Patent Publication Number: US-9404350-B2

Title: Flow-activated flow control device and method of using same in wellbores

Description:
BACKGROUND 
     1. Field of the Disclosure 
     This disclosure relates generally to apparatus and methods for completing a wellbore for the production of hydrocarbons from subsurface formations, including fracturing selected formation zones in a wellbore, sand packing and flooding a formation with a fluid. 
     2. Background of the Art 
     Wellbores are drilled in subsurface formations for the production of hydrocarbons (oil and gas). Modern wells can extend to great well depths, often more than 1500 meters (about 15,000 ft.). Hydrocarbons are trapped in various traps in the subsurface formations at different depths. Such sections of the formation are referred to as reservoirs or hydrocarbon-bearing formations or zones. Some formations have high mobility, which is a measure of the ease of the hydrocarbons flow from the reservoir into a well drilled through the reservoir under natural downhole pressures. Some formations have low mobility and the hydrocarbons trapped therein are unable to move with ease from the reservoir into the well. Stimulation methods are typically employed to improve the mobility of the hydrocarbons through the reservoirs. One such method, referred to as fracturing (also referred to as “fracing” or “fracking”), is often utilized to create cracks in the reservoir to enable the fluid from the formation (formation fluid) to flow from the reservoir into the wellbore. To fracture multiple zones, an assembly containing an outer string with an inner string therein is run in or deployed in the wellbore. The outer string is conveyed in the wellbore with a tubing attached to its upper end and it includes various devices corresponding to each zone to be fractured for supplying a fluid with proppant to each such zone. The inner string includes devices attached to a tubing to operate certain devices in the outer string and facilitate fracturing and/or other well treatment operations. For selectively treating a zone in a multi-zone wellbore, it is desirable to have an inner sting that can be selectively set corresponding to any zone in a multi-zone well and perform a well operation at such selected zone. Once a zone has been treated, the wellbore is filled with the treatment fluid, which may include a base fluid, such as water, proppant, such as sand or synthetic sand-like particles and an additive, such as guar. A valve, such as check valve, is often used to provide a fluid flow path from an annulus between an outer string and an inner string used for the treatment operation to the inner string so that a fresh fluid may be supplied to the annulus to remove the treatment fluid from the wellbore. This process is generally referred to a reverse circulation. 
     The disclosure herein provides apparatus and methods for enabling reverse circulation of fluid. 
     SUMMARY 
     In one aspect, an apparatus for use in a wellbore is disclosed that in one non-limiting embodiment includes A flow control device for use in a wellbore is disclosed that in one non-limiting embodiment may include a main flow passage and a weep hole, wherein the main flow passage closes when a fluid is supplied to a first end of the valve that exceeds a selected rate and opens when the fluid supplied is below the selected rate and wherein the weep hole continues to allow the fluid therethrough. 
     Examples of the more important features of a well treatment system and methods that have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features that will be described hereinafter and which will form the subject of the claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed understanding of the apparatus and methods disclosed herein, reference should be made to the accompanying drawings and the detailed description thereof, wherein like elements are generally given same numerals and wherein: 
         FIG. 1  shows an exemplary cased hole multi-zone wellbore that has a service assembly deployed therein that includes an outer string and an inner string for performing a treatment operation, according to one non-limiting embodiment of the present; 
         FIG. 2  shows position of the inner string for reverse circulation to remove treatment fluid from the wellbore using a flow control device made according to one non-limiting embodiment; 
         FIG. 3  shows a non-limiting embodiment of a flow control device (also referred to herein as the “valve” or “reversing valve”) in an open position that may be utilized for, among other things, reverse circulation; and 
         FIG. 4  shows the device of  FIG. 3  in a closed position to enable reverse circulation. 
     
    
    
     DETAILED DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a line diagram of a section of a wellbore system  100  that is shown to include a wellbore  101  formed in formation  102  for performing a treatment operation therein, such as fracturing the formation (also referred to herein as fracing or fracking), gravel packing, flooding, etc. The wellbore  101  is lined with a casing  104 , such as a string of jointed metal pipes sections, known in the art. The space or annulus  103  between the casing  104  and the wellbore  101  is filled with cement  106 . The particular embodiment of  FIG. 1  is shown for selectively fracking one or more zones in any selected or desired sequence or order. However, well bore  101  may be configured to perform other treatment or service operations, including, but not limited to, gravel packing and flooding a selected zone to move fluid in the zone toward a production well (not shown). The formation  102  is shown to include multiple zones Z1-Zn which may be fractured or treated for the production of hydrocarbons therefrom. Each such zone is shown to include perforations that extend from the casing  104 , through cement  106  and to a certain depth in the formation  102 . In  FIG. 1 , Zone Z1 is shown to include perforations  108   a , Zone Z2 perforations  108   b , and Zone Zn perforations  108   n . The perforations in each zone provide fluid passages for fracturing each such zone. The perforations also provide fluid passages for formation fluid  150  to flow from the formation  102  to the inside  104   a  of the casing  104 . The wellbore  101  includes a sump packer  109  proximate to the bottom  101   a  of the wellbore  101 . The sump packer  109  is typically deployed after installing casing  104  and cementing the wellbore  101 . The sump packer  109  is tested to a pressure rating before treating the well, such as fracturing and packing, which pressure rating may be below the expected pressures in the wellbore  101  after a zone has been treated and isolated. 
     After casing, cementing, perforating and sump packer deployment, the wellbore  101  is ready for treatment operations, such as fracturing and gravel packing of each of the production zones Z1-Zn. Although system  100  is described in reference to fracturing and sand packing production zones, the apparatus and methods described herein or with obvious modifications may also be utilized for other well treatment operations, including, but not limited to, gravel packing and water flooding. The formation  102  has a fluid  150  therein at formation pressure (P1) and the wellbore  101  is filled with a fluid  152 , such as completion fluid, which fluid provides hydrostatic pressure (P2) inside the wellbore  101 . The hydrostatic pressure P2 is greater than the formation pressure P1 along the depth of the wellbore  101 , which prevents flow of the fluid  150  from the formation  102  into the casing  104  and prevents blow-outs. 
     Still referring to  FIG. 1 , to fracture (treat) one or more zones Z1-Zn, a system assembly  110  is run inside the casing  104  by a conveying member  112 , which may be a tubular made of jointed pipe section, known in the art. In one non-limiting embodiment, the system assembly  110  includes an outer string  120  and an inner string  160  placed inside the outer string  120 . The outer string  120  includes a pipe  122  and a number of devices associated with each of the zones Z1-Zn for performing treatment operations described in detail below. In one non-limiting embodiment, the outer string  120  includes a sealing member  123   a , outside and proximate to a bottom end  123  of the outer string  120 . The outer string  120  further includes a lower packer  124   a , an upper packer  124   m  and intermediate packers  124   b ,  124   c , etc. The lower packer  124   a  isolates the sump packer  109  from hydraulic pressure exerted in the outer string  120  during fracturing and sand packing of the production zones Z1-Zn. In this case the number of packers in the outer string  120  is one more than the number of zones Z1-Zn. In some cases, the lower packer  109 , however, may be utilized as the lower packer  124   a . In one non-limiting embodiment, the intermediate packers  124   b ,  124   c , etc. may be configured to be independently deployed in any desired order so as to fracture and pack any of the zones Z1-Zn in any desired order. In another embodiment, some or all the packers may be configured to be deployed at the same time or substantially at the same time. In one aspect, packers  124   a - 124   m  may be hydraulically set or deployed packers. In another aspect, packers  124   a - 124   m  may be mechanically set or deployed. 
     Still referring to  FIG. 1 , the outer string  120  further includes a screen adjacent to each zone. For example, screen S1 is shown placed adjacent to zone Z1, screen S2 adjacent zone Z2 and screen Sn adjacent to zone Zn. The lower packer  124   a  and intermediate packer  124   b , when deployed, will isolate zone Z1 from the remaining zones: packers  124   b  and  124   c  will isolate zone Z2 and packers  124   m - 1  and  124   m  will isolate zone Zn. In one non-limiting embodiment, each packer has an associated packer activation device, such as a valve, that allows selective deployment of its corresponding packer in any desired order. In  FIG. 1 , a packer activation device  125   a  is associated with the lower packer  124   a , device  125   b  with intermediate packer  124   b , device  125   c  with intermediate packer  124   c  and device  125   m  with the upper packer  124   m . In one aspect, packers  124   a - 224   m  may be hydraulically-activated packers. In one aspect, the lower packer  124   a  and the upper packer  124   m  may be activated at the same or substantially the same time when a fluid under pressure is supplied to the pipe  112 . In one non-limiting embodiment, the activation devices associated with the intermediate packers  124   b ,  124   c , etc. may include a balanced piston device that remains under a balanced pressure condition (also referred to herein as the “inactive mode”) to prevent a pressure differential between the inside  120   a  and outside  120   b  of the outer sting  120  to activate the packer. When a packer activation device is activated by an external mechanism, it allows pressure of the fluid in the outer string  120  to cause its associated packer to be set or deployed. 
     Still referring to  FIG. 1 , in one non-limiting embodiment, each of the screens S1-Sn may be made by serially connecting two or more screen sections with interconnecting connection members to form a screen of a desired length, wherein the interconnections provide axial fluid communication between the adjacent screen sections. For example, screen Sn is shown to include screen sections  126  interconnected by connections  128 . The connections  128  may include a flow communication device, such as a sliding sleeve valve or sleeve  132   a , to provide flow of the fluid  150  from the formation  102  into the outer string  120 . Similarly, other screens may also include several screen sections and corresponding connection devices. The connections  128  allow axial flow between the screen sections  126 . The outer string  120  also includes, for each zone, a flow control device, referred to as a slurry outlet or a gravel exit, such as a sliding sleeve valve or another valve, uphole or above its corresponding screen to provide fluid communication between the inside  120   a  of the outer string  120  and each of the zones Z1-Zn. As shown in  FIG. 1 , a slurry outlet  140   a  is provided for zone Z1 between screen S1 and its intermediate packer  124   b , device  140   b  for zone Z2 and device  140   n  for zone Zn. In  FIG. 1 , device  140   a  is shown open while devices  140   b - 140   n  are shown in the closed position so no fluid can flow from the inside  120   a  of the outer string  120  to any of the zones Z2-Zn, until opened downhole. 
     In yet another aspect, the outer string  120  may further include an inverted seal below and another above each inflow control device for performing a treatment operation. In  FIG. 1 , inverted seals  144   a  and  144   b  are shown associated with slurry outlet  140   a , inverted seals  146   a  and  146   b  with the slurry outlet  140   b  and inverted seals  148   a  and  148   b  with slurry outlet  140   n . In one aspect, the inverted seals  144   a ,  144   b ,  146   a ,  146   b ,  148   a  and  148   b  may be configured so that they can be pushed inside  120  of the outer string  120  or removed from the inside of the outer string  120  after completion of the treatment operations or during the deployment of a production string (not shown) for the production of hydrocarbons from wellbore  101 . Pushing inverted seals inside  120   a  the outer string  120  or removing such seals from the inside  120   a  of the outer string  120  provides increased inside diameter of the outer string  120  for the installation of a production string for the production of hydrocarbons from zones Z1-Zn compared to an outer string having seals extending inside  120   a  the outer string  120 . Seals  144   a ,  144   b ,  146   a ,  146   b ,  148   a  and  148   b  may, however, be placed on the outside of the inner string instead on the inside of the outer string. In one non-limiting embodiment, the outer string  120  also includes a zone indicating profile or locating profile  190  (profile  190   a  for zone Z1, profile  190   b  for zone Z2 and profile  190   n  for zone Zn) for each zone and a corresponding set down profile  192  ( 192   a  for zone Z1,  192   b  for zone Z2 and  192   n  for zone Zn). 
     Still referring to  FIG. 1 , the inner string  160  (also referred to herein as the service string) may be a metallic tubular member  161  that in one embodiment includes an opening shifting tool  162  and a closing shifting tool  164  along the lower end  161   a  of the inner string  160 . The inner string  160  further may include a reversing valve  166  that enables the removal of treatment fluid from the wellbore after treating each zone, and an up-strain locating tool  168  for locating a location uphole of the set down locations Such as locations  194  for zone Z1,  194   b  for zone and  194   n  for Zone Zn) when the inner string is pulled uphole, and a set down tool or set down locating tool or set  170 . In one aspect, the set down tool  170  may be configured to locate each zone and then set down of the inner string at each such location for performing a treatment operation. The inner string  160  includes a plug  172  above the set down locating tool  170 , which prevents fluid communication between the space  172   a  above the plug  172  and the space  172   b  below the plug  172 . The inner string  160  further includes a crossover tool  174  (also referred to herein as the “frac port”) for providing a fluid path  175  between the inner string  160  and the outer string  120 . In one aspect, the frac port  174  also includes flow passages  176  therethrough, which passages may be gun-drilled through the frac port  174  to provide fluid communication between space  172   a  and  172   b . In one embodiment, the passages  176  are sufficiently narrow so that that there is relatively small amount of fluid flow through such passages. The passages  176 , however, are sufficient to provide fluid flow and thus pressure communication between spaces  172   a  and  172   b.    
     To perform a treatment operation in a particular zone, for example zone Z1, lower packer  124   a  and upper packer  124   m  are set or deployed. Setting the upper  124   m  and lower packer  124   a  anchors the outer string  120  inside the casing  104 . The production zone Z1 is then isolated from all the other zones. To isolate zone Z1 from the remaining zones Z2-Zn, the inner string  160  is manipulated so as to cause the opening shifting tool  162  to open a monitoring valve  133  in screen S1. The inner string  160  is then manipulated (moved up and/or down) inside the outer string  120  so that the set down tool  170  locates the locating or indicating profile  190   a . The set down tool  170  is then manipulated to cause it to set down in the set down profile  192   a . When the set down tool  170  is set down at location  192   a , the frac port  174  is adjacent to the slurry outlet  140   a . The pipe  161  of the inner string  160  has a sealing section that comes in contact with the Inverted seals  144   a  and  144   b , thereby isolating or sealing section  165  between the seals  144   a  and  144   b  that contains the slurry outlet  140   a  and the frac port  174  adjacent to slurry outlet  140   a , while providing fluid communication between the inner string and the slurry outlet  140   a . Sealing section  165  from the section  169  allows the lower port  127   a  of the packer setting device  125   b  to be exposed to the pressure in the section  165  while the upper port  127   b  is exposed to pressure in section  169 . The packer  124   b  is then set to isolate zone Z1. Once the packer  124   b  has been set, frac sleeve  140   a  is opened, as shown in  FIG. 1 , to supply slurry or another fluid to zone Z1 to perform a fracturing or a treatment operation. Once zone Z1 has been treated, the treatment fluid in the wellbore is removed by closing the reversing valve  166  to provide a fluid path from the surface in the space (or annulus) between the outer string  120  and the inner string  160  so that a fluid supplied into such annulus at the surface will cause the treatment fluid to move to the surface, which process is referred to as reverse circulation. After reverse circulation, the inner string  160  may then be moved to set down device  170  at another zone for treatment operations. A non-limiting embodiment of a flow device for reverse circulation is described below in reference to  FIGS. 3-4 . 
       FIG. 2  shows the position of the inner string  160  in the outer string with the reversing valve  160  closed in order to perform a reverse circulation operation. To perform reverse circulation, the inner string is moved to cause the up-strain locating tool  168  to locate and engage with the up-strain locating profile  194   a . In this position, the frac port seals with seal  146   a  and creates a fluid passage between annulus  280  and the inner string section  282  above the device  172 . The flow device  166  is then closed, as described in detail in reference to  FIG. 4 , to prevent flow of the fluid from section  282  section  284  below the flow device  166 . A fluid supplied into the annulus  280  will flow into section  282  via frac port opening  275  to move the fluid in section  282  to the surface, as shown by arrows  250 . 
       FIG. 3  shows a non-limiting embodiment of a flow control device  300  (also referred to herein as the “valve” or “reversing valve” for ease of explanation and not as a limitation) that may be hydraulically-activated to control flow of a fluid therethrough and which device may be utilized in wellbore operations, including, but not limited to, reverse circulation of a fluid in well treatment operations such as fracing, sand packing and gravel packing. Device  300  in  FIG. 3  is shown open or in an open position so that fluid  301  in pipe  302 , uphole or upstream location  303   a  of the device  300 , may flow to a downhole or downstream location  303   b  of the device  300 . In one aspect, the device  300  includes a valve housing  320  connected to a top sub  312 , such as by a threaded connection  314 . The top sub  312  has a flow through bore  313 . The valve housing  320  includes flow passage or flow area  325  and contains a seal face or seal shoulder  324  and houses a biasing member, such as spring  326 , proximate to an end  328  opposite of the seal shoulder  324 . The lower end  326   a  of the spring  326  abuts against a spring retaining member  329  attached to the valve housing  320 , such as by a threaded connection  327 . 
     Still referring to  FIG. 3 , the flow control device  300  has a movable valve mechanism or unit  330  that moves inside the valve housing  320  to close the flow of a fluid  301  through the device  300  in response to the flow, and thus the pressure, of the fluid  301 . The valve mechanism  330  that includes an axially-movable valve body  340  that moves axially in the top sub  312  and the valve housing  320  in response to a pressure applied thereto by the fluid  301  supplied to the tubing  302  attached to the top sub  312 . In one aspect, the valve body  340  is configured to axially move inside the valve housing  320 . The upper or uphole end of the valve body  340  includes one or more flow passages, such as passages  352   a  and  352   b  (also referred to herein as main passages) and a weep hole  374 . The valve body  340  has a bore  341  therein (a flow passage) that receives the fluid  301  from the flow passages  352   a ,  352   b  and the weep hole  374 . The passage  341  allows such received fluid to flow downhole through the device  300 . The valve body  340  also may include a seal member  342  that protrudes radially outward therefrom and moves inside the flow area  325  in the valve housing  320 . The seal member  342  has an outer profile or seal face  344  that matches the inside profile or seal of the shoulder  324  in the valve housing  320 . The valve body  340  further includes a spring acting member  348  that protrudes radially outward into the valve housing  320  and acts on the upper end  326   b  of the spring  326 . Flow through passages, such as one or more nozzles  350   a  and  350   b  allow flow of fluid  301  received by the pipe  302  to flow into the flow area  325  inside the valve housing  320 . The fluid from the area  325  flows into the bore  341  of the valve body  340  via passages  372  in the valve body  340 , as shown by arrows  370  and  380 . A relatively small passage  374  (also referred to as the “weep hole”) is provided in the movable member  340  to allow uninhibited flow of a relatively small amount of fluid  301  from the pipe  302  into the bore  341  of the valve body  340 . 
     Still referring to  FIG. 3 , the valve unit  330  that includes the valve body  340 , flow passages  350   a  and  350   b  and weep hole  374  are connected or are formed in such a manner that these elements or members axially moves in response the flow of the fluid  301  applied to the uphole end of the valve unit  330 . When fluid  301  is supplied to the pipe  302 , it acts on the uphole end of the valve unit  330 , wherein the nozzles  350   a  and  350   b  and the weep hole  374  allow the fluid  301  to flow from the pipe  302  into the bore  341  of the valve body  340  via the flow area  325  and passages  372  as shown by arrows  380 . The spring  326  acting on the valve body  340  prevents the valve body  340  and, thus, the valve unit  330 , from moving downward. When the flow rate of the fluid  301  is increased, the pressure applied by the fluid  301  on the valve unit  330 , and thus the valve body  340 , increases. When the flow rate exceeds a threshold value (also referred to as the selected rate or predetermined rate), the pressure applied on the valve unit  330  and thus the valve body  340 , creates sufficient pressure drop or differential across the nozzles  350   a  and  350   b  to cause the member valve unit  330  and thus the valve body  340  and the seal face  342  to move downward to cause the seal surface  344  to abut against the seal surface  327  of the shoulder  324 . This closes the fluid passage from the flow area  325  to the passages  372  in the valve body  340 , thereby preventing flow of the fluid  301  from the tubing  302  through the flow passages  350   a  and  350   b . A relatively small amount of the fluid  301 , however, continues to flow from the tubing  302  into the bore  341  via the weep hole  374 . The weep hole equalizes the pressure across the flow passages  352   a  and  352   b , which prevents creation of a vacuum condition (also referred to as swabbing) inside the valve body  340  as described in reference to  FIG. 4 . As long as the pressure applied by the fluid  301  remains above the threshold value, the valve  700  remains closed. 
       FIG. 4  shows the device  300  in the closed position. As described above in reference to  FIG. 3 , when the pressure of the fluid  301  is above a threshold or predetermined value, the valve unit  330  that includes the valve body  340 , flow passages  350   a ,  350   b  and the weep hole  374 , moves downward until the seal surface  344  of valve closing member  342  abuts against the shoulder  324 , as shown in  FIG. 4 . The spring  326  is correspondingly moved by the member  348  downward, which compresses the spring, as shown by the compressed state  426 . As long as the pressure applied by the fluid  301  remains above the threshold value, the valve closing member  342  will remain in sealing contact with the shoulder  324 , causing the device to remain closed and such that no, or substantially no, fluid will pass via the flow through passages  350   a  and  350   b . A relatively predetermined small amount of fluid continues to flow through the weep hole  374 , which prevents creation of a vacuum condition in the valve body  340  (i.e. prevents swabbing). When the flow of the fluid  301  is reduced below a certain rate, the pressure differential across the uphole side and the valve body decreases to a value that is insufficient to hold the spring in its compressed state, at which point the valve body  340  moves uphole, which moves the valve closing member  342  uphole, thereby opening the passage  325 , which allows the fluid  301  to flow from the pipe  302  to the valve body  340  as described in reference to  FIG. 3  above. The sizes of the flow passages  350   a  and  350   b  are configured to allow sufficient flow of the fluid  301  therethrough when the device  300  is open to avoid creating pressure differential across the uphole side  303   a  and the downhole side  303   b  above a desired or selected value until the flow rate of the fluid  301  exceeds a threshold value. The size of the weep hole  374  is configured so that the flow of the fluid  301  therethrough does not reduce the pressure differential below the desired value when the device is closed as shown in  FIG. 3 . The flow of the fluid  301 , however, is sufficient such that when the valve opens suddenly or rapidly, it will not cause a vacuum condition to occur in the valve body  340 . Also, when the flow device  300  moves in the wellbore with the valve closed (while reversing), the weep hole  374  allows transferring fluid  301  across the valve, which prevents the service tool from swabbing. During well operations, the hydrostatic pressure in the wellbore (due to the weight of the fluid column in the wellbore) is greater that the formation pressure. If swabbing occurs, in some cases the pressure in the wellbore below the device  300  may drop below the formation pressure, causing fluid from the formation to flow into the wellbore. In one aspect, the weep hole  374  may be configured so that pulling the inner string upward will not allow the pressure in the wellbore to drop below the formation pressure. 
     Flow control device  300 , thus, in one aspect, may be a flow device that includes a weeping flow passage (a weeping check valve) that closes when a certain or selected amount of pressure differential is created across the device. The flow control device  300  closes when fluid flow applied thereto is above a certain rate, which causes a pressure drop across the flow control device  300  exceeding a predetermined or selected pressure value. The flow control device  300 , however, remains open when the service string is manipulated to perform one or more operations in a wellbore, such as running the service string into the wellbore, setting the service string to frac a particular zone, lifting the service string, etc. The weep hole or flow passage  374  prevents swabbing, i.e., prevents a vacuum-like condition below the valve in the service string, which may also improve reliability of the flow control device for multi-zone applications, wherein the flow control device may be opened and closed several times for treating each zone. The opening and closing of the flow control device  300  also does not require any interaction with the outer string  120 , i.e., tool manipulation is not required to open or close the flow device  300 . Moving the device  300  at a certain speed in the wellbore  101  ( FIG. 1 ) filled with a drilling fluid or supplying a fluid at a certain rate to the device  300  or a combination thereof, will open or close the device  300 . Also, if the inner string is moved upward at a high rate, swabbing may cause the inner string  160  to hydraulically lock in the outer string  120  and may prevent further pulling of the inner string. Weep hole  374  prevents such an occurrence. A flow control device made according to an embodiment of this disclosure is also useful in open hole applications. In open holes, no casing exists inside the wellbore, but wellbores may be lined with a membrane to prevent fluid loss from the wellbore to the formation. Swabbing may pull the membrane inside the wellbore, exposing a greater area for fluid loss from the wellbore into the formation. In other situations swabbing may cause a section of the wellbore, particularly a soft formation section, to collapse and close the wellbore. Thus, in an aspect, device  300  may prevent collapsing of an open hole section and fluid loss. 
     The foregoing disclosure is directed to the certain exemplary embodiments and methods. Various modifications will be apparent to those skilled in the art. It is intended that all such modifications within the scope of the appended claims be embraced by the foregoing disclosure. The words “comprising” and “comprises” as used in the claims are to be interpreted to mean “including but not limited to”. Also, the abstract is not to be used to limit the scope of the claims.