SY/T 5579-2000 Method for detailed description of clastic oil and gas reservoirs
Some standard content:
ICS 75.18V.99
Registration No.: 6971—2000
Petroleum and Natural Gas Industry Standard of the People's Republic of China SY/T 5579---2000
Fine description method of clastic reservoir
Fine description method of clastic reservoir2000 - 03 ~ 31 Issued
State Administration of Petroleum and Chemical Industry
2000-10-01 Implementation
SY/T 5579—2000
1 Scope
2 Reference standards
Reservoir subdivision and comparison
Reservoir occurrence
Reservoir lithology
Sedimentary facies
Reservoir physical properties
Reservoir macroscopic heterogeneity
Reservoir microscopic pore structure
Reservoir fractures·
Reservoir diagenesis-
Comprehensive evaluation and classification of reservoirs
Reservoir geological model·
Results of detailed description of clastic reservoirs
Appendix A (Appendix to the standard)
Calculation method of characteristic parameters of permeability
SY/T 55792000
Detailed description of clastic oil and gas reservoirs is an important part of geological research in the middle and late stages of clastic rock oil and gas reservoir development, and is the geological basis for formulating oil and gas condensate development adjustment plans. This standard is revised on the basis of SYT5579-93 "Description Method of Conglomerate Reservoir". After revision, this standard includes the main contents of the fine description of clastic reservoirs in the middle and late stages of development. It is not only suitable for conglomerate reservoirs, but also for other types of clastic reservoirs: the application scope is wider and the content is more comprehensive. The formulation and implementation of this standard will help to standardize the fine description of clastic oil and gas reservoirs and promote the improvement of reservoir research level. 1. This standard adds the following contents:
1) Research on sensitivity, compressibility, thermal conductivity, mechanical properties, and change laws of reservoir physical properties; 2) Intra-layer heterogeneity, semi-surface heterogeneity, and inter-layer heterogeneity in macro-heterogeneity of reservoirs; 3) Pore types and clay mineral characteristics in micro-pore structure of reservoirs; 4) Reservoir fractures;
5) Division of diagenetic stages and diagenetic phases of reservoir diagenesis; 6) Reservoir geological model.
2. This standard deletes the following contents:
1) A2 "Relative paint permeability" in Appendix A of the original standard; 2) Appendix B "Description method of reservoir throat distribution" of the original standard; 3) Appendix D "Microfacies division of alluvial fan conglomerate reservoir" of the original standard; 4) Appendix D "Comprehensive evaluation of conglomerate reservoir" of the original standard. 3. Modify the following contents:
1) Reservoir subdivision and comparison:
2) Reservoir occurrence;
3) Reservoir lithology:
4) Sedimentary facies;
S) Reservoir diagenesis;
6) Reservoir detailed description results:
7) Original Appendix A.
This standard will take effect from the date of \:, and will replace Appendix A of SY/T5579-93. This standard is the appendix of the standard.
This standard is proposed by China National Petroleum Corporation. This standard is drafted by the Oil and Gas Development Professional Standardization Committee. The drafting unit of this standard is: Institute of Geological Sciences of Shengli Petroleum Administration Bureau. The drafters of this standard are Sun Guo and Zhao Baokun.
This standard was first issued in March 1993, and this is the first revision. Scope
Petroleum and Natural Gas Industry Standard of the People's Republic of China Fine description method of clastic reservoirs
Fine description method of clastic reservoirs This standard specifies the fine description method of clastic reservoirs. This standard is applicable to the geological description of reservoirs in the middle and late stages of clastic reservoir development. 2 Referenced standards
SY/T 5S79—2000
Replaces 5Y/1 5579--93
The clauses contained in the following standards constitute the clauses of this standard by citing them in this standard. When this standard is published, all versions are valid. All standards are subject to revision. Parties using this standard should explore the possibility of using the latest version of the following standards. SY/T5368-20(H Rock thin section identification
SY/T5477-92 Specification for the division of diagenetic stages of clastic rocks 3 Reservoir subdivision and comparison
Establish principles for subdivision and comparison of clastic reservoirs, determine the comparison marker layers and comparison methods and steps, and divide reasonable subdivision and comparison units. The detailed description of the reservoirs of oil and gas reservoirs in the middle and late stages of development should be further divided into small layers to single sand bodies. 4 Reservoir occurrence
Divide the oil layer groups, sandstone groups, small layers and single sand bodies according to different blocks, and describe the top and bottom burial depths of the reservoirs, the thickness of the sand (gravel) layer, the effective thickness, the number of sand (gravel) layers, the shape of the sand (gravel) layers, and the vertical and horizontal distribution and changes 5 Reservoir lithology
5.1 Rock and mineral components||t t||5.1.1 Determine the composition and relative content of the rock skeleton, J describe the mineralogy of the rock particles, and follow the provisions of SY/I5368. S.1.2 Determine the composition and relative content of the filling material between the rock skeletons, and describe the cementation type and cementation process of the cementing material, and follow the provisions of SYT5368.
5.2 Rock structure
5.2.1 Calculate various particle size parameters (average particle size, sorting coefficient, skewness, peak state) and particle size distribution curve through particle size analysis, and describe the particle size distribution characteristics. The particle size parameter calculation formula is as follows: - xf100
Sa = /f(xx)/1on
SK = So 3. Zf(X; -x)3/100
Kr - So-4≥f(X, X)/100
Wherein: x-flat groove particle size, mm;
So——sorting coefficient;
Approved by the State Administration of Petroleum and Chemical Industry on 2000-03-31 (1)
Implemented on 2000-10-01
SK—skewness;
-peaked state;
Mass fraction, %;
-center value of particle size interval, mm
SY/T $579—2000
5.2.2 Describe the particle roundness, sphericity, surface characteristics and particle contact relationship. 5.2.3 The particle size of rock particles is expressed by "D" or "Φ" value, and the particle size classification is shown in Table 1. The "D" and "@" values are converted as follows:
@_-lug
Where: D-
Particle diameter, mI;
Particle diameter
Table 1 Particle size classification table
Extreme group sand
Coarse silt sand||t t||Fine silt sand, mud
5.3 Rock classification and naming
<0.5-1.25
<0.25--0.125
<0.125~0.0625
0.0625~0.0313
>-1-50
>1~≤2
5.3.1 The classification is based on the relative proportions of quartz, feldspar and rock fragments. The classification results are shown in Figure 1 and Table 2 Quartz,
feldspar. %
1/3 rock fragments + cloud boat, chlorite, %
I-quartz sandstone; Ⅱ-feldspar quartz sandstone; Ⅲ→lithic quartz sandstone; next feldspar sandstone; V-lithic feldspar sandstone:--feldspar lithic sandstone: cut-lithic sandstone map [sandstone classification triangle map
classification map position
quartz sandstone
SY/T 5579--2000
Table 2 Sandstone classification table
Quartz-flint
feldspar quartz sandstone
rock slick quartz sandstone
feldspar sandstone
lithic feldspar sandstone
feldspar inferior clastic sandstone
rock slick sandstone
2375- 911
275~90
5.3.2 The rock convex grain size and filling materials should be included in the naming and implemented in accordance with the provisions of SY/T5368. 6 Sedimentary phases
The sedimentary phase research in the later stage of development focuses on the study of single sand body sedimentary microfacies. 6.1 Coring and single microfacies research
Feldspar/rock sliding ratiobzxz.net
221/3 -≤1
Based on the core data of the coring well and combined with the regional sedimentary phase background, sedimentary phase markers (petrological markers, mineralogical markers, paleontological markers, geochemical markers, etc.) are established to determine the core single sedimentary microfacies, and conduct vertical sequence and sedimentary cycle analysis. 6.2 Plane micro-study
According to the correspondence between core combination and logging curve, the logging response mode of various microfacies is established, and the logging curve is used to divide the single sedimentary microfacies in the whole area; typical sections are selected to analyze the combination and evolution law of sedimentary microfacies on the section; single sand body is used as a unit to conduct plane sedimentary microfacies research, describe the distribution law of different sedimentary microfacies in space, determine the sedimentary direction, material source and paleocurrent direction, 6.3 Sedimentary microfacies model and epifacies comprehensive evaluation Establish the sedimentary microfacies model of the study area, and conduct a comprehensive evaluation of various sedimentary microfacies, and describe the relationship between sedimentary microfacies and the distribution of remaining oil.
7 Reservoir physical properties
7.1 Basis for determination of reservoir physical property parameters
The research on reservoir physical property parameters in the middle and late stages of development should be based on coring data, adopt core calibration measurement and measurement technology, use standardized logging data, establish a logging interpretation model for the main reservoir physical property parameters in the study area, and provide high-precision reservoir physical property parameters through multi-parallel measurement and interpretation. It is required that there are no less than 10 interpretation points per meter in the vertical direction. 7.2 Effective porosity
7.2.1 For fractured reservoirs, the porosity of fractures (or dissolved pores, caves) and matrix porosity should be determined. 7.2.2 For small sections with similar lithology in a single layer, when the degree of cementation is the same, the effective porosity of the lithology section can be obtained by arithmetic averaging. For small sections with the same lithology, when the degree of cementation is different, the effective porosity of the lithology section can be obtained by weighting the effective thickness of small sections with different cementation degrees:
The effective porosity of a group is obtained by weighting the effective thickness of different lithology sections in the group. 7.2, 3 If the effective porosity values of each group or the same group of groups are not large, and the distribution of points on the plane is relatively uniform, the average effective porosity of a block can be obtained by arithmetic averaging. Otherwise, it must be obtained by weighting the effective pore volume controlled by a single well. 7.2.4 Study the pore compression law of the reservoir and correct the ground porosity to the underground porosity. 7.2.5 Describe the relationship between effective porosity and reservoir lithology, determine and evaluate the lower limit of effective porosity for industrial oil flow in various rock reservoirs.
7.3 Permeability
SY/T 5579-2000
7.3.1 Select a suitable amount of representative cores for vertical permeability analysis, and determine the relationship between vertical permeability and horizontal permeability. 7.3.2 Effective permeability data is obtained by calculating the test data, describing the relationship between the permeability interpreted by well logging and the effective permeability obtained by well testing.
7.3.3 The calculation method of the average permeability of the combined, layered and lithological sections shall be implemented in accordance with 7.2.2. 7.3.4 The average permeability of a block is generally obtained by the harmonic mean method. If the distribution law of permeability is normal distribution, it can be obtained by arithmetic mean method; if it is log-normal distribution, it can be obtained by geometric mean method. The calculation method is shown in Appendix A (marked with "Appendix"). 7.3.5 Describe the relationship between permeability and porosity and lithology, and determine the lower limit of industrial oil flow permeability in the reservoir. 7.3.6 Describe the distribution law of permeability. 7.3.7 Describe the law of permeability change under formation conditions. 7.4 Oil saturation 7.4.1 Original oil saturation - generally determined by the results of survey interpretation. Large-scale gas fields should have core analysis data verification of base drilling fluid coring or closed coring in the early stage of development. The relationship between original oil saturation and lithology, porosity, and permeability should be described, and the influence of different oil content heights on saturation should be described to determine the lower limit of industrial oil flow saturation in the reservoir. 7.4.2 Residual oil saturation in the middle and late stages of development The oil saturation is provided by measurement and interpretation and detailed reservoir numerical simulation, and verified by core analysis of inspection wells in different penetration sections and production logging data, with emphasis on describing the distribution of residual oil saturation and the relationship between residual oil saturation and sedimentary facies, microstructure and reservoir heterogeneity.
7.5 Relative permeability
7.5.1 Select rock samples of representative reservoirs from key core wells for relative permeability tests and draw relative permeability curves. High-temperature relative permeability tests should be carried out for heavy oil reservoirs. 7.5.2 Determine the characteristic values of the relative permeability curve (bound water saturation, residual oil saturation, movable permeability, isotonic point water content, oil phase permeability corresponding to bound water saturation, residual oil saturation corresponding to the water phase permeability, etc.) 7.5.3 Normalize the single sample relative permeability curve to determine the relative permeability curve of each layer. 7.6 Rock Wettability
Select representative rock samples for wettability determination, and fresh rock samples should be selected as much as possible to obtain wettability data under reservoir conditions.
7.7 Sensitivity
Select representative cores to determine the sensitivity of reservoir rocks (water sensitivity, velocity sensitivity, acid sensitivity, salt sensitivity and mechanical sensitivity) and describe reservoir sensitivity. 7.8 Compressibility
Select representative cores to determine the rock elastic compression coefficient and describe rock compressibility. 7.9 Thermal Conductivity
Select representative cores to determine the thermal conductivity of rocks Thermal conductivity, thermal expansion coefficient, thermal physical properties of reservoir rock 7.10 Mechanical properties
Select representative cores to determine the mechanical properties of rocks, and determine Poisson's ratio, shear modulus, field modulus, volume modulus, rock strength, etc.
7.11 The study on the variation law of reservoir physical parameters during the development stage should be based on the core wells and logging data of different development stages, and the phase zone should be established to establish the variation law of reservoir physical parameters (porosity, permeability, mud content, median grain size, wettability, relative permeability, etc.) at different development stages. 8 Macroscopic heterogeneity of reservoir
8.1 Intra-layer heterogeneity
8.1.1 Grain size rhythm
SY/T 5579—2000
Describes the vertical change sequence of the size of the debris particles in a single sand layer. The regularity of the grain size is divided into three types: a) Positive rhythm: coarse at the bottom and gradually fine upward; b) Inverse rhythm: fine at the bottom and gradually coarse upward; r) Compound rhythm: different combinations of the two. 8,1.2 Vertical changes in sedimentary structures
Describes the vertical change laws of various bedding types (cross-bedding, wavy bedding, parallel bedding, etc.) and other sedimentary structures in a single sand layer.
8,1,3 Interlayers
Study the thickness, occurrence, distribution range, and occurrence rate and density of mud interlayers, calcareous fire layers, and low-permeability fire layers within the layer, and analyze the causes and distribution patterns of interlayers. 8.1.4 Location of the highest permeability section
Mainly describe that the highest permeability section within the layer is at the bottom of the sand layer and the middle of the foot, and analyze the relationship between the location of the highest permeability section and the rhythmicity of grain size.
8.1.5 In-layer permeability heterogeneity
Calculate the permeability variation coefficient, grade difference, single-layer breakthrough coefficient and other parameters of the single sand layer by small layers to reflect the heterogeneity of the permeability within the layer. The calculation method is shown in Appendix A (Standard Appendix). 8.1.6 Study on the ratio of vertical permeability to horizontal permeability in different layers. Changes in the ratio of vertical permeability to horizontal permeability in different layers. 8.2 Planar heterogeneity
8.2.1 Sand body geometry
Generally classified and named according to the aspect ratio and width-to-thickness ratio: a) Sheet-shaped sand body: aspect ratio close to 1:1, width-to-thickness ratio greater than 1000; b) Bean-shaped sand body: aspect ratio less than 3:1, width-to-thickness ratio greater than 100; ) Strip-shaped sand body: aspect ratio less than 3:1, width-to-thickness ratio greater than 100 Banded: length-to-width ratio greater than 3:1, width-to-thickness ratio greater than 30. 8.2.2 All-directional continuity
Description of internal penetration includes:
a) All-directional length of sand body (in);
h) Degree of control under a certain well pattern (the percentage of sand body thickness convexity encountered by two or more wells at the same time in the total thickness convexity of sand body);
d) Drilling rate, that is, the percentage of wells encountering sand body in the total number of wells; d) Width-to-thickness ratio:
e) The ratio of the actual width of sand body to the given well spacing. 8.2.3 Connectivity of sand body
8.2.3.1 Concept and type of connected body. The composite sand body formed by the mutual contact and connection of various genetic unit sand bodies in the vertical direction and plane is called "connected sand body". According to the connectivity of sand bodies, it can be divided into: a) Multilateral type: mainly connected to each other laterally; b) Multi-layer type (or superposition type): mainly connected to each other vertically; c) Isolated type: not connected to other sand bodies. 8.2.3.2 The description of connectivity includes: a) Sand body coordination number: the number of sand bodies that are in contact and connected with a sand body; b) Connectivity degree: the percentage of the area of the part of a sand body connected to another sand body to the total area of the sand body, or expressed as the percentage of the number of connected wells to the sand body control wells; d) Connected body size: refers to the total area or total width of the number of genetic unit sand bodies and connected inverse bodies included in a connected body; 8.2.4 Heterogeneity on the permeability plane within the sand body SY/T 5579-2000 8.2.4.1 Macroscopic permeability directionality: refers to the directionality caused by lithology changes in the sand body. The description includes a) the difference between the main resting zone and the marginal zone; h) the difference between the sedimentary high energy zone and the low energy zone; c) the directionality caused by the geometric shape of the sand body.
It is necessary to describe its specific directionality, expressed in azimuth. 8, 24.2 Microscopic permeability directionality: refers to the permeability directionality caused by sedimentary structure and structural factors in the sand body, that is, anisotropy, expressed as the ratio between the permeabilities of various levels.
8.2.4.3 The overall planar heterogeneity of the sand body should describe the following: a) the planar change of the coefficient of variation of well point permeability; b) the distribution frequency of areas (or well points, or volumes) with different levels of permeability; c) the degree of difference in the permeability between the injection well and each production well under the conditions of the injection and production well network. 8.3 Interlayer heterogeneity
8.3.1 Sedimentary inter-cyclicity
Sedimentary cyclicity or macroscopic sedimentary sequence is the manifestation of the regular arrangement and superposition of sand bodies and non-reservoir layers of different origins and properties, and is the sedimentary cause of interlayer heterogeneity. 8.3.2 Number of sand layers
Expressed by the average number of sand layers drilled per well (total number of sand layers drilled/statistical well). 8.3.3 Percentage of sandstone
Ratio of total sandstone thickness to total formation thickness on the vertical section: expressed as a percentage. 8.3.4 Interlayer permeability heterogeneity
Mainly describes the following contents:
a) Permeability distribution characteristics;
b) Permeability variation coefficient;
c Permeability difference:
d) Single layer breakthrough coefficient.
The calculation method shall be implemented in accordance with Appendix A (Standard Appendix). 8.3.5 Configuration relationship on the section
The configuration relationship between the main oil layer and the non-main oil layer on the section. 8.3. Interlayer and interlayer
The description content includes:
a) The lithology and physical property standards of the interlayer;
) The distribution (position) of the interlayer on the section; c) The thickness of the interlayer and its changes on the plane; d) The separation, permeability, expansion and fracture development of the interlayer. 9 Reservoir microscopic pore structure
9.1 Pore type and pore combination
9.1.1 Describe the pore type of the reservoir.
9,1,1.1 Common intergranular pores include:
a) Primary intergranular pores: There is basically no or a small amount of filling in the pores, the pore size and distribution are relatively uniform, and basically reflect the size and shape of the pores during the sedimentary period;
h) Residual intergranular pores: Primary intergranular pores remaining due to compaction and deformation of debris particles and partial filling of intergranular pores: 6
SY/r 5579-2000
c) Dissolution intergranular pores: There are three types of harbor-shaped dissolution intergranular pores, long strip-shaped dissolution intergranular pores and large dissolution pores. 9.1.1.2 Common intragranular pores include:
a) Primary intragranular pores: intragranular pores formed in the parent rock; b) Dissolution intragranular pores: pores formed by dissolution inside the particles; c) Casting mold pores: pores in which the particles are completely or almost completely dissolved and retain the original particle shape. 9.1.1.3 Common pores in filling materials include:
a) Intercrystalline pores: pores between filling mineral crystals; b) Dissolution pores in filling materials: pores formed by dissolution inside filling materials. 9.1.1.4 Common slit pores include:
a) Structural slit pores: slit pores formed by cracks cutting through debris particles, matrix, cement, etc.; 5) Diagenetic slit pores: slit pores formed by shrinkage, compaction, pressure solution, etc. during diagenesis; c) Economic slit pores: pores formed by fluid flowing along rock cracks, causing the rocks on both sides of the cracks to dissolve. 9.1.2 Describe the pore combination types of rocks. 9.1.3 Describe the composition, filling properties and filling degree of pores (primary and secondary) and fracture fillings. 9.2 Pore throat distribution characteristics
9.2.1 The pore distribution mainly describes the following contents: a) The size and variation range of various pore diameters: 5) The percentage of various pores;
c) The surface ratio and pore throat coordination number;
d) The connectivity of pores.
9.2.2 The pore throat distribution characteristics mainly describe the following contents: a) Capillary pressure curve characteristic parameters (displacement pressure and the corresponding maximum connected pore throat radius, saturation median pressure and the corresponding pore throat radius, minimum unsaturated pore volume, exit efficiency, average capillary pressure and average pore throat radius); 6) Pore throat volume ratio, permeability contribution value and the lower limit of effective pore throat radius, the percentage of pore throats at each level; c) Probability distribution characteristic parameters (mean, sorting coefficient, skewness, coefficient of variation); d) Pore limit structure coefficient.
9.3 Characteristics of reservoir clay minerals
9.3.1 Analyze the composition and distribution of clay minerals. Statistic the clay mineral content, composition and self-content of each component according to the different blocks, sub-layers, sand formations and Shan formations, study the changes of clay minerals in the vertical and horizontal directions, 9.3.2 Analyze the occurrence of clay minerals. Describe the crystal structure of clay minerals and their distribution on the pore wall, particle surface and intergranular pore throat.
9.3.3 Analyze the influence of various types of clay minerals on the reservoir pore structure and evaluate their sensitivity. 9.3.4 Analyze the change rules of clay minerals and pore structure in reservoirs at different development stages. 10 Reservoir fractures
10.1 Classification of fracture genesis
Classify natural fractures (gasket fractures, interlayer fractures, weathering fractures, dissolution fractures, etc.) and artificial fractures (roof fractures, drilling induced fractures, etc.) of different genesis
10.2 Fracture occurrence
Describe the distribution form, distribution density, inclination, dip angle, strike, width and length of the fractures. 10.3 Fracture opening degree
Describe the fracture filling material, filling and opening degree, and whether it becomes an effective storage and seepage space. 10.4 Relationship between ground stress field and fracture
SY/T 5579-200U
Determine the size and direction of the block's ground stress field, and find out its relationship with natural fractures and artificial fractures. 10.5 Fracture distribution law
Study the relationship between fracture distribution and stratum, lithology and structural position, and describe the fracture distribution law. 10.6 The opening and closing rules of fractures
Analyze the opening and closing rules of fractures at different opening stages. 11 Reservoir diagenesis
11.1 Diagenesis and post-diagenesis
Based on the various analysis and identification results of the core, determine the main diagenesis and post-diagenesis experienced by the research object, and describe the transformation effect of each diagenetic event on the pore structure. Common diagenetic and post-diagenetic effects of clastic rocks include: mechanical pressure sinus action, chemical pressure solution cementation, dissolution, metasomatism, recrystallization, etc. Determine the order of occurrence of each diagenetic event in the geological history. 11.2 Diagenesis stage division
Based on the characteristics of various diagenetic minerals in the reservoir, the combination of clay minerals, the transformation of clay minerals in the illite/montmorillonite mixed layer, rock structure, organic matter maturity, paleotemperature and other indicators, determine the diagenetic stage. Specifically, the provisions of SY/T5477 shall be followed. 11.3 Diagenetic phases
For reservoirs with a large impact of post-diagenetic effects, diagenetic phase analysis shall be conducted. The diagenetic phases shall be named based on the sedimentary microfacies and diagenetic products, and the diagenetic phase plane and profile diagrams shall be compiled to directly characterize the reservoir characteristics. 12 Comprehensive evaluation and classification of reservoirs
12.1 Comprehensively compare the various parameters of the reservoirs described in detail in this standard. Determine the comprehensive evaluation and classification indicators of reservoirs. General parameters include: reserve size, oil sand body area, effective thickness, sand body drilling rate, permeability, effective porosity, shale content, cementation content, pore structure parameters, intra-layer heterogeneity parameters, etc. 12.2 Take small layers, sand layer groups or: · Fixed development strata as units, and classify and evaluate reservoirs according to different purposes based on comprehensive evaluation indicators. 12.3 Comprehensively determine the main small layer flow unit based on the dynamic and static description results, and describe the characteristics of different flow units. 13 Reservoir geological model
13.1 Types of reservoir geological models
13.1.1 According to the model type, it can be divided into single-parallel model, profile model and Lanwei model. 13.1.2 According to different development stages, it can be divided into conceptual model, static model and prediction model. The prediction model is generated by the fine description of reservoirs in the middle and late stages of development.
13.2 Steps of Jianwen reservoir geological model
13.2.1 According to the density of data points in different development stages, select the grid step size of different types of reservoir geological models. 13.2.2 According to the depth, geometric shape and connectivity and continuity of sand bodies, establish a three-dimensional spatial distribution skeleton model of sand bodies.
13.2.3 Based on the numerical values of the parallel points, the reservoir parameters of the well grid are predicted by using deterministic modeling or random modeling methods to establish a three-dimensional reservoir parameter model. 14 Results of fine description of clastic reservoirs
14.1 Text report.
14.2 The following figures should be attached to the report:
a) Reservoir subdivision and comparison description maps: typical cross-section maps of oil layer subdivision, small layer comparison map, etc.; h) Reservoir occurrence description maps: reservoir isopach maps, effective thickness contour maps, small layer plane maps, etc.; c) Sedimentary facies description maps: standard microfacies columnar maps, microfacies plane maps, sedimentary facies model maps, etc.: SY/I 5579—2000
d) Reservoir physical property description maps: effective porosity contour maps, permeability contour maps, original oil saturation contour maps, residual oil saturation contour maps, etc.;
e) Reservoir macroscopic heterogeneity description maps: interlayer plane maps, light layer plane maps, permeability variation coefficient plane contour maps, etc.; f) Typical curves of indoor experimental parameters: pore distribution and capillary pressure curves, relative permeability curves, sensitivity curves, etc.; g) Other maps: comprehensive oil layer condition map, etc. 14.3 The following data tables should be attached to the report:
a) Basic data table: drilling flaw statistics table, analysis and testing items self-statistics table, formation stratification data table, small layer number table, oil layer thickness statistics table, etc.;
b) Analysis and testing results table: rock and mineral statistics table, particle size statistics table, physical property statistics table, clay mineral statistics table, pore structure characteristic parameter statistics table, reservoir sensitivity statistics table, etc.; ) Comprehensive research results table: intra-layer permeability heterogeneity parameter table, inter-layer permeability heterogeneity parameter table, interlayer data table, layer data table, reservoir comprehensive evaluation data table, etc. 14.4 Reservoir parameter database and reservoir geological model three-dimensional data body. 9
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