Abstract:
Apparatus, assembly and process for allowing gas lift operations to be conducted along a relatively long perforated interval below a packer in a subterranean well. An elongated segregation member is lowered into locking engagement with a bypass mandrel secured to a tubing string above the packer. This segregation member is configured and dimensioned to define two fluid flow paths. A first flow path extends from the surface of the earth through the annulus formed between the tubing string above the packer and casing secured in the well, the bypass mandrel, a bore through a portion of the segregation member and the interior of the tubing string below the packer. A second flow path extends from the subterranean region penetrated by the well through the annulus formed between the tubing string below the packer and casing secured in the well, the annulus between the segregation member and the packer, and the interior of the tubing string above the packer. Fluid produced into the well from the subterranean region is conveyed to the surface via the second flow path and can be assisted by gas injected into the first flow path via retrievable gas lift valves in the tubing string above and below the packer. Pressurized gas is conveyed via the first flow path to these retrievable gas lift valves.

Description:
BACKGROUND OF THE INVENTION 
       [0001]    1. Field of the Invention 
         [0002]    The present invention relates to an apparatus, assembly and process for permitting fluid to be conveyed into a subterranean well via retrievable equipment positioned in tubing below a packer, and more particularly, to such apparatus, assembly and process for permitting gas lift to be conducted in a subterranean well below a packer wherein wireline retrievable gas lift valves are employed below the packer. 
         [0003]    2. Description of related Art 
         [0004]    To produce fluids, such as hydrocarbons, from a subterranean formation, a well is drilled from the surface to a depth sufficient to capture the fluids of interest. The well is typically completed by cementing a string of tubulars, i.e. a casing string, in the well and establishing fluid communication between the well and the formation(s) and/or zone(s) of interest by forming perforations through the casing and into the formation(s) and/or zone(s) of interest. Such perforations can be formed by any suitable means, such as by conventional perforating guns. Thereafter, production tubing is positioned within the well and the annulus between the production tubing and casing is sealed typically by means of a packer assembly. Fluids, such as oil, gas and/or water, are then produced from the formation(s) and/or zone(s) of interest into the well via the perforations in the casing and to the surface via production tubing for transportation and/or processing. 
         [0005]    While the formation or reservoir pressure is often initially sufficient to force produced fluids to the surface after completion of the well, some form of artificial lift, for example rod pumps, electrical submersible pumps, or gas lift, usually becomes necessary to assist in producing fluids from the well when the reservoir pressure becomes insufficient to produce fluids to the surface. In its simplest form, gas lift consists of injecting gas from the surface under pressure into the annulus between the casing and production tubing in a well. This injected gas is isolated from the perforations in the casing by means of the packer assembly that seals the casing/tubing annulus above the perforations. The production tubing above the packer is equipped with metering valves that inject the pressurized gas from the casing/tubing annulus into the tubing in an upward flow. These metering valves are installed in mandrels that are included in the tubing. This injected gas lightens the produced fluid present in the production tubing and the upward flow thereof assists in producing fluid upwardly toward the surface wellhead. The number and spacing of gas lift valves used in the production tubing above the packer is calculated to produce fluids to the surface in light of well data, the packer depth and desired production rates. It is preferred to use retrievable metering valves that can be removed from the well by means of a wireline unit and specially designed tools thereby eliminating the need and expense of pulling the production tubing from the well to repair and/or replace metering valves. 
         [0006]    Wells are being increasingly completed with long perforated intervals of casing below the packer, for example up to  1 , 500  feet or more, to maximize production of fluids from subterranean formation(s) and/or zone(s) of interest. Such wells can be produced by conventional gas lift using metering valves above the packer for so long as the reservoir pressure is sufficient enough to convey produced fluids above the first gas lift valve positioned above the packer assembly. However, the pressure in many wells is or becomes insufficient to permit the well to be produced by conventional gas lift techniques and equipment. 
         [0007]    A specialized packer has been developed to install gas metering valves in tubing below the packer so as to extend gas lift operations along the perforated interval below the packer. The tubing is secured to the packer and requires that the packer be released and all of the tubing and the packer be removed from the well to repair or replace the metering valves that are positioned below the packer. This packer and the procedure for removing metering valves are expensive and result in lost production of reservoir fluids. 
         [0008]    Thus, a need exists for apparatus, assemblies and processes to provide for gas lift in tubing below the packer assembly in a well so as to provide production from a perforated interval. A further need exists for such apparatus, assemblies and processes for performing gas lift operations below a packer in a well which permit gas lift metering valves to be retrievable by wireline. 
       SUMMARY OF THE INVENTION 
       [0009]    To achieve the foregoing and other objects, and in accordance with the purposes of the present invention, as embodied and broadly described herein, one characterization of the present invention may comprise an apparatus having an elongated member including an upper section, an intermediate section dimensioned to extend through a packer deployed in a subterranean well and a lower section. The elongated member has a generally axial bore extending through the lower section and the intermediate section and into the upper section and in fluid communication with at least one opening extending through a side wall of said upper section. 
         [0010]    In another characterization of the present invention, an assembly is provided which has first and second sections of tubing string and a segregation member. A first section of a tubing string extends from the surface of the earth into a subterranean well bore and has a packer secured to the lower end thereof. The first section has a generally axial bore therethrough and one or more openings through the wall thereof. A second section of the tubing string is secured to the packer and extends into the subterranean well bore below the packer. The second section has a generally axial bore therethrough and one or more openings through the wall thereof. A segregation member is releasably secured to the first section and extends through the packer and into the second section of the tubing string. A segregation member has a bore extending through a portion thereof which is in fluid communication with the one or openings through the wall of the first section so as to define a flow path from the surface of the earth through a first annulus defined between the first section and the well bore, the one or more openings, and the bore in the segregation member. 
         [0011]    In yet another characterization of the present invention, a subterranean well is provided comprising a tubing string positioned within a casing in a subterranean well and having a packer secured intermediate the length thereof and sealingly engaging the casing. At least one piece of equipment is secured to the tubing string below the packer and is capable of being retrieved on wireline that is conveyed within the tubing string. 
         [0012]    In a further characterization of the present invention, a process is provided for equipping a subterranean well for a gas lift operation. A tubing string having a packer secured intermediate the length thereof is positioned into a subterranean well. The packer sealingly engages casing secured in the well thereby defining a first annulus between the tubing string and casing above the packer and a second annulus between the tubing string and casing below the packer. The tubing string contains retrievable gas lift valves both above and below the packer and contains at least one opening through the wall of the tubing above the packer and at least one opening through the wall of the tubing sting below the packer. A device is positioned within the tubing string such that the device extends above and below said packer and defines a first fluid flow path from the first annulus to the interior of the tubing string below the packer and a second flow path from the second annulus to the interior of the tubing string above the packer. 
         [0013]    In a still further characterization of the present invention, a process is provided for conducting a gas lift operation in a subterranean well. A gas is injected under pressure into the annulus defined between a tubing string positioned in a subterranean well and casing secured in the well, through an internal flow path defined though a packer assembly secured to said tubing string intermediate the length thereof, and into the interior of said tubing string below the packer assembly. This gas is initially injected into the interior of the tubing string above the packer assembly via at least one first gas lift valve and subsequently is injected into the annulus defined between the tubing string and casing below the packer assembly via at least one second gas lift valve. Fluid is produced from a subterranean region penetrated by the well via the annulus between the tubing string below the packer assembly and the casing, an internal annular flow path through the packer assembly defined between said internal flow path and said packer assembly, and the interior of the tubing string above the packer assembly. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0014]    The accompanying drawings, which are incorporated in and form a part of the specification, illustrate the embodiments of the present invention and, together with the description, serve to explain the principles of the invention. 
           [0015]    In the drawings: 
           [0016]      FIG. 1  is a partially cutaway, cross sectional view of a subterranean well equipped with the assembly of the present invention; 
           [0017]      FIG. 2  is a partially cutaway, cross sectional view of a subterranean well equipped with the assembly of the present invention illustrating fluid flow in accordance with the gas lift process of the present invention; 
           [0018]      FIG. 3  is a partially cutaway, cross sectional view of a portion of the assembly of the present invention; 
           [0019]      FIG. 4  is a cross sectional view of the by-pass mandrel of the present invention; and 
           [0020]      FIG. 5  is a cross sectional view taken along line  5 - 5  of  FIG. 4 . 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       [0021]    Referring to  FIG. 1 , a well is indicated generally at  10  and has a well bore  14  which extends from the surface of the earth  12  to a subterranean depth sufficient to penetrate subterranean zones of interest. The well is equipped with generally tubular casing  16  which is conventionally made up of lengths of tubular casing secured together by any suitable means, such as mating screw threads. The casing  16  is secured to the well bore  14  by a sheath of cement  15  which is circulated into place as is evident to a skilled artisan. The well is thereafter placed in fluid communication with subterranean region  18  by means of at least one set of perforations  19  which is formed by any conventional means, such as by one or more perforating gun lowered to the desired depth within the well and ignited. As utilized throughout this description, the term “subterranean region” denotes one or more layers, strata, zones, horizons, reservoirs, or combinations thereof so long as fluids produced therefrom can be commingled for production from the well. The entire interval over which perforations exist in the well is termed the perforated interval  20 . 
         [0022]    In accordance with the present invention, a tubing string  30  is positioned in the well and can be made up of individual joints of tubing  31  secured together by collars  32  as illustrated in  FIGS. 1-3  by any suitable means, such as screw threads. Tubing string  30  can include at least one mandrel  34  having a side pocket  35  into which a retrievable apparatus or piece of equipment, for example a gas lift valve  36 , is releasably secured. A bypass mandrel  40  is secured to an adaptor  37  which in turn is secured to the lower end of the tubing string as positioned in the well  30  (mandrel  34  as illustrated in  FIG. 2 ) by any suitable means, such as by screw threads. The other end of bypass mandrel  40  is secured to adaptor  38  that in turn is secured to packer assembly  50 . Packer assembly  50 , flow crossover sleeve  60  and generally tubular seal bore nipple  70  are secured together in series by any suitable means, such as by screw threads, and a lower tubing string  80  is secured to the other end of the seal bore nipple by any suitable means, such as by screw threads. Cross over sleeve  60  has one or more ports or openings  62  along the length thereof. Lower tubing string  80  can be made up of individual joints of tubing  81  secured together by collars  82  as illustrated. Lower tubing string  80  can include at least one mandrel  84  having a side pocket  85  into which a retrievable apparatus or piece of equipment, for example a metered gas lift valve  86 , is releasably secured. The lower end of lower tubing string  80  is plugged by any suitable means, such as cap  88 . The number and spacing of mandrels  34  and  84  deployed in tubing string  30  and lower tubing string  80 , respectively, are calculated to provide for maximum gas lift capacity. 
         [0023]    The bypass mandrel  40  ( FIGS. 2-5 ) has an outer, generally tubular housing  41  and an inner, generally tubular member  44  which are connected together by one or more spokes or arms  42 . Housing  41  and inner tubular member  44  are preferably axially aligned. Housing  41 , inner member  44  and one or more spokes  42  can be integrally formed or secured together by any suitable means, such as by welds. Each spoke  42  has one or more ports  43  that provide for fluid communication between the exterior and interior of the bypass mandrel as hereinafter described. The inner diameter of inner tubular member  44  of the bypass mandrel is sized to permit passage of retrieval tools that can be lowered through tubing strings  30  and  80  for retrieval of equipment, such as gas lift valves  86 , from mandrels  84  that are positioned below packer  50  in a manner as hereinafter described. The inner surface of one end of the inner tubular member  44  is provided with a cross sectional profile  45 . Each end of housing  41  is provided with any suitable means for mating with other components of the assembly of the present invention, such as screw threads. 
         [0024]    The assembly described above can be assembled as the components are being run into the well. Once the assembly and associated tubing strings  30  and  80  are positioned so that packer assembly  50  is above and gas lift valves  86  are appropriately positioned in relation to the perforated interval from which fluids from subterranean region  18  are to be produced, the slips  52  and generally annular seal  54  of packer assembly  50  can be hydraulically and/or mechanically expanded into sealing engagement with casing  16  so as to form a fluid tight seal across annulus formed between packer assembly  50  and casing  16 . In this manner, the annulus  11  formed between casing string  16  and the tubing string  30  and associated components above the packer assembly  50  is segregated from the annulus  17  formed between the casing  16  and the lower tubing string  80  and associated components below the packer assembly. 
         [0025]    In accordance with the present invention, a segregation member  90  is thereafter conveyed into tubing  30  from the surface by any suitable means, such as by a wireline. Segregation member  90  functions to isolate separate fluid flow paths through the assembly of the present invention and has an upper end  91 , a generally tubular lower end  95  connected together by a generally tubular intermediate portion  94  of reduced diameter. Segregation member  90  can be integrally formed or formed of multiple portions secured together by any suitable means, for example by welds or threaded connections. Generally tubular portions  94  and  95  define an axial bore  98  therethrough that extends into one end of upper portion  91 . Upper portion  91  is provided with one or more radial openings  93  that can have any suitable configuration, for example a slot or port, and that intersect with bore  98  and extend outwardly to the periphery of upper end  91 . The other end of upper end  91  is provided with an axially extending bore  92  to allow engagement of segregation member  90  by a fishing tool for deployment and removal from a well. The outer peripheral surface of upper end  91  is provided with a cross sectional profile  97  that corresponds to cross sectional profile  45  of bypass mandrel  40 . The upper end has generally annular seals  96  which are spaced apart to provide a fluid tight seal for radial ports or openings  93  as hereinafter described. Annular seals  99  are provided around the exterior of lower end  95 . The length of segregation member  90  can vary depending upon the length of packer  50 , for example about 5 to about 8 feet. The diameters of the various components of segregation member  90  are selected depending upon the pressure and rate of gas being injected and fluid produced through the assembly of the present invention. 
         [0026]    Segregation member  90  is conveyed through tubing  30  until the profile  97  on the outer peripheral surface of upper end  91  thereof engages profile  45  on the inner surface of one end of inner tubular member  44  and releasably locks segregation member  90  into engagement with bypass mandrel  40 . In this positioned as illustrated in  FIGS. 1-3 , radial ports or openings  93  in upper portion  91  are aligned with ports  43  of bypass mandrel  40 , intermediate portion  94  of segregation member  90  extends through packer assembly  50  and annular seals  99  on the lower end  95  of segregation member  90  engage the inner surface  72  of seal bore nipple  70  so as to provide a fluid tight seal. 
         [0027]    Once the segregation member  90  is secured within bypass mandrel  40 , the wireline is released from segregation member  90  and withdrawn to the surface and the well is ready for production. In operation, fluid is produced from subterranean region  18  through perforations  19  in the perforated interval  20  and upwardly as indicated by arrows  100  through annulus  17 , ports  62 , annulus  67 , annulus  48  and bore  39  to the surface. If fluid is not capable of being produced to the surface by the pressure of the subterranean region, gas can be injected under pressure into annulus  11  between upper tubing string  30  and casing  16  as indicated by arrows  110  ( FIG. 2 ). Initially gas is injected into produced fluid contained in bore  39  of tubing string  30  above packer assembly  50  by means of gas lift valves  36  as indicated by arrows  120  to assist in production of fluid in tubing  30 . During this phase of the operation, gas is sequentially injected through gas lift valves  36  beginning with the uppermost gas lift valve  36  in tubing string  30 . Once the fluid pressure in the tubing string  30  has been sufficiently lowered by the injected gas, pressurized gas is conveyed though annulus  11 , aligned ports  93  and  43  and bores  98  and  89  as indicated by arrows  130  and is injected into produced fluid contained in annulus  17  by means of gas lift valves  86  as indicated by arrows  140 . During this phase of the gas lift operation, gas is sequentially injected through gas lift valves  86  beginning with the uppermost gas lift valve  86  in tubing string  80 . In this manner, pressurized gas is injected into produced fluid contained in the annulus between the lower tubing string below the packer to assist in production of produced fluids to the surface. 
         [0028]    When it is desired to remove gas lift valves  86  for repair or replacement, a wireline with a retrieving tool at the lower end thereof can be run into tubing string  30  so as to latch onto upper portion  91  of segregation member  90  via bore  92 . The wireline, retrieving tool and segregation member  90  are then removed from the well and wireline is then run into the well to retrieve the desired gas lift valves  86  in a manner evident to a skilled artisan. Thereafter, refurbished and/or new gas lift valves are secured in side pockets  85  of mandrels  84  via wireline and segregation member  90  is thereafter conveyed via tubing string  30  and locked in engagement with bypass mandrel  40 . 
         [0029]    The following example demonstrates the practice and utility of the present invention, but is not to be construed as limiting the scope thereof. 
       EXAMPLE 
       [0030]    A workover rig is moved onto a well, blow out prevention equipment is installed and the existing 2.875 inch outside diameter (“OD”) production tubing is removed from the 5.5 inch OD production casing in the well. The well is cleaned of any debris by running a tubing bailer on the 2.875 inch tubing to the total depth of the well of 9,000 feet. The tubing and bailer are removed from the well. The integrity of the casing above the top of the perforations in the well is determined by running a 5.5 inch OD packer on the 2.875 inch tubing to a depth of 7,500 feet. The packer is mechanically set and the annulus between the 2.875 inch tubing and the 5.5 inch casing above the packer is filled with completion fluid. The blow out prevention equipment is closed at the surface and the fluid in the annulus is pressurized to 1500 pounds per square inch to determine casing integrity. Once casing integrity has been established, the packer is released and the tubing and the packer are removed from the 5.5 inch casing. 
         [0031]    The below packer gas lift assembly is then inserted into the 5.5 inch casing. The assembly consists of the following components starting from the bottom. The assembly consists of a 2.875 inch tubing bull plug, 1,500 feet of 2.875 inch OD tubing with three 2.875 inch by 4.5 inch OD side pocket gas lift mandrels ported for annular flow spaced approximately 400 to 500 feet apart. Each gas lift mandrel is eccentric in design with the end fittings having 2.875 inch OD so as to permit mating by screw threads with the 2.875 inch OD tubing and the body of the mandrel that defines the side pocket has a 4.5 inch OD. The side pocket mandrels are each equipped with a wireline retrievable gas lift valve designed to operate with the predetermined gas lift injection volume and pressure. This portion of the assembly is then connected to a 2.875 inch OD by 2.25 inch inner diameter (“ID”) by 1.5 foot long seal nipple, a 2.875 inch OD by 1 foot long ported sub and a 5.5 inch OD casing packer. On top of the packer a 4.5 inch OD by 2.313 inch ID bypass mandrel is installed. Above the bypass mandrel, 7,500 feet of 2.875 inch OD tubing including three 2.875 inch by 4.5 inch side pocket gas lift mandrels ported for tubing flow are installed. Each gas lift mandrel is eccentric in design with the end fittings having 2.875 inch OD so as to permit mating by screw threads with the 2.875 inch OD tubing and the body of the mandrel that defines the side pocket has a 4.5 inch OD. The placement of the side pocket mandrels are based on the well pressure, expected production rate, design gas lift injection rate and pressure. A wireline retrievable gas lift valve which is designed to operate with the predetermined gas lift pressure and volume is installed in each side pocket mandrel. When the entire gas lift and tubing assembly is installed in the 5.5 inch OD production casing in the well, the gas lift assembly below the packer is placed adjacent to the perforated portion of the wellbore between the depths of 7,500 to 9,000 feet. The packer is then mechanically set approximately 50 feet above the top of the upper most perforation in the production casing. The blow out prevention equipment is then removed from the well, the 2.875 inch OD tubing is connected to the 5.5 inch OD casing wellhead, the wellhead valves are installed and the workover rig is removed from the well. 
         [0032]    A slickline (single element wireline) truck is moved in and rigged up on the well with a 2.875 inch OD lubricator installed on the wellhead. A segregation member having a 2.313 inch OD upper end with two sets of 2.313 inch OD seals located on either side of ports connected to a 1 inch OD intermediate portion approximately 12 feet long which then connects to a 2.25 inch OD lower end is attached to wireline running tools and installed into the lubricator on the wellhead. The valves on the wellhead are then opened and the segregation member is lowered into the 2.875 inch OD tubing in the well on the wireline to the bypass mandrel. The 2.25 inch OD lower seal of the segregation member is inserted through the bypass mandrel, through the center of the 5.5 inch OD packer and the ported sub into the 2.25 inch ID seal bore nipple. A profile on the 2.313 inch OD upper end of the segregation member is located and locked into a 2.313 inch ID profile in the bypass mandrel with the two sets of 2.313 inch OD seals spaced on either side of the ports in the bypass mandrel. The wireline setting tools are released from the segregation member and are then removed from the well by wireline. The lubricator and wireline truck are removed from the well. A high pressure gas line is connected to the annulus defined between the tubing and casing and the annulus is allowed to pressure up to the predetermined maximum kick off pressure. The tubing is connected to the appropriate production facilities and once the casing pressure has reached the predetermined level, the tubing is opened for flow to the production facilities. The well will go through a normal gas lift unloading sequence from the gas lift valves above the packer and will transfer downhole to the gas lift valves below the packer until injection reaches the lowest most operating gas lift valve. 
         [0033]    If the producing character of the well changes or a problem develops which would necessitate a change in the design or repair of the gas lift valves, a wireline truck is moved back on the well and the 2.875 inch OD lubricator is installed on the wellhead. Retrieving tools are attached to the wireline and are installed into the lubricator. The valves on the wellhead are opened and the retrieving tools are lowered into the 2.875 inch OD tubing on wireline to the upper end of the segregation member located in the bypass mandrel located at a depth of approximately 7,500 feet. The upper end of the segregation member is engaged by the wireline retrieving tools and the segregation member is removed from the well by wireline. A gas lift valve retrieving tool along with a side pocket kick over tool is then attached to the wireline and lowered into the 2.875 inch OD tubing, through the bypass mandrel to the depth of the gas lift valve which needs to be repaired or replaced. The side pocket kick over tool is activated, the gas lift valve is engaged with the retrieving tool and the valve is released from the side pocket mandrel and removed from the wellbore by wireline. The gas lift valve retrieving tool is removed from the wireline and a gas lift valve running tool is installed along with the side pocket kick over tool. The redesigned or repaired gas lift valve is attached to the gas lift valve running tool and is inserted into the 2.875 inch OD tubing and run through the bypass mandrel on wireline to the depth of the side pocket gas lift mandrel into which it is to be installed. At the proper depth, the side pocket kick over tool is activated and the gas lift valve is inserted and releasably secured into the side pocket mandrel. The wireline gas lift valve setting tool is released from the gas lift valve and the wireline and tools are removed from the wellbore. The side pocket kick over tool and the gas lift valve setting tool are removed from the wireline and the cross over seal assembly running tool is connected to the wireline. The upper end of the segregation member is then attached to the segregation member running tool and inserted into the 2.875 inch OD tubing on wireline. The lower 2.25 inch OD seal is inserted through the bypass mandrel, the 5.5 inch OD packer, the ported sub, and into the 2.25 inch ID seal bore nipple. The profile on the 2.313 inch OD upper end of the segregation member is inserted and locked into the 2.313 inch ID profile in the bypass mandrel with the two sets of 2.313 inch OD seals located either side of the ports in the bypass mandrel. The setting tool is released from the upper end of the segregation member and the setting tool is removed from the wellbore by wireline. The wireline truck and lubricator is removed from the well, high pressure gas injection is initiated on the annulus defined between the tubing and the casing, the tubing is opened to the production facilities and the gas lift unloading sequence through the gas lift valves is initiated until the gas injection reaches the operating gas lift valve. 
         [0034]    By including gas lift valves and associated mandrels in tubing that is supported on a packer assembly, the apparatus and process of the present invention permit long perforated intervals to be produced by gas lift. The tubing employed below the packer in accordance with the present invention can be up to 15,000 feet or more. Further, the apparatus and process of the present invention allow retrievable apparatus and equipment, for example gas lift valves, to be used over long perforated intervals below the packer assembly. In this manner, long perforated intervals can be effectively produced by gas lift and apparatus and equipment, such as gas lift valves, can be retrieved for repair or replacement without pulling the production tubing from the well. 
         [0035]    As noted above, the present invention can be deployed and practiced using retrievable equipment other than gas lift valves  36  and/or  86 . For example, flow control valves, water flood regulators, chokes, orifices, pressure gauges, temperature gauges, measurement devices or combinations thereof can be employed in lieu of gas lift valves  36  or  86  in one or all of the mandrels  34  or  84  deployed in casing strings  30  and  80 , respectively. Accordingly, operations such as chemical injection, foam injection to unload water from a well, fresh water injection to lower salt concentration of connate water, injection of scale inhibitor, can be preformed using the apparatus, assembly and process of the present invention. 
         [0036]    Although casing  16  is illustrated as being one continuous tubular having a substantially uniform diameter along the length thereof, casing  16  can be made up of several intervals of tubing having differing diameters as will be evident to a skilled artisan. For example, surface casing can extend from the surface of the earth to a given depth, intermediate casing having a diameter less than that of the surface casing can extend from generally the depth at which the surface casing ends to another given depth, and a liner having a diameter less than that of the intermediate casing can extend from generally the depth at which the intermediate casing ends to subterranean region of interest. The apparatus, assembly and process of the present invention can be used with various casing configurations as will be evident to a skilled artisan. Further, components of the assembly of the present invention can extend into one or more sections of casing of a well. For example, where a casing configuration having surface casing, intermediate casing and a liner is utilized, the elastomeric seal  54  and slips  55  of the packer assembly  50  can be set in intermediate casing while the lower tubing string  80  extends into a liner. 
         [0037]    While the foregoing preferred embodiments of the invention have been described and shown, it is understood that the alternatives and modifications, such as those suggested and others, may be made thereto and fall within the scope of the invention.