pressure stabilized. The permeability of the three rock samples was then measured. , and The damage rate of fracturing fluid to rock samples with solution pores is... for: ； Step 4: Calculate the damage rate of fracturing fluid to tight carbonate gas reservoirs based on the proportion of the three types of rock samples in the total number of rock samples obtained and their damage rates; The damage rate of fracturing fluid to tight carbonate gas reservoirs is calculated as follows: ,in This represents the damage rate of fracturing fluid to tight carbonate gas reservoirs. The damage rate of fracturing fluid filtrate to rock samples without fractures or solution pores. The damage rate of fracturing fluid to fractured, non-porous rock samples. The damage rate of fracturing fluid to rock samples with solution cavities.

2. The quantitative evaluation method according to claim 1, characterized in that, Step 1 is as follows: Step 1.1: Randomly obtain 15-30 rock samples from tight carbonate gas reservoirs; Step 1.2: After standardizing the rock sample, dry it. Step 1.3: The porosity and permeability of the dried rock sample were measured by gas analysis.

3. The quantitative evaluation method according to claim 1, characterized in that, In step 3.1, the fracturing fluid filtrate is prepared by taking a rock sample without fractures or cavities, displacing the rock sample with fracturing fluid, and collecting the displacing tail fluid as the fracturing fluid filtrate.

4. The quantitative evaluation method according to claim 1, characterized in that, The resolution of the CT scan in step 2.1 is no greater than 0.5 μm.

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