Patent Publication Number: US-2023144146-A1

Title: Detection systems and methods for an elastomer component

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to and the benefit of U.S. Provisional Application No. 63/002,377, entitled “TOOL DIAMETER AND JOINT DETECTION SYSTEMS AND METHODS,” filed Mar. 31, 2020; U.S. Provisional Application No. 63/002,379, entitled “DONUT COLLAPSE DETECTION SYSTEM AND METHOD,” filed Mar. 31, 2020; and, U.S. Provisional Application No. 63/002,382, entitled “PACKER VOLUME LOSS DETECTION SYSTEM AND METHOD,” filed Mar. 31, 2020. These applications are incorporated by reference in their entireties herein. 
    
    
     BACKGROUND 
     Elastomeric materials are used for a variety of applications in many different settings. In the oil and gas industry, elastomer material is used in many components including seals, donuts, and packers. In many situations, such as in the oil and gas industry, in situ monitoring of the elastomer properties, such as for fatigue due to temperature and/or pressure cycling, is either impossible or impractical due to the inaccessibility of the component and/or a relatively high intervention cost. 
     In well drilling operations such as in the oil and gas industry, blowout preventers (BOPS) are an important “valve” for well pressure control. Each of the elastomer packer elements of a BOP has an operational lifetime or service life. The service life of the packer element is influenced by the operation conditions such as closing/opening cycles, pressures, temperatures, exposed chemicals etc. The service life can be significantly reduced due to the adverse operation conditions, such as high operation pressures, temperatures and harsh chemicals. This situation causes significant challenges in predicting the service life of packer element of BOPs. In a real well blowout situation, a misprediction on service life of packer element of BOP could have severe consequences. Therefore, a reasonable prediction of the service life of packer element of BOP could not only reduce the operation cost, but also increase the confidence level during operation. In subsea BOPs, the prediction of service life of packer elements becomes even more important because it is extremely expensive to replace the packer element in subsea installation. Furthermore, the subsea environment requires an even higher confidence level for BOPs during operation. Hence, a reliable method to monitor the service life of elastomeric packer elements in BOPs in the oil and gas wells is highly desirable. 
     BRIEF DESCRIPTION 
     This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in determining or limiting the scope of the claimed subject matter as set forth in the claims. 
     According to some embodiments, methods are described for monitoring service life characteristics of an elastomer component in a BOP. The elastomer component is used for sealing a central bore of the BOP and the methods can include: measuring in situ on the BOP while deployed at a wellsite a parameter indicating sealing pressure of the elastomer component; and estimating a service life characteristic of the elastomer component based at least in part on the in situ measurement of the parameter. 
     According to some embodiments, the measuring is made with a sensor device that directly contacts an elastomer material of the elastomer component being monitored or of a second elastomer component that directly contacts the elastomer component being monitored. According to some embodiments, the measuring is made with a sensor device configured to measure contact pressure of the elastomer material. 
     According to some embodiments, the sensor device is of one of the following types: an integrated electronic piezoelectric (IEPE) pressure sensor; a strain gauge configured to measure deformation of a diaphragm contacting the elastomer material; and a type that employs an optical fiber having a plurality of distributed Bragg reflectors contained therein. In some cases, the optical fiber directly contacts elastomer material of the elastomer component being monitored or of a second elastomer component that directly contacts the elastomer component being monitored. Alternatively or in addition, the optical fiber can directly contact a metallic casing that houses the elastomer component being monitored or a second elastomer component that directly contacts the elastomer component being monitored. 
     According to some embodiments, the estimates of service life are at least based in part on comparing the in situ measurements with a predetermined value or values (e.g., threshold(s)) that indicate when the elastomer component is nearing the end of its useful life. The predetermined value or values can be set based on measurements made under real or simulated conditions, such as in a laboratory setting. The predetermined value or values can be set based on analysis of prior BOP case studies. According to some embodiments, the estimates of service life can be based on detecting changes in stress relaxation behavior of the elastomer material. 
     According to some embodiments, the estimates of services life can be based on fluid pressure measured in situ within a central bore of the BOP at a first location using a first pressure sensor. The first location can be below the elastomer component and the estimating of the service life characteristics of the elastomer component can include estimating elastomer volume or changes in elastomer volume based at least in part on measurements of fluid pressure from the first pressure sensor during movement of a piston of the BOP used to actuate the sealing in the central bore of the BOP. 
     According to some embodiments, fluid pressure can also be measured in situ on the BOP at a second location using a second pressure sensor, with a first location being below the elastomer component and a second location being above the elastomer component. The method can include calibrating at least one of the first and second pressure sensors based at least in part on a pressure differential between the first and second locations from measurements made by the first and second sensors while the BOP bore is not sealed, a known vertical distance between the first and second locations, and a known density of fluid within the central bore. 
     According to some embodiments, the service life characteristic(s) being estimated can include detecting potential leakage of the sealing in the central bore due to elastomer wear based at least in part on measurements made by the first and second pressure sensors while the central bore of the BOP is in a sealed configuration. 
     The BOP can be an annular type or ram-type BOP, and in some embodiments, the BOP is deployed in a subsea location. 
     According to some embodiments, methods are also described for investigating causes of failure of one or more components of a BOP. The methods can include: measuring in situ on the BOP, while deployed at a wellsite, a parameter indicating sealing pressure of an elastomer component used for sealing in the BOP; recording the in situ measurements; and analyzing the recorded measurements to determine one or more parameters related to failure of one or more components of the BOP. According to some embodiments, the one or more parameters can include one or more of the following: number of BOP actuations, number of BOP pressure tests, a number of stripping operations performed using the BOP, and a number of joints passing the BOP during stripping operations. 
     As used herein, the term “sealing pressure” of an elastomeric component refers to the pressure the elastomeric component exerts on a sealing object. As used herein, parameters that indicate sealing pressure also include parameters that indicate properties closely related to sealing pressure of the elastomeric component, such as a contact pressure and a material stress of the elastomer of the elastomeric component. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The subject disclosure is further described in the following detailed description, and the accompanying drawings and schematics of non-limiting embodiments of the subject disclosure. The features depicted in the figures are not necessarily shown to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form, and some details of elements may not be shown in the interest of clarity and conciseness. 
         FIG.  1    is a diagram illustrating a drilling and/or producing wellsite where an elastomer characterization system could be deployed, according to some embodiments; 
         FIG.  2    is a cross-sectional view of an annular BOP that includes an elastomer characterization system, according to some embodiments; 
         FIGS.  3  and  4    are diagrams showing results of finite element analysis of pressure within elastomeric components of an annular BOP during uncompressed and compressed states, respectively; 
         FIG.  5    is a plot illustrating changes in contact pressure in elastomer components of an annular BOP during closing and pressure holding; 
         FIG.  6    is a plot illustrating contract pressure characteristics changing over time for elastomer components of an annular BOP; 
         FIG.  7    is a diagram illustrating a strain gauge configured for making contact pressure measurements on elastomer components of an annular BOP, according to some embodiments; 
         FIG.  8    is a diagram illustrating an annular BOP configured with an elastomer characterization system, according to some further embodiments; 
         FIG.  9    is a cross-sectional view of an annular BOP that includes pressure sensors for use in an elastomer health monitoring system, according to some embodiments; 
         FIG.  10    is a schematic diagram showing aspects of a pressure sensor for use in an elastomer health monitoring system, according to some embodiments; 
         FIG.  11    is a block diagram showing aspects of determining BOP elastomer health based on fluid pressure measurements, according to some embodiments; 
         FIG.  12    is a plot illustrating aspects of determining remaining elastomer volume by comparing pressure measurements, according to some embodiments; 
         FIG.  13    is a plot illustrating aspects of detecting proper sealing of the BOP, according to some embodiments; 
         FIG.  14    is a block diagram illustrating signal-processing techniques used to enhance measurements from one or more pressure sensors, according to some embodiments; 
         FIG.  15    is a cross-sectional view of an annular BOP with a detection system, according to some embodiments; 
         FIG.  16    is a cross-sectional view of a portion of an annular BOP, such as the annular BOP of  FIG.  15    taken within line  16 - 16 , according to some embodiments; 
         FIG.  17    is a perspective view of a packer donut and a packer that may be used in an annular BOP, such as the annular BOP of  FIG.  15   , according to some embodiments; 
         FIG.  18    is a plot illustrating contact pressure with respect to piston stroke distance, according to some embodiments; 
         FIG.  19    is a plot illustrating contact pressure with respect to time, according to some embodiments; 
         FIG.  20    is a plot illustrating contact pressure with respect to time, according to some embodiments; 
         FIG.  21    is a plot illustrating contact pressure with respect to time, according to some embodiments; 
         FIG.  22    is a plot illustrating contact pressure with respect to piston stroke distance, according to some embodiments; 
         FIG.  23    is multiple plots illustrating contact pressure with respect to piston stroke distance, according to some embodiments; 
         FIG.  24    is a plot illustrating contact pressure with respect to piston stroke distance, according to some embodiments; and 
         FIG.  25    is multiple plots illustrating contact pressure with respect to piston stroke distance, according to some embodiments. 
     
    
    
     DETAILED DESCRIPTION 
     The particulars shown herein are for purposes of illustrative discussion of the embodiments of the present disclosure only. In this regard, no attempt is made to show structural details of the present disclosure in more detail than is necessary for the fundamental understanding of the present disclosure, the description taken with the drawings making apparent to those skilled in the art how the several forms of the present disclosure may be embodied in practice. 
     When introducing elements of various embodiments, the articles “a,” “an,” “the,” “said,” and the like, are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” “having,” and the like are intended to be inclusive and mean that there may be additional elements other than the listed elements. The use of “top,” “bottom,” “above,” “below,” and variations of these terms is made for convenience, but does not require any particular orientation of the components relative to some fixed reference, such as the direction of gravity. The term “fluid” encompasses liquids, gases, vapors, and combinations thereof. Numerical terms, such as “first,” “second,” and “third” may be used to distinguish components to facilitate discussion, and it should be noted that the numerical terms may be used differently or assigned to different elements in the claims. 
     According to some embodiments, systems and methods are described for monitoring elastomer components, such as monitoring a condition and/or a service life of packer elements (e.g., elastomer packer elements) of annular blowout preventers (BOPS) using measurements that indicate stress on the packer elements. In some embodiments, one or more sensors (such as pressure and/or strain sensors) are installed in a BOP housing where a contact pressure of the packer element can be directly measured. The measured contact pressure, which indicates stress in elastomeric material of the packer element, can be correlated with the condition and/or the service life of the packer element. 
       FIG.  1    is a diagram illustrating a drilling and/or producing wellsite where an elastomer characterization system could be deployed, according to some embodiments. In this example, an offshore drilling system is being used to drill a wellbore  11 . The system includes an offshore vessel or platform  20  at the sea surface  12  and a subsea blowout preventer (BOP) stack assembly  100  mounted to a wellhead  30  at a sea floor  13 . The platform  20  is equipped with a derrick  21  that supports a hoist (not shown). A tubular drilling riser  14  extends from the platform  20  to the BOP stack assembly  100 . The riser  14  returns drilling fluid or mud to the platform  20  during drilling operations. One or more hydraulic conduit(s)  15  extend along the outside of the riser  14  from the platform  20  to the BOP stack assembly  100 . The conduit(s)  15  supply pressurized hydraulic fluid to the BOP stack assembly  100 . Casing  31  extends from the wellhead  30  into the wellbore  11 . 
     Downhole operations, such as drilling, are carried out by a tubular string  16  (e.g., drill string) that is supported by the derrick  21  and extends from the platform  20  through the riser  14 , through the BOP stack assembly  100 , and into the wellbore  11 . In this example, a downhole tool  17  is shown connected to the lower end of the tubular string  16 . In general, the downhole tool  17  may include any suitable downhole tool(s) for drilling, completing, evaluating, and/or producing the wellbore  11  including, without limitation, drill bits, packers, cementing tools, casing or tubing running tools, testing equipment and/or perforating guns. During downhole operations, the string  16 , and hence the tool  17  coupled thereto, may move axially, radially, and/or rotationally relative to the riser  14  and the BOP stack assembly  100 . 
     The BOP stack assembly  100  is mounted to the wellhead  30  and is designed and configured to control and seal the wellbore  11 , thereby containing the hydrocarbon fluids (liquids and gases) therein. In this example, the BOP stack assembly  100  includes a lower marine riser package (LMRP)  110  and a BOP or BOP stack  120 . The LMRP  110  includes a riser flex joint  111 , a riser adapter  112 , one or more annular BOPs  113 , and a pair of redundant control units or pods. A flow bore  115  extends through the LMRP  110  from the riser  14  at the upper end of the LMRP  110  to the connection at the lower end of the LMRP  110 . The riser adapter  112  extends upward from the flex joint  111  and is coupled to the lower end of the riser  14 . The flex joint  111  allows the riser adapter  112  and the riser  14  connected thereto to deflect angularly relative to the LMRP  110 , while wellbore fluids flow from the wellbore  11  through the BOP stack assembly  100  into the riser  14 . The annular BOPs  113  each include annular elastomeric sealing elements (e.g., packer elements) that are mechanically squeezed radially inward to seal on a tubular extending through the LMRP  110  (e.g., the string  16 , casing, drill pipe, drill collar, etc.) or seal off the flow bore  115 . Thus, the annular BOPs  113  have the ability to seal on a variety of pipe sizes and/or profiles, as well as perform a “Complete Shut-off” (CSO) to seal the flow bore  115  when no tubular is extending through the annular BOPs  113 . According to some embodiments, each of the annular BOPs  113  includes one or more sensors  150 . According to some embodiments, the sensors  150  are elastomer stress sensors configured to make stress measurements on the elastomeric sealing elements so that characterizations of their properties can be calculated. According to some embodiments, sensors  150  are pressure sensors that are configured to make pressure measurements on fluid within the flow bore  115 . Each annular BOP  113  may include such pressure sensors positioned such that pressure can be measured above and below the elastomeric sealing element of each annular BOP  113 . As will be described in further detail, infra, such pressure measurements can be recorded and analyzed so that a health of the elastomeric sealing elements can be evaluated. 
     According to some embodiments, the BOP stack  120  includes one or more annular BOPs  113  as previously described with sensors  150 , choke/kill valves, and choke/kill lines. A main bore  125  extends through the BOP stack  120 . In addition, the BOP stack  120  includes multiple axially stacked ram BOPs  121 . Each ram BOP  121  includes a pair of opposed rams and a pair of actuators that actuate and drive the matching rams. In this embodiment, the BOP stack  120  includes four ram BOPs  121 , namely an upper ram BOP  121  including opposed blind shear rams or blades for severing the tubular string  16  and sealing off the wellbore  11  from the riser  14 , and the three lower ram BOPs  120  including the opposed pipe rams for engaging the string  16  and sealing the annulus around the tubular string  16 . In other embodiments, the BOP stack (e.g., the stack  120 ) may include a different number of rams, different types of rams, one or more annular BOPs, or combinations thereof. 
       FIG.  2    is a cross-sectional view of an annular BOP  113  that includes an elastomer characterization system (e.g., monitoring system), according to some embodiments. In this example, the annular BOP  113  includes two elastomer components: a donut  220  and a packer  222 . In order to close and seal the annular BOP  113 , hydraulic fluid enters below a piston  210  and pushes it upwards. The piston  210  lifts a pusher plate  212 , which in turn pushes on the donut  220 . The pressure on the donut  220  forces the packer  222  radially inwards to form a seal with any tube within a BOP bore  230  (or sealing off the BOP bore  230 , if there is no tube or pipe present). To re-open the annular BOP  113 , the hydraulic fluid enters above the piston  210 , thereby forcing it back downwards. In some embodiments, separate pistons can be used for opening and closing the annular BOP  113 . In this case, the sensor  150  is an elastomer stress sensor  150  installed on a top of a body  206  (e.g., housing) within a casing  204  of the annular BOP  113 . The sensor  150  is in contact with the donut  220 . By being in contact with the donut  220 , a contact pressure of the donut  220  can be monitored. As used herein, the term ‘contact pressure’ refers to an average normal stress exerted by the elastomer on a membrane of the sensor  150 . According to some embodiments, the elastomer characterization system could be battery powered or power can be supplied from the offshore vessel or platform  20  or the BOP stack assembly  100  (both shown in  FIG.  1   ). A data transmission/link can be wired to an acquisition system in a data processing unit  250 , or make use of wireless transmission technology, such as acoustic telemetry (e.g., in subsea) or radio-frequency (e.g., on surface). The storage system  242  can be a part of the surface acquisition system or it could be embedded at the sensor level or at the BOP stack level. 
     Also shown in  FIG.  2    is the data processing unit  250 , which according to some embodiments, includes a central processing system  244 , a storage system  242 , communications and input/output modules  240 , a user display  246  and a user input system  248 . Input/output modules  240  are in data communication with the sensor  150 , as shown by the dotted line. The data processing unit  250  may be located in the offshore vessel or platform  20  (shown in  FIG.  1   ), or may be located in other facilities near the wellsite or in some remote location. According to some embodiments, the data processing unit  250  is also used to monitor and control at least some other aspects of drilling operations or other functions on the offshore vessel or platform  20  (shown in  FIG.  1   ). 
       FIGS.  3  and  4    are diagrams showing results of finite element analysis of pressure within the elastomeric components of an annular BOP during uncompressed and compressed states, respectively. Also shown is the location of the sensor  150 , which in this case is an elastomer stress sensor  150 , installed on the top of the donut  220 . It should be appreciated that the sensor  150  may be installed at a different location and/or orientation, such as at an angle (e.g., 45 degree angle) on top of the donut  220  as shown in dotted lines. The stress sensor  150  monitors the contact pressure changes during compression of the donut  220 . As can be seen in  FIG.  4   , the contact pressure measured by the sensor  150  is equal to the contact pressure on the wellbore pipe within the BOP bore  230 . The equivalence is due to the isotropic uncompressing characteristics of the elastomeric materials. Therefore, if the contact pressure as measured by the sensor  150  is not high enough to hold the wellbore pressure, a leakage will be likely to occur. According to some embodiments, the contact pressure measurement from the sensor  150  can be used to monitor the BOP packer elements in either closed or opened positions. 
     Stress relaxation behavior of the elastomer material is a factor that affects the contact pressure, and resulting contact pressure decay. According to some embodiments, the stress relaxation behavior is used as an indicator to monitor the condition and/or the service life of BOP packer elements (e.g., the donut  220 , the packer  222 ). Elastomers used for packer elements are typically polymeric elastomers comprising various fillers, such as carbon black, clay and silica. See e.g., U.S. Pat. No. 9,616,659, and U.S. patent application Ser. No. 15/218,936, both incorporated herein by reference, which discuss typical compositions of BOP elastomers. Elastomers have strong Payne effects and stress soften effects (Mullin effects) due to the filler polymer interactions. This leads to a strong stress history effect of elastomer during deformation. For instance, the stress relaxation behavior tends to change slightly after each compression cycle. 
       FIG.  5    is a plot illustrating changes in the contact pressure in the elastomer components of an annular BOP during closing and pressure holding. The curve  510  shows a typical pressure curve, which could be measured for example using a sensor, such as sensor  150  shown in  FIG.  2   . As shown, there are typically distinct phases including the closing phase  502  which ends when the elastomer packer is fully engaged against the drill pipe. In phase  504 , the well bore fluid pressure is applied. In phase  506 , the well bore pressure is held by the annular BOP. Note that the slopes shown in  FIG.  5    are for illustrative purposes and do not necessarily reflect the actual time scale. In phase  506 , the stress relaxation characteristics of the elastomer are reflected in the slope shown by dashed line  512 . Similarly, in phase  504 , the stress relaxation characteristics of the elastomer are also reflected in the slope shown by dashed line  514 . As discussed above, the stress relaxation characteristics, for example as measured by the slope  512 , will typically be different after each compression cycle. 
       FIG.  6    is a plot illustrating the contract pressure characteristics changing over time for the elastomer components of an annular BOP. The four curves  610 ,  612 ,  614  and  616  represent the contact pressure of an elastomer component of an annular BOP, such as via measurements taken by the sensor  150  shown in  FIG.  2   . The measurements are made during a “pressure holding” phase, such as phase  506  shown in  FIG.  5   . The slopes of each curve are shown by the dashed lines k1, k2, k3 and k4. The stress relaxation characteristic, and therefore the slopes k1, k2, k3 and k4, are affected by various factors over time, such as the number of closing/opening cycles, as well as exposure to pressures, temperatures, and chemicals. In general, it has been found that, over time, the stress relaxation slope becomes steeper. According to some embodiments, the unique stress relaxation characteristics as measured by the contact pressure by the sensor  150  is used to predict the state of the elastomer components. By monitoring the stress relaxation behavior of the contact pressure, the condition and/or the service life of the BOP packer elements can be monitored. 
     In addition to stress relaxation, other factors that can affect the contact pressure include chemical attack (such as mud or other wellbore fluids), thermal degradations, and high pressure extrusions. According to some embodiments, two or more of those factors (including stress relaxation) are combined together to provide an even stronger impact on the changes of the contact pressure, thereby further improving the monitoring of the elastomer material, under some circumstances. 
     According to some embodiments, measurements of the contract pressure on the elastomer material during other BOP phases, such as during the closing phase (e.g., phase  502  in  FIG.  5   ) and/or the pressurization phase (e.g., phase  504  in  FIG.  5   ) can be used to learn information regarding BOP packer health. For example, the contact pressure can be measured versus a piston closing position during the closing step. For the pressurization phase, the contact pressure could be measured versus the well pressure. For further details on measuring the piston position, see e.g., U.S. Pat. App. Publ. 2015/0007651 and U.S. Pat. App. Publ. 2016/0123785, both of which are incorporated by reference herein. 
     According to some embodiments, data collection on multiple cases is combined with analysis to set initial criteria on the service life. The criteria can be further refined using algorithms/data science and statistics. The data analysis could be based on actual physics-based parameters and/or from multiple parameters with statistical behavior considered as inputs for machine learning algorithm(s). 
     According to some embodiments, the sensor  150  (e.g., shown in  FIG.  2   ) can be selected from various suitable types of devices. For example, the sensor  150  may be a piezoelectric type sensor, such as an integrated electronic piezoelectric (IEPE) pressure sensor. One suitable type of IEPE is a Type  211 B IEPE, which is a general purpose pressure sensor that measures transient and repetitive dynamic events in a wide variety of applications. Type  211 B IEPE sensors typically have low impedance, voltage mode, high level voltage signal, high natural frequency, and are acceleration compensated. They are well suited for fast transient measurement under varied environmental conditions. 
     Other types of sensors may be used to make contact pressure measurements on the elastomer components of the annular BOPs.  FIG.  7    is a diagram illustrating a strain gauge that is configured to obtain the contact pressure measurements on the elastomer components of the annular BOPs, according to some embodiments. A sensor  700  (e.g., strain gauge sensor) can be used to make contact pressure measurements, and can be substituted with or used in addition to the sensor  150  shown and described elsewhere herein. The sensor  700  has a body  710  that includes a membrane  712  (e.g., metallic membrane). The sensor  700  can be mounted within an annular BOP such that an outer surface of the membrane  712  is in direct contact with an elastomer component of the annular BOP, such as shown and described with respect to the sensor  150 . Sealing means, such as O-ring  720 , can be used for the mounting. A strain gauge  750  is mounted to an inner surface of the membrane  712 , as shown. When the membrane  712  is deformed due to a contact pressure from the elastomer component, the strain gauge  750  is also deformed. The deformation of the strain gauge  750  can be measured (e.g., by altering an electrical resistance) and recorded using known techniques. Although piezoelectric type sensors and strain gauge sensors have been described herein, according to some embodiments other types of sensor can be used. Other types of piezoelectric type sensors can be used, including voltage-transient response and frequency-change response quartz sensors. According to some embodiments, a piezo-resistive sensor can be used, such as based on metal foil strain, silicon lattice strain, or metallic nanowire strain. Other sensing techniques can also be used, such as a sensor that makes displacement measurements with ultrasonic transducers. Other types of sensors that could be used to measure contact pressure include inductive sensors and optical (opto-electronic) sensors. 
     Although the discussion above has included the use of one sensor only, according to some embodiments, multiple sensors can be installed on a single BOP. In some examples, the sensors are positioned at different circumferential positions. Multiple sensors spaced apart circumferentially could aid in cases when the drill pipe is potentially eccentrically positioned, which might result in misleading measurements by a single sensor. According to some embodiments, the sensor or sensors can be positioned at other positions than shown in  FIG.  2   . In the design shown in  FIG.  2   , for example, the sensor(s) can be positioned at locations indicated by dotted arrows A, B and/or C. The positioning of the sensor(s) should be selected based on a number of factors including the particular design of the BOP. Note that in the case of the annular BOP shown in  FIG.  2   , measurements from a sensor mounting to the location C might be obstructed by the pusher plate  212  when the annular BOP is nearly or fully in the closed (compressed) position. 
     According to some embodiments, one or more sensors can be embedded in the elastomer either by over molding during manufacturing or micromachining a path through the material. For further details of embedding sensors in the elastomer material, see US. Pat. Publ. No. 2017/0130562, which is incorporated by reference herein. 
     According to some embodiments, multiple sensors can be used for redundancy to ensure high reliability of the BOP equipment being monitored. The multiple sensors can be: (1) the same type of sensors mounted in similar and/or different locations; and/or (2) different types of sensors mounted in similar and/or different locations. The use of multiple sensors can provide higher measurement quality by cross-correlation and measurement error compensation. 
       FIG.  8    is a diagram illustrating an annular BOP configured with an elastomer characterization system (e.g., monitoring system), according to some further embodiments. In the case of  FIG.  8   , stress variations in the donut  220  of the annular BOP  113  are measured using optical fiber-based sensors. An optical fiber  850  is located in contact with the donut  220  and is configured with Bragg gratings for distributed Bragg grating measurements. The optical fiber  850 , which can be positioned in a groove on the inner surface of the casing  204 , can be used to detect lengthening of the circumference of the donut  220 , which can be calibrated to the contact pressure (or stress). Other locations can be used to deploy optical fiber-based Bragg grating devices due to the high sensitivity of such devices. For example, optical fibers  852  and  854  are shown positioned in contact with the casing  204 , but not directly in contact with an elastomer component of the annular BOP  113 . Bragg grating measurements can be used to detect minor deformations (elongations) in the circumference of the casing  204 , which through calibration can be related to contact pressure or stress values in the elastomer components. According to some embodiments, the fiber Bragg grating measurements can be used to monitor similar quantities as the ones described when using the pressure type and strain type sensors for monitoring elastomers in BOPs including: strain/stress versus piston position when closing the BOP; strain/stress vs. well pressure when applying wellbore pressure; and strain/stress over time at wellbore pressure plateau. 
     According to some embodiments, a combination of several sensor technologies is used to enhance measurement robustness for reliability (redundancy) and measurement uncertainty and stability. Combining measurements from two or more types of sensors provides these benefits since the different sensors generally have different calibration errors, drift, and performance. 
     According to some embodiments, any of the sensor(s) used (e.g., pressure, strain, fiber optic, etc.) can be calibrated prior to use. In a laboratory or other controlled setting, the sealing pressure of the elastomeric component (i.e., the pressure the component exhorts on a sealing object, such as a drill pipe) is measured directly and used to calibrate the readings from the sensor(s). Measures of stress (normal and/or shear), strain (deformation), and pressure from any of the sensors used can be calibrated back to the sealing pressure. Similarly, even though a particular sensor type may be configured to measure a particular physical property, the sensor&#39;s measurements can be related to and calibrated to monitor sealing pressure of the elastomeric components. For example, a piezoelectric sensor may measure strain (bending) on a membrane, which can be related to stress in a direction normal to the surface of the membrane. The sensor can be calibrated using fluid pressure. Although measurement values of the sensor may be expressed in terms of pressure (e.g., psi), the sensor&#39;s readings can be related to and calibrated for stress in the normal direction. Other types of sensors and/or positioning can be used (e.g., measuring “shear stress” in a tangential direction), but similarly related back to normal stress and sealing pressure. 
     According to some embodiments, the measurements and the sensor devices described herein can be used to analyze, investigate, and in some cases determine likely causes of failure in cases where one or more components of a BOP experience a failure. It has been found that recordings of measurements made of the contact pressure and/or other measurements can be used to keep track of various conditions and events that can be related to elastomer lifespan in the BOP. Examples of such conditions and events include: the number of BOP actuations (e.g., during fatigue tests and pressure tests), the number of stripping operations performed, and even the number of tool joints that have passed through the BOP during such stripping operations. By looking back at such recordings after a failure has occurred, a better understanding of how and why the failure occurred can results. 
     According to some embodiments, the techniques described herein can also be applied to other types of BOPs, such as ram type BOPs. In general, the techniques described herein are applicable to any type of BOP or other equipment (e.g., rotating control devices) having elastomer components, such as elastomer packers that are initially compressed to establish a first contact pressure and then further energized by wellbore pressure to form a sealing surface. While the techniques are applicable to nearly any type of elastomer packers used in BOP applications, they have been found to be especially suitable for annular packers, variable bore ram and flex ram packers, where a larger deformation of the elastomer material is used to establish the contact pressure and to form a seal under wellbore pressure. According to some embodiments, the elastomer material being monitored undergoes at least 10 percent of deformation in uniaxial, planar, or biaxial mode. According to some other embodiments, the elastomer material undergoes at least 20 percent deformation. In some cases, the elastomer material undergoes at least 50 percent deformation, and in some cases at least 200 percent deformation. 
       FIG.  9    is a cross section of an annular BOP that includes pressure sensors for use in an elastomer health monitoring system (e.g., monitoring system), according to some embodiments. In this example, the annular BOP  113  is similar or identical to that shown in  FIG.  2    in many respects. Note that the bore  230  in  FIG.  9    can correspond to the flow bore  115  in the LMRP  110  and/or the main bore  125  in the BOP stack  120 , as shown in  FIG.  1   . In these embodiments, the sensor  150  is a pressure sensor installed within the annular BOP  113  as shown and is configured to measure fluid pressure in a region  1232 , which is below the packer  222  (e.g., the sealing element of the annular BOP  113 ). According to some embodiments, a second pressure sensor  1250  is installed as shown and is configured to measure fluid pressure in a region  1234  that is above the packer  222 . 
     Also shown in  FIG.  9    is the data processing unit  250 , which is similar or identical to the data processing unit  250  shown in  FIG.  2    and includes a storage system  1242 . Input/output modules  240  are in data communication with the sensor  150 , as shown by the dotted line. The data processing unit  250  may be located in the offshore vessel or platform  20  (shown in  FIG.  1   ), or may be located in other facilities near the wellsite or in some remote location. According to some embodiments, the data processing unit  250  is also used to monitor and control at least some other aspects of drilling operations or other functions on the offshore vessel or platform  20  (shown in  FIG.  1   ). 
     According to some embodiments, the sensors  150  and  1250  are either battery powered, supplied by power from the offshore vessel or platform  20  or from the BOP stack assembly  100  (both shown in  FIG.  1   ). A data transmission/link, represented by dotted lines  1262 , can be wired to an acquisition system in the data processing unit  250 , or make use of wireless transmission technology, such as acoustic telemetry (e.g., in subsea) or radio-frequency (e.g., on surface). The storage system  1242  can be a part of the surface acquisition system, or it may be embedded at the sensor level or at the BOP stack level. 
     According to some embodiments, the annular BOP  113  includes the ability to determine the position of the piston  210  within the annular BOP  113 , such as during the closing process. In some cases, an ultrasonic technique can be used. In such cases, a sensor module  1270  is provided that includes an ultrasonic transducer, a temperature sensor, and a pressure sensor. Further details of using ultrasonic techniques for determining location of a piston in a subsea device is provided in co-owned U.S. Pat. Nos. 9,163,471, 9,187,974, and 9,804,039, which are incorporated herein by reference. According to some other embodiments, a coil assembly  1272 , together with the movable piston  210 , forms a linear variable differential transformer (LVDT). Further details of using LVDT techniques for determining location of a movable element within a container is provided in co-owned U.S. Pat. App. Publ. 2016/0123785, which is incorporated herein by reference. 
       FIG.  10    is a schematic diagram showing aspects of a pressure sensor for use in an elastomer health monitoring system (e.g., monitoring system), according to some embodiments. The sensor is labeled as  150 , although both pressure sensors  150  and  1250  shown in  FIG.  9    could use a design that is shown in  FIG.  10   . The sensor  150  in  FIG.  10    is a silicon-on-insulator (SOI) pressure gauge. A silicon sensor chip  1310  is shown mounted to a glass pedestal  1314 . A silicon piezo resistor(s)  1312  is shown, which are electrically connected with metal contacts  1316  and  1318 . The metal contacts  1316  and  1318  are connected to wires  1322  and  1324  and contact pins  1332  and  1334 , respectively. The sensor structure is sealed by a header glass  1330 , a housing wall  1340  and a diaphragm  1342 . In operation, the diaphragm  1342  is exposed to the fluid pressure (e.g., in regions  1232  and  1234  shown in  FIG.  9   ). The pressure is transmitted through the diaphragm  1342  and applied to an outer surface of the silicon chip  1310 . Mechanical stress on the chip  1310  is measured through the piezo resistor(s)  1312 . Sensors such as shown in  FIG.  10    can have outstanding metrology. According to some embodiments, the sensors  150  and  1250  are configured to monitor changes in pressure in the range of a few Pa [mpsi] per second, and at the same time able to read pressure values up to 138 MPa [20000 psi], in a temperature range from 0 degrees Celsius to 150 degrees Celsius. According to some embodiments, the dynamic response is equal to or better than 100 mpsi within a 1-5 minutes, and the gauge resolution of 1-15 mpsi @ 1 Hertz (Hz). 
     According to some embodiments, a suitable pressure gauge is used, which has at least the following specifications: Pressure range (FS), atm—10 kpsi; Temperature range, 85 degrees Celsius—125 degrees Celsius; Accuracy, Typ. 1×10 −3 FS; Repeatability, Typ. 1×10 −4  FS to 1×10 −3  FS; Resolution, Typ. 1×10 −5  FS to 1×10 −3  FS; Dynamic response to Pressure transient, Stabilization within 10 −4  FS&lt;1-10 s; Dynamic response to Temperature transient, Stabilization within 10 −4  FS&lt;10-30 s; Short term stability (0-4H), &lt;100-1000 mpsi; Medium term stability (4-14H), 1-10 psi; Long term stability (&gt;100H), 1-100 psi; Data rate, 1 Hz-10 Hz; and Reliability, 1 years—155 degrees Celsius. 
     According to some embodiments, one or more of the pressure gauges used has at least the following specifications: Pressure range (FS), 10 kpsi-30 kpsi; Temperature range, 125 degrees Celsius—200 degrees Celsius; Accuracy, Typ. range 0.5×10 −4  FS-2×10 −4  FS,  Max. 3×10 −4  FS; Repeatability, Typ. 1×10 −5  FS to 1×10 −4  FS; Resolution, Typ. 1×10 −6  FS to 1×10 −5  FS; Dynamic response to Pressure transient, Stabilization within 10 −4  FS&lt;0.1-10 s; Dynamic response to Temperature transient, Stabilization within 10 −4  FS&lt;1-30 s; Short term stability (0-4H), &lt;1-10 mpsi; Med. term stability (4-14H), 0.1-1 psi; Long term stability (&gt;100H), 0.1-1 psi; Data rate, 1 Hz-2000 Hz; and Reliability, 5 years—150 degrees Celsius. 
     According to some embodiments, the pressure sensors  150  and  1250  are further configured to provide temperature measurements, which can be used for pressure sensor calibration. Note that although a SOI-type pressure sensor is shown in  FIG.  10   , according to some other embodiments, one or more other known types of pressure sensors are used for the sensors  150  and/or  1250 . Examples of other types of sensors that could be suitable include: other types of pressure quartz transducers, piezoelectric resonant pressure sensors, optic fiber sensors, metallic alloy-based strain foil gauges, metallic nanowire based strain sensors, and force sensors for example based on a strain foil gauge. According to some embodiments, sensors  150  and/or  1250  are of a type and design such as used in Schlumberger&#39;s Signature CQG Crystal Quartz Gauge tool and/or Schlumberger&#39;s MDT Modular Formation Dynamics Tester. 
       FIG.  11    is a block diagram showing aspects of determining BOP elastomer health based on fluid pressure measurements, according to some embodiments. It is assumed that both the geometry and the properties of the fluid that fills the bore  230 , the flow bore  115 , and the main bore  125 , shown in  FIGS.  1  and  9   , are known. The block diagram of  FIG.  11    illustrates how to determine elastomer health properties based on the pressure measurements during a regular subsea BOP in-situ pressure test. Two pressure measurement sensors are used: P1(t) which is positioned below the BOP sealing element (corresponding to the sensor  150 , shown in  FIG.  9   ); and P2(t) which is positioned above the BOP sealing element (corresponding to the sensor  1250  shown in  FIG.  9   ). During the pressure test, measurements are recorded from both pressure sensors during both (1) the piston movement phase, and (2) while the well pressure is being applied. 
     In block  1410 , before moving the piston and while the well is in static conditions, P1−P2 (t=0) measurements are used to provide an in-situ calibration check for the two sensors, since this differential pressure is the product of known fluid density, known altitude difference between the sensors and the force of gravity on Earth (g). 
     In block  1412 , during the movement of the piston for closure of the BOP, P1(t) vs. piston position is monitored and recorded. Note that as described supra, ultrasonic and/or LVDT are examples of methods that can be used for determining the piston position. In block  1414 , the P1(t) versus piston position measurements are then compared to historical and/or simulated data obtained with the same or similar BOPs. Provided the fluid properties are known, as the elastomer wears and degrades, variations between the measured and historical and/or simulated P1(t) versus piston position data will tend to change and become characteristic of the remaining elastomer volume (Block  1420 ). 
     Blocks  1416  and  1418  illustrate two examples of how remaining elastomer volume could be determined. In block  1416 , a change (e.g., an increase) in the pressure P1, once the piston has reached its final position, can be used to determine the remaining volume of the elastomer. P1 is a product of the known fluid density, g, and the unknown fluid column height increase. Solving for the fluid column height increase can then be related to the remaining volume of elastomer. 
       FIG.  12    is a plot illustrating aspects of determining remaining elastomer volume by comparing pressure measurements, according to some embodiments. A first order calculation can be used, which takes into account the density change due to the replacement of the drilling fluid by the elastomer in the BOP wellbore section. The relationship is based on the change over time measured at pressure sensor P1: k0+k1*((P1(t h )−P1(t 1 ))/(ρ*g))+k2*((P1(t h )−P1(t 1 ))/(ρ*g)) 2  k3*((P1(t h )−P1(t 1 ))/(ρ*g)) 3  (volume loss). P1 is a pressure sensor below the elastomer such as sensor  150 , p is drilling fluid density, g is gravitational acceleration, k0, k1, k2, and k3 are geometric coefficients related to the packer. t h  and t 1  are times when the BOP is closed. t h  is a historical time, for example when the elastomer packer is in a new or otherwise well-known state, while t 1  the time of the periodic check. In  FIG.  12   , both curves  1510  and  1520  show recorded pressure measurements taken in a central bore of the BOP, such as by the sensor  150  shown in  FIG.  9   . Curve  1510  reflects measurements made at a historical time (e.g. when the elastomer packer is in a new or otherwise well-known state), while curve  1520  reflects a measurement made recently or currently. The BOP closure is shown at times  1512  and  1522  for curves  1510  and  1520 , respectively. Measurement points  1514  and  5124  show the P1 measurements for curves  1510  and  1520 , respectively. The pressure differential P1(t h )−P1(t 1 ) can be used, for example, in the relationship described above to estimate the elastomer volume loss. Note that according to some embodiments, the volume loss is estimated for an open BOP (no strain on the elastomer). The following is an illustrative example for volume loss determination: P1(t 0 )−P1(t 1 )=150 mpsi, ρ=1000 kg/m3, g=9.81 m/s 2 , k0=0, k1=0, k2=0.25, k3=0.75, volume loss 3 liters (2.10e-3 m 3 ). 
       FIG.  13    is a plot illustrating aspects of detecting proper sealing of the BOP, according to some embodiments. In this case, the P1 measurements can be used to detect proper sealing of the BOP. Note that this technique can be used for sealing integrity prior to additional well bore pressure being applied, rather than as a method for leak detection at maximum well bore pressure. Curve  1620  reflects P1 measurements made before, during, and after a BOP closure. A condition can be defined as follows: P1(t 0 )−P1(t 1 )&gt;ΔP_min. P1 is the pressure measured in the central bore of the BOP below the sealing element, such as by sensor  150  shown in  FIG.  9   . AP min is a minimum differential pressure threshold/drop to ensure sealing detection. t 0  and t 1  are respectively times when the BOP is open and closed. If P1(t 0 )−P1(t 1 )≤ΔP_min, then improper sealing of the BOP is indicated prior to application of additional pressure from below the BOP. Following is an illustrative example for sealing detection: P1(t 0 )−P1(t 1 )=150 mpsi, ΔP_min=100 mpsi. Therefore, the BOP is sealed with no additional well bore pressure. 
     Referring again to  FIG.  11   , alternatively or in addition to block  1416 , in block  1418 , more complex behaviors during the transient move of elastomer packer can be interpreted based on historical and/or simulation data. 
     In block  1422 , after the piston has reached its maximum position and before applying well pressure, P2(t) and P1(t) can be compared to historical and/or modeling data. In an ideal case, both should remain constant. However, if there is a leakage path due to elastomer wear, and if the differential pressure P2-P1 is sufficient, a flow would be induced, leading to monotonic variations of P1 and/or P2 with time. 
     In block  1424 , once well pressure is applied, P1 becomes greater than P2. Note that the difference will remain below the BOP differential pressure rating. In block  1426 , P1(t) and P2(t) are compared to historical and/or modeling data. Both should ideally remain constant. However, in case there is a leakage, the P2(t) variation can be used to determine flow rate (see example 1 of numerical application below), and the necessary differential pressure P1−P2 can then give an indication of microleak geometry provided fluid rheological properties are known (see example 2 of numerical application below). 
     Example 1—using P2(t) to determine leakage flow rate. Assumptions: annulus area: A=700 cm2 (20-inch riser and 5-inch drill pipe); fluid density: ρ=1500 kg/m3; flow rate: Q=3.5 mL/s=210 mL/min. 
     
       
         
           
             
               
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     that numerically gives a pressure variation of 45 Pa in one min (7 mpsi/min). This variation can be detected with high quality SOI pressure sensors. 
     Example 2—using P1-P2 to determine leak diameter. Assumptions: P1-P2=69 MPa (10000 psi); flow rate: Q=3.5 mL/s; Newtonian fluid with fluid viscosity: =0.1 Pas; cylindrical microleak through the elastomer with a length of: 1=30 cm; laminar flow (valid for a liquid in a small diameter leak path). 
     According to Poiseuille&#39;s law the radius r of the microleak channel to the power 4 can be expressed as: 
     
       
         
           
             
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     that numerically gives a radius of 250 microns for the corresponding micro leak in the elastomer. 
     Note that unlike with conventional leak detection systems, some of the pressure measurements described herein will benefit from relatively fast and high-resolution pressure sensors. For example, during the BOP piston movement, the pressures will change drastically (typically several thousand of psi in a few seconds) and the dynamic effects (e.g., fluid temperature variation and gauge response) could jeopardize the pressure data interpretation during the first minutes. 
     Therefore, to properly examine the entire leak signature, the pressure sensor should be highly stabilized (within a few mpsi) after a few minutes. Furthermore, if we assume an acceptable leak detection threshold of 3.5 mL/s (see example 1), the pressure sensor should be capable to resolve a variation of a few mpsi. Based on the foregoing, according to some embodiments, the pressure sensors used have a dynamic response of within 100 mpsi in a few minutes, and a gauge resolution of 1-15 mpsi @ 1 Hz. 
       FIG.  14    is a block diagram illustrating signal-processing techniques used to enhance measurements from one or more pressure sensors, according to some embodiments. The techniques can be applied to the signals and/or recorded data from sensors, such as the sensors  150  and/or  1250  shown in  FIG.  9   , to further enhance the evaluation of the elastomeric sealing elements of the BOP. As a part of the acquisition system (electronics), an algorithm shown in  FIG.  14    uses adaptive Analog-to-Digital-Conversion (ADC) gain and adaptive steady-state input offset to “zoom” in on specific operating points rather than looking at relatively small changes over the full measurement range. Block  1710  represents the acquisition from the sensor (e.g., in volts) without any offset compensation with full scale gain. In block  1712 , the measurement computation is made with the full-scale gain and calibration. In block  1714 , if the acquisition voltage is greater or equal to the offset compensation step, then the offset compensation is increased (block  1716 ). Otherwise, in block  1718 , if the acquisition voltage is less than or equal to half of the full scale, then in block  1720 , the ADC gain is increased. When the acquisition voltage is greater than half of the full scale, then the measurement acquisition is recorded with calibration steps (if any). Using techniques such shown in  FIG.  14   , increased sensitivity in psi/V with increased resolution in psi/V can be achieved. According to some embodiments, sensitivity and/or resolution could be improved by a factor of 2 to 100. 
     According to some embodiments, novel techniques are described to monitor a condition and/or a service life of a packer element of an annular BOP. According to some embodiments, high-quality pressure sensors are positioned above and/or below the packer element of the annular BOP. Pressure variations measured below the packer element are monitored versus piston position and/or time. The measured pressure variations can be used to detect elastomer wear that can occur over time and/or after pressure cycles. Pressure variations measured above the elastomer seal can be used to detect possible elastomer leakage, and in some cases, estimate the leakage rate. Finally, the differential pressure between the two sensors (e.g., above and below the packer element) can also be monitored, which can be used for micro-leak geometry characterization. Additional novel techniques are envisioned and are discussed with reference to  FIGS.  15 - 25   . 
       FIG.  15    is a cross-sectional view of an embodiment of an annular BOP  1798  that includes a detection system  1800  (e.g., monitoring system; tool diameter detection system; tool joint detection system; donut collapse detection system; packer volume loss detection system). In some embodiments, the detection system  1800  may carry out a tool diameter detection process by using a pressure or strain sensor and a piston stroke sensor to detect a diameter size of a tool (e.g., tubular) within the annular BOP  1798 . In some embodiments, the detection system  1800  may carry out a tool joint detection process by using a pressure or strain sensor to monitor changes in pressure and/or strain with respect to time to detect a presence of a tool joint (e.g., radially-expanded joints that couple pipe sections of the tubular to one another) within the annular BOP  1798 . 
     As shown, the annular BOP  1798  includes multiple annular elastomer components, which may be referred to herein as a donut  1802  and a packer  1804 . The donut  1802  circumferentially surrounds the packer  1804 , and the donut  1802  is positioned radially between the packer  1804  and a BOP housing  1807 . While the annular BOP  1798  includes both the donut  1802  and the packer  1804 , it should be appreciated that the detection system  1800  may be used with any of a variety of types of annular BOPs, including annular BOPs that are devoid of the donut  1802  (e.g., only include one annular elastomer component, such as a packer). 
     In order to actuate the donut  1802  and the packer  1804  to form a seal (e.g., annular seal about the tool), a piston  1805  (e.g., annular piston) is driven axially in an axial direction  1806  (the axial direction may also be referred to herein as an axial axis of the annular BOP  1798 ). For example, a hydraulic fluid may be pumped into the BOP housing  1807  into a space (e.g., annular space) below the piston  1805 , which drives the piston  1805  upwards in the axial direction  1806 . The piston  1805  drives and lifts a pusher plate  1808 , which in turn contacts and compresses the donut  1802 . The compression of the donut  1802  forces the packer  1804  radially inwards to form the seal about the tool within a BOP bore  1810  or to enable the packer  1804  to seal against itself across the BOP bore  1810  if no tool is present within the BOP bore  1810 . 
     In order to detect a diameter size of the tool (e.g., changes in the diameter size) and/or to detect a tool joint in the annular BOP  1798 , the detection system  1800  includes one or more pressure and/or strain sensors  1812  that output pressure and/or strain signals indicative of measured pressure and/or strain. In addition to the sensors  1812 , the detection system  1800  may include one or more piston stroke sensors  1820  (e.g., 1, 2, 3, 4) to facilitate detection of the diameter size of the tool. The piston stroke sensor  1820  outputs position signals indicative of a measured position of the piston  1805 , which enables the controller  1814  to determine how far the piston  1805  moves in the axial direction  1806  during actuation of the annular BOP  1798  (e.g., a piston stroke length). The sensors  1812  and the piston stroke sensor  1820  may couple to a controller  1814  (e.g., electronic controller) that includes a processor  1816  and a memory device  1818 . It should be appreciated that the controller  1814  may include operational features that are similar to or the same as the data processing unit  250  disclosed herein. 
     In operation, the controller  1814  receives the signals from the sensors  1812  and/or the piston stroke sensor  1820 , and the controller  1814  processes the signals with the processor  1816 . The processor  1816  may be used to execute software, such as software that enables the detection system  1800  to detect the diameter size of the tool in the annular BOP  1798  using feedback from the sensors  1812  and the piston stroke sensor  1820 . As will be explained in more detail below, the controller  1814  determines the pressure and/or strain on the donut  1802  and the piston stroke length of the piston  1805 . By determining how far the piston  1805  moved to achieve a desired pressure and/or strain, the controller  1814  is able to determine the diameter size of the tool in the annular BOP  1798 . The processor  1816  may also execute software that enables the detection system  1800  to detect tool joints as they pass through the annular BOP  1798  using feedback from the sensors  1812  with respect to time. 
     The processor  1816  may include multiple microprocessors, one or more “general-purpose” microprocessors, one or more special-purpose microprocessors, and/or one or more application specific integrated circuits (ASICS), or some combination thereof. For example, the processor  1816  may include one or more reduced instruction set computer (RISC) processors. The memory device  1818  may include a volatile memory, such as random access memory (RAM), and/or a nonvolatile memory, such as read-only memory (ROM). The memory device  1818  may store a variety of information and may be used for various purposes. For example, the memory device  1818  may store processor executable instructions (e.g., firmware or software) for the processor  1816  to execute, such as instructions for processing the signals from the sensors  1812  and/or the piston stroke sensor  1820 . The storage device(s) (e.g., nonvolatile memory) may include ROM, flash memory, a hard drive, or any other suitable optical, magnetic, or solid-state storage medium, or a combination thereof. The storage device(s) may store data, instructions, and any other suitable data. It should be appreciated that the controller  1814  may include other components, such as communication components that enable wired and/or wireless transmission of data to other devices and/or systems. 
     As shown in  FIG.  15   , a first sensor  1812  of the one or more sensors  1812  is positioned on a first side of the annular BOP  1798 , and a second sensor  1812  of the one or more sensors  1812  is positioned on a second side of the annular BOP  1798  that is opposite the first side of the annular BOP  1798  (e.g., offset by approximately 180 degrees about a circumference of the annular BOP  1798 ). The first sensor  1812  and the second sensor  1812  are supported within the BOP housing  1807  to contact the donut  1802  (e.g., an upper, tapered surface of the donut  1802 ). Additional features of the one or more sensors  1812  may be understood with reference to  FIG.  16   . 
     In particular,  FIG.  16    is a cross-sectional view of a portion of an embodiment of an annular BOP, such as the annular BOP  1798  of  FIG.  15    taken within line  16 - 16 . While  FIG.  16    includes one sensor  1812  of the one or more sensors  1812  to facilitate discussion, it should be appreciated that some or all of the one or more sensors  1812  may have the same features. As shown, the sensor  1812  is supported by the BOP housing  1807 , such as by being positioned within an opening  1822  that is formed in and extends through the BOP housing  1807 . The sensor  1812  may be oriented at an angle  1824  relative to a radial axis  1826  of the annular BOP  1798  (the radial axis  1826  may also be referred to herein as a radial direction). More particularly, an inner end  1828  of the sensor  1812  may be configured to contact an upper, tapered surface  1830  of the donut  1802  at an interface  1832 , which may be oriented at the angle  1824  relative to the radial axis  1826 . The angle  1824  may be between about 15 to 85 degrees, 30 to 60 degrees, or 40 to 50 degrees. In some embodiments, the angle  1824  may be approximately 15, 25, 35, 45, 55, or 65 degrees. 
     The configuration shown in  FIGS.  15  and  16    (e.g., the sensor  1812  oriented at the angle  1824 ) may enable the sensor  1812  to accurately measure the pressure and/or strain, as the sensor  1812  may detect the pressure and/or strain due to a reaction force at the tool within the annular BOP  1798  and/or with less error due to a reaction force at the piston  1805  and/or with less error due to frictional forces. The configuration may also provide access to the sensor  1812  from outside the annular BOP  1798 , such as access to the sensor  1812  without dismantling the annular BOP  1798  for more efficient maintenance operations (e.g., inspection and/or repair operations). The access to the sensor  1812  may also facilitate communication with the sensor  1812 , such as wired and/or wireless communications with the sensor  1812  (e.g., for power, control, and/or data transfer). 
       FIG.  17    is a perspective view of an embodiment of the donut  1802  surrounding the packer  1804 .  FIG.  17    also illustrates locations where the sensors  1812  may contact the donut  1802  to measure the pressure and/or strain. As illustrated, there are four locations  1840  equally spaced about a circumference of the donut  1802  where the sensors  1812  are configured to contact the donut  1802 . While the four locations  1840  are illustrated in  FIG.  17   , it should be appreciated that there may be a different number of locations  1840  depending on the number of sensors  1812  (e.g., 1, 2, 3, 4, 5, 6, 7, 8, or more locations  1840  and sensors  1812 ). The locations  1840  may be equidistant or vary in distance from each other. However, equally spaced sensors  1812  may facilitate accurate assessment of the diameter size of the tool and/or tool joint detection. 
       FIG.  18    is a plot  1850  illustrating an example of a response of the donut  1802  with respect to a position of the piston  1805  (e.g., piston stroke length). The plot  1850  includes a first axis  1852  (e.g., x-axis) that represents a piston position (e.g., piston stroke length) and a second axis  1854  (e.g., y-axis) that represents pressure or strain. The response of the donut  1802  is illustrated with curves  1856 ,  1858 , and  1860 . More particularly, the curves  1856 ,  1858 , and  1860  represent the response of the donut  1802  with tools of different diameter sizes in the annular BOP  1798 . 
     As illustrated, in order to reach a desired pressure or strain level  1862  (e.g., that provides the seal about the tool; a target value, which may be stored in the memory device  1818 , entered by an operator, and/or calculated by the controller  1814  or other computing system), the piston position may differ depending on the diameter size of the tool. For example, the piston  1805  may have to move an additional distance  1864  during a second closure of the annular BOP  1798  as compared to during a first closure of the annular BOP  1798  because a respective diameter size of a second tool (or tool section) in the annular BOP  1798  during the second closure is less than a respective diameter size of a first tool (or tool section) in the annular BOP  1798  during the first closure. In other words, the piston  1805  has to move a greater distance in order to provide the same contact pressure or strain (e.g., the pressure or strain level  1862 ). 
     Similarly, the piston  1805  may have to move an additional distance  1866  during a third closure of the annular BOP  1798  as compared to during the first closure of the annular BOP  1798  because a respective diameter size of a third tool (or tool section) in the annular BOP  1798  during the third closure is less than the respective diameter size of the first tool (or tool section) during the first closure and is less than the respective diameter size of the second tool (or tool section) during the second closure. In operation, the detection system  1800 , and particularly the controller  1814  of the detection system  1800 , is configured to correlate the piston position that achieves the desired pressure or strain level  1862  to the diameter size of the tool within the annular BOP  1798 . It should be appreciated that the controller  1814  may utilize one or more algorithms, look up tables, or the like to determine the diameter size of the tool within the annular BOP  1798  based on the piston position that achieves the desired pressure or strain level  1862 . 
     An indication of the diameter size of the tool within the annular BOP  1798  may be output to the operator (e.g., via a display that is communicatively coupled to the controller  1814 ). In some embodiments, the diameter size of the tool may be used to assist in tracking and/or locating portions of the tool, such as tracking and/or locating which portions of the tool are in the wellbore, which portions of the tool are in the BOP stack assembly, which portions of the tool are above the BOP stack, and the like. In some cases, a sequence of pipes joined by tool joints to form a tubular may be stored in a data log (e.g., in the memory device  1818 ). Characteristics (e.g., diameters) of the pipes and the tool joints may also be stored in the data log. 
     As one example to facilitate discussion, the data log may indicate that a series of small diameter pipes is positioned below a series of large diameter pipes. The diameter size of the tool as detected by the detection system  1800  may indicate whether one of the series of the small diameter pipes is positioned in the annular BOP  1798  (e.g., such as due to the piston position itself and/or due to a sudden change in the piston position due to the series of larger diameter pipes moving out of the annular BOP  1798  as the tool is pulled out of the wellbore during stripping operations). An indication that one of the series of small diameter pipes is positioned in the annular BOP  1798  may then be output to the operator and/or the information may be used to control other operations. For example, based on the information derived from the data log and/or the location of the one of the series of small diameter pipes in the annular BOP  1798 , the controller  1814  may instruct certain operations, enable certain operations (e.g., enable operation of a pipe ram BOP with pipe rams that are sized to seal about the series of small pipes), and/or block certain operations (e.g., block operation of a pipe ram BOP with pipe rams that are not sized to seal about the series of small diameter pipes). It should be appreciated that any of a variety of tools having any of a variety of configurations may extend through the annular BOP  1798 , and the operations (e.g., related to a pipe ram BOP or other equipment) carried out in response to the detection of the diameter size of the tool may vary accordingly. 
       FIG.  19    is a plot  1900  illustrating a contact pressure with respect to time for the donut  1802  of the annular BOP  1798 . The plot  1900  illustrates a response of the donut  1802  to a passage of a tool joint through the annular BOP  1798  while the annular BOP  1798  is closed (e.g., while the packer  1804  is sealed about the tool; during stripping operations). As noted herein, the tool joints connect pieces of equipment, such as tubulars (e.g., pipes), together to form the tool. The tool joint may define a diameter that differs from (e.g., is larger than) a remainder of the equipment. As the tool joint passes through the annular BOP  1798  while the annular BOP  1798  is closed, the tool joint may force radial expansion of the packer  1804 , and thus, compression of the donut  1802  radially outward toward the BOP housing  1807 . This additional compression of the donut  1802  is detectable with the pressure and/or strain sensors  1812 . For example, as the tool moves through the annular BOP  1798  while the annular BOP  1798  is closed, the additional compression of the donut  1802  is a temporary event that causes the pressure and/or strain signal to change in a particular manner over time (e.g., to correspond to a signature, which may be known and stored in the memory device  1818 ). 
     The plot  1900  includes a first axis  1902  (e.g., x-axis) that represents time and a second axis  1904  (e.g., y-axis) that represents the pressure or strain. The response of the donut  1802  over time is illustrated with the curve or line  1906 . As illustrated, the curve  1906  starts with the annular BOP  1798  already closed and the donut  1802  loaded to the desired pressure or strain level  1908 . During drilling operations, the tool may be pulled through the annular BOP  1798  while the annular BOP  1798  is closed. This may be referred to as stripping or scrapping the tool. As the tool is pulled through the annular BOP  1798  while the annular BOP  1798  is closed, the tool joints that hold sections of the tool together are also pulled through the annular BOP  1798 . As explained above, the tool joint may define a diameter that is greater than a respective diameter of other sections of the tool (e.g., other sections joined by the tool joint). Accordingly, as the tool joint passes through the annular BOP  1798  while the annular BOP  1798  is closed, the tool joint may contact the packer  1804 , which may force or drive the packer  1804  radially outward. As the packer  1804  expands radially outward, the packer  1804  in turn causes compression of the donut  1802 . This compression of the donut  1802  is detected by the pressure or strain sensors  1812 , and this is reflected in portion  1910  (e.g., increasing; positive slope) of the curve or line  1906 . 
     Then, after the tool joint passes through the packer  1804 , the donut  1802  expands as the excess pressure is removed, which is detected by the pressure or strain sensors  1812  as a reduction in the contact pressure. This reduction in the contact pressure is reflected in portion  1912  (e.g., decreasing; negative slope) of the curve or line  1906 . The pressure or strain on the donut  1802  then again increases (e.g., equalizes; returns to a steady state and/or to an initial pressure or strain, which may be the desired pressure or strain  1908 ) as another section of the tool (e.g., other than the tool joint) enters the annular BOP  1798  (e.g., is positioned within the packer  1804 ). When the annular BOP  1798  is in proper working condition, and when the sections of the tool before and after the tool joint have matching diameters sizes, the pressure or strain on the donut  1802  may increase to return to the initial pressure or strain, which may be the desired pressure or strain  1908 , as reflected in the portion  1914  (e.g., increasing; positive slope) of the curve or the line  1906 . 
     It is by monitoring these changes in the pressure or strain on the donut  1802  overtime that the detection system  1800  is able to detect the passage of the tool joints through the annular BOP  1798 . For example, the controller  1814  may count a number of tool joints over time (e.g., based on a number of such signatures recognized by the controller  1814  over time). In some embodiments, the controller  1814  may output an indication of the number of tool joints that have passed through the annular BOP  1798  (e.g., display a counter in substantially real time, where the counter displays a numerical value that increases by one with each tool joint detected via the disclosed techniques) and/or provide an indication each time a tool joint passes through the annular BOP  1798  (e.g., an audible or visual indicator). 
     Furthermore, as noted herein, the data log may include a sequence of pipes joined by the tool joints. The data log may also include the characteristics of the pipes and the tool joints, such as a spacing or a distance separating the tool joints. Thus, the controller  1814  may determine a total length of a portion of the tool pulled through the annular BOP  1798  (e.g., based on the number of tool joints pulled through the annular BOP  1798  and a distance between the tool joints), a rate at which the tool is pulled through the annular BOP  1798  (e.g., based on a time between adjacent tool joints and a distance between the adjacent tool joints), and the like. The controller  1814  may output the information to the operator to facilitate understanding and tracking of the operations. 
     The controller  1814  may also use the information related to the tool joints to control other operations. For example, based on information derived from the data log and/or the detection of the tool joint in the annular BOP  1798 , the controller  1814  may instruct certain operations, enable certain operations, and/or block certain operations. As a more specific example, the controller  1814  may access a spacing that separates the tool joints, calculate a rate of movement of the tool through the annular BOP  1798 , and/or detect a first tool joint in the annular BOP  1798 . In some such cases, upon detection of the first tool joint in the annular BOP  1798 , the controller  1814  may determine when a nonshearable section of the tool (or when a shearable section of the tool) will be within a shear ram BOP. For example, the controller  1814  may determine that a second tool joint (e.g., below the first tool joint) will be present within the shear ram BOP at a particular time (e.g., time window). Then, the controller  1814  may output an indication to the operator to notify the operator that certain ram BOPs (e.g., closure of the shear ram BOP) should not be operated during the particular time. It should be appreciated that the controller  1814  may additionally or alternatively output an indication to notify the operator that the certain ram BOPs (e.g., closure of the shear ram BOP) may be effectively completed during other times, such as other times that are not at the particular time (e.g., a shearable section of the tool is within the shear ram BOP). 
     The controller  1814  may also automate certain operations, such as to delay and/or to block operation of the shear ram BOP while the second tool joint is at the shear ram BOP. It should be appreciated that any of a variety of tools having any of a variety of configurations may extend through the annular BOP  1798 , and the operations in response to the detection of the tool joint may vary accordingly. Furthermore, while control of the ram BOPs is described herein to facilitate discussion, it should be appreciated that the detection of the tool joint in the annular BOP  1798  may be utilized to control any of a variety of operations (e.g., rotating control devices, valves). 
       FIG.  20    is a plot  1930  illustrating a contact pressure with respect to time for the donut  1802  of the annular BOP  1798 . The plot  1930  illustrates the response of the annular BOP  1798  to a passage of a tool joint through the annular BOP  1798  while the annular BOP  1798  is closed. As explained above, the tool joint may define a diameter that differs from (e.g., is larger than) the diameters of a remainder of the tool. As the tool joint passes through the annular BOP  1798  while the annular BOP  1798  is closed, the tool joint may force expansion of the packer  1804 , and thus, compression of the donut  1802 . This additional compression of the donut  1802  is detectable with the pressure or strain sensors  1812 . 
     The plot  1930  includes a first axis  1932  (e.g., x-axis) that represents time and a second axis  1934  (e.g., y-axis) that represents pressure or strain. The response of the donut  1802  over time is illustrated with the curve or line  1936 . As illustrated, the curve or line  1936  starts with the annular BOP  1798  already closed and the donut  1802  loaded to a desired pressure or strain level  1938 . During drilling operations, the tool may be pulled through the annular BOP  1798  while the annular BOP  1798  is closed. As the tool is pulled through the annular BOP  1798  while the annular BOP  1798  is closed, the tool joints that hold sections of the tool together are also pulled through the annular BOP  1798  while the annular BOP  1798  is closed. 
     Accordingly, as the tool joint passes through the annular BOP  1798  while the annular BOP  1798  is closed, contact between the tool joint and the packer  1804  may force or drive the packer  1804  radially outward. As the packer  1804  expands radially outward, the packer  1804  in turn causes compression of the donut  1802 . This compression of the donut  1802  is detected by the pressure or strain sensors  1812 , and this is reflected in portion  1940  (e.g., increasing; positive slop) of the curve or line  1936 . After the tool joint passes through the packer  1804 , the donut  1802  expands as the excess pressure is removed, which is detected by the pressure or strain sensors  1812  as a reduction in contact pressure. This reduction in pressure is reflected in portion  1942  (e.g., decreasing; negative slope) of the curve or line  1936 . The pressure or strain on the donut  1802  then increases as the diameter of the tool within the annular BOP  1798  returns to a steady state, which is reflected in portion  1944  (e.g., increasing; positive slope) of the curve or line  1936 . 
     However, in some situations, the pressure or strain on the donut  1802  may not return to the initial pressure or strain (e.g., the desired pressure or strain  1938 ); but instead, equalizes at a different pressure or strain seen at point  1946 . As illustrated, the pressure or strain on the donut  1802  may equalize at a lower pressure or strain. The reduction in the pressure or strain on the donut  1802  indicates that a next section of the tool (e.g., after the tool joint) may have a smaller diameter than the previous section of the tool (e.g., before the tool joint). By monitoring for the tool joint and a transition to a smaller diameter section of the tool, the detection system  1800  may determine information about the tool that may be provided to the operator and/or used to control other operations, including any of the other operations disclosed herein. Furthermore, in some embodiments, the controller  1814  may increase the hydraulic fluid pressure on the piston  1805  to drive the piston  1805  in the axial direction  1806  until the pressure or strain sensors  1812  output signals that indicate that the desired pressure or strain  1938  is reached (e.g., automated feedback loop). 
       FIG.  21    is a plot  1970  illustrating a contact pressure with respect to time for the donut  1802  of the annular BOP  1798 . The plot  1970  illustrates a response of the annular BOP  1798  to a passage of a tool joint through the annular BOP  1798  after closure. As explained above, as the tool joint pass through the annular BOP  1798 , the tool joint may force expansion of the packer  1804 , and thus, compression of the donut  1802 . This additional compression of the donut  1802  is detectable with the pressure or strain sensors  1812 . 
     The plot  1970  includes a first axis  1972  (e.g., x-axis) that represents time and a second axis  1974  (e.g., y-axis) that represents pressure. The response of the donut  1802  over time is illustrated with the curve or line  1976 . As illustrated, the curve  1976  starts with the annular BOP  1798  already closed and the donut  1802  loaded to a desired pressure level  1978 . During drilling operations, the tool may be pulled through the annular BOP  1798  while the annular BOP  1798  is closed. As the tool is pulled through the annular BOP  1798  while the annular BOP  1798  is closed, the tool joints that hold sections of the tool together are also pulled through the annular BOP  1798  while the annular BOP  1798  is closed. As the tool joint passes through the annular BOP  1798  while the annular BOP  1798  is closed, the tool joint may contact the packer  1804  and may force or drive the packer  1804  radially outward. The expansion of the packer  1804  radially outward causes compression of the donut  1802 . This compression of the donut  1802  is detected by the pressure or strain sensors  1812  and is reflected as portion  1980  (e.g., increasing; positive slope) in the curve or line  1976 . 
     After the tool joint passes through the packer  1804 , the donut  1802  expands as the excess pressure is removed, which is detected by the pressure or strain sensors  1812  as a reduction in contact pressure. This reduction in pressure is reflected in portion  1982  (e.g., decreasing; negative slope) of the curve or line  1976 . The pressure or strain on the donut  1802  then increases as the diameter of the tool within the annular BOP  1798  returns to a steady state, which is reflected in portion  1984  (e.g., increasing; positive slope) of the curve or line  1976 . 
     However, in some situations, the pressure or strain on the donut  1802  may not return to the initial pressure or strain (e.g., the desired pressure or strain  1978 ); but instead, equalizes at a different pressure or strain seen at point  1986 . As illustrated, the pressure or strain on the donut  1802  may equalize at a higher pressure or strain. The increase in pressure or strain on the donut  1802  indicates that a next section of the tool (e.g., after the tool joint) has a larger diameter than a previous section of the tool (e.g., before the tool joint). By monitoring for the tool joint and a transition to a larger diameter section of the tool, the detection system  1800  may determine information about the tool that may be provided to the operator and/or used to control other operations, including any of the other operations disclosed herein. Furthermore, in some embodiments, the controller  1814  may decrease the hydraulic fluid pressure on the piston  1805  to drive the piston  1805  opposite the axial direction  1806  until the pressure or strain sensors  1812  output signals that indicate that the desired pressure or strain  1978  is reached (e.g., automated feedback loop). 
     The sensors  1812  and the piston stroke sensor  1820  may also be utilized to assess the condition of the packer elements (e.g., the donut  1802  and/or the packer  1804 ) of the annular BOP  1798  in other ways. For example, the pressure and/or strain and the piston position may be used to identify wear on the packer  1804  and/or collapse of the donut  1802 . Thus, the detection system  1800  may carry out a packer wear detection process and/or a donut collapse detection process, as discussed in more detail below. 
       FIG.  22    is a plot  2050  illustrating a response of the donut  1802  with respect to a position of the piston  1805  (e.g., piston stroke length). The plot includes a first axis  2052  (e.g., x-axis) that represents the piston position (e.g., piston stroke length) and a second axis  2054  (e.g., y-axis) that represents pressure. The response of the donut  1802  is illustrated with curves  2056 ,  2058 , and  2060 . The curves  2056 ,  2058 , and  2060  represent actuation of the donut  1802  at different times, with the curve  2056  being at a first time, followed sequentially by the curve  2058  at a second time and then by the curve  2060  at a third time. In some embodiments, the curve  2056  may be considered a baseline or initial curve that establishes an expected behavior to seal about a tool with a particular diameter size without volume loss from the donut  1802  and/or the packer  1804 . 
     As illustrated, with each closure of the annular BOP  1798 , the piston  1805  moves a greater distance to reach a desired pressure or strain level  2062  on the donut  1802 . For example, the piston  1805  may have to move an additional distance  2064  at the second closure as compared to the first closure, an additional distance  2066  at the third closure as compared to the first closure. These changes represent a loss of material of the donut  1802  and/or the packer  1804 , which in turn represents overall volume loss from the donut  1802  and/or the packer  1804 . 
     In operation, the controller  1814  may detect these changes in the piston stroke distance and correlate them to the volume loss. It should be appreciated that the controller  1814  may utilize one or more algorithms, look up tables, or the like to determine the volume loss based on the piston position that achieves the desired pressure or strain level  2062 . The controller  1814  may be configured to provide an output to an operator to notify the operator of the detection of the volume loss and/or to provide an indication of the volume loss (e.g., a quantity or a percentage volume loss; a severity level). In some embodiments, the controller  1814  may be configured to provide a recommendation of a time to conduct maintenance operations (e.g., inspect, repair, or replace components) on the annular BOP  1798 . For example, in response to the piston position and/or the volume loss exceeding a threshold (e.g., the piston position and/or the volume loss varies by more than 5 percent compared to a most recent closure or a baseline closure), the controller  1814  may identify excessive volume loss and output the recommendation to replace the donut  1802  and/or the packer  1804 . With reference to  FIG.  22   , the additional distance  2064  may not exceed the threshold and may not result in the recommendation to replace the donut  1802  and/or the packer  1804 , while the additional distance  2066  may exceed the threshold and may result in the recommendation to replace the donut  1802  and/or the packer  1804 . 
     Furthermore, the controller  1814  may analyze trends over time (e.g., closures over time) and provide an output that indicates a prediction of a future time at which it is recommended to replace the donut  1802  and/or the packer  1804 . For example, even if the threshold is not exceeded, consistently increasing piston positions over a series of closures (e.g., increasing piston position for each closure in five consecutive closures) may enable the controller  1814  to estimate when the threshold will be exceeded and/or may result in the controller  1814  providing an indication to the operator (e.g., to notify the operator that the recommendation to replace may be provided after the next closure). 
     In some embodiments, the controller  1814  may access the data log, including the characteristics related to the diameter of the tool within the annular BOP  1798 , prior to providing the recommendation (e.g., to determine that the diameter has not changed and/or is unlikely to be a cause of the change in the piston position). Furthermore, the controller  1814  may assess a rate of the change and/or a pattern in the change to distinguish the change due to the diameter size of the tool from the change due to the volume loss (e.g., the change due to the diameter size of the tool may be relatively sudden and/or correlate with the data log that shows characteristics of the tool, while the change due to the volume loss may be gradual over time and/or not correlate with the data log). 
     In some embodiments, the controller  1814  may carry out a calibration step to account for a change in the diameter size of the tool and/or to identify the volume loss even as the diameter size of the tool within the annular BOP  1798  varies over time. For example, the controller  1814  may identify the diameter size of the section of the tool within the annular BOP  1798  (e.g., using the data log and/or other information, such as based on the detection and/or the counting of the tool joints), and then, the controller  1814  may compare the piston stroke length to reach the desired pressure or strain to an expected piston stroke length to reach the desired pressure or strain to assess the volume loss. With reference to  FIG.  24   , if the curve  2058  is the baseline curve that was obtained with a first pipe section of the particular diameter size, and the curve  2160  is obtained with the first pipe section or a second pipe section of the particular diameter size, then the controller  1814  may determine that there is a volume loss and/or assess the volume loss. 
       FIG.  23    includes plots  2070 ,  2072 ,  2074 , and  2076  that illustrate a response of the donut  1802  at different locations about the annular BOP  1798 . As explained above, the detection system  1800  may include multiple sensors  1812  that detect the pressure or strain of the donut  1802  at different locations  1840 .  FIG.  23    illustrates an example of feedback that may be provided from four different sensors  1812 . Accordingly, the plot  2070  represents the response of the donut  1802  at a first location as detected by a first sensor  1812 , the plot  2072  represents the response of the donut  1802  at a second location as detected by a second sensor  1812 , the plot  2074  represents the response of the donut  1802  at a third location as detected by a third sensor  1812 , and the plot  2076  represents the response of the donut  1802  at a fourth location as detected by a fourth sensor  1812 . Each plot includes an x-axis  2078  that represents the piston position (e.g., piston stroke length) and a y-axis  2080  that represents pressure or strain. Each plot includes curves  2082 ,  2084 , and  2086  that represent actuation of the donut  1802 . The curves  2082 ,  2084 ,  2086  may be at different times, with the curve  2082  being at a first time, followed sequentially by the curve  2084  being at a second time, and then by the curve  2086  being at a third time. 
     To facilitate understanding, the change in the piston position that would be needed to achieve the desired pressure or strain level  2088  at each location about the circumference is shown in each plot; however, it should be appreciated that in operation, the piston position would remain generally the same at each location about the circumference (e.g., the piston  1805  is annular and moves as one piece within the BOP housing  1807 ), and instead, the pressure may vary at the locations about the circumference for the piston positions at the different times due to the volume loss of the donut  1802  and/or the packer  1804 . 
     As explained herein, each time the annular BOP  1798  closes, the piston  1805  may need to move a greater distance to reach the desired pressure or strain level  2088  on the donut  1802  due to the volume loss of the donut  1802  and/or packer  1804 . However, the donut  1802  and/or packer  1804  may not experience uniform volume loss about the circumference. For example, different sections may experience different levels of volume loss. The difference in volume loss at different sections is illustrated in the plots  1870 ,  1872 ,  1874 , and  1876 . As illustrated, the distances  1890  and  1892  between the curves  1882 ,  1884 , and  1886  in the plots  1870  and  1874  are greater than the distances  1894  and  1896  between the curves  1882 ,  1884 , and  1886  in the plots  1872  and  1876 . The differences in these distances indicate more volume loss of the donut  1802  and/or packer  1804  on one side of the annular BOP  1798  (e.g., at the first sensor and the third sensor). For example, half of the donut  1802  and/or the packer  1804  may experience more volume loss than the other half. It should be appreciated that, instead, the difference in volume loss at the different sections may be indicated by the pressure varying at the locations about the circumference for the piston positions at the different times. 
     As explained herein, the resolution of the detection system  1800  may increase with additional sensors  1812 . In other words, additional sensors  1812  enable the detection system  1800  to detect which portions of the donut  1802  and/or the packer  1804  experience volume loss and/or a degree of the volume loss. This may enable the controller  1814  to detect the wear even if only present at a portion of the donut  1802  and/or the packer  1804 . This may enable the controller  1814  to provide an output indicative of the volume loss and/or the locations of the volume loss (e.g., a heat map that represents the volume loss) and/or to provide a recommendation to conduct maintenance operations on the annular BOP  1798 , among other actions disclosed herein. The controller  1814  may also control other operations, such as to stop stripping operations, to close a ram BOP, or the like, based on the volume loss and/or uneven volume loss. 
     It should be appreciated that the volume loss may be severe enough to cause collapse of the donut  1802  and/or other factors may occur to cause the collapse of the donut  1802 . The collapse of the donut  1802  may result in the donut  1802  buckling, usually on one side of the donut  1802 . The detection system  1800  may be configured to identify the collapse of the donut  1802 , as discussed in more detail below. 
       FIG.  24    is a plot  2150  illustrating a response of the donut  1802  with respect to a position of the piston  1805  (e.g., piston stroke length). The plot includes a first axis  2152  (e.g., x-axis) that represents the position of the piston  1805  (e.g., piston stroke length) and a second axis  2154  (e.g., y-axis) that represents pressure or strain. The response of the donut  1802  is illustrated with curves  2156 ,  2158 , and  2160 . The curves  2156 ,  2158 , and  2160  represent actuation of the donut  1802  at different times, with the curve  2156  being at a first time, followed sequentially by the curve  2158  at a second time and then by the curve  2160  at a third time. In some embodiments, the curve  2156  may be considered a baseline or initial curve that establishes an expected behavior to seal about a tool with a particular diameter size without collapse of the donut  1802  and/or the packer  1804 . 
     As illustrated, with each closure, the piston  1805  moves a greater distance to reach the desired pressure or strain level  2162  on the donut  1802 . For example, the piston  1805  may have to move an additional distance  2164  at the second closure compared to the first closure, and an additional distance  2166  at the third closure compared to the first closure. The changes in the position of the piston  1805  to reach the desired pressure or strain level  2162  may indicate volume loss of the donut  1802  and/or the packer  1804 , as discussed above with respect to  FIG.  22   . 
     In response to the piston position and/or the volume loss exceeding an additional threshold (e.g., the piston position and/or the volume loss varies by more than 10 percent compared to a most recent closure or a baseline closure), the controller  1814  may identify the collapse of the donut  1802  and output the recommendation to replace the donut  1802  and/or the packer  1804 . In some embodiments, the controller  1814  may identify the collapse of the donut  1802  in response to at least one significant difference between a previous response curve and a current response curve, such as at least one of a difference  2167  in a maximum contact pressure sensed by the sensor  1812  and a difference  2169  in the maximum distance of the piston stroke length. As illustrated, the difference  2167  illustrates a significant drop (e.g., greater than a pressure threshold, such as 5 percent or 10 percent) between the maximum pressure of the curve  2160  and the maximum pressure of the curve  2168 . This significant drop is indicative of a loss of contact between the sensor  1812  and the donut  1802  due to significant material loss (e.g., volume loss). The loss of contact inhibits the ability of the sensor  1812  to accurately detect pressure or strain on the donut  1802  and/or the ability of the donut  1802  to transfer pressure to the sensor  1812 . 
     In the illustrated embodiment, the decrease in the maximum pressure is accompanied by a significant increase (e.g., greater than the additional threshold) in the piston stroke length. As illustrated, the difference in the piston stroke length between the curve  2158  and the curve  2160  is significantly less than the difference in the piston stroke length  2169  between the curve  2160  and the curve  2168 . The significant increase in the piston stroke length  2069  is similarly indicative of significant material loss in that the piston  1805  has to move a significant distance to drive the donut  1802  to achieve even the lower pressure. In some embodiments, the controller  1814  may identify the collapse of the donut  1802  when the difference  2167  exceeds the pressure threshold and/or when the difference  2169  exceeds the additional threshold. It should be appreciated that any of the techniques disclosed with reference to  FIGS.  22  and  23    may be applied in the context of the collapse of the donut  1802  (e.g., the calibration step, the operations). 
       FIG.  25    illustrates plots  2170 ,  2172 ,  2174 , and  2176  that illustrate a response of the donut  1802  at different locations about the annular BOP  1798 . As explained above, the detection system  1800  may include multiple sensors  1812  that detect the pressure or strain of the donut  1802  at different locations  1840 , and thus, whether different portions of the donut  1802  have experienced collapse.  FIG.  25    illustrates an example of feedback that may be provided from four different sensors  1812  during collapse of the donut  1802 . Accordingly, the plot  2170  represents the response of the donut  1802  at a first location as detected by a first sensor  1812 , the plot  2172  represents the response of the donut  1802  at a second location as detected by a second sensor  1812 , the plot  2174  represents the response of the donut  1802  at a third location as detected by a third sensor  1812 , and the plot  2176  represents the response of the donut  1802  at a fourth location as detected by a fourth sensor  1812 . Each plot includes an x-axis  2178  that represents the piston position (e.g., piston stroke length) and a y-axis  2180  that represents pressure or strain. Furthermore, each plot includes curves  2182 ,  2184 ,  2186 , and  2187  that represent actuation of the donut  1802  at different times, with the curve  2182  being at a first time, followed sequentially by the curve  2184  at a second time, the curve  2186  at a third time, and the curves  2187  at a fourth time. 
     To facilitate understanding, the change in the piston position that would be needed to achieve the desired pressure or strain level  2188  at each location about the circumference is shown in each plot; however, it should be appreciated that in operation, the piston position would remain generally the same at each location about the circumference (e.g., the piston  1805  is annular and moves as one piece within the BOP housing  1807 ), and instead, the pressure may vary at the locations about the circumference for the piston positions at the different times due to the volume loss of the donut  1802  and/or the packer  1804 . 
     As explained above, each time the annular BOP  1798  closes, the piston  1805  may move a greater distance to reach the desired pressure or strain level  2188  on the donut  1802  due to the volume loss of the donut  1802  and/or packer  1804 . However, the donut  1802  and/or the packer  1804  may not experience uniform volume loss about the circumference. For example, different sections about the circumference may experience different levels of volume loss. Furthermore, different sections about the circumference may behave differently under collapse of the donut  1802 , as only one side of the donut  1802  may buckle during the collapse. 
     The differences at the different sections about the circumference is illustrated in the plots  2170 ,  2172 ,  2174 , and  2176 . As illustrated, the distances  2190  and  2192  between the curves  2182 ,  2184 , and  2186  in the plots  2170  and  2174  are greater than the distances  2194  and  2196  between the curves  2182 ,  2184 , and  2186  in the plots  2172  and  2176 . These differences in distances indicate more volume loss and/or different behavior of the donut  1802  and/or the packer  1804  on one side of the annular BOP  1798  (e.g., at the first sensor and the third sensor) as compared to an opposite side of the annular BOP  1798  (e.g., at the second sensor and the fourth sensor). For example, one half of the donut  1802  and/or the packer  1804  may experience more volume loss and/or buckling, while the other half of the donut  1802  and/or the packer  1804  may experience less volume loss and/or no buckling. Such uneven measurements, particularly with significant changes only on one side (e.g., one half) and either minimal or no changes on the other side (e.g., the other half), may indicate the collapse of the donut  1802 . It should be appreciated that, instead or in addition, the collapse of the donut  1802  may be indicated by the difference  2198  in the pressure at the locations about the circumference for the piston positions at the different times. For example, the collapse of the donut  1802  may be indicated by the pressure at the first location and the third location being less (e.g., significantly less) than the pressure at the second location and the fourth location for a given position of the piston  1805 . It should also be appreciated that the donut  1802  and/or the packer  1804  may shift within the annular BOP  1798  upon the collapse of the donut  1802 , such that the piston stroke length decreases and/or the pressure increases on one side, while the piston stroke length increases and/or the pressure decreases on the other side with the collapse of the donut  1802 . 
     As explained herein, the resolution of the detection system  1800  may increase by including additional sensors  1812 . In other words, additional sensors  1812  may enable the detection system  1800  to detect which portions of the donut  1802  and/or the packer  1804  have collapsed. This may enable the controller  1814  to detect the collapse even if only a portion of the donut  1802  and/or the packer  1804  have collapsed. This may enable the controller  1814  to provide an output indicative of the collapse and/or the locations of the collapse (e.g., an image that represents the collapse) and/or to provide a recommendation to conduct maintenance operations on the annular BOP  1798 , among other actions disclosed herein. The controller  1814  may also control other operations, such as to stop stripping operations, to close a ram BOP, or the like, based on the collapse. 
     While the disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. Rather, the disclosure is intended to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims. Indeed, any features shown in or described with reference to  FIGS.  1 - 25    may be combined in any suitable manner. Furthermore, it should be appreciated that the detection system may be utilized with any of a variety of types of equipment, including with any of a variety of types of annular BOPs.