Abstract:
A system for monitoring a wellbore service treatment, comprising a downhole tool operable to perform the wellbore service treatment; a conveyance connected to the downhole tool for moving the downhole tool in the wellbore, and a plurality of sensors operable to provide one or more wellbore indications and attached to the downhole tool or a component thereof via one or more tethers. A method of monitoring a wellbore service treatment, comprising conveying into a wellbore a downhole tool operable to perform the wellbore service treatment and a plurality of sensors operable to provide one or more wellbore indications attached to the downhole tool or a component thereof via one or more tethers, deploying the downhole tool at a first position in the wellbore for service, treating the wellbore at the first position; and monitoring an at least one wellbore indication provided by the wellbore sensors at the first position.

Description:
BACKGROUND 
   The present disclosure is directed to wellbore lithology fractionation technology, more particularly to fracture characterization using reservoir monitoring devices, and more particularly, but not by way of limitation, to a system and method for using several sensors attached below a fracturing tool string. 
   A wide variety of downhole tools may be used within a wellbore in connection with producing hydrocarbons from a hydrocarbon formation. Downhole tools such as frac plugs, bridge plugs, and packers, for example, may be used to seal a component against casing along the wellbore wall or to isolate one pressure zone of the formation from another. 
   Fracturing is a wellbore service operation to break or fracture a production layer with the purpose of improving flow from that production layer. In the case that multiple zones of production are planned, fracturing may be conducted as a multi-step operation, for example positioning fracturing tools in the wellbore to fracture a first zone, pumping fracturing fluids into the first zone, repositioning the fracturing tools in the wellbore to fracture a second zone, pumping fracturing fluids into the second zone, and repeating for each of the multiple zones of production. Fracturing fluids sometimes propagate into water bearing formations, which is undesirable. Water must be separated at the surface from oil or gas and properly disposed of, imposing undesirable expenses on the production operation. If the production fluids are pumped to the surface, pumping energy, and hence money, is expended lifting the waste water product to the surface. What is needed is a system and method to detect during the course of a fracturing job when the fracturing fluid is propagating into a water bearing formation so that the fracturing job may be interrupted. 
   Fracturing tools may be withdrawn from the wellbore, and sensors may then be deployed into the wellbore and used to directly sense the results of fracturing. The sensors are withdrawn from the wellbore, the sensor information they have stored is downloaded to a computer, and the data is analyzed for use in planning future fracturing jobs in similar lithology structures or similar production fields. This two trip process is undesirable. What is needed is a system and method for co-deployment and co-retraction of fracturing tools and sensors for a fracturing service operation which may reduce the number of tool string trips into and out of the wellbore. 
   SUMMARY 
   Disclosed herein is a system for monitoring a wellbore service treatment, comprising a downhole tool operable to perform the wellbore service treatment; a conveyance connected to the downhole tool for moving the downhole tool in the wellbore, and a plurality of sensors operable to provide one or more wellbore indications and attached to the downhole tool or a component thereof via one or more tethers. 
   Further disclosed herein is a method of monitoring a wellbore service treatment, comprising conveying into a wellbore a downhole tool operable to perform the wellbore service treatment and a plurality of sensors operable to provide one or more wellbore indications attached to the downhole tool or a component thereof via one or more tethers, deploying the downhole tool at a first position in the wellbore for service, treating the wellbore at the first position; and monitoring an at least one wellbore indication provided by the wellbore sensors at the first position. 
   These and other features and advantages will be more clearly understood from the following detailed description taken in conjunction with the accompanying drawings and claims. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a more complete understanding of the present disclosure and the advantages thereof, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts. 
       FIG. 1   a  depicts a wellbore and a first tool string in a first stage of a fracturing job. 
       FIG. 1   b  depicts a wellbore and a first tool string in a second stage of a fracturing job. 
       FIG. 1   c  depicts a wellbore and a first tool string in a third stage of a fracturing job. 
       FIG. 1   d  depicts a second tool string and fracturing configuration. 
       FIG. 1   e  depicts a third tool string and fracturing configuration. 
       FIG. 1   f  depicts a fourth tool string and fracturing configuration. 
       FIG. 1   g  depicts a fifth tool string and fracturing configuration. 
       FIGS. 1   h  and  1   i  depict a sixth tool string and fracturing configuration. 
       FIG. 2   a  illustrates a group of tiltmeters tethered together and hanging under a fracturing plug. 
       FIG. 2   b  illustrates a group of tiltmeters attached to wellbore casing. 
       FIG. 2   c  illustrates a group of tiltmeters each tethered separately to a fracturing plug. 
       FIG. 3   a  depicts a data recovery component. 
       FIG. 3   b  depicts an embodiment for tethering a sensor. 
       FIG. 4  is a flow chart illustrating a first method for monitoring a wellbore service treatment. 
       FIG. 5  is a flow chart illustrating a second method for monitoring a wellbore service treatment. 
       FIG. 6  is a flow chart illustrating a third method for monitoring a wellbore service treatment. 
   

   DETAILED DESCRIPTION 
   It should be understood at the outset that although an exemplary implementation of one embodiment of the present disclosure is illustrated below, the present system may be implemented using any number of techniques, whether currently known or in existence. The present disclosure should in no way be limited to the exemplary implementations, drawings, and techniques illustrated below, including the exemplary design and implementation illustrated and described herein. 
     FIGS. 1   a ,  1   b , and  1   c  show a wellbore  10 , which may be cased or uncased, and three stages of a wellbore service job corresponding to a first wellbore service configuration, in  FIG. 1   a , a second wellbore service configuration, in  FIG. 1   b , and a third wellbore service configuration, in  FIG. 1   c . The exemplary wellbore service job depicted is a fracturing service job, but the present disclosure contemplates other wellbore service jobs such as acidizing, gravel packing, cementing, perforating, logging, conducting a survey to collect data, placing downhole sensors, installing and shifting the position of gas lift valves and flow valves, and other wellbore service jobs known to those skilled in the art. The exemplary fracturing job is directed to improving the flow from a zone of interest  14 . In an embodiment shown in  FIGS. 1   a - c , a first tool string  8  comprises a bridge plug  16  and a plurality of sensors  18 —a first sensor  18   a , a second sensor  18   b , a third sensor  18   c , and a fourth sensor  18   d —attached to and hanging from the bridge plug  16 . The sensors  18  may be referred to as a sensor array or an array of sensors. 
   The bridge plug  16  may be generically referred to as a downhole tool. A wide variety of downhole tools may be used within a wellbore in connection with producing hydrocarbons from a hydrocarbon formation. Downhole tools such as frac plugs, bridge plugs, and packers, for example, may be used to seal a component against casing along the wellbore wall or to isolate one pressure zone of the formation from another. In addition, perforating guns may be used to create perforations through casing and into the formation to produce hydrocarbons. Downhole tools are typically conveyed into the wellbore on a wireline, tubing, pipe, or another type of cable. The first tool string  8  provides for the co-deployment and co-retraction of the bridge plug  16  and the sensors  18  using a tubing  20 . 
   The bridge plug  16  is an isolation tool that is operable to shut the well in, to isolate the zones above and below the bridge plug  16 , and to allow no fluid communication therethrough. The bridge plug  16  may be referred to as a sealable member. The sensors  18  may be tiltmeters, geophones, pressure sensors, temperature sensors, combinations thereof, or other sensors operable to sense wellbore characteristics which are known to those skilled in the art. The sensors  18  may each be supported by an individual or dedicated link or tether to the bridge plug  16  as shown in  FIG. 2   c . Alternately, the sensors  18  may be chained or linked together, as shown in  FIGS. 2   a  and  2   b , wherein sensor  18   d  is supported by a link or tether to sensor  18   c , sensor  18   c  is supported by a link or tether to sensor  18   b , sensor  18   b  is supported by a link or tether to sensor  18   a , and sensor  18   a  is supported by a link or tether to the bridge plug  16 . While in this exemplary case four sensors  18  are shown to be employed, in other wellbore service jobs either more or fewer sensors  18  may be employed, for example 1 or more. The embodiments of  FIGS. 2   a - c  may be used with any of the tool string embodiments disclosed herein. 
   In the first wellbore service configuration of  FIG. 1   a , the first tool string  8  has been lowered into the wellbore  10 , below the zone of interest  14 , via a tubing  20 . In another embodiment, the first tool string  8  may be conveyed into the wellbore  10  using wireline, slickline, coiled tubing, jointed tubing, or another conveyance known to those skilled in the art. The bridge plug  16  is placed to seal a lower boundary of the zone of interest  14 . 
   In the second wellbore service configuration of  FIG. 1   b , the tubing  20  has been detached from the bridge plug  16  and withdrawn from the wellbore  10 . A stimulation service pump  22  is connected to a wellhead  24  and provides a fracturing fluid or other wellbore servicing fluid at a desirable pressure, temperature, and flow rate into the wellbore  10 . The fracturing fluid flows down the wellbore  10 , through wellbore casing perforations, into the zone of interest  14 . In an alternative embodiment as shown in  FIGS. 1   h  and  1   i , the tubing may remain attached to the sealable member  19 , e.g., a packer, and the fracturing fluid may be pumped via one or more stimulation service pumps  22  into the zone of interest  14  via an internal flow path  21  inside the tubing  20 , via a flow path  23  in the annular space between the outer wall of tubing  20  and the inside wall of the wellbore  10 , or via both. The fracturing fluid may contain proppants or sand. A fracturing effect  26  is represented by an ellipse. During the course of the fracturing, or other wellbore service job, the sensors  18  collect data on conditions in the wellbore  10 . Hanging off of the bridge plug  16  or sealable member  19 , the sensors  18  are out of the flow of fracturing fluid and hence are not subject to possibly damaging ablation which may occur if proppants are employed. 
   In the third wellbore service configuration in  FIG. 1   c , the tubing has been run back into the wellbore  10 , the tubing  20  has been reattached to the bridge plug  16 , the bridge plug  16  has been disengaged from the wellbore casing, and the tubing  20  is shown withdrawing the first tool string  8  from the wellbore  10 . Alternatively, prior to withdrawing the tool string from the wellbore, the tool string may be redeployed and the treatment steps repeated to fracture multiple zones or intervals. For example, as shown in  FIGS. 1   h  and  1   i , multiple zones or intervals  14   a  and  14   b  within the wellbore  10  may be fractured. While two zones are show in  FIGS. 1   h  and  1   i , it should be understood that more than two zones may be treated in a multi-stage job, and preferably the zones are perforated sequentially starting at the bottom zone and working upward. As shown in  FIG. 1   h  the downhole tool is run into the wellbore via tubing  20  and the sealing member  19 , e.g., a packer, is set. An array of sensors  18   a - d  is tethered to and hangs from the bottom of packer. If not already present, perforations  25  are formed by a perforating component of the downhole tool, for example a hydra-jetting tool or a perforating gun. A treatment fluid such as a fracturing fluid may be pumped, for example via the annular flow path  23 , the flow path  21  inside the tubing, or both, though the perforations  25  and into the formation, thereby creating a fracturing effect  26 . Upon completion of the fracturing, for example as determined via data provided by the sensor array  18   a - d , the packer may be repositioned and reset and additional zones may be treated as shown in  FIG. 1   i.    
   When the first tool string  8  is removed from the wellbore  10 , the sensors  18  may be operably coupled to a monitoring computer to download the data collected by the sensors  18  during the wellbore service job. The sensor data may be analyzed to model the effect of the fracture job and to adjust fracturing parameters for future fracture jobs in similar lithology. The co-deployment and co-retrieval of the bridge plug  16  and the sensors  18  saves extra trips into the wellbore  10  to deploy and retract the sensors  18 . 
   Turning now to  FIG. 1   d , a second tool string  101  is shown comprising a packer  102 , a tool body  104 , a plurality of jets  106 , the bridge plug  16 , and the plurality of sensors  18  in a fourth wellbore service configuration  100   a . The second tool string  101  may be generically referred to as a downhole tool. The packer  102  seals between two areas of the wellbore  10  and contains a valve or conduit therethrough that permits fluid flow in one direction, as shown with arrows, when desirable. The packer  102  may be referred to as a sealable member. The jets  106  are a plurality of orifices in the tool body  104  wherefrom fracturing fluid flows under pressure. In some embodiments, the jets  106  may be inserts which are formed of special materials that resist erosion. The second tool string  101  is attached to the tubing  20  via a connector  108 . The second tool string  101  is shown after having placed the bridge plug  16  to seal a lower boundary of the zone of interest  14 , having disconnected from the bridge plug  16 , having withdrawn from the bridge plug  16 , and having placed the packer  102  to seal an upper boundary of the zone of interest  14 . The use of the packer  102  and the bridge plug  16  confines the fracture fluid and pressure to the region between the packer  102  and the bridge plug  16 , which may be useful when fracturing a wellbore  10  having multiple zones of interest  14  and/or multiple sets of perforations. 
   A fracturing job is shown in progress, with fracturing fluid, which may contain proppants, being pumped down the tubing  20 , through the tool body  104 , out of the jets  106 , into the zone of interest  14 . The sensors  18  hang down from the packer  102 , out of the path of fracturing fluid flow, for example as shown in  FIGS. 2   a  and  2   b . In an embodiment, the sensors  18  may attach themselves to the wellbore wall as in  FIG. 2   b , for example tiltmeters using magnetism to attach to a wellbore casing wall. In an embodiment according to  FIG. 3 , the data recovery component  60  may be employed to provide electrical power to and receive data from the sensors  18  and may be located above the packer  102 . 
   Turning now to  FIG. 1   e , a third tool string  120  is shown comprising the packer  102 , the tool body  104 , the jets  106 , the bridge plug  16 , and the plurality of sensors  18  in a fifth wellbore service configuration  100   b . The third tool string  120  may be generically referred to as a downhole tool. The third tool string  120  is attached to the tubing  20  via the connector  108 . The third tool string  120  is shown after having placed the bridge plug  16  to seal a lower boundary of the zone of interest  14 , having disconnected from the bridge plug  16 , having withdrawn from the bridge plug  16 , and having placed the packer  102  to seal an upper boundary of the zone of interest  14 . The use of the packer  102  and the bridge plug  16  confines the fracture fluid and pressure to the region between the packer  102  and the bridge plug  16 , which may be useful when fracturing a wellbore  10  having multiple zones of interest  14  and/or multiple sets of perforations. 
   A fracturing job is shown in progress, with fracturing fluid, which may contain proppants, being pumped down the tubing  20 , through the tool body  104 , out of the jets  106 , into the zone of interest  14 . The sensors  18  hang above the packer  102 , out of the path of fracturing fluid flow, suspended in the wellbore fluid due to buoyancy or through the action of a propulsion action. In an embodiment, the sensors may attach themselves to the wellbore wall as in  FIG. 2   b , for example tiltmeters using magnetism to attach to a wellbore casing wall. In an embodiment according to  FIG. 3 , the data recovery component  60  may be employed to provide electrical power to and receive data from the sensors  18  and may be located above the packer  102 . 
   Turning now to  FIG. 1   f , a fourth tool string  140  is shown comprising the packer  102 , the tool body  104 , the jets  106 , the bridge plug  16 , and the sensors  18  in a sixth wellbore service configuration  100   c . The fourth tool string  140  may be generically referred to as a downhole tool. The fourth tool string  140  is attached to the tubing  20  via the connector  108 . The fourth tool string  140  is shown after having placed the bridge plug  16  to seal a lower boundary of the zone of interest  14  and having placed the packer  102  to seal an upper boundary of the zone of interest  14 . The use of the packer  102  and the bridge plug  16  confines the fracture fluid and pressure to the region between the packer  102  and the bridge plug  16 , which may be useful when fracturing a wellbore  10  having multiple zones of interest  14  and/or multiple sets of perforations. 
   A fracturing job is shown in progress, with fracturing fluid, which may contain proppants, being pumped down the tubing  20 , through the tool body  104 , out of the jets  106 , into the zone of interest  14 . The sensors  18  hang below the bridge plug  16 , out of the path of fracturing fluid flow, for example as shown in  FIGS. 2   a  and  2   b . In an embodiment, the sensors may attach themselves to the wellbore wall as in  FIG. 2   b , for example tiltmeters using magnetism to attach to a wellbore casing wall. In an embodiment according to  FIG. 3 , the data recovery component  60  may be employed to provide electrical power to and receive data from the sensors  18  and may be located below the bridge plug  16 . 
   Turning now to  FIG. 1   g , a fifth tool string  160  is shown comprising the packer  102 , the tool body  104 , the jets  106 , the bridge plug  16 , and the sensors  18  in a seventh wellbore service configuration  100   d . The fifth tool string  160  may be generically referred to as a downhole tool. The fifth tool string  160  is attached to the tubing  20  via the connector  108 . The fifth tool string  160  is shown after having placed the bridge plug  16  to seal a lower boundary of the zone of interest  14 , having disconnected from the bridge plug  16 , having withdrawn from the bridge plug  16 , and having placed the packer  102  to seal an upper boundary of the zone of interest  14 . The use of the packer  102  and the bridge plug  16  confines the fracture fluid and pressure to the region between the packer  102  and the bridge plug  16 , which may be useful when fracturing a wellbore  10  having multiple zones of interest  14  and/or multiple sets of perforations. 
   A fracturing job is shown in progress, with fracturing fluid, which may contain proppants, being pumped down the tubing  20 , through the tool body  104 , out of the jets  106 , into the zone of interest  14 . The sensors  18  hang below the bridge plug  16 , out of the path of fracturing fluid flow, for example as shown in  FIGS. 2   a  and  2   b . In an embodiment, the sensors may attach themselves to the wellbore wall as in  FIG. 2   b , for example tiltmeters using magnetism to attach to a wellbore casing wall. In an embodiment according to  FIG. 3 , the data recovery component  60  may be employed to provide electrical power to and receive data from the sensors  18  and may be located below the bridge plug  16 . 
   Each of the tool strings may be referred to generally as a downhole tool. While the exemplary wellbore service jobs described above referred to using a bridge plug  16  and a packer  102  in various tool string configurations, those skilled in the art will readily appreciate that other sealable members may be employed to conduct fracturing wellbore service jobs as well as other wellbore service jobs. Other dispositions of the sensors  18  out of the flow of fracture fluid are also contemplated by this disclosure. 
   Turning now to  FIG. 2   a , the first tool string  8  is shown in the wellbore  10  with six tiltmeters (or other appropriate sensors)—a first tiltmeter  50   a , a second tiltmeter  50   b , a third tiltmeter  50   c , a fourth tiltmeter  50   d , a fifth tiltmeter  50   e , and a sixth tiltmeter  50   f -attached to and hanging below the bridge plug  16 , not attached to the wellbore  10 . The first tiltmeter  50   a  is attached to the bridge plug  16  by a first link  52   a . The second tiltmeter  50   b  is attached to the first tiltmeter  50   a  by second link  52   b . The third tiltmeter  50   c  is attached to the second tiltmeter  50   b  by a third link  52   c . The fourth tiltmeter  50   d  is attached to the third tiltmeter  50   c  by a fourth link  52   d . The fifth tiltmeter  50   e  is attached to the fourth tiltmeter  50   d  by a fifth link  52   e . The sixth tiltmeter  50   f  is attached to the fifth tiltmeter  50   e  by a sixth link  52   f.    
   Turning now to  FIG. 2   b , the wellbore  10  is shown with the tiltmeters  50   a - f  attached to the wellbore casing and with desirable slack in each of the links  52   a - f . The slack in each of the links  52   a - f  mechanically isolates the tiltmeters  50   a - f  from one another and from the bridge plug  16 . The slack may be imparted to the links  52   a - f  by performing a maneuver wherein the bridge plug  16  is lowered more quickly than the tiltmeters  50   a - f  can fall in suspension in the fluid in the wellbore  10 , the tiltmeters  50   a - f  are attached to the wellbore  10 , and the bridge plug  16  deploys and seals the wellbore  10 . The tiltmeters  50   a - f  may be designed to deploy a drag structure and/or to increase their buoyancy whereby to slow the descent of the tiltmeters  50   a - f  in the fluid in the wellbore  10 . The drag structure also may be employed to orient the tiltmeters  50   a - f  and to steer them towards the wellbore casing where the tiltmeters  50   a - f  may attach to the wellbore casing, for example employing magnets. 
   In another embodiment, the tiltmeters  50   a - f  may hang in tension, suspended by the links  52   a - f  and simultaneously attached to the wellbore casing without slack in the links. 
   The links  52   a - f  may be chain links; rope wire, or cable tethers; bands, or data transmission cables formed of metal, plastic, rubber, ceramic, composite materials, or other materials known to those skilled in the art. The sensors  50   a - f  may separate the links  52   a - f , forming part of the weight bearing structure supporting sensors located below. Alternately, the links  52   a - f  may form a continuous chain or tether, and sensors  50   a - f  may be attached thereto without forming part of the weight bearing structure. The links  52   a - f  may also serve as data communication pathways between the sensors  50   a - f  and a memory module  60 , as in  FIG. 3   a.    
   The discussion of how the sensors  50   a - f  are suspended from the bridge plug  16  and attached to the wellbore casing also applies to the alternative tool strings illustrated in  FIGS. 1   d - i.    
   Turning now to  FIG. 3   a , in some embodiments of the first tool string  8  a data recovery component  60  may attached as shown to the bottom of the bridge plug  16 . The data recovery component  60  comprises a battery  62  and a memory tool  64 . The battery  62  provides electrical power via a first cable  66   a  to the first sensor  18   a . The memory tool  64  communicates with and receives data from the first sensor  18   a  through the first cable  66   a  and stores this data, to be downloaded by a monitoring computer at the surface when the first tool string  8  is withdrawn from the wellbore  10 . In some embodiments, the memory tool  64  may provide data collection commands, data collection timing signals, and or excitation signals to the sensors  18  through the first cable  66   a.    
   The memory tool  64  may be a data recording device such as for example a microcontroller/microprocessor associated with a memory and operable to receive and store data from the sensors  18 . Electrical power is provided to and data is returned from each of the sensors  18  through a path comprising the first cable  66   a , the first sensor  18   a , a second cable  66   b  attached between the first sensor  18   a  and the second sensor  18   b , the second sensor  18   b , a third cable  66   c  attached between the second sensor  18   b  and the third sensor  18   c , the third sensor  18   c , a fourth cable  66   d  attached between the third sensor  18   c  and the fourth sensor  18   d , and the fourth sensor  18   d.    
   A first chain  68   a  is shown supporting the weight of the sensors  18 . The first chain  68   a  is shown attached to the data recovery component  60 , but in some embodiments the first chain  68   a  may attach to the bridge plug  16 . A second chain  68   b , a third chain  68   c  (not shown), and a fourth chain  68   d  (not shown) are interconnected through the bodies of the sensors  18  and support the weight of the sensors  18 . In an alternate embodiment as shown in  FIG. 3   b , the chains  68  attach to each other to form a continuous chain and the sensors attach thereto via attachment  69  without bearing any of the weight. The chains  68  may be constructed of metal, plastic, ceramic, or other materials. Support linkages other than chain also are contemplated, such as a flexible chord. 
   In some embodiments, the cable  66  and the chain  68  attached to each sensor  18  may attach directly to the data recovery component  60 . In an embodiment, the cable  66  may be a continuous cable with Tee-like drop connections provided along the length of the continuous cable for coupling to the sensors  18 . In some embodiments the cable  66  and the chain  68  may be enclosed in a sheath to prevent entanglements and to protect the cable  66  and chain  68  from hazards in the wellbore  10 . The cable  66  may be interwoven in the chain  68 . In an embodiment, the cable  66  may be integrated with the chain  68  or a tether. 
   The discussion of the data recovery component  60  also applies to the alternative tool strings illustrated in  FIGS. 1   d - i.    
   In some embodiments, a communication path may be provided between the surface and the downhole tool  16  and/or the sensors  18 . The communication path may be contained by the tubing, for example provided by a cable inside or embedded in the walls of the tubing  20 . In addition to or alternatively, the communication path may be provided by a wireless link such as radio link, an optical link, and/or an acoustic link through the fluid in the wellbore  10 . 
   A communication path between the surface and the second tool string  101 , the third tool string  120 , and the fourth tool string  140 , for example through a cable inside or embedded in the walls of the tubing  20  to a monitoring computer located at the surface, may be provided by the tubing  20 . This capability, which may be termed a real-time fracture monitoring capability or near real-time fracture monitoring capability, could be employed to monitor a wellbore servicing operation such as detecting pumping of fracturing fluid into a water bearing formation. Pumping fracturing fluid into a water bearing formation increases flow of water, which is generally not desirable. Being able to detect this event permits stopping the fracturing job and minimizing the fracturing of the water bearing formation. Additionally, this real-time or near real-time fracture monitoring capability may be employed to adaptively control the fracture job, such as stopping pumping of fracturing fluid after data from the sensors  18  fed into a fracture model generated by the monitoring computer indicates an optimal fracture stage has been arrived at. 
   In an embodiment, an acoustic communication link between the surface and the first tool string  8 , such as using hydraulic telemetry, may be established. This communication link may be used to monitor fracturing processes while fracturing is in progress as described above. 
   In one embodiment, a communication path between the surface and the fifth tool string  160  by providing a connectionless communication link between the bridge plug  16  and the packer  102  and by providing a connected communication link, for example a wire cable within the tubing  20 , from the packer  102  to the surface. The connectionless communication link may be provided by a radio link, an optical link, or an acoustic link, such as using hydraulic telemetry, through the fluid between the bridge plug  16  and the packer  102 . The communication path between the bridge plug  16  and the surface may support the ability to monitor fracturing processes while fracturing is in progress as described above. 
   In other embodiments, a combination of these communication link technologies may be employed to provide the ability to monitor fracturing processes or other wellbore service operations in real-time or near real-time. 
   Turning now to  FIG. 4 , a flow chart is shown of a first method for using the various tool strings of the present disclosure such as shown in  FIGS. 1   a - c . The first method begins at block  200  where a sealing member such as the bridge plug  16  or a packer, the sensors  18 , and the tubing  20  are co-deployed downhole. The first method proceeds to block  202  where the bridge plug  16  is seated in the wellbore casing and seals the wellbore  10  below the bridge plug  16  from the wellbore  10  above the bridge plug  16 . The first method proceeds to block  204  where the tubing  20  detaches from the bridge plug  16 . The first method proceeds to block  206  where the tubing  20  is retracted from the wellbore  10 . 
   The first method proceeds to block  208  where a wellbore service procedure such as a fracturing job is conducted. This involves pumping fracturing fluid down the wellbore  10  at the appropriate pressure, temperature, and flow rate with the appropriate mix of materials, such as proppants and fluids. The parameters for a specific fracturing job are engineered for a specific lithology or field based on experience and data obtained during previous fracture jobs, as is well known to those skilled in the art. Upon completion of pumping, the first method proceeds to block  210  where the tubing  20  is deployed into the wellbore  10  and reattaches to the bridge plug  16 . 
   The first method proceeds to block  212  where the bridge plug  16  detaches from the wellbore casing. The first method proceeds to block  214  where the tubing  20  is retracted from the wellbore  10 , drawing out with it the bridge plug  16  and the sensors  18 . 
   The first method proceeds to block  216  where the data collected by the sensors  18  is downloaded to a first computer system. The first method proceeds to block  218  where the data downloaded from the sensors is employed to characterize the fracture job by modeling on a second computer system. This first and second computer systems may be the same computer, or they may be different computers. The characterization of the fracture job of block  218  may occur at the location of the wellbore  10  or it may occur away from the location of the wellbore  10 , for example at a headquarters or at an office. 
   Observe that the first method described above saves extra trips into the wellbore  10  to deploy and retrieve the sensors  18 , for example using a wireline equipment. In the first method the sensors  18  are co-deployed and co-retracted with the bridge plug  16 . 
   Turning now to  FIG. 5 , a flow chart is shown of a second method for using the various tool strings of the present disclosure such as is shown in  FIGS. 1   h  and  1   i . The second method is related to the first method but is different by providing fracturing of multiple zones within the wellbore  10 . The second method begins at block  220  where a sealing member such as the bridge plug  16  or a packer, the sensors  18 , and the tubing  20  are co-deployed downhole. The second method proceeds to block  221  where the bridge plug  16  is seated in the wellbore casing and seals the wellbore  10  below the bridge plug  16  from the wellbore  10  above the bridge plug  16 ; where the tubing  20  detaches from the bridge plug  16 ; and where the tubing  20  is retracted from the wellbore  10 . 
   The first method proceeds to block  222  where a wellbore service procedure such as a fracturing job is conducted. This involves pumping fracturing fluid down the wellbore  10  at the appropriate pressure, temperature, and flow rate with the appropriate mix of materials, such as proppants and fluids. The parameters for a specific fracturing job are engineered for a specific lithology or field based on experience and data obtained during previous fracture jobs, as is well known to those skilled in the art. Upon completion of pumping, the second method proceeds to block  223  where the tubing  20  is deployed into the wellbore  10 , the tubing  20  reattaches to the bridge plug  16 , and the bridge plug  16  detaches from the wellbore casing. 
   The second method proceeds to block  224  where if another zone of the wellbore  10  remains to be fractured, the second method proceeds to block  225 . In block  225  the bridge plug  16  and sensors  18  are repositioned to fracture the next zone of the wellbore  10 , for example at a position further out of the wellbore  10 . The second method proceeds to block  221 . By repeatedly looping through blocks  221 ,  222 ,  223 ,  224 , and  225  multiple zones of the wellbore  10  may be fractured. Note that the sensors  18  attached to the bridge plug  16  are not deployed into and retracted from the wellbore  10  between each of the fracturing operations, thus saving numerous extra trips into and out of the wellbore  10 . The sensors  18  detect, collect, and store data for each of the multiple fracturing operations. 
   In block  224  if no additional zones of the wellbore  10  remain to be fractured, the second method proceeds to block  226  where the tubing  20  is retracted from the wellbore  10 , drawing out with it the bridge plug  16  and the sensors  18 . 
   The second method proceeds to block  227  where the data collected by the sensors  18  is downloaded to a first computer system. The second method proceeds to block  228  where the data downloaded from the sensors is employed to characterize the multiple fracture jobs by modeling on a second computer system. This first and second computer systems may be the same computer, or they may be different computers. The characterization of the fracture job of block  228  may occur at the location of the wellbore  10  or it may occur away from the location of the wellbore  10 , for example at a headquarters or at an office. 
   Observe that the second method described above saves multiple extra trips into the wellbore  10  to deploy and retrieve the sensors  18 , for example using wireline equipment. In the second method the sensors  18  are co-deployed and co-retracted with the bridge plug  16 . 
   Turning now to  FIG. 6 , a flow chart is shown of a third method for using the various tool strings of the present disclosure such as second tool string  101 , the third tool string  120 , the fourth tool string  140 , or the fifth tool string  160 . The third method begins at block  230  where a sealing member such as the bridge plug  16  or a packer, the sensors  18 , the first tool string  101 , and the tubing  20  are deployed into the wellbore  10 . The third method proceeds to block  232  where the bridge plug  16  is seated in the wellbore casing and seals the wellbore  10  below the bridge plug  16  from the wellbore  10  above the bridge plug  16 . 
   The third method proceeds to block  234  where a fracturing job is started. This involves pumping fracturing fluid down the wellbore  10  at the appropriate pressure, temperature, and flow rate with the appropriate mix of materials, such as proppants and fluids, as is well known to those skilled in the art. 
   The third method proceeds to block  236  where the sensors  18  are monitored at the surface by a first computer system. The monitoring includes gathering data from each of the sensors  18  and analyzing the gathered data. Analysis may include feeding the gathered data into a fracture model which predicts fracture progress based on a history of sensor data. The results of the analyzing the gathered data provides input to fracture job operators making a decision to continue pumping fracturing fluid, to stop pumping fracturing fluid, and perhaps to change the material mix of the fracturing fluid or other fracture job parameters such as pressure, temperature, and flow rate. 
   In an embodiment, in block  236  the pumping of fracturing fluid into the wellbore is completely ceased. Substantial vibration may be produced in the wellbore by the pumping of fracturing fluid, and this vibration may interfere with the sensors  18  monitoring the progress of the fracturing job. In another embodiment, in block  236  the pumping of fracturing fluid continues. 
   The third method proceeds to block  238  where if the fracturing fluid is not being pumped into a water bearing formation the third method proceeds to block  240 . In block  240 , if the fracture job is not complete, the third method returns to block  234  and the fracture job continues. 
   If in block  238  the fracturing fluid is being pumped into a water bearing formation the third method proceeds to block  242 . Similarly, if in block  240  the fracturing job is complete the third method proceeds to block  242 . In block  242  the pumping of fracturing fluid is stopped. The third method proceeds to block  244  where the bridge plug  16  detaches from the wellbore casing, and the tubing  20  is retracted from the wellbore  10 , drawing out with it the first tool string  101 , the bridge plug  16 , and the sensors  18 . 
   Observe that the third method described above saves extra trips into the wellbore  10  to deploy and retrieve the sensors  18 , for example using wireline equipment. In the third method the sensors  18  are co-deployed with the first tool string  101  or with the bridge plug  16  and co-retracted with the first tool string  101  or with the bridge plug  16 . Additionally, the third method permits on-location adaptation of fracture job plans to better accord with the circumstances detected, in real-time or near real-time, by the sensors  18 . 
   While several embodiments have been provided in the present disclosure, it should be understood that the disclosed systems and methods may be embodied in many other specific forms without departing from the spirit or scope of the present disclosure. The present examples are to be considered as illustrative and not restrictive, and the intention is not to be limited to the details given herein, but may be modified within the scope of the appended claims along with their full scope of equivalents. For example, the various elements or components may be combined or integrated in another system or certain features may be omitted, or not implemented. 
   Also, techniques, systems, subsystems and methods described and illustrated in the various embodiments as discreet or separate may be combined or integrated with other systems, modules, techniques, or methods without departing from the scope of the present disclosure. Other items shown as directly coupled or communicating with each other may be coupled through some interface or device, such that the items may no longer be considered directly coupled to each but may still be indirectly coupled and in communication with one another. Other examples of changes, substitutions, and alterations are ascertainable by one skilled in the art and could be made without departing from the spirit and scope disclosed herein.