Patent Publication Number: US-2023144743-A1

Title: Correction for Cuttings Lag

Description:
BACKGROUND 
     The present disclosure relates generally to tools and methods for assessing the effectiveness, safety and other characteristics of a subterranean wellbore operation. More particularly, embodiments of the disclosure include collecting information about particulates carried to the surface by a wellbore fluid during the wellbore operation. 
     During the drilling of a hydrocarbon-producing well, a drilling fluid or “mud” is continuously circulated from a surface location down to the bottom of the wellbore being drilled and back to the surface again. The returning mud includes particulates such as drill cuttings that may be derived primarily from the formation being penetrated by a drill bit. The particulates may also include geologic material that is eroded or otherwise detached from the surrounding formation at locations in the wellbore other than the bottom of the wellbore engaged by the drill bit. Drilling operators may need to know the lag time, or the time required for the particulates to reach the surface. The lag time may be estimated based on a lag test wherein a known substance is introduced into the drilling fluid and at the surface and subsequently detected at various times and locations along the drilling fluid flow path. Once detected, the lag time may be calculated and expressed in terms of time or pump cycles. In other wellbore operations, particulates carried to the surface may include proppants that return to the surface during or after hydraulic fracturing operations. Ascertaining the origin of the particulates returning to the surface may increase the effectiveness of drilling, pumping, sweeping, and/or, fracturing operations and may help reduce the cost of hydrocarbon recovery operations. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The disclosure is described in detail hereinafter, by way of example only, on the basis of examples represented in the accompanying figures, in which: 
         FIG.  1    is a partial, cross-sectional side view of a wellbore drilling system illustrating components for examining wellbore particles and determining an origin of the particles from within the wellbore in accordance with aspects of the present disclosure; 
         FIG.  2    is a block diagram of a controller of the system of  FIG.  1   ; 
         FIG.  3    is a flowchart illustrating a procedure for evaluating and altering a drilling operation based on a determination of the origin of particulates from within the wellbore; and 
         FIG.  4    is a timeline illustrating a pump schedule for a wellbore operation and an estimated position of the particulates within the wellbore during the wellbore operation, which may be determined with systems and methods in accordance with the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure describes systems and methods for determining the lag time and origin of particles in entrained in a non-Newtonian mud stream. A size and shape of the particles may be evaluated at the surface, which permits a settling rate to be determined for each of the particles in the mud stream. Together with an analysis of the mud properties, trajectory of the wellbore, a pumping schedule and other fluid dynamics associated with a wellbore operation, an origin of the each of the particles from within the wellbore may be determined. At least one operational parameter for the wellbore operation may be adjusted based on the determined origin of the particles. 
       FIG.  1    illustrates a wellbore drilling system  10  with an imaging system  12  in accordance with example embodiments of the present disclosure. The wellbore drilling system  10  includes a drilling platform  14  that supports a derrick  16  having a traveling block  18  for raising and lowering a drill string  20 . The drill string  20  may include, but is not limited to, drill pipe and coiled tubing, as generally known to those skilled in the art. A kelly  22  supports the drill string  20  as it is lowered through a rotary table  24 . A drill bit  28  is attached to the distal end of the drill string  20  and is driven either by a downhole motor and/or via rotation of the drill string  20  by the rotary table  24 . As the drill bit  28  rotates, it creates a wellbore  30 . The wellbore  30  penetrates a geologic formation “G” and extends from a surface location “S.” While wellbore  30  is illustrated extending from a terrestrial surface location “S,” the principles described herein are equally applicable to subsea drilling operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure. 
     As illustrated, the example wellbore  30  includes a vertical portion  30   a  extending from the surface location “S” to an elbow  30   b . A horizontal portion  30   c  of the wellbore  30  extends from the elbow  30   b  to a toe  30   d  of the wellbore where the drill bit  28  engages the geologic formation “G.” In other embodiments, a wellbore with any other geometry, e.g., deviated, slanted, curved and/or entirely vertical, may employ the systems and methods described herein without departing from the scope of the disclosure. 
     A pump  32  (e.g., a mud pump) circulates drilling fluid  36  through a feed pipe  38  and to the kelly  22 , which conveys the drilling fluid  36  downhole through the interior of the drill string  20  and through one or more orifices in the drill bit  28 . The drilling fluid  36  is then circulated back to the surface location “S” through an annulus  40  defined between the drill string  20  and the walls of the wellbore  30 . At the surface location “S,” the recirculated or spent drilling fluid  36  exits the annulus  40  and may be conveyed through a flow line  44  to one or more fluid processing unit(s)  46 . The fluid processing unit  46  may include a shaker table  50  with one or more screens  52  onto which the drilling fluid  36  is deposited for cleaning. Example particles P 1 , P 2  may be separated from the drilling fluid  36  by the one or more screens  52  in view of the imaging system  12 . The drilling fluid  36  may pass through the screens  52  into a retention pit  54  where one or more chemicals, fluids, or additives may be added to the drilling fluid  36  before returning to the pump  32  through flow line  56 . 
     The imaging system  12  includes an imaging device  60  focused on the one or more screens  52  or another location where particles P 1 , P 2  separated from the drilling fluid  36  may be visible. The imaging device  60  may include one or more cameras such as a charge coupled device (CCD) camera, or one or more low light or infrared cameras. The imaging device  60  may be employed in conjunction with one or more light sources  62 , such as a white light source, an incandescent light source (e.g., a tungsten filament light bulb), an infrared light source, a laser, one or more light emitting diodes (LEDs), or any combination thereof. The imaging system  12  is operably coupled to a controller  70  by a communication cable  72 . 
     The controller  70  may be located at the surface location “S,” e.g., on the drilling platform  14  or at another location adjacent the wellbore  30  being drilled. In other embodiments, the controller  70  may be located at a remote location, without departing from the scope of the disclosure. The controller  70  may generally operate to control the collection of data from imaging system  12 , to analyze the size and shape of particles P 1 , P 2  any other images or data provided by the imaging system  12 . The controller  70  may also be operably coupled to one or more downhole sensors  74  by a communication line  76 . The downhole sensors  74  may be provided within a measurement-while-drilling (MWD) or logging-while drilling (LWD) system, and the communication line  76  may include wired connections, mud pulse telemetry or other downhole telemetry systems. The sensors  74  may generally monitor a viscosity, density and other properties of the drilling fluid  36  in real-time and may also provide an indication of the trajectory of the wellbore  30 . The trajectory of the wellbore  30  may be derived from data regarding the position and orientation of the drill bit at predetermined intervals or as a continuous data stream. With the information provided through the communication cable  72  and the communication lien  76 , as well as any information stored within or otherwise available to the controller  70 , the controller may operate to determine an origin of the particles P 1 , P 2  from within the wellbore  30 . 
     Referring to  FIG.  2   , the controller  70  includes a data acquisition module  80  operably coupled to the communication cable  72  and the communication line  76 . The data acquisition module  80  may include logic  82 , perhaps comprising a programmable data acquisition module  80 . The logic  82  may be employed, for example, to select data  84  from the imaging system  12  ( FIG.  1   ) for processing. In some embodiments, the imaging system  12  may provide data  84  at timed intervals dependent upon the drilling operation (e.g., drilling, circulating, cleaning, etc.). The data  84  may comprise any type of image data including still images and/or video of the particles P 1 , P 2  ( FIG.  1   ) moving across the screens  52  ( FIG.  1   ). Similarly, the logic  82  may be employed to select data  84  provided by the downhole sensors  74  ( FIG.  1   ). The logic  82  of the controller also be may be programmed with an appropriate threshold, for example a predetermined number or distribution of particles identified as having a particular origin in the wellbore, which will cause the controller  70  to adjust a parameter of the drilling operation. 
     The data acquisition module  80  may further include a memory  86  communicably coupled to one or more processors  88  and may be used to compile or store the acquired data  84 , as well as other data, perhaps in an associated database  90 . A neural network  92  may be programmed into the memory  86  to assist the processors  88  in ascertaining the size and shape of particles P 1 , P 2 . For example, the neural network  92  may be trained prior to deployment using one or more kits or collections of physical training objects of a known shape, size, and volume. Such training objects may include sample physical objects, such as ball bearings, cubes, pyramids, or any three-dimensional objects of a known or determinable shape, size, and volume. In other embodiments, the training objects may include drill cuttings and geologic particles derived from the wellbore  30  and/or adjacent wellbores. A weight and/or density of each of the training objects may be stored in the database  90  to assist processors  88  in ascertaining an estimated density of the particles P 1 , P 2  observed in operation. 
     The controller  70  may include a remote workstation  94  communicably coupled to the data acquisition module with  80  with a transmitter  96 . The transmitter  96  may include any form of wired or wireless telecommunication such as, but not limited to, wires, fiber optics, wireless means (e.g., radio frequency, etc.). In such embodiments, the data  84  may be transmitted to the remote workstation  94  to be processed with associated processors  88  contained therein. The remote workstation  94  may include one or more peripheral devices  98 , such as a computer screen, a graphical user interface, a hand-held device, a printer, or any combination thereof. The peripheral devices  98  may provide an operator with a graphical display of the results of processing the data  84 , and of an estimated origin of the particles P 1 , P 2  from within the wellbore  30 . 
     Referring now to  FIG.  3   , and with continued reference to  FIGS.  1  and  2   , a procedure  100  for evaluating and altering a wellbore operation based on a determination of the origin of particulates P 1 , P 2  from within the wellbore  30  is illustrated. Initially at step  102 , the controller  70  may be trained to estimate a size and shape of particles P 1 , P 2  retrieved from the wellbore  30 . For example, the logic  82  may be programmed to take measurements of a plurality of calibration particles with a known size, shape, volume, density and other characteristics and the known characteristics of the calibration particles may be stored in the database  90  for comparison to particles P 1 , P 2  in operation. Any other known data regarding the wellbore operation, for example, well trajectory, mud properties, etc. may be stored in the database to assist in any subsequent analysis. 
     Next, at step  104 , the wellbore pumps  32  are activated to circulate drilling fluid  36  or another wellbore fluid through the wellbore  30 . The wellbore pumps  32  may not be running throughout the entire wellbore operation, and thus a pump schedule may be recorded (step  106 ). The times at which the pumps  32  are deactivated and the times the pumps  32  are running may be recorded along with the speed of the pumps  32 . The pump  32  may be operably coupled to controller  70  directly such that the pump schedule may be recorded in the database  90 , and/or the pump schedule may be estimated based on image data provided by the imaging system  12 , flow rates detected by down hole sensor  74 , or the pump schedule may be input manually by an operator at the peripheral device  94 . The pump schedule (see  FIG.  4   ) may form a timeline for the wellbore operation. Concurrently with recording the pump schedule, the fluid properties of the drilling fluid  36 , the wellbore trajectory, geologic properties surrounding the wellbore  30  may be monitored with the sensors  74  (step  108 ) and recorded in the database  90 . Sensors (not shown) positioned elsewhere along mud stream may also be queried to record values of fluid pressure, flow rate, etc. and recorded in the database  90 . Also while the pump schedule is being recorded, image data of particles P 1 , P 2  retrieved from the wellbore  30  are captured by the imaging system  12  (step  110 ). The images of the particles P 1 , P 2  may be measured by the processor  88  in data acquisition unit  80 , and the particles P 1 , P 2  may be categorized by size and shape. For example, measurements may be taken of the particles P 1 , P 2  along multiple axes and in parallel planes such that the particles may be categorized into one or more categories, for example, cubic, spherical, pyramidal. The density, composition and other characteristics of the particles may be estimated based on the characteristics of the most similar calibration particles, for example. The density of the particles may also be estimated based on bulk density and/or neutron density logs or measurements of the geologic formation “G” surrounding the wellbore  30 . 
     Next, at step  112 , a fluid velocity v f  of the drilling fluid  36  may be determined for any spatial interval in the wellbore  30 , for example the vertical portion  30   a  and the horizontal portion  30   c . The fluid velocity v f  may be readily calculated with measurements of the annular cross-sectional area of the wellbore portion  30   a ,  30   c  together with the volume pumped through the pumps  32 . In some embodiments, an average fluid velocity along the total wellbore is calculated rather than a fluid velocity in any particular interval. 
     At step  114 , a settling velocity v s  is determined for each of the particles P 1 , P 2 . In some embodiments, the settling velocity v s  is determined empirically or experimentally, for example using the calibration particles with the particular drilling fluid  36 . In other embodiments, the settling velocity v s  may be calculated using equation (1) below or a similar correction. 
     
       
         
           
             
               
                 
                   
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     Here μ e  is an effective viscosity for a non-Newtonian drilling fluid  36 , d is a nominal diameter of the particles P 1 , P 2 , ρ f  is the density of the drilling fluid  36  and ρ p  is the density of the particles P 1 , P 2 . Any similar correction factor may be employed for the settling velocity without departing from the scope of the disclosure. 
     Next at step  116 , a particle velocity v p  for each of the particles P 1 , P 2  may be determined taking into account fluid velocity v f  determined in step  112 . The drag, buoyancy, and lift from the fluid velocity v f  may be corrected for the trajectory of the wellbore  30  and compared to the force of gravity in a momentum balance, to calculate particle velocity V. 
     Once the particle velocity v p  is determined, a location of the particles P 1 , P 2  may be determined (step  118 ) by back calculating the position of the particle P 1 , P 2  downhole, considering the pump schedule recorded in step  106 . An example of the back calculation is described below with reference to  FIG.  4   . Next, in step  120 , at least one parameter of the wellbore operation may be adjusted in response to determining the location of the particles P 1 , P 2 . For example, if it is determined that an origin of one of the particles P 2  is in an undesirable location in the wellbore  30 , the elbow  30   b , for example, the density of the drilling fluid  136  may be altered to ensure the particles P 1 , P 2  are not accumulating in the wellbore  30 . Additionally, or alternatively, the pump rate may be altered, or other remedial actions may be employed. 
     Referring now to  FIG.  4   , a timeline illustrates an example pump schedule along with an estimated position of the particulates P 1 , P 2  within the wellbore  30  during the wellbore operation. The timeline illustrates a time period ending at t=0 when an image of particles P 1 , P 2  are captured by the imaging system  12  at the surface location “S.” The beginning of the time period is at t=−100 when the pumps  32  are first activated. In other embodiments, any portion of a wellbore operation and any duration may be recorded for analysis without departing from the scope of the disclosure. The example pump schedule generally indicates that the pumps  32  are run at ⅓ speed from t=−100 to t=−80 and from t=−40 to t=−25, full speed from t=−80 to t=−60 and from t=−10 to t=0 and deactivated from t=−60 to t=−40. The units for time, pump speed and distance within the wellbore  30  are not illustrated in the general example of  FIG.  4   , as those skilled in the art would readily recognize the manner in which the quantities may be determined. 
     The pump schedule generally establishes a plurality of time intervals for which a different particle velocity v p  may be determined. The wellbore position also establishes a plurality of intervals for which a particle velocity v p  may be determined. For example, a change in verticality of the wellbore at the elbow  30   b  may establish a boundary between portions of the wellbore with a different degree of verticality, e.g., the horizontal portion  30   c  and the vertical portion  30   a . As described below, a different particle velocity v p  may be determined for each of the individual interval, and the origin of the particles may be determined by back-calculating a location of the particle at the beginning of each of the intervals from the particle velocity v p  and a known or calculated position at the end of the interval. 
     From the surface location “S” where both particles P 1 , P 2  were recovered at t=0, a location of the each of the particles P 1 , P 2  may first be calculated at t=−10. The particle velocity, corrected for settling, determined for each of the particles P 1 , P 2  caused by the full speed operation of the pumps  32  while moving through the vertical portion  30   a  of the wellbore  30  can be used to determine a distance traveled by each of the particles over the time interval of t=−10 to t=0. Based on the size and shape of the particles, it may be determined that particle P 1  traveled faster than particle P 2 , and thus, would have been deeper within the wellbore  30  at time t=−10. The location of each of the particles P 1 , P 2  is noted and establishes a reference for calculating a location of the particles for a preceding interval, e.g., from t=−25 to t=−10. 
     For the time interval from t=−25 to t=−10, the pump schedule indicates that the pumps  32  were not running Thus, the particles P 1 , P 2  may have been settling over this time interval at the settling velocity v s  calculated for each of the particles P 1 , P 2 . The settling velocity v s  for each of the particles P 1 , P 2  may thus be used to calculate a location of the particles P 1 , P 2  at t=−25 that is higher in the wellbore  30  than the location calculated at t=−10. 
     The location of the particles P 1 , P 2  at the beginning of each time interval may similarly be calculated until an origin of the particles P 1 , P 2  is determined at t=−100. For the time interval from t=−40 to t=−25, since the pumps  32  were only operating at ⅓ capacity, the particle velocity v p  may be less than the particle velocity v p  calculated for full speed operation of the pumps  32 . At t=−70 it may be determined that particle P 1  transitioned from the horizontal portion  30   c  to the vertical portion  30   a  of the wellbore  30 . Thus, for the time interval from t=−80 to t=−70 the settling velocity v s  may be discounted as the particle P 1  may not tend to settle any significant distance in the horizontal portion  30   c . Thus, a different particle velocity v p  may be calculated for the time interval from t=−80 to t=−70 than for the time interval from t=−70 to t=−60 even though the pumps  32  may have been operating at full capacity over the entire time from t=−80 to t=−60. 
     Once the origin of the particles P 1 , P 2  is determined, it may be recognized that particle P 1  originated from the toe  30   d  of the wellbore  30  and may have been generated as the drill bit  28  cut into the geologic formation “G.” It may be recognized that the particle P 2  may have originated at the elbow  30   b , which may indicate a buildup of particles at the elbow  30   b . In response to determining the origin of the particles P 1 , P 2 , remedial actions may be taken to clean out the wellbore  30  such as changing a characteristic of the drilling fluid  36 , altering the pumping rate, or adjusting any parameter the wellbore operation that may remedy the buildup of particles at the elbow  30   b . In some embodiments, the controller  70  is preprogrammed with instructions to adjust the pumping rate automatically, or to display a proposed response to an operator on the peripheral device  94 . 
     The aspects of the disclosure described below are provided to describe a selection of concepts in a simplified form that are described in greater detail above. This section is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used as an aid in determining the scope of the claimed subject matter. 
     According to one aspect, the disclosure is directed to a method for evaluating and altering a wellbore operation. The method includes (a) circulating a wellbore fluid through a wellbore, the wellbore fluid carrying a plurality of particles originating from within the wellbore, (b) retrieving the particles from the wellbore, (c) measuring the particles to determine a size and shape of the particles, (d) determining a particle velocity for each of the particles within the wellbore from the size and shape determined for each of the particles and from a fluid velocity of the wellbore fluid within the wellbore (e) determining an origin of each of the particles from within the wellbore from the particle velocity determined for each of the particles and (f) adjusting at least one parameter of the wellbore operation in response to the origin determined for at least one of the particles. 
     In some embodiments, the method may further include capturing image data of the particles with an imaging system coupled to a controller, and wherein measuring the particles may include measuring the particles from the image data with the controller. Determining the particle velocity for each of the particles may include determining a settling velocity for each of the particles with the controller and determining the settling velocity may include characterizing a component of the particle velocity caused by gravity on the particle. In some embodiments, determining the settling velocity may include calculating the settling velocity from the equation: 
     
       
         
           
             
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     wherein μ e  is an effective viscosity for the wellbore fluid, d is a nominal diameter of the particle, ρ f  is the density of the wellbore fluid and ρ p  is the density of the particle. In one or more embodiments, the method further includes estimating the density of the particle by comparing the image data with image data of a plurality of calibration particles of known density stored by the controller. 
     In one or more embodiments, the method further includes recording a pump schedule including time intervals in which a pump is running to circulate the wellbore fluid and time intervals in which the pump is not running In some embodiments, determining a particle velocity for each of the particles includes determining a particle velocity for each of the particles for each of the intervals and wherein determining the origin of each of the particles includes determining a location of each of the particles at a beginning of each of the intervals from the particle velocity determined for each of the intervals. The method may further include recording a trajectory of the wellbore with the controller, the trajectory indicating a degree of verticality of the wellbore and determining the particle velocity for each of the particles may be based on the verticality of the wellbore. In some embodiments, determining the particle velocity includes correcting the particle velocity in vertical portions of the wellbore such that the particle velocity in the vertical portions of the wellbore is less than the particle velocity in horizontal portions of the wellbore. 
     In some embodiments, adjusting at least one parameter of the wellbore operation may include initiating a washout procedure. In some embodiments, the washout procedure may be initiated in response to identifying an indication of a buildup of particles win the wellbore. 
     According to another aspect, the disclosure is directed to a wellbore system. The wellbore system includes a pump fluidly coupled a wellbore and operable for circulating a wellbore fluid through the wellbore, an imaging system operable for capturing image data of particles carried by the wellbore fluid from the wellbore and a controller operably coupled to the imaging system to receive images of the particles therefrom, to measure the images of the particles to determine a size and shape of the particles, to determine a particle velocity for each of the particles within the wellbore from the size and shape determined, determine an origin of each of the particles from within the wellbore from the particle velocity determined and to adjust at least one parameter of a wellbore operation in response to the origin determined for at least one of the particles. 
     In one or more embodiments, the wellbore system further includes a downhole sensor disposed within the wellbore and operably coupled to the controller to transmit data indicative of at least one of the group consisting of a trajectory of the wellbore and a viscosity, density and/or fluid velocity of the wellbore fluid within the wellbore. The wellbore system may further include a drill string extending into the wellbore, and the downhole sensor may be carried by the drill string. 
     In some embodiments, the controller includes a neural network trained with calibration objects of a known shape, size, weight and volume to assist the controller in determining the size, shape, weight and/or density of the particles. The controller may include a processor operable to determine the particle velocity for each of the particles from a fluid velocity of the wellbore fluid and from a settling velocity characterizing a component of the particle velocity caused by gravity on each of the particles. The controller may include logic operable to select data from the imaging system for processing. 
     According to another aspect, the disclosure is directed to a non-transitory, computer readable medium. The non-transitory, computer readable medium is programmed with computer executable instructions that, when executed by a processor of a computer unit, perform the steps of (a) receiving images of particles retrieved from a wellbore, (b) measuring the images of the particles to determine a size and shape of the particles (c) determining a particle velocity for each of the particles within the wellbore from the size and shape of each of the particles and from a fluid velocity of a wellbore fluid within the wellbore (d) determining an origin of each of the particles from within the wellbore from the particle velocity of each of the particles and (e) adjusting at least one parameter of a wellbore operation in response to determining the origin of at least one of the particles. 
     In one or more embodiments, the instructions further cause the processor to determine a settling velocity for each of the particles from the size and shape of the particles. The instructions may further cause the processor to determine the particle velocity of each of the particles for each of a plurality of time intervals and estimating a location of the particles at a beginning of each of the intervals from the particle velocity determined for each of the intervals. The instructions may further cause the processor to determine the particle velocity based on a verticality of the portion of the wellbore in which the particle moves over each of the intervals. 
     The Abstract of the disclosure is solely for providing the United States Patent and Trademark Office and the public at large with a way by which to determine quickly from a cursory reading the nature and gist of technical disclosure, and it represents solely one or more examples. 
     While various examples have been illustrated in detail, the disclosure is not limited to the examples shown. Modifications and adaptations of the above examples may occur to those skilled in the art. Such modifications and adaptations are in the scope of the disclosure.