Abstract:
Improved methods and apparatus for isolating and opening a subterranean zone in a multiple zone well. An isolation tool is installed in the well with a tubing string accessing a particular zone. The tool can be remotely opened and closed to provide access to the zone either mechanically or by applying pressure variation sequences to the tool.

Description:
PRIORITY CLAIM 
     This application claims the benefit of U.S. Provisional Application No. 60/2000-1810PCT filed on Aug. 16, 2001, entitled UPPER ZONE ISOLATION TOOL FOR SMAT WELL COMPLETIONS and 60/229,230 filed Aug. 31, 2000, entitled UPPER ZONE ISOLATION TOOL FOR SMART WELL COMPLETIONS. 
    
    
     TECHNICAL FIELD 
     This invention relates to improved methods and apparatus for completing, producing and servicing wells, and in particular to improved methods and apparatus for separately isolating and treating multiple hydrocarbon bearing subterranean zones in a well. The methods and apparatus of the present invention are applicable to isolating well zones for treatment production, testing, completion and the like. 
     BACKGROUND OF THE INVENTION 
     It is common to encounter hydrocarbons wells intersecting more than one separate subterranean hydrocarbons bearing zones. These separate zones can have the same or different characteristics. Production of hydrocarbons from subterranean zones can be enhanced by performing various treatments to the zones. Examples of well treatments include fracturing, perforating, gravel packing, chemical treatment, and the like. The zone&#39;s particular characteristics determine the ideal treatments to be used. In multi zone wells, different well treatments may be required to properly treat the zones. 
     For example, the production of hydrocarbons from unconsolidated or poorly consolidated formation zones may result in the production of sand along with the hydrocarbons. The presence of formation fines and sand is disadvantageous and undesirable in that the particles abrade pumping and other producing equipment and reduce the fluid production capabilities of the producing zones in the wells. Particulate material (e.g., sand) may be present due to the nature of a subterranean formation and/or because of well stimulation treatments wherein proppant is introduced into a subterranean formation. Unconsolidated subterranean zones may be stimulated by creating fractures in the zones and depositing particulate proppant material in the fractures to maintain them in open positions. 
     Gravel pack treatments with and without sand screens and the like have commonly been installed in wellbores penetrating unconsolidated zones to control sand production from a well. The gravel pack treatments serve as filters and help to assure that fines and sand do not migrate with produced fluids into the wellbore. 
     In a typical gravel pack completion, a screen consisting of screen units is placed in the wellbore within the zone to be completed. The screen is typically connected to a tool having a packer and a crossover. The tool is in turn connected to a work or production string. A particulate material, usually graded sand (often referred to in the art as gravel) is pumped in a slurry down the work or production string and through the crossover whereby it flows into the annulus between the screen and the wellbore. The liquid forming the slurry leaks off into the subterranean zone and/or through a screen sized to prevent the sand in the slurry from flowing there through. As a result, the sand is deposited in the annulus around the screen whereby it forms a gravel pack. The size of the sand in the gravel pack is selected such that it prevents formation fines and sand from flowing into the wellbore with produced fluids. 
     Circulation packing (sometimes called “conventional” gravel-packing) begins at the bottom of the screen and packs upward along the length of the screen. Gravel is transported into the annulus between the screen and casing (or the screen and the open hole) where it is packed into position from the bottom of the completion interval upward. The transport fluid then returns to the annulus through the washpipe inside the screen that is connected to the workstring. 
     After gravel packing it is sometimes necessary to perform additional and different treatments on the gravel packed zone after its production performance has been monitored and evaluated. 
     As pointed out above, when a well intersects multiple spaced formation zones, each zone may require separate or even different successive treatments. In these multiple zone wells, a need arises to mechanically isolate the separate zones so that they may be individually treated. In the selected gravel packing treatment example, a multiple zone well may require that each zone be isolated and connected to the surface and treated individually. For example, undesirable fluid losses and control problems could prevent simultaneous gravel packing of multiple zones. In addition, each zone may require unique treatment procedures and subsequent individual zone testing and treatment may be required. 
     Conventional methods of isolating individual zones for treatment, utilize multi-trip processes of setting temporary packers. The packers are first set, the isolated zone treated and the packers removed. To overcome these time consuming and expensive conventional methods one-time hydraulic operated sleeves have been used to provide access to a zone after it has first been treated. When the zone is to be opened the tools&#39; hydraulically operated sleeve valve is opened as the well pressure is raised to a preset level and then bled off. These tools are one-shot in that they are installed in the closed position and once opened cannot be later closed to again isolate that particular zone. These prior systems and methods do not allow the zones to be selectively and repeatedly isolated for subsequent treatment and monitoring. 
     Thus, there are needs for improved methods and apparatus for completing wells, including providing a simple, cost-effective method and apparatus for individually and repeatedly isolating and treating multiple zones in a single well. 
     SUMMARY 
     The present invention provides improved methods and apparatus for isolating multiple hydrocarbon bearing zones in wells, including selectively and repeated isolation of individual zones in a well. More specifically, the present invention provides a zone isolation apparatus, which can be repeatedly opened and closed. This allows well zones to be selectively and individually treated or tested as may be required. This apparatus and method eliminates the costly and time consuming process of setting and removing packers each time the zone must be isolated. 
     The improved methods and apparatus basically comprise the steps of placing upper zone isolation apparatus on one or more of the zones of a well. In gravel packing the isolation apparatus is run in the well with the gravel pack-packer and screens and later opened and closed as required. 
     The improved methods and apparatus of the present invention, in one embodiment, utilizes a valve selectively providing fluid communication with a well zone isolated in an annulus between packers. The valve can be opened and closed by engaging and moving a sleeve accessible from the well surface through the well tubing. The valve is also remotely hydraulically actuateable by manipulating the downhole pressures. 
     Other and further objects, features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of preferred embodiments which follows when taken in conjunction with the accompanying drawings, in which: 
    
    
     DESCRIPTION OF THE DRAWINGS 
     FIG. 1 is a schematic view illustrating a well screen assembly containing the zone isolation apparatus embodying principles of the present invention located in cased well adjacent to vertically separate subterranean zone to be treated; 
     FIG.  2 —is a longitudinal sectional view of one embodiment of the tool of the present invention illustrated in the closed or run position; 
     FIGS. 3-5 are views similar to FIG. 2 illustrating the tool embodiment of FIG. 2 in a sequence of tool positions occurring during opening of the tool; 
     FIG. 6 is an enlarged perspective view of the spacer of the tool embodiment shown in FIGS. 2-5; 
     FIG. 7 is an enlarged perspective view of the valve seat mandrel of the tool embodiment shown in FIGS. 2-5; and 
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The present invention provides improved methods and apparatus for completing, and separately treating separate hydrocarbon zones in a single well. The methods can be performed in either vertical or horizontal wellbores. The term “vertical wellbore” is used herein to mean the portion of a wellbore in a producing zone to be completed which is substantially vertical or deviated from vertical. The term “horizontal wellbore” is used herein to mean the portion of a wellbore in a subterranean producing zone, which is substantially horizontal, or at an angle from vertical. Since the present invention is applicable in vertical, horizontal and inclined wellbores, the terms “upper and lower,” “top and bottom,” as used herein are relative terms and are intended to apply to the respective positions within a particular wellbore while the term “levels” is meant to refer to respective spaced positions along the wellbore. The term “zone” is used herein to refer to separate parts of the well designated for treatment and includes an entire hydrocarbon formation or even separate portions of the same formation and horizontally and vertically spaced portions of the same formation. As used herein, “down”, “downward”, or “downhole” refer to the direction in or along the wellbore from the wellhead toward the producing zone regardless of whether the well bore&#39;s orientation is horizontal, toward the surface or away from the surface. So that the upper zone would be the first zone encountered by the wellbore and the lower zone would be located further along the wellbore. Tubing, tubular, casing, pipe liner and conduit are interchangeable terms used in the well field to refer to walled fluid conductors. 
     Referring more particularly to the drawings wherein an embodiment of the present inventions is illustrated for purposes of example and wherein like reference characters are used throughout the several figures to represent like or corresponding parts, there is shown in FIG. 1 a cased wellbore generally designated by reference numeral  10 . The wellbore  10  is illustrated intersecting two separate hydrocarbon bearing zones, upper zone  12  and lower zone  14 . For purposes of description only two zones are shown, but it is understood that the present invention has application to isolate more than one well zone. As mentioned, while wellbore  10  is illustrated as a vertical cased well with two producing zones, the present invention is applicable to horizontal and inclined wellbores with more than two treatment zones and in uncased wells. In the illustrated embodiments arrow U indicates the uphole direction toward the wellhead. For purposes of explanation of the present invention the formations are to be treated by gravel packing but as previously discussed the present invention has application in other types of well treatments. 
     Upper and lower sand screen assemblies  21  and  31  are located inside the casing  16  of the wellbore  10  in the area of zones  12  and  14 , respectively. Casing  16  is perforated at  18  to provide fluid flow paths between the casing and zones. Production tubing  19  is mounted in the casing  16 . Conventional packers  24  and  26  and conventional crossover sub  30  seal or close the annulus  28  formed between the casing and sand screen assembly  21 . The crossover  30  and packers  24  and  26  are conventional gravel pack forming tools and are well known to those skilled in the art. 
     According to the present invention, the illustrated gravel pack assembly includes the isolation tool  40  of the present invention. Tool  40  is illustrated in an exemplary down hole tool assembly for descriptive purposes but it is to be understood that the tool of the present invention has application in a variety of tool configurations. Expansion joint and the like although not illustrated could be included in the tool assembly as needed. 
     Tool  40  contains a first flow passageway connected to communicate with the lower screen assembly  31  and production tubing  19 . A second flow passage in tool  40  communicates with the screen  21  and the annulus  25  above packer  24 . Packers  24  and  26  and crossover  30  isolate the annulus  28  from the first flow passageway and the remainder of the well. Tool  40  functions to selectively isolate and connect sand screen  21  to annulus  25 . Thus tool  40  selectively isolates the zone  12  from the remainder of the well and allows the zones  12  and  14  to be independently produced. According to the present invention, the tool  40  can be opened and closed by engaging a sleeve (not shown in FIG. 1) exposed in the first flow passageway of tool  40  or opened by raising and then lowering the pressure supplied to tool  40  from annulus  25 . The tool  40  can be opened production tubing has been run into place. 
     FIG. 2 illustrates in detail an embodiment of the tool  40 . The previously referenced first flow passageway through tool  40  is a central passageway designated by elongated arrow  42 . Arrow  42  points up hole or toward the wellhead. As previously described passageway  42  connects to tubing passing through lower packer  26  and connected to screen  31 . Tubing  44  is threaded into threads  52  in the downhole end of the passageway  42  and communicates with the lower screen  31 . Production tubing  19  is connected by threads  92  at the uphole end of passageway  42  and tubing  19  extends to the wellhead or an upper production packer (not shown). Passageway  42  extends completely through the housing  46  of tool  40  and is formed in part by internal passageways  50   a  and  50   b  in lower spacer  50 , internal passageway  60   a  in movable sleeve  60 , internal passageways  70   a  and  70   b  in valve seat mandrel  70  and internal passageway  90   a  in upper spacer  90 . Spacer  50 , mandrel  70  and sleeve  60  are shown in detail in FIGS.  5 , 6 , and  7 , respectively. 
     The previously referred to second fluid passageway is an annular passageway designated by elongated arrows  48   a  and  b  formed inside of housing  46 . The upper end of housing  46  is connected by threads to tubing  46   a . Tubing  46   a  is connected to annulus  25 . The downhole end of housing  46  is connected by threads to adapter  46   b . Adapter  46   b  retains the radially extending legs  54  on spacer  50  against shoulder  49  inside housing  46 . The reduced diameter portions  54   a  of these legs fit inside adapter  46   b . The axially extending spaces  56  between legs  54  form a portion of passageway  48   a . Adapter  46   b  is coupled by threads to tubing  46   c . Tubing  46   c  connects passageway  48   a  to the interior of screen  21 . In FIG. 2, the tool  40  is in the run or closed position with the passageway  48   a  closed from  48   b  by the engagement between the annular valve  82  (on sleeve valve  80 ) and the seat  72  (on valve seat mandrel  70 ). As will be described the valve  82  can be moved away from the seat  72  to open passageway  48  through the tool  40 . When the tool  40  is in the closed position (FIG.  2 ), the interior of screen  21  is closed from annulus  25  by valve  82  and seat  72 . As will be described with reference to FIG. 4, when open (valve  82  separated axially from seat  72 ) fluid from inside screen flows into annulus  25  and to the wellhead (not shown). 
     The assembly of sleeve  60  and sleeve valve  80  is illustrated in FIG.  7 . Sleeve  60  is connected by a spider ring  62  to the downhole end of sleeve valve  80 . As illustrated in FIG. 2, the downhole end of sleeve  60  telescopes in passageway  50   b  of spacer  50 . Suitable seals or packing  58  provide a sliding seal between the sleeve  60  and passageway  50   b  in spacer  50 . The uphole end of sleeve  60  telescopes into the passageway  70   a  of valve seat mandrel  70 . Suitable seals or packing  74  form a sliding seal between the sleeve  60  and passageway  70   a  of valve seat mandrel  70 . Annular shoulders  64  and  66  are formed adjacent the ends of passageway  60   a . These shoulders are exposed to the interior of the first flow passageway  42  and can be accessed through production tubing  19 . Since the sleeve  60  is mechanically connected to the axially movable sleeve valve  80 , the valve element  82  can be axially moved into and out of contact with the valve seat  72  buy engaging and axially moving one of the shoulders  64  or  66  on the sleeve  60 . In this manner, a tool can be run through the tubing  19  to engage the shoulders to axially move the sleeve  60  and sleeve valve  80  to manually open or close the second passageway  48   a  and  b.    
     As illustrated in FIG. 7, two sets of axially spaced lugs  84  and  86  are formed on the exterior of sleeve valve  80 . Lug sets  84  and  86  are each positioned on radially compressible longitudinally extending springs  84   a  and  86   a . These springs allow the lugs when forced radially inward to deflect the springs into the internal bore  45  of housing  46 . Valve sleeve  80  is mounted to slide in the interior bore  45  of housing  46 . According to a particular feature of the present invention, axially spaced annular grooves  46   d ,  46   e ,  46   f  and  46   g  are formed in the wall of bore  45 . Lugs  84  and  86  are of a size and shape to engage or extend into these grooves. The springs  84   a  and  86   a  resiliently urge the lugs radially outward to latch in the grooves to temporarily locate the sleeve valve  80  in discrete axial positions. Moving the sleeve between the open and closed positions requires locking and unlocking the lug sets into and out of the grooves. Note that the axial force needed to latch and unlatch lugs  84  from the grooves is designed to be less than the force needed to unlatch lugs  86 . This is accomplished by providing a larger number of lugs  86  on springs  86   a  that are stiffer. In the run position illustrated in FIG. 2, lugs  84  are located in slot  46   d  and lugs  86  are located in slot  46   f.    
     According to the present invention, a hydraulically operated actuator assembly  100  is located in the tool to open the passageway  48  in response to a series of pressure variations applied to annulus  25 . The hydraulic actuator assembly comprises cylinder-housing  110 , actuator sleeve  130  and coil spring  140  all concentrically mounted around valve seat mandrel  70 . Spring  140  is compressed between annular shoulder  89  and the downhole  132  end of sleeve  130 . The force of spring  140  urges the valve seat mandrel  70  in a downhole direction to separate the valve element  82  from the seat  72 . Spring  140  is designed to apply sufficient force to unlock or dislodge lugs  84  from slot  46   d  but insufficient force to unlock lugs  86  from slot  46   f . In the run position the locking force of lugs  86  in slots  46   f  hold the valve in the closed position. 
     Actuator sleeve  130  is initially held in place by shear screws  131 . In the illustrated embodiment a plurality of radially extending circumferentially spaced screws  131  are used. The screws are threaded into the housing  46  and extend into radially extending bores  133  in sleeve  130 . When sufficient axial force is applied to sleeve  130 , by pistons  118 , pins  131  will shear allowing the sleeve to move axially from the position shown in FIG. 2 to the position shown in FIG.  3 . 
     The hydraulic actuator cylinder-housing  110  comprises a cylindrical portion  112  of a size to extend through the spring  140  and is centered and supported from radially extending legs  76  and  78  on valve seat mandrel  70 . The uphole end  114  of portion  112  has a plurality of circumferentially spaced axially extending bores  116  formed therein. Actuator pistons  118  are mounted to reciprocate in bores  116 . Fluid input ports  120  communicate with the bores  116  and annulus  48   b . Actuator pistons  118  extend through the ends of bores  116  to engage the uphole end of sleeve  130 . When the pressure is raised in annulus  48   b  the pressure in bores  116  is in turn raised forcing pistons  118  against sleeve  130 . When the force exerted by pistons  118  overcomes and shears screws  131 , sleeve  130  moved axially in a downhole direction to the position shown in FIG.  3 . As sleeve  130  is forced to move downhole an annular shoulder  134  on sleeve  130  engages the uphole facing end of end of sleeve valve  80  forcing the sleeve valve  80  to move to the position shown in FIG. 3 with lug  86  displaced from slot  46   f . It is to be noted that the lug  84  is temporarily held in slot  46   e  by nose portion  138  of sleeve  130 . 
     When the pressure in annulus  48   b  is lowered, spring  140  will cause sleeve  130  to move from the position shown in FIG. 3 to the position shown in FIG.  4 . When the nose portion  138  has moved away from slot  46   d  and as previously pointed out spring  140  will cause lug  84  to be forced out of slot  46   d  allowing the sleeve valve to open by moving to the position shown in FIG.  4 . 
     In operation during production, the isolation tool  40  is assembled in the closed position and is lowered into wellbore  10  on a completion assembly to a position adjacent formation  12 . Packers  24  and  26  are set isolating the upper zone  12 . The lower zone  14  is serviced as required while the upper zone is isolated. Access to the upper zone can be accomplished by raising and then lowering the pressure in the annulus  25 , which causes the valve in tool  40  to open. The upper zone  12  can be opened or isolated as desired by lowering a tool through the production sting and engaging the internal shoulders  64  and  66  in tool  40  to mechanically open or close the valve as required. 
     Thus, the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned as well as those, which are inherent therein. Of course, the invention does not require that all the advantageous features and all the advantages need to be incorporated into every embodiment of the invention. While numerous changes may be made by those skilled in the art, such changes are included in the spirit of this invention as defined by the appended claims. The invention is not limited to the specific structures and variations disclosed but will permit obvious variations within the scope of the invention as defined by the claims herein.