METHOD AND APPARATUS FOR PREDICTING TUBING WEAR FOR WELL SYSTEMS

专利摘要:
The present invention relates to a method for determining a casing wear of a casing in a wellbore, a computer program product for determining a casing wear factor value (CWF), calculated for tubing in a wellbore, and a wellsite control device. In one embodiment, the wellsite controller includes: (1) an interface configured to receive actual remaining wall thickness (RWT) values that correspond to a set of casing depth values of a wellbore and (2) a processor configured to determine a retro-calculated casing wear factor (CWF) value for the wellbore based on a comparison between the actual RWT value and a RWT value estimated, for the set of casing depth values, where the estimated RWT value is calculated using an estimated CWF value as input.
公开号:FR3067744A1
申请号:FR1853999
申请日:2018-05-11
公开日:2018-12-21
发明作者:Aniket Aniket；Adolfo Gonzales
申请人:Landmark Graphics Corp；
IPC主号:

专利说明:

METHOD AND APPARATUS FOR PREDICTING TUBING WEAR FOR
WELL SYSTEMS
TECHNICAL AREA
The disclosure generally relates to systems, methods, and techniques for drilling and supporting a wellbore, and more specifically, methods for calculating and estimating casing wear for optimizing system drilling operations. well.
BACKGROUND OF THE INVENTION
In the search for hydrocarbons, such as oil and gas, and the development of wells containing hydrocarbons, oil field operators drill boreholes and carry out well completion operations. An example of a well completion operation is the installation of casing along a borehole. The drilling crew fixes casing segments together to close the casing while it is lowered into the borehole to a desired position. As soon as the team reaches the desired length and position for a particular section of tubing, it cements it in place to create a permanent tubing section installation. The team can then extend the borehole by drilling through the end of the installed tubing section. The process of installing casing sections and extending a borehole can be repeated until a target depth of the borehole is reached.
When drilling an oil and gas well, well operators, such as operators, engineers, well planners, etc., aim to achieve the target depth without significantly wearing down the casing wall. cause any casing ruptures. During drilling and well completion operations, many factors contribute to loss of borehole wall integrity or casing wear, such as corrosion, erosion during fracturing, rotation of the drill string which results in frictional wear along the contact surfaces with the casing, another mechanical wear, the type of fluid in the wellbore, the amount of pressure to which the fluid is subjected, the type of material through which the drilling is in progress, the angle or geometry of the wellbore, and other factors. Over time, such wear reduces a side wall thickness of casing, degrading the strength and integrity of casing. Whatever the cause, a rupture of a casing segment can result in costly well repair operations or abandonment of the well.
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BRIEF _DESCMpTION
Reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:
Figure 1 illustrates a diagram of an exemplary well system with a drilling tool inserted into a wellbore;
Figure 2 illustrates a diagram of an exemplary well system with multiple sections of tubing;
Figure 3 illustrates a block diagram of an example of a well site control system;
FIG. 4 illustrates a plot of time with respect to the wear of an example of a wellbore operation plan showing casing wear as a percentage on one. time elapsed ;
FIG. 5 illustrates a process diagram of an exemplary method for determining, and using, a casing wear factor value in. employing well logging;
FIG. 6 illustrates a process diagram of an example of a method of back calculation of a casing wear factor through an iterative process;
Figure 7 illustrates a flow diagram of an example of a casing factor back calculation method using a best matching casing factor range (CWF) process; and Figure 8 illustrates one. flow diagram of an example of a casing wear analysis method employing a CWF and a drill tool revolution count in a casing wear trend.
DETAILED DESCRIPTION
To reduce the possibility of casing ruptures due to wear, operators can increase the thickness of the casing material or use more expensive, wear-resistant material. Whatever the material, casing wear needs to be followed and monitored throughout the well operation so that well operators have information on casing integrity with the aim of preventing ruptures casing. Therefore, having a real-time understanding of how wear and tear on the casing walls has progressed since the start of a drilling operation and how long it remains before a sustaining operation results in Major damage to the casing walls would be beneficial to a well operator. A thorough understanding of the time remaining as well as the remaining laps available before reaching a casing wear limit will help
2Q17-IPM-10O992-U1-FR the drilling operator to plan and adjust operations more precisely in real time in order to stay within pre-defined constraints and avoid any security incidents.
Well operators typically keep well logs for each wellbore to monitor casing wear. These well logs contain, in part, the measured thickness of the casing walls at various locations and depths. If excessive wear is detected, then drilling and extraction operations can be put on hold and a repair operation is undertaken, resulting in significant cost to the well operator. These casing wall measurements can be taken using a variety of methods using, for example, diameter logs, or ultrasonic logs. In order to take these actions, other well operations are put on hold and again may result in significant cost or loss of income for the well operator. For example, shutdowns for a complete measurement of the actual remaining wall thickness of casing, under certain circumstances, can cost the general operation $ 1-2 million. Reducing the number of times a physical measurement needs to be taken is beneficial to well site operators.
To avoid the high cost of taking remaining wall thickness measurements, well planners often use casing well modeling and simulations to estimate the remaining wall thickness (RWT) of a casing as a means, to maintain well integrity at a lower cost. A metric or factor used in models and simulations is a casing wear factor (CWF). The casing wear factor is a known factor used in the industry for estimating casing wear and is derived from a combination of parameters, such as, material properties, a type of operation, a downhole pressure, downhole temperature, well readings, twist and twist of a wellbore. Other operating parameters, such as rotation speed, rotation time, and normal contact force, can also influence casing wear factors.
Laboratory-derived casing wear factors can be used for well modeling and simulations. However, one. laboratory testing has limitations since many difficult conditions cannot be properly estimated or re-created in a laboratory environment. To compensate for these limitations, casing wear factors may be overestimated and thus result in unnecessary costs for operating a well.
After a casing wear factor has been determined, it can then be used in a casing wear analysis for more advanced well system operational planning. Certain well system operations, such as, but not limited to, a
2O17-IPM-10O992-U1-FR drilling, a back bore, a rotation in elevation, a sliding, and a reciprocating movement, during an execution, affect the remaining wall thickness of casing by wear. The determined casing wear factor can be applied to each of these operations to further determine the amount of casing wear that could occur during an elapsed period of time in which such a well system operation is in progress. . A well system engineer, operator, or planner can use the casing wear determined for each operational stage of the well system plan, to create an updated well system plan where the thickness value of remaining casing wall remains within the acceptable tolerance level. Other wellbore conditions may also affect the values of remaining casing wall thickness, such as, but not limited to, erosion during fracturing, corrosion, other types of mechanical wear, and can be combined with the above-mentioned well system operations to be part of a specific well system plan. As new measurements of actual remaining casing wall thickness are taken from well casing, the well system plan can be revised iteratively with new estimates, back-calculated casing wear factors , and trend line analysis to determine an updated well system plan.
This disclosure presents a new method for deriving a value for the casing wear factor based on a wear log from the field and using this derived casing wear factor to model a well system plan . The method uses a back-calculated process to derive the casing wear factor from actual casing wear data. The derived casing wear factor can be used to determine the estimated remaining wall thickness for casing when selected well operations are performed over an elapsed time also incorporating a drilling tool revolution account for the operations wells selected. Such determination can be further used in a well system plan, which in turn can be used for planning, and operating of existing wells or the like. Therefore, disclosure can improve the accuracy of predicting casing conditions, such as casing failure, due to mechanical downhole wear to the casing during any well drilling operation. In addition to casing failures, casing conditions may include a percentage of casing wear, a remaining wall thickness of the casing, or some other predetermined casing condition that has stood out for monitoring. As an example, a method for improving a prediction accuracy for tubing failure disclosed herein includes a. cascade wear factor feedback based on multiple log depths from field wear logs that help perform wear analysis more precisely
2Q17-IPM-10O992-U1-FR of casing for subsequent operations performed in the well, in which the casing wear analysis includes an estimate of the amount of time and remaining turns before an occurrence of a casing condition is not encountered during oil and gas well drilling.
In an example of a method disclosed here for back calculation of casing wear factors, a set of casing depth locations is selected and the corresponding minimum remaining wall thickness values from the logs are identified. These remaining wall thickness values are identified as actual remaining wall thickness values. Next, the values of the remaining wall thickness, for each selected depth point, are estimated using a casing wear simulation modeling approach with an initial estimated value for the casing wear factor. Initial values used for the estimated casing wear factor can be obtained from a source, for example, similar well sites, past experience, an amount of material that has been removed from the well. drilling, and controlled or laboratory tests and experiments.
A processor can be programmed to perform a casing wear estimation and analysis algorithm represented by the methods disclosed herein. Using a processor, the estimated remaining wall thickness values are compared with the actual remaining wall thickness values at the corresponding depths to identify the alignment proximity of each set of actual remaining wall thickness values and estimated. An error value is derived and used to determine the level of precision or comfort in using the casing wear factor estimated for future modeling and simulations.
The error value between the actual remaining wall thickness of casing and the estimated remaining wall thickness of casing can be calculated using various techniques. For example, the error value can be calculated by the sum of errors method or the quadratic method. These are standard techniques used in statistical analysis to understand correlations between two sets of data points. The most appropriate casing wear factor to be used to estimate casing wear will be a minimum value when using the sum of error or quadratic methodologies.
The estimated casing wear factor can be continuously refined until the error value reaches an acceptable range or tolerance limit. The refined casing wear factor is considered to be the back-calculated wear factor. The range or an acceptable tolerance limit for the error value may vary depending on the well site operation
2Û17-IPM-10O992-U1-FR specific. For example, in some circumstances, an error value less than 0.01 indicates that the estimated casing wear factor is appropriate and accurate for an estimate of future casing wear at the selected point in the wellbore. In other well site operations, an error value less than 0.005 may be a more appropriate target range.
To refine the error value, the initial casing wear factor, for the calculation of an estimated remaining casing wall thickness, is adjusted and a second casing wear factor is used to calculate a new casing thickness. estimated remaining casing wall. Another comparison is made between the estimated and actual remaining wall thickness values of casing. If the new error value is less than the previous iteration error value, then it is better. Additional refinements to the casing wear factor are made and additional iterations of the calculation are performed until the error value reaches a selected value or is either within a prescribed range or level of tolerance. The resulting casing wear factor is now a back-calculated casing wear factor.
The estimated casing wear factor can be determined by selecting a minimum and maximum estimated casing wear factor and then the range created by the minimum and maximum values is divided into two parts. Then, representative casing wear factors are identified, for example, at the midpoint of these ranges. These two identified casing wear factors are then used to carry out a casing wear simulation to estimate the values of the remaining casing wall thickness. Next, the error value is determined by comparing the simulated / calculated remaining wall thickness values and the actual remaining wall thickness value for the two representative casing wear factors. The representative casing wear factor with a result of a lower error value is likely to provide more accurate simulations in future well operations. The most suitable casing wear factor is likely to be in the range where the casing wear factor provides the minimum error value, called the most suitable CWF range. The most suitable CWF range is again divided into two parts and new representative casing wear factors are selected .30 from each part, for example, at the center of the identified range, or a minimum value or maximum within this range. A new calculation is performed with the newly selected representative casing wear factors and a new error value is determined for each calculation.
For example, an initial casing wear factor range of 0 to 500 can be selected as appropriate for well site conditions and properties.
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This range can be divided into two smaller sub-ranges as best determined by well site properties, for example 0 to 250 and 251 to 500. A representative casing wear factor can be determined from each sub-range, for example, by selecting midpoints 125 and 376, The sub-range which has a result with a lower error value, after a calculation and comparison of the estimated remaining wall thickness of casing for each casing wear factor representative of the actual remaining wall thickness, is selected. This selected sub-range should be considered the new best matching CWF range. For example, if the casing wear factor 125 has resulted in a lower error value, then sub-range 0 to 250 should be the new CWF range that best matches and can be further divided into parts, by example, 0 to 125 and 126 to 250. Again, the iterative process of selecting midpoint values, using them to determine remaining wall thickness values, and comparing the estimated remaining wall thickness values to the actual remaining wall thickness value is repeated until an acceptable casing wear factor is determined.
The number of iterations performed by the processor can be limited to a defined number of times before leaving iteration processing. The defined number of times can be limited by a chosen value, for example, 20, or it can depend on the error value itself, for example, an error value less than 0.01.
After a number of iterations, an adequate value for the casing wear factor can be identified which, after treatment using simulation, provides an acceptable correspondence with the actual values of the remaining wall thickness casing. The casing wear factor can further be used with confidence for the next steps in a casing wear analysis, by wellbore operations teams, and in planning for this or other wells with similar properties.
The back-calculated casing wear factor can be used to perform casing wear analysis for operations management occurring inside the wellbore. The various operations of the well system plan can include drilling, back-boring, rotation, elevation, sliding, one. reciprocating, or other types of drilling operations. By using the back-calculated casing wear factor to simulate or estimate an execution, of these selected operations, one. plot or graph of time versus wear can be created by showing the approximate casing wear while each selected operation is in progress over an elapsed time. A most suitable trend line or a most suitable trend line can be estimated, using any available technique, such as using linear regression or another statistical process,
2Û17-IPM-10O992-U1-FR to provide a casing wear forecast if the selected operation should continue with a shorter or longer elapsed time.
The generated graph may also include one or more warning or boundary lines showing the point at which a most suitable operating trend line or curve would intersect such warning or boundary lines. Warning or limit lines can be inserted to show different levels of warning, for example, a limit line can be placed to show that the operation being executed should be changed or stopped. In addition, a boundary line can be placed at a point on the graph to indicate that action should be taken, such as ending or changing wellbore activities, and taking action. of remaining wall thickness of casing.
A well system operation may also include rotating a drilling tool and a drill string inside the wellbore. This rotation, in addition to other wear and tear caused by the well system operation, can cause casing wear and is tracked as the total number of turns to which the drill bit and a drill string are subjected. The lap count can be plotted against the elapsed time during which the spins occur and then the elapsed time is plotted against the estimated casing wear that may occur. A most suitable trend line can be estimated, using any available technique. The revolutions per minute (RPM) of the drill bit and of a drill string would increase as they are rotated faster. An increased rotational speed would increase the slope of the most suitable trend line, i.e., casing wear would occur more quickly over time. Likewise, a decreased rotation speed would decrease the slope of the most suitable trend line, i.e., casing wear would occur more slowly over the time.
Based on the casing wear determined for each selected operation, the well system planning steps or an elapsed time for each selected operation can be revised, or the sequence of selected operations can be rearranged to provide a more consistent match. narrow for the goals and objectives of the well system plan, while maintaining the remaining wall thickness of casing within an acceptable range or tolerance level.
The disclosed methods can be implemented directly inside a well site control device. As new well logging data becomes available, new process iterations can be performed to provide engineers, operators, and well planners with an estimated casing wear factor that can be used while operations drilling sites continue. These
2Û17-IPM-10O992-U1-EN information can be used, for example, to determine the number of turns of the drilling tool and drill string that can be done safely, to determine the amount of time elapsed during which wellbore can be in safe operation, to control the amount of fluid pressure applied inside the wellbore, to determine how much lubricant needs to be added, or to determine a best estimate when measuring The following actual wall casing remaining wall thickness should occur to minimize the amount of well downtime.
The method can be implemented within a computer program that deals with, or separately from, well site equipment. For example, the computer program can operate in a controlled or laboratory environment to better determine the initial casing wear factors estimated for various well site conditions and then use these factors in a well system plan.
Referring now to the figures, Figure 1 illustrates a diagram of an, example of a WO well site. Well 100 can be used to recover hydrocarbons or other valuable materials from below the earth's surface. The well site 100 includes a well 101, a drilling tool 106, a train, drilling 107, surface equipment 108, and a well site controller 110. The drilling train 107 connects the drilling tool 106 to surface equipment 108. The drilling well 101 includes two representative sections 102 and 103. A section 102 was installed one. casing to provide support and sealing for the wellbore. While the drill bit 106 and the drill string '107 are rotated to extend the borehole' 101, friction will cause wear to the casing of a section 102. The drill tool 106, a train, of drilling '107, and surface equipment 108 may be conventional devices.
The well site controller 110 directs a well site operation 100. The well site controller 110 includes a processor and memory that are configured to control various operations at the well site 100. An operator or an engineer may use the well site controller 110 to assist with or direct various operations at the well site 100. The well site controller 110 or portions thereof may be located remotely from the physical location of the wellbore 101. The wellsite control device 110 is communicatively coupled to at least some of the other components of the wellsite 100 via wired or wireless connections.
Figure 2 illustrates a system diagram of another example of a well site, one. well site 200, which is similar to a well site 100. A well site 200 includes a well bore 211, a drilling tool 206, a drill string 207, surface equipment
2Û17-IPM-10O992-U1-FR well site 208, and a well site control device 210. The well bore 211 includes sections 201, 202, and 203. As with the corresponding components of Figure 1, the drilling tool 206, the drill string 207, and the well site surface equipment 208 may be conventional devices or components. The well site controller 210 can be configured as, and operates as, the well site controller 110 of Figure 1. The well site controller 210 can be configured to run at least a portion of the process disclosed here. Well site controller 210 can generate a back-calculated casing wear factor. The determined back-calculated casing wear factor can then be used in other well operation steps, for example, a determination of a drilling rotation speed, an elapsed time for an execution of an operational step, a limit on the number of revolutions of the storm train, a pressure, well system fluid, a casing material to be used, a casing thickness to be used , a recommended time interval for when to measure the actual remaining wall thickness of casing, or to determine other well system factors.
While the wellbore 211 is drilled, it is periodically coated with casing material which is cemented in place, as shown in a section 201 with casing material 204. At periodic depths, for example at 2,000 feet, (typical depth locations are between 2,000 and 5,000 feet, but may be greater or less depending on specific wellbore characteristics), a narrower wellbore 202 is started and coated with casing material 205 and cemented in square. While a section 202 is being drilled, casing wear will occur in a section 201, on a casing material 204. The drilling tool 206 and the drill string 207 are rotated and thus cause friction against the casing material 204 and loss of material 204.
Additional sections may be created before the drilling tool 206 drills in the uncased section 203. For example, there may be three, four, or five, or more sections which are cased separately within a wellbore as the depth increases or the properties of a wellbore require it. This figure shows, by way of example only, two cased sections, 201 and 202, and an uncased section 203. The drilling tool 206 and the drilling string 207, while they are turned, will cause friction against the casing material 204 in a section 201 and the well casing 205 in a section 202 thus causing a loss of material at the point of contact, called casing wear.
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FIG. 3 illustrates a diagram of an example of a well site control system 300. The well site control system 300 includes, in part, a well site control device 301 capable of performing the process described here. The well site controller 301 is configured to receive input data 313, execute at least some of the methods and simulations disclosed herein, and provide at least some of the data resulting from the executions, resulting data 323, for a transmission. A communication interface 302 is configured to receive the input data 313 and transmit the resulting data 323. Input data 313 includes information from at least one (1) of a network connection 310 which can be wired or wireless, (2) from an electronic device 312, for example, but not limited to, a mobile phone, a PDA, a tablet, a laptop, electronic well system devices including sensors , or another device, or (3) by manual entry 311, for example, by an engineer, operator, or well planner. The input data 313 includes, in part, information obtained from actual measurements of the remaining wall thickness of casing, i.e., well logs, for example, from diameters, micro-electronic devices, magnetic resonance, or other processes used in industry. In addition, the input data 313 may also include factors or properties specific to the wellbore, for example, but not limited to, (1) the time elapsed during which the drilling tool has been running, ( 2) how many revolutions per minute the drilling tool is rotating, (3) the type of material being drilled, (4) the angle of the wellbore at the location where the measurement was taken , (5) fluid pressure within the wellbore, (6) applied friction reduction materials, i.e., lubricants, for example, graphene, and (7) a any other relevant factor.
Input data 313 may also include the initial estimated casing wear factor. If input data 313 does not include the estimated casing wear factor, then this data item can be retrieved by reading the estimated casing wear factors for various sets of wellbore factors or properties (hereinafter wellbore property sets) as stored in a memory 304. Wellbore property sets include wellbore properties which correspond to casing wear, such as, depth, a wellbore material, wellbore angle at a measurement point, fluid pressure in a wellbore, lubricant, and casing material. A memory 304 can be any type of electronic storage medium, for example, RAM, data file, data CD, hard disk drive, network storage, database, or any what other type of machine readable media. In Figure 3, memory 304 is shown
2Û17-IPM-10O992-U1-FR as an element of the well site control device 301. In other embodiments, the memory 304 can be partly located inside the well site control device 301 and partly located in another electronic system, or the memory 304 can be completely located in a separate electronic device, for example, a server or a database located remotely from the well site control device.
A processor 303 is configured to receive input data 313 from the communication interface 302. The processor 303 is programmed or configured to obtain a casing wear factor estimated as disclosed herein. Processor 303 can perform multiple iterations of an algorithm to refine the estimated casing wear factor until the error value reaches an appropriate range of values or tolerance, or until a defined number of times to execute the algorithm is reached. A processor 303 can also generate analysis information, for example, a graph, showing how a well system plan with its individual operations affects casing wear over an elapsed period of time.
A display device 305 is configured to provide a user interface with the well site control device 301. The display device 305 can provide the resulting casing wear factor and a determined well system plan analysis by processor 303 for viewing. A communication interface 302 receives the resulting data 323 from the processor 303 and transmits the resulting data 323 via a wired or wireless network 320 to, for example, but not limited to, (1) an electronic device 321, such as a laptop, mobile phone, PDA, tablet, well site equipment, or other device, or (2) to a manual processing device 322, for example, a display device or a printer, to be used, for example, by an engineer, operator, or well planner. The electronic device 321 or the manual processing device 322 can be located at or near a well site or can be located remote from the well site.
A well site control device 301 can further be considered to be any type of electronic device. For example, the communication interface 302, a processor 303, a memory 304, and a display device 305, as well as the software-based methods and algorithms accompanying them of the well site control device 301 can be integrated into a dedicated electronic circuit, for example, a ROM, a RAM ^, a DRAM ', or any other type of electronic circuit, which is then integrated into another device. For this type of implementation, certain components, for example, the display device 305 can be optional to the well site control device 301. As a variant, the well site control device 301 can be considered
2Û17-IPM-100992-U1-FR as a. a standalone device, for example, a laptop, PDA, mobile phone, tablet, desktop computer, or other computing device. Additionally, the well site controller 301 may be a part, or component, of a larger piece of well system equipment. As described above, Figure 3 is intended to illustrate how the method can be implemented within a well site control system 300 and is not intended to limit the type, format, or components of the well site control device 301.
Figure 4 illustrates a graph 400 of an example of a wellbore operation plan showing casing wear as a percentage over time. A graph 400 provides a plot of time with respect to wear as a visual representation of a tool for managing casing wear using the casing wear factor as disclosed here and the percentage of wear casing based on well operations and corresponding drill turns. As drilling operations progress, the driller and the engineer must keep in mind the speed at which they are approaching boundary conditions. Therefore, values of remaining time and remaining turns are estimated based on time ranges that the driller or engineer considers appropriate. The time ranges represent the assumption that in the event that the operating parameters in the future do not change significantly, the expected wear progression on the casing wall in the future could be accurately predicted by how wear has progressed in this specified time range.
Graph 400 can be used to estimate remaining time and remaining turns for any oil and gas well that can be applied both during the planning phase and during any drilling operation in real time . Based on the time and remaining turns, the drilling parameters can be adjusted to ensure that the design loads on the casing are not exceeded. This process is basically based on performing a "time versus wear" analysis for any well that is drilled. In this analysis, the progression of wear on the casing walls over time is calculated for each of the casing depths. In addition, the progression of wear with respect to the turns applied to the casing wall is also estimated. Graph 400 provides a plot for the progression of wear over time and turns.
Chart 401 includes a. x-axis 402 showing elapsed time, a primary y-axis 403 showing casing wear as a percentage, and a secondary y-axis 404 showing a revolution count of the drilling tool and the drill string. Graph 400 includes a legend that identifies actual drilling tool operations according to the operating plan of
2O17-IPM-10O992-U1-FR well system. The actual operations include a first operation step 405 and a second operation step 406. The legend also includes revolution accounts 407 and 408 respectively of the first operation step 405 and the second operation step 406. Graph 401 includes drawn lines 409, 410, 412, 413, which correspond to the operations identified in the legend, most suitable trend lines 411 and 414, and a warning or limit line 415 (designated below). as a boundary line).
The first and second stages of operation 405 and 406, can be one of several types of operations, i.e., drilling, back boring, rotation in elevation, sliding, reciprocating, and other types of operations performed by the drilling tool. In the example shown in Figure 401, two selected operations, the first operation step 405 and the second operation step 406, are executed in sequence as shown. Other drilling tool operations can also be included in Graph 401. A line can also be drawn for the first and second operation steps 405 and 406 showing the change in a percentage of casing wear 403 to measures that an elapsed time 402 changes during the execution of the corresponding operation.
Traced lines 409 and 410 can be generated by an algorithm based in part on the casing wear factor determined as previously described. Lines drawn for one or more additional operations can also be generated as part of an operation plan sequence. A most suitable trend line or trend line 411 can be determined to show how a change in elapsed time of execution of a selected operation would change the percentage of casing wear. The elapsed time can be increased or decreased.
The limit line 415 can be determined at any suitable value based, for example, on design parameters, historical data, and operating experience. Chart 401 shows a warning of approximately 41.0% casing wear percentage. A determination can be made using a graph 401 such that if a trend line 411 intersects a boundary line 415, then the well system engineer, operator, or planner can, if appropriate, alter or modify the well system plan. The objective may be, by way of example only, to limit casing wear, to limit the number of times that a measurement of actual remaining wall thickness of casing is taken, or any other of a number of different well site objectives.
Each selected operation step 405, and an additional selected operation step 406, if appropriate, may have an associated revolution count 407 and 408 where said revolution count is a linear count of the number of physical revolutions at which the tool
2Û17-IPM-10O992-U1-FR and a drill string are submitted during the execution of the selected operation. The slope of the lines drawn 412 and 413 is directly correlated to the revolutions per minute of the drilling tool and of a drill train, (as described above for 409 and 410, the lines drawn 412 and 413 can be modified by adjusting the elapsed time of the associated selected operation. A trend line 414 can be determined to show how casing wear would change with the change of an elapsed time for the selected operation. A trend line 414 can also be compared to a boundary line 415 and a plan of operation adjustment made if 414 and 415 were to cut.
FIG. 5 illustrates a process diagram of an exemplary method 500 of determining and using a casing wear factor value using well logging. The process begins in step 501 and the well system environment, properties, and factors are determined in step 502. Actual casing wall thickness values are measured at various locations and depths at inside a wellbore in step 503. The measured remaining wall thickness values are stored in a log. An estimated casing wear factor is determined in step 504. The estimated casing wear factor can be determined through, for example, controlled laboratory experiments, past experiences, and estimates. In a step 505, the actual remaining wall thickness of casing is compared to the remaining remaining wall thickness of casing based on a continuously refined casing wear factor. The method 500 continues towards a determination step. 506 where a decision is made whether the wear factor of the refined casing is acceptable. Acceptance can be based on a defined number of specified iterations or on the fact that an error value between the actual remaining wall thickness of casing and the estimated remaining wall thickness is within a range or tolerance level considered acceptable. If the casing wear factor is not acceptable, process 500 continues to step 504 and repeats. If acceptable, method 500 continues to step 507 where the refined / back-calculated casing wear factor, alone or combined with other data, can be used in future well operations and planning at the level of a well site with similar conditions, for example, the current well bore, or a different well bore in the same well site, or at a different well site. The method 500 then ends in a step 508.
Figure 6 illustrates a schematic diagram of an example of a method 600 for recalculating casing wear factors from a well. Method 600 uses an iterative approach and begins at step 601, Actual casing wall thickness measurements for an existing wellbore are taken in step 602. Actual remaining wall thickness values can be determined via conventional operation and stored
2Û17-IPM-10O992-U1-FR in a wear log for the wellbore. Then an estimated casing wear factor is determined in a step 603. The estimated casing wear factor can be an initial casing wear factor obtained from well logging, similar wellbore, d laboratory estimates, etc. The estimated casing wear factor can be based on actual usage conditions. An estimated casing wall thickness is determined using the casing wear factor estimated in step 604. The estimated remaining wall thickness is for a particular depth of the wellbore. A conventional simulation tool can be used to calculate the estimated remaining wall thickness using the estimated casing wear factor. In a step 605, the estimated remaining wall thickness is compared to the actual remaining wall thickness measurement of the casing of the particular depth. In a determination step 606, a decision is made whether the difference between the actual and estimated remaining wall thickness values is acceptable. An error value can be used to determine acceptance. For example, if the error value is within an acceptable range or a tolerance level, then the difference is considered acceptable and the method 600 continues to a step 607 where the casing wear factor refined, i.e., the back-calculated casing wear factor, alone or in combination with other data, can be used in future well operations and well planning. The method 600 then goes to a step 609 and ends. Returning to a determination step 606, if the difference is not acceptable, then the process continues to a step 608 where the casing wear factor is further refined and a new calculation is determined at 604.
FIG. 7 illustrates a process diagram of an exemplary implementation of a method 700 of back calculation of a casing wear factor through an iterative approach using multiple sub-ranges. The method 700 starts in a step 701. In a step 702, the actual remaining wall thickness values of casing over several depths are determined. Conventional methods can be used to obtain the remaining wall thickness values of the casing in a wellbore. In step 703, a range of CWF best corresponding to casing wear factors is determined. The most suitable CWF range can be derived from specific well site conditions, user experience, or other methods. The most suitable CWF range is divided into two sub-ranges in step 704 and a representative casing wear factor is selected from each of the sub-ranges in step 705. In other embodiments, the most suitable CWF range can be divided into more than two sub-ranges, if necessary or appropriate. An estimated remaining wall thickness is calculated in a step 706 for a particular casing depth using each of the representative casing wear factors. A conventional wall thickness simulation program
2Û1.7-IPM-10O992-U1-FR can be used. The resulting estimated remaining wall thickness values are then compared to the actual remaining wall thickness at the particular depth in a step 707. An error value can be developed based on the comparison. A best matching CWF range is selected in step 708 based on the comparison from step 707. The corresponding range with the casing wear factor corresponding to the lowest error value can be selected as the most suitable CWF range.
A decision is then made in a determination step 709 if the casing wear factor of the most suitable CWF range is acceptable. If not, method 700 continues to step 704 where the casing wear sub-range with the lowest error value is further divided into two smaller sub-ranges. The process continues iteratively, at determination step 709, until the casing wear factor is determined to be acceptable. This can either be the casing wear factor resulting in. an error value within the range or an acceptable tolerance level, a. defined number of iterations is complete, or some other factor stops the iterative process. At step 710, the determined casing wear factor, alone or in combination with other data, can be used in future use, planning, and operations of the current wellbore, another wellbore at level. well site, or another well site with similar conditions and properties. The process stops at step 711.
Figure 8 illustrates one. flow diagram of an example of a casing wear analysis method 800 using a casing wear factor, to determine an operating plan, of an updated well system. Method 800 corresponds to steps 507, 607, and 710 of the previous methods described here, in which the determined casing wear factors are used in well planning and operations. When drilling any oil and gas well, the driller and the engineer aim to obtain the target depth without significantly wearing down the casing wall so as to cause any casing failure conditions. In these situations, it is extremely helpful if the driller has an understanding of it. in real time how wear on the casing walls has progressed since the start of the drilling operation, and how much time it has before causing any major damage to the casing walls. A deep understanding of the time remaining as well as the remaining turns will help him plan and adjust operations more precisely in real time in order to stay within pre-defined constraints and avoid any security incidents. The method 800 can help with this understanding and begins in a step 805,
2O1.7-IPM-10O992-U1-EN
In step 810, an initial well system operating plan is determined. The plan may include an enumerated, sequenced list of well system operations and an elapsed time to complete each of the operations. The initial development of the plan also includes an estimate of the remaining wall thickness of casing, or casing wear, for each operation. The plan may also specify at which elapsed time points an actual remaining wall thickness measurement of casing should be taken as well as other operational steps, for example, but not limited to, elapsed time points estimated where casing repair or replacement operations may need to take place.
In step 820, one of the operations is selected for further review. In step 830, a representation of casing wear for the selected operation is generated using a casing wear factor, such as the casing wear factor determined from 507, 607, or 710. The representation can be generated via a conventional simulation or an algorithm employing a back-capped tubing wear factor as disclosed here. This is demonstrated, for example, as a line 409 or 410 in a graph 400, In a step 840, a most suitable trend line or curve, for example 411 or 414, is drawn on the graph. This most suitable trend will provide information regarding the change in casing wear if a decision had to be made for a change in the elapsed time the operation selected in step 820 would continue to be executed. The elapsed time can be increased or decreased in length. In a step 850, based on the operation selected at 802, a tachometer for the drilling tool and a. train, drilling is determined and a similar trend line is estimated so that the revolution count corresponds to the change in elapsed time of the correlated operation selected in step 820,
In step 860, the trend lines determined from steps 840 and 850 are analyzed to provide an updated estimate of casing wear occurring during the execution of the selected operation. In a determination step 870, the updated casing wear value, demonstrated in a graph 400 as a percentage of remaining casing material, is compared with one or more previously determined boundary lines, demonstrated as a boundary line 415. The boundary line may indicate that a measurement of the actual remaining wall thickness of casing should be made, one. critical threshold has been reached on the remaining wall thickness of casing, or another factor should be considered. If a boundary line were to be cut, then in step 885, the well system plan would be revised to eliminate Γ intersection. After the plan has been revised in a step 885, the method 800 returns to a step 810 to re-evaluate the revised plan.
2Û17-IPM-10O992-U1-EN
If the comparison in a determination step 870 results in the fact that the curve or a trend line does not cross a specified limit line, then the well system plan could be executed in a step 887. The method 800 then ends in step 890. Method 800 can be repeated after the next actual casing wall thickness measurement has been performed to provide updated information to well system engineers, operators, and planners.
The disclosure provides an automated method for estimating a casing wear factor based on wear logs which provides the best match rather than a visual judgment previously used for such analysis. A metric can be assigned for any wear factor value considered to be the best match. In addition, a more granular casing wear analysis is disclosed which is carried out section by section of the casing which can be used for an estimation of remaining time and remaining turns before a wear limit on any section of tubing is reached. Therefore, in contrast to a conventional casing wear analysis, the disclosure advantageously provides calculations of remaining time and remaining turns as part of an advanced casing wear analysis. Estimates of remaining time and remaining turns can be used to better plan drilling operations by mitigating wear and will help improve casing designs. Such real-time operation estimates also allow dynamic adjustment of drilling parameters (adjustments during drilling) so that actual wear on casing walls is maintained within the designed wear limits.
In interpreting the disclosure, all terms should be interpreted as broadly as possible in accordance with the context. In particular, the terms "comprises" and "comprising" should be interpreted as designating elements, components, or steps in a non-exclusive manner, indicating that the elements, components, or designated steps may be present, or used, or combined with other elements, components, or steps which are not explicitly mentioned.
The apparatuses, systems, or methods described above or at least a portion thereof can be implemented or realized by various processors, such as processors or digital data computers, in which the processors are programmed or store programs or executable sequences of software instructions for performing one or more of the process steps or the functions of the devices or systems. The software instructions of such programs can represent algorithms and be encoded in machine-executable form on non-transient digital data storage media, e.g. magnetic or optical disks, random access memory (RAM), of the
2Q17-IPM-10O992-U1-FR magnetic hard drives, flash memories, and / or read only memory (ROM), to allow various types of processors or computers of digital data to execute one, several or the set of steps of one or more of the methods or functions described above of the system described here.
Certain embodiments disclosed here may further relate to computer storage products with non-transient computer readable media which have program code thereon for performing various computer implemented operations which include at least some of the devices , systems, or perform or direct at least some of the process steps mentioned herein. A non-transient medium used here designates all of the computer-readable media with the exception of transients, which propagate signals. Examples of non-transient computer readable media include, but are not limited to: magnetic media such as hard disks, floppy disks, and magnetic tape cassettes; optical media such as CD-ROM discs; magneto-optical media such as flexible optical discs; and computer devices that are specifically configured to store and execute program code, such as ROM and RAM devices. Examples of program code include both machine code, as produced by a compilation program, and files containing higher level code that can be executed by the computer using an interpreter program.
Those skilled in the art concerned with this application will understand that other and additional additions, deletions, substitutions and modifications may be made to the embodiments described. It should also be understood that the terminology used here is only for the purposes of a description of particular embodiments, and is not intended to represent a limit, since the scope of this disclosure will be limited only by the revendications.
Unless defined otherwise, all the technical and scientific terms used here have the same meaning as that commonly understood by the skilled person concerned by this disclosure. Although any similar process or material or equivalent to those described here can also be used in the practice or testing of this disclosure, a limited number of examples of processes and materials are described here.
It should be noted that as used here and in the appended claims, the singular forms "one", "one", and "the" include referents in the plural unless the context clearly indicates otherwise.
The embodiments disclosed in this document include:
2Û17-IPM-10O992-U1-EN
A. A method for determining casing wear of casing in a wellbore, comprising obtaining actual remaining wall thickness (RWT) values of a wellbore casing which corresponds to an assembly of casing depth values from a wellbore, a calculation of estimated RWT values for the set of casing depth values based on at least one estimated casing wear factor (CWF) ; and determining a back-calculated CWF value for the wellbore based on a comparison between the actual RWT values and the estimated RWT values, wherein the calculation and determination are performed by a processor.
B. Well site control device, comprising an interface configured to receive actual remaining wall thickness (RWT) values that correspond to a set of casing depth values from a wellbore and a processor configured to determine a back-calculated casing factor (CWF) value for the wellbore based on a comparison between the actual RWT value and an estimated RWT value, for the set of casing depth values, where the estimated RWT value is calculated using an estimated CWF value as input.
C. Computer program product including a series of operating instructions stored on a non-transient computer readable medium which directs a processor to perform a method of tubing wear analysis, wherein the method includes determining a '' a casing wear factor (CWF) value back-calculated for one. casing in a wellbore based on a comparison between actual remaining wall thickness (RWT) values of the casing and estimated RWT values of the casing and a determination, using the back-calculated CWF value, an amount of time to complete a first well system operation in the wellbore before a casing condition occurs.
Each of embodiments A, B, and C can have one or more of the following additional elements combined:
Element 1: wherein the calculation includes a calculation of multiple estimated RWT values for the set of casing depth values using a different estimated CWF value for each of the multiple estimated RWT values. Element 2: wherein the determination includes a comparison of the actual RWT values to the estimated RWT values, a check of a CWF range best matched from one of the estimated CWF values based on the comparison, and a selection of the CWF value estimated from the CWF range that best matches the back-calculated CWF value. Element 3: in which the calculation and the determination are carried out iteratively. Element 4: where the multiple estimated RWT values are two and the different values of
2017-IPM-100992-U1-EN
CWF estimates are determined based on a minimum and maximum value for a CWF. Element 5: in which the calculation and the determination are carried out a defined number of times. Element 6: where the most suitable CWF range is one of the multiple CWF ranges with the highest correlation to actual RWT values.
Element 7; further comprising a casing wear analysis of the casing using the back-calculated CWF. Element 8: wherein the casing wear analysis includes an estimate of an amount of time to complete a well system operation before a casing condition occurs. Element 9: in which the casing wear analysis includes an estimate of a remaining number of turns of a drill string when performing a well system operation before a condition of occurrence occurs tubing. Element 10: further comprising a memory module configured to store a well wear field borehole log that includes the actual RWT values. Element 11: further comprising a memory module configured to store a set of estimated CWF values correlated by one. set of wellbore properties, where the processor selects a value
1.5 of initial CWF among it. Element 12: wherein, the back-calculated CWF value is used to determine at least one of an elapsed time to execute a selected operation, a number of revolutions for a selected operation, a drilling rotation speed, a pressure wellbore fluid, a recommended time interval before an actual RWT measurement, tubing material, and tubing thickness. Element 13: in which the determination of the back-calculated CWF includes a. calculation, multiple RWT values for the set of casing depth values using a different estimated CWF value for each of the multiple RWT values. Element 14: in which the determination of the back-calculated CWF includes a comparison of the actual RWT values with the multiple RWT values, a verification of a range of CWF corresponding best from one of the multiple values of R.WT on the basis of the comparison, and a selection of a new CWF value from the range of CWF that best matches as the back-calculated CWF value. Element 15: in which the determination of the back-calculated CWF is carried out iteratively. Element 16: in which the determination of the back-calculated CWF is carried out a defined number of times. Element 17: where the CWF range best matched is .30 one of the multiple CWF ranges with the highest correlation to actual RWT values. Element 18: in which the selected operation is one of a drill, a reverse bore, a rotation, in. heightening, sliding and reciprocating. Element 1.9: further comprising an estimate of a number of remaining turns of a drill when performing a second well system operation before a second casing condition occurs. Element 20: in which the first and second system operations
2Û17-IPM-10O992-U1-FR wells are the same well system operation and the first and second casing conditions are the same casing condition. Element 21: in which the well system operation is one of a drilling, a reverse bore, a raised rotation, a slip and a reciprocating motion. Element 22: wherein determining the calculated retro CWF5 value includes obtaining actual RWT values for wellbore casing that correspond to a set of wellbore casing depth values, calculating values for RWT estimated for the set of casing depth values based on at least one estimated CWF value, and a determination of a back-calculated CWF value for the wellbore based on a comparison between actual RWT values and estimated RWT values.
2O1.7-IPM-10O992-U1-EN

权利要求:
Claims (14)
[1]
THE _{FOLLOWING PORT1NT SÜR C1} CLAIMS:
1. Method for determining, casing wear of a casing in a wellbore, comprising:
obtaining actual remaining wall thickness (RWT) values from a well casing that corresponds to one. set of casing depth values of said wellbore;
calculating estimated RWT values for said set of casing depth values based on at least one estimated casing wear factor (CWF); and determining a back-calculated CWF value for said wellbore based on a comparison between said actual RWT values and said estimated RWT values, wherein said calculation and said determination are performed by a processor .
[2]
2. The method of claim 1, wherein said calculation includes a. calculating multiple estimated RWT values for said set of casing depth values employing a different estimated CWF value for each of said multiple estimated RWT values, and optionally wherein said multiple estimated RWT values are two or said values of Different estimated CWFs are determined based on a minimum and maximum value for a CWF.
[3]
The method of claim 2 wherein said determination includes comparing said actual RWT values to said estimated RWT values, verifying a range of CWF best matching from one of said estimated CWF values based on said comparison, and a selection of said estimated CWF value from said CWF range best matching as said back-calculated CWF value.
[4]
The method of claim 3, wherein said best matching CWF range is one of multiple CWF ranges having the strongest correlation with said actual RWT values.
2Û17-IPM-10O992-U1-EN
[5]
5. Method according to claim. 1, 2, 3, or 4, wherein said calculation and said determination are performed iteratively, and, optionally, wherein said calculation and said determination are performed a defined number of times.
[6]
The method of claim 1, 2, 3, or 4, further comprising performing a casing wear analysis of said casing using said back-calculated CWF value, and, optionally, wherein said wear analysis of casing includes an estimate of an amount of time to complete a well system operation before a casing condition occurs, or wherein said casing wear analysis includes an estimate of a remaining number of turns of a drill string when performing a well system operation before a casing condition occurs.
[7]
7. Well site control device, comprising:
an interface configured to receive actual remaining wall thickness (RWT) values that correspond to a set of casing depth values from a wellbore; and a processor configured to determine a back-calculated casing factor (CWF) value for said wellbore based on a comparison between said actual RWT value and an estimated RWT value, for said a set of casing depth values, where said estimated RWT value is calculated using an estimated CWF value as an input.
[8]
The well site control device of claim 7 further comprising a memory module configured to store a field wear log of said well bore which includes said actual RWT values and configured to store a set of values of CWFs estimated correlated by a set of wellbore properties, where said processor selects an initial CWF value from it.
[9]
The well site controller according to claim 7 wherein said processor is further configured to use said back-calculated CWF value to determine at least one. a time elapsed to perform a selected operation, a number of revolutions for a selected operation, a drilling rotation speed, a wellbore fluid pressure, a recommended time interval before a measure of actual RWT, casing material, and casing thickness.
2Û1.7-IPM-10O992-U1-EN
[10]
10. A well site control device according to claim 9 wherein said selected operation is one of a drilling, a reverse bore, a raised rotation, a slip, and a reciprocating movement.
[11]
11. Well site control device according to, la. claim 7, 8, or 10, wherein said processor is configured to determine said back-calculated CWF value by calculating multiple RWT values for said set of casing depth values using a different estimated CWF value for each of said multiple RWT values, and, optionally, wherein said processor is configured to determine said back-calculated CWF value by comparing said actual RWT values with said multiple RWT values, verifying a CWF range best corresponding to from one of said multiple RWT values based on said comparison, and selection of a new CWF value from said CWF range best matching as said back-calculated CWF value, and wherein said range of best matching CWF is one of multiple CWF ranges with the highest correlation to said values s of actual RWTs.
[12]
The well site control device according to claim 7 or 8, wherein said processor is configured to iteratively determine said back-calculated CWF value and said processor is configured to determine said back-calculated CWF value a defined number of time.
1.3. Computer program product including a series of operating instructions stored on a non-transient computer readable medium which directs a processor to carry out a casing wear analysis method, in which said method comprises:
a determination of a back-calculated casing factor (CWF) value for casing in a wellbore based on a comparison between actual remaining wall thickness (RWT) values of said casing and values estimated RWTs of said casing; and determining, using said back-calculated CWF value, an amount of time to perform a first well system operation in said wellbore before a first casing condition occurs.
2017-IPM-100992-U1-EN
[13]
14. A computer program product according to claim 13 further comprising an estimate of a remaining number of turns of a drill when performing a second well system operation before a second casing condition occurs. , wherein said first well system operation is one of a drilling, a reverse bore, a raised rotation, a slip, and reciprocating, and, optionally, wherein said first and second well system operations are the same well system operation and said first and second casing conditions are the same casing condition.
15. A computer program product according to claim 13 or 14, wherein a determination of said back-calculated CWF value includes:
obtaining actual RWT values for said well casing which correspond to a set of casing depth values for said well bore;
[14]
A calculation of estimated RWT values for said set of casing depth values based on at least one estimated CWF value; and determining a back-calculated CWF value for said wellbore based on a comparison between said actual RWT values and said estimated RWT values.

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同族专利:

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公开号 | 公开日

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GB2575594B|2022-02-02|

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NO20191359A1|2019-11-15|

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GB201915603D0|2019-12-11|

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US11199083B2|2021-12-14|

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WO2018231248A1|2018-12-20|

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US20200141225A1|2020-05-07|

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GB2575594A|2020-01-15|

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法律状态:
2019-05-23| PLFP| Fee payment|Year of fee payment: 2 |

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2020-03-13| PLSC| Publication of the preliminary search report|Effective date: 20200313 |

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2021-04-30| RX| Complete rejection|Effective date: 20210325 |

优先权:

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申请号 | 申请日 | 专利标题

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PCT/US2017/037886|WO2018231248A1|2017-06-16|2017-06-16|Method and apparatus to predict casing wear for well systems|

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IBWOUS2017037886|2017-06-16|

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