US20140166272A1

US20140166272A1 - Measurement and control system for a downhole tool

Info

Publication number: US20140166272A1
Application number: US14/091,675
Authority: US
Inventors: Allen R. Harrison
Original assignee: World Energy Systems Inc
Current assignee: World Energy Systems Inc
Priority date: 2012-12-14
Filing date: 2013-11-27
Publication date: 2014-06-19
Also published as: WO2014093029A1

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.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

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

1. Field of the Invention
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.
2. Description of the Related Art
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.
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.
There is now a need for new measurement and control systems for downhole steam generators.

SUMMARY OF THE INVENTION

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.
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.
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.
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

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.

FIG. 1 illustrates a measurement and control system for a downhole steam generator according to one embodiment.

FIG. 2 illustrates a measurement and control system for a downhole steam generator according to one embodiment.

FIG. 3 illustrates a measurement and control system for a downhole steam generator according to one embodiment.

FIG. 4 illustrates a measurement and control system for a downhole steam generator according to one embodiment.

FIG. 5 illustrates a measurement and control system for a plurality of systems and downhole steam generators according to one embodiment.

DETAILED DESCRIPTION

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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 510 a, 510 b. The master system 500 may control, monitor, and/or coordinate the operation of multiple surface measurement and control systems 500 a, 500 b, downhole systems 515 a, 515 b, and thus DHSGs 510 a, 510 b 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 510 a, 510 b and the downhole systems 515 a, 515 b, such as measurement and control systems 100-500 described herein, may be supported by umbilicals 520 a, 520 b that are connected to well heads 530 a, 530 b.
The master system 500 may thus control directly or indirectly one or more of the DHSGs 510 a, 510 b, such as by controlling the output of surface equipment 540 a, 540 b, which may be the same equipment for supplying process fluids, gasses, and/or mixtures to the DHSGs 510 a, 510 b. 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 510 a, 510 b. 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.
In one embodiment, the DHSGs 510 a, 510 b may be positioned in separate wells. In one embodiment, the DHSGs 510 a, 510 b may be position in the same well. For example, the DHSGs 510 a, 510 b 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 510 a, 510 b 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 510 a, 510 b may be positioned in the primary borehole and/or secondary boreholes extending from the primary borehole.
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.
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.
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.
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.

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.