U.S. patent application number 12/887334 was filed with the patent office on 2011-03-24 for apparatus and method for acoustic telemetry measurement of well bore formation debris accumulation.
This patent application is currently assigned to XAcT Downhole Telemetry Inc.. Invention is credited to Paul L. Camwell, James M. Neff.
Application Number | 20110069583 12/887334 |
Document ID | / |
Family ID | 43756523 |
Filed Date | 2011-03-24 |
United States Patent
Application |
20110069583 |
Kind Code |
A1 |
Camwell; Paul L. ; et
al. |
March 24, 2011 |
APPARATUS AND METHOD FOR ACOUSTIC TELEMETRY MEASUREMENT OF WELL
BORE FORMATION DEBRIS ACCUMULATION
Abstract
An invention is claimed wherein the signal loss along steel
drill pipe walls can be estimated in the absence of a loss
mechanism due to the formation debris at various positions in the
well bore; the signal loss in excess of the calculated attenuation
is generally and directly attributable to the build-up of said
formation debris and an estimation of the amount can be determined.
Furthermore, by use of distributed acoustic nodes positioned in the
well between the transmitter in the BHA and the surface
receiver--configured as repeaters--the formation debris build-up
can be determined in each section so defined. This new information
enables the driller to implement hole cleaning means in a timely
manner and as appropriate, thus avoiding the problems of getting
stuck in the hole, and possible well abandonment. An extension of
the method enables the hole cleaning process to be automated,
thereby improving efficiency.
Inventors: |
Camwell; Paul L.; (Calgary,
CA) ; Neff; James M.; (Okotoks, CA) |
Assignee: |
XAcT Downhole Telemetry
Inc.
|
Family ID: |
43756523 |
Appl. No.: |
12/887334 |
Filed: |
September 21, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61244336 |
Sep 21, 2009 |
|
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Current U.S.
Class: |
367/82 |
Current CPC
Class: |
E21B 47/095
20200501 |
Class at
Publication: |
367/82 |
International
Class: |
E21B 47/09 20060101
E21B047/09 |
Claims
1. A system for measuring formation debris accumulation in a
wellbore, comprising: an acoustic telemetry transmitter disposed at
a first location on a drill string, an acoustic telemetry receiver
disposed at a second location on the drill string spaced from the
first location or at a third location on the surface, and
configured to receive an acoustic signal sent along the drill
string from the transmitter via a wall of the drill string, and a
processor communicative with the receiver and having a memory
storing information comprising: an amplitude of an acoustic signal
launched by the transmitter, and parameters related to the
properties, motion, and inclination angle of a drill-string section
between the transmitter and receiver, the memory further encoded
with instructions executable by the processor to use the stored
information and an acoustic signal transmitted by the transmitter
and received by the receiver, to calculate an intrinsic signal
level loss along the drill string section between the transmitter
and receiver, an actual signal level loss of the transmitted
acoustic signal, and the difference between the actual signal level
loss and intrinsic signal level loss.
2. A system as claimed in claim 1 wherein the acoustic telemetry
transmitter is a bottomhole assembly transmitter located in a
bottomhole assembly of the drill string.
3. A system as claimed in claim 2 further comprising a bottomhole
assembly processor in communication with the bottomhole assembly
transmitter and having a memory encoded with information comprising
at least one of: an amplitude of an acoustic signal launched by the
bottomhole transmitter, and parameters related to one or more of
the properties, motion, and inclination angle of a drill-string
section between the bottomhole transmitter and the receiver, the
memory further encoded with instructions for the bottomhole
transmitter processor to cause the bottomhole transmitter to
transmit this information to the receiver.
4. A system as claimed in claim 2 further comprising a surface
transmitter communicative with the processor and located at
surface, and wherein the acoustic telemetry receiver is a surface
receiver located at surface and the processor is further programmed
to cause the surface transmitter to transmit a control signal to
the bottomhole assembly when the difference between the actual and
intrinsic signal level losses exceeds a threshold value.
5. A system as claimed in claim 1 further comprising a plurality of
telemetry nodes, and wherein the transmitter is a part of a first
node, and the receiver is part of a second node, and the drill
string section is between the first and second nodes.
6. A system as claimed in claim 5 wherein at least one node further
comprises a sensor for measuring the inclination angle of a drill
string section in the vicinity of the node.
7. A system as claimed in claim 4 further comprising one or more
telemetry nodes each disposed on the drill string between the
surface receiver and the bottom hole assembly transmitter, at least
one of the nodes comprising a node receiver configured to receive
acoustic signals sent along the drill string from another node or
from the bottom hole assembly transmitter, and a node transmitter
for transmitting an acoustic signal along the drill string to the
surface receiver.
8. A system as claimed in claim 7 wherein the at least one node
further comprises a node processor in communication with the node
transmitter and node receiver and having a memory encoded with
information comprising at least one of: an amplitude of an acoustic
signal launched by a transmitter of another node or by the
bottomhole assembly transmitter, and parameters related to one or
more of the properties, motion, and inclination angle of a
drill-string section in the vicinity of the node, the memory
further encoded with instructions for the node processor to cause
the node transmitter to transmit this information.
9. A system as claimed in claim 8 wherein the memory of the node
processor is further encoded with instructions for the node
processor to calculate the intrinsic signal level loss along the
drill string section in the vicinity of the node, the actual signal
level loss of an acoustic telemetry signal received by the node
receiver which was transmitted across the drill string section in
the vicinity of the node, and the difference between the actual
signal level loss and intrinsic signal level loss across the drill
string section in the vicinity of the node, and to cause the node
transmitter to transmit this information.
10. A system as claimed in claim 9 wherein the node transmitter is
configured to transmit an acoustic signal containing the difference
between the actual signal level loss and intrinsic signal level
loss across the drill string section in the vicinity of the node to
the surface receiver, and the surface processor is further
programmed to cause the surface transmitter to transmit a control
signal to the bottomhole assembly when the difference between the
actual and intrinsic signal level losses as calculated by the node
processor exceeds a threshold value.
11. A system as claimed in claim 9 wherein the memory of the node
processor is further encoded with instructions executable by the
node processor to cause the node transmitter to transmit a control
signal to the bottomhole assembly when the difference between the
actual and intrinsic signal level losses across the drill string
section as calculated by the node processor exceeds a threshold
value.
12. A system as claimed in claim 11 wherein the memory of the node
processor is further encoded with instructions executable by the
node processor when the threshold value is exceeded to cause the
associated node transmitter to acoustically transmit motor control
instructions selected from the group consisting of: changes to
drill bit rotation speed, drill bit angle, weight on bit, and flow
rate control.
13. A system as claimed in claim 1 wherein the process calculates
the actual signal loss by subtracting the amplitude of the acoustic
signal launched by the transmitter as stored in the memory from the
amplitude of the acoustic signal as received by the receiver.
14. A method for measuring formation debris accumulation in a
wellbore, comprising: determining an amplitude of an acoustic
signal launched by an acoustic telemetry transmitter disposed at a
first location on a drill string, and parameters related to the
properties, motion, and inclination angle of a drill-string section
between the transmitter and an acoustic telemetry receiver disposed
at a second location on the drill string spaced from the first
location or at a third location on the surface; receiving by the
receiver an acoustic signal transmitted by the transmitter;
calculating an intrinsic signal level loss along the drill string
section between the transmitter and receiver from the determined
parameters, calculating an actual signal level loss of the
transmitted acoustic signal from the received acoustic signal and
the determined amplitude of the acoustic signal launched by the
transmitter, and calculating the difference between the actual
signal level loss and intrinsic signal level loss.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. provisional
application No. 61/244,336, filed Sep. 21, 2009, which is
incorporated herein by reference.
FIELD
[0002] The present invention relates generally to an apparatus and
a method for acoustic telemetry measurement of well bore formation
debris accumulation.
BACKGROUND
[0003] Acoustic telemetry is a method of communication used, for
example, in the well drilling and production industry. In a typical
drilling environment, acoustic extensional carrier waves from an
acoustic telemetry device are modulated in order to carry
information via the drillpipe as the transmission medium to the
surface. Upon arrival at the surface the waves are detected,
decoded and displayed in order that drillers, geologists and others
helping steer or control the well are provided with drilling and
rock formation data. Downhole information can similarly be
transmitted via the well casings in production wells.
[0004] The device that typically generates the telemetry signal
(usually a PZT piezoelectric stack) causes extensional or similar
waves to be introduced into the steel walls of the drill pipe,
whence they travel to the surface. The walls are thereby caused to
move, either axially, radially or both in the transmission of
acoustic energy. The attenuation of such waves is dependent on a
number of factors, including pipe non-uniformities, pipe geometry
and tally, mode conversion, wall contact, drilling fluid type,
formation cuttings, cavings, and so on.
[0005] When drilling, one of the major problems is how to remove
cuttings and cavings from the well bore as drilling proceeds. If
this is not adequately solved, a well may be drilled ahead without
issue but withdrawing the drill pipe and the bottom hole assembly
(BHA) may be impossible and the well may have to be abandoned. It
is therefore important that the amount of cuttings or cavings and
their position in the well be known or accurately inferred in order
that appropriate and timely action (called hole cleaning) is taken.
Cavings are generally defined as formation debris in the wellbore
that does not originate due to the action of the drill bit but at
other sites within the well. The position of these sites can be
anywhere. Cavings can be large (perhaps 10 centimeters) or small,
whereas cuttings are usually small (from a few millimetres to a few
centimetres). The size issue will be seen to have importance later.
For our purposes we group both cavings and cuttings together as
formation debris.
[0006] The conventional method for assessing the build-up of
formation debris that may cause drilling problems is to make use of
a technique called `equivalent circulating density` (ECD). ECD
makes use of the fact that the drilling fluid's density is
increased by the presence of generally greater density particles
from the drilled formation that are suspended in the fluid. There
are numerous references discussing ECD. The usefulness of ECD is
reduced the higher the angle the well is drilled from vertical, and
is of no use if the drilling fluid is air (by which in this context
we mean nitrogen or diesel exhaust or similar non-explosive gases).
Thus high angle or horizontal wells drilled with air are at risk
due to the possibility of formation debris beds being difficult to
remove.
SUMMARY
[0007] According to one aspect, there is provided a system for
measuring formation debris accumulation in a wellbore, comprising
an acoustic telemetry transmitter disposed at a first location on a
drill string, an acoustic telemetry receiver disposed at a second
location on the drill string spaced from the first location or at a
third location on the surface, and configured to receive an
acoustic signal sent along the drill string from the transmitter
via a wall of the drill string, and a processor. The processor is
communicative with the receiver and has a memory that can store
information comprising: an amplitude of an acoustic signal launched
by the transmitter, and parameters related to the properties,
motion, and inclination angle of a drill-string section between the
transmitter and receiver. The memory is further encoded with
instructions executable by the processor to use the stored
information and an acoustic signal transmitted by the transmitter
and received by the receiver, to calculate an intrinsic signal
level loss along the drill string section between the transmitter
and receiver, an actual signal level loss of the transmitted
acoustic signal, and the difference between the actual signal level
loss and intrinsic signal level loss. This calculated difference is
indicative of the debris accumulation in the drill string
section.
[0008] The acoustic telemetry transmitter can be a bottomhole
assembly transmitter located in a bottomhole assembly of the drill
string. In such case, the system can further include a bottomhole
assembly processor in communication with the bottomhole assembly
transmitter and having a memory encoded with information comprising
at least one of: an amplitude of an acoustic signal launched by the
bottomhole transmitter, and parameters related to one or more of
the properties, motion, and inclination angle of a drill-string
section between the bottomhole transmitter and the receiver; this
memory is further encoded with instructions for the bottomhole
transmitter processor to cause the bottomhole transmitter to
transmit this information to the receiver.
[0009] The system can further include a surface transmitter
communicative with the processor and located at surface. In such
case, the acoustic telemetry receiver can be a surface receiver
located at surface and the processor can be further programmed to
cause the surface transmitter to transmit a control signal to the
bottomhole assembly when the difference between the actual and
intrinsic signal level losses exceeds a threshold value.
[0010] In an alternative configuration, the system can include a
plurality of telemetry nodes, in which case the aforementioned
transmitter is a part of a first node, and the aforementioned
receiver is part of a second node, and the drill string section is
between the first and second nodes. At least one node can comprise
a sensor for measuring the inclination angle of a drill string
section in the vicinity of the node.
[0011] In yet another alternative configuration, the system can
include a surface receiver, a bottomhole transmitter, and one or
more telemetry nodes each disposed on the drill string between the
surface receiver and the bottom hole assembly transmitter. At least
one of the nodes can comprise a node receiver configured to receive
acoustic signals sent along the drill string from another node or
from the bottom hole assembly transmitter, and a node transmitter
for transmitting an acoustic signal along the drill string to the
surface receiver. The at least one node can further comprise a node
processor in communication with the node transmitter and node
receiver and have a memory encoded with information comprising at
least one of: an amplitude of an acoustic signal launched by a
transmitter of another node or by the bottomhole assembly
transmitter, and parameters related to one or more of the
properties, motion, and inclination angle of a drill-string section
in the vicinity of the node. The memory can be further encoded with
instructions for the node processor to cause the node transmitter
to transmit this information. The memory of the node processor can
be further encoded with instructions for the node processor to
calculate the intrinsic signal level loss along the drill string
section in the vicinity of the node, the actual signal level loss
of an acoustic telemetry signal received by the node receiver which
was transmitted across the drill string section in the vicinity of
the node, and the difference between the actual signal level loss
and intrinsic signal level loss across the drill string section in
the vicinity of the node, and to cause the node transmitter to
transmit this information.
[0012] The node transmitter can be configured to transmit this
information to the surface receiver. In such case, the surface
processor is further programmed to cause the surface transmitter to
transmit a control signal to the bottomhole assembly when the
difference between the actual and intrinsic signal level losses as
calculated by the node processor exceeds a threshold value.
Alternatively, the memory of the node processor can be encoded with
instructions executable by the node processor to cause the node
transmitter to transmit a control signal to the bottomhole assembly
when the difference between the actual and intrinsic signal level
losses across the drill string section as calculated by the node
processor exceeds a threshold value. In this latter case, the
memory of the node processor can be further encoded with
instructions executable by the node processor when the threshold
value is exceeded to cause the associated node transmitter to
acoustically transmit motor control instructions selected from the
group consisting of: changes to drill bit rotation speed, drill bit
angle, weight on bit, and flow rate control.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] In the accompanying drawings, which illustrate the
principles of the present invention and an exemplary embodiment
thereof:
[0014] FIG. 1(a) is a schematic view of an annular space between a
well bore and a drilling tubular containing formation debris in a
well drilled with conventional liquid drilling fluid (known as mud)
where the well bore inclination varies from 0.degree. (vertical) to
<45.degree..
[0015] FIG. 1(b) is a schematic view of an annular space between a
well bore and a drilling tubular containing formation debris in a
directional well where the angle with vertical is >45.degree.
but <=65.degree..
[0016] FIG. 1(c) is a schematic view of an annular space between a
well bore and a drilling tubular containing formation debris
settled in a 65.degree. to horizontal 90.degree. well.
[0017] FIG. 2 shows a simplified and idealized view of a BHA
comprising a drilling motor and bit, a means of generating acoustic
signals, and drill pipe extending to the surface.
[0018] FIG. 3 is a schematic view of a simple directional well
comprising a vertical section, a build section and a horizontal
section, and which shows an acoustic telemetry wave launched from
the BHA toward the surface for detection by a rig.
[0019] FIG. 4 is a schematic view of the well shown in FIG. 3 and
three cross sectional views of the well A, B, C, in which: [0020]
cross sectional view A shows a relatively dispersed formation
debris in the vertical well bore section; [0021] cross sectional
view B shows more formation debris in contact with both the drill
pipe and the formation; and [0022] cross sectional view C shows the
horizontal section where a large build-up of formation debris
provides comprehensive contact between a drill pipe and an adjacent
formation.
[0023] FIG. 5(a) is a schematic view of an acoustic telemetry
system comprising a bottomhole transmitter and a surface receiver
according to one embodiment.
[0024] FIG. 5(b) shows an acoustic telemetry system according to
another embodiment comprising a bottomhole transmitter, a surface
receiver and a pair of acoustic telemetry nodes on a drill
string.
[0025] FIG. 6(a) is a schematic of a surface telemetry assembly
comprising the surface receiver, a surface transmitter and a
processor having a memory with instructions encoded thereon for
execution by the processor to process acoustic telemetry
measurement data relating to well bore formation debris
accumulation.
[0026] FIG. 6(b) is a schematic of a node assembly located at a
downhole location on the drill string and comprising a node
receiver, node transmitter, and a node processor.
DETAILED DESCRIPTION
[0027] Embodiments described herein introduce a new method and
apparatus for the oil and gas drilling industry which quantifies
the effect of formation debris in fluid filled wells with a
specific attenuation factor associated with the passage of acoustic
telemetry signals in drill pipe and other downhole tubular
members.
[0028] One embodiment comprises a system that carries out a method
of measuring debris formation accumulation in a wellbore. The
system comprises an acoustic telemetry transmitter near a drilling
bit of a BHA of a drill string, a surface acoustic telemetry
receiver configured to receive an acoustic signal sent along the
drill string from the transmitter via the walls of the drill
string, a processor communicative with the receiver and a memory
encoded with instructions executable by the processor to determine
the intrinsic signal loss along the drill string between the
transmitter and receiver (i.e. the loss due to acoustic waves
travelling along steel drillpipe, the loss due to passband
filtering, mode shifts and other similar irreducible effects),
measure the actual loss between said transmitter and receiver from
the received acoustic signal, then subtract the actual and
intrinsic losses to determine the build-up of drilling formation
debris in the well bore. This determined build up of formation
debris can be relayed to a person or to a device able to store,
indicate or implement the perceived need for reduction of formation
debris within the well being drilled.
[0029] In another embodiment, the sections of the well can be
delineated by the positions of several acoustic telemetry devices;
such devices can comprise at least one device being an acoustic
transmitter near the drill bit, at least one device being both an
acoustic receiver and an acoustic transmitter such as a telemetry
node, and at least one device being a surface acoustic receiver.
The devices utilize the acoustic telemetry signals propagating
within the walls of the drill pipe. In particular, the system can
comprise multiple telemetry devices each at select sections of the
well; the devices in these multiple sections can comprise a
receiver, a transmitter and a processor. Each receiver can receive
the transmitted acoustic signals arriving at its location, said
signals having incorporated decodeable data such as transmitter
amplitude and its local angle of inclination; each associated
processor can thereby determine the value of the actual acoustic
signal loss minus the expected intrinsic acoustic signal loss at
each selected location in the well to obtain multiple values--its
own and those received from other segments. Each associated
transmitter can send the determined value upstring to the surface.
Once received at the surface, an operator can use these multiple
values to determine if there is a need for well cleaning within
each of the multiple sections of the well.
[0030] In one embodiment, one or more processors can be programmed
to automatically assess the acoustic signal attenuation between
drill string sections, wherein the sections are defined by the
placement of acoustic transmitters and receivers. The processor(s)
can be programmed to telemeter the attenuations to the surface on a
preset timed basis. One or more of these processors can be
programmed to determine the difference between, or ratio of,
acoustic signal attenuations assessed for individual sections,
wherein such assessments are determined as the well progresses. An
alteration in the downhole drilling process can be effected without
surface intervention in order to automate the hole cleaning
process, thereby improving the process.
[0031] In another embodiment, one or more processors can be further
programmed to automatically assess acoustic signal attenuation
between sections between drill string sections, wherein the
sections are defined by the placement of acoustic transmitters and
receivers. The processor(s) can be programmed to telemeter the
attenuations to the surface whenever preset attenuation thresholds
are exceeded. One or more of these processors can be programmed to
determine the difference between, or ratio of, acoustic signal
attenuations assessed for individual sections, wherein such
assessments are determined as the well progresses.
[0032] When drilling a well, formation debris is removed from the
drill position to the surface by travelling along an annular cavity
between a drill pipe and BHA and the well bore. Referring now to
the Figures, FIG. 1(a) shows how the drilling fluid 2 returning to
the surface carries said formation debris 1 in a reasonably uniform
manner throughout the annulus 3. This is because the fluid flow
profile is reasonably uniform horizontally across the available
annular area, except close to the walls defining the annulus, where
the flow is reduced. If the mud flow is reduced to zero, the
formation debris will settle vertically under gravity, at a rate
determined in part by the fluid viscosity. Hole cleaning is
determined in large part simply by mud flow rate and mud viscosity.
The hole can be cleaned with stationary (non-rotating) pipe. This
generally holds true for deviations from vertical up to
45.degree..
[0033] If the well deviation is between 45.degree. and 65.degree.,
as shown in FIG. 1B, the formation debris will move up the hole on
the low side, but less efficiently than in a vertical well. In
order to help their movement greater flow rate may be required, or
utilizing the rotation of the drill pipe so as to stir them into
the annular region of higher flow, as shown as arrow 5. When the
mud pumps are turned off the hole angle is too high for practical
fluid viscosities to have a significant effect in keeping the
formation debris in suspension. They will slide (avalanche)
downhole, forming `dunes`.
[0034] In all high angle wells (>65.degree. to 90.degree.) the
formation debris will move as sand on a beach, settling 6 in the
lowest part of the well bore, with almost no formation debris being
lifted into the high flow area (shown as arrow 7). Mechanical
agitation is necessary for formation debris movement, independent
of flow rate and mud viscosity. This is indicated in FIG. 1C, where
we show the substantial mud flow rate occurring above the formation
debris, the formation debris settling 6 out in the short distance
to the lower side of the well.
[0035] When the formation debris is held in suspension the
effective density of the fluid increases (rock specific gravity
with respect to water is typically 2.2 to 2.6, and mud specific
gravity is typically 1.1 to 1.3). This can be measured by ECD
techniques and hole cleaning efforts can be applied accordingly.
Once the formation debris is supported by the well bore the mud
density returns to normal and ECD is ineffective.
[0036] The normal technique to introduce formation debris into the
higher velocity portion of the mud flow is to rotate the drill
pipe. Directional drilling usually requires a section of each drill
pipe advance (typically .about.30 ft) to be a combination of
rotating and sliding in order to maintain a required inclination.
Formation debris beds form in high angle wells while sliding, which
may be dissipated during the rotation section. If the drilling
fluid viscosity is minimal--for instance when the fluid is air--it
can be seen that formation debris build-up can be a serious issue.
High speed pipe rotation and `working the pipe` (maximum flow rate,
slowly moving the drill string up and down over a length of drill
pipe for tens of minutes to several hours) may be the only ways to
ensure formation debris is adequately removed.
[0037] It is generally accepted in the industry that hole cleaning
enhancement using the rotation movement of the drill pipe alone is
due to one or both of two effects--viscous coupling of the rotating
pipe to the drilling fluid, and the tendency of the drill pipe to
form a helical shape in the axial direction (corkscrew). Viscous
coupling is thought to help formation debris rotate into the areas
of higher fluid flow, thereby helping their movement out of the
hole. The corkscrew deviation of the drill pipe from simple
axially-straight curves can be at a maximum when there is
significant weight on the bit due to the drill string's own
self-weight. Rotation of the drill string will cause now cause
further mechanical agitation that can help sweep the formation
debris into a higher speed fluid location in the annulus, helping
the debris to be transported uphole. It is apparent that moving
formation debris away from the drill bit, BHA or drill string at
any location in a high angle well to the surface depends
significantly on the flow rate, density and viscosity of the
drilling fluid.
[0038] ECD as a means of determining how much formation debris is
in the well is of no use in air drilling as the air is relatively
ineffective in holding formation debris in suspension. Mechanical
motion that induces formation debris to be blown past pipe
connection joints (or upsets) must be relied upon, and is very much
less efficient than when the drilling fluid significantly comprises
a liquid.
[0039] FIG. 2 in very simplified form shows the configuration of a
typical drill string 10. At the bottom of the drill string is a
bottom hole assembly (BHA) 20 comprising a drilling motor and drill
bit 21, and a telemetry device 22 upstring from the motor and bit
21. In this embodiment the telemetry device 22 is an acoustic
telemetry tool that measures certain drilling parameters and
transmits this data encoded onto an acoustic telemetry signal, this
signal moving primarily along the steel walls of the drill string's
tubular members and towards the surface 24. The BHA components are
attached to drill pipe 23 that forms a link to the surface 24 and
the rig (not shown). The drill pipe 23 are usually tubes that have
a means of being screwed together, their main purpose being to
transport drilling fluid to the motor and bit 21, and to form a
durable mechanical link between rig and the BHA 10.
[0040] FIG. 3 is a representation of the drill string 10 in a
simple 3-section horizontal well. The first section drilled is a
vertical section 31; following is a build section 32, finally
followed by a horizontal section 33. As these sections are drilled
they typically have progressively smaller diameters. For instance
the vertical section 31 may be drilled with a 12.25'' bit while the
horizontal section 33 may be drilled with a 6.25'' bit. The
formation debris 1 would accumulate in the vertical section 31 and
up to 45.degree. of the build section 32 as indicated in FIG. 1A.
From 45.degree. to 65.degree. of the build section 32 the formation
debris 1 would form dunes as shown in FIG. 1B. Finally, moving to
the horizontal section 33 the formation debris 1 would form as
shown in FIG. 1C. A well drilled with a liquid is reasonably
effective in moving formation debris in the scenarios considered,
except perhaps for extended reach wells where particular care has
to be taken in long horizontal sections. But a well drilled with
air is much more difficult to clean. The only method that works is
to rotate the drill pipe at a rate that mechanically agitates the
formation debris into the high flow rate regime within the annulus.
The rotation rate is often very limited by torque as the higher
friction of the drillstring in air is significantly greater than in
liquid. This is not always appropriate for directional drilling
control, so formation debris can build up much more quickly than
with a liquid drilling fluid.
[0041] An acoustic telemetry signal 34 is generated close to the
bit 21 by the telemetry device 22 and is propagated towards the rig
at the surface 24. As noted previously, the signal 34 is launched
within the steel of the BHA 20 and continues in the steel walls of
the drill pipe 23. The drill pipe 23 forms frequency passbands and
stopbands so for the signal 34 to travel any substantial distance
along the pipe 23 it must lie within one of these passbands. The
acoustic signals are usually in the form of extensional waves,
thereby causing the walls of the pipe 23 to alternately expand and
contract in an axial direction. If the pipe 23 is constrained in
this movement by the local presence of formation debris 1, such
formation debris 1 can form an attenuation mechanism, the size of
which is in proportion to the extent of the formation debris 1
surrounding the pipe 23, and the force with which they connect the
drill pipe to the surrounding rock formation. The size of the
debris particles is also important because if they were large in
comparison to the diameter of the pipe 23 there would be fewer
points of contact from pipe 23 to formation through the medium of
the debris, affording less opportunity for the movement of the pipe
forming the extensional waves to be limited. Worst case would be
close-packed debris completely surrounding or packing the drill
pipe 23. FIG. 4 show the formation debris accumulations as
appropriate for vertical (A), build (B) and horizontal (C) sections
of a typical well bore 41, wherein formation debris in these
respective sections are labelled as 42, 45, and 46 respectively. In
the vertical section the drill pipe 23 can be in any position
within the bore 41, but the formation debris 42 are expected to be
of low concentration around the pipe 43, and dispersed reasonably
uniformly within the bore (view A), thus causing relatively low
signal attenuation via the mechanism latterly presented. In the
45.degree. to 65.degree. section of the build the formation debris
45 are expected to be of higher concentration around the drill pipe
due to the formation of dunes (view B); thus the attenuation here
will be greater than previously. In the 65.degree. to 90.degree.
section of the well the formation debris 46, particularly in an
air-drilled well, will fall uniformly to the bottom of the well
bore, and in poorly-cleaned wells will completely cover the drill
pipe (view C). Inspection of FIG. 2 indicates that drill pipe 23
comprises sections of narrow diameter pipe 23 joined to shorter
sections of larger diameter that enable the pipe 23 to be screwed
together. These larger diameter sections--upsets--generally hold
the thinner pipe 23 away from the formation 44. Thus in a clean
horizontal hole the only contact would be through the upsets. If
the formation debris bed (or beds) extends along the horizontal
path, it is possible that the whole length of the drillstring 10 in
this section and also some of the build section are in much closer
formation contact due to the packing of the formation debris, as
indicated in view C of FIG. 4.
[0042] The foregoing explains how formation debris may accumulate
within a well bore to the possible detriment of drill pipe removal,
generally leading to very costly well remediation efforts. The
unique properties of acoustic telemetry are utilized in order to
predict the build-up of formation debris in various sections of the
well before the problem becomes a serious issue via the utility of
measuring the loss in extensional wave amplitude caused by
significant packing of said formation debris around the drill pipe
and BHA.
Drill Pipe Attenuation
[0043] As already mentioned, the signal attenuation along the pipe
has many causes. Once the pipe tally defining the length of each
individual pipe and its specific geometry is known it is possible
to simulate the passage of an acoustic wave along such a
drillstring and predict its attenuation/unit length using known
techniques, which can be completely theoretical, or can be
augmented by field measurements. From the latter we have measured
attenuations of 8 dB/km along 500 m of good quality 4.75'' drill
pipe, and 14 dB/km along 500 m of well-used but similar type drill
pipe (several thread recuts per pipe), both sections being
suspended horizontally in air. Using data like this, and applying
it to an actual rig's tally provides a basis for assessing the
irreducible signal loss between an acoustic transmitter relatively
close to the bit, and a receiver located at surface within the rig
structure.
[0044] In practise the attenuations measured in such situations
show greater signal attenuation than would be expected from the
air-based measurements. For instance, loss due to coupling between
the pipe and the formation via liquid drilling fluid has a
significant effect. The extent to which there is direct wall
contact also has an effect of signal loss. It is found that the
loss/unit length in different sections of a well are also
important--in the horizontal section as shown in FIG. 5(a) for
example, the wall contact due to the pipe lying at the bottom of
the bore under gravity provides a greater attenuation than that of
the build section. Further, the loss/unit length in section c of
FIG. 5(a) is found to be less than the other two sections. These
attenuations can be directly measured or inferred. Indeed, the
different sections drilled provide a direct calibration given that
the hole is reasonably clear of formation debris.
[0045] As the well is drilled ahead, the actual signal level loss
can be determined from the actual reception of signal + noise at
the rig receiver (surface receiver) minus the known signal level
strength outputted by the transmitter, once the appropriate
filtering has taken place. The change in the intrinsic value of
signal attenuation can be estimated by modeling and compared with
reality, using known methods; in other words, the intrinsic signal
loss or attenuation can be predicted using the known properties of
the pipe and operating conditions such as the drillpipe placement
in the hole, incorporating factors such as the angle of
inclination, pipe rotation speed etc.
[0046] In one embodiment and as shown in FIGS. 5(a) and 6, a
processor 48 is at the surface 24 in the rig structure and is
communicative with a surface receiver 52, which receives the
acoustic telemetry signal 34 transmitted by a single acoustic
telemetry transmitter 51, which is in the telemetry device 22 of
the BHA 20 (henceforward "BHA transmitter"). The processor has a
memory 49 which stores information including: the strength
(amplitude) of a signal launched by the transmitter 51, parameters
related to one or more of the properties, motion, and inclination
angle of a drill string section between the BHA transmitter 51 and
the surface receiver. The properties of the drill string can be
predetermined and stored on the memory. The inclination angle can
be measured by an inclination sensor in a telemetry node on the
drill string, or at another location on the drill string. The
transmitter signal strength can be transmitted by the transmitter
51 or be previously stored on the memory. In this case, a BHA
processor 53 is provided which can instruct the BHA transmitter 51
to send telemetry signals to the receiver 52 that include the
strength of the signal launched by the BHA transmitter 51.
[0047] The memory also has stored thereon a program that is
executable by the processor 48 to calculate a predicted intrinsic
signal attenuation data according to known techniques and using at
least some of the aforementioned stored information. The memory 49
also has stored thereon a program executable by the processor 48 to
calculate the actual signal level loss from an acoustic telemetry
signal transmitted by the BHA transmitter 51 and received by the
surface receiver 52, by subtracting the transmitter signal strength
stored in the memory 49 from the measured strength of the acoustic
telemetry signal received by the surface receiver 52. This
calculated difference represents the actual signal level loss
including the attenuation of the formation debris, and is also
stored on the memory 49.
[0048] The program stored on the memory 49 also includes a set of
instructions that are executed by the processor 48 and which
perform a step of subtracting the determined actual signal level
loss from the predicted intrinsic signal level loss for the
horizontal, the build and the vertical sections stored on the
memory 49. The calculated difference, i.e. any excess signal level
loss above the intrinsic signal level loss, would be attributed to
extra loss mechanisms. We attribute this extra loss mainly due to
the build-up of formation debris, as has been explained. Therefore,
these programmed steps executed by the processor 48 determine the
signal loss caused by build-up of formation debris. This program
can thus be referred to as a formation build-up determination
program.
[0049] When the hole cleaning techniques as known in the art are
implemented, the observed signal level loss reduces as expected,
and further corroborates the link between signal strength changes
due to the presence or absence of the amount of formation debris
and their placement in the well bore. It is also reasonable to
correlate the amount of formation debris that actually reach
surface due to hole cleaning with the likelihood of pipe withdrawal
problems and with the excess attenuation seen. Thus one useful
application of this programmed method executed by the processor 48
is to predict the build-up of a `dangerous` amount of formation
debris via acoustic signal attenuation occurring along the drill
pipe walls before it becomes a significant issue.
[0050] Referring to FIG. 5(b) and according to another embodiment,
the formation build-up determination program can be adapted to
handle more complicated well configurations. In this embodiment,
the system comprises multiple distributed acoustic telemetry nodes
53 located at spaced intervals along the drill string, and which
augment the transfer of acoustic telemetry signals from the BHA
transmitter 51. Referring to FIG. 6(b) each node 53 is provided
with a node transmitter 59 for transmitting an acoustic signal
through the drill pipe, and a node receiver 61 for receiving an
acoustic signal transmitted through the drill pipe. Each node can
also be provided with an inclination sensor 62 to measure
inclination angle data used to calculate the intrinsic signal level
loss.
[0051] The segment of the drill string between the BHA transmitter
51 and the deepest node 53 ("first node") is referred to as
"Section h" in FIG. 5(b); we can estimate the attenuation along
this segment according to the technique described above. Similarly,
we can estimate the attenuation along different sections along the
drill string, such as "Section g" between the first node 53 and the
adjacent upstream node 53 ("second node"), and "Section f" between
the second node 53 and the surface receiver 52. While the
attenuation value will vary in each section as the well progresses
from surface to the target, the attenuation for each well section
is assessed and the excess noted, providing valuable inferential
formation debris knowledge to the driller.
[0052] It will be understood that the information may be associated
with the absolute value of attenuation or attenuation/unit length,
or simply the forgoing being greater than a preset threshold.
[0053] Each node 53 can further comprise a node processor 63 with a
memory that stores data including the intrinsic signal loss of an
associated drill string section and the transmitter signal strength
of an adjacent node's transmitter 59, and a program for execution
by the node processor 63 and which calculates the excess
attenuation of a drill string section in the vicinity of the node
53. The time-varying information thus achieved as the well proceeds
can be used to determine potential formation debris problems along
significant sections of the well, thereby enabling hole cleaning
procedures to be undertaken before the problems as discussed
occur.
[0054] Each node 53 will thus calculate the actual signal level
loss from a received signal transmitted by a transmitter 59 or 51
at the other end of the drill pipe section, and subtract the
estimated intrinsic signal loss of that section from the actual
signal loss to come up with a value that represents the excess
attributed to cutting in that section (this section being the drill
pipe section in the vicinity of the node 53). This information will
be sent up-string, node 53 to node 53, to the surface such that the
driller can then take appropriate action. In an alternate
embodiment, and instead of having each node 53 process and
determine the formation build-up in its associated section, each
node 53 can simply send the signal level each node 53 receives with
its associated incoming `launched` signal level of the node's
transmitter and its inclination, then pass these data in an
increasingly longer string to the surface where the surface
processor 52 does the excess/segment calculations and alerts the
driller.
[0055] As is well known in the industry, two-way communication is a
useful feature in distributed telemetry nodes. This feature can be
used to communicate relative attenuations from various sections of
the drill string to the others. This can be utilized as a
referential approach to the need for hole cleaning, as the
following example explains.
[0056] By referring to FIG. 5(b) we can see that section f is
expected to be relatively free of excess attenuation due to
formation debris build-up, thus its attenuation/unit length can be
measured at timed or triggered intervals and this information be
passed on to the nodes 53 at sections g and h. Section g may be
suffering from too much formation debris reducing the expected
signal between nodes 53, and this section's attenuation/unit length
can be related to that of section f. If the ratio (or similar) of
these is above a specified amount, one of the nodes 53, preferably
though not necessarily the uppermost, can relay this information to
the surface receiver 52 where appropriate action can be initiated.
This approach has a specific value in that it incorporates a
certain `calibration` effect, where one section of the well is
expected to have similar attenuation characteristics as others
(same pipe type, same drilling fluid, etc.), apart from the amount
of pipe contact with the wall in vertical compared to horizontal
sections, and the extent of formation debris build-up. Of these two
attenuators it is the latter that will significantly dominate
attenuation/unit length because it is only the short sections of
upsets in the drill pipe 23 (shown in FIG. 2) that that are
normally able to touch the wall; formation debris can run the whole
length of the section. Thus if the sections lengths are telemetered
as necessary, or inferred via well planning data,
attenuation/section above a planned threshold can be determined at
regular intervals or, indeed, when a threshold is reached. This
threshold would be chosen before the amount of formation debris
presented a danger to the well, and before the telemetered signal
was significantly compromised in amplitude at a receiving station,
either downhole or at surface.
[0057] Given that it is possible to assess the formation debris
build-up downhole in individual sections and compare via telemetry
means their relative amounts of build-up, the method can be
extended to control the production of formation debris via changes
to, for instance, the operating parameters of the drilling motor
(as would be apparent to one reasonably skilled in the art of
drilling motor control), again by telemetry means. For instance,
rotary steerable tools (RST) are able to semi-autonomously steer a
well without surface intervention. Extensions of this capability
include drill bit rotation speed, drill bit angle and flow rate
control. Acoustic telemetry, as described herein, is inherently a
two-way technique with extension waves able to travel both up and
down the well. A surface transmitter 55 is communicative with the
processor 48, which generates a motor control signal based on the
calculated debris formation in each pipe section. A simple acoustic
receiver 57 ("bottomhole assembly receiver") associated with a
motorized controllable drilling means (e.g. an air hammer, a rotary
steerable tool, variable orifice bit, circulating sub, combinations
of same etc.) can be caused to respond to the motor control signal.
Its response can therefore be to cause the drilling means system to
modify its production of formation debris (either increasing or
reducing as appropriate) in order to satisfy preset well drilling
parameters.
[0058] In yet another embodiment, the local calculations performed
at each node 53 are not sent to the surface receiver 52 and
processor 49 are instead are used to change the drilling parameters
in the BHA and control drilling operation in a manner than can
offset the deleterious build-up of formation cuttings, without need
of the driller's intervention. In other words, one of more nodes 53
can calculate a suitable motor control signal and send this signal
to the BHA receiver 47 to control the motorized controllable
drilling means, without the involvement of the surface processor
48.
[0059] In summary, there are three basic embodiments that can deal
with the excess signal loss due to downhole cuttings:
(i) The signal from the BHA transmitter 51 (closest to the drill
bit) is transmitted directly to surface as shown in FIG. 5(a) or by
multiple nodes 53 as shown in FIG. 5(b), received by the surface
receiver 52 and processed entirely by the processor 48. The
calculations carried out by the processor 48 compare actual signal
loss with the predicted intrinsic signal loss along the drill
string, the difference being ascribed to the build-up of cuttings.
This information is directly relayed to the driller to take
remediative action, or to enable a surface-to-downhole motor
control signal to be automatically sent by the surface transmitter
55 in order to take remediative action. (ii) The acoustic signal
levels in a multimode system as depicted by FIG. 5(b) may be
processed at each node 53; either the received acoustic signal and
other data (such as the launched transmission level and the local
drillpipe inclination, the pipe rotation speed etc.) are relayed on
to the surface receiver 52 or are locally processed at the node 53
and then are relayed on to the surface receiver 52, thereby
enabling the driller to take remediative action, or to enable a
surface-to-downhole signal to be automatically sent by the surface
transmitter 55 in order that remediative action is taken downhole.
(iii) The acoustic signal levels in a multimode system as depicted
by FIG. 5(b) may be processed at each node 53, utilizing data such
as the launched transmission level and the local drillpipe
inclination, the pipe rotation speed etc. Once processed, the
cuttings excess is calculated by the node processor 63 and if
greater than a specific threshold a telemetry signal is launched
from that node 53 primarily for downhole reception in order that
remediative action is taken, without the need for surface
intervention. This method enables automatic capability of hole
cleaning, without the specific necessity for surface intervention
(although this can be additionally incorporated in the procedure).
In effect the telemetry determination of excess attenuation
relating to the sectional formation debris build-up and their
values relative to each section affords a means that does not
require human or surface intervention in order to keep the well
clear of formation debris according to a predetermined change or
series of changes in how the well is drilled. In effect the
coupling of acoustic telemetry attenuation with the build-up of
formation debris can form a closed-loop system for preventative
hole cleaning within the scope of this invention.
[0060] We do not limit the preferred embodiments of this invention
to wells drilled with only or predominantly gaseous drilling
fluids, in contrast to wells drilled predominantly with liquid
drilling fluids, as the method has utility in both. We have merely
pointed out that hole cleaning is more difficult with air than with
liquid. Formation debris build-up has a generally equivalent effect
on the excess attenuation of extensional acoustic waves travelling
along steel pipe walls whether the fluid is air or liquid. Thus the
utility of the invention applies to both cases.
[0061] By the utilization of the apparatus and methods described
herein there is now a new tool in the oil & gas drilling
industry that can make drilling faster, more efficient and safer,
derived from the unexpected convergence of knowledge from the
mechanisms of formation debris build-up, particularly in air
drilled wells, and the acoustic signal loss along the walls of
drill pipe.
[0062] The components shown in FIGS. 5(a) and 5(b) are to be
understood as exemplary; the technique for using these components
as described are intended to apply to the multiplicity of wells
that can be drilled with acoustic telemetry methods wherein the
signal is launched and mainly travels along the walls of the drill
pipe.
[0063] While particular embodiments have been described in the
foregoing, it is to be understood that other embodiments are
possible and are intended to be included herein. It will be clear
to any person skilled in the art that modifications of and
adjustments to the foregoing embodiments, not shown, are
possible.
* * * * *