U.S. patent application number 12/855213 was filed with the patent office on 2012-02-16 for mud pulse telemetry synchronous time averaging system.
This patent application is currently assigned to PRECISION ENERGY SERVICES, INC.. Invention is credited to Robert Anthony Aiello, Steven Reid Farley, Michael Louis Larronde.
Application Number | 20120039151 12/855213 |
Document ID | / |
Family ID | 44759410 |
Filed Date | 2012-02-16 |
United States Patent
Application |
20120039151 |
Kind Code |
A1 |
Farley; Steven Reid ; et
al. |
February 16, 2012 |
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.
Inventors: |
Farley; Steven Reid;
(Magnolia, TX) ; Larronde; Michael Louis;
(Houston, TX) ; Aiello; Robert Anthony; (Spring,
TX) |
Assignee: |
PRECISION ENERGY SERVICES,
INC.
Fort Worth
TX
|
Family ID: |
44759410 |
Appl. No.: |
12/855213 |
Filed: |
August 12, 2010 |
Current U.S.
Class: |
367/83 |
Current CPC
Class: |
E21B 7/067 20130101;
E21B 47/18 20130101 |
Class at
Publication: |
367/83 |
International
Class: |
E21B 47/18 20060101
E21B047/18 |
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.
Description
[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. 2a depicts a strobe increment of 360 degrees;
[0016] FIG. 2b depicts strobe increments of 90 degrees;
[0017] FIG. 2c 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. 4a 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. 4b is the plot of a sum of pressures measured over a
plurality of strobe increments;
[0021] FIG. 4c shows a normalized plot of a cyclical pulse used to
operate a directional drilling system; and
[0022] FIG. 4d 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
.theta..sub.1 and terminated at an azimuth .theta..sub.2, where
.theta..sub.2-.theta..sub.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. 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
[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,
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.sub.i". These
composite signals are algebraically summed initially as
R'=.SIGMA..sub.ie.sub.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
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
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.
[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. 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.sub.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.sub.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.sub.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.
[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.sub.i are measured at 70. Preferably, the composite
signal R for a single strobe increment is simultaneously measured
at 80. Increment composite signals e.sub.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. 4a 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. 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).
[0043] FIG. 4c 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.
[0044] 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.
[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.
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