A method and system for calculating interwell formation pressure after a shale gas platform is put into production

Abstract

This invention provides a method and system for calculating inter-well formation pressure after a shale gas platform is put into production. The method includes: calculating the recovery degree R based on EUR and the current cumulative gas production Gp; and calculating the average formation pressure P under the original conditions. i Gas deviation factor Z under original conditions i EUR and Gp are used to calculate P1; a ~R diagram is plotted and a binomial fit is performed to obtain the deviation coefficient σ; P'2 is the measured formation pressure, P'1 is the formation static pressure, Z'1 is the gas deviation factor corresponding to P'1, and Z'2 is the gas deviation factor corresponding to P'2; P2 is calculated based on σ and P1; in the later stage of production, shale gas wells reach the boundary control flow stage, utilizing the formation pressure p at the gas supply boundary. e The Darcy steady-state flow formula for radial flow in a fracturing plane describes the formation pressure p(r) at any distance from the well in the reservoir. The system described above can implement this method. This invention can calculate the formation pressure drop after production commences.

Description

Technical Field

[0001] This invention relates to the field of shale gas well exploration and development technology, specifically to a method and system for calculating inter-well formation pressure after a shale gas platform is put into production. Background Technology

[0002] The survey revealed that currently available methods for calculating shale gas formation pressure all predict regional formation pressure based on well logging or logging parameters. For example, patent applications such as "Application No. CN201710512097.8, entitled 'Shale Gas Reservoir Formation Pressure Calculation Method and Computer-Readable Storage Medium'" and "Application No. CN202010228391.8, entitled 'Formation Pressure Calculation Method and Apparatus for Shale Gas Wells'" mostly use only static data to predict the original formation pressure and cannot consider the changes in formation pressure between platforms and wells after the shale gas wells are put into production.

[0003] Due to the extremely low permeability of shale reservoirs, well shut-in times during gas well pressure recovery tests can be as long as one month. Even with this, the semi-logarithmic pressure recovery curve often lacks a clear linear segment, and the interpretation of the double-logarithmic pressure recovery curve rarely reveals radial flow characteristics. Furthermore, the interpretation of formation pressure using the double-logarithmic pressure recovery curve carries significant uncertainty. Therefore, conventional methods for obtaining formation pressure from shale gas wells after production through unstable well testing have clear limitations. Consequently, providing a method and system for calculating inter-well formation pressure after shale gas platform production is of great significance. Summary of the Invention

[0004] In view of the shortcomings of the prior art, the purpose of this invention is to solve one or more problems existing in the prior art. For example, one objective of this invention is to solve the problem that it is currently impossible to calculate the formation pressure profile that has decreased after production.

[0005] To achieve the above objectives, the present invention provides a method for calculating inter-well formation pressure after a shale gas platform is put into production, the method comprising:

[0006] The recovery rate R is calculated based on the final recoverable reserves EUR of shale gas wells and the current cumulative gas production Gp.

[0007] Based on the mean formation pressure P under the original conditions i Gas deviation factor Z under original conditions i The final recoverable reserves (EUR) and current cumulative gas production (Gp) of shale gas wells are used to calculate the average formation pressure (P1) within the current well control area using the gas reservoir mass balance method.

[0008] Collect data from other shale gas wells within the block that have essentially the same geological and engineering conditions and measured static pressure data. The measured formation pressure is P'2, and P'1 is the formation static pressure calculated using conventional gas reservoir mass balance methods during the testing of other shale gas wells. The relationship diagram was obtained, and the binomial formula was used for fitting to obtain the deviation coefficient σ under different extraction degrees R; Z'1 is the gas deviation factor corresponding to P'1, and Z'2 is the gas deviation factor corresponding to P'2;

[0009] The average formation pressure P2 within the current well control range is calculated and corrected based on σ and P1.

[0010] In the later stages of shale gas well production, the well reaches the boundary control flow stage. At a given moment, the reservoir-wellbore flow is considered a steady radial flow, based on the formation pressure p at the gas supply boundary. e The Darcy steady-state flow formula for radial flow in a plane after fracturing describes the formation pressure p(r) at any distance from the well in the reservoir.

[0011] According to one or more exemplary embodiments of one aspect of the present invention, the well control range may be half of the well spacing L.

[0012] According to one or more exemplary embodiments of one aspect of the present invention, the calculation of the sampling degree R may include:

[0013]

[0014] In the formula, R represents the extraction degree, %; G p For the current cumulative gas production, 10 8 m 3 EUR represents ultimate recoverable reserves, 10 8 m 3 .

[0015] According to one or more exemplary embodiments of one aspect of the present invention, the final recoverable reserves EUR may be obtained by one or more methods selected from the following methods: the production estimation method based on analogy with the same geological area, the production dynamics analogy, the production decline method, and the analytical model method.

[0016] According to one or more exemplary embodiments of one aspect of the present invention, calculating the average formation pressure P1 within the current well control range may include:

[0017]

[0018] In the formula, P1 is the average formation pressure under the current conditions, in MPa; P i Z is the mean formation pressure under the original conditions, in MPa; Z1 is the gas deviation factor under the current conditions, dimensionless; Z i The gas deviation factor under the original conditions is dimensionless; Gp is ​​the current cumulative gas production, 10 8 m 3 EUR represents ultimate recoverable reserves, 10 8 m 3 .

[0019] According to one or more exemplary embodiments of one aspect of the present invention, the calculation of the average formation pressure P2 within the current well control range may include:

[0020]

[0021] In the formula, P2 is the average formation pressure within the current well control range, in MPa; Z2 is the gas deviation factor corresponding to P2, dimensionless; σ is the deviation coefficient, dimensionless; P1 is the average formation pressure under the current conditions, in MPa; Z1 is the gas deviation factor under the current conditions, dimensionless.

[0022] According to one or more exemplary embodiments of one aspect of the present invention, the formation pressure p(r) may include:

[0023]

[0024] In the formula, p(r) is the pressure at any distance r from the well, in MPa; p e P represents the pressure at the vent boundary, in MPa. i >p e >P2; r is the distance from the vent boundary to the well, in meters; x f The effective fracture half-length is in meters (m); L is the well spacing in meters (m); p wf The bottom hole flowing pressure is in MPa.

[0025] The formation pressure p at the gas supply boundary was obtained by using a trial-and-error method to achieve the average formation pressure within the well control range. e :

[0026] when At that time, the p was tried out e This is the correct value.

[0027] According to one or more exemplary embodiments of one aspect of the present invention, the current bottom hole flowing pressure p can be obtained using a gas-liquid two-phase wellbore flow pressure calculation method. wf .

[0028] According to one or more exemplary embodiments of one aspect of the present invention, the effective infinite conductivity fracture half-length x is interpreted based on pressure recovery well testing. f The formation pressure profile at the wellbore-vent boundary can be a two-section profile.

[0029] Another aspect of the present invention provides a formation pressure calculation system for shale gas platforms after commissioning. The system may include a recovery degree calculation unit, a first calculation unit, a deviation coefficient calculation unit, a second calculation unit, and a formation pressure calculation unit, wherein...

[0030] The recovery degree calculation unit is connected to the deviation coefficient calculation unit, the second calculation unit is connected to the first calculation unit and the deviation coefficient calculation unit, and the second calculation unit is connected to the formation pressure calculation unit.

[0031] The recovery degree calculation unit is configured to calculate the recovery degree R based on the final recoverable reserves EUR of the shale gas well and the current cumulative gas production Gp;

[0032] The first calculation unit is configured to calculate the mean formation pressure P under the original conditions. i Gas deviation factor Z under original conditions i The final recoverable reserves (EUR) and current cumulative gas production (Gp) of shale gas wells are used to calculate the average formation pressure (P1) within the current well control area using the gas reservoir mass balance method.

[0033] The deviation coefficient calculation unit is configured to collect data from other shale gas wells within the block that have essentially the same geological and engineering conditions and measured static pressure data. The measured formation pressure is P'2, and P'1 is the formation static pressure calculated using conventional gas reservoir material balance methods during the testing of other shale gas wells. The relationship diagram was obtained, and the binomial formula was used for fitting to obtain the deviation coefficient σ under different extraction degrees R; Z'1 is the gas deviation factor corresponding to P'1, and Z'2 is the gas deviation factor corresponding to P'2;

[0034] The second calculation unit is configured to calculate and correct the average formation pressure P2 within the current well control range based on σ and P1.

[0035] The formation pressure calculation unit was configured for the late-stage shale gas well reaching the boundary control flow phase. At a given moment, the reservoir-wellbore flow was considered a steady radial flow, based on the formation pressure p at the gas supply boundary. e The Darcy steady-state flow formula for radial flow in a plane after fracturing describes the formation pressure p(r) at any distance from the well in the reservoir.

[0036] Compared with the prior art, the beneficial effects of the present invention include at least one of the following:

[0037] (1) Based on production, pressure, well spacing, well test interpretation parameters, etc., this invention analyzes the distribution pattern of formation pressure profile, and uses a trial-and-error method to obtain the average formation pressure within the well control range to obtain the formation pressure at the gas supply boundary, thereby obtaining the formation pressure at any position between wells.

[0038] (2) Based on the evaluation results of actual development effects, this invention uses the gas well production, pressure, and pressure recovery test interpretation to solve the problem that the formation pressure profile that has decreased after production cannot be calculated. It is highly adaptable to shale gas wells.

[0039] (3) This invention takes into account the extremely low permeability outside the well control boundary of shale gas wells and the fixed characteristics of the well control boundary during the boundary control flow stage. It adopts the principle of material balance of closed constant volume gas reservoirs and calculates the formation pressure distribution based on the distribution characteristics of formation pressure drop after gas well production, using dynamic reserves, current cumulative gas production, and bottom hole pressure. It can be used to calculate the formation pressure between wells after the shale gas platform is put into production. Attached Figure Description

[0040] The above and other objects and features of the present invention will become clearer from the following description taken in conjunction with the accompanying drawings, in which:

[0041] Figure 1 Example 1 is shown Relationship diagram;

[0042] Figure 2 The distribution pattern of formation pressure between platform wells is shown;

[0043] Figure 3 A schematic diagram of the inter-well formation pressure calculation system after the shale gas platform of the present invention is shown. Detailed Implementation

[0044] In the following description, a method and system for calculating inter-well formation pressure after a shale gas platform is put into production will be described in detail with reference to the accompanying drawings and exemplary embodiments.

[0045] Exemplary Example 1

[0046] This exemplary embodiment provides a method for calculating inter-well formation pressure after a shale gas platform is put into production.

[0047] The main methods for calculating inter-well formation pressure after a shale gas platform goes into production include:

[0048] S1. Calculate the recovery rate R based on the final recoverable reserves EUR of the shale gas well and the current cumulative gas production Gp.

[0049] S2, Based on the average formation pressure P under the original conditions i Gas deviation factor Z under original conditions i The final recoverable reserves (EUR) and current cumulative gas production (Gp) of shale gas wells are used to calculate the average formation pressure (P1) within the current well control area using the gas reservoir mass balance method.

[0050] S3. Collect other shale gas wells within the block with basically the same geological and engineering conditions and measured static pressure data. Their measured formation pressure is P'2, and P'1 is the formation static pressure calculated using conventional gas reservoir mass balance methods during the testing of other shale gas wells. The relationship diagram was obtained, and a binomial fit was used to obtain the deviation coefficient σ under different extraction degrees R; P'2 is the measured formation pressure, Z'1 is the gas deviation factor corresponding to P'1, and Z'2 is the gas deviation factor corresponding to P'2.

[0051] S4. Calculate and correct the average formation pressure P2 within the current well control range based on σ and P1.

[0052] S5. In the later stages of shale gas well production, the well reaches the boundary control flow stage. At a certain point in time, the reservoir-wellbore flow is considered a steady radial flow, based on the formation pressure p at the gas supply boundary. e The Darcy steady-state flow formula for radial flow in a plane after fracturing describes the formation pressure p(r) at any distance from the well in the reservoir.

[0053] In this exemplary embodiment, the formation pressure p(r) can be expressed as:

[0054]

[0055] In the formula, p(r) is the pressure at any distance r from the well, in MPa; p e P represents the pressure at the vent boundary, in MPa. i >p e >P2; r is the distance from the vent boundary to the well, in meters; x f The effective fracture half-length is in meters (m); L is the well spacing in meters (m); p wf The bottom hole pressure is MPa.

[0056] Based on the pressure recovery well test interpretation, the effective infinite-conductivity fracture half-length x f The formation pressure profile from the wellbore to the venting boundary can be a two-section profile. The well control range is taken as half of the well spacing L, i.e., L / 2.

[0057] The formation pressure p at the gas supply boundary was obtained by using a trial-and-error method to achieve the average formation pressure within the well control range. e :

[0058] when At that time, the p was tried out e This is the correct value.

[0059] Furthermore, the current bottom hole flowing pressure p wf The pressure can be obtained using the gas-liquid two-phase wellbore flow calculation method.

[0060] In this exemplary embodiment, calculating the extraction degree R may include:

[0061]

[0062] In the formula, R represents the extraction degree, %; G p For the current cumulative gas production, 108 m 3 EUR represents ultimate recoverable reserves, 10 8 m 3 .

[0063] Furthermore, the final recoverable reserves (EUR) can be obtained through methods such as the production estimation method based on analogy with the same geological area, production dynamics analogy, production decline method, and analytical model method.

[0064] In this exemplary embodiment, calculating the average formation pressure P1 within the current well control range may include:

[0065]

[0066] In the formula, P1 is the average formation pressure under the current conditions, in MPa; P i Z1 is the mean formation pressure under the original conditions, in MPa; Z2 is the gas deviation factor under the current conditions (i.e., the gas deviation factor corresponding to P1), dimensionless; Z3 is the average formation pressure under the original conditions, in MPa; Z4 is the average formation pressure under the original conditions, in MPa; Z5 is the average formation pressure under the original conditions, in MPa; Z6 is the average formation pressure under the current conditions, in MPa; Z7 is the average formation pressure under the original conditions, in MPa; Z8 i The gas deviation factor under the original conditions is dimensionless; Gp is ​​the current cumulative gas production, 10 8 m 3 EUR represents ultimate recoverable reserves, 10 8 m 3 .

[0067] In this exemplary embodiment, calculating the corrected mean formation pressure P2 within the current well control range may include:

[0068]

[0069] In the formula, P2 is the average formation pressure within the current well control range, in MPa; Z2 is the gas deviation factor corresponding to P2, dimensionless; σ is the deviation coefficient, dimensionless; P1 is the average formation pressure under the current conditions, in MPa; Z1 is the gas deviation factor under the current conditions, dimensionless.

[0070] Exemplary Example 2

[0071] This exemplary embodiment provides another method for calculating inter-well formation pressure after a shale gas platform is put into production.

[0072] The method for calculating inter-well formation pressure after a shale gas platform is put into production in this exemplary embodiment may include the following:

[0073] (1) Based on one or more of the following methods, such as the production prediction method based on the same geological region, the production dynamics analogy, the production decline method, and the analytical model method, predict the final recoverable reserves (EUR) of the gas well.

[0074] (2) Calculate the extraction degree according to the following formula:

[0075] Formula 1:

[0076] In the formula, R represents the extraction degree, %; G p For the current cumulative gas production, 10 8 m 3 EUR represents ultimate recoverable reserves, 10 8 m 3 .

[0077] (3) Using the current gas production rate, calculate the initial value of the average formation pressure P1 within the current well control area according to the conventional gas reservoir material balance:

[0078] Formula 2:

[0079] In the formula, P1 is the average formation pressure under the current conditions, in MPa; P i Z is the mean formation pressure under the original conditions, in MPa; Z1 is the gas deviation factor under the current conditions, dimensionless; Z i The gas deviation factor under the original conditions is dimensionless; Gp is ​​the current cumulative gas production, 10 8 m 3 EUR represents ultimate recoverable reserves, 10 8 m 3 .

[0080] (4) The average formation pressure P2 within the current well control range is calculated and corrected using the deviation coefficient σ of the mass balance between the low-permeability gas reservoir and the conventional gas reservoir after fracturing:

[0081] Formula 3:

[0082] In the formula, P2 is the average formation pressure within the current well control range, in MPa; Z2 is the gas deviation factor corresponding to P2, dimensionless; σ is the deviation coefficient, dimensionless; P1 is the average formation pressure under the current conditions, in MPa; Z1 is the gas deviation factor under the current conditions, dimensionless.

[0083] In this step, the calculation steps for the deviation coefficient σ of the material balance between the low-permeability gas reservoir and the conventional gas reservoir after fracturing are as follows:

[0084] Collect shale gas wells with similar geological and engineering conditions and measured static pressure data within the block. The measured formation pressure is P'2. Calculate the formation static pressure P'1 during the test using conventional gas reservoir mass balance methods. A relationship diagram was plotted and fitted using a binomial function, such as... Figure 1 As shown, different extraction levels can be obtained. This is also known as the deviation coefficient σ. Here, Z'1 is the gas deviation factor corresponding to P'1, and Z'2 is the gas deviation factor corresponding to P'2.

[0085] (5) When a gas well is in self-flowing production, the current bottom hole flowing pressure p is calculated based on the wellhead pressure, gas production, and liquid production, using the gas-liquid two-phase wellbore flow pressure calculation method. wf .

[0086] (6) Based on the interpretation of pressure recovery well tests, the effective half-length x of the infinite conductivity fracture is... f The formation pressure profile at the wellbore-vent boundary is a two-section structure, as shown below. Figure 2 As shown, the crack is an infinitely conductive crack, and the linear flow pressure loss within the crack can be ignored.

[0087] (7) Shale reservoirs have extremely low permeability. When deploying shale gas development platforms, the distance between horizontal wells within the platform is relatively small. After large-scale fracturing, the degree of reservoir utilization between wells is high. Therefore, the well control range is taken as half of the well spacing L, which is L / 2.

[0088] (8) In the later stages of production, shale gas wells reach the boundary control flow stage. For a certain moment, the reservoir-wellbore flow can be regarded as a steady radial flow. The Darcy steady-state flow formula for planar radial flow after fracturing is used to describe the pressure p(r) at any distance r from the well in the reservoir:

[0089] Formula 4:

[0090] In the formula, p(r) is the pressure at any distance r from the well, in MPa; p e The pressure at the vent boundary is MPa; r is the distance from the vent boundary to the well, m; x f The effective fracture half-length is in meters (m); L is the well spacing in meters (m); p wf The bottom hole pressure is MPa.

[0091] (9) Integrate the expression for formation pressure p(r):

[0092]

[0093] Where, p e The unknown is the pressure p at the gas leakage boundary, which decreases due to the drop in formation pressure after the gas well is put into production. e The following relationship exists: P i >p e >P2. Therefore, we assume p using the trial-and-error method. e value.

[0094] (10) According to Figure 2 ,when At that time, the p was tried out e This is the correct value.

[0095] (11) According to the above formula 4 It can calculate the formation pressure at a distance r from the wellbore.

[0096] Exemplary Example 3

[0097] This exemplary embodiment provides a system for calculating inter-well formation pressure after a shale gas platform is put into production.

[0098] The inter-well formation pressure calculation system after the shale gas platform is put into operation can realize the inter-well formation pressure calculation method described in Exemplary Example 1 or Exemplary Example 2 above.

[0099] The inter-well formation pressure calculation system after the shale gas platform is put into operation in this exemplary embodiment may include, for example: Figure 3 The diagram shows a production recovery calculation unit, a first calculation unit, a deviation coefficient calculation unit, a second calculation unit, and a formation pressure calculation unit. The production recovery calculation unit is connected to the deviation coefficient calculation unit, the second calculation unit is connected to the first calculation unit and the deviation coefficient calculation unit, and the second calculation unit is connected to the formation pressure calculation unit.

[0100] The recovery degree calculation unit is configured to calculate the recovery degree R based on the final recoverable reserves EUR of the shale gas well and the current cumulative gas production Gp.

[0101] The first calculation unit is configured to calculate the mean formation pressure P under the original conditions. i Gas deviation factor Z under original conditions i The final recoverable reserves (EUR) and current cumulative gas production (Gp) of shale gas wells are used to calculate the average formation pressure (P1) within the current well control area using the gas reservoir mass balance method.

[0102] The deviation coefficient calculation unit is configured to collect data from other shale gas wells within the block that have essentially the same geological and engineering conditions and measured static pressure data. The measured formation pressure is P'2, and P'1 is the formation static pressure calculated using conventional gas reservoir material balance methods during the testing of other shale gas wells. The relationship diagram was obtained, and a binomial fit was used to obtain the deviation coefficient σ under different extraction degrees R; Z'1 is the gas deviation factor corresponding to P'1, and Z'2 is the gas deviation factor corresponding to P'2.

[0103] The second calculation unit is configured to calculate the corrected average formation pressure P2 within the current well control range based on σ and P1.

[0104] The formation pressure calculation unit was configured for the late-stage shale gas well reaching the boundary control flow phase. At a given moment, the reservoir-wellbore flow was considered a steady radial flow, based on the formation pressure p at the gas supply boundary. e The Darcy steady-state flow formula for radial flow in a plane after fracturing describes the formation pressure p(r) at any distance from the well in the reservoir.

[0105] To better understand the exemplary embodiments of the present invention described above, further explanation is provided below with reference to specific examples.

[0106] Example 1

[0107] In this example, the formation between wells in the Changning shale gas field is predicted after one well is put into production, including the following steps:

[0108] 1. Predict the final recoverable reserves (EUR) of gas wells using methods such as the production estimation method based on the same geological region analogy, production dynamic analogy, production decline method, and analytical model method.

[0109] 2. Calculate the degree of extraction:

[0110]

[0111] The calculated parameters for this well are shown in the table below:

[0112] Parameter name numerical values <![CDATA[Cumulative gas production (10 8 m 3 )]]> 0.72 <![CDATA[EUR(10 8 m 3 )]]> 1.39 Recovery rate (%) 64 Bottom hole flowing pressure (MPa) 7.5 Well spacing (m) 400 Crack half length (m) 65

[0113] 3. Calculate formation pressure P1 based on conventional gas reservoir material balance:

[0114]

[0115] According to the above formula, P1 is 19.78 MPa.

[0116] 4. Calculate the deviation coefficient: With a recovery rate of 64%, based on... Figure 1 The relationship shown is (y = 0.0001x) 2 The deviation coefficient σ is calculated to be 0.58 (-0.0137x+0.9289).

[0117] 5. Calculate the corrected formation pressure P2:

[0118]

[0119] According to the above formula, P2 is 17 MPa.

[0120] 6. Based on the bottom hole flowing pressure of 7.5 MPa, by trial and error and according to Equation 4, the formation pressure at a distance of 200 m from the wellbore is calculated to be 29 MPa.

[0121] In summary, the beneficial effects include:

[0122] This invention provides a method and system for calculating inter-well formation pressure after a shale gas platform is put into production, primarily applied in the field of shale gas well exploration and development. This invention considers the extremely low permeability outside the well control boundary of shale gas wells and the fixed characteristics of the well control boundary during the boundary-controlled flow stage. It adopts the principle of material balance in closed, constant-volume gas reservoirs and calculates the formation pressure distribution based on the distribution characteristics of formation pressure decline after gas well production, using dynamic reserves, current cumulative gas production, and bottom hole pressure. This method can be used for calculating inter-well formation pressure after a shale gas platform is put into production. Based on production, pressure, well spacing, and well test interpretation parameters, a formation pressure profile distribution morphology analysis is performed. The formation pressure at the gas supply boundary is obtained by using a trial-and-error method to achieve the average formation pressure within the well control range, thus allowing the calculation of formation pressure at any location between wells. Based on the evaluation results of actual development effects, the invention utilizes gas well production, pressure, and pressure recovery well test interpretation data, solving the current problem of not being able to calculate the formation pressure profile that has declined after production. This method is highly adaptable to shale gas wells.

[0123] Although the invention has been described above in conjunction with exemplary embodiments, those skilled in the art will understand that various modifications and changes can be made to the exemplary embodiments of the invention without departing from the spirit and scope defined by the claims.

Claims

1. A method for calculating inter-well formation pressure after a shale gas platform is put into production, characterized in that, The method includes: The recovery rate R is calculated based on the final recoverable reserves EUR of shale gas wells and the current cumulative gas production Gp. Based on the mean formation pressure P under the original conditions i Gas deviation factor Z under original conditions i The final recoverable reserves (EUR) and current cumulative gas production (Gp) of shale gas wells are used to calculate the average formation pressure (P1) within the current well control area using the gas reservoir mass balance method. Collect data from other shale gas wells within the block that have essentially the same geological and engineering conditions and measured static pressure data. The measured formation pressure is P'2, and P'1 is the formation static pressure calculated using conventional gas reservoir mass balance methods during the testing of other shale gas wells. The relationship diagram was obtained, and the binomial formula was used for fitting to obtain the deviation coefficient σ under different extraction degrees R; Z'1 is the gas deviation factor corresponding to P'1, and Z'2 is the gas deviation factor corresponding to P'2; The average formation pressure P2 within the current well control range is calculated and corrected based on σ and P1. In the later stages of shale gas well production, the well reaches the boundary control flow stage. At a given moment, the reservoir-wellbore flow is considered a steady radial flow, based on the formation pressure p at the gas supply boundary. e The Darcy steady-state flow formula for radial flow in a plane after fracturing describes the formation pressure p(r) at any distance from the well in the reservoir.

2. The method for calculating inter-well formation pressure after a shale gas platform is put into production according to claim 1, characterized in that, The well control range is taken as half of the well spacing L.

3. The method for calculating inter-well formation pressure after a shale gas platform is put into production according to claim 1, characterized in that, The calculation of the extraction degree R includes: In the formula, R represents the extraction degree, %; G p For the current cumulative gas production, 10 8 m 3 EUR represents ultimate recoverable reserves, 10 8 m 3 .

4. The method for calculating inter-well formation pressure after a shale gas platform is put into production according to claim 1 or 3, characterized in that, The final recoverable reserves (EUR) are obtained using one or more of the following methods: production estimation based on analogy with similar geological areas, production dynamics analogy, production decline method, and analytical model method.

5. The method for calculating inter-well formation pressure after a shale gas platform is put into production according to claim 1, characterized in that, The calculation of the average formation pressure P1 within the current well control area includes: In the formula, P1 is the average formation pressure under the current conditions, in MPa; P i Z is the mean formation pressure under the original conditions, in MPa; Z1 is the gas deviation factor under the current conditions, dimensionless; Z i The gas deviation factor under the original conditions is dimensionless; Gp is ​​the current cumulative gas production, 10 8 m 3 EUR represents ultimate recoverable reserves, 10 8 m 3 .

6. The method for calculating inter-well formation pressure after a shale gas platform is put into production according to claim 1, characterized in that, The calculation correction for the average formation pressure P2 within the current well control range includes: In the formula, P2 is the average formation pressure within the current well control range, in MPa; Z2 is the gas deviation factor corresponding to P2, dimensionless; σ is the deviation coefficient, dimensionless; P1 is the average formation pressure under the current conditions, in MPa; Z1 is the gas deviation factor under the current conditions, dimensionless.

7. The method for calculating inter-well formation pressure after a shale gas platform is put into production according to claim 1, characterized in that, The formation pressure p(r) includes: In the formula, p(r) is the pressure at any distance r from the well, in MPa; p e P represents the pressure at the vent boundary, in MPa. i >p e >P2; r is the distance from the vent boundary to the well, in meters; x f The effective fracture half-length is in meters (m); L is the well spacing in meters (m); p wf The bottom hole flowing pressure is in MPa. The formation pressure p at the gas supply boundary was obtained by using a trial-and-error method to achieve the average formation pressure within the well control range. e : when At that time, the p was tried out e This is the correct value.

8. The method for calculating inter-well formation pressure after a shale gas platform is put into production according to claim 7, characterized in that, The current bottom hole flowing pressure p is obtained using a gas-liquid two-phase wellbore flow pressure calculation method. wf .

9. The method for calculating inter-well formation pressure after a shale gas platform is put into production according to claim 7, characterized in that, Based on the pressure recovery well test interpretation, the effective infinite-conductivity fracture half-length x f The formation pressure profile at the wellbore-vent boundary is a two-section structure.

10. A system for calculating inter-well formation pressure after a shale gas platform is put into production, characterized in that, The system includes a recovery degree calculation unit, a first calculation unit, a deviation coefficient calculation unit, a second calculation unit, and a formation pressure calculation unit, wherein, The recovery degree calculation unit is connected to the deviation coefficient calculation unit, the second calculation unit is connected to the first calculation unit and the deviation coefficient calculation unit, and the second calculation unit is connected to the formation pressure calculation unit. The recovery degree calculation unit is configured to calculate the recovery degree R based on the final recoverable reserves EUR of the shale gas well and the current cumulative gas production Gp; The first calculation unit is configured to calculate the mean formation pressure P under the original conditions. i Gas deviation factor Z under original conditions i The final recoverable reserves (EUR) and current cumulative gas production (Gp) of shale gas wells are used to calculate the average formation pressure (P1) within the current well control area using the gas reservoir mass balance method. The deviation coefficient calculation unit is configured to collect data from other shale gas wells within the block that have essentially the same geological and engineering conditions and measured static pressure data. The measured formation pressure is P'2, and P'1 is the formation static pressure calculated using conventional gas reservoir material balance methods during the testing of other shale gas wells. The relationship diagram was obtained, and the binomial formula was used for fitting to obtain the deviation coefficient σ under different extraction degrees R; Z'1 is the gas deviation factor corresponding to P'1, and Z'2 is the gas deviation factor corresponding to P'2; The second calculation unit is configured to calculate and correct the average formation pressure P2 within the current well control range based on σ and P1. The formation pressure calculation unit was configured for the late-stage shale gas well reaching the boundary control flow phase. At a given moment, the reservoir-wellbore flow was considered a steady radial flow, based on the formation pressure p at the gas supply boundary. e The Darcy steady-state flow formula for radial flow in a plane after fracturing describes the formation pressure p(r) at any distance from the well in the reservoir.

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