A method and device for predicting coalbed gas reserves based on drilling data

Abstract

The present application relates to coal bed gas reserves prediction technical field, especially in kind based on while drilling data prediction coal bed gas reserves's method and device, the method, including real-time acquisition while drilling data with mud logging sensor, the effective gas volume that returns to wellhead in different time period is measured in real time through wellhead gas metering device, the effective gas is methane gas, the late time is calculated based on the physical property parameter of drilling fluid and effective gas, and the depth of well is returned to the position by using late time to while drilling data and effective gas volume;Based on the total hydrocarbon value measured in each period and effective gas volume, the coal bed gas volume corresponding to the period is calculated, the total volume of coal bed gas under the surface temperature and pressure condition is converted into the equivalent coal bed gas volume under the buried state of underground, the coal bed gas reserves contained in unit volume of coal rock is obtained, the present application can fully utilize the while drilling data obtained on site, realize the rapid and continuous prediction of coal bed gas content, and finally evaluate the coal bed gas reserves of the whole coal bed.

Description

Technical Field

[0001] This invention relates to the field of coalbed methane reserve prediction technology, and in particular to a method and apparatus for predicting coalbed methane reserves based on drilling data. Background Technology

[0002] In recent years, with major breakthroughs in the exploration and development of deep coalbed methane, coalbed methane has become an important strategic replacement resource for natural gas reserves and production. Accurate prediction of coalbed methane reserves is directly related to the design quality of production capacity construction plans and the scientific nature of investment decisions. Excessive deviations in reserve prediction can easily lead to the failure of development plans and significant economic losses. Currently, engineering technicians mainly rely on a combination of static geological methods and dynamic methods such as well logging and pilot production to predict coalbed methane reserves. Among these, the most widely used method is the gas content method based on isothermal adsorption experiments on coal samples. This involves measuring the Langmuir volume and Langmuir pressure parameters of coal samples in the laboratory, and then calculating geological reserves by combining parameters such as coal seam thickness, density, and gas-bearing area. In addition, some blocks also use methods such as coal core desorption, volumetric methods, well logging interpretation, and production dynamic analysis to correct and verify the reserve results.

[0003] However, current methods for predicting coalbed methane reserves generally suffer from the following shortcomings in field engineering practice: First, they are highly dependent on laboratory coal samples and have long testing cycles. Due to the significant heterogeneity of coalbed methane, a small number of coal samples cannot accurately reflect the gas-bearing characteristics of the entire well section. Furthermore, isothermal adsorption experiments and desorption tests are time-consuming, making it impossible to achieve real-time evaluation while drilling and failing to meet the needs of rapid decision-making on site. Second, the correspondence between gas logging data and well depth is difficult to determine accurately. During drilling, there is a lag time between the gas returning from the bottom of the well to the wellhead. Existing theoretical calculation models fail to fully consider the changes in the physical properties of drilling fluid and gas in the downhole temperature and pressure environment, resulting in insufficient data positioning accuracy. Third, in the development mode of long horizontal wells, traditional logging operations are difficult to carry out due to the limitations of the well structure. The application conditions of existing dynamic analysis methods are limited, making it impossible to achieve continuous prediction of coalbed methane reserves in long well sections. At present, a method and device for predicting coalbed methane reserves based on drilling data is needed. Summary of the Invention

[0004] To address the problems of existing technologies, such as heavy reliance on laboratory coal sample testing, long testing cycles, and difficulty in reflecting reservoir heterogeneity, this invention provides a method and apparatus for predicting coalbed methane reserves based on drilling data.

[0005] In a first aspect, the present invention provides a method for predicting coalbed methane reserves based on drilling data, which adopts the following technical solution: A method for predicting coalbed methane reserves based on drilling data includes: Real-time data acquisition while drilling is performed using logging sensors. The data includes well depth, drilling time, mechanical drilling rate, and total hydrocarbon gas measurement parameters. The effective gas volume returned from the wellhead at different times is measured in real time using a wellhead gas metering device. The effective gas is a methane-containing gas; The lag time is calculated based on the physical properties of drilling fluid and effective gas, and the lag time is used to reposition the well depth based on the drilling data and effective gas volume. Based on effective gas volume Total hydrocarbon values ​​measured at various time periods Calculate the coalbed methane volume for the corresponding time period. This allows us to obtain the total volume of coalbed methane in the coal-rock section under surface temperature and pressure conditions. ; The total volume of coalbed methane under surface temperature and pressure conditions is determined using the gas law. Equivalent coalbed methane volume converted to underground burial conditions The coalbed methane reserves per unit volume of coal were obtained. ; Coalbed methane reserves per unit volume of coal The total coalbed methane reserves contained in the entire coal seam Make predictions.

[0006] Furthermore, the calculation of the delay time based on the physical properties of the drilling fluid and the effective gas includes establishing an acceleration integral model based on gas return dynamics, and determining the acceleration of the gas during the annular return process based on the density and viscosity differences between the drilling fluid and the returned gas. ; Collect effective gas return rate at the wellhead and initial circulation rate of drilling fluid An integral constraint equation based on motion acceleration is established, and the integral constraint equation is solved by inversion using a numerical iterative algorithm to calculate the time lag required for gas to travel from the bottom of the well to the wellhead. The integral constraint equation is: ; in, The density difference between the gas and liquid phases Due to the viscosity difference between the gas and liquid phases, The effective gas return velocity measured at the wellhead. The initial velocity of the drilling fluid. The flow time of gas transport in the annulus. This indicates that the acceleration is determined by the density difference, viscosity difference, and flow time.

[0007] Furthermore, the calculation of the density and viscosity differences between the drilling fluid and the returned gas includes acquiring real-time downhole pressure and temperature parameters, and calculating the current drilling fluid viscosity and density based on the drilling fluid rheological properties. The calculation formulas for the drilling fluid viscosity and density are as follows: ; ; in, For drilling fluid viscosity under surface conditions, For ground reference pressure, Ground reference temperature The pressure sensitivity coefficient, For temperature sensitivity coefficient, For downhole pressure, The temperature is the temperature at the bottom of the well. The density of drilling fluid under downhole conditions. The density of drilling fluid under surface conditions. The compression factor is 1. is the coefficient of thermal expansion.

[0008] Furthermore, the calculation of the density difference and viscosity difference between the drilling fluid and the returned gas also includes obtaining the pressure P, temperature T and compressibility factor Z of the methane gas at the downhole location, calculating the effective gas density based on the current downhole conditions, and calculating the gas-liquid two-phase density difference based on the drilling fluid density. The molar mass of methane gas is determined based on the methane composition in the wellhead return gas, and the effective gas viscosity is calculated based on the molar mass. This leads to the gas-liquid two-phase viscosity difference. Based on the density and viscosity differences between the gas and liquid phases, a correction parameter for the gas-liquid two-phase slip velocity is established. The formula for calculating the effective gas viscosity is as follows: ; in, The viscosity of the effective gas, , and This is an empirical coefficient. Where is the density of the effective gas, and T is the downhole temperature.

[0009] Furthermore, the method of using the delay time to re-establish the well depth based on the drilling data and effective gas volume includes collecting the time when the effective gas returns to the wellhead. And based on the return time and late time The time difference relationship determines the time when the drill bit reaches the corresponding well depth. Based on drilling time Establish a mapping relationship between drilling data and well depth, and reorient the drilling data and effective gas volume to the drilling time. The corresponding well depth.

[0010] Furthermore, the calculation of the coalbed methane volume for the corresponding time period includes collecting the total hydrocarbon values ​​for each time period after well depth repositioning. and the effective gas volume for the corresponding time period , to increase the total hydrocarbon value With effective gas volume Perform multiplication to obtain the coalbed methane volume for each time period. The volume of coalbed methane at each time period within the drilled coal and rock section. By summing the results, the total volume of coalbed methane in this coal-rock section under the surface temperature and pressure conditions can be obtained. .

[0011] Furthermore, obtaining the coalbed methane reservoir per unit volume of coal includes determining the pressure, temperature, and compressibility factor under both surface and underground burial conditions, collecting the drill bit cross-sectional area S and the drilling section length H, and calculating the volume of fractured coal. The equivalent coalbed methane volume With the volume of broken coal and rock By performing ratio calculations, the coalbed methane reserves per unit volume of coal can be obtained. The equivalent coalbed methane volume The conversion formula is: ; in, This represents the equivalent volume of coalbed methane in its underground burial state. This refers to the total volume of coalbed methane under surface temperature and pressure conditions. For surface pressure, For underground burial pressure, For surface temperature, For underground temperature, The surface compressibility factor. It is the underground compressibility factor.

[0012] Furthermore, the prediction of the total coalbed methane reserves contained in the entire coal seam includes determining the coal seam thickness h and the gas-bearing area A based on well logging interpretation data and geological exploration data, and calculating the geological volume using the coal seam thickness h and the gas-bearing area A. Based on the coalbed methane reserves per unit volume of coal and rock With geological volume By performing multiplication, the total coalbed methane reserves contained in the entire coal seam can be obtained. .

[0013] Secondly, an apparatus for predicting coalbed methane reserves based on drilling data includes: The closed gas production system is equipped with a closed gas collection hood, a rigid support frame, a flexible sealing layer and a pneumatic clamping mechanism, and is used to seal and collect methane-containing effective gas returning from the wellhead. The gas-liquid separation system, connected to the closed gas production system, adopts a vertical cylindrical structure and has multiple baffles or swirl components inside for separating gas and drilling fluid. A flow stabilization buffer system, connected to the gas-liquid separation system, adopts a horizontal cylindrical structure and is used to absorb gas flow turbulence; The dual-range flow meter system, connected to the flow stabilization buffer system, consists of a large flow meter, a small flow meter, and parallel pipelines. It achieves continuous metering under different gas volume conditions through a switching valve. The temperature and pressure correction system is used to collect gas pressure and temperature data in real time and convert the working volume into the standard volume under the surface temperature and pressure conditions. The data processing unit is used to establish a late arrival time calculation model, perform coalbed methane volume calculation, and reserve prediction.

[0014] Furthermore, the flexible sealing layer achieves dynamic bonding and sealing with the wellhead flange through the pneumatic clamping mechanism, and the sealing pressure of the sealing layer is controlled within the range of 0.1~0.3MPa.

[0015] In summary, the present invention has the following beneficial technical effects: 1. This invention utilizes existing logging sensors at the well site to collect drilling data in real time, and combines this with a wellhead gas metering device to measure the volume of returned effective gas in real time. This enables rapid and continuous prediction of coal seam gas content without increasing additional testing costs or relying on complex downhole instruments, significantly shortening the reserve evaluation cycle and improving the timeliness of on-site decision-making.

[0016] 2. This invention establishes a delay time calculation model based on the physical properties (viscosity, density) of drilling fluid and returned gas, and uses the acceleration integral equation to invert and solve the delay time, thereby achieving accurate alignment of time-domain gas logging data and return volume with well depth. This overcomes the defect that traditional theoretical delay time formulas cannot accurately reflect the slippage and migration characteristics of gas in drilling fluid, and improves the accuracy of the correspondence between drilling gas logging data and formation depth.

[0017] 3. This invention obtains the surface coalbed methane volume by multiplying the total hydrocarbon value after repositioning by the effective gas volume and summing them up. Then, it uses the gas state equation to convert the volume under surface temperature and pressure conditions into the equivalent volume under underground burial conditions. Combined with drilling parameters, it calculates the gas content per unit volume of coal and rock, thus realizing the accurate inversion from surface measurement data to the actual underground reserves, providing reliable data support for the calculation of coalbed methane geological reserves.

[0018] 4. This invention, through the design of a wellhead gas metering device including a closed gas production system, a gas-liquid separation system, a flow stabilization buffer system, a dual-range flow meter system, and a temperature and pressure correction system, achieves continuous and accurate measurement of the effective gas volume returned under different gas volume conditions, providing key basic data support for reserve prediction based on drilling data. Attached Figure Description

[0019] Figure 1 This is a flowchart of a method for predicting coalbed methane reserves based on drilling data provided in an embodiment of the present invention; Figure 2 This is a flowchart of the wellhead gas volume metering device provided by the present invention; Figure 3 It is a dot-line graph showing the changes in effective gas volume and total hydrocarbons with well depth in the 2500m~2600m coal seam section after drilling into a certain well, measured by a wellhead volume metering device. Detailed Implementation

[0020] The present invention will be further described in detail below with reference to the accompanying drawings.

[0021] Example 1 Reference Figure 1 This embodiment of a method for predicting coalbed methane reserves based on drilling data includes: S1. Real-time acquisition of drilling data using logging sensors, including well depth, drilling time, mechanical drilling rate, and total hydrocarbon gas measurement parameters; S2. Real-time measurement of the effective gas volume returned from the wellhead at different times using a wellhead gas metering device. The effective gas is a methane-containing gas; S3. Calculate the late arrival time based on the physical property parameters of drilling fluid and effective gas, and use the late arrival time to reposition the well depth based on the drilling data and effective gas volume. S4, Based on effective gas volume Total hydrocarbon values ​​measured at various time periods Calculate the coalbed methane volume for the corresponding time period. This allows us to obtain the total volume of coalbed methane in the coal-rock section under surface temperature and pressure conditions. ; S5. Using the gas state equation, calculate the total volume of coalbed methane under surface temperature and pressure conditions. Equivalent coalbed methane volume converted to underground burial conditions The coalbed methane reserves per unit volume of coal were obtained. ; S6. Coalbed methane reserves per unit volume of coal and rock The total coalbed methane reserves contained in the entire coal seam Make predictions.

[0022] Specifically, a method for predicting coalbed methane reserves based on drilling data includes the following steps: like Figure 1 As shown, S1, Drilling data acquisition: Utilizing the existing integrated logging system at the well site, drilling data is acquired in real time during the drilling process using various types of logging sensors deployed at the drill platform, mud outlet, and instrument room. Specifically, a depth encoder is installed at the drill hook. By monitoring changes in the hook height and combining this with drill string assembly length data, the current well depth parameter H at the drill bit's location is calculated and recorded in real time. The well depth H is determined using the formula... The calculation yielded, where This represents the current column length. For the descent height of the large hook, The length from the bottom of the drill string assembly to the drill bit; Install speed and torque sensors on the drilling rig rotary table or top drive, and calculate the mechanical drilling rate by combining the change in well depth per unit time. The mechanical drilling speed The calculation formula is ,in This represents the change in well depth per unit time, expressed in meters (m). The corresponding time interval is in minutes; the drilling time required to drill each unit of well depth is automatically recorded by the drilling time recorder. Drilling time parameters, typically recorded as the time per meter of drilling, are... With mechanical drilling speed They are reciprocals of each other, satisfying A gas logging tool is installed at the mud outlet trough at the wellhead. The degasser is used to continuously degas the returned drilling fluid. The components of the degassed gas are analyzed by an infrared spectrometer or a hydrogen flame ionization detector. The total hydrocarbon value C is measured and recorded in real time. The total hydrocarbon value C represents the volume percentage of total hydrocarbons in the returned gas, in %. The data acquisition frequency is synchronized with the well depth recording frequency to ensure time sequence correspondence. It is preferred to record once every 0.1m or every 10s. During data acquisition, the sensor range is rationally selected based on the predicted gas content of the formation at the current well site. For total hydrocarbon detection sensors, the upper limit of the range should not be lower than 120% of the predicted maximum gas content, and the lower limit should not be higher than 80% of the predicted minimum gas content, to avoid measurement distortion caused by operating beyond or below the range. All acquired drilling data is transmitted in real time to the data processing unit via wired or wireless transmission and stored synchronously according to a unified timestamp to establish a drilling dataset. ,in The data acquisition timeframe provides the foundational time-series data for subsequent delay time calculations and data relocation.

[0023] S2. During drilling, a wellhead gas metering device located at the wellhead mud outlet is used to collect, separate, stabilize, meter, and correct the effective methane-containing gas returning to the wellhead at different times in real time, ultimately obtaining the effective gas volume under various surface temperature and pressure conditions. ; Specifically, the effective gas volume returned from the wellhead at different times is measured in real time using a wellhead gas metering device. The effective gas is methane-containing gas; the wellhead gas metering device includes a closed gas production system, a gas-liquid separation system, a flow stabilization buffer system, a dual-range flow meter system, a temperature and pressure correction system, and a data acquisition unit, with each system connected in series via a pressure-resistant sealed pipeline.

[0024] The closed-loop gas production system includes a closed gas collection hood, a rigid support frame, a flexible sealing layer, and a pneumatic clamping mechanism. The rigid support frame is made of corrosion-resistant high-strength alloy steel or stainless steel, and the flexible sealing layer is made of fluororubber or oil-resistant and high-temperature-resistant elastic material. The pneumatic clamping mechanism achieves dynamic contact and sealing with the wellhead flange, with the sealing pressure controlled at 0.1... Within the range of 0.3 MPa, the outlet end of the closed gas collection hood is connected to the inlet of the gas-liquid separation system through a pressure-resistant sealed pipe; the gas-liquid separation system adopts a vertical cylindrical structure, with multiple baffles or swirl components inside, used to reduce the flow velocity of the gas-liquid mixture and change the flow direction to achieve gas-liquid separation. The separated liquid phase is discharged into the mud tank through the bottom drain port, and the gas phase is connected to the inlet of the flow stabilization buffer system through the top outlet and a sealed pipe.

[0025] The flow stabilization and buffer system adopts a horizontal cylindrical structure, consisting of a flow stabilization and buffer tank, an inlet port, and an outlet port. It is used to absorb instantaneous pulsations of gas at the wellhead to reduce the impact of flow fluctuations on measurement accuracy. Its outlet is connected to the inlets of the large and small flow meters in the dual-range flow meter system via a split pipeline. The dual-range flow meter system consists of a large flow meter, a small flow meter, and parallel pipelines. The flow meters are selected as thermal mass flow meters or vortex flow meters. Continuous and accurate measurement under different gas flow conditions is achieved through a switching valve or automatic control unit. The outlets of the two flow meters merge and enter the temperature and pressure correction system through a unified pipeline. The temperature and pressure correction system consists of a pressure sensor, a temperature sensor, and mounting connectors, used to collect gas pressure in real time. With temperature data.

[0026] The data acquisition unit is connected to the flow meter, pressure sensor, and temperature sensor via signal lines, and calculates the operating volume based on the gas state equation. Standard volume converted to surface temperature and pressure conditions The conversion formula is as follows: ,in, The standard atmospheric pressure is 0.1013 MPa. The standard temperature is 298.15K. , These are the compressibility factors under standard and operating conditions, respectively, to achieve the effective gas volume returned from the wellhead at different times. Real-time measurement and recording.

[0027] Preferably, a methane sensor and a fluid reversing control valve are installed at the front end of the closed gas production system. When the methane sensor detects that the returned drilling fluid contains methane, the fluid reversing control valve switches the drilling fluid flow path to the closed gas production system, allowing the methane-containing gas to enter the metering process. When no methane is detected, the drilling fluid flow path is switched to the bypass channel and directly enters the mud pit, achieving energy-saving operation.

[0028] S3. Delay Time Calculation and Data Reset: Obtain the coalbed methane delay time and reset the drilling data and well depth. It should be noted that there are three methods for obtaining the coalbed methane delay time: The first method involves calculation based on theoretical formulas. This method calculates the theoretical delay time based on the drilling fluid circulation rate and the annular geometric volume of the wellbore. The calculation formula is as follows: ,in, The theory is that it is late. Here, D is the mud pump displacement, d is the wellbore diameter, d is the drill pipe outer diameter, H is the well depth, and V is the annular volume of the wellbore; for ease of field application, it can be converted into a simplified formula. In this case, D and d can be in inches, Q in L / s, H in meters, and T in minutes. The second method involves using indicators to determine the coalbed methane arrival time. First, the wellhead pipeline delay time (generally 1 minute) must be determined. The first method is to determine the marker descent time (3 min), then determine the marker descent time (determined by the ratio of the total drill string volume to the total displacement), and finally determine the delay time based on the marker's one-cycle time; the third method is the gas measurement data delay time calculation model based on physical property parameters established in this embodiment (preferred implementation).

[0029] It is important to note that the first method described above is actually a calculation of the drilling fluid's delay time, not a precise calculation of the delay time of cuttings or gas. This is because cuttings sink due to gravity and gas rises due to buoyancy, leading to discrepancies between the theoretical calculation and the actual result. This method is only used as a benchmark to judge the accuracy of the measured delay time. The second method can only be used for rapid drilling in special rock types and at specified intervals of 100m or 150m, and cannot achieve real-time continuous calculation. In contrast, this embodiment adopts the third method, which calculates the delay time based on the physical properties of drilling fluid and effective gas. This method can calculate the gas logging data delay time in real time and continuously, and specifically includes the following sub-steps: Pressure and temperature composite sensors deployed at different depths in the wellbore annulus are used to collect pressure data at various measuring points downhole in real time. With temperature A first calculation model was established based on the rheological properties of drilling fluid to calculate the viscosity of drilling fluid under downhole conditions. The first calculation model is In the formula The viscosity of drilling fluid under downhole conditions, in units of... , Viscosity of drilling fluid under surface conditions, in units of... , This is the pressure sensitivity coefficient, with units of 1 / MPa. Temperature sensitivity coefficient, unit: , , These represent the pressure under downhole and surface conditions, respectively, in MPa. , Temperatures under downhole and surface conditions, respectively, in units of C; A second calculation model is established based on the compressibility characteristics of drilling fluid to calculate the drilling fluid density under downhole conditions. The second calculation model is In the formula This refers to the density of drilling fluid under downhole conditions, expressed in kg / m³. Density of drilling fluid under surface conditions, in units of , The compressibility factor is expressed in units of 1 / MPa. The coefficient of thermal expansion is given by 1000 ppm. .

[0030] Obtain the pressure at the downhole location of the methane gas. ,temperature and compressibility factor Establish the gas state equation to calculate the effective gas density. The gas state equation In the formula This is the density of methane gas, in units of... Z is the compressibility factor, which is dimensionless, and is applied when the pressure is 10. At 20 MPa, take 0.92. 1.05; Determine the molar mass of methane gas based on the methane composition of the gas returned from the wellhead. A gas viscosity calculation model was established and the effective gas viscosity was calculated. The gas viscosity calculation model is as follows: In the formula Effective gas viscosity, in mPa. s, , and The empirical coefficient is the empirical coefficient, derived from the formula. , , Let T be the downhole temperature, in Kelvin (K); based on the aforementioned drilling fluid density... With effective gas density Calculate the density difference between the gas and liquid phases Based on the aforementioned drilling fluid viscosity With effective gas viscosity Calculate the viscosity difference between the gas and liquid phases Establish parameters for correcting the slip velocity of the gas-liquid two-phase system.

[0031] An acceleration integral model is established based on gas retraction dynamics, according to the density difference. viscosity difference The acceleration of the gas during the annular return process is determined by the flow time t. a The acceleration a Represented as a functional relationship The effective gas return velocity v is collected in real time by a flow meter installed at the outlet of the wellhead gas metering device, and the data is then analyzed by the mud pump discharge rate Q and the cross-sectional area of ​​the wellbore annulus. Calculate the initial circulation rate of drilling fluid The annular cross-sectional area Where D is the wellbore diameter, d is the drill pipe outer diameter, and the initial velocity of the drilling fluid is... Establish integral constraint equations based on motion acceleration. In the formula The time of lateness is expressed in seconds (s). The acceleration during the gas retraction process, in units of . And the acceleration For the aforementioned density difference viscosity difference and time The function, The effective gas return velocity measured at the wellhead, in m / s. The initial velocity of the drilling fluid is given in m / s. The integral constraint equation is solved numerically using computer programming techniques through iterative inversion to calculate the time required for gas to travel from the bottom of the well to its return from the wellhead. .

[0032] Preferably, a dual verification mechanism is used to verify the lateness time. The accuracy is ensured by: firstly, through wellhead gas injection simulation experiments, injecting methane gas of known volume and concentration into the drilling fluid circulation system, recording the time difference between the injection time and the time when the gas is detected at the wellhead, and comparing it with the late time calculated by the model to verify the model calculation error; secondly, using the measured late time data of historical wells to correct the model parameters, ensuring that the accuracy of the late time calculation meets the engineering requirements.

[0033] The moment when effective gas is collected and returned to the wellhead According to the return time With the aforementioned late time The time difference relationship determines the time when the drill bit reaches the corresponding well depth. The drilling time The calculation formula is Using the drilling time Find the well depth at the corresponding timestamp in the drilling data set. H Establish a mapping relationship between drilling data and well depth, and combine the drilling data collected in step S1 with the effective gas volume measured in step S2. The data is returned to the formation location corresponding to the well depth H, achieving precise matching between gas logging data and well depth, and forming a continuous vertical gas content data profile based on the well depth.

[0034] S4. Effective gas volume after well depth repositioning Total hydrocarbon values ​​for each time period Calculate the coalbed methane volume for the corresponding time period. Then, by summing up, the total volume of coalbed methane in that coal-rock section under the surface temperature and pressure conditions can be obtained. ; like Figure 3 As shown, the total hydrocarbon values ​​for each time period were collected after the well depth relocation process in step S3. and the effective gas volume for the corresponding time period To ensure the total hydrocarbon value With effective gas volume A dataset was established that strictly corresponds to the time series and well depth. Where i represents the time period number, , The total number of drilling periods in this coal and rock section; the total hydrocarbon value. Measured by a gas logging instrument, it represents the volume concentration of total hydrocarbon gases in the returned gas. When expressed as a percentage, it needs to be converted to decimal form for subsequent calculations. This embodiment uses a well as shown in Table 1 at 2640m. Taking the 2650m well section as an example, the logging data generated during normal drilling of this section includes date, well depth, vertical depth, and drilling time. Return time Drilling time, total hydrocarbon value (C), and heavy hydrocarbon value were recorded, with 10 whole-meter intervals recorded from well depth to 2640.00m to 2650.00m. Table 1. Partial logging gas measurement data of a well during normal drilling in the 2640~2650m section;

[0035] The drilling time for each meter segment is approximately 1.1 seconds. 2.1 min / m, the calculated late time is approximately 39 minutes, which is acceptable. The drilling time corresponding to each meter segment is calculated, achieving accurate alignment of total hydrocarbon data with well depth.

[0036] Then, the coalbed methane volume is calculated for each time period: the total hydrocarbon value for each time period is calculated. Effective gas volume for the corresponding time period Perform multiplication to calculate the coalbed methane volume for each time period. The calculation formula is as follows: In the formula Let be the volume of coalbed methane in the i-th time period; The effective gas volume after temperature and pressure correction in the i-th time period; Let be the total hydrocarbon value measured in the i-th time period, dimensionless; the physical meaning of this multiplication operation is: within the effective gas volume In this context, the volume proportion of methane gas is determined by the total hydrocarbon value. The product of these two characteristics represents the volume of pure coalbed methane returned during that period.

[0037] Finally, the overall accumulation and calculation of the coal and rock section is performed: the coalbed methane volume at each time period within the drilled coal and rock section is calculated. By summing the results, the total volume of coalbed methane in this coal-rock section under the surface temperature and pressure conditions can be obtained. The accumulation formula is: In the formula The total volume of coalbed methane in the coal-rock section under surface temperature and pressure conditions; n is the total number of drilling time periods in the coal-rock section; preferably, the division of the time periods is determined based on drilling time data, with each unit drilling depth (e.g., per meter or per 0.5 meters) constituting one time period, or based on time intervals (e.g., every 30 seconds or every minute) constituting one time period, ensuring that the time period division matches the total hydrocarbon detection frequency and the effective gas volume measurement frequency, and that the total volume of the coal-rock section... This represents the cumulative volume of coalbed methane returned during each period of drilling into the coal and rock section, signifying the total amount of coalbed methane released by the coal and rock section under surface temperature and pressure conditions.

[0038] S5. Using the gas state equation, calculate the total volume of coalbed methane under surface temperature and pressure conditions. Equivalent coalbed methane volume converted to underground burial conditions Calculate the volume of fractured coal and rock by combining drilling parameters. The coalbed methane reserves per unit volume of coal can be obtained through ratio calculation. ; First, the underground state parameters and equivalent volume conversion are determined: the pressure under the surface temperature and pressure conditions is determined respectively. ,temperature and compressibility factor and the pressure under underground burial conditions ,temperature and compressibility factor The surface pressure mentioned above Taking standard atmospheric pressure as 0.1013 MPa, the surface temperature... Take 298.15K, the surface compressibility factor Take 1; the underground burial pressure It is determined by the difference between overlying rock pressure and pore pressure, and the calculation formula is as follows: The overlying rock pressure From the formula Calculate, where Where is the overburden density, g is the gravitational acceleration, H is the coal seam burial depth, and the pore pressure is... Determined by actual measurements or empirical formulas; The underground temperature Determined by geothermal gradient and burial depth, the calculation formula is as follows: In the formula, G represents the geothermal gradient, and its commonly used value range is... The underground compressibility factor When no measured data is available, a value of 1 is used; a volume conversion model is established based on the ideal gas law to calculate the total volume of coalbed methane under the stated surface temperature and pressure conditions. Equivalent coalbed methane volume converted to underground burial conditions The gas state equation is: In the formula This represents the equivalent volume of coalbed methane in its underground burial state. This refers to the total volume of coalbed methane under surface temperature and pressure conditions. These are surface pressure, surface temperature, and surface compressibility factor, respectively. These are underground burial pressure, underground temperature, and underground compressibility factor, respectively. In the exemplary calculation, the overburden density is taken. gravitational acceleration Given a burial depth H = 2030m, the calculated overburden pressure is... The underground burial pressure is obtained after deducting the pore pressure. Take the ground temperature gradient The underground temperature was calculated. ,Pick Substituting the total volume of coalbed methane under the surface temperature and pressure conditions obtained in the aforementioned embodiments... The equivalent coalbed methane volume under underground burial conditions was calculated. .

[0039] Then, the volume of broken coal and rock and the unit volume of reserves are calculated: the cross-sectional area S of the drill bit is determined by collecting the geometric parameters of the drill bit, the length H of the drilled section is collected, and the volume of broken coal and rock by the drill bit is calculated. The calculation formula is as follows: In the formula Let S be the volume of the broken coal and rock, and S be the cross-sectional area of ​​the drill bit, which is determined by the drill bit diameter D using the formula... The calculation shows that H is the length of the drilled section; the equivalent coalbed methane volume in the underground burial state is... With the volume of the fractured coal and rock By performing ratio calculations, the coalbed methane reserves per unit volume of coal can be obtained. Vs The calculation formula is as follows: In the formula This represents the coalbed methane reserves per unit volume of coal and rock, indicating the volume of coalbed methane contained within a unit volume of coal and rock under underground burial conditions. In the exemplary calculation, the drill bit diameter D = 0.22 m is taken, then the cross-sectional area of ​​the drill bit is... The drilling section length H is taken as 10m (corresponding to the aforementioned 2640m). (2650m well section), the volume of fractured coal and rock was calculated. Combined with the aforementioned equivalent coalbed methane volume The coalbed methane reserves per unit volume of coal were calculated. .

[0040] S6. Determine the coal seam thickness h based on well logging interpretation data, including natural gamma ray logging, resistivity logging, density logging, or sonic transit-time logging data. By identifying the low gamma ray, high resistivity, and low density logging response characteristics of the coal seam, and combining this with well cuttings profiles for stratigraphic calibration, determine the effective coal seam thickness h, in meters. Determine the gas-bearing area A of the coal seam based on geological exploration data, including seismic structural interpretation data, geological outcrop survey data, drilling control data, and coalbed methane reservoir boundary analysis data. By drawing structural maps, fault sealing analysis, and reservoir continuity evaluation, delineate the planar distribution range of coalbed methane enrichment areas and calculate the gas-bearing area A of the coal seam. Preferably, for horizontal well sections where no logging operations have been performed, the top and bottom interfaces of the coal seam can be identified based on drilling gamma ray logging or cuttings logging data, and the vertical thickness can be calculated based on the wellbore trajectory to determine the coal seam thickness h.

[0041] Then, geological volume calculation and total reserves determination are performed: the geological volume of the entire coal seam is calculated using the coal seam thickness h and the gas-bearing area A. The calculation formula is as follows: In the formula The geological volume of the entire coal seam represents the total volume occupied by the gas-bearing coal seam in the three-dimensional underground space; the coalbed methane reserves per unit volume of coal and rock calculated in step S5 are... With the geological volume By performing multiplication, the total coalbed methane reserves contained in the entire coal seam can be obtained. The calculation formula is as follows: In the formula The total coalbed methane reserves contained in the entire coal seam are used to determine the gas-bearing area of ​​a certain block of coal seam in the exemplary calculation based on seismic interpretation and adjacent well drilling data. Determining the average coal seam thickness based on well logging interpretation h =8m, calculated geological volume The gas content per unit volume of coal and rock obtained in conjunction with the aforementioned embodiments The total reserves of the coal seam were calculated. This enables rapid prediction and evaluation of coalbed methane resources in the entire coal seam.

[0042] Example 2 The difference between this embodiment and Embodiment 1 is that this embodiment provides a device for predicting coalbed methane reserves based on drilling data; like Figure 2 As shown, the device includes a closed gas collection system, a gas-liquid separation system, a flow stabilization and buffer system, a dual-range flow meter system, a temperature and pressure correction system, and a data processing unit. Each system is connected in series through a pressure-resistant and sealed pipeline to form a complete route for continuously collecting, separating, and measuring methane-containing effective gas from the fluid returning from the wellhead. The closed-loop gas production system includes a closed gas collection hood, a rigid support frame, a flexible sealing layer, and a pneumatic clamping mechanism. The rigid support frame is made of corrosion-resistant high-strength alloy steel or stainless steel to ensure the structural stability of the gas collection hood under wellhead vibration and drilling fluid scouring conditions. The flexible sealing layer is made of fluororubber or oil-resistant, high-temperature-resistant elastic material, and achieves dynamic sealing with the wellhead flange through the pneumatic clamping mechanism, with the sealing pressure strictly controlled at 0.1 kJ / m³. Within the 0.3MPa range, this ensures that the effective gas returned from the wellhead does not leak, while also preventing the drilling fluid flow from being obstructed due to excessive sealing. The outlet end of the sealed gas collection hood is connected to the inlet of the gas-liquid separation system through a pressure-resistant sealed pipe, realizing the complete collection and closed drainage of methane-containing gas returned from the wellhead. Preferably, a methane sensor and a fluid reversing control valve are installed at the front end of the sealed gas collection hood. When the methane sensor detects the presence of methane in the returned drilling fluid, the control valve switches the flow path to the metering system. When no methane is detected, the flow path switches to the bypass channel and directly enters the mud pit, thus achieving energy saving.

[0043] The gas-liquid separation system adopts a vertical cylindrical structure, mainly composed of a separation cylinder, internal baffles or swirl components, a gas phase outlet, and a liquid phase discharge port. The separation cylinder is made of carbon steel with an anti-corrosion lining or stainless steel, which can withstand the long-term effects of water mist, drilling fluid, and corrosive components in the wellhead gas. The internal multi-stage baffle or swirl structure reduces the flow velocity of the gas-liquid mixture and changes its flow direction, achieving effective gas-liquid separation using gravity and centrifugal force. The separated liquid phase is discharged through the bottom drain port and returned to the mud pit, while the gas phase is connected to the inlet of the flow stabilization buffer system through a sealed pipeline via the top outlet, ensuring that the gas entering the subsequent metering system does not contain liquid components and improving metering accuracy.

[0044] The flow stabilization buffer system adopts a horizontal cylindrical structure, consisting of a flow stabilization buffer tank, an air inlet, and an air outlet. The buffer tank is made of pressure-resistant steel or stainless steel. This system is used to absorb the instantaneous pulsation of gas at the wellhead and reduce the impact of flow peaks caused by drilling fluid flow fluctuations on measurement accuracy. The inlet of the flow stabilization buffer system is connected to the gas phase outlet of the gas-liquid separation system through a pipeline, and its outlet is connected to the inlets of the large flow meter and the small flow meter in the dual-range flow meter system through a diversion pipeline, ensuring that the airflow entering the flow meter is stable and continuous.

[0045] The dual-range flow meter system consists of a large flow meter, a small flow meter, and a parallel pipeline system. The flow meters are thermal mass flow meters or vortex flow meters, and the housing material is stainless steel or aluminum alloy. The large and small flow meters are installed in parallel downstream of the flow stabilization buffer system. Continuous and accurate metering under different gas flow conditions is achieved through a switching valve or automatic control unit: the large flow meter is activated when the return gas volume is large, and the small flow meter is switched when the return gas volume is small, ensuring a metering accuracy within ±5% across the entire range. After the outlets of the two flow meters merge, they enter the temperature and pressure correction system through a unified pipeline to achieve continuous cumulative metering of gas volume.

[0046] The temperature and pressure correction system consists of a pressure sensor, a temperature sensor, and mounting connectors. The sensors use industrial-grade high-precision measuring elements, and the housing is made of stainless steel with a sealed structure. The system is installed at a key downstream location of the dual-range flow meter system and connects to the pipeline through a standard interface to collect real-time gas pressure and temperature data. Based on the gas state equation, the operating volume is converted to the standard volume under the surface temperature and pressure conditions, where the standard pressure is taken as 0.1013 MPa, the standard temperature as 298.15 K, and the compressibility factor is determined according to the gas composition.

[0047] The data processing unit includes a data acquisition module, a signal processing module, a storage module, and a display module. The data acquisition module is connected to the depth sensor, drilling time sensor, and total hydrocarbon detector of the dual-range flow meter system, the temperature and pressure correction system, and the well site logging system via signal lines to uniformly acquire and synchronously store various types of measurement data. The signal processing module incorporates algorithms for calculating late arrival time, coalbed methane volume, and reserves prediction. Based on received downhole pressure and temperature data, it establishes a model for calculating the late arrival time of gas logging data. It then performs an inversion of the acceleration integral equation to obtain the late arrival time, thereby resetting the well depth of the drilling data and effective gas volume. Based on the reset total hydrocarbon value and effective gas volume, it performs multiplication and summation operations to obtain the total coalbed methane volume. Based on the gas state equation, it performs volume conversion from surface to subsurface state to obtain the equivalent coalbed methane volume. Combined with drill bit geometric parameters, it calculates the volume of fractured coal and rock, performs ratio calculations to obtain the gas content per unit volume of coal and rock, and finally combines this with the geological volume of the coal seam to calculate the total reserves. The storage module is used to store intermediate and result data during the calculation process; the display module is used to display gas flow rate, cumulative volume, late arrival time, well depth, and reserve prediction results in real time, providing real-time data support for on-site engineering decisions.

[0048] The above are all preferred embodiments of the present invention and are not intended to limit the scope of protection of the present invention. Therefore, all equivalent changes made in accordance with the structure, shape and principle of the present invention should be covered within the scope of protection of the present invention.

Claims

1. A method for predicting coalbed methane reserves based on drilling data, characterized in that, include: Real-time data acquisition while drilling is performed using logging sensors. The data includes well depth, drilling time, mechanical drilling rate, and total hydrocarbon gas measurement parameters. The effective gas volume returned from the wellhead at different times is measured in real time using a wellhead gas metering device. The effective gas is a methane-containing gas; The lag time is calculated based on the physical properties of drilling fluid and effective gas, and the lag time is used to reposition the well depth based on the drilling data and effective gas volume. Based on effective gas volume Total hydrocarbon values ​​measured at various time periods Calculate the coalbed methane volume for the corresponding time period. This allows us to obtain the total volume of coalbed methane in the coal-rock section under surface temperature and pressure conditions. ; The total volume of coalbed methane under surface temperature and pressure conditions is determined using the gas law. Equivalent coalbed methane volume converted to underground burial conditions The coalbed methane reserves per unit volume of coal were obtained. ; Coalbed methane reserves per unit volume of coal The total coalbed methane reserves contained in the entire coal seam Make predictions.

2. The method for predicting coalbed methane reserves based on drilling data according to claim 1, characterized in that, The calculation of the lag time based on the physical properties of drilling fluid and effective gas includes establishing an acceleration integral model based on gas return dynamics, and determining the gas acceleration during the annular return process based on the density and viscosity differences between the drilling fluid and the returned gas. ; Collect effective gas return rate at the wellhead and initial circulation rate of drilling fluid An integral constraint equation based on motion acceleration is established, and the integral constraint equation is solved by inversion using a numerical iterative algorithm to calculate the time lag required for gas to travel from the bottom of the well to the wellhead. The integral constraint equation is: ； in, The density difference between the gas and liquid phases Due to the viscosity difference between the gas and liquid phases, The effective gas return velocity measured at the wellhead. The initial velocity of the drilling fluid. The flow time of gas transport in the annulus. This indicates that the acceleration is determined by the density difference, viscosity difference, and flow time.

3. The method for predicting coalbed methane reserves based on drilling data according to claim 2, characterized in that, The calculation of the density and viscosity differences between the drilling fluid and the returned gas includes obtaining real-time downhole pressure and temperature parameters, and calculating the current drilling fluid viscosity and density based on the drilling fluid rheological properties. The calculation formulas for the drilling fluid viscosity and density are as follows: ； ； in, For drilling fluid viscosity under surface conditions, For ground reference pressure, Ground reference temperature The pressure sensitivity coefficient, For temperature sensitivity coefficient, For downhole pressure, The temperature is the temperature at the bottom of the well. The density of drilling fluid under downhole conditions. The density of drilling fluid under surface conditions. The compression factor is 1. is the coefficient of thermal expansion.

4. The method for predicting coalbed methane reserves based on drilling data according to claim 3, characterized in that, The calculation of the density difference and viscosity difference between the drilling fluid and the returned gas also includes obtaining the pressure P, temperature T and compressibility factor Z of the methane gas at the downhole location, calculating the effective gas density based on the current downhole conditions, and calculating the gas-liquid two-phase density difference based on the drilling fluid density. The molar mass of methane gas is determined based on the methane composition in the wellhead return gas, and the effective gas viscosity is calculated based on the molar mass. This leads to the gas-liquid two-phase viscosity difference. Based on the density and viscosity differences between the gas and liquid phases, a correction parameter for the gas-liquid two-phase slip velocity is established. The formula for calculating the effective gas viscosity is as follows: ； in, The viscosity of the effective gas, , and This is an empirical coefficient. Where is the density of the effective gas, and T is the downhole temperature.

5. The method for predicting coalbed methane reserves based on drilling data according to claim 4, characterized in that, The method of using delay time to reposition well depth data and effective gas volume includes collecting the time when effective gas returns to the wellhead. And based on the return time and late time The time difference relationship determines the time when the drill bit reaches the corresponding well depth. Based on drilling time Establish a mapping relationship between drilling data and well depth, and reorient the drilling data and effective gas volume to the drilling time. The corresponding well depth.

6. The method for predicting coalbed methane reserves based on drilling data according to claim 1, characterized in that, The calculation of the coalbed methane volume for the corresponding time period includes collecting the total hydrocarbon values ​​for each time period after well depth repositioning. and the effective gas volume for the corresponding time period , to increase the total hydrocarbon value With effective gas volume Perform multiplication to obtain the coalbed methane volume for each time period. The volume of coalbed methane at each time period within the drilled coal and rock section. By summing the results, the total volume of coalbed methane in this coal-rock section under the surface temperature and pressure conditions can be obtained. .

7. The method for predicting coalbed methane reserves based on drilling data according to claim 1, characterized in that, The process of obtaining the coalbed methane reservoir per unit volume of coal includes determining the pressure, temperature, and compressibility factor under both surface and underground burial conditions, collecting the drill bit cross-sectional area S and the drilling section length H, and calculating the volume of fractured coal. The equivalent coalbed methane volume With the volume of broken coal and rock By performing ratio calculations, the coalbed methane reserves per unit volume of coal can be obtained. The equivalent coalbed methane volume The conversion formula is: ； in, This represents the equivalent volume of coalbed methane in its underground burial state. This refers to the total volume of coalbed methane under surface temperature and pressure conditions. For surface pressure, For underground burial pressure, For surface temperature, For underground temperature, The surface compressibility factor. It is the underground compressibility factor.

8. The method for predicting coalbed methane reserves based on drilling data according to claim 1, characterized in that, The prediction of the total coalbed methane reserves contained in the entire coal seam includes determining the coal seam thickness h and the gas-bearing area A based on well logging interpretation data and geological exploration data, and calculating the geological volume using the coal seam thickness h and the gas-bearing area A. Based on the coalbed methane reserves per unit volume of coal and rock With geological volume By performing multiplication, the total coalbed methane reserves contained in the entire coal seam can be obtained. .

9. An apparatus for predicting coalbed methane reserves based on drilling data, comprising the method described in claim 1, characterized in that, include: The closed gas production system is equipped with a closed gas collection hood, a rigid support frame, a flexible sealing layer and a pneumatic clamping mechanism, and is used to seal and collect methane-containing effective gas returning from the wellhead. The gas-liquid separation system, connected to the closed gas production system, adopts a vertical cylindrical structure and has multiple baffles or swirl components inside for separating gas and drilling fluid. A flow stabilization buffer system, connected to the gas-liquid separation system, adopts a horizontal cylindrical structure and is used to absorb gas flow turbulence; The dual-range flow meter system, connected to the flow stabilization buffer system, consists of a large flow meter, a small flow meter, and parallel pipelines. It achieves continuous metering under different gas volume conditions through a switching valve. The temperature and pressure correction system is used to collect gas pressure and temperature data in real time and convert the working volume into the standard volume under the surface temperature and pressure conditions. The data processing unit is used to establish a late arrival time calculation model, perform coalbed methane volume calculation, and reserve prediction.

10. The device for predicting coalbed methane reserves based on drilling data according to claim 9, characterized in that, The flexible sealing layer achieves dynamic bonding and sealing with the wellhead flange through the pneumatic clamping mechanism, and the sealing pressure of the sealing layer is controlled within the range of 0.1~0.3MPa.

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