• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
  • 引用文献
  • 法律状态
  • 优先权
    • 专利摘要:
    The estimation of casing wear (114; 238) for individual sections or lengths of the drill string may take into account the fact that individual sections of the drill string (110; 208) cause different degrees of wear. tubing (114; 238) depending on the physical and material properties of each section of the drill string (110; 208). In some cases, a method performed during a drilling operation may involve tracking a location of the plurality of drill string sections (116a-c) along the wellbore (112); matching a section of casing (114; 238) with the wear factors of the drill string (110; 208) of the drill string sections (116a-c) radially near the casing section (114; 238) drilling intervals for drilling operations; and calculating casing wear (114; 238) during drilling based on the wear factors of the drill string (110; 208) corresponding to the casing section (114; 238).
    公开号:FR3037352A1
    申请号:FR1654235
    申请日:2016-05-12
    公开日:2016-12-16
    发明作者:Last Name Aniket No；Adolfo Gonzales；Robello Samuel
    申请人:Landmark Graphics Corp；
    IPC主号:
    专利说明:

    [0001] ESTIMATING TUBING WEAR DURING DRILLING USING MULTIPLE WEAR FACTORS ALONG HISTORIC ROD LINE [0001] Embodiments described herein relate to estimating casing wear in the oil and gas industry. Wells in the gas and oil industry are generally drilled in stages. Once a step is completed, the drill string is often lined with casing to provide stability to the wellbore wall to mitigate subsidence and explosions as other stages are drilled. Because of this step drilling and this casing process, the subsequent steps that are remote from the surface generally have a smaller well diameter. When drilling below the cased portions of the wellbore, the casing may wear due to contact with the casing string. This wear causes a decrease in the thickness of the casing, which, in turn, weakened the casing. In order to avoid slump or explosion of the casing, it is advantageous to know the degree of wear that has occurred so that corrective actions can be made when the thickness of the casing is sufficiently reduced. For these reasons, it is important to be able to determine the thickness of the casing at any given point. The thickness of the casing can be determined by spectroscopy, for example, by gamma ray tools. Such tools may be used after drilling the wellbore through a cable work operation to evaluate the thickness of the tubing. However, this gives only a final evaluation of the casing and does not allow an analysis of the thickness or integrity of the casing during the drilling operation itself. In order to study the thickness of the casing during drilling, such analysis tools may be placed along the drill string. However, the analysis tools can only evaluate the casing that is a few meters away along the borehole relative to the current location of the analysis tool. Therefore, this does not allow accurate evaluation of the casing along the entire length of the wellbore.
    [0002] BRIEF DESCRIPTION OF THE DRAWINGS [0006] The following figures are presented to illustrate certain aspects of the embodiments, and should not be considered as exclusive embodiments. The subject matter of the invention described may be subject to considerable modifications, alterations, combinations and equivalents in form and function, as will be apparent to those skilled in the art who benefit from this description. [0007] Figure 1 illustrates a diagram of a portion of the drill string in a wellbore lined with a casing. FIG. 2 shows an illustrative histogram showing drill string wear factors (DSWF) experienced by an individual casing section after drilling a plurality of drill gaps. [0009] Figure 3 illustrates an example of a wellbore drilling module suitable for implementing the analyzes described herein, in one or more embodiments. DETAILED DESCRIPTION [0010] Embodiments described herein relate to estimating casing wear for individual casing portions or lengths. In addition, the described embodiments take into account that individual sections of the drill string may cause different degrees of casing wear depending on the physical and material properties of each section of the drill string. A drill string may comprise one or more of the following components: drill pipes, transition pipes (also called "heavy drilling pipes"), downhole modules (which may comprise, e.g. , drill collars, drill stabilizers, downhole motors, steerable rotary systems, measuring tools during drilling and logging tools during drilling), drill pipe protectors (which have less wear compared to the drill pipe), etc., each of which can cause casing wear as the drill string rotates within and / or axially along the wellbore. In order to perform the analyzes described herein, the drilling operations are divided (analytically, not physically) into depth intervals (hereinafter referred to as "drilling intervals"), and the casing which covers portions of the boreholes. a wellbore is divided (analytically, not physically) into sections of a given length (referred to herein as "casing section"). For example, drill intervals may be 5 (1.52 m) feet intervals, 20 feet (6.09 m) intervals, 100 feet (30.48 m) intervals, etc. The casing sections may be the same length or not as the drilling intervals. FIG. 1 illustrates a diagram of a portion of the drill string 110 in a wellbore 112 lined with casing 114. The embodiments described herein monitor the location of the individual sections of the drill string 116a. in relation to the casing sections 118a-h. Each drill string section 116a-c is assigned a drill string wear factor (DSWF) based on its physical and material properties. Table 1 provides an illustrative list of DSWF corresponding to the individual sections of the drill string 116a-c. Even though Table 1 contains a sectional-based DSWF / stem section section correspondence 116a-c, the correspondence may be based on any measurement that can be used to identify sections or lengths of the drill string (for example, eg, a distance from the drill bit). Table 1 Section of drill string Wear factor Distance to drill bit 116a 25 4125 feet (1257, 3 m) to 5100 feet (1554, 5 m) 116b 40 3850 feet (1173, 5 m) to 4125 feet (1257, 3 m) 116c 120 2100 feet (640, 08 m) to 3850 feet (1173, 5 m) [0014] In alternative embodiments, a default DSWF may be used and the sections of the drill string Having a different DSWF DSWF 3037352 4 can be identified and mapped to their respective DSWFs. For example, Table 2 provides an example of a description of a stem train by its DSWF. The default DSWF may be the DSWF for the drill pipe that makes up the majority of the drill string. Additional components of the drill string (e.g., transition rods and downhole modules) can each have a DSWF and a distance to the drill bit based on the location of the components along the train. of stems.
    [0003] Table 2 Wear Factor Distance from drill bit 2 by default (use unless otherwise indicated) 25 400 feet (121, 9, m) at 800 feet (243, 8 m) 40 2100 feet ( 640, 08 m) at 2400 feet (731, 5 m) 120 3255 feet (992, 12 m) to 4125 feet (1257, 3 m) 20 5100 feet (1554, 5 m) to 5250 feet (1600, 2 m) [0015] Referring again to FIG. 1, the location of each section of the drill string 116a-c is monitored during each drilling interval 120. For each drill interval 120, individual casing sections 118a-h are correlated to the DSWFs at the corresponding section. of the drill string 116a-c. For example, as shown in FIG. 1, the two upper casing sections 118a-b would be correlated to the DSWF of the upper section of the drill string 116a; the next four sections of casing 118c-f would be correlated to the DSWF of the middle section of the drill string 116b and the lower sections of the casing 118g-h would be correlated with the DSWF of the lower section of the drill string 116c. Then, when the next drilling interval 3037352 120 is drilled, the correlation of the casing sections 118a-h with the DSWF of the shank sections 116a-c is redone again. [0016] The casing wear for each casing section 118g-h can then be analyzed (qualitatively or quantitatively) as a function of the plurality of DSWF correlated thereto. For example, the plurality of DSWFs may be applied for estimating casing wear along a given casing section for each drilling interval. The estimation of the casing wear can be performed by a plurality of methods. For example, in some cases the DSWFs experienced by each section of casing may be graphically represented, eg, with a histogram or a pie chart. Figure 2 shows an illustrative histogram that can be presented to represent the DSWFs experienced by an individual section of casing after drilling a plurality of drill intervals with a drill string configured according to Table 2. In the illustrated graph, the The casing section has undergone parts of the drill string with a wear factor 2 times, a wear factor of 19 times, a wear factor 40 of 28 times, a wear factor 120 of 15 times and a wear factor of 3 times. The histogram of FIG. 2, or related graphical representations of the casing wear factors experienced by individual casing sections, can be used to estimate casing bore wear for each of the sections of the casing. For example, casing wear can be calculated when each DSWF and the number of times each DSWF has been subjected can be used in known methods and / or algorithms for applying a wear factor of tubing to provide casing wear from drilling (also referred to as "casing wear during drilling"). The use of tubing during drilling can be reported as a volume of spent casing (also called "casing wear volume"), a casing wear percentage (also referred to herein as "percentage of casing wear"). casing "), a remaining casing thickness, a remaining percentage of tubing, or a combination thereof. In another example, the casing wear during drilling for an individual casing section can be calculated by first calculating the casing wear for the individual casing section at each drilling interval (according to known methods and / or algorithms) and then adding the casing wear from each drilling interval measured during the drilling operation. Casing wear during drilling may be reported as a casing wear volume, a casing wear percentage, a remaining casing thickness, a remaining casing percentage, or a combination of these. [0019] In yet another example of estimating casing wear, an average casing wear factor (CWF'g) can be calculated for a casing section according to the following Equation 1 which weights the CWFavg based on the number of times each DSWF is associated with a given casing section, where n is the number of DSWFs and NDswF is the number of times that 10 DSWF, is correlated with the given casing section. _iDSWFi * NDSWF, i CW F avg Equation 1 [0020] The CWFavg may possibly be used to estimate casing wear during drilling, where CWF ', is used as the factor of casing wear in processes and processes. / or known algorithms for calculating casing wear during drilling. The casing wear during drilling may be reported as a casing wear volume, a casing wear percentage, a remaining casing thickness, a remaining casing percentage, or a combination of these. The casing wear during the estimated drilling with graphical representations, CWFavg, or both can be used as entering a casing wear pattern which estimates a total casing wear caused by a plurality of type of casing. wear, which may also include, eg, casing wear during reciprocating (i.e., casing wear caused by reciprocating the drill string when it is being used to smooth parts of a newly drilled wellbore), casing casing wear (ie, casing wear caused by the drill string as it is pulled out of the borehole, what happens often to replace or repair a drill string, drill string parts or tools coupled to the drill string), boring casing wear (ie, casing wear caused by drill string when strike or swivel it while simultaneously pulling on the n of rods for -iNDSWF, pull it out of the hole, which is usually done during the initial stages of drilling a drill string from a deviated wellbore or when increasing borehole width), casing wear by rotation on the bottom (i.e., casing wear caused by the drill string when it is pivoted without reciprocating, casing wear without drilling (e.g. . in offshore drilling sites, the movement of the sea can cause platform movement and therefore axial movement of the drill string along the wellbore), sliding casing wear (eg . casing wear caused by the drill string when it is not rotated but the drill bit that is coupled to the drill string is rotated with a slurry motor), etc. These casing wear patterns may, in some cases, be a summary of the plurality of types of wear. [0022] The total casing wear can be expressed as a casing wear volume, a casing wear percentage, a casing remaining thickness, a remaining casing percentage. , or a combination of these. The wear of the casing during drilling and / or the wear of the total casing can be used to determine when there is sufficient casing wear to compromise the integrity of the casing section. This can be done by one of several methods. For example, casing sections may have a threshold value of casing wear during drilling and / or a threshold value of total casing wear that is based on the physical and material properties of casing sections. In another example, casing wear during drilling and / or total casing wear can be used to estimate a thickness of casing sections to be used in the well to prevent breakage based on Known calculations taking into account the physical and material properties of the casing sections. The analyzes described herein may, in some embodiments, be used during a drilling operation. For example, when drilling a wellbore penetrating an underground formation, the location of the drill string sections, and their corresponding DSWF, can be monitored and correlated to sections of casing at each drilling interval. . The total casing wear can be calculated and analyzed continuously during drilling, after a predetermined number of drilling intervals, upon request, and any combination thereof. When the casing wear of one or more casing sections indicates that the integrity of one or more casing sections may be compromised, corrective action may be taken. For example, one or more of the casing sections may be reinforced by liners, screens, etc. In another example, the parameters of the drilling operation may be adjusted to maintain total casing wear below values of a total casing wear threshold, which mitigates casing failure. In yet another example, the drill string components may be modified to change the DSWF to help reduce casing wear, including the use of drill string protector to reduce wear of the drill pipe. tubing. In some cases, an alarm signal may be sent (eg, to an operator) when the total casing wear approaches, reaches or exceeds the threshold value. [0026] FIG. 3 illustrates an example of a wellbore drilling module 200 suitable for implementing the analyzes described herein, according to one or more embodiments. It should be noted that even though FIG. 3 generally illustrates a terrestrial drilling module, it will be readily apparent to those skilled in the art that the principles described herein are equally applicable to offshore drilling operations that use floating platforms or installations or on the seabed, without deviate from the scope of this disclosure. As illustrated, the drilling module 200 may comprise a drilling platform 202 which supports a derrick 204 having a movable muffle 206 for lifting and lowering the drill string 208. The rod train 208 may include, without limitation, a drill pipe and spiral casing, as is generally known to those skilled in the art. A kelly 210 supports the drill string 208 as it is lowered through a turntable 212. A drill bit 214 is attached to the distal end of the drill string 208 and is powered by either a motor at the bottom of the well. and / or by rotating the drill string 208 from the well surface. When the drill bit 214 rotates, it digs a borehole 216 which penetrates various subterranean formations 218. As illustrated, the wellbore 216 is partially doubled by the casing 238. The wear of the casing 238 or sections of the borehole this can be evaluated by the analyzes and methods described herein. A pump 220 (e.g., a slurry pump) circulates drilling fluid 222 through a feed pipe 224 and to the kelly 210 which carries the drilling fluid 222 to the bottom of the well. Through the interior of the drill string 208 and through one or more orifices in the drill bit 214. The drilling fluid 222 is then again circulated to the surface through the ring 226 defined between the drill string 208. and the walls of the borehole 216. At the surface, the recirculated or spent drilling fluid 222 exits the ring 226 and can be conveyed to one or more of the fluid treatment units 228 through a flow line. 230. After passing through the fluid processing unit (s) 228, a "clean" drilling fluid 222 is deposited in a near retention pond 232 (i.e., a sludge basin). Although illustrated as being placed at the exit of the wellbore 216 through the ring 226, one skilled in the art will readily understand that the fluid treatment unit (s) 228 can be placed at the level of the wellbore 216. any location in the drilling module 200 to facilitate its proper operation, without departing from the scope of the disclosure. [0029] Additives may be added to the drilling fluid 222 through a mixing hopper 234 which is communicatively coupled to or otherwise in fluid communication with the retention pond 232. The mixing hopper 234 may include, without limitation, blenders and related blending equipment which are known to those skilled in the art. In other embodiments, however, the additives may be added to the drilling fluid 222 at any location in the drilling module 200. In at least one embodiment, e.g., there may be multiple basins. 232, for example, multiple retention basins 232 in series. In addition, the retention pond 232 may be representative of one or more structures and / or fluid storage units in which additives may be stored, reconditioned and / or regulated until added to the fluid. The drilling module 200 may also include a control system 236 which may, inter alia, perform the analyzes described herein. The analyzes described herein may, in some embodiments, be used in the design of a drilling operation. For example, when a drilling operation is simulated (eg, using mathematical models stored or run on a control system), the casing wear factor and / or wear total casing for casing sections can be analyzed. If, during the simulation, the casing wear factors and / or the total casing wear indicates that the integrity of one or more casing sections may be compromised, the design of the casing operation may be compromised. drilling can be modified. In some cases, sections or components of the drill string having higher DSWF may be replaced by sections of the drill string having a lower DSWF to mitigate casing wear.
    [0004] As a non-limiting example, a histogram or other graphical representation of the DSWFs experienced by an individual casing section after drilling a plurality of drill intervals with a drill string (e.g., the flowchart illustrated in FIG. 2) can also be used to illustrate that casing wear during drilling due to specific components, which may or may not have the highest wear factor, occurs more often (eg wear factor 40 occurs more often than a wear factor 120 in FIG 2). Therefore, components having a wear factor that is most affected by the wear section can be changed or protected with a drill string protector, which in some cases can reduce the wear factor to Less than 1. [0033] In another example, the casing or portions thereof may be replaced by tubing that can withstand greater wear. [0034] In yet another example, the parameters of the drilling operation may be adjusted to maintain the total casing wear below the values of a total casing wear threshold, which mitigates the failure of the casing. tubing. In some cases, an alarm signal may be sent (eg, to an operator who designs the drilling operation), when the total wear of the casing approaches (e.g. found at 10 ° AD of the threshold value), reaches or exceeds the threshold value. A combination of the above examples to mitigate the wear of the casing during drilling and the total wear of the casing can also be implemented. The control system (s) 236 (eg, used at a drilling site or during the simulation of a drilling operation) and the corresponding computer hardware used to implement the various blocks, Illustrative modules, elements, components, methods, and algorithms described herein may include a processor configured to execute one or more instruction sequences, programming sequences, or code stored on a computer-readable non-transitory medium. The processor may, for example, be a versatile processor, a microcontroller, a digital signal processor, an application specific integrated circuit, a programmable gate array, a programmable logic device, a control, state, a logic gate, individual hardware components, an artificial neural network, or any similar computing entity that can perform calculations or other data manipulations. In some embodiments, a computer hardware may include such elements as, eg, a memory (eg, RAM, flash memory, ROM, PROM, EPROM, , hard disks, removable disks, CD-ROMs, DVDs, or any other similar suitable storage device or medium The executable sequences described herein may be implemented with one or more code sequences contained in a memory. In some embodiments, such a code may be read into a memory from another computer readable medium.The execution of the instruction sequences contained in the memory may cause the processor to perform the process steps described herein. One or more of the processors in a set of multiprocessors may be used to execute the instruction sequences in the memory. Arduous can be used in place of or in association with software instructions to implement various embodiments described herein. Therefore, the embodiments of the present invention are not limited to any specific combination of software and / or hardware. As used herein, a computer readable medium describes any medium that directly or indirectly transmits instructions to a processor for execution. A computer readable medium may take any form including, for example, a non-volatile medium, a volatile medium, and a transmission medium. A non-volatile medium may include, for example, optical and magnetic disks. The volatile medium may include, for example, a dynamic memory. The transmission media may include, for example, coaxial cables, wires, optical fiber, and wires that form a bus. Common forms of computer readable media may include, for example, floppy disks, flexible disks, hard disks, magnetic tapes, other than magnetic media, CD-ROMs, DVDs, and other media. such optics, punch cards, paper tapes and physical media of this type with holes, RAM, ROM, PROM, EPROM and flash EPROM. For example, the control system (s) 236 described herein may be configured to receive inputs, which may be actual or simulated data, which could include, without limitation, the configuration of a drill string ( eg, the length and / or composition of each drill string section, the order thereof, etc.), the DSWF corresponding to each drill string, the casing configuration (e.g., casing depth and diameter), analysis parameters (eg length assigned to casing sections), drill bit depth (eg, which can be used to track the location of each section of the drill string with respect to the casing sections), etc. The processor may be configured to correlate a DSWF to each casing section for each drilling interval as described herein and to produce a casing wear-related result (eg, casing wear in the casing). drilling and / or total casing wear) for each section. The result may be a numerical value that is indicative of casing wear (eg, casing wear due to drilling and / or total casing wear), pictorial representation of casing wear ( eg, a graph or figure with a color code that correlates casing wear due to drilling and / or total casing wear to depth), etc. These casing wear results may relate to individual casing sections, a plurality of casing sections or all casing sections in the casing. When the total casing wear represents at least a part of the result, a casing wear pattern described herein may be used and the processor may receive inputs relating to other casing wear mechanisms, such as eg borehole casing wear, casing wear through. Reciprocating, casing wear by triggering, casing wear by spinning on the bottom, sliding casing wear, etc. In some cases, the processor may also be configured to send an alarm signal (e.g., to an operator or other processor at the drilling site, at a site remote from the site of operation). drilling or drilling simulation) to the effect that casing wear during drilling and / or total casing wear indicates that the integrity of one or more casing sections may be compromised . Embodiments disclosed herein include: Embodiment A: A method which comprises drilling a wellbore penetrating a subterranean formation with a drill bit coupled to an end of the drill string extending into the borehole. wellbore, wherein a portion of the wellbore is lined with casing and the drill string which includes a plurality of drill string sections each having a drill string wear factor; tracking a location of the plurality of drill string sections along the wellbore; analyzing the progress of the drill bit in a plurality of drill intervals, each casing section having a length; analytically dividing the casing into a plurality of sections, each casing section having a length; Corresponding to at least some of the plurality of casing sections with the wear factor of the section of the drill string near each of the plurality of casing sections for at least some of the plurality of drill intervals; and calculating casing wear during drilling for at least one of the plurality of casing sections as a function of the drill string wear factors corresponding to the at least one of the plurality of casing sections. casing; Embodiment B: A method which includes simulating a drilling operation with a mathematical model of drilling a wellbore penetrating a subterranean formation with a drill bit coupled to one end of a drill string extending into the wellbore, wherein a portion of the wellbore is lined with casing and the drill string including a plurality of drill string sections each having a drill string wear factor, the model mathematical being stored on a processor-readable non-transitory medium for execution by the processor; tracking one of the plurality of drill string sections along the 14 wellbore; analyzing the progress of the drill bit in a plurality of drilling intervals, each drilling interval having a length; the analytical division of the casing into a plurality of casing sections, each casing section having a length corresponding to at least some of the plurality of casing sections with the drill factor of the drill string section of the drill string section radially near each of the plurality of casing sections for at least some of the plurality of drill intervals; and calculating casing wear during drilling for at least one of the plurality of casing sections as a function of wear factors of the drill string corresponding to at least one of the plurality of casing sections; Embodiments C: a drilling system that includes a drill bit coupled to an end of a drill string extending into a wellbore, wherein a portion of the wellbore is lined with a casing; a pump operatively connected to the drill string for circulating a drilling fluid through the wellbore; a control system that includes a processor-readable non-transitory medium and stores instructions for execution by the processor for performing a method comprising: tracking a location of a plurality of sections of a processor; drill string along a wellbore; analyzing the progress of the drill bit when drilling the wellbore at a plurality of drilling intervals, each drilling interval having a depth; the analytical division of the casing into a plurality of casing sections, each casing section having a length; corresponding to at least some of the plurality of casing sections with the drill member wear factor of the drill string section radially close to each of the plurality of casing sections for at least some of the plurality of casing sections. drilling intervals; and analyzing a casing wear for at least one of the plurality of casing sections based on the wear factors of the drill string corresponding to the at least one of the plurality of casing sections; and Embodiment D: a processor-readable non-transitory medium and storing instructions for execution by the precesser for performing a method comprising: tracking the location of a plurality of drill string sections along a borehole which is at least partially lined with casing; analyzing the progress of a drill bit coupled to one end of the drill string sections as it digs the wellbore at a plurality of drilling intervals, each drilling interval having a depth; the analytical division of the casing into a plurality of casing sections, each casing section having a length; corresponding at least to some of the plurality of casing sections with a drill string wear factor of the drill string section radially close to each of the plurality of casing sections for at least some of the plurality of intervals drilling ; and analyzing a casing wear for at least one of the plurality of casing sections as a function of the wear factors of the drill string corresponding to the at least one of the plurality of casing sections. [0044] Each embodiment A, B and C may have one or more of the additional elements, in any combination: Element 1: in which the calculation of casing wear during drilling for the at least one of the plurality of casing sections involves computing a CWF'g for the at least one of the plurality of casing sections according to Equation 1; Element 2: the method further comprising: assigning a threshold value for casing wear during drilling for the at least one of the plurality of casing sections; and performing a corrective operation on the at least one of the plurality of casing sections when casing wear during drilling exceeds the threshold value; Element 3: the method further comprising: assigning a threshold value for casing wear during drilling for the at least one of the plurality of casing sections; and applying a drill string protector to one or more of the sections of the drill string when casing wear during drilling exceeds the threshold value; Element 4: the method further comprising: assigning a threshold value for casing wear during drilling for at least one of the plurality of casing sections; and sending an alarm signal when the wear of the casing during drilling approaches, reaches or exceeds the threshold value; Element 5: The method also comprising: calculating a total casing wear for the at least one of the plurality of casing sections using a casing wear pattern based on casing wear during drilling and at least one of the casing bore wear, casing wear by reciprocating, casing wear, casing wear by rotation on the bottom or wear of the casing. slip casing; Element 6: the method further comprising: Element 5 and assigning a threshold value for total casing wear for the at least one of the plurality of casing sections; and performing a corrective operation on the at least one of the plurality of casing sections when the total casing wear exceeds the threshold value; Element 7: the method 5 further comprising: Element 5 and assigning a threshold value for total casing wear for the at least one of the plurality of casing sections; and applying a stalk protector to one or more of the tubing sections when the total casing wear exceeds the threshold value; Element 8: the method further comprising: Element 5 and assigning a threshold value for total casing wear for the at least one of the plurality of casing sections; and sending an alarm signal when the total casing wear approaches, reaches or exceeds the threshold value; and Item 9: the method further comprising: wherein calculating casing wear during drilling for the at least one of the plurality of casing sections involves analyzing a number of times each d wear of the drill string corresponds to at least one of the plurality of casing sections; and wherein the method further comprises modifying a drill string configuration by applying drill string guards to one or more of the plurality of drill string sections. As a non-limiting example, examples of combinations applicable to Embodiments A, B, C and D include: Element 1 in combination with one or more of Elements 2-4; Element 1 in combination with Element 5 and possibly also in combination with one or more of Elements 6-9; Element 1 in combination with Element 9; Two or more of the elements 2-4 in combination; one or more of Elements 2-4 in combination with Element 5 and optionally also in combination with one or more of Elements 6-8; Element 5 in combination with Element 9 and optionally also in combination with one or more of Elements 6-8; Element 5 in combination with two or more of the Elements 6-8; and any combination thereof. One or more illustrative embodiments incorporating the present invention disclosed herein are set forth below. For the sake of clarity, not all features of a physical implementation are described or illustrated in this application. It should be understood that in developing a physical implementation incorporating the embodiments of the present invention, many concrete-specific decisions must be made in order to achieve the specific objectives of the developers, such as compliance. with constraints related to the system or to commercial considerations, to government and other constraints that will vary from one implementation to another and from time to time. While keeping in mind that a developer's efforts may be time-consuming, it would nevertheless be a routine undertaking for tradespeople who benefit from this disclosure. [0047] Therefore, the present invention is well suited to achieve the purposes and achieve the advantages mentioned herein as well as those inherent in the present disclosure. The particular embodiments disclosed above are illustrative only, since the present invention may be modified and practiced in a different but equivalent manner which will be apparent to those skilled in the art who benefit from the teachings of the present disclosure. In addition, no limitation is contemplated with respect to the construction or design details described herein, other than those described in the following claims. It is therefore obvious that the given illustrative embodiments disclosed above may be altered, combined or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively described herein may suitably be practiced in the absence of any element not specifically disclosed herein and / or any optional element disclosed herein.
    权利要求:
    Claims (20)
    [0001]
    REVENDICATIONS1. A method of estimating casing wear (114; 238) during drilling comprising: drilling a wellbore (112) with a drill bit coupled to an end of a drill string rod extending into a wellbore, (112) in which a portion of the wellbore (112) is lined with tubing (114; 238) and the drill string (110; 208) including a plurality of a drill string (116a-c) each having a wear factor (40; 120) of the drill string (110; 208); tracking a location of the plurality of drill string sections (116a-c) along the wellbore (112); analyzing the progress of the drill bit in a plurality of intervals, each wellbore interval (112) having a depth; the analytical division of the casing (114; 238) into a plurality of casing sections (118a-h), each casing section (114; 238) having a length; matching at least some of the plurality of casing sections (118a-h) with the wear factor (40; 120) of the drill string (110; 208) of the drill string section (110; 208; ) radially near each of the plurality of casing sections (118a-h) for at least some of the plurality of drilling intervals; and calculating casing wear (114 238) during drilling for at least one of the plurality of casing sections (118a-h) based on the drill factors of the drill string (110; 208) corresponding to the at least one of the plurality of casing sections (118a-h).
    [0002]
    The method of claim 1, wherein calculating the casing wear (114; 238) while drilling for the at least one of the plurality of tubing sections (118a-h) comprises computing a mean casing wear factor (114; 238) (CWF'e) for at least one of the plurality of casing sections (118a-h) according to Equation 1 and the calculation of casing wear (114 238) during drilling based on CWF'e, where n represents the number of drill string factors (110; 208) associated with at least one of the plurality of casing sections (118a-h) and NDswF is the number of times each drill string factor (110; 2308) is correlated with at least one of the plurality of casing sections (118a-h) vile DSWFi * Ni CW F'g DSWF, Equation 1. 2, i = 1 lv DSWF, i 5
    [0003]
    The method of claim 1, further comprising: assigning a threshold value for casing wear (114) during drilling for the at least one of the plurality of casing sections (118a-h); and performing a corrective operation on the at least one of the plurality of casing sections (118a-h) when the casing wear (114; 238) during drilling exceeds the threshold value.
    [0004]
    The method of claim 1, further comprising: assigning a threshold value for casing wear (114; 238) during drilling for the at least one of the plurality of tubing sections (118a-h) ); and applying a drill string protector to one or more sections of the drill string (110; 208) when the wear of the casing (114; 238) during drilling exceeds the threshold value.
    [0005]
    The method of claim 1, further comprising: assigning a threshold value for casing wear (114; 238) during drilling for the at least one of the plurality of casing sections (118a); h); and sending an alarm signal when the casing wear (114; 238) during drilling approaches, reaches or exceeds the threshold value.
    [0006]
    The method of claim 1, further comprising: calculating a total casing wear (114; 238) for the at least one of the plurality of tubing sections (118a-h) when drilling using a model of casing wear (114; 238) on the wear of the casing (114; 238) and at least one of casing wear (114; 238) by bore, casing wear (114; 238) ) by reciprocating, casing wear (114; 238) by trigger, casing wear by rotation on the bottom, sliding casing (114; 238).
    [0007]
    The method of claim 6, further comprising: assigning a threshold value for the total casing wear (114; 238) for the at least one of the plurality of tubing sections (118a-h); and performing a corrective operation on the at least one of the plurality of casing sections (118a-h) when casing wear during drilling exceeds the threshold value.
    [0008]
    The method of claim 6, further comprising: assigning a threshold value for total casing wear (114; 238) for the at least one of the plurality of casing sections (118a-h) ; and applying a stalk protector to one or more sections of the drill string (110; 208) when the total casing wear (114; 238) exceeds the threshold value. 10
    [0009]
    The method of claim 6, further comprising: assigning a threshold value for total casing wear (114; 238) for the at least one of the plurality of casing sections (118a-h); and sending an alarm signal when the total casing wear (114; 238) approaches, reaches or exceeds the threshold value. 15
    [0010]
    A method of estimating casing wear (114; 238) during drilling comprising: simulating an operation with a mathematical wellbore drilling model (112) with a drill bit coupled to one end of the drill string (110; 208) extending into the wellbore (112), wherein a portion of the wellbore (112) is lined by casing (114; 238) and the drill string (110; 208) comprises a plurality of drill string sections (116a-c) each having a wear factor (40; 120) of drill string (110; 208), the mathematical model being stored on a non-transitory medium by a processor for execution by a processor; Tracking a location of the plurality of drill string sections (116a-c) along the wellbore (112); analyzing the progress of the drill bit in a plurality of intervals, each wellbore interval (112) having a depth; The analytical division of the casing (114; 238) into a plurality of casing sections (118a-h), each casing section (114; 238) having a length; matching at least some of the plurality of casing sections (118a-h) with the wear factor (40; 120) of the drill string (110; 208) of the drill string section (110; 208) radially proximate each of the plurality of casing sections (118a-h) for at least some of the plurality of bore intervals; and calculating a casing wear (114; 238) during drilling for at least one of the plurality of casing sections (118a-h) based on the wear factors of the drill string (110; 208) corresponding to the at least one of the plurality of casing sections (118a-h).
    [0011]
    The method of claim 10, wherein calculating the casing wear (114; 238) during drilling for the at least one of the plurality of tubing sections (118a-h) comprises computing a average casing wear factor (CWF'g) for at least one of the plurality of casing sections (118a-h) according to Equation 1 and the calculation of casing wear (114; 238) when drilling based on CWF'g, where n is the number of drill string factors (110; 208) associated with at least one of the plurality of casing sections (118a-h) and NDswF represents the number of times each factor of the drill string (110; 208) is correlated with at least one of the plurality of casing sections (118a-h) Er-iDSWFt * NDswF, i CWF'g = Equation 1. rti DSWF, Î
    [0012]
    The method of claim 10, further comprising: assigning a threshold value for casing wear (114; 238) during drilling for the at least one of the plurality of casing sections (118a); h); and modifying a parameter of the drilling operation when the casing wear (114; 238) during drilling exceeds the threshold value.
    [0013]
    The method of claim 10, further comprising: assigning a threshold value for casing wear (114; 238) when drilling for the at least one of the plurality of casing sections (118a-23b); h); and changing a configuration of the drill string (110; 208) when the casing wear (114; 238) during drilling exceeds a threshold value. 30
    [0014]
    The method of claim 13, wherein the modification of the drill string configuration (110; 208) comprises applying a drill string protector to one or more of the drill string sections (110; 208).
    [0015]
    The method of claim 10, further comprising: assigning a threshold value for casing wear (114; 238) during drilling for the at least one of the plurality of tubing sections (118a). - h); and sending an alarm signal when the casing wear (114; 238) during drilling approaches, reaches or exceeds the threshold value.
    [0016]
    The method of claim 10, further comprising: calculating a total casing wear (114; 238) for the at least one of the plurality of casing sections (118a-h) when drilling using a casing model; casing wear based on casing bore (114; 238) and at least one of casing bore wear, casing wear (114; 238) by reciprocating casing wear (114; 238) by triggering, casing wear (114; 238) by rotation on the bottom, sliding casing (114; 238).
    [0017]
    17. The method of claim 16, further comprising: assigning a threshold value for the total casing wear (114; 238) for the at least one of the plurality of casing sections (118a-h) ; and performing a corrective operation on the at least one of the plurality of casing sections (118a-h) when the casing wear (114; 238) during drilling exceeds the threshold value. 20
    [0018]
    The method of claim 10, wherein calculating the casing wear (114; 238) while drilling for the at least one of the plurality of casing sections (118a-h) involves analyzing the casing (114; a number of times that each wear factor (40; 120) of the drill string (110; 208) corresponds to the at least one of the plurality of casing sections (118a-h); and wherein the method further comprises modifying a configuration of the drill string (110; 208) by applying drill string protectors (110; 208) to one or more of the plurality of drill string sections ( 116a-c).
    [0019]
    A drilling system comprising: a drill bit coupled to an end of a drill string (110) extending into a wellbore, (112) wherein a portion of the wellbore (112) is doubled by casing (114; 238); a pump operatively connected to the drill string (110; 208) for circulating a drilling fluid (222) in the wellbore (112); A control system (236) which comprises a processor-readable non-transitory medium and for storing instructions for execution by the processor for executing a method comprising: tracking a location of the plurality of sections of the processor; rod train (116a-c) along the wellbore (112); analyzing the progress of the drill bit as it digs the wellbore (112) at a plurality of intervals, each wellbore interval (112) having a depth; the analytical division of the casing (114; 238) into a plurality of casing sections (118a-h), each casing section (114; 238) having a length; matching at least some of the plurality of casing sections (118a-h) with the wear factor (40; 120) of the drill string (110; 208) of the drill string section (110; 208; ) radially proximate each of the plurality of casing sections (118a-h) for at least some of the plurality of drilling intervals; and analyzing a casing wear (114; 238) for at least one of the plurality of casing sections (118a-h) based on the corresponding drill string wear factors (110; 208) at least one of the plurality of casing sections (118a-h).
    [0020]
    A processor readable non-transitary medium and for storing instructions for execution by the processor for performing a method of estimating casing wear (214; 238) during a borehole comprising: Tracking a location of the plurality of drill string sections (116a-c) along the wellbore (112) which is at least partially lined with casing (114; 238); analyzing the progress of the drill bit coupled to one end of the drill string sections (116a-c) as it digs the well (112) at a plurality of intervals, each well bore interval ( 112) having a depth; the analytical division of the casing (114; 238) into a plurality of casing sections (118a-h), each casing section (114; 238) having a length; The correspondence of at least some of the plurality of casing sections (118a-h) with a wear factor (40; 120) of the drill string section (110; 208) of the drill string section (110; 208) radially proximate each of the plurality of casing sections (118a-h) for at least some of the plurality of bore intervals; and analyzing a casing wear (114; 238). for at least one of the plurality of casing sections (118a-h) based on the wear factors of the drill string (110; 208) corresponding to the at least one of the plurality of casing sections (118a-h) -h). 10
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    同族专利:
    公开号 | 公开日
    GB2553468B|2021-01-20|
    GB201718418D0|2017-12-20|
    CA2985337C|2019-10-15|
    AU2015397957A1|2017-11-09|
    WO2016200397A1|2016-12-15|
    US20170175515A1|2017-06-22|
    CA2985337A1|2016-12-15|
    AR104525A1|2017-07-26|
    GB2553468A|2018-03-07|
    FR3037352B1|2019-07-05|
    US9745844B2|2017-08-29|
    NO20171708A1|2017-10-25|
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    法律状态:
    2017-04-12| PLFP| Fee payment|Year of fee payment: 2 |
    2018-04-25| PLFP| Fee payment|Year of fee payment: 3 |
    2018-11-02| PLSC| Search report ready|Effective date: 20181102 |
    2019-05-23| PLFP| Fee payment|Year of fee payment: 4 |
    2021-02-12| ST| Notification of lapse|Effective date: 20210105 |
    优先权:
    申请号 | 申请日 | 专利标题
    PCT/US2015/035468|WO2016200397A1|2015-06-12|2015-06-12|Estimating casing wear during drilling using multiple wear factors along the drill string|
    IBWOUS2015035468|2015-06-12|
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