Note: Descriptions are shown in the official language in which they were submitted.
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ALONG STRING MEASUREMENT TOOL WITH PRESSURE SENSOR
ARRAY
CLAIM OF PRIORITY
[001] This PCT application claims the benefit of the filing date of U.S.
Provisional Patent Application Serial No. 63/202,825, filed June 25, 2021
entitled,
"ALONG STRING MEASUREMENT TOOL WITH PRESSURE SENSOR
ARRAY," and U.S. Provisional Patent Application Serial No. 63/202,805, filed
June
25, 2021 entitled, "ALONG STRING MEASUREMENT TOOL WITH PRESSURE
SENSOR ARRAY." The entire content of each of the above applications is
incorporated herein by reference.
FIELD OF THE INVENTION
[002] The present disclosure relates to a measurement while drilling (MWD)
tool. More particularly, the present disclosure relates to an MWD tool adapted
to
measure annular pressure in the wellbore. Still more particularly, the present
disclosure
relates to an MWD having a sensor array adapted to collect several annular
pressures
along the length of the tool providing the ability to observe differential
pressures within
the length of the MWD tool resulting in a higher fidelity view of pressure
changes in
the wellbore.
BACKGROUND OF THE INVENTION
[003] The background description provided herein is for the purpose of
generally presenting the context of the disclosure. Work of the presently
named
inventor, to the extent it is described in this background section, as well as
aspects of
the description that may not otherwise qualify as prior art at the time of
filing, are
neither expressly nor impliedly admitted as prior art against the present
disclosure.
[004] Measurement while drilling (MWD) generally involves one or more
tools arranged along a drill string that allow for capturing downhole
information during
drilling and/or tripping drill pipe. In some cases, MWD tools are placed at
selected
locations along the drill string and are adapted to measure inclination angles
providing
support for directional drilling operations. Other along string measurement
(ASM)
tools may also be adapted to capture data relating to the downhole environment
for
logging while drilling (LWD) operations. For example, ASM tools may include
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temperature sensors, pressure sensors, gamma ray sensors, or other sensors.
These
sensors may allow for capturing wellbore data and/or data relating to the
surrounding
geological formations. In some cases, the ASM tool may measure density,
porosity,
resistivity, acoustic-caliper, inclination at the drill bit, magnetic
resonance and/or
formation pressure.
[005] One type of ASM tool may be adapted to measure the annular pressure
surrounding the drill string within the wellbore. These pressures may be used
to
estimate the density of the drilling fluid surrounding the drill string and
may help to
capture information relating to changing conditions in the wellbore. Knowledge
of
these changing conditions can be helpful, for example, to allow a drilling rig
operator
to control kicks (e.g., influx of fluid into the wellbore from a formation)
and/or loss of
fluid from the wellbore. Both situations can lead to wellbore stability
problems.
Nonetheless, current systems do not provide a sufficient ability to avoid or
reduce
random and systematic errors nor do they provide information having sufficient
fidelity.
BRIEF SUMMARY OF THE INVENTION
[006] The following presents a simplified summary of one or more
embodiments of the present disclosure in order to provide a basic
understanding of such
embodiments. This summary is not an extensive overview of all contemplated
embodiments and is intended to neither identify key or critical elements of
all
embodiments, nor delineate the scope of any or all embodiments.
[007] In one or more embodiments, an along string measurement tool may
include an elongate body configured for loading into a drill string and a
sensor array
arranged on the body. The sensor array may include a first sensor arranged at
a first
sensor location on the body and the first sensor may be oriented relative to
the body to
sense annular pressures in a wellbore and may also be configured for sensing
annular
pressures in a wellbore. The sensor array may include a second sensor arranged
at a
second sensor location on the body. The second sensor location may be spaced
longitudinally along the body from the first sensor location by a first
distance. The
second sensor may be oriented relative to the body to sense annular pressures
in a
wellbore and may also be configured for sensing annular pressures in a
wellbore.
[008] In one or more embodiments, a method of monitoring wellbore
characteristics may include receiving pressure sensor signals from first and
second
sensors arranged on and spaced longitudinally along an along string
measurement tool.
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The first and second sensor may be spaced apart by a first distance. The
method may
also include calculating a differential pressure signal based on the signals
from the first
and second sensors. The method may also include displaying a differential
pressure
signal for a drilling operator.
[009] While multiple embodiments are disclosed, still other embodiments of
the present disclosure will become apparent to those skilled in the art from
the following
detailed description, which shows and describes illustrative embodiments of
the
invention. As will be realized, the various embodiments of the present
disclosure are
capable of modifications in various obvious aspects, all without departing
from the
spirit and scope of the present disclosure. Accordingly, the drawings and
detailed
description are to be regarded as illustrative in nature and not restrictive.
BRIEF DESCRIPTION OF THE DRAWINGS
[010] While the specification concludes with claims particularly pointing
out
and distinctly claiming the subject matter that is regarded as forming the
various
embodiments of the present disclosure, it is believed that the invention will
be better
understood from the following description taken in conjunction with the
accompanying
Figures, in which:
[011] FIG. 1 is a cross-section view of a drilling rig drilling a well and
having
a drill string with several along string measurement (ASM) tools arranged in
the string,
according to one more embodiments.
[012] FIG. 2 is a view of a portion of the drill string of FIG. 1, showing
several
ASM tools on the string, according to one or more embodiments.
[013] FIG. 3 is a side or lengthwise view of one of the ASM tools having a
pressure sensor array, according to one or more embodiments.
[014] FIG. 4 is a diagram depicting a method of monitoring a wellbore,
according to one or more embodiments.
[015] FIG. 5A is a graph of a differential pressure signal measured
between
two ASM Tools arranged 270 feet apart in a wellbore, according to one or more
embodiments.
[016] FIG. 5B is a graph of an estimated density based on the differential
pressure signal of FIG. 5A, according to one or more embodiments.
[017] FIG. 5C is a graph of a surface density signal for the well
pressures
depicted in FIG. 5A, according to one or more embodiments.
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[018] FIG. 6A is a focused view of a portion of FIG. 5A.
[019] FIG. 6B is a focused view of a portion of FIG. 5A with denoised
measured data (e.g., measured data passed through a denoising filter) and
including a
computed differential pressure.
[020] FIG. 7 includes of a series of comparable zero measurement error
effective density graphs showing the comparison of effective density within a
single
tool as compared to effective density between spaced apart tools, according to
one or
more embodiments.
[021] FIG. 8 includes of a series of comparable 1% measurement error
effective density graphs showing the comparison of effective density within a
single
tool as compared to effective density between spaced apart tools, according to
one or
more embodiments.
[022] FIG. 9 includes of a series of comparable 5% measurement error
effective density graphs showing the comparison of effective density within a
single
.. tool as compared to effective density between spaced apart tools, according
to one or
more embodiments.
[023] FIG. 10A includes a diagram of the effect on differential pressures
from
an influx, where the pressure sensors have a 100 ft spacing, according to one
or more
embodiments.
[024] FIG. 10B includes a diagram of an effective density based on the
differential pressures of FIG. 10A, according to one or more embodiments.
DETAILED DESCRIPTION
[025] The present disclosure, in one or more embodiments, relates to
a
measurement while drilling tool having an annular pressure sensor array.
Particular
arrangements of the sensors in the array may provide for the ability to reduce
random
error as well as systematic error in downhole pressure measurements. The
arrangement
of the sensors in the array may also provide high fidelity data relating to
the downhole
pressures and related fluid densities that are present in the wellbore. The
reduced error
and higher fidelity data may allow the drilling operator to better control
influxes of fluid
into the wellbore from the formation (e.g., kicks), loss of fluid from the
wellbore into
the formation, and otherwise have a better understanding of the conditions
that are
present in and along the wellbore.
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[026] FIG. 1 is a cross-section view of a drilling rig 50 drilling a well
and
having a drill string 52 with several tools arranged in the string, according
to one or
more embodiments. As shown, the drilling system may include a drill rig 50
having a
mast, a drill floor, and a variety of pipe handling equipment adapted to
connect drill
5 .. pipe, stands, or tubulars end-to-end to feed a drill string into a
wellbore. The equipment
may include, for example, a top drive, an iron roughneck, one or more pipe
elevators,
drill floor slips, a racking board, and other equipment used to manage
drilling and
tripping operations. Drill fluid systems may also be provided for pumping
drilling fluid
into and through the drill string to operate a drill bit arranged at the tip
of the drill string.
The drill fluid system may also include a recovery portion for capturing
drilling fluid
returning from the wellbore carrying cuttings. The drill fluid system may
clean the
returning drill fluid and deliver it for reuse in the wellbore.
[027] As shown, the drill string 52 may include a series of drill pipes
connected end-to-end extending downward from the drill rig 50 into a wellbore
in the
ground. The drill string 52 may include a bottom hole assembly (BHA) 54
arranged at
the tip of the string that includes drill bit, a steering system, one more
measuring devices
and the like. Upward from the BHA may be a measurement while drilling (MWD)
tool
56 that is particularly adapted to assist with directional drilling by sensing
and providing
inclination information to the drilling operator or drilling system. Upward
from the
.. MWD tool may be a logging while drilling (LWD) tool 58 that is adapted to
capture
geological and/or wellbore information that allows the operator, well
servicers, or other
operators with information about the geological formations the well extends
through.
In addition, and as shown, the drill string 52 may include one or more along
string
measurement (ASM) tools 100. As shown, the ASM tools 100 may be spaced along
the drill string and may be adapted for sensing pressures in the wellbore as
discussed in
more detail below. While a particular arrangement of tools has been discussed,
other
arrangements may be provided where, for example, the particular order of tools
behind
the BHA is changed or modified.
[028] Turning now to FIG. 2, an isolated view of a drill string 52 is
shown. As
shown, the drill string 52 may include one or more along string measurement
(ASM)
tools 100 spaced along the string behind the bottom hole assembly (BHA). In
one or
more embodiments, an ASM tool 100 may be arranged relatively close to the BHA
so
as to capture bottom hole pressures. The other ASM tools 100 may be spaced
along
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the drill string at equal spacings or unequal (e.g., asymmetric) spacings may
be
provided.
[029] In one or more embodiments, the ASM tools 100 may be part of a wired
drill pipe (WDP) system allowing for power and/or communication signals to be
transmitted along the length of the drill pipe to and/or from the several
tools on the drill
string. The system may be, for example, a data telemetry system. The data
telemetry
system may include a surface unit configured for sending and receiving signals
through
the drill string and/or for processing data received and displaying the data
to the
operator. In one or more embodiments, the data telemetry system may include an
electromagnetic telemetry system or a pulsed flow telemetry system.
[030] Turning now to FIG. 3, a single along string measurement (ASM) tool
100 is shown. The ASM tool 100 may be adapted for assembly along a drill
string 52
and configured to sense annular pressure in the wellbore at the location of
the tool 100.
In particular, the ASM tool 100 may be adapted to sense absolute annular
pressure and
differential pressures along the length of the tool 100. The ASM tool may
include a
body portion 102 and a sensor array 104.
[031] The body portion or body 102 of the ASM tool 100 may be configured
for loading, installing, and/or securing within a drill string 52 and adapted
to function
similarly to the rest of the drill string 52. That is, the body portion 102
may be adapted
for threadably engaging drill pipe or tubulars on each end thereof and adapted
to
provide a conduit through which drilling fluid may pass on its way to the
bottom hole
assembly (BHA). The body portion 102 may be an elongate and substantially
cylindrical element having a box end 106 and a pin end 108. The box end 106
may
include a relatively broad cylindrical portion having internal threading on a
conically
shaped internal surface. The pin end 108 may include a relatively narrower
conical
portion having threading on an external surface thereof The pin end 108 may be
adapted for stabbing into a box end 106 of an adjacent tubular and for
threadably
engaging the adjacent tubular. In this fashion, the ASM tool 100 may be placed
along
the drill string 52 simply by taking the place of an otherwise present tubular
of the drill
string 52. In one or more embodiments, the body portion 102 may have a length
that is
the same or similar to a length of drill pipe and, as such may range from
approximately
20 feet to approximately 40 feet, or from approximately 25 feet to
approximately 35
feet, or a length of approximately 30 feet may be provided. Still other sizes
of the body
portion may be provided.
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[032] The sensor array 104 may be configured to provide several annular
pressures along the length of the ASM tool 100. In particular, the sensor
array 104 may
be configured to provide several absolute pressure measurements and further to
allow
for several differential pressure measurements within the length of the tool.
In one or
more embodiments, the sensor array may include a plurality sensors 110 spaced
along
the length of the ASM Tool 100. The sensors 110 may be arranged on the body
portion
102 and oriented facing out so as to be exposed to an outboard side of the
body portion
and, thus, exposed to pressures in the annulus between the drill string 52 and
the
wellbore wall when the ASM tool 100 is in use in a wellbore. In one or more
embodiments, the ASM tool 100 may include two sensors 110 arranged at opposing
ends of the ASM tool 100. In other embodiments, three sensors 110 may be
provided
with two sensors 110 arranged at or near the ends of the tool 100 and a third
sensor 110
arranged between the outer sensors 110. The third sensor 110 may be centered
between
the outer two sensors 110 or it may be located to create unequal spaces on
either side
thereof (e.g., an asymmetric spacing). Still other numbers of sensors 110 may
be
provided along the length of the ASM tool 100 including 4, 5, 6, 7, 8, or more
sensors
110. In one or more embodiments, each sensor 110 may be a sensor pair. That
is, in
one or more embodiments, an additional sensor 110 may be provided in close
proximity
to the sensors 110 on the ASM tool 100 such that each sensor location 112
along the
length of the ASM tool 100 includes two sensors 110 instead of one. In one or
more
embodiments, the additional sensor 110 may be spaced a short distance
longitudinally
along the ASM tool 100 as shown in FIG. 3. Alternatively or additionally, the
additional sensor 110 may be arranged at a same longitudinal location, but at
a different
radial location around the circumference of the ASM tool 100. In any case,
where
sensor pairs are provided, the 2-sensor tool described may be a 4-sensor tool
and the 3-
sensor tool described may be a 6-sensor tool. Still other numbers of sensors
at particular
sensor locations along the length of the ASM tool 100 may be provided.
[033] FIG. 3 shows a particular sensor array including three sensor
locations
112 and a pair of sensors 110 at each of the sensor locations 112. As shown, a
first pair
of sensors 110 may be provided at or near a first end of the ASM tool 100. The
first
pair of sensors 110 may include a first sensor 110 with a second sensor 110
spaced a
short distance longitudinally and/or circumferentially away from the first
sensor 110.
A second pair of sensors 110 may be provided along the length of the ASM tool
100
and spaced from the first pair of sensors 110. The second pair of sensors 110
may
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include a third sensor 110 with a fourth sensor 110 spaced a short distance
longitudinally and/or circumferentially away from the third sensor 110. A
third pair of
sensors 110 may be provided spaced from the second pair of sensors and at or
near a
second end of the ASM tool 100 opposite the first end.. The third pair of
sensors 110
may include a fifth sensor 110 with a sixth sensor 110 spaced a short distance
longitudinally and/or circumferentially away from the fifth sensor 110. The
second pair
of sensors may be arranged between the first and third pairs of sensors 110.
As shown,
the second pair of sensors 110 may be located so as to be spaced a first
distance 114
from the first pair of sensors and a second distance 116 from the third pair
of sensors.
While this first and second distance 114/116 may be equal, FIG. 3 shows these
distances
114/116 being unequal. This unequal spacing may provide for additional
measurement
advantages discussed in more detail below. The sensors 110 in each pair may be
spaced
from one another by a short distance. The short distance may range from
approximately
0.5 inches to approximately 18 inches, or from approximately 3 inches to
approximately
12 inches or a short distance of approximately 6 inches may be provided. In
contrast,
the spacing of the pairs of sensors relative to adjacent pairs of sensors may
range from
approximately 24 inches to approximately 300 inches, or from approximately 36
inches
to approximately 120 inches, or from approximately 48 inches to approximately
96
inches, or from approximately 60 inches to approximately 72 inches, for
example.
[034] In one or more embodiments, the sensors 110 in the sensor array 104
may be pressure sensors. For example, mechanical pressure transducers or
capacitance
pressure transducers may be provided. Additionally or alternatively, strain
pressure
transducers or quartz pressure transducers may be provided. In any case, the
sensors
may be adapted to emit a signal based on the pressure it is experiencing at
any given
time. The sensors may emit a signal continually, periodically, or when
prompted, for
example. In one or more embodiments, the sensors 110 may be in wired or
wireless
communication with a controller or other receiver for analyzing the sensor
data and/or
displaying the sensor data for a drill rig operator.
[035] The sensors 110 in the array 104 may be in powered and/or
signal
.. communication with the telemetry system and/or one another. That is, for
example,
where differential sensor measurements within the tool are desired, one or
more sensors
or sensor pairs may be hardwired to another so as to emit a differential
pressure signal
to the telemetry system.
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[036] In operation and use, and in reference to FIG. 4, a method of
monitoring
a wellbore 200 with the above-described along string measurement (ASM) tool
may be
provided. In one or more embodiments, the method may include drilling a well
or
tripping drill pipe into or out of a well. 202. The method may also include
loading an
ASM tool onto the drill string and/or loading multiple ASM tools onto the
drill string
as the drill string is advanced into a wellbore. 204. As mentioned, the tools
may be
loaded onto the drill string by adding the tool to the drill string instead of
a pipe or pipe
stand, for example. Where a single ASM tool is provided, the ASM tool may be
loaded
onto the drill string at or near the bottom hole assembly or at a location
further up the
drill string. Where multiple ASM tools are provided, a first ASM tool may be
loaded
onto the drill string at or near the bottom hole assembly. A second ASM tool
may be
loaded onto the drill string and spaced up the drill string a first distance
from the first
ASM tool. A third ASM tool may be loaded onto the drill string and spaced up
the drill
string a second distance from the second ASM tool. The first distance and the
second
distance may be the same or they may be unequal providing for an asymmetric
arrangement of ASM tools along the drill string. Still other arrangements of
multiple
ASM tools on the drill string may be provided including arrangements without
an ASM
tool at or near the bottom hole assembly.
[037] With the one or more ASM tools loaded onto the drill string and
arranged in a wellbore, the method may include activating the one or more ASM
tools.
206. In one or more embodiments, the ASM tools may be activated upon loading
onto
the drill string. In other embodiments, the ASM tools may be activated by the
telemetry
system, which may provide power and/or an activation signal to the ASM tool or
tools.
[038] The method may also include collecting wellbore pressures with the
ASM tool or tools. 208. The method may include continuously, periodically, or
selectively collecting wellbore pressures during drilling and/or during
tripping into or
out of a well. For example, continuously collecting may include beginning to
collect
pressures upon activation of the ASM tool, periodically may include collecting
pressures at particular time intervals or during particular events, and
selectively may
include user selected collection, for example. The wellbore pressures may be
in the
form of signals that provide pressure vs. time.
[039] The method may also include transmitting the collected pressures to a
surface unit of a telemetry system, for example. 210. The transmitting may be
performed wirelessly or via wired drill pipe, for example. In one or more
embodiments,
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the transmitting may be via pulsed flow telemetry, for example. The method may
also
include receiving the transmitted pressure signals 212 and monitoring and/or
analyzing
pressures received from the ASM tools. 214. In one or more embodiments, the
monitoring and/or analyzing may include monitoring and/or analyzing absolute
5 pressures or differential pressures with a particular ASM tool and/or
between multiple
ASM tools in the drill string. Still further, the monitoring and/or analyzing
may include
watching for pressure conditions that are indicative of an influx of fluid
from the
underground formation into the wellbore, outflow of fluid from the wellbore
into the
formation, pack off, or other downhole problems that can occur and may be
evident
10 from changing pressure conditions.
[040] For example, drill fluid may be designed and selected with a goal of
providing downhole pressures that are sufficient to counteract internal
pressures in
underground formations. That is, the drill fluid density may be selected such
that at
particular wellbore depths, the hydrostatic pressure developed in the annular
space
around the drill string due to the weight of the drill fluid is the same as or
slightly above
the formation pressure. This may help prevent formation fluid from entering
the
wellbore. However, sometimes unanticipated high pressures are encountered as
drilling
progresses and high-pressure fluids may enter the wellbore. When this happens,
the
fluids may mix with the drilling fluid and change the density of the drilling
fluid, often
making it less dense, further exacerbating the problem and causing the influx
to
propagate quickly up the wellbore. In some cases, the influx can lead to a
blow out at
the surface of the drilling operation. The fluid influx into the wellbore may
be liquid
or gas, which can also change the effect of the influx on the wellbore
characteristics.
[041] Other downhole problems can also occur such as pack off, for example.
A pack off occurs when the cuttings from the drill bit get clogged in the
annular space
around the drill string and fail to flow upward in the annular space to the
surface. With
the continual pumping of fluid down the wellbore to operate the drill bit,
pressures in
the annular space around the drill string and below the pack off may increase.
Still
other scenarios can occur that may change the pressures in the annular space
around the
drill string. For example, a high permeable formation zone may cause mud fluid
loss
from the wellbore to the formation, which can lead to a wellbore stability
problem. The
loss of fluid may change the pressure gradient.
[042] It is to be appreciated that as the driller drills into the ground,
the
absolute pressures in the well bore may continue to increase and, as such, it
may be
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difficult to establish a benchmark for changes in well pressure because the
absolute
pressure is changing. That is, the further down a driller drills, the higher
the hydrostatic
pressure is in the annular space around the drill string at or near the bottom
hole
assembly. As such, absolute pressures at any given ASM tool may continue to
increase
as the wellbore gets deeper. However, where the spacing between any given two
sensors along the drill string remains substantially constant, as is the case
with ASM
tools spaced along the drill string, the difference between the hydrostatic
pressure at
one sensor relative to another sensor remains constant. For this reason, it
can be helpful
for a driller to monitor the differential pressures between sensors spaced
along the drill
string. In one or more embodiments, the monitoring and/or analyzing pressures
may
include calculating differential pressures. In some embodiments, these
differential
pressures may be further normalized by dividing them by a factor depending on
the
length between the sensors, which may result in an interval density or
effective density
of the fluid between the sensors.
[043] As shown in FIG. 5A, a differential pressure signal based on a
differential between sensors that are spaced approximately 270 feet from one
another
along a drill string are shown. As shown, the signal may remain substantially
constant
and oscillating around about 140 psi from time 0 minutes to time 110 minutes.
At that
point, the differential pressure begins to drop until 113 or 114 minutes and
returns to
approximately 140 psi at about 117 or 118 minutes. Another drop is seen at
approximately 160 minutes. This particular data set may result from a fluid
influx into
the bottom of the wellbore that reduces the pressure in the wellbore. FIG. 5B
shows
the density estimated from the differential pressure given in FIG. 5A. FIG. 5C
shows
the density measured on the surface using a Coriolis meter. FIG. 5C is
relatively clear
and shows a relatively consistent mud density of about 9.5 ppg. However, two
influxes
of 7.0 ppg diesel at around 127 minutes and 8.33 ppg water at around 172
minutes are
also shown. The estimated density (FIG. 5B) also shows the first influx at
around 113-
114 minutes. The Coriolis density lags behind the estimated density by
approximately
10-15 minutes (At) due to the time it takes for the influx to reach the
surface. The
second influx is barely visible in the estimated density plot of FIG. 5B. This
is because
the difference in the density of water (8.33 ppg) and the drilling mud (9.5
ppg) is
relatively small. The diesel influx, on the other hand, has a larger density
disparity with
the mud and the influx shows up a bit more clearly. A similar effect may occur
when
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the volume of the influx is relatively low. The effect of noise and/or error
can make it
difficult to identify pressure changes, which, although small, can be
meaningful.
[044] FIG. 6A is a closeup view of the differential pressure graph along
with
a denoised signal showing the two influx events. FIG. 6B is a closeup view as
well
with the measured data removed and showing only the denoised data. FIG. 6B
also
shows computed data in the form of a solid line. For example, the first influx
event
included 25 barrels of diesel fuel having a density of 7 ppg. The second
influx event
included 50 barrels of water having a density of 8.33 ppg.
[045] In view of the above, the method steps of monitoring and/or analyzing
the pressures received from the ASM tools 214 may include one or more steps
such as
the following. The multiple pressure values from a given sensor set may be
averaged
to help reduce statistical error. 214A Moreover, where asymmetric arrangements
of
sensors are used along the drill string or on a given tool, systematic error
may be
reduced. The method may also include calculating differential pressures
between
selected sets of sensors 214B and/or calculating interval or effective
densities based on
those pressures. 214C It is to be appreciated that sets of sensors at varying
locations
within the wellbore may provide different information depending on the range
of the
wellbore that the sensors cover. As such, multiple sets of differential
pressures and/or
interval densities may be calculated. For example, as between ASM Tools, each
permutation of differential pressure and/or interval density may be
calculated. That is,
where there are three ASM Tools, the differential pressure and/or interval
density may
be calculated between the first and third tool, between the first and second
tool, and
between the second and third tool. Still further, and as between sensor sets
on a single
tool, each permutation of differential pressure and/or interval densities may
be
calculated. That is, where there are three sensor sets on a given tool, the
differential
pressure and/or interval density may be calculated as between the first and
third sensor
set, between the first and second sensor set, and between the second and third
sensor
set
[046] In one or more embodiments, the method may also include applying a
denoising filter to the sensor data (e.g., to the differential pressure data
or the interval
density data). 214D. The denoising filter may include a time, frequency,
and/or time-
frequency filter based on an understanding of the reasonable times or
frequencies the
pressure data falls in, for example. The method may also include displaying
the
calculated differential pressure and/or density signals to a user. 216. The
method may
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13
also include watching for reductions or increases in the differential pressure
or density.
218. An operator, for example, may have a continual feed of one or more
differential
pressure or interval density signals and may monitor the feed for changes and
may take
action accordingly.
[047] As may be appreciated, the differential pressures and corresponding
densities that are computed for sensors within a tool and/or between different
tools in a
drill string may provide for a hierarchical, multiresolution analysis of the
data. This
may improve the detection, identification, and quantification of various
influxes/losses
during drilling operations.
[048] It is to be appreciated that the spacing of the sensors and their
position
in the wellbore may provide for differences in the data available to the
drilling operator.
For example, the data shown in FIGS. 5A-6B is based on sensors that are
arranged 270
feet apart in a wellbore. As shown and mentioned, the influxes that occurred
do not
reflect drastic departures of the differential pressure line and when sensor
error is
present (e.g., the oscillations around 140 psi), the changes in the
differential pressure
can get lost.
[049] However, and in reference to FIGS. 7-9, the presently described ASM
tool may provide for a higher fidelity depiction of the effect of an influx on
a wellbore,
for example. Moreover, as shown, the presently described ASM tool may be
better
suited to detect influxes where the difference between the density of the
influx fluid
and the drilling mud is relatively small.
[050] As shown in FIG. 7, several diagrams of interval densities are shown.
The graphs relate to three ASM Tools arranged in a wellbore: atop ASM Tool, a
middle
ASM Tool, and a bottom ASM Tool. The top graph is an interval density based on
sensors arranged on a same tool. The remaining graphs in the FIG. show
interval
densities based on sensors arranged on separate tools. A comparison of the top
graph
to the remaining graphs reveals that the close proximity of the sensors on the
tool cause
the influx of fluid to be very apparent even though the density of the influx
fluid is close
to the mud density (8 ppg vs. 10 ppg). This is because the differential
pressure between
.. the two sensors is relatively low due to their close proximity and, as
such, a change in
pressure at one of the sensors reflects a relatively large departure from the
interval
density baseline. The next graph down, for example, may be a graph of interval
densities between the bottom ASM Tool and the middle ASM Tool and the third
graph
may be a graph of interval densities between the middle ASM Tool and the top
ASM
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14
Tool. Finally, the bottom graph may be a graph of the interval density between
the
bottom ASM Tool and the top ASM Tool. Since the differential pressure from
these
further spaced apart sensors is greater, the significance of the change in
pressure gets
diluted. That is, the middle two graphs show a density change of approximately
1.25
ppg as compared to the density change of approximately 2 ppg in the top graph.
In the
bottom graph, the interval density change is closer to 0.5 ppg. When error is
present,
the effect of the influx on the interval density can get lost. For example, as
shown in
FIG. 8, a 1% error is included in the interval density readings. While still
discernible,
the lower three graphs begin to lose the clarity relating to the fluid influx,
while the top
graph remains quite clear. In FIG. 9, a 5% error is included in the interval
density
readings. Here, the effect of the influx in the bottom graph is all but lost
and the effect
of the influx in the middle two graphs is barely discernible, if at all.
However, the effect
of the influx in the top graph remains very clear. This higher fidelity view
of the effect
of an influx in a wellbore is provided by the presently described ASM Tool and
reflects
a substantial improvement in the detectability of density change in fluid mix
and/or
changes in the pressure gradient. That is, the inventors of the present ASM
Tool
embarked on a designing a tool with higher redundancy and higher spatial
resolution
that could reduce statistical error while improving the detectability and the
trackability
as the fluid influx/loss moves along the wellbore, and provides a hierarchical
approach
to measurement and data analysis.
[051] FIGS. 10A and 10B show another example of the limited
measurement
sensitivity of systems having sensors with relatively large spacings. For
example, as
shown, sensors may be arranged 100 feet apart along a drill string and an
influx fluid
having a 7 ppg density may flow into a wellbore that is using a 9.5 ppg
drilling mud.
Varying volumes of influx from 2 bbl to 20 bbl are shown. As shown, volumes
below
2 bbl may be difficult to detect. Accurate estimation of fluid density may
involve a
minimum volume influx of 14 bbl for detection. Detectability may also depend
on the
contrast between the densities of the influx and the drilling mud. Moreover,
the
effective density may not match exactly with the influx densities because of
the
hydrostatic assumptions in the density computation, while the pressure
computation
includes the fluid flow velocity and corresponding corrections. This is yet
another
example revealing that tool configurations with multiple short-spaced sensors
may
enhance detectability and accuracy.
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[052] As used herein, the terms "substantially" or "generally" refer to the
complete or nearly complete extent or degree of an action, characteristic,
property,
state, structure, item, or result. For example, an object that is
"substantially" or
µ`generally" enclosed would mean that the object is either completely enclosed
or nearly
5 completely enclosed. The exact allowable degree of deviation from
absolute
completeness may in some cases depend on the specific context. However,
generally
speaking, the nearness of completion will be so as to have generally the same
overall
result as if absolute and total completion were obtained. The use of
"substantially" or
µ`generally" is equally applicable when used in a negative connotation to
refer to the
10 complete or near complete lack of an action, characteristic, property,
state, structure,
item, or result. For example, an element, combination, embodiment, or
composition
that is "substantially free of' or "generally free of' an element may still
actually contain
such element as long as there is generally no significant effect thereof.
[053] To aid the Patent Office and any readers of any patent issued on this
15 application in interpreting the claims appended hereto, applicants wish
to note that they
do not intend any of the appended claims or claim elements to invoke 35 U.S.C.
112(f)
unless the words "means for" or "step for" are explicitly used in the
particular claim.
[054] Additionally, as used herein, the phrase "at least one of [X] and
[Y],',
where X and Y are different components that may be included in an embodiment
of the
present disclosure, means that the embodiment could include component X
without
component Y, the embodiment could include the component Y without component X,
or the embodiment could include both components X and Y. Similarly, when used
with
respect to three or more components, such as "at least one of [X], [Y], and
[Z]," the
phrase means that the embodiment could include any one of the three or more
components, any combination or sub-combination of any of the components, or
all of
the components.
[055] In the foregoing description various embodiments of the present
disclosure have been presented for the purpose of illustration and
description. They are
not intended to be exhaustive or to limit the invention to the precise form
disclosed.
Obvious modifications or variations are possible in light of the above
teachings. The
various embodiments were chosen and described to provide the best illustration
of the
principals of the disclosure and their practical application, and to enable
one of ordinary
skill in the art to utilize the various embodiments with various modifications
as are
suited to the particular use contemplated. All such modifications and
variations are
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16
within the scope of the present disclosure as determined by the appended
claims when
interpreted in accordance with the breadth they are fairly, legally, and
equitably entitled.
