U.S. patent application number 14/435987 was filed with the patent office on 2015-10-22 for apparatus and method for evaluating cement integrity in a wellbore using acoustic telemetry.
The applicant listed for this patent is Max DEFFENBAUGH, Mark M. DISKO, Stuart R. KELLER, Timothy I. MORROW, David A. STILES. Invention is credited to Max Deffenbaugh, Mark M. Disko, Stuart R. Keller, Timothy I. Morrow, David A. Stiles.
Application Number | 20150300159 14/435987 |
Document ID | / |
Family ID | 50979175 |
Filed Date | 2015-10-22 |
United States Patent
Application |
20150300159 |
Kind Code |
A1 |
Stiles; David A. ; et
al. |
October 22, 2015 |
Apparatus and Method for Evaluating Cement Integrity in a Wellbore
Using Acoustic Telemetry
Abstract
An electro-acoustic system for downhole telemetry employs a
series of communications nodes spaced along a string of casing
within a wellbore. In one embodiment the nodes are placed within
the cement sheath surrounding the joints of casing and allow
wireless communication between transceivers residing within the
communications nodes and a receiver at the surface. The
transceivers provide node-to-node communication up a wellbore at
high data transmission rates for data indicative of cement sheath
integrity. A method of evaluating a cement sheath in a wellbore
uses a plurality of data transmission nodes situated along the
casing string which send signals to a receiver at the surface. The
signals are then analyzed.
Inventors: |
Stiles; David A.; (Spring,
TX) ; Keller; Stuart R.; (Houston, TX) ;
Morrow; Timothy I.; (Humble, TX) ; Deffenbaugh;
Max; (Fulshear, TX) ; Disko; Mark M.; (Glen
Gardner, NJ) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
STILES; David A.
KELLER; Stuart R.
MORROW; Timothy I.
DISKO; Mark M.
DEFFENBAUGH; Max |
|
|
US
US
US
US
US |
|
|
Family ID: |
50979175 |
Appl. No.: |
14/435987 |
Filed: |
December 18, 2013 |
PCT Filed: |
December 18, 2013 |
PCT NO: |
PCT/US13/76278 |
371 Date: |
April 15, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61739681 |
Dec 19, 2012 |
|
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|
Current U.S.
Class: |
367/82 |
Current CPC
Class: |
E21B 47/017 20200501;
E21B 47/005 20200501; E21B 47/16 20130101 |
International
Class: |
E21B 47/16 20060101
E21B047/16; E21B 47/00 20060101 E21B047/00 |
Claims
1. An electro-acoustic telemetry system for evaluating a cement
sheath in a wellbore, comprising: a casing string disposed in a
wellbore, with a cement sheath residing within an annular region
formed between the casing string and a surrounding subsurface rock
matrix along the casing string; a topside communications node
placed proximate a surface of the wellbore; a plurality of
subsurface communications nodes spaced along the wellbore and
attached to an outer wall of the casing string, the subsurface
communications nodes configured to transmit acoustic waves from
node-to-node up the wellbore and to the topside communications
node, and with at least some of the subsurface communications nodes
being in contact with the cement sheath; and a receiver at the
surface configured to receive signals from the topside
communications node; wherein each of the subsurface communications
nodes comprises: a sealed housing; an electro-acoustic transducer
and associated transceiver also residing within the housing, with
the transceiver being designed to relay signals from node-to-node
up the wellbore, with each signal representing a packet of
information that comprises an identifier for the subsurface
communications node that originally transmitted the signal, and an
acoustic waveform having an amplitude; and an independent power
source residing within the housing providing power to the
transceiver.
2. The electro-acoustic telemetry system of claim 1, wherein the
subsurface communications nodes are spaced apart such that each
joint of pipe supports at least one subsurface communications
node.
3. The electro-acoustic telemetry system of claim 1, wherein the
subsurface communications nodes are spaced at about 20 to 40 foot
(6.1 to 12.2 meter) intervals.
4. The electro-acoustic telemetry system of claim 1, wherein the
subsurface communications nodes transmit data in acoustic form at a
rate exceeding about 50 bps.
5. The electro-acoustic telemetry system of claim 1, wherein each
of the electro-acoustic transceivers is designed to receive
acoustic waves at a first frequency, and then transmit the acoustic
waves at a second different frequency up the wellbore to a next
subsurface communications node.
6. The electro-acoustic system of claim 1, further comprising: one
or more sensors placed along the wellbore, the sensors being any of
strain gauges, temperature sensors, microphones, or combinations
thereof; and wherein the subsurface communications nodes are
configured to receive and relay acoustic signals indicative of
readings taken by the sensors up to the surface.
7. The electro-acoustic system of claim 6, wherein: the one or more
sensors reside within the housings of selected subsurface
communications nodes; and the electro-acoustic transducers within
the selected subsurface communications nodes convert signals from
the sensors into acoustic signals for the associated
transceivers.
8. The electro-acoustic system of claim 6, wherein a frequency band
for the acoustic wave transmission by the transceivers is about 25
KHz wide.
9. The electro-acoustic system of claim 6, wherein a frequency band
for the acoustic wave transmission by the transceivers operates
from about 100 kHz to 125 kHz.
10. The electro-acoustic telemetry system of claim 6, wherein the
acoustic waves provide data that is modulated by (i) a multiple
frequency shift keying method, (ii) a frequency shift keying
method, (iii) a multi-frequency signaling method, (iv) a phase
shift keying method, (v) a pulse position modulation method, or
(vi) an on-off keying method.
11. The electro-acoustic telemetry system of claim 6, wherein each
subsurface communications node listens for the acoustic waves
generated at the first frequency for a longer time than the time
for which the acoustic waves were generated at the second frequency
by a previous subsurface communications node.
12. The electro-acoustic telemetry system of claim 1, wherein: a
well head is placed above the wellbore; and the topside
communications node is placed (i) on an outer surface of the well
head, (ii) on an outer surface of a tubular body that is downstream
of the wellhead, or (iii) on the outer surface of an uppermost
joint of the casing string.
13. The electro-acoustic telemetry system of claim 12, wherein the
signal from the topside communications node to the receiver is
transmitted via a Class I, Division I conduit or a wireless
transmission.
14. The electro-acoustic telemetry system of claim 1, wherein the
subsurface communications nodes are attached to the outer wall of
the casing string by (i) an adhesive material, (ii) welding, or
(iii) one or more mechanical fasteners.
15. The electro-acoustic telemetry system of claim 1, wherein: each
of the subsurface communications nodes is attached to the casing
string by one or more clamps; and each of the one or more clamps
comprises: a first arcuate section; a second arcuate section; a
hinge for pivotally connecting the first and second arcuate
sections; and a fastening mechanism for securing the first and
second arcuate sections around an outer surface of the casing
string.
16. The electro-acoustic telemetry system of claim 1, wherein: the
receiver comprises a processor; and the processor is programmed to
identify amplitude values generated by each subsurface
communications node and compare those amplitude values to a
baseline amplitude value.
17. The electro-acoustic telemetry system of claim 16, wherein the
baseline amplitude value is (i) a previously stored amplitude value
indicative of an amplitude value of a joint of casing having a
continuous annular cement sheath, or (ii) a moving average of
amplitude readings taken from a pre-designated number of
communications nodes in proximity to a subject communications
node.
18. The electro-acoustic telemetry system of claim 16, wherein:
selected communications nodes further comprise a temperature
sensor, with those selected communications nodes being designed to
generate a signal that corresponds to temperature readings taken by
the respective temperature sensors; and the transceivers transmit
acoustic signals up the wellbore representative of the temperature
readings, node-to-node, as part of the packets of information.
19. The electro-acoustic telemetry system of claim 18, wherein the
processor is further programmed to identify temperature values
generated by the selected subsurface communications node and
compare those temperature values to a baseline temperature
value.
20. The electro-acoustic telemetry system of claim 19, wherein the
baseline temperature value is (i) a previously stored temperature
value indicative of a temperature value of a joint of casing having
a freshly-cemented annular region, or (ii) is a moving average of
temperature readings taken from a pre-designated number of
communications nodes in proximity to a subject communications
node.
21. The electro-acoustic telemetry system of claim 16, wherein:
selected communications nodes further comprise a strain gauge, with
those selected communications nodes being designed to generate a
signal that corresponds to strain readings taken by the respective
strain gauges; and the electro-acoustic transceivers transmit
acoustic signals up the wellbore representative of the strain
readings, node-to-node, as part of the packets of information.
22. The electro-acoustic telemetry system of claim 16, wherein:
selected communications nodes further comprise a passive acoustic
sensor, with those selected communications nodes being designed to
generate a signal that corresponds to ambient noise readings taken
by the respective temperature sensors; and the electro-acoustic
transceivers transmit acoustic signals up the wellbore
representative of the noise readings, node-to-node, as part of the
packets of information.
23. A method of detecting the integrity of a cement sheath along a
wellbore, comprising: running joints of casing into the wellbore,
the joints of casing being connected by threaded couplings to form
a casing string; attaching a series of communications nodes to the
joints of casing according to a pre-designated spacing, wherein
adjacent communications nodes are configured to communicate by
acoustic signals transmitted through the joints of casing, and
wherein each of the communications nodes comprises: a sealed
housing; an electro-acoustic transducer and associated transceiver
residing within the housing configured to relay signals, with each
signal representing a packet of information that comprises an
identifier for the subsurface communications node originally
transmitting the signal, and an acoustic waveform; and an
independent power source also residing within the housing for
providing power to the transceiver; placing a cement sheath within
an annular region formed between the casing string and a
surrounding subsurface matrix substantially along the wellbore;
sending signals from the communications nodes to a receiver at a
surface via the series of communications nodes; and analyzing the
signals to evaluate the integrity of the cement sheath proximate
each of the communications nodes.
24. The method of claim 23, wherein the surface is an earth
surface, or a drilling or production platform over a water
surface.
25. The method of claim 20, wherein the housing for each of the
intermediate communications nodes is fabricated from a steel
material, with the steel material of the housing having a resonance
frequency within a width of the resonance frequency of the acoustic
waveforms transmitted through the joints of casing.
26. The method of claim 23, wherein: the series of communications
nodes comprises a topside communications node residing proximate
the surface, and a series of subsurface communications nodes along
the wellbore below the topside communications nodes; and the
topside communications node transmits the signals from an uppermost
subsurface communications node to the receiver.
27. The method of claim 26, wherein: a well head is placed above
the wellbore; and the topside communications node is clamped (i) on
an outer surface of the well head, or (ii) on the outer surface of
an uppermost joint of the casing string.
28. The method of claim 27, wherein the topside communications node
is in electrical communication with the receiver by means of a
Class I, Division I conduit or a wireless transmission.
29. The method of claim 26, wherein each of the subsurface
communications nodes is attached to an outer wall of a joint of
casing by (i) an adhesive material, (ii) welding, or (iii) one or
more mechanical fasteners.
30. The method of claim 26, wherein: each of the subsurface
communications nodes is attached to a joint of casing by one or
more clamps; and the step of attaching the communications nodes to
the joints of casing comprises clamping the communications nodes to
an outer surface of the joints of casing.
31. The method of claim 30, wherein: the housing of each of the
subsurface communications nodes comprises a first end and a second
opposite end; and each of the one or more clamps comprises a first
clamp secured at the first end of the housing, and a second clamp
secured at the second end of the housing.
32. The method of claim 23, wherein the subsurface communications
nodes are spaced apart such that each joint of casing supports at
least one subsurface communications node.
33. The method of claim 23, wherein the subsurface communications
nodes are spaced at about 20 to 40 foot (6.1 to 12.2 meter)
intervals.
34. The method of claim 23, wherein the subsurface communications
nodes transmit data representing the waveforms at a rate exceeding
about 50 bps.
35. The method of claim 23, wherein analyzing the signals to
evaluate the integrity of the cement sheath comprises: identifying
amplitude values generated by each of the subsurface communications
nodes; and comparing those amplitude values to a baseline amplitude
value.
36. The method of claim 35, wherein the baseline amplitude value is
(i) a previously stored amplitude value indicative of an amplitude
value of a joint of casing having a continuous annular cement
sheath, or (ii) a moving average of amplitude readings taken from a
pre-designated number of communications nodes in proximity to a
subject communications node.
37. The method of claim 36, wherein: each of the subsurface
communications nodes further comprises a temperature sensor, and is
designed to generate a signal that corresponds to temperature
readings taken by the temperature sensor; and the electro-acoustic
transceivers in the subsurface communications nodes also transmit
acoustic signals up the wellbore representative of the temperature
readings, node-to-node.
38. The method of claim 35, wherein analyzing the signals to
determine the integrity of the cement sheath further comprises:
identifying temperature values generated by each of the subsurface
communications nodes; and comparing those temperature values to a
baseline temperature value.
39. The method of claim 38, wherein the baseline temperature value
is (i) a previously stored temperature value indicative of a
temperature value of a joint of casing having a freshly-cemented
annular region, or (ii) a moving average of temperature readings
taken from a pre-designated number of communications nodes in
proximity to a subject communications node in the wellbore.
40. The method of claim 23, wherein: selected communications nodes
further comprise a strain gauge, with those selected communications
nodes being designed to generate a signal that corresponds to
strain readings taken by the respective strain gauges; and the
electro-acoustic transceivers transmit acoustic signals up the
wellbore representative of the strain readings, node-to-node, as
part of the packets of information.
41. The method of claim 23, wherein: selected communications nodes
further comprise a passive acoustic sensor, with those selected
communications nodes being designed to generate a signal that
corresponds to ambient noise readings taken by the respective
temperature sensors; and the electro-acoustic transceivers transmit
acoustic signals up the wellbore representative of the noise
readings, node-to-node, as part of the packets of information.
42. The method of claim 23, wherein a frequency band for the
acoustic wave transmission by the transceivers is about 25 KHz
wide.
43. The method of claim 23, wherein a frequency band for the
acoustic wave transmission by the transceivers operates from about
100 kHz to 125 kHz.
44. The method of claim 23, wherein the acoustic waves provide data
that is modulated by (i) a multiple frequency shift keying method,
(ii) a frequency shift keying method, (iii) a multi-frequency
signaling method, (iv) a phase shift keying method, (v) a pulse
position modulation method, or (vi) an on-off keying method.
45. The method of claim 23, further comprising: identifying a
subsurface communications node sending signals indicative of poor
cement integrity within the surrounding cement sheath.
46. The method of claim 23, further comprising: perforating the
joint of casing supporting that subsurface communications node; and
squeezing cement through the perforated joint of casing and into
the annular region around the casing string.
47. The method of claim 23, wherein analyzing the signals to
evaluate the integrity of the cement sheath further comprises
comparing the attenuation of acoustic signals between pairs of
subsurface communications nodes.
48. The method of claim 47, wherein analyzing the signals to
evaluate the integrity of the cement sheath further comprises
comparing the attenuation of acoustic signals with cement bond-log
data.
49. A method of detecting the integrity of a cement sheath in an
annular region along a wellbore, comprising: receiving signals from
a wellbore, each signal defining a packet of information having (i)
an identifier for a subsurface communications node originally
transmitting the signal, and (ii) an acoustic amplitude value for
the subsurface communications node originally transmitting the
signal; correlating subsurface communications nodes to their
respective locations in the wellbore; and analyzing the amplitude
values to determine whether any of such amplitude values are
indicative of a poor cement sheath along the wellbore.
50. The method of claim 49, wherein: the annular region resides
between a casing string and a surrounding subsurface rock matrix;
and each of the subsurface communications nodes is attached to an
outer wall of the casing string according to a pre-designated
spacing, and resides within the annular region.
51. The method of claim 50, wherein: the subsurface communications
nodes are configured to communicate by acoustic signals transmitted
through the casing string, and each of the communications nodes
comprises: a sealed housing; an electro-acoustic transducer and
associated transceiver residing within the housing; and an
independent power source also residing within the housing for
providing power to the transceiver.
52. The method of claim 51, wherein analyzing the amplitude values
comprises: identifying amplitude values generated by each of the
subsurface communications nodes; and comparing those amplitude
values to a baseline amplitude value.
53. The method of claim 52, wherein the baseline amplitude value is
(i) a previously stored amplitude value indicative of an amplitude
value of a joint of casing having a continuous annular cement
sheath, or (ii) a moving average of amplitude readings taken from a
pre-designated number of communications nodes in proximity to a
subject communications node.
54. The method of claim 52, wherein: selected subsurface
communications nodes further comprises a temperature sensor, and
are designed to generate a signal that corresponds to temperature
readings taken by the temperature sensor; the electro-acoustic
transceivers in the subsurface communications nodes transmit
acoustic signals up the wellbore representative of the temperature
readings, node-to-node; the packet of information generated by each
subsurface communications node further has (iii) an acoustic
waveform indicative of a temperature reading; and the method
further comprises analyzing the temperature readings to determine
whether any of such temperature readings are indicative of a poor
cement sheath along the wellbore.
55. The method of claim 54, wherein analyzing the temperature
readings comprises: identifying temperature values generated by
each of the subsurface communications nodes; and comparing those
temperature values to a baseline temperature value.
56. The method of claim 55, wherein the baseline temperature value
is (i) a previously stored temperature value indicative of a
temperature value of a joint of casing having a freshly-cemented
annular region, or (ii) a moving average of temperature readings
taken from a pre-designated number of communications nodes in
proximity to a subject communications node in the wellbore.
57. The method of claim 52, wherein: at least some of the
subsurface communications nodes further comprises a passive
acoustic sensor, and generate a signal that corresponds to ambient
noise readings taken by the passive acoustic sensors; the
electro-acoustic transceivers in the subsurface communications
nodes transmit acoustic signals up the wellbore representative of
the ambient noise readings, node-to-node; the packet of information
generated by the subsurface communications nodes further has (iii)
an acoustic waveform indicative of the ambient noise readings; and
the method further comprises analyzing the ambient noise readings
to determine whether any of such ambient noise readings are
indicative of a poor cement sheath along the wellbore.
58. The method of claim 52, wherein: at least some of the
subsurface communications nodes further comprises a strain gauge,
and generate a signal that corresponds to strain readings taken by
the strain gauges; the electro-acoustic transceivers in the
subsurface communications nodes transmit acoustic signals up the
wellbore representative of the strain readings, node-to-node; the
packet of information generated by the subsurface communications
nodes further has (iii) an acoustic waveform indicative of the
strain readings; and the method further comprises analyzing the
strain readings to determine whether any of such strain readings
are indicative of a poor cement sheath along the wellbore.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Patent Application No. 61/739,681, filed Dec. 19, 2012, the
disclosure of which is hereby incorporated by reference.
BACKGROUND OF THE INVENTION
[0002] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present disclosure. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present disclosure. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
FIELD OF THE INVENTION
[0003] The present invention relates to the field of well drilling
and completions. More specifically, the invention relates to the
transmission of data along a tubular body within a wellbore. The
present invention further relates to the evaluation of cement
integrity behind a casing string using acoustic signals.
GENERAL DISCUSSION OF TECHNOLOGY
[0004] In the drilling of oil and gas wells, a wellbore is formed
using a drill bit that is urged downwardly at a lower end of a
drill string. The drill bit is rotated while force is applied
through the drill string and against the rock face of the formation
being drilled. After drilling to a predetermined depth, the drill
string and bit are removed and the wellbore is lined with a string
of casing. An annular area is thus formed between the string of
casing and the formation penetrated by the wellbore.
[0005] A cementing operation is typically conducted in order to
displace drilling fluid and fill part or all of the
hollow-cylindrical annular area between the casing and the borehole
wall with cement. The combination of cement and casing strengthens
the wellbore and facilitates the zonal fluid isolation of certain
sections of a hydrocarbon-producing formation (or "pay zones")
behind the casing.
[0006] A first string of casing is placed from the surface and down
to a first drilled depth. This casing is known as a surface casing.
In the case of offshore operations, this casing may be referred to
as a conductor pipe. Typically, one of the main functions of the
initial string(s) of casing is to isolate and protect the
shallower, useable water bearing aquifers from contamination by any
other wellbore fluids. Accordingly, these casing strings are almost
always cemented entirely back to surface.
[0007] One or more intermediate strings of casing is also run into
the wellbore. These casing strings will have progressively smaller
outer diameters into the wellbore. In most current wellbore
completion jobs, especially those involving so called
unconventional formations where high-pressure hydraulic operations
are conducted downhole, these casing strings may be entirely
cemented. In some instances, an intermediate casing string may be a
liner, that is, a string of casing that is not tied back to the
surface.
[0008] The process of drilling and then cementing progressively
smaller strings of casing is repeated several times until the well
has reached total depth. In some instances, the final string of
casing is also a liner. The final string of casing, referred to as
a production casing, is also typically cemented into place.
[0009] Additional tubular bodies may be included in a well
completion. These include one or more strings of production tubing
placed within the production casing or liner. Each tubing string
extends from the surface to a designated depth proximate a
production interval, or "pay zone." Each tubing string may be
attached to a packer. The packer serves to seal off the annular
space between the production tubing string(s) and the surrounding
casing.
[0010] It is important that the cement sheath surrounding the
casing strings have a high degree of circumferential and axial
integrity around the casing annulus against fluid channeling or
flowing through the cement along the wellbore. The cement must also
bond with the casing surface and borehole wall to affect a
hydraulic seal against fluid migration along the wellbore. This
means that the cement is fully placed into the annular region to
prevent fluid communication between fluids at the level of
subsurface completion and aquifers residing just below the surface.
Such fluids may include fracturing fluids, aqueous acid, and
formation fluids.
[0011] Heretofore, the integrity of a cement sheath has been
determined through the use of a so-called cement bond long. A
cement bond log (or CBL), uses an acoustic signal that is
transmitted by a logging tool at the end of a wireline. The logging
tool includes a transmitter, and then a receiver that "listens" for
sound waves generated by the transmitter through the surrounding
case strings. The logging tool includes a signal processor that
takes a continuous measurement of the amplitude of sound pulses
from the transmitter to the receiver.
[0012] The theory behind the CBL is that the amplitude of a sonic
signal as it travels through a well cemented pipe is only a
fraction of the amplitude through uncemented pipe. Acoustic signals
in free steel casing generally provide a large amplitude because
the acoustic energy remains in the steel. However, for casing that
is surrounded by and well bonded with cement, the amplitude is
small because the acoustic energy is dispersed not only in the
steel but also into the coupled cement and formation. Bond logs may
also measure acoustic impedance of the cement or other material in
the annulus behind the casing by resonant frequency decay.
[0013] Cement bond logs are typically conducted using an acoustic
logging tool that is pulled through the wellbore using a wireline.
This is done after a casing string has been cemented in placed
within the wellbore. However, it is desirable to be able to
evaluate the integrity of the cement sheath behind the casing
string immediately after the cementing operation has been conducted
and without need for a wireline or separate logging tool. Further,
it is desirable to determine the progress of cement placement
during the cementing operation using a series of communications
nodes placed along the casing string as part of the well
completion. Still further, a need exists for an acoustic telemetry
system that enables the operator to receive signals at high data
transmission rates, with such signals being indicative of cement
sheath integrity, both at the time of cementing and later in the
life of the well.
SUMMARY OF THE INVENTION
[0014] An electro-acoustic system for downhole telemetry is
provided herein. The system employs a series of communications
nodes spaced along a wellbore. Each node transmits a signal that
represents a packet of information. The packet of information
includes both a node identifier and an acoustic wave. The signals
are relayed up the wellbore from node-to-node in order to provide a
wireless signal to a receiver at the surface.
[0015] The system first includes a string of casing. The casing
string is disposed in the wellbore. In actuality, the wellbore may
have more than one casing string, including a string of surface
casing, one or more intermediate casing strings, and a production
casing. In any aspect, the wellbore is completed for the purpose of
conducting hydrocarbon recovery operations. A cement sheath resides
within an annular region formed between the casing string and a
surrounding subsurface rock matrix. The cement sheath extends
substantially along the exterior of the casing string.
[0016] The system further has a topside communications node. The
topside communications node may be placed along the casing string
proximate to surface. The surface may be an earth surface.
Alternatively, in a subsea context, the surface may be an offshore
platform or vessel at or below a water level. In another
embodiment, the topside communications node is connected to the
wellhead.
[0017] The system further includes a plurality of subsurface
communications nodes. The subsurface communications nodes are
attached to an outer wall of the casing string in spaced-apart
relation. In one aspect, the communications nodes are spaced at
between about 20 and 40 foot (6.1 to 12.2 meter) intervals.
Preferably, each joint of pipe making up the casing string receives
one node. The communications nodes are configured to transmit
acoustic waves from node-to-node, up to the topside communications
node.
[0018] Each of the subsurface communications nodes has a sealed
housing. In addition, each node relies upon an independent power
source. The power source may be, for example, batteries or a fuel
cell. The power source resides within the housing.
[0019] In addition, each of the subsurface communications nodes has
an electro-acoustic transducer. In one aspect, the communications
nodes transmit data as mechanical waves at a rate exceeding about
50 bps. In one aspect, the electro-acoustic transducer is
associated with a transceiver designed to receive acoustic waves at
a first frequency, and then transmit or relay the acoustic waves at
a second different frequency. Multiple frequency shift keying
(MFSK) may be used as a modulation scheme enabling the transmission
of information.
[0020] The system also includes a receiver. The receiver is
positioned at the surface and is configured to receive signals from
the topside communications node. The signals originate with the
various subsurface communications nodes. In one aspect, the
receiver is in electrical communication with the topside
communications node by means of an electrical wire or through a
wireless data transmission such as Wi-Fi or Blue Tooth. The
receiver is configured to process the signals to identify any
sections of casing that are not adequately cemented.
[0021] A method of detecting the integrity of a cement sheath along
a wellbore is also provided herein. The method uses a plurality of
data transmission nodes situated along a casing string to
accomplish a wireless transmission of data along the wellbore. The
data represents signals that indicate the presence of a cement
sheath both adjacent to and between the respective communications
nodes.
[0022] The method first includes running joints of pipe into the
wellbore. The joints of pipe are connected together at threaded
couplings. The joints of pipe are fabricated from a steel material
and have a resonant frequency.
[0023] The method also provides for attaching a series of
communications nodes to the joints of pipe according to a
pre-designated spacing. In one aspect, each joint of pipe receives
at least one communications node. Preferably, each of the
communications nodes is attached to a joint of pipe by one or more
clamps. In this instance, the step of attaching the communications
nodes to the joints of pipe comprises clamping the communications
nodes to an outer surface of the joints of pipe.
[0024] The series of communications nodes includes a topside
communications node. This is the uppermost communications node
along the wellbore. More specifically, the topside communications
node is attached to the tubular body proximate the surface.
Alternatively, the topside communications node is connected to the
well head or to a tubular body immediately downstream from the
wellhead. The topside communications node transmits signals from an
uppermost subsurface communications node to the surface.
[0025] The communications nodes also include a series of subsurface
communications nodes residing below the topside communications
nodes. The subsurface communications nodes reside in spaced-apart
relation along the casing string. The subsurface communications
nodes are configured to transmit acoustic waves up to the topside
communications node. Each subsurface communications node includes
an electro-acoustic transducer and associated transceiver that
receives an acoustic signal from a previous communications node,
and then transmits or relays that acoustic signal to a next
communications node, in node-to-node arrangement. In one aspect,
the communications nodes transmit data as mechanical waves at a
rate exceeding about 50 bps.
[0026] In one embodiment, one or more of the subsurface
communications nodes includes a temperature sensor. The
communications nodes are then designed to generate a signal that
corresponds to temperature readings sensed by the respective
temperature sensors. The electro-acoustic transceivers in the
subsurface communications nodes then transmit acoustic signals up
the wellbore representative of the temperature readings,
node-to-node.
[0027] In another embodiment, selected subsurface communications
nodes include a strain gauge. Alternatively or in addition,
selected subsurface communications nodes include passive acoustic
sensors, or microphones. Signals from the strain gauges or the
microphones are sent to the surface via the subsurface
communications nodes.
[0028] The method next includes providing a receiver. The receiver
is placed at the surface. The receiver has a processor that
processes signals received from the topside communications node,
such as through the use of firmware and/or software. The receiver
preferably receives electrical or optical signals via a so-called
"Class I, Division I" conduit, meaning a conduit (as defined by
NFPA 497 and API 500) for operation in an electrically classified
area. Alternatively, data may be transferred from the topside
communications node to the receiver via an electromagnetic (RF)
wireless connection. The processor processes the signals to
identify which signals correlate to which subsurface communications
node.
[0029] The method also includes analyzing the signals to evaluate
the integrity of the cement sheath in proximity to each of the
communications nodes. Analyzing the signals will allow the operator
to infer the quality of the cement sheath at and in between the
nodes. If it is determined that cement has not been properly placed
around the casing string adjacent one of the communications nodes,
then appropriate decisions on subsequent drilling, completing,
operating or abandonment the well can be undertaken.
BRIEF DESCRIPTION OF THE DRAWINGS
[0030] So that the present inventions can be better understood,
certain drawings, charts, graphs and/or flow charts are appended
hereto. It is to be noted, however, that the drawings illustrate
only selected embodiments of the inventions and are therefore not
to be considered limiting of scope, for the inventions may admit to
other equally effective embodiments and applications.
[0031] FIG. 1 is a side, cross-sectional view of an illustrative
wellbore. The wellbore is being formed using a derrick, a drill
string and a bottom hole assembly. A series of communications nodes
is placed along the drill string as part of a telemetry system.
[0032] FIG. 2 is a cross-sectional view of a wellbore having been
completed. The illustrative wellbore has been completed as a cased
hole completion. A series of communications nodes is placed along
the casing string as part of a telemetry system.
[0033] FIG. 3 is a perspective view of an illustrative tubular pipe
joint as may be positioned in a wellbore. A communications node of
the present invention, in one embodiment, is shown exploded away
from the pipe joint.
[0034] FIG. 4A is a perspective view of a communications node as
may be used in the wireless data transmission system of the present
invention, in an alternate embodiment.
[0035] FIG. 4B is a cross-sectional view of the communications node
of FIG. 4A. The view is taken along the longitudinal axis of the
node. Here, a sensor is provided within the communications
node.
[0036] FIG. 4C is another cross-sectional view of the
communications node of FIG. 4A. The view is again taken along the
longitudinal axis of the node. Here, a sensor resides along the
wellbore external to the communications node.
[0037] FIGS. 5A and 5B are perspective views of a shoe as may be
used on opposing ends of the communications node of FIG. 4A, in one
embodiment. In FIG. 5A, the leading edge, or front, of the shoe is
seen. In FIG. 5B, the back of the shoe is seen.
[0038] FIG. 6 is a perspective view of a communications node system
as may be used in the methods of the present invention, in one
embodiment. The communications node system utilizes a pair of
clamps for connecting a subsurface communications node onto a
tubular body.
[0039] FIG. 7 is a flowchart demonstrating steps of a method for
detecting the integrity of a cement sheath along a wellbore in
accordance with the present inventions, in one embodiment.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
[0040] As used herein, the term "hydrocarbon" refers to an organic
compound that includes primarily, if not exclusively, the elements
hydrogen and carbon. Examples of hydrocarbons include any form of
natural gas, oil, coal, and bitumen that can be used as a fuel or
upgraded into a fuel.
[0041] As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids.
For example, hydrocarbon fluids may include a hydrocarbon or
mixtures of hydrocarbons that are gases or liquids at formation
conditions, at processing conditions, or at ambient conditions
(about 20.degree. C. and 1 atm pressure). Hydrocarbon fluids may
include, for example, oil, natural gas, gas condensates, coal bed
methane, shale oil, pyrolysis oil, and other hydrocarbons that are
in a gaseous or liquid state.
[0042] As used herein, the term "subsurface" refers to the region
below the earth's surface.
[0043] As used herein, the term "sensor" includes any electrical
sensing device or gauge. The sensor may be capable of monitoring or
detecting pressure, temperature, fluid flow, vibration, or
resistivity or other formation data.
[0044] As used herein, the term "formation" refers to any definable
subsurface region. The formation may contain one or more
hydrocarbon-containing layers, one or more non-hydrocarbon
containing layers, an overburden, and/or an underburden of any
geologic formation.
[0045] The terms "zone" or "zone of interest" refer to a portion of
a formation containing hydrocarbons. The term "hydrocarbon-bearing
formation" may alternatively be used. Zones of interest may also
include formations containing brines or useable water which are to
be isolated.
[0046] As used herein, the term "wellbore" refers to a hole in the
subsurface made by drilling or insertion of a conduit into the
subsurface. A wellbore may have a substantially circular cross
section, or other cross-sectional shape. As used herein, the term
"well," when referring to an opening in the formation, may be used
interchangeably with the term "wellbore."
[0047] The terms "tubular member" or "tubular body" refer to any
pipe, such as a joint or string of casing, a joint or string of a
liner pipe, a joint or string of drill pipe, a production tubing
joint or string, an injection tubing joint or string, or any other
tubular tool associated with use in a wellbore.
DESCRIPTION OF SELECTED SPECIFIC EMBODIMENTS
[0048] The inventions are described herein in connection with
certain specific embodiments. However, to the extent that the
following detailed description is specific to a particular
embodiment or a particular use, such is intended to be illustrative
only and is not to be construed as limiting the scope of the
inventions.
[0049] FIG. 1 is a side, cross-sectional view of an illustrative
well site 100. The well site 100 includes a derrick 120 at an earth
surface 101. The well site 100 also includes a wellbore 150
extending from the earth surface 101 and down into an earth
subsurface 155. The wellbore 150 is being formed using the derrick
120, a drill string 160 below the derrick 120, and a bottom hole
assembly 170 at a lower end of the drill string 160.
[0050] Referring first to the derrick 120, the derrick 120 includes
a frame structure 121 that extends up from the earth surface 101.
The derrick 120 supports drilling equipment including a traveling
block 122, a crown block 123 and a swivel 124. A so-called kelly
125 is attached to the swivel 124. The kelly 125 has a
longitudinally extending bore (not shown) in fluid communication
with a kelly hose 126. The kelly hose 126, also known as a mud
hose, is a flexible, steel-reinforced, high-pressure hose that
delivers drilling fluid through the bore of the kelly 125 and down
into the drill string 160.
[0051] The kelly 125 includes a drive section 127. The drive
section 127 is non-circular in cross-section and conforms to an
opening 128 longitudinally extending through a kelly drive bushing
129. The kelly drive bushing 129 is part of a rotary table. The
rotary table is a mechanically driven device that provides
clockwise (as viewed from above) rotational force to the kelly 125
and connected drill string 160 to facilitate the process of
drilling a borehole 105. Both linear and rotational movement may
thus be imparted from the kelly 125 to the drill string 160.
[0052] A platform 102 is provided for the derrick 120. The platform
102 extends above the earth surface 101. The platform 102 generally
supports rig hands along with various components of drilling
equipment such as a pumps, motors, gauges, a dope bucket, tongs,
pipe lifting equipment and control equipment. The platform 102 also
supports the rotary table.
[0053] It is understood that the platform 102 shown in FIG. 1 is
somewhat schematic. It is also understood that the platform 102 is
merely illustrative and that many designs for drilling rigs and
platforms, both for onshore and for offshore operations, exist.
These include, for example, top drive drilling systems. The claims
provided herein are not limited by the configuration and features
of the drilling rig unless expressly stated in the claims.
[0054] Placed below the platform 102 and the kelly drive section
127 but above the earth surface 101 is a blow-out preventer, or BOP
130. The BOP 130 is a large, specialized valve or set of valves
used to control pressures during the drilling of oil and gas wells.
Specifically, blowout preventers control the fluctuating pressures
emanating from subterranean formations during a drilling process.
The BOP 130 may include upper 132 and lower 134 rams used to
isolate flow on the back side of the drill string 160. Blowout
preventers 130 also prevent the pipe joints making up the drill
string 160 and the drilling fluid from being blown out of the
wellbore 150 in the event of a sudden pressure kick.
[0055] As shown in FIG. 1, the wellbore 150 is being formed down
into the subsurface formation 155. In addition, the wellbore 150 is
being shown as a deviated wellbore. Of course, this is merely
illustrative as the wellbore 150 may be a vertical well or even a
horizontal well, as shown later in FIG. 2.
[0056] In drilling the wellbore 150, a first string of casing 110
is placed down from the surface 101. This is known as surface
casing 110 or, in some instances (particularly offshore), conductor
pipe. The surface casing 110 is secured within the formation 155 by
a cement sheath 112. The cement sheath 112 resides within an
annular region 115 between the surface casing 110 and the
surrounding formation 155.
[0057] During the process of drilling and completing the wellbore
150, additional strings of casing (not shown) will be provided.
These may include intermediate casing strings and a final
production casing string. For an intermediate case string or the
final production casing, a liner may be employed, that is, a string
of casing that is not tied back to the surface 101.
[0058] As noted, the wellbore 150 is formed by using a bottom hole
assembly 170. The bottom-hole assembly 170 allows the operator to
control or "steer" the direction or orientation of the wellbore 150
as it is formed. In this instance, the bottom hole assembly 170 is
known as a rotary steerable drilling system, or RSS.
[0059] The bottom hole assembly 170 will include a drill bit 172.
The drill bit 172 may be turned by rotating the drill string 160
from the platform 102. Alternatively, the drill bit 172 may be
turned by using so-called mud motors 174. The mud motors 174 are
mechanically coupled to and turn the nearby drill bit 172. The mud
motors 174 are used with stabilizers or bent subs 176 to impart an
angular deviation to the drill bit 172. This, in turn, deviates the
well from its previous path in the desired azimuth and
inclination.
[0060] There are several advantages to directional drilling. These
primarily include the ability to complete a wellbore along a
substantially horizontal axis of a subsurface formation, thereby
exposing a greater formation face. These also include the ability
to penetrate into subsurface formations that are not located
directly below the wellhead. This is particularly beneficial where
an oil reservoir is located under an urban area or under a large
body of water. Another benefit of directional drilling is the
ability to group multiple wellheads on a single platform, such as
for offshore drilling. Finally, directional drilling enables
multiple laterals and/or sidetracks to be drilled from a single
wellbore in order to maximize reservoir exposure and recovery of
hydrocarbons.
[0061] As the wellbore 150 is being formed, the operator may wish
to evaluate the integrity of the cement sheath 112 placed around
the surface casing 110 (or other casing string). To do this, the
industry has relied upon so-called cement bond logs. As discussed
above, a cement bond log (or CBL), uses an acoustic signal that is
transmitted by a logging tool at the end of a wireline. The logging
tool includes a transmitter, and one or more receivers that
"listen" for sound waves generated by the transmitter through the
surrounding casing string. The logging tool includes a signal
processor that takes a continuous measurement of the amplitude of
sound pulses from the transmitter to the receiver. Alternately, the
attenuation of the sonic signal may be measured.
[0062] In some instances, a bond log will measure acoustic
impedance of the material in the annulus directly behind the
casing. This may be done through resonant frequency decay. Such
logs include, for example, the USIT log of Schlumberger (of Sugar
Land, Tex.) and the CAST-V log of Halliburton (of Houston,
Tex.).
[0063] It is desirable to implement a downhole telemetry system
that enables the operator to evaluate cement sheath integrity
without need of running a CBL line. This enables the operator to
check cement sheath integrity as soon as the cement has set in the
annular region 115 or as soon as the wellbore 150 is completed. To
do this, the well site 100 includes a plurality of communications
nodes 180, 182. The communications nodes 180, 182 are placed along
the outer surface of the surface casing 110 according to a
pre-designated spacing. The communications nodes then send acoustic
signals up the wellbore 150 in node-to-node arrangement.
[0064] Acoustic telemetry systems are known in the industry. U.S.
Pat. No. 5,924,499 entitled "Acoustic Data Link and Formation
Property Sensor for Downhole MWD System" teaches the use of
acoustic signals for "short hopping" a component along a drill
string. Signals are transmitted from the drill bit or from a
near-bit sub and across the mud motors. This may be done by sending
separate acoustic signals simultaneously--one that is sent through
the drill string, a second that is sent through the drilling mud,
and optionally, a third that is sent through the formation. These
signals are then processed to extract readable signals.
[0065] U.S. Pat. No. 6,912,177, entitled "Transmission of Data in
Boreholes," addresses the use of an acoustic transmitter that is as
part of a downhole tool. Here, the transmitter is provided adjacent
a downhole obstruction such as a shut-in valve along a drill stem
so that an electrical signal may be sent across the drill stem.
U.S. Pat. No. 6,899,178, entitled "Method and System for Wireless
Communications for Downhole Applications," describes the use of a
"wireless tool transceiver" that utilizes acoustic signaling. Here,
an acoustic transceiver is in a dedicated tubular body that is
integral with a gauge and/or sensor. This is described as part of a
well completion.
[0066] U.S. Pat. No. 4,314,365, entitled "Acoustic Transmitter and
Method to Produce Essentially Longitudinal, Acoustic Waves, teaches
a "portable, electrohydraulic, acoustic transmitter" that attaches
to an outer surface of a drill string. The transmitter is used to
send acoustic signals down a drill string to a downhole receiver.
When actuated, the downhole receiver activates a subsurface
"instrument package" which performs a desired "downhole
function."
[0067] None of these patents disclose an acoustic telemetry system
that enables an operator to receive signals at the surface that are
indicative of cement sheath integrity behind a casing string. In
contrast, the well site 100 of FIG. 1 presents a telemetry system
that utilizes a series of novel communications nodes 180, 182
placed along the casing 110. These nodes 180, 182 allow for the
high speed transmission of wireless signals based on the in situ
generation of acoustic waves. The waves represent wave forms that
may be processed and analyzed at the surface.
[0068] The nodes first include a topside communications node 182.
The topside communications node 182 is placed closest to the
surface 101. The topside communications node 182 is configured to
receive acoustic signals and convert them to electrical or optical
signals. The topside communications node 182 may be above grade or
below grade.
[0069] In addition, the nodes include a plurality of subsurface
communications nodes 180. The subsurface communications nodes 180
are configured to receive and then relay acoustic signals along the
length of the wellbore 150 up to the topside communications node
182.
[0070] In FIG. 1, the nodes 180, 182 are shown schematically.
However, FIG. 3 offers an enlarged perspective view of an
illustrative pipe joint 300, along with a communications node 350.
The illustrative communications node 350 is shown exploded away
from the pipe joint 300.
[0071] In FIG. 3, the pipe joint 300 is intended to represent a
joint of casing. However, the pipe joint 300 may be any other
tubular body such as a joint of tubing, drill pipe, pipeline, or
other jointed tubular conduit assembly. The illustrated pipe joint
300 has an elongated wall 310 defining an internal bore 315. The
bore 315 transmits drilling fluids such as an oil based mud, or
OBM, during a drilling operation. The bore 315 also receives a
string of tubing (such as production tubing or injection tubing,
not shown), once a wellbore is completed.
[0072] The illustrated pipe joint 300 has a box end 322 having
internal threads. In addition, the pipe joint 300 has a pin end 324
having external threads, such as via an integrated box end or with
an internally threaded collar connector. The threads may be of any
design. Tubing joints and casing joints have a slightly different
general end appearance than the illustrated drill pipe joint, but
these are also tubular bodies that may be equipped similar to the
illustrated drill pipe joint 300.
[0073] As noted, an illustrative communications node 350 is shown
exploded away from the pipe joint 300. The communications node 350
is designed to attach to the wall 410 of the pipe joint 300 at a
selected location. In one aspect, each pipe joint 300 will have a
communications node 350 between the box end 322 and the pin end
324. In one arrangement, the communications node 350 is placed
immediately adjacent the box end 322 or, alternatively, immediately
adjacent the pin end 324 of every joint of pipe. In another
arrangement, the communications node 350 is placed at a selected
location along every second or every third pipe joint 300 in a
drill string. In still another arrangement, at least some pipe
joints 300 receive two communications nodes 350.
[0074] The communications node 350 shown in FIG. 3 is designed to
be pre-welded onto the wall 310 of the pipe joint 300.
Alternatively, the communications node 350 may be glued using an
adhesive such as epoxy. However, it is preferred that the
communications node 350 be configured to be selectively attachable
to/detachable from a pipe joint 300 by mechanical means at a well
site. This may be done, for example, through the use of clamps.
Such a clamping system is shown at 600 in FIG. 6, described more
fully below. In any instance, the communications node 350 is an
independent wireless communications device that is designed to be
attached to an external surface of a well pipe.
[0075] There are benefits to the use of an externally-placed
communications node that uses acoustic waves. For example, such a
node will not decrease the effective inner diameter which would
interfere with passing subsequent assemblies or tubulars through
the internal bore 315 of the pipe joint 300. Further, installation
and mechanical attachment can be readily assessed and adjusted.
[0076] In FIG. 3, the communications node 350 includes an elongated
body 351. The body 351 supports one or more batteries, shown
schematically at 352. The body 351 also supports an
electro-acoustic transducer, shown schematically at 354. The
electro-acoustic transducer 354 is associated with a transceiver
that receives acoustic signals at a first frequency, converts the
received signals into a digital signal, converts the digital signal
back into an acoustic signal, and transmits the acoustic signal at
a second different frequency to a next communications node.
[0077] The communications node 350 is intended to represent the
communications nodes 180 of FIG. 1, in one embodiment. The
electro-acoustic transducer 354 in each node 180 allows signals to
be sent from node-to-node, up the wellbore 150, as acoustic waves.
The acoustic waves may be at a frequency of, for example, between
about 100 kHz and 125 kHz. A last subsurface communications node
180 transmits the signals to the topside node 182. Beneficially,
the subsurface communications nodes 180 do not require a wire or
cable to transmit data to the surface. Preferably, communication is
routed around nodes which are not functioning properly.
[0078] The well site 100 of FIG. 1 also shows a receiver 190. The
receiver 190 comprises a processor 192 that receives signals sent
from the topside communications node 182. The signals may be
received through a wire (not shown) such as a co-axial cable, a
fiber optic cable, a USB cable, or other electrical or optical
communications wire. Alternatively, the receiver 190 may receive
the final signals from the topside node 182 wirelessly through a
modem, a transceiver or other wireless communications link such as
Bluetooth or Wi-Fi. The receiver 190 preferably receives electrical
signals via a so-called Class I, Division I conduit, that is, a
housing for wiring that is considered acceptably safe in an
explosive environment. In some applications, radio, infrared or
microwave signals may be utilized.
[0079] The processor 192 may include discrete logic, any of various
integrated circuit logic types, or a microprocessor. In any event,
the processor 192 may be incorporated into a computer having a
screen. The computer may have a separate keyboard 194, as is
typical for a desk-top computer, or an integral keyboard as is
typical for a laptop or a personal digital assistant. In one
aspect, the processor 192 is part of a multi-purpose "smart phone"
having specific "apps" and wireless connectivity.
[0080] FIG. 1 demonstrates the use of a wireless data telemetry
system during a drilling operation. However, the wireless downhole
telemetry system may also be employed after a well is completed.
This enables the operator to confirm the viability of a cement
sheath after, for example, formation fracturing operations have
taken place.
[0081] FIG. 2 is a cross-sectional view of an illustrative well
site 200. The well site 200 includes a wellbore 250 that penetrates
into a subsurface formation 255. The wellbore 250 has been
completed as a cased-hole completion for producing hydrocarbon
fluids. The well site 200 also includes a well head 260. The well
head 260 is positioned at an earth surface 201 to control and
direct the flow of formation fluids from the subsurface formation
255 to the surface 201.
[0082] Referring first to the well head 260, the well head 260 may
be any arrangement of pipes or valves that receive reservoir fluids
at the top of the well. In the arrangement of FIG. 2, the well head
260 represents a so-called Christmas tree. A Christmas tree is
typically used when the subsurface formation 255 has enough in situ
pressure to drive production fluids from the formation 255, up the
wellbore 250, and to the surface 201. The illustrative well head
260 includes a top valve 262 and a bottom valve 264.
[0083] It is understood that rather than using a Christmas tree,
the well head 260 may alternatively include a motor (or prime
mover) at the surface 201 that drives a pump. The pump, in turn,
reciprocates a set of sucker rods and a connected positive
displacement pump (not shown) downhole. The pump may be, for
example, a rocking beam unit or a hydraulic piston pumping unit.
Alternatively still, the well head 260 may be configured to support
a string of production tubing having a downhole electric
submersible pump, a gas lift valve, or other means of artificial
lift (not shown). The present inventions are not limited by the
configuration of operating equipment at the surface unless
expressly noted in the claims.
[0084] Referring next to the wellbore 250, the wellbore 250 has
been completed with a series of pipe strings referred to as casing.
First, a string of surface casing 210 has been cemented into the
formation. Cement is shown in an annular bore 215 of the wellbore
250 around the casing 210. The cement is in the form of an annular
sheath 212. The surface casing 110 has an upper end in sealed
connection with the lower valve 264.
[0085] Next, at least one intermediate string of casing 220 is
cemented into the wellbore 250. The intermediate string of casing
220 is in sealed fluid communication with the upper master valve
262. A cement sheath 212 is again shown in a bore 215 of the
wellbore 250. The combination of the casing 210/220 and the cement
sheath 212 in the bore 215 strengthens the wellbore 250 and
facilitates the isolation of formations behind the casing
210/220.
[0086] It is understood that a wellbore 250 may, and typically
will, include more than one string of intermediate casing. In some
instances, an intermediate string of casing may be a liner.
[0087] Finally, a production string 230 is provided. The production
string 230 is hung from the intermediate casing string 230 using a
liner hanger 231. The production string 230 is a liner that is not
tied back to the surface 101. In the arrangement of FIG. 2, a
cement sheath 232 is provided around the liner 230.
[0088] The production liner 230 has a lower end 234 that extends to
an end 254 of the wellbore 250. For this reason, the wellbore 250
is said to be completed as a cased-hole well. Those of ordinary
skill in the art will understand that for production purposes, the
liner 230 may be perforated after cementing to create fluid
communication between a bore 235 of the liner 230 and the
surrounding rock matrix making up the subsurface formation 255. In
one aspect, the production string 230 is not a liner but is a
casing string that extends back to the surface.
[0089] As an alternative, end 254 of the wellbore 250 may include
joints of sand screen (not shown). The use of sand screens with
gravel packs allows for greater fluid communication between the
bore 235 of the liner 230 and the surrounding rock matrix while
still providing support for the wellbore 250. In this instance, the
wellbore 250 would include a slotted base pipe as part of the sand
screen joints. Of course, the sand screen joints would not be
cemented into place and would not include subsurface communications
nodes.
[0090] The wellbore 250 optionally also includes a string of
production tubing 240. The production tubing 240 extends from the
well head 260 down to the subsurface formation 255. In the
arrangement of FIG. 2, the production tubing 240 terminates
proximate an upper end of the subsurface formation 255. A
production packer 241 is provided at a lower end of the production
tubing 240 to seal off an annular region 245 between the tubing 240
and the surrounding production liner 230. However, the production
tubing 240 may extend closer to the end 234 of the liner 230.
[0091] In some completions a production tubing 240 is not employed.
This may occur, for example, when a monobore is in place.
[0092] It is also noted that the bottom end 234 of the production
string 230 is completed substantially horizontally within the
subsurface formation 255. This is a common orientation for wells
that are completed in so-called "tight" or "unconventional"
formations. Horizontal completions not only dramatically increase
exposure of the wellbore to the producing rock face, but also
enables the operator to create fractures that are substantially
transverse to the direction of the wellbore. Those of ordinary
skill in the art may understand that a rock matrix will generally
"part" in a direction that is perpendicular to the direction of
least principal stress. For deeper wells, that direction is
typically substantially vertical. However, the present inventions
have equal utility in vertically completed wells or in
multi-lateral deviated wells.
[0093] As with the well site 100 of FIG. 1, the well site 200 of
FIG. 2 includes a telemetry system that utilizes a series of novel
communications nodes. This again is for the purpose of evaluating
the integrity of the cement sheath 212, 232. The communications
nodes are placed along the outer diameter of the casing strings
210, 220, 230. These nodes allow for the high speed transmission of
wireless signals based on the in situ generation of acoustic
waves.
[0094] The nodes first include a topside communications node 282.
The topside communications node 282 is placed closest to the
surface 201. The topside node 282 is configured to receive acoustic
signals.
[0095] In addition, the nodes include a plurality of subsurface
communications nodes 280. Each of the subsurface communications
nodes 280 is configured to receive and then relay acoustic signals
along essentially the length of the wellbore 250. Preferably, the
subsurface communications nodes 280 utilize two-way
electro-acoustic transducers to receive and relay mechanical
waves.
[0096] The subsurface communications nodes 280 transmit signals as
acoustic waves. The acoustic waves are preferably at a frequency of
between about 50 kHz and 500 kHz. The signals are delivered up to
the topside communications node 282 so that signals indicative of
cement integrity are sent from node-to-node. A last subsurface
communications node 280 transmits the signals acoustically to the
topside communications node 282. Communication may be between
adjacent nodes or may skip nodes depending on node spacing or
communication range. Preferably, communication is routed around
nodes which are not functioning properly.
[0097] The well site 200 of FIG. 2 shows a receiver 270. The
receiver 270 comprises a processor 272 that receives signals sent
from the topside communications node 284. The processor 272 may
include discrete logic, any of various integrated circuit logic
types, or a microprocessor. The receiver 270 may include a screen
and a keyboard 274 (either as a keypad or as part of a touch
screen). The receiver 270 may also be an embedded controller with
neither a screen nor a keyboard which communicates with a remote
computer such as via wireless, cellular modem, or telephone
lines.
[0098] The signals may be received by the processor 272 through a
wire (not shown) such as a co-axial cable, a fiber optic cable, a
USB cable, or other electrical or optical communications wire.
Alternatively, the receiver 270 may receive the final signals from
the topside node 282 wirelessly through a modem or transceiver. The
receiver 270 preferably receives electrical signals via a so-called
Class I, Div. 1 conduit, that is, a wiring system or circuitry that
is considered acceptably safe in an explosive environment.
[0099] FIGS. 1 and 2 present illustrative wellbores 150, 250 that
may receive a downhole telemetry system using acoustic transducers.
In each of FIGS. 1 and 2, the top of the drawing page is intended
to be toward the surface and the bottom of the drawing page toward
the well bottom. While wells commonly are completed in
substantially vertical orientation, it is understood that wells may
also be inclined and even horizontally completed. When the
descriptive terms "up" and "down" or "upper" and "lower" or similar
terms are used in reference to a drawing, they are intended to
indicate location on the drawing page, and not necessarily
orientation in the ground, as the present inventions have utility
no matter how the wellbore is orientated.
[0100] In each of FIGS. 1 and 2, the communications nodes 180, 280
are specially designed to withstand the same corrosion and
environmental conditions (high temperature, high pressure) of a
wellbore 150 or 250 As the casing, drill string, or production
tubing. To do so, it is preferred that the communications nodes
180, 280 include steel housings for holding the electronics. In one
aspect, the steel material is a corrosion resistant alloy.
[0101] FIG. 4A is a perspective view of a communications node 400
as may be used in the wireless data transmission systems of FIG. 1
or FIG. 2 (or other wellbore), in one embodiment. The
communications node 400 is designed to provide data communication
using a transceiver within a novel downhole housing assembly. FIG.
4B is a cross-sectional view of the communications node 400 of FIG.
4A. The view is taken along the longitudinal axis of the node 400.
The communications node 400 will be discussed with reference to
FIGS. 4A and 4B, together.
[0102] The communications node 400 first includes a fluid-sealed
housing 410. The housing 410 is designed to be attached to an outer
wall of a joint of wellbore pipe, such as the pipe joint 300 of
FIG. 3. Where the wellbore pipe is a carbon steel pipe joint such
as drill pipe, casing or liner, the housing 410 is preferably
fabricated from carbon steel. This metallurgical match avoids
galvanic corrosion at the coupling.
[0103] The housing 410 includes an outer wall 412. The wall 412 is
dimensioned to protect internal electronics for the communications
node 400 from wellbore fluids and pressure. In one aspect, the wall
412 is about 0.2 inches (0.51 cm) in thickness. The housing 410
optionally also has a protective outer layer 425. The protective
outer layer 425 resides external to the wall 412 and provides an
additional thin layer of protection for the electronics.
[0104] A bore 405 is formed within the wall 412. The bore 405
houses the electronics, shown in FIG. 4B as a battery 430, a power
supply wire 435, a transceiver 440, and a circuit board 445. The
circuit board 445 will preferably include a micro-processor or
electronics module that processes acoustic signals. An
electro-acoustic transducer 442 is provided to convert acoustical
energy to electrical energy (or vice-versa) and is coupled with
outer wall 412 on the side attached to the tubular body. The
transducer 442 is in electrical communication with a sensor
432.
[0105] It is noted that in FIG. 4B, the sensor 432 resides within
the housing 410 of the communications node 400. However, as noted,
the sensor 432 may reside external to the communications node 400,
such as above or below the node 400 along the wellbore. In FIG. 4C,
a dashed line is provided showing an extended connection between
the sensor 432 and the electro-acoustic transducer 442.
[0106] The transceiver 440 will receive an acoustic telemetry
signal. In one preferred embodiment, the acoustic telemetry data
transfer is accomplished using multiple frequency shift keying
(MFSK). Any extraneous noise in the signal is moderated by using
well-known conventional analog and/or digital signal processing
methods. This noise removal and signal enhancement may involve
conveying the acoustic signal through a signal conditioning circuit
using, for example, a bandpass filter.
[0107] The transceiver will also produce acoustic telemetry
signals. In one preferred embodiment, an electrical signal is
delivered to an electromechanical transducer, such as through a
driver circuit. In a preferred embodiment, the transducer is the
same electro-acoustic transducer that originally received the MFSK
data. The signal generated by the electro-acoustic transducer then
passes through the housing 410 to the tubular body (such as
production tubing 240), and propagates along the tubular body to
other communication nodes. The re-transmitted signal represents the
same sensor data originally transmitted by sensor communications
node 284. In one aspect, the acoustic signal is generated and
received by a magnetostrictive transducer comprising a coil wrapped
around a core as the transceiver. In another aspect, the acoustic
signal is generated and received by a piezoelectric ceramic
transducer. In either case, the electrically encoded data are
transformed into a sonic wave that is carried through the wall of
the tubular body in the wellbore.
[0108] Each transceiver 440 is associated with a specific joint of
pipe. That joint of pipe, in turn, has a known location or depth
along the wellbore. The acoustic wave as originally transmitted
from the transceiver 440 will represent a packet of information.
The packet will include an identification code that tells a
receiver (such as receiver 270 in FIG. 2) where the signal
originated, that is, which communications node 400 it came from. In
addition, the packet will include an amplitude value originally
recorded by the communications node 400 for its associated joint of
pipe.
[0109] When the signal reaches the receiver at the surface, the
signal is processed. This involves identifying which communications
node the signal originated from, and then determining the location
of that communications node along the wellbore. This further
involves comparing the original amplitude value with a baseline
value. The baseline value represents an anticipated value for a
joint of casing having a fluid residing within its bore and a
continuous cement sheath along its outer surface.
[0110] If the measured amplitude value is at or below the baseline
amplitude value, then the operator can assume that a cement sheath
has been placed around the joint of pipe at issue. On the other
hand, if the measured amplitude value is above the baseline
amplitude value, then the operator should assume that a poor cement
sheath has been placed around the joint of pipe at issue. In that
instance, remedial steps may be taken. Where the wellbore is
presently undergoing a cementing operation, such steps may include
further injecting cement through a cement shoe and up the annular
region in the hopes of filling the annular region. More likely,
where the wellbore has been completed, such steps may include
placing perforations in the casing at the subject joint of pipe,
and then conducting a so-called "cement squeeze" in order to
isolate the joint of pipe and fill the annular region at the depth
of that joint of pipe. Alternatively, the operator may elect to
forego perforating casing at that depth or along a certain zone of
interest.
[0111] The communications node 400 optionally also includes one or
more sensors 432. The sensors 432 may be, for example, pressure
sensors, temperature sensors, or microphones. The sensor 432 sends
signals to the transceiver 440 through a short electrical wire 435
or through the printed circuit board 435. Signals from the sensor
432 are converted into acoustic signals using an electro-acoustic
transducer, that are then sent by the transceiver 440 as part of
the packet of information.
[0112] Preferably, the sensor 432 is a temperature sensor. The
packet of information will then include signals representative of
temperature readings taken by the temperature sensor. When the
signal reaches the receiver at the surface, the signal is compared
with a baseline value. The baseline value represents an anticipated
temperature for a joint of casing having a fresh column of cement
residing there around. Those of ordinary skill in the art of well
completions will understand that cement mix undergoes an exothermic
reaction which causes an increase in temperature.
[0113] If the measured temperature value is at or above the
baseline temperature value, then the operator can assume that a
cement sheath has been placed around the joint of pipe at issue. On
the other hand, if the measured temperature value is below the
baseline temperature value, then the operator should assume that a
poor cement sheath has been placed around the joint of pipe at
issue. Appropriate remedial steps may then be considered.
[0114] Additional methods of processing temperature data may be
used. For example, the receiver may collect temperature data from a
designated number of communications nodes that are in proximity to
the subject communications node. Temperature readings will then be
averaged to determine a moving average temperature value for a
section of casing. The measured temperature reading will then be
compared to the moving average temperature value to determine
cement integrity at the level of a particular joint of pipe.
[0115] Ideally, the operator will review a combination of amplitude
data and temperature data along the wellbore to confirm cement
sheath integrity. Strain data and passive acoustic data may also be
used to evaluate the integrity of the cement sheath.
[0116] The communications node 400 also optionally includes a shoe
500. More specifically, the node 400 includes a pair of shoes 500
disposed at opposing ends of the wall 412. Each of the shoes 500
provides a beveled face that helps prevent the node 400 from
hanging up on an external tubular body or the surrounding earth
formation, as the case may be, during run-in or pull-out. The shoes
500 may have a protective outer layer 422 and an optional
cushioning material 424 under the outer layer 422.
[0117] FIGS. 5A and 5B are perspective views of an illustrative
shoe 500 as may be used on an end of the communications node 400 of
FIG. 4A, in one embodiment. In FIG. 5A, the leading edge or front
of the shoe 500 is seen, while in FIG. 4B the back of the shoe 500
is seen.
[0118] The shoe 500 first includes a body 510. The body 510
includes a flat under-surface 512 that butts up against opposing
ends of the wall 412 of the communications node 400.
[0119] Extending from the under-surface 512 is a stem 520. The
illustrative stem 520 is circular in profile. The stem 520 is
dimensioned to be received within opposing recesses 414 of the wall
412 of the node 400.
[0120] Extending in an opposing direction from the body 510 is a
beveled surface 530. As noted, the beveled surface 530 is designed
to prevent the communications node 400 from hanging up on an object
during run-in into a wellbore.
[0121] Behind the beveled surface 530 is a flat (or slightly
arcuate) surface 535. The surface 535 is configured to extend along
the drill string 160 (or other tubular body) when the
communications node 400 is attached along the tubular body. In one
aspect, the shoe 500 includes an optional shoulder 515. The
shoulder 515 creates a clearance between the flat surface 535 and
the tubular body opposite the stem 520.
[0122] In one arrangement, the communications nodes 400 with the
shoes 500 are welded onto an outer surface of the tubular body,
such as wall 310 of the pipe joint 300. More specifically, the body
410 of the respective communications nodes 400 are welded onto the
wall of a joint of casing. In some cases, it may not be feasible or
desirable to pre-weld the communications nodes 400 onto pipe joints
before delivery to a well site. Further still, welding may degrade
the tubular integrity or damage electronics in the housing 410.
Therefore, it is desirable to utilize a clamping system that allows
a drilling or service company to mechanically connect/disconnect
the communications nodes 400 along a tubular body as the tubular
body is being run into a wellbore.
[0123] FIG. 6 is a perspective view of a communications node system
600 as may be used for methods of the present invention, in one
embodiment. The communications node system 600 utilizes a pair of
clamps 610 for mechanically connecting a communications node 400
onto a tubular body 630 such as a joint of casing or liner.
[0124] The system 600 first includes at least one clamp 610. In the
arrangement of FIG. 6, a pair of clamps 610 is used. Each clamp 610
abuts the shoulder 515 of a respective shoe 500. Further, each
clamp 610 receives the base 535 of a shoe 500. In this arrangement,
the base 535 of each shoe 500 is welded onto an outer surface of
the clamp 610. In this way, the clamps 610 and the communications
node 400 become an integral tool.
[0125] The illustrative clamps 610 of FIG. 6 include two arcuate
sections 612, 614. The two sections 612, 614 pivot relative to one
another by means of a hinge. Hinges are shown in phantom at 615. In
this way, the clamps 610 may be selectively opened and closed.
[0126] Each clamp 610 also includes a fastening mechanism 620. The
fastening mechanisms 620 may be any means used for mechanically
securing a ring onto a tubular body, such as a hook or a threaded
connector. In the arrangement of FIG. 6, the fastening mechanism is
a threaded bolt 625. The bolt 625 is received through a pair of
rings 622, 624. The first ring 622 resides at an end of the first
section 612 of the clamp 610, while the second ring 624 resides at
an end of the second section 614 of the clamp 610. The threaded
bolt 625 may be tightened by using, for example, one or more
washers (not shown) and threaded nuts 627.
[0127] In operation, a clamp 610 is placed onto the tubular body
630 by pivoting the first 612 and second 614 arcuate sections of
the clamp 610 into an open position. The first 612 and second 614
sections are then closed around the tubular body 630, and the bolt
625 is run through the first 622 and second 624 receiving rings.
The bolt 625 is then turned relative to the nut 627 in order to
tighten the clamp 610 and connected communications node 400 onto
the outer surface of the tubular body 630. Where two clamps 610 are
used, this process is repeated.
[0128] The tubular body 630 may be, for example, a casing string
such as the illustrative casing string 160 of FIG. 1.
Alternatively, the tubular body 630 may be a string of production
tubing such as the tubing 240 of FIG. 2. In any instance, the wall
412 of the communications node 400 is fabricated from a steel
material having a resonant frequency compatible with the resonant
frequency of the tubular body 630. Stated another way, the
mechanical resonance of the wall 412 is at a frequency contained
within the frequency band used for telemetry.
[0129] In one aspect, the communications node 400 is about 12 to 16
inches (0.30 to 0.41 meters) in length as it resides along the
tubular body 630. Specifically, the housing 410 of the
communications node may be 8 to 10 inches (0.20 to 0.25 meters) in
length, and each opposing shoe 500 may be 2 to 5 inches (0.05 to
0.13 meters) in length. Further, the communications node 400 may be
about 1 inch in width and inch in height. The base 410 of the
communications node 400 may have a concave profile that generally
matches the radius of the tubular body 630.
[0130] A method for transmitting date in a wellbore is also
provided herein. The method preferably employs the communications
node 400 and the communications node system 600 of FIG. 6.
[0131] FIG. 7 provides a flow chart for a method 700 of detecting
the integrity of a cement sheath along a wellbore. The method 700
uses a plurality of data transmission nodes situated along a casing
string to accomplish a wireless transmission of data along the
wellbore. The data represents signals that indicate the presence of
a cement sheath adjacent or in proximity to the respective
communications nodes.
[0132] The method 700 first includes running a tubular body into
the wellbore. This is shown at Box 710. The tubular body is formed
by connecting a series of pipe joints end-to-end, with the pipe
joints being connected by threaded couplings. The joints of pipe
are fabricated from a steel material suitable for conducting an
acoustic signal.
[0133] The method 700 also provides for attaching a series of
communications node to the joints of pipe. This is provided at Box
720. The communications nodes are attached according to a
pre-designated spacing. In one aspect, each joint of pipe receives
a communications node. Preferably, each of the subsurface
communications nodes is attached to a joint of pipe by one or more
clamps. In this instance, the step 720 of attaching the
communications nodes to the joints of pipe comprises clamping the
communications nodes to an outer surface of the joints of pipe.
Alternatively, an adhesive material or welding may be used for the
attaching step 720.
[0134] The method 700 further includes placing a cement sheath
around the tubular body. This is indicated at Box 730. The cement
sheath is placed within an annular region formed between the casing
joints and the surrounding subsurface rock matrix or previous
strings of casing. The cement sheath is placed in the annular
region using any known method of cementing casing into a wellbore.
Typically, cement is injected down the casing string behind a
bottom wiper plug and ahead of a top wiper plug, through a cement
shoe, and back up the annular region. In the method 700, the cement
sheath will ideally surround the externally placed communications
nodes in the annular region along areas where a cement sheath is
desired.
[0135] The communications nodes include a series of subsurface
communications nodes. The nodes reside along the casing string. The
communications nodes also include a topside communications node.
This is the uppermost communications node along the wellbore. The
topside communications node may be attached to the tubular body
proximate the surface. More preferably, the topside communications
node is connected to the well head. The topside communications node
transmits signals from an uppermost subsurface communications node
to a receiver at the surface.
[0136] The subsurface communications nodes are configured to
transmit acoustic waves up to the topside communications node. Each
subsurface communications node includes a transceiver that receives
an acoustic signal from a previous communications node, and then
transmits or relays that acoustic signal to a next communications
node, in node-to-node arrangement.
[0137] The method 700 also includes providing a receiver. This is
shown at Box 740. The receiver is placed at the surface. The
receiver has a processor that processes signals received from the
topside communications node, such as through the use of firmware
and/or software. The receiver preferably receives electrical or
optical signals via a so-called "Class I, Division I" conduit or
through a radio signal. The processor processes signals to identify
which signals correlate to which subsurface communications node.
This may involve the use of a multiplexer or a pulse-receive
switch.
[0138] The method next includes transmitting signals from each of
the communications nodes up the wellbore and to the receiver. This
is provided at Box 750. The signals are acoustic signals that have
a resonance amplitude. These signals are sent up the wellbore,
node-to-node. In one aspect, piezo wafers or other piezoelectric
elements are used to receive and transmit acoustic signals. In
another aspect, multiple stacks of piezoelectric crystals or other
magnetostrictive devices are used. Signals are created by applying
electrical signals of an appropriate frequency across one or more
piezoelectric crystals, causing them to vibrate at a rate
corresponding to the frequency of the desired acoustic signal.
[0139] In one aspect, the data transmitted between the nodes is
represented by acoustic waves according to a multiple frequency
shift keying (MFSK) modulation method. Although MFSK is well-suited
for this application, its use as an example is not intended to be
limiting. It is known that various alternative forms of digital
data modulation are available, for example, frequency shift keying
(FSK), multi-frequency signaling (MF), phase shift keying (PSK),
pulse position modulation (PPM), and on-off keying (OOK). In one
embodiment, every 4 bits of data are represented by selecting one
out of sixteen possible tones for broadcast.
[0140] Acoustic telemetry along tubulars is characterized by
multi-path or reverberation which persists for a period of
milliseconds. As a result, a transmitted tone of a few milliseconds
duration determines the dominant received frequency for a time
period of additional milliseconds. Preferably, the communication
nodes determine the transmitted frequency by receiving or
"listening to" the acoustic waves for a time period corresponding
to the reverberation time, which is typically much longer than the
transmission time. The tone duration should be long enough that the
frequency spectrum of the tone burst has negligible energy at the
frequencies of neighboring tones, and the listening time must be
long enough for the multipath to become substantially reduced in
amplitude. In one embodiment, the tone duration is 2 ms, then the
transmitter remains silent for 48 milliseconds before sending the
next tone. The receiver, however, listens for 2+48=50 ms to
determine each transmitted frequency, utilizing the long
reverberation time to make the frequency determination more
certain. Beneficially, the energy required to transmit data is
reduced by transmitting for a short period of time and exploiting
the multi-path to extend the listening time during which the
transmitted frequency may be detected.
[0141] In one embodiment, an MFSK modulation is employed where each
tone is selected from an alphabet of 16 tones, so that it
represents 4 bits of information. With a listening time of 50 ms,
for example, the data rate is 80 bits per second.
[0142] The tones are selected to be within a frequency band where
the signal is detectable above ambient and electronic noise at
least two nodes away from the transmitter node so that if one node
fails, it can be bypassed by transmitting data directly between its
nearest neighbors above and below. In one example the tones are
evenly spaced in period within a frequency band from about 100 kHz
to 125 kHz. In another example, the tones are evenly spaced in
frequency within a frequency band from about 100 kHz to 125
kHz.
[0143] Preferably, the nodes employ a "frequency hopping" method
where the last transmitted tone is not immediately re-used. This
prevents extended reverberation from being mistaken for a second
transmitted tone at the same frequency. For example, 17 tones are
utilized for representing data in an MFSK modulation scheme;
however, the last-used tone is excluded so that only 16 tones are
actually available for selection at any time.
[0144] The communications nodes will transmit data as mechanical
waves at a rate exceeding about 50 bps.
[0145] In one embodiment, each of the subsurface communications
nodes also includes a temperature sensor. When the cement job is
complete and the cement is setting, an exothermic reaction will
take place. Changes in temperature will be indicative of the
presence of cement between communications nodes. Later during
production, changes in temperature may be indicative of the
presence of formation fluids flowing behind the casing string. This
may be indicative of flaws in the cement sheath. In any instance,
the communications nodes are then designed to generate a signal
that corresponds to temperature readings sensed by the respective
temperature sensors along their corresponding joints of pipe.
[0146] Other sensors may also be employed in selected subsurface
communications nodes. In one embodiment, strain gauges are used as
sensors. Strain gauge data can be used to determine changes in
stress on the casing as cement transitions from a fluid capable of
transmitting hydrostatic pressure to a solid that is set. Strain
gauge data can also be used to later identify volumetric changes
within the set cement due to chemical reactions as cement hydration
continues. Further, strain gauge data may be used to detect a
pressure increase in the wellbore due to reservoir fluid influx
through a flaw in the cement sheath. Data from the strain gauges
may be included as part of the packet of information sent to the
receiver at the surface for analysis.
[0147] In another embodiment, microphones are placed within
selected subsurface communications nodes. Passive acoustic data
gathered by microphones can be used to detect wellbore fluids,
especially gas, that are flowing through a flaw or a mud channel in
the cement sheath. As gas moves through a small gap it will produce
ambient noises across a broad range of frequencies that can be
detected by passive acoustic sensors in the nodes. Data from
microphones may be included as part of the packet of information
sent to the receiver at the surface for analysis.
[0148] As can be seen, various data can be gathered by sensors
including temperature measurements, casing strain, noise caused by
gas flow, and acoustic wave measurements themselves. All of this
data may be considered together in evaluating a cement sheath along
a wellbore.
[0149] The method 700 also includes analyzing the signals from the
communications nodes. This is seen at Box 760. The signals are
analyzed to evaluate the integrity of the cement sheath adjacent or
in proximity to each of the subsurface communications nodes.
Preferably, the signals are analyzed after the cement has set into
a solid material having a compressive strength. Analyzing the
signals may mean comparing the amplitude to a baseline or to other
amplitude readings.
[0150] The receiver (or a processor associated with the receiver)
will compare amplitude values of the various acoustic signals, or
waveforms, against a baseline amplitude value to confirm that the
amplitude is not too high. The baseline amplitude value may be a
specific value input into the program representative of an expected
amplitude value for a joint of casing having fluids within its bore
and a cement sheath around its outer surface. Alternatively, the
baseline amplitude value may be a moving average amplitude value
determined by the program by averaging amplitude readings from a
pre-designated number of communications nodes in proximity to the
subject communications node. In one aspect, matrix equations are
used to calculate a moving average, which serves as the baseline
amplitude value. In any instance, an excessively high amplitude
value suggests that cement has not been adequately placed around
the pipe proximate to the communications node.
[0151] Where the signals correspond to temperature readings, the
signals are compared to a baseline temperature value representing
an expected temperature for fresh cement. Alternatively, the
baseline temperature value may be a moving average temperature
value determined by the program by averaging temperature readings
from a pre-designated number of communications nodes in proximity
to the subject communications node. In any instance, if the
temperature reading from a specific communications node is too low,
this will suggest that cement has not been adequately squeezed
around the pipe joint at the level of that communications node.
[0152] Alternatively, analyzing the signals may mean measuring
attenuation of a sonic signal. Propagation of acoustic waves
between pairs of electro-acoustic transducers on neighboring
subsurface communications nodes produces localized information
(between two nodes) about the presence of cement and bonding. The
level of acoustic wave attenuation increases from empty casing, to
water-filled casing, to mud-filled casing, to casing with cement
slurry (before setting), to a solidified/set cement. A plurality of
pair-wise acoustic attenuation measurements provides a real-time
log of the presence of cement. Optionally, this acoustic
attenuation data is correlated with conventional cement bond-log
data to analyze cement integrity.
[0153] A next step in the method 700 may be the identification of a
subsurface communications node that is sending signals indicative
of poor cement integrity within the cement sheath. This is provided
at Box 770. If it is determined that cement has not been properly
placed around the casing string adjacent one of the communications
nodes, various operational decisions may be made. This is indicated
at Box 780. In some embodiments (not illustrated), Boxes 770 and
780 may be replace with a single box stating "Make appropriate
decision on subsequent drilling, completing, operating, or
abandonment of the well."
[0154] In the method 700, each of the communications nodes has an
independent power source. The independent power source may be, for
example, batteries or a fuel cell. Having a power source that
resided within the housing of the communications nodes avoids the
need for passing electrical connections through the housing, which
could compromise fluid isolation. In addition, each of the
intermediate communications nodes has a transducer and associated
transceiver.
[0155] Preferably, the electro-acoustic transducer receives
acoustic signals at a first frequency, and then sends acoustic
signals at a second frequency that is different from the first
frequency. Each transducer then "listens" for signals at the second
frequency. Preferably, each transducer "listens" for the acoustic
waves sent at the first frequency until after reverberation of the
acoustic waves at the first frequency has substantially attenuated.
Thus, a time is selected for both transmitting and for receiving.
In one aspect, the listening time may be about twice the time at
which the waves at the first frequency are transmitted or pulsed.
To accomplish this, the transducer will operate with and under the
control of a micro-processor located on a printed circuit board,
along with memory. Beneficially, the energy required to transmit
signals is reduced by transmitting for a shorter period of
time.
[0156] It is noted that the method 700 and the claims herein do not
require that communications nodes be placed along the entire
wellbore, but only along a selected section or sections. Further,
the method 700 and the claims herein do not require that the cement
sheath be placed along the entire annular region unless the claims
expressly so state.
[0157] A separate method for determining the integrity of a cement
sheath is provided herein. The cement sheath resides within an
annular region along a wellbore. Preferably, the annular region is
between a string of casing and a surrounding subsurface rock
matrix.
[0158] The method first includes receiving signals from a wellbore.
Each signal defines a packet of information having (i) an
identifier for a subsurface communications node originally
transmitting the signal, and (ii) an acoustic amplitude value for
the subsurface communications node originally transmitting the
signal.
[0159] The method also includes correlating communications nodes to
their respective locations in the wellbore. In addition, the method
comprises analyzing the amplitude values to determine whether any
of such amplitude values are indicative of a poor cement sheath
along the wellbore.
[0160] In this method, the subsurface communications nodes may be
constructed in accordance with communications node 350 of FIG. 3,
communications node 400 of FIG. 4, or other arrangement for
acoustic transmission of data. Preferably, each of the subsurface
communications nodes is attached to an outer wall of the casing
string according to a pre-designated spacing, and resides within
the annular region. The subsurface communications nodes are
configured to communicate by acoustic signals transmitted through
the casing string.
[0161] In one aspect, analyzing the amplitude values comprises
identifying amplitude values generated by each of the subsurface
communications nodes, and comparing those amplitude values to a
baseline amplitude value. The baseline amplitude value may be, for
example, (i) a previously stored amplitude value indicative of an
amplitude value of a joint of casing having a continuous annular
cement sheath, or (ii) a moving average of amplitude readings taken
from a pre-designated number of communications nodes in proximity
to a subject communications node.
[0162] In one aspect, each of the subsurface communications nodes
further comprises a temperature sensor. The communications nodes
are then designed to generate a signal that corresponds to
temperature readings taken by the temperature sensors. The
electro-acoustic transceivers in the subsurface communications
nodes transmit acoustic signals up the wellbore representative of
the temperature readings, node-to-node. In this instance, the
packet of information generated by each subsurface communications
node further has (iii) an acoustic waveform indicative of a
temperature reading. In addition, the method further comprises
analyzing the temperature readings to determine the presence of
cement adjacent to the sensor.
[0163] In one aspect, analyzing the temperature readings comprises
identifying temperature values generated by each of the subsurface
communications nodes, and comparing those temperature values to a
baseline temperature value. The baseline temperature value may be
(i) a previously stored temperature value indicative of a
temperature value of a joint of casing having a freshly-cemented
annular region, or (ii) a moving average of temperature readings
taken from a pre-designated number of communications nodes in
proximity to a subject communications node in the wellbore.
[0164] As noted above, other sensors may be placed in selected
subsurface communications nodes. These may include strain gauges
and microphones.
[0165] As can be seen, a novel downhole telemetry system is
provided, as well as a novel method for the wireless transmission
of information using a plurality of data transmission nodes for
detecting cement sheath integrity. In some States, new hydraulic
fracturing regulations are being implemented which may require the
use of cement bond logs. However, the system disclosed herein may
potentially be used by an operator in lieu a cement bond log.
[0166] While it will be apparent that the inventions herein
described are well calculated to achieve the benefits and
advantages set forth above, it will be appreciated that the
inventions are susceptible to modification, variation and change
without departing from the spirit thereof.
* * * * *