Optimization method, device and equipment for drilling engineering design

Abstract

The embodiment of the application discloses a kind of optimization method, device and equipment of drilling engineering design, belong to oil and gas safety drilling engineering field.The method is by calculating the overflow risk contribution value of design well, injection-production relationship risk contribution value, injection well casing pressure risk contribution value, injection well position risk contribution value and well leakage risk contribution value, the influence of five factors, such as water invasion overflow, injection-production relationship, injection well casing pressure, injection well position and well leakage, on the well control risk of design well is quantified, the total well control risk contribution value determined based on the five risk contribution values, accurately assess the probability of well control risk of design well, and then suitable wellbore structure and cementing process can be recommended for design well, to optimize the drilling engineering design of design well, to ensure the safety of drilling construction of design well.

Description

Technical Field

[0001] This application relates to the field of oil and gas safe drilling engineering, and in particular to an optimization method, apparatus and equipment for drilling engineering design. Background Technology

[0002] In oilfield development, many oilfields, especially in the later stages, often employ water injection to stabilize production. However, prolonged water injection can drastically alter the formation pressure distribution, creating a multi-pressure system underground and posing additional challenges to drilling operations. Currently, drilling in oilfields with long-term water injection carries well control risks such as lost circulation, well kicks, and blowouts. These risks can lead to significant resource and property losses, as well as casualties and severe environmental pollution. Therefore, assessing well control risks during drilling and optimizing drilling engineering design based on these risks to ensure drilling safety is a critical technical problem that needs to be addressed. Summary of the Invention

[0003] This application provides an optimization method, apparatus, and equipment for drilling engineering design. It can accurately assess the probability of well control risks occurring in the designed well, and thus recommend suitable wellbore structures and cementing processes to optimize the drilling engineering design, thereby ensuring the safety of drilling operations. The technical solution is as follows:

[0004] On the one hand, an optimization method for drilling engineering design is provided, the method comprising:

[0005] Based on the formation pressure at the wellhead location of the design well, the vertical depth of multiple target points of the design well, the oil pressure of multiple production wells adjacent to the design well, the oil pressure and casing pressure of multiple water injection wells adjacent to the design well, the distance between the design well and the multiple production wells, the distance between the design well and the multiple water injection wells, the number of well leakage incidents in adjacent wells of the design well, and the geological structure of the area where the design well is located, the overflow risk contribution value, injection-production relationship risk contribution value, water injection well casing pressure risk contribution value, water injection well location risk contribution value, and well leakage risk contribution value of the design well are determined. The design well is the well to be drilled.

[0006] Based on the overflow risk contribution value, injection-production relationship risk contribution value, casing pressure risk contribution value, injection well location risk contribution value, and well leakage risk contribution value of the designed well, the total well control risk contribution value of the designed well is determined.

[0007] Based on the total well control risk contribution value, the wellbore structure and cementing process used in the drilling process of the designed well are determined.

[0008] On the other hand, an optimization device for drilling engineering design is provided, the device comprising:

[0009] The first determining module is used to determine the overflow risk contribution value, injection-production relationship risk contribution value, water injection well casing pressure risk contribution value, water injection well location risk contribution value, and well leakage risk contribution value of the design well based on the formation pressure value at the wellhead location of the design well, the vertical depth of multiple target points of the design well, the oil pressure of multiple production wells adjacent to the design well, the oil pressure and casing pressure of multiple water injection wells adjacent to the design well, the distance between the design well and the multiple production wells, the distance between the design well and the multiple water injection wells, the number of well leakage incidents in adjacent wells of the design well, and the geological structure of the area where the design well is located. The design well is a well to be drilled.

[0010] The second determining module is used to determine the total well control risk contribution value of the design well based on the overflow risk contribution value, injection-production relationship risk contribution value, casing pressure risk contribution value of the injection well, location risk contribution value of the injection well, and well leakage risk contribution value of the design well.

[0011] The third determining module is used to determine the wellbore structure and cementing process used in the drilling process of the designed well based on the total well control risk contribution value.

[0012] In some embodiments, the first determining module includes:

[0013] The first determining unit is used to determine the overflow risk contribution value of the design well based on the formation pressure value at the wellhead location;

[0014] The second determining unit is used to determine the injection-production relationship risk contribution value of the design well based on the vertical depth of the multiple target points, the oil pressure of the multiple production wells, the oil pressure of the multiple injection wells, the distance between the design well and the multiple production wells, and the distance between the design well and the multiple injection wells.

[0015] The third determining unit is used to determine the casing pressure risk contribution value of the design well based on the casing pressure of the plurality of injection wells and the distance between the design well and the plurality of injection wells.

[0016] The fourth determining unit is used to determine the risk contribution value of the injection well location of the design well based on the distance between the design well and the plurality of injection wells;

[0017] The fifth determining unit is used to determine the well leakage risk contribution value of the design well based on the number of well leakages occurring in adjacent wells and the geological structure of the area where the design well is located.

[0018] In some embodiments, the second determining unit is configured to determine the average vertical depth of the design well as the average vertical depth of the plurality of target points; determine the average formation pressure coefficient of the design well based on the average vertical depth of the design well, the oil pressure of the plurality of production wells, the oil pressure of the plurality of water injection wells, the distance between the design well and the plurality of production wells, and the distance between the design well and the plurality of water injection wells, wherein the average formation pressure coefficient is used to reflect the degree of influence of the production wells and water injection wells adjacent to the design well on the formation pressure of the design well; and determine the injection-production relationship risk contribution value of the design well based on the average vertical depth formation pressure coefficient of the design well.

[0019] In some embodiments, the fourth determining unit is configured to, for any injection well, query the risk contribution value corresponding to the distance between the injection well and the design well from the first mapping information, wherein the first mapping information is used to indicate the correspondence between the distance between the injection well and the design well and the risk contribution value; and determine the average value of the multiple risk contribution values ​​corresponding to the distance between the multiple injection wells and the design well as the injection well location risk contribution value of the design well.

[0020] In some embodiments, the fifth determining unit is configured to determine whether the design well encounters a fault or unconformity during drilling based on the geological structure of the area where the design well is located; if a fault or unconformity is encountered, the well leakage risk contribution value of the design well is determined to be 1; if no fault or unconformity is encountered, the risk contribution value corresponding to the number of well leakages in adjacent wells is queried from second mapping information based on the number of well leakages in adjacent wells, wherein the second mapping information is used to indicate the correspondence between the number of well leakages and the risk contribution value; and the risk contribution value corresponding to the number of well leakages in adjacent wells is determined as the well leakage risk contribution value of the design well.

[0021] In some embodiments, the second determining module includes:

[0022] The generation unit is used to generate a well control risk radar map of the design well based on the overflow risk contribution value, injection-production relationship risk contribution value, casing pressure risk contribution value of the injection well, location risk contribution value of the injection well, and well leakage risk contribution value of the design well.

[0023] The sixth determining unit is used to determine the ratio of the area of ​​the inner pentagon to the area of ​​the outer pentagon in the well control risk radar chart as the total well control risk contribution value of the designed well.

[0024] In some embodiments, the third determining module includes:

[0025] The query unit is used to query the well control risk level corresponding to the total well control risk contribution value from the third mapping information based on the total well control risk contribution value. The third mapping information is used to indicate the correspondence between the risk contribution value and the well control risk level. The well control risk level is used to represent the probability of well control risk occurring in the design well during the drilling process.

[0026] The seventh determining unit is used to determine the wellbore structure and cementing process corresponding to the well control risk level as the wellbore structure and cementing process used in the drilling process of the designed well.

[0027] The seventh determining unit is used to determine, when the well control risk level is low, that the wellbore structure used in the drilling process of the designed well is a two-section wellbore structure and the cementing process is conventional cementing or dual-density cementing; when the well control risk level is medium, that the wellbore structure used in the drilling process of the designed well is a two-section wellbore structure with a backup three-section wellbore structure and the cementing process is dual-density cementing; and when the well control risk level is high, that the wellbore structure used in the drilling process of the designed well is a three-section wellbore structure or a two-section wellbore structure with a backup three-section wellbore structure and the cementing process is staged cementing.

[0028] On the other hand, a computer device is provided, the computer device including a processor and a memory, the memory storing at least one computer program, the at least one computer program being loaded and executed by the processor to implement the drilling engineering design optimization method as described above.

[0029] On the other hand, a computer-readable storage medium is provided, wherein at least one computer program is stored therein, the at least one computer program being loaded and executed by a processor to implement the drilling engineering design optimization method as described above.

[0030] On the other hand, a computer program product is provided, including a computer program loaded and executed by a processor to implement the drilling engineering design optimization method as described above.

[0031] This application provides an optimization method for drilling engineering design. By calculating the overflow risk contribution value, injection-production relationship risk contribution value, injection well casing pressure risk contribution value, injection well location risk contribution value, and well leakage risk contribution value of the design well, the method quantifies the impact of five factors—water intrusion overflow, injection-production relationship, injection well casing pressure, injection well location, and well leakage—on well control risks in the design well. Based on the total well control risk contribution value determined by these five risk contribution values, the method can accurately assess the probability of well control risks occurring in the design well. Consequently, it can recommend suitable wellbore structures and cementing processes for the design well to optimize the drilling engineering design and thus ensure the safety of drilling operations. Attached Figure Description

[0032] To more clearly illustrate the technical solutions in the embodiments of this application, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of the embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0033] Figure 1 This is a schematic diagram of an implementation environment provided in an embodiment of this application;

[0034] Figure 2 This is a flowchart of an optimization method for drilling engineering design provided in an embodiment of this application;

[0035] Figure 3 This is a flowchart of another optimization method for drilling engineering design provided in an embodiment of this application;

[0036] Figure 4 This application provides an embodiment of a formation pressure distribution map of the X group in the GD block over the past 5 years.

[0037] Figure 5 This is a formation pressure distribution map of the X group in the GD block over the last 5 years, provided in an embodiment of this application;

[0038] Figure 6 This is a parameter diagram for defining overflow risk areas provided in an embodiment of this application;

[0039] Figure 7 This is a design well overflow risk zone delineation diagram provided in an embodiment of this application;

[0040] Figure 8 This is a GD block pressure structure overlay diagram provided in an embodiment of this application;

[0041] Figure 9 This is a well control risk radar map of a GD-A well provided in an embodiment of this application;

[0042] Figure 10 This is a wellbore structure diagram of a GD-A well provided in an embodiment of this application;

[0043] Figure 11 This is a flowchart of a drilling engineering design optimization provided in an embodiment of this application;

[0044] Figure 12 This is a schematic diagram of the structure of an optimization device for drilling engineering design provided in an embodiment of this application;

[0045] Figure 13This is a schematic diagram of the structure of another drilling engineering design optimization device provided in the embodiments of this application;

[0046] Figure 14 This is a schematic diagram of the structure of a computer device provided in an embodiment of this application. Detailed Implementation

[0047] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the implementation methods of this application will be further described in detail below with reference to the accompanying drawings.

[0048] It is understood that the terms "first," "second," etc., used in this application may be used to describe various concepts herein, but unless otherwise stated, these concepts are not limited by these terms. These terms are only used to distinguish one concept from another. For example, without departing from the scope of this application, first mapping information may be referred to as second mapping information, and similarly, second mapping information may be referred to as first mapping information.

[0049] It should be noted that all information (including but not limited to user device information, user personal information, etc.), data (including but not limited to data used for analysis, stored data, displayed data, etc.), and signals involved in this application have been authorized by the user or fully authorized by all parties, and the collection, use, and processing of related data must comply with the relevant laws, regulations, and standards of the relevant countries and regions. For example, the geological structure information involved in this application was obtained with full authorization.

[0050] The implementation environment of the embodiments of this application is described below.

[0051] Figure 1 This is a schematic diagram of an implementation environment provided in an embodiment of this application. See also... Figure 1 The implementation environment includes a terminal 101 and a server 102. The terminal 101 can be connected to the server 102 via a wireless network or a wired network.

[0052] Optionally, terminal 101 can be at least one of a smartphone, desktop computer, laptop, or tablet computer. Terminal 101 has an application installed or running that can obtain various data from server 102 for calculating the well control risk contribution value of the design well, such as formation pressure, vertical depth, well spacing, and oil pressure. Therefore, technicians can use this application to calculate multiple well control risk contribution values ​​for the design well, such as overflow risk contribution value, injection-production relationship risk contribution value, injection well casing pressure risk contribution value, injection well location risk contribution value, and well leakage risk contribution value. The application can also generate a well control risk radar chart of the design well based on multiple well control risk contribution values ​​to determine the well control risk level of the design well and recommend drilling engineering designs suitable for the well control risk level. The application is associated with server 102, which provides backend services.

[0053] Optionally, server 102 can be an independent physical server, a server cluster or distributed system composed of multiple physical servers, or a cloud server providing basic cloud computing services such as cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communication, middleware services, domain name services, security services, CDN (Content Delivery Network), and big data and artificial intelligence platforms. In some embodiments, server 102 undertakes the main computing work, and terminal 101 undertakes the secondary computing work; or, server 102 undertakes the secondary computing work, and terminal 101 undertakes the main computing work; or, server 102 and terminal 101 collaborate on computing using a distributed computing architecture.

[0054] Terminal 101 can refer to one of a plurality of terminals; this embodiment uses terminal 101 as an example. Those skilled in the art will understand that the number of terminals can be more or less. For example, there may be several terminals, or dozens or hundreds of terminals, or even more. This application embodiment does not limit the number of terminals or the type of device.

[0055] Figure 2 This is a flowchart illustrating an optimization method for drilling engineering design provided in an embodiment of this application. This embodiment is executed by a computer device, as shown below. Figure 2 The method includes:

[0056] 201. The computer equipment determines the overflow risk contribution value, injection-production relationship risk contribution value, water injection well casing pressure risk contribution value, water injection well location risk contribution value, and well leakage risk contribution value of the design well based on the formation pressure value at the wellhead location of the design well, the vertical depth of multiple target points of the design well, the oil pressure of multiple production wells adjacent to the design well, the oil pressure and casing pressure of multiple water injection wells adjacent to the design well, the distance between the design well and multiple production wells, the distance between the design well and multiple water injection wells, the number of well leakage incidents in adjacent wells of the design well, and the geological structure of the area where the design well is located. The design well is the well to be drilled.

[0057] In this embodiment, a design well refers to a well to be drilled. The target point of a design well, also called the objective point, refers to the formation location that needs to be reached during drilling. The vertical depth of the target point refers to the vertical distance from the target point to the wellhead of the design well. An oil production well is used to extract crude oil from an oil field. A water injection well is used to inject water into an oil field to maintain oil field pressure and improve recovery. The oil pressure of an oil production well refers to the pressure inside the tubing at the wellhead, which is one of the driving forces propelling crude oil from the formation to the wellhead. The oil pressure of a water injection well refers to the pressure inside the tubing at the wellhead, reflecting the pressure of the water injection system when injecting water into the formation. The casing pressure of a water injection well refers to the pressure in the annular space between the casing and tubing at the wellhead, reflecting the sealing performance of the casing and the effect of formation fluids on the casing. Adjacent wells to a design well refer to wells surrounding the design well, including water injection wells and oil production wells. Well leakage refers to the phenomenon of drilling fluid or other working fluids flowing from the wellbore into the formation during drilling. The geological structure of the area where the design well is located is used to reflect the types of formations that the design well may encounter during the drilling process.

[0058] To comprehensively assess the probability of well control risks occurring during drilling of a design well, the computer equipment must consider not only the formation pressure at the well's location and the geological structure of the drilling area, but also the injection and production conditions and well leakage in the surrounding area. Accordingly, the computer equipment can determine the contribution values ​​of the design well's overflow risk, injection-production relationship risk, injection well casing pressure risk, injection well location risk, and well leakage risk based on the formation pressure at the design well's location, the vertical depth to be reached, the basic data of multiple adjacent production wells and injection wells, and the geological structure of the area where the design well is located. This allows for the quantification of the impact of five factors—water intrusion overflow, injection-production relationship, injection well casing pressure, injection well location, and well leakage—on the occurrence of well control risks in the design well.

[0059] 202. The computer equipment determines the total well control risk contribution value of the design well based on the overflow risk contribution value, injection-production relationship risk contribution value, casing pressure risk contribution value, location risk contribution value, and well leakage risk contribution value of the design well.

[0060] In this embodiment, the overflow risk contribution value indicates the degree to which the overflow risk level of the area where the design well is located contributes to the well control risk during drilling, i.e., the probability of the design well overflowing. The injection-production relationship risk contribution value indicates the degree to which the injection-production situation of adjacent production wells and water injection wells contributes to the well control risk during drilling. The water injection well casing pressure risk contribution value indicates the degree to which the casing pressure of adjacent water injection wells contributes to the well control risk during drilling. The water injection well location risk contribution value indicates the degree to which the location distribution of multiple adjacent water injection wells contributes to the well control risk during drilling. The well leakage risk contribution value indicates the degree to which the well leakage situation of neighboring wells and the geological structure of the area where the design well is located contributes to the well control risk during drilling, i.e., the probability of well leakage. Accordingly, the computer equipment can calculate the total well control risk contribution value of the design well based on these five risk contribution values. The total well control risk contribution value is used to indicate the probability of well control risks occurring during the drilling process of the designed well.

[0061] 203. Based on the total well control risk contribution value, the computer equipment determines the wellbore structure and cementing process to be used in the drilling process of the designed well.

[0062] In this embodiment, a low total well control risk contribution value indicates the probability of well control risk occurring during drilling, meaning the well is located in a low-risk well control zone. Accordingly, the computer equipment can determine the wellbore structure and cementing process suitable for drilling in a low-risk well control zone as the wellbore structure and cementing process used for the well. Similarly, if the well is located in a high-risk well control zone, the computer equipment can determine the wellbore structure and cementing process suitable for drilling in a high-risk well control zone as the wellbore structure and cementing process used for the well.

[0063] This application provides an optimization method for drilling engineering design. By calculating the overflow risk contribution value, injection-production relationship risk contribution value, injection well casing pressure risk contribution value, injection well location risk contribution value, and well leakage risk contribution value of the design well, the method quantifies the impact of five factors—water intrusion overflow, injection-production relationship, injection well casing pressure, injection well location, and well leakage—on well control risks in the design well. Based on the total well control risk contribution value determined by these five risk contribution values, the method can accurately assess the probability of well control risks occurring in the design well. Consequently, it can recommend suitable wellbore structures and cementing processes for the design well to optimize the drilling engineering design and thus ensure the safety of drilling operations.

[0064] The above Figure 2 The main flow of the drilling engineering design optimization method provided in the embodiments of this application is illustrated. The optimization scheme of the drilling engineering design will be described in detail below. Figure 3 This is a flowchart of another drilling engineering design optimization method provided in an embodiment of this application. This method is executed by a computer device. See [link to relevant documentation]. Figure 3 The method includes:

[0065] 301. The computer equipment determines the overflow risk contribution value, injection-production relationship risk contribution value, water injection well casing pressure risk contribution value, water injection well location risk contribution value, and well leakage risk contribution value of the design well based on the formation pressure value at the wellhead location of the design well, the vertical depth of multiple target points of the design well, the oil pressure of multiple production wells adjacent to the design well, the oil pressure and casing pressure of multiple water injection wells adjacent to the design well, the distance between the design well and multiple production wells, the distance between the design well and multiple water injection wells, the number of well leakage incidents in adjacent wells of the design well, and the geological structure of the area where the design well is located. The design well is the well to be drilled.

[0066] In this embodiment, a design well refers to a well to be drilled. The target point of a design well, also called the objective point, refers to the formation location that needs to be reached during drilling. The vertical depth of the target point refers to the vertical distance from the target point to the wellhead of the design well. An oil production well is used to extract crude oil from an oil field. A water injection well is used to inject water into an oil field to maintain oil field pressure and improve recovery. The oil pressure of an oil production well refers to the pressure inside the tubing at the wellhead, which is one of the driving forces propelling crude oil from the formation to the wellhead. The oil pressure of a water injection well refers to the pressure inside the tubing at the wellhead, reflecting the pressure of the water injection system when injecting water into the formation. The casing pressure of a water injection well refers to the pressure in the annular space between the casing and tubing at the wellhead, reflecting the sealing performance of the casing and the effect of formation fluids on the casing. Adjacent wells to a design well refer to wells surrounding the design well, including water injection wells and oil production wells. Well leakage refers to the phenomenon of drilling fluid or other working fluids flowing from the wellbore into the formation during drilling. The geological structure of the area where the design well is located is used to reflect the types of formations that the design well may encounter during the drilling process.

[0067] To determine the formation pressure at the wellhead location of the designed well, computer equipment needs to collect and organize basic data on wells completed over the past N years in the block where the designed well is located, in order to establish a well completion database for that block. The well completion database is organized by well, with one set of data corresponding to each well. Each set of data includes the well number, structural location, complexity and corresponding depth, completion date, sampling depth and corresponding drilling fluid density and system, bottomhole coordinates, wellhead coordinates, encountered formation and its vertical depth, inclination measurement data, kill fluid density, and completion fluid density, etc.

[0068] Complex situations refer to phenomena such as overflows, lost circulation, and oil and gas intrusion that occur during the drilling process. The corresponding complex well depth refers to the well depth at which these complex situations occur. Sampling well depth refers to the specific depth at which drilling fluid samples are taken during drilling. Samples are taken periodically at certain intervals according to the progress of drilling operations to monitor changes in drilling fluid properties. Encountered formations refer to the formations encountered during drilling. Bottom boundary vertical depth refers to the vertical distance from the bottom boundary of the formation to the wellhead. Inclination data are data obtained during drilling using inclination instruments, reflecting the wellbore trajectory, spatial position, and direction. Inclination data includes inclination angle and azimuth angle. The inclination angle is the angle between the wellbore axis and the vertical line, reflecting the degree to which the wellbore deviates from the vertical. The azimuth angle is the angle between the projection of the wellbore axis onto the horizontal plane and true north, reflecting the direction of the wellbore. Kill fluid is the fluid injected into the well during drilling and workover operations to control formation pressure and prevent blowouts. Completion fluid refers to the fluid used during well completion operations.

[0069] After establishing a well completion database for the block where the design well is located, the computer equipment can draw a formation pressure map for the block based on this database. Then, based on the wellhead coordinates of the design well, the formation pressure value at the wellhead location is determined from the formation pressure map. The process of drawing the formation pressure map includes: First, the computer equipment divides the horizontal projection of the block into multiple square grids, each grid being step × step. Then, based on the data in the well completion database, the computer equipment calculates the formation pressure value at the center point of each grid and uses this value as the formation pressure value for that grid. Finally, based on the formation pressure value of each grid, the computer equipment colors each grid according to different pressure ranges, thus drawing the formation pressure map for the block.

[0070] In some embodiments, the computer device calculates the formation pressure value at any grid center point (Xc, Yc) using the following formula 1.

[0071] Formula 1:

[0072] P p (Formation,X c ,Y c )=ρ mudMax (Formation,X c ,Y c )–α

[0073] Where Formation represents a specific stratum, P p (Formation,X c ,Y cρ represents the formation pore pressure at point (Xc, Yc) on the horizontal projection map of a certain formation. mudMax (Formation,X c ,Y c ) represents the maximum drilling fluid density of a certain formation at point (Xc,Yc) on the horizontal projection map, and α represents the safety margin for drilling fluid density, with a value range of 0 to 0.05.

[0074] In some embodiments, the computer device can calculate the maximum drilling fluid density of a formation at point (Xc, Yc) on a horizontal projection map using the following formula 2.

[0075] Formula 2:

[0076] ρ mudMax (Formation,X c ,Y c )=Average{ρ mudMax (Name[i],Formation,x,y)}

[0077] (X c -1.5step)≤x≤(X c +1.5step),(Y c -1.5step)≤y≤(Y c +1.5step), (i = 0, 1, 2, ...)

[0078] Where step represents the transformation of the square grid, Name[i] represents the well number of the completed well within the (x,y) range of the horizontal projection map, Average represents the average value, and ρ mudMax (Name[i],Formation,x,y) represents the maximum drilling fluid density of a completed well in a certain formation within the range of the horizontal projection map (x,y).

[0079] In some embodiments, for a completed well within the (x,y) range of a horizontal projection map, the computer device can determine the sampling depth of the well, the drilling fluid density corresponding to the sampling depth, and the encountered formation and the vertical depth of the formation bottom boundary from the completed well data. Then, the computer device can calculate the sampling point and the corresponding sampling depth of the well using Formula 3 below, and then calculate the maximum drilling fluid density of the well in a certain formation I using Formula 4 below.

[0080] Formula 3:

[0081] (TVD[i],X[i],Y[i])=MinCurv(Survey(Name[i]),MD[i]),(i=0,1,2,...)

[0082] Where Survey(Name[i]) represents the inclination data of the completed well i within the range of the horizontal projection map (x,y), MD[i] represents the well depth of the completed well i, X[i] and Y[i] represent the coordinates of the sampling point of the completed well i, TVD[i] represents the vertical depth of the completed well i at the sampling point (X[i],Y[i]), and MinCurv represents the minimum curvature method.

[0083] Formula 4:

[0084] ρ mudMax (Name[i],Formation[I])=Max{ρ mud [i](Name[i],TVD[i],X[i],Y[i],TVD[I-1]<

[0085] TVD[i]≤TVD[I])},(i=0,1,2,……)

[0086] Where, ρ mudMax (Name[i],Formation[I]) represents the maximum drilling fluid density of well i in formation I after drilling, TVD[i] represents the vertical depth of well i at multiple sampling points (X[i],Y[i]) in formation I after drilling, and ρ mud [i](Name[i],TVD[i],X[i],Y[i],TVD[I-1]<TVD[i]≤TVD[I]) represents the drilling fluid density at multiple sampling points located in formation I after drilling i.

[0087] For example, taking the GD-A well in the GD block as the design well, the basic information of the GD-A well, such as its geographical location, structural location, wellhead coordinates, target coordinates, and target vertical depth, is shown in Table 1.

[0088] Table 1. Overview of the geographical environment and geological objectives of Well GD-A

[0089]

[0090] First, the computer equipment was able to statistically analyze and organize 3,741 pressure points varying with well depth for 359 completed wells in the GD block over 10 years, as well as 664 sets of well completion survey data, to establish a well completion database for the block, with each period lasting 5 years. The database includes, but is not limited to, data on complex conditions, complex well depths, completion dates, and maximum drilling fluid density in complex formations. See Tables 2-4.

[0091] Table 2. Statistics on drilling fluid density in complex formations after well completion in the GD block in the first 5 years.

[0092] Complex situations Complex well depth / m Date of completion Maximum drilling fluid density overflow 1259 20xx 1.22 Oil and gas intrusion 1570 20xx 1.33 Oil and gas intrusion 1271、1590 20xx 1.36 overflow 1328 20xx 1.45 overflow 1399 20xx 1.35 Well leakage 1389 20xx 1.17 overflow 1525 20xx 1.34 Overflow, well leakage 1334 20xx 1.35 overflow 1327、1760 20xx 1.32 overflow 1293、2104 20xx 1.35 Overflow well control 1480 20xx 1.38 overflow 1503 20xx 1.37 Overflow well control 1249 20xx 1.40 Overflow well control 1150 20xx 1.37 ...... ...... ...... ......

[0093] Table 3. Statistics of drilling fluid density in wells drilled in the GD block during the last 5 years, particularly in complex downhole formations.

[0094]

[0095]

[0096] Table 4. Drilling fluid density variation with depth in the GD block.

[0097]

[0098]

[0099] Then, since the production sections of the adjacent oil production wells and water injection wells of this design well are mainly concentrated in the X group formation, the X group formation is considered as the main contributing layer for well control risk. Accordingly, the computer equipment divides the horizontal projection map of the GD block into 1m × 1m square grids. For the X group formation, formulas one through four above are used to calculate the formation pressure for each grid, and each grid is colored according to different pressure ranges to create a formation pressure map. The computer equipment can generate formation pressure distribution maps of the X group formation in the GD block for the previous 5 years and the following 5 years based on the well completion database and well completion data for the following 5 years, respectively. Figure 4 and Figure 5 As shown. Among them, Figure 4 This is a formation pressure distribution map of the X group of the GD block in the first 5 years provided in an embodiment of this application. Figure 5 This is a formation pressure distribution map of the X group in a GD block over the last 5 years, provided in an embodiment of this application. From... Figure 4 and Figure 5 As can be seen, in the latter 5 years, the GD block was affected by water injection disorder, resulting in local abnormal high pressure, and the pressure was generally higher than in the first 5 years. Figure 4 and Figure 5 The horizontal axis represents the east-west geodetic coordinates, and the vertical axis represents the north-south geodetic coordinates.

[0100] To comprehensively assess the probability of well control risks occurring during drilling of a design well, the computer equipment must consider not only the formation pressure at the well's location and the geological structure of the drilling area, but also the injection-production situation and well leakage in the surrounding area. Accordingly, based on the formation pressure at the design well's location, the vertical depth of the well to be drilled, the basic data of multiple adjacent production wells and injection wells, and the geological structure of the area where the design well is located, the computer equipment can determine the contribution values ​​of the design well's overflow risk, injection-production relationship risk, injection well casing pressure risk, injection well location risk, and well leakage risk. This allows for the quantification of the impact of these five factors—water intrusion overflow, injection-production relationship, injection well casing pressure, injection well location, and well leakage—on the occurrence of well control risks in the design well.

[0101] In some embodiments, the computer device can calculate multiple risk contribution values ​​for the design well through the following steps (1)-(5).

[0102] (1) The computer equipment determines the overflow risk contribution value of the designed well based on the formation pressure value at the wellhead location. This overflow risk contribution value is positively correlated with the formation pressure value at the wellhead location. In some embodiments, the computer equipment can calculate the overflow risk contribution value of the designed well using the following formula (Formula 5).

[0103] Formula 5:

[0104] V overflow =P p (Formation,X0,Y0) / P max

[0105] Among them, V overflow This represents the overflow risk contribution value of the design well, where X0 and Y0 represent the wellhead coordinates of the design well, and P... p (Formation, X0, Y0) represents the formation pressure at the wellhead location of the designed well on a certain formation pressure distribution map, P max This represents the maximum pressure coefficient, which is the highest pressure in the block where the design well is located.

[0106] (2) The computer equipment determines the risk contribution value of the injection-production relationship of the design well based on the vertical depth of multiple target points of the design well, the oil pressure of multiple production wells, the oil pressure of multiple injection wells, the distance between the design well and multiple production wells, and the distance between the design well and multiple injection wells. Both production wells and injection wells are adjacent to the design well. The computer equipment needs to collect basic data on production wells and injection wells near the design well in advance, based on the wellhead location of the design well. Basic data includes the oil pressure of production wells, the oil pressure of injection wells, casing pressure, the number of production wells, the number of injection wells, the vertical depth of production wells in the target formation, the vertical depth of injection wells within injection wells, and their respective inclination data. The oil pressure of a production well refers to the average oil pressure of the production well over a period of time; the same applies to injection wells.

[0107] To determine the distance between an oil production well or a water injection well and a design well, for any given oil production well or water injection well, the computer equipment can determine the position coordinates of the oil production well at the midpoint of the target formation and the position coordinates of the water injection well at the midpoint of the water injection well section based on the basic data of the oil production well and the water injection well. Then, based on the position coordinates of the target point, the position coordinates of the oil production well, and the position coordinates of the water injection well, the distance between the oil production well and the design well and the distance between the water injection well and the design well can be determined.

[0108] In some embodiments, the computer device determines the average vertical depth of the design well by averaging the vertical depths of multiple target points. Based on the average vertical depth of the design well, the oil pressure of multiple production wells, the oil pressure of multiple injection wells, the distance between the design well and the multiple production wells, and the distance between the design well and the multiple injection wells, the computer device determines the average formation pressure coefficient of the design well. Based on the average vertical depth formation pressure coefficient of the design well, the computer device determines the injection-production relationship risk contribution value of the design well. The design well may have one target point or multiple target points; this embodiment does not impose any limitation on this. The average formation pressure coefficient reflects the degree of influence of adjacent production wells and injection wells on the formation pressure of the design well. The injection-production relationship risk contribution value of the design well is positively correlated with this average formation pressure coefficient.

[0109] In some embodiments, the computer device can calculate the overflow risk contribution value of the design well using the following formula six.

[0110] Formula Six:

[0111]

[0112] Among them, V in&pro This indicates the overflow risk contribution value of the design well. P represents the average formation pressure coefficient of the design well. max This represents the maximum pressure coefficient, which is the highest pressure in the block where the design well is located.

[0113] In some embodiments, the computer device can calculate the average formation pressure coefficient of the design well using the following formula 7.

[0114] Formula 7:

[0115]

[0116] in, TVD represents the average formation pressure coefficient of the design well. target This indicates the average vertical depth of the designed well. This indicates the oil pressure of oil well i. L represents the oil pressure of injection well j. o [i] represents the distance between production well i and the design well, L w [j] represents the distance between water injection well j and the design well, n represents the number of oil production wells, and m represents the number of water injection wells.

[0117] In some embodiments, the computer device can calculate the distance between the production well i and the design well, and the distance between the injection well j and the design well, using the following formulas eight to eleven.

[0118] Formula 8:

[0119]

[0120] Formula Nine:

[0121]

[0122] Formula 10:

[0123] (X oilzonecentre [i],Y oilzonecentre [i])=(Survey[i],TVD oilzonecentre )

[0124] Formula 11:

[0125] (X injintervalcentre [j],Y injintervalcentre [j])=(Survey[j],TVD injintervalcentre )

[0126] Among them, (X) trgt1 ,Y trgt1 () represents the position coordinates of the shallowest target point among multiple target points in the design well; the shallowest target point is the target point with the shortest vertical depth. (X) oilzonecentre [i],Y oilzonecentre [i]) represents the coordinates of the oil well i at the midpoint of the target formation, (X injintervalcentre [j],Y injintervalcentre [j] represents the coordinates of the midpoint of injection well j in the injection well section, Survey[i] represents the inclination data of production well i, Survey[j] represents the inclination data of injection well j, and TVD oilzonecentre TVD represents the vertical depth at the midpoint of the target formation of oil well i. inj intervalcentre This indicates the vertical depth at the midpoint of the injection section of injection well j.

[0127] (3) The computer equipment determines the casing pressure risk contribution value of the design well based on the casing pressure of multiple injection wells and the distance between the design well and the multiple injection wells. Among them, the casing pressure indicator is the average casing pressure of the injection well over a period of time.

[0128] In some embodiments, the computer device calculates the risk contribution value of the injection well casing pressure of the design well using the following formula 12.

[0129] Formula 12:

[0130]

[0131] in, L represents the contribution value of the casing pressure risk of the design well. w [j] represents the distance between injection well j and the design well. The casing pressure of injection well j is represented by m, and the number of injection wells is represented by m.

[0132] (4) The computer equipment determines the location risk contribution value of the design well and the injection wells based on the distance between the design well and multiple injection wells. The location risk contribution value of the injection well is negatively correlated with the distance between the design well and the injection wells.

[0133] In some embodiments, for any injection well, the computer device queries the risk contribution value corresponding to the distance between the injection well and the design well from first mapping information. The first mapping information is used to indicate the correspondence between the distance between the injection well and the design well and the risk contribution value. The computer device determines the average of the multiple risk contribution values ​​corresponding to the distances between multiple injection wells and the design well as the injection well location risk contribution value of the design well. The closer the distance between the design well and the injection well, the more the design well, as a beneficiary well of the injection well, is affected by the injection. Therefore, the impact of injection wells at different locations on the design well varies. The computer device can first determine the risk contribution value corresponding to each injection well, and then determine the average of the risk contribution values ​​of multiple injection wells to the design well, to measure the degree to which the location distribution of multiple injection wells adjacent to the design well contributes to the well control risk that may occur during the drilling process of the design well.

[0134] In some embodiments, the computer calculates the risk contribution value of the injection well location of the design well using Formulas Thirteen and Fourteen below.

[0135] Formula Thirteen:

[0136]

[0137] Formula Fourteen:

[0138]

[0139] Among them, L w [j] represents the distance between injection well j and the design well, V injloc (L w [j]) represents the risk contribution value corresponding to the distance between injection well j and the design well. This represents the risk contribution value of the injection well location in the design well, where m represents the number of injection wells.

[0140] (5) The computer equipment determines the well leakage risk contribution value of the design well based on the number of well leakage occurrences in adjacent wells and the geological structure of the area where the design well is located. Specifically, the computer equipment can first determine whether the design well will encounter formations prone to well leakage during drilling, based on the geological structure of the area where the design well is located. If such formations are encountered, the well leakage risk contribution value of the design well is a preset value. If not, the well leakage risk contribution value of the design well is determined based on the number of well leakage occurrences in adjacent wells.

[0141] In some embodiments, the computer device determines whether the design well encounters a fault or unconformity during drilling based on the geological structure of the area where the design well is located. If a fault or unconformity is encountered, the computer device determines the well leakage risk contribution value of the design well to be 1. If no fault or unconformity is encountered, the computer device queries a second mapping information source based on the number of well leakage occurrences in adjacent wells, where the second mapping information indicates the correspondence between the number of well leakage occurrences and the risk contribution value. The computer device then determines the risk contribution value corresponding to the number of well leakage occurrences in adjacent wells as the well leakage risk contribution value of the design well. A fault is a structural feature where the Earth's crust fractures under stress, resulting in significant relative displacement of rock blocks along the fracture surface. An unconformity is the contact surface between two sets of strata from different ages. The existence of an unconformity often signifies a missing stratum. During sedimentary hiatuses, due to erosion and other processes, a portion of the older strata is eroded away, leading to a missing stratum between the new and older strata. Therefore, if a design well encounters a fault or unconformity during drilling, it indicates that well leakage is certain to occur during the drilling process. Thus, the well leakage risk contribution value for the design well is set to 1. Even if such a fault or unconformity is not encountered, it does not mean that well leakage will not occur during drilling. Therefore, the computer can estimate the probability of well leakage in the design well based on the number of times well leakage has occurred in neighboring wells around the design well.

[0142] In some embodiments, in the absence of faults or unconformities, the computer calculates the risk contribution value of the injection well location of the design well using the following formula 15.

[0143] Formula 15:

[0144]

[0145] Among them, V lk (Formation) represents the well leakage risk contribution value of the designed well in a certain formation, N lk This indicates the number of times well leakage has occurred in adjacent wells of the designed well.

[0146] For example, taking the GD-A well in the GD block as the design well, we will conduct a dynamic assessment of well control risks for the design well.

[0147] For water intrusion and overflow, computer equipment can combine Figure 3 The formation pressure map shown divides the GD block into high, medium, and low overflow risk zones. Figure 6 This application provides an embodiment of an overflow risk area delineation parameter diagram, such as... Figure 6As shown, the drilling fluid density in the low-risk overflow zone is <1.30 g / cm3, the drilling fluid density in the medium-risk overflow zone is 1.30-1.45 g / cm3, and the drilling fluid density in the high-risk overflow zone is >1.45 g / cm3. Figure 7 This application provides a design well overflow risk zone delineation map, such as... Figure 7 As shown, well GD-A is located in a low-risk overflow zone, with an expected drilling fluid density of 1.25-1.30 g / cm³. To improve the well's ability to cope with overflow risk, the formation pressure at the wellhead location on the X-group formation map is taken as 1.3, and the maximum pressure coefficient is taken as 1.6. Accordingly, using Formula 5 above, the overflow risk contribution value of well GD-A is calculated to be 1.30 / 1.60 = 0.81. Figure 6 and Figure 7 The horizontal axis represents the east-west geodetic coordinates, and the vertical axis represents the north-south geodetic coordinates.

[0148] For the injection-production relationship, the pressure of the production wells and injection wells around the GD-A well is shown in Tables 5 and 6.

[0149] Table 5 Production Data of Adjacent Oil Wells

[0150]

[0151] Table 6. Water Injection Data of Adjacent Injection Wells

[0152]

[0153] The computer equipment can calculate the average formation pressure coefficient of well GD-A using Formula 7 above. See Table 7 for the calculation process.

[0154] Table 7 Calculation of Average Formation Pressure Coefficient for Designed Wells

[0155]

[0156] The computer equipment can calculate the risk contribution value of the injection-production relationship of the GD-A well as 0.48 / 1.60 = 0.30 based on the average formation pressure coefficient of the GD-A well using Formula 6 above.

[0157] Regarding the casing pressure of the injection well, the computer equipment can calculate the risk contribution value of the injection well casing pressure of well GD-A using the above-mentioned method (see Table 8). The calculation process is shown in Table 8.

[0158] Table 8. Calculation Table of Casing Pressure Risk Contribution Value for Designed Wells

[0159]

[0160] For the location of the injection well, the computer equipment can calculate the risk contribution value of the injection well location for well GD-A using formulas thirteen and fourteen. The calculation process is shown in Table 9.

[0161] Table 9. Calculation of Risk Contribution Value of Injection Well Location in Design Wells

[0162]

[0163] For well leakage Figure 8 This application provides an embodiment of a GD block pressure structure overlay map, based on a computer device. Figure 8 Based on the geological structure shown, the drilling geological design for well GD-A is as follows: It is predicted that a fault will be encountered at a vertical depth of 1390m in X-3 (corresponding depth of 1421.11m, fault displacement of 20m); a fault will be encountered at a vertical depth of 1720m in X-4 (corresponding depth of 1768.02m, fault displacement of 30m); and a fault will be encountered at a vertical depth of 2220m in Y-4 (corresponding depth of 2293.64m, fault displacement of 10m). An unconformity is predicted to be encountered near a vertical depth of 2265m at the bottom of Y (corresponding depth of 2340.95m). Therefore, the geological design indicates two faults in the X group strata, resulting in a well leakage risk contribution of 1.0 for well GD-A.

[0164] 302. The computer equipment generates a well control risk radar chart for the design well based on the overflow risk contribution value, injection-production relationship risk contribution value, casing pressure risk contribution value, location risk contribution value, and well leakage risk contribution value of the design well.

[0165] For example, Figure 9 This is a well control risk radar chart of a GD-A well provided in an embodiment of this application. For example... Figure 9 As shown, based on the contribution values ​​of overflow risk (0.81), injection-production relationship risk (0.30), casing pressure risk (0.38), location risk (0.50), and leakage risk (1.0) of well GD-A, the computer equipment generated a well control risk radar chart for well GD-A.

[0166] 303. The computer equipment determines the ratio of the area of ​​the inner pentagon to the area of ​​the outer pentagon in the well control risk radar chart as the total well control risk contribution value of the designed well.

[0167] In this embodiment of the application, the computer device can calculate the total well control risk contribution value of the designed well using the following formula sixteen.

[0168] Formula Sixteen:

[0169]

[0170] Among them, V totalS represents the total well control risk contribution value of the designed well, S1 represents the area of ​​the inner pentagon in the well control risk radar chart, and S represents the area of ​​the outer pentagon in the well control risk radar chart.

[0171] For example, computer equipment through Figure 8 The well control risk radar chart of well GD-A shown shows that the total well control risk contribution value of well GD-A can be calculated to be 0.37.

[0172] 304. The computer equipment queries the well control risk level corresponding to the total well control risk contribution value from the third mapping information based on the total well control risk contribution value. The third mapping information is used to indicate the correspondence between the risk contribution value and the well control risk level. The well control risk level is used to represent the probability of well control risk occurring in the design well during the drilling process.

[0173] In this embodiment, well control risk levels are divided into three levels: low, medium, and high. When the total well control risk contribution value is less than 0.4, the computer equipment can determine that the well control risk level of the designed well is low, indicating that the designed well is in a low-risk well control zone. When the total well control risk contribution value is not less than 0.4 and less than 0.7, the computer equipment can determine that the well control risk level of the designed well is medium, indicating that the designed well is in a medium-risk well control zone. When the total well control risk contribution value is not less than 0.7, the computer equipment can determine that the well control risk level of the designed well is high, indicating that the designed well is in a high-risk well control zone.

[0174] 305. The computer equipment determines the wellbore structure and cementing process corresponding to the well control risk level as the wellbore structure and cementing process to be used in the drilling process of the designed well.

[0175] In this embodiment of the application, the computer device can determine the wellbore structure and cementing process suitable for use at the well control risk level of the designed well, and then determine the wellbore structure and cementing process to be used for the designed well.

[0176] In some embodiments, when the well control risk level is low, the computer equipment determines that the wellbore structure used in the drilling process of the designed well is a two-section wellbore structure and the cementing process is conventional cementing or dual-density cementing; when the well control risk level is medium, the computer equipment determines that the wellbore structure used in the drilling process of the designed well is a two-section wellbore structure with a three-section configuration and the cementing process is dual-density cementing; when the well control risk level is high, the computer equipment determines that the wellbore structure used in the drilling process of the designed well is a three-section wellbore structure or a two-section wellbore structure with a three-section configuration and the cementing process is staged cementing.

[0177] Optionally, when the well control risk level is low, the computer equipment can also determine that the casing depth of the designed well should not be less than 500 meters. When the well control risk level is medium, the computer equipment can also determine that the drilling fluid density of the designed well needs to be increased by 0.02-0.05 g / cm3 before cementing. When the well control risk level is high, in addition to using staged cementing, the computer equipment can also optimize the use of external packers and staged cementing technologies, and use a rapid-setting, early-strength cement slurry system.

[0178] For example, Figure 10 This is a wellbore structure diagram of a GD-A well provided in an embodiment of this application, as shown below. Figure 10 As shown, well GD-A is located in a low-risk well control zone. Computer equipment was used to optimize the well structure and cementing process of GD-A, and the well structure was determined to be a two-section well structure with a casing depth of 550m. The cementing process was to be normal cementing or dual-density cementing.

[0179] For example, Figure 11 This is a flowchart of a drilling engineering design optimization provided in an embodiment of this application, such as... Figure 11 As shown, the computer equipment first needs to establish a database of completed wells in the block where the design well is located over the past few years. Then, based on this database, it draws a formation pressure distribution map of the block where the design well is located, and determines the formation pressure at the wellhead location from this map. Next, the computer equipment can perform a dynamic well control risk assessment of the design well, calculating the contribution values ​​for overflow risk, injection-production relationship risk, injection well casing pressure risk, injection well location risk, and well leakage risk. Based on these risk contribution values, it then draws a radar chart of the design well. Next, based on the radar chart, the computer equipment determines the well control risk level of the design well, i.e., identifies the risk zone where the design well is located. Finally, based on the risk zone, the computer equipment performs drilling optimization design for the design well, determining the wellbore structure and cementing process to be used.

[0180] This application provides an optimization method for drilling engineering design. By calculating the overflow risk contribution value, injection-production relationship risk contribution value, injection well casing pressure risk contribution value, injection well location risk contribution value, and well leakage risk contribution value of the design well, the method quantifies the impact of five factors—water intrusion overflow, injection-production relationship, injection well casing pressure, injection well location, and well leakage—on well control risks in the design well. Based on the total well control risk contribution value determined by these five risk contribution values, the method can accurately assess the probability of well control risks occurring in the design well. Consequently, it can recommend suitable wellbore structures and cementing processes for the design well to optimize the drilling engineering design and thus ensure the safety of drilling operations.

[0181] Figure 12This is a schematic diagram of the structure of an optimization device for drilling engineering design provided in an embodiment of this application. See also... Figure 12 The device includes: a first determining module 1201, a second determining module 1202, and a third determining module 1203.

[0182] The first determining module 1201 is used to determine the overflow risk contribution value, injection-production relationship risk contribution value, water injection well casing pressure risk contribution value, water injection well location risk contribution value, and well leakage risk contribution value of the design well based on the formation pressure value at the wellhead location of the design well, the vertical depth of multiple target points of the design well, the oil pressure of multiple production wells adjacent to the design well, the oil pressure and casing pressure of multiple water injection wells adjacent to the design well, the distance between the design well and multiple production wells, the distance between the design well and multiple water injection wells, the number of well leakage incidents in adjacent wells of the design well, and the geological structure of the area where the design well is located. The design well is the well to be drilled.

[0183] The second determining module 1202 is used to determine the total well control risk contribution value of the design well based on the overflow risk contribution value, injection-production relationship risk contribution value, casing pressure risk contribution value of the injection well, location risk contribution value of the injection well, and well leakage risk contribution value of the design well.

[0184] The third determination module 1203 is used to determine the wellbore structure and cementing process used in the drilling process of the designed well based on the total well control risk contribution value.

[0185] In some embodiments, Figure 13 This is a schematic diagram of another drilling engineering design optimization device provided in an embodiment of this application. See also... Figure 13 The first determining module 1201 includes:

[0186] The first determining unit 1301 is used to determine the overflow risk contribution value of the design well based on the formation pressure value at the wellhead location;

[0187] The second determining unit 1302 is used to determine the injection-production relationship risk contribution value of the design well based on the vertical depth of multiple target points, the oil pressure of multiple oil production wells, the oil pressure of multiple water injection wells, the distance between the design well and multiple oil production wells, and the distance between the design well and multiple water injection wells.

[0188] The third determining unit 1303 is used to determine the casing pressure risk contribution value of the design well based on the casing pressure of multiple injection wells and the distance between the design well and multiple injection wells.

[0189] The fourth determining unit 1304 is used to determine the risk contribution value of the injection well location of the design well based on the distance between the design well and multiple injection wells.

[0190] The fifth determining unit 1305 is used to determine the well leakage risk contribution value of the design well based on the number of well leakage occurrences in adjacent wells of the design well and the geological structure of the area where the design well is located.

[0191] In some embodiments, the second determining unit 1302 is used to determine the average vertical depth of the design well as the average vertical depth of the multiple target points; based on the average vertical depth of the design well, the oil pressure of multiple production wells, the oil pressure of multiple injection wells, the distance between the design well and the multiple production wells, and the distance between the design well and the multiple injection wells, determine the average formation pressure coefficient of the design well, the average formation pressure coefficient being used to reflect the degree of influence of the production wells and injection wells adjacent to the design well on the formation pressure of the design well; and based on the average vertical depth formation pressure coefficient of the design well, determine the injection-production relationship risk contribution value of the design well.

[0192] In some embodiments, the fourth determining unit 1304 is configured to, for any injection well, query the risk contribution value corresponding to the distance between the injection well and the design well from the first mapping information, the first mapping information being used to indicate the correspondence between the distance between the injection well and the design well and the risk contribution value; and determine the average value of the multiple risk contribution values ​​corresponding to the distance between multiple injection wells and the design well as the injection well location risk contribution value of the design well.

[0193] In some embodiments, the fifth determining unit 1305 is used to determine whether the design well encounters a fault or unconformity during drilling based on the geological structure of the area where the design well is located; if a fault or unconformity is encountered, the well leakage risk contribution value of the design well is determined to be 1; if no fault or unconformity is encountered, the risk contribution value corresponding to the number of well leakages in adjacent wells is queried from the second mapping information based on the number of well leakages in adjacent wells, the second mapping information being used to indicate the correspondence between the number of well leakages and the risk contribution value; and the risk contribution value corresponding to the number of well leakages in adjacent wells is determined as the well leakage risk contribution value of the design well.

[0194] In some embodiments, see continue to see Figure 13 The second determining module 1202 includes:

[0195] The generation unit 1306 is used to generate a well control risk radar chart of the design well based on the overflow risk contribution value, injection-production relationship risk contribution value, casing pressure risk contribution value, location risk contribution value, and well leakage risk contribution value of the design well.

[0196] The sixth determining unit 1307 is used to determine the ratio of the area of ​​the inner pentagon to the area of ​​the outer pentagon in the well control risk radar chart as the total well control risk contribution value of the designed well.

[0197] In some embodiments, see continue to see Figure 13The third determining module 1203 includes:

[0198] The query unit 1308 is used to query the well control risk level corresponding to the total well control risk contribution value from the third mapping information based on the total well control risk contribution value. The third mapping information is used to indicate the correspondence between the risk contribution value and the well control risk level. The well control risk level is used to represent the probability of well control risk occurring in the design well during the drilling process.

[0199] The seventh determining unit 1309 is used to determine the wellbore structure and cementing process corresponding to the well control risk level as the wellbore structure and cementing process used in the drilling process of the designed well.

[0200] The seventh determining unit 1309 is used to determine, under the condition of low well control risk level, the wellbore structure used in the drilling process of the designed well is a two-section wellbore structure and the cementing process is conventional cementing or dual-density cementing; under the condition of medium well control risk level, it is determined that the wellbore structure used in the drilling process of the designed well is a two-section wellbore structure with a backup three-section wellbore structure and the cementing process is dual-density cementing; under the condition of high well control risk level, it is determined that the wellbore structure used in the drilling process of the designed well is a three-section wellbore structure or a two-section wellbore structure with a backup three-section wellbore structure and the cementing process is graded cementing.

[0201] This application provides an optimization device for drilling engineering design. By calculating the overflow risk contribution value, injection-production relationship risk contribution value, water injection well casing pressure risk contribution value, water injection well location risk contribution value, and well leakage risk contribution value of the design well, the device quantifies the impact of five factors—water intrusion overflow, injection-production relationship, water injection well casing pressure, water injection well location, and well leakage—on well control risks in the design well. Based on the total well control risk contribution value determined by these five risk contribution values, the device can accurately assess the probability of well control risks occurring in the design well. This allows for the recommendation of suitable wellbore structures and cementing processes for the design well, thereby optimizing the drilling engineering design and ensuring the safety of drilling operations.

[0202] It should be noted that the drilling engineering design optimization device provided in the above embodiments is only an example of the division of the above functional modules. In practical applications, the above functions can be assigned to different functional modules as needed, that is, the internal structure of the computer equipment can be divided into different functional modules to complete all or part of the functions described above. In addition, the drilling engineering design optimization device and the drilling engineering design optimization method embodiments provided in the above embodiments belong to the same concept, and their specific implementation process can be found in the method embodiments, which will not be repeated here.

[0203] This application also provides a computer device, which includes a processor and a memory. The memory stores at least one computer program, which is loaded and executed by the processor to implement the drilling engineering design optimization method of the above embodiments.

[0204] Figure 14 This is a schematic diagram of the structure of a computer device provided in an embodiment of this application.

[0205] Computer device 1400 includes a processor 1401 and a memory 1402.

[0206] Processor 1401 may include one or more processing cores, such as a quad-core processor, an octa-core processor, etc. Processor 1401 may be implemented using at least one hardware form selected from DSP (Digital Signal Processing), FPGA (Field Programmable Gate Array), and PLA (Programmable Logic Array). Processor 1401 may also include a main processor and a coprocessor. The main processor, also known as a CPU (Central Processing Unit), is used to process data in the wake-up state; the coprocessor is a low-power processor used to process data in the standby state. In some embodiments, processor 1401 may integrate a GPU (Graphics Processing Unit), which is responsible for rendering and drawing the content required to be displayed on the screen. In some embodiments, processor 1401 may also include an AI (Artificial Intelligence) processor, which is used to handle computational operations related to machine learning.

[0207] Memory 1402 may include one or more computer-readable storage media, which may be non-transitory. Memory 1402 may also include high-speed random access memory and non-volatile memory, such as one or more disk storage devices or flash memory devices. In some embodiments, the non-transitory computer-readable storage media in memory 1402 are used to store at least one computer program, which is used by processor 1401 to implement the optimization method for drilling engineering design provided in the method embodiments of this application.

[0208] In some embodiments, the computer device 1400 may also optionally include: a peripheral device interface 1403 and at least one peripheral device. The processor 1401, memory 1402, and peripheral device interface 1403 can be connected via a bus or signal line. Each peripheral device can be connected to the peripheral device interface 1403 via a bus, signal line, or circuit board. Optionally, the peripheral device includes at least one of: a radio frequency circuit 1404, a display screen 1405, a camera assembly 1406, an audio circuit 1407, and a power supply 1408.

[0209] Peripheral device interface 1403 can be used to connect at least one I / O (Input / Output) related peripheral device to processor 1401 and memory 1402. In some embodiments, processor 1401, memory 1402 and peripheral device interface 1403 are integrated on the same chip or circuit board; in some other embodiments, any one or two of processor 1401, memory 1402 and peripheral device interface 1403 can be implemented on separate chips or circuit boards, which is not limited in this embodiment.

[0210] The radio frequency (RF) circuit 1404 is used to receive and transmit RF (Radio Frequency) signals, also known as electromagnetic signals. The RF circuit 1404 communicates with communication networks and other communication devices via electromagnetic signals. The RF circuit 1404 converts electrical signals into electromagnetic signals for transmission, or converts received electromagnetic signals back into electrical signals. Optionally, the RF circuit 1404 includes: an antenna system, an RF transceiver, one or more amplifiers, a tuner, an oscillator, a digital signal processor, a codec chipset, a user identity module card, etc. The RF circuit 1404 can communicate with other devices through at least one wireless communication protocol. This wireless communication protocol includes, but is not limited to: metropolitan area networks (MANs), various generations of mobile communication networks (2G, 3G, 4G, and 5G), wireless local area networks (WLANs), and / or WiFi (Wireless Fidelity) networks. In some embodiments, the RF circuit 1404 may also include circuitry related to NFC (Near Field Communication), which is not limited in this application.

[0211] Display screen 1405 is used to display a UI (User Interface). This UI may include graphics, text, icons, videos, and any combination thereof. When display screen 1405 is a touch display screen, it also has the ability to collect touch signals on or above its surface. These touch signals can be input as control signals to processor 1401 for processing. In this case, display screen 1405 can also be used to provide virtual buttons and / or a virtual keyboard, also known as soft buttons and / or a soft keyboard. In some embodiments, display screen 1405 may be a single screen disposed on the front panel of computer device 1400; in other embodiments, display screen 1405 may be at least two screens, disposed on different surfaces of computer device 1400 or in a folded design; in still other embodiments, display screen 1405 may be a flexible display screen disposed on a curved or folded surface of computer device 1400. Furthermore, display screen 1405 may also be configured as a non-rectangular, irregular shape, i.e., a non-rectangular screen. The display screen 1405 can be made of materials such as LCD (Liquid Crystal Display) and OLED (Organic Light-Emitting Diode).

[0212] The camera assembly 1406 is used to acquire images or videos. Optionally, the camera assembly 1406 includes a front-facing camera and a rear-facing camera. The front-facing camera is disposed on the front panel of the computer device 1400, and the rear-facing camera is disposed on the back of the computer device 1400. In some embodiments, there are at least two rear-facing cameras, which are any one of a main camera, a depth-sensing camera, a wide-angle camera, and a telephoto camera, to achieve background blurring by fusion of the main camera and the depth-sensing camera, panoramic shooting by fusion of the main camera and the wide-angle camera, VR (Virtual Reality) shooting, or other fusion shooting functions. In some embodiments, the camera assembly 1406 may also include a flash. The flash may be a single-color temperature flash or a dual-color temperature flash. A dual-color temperature flash refers to a combination of a warm light flash and a cool light flash, which can be used for light compensation at different color temperatures.

[0213] The audio circuit 1407 may include a microphone and a speaker. The microphone is used to collect sound waves from the user and the environment, converting the sound waves into electrical signals that are input to the processor 1401 for processing, or input to the radio frequency circuit 1404 for voice communication. For stereo sound acquisition or noise reduction purposes, multiple microphones may be used, each located at a different part of the computer device 1400. The microphone may also be an array microphone or an omnidirectional microphone. The speaker is used to convert electrical signals from the processor 1401 or the radio frequency circuit 1404 into sound waves. The speaker may be a conventional diaphragm speaker or a piezoelectric ceramic speaker. When the speaker is a piezoelectric ceramic speaker, it can convert electrical signals not only into audible sound waves but also into inaudible sound waves for purposes such as distance measurement. In some embodiments, the audio circuit 1407 may also include a headphone jack.

[0214] Power supply 1408 is used to supply power to the various components in computer device 1400. Power supply 1408 can be AC ​​power, DC power, a disposable battery, or a rechargeable battery. When power supply 1408 includes a rechargeable battery, the rechargeable battery can support wired or wireless charging. The rechargeable battery can also be used to support fast charging technology.

[0215] In some embodiments, the computer device 1400 further includes one or more sensors 1409. The one or more sensors 1409 include, but are not limited to, an accelerometer 1410, a gyroscope 1411, a pressure sensor 1412, an optical sensor 1413, and a proximity sensor 1414.

[0216] Accelerometer 1410 can detect the magnitude of acceleration along the three coordinate axes of a coordinate system established by computer device 1400. For example, accelerometer 1410 can be used to detect the components of gravitational acceleration along the three coordinate axes. Processor 1401 can control display screen 1405 to display the user interface in either a landscape or portrait view based on the gravitational acceleration signal acquired by accelerometer 1410. Accelerometer 1410 can also be used for games or for acquiring user motion data.

[0217] The gyroscope sensor 1411 can detect the orientation and rotation angle of the computer device 1400. The gyroscope sensor 1411 can work in conjunction with the accelerometer sensor 1410 to acquire 3D motion data from the user on the computer device 1400. Based on the data acquired by the gyroscope sensor 1411, the processor 1401 can perform the following functions: motion sensing (e.g., changing the UI based on the user's tilt), image stabilization during shooting, game control, and inertial navigation.

[0218] Pressure sensor 1412 can be disposed on the side bezel of computer device 1400 and / or on the lower layer of display screen 1405. When pressure sensor 1412 is disposed on the side bezel of computer device 1400, it can detect the user's grip signal on computer device 1400, and processor 1401 can perform left / right hand recognition or quick operation based on the grip signal collected by pressure sensor 1412. When pressure sensor 1412 is disposed on the lower layer of display screen 1405, processor 1401 can control operable controls on the UI interface based on the user's pressure operation on display screen 1405. Operable controls include at least one of button controls, scroll bar controls, icon controls, and menu controls.

[0219] Optical sensor 1413 is used to collect ambient light intensity. In one embodiment, processor 1401 can control the display brightness of display screen 1405 based on the ambient light intensity collected by optical sensor 1413. Optionally, when the ambient light intensity is high, the display brightness of display screen 1405 is increased; when the ambient light intensity is low, the display brightness of display screen 1405 is decreased. In another embodiment, processor 1401 can also dynamically adjust the shooting parameters of camera assembly 1406 based on the ambient light intensity collected by optical sensor 1413.

[0220] A proximity sensor 1414, also known as a distance sensor, is installed on the front panel of the computer device 1400. The proximity sensor 1414 is used to detect the distance between the user and the front of the computer device 1400. In one embodiment, when the proximity sensor 1414 detects that the distance between the user and the front of the computer device 1400 is gradually decreasing, the processor 1401 controls the display screen 1405 to switch from a screen-on state to a screen-off state; when the proximity sensor 1414 detects that the distance between the user and the front of the computer device 1400 is gradually increasing, the processor 1401 controls the display screen 1405 to switch from a screen-off state to a screen-on state.

[0221] Those skilled in the art will understand that Figure 14 The structure shown does not constitute a limitation on the computer device 1400, and may include more or fewer components than shown, or combine certain components, or use different component arrangements.

[0222] This application also provides a computer-readable storage medium storing at least one computer program, which is loaded and executed by a processor to implement the drilling engineering design optimization method of the above embodiments.

[0223] This application also provides a computer program product, including a computer program that is loaded and executed by a processor to implement the drilling engineering design optimization method as described in the above embodiments.

[0224] Those skilled in the art will understand that all or part of the steps of the above embodiments can be implemented by hardware or by a program instructing related hardware. The program can be stored in a computer-readable storage medium, such as a read-only memory, a disk, or an optical disk.

[0225] The above are merely optional embodiments of the present application and are not intended to limit the present application. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present application should be included within the protection scope of the present application.

Claims

1. An optimization method for drilling engineering design, characterized in that, The method includes: Based on the formation pressure at the wellhead location of the design well, the vertical depth of multiple target points of the design well, the oil pressure of multiple production wells adjacent to the design well, the oil pressure and casing pressure of multiple water injection wells adjacent to the design well, the distance between the design well and the multiple production wells, the distance between the design well and the multiple water injection wells, the number of well leakage incidents in adjacent wells of the design well, and the geological structure of the area where the design well is located, the overflow risk contribution value, injection-production relationship risk contribution value, water injection well casing pressure risk contribution value, water injection well location risk contribution value, and well leakage risk contribution value of the design well are determined. The design well is the well to be drilled. Based on the overflow risk contribution value, injection-production relationship risk contribution value, casing pressure risk contribution value, injection well location risk contribution value, and well leakage risk contribution value of the designed well, the total well control risk contribution value of the designed well is determined. Based on the total well control risk contribution value, the wellbore structure and cementing process used in the drilling process of the designed well are determined.

2. The optimization method for drilling engineering design according to claim 1, characterized in that, The method of determining the overflow risk contribution value, injection-production relationship risk contribution value, water injection well casing pressure risk contribution value, water injection well location risk contribution value, and well leakage risk contribution value of the design well based on the formation pressure value at the wellhead location of the design well, the vertical depth of multiple target points of the design well, the oil pressure of multiple production wells adjacent to the design well, the oil pressure and casing pressure of multiple water injection wells adjacent to the design well, the distance between the design well and the multiple production wells, the distance between the design well and the multiple water injection wells, the number of well leakage incidents in adjacent wells of the design well, and the geological structure of the area where the design well is located, includes: The overflow risk contribution value of the design well is determined based on the formation pressure value at the wellhead location; Based on the vertical depth of the multiple target points, the oil pressure of the multiple production wells, the oil pressure of the multiple injection wells, the distance between the design well and the multiple production wells, and the distance between the design well and the multiple injection wells, the risk contribution value of the injection-production relationship of the design well is determined. The casing pressure risk contribution value of the design well is determined based on the casing pressure of the plurality of injection wells and the distance between the design well and the plurality of injection wells. The risk contribution value of the injection well location of the design well is determined based on the distance between the design well and the plurality of injection wells. The leakage risk contribution value of the design well is determined based on the number of well leakage occurrences in adjacent wells and the geological structure of the area where the design well is located.

3. The optimization method for drilling engineering design according to claim 2, characterized in that, The step of determining the injection-production relationship risk contribution value of the design well based on the vertical depth of the multiple target points, the oil pressure of the multiple production wells, the oil pressure of the multiple injection wells, the distance between the design well and the multiple production wells, and the distance between the design well and the multiple injection wells includes: The average vertical depth of the multiple target points is determined as the average vertical depth of the designed well. Based on the average vertical depth of the design well, the oil pressure of the plurality of production wells, the oil pressure of the plurality of water injection wells, the distance between the design well and the plurality of production wells, and the distance between the design well and the plurality of water injection wells, the average formation pressure coefficient of the design well is determined. The average formation pressure coefficient is used to reflect the degree of influence of the production wells and water injection wells adjacent to the design well on the formation pressure of the design well. Based on the average vertical formation pressure coefficient of the designed well, the risk contribution value of the injection-production relationship of the designed well is determined.

4. The optimization method for drilling engineering design according to claim 2, characterized in that, The step of determining the injection well location risk contribution value of the design well based on the distance between the design well and the plurality of injection wells includes: For any injection well, based on the distance between the injection well and the design well, the risk contribution value corresponding to the distance is queried from the first mapping information. The first mapping information is used to indicate the correspondence between the distance between the injection well and the design well and the risk contribution value. The average of multiple risk contribution values ​​corresponding to the distances between the multiple injection wells and the design well is determined as the risk contribution value of the injection well location of the design well.

5. The optimization method for drilling engineering design according to claim 2, characterized in that, The determination of the well leakage risk contribution value of the design well based on the number of well leakage occurrences in adjacent wells and the geological structure of the area where the design well is located includes: Based on the geological structure of the area where the design well is located, determine whether the design well encounters faults or unconformities during the drilling process; In the event of a fault or unconformity, the well leakage risk contribution value of the designed well is determined to be 1; Without encountering faults or unconformities, based on the number of well leaks in adjacent wells of the designed well, the risk contribution value corresponding to the number of well leaks in the adjacent wells is queried from the second mapping information. The second mapping information is used to indicate the correspondence between the number of well leaks and the risk contribution value. The risk contribution value corresponding to the number of well leakages in adjacent wells is determined as the well leakage risk contribution value of the designed well.

6. The optimization method for drilling engineering design according to claim 1, characterized in that, The total well control risk contribution value of the designed well is determined based on the overflow risk contribution value, injection-production relationship risk contribution value, injection well casing pressure risk contribution value, injection well location risk contribution value, and well leakage risk contribution value of the designed well, including: Based on the overflow risk contribution value, injection-production relationship risk contribution value, injection well casing pressure risk contribution value, injection well location risk contribution value, and well leakage risk contribution value of the designed well, a well control risk radar map of the designed well is generated. The ratio of the area of ​​the inner pentagon to the area of ​​the outer pentagon in the well control risk radar chart is determined as the total well control risk contribution value of the designed well.

7. The optimization method for drilling engineering design according to claim 1, characterized in that, The determination of the wellbore structure and cementing process used in the drilling process of the designed well based on the total well control risk contribution value includes: Based on the total well control risk contribution value, the well control risk level corresponding to the total well control risk contribution value is queried from the third mapping information. The third mapping information is used to indicate the correspondence between the risk contribution value and the well control risk level. The well control risk level is used to represent the probability of well control risk occurring in the design well during the drilling process. The wellbore structure and cementing process corresponding to the well control risk level are determined as the wellbore structure and cementing process used in the drilling process of the designed well.

8. The optimization method for drilling engineering design according to claim 7, characterized in that, The step of determining the wellbore structure and cementing process corresponding to the well control risk level as the wellbore structure and cementing process to be used in the drilling process of the designed well includes: When the well control risk level is low, the wellbore structure used in the drilling process of the designed well is determined to be a two-section wellbore structure and the cementing process is conventional cementing or dual-density cementing. Under the condition that the well control risk level is medium, it is determined that the wellbore structure used in the drilling process of the designed well is a two-section wellbore structure with a backup of a three-section wellbore structure, and the cementing process is dual-density cementing. When the well control risk level is high, the wellbore structure used in the drilling process of the designed well is determined to be a three-section wellbore structure or a two-section wellbore structure with a backup three-section wellbore structure, and the cementing process is staged cementing.

9. An optimization device for drilling engineering design, characterized in that, The device includes: The first determining module is used to determine the overflow risk contribution value, injection-production relationship risk contribution value, water injection well casing pressure risk contribution value, water injection well location risk contribution value, and well leakage risk contribution value of the design well based on the formation pressure value at the wellhead location of the design well, the vertical depth of multiple target points of the design well, the oil pressure of multiple production wells adjacent to the design well, the oil pressure and casing pressure of multiple water injection wells adjacent to the design well, the distance between the design well and the multiple production wells, the distance between the design well and the multiple water injection wells, the number of well leakage incidents in adjacent wells of the design well, and the geological structure of the area where the design well is located. The design well is a well to be drilled. The second determining module is used to determine the total well control risk contribution value of the design well based on the overflow risk contribution value, injection-production relationship risk contribution value, casing pressure risk contribution value of the injection well, location risk contribution value of the injection well, and well leakage risk contribution value of the design well. The third determining module is used to determine the wellbore structure and cementing process used in the drilling process of the designed well based on the total well control risk contribution value.

10. A computer device, characterized in that, The computer device includes a processor and a memory, the memory storing at least one computer program, which is loaded and executed by the processor to implement the drilling engineering design optimization method as described in any one of claims 1 to 8.

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