U.S. patent application number 14/091675 was filed with the patent office on 2014-06-19 for measurement and control system for a downhole tool.
This patent application is currently assigned to World Energy Systems Incorporated. The applicant listed for this patent is World Energy Systems Incorporated. Invention is credited to Allen R. HARRISON.
Application Number | 20140166272 14/091675 |
Document ID | / |
Family ID | 50929595 |
Filed Date | 2014-06-19 |
United States Patent
Application |
20140166272 |
Kind Code |
A1 |
HARRISON; Allen R. |
June 19, 2014 |
MEASUREMENT AND CONTROL SYSTEM FOR A DOWNHOLE TOOL
Abstract
A system and method of measuring and controlling the operation
of a downhole steam generator. The system may include surface
and/or downhole control systems for sending and/or receiving
control and measurement signals. The control systems may also
communicate with and control surface and/or downhole equipment for
supplying process fluids, gasses, and/or mixtures to the downhole
steam generator. The control system may control operation of the
downhole steam generator by storing, processing, and/or analyzing
measured data corresponding to one or more downhole steam generator
operations and/or one or more field, formation, reservoir, or other
operating objective.
Inventors: |
HARRISON; Allen R.;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
World Energy Systems Incorporated |
Forth Worth |
TX |
US |
|
|
Assignee: |
World Energy Systems
Incorporated
Forth Worth
TX
|
Family ID: |
50929595 |
Appl. No.: |
14/091675 |
Filed: |
November 27, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61737570 |
Dec 14, 2012 |
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Current U.S.
Class: |
166/250.01 ;
166/53 |
Current CPC
Class: |
E21B 47/00 20130101;
E21B 43/24 20130101 |
Class at
Publication: |
166/250.01 ;
166/53 |
International
Class: |
E21B 44/00 20060101
E21B044/00 |
Claims
1. A measurement and control system, comprising: a downhole steam
generator (DHSG); and a surface control unit functioning to receive
a measurement signal from the DHSG, wherein the surface control
unit functions to control operation of the DHSG in response to the
measurement signal.
2. The system of claim 1, wherein the surface control unit is in
communication with the DHSG via one or more umbilical lines,
wherein the umbilical lines comprise at least one transmission line
for transmitting the measurement signal from the DHSG to the
surface control unit.
3. The system of claim 2, wherein the umbilical lines comprise at
least one transmission line for transmitting a control signal from
the surface control unit to the DHSG to adjust the operation of the
DHSG.
4. The system of claim 3, further comprising a downhole control
unit functioning to receive at least one measurement from the DHSG
and convert the measurement into the measurement signal that is
communicated to the surface control unit.
5. The system of claim 4, wherein the downhole control unit
functions to generate a control signal based on the at least one
measurement and communicate the control signal to the surface
control unit to adjust the operation of the DHSG.
6. The system of claim 5, wherein the surface control unit changes
one or more parameters of at least one process fluid, gas, or
mixture supplied to the DHSG based on the control signal generated
by the downhole control unit.
7. The system of claim 6, wherein the downhole control unit changes
one or more parameters of at least one process fluid, gas, or
mixture supplied to the DHSG based on the at least one measurement
or based on a control signal sent from the surface control unit in
response to the measurement signal.
8. The system of claim 1, wherein the surface control unit
functions to receive oilfield data and control operation of the
DHSG in response to the oilfield data.
9. The system of claim 1, further comprising a plurality of surface
control units controlled by a master control unit, wherein each
surface control unit controls operation of a DHSG.
10. The system of claim 9, wherein the master control unit
functions to receive oilfield data and control operation of the
surface control units in response to the oilfield data.
11. A method of operating a measurement and control system,
comprising: monitoring an operational characteristic of a downhole
steam generator (DHSG) using a surface control unit; receiving a
measurement signal corresponding to the operational characteristic;
and controlling operation of the DHSG in response to the
measurement signal.
12. The method of claim 11, further comprising receiving the
measurement signal via at least one transmission line of an
umbilical that is connected to the DHSG and the surface control
unit.
13. The method of claim 12, further comprising transmitting a
control signal from the surface control unit to the DHSG via at
least one transmission line of the umbilical to adjust the
operation of the DHSG.
14. The method of claim 13, further comprising receiving at least
one measurement from the DHSG using a downhole control unit, and
converting the measurement into the measurement signal that is
communicated to the surface control unit by the downhole control
unit.
15. The method of claim 14, wherein the downhole control unit
generates a control signal based on the at least one measurement
and communicates the control signal to the surface control unit to
adjust the operation of the DHSG.
16. The method of claim 15, further comprising changing one or more
parameters of at least one process fluid, gas, or mixture supplied
to the DHSG based on the control signal generated by the downhole
control unit.
17. The method of claim 16, further comprising changing one or more
parameters of at least one process fluid, gas, or mixture supplied
to the DHSG based on the at least one measurement or based on a
control signal sent from the surface control unit in response to
the measurement signal.
18. The method of claim 11, further comprising receiving oilfield
data using the surface control unit, and controlling operation of
the DHSG in response to the oilfield data.
19. The method of claim 11, further comprising controlling a
plurality of surface control units using a master control unit,
wherein each surface control unit controls operation of a DHSG.
20. The method of claim 19, wherein the master control unit
receives oilfield data and controls operation of the surface
control units in response to the oilfield data.
21. A measurement and control system, comprising: a master control
unit operable to receive oilfield data; a plurality of surface
control units in communication with the master control unit,
wherein each surface control unit controls operation of a downhole
steam generator (DHSG), and wherein the master control unit
functions to control operation of the DHSGs via remote setpoint
adjustments to the surface control units in response to the
oilfield data.
22. The system of claim 21, further comprising a downhole control
unit operable to receive measurement signals from at least one of
the DHSGs and communicate the signals to at least one of the
surface control units.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims benefit of U.S. Patent Application
Ser. No. 61/737,570, filed Dec. 14, 2012, the contents of which are
herein incorporated by reference in its entirety.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] Embodiments of the invention relate to a measurement and
control system for a downhole tool. In particular, embodiments of
the invention relate to a system for measuring the operational
characteristics of a downhole steam generator, controlling the
operation of the downhole steam generator, and performing
diagnostic operations.
[0004] 2. Description of the Related Art
[0005] The general configuration of the surface provision of fuel,
oxidants, and water to a downhole steam generator are known. There
are, however, serious technical difficulties connected to the
ignition, combustion, and production of steam from downhole steam
generators due to the many interacting physical processes involved.
Such physical processes include but are not limited to operating
pressures, operating temperatures, downhole remoteness, feed line
delays, and acoustic feedback.
[0006] Generally, downhole steam generators may have systems at the
surface for providing fuel, oxidant, and water to the wellhead.
These systems, however, are not only remote to the downhole steam
generator, but do not provide a means for feedback into the control
loop the actual measured performance at the downhole steam
generator. In essence, these systems are essentially controlled by
an "open loop" control system wherein there is no measurement of
the system's downhole output that can be used to adjust the
system's operational parameters and thus adjust the system's
downhole output or performance. Previous configurations of downhole
steam generators did not use or need measurement and control
downhole at the downhole steam generator.
[0007] There is now a need for new measurement and control systems
for downhole steam generators.
SUMMARY OF THE INVENTION
[0008] Embodiments of the invention include a measurement and
control system that comprises a downhole tool, such as a downhole
steam generator; and a (surface and/or downhole) control unit that
functions to receive a measurement signal from the downhole tool,
wherein the control unit functions to control operation, output,
and/or performance of the downhole tool in response to the
measurement signal. This may be the feedback and control loop for a
single well DHSG system, for example. The measurement signal may
contain information related to the configuration, output, and/or
performance, etc. of the downhole, wellhead, and/or surface
equipment.
[0009] Embodiments of the invention include a measurement and
control system that comprises a downhole tool, such as a downhole
steam generator; and a (surface and/or downhole) control unit
operable to receive oilfield data, wherein the control unit is
operable to control operation of the downhole tool in response to
the oilfield data.
[0010] Embodiments of the invention include a method of operating a
measurement and control system that comprises measuring and/or
monitoring an operational characteristic of a downhole tool, such
as a downhole steam generator; communicating and/or receiving a
measurement signal corresponding to the operational characteristic;
and controlling operation of the downhole tool using a control unit
in response to the measurement signal.
[0011] Embodiments of the invention include a measurement and
control system that comprises a master control unit that functions
to receive oilfield data; a plurality of surface control units in
communication with the master control unit, wherein each surface
control unit controls operation of a downhole steam generator
(DHSG), and wherein the master control unit is operable to control
operation of the DHSGs via remote setpoint adjustments to each
surface control unit in response to the oilfield data. The remote
setpoint adjustments may be continuously variable. The master
control unit may be an oilfield master controller that controls one
or more individual well surface and/or downhole control units,
which control the operation of one or more downhole steam
generators.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] So that the manner in which the above recited features of
the invention can be understood in detail, a more particular
description of the invention, briefly summarized above, may be had
by reference to embodiments, some of which are illustrated in the
appended drawings. It is to be noted, however, that the appended
drawings illustrate only typical embodiments of this invention and
are therefore not to be considered limiting of its scope, for the
invention may admit to other equally effective embodiments.
[0013] FIG. 1 illustrates a measurement and control system for a
downhole steam generator according to one embodiment.
[0014] FIG. 2 illustrates a measurement and control system for a
downhole steam generator according to one embodiment.
[0015] FIG. 3 illustrates a measurement and control system for a
downhole steam generator according to one embodiment.
[0016] FIG. 4 illustrates a measurement and control system for a
downhole steam generator according to one embodiment.
[0017] FIG. 5 illustrates a measurement and control system for a
plurality of systems and downhole steam generators according to one
embodiment.
DETAILED DESCRIPTION
[0018] Embodiments of the invention include a system for providing
measurement and control of a downhole steam generator ("DHSG"). The
DHSG may be supported from the surface by a wellhead. The system
may provide measurement and control of the DHSG at the surface
and/or downhole. The system may use a signal pathway from the DHSG
to the surface wellhead. In addition to water, fuel, oxidizer,
and/or ignitor lines between the wellhead and the DHSG, the system
may include one or more signal transmission lines for the
measurement and control. The system described herein provides the
means for construction of a "closed loop" control system where the
operational parameters may be adjusted depending upon the system's
actual output and performance and the desired output and
performance. The closed loop control system may include manual
intervention.
[0019] The measurement and control of surface and/or downhole
equipment or delivery equipment, such as pumps, compressors,
valves, etc., and/or DHSGs may involve several subsystems which
have reaction time delays, opportunities for oscillation, pressure
losses, and flow constrictions. As such, the measurements and
control requirements can be complex and highly interactive.
Therefore, the measurement and control system embodiments described
herein optimally serve the distribution system and its control
architecture, wherein the interaction delays are minimized by
keeping the measurement and control within a localized system by
segmenting and isolating sections of the overall system into
focused subsystems.
[0020] The measurement and control systems 100-500 described herein
may include a control unit having programmable central processing
units operable with memory, mass storage devices, input/output
controls, and/or display devices. The control unit may include
support circuits such as power supplies, clocks, cache, and/or
input/output circuits. The control unit may be operable to process,
store, analyze, send, and/or receive data from sensors and/or other
devices, and may be operable to control one or more devices that
are in (wired and/or wireless) communication with the systems. The
control unit may be configured with software/algorithms that
process input signals/commands to generate output signals/commands
based on an operational characteristic of the DHSG. The control
units may control the DHSG operation based on input/output and/or
pre-programmed knowledge derived from reservoir/well analysis (a
priori or real time) and/or the DHSG performance.
[0021] In one embodiment, the control unit may be and/or include an
analog or digital device that has a preprogrammed response upon
receiving a particular input. For example, one or more basis analog
control devices, such as signal amplifiers, with simple analog
input and analog response may be used with the measurement and
control systems 100-500 described herein. Another example is a
bimetal thermostat for (at least partially) opening and closing an
orifice within the measurement and control systems 100-500
described herein. Further examples include digital circuits and
switches. Reduced command processors may be used to operate these
analog or digital devices. An input, such as a measurement, is
received by the control unit or analog or digital device, and a
response is given by the control unit or analog or digital device
to control (such as change) the operation of a DHSG. Numerous types
of analog or digital devices known in the art may be used with the
measurement and control systems 100-500 in both uphole and downhole
operation.
[0022] Although the embodiments described herein relate to a DHSG,
embodiments of the invention may be used with any other types of
downhole tools. One example of a DHSG that may be used with the
embodiments described herein is shown and described as DHSG 10, 100
in U.S. Patent Application Publication No. 2011/0127036, filed on
Jul. 15, 2010. Another example of a DHSG that may be used with the
embodiments described herein is shown and described as system 1000
in U.S. Patent Application Publication No. 2011/0214858, filed on
Mar. 7, 2011. The contents of each of the above referenced patent
application publications are herein incorporated by reference in
their entirety.
[0023] FIG. 1 illustrates one embodiment of a measurement and
control system 100 for measuring the operational characteristics of
and controlling the operation of a DHSG 110. The system 100 may
also measure and control surface equipment 140 used for supplying
water, fuel, oxidant, ignition, and/or other process fluids,
gasses, mixtures, and/or other process consumables such as ignition
power, to the DHSG 110. The DHSG 110 may be supported at the
surface by a wellhead 130 via one or more umbilicals 120. The
umbilicals 120 may include one more conduits/lines for
communicating process fluids, gasses, mixtures, and/or other
process consumables such as ignition power, to and from the DHSG
110, as well as one or more conduits/lines for communicating
mechanical, electrical, and/or hydraulic signals to and from the
DHSG 110.
[0024] The system 100 may receive and send signals directly to and
from the DHSG 110. One or more measurement signals may be
transmitted directly to the system 100. One or more control signals
may be directly wired into the DHSG 110. In addition to water,
fuel, oxidizer, and/or ignitor lines from the surface, one or more
electrical signal transmission lines may be included to communicate
with the DHSG 110. The transmission lines may carry analog and/or
digital signals, and may use one or more transmission methods or
combination of transmission modes.
[0025] In one embodiment, one or more sensors may be placed at or
near the DHSG 110. The sensors may measure the operational
characteristics or performance of the DHSG 110, such as
temperatures, pressures, flow rates, volumes, generation of steam,
and/or the type, volume, quantity, and/or quality of any
reactant/injectant materials, e.g. process fluids, gasses,
mixtures, and/or other process consumables such as ignition power,
flowing into and/or out of the DHSG 110. Process fluids, gasses,
and/or mixtures may include, but are not limited to, water, steam,
air, oxygen, carbon dioxide, hydrogen, nitrogen, methane, syngas,
nanocatalyst, nanoparticles, fracturing materials, propants, and/or
any other materials that may positively or negatively affect a
formation, a reservoir within the formation, and/or hydrocarbons
within the reservoir. Sensors may include, but are not limited to,
pressure, temperature, flow, acoustic, electromagnetic, NMR,
nuclear, density, and/or fluorescent detector sensors. In one
embodiment, control valves, ignitors, glowplugs, motors, pumps
and/or other constriction or expansion devices may also be placed
at the DHSG 110 to adjust its performance and ability to inject
materials (such as steam and other injectants) into a reservoir.
Process fluids, gasses, and/or mixtures may be controlled by final
control elements, which may be located at the surface and/or
downhole, and which may be passive or active (flow restrictors),
digital (on/off), and/or modulating proportional devices.
[0026] One or more measurement signals, originating from the DHSG
110, may be transmitted to the system 100 (1) directly via an
electrical or optical signal in either analog or digital form; (2)
indirectly to a subsurface subsystem where they are converted to
electrical or optical signaling where they are then transmitted to
the surface via analog or digital telemetry; and/or (3) by
intelligent indirect transmission to the surface with compression
and multiplexing of information occurring downhole prior to
transmission via analog or digital telemetry using optical or
electrical signaling.
[0027] One or more control signals, originating from the system
100, may be transmitted to the DHSG 110 (1) directly via analog or
digital signals to each or combined control mechanisms of the DHSG
110; (2) indirectly via analog or digital signals via electrical or
optical signaling to an intermediate control system located
downhole, such as nearby the DHSG 110; and/or (3) by intelligent
indirect transmission with compression and multiplexing of
information from the surface to an intermediate control system
located downhole, such as nearby the DHSG 110.
[0028] The system 100 may control operation of the DHSG 110 based
on or in response to one or more measurement signals by changing
the operational characteristics and/or condition of one or more
final control elements (which may be located at the surface and/or
downhole), which in turn change the state of the process fluids,
gasses, and/or mixtures of interest at the DHSG 110. The system 100
may generate and transmit one or more control signals to the DHSG
110 (or downhole system in control of the DHSG 110) to control the
operation of the DHSG 110. The system 100 may control one or more
components of the DHSG 110.
[0029] FIG. 2 illustrates one embodiment of a measurement and
control system 200 for measuring the operational characteristics of
and controlling the operation of a DHSG 210. The system 200 may
receive performance measurements from the DHSG 210. In particular,
a downhole system 215 (such as a measurement interface) may receive
sensor measurements from the DHSG 210 where they may be converted
to digital form, averaged, fast Fourier transformed (FFT), filtered
and/or otherwise analyzed. This information may then be compressed
or multiplexed and digitally transmitted to the surface through the
umbilical 220 and wellhead 230 to the system 200. The system 200
may use this information to control surface equipment 240 and the
materials and/or process fluids, gasses, and/or mixtures delivered
to the DHSG 210 to adjust the operation of the DHSG 210. In one
embodiment, there may not be any control systems or parameters
adjusted downhole. The downhole system 215 packages the downhole
sensor information for transmission to the surface system 200.
[0030] FIG. 3 illustrates one embodiment of a measurement and
control system 300 for measuring the operational characteristics of
and controlling the operation of a DHSG 310. A downhole system 315,
such as the measurement and control systems 100-500 described
herein, may be local to the DHSG 310 so as to reduce control
reaction lag time, provide for multiple and processed performance
measurements of the DHSG 310, and/or provide a means for
distributed control of the DHSG 310. The downhole system 315 may be
supported by umbilicals 320 that are connected to well head 330 at
the surface. Control signals may be generated by and transmitted
from the surface system 300 to the downhole system 315 to control
operation of the DHSG 310. Control signals may be generated by and
transmitted from the downhole system 315 to the surface system 300
to control operation of the DHSG 310. Measurement signals (such as
sensor measurements) may be processed and used by the surface
system 300 and/or the downhole subsystem 315. The control signals
originating from the downhole system 315 may be transmitted to the
surface system 300 via one or more transmission lines within or
separate from umbilicals 320. These control signals may serve as
requests to the surface system 300. The surface system 300 may
respond to the requests by changing the state of one or more final
control elements, which in turn change the state or condition of
the process fluids, gasses, and/or mixtures provided to or by the
DHSG 310.
[0031] FIG. 3 illustrates ten measurement signals 1-10 and ten
control signals A-J communicated between the systems 300, 315 and
DHSG 310. The DHSG 310 may produce measurement signals 6-10, and
may be controlled by control signals G-J. Measurement signals 6 and
7 are transmitted to the surface system 300, while measurements
signals 8-10 are processed by the downhole system 315 (and may not
be transmitted to the surface). Measurement signals 4 and 5 may be
generated by the downhole system 315 (and may derived from signals
8-10 and others) and may be transmitted to the surface system 300.
Similarly, control signal G from the surface may be directly
transmitted to the DHSG 310 by the downhole system 315. The
downhole system 315 may synthesize control signals H-J from the
controls signals E-G from the surface system 300.
[0032] In one embodiment, a portion of the control system for the
DHSG 310 is placed within the downhole system 315. All, a portion,
or none of the measurement signals are sent to the surface system
300, and, similarly, all, a portion, or none of the control signals
are generated by the downhole system 315. The downhole control may
be implemented within the downhole system 315 by any combination of
analog or digital electronic circuitry. Analog circuitry includes,
but not limited to, analog filters, comparators, amplifiers,
current loop drivers, etc. Digital circuitry includes, but not
limited to, D-A, A-D conversion, digital signal processors, control
CPUs, microcontrollers, FPGA's, etc.
[0033] In one embodiment, control signals from the surface system
300 may be interpreted by the downhole system 315, which then
drives one or more control processes of flow, pressure, ignition,
injection, etc. via electrical signals to control valves, igniters,
etc. of the DHSG 310. Similarly, measurement signals of the DHSG
310 performance will feed back into the downhole system 315, and
may be used within the downhole system 315 control loop. The
downhole system 315 may send measurements and control requests to
the surface system 300.
[0034] In one embodiment, the system 300 includes a control
architecture, which consists of shared information spaces and
distributed or layered control interaction mechanisms. The surface
system 300 may pass control signals to the downhole system 315,
which, in turn, determines settings for one or more local
performance control parameters dependent upon sensor measurements.
In this manner, the closed loop control for the downhole system 315
and DHSG 310 is completely downhole and only informational
measurements of performance are transmitted up-hole.
[0035] FIG. 4 illustrates one embodiment of a measurement and
control system 400 for measuring the operational characteristics of
and controlling the operation of a DHSG 410. The DHSG 410 and a
downhole system 415, such as measurement and control systems
100-500 described herein, may be supported by umbilicals 420 that
are connected to well head 430. Measurement information or other
oilfield data from one or more wells in the same and/or surrounding
fields may be used to set the operating parameters of the DHSG 410.
The measurement information or other oilfield data may be
communicated to the surface system 400 to determine and control the
operating parameters of the DHSG 410, such as by controlling the
output of surface equipment 440 supplying process fluids, gasses,
and/or mixtures to the DHSG 410, or by modulating external set
points or parameters of one of the measurement and control systems
100-300 described herein.
[0036] In one embodiment, the various measurements from the
surrounding field may be used to set the desired operation of the
DHSG 410. The interaction between the DHSG 410, and if applicable
other adjacent or nearby DHSG's, and the reservoir or formation is
monitored, and the results are used to adjust the desired operating
setpoints and performance levels and control of the DHSG 410. The
measured field information may be input into a specific, complex
model (within the system 400) for the field and its interaction
with the DHSG 410. From this model, the required setpoints of the
DHSG 410 may be determined to achieve the desired performance of
the injection well. The resulting impact on the reservoir or
formation by the DHSG 410 may be measured, and this information may
be feed back into the model to determine the real-time setpoints
for the operating parameters of the DHSG 410.
[0037] FIG. 5 illustrates one embodiment of a measurement and
control system 500 for measuring the operational characteristics of
and controlling the operation of one or more DHSGs 510a, 510b. The
master system 500 may control, monitor, and/or coordinate the
operation of multiple surface measurement and control systems 500a,
500b, downhole systems 515a, 515b, and thus DHSGs 510a, 510b from a
central control point. The master system 500 may use measurement
information or other oilfield data from one or more wells 1-N in a
field. The DHSGs 510a, 510b and the downhole systems 515a, 515b,
such as measurement and control systems 100-500 described herein,
may be supported by umbilicals 520a, 520b that are connected to
well heads 530a, 530b.
[0038] The master system 500 may thus control directly or
indirectly one or more of the DHSGs 510a, 510b, such as by
controlling the output of surface equipment 540a, 540b, which may
be the same equipment for supplying process fluids, gasses, and/or
mixtures to the DHSGs 510a, 510b. The master system 500
"orchestrates" multiple DHSGs, and may use, in addition to
information coming from each DHSG, additional information related
to the overall field, formation, and/or reservoir and resulting
affects of the one or more DHSGs. This additional information may
be a set programmed sequence of DHSG on/off and other control
options. This additional information may be measurements made
within the field that would provide feedback to the orchestrated
operation of one or more DHSGs 510a, 510b. This information may
include oil flow, porosity, temperature, pressure, viscosity,
and/or other characteristics as observed from one or more wells in
the field. In one embodiment, one or more master systems 500 may be
used.
[0039] In one embodiment, the DHSGs 510a, 510b may be positioned in
separate wells. In one embodiment, the DHSGs 510a, 510b may be
position in the same well. For example, the DHSGs 510a, 510b may be
disposed in a serial configuration, one above the other or spaced
apart for injecting fluids into one or more reservoirs. For further
example, the DHSGs 510a, 510b may be disposed in separate wells or
branches of a multilateral well (e.g. a primary borehole having one
or more secondary or lateral boreholes extending from the primary
borehole) for injecting fluids into one or more reservoirs. One or
more DHSGs 510a, 510b may be positioned in the primary borehole
and/or secondary boreholes extending from the primary borehole.
[0040] The measurement and control systems 100-500 described herein
may be operable to conduct one or more diagnostic tests, and
perform one or more corrective actions based on the diagnostic
tests. The measurement and control systems 100-500 may monitor the
wellbore operations for deterioration or failing of one or more
components of the systems, such as the steam generator, the
umbilical, the well head, and/or surface equipment, and may then
apply corrective measures to prevent system and/or operation
failure. In this manner, the measurement and control systems
100-500 may predict potential malfunctions and/or maintenance
requirements, and may be utilized as a preventative maintenance
tool.
[0041] In one embodiment, the measurement and control systems
100-500 may be programmed with one or more maintenance schedules of
one or more components of the systems, such as the steam generator,
the umbilical, the well head, and/or surface equipment, and may
provide an indication of a scheduled maintenance before a component
fails or reaches the end of its operating life. In one embodiment,
the measurement and control systems 100-500 may monitor operational
parameters such as temperature, pressure, fuel/oxygen/water/steam
type and purity, and wellbore environment conditions (e.g. acidity,
gas cut, etc.), all of which will affect the performance and life
of the components of the systems and wellbore equipment. In one
embodiment, the measurement and control systems 100-500 may
optimize the performance of the system components and wellbore
operations to maximize the life of the system components and/or
wellbore production.
[0042] One or more of the embodiments of the systems 100, 200, 300,
400, and 500 described herein may be combined, interchanged, and/or
duplicated to form additional measurement and control systems.
[0043] While the foregoing is directed to embodiments of the
invention, other and further embodiments of the invention may be
devised without departing from the basic scope thereof, and the
scope thereof is determined by the claims that follow.
* * * * *