Abstract:
Embodiments of the present invention generally relate to a sealant for forming durable plugs in wells and method for completing or abandoning wells. In one embodiment, a method of plugging a wellbore includes mixing sealant; mixing cement; pumping the cement and sealant into the wellbore. The cement is above the sealant and the sealant cures to become viscoelastic or semisolid.

Description:
BACKGROUND OF THE INVENTION 
       [0001]    1. Field of the Invention 
         [0002]    Embodiments of the present invention generally relate to a sealant for forming durable plugs in wells and methods for completing or abandoning wells. 
         [0003]    2. Description of the Related Art 
         [0004]      FIG. 1A  is a cross section of a prior art sub-sea wellbore  5  drilled and completed with a land-type completion  1 . A conductor casing string  10  may be set from above sea-level  15 , through the sea  20 , and into the sea-floor or mudline  25 . The conductor casing  10  allows the wellhead (not shown) to be located on a production platform  30  above sea-level  15  rather than on the sea-floor  25 . Alternatively, the platform  30  may service a subsea-type completion or a manifold from multiple subsea-type completions. 
         [0005]    Once the conductor casing  10  has been set and cemented  35  into the wellbore  5 , the wellbore  5  may be drilled to a deeper depth. A second string of casing, known as surface casing  40 , may then be run-in and cemented  45  into place. As the wellbore  5  approaches a hydrocarbon-bearing formation  50 , i.e., crude oil and/or natural gas, a third string of casing, known as production casing  55 , may be run-into the wellbore  5  and cemented  60  into place. Thereafter, the production casing  55  may be perforated  65  to permit the fluid hydrocarbons  70  to flow into the interior of the casing. The hydrocarbons  70  may be transported from the production zone  50  of the wellbore  5  through a production tubing string  75  run into the wellbore  5 . An annulus  80  defined between the production casing  55  and the production tubing  75  may be isolated from the producing formation  50  with a packer  85 . 
         [0006]    Additionally, a stove or drive pipe may be jetted, driven, or drilled in before the conductor casing  10  and/or one or more intermediate casing strings may be run-in and cemented between the surface  40  and production  55  casing strings. The stove or drive pipe may or may not be cemented. 
         [0007]      FIG. 1B  is a cross section of the platform  30  and completion  1  after subsidence due to production from the formation  50 . The subsidence may be substantial, such as ten feet or tens of feet. The subsidence may also be more prevalent proximate to the formation  50  than at the sea-floor, thereby inducing stress in the casings  10 ,  40 ,  55  and fracturing the brittle cement sections  35 ,  45 ,  60 . The wellbore  5  may have been in production for many years, thereby depleting the formation  50  such that the platform operator desires to plug and abandon the wellbore  5 . However, a typical plug procedure may be futile as the subsistence may have made the casings  10 ,  40 ,  55  unstable subject to continued movement and/or the formation  50  may continue to subside even after abandonment, thereby fracturing typical abandonment plugs made from cement. 
       SUMMARY OF THE INVENTION 
       [0008]    Embodiments of the present invention generally relate to a sealant for forming durable plugs in wells and methods for completing or abandoning wells. In one embodiment, a method of completing or abandoning a wellbore includes mixing sealant; mixing cement; pumping the cement and sealant into the wellbore. The cement is above the sealant and the sealant cures to become viscoelastic or semisolid. 
         [0009]    In another embodiment, a plug for completing or abandoning a wellbore includes a top layer comprising Portland cement; and a middle or bottom layer comprising a viscoelastic or semisolid sealant. 
         [0010]    In another embodiment, a method for repairing damaged cement in a wellbore includes: forming an opening through a wall of a casing or liner cemented in the wellbore; and pumping sealant through the opening and into the damaged cement. The sealant cures to become viscoelastic or semisolid. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0011]    So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
           [0012]      FIG. 1A  is a cross section of a prior art sub-sea wellbore drilled and completed with a land-type completion.  FIG. 1B  is a cross section of the platform and completion after subsidence due to production from the formation. 
           [0013]      FIGS. 2A-F  illustrate a plug and abandon (P&amp;A) operation conducted on the subsided wellbore, according to one embodiment of the present invention.  FIG. 2A  illustrates killing the formation.  FIG. 2B  illustrates plugging the production casing bore by pumping in a multi-layer plug.  FIG. 2C  illustrates perforation of the production casing.  FIG. 2D  illustrates running of a workstring.  FIG. 2E  illustrates plugging the production casing annulus by pumping in a multi-layer plug.  FIG. 2F  illustrates plugging the production casing bore at or just below the mudline by setting a bridge plug and pumping in a multi-layer plug and cutting the completion. 
           [0014]      FIGS. 3A and 3B  illustrate operation of the sealant to heal a crack formed in cement due to subsidence. 
           [0015]      FIGS. 4A-D  illustrate a plug and abandon (P&amp;A) operation conducted on the subsided wellbore, according to another embodiment of the present invention. 
           [0016]      FIG. 4A  illustrates milling a section of the production casing.  FIG. 4B  illustrates plugging the formation by pumping in a multi-layer plug.  FIG. 4C  illustrates plugging the production casing annulus by pumping in a multi-layer plug.  FIG. 4D  illustrates plugging the production casing bore at or just below the mudline by setting a bridge plug and pumping in a multi-layer plug and cutting the completion. 
           [0017]      FIGS. 5A-D  illustrate drilling and completion of a wellbore, according to another embodiment of the present invention.  FIG. 5A  illustrates drilling the wellbore. 
           [0018]      FIG. 5B  illustrates a production casing assembly deployed into the wellbore.  FIG. 5C  illustrates pumping of a multi-layer plug.  FIG. 5D  illustrates the multi-layer plug pumped into the production casing annulus. 
       
    
    
     DETAILED DESCRIPTION 
       [0019]      FIGS. 2A-F  illustrate a plug and abandon (P&amp;A) operation conducted on the subsided wellbore  5 , according to one embodiment of the present invention.  FIG. 2A  illustrates killing the formation  50 . The formation  50  may be killed by pumping in a kill fluid  205 , such as seawater or mud. The production tubing  70  and packer  85  may then be removed from the wellbore  5 . 
         [0020]      FIG. 2B  illustrates plugging the production casing  55  bore by pumping in a multi-layer plug  250 . A workstring  210 , such as coiled tubing or drill pipe, may be deployed from the platform  30  to a depth proximate to the formation  50 . The workstring  210  may be deployed through a bore of the production casing  55 . The multi-layer plug  250  may be pumped through the workstring using one or more darts or plugs (not shown). The plug  250  may include a bottom layer  253  of cement, a middle layer  252  of sealant, and a top layer  251  of cement. The cement layers  251 ,  253  may be Portland cement. The bottom layer  253  may fill in the production perforations  65 . The plug  250  may be allowed to cure for a predetermined period of time, such as one hour, six hours, twelve hours, or one day. The workstring  210  may then be removed from the wellbore  5 . Alternatively, sand may be used as the bottom layer  253  or the bottom layer  253  may be omitted. 
         [0021]      FIG. 2C  illustrates perforation of the production casing  55 . A perforation gun  220  may be deployed from the platform  30  using a workstring  215 , such as wireline. The perforation gun  220  may be operated to fire projectiles (not shown) or exhaust from shaped charges into the production casing  55 , thereby forming perforations  225 . The perforations  225  may be located between a top of the production casing cement  60  and a shoe of the surface casing  40 . A depth of the top of the cement  60  may vary. Alternatively, a chemical cutter (not shown) or thermite torch may be used to form a window or remove a section of casing. Alternatively, a section mill may be deployed to remove a section of casing. 
         [0022]      FIG. 2D  illustrates running of the workstring  210 . The workstring  210  may be redeployed carrying a packer  230  as part of a bottom hole assembly (BHA). The packer  230  may be set just above the perforations  225 . 
         [0023]      FIG. 2E  illustrates plugging the production casing annulus by pumping in a multi-layer plug  255 . The multi-layer plug  255  may be pumped from the platform  30  through the workstring  210 , and into the production casing annulus through the perforations  225 . The multi-layer plug  255  may include the middle sealant layer  252  and the top cement layer  251 . Instead of a bottom layer  253 , the existing production casing cement  60  may be used for a bottom layer. Alternatively, a bottom layer may be pumped in. As shown, the plug  255  may extend from the top of the production casing cement  60  to the mudline  25 . Alternatively, the plug  255  may extend only to the surface casing  40  shoe. Alternatively, the plug  255  may be pumped in without using the workstring  210 . 
         [0024]      FIG. 2F  illustrates plugging the production casing bore at or just below the mudline  25  by setting a bridge plug  235  and pumping in a multi-layer plug  260  and cutting the completion  1 . Once the plug  255  has cured, the workstring  210  may be retrieved from the wellbore  5 . A bridge plug  235  may be set just below the mudline  25  using a workstring (not shown). The multi-layer plug  260  may then be pumped through the workstring to the bridge plug  235 . The multi-layer plug  260  may include the middle sealant layer  252  and the top cement layer  251 . The bridge plug  235  may serve as the bottom layer. Once the plug  260  has cured, the workstring may be retrieved from the completion  1  and the casings  10 ,  40 ,  55  may be cut using a casing cutter (not shown) deployed from the platform using a workstring. The casings  10 ,  40 ,  55  may be cut at or just below the mudline  25 , the upper portions salvaged, and the lower portions abandoned with the wellbore  5 . 
         [0025]      FIGS. 3A and 3B  illustrate operation of the sealant  252  to heal a crack  310  formed in cement  251  due to subsidence. 
         [0026]    The sealant  252  may be mixed on the platform  30  and pumped as a liquid or at least substantially a liquid. The cement  251 ,  253  may also be mixed on the platform  30 . The sealant  252  may then cure to become viscoelastic or semisolid. As discussed above, due to subsidence, the cement layer  251  may become damaged  310  after the plug has been pumped and has cured. As formation pressure  305  pushes on the sealant  252 , the sealant may viscously flow or deform into the crack  310  until frictional resistance or material stiffness equalizes against the fluid pressure, thereby plugging or healing the cement. The sealant  252  may repeatedly heal the cement  251  over time as the sealant may not degrade over time. The plugs  250 ,  255 ,  260  may then reliably contain the formation  50  even in the unstable subsiding completion  1 . 
         [0027]    Additionally or alternatively, the cured sealant  252  may function as a seal independent from the cement  251 ,  253  and the cement may serve as a structural retainer to prevent extrusion of the sealant akin to a seal stack used in valves, packers, and/or plugs. Should the sealant lose engagement with the wellbore and/or casing due to excessive stress or strain, the sealant may re-engage the casing and/or wellbore after removal of the stress or strain due to adhesive properties of the sealant. 
         [0028]    In liquid form, the sealant  252  may include a resin, such as epoxide, a reactive diluent, and a hardener, such as polyamine, so that the sealant cures to form a polymer, such as epoxy. Relative to the resin as one-hundred, the diluent may range from a zero to one-hundred weight ratio, such as ten. The hardener amounts may range from one to one hundred, such as thirty-five. The following working example sealants have been manufactured and tested (ratios by weight): one hundred: thirty: fifteen and one hundred: forty: fifteen—epoxide resin: diluent: hardener. 
         [0029]    The sealant  252  may further include solids, such as particulates or fibers, such as barite, silica flour, silica sand, calcium carbonate, manganese dioxide, ferrous oxide, various ground plastics, hollow glass or ceramic microbeads, and various ground rubber. The solids may serve as a weighting agent to increase the density of the sealant, reinforcement to increase mechanical resilience of the sealant, and/or as a bridging agent to prevent loss of sealant into a permeable or fractured formation or cement bottom. 
         [0030]    Alternatively, in liquid form, the sealant may include a polymer solution and a crosslinking reagent so that the sealant cures to from a cross-linked polymer gel. The gel may be stiff, viscoelastic, and adhesive. The polymer may be polyacrylamide, polyvinyl alcohol, polyvinyl acetate, guar, or cellulose. The polymer may be synthetic or natural. The crosslinking reagent may be a di or trivalent metal compound, such as chromium carboxylate, zirconium oxychloride, sodium borate, other transition metal salts, aldehydes (such as phenylformadehyde and gluteraldehyde). The diluent may be water. The polymer may range from ten to one hundred lb/barrel, such as seventeen and a half, and the crosslinking reagent can range from one to ten lb/barrel, such as five, for one barrel water. 
         [0031]    Alternatively, the sealant  252  may be a composite of the epoxy and the cross-linked polymer gel. The following working example sealant has been manufactured and tested: one to one by volume of a) (ratios by weight): one hundred: ten: twenty-five—epoxide resin: diluent: hardener; and b) eleven lb polyacrylamide and one point two lb crosslinking reagent per bbl of water. 
         [0032]    Alternatively, the sealant may be a mud. The mud may be made by mixing oil, such as diesel, with bentonite to form a slurry. The bentonite may be added to substantially increase a density of the slurry, such as to eleven and a half lb/gal. Water or water based mud may then be emulsified with the slurry, thereby allowing the bentonite to hydrate and substantially increasing the gel strength of the mud. The water or water based mud may be added so that the resulting mixture is water or oil based. 
         [0033]    Alternatively, the sealant may be made by mixing a calcium chloride solution, such as ten percent concentration, and a sodium silicate solution, such as forty percent concentration. The mixture may cure to form a silicate plug. 
         [0034]      FIGS. 4A-D  illustrate a plug and abandon (P&amp;A) operation conducted on the subsided wellbore  5 , according to another embodiment of the present invention. 
         [0035]      FIG. 4A  illustrates milling a section of the production casing  55 . The formation  50  may be killed by pumping in a kill fluid (see  FIG. 2A ), such as seawater or mud. The production tubing  70  and packer  85  may be removed from the wellbore  5 . The workstring  210  may be deployed carrying a section mill  405  as part of a bottom hole assembly (BHA). The workstring  210  may be deployed from the platform  30  through the production casing bore. 
         [0036]    The section mill  405  may include a housing, a piston, a plurality of arms, a piston biasing member, such as a spring. The housing may be tubular and include one or more sections connected by threaded couplings. The upper section may have a threaded coupling, such as a pin, formed at a longitudinal end thereof for connection to the workstring  210 . Each arm may be pivoted to the housing for rotation relative to the housing between a retracted position and an extended position. An inner surface of each arm may form a cam. The housing may have a pocket formed through a wall thereof for each arm. Each arm may extend through a respective pocket in the extended position. An outer surface of each arm may form one or more blades. Cutters may be bonded into respective recesses formed along each blade. The cutters may be made from a hard material, such as a ceramic or cermet, such as tungsten carbide. The cutters may be may be pressed or threaded into the recesses. Alternatively, the cutters may be bonded into the recesses, such as by brazing, welding, soldering, or using an adhesive. 
         [0037]    The piston may be tubular, disposed in a bore of the housing, and include a shoulder. The piston spring may be disposed between the piston shoulder and a top of one of the housing sections, thereby longitudinally biasing the piston away from the arms. The piston may have a nozzle. To extend the arms, drilling fluid may be pumped through the workstring  210  to the housing bore. The drilling fluid may then continue through the nozzle. Flow restriction through the nozzle may cause pressure loss so that a greater pressure is exerted on the nozzle than on a cammed surface of the piston, thereby longitudinally moving the piston downward toward the arms and against the piston spring. As the piston moves downward, the cammed surface engages the cam surface of each arm, thereby rotating the arms about the pivot to the extended position. The piston may have a flow port formed through a wall thereof corresponding to each arm. The ports may be closed by one of the housing sections in the retracted position and may be in fluid communication with the pocket in the extended position, thereby spraying drilling fluid through the pocket and washing the arms, thereby lubricating the arms and carrying cuttings from the arms. 
         [0038]    Once deployed, the section mill  405  may be operated to remove a section of the production casing  55  at a depth corresponding to the production casing cement  60 , thereby forming a window  425  providing fluid communication between a bore of the production casing and the open production casing annulus above the cement  60 . The section mill  405  may continue until reaching the formation  50  and leave a portion of the production casing  60  lining the formation  50 . Alternatively, the section mill  405  may continue to the production casing shoe. 
         [0039]      FIG. 4B  illustrates plugging the formation  50  by pumping in a multi-layer plug  450 . Once the production casing has been milled, the workstring  210  may be retrieved to the platform  30 , the section mill removed, and the workstring may be redeployed into the wellbore. The multi-layer plug  450  may be pumped through the workstring  210  using one or more darts or plugs (not shown). The plug  450  may include a bottom layer  253  of cement, a middle layer  252  of sealant, and a top layer  251  of cement. The bottom layer  253  may fill in the production perforations  65 . The plug  450  may be allowed to cure for a predetermined period of time, such as one hour, six hours, twelve hours, or one day. Alternatively, sand may be used as the bottom layer  253  or the bottom layer  253  may be omitted. 
         [0040]      FIG. 4C  illustrates plugging the production casing annulus by pumping in a multi-layer plug  455 . Once the plug  450  has cured, the workstring  210  maybe moved above the window  425  and the packer  230  set. The multi-layer plug  455  may be pumped from the platform  30  through the workstring  210 , and into the production casing annulus through the window  425 . The multi-layer plug  455  may include the middle sealant layer  252  and the top cement layer  251 . Instead of a bottom layer  253 , the existing production casing cement  60  may be used for a bottom layer. Alternatively, a bottom layer may be pumped in. As shown, the plug  455  may extend from the top of the production casing cement  60  to the mudline  25 . Alternatively, the plug  455  may extend only to the surface casing  40  shoe. Alternatively, the plug  455  may be pumped in without using the workstring  210 . A residual layer  452  of sealant may be left in the production casing bore. 
         [0041]      FIG. 4D  illustrates plugging the production casing bore at or just below the mudline  25  by setting a bridge plug  235  and pumping in a multi-layer plug  460  and cutting the completion  1 . Once the plug  455  has cured, the workstring  210  may be retrieved from the wellbore  5 . The bridge plug  235  may be set just below the mudline  25  using a workstring (not shown). The multi-layer plug  460  may then be pumped through the workstring to the bridge plug  235 . The multi-layer plug  460  may include the middle sealant layer  252  and the top cement layer  251 . The bridge plug  235  may serve as the bottom layer. Once the plug  460  has cured, the workstring may be retrieved from the completion  1  and the casings  10 ,  40 ,  55  may be cut using a casing cutter (not shown) deployed from the platform using a workstring. The casings  10 ,  40 ,  55  may be cut at or just below the mudline  25 , the upper portions salvaged, and the lower portions abandoned with the wellbore  5 . 
         [0042]    Although as shown similar in length, the sealant layer  252  may actually have a length less than or substantially less than the top cement layer  251 , such as less than or equal to one-half, one-third, one-fourth, or one-fifth a length of the cement layer  251 . The relative length may be controlled by volume of the sealant  252  relative to volume of the cement  251  pumped in the wellbore. 
         [0043]    Alternatively, the multi-layer plug may be used to seal a bore and/or annulus of a production liner (not shown) which may have been used to complete the wellbore instead of the production casing  55 . 
         [0044]    Alternatively, the sealant  252  may be injected into the existing production casing cement  60 . This alternative may be especially useful if the top of the production casing cement extends upward proximate to or past the surface casing shoe. 
         [0045]    Alternatively, the sealant or multi-layer plugs may be used to repair leaking casing annuluses so that the wellbore  5  may be placed back into production. Alternatively, the sealant may be used to repair casing annuluses of non-subsiding formations so that the wellbore may be placed back into formation. 
         [0046]    Alternatively, the sealant or multi-layer plug may be installed in the surface casing and/or conductor casing annuluses. 
         [0047]    Alternatively, the sealant or multi-layer plug may be used to plug and abandon non-subsiding wellbores, such as wellbores to hydrocarbon-bearing formations, aquifers (subsiding or non-subsiding), or geothermal wellbores. Even in non-subsiding wellbores, the cement may be subject to cyclic stresses and strains from temperature, pressure, seismic activity, or tectonic activity leading to failure of the cement. 
         [0048]    Additionally, the sealant or multi-layer plug may be especially useful for plugging and abandoning or repairing wellbores to natural gas formations or wellbores traversing nuisance gas formations, whether subsiding or not, where even minor damage or degradation to the cement may result in leakage. 
         [0049]      FIGS. 5A-D  illustrate drilling and completion of a wellbore  500 , according to another embodiment of the present invention.  FIG. 5A  illustrates drilling the wellbore  500 . As shown, the conductor  10  and surface  40  casings have been cemented  35 ,  45  in the place. A drilling assembly may be run-into the wellbore  500  from a drilling platform. The drilling assembly may include a drill string  505  and a bottom hole assembly (BHA). The drill string  505  may be made from joints of drill pipe threaded together or coiled tubing. The BHA may include a drill bit  510 . The BHA may further include a mud motor (not shown), a measuring-while-drilling (MWD) sub (not shown), a logging-while-drilling (LWD) sub, and/or a steering tool (not shown). The drill bit  510  may be rotated by the mud motor and/or at the surface by a rotary table or top drive. Drilling fluid  515   f , such as mud, may be injected through the drill string  505 . The drilling fluid  515   f  may exit into the annulus via ports formed through the drill bit  510  and carry cuttings (collectively returns  515   r ) from the drill bit to the platform. The cuttings may be separated from the drilling fluid at the platform and the drilling fluid  515   f  recycled. Once the formation  50  is reached, the drilling assembly may be retrieved from the wellbore  500  to the platform. 
         [0050]      FIG. 5B  illustrates a production casing assembly deployed into the wellbore  500 . The production casing assembly may include the production casing string  55  and a BHA. The casing string  55  may include joints of casing threaded together. Centralizers  558  may be spaced along the casing string  55  and/or the BHA. The BHA may include a casing shoe  556  and a float collar  557 . The float collar  557  may include a check valve, such as a flapper, and a shoulder for receiving a wiper plug  520 . After the casing assembly has been run-into the wellbore  500 , a cementing head (not shown) may be connected to the casing string  55  at the platform. The cementing head may include valves and one or more wiper plugs, such as a top plug  525  and a bottom plug  520 . The cementing head may then be connected to a cement pump (not shown). Drilling fluid  515   f  may then be circulated to clean the wellbore (not shown). 
         [0051]      FIG. 5C  illustrates pumping of a multi-layer plug  550 . The bottom plug  520  may be released from the cementing head. A preflush or spacer (not shown) may be pumped through the cementing head behind the bottom plug  520 . The top cement layer  251  may then be pumped behind the spacer. The sealant  252  may then be pumped behind the top cement layer  251 . The bottom layer  253  of cement may then be pumped behind the sealant  252 . Once the bottom layer  253  has been pumped, the top plug  525  may be released from the cementing head. A propellant  530 , such as mud, may then be pumped behind the top plug  525  thereby propelling the multi-layer plug  550  through the production casing  55 . The propellant  530  may be lighter than the drilling fluid  515   f  so as to maintain the casing  55  in compression as the multi-layer plug  550  cures. The casing  55  may be rotated and/or reciprocated as the multi-layer plug  550  is being pumped. 
         [0052]      FIG. 5D  illustrates the multi-layer plug  550  pumped into the production casing annulus. Once the bottom plug  520  reaches the float collar  557 , a diaphragm in the bottom plug  520  may rupture. The spacer and multi-layer plug  550  may then flow through the bottom plug  520  and into the annulus, thereby displacing the drilling fluid present there. The top plug  525  may continue through the production casing  55  until reaching the bottom plug  520 , thereby providing a pressure increase detectable at the drilling platform. The cement pump may then be shut down and pressure released from the cementing head. The check valve in the float collar  557  may then close, thereby preventing back-flow of the multi-layer plug  550  from the annulus. Once the multi-layer plug  550  cures, the float collar  557 , guide shoe  556 , and any residual cement may be drilled out (not shown) and the casing  55  perforated for production. 
         [0053]    Alternatively, two or more multi-layer plugs may be pumped in the production casing annulus using a two or more stage cementing operation. One or more stage valves (not shown) may be disposed along the casing, such as at a mid-point of the casing or above a weak formation. The stage valve may be operated by additional wiper plugs configured to engage and open or close the stage valve. 
         [0054]    Alternatively, the wellbore may be completed with production liner (not shown) instead of production casing and the multi-layer plug may be used to seal the liner annulus. 
         [0055]    Additionally, the conductor and/or surface casings annuluses may be sealed using the multi-layer plug instead of cement. 
         [0056]    Alternatively, the multi-layer plug may be used in primary or secondary cementing operations of land-based wellbores and/or sub-sea type completions. 
         [0057]    While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.