Patent Publication Number: US-9404348-B2

Title: Packer for alternate flow channel gravel packing and method for completing a wellbore

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is the National Stage of International Application No. PCT/US2011/061223, filed Nov. 17, 2011, which claims the benefit of U.S. Provisional Application No. 61/424,427, filed Dec. 17 2010, the entirety of which is incorporated herein by reference for all purposes. 
    
    
     BACKGROUND OF THE INVENTION 
     This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art. 
     FIELD OF THE INVENTION 
     The present disclosure relates to the field of well completions. More specifically, the present invention relates to the isolation of formations in connection with wellbores that have been completed using gravel-packing. The application also relates to a downhole packer that may be set within either a cased hole or an open-hole wellbore and which incorporates Alternate Path® technology. 
     DISCUSSION OF TECHNOLOGY 
     In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation. A cementing operation is typically conducted in order to fill or “squeeze” the annular area with cement. The combination of cement and casing strengthens the wellbore and facilitates the isolation of the formation behind the casing. 
     It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. The process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth. The final string of casing, referred to as a production casing, is cemented in place and perforated. In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface. 
     As part of the completion process, a wellhead is installed at the surface. The wellhead controls the flow of production fluids to the surface, or the injection of fluids into the wellbore. Fluid gathering and processing equipment such as pipes, valves and separators are also provided. Production operations may then commence. 
     It is sometimes desirable to leave the bottom portion of a wellbore open. In open-hole completions, a production casing is not extended through the producing zones and perforated; rather, the producing zones are left uncased, or “open.” A production string or “tubing” is then positioned inside the wellbore extending down below the last string of casing and across a subsurface formation. 
     There are certain advantages to open-hole completions versus cased-hole completions. First, because open-hole completions have no perforation tunnels, formation fluids can converge on the wellbore radially 360 degrees. This has the benefit of eliminating the additional pressure drop associated with converging radial flow and then linear flow through particle-filled perforation tunnels. The reduced pressure drop associated with an open-hole completion virtually guarantees that it will be more productive than an unstimulated, cased hole in the same formation. 
     Second, open-hole techniques are oftentimes less expensive than cased hole completions. For example, the use of gravel packs eliminates the need for cementing, perforating, and post-perforation clean-up operations. 
     A common problem in open-hole completions is the immediate exposure of the wellbore to the surrounding formation. If the formation is unconsolidated or heavily sandy, the flow of production fluids into the wellbore may carry with it formation particles, e.g., sand and fines. Such particles can be erosive to production equipment downhole and to pipes, valves and separation equipment at the surface. 
     To control the invasion of sand and other particles, sand control devices may be employed. Sand control devices are usually installed downhole across formations to retain solid materials larger than a certain diameter while allowing fluids to be produced. A sand control device typically includes an elongated tubular body, known as a base pipe, having numerous slotted openings. The base pipe is then typically wrapped with a filtration medium such as a screen or wire mesh. 
     To augment sand control devices, particularly in open-hole completions, it is common to install a gravel pack. Gravel packing a well involves placing gravel or other particulate matter around the sand control device after the sand control device is hung or otherwise placed in the wellbore. To install a gravel pack, a particulate material is delivered downhole by means of a carrier fluid. The carrier fluid with the gravel together forms a gravel slurry. The slurry dries in place, leaving a circumferential packing of gravel. The gravel not only aids in particle filtration but also helps maintain formation integrity. 
     In an open-hole gravel pack completion, the gravel is positioned between a sand screen that surrounds a perforated base pipe and a surrounding wall of the wellbore. During production, formation fluids flow from the subterranean formation, through the gravel, through the screen, and into the inner base pipe. The base pipe thus serves as a part of the production string. 
     A problem historically encountered with gravel-packing is that an inadvertent loss of carrier fluid from the slurry during the delivery process can result in premature sand or gravel bridges being formed at various locations along open-hole intervals. For example, in an inclined production interval or an interval having an enlarged or irregular borehole, a poor distribution of gravel may occur due to a premature loss of carrier fluid from the gravel slurry into the formation. Premature sand bridging can block the flow of gravel slurry, causing voids to form along the completion interval. Thus, a complete gravel-pack from bottom to top is not achieved, leaving the wellbore exposed to sand and fines infiltration. 
     The problems of sand bridging has been addressed through the use of Alternate Path® Technology, or “APT.” Alternate Path® Technology employs shunt tubes (or shunts) that allow the gravel slurry to bypass selected areas along a wellbore. Such alternate path technology is described, for example, in U.S. Pat. No. 5,588,487 entitled “Tool for Blocking Axial Flow in Gravel-Packed Well Annulus,” and U.S. Pat. No. 7,938,184 entitled “Wellbore Method and Apparatus for Completion, Production, and Injection”. Additional references which discuss bypass technology include U.S. Pat. Nos. 4,945,991; 5,113,935; 7,661,476; and M.D. Barry, et al., “Open-hole Gravel Packing with Zonal Isolation,” SPE Paper No. 110,460 (November 2007). 
     The efficacy of a gravel pack in controlling the influx of sand and fines into a wellbore is well-known. However, it is also sometimes desirable with open-hole completions to isolate selected intervals along the open-hole portion of a wellbore in order to control the inflow of fluids. For example, in connection with the production of condensable hydrocarbons, water may sometimes invade an interval. This may be due to the presence of native water zones, coning (rise of near-well hydrocarbon-water contact), high permeability streaks, natural fractures, or fingering from injection wells. Depending on the mechanism or cause of the water production, the water may be produced at different locations and times during a well&#39;s lifetime. Similarly, a gas cap above an oil reservoir may expand and break through, causing gas production with oil. The gas breakthrough reduces gas cap drive and suppresses oil production. 
     In these and other instances, it is desirable to isolate an interval from the production of formation fluids into the wellbore. Annular zonal isolation may also be desired for production allocation, production/injection fluid profile control, selective stimulation, or water or gas control. However, the design and installation of open-hole packers is highly problematic due to under-reamed areas, areas of washout, higher pressure differentials, frequent pressure cycling, and irregular borehole sizes. In addition, the longevity of zonal isolation is a consideration as the water/gas coning potential often increases later in the life of a field due to pressure drawdown and depletion. 
     Therefore, a need exists for an improved sand control system that provides bypass technology for the placement of gravel that bypasses a packer. A need further exists for a packer assembly that provides isolation of selected subsurface intervals along an open-hole wellbore. Further, a need exists for a packer that utilizes alternate path channels, and that provides a hydraulic seal to an open-hole wellbore before any gravel is placed around the sealing element. 
     SUMMARY OF THE INVENTION 
     A specially-designed downhole packer is first offered herein. The downhole packer may be used to seal an annular region between a tubular body and a surrounding open-hole wellbore. The downhole packer may be placed along a string of sand control devices, and set before a gravel packing operation begins. 
     In one embodiment, the downhole packer comprises an inner mandrel. The inner mandrel defines an elongated tubular body. In addition, the downhole packer has at least one alternate flow channel along the inner mandrel. Further, the downhole packer has a sealing element external to the inner mandrel. The sealing element resides circumferentially around the inner mandrel. 
     The downhole packer further includes a movable piston housing. The piston housing is initially retained around the inner mandrel. The piston housing has a pressure-bearing surface at a first end, and is operatively connected to the sealing element. The piston housing may be released and caused to move along the inner mandrel. Movement of the piston housing actuates the sealing element into engagement with the surrounding open-hole wellbore. 
     Preferably, the downhole packer further includes a piston mandrel. The piston mandrel is disposed between the inner mandrel and the surrounding piston housing. An annulus is preserved between the inner mandrel and the piston mandrel. The annulus beneficially serves as the at least one alternate flow channel through the packer. 
     The downhole packer may also include one or more flow ports. The flow ports provide fluid communication between the alternate flow channel and the pressure-bearing surface of the piston housing. The flow ports are sensitive to hydrostatic pressure within the wellbore. 
     In one embodiment, the downhole packer also includes a release sleeve. The release sleeve resides along an inner surface of the inner mandrel. Further, the downhole packer includes a release key. The release key is connected to the release sleeve. The release key is movable between a retaining position wherein the release key engages and retains the moveable piston housing in place, to a releasing position wherein the release key disengages the piston housing. When disengaged, absolute pressure acts against the pressure-bearing surface of the piston housing and moves the piston housing to actuate the sealing element. 
     In one aspect, the downhole packer also has at least one shear pin. The at least one shear pin may be one or more set screws. The shear pin or pins releasably connects the release sleeve to the release key. The shear pin or pins is sheared when a setting tool is pulled up the inner mandrel and slides the release sleeve. 
     In one embodiment, the downhole packer also has a centralizer. The centralizer may be operable in response to manipulation of the packer or sealing mechanism, or in other embodiments be operable separately from manipulating the packer or sealing mechanism. 
     A method for completing a wellbore is also provided herein. The wellbore may include a lower portion completed as an open-hole. In one aspect, the method includes providing a packer. The packer may be in accordance with the packer described above. For example, the packer will have an inner mandrel, alternate flow channels around the inner mandrel, and a sealing element external to the inner mandrel. The sealing element is preferably an elastomeric cup-type element 
     The method also includes connecting the packer to a tubular body, and then running the packer and connected tubular body into the wellbore. The packer and connected tubular body are placed along the open-hole portion of the wellbore. Preferably, the tubular body is a sand screen, with the sand screen comprising a base pipe, a surrounding filter medium, and alternate flow channels. Alternatively, the tubular body may be a blank pipe comprising alternate flow channels. The alternate flow channels may be either internal or external to the filter medium or the blank pipe, as the case may be. 
     The base pipe of the sand screen may be made up of a plurality of joints. For example, the packer may be connected between two of the plurality of joints of the base pipe. 
     The method also includes setting the packer. This is done by actuating the sealing element of the packer into engagement with the surrounding open-hole portion of the wellbore. As an alternative, the packer may be set along a non-perforated joint of casing. Thereafter, the method includes injecting a gravel slurry into an annular region formed between the tubular body and the surrounding wellbore, and then further injecting the gravel slurry through the alternate flow channels to allow the gravel slurry to bypass the sealing element. In this way, the open-hole portion of the wellbore is gravel-packed below the packer. In one aspect, the wellbore is gravel packed above and below the packer after the packer has been completely set in the open-hole wellbore. 
     In one embodiment herein, the packer is a first mechanically-set packer that is part of a packer assembly. In this instance, the packer assembly may comprise a second mechanically-set packer constructed in accordance with the first packer. The step of further injecting the gravel slurry through the alternate flow channels allows the gravel slurry to bypass the sealing element of the packer assembly so that the open-hole portion of the wellbore is gravel-packed above and below the packer assembly after the first and second mechanically-set packers have been set in the wellbore. 
     The method may further include running a setting tool into the inner mandrel of the packer, and releasing the movable piston housing from its retained position. The method then includes communicating hydrostatic pressure to the piston housing through the one or more flow ports. Communicating hydrostatic pressure moves the released piston housing and actuates the sealing element against the surrounding wellbore. 
     It is preferred that the setting tool is part of a washpipe used for gravel packing. In this instance, running the setting tool comprises running a washpipe into a bore within the inner mandrel of the packer, with the washpipe having a setting tool thereon. The step of releasing the movable piston housing from its retained position then comprises pulling the washpipe with the setting tool along the inner mandrel. The release sleeve moves to shear the at least one shear pin and shift the release sleeve. This further serves to free the at least one release key, and release the piston housing. 
     The method may also include producing hydrocarbon fluids from at least one interval along the open-hole portion of the wellbore. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the present inventions can be better understood, certain illustrations, charts and/or flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications. 
         FIG. 1  is a cross-sectional view of an illustrative wellbore. The wellbore has been drilled through three different subsurface intervals, each interval being under formation pressure and containing fluids. 
         FIG. 2  is an enlarged cross-sectional view of an open-hole completion of the wellbore of  FIG. 1 . The open-hole completion at the depth of the three illustrative intervals is more clearly seen. 
         FIG. 3A  is a cross-sectional side view of a packer assembly, in one embodiment. Here, a base pipe is shown, with surrounding packer elements. Two mechanically set packers are shown in spaced-apart relation. 
         FIG. 3B  is a cross-sectional view of the packer assembly of  FIG. 3A , taken across lines  3 B- 3 B of  FIG. 3A . Shunt tubes are seen within the packer assembly. 
         FIG. 3C  is a cross-sectional view of the packer assembly of  FIG. 3A , in an alternate embodiment. In lieu of shunt tubes, transport tubes are seen manifolded around the base pipe. 
         FIG. 4A  is a cross-sectional side view of the packer assembly of  FIG. 3A . Here, sand control devices, or sand screens, have been placed at opposing ends of the packer assembly. The sand control devices utilize external shunt tubes. 
         FIG. 4B  provides a cross-sectional view of the packer assembly of  FIG. 4A , taken across lines  4 B- 4 B of  FIG. 4A . Shunt tubes are seen outside of the sand screen to provide an alternative flowpath for a particulate slurry. 
         FIG. 5A  is another cross-sectional side view of the packer assembly of  FIG. 3A . Here, sand control devices, or sand screens, have again been placed at opposing ends of the packer assembly. However, the sand control devices utilize internal shunt tubes. 
         FIG. 5B  provides a cross-sectional view of the packer assembly of  FIG. 5A , taken across lines  5 B- 5 B of  FIG. 5A . Shunt tubes are seen within the sand screen to provide an alternative flowpath for a particulate slurry. 
         FIG. 6A  is a cross-sectional side view of one of the mechanically-set packers of  FIG. 3A . The mechanically-set packer is in its run-in position. 
         FIG. 6B  is a cross-sectional side view of the mechanically-set packer of  FIG. 3A . Here, the mechanically-set packer element is in its set position. 
         FIG. 6C  is a cross-sectional view of the mechanically-set packer of  FIG. 6A . The view is taken across line  6 C- 6 C of  FIG. 6A . 
         FIG. 6D  is a cross-sectional view of the mechanically-set packer of  FIG. 6A . The view is taken across line  6 D- 6 D of  FIG. 6B . 
         FIG. 6E  is a cross-sectional view of the mechanically-set packer of  FIG. 6A . The view is taken across line  6 E- 6 E of  FIG. 6A . 
         FIG. 6F  is a cross-sectional view of the mechanically-set packer of  FIG. 6A . The view is taken across line  6 F- 6 F of  FIG. 6B . 
         FIG. 7A  is an enlarged view of the release key of  FIG. 6A . The release key is in its run-in position along the inner mandrel. The shear pin has not yet been sheared. 
         FIG. 7B  is an enlarged view of the release key of  FIG. 6B . The shear pin has been sheared, and the release key has dropped away from the inner mandrel. 
         FIG. 7C  is a perspective view of a setting tool as may be used to latch onto a release sleeve, and thereby shear a shear pin within the release key. 
         FIGS. 8A through 8J  present stages of a gravel packing procedure using one of the packer assemblies of the present invention, in one embodiment. Alternate flowpath channels are provided through the packer elements of the packer assembly and through the sand control devices. 
         FIG. 8K  shows the packer assembly and gravel pack having been set in an open-hole wellbore following completion of the gravel packing procedure from  FIGS. 8A through 8K . 
         FIG. 9A  is a cross-sectional view of a middle interval of the open-hole completion of  FIG. 2 . Here, a straddle packer has been placed within a sand control device across the middle interval to prevent the inflow of formation fluids. 
         FIG. 9B  is a cross-sectional view of middle and lower intervals of the open-hole completion of  FIG. 2 . Here, a plug has been placed within a packer assembly between the middle and lower intervals to prevent the flow of formation fluids up the wellbore from the lower interval. 
         FIG. 10  is a flowchart showing steps that may be performed in connection with a method for completing an open-hole wellbore, in one embodiment. 
         FIG. 11  is a flowchart that provides steps for a method of setting a packer, in one embodiment. The packer is set in an open-hole wellbore, and includes alternate flow channels. 
     
    
    
     DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS 
     Definitions 
     As used herein, the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons generally fall into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring hydrocarbons, including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel. 
     As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions or at ambient conditions (15° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, coal bed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state. 
     As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, and combinations of liquids and solids. 
     As used herein, the term “subsurface” refers to geologic strata occurring below the earth&#39;s surface. 
     The term “subsurface interval” refers to a formation or a portion of a formation wherein formation fluids may reside. The fluids may be, for example, hydrocarbon liquids, hydrocarbon gases, aqueous fluids, or combinations thereof. 
     As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shape. As used herein, the term “well”, when referring to an opening in the formation, may be used interchangeably with the term “wellbore.” 
     The term “tubular member” refers to any pipe, such as a joint of casing, a portion of a liner, or a pup joint. 
     The term “sand control device” means any elongated tubular body that permits an inflow of fluid into an inner bore or a base pipe while filtering out predetermined sizes of sand, fines and granular debris from a surrounding formation. 
     The term “alternate flow channels” means any collection of manifolds and/or shunt tubes that provide fluid communication through or around a downhole tool such as a packer to allow a slurry to by-pass the packer or any premature sand bridge in an annular region and continue gravel packing below, or above and below, the tool. 
     Description of Specific Embodiments 
     The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the inventions. 
     Certain aspects of the inventions are also described in connection with various figures. In certain of the figures, the top of the drawing page is intended to be toward the surface, and the bottom of the drawing page toward the well bottom. While wells commonly are completed in substantially vertical orientation, it is understood that wells may also be inclined and or even horizontally completed. When the descriptive terms “up and down” or “upper” and “lower” or similar terms are used in reference to a drawing or in the claims, they are intended to indicate relative location on the drawing page or with respect to claim terms, and not necessarily orientation in the ground, as the present inventions have utility no matter how the wellbore is orientated. 
       FIG. 1  is a cross-sectional view of an illustrative wellbore  100 . The wellbore  100  defines a bore  105  that extends from a surface  101 , and into the earth&#39;s subsurface  110 . The wellbore  100  is completed to have an open-hole portion  120  at a lower end of the wellbore  100 . The wellbore  100  has been formed for the purpose of producing hydrocarbons for commercial sale. A string of production tubing  130  is provided in the bore  105  to transport production fluids from the open-hole portion  120  up to the surface  101 . 
     The wellbore  100  includes a well tree, shown schematically at  124 . The well tree  124  includes a shut-in valve  126 . The shut-in valve  126  controls the flow of production fluids from the wellbore  100 . In addition, a subsurface safety valve  132  is provided to block the flow of fluids from the production tubing  130  in the event of a rupture or catastrophic event above the subsurface safety valve  132 . The wellbore  100  may optionally have a pump (not shown) within or just above the open-hole portion  120  to artificially lift production fluids from the open-hole portion  120  up to the well tree  124 . 
     The wellbore  100  has been completed by setting a series of pipes into the subsurface  110 . These pipes include a first string of casing  102 , sometimes known as surface casing or a conductor. These pipes also include at least a second  104  and a third  106  string of casing. These casing strings  104 ,  106  are intermediate casing strings that provide support for walls of the wellbore  100 . Intermediate casing strings  104 ,  106  may be hung from the surface, or they may be hung from a next higher casing string using an expandable liner or liner hanger. It is understood that a pipe string that does not extend back to the surface (such as casing string  106 ) is normally referred to as a “liner.” 
     In the illustrative wellbore arrangement of  FIG. 1 , intermediate casing string  104  is hung from the surface  101 , while casing string  106  is hung from a lower end of casing string  104 . Additional intermediate casing strings (not shown) may be employed. The present inventions are not limited to the type of casing arrangement used. 
     Each string of casing  102 ,  104 ,  106  is set in place through cement  108 . The cement  108  isolates the various formations of the subsurface  110  from the wellbore  100  and each other. The cement  108  extends from the surface  101  to a depth “L” at a lower end of the casing string  106 . It is understood that some intermediate casing strings may not be fully cemented. 
     An annular region  204  is formed between the production tubing  130  and the casing string  106 . A production packer  206  seals the annular region  204  near the lower end “L” of the casing string  106 . 
     In many wellbores, a final casing string known as production casing is cemented into place at a depth where subsurface production intervals reside. However, the illustrative wellbore  100  is completed as an open-hole wellbore. Accordingly, the wellbore  100  does not include a final casing string along the open-hole portion  120 . 
     In the illustrative wellbore  100 , the open-hole portion  120  traverses three different subsurface intervals. These are indicated as upper interval  112 , intermediate interval  114 , and lower interval  116 . Upper interval  112  and lower interval  116  may, for example, contain valuable oil deposits sought to be produced, while intermediate interval  114  may contain primarily water or other aqueous fluid within its pore volume. This may be due to the presence of native water zones, high permeability streaks or natural fractures in the aquifer, or fingering from injection wells. In this instance, there is a probability that water will invade the wellbore  100 . 
     Alternatively, upper  112  and intermediate  114  intervals may contain hydrocarbon fluids sought to be produced, processed and sold, while lower interval  116  may contain some oil along with ever-increasing amounts of water. This may be due to coning, which is a rise of near-well hydrocarbon-water contact. In this instance, there is again the possibility that water will invade the wellbore  100 . 
     Alternatively still, upper  112  and lower  116  intervals may be producing hydrocarbon fluids from a sand or other permeable rock matrix, while intermediate interval  114  may represent a non-permeable shale or otherwise be substantially impermeable to fluids. 
     In any of these events, it is desirable for the operator to isolate selected intervals. In the first instance, the operator will want to isolate the intermediate interval  114  from the production string  130  and from the upper  112  and lower  116  intervals so that primarily hydrocarbon fluids may be produced through the wellbore  100  and to the surface  101 . In the second instance, the operator will eventually want to isolate the lower interval  116  from the production string  130  and the upper  112  and intermediate  114  intervals so that primarily hydrocarbon fluids may be produced through the wellbore  100  and to the surface  101 . In the third instance, the operator will want to isolate the upper interval  112  from the lower interval  116 , but need not isolate the intermediate interval  114 . Solutions to these needs in the context of an open-hole completion are provided herein, and are demonstrated more fully in connection with the proceeding drawings. 
     In connection with the production of hydrocarbon fluids from a wellbore having an open-hole completion, it is not only desirable to isolate selected intervals, but also to limit the influx of sand particles and other fines. In order to prevent the migration of formation particles into the production string  130  during operation, sand control devices  200  have been run into the wellbore  100 . These are described more fully below in connection with  FIG. 2  and with  FIGS. 8A through 8J . 
     Referring now to  FIG. 2 , the sand control devices  200  contain an elongated tubular body referred to as a base pipe  205 . The base pipe  205  typically is made up of a plurality of pipe joints. The base pipe  205  (or each pipe joint making up the base pipe  205 ) typically has small perforations or slots to permit the inflow of production fluids. 
     The sand control devices  200  also contain a filter medium  207  wound or otherwise placed radially around the base pipes  205 . The filter medium  207  may be a wire mesh screen or wire wrap fitted around the base pipe  205 . The filter medium  207  prevents the inflow of sand or other particles above a pre-determined size into the base pipe  205  and the production tubing  130 . 
     In addition to the sand control devices  200 , the wellbore  100  includes one or more packer assemblies  210 . In the illustrative arrangement of  FIGS. 1 and 2 , the wellbore  100  has an upper packer assembly  210 ′ and a lower packer assembly  210 ″. However, additional packer assemblies  210  or just one packer assembly  210  may be used. The packer assemblies  210 ′,  210 ″ are uniquely configured to seal an annular region (seen at  202  of  FIG. 2 ) between the various sand control devices  200  and a surrounding wall  201  of the open-hole portion  120  of the wellbore  100 . 
       FIG. 2  is an enlarged cross-sectional view of the open-hole portion  120  of the wellbore  100  of  FIG. 1 . The open-hole portion  120  and the three intervals  112 ,  114 ,  116  are more clearly seen. The upper  210 ′ and lower  210 ″ packer assemblies are also more clearly visible proximate upper and lower boundaries of the intermediate interval  114 , respectively. Finally, the sand control devices  200  along each of the intervals  112 ,  114 ,  116  are shown. 
     Concerning the packer assemblies themselves, each packer assembly  210 ′,  210 ″ may have at least two packers. The packers are preferably set through a combination of mechanical manipulation and hydraulic forces. The packer assemblies  210  represent an upper packer  212  and a lower packer  214 . Each packer  212 ,  214  has an expandable portion or element fabricated from an elastomeric or a thermoplastic material capable of providing at least a temporary fluid seal against the surrounding wellbore wall  201 . 
     The elements for the upper  212  and lower  214  packers should be able to withstand the pressures and loads associated with a gravel packing process. Typically, such pressures are from about 2,000 psi to 3,000 psi. The elements of the packers  212 ,  214  should also withstand pressure load due to differential wellbore and/or reservoir pressures caused by natural faults, depletion, production, or injection. Production operations may involve selective production or production allocation to meet regulatory requirements. Injection operations may involve selective fluid injection for strategic reservoir pressure maintenance. Injection operations may also involve selective stimulation in acid fracturing, matrix acidizing, or formation damage removal. 
     The sealing surface or elements for the mechanically set packers  212 ,  214  need only be on the order of inches to affect a suitable hydraulic seal. In one aspect, the elements are each about 6 inches (15.2 cm) to about 24 inches (70.0 cm) in length. 
     The elements for the packers  212 ,  214  are preferably cup-type elements. Cup-type elements are well known for use in cased-hole completions. However, they generally are not known for use in open-hole completions as they are not engineered to expand into engagement with an open-hole diameter. The preferred cup-type nature of the sealing surfaces of the packer elements  212 ,  214  will assist in maintaining at least a temporary seal against the wall  201  of the intermediate interval  114  (or other interval) as pressure increases during the gravel packing operation. 
     The upper  212  and lower  214  packers are set prior to a gravel pack installation process. As described more fully below, the packers  212 ,  214  may be set by sliding a release sleeve. This, in turn, allows hydrostatic pressure to act downwardly against a piston mandrel. The piston mandrel acts down upon a centralizer and/or packer elements, causing the same to expand against the wellbore wall  201 . The expandable portions of the upper  212  and lower  214  packers are expanded into contact with the surrounding wall  201  so as to straddle the annular region  202  at a selected depth along the open-hole completion  120 . 
       FIG. 2  shows a mandrel at  215 . This may be representative of the piston mandrel, and other mandrels used in the packers  212 ,  214  as described more fully below. 
     The upper  212  and lower  214  packers may generally be mirror images of each other, except for the release sleeves or other engagement mechanisms. Unilateral movement of a shifting tool (shown in and discussed in connection with  FIGS. 7A and 7B ) will allow the packers  212 ,  214  to be activated in sequence or simultaneously. The lower packer  214  is activated first, followed by the upper packer  212  as the shifting tool is pulled upward through an inner mandrel (shown in and discussed in connection with  FIGS. 6A and 6B ). A short spacing is preferably provided between the upper  212  and lower  214  packers. 
     The packer assemblies  210 ′,  210 ″ help control and manage fluids produced from different zones. In this respect, the packer assemblies  210 ′,  210 ″ allow the operator to seal off an interval from either production or injection, depending on well function. Installation of the packer assemblies  210 ′,  210 ″ in the initial completion allows an operator to shut-off the production from one or more zones during the well lifetime to limit the production of water or, in some instances, an undesirable non-condensable fluid such as hydrogen sulfide. 
     Packers historically have not been installed when an open-hole gravel pack is utilized because of the difficulty in forming a seal along an open-hole portion, and because of the difficulty in forming a complete gravel pack above and below the packer. Related patent applications, U.S. Publication Nos. 2009/0294128 and 2010/0032158 disclose apparatus&#39; and methods for gravel-packing an open-hole wellbore after a packer has been set at a completion interval. Zonal isolation in open-hole, gravel-packed completions may be provided by using a packer element and secondary (or “alternate”) flow paths to enable both zonal isolation and alternate flow path gravel packing. 
     Certain technical challenges have remained with respect to the methods disclosed in U.S. Pub Nos. 2009/0294128 and 2010/0032158, particularly in connection with the packer. The applications state that the packer may be a hydraulically actuated inflatable element. Such an inflatable element may be fabricated from an elastomeric material or a thermoplastic material. However, designing a packer element from such materials requires the packer element to meet a particularly high performance level. In this respect, the packer element needs to be able to maintain zonal isolation for a period of years in the presence of high pressures and/or high temperatures and/or acidic fluids. As an alternative, the applications state that the packer may be a swelling rubber element that expands in the presence of hydrocarbons, water, or other stimulus. However, known swelling elastomers typically require about 30 days or longer to fully expand into sealed fluid engagement with the surrounding rock formation. Therefore, improved packers and zonal isolation apparatus&#39; are offered herein. 
       FIG. 3A  presents an illustrative packer assembly  300  providing an alternate flowpath for a gravel slurry. The packer assembly  300  is seen in cross-sectional side view. The packer assembly  300  includes various components that may be utilized to seal an annulus along the open-hole portion  120 . 
     The packer assembly  300  first includes a main body section  302 . The main body section  302  is preferably fabricated from steel or from steel alloys. The main body section  302  is configured to be a specific length  316 , such as about 40 feet (12.2 meters). The main body section  302  comprises individual pipe joints that will have a length that is between about 10 feet (3.0 meters) and 50 feet (15.2 meters). The pipe joints are typically threadedly connected end-to-end to form the main body section  302  according to length  316 . 
     The packer assembly  300  also includes opposing mechanically-set packers  304 . The mechanically-set packers  304  are shown schematically, and are generally in accordance with mechanically-set packer elements  212  and  214  of  FIG. 2 . The packers  304  preferably include cup-type elastomeric elements that are less than 1 foot (0.3 meters) in length. As described further below, the packers  304  have alternate flow channels that uniquely allow the packers  304  to be set before a gravel slurry is circulated into the wellbore. 
     A short spacing  308  is provided between the mechanically-set packers  304 . The spacing is seen at  308 . When the packers  304  are mirror-images of one another, the cup-type elements are able to resist fluid pressure from either above or below the packer assembly. 
     The packer assembly  300  also includes a plurality of shunt tubes. The shunt tubes are seen in phantom at  318 . The shunt tubes  318  may also be referred to as transport tubes or jumper tubes. The shunt tubes  318  are blank sections of pipe having a length that extends along the length  316  of the mechanically-set packers  304  and the spacing  308 . The shunt tubes  318  on the packer assembly  300  are configured to couple to and form a seal with shunt tubes on connected sand screens as discussed further below. 
     The shunt tubes  318  provide an alternate flowpath through the mechanically-set packers  304  and the intermediate spacing  308 . This enables the shunt tubes  318  to transport a carrier fluid along with gravel to different intervals  112 ,  114  and  116  of the open-hole portion  120  of the wellbore  100 . 
     The packer assembly  300  also includes connection members. As exemplified in the illustrations, these connection members may represent traditional threaded couplings. A neck section  306  may be provided at a first end of the packer assembly  300 . The neck section  306  has external threads for connecting with a threaded section  310  at an opposing end, such as a coupling box of a sand screen or other pipe or tubular member. 
     The neck section  306  and the threaded section  310  may be made of steel or steel alloys. The neck section  306  and the threaded section  310  are each configured to be a specific length  314 , such as 4 inches (10.2 cm) to 4 feet (1.2 meters) (or other suitable distance). The neck section  306  and the threaded section  310  also have specific inner and outer diameters. The neck section  306  has external threads  307 , while the threaded section  310  has internal threads  311 . These threads  307  and  311  may be utilized to form a seal between the packer assembly  300  and sand control devices or other pipe segments. 
     A cross-sectional view of the packer assembly  300  is shown in  FIG. 3B .  FIG. 3B  is taken along the line  3 B- 3 B of  FIG. 3A . Various shunt tubes  318  are placed radially and equidistantly around the base pipe  302 . A central bore  305  is shown within the base pipe  302 . The central bore  305  receives production fluids during production operations and conveys them to the production tubing  130 . 
       FIG. 4A  presents a cross-sectional side view of a zonal isolation apparatus  400 , in one embodiment. The zonal isolation apparatus  400  includes the packer assembly  300  from  FIG. 3A . In addition, sand control devices  200  have been connected at opposing ends to the neck section  306  and the notched section  310 , respectively. Shunt tubes  318  from the packer assembly  300  are seen connected to shunt tubes  218  on the sand control devices  200 . The shunt tubes  218  represent packing tubes that allow the flow of gravel slurry between a wellbore annulus and the tubes  218 . The shunt tubes  218  on the sand control devices  200  optionally include valves  209  to control the flow of gravel slurry such as to packing tubes (not shown). 
       FIG. 4B  provides a cross-sectional side view of the zonal isolation apparatus  400 .  FIG. 4B  is taken along the line  4 B- 4 B of  FIG. 4A . This is cut through one of the sand screens  200 . In  FIG. 4B , the slotted or perforated base pipe  205  is seen. This is in accordance with base pipe  205  of  FIGS. 1 and 2 . The central bore  105  is shown within the base pipe  205  for receiving production fluids during production operations. 
     An outer mesh  220  is disposed immediately around the base pipe  205 . The outer mesh  220  preferably comprises a wire mesh or wires helically wrapped around the base pipe  205 , and serves as a screen. In addition, shunt tubes  218  are placed radially and equidistantly around the outer mesh  205 . This means that the sand control devices  200  provide an external embodiment for the shunt tubes  218  (or alternate flow channels). 
     The configuration of the shunt tubes  218  is preferably concentric. This is seen in the cross-sectional view of  FIG. 3B . However, the shunt tubes  218  may be eccentrically designed. For example,  FIG. 2B  in U.S. Pat. No. 7,661,476 presents a “Prior Art” arrangement for a sand control device wherein packing tubes  208 A and transport tubes  208   b  are placed external to the base pipe  202  and surrounding filter medium  204 . 
     In the arrangement of  FIGS. 4A and 4B , the shunt tubes  218  are external to the filter medium, or outer mesh  220 . The configuration of the sand control device  200  may be modified. In this respect, the shunt tubes  218  may be moved internal to the filter medium  220 . 
       FIG. 5A  presents a cross-sectional side view of a zonal isolation apparatus  500 , in an alternate embodiment. In this embodiment, sand control devices  200  are again connected at opposing ends to the neck section  306  and the notched section  310 , respectively, of the packer assembly  300 . In addition, shunt tubes  318  on the packer assembly  300  are seen connected to shunt tubes  218  on the sand control assembly  200 . However, in  FIG. 5A , the sand control assembly  200  utilizes internal shunt tubes  218 , meaning that the shunt tubes  218  are disposed between the base pipe  205  and the surrounding screen  220 . 
       FIG. 5B  provides a cross-sectional side view of the zonal isolation apparatus  500 .  FIG. 5B  is taken along the line B-B of  FIG. 5A . This is cut through one of the sand screens  200 . In  FIG. 5B , the slotted or perforated base pipe  205  is again seen. This is in accordance with base pipe  205  of  FIGS. 1 and 2 . The central bore  105  is shown within the base pipe  205  for receiving production fluids during production operations. 
     Shunt tubes  218  are placed radially and equidistantly around the base pipe  205 . The shunt tubes  218  reside immediately around the base pipe  205 , and within a surrounding filter medium  220 . This means that the sand control devices  200  of  FIGS. 5A and 5B  provide an internal embodiment for the shunt tubes  218 . 
     An annular region  225  is created between the base pipe  205  and the surrounding outer mesh or filter medium  220 . The annular region  225  accommodates the inflow of production fluids in a wellbore. The outer wire wrap  220  is supported by a plurality of radially extending support ribs  222 . The ribs  222  extend through the annular region  225 . 
       FIGS. 4A and 5A  present arrangements for connecting sand control joints to a packer assembly. Shunt tubes  318  (or alternate flow channels) within the packers fluidly connect to shunt tubes  218  along the sand screens  200 . However, the zonal isolation apparatus arrangements  400 ,  500  of  FIGS. 4A-4B and 5A-5B  are merely illustrative. In an alternative arrangement, a manifolding system may be used for providing fluid communication between the shunt tubes  218  and the shunt tubes  318 . 
       FIG. 3C  is a cross-sectional view of the packer assembly  300  of  FIG. 3A , in an alternate embodiment. In this arrangement, the shunt tubes  218  are manifolded around the base pipe  302 . A support ring  315  is provided around the shunt tubes  318 . It is again understood that the present apparatus and methods are not confined by the particular design and arrangement of shunt tubes  318  so long as slurry bypass is provided for the packer assembly  210 . However, it is preferred that a concentric arrangement be employed. 
     It should also be noted that the coupling mechanism for the sand control devices  200  with the packer assembly  300  may include a sealing mechanism (not shown). The sealing mechanism prevents leaking of the slurry that is in the alternate flowpath formed by the shunt tubes. Examples of such sealing mechanisms are described in U.S. Pat. No. 6,464,261; Intl. Pat. Application No. WO 2004/094769; Intl. Pat. Application No. WO 2005/031105; U.S. Pat. Publ. No. 2004/0140089; U.S. Pat. Publ. No. 2005/0028977; U.S. Pat. Publ. No. 2005/0061501; and U.S. Pat. Publ. No. 2005/0082060. 
     As noted, the packer assembly  300  includes a pair of mechanically-set packers  304 . When using the packer assembly  300 , the packers  304  are beneficially set before the slurry is injected and the gravel pack is formed. This requires a unique packer arrangement wherein shunt tubes are provided for an alternate flow channel. 
     The packers  304  of  FIG. 3A  are shown schematically. However,  FIGS. 6A and 6B  provide more detailed views of a mechanically-set packer  600  that may be used in the packer assembly of  FIG. 3A , in one embodiment. The views of  FIGS. 6A and 6B  provide cross-sectional side views. In  FIG. 6A , the packer  600  is in its run-in position, while in  FIG. 6B  the packer  600  is in its set position. 
     The packer  600  first includes an inner mandrel  610 . The inner mandrel  610  defines an elongated tubular body forming a central bore  605 . The central bore  605  provides a primary flow path of production fluids through the packer  600 . After installation and commencement of production, the central bore  605  transports production fluids to the bore  105  of the sand screens  200  (seen in  FIGS. 4A and 4B ) and the production tubing  130  (seen in  FIGS. 1 and 2 ). 
     The packer  600  also includes a first end  602 . Threads  604  are placed along the inner mandrel  610  at the first end  602 . The illustrative threads  604  are external threads. A box connector  614  having internal threads at both ends is connected or threaded on threads  604  at the first end  602 . The first end  602  of inner mandrel  610  with the box connector  614  is called the box end. The second end (not shown) of the inner mandrel  610  has external threads and is called the pin end. The pin end (not shown) of the inner mandrel  610  allows the packer  600  to be connected to the box end of a sand screen or other tubular body such as a stand-alone screen, a sensing module, a production tubing, or a blank pipe. 
     The box connector  614  at the box end  602  allows the packer  600  to be connected to the pin end of a sand screen or other tubular body such as a stand-alone screen, a sensing module, a production tubing, or a blank pipe. 
     The inner mandrel  610  extends along the length of the packer  600 . The inner mandrel  610  may be composed of multiple connected segments, or joints. The inner mandrel  610  has a slightly smaller inner diameter near the first end  602 . This is due to a setting shoulder  606  machined into the inner mandrel. As will be explained more fully below, the setting shoulder  606  catches a release sleeve  710  in response to mechanical force applied by a setting tool. 
     The packer  600  also includes a piston mandrel  620 . The piston mandrel  620  extends generally from the first end  602  of the packer  600 . The piston mandrel  620  may be composed of multiple connected segments, or joints. The piston mandrel  620  defines an elongated tubular body that resides circumferentially around and substantially concentric to the inner mandrel  610 . An annulus  625  is formed between the inner mandrel  610  and the surrounding piston mandrel  620 . The annulus  625  beneficially provides a secondary flow path or alternate flow channels for fluids. 
     In the arrangement of  FIGS. 6A and 6B , the alternate flow channels defined by the annulus  625  are external to the inner mandrel  610 . However, the packer could be reconfigured such that the alternate flow channels are within the bore  605  of the inner mandrel  610 . In either instance, the alternate flow channels are “along” the inner mandrel  610 . 
     The annulus  625  is in fluid communication with the secondary flow path of another downhole tool (not shown in  FIGS. 6A and 6B ). Such a separate tool may be, for example, the sand screens  200  of  FIGS. 4A and 5A , or a blank pipe, or other tubular body. The tubular body may or may not have alternate flow channels. 
     The packer  600  also includes a coupling  630 . The coupling  630  is connected and sealed (e.g., via elastomeric “o” rings) to the piston mandrel  620  at the first end  602 . The coupling  630  is then threaded and pinned to the box connector  614 , which is threadedly connected to the inner mandrel  610  to prevent relative rotational movement between the inner mandrel  610  and the coupling  630 . A first torque bolt is shown at  632  for pinning the coupling to the box connector  614 . 
     In one aspect, a NACA (National Advisory Committee for Aeronautics) key  634  is also employed. The NACA key  634  is placed internal to the coupling  630 , and external to a threaded box connector  614 . A first torque bolt is provided at  632 , connecting the coupling  630  to the NACA key  634  and then to the box connector  614 . A second torque bolt is provided at  636  connecting the coupling  630  to the NACA key  634 . NACA-shaped keys can (a) fasten the coupling  630  to the inner mandrel  610  via box connector  614 , (b) prevent the coupling  630  from rotating around the inner mandrel  610 , and (c) streamline the flow of slurry along the annulus  612  to reduce friction. 
     Within the packer  600 , the annulus  625  around the inner mandrel  610  is isolated from the main bore  605 . In addition, the annulus  625  is isolated from a surrounding wellbore annulus (not shown). The annulus  625  enables the transfer of gravel slurry from alternative flow channels (such as shunt tubes  218 ) through the packer  600 . Thus, the annulus  625  becomes the alternative flow channel(s) for the packer  600 . 
     In operation, an annular space  612  resides at the first end  602  of the packer  600 . The annular space  612  is disposed between the box connector  614  and the coupling  630 . The annular space  612  receives slurry from alternate flow channels of a connected tubular body, and delivers the slurry to the annulus  625 . The tubular body may be, for example, an adjacent sand screen, a blank pipe, or a zonal isolation device. 
     The packer  600  also includes a load shoulder  626 . The load shoulder  626  is placed near the end of the piston mandrel  620  where the coupling  630  is connected and sealed. A solid section at the end of the piston mandrel  620  has an inner diameter and an outer diameter. The load shoulder  626  is placed along the outer diameter. The inner diameter has threads and is threadedly connected to the inner mandrel  610 . At least one alternate flow channel is formed between the inner and outer diameters to connect flow between the annular space  612  and the annulus  625 . 
     The load shoulder  626  provides a load-bearing point. During rig operations, a load collar or harness (not shown) is placed around the load shoulder  626  to allow the packer  600  to be picked up and supported with conventional elevators. The load shoulder  626  is then temporarily used to support the weight of the packer  600  (and any connected completion devices such as sand screen joints already run into the well) when placed in the rotary floor of a rig. The load may then be transferred from the load shoulder  626  to a pipe thread connector such as box connector  614 , then to the inner mandrel  610  or base pipe  205 , which is pipe threaded to the box connector  614 . 
     The packer  600  also includes a piston housing  640 . The piston housing  640  resides around and is substantially concentric to the piston mandrel  620 . The packer  600  is configured to cause the piston housing  640  to move axially along and relative to the piston mandrel  620 . Specifically, the piston housing  640  is driven by the downhole hydrostatic pressure. The piston housing  640  may be composed of multiple connected segments, or joints. 
     The piston housing  640  is held in place along the piston mandrel  620  during run-in. The piston housing  640  is secured using a release sleeve  710  and release key  715 . The release sleeve  710  and release key  715  prevent relative translational movement between the piston housing  640  and the piston mandrel  620 . The release key  715  penetrates through both the piston mandrel  620  and the inner mandrel  610 . 
       FIGS. 7A and 7B  provide enlarged views of the release sleeve  710  and the release key  715  for the packer  600 . The release sleeve  710  and the release key  715  are held in place by a shear pin  720 . In  FIG. 7A , the shear pin  720  has not been sheared, and the release sleeve  710  and the release key  715  are held in place along the inner mandrel  610 . However, in  FIG. 7B  the shear pin  720  has been sheared, and the release sleeve  710  has been translated along an inner surface  608  of the inner mandrel  610 . 
     In each of  FIGS. 7A and 7B , the inner mandrel  610  and the surrounding piston mandrel  620  are seen. In addition, the piston housing  640  is seen outside of the piston mandrel  620 . The three tubular bodies representing the inner mandrel  610 , the piston mandrel  620 , and the piston housing  640  are secured together against relative translational or rotational movement by four release keys  715 . Only one of the release keys  715  is seen in  FIG. 7A ; however, four separate keys  715  are radially visible in the cross-sectional view of  FIG. 6E , described below. 
     The release key  715  resides within a keyhole  615 . The keyhole  615  extends through the inner mandrel  610  and the piston mandrel  620 . The release key  715  includes a shoulder  734 . The shoulder  734  resides within a shoulder recess  624  in the piston mandrel  620 . The shoulder recess  624  is large enough to permit the shoulder  734  to move radially inwardly. However, such play is restricted in  FIG. 7A  by the presence of the release sleeve  710 . 
     It is noted that the annulus  625  between the inner mandrel  610  and the piston mandrel  620  is not seen in  FIG. 7A or 7B . This is because the annulus  625  does not extend through this cross-section, or is very small. Instead, the annulus  625  employs separate radially-spaced channels that preserve the support for the release keys  715 , as seen best in  FIG. 6E . Stated another way, the large channels making up the annulus  625  are located away from the material of the inner mandrel  610  that surrounds the keyholes  615 . 
     At each release key location, a keyhole  615  is machined through the inner mandrel  610 . The keyholes  615  are drilled to accommodate the respective release keys  715 . If there are four release keys  715 , there will be four discrete bumps spaced circumferentially to significantly reduce the annulus  625 . The remaining area of the annulus  625  between adjacent bumps allows flow in the alternate flow channel  625  to by-pass the release key  715 . 
     Bumps may be machined as part of the body of the inner mandrel  610 . More specifically, material making up the inner mandrel  610  may be machined to form the bumps. Alternatively, bumps may be machined as a separate, short release mandrel (not shown), which is then threaded to the inner mandrel  610 . Alternatively still, the bumps may be a separate spacer secured between the inner mandrel  610  and the piston mandrel  620  by welding or other means. 
     It is also noted here that in  FIG. 6A , the piston mandrel  620  is shown as an integral body. However, the portion of the piston mandrel  620  where the keyholes  615  are located may be a separate, short release housing. This separate housing is then connected to the main piston mandrel  620 . 
     Each release key  715  has an opening  732 . Similarly, the release sleeve  710  has an opening  722 . The opening  732  in the release key  715  and the opening  722  in the release sleeve  710  are sized and configured to receive a shear pin. The shear pin is seen at  720 . In  FIG. 7A , the shear pin  720  is held within the openings  732 ,  722  by the release sleeve  710 . However, in  FIG. 7B  the shear pin  720  has been sheared, and only a small portion of the pin  720  remains visible. 
     An outer edge of the release key  715  has a ruggled surface, or teeth. The teeth for the release key  715  are shown at  736 . The teeth  736  of the release key  715  are angled and configured to mate with a reciprocal ruggled surface within the piston housing  640 . The mating ruggled surface (or teeth) for the piston housing  640  are shown at  646 . The teeth  646  reside on an inner face of the piston housing  640 . When engaged, the teeth  736 ,  646  prevent movement of the piston housing  640  relative to the piston mandrel  620  or the inner mandrel  610 . Preferably, the mating ruggled surface or teeth  646  reside on the inner face of a separate, short outer release sleeve, which is then threaded to the piston housing  640 . 
     Returning now to  FIGS. 6A and 6B , the packer  600  includes a centralizing member  650 . The centralizing member  650  is actuated by the movement of the piston housing  640 . The centralizing member  650  may be, for example, as described in U.S. Patent Publication No. 2011/0042106. 
     The packer  600  further includes a sealing element  655 . As the centralizing member  650  is actuated and centralizes the packer  600  within the surrounding wellbore, the piston housing  640  continues to actuate the sealing element  655  as described in U.S. Patent Publication No. 2009/0308592. 
     In  FIG. 6A , the centralizing member  650  and sealing element  655  are in their run-in position. In  FIG. 6B , the centralizing member  650 , energy directing member  657 , and connected sealing element  655  have been actuated. This means the piston housing  640  has moved along the piston mandrel  620 , causing both the centralizing member  650  and the sealing element  655  to engage the surrounding wellbore wall. 
     An anchor system as described in WO 2010/084353 may be used to prevent the piston housing  640  from going backward. This prevents contraction of the cup-type element  655 . 
     As noted, movement of the piston housing  640  takes place in response to hydrostatic pressure from wellbore fluids, including the gravel slurry. In the run-in position of the packer  600  (shown in  FIG. 6A ), the piston housing  640  is held in place by the release sleeve  710  and associated piston key  715 . This position is shown in  FIG. 7A . In order to set the packer  600  (in accordance with  FIG. 6B ), the release sleeve  710  must be moved out of the way of the release key  715  so that the teeth  736  of the release key  715  are no longer engaged with the teeth  646  of the piston housing  640 . This position is shown in  FIG. 7B . 
     To move the release the release sleeve  710 , a setting tool is used. An illustrative setting tool is shown at  750  in  FIG. 7C . The setting tool  750  defines a short cylindrical body  755 . Preferably, the setting tool  750  is run into the wellbore with a washpipe string (not shown). Movement of the washpipe string along the wellbore can be controlled at the surface. 
     An upper end  752  of the setting tool  750  is made up of several radial collet fingers  760 . The collet fingers  760  collapse when subjected to sufficient inward force. In operation, the collet fingers  760  latch into a profile  724  formed along the release sleeve  710 . The collet fingers  760  include raised surfaces  762  that mate with or latch into the profile  724  of the release key  710 . Upon latching, the setting tool  750  is pulled or raised within the wellbore. The setting tool  750  then pulls the release sleeve  710  with sufficient force to cause the shear pins  720  to shear. Once the shear pins  720  are sheared, the release sleeve  710  is free to translate upward along the inner surface  608  of the inner mandrel  610 . 
     As noted, the setting tool  750  may be run into the wellbore with a washpipe. The setting tool  750  may simply be a profiled portion of the washpipe body. Preferably, however, the setting tool  750  is a separate tubular body  755  that is threadedly connected to the washpipe. In  FIG. 7C , a connection tool is provided at  770 . The connection tool  770  includes external threads  775  for connecting to a drill string or other run-in tubular. The connection tool  770  extends into the body  755  of the setting tool  750 . The connection tool  770  may extend all the way through the body  755  to connect to the washpipe or other device, or it may connect to internal threads (not seen) within the body  755  of the setting tool  750 . 
     Returning to  FIGS. 7A and 7B , the travel of the release sleeve  710  is limited. In this respect, a first or top end  726  of the release sleeve  710  stops against the shoulder  606  along the inner surface  608  of the inner mandrel  610 . The length of the release sleeve  710  is short enough to allow the release sleeve  710  to clear the opening  732  in the release key  715 . When fully shifted, the release key  715  moves radially inward, pushed by the ruggled profile in the piston housing  640  when hydrostatic pressure is present. 
     Shearing of the pin  720  and movement of the release sleeve  710  also allows the release key  715  to disengage from the piston housing  640 . The shoulder recess  624  is dimensioned to allow the shoulder  734  of the release key  715  to drop or to disengage from the teeth  646  of the piston housing  640  once the release sleeve  710  is cleared. Hydrostatic pressure then acts upon the piston housing  640  to translate it downward relative to the piston mandrel  620 . 
     After the shear pins  720  have been sheared, the piston housing  640  is free to slide along an outer surface of the piston mandrel  620 . To accomplish this, hydrostatic pressure from the annulus  625  acts upon a shoulder  642  in the piston housing  640 . This is seen best in  FIG. 6B . The shoulder  642  serves as a pressure-bearing surface. A fluid port  628  is provided through the piston mandrel  620  to allow fluid to access the shoulder  642 . Beneficially, the fluid port  628  allows a pressure higher than hydrostatic pressure to be applied during gravel packing operations. The pressure is applied to the piston housing  640  to ensure that the packer elements  655  engage against the surrounding wellbore. 
     The packer  600  also includes a metering device. As the piston housing  640  translates along the piston mandrel  620 , a metering orifice  664  regulates the rate the piston housing translates along the piston mandrel therefore slowing the movement of the piston housing and regulating the setting speed for the packer  600 . To further understand features of the illustrative mechanically-set packer  600 , several additional cross-sectional views are provided. These are seen at  FIGS. 6C, 6D, 6E, and 6F . 
     First,  FIG. 6C  is a cross-sectional view of the mechanically-set packer of  FIG. 6A . The view is taken across line  6 C- 6 C of  FIG. 6A . Line  6 C- 6 C is taken through one of the torque bolts  636 . The torque bolt  636  connects the coupling  630  to the NACA key  634 . 
       FIG. 6D  is a cross-sectional view of the mechanically-set packer of  FIG. 6A . The view is taken across line  6 D- 6 D of  FIG. 6B . Line  6 D- 6 D is taken through another of the torque bolts  632 . The torque bolt  632  connects the coupling  630  to the box connector  614 , which is threaded to the inner mandrel  610 . 
       FIG. 6E  is a cross-sectional view of the mechanically-set packer  600  of  FIG. 6A . The view is taken across line  6 E- 6 E of  FIG. 6A . Line  6 E-E is taken through the release key  715 . It can be seen that the release key  715  passes through the piston mandrel  620  and into the inner mandrel  610 . It is also seen that the alternate flow channel  625  resides between the release keys  715 . 
       FIG. 6F  is a cross-sectional view of the mechanically-set packer  600  of  FIG. 6A . The view is taken across line  6 F- 6 F of  FIG. 6B . Line  6 F- 6 F is taken through the fluid ports  628  within the piston mandrel  620 . As the fluid moves through the fluid ports  628  and pushes the shoulder  642  of the piston housing  640  away from the ports  628 , an annular gap  672  is created and elongated between the piston mandrel  620  and the piston housing  640 . 
     Once the bypass packer  600  is set, gravel packing operations may commence.  FIGS. 8A through 8J  present stages of a gravel packing procedure, in one embodiment. The gravel packing procedure uses a packer assembly having alternate flow channels. The packer assembly may be in accordance with packer assembly  300  of  FIG. 3A . The packer assembly  300  will have mechanically-set packers  304 . These mechanically-set packers  304  may be in accordance with packer  600  of  FIGS. 6A and 6B . 
     In  FIGS. 8A through 8J , sand control devices are utilized with an illustrative gravel packing procedure. In  FIG. 8A , a wellbore  800  is shown. The illustrative wellbore  800  is a horizontal, open-hole wellbore. The wellbore  800  includes a wall  805 . Two different production intervals are indicated along the horizontal wellbore  800 . These are shown at  810  and  820 . Two sand control devices  850  have been run into the wellbore  800 . Separate sand control devices  850  are provided in each production interval  810 ,  820 . Fluids in the wellbore  800  have been displaced using a clean fluid  814 . 
     Each of the sand control devices  850  is comprised of a base pipe  854  and a surrounding sand screen  856 . The base pipe  854  has slots or perforations to allow fluid to flow into the base pipe  854 . The sand control devices  850  also each include alternate flow paths. These may be in accordance with shunt tubes  218  from either  FIG. 4B  or  FIG. 5B . Preferably, the shunt tubes are internal shunt tubes disposed between the base pipes  854  and the sand screens  856  in the annular region shown at  852 . 
     The sand control devices  850  are connected via an intermediate packer assembly  300 . In the arrangement of  FIG. 8A , the packer assembly  300  is installed at the interface between production intervals  810  and  820 . More than one packer assembly  300  may be incorporated. 
     In addition to the sand control devices  850 , a washpipe  840  has been lowered into the wellbore  800 . The washpipe  840  is run into the wellbore  800  below a crossover tool or a gravel pack service tool (not shown) which is attached to the end of a drill pipe  835  or other working string. The washpipe  840  is an elongated tubular member that extends into the sand screens  850 . The washpipe  840  aids in the circulation of the gravel slurry during a gravel packing operation, and is subsequently removed. Attached to the washpipe  840  is a shifting tool, such as the shifting tool  750  presented in  FIG. 7C . The shifting tool  750  is positioned below the packer  300 . 
     In  FIG. 8A , a crossover tool  845  is placed at the end of the drill pipe  835 . The crossover tool  845  is used to direct the injection and circulation of the gravel slurry, as discussed in further detail below. 
     A separate packer  815  is connected to the crossover tool  845 . The packer  815  and connected crossover tool  845  are temporarily positioned within a string of production casing  830 . Together, the packer  815 , the crossover tool  845 , the elongated washpipe  840 , the shifting tool  750 , and the gravel pack screens  850  are run into the lower end of the wellbore  800 . The packer  815  is then set in the production casing  830 . The crossover tool  845  is then released from the packer  815  and is free to move as shown in  FIG. 8B . 
     In  FIG. 8B , the packer  815  is set in the production casing string  830 . This means that the packer  815  is actuated to extend slips and an elastomeric sealing element against the surrounding casing string  830 . The packer  815  is set above the intervals  810  and  820 , which are to be gravel packed. The packer  815  seals the intervals  810  and  820  from the portions of the wellbore  800  above the packer  815 . 
     After the packer  815  is set, as shown in  FIG. 8B , the crossover tool  845  is shifted up into a reverse position. Circulation pressures can be taken in this position. A carrier fluid  812  is pumped down the drill pipe  835  and placed into an annulus between the drill pipe  835  and the surrounding production casing  830  above the packer  815 . The carrier fluid is a gravel carrier fluid, which is the liquid component of the gravel packing slurry. The carrier fluid  812  displaces the clean displacement fluid  814  above the packer  815 , which may be an oil-based fluid such as the conditioned NAF. The carrier fluid  812  displaces the displacement fluid  814  in the direction indicated by arrows “C.” 
     Next, the packers  304  are set, as shown in  FIG. 8C . This is done by pulling the shifting tool located below the packer assembly  300  on the washpipe  840  and up past the packer assembly  300 . More specifically, the mechanically-set packers  304  of the packer assembly  300  are set. The packers  304  may be, for example, packer  600  of  FIGS. 6A and 6B . The packer  600  is used to isolate the annulus formed between the sand screens  856  and the surrounding wall  805  of the wellbore  800 . The washpipe  840  is lowered to a reverse position. While in the reverse position, as shown in  FIG. 8D , the carrier fluid  812  with gravel may be placed within the drill pipe  835  and utilized to force the clean displacement fluid  814  through the washpipe  840  and up the annulus formed between the drill pipe  835  and production casing  830  above the packer  815 , as shown by the arrows “C.” 
     In  FIGS. 8D through 8F , the crossover tool  845  may be shifted into the circulating position to gravel pack the first subsurface interval  810 . In  FIG. 8D , the carrier fluid with gravel  816  begins to create a gravel pack within the production interval  810  above the packer  300  in the annulus between the sand screen  856  and the wall  805  of the open-hole wellbore  800 . The fluid flows outside the sand screen  856  and returns through the washpipe  840  as indicated by the arrows “D.” 
     In  FIG. 8E , a first gravel pack  860  begins to form above the packer  300 . The gravel pack  860  is forming around the sand screen  856  and towards the packer  815 . Carrier fluid  812  is circulated below the packer  300  and to the bottom of the wellbore  800 . The carrier fluid  812  without gravel flows up the washpipe  840  as indicated by arrows “C.” 
     In  FIG. 8F , the gravel packing process continues to form the gravel pack  860  toward the packer  815 . The sand screen  856  is now being fully covered by the gravel pack  860  above the packer  300 . Carrier fluid  812  continues to be circulated below the packer  300  and to the bottom of the wellbore  800 . The carrier fluid  812  sans gravel flows up the washpipe  840  as again indicated by arrows “C.” 
     Once the gravel pack  860  is formed in the first interval  810  and the sand screens above the packer  300  are covered with gravel, the carrier fluid with gravel  816  is forced through the shunt tubes (shown at  318  in  FIG. 3B ). The carrier fluid with gravel  816  forms the gravel pack  860  in  FIGS. 8G through 8J . 
     In  FIG. 8G , the carrier fluid with gravel  816  now flows within the production interval  820  below the packer  300 . The carrier fluid  816  flows through the shunt tubes and packer  300 , and then outside the sand screen  856 . The carrier fluid  816  then flows in the annulus between the sand screen  856  and the wall  805  of the wellbore  800 , and returns through the washpipe  840 . The flow of carrier fluid with gravel  816  is indicated by arrows “D,” while the flow of carrier fluid in the washpipe  840  without the gravel is indicated at  812 , shown by arrows “C.” 
     It is noted here that slurry only flows through the bypass channels along the packer sections. After that, slurry will go into the alternate flow channels in the next, adjacent screen joint. Alternate flow channels have both transport and packing tubes manifolded together at each end of a screen joint. Packing tubes are provided along the sand screen joints. The packing tubes represent side nozzles that allow slurry to fill any voids in the annulus. Transport tubes will take the slurry further downstream. 
     In  FIG. 8H , the gravel pack  860  is beginning to form below the packer  300  and around the sand screen  856 . In  FIG. 8I , the gravel packing continues to grow the gravel pack  860  from the bottom of the wellbore  800  up toward the packer  300 . In  FIG. 8J , the gravel pack  860  has been formed from the bottom of the wellbore  800  up to the packer  300 . The sand screen  856  below the packer  300  has been covered by gravel pack  860 . The surface treating pressure increases to indicate that the annular space between the sand screens  856  and the wall  805  of the wellbore  800  is fully gravel packed. 
       FIG. 8K  shows the drill string  835  and the washpipe  840  from  FIGS. 8A through 8J  having been removed from the wellbore  800 . The casing  830 , the base pipes  854 , and the sand screens  856  remain in the wellbore  800  along the upper  810  and lower  820  production intervals. Packer  300  and the gravel packs  860  remain set in the open hole wellbore  800  following completion of the gravel packing procedure from  FIGS. 8A through 8J . The wellbore  800  is now ready for production operations. 
     As mentioned above, once a wellbore has undergone gravel packing, the operator may choose to isolate a selected interval in the wellbore, and discontinue production from that interval. To demonstrate how a wellbore interval may be isolated,  FIGS. 9A and 9B  are provided. 
     First,  FIG. 9A  is a cross-sectional view of a wellbore  900 A. The wellbore  900 A is generally constructed in accordance with wellbore  100  of  FIG. 2 . In  FIG. 9A , the wellbore  900 A is shown intersecting through a subsurface interval  114 . Interval  114  represents an intermediate interval. This means that there is also an upper interval  112  and a lower interval  116  (seen in  FIG. 2 , but not shown in  FIG. 9A ). 
     The subsurface interval  114  may be a portion of a subsurface formation that once produced hydrocarbons in commercially viable quantities but has now suffered significant water or hydrocarbon gas encroachment. Alternatively, the subsurface interval  114  may be a formation that was originally a water zone or aquitard or is otherwise substantially saturated with aqueous fluid. In either instance, the operator has decided to seal off the influx of formation fluids from interval  114  into the wellbore  900 A. 
     A sand screen  200  has been placed in the wellbore  900 A. Sand screen  200  is in accordance with the sand control device  200  of  FIG. 2 . In addition, a base pipe  205  is seen extending through the intermediate interval  114 . The base pipe  205  is part of the sand screen  200 . The sand screen  200  also includes a mesh screen, a wire-wrapped screen, or other radial filter medium  207 . The base pipe  205  and surrounding filter medium  207  preferably comprise a series of joints connected end-to-end. The joints are ideally about 5 to 45 feet in length. 
     The wellbore  900 A has an upper packer assembly  210 ′ and a lower packer assembly  210 ″. The upper packer assembly  210 ′ is disposed near the interface of the upper interval  112  and the intermediate interval  114 , while the lower packer assembly  210 ″ is disposed near the interface of the intermediate interval  114  and the lower interval  116 . Each packer assembly  210 ′,  210 ″ is preferably in accordance with packer assembly  300  of  FIGS. 3A and 3B . In this respect, the packer assemblies  210 ′,  210 ″ will each have opposing mechanically-set packers  304 . The mechanically-set packers are shown in  FIG. 9A  at  212  and  214 . The mechanically-set packers  212 ,  214  may be in accordance with packer  600  of  FIGS. 6A and 6B . The packers  212 ,  214  are spaced apart as shown by spacing  216 . 
     The dual packers  212 ,  214  are mirror images of each other, except for the release sleeves (e.g., release sleeve  710  and associated shear pin  720 ). As noted above, unilateral movement of a shifting tool (such as shifting tool  750 ) shears the shear pins  720  and moves the release sleeves  710 . This allows the packer elements  655  to be activated in sequence, the lower one first, and then the upper one. 
     The wellbore  900 A is completed as an open-hole completion. A gravel pack has been placed in the wellbore  900 A to help guard against the inflow of granular particles. Gravel packing is indicated as spackles in the annulus  202  between the filter media  207  of the sand screen  200  and the surrounding wall  201  of the wellbore  900 A. 
     In the arrangement of  FIG. 9A , the operator desires to continue producing formation fluids from upper  112  and lower  116  intervals while sealing off intermediate interval  114 . The upper  112  and lower  116  intervals are formed from sand or other rock matrix that is permeable to fluid flow. To accomplish this, a straddle packer  905  has been placed within the sand screen  200 . The straddle packer  905  is placed substantially across the intermediate interval  114  to prevent the inflow of formation fluids from the intermediate interval  114 . 
     The straddle packer  905  comprises a mandrel  910 . The mandrel  910  is an elongated tubular body having an upper end adjacent the upper packer assembly  210 ′, and a lower end adjacent the lower packer assembly  210 ″. The straddle packer  905  also comprises a pair of annular packers. These represent an upper packer  912  adjacent the upper packer assembly  210 ′, and a lower packer  914  adjacent the lower packer assembly  210 ″. The novel combination of the upper packer assembly  210 ′ with the upper packer  912 , and the lower packer assembly  210 ″ with the lower packer  914  allows the operator to successfully isolate a subsurface interval such as intermediate interval  114  in an open-hole completion. 
     Another technique for isolating an interval along an open-hole formation is shown in  FIG. 9B .  FIG. 9B  is a side view of a wellbore  900 B. Wellbore  900 B may again be in accordance with wellbore  100  of  FIG. 2 . Here, the lower interval  116  of the open-hole completion is shown. The lower interval  116  extends essentially to the bottom  136  of the wellbore  900 B and is the lowermost zone of interest. 
     In this instance, the subsurface interval  116  may be a portion of a subsurface formation that once produced hydrocarbons in commercially viable quantities but has now suffered significant water or hydrocarbon gas encroachment. Alternatively, the subsurface interval  116  may be a formation that was originally a water zone or aquitard or is otherwise substantially saturated with aqueous fluid. In either instance, the operator has decided to seal off the influx of formation fluids from the lower interval  116  into the wellbore  100 . 
     To accomplish this, a plug  920  has been placed within the wellbore  100 . Specifically, the plug  920  has been set in the mandrel  215  supporting the lower packer assembly  210 ″. Of the two packer assemblies  210 ′,  210 ″, only the lower packer assembly  210 ″ is seen. By positioning the plug  920  in the lower packer assembly  210 ″, the plug  920  is able to prevent the flow of formation fluids up the wellbore  200  from the lower interval  116 . 
     It is noted that in connection with the arrangement of  FIG. 9B , the intermediate interval  114  may comprise a shale or other rock matrix that is substantially impermeable to fluid flow. In this situation, the plug  920  need not be placed adjacent the lower packer assembly  210 ″; instead, the plug  920  may be placed anywhere above the lower interval  116  and along the intermediate interval  114 . Further, in this instance the upper packer assembly  210 ′ need not be positioned at the top of the intermediate interval  114 ; instead, the upper packer assembly  210 ′ may also be placed anywhere along the intermediate interval  114 . If the intermediate interval  114  is comprised of unproductive shale, the operator may choose to place blank pipe across this region, with alternate flow channels, i.e. transport tubes, along the intermediate interval  114 . 
     A method  1000  for completing a wellbore is also provided herein. The method  1000  is presented in  FIG. 10 .  FIG. 10  provides a flowchart presenting steps for a method  1000  of completing a wellbore, in various embodiments. Preferably, the wellbore is an open-hole wellbore. 
     The method  1000  includes providing a zonal isolation apparatus. This is shown at Box  1010  of  FIG. 10 . The zonal isolation apparatus is preferably in accordance with the components described above in connection with  FIG. 2 . In this respect, the zonal isolation apparatus may first include a sand screen. The sand screen will represent a base pipe and a surrounding mesh or wound wire. The zonal isolation apparatus will also have at least one packer assembly. The packer assembly will have at least one mechanically-set packer, with the mechanically-set packer having alternate flow channels. 
     Preferably, the packer assembly will have at least two mechanically set packers. Alternate flow channels will travel through each of the mechanically-set packers. Preferably, the zonal isolation apparatus will comprise at least two packer assemblies separated by sand screen joints or blank joints or some combination thereof. 
     The method  1000  also includes running the zonal isolation apparatus into the wellbore. The step of running the zonal isolation apparatus into the wellbore is shown at Box  1020 . The zonal isolation apparatus is run into a lower portion of the wellbore, which is preferably completed as an open-hole. 
     The open-hole portion of the wellbore may be completed substantially vertically. Alternatively, the open-hole portion may be deviated, or even horizontal. 
     The method  1000  also includes positioning the zonal isolation apparatus in the wellbore. This is shown in  FIG. 10  at Box  1030 . The step of positioning the zonal isolation apparatus is preferably done by hanging the zonal isolation apparatus from a lower portion of a string of production casing. The apparatus is positioned such that the sand screen is adjacent one or more selected production intervals along the open-hole portion of the wellbore. Further, a first of the at least one packer assembly is positioned above or proximate the top of a selected subsurface interval. 
     In one embodiment, the wellbore traverses through three separate intervals. These include an upper interval from which hydrocarbons are produced, and a lower interval from which hydrocarbons are no longer being produced in economically viable volumes. Such intervals may be formed of sand or other permeable rock matrix. The intervals may also include an intermediate interval from which hydrocarbons are not produced. The formation along the intermediate interval may be formed of shale or other substantially impermeable material. The operator may choose to position the first of the at least one packer assembly near the top of the lower interval or anywhere along the non-permeable intermediate interval. 
     In one aspect, the at least one packer assembly is placed proximate a top of an intermediate interval. Optionally, a second packer assembly is positioned proximate the bottom of a selected interval such as the intermediate interval. This is shown in Box  1035 . 
     The method  1000  next includes setting the mechanically set packer elements in each of the at least one packer assembly. This is provided in Box  1040 . Mechanically setting the upper and lower packer elements means that an elastomeric (or other) sealing member engages the surrounding wellbore wall. The packer elements isolate an annular region formed between the sand screens and the surrounding subsurface formation above and below the packer assemblies. 
     Beneficially, the step of setting the packer of Box  1040  is provided before slurry is injected into the annular region. Setting the packer provides a hydraulic and mechanical seal to the wellbore before any gravel is placed around the elastomeric element. This provides a better seal during the gravel packing operation. 
     The step of Box  1040  may be accomplished by using the packer  600  of  FIGS. 6A and 6B . The open-hole, mechanically-set packer  600  enables gravel pack completions to gain the current flexibility of standalone screen (SAS) applications by providing future zonal isolation of unwanted fluids while enjoying the benefits of reliability of an alternate path gravel pack completion. 
       FIG. 11  is a flowchart that provides steps that may be used, in one embodiment, for a method  1100  of setting a packer. The method  110  first includes providing the packer. This is shown at Box  1110 . The packer may be in accordance with packer  600  of  FIGS. 6A and 6B . Thus, the packer is a mechanically-set packer that is set against an open-hole wellbore to seal an annulus. 
     Fundamentally, the packer will have an inner mandrel, and alternate flow channels around the inner mandrel. The packer may further have a movable piston housing and an elastomeric sealing element. The sealing element is operatively connected to the piston housing. This means that sliding the movable piston housing along the packer (relative to the inner mandrel) will actuate the sealing element into engagement with the surrounding wellbore. 
     The packer may also have a port. The port is in fluid communication with the piston housing. Hydrostatic pressure within the wellbore communicates with the port. This, in turn, applies fluid pressure to the piston housing. Movement of the piston housing along the packer in response to hydrostatic pressure causes the elastomeric sealing element to be expanded into engagement with the surrounding wellbore. 
     It is preferred that the packer also have a centralizing system. An example is the centralizer  660  of  FIGS. 6A and 6B . It is also preferred that mechanical force used to actuate the sealing element be applied by the piston housing through the centralizing system. In this way, both the centralizers and the sealing element are set through the same hydrostatic force. 
     The method  1100  also includes connecting the packer to a tubular body. This is provided at Box  1120 . The tubular body may be a blank pipe or a downhole sensing tool equipped with alternate flow channels. However, it is preferred that the tubular body be a sand screen equipped with alternate flow channels. 
     Preferably, the packer is one of two mechanically-set packers having cup-type sealing elements. The packer assembly is placed within a string of sand screens or blanks equipped with alternate flow channels. 
     Regardless of the arrangement, the method  1100  also includes running the packer and the connected tubular body into a wellbore. This is shown at Box  1130 . In addition, the method  1100  includes running a setting tool into the wellbore. This is provided at Box  1140 . Preferably, the packer and connected sand screen are run first, followed by the setting tool. The setting tool may be in accordance with exemplary setting tool  750  of  FIG. 7C . Preferably, the setting tool is part of or is run in with a washpipe. 
     The method  1100  next includes moving the setting tool through the inner mandrel of the packer. This is shown at Box  1150 . The setting tool is translated within the wellbore through mechanical force. Preferably, the setting tool is at the end of a working string such as coiled tubing. 
     Movement of the setting tool through the inner mandrel causes the setting tool to shift a sleeve along the inner mandrel. In one aspect, shifting the sleeve will shear one or more shear pins. In any aspect, shifting the sleeve releases the piston housing, permitting the piston housing to shift or to slide along the packer relative to the inner mandrel. As noted above, this movement of the piston housing permits the sealing element to be actuated against the wall of the surrounding open-hole wellbore. 
     In connection with the moving step of Box  1150 , the method  1100  also includes communicating hydrostatic pressure to the port. This is seen in Box  1160 . Communicating hydrostatic pressure means that the wellbore has sufficient energy stored in a column of fluid to create a hydrostatic head, wherein the hydrostatic head acts against a surface or shoulder on the piston housing. The hydrostatic pressure includes pressure from fluids in the wellbore, whether such fluids are completion fluids or reservoir fluids, and may also include pressure contributed downhole by a reservoir. Because the shear pins (including set screws) have been sheared, the piston housing is free to move. 
     Returning back to  FIG. 10 , the method  1000  for completing an open-hole wellbore also includes injecting a particulate slurry into the annular region. This is demonstrated in Box  1050 . The particulate slurry is made up of a carrier fluid and sand (and/or other) particles. One or more alternate flow channels allow the particulate slurry to bypass the sealing elements of the mechanically-set packers. In this way, the open-hole portion of the wellbore is gravel-packed below, or above and below (but not between), the mechanically-set packer elements. 
     It is noted that the sequence for annulus pack-off may vary. For example, if a premature sand bridge is formed during gravel packing, the annulus above the bridge will continue to be gravel packed via fluid leak-off through the sand screen due to the alternate flow channels. In this respect, some slurry will flow into and through the alternate flow channels to bypass the premature sand bridge and deposit a gravel pack. As the annulus above the premature sand bridge is nearly completely packed, slurry is increasingly diverted into and through the alternate flow channels. Here, both the premature sand bridge and the packer will be bypassed so that the annulus is gravel packed below the packer. 
     It is also possible that a premature sand bridge may form below the packer. Any voids above or below the packer will eventually be packed by the alternate flow channels until the entire annulus is fully gravel packed. 
     During pumping operations, once gravel covers the screens above the packer, slurry is diverted into the shunt tubes, then passes through the packer, and continues to pack below the packer via the shunt tubes (or alternate flow channels) with side ports allowing slurry to exit into the wellbore annulus. The hardware provides the ability to seal off bottom water, selectively complete or gravel pack targeted intervals, perform a stacked open-hole completion, or isolate a gas/water-bearing sand following production. The hardware further allows for selective stimulation, selective water or gas injection, or selective chemical treatment for damage removal or sand consolidation. 
     The method  1000  further includes producing production fluids from intervals along the open-hole portion of the wellbore. This is provided at Box  1060 . Production takes place for a period of time. 
     In one embodiment of the method  1000 , flow from a selected interval may be sealed from flowing into the wellbore. For example, a plug may be installed in the base pipe of the sand screen above or near the top of a selected subsurface interval. This is shown at Box  1070 . Such a plug may be used at or below the lowest packer assembly, such as the second packer assembly from step  1035 . 
     In another example, a straddle packer is placed along the base pipe along a selected subsurface interval to be sealed. This is shown at Box  1075 . Such a straddle may involve placement of sealing elements adjacent upper and lower packer assemblies (such as packer assemblies  210 ′,  210 ″ of  FIG. 2  or  FIG. 9A ) along a mandrel. 
     Other embodiments of sand control devices  200  may be used with the apparatuses and methods herein. For example, the sand control devices may include stand-alone screens (SAS), pre-packed screens, or membrane screens. The joints may be any combination of screen, blank pipe, or zonal isolation apparatus. 
     The downhole packer may be used for formation isolation in contexts other than production. For example, the method may further comprise injecting a solution from an earth surface, through the inner mandrel below the packer, and into a subsurface formation. The solution may be, for example, and aqueous solution, an acidic solution, or a chemical treatment. The method may then further comprise circulating the aqueous solution, the acidic solution, or the chemical treatment to clean a near-wellbore region along the open-hole portion of the wellbore. This may be done before or after production operations begin. Alternatively, the solution may be an aqueous solution, and the method may further comprise continuing to inject the aqueous solution into the subsurface formation as part of an enhanced oil recovery operation. This would preferably be in lieu of production from the wellbore. 
     While it will be apparent that the inventions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof. Improved methods for completing an open-hole wellbore are provided so as to seal off one or more selected subsurface intervals. An improved zonal isolation apparatus is also provided. The inventions permit an operator to produce fluids from or to inject fluids into a selected subsurface interval.