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 . 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 . an example of a drilling system 10 is shown in a side sectional view in fig1 , 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 . 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 . 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 &# 39 ; 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 . 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 . referring now to fig2 , 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 . 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 . 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 . 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 .