SY/T 5386-2000 Rules for calculation of proved petroleum reserves - Fractured oil and gas reservoirs
Some standard content:
ICS 75.180.99
Registration No.: 8145—2001
Petroleum and Natural Gas Industry Standard of the People's Republic of ChinaSY/T 5386—2000
The regulations of proved reserves calculation of petroleumThe part of fractured oil and gas reservoir2000-12-25Promulgated
State Administration of Petroleum and Chemical Industry
2001 —06 - 01 Implementation
SY/T 5386-2000
Cited standards
Requirements for calculation of reserves of fractured oil and gas reservoirsObjective
Types of reservoir spaces and classification of reservoir types of fractured oil and gas reservoirsClassification of fractured oil and gas zones
Reserve classification and interim reporting conditions for geological reserves of each levelVolumetric calculation of geological reserves of oil and gas
Volumetric calculation of geological reserves of condensate gas reservoirs
9Estimation methods for recovery factor in the drilling stage and early development stage10Dynamic calculation methods for recoverable reserves of continental gas in the middle and late stages of development11
Reserve evaluation...
12 Requirements for preparation of reserve reports
Appendix A (Standard Appendix)
Appendix (Standard Appendix)
Appendix ((Standard Appendix)
Appendix D (Standard Appendix)
Parameter symbols and codes
Inflammation types of reservoir spaces in fractured oil and gas reservoirs and classification of reservoir types Relationship diagram between pseudo-critical pressure, pseudo-critical temperature and relative density of natural gas Deviation coefficient diagram for determining natural gas
SY/I5386—2000
Fractured oil and gas reservoirs are one of the important oil and gas reservoir types in my country, distributed in various areas of the country. Their reservoir rocks include carbonate rocks, igneous rocks, metamorphic rocks, argillaceous rocks and cemented dense clastic rocks. Their reservoir layers There are multiple reservoir space types such as fractures, holes and pores, and multiple reservoir types are formed by the combination of holes and holes. This type of oil and gas reservoir has the seepage characteristics of dual-porosity media, which is different from the clastic rock oil and gas reservoir with general porosity media: According to the characteristics of fractured oil and gas reservoirs, the reserve calculation, reserve parameter determination and recovery rate prediction methods should be standardized. With the continuous discovery and investment of fractured oil and gas reservoirs in my country and the application of new technologies and methods, certain experience has been accumulated in reserve calculation and recovery rate prediction. The original SY/T5386- 91 Some parts of the "Detailed Rules for Reserve Calculation of Fractured Oil and Gas Reservoirs" cannot meet the requirements of reserve calculation, and the original standard should be revised and supplemented as necessary. According to the spirit of the second annual meeting of the third oilfield development geological sub-standard committee in May 1999, the revised standard reorganized the relevant contents of the original standard and made necessary revisions and supplements to the technical requirements. In view of the characteristics of fractured oil and gas reservoirs, this standard adds supporting measurement series, core observation and research, and types of reservoir space in fractured oil and gas reservoirs. The content includes the classification of oil and gas geological reserves, the relevant formulas for calculating oil and gas geological reserves by volumetric method, the method for obtaining the main reserve parameters, the method for calculating the geological reserves of condensate gas reservoirs by volumetric method and the relevant formulas, as well as the methods for calculating oil and gas geological reserves, recovery rate and recoverable reserves according to different stages of exploration and development. At the same time, relevant industry standards such as oil and gas reservoir classification and oil reserve calculation method are also cited. The appendix A, appendix B, appendix C and appendix D of this standard are all standard appendices. This standard is effective and replaces SY/T5386-91. This standard is proposed by China National Petroleum Corporation: This standard is organized by the Oil and Gas Development Professional Standardization Committee. The drafting unit of this standard: Exploration and Development Research Institute of North China Oilfield Branch of China National Petroleum Corporation. The drafters of this standard are Zhu Yadong and Zhang Guojie. This standard was issued in 1991 and is revised for the first time. 1 Scope
Petroleum and Natural Gas Industry Standard of the People's Republic of China Rules for Calculation of Proved Reserves of Petroleum
Fractured Oil and Gas Reservoirs Part
The regulations of proved reserves calculation of petroleum
The part of fractured oil and gas reservoirSY/T 5386—2000
Replaces SY/T5386—91
This standard specifies the types of reservoir space, reservoir types, reserve classification, determination of reserve parameters and calculation methods of geological reserves and recoverable reserves of fractured oil and gas reservoirs.
This standard is applicable to the calculation of geological reserves and recoverable reserves of petroleum and natural gas in fractured oil and gas reservoirs. 2 Referenced Standards
The provisions contained in the following standards constitute the provisions of this standard by reference in this standard. When this standard is published, the versions shown are valid. All standards will be revised. The party using this standard should explore the possibility of using the latest version of the following standards: GBn269-88 Petroleum Reserves Specification
GBm27)-88 Natural Gas Reserves Specification
SY/T5367-1998 Calculation Method of Recoverable Petroleum ReservesSY/T6098-2000 Calculation Method of Recoverable Natural Gas ReservesSY/F6101-94 Technical Requirements for Determination of Phase Characteristics of Condensate Gas ReservoirsSY/T G109-94 Petroleum and Natural Gas Reserves Report Diagrams and TablesSY/T6168-1995 Gas Reservoir Classification
SY/T6169-1995 Oil Reservoir Classification
SY/T 6313.1—1998 Method for determining gas-water interface SY/F6313.2—1998 Method for determining oil-gas-water interface Gas-water interface 3 Requirements for storage calculation of fractured oil and gas reservoirs 3.1 Select different reserve calculation methods according to the characteristics of fractured oil and gas reservoirs Fractured oil and gas are complex oil and gas reservoirs. According to the geological characteristics, complexity and exploration and development stage of oil and gas combustion types, appropriate methods should be selected to determine reserve parameters and calculate reserves. 3.1.1 Select different methods to determine reserve parameters according to different reservoir space types of oil and gas reservoirs Fractured oil and gas reservoirs are complex reservoirs. Their geological laws should be carefully studied, the types and distribution characteristics of reservoir space should be identified, and the volumes of fractures, caves and pores should be determined. According to the different reservoir space types of gas reservoirs, appropriate methods should be selected to determine reserve parameters and calculate reserves.
3.1.2 According to the geological conditions and available data, more than two methods should be used to calculate reserves, and comparative verification should be carried out. 3.1.3 After the natural gas is put into development, the reserves should be verified regularly using multiple methods according to different development stages. 3.2 Fractured oil and gas reservoirs must use advanced matching logging series. For fractured oil and gas reservoirs of different lithologies, four comprehensive matching logging series, including lithology-porosity, resistivity, fracture-imaging and nuclear magnetic resonance, should be selected.
Approved by the State Administration of Petroleum and Chemical Industry on 2000-1225 and implemented on 2001-06-01
3.2.1 Lithology-porosity logging series
SY/T5386-2000
The lithology-porosity logging series includes: natural gamma logging (GR), dual parallel diameter logging (△CAL), lithology density logging (Pe), natural potential logging (Sp), formation density logging (FDC), neutron gamma logging (NG), dual source distance compensated neutron logging (CNL), and long source distance sonic logging (SBH).
3.2.2 Resistivity logging series
The resistivity logging series includes: dual lateral resistivity logging (DLL), micro-spherical focused logging (MFSC, dual induction resistivity logging (ILD, ILM).
3.2.3 Fracture-imaging logging series
The fracture-imaging logging series mainly includes: high-resolution formation dip logging (HDT), fracture identification (FIL), conductivity anomaly (DCA) and formation dip (DIP) processing: micro-conductivity scanning logging (FMS), downhole acoustic television Well logging (BHTV), digital acoustic circumferential well imaging logging (CBIL).
3.2.4 Nuclear magnetic logging
Use nuclear magnetic logging to measure the saturation of bound water in the matrix pores of the rock system. 3.3 Observation and study of fractured oil and gas reservoir cores
3.3.1 Macroscopic study of cores
It mainly includes observation and study of oil and gas occurrence in cores: classification statistics of fracture development conditions (fracture aperture, density, extension length and direction, group division, mechanical properties); statistics of effective fractures and pore surface ratios. 3.3.2 Microscopic study of cores
It mainly includes sampling the cores to make cast thin sections, determine their rock type, rock structure, mineral composition, and microscopic reservoir space type; use image analyzers to determine the surface ratios of small fractures, microcracks, and matrix pores, and use fluorescent thin sections, electron microscope scanning, and other methods to observe the oil content of the matrix and fractures.
3.3.3 Others
Carry out directional coring and core nuclear magnetic resonance research work 4 Types of reservoir space in fractured oil and gas reservoirs and classification of reservoir types For the types of reservoir space in fractured oil and gas reservoirs and classification of reservoir types, please refer to Appendix B (Appendix to the standard). 5 Classification of fractured oil and gas reservoirs
5.1 Classification of oil and gas reservoirs
The classification method should comply with the provisions of SY/T6168 and SY/T6169. 5.2 Methods for distinguishing oil and gas reservoir types
The methods for distinguishing fractured oil and gas reservoirs shall comply with the provisions of Appendix A of SY/T6101--94 on reserve classification and declaration conditions for geological reserves of each level6
6.1 Classification of reserves
Oil and gas reserves can be divided into three levels: predicted reserves, controlled reserves and proved reserves. 6.2 Proved reserves
According to the degree and complexity of exploration and development, they are divided into developed proved reserves, undeveloped proved reserves and basic proved reserves. 6.2.1 Developed proved reserves
Developed proved reserves refer to the reserves that have been put into production through the implementation of development plans, development drilling and construction of development facilities, and under modern technical and economic conditions.
6.2.1.1 Application conditions for developed proven reserves The development well network has been drilled, and a 1:10000 oil and gas layer top surface structural map compiled by combining seismic and drilling data has been submitted; the wells drilled have been logged in accordance with the regulations of SY/T5386-2000, and the reserve calculation parameters have been interpreted; water testing, pressure measurement, and production calculation have been carried out at the edge and bottom water parts of the oil and gas reservoir, and the energy of the edge and bottom water has been understood; the dynamic data of oil, gas, water production, formation pressure, temperature, etc. have been obtained; the analytical experimental data required to determine the recovery rate (oil displacement efficiency, wettability, relative permeability, etc.) have been obtained. 6.2.1.2 The degree of geological understanding of developed proven reserves The structural morphology of the oil and gas reservoir, fault distribution, oil, gas, and water distribution law, oil and gas reservoir type, fracture and hole distribution characteristics, reservoir physical properties, fluid properties, drive type, pressure system and oil and gas layer production capacity, etc. have been clearly understood, and the reserve parameters are reliable. 6.2.2 Undeveloped proved reserves
Undeveloped proved reserves refer to the reserves calculated after the evaluation drilling has been completed, a few development wells have been drilled, the oil and gas reservoirs have been described in detail, and reliable reserve parameters have been obtained. The relative error shall not exceed ±20%. 6.2.3 Basic proved reserves
Basic proved reserves refer to the basic proved reserves that can be calculated as the basis for "rolling exploration and development" after the high-resolution seismic exploration has been completed, the oil and gas reservoirs have been described in detail, and the evaluation wells have been drilled. The reserve calculation parameters are basically obtained, and the oil and gas-bearing area is basically controlled. In view of the complexity of fractured oil and gas reservoirs, the requirements for proved reserves cannot be met under the current exploration conditions, but the reserve parameters can be further implemented through rolling exploration and development. The relative error of basic proved reserves should be less than ±30%. 6.2.3.1 Application conditions for undeveloped proved reserves and basic proved reserves: High-resolution seismic has been conducted, and a detailed description of the oil and gas reservoir has been made. A 1:10,000 or 1:25,000 oil and gas layer top surface structural map has been submitted; the appraisal well has been drilled, and the main oil and gas layer has at least one complete core section; the coring footage of the oil and gas layer section is not less than 30% of the cumulative thickness of the oil and gas layer; a logging series suitable for the geological characteristics of the oil and gas reservoir and the identification of fractures, holes, layers and lithology has been determined, and the oil, gas and water layers ( The conformity rate is above 85%), the porosity of fracture and hole sections, oil and gas saturation, effective thickness and other parameters; the oil and gas layer production capacity, pressure and temperature data have been obtained; the evaluation wells with very long sections and many layers have been tested in sections, and a certain number of single-layer test oil (gas) data and unstable single well test data are available: the reservoir core physical property parameter analysis data have been obtained, including large (small) diameter core physical properties, mercury injection and other analysis data: the oil, gas, water properties and high-pressure physical property analysis data have been obtained. 6.2.3.2 The degree of geological understanding of undeveloped proven reserves and basically proven reserves The closure conditions are clear, and the distribution of structural highs and major faults has been explored; the oil and gas reservoir types and the distribution characteristics of oil, gas and water have been identified; the oil and gas bearing area has been basically controlled; the reservoir types of oil and gas reservoirs, the general distribution characteristics of fractures and holes and the facies changes have been basically understood: the reserve parameters are basically reliable; the oil and gas well production capacity fluid properties and driving types are basically understood. 7 Calculation of oil and gas geological reserves by volumetric method
7.1 Basic formula for calculating oil and gas geological reserves by volumetric method [see formula (1) to formula (4)] N=100A.H(1-Swi)p/Ba
G=0.01A,H(1-Sw)
GR=GER
7.2 Formula for calculating oil and gas geological reserves in fracture system fracture-cavity pores by volumetric method [see formula (5) and formula (6)] N=100A. Hpra(1-Swfa)p/Bt
G=0.01A.Hpa(1-Swid)
7.3 Formula for calculating oil and gas geological reserves in rock system matrix pores by volumetric method [see formula (7) and formula (8)] Nm=100A. Hpm(1-Swm）p/Bi
SY/T 5386—2000
Gu= 0.01A,H9m(1 -Sum)p
7.4 Formula for calculating total oil and gas geological reserves by product method [see formula (9) and formula (10)NN-Nm
G=GrtGm
7.5 Delineation of oil and gas bearing area
7.5.1 Delineation of developed proven reserve area The developed proven reserve area shall be delineated comprehensively according to the type of oil and gas reservoir and in combination with the state and static data of production wells. 7.5.2 Delineation of undeveloped proven reserve area and basic proven reserve area. (8)
--(10)
a) Delineate the oil-bearing boundary according to the drilling, coring, logging interpretation and test data, and shall be verified by stratified oil and gas test data. b) The boundaries of oil and gas should be delineated according to different types of oil and gas reservoirs. c) The boundaries of oil and gas should be delineated according to the data of the edge detection test. 7.5.3 Delineation of the area of different types of oil and gas reservoirs a) Fault-blocked oil and gas reservoirs: The blocked part is delineated by the fault boundary or the trace line in the section, and the open part is delineated by the actual oil-water interface
b) Layered water and massive bottom water oil and gas reservoirs: Delineated by the interface between the edge and bottom water interface and the structural contour line. c) Oil and gas reservoirs controlled by paleo-weathering erosion surface and unconformity surface: Delineated by the boundary where the edge and bottom water interface intersect with the weathering and erosion line and unconformity line
d) Lithology pinch-out oil and gas reservoirs: Delineated by the lithology pinch-out line and the actual oil-water interface, e) Fracture-enclosed oil and gas reservoirs: Delineated according to the distribution boundary of the fracture system. 7.5.4 Method for determining gas-oil-water interface 7.5.4.1 Using logging data to determine oil-water or gas-water interface In the case of less coring and layered test data, the oil-water or gas-water interface can be roughly determined by using cuttings logging and oil display of gas logging. Usually, when drilling into pure oil-bearing zones, the oil-bearing cuttings have a high self-separation ratio, and when entering pure gas-bearing zones, the gas logging value is abnormally high: after entering the oil (gas)-water transition zone, the oil-bearing cuttings decrease, and the gas logging display weakens or disappears. 7.5.4.2 Using formation testing methods to determine oil-water and gas-water interfaces Based on the pressure data measured by formation repeat testing (RFT or FMT) and drill pipe F test (LDST), a pressure-depth relationship diagram is drawn. Since the pressure gradients of oil, gas and water layers are significantly different, the oil-gas, oil-water or gas-water interface can be determined by the intersection of the repulsive gradient lines.
7.5.4.3 Application of double porosity overlap method to determine oil-water interface The essence of effective porosity method is that total porosity reflects the total pore volume including oil-bearing and water-bearing pores, while water-bearing porosity only reflects the pore volume containing water in the ground. Total porosity is obtained by adding one-density, and water-bearing porosity is calculated by Archie's formula using the resistivity curve of the depth side. After the two porosity curves overlap, the difference between total porosity and water-bearing porosity is the oil-bearing porosity. There is no difference between the two porosity curves after single stacking, which reflects water layer or dense layer: the method of using this method to determine the oil-water interface is simple and self-explanatory, but due to factors such as lithology, pore structure, resistivity, and mismatch of density detection range, its application is subject to certain restrictions. 7.5.4.4. The deep and shallow lateral resistivity overlap method is used to judge the oil-water interface. The deep and shallow lateral test pieces are used for different purposes to detect the formation. The horizontal water content change is used to reflect the hernial content of the formation and the oil-water change during the development process: when the drilling resistivity is greater than the formation water resistivity, the deep side resistivity is greater than the shallow side resistivity, that is, the positive amplitude difference is the oil layer; on the contrary, the negative difference is the water layer: when there is no difference between the deep and shallow resistivity, the high resistivity is the dense layer, and the low resistivity and natural gamma are the mud layer. This method of judging the oil-water interface is less affected by lithology, pore structure, etc., but is more affected by the invasion of filter slurry. 7.5.4.5 Determine the gas-oil and gas-water interface by the re-logging method of the shock wave-Φ-Zishan curve. The hydrogen content in the gas layer increases, and the gamma value and the acoustic time difference value increase in different directions. The lines 4
SYT 5386-20H
are overlapped in sequence according to the water layer, mud layer, and dense layer. The gas-oil or gas-water interface can be determined by the size of the amplitude difference. .5.4.6 Determine the gas-oil interface by neutron gamma time lapse logging. The open hole logging before the completion and the logging after the casing are solidified and the secondary neutron gamma logging curves are overlapped and compared. The neutron gamma curve value in the gas layer is significantly increased.
7.5.4.7 Determine the fracture system and rock system by using deep lateral resistivity time shift logging. The oil:water interface is in the pure oil section, and the oil saturation remains unchanged, and the time lapse curves overlap. In the process of continuous water drive oil production, the time-lapse curve gradually decreases with the decrease of oil saturation in the fracture system and the rock block system. The boundary depth between the overlap section and the descending section of the time-lapse curve is the oil-water interface of the fracture system. Below the oil-water interface of the rock block system, the formation is all water-containing, the time-lapse curve coincides, and the boundary depth between the descending section and the overlap section of the time-lapse curve is the oil-water interface of the rock block system. Therefore, this method can monitor the differences and changes in the drainage interface of the fracture system and the rock block system during the development of oil and gas reservoirs. 7.5.4.8 Using core analysis and logging interpretation data to determine the gas-oil-water interface This method should comply with the provisions of SY/T6313.1 and SY/T6313.2. 7.5.4.9 Comprehensive analysis and judgment of the gas-oil-water interface Using test, recording and logging data, combined with Shantou (gas) reservoir profile comprehensive analysis and comparison to determine the gas-oil-water boundary. 7.6 Effective Thickness Determination Method
7.6.1 Determination of the Boundary between Reservoir and Non-Reservoir Due to the heterogeneity of fractures and pore spaces in fractured oil and gas reservoirs, as well as the special conditions of oil and gas accumulation and percolation, it is necessary to comprehensively study the lithology, physical properties, electrical properties, oil (gas) content, and distribution characteristics of fractures and pores of the reservoirs, and formulate a classification standard suitable for fractured reservoirs in the region in combination with the specific conditions of gas reservoirs in each region. 7.6.1.1 Observation of Gas Content of Cores to Classify Reservoirs and Non-Reservoir Cores The occurrence of gas content of cores is divided into six levels: saturated gas content, gas content, oil invasion, oil spot, oil trace, and fluorescence. For carbonate reservoirs, the amount of mud content directly affects the storage degree and oil content of the reservoir space. The relationship between mud content and oil content can be formulated. Figure 7.6.1.2 Physical and electrical property standards for classifying reservoirs. When the rock physical properties are low to a certain level, it does not have the storage and permeability capacity and can be classified as a reservoir (excluding pure fractured oil and gas reservoirs). Therefore, by analyzing the relationship between oil and gas and no oil and gas, the physical property boundary can be found as the lower limit standard for classifying reservoirs. Combined with the survey data, the relationship between oil content, oil content, fracture and pore development and electrical properties is analyzed to formulate the electrical property standards for determining reservoirs. 7.6.2 Classification and evaluation of reservoirs
7.6,2.1 Classification and evaluation based on reservoir physical properties
Based on the effective porosity and permeability of the reservoirs, the reservoirs are divided into 5 categories (see Table 1). 1 Classification of effective porosity and permeability of fractured oil and gas reservoirs Effective porosity
Extremely high porosity: extremely high permeability
High porosity, medium permeability
Medium porosity, medium permeability
Low porosity, low permeability
Extremely low porosity, extremely low permeability
Clastic rock
25≤30
-15 -<25
a t0~<15
了.折.2.2 Classification and evaluation according to the degree of reservoir fracture development and production capacity Non-clastic
Silver According to the degree of reservoir fracture development and production capacity, the reservoirs are divided into 4 categories (览衣2) Air permeability
10-3ar
2500 --<100
a:50 ~≤500
210 ~≤50
I. High-yield reservoir
Ⅱ, medium-yield reservoir
Ⅲ. Low-yield reservoir
IV. Extra-low-yield reservoir
SY/T5386—2000
Table 2 Fracture-cavity development degree and production capacity of fractured oil and gas reservoirs Classification Well depth in kilometers Stable daily production
Fracture-cavity development degree
Fracture-cavity development
Fracture-cavity development is relatively developed
Fracture-cavity development is poor
Fracture-cavity development is undeveloped
m2/ (km*d)
In industrial oil and gas wells, the thickness of Class II, III reservoirs is the effective thickness for calculating reserves. 7.6.3 Effective thickness value
On the basis of determining the effective thickness of a single well, try to use the area trade-off method to determine the effective thickness of the oil and gas reservoir. Gas reservoir
10°m2/(km*d)
≥3~<10
≥1~<3
For undeveloped fractured complex small fault block oil and gas reservoirs, there are only 1-2 exploration wells or evaluation wells. The value of effective thickness should take into account the structural position of the oil and gas and the position of the fracture development zone. On the basis of determining the effective thickness of a single well, the effective thickness should be converted according to a certain ratio. The effective porosity is taken as the effective thickness value of the oil and gas reservoir.
7.7 Determination of effective porosity
7.7.1 Porosity types of fractured oil and gas reservoirs According to the ability of drilling, logging and electrical measurement to resolve the size of the reservoir space, the effective porosity of the fractured oil and gas reservoir is decomposed into the fracture-vug porosity of large fracture systems, the fracture-vug porosity of small and medium-sized fracture systems and the matrix porosity of the rock system. For a specific fractured oil and gas reservoir, it can have one or more porosity combinations. 7.7.2 Determination of fracture-vug porosity of large fracture systems The fracture-vug porosity of large fracture systems refers to the ratio of the pore volume of the large macroscopic fracture network system to the reservoir volume. Large fracture system The porosity of fractures and caves calculated by logging methods has a large error. The drilling tool emptying or abnormal well diameter expansion (the well diameter curve shows a steep increase, with a relative amplitude of more than 1 cm) and the drilling fluid leakage data (the leakage volume is more than hundreds of cubic meters) are used to estimate the drilling cave rate (H). The average drilling cave rate (H-) represents the fracture and cave porosity of large fracture systems in oil and gas reservoirs. The calculation is shown in formula (11):
ZHe+ZH+ZHk
（11）
The cumulative drilling fluid leakage well section length (H) and the cumulative well diameter abnormal expansion length. The cumulative drilling tool emptying length (Hs) and (Hk) of the same well section are only calculated once.
7.7.3 Rock block system Determination of matrix porosity The porosity of conventional reservoir core samples is analyzed, and its average value represents the matrix porosity of the rock system; the sonic logging porosity of the rock system () approximately represents the effective matrix porosity of the rock system (); the porosity of full-diameter core samples of the reservoir is analyzed, and its average value represents the sum of the matrix porosity of the rock system and the porosity of some small fracture systems. 7.7.4 Determination of fracture-vuggy porosity of small and medium-sized fracture systems The fracture-vuggy porosity of small and medium-sized fracture systems refers to the ratio of the pore volume of the small and medium-sized fracture network system to the reservoir volume. Reservoirs with small and medium-sized fracture systems generally do not have the phenomenon of drilling tool emptying and abnormal well diameter expansion, but only small leakage or seepage of drilling fluid. The logging method is used to calculate their porosity.
Use deep lateral and shallow lateral resistivity methods to calculate the porosity, see formula (12): 中=mt
（12）
Use secondary porosity method to calculate the porosity, see formula (13): SY/T5386-2000
r=中-mt
（13)
Use density method, neutron gamma method or neutron-density intersection method to calculate the total porosity of the reservoir and the total porosity of the rock block system in the reservoir (Φmt), and the difference between the two is the fracture-cavity porosity (Φ) of the small fracture system in the reservoir. The secondary porosity method is only applicable to fractured oil reservoirs with high-angle fracture systems in carbonate rocks, low-permeability clastic rocks, and mudstones. 7.7.5 Using the pressure recovery curve and numerical simulation method to obtain the effective porosity of the reservoir Using the representative measured pressure recovery curve, fitting is performed to obtain the fitting parameters such as the oil (gas) well oil (gas) supply radius, oil (gas) layer thickness, fracture porosity, rock block porosity, fracture permeability, and flow test coefficient. Numerical simulation is used to perform historical fitting to obtain various parameters. The above method is used to finally obtain the oil (gas) supply radius and the effective porosity within the percolation range. 7.7.6 Selection of effective porosity of reservoirs
According to the above methods for calculating various types of porosity, the thickness weighting method is used to calculate the average porosity of small and medium-sized fracture systems and rock systems in a single well. The area weighting method is used to calculate the average porosity of small and medium-sized fracture systems () and the average porosity of acoustic logging of rock systems (3). Then, effective porosity values are calculated according to different reservoir types. The effective porosity of a reservoir is the sum of the porosities of various types of reservoir spaces. The porosity calculation formula is as follows. a) The effective porosity of the composite reservoir with large fractures and caves is calculated as shown in formula (14): (14)
b) The reservoir with small fractures and caves includes fracture type, pore (or cave)-fracture type, fracture-pore (or cave) type and quasi-pore type reservoir. The effective porosity is calculated as shown in formula (15): 0=+
c) The effective porosity of igneous rock pore (or cave)-fracture type and fracture-pore (or cave) type reservoir with pore structure is calculated as shown in formula (16): where +
wherein is the percentage of oil (gas) pore hole surface area ratio in the total pore hole surface area ratio of the core observed and statistically calculated. 7.8 Determination of Oil and Gas Saturation
7.8.1 Oil and Gas Saturation of Fracture System Void Pores: (16)
For oil and gas reservoirs with developed fractures, the oil and gas saturation in the fracture system voids is selected to be 0.9-1.0 based on the results of indoor tests and the reservoir type.
7.8.2 Oil and Gas Saturation of Matrix Pores in Rock Block System The oil and gas saturation in the matrix pores of the rock block system is usually obtained by measuring the bound water saturation by coring with oil-based (or sealed) drilling fluid: it is obtained by using the capillary pressure curve; a relationship chart between the oil and gas saturation measured by core measurement and the oil and gas saturation interpreted by logging is prepared, and a correlation formula between porosity (or permeability) and oil and gas saturation is established to obtain the oil and gas saturation. 7.8.3 Correction of oil and gas saturation in pores of igneous rock blocks with pore structures Igneous rocks with pore structures do not contain oil and gas because some isolated pores are not connected to the fracture system and must be corrected. The correction saturation (S, S) formulas are shown in equations (17) and (18): Sh = Sua/n
Sm = Sm/n
7.8.4 Gas saturation of gas cap in oil reservoir
The bound oil saturation should be subtracted from the gas saturation in the gas cap of the oil reservoir. 7.9 Other parameters
(17)
Surface crude oil density, formation crude oil volume coefficient, original formation pressure, and gas layer temperature should comply with the provisions of GBn269 and GBn270.
7.10 Deviation coefficient of original gas in gas reservoir
7.10,1 Pseudo-critical pressure and pseudo-critical temperatureSY/T 5386—2000
According to the gas composition, the pseudo-critical pressure (P) and pseudo-critical temperature (T) of the mixture are determined by using formula (19) and formula (20). Pjx
Formula (19) and formula (20) are the sum of all components contained in natural gas, (19)
(20)
In the early stage of gas exploration, in the absence of gas composition data, the gas pseudo-critical pressure (P) and pseudo-critical temperature (T) can also be obtained by referring to the relevant plates [Figure CI in the Appendix of the Standard] according to the relative density of natural gas (), and necessary corrections are made for the components containing H, S, C2:N2 [Appendix C (Appendix of the Standard) Figure (2), 7.10.2 Calculation of quasi-relative pressure (pr) and quasi-relative temperature (T) Ppr
·(22)
Use the two parameters of quasi-relative pressure () and quasi-relative temperature (T) to refer to the relevant plate_Appendix D (Standard Appendix) in Figure D1] to obtain the original gas deviation coefficient (Z,), 7.11 Division of reserve calculation unit
Fractured oil and gas reservoirs have a variety of reservoir types. The division of reserve calculation units mainly considers the differences in reservoir type and storage and permeability. , oil (gas) and water combination relationship and geological structure characteristics, when calculating proven reserves, it is necessary to calculate reserves by block, layer group, reservoir type, and oil (gas) and water system. If there are several sets of fracture systems that are not connected to each other, it is also necessary to calculate the reserves by fracture system. 8 Volumetric method for calculating geological reserves of condensate gas reservoirs
8.1 Calculation method
Under the original formation conditions, condensate gas exists in the reservoir as a single gas, so the geological reserves of condensate gas reservoirs are still calculated using formula (6), formula (8), and formula (10), but the original gas The determination of the deviation coefficient should take into account the influence of the components of condensate gas and total produced fluid (including condensate oil and natural gas).
8.2 Deviation coefficient of original gas in condensate gas reservoir
8.2.1 Determination of relative density of co-current fluid Based on the relative density of natural gas produced by condensate gas well (), the relative density of condensate oil (), and the gas production ratio (GOR) of condensate gas well, the relative density of total produced fluid (w) is determined. The calculation formula is shown in formula (23) and formula (24): Y
GORY++ 830Y.
240567
M — 44.297/(1.03 - .)
8.2.2 Obtaining the pseudo-critical pressure and pseudo-critical temperature (23)
After determining the relative density () of the total fluid produced from the riser, refer to the relevant plate [Figure CI in Appendix C (Appendix to the standard)] to obtain the pseudo-critical pressure and pseudo-critical temperature T. After correction, refer to Figure (2) in Appendix C (Appendix to the standard), and then use formula (21) and formula (22) to calculate the pseudo-relative pressure Pe- and pseudo-relative temperature Tr. Refer to the relevant plate [Figure D11 in Appendix D (Appendix to the standard) to obtain the original gas deviation coefficient 2, value. 8.3 Calculation of the original geological reserves of natural gas and condensate in condensate gas reservoirs 8
8.3.1 Calculation of natural gas geological reserves
SY/T 5386—2000
The molar fraction f of natural gas in the total fluid produced by condensate gas. Calculated by formula (25): fu =
Original geological reserves G of natural gas. Calculated by formula (26) and formula (27): G.= Gfg
GRC = GERG
8.3.2 Calculation of geological reserves of condensate oil
Original geological reserves of condensate oil in condensate gas reservoir (N,) Calculated by formula (28) and formula (29): N. = 104G/GOR
Nrc = NERc
9 Estimation method of recovery factor in drilling stage and initial development stage 9.1 Estimation method of recovery factor of oil and gas reservoir
The method of determining the recovery factor of oil and gas reservoir shall comply with the provisions of SY/T5367 and SY/T6098. 9.2 Estimation of Recovery Factor of Condensate Gas Reservoirs
9.2.1 Determination of Total Recovery Factor of Condensate Gas Reservoirs
Use the empirical statistical value method and geological analogy method to determine the total recovery factor (E) of condensate gas reservoirs. 9.2.2 Estimation of Condensate Oil Recovery Factor in Condensate Gas Reservoirs The estimation of condensate oil recovery factor in condensate gas reservoirs is calculated by formula (30): F-rc = 0.9367) 027GOR02508(5.625×10-2T + 1)0. 0084(1-076 Note: The unit of formation temperature T in the formula is t:: 9.2.3 Estimation of Natural Gas Recovery Factor in Condensate Gas Reservoirs The estimation of natural gas recovery factor in condensate gas reservoirs is calculated by formula (31): ER-Enc(1 10 Methods for calculating recoverable reserves of oil and gas by concurrent mid- and late-stage dynamic methods. The calculation should comply with the provisions of SY/T5367 and SY/T6098: 11 Reserve evaluation 11.1 Reserve feasibility evaluation (29) After the calculation of oil and gas reservoir reserves is completed, analyze the completeness and accuracy of various parameters to see whether they meet the requirements of this level of reserves; analyze the methods for determining reserve parameters and the accuracy of various charts; analyze whether the calculation and selection of reserve parameters are reasonable, and conduct comparative verification of several calculation methods: analyze the geological research work of the oil and gas reservoir to determine whether it meets the requirements of this level of reserves. 11.2 Comprehensive evaluation of reserves 11.2.1 Classification of production capacity a) According to the stable daily production of kilometers deep, the production capacity of oil and gas reservoirs is divided into 4 categories (see Table 3)1 Capacity Size Classification
a) Based on the stable daily production per kilometer and depth, the capacity of oil and gas reservoirs is divided into 4 categories (see Table 3)1 Capacity Size Classification
a) Based on the stable daily production per kilometer and depth, the capacity of oil and gas reservoirs is divided into 4 categories (see Table 3)2 Oil and gas saturation of the matrix pores of the rock block system The oil and gas saturation in the matrix pores of the rock block system is usually obtained by measuring the bound water saturation by coring with oil-based (or closed) drilling fluid: It is obtained by using the capillary pressure curve; a relationship chart between the oil and gas saturation measured by core and the oil and gas saturation interpreted by logging is developed, and a correlation formula between porosity (or permeability) and oil and gas saturation is established to obtain the oil and gas saturation. 7.8.3 Correction of oil and gas saturation in the pores of the rock block system of igneous rocks with pore structures Igneous rocks with pore structures do not contain oil and gas because some isolated pores are not connected to the fracture system, so they must be corrected. The corrected saturation (S, S) formulas are shown in equations (17) and (18): Sh = Sua/n
Sm = Sm/n
7.8.4 Gas saturation of the gas cap of the reservoir
The bound oil saturation should be subtracted from the gas saturation in the gas cap of the reservoir. 7.9 Other parameters
（17）
Surface crude oil density, formation crude oil volume coefficient, original formation pressure, gas layer temperature shall comply with the provisions of GBn269 and GBn270.
7.10 Original gas deviation coefficient of gas reservoir
7.10,1 Pseudo-critical pressure and pseudo-critical temperatureSY/T 5386—2000
According to the gas composition, use formula (19) and formula (20) to determine the pseudo-critical pressure (P) and pseudo-critical temperature (T) of the mixture. Pjx
Formula (19) and formula (20) are the sum of all components contained in natural gas. (19)
(20)
In the early stage of exploration, when there is a lack of gas composition data, the gas pseudo-critical pressure (P) and pseudo-critical temperature (T) can be obtained according to the relative density (%) of natural gas by referring to the relevant plate [Figure CI in the Standard Appendix], and necessary corrections can be made for the components containing H, S, C2:N2 [Appendix C (Standard Appendix) Figure (2), 7.10.2 Calculation of quasi-relative pressure (pr) and quasi-relative temperature (T) Ppr
·(22)
Use the two parameters of quasi-relative pressure () and quasi-relative temperature (T) to refer to the relevant plate_Appendix D (Standard Appendix) in Figure D1] to obtain the original gas deviation coefficient (Z,), 7.11 Division of reserve calculation unit
Fractured oil and gas reservoirs have a variety of reservoir types. The division of reserve calculation units mainly considers the differences in reservoir type and storage and permeability. , oil (gas) and water combination relationship and geological structure characteristics, when calculating proven reserves, it is necessary to calculate reserves by block, layer group, reservoir type, and oil (gas) and water system. If there are several sets of fracture systems that are not connected to each other, it is also necessary to calculate the reserves by fracture system. 8 Volumetric method for calculating geological reserves of condensate gas reservoirs
8.1 Calculation method
Under the original formation conditions, condensate gas exists in the reservoir as a single gas, so the geological reserves of condensate gas reservoirs are still calculated using formula (6), formula (8), and formula (10), but the original gas The determination of the deviation coefficient should take into account the influence of the components of condensate gas and total produced fluid (including condensate oil and natural gas).
8.2 Deviation coefficient of original gas in condensate gas reservoir
8.2.1 Determination of relative density of co-current fluid Based on the relative density of natural gas produced by condensate gas well (), the relative density of condensate oil (), and the gas production ratio (GOR) of condensate gas well, the relative density of total produced fluid (w) is determined. The calculation formula is shown in formula (23) and formula (24): Y
GORY++ 830Y.
240567
M — 44.297/(1.03 - .)
8.2.2 Obtaining the pseudo-critical pressure and pseudo-critical temperature (23)
After determining the relative density () of the total fluid produced from the riser, refer to the relevant plate [Figure CI in Appendix C (Appendix to the standard)] to obtain the pseudo-critical pressure and pseudo-critical temperature T. After correction, refer to Figure (2) in Appendix C (Appendix to the standard), and then use formula (21) and formula (22) to calculate the pseudo-relative pressure Pe- and pseudo-relative temperature Tr. Refer to the relevant plate [Figure D11 in Appendix D (Appendix to the standard) to obtain the original gas deviation coefficient 2, value. 8.3 Calculation of the original geological reserves of natural gas and condensate in condensate gas reservoirs 8
8.3.1 Calculation of natural gas geological reserves
SY/T 5386—2000
The molar fraction f of natural gas in the total fluid produced by condensate gas. Calculated by formula (25): fu =
Original geological reserves G of natural gas. Calculated by formula (26) and formula (27): G.= Gfg
GRC = GERG
8.3.2 Calculation of geological reserves of condensate oil
Original geological reserves of condensate oil in condensate gas reservoir (N,) Calculated by formula (28) and formula (29): N. = 104G/GOR
Nrc = NERc
9 Estimation method of recovery factor in drilling stage and initial development stage 9.1 Estimation method of recovery factor of oil and gas reservoir
The method of determining the recovery factor of oil and gas reservoir shall comply with the provisions of SY/T5367 and SY/T6098. 9.2 Estimation of Recovery Factor of Condensate Gas Reservoirs
9.2.1 Determination of Total Recovery Factor of Condensate Gas Reservoirs
Use the empirical statistical value method and geological analogy method to determine the total recovery factor (E) of condensate gas reservoirs. 9.2.2 Estimation of Condensate Oil Recovery Factor in Condensate Gas Reservoirs The estimation of condensate oil recovery factor in condensate gas reservoirs is calculated by formula (30): F-rc = 0.9367) 027GOR02508(5.625×10-2T + 1)0. 0084(1-076 Note: The unit of formation temperature T in the formula is t:: 9.2.3 Estimation of Natural Gas Recovery Factor in Condensate Gas Reservoirs The estimation of natural gas recovery factor in condensate gas reservoirs is calculated by formula (31): ER-Enc(1 10 Methods for calculating recoverable reserves of oil and gas by concurrent mid- and late-stage dynamic methods. The calculation should comply with the provisions of SY/T5367 and SY/T6098: 11 Reserve evaluation 11.1 Reserve feasibility evaluation (29) After the calculation of oil and gas reservoir reserves is completed, analyze the completeness and accuracy of various parameters to see whether they meet the requirements of this level of reserves; analyze the methods for determining reserve parameters and the accuracy of various charts; analyze whether the calculation and selection of reserve parameters are reasonable, and conduct comparative verification of several calculation methods: analyze the geological research work of the oil and gas reservoir to determine whether it meets the requirements of this level of reserves. 11.2 Comprehensive evaluation of reserves 11.2.1 Classification of production capacity a) According to the stable daily production of kilometers deep, the production capacity of oil and gas reservoirs is divided into 4 categories (see Table 3)2 Oil and gas saturation of the matrix pores of the rock block system The oil and gas saturation in the matrix pores of the rock block system is usually obtained by measuring the bound water saturation by coring with oil-based (or closed) drilling fluid: It is obtained by using the capillary pressure curve; a relationship chart between the oil and gas saturation measured by core and the oil and gas saturation interpreted by logging is developed, and a correlation formula between porosity (or permeability) and oil and gas saturation is established to obtain the oil and gas saturation. 7.8.3 Correction of oil and gas saturation in the pores of the rock block system of igneous rocks with pore structures Igneous rocks with pore structures do not contain oil and gas because some isolated pores are not connected to the fracture system, so they must be corrected. The corrected saturation (S, S) formulas are shown in equations (17) and (18): Sh = Sua/n
Sm = Sm/n
7.8.4 Gas saturation of the gas cap of the reservoir
The bound oil saturation should be subtracted from the gas saturation in the gas cap of the reservoir. 7.9 Other parameters
（17）
Surface crude oil density, formation crude oil volume coefficient, original formation pressure, gas layer temperature shall comply with the provisions of GBn269 and GBn270.
7.10 Original gas deviation coefficient of gas reservoir
7.10,1 Pseudo-critical pressure and pseudo-critical temperatureSY/T 5386—2000
According to the gas composition, use formula (19) and formula (20) to determine the pseudo-critical pressure (P) and pseudo-critical temperature (T) of the mixture. Pjx
Formula (19) and formula (20) are the sum of all components contained in natural gas. (19)
(20)
In the early stage of exploration, when there is a lack of gas composition data, the gas pseudo-critical pressure (P) and pseudo-critical temperature (T) can be obtained according to the relative density (%) of natural gas by referring to the relevant plate [Figure CI in the Standard Appendix], and necessary corrections can be made for the components containing H, S, C2:N2 [Appendix C (Standard Appendix) Figure (2), 7.10.2 Calculation of quasi-relative pressure (pr) and quasi-relative temperature (T) Ppr
·(22)
Use the two parameters of quasi-relative pressure () and quasi-relative temperature (T) to refer to the relevant plate_Appendix D (Standard Appendix) in Figure D1] to obtain the original gas deviation coefficient (Z,), 7.11 Division of reserve calculation unit
Fractured oil and gas reservoirs have a variety of reservoir types. The division of reserve calculation units mainly considers the differences in reservoir type and storage and permeability. , oil (gas) and water combination relationship and geological structure characteristics, when calculating proven reserves, it is necessary to calculate reserves by block, layer group, reservoir type, and oil (gas) and water system. If there are several sets of fracture systems that are not connected to each other, it is also necessary to calculate the reserves by fracture system. 8 Volumetric method for calculating geological reserves of condensate gas reservoirs
8.1 Calculation method
Under the original formation conditions, condensate gas exists in the reservoir as a single gas, so the geological reserves of condensate gas reservoirs are still calculated using formula (6), formula (8), and formula (10), but the original gas The determination of the deviation coefficient should take into account the influence of the components of condensate gas and total produced fluid (including condensate oil and natural gas).
8.2 Deviation coefficient of original gas in condensate gas reservoir
8.2.1 Determination of relative density of co-current fluid Based on the relative density of natural gas produced by condensate gas well (), the relative density of condensate oil (), and the gas production ratio (GOR) of condensate gas well, the relative density of total produced fluid (w) is determined. The calculation formula is shown in formula (23) and formula (24): Y
GORY++ 830Y.
240567
M — 44.297/(1.03 - .)
8.2.2 Obtaining the pseudo-critical pressure and pseudo-critical temperature (23)
After determining the relative density () of the total fluid produced from the riser, refer to the relevant plate [Figure CI in Appendix C (Appendix to the standard)] to obtain the pseudo-critical pressure and pseudo-critical temperature T. After correction, refer to Figure (2) in Appendix C (Appendix to the standard), and then use formula (21) and formula (22) to calculate the pseudo-relative pressure Pe- and pseudo-relative temperature Tr. Refer to the relevant plate [Figure D11 in Appendix D (Appendix to the standard) to obtain the original gas deviation coefficient 2, value. 8.3 Calculation of the original geological reserves of natural gas and condensate in condensate gas reservoirs 8
8.3.1 Calculation of natural gas geological reserves
SY/T 5386—2000
The molar fraction f of natural gas in the total fluid produced by condensate gas. Calculated by formula (25): fu =
Original geological reserves G of natural gas. Calculated by formula (26) and formula (27): G.= Gfg
GRC = GERG
8.3.2 Calculation of geological reserves of condensate oil
Original geological reserves of condensate oil in condensate gas reservoir (N,) Calculated by formula (28) and formula (29): N. = 104G/GOR
Nrc = NERc
9 Estimation method of recovery factor in drilling stage and initial development stage 9.1 Estimation method of recovery factor of oil and gas reservoir
The method of determining the recovery factor of oil and gas reservoir shall comply with the provisions of SY/T5367 and SY/T6098. 9.2 Estimation of Recovery Factor of Condensate Gas Reservoirs
9.2.1 Determination of Total Recovery Factor of Condensate Gas Reservoirs
Use the empirical statistical value method and geological analogy method to determine the total recovery factor (E) of condensate gas reservoirs. 9.2.2 Estimation of Condensate Oil Recovery Factor in Condensate Gas Reservoirs The estimation of condensate oil recovery factor in condensate gas reservoirs is calculated by formula (30): F-rc = 0.9367) 027GOR02508(5.625×10-2T + 1)0. 0084(1-076 Note: The unit of formation temperature T in the formula is t:: 9.2.3 Estimation of Natural Gas Recovery Factor in Condensate Gas Reservoirs The estimation of natural gas recovery factor in condensate gas reservoirs is calculated by formula (31): ER-Enc(1 10 Methods for calculating recoverable reserves of oil and gas by concurrent mid- and late-stage dynamic methods. The calculation should comply with the provisions of SY/T5367 and SY/T6098: 11 Reserve evaluation 11.1 Reserve feasibility evaluation (29) After the calculation of oil and gas reservoir reserves is completed, analyze the completeness and accuracy of various parameters to see whether they meet the requirements of this level of reserves; analyze the methods for determining reserve parameters and the accuracy of various charts; analyze whether the calculation and selection of reserve parameters are reasonable, and conduct comparative verification of several calculation methods: analyze the geological research work of the oil and gas reservoir to determine whether it meets the requirements of this level of reserves. 11.2 Comprehensive evaluation of reserves 11.2.1 Classification of production capacity a) According to the stable daily production of kilometers deep, the production capacity of oil and gas reservoirs is divided into 4 categories (see Table 3)11 Division of reserve calculation units
Fractured oil and gas reservoirs have various reservoir types. The division of reserve calculation units mainly considers the differences in reservoir types and storage and permeability, the oil (gas) and water combination relationship and geological structure characteristics. When calculating proven reserves, it is necessary to calculate reserves by block, layer group, reservoir type and oil (gas) and water system. If there are several sets of fracture systems that are not interconnected, it is also necessary to calculate the reserves of each fracture system. 8 Calculation of geological reserves of condensate gas reservoirs by volumetric method
8.1 Calculation method
Under the original formation conditions, condensate gas exists in the reservoir as a single gas. Therefore, the geological reserves of condensate gas reservoirs are still calculated using formulas (6), (8), and (10). However, the determination of the original gas deviation coefficient should take into account the influence of the components of condensate gas and total produced fluid (including condensate oil and natural gas).
8.2 Original gas deviation coefficient of condensate gas reservoir
8.2.1 Determination of relative density of concurrent fluids According to the relative density of natural gas produced by condensate gas wells (W), the relative density of condensate oil (W) and the gas production ratio (GOR) of condensate gas wells, the relative density of total produced fluids (W) is determined. The calculation formula is shown in formulas (23) and (24): Y
GORY++ 830Y.
240567
M — 44.297/(1.03 - .)
8.2.2 Obtaining the pseudo-critical pressure and pseudo-critical temperature (23)
After determining the relative density () of the total fluid produced from the riser, refer to the relevant plate [Figure CI in Appendix C (Appendix to the standard)] to obtain the pseudo-critical pressure and pseudo-critical temperature T. After correction, refer to Figure (2) in Appendix C (Appendix to the standard), and then use formula (21) and formula (22) to calculate the pseudo-relative pressure Pe- and pseudo-relative temperature Tr. Refer to the relevant plate [Figure D11 in Appendix D (Appendix to the standard) to obtain the original gas deviation coefficient 2, value. 8.3 Calculation of the original geological reserves of natural gas and condensate in condensate gas reservoirs 8
8.3.1 Calculation of natural gas geological reserves
SY/T 5386—2000
The molar fraction f of natural gas in the total fluid produced by condensate gas. Calculated from formula (25): fu =
Original geological reserves of natural gas G. Calculated from formula (26) and formula (27): G.= Gfg
GRC = GERG
8.3.2 Calculation of geological reserves of condensate oil
Original geological reserves of condensate oil in condensate gas reservoir (N,) Calculated from formula (28) and formula (29): N. = 104G/GOR
Nrc = NERc
9 Estimation method for recovery factor in the drilling stage and initial development stage 9.1 Estimation method for oil and gas reservoir recovery factor
The method for determining oil and gas reservoir recovery factor shall comply with the provisions of SY/T5367 and SY/T6098. 9.2 Estimation method for recovery factor of condensate gas reservoir
9.2.1 Determination of total recovery factor of condensate gas reservoir
The total recovery factor (E) of condensate gas reservoir shall be determined by empirical statistical value method and geological analogy method. 9.2.2 Estimation method for condensate oil recovery factor in condensate gas reservoir The estimation method for condensate oil recovery factor in condensate gas reservoir is calculated by formula (30): F-rc = 0.9367) 027GOR02508(5.625×10-2T + 1)0. 0084(1-076 Note: In the formula, the formation temperature T The unit is t: 9.2.3 Estimation method of natural gas recovery rate in condensate gas reservoir Estimation method of natural gas recovery rate in condensate gas reservoir Shan formula (31) calculation: ER- Enc (1 10 Methods for calculating recoverable reserves of oil and gas by concurrent mid- and late-stage dynamic methods. The calculation should comply with the provisions of SY/T5367 and SY/T6098: 11 Reserve evaluation 11.1 Reserve feasibility evaluation (29) After the calculation of oil and gas reservoir reserves is completed, analyze the completeness and accuracy of various parameters to see whether they meet the requirements of this level of reserves; analyze the methods for determining reserve parameters and the accuracy of various charts; analyze whether the calculation and selection of reserve parameters are reasonable, and conduct comparative verification of several calculation methods: analyze the geological research work of the oil and gas reservoir to determine whether it meets the requirements of this level of reserves. 11.2 Comprehensive evaluation of reserves 11.2.1 Classification of production capacity a) According to the stable daily production of kilometers deep, the production capacity of oil and gas reservoirs is divided into 4 categories (see Table 3)11 Division of reserve calculation units
Fractured oil and gas reservoirs have various reservoir types. The division of reserve calculation units mainly considers the differences in reservoir types and storage and permeability, the oil (gas) and water combination relationship and geological structure characteristics. When calculating proven reserves, it is necessary to calculate reserves by block, layer group, reservoir type and oil (gas) and water system. If there are several sets of fracture systems that are not interconnected, it is also necessary to calculate the reserves of each fracture system. 8 Calculation of geological reserves of condensate gas reservoirs by volumetric method
8.1 Calculation method
Under the original formation conditions, condensate gas exists in the reservoir as a single gas. Therefore, the geological reserves of condensate gas reservoirs are still calculated using formulas (6), (8), and (10). However, the determination of the original gas deviation coefficient should take into account the influence of the components of condensate gas and total produced fluid (including condensate oil and natural gas).
8.2 Original gas deviation coefficient of condensate gas reservoir wwW.bzxz.Net
8.2.1 Determination of relative density of concurrent fluids According to the relative density of natural gas produced by condensate gas wells (W), the relative density of condensate oil (W) and the gas production ratio (GOR) of condensate gas wells, the relative density of total produced fluids (W) is determined. The calculation formula is shown in formulas (23) and (24): Y
GORY++ 830Y.
240567
M — 44.297/(1.03 - .)
8.2.2 Obtaining the pseudo-critical pressure and pseudo-critical temperature (23)
After determining the relative density () of the total fluid produced from the riser, refer to the relevant plate [Figure CI in Appendix C (Appendix to the standard)] to obtain the pseudo-critical pressure and pseudo-critical temperature T. After correction, refer to Figure (2) in Appendix C (Appendix to the standard), and then use formula (21) and formula (22) to calculate the pseudo-relative pressure Pe- and pseudo-relative temperature Tr. Refer to the relevant plate [Figure D11 in Appendix D (Appendix to the standard) to obtain the original gas deviation coefficient 2, value. 8.3
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