Method for quantitatively calculating hydrocarbon-bearing abundance of reservoir by using logging data and finely explaining hydrocarbon-bearing abundance of reservoir

Abstract

The invention discloses a method for quantitatively calculating the hydrocarbon-bearing abundance of a reservoir by using logging data and performing fine interpretation. The method comprises the following steps: step 1, acquiring gas logging data, gas logging equipment data, drilling parameter data and coring top and bottom depths of a calculation well section; abnormal points in the gas logging data and the drilling parameter data are removed, and the calculability of the well section is evaluated and calculated; 2, performing multi-step conversion calculation on each footage of the well section with the calculability to obtain an initial value of a logging hydrocarbon index; step 3, performing multiple correction processing on the initial value of the logging hydrocarbon-containing index to obtain a logging hydrocarbon-containing index value after background gas-coring correction, a logging hydrocarbon-containing index value after background gas-coring-seepage gas correction and a logging hydrocarbon-containing index value after fluid type correction; 4, quantitatively evaluating the oil-gas possibility of the reservoir according to the logging hydrocarbon-containing index curve; the fluid property is judged by recording and measuring a hydrocarbon-containing abundance difference value; and performing gas reservoir test productivity prediction by using the average value of the logging hydrocarbon-containing index values after the background gas-coring correction.

Description

Technical Field

[0001] The present invention belongs to the logging technical field in the wellbore technology of the petroleum industry exploration industry, and particularly relates to a method for quantitatively calculating the hydrocarbon abundance of a reservoir and a fine interpretation method by using logging data. Background Technique

[0002] Gas logging is an important technical means for logging professionals to judge and interpret oil and gas layers. The object of gas logging interpretation is the composition and content of natural gas in drilling fluid, and based on this, the oil and gas bearing property is analyzed and judged. Currently, widely used technologies in the logging industry include the PIXLER hydrocarbon ratio method, the triangular chart method, the 3H hydrocarbon ratio method, the abnormal multiple method, etc. Qualitative interpretation and evaluation of oil and gas water layers are mainly carried out by establishing charts through gas logging values or ratios. At present, there is a lack of effective means to directly obtain the oil and gas abundance of reservoirs in the logging field. There are many influencing factors and large interference in gas logging data, and the comparability between layers and wells is poor. The accuracy and universality cannot meet the growing demand for the interpretation and evaluation of complex oil and gas layers in oil and gas exploration and development.

[0003] It is necessary to establish a reliable method for obtaining the oil and gas abundance of reservoirs and interpretation and evaluation by using a small amount of data while drilling to cope with the interpretation and evaluation of complex oil and gas layers, improve the coincidence rate of interpretation, and effectively overcome the problems of poor comparability and universality of conventional logging interpretation.

[0004] Chinese invention patent CN201910854681.0 provides a method for quantitatively evaluating the oil and gas bearing property of a reservoir based on gas logging parameters. The method includes preprocessing gas logging data; defining two derived parameters: hydrocarbon index Y = (4C4 + 5C5) / (C1 + 2C2), hydrocarbon index Z = (C4 + C5) / (C1 + C2); using the hydrocarbon index Y and the hydrocarbon index Z to intersect with the heavy components C3 and C4 + C5 in the gas logging hydrocarbon components respectively to obtain 4 intersection factors S1, S2, S3 and S4; calculating the hydrocarbon abundance S by using the 4 intersection factors H ; using the quantitative interpretation standard of reservoir fluid based on the hydrocarbon abundance S H to obtain an interpretation conclusion.

[0005] Chinese invention patent CN201910854626.1 provides a logging oil and gas layer interpretation method for calculating the comprehensive water cut of a reservoir by using multiple parameters. The method includes using geological, gas logging and geochemical data obtained from on-site logging, conducting data quality analysis, combining regional characteristics, quantifying influencing factors, considering the interpretation weight coefficient of a single technology in the work area, the gaseous and liquid hydrocarbon abundance indexes under different oil quality conditions, the total hydrocarbon value of a typical water layer in the same formation group or the same oil-water system, and P gThe calculated comprehensive water content of the reservoir is a quantitative parameter, which can be used to analyze the water content of the reservoir and thus quantitatively evaluate the oil and gas content of the reservoir.

[0006] Chinese invention patent CN201210185925.9 provides a method for determining the oil and gas saturation of a gas well logging, the method comprising reading the maximum abnormal value C of total hydrocarbon or methane in the oil and gas abnormal display layer. t ; Prioritize the gas measurement background value C of the oil and gas display layer b ; Select the regional gas logging oil and gas saturation index n; According to the formula S h =1-(C t / C b ) -1 / n , calculate the oil and gas saturation S of the specific oil and gas display layer h , output the calculation results.

[0007] Chinese invention patent CN202110742033.3 provides a method for constructing a reservoir fluid indicator factor, which includes first calculating the gas content index, using the trend surface analysis fitting method to perform exponential function fitting on the drilling fluid density difference, gas content index, and gas logging total hydrocarbon value, and obtain the relationship function between the gas logging total hydrocarbon value and the drilling fluid density difference and gas content index, and then calculating the reservoir fluid indicator factor based on the corrected gas logging value to intuitively indicate the reservoir fluid properties.

[0008] At present, most of the patents related to logging hydrocarbon abundance evaluation are implemented in the following ways: gas logging is mainly combined with other logging projects, and the logging parameters or their derivative parameters are used based on mathematical correlation, and the fitting formula method and curve intersection method are used to obtain the hydrocarbon abundance value of the reservoir or evaluate the hydrocarbon content of the reservoir. There are no methods that use logging data to quantitatively calculate the logging hydrocarbon index through multi-step conversion and multiple corrections, quantitatively evaluate the hydrocarbon content by using the logging hydrocarbon index, identify the fluid properties by using the difference in logging hydrocarbon abundance, and predict the gas layer test capacity by using the relationship formula between the average value of the logging hydrocarbon index and the gas layer test layer meter unimpeded flow. Summary of the invention

[0009] The purpose of the present invention is to provide a method for quantitatively calculating the hydrocarbon abundance of reservoirs and fine interpretation using logging data, which can finely characterize the hydrocarbon abundance and changes in the reservoir, achieve accurate quantitative evaluation of the oil and gas content of the reservoir, improve the interpretation compliance rate, eliminate the differences between layers and wells, and enhance the accuracy and universality of logging interpretation.

[0010] The technical solution provided by the present invention is:

[0011] A method for quantitatively calculating reservoir hydrocarbon abundance and fine interpretation using logging data, comprising:

[0012] Step 1: Collect gas measurement data, gas measurement equipment data, drilling parameter data and coring top and bottom depths of the calculated well section; remove abnormal points in the gas measurement data and the drilling parameter data, and evaluate the computability of the calculated well section;

[0013] Step 2: for each footage of a well section that can be calculated, a multi-step conversion calculation is performed on the surface hydrocarbon gas volume, the ideal volume of formation hydrocarbon gas, the actual volume of formation hydrocarbon gas, and the volume content of formation hydrocarbon gas; a regional factor is determined, and an initial value of the logging hydrocarbon index is calculated in combination with the regional factor;

[0014] Step 3, the initial value of the logging hydrocarbon index is subjected to multiple correction processing of background gas correction, coring correction, seepage gas correction and fluid type correction in sequence, to obtain a logging hydrocarbon index value after background gas-coring correction, a logging hydrocarbon index value after background gas-coring-seepage gas correction and a logging hydrocarbon index value after fluid type correction;

[0015] Step 4: construct a continuous logging hydrocarbon index curve for the calculation section based on the logging hydrocarbon index value after correction for the background gas-coring-seepage gas or the logging hydrocarbon index value after correction for the fluid type at each footage in the calculation section, and quantitatively evaluate the oil and gas content of the reservoir; identify the fluid properties by the difference in recorded hydrocarbon abundance; and construct a relationship formula using the average value of the logging hydrocarbon index value after correction for the background gas-coring and the meter-free flow rate of the gas layer test layer to predict the gas layer test production capacity for subsequent drilling in the same area.

[0016] Preferably, the multi-step conversion calculation includes:

[0017] Calculate the surface hydrocarbon gas volume:

[0018]

[0019] Where V sur_gas is the surface hydrocarbon volume of the footage, m 3 ; V degasser_gas is the volume of hydrocarbon gas in the degasser at this footage, m 3 ; K degas V is the degassing efficiency of the degasser, decimal, dimensionless; mud is the circulating mud volume for this footage, m 3 ; V degasmud is the degasser mud volume of the footage, m 3 ;

[0020] Calculate the ideal volume of hydrocarbon gas in the formation:

[0021]

[0022] Where V for_ideal_gas is the ideal volume of hydrocarbon gas in the formation at this footage, m3 ; V0_V is the ideal hydrocarbon gas volume ratio between the ground and underground, in decimals, dimensionless;

[0023] Calculate the true volume of hydrocarbon gas in the formation:

[0024] V for_active_gas = V for_ideal_gas ×Z

[0025] In the formula, V for_active_gas is the true volume of hydrocarbon gas in the formation at this footage, m 3 ; Z is the hydrocarbon gas deviation factor at this footage, dimensionless;

[0026] Calculate the volume content of hydrocarbon gas in the formation:

[0027]

[0028] In the formula, VC for_gas_rock is the volume content of hydrocarbon gas in the formation at this footage, %; V rock is the volume of broken rock at this footage, m 3 .

[0029] Preferably, the calculation formula for the initial value of the logging hydrocarbon index is:

[0030] Mhi1 = VC for_gas_rock ×K area

[0031] In the formula, Mhi1 is the initial value of the logging hydrocarbon index, %; K area is the regional factor, in decimals, dimensionless.

[0032] Preferably, the calculation formula for the logging hydrocarbon index value after background gas - core correction is:

[0033]

[0034] In the formula, Mhi2 is the logging hydrocarbon index value after background gas - core correction, %; K bg is the background gas correction coefficient, in decimals, dimensionless; K core is the core correction coefficient, in decimals, dimensionless.

[0035] Preferably, the calculation formula for the logging hydrocarbon index value after background gas - core - seepage gas correction is:

[0036]

[0037] In the formula, Mhi3 is the logging hydrocarbon index value after background gas - core - seepage gas correction, %; a1 is a formula constant, in decimals, dimensionless; b1 is a formula constant, in decimals, dimensionless; c1 is a formula constant, in decimals, dimensionless.

[0038] Preferably, the identification rule for identifying fluid properties by recording the difference in hydrocarbon abundance is as follows:

[0039] When the calculation well is in the main gas zone, the calculation well section is Mhi3 - S hc <0, then the calculation well section is identified as an oil layer;

[0040] When the calculation well is in the main oil zone, the calculation well section is Mhi3 - S hc >0, then the calculation well section is identified as a gas layer;

[0041] Wherein, S hc is the logging hydrocarbon saturation.

[0042] Preferably, the calculation formula for the logging hydrocarbon index value after fluid type correction is:

[0043] Mhi4 = Mhi3 × K type

[0044] In the formula, Mhi4 is the logging hydrocarbon index value after fluid type correction, %; K type is the fluid type correction coefficient, decimal, dimensionless.

[0045] Preferably, the logging hydrocarbon index continuous curve of the calculation well section is constructed by using the logging hydrocarbon index value after background gas - core - percolating gas correction or the logging hydrocarbon index value after fluid type correction, and the interpretation parameters are extracted to establish the evaluation criteria for the main fluid type and the secondary fluid type for quantitative interpretation.

[0046] Preferably, the relational formula constructed by the average value of the logging hydrocarbon index value after background gas - core correction and the open - flow potential per meter of the gas layer test layer is:

[0047]

[0048] In the formula, Q aof_h is the open - flow potential per meter of the gas layer test layer, 10 4 m 3 / d / m; Q aof is the open - flow potential of the gas layer test layer, 10 4 m 3 / d; h is the effective thickness of the pay zone, m; e is the exponential function with the natural constant e as the base; a2, b2 are formula constants, decimal, dimensionless.

[0049] The beneficial effects of the present invention are:

[0050] The method for quantitatively calculating hydrocarbon abundance in reservoir and fine interpretation using logging data provided by the present invention utilizes logging data to obtain a continuous curve of logging hydrocarbon index through multi-step conversion calculation and multiple correction calculations, finely depicts the hydrocarbon abundance in reservoir and its variation, realizes accurate quantitative evaluation of hydrocarbon-bearing property of reservoir, improves interpretation coincidence rate and recognition and interpretation of complex fluids, eliminates differences between layers and wells, enhances interpretation quality, increases the number of wells that can be calculated, and improves the accuracy and universality of logging interpretation. BRIEF DESCRIPTION OF THE DRAWINGS

[0051] Figure 1 It is a flow chart of the method for quantitatively calculating hydrocarbon abundance in reservoir and fine interpretation using logging data described in the present invention.

[0052] Figure 2 It is a schematic diagram of the multi-step conversion calculation steps described in the present invention.

[0053] Figure 3 It is an example diagram of background gas correction described in the present invention.

[0054] Figure 4 It is an example diagram of core correction described in the present invention.

[0055] Figure 5 It is an example diagram of seepage gas correction described in the present invention.

[0056] Figure 6 It is an example diagram of the application of calculating logging hydrocarbon index for gas layers in the main gas area described in the present invention.

[0057] Figure 7 It is an example diagram of the application of calculating logging hydrocarbon index for oil layers in the main oil area described in the present invention.

[0058] Figure 8 It is an example diagram of the application of identifying oil layers in the main gas area described in the present invention.

[0059] Figure 9 It is an example diagram of the application of building a test production capacity model for gas layers in the main gas area described in the present invention. DETAILED DESCRIPTION OF THE INVENTION

[0060] The following further detailed description of the present invention is provided in conjunction with the drawings, so that those skilled in the art can implement it with reference to the text of the specification.

[0061] As Figure 1 shown, the present invention provides a method for quantitatively calculating hydrocarbon abundance in reservoir and fine interpretation using logging data, and the specific implementation process is as follows.

[0062] Step 1: Collect gas logging data, gas logging equipment data, drilling parameter data and core top and bottom depths of the calculated well section.

[0063] Among them, the gas measurement equipment includes a degasser, a sample gas pipe, and a chromatograph.

[0064] The gas measurement data is the result data of gas logging. The gas measurement data is the content of C1, C2, C3, iC4, nC4, iC5, and nC5 in the gas separated from the drilling fluid. Hydrocarbon gas (hydrocarbon gas) is separated from the drilling fluid by the degasser, and the chromatographic analysis technology of the chromatograph is used to analyze the components of the separated hydrocarbon gas, and the component contents of C1, C2, C3, iC4, nC4, iC5, and nC5 are separated and quantitatively detected, so as to obtain the gas measurement data.

[0065] The gas measurement equipment data includes the degasser displacement, the sample gas pipe flow rate, and the chromatographic analysis period; the degasser displacement, the sample gas pipe flow rate, and the chromatographic analysis period are all obtained by consulting the equipment manual or on-site configuration parameters. For example, the displacement of the GZG degasser is 1500 mL / min; the sample gas pipe flow rate is conventionally set to 450 mL / min; the Resversal analysis period is 42 s / cycle.

[0066] The drilling parameter data is the engineering parameter data during the drilling process. The drilling parameter data includes the bit diameter, the drilling time, and the mud pump displacement.

[0067] Data quality control and computability evaluation are carried out on the collected data, abnormal points in the gas measurement data and the drilling parameter data are removed, and the computability of the calculated well section is evaluated. The specific process is as follows: for the gas measurement data, abnormal points in the reservoir gas measurement data caused by connecting a single joint, well leakage (gushing), drilling fluid additives, etc. should be removed; for the drilling parameter data, data points with abnormal values beyond the reasonable range should be removed; carefully analyze the gas measurement curve and the drilling parameter curve, and observe whether there is background gas interference in the gas measurement curve and whether there is abnormal drilling time in the drilling parameter curve. When the gas measurement curve of a certain well section is too interfered by background gas or there is abnormal drilling time in the drilling parameter curve resulting in serious distortion and it is evaluated that it cannot be corrected, then this well section is included in the non-computable range.

[0068] Step 2: Perform multi-step conversion calculations of the ground hydrocarbon gas volume, the ideal volume of formation hydrocarbon gas, the true volume of formation hydrocarbon gas, and the formation hydrocarbon gas volume content for each bit footage of the well section with computability; determine the regional factor of the area where the calculated well section is located, and calculate the initial value of the logging hydrocarbon index in combination with the regional factor. The specific calculation process is as follows:

[0069] Step 1: The process of calculating the ground hydrocarbon gas volume is as follows:

[0070] Calculate the total number of chromatographic cycles for this footage:

[0071]

[0072] In the formula, Cycles is the total number of cycles of the footage chromatogram, an integer, dimensionless; Rop is the penetration rate, min / m; H is the footage length, m, which takes the value of 1 when the footage is in whole meters; CycleTime is the chromatogram analysis cycle, s; int is the rounding function;

[0073] Calculate the hydrocarbon gas volume of the sample gas pipe in the i-th cycle:

[0074]

[0075] Among them,

[0076]

[0077] In the formula, is the hydrocarbon gas volume of the sample gas pipe in the i-th cycle, m 3 ; SGPFlw is the flow rate of the sample gas pipe, mL / min; ChrCycle i is the sum of the gas logging component contents in the i-th cycle, %; i is the cycle number, an integer; g j is the content of the j-th component in the gas logging chromatogram, %; j is the component serial number, an integer, and the component serial numbers 1-7 represent C1, C2, C3, iC4, nC4, iC5, and nC5 respectively;

[0078] Calculate the hydrocarbon gas volume of the degasser for this footage:

[0079]

[0080] In the formula, V sgp_gas is the hydrocarbon gas volume of the sample gas pipe for this footage, m 3 ;

[0081] When the density of the gas logging data is one gas logging chromatogram data per footage, the formula for the hydrocarbon gas volume of the sample gas pipe for this footage can be changed as follows:

[0082]

[0083] The calculation formula for the hydrocarbon gas volume of the sample gas pipe for this footage is finally simplified to:

[0084] V sgp_gas = SGPFlw × 10 -6 × ChrDeep × Rop × H × 0.01

[0085] In the formula, ChrDeep is the sum of the gas logging component contents for this footage, %;

[0086] Calculate the hydrocarbon gas volume of the degasser for this footage:

[0087] V degasser_gas = V sgp_gas

[0088] Wherein, V degasser_gas is the hydrocarbon gas volume of the footage degasser, m 3 ;

[0089] Calculate the mud volume of the footage degasser:

[0090] V degasmud = Rop × H × DegasserFlw × 10 -6

[0091] Wherein, V degasmud is the mud volume of the footage degasser, m 3 ; DegasserFlw is the degasser displacement, mL / min;

[0092] Calculate the circulating mud volume of the footage:

[0093] V mud = Rop × H × PmpFlw × 0.001

[0094] Wherein, V mud is the circulating mud volume of the footage, m 3 ; PmpFlw is the mud pump displacement, L / min;

[0095] Calculate the surface hydrocarbon gas volume of the footage as:

[0096]

[0097] Wherein, V sur_gas is the surface hydrocarbon gas volume of the footage, m 3 ; K degas is the degassing efficiency of the degasser, in decimals, dimensionless, and can be obtained through tests under on-site operating conditions.

[0098] Step 2. The formula for calculating the ideal volume of the formation hydrocarbon gas is:

[0099]

[0100] Wherein,

[0101]

[0102] Wherein, V for_ideal_gas is the ideal volume of the formation hydrocarbon gas of the footage, m 3; V0_V is the ideal hydrocarbon gas volume ratio between the ground and underground, a decimal number, dimensionless; P0 is the surface pressure, in MPa; P is the formation pressure at this footage, in MPa, generally approximately obtained by calculating the hydrostatic pressure gradient of this well. If there is a measured pressure curve for this well, then use the measured pressure curve value at this footage; T0 is the surface temperature, in K; T is the formation temperature at this footage, in K, generally approximately obtained by calculating the geothermal gradient of this well. If there is a measured temperature curve for this well, then use the measured temperature curve value at this footage.

[0103] Step 3, the process of calculating the true volume of hydrocarbon gas in the formation is as follows:

[0104] Calculate the hydrocarbon gas deviation factor at this footage: There are various methods for obtaining the hydrocarbon gas deviation factor, such as the chart method, experimental method, equation of state calculation method, empirical formula method, etc.; According to the temperature and pressure calculation range and accuracy requirements of oil and gas drilling, compare repeatedly and select the applicable obtaining method, that is, use the Brill - Beggs 1974 formula to calculate the hydrocarbon gas deviation factor. Since hydrocarbon gas is a mixed gas, the hydrocarbon gas critical temperature and hydrocarbon gas critical pressure parameters required in the hydrocarbon gas deviation factor calculation formula are obtained using Key's mixing rule, that is, first use Key's mixing rule to calculate the hydrocarbon gas critical temperature and hydrocarbon gas critical pressure at this footage, and then obtain the hydrocarbon gas reduced temperature and hydrocarbon gas reduced pressure, and then use the Brill - Beggs 1974 formula to calculate and obtain the hydrocarbon gas deviation factor; The calculation process of the hydrocarbon gas deviation factor formula at this footage is as follows:

[0105] Calculate the hydrocarbon gas critical temperature at this footage:

[0106]

[0107] In the formula, Tc is the hydrocarbon gas critical temperature at this footage, in K; Tc j is the critical temperature of the j - th component, in K; The critical temperature values of the C1, C2, C3, iC4, nC4, iC5, nC5 components adopted in the present invention are 190.6K, 305.6K, 370.0K, 408.3K, 425.0K, 460.6K, 469.4K respectively;

[0108] Calculate the hydrocarbon gas critical pressure at this footage:

[0109]

[0110] In the formula, Pc is the hydrocarbon gas critical pressure at this footage, in MPa; Pc j is the critical pressure of the j - th component, in MPa; The critical pressure values of the C1, C2, C3, iC4, nC4, iC5, nC5 components adopted in the present invention are 4.61MPa, 4.88MPa, 4.25MPa, 3.65MPa, 3.80MPa, 3.38MPa, 3.37MPa respectively;

[0111] Calculate the hydrocarbon gas reduced temperature:

[0112]

[0113] In the formula, Tr is the hydrocarbon gas reduced temperature, in decimals, dimensionless;

[0114] Calculate the hydrocarbon gas reduced pressure:

[0115]

[0116] In the formula, Pr is the hydrocarbon gas reduced pressure, in decimals, dimensionless;

[0117] The deviation factor of the hydrocarbon gas for the said footage is calculated as:

[0118] Z = A + (1 - A) × e -B + L × Pr R

[0119] Wherein,

[0120]

[0121] In the formula, Z is the deviation factor of the hydrocarbon gas for the said footage, dimensionless; A, B, L, R, U, and F are all intermediate variables in the calculation, dimensionless;

[0122] The true volume of the hydrocarbon gas in the formation for the said footage is calculated as:

[0123] V for_active_gas = V for_ideal_gas × Z

[0124] In the formula, V for_active_gas is the true volume of the hydrocarbon gas in the formation for the said footage, m 3 .

[0125] Step 4. The process of calculating the volume content of the hydrocarbon gas in the formation is as follows:

[0126] Calculate the volume of the broken rock for the said footage:

[0127]

[0128] In the formula, V rock is the volume of the broken rock for the said footage, m 3 ; BitSize is the bit diameter, in inch; π is the pi;

[0129] The volume content of the hydrocarbon gas in the formation for the said footage is calculated as:

[0130]

[0131] In the formula, VC for_gas_rockis the volume content of hydrocarbon gas in the formation of this footage, %.

[0132] Step 5, calculate the initial value of the mudlogging hydrocarbon index obtained as follows:

[0133] Mhi1 = VC for_gas_rock × K area

[0134] In the formula, Mhi1 is the initial value of the mudlogging hydrocarbon index (in the main oil area, it actually refers to the oil content index, and in the main gas area, it actually refers to the gas content index), %; Mhi is the English initials abbreviation of Mudlog hydrocarbon index; K area is the regional factor, decimal, dimensionless; the regional factor can be determined according to the specific situation of the calculation area, and the value range in different basins is from dozens to hundreds.

[0135] Main fluid type: The fluid type with the largest proportion in the production layer of a region; Secondary fluid type: The hydrocarbon fluid type other than the main fluid type in a region. In the main gas area, the main fluid type is the gas layer and the secondary fluid type is the oil layer; In the main oil area, the main fluid type is the oil layer and the secondary fluid type is the gas layer.

[0136] The regional factor is the conversion parameter that scales the volume content of hydrocarbon gas in the formation to the mudlogging hydrocarbon index of the main fluid type; Through the regional factor, the volume content of hydrocarbon gas is scaled to the gas layer in the main gas area and to the oil layer in the main oil area.

[0137] Step 3, perform multiple correction processes on the initial value of the mudlogging hydrocarbon index, including background gas correction, core correction, seepage gas correction, and fluid type correction, to obtain the mudlogging hydrocarbon index value after background gas-core correction, the mudlogging hydrocarbon index value after background gas-core-seepage gas correction, and the mudlogging hydrocarbon index value after fluid type correction; The specific calculation process is as follows:

[0138] Step 1, perform background gas correction and core correction on the initial value of the mudlogging hydrocarbon index in sequence, and the specific process of obtaining the mudlogging hydrocarbon index value after background gas-core correction is as follows:

[0139] Calculate the correction comparison parameter:

[0140] Corr_para = g1 × Rop × PmpFlw × 0.001

[0141] In the formula, Corr_para is the correction comparison parameter, decimal, dimensionless; g1 is the methane content in gas logging, %.

[0142] Calculate the background gas correction coefficient:

[0143]

[0144] Wherein, K bg is the background gas correction coefficient, a decimal number, dimensionless; Corr_para bg is the actual value of the correction ratio parameter of the representative mudstone layer or non-oil / gas sand layer in the abnormal section of the background gas, a decimal number, dimensionless; Corr_para base1 is the baseline value of the correction ratio parameter of the mudstone layer or non-oil / gas sand layer in the section without background gas anomaly, a decimal number, dimensionless; Corr_para bg and Corr_para base1 are both read on the Corr_para curve; when there is no influence of background gas, K bg takes the value of 1;

[0145] Calculate the core correction coefficient:

[0146]

[0147] Wherein, K core is the core correction coefficient, a decimal number, dimensionless; Corr_para core is the actual value of the representative correction ratio parameter of the core section, a decimal number, dimensionless; Corr_para base2 is the baseline value of the correction ratio parameter of the non-core section overlying the core section, a decimal number, dimensionless, Corr_para core and Corr_para base2 are both read on the Corr_para curve; when the core section is a non-reservoir, or when there are significant changes in the lithology and physical properties of the core section relative to the overlying non-core section, or when Corr_para core of the core section relative to Corr_para base2 of the overlying non-core section does not decrease significantly, K core takes the value of 1;

[0148] Calculate the logging hydrocarbon index value after the background gas-core correction as:

[0149]

[0150] Wherein, Mhi2 is the logging hydrocarbon index value after the background gas-core correction, %.

[0151] Step 2, Determine whether percolation gas correction is required: Generally, the gas logging value is mainly contributed by rock fragmentation gas; when obvious gas invasion is observed in the gas logging value, that is, when the gas logging value is contributed not only by fragmentation gas but also by a large amount of formation percolation gas, percolation gas correction is required.

[0152] The calculation formula for the percolation gas correction is:

[0153]

[0154] In the formula, Mhi3 is the hydrocarbon-bearing index value of logging after background gas-core-permeating gas correction, %, a1 is a formula constant, a decimal number, dimensionless; b1 is a formula constant, a decimal number, dimensionless; c1 is a formula constant, a decimal number, dimensionless; a1, b1, and c1 are empirical parameters, and the values of a1, b1, and c1 can be obtained by using the relational formula fitted from the Mhi2 of the representative well in the area where the calculation interval is located and the logging hydrocarbon saturation S hc to obtain a1, b1, and c1 by fitting the relational formula obtained.

[0155] Step 3. The hydrocarbon-bearing index value Mhi3 of logging after background gas-core-permeating gas correction represents the hydrocarbon-bearing index (gas-bearing index) of the gas layer in the main gas area or the hydrocarbon-bearing index (oil-bearing index) of the oil layer in the main oil area; since there is an obvious volume difference between the gas content of the oil layer and the gas content of the gas layer, the calculated value of Mhi3 for the reservoir of the secondary fluid type will deviate. The calculated value of Mhi3 for the oil layer in the main gas area is smaller than the true value, and the calculated value of Mhi3 for the gas layer in the main oil area is larger than the true value. Therefore, fluid type correction processing needs to be carried out on the oil layer in the main gas area and the gas layer in the main oil area again.

[0156] Perform the identification of the secondary fluid type, and perform fluid type correction on the hydrocarbon-bearing index value of logging after background gas-core-permeating gas correction for the interpreted layer of the secondary fluid type to obtain the hydrocarbon-bearing index value of logging after fluid type correction. The specific process is as follows:

[0157] Identification of the secondary fluid type, that is, identification of the oil layer in the main gas area and the gas layer in the main oil area: The identification of the secondary fluid type can be carried out through the difference in hydrocarbon abundance Mhi3 - S of logging hc , or other logging interpretations, such as: gas logging component interpretation, geochemical logging interpretation, fluorescence / 3D logging interpretation to obtain the secondary fluid type of the interpreted layer.

[0158] Among them, the logging hydrocarbon saturation is a parameter independent of the fluid type. The difference between the hydrocarbon-bearing index value of logging after background gas-core-permeating gas correction and the logging hydrocarbon saturation is used to obtain the difference in hydrocarbon abundance Mhi3 - S of logging hc , which can effectively reflect the fluid type difference; among them, S hc is the logging hydrocarbon saturation.

[0159] Check and eliminate the interference of other factors, and confirm that the calculated value of Mhi3 for the calculation interval reliably reflects the hydrocarbon abundance, and the Mhi3 curve shape of the upper and lower adjacent layers is in good consistency with the S hc curve shape. After that, the identification rule for identifying the fluid property through the difference in hydrocarbon abundance of logging is as follows:

[0160] When the calculation well is in the main gas area, for the calculation interval Mhi3 - S hc < 0, then the calculation interval is identified as an oil layer;

[0161] When the calculation well is in the main oil area, the calculation interval is Mhi3-S hc >0, then the calculation interval is identified as a gas layer;

[0162] Based on the difference in hydrocarbon abundance Mhi3-S in logging hc characteristics and identification rules, determine the fluid properties and identify the secondary fluid types.

[0163] Generally, when the value of |Mhi3-S hc | is large, the coincidence rate is high, but when the value of |Mhi3-S hc | is small, the coincidence rate will decrease. When the value of |Mhi3-S hc | is small, refer to the fluid type results of other logging interpretations to comprehensively identify the secondary fluid types.

[0164] If there is no secondary fluid type in the calculation interval, the fluid type correction is not required; if there is a secondary fluid type in the calculation interval, the fluid type correction is required. When performing the fluid type correction, only the high hydrocarbon-bearing layers (oil layers / gas layers) of the secondary fluid type are corrected, and the low hydrocarbon-bearing layers (oil-water layers / gas-water layers and lower-level layers) of the secondary fluid type are not corrected.

[0165] When it is determined that the fluid type correction is required, perform the fluid type correction on the logging hydrocarbon index value after background gas-core-percolating gas correction. The calculation formula for the fluid type correction is:

[0166] Mhi4 = Mhi3 × K type

[0167] In the formula, Mhi4 is the logging hydrocarbon index value after fluid type correction, %; K type is the fluid type correction coefficient, a decimal number, dimensionless, and K type is an empirical constant, which can be determined according to the specific situation of the calculation area;

[0168] The calculation of the logging hydrocarbon index value after the fluid type correction is an optional calculation. For wells without secondary fluid types, only calculate to the logging hydrocarbon index value after background gas-core-percolating gas correction, and quantitatively evaluate the hydrocarbon-bearing property of the reservoir based on the logging hydrocarbon index value after background gas-core-percolating gas correction, without further calculating the logging hydrocarbon index value after the fluid type correction.

[0169] Step Four: Based on the quantitative calculation results, carry out further detailed interpretation and evaluation. The specific evaluation process is as follows:

[0170] Step 1: The specific process of quantitatively evaluating the hydrocarbon-bearing property of the reservoir using the logging hydrocarbon index is as follows:

[0171] According to the characteristic that the hydrocarbon-bearing index of mud logging is a parameter of "hydrocarbon saturation level", the oil and gas-bearing property of the reservoir is quantitatively evaluated. Among them, in this embodiment, the parameter of "hydrocarbon saturation level" is the corrected mud logging hydrocarbon-bearing index value Mhi3 of the background gas-core-seepage gas or the corrected mud logging hydrocarbon-bearing index value Mhi4 of the fluid type for each footage in the calculated well section, forming a continuous curve of the parameter of "hydrocarbon saturation level" in the calculated well section, which can finely depict the hydrocarbon abundance of the reservoir and its changes, so as to quantitatively evaluate the oil and gas-bearing property of the reservoir. The quantitative interpretation carried out using the parameter of "hydrocarbon saturation level" is of the same type as the conclusion of conventional mud logging interpretation, mainly gas layer, gas-water layer, gas-bearing water layer, oil layer, oil-water layer, oil-bearing water layer, water / dry layer. The difference is that the quantitative interpretation is based on the continuous curve data of the mud logging hydrocarbon-bearing index Mhi, with more definite interval range values and upper and lower limit values, and the established evaluation criteria are also more stable and unified.

[0172] Using the corrected mud logging hydrocarbon-bearing index value of the background gas-core-seepage gas or the corrected mud logging hydrocarbon-bearing index value of the fluid type to form a continuous curve of the mud logging hydrocarbon-bearing index in the calculated well section, extracting interpretation parameters, and establishing evaluation criteria for the main fluid type and the secondary fluid type. Subsequent drilling is finely interpreted according to the quantitative criteria. Taking the evaluation of the oil and gas-bearing property of the main fluid type and the secondary fluid in the main gas area as an example, the established evaluation criteria are shown in Table 1;

[0173] Table 1: Evaluation criteria for the main fluid type and the secondary fluid type in the main gas area

[0174]

[0175] In the formula, n1, n2, n3, n4, n5, n6 are empirical parameters, which are determined according to the specific situation of the calculation area.

[0176] In most cases, the parameter of "hydrocarbon saturation level" can be compared with the logging hydrocarbon saturation. However, due to different calculation principles, the interval range values and upper and lower limit values of the mud logging hydrocarbon-bearing index Mhi calculated by the present invention are different from the logging hydrocarbon saturation S hc There are certain differences. Among them, the calculation of the mud logging hydrocarbon-bearing index is usually based on single-point data, that is, for each independent depth point (such as each footage), according to the gas logging data, drilling parameters and gas logging equipment parameters at this depth point, the corresponding mud logging hydrocarbon-bearing index value is calculated through multiple conversions and multiple correction formulas; the calculation of each depth point is independent and does not depend on the data of adjacent points, ensuring the vertical resolution of the data. After completing all single-point calculations, the mud logging hydrocarbon-bearing index values of each depth point are arranged in depth order and connected to finally form a continuous mud logging hydrocarbon-bearing index continuous curve.

[0177] Step 2. The specific process of using the difference in the hydrocarbon abundance of mud logging to identify the fluid property is as follows:

[0178] The fluid property is identified by the difference in hydrocarbon abundance measured by logging. If the difference in hydrocarbon abundance measured by logging is not used to identify the secondary fluid type in Step 3, then the difference in hydrocarbon abundance measured by logging is used to identify the fluid property in Step 4.

[0179] Step 3: The specific process of predicting the productivity of a gas layer test using the average value of the corrected logging hydrocarbon index value of the background gas - core sampling is as follows:

[0180] Obtain the average value of the corrected logging hydrocarbon index value of the background gas - core sampling for the gas layer test layer, and obtain the open - hole flow rate per meter of the gas layer test layer through well completion testing; fit a relationship formula between the average value of the corrected logging hydrocarbon index value of the background gas - core sampling and the open - hole flow rate per meter of the gas layer test layer, and use the relationship formula to predict the productivity of the gas layer test for subsequent drilled wells in the same area. As Figure 9 shown in the embodiment, it shows a significant positive correlation. Since the curve rises rapidly, a third - order exponential formula is selected for fitting, and the fitted relationship formula is:

[0181]

[0182] In the formula, Q aof_h is the open - hole flow rate per meter of the gas layer test layer, 10 4 m 3 / d / m; Q aof is the open - hole flow rate of the gas layer test layer, 10 4 m 3 / d; h is the effective thickness of the productive formation, m; e is the exponential function with the natural constant e as the base; a2 and b2 are formula constants, decimals, dimensionless, and a2 and b2 are empirical parameters obtained through the fitted relationship formula. The rising speeds of the curves in different areas are different, and a first - order or second - order exponential formula can be selected for fitting according to the situation.

[0183] Step Five: After the calculation and evaluation are completed, the quantitative continuous curve of the logging hydrocarbon index and the interpretation results of a single well are output as results and evaluated for effectiveness. The effectiveness of the quantitative interpretation of the logging hydrocarbon index can be evaluated by using the formation test conclusion and the logging interpretation conclusion; the main evaluation indicators are the coincidence rate compared with the formation test conclusion and the consistency rate compared with the logging interpretation conclusion. The coincidence rate and the consistency rate are two levels of comparison benchmarks; the reliability of the formation test conclusion is high, but the quantity is small, the logging interpretation conclusion is more accurate and the quantity is large; in most cases, the number of logging interpretation layers is one order of magnitude more than the number of formation test layers. When there is no test data, the logging interpretation is a better reference system; at the same time, for deep / ultra - deep low - porosity and low - permeability reservoirs, the reliability of the logging interpretation will decrease; therefore, the effectiveness evaluation is mainly based on the formation test coincidence rate and supplemented by the logging interpretation consistency rate.

[0184] The method for quantitatively calculating hydrocarbon abundance in reservoirs and fine interpretation using mud logging data provided by the present invention has achieved remarkable results in the quantitative calculation and interpretation evaluation of hydrocarbon layers in multiple basins in the Chinese sea area. In Formation Test 118 layers in Sag A of a certain sea area, the interpretation conclusions of 103 layers in quantitative mud logging interpretation are consistent with the test conclusions, and the coincidence rate is 87%, among which the coincidence rate of gas layers is 100%. In 1540 layers of well logging interpretation in this sag, the interpretation conclusions of 1279 layers in quantitative mud logging interpretation are consistent with the well logging interpretation conclusions, and the consistency rate is 83%, among which the consistency rate of gas layers is 89%. In Formation Test 116 layers in Sag B of a certain sea area, the interpretation conclusions of 83 layers in quantitative mud logging interpretation are consistent with the test conclusions, and the coincidence rate is 72%, among which the coincidence rate of oil layers is 90%. In 1802 layers of well logging interpretation in this sag, the interpretation conclusions of 1529 layers in quantitative mud logging interpretation are consistent with the well logging interpretation conclusions, and the consistency rate is 85%, among which the consistency rate of oil layers is 81%.

[0185] Since the hydrocarbon index in mud logging and the hydrocarbon saturation in well logging are calculated based on different principles and each has professional independence, and at the same time the well logging interpretation conclusion is not an absolute measurement scale, the higher the consistency rate between the two is not necessarily better. In addition, the exploration layers in Sag A and Sag B are mainly medium and deep layers, and the reliability of well logging interpretation conclusions for some low-porosity and low-permeability reservoirs decreases. Therefore, the consistency rate between mud logging and well logging in the present invention is appropriate, and the problem of comparability between mud logging and well logging is also well solved.

[0186] As Figure 2 shown, the first track: MD measured depth; the second track: content of C1-nC5 gas logging components; the third track: T g total gas logging hydrocarbon content, ChrDeep content of gas logging components, and; the fourth track: BitSize bit diameter, PmpFlw outlet mud pump displacement, Rop drilling time; the fifth track: P formation pressure; the sixth track: T formation temperature; the seventh track: V0_V ideal hydrocarbon gas volume ratio on the ground and underground; the eighth track: Z formation hydrocarbon gas deviation factor; the ninth track: V sur_gas ground hydrocarbon gas volume; the tenth track: V for_ideal_gas ideal volume of formation hydrocarbon gas; the eleventh track: V for_active_gas true volume of formation hydrocarbon gas; the twelfth track: V rock volume of broken rock; the thirteenth track: VC for_gas_rock formation hydrocarbon gas volume content; the fourteenth track: Mhi1 initial value of mud logging hydrocarbon index.

[0187] As Figure 3 shown, the first track: BitSize bit diameter, PmpFlw outlet mud pump displacement, Rop drilling time; the second track: Corr_para correction comparison parameter, the blue dotted line is the value-taking line for the base value and the abnormal value; the third track: MD measured depth; the fourth track: content of C1-nC5 gas logging components, T gTotal gas-logging hydrocarbon content; Channel 5: RD resistivity, GR gamma; Channel 6: ZDEN density, CNCF neutron, DT sonic, ND_CROSS density-neutron crossplot; Channel 7: Lith logging lithology; Channel 8: VSH shale content, POR porosity, SAND sandstone content (shale content-porosity crossplot display); Channel 9: S w Well-logging water saturation; Channel 10: Mhi1 initial value of logging hydrocarbon index, Mhi2 logging hydrocarbon index value after background gas-core correction (only background gas correction for this well); Channel 11: S w Well-logging water saturation, Mhi3 logging hydrocarbon index value after background gas-core-percolating gas correction; Channel 12: Original logging interpretation conclusion; Channel 13: Well-logging interpretation conclusion.

[0188] As Figure 4 shown, Channel 10: Mhi1 initial value of logging hydrocarbon index, Mhi2 logging hydrocarbon index value after background gas-core correction (only core correction for this well); The other channels are the same as Figure 3 the interpretation.

[0189] As Figure 5 shown, Channel 10: Mhi1 initial value of logging hydrocarbon index, Mhi3 logging hydrocarbon index value after background gas-core-percolating gas correction; The other channels are the same as Figure 3 the interpretation.

[0190] As Figure 3-5 shown, by comparing before and after, it can be seen that the effective correction of background gas, core and percolating gas avoids distortion, expands the calculable range, and improves the reliability and accuracy.

[0191] The well-logging hydrocarbon saturation is:

[0192] S hc = 100 - S w

[0193] In the formula, S w is the well-logging water saturation.

[0194] Through the S w well-logging water saturation curve, the well-logging hydrocarbon saturation curve can be obtained, and thus through the characteristics and identification rules of the difference in hydrocarbon abundance Mhi3 - S hc between logging and well-logging, the fluid properties can be determined and the secondary fluid types can be identified.

[0195] As Figure 6-7 shown, Channel 10: Mhi1 initial value of logging hydrocarbon index; Channel 11: Mhi2 logging hydrocarbon index value after background gas-core correction; Channel 12: Mhi3 logging hydrocarbon index value after background gas-core-percolating gas correction, S wLogging water saturation; Track 13: Mhi3 logging hydrocarbon index value after background gas-core-percolating gas correction, filled above the lower limit; Track 14: Interpretation conclusion of this quantitative logging; Track 15: Original logging interpretation conclusion; Track 16: Logging interpretation conclusion; Track 17: Test conclusion; The remaining tracks are the same as Figure 3 the interpretation.

[0196] As Figure 6 shown, the interpretation result is confirmed by formation testing. The logging hydrocarbon index curve Mhi3 after background gas-core-percolating gas correction and the logging water saturation curve S w (S w inverse display is equivalent to S hc ) have good consistency, and the gas-water interface is clear, which is convenient for researchers to accurately interpret. Compared with the conventional gas logging curve, the amplitude change of the logging hydrocarbon index curve Mhi is faster and more sensitive, which can better reflect the change of hydrocarbon abundance in the reservoir. It has higher vertical resolution, is conducive to sub-layer interpretation, and is closer to the actual interface depth. The logging hydrocarbon index curve Mhi is a quantitative curve, which can provide a quantitative identification basis and unified boundary standard for the determination of fluid interfaces such as gas layers-gas-water layers-gas-bearing water layers.

[0197] As Figure 7 shown, the interpretation result is confirmed by formation testing. The logging hydrocarbon index curve Mhi3 after background gas-core-percolating gas correction and the logging water saturation curve S w (S w inverse display is equivalent to S hc ) have good consistency, and the oil-water interface is clear, which is convenient for researchers to accurately interpret. Compared with the conventional gas logging curve, the logging hydrocarbon index curve Mhi has higher vertical resolution, which is conducive to sub-layer interpretation. Especially, the division of interbeds, oil layers and oil-water layer interfaces is easier than conventional gas logging and has a quantitative basis.

[0198] As Figure 8 shown, Track 9: Initial value of Mhi1 logging hydrocarbon index; Track 10: Logging hydrocarbon index value after background gas-core correction of Mhi2; Track 11: Logging hydrocarbon index value after background gas-core-percolating gas correction of Mhi3, S w logging water saturation; Track 12: Logging hydrocarbon index value after fluid type correction of Mhi4, S w logging water saturation; Track 13: Logging hydrocarbon index value after background gas-core-percolating gas correction of Mhi3, filled above the lower limit of the main fluid type; Track 14: Logging hydrocarbon index value after fluid type correction of Mhi4, filled above the lower limit of the secondary fluid type; Track 15: Interpretation conclusion of this quantitative logging; Track 16: Original logging interpretation conclusion; Track 17: Logging interpretation conclusion; Track 18: Test conclusion; Track 19: Completion test conclusion; The remaining tracks are the same asFigure 6-7 The explanations are the same. As Figure 8 shown, the interpreted results are confirmed by formation testing. After fluid type correction, the logging hydrocarbon index curve Mhi4 and the logging water saturation curve S w (S w inverse display is equivalent to S hc ) have good consistency, and the oil-gas-water interface is clear, which is convenient for researchers to accurately interpret. The difference in hydrocarbon abundance between logging and measurement Mhi3 - S hc accurately identifies the secondary fluid type - oil layer in the main gas area, and also reversely proves that the logging hydrocarbon index curve Mhi is a parameter of "hydrocarbon saturation level". Otherwise, it cannot be compared with the logging hydrocarbon abundance curve, and it is even more impossible to identify the fluid type. At the same time, it provides a unique solution for the interpretation of difficult layers. Especially when the logging interpretation has difficulty in identifying the oil and gas types and the gas logging components of the oil layer / gas layer are not much different, and the conventional logging interpretation is also difficult to identify the oil and gas types, the present invention can play a very good role.

[0199] As Figure 9 shown, the x-axis: the average value of the logging hydrocarbon index value Mhi2 of the background gas of the gas layer test layer - after core correction; the y-axis: the open flow potential Q of the gas layer test layer aof_h .

[0200] The method for quantitatively calculating hydrocarbon abundance in reservoirs and fine interpretation using mud logging data provided by the present invention starts from the gas logging content in mud logging, constructs a complete theoretical formula and implementation method for quantitatively calculating the formation hydrocarbon index using mud logging parameters, and calculates the continuous curve of the mud logging hydrocarbon index as the "hydrocarbon saturation level" parameter. In most cases, it can be compared with the logging hydrocarbon saturation, with clear physical meaning and intuitive and precise numerical values. The present invention incorporates multi-step conversion calculations of influencing factors and multiple correction treatments of interference factors to make the calculation results more accurate. The multi-step conversion calculation eliminates the gas logging differences caused by different temperature and pressure conditions, different drilling parameters, and different mud logging equipment parameters between layers and wells, avoiding the problem of data distortion caused by these factors in traditional methods misleading interpreters, greatly improving the comparability between layers and wells, and helping to improve the interpretation quality. For interference factors, especially the correction treatments of background gas, core samples, and seepage gas, it can effectively improve the accuracy, significantly expand the calculable range, and increase the number of calculable wells. Without correction treatment, the number of calculable wells in some areas is less than 50%, while after adding correction treatment, the number of calculable wells exceeds 80%. The present invention has made significant progress compared with traditional mud logging interpretation. Traditional mud logging mostly conducts qualitative interpretation of hydrocarbon-bearing properties based on simple formulas and charts, while the calculation result of the present invention is a continuous mud logging hydrocarbon index curve of the "hydrocarbon saturation level", which can be interpreted more precisely. From the perspective of the single-well profile, the longitudinal resolution of the mud logging hydrocarbon index curve is higher, which is conducive to sub-layer interpretation, can better reflect the high and low changes in hydrocarbon abundance in the reservoir, is more sensitive than conventional gas logging parameters, has a straight baseline, prominent anomalies, good intuitiveness, and strong interpretability, especially beneficial for the identification and interpretation of complex fluids, and can provide a quantitative discrimination basis and unified boundary standard for the determination of fluid interfaces such as oil-water, gas-water, and gas-oil. The calculation method of the present invention has strong adaptability, a large calculable range, and good stability, showing good consistency between layers and wells and regional universality, with a high coincidence rate when compared with formation test conclusions, and a good and appropriate coincidence rate when compared with logging interpretation conclusions. Three quantitative interpretation methods, such as hydrocarbon-bearing layer interpretation based on the mud logging hydrocarbon index, identification of hydrocarbon types by the difference in hydrocarbon abundance between logging and mud logging, and prediction of gas layer productivity, have been batch-verified and applied in multiple sea areas with outstanding effects. When well logging operations cannot be carried out under complex working conditions due to lack of well logging data, or when the accuracy of logging hydrocarbon saturation decreases in low-porosity and low-permeability reservoirs and low-resistivity reservoirs, the quantitative calculation and interpretation evaluation of the mud logging hydrocarbon index of the present invention can provide strong data support for completion geological decision-making. The present invention can be widely applied to the quantitative interpretation of hydrocarbon abundance, identification of fluid types, and prediction of gas layer test productivity during the drilling process.

[0201] Although the embodiments of the present invention have been disclosed as above, they are not limited to the applications listed in the specification and the embodiments. It can be fully applied to various fields suitable for the present invention. For those skilled in the art, additional modifications can be easily made. Therefore, without departing from the general concept defined by the claims and the equivalent scope, the present invention is not limited to the specific details and the illustrated examples herein.

Claims

1. A method for quantitatively calculating reservoir hydrocarbon abundance and fine interpretation using logging data, characterized in that: include: Step 1: Collect gas measurement data, gas measurement equipment data, drilling parameter data and coring top and bottom depths of the calculated well section; remove abnormal points in the gas measurement data and the drilling parameter data, and evaluate the computability of the calculated well section; Step 2: for each footage of a well section that can be calculated, a multi-step conversion calculation is performed on the surface hydrocarbon gas volume, the ideal volume of formation hydrocarbon gas, the actual volume of formation hydrocarbon gas, and the volume content of formation hydrocarbon gas; a regional factor is determined, and an initial value of the logging hydrocarbon index is calculated in combination with the regional factor; Step 3, the initial value of the logging hydrocarbon index is subjected to multiple correction processing of background gas correction, coring correction, seepage gas correction and fluid type correction in sequence, to obtain a logging hydrocarbon index value after background gas-coring correction, a logging hydrocarbon index value after background gas-coring-seepage gas correction and a logging hydrocarbon index value after fluid type correction; Step 4: construct a continuous logging hydrocarbon index curve for the calculation section based on the logging hydrocarbon index value after correction for the background gas-coring-seepage gas or the logging hydrocarbon index value after correction for the fluid type at each footage in the calculation section, and quantitatively evaluate the oil and gas content of the reservoir; identify the fluid properties by the difference in recorded hydrocarbon abundance; and construct a relationship formula using the average value of the logging hydrocarbon index value after correction for the background gas-coring and the meter-free flow rate of the gas layer test layer to predict the gas layer test production capacity for subsequent drilling in the same area.

2. The method for quantitatively calculating reservoir hydrocarbon abundance and fine interpretation using logging data according to claim 1, characterized in that: The multi-step conversion calculation includes: Calculate the surface hydrocarbon gas volume: Where V sur_gas is the surface hydrocarbon volume of the footage, m 3 ; V degasser_gas is the volume of hydrocarbon gas in the degasser at this footage, m 3 ; K degas V is the degassing efficiency of the degasser, decimal, dimensionless; mud is the circulating mud volume for this footage, m 3 ; V degasmud is the degasser mud volume of the footage, m 3 ; Calculate the ideal volume of hydrocarbon gas in the formation: Where V for_ideal_gas is the ideal volume of hydrocarbon gas in the formation at this footage, m 3 ; V0_V is the ideal hydrocarbon gas volume ratio between the ground and underground, decimal, dimensionless; Calculate the true volume of hydrocarbon gas in the formation: V for_active_gas =V for_ideal_gas ×Z Where V for_active_gas is the actual volume of hydrocarbon gas in the formation at this footage, m 3 ; Z is the hydrocarbon gas deviation factor of the footage, dimensionless; Calculate the hydrocarbon gas volume content of the formation: Where, VC for_gas_rock V is the volume content of hydrocarbon gas in the formation at this footage, %; rock is the volume of rock broken at this footage, m 3 .

3. The method for quantitatively calculating reservoir hydrocarbon abundance and fine interpretation using logging data according to claim 2, characterized in that: The calculation formula of the initial value of the logging hydrocarbon index is: Mhi1=VC for_gas_rock ×K area Where Mhi1 is the initial value of hydrocarbon index in logging, %; K area is the regional factor, decimal, dimensionless.

4. The method for quantitatively calculating reservoir hydrocarbon abundance and fine interpretation using logging data according to claim 3 is characterized in that: The calculation formula of the logging hydrocarbon index value after background gas-coring correction is: Where Mhi2 is the logging hydrocarbon index value after background gas-coring correction, %; K bg is the background gas correction coefficient, decimal, dimensionless; K core is the coring correction factor, decimal, dimensionless.

5. The method for quantitatively calculating reservoir hydrocarbon abundance and fine interpretation using logging data according to claim 4, characterized in that: The calculation formula of the logging hydrocarbon index value after background gas-coring-seepage gas correction is: Wherein, Mhi3 is the logging hydrocarbon index value after background gas-coring-seepage gas correction, %; a1 is the formula constant, decimal, dimensionless; b1 is the formula constant, decimal, dimensionless; c1 is the formula constant, decimal, dimensionless.

6. The method for quantitatively calculating reservoir hydrocarbon abundance and fine interpretation using logging data according to claim 5, characterized in that: The identification rule for identifying fluid properties by recording the difference in hydrocarbon abundance is: When the calculation well is in the main gas zone, calculate the well section Mhi3-S hc <0, the calculated well section is identified as an oil layer; When the calculation well is in the main oil zone, calculate the well section Mhi3-S hc >0, the calculated well section is identified as a gas layer; Among them, S hc It is the hydrocarbon saturation of well logging.

7. The method for quantitatively calculating reservoir hydrocarbon abundance and fine interpretation using logging data according to claim 6, characterized in that: The calculation formula of the logging hydrocarbon index value after the fluid type correction is: Mhi4=Mhi3×K type Where Mhi4 is the hydrocarbon index value of logging after fluid type correction, %; K type is the fluid type correction factor, decimal, dimensionless.

8. The method for quantitatively calculating reservoir hydrocarbon abundance and fine interpretation using logging data according to claim 7, characterized in that: The logging hydrocarbon index value after correction of the background gas-coring-seepage gas or the logging hydrocarbon index value after correction of the fluid type is used to form a logging hydrocarbon index continuous curve for calculating the well section, extract interpretation parameters, establish evaluation criteria for the main fluid type and the secondary fluid type, and perform quantitative interpretation.

9. The method for quantitatively calculating reservoir hydrocarbon abundance and fine interpretation using logging data according to claim 4, characterized in that: The relationship formula between the average value of the logging hydrocarbon index value after background gas-coring correction and the unimpeded flow rate per meter of the gas layer test layer is: In the formula, Q aof_h is the unobstructed flow rate of the gas layer test layer, 10 4 m 3 / d / m;Q aof is the unimpeded flow rate of the gas layer test layer, 10 4 m 3 / d; h is the effective thickness of the pay zone, m; e is an exponential function with the natural constant e as the base; a2 and b2 are formula constants, decimals, and dimensionless.

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