Method for evaluating gas reservoir and gas production capacity after fracturing

Abstract

The present invention discloses a method for evaluating gas-bearing formations and post-fracture gas production capacity, which includes: inversely calculating formation pressure using well logging curves to qualitatively identify gas-bearing formations; determining reservoir rock mechanical property parameters and pore structure conditions; determining reservoir fracturability and the conversion relationship between irreducible water and movable water after fracturing; establishing a gas saturation model under different production conditions; and predicting the liquid production property of the reservoir after fracturing according to the gas saturation model. By using the solution of the present invention, accurate evaluation of post-fracture gas production can be achieved, providing effective data support for subsequent gas field development.

Description

Technical Field

[0001] The present invention relates to the field of oil geological exploration, and specifically relates to a method for evaluating gas reservoirs and post-fracture gas production capacity. Background Art

[0002] At present, the development of some gas field blocks has entered the middle and late stages. The resource quality of the production capacity replacement areas has declined, the geological characteristics of the reservoirs are more complex, the gas saturation is significantly lower than that of the main production areas, and some blocks belong to low-porosity and low-permeability reservoirs. There is a large difference between the actual post-fracture gas production situation and the calculated gas saturation, and the coincidence rate is only less than 70%. Therefore, how to accurately evaluate the gas content and production capacity in the later stage of the gas field plays a key role in the gas well production capacity and the efficient development of the gas field. Summary of the Invention

[0003] The present invention provides a method for evaluating gas reservoirs and post-fracture gas production capacity to achieve accurate evaluation of post-fracture gas production and provide effective data support for the later-stage gas field development.

[0004] To this end, the present invention provides the following technical solutions:

[0005] A method for evaluating gas reservoirs and post-fracture gas production capacity, the method comprising:

[0006] Inverting formation pressure using logging curves and qualitatively identifying gas reservoirs;

[0007] Determining the reservoir rock mechanical property parameters and pore structure conditions;

[0008] The reservoir fracturability and the conversion relationship between irreducible water and mobile water after fracturing;

[0009] Establishing a gas production gas saturation model under different production conditions;

[0010] Predicting the fluid production properties of the reservoir after fracturing according to the gas saturation model.

[0011] Optionally, the inverting formation pressure using logging curves and qualitatively identifying gas reservoirs includes:

[0012] Characterizing the normal pressure trend using the relationship between neutron, transit time and depth to obtain a normal pressure trend line;

[0013] Comparing the measured value with the normal pressure trend line to obtain a pressure coefficient;

[0014] Performing gas correction on the pressure coefficient to obtain a corrected formation pressure coefficient;

[0015] Determining the pressure change situation according to the pressure coefficient;

[0016] Determining the gas-bearing property of the reservoir according to the pressure change situation.

[0017] Optionally, the normal pressure trend line includes: a time difference normal pressure trend line and a neutron normal pressure trend line; the pressure coefficient includes a time difference pressure coefficient and a neutron pressure coefficient.

[0018] Optionally, determining the pressure change situation according to the pressure coefficient includes: calculating a pressure production value gas indication and a pressure ratio gas indication according to the pressure coefficient.

[0019] Optionally, the gas-bearing saturation models under different production situations include: a fully gas-producing gas-bearing saturation model after fracturing, a minimum gas-producing gas-bearing saturation model after fracturing, and a main gas-producing gas-bearing saturation model after fracturing.

[0020] Optionally, determining the reservoir rock mechanical property parameters includes:

[0021] Determining the correlation between the longitudinal wave time difference and the shear wave of the array acoustic wave;

[0022] Inverting the shear wave by using the longitudinal wave time difference in combination with lithology changes, and calculating the reservoir rock mechanical property parameters.

[0023] Optionally, the reservoir rock mechanical property parameters include: shear modulus, Young's modulus, bulk modulus, longitudinal-to-shear wave velocity ratio, shear wave time difference, and fracturability index.

[0024] The method for evaluating a gas reservoir and the gas production capacity after fracturing provided by the present invention, in view of the situation where the actual gas production situation after fracturing does not match the calculated gas-bearing saturation, establishes a post-fracture gas-bearing saturation model of the reservoir by combining core and logging data, and uses this model to accurately evaluate the gas production situation after fracturing. Description of the Drawings

[0025] Figure 1 is a flowchart of the method for evaluating a gas reservoir and the gas production capacity after fracturing provided by the present invention;

[0026] Figure 2 is a flowchart of qualitatively identifying a gas reservoir in an embodiment of the present invention;

[0027] Figure 3 is a schematic diagram of a time difference normal pressure trend line in an embodiment of the present invention;

[0028] Figure 4 A schematic diagram of a neutron normal pressure trend line in an embodiment of the present invention;

[0029] Figure 5 is a consistency cross plot of calculating permeability by using the above permeability model and core analysis permeability in an embodiment of the present invention. Detailed Embodiments

[0030] To more clearly illustrate the technical solutions in the embodiments of the present invention or in the prior art, the following will briefly introduce the accompanying drawings required for the embodiments. Obviously, the accompanying drawings in the following description are only some embodiments of the present invention. For those of ordinary skill in the art, without creative efforts, other accompanying drawings can be obtained based on these drawings.

[0031] The present invention will be described in detail below in conjunction with the accompanying drawings and specific embodiments. The embodiments cannot be elaborated one by one here, but the embodiments of the present invention are not limited to the following embodiments.

[0032] In view of the situation where the actual gas production after fracturing does not match the calculated gas saturation, the present invention provides a method for evaluating the gas layer and the gas production capacity after fracturing. A reservoir post-fracture gas saturation model is established by combining core and logging data, and this model is used to accurately evaluate the gas production situation after fracturing.

[0033] As Figure 1 shown, it is a flowchart of a method for evaluating the gas layer and the gas production capacity after fracturing provided by the present invention, including the following steps:

[0034] In step 101, the formation pressure is inverted using logging curves to qualitatively identify gas layers.

[0035] The magnitude of the acoustic travel time depends on lithology, degree of compaction, porosity, and fluid content in the pores. When the lithology and formation water properties change little, the acoustic travel time mainly reflects the porosity. Under normal compaction, the porosity of mudstone decreases with the increase of depth D, and the degree of decrease changes exponentially. Therefore, the formation pressure can be inversely fitted using porosity curves such as travel time. However, the travel time is severely affected by gas content and production, and the pressure coefficient obtained by inversion needs to be corrected for gas content to reflect the pore pressure change of the formation.

[0036] The main derivation process is as follows: For a normal pressure system, the travel time and depth have an exponential relationship, that is:

[0037] Δt = Δt0e -cD

[0038] Taking the logarithm on both sides, then there is:

[0039] lnΔt = -cD ln e + lnΔt0

[0040] In the above formula: Δt is the travel time, D is the depth, and C is a constant.

[0041] The pressure coefficient can be further expressed as: And for the actual pressure coefficient at a certain point, its value is equal to the ratio of the actual logarithm value to the logarithm value of the normal pressure system.

[0042] PPF = lnΔtx / lnΔt

[0043] As Figure 2 shown, it is a flowchart for qualitatively identifying gas layers in an embodiment of the present invention, including the following steps:

[0044] Step 201: Characterize the normal pressure trend using the relationship between neutron, transit time and depth in the shale section to obtain the normal pressure trend line.

[0045] The normal pressure trend line includes: transit time normal pressure trend line, neutron normal pressure trend line; as Figure 3 and Figure 4 respectively show the schematic diagrams of the transit time normal pressure trend line and the neutron normal pressure trend line in the embodiment of the present invention, where the horizontal and vertical coordinates are depth (m), logarithm of transit time and logarithm of neutron respectively.

[0046] Step 202: Compare the measured values with the normal pressure trend line to obtain the pressure coefficient.

[0047] In the embodiment of the present invention, the pressure coefficient includes transit time pressure coefficient and neutron pressure coefficient.

[0048] Transit time normal pressure trend equation: Establish the relationship between the logarithm of the measured transit time value and depth, see Step 201.

[0049] PFC = -6 * pow(10, -5) * DEP + 6.6574

[0050] Neutron normal pressure trend equation: Establish the relationship between the logarithm of the measured neutron value and depth, see Step 201.

[0051] PFZ = -0.0002 * DEP + 4.9371

[0052] The actual pressure equations for a certain point are respectively:

[0053] Transit time actual pressure equation: PFS = ln(AC), where AC is the transit time logging value;

[0054] Neutron actual pressure equation: PFN = ln(CN), where CN is the compensated neutron logging value;

[0055] Then the actual pressure coefficient at a certain point is the ratio of the actual pressure value at that point to the normal pressure, that is:

[0056] Transit time pressure coefficient:

[0057] PPF = 5 * PFS / PFC - 3.25

[0058] Neutron pressure coefficient:

[0059] PP = 0.55 * PFN / PFZ + 0.35

[0060] Step 203: Perform gas-bearing correction on the pressure coefficient to obtain the corrected formation pressure coefficient.

[0061] To overcome the influence of gas-bearing property changes on logging curves, the pressure coefficient after gas-bearing correction is more accurate. The correction equation obtained through regression based on actual pressure measurement data is as follows:

[0062] YLXS = (0.5 * (SGAV + 240) / 300 * PP + (1 - 0.5 * (SGAV + 240) / 300) * PPF)

[0063] Step 204: Determine the pressure change situation of the two based on the pressure coefficient.

[0064] The larger the pressure coefficient, the greater the pressure. If it is greater than 1, it is overpressure.

[0065] Step 205: Determine the gas-bearing property of the reservoir based on the pressure change situation.

[0066] Determine the pressure change difference between the two based on the travel time difference and neutron pressure coefficient, thereby indicating the gas-bearing situation. This is mainly due to the fact that after gas-bearing, the travel time becomes larger and the neutron becomes smaller, resulting in an increase in the calculated travel time pressure coefficient and a decrease in the neutron pressure coefficient. The difference between the two is the gas-bearing indication.

[0067] Specifically, the gas-bearing indication of pressure difference and the gas-bearing indication of pressure ratio can be calculated based on the pressure coefficient.

[0068] The gas-bearing indication of pressure difference can be expressed as follows:

[0069] AIR = PPF - PP

[0070] The gas-bearing indication of pressure ratio can be expressed as follows:

[0071] PTO = PPF / PP

[0072] Permeability is an important parameter for evaluating reservoir properties and seepage capacity, and it has a close relationship with the particle size of rock grains, shale content, and effective porosity. Therefore, a correlation can be established between core analysis permeability (Perm or K), porosity, and natural gamma.

[0073] The size of permeability is directly proportional to the effective porosity and inversely proportional to the shale content or natural gamma.

[0074] The permeability model is established as follows: Establish a relationship through regression based on permeability experimental data, effective porosity, and natural gamma.

[0075] PERM = K * f(PSWE, GR, Kp, Kg)

[0076] Among them, the meanings of the parameters are as follows:

[0077] PSWE - effective porosity, unit: %;

[0078] GR - natural gamma, unit: API;

[0079] Kp, Kg - coefficients related to PSWE and GR, constants, dimensionless;

[0080] K - total coefficient of the permeability equation, constant, dimensionless.

[0081] As Figure 5 shown, it is the crossplot of the permeability calculated using the above permeability model and the core experiment - analyzed permeability in the embodiment of the present invention. The abscissa is the permeability calculated through regression, and the ordinate is the core experiment permeability data, and the consistency between the two is relatively good.

[0082] Through the comprehensive analysis of core and logging data, it can be found that the main reasons for the error are sediment heterogeneity, permeability directionality, logging curve resolution, and curve distortion caused by wellbore irregularity, etc. The average absolute error between the calculation result using the above permeability model and the core analysis data is 0.35 mD.

[0083] Continue to refer to Figure 1 , in step 102, determine the reservoir rock mechanical property parameters (such as shear modulus, Young's modulus, and bulk modulus) and pore structure conditions.

[0084] Specifically, determine the correlation between the longitudinal wave slowness and the shear wave of the array acoustic wave; use the longitudinal wave slowness combined with lithology changes to invert the shear wave, and calculate the rock mechanical property parameters.

[0085] The rock mechanical property parameters may include, but are not limited to, any one or more of the following: shear modulus, Young's modulus, bulk modulus, longitudinal - to - shear wave velocity ratio, shear wave slowness, fracturability index, etc.

[0086] The specific calculation formulas are as follows:

[0087] Shear modulus:

[0088] SMOD = ρVs 2

[0089] Young's modulus:

[0090] Bulk modulus:

[0091] In the above formulas, Vp and Vs are the longitudinal and shear wave velocities of the rock, respectively, sourced from logging.

[0092] Using array acoustic logging data, establish the correlation between the P-wave to S-wave velocity ratio and natural gamma ray:

[0093] SCRAP = 0.0042 * (100 * (GR - GRmin) / (GRmax - GRmin)) + 1.45

[0094] Then invert to obtain the S-wave slowness:

[0095] AS = SCRP * AC

[0096] In the above equations, AC and AS are the logging P-wave and S-wave slowness values respectively.

[0097] Through the inverted S-wave, the fracability index can be calculated. This index characterizes the fracability and transformability of the rock. The calculation of the fracability index is as follows:

[0098] FRAC = 100 · YMOD 0.36

[0099] In step 103, determine the fracability of the reservoir and the situation where the irreducible water is released as mobile water after fracturing.

[0100] Based on the reservoir rock mechanical properties and pore structure, analyze the fracability of the reservoir and the conversion relationship between irreducible water and mobile water after fracturing. The larger the fracability index, the greater the degree of fracturing transformation and the greater the amount of irreducible water converted to mobile water. This parameter is mainly used to qualitatively evaluate the transformability of the reservoir and the possibility of irreducible water being converted to mobile water.

[0101] In step 104, establish the gas saturation models under different production conditions.

[0102] According to the different requirements for gas saturation in gas production from reservoirs with different permeabilities, and combined with the conversion of irreducible water to mobile water after fracturing, establish the gas saturation models under different production conditions to predict the gas production situation after fracturing.

[0103] In the embodiments of the present invention, the gas saturation models under different production conditions may include: the complete gas production gas saturation model after fracturing, the minimum gas production gas saturation model after fracturing, and the main gas production gas saturation model after fracturing.

[0104] Using the actual gas-water relative permeability relationship equation, obtain the saturations required for complete gas, main gas, and minimum gas respectively, and then substitute the fracability to achieve the conversion of irreducible water to mobile water, as follows:

[0105] Predict the complete gas production gas saturation after fracturing:

[0106] CSSGY = 10.8878 * log(FRAC * PERM) + 33.625

[0107] Predict the minimum gas production gas saturation after fracturing:

[0108] CSSGY0 = 3.4122 * log(FRAC * PERM) + 5.8203

[0109] Predict the main gas production gas saturation after fracturing:

[0110] CSSGY1 = 5.9784 * log(FRAC * PERM) + 20.5360

[0111] Wherein, PERM is the calculated permeability and FRAC is the fracturing index.

[0112] In step 105, predict the liquid production performance of the reservoir after fracturing according to the gas saturation model.

[0113] For the specific gas production situation of the reservoir, it can be compared and judged according to the gas saturation SGAV and the predicted gas saturation, as follows:

[0114] When SGAV > CSSGY, the reservoir produces gas completely;

[0115] When CSSGY1 < SGAV < CSSGY, the reservoir mainly produces gas but contains water;

[0116] When CSSGY0 < SGAV < CSSGY1, the reservoir mainly produces water but contains gas;

[0117] When SGAV < CSSGY0, the reservoir only produces water and does not produce gas.

[0118] The method for evaluating the gas layer and the gas production capacity after fracturing provided by the present invention, in view of the situation where the actual gas production situation after fracturing does not match the calculated gas saturation, combines the middle core and logging data to establish a gas saturation model of the reservoir after fracturing, and uses this model to achieve an accurate evaluation of the gas production situation after fracturing.

[0119] In the embodiments of the present invention, "a plurality of" means two or more.

[0120] It should be noted that the terms "including" and "having" and any variations thereof in the specification and claims of the present invention and the above-mentioned drawings are intended to cover non-exclusive inclusion. For example, a process, method, system, product or device including a series of steps or units does not necessarily have to be limited to those steps or units clearly listed, but may include other steps or units not clearly listed or inherent to these processes, methods, products or devices.

[0121] Each embodiment in this specification is described in a progressive manner. For the same or similar parts among the embodiments, reference can be made to each other. Each embodiment focuses on the differences from other embodiments. Moreover, the system embodiments described above are merely illustrative. The modules and units described as separate components may or may not be physically separated, that is, they may be located on one network unit or distributed to multiple network units. Some or all of the modules can be selected according to actual needs to achieve the purpose of the solution of this embodiment. A person of ordinary skill in the art can understand and implement it without creative work.

[0122] In specific implementation, regarding the various modules / units included in the various devices and products described in the above embodiments, they can be software modules / units, hardware modules / units, or some can be software modules / units and some can be hardware modules / units.

[0123] In addition, in each embodiment of the present application, the functional units can be integrated in a processing unit, or each unit can be physically arranged separately, or two or more units can be integrated in one unit. The above integrated units can be implemented in the form of hardware or in the form of a combination of hardware and software functional units.

[0124] The above has introduced the embodiments of the present invention in detail. Specific implementation manners are used in this article to expound the present invention. The description of the above embodiments is only used to help understand the method and system of the present invention. They are only a part of the embodiments of the present invention, rather than all the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by a person of ordinary skill in the art without creative work should fall within the protection scope of the present invention. The content of this specification should not be construed as a limitation to the present invention. Therefore, any modifications, equivalent replacements, improvements, etc. made within the spirit and principle of the present invention should be included in the protection scope of the present invention.

Claims

1. A method for evaluating gas reservoirs and post-fracture gas production capacity, characterized in that, The method includes: Characterizing the normal pressure trend by using the relationships among neutrons, acoustic transit time and depth to obtain the normal pressure trend line; the normal pressure trend line includes: the acoustic transit time normal pressure trend line, the neutron normal pressure trend line; specifically, characterizing the normal pressure trend by using the relationships among neutrons, acoustic transit time and depth to obtain the normal pressure trend line is: establishing the relationship between the logarithm of the measured acoustic transit time value and depth and establishing the relationship between the logarithm of the measured neutron value and depth; Comparing the measured value at the measurement point with the normal pressure value at the measurement point in the normal pressure trend line to obtain the pressure coefficient at the measurement point, and the pressure coefficient includes the acoustic transit time pressure coefficient and the neutron pressure coefficient, wherein, the acoustic transit time pressure coefficient: PPF = 5 * PFS / PFC - 3.25; the neutron pressure coefficient: PP = 0.55 * PFN / PFZ + 0.35; In the formula, PFC = -6 * pow(10, -5) * DEP + 6.6574; PFZ = -0.0002 * DEP + 4.9371; PFS = ln(AC), where AC is the acoustic transit time logging value; PFN = ln(CN), where CN is the compensated neutron logging value; Performing gas-bearing correction on the pressure coefficient to obtain the corrected formation pressure coefficient; wherein, the equation for the gas-bearing correction is: YLXS = (0.5 * (SGAV + 240) / 300 * PP + (1 - 0.5 * (SGAV + 240) / 300) * PPF), where SGAV represents the gas saturation; Determining the pressure change situation according to the pressure coefficient of the formation; determining the gas-bearing property of the reservoir according to the pressure change situation of the formation; Determining the reservoir rock mechanical property parameters and the pore structure situation; analyzing the fracturability of the reservoir and the conversion relationship between the irreducible water and the mobile water after fracturing according to the reservoir rock mechanics characteristics and the pore structure situation. The conversion relationship is that the larger the fracturing index, the greater the degree of fracturing transformation, and the greater the amount of irreducible water converted into mobile water; According to the different requirements for gas saturation when producing gas in reservoirs with different permeabilities, and combining the conversion relationship between the irreducible water and the mobile water after fracturing, establishing a gas saturation model under different production conditions to predict the gas production situation after fracturing; The establishment of the gas saturation model for gas production under different production conditions to predict the gas production situation after fracturing specifically includes: Predicting the gas saturation for complete gas production after fracturing: CSSGY = 10.8878 * log(FRAC * PERM) + 33.625 Predicting the minimum gas saturation for gas production after fracturing: CSSGY0 = 3.4122 * log(FRAC * PERM) + 5.8203 Predicting the main gas saturation for gas production after fracturing: CSSGY1 = 5.9784 * log(FRAC * PERM) + 20.5360 wherein, PERM is the calculated permeability, and FRAC is the fracturing index; The calculation permeability model is established as follows. The relationship is established by regression according to the permeability experimental data, effective porosity and natural gamma: PERM = K * f(PSWE, GR, Kp, Kg) wherein, the meanings of the parameters are as follows: PSWE - effective porosity, unit: %; GR - Natural gamma ray, unit API; Kp, Kg - Coefficients related to PSWE and GR, constants, dimensionless; K - Total coefficient of the permeability equation, constant, dimensionless; The shear wave obtained by inversion is used to calculate the fracability index, and the calculation of the fracability index is as follows: FRAC = 100·YMOD 0.36 where YMOD is Young's modulus; Based on the comparison and discrimination between the gas saturation SGAV and the predicted gas saturation, the specific situation is as follows: When SGAV > CSSGY, the reservoir produces gas completely; When CSSGY1 < SGAV < CSSGY, the reservoir mainly produces gas but contains water; When CSSGY0 < SGAV < CSSGY1, the reservoir mainly produces water but contains gas; When SGAV < CSSGY0, the reservoir only produces water and does not produce gas.

2. The method for evaluating gas-bearing formation and post-fracture gas production capacity according to claim 1, wherein The determination of the pressure change situation according to the pressure coefficient includes: Calculating the gas indication of the pressure difference and the gas indication of the pressure ratio according to the pressure coefficient; The gas indication of the pressure difference is expressed as follows: AIR = PPF - PP The gas indication of the pressure ratio is expressed as follows: PTO = PPF / PP.

3. The method for evaluating gas-bearing formation and post-fracture gas production capacity according to claim 1, wherein The determination of the reservoir rock mechanical property parameters includes: Determining the correlation between the longitudinal wave travel time and the shear wave of the array acoustic wave; Using the longitudinal wave travel time combined with the lithology change to invert the shear wave and calculating the reservoir rock mechanical property parameters.

4. The method for evaluating the gas reservoir and the gas production capacity after fracturing according to claim 3, wherein, The reservoir rock mechanical property parameters include: shear modulus, Young's modulus, bulk modulus, longitudinal - to - shear wave velocity ratio, shear wave travel time, fracability index.

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