Abstract:
A system and method are disclosed for efficient and reliable deployment of radioactive markers and remote sensors in earth formations through cased wellbores. The markers and sensors are permanently deployed to obtain data on compaction, pressure and other useful formation properties.

Description:
BACKGROUND OF THE INVENTION  
         [0001]    1. Field of the Invention  
           [0002]    The present invention relates to a method for measuring compaction and other formation properties adjacent a subterranean wellbore using radioactive markers or sensors. More particularly, the method includes a system which can be reliably used after casing is run in the wellbore.  
           [0003]    2. Description of Related Art  
           [0004]    Many subterranean reservoirs undergo compaction as hydrocarbons within the reservoir are produced or extracted and the fluid pressure in the reservoir decreases. As a result, compaction of the formation surrounding the reservoir, and even collapse of the wellbore used to access the reservoir, are likely to occur. In the absence of any reliable means to measure compaction or pressure, peak production rates are compromised in order to reduce the risk that the wellbore may collapse. Thus, information from compaction measurements can maximize production rates from reservoirs currently underutilized for fear of collapse. Likewise, knowing the differential pressure between different vertical zones of a formation, merely assumed to be at equilibrium, or knowing the relative production flow rates from various layers of the formation can improve production capacity from the reservoir. Consequently, the efficient production of hydrocarbons from a subterranean reservoir typically requires knowledge of various formation properties and parameters during the productive life of the reservoir, such as compaction and pressure.  
           [0005]    Compaction is typically measured by the movement of the formation in and above and below a production zone or reservoir. In order to measure this movement, multiple radioactive markers are deployed directly into the formation and the surrounding region of interest representing a reservoir as the wellbore is being drilled. Each marker is identified by a unique radioactive signal which is monitored by conventional means within the wellbore, even after the wellbore is completed. Other formation properties such as pressure, temperature, and resistivity require more complicated electronics embodied in conventional sensors which are deployed directly into the formation surrounding the reservoir and/or directly into the production zone of the reservoir. Because conventional sensors are unable to communicate through the casing once the wellbore is completed, these sensors are extremely limited in their practical use.  
           [0006]    One well-known method used to deploy markers and sensors requires a ballistic charge which essentially fires the marker or sensor directly into the formation. Several patents exemplify a “ballistic” means for deployment of markers such as U.S. Pat. Nos. 3,869,607; 4,396,838; and 5,753,813. This method, however, is associated with numerous inherent disadvantages. As markers are fired into the formation, they are often lost in the formation or get dislodged and circulate back to the surface in a slurry which poses environmental concerns. Further, the markers can either end up too far into the formation to detect or drop to the bottom of the wellbore, in either case being rendered useless. This method is particularly undesirable if the marker needs to be placed in a wall of the casing, commonly referred to as tagging. In most situations, cased wells simply cannot be tagged using this method.  
           [0007]    The disadvantages inherent in a ballistic means for deployment are compounded when sensors are used. For example, U.S. Pat. Nos. 6,028,534; 6,234,257; and 6,467,387 each disclose a means to deploy data sensors during the drilling phase by shooting the sensor directly into the formation. For successful deployment, the sensor must survive both the launch and impact of the formation without substantial deformation or disintegration of any internal component; the sensor must ensure sufficient and straight penetration into all types of formation; and it must be capable of RF or other wireless communication through the formation to the data processing components in the wellbore. To this end, the &#39;534 and &#39;257 patents each disclose a means for communicating with each sensor to determine its location after it is deployed. Accordingly, these patents describe the use of a gamma ray pip-tag which is used in each sensor to emit a distinctive radioactive signal like that of a marker. This process, however, involves additional time and expense which adversely impacts the overall productivity of the reservoir.  
           [0008]    The tools and methods described by the foregoing patents are undoubtedly impaired by the ballistic means used to deploy the markers and sensors. Further, this means of deployment is encumbered by the casing and may compromise production pressure within the wellbore where perforations are made in non-producing zones. In addition to these disadvantages, conventional communication between each sensor and the wellbore is cut off once the casing is run in the wellbore.  
           [0009]    Accordingly, formation testing tools for use in cased wellbores, as exemplified by U.S. Pat. Nos. 6,070,662; 5,692,565; and 5,875,840, are often preferred. Like many formation testing tools used in wellbores without casing, these tools are generally limited to the acquisition of formation data while the tool is disposed in the wellbore and in physical contact with the formation region of interest. In other words, these tools are not designed to deploy markers or sensors capable of measuring formation properties over time.  
           [0010]    For example, the &#39;565 patent, incorporated herein by reference, describes a method for sampling formation properties behind a cased wellbore. As shown in FIG. 1 of the &#39;565 patent (reproduced herein as FIG. 1) a flexible drilling shaft  18  is used to create a uniform casing perforation through which fluids may be extracted from the formation  10  and sampled. The inner housing  14  of the tool  12  contains a cartridge  26  which holds several plugs. A translation piston  16  shifts the inner housing  14  to move the cartridge  26  into position. A plug setting piston  25  then forces a plug from the cartridge  26  into the casing wall  11  to seal the perforation. This process can be repeated using several plugs in a single descent. Upon completion of the sampling process, the casing perforation is plugged, thereby preventing any further communication with the formation without repeating the perforation process.  
           [0011]    As shown in FIG. 6 c  of the &#39;565 patent (reproduced herein as FIG. 2) the tool  12  is designed to push a hollow steel plug  79  into the perforation in the casing wall to seal the casing  11  and provide pressure integrity. The plug  79  is composed of a tubular socket and a tapered plug  77 . The tubular socket has a closed front end, a lip  78  and grooves in the center. The tapered plug  77  is inserted in the open end of the socket component. The lip  78  holds the socket and prevents it from sliding past the casing wall during insertion.  
           [0012]    Conventional formation testing tools and methods, like that described by the &#39;565 patent, consume substantial rig time. In most applications, the drill string must be removed from the wellbore before running the formation testing tool into the wellbore. Likewise, the formation testing tool must be removed from the wellbore before further production operations can be resumed.  
           [0013]    Accordingly, it is a primary object of the present invention to provide an improved system and method for measuring compaction and other formation properties through cased wellbores using markers and/or sensors. It is a further object of the present invention to provide a system and method which enables more accurate and permanent placement of each marker and sensor in the formation.  
           [0014]    It is another object of the present invention to provide a more efficient and reliable system and method for placing markers and sensors in the formation after the wellbore is lined with casing.  
           [0015]    It is another object of the present invention to provide an environmentally safe system and method for placing markers and sensors in the formation.  
           [0016]    It is another object of the present invention to provide a system and method which enables the placement of markers within the casing for tagging.  
           [0017]    One advantage is the ability to communicate with sensors placed in the formation using the system and method of the present invention after the casing is run.  
           [0018]    Another advantage is the ability to precisely locate sensors placed in the formation using the system and method of the present invention after the casing is run.  
         SUMMARY OF THE INVENTION  
         [0019]    The present invention is therefore designed to accomplish the foregoing objects and advantages, as well as various other objects and advantages, using a unique system and method that enables efficient, accurate and permanent placement of each marker and sensor in the formation through a cased wellbore. The system generally comprises a plurality of markers and/or sensors, depending on the particular formation property to be measured, and a means for deployment of the markers and sensors through the casing into the formation. Conventional means are used to seal perforations in the casing and communicate with each sensor. Markers are used to measure compaction of the formation while sensors may be used for the same purpose and to measure other formation properties such as pressure, temperature and resistivity. In short, the present invention substantially improves the efficiency and effectiveness of measuring compaction and other formation properties through cased wellbores.  
           [0020]    In one embodiment of the invention, the deployment means comprises a tool with an inner housing. The inner housing includes a drill for perforating the casing and boring through a cement sheath or liner, as necessary, into the formation. The drill therefore, creates a separate passage through the casing, cement and formation at a desired depth and azimuth within the wellbore. Once each passage is complete, the drill is removed from the passage and the tool, suspended on a cable, is adjusted within the wellbore to align a cartridge within the inner housing containing markers and/or sensors with the passage. A piston then sets a first marker or first sensor in the casing. Once set, the inner housing is adjusted again to allow the drill to return to the passage where the first marker or first sensor is positioned in the casing. The drill, which is disabled from rotating, then forces the first marker or first sensor through the passage into the formation. In this manner, the exact location (depth and azimuth) of each marker and sensor may be immediately communicated to the surface and recorded upon its deployment, thereby eliminating the need for additional conventional tools and methods which are required to locate markers and sensors before the wellbore is lined with casing.  
           [0021]    Once the first marker or first sensor is permanently in place, the drill is retracted within the inner housing and the process repeated using a second marker or second sensor at the same, or different, depth and azimuth in the wellbore as needed. Once the process is complete at a desired depth, the passage (perforation) through the casing is sealed. Depending on whether the casing must be tagged or whether sensors are deployed into the formation, the casing may be permanently sealed with a marker or in a manner that enables communication with a sensor.  
           [0022]    The foregoing process is repeated until the requisite number of markers and sensors are deployed within the formation, cement and casing or until the deployment means must be retracted to reload the cartridge with additional markers and/or sensors. Depending on the formation property of interest and other wellbore conditions, multiple markers and sensors may be positioned within the formation at the same depth. Nevertheless, each passage through the casing is preferably sealed before production begins.  
           [0023]    In one embodiment of the invention, multiple markers are used to measure compaction of the formation. Each marker generally comprises a substantially cylindrical housing having a bore which extends through an opening at one end of the marker housing. A plug is partially disposed through the opening within the bore and is integrally connected to the marker housing, however, may be tapered to provide a force fit within the bore. In either case, the bore is large enough to accommodate a radioactive element which is encased in a protective element positioned between a terminal end of the bore and a one end of the plug. Each marker is designed to pass freely through the passage or perforation made in the casing by the drill and includes a shearable lip circumscribing the opening in the marker housing. Upon contact with the inside diameter of the casing, the lip is sheared as the marker passes through the casing into the formation. In another embodiment, however, the marker may be used to seal the perforation in the casing using a different, slightly larger, marker housing. In this embodiment, the lip is an integral part of the marker housing and the plug is force-fit within the bore so that when the lip meets the inside diameter of the casing, preventing further movement of the marker, the plug proceeds within the bore thereby causing the end of the marker housing near the lip to expand within the perforation—reinforcing the seal where the marker housing contacts the casing. Thus, the marker, in this embodiment, can be used to tag the casing and seal the passage. Alternatively, the radioactive element and protective element may be eliminated if tagging is undesirable.  
           [0024]    In another embodiment of the invention, a sensor is used to measure formation properties, such as pressure, temperature and resistivity. The sensor, like the marker, comprises a substantially cylindrical housing with a bore partially disposed through an opening at one end of the sensor housing. A plug is partially disposed through the opening and within the bore. In either case, the bore is large enough to accommodate the sensor electronics and antenna positioned between a terminal end of the bore and a one end of the plug. Additionally, the sensor housing includes a conduit which permits fluid communication between the formation and bore which contains the sensor electronics. The sensor electronics generally comprise components well-known to those skilled in the art such as a data sensor for measuring the various formation properties of interest (e.g., pressure, temperature or resistivity), a receiver for receiving remotely transmitted signals, and a transmitter for transmitting a signal representative of the sensor indicated property. In this embodiment, however, the plug is preferably connected to the sensor housing in order to prevent accidental impingement upon the sensor electronics and antenna. Each sensor is designed to pass through the passage or perforation made in the casing by the drill and includes a shearable lip circumscribing the opening in the sensor housing. Upon contact with the inside diameter of the casing, the lip is sheared as the sensor passes through the casing into the formation. In another embodiment, however, the sensor may be used to seal the perforation in the casing using a different, slightly larger, sensor housing. In this embodiment, the lip is an integral part of the sensor housing and the plug is force-fit within the bore so that when the lip meets the inside diameter of the casing, preventing further movement of the sensor, the plug proceeds within the bore thereby causing the end of the sensor housing near the lip to expand within the perforation—reinforcing the seal where the sensor housing contacts the casing. Thus, the sensor, in this embodiment, can be used to tag the casing, seal the passage and facilitate communication with other sensors deployed in the same passage. Alternatively, the sensor electronics may be eliminated if tagging is undesirable.  
           [0025]    Because the markers and sensors are deployed in a non-ballistic manner through the casing into the formation, they may be manufactured from conventional materials which require less resistance to the ballistic forces typically encountered by conventional deployment means. The use of less resistant materials also facilitates improved communication between the sensor electronics to a position within the wellbore.  
           [0026]    Once each marker and/or sensor are permanently in place, the corresponding formation properties of interest are monitored by means generally known to those skilled in the art.  
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0027]    The present invention is described with reference to the accompanying drawings. In the drawings, like reference numbers indicate identical or functionally similar elements.  
         [0028]    [0028]FIG. 1 is a cross-sectional side view of the tool disclosed in FIG. 1 of the &#39;565 patent.  
         [0029]    [0029]FIG. 2 is a cross-sectional side view of the plug disclosed in FIG. 6 c  of the &#39;565 patent.  
         [0030]    [0030]FIG. 3 is a cross-sectional side view of a formation marker of the present invention.  
         [0031]    [0031]FIG. 4 is a cross-sectional side view of the formation marker in FIG. 3 shown passing through the casing wall.  
         [0032]    [0032]FIG. 5 is a cross-sectional side view of a casing marker of the present invention.  
         [0033]    [0033]FIG. 6 is a partial cross-sectional side view of a logging tool suspended in a subterranean wellbore adjacent markers positioned in the casing, cement and formation.  
         [0034]    [0034]FIG. 7 is a cross-sectional side view of a sensor of the present invention.  
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0035]    Deployment Means  
         [0036]    Referring to FIG. 1, the system includes a deployment means or tool  12 . The tool  12  is suspended on a cable  13  inside a wellbore. The wellbore is drilled using methods well known in the art of oil and gas exploration. A casing wall  11  is added to stabilize and provide support for the rock formation  10  surrounding the wellbore. Cement  10   b  is also often added to the outside of the casing  11  to hold the casing  11  in place and provide support and a seal between the formation  10  and the casing  11 .  
         [0037]    The primary components of the tool  12  include an inner housing  14  containing a drill  19  operated by a translation motor  22  and a drive motor  20 . The housing  14  also contains a cartridge  26  which holds a plurality of markers and/or sensors. A housing translation piston  16  located within the body  17  of the tool  12  shifts the housing  14  to move the cartridge  26  or drill  19  into position. When the cartridge  26  is in position, a setting piston  25  forces a marker or sensor from the cartridge  26  into the casing  11 . As described further in reference to FIG. 6, the tool  12  can deploy several markers through the casing into the formation  10  during a single descent within the wellbore.  
         [0038]    The tool  12  also includes a fluid sampling means  24   b  which is unnecessary for the purposes of the present invention. Therefore, the fluid sampling means  24   b  is preferably eliminated to provide additional space in the housing  14  for a larger cartridge  26 . Additionally, removal of the fluid sampling means  24   b  allows the tool  12  to be made more compact and economical. The cartridge  26  within the housing  14  may also be modified to include a circular design allowing the cartridge  26  to surround the drill  19 . Consequently, the cartridge  26  would not have to move as far when it is maneuvered into position after drilling.  
         [0039]    The Markers  
         [0040]    Depending on the formation property to be measured, the system may include a plurality of radioactive markers to measure compaction of the formation surrounding a region of interest or reservoir. Referring now to FIG. 3, each marker  42  generally comprises a substantially cylindrical marker housing  45  having a bore  47  which extends through an opening at one end of the housing  45 . A plug  46  is partially disposed through the opening within the bore  47 , and is integrally connected to the marker housing  45 , however, may be tapered to provide a force-fit within the bore  47 . In either case, the bore  47  is large enough to accommodate a radioactive element  44  that is encased by a protective element  43  positioned between a terminal end of the bore  48  and one end of the plug  49 . It will be appreciated by those skilled in the art that the radioactive element  44  may be a cesium wire with a unique signature or signal that is capable of being detected through the protective element  43  (e.g., steel) and the casing  11 . It is contemplated, however, that the radioactive element  44  and protective element  43  may be positioned at other locations within the marker  42  without departing from the spirit of the invention. For example, the radioactive element  44  and protective element  43  could easily be placed in a milled out area within the plug  46  or press fit into a milled out area in the marker housing  45  at the terminal end of the bore  48 .  
         [0041]    Each marker which is deployed through the casing  11  into the cement  10   b  or formation  10  is designed to pass freely through the passage or perforation  54  made in the casing  11  by the drill  19  and includes a shearable lip  53  circumscribing the opening in the marker housing  45 . Upon contact with the inside diameter of the casing  11 , the lip  53  is sheared as the marker  42  passes through the casing  11  into the cement  10   b  as shown in FIG. 4.  
         [0042]    In another embodiment, however, the marker may be used to seal the perforation in the casing using a different, slightly larger, marker housing  45   b  as shown in FIG. 5. In this embodiment, the lip  53   b  is an integral part of the marker housing  45   b  and the plug  46  is force fit within the bore  47  so that when the lip  53   b  meets the inside diameter of the casing  11 , preventing further radial movement of the marker  42   b , the plug  46  proceeds within the bore  47  thereby causing the end of the marker housing  45   b  near the lip  53   b  to expand within the perforation  54 —reinforcing the seal where the marker housing  45   b  contacts the casing  11 . Thus, the marker  42   b , in this embodiment, can be used to tag the casing  11  and seal the passage  54 . Alternatively, the radioactive element  44  and protective element  43  may be eliminated if tagging is undesirable.  
         [0043]    Using the tool  12  shown in FIG. 1 and a plurality of markers like the marker described in reference to FIG. 3, compaction of the formation surrounding a region of interest or reservoir can be measured and constantly monitored, if necessary. Additionally, the casing can be tagged in the manner thus described in reference to FIG. 5 for marking reference points on the casing and/or determining relative movement between the casing and the formation. As described further below, the precise alignment between the casing, cement and formation at any given depth can be monitored using the system and method of the present invention, which is useful for determining if a passage through the casing into the formation is blocked due to relative movement between the casing, cement and formation.  
         [0044]    Referring now to FIGS. 1 and 6, one application or use of the tool  12  to measure compaction formation parameters is exemplified. A passage  54  is formed through the casing  11 , cement  10   b  and formation  10  using the drill  19  at a predetermined depth and azimuth relative to the wellbore. The drill  19  is then removed from the passage  54  and the housing  14  is adjusted to align a first marker  33  carried in the cartridge  26  with the passage  54 . The radioactive element  40  in each marker emits a signal unique to each marker for distinguishing it from the other markers. Once the marker  33  is aligned with the passage  54 , the setting piston  25  forces the marker  33  into a position within the casing  11 . After the marker  33  is inserted into the casing  11 , the housing  14  is adjusted to realign the drill  19  with the marker  33 . The drill  19  is then used to push the marker  33  through the casing  11  and cement  10   b  into a final position in the formation  10  as shown in FIG. 6. In order to prevent damage to the marker  33 , the drill  19  is disabled from rotation during insertion of the marker  33 . Thus, the drill  19  merely pushes the marker  33  to the final position in the formation  10 .  
         [0045]    Once the first marker  33  is in place, the drill  19  is retracted from the passage  54  and the housing  14  is adjusted to align a second marker  34  in the cartridge  26  with the passage  54 . The second marker  34  is thus, positioned in the same manner as the first marker  33 , however, at a final position in the cement  10   b  as shown in FIG. 6.  
         [0046]    Once the second marker  34  is in place, the drill  19  is retracted from the passage  54  and the housing  14  is adjusted to align a third marker  35  in the cartridge  26  with the passage  54 . The third marker  35 , however, is set at a final position within the casing  11  as shown in FIG. 6. Because the third marker  35  is positioned in the casing  11 , only the setting piston  25  is needed to position the third marker  35 .  
         [0047]    Because compaction is measured using markers typically positioned in the formation surrounding the reservoir, perforations in the casing where each passage is formed are undesirable. Consequently, it is often necessary to seal each passage with a marker as exemplified by the marker shown in FIG. 5. Thus, the third marker  35  can be used for tagging the casing  11  and sealing the passage  54 . Alternatively, the radioactive element  44  and protective element  43  may be eliminated if tagging is undesirable.  
         [0048]    Still referring to FIGS. 1 and 6, another passage  55  is formed through the casing  11 , cement  10   b  and formation  10  at another predetermined depth and azimuth using the drill  19 . In the same manner thus described for positioning the first marker  33 , second marker  34  and third marker  35 , a fourth marker  36 , fifth marker  37 , and sixth marker  38  are positioned within the formation  10 , cement  10   b  and casing  11 , respectively. Additional markers may be deployed in the same manner at various positions within the casing  11 , cement  10   b  and formation  10  as deemed necessary. This process may be repeated during a single descent within the wellbore until the tool  12  must be removed from the wellbore to load the cartridge  26  with additional markers.  
         [0049]    Once each marker is permanently in place, compaction may be measured by conventional means generally known to those skilled in the art. Illustrative of one such means is the use of the logging tool  39  shown in FIG. 6. The logging tool  39  is inserted into the wellbore  41  to measure the movement between multiple markers over time. The first marker  33 , second marker  34 , and third marker  35  represent a first set of markers positioned above a region of interest indicative of a reservoir and the fourth marker  36 , fifth marker  37  and sixth marker  38  represent a second set of markers positioned below the region of interest. Spectral gamma ray detectors  40  are positioned on the logging tool  39  in spaced relation to one another that corresponds with the distance (d) between the first set of markers and the second set of markers. Each detector  40  is capable of detecting at least one unique radioactive signal emitted by a marker. As the logging tool  39  moves within the wellbore  41  past the first set of markers and second set of markers, an initial position is detected for each set of markers. Once the initial position of the first set of markers and second set of markers is recorded, the logging tool  39  is then used to monitor longitudinal movement of the first set of markers and second set of markers over time.  
         [0050]    For example, at some time during the production process, compaction may be monitored by lowering the logging tool  39  within the wellbore  41 . Because the exact location (depth and azimuth) of the first set of markers and second set of markers was recorded upon their initial deployment, the detectors  40  are able to detect whether the first set of markers and second set of markers are closer together, indicating compaction. Similarly, the detectors  40  are able to detect whether there is longitudinal movement between the first marker  33  and the third marker  35 , or the fourth marker  36  and the sixth marker  38 , indicating a shift between the formation  10  and casing  11 . In either case, the ability to monitor these parameters over time is invaluable to the overall productivity of the reservoir.  
         [0051]    The Sensors  
         [0052]    In the same manner thus described for the deployment of markers, a plurality of sensors may be deployed to measure compaction and other formation properties such as pressure, temperature and resistivity.  
         [0053]    Referring now to FIG. 7, a sensor  65 , like the marker, comprises a substantially cylindrical housing  51  having a bore  61  which extends through an opening at one end of the sensor housing  51 . A plug  52  is partially disposed through the opening within the bore  61 . The bore  61  is large enough to accommodate the sensor electronics  50  and antennae  60  positioned between a terminal end of the bore  62  and one end of the plug  63 . It is contemplated, however, that the sensor electronics  50  and antennae  60  may be placed at other locations within the sensor housing  51  without departing from the spirit of the invention. Additionally, the sensor housing  51  includes a conduit  56  which permits fluid communication between the formation  10  and the bore  61  containing the sensor electronics  50 . The sensor electronics  50  generally comprise components well known to those skilled in the art, such as a data sensor for measuring various formation properties of interest (e.g., pressure, temperature or resistivity); a receiver for receiving remotely transmitted signals; and a transmitter for transmitting a signal representative of the sensor indicated formation property. The plug  52 , however, is preferably connected to the sensor housing  51  in order to prevent accidental impingement on the sensor electronics  50  and antennae  60 .  
         [0054]    Each sensor  65  is designed to pass through the passage or perforation  54  made in the casing  11  and includes a shearable lip  64  circumscribing the opening in the sensor housing  51 . Upon contact with the inside diameter of the casing  11 , the lip  64  is sheared as the sensor  65  passes through the casing  11  into the formation. In another embodiment (not shown) the sensor may be used to seal the perforation in the casing using a different, slightly larger, sensor housing. In this embodiment, the lip is an integral part of the sensor housing and the plug is force fit within the bore so that when the lip meets the inside diameter of the casing, preventing further radial movement of the sensor, the plug proceeds within the bore, thereby causing the end of the sensor housing near the lip to expand within the perforation—reinforcing the seal where the sensor housing contacts the casing. Thus, the sensor can be used to tag the casing, seal the passage and facilitate communication with other sensors deployed in the same passage by conventional means generally known to those skilled in the art. If tagging is unnecessary, however, the sensor electronics  50  can be eliminated and the antennae  60  modified in the manner described in the &#39;662 patent to seal the passage and facilitate communication with other sensors deployed in the same passage.  
         [0055]    Multiple sensors may, therefore, be deployed and used in the same manner thus described for the markers until the tool  12  must be removed from the wellbore to load the cartridge  26  with additional sensors. Additionally, multiple sensors may be deployed into the formation production zone or reservoir to measure other formation properties, such as pressure, temperature and resistivity. Once each sensor is permanently in place, these formation properties may be measured intermittently or constantly in the manner described in the &#39;662 patent or as described in U.S. patent application Ser. Nos. 09/768,655; 09/769,046; and 09/798,192.  
         [0056]    The present invention provides a more efficient and reliable system and method for placing markers and sensors in the formation after the wellbore is lined with casing. Because the markers and sensors are deployed in a non-ballistic manner, they may be manufactured from conventional materials which require less resistance to the ballistic forces typically encountered by conventional deployment means. The use of less resistant materials also facilitates improved communication between the sensor electronics to a position within the wellbore. And, multiple sensors and markers can be loaded in the cartridge  26  of the tool  12  and deployed during a single descent within the wellbore due to their uniform design which enables them to be aligned in any order within the cartridge  26 .  
         [0057]    Further modifications and embodiments of many aspects of this invention will also be obvious to those skilled in the art of oil and gas exploration techniques. The description contained herein is illustrative and should be construed as teaching those skilled in the art the general manner of carrying out the invention. Many elements may be substituted for those elements of the invention described herein. Many changes may be made without departing from the spirit and scope of this invention.