Patent Application
20140166272
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
| Number | Date | Country | |
|---|---|---|---|
| 61737570 | Dec 2012 | US |
