Abstract:
A packer deployed well wall monitoring or transceiver assembly. The assembly may be particularly suited for use with swellable packers wherein the sensor or transceiver is delivered in a manner that substantially avoids damage thereto. Furthermore, the pre-deployment configuration of the assembly may enhance the deployment and reliability of the sensor in terms of formation monitoring over time. The deployment of the packer provides the energy required for the sensor or transceiver to contact the well wall. The packer elastomeric material provides or can be enhanced to provide isolation of the sensor or transceivers from extraneous borehole disturbances improving their signal to noise characteristics.

Description:
PRIORITY CLAIM/CROSS REFERENCE TO RELATED APPLICATION(S) 
       [0001]    This Patent Document claims priority under 35 U.S.C. §119 to U.S. Provisional App. Ser. No. 61/313,952, filed on Mar. 15, 2010, and entitled, “Packer Deployed Formation Sensor”, incorporated herein by reference in its entirety. 
     
    
     FIELD 
       [0002]    Embodiments described relate to sensors for use in conjunction with downhole operations. In particular, sensors for incorporation into downhole completion equipment, specifically at downhole packers, are detailed. Such sensors may be utilized in open-hole or cased hole environments and are particularly well suited for acquisition of well wall and formation characteristics. 
       BACKGROUND 
       [0003]    Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming, and ultimately very expensive endeavors. As a result, over the years, a significant amount of added emphasis has been placed on well monitoring and maintenance. Careful attention to design, monitoring and maintenance may help maximize production and extend well life. Thus, a substantial return on the investment in the completed well may be better ensured. 
         [0004]    Monitoring well conditions may be undertaken by way of running a logging application. That is to say, logging to determine well pressures, temperatures, flow rates and other profile characteristics may be undertaken over the course of the life of the well, and not just prior to well completions. However, such follow-on logging comes with considerable costs. For example, in order to run such applications, the well may be shut down and other applications put on hold for several hours, if not days, while the logging application is run. Depending on the particular well and operations suspended for the logging, this may translate into tens to hundreds of thousands of dollars in added costs, particularly when factoring in lost production time. 
         [0005]    Due to the high costs associated with follow-on logging as described above, ongoing monitoring of well conditions is often attempted through the use of downhole structure that is already present in the well. For example, pressure, temperature and other sensors may be incorporated into the sidewalls of completions tubulars. These sensors may be communicatively tethered to surface equipment via a line running along and supported by the tubular structure. Thus, data acquired by the sensors may be relayed to the surface equipment for ongoing monitoring of downhole well conditions. 
         [0006]    Unfortunately, depending of the type of monitoring to be conducted, tubular mounting of sensors may place significant limitations on the quality of the data obtained. So, for example, flow and resistivity sensors may provide workable data when outfitted at a tubular wall. On the other hand, where the sensor is an acoustic sensor, for example, directed at the formation defining the well, it is unlikely that disposing the sensor at the tubular will result in obtaining any usable formation data. That is, acoustic noise through the tubular and/or downhole fluid flow through the annular space between the tubular and the formation may be quite significant. Thus, the signal to noise ratio acquired by the sensor is unlikely to result in workable data as such relates to the formation. Indeed, such signal to noise ratio issues may present for pressure, electrical, electromagnetic and a variety of other sensor types. 
         [0007]    In some cases, where obtaining formation characteristic data is paramount, a subsequent interventional application directed specifically at the formation may be undertaken due to the unavailability of reliable data from a tubular disposed sensor. However, as with the follow-on logging application described above, this may come at significant added costs. 
         [0008]    Furthermore, in some cases, the amount of formation characteristic data that is sought across the oilfield is of such significance to operations that cross-well, borehole to surface or surface to borehole logging is undertaken. Cross-well logging involves the acquisition of formation data from multiple wells throughout the oilfield, typically using a source such as a well, surface or shallow dedicated “subsurface” transmitter deployment, with an observation well, surface or dedicated “subsurface” sensor deployment. These methods typically provide a two dimensional plane of information, such as resistivity, between the source and receiver locations. As such, formation characteristics between wells and throughout the oilfield may be better established. Distributing suitable sensors or transceivers into otherwise producing or injecting wells, affords a more comprehensive distribution of detection or transmission “locations” allowing multiple planes of information to be determined, improving areal and vertical coverage of the information. 
         [0009]    Of course, formation logging of multiple wells drives up the cost of operations dramatically. That is to say, the interruption and added interventional efforts of follow-on logging are now multiplied. Unfortunately, so are the costs. Due to the added costs associated with follow-on logging, well monitoring often remains limited to that which may be acquired from completions tubular disposed sensors. This may come with sacrifice to the quality of the acquired data, particularly in the case of data sought to be acquired from the formation itself. At present, alternative options for acquisition of such formation data is limited to those options that that are accompanied by the noted dramatic increase in operational costs. 
       SUMMARY 
       [0010]    A packer assembly for disposal in a well at an oilfield. The assembly includes a packer disposed about a tubular and is equipped with either of a sensor or transmitter at an outer surface thereof. A telemetric line is coupled to the sensor or transmitter as the case may be and run to a surface of the oilfield. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0011]      FIG. 1  is a front, partially-sectional view of an embodiment of a packer deployed sensor assembly. 
           [0012]      FIG. 2  is an overview of an oilfield having a well accommodating a sensor system which incorporates the assembly of  FIG. 1 . 
           [0013]      FIG. 3A  is a cross-sectional view of the system taken from  3 - 3  of  FIG. 2  and revealing the packer sensor assembly in a deployed state. 
           [0014]      FIG. 3B  is a cross-sectional view of the packer sensor assembly of  FIG. 3A  in an undeployed state. 
           [0015]      FIG. 4A  is a side cross-sectional view of the packer sensor assembly in an undeployed state. 
           [0016]      FIG. 4B  is a side cross-sectional view of the packer sensor assembly in a deployed state. 
           [0017]      FIG. 5  is an enlarged view of a portion of the assembly taken from  5 - 5  of  FIG. 4B  and revealing the interface of a sensor of the assembly with a well wall. 
           [0018]      FIG. 6  is a flow-chart summarizing an embodiment of utilizing a packer deployed formation sensor. 
       
    
    
     DETAILED DESCRIPTION 
       [0019]    Embodiments herein are described with reference to certain types of sensor-packer assemblies. For example, these embodiments focus on swellable packer assemblies. However, a variety of alternative device deployments for delivery of downhole sensors may be utilized which are not limited to swellable packer embodiments. Similarly, the assemblies are shown disposed in open-hole environments for formation related data acquisition. However, in other embodiments, such assemblies may be utilized in cased hole environments. Further, the data acquisition involved may be directed at downhole conditions aside from formation characteristics. Regardless, embodiments detailed herein utilize packer deployed sensor and/or transmitter assemblies that are brought into proximity with a well wall for sensing and/or transmitting thereat, as the case may be. 
         [0020]    Referring now to  FIG. 1 , a front, partially-sectional view of an embodiment of a packer deployed sensor assembly  100  is depicted. The assembly  100  includes a packer  160  that is disposed about a production tubular  110 . However, in other embodiments, a variety of tubular, basepipe, mandrel or other under-support structure may be employed, depending upon the particular nature of downhole operations. The assembly  100  also includes a protective jacket  175  about a sensor  101 . That is, the sensor  101  may be disposed at the outer surface of the packer  160  and covered by a protective jacket  175  as detailed further below. In one embodiment the packer  160  is of a swell variety employing a conventional swellable elastomer suitable for providing downhole isolations as well as delivering the sensor  101  toward a well wall as noted below. However, in other embodiments, mechanical or other packer varieties may be utilized. 
         [0021]    The above described protective jacket  175  may be of a polymeric or metallic material configured to protect the sensor  101  during advancement of the assembly  100  through a downhole environment, prior to packer deployment. As detailed below, the jacket  175  may be configured for removal or dissolution once the packer  160  reaches a downhole target location for deployment. In a dissolvable metal-based embodiment, the jacket  175  may incorporate some variety of calcium, aluminum, zinc and/or magnesium. Regardless, whether metal-based or elastomeric, a conventional chemical slug of acid or solvent may be utilized to degrade the jacket  175  or, in an alternate embodiment, downhole conditions alone may be sufficient to adequately degrade the jacket  175 . 
         [0022]    With added reference to  FIG. 2 , the noted sensor  101  may be one of several that are disposed at the outer surface of the packer  160 . Indeed, in the depiction of  FIG. 1 , multiple sensors  101  are visible. As detailed further below, the sensors  101  are configured for deployment by the packer  160  for secure positioning at a well wall  285 . Thus, in certain embodiments the sensors  101  may be tailored to acquire wall  285  or formation  290 ,  295  data. However, in other embodiments, other information may be targeted. Furthermore, in some embodiments, the sensors  101  may serve as transceivers configured for transmissions  205  toward the wall  285  and formation  290 ,  295  in addition to sensing capacity. Indeed, in yet other embodiments, a sensor may actually be entirely substituted with a device serving solely as a transmitter. For example, this may be the case where an acoustic transmitter is provided and another sensor  101  is also provided to acquire downhole acoustic transmissions. 
         [0023]    In all, sensors  101  (or transceivers) may be disposed as depicted in  FIG. 1  for data acquisitions ranging from pressure, temperature, resistivity, hydrophone, vibration, acoustic, geophone, streaming potential, multiple axis accelerometer, strain, electromagnetic, magnetic, acidity, dipole, capacitance, dielectric, chemical detection including carbon dioxide, and a host of others. Transmitters (or transceivers) may similarly be geared toward emissions of an electromagnetic, acoustic, electrical dipole, vibrator, or sonic nature. 
         [0024]    Data acquired by these sensors  101  may be telemetrically conveyed over a line  125  running therefrom. Indeed, the line  125  may be electric, hydraulic, fiber optic, or other suitable line for conveyance of data and/or power to or from the sensor  101 . That is, this line  125  may run uphole from the assembly  100  toward surface equipment  225  at the surface of an oilfield  200  as detailed with respect to  FIG. 2  below. Thus, analysis of detected data may be performed and, for example, in the case of transmitter or transceiver use, control over emissions may be directed from surface. 
         [0025]    In the embodiment shown, an electronic subassembly  135  is positioned between the line  125  and the sensors  101 . As such, processing or control interface may be afforded between the noted surface equipment  225  and the sensors  101 . That is to say, data acquired by a sensor  101  may be processed prior to directing uphole over the line  125 . Further, the connection between the sensor  101  and the subassembly  135  may be hard wired or wireless in nature for communication of data and/or power therebetween. The subassembly  135  may be of particular benefit where the line  125  is of the fiber optic variety, in which the subassembly  135  serves as an interface to translate electronic data transmissions into light signal for transmission over the line  125 . 
         [0026]    Referring now to  FIG. 2 , an overview of an oilfield  200  is shown. A well  280  which accommodates a sensor system incorporating the assembly  100  of  FIG. 1  is itself accommodated at the oilfield  200 . In the embodiment shown, the well  280  is open-hole in nature with deployed packers  160 ,  260  making contact with a well wall  285  that is defined by the formation  290 ,  295  itself. Thus, as detailed below, sensors  101 ,  201  may be forced into direct contact with the formation  290 ,  295 . However, in other embodiments, the system may be deployed and utilized within a cased-hole environment. Regardless, where such a swelling deployment of the sensors  101 ,  201  is utilized, the possibility of shock damage thereto over the course of deployment is reduced. 
         [0027]    In the embodiment shown, the packers  160 ,  260  are of a swellable configuration as noted above, resulting in forcibly holding the sensors  101 ,  201  in position at the well wall  285 . The elastomeric material employed for such configurations may be selected to enhance isolation of the sensors  101 ,  201  at the wall  285 . Thus, the signal to noise ratio may similarly be enhanced for sensor detections directed at the wall  285 . That is to say, the detection of stray noise, pressure, electrical conductivity, vibration or other misleading disturbances may be minimized, thereby improving the quality of the detections acquired by the sensors  101 ,  201 . 
         [0028]    The well  280  is shown traversing various formation layers  290 ,  295  with a packer  160 ,  260  disposed in each. Thus, the above noted sensors  101 ,  201  may be disposed at locations that allow data acquisition relative each layer  290 ,  295 . Alternatively, as noted above, the sensors  101 ,  201  may be transceivers or transmitters that allow for transmissions into the formation layers  290 ,  295  (see  205 ). These transmissions may be sonic, electromagnetic arrays or of other varieties useful in directing into the formation  290 ,  295 . Indeed, in one embodiment, the packers  160 ,  260  are outfitted with multiple transceivers and/or both sensors  101 ,  201  and transmitters. So, for example, acoustic or other transmissions (e.g.  205 ) may be directed into the formation  290 ,  295  and sensed therefrom relative the same packer location. 
         [0029]    Continuing with reference to  FIG. 2 , a host of surface equipment  225  is disposed at the surface of the oilfield  200 . This includes a production line  257  running from a well head  255  in an embodiment where the packers  160 ,  260  are supported by production tubing  110  of the system. A rig  230  is even positioned over the well head  255  to support alternate monitoring or more directly interventional subsequent applications. However, more notably, a processing or control unit  250  is also disposed adjacent the well head  255 . 
         [0030]    The above noted unit  250  may be telemetrically coupled to the downhole sensors  101 ,  201  via the above described telemetric line  125 . As such, data acquired by the sensors  101 ,  201  may ultimately be processed by the control unit  250  to establish downhole conditions such as those pertaining to the formation  290 ,  295 . The line  125  may be supported externally by the tubing  110  of the system as depicted in  FIG. 2 . However, the line  125  may alternatively be incorporated into the tubing structure, for example, in combination with electrical or hydraulic downhole wetmate systems. Indeed, inductive coupling may even be utilized to allow the line  125  to alternately be incorporated into a casing or liner disposed at the well wall  285 . 
         [0031]    In an embodiment where the sensors  101 ,  201  are in the form of transceivers or substituted with transmitters, the control unit  250  may direct transmissions into the formation  290 ,  295  as indicated at  205 , perhaps followed by analysis of detected information as a result of such transmissions. In one embodiment, the directing of such transmissions may even be intelligent. That is, such directing may be based in part on real-time or prior sensor acquired information. 
         [0032]    Referring now to  FIG. 3A , a cross-sectional view of the system taken from  3 - 3  of  FIG. 2  is shown. In this depiction, the packer  160  is shown in the same deployed state as that depicted in  FIG. 2 , with the sensors  101  forcibly disposed at the well wall  285 . In the view of  FIG. 3A , the protective jacket  175  (see  FIG. 3B ) is removed and the packer  160  swollen or otherwise expanded through mechanical, hydraulic or other means to the deployed state with the sensors  101  right at the formation  290  for data acquisition therefrom, or in the case of a transmitter, transmissions thereto. In this view, the support provided by the production tubing  110  to the packer  160  is also apparent, as is a production channel running through the tubing  110 . 
         [0033]    Referring now to  FIG. 3B , a cross-sectional view of the system taken from  3 - 3  of  FIG. 3A  is also shown. However, in this depiction, the packer  160  is in an undeployed state with the protective jacket  175  in place about the packer  160  and sensors  101 . That is, prior to deployment as shown in  FIG. 3A , the protective jacket  175  remains for protection of the sensors  101 . Indeed, with the jacket  175  in place and adequate clearance through the well  280 , the system may be run from surface and into position as depicted in  FIG. 2  without undue concern over damage to the sensors  101 . Once in place, the jacket  175  may be removed via degradation or other means as noted hereinabove. Thus, deployment of the packer  160  as depicted in  FIG. 3A  may ensue. 
         [0034]    Referring now to  FIG. 4A , a side cross-sectional view of the packer assembly  100  is shown in an undeployed state like that of  FIG. 3B . In this cross-sectional view, added features are apparent, particularly those serving as an aid to deployment of the sensors  101 . For example, the sensors  101  are apparent below the protective jacket  175  and disposed on a supportive platform  400 . The platform  400  is in turn coupled to a force enhancing mechanism in the form of pistons  425  which are disposed in hydraulic chambers running through the packer  160  and tubing  110 . Thus, the hydraulically driven platform  400  may serve as an aid in deployment of the sensors  101  into the face of the irregular open-hole well wall  285  as described further below. In an alternate embodiment, the pistons  425  are spring loaded as opposed to hydraulically driven. As such, removal of the protective jacket  175  may be sufficient to attain the enhanced forces supplied by the pistons  425  toward the sensors  101  and platform  400 . 
         [0035]    Continuing with reference to  FIG. 4A , the sensors  101  are shown disposed in protective media  475 . That is, space between the protective jacket  175  and the platform  400  that is not occupied by the sensors  101  or the telemetric line  125  may be filled with media  475  configured to protect the integrity of the sensors  101  and/or the data acquisition (or transmissions) thereby. For example, a noise insulating or shock absorbing polymeric compound may be utilized to enhance signal, particularly where the sensor  101  is acoustic in nature. Synthetic rubber, fluoropolymer elastomers and composite plastics may be suitable for such use. Additionally, the media  475  may also be a dielectric to ward off the possibility of short circuit. Polyaryl ether ketones, polyimides, polyphenyl sulfide, and ethylene or propylene copolymers may be suitable for such use along with xylylene polymers. 
         [0036]    Referring now to  FIG. 4B , a side cross-sectional view of the packer sensor assembly  100  is shown in a deployed state with the protective jacket  175  of  FIG. 4B  removed. In this depiction the swollen nature of the packer  160  is evident, forcing the sensors  101  into the well wall  285 . Furthermore, the amount of force imparted on the sensors  101  may be enhanced by the deployment of the above noted pistons  425  directed at the platform  400 . In one embodiment, the pistons  425  may be of a ratcheted configuration. By way of example, the swell of the packer  160  may impart forces of up to a couple hundred PSI, whereas the enhanced force supplied by the pistons  425  may impart PSI forces in the thousands on the platform  400  and sensors  101 . Indeed, as shown in  FIG. 4B , the sensors  101  may actually penetrate the surface of the wall  285 , embedding into the formation  290  to a degree. 
         [0037]    In the embodiment of  FIG. 4B , the sensors  101  are depicted as transceivers which are employed to emit transmissions  205  as described above. This may be a particularly effective detection technique given the substantially complete contact that is forcibly maintained between these transceivers  101  and the wall  285 . That is to say, with such contact, transmissions  205  such as acoustics may readily propagate through the formation followed by a substantially interference-free detection, perhaps even by the same transceivers  101 . Analysis of such detections, for example, at the control unit  250  of  FIG. 2  may provide reliable information as to characteristics of the formation  290 . Additionally, these, or any other detections made by the sensors  101  may be processed by the electronic subassembly  135  for relay uphole as described above. 
         [0038]    Referring now to  FIG. 5 , an enlarged view of a portion of the assembly  100  taken from  5 - 5  of  FIG. 4B  is shown. In this view the interfacing of the sensor  101  with the well wall  285  is more apparent. Indeed, in the embodiment shown, the sensor  101  is outfitted with probes  550  for penetrating further into the formation  290 . Thus, improved contact for detections, transmissions and/or grip may be provided. Additionally, the hydraulics of the piston  425  and chamber  450  are also accompanied by a rupture disk  500  which serves as a barrier to the channel  300  at the other side of the tubing  110 . Thus, prior to piston deployment as shown in  FIG. 5 , pressure in the chamber  450  may be kept at a lower pre-deployment level. Subsequently, pressure in the channel  300  may be driven up to a level sufficient to rupture the disk  500  as shown in  FIG. 5 , thereby deploying the piston  425  and providing the noted enhanced forces on the platform  400  and sensor  101 . 
         [0039]    Referring now to  FIG. 6 , a flow-chart is depicted summarizing an embodiment of utilizing a packer deployed formation sensor assembly. The assembly is delivered into a well and set as indicated at  615  and  630 . This setting includes setting of a packer of the assembly as well as positioning a sensor and/or transmitter into interface with a wall of the well. In the case of a sensor, confirmation of the setting may be obtained as indicated at  645 , for example where the sensor incorporates or is a strain gauge. 
         [0040]    Perhaps more to the point, however, the assembly may be utilized to acquire well information directly from the wall of the well as indicated at  660 . This information may be analyzed as indicated at  675 , for example as an aid in building a profile of the well. Indeed, such information may even be beneficial in helping to build an overall profile of the formation. Furthermore, this information may be utilized in real-time, for example to direct the emission of transmissions into the formation for further analysis such as where the sensor is of a transceiver variety (see  690 ). Of course, such emissions may also take place irrespective of prior analysis. 
         [0041]    Embodiments detailed hereinabove provide techniques for determining formation and other downhole information that is of enhanced reliability and accuracy. Further, such tools and techniques for acquiring such downhole data may be utilized in a manner that obviates the need for separately run logging or other dedicated data acquiring well interventions. Thus, in addition to improved results through the use of packer deployed sensors, the costs of attaining such information may be dramatically reduced. In fact, such tools and techniques may be particularly beneficial in supporting heretofore dramatically difficult and costly cross-well logging operations. 
         [0042]    The preceding description has been presented with reference to presently preferred embodiments. 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, sensor assemblies are detailed hereinabove as utilizing a telemetric line. However, emerging wireless power and/or communications technologies may similarly be utilized. Furthermore, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.