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[0001]    This disclosure is related to U.S. patent application Ser. No. 11/848,328 filed on Aug. 31, 2008, and Ser. No. 12/344,873 filed Dec. 28, 2008 both of which are hereby entered into this disclosure by reference. 
     
    
     FIELD OF THE INVENTION 
       [0002]    This invention is related to the directional drilling of a well borehole. More particularly, the invention is related to minimizing adverse effects, in mud pulse telemetry, of drilling fluid pressure fluctuations used to operate directional drilling apparatus. 
       BACKGROUND 
       [0003]    The complex trajectories and multi-target oil wells require precision placement of well borehole path and the flexibility to continually maintain path control. It is preferred to control or “steer” the direction or path of the borehole during the drilling operation using measurement-while-drilling (MWD) methodology. It is further preferred to control the path rapidly during the drilling operation at any depth and target as the borehole is advanced by the drilling operation. In addition, it is preferred to alter the path of the borehole while maintaining rotation of the drill string, and to simultaneously telemeter borehole information to the surface of the earth. 
         [0004]    Many types of directional steering assemblies, comprising a motor disposed in a housing with an axis displaced from the axis of the drill string, are known in the prior art. The motor can be a variety of types including electric, or hydraulic. Hydraulic turbine motors are operated by circulating drilling fluid and are commonly known as a “mud” motors. A rotary bit is attached to a shaft of the motor, and is rotated by the action of the motor. The axially offset motor housing, commonly referred to as a bent subsection or “bent sub”, provides axial displacement that can be used to change the trajectory of the borehole. By rotating the drill bit with the motor and simultaneously rotating the drill bit with the drill string, the trajectory or path of the advancing borehole is parallel to the axis of the drill string. By rotating the drill bit with the motor only, the trajectory of the borehole is deviated from the axis of the drill string. By alternating these two methodologies of drill bit rotation, the path of the borehole can be controlled. While deviating the borehole, the non-rotating drill string can cause operational problems. More specifically, static friction between the non-rotating drill string and the borehole wall creates static friction that impedes drilling efficiency. A more detailed description of directional drilling using the bent sub concept is disclosed in U.S. Pat. Nos. 3,260,318, and 3,841,420, which are herein entered into this disclosure by reference. 
         [0005]    Borehole steering assemblies are typically disposed near the drill bit, which terminates the lower or “down hole” end of a drill string. In order to obtain the desired real time directional control, it is preferred to operate the steering device remotely from the surface of the earth. This requires a two-way telemetry system between the BHA and the surface of the earth. The most common MWD telemetry system uses mud pulse methodology to transmit data between the BHA and the surface of the earth. 
         [0006]    Steering systems have been developed that allow controlled borehole steering while maintaining rotation of the drill string. These systems will be referred to, in this disclosure, as “directional drilling systems”. Continuous rotation of the drill string allowed by these systems minimizes previously mentioned operational problems resulting from static friction between the drill string and the borehole wall. Directional drilling systems alter or perturb one or more drilling parameters during a portion of a revolution of drill string. This periodic perturbation removes a disproportional amount of material from the wall of the borehole resulting in a deviation of the borehole path. 
         [0007]    Previously referenced U.S. patent application Ser. No. 11/848,328 discloses a directional drilling system that periodically increases the bit rotation rate over a predetermined arc of each drill string rotation. This results in the desired disproportional removal of borehole wall material thus resulting in borehole deviation in the azimuthal direction of the predetermined arc. The periodic increase in bit rotation is accomplished by periodically increasing the mud flow through the mud motor which, in turn, induces a pressure pulse in the stand pipe of the drilling rig. 
         [0008]    Previously referenced U.S. patent application Ser. No. 12/344,873 discloses another type of directional drilling system that periodically increases the rate of penetration of the bit over a predetermined arc of each drill string rotation. This again results in the desired disproportional removal of borehole wall material thus resulting in borehole deviation in the azimuthal direction of the predetermined arc. The periodic increase in rate of penetration is again accomplished by periodically increasing the mud flow as the bit rotates through the predetermined arc, and again results in a pressure pulse in the stand pipe. 
         [0009]    As mentioned previously, it is highly advantageous to control a directional drilling operation in real time from the surface of the earth. In order to obtain the desired real time directional control, a two-way telemetry system between the BHA and the surface of the earth is required, and the most common MWD telemetry system is a mud pulse system. Data from downhole sensors and from surface commands are encoded for transmission by varying the pressure or “pulsing” the pressure of the drilling mud column. These pressure pulses are subsequently decoded to extract transmitted data. 
         [0010]    As mentioned previously, the above described directional drilling systems are also controlled by drilling mud pressure pulses, with these pressure pulses resulting in drilling fluid standpipe pressure fluctuations. The steering system pressure fluctuations will typically occur once per revolution of the drill string, but steering systems can use multiple periodic pressure fluctuations per revolution. Drilling fluid pressure variations caused by the steering system interfere with pressure variations induced by the mud pulse telemetry system. It is, therefore, necessary to remove the effects of periodic steering system pulses to allow the mud pulse telemetry system to operate properly. 
       SUMMARY OF THE INVENTION 
       [0011]    This invention comprises apparatus and methods for removing the effects of directional drilling systems drilling fluid pulses to allow a MWD mud pulse telemetry system to operate without interference. The methodology is based upon Synchronous Time Averaging (STA) which has been used to remove cyclical (or synchronous) “noise” in electromagnetic telemetry system as disclosed in U.S. Pat. No. 7,609,169, which is herein entered into this disclosure by reference. 
         [0012]    With STA, any pressure fluctuation that is cyclical (or synchronous) with a measurable event can be profiled and subsequently subtracted from a mud pulse telemetry signal. STA functions by placing a strobe in such a manner that the strobe is triggered for each cyclical event. The cyclical event in this disclosure is one (or more) revolution(s) of the drill string. If there is a pressure fluctuation that correlates to that cyclical event, it will be identified by a stable profile of that pressure fluctuation. This pressure profile is then used to remove the cyclical pressure fluctuation from the mud pulse telemetry signal thereby allowing normal operation of the mud pulse telemetry system. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0013]    The manner in which the above recited features and advantages, briefly summarized above, are obtained can be understood in detail by reference to the embodiments illustrated in the appended drawings. 
           [0014]      FIG. 1  illustrates a MWD system comprising a directional drilling system and a synchronous time averaging system to eliminate steering pressure fluctuations at the surface; 
           [0015]      FIG. 2   a  depicts a strobe increment of 360 degrees; 
           [0016]      FIG. 2   b  depicts strobe increments of 90 degrees; 
           [0017]      FIG. 2   c  depicts a strobe increment of 720 degrees; 
           [0018]      FIG. 3  is a conceptual flow chart of one embodiment of STA system for minimizing cyclical noise in a mud pulse telemetry system; 
           [0019]      FIG. 4   a  is a plot of pressure representing a composite signal R measured over a single strobe increment for one revolution of the drill string; 
           [0020]      FIG. 4   b  is the plot of a sum of pressures measured over a plurality of strobe increments; 
           [0021]      FIG. 4   c  shows a normalized plot of a cyclical pulse used to operate a directional drilling system; and 
           [0022]      FIG. 4   d  shows a mud pulse telemetry signal from which the directional drilling system pulse has been removed. 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       [0023]    A preferred embodiment of this invention comprises apparatus and methods for removing the effects of directional drilling system drilling fluid pulses to allow a MWD mud pulse telemetry system to operate without interference. The methodology is based upon Synchronous Time Averaging (STA) techniques, although the same methodology can be used in synchronous rotational arc averaging as will be subsequently illustrated. 
         [0024]    Synchronous time averaging is used to identify cyclical noise in mud pulse telemetry response. This telemetry response, which comprises a “signal” component and a “noise” component, will hereafter be referred as the “composite” signal. The signal component typically represents response data from one or more sensors disposed within a borehole assembly (BHA), or data transmitted from the surface to the BHA. The noise component can represent any type of cyclical or synchronous noise. In this disclosure, the noise component represents one or more cyclical pressure pulses used in previously defined directional drilling systems. A strobe is triggered by a cooperating trigger, responsive to a stimulus, to record during a predetermined “strobe increment”, a plurality of “increment composite noise signals”. The stimulus can be a switch, reflector, magnet, protrusion, indention, time signal, or any suitable means to operate the trigger and cooperating strobe. These increment composite noise signals are algebraically summed Any non cyclical pressure pulse components (such as random pulses representing BHA sensor responses) occurring during the strobe increment will approach a constant value in the summing operation. Any cyclical noise occurring during the strobe increment and in synchronization with the strobe increment (such as pressure pulses used in directional drilling systems) will be emphasized by the algebraic summing. The trigger-strobe-summing methodology produces a signature or “picture” of any cyclical noise component occurring synchronously with the strobe increment. This noise component is then combined with the measured composite signal to remove, or to at least minimize, cyclical noise allowing the mud pulse telemetry system to operate optimally. 
         [0025]    As mentioned above, the technique is not limited to time averaging. Strobe increments can be defined in units of degrees of an arc as well as an increment of time. In the former case, the process would actually comprise “arc” averaging rather than “time” averaging. For purposes of discussion, the averaging process will be generally referred to as STA although arc averaging will be used to conceptually illustrate the system. 
         [0026]    The directional drilling system exemplified by U.S. patent application Ser. No. 11/843,382 utilizes one or more pressure variations per revolution of the drill string. In view of this embodiment, the strobe and cooperating trigger are controlled by the rotation of the rotary table. More specifically, the strobe increment is initiated and terminated by the rotational passage of stimuli comprising predetermined azimuth points on the rotary table. In this embodiment, the strobe increment is in degrees, and can comprise a partial arc of the rotary table or even multiple rotations of the rotary table. As an example, the strobe increment can be a single rotation of the rotary table. For this example, the strobe increment is initiated by the trigger at an azimuth θ 1  and terminated at an azimuth θ 2 , where θ 2 −θ 1 =360 degrees. Other strobe increments are applicable as will be illustrated in a subsequent section of this disclosure. 
         [0027]    Attention is directed to  FIG. 1 , which illustrates a borehole assembly (BHA)  10  suspended in a borehole  29  defined by a wall  51  and penetrating earth formation  36 . The upper end of the BHA  10  is operationally connected to a lower end of a drill pipe  33  by means of a suitable connector  20 . The upper end of the drill pipe  33  is operationally connected to a rotary drilling rig, which is well known in the art and represented conceptually at  31 . Elements of the steering apparatus are disposed within a bent sub  16  of the BHA  10 . More specifically, a rotary drill bit  18  is operationally connected to a mud motor  14  by a shaft  17 . The mud motor  14  is disposed within a bent sub  16 . 
         [0028]    Again referring to  FIG. 1 , the BHA  10  also comprises an auxiliary sensor section  22 , a power supply section  24 , an electronics section  26 , and a downhole telemetry section  28 . The auxiliary sensor section  22  typically comprises directional sensors such as magnetometers and inclinometers that can be used to indicate the orientation of the BHA  10  within the borehole  29 . This information, in turn, is used in defining the borehole trajectory path of the borehole. The auxiliary sensor section  22  can also comprise other sensors used in Measurement-While-Drilling (MWD) and Logging-While-Drilling (LWD) operations including, but not limited to, sensors responsive to gamma radiation, neutron radiation and electromagnetic fields. The electronics section  26  comprises electronic circuitry to operate and control other elements within the BHA  10 . The electronics section  26  preferably comprise downhole memory (not shown) for storing directional drilling parameters, measurements made by the sensor section, and directional drilling operating systems. The electronic section  26  also preferably comprises a downhole processor to control elements comprising the BHA  10  and to process various measurement and telemetry data. Elements within the BHA  10  are in communication with the surface  45  of the earth via the downhole telemetry section  28 . The downhole telemetry section  28  receives and transmits data to a surface telemetry section  39 . The telemetry path is illustrated conceptually by the broken line  30 . A power supply section  24  supplies electrical power necessary to operate the other elements within the BHA  10 . The power is typically supplied by batteries. 
         [0029]    Once again referring to  FIG. 1 , drilling fluid or drilling “mud” is circulated by the mud system  32  from the surface  45  downward through the drill string comprising the drill pipe  33  and BHA  10 , exits through the drill bit  18 , and returns to the surface via the borehole-drill string annulus. The drilling fluid system is well known in the art. 
         [0030]      FIG. 1  illustrates a trigger  34  and a strobe  38  cooperating with the drilling rig  31 , and more particularly with an element such as the rotary table or top drive (neither shown) of the drilling rig. A rotary table will be used for purposes of illustration and discussion. A “strobe increment” is initiated or “triggered” and subsequently terminated by the rotational passage of stimuli comprising predetermined azimuth points on the rotary table. The stimuli can comprise a switch, a reflector, a magnet, or any suitable means to operate the trigger and cooperating strobe. Stimuli configured as azimuth points will be illustrated in detail in  FIGS. 2   a - 2   c  and related discussion. The surface telemetry section  39  is connected at  37  to the stand pipe of the drilling rig, in addition to being connected to the strobe  38 , and a surface processor  40 . The surface telemetry section  39  receives a “composite” mud pulse telemetry response from the downhole telemetry section  28 . This response comprises a telemetry “signal” component representative of the response of the sensor package  14  and a “noise” component. 
       Basic Concept of STA 
       [0031]    In the context of this disclosure, the signal represents mud pulse telemetry pulses and the noise component is a series of pressure pulses used to activate a directional drilling system. The composite telemetry system responses are received at the surface by the surface telemetry section  39 . These composite signals are measured during the plurality of strobe increments and algebraically summed and stored in the processor  40 . As mentioned above, any non cyclical pressure pulse components (such as mud pulses representing BHA sensor responses) occurring during a plurality of strobe increment will sum to a constant or “average” pressure value “A” over a plurality of strobe increment. This is because the mud pulse telemetry pulses can occur at any point in the strobe increment. Conversely, a cyclical noise occurring during the predetermined strobe increment, and in synchronization with the strobe increment, will be enhanced by the algebraic summing of the plurality of strobe increments. A signature or picture of any cyclical noise component occurring synchronously with the predetermined strobe increment is obtained preferably by subtracting the average pressure pulse value, preferably within the processor  40 . The composite signal from a single strobe increment measured by the surface telemetry section  39  is simultaneously input directly into the processor  40 , as shown conceptually in  FIG. 1 . The noise signature, normalized to a single strobe increment, is then subtracted from the measured composite signal, within the processor  40 , to remove cyclical steering system pulse from the response of the telemetry system. This results in a mud pulse pressure signal that is free from any cyclical pressure pulses used to activate a directional drilling system. The mud pulse signal is then converted, preferably within the processor  40 , into one or more parameters of interest using responses from sensor within the BHA  10 . These results are typically output to a recorder  42  as a function of depth within the borehole  29  thereby forming a record of the one or more parameters in a form commonly known as a “log”. 
         [0032]    It should be recalled that the strobe  38  can be triggered by stimuli other than predetermined azimuth points on a rotating element of the drilling rig including a rotary table, a top drive or protruding drill string sections. This capability is illustrated conceptually in  FIG. 1  as an “auxiliary” input  35  cooperating with the trigger  34 . As an example, a clock can be synchronized with the rotation of the drill string and all processing can be based upon time rather than degrees of rotation. Stated another way, synchronous time averaging and synchronous arc averaging are conceptually equivalent and will be considered equivalent in this disclosure. 
       Data Processing 
       [0033]    The synchronous time averaging technique can be implemented using a variety of mathematical formalism with essentially the same end results of cyclical noise removal from a composite electromagnetic signal. The following formalism is, therefore, used to illustrate basic concepts, but other mathematical formalisms within the framework of the basic concepts may be equally effective. 
         [0034]    As discussed previously, the telemetered composite pressure pulse signal “R” is represented conceptually by the broken line  30  in  FIG. 1 . R comprises a signal component “S” representative of the response of the mud telemetry system and a composite noise component “N” representing one or more pressure pulses used to operate a directional drilling system. Stated mathematically, 
         [0000]        R=S+N.   (1)
 
         [0035]    The strobe is triggered by the cooperating trigger to record, during a strobe increment (in units of time or degrees), a plurality (k-j) of increment composite signals “e i ”. These composite signals are algebraically summed initially as 
         [0000]        R′=Σ   i   e   i .( i=j, . . . ,k )  (2)
 
         [0036]    If (k-j) is sufficiently large, any non cyclical pressure pulse component (such as mud pulse telemetry pulses “S”) occurring during the strobe increments will approach an average value “A” in the algebraic summing of R′. Any cyclical noise component (such as cyclical pulses N used to activate a directional drilling system) occurring during the strobe increments, and in synchronization with the strobe increments, is enhanced by the algebraic summing R′. Equation (2) therefore yields a cyclical noise component superimposed on an average mud pulse pressure value A. The value A is subtracted from R′ to obtain a signature or picture of the noise component N. That is 
         [0000]        N=R′−A   (3)
 
         [0037]    This cyclical noise component is normalized to a single strobe increment (N′) and then combined with a single strobe increment composite signal R to determine the mud pulse signal S. For purposes of illustration, a simple subtraction 
         [0000]        S=R−N′   (4)
 
         [0000]    is used to illustrate the determination of S, the mud pulse signal component of interest. The parameter S is, therefore, the telemetered signal in a single strobe increment with the cyclical noise removed, and is indicative of the response of the sensor package  14  or data transmitted from the surface to the BHA  10 . A variety of methods can be used to combine the composite signal R and the measure of N including semblance and least squares fitting techniques. 
         [0038]    The noise normalization of the parameter N is illustrated in more detail in the following section. Degrees rather than time are used to define the strobe increments. The discussion is equally applicable to strobe increments defined in time.  FIGS. 2   a ,  2   b  and  2   c  illustrates conceptually three strobe increments g, related to determining cyclical noise generated by a rotating element of a drilling rig such as a rotary table. In this case, increment composite signals e i  are measured during strobe increments “i” defined in units of degrees of rotation. The rotary table (or top drive) is represented conceptually by the cylinder  50  in  FIGS. 2   a - 2   c . It should be understood that the cylinder  50  can also represent essentially any other rotating element providing appropriate strobe increments. In  FIG. 2   a , only a single predetermined azimuth point is shown at  52 . The resulting strobe increment g i =360 degrees is illustrates conceptually by the arrow  54 . In  FIG. 2   b  two of four predetermined azimuth points are shown at  56  and  58  resulting in strobe increments g i =90 degrees, as partially illustrated by the arrows  62 ,  64  and  66 . In  FIG. 2   c , again only a single predetermined azimuth point is shown at  60 , but the strobe increment g, is 720 degrees as indicated by the arrow  68 . Strobe increments do not necessarily need to be equal or need to be contiguous. Using the mathematical formalism discussed above, the choice of strobe increment necessitates the normalization of the noise component N expressed mathematically in equation (3). That is 
         [0000]        N′=KN,   (5)
 
         [0000]    where N′ is the normalized noise component discussed above and K is a multiplicative normalization factor. For the strobe increment shown in  FIG. 2   a , K=1. For the strobe increments shown in  FIG. 2   b , K=4. Finally, for the strobe increment shown in  FIG. 2   c , K=0.50. 
         [0039]      FIG. 3  is a simplified flow chart illustrating how the concept of synchronous time averaging is used in a telemetry system to remove cyclical noise and to generate “logs” of parameters of interest as a function of borehole depth. Increment composite signals e i  are measured at  70 . Preferably, the composite signal R for a single strobe increment is simultaneously measured at  80 . Increment composite signals e i  are algebraically summed at  72  according to equation (2). A normalized noise component N′ is computed at  74  according to equations (3) and (5). The components R and N′ are combined at  76  to determine the signal component S according to equation (4). The signal component S is then used to compute at least one parameter of interest at  78  using a telemetered sensor and a predetermined relationship, wherein the predetermined relationship is preferably resident in the processor  40 . The procedure is incremented in depth at  82  and the previously described steps are repeated at a new depth. 
       Results 
       [0040]    The results of synchronous time averaging to eliminate noise from directional drilling system mud pressure pulses are illustrated with the following simplified, hypothetical examples. 
         [0041]      FIG. 4   a  is a plot of pressure (ordinate) representing a composite signal R measured over a single strobe increment (i.e. K=1) for one revolution of the drill string. The abscissa can, as discussed previously, be in units of time or degrees. The curve  84  represents pressure recorded at the surface telemetry section  39 . Excursions  86  represent data pulses from the mud pulse telemetry system. The excursion  88 , shown superimposed on a data pulse  86 , is a cyclical pressure pulse used to operate a directional drilling system. 
         [0042]    The curve  90  of  FIG. 4   b  represents R′ which is the sum of R over a plurality of strobe increments as defined in equation (2). Over the span of the strobe increments in which random data pulses fall, the summation approaches an average pressure A as shown at  91 . The cyclical pulse from the directional drilling system sums as shown at  88   a . In this illustration, K=1/(k−j). 
         [0043]      FIG. 4   c  shows a curve  92  which represents N′=KN=K(R′—A) where the excursion  88   b  represents the directional drilling system pulse  88   b  normalized to a single strobe increment. 
         [0044]    Finally curve  84  of  FIG. 4   d  represents the pressure curve S from which the rotary steering pulse  88   b  has been subtracted.  FIG. 4   d  represents, therefore, mud telemetry pulses free from interference from a directional drilling system pulse. 
         [0045]    While the foregoing disclosure is directed toward the preferred embodiments of the invention, the scope of the invention is defined by the claims, which follow.

Summary:
Apparatus and methods for removing the effects of directional drilling systems drilling fluid pulses to allow a MWD mud pulse telemetry system to operate without interference. The methodology is based upon Synchronous Time Averaging (STA). With STA, any pressure fluctuation that is cyclical (or synchronous) with a measurable event can be profiled and subsequently subtracted from a mud pulse telemetry signal. STA functions by placing a strobe in such a manner that the strobe is triggered for each cyclical event. The cyclical event in this disclosure is one (or more) revolution(s) of the drill string. If there is a pressure fluctuation that correlates to that cyclical event, it will be identified by a stable profile of that pressure fluctuation. This pressure profile is then used to remove the cyclical pressure fluctuation from the input mud pulse telemetry signal thereby allowing normal operation of the mud pulse telemetry system.