A method for determining the lower limit of pre-existing porosity and permeability for large-scale dissolution in deep clastic reservoirs

Abstract

The present invention belongs to the technical field of deep clastic rock resource exploration, and specifically relates to a method for determining the lower limit of pre-existing porosity and permeability for the occurrence of large-scale dissolution in deep clastic rock reservoirs. The present invention characterizes the ability of dissolution pores to develop by comparing the differences in porosity, dissolution surface porosity, and mineral composition before and after acid injection displacement experiments of dense clastic rocks and clastic rocks containing stress fracture networks, and verifies whether certain pre-existing porosity and permeability conditions are required for interconnected pore channels that allow acidic fluids to contact soluble minerals. On this basis, an acid injection displacement experiment is carried out on the clastic rock samples to be tested, and by comparing the differences in porosity, dissolution surface porosity, and mineral composition before and after, the ability of dissolution pores to develop is characterized, and the lower limit of pre-existing porosity and permeability for the development of large-scale dissolution pores in deep reservoirs is determined. When the clastic rock meets the lower limit of pre-existing porosity and permeability conditions, it can be determined that the deep clastic rock is a deep high-quality reservoir.

Description

Technical Field

[0001] The present 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 research have shown that large-scale, high-quality reservoirs are developed in deep strata of varying ages in diverse oil and gas-bearing basins around the world. These high-quality reservoirs are distributed over a wide range of depths (3,500 to 8,000 meters) and span a wide range of ages, from the Upper Paleozoic to the Cenozoic, with significant development in the Jurassic-Cretaceous and Paleogene-Neogene systems. The main genetic models of deep high-quality reservoirs are: 1. Early denudation and transportation deposition control type, including 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 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-lying The main control type is geothermal, 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 pre-salt Paleocene and Eocene sandstone reservoirs in the Gulf of Mexico; the main control type is early hydrocarbon filling, such as the Permian conglomerate reservoirs in the Junggar Basin; the main control type is late transformation, including the main control type of polygenetic dissolution pore formation, such as the Permian deep sandstone in the Huanghua Depression of the Bohai Bay Basin; the main control type is tectonic microfracture, such as the tight sandstone reservoirs of the Middle-Lower Jurassic Shuixigou Group in the Kekeya area of ​​the Tuha Basin. Based on the genetic type, it can be seen that dissolution pores are one of the important pore types in deep clastic reservoirs.

[0003] Microscopic observation of rock thin sections reveals that the formation of high-quality deep reservoirs in almost all regions of China is associated with dissolution, primarily through the dissolution of intergranular carbonate cements. Dissolution is the most common mechanism for the formation of high-quality deep clastic reservoirs in China, though the extent of dissolution varies across regions. Deep dissolution is primarily caused by organic acids (primarily) and carbon dioxide (carbonic acid formed when dissolved in water) produced by the maturation of organic matter, as well as by atmospheric water and deep hydrothermal fluids dissolving readily soluble minerals. This is also confirmed by the significant negative correlation between deep carbonate cements and porosity. Deep, high-quality reservoirs formed by the dissolution of feldspar and rock fragments have already been discovered.

[0004] The above analysis shows that secondary solution pores are the primary pore type in deep clastic reservoirs. These pore spaces, formed by acidic fluids (organic acids, atmospheric water, and deep hydrothermal fluids) dissolving soluble minerals (feldspar and carbonates), make a significant contribution to the spatial distribution of deep clastic reservoirs. In addition to acidic fluids and soluble minerals, the presence of interconnected pore spaces that allow acidic fluids to migrate near soluble minerals also constrains the scale of secondary solution pore development. However, prior art has not addressed whether interconnected pore spaces that allow acidic fluids to contact soluble minerals require certain pre-existing porosity and permeability conditions, or how to determine these 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 in 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] A first acid injection flooding experiment was conducted on a dense clastic rock and a clastic rock containing a 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 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.

[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 4.5-5 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 taken as 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 rock.

[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 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.

[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 of the injection 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 sample.

[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 pre-existing porosity and permeability for the occurrence of large-scale dissolution in deep clastic rock reservoirs, comprising the following steps: selecting dense clastic rock and clastic rock containing a stress fracture network as standard samples to conduct 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; conducting a second acid injection displacement experiment on the clastic rock to be tested, and testing the porosity of the resulting 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 amount is greater than 3.5%-6%, the carbonate rock dissolution amount 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 used as the lower limit 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 rock. The determination method provided by the present invention can meet the research on the channel problem of dissolution reaction caused by contact 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 acid injection flooding experiments on clastic rock samples and compares the differences in porosity, dissolution surface porosity, and mineral composition before and after acid injection to characterize the development of dissolution pores and verify whether the pore channels that allow acidic fluids to contact soluble minerals are dissolution-initiated. The present invention conducts acid injection flooding experiments on the clastic rock samples to characterize the development of dissolution pores and determine the pre-existing porosity and permeability lower limit conditions for the development of large-scale dissolution pores in deep reservoirs. When the clastic rock to be tested meets the pre-existing porosity and permeability 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 diagrams of the dense clastic rock sample and the clastic rock containing a stress fracture network in Example 1, original, after fracturing, and after acid injection;

[0020] Figure 2 This is a statistical graph showing the porosity increase and feldspar reduction of the clastic rock sample before and after the acid injection flooding experiment on the clastic rock in the gradient porosity range in Example 1;

[0021] Figure 3 This is a statistical diagram of the reduction in carbonate rock and the increase in porosity 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;

[0022] Figure 4 This is a statistical diagram of the permeability increase and feldspar reduction of the clastic rock sample before and after the acid injection displacement experiment on the clastic rock in the gradient permeability range in Example 1;

[0023] Figure 5 This is a statistical diagram of the feldspar reduction in the clastic rock samples before and after the acid injection displacement experiment on the clastic rock 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] A first acid injection flooding experiment was conducted on a dense clastic rock and a clastic rock containing a 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 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.

[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 4.5-5 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 taken as 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 rock.

[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 conduct 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, preferably a clastic rock of the core densification type caused by early dolomite cementation. The dimensions of the dense clastic rock are preferably 5 cm in length and 2.5 cm in diameter. Microscopic observation of the dense clastic rock reveals suspended clastic particles and cemented in the form of a dolomite base. Dolomite is a readily soluble mineral and is suitable for chemical reactions in which acidic fluids charge and dissolve minerals to form secondary dissolution pores.

[0032] In the present invention, the clastic rock containing stress fracture networks 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 networks 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 a stress fracture network is preferably 2%, and the permeability is preferably 4 mD. The composition of the clastic rock containing a 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 for the first acid injection flooding experiment is preferably a filling simulation experimental instrument, preferably model FDES-65Z; the acidic fluid used in the first acid injection flooding experiment preferably includes formic acid, acetic acid, and oxalic acid; the pH of the acidic fluid is preferably 2.5 to 3.0, specifically 2.5, 2.75, or 3.0. In the present invention, the pH is set higher than the actual geological value to compensate for the temperature and time effects of the clastic rock formation reaction.

[0037] Prior to the first acid flooding experiment, the present invention preferably further includes subjecting the dense clastic rock and the clastic rock containing a stress fracture network to oil washing treatments, respectively. The oil washing treatment is preferably performed using saturated formation water; the saturated formation water is preferably of the NaHCO3 type and has a density of 1.02 g / mL. The proportion of the saturated formation water used in the oil washing treatment is preferably based on the actual formation water salinity in the oil field. In the present invention, the oil washing treatment can simulate the washing of the clastic rock to a saturated formation water state.

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

[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 outlet for 20 hours, the reaction stops.

[0040] The present invention also preferably includes conducting high-pressure mercury injection and whole-rock mineralogy analysis on the dense clastic rock and the clastic rock containing a stress fracture network before and after the first acid injection flooding experiment, respectively, to determine porosity, permeability, and mineral composition. By comparing differences in porosity and permeability, mineral composition, and dissolution porosity, the present invention can simulate the dissolution differences between the same sample with and without fractures (fractures represent connected pore space), and analyze whether certain pre-existing porosity and permeability conditions are required to allow acidic fluids to contact the connected pore space 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] Based on the determination 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 taken as the lower limits of the existing 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 of the clastic rock to be tested is preferably in the range of 1% to 30%, and the permeability is preferably in the range of 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 conditions of the second acid injection flooding experiment are preferably consistent with those of the first acid injection flooding, and details thereof will not be repeated here.

[0047] In the present invention, the porosity increment and permeability increment are preferably obtained through a high-pressure mercury injection test. The high-pressure mercury injection test preferably includes the following steps: the experimental equipment is a PoreSizer 9320 mercury injection instrument from Micromeritics; the maximum experimental pressure is 136 MPa (the C28 rock sample is a subsequent supplementary rock sample, and its maximum experimental pressure is 32.1 MPa). Therefore, the lower limit of the pore throat radius measured in the experiment is 0.0054 μm (the lower limit of the pore throat radius of the C28 rock sample is 0.0234 μm). Pore throats below this value cannot be measured due to experimental conditions. The experimental method and data processing methods are based on SY / T5346-2005 "Determination of Capillary Pressure Curves in Rocks."

[0048] In the present invention, the feldspar and carbonate dissolution amounts are preferably determined by whole-rock mineralogy analysis, which preferably includes the following steps: qualitatively and quantitatively determining the mineral composition of the shale sample using X-ray diffraction patterns; mixing the crushed sample powder (300 mesh) with ethanol and applying it to a glass slide; and then conducting a Co Kα radiation generation experiment using a Bruker D8 DISCOVER diffractometer at 45 kV and 35 mA. The present invention can determine the dissolution amount by comparing the feldspar and carbonate content before and after acid injection.

[0049] In the present invention, the surface area fraction 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-HGF1 Intensilight to observe the thin section and distinguish the pores; further, in order to accurately record and quantify the point count data, using a statistical point count system (PETROG), 300 difference points are taken on the surface area to record the change in pore ratio before and after acid injection. The present invention can obtain the surface area fraction increment by comparing the change in pore ratio before and after acid injection.

[0050] 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 examples, but they should not be understood 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 was based on the actual formation water salinity 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 the 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, and its pH value was 2.75. The pH value 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 mineralogy analysis, and microscopic statistical analysis were performed on dense clastic rocks and clastic rocks containing stress fracture networks before and after the acid injection flooding experiment. 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 fracture networks by high-pressure mercury injection is shown in Table 1. Figure 1 shown.

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

[0056]

[0057] Combined with 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 acidic fluid is difficult to inject into the dense clastic rock sample at a filling pressure of 5 MPa. The acidic fluid fails to fully contact with the dissolved minerals and a dissolution reaction occurs, resulting in no significant changes in porosity, mineral composition, and apparent dissolution rate.

[0058] Comparison between dense clastic rock and clastic rock containing stress fracture network shows increased porosity and permeability, but no significant changes in mineral composition and apparent dissolution rate. The increased porosity and permeability is caused by the cracks generated 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 clastic rock containing stress fracture network, while the content of soluble minerals in the mineral composition (feldspar and carbonate rock content 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 space of soluble minerals.

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

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

[0063]

[0064] Acid injection flooding experiments were conducted on the above-mentioned clastic rocks under the same experimental conditions as those in the above-mentioned acid injection flooding experiments. This was done to simulate the differences in dissolution of samples before and after acidic fluid transformation under different porosity and permeability conditions, and to determine the pre-existing porosity and permeability lower limit conditions for the development of large-scale dissolution pores. Specific information on the samples after the acid injection flooding experiments is shown in Table 3.

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

[0066]

[0067] Figure 2 This is a statistical graph showing the porosity increase and feldspar reduction of the clastic rock sample before and after the acid injection flooding experiment on the clastic rock in the gradient porosity range in Example 1; Figure 3 This is a statistical diagram of the carbonate rock reduction and porosity increase of the clastic rock samples 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 injected; 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 injected, 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%, although the porosity, feldspar dissolution amount, carbonate rock dissolution amount, and surface porosity increase, they have a low correlation with the porosity of the original sample.

[0069] Figure 4 This is a statistical diagram of the permeability increase and feldspar reduction of the clastic rock sample before and after the acid injection displacement experiment on the clastic rock 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 do not change significantly before and after the acid fluid is injected; when the permeability is >0.1mD, the porosity, feldspar dissolution amount, carbonate rock dissolution amount, and surface porosity increase before and after the acid fluid is injected, 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, although the porosity, feldspar dissolution amount, carbonate rock dissolution amount, and surface porosity increase, they have a low correlation with the porosity of the original sample.

[0070] Based on the above analysis and judgment, in deep clastic reservoirs, certain pre-existing porosity and permeability conditions are required to allow acidic fluids to contact the connected pore space of soluble minerals. Combined with the comparison of porosity, permeability, feldspar dissolution, carbonate dissolution, and surface porosity 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 provides a detailed description of the present invention, 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 scope of protection of the present invention.

Claims

1. A method for determining the lower limit of pre-existing porosity and permeability for large-scale dissolution in deep clastic reservoirs, characterized by: The following steps are involved: A first acid injection flooding experiment was conducted on a dense clastic rock and a clastic rock containing a 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 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. 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 4.5-5 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 taken as 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 rock.

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

3. The determination method according to claim 2, wherein: 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, wherein: 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.

5. The determination method according to claim 1, wherein: 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, wherein: The first acid injection displacement experiment and the second acid injection displacement experiment both further 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.

Images