Quantitative evaluation method for damage of fracturing fluid to compact carbonate rock gas reservoir

Abstract

The invention discloses a quantitative evaluation method for damage of fracturing fluid to a compact carbonate gas reservoir, which is implemented according to the following steps: randomly acquiring a plurality of rock samples of the compact carbonate gas reservoir, and respectively measuring the porosity and permeability of the rock samples by a gas logging method; performing CT scanning on the rock samples, dividing the rock samples into three types, and then calculating the proportions of the three types of rock samples in the total amount of the obtained rock samples; treating the three types of rock samples by using a displacement device, and then respectively calculating the damage rates of the three types of rock samples; and calculating the damage rate of the fracturing fluid to the compact carbonate rock gas reservoir according to the proportions and damage rates of the three types of rock samples in the total amount of the obtained rock samples. According to the quantitative evaluation method for the damage of the fracturing fluid to the compact carbonate rock gas reservoir, the characteristics of cracks, dissolved hole development and high heterogeneity of the compact carbonate rock gas reservoir are considered, a method for solving the weighted damage rate through multi-sample classification testing is established, and the damage degree of the fracturing fluid to the compact carbonate rock gas reservoir can be accurately reflected.

Description

Technical Field

[0001] The invention belongs to the technical field of unconventional oil and gas field development, and relates to a quantitative evaluation method for damage of fracturing fluid to dense carbonate gas reservoirs. Background Art

[0002] With the steady development of the global economy, the exploration and development potential of conventional oil and gas resources has decreased, and people's environmental awareness has increased. The global consumer market's demand for natural gas is gradually increasing. Therefore, it is very necessary to promote the exploration and development of unconventional complex gas reservoirs in the oil and gas industry. The development of carbonate gas reservoirs is a typical representative of this. Carbonate gas reservoirs are widely distributed around the world, with huge reserves, and they play an important role in the world's natural gas production and geological research. my country's carbonate gas reservoirs are mainly distributed in the Tarim, Sichuan and Ordos basins. The development of carbonate gas reservoirs occupies an important position in my country's natural gas extraction. However, tight carbonate gas reservoirs have the characteristics of nano-micro pore throat development, poor pore throat connectivity, developed fractures and dissolved pores, strong reservoir heterogeneity, and low matrix porosity and permeability. This special reservoir property makes the natural production capacity of tight carbonate gas reservoirs low or no natural production capacity, and fracturing transformation is required to achieve economic and industrial development.

[0003] Under the action of the high-pressure pump group on the ground, the fracturing fluid enters the formation and presses open the cracks. At the same time, a part of the liquid will enter the reservoir and form a filter cake on the crack wall. After the fracturing fluid is returned, the cracks are closed on the proppant, completing the fracturing transformation of the low permeability reservoir. In this process, the invasion of the fracturing fluid and the retention of residues will cause a certain degree of damage to the formation, reducing the effect of fracturing production increase. Therefore, effectively and accurately evaluating the degree of damage of the fracturing fluid to the tight carbonate gas reservoir is of great significance for optimizing the fracturing fluid formula, designing the fracturing construction process, and guiding the exploration and development decision of the tight carbonate gas reservoir.

[0004] At present, the evaluation method of fracturing fluid damage to tight carbonate gas reservoirs still uses the traditional sampling core displacement method, which is: randomly drill one or several target carbonate gas reservoir rock samples, directly measure the permeability of the rock samples before and after the fracturing fluid invasion through core displacement experiments, and calculate the damage rate. However, tight carbonate reservoirs have developed natural fractures and dissolved pores and strong heterogeneity. Traditional evaluation methods do not consider the influence of the above factors. The evaluation results are extremely random, unrepresentative, and inaccurate. It is difficult to truly reflect the actual damage rate of fracturing fluid to the reservoir, and often it is impossible to get a correct conclusion. Therefore, it is urgent to consider the influence of fractures and dissolved pores on reservoir damage evaluation and the heterogeneity of carbonate reservoirs, and establish a representative, accurate, and rigorous quantitative evaluation method for fracturing fluid damage to tight carbonate gas reservoirs. Summary of the invention

[0005] The purpose of the present invention is to provide a quantitative evaluation method for the damage of fracturing fluid to tight carbonate gas reservoirs, which solves the problem that the evaluation method in the prior art does not consider the influence of cracks and dissolved pores on reservoir damage evaluation and the heterogeneity of carbonate reservoirs.

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

[0007] Step 1, randomly obtaining multiple rock samples of a tight carbonate gas reservoir, and measuring the porosity and permeability of each rock sample by gas measurement;

[0008] Step 2: Perform CT scanning on each rock sample, and classify the multiple rock samples into three categories according to the CT scanning results, and then calculate the proportion of the three categories of rock samples in the total amount of rock samples obtained;

[0009] Step 3, the three types of rock samples are treated with the displacement device and their damage rates are calculated respectively;

[0010] Step 4: Calculate the damage rate of the fracturing fluid to the tight carbonate gas reservoir according to the proportion of the three types of rock samples in the total amount of rock samples obtained and their damage rate.

[0011] The present invention is also characterized in that:

[0012] Step 1 is:

[0013] Step 1.1, randomly obtain 15 to 30 rock samples from tight carbonate gas reservoirs;

[0014] Step 1.2, drying the rock sample after standardization treatment;

[0015] Step 1.3: Measure the porosity and permeability of the dried rock samples by gas testing.

[0016] Step 2 is:

[0017] Step 2.1, perform CT scanning on the rock sample;

[0018] Step 2.2, according to the scanning results, the multiple rock samples are divided into three categories: rock samples without cracks and dissolved pores, rock samples with cracks and dissolved pores, or rock samples with dissolved pores;

[0019] Step 2.3, calculate the proportions of rock samples without cracks and dissolved pores, rock samples with cracks and dissolved pores, and rock samples with dissolved pores in the total amount of rock samples obtained, respectively: p1, p2, and p3.

[0020] Step 3 is:

[0021] Step 3.1: Sort the rock samples without cracks and dissolved pores by permeability from low to high, and select three rock samples with low, medium and high permeabilities. The gas permeabilities of the three rock samples are recorded as K a1低 , K a1中 and K a1高 Then, the displacement device was used to inject 1PV-3PV fracturing fluid filtrate into the three rock samples respectively. After the injection, the samples were left to stand for 0.5h-24h, and then the gas was driven forward until the pressure was stable. The permeabilities of the three rock samples were measured to be K a2低 , K a2中 and K a2高 , then the damage rate η1 of the fracturing fluid filtrate to the rock sample without cracks and dissolved pores is:

[0022]

[0023] Step 3.2: Sort the rock samples with cracks but no dissolved pores by permeability from low to high, and select three rock samples with low, medium and high permeabilities. The gas permeabilities of the three rock samples are recorded as K b1低 , K b1中 and K b1高 Then, the displacement device was used to inject 1PV-3PV fracturing fluid into the three rock samples respectively. After the injection, the samples were left to stand for 0.5h-24h, and then the gas was driven forward until the pressure was stable. The permeabilities of the three rock samples were measured to be K b2低 , K b2中 and K b2高 , then the damage rate η2 of the fracturing fluid to the rock sample with cracks but no dissolved pores is:

[0024]

[0025] Step 3.3: Sort the pore samples by permeability from low to high, and select three samples with low, medium and high permeabilities. The gas permeabilities of the three samples are recorded as K c1低 , K c1中 and K c1高 ; Then, the displacement device was used to inject 1PV-3PV fracturing fluid into the three rock samples respectively. After the injection, the samples were left to stand for 0.5h-24h, and then the gas was driven forward until the pressure was stable. The permeabilities of the three rock samples were measured to be K c2低 , K c2中 and K c2高 , then the damage rate η3 of the fracturing fluid to the soluble pore rock sample is:

[0026]

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

[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 cracks and dissolved pores, η2 is the damage rate of fracturing fluid to rock samples with cracks and no dissolved pores, and η3 is the damage rate of fracturing fluid to rock samples with dissolved pores.

[0029] The fracturing fluid filtrate in step 3.1 is: take a rock sample without cracks and dissolved pores, use fracturing fluid to displace the rock sample without cracks and dissolved pores, and collect the displacement tail liquid 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 the present invention are:

[0032] (1) The quantitative evaluation method of the damage of fracturing fluid to tight carbonate gas reservoirs in the present invention takes into account the characteristics of tight carbonate gas reservoirs, such as cracks, developed dissolved pores, and strong heterogeneity, and establishes a method for calculating the weighted damage rate by multi-sample classification testing. 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 the fracturing fluid to the tight carbonate gas reservoir of the present invention adopts the method of testing the damage rate by rock sample classification, which can not only clarify the damage degree of the reservoir as a whole, but also clarify the local damage degree of the fracturing fluid to each type of rock.

[0034] (3) The quantitative evaluation method of the damage of the fracturing fluid to the tight carbonate gas reservoir is simple, effective, and has strong scalability. It can also be used in the fields of evaluation and optimization of fracturing fluid formulations. BRIEF DESCRIPTION OF THE DRAWINGS

[0035] Figure 1 The present invention is a flow chart of a quantitative evaluation method for damage of fracturing fluid to tight carbonate gas reservoirs. DETAILED DESCRIPTION

[0036] The present invention is described in detail below with reference to the accompanying drawings and specific embodiments.

[0037] The quantitative evaluation method of the damage of the fracturing fluid to the tight carbonate gas reservoir is as follows: Figure 1 As shown, the specific implementation steps are as follows:

[0038] Step 1, randomly obtaining multiple rock samples of a tight carbonate gas reservoir, and measuring the porosity and permeability of each rock sample by gas measurement;

[0039] Step 1 is:

[0040] Step 1.1, randomly obtain 15 to 30 rock samples from tight carbonate gas reservoirs;

[0041] Step 1.2, drying the rock sample after standardization treatment;

[0042] Step 1.3: Measure the porosity and permeability of the dried rock samples by gas testing.

[0043] Step 2: Perform CT scanning on each rock sample, and classify the multiple rock samples into three categories according to the CT scanning results, and then calculate the proportion of the three categories of rock samples in the total amount of rock samples obtained;

[0044] Step 2 is:

[0045] Step 2.1, perform CT scanning on the rock sample;

[0046] Step 2.2, according to the scanning results, the multiple rock samples are divided into three categories: rock samples without cracks and dissolved pores, rock samples with cracks and dissolved pores, or rock samples with dissolved pores;

[0047] Step 2.3, calculate the proportions of rock samples without cracks and dissolved pores, rock samples with cracks and dissolved pores, and rock samples with dissolved pores in the total amount 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, the three types of rock samples are treated with the displacement device and their damage rates are calculated respectively;

[0050] Step 3 is:

[0051] Step 3.1: Sort the rock samples without cracks and dissolved pores by permeability from low to high, and select three rock samples with low, medium and high permeabilities. The gas permeabilities of the three rock samples are recorded as K a1低 , K a1中 and K a1高 Then, the displacement device was used to inject 1PV-3PV fracturing fluid filtrate into the three rock samples respectively. After the injection, the samples were left to stand for 0.5h-24h, and then the gas was driven forward until the pressure was stable. The permeabilities of the three rock samples were measured to be K a2低 , K a2中 and K a2高 , then the damage rate η1 of the fracturing fluid filtrate to the rock sample without cracks and dissolved pores is:

[0052]

[0053] Step 3.2: Sort the rock samples with cracks but no dissolved pores by permeability from low to high, and select three rock samples with low, medium and high permeabilities. The gas permeabilities of the three rock samples are recorded as K b1低 , K b1中 and K b1高Then, the displacement device was used to inject 1PV-3PV fracturing fluid into the three rock samples respectively. After the injection, the samples were left to stand for 0.5h-24h, and then the gas was driven forward until the pressure was stable. The permeabilities of the three rock samples were measured to be K b2低 , K b2中 and K b2高 , then the damage rate η2 of the fracturing fluid to the rock sample with cracks but no dissolved pores is:

[0054]

[0055] Step 3.3: Sort the pore samples by permeability from low to high, and select three samples with low, medium and high permeabilities. The gas permeabilities of the three samples are recorded as K c1低 , K c1中 and K c1高 ; Then, the displacement device was used to inject 1PV-3PV fracturing fluid into the three rock samples respectively. After the injection, the samples were left to stand for 0.5h-24h, and then the gas was driven forward until the pressure was stable. The permeabilities of the three rock samples were measured to be K c2低 , K c2中 and K c2高 , then the damage rate η3 of the fracturing fluid to the soluble pore rock sample is:

[0056]

[0057] The fracturing fluid filtrate in step 3.1 is: take a rock sample without cracks and dissolved pores, use fracturing fluid to displace the rock sample without cracks and dissolved pores, and collect the displacement tail liquid as the fracturing fluid filtrate.

[0058] Step 4: Calculate the damage rate of the fracturing fluid to the tight carbonate gas reservoir according to the proportion of the three types of rock samples in the total amount of rock samples obtained and their damage rate;

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

[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 cracks and dissolved pores, η2 is the damage rate of fracturing fluid to rock samples with cracks and no dissolved pores, and η3 is the damage rate of fracturing fluid to rock samples with dissolved pores.

[0061] Example 1

[0062] The quantitative evaluation method of the damage of the fracturing fluid to the tight carbonate gas reservoir is as follows: Figure 1 As shown, the specific implementation steps are as follows:

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

[0064] Step 2, the rock samples after gas testing are subjected to CT scanning respectively. According to the CT scanning results, the rock samples are divided into three categories: rock samples without cracks and pores, rock samples with cracks and pores, and rock samples with pores. The proportions of the three types of rock samples are calculated to be 33.33%, 40% and 26.67% respectively;

[0065] Step 3, preparing a fracturing fluid according to 0.3% guar gum + 2% cross-linking agent; taking a rock sample C-13 without cracks and dissolved pores, using the fracturing fluid to displace the rock sample without cracks and dissolved pores, and collecting the displacement tail liquid as the fracturing fluid filtrate;

[0066] The damage rate η1 of fracturing fluid filtrate to rock samples without cracks and dissolved pores is calculated as:

[0067] The rock samples without cracks and dissolved pores were sorted from low to high according to permeability, and three rock samples with low, medium and high permeabilities were selected. The three rock samples were C-8, C-12 and C-1, and their gas-measured permeabilities were 0.081mD, 0.230mD and 0.464mD, respectively. Then, 1PV of fracturing fluid filtrate was injected into the three rock samples using a displacement device. After the injection, the samples were allowed to stand for 0.5h, and then positively gas-driven until the pressure was stable. The gas-measured permeabilities of the three rock samples were 0.039mD, 0.129mD and 0.298mD, respectively. The damage rate η1 of the fracturing fluid filtrate to the rock samples without cracks and dissolved pores was calculated:

[0068]

[0069] The damage rate η2 of fracturing fluid to rock samples with cracks but no dissolved pores is calculated as:

[0070] The rock samples with cracks but no dissolved pores are sorted from low to high according to the permeability, and three rock samples with low, medium and high permeabilities are selected. The three rock samples are C-9, C-2 and C-14, and their gas-measured permeabilities are 1.525mD, 1.892mD and 2.300mD respectively. Then, 1PV fracturing fluid is injected into the three rock samples using a displacement device. After the injection, the samples are left to stand for 0.5h, and then positively gas-driven until the pressure is stable. The gas-measured permeabilities of the three rock samples are 1.049mD, 1.333mD and 1.704mD respectively. The damage rate η2 of the fracturing fluid to the rock samples with cracks but no dissolved pores is calculated:

[0071]

[0072] The damage rate η3 of fracturing fluid to rock samples with dissolved pores is calculated as:

[0073] The samples with dissolved pores were sorted from low to high in terms of permeability, and three samples with low, medium and high permeabilities were selected. The three samples were C-10, C-11 and C-6, and their gas-measured permeabilities were 6.931mD, 8.165mD and 10.544mD, respectively. Then, 1PV fracturing fluid was injected into the three samples using a displacement device. After the injection, the samples were allowed to stand for 0.5h, and then positively gas-driven until the pressure was stable. The gas-measured permeabilities of the three samples were 5.844mD, 7.306mD and 9.088mD, respectively. The damage rate η3 of the fracturing fluid to the samples with dissolved pores was calculated as follows:

[0074]

[0075] Step 4: Calculate the damage rate η of the 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 scanning results of rock samples in the Ordos Basin

[0078]

[0079] Example 2

[0080] Step 1: 16 carbonate rock samples were randomly drilled from a dense carbonate gas reservoir in the Ordos Basin. The rock samples were columnar rock samples with a diameter of 25 mm and a length of 30 mm. After the carbonate rock samples were dried, the porosity and permeability of the carbonate reservoir rock samples were measured by gas flow, as shown in Table 2.

[0081] Step 2, the rock samples after gas testing are subjected to CT scanning respectively. According to the CT scanning results, the rock samples are divided into three categories: rock samples without cracks and pores, rock samples with cracks and pores, and rock samples with pores. The proportions of the three types of rock samples are calculated to be 18.75%, 37.5% and 37.5% respectively;

[0082] Step 3, preparing a fracturing fluid according to 0.4% guar gum; taking a rock sample C-1 without cracks and dissolved pores, displacing the rock sample without cracks and dissolved pores with the fracturing fluid, and collecting the displacement tail liquid as the fracturing fluid filtrate;

[0083] The damage rate η1 of fracturing fluid filtrate to rock samples without cracks and dissolved pores is calculated as:

[0084] The rock samples without cracks and dissolved pores were sorted from low to high according to permeability, and three rock samples with low, medium and high permeabilities were selected. The three rock samples were C-3, C-8 and C-9, and their gas-measured permeabilities were 0.034mD, 0.060mD and 0.083mD, respectively. Then, the displacement device was used to inject 2PV fracturing fluid filtrate into the three rock samples, and the injection was allowed to stand for 2h, followed by positive gas drive until the pressure was stable. The gas-measured permeabilities of the three rock samples were 0.013mD, 0.047mD and 0.062mD, respectively. The damage rate η1 of the fracturing fluid filtrate to the rock samples without cracks and dissolved pores was calculated:

[0085]

[0086] The damage rate η2 of fracturing fluid to rock samples with cracks but no dissolved pores is calculated as:

[0087] The rock samples with cracks but no dissolved pores were sorted from low to high according to the permeability, and three rock samples with low, medium and high permeabilities were selected. The three rock samples were C-4, C-13 and C-14, and their gas-measured permeabilities were 1.292mD, 1.392mD and 1.832mD, respectively. Then, the displacement device was used to inject 2PV fracturing fluid into the three rock samples, and the samples were left to stand for 2h after the injection. Then, the gas was driven forward until the pressure was stable. The gas-measured permeabilities of the three rock samples were 1.157mD, 1.186mD and 1.701mD, respectively. The damage rate η2 of the fracturing fluid to the rock samples with cracks but no dissolved pores was calculated:

[0088]

[0089] The damage rate η3 of fracturing fluid to rock samples with dissolved pores is calculated as:

[0090] The samples with dissolved pores were sorted from low to high in terms of permeability, and three samples with low, medium and high permeabilities were selected. The three samples were C-5, C-6 and C-11, and their gas-measured permeabilities were 8.361mD, 8.870mD and 10.543mD, respectively. Then, a displacement device was used to inject 2PV fracturing fluid into the three samples, and the samples were allowed to stand for 2h after the injection. Then, the samples were positively gas-driven until the pressure was stable. The gas-measured permeabilities of the three samples were 5.932mD, 6.326mD and 6.836mD, respectively. The damage rate η3 of the fracturing fluid to the samples with dissolved pores was calculated as:

[0091]

[0092] Step 4: Calculate the damage rate η of the 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 scanning results of rock samples in the Ordos Basin

[0095]

[0096]

[0097] Example 3

[0098] Step 1: 18 carbonate rock samples were randomly drilled from a dense carbonate gas reservoir in the Sichuan Basin. The rock samples were columnar rock samples with a diameter of 25 mm and a length of 35 mm. After the carbonate rock samples were dried, the porosity and permeability of the carbonate reservoir rock samples were measured by gas flow, as shown in Table 3.

[0099] Step 2, the rock samples after gas testing are subjected to CT scanning respectively. According to the CT scanning results, the rock samples are divided into three categories: rock samples without cracks and pores, rock samples with cracks and pores, and rock samples with pores. The proportions of the three types of rock samples are calculated to be 27.78%, 16.67% and 55.56% respectively;

[0100] Step 3, preparing a fracturing fluid according to 0.2% guar gum; taking a rock sample C-13 without cracks and dissolved pores, displacing the rock sample without cracks and dissolved pores with the fracturing fluid, and collecting the displacement tail liquid as the fracturing fluid filtrate;

[0101] The damage rate η1 of fracturing fluid filtrate to rock samples without cracks and dissolved pores is calculated as:

[0102] The rock samples without cracks and dissolved pores were sorted from low to high according to permeability, and three rock samples with low, medium and high permeabilities were selected. The three rock samples were C-7, C-8 and C-16, and their gas-measured permeabilities were 0.037mD, 0.162mD and 0.286mD, respectively. Then, 1.5PV fracturing fluid filtrate was injected into the three rock samples using a displacement device. After the injection, the samples were allowed to stand for 4h, and then positively gas-driven until the pressure was stable. The gas-measured permeabilities of the three rock samples were 0.026mD, 0.123mD and 0.263mD, respectively. The damage rate η1 of the fracturing fluid filtrate to the rock samples without cracks and dissolved pores was calculated:

[0103]

[0104] The damage rate η2 of fracturing fluid to rock samples with cracks but no dissolved pores is calculated as:

[0105] The rock samples with cracks but no dissolved pores were sorted from low to high according to the permeability, and three rock samples with low, medium and high permeabilities were selected. The three rock samples were C-5, C-10 and C-4, and their gas-measured permeabilities were 2.438mD, 2.644mD and 3.800mD, respectively. Then, 1.5PV fracturing fluid was injected into the three rock samples using a displacement device. After the injection, the samples were left to stand for 4h, and then positively gas-driven until the pressure was stable. The gas-measured permeabilities of the three rock samples were 2.222mD, 2.276mD and 3.054mD, respectively. The damage rate η2 of the fracturing fluid to the rock samples with cracks but no dissolved pores was calculated:

[0106]

[0107] The damage rate η3 of fracturing fluid to rock samples with dissolved pores is calculated as:

[0108] The samples with dissolved pores were sorted from low to high in terms of permeability, and three samples with low, medium and high permeabilities were selected. The three samples were C-14, C-1 and C-11, and their gas-measured permeabilities were 10.376mD, 12.676mD and 13.994mD, respectively. Then, 1.5PV fracturing fluid was injected into the three samples using a displacement device. After the injection, the samples were allowed to stand for 4h, and then positively gas-driven until the pressure was stable. The gas-measured permeabilities of the three samples were 8.543mD, 9.281mD and 9.839mD, respectively. The damage rate η3 of the fracturing fluid to the samples with dissolved pores was calculated as:

[0109]

[0110] Step 4: Calculate the damage rate η of the 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 scanning results of rock samples in Sichuan Basin

[0113]

[0114]

[0115] Example 4

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

[0117] Step 2, the rock samples after gas testing are subjected to CT scanning respectively. According to the CT scanning results, the rock samples are divided into three categories: rock samples without cracks and pores, rock samples with cracks and pores, and rock samples with pores. The proportions of the three types of rock samples are calculated to be 23.33%, 46.67% and 30.00% respectively;

[0118] Step 3, preparing a fracturing fluid according to 0.5% anionic polyacrylamide; taking a rock sample C-15 without cracks and dissolved pores, using the fracturing fluid to displace the rock sample without cracks and dissolved pores, and collecting the displacement tail liquid as the fracturing fluid filtrate;

[0119] The damage rate η1 of fracturing fluid filtrate to rock samples without cracks and dissolved pores is calculated as:

[0120] The rock samples without cracks and dissolved pores were sorted from low to high according to permeability, and three rock samples with low, medium and high permeabilities were selected. The three rock samples were C-5, C-23 and C-4, and their gas-measured permeabilities were 0.077mD, 0.505mD and 0.661mD, respectively. Then, the displacement device was used to inject 3PV fracturing fluid filtrate into the three rock samples, and the samples were left to stand for 24h after the injection. Then, the gas was driven forward until the pressure was stable. The gas-measured permeabilities of the three rock samples were 0.052mD, 0.328mD and 0.543mD, respectively. The damage rate η1 of the fracturing fluid filtrate to the rock samples without cracks and dissolved pores was calculated:

[0121]

[0122] The damage rate η2 of fracturing fluid to rock samples with cracks but no dissolved pores is calculated as:

[0123] The rock samples with cracks but no dissolved pores were sorted from low to high according to permeability, and three rock samples with low, medium and high permeabilities were selected. The three rock samples were C-22, C-28 and C-19, and their gas-measured permeabilities were 1.246mD, 2.029mD and 3.075mD, respectively. Then, the displacement device was used to inject 3PV fracturing fluid into the three rock samples, and the samples were left to stand for 24h after the injection. Then, the gas was driven forward until the pressure was stable. The gas-measured permeabilities of the three rock samples were 1.003mD, 1.792mD and 2.886mD, respectively. The damage rate η2 of the fracturing fluid to the rock samples with cracks but no dissolved pores was calculated:

[0124]

[0125] The damage rate η3 of fracturing fluid to rock samples with dissolved pores is calculated as:

[0126] The samples with dissolved pores were sorted from low to high in terms of permeability, and three samples with low, medium and high permeabilities were selected. The three samples were C-18, C-11 and C-13, and their gas-measured permeabilities were 7.593mD, 10.508mD and 11.614mD, respectively. Then, the displacement device was used to inject 3PV fracturing fluid into the three samples, and the samples were allowed to stand for 24h after the injection. Then, the gas was driven forward until the pressure was stable. The gas-measured permeabilities of the three samples were 5.282mD, 8.373mD and 9.938mD, respectively. The damage rate η3 of the fracturing fluid to the samples with dissolved pores was calculated as follows:

[0127]

[0128] Step 4: Calculate the damage rate η of the 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 scanning results of rock samples in Sichuan Basin

[0131]

[0132]

[0133] The quantitative evaluation method of the damage of the fracturing fluid to the tight carbonate gas reservoir of the present invention firstly drills a certain number of target reservoir rock samples, then measures the porosity and permeability and performs CT scanning, classifies the rock samples according to the presence or absence of cracks and dissolved pores, and after each category is sorted according to the permeability, three rock samples with high, medium and low permeabilities are selected from each category of rock samples for displacement experiments, and the damage rate of the fracturing fluid is measured. Finally, the measured damage rate is weighted and calculated to obtain the final damage rate. Compared with the prior art, the quantitative evaluation method of the present invention fully considers the characteristics of the tight carbonate gas reservoir with developed cracks and dissolved pores and strong heterogeneity, and the results are more scientific and rigorous, and can more accurately reflect the degree of damage of the fracturing fluid to the tight carbonate gas reservoir, and is simple and effective, with strong scalability, and can also be used in the fields of evaluation and optimization of fracturing fluid formulations.

Claims

1. A quantitative evaluation method for damage of fracturing fluid to tight carbonate gas reservoirs, characterized in that: Follow the steps below to implement it: Step 1: randomly obtain multiple rock samples of a tight carbonate gas reservoir, and measure the porosity and permeability of each rock sample by gas measurement; Step 2, performing CT scanning on each of the rock samples, and classifying the plurality of rock samples into three categories according to the CT scanning results, and then calculating the proportion of the three categories of rock samples in the total amount of rock samples obtained; Step 3, treating the three types of rock samples with a displacement device and calculating their damage rates respectively; Step 4: Calculate the damage rate of the fracturing fluid to the tight carbonate gas reservoir according to the proportion of the three types of rock samples in the total amount of rock samples obtained and their damage rate.

2. The quantitative evaluation method according to claim 1, characterized in that: The step 1 is: Step 1.1, randomly obtain 15 to 30 rock samples from tight carbonate gas reservoirs; Step 1.2, drying the rock sample after standardization treatment; Step 1.3: Measure the porosity and permeability of the dried rock samples by gas testing.

3. The quantitative evaluation method according to claim 1, characterized in that: The step 2 is: Step 2.1, performing CT scanning on the rock sample; Step 2.2, according to the scanning results, the plurality of rock samples are divided into three categories: rock samples without cracks and dissolved pores, rock samples with cracks and dissolved pores, or rock samples with dissolved pores; Step 2.3, calculate the proportions of rock samples without cracks and dissolved pores, rock samples with cracks and dissolved pores, and rock samples with dissolved pores in the total amount of rock samples obtained, respectively: p1, p2, and p3.

4. The quantitative evaluation method according to claim 3, characterized in that: The step 3 is: Step 3.1: Sort the rock samples without cracks and dissolved pores from low to high in terms of permeability, and select three rock samples with low, medium and high permeabilities. The gas permeabilities of the three rock samples are recorded as K a1低 , K a1中 and K a1高 Then, the displacement device was used to inject 1PV-3PV fracturing fluid filtrate into the three rock samples respectively. After the injection, the samples were left to stand for 0.5h-24h, and then the gas was driven forward until the pressure was stable. The permeabilities of the three rock samples were measured to be K a2低 , K a2中 and K a2高 , then the damage rate η1 of the fracturing fluid filtrate to the rock sample without cracks and dissolved pores is: Step 3.2: Sort the rock samples with cracks but no dissolved pores from low to high in terms of permeability, and select three rock samples with low, medium and high permeabilities. The gas permeabilities of the three rock samples are recorded as K b1低 , K b1中 and K b1高 Then, the displacement device was used to inject 1PV-3PV fracturing fluid into the three rock samples respectively. After the injection, the samples were left to stand for 0.5h-24h, and then the gas was driven forward until the pressure was stable. The permeabilities of the three rock samples were measured to be K b2低 , K b2中 and K b2高 , then the damage rate η2 of the fracturing fluid to the rock sample with cracks but no dissolved pores is: Step 3.3: Sort the pore samples from low to high in terms of permeability, and select three samples with low, medium and high permeabilities. The gas permeabilities of the three samples are recorded as K c1低 , K c1中 and K c1高 ; Then, the displacement device was used to inject 1PV-3PV fracturing fluid into the three rock samples respectively. After the injection, the samples were left to stand for 0.5h-24h, and then the gas was driven forward until the pressure was stable. The permeabilities of the three rock samples were measured to be K c2低 , K c2中 and K c2高 , then the damage rate η3 of the fracturing fluid to the soluble pore rock sample is:

5. The quantitative evaluation method according to claim 4, characterized in that: The damage rate of the fracturing fluid to the tight carbonate gas reservoir is calculated in step 4 as follows: 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 cracks and dissolved pores, η2 is the damage rate of fracturing fluid to rock samples with cracks and no dissolved pores, and η3 is the damage rate of fracturing fluid to rock samples with dissolved pores.

6. The quantitative evaluation method according to claim 4, characterized in that: The fracturing fluid filtrate in step 3.1 is: take a rock sample without cracks and dissolved pores, use fracturing fluid to displace the rock sample without cracks and dissolved pores, and collect the displacement tail liquid as the fracturing fluid filtrate.

7. The quantitative evaluation method according to claim 3, characterized in that: The resolution of the CT scan in step 2.1 is no greater than 0.5 μm.

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