Well drilling overflow leakage determination method and computer program

Abstract

The present disclosure relates to a drilling spill determination method and computer program, the method comprising: determining a current gas content and an actual annulus flow rate of a fluid within a drilling annulus based on a fluid sample at a drilling casing shoe; wherein the annular space is located between the inner wall of a casing pipe of a drilled well and the outer wall of a drill rod; under the condition that the current gas containing rate is smaller than a preset gas containing rate threshold value, the current working condition is determined according to preset parameters of well drilling; determining an annulus flow velocity determination model corresponding to the current working condition according to a preset corresponding relation between the annulus flow velocity and the working condition, and determining a theoretical annulus flow velocity under the current working condition according to the annulus flow velocity determination model; and judging whether overflow leakage occurs or not according to the actual annular flow velocity and the theoretical annular flow velocity. According to the method, the accuracy of overflow leakage judgment is improved, the false alarm rate of overflow leakage judgment is reduced, the effectiveness of the method for monitoring the gas cut at the casing shoe is guaranteed, and the practicability of monitoring the gas cut at the casing shoe is improved.

Description

Technical Field

[0001] This disclosure relates to the field of oil and gas drilling pressure control technology, and in particular to a method and computer program for determining drilling leakage. Background Technology

[0002] China has abundant deep and ultra-deep oil and gas resources, and exploration activities are increasing. However, drilling and completion face extremely complex environments such as high temperature, high pressure, high production, and high corrosion, as well as problems such as poor timeliness of blowout risk warnings and low success rate of overflow and well kick handling.

[0003] To address this issue, previous researchers have studied leakage monitoring methods, proposing both surface and downhole leakage monitoring methods for early leakage monitoring. These methods primarily monitor the surface mud level, wellhead fluid level, and stand pressure. Downhole leakage monitoring methods, on the other hand, analyze downhole fluid changes by measuring parameters such as gas cut, gas-oil ratio, salinity, and dielectric constant while drilling, thereby analyzing complex bottom hole leakage situations.

[0004] However, under current technology, downhole monitoring methods suffer from problems such as high susceptibility to interference and poor transmission accuracy, making them unsuitable for routine application. Surface monitoring methods, on the other hand, rely on ground data and suffer from poor timeliness and high false alarm rates due to changes in operating conditions. Summary of the Invention

[0005] This disclosure provides a method, apparatus, equipment, storage medium, and computer program for determining drilling spills. The method involves installing a Doppler ultrasonic device at the casing shoe to monitor the flow regime within the annulus, including real-time data such as flow velocity and gas content. Specifically, this disclosure proposes a spill judgment method based on measurement data and integrated logging data for gas intrusion monitoring at the casing shoe, providing a safe time window for the spill to reach the wellhead. This reduces the false alarm rate of gas intrusion monitoring at the casing shoe and improves the timeliness and accuracy of the application.

[0006] Firstly, this disclosure provides a method for determining drilling leakage, including:

[0007] Based on fluid samples from the casing shoe, the current gas content and actual annular velocity of the fluid within the drilling annulus are determined; wherein the annulus is located between the inner wall of the casing and the outer wall of the drill pipe.

[0008] If the current gas content is less than the preset gas content threshold, the current working condition is determined according to the preset drilling parameters;

[0009] Based on the preset correspondence between annular velocity and operating conditions, an annular velocity determination model corresponding to the current operating condition is determined, and the theoretical annular velocity under the current operating condition is determined based on the annular velocity determination model.

[0010] Whether leakage has occurred is determined based on the actual annular velocity and the theoretical annular velocity; wherein, the leakage includes overflow and / or leakage.

[0011] In some embodiments, it also includes:

[0012] An overflow is determined to have occurred if the gas content is not less than a preset gas content threshold.

[0013] In some embodiments, determining the current gas content and actual annular velocity of the fluid within the annular space includes:

[0014] The fluid sample is subjected to gas intrusion monitoring and analysis using Doppler ultrasound to determine the gas content and flow rate of the fluid sample. The gas content of the fluid sample is taken as the current gas content, and the flow rate of the fluid sample is taken as the actual annular flow rate.

[0015] In some embodiments, determining whether leakage has occurred based on the actual annular velocity and the theoretical annular velocity includes:

[0016] If the difference between the actual annular velocity and the theoretical annular velocity is not within a preset accuracy range, leakage is determined to have occurred.

[0017] In some embodiments, the annular velocity determination model includes a first annular velocity determination model for determining the pump start-up and shutdown process, the first annular velocity determination model including:

[0018] V a =f(Q)

[0019] Among them, V a Where is the annular velocity and Q is the displacement of the drilling fluid pump.

[0020] In some embodiments, the annular velocity determination model includes a second annular velocity determination model for determining the process of setting up and lowering the tubing string, the second annular velocity determination model including:

[0021]

[0022] Among them, V a V is the annular velocity, Q is the displacement of the drilling fluid pump, and V is the displacement of the drilling fluid pump. p D is the drill pipe lowering speed. pO D is the outer diameter of the last drill pipe lowered into the well. pI This refers to the inner diameter of the last drill pipe lowered into the well. The inner diameter of the sleeve at the sleeve shoe location. t represents the outer diameter of the drill string at the casing shoe, h represents the height of the large hook, and t represents the time.

[0023] In some embodiments, the annular velocity determination model includes a third annular velocity determination model for determining the drilling circulation process, the third annular velocity determination model including:

[0024]

[0025] Among them, V a Where is the annular velocity, and Q is the displacement of the drilling fluid pump. The inner diameter of the sleeve at the sleeve shoe location. The outer diameter of the drill string at the casing shoe.

[0026] In some embodiments, the annular velocity determination model includes a fourth annular velocity determination model for determining the annular velocity during drilling, the fourth annular velocity determination model including:

[0027]

[0028] Among them, V a Where is the annular velocity, and Q is the displacement of the drilling fluid pump. D represents the volume of rock drilled per unit time. h H represents the wellbore size. b For drill bit depth, The inner diameter of the sleeve at the sleeve shoe location. The outer diameter of the drill string at the casing shoe.

[0029] In some embodiments, it also includes:

[0030] In the event of an overflow, the model is determined based on a preset overflow time to determine the time it takes for the overflow to return to the wellhead.

[0031] In some embodiments, the preset overflow time determination model includes a first time determination model that does not include the case of gas expansion, the first time determination model including:

[0032]

[0033] Where T is the time it takes for the overflow to reach the wellhead, Hs is the distance between the drilling casing shoe and the wellhead, and V is the distance between the drilling casing shoe and the wellhead. t Let t be the actual annular velocity, t0 be the initial moment when the annular velocity changes, and t t To determine the time when overflow occurs after time Δt, V tt To determine the annular velocity at the moment of overflow.

[0034] In some embodiments, the preset overflow time determination model includes a second time determination model that includes the case of gas expansion, the second time determination model including:

[0035]

[0036] V t =V t0 +at

[0037]

[0038] Where T is the time it takes for the overflow to reach the wellhead, Hs is the distance between the drilling casing shoe and the wellhead, and V is the distance between the drilling casing shoe and the wellhead. t ρ is the actual annular velocity, a is the gas transport acceleration, m is the gas mass per unit annular height at the drill casing shoe, ρ is the drilling fluid density, g is the gravitational acceleration, and v is the gas volume per unit annular height at the drill casing shoe.

[0039] In a second aspect, this disclosure provides a computer program product, including a computer program / instructions that, when executed by a processor, implement the steps of the methods described above.

[0040] This disclosure provides a drilling spill determination method and computer program. When measuring annular velocity and gas content at the casing shoe using Doppler ultrasonic gas intrusion or other monitoring methods, it considers various operating conditions such as normal drilling, tripping the drill string, single-strut connection, circulation, and pump start-up / shutdown. It proposes methods for calculating annular velocity and identifying spills under these conditions. It also prioritizes gas content, immediately identifying a spill when the gas content is >1%. Furthermore, it establishes a method for calculating the time it takes for spilled gas to rise to the wellhead, determining the spill handling time window. This improves the accuracy of spill detection when using gas intrusion monitoring devices at the casing shoe, reduces the false alarm rate of directly judging spills based on annular velocity, ensures the effectiveness of the gas intrusion monitoring method at the casing shoe, and enhances the practicality of gas intrusion monitoring at the casing shoe. Attached Figure Description

[0041] The present disclosure will be described in more detail below based on embodiments and with reference to the accompanying drawings:

[0042] Figure 1 This is a flowchart illustrating a method for determining drilling leakage according to an embodiment of the present disclosure.

[0043] Figure 2 This is a schematic diagram illustrating gas intrusion monitoring at the drilling casing shoe, as provided in an embodiment of this disclosure.

[0044] Figure 3 This is a schematic flowchart of another drilling leakage determination method provided in an embodiment of this disclosure.

[0045] In the accompanying drawings, the same parts are referred to by the same reference numerals, and the drawings are not drawn to scale. Detailed Implementation

[0046] To enable those skilled in the art to better understand the technical solutions of this disclosure, and to fully understand and implement the process of how this disclosure applies technical means to solve technical problems and achieve corresponding technical effects, the technical solutions in the embodiments of this disclosure will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this disclosure, not all embodiments. The embodiments of this disclosure and the various features within them can be combined with each other without conflict, and the resulting technical solutions are all within the protection scope of this disclosure. All other embodiments obtained by those skilled in the art based on the embodiments of this disclosure without creative effort should fall within the protection scope of this disclosure.

[0047] It should be noted that the terms "first," "second," etc., in the specification, claims, and accompanying drawings of this disclosure are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of this disclosure described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover non-exclusive inclusion; for example, a process, method, system, product, or apparatus that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or apparatus.

[0048] It should be noted that the steps shown in the flowchart in the accompanying drawings can be executed in a computer system such as a set of computer-executable instructions, and although a logical order is shown in the flowchart, in some cases the steps shown or described may be executed in a different order than that shown here.

[0049] Example 1

[0050] In this embodiment, operating conditions are identified by analyzing the operating status parameters of surface equipment, wellbore data, and annular flow velocity. A specific overflow detection method is designed for each operating condition based on annular flow regime changes, improving the accuracy of overflow alarms and reducing false alarm rates. Simultaneously, the safe handling time is calculated using the overflow return time, allowing for safe and efficient overflow mitigation within this timeframe.

[0051] Figure 1 This is a flowchart illustrating a method for determining drilling leakage according to an embodiment of this disclosure. Figure 1 As shown, the drilling leakage determination method provided in this embodiment includes:

[0052] Step 110: Based on the fluid sample at the drilling casing shoe, determine the current gas content and actual annular velocity of the fluid in the drilling annulus; wherein the annulus is located between the inner wall of the drilling casing and the outer wall of the drill pipe.

[0053] In some embodiments, determining the current gas content and actual annular velocity of the fluid within the annular space includes:

[0054] The fluid sample is subjected to gas intrusion monitoring and analysis using Doppler ultrasound to determine the gas content and flow rate of the fluid sample. The gas content of the fluid sample is taken as the current gas content, and the flow rate of the fluid sample is taken as the actual annular flow rate.

[0055] In some embodiments, it also includes:

[0056] If the current gas content is not less than a preset gas content threshold, an overflow is determined to have occurred.

[0057] Examples of air intrusion monitoring and analysis can be found in the following examples. Figure 2 .

[0058] Preferably, the preset threshold is set to 1%, but it can also be set according to actual needs.

[0059] Optionally, leakage is first detected based on the gas content of the measured function. When drilling with oil-based or water-based drilling fluids, if the gas content in the annulus fluid is detected to be greater than 1%, a leak is determined to have occurred downhole. Since the bottomhole pressure is lower than the formation pressure, a leak alarm is triggered, and the drilling is switched to controlled pressure drilling or well control measures are taken based on changes in gas content. In other words, when drilling with water-based or oil-based drilling fluids, the determination of a gas content exceeding 1% has priority, and a leak is directly identified.

[0060] Step 120: If the current gas content is less than the preset gas content threshold, determine the current working condition based on the preset drilling parameters.

[0061] The preset parameters may include: the height of the drilling hook, the on / off status of the drilling fluid pump, the stand pressure data, the casing pressure data, etc.; the current working conditions include: normal safe drilling conditions, tripping in and out of tubing conditions, drilling fluid circulation conditions, normal drilling conditions, and connecting or disconnecting a single section of tubing conditions.

[0062] Optionally, the operating condition can be determined based on the operating status of the ground equipment, such as the hook height, pump on / off status, vertical pressure, and casing pressure data. This can be supplemented by gas intrusion monitoring data at the casing shoe, such as using rapid changes in flow velocity to determine pump start / stop status. Other operating conditions can be identified using comprehensive logging data. The leakage identification method proposed in this disclosure for gas intrusion monitoring at the casing shoe under various operating conditions compares actual theoretical calculation results with annular flow velocity measurement results to analyze leakage situations. Gas content has priority; if the gas content is found to be >1%, it is directly identified as an overflow.

[0063] Step 130: Based on the preset correspondence between annular velocity and operating condition, determine the annular velocity determination model corresponding to the current operating condition, and determine the theoretical annular velocity under the current operating condition based on the annular velocity determination model.

[0064] Among them, the one-to-one correspondence between the working conditions and the annular velocity determination model is stored in the preset correspondence relationship.

[0065] In some embodiments, the annular velocity determination model includes a first annular velocity determination model for determining the pump start-up and shutdown process, the first annular velocity determination model including:

[0066] V a =f(Q)

[0067] Among them, V a ρ is the annular velocity, in m / s; Q is the displacement of the drilling fluid pump, in L / s.

[0068] Optionally, during normal safe drilling, the annular velocity reduction trend observed during pump start-up and shutdown operations is generally rapid. A functional relationship (i.e., the first annular velocity determination model) is established based on the change in pump displacement and pump start-up / shutdown velocity, as shown in the above formula. This functional relationship is embedded into the overflow monitoring algorithm. When the monitored annular velocity reduction trend conforms to this relationship, it is determined that the operating condition has changed to ground pump start-up / shutdown operation, and this alarm is ignored when setting alarms.

[0069] In some embodiments, the annular velocity determination model includes a second annular velocity determination model for determining the process of setting up and lowering the tubing string, the second annular velocity determination model including:

[0070]

[0071] Among them, V a V is the annular velocity, Q is the displacement of the drilling fluid pump, and V is the displacement of the drilling fluid pump. p D is the drill pipe lowering speed, in m / s. pO D is the outer diameter of the last drill pipe lowered into the well. pI This refers to the inner diameter of the last drill pipe lowered into the well. The inner diameter of the casing at the casing shoe is in meters (m). The outer diameter of the drill string at the casing shoe is in meters (m), h is the hook height in meters (m), and t is the time in seconds (s).

[0072] Optionally, tripping judgment is made based on changes in hook height, well depth, and drill bit data from the logging data. When the drill bit position is less than the drilled depth and the hook is being raised or lowered, it is judged as a routine tripping operation. The upward and downward speeds of the hook are constantly calculated, and the normal annular velocity change trend during tripping is calculated. The annular velocity is analyzed based on the measured data from gas intrusion monitoring and compared with the normal change trend. If it conforms to the trend, the alarm is ignored; if it does not conform to the trend, overflow or leakage is judged based on the velocity change trend. When the drill bit is above the monitoring position during tripping, the measured flow velocity V is judged. t When V t When V > 0 + θ, it is directly judged as overflow; when V t When the value is less than 0-θ, it is judged as downhole leakage.

[0073] In some embodiments, the annular velocity determination model includes a third annular velocity determination model for determining the drilling circulation process, the third annular velocity determination model including:

[0074]

[0075] Among them, V a Where is the annular velocity, and Q is the displacement of the drilling fluid pump. The inner diameter of the sleeve at the sleeve shoe location. The outer diameter of the drill string at the casing shoe.

[0076] Optionally, during drilling fluid circulation, the discharge rate is kept constant, and the annular velocity is monitored at all times. The measured annular velocity is compared with the calculated velocity, and a reasonable fluctuation range is set according to the actual situation. When the velocity is within the upper or lower fluctuation range, it is judged as a normal situation. When the measured annular velocity exceeds or falls below the set range, it is judged as downhole overflow or leakage.

[0077] Under normal circumstances: Va-θ <Vt<Va+θ

[0078] θ is typically 1% to 5% of Va, but can be chosen based on actual conditions; it is an additional precision value and is expressed in m / s. Vt is the actual annular velocity obtained from the measurement data at the casing shoe and is expressed in m / s.

[0079] In some embodiments, the annular velocity determination model includes a fourth annular velocity determination model for determining the annular velocity during drilling, the fourth annular velocity determination model including:

[0080]

[0081] Among them, V a Where is the annular velocity, and Q is the displacement of the drilling fluid pump. D represents the volume of rock drilled per unit time. h The wellbore size is in meters (m) and height (H). b The drill bit depth is expressed in meters (m). The inner diameter of the sleeve at the sleeve shoe is in meters. The outer diameter of the drill string at the casing shoe is in meters (m).

[0082] Optionally, during normal drilling, leakage is judged based on drill bit size, mechanical drilling speed and measured data, and working conditions are identified based on drilling pressure data, drill bit position and well depth data.

[0083] When P b >0; H b =H r The time is judged to be in normal drilling condition (P) b Drilling pressure, in MPa, H b H represents the drill bit depth. r (The actual drilled depth is in meters). The actual annular velocity is calculated based on normal drilling parameters. The measured annular velocity is compared and analyzed with the theoretical calculated value. A reasonable threshold is set. When the measured value exceeds the threshold range, the downhole is judged to be in an overflow or leakage state based on the actual situation.

[0084] In some embodiments, the annular velocity determination model includes a fifth annular velocity determination model for determining the process of connecting or disconnecting a single pipe, wherein the theoretical annular velocity determined by the fifth annular velocity determination model is 0.

[0085] Optionally, when connecting or disconnecting a single pipe, this operation is generally carried out with the pump stopped. The annular flow velocity at the casing shoe is used to determine whether it is an overflow. When Va>0+θ, it is directly determined to be an overflow. When Va<0-θ, it is determined to be a downhole leakage.

[0086] Step 140: Determine whether leakage has occurred based on the actual annular velocity and the theoretical annular velocity; wherein, the leakage includes overflow and / or leakage.

[0087] In some embodiments, determining whether leakage has occurred based on the actual annular velocity and the theoretical annular velocity includes:

[0088] If the difference between the actual annular velocity and the theoretical annular velocity is not within a preset accuracy range, leakage is determined to have occurred.

[0089] The accuracy threshold θ can be set to 1% to 5% of the theoretical annular velocity under the current operating conditions, and the preset accuracy range can be set to [-θ, θ].

[0090] In some embodiments, it also includes:

[0091] In the event of an overflow, the model is determined based on a preset overflow time to determine the time it takes for the overflow to return to the wellhead.

[0092] In some embodiments, the preset overflow time determination model includes a first time determination model that does not include the case of gas expansion, the first time determination model including:

[0093]

[0094] Where T is the time it takes for the overflow to reach the wellhead, in seconds; Hs is the distance between the drilling casing shoe and the wellhead, in meters; and V... t The actual annular velocity is expressed in m / s, and t0 is the initial moment when the annular velocity changes, expressed in seconds. t The overflow time is determined after Δt, in seconds (V). tt The annular velocity at the moment of overflow is determined, in m / s.

[0095] Optionally, the time from the detection of the overflow to its return to the wellhead can be calculated to reasonably determine the well crew's response time, thereby enabling timely detection and handling to ensure drilling safety.

[0096] In some embodiments, the preset overflow time determination model includes a second time determination model that includes the case of gas expansion, the second time determination model including:

[0097]

[0098] V t =V t0 +at

[0099]

[0100] Where T is the time it takes for the overflow to reach the wellhead, in seconds; Hs is the distance between the drilling casing shoe and the wellhead, in meters; and V... t The actual annular velocity is given in m / s, and 'a' is the gas transport acceleration in m / s². -2 m is the gas mass per unit annular height at the drill casing shoe, in kg; ρ is the density of the drilling fluid; g is the acceleration due to gravity; and v is the gas volume per unit annular height at the drill casing shoe, in m³. 3 .

[0101] Optionally, the time it takes for the gas to migrate to the wellhead can be reasonably calculated by calculating the gas migration velocity and taking into account the gas expansion due to pressure reduction during the upward return.

[0102] Based on the model determined in the second time, we can obtain:

[0103]

[0104] Furthermore, through integral conversion, the maximum time window from gas detection to gas migration to the wellhead can be calculated, which can promptly remind the well team to handle the overflow and ensure safe and efficient operation.

[0105] Furthermore, for a better understanding of the technical solution of this application, please refer to... Figure 3 , Figure 3 This is a schematic flowchart of another drilling leakage determination method provided in an embodiment of this disclosure.

[0106] In this embodiment, operating conditions are identified by comprehensively analyzing logging data (such as hook height, displacement, drilling pressure, and wellbore data) and the annular flow status at the casing shoe. It is particularly important to note that gas content measurement at the casing shoe has priority in overflow detection. If the gas content exceeds 1%, further operating condition identification is unnecessary, and the system can be directly identified as an overflow, initiating pressure control or well control procedures. Based on calculations and analyses of sensitive parameters for each operating condition, an equation and calculation method for the annular flow velocity change trend at the casing shoe under various operating conditions are established. The measured annular flow velocity values ​​are compared with the changing values, and a reasonable threshold is set. When the measured value is within a reasonable range, the system is considered to be operating normally. When the measured value exceeds the threshold, overflow or leakage is detected and an alarm is triggered. By establishing an overflow monitoring and judgment method for various operating conditions under gas intrusion monitoring at the casing shoe, the high false alarm rate caused by changes in operating conditions can be effectively eliminated, effectively ensuring the safety of the entire drilling process. Establish a method for calculating the time it takes for overflow or gas to rise to the wellhead, determine the safe handling time window, and promptly remind the drilling team to handle the situation within the time window to effectively ensure drilling safety.

[0107] Example 2

[0108] Based on the above embodiments, this embodiment is a specific example.

[0109] In this embodiment, leakage is determined by starting the next drill string.

[0110] When logging data is accessed, if the drill bit position is found to be less than the actual well depth and the hook is in the upward position, it is determined that the tubing string needs to be pulled out. The upward speed V of the hook is recorded continuously. pAnd the pump displacement Q, calculate the theoretical annulus flow velocity Va according to the upward speed of the traveling block, and based on the measured data of the annulus flow velocity Vt at the casing shoe, compare and analyze Va and Vt. Set the upper and lower amplitude accuracy to 3%Va. When Vt > 103%Va, it can be judged that there is an overflow at the bottom of the well; when Vt < 97%Va, it can be judged that there is a loss in the well. Furthermore, the pressure control or well killing operation can be carried out according to the amount of overflow and loss.

[0111] When 97%Va < Vt < 103%Va, it is judged as a normal drill pipe pulling situation, and the current working condition is maintained to pull the drill pipe according to the plan. When the bit depth remains unchanged and the pump displacement is 0 after one drill pipe string is pulled out, the bit depth remains unchanged and the pump displacement is 0. Then, the single joint is removed. At this time, judge whether the annulus flow velocity Va at the casing shoe is 0. When Va > 0 + 0.05 m / s, it is judged that there is an overflow in the well; when Va < 0 - 0.05 m / s, it is judged that there is a loss in the well. Calculate the amount of overflow and loss and the time window for the overflow to return to the wellhead, and timely remind the well team to carry out pressure control or well killing operation. When 0 - 0.05 m / s < Va < 0 + 0.05 m / s, it is a normal working condition, and the operation of pulling out the next string is carried out.

[0112] The following takes normal drilling as an example for elaboration. Judge whether it is in the normal drilling state according to the data such as the position of the bit, the drilled depth, and the drilling pressure. When the drilling pressure Pb > 0 and Hr = Hb, it is judged as the normal drilling state. Compare and analyze the actual annulus flow velocity Vt and the theoretical Va. When Vt is within the range of Va ± 3%Va, it is judged as the normal drilling state; when Vt > 103%Va, it is judged that there is an overflow at the bottom of the well; when Vt < 97%Va, it is judged that there is a loss in the well.

[0113] Furthermore, calculate the amount of overflow and loss and the time window for the overflow to return to the wellhead, and remind the well team to carry out pressure control or well killing operation according to the degree of overflow and loss.

[0114] Example 3

[0115] Based on the above embodiments, this embodiment provides a device for determining drilling overflow and loss.

[0116] This device embodiment can be used to execute the method embodiment of this application. For the details not disclosed in this device embodiment, please refer to the method embodiment of this application. The device disclosed in this embodiment includes:

[0117] The gas holdup and actual annulus flow velocity determination module is used to determine the current gas holdup and actual annulus flow velocity of the fluid in the drilling annulus based on the fluid sample at the casing shoe of the drilling; wherein, the annulus is located between the inner wall of the casing and the outer wall of the drill pipe of the drilling.

[0118] The current working condition determination module is used to determine the current working condition based on preset drilling parameters when the current gas content is less than a preset gas content threshold.

[0119] The annular velocity determination module is used to determine the annular velocity determination model corresponding to the current working condition based on the preset correspondence between the annular velocity and the working condition, and to determine the theoretical annular velocity under the current working condition based on the annular velocity determination model.

[0120] The determination module is used to determine whether leakage has occurred based on the actual annular flow velocity and the theoretical annular flow velocity; wherein, the leakage includes overflow and / or leakage.

[0121] Those skilled in the art will understand that the modules or steps described above can be implemented using general-purpose computing devices, either centralized on a single computing device or distributed across a network of multiple computing devices. Optionally, they can be implemented using computer-executable program code, thereby allowing them to be stored in a storage device for execution by a computing device. Furthermore, in some cases, the steps shown or described can be performed in a different order than presented herein, or they can be fabricated as separate integrated circuit modules, or multiple modules or steps can be fabricated as a single integrated circuit module.

[0122] Those skilled in the art will clearly understand that, for the sake of convenience and brevity, the specific working process of each module in the device can be referred to the corresponding process in the foregoing method embodiment, and will not be repeated here.

[0123] Example 4

[0124] Based on the above embodiments, this embodiment provides a computer device.

[0125] The computer device includes a memory, a processor, and a computer program stored in the memory, wherein the processor executes the computer program to implement the steps of the method described in the above embodiments.

[0126] In some embodiments of this example, a computer-readable storage medium is provided, on which a computer program is stored, characterized in that the computer program, when executed by a processor, implements the steps of the method described in the above embodiments.

[0127] In some embodiments of this example, a computer program product is provided, including a computer program / instructions, characterized in that the computer program, when executed by a processor, implements the steps of the method described in the above embodiments.

[0128] The processor may include, but is not limited to, one or more processors or microprocessors. Each processor may be implemented as an Application Specific Integrated Circuit (ASIC), Digital Signal Processor (DSP), Digital Signal Processing Device (DSPD), Programmable Logic Device (PLD), Field Programmable Gate Array (FPGA), controller, microcontroller, microprocessor, or other electronic component, for executing the methods described in the above embodiments.

[0129] Computer-readable storage media can be implemented by any type of volatile or non-volatile storage device or a combination thereof. Computer-readable storage media may include, but are not limited to, random access memory (RAM), read-only memory (ROM), flash memory, EPROM memory, EEPROM memory, registers, and computer storage media (e.g., hard disks, floppy disks, solid-state drives, removable disks, CD-ROMs, DVD-ROMs, Blu-ray discs, etc.).

[0130] Computer-readable storage media may also store at least one computer-executable program / instruction, such as computer-readable instructions. Computer-readable storage media include, but are not limited to, volatile memory and / or non-volatile memory. Volatile memory may include, for example, random access memory (RAM) and / or cache memory. Computer-readable storage media may include, for example, read-only memory (ROM), hard disk, flash memory, etc. For example, a non-transitory computer-readable storage medium may be connected to a computing device such as a computer, and then, when the computing device executes the computer-readable instructions stored on the computer-readable storage medium, the various methods described above can be performed.

[0131] In addition, the computer device may include (but is not limited to) a data bus, an input / output (I / O) bus, a display, and input / output devices (e.g., keyboard, mouse, speakers, etc.).

[0132] The processor can communicate with external devices via the I / O bus through wired or wireless networks.

[0133] In one embodiment, the at least one computer-executable instruction may also be compiled into or comprise a software product / computer program product, wherein one or more computer-executable instructions are executed by a processor to perform the steps of the various functions and / or methods in the embodiments described herein.

[0134] In the embodiments provided in this disclosure, it should be understood that the disclosed apparatus and methods can also be implemented in other ways. The apparatus embodiments described above are merely illustrative; for example, the flowcharts and block diagrams in the accompanying drawings illustrate the architecture, functionality, and operation of possible implementations of apparatus, methods, and computer program products according to various embodiments of this disclosure. In this regard, each block in a flowchart or block diagram may represent a module, segment, or portion of code containing one or more executable instructions for implementing a specified logical function. It should also be noted that in some alternative implementations, the functions marked in the blocks may occur in a different order than those marked in the drawings. For example, two consecutive blocks may actually be executed substantially in parallel, and they may sometimes be executed in reverse order, depending on the functions involved. It should also be noted that each block in a block diagram and / or flowchart, and combinations of blocks in block diagrams and / or flowcharts, can be implemented using a dedicated hardware-based system that performs the specified function or action, or using a combination of dedicated hardware and computer instructions.

[0135] It should be noted that, in this disclosure, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitation, an element limited by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0136] While the embodiments disclosed herein are as described above, the foregoing content is merely for the purpose of facilitating understanding of this disclosure and is not intended to limit this disclosure. Any person skilled in the art to which this disclosure pertains may make any modifications and changes in form and detail of the implementation without departing from the spirit and scope of this disclosure; however, the scope of patent protection of this disclosure shall still be determined by the scope defined in the appended claims.

Claims

1. A method of drilling spill determination, the method comprising: The method comprises: determining a current gas cut of fluid in an annular space of a wellbore and an actual annular velocity based on a fluid sample at a wellbore casing shoe, wherein the annular space is between an inner wall of a casing of the wellbore and an outer wall of a drill pipe; in a case where the current gas cut is less than a preset gas cut threshold, determining a current working condition according to preset parameters of the wellbore; determining an annular velocity determination model corresponding to the current working condition according to a preset corresponding relationship between the annular velocity and the working condition, and determining a theoretical annular velocity in the current working condition according to the annular velocity determination model; determining whether overflow and / or loss has occurred according to the actual annular velocity and the theoretical annular velocity.

2. The method of claim 1, wherein, The method further comprises: in a case where the current gas cut is not less than the preset gas cut threshold, determining that overflow has occurred.

3. The method of claim 1, wherein, The method of determining the current gas cut of fluid in the annular space and the actual annular velocity comprises: monitoring and analyzing gas invasion of the fluid sample by Doppler ultrasound to determine the gas cut and the flow rate of the fluid sample, and taking the gas cut of the fluid sample as the current gas cut and the flow rate of the fluid sample as the actual annular velocity.

4. The method of claim 1, wherein, The method of determining whether overflow and / or loss has occurred according to the actual annular velocity and the theoretical annular velocity comprises: in a case where a difference between the actual annular velocity and the theoretical annular velocity is not within a preset accuracy interval, determining that overflow and / or loss has occurred.

5. The method of claim 1, wherein, The annular velocity determination model comprises a first annular velocity determination model for determining a first annular velocity in a pump start-stop process, and the first annular velocity determination model comprises: V a = f(Q) where V a is the annular flow rate, Q is the displacement of the drilling fluid pump.

6. The method of claim 1, wherein, The annular velocity determination model comprises a second annular velocity determination model for determining a second annular velocity in a pipe tripping process, and the second annular velocity determination model comprises: where V a is the annular flow rate, Q is the displacement of the drilling fluid pump, V p is the trip speed of the drill pipe, D pO is the outer diameter of the last drill pipe run into the well, D pI is the inner diameter of the last drill pipe run into the well, is the casing inner diameter at the casing shoe, is the drill string outer diameter at the casing shoe, h is the hook height, and t is the time.

7. The method of claim 1, wherein, The annular velocity determination model comprises a third annular velocity determination model for determining a third annular velocity in a wellbore circulation process, and the third annular velocity determination model comprises: where V a is the annular flow rate, Q is the displacement of the drilling fluid pump, is the casing inner diameter at the casing shoe, is the drill tool outer diameter at the casing shoe.

8. The method of claim 1, wherein, The annular velocity determination model comprises a fourth annular velocity determination model for determining a fourth annular velocity in a drilling process, and the fourth annular velocity determination model comprises: where V a is annular velocity, Q is the displacement of the drilling fluid pump, is the volume of rock drilled per unit time, D h is the hole size, H b is the bit depth, is the casing inner diameter at the casing shoe, is the tool outer diameter at the casing shoe.

9. The method according to any one of claims 1 to 8, characterized in that, The method further comprises: in a case where overflow has occurred, determining a time for overflow to return to a wellhead of the wellbore according to a preset overflow time determination model.

10. The method of claim 9, wherein, The preset overflow time determination model comprises a first time determination model not involving gas expansion, and the first time determination model comprises: Wherein, T is the time of overflow to the wellhead, Hs is the distance between the drilling casing shoe and the wellhead, V t is the actual annular flow rate, t0 is the initial time when the annular flow rate changes, t t is the time when overflow is determined after the time Δt, V tt is the annular flow rate when overflow is determined.

11. The method of claim 9, wherein, The preset overflow time determination model comprises a second time determination model involving gas expansion, and the second time determination model comprises: V t = V t0 + at where T is the time to overflow the wellhead, Hs is the distance between the drill shoe and the wellhead, V t is the actual annular flow rate, a is the gas migration acceleration, m is the mass of gas per unit annular height at the drill shoe, p is the density of the drilling fluid, g is the gravitational acceleration, and v is the volume of gas per unit annular height at the drill shoe.

12. A computer program product comprising computer programs / instructions, characterized in that, The computer program is executed by a processor to implement the steps of the method of any one of claims 1 to 11.

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