Abstract:
A method of determining changing well characteristics at downhole locations based on changes in detected temperatures by permanently installed downhole sensors. The methods and tools utilized involve the establishing of baseline temperature profiles, for example, at the outset of well operations. The installed sensors may be powered are rechecked on a periodic or continuous basis for substantial deviations to the temperature profiles which are indicative of particular well condition changes such as the depositing of asphaltene or decreases in fluid velocity.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    The present application claims priority to EP Application Serial No. 15290174.0, which was filed on Jul. 7, 2015, and is incorporated herein by reference in its entirety. 
       BACKGROUND 
       [0002]    Field 
         [0003]    The present disclosure relates to techniques for completing a reservoir. More particularly, the present disclosure relates to tools and methods for intelligent completions and monitoring systems. 
         [0004]    Description of the Related Art 
         [0005]    Exploring, drilling and completing hydrocarbon wells are generally complicated, time consuming and ultimately very expensive endeavors. Thus, maximizing recovery is a significant concern in any well operation. Along these lines, over the years, wells have tended to become deeper and deeper, perhaps exceeding 30,000 feet in depth, and of fairly sophisticated architecture to help ensure greater access to the reservoir. Similarly, increased attention has also been paid to monitoring and maintaining the health of such wells. A premium is also placed on maximizing the recovery rate and extending the overall life of the well as much as possible. 
         [0006]    Of course, maximizing recovery, the recovery rate and the overall life of the well are dependent on a host of different factors, not the least of which is the condition of the well architecture. For example, most of the well may be defined by a smooth steel casing that is configured for the rapid up hole transfer of hydrocarbons and other fluids from a formation. However, a buildup of irregular occlusive scale, sludge, wax and other debris or “asphaltenes” may occur over time at the inner surface of the casing or tubing and other architecture so as to restrict flow. Such debris may even form over perforations in the casing, screen, or slotted pipe thereby also hampering hydrocarbon flow into the main borehole of the well from the surrounding formation. 
         [0007]    In many cases this buildup is a function of pressure. For example, sudden pressure drops at downhole locations near restrictions may be prone to develop asphaltene buildup. Of course, removing such restrictions to avoid buildup and enhance recovery would only compromise the architecture of the well and hamper recovery in a different manner. Further, this would not eliminate all buildup given that even asphaltene may continue to buildup in absence of such restrictions. 
         [0008]    As a practical matter, instead of altering well architecture, buildup as described above is dealt with by first detecting the buildup and then performing an interventional application to achieve its removal. For example, over the course of the life of the well logging applications may be run to detect and map out downhole well conditions. This includes running a logging tool through the well to attain and record such conditions, including locations of potential buildup. Once detected, a variety of cleanout techniques may be utilized to remove debris from the well so as to help ensure unobstructed hydrocarbon recovery. 
         [0009]    Unfortunately, performing a complete cleanout generally requires shutting down production and proceeding with another intervention. For example, once asphaltene buildup is detected, production is often shut down, followed by the introduction of a solvent such as xylene that fills the well for a couple of days and is then pumped out. This is then followed by re-examining the well condition and resuming production if the buildup has been sufficiently removed by the solvent-based cleanout. 
         [0010]    Of course, the interventional cleanout is an expensive undertaking. In fact, even setting aside the equipment, operator and material cost of a cleanout as described above, there is also the expense of shutting down production for days at a time. All in all, restoring the architecture of the well to an optimum buildup-free state may cost the operator several hundred thousand if not a million or more in today&#39;s dollars. 
         [0011]    Efforts have been undertaken to try and avoid the need for such costly cleanouts. These efforts may focus on preventing buildup and thereby avoiding the need for such an all-encompassing interventional cleanout. For example, to avoid asphaltene buildup in particular, modeling of the well may take place to help estimate a flow rate threshold to stay under and reduce the likelihood of asphaltene deposits. This manner of avoiding sudden pressure drops may be effective, however, it also compromises the ability of the well to produce at a maximum rate. Once more, this technique is employed in a blind fashion. That is, the rate of production is compromised without any direct indication of problematic buildup actually starting to develop. 
         [0012]    Similarly, a circulating chemical injection system may be incorporated into the well hardware and employed to deliver a metered amount of chemical mixture on a near continuous basis to help prevent such buildup. However, this requires an added hardware and material expense along with the expense of separating the chemical mixture from production once the well fluids are produced. Further, this again takes place in a largely blind fashion, adding on these expenses without any direct indication of problematic buildup actually starting to develop. 
       SUMMARY 
       [0013]    A method of determining a characteristic of a downhole fluid in a well is detailed herein. The method may include deploying an array of sensors downhole in the well and calibrating each sensor according to its position in the well as well as an initial temperature reading at the sensor. Then, each sensor may be monitored for a temperature change indicative of a change in a velocity of the fluid due to a change in the characteristic of the fluid. 
         [0014]    In some embodiments, a sensor system for detecting changes in downhole conditions in a well at an oilfield is disclosed. The sensor system includes a first plurality of permanently installed downhole temperature sensors at a given depth in the well, a second plurality of permanently installed downhole temperature sensors at another depth of the well below the given depth, and a control unit positioned at the oilfield and in communication with the pluralities of sensors for directing powering thereof and obtaining temperature readings therefrom. The system also includes a processor of the control unit for individually analyzing a deviation from a baseline temperature profile for each sensor of the pluralities of sensors for determining a change in a non-temperature based condition in the well 
         [0015]    However, many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0016]    So that the manner in which the above recited features can be understood in detail, a more particular description may be had by reference to embodiments, some of which are illustrated in the appended drawings, wherein like reference numerals denote like elements. It is to be noted, however, that the appended drawings illustrate various embodiments and are therefore not to be considered limiting of its scope, and may admit to other equally effective embodiments. 
           [0017]      FIG. 1  is a side schematic view of an embodiment of a temperature sensor system incorporated into hardware of a well for establishing downhole fluid characteristics. 
           [0018]      FIG. 2  is an overview of an oilfield with a well accommodating the temperature sensor system of  FIG. 1 . 
           [0019]      FIG. 3A  is an enlarged view of discrete sensors of the sensor system of  FIG. 2  during downhole production of a fluid. 
           [0020]      FIG. 3B  is a chart plotting temperature of one of the discrete sensors of  FIG. 3A  over a time where characteristics of the fluid have remained substantially constant. 
           [0021]      FIG. 4A  is an enlarged view of other discrete sensors of the sensor system of  FIG. 2  during downhole production of the fluid. 
           [0022]      FIG. 4B  is a chart plotting temperature of one of the discrete sensors of  FIG. 4A  over a time where characteristics of the fluid have substantially changed. 
           [0023]      FIG. 5  is a flow-chart summarizing an embodiment of utilizing a temperature sensor system to monitor for downhole fluid characteristic changes. 
       
    
    
     DETAILED DESCRIPTION 
       [0024]    In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure. However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. 
         [0025]    In the specification and appended claims: the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element”. Further, the terms “couple”, “coupling”, “coupled”, “coupled together”, and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements”. As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the disclosure. 
         [0026]    Embodiments are described with reference to certain types of temperature sensor systems and fluid detections. In particular, sensors directed at the detection of asphaltene buildup during hydrocarbon production are utilized. For example, the sensors may be powered up periodically to determine changes in fluid characteristics indicative of asphaltene buildup at given sensors. Of course, the system and techniques may be utilized to examine for changes in other fluid characteristics. Regardless, so long as individual installed powered sensors of the system may be monitored to correlate temperature changes with non-temperature based well characteristic changes, appreciable benefit may be realized. 
         [0027]    Referring specifically now to  FIG. 1 , a side schematic view of an embodiment of a temperature sensor system  100  is shown incorporated into well hardware for establishing downhole fluid characteristics. In particular, the system is equipped with multiple sensor arrays  105 ,  110 , each including a variety of discrete individual sensors (e.g.  107 ,  108 ,  109  and  112 ,  113 ,  114 , respectively). Each sensor ( 107 - 109  and  112 - 114 ) may be utilized to measure temperature at its own particular installed location. For example, with added reference to  FIG. 2 , in the embodiment shown, the arrays  105 ,  110  are mounted to production tubing  186  at the interior of casing  181  that defines the well  180 . Thus, the system  100  is well suited for measuring characteristics of production fluid  225  at each individual sensor ( 107 - 109  and  112 - 114 ). More specifically, the sensors ( 107 - 109  and  112 - 114 ) are temperature sensors. Therefore, as detailed further below, changing characteristics of production fluid  225  that may be correlated to changes in temperature may be dynamically monitored over time. 
         [0028]    In the embodiment shown, the sensors ( 107 - 109  and  112 - 114 ) may be permanently installed resistance temperature detectors. Thus, once they are powered up, they may generate a degree of heat on their own. While this heat is likely to rapidly dissipate in most circumstances, changes in downhole fluid characteristics, may emerge that present in the form of changes in the temperature detection profile of the system  100  on a sensor by sensor basis. For example, where production constituents begin to deposit directly on the sensors ( 107 - 109  and  112 - 114 ), such as in the case of asphaltene buildup, a detectable rise in sensor temperature may result. This rise in temperature may also be correlated to fluid velocity and type, providing additional useful information to operators in a real-time fashion. That is, in contrast to a logging interventional application or passive fiber optic temperature detection, these sensor arrays  105 ,  110  are permanently installed and powered. As a result, each individual sensor ( 107 - 109  and  112 - 114 ) is afforded the opportunity to physically allow buildup thereat and generate heat during use that may be affected by such buildup. 
         [0029]    Continuing with reference to  FIG. 1 , the system  100  is shown installed with other hardware such as the tubing  186  and casing  180  as noted above. The particular installation shown utilizes upper  180  and lower  185  completion hardware with a packer  120  providing isolation within the upper completion  180 . Thus, the lower completion  185  may be used to target particular production location within a reservoir of a downhole formation  295  (see  FIG. 2 ). A coupler  130  is utilized to allow for effective connections to be made between the upper  180  and lower  185  completion hardware. For example, in the embodiment shown, the sensor arrays  105 ,  110  are electronically powered by a lower completion line  145 . This line  145  is electronically coupled to the upper completion line  140  through the noted coupler  130  and ultimately traverses the well head  175 , exiting the system  100  for sake of obtaining power from an external location. 
         [0030]    In the embodiment shown, the electrical lower completion line  145  provides power to the first, more up hole, sensor array  105  through a conventional dry mate connection  160  and splits off to an electrical relay line  147  that continues on via another connection  165  for powering the second, more downhole, array  110 . Intervening junctions  127  and flux stations  125 ,  150  may be present for regulating or modulating power and digitizing temperature data, respectively. This particular architecture is representative of how such a system  100  may be utilized for focusing on downhole fluids in an isolated production region of a well  280  (see  FIG. 2 ). Of course, this is but one potential layout for utilization of such a system  100 . A variety of different or additional components may be utilized. For example, another such system may be employed for injection wells and fluids (as opposed to being focused on production). 
         [0031]    Continuing now with reference to  FIG. 2 , an overview of an oilfield  200  is shown with a well  280  accommodating the temperature sensor system  100  of  FIG. 1 . In this environment, the usefulness of the system  100  may be better appreciated. For example, in this view, the sensor arrays  105 ,  110  of the system  100  depicted in  FIG. 1 , remain, but, for sake of illustration, are out of the field of view. In this manner, the adjacent flow of production fluid  225  from formation perforations  250  is readily apparent. Specifically, the isolated production tubing  186  is provided with inlets  270  that allow for the uptake of production  225  through a channel  285  thereof via the perforated adjacent casing  181 . 
         [0032]    In the embodiment shown, certain types of surface equipment for managing production is found adjacent the rig  240 . Specifically, emerging from the well head  175  are a production pipe  220  and chemical injection pipe  210 . Fluid flow through these pipes  220 ,  210  may be regulated by a control unit  215  in communication with the installed temperature sensor system  100 . So, for example, the rate of production  225  from the well  280  may be slowed or chemical injection introduced depending upon analysis performed by a processor of the unit  215  based on the temperature data acquired from the system  100 . 
         [0033]    Given that certain types of buildup may be pressure related, utilizing the control unit to manage the flow of production in response to system temperature readings may be beneficial. Additionally, as shown in  FIG. 2 , the chemical injection pipe  210  leads to a chemical injection line  260  that traverses the packer  120  and coupler  130  to reach the production region near the installed system  100 . Thus, the control unit  215  may regulate chemical injection as needed to help minimize buildup. Furthermore, because the unit  215  is able to introduce such measures based on real-time analysis of temperature data, not only is the need for a logging intervention avoided, but so too is the need to blindly or prematurely slow production or unnecessarily introduce a chemical mixture. Of course, in order to take advantage of such real time temperature data, monitoring downhole sensor data over time is key. 
         [0034]    Referring now to  FIG. 3A , an enlarged view of two discrete sensors  107 ,  108  of the system of  FIG. 2  is shown during downhole production of a fluid  225 . In this view, the uptake of fluid  225  from the adjacent perforation  250  is evident. Thus, the depicted sensors  107 ,  108  are unlikely to detect substantial changes in temperature from one point in time to another. That is, the temperature sensors  107 ,  108  are adept at detecting changes in the surrounding medium which includes conditions related to the fluid  225 . While the well itself may be assumed to be largely steady state in terms of temperature, changes in fluid velocity, buildup on the sensors  107 ,  108  and other dynamic conditions of the fluid  225  may result in temperature detection changes. 
         [0035]    Referring now to  FIG. 3B , a chart is shown plotting the temperature readings obtained from of one of the discrete sensors  107  of  FIG. 3A  over a time. As indicated above, the characteristics of the producing fluid  225  in  FIG. 3A  have remained substantially constant over time. So, for example, at the outset of production operations, a baseline  307  for the sensor  107  may be established. In the chart of  FIG. 3A , it is apparent that once the powered sensor  107  warms up and begins detection, a stabilized temperature detection of about 50.1° C. is established. Specifically, after about 20 minutes, this baseline  307  may be established. 
         [0036]    The powered sensor  307  may remain on or, perhaps more likely, turned off and then powered back up again for monitoring on a daily, hourly or some other periodic basis. Regardless, once the baseline  307  is established, the sensor  107  may again be checked. In the embodiment shown, the sensor  107  is again turned on at a future point in time and a detection ( 300 ) monitored. In this case, a time to stabilization of about 20 minutes at about 50.1° C. is again determined. Thus, the sensor  107  has detected no notable change in well fluid characteristics. So, for example, with added reference to  FIG. 2 , no cause for action by the control unit  215  is apparent. 
         [0037]    Referring now to  FIG. 4A , an enlarged view of other discrete sensors  112 ,  113  at another location in the well  280  are shown (see  FIG. 2 ). In contrast to the sensors  107 ,  108 , however, these sensors  112 ,  113  have experienced some surrounding buildup  450  from the fluid  225 . More specifically, in the embodiment shown, this buildup  450  is asphaltene deposited at various locations of the production region, including right on the sensors  112 ,  113 . As a result, temperature readings from these sensors  112 ,  113  may now differ from baseline readings established at the outset of production operations as described below. 
         [0038]    Referring now to  FIG. 4B , a chart plotting temperature of one of the discrete sensors  112  of  FIG. 4A  over a time is shown. However, unlike the chart of  FIG. 3B , conditions surrounding this sensor  112  have substantially changed. More specifically, a baseline  412  for the sensor  112  is established at the outset of production operations. Though the location in the well for this sensor  112  is below that of the sensor  107  of  FIG. 3A , the baseline  412  is largely the same. That is, after about 20 minutes, a stabilized temperature reading of about 50.1° C. is established for the sensor  112 . However, when these readings are taken again in the future after the buildup  450  of  FIG. 4A  has emerged, the results are quite different. 
         [0039]    Unlike the baseline  412 , once a sensor  112  with buildup  450  is turned back on, a different type of detection ( 400 ) emerges. Specifically, as shown in  FIG. 4B , the sensor  112  warms up and, after 20 minutes, does not stabilize in temperature. Instead, the insulating layer of buildup  450  causes the detected temperature to continue to rise until at about 40 minutes, a stabilized temperature of about 50.3 degrees is attained. In this circumstance, the delay in reaching the stabilized temperature as well as the higher temperature, in comparison to the baseline  412  are both real-time indicators that changes have occurred downhole. Pre-stored profile information at the control unit  215  of  FIG. 2  may be referenced to establish the particular meaning of the change in detection  400 . For example, a particular temperature rise and increase in time to stabilization may correspond to a particular fluid velocity as described further below. This, in turn may correspond to a degree of asphaltene buildup in millimeters as previously established and stored at the unit  215 . 
         [0040]    Parameters or guidelines for when to take corrective action such as reducing production flow, introducing chemical injection, or taking some other corrective measure may or may not be set in advance of operations. For example, the change may be considered substantial enough to warrant action in situations where the time to temperature stabilization has increased by 50% in combination with a temperature increase of more than 1/10 of a ° C. Of course, these are only exemplary parameters. Further, the type and degree of corrective action may also differ depending on the magnitude of the changes represented in the detection  400 . For example, a minor reduction in production rate may initially be sought which is later further reduced should the magnitude of the change in detection  400  increase further. Along the same lines, the corrective action and determination as to whether or not such action should be taken may depend on the type of operations, stage of life of the well, and other operational considerations. For example, detections  400  as shown in  FIG. 4B  may have vastly different implications on an older injection well slated to be taken off-line in the near future in contrast to a production well as depicted in  FIG. 2 . Nevertheless, in either circumstance, the operator is provided with real-time fluid condition information from permanently installed downhole powered sensors (e.g.  112 ,  113  and others). 
         [0041]    While the above examples reveal the correlation between detected temperature changes and the particular circumstance of asphaltene buildup, it is worth noting that changes in detection may be indicative of a variety of characteristics of downhole fluid conditions. For example, a rise in temperature may be indicative of a lowering of fluid velocity. By way of specific example, in the chart of  FIG. 4B , the raise in temperature from the baseline  412  to the current detection  400  may translate to a shift from about 0.01 meters per second (m/s) to about 0.0005 m/s. Of course, this is only exemplary as a variety of other fluid characteristic information may be ascertained by monitoring such changes in detection  400 , particularly when combined with other real-time available information, such as pressure. 
         [0042]    Referring now to  FIG. 5 , a flow-chart summarizing an embodiment of utilizing a temperature sensor system to monitor for downhole fluid characteristic changes is shown. As indicated at  510 , the system includes at least one sensor installed at a downhole location. The sensor may then be powered to establish a baseline temperature profile at the outset of operations (see  530 ). Thus, periodically, the sensor may be monitored in the future for substantial deviations from the baseline profile as indicated at  550 . This may be achieved by monitoring the sensor on a continuous basis or by periodically powering the sensor on to check for such deviations at predetermined intervals. With such dynamic fluid characteristic information in hand derived from these types of temperature comparisons, the operator may continue well operations (see  590 ) or take corrective action as needed (see  570 ). For example, a substantial temperature profile deviation may be indicative of asphaltene buildup or other condition warranting corrective action. Regardless, the operator is provided with real-time information that may allow operations to ultimately continue (see  590 ) even if intervening corrective action is warranted, for example, based on stored predetermined parameters. 
         [0043]    Embodiments described hereinabove include techniques that may avoid costly intervention for the sake of logging well conditions and/or follow-on costly cleanouts. Furthermore, with real-time fluid characteristic and buildup information available, premature corrective action such as reducing flow-rate and/or unnecessary chemical injection may be avoided. So, for example, production need not be prematurely hampered or blindly contaminated with chemical injection fluid. 
         [0044]    Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. For example, while the techniques herein focus on the detection of asphaltene buildup, other fluid changes or velocity determinations may be established with such techniques, such as gas detection or the emergence of water breakthrough in a hydrocarbon well. 
         [0045]    Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses, such as are within the scope of the appended claims.