A method for predicting favorable reservoirs

Abstract

The present invention relates to a method for predicting favorable reservoirs, which uses siliceous shale phase, rich in organic matter and mature organic matter maturity as lithofacies evaluation standards, uses porosity above medium pores, permeability above medium permeability and micropore proportion less than 33.3% as reservoir performance evaluation standards, and uses high adsorption as gas content evaluation standard to construct a continental shale reservoir quality evaluation method, and the reservoir that meets the continental shale reservoir quality evaluation method is a favorable reservoir. The present invention divides lithofacies based on the mineral components and geochemical characteristics of continental shale, and integrates the reservoir performance and gas content of the reservoir to achieve the identification of favorable reservoirs. The present invention overcomes the difficulties of rapid changes in the sedimentary environment and strong heterogeneity of continental shale reservoirs, and uses precise lithofacies division as a means to complete a comprehensive geological study of shale reservoirs through multiple parameters. The present invention provides a reference for the exploration and development of continental shale oil and gas.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas exploration, and in particular to a method for predicting a favorable reservoir. Background Art

[0002] The continental sedimentary system has the characteristics of rapid sedimentary phase change, strong heterogeneity, and great differences in lithology. Most lake basins are formed under relatively complex sedimentary phases. The sediment components contain clay minerals, brittle minerals and carbonate rocks, and the lithology development within the formation is significantly different. Affected by the scale of lake sedimentation, continental shale is greatly affected by the sedimentary environment and geological structure during its evolution. Compared with the marine shale with a quiet water body sedimentary environment, which is mostly in the overmature stage, continental shale is found in the immature (Yanchang Formation in the Ordos Basin) to the overmature stage (Shanxi Formation in the Ordos Basin). The organic matter abundance and thermal evolution degree of continental shale vary greatly. The differences in shale lithology, sedimentary environment, deep fluids and later diagenetic evolution process cause significant differences in mineral composition, showing strong heterogeneity, which will inevitably lead to the diversity of rock fabrics and complexity of pore structure in the laminae of continental shale, which will increase the difficulty of later development and extraction. Therefore, the prediction of favorable reservoirs for continental shale is of great significance.

[0003] Existing evaluation methods usually evaluate the development parameters of the target layer in the exploration area, such as the results of oil (gas) testing, fracturing parameters, drilling parameters, and fluid parameters, so as to establish an evaluation method for predicting reserves and favorable reservoirs at sweet spots; then determine the economic lower limit of natural gas equivalent through mining economic evaluation, and determine the favorable development area of ​​shale gas by combining multiple parameters, and do not distinguish between marine and terrestrial phases. In view of the strong heterogeneity, rapid lithology changes, and large differences in single well production in continental sedimentary environment basins, the practicality is low. It is necessary to seek a more in-depth and targeted evaluation method focusing on reservoir characteristics to identify continental shale gas sweet spots and favorable reservoirs. Summary of the invention

[0004] Based on the above reasons, the present invention provides a favorable reservoir prediction method. This technology focuses on reservoir characteristics, divides the advantageous lithofacies based on the mineral composition of continental shale, and then conducts classification research based on the hydrocarbon generation component basis, thermal evolution degree and gas-bearing parameters of the reservoir, thereby serving to find high-quality reservoirs and providing support for the exploration and later development of continental shale reservoirs.

[0005] The technical solution of the present invention is: A method for predicting favorable reservoirs is proposed, which takes siliceous shale phase, rich in organic matter and mature organic matter maturity as lithofacies evaluation standards, takes porosity above medium pores, permeability above medium permeability and micropore proportion less than 33.3% as reservoir performance evaluation standards, and takes high adsorption as gas content evaluation standard to construct a continental shale reservoir quality evaluation method, and the reservoir that meets the continental shale reservoir quality evaluation method is defined as a favorable reservoir.

[0006] The petrographic evaluation criteria also include medium organic matter and over-mature organic matter maturity; the gas content evaluation criteria also include medium adsorption and high gas content.

[0007] The parameters of the lithofacies evaluation standard include mineral composition, organic carbon content and organic matter maturity; among them, the classification standard of organic carbon content is: TOC < 1% is low organic matter, 1% ≤ TOC < 2% is medium organic matter, and TOC ≥ 2% is rich organic matter; the classification standard of organic matter maturity is: Ro < 1% is immature, 1% ≤ Ro < 2% is mature, and Ro ≥ 2% is overmature.

[0008] The parameters of the reservoir performance evaluation standard include porosity, permeability and pore size distribution type; the porosity classification standard is: porosity <2% is low porosity, 2%≤porosity <4% is medium porosity, and porosity ≥4% is high porosity; the permeability classification standard is: permeability <0.1mD is low permeability, 0.1mD≤permeability <1mD is medium permeability, and permeability ≥1mD is high permeability; the pore size distribution type classification standard is: macropore proportion ≥50% is macroporous type, medium porosity ≥50% is macroporous type, and high porosity ≥50% is high permeability. The proportion of micropores ≥50% is mesopore type, the proportion of micropores ≥50% is micropore type, the proportion of mesopores > the proportion of macropores > 33% is macropore-mesopore type, the proportion of mesopores > the proportion of micropores > 33% is micropore-mesopore type, the proportion of micropores > the proportion of macropores > 33% is macropore-micropore type, the proportion of micropores > the proportion of mesopores > 33% is mesopore-micropore type, the proportion of macropores > the proportion of mesopores > 33% is mesopore-macropore type, the proportion of macropores > the proportion of micropores > 33% is micropore-macropore type.

[0009] The parameters of the gas content evaluation standard include isothermal adsorption gas content and on-site analytical gas content; the classification standard of isothermal adsorption gas content is as follows: isothermal adsorption gas content <1.5% is low adsorption, 1.5%≤isothermal adsorption gas content <3% is medium adsorption, and isothermal adsorption gas content ≥3% is high adsorption; the classification standard of on-site analytical gas content is as follows: on-site analytical gas content <1.5% is low gas content, 1.5%≤on-site analytical gas content <3% is medium gas content, and on-site analytical gas content ≥3% is high gas content.

[0010] The mineral composition is obtained through XDR mineral diffraction experimental analysis, and the specific process is: using siliceous minerals, clay minerals and carbonate minerals as three end members to project points on the mineral triangle diagram, and dividing the siliceous shale phase, clay shale phase, dolomite shale and mixed shale phase types according to the mineral components.

[0011] Wherein, the porosity and permeability are obtained by nitrogen measurement method.

[0012] It also includes that pores < 2nm are micropores, pores 2nm≤<50nm are mesopores, and pores ≥50 nm are macropores.

[0013] The on-site analyzed gas content is obtained through on-site pressure-maintaining coring testing.

[0014] The technical effects of the present invention are: The present invention divides lithofacies based on the mineral components and geochemical characteristics of continental shale, integrates the reservoir performance and gas content of the reservoir, and realizes the identification of favorable reservoirs. The present invention overcomes the difficulties of rapid changes in the sedimentary environment and strong heterogeneity of continental shale reservoirs, and uses precise lithofacies division as a means to complete a comprehensive geological study of shale reservoirs through multiple parameters. The present invention provides a reference for the exploration and development of continental shale oil and gas. BRIEF DESCRIPTION OF THE DRAWINGS

[0015] Figure 1 This is the petrographic evaluation diagram of the present invention.

[0016] Figure 2 This is a result diagram of identifying favorable reservoirs using the method provided by the present invention. DETAILED DESCRIPTION

[0017] Taking the continental shale gas exploration in the Yishan Slope Yanchang exploration area in the Ordos Basin as an example, a favorable reservoir prediction method is described. The specific process is as follows: S1. Lithofacies classification of continental shales according to lithofacies evaluation standards: According to the XDR mineral component triangle diagram, it can be summarized into four mineral component lithofacies types: type I dolomitic shale, type II clay shale phase, type III siliceous shale phase, and type IV mixed shale phase; the siliceous shale phase is selected as the optimal condition for favorable reservoirs; Then, according to the classification standards of organic carbon content and organic matter maturity, nine geochemical lithofacies are divided: organic-rich overmature lithofacies, organic-rich mature lithofacies, organic-rich immature lithofacies, medium organic overmature lithofacies, medium organic mature lithofacies, medium organic immature lithofacies, low organic overmature lithofacies, low organic mature lithofacies and low organic immature lithofacies; according to the lithofacies evaluation standards, organic-rich overmature lithofacies, organic-rich mature lithofacies and medium organic overmature lithofacies are screened out as the preferred conditions for favorable reservoirs.

[0018] S2. Classification of reservoir performance of continental shales according to reservoir performance evaluation standards: According to the porosity classification standard, it is divided into: low porosity, medium porosity and high porosity; according to the permeability classification standard, it is divided into: low permeability, medium permeability and high permeability; according to the pore size distribution type classification standard, it is divided into: macropore type, mesopore type, micropore type, macropore-mesopore type, micropore-mesopore type, macropore-micropore type, mesopore-micropore type, mesopore-macropore type, micropore-macropore type, a total of 9 types; according to the reservoir performance evaluation standard, the pore size distribution types of non-low porosity, non-low permeability, and micropore proportion less than 33.3% (macropore type, mesopore type, macropore-mesopore type, mesopore-macropore type, micropore-mesopore type, micropore-macropore type) are screened out as the preferred conditions for favorable reservoirs.

[0019] S3. Classification of gas content of continental shales according to gas content evaluation standards: According to the classification standards of isothermal adsorption gas content and the classification standards of field analysis gas content, a total of 9 types are divided: low adsorption and low gas content, low adsorption and medium gas content, low adsorption and high gas content, medium adsorption and low gas content, medium adsorption and medium gas content, medium adsorption and high gas content, high adsorption and low gas content, high adsorption and medium gas content and high adsorption and high gas content; according to the gas content evaluation standards, medium adsorption and high gas content, high adsorption and low gas content, high adsorption and low gas content, high adsorption and medium gas content and high adsorption and high gas content are selected as the preferred conditions for favorable reservoirs.

[0020] S4. Optimization of favorable continental shale reservoirs: Based on the above favorable reservoir optimization conditions, favorable reservoir optimization was completed for the Upper Paleozoic Shanxi Formation in the YYa well in the Yanchang exploration area. Figure 2 As shown, favorable reservoir 1 is selected as siliceous, organic-rich, over-mature, high porosity, medium permeability, medium pore type, high adsorption, and low gas-bearing shale lithofacies; favorable reservoir 2 is siliceous, organic-rich, over-mature, high porosity, medium permeability, medium-pore-macropore type, high adsorption, and high gas-bearing shale lithofacies. Fracturing gas tests were performed on favorable reservoirs 1 and 2, and an unimpeded flow rate of 6210 cubic meters was obtained, reaching the lower limit of industrial gas flow. The gas test results are consistent with the results of identifying favorable reservoirs by this method.

Claims

1. A method for predicting a favorable reservoir, characterized in that: A continental shale reservoir quality evaluation method was constructed with siliceous shale facies, rich in organic matter and mature organic matter maturity as the lithofacies evaluation standards, porosity above medium pores, permeability above medium permeability and micropore proportion less than 33.3% as the reservoir performance evaluation standards, and high adsorption as the gas content evaluation standard. The reservoirs that meet the continental shale reservoir quality evaluation method are favorable reservoirs.

2. The method for predicting favorable reservoirs according to claim 1, characterized in that: The petrographic evaluation criteria also include medium organic matter and over-mature organic matter maturity; the gas content evaluation criteria also include medium adsorption and high gas content.

3. The method for predicting favorable reservoirs according to claim 2, characterized in that: The parameters of the lithofacies evaluation standard include mineral composition, organic carbon content and organic matter maturity; among them, the classification standard of organic carbon content is: TOC < 1% is low organic matter, 1% ≤ TOC < 2% is medium organic matter, and TOC ≥ 2% is rich organic matter; the classification standard of organic matter maturity is: Ro < 1% is immature, 1% ≤ Ro < 2% is mature, and Ro ≥ 2% is overmature.

4. The method for predicting favorable reservoirs according to claim 2, characterized in that: The parameters of the reservoir performance evaluation standard include porosity, permeability and pore size distribution type; the porosity classification standard is: porosity <2% is low porosity, 2%≤porosity <4% is medium porosity, and porosity ≥4% is high porosity; the permeability classification standard is: permeability <0.1mD is low permeability, 0.1mD≤permeability <1mD is medium permeability, and permeability ≥1mD is high permeability; the pore size distribution type classification standard is: macropore proportion ≥50% is macroporous type, medium porosity ≥50% is macroporous type, and high porosity ≥50% is high permeability. The proportion of micropores ≥50% is mesopore type, the proportion of micropores ≥50% is micropore type, the proportion of mesopores > the proportion of macropores > 33% is macropore-mesopore type, the proportion of mesopores > the proportion of micropores > 33% is micropore-mesopore type, the proportion of micropores > the proportion of macropores > 33% is macropore-micropore type, the proportion of micropores > the proportion of mesopores > 33% is mesopore-micropore type, the proportion of macropores > the proportion of mesopores > 33% is mesopore-macropore type, the proportion of macropores > the proportion of micropores > 33% is micropore-macropore type.

5. The method for predicting favorable reservoirs according to claim 2, characterized in that: The parameters of the gas content evaluation standard include isothermal adsorption gas content and on-site analytical gas content; the classification standard of isothermal adsorption gas content is as follows: isothermal adsorption gas content <1.5% is low adsorption, 1.5%≤isothermal adsorption gas content <3% is medium adsorption, and isothermal adsorption gas content ≥3% is high adsorption; the classification standard of on-site analytical gas content is as follows: on-site analytical gas content <1.5% is low gas content, 1.5%≤on-site analytical gas content <3% is medium gas content, and on-site analytical gas content ≥3% is high gas content.

6. The method for predicting favorable reservoirs according to claim 3, characterized in that: The mineral composition is obtained through XDR mineral diffraction experimental analysis, and the specific process is: using siliceous minerals, clay minerals, and carbonate minerals as three end members to project points on the mineral triangle diagram, and dividing the siliceous shale phase, clay shale phase, dolomite shale and mixed shale phase types according to the mineral components.

7. The method for predicting favorable reservoirs according to claim 4, characterized in that: The porosity and permeability are obtained by nitrogen gas measurement.

8. The method for predicting favorable reservoirs according to claim 4, characterized in that: It also includes that pores < 2 nm are micropores, pores 2 nm ≤ < 50 nm are mesopores, and pores ≥ 50 nm are macropores.

9. The method for predicting favorable reservoirs according to claim 5, characterized in that: The on-site analyzed gas content is obtained by on-site testing of pressure-maintaining coring.

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