Determination method for lower limit of pre-stored pore permeability of scale corrosion of deep clastic rock reservoir

Abstract

The invention belongs to the technical field of deep clastic rock resource exploration, and particularly relates to a method for judging the lower limit of pre-stored pore permeability of scale corrosion occurrence of a deep clastic rock reservoir. According to the method, by comparing the pore permeability, corrosion surface porosity and mineral component differences before and after an acid injection displacement experiment of compact clastic rocks and clastic rocks containing stress fracture nets, the development capability of corrosion pores is represented, and whether a communicated pore channel allowing an acid fluid to be in contact with soluble minerals needs a certain pre-stored pore permeability condition or not is verified. And on the basis, carrying out an acid injection displacement experiment on a clastic rock sample to be detected, and comparing the porosity and permeability difference, the porosity difference of the corrosion surface and the mineral component difference before and after so as to characterize the development capability of the corrosion hole and judge the pre-stored porosity and permeability lower limit condition of the development of the scale corrosion hole of the deep reservoir. And when the clastic rock has the pre-stored pore permeability lower limit condition, determining that the deep clastic rock is a deep high-quality reservoir.

Description

Technical Field

[0001] The invention belongs to the technical field of deep clastic rock resource exploration, and in particular relates to a method for determining the lower limit of pre-existing porosity and permeability for large-scale dissolution of deep clastic rock reservoirs. Background Art

[0002] Existing exploration practices and studies have shown that large-scale high-quality reservoirs are developed in deep strata of different ages in different oil and gas basins around the world. High-quality reservoirs are distributed in a wide range of burial depths (3500-8000m) and a wide age span (developed from the Upper Paleozoic to the Cenozoic, and developed in large quantities in the Jurassic-Cretaceous and Paleogene-Neogene). The main genetic modes of deep high-quality reservoirs are: 1. Early denudation and transportation deposition control type, including the source-sink system control type, such as the deep reservoirs controlled by the provenance of the four major basin-margin water systems in the Paleogene of the Bohai Bay Basin; differential hydrodynamic control type, such as the deep-water turbidite sandstone reservoirs of the Auger oil and gas field in the deepwater area of ​​the Gulf of Mexico; early clay film control type, such as the marine sandstone reservoirs with chlorite clay film in the Middle and Lower Jurassic of the Norwegian continental shelf; 2. Medium-term burial control type, including the early long-term shallow burial control type, such as the sandstone reservoirs of the Lower Cretaceous Bashijiqike Formation in the Kuche Depression of the Tarim Basin; low The main control type is geotemperature, such as the Devonian Donghe sandstone in the Tarim Basin; the main control type is overpressure, such as the shallow marine sandstone of the Upper Jurassic Fulma Formation in the Central Graben of the North Sea; the main control type is low-density overburden, such as the subsalt Paleogene and Eocene sandstone reservoirs in the Gulf of Mexico; the main control type is early hydrocarbon filling, such as the Permian conglomerate reservoir in the Junggar Basin; third, the main control type of late transformation, including multi-genesis dissolution pore-forming main control type, such as the Permian deep sandstone in the Huanghua Depression in the Bohai Bay Basin; the main control type of structural microfractures, such as the tight sandstone reservoir of the Middle-Lower Jurassic Shuixigou Group in the Kekeya area of ​​the Tuha Basin. From the genetic type, it can be seen that dissolution pores are one of the important pore types of deep clastic reservoirs.

[0003] Microscopic observation of rock slices revealed that the formation of deep high-quality reservoirs in any region of China is almost always related to dissolution, and is basically dominated by the dissolution of intergranular carbonate cements. Dissolution is the most common mechanism for the formation of deep high-quality clastic reservoirs in China, but the degree of dissolution varies in different regions. Deep dissolution is mainly caused by organic acids (mainly) and carbon dioxide (carbonic acid formed by dissolving in water) produced by the maturity of organic matter, as well as atmospheric water and deep hydrothermal fluids dissolving soluble minerals. This can also be confirmed by the obvious negative correlation between deep carbonate cements and porosity, and deep high-quality reservoirs formed by the dissolution of feldspar and rock debris particles have been discovered.

[0004] Through the above analysis, it can be seen that secondary dissolution pores are the main pore type in deep clastic reservoirs. They are secondary pore spaces formed by acidic fluids (organic acids, atmospheric water, deep hydrothermal fluids) dissolving soluble minerals (feldspar, carbonate rocks), and they make an important contribution to the deep clastic reservoir space. In addition to acidic fluids and soluble minerals, the connected pore space that allows acidic fluids to migrate to the vicinity of soluble minerals is also one of the constraints on the development scale of secondary dissolution pores; however, the prior art does not report whether the connected pore space that allows acidic fluids to contact soluble minerals requires certain pre-existing porosity and permeability conditions, and how to determine the specific pre-existing porosity and permeability conditions. Summary of the invention

[0005] The purpose of the present invention is to provide a method for determining the lower limit of pre-existing porosity and permeability for large-scale dissolution of deep clastic reservoirs. The determination method provided by the present invention can determine the lower limit of pre-existing porosity and permeability that allows large-scale dissolution to occur.

[0006] In order to achieve the above object, the present invention provides the following technical solutions:

[0007] The present invention provides a method for determining the lower limit of pre-existing porosity and permeability for large-scale dissolution of deep clastic reservoirs, comprising the following steps:

[0008] The first acid injection displacement experiment is conducted by selecting dense clastic rock and clastic rock containing stress fracture network as standard samples to test the apparent dissolution rate of the clastic rock. If the apparent dissolution rate of the clastic rock containing stress fracture network is greater than 0 and the apparent dissolution rate of the dense clastic rock is equal to 0, it is determined that the connected pores in the clastic rock affect the occurrence of large-scale dissolution;

[0009] The clastic rock to be tested is subjected to a second acid injection displacement experiment to test the porosity, permeability, component content and surface ratio of the obtained clastic rock;

[0010] When the porosity increment of the clastic rock to be tested is greater than 0.7-2%, the permeability increment is greater than 4.5-5mD, the feldspar dissolution is greater than 3.5%-6%, the carbonate rock dissolution is greater than 3.5-6%, and the surface surface increment is greater than 1.5-5%, the porosity and permeability of the clastic rock to be tested are the lower limits of the existing porosity and permeability for large-scale dissolution to occur;

[0011] The components of the dense clastic rock, the clastic rock containing stress fracture network and the clastic rock to be tested independently include quartz, feldspar, clay minerals and carbonate rocks.

[0012] Preferably, the dense clastic rock, the clastic rock containing stress fracture networks and the clastic rock containing pores independently include the following components in percentage by mass: quartz 25-65%, feldspar 8-28%, clay minerals 10-17%, and carbonate rock 5-40%.

[0013] Preferably, the dense clastic rock has a porosity of 1% and a permeability of 0.01 mD; the clastic rock containing a stress fracture network has a porosity of 2% and a permeability of 4 mD.

[0014] Preferably, the acidic fluids used in the first acid injection displacement experiment and the second acid injection displacement experiment independently include formic acid, acetic acid and oxalic acid; and the pH values ​​of the acidic fluids independently range from 2.5 to 3.0.

[0015] Preferably, the injection pressures of the first acid injection displacement experiment and the second acid injection displacement experiment are independently 4.5-5.5 MPa, and the confining pressures are independently 6-8 MPa.

[0016] Preferably, the first acid injection displacement experiment and the second acid injection displacement experiment both further include performing oil washing treatment on the test samples.

[0017] Preferably, the oil washing treatment is carried out using saturated formation water; the water type of the saturated formation water is NaHCO3 type, and the density is 1.02 g / mL.

[0018] The present invention provides a method for determining the lower limit of the pre-existing porosity and permeability for the occurrence of large-scale dissolution in deep clastic rock reservoirs, comprising the following steps: respectively selecting dense clastic rock and clastic rock containing a stress fracture network as standard samples to carry out a first acid injection displacement experiment, testing the apparent dissolution rate of the clastic rock; if the apparent dissolution rate of the clastic rock containing a stress fracture network is greater than 0, and the apparent dissolution rate of the dense clastic rock is equal to 0, it is determined that the connected pores in the clastic rock affect the occurrence of large-scale dissolution; carrying out a second acid injection displacement experiment on the clastic rock to be tested, testing the porosity of the obtained clastic rock , permeability, component content and surface area; when the porosity increment of the clastic rock to be tested is greater than 0.7-2%, the permeability increment is greater than 4.5-5mD, the feldspar dissolution is greater than 3.5%-6%, the carbonate rock dissolution is greater than 3.5-6%, and the surface area increment is greater than 1.5-5%, the porosity and permeability of the clastic rock to be tested are the lower limits of the existing porosity and permeability for large-scale dissolution; the components of the dense clastic rock, the clastic rock containing stress fracture network and the clastic rock to be tested independently include quartz, feldspar, clay minerals and carbonate rocks. The determination method provided by the present invention can meet the research on the channel problem of dissolution reaction between acidic fluid and soluble minerals, and is an important supplement and improvement to the dissolution mechanism of deep clastic reservoirs. The present invention conducts an acid injection displacement experiment on clastic rock samples, and compares and analyzes the porosity difference, dissolution surface ratio difference and mineral component difference before and after acid injection to characterize the dissolution pore development ability and verify whether the pore channel that allows acidic fluid to contact soluble minerals is created by dissolution; The present invention conducts an acid injection displacement experiment on the clastic rock samples to be tested, and by comparing the porosity difference, dissolution surface ratio difference and mineral component difference before and after, it can characterize the dissolution pore development ability and determine the pre-existing porosity lower limit conditions for the development of dissolution pores on a deep reservoir scale. When the clastic rock to be tested meets the pre-existing porosity lower limit conditions, it can be determined that the clastic rock is a deep high-quality reservoir. BRIEF DESCRIPTION OF THE DRAWINGS

[0019] Figure 1 The high-pressure mercury injection pore size distribution diagram of the dense clastic rock sample and the clastic rock containing the stress fracture network in Example 1, originally, after fracturing and after acid injection;

[0020] Figure 2 The figure is a statistical diagram of the porosity increase and feldspar reduction of the clastic rock sample before and after the acid injection displacement experiment on the clastic rock to be tested in the gradient porosity range in Example 1;

[0021] Figure 3 The statistical diagram of the carbonate rock reduction and the surface porosity increase of the clastic rock sample before and after the acid injection displacement experiment on the clastic rock to be tested in the gradient porosity range in Example 1;

[0022] Figure 4 The statistical diagram of the increase in permeability and the decrease in feldspar of the clastic rock sample before and after the acid injection displacement experiment on the clastic rock to be tested in the gradient permeability range in Example 1;

[0023] Figure 5 This is a statistical chart of the feldspar reduction in the clastic rock samples before and after the acid injection displacement experiment on the clastic rock to be tested in the gradient permeability range in Example 1. DETAILED DESCRIPTION

[0024] The present invention provides a method for determining the lower limit of pre-existing porosity and permeability for large-scale dissolution of deep clastic reservoirs, comprising the following steps:

[0025] The first acid injection displacement experiment is conducted by selecting dense clastic rock and clastic rock containing stress fracture network as standard samples to test the apparent dissolution rate of the clastic rock. If the apparent dissolution rate of the clastic rock containing stress fracture network is greater than 0 and the apparent dissolution rate of the dense clastic rock is equal to 0, it is determined that the connected pores in the clastic rock affect the occurrence of large-scale dissolution;

[0026] The clastic rock to be tested is subjected to a second acid injection displacement experiment to test the porosity, permeability, component content and surface ratio of the obtained clastic rock;

[0027] When the porosity increment of the clastic rock to be tested is greater than 0.7-2%, the permeability increment is greater than 4.5-5mD, the feldspar dissolution is greater than 3.5%-6%, the carbonate rock dissolution is greater than 3.5-6%, and the surface surface increment is greater than 1.5-5%, the porosity and permeability of the clastic rock to be tested are the lower limits of the existing porosity and permeability for large-scale dissolution to occur;

[0028] The components of the dense clastic rock, the clastic rock containing stress fracture network and the clastic rock to be tested independently include quartz, feldspar, clay minerals and carbonate rocks.

[0029] In the present invention, unless otherwise specified, the reagents and raw materials used are commercially available products well known to those skilled in the art.

[0030] The present invention selects dense clastic rock and clastic rock containing stress fracture network as standard samples to carry out the first acid injection displacement experiment, and tests the apparent dissolution rate of the clastic rock. If the apparent dissolution rate of the clastic rock containing stress fracture network is greater than 0 and the apparent dissolution rate of the dense clastic rock is equal to 0, it is determined that the connected pores in the clastic rock affect the occurrence of large-scale dissolution.

[0031] In the present invention, the dense clastic rock is preferably a dense clastic rock drilling core, and the dense clastic rock drilling core is preferably a clastic rock of the core densification type caused by early dolomite cementation; the size of the dense clastic rock is preferably: 5 cm in length and 2.5 cm in diameter. In the present invention, the dense clastic rock can be observed under a microscope to show that the clastic particles are suspended and cemented in the form of a dolomite base. Dolomite is a soluble mineral and is suitable for the chemical reaction of acidic fluid filling dissolving minerals to form secondary dissolution pores.

[0032] In the present invention, the clastic rock containing stress fracture network is preferably obtained by subjecting the dense clastic rock to a triaxial compression test; after the triaxial compression test, the clastic rock containing stress fracture network can produce porosity and permeability differences with the dense clastic rock; the experimental equipment for the triaxial compression test is preferably Autolab2000c.

[0033] In the present invention, the dense clastic rock and the clastic rock containing stress fracture network independently preferably include the following components in percentage by mass: quartz 25-65%, feldspar 8-28%, clay minerals 10-17%, and carbonate rock 5-40%.

[0034] In the present invention, the porosity of the dense clastic rock is preferably 1%, and the permeability is preferably 0.01 mD. In the present invention, the porosity of the clastic rock containing stress fracture network is preferably 2%, and the permeability is preferably 4 mD; the composition of the clastic rock containing stress fracture network is preferably the same as that of the dense clastic rock.

[0035] As an embodiment of the present invention, the composition information table of the dense clastic rock and the clastic rock containing stress fracture network is shown in Table 1.

[0036] In the present invention, the experimental equipment of the first acid injection displacement experiment is preferably a filling simulation experimental instrument, and the model is preferably FDES-65Z; the acidic fluid used in the first acid injection displacement experiment preferably includes formic acid, acetic acid and oxalic acid; the pH of the acidic fluid is preferably 2.5-3.0, specifically 2.5, 2.75 or 3.0. In the present invention, a pH higher than the actual geological value is set to compensate for the temperature and time effects of the reaction of the clastic rock formation.

[0037] Before the first acid injection displacement experiment, the present invention also preferably includes washing the dense clastic rock and the clastic rock containing the stress fracture network with oil respectively; the oil washing treatment is preferably carried out with saturated formation water; the water type of the saturated formation water is preferably NaHCO3 type, and the density is preferably 1.02g / mL; the proportion of the saturated formation water used in the oil washing treatment is preferably based on the actual formation water mineralization of the oil field. In the present invention, the oil washing treatment can simulate washing the clastic rock with oil to a saturated formation water state.

[0038] In the present invention, the injection pressure of the first acid injection displacement experiment is preferably 4.5-5.5MPa, specifically 4.5MPa, 5.0MPa or 5.5MPa; the confining pressure is preferably 6-8MPa, specifically 6MPa, 7MPa or 8MPa. In the present invention, the power of filling the tight clastic reservoir with organic acid fluid is to simulate the overpressure in the hydrocarbon generation pressurization process.

[0039] In the present invention, during the first acid injection displacement experiment, the meter at the outlet of the filling device is preferably observed once every 2 hours; when the fluid increase rate of the meter at the outlet is constant (fluid cumulative amount difference / metering time difference), or there is no change in the fluid at the meter at the outlet for 20 hours, the reaction stops.

[0040] The present invention also preferably includes performing high-pressure mercury injection tests and whole-rock mineral analysis on the dense clastic rock and the clastic rock containing stress fracture networks before and after the first acid injection displacement experiment, respectively, to obtain porosity, permeability and mineral components. In the present invention, by comparing the differences in porosity and permeability, mineral component differences and dissolution surface porosity differences, it is possible to simulate the dissolution differences under the conditions of the same sample with or without cracks (cracks represent connected pore spaces), and analyze whether certain pre-existing porosity and permeability conditions are required to allow acidic fluids to contact the connected pore spaces of soluble minerals.

[0041] In the present invention, if the apparent dissolution rate of the clastic rock containing the stress fracture network is greater than 0, and the apparent dissolution rate of the dense clastic rock is equal to 0, it is determined that the connected pores in the clastic rock affect the occurrence of large-scale dissolution.

[0042] On the basis of determining that the connected pore space in the clastic rock affects the occurrence of large-scale dissolution, the present invention conducts a second acid injection displacement experiment on the clastic rock to be tested, and tests the porosity, permeability, component content and surface ratio of the obtained clastic rock;

[0043] When the porosity increment of the clastic rock to be tested is greater than 0.7-2%, the permeability increment is greater than 4.5-5 mD, the feldspar dissolution amount is greater than 3.5%-6%, the carbonate rock dissolution amount is greater than 3.5-6%, and the surface porosity increment is greater than 1.5-5%, the porosity and permeability of the clastic rock to be tested are the existing lower limits of porosity and permeability for large-scale dissolution to occur.

[0044] In the present invention, the clastic rock to be tested preferably includes the following components in percentage by mass: quartz 25-65%, feldspar 8-28%, clay minerals 10-17%, and carbonate rock 5-40%.

[0045] In the present invention, the porosity range of the clastic rock to be tested is preferably 1% to 30%, and the permeability range is preferably 0.01 mD to 1000 mD. As an embodiment of the present invention, the composition of the clastic rock to be tested is shown in Table 2.

[0046] In the present invention, the second acid injection displacement experiment is preferably carried out under the same conditions as the first acid injection displacement experiment, which will not be described in detail herein.

[0047] In the present invention, the porosity increment and permeability increment are preferably obtained by high-pressure mercury injection experiment, and the high-pressure mercury injection experiment preferably includes the following steps: the experimental equipment is PoreSizer9320 mercury injection instrument of Micromeritics Company; the maximum experimental pressure is 136MPa (C28 rock sample is a subsequent supplementary rock sample, and its maximum experimental pressure is 32.1MPa), so the lower limit of the pore throat radius measured in the experiment is 0.0054μm (the lower limit of the pore throat radius of C28 rock sample is 0.0234μm), and the pore throat below this value cannot be measured due to experimental conditions. The experimental method and data processing method refer to SY / T5346-2005 "Determination of rock capillary pressure curve".

[0048] In the present invention, the feldspar dissolution amount and carbonate dissolution amount are preferably obtained by whole-rock mineral analysis, and the whole-rock mineral analysis preferably includes the following steps: using X-ray diffraction patterns to qualitatively and quantitatively obtain the mineral components in the shale sample; mixing the crushed sample powder (300 mesh) with ethanol and coating it on a glass slide; and then performing a Co Kα radiation generation experiment under the conditions of 45kV and 35mA by a BrukerD8 DISCOVER diffractometer. The present invention can determine the dissolution amount by comparing the difference in the content of feldspar and carbonate before and after acid injection.

[0049] In the present invention, the surface rate increment is preferably obtained by microscopic statistical analysis; the microscopic statistical analysis preferably includes the following steps: using a Nikon ECLIPSE LV100N POL polarizing microscope and a Nikon C-HGF1Intensilight to observe the thin slice and distinguish the pores; further, in order to accurately record and quantify the point data, a statistical point system (PETROG) is used to take 300 difference points on the surface area and record the change in pore ratio before and after acid injection. The present invention can obtain the surface rate increment by comparing the change in pore ratio before and after acid injection.

[0050] In order to further illustrate the present invention, a method for determining the lower limit of pre-existing porosity and permeability for large-scale dissolution of deep clastic reservoirs provided by the present invention is described in detail below in conjunction with embodiments, but they should not be construed as limiting the scope of protection of the present invention.

[0051] Example 1

[0052] Dense clastic rock and clastic rock containing stress fracture network with a length of 5 cm and a diameter of 2.5 cm were selected for oil washing treatment to a saturated formation water state. The formation water ratio referred to the actual formation water mineralization of the oil field. The water type was NaHCO3 type with a density of 1.02 g / mL.

[0053] The first acid injection displacement experiment was carried out. The filling device selected was a filling simulation experiment instrument, model FDES-65Z. The acidic fluid was prepared with an organic acid solution of formic acid, acetic acid and oxalic acid. Its pH value was 2.75, which was higher than the actual geological value to compensate for the temperature and time effects of the reaction.

[0054] High-pressure mercury injection experiments, whole-rock mineral analysis and microscopic statistical analysis were performed on dense clastic rocks and clastic rocks containing stress fractures before and after the acid injection flooding experiment, and the porosity and permeability, mineral composition and apparent dissolution rate were obtained, as shown in Table 1. The pore size distribution of dense clastic rocks and clastic rocks containing stress fractures by high-pressure mercury injection is shown in Figure 1 shown.

[0055] Table 1 Comparison of dense clastic rock and clastic rock with stress fracture network before and after acid injection displacement experiment

[0056]

[0057] Combining Table 1 and Figure 1 It can be seen that: the comparison between the dense clastic rock and the dense clastic rock after acid injection shows that the acid fluid is difficult to inject into the dense clastic rock sample at a filling pressure of 5Mpa, and the acid fluid fails to fully contact with the dissolved minerals to cause dissolution reaction, resulting in no obvious changes in porosity, mineral composition, and apparent dissolution rate;

[0058] Comparison between dense clastic rock and clastic rock with stress fracture network shows that porosity and permeability increase, but mineral composition and apparent dissolution rate do not change significantly. The increase in porosity and permeability is caused by the cracks produced by triaxial compression (manifested by the abnormally high high pore size interval of the mercury injection curve);

[0059] Comparison between dense clastic rock after acid injection and clastic rock containing stress fracture network after acid injection shows that the porosity and permeability of clastic rock containing stress fracture network increased when acidic fluid was injected into it, while the soluble minerals in the mineral components (the content of feldspar and carbonate rock decreased) and the apparent dissolution rate increased.

[0060] Based on the above comparative experimental analysis, it can be seen that dense low-porosity and permeability reservoirs cannot allow acidic fluids to fully contact with soluble minerals, and deep clastic reservoirs require certain pre-existing porosity and permeability conditions to allow acidic fluids to contact the connected pore spaces of soluble minerals.

[0061] Ten clastic rock samples with gradient porosity and permeability were selected, with a porosity distribution range of 1-30% and a corresponding permeability distribution range of 0.01-1000 mD. High-pressure mercury injection experiments, whole-rock mineralogy analysis and microscopic statistical analysis were carried out. The specific information of the samples is shown in Table 2.

[0062] Table 2 Information of clastic rock samples to be tested

[0063]

[0064] Acid injection displacement experiment was carried out on the above-mentioned clastic rock to be tested. The experimental conditions were the same as those of the above-mentioned acid injection displacement experiment, so as to simulate the difference in dissolution of samples before and after acid fluid transformation under different porosity and permeability conditions, and determine the pre-existing porosity and permeability lower limit conditions for the development of large-scale dissolution pores. The specific information of the samples after the acid injection displacement experiment is shown in Table 3.

[0065] Table 3 Information of the clastic rock samples after acid injection flooding experiment

[0066]

[0067] Figure 2 The figure is a statistical diagram of the porosity increase and feldspar reduction of the clastic rock sample before and after the acid injection displacement experiment on the clastic rock to be tested in the gradient porosity range in Example 1; Figure 3 This is a statistical chart of the carbonate rock reduction and surface porosity increase of the clastic rock sample before and after the acid injection displacement experiment on the clastic rock in the gradient porosity range in Example 1.

[0068] Combined with Table 3, Figure 2 and Figure 3 It can be seen that when the porosity is <10%, the porosity, feldspar dissolution amount, carbonate rock dissolution amount and surface porosity do not change significantly before and after the acid fluid is filled; when the porosity is >10%, the porosity, feldspar dissolution amount, carbonate rock dissolution amount and surface porosity increase before and after the acid fluid is filled, and reach the maximum value when the porosity is ≈15%, showing a single peak trend of first increasing and then decreasing; when the porosity is >20%, the porosity, feldspar dissolution amount, carbonate rock dissolution amount and surface porosity increase, but have a low correlation with the porosity of the original sample.

[0069] Figure 4 The statistical diagram of the increase in permeability and the decrease in feldspar of the clastic rock sample before and after the acid injection displacement experiment on the clastic rock to be tested in the gradient permeability range in Example 1; Figure 5 The following is a statistical diagram of the reduction in carbonate rock and feldspar of the clastic rock samples before and after the acid injection displacement experiment on the clastic rock in the gradient permeability range in Example 1. Figure 4 It can be seen that when the permeability is <0.1mD, the porosity, feldspar dissolution amount, carbonate rock dissolution amount and surface porosity before and after the acid fluid is injected do not change significantly; when the permeability is >0.1mD, the porosity, feldspar dissolution amount, carbonate rock dissolution amount and surface porosity before and after the acid fluid is injected all increase, and reach the maximum value when the permeability is ≈10mD, showing a single peak trend of first increasing and then decreasing; when the permeability is >100mD, the porosity, feldspar dissolution amount, carbonate rock dissolution amount and surface porosity increase, but have a low correlation with the porosity of the original sample.

[0070] Based on the above analysis and judgment, in deep clastic reservoirs, the interconnected pore space that allows acidic fluids to contact soluble minerals requires certain pre-existing porosity and permeability conditions. Combining the comparison of porosity, permeability, feldspar dissolution, carbonate dissolution and surface area before and after acid injection in Tables 2 and 3, it can be concluded that the lower limit of pre-existing porosity and permeability verified by the above experiments is approximately porosity = 10.64% and permeability = 0.41mD (i.e. sample number 7B).

[0071] Although the above embodiment describes the present invention in detail, it is only a part of the embodiments of the present invention, not all of the embodiments. Other embodiments can be obtained based on this embodiment without creativity, and these embodiments all fall within the protection scope of the present invention.

Claims

1. A method for determining the lower limit of pre-existing porosity and permeability for large-scale dissolution of deep clastic reservoirs, characterized in that: The following steps are involved: The first acid injection displacement experiment is conducted by selecting dense clastic rock and clastic rock containing stress fracture network as standard samples to test the apparent dissolution rate of the clastic rock. If the apparent dissolution rate of the clastic rock containing stress fracture network is greater than 0 and the apparent dissolution rate of the dense clastic rock is equal to 0, it is determined that the connected pores in the clastic rock affect the occurrence of large-scale dissolution; The clastic rock to be tested is subjected to a second acid injection displacement experiment to test the porosity, permeability, component content and surface ratio of the obtained clastic rock; When the porosity increment of the clastic rock to be tested is greater than 0.7-2%, the permeability increment is greater than 4.5-5mD, the feldspar dissolution is greater than 3.5%-6%, the carbonate rock dissolution is greater than 3.5-6%, and the surface surface increment is greater than 1.5-5%, the porosity and permeability of the clastic rock to be tested are the lower limits of the existing porosity and permeability for large-scale dissolution to occur; The components of the dense clastic rock, the clastic rock containing stress fracture network and the clastic rock to be tested independently include quartz, feldspar, clay minerals and carbonate rocks.

2. The determination method according to claim 1, characterized in that: The dense clastic rock, the clastic rock containing stress fracture network and the clastic rock containing pores independently include the following components in percentage by mass: 25-65% of quartz, 8-28% of feldspar, 10-17% of clay minerals and 5-40% of carbonate rock.

3. The determination method according to claim 2, characterized in that: The porosity of the dense clastic rock is 1%, and the permeability is 0.01 mD; the porosity of the clastic rock containing the stress fracture network is 2%, and the permeability is 4 mD.

4. The determination method according to claim 1, characterized in that: The acidic fluids used in the first acid injection displacement experiment and the second acid injection displacement experiment independently include formic acid, acetic acid and oxalic acid; the pH values ​​of the acidic fluids independently range from 2.5 to 3.

0.

5. The determination method according to claim 1, characterized in that: The injection pressures of the first acid injection displacement experiment and the second acid injection displacement experiment are independently 4.5-5.5 MPa, and the confining pressures are independently 6-8 MPa.

6. The determination method according to claim 1, characterized in that: The first acid injection displacement experiment and the second acid injection displacement experiment both include performing oil washing treatment on the test samples.

7. The determination method according to claim 6, characterized in that: The oil washing treatment is carried out using saturated formation water; the water type of the saturated formation water is NaHCO3 type, and the density is 1.02 g / mL.

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