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CROSS REFERENCE TO RELATED APPLICATIONS 
     This patent application is a continuation of U.S. patent application Ser. No. 12/473,444 filed on May 28, 2009 which is a continuation-in-part of U.S. patent application Ser. No. 12/262,372 filed on Oct. 31, 2008 and which is now U.S. Pat. No. 7,730,972 issued on Jun. 8, 2010, which is a continuation-in-part of U.S. patent application Ser. No. 12/178,467 filed on Jul. 23, 2008 and which is 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 which 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 which is 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 which is now U.S. Pat. No. 7,617,886, which is a continuation-in-part of U.S. patent application Ser. No. 11/837,321 filed on Aug. 10, 2007 and which is now U.S. Pat. No. 7,559,379, which is a continuation-in-part of U.S. patent application Ser. No. 11/750,700 filed on May 18, 2007 and which is 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 which is 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 which is 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 which is 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 which is 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 which is now U.S. Pat. No. 7,600,586 issued on Oct. 13, 2009. 
     U.S. patent application Ser. No. 12/039,608 is also a continuation-in-part of U.S. patent application Ser. No. 11/278,935 filed on Apr. 6, 2006 and which is 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 which is 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 which is now U.S. Pat. No. 7,337,858 issued on March 4, 2008, which is a continuation-in-part of U.S. patent application Ser. No. 11/306,976 filed on Jan. 18, 2006 and which is now U.S. Patent 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 which is 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 which is 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 which is now U.S. Pat. No. 7,270,196 issued on Sep. 18, 2007. 
     U.S. patent application Ser. No. 12/039,608 is also a continuation-in-part of U.S. patent application Ser. No. 11/555,334 filed on Nov. 1, 2006 and which is 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 
     This invention relates to the field of downhole turbins used in drilling. More Specifically, the invention relates to controlling the rotational velocith of downhole turbines. 
     Previous attempts at controlling downhole turbine speed were performed by diverting a portion of the drilling fluid away from the turbine. It was believed that the diversion of drilling fluid away from the turbine results in less torque on the turbine itself. However, this technique may also require the additional expense of having to over design the turbine to ensure that sufficient torque is delivered when fluid flow is restricted. 
     U.S. Pat. No. 5,626,200 to Gilbert et al., which is herein incorporated by reference for all that it contains, discloses a logging-while-drilling tool for use in a wellbore in which a well fluid is circulated into the wellbore through a hollow drill string. In addition to measurement electronics, the tool includes an alternator for providing power to the electronics, and a turbine for driving the alternator. The turbine blades are driven by the well fluid introduced into the hollow drill string. The tool also includes a deflector to deflect a portion of the well fluid away from the turbine blades. 
     U.S. Pat. No. 5,839,508 to Tubel et al., which is herein incorporated by reference for all that it contains, discloses an electrical generating apparatus which connects to the production tubing. In a preferred embodiment, this apparatus includes a housing having a primary flow passageway in communication with the production tubing. The housing also includes a laterally displaced side passageway communicating with the primary flow passageway such that production fluid passes upwardly towards the surface through the primary and side passageways. A flow diverter may be positioned in the housing to divert a variable amount of the production fluid from the production tubing and into the side passageway. In accordance with an important feature of this invention, an electrical generator is located at least partially in or along the side passageway. The electrical generator generates electricity through the interaction of the flowing production fluid. 
     U.S. Pat. No. 4,211,291 to Kellner, which is herein incorporated by reference for all it contains, discloses a drill fluid powered hydraulic system used for driving a shaft connected to a drill bit. The apparatus includes a hydraulic fluid powered motor actuated and controlled by hydraulic fluid. The hydraulic fluid is supplied to the hydraulic fluid powered motor through an intermediate drive system actuated by drill fluid. The intermediate drive system is provided with two rotary valves and two double sided accumulators. One of the rotary valves routes the hydraulic fluid to and from the accumulators from the drill fluid supply and from the accumulators to the drill bit. The rotary valves are indexed by a gear system and Geneva drive connected to the motor or drill shaft. A heat exchanger is provided to cool the hydraulic fluid. The heat exchanger has one side of the exchange piped between the drill fluid inlet and the drill fluid rotary valve and the other side of the exchange piped between the hydraulic fluid side of the accumulators and the hydraulic fluid rotary valve. 
     U.S. Pat. No. 4,462,469 to Brown, which is herein incorporated by reference for all that it contains, discloses a motor for driving a rotary drilling bit within a well through which mud is circulated during a drilling operation, with the motor being driven by a secondary fluid which is isolated from the circulating mud but derives energy therefrom to power the motor. A pressure drop in the circulating mud across a choke in the drill string is utilized to cause motion of the secondary fluid through the motor. An instrument which is within the well and develops data to be transmitted to the surface of the earth controls the actuation of the motor between different operation conditions in correspondence with data signals produced by the instrument, and the resulting variations in torque in the drill string and/or the variations in torque in the drill string and/or the variations in circulating fluid pressure are sensed at the surface of the earth to control and produce a readout representative of the down hole data. 
     U.S. Pat. No. 5,098,258 to Barnetche-Gonzalez, which is herein incorporated by reference for all that it contains, discloses a multistage drag turbine assembly provided for use in a downhole motor, the drag turbine assembly comprising an outer sleeve and a central shaft positioned within the outer sleeve, the central shaft having a hollow center and a divider means extending longitudinally in the hollow center for forming first and second longitudinal channels therein. A stator is mounted on the shaft. The stator has a hub surrounding the shaft and a seal member fixed to the hub wherein the hub and the shaft each have first and second slot openings therein. A rotor comprising a rotor rim and a plurality of turbine blades mounted on the rotor rim is positioned within the outer sleeve for rotation therewith with respect to the stator such that a flow channel is formed in the outer sleeve between the turbine blades and the stator. A flow path is formed in the turbine assembly such that fluid flows though the turbine assembly, flows through the first longitudinal channel in the central shaft, through the first slot openings in the shaft and the stator hub, through the flow channel wherein the fluid contacts the edges of the turbine blades for causing a drag force thereon, and then through the second slot openings in the stator hub and the shaft into the second channel. 
     BRIEF SUMMARY 
     In one aspect of the present invention, a downhole drill string assembly has a bore formed there through formed to accept drilling fluid. The assembly also includes a turbine disposed within the bore. The turbine has at least one turbine blade and is in communication with a generator, a gear box, a steering assembly, a hammer element, a pulse telemetry device or any combination thereof. 
     The downhole drill string assembly further includes at least one flow guide disposed within the bore. The flow guide may be controlled by a feedback loop. The at least one flow guide may include a fin, an adjustable vein, a flexible surface, a pivot point or any combination thereof. The flow guide may be in communication with an actuator. The actuator may be a rack and pinion, a solenoid valve, an aspirator, a hydraulic piston, a flange, a spring, a pump, a motor, a plate, at least one gear, or a combination thereof. 
     In another aspect of embodiments of the present invention, a method for adjusting the rotation of a turbine is disclosed. This method comprises the steps of providing a downhole drill string assembly having a bore there through to receive drilling fluid, a turbine disposed within the bore and exposed to the drilling fluid, and at least one flow guide disposed within the bore and exposed to the drilling fluid. Then adjusting the flow guide to alter the flow of the drilling fluid, wherein the altered flow of the drilling fluid adjusts the rotation of the turbine. 
     The adjustment of the rotation of the turbine may comprise slowing down or speeding up of the rotational velocity of the turbine, or increasing or decreasing the rotational torque of the turbine. The adjustments may be controlled by a downhole telemetry system, a processing unit, a control loop, or any combination of the previous. The control loop may control the voltage output from a generator, a rotational velocity of the turbine, or a rotational torque from the turbine. The gain values of the control loop may be adjustable by an uphole computer and fed down to the turbine by a telemetry system or may be autonomously generated by prior programming against a preset target. 
     The assembly may further include a hammer disposed within the drill string and mechanically coupled to the turbine, wherein an actuation of the hammer is changed by adjusting the rotation of the turbine. The change in the actuation of the hammer may take the form of a change in frequency. This change in actuation may allow the hammer to be used to communicate uphole. The actuating hammer may be able to communicate through acoustic waves, vibrations of the drill string assembly, or changes in pressure created by the hammer impacting the formation or by the hammer impacting a surface within the drill string assembly. The turbine itself may also create a pressure pulse for use in communication or the turbine may actuate a valve to create a pressure pulse for use in communication. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a orthogonal diagram of an embodiment of a drill string assembly suspended in a cross section of a bore hole. 
         FIG. 2  is a cross-sectional diagram of an embodiment of a drill string assembly. 
         FIG. 3  is a perspective diagram of an embodiment of a turbine, flow guide, and actuator. 
         FIG. 4   a  is another perspective diagram of an embodiment of a turbine, flow guide, and actuator. 
         FIG. 4   b  is another perspective diagram of an embodiment of a turbine, flow guide, and actuator. 
         FIG. 5  is another perspective diagram of an embodiment of a turbine, flow guide, and actuator. 
         FIG. 6  is a perspective diagram of an embodiment of a flow guide and actuator. 
         FIG. 7  is another perspective diagram of an embodiment of a turbine, flow guide, and actuator. 
         FIG. 8  is another perspective diagram of an embodiment of a turbine, flow guide, and actuator. 
         FIG. 9  is a cross-sectional diagram of an embodiment of a turbine, flow guide, and actuator. 
         FIG. 10   a  is another cross-sectional diagram of an embodiment of a turbine, flow guide, and actuator. 
         FIG. 10   b  is another cross-sectional diagram of an embodiment of a turbine, flow guide, and actuator. 
         FIG. 11  is another cross-sectional diagram of an embodiment of a turbine, flow guide, and actuator. 
         FIGS. 12   a  and  12   b  are side view diagrams of an embodiment of a turbine comprising dynamic turbine blades. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 1  is a an orthogonal diagram of an embodiment of a drill string  100  suspended by a derrick  108  in a bore hole  102 . A downhole drill string component having a drilling assembly  103  is located at a bottom of the bore hole  102  and includes a drill bit  104 . As the drill bit  104  rotates downhole, the drill string  100  advances farther into a subterranean formations  105  having the bore hole  102 . The drilling assembly  103  and/or downhole components may have data acquisition devices adapted to gather data that may be used identify a desirable formation  107  and to aid the drill string  100  in accessing the desirable formation  107 . The data may be sent to the surface via a transmission system to a data swivel  106 . The data swivel  106  may send data and/or power to the drill string  100 . U.S. Pat. No. 6,670,880 to Hall et al. which is herein incorporated by reference for all that it contains, discloses a telemetry system that may be compatible with the present invention; however, other forms of telemetry may also be compatible such as systems that include mud pulse systems, electromagnetic waves, radio waves, wired pipe, and/or short hop. The data swivel  106  may be connected to a processing unit  110  and/or additional surface equipment. 
     Referring now to  FIG. 2 , a drilling assembly  103 A compatible with drill string  100  is illustrated. The drilling assembly  103 A may have a jack element  202 A. The jack element  202 A aids in formation penetration and in steering the drill string. A first turbine  207 A and a second turbine  240 A may be located within a bore  208 A formed in the drilling assembly  103 A. The first turbine  207 A or the second turbine  240 A may be adapted for a variety of purposes including, but not limited to power generation, jack element actuation, steering, or hammer actuation. 
     In the embodiment of  FIG. 2  the first turbine  207 A is adapted to rotate the jack element  202 A and the second turbine  240 A is adapted to actuate a hammer element  234 A. A gearbox  211 A disposed in the bore  208 A is adapted to transfer torque from the first turbine  207 A to the jack element  202 A. The rotational speed of the first turbine  207 A is adjustable such that the rotational speed of the jack element  202 A changes. The rotational speed of the second turbine  240 A is adjustable such that the actuation of the hammer element  234 A changes. A downhole processing unit  203 A disposed within the bore  208 A is in communication with a first actuator  204 A and a second actuator  241 A. In the embodiment of  FIG. 2 , the actuators  203 A,  241 A includes planetary gear systems  206 A. The first actuator  204 A in further communication with a first at least one flow guide  205 A, and the second actuator  241 A is in turn in communication with a second at least one flow guide  245 A. The downhole processing unit  203 A controls the actuators  204 A,  245 A independently such that the first at least one flow guides  205 A and the second at least one flow guide  245 A are manipulated causing the first turbine  207 A and the second turbine  240 A to change speeds independently. 
     Adjusting the second at least one flow guide  245 A causes the second turbine  240 A to change rotational speed thereby causing the frequency of the actuation of the hammer element  234 A to change. Through the changing of the frequency of the actuation of the hammer element  234 , uphole communication is possible. The communication signals may take the form of the hammer element  234 A creating acoustic waves from an impact of the hammer element  234 A on the formation, or the impact of the hammer element  234 A on a surface  246 A within the drill string assembly  103 A. The communication signals may also take the form of a vibration of the tool string assembly  103 A or pressure changes of a drilling fluid within the tool string assembly  103 A caused by the hammer element&#39;s  234 A actuation. An uphole sensor such as a geophone, a pressure sensor, or an acoustic sensor may be used to receive the communications uphole. Communication along the drill string may also take the form of pressure pulses created by changing the rotational speed of the first turbine  207 A and/or the second turbine  240 A, or by rotating a valve with the first turbine  207 A of the second turbine  240 A. 
     The processing unit  203 A may also be in communication with a downhole telemetry system, such that an uphole operator can send commands to the first actuator  204 A and the second actuator  241 A. The processing unit  203 A may also have a feedback loop that controls the actuator  204 A. The feedback loop may be controlled by an output of the first turbine  207 A and/or the second turbine  240 A. The controlling output of the first turbine  207 A and/or the second turbine  240 A may include a voltage output from a generator (not shown) that is powered by the first turbine  207 A or the second turbine  240 A respectively, a desired rotational velocity of first turbine  207 A or the second turbine  240 A respectively, or a desired rotational torque of the first turbine  207 A or the second turbine  240 A respectively. The controlling gains of the feedback loop and other aspects of the feedback loop may be adjustable by an uphole computer. 
       FIG. 3  is a perspective diagram of a portion of an embodiment of a drilling assembly  103 B. In this figure a turbine  207 B, an actuator  204 B and at least one flow guide  205 B are depicted. The actuator  204 B in this embodiment is a plate  301 B. The plate  301 B is disposed axially around the drilling assembly  103 B. The plate  301 B includes pass through slots  302 B adapted to allow fluid to flow through the plate  301 B. The plate  301 B includes attachment points  303 B adapted to attach to at least one flow guide  205 B. The at least one flow guide  205 B has a clamp  305 B. 
     The clamp  305 B is adapted to attach to the drill assembly  103 B through a connection point  304 B. The flow guide  205 B includes a flexible vane  306 B. 
     As drilling fluid travels down the drill string and enters into the drilling assembly  103 B the turbine  207 B may begin to rotate. The rotational force generated by the turbine  207 B may be used for a variety of applications including but not limited to generating power or actuating devices downhole. It may be beneficial to control the rotational speed of the turbine  207 B to better meet requirements at a given time. 
     The plate  301 B may be part of an actuator  204 B such as a gear system or motor that actuates rotational movement. Alternatively, the plate  301 B may hold the flow guide  205 B stationary. A downhole processing unit disposed within the drill string (see  FIG. 2 ) or surface processing unit (see  FIG. 1 ) may be in communication with the plate  301 B through the actuator  204 B. Rotating the plate  301 B may cause the vanes  306 B to flex and bend such that a downwash angle of the drilling fluid may change below the at least one flow guide  205 B. The flexible vanes  306 B of the flow guide  205 B may also restrict the rotational movement of the plate  301 B. 
       FIGS. 4   a  and  4   b  illustrate the portion of an embodiment of a drilling assembly  103 B of  FIG. 3  and depict the flexible vanes  306 B in various positions. In this embodiment, drilling fluid  410 B is depicted flowing down the drill string and engaging the turbine  207 B. Adjusting the flexible vanes  306 B by rotating  454  the plate  301 B flexes the flexible vanes  306 B and changes the downwash angle that the drilling fluid  410 B will engage the turbine  207 . Changing the downwash angle causes the turbine  207 B to travel at different speeds based upon the rotation  454  of the plate  301 B. This method is used to slow down or speed up the turbine  207 B or to increase or decrease the torque from the turbine  207 .  FIG. 4   a  depicts the plate  301 A having no torque applied to it. In this orientation the vanes  306 B are not flexed or bent. The drilling fluid  410  may flow past the vanes  306 B nearly uninterrupted. The drilling fluid  410 B may go on to exert a force on the turbine  207 B by generating lift as it passes the turbine  207 B. In  FIG. 4   b  the plate  301 B has a torque applied to it rotating the plate such that the vanes  306 B are flexed. The flexed vanes  306 B change the downwash angle of the drilling fluid  410 B. The drilling fluid  410 B engages the turbine  207 B at an angle. The turbine  207 B turns faster in this case due to increased lift than it would in the case depicted in  FIG. 4   a.    
       FIG. 5  depicts a diagram of a portion of an embodiment of a drilling assembly  103 C comprising at least one flow guide  205 C, a turbine  207 C, and a generator  572 C. In this embodiment the rotation of the turbine  207 C actuates the generator  572 C creating electrical power. The at least one flow guide  205 C may be controlled by a feedback loop that is driven by the output voltage of the generator  572 C. In one embodiment, the feedback loop positions the at least one flow guide  205 C in such a way as to prevent the generator  572 C from creating either too little power or too much power. Excess power created by the generator  572 C may turn into heat which can adversely affect downhole instruments and too little power may prevent downhole instruments from operating. 
     In another embodiment, the positioning of the at least one flow guide  205 C is set by an uphole user. An uphole user may set the position of the at least one flow guide  205 C based upon a flow rate of drilling fluid entering the drilling assembly  103 C, based upon a desired power output, or based upon some other desired parameter. 
       FIG. 6  depicts a portion of an embodiment of a drilling assembly  103 D having an actuator  204 D and at least one flow guide  205 D. In this this embodiment the at least one flow guide  205 D is a rigid fin  503 D. The fin  503 D attaches to the drill string through a pivot point  504 D. The actuator  204 D in this embodiment is a plate  301 D with slots  501 D disposed around its circumference. The slots  501 D are adapted to receive tabs  502 D disposed on the fins  503 D. The actuator  204 D controls the fins  503 D by rotating the plate  301 D such that the tabs  502 D engaged within the slots  501  cause the fins  503 D to rotate on their pivot point  504 D. The rotated fins  503 D cause drilling fluid to change the angle at which it engages a turbine (not shown). 
       FIG. 7  is a diagram of an embodiment an embodiment of a drilling assembly  103 E having a turbine  207 E, an actuator  204 E, and at least one flow guide  205 E. The flow guides  205 E in the embodiment of  FIG. 7  are fins  503 . In this embodiment the actuator  204 E comprises a rack  601 E and pinion  602 E. The rotation of the rack  601 E causes the fins  503 E to rotate around a pivot point  504 E. The rotated fins  503 E change the angle at which drilling fluid engages the turbine  207 E thereby changing the rotational speed of the turbine  207 E. 
       FIG. 8  is a depiction of another embodiment of a drilling assembly  103 F having a turbine  207 F, an actuator  204 F and at least one flow guide  205 F. In this embodiment the actuator  204 F is a slider  701 F. The slider  701 F is disposed radially around a central axis of the drilling assembly  103 F. The actuator  204 F includes a motor, a pump, a piston, at least one gear, or a combination thereof, adapted to move the slider  701 F parallel to the central axis of the drilling assembly  103 F. The slider  701 F has at least one flange  702 F. The flow guide  205 F is a fin  503 F connected to the drill string at a pivot point  504 F. The flow guide  205 F further includes a lip  703 F. The flange  702 F of the slider  701 F is adapted to fit on the lip  703 F of the flow guide  205 F. As the slider  701 F moves towards the flow guide  205 F the flange  702 F exerts a force on the lip  703 F causing the fins  503 F to rotate. The rotated fins  503 F change the angle at which drilling fluid engages the turbine  207 F, generating additional lift, and changing the rotational speed of the turbine  207 F. 
       FIG. 9  is a cross-sectional diagram depicting an embodiment of a drilling assembly  103 G. In this embodiment the actuator  204 G includes a solenoid valve  800 G. The solenoid valve  800 G includes a coil of wire  801 G wrapped circumferentially around a central axis of the drilling assembly  103 G. When the coil of wire  801 G is electrically excited, a slider  701 G is displaced such that a flow guide  205 G is actuated. A preloaded torsion spring  802 G may then return the flow guide  205 G to an original position after the solenoid valve  800 G disengages. 
       FIGS. 10   a  and  10   b  depict another embodiment of a drilling assembly  103 H having a turbine  207 H, an actuator  204 H, and a flow guide  205 H. The drill string assembly  103 H has a plurality of turbines  207 H. In this embodiment, the flow guide  205 H a funnel  905 H. As the funnel  905 H is axially translated it alters the flow space across the turbines  207 H. As the funnel  905 H restricts the flow space across the turbines  207 H the drilling fluid velocity increases thus increasing the rotational speed of the turbines  207 H. 
     The funnel  905 H may be axially translated by means of a Venturi tube  910 H. The Venturi tube  910 H has at least one constricted section  915 H of higher velocity and lower pressure drilling fluid and at least one wider section  920 H of lower velocity and higher pressure drilling fluid. The Venturi tube  910 H also has at least one low pressure aspirator  930 H and at least one high pressure aspirator  940 H. The at least one low pressure aspirator  930 H that may be opened by at least one low pressure valve  935 H and the at least one high pressure aspirator  940 H may be opened by at least one high pressure valve (not shown). When the high pressure aspirator  940 H is opened and the low pressure aspirator  930 H is closed, the drilling fluid flows from the bore  208 H to a chamber  950 H. A piston element  955 H attached to the funnel  905 H and slidably housed within the chamber  950 H forms a pressure cavity. As drilling fluid flows into the chamber  950 H the pressure cavity expands axially translating the funnel  905 H. (See  FIG. 10   a ) If the low pressure aspirator  930 H is opened and the high pressure aspirator  940 H is closed, the drilling fluid flows from the pressure chamber  950 H to the bore  208 H. As drilling fluid flows out of the chamber  950 H the pressure cavity contracts reversing the axial translation of the funnel  905 H. (See  FIG. 10   b ) 
       FIG. 11  illustrates an embodiment of a flow guide  205 J in the form of a funnel  905 J. In this embodiment the funnel  905 J may be axially translated by means of at least one motor  1001 J. The motor  1001 J is in communication with a rack  1005 J and pinion  1010 J. The rack  1005 J is connected to the funnel  905 J and the pinion  1010 J is a worm gear. As the pinion  1010 J is rotated by the motor  1001 J the rack  1005 J and funnel  905 J are axially translated. 
       FIGS. 12   a  and  12   b  illustrate an embodiment of a turbine  207 K having at least one turbine blade  1107 . The turbine blade  1107  is aligned along an initial vector  1110 . The turbine blade  1107  may rotate a given angle  1115  to a subsequent vector  1120 . The given angle  1115  may remain the same for several rotations of the turbine blade  1107  or the given angle  1115  may vary for different rotations. Rotation of the turbine blade  1107  from the initial vector  1110  to the subsequent vector  1120  may alter the rotational speed of the turbine  207 K. 
     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.

Summary:
In one aspect of the present invention, a downhole drill string assembly comprises a bore there through to receive drilling fluid. A turbine may be disposed within the bore and exposed to the drilling fluid. At least one flow guide may be disposed within the bore and exposed to the drilling fluid wherein the flow guide acts to redirect the flow of the drilling fluid across the turbine. The flow guide may be adjusted by an actuator. Adjustments to the flow guide may be controlled by a downhole telemetry system, a processing unit, a control loop, or any combination thereof. In various embodiments the turbine may comprise rotatable turbine blades.