MUD PULSE TELEMETRY SYNCHRONOUS TIME AVERAGING SYSTEM

Abstract

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.

Description

FIELD OF THE INVENTION

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

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.

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.

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.

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.

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.

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.

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.

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

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.

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

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.

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;

FIG. 2 a depicts a strobe increment of 360 degrees;

FIG. 2 b depicts strobe increments of 90 degrees;

FIG. 2 c depicts a strobe increment of 720 degrees;

FIG. 3 is a conceptual flow chart of one embodiment of STA system for minimizing cyclical noise in a mud pulse telemetry system;

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;

FIG. 4 b is the plot of a sum of pressures measured over a plurality of strobe increments;

FIG. 4 c shows a normalized plot of a cyclical pulse used to operate a directional drilling system; and

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

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.

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.

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.

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 θ₁ and terminated at an azimuth θ₂, where θ₂−θ₁=360 degrees. Other strobe increments are applicable as will be illustrated in a subsequent section of this disclosure.

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.

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.

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.

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. 2a-2c 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

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”.

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

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.

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,

R=S+N.  (1)

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

R′=Σ _i e _i.(i=j, . . . ,k)  (2)

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

N=R′−A  (3)

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

S=R−N′  (4)

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.

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. 2a, 2b and 2c 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. 2a-2c. It should be understood that the cylinder 50 can also represent essentially any other rotating element providing appropriate strobe increments. In FIG. 2a, 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. 2b 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. 2c, 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

N′=KN,  (5)

where N′ is the normalized noise component discussed above and K is a multiplicative normalization factor. For the strobe increment shown in FIG. 2a, K=1. For the strobe increments shown in FIG. 2b, K=4. Finally, for the strobe increment shown in FIG. 2c, K=0.50.

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

The results of synchronous time averaging to eliminate noise from directional drilling system mud pressure pulses are illustrated with the following simplified, hypothetical examples.

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.

The curve 90 of FIG. 4b 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 88a. In this illustration, K=1/(k−j).

FIG. 4 c shows a curve 92 which represents N′=KN=K(R′—A) where the excursion 88b represents the directional drilling system pulse 88b normalized to a single strobe increment.

Finally curve 84 of FIG. 4d represents the pressure curve S from which the rotary steering pulse 88b has been subtracted. FIG. 4d represents, therefore, mud telemetry pulses free from interference from a directional drilling system pulse.

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.

Claims

1. A MWD mud pulse telemetry system for telemetering sensor data while operating a directional drilling system, the telemetry system comprising: (a) a telemetry section for measuring a composite pressure signal;(b) a trigger sensitive to a stimulus and cooperating with a strobe to define a plurality of strobe increments; and(c) a processor cooperating with said telemetry section (i) to algebraically sum increment composite pressure pulse signals measured during said plurality of strobe increments to define a cyclical pressure pulse component related to said directional drilling system, and(ii) to combine said cyclical pressure pulse component with said composite signal to obtain a mud pulse telemetry signal component.

2. The mud pulse telemetry system of claim 1 wherein said stimulus comprises a predetermined azimuth point on a rotating element.

3. The mud pulse telemetry system of claim 1 wherein said stimulus comprises a signal generated by a clock.

4. A method for mud pulse telemetering sensor data while operating a directional drilling system, the method comprising: (a) measuring a composite pressure signal with a telemetry section;(b) defining a plurality of strobe increments with a trigger sensitive to a stimulus and cooperating with a strobe; and(c) within a processor cooperating with said telemetry section (i) algebraically summing increment composite pressure pulse signals measured during said plurality of strobe increments to define a cyclical pressure pulse component related to said directional drilling system, and(ii) combining said cyclical pressure pulse component with said composite signal to obtain a mud pulse telemetry signal component.

5. The method of claim 4 wherein said stimulus comprises a predetermined azimuth point on a rotating element.

6. The mud pulse telemetry system of claim 4 wherein said stimulus comprises a signal generated by a clock.

7. A MWD logging system comprising: (a) a directional drilling system;(a) a downhole mud pulse telemetry section for transmitting a signal component from a downhole sensor;(b) a surface mud pulse telemetry section for measuring a composite signal comprising said signal component;(c) a trigger responsive to an azimuth point on a rotating element and cooperating with a strobe to define a plurality of strobe increments; and(d) a processor cooperating with said surface mud pulse telemetry section (i) to algebraically sum increment composite signals measured during said plurality of strobe increments to define a cyclical pulse component used to operate said directional drilling system, and(ii) to combine said cyclical pulse component with said composite signal to obtain said signal component.

8. The logging system of claim 7 wherein said cyclical pulse component is normalized as a function of said definition of said plurality of said strobe increments.

9. The logging system of claim 7 further comprising a predetermined relationship for converting said signal component into a parameter of interest.

10. The logging system of claim 9 further comprising a recorder cooperating with said processor to generate a log of said parameter of interest.

11. The logging system of claim 7 wherein said directional drilling system comprises: (a) a bent sub cooperating with a drill string and drill bit; and(b) a mud motor disposed within said bent sub; wherein (i) said drill string and said mud motor are operationally connected to said drill bit to operate said drill bit independent of rotation of said drill string,(ii) said cyclical pulse component is used vary the rotational speed of said drill bit, and(iii) said borehole is deviated by said periodic variation of said rotary speed of said drill bit.

12. A MWD logging method comprising: (a) providing a directional drilling system;(a) transmitting a signal component from a downhole sensor with a downhole mud pulse telemetry section;(b) measuring a composite signal comprising said signal component with a surface mud pulse telemetry section;(c) defining a plurality of strobe increments with a trigger responsive to an azimuth point on a rotating element and cooperating with a strobe; and(d) with a processor cooperating with said surface mud pulse telemetry section (i) summing algebraically increment composite signals measured during said plurality of strobe increments to define a cyclical pulse component used to operate said directional drilling system, and(ii) combining said cyclical pulse component with said composite signal to obtain said signal component.

13. The method of claim 12 further comprising normalizing said cyclical pulse component as a function of said definition of said plurality of said strobe increments.

14. The method of claim 12 further comprising converting said signal component into a parameter of interest with a predetermined relationship.

15. The method of claim 14 further comprising generating a log of said parameter of interest with a recorder cooperating with said processor.

16. The method of claim 12 wherein said directional drilling system comprises: (a) a bent sub cooperating with a drill string and drill bit; and(b) a mud motor disposed within said bent sub; wherein (i) said drill string and said mud motor are operationally connected to said drill bit to operate said drill bit independent of rotation of said drill string,(ii) said cyclical pulse component is used vary the rotational speed of said drill bit, and(iii) said borehole is deviated by said periodic variation of said rotary speed of said drill bit.