A method and system for predicting formation pressure using combined well logging and seismic velocity correction

Abstract

This invention relates to the field of formation pressure prediction technology, and particularly to a method and system for formation pressure prediction based on joint correction of well logging and seismic velocity. The method includes calculating the overlying strata pressure of a single well based on measured density and pressure data from drilled wells and inferring the Eaton index; resampling and gridding the parameters using the minimum curvature method, mapping them to a virtual grid plane of the entire formation profile; extracting measured well logging velocities and seismic average velocities; performing piecewise fitting according to velocity intervals and normal and overpressured strata; after error verification to determine the effectiveness of the fitted model, completing the seismic average velocity correction; and substituting the corrected velocity, gridded overlying strata pressure, and Eaton index into the Eaton formula to obtain continuous formation pressure prediction results for both well-drilled and non-well-drilled areas. This invention achieves formation pressure prediction for the entire area, effectively eliminates the systematic bias between seismic and well logging velocities, improves the accuracy and prediction precision of overpressured formation parameters, and possesses strong engineering practicality and promotional value.

Description

Technical Field

[0001] This invention relates to the field of formation pressure prediction technology, and in particular to a formation pressure prediction method and system based on joint correction of well logging and seismic velocity. Background Technology

[0002] In oil and gas exploration and development, formation pressure prediction is a crucial technical step in ensuring drilling safety and optimizing development plans. Traditional formation pressure prediction often employs the Eaton method, which relies on single-well logging data to calculate pressure at well locations. However, logging data is only valid for the well itself; in areas without wells, there is no measured data to calculate formation pressure. Therefore, it can only be used for single-well pressure calculations, failing to provide comprehensive and continuous formation pressure prediction results. Furthermore, when using the Eaton method to calculate formation pressure, seismic mean velocity is directly used as an input parameter. Because seismic data has a large vertical sampling interval and its vertical resolution is far lower than downhole logging data, there is a systematic deviation between seismic mean velocity and logging velocity. Directly using seismic mean velocity as a parameter will significantly increase the error in formation pressure prediction.

[0003] Chinese patent CN107843927A discloses a method and apparatus for predicting shale formation pressure based on combined well-seismic velocities (classification number G01V1 / 36). The method involves obtaining seismic layer velocities; calculating improved seismic layer velocities; calculating formation pressure based on the improved seismic layer velocities; calculating a correction pressure coefficient; and correcting the formation pressure using the correction pressure coefficient. This invention, based on the Fillpone pressure prediction empirical formula, selects a pseudo-acoustic curve to invert layer velocities, thereby obtaining improved layer velocities that better reflect the actual lithology of the formation. The formation pressure calculated using these improved layer velocities is more reasonable. Furthermore, based on the actual work area and actual formation, this invention obtains a correction pressure coefficient through statistical fitting of layer velocities and pressure correction coefficients, correcting the pressure prediction empirical formula, making the calculated pressure more applicable to the research area and more effective and reasonable. By improving the obtained seismic layer velocities to calculate formation pressure, and by performing exponential regression on the ratio of the layer velocity corresponding to the target layer in multiple wells within the study area to the measured pressure value and the calculated pressure value at that target layer, a corrected pressure coefficient is obtained. This corrected pressure coefficient is then used to correct the calculated formation pressure. By selecting layer velocities from simulated sonic curves, an improved layer velocity that accurately reflects the formation is obtained. Using this velocity, the calculated formation pressure is more reasonable. Furthermore, by obtaining the corrected pressure velocity from the actual study area and formation, the pressure prediction is further corrected, making the prediction results applicable to the study area.

[0004] Chinese patent CN120906540A discloses a well logging prediction method for shale reservoir formation pore pressure based on an improved Bowers equation (classification number E21B47 / 06). This method, combined with the Bowers equation, establishes an acoustic wave velocity response equation considering the influence of density and organic matter content. Immersion experiments are conducted on rock samples, and based on acoustic transit time, density, and shallow / deep resistivity from well logging data, hydration-corrected formation acoustic velocity and density are obtained. Based on the hydration-corrected acoustic velocity and density of the undisturbed formation, the Bowers equation for the studied formation is obtained. The Bowers equation for the studied formation is then modified to obtain an improved Bowers equation. Based on the improved Bowers equation, the effective formation stress and vertical stress are calculated. Based on the effective formation stress and vertical stress, the formation pore pressure is calculated. The modified Bowers formation pore pressure prediction model established in this application significantly improves prediction accuracy, which helps reduce the occurrence of construction accidents and lower development costs. An acoustic wave velocity response equation influencing density and organic matter content was established. The relationship between density, P-wave velocity, and resistivity under drilling fluid hydration was determined through rock immersion experiments. Hydration corrections were applied to the logging acoustic velocity and density. After fitting the original Bowers equation, an improved Bowers equation was obtained by combining formation density and organic carbon content to correct the unloading equation. This improved equation was then used to calculate the effective formation stress and vertical stress, and the difference between the two was used to determine the pore pressure. This method solves the problems of traditional Bowers equations not considering organic hydrocarbon generation corrections and drilling fluid intrusion hydration leading to distorted logging parameters and inaccurate pore pressure prediction.

[0005] Therefore, it is necessary to propose a formation pressure prediction method and system that combines well logging and seismic velocity correction to solve the above problems. Summary of the Invention

[0006] The purpose of this invention is to provide a method and system for predicting formation pressure by combining well logging and seismic velocity correction, in order to solve the problems that it is impossible to generate a global and continuous formation pressure prediction result and that the error in formation pressure prediction will be significantly larger when the average seismic velocity is directly used as a parameter for calculation.

[0007] To achieve the above objectives, the present invention provides the following technical solution: A method for predicting formation pressure using a combination of well logging and seismic velocity correction includes the following steps: The measured density and parameters of each well are taken from the well logging data of all drilled wells in the region. The overlying strata pressure of each well is calculated. The minimum curvature method is used for resampling and gridding to map the overlying strata pressure of each well to the virtual grid plane of the formation profile of the entire region. The measured pressure of each well is taken and combined with the parameters of each well to back-calculate the Eaton index of each well. When the Eaton index meets the resampling conditions, the minimum curvature method is used for resampling and gridding to map the Eaton index of each well to the virtual grid plane of the formation profile of the entire region. For all drilled wells, the measured logging velocity and the seismic mean velocity are extracted separately. The seismic mean velocity is then piecewise fitted to obtain the fitted logging velocity. The error between the measured logging velocity and the fitted logging velocity is calculated for each well and for each depth point to obtain the average error for the entire area. If the average error for the entire area meets the preset threshold, the fitting model is valid. The seismic mean velocity is then corrected using the fitting model, and the corrected seismic mean velocity is output. Based on the corrected average seismic velocity, the overlying strata pressure on the gridded surface, and the Eaton index, the formation pressure prediction results for the entire region are calculated by substituting them into the Eaton formula.

[0008] Preferably, the step of taking the measured density and parameters of a single well from the well logging data of all drilled wells in the entire area, calculating the overlying strata pressure of the single well, and resampling and gridding using the minimum curvature method to map the overlying strata pressure of the single well onto a virtual grid plane of the formation profile of the entire area includes: Obtain the measured density of all drilled wells in the region and the drilling depth in the parameters of individual wells; The density gradient formula is used to calculate the overlying strata pressure of a single well at depth points for each drilling depth using measured density. For the stratigraphic profile of the entire area, a virtual grid plane was constructed, and the minimum curvature method was used to smooth the overlying strata pressure data of a single well through interpolation and resampling to fully map it to all nodes of the virtual grid plane.

[0009] Preferably, the virtual grid plane includes a horizontal grid and a vertical grid, wherein the horizontal grid corresponds to the horizontal position of the stratigraphic profile of the entire area, and the vertical grid corresponds to the stratigraphic depth of the entire area.

[0010] Preferably, the step of taking the measured pressure of a single well, back-calculating the Eaton index of the single well based on the single well parameters, and when the Eaton index meets the resampling conditions, resampling and gridding using the minimum curvature method to map the Eaton index of the single well to a virtual grid plane of the entire formation profile includes: The measured pressure and single-well parameters of the drilled formation are obtained, and then substituted into the Eaton index back calculation formula to calculate the Eaton index of a single well at each depth point. For well locations with several measured pressures, multiple Eaton indices are calculated. When the drilling depth corresponding to the Eaton index does not exceed the top and bottom depths of the overpressure box, the median of all Eaton indices for that well is taken, and the Eaton index of a single well is resampled and mapped to a virtual grid plane using the minimum curvature method. When the drilling depth corresponding to the Eaton index exceeds the top and bottom depths of the overpressure box, the Eaton index of a single well is resampled and mapped to a virtual grid plane.

[0011] Preferably, for areas on the virtual grid plane where no wells are drilled, the Eaton index is supplemented using interpolation to obtain Eaton index parameters covering the entire stratigraphic profile.

[0012] Preferably, the steps of extracting the measured logging velocity and the seismic average velocity for each drilled well in the virtual grid plane, performing piecewise fitting based on the seismic average velocity to obtain the fitted logging velocity, and calculating the error between the measured logging velocity and the fitted logging velocity for each well and each depth point to obtain the average error for the entire area, and if the average error for the entire area meets a preset threshold, the fitting model is valid, and the seismic average velocity of the virtual grid plane is corrected using the fitting model, and the corrected seismic average velocity is output, include: Obtain the measured logging velocity and seismic average velocity for each drilled well and at each depth point; Based on the average seismic velocity, velocity intervals are divided. Based on the normal pressure region and overpressure region of the formation, the formation segments are divided. Based on the velocity intervals, the formation segments are combined with segmented fitting to calculate the fitted logging velocity at the corresponding depth point of each well. Based on the fitted logging rate, the fitting error is calculated in layers to obtain the average error for the entire area; The average error of the entire area is compared with the preset error threshold to determine the effectiveness of the piecewise fitting model. Using the effective fitting model, the average seismic velocity of the nodes of the virtual grid plane is corrected, and the corrected average seismic velocity is output.

[0013] Preferably, the steps of dividing the velocity range according to the average seismic velocity, dividing the formation into segments according to the normal pressure region and overpressure region of the formation, and performing segmented fitting based on the velocity range and the formation segments to calculate the fitted logging velocity at the corresponding depth point of each well include: Based on the average earthquake velocity, a first velocity interval and a second velocity interval are obtained. When the average earthquake velocity is in the first velocity interval, a linear fitting formula is used for fitting; when the average earthquake velocity is in the second velocity interval, a sine fitting formula is used for fitting. The overpressure zone was divided into stratigraphic segments, resulting in a normal compaction segment, a first overpressure segment, and a second overpressure segment. When fitting in segments, if the depth point is in the normal pressure region, then fitting is performed only based on the velocity range in which the seismic mean velocity is located; if the depth point is in any of the layers in the normal compaction zone, the first overpressure zone, or the second overpressure zone, then segmented fitting is performed based on the velocity range in which the seismic mean velocity is located. The fitting logging rate at the corresponding depth point of each well was calculated.

[0014] Preferably, the step of calculating the fitting error in layers based on the fitted logging rate to obtain the average error for the entire area includes: Based on the measured logging rate and the fitted logging rate, the relative error of a single depth point is calculated for each depth point. Calculate the average error of a single well by statistically analyzing the relative errors at all depth points. The average error for the entire region is calculated based on the average error of each drilled well in the region.

[0015] Preferably, the step of calculating the formation pressure prediction results for the entire area by substituting the corrected average seismic velocity, the overlying strata pressure on the virtual grid plane, and the Eaton index into the Eaton formula includes: The corrected average seismic velocity, the overlying strata pressure on the grid, and the Eaton index correspond to each node of the virtual grid plane. The parameters corresponding to the nodes are substituted into the Eaton formula to calculate the formation fluid pressure at each node, so as to output the formation pressure prediction results for well-controlled and well-free areas in the whole region.

[0016] A formation pressure prediction system with combined well logging and seismic velocity correction includes: The single-well parameter gridding module is used to calculate the overlying strata pressure and Eaton index of a single well, and maps them to the virtual grid plane of the entire stratigraphic profile using the minimum curvature method; The velocity fitting modeling module is used to extract the measured logging velocity of drilled wells and the average seismic velocity, and to complete the segmented fitting according to the velocity range and overpressure segment; The fitting accuracy verification module is used to calculate the fitting error point by point, well by well, and across the entire area, and to determine the effectiveness of the piecewise fitting model. The earthquake velocity correction module is used to correct the global average earthquake velocity using an effective fitting model. The whole-area pressure calculation module substitutes the corrected seismic average velocity and gridded parameters into the Eaton formula to calculate and output the whole-area formation pressure prediction results.

[0017] The technical effects and advantages of the present invention in the above technical solution are as follows: 1. This invention uses the minimum curvature method to map the overlying strata pressure and Eaton index of a single well onto a virtual grid plane of the entire area, thereby filling the parameter gaps in wellless areas, realizing formation pressure prediction in both well-covered and wellless areas, and improving the spatial applicability of the prediction results.

[0018] 2. This invention uses a segmented fitting model of velocity range and overpressure zone to complete velocity correction by combining multi-level error verification. This enables the corrected average seismic velocity to cover well-free areas, improves data accuracy, and reduces pressure prediction errors.

[0019] 3. This invention uses measured pressure to infer the Eaton index and employs the minimum curvature method to ensure the continuity of gridded parameters across the entire spatial region, thereby improving the accuracy of pressure prediction results. Attached Figure Description

[0020] Figure 1 This is a flowchart of a formation pressure prediction method based on joint correction of well logging and seismic velocity according to the present invention.

[0021] Figure 2 This is a structural diagram of a formation pressure prediction system based on the combined correction of well logging and seismic velocity according to the present invention. Detailed Implementation

[0022] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0023] Example 1, as Figure 1 As shown in the figure, this embodiment provides a method for predicting formation pressure by combining well logging and seismic velocity correction, including the following steps: S1: Take the measured density and parameters of a single well from the well logging data of all drilled wells in the whole area, calculate the overlying strata pressure of the single well, and use the minimum curvature method to resample and grid it to map the overlying strata pressure of the single well to the virtual grid plane of the formation profile of the whole area. Take the measured pressure of the single well and back-calculate the Eaton index of the single well in combination with the parameters of the single well. When the Eaton index meets the resampling conditions, use the minimum curvature method to resample and grid it to map the Eaton index of the single well to the virtual grid plane of the formation profile of the whole area. S2: For all drilled wells, extract the measured logging velocity and the seismic average velocity respectively. Perform piecewise fitting based on the seismic average velocity to obtain the fitted logging velocity. Calculate the error between the measured logging velocity and the fitted logging velocity for each well and each depth point to obtain the average error for the entire area. If the average error for the entire area meets the preset threshold, the fitting model is valid. Use the fitting model to correct the seismic average velocity and output the corrected seismic average velocity. S3: Based on the corrected average seismic velocity, the overlying strata pressure on the gridded surface, and the Eaton index, the Eaton formula is substituted to calculate the predicted strata pressure for the entire region.

[0024] In one embodiment of the present invention, the step of taking the measured density and parameters of a single well from the well logging data of all drilled wells in the entire area, calculating the overlying strata pressure of the single well, and resampling and gridding using the minimum curvature method to map the overlying strata pressure of the single well onto a virtual grid plane of the formation profile of the entire area includes: S11: Obtain the measured density of all drilled wells in the region and the drilling depth in the parameters of individual wells; S12: Using the density gradient formula and measured density, the overlying strata pressure of a single well is calculated at depth points for each drilling depth. S13: For the stratigraphic profile of the entire area, a virtual grid plane is constructed, and the minimum curvature method is used to smooth the overlying strata pressure data of a single well through interpolation and resampling to fully map it to all nodes of the virtual grid plane.

[0025] The virtual grid plane includes horizontal grids and vertical grids. The horizontal grids correspond to the horizontal positions of the stratigraphic profile of the entire area, and the vertical grids correspond to the stratigraphic depths of the entire area.

[0026] In this embodiment of the invention, as shown in steps S11-S13 above, to address the problem that the traditional Eaton method can only obtain overburden pressure data from a single well, lacks effective parameters for formation pressure calculation in areas without wells, and the data cannot cover the entire study area, the effective overburden pressure data from a single well is extended to the entire formation area to achieve formation pressure calculation across the entire area. This involves obtaining the measured density data of all drilled wells in the entire area and the drilling depth in the single-well parameters. The measured density data is the actual formation density data collected at each depth point through density logging for all drilled wells in the entire area. The drilling depth is the vertical depth of the formation corresponding to each density measurement point. Using the density gradient formula used in petroleum exploration, and with the measured density corresponding to each depth point as input, the overburden pressure at each depth location of a single well is calculated, completing the overburden pressure solution at the well point location. The calculation formula is as follows: ; in, For the measured density, For depth, This refers to the pressure of the overlying strata. It is important to understand that when calculating the pressure of the overlying strata, the influence of seawater depth must be considered, and the density within the seawater depth range must be limited to a constant value. ; For the entire stratigraphic profile, a virtual grid plane is constructed according to the scale of the profile. The horizontal grid positions correspond to the horizontal positions of the entire stratigraphic profile, and the vertical grid positions correspond to the stratigraphic depths of the entire region. Specifically, the construction of the virtual grid plane is based on the actual horizontal length of the target stratigraphic profile as the horizontal boundary and the vertical depth range of the target stratigraphic layer as the vertical boundary. Along the horizontal direction of the profile, it is uniformly divided at fixed intervals into a preset number of horizontal grids, with each grid node corresponding to a horizontal position of the profile. Along the stratigraphic depth direction, it is uniformly divided at fixed depth steps into a preset number of vertical grids, with each grid node corresponding to a depth layer. The horizontal and vertical grids are interleaved to generate a 2000×1000 virtual grid plane, i.e., the number of horizontal grids is 2000 and the number of vertical grids is 1000. Therefore, each plane corresponds to a set of horizontal positions and stratigraphic depths. Based on the virtual grid plane and the overlying strata pressure of a single well, the minimum curvature method is used to perform smooth interpolation and resampling processing on the overlying strata pressure data of the single well. This is to assign the pressure data to all nodes of the virtual grid plane, fully covering the well point area and the area without wells. Specifically, the coordinates of the overlying strata pressure data of the single well are mapped one-to-one with the nodes of the virtual grid plane. Based on the well point pressure value, the goal is to minimize the curvature and make the change of the pressure surface of the entire profile the smoothest. The pressure value of the grid node in the area without wells is calculated through numerical iteration. According to the virtual grid plane, the generated continuous pressure surface is resampled, and the calculated pressure value is matched to each grid node to achieve parameter assignment of the grid nodes in the entire area.

[0027] In one embodiment of the present invention, the step of taking the measured pressure of a single well, back-calculating the Eaton index of the single well based on the single well parameters, and when the Eaton index meets the resampling condition, resampling and gridding using the minimum curvature method to map the Eaton index of the single well to a virtual grid plane of the entire formation profile includes: S14: Obtain the measured pressure and single-well parameters of the drilled formation, substitute them into the Eaton index back calculation formula, and calculate the Eaton index of a single well at each depth point; S15: For well locations with several measured pressures, multiple Eaton indices are calculated. When the drilling depth corresponding to the Eaton index does not exceed the top and bottom depths of the overpressure box, the median of all Eaton indices for that well is taken, and the Eaton index of a single well is resampled and mapped to a virtual grid plane using the minimum curvature method. When the drilling depth corresponding to the Eaton index exceeds the top and bottom depths of the overpressure box, the Eaton index of a single well is resampled and mapped to a virtual grid plane.

[0028] For areas on the virtual grid plane without drilling, the Eaton index is supplemented using interpolation to obtain Eaton index parameters covering the entire stratigraphic profile.

[0029] In this embodiment of the invention, as shown in steps S14-S15 above, to solve the problems of missing Eaton index and easy distortion of the index in overpressured sections in wellless areas, the index is inversely calculated using measured pressure, and the value is optimized according to the depth conditions of the overpressure chamber. After gridding using the minimum curvature method, a continuous and unbiased Eaton index grid parameter is formed for the entire area. Specifically, the measured pressure and parameters of a single well are obtained, including the calculated overlying strata pressure, hydrostatic pressure, measured sonic transit time, and normal compaction sonic transit time. These parameters are substituted into the Eaton index inverse calculation formula, and the solution is performed point by point according to the drilling depth to obtain the Eaton index at each depth position of the single well. The Eaton index inverse calculation formula is as follows: ; in, For Eaton Index, For the pressure of the overlying strata, To measure formation fluid pressure, For hydrostatic pressure, This represents the acoustic time difference during normal compression. This is the measured time difference of sound waves; For the same well location, when multiple sets of measured pressures exist, multiple Eaton indices corresponding to different depths will be calculated. Therefore, during resampling, the top and bottom depths of the overpressure box need to be used as the resampling condition. When the drilling depth corresponding to the Eaton index does not exceed the top and bottom depths of the overpressure box, the median of all Eaton indices for that well is taken. Then, the median of the Eaton index is smoothed and resampled using the minimum curvature method to map it onto the virtual grid plane of the formation profile for the entire area. When the drilling depth corresponding to the Eaton index exceeds the top and bottom depths of the overpressure box, the Eaton index calculated at each depth point is retained. The minimum curvature method is used for smoothing and resampling to map the Eaton index of a single well onto the virtual grid plane, and finally, the Eaton index grid parameters for the entire area are obtained.

[0030] In one embodiment of the present invention, the steps of extracting the measured logging velocity and the seismic mean velocity for each drilled well in the virtual grid plane, performing piecewise fitting based on the seismic mean velocity to obtain the fitted logging velocity, calculating the error between the measured logging velocity and the fitted logging velocity for each well and for each depth point to obtain the average error for the entire area, and if the average error for the entire area meets a preset threshold, the fitting model is valid, and the seismic mean velocity of the virtual grid plane is corrected using the fitting model, and the corrected seismic mean velocity is output, include: S21: Obtain the measured logging velocity and seismic average velocity for each drilled well and at each depth point; S22: Based on the average seismic velocity, the velocity intervals are divided. Based on the normal pressure region and overpressure region of the formation, the formation segments are divided. Based on the velocity intervals, the formation segments are combined to perform segmented fitting, and the fitted logging velocity at the corresponding depth point of each well is calculated. S23: Based on the fitted logging rate, calculate the fitting error in each level to obtain the average error for the entire area; S24: Compare the average error of the entire area with the preset error threshold to determine the effectiveness of the piecewise fitting model. Using the effective fitting model, correct the average seismic velocity of the nodes of the virtual grid plane and output the corrected average seismic velocity.

[0031] The steps of dividing the formation into velocity intervals based on the average seismic velocity, dividing the formation into stratigraphic segments based on the normal pressure and overpressure regions, and performing segmented fitting based on the velocity intervals and stratigraphic segments to calculate the fitted logging velocity at the corresponding depth point for each well include: S221: Based on the average earthquake velocity, a first velocity interval and a second velocity interval are obtained. When the average earthquake velocity is in the first velocity interval, a linear fitting formula is used for fitting; when the average earthquake velocity is in the second velocity interval, a sine fitting formula is used for fitting. S222: Divide the overpressure zone into stratigraphic segments to obtain the normal compaction segment, the first overpressure segment, and the second overpressure segment; S223: When fitting in segments, if the depth point is in the normal pressure region, then only the velocity range of the earthquake average velocity is used for fitting; if the depth point is in any of the layers in the normal compaction zone, the first overpressure zone, or the second overpressure zone, then segmented fitting is used based on the velocity range of the earthquake average velocity. S224: Calculate the fitting logging rate at the corresponding depth point of each well.

[0032] The step of calculating the fitting error in layers based on the fitted logging rate to obtain the average error for the entire area includes: S231: Calculate the relative error of a single depth point based on the measured logging rate and the fitted logging rate; S232: Calculate the average error of a single well by statistically analyzing the relative errors at all depth points. S233: The average error of the entire region is calculated based on the average error of each well drilled in the region.

[0033] In this embodiment of the invention, as shown in steps S21-S24 above, the velocity range is used to perform piecewise fitting with the formation lithology and overpressure zone, and a piecewise fitting model is generated through an error verification mechanism to correct the seismic average velocity and improve the accuracy of formation pressure prediction. The measured logging velocities and seismic average velocities of all drilled wells in the study area are extracted. The measured logging velocities represent the actual formation velocities and indicate the actual formation response speed. The seismic average velocity is the global velocity data obtained by inverting seismic data. As shown in steps S221-S224 above, the velocity range is divided according to the seismic average velocity. The velocity range includes a first velocity range, which is a low-velocity range, where the seismic average velocity is less than or equal to 3300. The interval is fitted using a linear fitting formula, which is: ; in, To measure the actual logging speed, The average velocity of the earthquake, , These are the fitting coefficients; The velocity range also includes a second velocity range, which is the high-speed range, where the average earthquake velocity is greater than or equal to 3300 km / h. The interval is fitted using a sine fitting formula, which is: ; in, To measure the actual logging speed, The average velocity of the earthquake, , , , All are fitting coefficients; When performing piecewise fitting, the matching is performed according to the velocity range, and the fitting model corresponding to the velocity range is selected. If the depth point is in the normal pressure region, the velocity range in which the seismic average velocity is located is used for fitting; if the depth point is in any of the layers in the normal compaction section, the first overpressure section, or the second overpressure section, piecewise fitting is performed according to the velocity range in which the seismic average velocity is located, and the fitted logging velocity of the corresponding depth point of each well is calculated. After calculating the fitted logging velocity, it is also necessary to calculate the fitting error for each layer. For each well, the relative error of each depth point is calculated. Specifically, the absolute value of the difference between the measured logging velocity and the fitted logging velocity is divided by the measured logging velocity to obtain the relative error of the single point. The average error of each well at all depth points is statistically analyzed. Then, the arithmetic mean of the average error of each well in the whole area is taken to obtain the average error of the whole area. The average error is compared with the preset error threshold to determine whether the fitting model of the segmented fitting is effective. Specifically, the error threshold can be set by statistically analyzing the fitting error distribution of each depth point of all drilled wells in the whole area, calculating the upper limit of the 95% confidence interval of the error, and using this upper limit as the preset threshold to ensure that more than 95% of the well points meet the fitting standard. After confirming the effectiveness of the fitting model, the seismic mean velocity is corrected using the fitting model, and the corrected seismic mean velocity is output. Specifically, it is important to understand that the fitting correction process does not modify the original seismic mean velocity. Instead, it uses a validated piecewise fitting formula to substitute the original seismic mean velocity for each depth point in the entire area. The result is a corrected velocity that closely matches the original seismic mean velocity. For the seismic mean velocities of well points and grid nodes without well points in the entire area, the process is performed point by point. According to the effective fitting model, a corresponding fitting formula and layer coefficient are matched for each seismic mean velocity. That is, the velocity range is determined. For normal pressure areas, the fitting formula corresponding to the seismic mean velocity is used directly. For overpressure areas, the fitting is performed piecewise according to the velocity range. During the fitting process, the seismic mean velocity of each depth point and grid node is substituted into the matched fitting formula and the fitting coefficient of the corresponding layer to calculate the fitted logging velocity. The fitted logging velocity of all nodes in the virtual grid plane is then used as the corrected seismic mean velocity.

[0034] In one embodiment of the present invention, the step of calculating the formation pressure prediction result for the entire area by substituting the corrected average seismic velocity, overlying strata pressure, and Eaton index on the virtual grid plane into the Eaton formula includes: S31: The corrected average seismic velocity, the overlying strata pressure on the grid, and the Eaton index correspond to each node of the virtual grid plane. The parameters corresponding to the nodes are substituted into the Eaton formula to calculate the formation fluid pressure at each node, so as to output the formation pressure prediction results for well-controlled and well-free areas in the whole region.

[0035] In this embodiment of the invention, as shown in step S31 above, the parameters corresponding to the nodes are substituted into the Eaton formula to calculate the formation fluid pressure at each node, and the formation pressure prediction results for the entire area are output. The Eaton formula is: ; in, Formation fluid pressure, For the best, For hydrostatic pressure, This is the measured time difference value of sound waves. This represents the acoustic time difference during normal compression. This refers to the Eaton index.

[0036] Example 2, as Figure 2 As shown, this embodiment provides a formation pressure prediction system with joint correction of well logging and seismic velocity, including: The single-well parameter gridding module is used to calculate the overlying strata pressure and Eaton index of a single well, and maps them to the virtual grid plane of the entire stratigraphic profile using the minimum curvature method; The velocity fitting modeling module is used to extract the measured logging velocity of drilled wells and the average seismic velocity, and to complete the segmented fitting according to the velocity range and overpressure segment; The fitting accuracy verification module is used to calculate the fitting error point by point, well by well, and across the entire area, and to determine the effectiveness of the piecewise fitting model. The earthquake velocity correction module is used to correct the global average earthquake velocity using an effective fitting model. The whole-area pressure calculation module substitutes the corrected seismic average velocity and gridded parameters into the Eaton formula to calculate and output the whole-area formation pressure prediction results.

[0037] The system uses a single-well parameter gridding module to calculate the overlying strata pressure and Eaton index of a single well and perform global gridding mapping. It uses a velocity fitting modeling module to perform piecewise fitting between measured well logging velocity and seismic mean velocity. The fitting accuracy verification module determines the validity of the fitting model, and the seismic velocity correction module corrects the global seismic mean velocity. The global pressure calculation module substitutes the corrected velocity and gridding parameters into the Eaton formula to achieve accurate calculation and output of formation pressure in both well-covered and well-free areas. This solves the problems of insufficient spatial coverage, large prediction deviation, and low prediction accuracy in traditional prediction methods.

[0038] The foregoing has shown and described the basic principles, main features, and advantages of the present invention. Those skilled in the art should understand that the present invention is not limited to the above embodiments. The embodiments and descriptions in the specification are merely principles of the invention. Various changes and modifications can be made to the invention without departing from its spirit and scope, and all such changes and modifications fall within the scope of the claimed invention. The scope of protection claimed by the appended claims and their equivalents is defined.

Claims

1. A method of predicting formation pressure from well logs and seismic velocity joint correction, characterized in that, Includes the following steps: The measured density and parameters of each well are taken from the well logging data of all drilled wells in the region. The overlying strata pressure of each well is calculated. The minimum curvature method is used for resampling and gridding to map the overlying strata pressure of each well to the virtual grid plane of the formation profile of the entire region. The measured pressure of each well is taken and combined with the parameters of each well to back-calculate the Eaton index of each well. When the Eaton index meets the resampling conditions, the minimum curvature method is used for resampling and gridding to map the Eaton index of each well to the virtual grid plane of the formation profile of the entire region. For the drilled wells in the virtual grid plane, the measured logging velocity and the seismic average velocity are extracted respectively. The seismic average velocity is then piecewise fitted to obtain the fitted logging velocity. The error between the measured logging velocity and the fitted logging velocity is calculated for each well and for each depth point to obtain the average error for the whole area. If the average error for the whole area meets the preset threshold, the fitting model is valid. The seismic average velocity of the virtual grid plane is then corrected using the fitting model, and the corrected seismic average velocity is output. Based on the corrected average seismic velocity, overlying strata pressure, and Eaton index on the virtual grid plane, the predicted strata pressure for the entire region is calculated by substituting these values ​​into the Eaton formula.

2. The method of claim 1, wherein, The steps of taking the measured density and parameters of a single well from the well logging data of all drilled wells in the entire area, calculating the overlying strata pressure of the single well, and resampling and gridding using the minimum curvature method to map the overlying strata pressure of the single well onto the virtual grid plane of the formation profile of the entire area include: Obtain the measured density of all drilled wells in the region and the drilling depth in the parameters of individual wells; The density gradient formula is used to calculate the overlying strata pressure of a single well at depth points for each drilling depth using measured density. For the stratigraphic profile of the entire area, a virtual grid plane was constructed, and the minimum curvature method was used to smooth the overlying strata pressure data of a single well through interpolation and resampling to fully map it to all nodes of the virtual grid plane.

3. The method of claim 2, wherein: The virtual grid plane includes horizontal grids and vertical grids. The horizontal grids correspond to the horizontal positions of the stratigraphic profile of the entire area, and the vertical grids correspond to the stratigraphic depths of the entire area.

4. The method of claim 1, wherein, The steps of taking the measured pressure of a single well, back-calculating the Eaton index of the single well based on the single well parameters, and when the Eaton index meets the resampling conditions, using the minimum curvature method for resampling and gridding to map the Eaton index of the single well to a virtual grid plane of the entire formation profile include: The measured pressure and single-well parameters of the drilled formation are obtained, and then substituted into the Eaton index back calculation formula to calculate the Eaton index of a single well at each depth point. For well locations with several measured pressures, multiple Eaton indices are calculated. When the drilling depth corresponding to the Eaton index does not exceed the top and bottom depths of the overpressure box, the median of all Eaton indices for that well is taken, and the Eaton index of a single well is resampled and mapped to a virtual grid plane using the minimum curvature method. When the drilling depth corresponding to the Eaton index exceeds the top and bottom depths of the overpressure box, the Eaton index of a single well is resampled and mapped to a virtual grid plane.

5. The method of claim 1, wherein: For areas on the virtual grid plane without drilling, the Eaton index is supplemented using interpolation to obtain Eaton index parameters covering the entire stratigraphic profile.

6. The method of claim 1, wherein The steps include: extracting the measured logging velocity and the seismic mean velocity from the drilled wells in the virtual grid plane; performing piecewise fitting based on the seismic mean velocity to obtain the fitted logging velocity; calculating the error between the measured logging velocity and the fitted logging velocity for each well and each depth point to obtain the average error for the entire area; if the average error for the entire area meets a preset threshold, the fitting model is valid; and using the fitting model to correct the seismic mean velocity in the virtual grid plane, outputting the corrected seismic mean velocity. Obtain the measured logging velocity and seismic average velocity for each drilled well and at each depth point; Based on the average seismic velocity, velocity intervals are divided. Based on the normal pressure region and overpressure region of the formation, the formation segments are divided. Based on the velocity intervals, the formation segments are combined with segmented fitting to calculate the fitted logging velocity at the corresponding depth point of each well. Based on the fitted logging rate, the fitting error is calculated in layers to obtain the average error for the entire area; The average error of the entire area is compared with the preset error threshold to determine the effectiveness of the piecewise fitting model. Using the effective fitting model, the average seismic velocity of the nodes of the virtual grid plane is corrected, and the corrected average seismic velocity is output.

7. The method of claim 6, wherein, The steps of dividing the formation into velocity intervals based on the average seismic velocity, dividing the formation into stratigraphic segments based on the normal pressure and overpressure regions, and performing segmented fitting based on the velocity intervals and stratigraphic segments to calculate the fitted logging velocity at the corresponding depth point for each well include: Based on the average earthquake velocity, a first velocity interval and a second velocity interval are obtained. When the average earthquake velocity is in the first velocity interval, a linear fitting formula is used for fitting; when the average earthquake velocity is in the second velocity interval, a sine fitting formula is used for fitting. The overpressure zone was divided into stratigraphic segments, resulting in a normal compaction segment, a first overpressure segment, and a second overpressure segment. When fitting in segments, if the depth point is in the normal pressure region, then fitting is performed only based on the velocity range in which the seismic mean velocity is located; if the depth point is in any of the layers in the normal compaction zone, the first overpressure zone, or the second overpressure zone, then segmented fitting is performed based on the velocity range in which the seismic mean velocity is located. The fitting logging rate at the corresponding depth point of each well was calculated.

8. The method of claim 6, wherein, The step of calculating the fitting error in layers based on the fitted logging rate to obtain the average error for the entire area includes: Based on the measured logging rate and the fitted logging rate, the relative error of a single depth point is calculated for each depth point. Calculate the average error of a single well by statistically analyzing the relative errors at all depth points. The average error for the entire region is calculated based on the average error of each drilled well in the region.

9. The method of claim 1, wherein, The step of calculating the formation pressure prediction results for the entire area by substituting the corrected average seismic velocity, overlying strata pressure, and Eaton index on the virtual grid plane into the Eaton formula includes: The corrected average seismic velocity, the overlying strata pressure on the grid, and the Eaton index correspond to each node of the virtual grid plane. The parameters corresponding to the nodes are substituted into the Eaton formula to calculate the formation fluid pressure at each node, so as to output the formation pressure prediction results for well-controlled and well-free areas in the whole region.

10. A system for predicting formation pressure using well logs and seismic velocities, applied to the method for predicting formation pressure using well logs and seismic velocities according to any one of claims 1 to 9, characterized in that, include: The single-well parameter gridding module is used to calculate the overlying strata pressure and Eaton index of a single well, and maps them to the virtual grid plane of the entire stratigraphic profile using the minimum curvature method; The velocity fitting modeling module is used to extract the measured logging velocity of drilled wells and the average seismic velocity, and to complete the segmented fitting according to the velocity range and overpressure segment; The fitting accuracy verification module is used to calculate the fitting error point by point, well by well, and across the entire area, and to determine the effectiveness of the piecewise fitting model. The earthquake velocity correction module is used to correct the global average earthquake velocity using an effective fitting model. The whole-area pressure calculation module substitutes the corrected seismic average velocity and gridded parameters into the Eaton formula to calculate and output the whole-area formation pressure prediction results.

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