Note: Descriptions are shown in the official language in which they were submitted.
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TELEMETRY TRANSMITTER OPTIMIZATION VIA INFERRED
MEASURED DEPTH
FIELD OF THE INVENTION
The present invention relates to telemetry apparatus and methods, and more
particularly to acoustic telemetry apparatus and methods used in the oil and
gas
industry.
BACKGROUND OF THE INVENTION
There are numerous methods, techniques and innovations designed to improve
the oil and gas drilling process. Many of these involve feedback of various
measured downhole parameters that are communicated to the surface to enable
the driller to more efficiently, safely or economically drill the well. For
example,
United States Patent No. 6,968,909 to Aldred et al. teaches a control system
that
combines measurement of downhole conditions with certain aspects of the
operation of the drillstring. These downhole measurements are conveyed to the
surface by well-known standard telemetry methods where they are used to
update a surface equipment control system that then changes operation
parameters. Closed loop two-way communication techniques like this, however,
rely on the adequate detection at the surface of the telemetered parameters.
It is
standard in the drilling industry to control certain parameters of the
downhole
telemetry transmitter by downlinking appropriate commands from the surface.
For example, changing the downhole drilling fluid pressure in a prescribed
manner by changing the flow rate of the drilling fluid and subsequently
monitoring
this by a downhole pressure gauge is a common technique. Problems
associated with this and similar downlinking techniques include false
detection,
slowing of the drilling process and the need to include human intervention in
the
process.
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There are at present two standard telemetry techniques in common use - data
conveyed via pressure waves in the drilling fluid and data conveyed via very
low
frequency electromagnetic waves, both originating at a downhole transmitter.
30 Another telemetry technique beginning to emerge in the drilling arena is to
convey the data via acoustic waves travelling along the drillpipe. All three
technologies suffer from noise associated with the drilling operation, and all
three
similarly suffer signal attenuation at the surface as the well bore increases
in
length. These problems are illustrated herein by discussing some of the issues
35 associated with the utilization of acoustic transmissions to transfer data
from
downhole to an acoustic receiver rig at the surface.
Ttie design of acoustic systems for static production wells has been
reasonably
successful, as each system can be modified within economic constraints to suit
these relatively long-lived applications. The application of acoustic
telemetry in
40 the plethora of individually differing real-time drilling situations,
however, is less
widespread. This is primarily due to it presently being an emerging technology
and because of specific problems related to the increased in-band noise due to
certain drilling operations, and unwanted acoustic wave reflections associated
with downhole components such as the bottom-hole assembly (or "BHA"),
45 typically attached to the end of the drillstring. The problem of
communication
through drillpipe is further complicated by the fact that drilipipe has
heavier tool
joints than production tubing, resulting in broader stopbands; this entails
relatively less available acoustic passband spectrum, making the problems of
noise and signal distortion even more severe. As the well is drilled and the
50 arriount of drillpipe increases there is a general degradation of the
available
acoustic passband properties, primarily through two effects: the non-identical
dimensions of the drillpipes due to manufacturing tolerances and recuts of
tool
joirits will narrow and distort the acoustic passband; the acoustic signal
attenuation increase is directly related to the number of drillpipes.
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55 T=he amount of drilipipe in the well is directly related to the 'measured
depth'
(PvID), in contrast to the 'true vertical depth' (TVD), i.e. the vertical
depth used in
calculating the hydrostatic pressure in a well. Attenuation is also a function
of the
amount of wall contact with the drillpipe because this contact provides a
means
of extracting energy from acoustic waves travelling along the pipe. Typical
60 attenuation values may range from 12dB to 35dB per kilometre.
Noise from many sources must be dealt with. For example, the drill bit, mud
motor and the BHA and pipe all create acoustic noise, particularly when
drilling.
The downhole noise amplitude generally increases as rotation speed and/or the
drilling rate of penetration increases. On the surface, noise originates from
65 virtually all moving parts of the rig. Dominant noise sources include
diesel
generators, rotary tables, top drives, pumps and centrifuges.
Ttius it is evident that channel issues and noise problems will increase with
the
measured depth, drilling rate and rotary speed.
In summary, the challenges to be met for acoustic telemetry in drilling wells
70 include:
= Restricted channel bandwidth due to the drillstring passband structure
(see United States Patent No. 5,128, 901 to Drumheller)
= Channel centre shifts
= Dynamically changing channel properties
75 = Downhole noise due to drillpipe movements
= Downhole noise due to mud motor and/or drill bit activity
= Surface noise due to rig components such as diesel generators, rotating
tables, and top drives
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Channel impairments generally degrade the signal's ampiitude and/or phase
80 iritegrity, while noise impedes the receiver's ability to detect what
signal there is.
A very simple metric that is used in these circumstances is the signal-to-
noise
ratio (SNR). Maximizing the SNR is a telemetry objective. The present
invention
teaches a novel means of enabling the automatic control of various transmitter
parameters so as to maintain the SNR available at surface at or above a
85 minimum achievable and predetermined threshold in the acoustic drilling
telemetry environment. It can equally be applied to the other major telemetry
means indicated herein as they have similar SNR issues resulting from their
own
associated telemetry channel impairments.
SUMMARY OF THE INVENTION
90 It is an object of the present invention to optimize the telemetry
performance of a
simple one-way (subsurface to surface) telemetry link from the downhole
transmitter through the appropriate channel to a receiver located on the rig
at
surface. For convenience the telemetry performance is defined simply as the
ability of the surface receiver to decode the telemetered parameters detected
at
95 surface in the presence of noise. It is evident that the noise sources as
discussed are present to an extent that depends on the immediate needs of the
rig crew actually drilling and steering the well. It is also evident that the
signal
attenuation will increase as the well is drilled, bringing more drillpipe and
more
wall contact. The present invention is directed to enhancing the received
signal
100 in order to offset the reduction in SNR as the MD increases by
implementing one
or more of the following exemplary actions, which are for illustrative
purposes
only:
= signal repetition
= reduced data rate
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105 = increased signal length
= increase the signal's frequency span
= increase the transmitter's output level
Undertaking these actions is not novel in itself; it is the means by which
these
techniques are employed, as explained below.
110 If the transmitter module had access to the MD of the drilipipe it could
be
programmed to undertake certain of the SNR improvements at specified MDs. In
the case of acoustic telemetry for instance, at each 500m increment a
combination of signal increase and chirp length could be implemented. Because
the telemetry system to which the present invention beneficially but not
115 exclusively applies is for one-way systems, the downhole tool may not be
in
receipt of this information from the surface, and thus an inferential method
would
be utilized. The basis for the present invention is to infer the approximate
measured depth (i.e. the total length of the drill pipe) by measuring downhole
pressure. Pressure values are readily available by the use of one or more
120 pressure sensors that can sample bore pressure, annular pressure or both.
The
majority of downhole telemetry tools incorporate at least one pressure sensor
as
this is an important parameter in safely drilling a well. Once the pressure is
determined the most straightforward inferential method is to utilize a look-up
table that is configured around particular parameters of the well being
drilled.
125 According to one aspect of the invention, there is provided a method and
apparatus for enhancing downhole telemetry performance. The method
comprises: measuring downhole pressure at a specified location; inferring a
measured depth from the measured downhole pressure; and modifying a
downhole telemetry signal at one or more measured depths in order to offset
the
130 estimated signal-to-noise ratio reduction with increasing measured depth.
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apparatus comprises: a pressure sensor for measuring downhole pressure at a
specified location; a telemetry signal transmitter; and a processor with a
memory
having recorded thereon steps and instructions for carrying out the method.
The measured depth calculation becomes more complicated when the well
135 deviates from vertical. This deviation can be assessed by the use of
a'direction
and inclination' sensor (D&I) commonly deployed downhole. The issue is that
even though the angle in the hole is known, prior to this invention the
downhole
tool is not able to assess its distance along the deviated section(s) of the
well
without information being relayed from the surface. Our invention provides an
140 inferential method of estimating MD for all sections of the well.
Ttie step of inferring can be performed even when the specified location is in
a
horizontal section of a well bore, comprising measured downhole pressure(s)
with a form of a previously-calculated equivalent circulating density estimate
for
specified locations, with preferably, although necessarily a correlation of
D&I
145 angle of well trajectory measurements. The pressure sensor can usually be
configured to measure annulus pressure or bore pressure or both. The step of
inferring a measured depth can comprise associating a measured annulus
pressure to a predicted annulus pressure then selecting a measured depth
corresponding to the associated predicted annulus pressure.
150 The method can be performed in a drill string having a bottom hole
assembly
with no repeater. In such case the specified location is the location of the
bottom
hole assembly in a well bore. Alternatively, the method can be performed in a
drill string having a bottom hole assembly and at least one repeater; in such
case
the specified location is the location of the repeater closest to the surface,
and
155 the step of inferring measured depth comprises inferring a first measured
depth
between the specified location and the surface, incorporating a predetermined
second measured depth between the specified location and the bottom hole
assembly, then combining the first and second measured depths.
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160 BRIEF DESCRIPTION OF THE DRAWINGS
The following drawings illustrate the principles of the present invention and
an
exemplary embodiment thereof:
Figure 1 is schematic representation of a rig 1 and the profile 2 of a
vertical well.
Figure 2 further shows the profile 3 of a deviated well.
165 Figure 3 further shows the profile 4 of a typical horizontal well.
Figure 4 further shows the profile 5 of a typical extended reach well.
Figure 5 is a graph showing a consolidation of the overall drilling industry
preferences when drilling wells that incorporate non-vertical sections.
Figure 6a is a schematic representation of a rig with a depiction of a
downhole
170 telemetry tool.
Figure 6b is a schematic representation of a rig with a depiction of a
downhole
telemetry tool with the addition of a repeater telemetry tool.
Figure 6c is a schematic representation of the representation depicted in
Figure
6b but indicating a situation where drilling has progressed.
175 DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT
It is apparent from Figure 1 that the MD is readily predicted by the downhole
tool
by measuring the downhole hydrostatic pressure Phs once the fluid density is
known or assumed, as predicted by equation 1:
Phs=pgh [i]
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180 where p = drilling fluid density
g = acceleration due to gravity
h = vertical height of the fluid column
It is normal that during the course of drilling a well the density p is
deliberately
changed. Furthermore p can change depending on whether the fluid is being
185 pumped or is stationary. It can also change depending on the volume and
type
of cuttings and how they are held in suspension. This effect leads to
consideration of an equivalent circulating density calculation (ECD, equation
2,
following) that is utilized for the control and safety of modern wells.
The present invention as applied to reasonably vertical wells is to utilize
the
190 pressure readings when the flow is static.
At the well planning stage it will be known to an adequate degree of accuracy
how the well profile and the addition of materials to the drilling fluid will
affect the
downhole pressure PhB. It does not matter whether the sampled pressure is that
in the bore or in the annulus - they are almost the same under static
conditions.
195 Thus a look-up table that equates pressure Phs to MD can be constructed,
where
it is assumed that h is equivalent to MD. It is then apparent that relatively
coarse
changes in MD (for example, increments of 500m) can be inferred by assessing
Phs that in turn can implement changes in the transmitted signal in a way that
increases SNR and thus will improve detection and decoding ability of the
200 surface equipment. Such a look-up table or similar can be readily built by
incorporating appropriate features of the planned well such as drilling fluid
flow
rate, drilling fluid density, drilling fluid viscosity, well profile, bottom
hole assembly
component geometry, drillpipe geometry, and indications as to whether the
fluid
is flowing or stationary.
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205 If the value of p is changed, as noted above, this effect can easily be
accommodated by planned incremental changes for p in the look-up table that
are applied to the successively deeper sections of the well. For instance if
the
static pressure changes in excess of a given threshold between one
predetermined pressure in the table and the next, the inference is that the
210 increase is due primarily to a planned increase in mud density and not
simply an
inicrease in TVD.
Figure 2 adds a minor complication in that once a given depth is encountered
the well is steered away from vertical at some predetermined angle, as could
conveniently be assessed by the D&I package, although our invention does not
215 require this as the angular deviation may be also inferred from simple
static
pressure changes. The correspondence of pressure to MD is modified in an
obvious manner using simple geometry.
It is now apparent that the look-up table as described is a viable method of
determining MD in deviated wells. However it is known that in the art that
Figure
220 2 is an oversimplification of practical wells because it is not usually
possible to
drill a well in a perfectly straight line for any significant distance. The
driller's job
includes the need to continually correct the profile by making relatively
small
steering adjustments. In most instances these corrections are small enough
that
the method as described herein will remain substantially valid.
225 Figure 3 adds an apparently major obstacle to inference of MD because the
profile 4 contains a section of horizontal well, thus rendering equation 1
inappropriate for this section. In practical drilling applications horizontal
sections
are included in a class of wells called 'extended reach drilling' (ERD) wells,
as
depicted in Figure 4. The profile 5 can be typical of a directional well
containing
230 not only horizontal sections but also generally positive sloped sections
and
generally negative sloped sections. This is because in many circumstances it
is
necessary to follow a target formation that undulates in TVD. In a proportion
of
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these wells the generally horizontal section is relatively short compared to
the
vertical section. In these cases it would be adequate to use the look-up table
to
235 maximize the SNR improvements for the whole of the horizontal section.
In many ERD wells, however, the generally horizontal drilled section is equal
to
or greater than the length of the vertical section. This is indicated in
Figure 5,
where the X-axis 6 depicts TVD in meters and the Y-axis 7 depicts the
horizontal
displacement (departure) from vertical in meters. The hatched section 8 in
this
240 figure consolidates and presents the industry well drilling practise for
these
parameters over the last 40 years. Although it is not obvious from Figure 5,
roughly 67% of ERD wells have a departure from vertical greater than their
TVD.
Because the well types typified by Figures 3 and 4 are a very significant
fraction
of the total number of wells drilled, incorporating another technique is
necessary
245 for the MD estimation procedure. According to the present invention, the
pressure can also be measured under flow (dynamic) conditions and use is then
made of a prediction of ECD versus MD. A greatly simplified explanation of
this
and its relevance to the present invention is as follows.
The annular pressure AP due to dynamic flow increases with flow rate and pipe
250 length (i.e. MD) because of factors such as the increase in friction both
inside
and outside the drillpipe. AP also usually increases to a relatively small
extent (a
few percent) with cuttings in the annulus because they restrict flow
(particularly at
the tool joint sections) and also increase in net fluid density when the
cuttings are
in suspension. Because of the generally small effect of cutting, they will be
255 neglected hereon as they do not modify the principles embodied in this
invention.
As the AP value changes it also equally changes the bore (internal pipe)
pressure because the drilling fluid flows continuously from bore to annulus.
Therefore we could equivalently measure the bore pressure if that happened to
be more convenient, or indeed, as necessitated by the type of pressure gauge
in
260 the BHA.
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The simplest form of the calculation of ECD is (for instance see Formulas and
Calculations for Drilling, Production and Workover, 2'nd edition; publisher:
Butterworth-Heinemann; 2002, ISBN: 0750674520):
ECD = MW + (AP / (0.052 x TVD) [2]
265 where MW = drilling fluid (mud) weight (pounds per gallon)
AP = annulus pressure drop (psi) between surface and the depth at TVD
TVD = true vertical depth (feet)
Sophisticated algorithms are readily available to quantify AP in the well
planning
stage and thus predict ECD at any position along the planned well trajectory
by
270 taking into account the many variables that modify the predicted value of
ECD.
The present state of the art is that predicted ECD compared to actual ECD can
be accurate to within -5% for a calibrated model, or -10% or more for a non-
calibrated model. We take advantage of this standard calculation to
incorporate
the pressure drop in excess of the hydrostatic drop (equation 1) and
incorporate
275 the total pressure drop expected at each stage of the well's progress into
the
look-up table, the ECD-related calculations being particularly pertinent for
the
stages where deviations from vertical are significant. This procedure merely
complicates the table (or similar) entries, and requires that certain
drilistring
parameters are taken into the flow condition calculations. We point out that
we
280 do not actually need to calculate ECD; we need only to compute the
relationship
of AP to MD, this forming a part of the derived ECD calculations commonly
utilized in the drilling industry. The AP value we use is directly associated
with
length of drillpipe along the whole length of the well bore (i.e. MD) and the
BHA
geometry.
285 We are assuming in these cases that the planned flow rate is followed in
practise. If it is not, an error proportional to the square of the flow
velocity is
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introduced in the pressure p calculation, as would be given in the simplest
form
(laminar flow) by Daniel Bernoulli's hydrodynamic equation (see for instance
H.
Lamb, Hydrodynamics, 6th ed., Cambridge University Press, 1953, pp. 20-25):
290 p+~/2pv2+pgAh=constant [3]
where v = fluid velocity
Ah = vertical height change over which pressure p is measured
If the BHA pressure gauge has both bore and annulus pressure measuring
capabilities, one can make use of equation 3 by measuring the differential
295 pressure (i.e. bore - annulus) that is normally sensed across the mud
motor and
drill bit, thereby estimating the velocity v. Either a calculation or a
calibration can
be used to link v to p. This value of v can be used to modify the tabular
entries
to a specific set of flow velocities, and thereby obtain a more accurate
estimate of
MD, as indicated below.
300 Once v is calculated in this manner (or assumed from preset table entries)
then
the appropriate annular pressure AP (equation 2) can be associated with a
specific flow velocity. The next step is to recognise that the total dynamic
annular or bore pressure Ptoo, as measured by the downhole BHA tool in these
types of wells is given by:
305 Ptod = Pns + AP [4]
where we have separated the hydrostatic head component of pressure (Phs) and
the hydrodynamic pressure drop associated only with flow in equation 4. Thus
in
a well with significant horizontal sections a combined measure of static and a
dynamic pressures can be used to isolate AP. AP has already been calculated
310 aniJ is in tabular form in a look-up table (or similar) in the downhole
tool.
Because AP is a function of v and if v is known, it is now obvious that a
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reasonable estimate of AP can be mapped directly to MD. If v is not measured
the assumed value of v is utilized in a simpler table, with a somewhat lesser
degree of accuracy in MD. Either way, because we use MD in a coarse
315 iricremental fashion (e.g. increments of -500m) the changes to
transmission
parameters that modify SNR will not be significantly suboptimal.
The methods described herein can also beneficially apply to drilling
circumstances where downlinking to the telemetry tool is possible. This is
because the automatic nature of the telemetry changes associated with sampling
320 downhole pressure makes it unnecessary for surface control or intervention
to be
applied to the task of ensuring adequate received SNR under most drilling
conditions.
Furthermore, the methods described herein can also beneficially apply to
drilling
circumstances where a telemetry repeater tool is also included in the
drillstring.
325 Figure 6a depicts the conventional start of a deviated well where the BHA
10
(iricluding drilling means and telemetry tool) is separated from the rig 1 by
a
length (MD) of drillpipe 9. The invention as previously discussed applies to
this
stage. The next stage is to insert a repeater 11 as shown in Figure 6b. The
amount of drillpipe between repeater 11 and BHA has now a planned increase
330 12 that is intended to enable communications over approximately twice the
distance that limits a non-repeater circumstance. Because it is known in the
well
planning stage that a repeater would be inserted at a specific MD, the look-up
table or similar means would now fix the appropriate telemetry parameters to
values suitable for adequate communications from the BHA telemetry device 10
335 to the repeater 11. The invention now applies to control of the
appropriate
telemetry parameters associated with the repeater 11, as shown in Figure 6c.
As the well progresses the drillpipe length 13 between the repeater and the
rig
increases, and SNR communication to the rig is modified by the look-up table
or
similar within the repeater, enabling efficient communication as before.
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340 In summary, it is possible for the tool to make an approximate inferred
estimate
of its MD by making use of standard downhole sensors and assessing the
downhole pressure. Thus, the tool could be programmed to automatically adjust
certain of its acoustic transmitted parameters such that it could compensate
for
the surface reduction in SNR caused by increasing attenuation due to
increasing
345 NID. The present invention therefore provides a method by which tool
telemetry
decoding performance may be maintained at or above a specified threshold with
increasing well length without the need to communicate to the tool from the
surface. This method also includes the circumstances where one or more
repeaters are incorporated, as would now be understood by one skilled in the
art.
350
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