Abstract:
Disclosed herein is a method of locating and quantifying friction between a drillstring and a wellbore. The method includes, positioning a plurality of sensors within a wellbore, communicatively coupling the plurality of sensors, monitoring signals from the plurality of sensors, logging the sensed signals versus time versus depth of each of the plurality of sensors, locating at least one friction zone along the drillstring within the wellbore based on the logging and quantifying friction in the at least one friction zone based on the logging.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
       [0001]    Under 35 U.S.C. §119(e), this application claims the benefit of U.S. Provisional Application No. 61/031,755, filed Feb. 27, 2008, the entire disclosure of which is incorporated herein by reference. 
     
    
     BACKGROUND OF THE INVENTION 
       [0002]    Successfully recovering the maximum amount of hydrocarbon production from a well is largely dependent upon characteristics of the wellbore drilled into the earth formation. How accurately a well operator understands the conditions that affect the drilling operation can have a significant effect on efficiency and on the ultimate production from a well. As such, tools to increase knowledge of the effects of the wellbore on the drillstring during drilling are of interest to well operators. 
       BRIEF DESCRIPTION OF THE INVENTION 
       [0003]    Disclosed herein is a method of locating and quantifying friction between a drillstring and a wellbore. The method includes: positioning a plurality of sensors within a wellbore, communicatively coupling the plurality of sensors, monitoring signals from the plurality of sensors, logging the sensed signals versus time versus depth of each of the plurality of sensors, locating at least one friction zone along the drillstring within the wellbore based on the logging and quantifying friction in the at least one friction zone based on the logging. 
         [0004]    Further disclosed herein is a downhole drillstring friction quantification and location system. The system includes: a plurality of sensors positioned along the drillstring, and a processor in communication with the plurality of sensors. The processor is configured to track a depth of each of the plurality of sensors based on estimated drillstring weight and downhole temperatures. The processor is further configured to adjust the tracked depth based on actual sensed data from the plurality of sensors and determine a location of at least one friction zone based upon deviations of parameters sensed by the plurality of sensors from estimated values for those parameters. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0005]    The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike: 
           [0006]      FIG. 1  depicts a schematical representation of a drillstring friction location and quantification system disclosed herein; 
           [0007]      FIG. 2  depicts a multidimensional graph of sensed parameter versus depth of sensor versus time; and 
           [0008]      FIG. 3  depicts a graph of a sensed parameter versus depth for a drillstring within a wellbore. 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0009]    A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures. 
         [0010]    Referring to  FIG. 1 , an embodiment of a downhole drillstring friction quantification, monitoring and/or location system  10  is illustrated. The system  10  includes a plurality of sensors  14  positioned along a drillstring  18  and a processor  22  in communication with the sensors  14 . In one embodiment, the processor  22  is in high data rate communication with the sensors  14 , for example through a high bandwidth channel such as via a wired pipe  24 . The drillstring  18  is shown located within wellbore  26 . The sensors  14 , distributed along the drillstring  18  may be configured to monitor several characteristics including torque, weight, temperature, pressure and magnetic fields, for example. The sensors  14  can be identified by their relative location from surface such as S i  at a depth of l i , for example. As such, the sensors  14  in descending order from surface would be S i+1 , S i+2 , S i+3  . . . at depths l i+1 , l i+2 , l i+3  . . . respectively. 
         [0011]    In one embodiment, the positions of the sensors  14  along the drillstring  18  are monitored with some depth uncertainty due mainly to unexpected axial stress, floating effects and temperature variation but may be considered as initially known sufficiently accurate. During drilling operations the drillstring  18  is moved along the wellbore axis over time during, for example, drilling, tripping and reaming. The drilling process is influenced by applying torque M and weight W on a drill bit  30  (WOB) or weight on a reamer  30  (WOR) or other downhole components. Torque is generally applied, for example, by means of a surface rotation device  34  (M S ) and optionally a downhole rotation device such as a motor or turbine  38  (M DH ). WOB and WOR are adjusted by balancing drillstring  18  weight and hook load (HL) all resulting in a certain weight and torque distribution in the drillstring  18 . The surface inputs, M S , HL and fluid flow rate (FR), can be easily measured or calculated. In one embodiment, calculating M DH  includes deriving values from device data sheets for known flow rates. WOB and torque-on-bit (TOB) can be measured by dynamic sensors located, for example, in the bottom hole assembly  40  (BHA). Drillstring  18  weight and torque as well as other conditions along the drillstring  18  and wellbore  26 , however, are typically only available through static and dynamic models for an idealized system with well known geometries and earth formation properties. These idealized properties only partly match reality. 
         [0012]    Referring to  FIG. 2 , to derive a more realistic picture of the drilling environment, the sensors  14  may be sampled at various times t j  (j=0 . . . m, with m elements of the natural numbers N) and sensor depth l i  recorded for the same times t j . With these readings and records, a multidimensional log space can be completed with points P(S ki , l i , t j ) over time and drillstring  18  movement (where k indicates the sensor type), where one dimension is time t j , one is sensor depth l i  (measurement depth), and other dimensions are the outputs of the various sensors  14 . Uncertainties of readings of the sensors  14 , depth and time are denoted by an ellipsoid of uncertainty  42 . Coordinates of the various points can and should be corrected for possible dynamic effects and input variations, such as, changes in surface torque via torque sensor  14  readings, for example. 
         [0013]    Referring to  FIG. 3 , a typical depth based log can be achieved by simply projecting the points of one type of sensor  14  onto a sensor-depth plane  44 . Measurements for a specific depth may be averaged, or filtered otherwise. Using multiple sensors  14  along the drillstring  18  allows one to draw complete depth logs without moving the string over the entire measured well depth. The records may also be used to show a time dependency of the log progression, for example. Examples of depth logs include torque logs over measured depth when using torque sensors  14 , stress logs over measured depth when using strain gage arrays or magnetic field sensor arrays and weight logs over measured depth when using axial strain gages or magnetic sensor arrangements measuring axial stress. Temperature sensors could be used to display temperature distribution along the well path, and pressure sensors could be used in order to derive measured pressure-depth correlation logs. 
         [0014]    Results may be used to reconsider initial assumptions, for example, depths may be calculated based on the mechanical loads and temperatures fed back into the initial string and well model from the measurements in order to minimize uncertainties. 
         [0015]    Projected measurement points may be newly ascending, enumerated along a depth axis, starting from surface and denoted by exemplary identifiers (S(l 0 ), S(l 1 ) . . . S(l q )=S 0 , S 1  . . . S q  (with q elements of the natural number N). In the case of torque and weight (simply derived, for examples) from axial stress readings and drillstring geometry) the log would be expected to show a steady and (depending on wellbore  26  and drillstring  18  geometry) partly linear approximated progression respectively with a constant gradient (or slope)  46  in the absence of friction: 
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         [0016]    This means friction zones  48 , or spots of noticeably greater friction, can be detected with a gradient log derived from weight and torque logs. The friction zones  48  can be assumed to reside where an alternate gradient  50  exists that deviates from the expected constant gradient  46 . A magnitude of the frictional zones  48  can be determined by the difference between the gradient  50  and the gradient  46 . Additionally, the depths where the gradient  46  transitions to the gradient  50  can indicate a beginning  54  of the friction zone  48 . Similarly, where the gradient  50  transitions to the gradient  46  can indicate an ending  58  of the friction zone  48 . Comparison with mechanical models identifying wall contact or other static and dynamic drillstring  18  to wellbore  26  interactions causing high friction, may allow mapping wellbore  26  intervals that have a weight or torque transfer problem due to swelling and deviated wellbore  26  profiles, such as local doglegs and cutting accumulation, for example. 
         [0017]    Other applications utilizing the sensors  14  spaced apart along the drillstring  18  include determination of differential sticking, identification of where a pipe is stuck and weight and torque transfer across an active drilling element, such as a reamer, for example. 
         [0018]    While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims.