BRPI1104009A2 - mud pulse telemetry mean time synchronous system - Google Patents

Abstract

SLOW PULSE TELEMETRY AVERAGE SYNCHRONOUS SYSTEM. The present invention relates to apparatus and methods for removing the effects of drilling from directional fluid pulse drilling systems to enable a MWD mud pulse telemetry system to operate without interference. The methodology is based on synchronous time weighting (STA). With STA, any pressure fluctuation that is cyclic (or synchronous) with a measurable event can be profiled and subsequently subtracted from a mud pulse telemetry signal. STA works by placing a strobe in such a way that the strobe is triggered for each cyclic event. The cyclic event in this description is one (or more) revolution (s) of the drill string. If there is a pressure fluctuation that relates to the cyclic event, it will be identified by a stable pressure fluctuation profile. This pressure profile is then applied to remove the cyclic pressure fluctuation from the mud pulse telemetry signal input thereby allowing normal operation of the mud pulse telemetry system.

Description

Descriptive Report of the Invention Patent for "SYNCHRONAL PULSE TELEMETRY TIME MEDIA SYSTEM".

This description relates to United States Patent Application Serial No. 11 / 848,328 filed August 31, 2008 ， and Serial No. 12 / 344,873 filed December 28, 2008 both of which are incorporated by reference herein. Field of the invention

The present invention relates to directional drilling of a ροςο drilling bottom. More particularly, the ϊηνβηςδο is related to the minimization of adverse effects, in mud pulse telemetry, of fluid pressure fluctuation drills applied to operate directional drilling apparatus. Background

Complex trajectories and multi-target oil pits require precise location of the pogo drilling bottom path and the flexibility to continually maintain control of the path. It is preferable to control or "steer" the direction or path of the drilling bottom during drilling operation using the drilling methodology (MWD). It is further preferred to quickly control the path during drilling operation at any depth and target as the drilling bottom is advanced by the drilling operation. In addition, it is preferable to change the path of the drillhole by maintaining the rotation of the drill string, and to simultaneously measure information from the drillhole to the ground surface.

Many types of directional guidance 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 engine can be a variety of types including electric, or hydraulic. Hydraulic turbine engines are operated by circulating drilling fluid and are commonly known as a "mud" engine. A rotary drill is attached to the motor shaft, and is rotated by the motor action. The bypass axial motor housing, commonly referred to as a folded or "subfolded" sub-segment, allows for axial displacement that can be used to alter the drilling bottom trajectory. By rotating the drill bit with the engine and simultaneously rotating the drill bit with the drill string, the trajectory or path of the drillhole in advance and parallel to the drill string axis. By turning the drill bit with the motor only, the trajectory of the drill bottom is offset from the axis of the drill string. By alternating these two drill bit rotation methodologies, the path of the drill bottom can be controlled. While deflecting to the bottom of the drill, the non-rotating drill string may cause operational problems. More specifically, static friction between the non-rotating drill string and the drill bottom wall creates statistical friction that impedes drilling efficiency. A more detailed description of directional drilling, applying the concept of underbending is described in U.S. Pat. 3,260,318 ， and 3,841,420, which are incorporated herein by reference.

Drill bottom direction assemblies are typically arranged near the drill bit, which terminates at the smallest or end of the "pogo hole" of a drill string. In order to obtain the desired real-time directional control, it is preferable to operate the device steering remotely from the ground surface. This requires a two-way telemetry system between the BHA and the ground surface. The most common MWD telemetry system uses mud pulse methodology to transmit data between the BHA and the earth's surface. Steering systems have been developed to allow

also control the direction of the drilling bottom while maintaining rotation of the drilling column. These systems will be referred to herein as "directional drilling systems". Continuous rotation of the drill string allowed by these previously mentioned systems minimizes operational problems resulting from the static friction between the drill string and the drill bottom wall. Drilling Systems

directional control have altered or disturbed one or more drilling parameters during a part of a drilling column revolution. This periodic disturbance removes a disproportionate amount of material from the drilling bottom wall resulting in a deviation from the drilling bottom path.

United States Patent Application Serial No.

Previously referenced 11 / 848,328 describes a directional drilling system that periodically increases the rotation rate of just over a predetermined arc of each rotation of the drilling column. This results in the disproportionate desired removal of the drilling fund wall material, thus resulting in a deviation from the drilling bottom in the azimuthal direction of the predetermined arc. Periodic increase in drill rotation is effected periodically by increasing the flow of the mud through the mud motor which in turn induces a pressure pulse in the drill rig tube support. United States Patent Application Serial No.

Previously referenced 12 / 344,873 describes another type of directional drilling system which periodically increases the drill penetration rate through a predetermined arc of each drilling column rotation. This again results in disproportionate removal. of the drilling bottom wall material, thereby resulting in the drilling bottom drifting in the azimuthal direction of the predetermined arc. The periodic increase in penetration rate is once again effected by periodically increasing the mud flow as the drill rotates through the predetermined arc, and once again results in a pressure pulse in the bearing support. pipe .

As previously mentioned, it is highly advantageous to control a directional drilling operation in real time from the ground surface. In order to obtain the desired directional control in real time, a two-way telemetry system between the BHA and the ground surface is required, and the most common MWD telemetry system and a mud pulse system. Data from borehole sensors and from surface

Control units are coded for transmission by varying the pressure or "pulsing" the pressure of the mud drill column. These pressure pulses are subsequently encoded to extract transmitted data.

As previously mentioned, the directional drilling systems described above are also controlled by mud pressure drilling pulses, with these pressure pulses resulting in fluctuating drilling fluid from the pressure tube holder. Pressure fluctuation of the steering system typically occurs once per revolution of the drill string, but steering systems may use various periodic pressure fluctuations per revolution. Variation in drilling fluid pressure caused by the steering system interferes with the pressure variation induced by the mud pulse telemetry system. It is therefore necessary to remove the effects of the periodic steering pulse system to enable the mud pulse telemetry system to operate properly.

Summary of the invention

This invention comprises apparatus and methods for removing the effects of the drilling fluid pulses from the directional drilling system to enable a MWD mud pulse telemetry system to operate without interference. The methodology is based on the Synchronous Time Weighting (STA) that has been used to remove cyclic (or synchronous) "noise" in an electromagnetic telemetry system as described in United States Patent 7,609,169, which is inserted herein by reference.

With STA, any pressure fluctuation which is cyclic (or synchronous) with a measurable event can be profiled and subsequently subtracted from a mud pulse telemetry signal. STA works by placing a strobe in such a way that the strobe is triggered by each cyclic event. The cyclic event in this disclosure is one (or more) revolution (s) of the drill string. If there is a pressure fluctuation that relates to that cyclic event, it will be identified by a stable profile of that pressure fluctuation. This pressure profile is then applied to

to remove the cyclic pressure fluctuation from the mud pulse telemetry signal thereby allowing normal operation of the

wrist pulse mud.

Brief Description of Drawings

The manner in which the above-mentioned characteristics and advantages, briefly summarized above, are obtained may be understood in detail by the embodiments illustrated in the accompanying drawings.

Figure 1 illustrates a MWD system comprising a directional drilling system and a Synchronous Time Weighting System for eliminating the direction of surface pressure fluctuations; Figure 2a shows a 360 degree strobe increment;

Figure 2b shows a 90 degree strobe increment; Figure 2c shows a 720 degree strobe increment; Figure 3 is a conceptual flow chart of an embodiment of the STA system for minimizing cyclic noise in a mud pulse telemetry system;

Fig. 4a is a pressure graph depicting a composite signal R measured by a stroboscopic increment increment for a drilling column revolution;

Figure 4b is a graph of a sum of pressures measured by a plurality of strobe increments;

Figure 4c shows a standard graph of a cyclic pulse applied to operate a directional drilling system; and

Figure 4d shows a telemetry signal has been removed. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS A preferred embodiment of this invention comprises apparatus.

Tools and methods for removing the effects of the drilling fluid pulses from the directional drilling system to enable a MWD mud pulse telemetry system to operate without interference. The methodology is based on the techniques of Synchronous Time Weighting (STA) 1 although the same methodology can be applied to the synchronous rotational arc weighting as will be illustrated below.

Synchronous time weighting is applied to identify cyclic noise in mud pulse telemetry response. This time response comprising a "signal" component and a "noise" component will hereinafter be referred to as a "composite" signal. The signal component typically represents response data from one or more sensors disposed within a set of drill bottoms (BHA), or data transmitted from the surface of the BHA. The noise component can represent any type of cyclic or synchronous noise. In this specification, the noise component represents one or more cyclic pressure pulses applied in a previously defined directional drilling system. A strobe is triggered by a cooperative trigger responsive to a stimulus to record during a predetermined "strobe boost" a plurality of "compound noise signal boosts". The- The module can be a switch, reflector, magnet, protrusion, notch, time signal, or any suitable means for operating the cooperating trigger and strobe. These increments composed of noise signals are algebraically summed. pulse pressure (such as a random pulse representing BHA sensor responses) occurring during the strobe increment will approach a constant value in the sum operation Any cyclic noise occurring during the strobe increment and the incremental synchronization stroboscope (such as pulse pressure applied to directional drilling systems) will be emphasized by the algebraic sum The strobe trigger sum methodology produces a signature or "image" of any cyclic noise component occurring in sync with the increment of the This noise component is then combined with the measured signal compound to remove, or at least and minimize, cyclic noise allowing mud pulse telemetry system to operate more efficiently.

As mentioned above, the technique is not limited to time weighting. Strobe Increment can be set in units of degrees of an arc as well as a time increment. In the first case, ο

This process would really comprise "arc" weighting rather than "time" weighting. For purposes of the discussion, the weighting process will generally be referred to as STA although arc weighting is applied to conceptually illustrate the system.

The directional piercing system exemplified by United States Patent Application Serial No. 11 / 843.382 utilizes one or more piercing column pressure variations. In view of this mode, the strobe and the cooperation trigger are controlled by the rotation of the rotary table. More specifically, the stroboscope increment is initiated and terminated by the stimulation rotation passage comprising predetermined azimuth points in the rotational table. In this mode, the stroboscope increment is in degrees, and may comprise a partial arc of the rotary table or even multiple rotates of the rotary table. As an example, the strobe increment may be a Kinetics rotational table rotation. For this example, the estroscope increment is initiated by the trigger on an azimuth B1 and terminated on an azimuth Θ2, where θ2-θ · ι = 360 degrees. Other strobe increments are applicable as will be illustrated in a subsequent section of this disclosure.

Attention is directed to Figure 1, which illustrates a set of drill bottoms (BHA) 10 suspended from a drill bottoms 29 defined by a wall 51 and penetrating ground forming 36. The upper end of BHA 10 is operatively 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 operationalized and connected to a rotary drilling platform, which is well known in the art and conceptually represented as 31. Elements of the steering apparatus are disposed within a subfolder 16 of BHA 10. More specifically, a rotary drill 18 is operated connected to a mud motor 14 by an axis 17. The mud motor 14 is disposed within a subfolder. 16

Referring again to Figure 1, BHA 10 also comprises

it comprises an auxiliary sensor section 22, a power supply section 24, an electronics section 26, and a well bore telemetry section 28. The auxiliary sensor section 22 typically comprises directional sensors such as magnetometers and inclinometers that can be applied to indicate the orientation of the BHA 10 within the perforation bottom 29. This information, in turn, is applied in defining the perforation bottom path, the perforation bottom path. Auxiliary sensor section 22 may also comprise other sensors applied to metering during drilling (MWD) and including but not limited to Record During Drilling (LWD) operation, sensors responsive to gamma radiation, neutron radiation and electromagnetic fields . Electronics section 26 comprises electronic circuits for operating and controlling other elements within BHA 10. Electronics section 26 preferably comprises drilling memory (not shown) for storing directional drilling parameters, measurements taken by the electronics section. sensor, and directional drilling operating systems. The electronics section 26 preferably further comprises a wellbore process for controlling the elements comprising BHA 10 and for measuring various telemetry processes and data. Elements within the BHA 10 are in communication with the ground surface 45 through the pit bore telemetry section 28. The bore hole telemetry section 28 receives and transmits data to a bore section surface. telemetry 39. The telemetry path is conceptually illustrated by the broken line 30. A section of the power supply 24 power supply required to operate the other elements within BHA 10. Power is typically supplied by batteries. Again referring to figure 1, drilling fluid or

Drill "mud" is circulated by the mud system 32 from surface 45 down through the drill string comprising drill pipe 33 and BHA 10, output through drill bit 18, and returned to the surface through the drill. drilling bottom of the annular drilling column. The drilling fluid system is well known in the art.

Figure 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 unit (also not shown) of the drilling rig. A rotational table will be applied for illustration and discussion purposes. A "strobe increment" is initiated or "triggered" and subsequently terminated by the stimulus rotation pass comprising predetermined azimuth points on the rotary table. The stimulus may comprise a switch, a reflector, a magnet, or any suitable means for operating the cooperating trigger and strobe. Stimulus configured as azimuth point will be illustrated in detail in Figures 2a-2c and related discussion. Surface telemetry section 39 is connected to 37 to the drill rig tube bracket, and is connected to strobe 38, and a surface processor 40. Surface telemetry section 39 receives a "composite" mud pulse telemetry response from the well bore telemetry section 28. This response comprises a "signal" telemetry component representative of the response of sensor package 14 and a "noise" component.

STA Basic Concept

In the context of this description, the signal represents mud pulse telemetry pulses and the noise component is a series of pressure pulses applied to activate a directional drilling system. Composite telemetry system responses are received on the surface through surface telemetry section 39. These composite signals are measured during a plurality of strobe increment and algebraically summed and stored in processor 40. As mentioned above , any non-cyclic pressure pulse component (such as mud pulses representing BHA sensor responses) occurring during a plurality of strobe increments will add to a "mean" constant or pressure value "A" by a plurality of increments. stroboscopes. This is because mud pulse telemetry pulses can occur at any point in the strobe increment. Conversely, a cyclic noise occurring during a predetermined strobe increment, and in sync with the strobe increment, will be reinforced by the algebraic sum of the strobe increment plurality. A signature or image of any component of the cyclic noise occurring in sync with the predetermined strobe increment is preferably obtained by subtracting the pulse value from the mean pressure, preferably within processor 40. The signal composed from a single increment of The strobe measured by the surface telemetry section 39 is simultaneously entered directly into processor 40, as conceptually shown in Figure 1. The noise signature, normalized to a single strobe increment, is then subtracted from the composite signal. measured within processor 40 to remove the pulse from the cyclic steering system from the telemetry system response. This results in a mud pulse pressure signal that is free of any cyclic pressure pulse applied to a directional drilling system. The mud pulse signal is then converted, preferably within processor 40, into one or more parameters of interest by applying responses from the sensor within BHA 10. These results are typically taken for a register 42 as a function of depth from within the drilling bottom 29 thus forming a register of one or more parameters in a form commonly known as a "register". It should be remembered that strobe 38 can be fired.

by stimulus that does not predetermine azimuth points on a rotating drilling rig element including a rotary table, a top unit or a section of the protruding drilling column. This capacity is conceptually illustrated in Figure 1 as an "auxiliary" input 35 cooperating with trigger 34. As in the example, a clock can be synchronized with the rotation of the drill string and all processing can be based on time instead of degrees of rotation. Otherwise stated, synchronous time weighting and arc weighting are conceptually equivalent and will be considered equivalent in this description.

Data processing

The synchronic time-weighting technique can be implemented by applying a variety of mathematical formalism with essentially the same end result of cyclic noise removed from a composite electromagnetic signal. The formalism that will be discussed in more detail below is therefore applied to illustrate basic concepts, but other mathematical formalisms within the framework of basic concepts can be equally effective.

As previously discussed, the telemetry composite pressure pulse signal "R" is conceptually represented by the broken line in Figure 1. R comprises an "S" signal component representative of the response of the mud telemetry system and a component of compound noise "N" representing one or more pulse pressure applied to operate a directional drilling system. Mathematically established,

(1) R = S + N.

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 the increment composed of "e" signals. This composite of signals is algebraically summed initially as

(2) R1 = Ile. (i = j, ..., k)

If (kj) is large enough, any non-cyclic pressure pulse component (such as mud pulse telemetry pulses "S") occurring during a strobe increment will approximate an average value "A" in the algebraic sum. from R '. Any cyclic noise component (such as cyclic pulses N applied to activate a directional drilling system) occurring during a strobe increment, and in sync with the strobe increment, is reinforced by the algebraic sum R '. Equation (2) therefore produces a cyclic noise component superimposed on an average of the mud pulse pressure value A. The value A is subtracted from R 'to obtain a signature or image of the noise component N Which is (3) N = R '- A

this cyclic noise component is normalized to single strobe increment (N ') and then combined with a single signal composed of strobe increment R to determine the mud pulse S signal. For illustration purposes, a simple subtraction

(4) S = R - N1

is applied to illustrate the determination of S1 the mud pulse signal component of interest. Parameter S is therefore the telemetry signal in a single strobe increment with cyclic noise removed, and is indicative of response from sensor pack 14 or data transmitted from the surface to BHA 10. A variety of methods can be applied to combine the composite signal Rea measured by N including appearance and

tables of adjustment techniques.

The noise normalization of parameter N is illustrated in more detail in the following section. Degrees instead of time are applied to define the increment of strobes. The discussion is equally applicable to the time-defined strobe increment. Figures 2a, 2b and 2c

15

conceptually illustrate three strobe increments g, related to determine cyclic noise generated by a rotating element of a drilling rig such as a rotary table. In this case, signals composed of increment ej are measured during strobe increment "i" defined in units of degrees of rotation. The rotary table (or

20

top unit) is conceptually represented by cylinder 50 in figures 2a-2c. It should be understood that cylinder 50 can also essentially represent any other rotating element providing suitable increment of strobes. In figure 2a, only a single predetermined azimuth point is shown at 52. The strobe increment

25

resulting g, = 360 degrees is conceptually illustrated by arrow 54. In figure 2b two of four predetermined azimuth points are shown at 56 and 58 resulting in the strobe increment gj = 90 degrees, as shown by arrows 62, 64 and 66. In figure 2c, once again only a single predetermined azimuth point is shown at 60, but the

30

strobe increment g, is 720 degrees as indicated by arrow 68. Strobe increment does not necessarily need to be the same or must be contiguous. Applying the mathematical formalism discussed above, the selection of strobe increment requires normalization of the noise component N expressed mathematically in equation (3). What is

(5) N1 = KN,

Where

N 'is the normalized noise component discussed above and K is

a multiplicative normalization factor. For the strobe increment shown in figure 2a, K = 1. For the strobe increment shown in figure 2b, K = 4. Finally, for the strobe increment shown in figure 2c, K = 0.50. Figure 3 is a simplified flowchart illustrated as the concept of

Synchronous time weighting is applied in a telematics system to remove cyclic noise and to generate "records" of the parameters of interest as a function of the depth of the drilling bottom. Compound increment signals e, are measured at 70. Preferably, the composite signal R for a single strobe increment is simultaneously measured at 80. Compound increment signals e j are algebraically summed at 72 according to equation (2) . A standardized noise component N 'is computed at 74 according to equations (3) and (5). The ReN 'components are combined in 76 to determine the signal component S according to equation (4). The signal component S is then applied to compute by it a parameter of interest by applying a telemetry sensor and a predetermined ratio, wherein the predetermined ratio is preferably resident in processor 40. The procedure is incremented in depth in 82 and the steps previously described are repeated to a new depth. Results

The results of synchronous time weighting to eliminate noise from the mud pulse pressure directional drilling system are illustrated with the following simplified and hypothetical examples. Figure 4a is a pressure graph (ordered) representing

a composite signal R measured by a single strobe increment (i.e. K = 1) for one revolution of the drill string. The abscissa may, as previously discussed, be in units of time or degrees. Curve 84 represents the pressure recorded in the surface telemetry section 39. Excursions 86 represent data pulses from the mud pulse telemetry system. Tour 88, shown overlapping a data pulse 86, is a cyclic pressure pulse applied to operate a directional drilling system.

Curve 90 of Fig. 4b represents R1 which is the sum of R by a plurality of strobe increment as defined in equation (2). On the scope of the strobe increment in which the random data pulses drop, the sum of the methods at mean pressure A as shown in 91. The cyclic pulse from the directional drilling system summed as shown in 88a. In this illustration, K = 1 / (k-j).

Figure 4c shows a curve 92 representing N1 = KN = K (R '- A) where excursion 88b represents the pulse of directional drilling system 88b normalized to a single strobe increment.

Finally the curve 84 of figure 4d represents the pressure curve S from which the rotational steering pulse 88b was subtracted. Figure 4d thus represents interference free mud telemetry pulses from a directional drilling pulse system. While the foregoing description is directed toward the

Preferred embodiments of the invention, the scope of the invention is defined by the following claims.

Claims (16)

1. MWD mud pulse telemetry system for data telemetry sensor, while operating a directional drilling system, the telemetry system comprises: (a) a telemetry section for measuring a composite pressure signal; (b) a trigger sensitive to a stimulus and cooperating with the strobe to define a plurality of strobe increments; and (c) a processor cooperating with said telemetry section; (i) for algebraically summing the signals of the pressure pulse cycle compound increment measured during said plurality of strobe increment to define a cyclic pressure pulse component related to said directional drilling system, and (ii) ) to combine said cyclic pressure pulse component with said composite signal to obtain a mud pulse telemetry signal component. A mud pulse telemetry system according to claim 1, wherein said stimulus comprises a predetermined azimuth point on a rotary element. A mud pulse telemetry system according to claim 1, wherein said stimulus comprises a signal generated by a clock. 4. A method for Ima pulse data telemetry sensor while operating a directional drilling system, the method comprising: (a) measuring a pressure signal composed of a telephoto section; (b) defining a plurality of stroboscope increment with a stimulus sensitive trigger and cooperating with a strobe; and (c) within a processor cooperating with said telemetry section (i) algebraically summing the signals of the compound pulse pressure increment measured during said plurality of strobe increments to define a cyclic pressure pressure component. pulse related to said directional piercing system, and (ii) combining said cyclic pressure pulse component with said composite signal to obtain a mud pulse telemetry signal component. A method according to claim 4, wherein said stimulus comprises a predetermined azimuth point on a rotating element. Mud pulse telemetry system as defined in claim 4 wherein said stimulus comprises a signal generated by a clock. 7. MWD registration system comprising: (a) a directional drilling system; (a) a mud pulse wellbore telemetry section for transmitting a signal component from a wellbore sensor; (b) a pulse surface 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 the strobe to define a plurality of strobe increments; and (d) a processor cooperating with said mud pulse surface telemetry section (i) for the algebraic sum of the increment incremental signals measured during said plurality of strobe increments to define a component. cyclic pulse rate applied to operate said directional piercing system, and (ii) to combine said cyclic pulse component with said composite signal to obtain said signal component. A recording system according to claim 7, wherein said cyclic pulse component is normalized as a function of said definition of said plurality of said strobe increment. A record system according to claim 7 further comprising a predetermined ratio for converting said signal component into a parameter of interest. A register system according to claim 9 further comprising a register cooperating with said processor to generate a register of said parameter of interest. A logging system according to claim 7, wherein said directional wellbore system comprises: (a) a subfold cooperating with a drill string and a drill bit; and (b) a mud motor disposed within said subfolder; wherein (i) said drill string and said mud motor are operatively connected for said drill bit to operate said drill bit independent of the rotation of said drill string, (ii) said cyclic pulse component is applied to varying the rotational speed of said drill bit, and (iii) said drilling bottom is offset by said periodic variation of said rotational speed of said drill bit. 12. MWD registration method comprising: (a) providing a directional drilling system; (a) transmitting a signal component from a wellbore sensor with a mud pulse wellbore telemetry section; (b) measuring a composite signal comprising said signal component with a telemetry section of the mud pulse surface; (c) defining a plurality of increment strobes with a trigger responsive to an azimuth point on a rotating element and cooperating with the strobe; and (d) with a processor cooperating with said mud pulse surface telemetry section (i) algebraically summing the signals composed of increments measured during said plurality of stroboscope increment to define a cyclic pulse component applied to operate said directional piercing system, and (ii) combining said cyclic pulse component with said composite signal to obtain said signal component. The method of claim 12 further comprising normalizing said cyclic pulse component as a function of said defining said plurality of said stroboscope increment. A method according to claim 12 further comprising converting said signal component into a parameter of interest with a predetermined ratio. The method of claim 14 further comprising generating a register of said parameter of interest with a register cooperating with said processor. The method of claim 12, wherein said directional drilling system comprises: (a) a subfold cooperating with the drill string and a drill bit; and (b) a mud motor disposed within said subfolder; wherein (i) said drill string and said mud motor are operationalized and connected to said drill bit to operate said drill bit independent of the rotation of said drill string, (ii) said component pulse cycling is applied to vary the rotational speed of said drill bit, and (iii) said drill bottom is offset by said periodic variation of said rotational speed of said drill bit.