Patent Document

CROSS REFERENCE TO RELATED APPLICATIONS 
     This patent application is a continuation-in-part of U.S. patent application Ser. No. 12/178,467 filed on Jul. 23, 2008 now U.S. Pat. No. 7,730,975 issued on Jun. 8, 2010, which is a continuation-in-part of U.S. patent application Ser. No. 12/039,608 filed on Feb. 28, 2008 and is now U.S. Pat. No. 7,762,353 issued on Jul. 27, 2010, which is a continuation-in-part of U.S. patent application Ser. No. 12/037,682 filed on Feb. 26, 2008 and now U.S. Pat. No. 7,624,824 issued on Dec. 1, 2009, which is a continuation-in-part of U.S. patent application Ser. No. 12/019,782 filed on Jan. 25, 2008 and now U.S. Pat. No. 7,617,886 issued on Nov. 17, 2009, which is a continuation-in-part of U.S. patent application Ser. No. 11/837,321 filed on Aug. 10, 2007 and now U.S. Pat. No. 7,559,379 issued on Jul. 14, 2009, which is a continuation-in-part of U.S. patent application Ser. No. 11/750,700 filed on May 18, 2007 and now U.S. Pat. No. 7,549,489 issued on Jun. 23, 2009, which is a continuation-in-part of U.S. patent application Ser. No. 11/737,034 filed on Apr. 18, 2007 and now U.S. Pat. No. 7,503,405 issued on Mar. 17, 2009, which is a continuation-in-part of U.S. patent application Ser. No. 11/686,638 filed on Mar. 15, 2007 and now U.S. Pat. No. 7,424,922 issued on Sep. 16, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/680,997 filed on Mar. 1, 2007 and now U.S. Pat. No. 7,419,016 issued on Sep. 2, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/673,872 filed on Feb. 12, 2007 and now U.S. Pat. No. 7,484,576 issued on Feb. 3, 2009, which is a continuation-in-part of U.S. patent application Ser. No. 11/611,310 filed on Dec. 15, 2006 and now U.S. Pat. No.  7,600,586 issued on Oct.  13, 2009. 
     U.S. patent application Ser. No. 12/178,467 is also a continuation-in-part of U.S. patent application Ser. No. 11/278,935 filed on Apr. 6, 2006 and now U.S. Pat. No. 7,426,968 issued on Sep. 23, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/277,394 filed on Mar. 24, 2006 and now U.S. Pat. No. 7,398,837 issued on Jul. 15, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/277,380 filed on Mar. 24, 2006 and now U.S. Pat. No. 7,337,858 issued on Mar. 4, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/306,976 filed on Jan. 18, 2006 and now U.S. Pat. No. 7,360,610 issued on Apr. 22, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/306,307 filed on Dec. 22, 2005 and now U.S. Pat. No. 7,225,886 issued on Jun. 5, 2007, which is a continuation-in-part of U.S. patent application Ser. No. 11/306,022 filed on Dec. 14, 2005 and now U.S. Pat. No. 7,198,119 issued on Apr. 3, 2007, which is a continuation-in-part of U.S. patent application Ser. No. 11/164,391 filed on Nov. 21, 2005 and now U.S. Pat. No. 7,270,196 issued on Sep. 18, 2007. 
     U.S. patent application Ser. No. 12/178,467 is also a continuation-in-part of U.S. patent application Ser. No. 11/555,334 filed on Nov. 1, 2006 and now U.S. Pat. No. 7,419,018 issued on Sep. 2, 2008. 
     All of these applications are herein incorporated by reference in their entirety. 
    
    
     BACKGROUND  
     The present invention relates to the field of oil, gas and/or geothermal exploration and more particularly to the field of percussive tools used in down hole drilling. More specifically, the invention relates to the field of downhole jack hammers and vibrators which may be actuated by drilling fluid or mud. 
     Percussive jack hammers are known in the art and may be placed at the end of a bottom hole assembly (BHA). At that location they act to effectively apply drilling power to a formation, thus aiding penetration into the formation. 
     U.S. Pat. No. 7,424,922 to Hall, et al., which is herein incorporated by reference for all that it contains, discloses a jack element that is housed within a bore of a tool string and that has a distal end extending beyond a working face of the tool string. A rotary valve is disposed within the bore of the tool string. The rotary valve has a first disc attached to a driving mechanism and a second disc axially aligned with and contacting the first disc along a flat surface. As the discs rotate relative to one another at least one port formed in the first disc aligns with another port formed in the second disc. Fluid passing through the aligned ports displaces an element in mechanical communication with a jack element. 
     Percussive vibrators are also known in the art and may be placed anywhere along the length of the drill string. Such vibrators act to shake the drill string loose when it becomes stuck against the earthen formation or to help the drill string move along when it is laying substantially on its side in a nonvertical formation. Vibrators may also be used to compact a gravel packing or cement lining by vibration, or to fish a stuck drill string or other tubulars, such as production liners or casing strings, gravel pack screens, etc., from a bore hole. 
     U.S. Pat. No. 4,890,682 to Worrall, et al., which is herein incorporated by reference for all that it contains, discloses a jarring apparatus provided for vibrating a pipe string in a borehole. The jarring apparatus generates, at a downhole location, longitudinal vibrations in the pipe string in response to a flow of fluid through the interior of said pipe string. 
     U.S. Pat. No. 7,419,018 to Hall, et al., which is herein incorporated by reference for all that it contains, discloses a downhole drill string component which has a shaft being axially fixed at a first location to an inner surface of an opening in a tubular body. A mechanism is axially fixed to the inner surface of the opening at a second location and is in mechanical communication with the shaft. The mechanism is adapted to elastically change a length of the shaft and is in communication with a power source. When the mechanism is energized, the length is elastically changed. 
     Not withstanding the preceding patents regarding downhole jack hammers and vibrators, there remains a need in the art for more powerful mud actuated downhole tools. There is also a need in the art for means to easily adjust the force of the downhole tool. Thus, further advancements in the art are needed. 
     SUMMARY  
     In one aspect of the present invention a downhole tool string includes a downhole percussive tool. The downhole percussive tool has an interior chamber with a piston element that divides the interior chamber into two pressure chambers. The piston element may slide back and forth within the interior chamber thus altering the volumes of the two pressure chambers. The percussive tool also has input channels that lead drilling fluid into the interior chamber or bypass the interior chamber and continue along the downhole tool string. The downhole percussive tool additionally has exit orifices that release drilling fluid from the interior chamber and take drilling fluid directly from the input channels and send it along the downhole tool string. Furthermore, the percussive tool has exhaust orifices that release drilling fluid from the interior chamber. 
     The present invention includes a rotary valve that is actively driven by a driving mechanism. The driving mechanism may be a turbine, a motor, or another suitable means known in the art. The rotary valve comprises two discs that face each other along a surface. Both discs have ports formed therein that may align or misalign as the discs rotate relative to one another. The discs may be formed of material selected from the group consisting of steel, chromium, tungsten, tantalum, niobium, titanium, molybdenum, carbide, natural diamond, polycrystalline diamond, vapor deposited diamond, cubic boron nitride, TiN, AlNi, AlTiNi, TiAlN, CrN/CrC/(Mo, W)S2, TiN/TiCN, AlTiN/MoS2, TiAlN, ZrN, diamond impregnated carbide, diamond impregnated matrix, and silicon bounded diamond, and. 
     In a first stroke of the piston element, the two discs rotate relative to one another and at least two misalign to block the flow of drilling fluid to a first group of input channels. At the same moment, at least two other ports align to allow a second group of input channels to feed drilling fluid into a first pressure chamber on one side of the interior chamber and also out through exit orifices. The flow of drilling fluid into the first pressure chamber causes the pressure to rise in that chamber and forces the piston element to move towards a second pressure chamber. Drilling fluid in the second pressure chamber is forced out through exit orifices or through exhaust orifices. The combined area of the exit orifices and exhaust orifices through which the drilling fluid in the second pressure chamber is being released may be larger than the combined area of the exit orifices through which the drilling fluid from the second group of input channels is flowing, thus causing the pressure to be greater in the first pressure chamber than in the second pressure chamber. 
     In a second stroke of the piston element, the two discs rotate further relative to one another, thus aligning the at least two ports and allowing the first group of input channels to supply drilling fluid into the second pressure chamber and also out through exit orifices. The at least two other ports also misalign to block the flow of drilling fluid to the second group of input channels. The increased pressure from the drilling mud in the second pressure chamber forces the piston element to move back toward the first pressure chamber. The drilling fluid in the first pressure chamber under lower pressure is forced out of exit orifices or through exhaust orifices. The combined area of the exit orifices and exhaust orifices through which the drilling fluid in the first pressure chamber is being released may be larger than the combined area of the exit orifices through which the drilling fluid from the first group of input channels is flowing, thus causing the pressure to be greater in the second pressure chamber than in the first pressure chamber. 
     Since the pressure differential between the first pressure chamber and the second pressure chamber is primarily a function of the difference in areas of the exit orifices and exhaust orifices dedicated to each, then that pressure differential may be easily adjusted by regulating the size of the orifices used rather than changing the internal geometry of the rotary valve. 
     In one embodiment of the present invention, the percussive tool acts as a jack hammer. In this embodiment, the percussive tool includes a jack element that is partially housed within a bore of the drill string and has a distal end extending beyond the working face of the tool string. The back-and-forth motion of the piston element causes the jack element to apply cyclical force to the earthen formation surrounding the drill string at the working face of the tool string. This generally aids the drill string in penetrating through the formation. In this embodiment, the exit orifices and exhaust orifices are formed as nozzles that spray drilling fluid out of the working face of the tool string and also generally allow the drill string to move faster through the formation. 
     In another embodiment of the present invention, the percussive tool acts as a vibrator. In this embodiment, the percussive tool may be located at any location along the drill string and shakes the drill string as the piston element moves back and forth. The piston element may be weighted sufficiently to shake the drill string or an additional weight may be partially housed within the drill string that acts to shake the drill string. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a side-view diagram of an embodiment of a downhole tool string assembly in a cut away view of a formation. 
         FIG. 2  is a cross-sectional diagram of an embodiment of a downhole percussive tool. 
         FIGS. 3   a - j  are perspective diagrams of several components of an embodiment of a downhole percussive tool. 
         FIG. 4  is an axial diagram of an embodiment of a drill bit. 
         FIG. 5  is a flow diagram of an embodiment of a method of actuating a downhole drill string tool. 
         FIG. 6   a  is a representative drilling fluid flow diagram of an embodiment of a first stroke of a downhole drill string tool. 
         FIG. 6   b  is a representative drilling fluid flow diagram of an embodiment of a second stroke of a downhole drill string tool. 
         FIG. 7  is a flow diagram of an embodiment of a method of actuating a downhole drill string tool comprising a jack element. 
         FIG. 8  is a flow diagram of an embodiment of a method of actuating a downhole drill string tool comprising vibrating means. 
     
    
    
     DETAILED DESCRIPTION  
     Referring now to  FIG. 1 , a downhole drill string  101  may be suspended by a derrick  102 . The downhole drill string  101  may comprise one or more downhole drill string tools  100 , linked together in the downhole drill string  101  and in communication with surface equipment  103  through a downhole network. 
       FIG. 2  shows a cross-sectional diagram of an embodiment of a downhole drill string tool  100 A. This embodiment of a downhole drill string tool  100 A includes a percussive tool  110 . The percussive tool  110  has an inner cylinder  120  that defines an interior chamber  125 . The percussive tool  110  also has an outer cylinder  180  which may have multiple internal flutes  182  (see  FIG. 3   a ). The outer cylinder  180  substantially surrounds the internal cylinder  120  and the internal flutes  182  may be in contact with the internal cylinder  120  thus forming multiple input channels  184  and  186 . (See  FIG. 3   a ) 
     A piston element  130  sits within the interior chamber  125  and divides the interior chamber  125  into a first pressure chamber  126  and a second pressure chamber  127 . The piston element  130  may slide back and forth within the interior chamber  125  thus altering the respective volumes of the first pressure chamber  126  and the second pressure chamber  127 . The volume of the first pressure chamber  126  may be inversely related to the volume of the second pressure chamber  127 . The piston element  130  has seals  132  which may prevent drilling fluid from passing between the first pressure chamber  126  and the second pressure chamber  127 . 
     The drill string  101  has a center bore  150  through which drilling fluid may flow downhole. At the percussive tool  110 , the center bore  150  may be separated thus allowing the drilling fluid to flow past a turbine  160  which has multiple turbine blades  162 . In this embodiment, the turbine  160  acts as a driving mechanism to drive a rotary valve  170 . In other embodiments, the driving mechanism may be a motor or another suitable means known in the art. 
     The rotary valve  170  comprises a first disc  174  which is attached to the driving mechanism, the turbine  160  in this embodiment, and a second disc  172  which is axially aligned with the first disc  174  by means of an axial shaft  176 . The second disc  172  also faces the first disc  174  along a surface  173 . The first disc  174  and the second disc  172  may comprise materials selected from the group consisting of steel, chromium, tungsten, tantalum, niobium, titanium, molybdenum, carbide, natural diamond, polycrystalline diamond, vapor deposited diamond, cubic boron nitride, TiN, AlNi, AlTiNi, TiAlN, CrN/CrC/(Mo, W)S2, TiN/TiCN, AlTiN/MoS2, TiAlN, ZrN, diamond impregnated carbide, diamond impregnated matrix, silicon bounded, and diamond. A superhard material such as diamond or cubic boron nitride may line internal edges  371  (see  FIG. 3   e )of the first disc  174  and second disc  172  to increase resistance to abrasion. The superhard material may be sintered, inserted, coated, or vapor deposited. 
     The first disc  174  may have through ports  370  and exhaust ports  372 . (See  FIG. 3   f ) The second disc  172  may have first ports  374  and second ports  376 . (See  FIG. 3   e ) As drilling fluid flows down the center bore  150  and passes by the turbine blades  162  it causes the turbine  160  to rotate and drive the first disc  174 . The first disc then rotates relative to the second disc. 
     In a first stroke of the piston element  130 , as the first and second discs  174  and  172  rotate relative to one another, the through ports  370  of the first disc  174  align with the second ports  376  of the second disc  172 . This allows drilling fluid to flow into the second input channels  186 . From the second input channel a portion of the fluid flows into the first pressure chamber  126  and a portion of the fluid flows down the second input channels  186  and out a second exit orifice  386 . (See  FIGS. 3   g  and  3   h ) Also, during the first stroke the exhaust ports  372  of the first disc  174  align with the first ports  374  of the second disc  172 . This allows drilling fluid within the second pressure chamber  127  to escape to the first input channels  184  and either flow out first exit orifices  384  or flow out exhaust channel  190  to exhaust orifices  192 . 
     In a second stroke of the piston element  130 , as the first and second discs  174  and  172  rotate further relative to one another, the through ports  370  of the first disc  174  align with the first ports  374  of the second disc  172 . This allows drilling fluid to flow into the first input channels  184 . From the first input channels a portion of the fluid flows into the second pressure chamber  127  and another portion of the fluid flows down the first input channels  184  and out the first exit orifice  384 . (See  FIGS. 3   g  and  3   h ) Also during the second stroke the exhaust ports  372  of the first disc  174  align with the second ports  376  of the second disc  172 . This allows drilling fluid within the first pressure chamber  126  to escape to the second input channels  186  and either flow out second exit orifices  386  or flow out exhaust channel  190  to exhaust orifices  192 . 
     The drilling fluid may be drilling mud traveling down the drill string or hydraulic fluid isolated from the downhole drilling mud and circulated by a downhole motor. In various embodiments, the ports may be alternately opened electronically. 
     In the embodiment shown in  FIG. 2 , the first exit orifices  384  includes first exit nozzles  204 , the second exit orifices  386  includes second exit nozzles  206 , and the exhaust orifices  192  includes exhaust nozzles  209 . (See  FIG. 4 ) 
     The first exit nozzles  204 , second exit nozzles  206 , and exhaust nozzles  209  may be located on a drill bit  140 . The drill bit  140  may have a plurality of cutting elements  142 . The cutting elements  142  may comprise a superhard material such as diamond, polycrystalline diamond, or cubic boron nitride. The drill bit  140  may rotate around a jack element  138  which protrudes from the drill bit  140 . The jack element  138  may be in contact with an impact element  136 . In operation, as the piston element  130  slides within the inner cylinder  120  it may impact the impact element  136  which may force the jack element  138  to protrude farther from the drill bit  140  with repeated thrusts. It is believed that these repeated thrusts may aid the drill bit  140  in drilling through earthen formations. The jack element  138  may also have an angled end that may help steer the drill bit  140  through earthen formations. 
     One of the advantages of this embodiment is that if the first exit nozzles  204  and second exit nozzles  206  are similar in discharge area then the pressure in the first pressure chamber  126  is greater than the pressure in the second pressure chamber  127  during the first stroke and the reverse is true during the second stoke. This is true because the discharge area of the exhaust nozzles  209  added to the discharge area of the exit nozzles from which the drilling fluid is escaping will always be greater than the discharge area of the exit nozzles from which the drill fluid is not escaping. Another believed advantage of this embodiment is that the pressure differential between the first pressure chamber  126  and the second pressure chamber  127  may be able to be adjusted by adjusting the discharge area of the exhaust nozzle  209 . 
     Referring now to  FIGS. 3   a - j , which are perspective diagrams of several components of the embodiment shown in  FIG. 2 . 
       FIG. 3   a  is a perspective diagram of an embodiment of the outer cylinder  180 . As described earlier, outer cylinder  180  may have multiple internal flutes  182 . The internal flutes  182  may be in contact with the internal cylinder  120  (see  FIG. 3   b ) thus forming multiple input channels  184  and  186 . The first input channels  184  may be aligned with second openings  324  (see  FIG. 3   b ) to the second pressure chamber  127  thus allowing drilling fluid to flow into and out of the second pressure chamber  127 . The second input channels  186  may be aligned with first openings  326  (see  FIG. 3   b ) to the first pressure chamber  126  thus allowing drilling fluid to flow into and out of the first pressure chamber  126 . 
       FIG. 3   b  is a perspective diagram of an embodiment of the inner cylinder  120 . The inner cylinder  120  may have first openings  326  and second openings  324 . 
       FIG. 3   c  is a perspective diagram of an embodiment of the piston element  130 . The piston element  130  sits within the inner cylinder  120  (see  FIG. 3   b ) and separates the inner cylinder into the first pressure chamber  126  and second pressure chamber  127 . (See  FIG. 2 ) In operation, the piston element  130  may impact the impact element  136 . (See  FIG. 3   d ). 
       FIG. 3   d  is a perspective diagram of an embodiment of the impact element  136 . It is believed that the force of the piston element  130  (see  FIG. 3   c ) impacting the impact element  136  may apply repetitive force to the jack element  138  (see  FIG. 3   i ) thus aiding in the breaking up of earthen formations. 
       FIG. 3   e  is a perspective diagram of an embodiment of a second disc  172  which may form part of rotary valve  170 . (See  FIG. 2 ) Second disc  172  may include first ports  374  and second ports  376 . 
       FIG. 3   f  is a perspective diagram of an embodiment of a first disc  174  which may form another part of rotary valve  170 . (See  FIG. 2 ) First disc  174  may have through ports  370  and exhaust ports  372 . The first disc  174  may face the second disc  172  (see  FIG. 3   e ) along a surface  173 . 
       FIGS. 3   g  and  3   h  are perspective diagrams showing reverse sides of an embodiment of a flow plate  380 . The flow plate  380  may have first exit orifices  384  and second exit orifices  386  which may conduct some of the flow from first input channels  184  and second input channels  186  respectively (see  FIG. 2 ). Flow plate  380  may also have exhaust orifice  192  which may conduct some of the flow from exhaust channel  190  (see  FIG. 2 ). 
       FIG. 3   i  is a perspective diagram of an embodiment of jack element  138 . The jack element  138  may be formed of a material such as steel, chromium, tungsten, tantalum, niobium, titanium, molybdenum, carbide, natural diamond, polycrystalline diamond, vapor deposited diamond, cubic boron nitride, TiN, AlNi, AlTiNi, TiAlN, CrN/CrC/(Mo, W)S2, TiN/TiCN, AlTiN/MoS2, TiAlN, ZrN, diamond impregnated carbide, diamond impregnated matrix, silicon bounded diamond, and/or combinations thereof. 
       FIG. 3   j  is a perspective diagram of an embodiment of turbine  160 . Turbine  160  may have a substantially circular geometry. Turbine  160  may also include multiple turbine blades  162 . Turbine  160  may be adapted to rotate when drilling fluid flows past turbine blades  162 . 
       FIG. 4  is an axial diagram of an embodiment of a drill bit  140 . Drill bit  140  may include first exit nozzles  204 , second exit nozzles  206 , and exhaust nozzles  209 . Drill bit  140  may also include a plurality of cutting elements  142 . Drill bit  140  may rotate around a jack element  138  which protrudes from the drill bit  140 . 
       FIG. 5  is a flow diagram of an embodiment of a method of actuating a downhole drill string tool  500 . Method  500  comprises the steps of rotating a rotary valve by means of a driving mechanism  502 ; aligning at least one port formed in a first disc with at least one port formed in a second disc  504 ; supplying drilling fluid from at least one second input channel to a first pressure chamber and to at least one second exit orifice  506 ; releasing drilling fluid from a second pressure chamber to at least one first exit orifice and at least one exhaust orifice  508 ; realigning the at least one port formed in the first disc with the at least one port formed in the second disc  510 ; supplying drilling fluid from the at least one first input channel to the second pressure chamber and to the at least one first exit orifice  512 ; and releasing drilling fluid from the first pressure chamber to the at least one second exit orifice and the at least one exhaust orifice  514 . The rotating a rotary valve by means of a driving mechanism  502  may comprise passing drilling fluid past a turbine with multiple turbine blades which then rotates a rotary valve. The rotating  502  may also comprise rotating a motor or other driving means known in the art. 
       FIGS. 6   a  and  6   b  are drilling fluid flow diagrams representing embodiments of first and second strokes  600  and  610  respectively of a downhole drill string tool.  FIG. 6   a  represents a piston element  630  sitting within an interior chamber  625  and dividing it into a first pressure chamber  626  and a second pressure chamber  627 . During the first stroke  600 , first input channels  684  are sealed, as indicated by the x next to the reference number, and second input channels  686  are open thus allowing drilling fluid to flow into first pressure chamber  626  and out a second exit orifice  696 . Meanwhile, drilling fluid within second pressure chamber  627  is allowed to escape out of first exit orifice  694  and exhaust orifice  692 . If the discharge areas of first exit orifice  694  and second exit orifice  696  are similar then the additional discharge area of the exhaust orifice  692  will cause the pressure in the first pressure chamber  626  to be greater than the pressure in the second pressure chamber  627  during the first stroke  600  causing the piston element  630  to move away from the first pressure chamber  626  and toward the second pressure chamber  627 . The pressure differential between the first pressure chamber  626  and the second pressure chamber  627  will be able to be adjusted by adjusting the size of the exhaust orifice  692 . 
     During second stroke  610 , second input channels  686  are sealed, as indicated by the x next to the reference number, and first input channels  684  are open thus allowing drilling fluid to flow into second pressure chamber  627  and out a second exit orifice  696 . Meanwhile, drilling fluid within first pressure chamber  626  is allowed to escape out of second exit orifice  696  and exhaust orifice  692 . This will cause the pressure in the second pressure chamber  627  to be greater than the pressure in the first pressure chamber  626  causing the piston element  630  to move away from the second pressure chamber  627  and toward the first pressure chamber  626 . 
       FIG. 7  is a flow diagram of an embodiment of a method of actuating a downhole drill string tool comprising a jack element  700 . Method  700  comprises the steps of rotating a rotary valve by means of a driving mechanism  702 ; aligning at least one port formed in a first disc with at least one port formed in a second disc  704 ; supplying drilling fluid from at least one second input channel to a first pressure chamber and to at least one second exit orifice  706 ; releasing drilling fluid from a second pressure chamber to at least one first exit orifice and at least one exhaust orifice  708 ; realigning the at least one port formed in the first disc with the at least one port formed in the second disc  710 ; supplying drilling fluid from the at least one first input channel to the second pressure chamber and to the at least one first exit orifice  712 ; releasing drilling fluid from the first pressure chamber to the at least one second exit orifice and the at least one exhaust orifice  714 ; wherein the first exit orifice includes a nozzle, the second exit orifice includes a nozzle, and the exhaust orifice includes a nozzle, altering the discharge area of the exhaust nozzle to change the pressure differential between the first pressure chamber and the second pressure chamber  716 ; contacting a piston element slidably sitting intermediate the first pressure chamber and second pressure chamber with a jack element substantially coaxial with an axis of rotation, partially housed within a bore of the drill string tool, and having a distal end extending beyond a working face of the drill string tool  718 ; and rotating the working face of the drill string tool around the jack element  720 . It is believed that the percussive action of the jack element will help break up earthen formations that may be surrounding the downhole drill string tool and thus allow it to progress more rapidly through the earthen formations. 
       FIG. 8  is a flow diagram of an embodiment of a method of actuating a downhole drill string tool comprising vibrating means  800 . Method  800  comprises the steps of rotating a rotary valve by means of a driving mechanism  802 ; aligning at least one port formed in a first disc with at least one port formed in a second disc  804 ; supplying drilling fluid from at least one second input channel to a first pressure chamber and to at least one second exit orifice  806 ; releasing drilling fluid from a second pressure chamber to at least one first exit orifice and at least one exhaust orifice  808 ; realigning the at least one port formed in the first disc with the at least one port formed in the second disc  810 ; supplying drilling fluid from the at least one first input channel to the second pressure chamber and to the at least one first exit orifice  812 ; releasing drilling fluid from the first pressure chamber to the at least one second exit orifice and the at least one exhaust orifice  814 ; and contacting a piston element slidably sitting intermediate the first pressure chamber and second pressure chamber with a weight sufficient to vibrate the downhole drill string tool  816 . It is believed that the percussive action of the weight will help downhole drill string tool break free when caught on earthen formations that may be surrounding the downhole drill string tool and otherwise allow it to progress more rapidly through the earthen formations. 
     Whereas the present invention has been described in particular relation to the drawings attached hereto, it should be understood that other and further modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present invention.

Technology Category: 0