U.S. patent application number 17/242422 was filed with the patent office on 2021-08-12 for method and system for performing communications during cementing operations.
The applicant listed for this patent is ExxonMobil Upstream Research Company. Invention is credited to David K. Kent, Xiaohua Yi.
Application Number | 20210246778 17/242422 |
Document ID | / |
Family ID | 1000005542674 |
Filed Date | 2021-08-12 |
United States Patent
Application |
20210246778 |
Kind Code |
A1 |
Kent; David K. ; et
al. |
August 12, 2021 |
Method and System for Performing Communications During Cementing
Operations
Abstract
A method and system are described for communicating within a
system, which may be along tubular members and used during
cementing installation operations. The method includes constructing
a communication network and installing the communication nodes
along a wellbore. The communication nodes are used to monitor the
fluids adjacent to the communication nodes during the cementing
installation operations. Once the cement is installed, the
cementing installation operations may be used for hydrocarbon
operations, such as hydrocarbon exploration, hydrocarbon
development, and/or hydrocarbon production.
Inventors: |
Kent; David K.; (Spring,
TX) ; Yi; Xiaohua; (The Woodlands, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
ExxonMobil Upstream Research Company |
Spring |
TX |
US |
|
|
Family ID: |
1000005542674 |
Appl. No.: |
17/242422 |
Filed: |
April 28, 2021 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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16175418 |
Oct 30, 2018 |
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17242422 |
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62588054 |
Nov 17, 2017 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/005 20200501;
E21B 47/16 20130101; E21B 33/13 20130101; E21B 47/18 20130101; E21B
33/14 20130101 |
International
Class: |
E21B 47/005 20060101
E21B047/005; E21B 33/13 20060101 E21B033/13; E21B 33/14 20060101
E21B033/14; E21B 47/16 20060101 E21B047/16; E21B 47/18 20060101
E21B047/18 |
Claims
1. A method of performing cementing operations by communicating
data among a plurality of communication nodes, the method
comprising: obtaining well data for a subsurface region;
determining a communication network based on the obtained well
data, wherein the communication network includes a plurality of
communication nodes; installing the plurality of communication
nodes into a wellbore and a cement monitoring system, wherein one
or more communication nodes of the plurality of communication nodes
are configured to obtain measurements associated with fluids within
the wellbore and to transmit the measurement data to other
communication nodes in the communication network; performing
cementing installation operations to install cement at a cement
location, wherein the performing cementing installation operations
include: obtaining measurements from one of the one or more
communication nodes during the cementing installation operations;
and transmitting data packets associated with the obtained
measurements from the one of the one or more communication nodes to
a control unit via the communication network during the cementing
installation operations; and performing hydrocarbon operations in
the wellbore after the cement is installed at the cement
location.
2. The method of claim 1, further comprising adjusting cementing
installation operations based on the transmitted data packets
associated with the obtained measurements.
3. The method of claim 1, further comprising determining changes in
density of fluids adjacent to the one or more communication nodes
during the cementing installation operations.
4. The method of claim 1, further comprising determining changes in
gamma ray emissions of fluids adjacent to the one or more
communication nodes during the cementing installation
operations.
5. The method of claim 1, further comprising configuring the
plurality of the communication nodes based on a communication
network configuration.
6. The method of claim 5, wherein the communication network
configuration comprises one of one or more frequency bands, one or
more individual tones, one or more coding methods, and any
combination thereof.
7. The method of claim 1, wherein the step of transmitting data
packets comprises transmitting high-frequency signals that are in
the range between 20 kilohertz and 1 megahertz.
8. The method of claim 1, wherein the performing cementing
installation operations comprises: pumping a cementing fluid into
the wellbore; disposing the cementing fluid adjacent to the tubular
member within the wellbore; and setting the cementing fluid within
the wellbore to form the cement at the cement location.
9. The method of claim 8, wherein the performing cementing
installation operations comprises: pumping a first fluid into the
wellbore prior to the pumping the cementing fluid into the
wellbore, wherein the first fluid comprises one or more of
viscosifier, emulsifier, weighting material, water, oil, and any
combination thereof.
10. The method of claim 9, further comprising: obtaining
measurements from the one or more communication nodes associated
with the first fluid during the cementing installation operations;
and transmitting data packets associated with the obtained first
fluid measurements from the one or more communication nodes to the
control unit via the communication network during the cementing
installation operations.
11. The method of claim 9, wherein the performing cementing
installation operations comprises: pumping a first fluid into the
wellbore prior to the pumping the cementing fluid into the
wellbore.
12. The method of claim 1, further comprising: obtaining
measurements from the one or more communication nodes associated
with the cementing fluid during the cementing installation
operations; and transmitting data packets associated with the
obtained cementing fluid measurements from the one or more
communication nodes to the control unit via the communication
network during the cementing installation operations.
13. The method of claim 12, wherein the cementing fluid comprises
one or more of lime, silica, alumina, iron oxide, gypsum, water,
additives and any combination thereof.
14. The method of claim 13, wherein the additives comprise one or
more of accelerators, retarders, extenders, weighting agents,
dispersants, fluid-loss control agents, lost-circulation control
agents, antifoam agents and any combination thereof.
15. The method of claim 9, wherein the performing cementing
installation operations comprises: pumping a second fluid into the
wellbore after the pumping the cementing fluid into the
wellbore.
16. The method of claim 15, further comprising: obtaining
measurements from the one or more communication nodes associated
with the second fluid during the cementing installation operations;
and transmitting data packets associated with the obtained second
fluid measurements from the one or more communication nodes to the
control unit via the communication network during the cementing
installation operations.
17. A hydrocarbon system comprising: a wellbore in a hydrocarbon
system; a plurality of tubular members disposed in the wellbore; a
communication network associated with the hydrocarbon system,
wherein the communication network comprises a plurality of
communication nodes that are configured to communicate operational
data between two or more of the plurality of communication nodes
during operations; and a cement monitoring system, wherein one or
more communication nodes of the plurality of communication nodes
are configured to obtain measurements associated with fluids within
the wellbore, to transmit the measurement data to other
communication nodes in the communication network and to monitor the
cementing operations.
18. The system of claim 17, wherein the one or more communication
nodes of the plurality of communication nodes are configured to
measure changes in density of fluids adjacent to the one or more
communication nodes during the cementing installation
operations.
19. The system of claim 17, wherein the one or more communication
nodes of the plurality of communication nodes are configured to
measure changes in gamma ray emissions of fluids adjacent to the
one or more communication nodes during the cementing installation
operations.
20. The system of claim 17, wherein the plurality of communication
nodes are configured to transmit high-frequency signals that are in
the range between 20 kilohertz and 1 megahertz.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This application is a continuation and claims priority to
application Ser. No. 16/175,418, filed Oct. 30, 2018, which claims
the benefit of Application No. 62/588,054, filed Nov. 17, 2017, the
disclosures of which are hereby incorporated by reference in their
entireties.
[0002] This application is related to U.S. Patent Publication No.
2018/0058207, published Mar. 1, 2018 entitled "Dual Transducer
Communications Node for Downhole Acoustic Wireless Networks and
Method Employing Same;" U.S. Patent Publication No. 2018/0058206
published Mar. 1, 2018 entitled "Communication Networks, Relay
Nodes for Communication Networks, and Methods of Transmitting Data
Among a Plurality of Relay Nodes;" U.S. Patent Publication No.
2018/0058208, published Mar. 1, 2018 entitled "Hybrid Downhole
Acoustic Wireless Network;" U.S. Patent Publication No.
2018/0058203, published Mar. 1, 2018 entitled "Methods of
Acoustically Communicating and Wells that Utilize the Methods" U.S.
Patent Publication No. 2018/0058209, published Mar. 1, 2018
entitled "Downhole Multiphase Flow Sensing Methods;" U.S. Patent
Publication No. 2018/0066510, published Mar. 8, 2018 entitled
"Acoustic Housing for Tubulars," the disclosures of which are
incorporated herein by reference in their entireties.
[0003] This application is related to U. S. patent applications
having common inventors and assignee: U.S. application Ser. No.
16/139,414, filed Sep. 24, 2018 entitled "Method and System for
Performing Operations using Communications;" U.S. patent
application Ser. No. 16/139,394, filed Sep. 24, 2018 entitled
"Method and System for Performing Communications using Aliasing;"
U.S. patent application Ser. No. 16/139,427, filed Sep. 24, 2018
entitled "Method and System for Performing Operations with
Communications;" U.S. patent application Ser. No. 16/139,421, filed
Sep. 24, 2018 entitled "Method and System for Performing Wireless
Ultrasonic Communications Along a Drilling String;" U.S. patent
application Ser. No. 16/139,384, filed Sep. 24, 2018 entitled
"Method and System for Performing Hydrocarbon Operations with Mixed
Communication Networks;" U.S. patent application Ser. No.
16/139,373, filed Sep. 24, 2018 entitled "Vertical Seismic
Profiling;" U.S. Provisional Application No. 62/588,067 filed Nov.
17, 2017 entitled "Method and System for Performing Operations
using Communications for a Hydrocarbon System;" U.S. Provisional
Application No. 62/588,080 filed Nov. 17, 2017 entitled "Method and
System for Performing Wireless Ultrasonic Communications Along
Tubulars Members;" U.S. Provisional Application No. 62/588,103
filed Nov. 17, 2017 entitled "Method and System for Performing
Hydrocarbon Operations using Communications Associated with
Completions," the disclosures of which are incorporated herein by
reference in their entireties.
FIELD OF THE INVENTION
[0004] This disclosure relates generally to the field of performing
operations, such as hydrocarbon exploration, hydrocarbon
development, and hydrocarbon production and, more particularly, to
communicating and obtaining measurement data during cementing
operations. Specifically, the disclosure relates to methods and
systems for communicating with communication nodes, which may
include being disposing along one or more tubular members, such as
along casing or tubing within a wellbore, and utilized to enhance
cementing operations and other associated operations.
BACKGROUND
[0005] 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 invention. Accordingly, it should
be understood that this section should be read in this light, and
not necessarily as admissions of prior art.
[0006] In hydrocarbon exploration, hydrocarbon development, and/or
hydrocarbon production operations, several real time data systems
or methods have been proposed. As a first example, a physical
connection, such as a cable, an electrical conductor or a fiber
optic cable, is secured to a tubular member, which may be used to
evaluate conditions, such as subsurface conditions. The cable may
be secured to an inner portion of the tubular member or an outer
portion of the tubular member. The cable provides a hard wire
connection to provide real-time transmission of data. Further, the
cables may be used to provide high data transmission rates and the
delivery of electrical power directly to downhole sensors. However,
use of physical cables may be difficult as the cables have to be
unspooled and attached to the tubular member sections disposed
within a wellbore. Accordingly, the conduits being installed into
the well may not be rotated because of the attached cables, which
may be broken through such installations. This limitation may be
problematic for installations into horizontal wells, which
typically involve rotating the tubular members. These passages for
the cables provide potential locations for leakage of fluids, which
may be more problematic for configurations that involve high
pressures fluids. In addition, the leakage of down-hole fluids may
increase the risk of cement seal failures.
[0007] In contrast to physical connection configurations, various
wireless technologies may be used for downhole communications. Such
technologies are referred to as telemetry. These communication
nodes communicate with each other to manage the exchange of data
within the wellbore and with a computer system that is utilized to
manage the hydrocarbon operations. The communication nodes may
involve different wireless network types. As a first example, radio
transmissions may be used for wellbore communications. However, the
use of radio transmissions may be impractical or unavailable in
certain environments or during certain operations. Acoustic
telemetry utilizes an acoustic wireless network to wirelessly
transmit an acoustic signal, such as a vibration, via a tone
transmission medium. In general, a given tone transmission medium
may only permit communication within a certain frequency range;
and, in some systems, this frequency range may be relatively small.
Such systems may be referred to herein as spectrum-constrained
systems. An example of a spectrum-constrained system is a well,
such as a hydrocarbon well, that includes a plurality of
communication nodes spaced-apart along a length thereof. However,
conventional data transmission mechanisms may not be effectively
utilized and may not be utilized with certain hydrocarbon
operations.
[0008] In hydrocarbon operations, wellbores are drilled to provide
access to subsurface fluids, the produced fluids may include sand
or other solids along with the hydrocarbons and/or water. Further,
the wellbore may be unstable and/or may not be structurally sound
as a result of the subsurface formation conditions along changes in
the hydrocarbon operations. Such changes in the subsurface
formation and/or associated conditions may result in production of
debris, such as sand, solids and/or formation material, which has
multiple adverse effects on hydrocarbon operations. Sand and/or
solids production may increase significantly during the first flow
and/or water breakthrough or even when conditions change.
Unfortunately, the sand or solid production may reduce well
productivity, may damage completion devices, may hinder wellbore
access and/or may increase solid disposal. In addition, cementing
the formation may enhance the stability of the formation.
[0009] To limit sand and/or solid production, cementing the
formation may be performed to minimize debris, such as sand and/or
formation material. The cementing operations may involve the
passing the cement into the wellbore and directing the cement to a
specific location within the wellbore. Unfortunately, the correct
placement of cement is a problem with cementing operations.
Conventional methods may involve performing calculations to
determine the correct placement of cement. The calculations may
include determining the volume of cement slurry necessary to fill
the void space where the cement is planned to be placed. The
estimation of the volume is performed by direct physical
measurements using multi-finger caliper log and/or by sonic
measurements. Unfortunately, these estimations may not represent
the actual wellbore, which results in the cementing not properly
covering the zone of interest or using excess cement.
[0010] Accordingly, there remains a need in the industry for
methods and systems that are more efficient and may lessen problems
associated with noisy and ineffective communication. Further, a
need remains for efficient approaches to perform real-time or
concurrent monitoring during the cementing operations, which
involves acoustic communicating along tubular members within a
wellbore. The present techniques provide methods and systems that
overcome one or more of the deficiencies discussed above.
SUMMARY
[0011] In one embodiment, a method of performing cementing
operations by communicating data among a plurality of communication
nodes is described. The method comprising: obtaining well data for
a subsurface region; determining a communication network based on
the obtained well data, wherein the communication network includes
a plurality of communication nodes; installing the plurality of
communication nodes into a wellbore and a cement monitoring system,
wherein one or more communication nodes of the plurality of
communication nodes are configured to obtain measurements
associated with fluids within the wellbore and to transmit the
measurement data to other communication nodes in the communication
network; performing cementing installation operations to install
cement at a cement location, wherein the performing cementing
installation operations include: obtaining measurements from one of
the one or more communication nodes during the cementing
installation operations; and transmitting data packets associated
with the obtained measurements from the one of the one or more
communication nodes to a control unit via the communication network
during the cementing installation operations; and performing
hydrocarbon operations in the wellbore after the cement is
installed at the cement location.
[0012] The method may include various enhancements. The method may
further comprising adjusting cementing installation operations
based on the transmitted data packets associated with the obtained
measurements; further comprising determining changes in density of
fluids adjacent to the one or more communication nodes during the
cementing installation operations; further comprising determining
changes in gamma ray of fluids adjacent to the one or more
communication nodes during the cementing installation operations;
further comprising configuring the plurality of the communication
nodes based on a communication network configuration; wherein the
communication network configuration comprises selecting one of one
or more frequency bands, one or more individual tones, one or more
coding methods, and any combination thereof; further comprising
producing hydrocarbons from the wellbore; wherein the transmitting
data packets comprises transmitting high-frequency signals that are
greater than (>) 20 kilohertz; wherein the transmitting data
packets comprises transmitting high-frequency signals that are in
the range between greater than 20 kilohertz and 1 megahertz;
wherein the performing cementing installation operations comprise:
pumping a cementing fluid into the wellbore, disposing the
cementing fluid adjacent to the tubular member within the wellbore,
and setting the cementing fluid within the wellbore to form the
cement at the cement location; wherein the performing cementing
installation operations comprise: pumping a first fluid into the
wellbore prior to the pumping the cementing fluid into the
wellbore; wherein the first fluid comprises one or more of
viscosifier, emulsifier, weighting material, water, oil and any
combination thereof; further comprising: obtaining measurements
from the one or more communication nodes associated with the first
fluid during the cementing installation operations, and
transmitting data packets associated with the obtained first fluid
measurements from the one or more communication nodes to the
control unit via the communication network during the cementing
installation operations; wherein the performing cementing
installation operations comprise: pumping a first fluid into the
wellbore prior to the pumping the cementing fluid into the
wellbore; further comprising: obtaining measurements from the one
or more communication nodes associated with the cementing fluid
during the cementing installation operations, and transmitting data
packets associated with the obtained cementing fluid measurements
from the one or more communication nodes to the control unit via
the communication network during the cementing installation
operations; wherein the cementing fluid comprise one or more of
lime, silica, alumina, iron oxide, gypsum, water, additives and any
combination thereof; wherein the additives comprises one or more of
accelerators, retarders, extenders, weighting agents, dispersants,
fluid-loss control agents, lost-circulation control agents,
antifoam agents and any combination thereof; wherein the performing
cementing installation operations comprise: pumping a second fluid
into the wellbore after the pumping the cementing fluid into the
wellbore; further comprising: obtaining measurements from the one
or more communication nodes associated with the second fluid during
the cementing installation operations, and transmitting data
packets associated with the obtained second fluid measurements from
the one or more communication nodes to the control unit via the
communication network during the cementing installation
operations.
[0013] A hydrocarbon system is described. The hydrocarbon system
comprises: a wellbore in a hydrocarbon system; a plurality of
tubular members disposed in the wellbore; a communication network
associated with the hydrocarbon system, wherein the communication
network comprises a plurality of communication nodes that are
configured to communicate operational data between two or more of
the plurality of communication nodes during operations; and a
cement monitoring system, wherein one or more communication nodes
of the plurality of communication nodes are configured to obtain
measurements associated with fluids within the wellbore, to
transmit the measurement data to other communication nodes in the
communication network and to monitor the cementing operations.
[0014] The system may include various enhancements. The system may
include wherein the one or more communication nodes of the
plurality of communication nodes are configured to measure changes
in density of fluids adjacent to the one or more communication
nodes during the cementing installation operations; wherein the one
or more communication nodes of the plurality of communication nodes
are configured to measure changes in gamma ray of fluids adjacent
to the one or more communication nodes during the cementing
installation operations; wherein the plurality of communication
nodes are configured to transmit high-frequency signals that are
greater than (>) 20 kilohertz; and/or wherein the plurality of
communication nodes are configured to transmit high-frequency
signals that are in the range between greater than 20 kilohertz and
1 megahertz.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] The advantages of the present invention are better
understood by referring to the following detailed description and
the attached drawings.
[0016] FIG. 1 is an exemplary schematic representation of a well
configured to utilize a communication network having a cement
monitoring system that includes one or more communication nodes in
accordance with certain aspects of the present techniques.
[0017] FIGS. 2A and 2B are exemplary views of communications nodes
of FIG. 1.
[0018] FIG. 3 is an exemplary flow chart in accordance with an
embodiment of the present techniques.
DETAILED DESCRIPTION
[0019] In the following detailed description section, the specific
embodiments of the present disclosure are described in connection
with preferred embodiments. However, to the extent that the
following description is specific to a particular embodiment or a
particular use of the present disclosure, this is intended to be
for exemplary purposes only and simply provides a description of
the exemplary embodiments. Accordingly, the disclosure is not
limited to the specific embodiments described below, but rather, it
includes all alternatives, modifications, and equivalents falling
within the true spirit and scope of the appended claims.
[0020] Various terms as used herein are defined below. To the
extent a term used in a claim is not defined below, it should be
given the broadest definition persons in the pertinent art have
given that term as reflected in at least one printed publication or
issued patent.
[0021] The articles "the", "a", and "an" are not necessarily
limited to mean only one, but rather are inclusive and open ended
so as to include, optionally, multiple such elements.
[0022] The directional terms, such as "above", "below", "upper",
"lower", etc., are used for convenience in referring to the
accompanying drawings. In general, "above", "upper", "upward" and
similar terms refer to a direction toward the earth's surface along
a wellbore, and "below", "lower", "downward" and similar terms
refer to a direction away from the earth's surface along the
wellbore. Continuing with the example of relative directions in a
wellbore, "upper" and "lower" may also refer to relative positions
along the longitudinal dimension of a wellbore rather than relative
to the surface, such as in describing both vertical and horizontal
wells.
[0023] As used herein, the term "and/or" placed between a first
entity and a second entity means one of (1) the first entity, (2)
the second entity, and (3) the first entity and the second entity.
Multiple elements listed with "and/or" should be construed in the
same fashion, i.e., "one or more" of the elements so conjoined.
Other elements may optionally be present other than the elements
specifically identified by the "and/or" clause, whether related or
unrelated to those elements specifically identified. Thus, as a
non-limiting example, a reference to "A and/or B", when used in
conjunction with open-ended language such as "comprising" can
refer, in one embodiment, to A only (optionally including elements
other than B); in another embodiment, to B only (optionally
including elements other than A); in yet another embodiment, to
both A and B (optionally including other elements). As used herein
in the specification and in the claims, "or" should be understood
to have the same meaning as "and/or" as defined above. For example,
when separating items in a list, "or" or "and/or" shall be
interpreted as being inclusive, i.e., the inclusion of at least
one, but also including more than one, of a number or list of
elements, and, optionally, additional unlisted items. Only terms
clearly indicated to the contrary, such as "only one of" or
"exactly one of," or, when used in the claims, "consisting of,"
will refer to the inclusion of exactly one element of a number or
list of elements. In general, the term "or" as used herein shall
only be interpreted as indicating exclusive alternatives (i.e.,
"one or the other but not both") when preceded by terms of
exclusivity, such as "either," "one of," "only one of," or "exactly
one of".
[0024] As used herein, "about" refers to a degree of deviation
based on experimental error typical for the particular property
identified. The latitude provided the term "about" will depend on
the specific context and particular property and can be readily
discerned by those skilled in the art. The term "about" is not
intended to either expand or limit the degree of equivalents which
may otherwise be afforded a particular value. Further, unless
otherwise stated, the term "about" shall expressly include
"exactly," consistent with the discussion below regarding ranges
and numerical data.
[0025] As used herein, "any" means one, some, or all
indiscriminately of whatever quantity.
[0026] As used herein, "at least one," in reference to a list of
one or more elements, should be understood to mean at least one
element selected from any one or more of the elements in the list
of elements, but not necessarily including at least one of each and
every element specifically listed within the list of elements and
not excluding any combinations of elements in the list of elements.
This definition also allows that elements may optionally be present
other than the elements specifically identified within the list of
elements to which the phrase "at least one" refers, whether related
or unrelated to those elements specifically identified. Thus, as a
non-limiting example, "at least one of A and B" (or, equivalently,
"at least one of A or B," or, equivalently "at least one of A
and/or B") can refer, in one embodiment, to at least one,
optionally including more than one, A, with no B present (and
optionally including elements other than B); in another embodiment,
to at least one, optionally including more than one, B, with no A
present (and optionally including elements other than A); in yet
another embodiment, to at least one, optionally including more than
one, A, and at least one, optionally including more than one, B
(and optionally including other elements). The phrases "at least
one", "one or more", and "and/or" are open-ended expressions that
are both conjunctive and disjunctive in operation. For example,
each of the expressions "at least one of A, B and C", "at least one
of A, B, or C", "one or more of A, B, and C", "one or more of A, B,
or C" and "A, B, and/or C" means A alone, B alone, C alone, A and B
together, A and C together, B and C together, or A, B and C
together.
[0027] As used herein, "based on" does not mean "based only on",
unless expressly specified otherwise. In other words, the phrase
"based on" describes both "based only on," "based at least on," and
"based at least in part on."
[0028] As used herein, "clock tick" refers to a fundamental unit of
time in a digital processor. For example, one clock tick equals the
inverse of the effective clock speed that governs operation of the
processor. Specifically, one clock tick for a 1 MHz effective clock
speed is equal to one microsecond. As another example, one clock
tick may be equivalent to the minimum amount of time involved for a
scalar processor to execute one instruction. A processor may
operate at various effective clock speeds, and, as such, the amount
of time equivalent to one clock tick may vary, but a fractional
clock tick is not possible.
[0029] As used herein, "conduit" refers to a tubular member forming
a physical channel through which something is conveyed. The conduit
may include one or more of a pipe, a manifold, a tube or the like,
or the liquid contained in the tubular member. Alternately, conduit
refers to an acoustic channel of liquid which may, for example,
exist between the formation and a tubular.
[0030] As used herein, "couple" refers to an interaction between
elements and is not meant to limit the interaction to direct
interaction between the elements and may also include indirect
interaction between the elements described. Couple may include
other terms, such as "connect", "engage", "attach", or any other
suitable terms.
[0031] As used herein, "determining" encompasses a wide variety of
actions and therefore "determining" can include calculating,
computing, processing, deriving, investigating, looking up (e.g.,
looking up in a table, a database or another data structure),
ascertaining and the like. Also, "determining" can include
receiving (e.g., receiving information), accessing (e.g., accessing
data in a memory) and the like. Also, "determining" can include
resolving, selecting, choosing, establishing and the like.
[0032] As used herein, "one embodiment," "an embodiment," "some
embodiments," "one aspect," "an aspect," "some aspects," "some
implementations," "one implementation," "an implementation," or
similar construction means that a particular component, feature,
structure, method, or characteristic described in connection with
the embodiment, aspect, or implementation is included in at least
one embodiment and/or implementation of the claimed subject matter.
Thus, the appearance of the phrases "in one embodiment" or "in an
embodiment" or "in some embodiments" (or "aspects" or
"implementations") in various places throughout the specification
are not necessarily all referring to the same embodiment and/or
implementation. Furthermore, the particular features, structures,
methods, or characteristics may be combined in any suitable manner
in one or more embodiments or implementations.
[0033] As used herein, "exemplary" is used exclusively herein to
mean "serving as an example, instance, or illustration." Any
embodiment described herein as "exemplary" is not necessarily to be
construed as preferred or advantageous over other embodiments.
[0034] As used herein, "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.
[0035] As used herein, "hydrocarbons" are generally defined as
molecules formed primarily of carbon and hydrogen atoms such as oil
and natural gas. Hydrocarbons may also include other elements or
compounds, such as, but not limited to, halogens, metallic
elements, nitrogen, oxygen, sulfur, hydrogen sulfide (H.sub.2S),
and carbon dioxide (CO.sub.2). Hydrocarbons may be produced from
hydrocarbon reservoirs through wells penetrating a hydrocarbon
containing formation. Hydrocarbons derived from a hydrocarbon
reservoir may include, but are not limited to, petroleum, kerogen,
bitumen, pyrobitumen, asphaltenes, tars, oils, natural gas, or
combinations thereof. Hydrocarbons may be located within or
adjacent to mineral matrices within the earth, termed reservoirs.
Matrices may include, but are not limited to, sedimentary rock,
sands, silicilytes, carbonates, diatomites, and other porous
media.
[0036] As used herein, "hydrocarbon exploration" refers to any
activity associated with determining the location of hydrocarbons
in subsurface regions. Hydrocarbon exploration normally refers to
any activity conducted to obtain measurements through acquisition
of measured data associated with the subsurface formation and the
associated modeling of the data to identify potential locations of
hydrocarbon accumulations. Accordingly, hydrocarbon exploration
includes acquiring measurement data, modeling of the measurement
data to form subsurface models, and determining the likely
locations for hydrocarbon reservoirs within the subsurface. The
measurement data may include seismic data, gravity data, magnetic
data, electromagnetic data, and the like. The hydrocarbon
exploration activities may include drilling exploratory wells.
[0037] As used herein, "hydrocarbon development" refers to any
activity associated with planning of extraction and/or access to
hydrocarbons in subsurface regions. Hydrocarbon development
normally refers to any activity conducted to plan for access to
and/or for production of hydrocarbons from the subsurface formation
and the associated modeling of the data to identify preferred
development approaches and methods. By way of example, hydrocarbon
development may include modeling of the subsurface formation and
extraction planning for periods of production, determining and
planning equipment to be utilized and techniques to be utilized in
extracting the hydrocarbons from the subsurface formation, and the
like.
[0038] As used herein, "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 (20.degree. Celsius
(C) and 1 atmospheric (atm) pressure). Hydrocarbon fluids may
include, for example, oil, natural gas, gas condensates, coal bed
methane, shale oil, shale gas, and other hydrocarbons that are in a
gaseous or liquid state.
[0039] As used herein, "hydrocarbon operations" refers to any
activity associated with hydrocarbon exploration, hydrocarbon
development, collection of wellbore data, and/or hydrocarbon
production. It may also include the midstream pipelines and storage
tanks, or the downstream refinery and distribution operations. By
way of example, the hydrocarbon operations may include managing the
communications for the wellbore through the communication nodes by
utilizing the tubular members, such as drilling string and/or
casing.
[0040] As used herein, "hydrocarbon production" refers to any
activity associated with extracting hydrocarbons from subsurface
location, such as a well or other opening. Hydrocarbon production
normally refers to any activity conducted to form the wellbore
along with any activity in or on the well after the well is
completed. Accordingly, hydrocarbon production or extraction
includes not only primary hydrocarbon extraction, but also
secondary and tertiary production techniques, such as injection of
gas or liquid for increasing drive pressure, mobilizing the
hydrocarbon or treating by, for example, chemicals, hydraulic
fracturing the wellbore to promote increased flow, well servicing,
well logging, and other well and wellbore treatments.
[0041] As used herein, "mode" refers to a setting or configuration
associated with the operation of communication nodes in a
communication network. For example, the mode may include a setting
for acoustical compression wave, acoustical shear wave, or any
combination thereof.
[0042] As used herein, "monitored section" and "monitored sections"
refer to locations along the tubular members that include sensors
and/or are regions of interest.
[0043] As used herein, "unmonitored section" and "unmonitored
sections" refer to locations along the tubular members that do not
include sensors and/or are not regions of interest.
[0044] As used herein, "operatively connected" and/or "operatively
coupled" means directly or indirectly connected for transmitting or
conducting information, force, energy, or matter.
[0045] As used herein, "optimal", "optimizing", "optimize",
"optimality", "optimization" (as well as derivatives and other
forms of those terms and linguistically related words and phrases),
as used herein, are not intended to be limiting in the sense of
requiring the present invention to find the best solution or to
make the best decision. Although a mathematically optimal solution
may in fact arrive at the best of all mathematically available
possibilities, real-world embodiments of optimization routines,
methods, models, and processes may work towards such a goal without
ever actually achieving perfection. Accordingly, one of ordinary
skill in the art having benefit of the present disclosure will
appreciate that these terms, in the context of the scope of the
present invention, are more general. The terms may describe one or
more of: 1) working towards a solution which may be the best
available solution, a preferred solution, or a solution that offers
a specific benefit within a range of constraints; 2) continually
improving; 3) refining; 4) searching for a high point or a maximum
for an objective; 5) processing to reduce a penalty function; 6)
seeking to maximize one or more factors in light of competing
and/or cooperative interests in maximizing, minimizing, or
otherwise controlling one or more other factors, etc.
[0046] As used herein, "potting" refers to the encapsulation of
electrical components with epoxy, elastomeric, silicone, or
asphaltic or similar compounds for the purpose of excluding
moisture or vapors. Potted components may or may not be
hermetically sealed.
[0047] As used herein, "range" or "ranges", such as concentrations,
dimensions, amounts, and other numerical data may be presented
herein in a range format. It is to be understood that such range
format is used merely for convenience and brevity and should be
interpreted flexibly to include not only the numerical values
explicitly recited as the limits of the range, but also to include
all the individual numerical values or sub-ranges encompassed
within that range as if each numerical value and sub-range is
explicitly recited. For example, a range of about 1 to about 200
should be interpreted to include not only the explicitly recited
limits of 1 and about 200, but also to include individual sizes
such as 2, 3, 4, etc. and sub-ranges such as 10 to 50, 20 to 100,
etc. Similarly, it should be understood that when numerical ranges
are provided, such ranges are to be construed as providing literal
support for claim limitations that only recite the lower value of
the range as well as claims limitation that only recite the upper
value of the range. For example, a disclosed numerical range of 10
to 100 provides literal support for a claim reciting "greater than
10" (with no upper bounds) and a claim reciting "less than 100"
(with no lower bounds).
[0048] As used herein, "sealing material" refers to any material
that can seal a cover of a housing to a body of a housing
sufficient to withstand one or more downhole conditions including
but not limited to, for example, temperature, humidity, soil
composition, corrosive elements, pH, and pressure.
[0049] As used herein, "sensor" includes any electrical sensing
device or gauge. The sensor may be capable of monitoring or
detecting pressure, temperature, fluid flow, vibration,
resistivity, or other formation data. Alternatively, the sensor may
be a position sensor.
[0050] As used herein, "stream" refers to fluid (e.g., solids,
liquid and/or gas) being conducted through various regions, such as
equipment and/or a formation. The equipment may include conduits,
vessels, manifolds, units or other suitable devices.
[0051] As used herein, "subsurface" refers to geologic strata
occurring below the earth's surface.
[0052] As used herein, "telemetry diagnostic data", "diagnostic
telemetry data", or "telemetry data" refer to data associated with
the communication nodes exchanging information. The telemetry data
may be exchanged for the purpose of assessing and proving or
otherwise optimizing the communication. By example, this may
include frequency and/or amplitude information.
[0053] As used herein, "physical layer" refers to the lowest layer
of the Open Systems Interconnection model (OSI model) maintained by
the identification ISO/IEC 7498-1. The OSI model is a conceptual
model that partitions a communication system into abstraction
layers. The physical layer defines basic electrical and physical
specifications of the network such as acoustic frequency band,
radio-frequency (RF) frequency band, acoustic versus
electromagnetic communication, and other electrical and physical
aspects of the communication.
[0054] As used herein, "direct mapping" refers to establishing a
correspondence between communication frequencies and symbolic
information such that particular communication frequencies
represent a particular piece of symbolic information. Examples of
symbolic information include, but are not limited to, the letters
in alphabet or specific arrangements of bits in a computer memory.
By way of example, direct mapping in an acoustic telemetry system
may include each 100 kHz tone representing the letter "A", each 102
kHz tone representing the letter "B", each 104 kHz tone
representing the letter "C", and so on. By contrast, "spread
spectrum" may involve a correspondence between communication
frequencies and symbolic information that changes repeatedly and in
rapid fashion, such that, by way of example, a 100 kHz tone may
represent the letter "A" and a 104 kHz tone may represent the
letter "B" and a 102 kHz tone may represent the letter "C", then a
110 kHz tone may represent the letter "A" and a 112 kHz tone may
represent the letter "B" and a 114 kHz tone may represent the
letter "C", then a 90 kHz tone may represent the letter "A" and a
84 kHz tone may represent the letter "B" and a 96 kHz tone may
represent the letter "C", and so on. In addition, the direct
mapping may not change, while spread spectrum may change.
[0055] As used herein, "frequency combining" refers to aggregating
similar frequencies by dividing the range of possible frequencies
into a number of sections and classifying all frequencies within
any one section as occurrences of a single frequency. It will be
apparent to a person skilled in the computational arts that the
totality of possible frequencies may be excessively large, leading
to an excessive degree of computational complexity inherent in
analysis of the frequencies, and that frequency combining can limit
the number of possibilities to reduce the computational complexity
inherent in analysis of the possibilities to an acceptable level.
The limited number of possibilities resulting from frequency
combining may be referred to as the "combined frequencies". The
cadence of digital clock ticks acts as an upper bound on the number
of possible combined frequencies in all cases.
[0056] As used herein, "signal strength" refers to a quantitative
assessment of the suitability of a characteristic for a particular
purpose. A characteristic may be an amplitude, a Fast Fourier
Transform (FFT) magnitude, a signal-to-noise ratio (SNR), a zero
crossing (ZCX) quality, a histogram quantity, an occurrence count,
a margin or proportion above a baseline, or any other suitable
measurement or calculation. By way of example, a histogram
representing ZCX occurrence counts by period may assess ZCX signal
strength for each period by dividing the occurrence count for each
period by the maximum occurrence count in the histogram such that
the ZCX signal strength for the period having the maximum
occurrence count is 1 and this is the highest ZCX signal strength
among all the periods in the histogram.
[0057] As used herein, "tubular member", "tubular section" or
"tubular body" refer to any pipe, such as a joint of casing, a
portion of a liner, a drill string, a production tubing, an
injection tubing, a pup joint, a buried pipeline, underwater
piping, or above-ground piping. Solid lines therein, and any
suitable number of such structures and/or features may be omitted
from a given embodiment without departing from the scope of the
present disclosure.
[0058] As used herein, "wellbore" or "downhole" 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."
[0059] As used herein, "well data" may include seismic data,
electromagnetic data, resistivity data, gravity data, well log
data, core sample data, and combinations thereof. The well data may
be obtained from memory or from the equipment in the wellbore. The
well data may also include the data associated with the equipment
installed within the wellbore and the configuration of the wellbore
equipment. For example, the well data may include the composition
of the tubular members, thickness of the tubular members, length of
the tubular members, fluid composition within the wellbore,
formation properties, cementation within the wellbore and/or other
suitable properties associated with the wellbore.
[0060] As used herein, "zone", "region", "container", or
"compartment" is a defined space, area, or volume contained in the
framework or model, which may be bounded by one or more objects or
a polygon encompassing an area or volume of interest. The volume
may include similar properties.
[0061] The exchange of information may be used to manage the
operations for different technologies. By way of example, the
communication network may include communication nodes disposed
along one or more tubular members. The communication nodes may be
distributed along casing or tubing within a wellbore, along a
subsea conduit and/or along a pipeline, to enhance associated
operations. To exchange information, the communication network may
include physically connected communication nodes, wirelessly
connected communication nodes or a combination of physically
connected communication nodes and wirelessly connected
communication nodes.
[0062] By way of example, the communication network may be used for
data exchanges of operational data, which may be used for real-time
or concurrent operations involving hydrocarbon exploration
operations, hydrocarbon development operations, and/or hydrocarbon
production operations, for example. In hydrocarbon operations, the
system or method may involve communicating via a downhole network
including various communication nodes spaced-apart along a length
of tubular members, which may be a tone transmission medium (e.g.,
conduits). In addition, certain communication nodes, which are
disposed near specific tools or near certain regions, may include
one or more sensors. The communication nodes may communicate with
each other to manage the exchange of data within the wellbore and
with a computer system that is utilized to manage the hydrocarbon
operations. By way of example, the communication network may
involve transmitting and/or receiving signals or tones via one or
more frequencies of acoustic tones in the form of data packets via
the tone transmission medium. The downhole wireless communication
through the tubular members, such as casing and/or production
tubing, may be beneficial for enhancing hydrocarbon operations,
such as monitoring and/or optimizing the cementing installation,
managing the operation of the completions, and/or monitoring the
operation of the well once the cement is installed. In such
communications, the communication network may include communication
nodes that include one or more sensors or sensing components to
utilize ultrasonic acoustic frequencies to exchange information,
which may simultaneously or concurrently performed with the
cementing operations.
[0063] In certain configurations, the communication nodes may
include a housing that isolates various components from the
wellbore environment. In particular, the communication nodes may
include one or more encoding components, which may be configured to
generate and/or to induce one or more acoustic tones within tone
transmission medium, such as a tubular member or liquid inside the
tubular member. Alternately, conduit refers to an acoustic channel
of liquid which may, for example, exist between the formation and a
tubular member. In addition, the communication nodes may include
one or more decoding components, which may be configured to receive
and/or to decode acoustic tones from the tone transmission medium.
The communication nodes may include one or more power supplies
configured to supply energy to the other components, such as
batteries. The communication nodes may include one or more sensors,
which may be configured to obtain measurement data associated with
the downhole environment and/or the formation. In particular, the
one or more sensors may be used to monitor the cement installation
and/or the composition of the fluids. The communication nodes may
include relatively small transducers to lessen the size of the
communication nodes, such that they may be disposed or secured to
locations having limited clearance, such as on the surface of
tubular members (e.g., internal surface and/or outer surface),
and/or between successive layers of downhole tubular members. As an
example, small acoustic transducers may be configured to transmit
and/or receive tones.
[0064] As noted above, the cementing operations may involve passing
the cement into the wellbore and directing the cement to a specific
location within the wellbore. The cementing operations may comprise
displacing drilling fluid and filling part or all of the volume
between the tubular member and the formation (e.g.,
hollow-cylindrical annular area between the casing and the borehole
wall with cement). The combination of cement and tubular members
may be used to strengthen the wellbore and may be used to
facilitate the zonal fluid isolation of specific sections (e.g.,
monitored sections) of a hydrocarbon-producing formation. The
present techniques utilize communication nodes to provide real-time
or concurrent data associated with the cementing installation and
may also be used to monitor the cement installation in the
subsurface region. Beneficially, the use of the communication nodes
may be used to monitor the cementing operations, which does not
solely utilize estimations to perform the cementing installation.
Accordingly, the present techniques may include concurrent and/or
real-time monitoring of cementing installation and/or cement.
[0065] The communication nodes may be used to enhance the correct
placement of cement with cementing operations. By using the sensors
or sensing components in the communication nodes, the inaccuracy or
uncertainty may be minimized or removed. The communication nodes
may be programmed to transmit a signal (e.g., a notification
associated with the cementing installation) to a control unit
(e.g., topside communication node or other computer system being
utilized with cementing operations). The communication nodes may
include one or more sensors or sensing components, which may be
used to monitor different properties and may be used to verify the
different properties. The notification may include the detection of
a change in pressure, a change in temperature, a change in density
of the fluid and/or a change in gamma ray emissions of the fluid.
By way of example, once the notification is transmitted to the
control unit, the control unit may monitor the actual location of
the cement along the tubular member. With this notification, the
pumping of cement may be adjusted or stopped based on the
notification and/or the pumping of a spacer fluid may start or be
adjusted.
[0066] The distribution and locations of the communication nodes
may vary based on the cement locations and specific aspects of the
wellbore. The distribution of the communication nodes may involve
disposing more communication nodes within the monitored sections of
the wellbore. This distribution of communication nodes may include
disposing two or more communication nodes in a horizontal
configuration or a circumferential configuration, such as
substantially equidistantly around the outer surface of the tubular
member. As a specific example, the communication nodes may include
disposing four communication nodes disposed around the outer
surface of the tubular members. Further, the distribution of
communication nodes may include disposing two or more communication
nodes in a vertical configuration or a longitudinal configuration,
such as spaced along the surface of the tubular members. As a
specific example, the communication nodes may include disposing
four communication nodes disposed around the outer surface of the
tubular member.
[0067] The configuration of the communication nodes into a
communication network may include disposing the communication nodes
at specific locations based on the proposed cement locations,
specific aspects associated with the wellbore and specific aspects
associated with the wellbore. The present techniques may involve
managing the cementing installation operations based on the
measurements or notifications from the communication nodes and
associated calculations to minimize uncertainty or risk in the
cementing installation operations. For example, the present
techniques may include determining the timing of different steps in
the cementing operations. For example, the cementing installation
operations may include using different fluids, which may be used to
manage volume of cement and other fluids. In particular, the
cementing operations may include disposing a first fluid into the
wellbore. The first fluid may include a first property that may be
measured by the communication nodes, such as density, gamma ray
emissions, and/or a specific property. The first fluid may be used
to dispose a drilling fluid within the wellbore. The first fluid
may include viscosifiers, emulsifiers, weighting material, water,
oil. The cementing operations may include disposing a second fluid
into the wellbore. The second fluid may include a second property
that may be measured by the communication nodes, such as density,
gamma ray emissions, and/or a specific property. The second fluid
may be used to dispose the first fluid within the wellbore. The
second fluid may include viscosifiers, emulsifiers, weighting
material, water, oil, and any combinations thereof. Further, the
cementing operations may include disposing cement or a cementing
fluid into the wellbore. The cementing fluid may include a cement
property that may be measured by the communication nodes, such as
density, gamma ray emissions, and/or a specific property. The
cementing fluid may be used to dispose the second fluid within the
wellbore. The cementing fluids may include lime, silica, alumina
and iron oxide, gypsum, water, additives such as, but not limited
to, accelerators, retarders, extenders, weighting agents,
dispersants, fluid-loss control agents, lost-circulation control
agents, antifoam agents and/or any combination thereof. Also, the
cementing operations may include disposing a third fluid into the
wellbore. The third fluid may include a third property that may be
measured by the communication nodes, such as density, gamma ray
emissions, and/or a specific property. The third fluid may be used
to dispose the cementing fluid within the wellbore. The third
fluids may include spacer fluid, one or more viscosifiers, one or
more emulsifiers, one or more weighting materials, and/or water.
The third fluid may be include retarders to prevent the hardening
of the cement in the wellbore. The communication nodes may also
include one or more sensors or sensing components, which may be
used to monitor two or more different properties and the different
properties may be used to verify the different properties.
[0068] By way of example, the method may include performing a
cementing operations. The method may include drilling a wellbore
with a drilling fluid; determining a communication network
comprising various communication nodes; configuring the
communication nodes and installing the communication nodes on one
or more tubular members; disposing the one or more tubular members
into the wellbore; disposing or pumping a first fluid into the
wellbore to displace the drilling fluid; disposing or pumping a
cementing fluid into the wellbore to displace the first fluid;
and/or disposing or pumping a second fluid into the wellbore to
displace the cementing fluid, wherein the second fluid is used to
displace the cementing fluid to the cementing installation
location. The communication nodes may be configured to detect one
or more properties and provide notifications associated with one or
more of the fluids within the wellbore. Further, the first fluid,
cementing fluid and/or second fluid may each include specific
properties that may be detected by the communication nodes.
[0069] To manage the cementing installation operations, the present
techniques may include obtaining measurements, using the
measurements and/or providing notifications associated with the
cementing operations. The communication nodes may provide signals
or notifications associated with the properties of fluids within
the wellbore. Based on the notifications, the calculations to
determine the correct placement of cement may be enhanced to lessen
uncertainty or risk. The calculations may include determining the
volume of the first fluid disposed in the wellbore associated with
the cement location, determining the volume of the cementing fluid
to fill the volume at the cement location, and determining the
volume of the second fluid to dispose the cementing fluid to the
cement location; and determine the location of the respective
fluids within the wellbore.
[0070] By way of example, the communication nodes may be configured
to manage the cementing installation operations. A first set of
communication node may be disposed on tubular members at a first
sensor location within the wellbore that is upstream of the
location that cement installation is to be positioned. The first
sensor location may be determined to provide appropriate timing on
the exchange of fluids in the cementing installation (e.g., the
changing of different fluids to change the fluids being passed
through the wellbore). A second set of communication node may be
disposed on tubular members at a second sensor location within the
wellbore that is at a location downstream of the first sensor
location and upstream of the cement installation location. The
second sensor location may be determined to provide appropriate
timing on the exchange of fluids in the cementing installation
(e.g., the changing of different fluids to change the fluids being
passed through the wellbore). In addition, a third set of
communication node may be disposed on tubular members at a third
sensor location within the wellbore that is at a location
downstream of the second sensor location and at the cement
installation location. The third sensor location may be determined
to provide appropriate timing on the exchange of fluids in the
cementing installation (e.g., the changing of different fluids to
change the fluids being passed through the wellbore).
[0071] In certain configurations, the present techniques may
include cementing installation system. The communication nodes may
include one or more ultrasonic transducers for transmitting and
receiving acoustic signals; electronic circuits for signal
processing and computation; and/or batteries for power supply.
Extra ultrasonic transducers with same or different operating
frequencies may be included for sensing purposes. The communication
nodes may include one or more sensing components installed on
tubular member (e.g., casing and/or tubing, such as a sand screen).
The one or more sensing components may form a sensor array for data
collection as well as communication. The measured data may be
relayed back to topside equipment to a control unit. As cementing
locations may be predefined (e.g., monitored sections), one or more
communication nodes may include dedicated sensors and may be
installed along tubular members in the preferred configurations to
monitor the cementing installation locations (e.g., distribution of
communication nodes with sensors or distribution of a communication
node with associated sensors). For other areas of the wellbore
(e.g., unmonitored sections), the communication nodes are primarily
used for data packet exchanges, which are used to relay the
measured data or notifications to a control unit at the control
unit.
[0072] In addition to the monitoring the cementing installation,
the system may include one or more communication nodes having one
or more sensors in a dense configuration in the cement location or
area. The sensors may be configured to measure pressure,
temperature, gamma ray, flow meter, resistivity, capacitance,
stress, strain, density, vibration and any combination thereof. The
sensors may be within the housing of the communication node or may
include individual housings for the sensors and a controller that
houses the other components. The distributed sensors provide
localized measurement data about the existence of voids and/or gaps
in the cement installation. The data may be combined, integrated
and used to generate a 3D cement installation map associated with
the cement installation in the monitored region. As a result, the
acoustic attenuation between two sensors may also provide an
indication of installation indicator (e.g., quality indicator) for
qualitative check.
[0073] In certain configurations, the communication nodes for the
cementing installation operations may be pre-installed on the
tubular member prior to disposing the cementing fluid into the
wellbore. In such as configuration, the cement monitoring system
(e.g., cementing installation monitoring system) may be disposed at
the cementing installation area to monitor before the cementing
installation is provided to the area, during the cementing
installation, and even after the cementing installation is
installed. The monitoring may include measuring a first property
for the cementing installation operations before the cementing
installation and during the cementing installation operations and
then may include measuring a second property for the cementing
installation operations after the cementing installation. The
measurements may be transmitted to the control unit or a processor
in the communication node, which may be configured to compare the
measurements for different time periods to determine information
about the progress of the cementing installation. The comparisons
may be used to determine if the cementing installation operations
should be adjusted based on the measurement data.
[0074] In certain configurations, the cement monitoring system may
include one or more communication nodes, which may include various
sensors, configured to exchange data packets with a control unit.
The communication nodes may be disposed on an interior surface of
the tubular member, an external surface of the tubular member,
and/or a combination thereof. In the communication nodes include
one or more sensors, the sensors may be distributed in individual
housings that communicate with a controller and/or a single
housing. The sensors may be disposed on an interior surface of the
tubular member, an external surface of the tubular member, and/or a
combination thereof. The sensors may be used to acquire
measurements associated with the area that the cement is to be
installed, about the cementing installation, and/or about the
environment or fluids after the cement is installed. The exchange
of data with the control unit from the communication nodes may be
performed in real time or concurrently with the cementing
installation operations (e.g., exchanging of fluids near the
cementing installation area, disposing cementing fluid into the
cementing installation area, and/or removing other fluid after
installation of the cement).
[0075] The communication nodes may be configured to perform
ultrasonic telemetry and sensing in specific frequency bands. As an
example, the communication network may utilize low-frequency ranges
and/or high-frequency ranges (e.g., may include low-frequency
communication nodes and/or high-frequency communication nodes). The
low-frequency communication nodes may be configured to transmit
signals and to receive signals that are less than or equal to
(<) 200 kHz, <100 kHz, <50 kHz, or <20 kHz. In
particular, the low-frequency communication nodes may be configured
to exchange signals in the range between 100 Hz and 20 kHz; in the
range between 1 kHz and 20 kHz; and in the range between 5 kHz and
20 kHz. Other configurations may include low-frequency
communication nodes, which may be configured to exchange signals in
the range between 100 Hz and 200 kHz; in the range between 100 Hz
and 100 kHz; in the range between 1 kHz and 200 kHz; in the range
between 1 kHz and 100 kHz; in the range between 5 kHz and 100 kHz
and in the range between 5 kHz and 200 kHz. The communication nodes
may also include high-frequency communication nodes configured to
transmit and receive signals that are greater than (>) 20 kHz,
>50 kHz, >100 kHz or >200 kHz. Also, the high-frequency
communication nodes may be configured to exchange signals in the
range between greater than 20 kHz and 1 MHz, in the range between
greater than 20 kHz and 750 kHz, in the range between greater than
20 kHz and 500 kHz. Other configurations may include high-frequency
communication nodes, which may be configured to exchange signals in
the range between greater than 100 kHz and 1 MHz; in the range
between greater than 200 kHz and 1 MHz; in the range between
greater than 100 kHz and 750 kHz; in the range between greater than
200 kHz and 750 kHz; in the range between greater than 100 kHz and
500 kHz; and in the range between greater than 200 kHz and 500
kHz.
[0076] In addition, the communication nodes may operate with low
frequency bands and/or high-frequency bands to enhance operations.
The communication nodes may include piezo transducers that may be
coupled to the environment to be sensed (e.g., pulse echo from
piezo assembly behind a thin steel wall and thus proximate flowing
media, hydrates, sand, which may be within the tubular member
and/or external to the tubular member). The configurations may
include the use of acoustic or other transducer arrays spaced on an
azimuth. Such transducer arrays may be used to launch single mode
acoustic or vibrational waves that may be tailored for one or more
of: (i) long distance telemetry, (ii) focusing the acoustic energy
in steel tubular, or within media, or outside of surface of
tubular, (iii) for one or more piezoelectric transducers, the
termination properties, coupling to adjoining tubular members, and
preferable acoustic wave properties that may be enhanced by the
radial design versus a point or wide line attachment. The
communication nodes may be configured to detect the properties
through a wall or surface and/or through exposure to the fluid
adjacent to the communication node.
[0077] In still yet another configuration, the electronic circuits
are present within the communication nodes (e.g., which may include
sensors) to process the collected measurement data, store the data
for transmission, and conduct necessary on-board computation to
simplify data for transmission. Local detection of faulty data,
data compression, and automated communication with neighboring
sensors may be performed with the on-board electronics, signal
processing components and microprocessor. In such a configuration,
the communication nodes of the cement monitoring system (e.g.,
cementing installation monitoring system) may efficiently manage
the exchange of measured data, which may be communicated in real
time or concurrently with the installation of the cement within the
subsurface region.
[0078] In another configuration, the communication node may be
configured to function as a transmitter and/or receiver for data
transmission to the control unit disposed at the topside or other
devices within the wellbore. In other configurations, multiple
different types of devices may be connected. For example, if it is
an acoustic system, piezos may be facilitated as a transmitter and
a receiver to relay data back to topside equipment or other
communication nodes. If it is an electromagnetic system, then
radio-frequency receivers with communication frequency ranges may
be integrated.
[0079] In other configurations, the communication nodes may be
configured to function as a transmitter and/or receiver and/or may
be oriented to receive and/or transmit inside the tubular member,
outside the tubular member and/or a combination thereof. The range
of the communication nodes may be extended by broadcasting directly
into the tubular member versus receiving and transmitting on the
exterior of the tubular member. In addition, the reliability and
quality of the acoustic transmission when broadcasting into the
tubular member may be enhanced.
[0080] In addition, other configurations may include communications
nodes and associated sensors integrated into an array, such as a
collar and/or even within joints or tubular members. Such an
integration may save time by avoiding an added step of clamping the
communication nodes onto the tubular members prior to installation.
This integration may include enhancing reliability by eliminating
the field installation and potential of improper or poor mating of
the communication nodes to the tubular member. The integration may
avoid cost and/or the complexity of external communication nodes,
which may be necessary for measure of pressure directly in flow
zone or annulus. Telemetry electronics and/or hardware along with
sensors in an integrated package that may maintain communication
node physical integrity, while enhancing accuracy of in-flow zone
measurements and/or exterior materials.
[0081] In addition to the variations on the configurations, the
communication node may include different types of sensors, such as
sonic logging components and/or an imaging measurement components.
In such configurations, the communication nodes may include
additional power supplies, such as batteries, to drive an array of
acoustic sources or a single acoustic source to generate sufficient
acoustic energy to perform sonic logging or obtaining imaging
measurements, where the source may be triggered by a communication
node. By way of example, the communication nodes may include one or
more sensors that may include a sonic log component. The sonic log
component may operate by emitting a large acoustic pulse on the
communication node, which is disposed near the sand screen. The
sonic logging techniques may include an acoustic wave that may
travel along the tubular members and any associated formation, with
sufficient energy to be detected by the communication nodes. Using
sonic logging interpretation techniques, the measured data may be
used to evaluate voids or gaps (e.g., permeability, porosity,
lithology, or fluid type in the nearby formation), and/or to
evaluate the cementing installation before and after the cementing
installation operations. Assessing some of these properties may
involve additional data or knowledge of the system (e.g., well
data).
[0082] To manage the transmission and reception of signals, the
processor in the communication node may operate at one or more
effective clock speeds. The presence of a clock in a digital
system, such as a communication node, results in discrete (not
continuous) sampling, and is frequency combining (e.g., any
frequency that falls between clock ticks is detected at the higher
tick or lower tick (because fractional ticks are not permitted), so
in a sense, the frequencies that fall between clock ticks result in
combined frequencies. The communication nodes may operate at a
high-frequency effective clock speed and/or a low-frequency
effective clock speed. The effective clock speed is the clock speed
at which the processor operates after inclusion of applicable clock
multipliers or clock dividers. As a result, the sampling frequency
is equal to the effective clock speed, while the telemetry
frequency is the frequency of a given telemetry tone. By way of
example, the telemetry frequency may be less than or equal to 200
kHz, less than or equal to 150 kHz, less than or equal to 75 kHz or
less than or equal to 50 kHz, or even the range may be between
greater than 20 kHz and 1 MHz, in the range between greater than 20
kHz and 750 kHz, in the range between greater than 20 kHz and 500
kHz. The high-frequency effective clock speed may be may be greater
than 200 kHz, greater than or equal to 500 kHz, greater than or
equal to 1 MHz, greater than or equal to 10 MHz or greater than or
equal to 100 MHz.
[0083] Downhole communications along the tubular members, such as
casing and/or production tubing, may be beneficial for enhancing
hydrocarbon operations, such as optimizing or monitoring cementing
installation operations and monitoring the production of fluids
after the cementing installation for well management. The present
techniques may include various enhancements, such as frequency
selection, which may utilize laboratory and/or surface testing
facilities and acoustic waveguide theory. Another enhancement may
include frequency optimization, which involves broadcast broadband
signals locally between downhole neighboring communication nodes.
For the frequency optimization, only the strongest acoustic signals
may be selected and may be used for communication between each pair
of communication nodes. Also, acoustic signals may be the same or
different among different pairs of communication nodes in the
system. As yet another enhancement, adaptive coding methods may be
selected to support communication based on the selected number of
acoustic frequencies. For one example, the communication may be
successful when the right coding method is selected if the number
of acoustic frequencies is limited (e.g., one frequency). However,
the communication data rate may be compromised once the number of
acoustic frequencies becomes limited. Further, the set of acoustic
frequencies and coding method may also be re-evaluated and updated
at various time intervals and/or as acoustic condition changes.
[0084] The communication network may include different types of
wireless communication nodes that form respective wireless
communication networks. The wireless networks may include
long-range communication nodes (e.g., having a range between about
1 foot to about 1,000 feet, in a range between about 100 feet to
500 feet or even up to 1,000 feet). The long-range communication
nodes may be formed into communication networks (e.g., an
ultrasonic acoustic communication network) that may involve using a
multiple frequency shift keying (MFSK) communication configuration.
In MFSK communication configurations, reliable detection and
decoding of the acoustic signal frequencies is the basis for this
type of communication. As noted above, the unknown and
unpredictable downhole acoustic conditions may be defined from the
formation, cementation, and/or composition (e.g., gas, water and/or
oil). Accordingly, it may be difficult to select the frequencies
for acoustic signals to be utilized between the communication nodes
prior to deployment within the wellbore to support a desired
communication (e.g., long range communication) with minimum power
consumption.
[0085] As another enhancement, the frequency ranges utilized for
the communication network may be adjusted dynamically. In
particular, the acoustic communication channel between each pair of
communication nodes may be variable over a small frequency range.
The frequency selectivity is a result of the coupling of acoustic
signals to the tubular members from individual communication nodes,
which may be influenced by the installation, but also may be
influenced by conditions, such as the acoustic signal propagation
path variations along the wellbore (e.g., formation, cement,
casing, and/or composition of gas, water, and oil). As a further
influence, the coupling and propagation of an acoustic signal may
be disrupted after performing hydrocarbon operations (e.g.,
perforating or cementing installation operations in the wells). As
a result, selecting one pre-selected set of acoustic frequencies
for the entire communication system operational life is likely to
be limiting.
[0086] By selecting and optimizing the acoustic frequencies in
combination with adaptive coding methods between each pair of
communication nodes, the present techniques provide a system and
method to support reliable long range communication along tubular
members, such as in the downhole environment. The frequency band
selection method for communication networks may utilize laboratory
and/or surface testing facilities and acoustic waveguide theory.
Then, if needed, the individual acoustic frequencies may be further
optimized after the communication nodes are deployed along the
tubular members, such as once disposed into the wellbore. The
acoustic signals with the highest signal strength in a broad
frequency band are selected and used for communication between each
pair of communication nodes, and they may be the same or different
among different pairs of communication nodes in the system. After
the frequencies are selected, one of several coding methods may be
selected and adapted to support communication based on the selected
number of acoustic frequencies. Within a specific time and/or
condition changes, the set of acoustic frequencies and coding
methods may be re-evaluated and updated to re-optimize system's
communication reliability and speed.
[0087] Further, the acoustic communication band optimization may
also include selecting a tone detection method. The tone detection
method may include a fast Fourier transform (FFT), zero crossing
(ZCX) and any combination thereof. The tones may be defined as
decoded or detected if FFT recognizes the correct frequencies or
ZCX recognizes the correct periods. The FFT and/or ZCX may be
selected depending on computational power and energy efficiency of
the microcontroller deployed in the communication node. For FFT,
tone selection may be based on the relative magnitude of each tone.
FFT may involve greater computational power, but is more able to
handle background noise. For ZCX, tone selection may be based on
normalized period of zero crossings of each tone. ZCX may involve
less computational power, but may be vulnerable to misdetections
due to background noise. Further, FFT may be supplemented by post
processing curve fitting and ZCX may be implemented in a variety of
different methods. Both methods may only involve a tone to be
detected within a specific range rather than an exact
frequency.
[0088] In another configuration, a method of performing cementing
operations by communicating data among a plurality of communication
nodes is described. The method comprising: obtaining well data for
a subsurface region; determining a communication network based on
the obtained well data, wherein the communication network includes
a plurality of communication nodes; installing the plurality of
communication nodes into a wellbore and a cement monitoring system,
wherein one or more communication nodes of the plurality of
communication nodes are configured to obtain measurements
associated with fluids within the wellbore and to transmit the
measurement data to other communication nodes in the communication
network; performing cementing installation operations to install
cement at a cement location, wherein the performing cementing
installation operations include: obtaining measurements from one of
the one or more communication nodes during the cementing
installation operations; and transmitting data packets associated
with the obtained measurements from the one of the one or more
communication nodes to a control unit via the communication network
during the cementing installation operations; and performing
hydrocarbon operations in the wellbore after the cement is
installed at the cement location.
[0089] The method may include various enhancements. The method may
further comprising adjusting cementing installation operations
based on the transmitted data packets associated with the obtained
measurements; further comprising determining changes in density of
fluids adjacent to the one or more communication nodes during the
cementing installation operations; further comprising determining
changes in gamma ray of fluids adjacent to the one or more
communication nodes during the cementing installation operations;
further comprising configuring the plurality of the communication
nodes based on a communication network configuration; wherein the
communication network configuration comprises selecting one of one
or more frequency bands, one or more individual tones, one or more
coding methods, and any combination thereof; further comprising
producing hydrocarbons from the wellbore; wherein the transmitting
data packets comprises transmitting high-frequency signals that are
greater than (>) 20 kilohertz; wherein the transmitting data
packets comprises transmitting high-frequency signals that are in
the range between greater than 20 kilohertz and 1 megahertz;
wherein the performing cementing installation operations comprise:
pumping a cementing fluid into the wellbore, disposing the
cementing fluid adjacent to the tubular member within the wellbore,
and setting the cementing fluid within the wellbore to form the
cement at the cement location; wherein the performing cementing
installation operations comprise: pumping a first fluid into the
wellbore prior to the pumping the cementing fluid into the
wellbore; wherein the first fluid comprises one or more of
viscosifier, emulsifier, weighting material, water, oil and any
combination thereof; further comprising: obtaining measurements
from the one or more communication nodes associated with the first
fluid during the cementing installation operations, and
transmitting data packets associated with the obtained first fluid
measurements from the one or more communication nodes to the
control unit via the communication network during the cementing
installation operations; wherein the performing cementing
installation operations comprise: pumping a first fluid into the
wellbore prior to the pumping the cementing fluid into the
wellbore; further comprising: obtaining measurements from the one
or more communication nodes associated with the cementing fluid
during the cementing installation operations, and transmitting data
packets associated with the obtained cementing fluid measurements
from the one or more communication nodes to the control unit via
the communication network during the cementing installation
operations; wherein the cementing fluid comprise one or more of
lime, silica, alumina, iron oxide, gypsum, water, additives and any
combination thereof; wherein the additives comprises one or more of
accelerators, retarders, extenders, weighting agents, dispersants,
fluid-loss control agents, lost-circulation control agents,
antifoam agents and any combination thereof; wherein the performing
cementing installation operations comprise: pumping a second fluid
into the wellbore after the pumping the cementing fluid into the
wellbore; further comprising: obtaining measurements from the one
or more communication nodes associated with the second fluid during
the cementing installation operations, and transmitting data
packets associated with the obtained second fluid measurements from
the one or more communication nodes to the control unit via the
communication network during the cementing installation
operations.
[0090] A hydrocarbon system is described. The hydrocarbon system
comprises: a wellbore in a hydrocarbon system; a plurality of
tubular members disposed in the wellbore; a communication network
associated with the hydrocarbon system, wherein the communication
network comprises a plurality of communication nodes that are
configured to communicate operational data between two or more of
the plurality of communication nodes during operations; and a
cement monitoring system, wherein one or more communication nodes
of the plurality of communication nodes are configured to obtain
measurements associated with fluids within the wellbore, to
transmit the measurement data to other communication nodes in the
communication network and to monitor the cementing operations.
[0091] The system may include various enhancements. The system may
include wherein the one or more communication nodes of the
plurality of communication nodes are configured to measure changes
in density of fluids adjacent to the one or more communication
nodes during the cementing installation operations; wherein the one
or more communication nodes of the plurality of communication nodes
are configured to measure changes in gamma ray of fluids adjacent
to the one or more communication nodes during the cementing
installation operations; wherein the plurality of communication
nodes are configured to transmit high-frequency signals that are
greater than (>) 20 kilohertz; and/or wherein the plurality of
communication nodes are configured to transmit high-frequency
signals that are in the range between greater than 20 kilohertz and
1 megahertz.
[0092] Beneficially, the present techniques provide various
enhancements to the operations. The present techniques provide
enhancements to enhance calculation or determination of the volume
of cement slurry to be pumped downhole into the wellbore. The
present techniques may enhance the cementing operations; zonal
isolation, structural support for tubular member, protect tubular
members from corrosion, isolate tubular member for subsequent
drilling. The sensors in the communication node may be used before
the cementing operations to determine whether the tubular member is
centralized, to check the downhole temperature, which may be used
to optimize the cementing fluid as far as the cementing fluid
thickening time, rheology, set time and compressive-strength
development. Additionally, enhancements to the determination of the
volume of cementing fluid to be pump into the cement location may
be estimated based on previous fluid change outs. The cementing
operations may lessen the amount of cementing fluid that is pumped
and may reduce the drill rig time to perform the cementing
operations. Accordingly, the present techniques may be further
understood with reference to FIGS. 1 to 3, which are described
further below.
[0093] FIG. 1 is an exemplary schematic representation of a well
100 configured to utilize a communication network having a cement
monitoring system that includes one or more communication nodes in
accordance with certain aspects of the present techniques. The
cement monitoring system may be used to provide a mechanism to
monitor the installation of cement within the wellbore and/or
monitoring hydrocarbon operations, such as the cement and/or
fluids. The monitoring may be performed concurrently,
simultaneously and/or in real-time with the performance of the
hydrocarbon operations, such as cementing installation
operations.
[0094] FIG. 1 is a schematic representation of a well 100
configured that utilizes a network having the proposed
configuration of a cement monitoring system that includes one or
more communication nodes. The well includes a wellbore 102 that
extends from surface equipment 120 to a subsurface region 128 and a
wellbore 162 that extends from surface equipment 160 to the
subsurface region 128. Wellbores 102 and 162 also may be referred
to herein as extending between a surface region 126 and subsurface
region 128 and/or as extending within a subterranean formation 124
that extends within the subsurface region. The wellbores 102 and
162 may include a plurality of tubular sections, which may be
formed of carbon steel, such as a casing or liner. Subterranean
formation 124 may include hydrocarbons. The well 100 may be used as
a hydrocarbon well, a production well, and/or an injection
well.
[0095] Well system also includes an acoustic wireless communication
network. The acoustic wireless network also may be referred to
herein as a downhole acoustic wireless network that includes
various communication nodes 114 and a topside communication node
and/or control unit 132. The communication nodes 114 may be
spaced-apart along a tone transmission medium that extends along a
length of wellbore 102 and 162. The communication nodes 114 may be
disposed on the interior surface of the tubular members and/or the
sensors may be configured to be in contact with the interior
surface to monitor or measure the fluid as it passes. In the
context of wellbore 102, the tone transmission medium may include a
downhole tubular 110 that may extend within wellbore 102, a
wellbore fluid 104 that may extend within wellbore 102, a portion
of subsurface region 128 that is proximal wellbore 102, a portion
of subterranean formation 124 that is proximal wellbore 102 and/or
that may extend within an annular region between wellbore 102 and
downhole tubular 110. Downhole tubular 110 may define a fluid
conduit 108. In the context of wellbore 162, the tone transmission
medium may include a downhole tubular 164 that may extend within
wellbore 162, a wellbore fluid 166 that may extend within wellbore
162, a portion of subsurface region 128 that is proximal wellbore
162, a portion of subterranean formation 124 that is proximal
wellbore 162 that may extend within wellbore 162 and/or that may
extend within an annular region between wellbore 162 and downhole
tubular 164. Downhole tubular 164 may define a fluid conduit within
the casing 168.
[0096] Communication nodes 114 and 148 may include various
components to manage communication and monitor the wellbore. By way
of example, the communication nodes 114 may include one or more
encoding components 116, which may be configured to generate an
acoustic tone, such as acoustic tone, and/or to induce the acoustic
tone within tone transmission medium. Communication nodes 114 also
may include one or more decoding components 118, which may be
configured to receive acoustic tone from the tone transmission
medium. The communication nodes 114 may function as both an
encoding component 116 and a decoding component 118 depending upon
whether the given node is transmitting an acoustic tone (e.g.,
functioning as the encoding component) or receiving the acoustic
tone (e.g., functioning as the decoding component). The
communication nodes 114 and 148 may include both encoding and
decoding functionality, or structures, with these structures being
selectively utilized depending upon whether or not the given
communication node is encoding the acoustic tone or decoding the
acoustic tone. In addition, the communication nodes 114 and 148 may
optionally include sensing components that are utilized to measure,
control, and monitor conditions within the respective wellbore,
such as wellbore 102 and 162.
[0097] In well, transmission of acoustic tone may be along a length
of wellbore along a fluid within the wellbore or tubular member. As
such, the transmission of the acoustic tone is substantially axial
along the tubular member, and/or directed, such as by tone
transmission medium. Such a configuration may be in contrast to
more conventional wireless communication methodologies, which
generally may transmit a corresponding wireless signal in a
plurality of directions, or even in every direction.
[0098] To install cement in the portion of subterranean formation
124 that is proximal wellbore 102 and 162, cementing installation
operations may be utilized. For the wellbore 102, the cementing
installation operations may include cement monitoring system 140
may include communication nodes 114 and 148 along with a cross over
tool 142, packer 144 and a tubular member 146, while the cementing
installation operations of the wellbore 162 may include a cement
monitoring system may include communication nodes 114 and 148 along
with tubular members 164. The communication nodes 114 and 148 may
include sensing components, which may be within the communication
node housing or may be in contact with the communication node. The
sensing components may include communication nodes 114 and 148 that
are used to monitor different properties and the different
properties may be used to verify the measured properties.
[0099] The cement monitoring system may also include communication
nodes 148, which may include similar components to the
communication nodes 114 and be configured to exchange data packets
with the communication nodes 114 and the control unit 132. The
communication nodes 148 may further include one or more sensors
that are configured to measure certain properties associated with
the cement area or cement location or other locations upstream of
the cement location.
[0100] The cementing installation operations may include passing
cementing fluid 130 into the respective wellbores 102 and 162. For
the wellbore 102, the cementing installation operations may include
passing cementing fluid 130 through the interior regions of the
downhole tubular 110 and tubular member 146. The cementing fluid
130 may be conducted away from the interior region of the tubular
member 146 and along the exterior surface of the tubular member 146
(e.g., pumped into the volume between the tubular member 146 and
the wellbore 102). As the cementing fluid passes each of the
communication nodes 148, a notification or signal may be
transmitted from the respective communication node 148 to the
control unit 132, which may pass through the other communication
nodes 114 and 148. In addition, other configurations may include
communication nodes 114 and 148 that are disposed within the
tubular members 110, 146, and 164 that are utilized to transmit a
notification or signal from the respective communication node 114
or 148 to the control unit 132.
[0101] The plurality of frequencies, which are utilized in the
communication nodes 114 and 148, may include the first frequency
for a first type of communication node type and/or a second
frequency for a second type of communication node type. Each of the
wireless network types may be utilized in different configurations
to provide the communication for the hydrocarbon operations. The
respective frequency ranges may be any suitable values. As
examples, each frequency in the plurality of high-frequency ranges
may be at least 20 kilohertz (kHz), at least 25 kHz, at least 50
kHz, at least 60 kHz, at least 70 kHz, at least 80 kHz, at least 90
kHz, at least 100 kHz, at least 200 kHz, at least 250 kHz, at least
400 kHz, at least 500 kHz, and/or at least 600 kHz. Additionally or
alternatively, each frequency in the plurality of high-frequency
ranges may be at most 1,000 kHz (1 megahertz (MHz)), at most 800
kHz, at most 750 kHz, at most 600 kHz, at most 500 kHz, at most 400
kHz, at most 200 kHz, at most 150 kHz, at most 100 kHz, and/or at
most 80 kHz. Further, each frequency in the low-frequency ranges
may be at least 20 hertz (Hz), at least 50 Hz, at least 100 Hz, at
least 150 Hz, at least 200 Hz, at least 500 Hz, at least 1 kHz, at
least 2 kHz, at least 3 kHz, at least 4 kHz, and/or at least 5 kHz.
Additionally or alternatively, each frequency in the high-frequency
ranges may be at most 10 kHz, at most 12 kHz, at most 14 kHz, at
most 15 kHz, at most 16 kHz, at most 17 kHz, at most 18 kHz, and/or
at most 20 kHz.
[0102] The communication nodes 114 and 148 may include various
configurations, such as those described in FIGS. 2A and 2B. The
communications node may be disposed on a conduit and/or a tubular
section within the respective wellbore, such as wellbore 102 and
162 and may be disposed along or near a tubular member, such as
tubular member 146 and 164 associated with a cement location and/or
may be disposed upstream of the cement location on tubular members
110, 146 and 164. The communication nodes may be associated with
equipment, may be associated with tubular members and/or may be
associated with the surface equipment. The communication nodes may
also be configured to attach at joints, internal or external
surfaces of tubular members, surfaces within the wellbore, or to
equipment.
[0103] As a specific example, the communications nodes may be
structured and arranged to attach to the surface (e.g., internal or
external surface) of conduits at a selected location. This type of
communication node may be disposed in a wellbore environment as a
communications node (e.g., an intermediate node between the surface
and any communication nodes associated with the equipment and/or
sensors). The communication nodes, which are primarily used for
exchanging data packets within the wellbore, may be disposed on
each tubular member, or may be disposed on alternative tubular
members, while other communication nodes, which are primarily used
for obtaining measurements and then exchanging data packets with
other communication nodes within the wellbore, may be disposed on
tubular members or other wellbore equipment. By way of example, the
communications node may be welded onto the respective surface or
may be secured with a fastener to the tubular member (e.g., may be
selectively attachable to or detachable from tubular member). The
fastener may include the use of clamps (not shown), an epoxy or
other suitable acoustic couplant may be used for chemical bonding.
By attaching to the external surface of the tubular member, the
communication nodes may lessen interfere with the flow of fluids
within the internal bore of the tubular section. Further, the
communication nodes may be integrated into a joint, a tubular
member and/or equipment.
[0104] FIG. 2A is a diagram 200 of an exemplary communication node.
The communication node 200 may include a housing 202 along with a
central processing unit (CPU) 204, memory 206, which may include
instructions or software to be executed by the CPU 204 one or more
encoding components 208, one or more decoding components 210, a
power component 212 and/or one or more sensing components 214,
which communicate via a bus 216. The central processing unit (CPU)
204 may be any general-purpose CPU, although other types of
architectures of CPU 204 may be used as long as CPU 204 supports
the inventive operations as described herein. The CPU 204 may
contain two or more microprocessors and may be a system on chip
(SOC), digital signal processor (DSP), application specific
integrated circuits (ASIC), and field programmable gate array
(FPGA). The CPU 204 may execute the various logical instructions
according to disclosed aspects and methodologies. For example, the
CPU 204 may execute machine-level instructions for performing
processing according to aspects and methodologies disclosed herein.
The memory 206 may include random access memory (RAM), such as
static RAM (SRAM), dynamic RAM (DRAM), synchronous DRAM (SDRAM), or
the like, read-only memory (ROM), such as programmable ROM (PROM),
erasable PROM (EPROM), electronically erasable PROM (EEPROM), or
the like. In addition, the memory 206 may include NAND flash and/or
NOR flash. Further, the power component 212 may be disposed in the
housing 202 and may be configured to provide power to the other
components. The power component 212 may include one or more
batteries.
[0105] To manage the communications, the communication node 200 may
utilize the one or more encoding components 208 and one or more
decoding components 210 within the housing 202. The encoding
components 208, which may include one or more transducers, may be
disposed within the housing 202 and may be configured to generate
an acoustic tones and/or to induce the acoustic tone on a tone
transmission medium. The one or more decoding components 210, which
may include one or more transducers, may be disposed within the
housing 202 and may be configured to receive acoustic tones from
the tone transmission medium. The encoding and decoding components
208 and 210 may include instructions stored in memory and utilized
to perform the generation of the acoustic tones or decoding of the
acoustic tones along with compression or decompression of the data
packets into the acoustic tones. The encoding component 208 and
decoding component 210 may utilize the same transducer in certain
configurations.
[0106] The one and/or more sensing components 214 (e.g., sensors,
which may be used to obtain properties of the fluid in the
wellbore) may be configured to obtain sensing data and communicate
the obtained measurement data to other communication nodes. By way
of example, the sensing components 214 may be configured to obtain
pressure measurements, temperature measurements, fluid flow
measurements, vibration measurements, resistivity measurements,
capacitance measurements, strain measurements, acoustics
measurements, stimulation and/or hydraulic fracture properties
measurements, chemicals measurements, position measurements and
other suitable measurements. By way of example, the sensing
components 214 may be configured to obtain measurements associated
with the detection of changes in density, changes in gamma ray
emissions, changes in temperature, changes in pressure and/or
specific property to monitor the location of the cementing fluid
and/or other fluids used for cementing installations. In addition,
the sensing component may be used to detect voids or gaps in the
cement, as well.
[0107] In yet another exemplary configuration, FIG. 2B is an
exemplary cross sectional diagram of a communications node 250 that
may be used in the system. The view of the communication node 250
is along the longitudinal axis. The communications node 250
includes a housing 252, which may be fabricated from carbon steel
or other suitable material to avoid corrosion at the coupling. The
housing 252 is dimensioned to provide sufficient structural
strength to protect internal components and other electronics
disposed within the interior region. By way of example, the housing
252 has an outer wall 260, which may be about 0.2 inches (0.51
centimeters (cm)) in thickness. A cavity 262 houses the
electronics, including, by way of example and not of limitation, a
power source 254 (e.g., one or more batteries), a power supply wire
264, a first electro-acoustic transducer 256, a second
electro-acoustic transducer 258, and a circuit board 266. The
circuit board 266 may preferably include a micro-processor or
electronics module that processes acoustic signals.
[0108] For communication between communication nodes, the first
transducer 256 and the second transducer 258, which may each be
electro-acoustic transducers, are provided to convert acoustical
energy to electrical energy (or vice-versa) and are coupled with
outer wall 260 on the side attached to the tubular member. As an
example, the first transducer 256, which may be configured to
receive acoustic signals, and a second transducer 258, which may be
configured to transmit acoustic signals, are disposed in the cavity
262 of the housing 252. The first and second transducers 256 and
258 provide a mechanism for acoustic signals to be transmitted and
received from node-to-node, either up the wellbore or down the
wellbore. In certain configurations, the second electro-acoustic
transducer 258, configured to serve as a transmitter, of
intermediate communications nodes 250 may also produce acoustic
telemetry signals. Also, an electrical signal is delivered to the
second transducer 258 via a driver circuit. By way of example, a
signal generated in one of the transducers, such as the second
transducer 258, passes through the housing 252 to the tubular
member, and propagates along the tubular member to other
communications nodes. As a result, the transducers that generates
or receives acoustic signals may be a magnetostrictive transducer
(e.g., including a coil wrapped around a core) and/or a
piezoelectric ceramic transducer. Regardless of the specific type
of transducer, the electrically encoded data are transformed into a
sonic wave that is carried through the walls of a tubular member in
the wellbore. In certain configurations, a single transducer may
serve as both the transmitter and receiver.
[0109] Further, the internals of communications nodes 250 may
include a protective layer 268. The protective layer 268 resides
internal to the wall 260 and provides an additional thin layer of
protection for the electronics. This protective layer provides
additional mechanical durability and moisture isolation. The
intermediate communications nodes 250 may also be fluid sealed with
the housing 252 to protect the internal electronics. One form of
protection for the internal electronics is available using a
potting material.
[0110] To secure the communication node to the tubular member, the
intermediate communications nodes 250 may also optionally include a
shoe 270. More specifically, the intermediate communications nodes
250 may include a pair of shoes 270 disposed at opposing ends of
the wall 260. Each of the shoes 270 provides a beveled face that
helps prevent the node 250 from hanging up on an external tubular
body or the surrounding earth formation, as the case may be, during
run-in or pull-out.
[0111] To enhance the performance, the communication nodes may be
configured to manage different types of wireless networks. For
example, a communication node may be configured to operate with
different types of networks and may use different frequencies to
exchange data, such as low frequencies, high frequencies and/or
radio frequencies. Accordingly, the communication nodes may be
configured to communicate with each of the types of communication
networks and/or may be configured to transmit with one type of
communication network and receive with another type of
communication network. In certain configurations, the acoustic
waves may be communicated in asynchronous packets of information
comprising various separate tones. In other configurations, the
acoustic telemetry data transfer may involve multiple frequency
shift keying (MFSK). Any extraneous noise in the signal is
moderated by using well-known 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, one or more bandpass filters.
[0112] As may be appreciated, the method of cementing installation
may include monitoring the process to enhance the operations. The
monitoring of the cementing installation may be performed in real
time or may be performed concurrently or simultaneously with the
cementing installation. Further, the monitoring may include
obtaining measurement data adjacent to the communication node,
determining one or more properties of the fluids adjacent to the
communication node; determining whether to transmit one or more
notifications based on the determined measurement data or
determined properties, optionally visualizing the cementing fluid
and/or another fluid within the wellbore and adjusting cementing
installation operations based on the notifications. The determining
one or more properties may include computing changes in density,
changes in gamma ray emissions, changes in temperature, changes in
pressure and/or changes in specific properties, which may be used
to monitor the location of the cementing fluid and/or other fluids
used for cementing installations. In other configurations, the
monitoring may include determining voids or gaps in the cement
installation based on the measured properties, optionally
visualizing a portion of the cement and adjusting hydrocarbon
operations based on the determined voids or gaps in the cement. The
determining voids or gaps in the installed cement may include
computing changes in density, changes in gamma ray emissions,
changes in temperature, changes in pressure and/or changes in
specific properties, which may be used to monitor the location of
the cementing fluid and/or other fluids used for cementing
installations. In other configurations, the communication nodes may
be configured to exchange data packets with other devices, such as
one or more hydrophones or other equipment.
[0113] FIG. 3 is an exemplary flow chart 300 in accordance with an
embodiment of the present techniques. The flow chart 300 is a
method for creating, installing and using a communication network
in a wellbore associated with hydrocarbon operations, which include
installing cement within the wellbore. The method may include
creating a communication network and installing the communication
network in a wellbore along with a cement monitoring system, as
shown in blocks 302 to 310. Then, the communication network may be
monitored and hydrocarbon operations are performed, as shown in
blocks 312 to 322.
[0114] To begin, the method involves creating, installing and using
a wireless network for a wellbore along with a cement monitoring
system, as shown in blocks 302 to 310. At block 302, well data for
a subsurface region is obtained. The well data may include seismic
data, electromagnetic data, resistivity data, gravity data, well
log data, core sample data, and combinations thereof. The well data
may be obtained from memory or from the equipment in the wellbore.
The well data may also include the data associated with the
equipment installed within the wellbore and the configuration of
the wellbore equipment and/or hardware capabilities. For example,
the well data may include the composition of the tubular members,
thickness of the tubular members, length of the tubular members,
fluid composition within the wellbore, formation properties,
cementation within the wellbore and/or other suitable properties
associated with the wellbore. At block 304, properties and/or a
cement location are identified. The cementing locations may be
identified based on the predetermined locations near a subsurface
region, which is determined to be unstable or near a location
determined to provide additional structural support. The properties
may be identified because they may be used to monitor the fluids,
such as cementing fluid and/or other fluids used in the cementing
installation operations. The one or more properties may include
density, temperature, gamma ray, flow meter, resistivity,
capacitance, stress, strain, vibration and any combination
thereof.
[0115] Then, at block 306, a communication network configuration is
determined based on the obtained well data, properties and/or
cementing location. The determining the communication network
configuration may include determining locations for sensing
properties, spacing of communication nodes, and one or more
communication configuration settings. The creation of the
communication network may include selecting acoustic frequency band
and individual frequencies; optimizing the acoustic communication
band for each pair of communication nodes; determining coding
method for the network and/or determining selective modes for the
network. Further, the communication network may be configured to
manage different wireless network types. For example, a
communication node may be configured to operate with different
wireless network types, such as low frequency, high frequency
and/or radio frequency. The creation of the communication network
may include performing a simulation with a configuration of
communication nodes, which may include modeling specific
frequencies and/or use of certain wireless communication node types
within specific zones or segments of the wellbore. The simulation
may include modeling the tubular members, the communication of
signals between communication nodes, the sensor locations and
associated data and/or other aspects. The simulation results may
include the computation of time-varying fluid pressure and fluid
compositions and the prediction of signal travel times within the
wellbore. Performing the simulation may also include modeling
fluid, modeling signal transmissions and/or structural changes
based on the network. In addition, the creation of the wireless
network may include installing and configuring the communication
nodes in the wireless network in a testing unit, which may include
one or more tubular members and the associated communication nodes
distributed along the tubular members within a housing or support
structure (e.g., a testing unit disposed above and/or external to
the wellbore). The testing unit may also contain a fluid disposed
around the tubular member within the housing. The modeling may
include theoretical work based on acoustic waveguide theory and/or
a scale above grade lab system tests. Further, the modeling and/or
historical experience may provide an estimate for the frequency
ranges including the preferred tonal frequency separation. The
tonal frequencies may not have to be equally spaced. The frequency
range bandwidth may be constrained by both the acoustics of the
channel and the capability of the transmission and reception
electronics, including transmit and receive transducers. Likewise,
the frequency spacing of the MFSK tones may be constrained by the
tonal purity of the transmitted tone and resolution of the receiver
decoder.
[0116] Then, the communication nodes are configured based on the
communication network configuration, as shown in block 308. The
configuration of the communication nodes may include programming or
storing instructions into the respective communication nodes and
any associated sensors to monitor operations, such as the cementing
installation, and exchange data packets associated with the
operations near the cement location. At block 310, the
communication nodes and cement monitoring system are installed into
the wellbore based on the communication network configuration. The
installation of the communication nodes in the network may include
disposing the communication nodes within the wellbore, which may be
secured to tubular members and/or equipment. The installation of
the communication network, which may include one or more wireless
networks, may include verification of the communication network by
performing testing, may include distribution of the sensors and/or
verification of the communication nodes in the proposed network
configuration.
[0117] Then, the communication network may be monitored and
hydrocarbon operations are performed, as shown in blocks 312 to
322. At block 312, the data packets are exchanged during cementing
installation operations. The exchange of data packets may involve
the transmission of commands for equipment and/or measurement data
and the associated reception of the transmissions. During the
cementing installation operations may include activities during
preparation of the communication nodes prior to installation into
the wellbore or while the equipment is being run into the wellbore,
activities prior to and during the disposing of the cementing fluid
into the wellbore adjacent to the tubular members, and/or after the
installation of the cement. At block 314, one or more properties
are determined for cementing installation operations. The
determination of one or more properties may include computing
comparisons of the measurement data obtained from one or more
sensors. These computations may be associated with the density of
the fluid adjacent to the communication nodes. At block 316, a
determination is made whether an adjustment is needed for cementing
installation operations. The determination may include determining
location of properties associated with the different fluids being
passed through the wellbore by the communication node. The
determination may include transmitting a notification to indicate
that an adjustment is needed or that a specific fluid is adjacent
to the communication node. The communication nodes may be
configured be configured to monitor the materials (e.g., fluids)
within the tubular member, materials (e.g., fluids) and/or outside
the tubular member. If an adjustment is needed, the cementing
installation operations may be adjusted, as shown in block 318. The
adjustment to the cementing installation operations may include
adjusting the fluid being pumped down the wellbore, adjusting the
frequencies of the signals being transmitted, adjusting the
properties that the communication node is monitoring, adjusting the
pressure and/or flow rate of the fluid being pumped into the
wellbore. For example, as the volume inside the tubular member is
known, the detection of a fluid passing the communication node may
change or may be adjusted.
[0118] If an adjustment is not needed, a determination is made
whether cementing installation operations are complete in block
320. The determination of cementing installation operations being
complete may include the top plug has reached the bottom plug
located just above the bottom of the wellbore at the float collar,
the downhole communication nodes may detect a change of property of
the fluid passing by communication node. If the cementing
installation operations are not complete, the data packets may
continue to be exchanged during cementing installation operations,
as shown in block 312. If the cementing installation operations are
complete, the hydrocarbon operations may be performed, as shown in
block 322. The hydrocarbon operations may involve using the
wellbore and associated cement to recovery hydrocarbons from the
subsurface region. The hydrocarbon operations may include
hydrocarbon exploration operations, hydrocarbon development
operations, collection of wellbore data, and/or hydrocarbon
production operations. For example, the communication network may
be used to enhance the cementing installation operations and/or
composition of the fluids being produced from the well. As another
example, the communication network may be used to adjust
hydrocarbon production operations, such as installing or modifying
equipment for a completion associated with the cementing
installation, which may be based on the produced fluids. Further,
the communication network may be utilized to predict hydrocarbon
accumulation within the subsurface region based on the monitored
produced fluids; to provide an estimated recovery factor; and/or to
determine rates of fluid flow for a subsurface region. The
production facility may include one or more units to process and
manage the flow of production fluids, such as hydrocarbons and/or
water, from the formation.
[0119] Beneficially, the method provides an enhancement in the
production, development, and/or exploration of hydrocarbons. In
particular, the method may be utilized to enhance communication
within the wellbore by providing a specific configuration that
optimizes communication for cementing installation operations.
Further, as the communication is provided in real time,
simultaneously or concurrently with cementing installation
operations, the communication network may provide enhancements to
production at lower costs and lower risk. As a result, the present
techniques lessen completion time due to monitoring the cementing
installation in real time, simultaneously or concurrently with the
installation of the cement.
[0120] As may be appreciated, the blocks of FIG. 3 may be omitted,
repeated, performed in a different order, or augmented with
additional steps not shown. Some steps may be performed
sequentially, while others may be executed simultaneously or
concurrently in parallel. By way of example, the communication
network may be adjusted or modified while the data packets are
exchanged by performing various steps. For example, the method may
include performing adjustments or modification of the selected
acoustic frequency bands and individual frequencies. The acoustic
frequency band and individual frequencies may include each
frequency in the plurality of high-frequency ranges, which may be
at least 20 kilohertz (kHz), at least 25 kHz, at least 50 kHz, at
least 60 kHz, at least 70 kHz, at least 80 kHz, at least 90 kHz, at
least 100 kHz, at least 200 kHz, at least 250 kHz, at least 400
kHz, at least 500 kHz, and/or at least 600 kHz. Additionally or
alternatively, each frequency in the plurality of high-frequency
ranges may be at most 1,000 kHz (1 megahertz (MHz)), at most 800
kHz, at most 750 kHz, at most 600 kHz, at most 500 kHz, at most 400
kHz, at most 200 kHz, at most 150 kHz, at most 100 kHz, and/or at
most 80 kHz. Further, each frequency in the low-frequency ranges
may be at least 20 hertz (Hz), at least 50 Hz, at least 100 Hz, at
least 150 Hz, at least 200 Hz, at least 500 Hz, at least 1 kHz, at
least 2 kHz, at least 3 kHz, at least 4 kHz, and/or at least 5 kHz.
Additionally or alternatively, each frequency in the high-frequency
ranges may be at most 10 kHz, at most 12 kHz, at most 14 kHz, at
most 15 kHz, at most 16 kHz, at most 17 kHz, at most 18 kHz, and/or
at most 20 kHz. Further, the acoustic communication bands and
individual frequencies for each pair of communication nodes may be
optimized, which may include determining the explicit MFSK
frequencies. Also, the coding methods for the communication network
may be determined. In addition, the clock ticks may be optimized to
maximize data communication rate. For example, the coding method
may be selected based on availability of frequency bands and/or
communication rates may be compromised if the frequency band is
limited. In certain configurations, the coding method may include
performing frequency combining based on one or more clock ticks per
tone (e.g., one clock tick per tone, two clock ticks per tone,
three clock ticks per tone, and/or more clock ticks per tone) to
achieve more or fewer tones within a frequency band.
[0121] Further, as communication nodes may be configured with a
setting or profile, the settings may include various parameters.
The settings may include acoustic frequency band and individual
frequencies (e.g., acoustic communication band and individual
frequencies for each pair of communication nodes); and/or coding
methods (e.g., establishing how many tones to use for MFSK (2, 4,
8, . . . ) and/or whether to use direct mapping or spread
spectrum), and/or tone detection method, such as FFT, ZCR and other
methods. The settings may include frequency combining using one or
more clock ticks per tone. The tones may be selected to compensate
for poor acoustic propagation.
[0122] Persons skilled in the technical field will readily
recognize that in practical applications of the disclosed
methodology, it is partially performed on a computer, typically a
suitably programmed digital computer or processor based device.
Further, some portions of the detailed descriptions which follow
are presented in terms of procedures, steps, logic blocks,
processing and other symbolic representations of operations on data
bits within a computer memory. These descriptions and
representations are the means used by those skilled in the data
processing arts to most effectively convey the substance of their
work to others skilled in the art. In the present application, a
procedure, step, logic block, process, or the like, is conceived to
be a self-consistent sequence of steps or instructions leading to a
desired result. The steps are those requiring physical
manipulations of physical quantities. Usually, although not
necessarily, these quantities take the form of electrical or
magnetic signals capable of being stored, transferred, combined,
compared, and otherwise manipulated in a computer system.
[0123] It should be borne in mind, however, that all of these and
similar terms are to be associated with the appropriate physical
quantities and are merely convenient labels applied to these
quantities. Unless specifically stated otherwise as apparent from
the following discussions, it is appreciated that throughout the
present application, discussions utilizing the terms such as
"processing" or "computing", "calculating", "comparing",
"determining", "displaying", "copying," "producing," "storing,"
"adding," "applying," "executing," "maintaining," "updating,"
"creating," "constructing" "generating" or the like, refer to the
action and processes of a computer system, or similar electronic
computing device, that manipulates and transforms data represented
as physical (electronic) quantities within the computer system's
registers and memories into other data similarly represented as
physical quantities within the computer system memories or
registers or other such information storage, transmission, or
display devices.
[0124] Embodiments of the present techniques also relate to an
apparatus for performing the operations herein, such as monitoring
and communicating. This apparatus, such as the control unit or the
communication nodes, may be specially constructed for the required
purposes, or it may comprise a general-purpose computer or
processor based device selectively activated or reconfigured by a
computer program stored in the computer (e.g., one or more sets of
instructions). Such a computer program may be stored in a computer
readable medium. A computer-readable medium includes any mechanism
for storing or transmitting information in a form readable by a
machine (e.g., a computer). For example, but not limited to, a
computer-readable (e.g., machine-readable) medium includes a
machine (e.g., a computer) readable storage medium (e.g., read only
memory ("ROM"), random access memory ("RAM"), NAND flash, NOR
flash, magnetic disk storage media, optical storage media, flash
memory devices, etc.), and a machine (e.g., computer) readable
transmission medium (electrical, optical, acoustical or other form
of propagated signals (e.g., carrier waves, infrared signals,
digital signals, etc.)).
[0125] Furthermore, as will be apparent to one of ordinary skill in
the relevant art, the modules, features, attributes, methodologies,
and other aspects of the invention can be implemented as software,
hardware, firmware or any combination of the three. Of course,
wherever a component of the present invention is implemented as
software, the component can be implemented as a standalone program,
as part of a larger program, as a plurality of separate programs,
as a statically or dynamically linked library, as a kernel loadable
module, as a device driver, and/or in every and any other way known
now or in the future to those of skill in the art of computer
programming. Additionally, the present techniques are in no way
limited to implementation in any specific operating system or
environment.
[0126] By way of example, the control unit may include a computer
system that may be used to perform any of the methods disclosed
herein. A central processing unit (CPU) is coupled to system bus.
The CPU may be any general-purpose CPU, although other types of
architectures of CPU (or other components of exemplary system) may
be used as long as CPU (and other components of system) supports
the inventive operations as described herein. The CPU may contain
two or more microprocessors and may be a system on chip (SOC),
digital signal processor (DSP), application specific integrated
circuits (ASIC), and field programmable gate array (FPGA).
[0127] The CPU may execute the various logical instructions
according to disclosed aspects and methodologies. For example, the
CPU may execute machine-level instructions for performing
processing according to aspects and methodologies disclosed
herein.
[0128] The computer system may also include computer components
such as a random access memory (RAM), which may be SRAM, DRAM,
SDRAM, or the like. The computer system may also include read-only
memory (ROM), which may be PROM, EPROM, EEPROM, or the like. RAM
and ROM, which may also include NAND flash and/or NOR flash, hold
user and system data and programs, as is known in the art. The
computer system may also include an input/output (I/O) adapter, a
graphical processing unit (GPU), a communications adapter, a user
interface adapter, and a display adapter. The I/O adapter, the user
interface adapter, and/or communications adapter may, in certain
aspects and techniques, enable a user to interact with computer
system to input information.
[0129] The I/O adapter preferably connects a storage device(s),
such as one or more of hard drive, compact disc (CD) drive, floppy
disk drive, tape drive, etc. to computer system. The storage
device(s) may be used when RAM is insufficient for the memory
requirements associated with storing data for operations of
embodiments of the present techniques. The data storage of the
computer system may be used for storing information and/or other
data used or generated as disclosed herein. The communications
adapter may couple the computer system to a network (not shown),
which may include the network for the wellbore and a separate
network to communicate with remote locations), which may enable
information to be input to and/or output from system via the
network (for example, a wide-area network, a local-area network, a
wireless network, any combination of the foregoing). User interface
adapter couples user input devices, such as a keyboard, a pointing
device, and the like, to computer system. The display adapter is
driven by the CPU to control, through a display driver, the display
on a display device.
[0130] The architecture of system may be varied as desired. For
example, any suitable processor-based device may be used, including
without limitation personal computers, laptop computers, computer
workstations, and multi-processor servers. Moreover, embodiments
may be implemented on application specific integrated circuits
(ASICs) or very large scale integrated (VLSI) circuits. In fact,
persons of ordinary skill in the art may use any number of suitable
structures capable of executing logical operations according to the
embodiments.
[0131] As may be appreciated, the method may be implemented in
machine-readable logic, such that a set of instructions or code
that, when executed, performs the instructions or operations from
memory. By way of example, the computer system includes a
processor; an input device and memory. The input device is in
communication with the processor and is configured to receive input
data associated with a subsurface region. The memory is in
communication with the processor and the memory has a set of
instructions, wherein the set of instructions, when executed, are
configured to: perform certain operations.
[0132] It should be understood that the preceding is merely a
detailed description of specific embodiments of the invention and
that numerous changes, modifications, and alternatives to the
disclosed embodiments can be made in accordance with the disclosure
here without departing from the scope of the invention. The
preceding description, therefore, is not meant to limit the scope
of the invention. Rather, the scope of the invention is to be
determined only by the appended claims and their equivalents. It is
also contemplated that structures and features embodied in the
present examples can be altered, rearranged, substituted, deleted,
duplicated, combined, or added to each other. As such, it will be
apparent, however, to one skilled in the art, that many
modifications and variations to the embodiments described herein
are possible. All such modifications and variations are intended to
be within the scope of the present invention, as defined by the
appended claims.
* * * * *