A method for calculating geological proven reserves of natural gas wells based on logging while drilling

Abstract

The present invention belongs to the technical field of petroleum exploration, and discloses a method for calculating geological proven reserves of natural gas wells based on logging while drilling, which includes the following steps: 1. Determine the starting depth position of the target reservoir according to the logging while drilling display, and record the logging while drilling gas measurement and well diameter data of the depth interval; 2. Calculate the gas volume contained in the rock fragments per unit thickness under surface conditions according to the ground measurement data; 3. Calculate the gas volume contained in the rock per unit thickness under formation conditions according to the gas state equation; 4. Calculate the gas content ratio of the rock per unit volume under formation conditions; 5. Calculate the well-controlled geological proven reserves of natural gas corresponding to the cumulative reservoir thickness; 6. Accumulate the well-controlled pure gas reservoir geological proven reserves within the processing depth range. The present invention can conveniently obtain the geological proven reserves of the reservoir in real time, which is more direct, convenient and fast to calculate, with high accuracy, low cost, and easy to promote compared with the method based on logging curves after drilling.

Description

Technical Field

[0001] The invention belongs to the technical field of petroleum exploration, and in particular relates to a method for calculating geological proven reserves of natural gas wells based on logging while drilling. Background Art

[0002] Oil and gas geological reserves are usually calculated using the volumetric method, which is a method that uses static data and parameters of oil and gas fields to calculate the oil and gas reserves in porous reservoirs. For pure gas reservoirs, the static volumetric method is used to calculate the natural gas geological reserves as follows:

[0003] G=0.01×A×H e ×Φ×(1-S wi ) / B gi

[0004] Where G is the original natural gas geological reserves of the gas reservoir, billion cubic meters; A is the gas-bearing area, square kilometers; H e is the effective thickness of the reservoir, in meters; Φ is the average effective porosity, in decimals; S wi is the average initial water saturation, decimal; B gi is the average natural gas volume coefficient, dimensionless.

[0005] The calculation method of the geological reserves of the above-mentioned natural gas wells depends largely on the calculation of the reservoir porosity and original water saturation after drilling. These two key parameters are dependent on the geophysical logging after drilling. For example, the reservoir porosity can be calculated by acoustic, density or neutron porosity logging curves, and the gas saturation can be obtained by Archie's formula or its deformation based on rock physics experiments combined with resistivity logging curves. However, due to the influence of post-drilling mud invasion, the calculation accuracy of reservoir porosity and saturation based on logging curves is often affected, and real-time evaluation during the drilling process cannot be achieved. In addition, the cost of post-drilling logging is relatively high, and the work time is low, which brings certain challenges to exploration decisions. There is currently no other solution.

[0006] The purpose of exploration drilling is to evaluate whether there is a gas layer underground, and then calculate the reserves. If there is a reserve value, it means that an oil and gas field has been discovered. Reserve data is the only standard for measuring the size of an oil and gas field. In the past, reserve calculations required drilling, inserting precision measuring instruments into the well, measuring porosity and other data, and then calculating, which was time-consuming, labor-intensive, and costly. Summary of the invention

[0007] The purpose of the present invention is to propose a method for calculating and evaluating the proven reserves of natural gas and petroleum using real-time geological logging data at the drilling site, that is, during the drilling process, using the on-site real-time measurement data of ground geological logging such as gas logging while drilling, drilling time, displacement, wellbore size, temperature, etc., by eliminating the influence of wellbore environmental factors on the logging gas logging values, natural gas is restored from the surface to the underground, thereby establishing a geological reserve calculation model based on logging data, improving work efficiency, reducing engineering construction costs, realizing real-time reservoir geological reserve evaluation during drilling exploration, and avoiding the situation where non-hydrocarbon natural gas reserves are calculated due to the possible presence of non-hydrocarbon gases in the original volumetric method calculation.

[0008] In order to solve the problem of real-time calculation and evaluation of geologically proven reserves of natural gas wells, the present invention provides a method for calculating geologically proven reserves of natural gas wells by using real-time geological logging data at a drilling site.

[0009] To achieve the above object, the present invention adopts the following scheme:

[0010] A method for calculating geological proven reserves of natural gas wells based on logging while drilling, characterized in that it comprises the following steps:

[0011] Step 1: Determine the starting depth of the target layer according to the logging and gas logging display, and record the logging and gas logging and well diameter data of the depth interval;

[0012] Step 2: Calculate the volume of gas contained in rock fragments per unit thickness under surface conditions based on ground measurement data;

[0013] Step 3: Calculate the gas volume per unit thickness of rock under formation conditions according to the gas state equation;

[0014] Step 4: Calculate the gas content ratio per unit volume of rock under formation conditions, which is used to evaluate the ratio of the volume of natural gas contained in the rock under formation conditions to the volume of the rock, and is one of the important parameters for reserve assessment;

[0015] Step 5: Select a corresponding calculation formula based on the cumulative effective reservoir thickness obtained by logging while drilling to calculate the proven geological reserves of well-controlled natural gas corresponding to the cumulative effective reservoir thickness;

[0016] Step 6: Accumulate the proven reserves of natural gas in the well-controlled pure gas reservoir within the processing depth range, which is an important basis for gas field development and management and is used for the formulation and preparation of natural gas development plans.

[0017] Preferably, step one is specifically as follows: according to the logging while drilling lithology analysis of the study block, the starting depth of the gas reservoir area is determined, the processing starts, and the average values ​​of the logging while drilling gas logging and well diameter in the corresponding depth interval are recorded at the same time.

[0018] Preferably, step 2 specifically includes: calculating the gas volume V1 contained in rock fragments per unit thickness under surface conditions.

[0019] The volume of gas contained in the rock fragments per unit thickness under surface conditions during drilling can be expressed as:

[0020] V1=10 -6 ×C ng ×ROP×Flow

[0021] Among them, V1 represents the volume of gas contained in the rock fragments per unit thickness under surface conditions, in L; ROP is measured by the surface logging equipment, which represents drilling time, indicating the time spent drilling into the rock per unit thickness, in Min; Flow represents the displacement, which is equal to the sum of the circulating displacement of the drilling pump and the displacement of the booster pump, in L / Min; C ng Indicates the concentration of gas (hydrocarbon natural gas) in surface drilling fluid. C n Represents the gas measurement value of each hydrocarbon component, n = 1, 2, 3, 4, 5, unit ppm, E n represents the degassing efficiency of each component, dimensionless; it should be noted that, compared with the traditional static volume method, the present invention only calculates the degassing efficiency of hydrocarbons (i.e., C n ) gas content; k is the conversion factor between the flow rate of the gas analyzed by the gas testing equipment and the displacement of the degasser.

[0022] Preferably, step three is specifically as follows: according to the gas state equation, the gas volume V2 contained in the rock per unit thickness under formation conditions is calculated.

[0023] The gas state equation can be used to convert the gas volume V1 contained in rock fragments per unit thickness under surface conditions into the gas volume V2 (unit L) under formation conditions, as follows:

[0024]

[0025] Among them, P, V, Z, and T represent pressure, volume, deviation compressibility coefficient, and temperature (absolute temperature, unit K) under different conditions, respectively. The subscript "1" represents the gas state under surface conditions, and the subscript "2" represents the gas state under formation conditions.

[0026] Each parameter in the above formula can be obtained through the following process: gas pressure of target layer under formation conditions P2 = vertical depth of well 0.0098 × H (m) × drilling fluid density ρ m (g / cm 3 ), unit is MPa; absolute temperature of target layer under formation conditions T2 = well depth h (m) × geothermal gradient G t(℃ / m)+273.15, unit is K; the deviation compressibility coefficient Z2 of gas under formation conditions can be obtained from the standard generalized compressibility factor chart; gas pressure P1 under surface conditions = 0.101325MPa; drilling fluid surface temperature T1 = drilling fluid outlet temperature T out (℃)+273.15, unit is K; the deviation compression coefficient Z1=1 under surface conditions.

[0027] Substituting the known parameters P1, V1, T1, Z1, P2, T2, and Z2 into the above formula, we can obtain the gas volume V2 contained in the rock per unit thickness:

[0028]

[0029] Preferably, step 4 is specifically as follows: Calculate the gas content ratio C per unit volume of rock under formation conditions ug

[0030] The gas content ratio per unit volume of rock under formation conditions can be expressed as:

[0031]

[0032] Wherein, V2 is the volume of gas contained in unit thickness of rock under formation conditions, in L; D is the borehole diameter, in mm, which can be directly obtained through the drill bit size data. It should be pointed out that the unit of mm is often used in logging while drilling. Therefore, it needs to be converted into metric units first when using the above formula for calculation.

[0033] Further substitute V2 and the P1, V1, T1, Z1, P2, T2, and Z2 parameters involved in V2 into the above C ug The specific calculation formula for the gas content ratio per unit volume of rock under formation conditions is obtained from the formula as follows:

[0034]

[0035] Preferably, step five specifically includes: selecting a corresponding calculation formula according to the cumulative effective reservoir thickness obtained by logging while drilling, and calculating the well-controlled proven natural gas reserves corresponding to the cumulative effective reservoir thickness.

[0036] When the effective thickness of the reservoir in logging while drilling is less than 1 meter ((h2-h1)<1), the single well control area corresponding to the effective reservoir bottom depth is obtained respectively The cumulative effective thickness of the reservoir is H, and the gas content ratio of unit volume of rock within the top and bottom depth range of the effective reservoir is C ug Maximum value, natural gas volume coefficient corresponding to the effective reservoir bottom depth (obtained through the gas state equation), substitute The cumulative proven natural gas reserves controlled by single wells in all reservoirs with effective thickness less than 1 meter can be calculated.

[0037] When the effective thickness of the reservoir in logging while drilling is greater than 1 meter ((h2-h1)≥1), the calculation is divided into two parts. The first part is the integral of the cumulative sum of unit depths less than 1 meter, that is, The second is the remaining part less than 1 meter, using The above analysis can be expressed by the following expression:

[0038]

[0039] Where G is the proven natural gas geological reserves of well-controlled gas reservoirs, billion cubic meters10 8 m 3 ; A is the gas-bearing area, square kilometers km 2 ; H is the effective thickness of the reservoir, m; C ug is the underground gas content ratio of unit volume of rock within the corresponding depth range, a dimensionless quantity; B is the corresponding natural gas volume coefficient, a dimensionless quantity; h1 and h2 are the top and bottom depths of the effective reservoir, respectively, in meters; Int is rounded. It can be seen from the above formula that to calculate the geologically proven reserves G of natural gas wells in well-controlled pure gas reservoirs, it is necessary to accurately determine the four items on the right side of the above formula, among which A can be used to determine the well-controlled gas content range by delineating the gas-bearing boundary. Well control methods, sedimentary microfacies prediction methods, and seismic reservoir lateral prediction methods are commonly used. H can be based on the effective thickness of the reservoir recorded in real time during the drilling logging process. The underground gas content ratio of unit volume of rock C ug The gas state equation is needed to convert the gas content in the surface drilling fluid into the gas content ratio per unit volume of underground rock. The natural gas volume coefficient B can be obtained through the gas state equation.

[0040] Preferably, step six is ​​specifically as follows: according to step five, the calculation results of multiple reservoirs within the depth range of the gas reservoir are accumulated; when the processing depth is less than the gas-water interface depth, steps one to five are calculated cyclically, and the proved geological reserves of the well-controlled natural gas obtained in each step are accumulated until the processing depth is equal to or greater than the gas-water interface, thereby obtaining the accumulated geological proved reserves of the natural gas wells in the gas reservoir.

[0041] The present invention also provides a system for calculating geological proven reserves of natural gas wells, characterized by comprising: a data input module for executing step 1; a surface gas volume calculation module for executing step 2; a formation gas volume calculation module for executing step 3; a rock gas content ratio determination module for executing step 4; and a proven reserves calculation module for executing step 5. Preferably, it also includes a data entry module and a result display module, such as a display screen, a computer terminal or a mobile phone terminal.

[0042] Compared with the prior art, the present invention has the following beneficial effects:

[0043] The present invention provides a method for calculating geological proven reserves of natural gas wells based on logging while drilling, which realizes real-time calculation of reservoir geological reserves by using logging while drilling data, improves calculation accuracy, reduces cost, overcomes the problem of decreased calculation accuracy caused by mud invasion based on post-drilling logging curves, and avoids the calculation of non-hydrocarbon gases. The method is calculated based on technical principles without any additional cost, and has great practical significance. The present invention can conveniently obtain the geological proven reserves of reservoirs in real time. Compared with the method based on logging curves after drilling, the present invention is more direct, convenient to calculate, fast and practical, with high accuracy, low cost, and easy to promote. BRIEF DESCRIPTION OF THE DRAWINGS

[0044] Figure 1 A schematic diagram of a flow chart of a method for calculating geological proven reserves of natural gas wells by logging while drilling provided in the present invention;

[0045] Figure 2 A standard generalized compression factor chart in an embodiment of the present invention;

[0046] Figure 3 It is the cumulative reservoir and reservoir reserves per unit thickness found by well-controlled geology of the natural gas well obtained in the embodiment of the present invention. DETAILED DESCRIPTION

[0047] The present invention is described below by means of specific embodiments to facilitate understanding of the present invention, but the present invention is not limited thereto.

[0048] like Figure 1 As shown, the method for calculating geological proven reserves of natural gas wells based on logging while drilling provided by the present invention has the following steps:

[0049] Step 1: The logging while drilling is displayed as the target reservoir, that is, the processing starts, and the logging while drilling gas measurement and well diameter (drill bit size) data of the depth interval are recorded.

[0050] Step 2: Calculate the gas volume V1 contained in the rock fragments per unit thickness under surface conditions.

[0051] The gas volume in the surface drilling fluid during drilling can be expressed as:

[0052] V1=10 -6 ×C ng ×ROP×Flow (1)

[0053] Among them, V1 represents the volume of gas contained in the rock fragments per unit thickness under surface conditions, in L; ROP is measured by the surface logging equipment, which represents drilling time, indicating the time spent drilling into the rock per unit thickness, in Min; Flow represents the displacement, which is equal to the sum of the circulating displacement of the drilling pump and the displacement of the booster pump, in L / Min; C ng Indicates the concentration of gas (hydrocarbon natural gas) in surface drilling fluid. C n Represents the gas measurement value of each hydrocarbon component, n = 1, 2, 3, 4, 5, unit ppm, E n Represents the degassing efficiency of each component, dimensionless. It should be pointed out that, compared with the traditional static volume method, the present invention only calculates the hydrocarbon gas content; k is the conversion coefficient of the gas flow rate analyzed by the gas testing equipment and the degasser displacement. For different logging degassing equipment and gas detection analyzers, the coefficient is different, and it is necessary to analyze the gas flow rate and the degasser displacement through the gas testing equipment.

[0054] Step 3: Calculate the gas volume V2 per unit thickness of rock under formation conditions based on the gas state equation

[0055] The gas state equation (2) can be used to convert the gas volume V1 contained in rock fragments per unit thickness under surface conditions into the gas volume V2 contained in rock per unit thickness under formation conditions, as follows:

[0056]

[0057] Among them, P, V, Z, and T represent pressure, volume, deviation compressibility coefficient, and temperature (absolute temperature, unit K) under different conditions, respectively. The subscript "1" represents the gas state under surface conditions, and the subscript "2" represents the gas state under formation conditions.

[0058] The various parameters in formula (2) can be obtained through the following process:

[0059] Gas pressure at target layer under formation conditions P2 = 0.0098*vertical depth of well H (m)×drilling fluid density ρ m (g / cm 3 ), unit is MPa; absolute temperature of target layer under formation conditions T2 = well depth h (m) × geothermal gradient G t (℃ / m)+273.15, unit is K; the deviation compressibility coefficient Z2 of gas under formation conditions can be obtained from the standard generalized compressibility factor chart; gas pressure P1 under surface conditions = 0.101325MPa; drilling fluid surface temperature T1 = drilling fluid outlet temperature T out (℃)+273.15, unit is K; the deviation compression coefficient Z1=1 under surface conditions.

[0060] Substituting the known parameters P1, V1, T1, Z1, P2, T2, and Z2 into equation (2), we can obtain the gas volume V2 contained in the rock per unit thickness under formation conditions:

[0061]

[0062] Step 4: Calculate the gas content ratio C per unit volume of rock under formation conditions ug .

[0063] The gas content ratio per unit volume of rock under formation conditions can be expressed as:

[0064]

[0065] Wherein, D is the borehole diameter (in mm), which can be directly obtained from the drill bit size data.

[0066] Further substituting formula (3) and its related parameters into formula (4), the gas content ratio per unit volume of rock under formation conditions can be obtained as:

[0067]

[0068] Step 5: Select a corresponding calculation formula based on the cumulative effective reservoir thickness obtained from logging while drilling to calculate the proven geological reserves of well-controlled natural gas corresponding to the cumulative effective reservoir thickness.

[0069]

[0070] Where G is the proven natural gas geological reserves of well-controlled gas reservoirs, billion cubic meters10 8 m 3 ; A is the gas-bearing area, square kilometers km 2 ; H is the effective thickness of the reservoir, m; C ug is the gas content ratio of unit volume of rock underground within the corresponding depth range, a dimensionless quantity; B is the corresponding natural gas volume coefficient, a dimensionless quantity; h1 and h2 are the top and bottom depths of the effective reservoir, respectively, in meters; Int is rounded. It can be seen from formula (6) that to calculate the geological proven reserves G of a pure gas reservoir controlled by a single well, it is necessary to accurately determine the four items on the right side of formula (6), among which A can be used to delineate the gas-bearing boundary through the sand body boundary of multiple wells to determine the gas-bearing range controlled by a single well; H can be based on the effective thickness of the reservoir recorded in real time during the logging process while drilling; the gas content ratio of unit volume of rock underground C ug The gas state equation is needed to convert the gas content in the surface drilling fluid into the gas content ratio of the underground unit volume of rock. The natural gas volume coefficient B can be obtained through the gas state equation.

[0071] When the effective thickness of the reservoir during logging while drilling is less than 1 meter, according to the first formula of formula (6), the single well control area corresponding to the effective reservoir bottom depth needs to be obtained: The gas-bearing boundary can be delineated by descending the boundaries of the sand bodies of multiple wells, and the gas-bearing range controlled by a single well can be determined. The cumulative effective thickness of the reservoir H is the gas content ratio of the unit volume of rock within the top and bottom depth range of the effective reservoir on the ground C ug Maximum value, natural gas volume coefficient corresponding to the effective reservoir bottom depth (obtained through the gas state equation), substitute The cumulative proven natural gas reserves controlled by single wells in all reservoirs with effective thickness less than 1 meter can be calculated.

[0072] When the effective thickness of the logging while drilling reservoir is greater than 1 meter, the calculation is divided into two parts according to the second formula of formula (6). The first part is based on the first half of formula (6), accumulating the cumulative sum of the proven reserves of natural gas in the reservoir per unit meter in the depth range from h1 to h2, where int(h2-h1) is the number of reservoirs of unit thickness in the depth range from h1 to h2, and the calculation starts from h1+m. The second part is based on the second half of formula (6), and the calculation process is the same as the case where the effective thickness of the logging while drilling reservoir is less than 1 meter, except that the integration range is changed from h1 to h2 to h1+int(h2-h1). + To h2.

[0073] Step 6. According to step 5, the calculation results of multiple reservoirs within the depth range of the gas reservoir are accumulated. When the processing depth is less than the gas-water interface depth, steps 1 to 5 are calculated repeatedly, and the proved geological reserves of well-controlled natural gas obtained in each step are accumulated until the processing depth is equal to or greater than the gas-water interface, thus obtaining the accumulated geological proved reserves of the natural gas wells in the gas reservoir.

[0074] In order to illustrate the process and results of the present invention, Figure 3 Given the well-controlled geological proven reserves calculation result of a specific natural gas well, the sandstone reservoir depth ranges from 2418.49 to 2464.7 meters, with a total effective reservoir thickness of 46.21 meters. The lithology is mainly muddy silt and siltstone. According to the above processing steps, the following formula (6) is selected for calculation, which is divided into two steps: from 2418.49 meters according to The reservoir thickness of 46 units is accumulated successively, up to 2464.49 meters.

[0075] According to the data shown in Table 1, the cumulative reserves are 11.059 billion cubic meters, and the remaining 0.21 meters are The calculated volume is 120 million cubic meters, of which the gas-bearing area A is 39.5 cubic kilometers. Using the volumetric method according to the formula G = 0.01 × A × H e ×Φ×(1-S wi ) / B giThe calculated well-controlled reserves are 13.229 billion cubic meters (gas-bearing area A is 39.5 cubic kilometers, effective reservoir thickness is 46.21 meters, effective porosity is 10.4%, and gas saturation is 27.8%). The results calculated by the two methods are consistent in magnitude. The entire calculation process is efficient and fast, and the results are reliable.

[0076] Table 1 Logging data and related calculation parameters used in the embodiment of the present invention

[0077]

[0078] The present invention can also be implemented by a system for calculating geological proven reserves of natural gas wells, the system comprising: a data input module for executing step 1; a surface gas volume calculation module for executing step 2; a formation gas volume calculation module for executing step 3; a rock gas content ratio determination module for executing step 4; and a proven reserves calculation module for executing step 5. Preferably, it also includes a data entry module and a result display module, such as a display screen, a computer terminal or a mobile phone terminal.

Claims

1. A method for calculating geological proven reserves of natural gas wells based on logging while drilling, characterized in that: The steps include: Step 1: Determine the starting depth of the target reservoir according to the logging while drilling display, and record the logging while drilling gas logging and well diameter data of the depth interval; Step 2: Calculate the volume of gas contained in rock fragments per unit thickness under surface conditions based on ground measurement data; Step 3: Calculate the gas volume per unit thickness of rock under formation conditions according to the gas state equation; Step 4: Calculate the gas content ratio of unit volume of rock under formation conditions; Step 5: Select a corresponding calculation formula based on the cumulative reservoir thickness of logging while drilling to calculate the well-controlled natural gas geological reserves corresponding to the cumulative reservoir thickness; Step 6: Accumulate the proven reserves of natural gas in the well-controlled pure gas reservoir within the processing depth range; The specific step 5 is: selecting a corresponding calculation formula according to the cumulative reservoir thickness of the well logging while drilling, and calculating the well-controlled natural gas geological proven reserves corresponding to the cumulative reservoir thickness; When the reservoir thickness of logging while drilling is less than 1 meter, that is, (h2-h1)<1, the single well control area corresponding to the effective reservoir bottom depth is obtained respectively. The cumulative thickness of the effective reservoir is H, and the gas content ratio of the unit volume of rock within the top and bottom depth range of the effective reservoir is C ug Maximum value, natural gas volume coefficient corresponding to the effective reservoir bottom depth obtained by the gas state equation Substitution Calculate the cumulative proven natural gas reserves of all wells with a reservoir thickness of less than 1 meter; When the reservoir thickness of the logging while drilling is greater than 1 meter, that is, (h2-h1)≥1, the calculation is divided into two parts. The first part is the cumulative sum of unit depths less than 1 meter, that is, The second is the remaining part less than 1 meter, using Calculated; specifically, it is expressed as follows: Where G is the proven natural gas geological reserves of the well-controlled gas reservoir, in units of 100 million cubic meters; A is the gas-bearing area, in units of square kilometers; H is the effective thickness of the reservoir, in units of meters; C is the gas-bearing area, in units of square kilometers; ug is the gas content ratio of unit volume of rock underground within the corresponding depth range, a dimensionless quantity; B is the corresponding natural gas volume coefficient, a dimensionless quantity; h1 and h2 are the top and bottom depths of the effective reservoir, respectively, in meters; Int is rounding; A is the gas-bearing boundary delineated to determine the gas-bearing range of the well control; H is based on the effective thickness of the reservoir recorded in real time during the logging while drilling process; C is the gas content ratio per unit volume of rock underground ug The gas state equation is needed to convert the gas content in the surface drilling fluid into the gas content ratio per unit volume of underground rock; the natural gas volume coefficient B is obtained through the gas state equation.

2. The method according to claim 1, characterized in that Step 1 is as follows: according to the lithology analysis of the drilling logging in the study area, the starting depth of the gas reservoir is determined, and the average value of the drilling logging gas logging and well diameter in the corresponding depth interval is recorded.

3. The method according to claim 1 or 2, characterized in that Step 2 is specifically as follows: calculate the gas volume V1 contained in the rock fragments per unit thickness under surface conditions; Specific area, V1 = 10 -6 ×C ng ×ROP×Flow Among them, V1 is in L; ROP is measured by the surface logging equipment and represents drilling time, which means the time spent drilling into the rock of unit thickness, in Min; Flow represents displacement, which is equal to the sum of the circulation displacement of the drilling pump and the displacement of the booster pump, in L / Min; C ng Indicates the concentration of hydrocarbon natural gas in surface drilling fluid. C n Represents the gas measurement value of each hydrocarbon component, n = 1, 2, 3, 4, 5, the unit is ppm, E n Represents the degassing efficiency of each component and is dimensionless; k is the conversion factor between the flow rate of the gas analyzed by the gas testing equipment and the displacement of the degasser.

4. The method according to claim 3, characterized in that Step three is as follows: calculate the gas volume V2 contained in the rock per unit thickness under formation conditions according to the gas state equation; Specifically, the gas volume V1 contained in rock fragments per unit thickness under surface conditions can be converted into the gas volume under formation conditions through the gas state equation, as follows: Among them, the unit of V2 is L, P, V, Z, and T represent pressure, volume, deviation compressibility, and absolute temperature under different conditions, respectively. The unit of absolute temperature is K. The subscript "1" represents the gas state under surface conditions, and the subscript "2" represents the gas state under formation conditions. The various parameters in the formula are obtained through the following process: The target layer gas pressure P2 under formation conditions = vertical depth of the well 0.0098 × H (m) × drilling fluid density ρ m (g / cm 3 ), unit is MPa; absolute temperature of target layer under formation conditions T2 = well depth h (m) × geothermal gradient G t (℃ / m)+273.15, unit is K; the deviation compressibility coefficient Z2 of gas under formation conditions can be obtained from the standard generalized compressibility factor chart; gas pressure P1 under surface conditions = 0.101325MPa; drilling fluid surface temperature T1 = drilling fluid outlet temperature T out (℃)+273.15, unit is K; under surface conditions, the deviation compression coefficient Z1=1; Furthermore, by substituting the known parameters P1, V1, T1, Z1, P2, T2, and Z2 into the above formula, we can obtain the gas volume V2 contained in the rock per unit thickness:

5. The method according to claim 4, characterized in that Step 4 is as follows: Calculate the gas content ratio C per unit volume of rock under formation conditions ug : Where D is the borehole diameter, in mm, which can be directly obtained from the drill bit size data; Further substitute V2 and the P1, V1, T1, Z1, P2, T2, and Z2 parameters involved in V2 into the above C ug The specific calculation formula for the gas content ratio per unit volume of rock under formation conditions is obtained from the formula as follows:

6. The method according to claim 5, characterized in that The method for determining A uses well control method, sedimentary microfacies prediction method, and seismic reservoir lateral prediction method.

7. The method according to claim 6, characterized in that Step six is ​​as follows: according to step five, the calculation results of multiple reservoirs within the depth range of the gas reservoir are accumulated; when the processing depth is less than the gas-water interface depth, steps one to five are calculated cyclically, and the proved geological reserves of well-controlled natural gas obtained in each step are accumulated until the processing depth is equal to or greater than the gas-water interface, thus obtaining the accumulated proven geological reserves of the natural gas wells in the gas reservoir.

8. A system for calculating geologically proven reserves of natural gas wells, characterized in that: The method comprises a functional module for executing the method according to any one of claims 1 to 7.

9. The system for calculating geologically proven reserves of natural gas wells according to claim 8, characterized in that: include: A data input module for executing step 1; A surface gas volume calculation module for executing step 2; A formation gas volume calculation module for executing step three; a rock gas content ratio determination module for executing step four; and a proven reserves calculation module for executing step five.

10. The system for calculating geologically proven reserves of natural gas wells according to claim 8, characterized in that: It also includes a data entry module and a result display module.

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