Untitled record

Methods and Apparatuses for Measuring Drill Bit Conditions

Full description

Background of the invention

The present invention relates generally to drill bits for drilling subterranean formations and, more specifically, to methods and apparatuses for monitoring downhole conditions during drilling operations.

The oil and gas industry spends large sums of money designing cutting tools, such as downhole drilling bits including roller cone rock bits and fixed cutter bits, that have relatively long service lives. , with relatively rare failure. Specifically, significant amounts of money are spent designing and manufacturing roller cone rock bits and fixed cutter bits in a manner that minimizes the chance of catastrophic drill bit failure during drilling operations. Losing a roller cone or polycrystalline diamond compact (PDC) from a fixed cutter bit during drilling operations hampers drilling operations and, in the worst cases, requires rather expensive fishing operations. If fishing fails, operations called sidetrack drilling must be performed to drill around the portion of the wellbore that includes lost roller cones or PDC cutters. Typically, during drilling operations, bits are withdrawn and replaced early with new bits even though they can still get more service from the replaced bit. These costly replacements of downhole drill bits are expensive, since each trip out of the well detracts from overall drilling activity, and consumes considerable manpower, but they are nevertheless carried out to avoid a more disruptive and expensive process, at best. Under the circumstances, pulling the drill string and replacing the bit during detection of failure or, in the worst case, having to perform the necessary trawling and side-drilling operations if the One or more cones or compacts due to condylar failure.

With the increasing need for dynamic data for a downhole drilling system, a number of “sub-assemblies” (i.e., sub-assemblies) including sensors incorporated in the drill string above the bit have been identified and used to collect data related to drilling variables. drilling parameters) and their installation in drill strings. Unfortunately, these branches cannot provide actual data of what actually happens at the condyle due to their remote physical placement above the condyle itself.

Data acquisition is traditionally performed by mounting a sub in the Bottom Hole Assembly (BHA) several feet to tens of feet away from the bit. Data collected from branches distal to the bit may not accurately reflect what is happening directly at the bit during drilling. Often times, this lack of data results in an event of what could cause a bit to fail or cause a bit to work well, without directly relevant facts or data to correlate with the bit's performance.

Hence, there is a need for a drill bit equipped to measure and record data relating to the efficiency and conditions of the drill bit during operation. This drill bit can extend the useful bit life in a given borehole, allowing the bit to be reused in multiple drilling operations and providing the ability to generate bit efficiency data on existing drill bits, which can be used to develop future drill bit improvements.

General description of the invention

In one embodiment of the present invention, a drill bit for drilling a subterranean formation includes a drill bit bearing at least one cutting element and configured to be coupled to a drill string. Furthermore, the drill bit includes at least an optical sensor mounted in the drill bit and designed to sense at least a physical parameter in the drill bit.

Another embodiment of the invention includes an apparatus for drilling an underground formation including a drill bit bearing at least one cutting element and configured for coupling to a drill string and a chamber formed within the bit and designed to maintain a pressure substantially near surface atmospheric pressure during Drilling the underground formation. Further, the equipment includes at least an optical sensor mounted in the drill bit and designed to sense at least a physical variable and an electronics module mounted in the drill bit. The electronic device unit includes a memory, a processor, and a sensor interface with a light source. The sensor interface is coupled to at least the optical sensor and the operable processor is coupled to the memory and the sensor interface. Additionally, the processor is designed to execute computer instructions. Computer commands are designed to control the transmission of a light signal from the light source to at least the optical sensor and to analyze a reflected light signal from the at least the optical sensor.

Another embodiment of the invention includes a method including providing at least an optical sensor within a drill bit and measuring at least a physical variable associated with the drill bit from the at least optical sensor.

Brief explanation of the drawings

Figure 1 shows a conventional drilling rig for carrying out drilling operations;

Figure 2 is a perspective view of the top of a conventional matrix-type rotary drag;

Figure 3a is a perspective view of the shank and end cap;

Figure 3b is a cross-sectional figure of a shaft and end cap;

Figure 4a shows an optical fiber including gratings and a formed Bragg grating fiber, according to an embodiment of the present invention;

Figure 4b shows a network of optical fibers including Bragg gratings formed therein, in accordance with an embodiment of the present invention;

Figure 5 shows an optical sensor placed within a drill bit in accordance with an embodiment of the present invention;

Figure 6a-6e are perspective views of a drill bit showing locations in a drill bit according to an embodiment of the present invention where an electronic device unit, an optical sensor, or combinations thereof may be located;

Figure 7 is a block diagram of an electronic device module according to an embodiment of the present invention; And

Figures 8a and 8b show a gray-scale map and a black-and-white (shaded) map that publishes a color-coded map, respectively.

Detailed description

Embodiments of the present invention include a drill bit and an optical sensor mounted within the drill bit designed to measure downhole conditions during drilling operations.

Figure 1 shows an example of a conventional piece of equipment for carrying out subterranean drilling operations. The drilling rig 110 includes a derrick winch 112, derrick floor 114 114, drawworks 116, hook 118, swivel hitch 120, Kelly joint 122, and rotary table 124. Drilling rig 140 extends, comprising a drill pipe section 142 and a drill collar section 144, down from the drilling machine 110 into a borehole 100. The drill pipe segment 142 may include a plurality of tubular drill pipe ends connected together, and the drill collar segment 144 may likewise include a plurality of drill collars. In addition, the drill string 140 can include a measurement-while-drilling (MWD) recording assembly and a mud cross-pulse telemetry data transmission assembly, collectively referred to as communication system MWD 146, as well as Another connection known to those of ordinary skill in the art.

During drilling operations, drilling fluid is circulated from the mud pit 160 through the mud pump 162, through the desurger 164, and through the mud supply line 166 in the swivel 120. The drilling mud flows (referred to as Also with drilling fluid) through the Kelly joint 122 and into the axial central bore in the drill string 140. Finally, the drilling mud exits through pertures or nozzles, located in the drill bit 200, where it connects to the lowermost portion of the drill string 140 below the drill collar segment 144. The drilling mud flows back up through the annular space between the outer surface of the drill string 140 and the inner surface of the wellbore 100, which is rotated to the surface where it enters the mud hole 160 through the mud return line 168.

A shaker screen (not shown) can be used to separate formation debris from the drilling mud before returning it to the mud hole 160. The MWD communication system 146 can use a mud pulse telemetry technique to communicate data from a downhole location to Surface during drilling operations. To receive data at the surface, a mud pulse transducer 170 is equipped in connection with the mud supply line 166. The mud pulse transducer 170 generates electrical signals in response to pressure variations of the drilling mud supply line 166. These electrical signals are transmitted by a surface conductor 172 to a surface electronic processing system 180, which is conventionally a processing system Data is used by a central processing unit to carry out program instructions and to respond to user commands entered through a keyboard or graphical pointing device. The telemetry system is equipped with a mud pulse to communicate data to the surface on a number of downhole conditions transmitted by the borehole logging and measurement systems conventionally located within the MWD 146 communication system. Mud pulses are produced that determine the data transmitted to the surface by Equipment conventionally placed within the MWD 146 communication system. This equipment typically includes a pressure pulse generator operating under the control of electronic devices contained in a housing designed to allow drilling mud to be blown through a nozzle extending through the drill collar wall. Each time the pressure pulse generator causes venting, a negative pressure pulse is sent that will be received by the mud pulse transducer 170. An alternative conventional setup generates and sends positive pressure pulses. As is common, circulating drilling mud can also provide a source of energy for a turbine-driven generator subassembly (not shown) which may be located near the Bottom Hole Assembly (BHA). A turbine-driven generator can generate pressure-pulse electrical power for various circuits, including those that make up the operational components of measurement-while-drilling tools. As an alternative or supplemental source of electrical power, batteries may be provided, specifically as a back-up for the turbine-driven generator.

Figure 2 is a perspective view of an example of a drill bit 200 with a fixed cutter, or so-called “drag” bit, assorted. Conventionally, the drill bit 200 has threads at the shank 210 at the upper extent of the drill bit 200 for connection to the drill string 140 (see Figure 1). At least one blade 220 (plurality assembly shown) may generally be equipped at the opposite end of shaft 210 with a set of diamonds with natural or synthetic diamond bits (polycrystalline diamond compact cutters) 225, Equipped along the rotationally leading faces of the blades 220 for effect efficient disintegration of the formation material. Drill bit rotation rate 200 in a hole Well 100 is under the influence of the weight on the bit (WOB). A gage pad surface 230 extends upward from each of the blades 220, which are close to, and generally contact with, the side wall of the wellbore 100 (Figure 1) during the drilling process of the drill bit 200. A plurality of channels extends a plurality of channels 240, called a “gage pad surface 230.” "junkslots", between the blades 220 and the gage pad surfaces 230 to provide a clearance area for formation chips formed by the cutters 225.

A set of plurality of gage inserts 235 are provided on the surfaces of the gauge plate 230 of the drill bit 200. Shear scissors cutting plurality of gage inserts 235 on the surfaces of the gauge plate 230 of the drill bit 200 provide the ability to effectively cut formation material at the sidewall of the wellbore 100 and to provide Improved gage-holding ability in earth-boring bits with fixed cutter variety. The drill bit 200 is illustrated as a PDC ("polycrystalline diamond drill bit") bit, but the 235-gauge bits can be equally useful in fixed cutter or other drag bits that have 230-gauge layer surfaces to engage the side wall of a hole. Well 100.

Those of ordinary skill in the art will recognize that the present invention may be embodied in a variety of drill bit types. The present invention has application in the context of a tricone or roller cone rotary drill bit or other subterranean drilling tools as known in the art in that nozzles can be used to transfer drilling mud to installation parts during use. Accordingly, as used herein, the term “drill bit” includes and includes any and all rotary bits, , including core bits, rollercone bits, fixed cutter bits; Including PDC, natural diamond bits, thermally stable produced (TSP) synthetic diamond bits, diamond impregnated bits without limitation, eccentric bits, bicenter bits, reamers, expander wings Reamer wings, as well as other earth-boring tools, are designed to accept electronics modules, sensors, or any combination. ones, as described more fully below.

3a and 3b show an embodiment of a shaft 210 attached to a drill bit 200 (not shown), and an end cap 270. The shaft 210 includes a central hole 280 machined through the longitudinal axis of the shaft 210. In a conventional drill bit 200, such a central bore 280 is designed To allow drilling mud to flow through it. In the present invention, at least a portion of the center hole 280 is given a diameter sufficient to accept an electronic device module 290 designed in a substantially annular ring, also without substantially affecting the structural integrity of the shaft 210. Thus, the electronic device unit 290 can be positioned down into the center hole 280, around the end cap 270, extending through the inner diameter of the annular ring of the electronic device unit 290 to form a fluid tight annular chamber 260 (Figure 3b) with the wall of the center hole 280 and seal. The electronic device module 290 is located within the column 210.

The end cap 270 includes a cap bore hole 276 machined through it, through which drilling mud can flow through the end cap 270, through the center hole 280 of the shaft 210 to the other side of the shaft 210, and then into the drill bit body 200. In addition, the end cap 270 includes a first flange 271 (see Figure 3b) including a first sealing ring 272, near the lower end of the end cap 270, and a second flange 273 including a second sealing ring. sealing ring 274, near the upper end of the end cap 270.

Figure 3b is a cross-sectional view of the end cap 270 attached to the shaft 210, showing the annular chamber 260 formed between the first flange 271, the second flange 273, the end cap body 275, and the walls of the central bore 280. The first sealing ring 272 and the second sealing ring 274 provide a fluid tight seal and protector between the end cap 270 and the wall of the center hole 280. The protective seal formed by the first sealing ring 272 and the second sealing ring 274 can provide the ability to keep the annular chamber 260 at approximately atmospheric pressure during drilling operations.

In the embodiment shown in Figures 3a and 3b, the first sealing ring 272 and the second sealing ring 274 are formed from a material suitable for a high-pressure, high-temperature environment, such as, for example, a hydrogen butadiene nitrile rubber ring. Hydrogenated Nitrile Butadiene Rubber (HNBR) O-ring in combination with a spare PEEK ring. In addition, the end cap 270 may be secured to the column 210 using a number of connection mechanisms such as, for example, a secure press-fit using sealing rings 272 and 274, a threaded connection, an epoxy connection, and a retaining barrier. Shape-memory retainer, welded, and brazed. Those of ordinary skill in the art will realize that the end cap 270 can be kept in a completely fixed position by a relatively simple connection mechanism owing to the indication of pressure and mud flow down during drilling operations.

In addition to placing the electronics module 290 inside the drill bit 200, one or more optical sensors 340 (see Figure 4-7) may be located inside the drill bit 200, or above the drill bit 200 in the bottom hole assembly. Furthermore, optical sensor 340 may be located within the drill bit 200 at a location proximate to the blade 220 or cutter 225 (see Figure 2). Additionally, optical sensor 340 may be located within a groove or formed chamber within the drill bit 200, as described more comprehensively below.

Optical sensor 340 can include one or more optical fibers, each of the optical fibers employing a plurality of fiber Bragg gratings. Furthermore, as known in the art, each grating within an optical fiber can be designed as a sensor to measure a physical variable. As is known to one of ordinary skill in the art, fiber Bragg grating refers to the periodically spaced changes in the refractive index made in the core of an optical fiber. These periodic changes reflect a very fine range of wavelengths specific to the passage of light through the fiber while transmitting other wavelengths. As known in the art, a reflected signal can be compared with a transmitted signal to determine the differences between the two signals. Signal variations can be related to various physical variables to determine a physical variable within the drill bit 200. Furthermore, based on a special grating doping, the grating can be designed as a sensor to measure physical variables such as, for example, strain, temperature, or pressure at the grating location. Additionally, the load or torque applied to a location inside the drill bit 200 or at a breaker 225 can be calculated from a strain measurement.

As shown in Figure 4a, an optical sensor 340 can include an optical fiber 342 having one or more fiber Bragg gratings 344 formed therein, where each grating 344 can be designed to sense a signal of a physical variable (i.e., temperature, voltage, or pressure) shown by a drill bit. By way of example only, but not as a limitation, each Bragg fiber grating 344 may be designed to sense a voltage signal appearing at a corresponding grating location within the optical fiber 342. In another embodiment, optical sensor 340 can include an optical fiber 342 having one or more fiber Bragg gratings 344, where each grating 344 can be designed to sense a single signal from a plurality of physical variables displayed by a drill bit. Alternatively, a single optical fiber 342 may comprise one or more fiber Bragg gratings 344, where each grating 344 can be designed to sense a temperature, pressure, or voltage appearing at a corresponding grating location within the optical fiber 342.

Furthermore, as shown in Figure 4b, the optical sensor 340 can be designed as a network 346 of optical fibers 342, where each of the optical fibers 342 within the network 346 can include one or more fiber Bragg gratings 344 designed for sensing. An indication of a physical variable (i.e., temperature, pressure, or voltage) displayed by a drill bit. By way of example only, and not as a limitation, each of the optical fibers 342 within the fiber optic mesh 346 may include one or more fiber Bragg gratings 344 designed to sense a temperature signal appearing at a location corresponding to each grating 344 within the mesh. Further, in another embodiment, the optical sensor 340 can be designed as a fiber optic grating 346 342, wherein each of the optical fibers 342 within the grating 346 can include one or more fiber Bragg gratings 344 designed to sense only one signal from A set of physical variables shown by a drill bit. By way of example only, and not as a limitation, each of the optical fibers 342 within the network 346 of the optical fibers 342 includes one or more fiber Bragg gratings 344 designed to sense a voltage signal appearing at the locations of one or more gratings 344, sensing a temperature signal Heat appearing at the locations of one or more gratings 344, and/or sensing a pressure signal appearing at the locations of one or more gratings 344 within the optical fiber 342. As a result, optical sensor 340 may include a fiber optic grating 346 342 having one or more fiber Bragg gratings 344 designed to sense a voltage signal appearing at locations within the drill bit, a fiber optic grating 346 342 having one or more fiber gratings. Bragg grating 344 is designed to sense a pressure signal appearing at locations within the drill bit, and/or fiber optic grating 346 342 has one or more fiber grating Bragg gratings 344 designed to sense a temperature signal appearing at locations within the drill bit. Further, optical sensor 340 may include one optical fiber grating 346 342 having one or more Bragg fiber gratings 344 designed to sense a voltage signal appearing at corresponding grating locations within the drill bit, a temperature appearing at corresponding grating locations within the bit. Drilling, and/or pressure appears at corresponding grating locations within the drill bit. Figure 5 is a top view of the drill bit 200 inside a borehole 100 showing non-exclusive examples of the optical sensor 340 positioned at various locations within the drill bit 200.

Optical fiber 342 including gratings 344, as shown in Figure 4a, and grating 346 of optical fiber 342 including gratings 344, as shown in Figure 4b, are only non-exclusive examples of the envisioned optical sensor designs 340. . Accordingly, various modifications and alternative forms of the optical fiber 342 including gratings 344 and the network 346 of optical fibers 342 including gratings 344 are within the scope of the invention.

As noted above, the drill bit 200 can be designed to receive the electronics module 290, sensors 340, or any combination thereof. In an embodiment where the drill bit 200 includes a drill bit with a steel body, a cavity or chamber can be projected from the drill bit 200 and optical fibers including fiber mesh Bragg barriers can be installed within the cavity or chamber. The cavity or chamber can then be capped and sealed to protect the optical sensor 340. In an embodiment where the drill bit 200 includes a cast bit, this may require that the optical sensor be placed within the casting bit after the bit has been cast due to the fact that some fiber optic gratings are not capable of withstanding the temperatures used in casting. As a result, in order to create a cavity or chamber within a casting bit, sand or clay pieces, called "displacement materials", can be placed in the bit mold before casting. After the die is cast, sand or silt pieces can be broken up and removed to form a cavity or chamber within the body of the casting bit. Optical fibers including fiber Bragg gratings can then be installed within the cavity or chamber and the cavity or chamber can then be covered and sealed to protect the optical sensor 340. Optical gratings of other optical fibers, such as sapphire gratings, can withstand , casting temperatures, therefore, can be placed in a die before casting.

Figure 6a-6e are perspective representations of the drill bit 200 illustrating locations in the drill bit 200 where the electronics module 290, optical sensor 340, or combinations thereof may be located. Figure 6a shows an oval cut out 260b, placed behind the oval depression (which may also be referred to as a torque slot) used to stamp the bit with a serial number that can be multiplied to accept electronic devices. This area may also be covered and sealed to protect the electronics module 290 and/or sensors 340. Alternatively, a circular section 260c placed in the oval depression used to seal the bit can be hammered to accept the electronics module 290 and/or optical sensor 340, which can then be covered and sealed to protect the electronics module 290 and/or optical sensor 340. Additionally, the shaft includes 210 on an annular race 260a formed into the center hole 280. The annular race 260a can allow the expansion of electronic device module 290 and/or sensors 340 in the annular race 260a such that an end cap 270 (see Figures 3a and 3b) is held in position.

Figure 6B shows an alternative design for column 210. A circular depression 260d can be formed in column 210 and the center hole 280 is machined around the circular depression, allowing drilling mud to be transported. The circular depression 260D can be covered and sealed to protect the electronics module 290 and/or optical sensor 340 within the circular depression 260D.

Figure 6c-6e shows circular depressions (260e, 260f, 260g) formed at locations on the drill bit 200. These locations show that a reasonable amount of room for the electronics module 290 and/or optical sensor 340 will maintain acceptable structural strength in the blade.

Figure 7 shows an embodiment of an electronic device module 290, which can be designed to perform a different set of functions. The electronics module 290 can include a power supply 310, a processor 320, and a memory 330. Furthermore, the electronics module 290 can include a sensor interface 360 coupled to each optical sensor 340 via an optical cable 362 . The sensing interface 360 can include a light source 361, such as a laser, and appropriate equipment to transmit light to Bragg gratings formed within the optical fiber core of the optical sensor 340. The light source 361 can include a light source with a known, controllable frequency. It shall be noted that each light source 361 may be operable coupled to one or more optical sensors 340. Furthermore, it shall be noted that the wavelength of light emitted from light source 361 may vary based on a variable to be sensed. Furthermore, the 360 sensor interface may also include a logic circuitry, including any suitable circuitry and processing equipment necessary to perform operations including receiving and/or analyzing return signals (reflected light) from one or more Of the 340 optical sensors.

The electronic device module 290 may also include processing equipment designed to generate a map showing the apparent temperature, pressure, or voltage at locations within a drill bit. For example, in an embodiment where the grating 346 (see Figure 4b) includes an array of fiber Bragg gratings 344 designed to sense a physical variable signal (i.e., temperature, pressure, or voltage), the resulting measurements at each grating 344 can be processed by Electronic device module 290 to generate a 3-D map, such as a gray-scale map or a color-coded map, showing the degrees of strain, temperature, or pressure seen at locations within a drill bit. Figure 8a shows a grayscale map 800, where the x-axis and y-axis of the map 800 can indicate a location within the drill bit at which the physical variable is sensed and the z-axis z of the map 800 can indicate an amplification of the sensed physical variable. with it. Furthermore, the electronic device module 290 can be designed to generate a color-coded map 850 (see Figure 8b for black-and-white rendering thereof), where the x-axis and y-axis of the color-coded map 850 can indicate a location within the drill bit The physical variable is sensed and the amplification of the sensed physical variable can be represented by a color (for example, blue, green, yellow). For example, a portion of the color-coded map 850 with a darker color (i.e., region 860) may represent a region where the amplification of a physical variable sensed is less than the amplification of the physical variable sensed at the other region represented by the portions of the color-coded map. Chromatically 850 has a lighter color (ie, area 870). As is known in the art, the map can then be compared to a finite element analysis (FEA) model of a particular drill bit to predict potential bit failure with reasonable certainty.

It can be advantageous to measure past conditions of the drill bit within the downhole environment using an optical sensor using the previously described Bragg grating technology that is rugged, reliable, and relatively inexpensive to manufacture and operate. Furthermore, an optical sensor has no downhole electronics or moving parts and, therefore, can be exposed to harsh downhole operating conditions without the typical loss of efficiency seen with electronic sensors.

Memory 330 may be used to store sensor data, signal processing results, long-term data storage, and computer instructions for execution by the processor 320. Memory portions 330 may be located outside the processor 320 and portions may be located inside the processor 320. Memory 330 can include Dynamic Random Access Memory (DRAM), Static Random Access Memory (SRAM), Read Only Memory (ROM), Nonvolatile Random Access Memory ( NVRAM, such as Flash memory, Electrically Erasable Programmable ROM (EEPROM), or combinations thereof. In an embodiment of Figure 7, the memory 330 is a combination of SRAM in the processor (not shown), flash memory 330 in the processor 320, and external Flash memory 330. Flash memory may be desirable for low-power operation and the ability to save information when not Availability of memory capacity of 330.

A communication port 350 may be included in the electronic device module 290 for communication with external devices such as the MWD communication system 146 and remote processing system 390. The communication port 350 may be designed for a direct communication link 352 to the remote processing system 390 using a direct wire connection or a wireless communication protocol, such as, for example only, infrared, Bluetooth, and 802.11 protocols. a/b/g. Using a direct connection, the electronics module 290 can be designed to communicate with a remote processing system 390, such as, for example, a computer, a portable computer, and a personal digital assistant (PDA) when the drill bit 200 is not downhole. Thus, the direct connection link 352 can be used for a variety of functions, such as, for example, to downhole software download and software upgrades, to enable the processing of the electronic device unit 290 by uploading configuration data, and to upload sample data and analysis data. data. data. The communication port 350 may also be used to ask the electronics module 290 for information regarding the drill bit 200, such as, for example, the bit serial number, electronics module serial number, data version, total elapsed operating time of the bit, and long drill bit data. Other terms can be stored in NVRAM.

The communication port 350 can also be designed to communicate with the MWD communication system 146 in a downhole assembly via a wired or wireless communication link 354 and a protocol designed to enable remote communication over restricted distances in a drilling environment as known by those of ordinary skill in the art. A technology available for connecting data signals to a coupling assembly in drill string 140 (Figure 1) is depicted, described, and protected in U.S. Patent No. 4,884,071 entitled “Wellbore Tool With Hall Effect Coupling,” issued on November 28, 1989 to Howard.

The MWD communication system 146 may, in turn, communicate data from the electronics module 290 to a remote processing system 390 using a cross-mud pulse telemeter 356 or other suitable communication means suitable for communicating over the relatively long distances encountered in the drilling process.

The processor 320 in embodiment of Figure 7 is designed to process, analyze, and store collected sensor data. In addition, processor 320 in the embodiment includes SRAM and internal NVRAM. However, those of ordinary skill in the art will note that the present invention may be practiced using memory 330 which is solely outside the processor 320 as well as a design without the use of external memory 330 and memory only 330 within the processor 320.

Although the present invention is described herein with respect to certain embodiments, those of ordinary skill in the art will understand or realize that it is not limited thereby. Otherwise, many additions, deletions, and modifications may be made to those embodiments without departing from the scope of the invention as protected herein, including legal equivalents. In addition, features of one embodiment may be aggregated with features of another embodiment while remaining within the scope of the invention.