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BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates broadly to apparatus and processes for recovering fluid by injection of hot vapor or other heat assisted production techniques. More particularly, this invention relates to apparatus and processes for recovering natural bitumen and other forms of heavy oil by heat assisted production techniques. 
     2. Description of Related Art 
     There are many petroleum-bearing formations from which oil cannot be recovered by conventional means because the oil is so viscous that it will not flow from the formation to a conventional oil well. Examples of such formations are the bitumen deposits in Canada and in the United States and the heavy oil deposits in Canada, the United States, and Venezuela. In these deposits, the oil is so viscous, under the prevailing temperatures and pressures within the formations, that it flows very slowly (or not at all) in response to the force of gravity. Heavy oil is an asphaltic, dense (low API gravity), and viscous oil that is chemically characterized by its contents of asphaltenes (very large molecules incorporating most of the sulfur and perhaps 90 percent of the metals in the oil). Most heavy oil is found at the margins of geological basins and is thought to be the residue of formerly light oil that has lost its light-molecular-weight components through degradation by bacteria, water-washing, and evaporation. Natural bitumen (often called tar sands or oil sands) shares the attributes of heavy oil but is yet more dense and more viscous. 
     Heavy oil is typically recovered by injecting super-heated steam into the reservoir, which reduces the oil viscosity and increases the reservoir pressure through displacement and partial distillation of the oil. Steam may be injected continuously utilizing separate injection and production wells. Alternatively, the steam may be injected in cycles so that a well is used alternatively for injection and production (the so called “huff and puff” process). 
     Natural bitumen is so viscous that it is immobile in the reservoir. For oil sand deposits less than 70 meters deep, bitumen is recovered by mining the sands, then separating the bitumen from the reservoir rock by hot water processing, and finally upgrading the natural bitumen to synthetic crude oil. In deeper bitumen deposits, steam is injected into the reservoir in order to mobilize the oil for recovery. The product may be upgraded onsite or mixed with dilutent and transported to an upgrading facility. 
       FIGS. 1A and 1B  illustrate a system for recovery of oil from a reservoir of natural bitumen. This system, which is commonly referred to as a steam-assisted gravity drainage system, employs a stacked pair of horizontal wells disposed in a reservoir  2  of natural bitumen which is typically sandwiched between a top layer of caprock  4  and a bottom layer of shale  6 . The upper well  8 , referred to as the injection well, is used to inject a hot vaporized fluid (such as steam and/or a solvent vapor) into the bitumen reservoir  2 . The hot vaporized fluid heats the formation and mobilizes the bitumen. Gravity causes the mobilized bitumen to move toward the lower well  10 , referred to as the production well, as shown in  FIG. 1B . The bitumen fluid is then pumped by an artificial lift system to the surface through the production well  10 . 
     Recent advances in electrical submersible pump (ESP) designs (such as the HOTLINE ESP commercially available from Schlumberger) are capable of operation in the expected temperature ranges (e.g., greater than 205° C.) of many heat assisted production techniques including the steam-assisted drainage system of  FIGS. 1A and 1B  for bitumen recovery. However, the downhole ESP can be damaged (or its operational lifetime adversely impacted) by the periodic direct breakthrough of injection vapor, which is referred to herein as “injection vapor breakthrough.” The injection vapor is commonly supplied to the injection well  8  at a temperature on the order of 260° C. When injection vapor breakthrough occurs, injection vapor enters the production well without experiencing significant cooling relative to its hot temperature as supplied to the injection well. The high temperature of the injection vapor breakthrough can damage the downhole ESP when it is running and/or can adversely impact its operational life. 
     Similar problems can be experienced by surface equipment, such as a multiphase flow meter. The multiphase flow meter continually measures the individual phases of the production fluid without the need for prior separation, which allows for quick and efficient well performance trend analysis and immediate well diagnostics. Such multiphase flow meters can be damaged, or their operational life shortened significantly, by the high temperatures that result from injection vapor breakthrough. 
     Thus, there remains a need in the art to provide mechanisms that protect downhole equipment and surface equipment from the high temperatures that result from the breakthrough of injection vapor in heat assisted production applications. 
     BRIEF SUMMARY OF THE INVENTION 
     It is therefore an object of the invention to provide a mechanism that protects downhole equipment from the high temperatures that result from the breakthrough of injection vapor in heat assisted production applications. 
     It is another object of the invention to provide a mechanism that protects surface equipment from the high temperatures that result from the breakthrough of injection vapor in heat assisted production applications. 
     In accord with these objects, which will be discussed in detail below, an automatic control system is provided that protects downhole equipment (such as ESPs) as well as surface equipment (such as multiphase flowmeters) from the high temperatures that result from the breakthrough of injection vapor. With respect to downhole equipment protection, the system operates to derive an estimate of the temperature of the production fluid at a location upstream from the downhole equipment. A first alarm signal is generated in the event that this temperature exceeds a threshold temperature characteristic of injection vapor breakthrough. Supply of electric power to the downhole equipment is automatically shut off in response to receiving the first alarm signal. With respect to surface equipment, a bypass path is provided together with a bypass valve for selectively directing production fluid to the bypass path. The system operates to derive an estimate of the temperature of the production fluid at a surface location upstream from the surface equipment. A second alarm signal is generated in the event that this temperature exceeds a threshold temperature characteristic of injection vapor breakthrough. The bypass valve is automatically controlled to direct production fluid to the bypass path in response to receiving the second alarm signal. 
     It will be appreciated that by automatically turning off the downhole equipment while injection vapor breakthrough passes by the downhole equipment, damage to the downhole equipment can be avoided and its operational life increased. Similarly, by directing the injection vapor breakthrough along a bypass path, damage to the surface equipment can be avoided and its operational life increased. 
     According to one embodiment of the invention, the temperature measurements of the system are derived by optical time-domain reflectometry of optical pulses that propagate along an optical fiber that extends to appropriate measurement locations along the production tubing. 
     Additional objects and advantages of the invention will become apparent to those skilled in the art upon reference to the detailed description taken in conjunction with the drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIGS. 1A and 1B  are pictorial illustrations of a steam-assisted gravity drainage system. 
         FIG. 2A  is a pictorial illustration of the downhole components of an improved steam-assisted gravity drainage system in accordance with the present invention. 
         FIG. 2B  is a functional block diagram of the surface components of the improved steam-assisted gravity drainage system in accordance with the present invention. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     In the description, the terms “downstream” and “upstream”; “downhole” and “uphole”; “down” and “up”; “upward” and “downward”; and other like terms indicate relative positions in a wellbore relative to the direction of fluid flow therein. In other words, fluid flows from “upstream” locations and elements to “downstream” locations and elements. Note that when applied to apparatus and methods for use in wellbores that are deviated or horizontal, such terms may refer to a left to right relationship, right to left relationship, or other relationships as appropriate. 
     Turning now to  FIGS. 2A and 2B , there is shown an improved steam-assisted gravity drainage system  100  in accordance with the present invention. The system incorporates an automatic control system that protects downhole equipment and surface equipment from the high temperatures that result from the breakthrough of injection vapor. 
     As is conventional, the system  100  employs a stacked pair of horizontal wells disposed in a reservoir  102  of natural bitumen, which is typically sandwiched between a top layer of caprock  104  and a bottom layer of shale (not shown). An injection well  108  injects a hot vaporized fluid, such as steam, carbon dioxide, and/or a solvent, into the bitumen reservoir  102  as is well known in the art. The injection of the hot vaporized fluid heats the reservoir  102  and mobilizes the bitumen. Gravity causes the mobilized bitumen to move toward the production well  110  as shown in  FIG. 1B . 
     The production well  110  employs a casing  111  that is cemented in place. The casing  111  has a plurality of perforations  112  which allow fluid communication between the interior of the casing  111  and the bitumen reservoir  102 . Production tubing  113  extends within the casing  111  from the surface to an ESP assembly  114  disposed within the casing  111 . A stinger assembly  115  extends within the casing  111  between the downhole end of the ESP assembly  114  and a production packer  116  (if used). An isolation packer  117  and a sump packer  118  may or may not be used to isolate the production zone within the lateral section of the casing  111 . A tubing string  119  (sometimes referred to as coiled tubing, workstring, or other terms well known in the art) extends from the production packer  116  (if used) to the sump packer  118  (if used). A portion of the tubing string  119  in the vicinity of the perforations  112  includes a screen member  121  as is well known in the art. Generally, the screen member  121  has a perforated base pipe with filter media disposed thereon to provide the necessary filtering. Such filter media can be realized, for example, from wire wrapping, mesh material, pre-packs, multiple layers, woven mesh, sintered mesh, foil material, wrap-around slotted sheet, or wrap-around perforated sheet. Many common screen members include a spacer that offsets the filter media from the base pipe in order to provide a flow annulus therebetween. Typically, granular filtercake material, such as a gravel pack or resin-based pack, is injected into the wellbore such that it fills the annular space between the screen member  121  and the well casing  111  and perforations  112  therethough. 
     The ESP assembly  114  is powered by electrical energy delivered thereto from the surface. The ESP assembly  114  pumps mobilized bitumen fluid that flows into the perforations  112  and screen member  121  through the tubing string  119  and stinger assembly  115  and up the production tubing  113  to the surface. The ESP assembly  114  may comprise a variety of components depending on the particular application or environment in which it is used. The exemplary ESP assembly  114  shown in  FIG. 2A  includes a handling sub  114 - 1 , a discharge head  114 - 2 , a pump section  114 - 3 , a protector/seal section  114 - 4 , a motor section  114 - 5 , and a motor plug  114 - 6 . The handling sub  114 - 1  is used to handle the ESP assembly  114  during installation and acts as a connector to the production tubing thread that leads to the top of the production tubing  113 . The pump section  114 - 3  provides mechanical elements (e.g., vanes, pistons) that pump mobilized bitumen fluid from intake ports and out the discharge head  114 - 2  for supply to the surface. The intake ports provide a fluid path for drawing fluid into the pump section  114 - 3  from the reservoir  102  via the stinger  115 , the tubing string  119 , the screen member  121  and the perforations  112 . The protector/seal section  114 - 4  transmits torque generated by the motor section  114 - 5  to the pump section  114 - 3  for driving the pump. The protector/seal section  114 - 4  also provides a seal against fluids/contaminants entering the motor section  114 - 5 . The motor section  114 - 5  provides an electric motor assembly that is driven by electric power supplied thereto from the surface. The motor plug  114 - 6 , which is disposed on the bottom end of the ESP assembly  114 , provides an additional clamping position as well as protecting the ESP assembly when running the completion. A downhole monitoring tool (not shown) is typically provided between the motor section  114 - 5  and the motor plug  114 - 6 . The downhole monitoring tool provides for monitoring/telemetry of downhole conditions/parameters at or near the pumping location. 
     As shown in  FIG. 2B , at the surface the production tubing  113  extends beyond the casing  111 . A multiphase flowmeter  151  is provided in the production tubing path. The multiphase flow meter  151  continually measures the individual phases of the production fluid flowing through the production tubing  113  without the need for prior separation, which allows for quick and efficient well performance trend analysis and immediate well diagnostics. A bypass path around the multiphase flowmeter  151  is provided by a diverter valve  153  and diverter tubing section  155 . A second diverter valve  157  may be used to divert vapor fluid and possibly other production fluids that flow through the bypass path to a vapor bypass tank or other suitable processing means. The diverter valve  153  and the diverter valve  157  are electronically actuated (e.g., open and closed) and controlled by a system control module  159 . 
     An ESP control module  161  is provided that controls the operation of the ESP motor section  114 - 5  ( FIG. 2A ) of the ESP assembly  114  via power cables  163  therebetween. The power cables  163  (which are typically armored-protected, insulated conductors) extend through the wellhead outlet  159  and downward along the exterior of the production tubing  113  in the annular space between the production tubing  113  and the casing  111 . When it is present, telemetry signals generated by the downhole monitoring tool of the ESP assembly  114  are communicated over the power cables  163 . The ESP control module  161  is capable of selectively turning on and shutting off the supply of power to the ESP motor section  114 - 5  supplied thereto via the power cables  163 . The ESP control module  161  also may incorporate variable-speed drive functionality that adjusts pump output by varying the operational motor speed of the ESP motor section  114 - 5 . In steam-assisted gravity drainage system wells the temperatures are generally too high to use conventional pressure and temperature sensors to shutdown the ESP. Consequently, slugs of hot fluid are presently allowed to pass through the pumps, with the attendant detrimental effects. In contrast, the present invention&#39;s use of a fiber optic distributed temperature sensing (DTS) system to detect a hot slug of fluid allows the pump to be shutdown before the slug of hot fluid reaches it. 
     Therefore, production well  110  employs a fiber optic distributed temperature sensing and monitoring system realized by a surface-located fiber optic temperature sensing and monitoring module  165  with an optical fiber  167  extending therefrom. In the illustrative embodiment, the optical fiber  167  is deployed as a control line that extends along the bypass path, then along the production tubing  113  and down through the wellhead outlet  159  to the stinger assembly below the ESP assembly  114 . Similar to the power cables  163 , the fiber optic control line  167  extends downward along the exterior of the production tubing  113  in the annular space between the production tubing  113  and the casing  111 . The fiber optic control line  167  may terminate at a predetermined position downstream of the ESP assembly  114  (e.g., adjacent the stinger assembly  111 ) as shown. The depth at which the fiber optic control line  167  may be terminated will be determined so as to detect a hot slug of fluid sufficiently early to shutdown the ESP and allow the motor to cool before the hot slug passes. Alternatively, the fiber optic control line  167  may continue further into the wellbore of the production well  110 , for example to the vicinity of the production zone. In yet other embodiments, the fiber optic control line may form a loop that returns back up the production well  110  for double-ended sensing as is well known, or the loop may continue to the injection well  108  or other wells (not shown) for distributed temperature sensing therein. In still other embodiments, the distributed temperature sensing and monitoring module  165  may be located adjacent the injection well  108  or adjacent another well and the temperature alarm/clear signals communicated therefrom. 
     The temperature sensing operation of the fiber optic distributed temperature sensing and monitoring module  165  is based on optical time-domain reflectometry (OTDR), which is commonly referred to as “backscatter.” In this technique, a pulsed-mode high power laser source launches a pulse of light along the optical fiber  167  through a directional coupler. The optical fiber  167  forms the temperature sensing element of the system and is deployed where the temperature is to be measured. As the pulse propagates along the optical fiber  167 , its light is scattered through several mechanisms, including density and composition fluctuations (Rayleigh scattering) as well as molecular and bulk vibrations (Raman and Brillouin scattering, respectively). Some of this scattered light is retained within the fiber core and is guided back towards the source. This returning signal is split off by the directional coupler and sent to a highly sensitive receiver. In a uniform fiber, the intensity of the returned light shows an exponential decay with time (and reveals the distance the light traveled down the fiber based on the speed of light in the fiber). Variations in such factors as composition and temperature along the length of the fiber show up in deviations from the “perfect” exponential decay of intensity with distance. The OTDR technique is well established and used extensively in the optical telecommunications industry for qualification of a fiber link or fault location. In such an application, the Rayleigh backscatter signature is examined. The Rayleigh backscatter signature is unshifted from the launch wavelength. This signature provides information on loss, breaks, and inhomogeneities along the length of the fiber; and it is very weakly sensitive to temperature differences along the fiber. The two other backscatter components (the Brillouin backscatter signature and the Raman backscatter signature) are shifted from the launch wavelength and the intensity of these signals are much lower than the Rayleigh component. The Brillouin backscatter signature and the “Anti-Stokes” Raman backscatter signature are temperature sensitive. Either one (or both) of these backscatter signatures can be extracted from the returning signals by optical filtering and detected by a detector. The detected signals are processed by the signal processing circuitry, which typically amplifies the detected signals and then converts (e.g., digitizes by a high speed analog-to-digital converter) the resultant signals into digital form. The digital signals may then be analyzed to generate a temperature profile along the optical fiber  167 . The optical fiber  167  can be either multimode fiber or single mode fiber. An example of a commercially available optical fiber distributed temperature sensing system is the SENSA DTS System, sold by Schlumberger. 
     The fiber optic distributed temperature sensing and monitoring module  165  is controlled to monitor the downhole temperature at a location below the ESP assembly  114  and raise an alarm if the temperature at this location exceeds a predetermined maximum temperature. The predetermined maximum temperature is set to a temperature that differentiates between the flow of normal production fluid and the flow of injection vapor breakthrough. In this manner, the alarm is indicative of injection vapor breakthrough (typically referred to as a “hot slug”) flowing through the production tubing at the location below the ESP assembly. The alarm is cleared when the measured temperature drops to a temperature that is indicative that the flow of normal production fluid has returned (i.e., the injection vapor breakthrough flow has passed). The downhole temperature alarm and clear signals are communicated from the fiber optic distributed temperature sensing and monitoring module  165  to the system control module  159 . In response to receipt of the downhole temperature alarm signal, the system control module  159  sends an ESP Disable command to the ESP control module  161 , which operates to turn off power to the ESP motor  114 - 5 . In response to receipt of the alarm clear signal, the system control module  159  sends an ESP Enable command to the ESP control module  161 , which operates to control the power supplied to the ESP motor  114 - 5  in accordance with a designated control scheme. Typically, such control schemes monitor the downhole pressure and control the power supplied to the ESP motor  114 - 5  in the event that pressure anomalies are detected. Variable speed controls can be used to adjust the power supplied to the ESP motor  114 - 5  in order to maximize production based on the real-time downhole pressure measurements. It is commonplace for the control scheme of the ESP motor  114 - 5  to be dynamically updated for optimal performance. In this manner, the distributed temperature sensing and monitoring module  165 , the system control module  159 , and the ESP control module  161  cooperate to turn off power to the ESP motor  114 - 5  while injection vapor breakthrough flows through the tubing string and past the ESP assembly  114 . This reduces the risk of damage on the ESP motor  114 - 5  that is caused by the hot temperatures of the injection vapor breakthrough when the motor is running and is expected to improve the operational life of the ESP motor in such high heat conditions. 
     The mechanism by which the hot slug of fluid moves past the ESP when it is shutdown is explained as follows. Steam-assisted gravity drainage wells use a very low wellhead pressure in order to avoid flashing of the steam out of the produced fluid below the ESP. If the ESP is turned off, the hydrostatic column of fluid in the production tubing prevents the steam from migrating through the ESP and up the tubing. Instead it migrates up the annulus to the surface and is vented to a special tank. This vent is a common feature of steam-assisted gravity drainage wells for this purpose. The hot slug would be expected to cool quickly in the annulus, which is usually a large volume, and the steam will dissipate back into the fluid which will then fall back as it cools and will be suitable for pumping up through the production tubing once the ESP is restarted. 
     The fiber optic distributed temperature sensing and monitoring module  165  is also controlled to monitor temperature at a surface location upstream from the multiphase flowmeter  151  and raise an alarm if the temperature at this surface location exceeds a predetermined maximum temperature. Here too, the predetermined maximum temperature is set to a temperature that differentiates between the flow of normal production fluid and the flow of injection vapor breakthrough. In this manner, the alarm is indicative of vapor breakthrough (typically referred to as a “hot slug”) flowing through the production tubing at the surface location upstream from the multiphase flowmeter. The alarm is cleared when the temperature drops to a temperature that is indicative that the flow of normal production fluid has returned (i.e., the injection vapor breakthrough flow has passed). These flowmeter temperature alarm and clear signals are communicated from the fiber optic temperature sensing and monitoring module  165  to the system control module  159 . In response to receipt of the flowmeter temperature alarm signal, the system control module  159  controls the diverter or bypass valve  153  to direct the production fluid along the diverter tubing section or bypass path  155 , thereby bypassing the multiphase flowmeter  151 . Optionally, it can also control the diverter or bypass valve  157  to direct the production fluid flow along the bypass path to a tank or other suitable processing means. In this manner, the distributed temperature sensing and monitoring module  165  and the system control module  159  cooperate to direct vapor breakthrough though the bypass tubing  155  and avoid thermal contact with the multiphase flowmeter  151 . This reduces the risk of damage to the multiphase flowmeter  151  and is expected to improve the operational life of the multiphase flowmeter  151  in such high heat conditions. 
     There have been described and illustrated herein an embodiment of an improved steam-assisted gravity drainage system. The system incorporates an automatic control system that protects downhole equipment (such as an ESP) as well as surface equipment (such as a multiphase flowmeter) from the high temperatures that result from the breakthrough of injection vapor. While particular embodiments of the invention have been described, it is not intended that the invention be limited thereto, as it is intended that the invention be as broad in scope as the art will allow and that the specification be read likewise. Thus, while a particular stacked horizontal well pair configuration has been disclosed, it will be appreciated that other well configurations (such as one or more vertical-type injector wells that work in conjunction with one or more production wells, multi-branch horizontal injector and/or production well configurations, or other suitable configurations) can be used as well. In addition, while particular types of completions have been disclosed, it will be understood that different completion types can be used. For example, and not by way of limitation, frac-pack completions, open-hole completions, stand-alone screen completions, and expandable screen completions can be used. Remotely controlled hydraulic-actuated packers can be employed in intelligent completion applications. Also, while fiber optic distributed sensing and monitoring methodologies are preferred, it will be recognized that other remote temperature sensing and monitoring technologies, such as point sensors, can be used. Additionally, fiber optic pressure sensors, or other types of pressure sensors, may be used in place of, or as a supplement to, temperature sensors in the present invention. Furthermore, while the automatic system is described as part of a steam-assisted gravity drainage application, it will be understood that it can be similarly used as part of other heat assisted production applications for bitumen and/or other heavy oils. Furthermore, it is contemplated that the present invention can be employed in other heat assisted fluid recovery applications, such as the heat assisted removal of contaminants from soil. It will therefore be appreciated by those skilled in the art that yet other modifications could be made to the invention without deviating from its scope as claimed.

Summary:
An automatic control system that protects downhole equipment and surface equipment from high temperatures resulting from the breakthrough of injection vapor. The system operates to derive an estimate of the temperature of production fluid at a location upstream from the downhole equipment. An alarm signal is generated in the event that this temperature exceeds a threshold temperature characteristic of injection vapor breakthrough. Electric power to the downhole equipment is automatically shut off in response to receiving the alarm signal. A bypass valve selectively directs production fluid to a bypass path. The system operates to derive an estimate of the temperature of the production fluid at a location upstream from the surface equipment. An alarm signal is generated when this temperature exceeds a threshold temperature characteristic of injection vapor breakthrough. The bypass valve is automatically controlled to direct production fluid to the bypass path in response to receiving the alarm signal.