Evaluation method for residual reserves of low-permeability gas reservoir stratum

Abstract

The invention discloses a method for evaluating residual reserves of a low-permeability gas reservoir stratum, which comprises the following steps of: firstly, obtaining block production data and basic parameters through a target well, and respectively calculating stratum pressure by sequentially adopting four means of a material balance method, a wellhead casing pressure conversion method, a flowing material balance method and a modern yield instability analysis method; an algorithm with the minimum absolute error and the minimum relative error is used as a final pressure calculation method of the well; and correcting abnormal results by using a modern yield instability analysis method or a wellhead casing pressure conversion method. And importing the obtained formation pressure into software to draw a formation pressure distribution diagram, and generating a pressure loss rate curve diagram in combination with a pressure drop loss rate model so as to realize quantitative evaluation of the residual reserves of the formation. According to the method, a systematic and high-precision formation pressure optimization and residual reserve evaluation scheme is provided for low-permeability production gas reservoirs.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas field development, and particularly relates to a method for evaluating the remaining reserves of a low-permeability gas reservoir formation. Background Art

[0002] Formation pressure is a core parameter in the development of gas reservoirs, directly reflecting the energy state of the reservoir and playing a key role in dynamic reserve calculations, production dynamic analysis, and capacity evaluation. In particular, in the development of low-permeability gas reservoirs, accurate and rapid acquisition of formation pressure is of great significance for optimizing development plans and improving the efficiency of gas reservoir development. However, the existing technology has four typical methods for calculating formation pressure: the material balance method, the flowing material balance method, the wellhead casing pressure conversion method, and the modern production instability analysis method. However, based on different operating conditions, the existing technology lacks a calculation method for formation pressure in specific working conditions, that is, a method for optimizing the four typical calculation methods. Therefore, a systematic optimization evaluation scheme for the four typical formation pressures under different working conditions is needed. Summary of the Invention

[0003] The purpose of the present invention is to provide a method for evaluating the remaining reserves of low-permeability gas reservoir formations, which solves the problem in the prior art of lacking a calculation method for formation pressure under specific working conditions, namely, a preferred method among four typical calculation methods.

[0004] The technical solution adopted by the present invention is a method for evaluating the remaining reserves of low-permeability gas reservoir formations, which specifically comprises the following steps: S1. Obtain block production data and basic parameters through target wells; S2. Based on production data and basic parameters, the formation pressure is calculated using the material balance method, the wellhead casing pressure conversion method, the flowing material balance method, and the modern production instability analysis method. The absolute and relative errors of the different calculation methods are then calculated. S3. By comparing the absolute error and the relative error, the algorithm with the smallest error value is selected as the formation pressure calculation method of the target well; S4. For target wells with distorted calculations, use modern production instability analysis methods or wellhead casing pressure conversion methods to correct them and obtain formation pressure; S5. Substituting the formation pressure into the software to generate a formation pressure distribution map; S6. Calculate the pressure loss rate using a pressure drop loss rate calculation model and generate a pressure loss rate curve graph; S7. Evaluate the remaining reserves of formation pressure through the formation pressure distribution diagram and the pressure loss rate curve diagram.

[0005] The present invention is also characterized in that: Production data includes static data and dynamic data. Static data include: effective thickness, permeability, porosity, and water saturation; dynamic data include: cumulative water production, cumulative gas production, and water-gas ratio.

[0006] The material balance method involves calculating the formation pressure at different production rates using the regression equation between apparent formation pressure and cumulative gas production. Without considering bound water and rock elastic deformation, the material balance equation for a water-flooded gas reservoir is derived as follows: (1) Where, is the water intrusion, is the cumulative gas production, is the cumulative water production, is the original geological reserves, is the original volume coefficient of the gas; is the gas volume coefficient; is the volume coefficient of water; The ratio of the volume of natural gas under formation conditions to the volume of natural gas under standard surface conditions is the natural gas volume coefficient. When the reservoir pressure is P and the temperature is T, the natural gas state equation can be combined to obtain the natural gas volume coefficient calculation formula: (2) (3) Where, is the formation temperature, is the ground temperature under standard conditions, is the original formation pressure, is the current formation pressure, is the pressure under standard ground conditions, is the deviation coefficient of natural gas at the original pressure Pi, is the deviation coefficient of natural gas at pressure P; Will 、 Substituting the calculation formula into formula (1), we can get the current formation pressure P: (4) in The formula is as follows: (5) In the material balance method, when there is no water drive in the gas reservoir, that is, when We=0 and Wp=0 in the water-free gas reservoir, Equation (4) is transformed into: (6) For closed water-producing gas reservoirs, Equation (4) is converted to: (7) The wellhead casing pressure deduction algorithm includes: after the production gas well is shut in until the entire formation pressure reaches a balanced state, the wellbore pressure gradient and the wellhead pressure have a linear formula as follows: (8) The calculation formula of formation pressure is: (9) Where, is the wellbore pressure gradient, is the gas wellhead flowing pressure, For the depth down to the middle of the gas layer, It is the formation pressure after the well is shut in for a long time.

[0007] The flow material balance method includes: The bottom hole flowing pressure and cumulative gas production have a binomial relationship: (10) The relationship between wellhead casing pressure and cumulative gas production is: (11) Determine the formation pressure calculation formula: (12) Where, is the bottom hole flowing pressure of the gas well, It is the formation pressure during quasi-steady-state production of the gas well.

[0008] Modern production instability analysis methods include: using the Blasingame model to normalize the production data of low-porosity and low-permeability fractured gas wells after fracturing, fitting the production integral and production integral differential curves through material balance time, inverting the permeability, skin coefficient, effective recovery rate and recoverable reserves, and establishing a fracture model based on this to predict production performance.

[0009] In S6, the pressure drop loss rate calculation model includes the early and late mathematical models of unstable seepage, where the equation of the early mathematical model of unstable seepage is as follows: (13) The mathematical model equation of the late stage of unstable seepage is as follows:

[0010] (14) (15) The mathematical model equations for calculating the pressure drop loss rate at any location in the gas reservoir at any time are as follows: (16) (17) Where, is the pressure drop at any position in the gas well at any time, dimensionless; is the original formation pressure; is the gas well production under standard conditions; is the viscosity of natural gas at original pressure and temperature; is the comprehensive compressibility coefficient at the original pressure and temperature; is the viscosity of natural gas at average pressure and temperature; is the natural gas deviation factor at average pressure and temperature; is the air layer temperature; is the gas layer permeability; is the thickness of the gas layer; is the pressure conductivity coefficient; For time; is the gas volume coefficient; is the supply radius; is the radius of the gas well; is the porosity; is the average pressure at time t at a distance r from the well.

[0011] The beneficial effects of the present invention are: (1) The system optimization of formation pressure calculation methods was realized. By comparing the errors of four typical methods, namely the material balance method, the wellhead casing pressure deduction method, the flow material balance method and the modern production instability analysis method, the algorithm with the smallest error and the strongest adaptability to working conditions was selected, thus solving the industry problem of blind method selection and low reliability of calculation results.

[0012] (2) The accuracy and efficiency of formation pressure calculation in low-permeability gas reservoirs have been significantly improved, and the entire process can be completed in batches. The calculation time for a single well has been shortened from several days to minutes, thus avoiding production losses caused by long-term well shutdown. BRIEF DESCRIPTION OF THE DRAWINGS

[0013] Figure 1 is a graph showing the relationship between apparent formation pressure and cumulative gas production in the present invention; Figure 2 This is a comparison diagram of the pressure drop loss rate of the closed formation model and the infinite formation model at different well control radii in the present invention; Figure 3 This is the formation pressure distribution diagram of the BX group in the YQ2-Y128 well area in the present invention; Figure 4 This is the formation pressure distribution diagram of the SHZ group in the YQ2-Y128 well area in the present invention; Figure 5 This is the formation pressure distribution diagram of the SX group in the YQ2-Y128 well area of ​​the present invention; Figure 6This is the production pressure drop funnel diagram of a typical gas well in the YQ2-Y128 well area of ​​the present invention; Figure 7 This is a comparison chart of the effect of the permeability of the YQ2-Y128 well area on the pressure drop funnel in the present invention; Figure 8 This is a comparison chart of the effect of production time on the pressure drop funnel in the YQ2-Y128 well area of ​​the present invention; Figure 9 It is a plane diagram of the pressure drop loss rate of the SX group gas wells in the YQ2-Y128 well area of ​​the present invention; Figure 10 This is a plane diagram of the pressure drop loss rate of the BX group gas wells in the YQ2-Y128 well area of ​​the present invention; Figure 11 It is a plane diagram of the pressure drop loss rate of the SHZ group gas wells in the YQ2-Y128 well area in the present invention. DETAILED DESCRIPTION

[0014] The following describes it in detail with reference to specific implementation methods.

[0015] The method for evaluating the remaining reserves of low permeability gas reservoir formations specifically comprises the following steps: S1. Obtain block production data and basic parameters through target wells.

[0016] Production data includes static data and dynamic data. Static data include: effective thickness, permeability, porosity, and water saturation; dynamic data include: cumulative water production, cumulative gas production, and water-gas ratio.

[0017] S2. Based on production data and basic parameters, the formation pressure is calculated using the material balance method, wellhead casing pressure conversion method, flowing material balance method, and modern production instability analysis method. The absolute and relative errors of different calculation methods are then calculated.

[0018] In S2, the material balance method uses the regression equation between apparent formation pressure and cumulative gas production to calculate the formation pressure at different production rates. Without considering bound water and rock elastic deformation, the material balance equation for the water-flooded gas reservoir is derived as follows: (1) Where, is the water intrusion, is the cumulative gas production, is the cumulative water production, is the original geological reserves, is the original volume coefficient of the gas; is the gas volume coefficient; is the volume coefficient of water.

[0019] in 、 、 、 The unit is ten thousand square meters (10 4 m 3 ).

[0020] The ratio of the volume of natural gas under formation conditions to the volume of natural gas under standard surface conditions is the natural gas volume coefficient. When the reservoir pressure is P and the temperature is T, the natural gas state equation can be combined to obtain the natural gas volume coefficient calculation formula: (2) (3) Where, is the formation temperature, is the ground temperature under standard conditions, is the original formation pressure, is the current formation pressure, is the pressure under standard ground conditions, is the deviation coefficient of natural gas at the original pressure Pi, is the deviation coefficient of natural gas at pressure P.

[0021] in, and The unit is Kelvin (K), 、 and The unit is megapascal (MPa). The value is 293.15K. The value is 0.101MPa.

[0022] Will 、 Substituting the calculation formula into formula (1), we can get the current formation pressure P: (4) in The formula is as follows: (5).

[0023] In the material balance method, when there is no water drive in the gas reservoir, that is, when We=0 and Wp=0 in the water-free gas reservoir, Equation (4) is transformed into: (6) For closed water-producing gas reservoirs, Equation (4) is converted to: (7).

[0024] like Figure 1 As shown in Figure 2, according to the formation pressure calculation formula of the material balance method, it can be seen that there is a linear relationship between the apparent formation pressure and the cumulative gas production.

[0025] The wellhead casing pressure deduction algorithm includes: after the production gas well is shut in until the entire formation pressure reaches a balanced state, the wellbore pressure gradient and the wellhead pressure have a linear formula as follows: (8) The calculation formula of formation pressure is: (9) Where, is the wellbore pressure gradient, is the gas wellhead flowing pressure, For the depth down to the middle of the gas layer, It is the formation pressure after the well is shut in for a long time.

[0026] in, The unit is MPa / 100m, and The unit is MPa, The unit is meter (m).

[0027] The flowing material balance method states that after gas seepage in a closed gas reservoir enters a quasi-stable state, the formation pressure and bottomhole flowing pressure have a nearly perfect positive correlation, meaning that the change in formation pressure is almost equal to the change in bottomhole flowing pressure. Statistics of gas well production data reveal that in the quasi-stable state, the wellhead pressure and bottomhole pressure decrease at the same rate, and the bottomhole flowing pressure and cumulative gas production have a binomial relationship: (10) The relationship between wellhead casing pressure and cumulative gas production is: (11) Determine the formation pressure calculation formula: (12) Where, is the bottom hole flowing pressure of the gas well, It is the formation pressure during quasi-steady-state production of the gas well.

[0028] Where, and The unit is MPa.

[0029] Modern production instability analysis methods include: using the Blasingame model to normalize the production data of low-porosity and low-permeability fractured gas wells after fracturing, fitting the production integral and production integral differential curves through material balance time, inverting the permeability, skin coefficient, effective recovery rate and recoverable reserves, and establishing a fracture model based on this to predict production performance.

[0030] Modern production instability analysis methods are based on well testing analysis of production data. They often utilize RTA numerical simulation software to analyze production data such as flow rate and bottomhole pressure, determine reservoir parameters such as permeability, skin coefficient, effective recovery factor, and recoverable reserves, and predict production performance. RTA has eight analysis models with varying degrees of accuracy. The target well area features low porosity and permeability, with well-developed fractures. All producing gas wells have undergone fracturing. The Blasingame analysis model normalizes production data. The template for the normalized production curve (production integral and production integral differential) uses material balance fitting to time, which better fits the data. Therefore, the Blasingame method was selected in this paper to establish the fracture model.

[0031] The absolute error is calculated as the absolute value of the formation pressure difference between the two different calculation methods. The relative error is calculated as the percentage of the absolute error to the reference value.

[0032] S3. Through absolute error and relative error, the algorithm with the smallest error value is selected as the formation pressure calculation method of the target well.

[0033] S4. For target wells with distorted calculations, use modern production instability analysis methods or wellhead casing pressure conversion methods to correct them and obtain formation pressure.

[0034] Among them, the target wells with calculation distortion are wells whose formation pressure calculation results deviate significantly from the true value due to data anomalies, model limitations or special geological conditions.

[0035] S5. Substitute the formation pressure into the software to generate a formation pressure distribution map.

[0036] You can use Python-written software to generate a formation pressure distribution map by substituting the formation pressure. You can also use software such as Schlumberger Petrel + Eclipse, CMG (IMEX, GEM, STARS), and Halliburton Nexus to generate a formation pressure distribution map.

[0037] S6. Calculate the pressure loss rate using the pressure drop loss rate calculation model and generate a pressure loss rate curve.

[0038] When the flow of fluid in a gas reservoir is in equilibrium, changing the operating system of a well in the reservoir, or changing the well production rate or pressure, will cause pressure disturbances at the bottom of the well. Over time, the pressure disturbance continues to expand radially toward the formations surrounding the wellbore wall, eventually reaching a new equilibrium state. This process is called unstable seepage. The pressure drop loss rate calculation model includes early and late stage mathematical models for unstable seepage. The equation for the early stage mathematical model is as follows: (13) The mathematical model equation of the late stage of unstable seepage is as follows:

[0039] (14) (15) The mathematical model equations for calculating the pressure drop loss rate at any location in the gas reservoir at any time are as follows: (16) (17) Where, is the pressure drop at any position in the gas well at any time, dimensionless; is the original formation pressure; is the gas well production under standard conditions; is the viscosity of natural gas at original pressure and temperature; is the comprehensive compressibility coefficient at the original pressure and temperature; is the viscosity of natural gas at average pressure and temperature; is the natural gas deviation factor at mean pressure and temperature; is the air layer temperature; is the gas layer permeability; is the thickness of the gas layer; is the pressure conductivity coefficient; For time; is the gas volume coefficient; is the supply radius; is the radius of the gas well; is the porosity; is the average pressure at time t at a distance r from the well.

[0040] in, and The unit is MPa, The unit is 10 4 m 3 , and The unit is millipascal second (mPa·s). The unit is MPa -1 , The unit is K, The unit is square micrometer (μm 2 ), and The unit is m, The unit is μm 2 MPa / (mPa·s), The unit is hour (h).

[0041] like Figure 2 As shown in the figure, the pressure loss rates of the two pressure drop loss rate models at different well control radii are calculated and plotted as a curve. The pressure drop loss rate decreases with the increase of the well control radius, and the reduction range of the infinite formation model is greater than that of the closed formation model, which is more consistent with the mining experience of the well area over the years and is suitable for analyzing the pressure sweep range of gas wells in the well area.

[0042] S7. Evaluate the remaining reserves of formation pressure through the formation pressure distribution diagram and the pressure loss rate curve diagram.

[0043] Taking the YQ2-Y128 well block as an example, most of the producing gas wells in the YQ2-Y128 well block have been in production for a long time and have a lot of historical production data. After sorting out the production data of the block, 10 typical producing gas wells with relatively high integrity of static data (effective thickness, permeability, porosity, water saturation), dynamic data and pressure measurement data were selected. Table 1 shows the basic parameters required for calculation or characteristic parameters for applicability evaluation: Table 1 Production data of typical wells

[0044] Combining the daily production data and basic parameters of gas wells, the formation pressure was calculated according to the above methods, the errors of various methods were statistically analyzed, and their adaptability was analyzed. The data are shown in Table 2.

[0045] Table 2 Analysis of calculated formation pressure errors

[0046] It can be seen from the error statistics that the formation pressure calculated by the material balance method - water-producing gas reservoir has a minimum error value of 0.38MPa and a relative error of 3.05%. The modern production instability analysis method and the wellhead casing pressure conversion method also have high accuracy, with relative errors of 3.86% and 6.51% respectively. The formation pressure calculated by the material balance method - constant volume gas reservoir has a certain degree of increase in error due to the presence of a certain amount of water production in the gas wells in the well area, with a relative error of 11.76%. The flowing material balance method is prone to large errors due to the difficulty in accurately grasping the quasi-steady-state judgment during the production process of the gas well, with a relative error of 29.78%.

[0047] Considering the applicable conditions and errors in the calculation results of different formation pressure calculation methods, the material balance method for water-producing gas reservoirs is used as the primary method for formation pressure calculation due to its simplicity and high accuracy. For special gas wells with minor calculation distortions, modern production instability analysis methods or wellhead casing pressure conversion methods can be used to correct them. Table 3 shows a comparison of the formation pressures of 10 typical producing gas wells calculated using the material balance method for water-producing gas reservoirs with the formation pressures of wells with actual pressure measurement data.

[0048] Table 3 Comparison of calculated formation pressure of water-producing gas reservoirs using the material balance method and measured formation pressure of gas reservoirs

[0049] The calculation error of the material balance method for water-producing gas reservoirs is less than 5% except for one well, which shows high calculation accuracy. The maximum relative error is 11.54%, indicating that this method has high stability and is suitable for calculating formation pressure of gas wells in this well area.

[0050] According to the above typical example analysis, it can be seen that the material balance method - water-producing gas reservoir is the optimal calculation method, and its core calculation equation is: (7) To facilitate the subsequent calculation of formation pressure P, we used Python software to write the calculation code. The apparent formation pressure calculated from the measured formation pressure was then compared to verify the feasibility of the method. Table 4 shows a comparative analysis of the two calculation results. The relative error values ​​indicate that the method has high accuracy and stability, thus verifying the correctness of the Python program.

[0051] Table 4 Comparative analysis of apparent formation pressure calculated by code and measured pressure

[0052] According to the stratigraphic division scheme of the YA gas field, the study well area can be divided into three stratigraphic systems: the BX group, the SHZ group, and the SX group. The formation pressure of each gas well in the three stratigraphic systems was calculated using Python program code, and the formation pressure distribution maps of the three stratigraphic systems were drawn using numerical simulation software.

[0053] like Figure 3 As shown in Figure 2, the BX Formation presents a formation pressure distribution with low pressure in the middle and high pressure at the edges. Figure 4 As shown in Figure 1, the formation pressure of the SHZ group is generally high, with only a few areas having low formation pressure and the gas-bearing layers are more dispersed than the other two formations. Figure 5 As shown, the SX Formation, in contrast to the SHZ Formation, has only a few areas of high formation pressure. The vast majority of areas are low-pressure zones, with formation pressures below 10 MPa. Overall, the SHZ Formation has the highest formation pressure, followed by the BX Formation, with the SX Formation having the lowest. Formation pressures in both the BX and SX Formations decrease gradually from the edges to the center, indicating that these two formations possess good reservoir properties. Furthermore, the lower pressure distribution in the SX Formation indirectly reflects its abundant remaining reserves, significant recovery potential, and potential for intensified production.

[0054] To improve calculation efficiency, Python software was used to write the calculation formula of the infinite formation model and the program code for drawing the pressure drop funnel based on the calculation results, so that the changes in gas well formation pressure can be analyzed more intuitively and clearly. Figure 6 This is a typical gas well production pressure drop funnel diagram. The pressure drop loss rate gradually decreases as it expands around the production well, forming a typical funnel shape. Figure 7 This is a comparison chart of the effect of permeability on the pressure drop funnel. Figure 8 This is a comparison chart of the effect of production time on the pressure drop funnel. Figure 7 and Figure 8 Combined analysis reveals that the pressure drop rate increases with increasing permeability. The larger the pressure sweep, the greater the pressure loss at the same well spacing. Formation pressure loss primarily occurs within 200 m from the well bottom. For a gas reservoir with a permeability of 0.17 mD, the pressure loss exceeds 70% from the well bottom to 200 m, showing a trend of initially decreasing sharply followed by a gradual decrease. At a constant permeability, the pressure drop rate increases slightly with production time, and the increase is greater with increasing well spacing.

[0055] Similar to the formation pressure calculation, the gas wells in the study area are also divided into three groups: BX group, SHZ group and SX group according to the YA gas field stratigraphic division scheme. The pressure drop loss rate of all gas wells in the three distributions is calculated using the Python program code, and the results are as follows: Figure 9 、 Figure 10 and Figure 11 Plane diagram of the pressure drop loss rate of gas wells in the three formations.

[0056] Based on gas well production performance data, a comparative analysis of the results of four typical formation pressure calculation methods with the measured formation pressure shows that the material balance method for water-producing gas reservoirs has the highest calculation accuracy and the best stability. For a small number of abnormal gas wells with distorted calculations using the material balance method for water-producing gas wells, modern production instability analysis methods or wellhead casing pressure conversion methods with higher calculation accuracy can be used for calibration to accurately evaluate the formation pressure in the well area.

[0057] Example 1 The method for evaluating the remaining reserves of low permeability gas reservoir formations specifically comprises the following steps: S1. Obtain block production data and basic parameters through target wells; S2. Based on production data and basic parameters, the formation pressure is calculated using the material balance method, the wellhead casing pressure conversion method, the flowing material balance method, and the modern production instability analysis method. The absolute and relative errors of the different calculation methods are then calculated. S3. By comparing the absolute error and the relative error, the algorithm with the smallest error value is selected as the formation pressure calculation method of the target well; S4. For target wells with distorted calculations, use modern production instability analysis methods or wellhead casing pressure conversion methods to correct them and obtain formation pressure; S5. Substituting the formation pressure into the software to generate a formation pressure distribution map; S6. Calculate the pressure loss rate using a pressure drop loss rate calculation model and generate a pressure loss rate curve graph; S7. Evaluate the remaining reserves of formation pressure through the formation pressure distribution diagram and the pressure loss rate curve diagram.

[0058] Example 2 The method for evaluating the remaining reserves of low permeability gas reservoir formations specifically comprises the following steps: S1. Obtain block production data and basic parameters through target wells; S2. Based on production data and basic parameters, the formation pressure is calculated using the material balance method, the wellhead casing pressure conversion method, the flowing material balance method, and the modern production instability analysis method. The absolute and relative errors of the different calculation methods are then calculated. S3. By comparing the absolute error and the relative error, the algorithm with the smallest error value is selected as the formation pressure calculation method of the target well; S4. For target wells with distorted calculations, use modern production instability analysis methods or wellhead casing pressure conversion methods to correct them and obtain formation pressure; S5. Substituting the formation pressure into the software to generate a formation pressure distribution map; S6. Calculate the pressure loss rate using a pressure drop loss rate calculation model and generate a pressure loss rate curve graph; S7. Evaluate the remaining reserves of formation pressure through the formation pressure distribution diagram and the pressure loss rate curve diagram.

[0059] Production data includes static data and dynamic data. Static data include: effective thickness, permeability, porosity, and water saturation; dynamic data include: cumulative water production, cumulative gas production, and water-gas ratio.

[0060] Example 3 The method for evaluating the remaining reserves of low permeability gas reservoir formations specifically comprises the following steps: S1. Obtain block production data and basic parameters through target wells; S2. Based on production data and basic parameters, the formation pressure is calculated using the material balance method, the wellhead casing pressure conversion method, the flowing material balance method, and the modern production instability analysis method. The absolute and relative errors of the different calculation methods are then calculated. S3. By comparing the absolute error and the relative error, the algorithm with the smallest error value is selected as the formation pressure calculation method of the target well; S4. For target wells with distorted calculations, use modern production instability analysis methods or wellhead casing pressure conversion methods to correct them and obtain formation pressure; S5. Substituting the formation pressure into the software to generate a formation pressure distribution map; S6. Calculate the pressure loss rate using a pressure drop loss rate calculation model and generate a pressure loss rate curve graph; S7. Evaluate the remaining reserves of formation pressure through the formation pressure distribution diagram and the pressure loss rate curve diagram.

[0061] The material balance method involves calculating the formation pressure at different production rates using the regression equation between apparent formation pressure and cumulative gas production. Without considering bound water and rock elastic deformation, the material balance equation for a water-flooded gas reservoir is derived as follows: (1) Where, is the water intrusion, is the cumulative gas production, is the cumulative water production, is the original geological reserves, is the original volume coefficient of the gas; is the gas volume coefficient; is the volume coefficient of water; The ratio of the volume of natural gas under formation conditions to the volume of natural gas under standard surface conditions is the natural gas volume coefficient. When the reservoir pressure is P and the temperature is T, the natural gas state equation can be combined to obtain the natural gas volume coefficient calculation formula: (2) (3) Where, is the formation temperature, is the ground temperature under standard conditions, is the original formation pressure, is the current formation pressure, is the pressure under standard ground conditions, is the deviation coefficient of natural gas at the original pressure Pi, is the deviation coefficient of natural gas at pressure P; Will 、 Substituting the calculation formula into formula (1), we can get the current formation pressure P: (4) in The formula is as follows: (5).

[0062] In the material balance method, when there is no water drive in the gas reservoir, that is, when We=0 and Wp=0 in the water-free gas reservoir, Equation (4) is transformed into: (6) For closed water-producing gas reservoirs, Equation (4) is converted to: (7).

[0063] Example 4 The method for evaluating the remaining reserves of low permeability gas reservoir formations specifically comprises the following steps: S1. Obtain block production data and basic parameters through target wells; S2. Based on production data and basic parameters, the formation pressure is calculated using the material balance method, the wellhead casing pressure conversion method, the flowing material balance method, and the modern production instability analysis method. The absolute and relative errors of the different calculation methods are then calculated. S3. By comparing the absolute error and the relative error, the algorithm with the smallest error value is selected as the formation pressure calculation method of the target well; S4. For target wells with distorted calculations, use modern production instability analysis methods or wellhead casing pressure conversion methods to correct them and obtain formation pressure; S5. Substituting the formation pressure into the software to generate a formation pressure distribution map; S6. Calculate the pressure loss rate using a pressure drop loss rate calculation model and generate a pressure loss rate curve graph; S7. Evaluate the remaining reserves of formation pressure through the formation pressure distribution diagram and the pressure loss rate curve diagram.

[0064] The wellhead casing pressure deduction algorithm includes: after the production gas well is shut in until the entire formation pressure reaches a balanced state, the wellbore pressure gradient and the wellhead pressure have a linear formula as follows: (8) The calculation formula of formation pressure is: (9) Where, is the wellbore pressure gradient, is the gas wellhead flowing pressure, For the depth down to the middle of the gas layer, It is the formation pressure after the well is shut in for a long time.

[0065] Example 5 The method for evaluating the remaining reserves of low permeability gas reservoir formations specifically comprises the following steps: S1. Obtain block production data and basic parameters through target wells; S2. Based on production data and basic parameters, the formation pressure is calculated using the material balance method, the wellhead casing pressure conversion method, the flowing material balance method, and the modern production instability analysis method. The absolute and relative errors of the different calculation methods are then calculated. S3. By comparing the absolute error and the relative error, the algorithm with the smallest error value is selected as the formation pressure calculation method of the target well; S4. For target wells with distorted calculations, use modern production instability analysis methods or wellhead casing pressure conversion methods to correct them and obtain formation pressure; S5. Substituting the formation pressure into the software to generate a formation pressure distribution map; S6. Calculate the pressure loss rate using a pressure drop loss rate calculation model and generate a pressure loss rate curve graph; S7. Evaluate the remaining reserves of formation pressure through the formation pressure distribution diagram and the pressure loss rate curve diagram.

[0066] The flow material balance method includes: The bottom hole flowing pressure and cumulative gas production have a binomial relationship: (10) The relationship between wellhead casing pressure and cumulative gas production is: (11) Determine the formation pressure calculation formula: (12) Where, is the bottom hole flowing pressure of the gas well, It is the formation pressure during quasi-steady-state production of the gas well.

[0067] Example 6 The method for evaluating the remaining reserves of low permeability gas reservoir formations specifically comprises the following steps: S1. Obtain block production data and basic parameters through target wells; S2. Based on production data and basic parameters, the formation pressure is calculated using the material balance method, the wellhead casing pressure conversion method, the flowing material balance method, and the modern production instability analysis method. The absolute and relative errors of the different calculation methods are then calculated. S3. By comparing the absolute error and the relative error, the algorithm with the smallest error value is selected as the formation pressure calculation method of the target well; S4. For target wells with distorted calculations, use modern production instability analysis methods or wellhead casing pressure conversion methods to correct them and obtain formation pressure; S5. Substituting the formation pressure into the software to generate a formation pressure distribution map; S6. Calculate the pressure loss rate using a pressure drop loss rate calculation model and generate a pressure loss rate curve graph; S7. Evaluate the remaining reserves of formation pressure through the formation pressure distribution diagram and the pressure loss rate curve diagram.

[0068] Modern production instability analysis methods include: using the Blasingame model to normalize the production data of low-porosity and low-permeability fractured gas wells after fracturing, fitting the production integral and production integral differential curves through material balance time, inverting the permeability, skin coefficient, effective recovery rate and recoverable reserves, and establishing a fracture model based on this to predict production performance.

[0069] Example 7 The method for evaluating the remaining reserves of low permeability gas reservoir formations specifically comprises the following steps: S1. Obtain block production data and basic parameters through target wells; S2. Based on production data and basic parameters, the formation pressure is calculated using the material balance method, the wellhead casing pressure conversion method, the flowing material balance method, and the modern production instability analysis method. The absolute and relative errors of the different calculation methods are then calculated. S3. By comparing the absolute error and the relative error, the algorithm with the smallest error value is selected as the formation pressure calculation method of the target well; S4. For target wells with distorted calculations, use modern production instability analysis methods or wellhead casing pressure conversion methods to correct them and obtain formation pressure; S5. Substituting the formation pressure into the software to generate a formation pressure distribution map; S6. Calculate the pressure loss rate using a pressure drop loss rate calculation model and generate a pressure loss rate curve graph; S7. Evaluate the remaining reserves of formation pressure through the formation pressure distribution diagram and the pressure loss rate curve diagram.

[0070] In S6, the pressure drop loss rate calculation model includes the early and late mathematical models of unstable seepage, where the equation of the early mathematical model of unstable seepage is as follows: (13) The mathematical model equation of the late stage of unstable seepage is as follows:

[0071] (14) (15) The mathematical model equations for calculating the pressure drop loss rate at any location in the gas reservoir at any time are as follows: (16) (17) Where, is the pressure drop at any position in the gas well at any time, dimensionless; is the original formation pressure; is the gas well production under standard conditions; is the viscosity of natural gas at original pressure and temperature; is the comprehensive compressibility coefficient at the original pressure and temperature; is the viscosity of natural gas at average pressure and temperature; is the natural gas deviation factor at mean pressure and temperature; is the air layer temperature; is the gas layer permeability; is the thickness of the gas layer; is the pressure conductivity coefficient; For time; is the gas volume coefficient; is the supply radius; is the radius of the gas well; is the porosity; is the average pressure at time t at a distance r from the well.

Claims

1. A method for evaluating remaining reserves in low-permeability gas reservoir formations, characterized in that: The specific steps include: S1. Obtain block production data and basic parameters through target wells; S2. Based on production data and basic parameters, the formation pressure is calculated using the material balance method, the wellhead casing pressure conversion method, the flowing material balance method, and the modern production instability analysis method. The absolute and relative errors of the different calculation methods are then calculated. S3. By comparing the absolute error and the relative error, the algorithm with the smallest error value is selected as the formation pressure calculation method of the target well; S4. For target wells with distorted calculations, use modern production instability analysis methods or wellhead casing pressure conversion methods to correct them and obtain formation pressure; S5. Substituting the formation pressure into the software to generate a formation pressure distribution map; S6. Calculate the pressure loss rate using a pressure drop loss rate calculation model and generate a pressure loss rate curve graph; S7. Evaluate the remaining reserves of formation pressure through the formation pressure distribution diagram and the pressure loss rate curve diagram.

2. The method for evaluating remaining reserves of low-permeability gas reservoirs according to claim 1, wherein: The production data includes static data and dynamic data, wherein the static data includes: effective thickness, permeability, porosity, and water saturation; the dynamic data includes: cumulative water production, cumulative gas production, and water-gas ratio.

3. The method for evaluating remaining reserves of low-permeability gas reservoir formations according to claim 1, wherein: The material balance method includes: using the regression equation between apparent formation pressure and cumulative gas production to calculate the formation pressure under different production rates. Without considering bound water and rock elastic deformation, the material balance equation of the water-flooded gas reservoir is derived as follows: （1） Where, is the water intrusion, is the cumulative gas production, is the cumulative water production, is the original geological reserves, is the original volume coefficient of the gas; is the gas volume coefficient; is the volume coefficient of water; The ratio of the volume of natural gas under formation conditions to the volume of natural gas under standard surface conditions is the natural gas volume coefficient. When the reservoir pressure is P and the temperature is T, the natural gas state equation can be combined to obtain the natural gas volume coefficient calculation formula: （2） （3） Where, is the formation temperature, is the ground temperature under standard conditions, is the original formation pressure, is the current formation pressure, is the pressure under standard ground conditions, is the deviation coefficient of natural gas at the original pressure Pi, is the deviation coefficient of natural gas at pressure P; Will 、 Substituting the calculation formula into formula (1), we can get the current formation pressure P: （4） in The formula is as follows: （5）。 4. The method for evaluating remaining reserves of low-permeability gas reservoir formations according to claim 3, wherein: In the material balance method, when there is no water flooding in the gas reservoir, that is, when the water-free gas reservoir has We = 0 and Wp = 0, Equation (4) is transformed into: （6） For closed water-producing gas reservoirs, Equation (4) is converted to: （7）。 5. The method for evaluating remaining reserves of low-permeability gas reservoir formations according to claim 1, wherein: The wellhead casing pressure deduction algorithm includes: after the production gas well is shut in until the entire formation pressure reaches a balanced state, the wellbore pressure gradient and the wellhead pressure have a linear formula as follows: （8） The calculation formula of formation pressure is: （9） Where, is the wellbore pressure gradient, is the gas wellhead flowing pressure, For the depth down to the middle of the gas layer, It is the formation pressure after the well is shut in for a long time.

6. The method for evaluating remaining reserves of low permeability gas reservoirs according to claim 1, wherein: The flow material balance method includes: The bottom hole flowing pressure and cumulative gas production have a binomial relationship: （10） The relationship between wellhead casing pressure and cumulative gas production is: （11） Determine the formation pressure calculation formula: （12） Where, is the bottom hole flowing pressure of the gas well, It is the formation pressure during quasi-steady-state production of the gas well.

7. The method for evaluating remaining reserves of low permeability gas reservoirs according to claim 1, characterized in that: The modern production instability analysis method includes: using the Blasingame model to normalize the production data of low-porosity and low-permeability fractured gas wells after fracturing, fitting the production integral and production integral differential curves through material balance time, inverting the permeability, skin coefficient, effective recovery rate and recoverable reserves, and establishing a fracture model based on the results to predict production performance.

8. The method for evaluating remaining reserves of low-permeability gas reservoir formations according to claim 1, wherein: In S6, the pressure drop loss rate calculation model includes the early and late mathematical models of unstable seepage, wherein the equation of the early mathematical model of unstable seepage is as follows: （13） The mathematical model equation of the late stage of unstable seepage is as follows: （14） （15） The mathematical model equations for calculating the pressure drop loss rate at any location in the gas reservoir at any time are as follows: （16） （17） Where, is the pressure drop at any position in the gas well at any time, dimensionless; is the original formation pressure; is the gas well production under standard conditions; is the viscosity of natural gas at original pressure and temperature; is the comprehensive compressibility coefficient at the original pressure and temperature; is the viscosity of natural gas at average pressure and temperature; is the natural gas deviation factor at average pressure and temperature; is the air layer temperature; is the gas layer permeability; is the thickness of the gas layer; is the pressure conductivity coefficient; For time; is the gas volume coefficient; is the supply radius; is the radius of the gas well; is the porosity; is the average pressure at time t at a distance r from the well.

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