The present invention relates to a method of, and system for, performing a reaming operation at a wellsite. The wellsite may be equipped with a rig with a drilling tool deployed from the rig and advanced/advancing into a subterranean formation to create a wellbore. An underreamer may be carried by the drilling tool to expand the wellbore.

Drilling tools are advanced into the earth to form wellbores and reach subsurface targets. In the oil and gas industry, drilling tools are used to create wellbores to reach subsurface reservoirs for production of fluids, such as hydrocarbons, to the surface. These drilling tools include a bottom hole assembly and a bit deployed from a surface rig by a drill string. A drilling assembly is provided at the surface rig to connect stands of pipe in series to form the drill string, and to advance and rotate the bit.

The drilling tool may be provided with various components, such as power, communication, testing, and data collection devices. For example, the drilling tool may be provided with measurement while drilling and logging while drilling devices for collecting downhole data. The drilling tool may also be provided with telemetry devices for communication with a surface unit at the rig.

The drilling tool may also be provided with other components, such as an underreamer, for performing downhole functions. The underreamer may be positioned on the drilling tool a distance uphole from the bit to widen the wellbore formed by the bit.

Despite the advancements in drilling technology, there remains a need for developing techniques for detecting potential failures that may occur during drilling. The present disclosure is directed at addressing such needs.

SUMMARY

In at least one aspect, the present invention provides method of performing a reaming operation at a wellsite, the wellsite having a rig with a drilling tool deployed from the rig, the method comprising:

- advancing the drilling tool into a subterranean formation to create a wellbore, comprising drilling into the subterranean formation with the drilling tool and reaming the wellbore with an underreamer carried by the drilling tool;

- measuring surface drilling parameters comprising surface torque and surface weight on bit from surface sensors positioned about the rig; - measuring downhole drilling parameters comprising downhole weight on bit and downhole torque from downhole sensors positioned about the drilling tool;

- generating a weight on reamer parameter from the measured surface weight on bit and the measured downhole weight on bit;

- generating a frictional torque parameter by detecting from the surface sensors when the drilling tool is in a rotating off bottom state and selecting a portion of the measured surface torque measured during the rotating off bottom state;

- generating a torque on reamer parameter from the frictional torque parameter, the downhole torque parameter, and the surface torque; and

- detecting reamer performance by monitoring changes in at least one reamer performance metric, the at least one reamer performance metric comprising an integration of the torque on reamer parameter with the weight on reamer parameter.

In another aspect, the invention provides system for performing a reaming operation at a wellsite, the wellsite having a rig with a drilling tool deployed from the rig, the system comprising:

- a drilling tool comprising at least a drill bit and carrying at least an underreamer;

- draw works for suspending and advancing the drilling tool into a subterranean formation to create a wellbore, whereby reaming the wellbore with the underreamer;

- surface sensors positioned about the rig and configured to measure surface drilling parameters, comprising surface torque and surface weight on bit;

- downhole sensors positioned about the drilling tool and configured to measure downhole drilling parameters, comprising downhole weight on bit and downhole torque;

- a processor configured to:

- generate a weight on reamer parameter from the measured surface weight on bit and the measured downhole weight on bit;

- generate a frictional torque parameter by detecting from the surface sensors when the drilling tool is in a rotating off bottom state and selecting a portion of the measured surface torque measured during the rotating off bottom state;

- generate a torque on reamer parameter from the frictional torque parameter, the downhole torque parameter, and the surface torque; and

- detect reamer performance by monitoring changes in at least one reamer performance metric, the at least one reamer performance metric comprising an integration of the torque on reamer parameter with the weight on reamer parameter. BRIEF DESCRIPTION DRAWINGS

So that the above recited features and advantages can be understood in detail, a more particular description, briefly summarized above, may be had by reference to the embodiments thereof that are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate example embodiments and are, therefore, not to be considered limiting of its scope. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale or in schematic in the interest of clarity and conciseness.

Figure 1A is a schematic view, partially in cross-section, of a wellsite including surface and subsurface drilling equipment for drilling a wellbore, the subsurface equipment including a downhole drilling tool.

Figure IB is a detailed view of a portion IB of the downhole drilling tool of Figure 1A depicting an underreamer.

Figure 2 is a flow chart depicting a method of performing a reamer operation at the wellsite.

Figure 3 is a flow chart depicting another version of the method of performing the reamer operation at the wellsite.

Figures 4A-4F are graphs depicting drilling parameters generated from

measurements taken by sensors at the wellsite.

Figures 5A - 5C are graphs depicting reamer performance metrics generated from the drilling parameters.

DETAILED DESCRIPTION

The description that follows includes exemplary systems, apparatuses, methods, and instruction sequences that embody techniques of the inventive subject matter.

However, it is understood that the described embodiments may be practiced without these specific details.

The disclosure relates to methods of reaming a wellbore and monitoring such reaming. The term "reaming" as used herein refers to the process of drilling a pilot hole with a drill bit to form a wellbore, while enlarging the pilot hole with a reamer to enlarge the wellbore.

A drilling tool is provided with a bit to drill the wellbore and an underreamer to enlarge the wellbore. Non- limiting examples of underreamers are provided in

Patent/Application publication Nos. US2014/0182934, US2015/0322767, US2010/0139981, US2011/0166837, US2014/0251687, US2011/0247878,

US2004/0064258, US2005/0211470, US2010/0259415, EP3012671, WO2014/142783, the entire contents of which are hereby incorporated by reference herein.

The drilling tool and the underreamer are subject to weight and torque forces applied from surface equipment. Sensors may be provided about the surface and downhole equipment for measuring drilling parameters, such as weight on bit and torque on bit. Reamer parameters, such as weight on reamer, may be determined from the measurements at the wellsite. Conventional reamer monitoring may consider axial loading at the underreamer by examining weight on reamer determined directly from the surface and downhole weight on bit measurements, or by examining mechanical specific energy and rate of penetration. To consider additional influences and/or to provide indicators independent of variations in the weight on bit which may be caused by other drilling factors (e.g., drill bit efficiency and/or drilling lithologies), the present disclosure considers multiple drilling parameters, such as a combination of torque and weight parameters.

The present disclosure defines reamer performance metrics by integrating the drilling parameters in a way that considers a combination of drilling forces, such as weight forces (e.g., weight on reamer) and torque forces (e.g., torque on reamer), applied to the

underreamer. These reamer performance metrics may be monitored to determine potential defects in reamer operations. Changes in the reamer performance metrics may indicate potential changes in drilling conditions and/or equipment failure beyond normal wear and tear.

Detection of potential changes in the reamer performance metrics provides an opportunity to detect potential issues before or when they occur. Consequences of these potential issues may include, for example, extra trips to change out failed underreamers, out of specification (e.g., under-gauged) hole sections, inability to pass equipment through reamed hole sections, required re-design of wellsite operations, risks to wellsite integrity, failure of the wellbore, etc. Failures of equipment, such as the underreamer may cause equipment damage, drilling delays, and/or other drilling impacts that may impose higher drilling costs and/or operational delays.

The present disclosure seeks to predict and/or detect potential reamer failures, thereby providing early warning of defects in the drilling/reaming operations with greater accuracy. For example, reamer failures may be detected from the reamer performance metrics. Such reamer failures may be any failure that prevents the reamer from reaming the wellbore as intended, such as failure to enlarge a pilot hole formed by the drill bit to a specified diameter.

Figure 1A shows a wellsite 100 including surface and subsurface drilling equipment 102a,b for forming a wellbore 104 in the subterranean formation 106. While a specific example is depicted as an onshore location, the wellsite 100 may be on or offshore. The surface equipment 102a includes a rig 108, a rotary table 110, a drilling assembly 111, and a surface unit 112a. The rotary table 110 is positioned on a surface location with the rig 108 supported thereon. The rig 108 supports the drilling assembly 111 above the rotary table 110. The drilling assembly 111 includes devices for connecting portions of the downhole equipment 102b for deployment into the wellbore 104.

The drilling assembly 111 includes a top drive 114, an elevator 116, a traveling block 118, and a pipe handler 120. The top drive 114 is movably supported from the rig 108 by the traveling block 118. The elevator 116 and pipe handler 120 support and move stands of pipe and other portions of the subsurface equipment 102b in position about the rotary table 110 for assembly/disassembly. A surface sub 122 may be positioned at the rotary table 110 below the pipe handler 120 for receiving the stands of pipe. The pipe handler 120 may be used to threadedly connect the stands of pipe to the subsurface equipment 102b.

The subsurface equipment 102b includes a drilling tool 124 supported from the rotary table 110. The drilling tool 124 may include a bit 126, a bottom hole assembly (BHA) 127, and a drill string 130. The bit 126 may be a roller cone, matrix or other bit capable of engaging the subterranean formation 106 and removing cuttings to form the wellbore 104. The drill bit 126 may be driven by a motor in the BHA 127.

The BHA 127 may include various components for performing downhole functions, such as drilling, measuring, communicating, etc. The BHA 127 may be a modular unit with one or more subs capable of performing the various functions. For example, the BHA 127 may have one or more components, such as a mud pulse telemetry unit 129a, a power supply, a measurement unit (e.g., measurement while drilling (MWD) 129b, logging while drilling (LWD), etc. As shown, the BHA 127 may have the telemetry unit 129a and the MWD unit 129b.

The drill string 130 includes a series of tubulars, such as drill pipe, connected to form an elongate tubular string for the passage of fluids and/or for supporting equipment used in drilling. A surface end of the drill string 130 may be connected to the surface sub 122. The drilling assembly 111 may be used to apply forces to the drilling tool 124 to facilitate drilling. For example, the drilling assembly 111 may apply a downhole force (or weight) to the drill string 130 to advance the drilling tool 124 downhole as indicated by the wide downward arrow. The drilling assembly 111 may also apply a rotational force (or torque) to the drill string 130 to rotate the drilling tool 124 as indicated by the wide curved arrows.

A mud pit 131 may be provided at the surface for passing mud through the drill string 130, the BHA 127, and out the bit 126 as indicated by the arrows. Cuttings may be returned to the surface through an annulus 132 between the drilling tool 124 and a wall of the wellbore 104 as also indicated by arrows.

The surface and subsurface equipment 102a,b may include communication devices for passing signals. As shown by the dashed lines, communication links 134 may be established to pass signals between the drilling assembly 111, the drilling tool 124, the surface unit 112a, and/or other locations, such as remote location 112b. Communication may be through wired or wireless means, such as wired drill pipe, mud pulse,

electromagnetic, and/or other telemetry. For example, the BHA 127 may be provided with mud pulse telemetry driven by mud flow for sending pulse signals to the surface unit 112a. Cables may also be provided to communicatively connect various equipment, such as the surface torque sensor 128d and the surface unit 112a. The communication links 134 may be used to pass power, communication, data, and/or other signals.

The surface unit 112a and/or remote location 112b may act as a central unit provided with various equipment, generally indicated at 113a and 113b, such as processors (CPUs), displays, input/output devices, databases, transceivers, encoders, and/or other electronics, for communication with various locations about the wellsite 100 and/or remote locations 112b. The central unit may be provided with devices to send, receive, process, translate, filter, convert, and/or otherwise process data. The central unit may be operated by an operator and/or have automated control capabilities. The central unit may be coupled to one or more measurement devices for receiving data therefrom. The central unit may also have one or more processors (e.g., CPUs) for determining outputs, making decisions, and/or taking action at the wellsite. Action may be taken, for example, by allowing the central unit to activate and/or adjust operations at the wellsite.

The central unit(s) may be in communication with one or more measurement devices, such as sensors, gauges, and/or other devices, positioned about the wellsite 100 for measuring wellsite parameters. As shown, the surface equipment 102a may include surface sensors 128a-d for measuring drilling parameters. These surface sensors 128a-d include a hook load sensor 128a, draw works sensor 128b, a top drive sensor 128c, and a torque sensor 128d. As shown, the subsurface equipment 102b may include downhole sensors 128e,f for measuring drilling parameters. These downhole sensors 128e,f include a measurement while drilling (MWD) tool 128e and a bit sensor 128f. Sensors may also be provided for measuring other wellsite parameters, such as temperature, pressure, and/or other parameters. While specific examples of sensors 128a-f are shown, a variety of sensors may be positioned about the wellsite for measuring various wellsite parameters.

During drilling, the bit 126 and the BHA 127 are advanced into the wellbore 104 by the drill string 130. The drill string 130 is extended and driven by rotationally adding tubulars to an uphole end of the drill string 130 using the drilling assembly 111. During drilling and/or during breaks in drilling, the sensors 128a-f may collect measurements which may be used to monitor the performance of the drilling tool 124 as described further herein.

Wellsite parameters may be generated, for example, from measurements (e.g., using sensors at the wellsite), third party sources (e.g., from customer data and/or other sources), observations, extractions (e.g., calculated from other parameters), and/or from other means. The wellsite parameters may include drilling, fluid, equipment, formation, and/or other parameters.

Drilling parameters may be properties of the formation, equipment, operations, etc., that may affect drilling. Fluid parameters may be properties of the drilling fluid pumped through the drilling equipment. Equipment parameters may be type, size, settings, and/or other properties of the wellsite equipment. Formation parameters may be type of rock, dimensions of formation layers, reservoir, and/or other properties of the formation. One or more properties may be part of the drilling, equipment, formation, and/or other wellsite parameters.

Examples of surface drilling parameters include surface weight on bit (SWOB), schematically indicated at 151; surface torque (STRQ), schematically indicated at 152; block position (BPOS), and surface revolutions per minute (SRPM). SWOB 151 may be the downhole (or downward) force exerted on the drill bit as indicated by the wide downward arrows as measured by surface sensors, such as the hook load sensor 128a. The STRQ 152 may be the moment applied by the surface equipment to rotate the downhole tool as measured by the torque sensor 128d on the top drive (i.e., the amount the top drive motor may work to overcome friction and rotate the drilling tool to cut the formation). The BPOS may be the movement of the traveling block as measured by the draw works sensor 128b (e.g., encoder) and/or change in bit depth. The SRPM may be the rotation (or spin) of the downhole tool as measured by the top drive sensor 128c.

Examples of downhole drilling parameters that may be measured at the wellsite using the downhole equipment may include downhole weight on bit (DWOB), schematically indicated at 153; and downhole torque (DTRQ), schematically indicated at 154. DWOB 153 is the downhole (or downward) force exerted on the drill bit as indicated by the wide downward arrows as measured from subsurface sensor(s), such as the MWD tool 128e. The downhole torque may be the moment applied to the downhole tool as measured by the subsurface sensor(s), such as the MWD tool 128e.

From these measured drilling parameters, additional drilling parameters may be extracted, such as rate of penetration (ROP), and/or other parameters. For example, the ROP may be the speed at which the drill bit breaks the rock as determined by measuring the time to drill from a first drilling depth to a second drilling depth.

Other drilling parameters may be determined from the surface and/or subsurface equipment, such as bit depth (Db) and hole depth (Hd), schematically indicated at 155. The Db and Hd may be the distance from the surface to a bottom of the wellbore 104. These depths may be determined, for example, by measurements taken by downhole sensors, such as MWD and/or survey components. The Db and Hd may also be determined by adding lengths of each piece of equipment (e.g., drill pipes, bit, and BHA) used to form the downhole tool.

The various parameters detected by the sensors may be used to determine certain states of the wellsite. For example, BPOS, Db, Hd, ROP, and SRPM may be used to determine if the drill bit is rotating. If the BOPS, Db, Hd, ROP are changing or if SRPM shows a positive number, this may indicate the downhole tool is moving. This may be used to determine a rig state when the drilling tool is rotating off bottom (RTOB), i.e. when the bit and reamer are rotating, but are not in engagement with the wellbore.

In the RTOB position, it is assumed that there is no friction generated by the bit and underreamer, thereby providing a surface torque that equals a frictional torque. In this

RTOB state, a linear regression of the measured STRQ and DTRQ may be performed to extract a frictional torque (FTOR). Time-based FTOR samples may be converted to a depth domain and a regression performed to derive a relationship between the FTOR and depth. For example, the torque measurements identified as being measured when the drilling tool is in the RTOB state may be averaged. The result is FTOR. This information may be further refined to provide a further understanding of the wellsite and/or individual equipment, such as the underreamer.

Figure IB shows a detailed view of a portion of the drilling tool 124 of Figure 1 A.

As shown by Figures 1A and IB, the drilling tool 124 may include an underreamer 138. The underreamer 138 as shown includes cutter blocks 140 radially expandable about the drill string 130 as indicated by the radial arrows. The cutter blocks 140 expand to a diameter D' wider than a diameter D of a pilot hole drilled by the drill bit 126. The cutter blocks 140 may be provided with a hardened surface for engagement with a wall of the wellbore 104. This engagement may be used to break away portions of the subterranean formation 106 to remove cuttings which are carried away through the annulus with drilling mud.

The forces applied to the drilling tool 124 during drilling, such as the surface weight and torque applied by the drilling assembly 111, may be partially used by the underreamer 138 to engage and cut away portions of the subterranean formation 106 to expand the wellbore 104. The weight and torque from the surface may be applied onto underreamer 138 and drill bit 126. As shown in Figure IB, the drilling tool 124 receives the downward and rotational forces from the surface equipment as indicated by the wide downward and curved arrows, respectively.

The forces applied to the underreamer 138 may be extracted from the forces applied to the drilling tool 124. The torque and surface weight on bit force applied to the underreamer 138 are referred to as torque on underreamer (or TOR, schematically indicated at 156) and a weight on underreamer (or WOR, schematically indicated at 157), respectively. For example, the WOR may be determined from the measured SWOB 151 and the DWOB 153 as follows:

WOR = SWOB - DWOB (1)

The WOR 157 may be monitored to determine potential problems with the reamer.

Examples of reamer monitoring and/or analysis is described in Patent/ Application publication Nos. US2015/0081221, US2014/0326449, US2014/0182934,

US2015/0322767, US2010/0139981, US2011/0166837, US2014/0251687,

US2005/0273302, US2011/0247878, US2004/0064258, US2005/0211470, US2010/0259415, US2010/0133008, US2011/020410, EP3012671, and WO 2014142783, the entire contents of which are hereby incorporated by reference herein.

To provide a more complete evaluation of reamer performance, additional factors to WOR may also be considered. Additional factors, such as torque, may be used to provide indicators independent of variations in the weight on reamer caused by other drilling factors (e.g., drill bit efficiency and/or drilling lithologies). For example, both weight on reamer and torque on reamer may be integrated to predict potential reamer issues. The TOR 156 may be determined from the FTOR and the measured STRQ and DTRQ as follows:

TOR = STRQ - DTRQ - FTOR (2) The TOR may provide an unloading torque and drag model of how difficult drilling may be, and/or when it is time to clean the hole. If WOR remains constant while TOR drops significantly, it may indicate a problem with underreamer cutter being worn out and losing cutting capabilities.

By integrating the WOR and TOR, underreamer metrics may be determined which may be used as an indicator of underreamer performance. Examples of such metrics include weight load ratio (WLR), reamer aggressiveness (Ar), and a reamer wear factor (WFr). WLR may be a measure of the weight distribution between the underreamer and the bit determined as follows:

WLR = WOR/SWOB (3) Ar may be a measure of the cutter aggressiveness of the reamer determined as follows:

Ar = TOR/WOR (4)

WFr may be a factor used to indicate potential wear of the cutter blocks. The WFr may be determined from the calculated WOR and the depth of cut (DOC) of the underreamer as follows: WF _r = WOR/DOC (5)

DOC = ROP/RPM (6)

The WFr may be multiplied by a constant for unit conversion as needed. The WFr may be sensitive to cutter wipe out failure and serve as an indicator of potential reamer failure. The reamer performance metrics may be monitored over time to determine trends. Normal values for the underreamer factors may be learned during healthy operating conditions. Variations from the normal values (or abnormal behaviors), such as increases in the WFr, may be detected over time. Deviations from the normal values may be determined over time to evaluate potential equipment failures. Such information may be fed back to the wellsite (e.g., surface unit 112a) to notify operators.

In cases where a portion of the wellbore being drilled and reamed comprises multiple formation layers with varying compressive rock strength, the metrics may be applied for each of the formation layers based on measurements (e.g., gamma ray, sonic, etc.) by downhole sensors, such as the MWD tool 128e. Trends may be compared for measurements taken along the same formation layers for a depth interval where both the bit and underreamer are drilling the same formation layer, thereby eliminating the effects of changes in the formation layers.

During hole enlargement while drilling, when one or more of the drilling efficiency metrics exceeds predetermined threshold values, a warning may be generated indicating that the underreamer has an alert condition. Such an alert condition may indicate that the underreamer is undergoing damage and/or more than normal wear and tear. Such a condition persisting over time may give confidence that the underreamer may be likely to fail, and/or provide an indication that an under-gauged hole section may have been reamed.

Figure 2 is a flow chart schematically depicting an example method 200 of monitoring an underreamer. In this example, the method 200 involves 248 - measuring drilling parameters. The measuring 248 may involve generating 248a - surface drilling measurements (e.g., SWOB, STRQ, , SRPM, BPOS, Db, Hd, ROP, F, etc.) and 248b - downhole drilling measurements (e.g., DWOB, DTRQ, etc.). Part or all of these measurements may be generated by measurements from the surface and downhole sensors at wellsite 100 as schematically shown. The method may also involve 248c - collecting additional information, such as wellsite information (e.g., hole size, bit diameter, reamer diameter, well surveys, equipment specifications, wellsite conditions, customer requirements, etc.), which may be input as schematically shown.

The method 200 continues with 250 generating drilling parameters. The drilling parameters may be generated by combining, filtering, classifying, coding, formatting, and/or otherwise adjusting the measured and/or collected drilling and/or wellsite parameters. The drilling parameters may be adjusted on or offsite (e.g., at the surface unit 112a or the remote location 112b). For example, calibrations may be performed during operations to classify certain measurements as 'normal' or 'abnormal' based on known operating conditions. The processing may be performed onsite and/or offsite by one or more operators, experts, and/or managers, and/or by processors (e.g., CPUs) capable of performing the processing functions.

The processed drilling parameters may then be used to generate various 251 underreamer parameters, such as weight parameters 252a, torque parameters 252b, velocity drilling parameters 252c, and/or other parameters. The weight parameters 252a as shown include measured weight on bit (SWOB, DWOB) 252al, and weight on reamer (WOR) 252a2 which may be determined using Equation (1). The torque parameters 252b may include 252b 1 FTRQ which may be determined from the drilling parameters 250, and 252b2 TOR which may be determined from the FTRQ and the drilling parameters using Equation (2). The velocity drilling parameters 252c may include other measured drilling parameters, such as ROP, WLR, and RPM.

The method continues with 254 - generating reamer performance metrics, such as

WLR, Ar, and WFr. The reamer performance metrics 254 may be determined from a combination of the underreamer parameters 251 using the Equations (3) - (6). This information may be fed back to the wellsite 100 as schematically indicated by the arrows.

Figure 3 is a flow chart 300 depicting another version of the method of performing a drilling while reaming operation at a wellsite. The method involves 360 - advancing the drilling tool into the subterranean formation to form a wellbore as shown in Figure 1A. The method continues with 362 - measuring surface drilling parameters comprising surface torque (STRQ) and surface weight on bit (SWOB) from surface sensors positioned about the rig, and 364 - measuring downhole drilling parameters comprising downhole weight on bit (DWOB) and downhole torque (DTRQ) from downhole sensors positioned about the drilling tool as shown, for example, in Figure 2 (248b). The method continues with 370 - generating weight on reamer (W OR) from the measured surface weight on bit (SWOB) and the measured downhole weight on bit (DWOB) (see, e.g., Equation (1)).

The method continues with 372 - generating frictional torque (FTRQ) by detecting from the surface sensors when the drilling tool is operating in a rotating off bottom (RTOB) state, selecting the portion of the measured surface torque (STRQ) and the downhole torque (DTRQ) measured when the drilling tool is operating in the RTOB state, and combining the selected portion of the measured surface torque (STRQ) and the measured downhole torque (DTRQ). Next, the method involves 374 - generating torque on reamer (TOR) from the fnctional torque (FTOR), the surface torque (STRQ), and the downhole torque (DTRQ) (see, e.g., Equation (2)).

The method continues with 376 - generating reamer performance metrics (WLR, Ar, WFr) by integrating the torque on reamer (TOR) with the weight on reamer (WOR). The generated reamer performance metrics may be communicated to the wellsite for 378 - adjusting the drilling based on the generated underreamer performance metrics.

The method may also involve 366 - processing the measured surface and downhole parameters, the processing comprising at least one of filtering, coding, translating, and combinations thereof and/or 368 - communicating the downhole drilling parameters and the surface drilling parameters to a central unit (e.g., surface unit 112a and/or the remote location 112b).

Other processes may be performed with the method. The methods may be performed in any order, and repeated as desired.

EXAMPLE

A reamer operation for a drilling tool is monitored during a drilling operation during drilling of a portion 480 of a wellbore at a depth from 19,000 to 19,400 feet (5790 to 5910 m). Sensors at the wellsite provide measurements as shown in Figures 4A-F for SWOB, DWOB, STRQ, DTRQ, ROP, and RPM, respectively. The corresponding reamer performance metrics are shown in Figures 5A-C for reamer wear factor, weight load ratio, and reamer aggressiveness, respectively.

[0001] Based on the data in Figures 4A-4F and 5A-5C, the averaged values for the portion 480 of the wellbore are as shown in Table I below:

TABLE I

Monitoring is performed at each of the settings in Table II below:

TABLE II

All of the above three types are used to identify abnormal behaviors of the three reamer performance metrics at depth Dr at 19700 ft (6000 m). As shown by Figures 5A-5C, increases in the reamer wear factor and weight load ratio, and a decrease in the reamer aggressiveness are detected.

The results may be used to generate a warning indicating a potential reamer failure at the depth Dr. The results also demonstrate that WFr is sensitive to reamer wipe-out failure in a hard formation. An order of magnitude value increase of the WFr is observed in reamer failure events.

While the embodiments are described with reference to various implementations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible. For example, various sensors may be used to generate various parameters for consideration in the reamer performance metrics.

The methodologies and systems proposed herein can generally be employed in a method of performing a reaming operation at a wellsite. The wellsite may have a rig with a drilling tool deployed from the rig. The drilling tool may be advanced into a subterranean formation to create a wellbore. The rig may be positioned on the subterranean formation. An underreamer is carried by the drilling tool to expand the wellbore.

The method and system generally involve measuring surface drilling parameters comprising surface torque and surface weight on bit from surface sensors positioned about the rig, measuring downhole drilling parameters comprising downhole weight on bit and downhole torque from downhole sensors positioned about the drilling tool, and generating a weight on reamer parameter from the measured surface weight on bit and the measured downhole weight on bit. The method and system also involve generating a frictional torque parameter by detecting from the surface sensors when the drilling tool is in a rotating off bottom state and selecting a portion of the measured surface torque measured during the rotating off bottom state. The method continues with generating a torque on reamer parameter from the frictional torque, the downhole torque, and the surface torque, and the system has a processor configured to generate the same. The method continues with detecting reamer performance by monitoring changes in at least one reamer performance metric, and the processor is configured to detect the same. The reamer performance metric comprises an integration of the torque on reamer with the weight on reamer.

Generating the frictional torque parameter may comprise selecting the portion of the measured surface torque for a portion of the wellbore drilled during the rotating off bottom state. Generating the torque on reamer parameter may comprise removing the measured downhole torque and the generated frictional torque from the measured surface torque. Generating the weight on reamer parameter may comprise removing the measured downhole weight on bit from the surface weight on bit. The reamer performance metric may comprise a weight load ratio, and the method and/or system may further involve generating the weight load ratio from the weight on reamer and the surface weight on bit.

The reamer performance metric may comprise generating a reamer wear factor ratio based on the weight on reamer, rate of penetration and revolutions per minute. The reamer performance metric may comprise reamer aggressiveness. The measuring drilling parameters may comprise providing the drilling tool with a measurement while drilling tool, a torque sensor, a weight sensor, and/or revolutions per minute sensor.

Measuring surface drilling parameters may comprise providing sensors at the rig. The sensors comprise a hook load sensor, a draw works sensor, a top drive sensor, a torque sensor, and combinations thereof. The measuring surface parameters may involve measuring velocity parameters comprising block position, bit depth, hole depth, revolutions per minute, weight load ratio, and/or rate of penetration. Detecting reamer performance may comprise detecting changes in the velocity parameters.

The method may also involve communicating the downhole drilling parameters and the surface drilling parameters to a central unit, while the system may comprise one or more drilling parameter communication links configured for these communications. The central unit may be located in a surface unit at the wellsite, or in a remote location. The method and system may also involve processing the measured surface and downhole parameters, the processing comprising at least one of filtering, coding, translating, and combinations thereof. The method may also involve communicating the reamer performance metrics to the wellsite, whereas the system may comprise a reamer performance communication link for this communication.

In at least one aspect, the method and system may involve generating surface torque parameters from surface torque measured by surface sensors at the rig and downhole torque parameters measured by downhole sensors in the drilling tool.

Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.