Abstract:
A method of forming a plug in a wellbore includes disposing a work string in a wellbore. The work string includes a first tool comprising a port providing fluid communication between an interior space of the first tool to an exterior space to permit placement of a plug in a wellbore. The method includes introducing a first fluid volume via the work string to form a plug in the wellbore, and includes load testing the plug at least in part by applying an axial force on the plug with the work string to determine that the plug is set.

Description:
BACKGROUND 
     The present disclosure relates generally to wellbore operations and, more particularly, to an apparatus and method of forming a plug in a wellbore. 
     When drilling a wellbore which penetrates one or more subterranean earth formations, it is often advantageous or necessary to form a hardened plug in the wellbore. Such plugs are used for many reasons, including abandonment of the well, wellbore isolation, wellbore stability, or kick-off procedures. Typically, a cement plug may be set in a borehole by pumping a volume of cement slurry into the workstring. The cement slurry travels down the workstring and exits into the wellbore to form the plug. The cement slurry typically exits through one or more openings located at or near the end of the workstring. After placement of the cement slurry, the work string is pulled out of the cement plug. 
     At this point, in case of a plug verification requirement, a conventional operational method requires waiting for the cement to set, and then using the workstring to contact the hard cement plug with enough force to verify the presence of the plug, as well as the location of the top of the plug. The necessary wait time typically is substantial. For example, the operation duration of a typical job may require a cement fluid time in the range of about four (4) to six (6) hours, which may translate to a wait-on-cement (WOC) time of about twelve (12) to twenty-four (24) hours. The total time required, of course, will increase with the number of plugs involved in the job. 
     Therefore, what is needed is an apparatus and method for forming plugs in a wellbore that improves plug formation operations and decreases the amount of time required. 
     SUMMARY 
     The present disclosure relates generally to wellbore operations and, more particularly, to an apparatus and method of forming a plug in a wellbore. 
     In one aspect, a method of forming a plug in a wellbore is disclosed. The method may include disposing a work string in a wellbore. The work string may include a first tool comprising a port providing fluid communication between an interior space of the first tool to an exterior space to permit placement of a plug in a wellbore. The method may further include introducing a first fluid volume via the work string to form a plug in the wellbore, and load testing the plug at least in part by applying an axial force on the plug with the work string to determine that the plug is set. 
     In another aspect, an apparatus to form a plug in a wellbore is disclosed. The apparatus may include a work string that includes a first tubular section. The work string may further include a disconnect tool coupling the first tubular section to a first tool so that the first tubular section and the first tool are in fluid communication via the disconnect tool. The disconnect tool may be configured to allow selective decoupling of the first tubular section and the first tool. The first tool may include a port providing fluid communication between an interior space of the first tool to an exterior space to permit placement of a plug in a wellbore. The work string may further include a rupture element assembly configured to indicate an upper extent of the plug in the wellbore. The work string may be configured to permit load testing the plug at least in part by applying an axial force on the plug with the work string to determine that the plug is set. 
     Accordingly, certain embodiments according to the present disclosure may allow for significant time savings, as compared to conventional operations, by eliminating the need for physically tagging a plug with a work string by applying weight from above. Certain embodiments provide for the use of the string to physically load test the plug in the most appropriate direction, namely upwards, with a pull test. Certain embodiments allow for optimized means of determining a plug TOC (top of cement) after the plug has been set in a wellbore. 
     The features and advantages of the present disclosure will be readily apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the disclosure. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Some specific exemplary embodiments of the disclosure may be understood by referring, in part, to the following description and the accompanying drawings. 
         FIGS. 1A and 1B  are diagrams of work strings in a well bore, in accordance with certain embodiments of the present disclosure. 
         FIG. 2  illustrates one exemplary diverter section, in accordance with certain embodiments of the present disclosure. 
         FIGS. 3A and 3B  illustrate one exemplary disconnect tool, in accordance with certain embodiments of the present disclosure. 
         FIGS. 4A and 4B  depict a flow diagram for an example method, in accordance with certain exemplary embodiments of the present disclosure. 
     
    
    
     While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure. 
     DETAILED DESCRIPTION 
     The present disclosure relates generally to wellbore operations and, more particularly, to an apparatus and method of forming a plug in a wellbore. 
     Illustrative embodiments of the present disclosure are described in detail herein. In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation specific decisions must be made to achieve the specific implementation goals, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure. 
     To facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the disclosure. Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, or otherwise nonlinear wellbores in any type of subterranean formation. Embodiments may be applicable to injection wells as well as production wells, including hydrocarbon wells. 
     Certain embodiments of the present disclose provide for the use of a work string after it is cemented in place to physically load test the plug in the upward direction with a pull test. The upward direction provides an appropriate simulation of the forces that the plug would bear, and knowledge of the pulling force and the travel/stretch of the string may be used to calculate the position of the plug. The pulling force may include an axial force directed up the wellbore. Alternatively or in addition, load testing in the downward direction may be performed, with an axial force directed down the wellbore. Additionally, certain embodiments provide for the use of rupture elements that allows determination of the location of a plug TOC (top of cement) in relation to the rupture elements which have known locations in the wellbore. Certain embodiments may provide for the use of a free pipe locator tool to get an exact free pipe location. 
       FIGS. 1A and 1B  are diagrams of work strings in a well bore, in accordance with certain embodiments of the present disclosure. The work strings may allow use of what is referred to as “hot” cement slurries, because the required thickening times are extremely short relative to those of other cement slurries. Time requirements are short because main requirements are for mixing, pumping and displacement. No time is necessary for pulling out or circulating above a plug. 
     A work string  100  is shown as located in a wellbore  102 , which may be open hole or cased hole. The work string  100  may include a series of coupled tubular members coupled in any conventional manner. By way of example without limitation, adjacent tubular members may be threadedly connected at corresponding end portions. A continuous bore may be defined by the tubular members and may extend for the length of the work string  100 . 
     The lower end of the tool string  100  may include a diverter section  104 . As viewed in the drawing, the diverter section  104  may be positioned near the bottom of the wellbore  102 , but the diverter section  104  may be positioned at any suitable location in the wellbore  102 . The diverter section  104  may be coupled to a dart landing sub  108 . In certain embodiments, the diverter section  104  may be coupled to the dart landing sub  108  via a tubular member  106 . In certain embodiments, such as that depicted in  FIG. 1B , the work string  100  may include a float sub  105  positioned, for example, between the diverter section  104  and the dart landing sub  108 . The float sub  105  may be configured to prevent backflow into the work string  100 . 
     The dart landing sub  108  may be coupled to a rupture disk sub  110 . The rupture disk sub  110  may be coupled to one or more additional rupture disk subs to form a series of rupture disk subs spaced along a portion of the tool string  100 . In the non-limiting example of  FIG. 1 , the rupture disk sub  110  is coupled to a rupture disk sub  114  via tubular member  112 , and the rupture disk sub  114  coupled to a rupture disk sub  118  via tubular member  116 . Each rupture disk sub  110 ,  114 ,  118  may comprise a rupture disk assembly of one or more rupture elements that may be ruptured at a predetermined pressure level. The burst pressure ratings of the rupture disk subs may increase stepwise with a higher position in the work string  100 . By way of example without limitation, the rupture disk sub  110  may have a burst rating of 2000 psi; the rupture disk sub  114  may have a burst rating of 2500 psi; and the rupture disk sub  118  may have a burst rating of 3000 psi. As will be explained in greater detail later, the series of rupture disk subs may indicate the TOC (top of cement) after a cement plug has been set in the annulus between the work string  100  and the wellbore  102 , and also filling parts of the work string. 
     The rupture disk sub  118  may be coupled to a disconnect tool  120 . The disconnect tool  120  may be coupled to a tubular section  122 , which may extend to the ground surface. Although not clear from the diagram of  FIG. 1 , it should be understood that, in most installations, the lengths of the tool string components may be far greater than the lengths depicted; and, when the tool string components are connected as shown and described above, the tool string  100  thus formed is sufficient to span substantially the entire length of the wellbore  102  plus any additional distance to the rig (riser). 
     In certain embodiments, one or more of the work string components may be coupled to or comprise a centralizer to guide the work string component relative to the wellbore  102 . A centralizer, as used herein, may include conventional centralizers and any device extending toward the wellbore  102  that aids in centering the tool string component to which the centralizer is coupled in any suitable manner. Therefore, when lowered into the wellbore  102  as a part of the tool string  100 , the device functions to center the tool string component, and therefore the tool string  100 . The diverter section  104  and the tubular member  106  may have centralizers. In the example depicted, the diverter section  104  include one or more centralizers  107  extending radially away from the diverter section  104 . In certain embodiments, the centralizer  107  may include multiple flat, elastomer gaskets stacked together. 
       FIG. 2  illustrates one exemplary diverter section  104 , in accordance with certain embodiments of the present disclosure. The diverter section  104  may comprise a tubular housing with one or more ports  105  defined therethrough to communicate and redirect fluids received via the work string  100  to the annulus between the diverter section  104  and the wellbore  102 , referring again to  FIG. 1 . The diverter section  104  may be configured to provide jetting action for wellbore cleaning to help ensure successful cement placement. 
     Still referring to  FIG. 1 , the disconnect tool  120  is well disclosed in U.S. Pat. Nos. 6,772,835 and 6,880,636, which are hereby incorporated by reference in its entirety for all purposes. Since the disconnect tool  120  is well disclosed in the above-referenced patent, the tool will only be described generally as follows.  FIGS. 3A and 3B  illustrate one exemplary disconnect tool  120 , in accordance with certain embodiments of the present disclosure.  FIG. 3A  shows the disconnect tool  120  in the connected state; in  FIG. 3B  shows the disconnect tool  120  in the disconnected state. The disconnect tool  120  comprises an upper body member  124  that may be coupled to the tubular section  122  and a lower body member  126  that may be coupled to the rupture disk sub  118 . The two body members are quick-releasably coupled together, and the upper member  124  defines a seat for receiving a flow prevention mechanism. The flow prevention mechanism may be a releasing dart or a phenolic ball. The flow prevention mechanism may be a ball valve as disclosed in U.S. Pat. No. 7,472,752, which is hereby incorporated by reference in its entirety for all purposes. The seat has a greater diameter than the ball valve so as to allow the latter ball valve to pass through the tool  120 . 
     Referring again to  FIG. 1 , the work string  100  is shown assembled and lowered to a predetermined depth in the wellbore  102 , so that the lower end of the diverter section  104  is disposed above the bottom of the wellbore  102 . It should be understood that the diverter section  104  may be disposed at any suitable position above the bottom of the wellbore  102 . If applicable, it may be desirable to tag the total depth of the wellbore  102  with the work string  100  first and then raise the work string  100  off the bottom of the well bore  102  and into position. 
       FIG. 1B  shows the work string  100  with cement plug  128  in place, in the annulus between the tail pipe of the work string  100  and the wellbore  102 , as well as inside the lower portion of the work string. In this context, the end of the work string  100  may be referred to generally as the “tail pipe.” While the plug  128  is depicted as already in place, it should be understood that the diverter section  104  may be used to jet fluids for wellbore cleaning prior to the placement of the plug  128 . 
     With the plug  128  set and cement located inside and outside the tailpipe, the work string  100  may be used to physically load test the plug  128  in the upward direction with a pull test when the cement has cured. As should be understood by one skilled in the art and having the benefit of this disclosure, the pulling force may be applied with any suitable work string lifting equipment. As a non-limiting example, a pull test may include applying a suitable pulling force (of about 30 MT, e.g.) over the dead weight of the work string  100 . In this way, there is no need for physically tagging a plug with a work string by applying weight from above. Alternatively or in addition, load testing in the downward direction may be performed. Additionally, the cement plug may be pressure tested to limitation of the exposed rupture disks, either down the work string or in reverse direction or a combination of the two. 
     The cement plug  128  is depicted with a TOC (top of cement)  130  as a non-limiting example. The TOC  130  is above rupture subs  110  and  114 , but below rupture sub  118 . A lower TOC limit  132  represents what may be one potential lower limit for a TOC. An upper TOC limit  134  represents what may be one potential upper limit for a TOC. The span between the lower TOC  132  limit and the upper TOC limit  134  may be one potential range of the planned extent of the cement plug. It should be understood that many variations may implemented in view of the present disclosure. 
     The series of rupture subs  110 ,  114 ,  118  may allow for determination of the location of TOC  130  in relation to the rupture disks which may have known locations in the wellbore  102 . The pressure at which circulation is established at will indicate which rupture sub has been burst, since the burst pressure rating will increase stepwise going upwards in the string. In the non-limiting example depicted, the lowest rupture sub  110  may be designed with a burst rating of 2000 psi, and fluid in the work string  100  or annulus may be pressurized to burst the rupture sub  110 . However, because the plug  128  extends above the rupture sub  110 , circulation cannot be established. When fluid pressure is increased corresponding to the burst rating of the next rupture sub  114 , which may be rated for 2500 psi, circulation likewise cannot be established due to the extent of the plug  128 . But, when fluid pressure is increased corresponding to the burst rating of the uppermost rupture sub  118 , which may be rated for 3000 psi, the rupture sub  118  may be ruptured and circulation through the work string  100  and up the annulus or in reverse direction may be established. This process would indicate that the TOC  130  is between the uppermost rupture sub  118  and the middle rupture sub  114 , based on the known ratings of the subs and the applied fluid pressures. With the known locations of the work string  100  and the rupture subs  114 ,  118 , the TOC  130  can be determined. In view of this example, it should be appreciated that many variations may be implemented, including implementing any number of rupture subs and/or elements in any desired positions to employ the principles of this disclosure. 
       FIGS. 4A and 4B  depict a flow diagram for an example method  400 , in accordance with certain exemplary embodiments of the present disclosure. Teachings of the present disclosure may be utilized in a variety of implementations. As such, the order, combination, and/or performance of the steps comprising the method  400  may depend on the implementation chosen. 
     According to one example, the method  400  may begin at step  402 . At step  402 , the work string  100  may be assembled and run in hole. At step  404 , if applicable, the total depth (TD) of the wellbore  102  may be tagged with the work string  100 . At step  406 , raise the work string  100  off the bottom of the well bore  102  and into position. 
     At step  408 , a cementing head (not shown) may be installed on a top portion of the tubular section  124 . In certain exemplary embodiments, the cementing head may be a top drive cementing head configured for two darts. A wide variety of cementing heads may be suitable for use according to the present disclosure. Examples of such suitable cementing heads may be found, for example, in U.S. Pat. No. 6,517,125, the disclosure of which is incorporated herein by reference. In certain exemplary embodiments, the cementing head may comprise a plunger assembly having the capability of individually segregating multiple cementing plugs or darts. An example of such cementing head may be found, for example, in U.S. Pat. Nos. 5,236,035, and 5,293,933, the disclosures of which are incorporated herein by reference. 
     At step  410 , circulation may be initiated in the work string  100  and the annulus. The circulation may be two times bottoms up or gas down. The work string  100  also may be rotated and reciprocated. 
     At step  412 , a volume of fluid and a volume of cement slurry may be pumped into the work string  100 . At step  414 , a sample of a predetermined volume of cement, such as from the first cubic meter, may be taken for analysis. The sample may be for analysis with an Ultrasonic Cement Analyzer (UCA) to determine the time required to develop adequate strength, for example. 
     At step  416 , a bottom dart may be dropped down the work string  100 . The bottom dart may be a foam or conventional wiper dart with one or more flexible wipers that sealingly engage the interior wall of the work string  100  to ensure that the work string  100  is adequately clean and in order to reduce contamination of the cement slurry that may follow. Another fluid, such as drilling fluid, may be pumped behind the dart to maintain pressure behind the dart and push it down the work string  100 . The dart may be capable of passing through the disconnect tool  120  and provide a hydraulic seal upon reaching the dart landing sub  108 . 
     At step  418 , as the cement travels down the work string  100 , the cement may be displaced while rotating the work string  100  until the cement is at the tail pipe. At step  420 , the cement and the bottom dart may be displaced while rotating and reciprocating string, and the cement may exit through one or more openings located at the tail pipe. At step  422 , the dart may be landed in the dart landing sub  108 . 
     At step  424 , up/down weights may be taken. At step  426 , surface lines may be flushed and cleaned. At step  428 , the annulus and drill pipe may be observed for backflow and thermal expansion. At step  430 , the cement sample that was taken for analysis with the UCA may be observed for initial set and strength development. After a determination that the cement in the wellbore  102  is set, the work string  100  may be pressurized up to a suitable pressure to blow the rupture disk(s) of the first rupture sub  110  at step  432 . The rupture pressure may be observed, and the fluid densities in annulus and pipe may be considered. As discussed previously, the fluid pressure in the work string  100  may be increased in stepwise fashion until circulation is established at step  434 . With circulation established, it may be performed one or more times bottoms up, and shakers may be observed at step  436 . 
     At step  438 , a pull test of the plug  128  may be performed by, e.g., applying a suitable (e.g., about 30 MT) overpull. At step  440 , a free point locator wireline system may be applied. For example, a commercially available free point locator may be used in conjunction with the present method to obtain an exact free point location and provide further accuracy in locating the TOC. At step  442 , a top dart may be dropped into the work string  100 , and displaced to the disconnect tool  120 . At step  444 , with suitable pressure applied from the behind to displace the dart, the dart may activate the disconnect tool  120  to disconnect the tail pipe from the work string  100 . Complete details of this disconnect tool  120  and disconnect operation are provided in U.S. Pat. No. 6,772,835. 
     At step  446 , the top drive cement head may be detached. At step  448 , pull-out of the work string  100  may be initiated, and the well may be pressure-tested. At step  450 , the work string  100  may be pulled out of the wellbore  102 , leaving the tail pipe in the plug  128 . The tail pipe, which includes sections below the disconnect tool  120 , is therefore considered sacrificial. 
     With a conventional operational method, the rig would have to wait on the cement to set (WOC), and then use the string to tag the hard cement to verify that it is actually present and to verify the TOC. This WOC time can be substantial, as the operation duration during a normal job may require, for example, a cement fluid time in the range of 4-6 hours, which may translate to a WOC time of 12-24 hours. However, with certain embodiments according to the present disclosure, an example of program job time may be less than 1½-2 hours, with corresponding WOC time 4-6 hours. Additional job preparation time may not exceed 1 hour. Therefore, certain embodiments can offer substantial time saving during plug and abandonment operations, which as an example may be in the range 8-18 hours for one plug. If multiple plugs are eliminated, each plug elimination may add another 8-24 hours to the saved rig time potential. Hence, if a 3-plug program is replaced by this process a rig time potential of approximately 16-20 hours may be expected. It should be understood that the above examples are not provided by way of limitation. 
     Accordingly, certain embodiments according to the present disclosure may allow for significant time savings, as compared to conventional operations, by eliminating the need for physically tagging a plug with a work string by applying weight from above. Certain embodiments provide for the use of the string to physically load test the plug in the upward direction with a pull test. Alternatively or in addition, load testing in the downward direction may be performed. Certain embodiments allow for optimized means of determining a plug TOC (top of cement) after the plug has been set in a wellbore. 
     Even though the figures depict embodiments of the present disclosure in a particular orientation, it should be understood by those skilled in the art that embodiments of the present disclosure are well suited for use in a variety of orientations. Accordingly, it should be understood by those skilled in the art that the use of directional terms such as above, below, upper, lower, upward, downward, higher, lower, and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure. 
     Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. The indefinite articles “a” or “an,” as used in the claims, are each defined herein to mean one or more than one of the element that the article introduces.