Patent Application
20110042083
The present invention relates generally to hydrocarbon production, and more particularly to a method of increasing hydrocarbon recovery from a reservoir.
In certain subterranean formations, fluid is injected into the reservoir to displace or sweep the hydrocarbons out of the reservoir. This method of production is generally referred to as a method of “Enhanced Oil Recovery” which may be water-flooding, gas injection, steam injection, etc. For the purpose of this specification, the general process will be defined as injecting a fluid (gas or liquid) into a reservoir in order to displace the existing hydrocarbons into a producing well. The primary issue with injecting fluid to enhance oil recovery is how to sweep the reservoir of the hydrocarbon in the most efficient manner possible. Because of geological differences in a reservoir, the permeability may not be homogenous. Because of such permeability differences between the vertical and horizontal directions or the existence of higher permeability streaks, the injecting fluid may bypass some of the reservoir fluid and create a path into the producing well. Even with homogenous reservoirs, the tendency of the injected fluid is to breakthrough into the producing well and consequently leave a large volume of the reservoir un-swept by the injecting fluid. This problem generally gets worse as the mobility ratio between the fluids becomes unfavorable, such as when the mobility of the injected fluid is significantly higher than the reservoir fluid.
The industry has come up with numerous methods to improve the sweep efficiency and the overall reservoir that is swept by individual wells. These methods include fracturing and the use of horizontal wells. The industry currently uses horizontal wells as injectors in an attempt to expose more of the reservoir to the injecting fluid. The goal is to create a movement of injection fluid evenly across the reservoir. This is done to emulate the highly efficient line drive. The industry also uses horizontal wells as producers, again the goal being to evenly produce the reservoir so to form a line drive.
SPE Paper 84077 presents a method referred to as toe-to-heel waterflooding where a horizontal lateral is used to produce the reservoir with a vertical injector located nearer the toe (end) of the lateral. The method referred to in this paper is limited, since the horizontal lateral only covers a limited area in the reservoir. A horizontal lateral covers a small area in the vertical direction, thus the vertical sweep efficiency is fairly low. It therefore does not maximize the amount of surface area that can be used to recover the hydrocarbons. This method also suffers from an inability to control the influx of injection fluid at the toe to improve recovery.
Part of the efficiency of the sweep is reducing the production of the injection fluid. The industry has created several techniques from the use of chemicals that block the injection fluid, to injection fluids that improve the matrix flow through the reservoir to reduce channeling. Some injection programs include attempts to plug high permeability streaks and natural fractures in the reservoir. This is done to shut-off pathways that can exist between the injector well and producing wells. As these pathways are restricted the injection fluid will develop new pathways to the producing wells. This will force the injection fluid into more of the reservoir to displace hydrocarbons, thus improving sweep efficiency and reducing the influx of injected fluid into the producing wells.
When the injection fluid is produced, such as water, it is usually removed from the hydrocarbons at the surface using multi-phase separation devices. These devices operate to agglomerate and coalesce the hydrocarbons, thereby separating them from the water. A drawback of this approach, however, is that no separation process is perfect. As such, some amount of the hydrocarbons always remains in the water. This can create environmental problems when disposing of the water, especially in off-shore applications. Also, the multi-phase separation devices are rather large in size, which is another disadvantage in off-shore applications, as space is limited. Yet another drawback is that these devices can require additional maintenance or repair if solids are part of the produced fluid stream. A further, and perhaps greatest drawback of these solutions, is that they do nothing to increase or maximize the amount of hydrocarbons being produced. Their only focus is removing the water from the production.
Specialized downhole tools have also been developed, which separate the water from the hydrocarbons downhole. These tools are designed to re-inject the water into some designated formation as the hydrocarbons are produced. While these devices can remove a significant amount of water from the hydrocarbons, their efficiency are usually low. They also suffer from the same drawback of the surface separation devices in that they do nothing to increase or maximize the amount of hydrocarbons being produced.
A solution is therefore desired that not only improves the efficiency and economics of enhanced oil recovery through injection, but that also reduces the amount of injection fluid that infiltrates the hydrocarbon production of an existing well.
An embodiment of the present invention is directed to a method of hydrocarbon production from a hydrocarbon reservoir. The method includes providing a substantially horizontal wellbore within a hydrocarbon reservoir having at least one productive interval and forming at least one transverse non-conductive fracture, in the reservoir along the substantially horizontal wellbore. An injection well is also provided. A non-conductive fracture can be created adjacent the producer well to create a sealed transverse fracture that forms a barrier within the reservoir to divert non-hydrocarbon fluids away from the production intervals of the substantially horizontal wellbore. A fluid is injected into the reservoir through the injection well to displace hydrocarbons within the reservoir toward the producing well. Hydrocarbons are drained from the reservoir into the substantially horizontal wellbore. Fluid production flows through an inflow control device (ICD) that can restrict the fluid flow and distribute the drawdown pressure optimally along the horizontal wellbore. There can be more than one substantially horizontal wellbore, each can have multiple non-conductive and conductive transverse fractures. The injection well can be a horizontal well.
The non-conductive transverse fracture can be placed during the well construction, after initial production has begun or at any time during the life of the well. A non-conductive transverse fracture(s) can form a barrier(s) within the reservoir to divert injected fluids to increase sweep efficiency and reduce the influx of injected fluids into the production intervals.
The inflow control device(s) can provide an increasing pressure drop along the horizontal wellbore as the volume of fluid flow through the device increases. The inflow control device(s) can provide an optimized pressure drop in the reservoir along the productive horizontal lateral through the inflow control device for the designed volume of fluid flow through the device. The method can further comprise the selective closing or sealing of an inflow control device when production through the inflow control device reaches an unacceptable level of non-hydrocarbon fluids with the hydrocarbon production.
Additional inflow control devices can be selectively closed or sealed when production from the production interval associated with such inflow control devices reach an unacceptable level of non-hydrocarbon fluids with the hydrocarbon production.
The inflow control device can be a valve device, referred to as an inflow control valve (ICV), which can be closed. The inflow control device can include a sliding sleeve device that can be closed or sealed when production associated with such inflow control devices reach an unacceptable level of non-hydrocarbon fluids. Additional sliding sleeves not associated with an inflow control device can be incorporated with the substantially horizontal wellbore. The additional sliding sleeves can be used to create subsequent transverse fractures, such as non-conductive transverse fractures, that can be used as barrier fractures between productive intervals. Alternately a sliding sleeve having multiple ports can be used. A multi-port sliding sleeve can utilize one port for the creation of substantially transverse fractures, which can be closed after the fracture operation is completed. A second port can then be opened which allows production through an ICD. After production through the ICD reaches unacceptable level of non-hydrocarbon fluids, the second port can then be closed.
A further embodiment of the present invention is a method of designing a hydrocarbon production system that includes determining the stress field within a hydrocarbon reservoir, designing at least one horizontal well in the direction of the minimum horizontal stress and designing a plurality of fractures transverse to the wellbore. The design includes at least one injection well within the hydrocarbon reservoir and a reservoir model that incorporates the physical and mechanical properties of the reservoir and the stress field magnitude and orientation. The reservoir model is designed to incorporate the distance from the tip of the horizontal well to the injection well, number and location of the plurality of fractures transverse to the wellbore, number of inflow control devices, number of inflow control valves, injection rate of flood fluid, location of the injection interval. The model can be verified and built into a reservoir simulator. The parameters are varied to optimize the hydrocarbon production system design for the hydrocarbon reservoir.
The present invention is directed to a method of increasing hydrocarbon recovery from an existing well through injecting fluid to displace the hydrocarbons from the reservoir while simultaneously reducing the influx of water and other non-hydrocarbon fluids, such as carbon dioxide, into the existing well. In its most basic form, the present invention achieves its goal by providing at least one substantially horizontal wellbore, creating at least one non-conductive barrier fracture and injecting a flood fluid, such as water, into the formation so as to force the hydrocarbons into the remaining wellbore. As those of ordinary skill in the art will appreciate from the disclosure that follows, there are many different ways of arranging the substantially horizontal wells, many different ways of injecting the fluid into the formation, and many different ways of recovering the hydrocarbons into the transverse fractures. A number of exemplary ways of performing these functions are disclosed herein.
Turning to
A plurality of transverse fractures 116, either conductive or non-conductive, are formed along the horizontal wellbore 110. The transverse fractures 116 are formed generally parallel to one another. There are a number of different ways of carrying out this step. In one exemplary embodiment, the plurality of transverse fractures 116 are formed by using a hydra jetting tool, such as that used in the SurgiFrac® fracturing service offered by Halliburton Energy Services. In this embodiment, the tool forms each fracture of the plurality of transverse fractures 116 one at a time. Each transverse fracture 116 can be formed by the following steps: (i) positioning the hydra jetting tool in the substantially horizontal wellbore 110 at the location where the transverse fracture 116 is to be formed, (ii) hydrajet perforating the reservoir 112 at the location where the transverse fracture 116 is to be formed, and (iii) injecting a fracture fluid into the perforation at sufficient pressure to form a transverse fracture 116 along the perforation. As those of ordinary skill in the art will appreciate, there are many variations on this embodiment. For example, fracture fluid can be simultaneously pumped down the annulus while it is being pumped out of the hydra jetting tool to initiate the fracture or not. Alternatively, the fracturing fluid may be pumped down the annulus and not through the hydra jetting tool to initiate and propagate the fracture, i.e., in this version the hydra jetting tool only forms the perforations.
In another version of this embodiment, the plurality of transverse fractures 116, either conductive or non-conductive, are formed by staged fracturing. Staged fracturing can be performed by (i) detonating a charge in the substantially horizontal wellbore 110 at the location where a transverse fracture 116 is to be formed so as to form a perforation in the reservoir at that location, (ii) pumping a fracture fluid into the perforation at sufficient pressure to propagate the transverse fracture 116, (iii) installing a plug in the substantially horizontal well 110 bore uphole of the transverse fracture 116, (iv) repeating steps (i) through (iii) until the desired number of transverse fractures 116 have been formed; and (v) removing the plugs following the completion of step (iv). As those of ordinary skill in the art will appreciate, there are many variants on the staged fracture method.
In yet another version of this embodiment, the plurality of transverse fractures 116, either conductive or non-conductive, are formed using a limited entry perforation and fracture technique. The limited entry perforation and fracture technique can be performed by (i) lining the substantially horizontal wellbore 110 with a casing string 114 having a plurality of sets of predrilled holes arranged along its length, and (ii) pumping a fracturing fluid through the plurality of sets of predrilled holes in the casing string at sufficient pressure to fracture the reservoir 112 at the locations of the sets of predrilled holes.
In still another version of this embodiment, the plurality of transverse fractures 116, either conductive or non-conductive, can be formed by the steps of (i) installing a tool having a plurality of hydra jets formed along its length into the substantially horizontal wellbore 110, and (ii) pumping fluid through the plurality of hydra jets simultaneously at one or more pressures sufficient to first perforate and then fracture the reservoir 112 at the locations of the hydra jets.
In still another version of this embodiment, the plurality of transverse fractures, either conductive or non-conductive, can be formed by the steps of (i) installing sliding sleeves as part of the casing along the length of the substantially horizontal wellbore, (ii) opening individual sleeves, and (iii) pumping fluid through the sleeves to fracture the reservoir at the location of the sleeves. The plurality of sliding sleeves can be used for fracturing purposes or be equipped with an inflow control device (ICD) for production purposes. In the case where a sleeve is used to place a non-conductive barrier fracture the sleeve is closed after placement of the fracture treatment. When all transverse fractures have been created and the associated sleeves closed, the production sleeves with ICD's are then opened to allow production. Alternately a sliding sleeve having multiple ports can be used. A multi-port sliding sleeve can utilize one port for the creation of substantially transverse fractures, which can be closed after the fracture operation is completed. A second port can then be opened which allows production through an ICD. After production through the ICD reaches unacceptable level of non-hydrocarbon fluids, the second port can then be closed. One non-limiting example of a sliding sleeve that can be used to create transverse fractures within a reservoir is the Delta Stim® sleeve and completion service offered by Halliburton Energy Services. This sliding sleeve can be shifted by either a mechanical shifting tool or alternately through a ball-drop system. The ball-drop system enables multiple sleeves to be run in a casing string with the choice of which sleeve to be shifted determined by the size of the dropped ball.
After the substantially horizontal wellbore 110 has been cased one or more non-conductive and/or conductive transverse fractures 116 can be created. The non-conductive transverse fracture can be referred to as a non-conductive Barrier Fracture (NCBF).
The casing can be cemented within the substantially horizontal wellbore 110 to isolate intervals of the reservoir or optionally the isolation of intervals along the openhole horizontal well can involve the use of external packers. One non-limiting example of an external packer that can be used to create a seal between the casing and the reservoir is the Swellpacker® isolation system offered by Halliburton Energy Services. This system operates on the swelling properties of rubber in hydrocarbons and can seal the annulus around the casing to the wellbore.
The NCBF can be placed as a remedial treatment after the well has been producing for some time. This can be accomplished by first isolating the perforations using a packer 135 (such as a hydraulically set drillable, retrievable or inflatable packer) on the end of tubing and set in the casing; then pumping the sealant in a fluid state through the tubing, then through the perforations creating a transverse fracture 118 until a sufficient volume of sealant has been placed to accomplish a barrier to flow of fluids by the flood front 130.
The sealant can be any material that can be used to create the desired transverse fracture that can form a sufficient barrier to the flow of fluids within the reservoir under the influence of the flood front 130. Non-limiting examples of a suitable sealant include a cement, a linear polymer mixture, a linear polymer mixture with cross-linker, an in-situ polymerized monomer mixture, a resin-based fluid, an epoxy based fluid, or a magnesium based slurry. Each of these sealants can be capable of being placed in a fluid state with the property of becoming a viscous fluid or solid barrier to fluid migration after or during placement into the fracture. In one embodiment, the sealant is H2Zero™. Other sealants could include particles, drilling mud, cuttings, and slag. Exemplary particles could be ground cuttings so that a wide range of particle sizes would exist producing low permeability as compared to the surrounding reservoir.
An injection well 120 can be located remote from, but generally parallel to, existing well 100. In embodiment the injection well 120 can be located proximate the NCBF 118. Once the injection well 120 has been formed and the NCBF 118 is created, flood fluid can be pumped down the injection well 120. As the flood fluid is pumped into the reservoir 112 it forms a propagating flood front 130. The flood front 130 is diverted around the NCBF 118, as indicated by the large arrows. At the same time, hydrocarbons are drained into the transverse fractures 116, as indicated in by the small arrows. As the adjacent transverse fractures 116 begin producing high rates of flood fluid, they can be isolated from the production stream in the casing, such as by setting a bridge plug 135 in the substantially horizontal wellbore 110 just uphole of the particular transverse fracture that is to be isolated. The bridge plug 135 may be a mechanical bridge plug that is either drillable or retrievable. Alternatively, a plug made of a diverting agent or a removable viscous fluid. This isolation process is repeated as sufficiently high flood fluid ratios are being produced from successive production intervals until all of the production intervals have been isolated.
A device 150 for monitoring the amount of infiltration of the flood fluid into the hydrocarbons being produced in the substantially horizontal wellbore 110 is installed adjacent to one or more of the production intervals. Examples of such devices include, but are not limited to, fluid flow meters, electric resistivity devices, oxygen decay monitoring devices, fluid density monitoring devices, pressure gauge devices, and temperature monitoring devices. Data from these devices can be obtained through electric lines, fiber-optic cables, retrieval of bottom hole sensors or other methods common in the industry. Another solution involves installing a sampling line into the production flow path. This could be a tubing (coiled or jointed) that takes a sample of the fluid at a point in the wellbore. If the sampling line is continuous tubing, then the well can be continuously monitored. In yet another embodiment, a sampling chamber is formed in the production flow path so that discrete samples of fluid can be taken. With such devices/solutions, the percentage of injection fluid to hydrocarbons can be measured at the surface, so that a judgment can be made whether to close a production interval.
Turning to
An injection well 120 can be located remote from, but generally parallel to, existing well 100. In an embodiment the injection well 120 can be located proximate the sealed NCBF 118. Once the injection well 120 has been formed and the transverse fracture 118 is created or sealed to form a NCBF 118, flood fluid can be pumped down the injection well 120. As the flood fluid is pumped into the reservoir 112 it forms a propagating flood front 130. The flood front 130 is diverted around the NCBF 118, as indicated by the large arrows. At the same time, hydrocarbons are drained into the wellbore 110 or transverse fractures 116, as indicated by the small arrows. The production into the horizontal wellbore 110 is restricted by use of one or more inflow control device (ICD) 145. The ICD 145 limits the production through each production interval thereby enabling a more uniform drainage from the hydrocarbon reservoir 112. For example the ICD 145a farthest from the existing well 100 can restrict production from the reservoir 112 farthest from the existing well 100, which can postpone the eventual breakthrough and production of the flood fluid and enable an increased ultimate hydrocarbon production from the reservoir 112.
An illustration of one type of ICD is shown in the cut-away view presented by
In an alternate embodiment of the present invention one or more of the inflow control device (ICD) 145 can be an inflow control valve (ICV). The ICV can be of any suitable design that can be closed through an intervention, such as by wireline, coiled tubing, hydraulic activation or the like. For example, referring to
In an embodiment of the present invention one or more of the inflow control device (ICD) 145 can include both an inflow control device and an inflow control valve (ICV). For example, referring to
Turning to
One or more of the inflow control device (ICD) 145 can be an inflow control device and/or an inflow control valve (ICV). The ICD 145a can restrict production from the portion of the wellbore adjacent ICD 145a. When the production of the flood fluid through ICD 145a reaches an unacceptable level, the ICV 145a can be closed, thereby stopping production from the isolated portion of the wellbore. In like manner when the production of the flood fluid through ICD 145b reaches an unacceptable level, the ICV 145b can be closed, thereby stopping production from the production interval of the wellbore.
Turning to
Fluid is injected into the reservoir 112 through toe section 140 of substantially horizontal wellbore 111 through the end of tubing 160. A flood front 130 propagates outward in the direction indicated by the large arrows in
As the flood fluid ratio reaches an unacceptably high level from an isolated portion of the wellbore, the associated ICD can be sealed or closed starting with ICD 145a closest to existing well 100 and moving toward ICD 145d closest to the toe portion of substantially horizontal wellbore 110.
One or more of the inflow control device (ICD) 145 can be an inflow control device and/or an inflow control valve (ICV). The ICD 145a can restrict production through an adjacent transverse fracture or isolated portion of the wellbore nearest to ICD 145a. When the production of the flood fluid through ICD 145a reaches an unacceptable level, the ICV 145a can be closed, thereby stopping production through ICD 145a and the portion of the wellbore drained by ICD 145a. In like manner when the production of the flood fluid through ICD 145b reaches an unacceptable level, the ICV 145b can be closed, thereby stopping production through ICD 145b and the portion of the wellbore drained by ICD 145b.
A device for monitoring the amount of non-hydrocarbon fluid in the hydrocarbon production 150 may also be employed in substantially horizontal wellbore 110. The hydrocarbon production flows in the direction of the arrow moving up the annulus and wellbore 110 into existing wellbore 100.
To study the effects of the aspects of the present invention a relatively simple, homogeneous reservoir was modeled for a pressure maintenance scenario in a water flood project using numerical simulation. Table 1 shows the reservoir properties modeled for Scenarios 1-6. The reservoir simulator chosen is capable of incorporating reservoir heterogeneity such as high permeability streaks, faults, dipping reservoirs, etc., and fluid properties that include high mobility ratios such as those presented by heavy oil reservoirs.
The completion scenarios chosen for comparison are described in Table 2. The flow periods and injection periods are for 10 years. A baseline scenario, referred to as Scenario 1, was modeled with an openhole horizontal producer wellbore with no non-conductive Barrier Fracture (NCBF) and no inflow control. A producer having the addition of ICD's was simulated using limited perforated intervals to produce a restriction on the fluid flow as an ICD would give, referred to as Scenario 2. In Scenario 3 a producer having both ICD's and ICV's used the same perforation configuration as Scenario 2 but were simulated as closed perforations after excessive water production occurred at each interval. A producer with one NCBF (Scenario 4) and with 5 NCBF (Scenario 5) were simulated as having barrier fractures of 1000 feet long by 1 feet thick, low porosity, low permeability streaks that are transverse to the horizontal wellbore and extending through the entire thickness of the productive interval. The NCBF were simulating a 500 feet fracture half-length and were placed in the producers prior to production and injection operations. Finally, the combination of ICD's, ICV's and five NCBF was simulated in Scenario 6 to illustrate the combination of these controls. The completion configuration for these controls is shown in Table 3.
The production rate for each producer in scenarios 1-6 was limited to 10,000 bpd of Water+Oil maximum and the injection rate was set at 10,000 BWPD. The vertical injection well in all scenarios was simulated as an openhole completion. The vertical well was completely penetrating the production interval. The 2000 ft horizontal lateral was placed at 2015 ft vertical depth. The vertical injection well placement is shown in
Results—Single Horizontal Producer with Vertical Injector—Scenarios 1-6
Referring to
Referring to
Reservoir Simulation—Dual Horizontal Wells with Horizontal Well Injector
A final comparison study (Scenario 7, 8, 9, 10) was performed for a pair of horizontal producers with a horizontal injector well transverse to the direction of the parallel producers, as shown in
Results—Dual Horizontal Producers with Single Horizontal Injector—Scenarios 7 Through 10
The perforation configurations for scenarios 7, 8, 9, and 10 are shown in Table 6. The cumulative results combine production from the two producers. Referring to
Referring to
Summary of Simulation Results
Using the cumulative production from Scenario 1 (for the single horizontal producer case) and Scenario 7 (for the Dual Horizontal producers case) as the base cases for the simulations, the value of inflow controls used in conjunction with one or more NCBF are shown in terms of improved oil recovery, incremental oil, and reduced water production in Table 7.
Horizontal producers with Inflow Controls and NCBF are shown through reservoir simulation to improve the recovery of oil and reduce the production of water in a waterflood. In simulations of a single horizontal producer and single vertical injector, the combination of both ICD and NCBF usage resulted in a significant improvement above the base case, as shown by Scenarios 5 and 6 in Table 7. The optimum result was for Scenario 6 that utilized ICD, ICV, and NCBF usage. In simulations of dual horizontal producers and single horizontal injector, the combination of both ICD and NCBF usage also resulted in an improvement above the base case, as shown by Scenarios 8, 9, and 10 in Table 7.
A further aspect of the present invention is a method of reservoir simulation to predict and evaluate the oil and non-hydrocarbon production and flood front progression over time while utilizing the various combinations of barrier fractures and inflow control devices/valves. The combination of ICD's, ICV's and NCBF can yield greater efficiency in flooding oil reservoirs than by these controls individually. Through reservoir simulation of various completion scenarios the value of these controls can be evaluated. The use of reservoir simulation is also important in optimizing the placement and number of these controls for a given completion.
The optimization process can include a number of differing aspects such as those listed in the non-limiting embodiment below:
The reservoir model used for analyzing the scenarios provided herein utilized a commercially available simulator QuikLook™ by Halliburton. It was capable of simulating horizontal wellbores having multiple transverse fractures. It had the ability to account for three-phase, four component system (gas, oil, water, and injected fracturing fluid) and have intermittent injection and production flow periods. It further had the ability to account for asymmetric fracture wings with adjustable length, width, height, and conductivity characteristics.
The reservoir simulator was linked to a commercially available numerical wellbore simulator, WellCat™ by Halliburton. The simulator was used to calculate wellbore temperature and pressure profile during the injection of fluids, thus accounting for the cool down of the formation during a sustained injection of flood fluids. The program can model vertical, horizontal, and multilateral wells that may be fractured or not.
While the invention has been depicted, described, and is defined by reference to exemplary embodiments of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. For example, as those of ordinary skill in the art will appreciate, the exact number, size and order of the transverse fractures formed is not critical. The depicted and described embodiments of the invention are exemplary only, and are not exhaustive of the scope of the invention. Consequently, the invention is intended to be limited only by the scope of the appended claims, giving full cognizance to equivalents in all respects.
Depending on the context, all references herein to the “invention” may in some cases refer to certain specific embodiments only. In other cases it may refer to subject matter recited in one or more, but not necessarily all, of the claims. While the foregoing is directed to embodiments, versions and examples of the present invention, which are included to enable a person of ordinary skill in the art to make and use the inventions when the information in this patent is combined with available information and technology, the inventions are not limited to only these particular embodiments, versions and examples. Other and further embodiments, versions and examples of the invention may be devised without departing from the basic scope thereof and the scope thereof is determined by the claims that follow.
While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.
