A method of forming a wellbore with a drill string and that includes continuously and automatically measuring a TARE value of the drill string. The TARE value of the drill string is measured while the drill string is rotating, fluid is circulating in the drill string, and after the drill string has been axially stationary for a set period of time. The TARE value is designated as an average of the measured hook load over the latter half of the set period of time. Knowing the measured TARE value and a designated weight on bit (“WOB”) of the drill string, a hook load for supporting the drill string is calculated. Matching the force applied that supports the drill string to the calculated hook load results in an actual WOB that matches the designated WOB.

BACKGROUND OF THE INVENTION 
       [0001]    1. Field of Invention 
         [0002]    The present disclosure relates to a method of calculating weight on bit for a drill string during earth boring operations. More specifically, the present disclosure concerns a method of calculating a tare weight, which is then used for estimating weight on bit. 
         [0003]    2. Description of Prior Art 
         [0004]    Hydrocarbon producing wellbores extend subsurface and intersect subterranean formations where hydrocarbons are trapped. Completing the wellbores with casing and tubing allows conduits for the hydrocarbons to be produced to surface. Earth boring drill bits are typically used to form the wellbores, which mount on ends of drill strings. Motorized drive systems on surface rotate the drill strings and bits, that in turn crush the rock. Cutting elements on the drill bit scrape the bottom of the wellbore as the bit is rotated and excavate material thereby deepening the wellbore. Drilling fluid is typically pumped down the drill string and directed from the drill bit into the wellbore. The drilling fluid flows back up the wellbore in an annulus between the drill string and walls of the wellbore. 
         [0005]    The amount of weight or force applied to the drill bit during drilling, generally referred to as weight on bit (“WOB”), typically affects drilling performance and tool life. Applying an insufficient WOB often reduces penetration rate and increases bit vibration. In contrast, applying excessive WOB can cause mechanical bit failure; and above a certain maximum threshold WOB does not increase penetration rates further. The force exerted holding the drill string at the drilling rig is commonly referred to as the hook load. Traditionally, WOB measurements are based on a difference in hook load between bit off bottom and on bottom. That is, when a portion of the hanging drill string weight is supported by the bit resting on the bottom of the wellbore, hook load is reduced by that portion. This difference between current hook load and a pre-set “TARE” value is taken as a reference for the amount of weight put on the bit. A TARE value is typically obtained by measuring the hook load while suspending the drill string in the wellbore, and without the drill string being supported on the bottom. Because the drill string weight changes as drill pipe segments are added to the drill string, correctly applying a designated WOB requires that the TARE weight be constantly monitored. 
       SUMMARY OF THE INVENTION 
       [0006]    Disclosed herein is an example of a method of forming a wellbore with a drilling assembly; where the drilling assembly is made up of a drill string with an attached drill bit. In this example, the method includes obtaining values of measured weights of the drilling assembly that were taken over a set time span, while the drilling assembly was rotating in the wellbore, while fluid was flowing through the drill string and was being discharged from nozzles that are on the drill bit, and while the drill string was axially stationary in the wellbore. The method of this example further includes estimating an average of the measured weight over a portion of the set time span, and designating a TARE weight of the drilling assembly to be substantially the same as the average of the measured weight over the set time span. The portion of the set time span can be about the latter half of the set time span. Alternatively, the portion of the set period of time can be about the entirety of the set time span. Optionally, the set time span can be about ten seconds. In this example, the portion of the set time span can be the latter 30 percent of the set time span. The fluid can flow in the drill string at a rate substantially equal to a maximum rate of flow in the drill string. The drill string can be axially stationary in the wellbore for a defined period of time before estimating an average of the measured weight. The method can further include repeating the steps of obtaining measured weights of the drilling assembly as it rotates, has fluid flowing therein, and while it is stationary; and re-estimating an average of the measured weight, and then designating a TARE weight based on an average of the measured weight over the set time span. The measured weight of the drilling assembly can be obtained while the drill bit was spaced away from a bottom of the wellbore. The method can further include measuring a hook load of the drilling string while the drill bit is in contact with a bottom of the wellbore, and subtracting the measured hook load from the TARE weight to obtain a measured weight on bit of the drilling assembly. In one example, the method further includes adjusting the hook load of the drilling string while the drill bit is in contact with the bottom of the wellbore until the measured weight on bit of the drilling assembly is substantially the same as a designated weight on bit of the drilling assembly. 
         [0007]    Also disclosed herein is a method of forming a wellbore with a drilling assembly, where the drilling assembly is made up of a drill string with an attached drill bit. In this example the method includes obtaining values of the drilling assembly weights that were taken over a set time span and while the drilling assembly was rotating in the wellbore, while fluid was flowing through the drill string and was being discharged from nozzles that are on the drill bit, and while the drill string was axially stationary in the wellbore. The method of this example further includes calculating a TARE weight of the drilling assembly based on the values of the drilling assembly weights taken over the set time span. The step of calculating the TARE weight of the drilling assembly can involve taking an average of the values of the drilling assembly weights over a portion of the set time span. In this example the portion of the set time span is about the latter 50% of the set time span. The method may optionally further include estimating a weight on bit of the drilling assembly when the bit is in contact with a bottom of the wellbore, and adjusting a hook load supporting the drilling assembly based on the step of estimating a weight on bit, so that an actual weight on bit is substantially equal to a designated weight on bit. Further included with the method is repeating the steps of obtaining values of the drilling assembly weights and calculating a TARE weight of the drilling assembly after a length of pipe has been added to the drill string. 
         [0008]    Another example method of forming a wellbore with a drilling assembly is disclosed herein, and where the drilling assembly has a drill string with an attached drill bit. In this example the method includes obtaining values of the weight of the drilling assembly that were measured over a time period while, the drilling assembly was rotating, fluid was flowing through the drilling assembly, and the drilling assembly was axially stationary, taking an average of the values of the weight of the drilling assembly that were measured during a time span that is about one half that of the time period to define an average weight, designating the average weight as a TARE weight of the drilling assembly, and estimating a weight on bit of the drilling using the TARE weight. The method can further include continuously monitoring drilling assembly rotation, fluid flow through the drilling assembly, and axial movement of the drilling assembly and repeating the steps of obtaining drilling assembly weight, taking the average of the values of the weight, and designating the average weight as a TARE weight; and the next time the drilling assembly is rotating, while fluid is flowing through the drilling assembly, and while the drilling assembly is axially stationary. 
     
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         [0009]    Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which: 
           [0010]      FIG. 1  is a side partial sectional view of an example of a drilling system having a drill string and forming a wellbore. 
           [0011]      FIG. 2  is a side partial sectional view of at example of the drilling system of  FIG. 1  while the TARE weight of the drill string is being measured. 
       
    
    
       [0012]    While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to that embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims. 
       DETAILED DESCRIPTION OF INVENTION 
       [0013]    The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. In an embodiment, usage of the term “about” includes +/−5% of the cited magnitude. In an embodiment, usage of the term “substantially” includes +/−5% of the cited magnitude. 
         [0014]    It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation. 
         [0015]    An example of a drilling system  10  is shown in a side sectional view in  FIG. 1 , where drilling system  10  is used for forming a wellbore  12  through a formation  14 . Drilling system  10  includes an elongate drill siring  16  disposed within wellbore  12 , and is shown made up of segments of drill pipe  18 . In one example, the segments of drill pipe  18  are threadingly coupled to one another. A drill bit  20  is shown mounted on a lower end of drill string  16 , and which includes a bit body  22  that threadingly mounts on a lowermost one of the drill pipes  18  of the drill string  16 . Inserts or cutters  24  are shown on a surface of drill bit body  22  opposite from where it attaches to drill string  16 . When the string  16  and bit  20  are rotated, the cutters  24  crush the rock making up the formation  14  thereby forming borehole  12 . 
         [0016]    Above an opening of wellbore  12  is a derrick  26  shown mounted on a surface  28 , and which includes equipment for manipulating the drill string  16 ; which includes a drawworks  30 . The drawworks  30  selectively pull or release a cable  32  shown engaging sheaves  34  that are rotatingly mounted on an upper end of derrick  26 . Additional cables run through the sheaves  34 , and which on a lower end support a traveling block  36 , that in conjunction with a hook  38  and swivel  40  couple with drill string  16  for raising and lowering drill string  16 . A kelly  42  axially couples to a lower end of swivel  40 ; and is rotatable with respect to swivel  40 . A lower end of kelly  42  projects through a rotary table  44 , which engages outer surfaces of kelly  42  and rotates to exert a rotational force onto drill string  16 . Rotary table  44  is formed on a platform  46  that attaches to derrick  26 , and is set above surface  28 . Drawworks  30  are shown mounted on platform  46 . Below platform  46  and at surface  28  is a wellhead housing  48  that is mounted in the opening of wellbore  12 . On top of the wellhead housing  48  is a blowout preventer (“BOP”)  50  and through which segments of the drill pipe  18  are inserted after being coupled with kelly  42 . Rams  52  mount on lateral sides of BOP  50  and are equipped with blades (not shown) that can selectively sever the pipe string  16  and also form a safety barrier in the event wellbore  12  needs to be shut-in during emergency situations. 
         [0017]    Further shown on surface  28  are stands of pipe  54  that are supported by a rack  56  illustrated on one of the side beams of derrick  26 . Also on platform  46  is a driller's console  58  having gauges representing downhole conditions, and controls for operating the drilling assembly  10 ; such as the drawworks  30 . Schematically illustrated is a controller  60  having a communication means  62  to provide communication between controller  60  and console  58 . Communications means  62  can be wireless, fiber optic, or made up of electrically conducting material. Embodiments exist wherein controller  60  is included within console  58 . 
         [0018]    The weight on bit (“WOB”) exerted by drill string  16  on the bottom of wellbore  12  can be controlled by an operator on the platform  46  and in conjunction with the console  58 . Operator can adjust drawworks  30  so that an upward force on drill string  16  can be exerted on traveling block  36 , hook  38 , swivel  40 , and kelly  42 . Alternatively, these functions can be from software commands stored in a medium that operates in conjunction with the controller  60 . In one example, WOB is estimated based on a hook load, which is the axial force exerted on hook  38 , or other components that provide an axial supporting force for drill string  16 . Sensors (not shown) can provide a signal that when viewed at console  58  represents the axial load by which drill string  16  is supported by the remaining portions of the drilling system  10 , i.e. the hook load. 
         [0019]    Referring now to  FIG. 2 , shown in side partial sectional view is an example of estimating a TARE weight of the drill string  16 . In this example, drill string  16  and bit  20  are drawn upwards within wellbore  12 , such as by actuation of drill works  30  so that drill bit  22  is raised up from the bottom of wellbore  12 . Here the TARE weight is measured after following conditions have occurred: (1) the drill string is rotating, which eliminates stored static axial friction forces that can absorb some of the total drill string weight; (2) mud or other drilling fluid is circulating through an annulus within drill string  16  and shown being discharged as fluid jets  68  that exit from nozzle  66  formed on a lower end of drill bit and adjacent the cutters  24 ; and (3) the drilling system detects no axial movement of the drill string  16  for a defined period of time. The lack of axial movement ensures that static or dynamic friction forces are no longer exerted on the drill string  16 . The fluid that forms the fluid jet  64  can be from a fluid source  68  shown on surface and that connects into swivel  40  via fluid line  70 . Moreover, the TARE weight is in one example taken to be an average of the values of the measured weight of the drill string  16  taken over a set time period. In one example the set time period is about 10 seconds; in this example, the TARE weight is taken to be the average of the values of measured weight of the drill string  16  taken over the about 10 second time span. In another embodiment the TARE weight is taken to be the average of the measured weight of the drill string  16  taken over a portion of the set time period, where the portion can be substantially the same as the set time period, or any amount of time that is less than the set time period. Embodiments exist wherein the portion ranges from 1% to 99% of the set time period, 10% to 90% of the set time period, 20%-80% of the set time period, 30%-70% of the set time period, 40%-60% of the set time period, 50% of the set time period, any discrete value within these percentage values, and combination of the upper and lower limits provided herein, e.g. 30%-50%. The percentage portions of the set time period can be weighted towards the beginning of the set time period, the middle of the set time period, or the end of the set time period. In a specific example, where the set time period is about 10 seconds, the average hook load measured during the last 3-5 seconds of this time period is used for the TARE weight. 
         [0020]    Each time a TARE weight is calculated, a weight on bit value can be calculated by subtracting the hook load daring drilling from the TARE weight. In one embodiment, a TARE weight is measured every time a segment of drill pipe  18  is added to the drill string  16 . Moreover, examples exist where the controller  60  can be programmed to automatically obtain values of TARE weights when the three above-mentioned conditions are met ((1) the drill string is rotating; (2) fluid flow through the drill string; and (3) no axial movement of the drill string) so that not only can an accurate TARE weight be obtained, but will also accommodate situations where lengths of pipe  18  are added to pipe string  16 , thereby increasing the weight of the drill string  16  and affecting the TARE weight. Moreover, obtaining TARE weights as described herein automatically and at regular intervals can ensure an accurate TARE weight is being used. 
         [0021]    Although the drilling system shown includes a derrick  26  and kelly system, other types of drilling systems can be employed with method, such as a top drive system. Moreover, the knowledge of a designated weight on bit is important so that when the new TARE weight is obtained, adjusting the hook load can then result in a true weight on bit that is substantially the same as the designated weight on bit. As such, desired drilling rates can be obtained and without undue wear being imparted on the drill bit  20 . Alternate examples exist wherein the TARE weight is taken to be an average of the entire time span, half of the time span, or about 30% of the time span. Moreover, the latter portion of the time span can be used in order to obtain the estimated averages. 
         [0022]    The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.