SY/T 5601-1993 Geological evaluation methods for natural gas reservoirs
Some standard content:
SY/T5601—93 Petroleum and Natural Gas Industry Standard of the People's Republic of China
Geological Evaluation Methods of Natural Gas Reservoirs
Published on September 9, 1993
China National Petroleum Corporation
Implementation on March 1, 1994
1 Subject Content and Scope of Application
Petroleum and Natural Gas Industry Standard of the People's Republic of China Geological Evaluation Methods of Natural Gas Reservoirs
This standard specifies the geological evaluation methods of natural gas reservoirs. SY/T 5601—93
This standard is applicable to the geological evaluation of organic gas deposits in the exploration stage, and is also applicable to the prediction of the possibility of natural gas formation in unknown areas and the size of its scale.
2 Reference Standards
GBn270 Natural Gas Reserves Specification
3 Concept and Evaluation Unit of Natural Gas Reservoirs
A natural gas reservoir refers to a collection of natural gas with a unified pressure system and a unified gas-water or gas-oil interface in a single enclosure. Including pure gas reservoirs, oilfield gas cap gas reservoirs, condensate gas reservoirs, and water-soluble gas reservoirs. Gas reservoirs are the basic units of evaluation. For multi-fracture chain system gas reservoirs or fault block gas reservoirs, when the scale of a single fracture system or fault block is very small and the relationship between them is complicated, they can be evaluated as a gas reservoir in the same structure. 4 Evaluation of geological conditions for the formation of natural gas
The formation and scale of natural gas reservoirs are controlled by regional geological conditions, mainly depending on the conditions of gas source layer, gas reservoir, cap rock, closure, migration, accumulation and preservation and their mutual configuration relationship. In the evaluation, we should make full use of seismic, logging, comprehensive recording, testing and various analysis data to make single and comprehensive evaluations:
4.1 Evaluation of regional geological characteristics
Including the nature of the basin, the location of the regional structure, regional structure, faults, magmatic activity, accumulation characteristics and development history, hydrogeological conditions
4.2 Evaluation of gas source layer
4.2.1 Determine the gas source layer, use the composition of natural gas components and the carbon and hydrogen isotopes of methane and methane homologues, carbon and hydrogen isotopes of carbon dixenide, carbon and hydrogen isotopes of adsorbed gas, geochemical characteristics of condensate oil, biomarkers and carbon isotopes of source rock and reservoir asphalt extract group components, and use relevant comparison charts or regression equations to determine the gas source layer and the genetic type of natural gas. For multi-source gas, determine the main gas source layer and the desired gas source layer. 4.2.2 Determine the age of the gas source layer, sedimentary phase, lithology, density, distribution area, organic matter abundance, parent material type, thermal maturity and its changes, and make contour maps or zoning category maps respectively. 4.2.3 Calculate the gas generation intensity (gas generation per unit area), and make a contour map of gas generation intensity. The calculation formula for gas generation intensity is: DH.pC.Rg
Where: D——gas generation intensity, 10m*/km2, H--effective gas generation rock thickness, km;
Approved by China National Petroleum Corporation on September 9, 1993*)
Implemented on March 1, 1994
β-gas generation rock density, 10\t/km
C-residual organic carbon in gas generation rock. Decimal;
R--residual organic carbon recovery coefficient;
g-unit organic carbon gas production rate, m\/t. SY/T5601—93
Regarding the determination of parameter values in the formula, the effective gas-generating rock standard shall be temporarily treated with reference to the oil-generating rock standard, and its thickness (H) shall be taken according to actual data: the density of gas-generating rock (β) shall be taken according to the measured data in the area as much as possible: the residual organic carbon (C) shall be taken according to the actual analysis data: the recovery coefficient of residual organic carbon (R), when no better method is obtained, can be taken with reference to Figure 1, the maturity range of type I parent material from low to high is 1~3.4, type I is 11.8, type I is 1~1.2, and type I is 1~1.2; the gas production rate (g) shall be taken according to the results of thermal simulation test of gas-generating rocks in this area (if it is an immature gas-generating layer, it shall be taken according to the results of biogas simulation experiment). When the data in this area is used, the experimental data of the same type of parent material in areas with similar geological conditions can be borrowed.
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Figure 1 Curve of residual organic carbon recovery coefficient of source rock
Depth (m)
58? Tmax(芒)
4.2.4 According to the thermal evolution history of the gas-generating rock, the main generation period of natural gas shall be determined. When there is a clear break in the thermal evolution process of the gas-generating rock, the secondary gas generation process of the gas-generating rock shall be studied to determine the highest evolution degree in the first gas generation process and the increase in the thermal evolution degree in the secondary gas generation process. The secondary gas generation intensity can also be calculated separately and the secondary gas generation intensity contour map can be compiled. 4.3 Gas reservoir evaluation
4.3.1 Age, lithology, mineral composition, grain size, structure, cementing material composition and cementing type of gas reservoir. 4.3.2 Reservoir space type, pore radius, pore throat ratio, capillary pressure curve characteristics; development of reservoir fractures, fracture density and occurrence: development of dissolved pores and caves, filling material composition and filling degree. 4.3.3 Total thickness, single layer thickness and effective thickness of gas reservoir. To determine the effective thickness and lower limit standard, it is necessary to study the various physical parameters and pore structure of the reservoir and other basic factors controlling the flow of gas and water, based on core analysis data, based on single layer test results and widely apply the quantitative interpretation results of logging data. The occurrence of gas reservoir is described in terms of block, thick layer, lens, thin layer, interlayer, etc. Prepare contour maps of total gas reservoir thickness and main gas reservoir thickness. 4.3.4 Porosity and permeability values of gas reservoir and their vertical and horizontal changes. Prepare porosity and permeability contour maps. 4.3.5 Gas reservoir classification and level determination:
4. The classification of sandstone gas reservoirs is shown in Table 1. According to the cross-combination of the porosity and permeability data listed in the table, gas reservoirs of high porosity and low permeability, medium porosity and low permeability, etc. can also be classified. b. The classification of carbonate gas reservoirs is shown in Table 2. Similar to sandstone gas reservoirs, gas reservoirs of high porosity and low permeability, medium porosity and low permeability, etc. can also be classified. 2
Gas reservoir level
Extra-low ionization
Energy ionization level
Extra-low ionization
SY/T 5601--93
Table 1 Classification of sandstone gas reservoirs
Posity, %
<15～10
Gas reservoir level
Extra-low permeability
Classification of carbonate gas reservoirs
Porosity, %
12～4
Gas reservoir level
Extra-low permeability
4.3.6 Analysis of sedimentary facies belts, gas reservoir rock types and morphology, diagenesis and secondary changes. Permeability, 10-8μm
500~10
Permeability, 10-\um
100~10
10~0,1
4.4 Blue layer evaluation
Caprocks are divided into direct caprocks and regional caprocks. The former refers to the rock formation that directly seals the formation of gas reservoirs: the latter refers to the natural gas caprock distributed in a large area.
The sealing capacity of the caprock is related to lithology, rock physical properties (porosity and permeability), thickness, burial depth, formation pressure, hydrocarbon concentration, etc. It should be studied by multi-factor analysis.
4.4.1 The sealing capacity of the direct caprock of the gas reservoir is mainly determined by the breakthrough pressure of the caprock rock (P) and the residual pressure of the gas reservoir (Ap,). P can be directly measured in the experiment, and can be calculated by formula. As long as A and P are met, the caprock has the ability to seal gas.
Reservoir residual pressure meter formula:
AH,-h'p.-w*g
Formula APt
Reservoir residual pressure, MPu;
-Gas column height of gas, m
Gas-water density difference, g/cm;
-Gravity acceleration, cm/s.
The critical gas column height that can be sealed can also be calculated by the following formula based on the difference between the capillary pressure (breakthrough pressure PA) value of the cap layer and the capillary median pressure (P) of the reservoir. he: pa Pk.
In the formula: h\-critical gas column height, m;-breakthrough pressure of the cap layer, MPa:
Pr-reservoir pressure, MPa:
-Gas-water density difference, &/cm\
9-Gravity acceleration, cm/s.
SY/T 5601--93
4.4.2 Regional caprock mainly evaluates the preservation conditions of natural gas from a macroscopic perspective, including whether the regional caprock has been formed before the main generation period of natural gas, the age of the regional caprock, lithology, thickness and regional changes, and the degree of damage caused by faults. 4.5 Map closure evaluation
4.5.1. Trap type: For anticline traps, the trap area, height, major axis, minor axis and the occurrence of the two wings should be described. For non-anticline traps, in addition to describing the trap shape and scale, the main closing factors of formation should be explained, such as reservoir pinch-out, lithology change, etc. 4.5.2 Trap development history and the main formation period of the trap. 4.5.3 Fault situation: nature, direction and number of faults, location, occurrence, length and fault distance of the trap where the main faults are located, fault development history, analysis of the lithology of the two sides of the fault and the opening or closure of the fault. 4.6 Comprehensive evaluation
Based on the above-mentioned single evaluation of natural gas reservoirs, the migration and accumulation of natural gas should be comprehensively analyzed from the aspects of natural gas generation history, trap development history and reservoir diagenetic change history. 4.6.1 According to the parent material type, latitude and thermal evolution history and hydrocarbon generation model, the main generation period, migration phase and period of natural gas are analyzed by digital simulation method.
4.6.2 Analyze the main pathways and directions of natural gas migration through the study of regional structure, sedimentation, local trap development characteristics, paleo-hydrogeology and fluid potential. Pay special attention to the role of sedimentary discontinuities, faults and cracks in natural gas migration. .4.6.3 Analyze the late transformation and preservation of gas reservoirs through the study of structural changes, fault activities, hydrodynamics and groundwater chemical properties.
4.6.4 Comprehensively analyze the mutual configuration relationship of various formation conditions, determine the period of natural gas accumulation, case type and establish the accumulation model.
4.7 Types and naming of natural gas reservoirs
4.7.1 According to the classification scheme in Table 3, use the trap type, reservoir characteristics and fluid properties for comprehensive classification and naming. The name is mainly based on the trap, and one or two other elements are added. For example, a gas reservoir is named as ××× extrusion anticline porous carbonate gas reservoir, or ××× fault anticline condensate gas reservoir, etc.
4.7.2 Condensate gas is divided into five levels according to the condensate content, gas-oil ratio and Cs+ content in natural gas, see Table 4.5 Gas reserve evaluation
5.1 Basic parameters of gas reservoirs
5.1.1 Gas reservoir closure area and closure degree, closure top elevation, gas-bearing area and elevation, gas reservoir filling coefficient, gas-water or gas-oil interface elevation.
5.1.2 Original formation temperature, pressure and pressure coefficient at the middle depth of the gas reservoir. See Table 5 for the classification of gas reservoir pressure.5.1.3 Gas, oil and water properties in gas reservoirs: Natural gas properties include hydrocarbon components, non-hydrocarbon (H, S, CO,) and rare gas (He, Ar, etc.) white content, natural gas density, condensate content, etc. Crude oil properties include density, viscosity, wax content, sulfur content, freezing point, filling content, etc.; water properties include ion content, mineralization, water type, water gas saturation, etc.
Comprehensive classification table of natural gas reservoirs
Squeezing anticline closure
Reverse traction anticline trap
Pyrite anticline closure
Syngenetic sedimentary anticline trap
Plastic pool arching anticline trap
Hidden piercing syngenetic anticline closure
Reservoir characteristics
Carbonate bi
Pyroclastic or
Metamorphic rock
Porosity| |tt||Fracture
Fracture-porosity
Porosity-fracture
Gas occurrence
Gas cap gas
Gas layer gas
Condensate gas
Water-floating gas
Structural plasticity
Non-fusible gas
Wet-break type
Rock-controlled type
Ground wing type
Hydrodynamic type
Complex type!
Extra-high content
High content
Medium content
Fault anticline closure
Fault circle
Fault block trap
Collection layer pinch-out trap
Reservoir compensation lens closure
Organic reef agent
Unconformity surface soil stratum trap
Subconformity stratum closure
Structural-lithological closure
Structural-stratigraphic trap
Stratigraphic-lithological trap
SY/T560T—93
Bedding characteristics
Carbonate rock
Igneous rock
Metamorphic rock
Porosity
Fracture
Vugs Property
Fracture-porosity
Pore-fracture property
Table 4 Classification of condensate oil content in condensate gas reservoirs Condensate oil content
cm\/m3
750350
350~150
150~50
Hydrogen-oil ratio
m°/ms
1330-2860
2860~6670
>6670~20000
Table 4 Pressure coefficient and classification of natural gas reservoirs
Pressure coefficient
<1.1~0.96
4.0.96~0,75
5,1.4 The original maximum and average daily production of gas, oil and water of a single well in a gas reservoir. Industrial gas well lower limit GBn270 Chapter 8.
5,15 Gas reservoir drive types, including edge water, bottom water, water drive, elastic drive, etc. 5,2 Gas barrier reserve calculation
Calculate the reserves of gas barrier according to the requirements and methods in CBn270. Gas production
Gas pre-gas
Gas layer gas
Condensate gas
Water-soluble gas
Cs+ content
≤.5.0~2.5
Reservoir pressure classification
Ultra-low pressure
6 Gas field reservoir abundance and scale
6.1 Gas field reserve abundance
SY/T 5601-93
The reserve abundance of gas fields is divided into three levels: high, medium and low according to GBn270: high abundance
low abundance
6.2 Gas field reserve scale
10\m\/km\
10°m/km*
10°m\/km2
The reserve scale of gas fields is divided into three levels: large, medium and small according to GBn270. Large gas fields
Medium gas fields
Small gas fields
300~50
10°m?
10°m2
6.3 The gas lift production is determined according to the natural gas production and standards of 8, 2, 1 kilometers in depth in GBn270. 7 Preparation of Geological Evaluation Report of Natural Gas Reservoir
7.1 The geological evaluation report of gas reservoir is prepared based on gas use. For gas fields composed of multiple gas structures, the main gas reservoirs to which the gas fields belong can be described separately when necessary.
7.2 Contents of the report
7.2.1 Overview of the gas field, including the regional structural position, geographical location, discovery time and discovery wells, and a brief exploration history of the gas field. 7.2.2 Comparison and evaluation of gas sources.
7.2.3 Characteristics and evaluation of gas reservoirs.
7,2,4 Trap conditions.
7.2.5 Evaluation of caprock and reservoir-caprock combination.
7,2.6 Migration, accumulation and comprehensive evaluation of gas reservoir shape. 7,2 Industrial evaluation of gas reservoirs, including gas reservoir type, stratum, gas-bearing area and height, gas layer thickness, testing and production capacity, oil, gas, water properties and distribution overview, and reserve calculation and evaluation. 7.2.8 Technical and economic evaluation of gas reservoirs.
7.3 Appendixes and tables
Unified requirements for the report: Attached are the comprehensive map of the gas field, the basic data table of the natural gas reservoir, and the basic data table of natural gas analysis. The specifications are shown in Figure 2, Table 6, and Table 7 respectively.
Table B Basic data of natural gas reservoirs
Gas use ()
Gas-bearing positions
Middle buried depth, m
Gas-bearing area, km2
Gas-bearing height, m
Filling degree, weak
Number of completed drillings
Average well depth, m
Number of test gas wells
Number of gas-obtained wells
Initial production, 10+m/d
(m :h-www.bzxz.net
SY/T 5601--93
Figure 2 Gas field comprehensive map
Ranjia bird
Pulse/min
8901200
ixngn2c0
Fukoumen
Feijiasong formation
Changxinghu
Guoge system
Bottom 1 Dianyang
Direct benefit layer
Regional cover tunnel
Original formation pressure,
ground overflow,
area. km2
density, m
original density, m
pore type
porosity. %
Permeability, 10-
Gas saturation, crying
Lithology and parent material type
Reduced maturity, R, %
Sitting gas potential, 108m/hm
Thickness, m
Thickness, m
Date of filling in the form:
SY/T 5601-93
Controlled reserves, 10\m
Proven reserves.10°m3
Person filling in the form:
Filling well depth/layer
Gas testing period
Gas testing opening section/layer
Porosity. mm
set, MPa
oil pressure, MPa
gas oxygen production, m^/d
oil production load, t/
water production, m=/d
auditor;
SY/T 5601-—93
Dho-!*H+Qi?h'Q
additional instructions
SY/T 5601—93
This standard is proposed by China National Petroleum Corporation. This standard is under the technical supervision of the Petroleum Geological Exploration Professional Standardization Committee. This standard is also organized and drafted by the Institute of Geology, Petroleum Exploration and Development Research Institute, China National Petroleum Corporation. The drafters of this standard are Jianhoufa, Kong Zhiping, Zhentan, Li Yiping, and Hong Feng.
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