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BACKGROUND 
   Embodiments described relate to well configurations and diagnostic tools employed therefor. In particular, embodiments of diagnostic tools are described that include the capacity to shift or slide a sleeve within a well over a perforation or aperture in order to close or open the access to the well thereat. 
   BACKGROUND OF THE RELATED ART 
   Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. This may be especially true in the case of certain wells where the configuration and environment of the well presents added challenges, such as in the case of horizontal or subsea wells. 
   In recognition of the potentially enormous expense of well completion added emphasis has been placed on well monitoring and maintenance over the years. That is, placing emphasis on increasing the life and productivity of a given well may help ensure that the well provides a healthy return on the significant investment involved in its completion. Thus, over the years, well diagnostics have become a more sophisticated and critical part of managing well operations. 
   Well diagnostic tools, often referred to as production logging tools, may be employed to analyze the condition of a well and its surroundings. Such logging tools may come in handy for performing diagnostics in the face of an unintended event. For example, in the case of an oil well, unintended sudden or significant water production may occur. In light of such an event, a logging tool may be employed to determine an overall production profile of the well. A logging tool may be used to obtain fluid hydrocarbon, gas hydrocarbons and water saturation values as well as data relative to the geology surrounding the well. As described below, logging data may even be taken from many segments of the well. Thus, a production profile of the entire well may be obtained along with an understanding of the contribution of various well segments to that overall profile and how they inter-act in the dynamic behavior of a well. As also described below, corrective maintenance may be performed on the well based on the results of the described logging application. 
   Unfortunately, running a logging tool through a well as indicated above requires that production from the well be shut off while a logging cable, with logging tool attached thereto, is lowered into the well. This may require well production to be shut off for six hours or more in a vertical well. Furthermore, in the case of horizontal or incline wells, common in the case of subsea wells, slower and more aggressive techniques such as coiled tubing may be necessary in order to advance the logging tool through the well for taking various measurements. Such a well may be shut off for 6-8 hours just to advance the logging tool through the well. Additional production time is then lost in performing analysis with the logging tool and thereafter removing the tool from the well. 
   Every production hour lost to the performance of other operations at the well, such as the described logging may be quite significant. For example, in the case of an offshore subsea well, the cost of any operation may exceed about $10,000 per hour whether productive in obtaining targeted fluids or not. Additionally, production time may be lost in taking corrective action following the logging application. That is, depending on the results of the logging application, certain sections of the well may need to be sealed off, for example to prevent water uptake as in the above noted scenario. Certain well features such as sliding sleeves may be employed to reduce this amount of additional time required to close off a well segment. However, even use of a sliding sleeve requires physical intervention by placement of a tool at the site of a sliding sleeve in order to manipulate its closure. Thus, a significant degree of additional production time and expense may be lost in taking the corrective action. As alluded to above, this expense is exacerbated in the case of horizontal, high angle, subsea or other wells of challenging access configurations. For example, a horizontal offshore well may be shut off for ten or more hours at a cost of several hundred thousand dollars in rig time and expense in order to run a logging application and take even minimal corrective action on the well such as effecting closure of a sliding sleeve. 
   SUMMARY 
   An apparatus is provided that includes a shaft with a diagnostic implement coupled thereto. The diagnostic implement may be used to establish a condition of a well. Additionally, a sleeve shifting device is coupled to the shaft in order to move a sleeve within the well based on the condition. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a side sectional overview of a well having a production assembly and a borehole assembly employing an embodiment of a diagnostic sleeve shifting tool. 
       FIG. 2  is an enlarged view of the diagnostic sleeve shifting tool within the borehole assembly taken from section lines  2 - 2  of  FIG. 1 . 
       FIG. 3A  is a side cross sectional view of the diagnostic sleeve shifting tool of  FIG. 2  positioned with an engagement mechanism thereof relative to a sleeve of the borehole assembly. 
       FIG. 3B  is a side cross sectional view of the diagnostic sleeve shifting tool of  FIG. 3A  with engagement mechanism actuated for engagement of the sleeve. 
       FIG. 3C  is a side cross sectional view of the diagnostic sleeve shifting tool of  FIG. 3B  engaged with and moving the sleeve via the engagement mechanism. 
       FIG. 4  is a flow chart summarizing an embodiment of employing a diagnostic sleeve shifting tool to perform diagnostics on, and move a sleeve of, a well borehole assembly. 
   

   DETAILED DESCRIPTION 
   Embodiments are described with reference to certain hydrocarbon well configurations and diagnostic tools. However, tools employing a variety of diagnostic implements applied to a host of different well configurations may be employed. Regardless, embodiments described herein include a diagnostic tool having the capacity to shift or slide a well sleeve between an open and a closed state over a well perforation or aperture. 
   Referring now to  FIG. 1 , an embodiment of a well  101  is shown. The well  101  includes a production assembly  175  coupled to a borehole assembly  177 . In the embodiment shown, the well  101  is an offshore horizontal oil well as is apparent from the location of the production assembly  175  above the water  150  and the horizontal orientation of the borehole assembly  177  underground  155 . However, embodiments described herein may be applicable to a variety of well types including production and injection wells, wherein production fluids include but are not limited to oil, gas, condensate and water, while injection well include but are not limited to water, gas and carbon dioxide. Nevertheless, use of an embodiment of a diagnostic sleeve shifting tool  100  may be of particular benefit for high angle (e.g. over about 55°), horizontal, offshore, or other wells of comparatively challenging accessibility. 
   In terms of challenging accessibility, the production assembly  175  for the offshore horizontal well  101  of  FIG. 1  includes a production deck  196  to accommodate applications for dealing with the challenges of advancing tools through a tortuous borehole assembly  177 . For example, a coiled tubing application may be employed whereby coiled tubing  180  is drawn from a tubing reel  181  and advanced through a gooseneck guide  190  by an injector head  192 . In certain applications, the coiled tubing  180  may be directed beyond a production tree  198  with enough force to actually drill underground  155 . Thus, in the embodiment shown, the coiled tubing  180  may be directed with enough force to advance a diagnostic sleeve shifting tool (DSST)  100  through the tortuous borehole assembly  177 . In an alternate embodiment, however, a conventional jointed tubing or a wireline with a tractor mechanism may be employed in place of the coiled tubing  180  for moving the DSST  100 . 
   Continuing with reference to  FIG. 1 , the production assembly  175  may also include a control unit  194  with user interface, power unit  191  and other conventional production assembly features and tools. As indicated above, a production tree  198  is located below the production deck  196  where a variety of application hook-ups may be coupled. For purposes here, a single borehole assembly  177  is shown coupled to the production tree  198 . However, in other embodiments a variety of assemblies for any number of particular applications may be coupled to the production tree  198 . 
   The borehole assembly  177  couples to the production tree  198  with a borehole casing  125  extending downward through the water  150  below the offshore well  101  and underground  155 . In the embodiment shown, the borehole casing  125  lines a borehole that extends horizontally as alluded to above. This is not an uncommon occurrence in the case of an offshore well  101 . However, as also alluded to above, the horizontal nature of the borehole assembly  177  presents a tortuous path for advancement of a DSST  100  or other tools. As a result, advancement of such devices may be achieved with an aggressive application such as the described coiled tubing deployment technique. In other embodiments, advancement of such tools may be achieved with jointed tubing or conventional tractor applications, for example, to achieve downward sleeve opening as described further below. 
   Regardless of the particular application employed, advancement and retrieval of a tool through an entire borehole assembly may take between about 6 and about 24 hours depending on factors such as the task to be performed by the tool, the extent and tortuousness of the borehole assembly  177 , and the particular application employed for advancement and retrieval of the tool. Thus, the significance of efficient and proper performance of the tool along with its efficient advancement and retrieval may be seen. This may be especially important in the case of a high angle or horizontal well  101  as shown, where longer advancement and retrieval times may inherently be involved. For example, it may take more than two to four times as long to advance and retrieve a tool through a tortuous well  101  as shown, as compared to a substantially vertical well. 
   The significance of the above described time and expense involved, may be magnified where erroneous performance by an inserted tool results in the need to repeat the procedure, once again shutting off targeted fluid production by the well  101  for an extensive period of time. Thus, as described below, any reduction in the amount of time the well  101  is shut down for such procedures may be of great benefit. Such benefit may be afforded by use of a DSST  100  as described further below. 
   Continuing with reference to  FIG. 1 , the underground  155  portion of the well  101  reveals production regions  157 ,  159  adjacent the horizontal portion of the borehole casing  125 . Perforations or apertures  131 ,  132  in the borehole casing  125  are provided adjacent the production regions  157 ,  159 . In this manner, the well  101  may be provided with access to targeted fluids such as hydrocarbons which may be contained underground  155 . A variety of hydrocarbon and other gas or liquid fluids, may be accessed underground  155  by such a well  101 . Additionally, while only two production regions  157 ,  159  and corresponding apertures  131 ,  132  are shown, the well  101  is likely to extend through numerous additional production regions (not shown) before terminating. In fact, the well  101  may extend for several miles traversing potentially dozens of production regions from which targeted fluids may be drawn. Furthermore, these regions  157 ,  159  appear to be fairly close to one another in  FIG. 1 . However, such production regions  157 ,  159  may be as much as a mile apart or more. 
   The above described production regions  157 ,  159  including those not necessarily shown in  FIG. 1 , each contribute an individual amount to the overall production of the well  101 . For example, a first production region  157  may contribute a first amount of targeted fluid to well operations while a second production region  159  may contribute a second amount. These amounts may vary from one region (i.e.  157 ) to the next (i.e.  159 ). However, added together an overall production profile for operations at the well  101  may be established. 
   As indicated above, potential disparity between the contributions of the above noted production regions (i.e.  157 ,  159 ) may be present. Nevertheless, the overall production profile for operations at the well  101  may be at an optimum, with each production region positively contributing thereto. However, in certain circumstances an event may arise in which production at a given production region (i.e.  157 ,  159 ) is compromised, perhaps even to the point of adversely affecting the overall production profile for the well operations. Note that in some instances the regions  157 ,  159  may not be producing at all or may be taking in fluid. Embodiments of the DSST  100  may also be useful in these areas of the well. For example, upon detection of such an area the DSST  100  may be used to open an adjacent sleeve  135 ,  136  and run a confirmation log to determine the affect of the sleeve closing. 
   By way of example, in an embodiment where the targeted fluid is a hydrocarbon, an adverse event such as water leakage into the first production region  157  may occur. This is a common scenario for nearly all maturing production well(s)  101 . Nevertheless, such water leakage may be to the point that the overall production profile of well operations is adversely affected. In fact, it may take no more than about 10% water production by the well  101  as a whole in order to render production operations at the well fruitless. Thus, as described below, rather than cease operations at the well  101  altogether, it may be advantageous to close off the first production region  157  in order to optimize or restore effective production of the targeted hydrocarbon. In fact, as a preventative and optimizing measure, this may be done when no more than about 5% water production is encountered. Closing off the production region  157  or  159  may be achieved by closure of a corresponding sleeve  135  or  136 , respectively, adjacent thereto, as detailed further below. At a later date in the life cycle of the well  101 , it may be deemed economical and prudent to re-open a sliding sleeve  135 ,  136  producing at high water percentage as higher variations in produced fluids may be tolerable. The DSST  100  would be used at each of the decision points in the life of the well  101 . 
   In the above hypothetical scenario, an example of an event at the first production region  157  is described. In practice, however, it would be likely that the particular region of the event would be unknown, at least initially. For example, from the standpoint of operators at the production assembly  175 , an event may present itself as a fairly sudden change in the production profile of well operations. In the example provided this might be the sudden emergence of water production adversely affecting the production of targeted hydrocarbons. However, the location of such water production may not readily be apparent. Therefore, a logging tool such as the DSST  100  may be employed for surveying the borehole assembly  177  to determine the site of the event as described further below. The DSST  100  may also be used to obtain fluid hydrocarbon and water saturation values as well as data relative to the geology surrounding the well  101 . In one embodiment the DSST  100  is capable of measuring all fluids and gases, and can determine if a given fluid is water, gas or oil and the velocity and/or rate of each phase. The DSST  100  may also be configured to determine the location (segregation) of the fluid (gas) type in the well bore. This can be determined at any location in the well  101 . 
   Continuing with reference to  FIGS. 1 and 2 , the DSST  100  is shown advancing within the borehole casing  125  to the production regions  157 ,  159 . The DSST  100  may include a shaft  250  equipped with a variety of diagnostic implements ( 220 ,  240 ,  260 ,  280 ) to establish conditions of the well  101  within the borehole casing  125 . For example, a saturation implement  220  may be provided to obtain water flow information. An ejector implement  260  may be employed in conjunction with the saturation implement  220 . That is, the ejector implement  260  may eject a non-radioactive marker for detection by the saturation implement  220  in establishing water flow information. Other diagnostic implements may include an imaging implement  240  as well as a fullbore spinner implement  280  to measure fluid velocity. Additionally, a variety of other diagnostic implements may be accommodated by the DSST  100  for establishing pressure, temperature or other well conditions. In one embodiment, the DSST  100  may include any means of obtaining logging information at the production regions of interest. 
   In the case of an event, such as the above noted water production, recovery of targeted fluids by the production assembly  175  may be temporarily terminated. In the embodiment shown, coiled tubing  180  with the DSST  100  assembled thereto may then be advanced through the borehole assembly  177 . Alternatively, a conventional, and potentially more economical, tractor advancing mechanism may be employed. As indicated above, the DSST  100  may be advanced while acquiring data relative to each segment of the borehole assembly  177  including those immediately adjacent regions  157 ,  159  as well as those less directly adjacent such regions  157 ,  159 . A survey of the borehole assembly  177  to acquire data in this manner may be referred to as logging. 
   Typical logging and follow on sleeve shifting procedures as described above may take ten hours or more at considerable expense given the loss of targeted fluid production during this procedure time. Therefore, the benefit of employing a DSST  100  that eliminates the introduction of a separate sleeve shifting tool and procedure may be quite significant as detailed below. That is, embodiments of a DSST  100  may be configured to eliminate the need for running a wholly separate follow on sleeve shifting procedure in order to close a sleeve  135 ,  136  once the site of the water leak is established. As a result, potentially tens, and in some cases hundreds, of thousands of dollars in cost for rig and operation time required by the use of a conventional separate sleeve shifting procedures may be avoided. 
   Continuing with reference to  FIGS. 1 and 2 , logging of the entire borehole assembly  177  with the DSST  100  as indicated above may provide operators with critical information. For example, such a logging procedure may be used to identify the source of an undesirable event such as the above noted water leakage. That is, in the above hypothetical scenario, an example of an event at the first production region  157  is described where water may be leaking through a first aperture  131 . Water leaking into the borehole casing  125  in this manner may significantly impair production of targeted fluids. Therefore, the shaft  250  of the DSST  100  is equipped with a sleeve shifting device  200  in order to effect closure of a first sleeve  135  over the first aperture  131  to stop the indicated water leakage into the borehole casing  125 . As described further herein, it is this sleeve shifting device  200  which provides significant time and cost savings by eliminating the need to advance a separate sleeve shifting tool to the first aperture  131  to achieve closure of the first sleeve  135 . 
   Referring now to  FIGS. 3A-3C , and with added reference to the flow-chart of  FIG. 4 , a method of moving a sleeve with the DSST  100  is shown. That is, with reference to the water leakage scenario noted above, a single DSST  100  may be employed for both running a logging procedure and for closing a first sleeve  135  over a first aperture  131  to prevent water leakage into the borehole casing  125  from the first production region  157 . With reference to  FIG. 3A , the DSST  100  may be advanced throughout the borehole casing  125  of a well in running a logging procedure as described above and indicated at  420 . Once the water leakage information is established by the logging procedure, the DSST  100  may be drawn from the terminal end of the borehole casing  125  and toward the first sleeve  135 . As shown in  FIG. 3A  and indicated at  430 , the sleeve shifting device  200  is positioned adjacent the first sleeve  135 , slightly downhole thereof. In this manner, the sleeve shifting device  200  may be expanded, allowing further movement of the DSST  100  to close the first sleeve  135  as detailed below. In the embodiment of  FIGS. 3A-3C , the positioning and movement of the DSST  100  is achieved via coiled tubing  180  as described further below. However in an alternate embodiment a conventional tractor mechanism, or another appropriate means, may be employed to achieve movement of the DSST  100 . 
   Referring specifically to  FIG. 3B , the sleeve shifting device  200  is shown expanded from the shaft  250  of the DSST  100  adjacently downhole of the first sleeve  135  as indicated above. Precise positioning of the DSST  100  and sleeve shifting device  200  may be confirmed by an implement of the DSST  100  such as the imaging implement  240  or other locating device (see  FIG. 2 ). Once positioned as indicated, an operator may send an electronic signal via wire or fiber optic cable to the DSST  100  for expansion of the sleeve shifting device  200  as shown. Expansion may be achieved physically by conventional means such as hydraulics. In one embodiment, expansion of the sleeve shifting device  200  may occur in an automated fashion via a control unit  194  or other mechanism having the capacity to take advantage of logging information obtained during the logging procedure. 
   Referring now to  FIG. 3C , the DSST  100  with expanded sleeve shifting device  200  is shown being drawn from the borehole casing  125  in an uphole direction (see arrow  300 ). That is, the coiled tubing  180  is being retracted via conventional means at the production assembly  175  of  FIG. 1 . Retraction of the coiled tubing  180  in this manner forces the expanded sleeve shifting device  200  into contact with the first sleeve  135 . Thus, given the sliding or shifting nature of the first sleeve  135 , it is drawn over the first aperture  131  in order to close off the first production region  157  as indicated at  450 . In this manner water leakage into the borehole casing  125  from the first production region  157  may be terminated. In one embodiment, a diagnostic implement of the DSST  100  is employed at this time to confirm the cessation of water leakage. As indicated at  460 , such a confirmation log may help ensure that the intended shifting of the sleeve  135  and closure of the first aperture  131  has occurred. 
   Once closure of the first aperture  131  is achieved, the sleeve shifting device  200  may be retracted back toward the shaft  250  allowing complete removal of the DSST  100  from within the borehole casing  125 . Once again, closure of the first aperture  131  and retraction of the sleeve shifting device  200  may be achieved manually or in an automated fashion which takes advantage of logging information obtained during the initial logging procedure. 
   The above described method of employing the DSST  100  details closure of a sleeve  135  by retraction of coiled tubing  180 . However, in another embodiment a closed sleeve, similar to the first sleeve  135  may be opened by positioning the DSST  100  and sleeve shifting device  200  slightly uphole of the sleeve  135  and advancing the coiled tubing  180  downwardly. Additionally, in an alternative configuration of the borehole assembly  177 , opening and closing of a sleeve may take place in an opposite direction to the embodiments shown herein. For example, in such an alternate configuration, an expanded sleeve shifting device  200  may close a sleeve over a more downhole aperture by positioning the DSST  100  uphole of the sleeve and advancing there-toward. Similarly, opening of such an aperture may be achieved by positioning the DSST  100  slightly downhole of the sleeve and retracting the expanded sleeve shifting device  200  theretoward. The above described techniques of employing the DSST  100  may be employed to close off a water leak at the first production region  157 . As a result, the overall production profile of the well  101  may be optimized and the DSST  100  removed as indicated above. However, in one embodiment, the DSST  100  is employed to perform diagnostics both before and after sleeve shifting procedures as indicated at  470 . That is, diagnostics may point to a particular production region  157  as the source of an event. However, it is possible that in order to achieve an optimum production profile, multiple sleeves may need to be shifted as described. In such circumstances, logging information may require updating after initial sleeve shifting procedures in order to determine subsequent sleeve shifting procedures that may be desired. Furthermore, even where this is not the case, it may be worthwhile to confirm the accuracy of the logging information while the DSST  100  remains within the borehole assembly  177 . That is, this may be preferable to shutting down production to re-run DSST  100  procedures in the unfortunate event that a single application of these procedures failed to optimize the overall production profile of the well  101 . 
   As indicated above, logging information may be used to allow operators to take corrective action in the face of an undesirable event. However, such logging information may also be employed in order to further optimize the overall production profile over the life of the well  101 . For example, a well  101  may be configured with numerous sleeves adjacent numerous production regions as noted above. At the outset of operations at the well  101  many of the sleeves may be open and many others closed, the status of each determined based on the particular conditions present at each production region at the outset of operations. For example, in one scenario the pressure present at several downhole production regions at the outset of operations may be minimal compared to the majority of the remaining production regions. Therefore, rather than allow these downhole production regions to potentially siphon off targeted fluids, they may initially be closed off by adjacent sleeves. However, over the life of the well  101 , pressure at the remaining production regions may naturally decrease to about that of the downhole production regions. Confirmation of this fact and corresponding opening of the downhole production regions may be achieved in a single application of the DSST  100  as described above. Thus, the DSST  100  may be employed as a valuable management tool throughout the life of the well, not limited to use during more sudden undesirable events. 
   The embodiments described herein provide a diagnostic sleeve shifting tool that eliminates the need for running an entirely separate sleeve shifting procedure and tool through a well once determining that a particular sleeve or sleeves of the well need to be shifted. Employment of such a diagnostic sleeve shifting tool may save considerable time and expense, perhaps even in the tens or hundreds of thousands of dollars range. This is due to the significant savings in production and equipment operation time that may be achieved by employing a single tool capable of both performing logging applications and follow-on sleeve shifting. Furthermore, the effectiveness of sleeve shifting may be established in real time by diagnostic implements of the tool while sleeve shifting capability remains in the well (i.e. also with the tool). Thus, additional cost savings may be experienced in the form of improved effectiveness of diagnostic and sleeve shifting operations. Furthermore, while exemplary embodiments described, other embodiments are possible. Additionally, many changes, modifications, and substitutions may be made without departing from the scope of the described embodiments.

Summary:
A diagnostic tool which doubles as a sleeve shifting tool. The tool may include a diagnostic implement for measuring downhole conditions in a well such as flow-rate, pressure and temperature. Where the well includes a slidable or shiftable sleeve, the tool may be employed to slide such a sleeve for controlling communication between the well and an underground production region adjacent the location of the well. In this manner real time diagnostic assessment may occur at the well location in conjunction with means to affect the sleeve position. Thus, the need to run additional subsequent procedures with additional tools for affecting the sleeve position may be eliminated. As a result, substantial time and expense may be saved in conducting such well procedures.