Patent Application
20150233205
During drilling oil and gas wells, subterranean fractures may be penetrated by a wellbore formed by a drill bit. These pre-existing fractures are called natural fractures. These natural fractures may be of various shapes and sizes and some of them may be in a form of vugs, voids, pores, joints, cracks, faults or caverns. During drilling, drilling fluid is normally pumped through hollow drill pipe to the drill bit and through nozzles on the bit into the wellbore flowing upward through the annulus formed between the wellbore and the drill pipe back to surface. The drilling fluid is to carry drilled cuttings to surface, cool the bit, lubricate the drill pipe, apply hydraulic pressure to the wellbore, etc. After the drilled cuttings are separated from the drilling fluid by devices such as shale shaker screens, the drilling fluid then is pumped down through the hollow drill pipe again. This process is called drilling fluid circulation, which is a normal process of drilling. The fluid pressure or hydraulic pressure applied to the wellbore sometimes may be too high and may burst the wellbore and create fractures. These fractures are called induced fractures. In either case of natural fractures or induced fractures, drilling fluid may be totally or partially lost into the fractures and no drilling fluid or only partial of the drilling fluid returns to the surface. This is called lost circulation or lost returns.
For a fracture connecting to a wellbore, the fracture has an entrance at the wellbore wall and is of a fracture width that may not be tapering toward the tip of the fracture several hundred feet away from the wellbore. Fracture width is the distance between the two walls of a fracture or fracture faces and it is a meaningful indicator for a fracture size in terms of sealing. A fracture may be of various shapes. In general, fracture size here is referred to as the smallest dimension of a fracture entrance. For an induced fracture, at the fracture tip, the fracture width becomes zero.
In order to stop the unwanted lost circulation, sealing materials are often pumped down hole to the fractures to attempt to form a seal to the fractures. These sealing materials are often particulate materials mixed and suspended in a carrying fluid such as water, seawater, oil, diesel, synthetic oil, drilling fluid, cement slurry, completion fluid or any oil field fluid to form a sealing fluid. These sealing materials include but not limited to the following: diatomaceous earth, calcium carbonate, sand, coke, petroleum coke, graphite, resilient graphitic carbon, synthetic graphite, cedar fiber, nut hulls, corn cobs, asphalt, gilsonite, rubber, drilled cuttings, saw dust, mica, wood chips, engineering plastics, fly ash, cotton seed hulls, walnut hulls, pistachio hulls, almond hulls, peanut hulls, cement, lime, clay, bentonite, modified clay, organoclay, limestone, lime, cement, concrete, dolomite, marble, resin particles, metal particles, ceramic particles, weighting materials such as barite, hematite, iron oxide, ilmenite, and combinations thereof. Optionally, nanotechnology particles, e.g., silica nanoparticles, clay nanoparticles, and the like are used for the compositions. Optionally, chemically treated particles are used for the compositions. The chemically treated particles can include resin coated, surface sticky, surface hydrophobic and surface hydrophilic particles. Optionally, the sealing materials further consist one or more of the following soft sealing materials: foam rubber, sponge, open-cell sponge and open-cell foam rubber. These soft sealing materials are highly elastic or spongy. They can be easily compressed or deformed with a small force and they can easily restore their size and shape when the force is removed. Therefore the soft sealing materials larger than a fracture if forced into the fracture can fit and bridge off the fracture nicely. These foam rubber, sponge, open-cell sponge and open-cell foam rubber as sealing materials are well described in the U.S. Pat. No. 7,741,247, entitled “Methods and Compositions for Sealing Fractures, Voids, and Pores of Subterranean Rock Formations” which is incorporated by reference herein in its entirety and in a technical paper, AADE-11-NTCE-25, “Is It Really Possible to Efficiently Form A Strong Seal inside Subterranean Openings without Knowing Their Shape and Size?”, authored by Hong (Max) Wang and presented at the 2011 AADE National Technical Conference and Exhibition held at the Hilton Houston North Hotel, Houston, Tex., Apr. 12-14, 20. This technical paper is also incorporated by reference herein in its entirety. In order to form a good seal, these particulate materials normally have a wide particle size distribution. When fractures are sealed, lost circulation is cured.
Sealing fluid is normally formed by mixing sealing materials with carrying fluid in a tank at a rig site. Connected to the tank, there may be a hopper and a pump. During mixing, the pump continuously pumps the carrying fluid from the tank to the hopper. The sealing materials are added into the tank of carrying fluid through the hopper. There is a jet in the hopper that can create a vacuum when the carrying fluid flows through it at a high speed. The vacuum pulls the sealing materials into the flowing stream to the mixing tank. In the tank, there may be an agitator to help mix the fluid and keep the sealing materials suspended in the fluid before being pumped out of the tank. After being mixed, the sealing fluid is normally pumped with a mud pump to the subterranean fractures through drill pipe set inside a wellbore close to the fractures. It is most likely that the total volume of the sealing fluid is not large enough to reach the fractures by pumping the fluid only. In this case, a second fluid called a displacing fluid such as drilling fluid can be pumped behind the sealing fluid to displace it to the fractures. Other than drilling fluid, water, oil, completion fluid, seawater, brine, synthetic oil, diesel, cement slurry or any other oilfield fluid may be pumped to displace the sealing fluid to the fractures.
Sometimes, a different fluid called as a spacer fluid may be pumped between a sealing fluid and a displacing drilling fluid or a drilling fluid originally in a wellbore in order to avoid possible incompatibility issues between the sealing fluid and the drilling fluid. But a spacer fluid generally is not a sealing fluid. However, a spacer fluid pumped behind the sealing fluid is also a displacing fluid.
It is intended that sealing fluid is pumped to a fracture and seal the fracture. However, at the time of treating the fracture with sealing fluid, the operator generally does not know the size of the fracture.
In order for a seal to hold a large pressure differential, the sealing materials are often rigid and strong particulate materials. With fracture sizes unknown, the selected seal materials often do not match with the fracture sizes. When the fracture is too narrow, the seal materials will not be able to get into the fracture so the seal can only form at the entrance of the fracture inside a wellbore. When this happens, the fracture is only sealed temporally. The seal is soon removed when the drill pipe moves up and down in the wellbore and the well begins to lose circulation again. When the sealing materials are smaller than fracture width, the sealing fluid can simply flow into the fracture and flow away without forming a seal. Only when the sealing materials have a size basically matching that of a fracture can a seal easily form. However it is very challenging to match a fracture size with a sealing material when the fracture size is unknown. The industry has been in a trial-and-error mode for curing lost circulation and this challenge has caused many lost circulation jobs to fail.
This problem may have been mitigated somewhat by adding some larger soft sealing materials such as fiber, foam rubber, sponge, etc. to smaller rigid sealing materials. With these soft sealing materials, the required exact match of size seems to be loosened up a little. While being pumped into a fracture, these larger soft sealing materials, if they are not too much larger than the fracture width, may still be pushed into a fracture and engage the fracture faces and stop moving forward in the fracture. Then the larger soft sealing materials may initiate a bridge inside the fracture while the carrying fluid is still flowing through the bridge down into the fracture. With the continuous flowing-in of the carrying fluid, more of the smaller rigid sealing materials, when they are smaller than the fracture, then may be carried to the bridge and stopped from further flowing away. Eventually enough of the sealing materials accumulate behind the bridge and form a seal. However, when the larger soft sealing materials are too much larger than the fracture width, the seal still tends to form at the entrance of the fracture inside the wellbore. Due to the concern, an operator tends to refrain from selecting a too large size of the larger soft sealing materials. Similarly, when the larger soft sealing materials are smaller than the fracture, a seal still can hardly form. In order to form a strong seal and form the sealing inside a fracture, it is still obvious that matching the fracture size seems to be very important. Even with soft sealing materials, failed jobs of curing lost circulation caused by the above mentioned challenge are still often observed, even if the sealing materials seem to be perfect for sealing in a lab when the fracture size and shape are known.
Furthermore, a fracture, especially an induced fracture, may change its width or be inflated substantially when some fluid is pumped into the fracture, especially if the fluid is pumped under high pressure. A wellbore normally always contains drilling fluid. Pumping sealing fluid from surface to a fracture has to displace some drilling fluid into the fracture first before sealing fluid can be pumped into the fracture. This drilling fluid pumped into the fracture ahead of the sealing fluid can inflate the fracture and widen its width substantially before the sealing materials reach the fracture. This makes it even harder to match the size of a fracture with a sealing material without a consistent method based on fundamental understandings as taught by this disclosure.
In this disclosure, an innovative pumping procedure is disclosed to facilitate the required matching of the size of sealing materials to a fracture and ensure seals formed inside a fracture to cure lost circulation.
The width of fractures, especially induced fractures, responds to pressure of the fluid invading the fractures. This initial fracture width or size can be called as the original fracture size. When more fluid is pumped into a fracture, the pressure pushes the fracture wider. This widened fracture then has a dynamic size. When the pressure reduces, the fracture may close back to its original size. When pump is shut down, fluid in a fracture may leak into the rock matrix, cracks or flow away down the fracture causing the pressure to decrease naturally over time. The invented method is to utilize this response to first open a fracture wide enough to accept sealing materials, second, pump in sealing materials, and third, shut down the pump (decreasing fluid pressure) to let the fracture close to initiate a seal inside the fracture rather than at the entrance. Furthermore, the soft sealing materials such as sponge, if any, can fit the fractures or other voids better by restoring its size and shape when the force from the carrying fluid applying to the soft sealing materials is removed when the pump is shut down. When the soft sealing materials become larger, they are more likely to engage the fracture faces and help to initialize a seal. The method then continues to a fourth step by resuming to slowly pump to maintain an increasing pressure differential across the initialized seal to continue to deposit more sealing materials to the seal and pack the seal strong enough to hold certain pressure. This can increase the wellbore strength as discussed below.
With this method, it is therefore not important anymore to select the sealing materials of exactly the same size as the original fracture size. In contrary, as long as some of the sealing materials have a size larger than the original fracture size, it can form a seal inside the fracture.
Sometimes, a sealing material of a known size is pumped very slowly to a fracture to evaluate the original fracture size. When some sealing is achieved, it indicates that the fracture size is not larger than the size of the sealing material. If no seal is achieved at all, it indicates that the fracture size may be larger than the selected sealing material. An original fracture size therefore can be estimated. Another way to estimate a size of void is by use of the loss of the weight on bit when the bit drills into the void. The sudden extension of the drill string is correlated to the loss of weight on bit with the famous Hooke's law. The extension calculated then is a direct indicator of the size of the void in the direction of the wellbore. Though any of the above methods may be estimates, one skilled in the art can appreciate the size of a fracture for a range such as in millimeters, a fraction of an inch. With this estimate, selecting a sealing material larger than this size then is simple and easy. Since it is much less challenging to select some sealing materials of a size larger than a size, even if estimated, it is obvious that the invention has an advantage over conventional sealing method.
In order to better seal a fracture of an unknown size, a sealing material selected may have some particulates, rigid or soft, larger than an estimated original fracture size. In one embodiment, an original fracture size is estimated. In one embodiment, the sealing fluid that has some of the sealing materials of a size larger than the estimated original fracture size is selected.
With a selected sealing material in a carrying fluid being pumped to the vicinity of a fracture to be sealed the invented pumping procedure for forming a seal inside the fracture comprises the following steps:
Step 1: Pump to Initialize a Seal
In order to avoid forming a seal at the entrance (which will tend to be only a temporary seal as discussed above) and to form a seal inside a fracture, a high pump rate (barrels per minute) of pumping the sealing materials is used to create a high pumping pressure that can open the fracture wide. A device such as a packer or a blowout preventer (BOP) may be used to assist in the build-up of fluid pressure in the wellbore proximate to the fracture. The packer or BOP would be installed in the borehole above the fracture and closed before the sealing materials are pumped into the fracture. Furthermore, at a high pump rate, the force applied to the sealing materials is high and can deform the materials significantly, especially the soft sealing materials, and promote the flow carrying the sealing materials into the fracture. The pump rate is preferred to be higher than or equal to 2 barrel per minute. In one embodiment, it is 3 barrel per minute. In another embodiment, it is 5 barrel per minute. In another embodiment, it is as high as possible or as permitted. The barrel here is the US barrel equal to 42 gallons.
The upper wellbore may be cased off with a steel casing. The cased wellbore normally is strong. The uncased lower wellbore forms the open hole wellbore. Other than the fractures, there may be other weak points that have to be considered during pressurizing the wellbore so that these weak points will not break down when pumping the sealing fluid. A typical weak point is the previous casing shoe, where the open hole wellbore starts. The lowest pressure rating for any possible weak points except the fracture to be sealed is the pressure limit for pumping the sealing fluid. A pump rate should be limited by the pressure limit.
When a wellbore is partially losing returns, without control, sealing materials may be carried, rather than to a fracture, upward toward surface through the annulus after being pumped out of drill pipe and into the wellbore. In order to avoid this, the annulus of the wellbore is normally isolated by a device such as a packer or a blowout preventer (BOP). The packer or blowout preventer may be positioned above the location of the fracture. After the annulus is isolated, the pumped fluid can only flow to the fracture where the least resistance exists. This will also increase the pressure on the fracture faces and push the fracture to open wide.
The maximum pressure a wellbore can hold can be called its wellbore strength. A wellbore that can contain only a low pressure value is a weak wellbore. After the leaky fractures are sealed and the wellbore can contain more pressure, the wellbore is strengthened. It is typical that there is a required wellbore strength to be achieved before pumping a sealing fluid to seal the fractures. The wellbore pressure a wellbore can hold when some sealing materials have been pumped into fractures may be used to tell if the required wellbore strength has been achieved.
In a severe lost circulation situation, no returns of drilling fluid will be observed regardless how fast the pump rate is. In such as case, the fractured wellbore interval is weak and capable of holding only a certain low pressure or a certain height of drilling fluid column. More fluid pumped into the wellbore will automatically flow away through the fractures. So fluid level may be way below the surface and wellbore pressure or the hydrostatic head or the fluid column height in the wellbore remains basically constant. In such a situation, sealing fluid pumped down into the wellbore can hardly travel upward and it can only travel down to the fractures. So in such a situation, isolating the annulus with a packer or BOP is not necessary. The fluid level and wellbore pressure will rise with more fluid pumped in basically only after seals to these fractures are initialized.
The volume of sealing fluid intended to be pumped into the fractures at a high rate is preferred to be at least 1 barrel. In one embodiment, the volume is 20 barrels. In another embodiment, the volume is 10 barrels.
During pumping, the sealing materials are pushed into fractures at a specific high pump rate and the pump pressure may increase to reach a pressure limit or rating. In this case, the volume to be pumped into the fractures is dictated by the pressure limit. (Recall the pump rate is controlled by the pressure limit.) In one embodiment, the pump is stopped when only 40% of the designed volume is pumped into fractures. This occurs when the pressure is approaching the pressure limit. A pressure limit can be selected utilizing the method discussed above. In another embodiment, the pump rate is reduced to delay reaching the pressure limit in order to pump more of the sealing materials into fractures.
After pumping sealing materials into fractures, the pump is stopped or shut down to wait for at least 5 minutes to promote the accumulation of the sealing materials within the fracture. It will be appreciated that there is still a pressure gradient and fluid (carrying sealing materials) continues to flow into the fracture at the time of pump shut-down. The accumulation of the sealing materials inside a fracture is a filtration process. When the pump is shut down, with some of the sealing fluid continuing to flow away along the fracture or to leak into the pores of the rock, the pressure will gradually decrease and the fracture will slowly close. The soft sealing materials such as sponge, if any, will gradually restore its size and shape at the same time. Somewhere the pressure will become low enough to cause the fracture width to become narrow enough and/or the soft sealing materials to become large enough so that the large sealing materials start to engage the fracture faces and stop moving forward along with the carrying fluid, forming a bridge. With the continuous slow flow of the carrying fluid, more small sealing materials are carried to the bridge to accumulate enough to initialize a seal.
When the sealing materials are large enough relative to the fracture size, a seal may be initialized while pumping the sealing materials into a fracture. In this case, if some of the sealing materials larger than the fracture are rigid, the seal tends to form at the entrance of the fracture. However, when the large sealing materials are only the soft materials such as the sponge, the seal may still form inside the fracture.
The longer the waiting period is after the pump is stopped or shut down, the more sealing materials can accumulate and the better the seal initialization. However, it is normally not necessary to stop the pump (shut down) for over 5 hours. In one embodiment, the shut-down period is 5 minutes. In another embodiment, the shut-down period is 20 minutes. In another embodiment, the shut-down period is 2 hours.
An injection test can be performed before pumping the sealing fluid to benchmark the pressure pumping into a fracture at different pump rates and the pressure fall-off after the pump is shut down. The injection test generally is done by injecting drilling fluid into the loss zone fractures. Without seals in the fractures, drilling fluid can easily flow away through these fractures from the wellbore. It is therefore obvious that the pressure will be relatively low at this time. After shutting down the pump, the low pump pressure can fall even further. This injection test can be performed at several different pump rates to have a broad understanding of the fracture behavior. The recorded results of the pressure at different pump rates can be used to evaluate the pressure response when the sealing fluid is injected into the fractures by comparison.
Seal initialization can be indicated by pump pressure comparison, i.e., comparison of hydraulic pressure during pumping in and after pump shut down. The comparison can also be done with the results of an injection test. The comparison of pumping-in pressure is preferred to be done with the same pumping-in rate for a clear and easy understanding. However, the comparison of pressure fall-off after pump shut down does not require similar conditions. Sometimes, sealing may be initialized and observed while pumping a sealing fluid into a fracture at a constant pump rate. When a seal is being initialized while pumping, the pump pressure starts to increase with pumping. This is an indicator of seal initialization. Otherwise the pump pressure will remain basically constant. If a seal has been initialized during the pump shut down period, when pumping resumes at the same pump rate as before, the pumping-in pressure will be higher than the previous pumping-in pressure (before the pump was shut down) and more likely the pressure also continues to increase with the resumed pumping. This is another indicator of seal initialization. Furthermore, when a seal has been initialized, the pump pressure at the shut-down period will fall off at a slower pace than that for when the seal has not been initialized or the pump pressure at the shut-down period seems to fall toward a higher stabilized pressure level. This is the third indicator of seal initialization. In one embodiment, the pressure is closely monitored and an indicator of seal initialization is looked for throughout the seal initialization period.
The pressure preferred to be monitored is the fluid pressure in a wellbore proximate to the entrance of the fracture. However, it is normally difficult to put a sensor there to measure this wellbore pressure directly. Pump pressure therefore is often used to deduce this wellbore pressure. Sometimes, a pressure sensor in the annulus below the BOP can also be used to deduce this wellbore pressure. Though rare, it is also possible that there is a pressure sensor downhole on the drillpipe. This pressure can also be used to deduce the wellbore pressure proximate to the fracture. For example, the wellbore pressure at the fracture is basically equal to the annulus pressure measured right below the BOP plus the fluid hydrostatic head from the fluid column between the annulus pressure sensor location at the BOP and the fracture location. No matter where the pressure is measured directly, it can normally be well appreciated by those skilled in the art for the needed wellbore pressure proximate to the fracture. Furthermore, it is often not the exact value of the pressure but the change of the pressure that is what is needed for understanding seal initialization. Therefore, it is not intended to differentiate the pressure in the description of the invention. When pressure is monitored, it can be monitored by an annulus pressure sensor, a pump pressure sensor, a downhole pressure sensor or any or all of the above. They should all reveal the same wellbore pressure proximate to the fracture to one skilled in the art.
This alternating pumping-in and pump shut-down cycle can be repeated several times in order to ensure the seal has been initiated, preferably 3 times or until the seal initiation indicated by pump pressure. In one embodiment, this pumping-in and shut-down cycle is repeated once. In another embodiment, this cycle is repeated until the indicator of seal initialization has been observed. In another embodiment, this cycle is repeated until the pump pressure has reached the pressure limit even though the pump rate has been reduced to 2 barrels per minute. Recall the lowest pressure rating for any possible weak points except the fracture to be sealed is the pressure limit for pumping the sealing fluid. A pump rate should be limited by the pressure limit.
When the alternating pumping-in and pump shut-down cycle is repeated, it is preferred that the volume of sealing fluid into fractures is reduced in the pumping period in order not to disrupt the potential seal initiated by a previous pumping-in and shut-down cycle. In one embodiment, each cycle has a pumping-in volume of 1barrel less than that of its previous cycle. In another embodiment, the current cycle has a pumping-in volume only half of that of its previous cycle.
Step 2: Pump to Grow the Seal
After the seal initialization within a fracture, a period of slowly increasing pump pressure to grow the seal back toward the wellbore follows. The initialized seal formed by a pack of sealing materials can hardly be perfect and it still can let carrying fluid to go through. When more carrying fluid goes through the initialized seal, more sealing materials are carried to the seal and deposited onto the seal. “Grow the seal” means letting more of the sealing materials accumulate to the initialized seal to increase the thickness of the seal.
In order to grow the seal, pumping a small volume at a low rate into the wellbore, then shutting-down (stopping) the pump is preferred. This small volume into the wellbore can increase the wellbore pressure to increase the pressure differential across the initialized seal for further filtration to happen and more particulates to accumulate over time. In this period, with increased pressure, the fracture is widened and more sealing materials are packed onto the seal in the fractures. When the seal is getting thicker, the pressure differential required to continue the filtration is higher. Therefore it is often necessary to repeat this alternating pumping-in and shut-down cycle multiple times to increase the pressure differential across the seal along with the growth of the seal in order to keep a decent growth rate of the seal.
The small volume is preferred to be less than 5 barrels. In one embodiment, the volume is 2 barrels. In another embodiment, the volume is 1 barrel. The small volume can be defined by a pump pressure increment such as 25 pounds per square inch (psi). Once the pressure increment is reached, the pump then is shut down for a period of time. In one embodiment, the pressure increment is 25 psi. In another embodiment, the pressure increment is 50 psi. In another embodiment, the pressure increment is 250 psi. In another embodiment, the pump is shut down when either 50 psi pressure increment or 2 barrels of volume is reached first. The low volume rate is preferred to be less than 1 barrel per minute. In one embodiment, the rate is 0.25 barrel per minute. In another embodiment, the rate is 0.5 barrel per minute. The pump shut-down period following each pumping-in period is necessary and it is preferable to be from 5 to 30 minutes and longer the better. In one embodiment, it is 10 minutes. In another embodiment, it is 20 minutes. Recall that wellbore fluid pressure can be monitored during the shut-down period. It is a goal that pressure will drop off slowly during this shut-down period.
This alternating pumping-in and shut-down cycle can be repeated. In one embodiment, it is repeated three times. In another embodiment, it is repeated over and over until the pump pressure reaches a target value. This reached pressure value can be used as an indicator of the strength of the seal formed. It is therefore typical to eventually pump in fluid to reach a pressure value equivalent to the required wellbore strength to check if the target wellbore pressure can be held by the wellbore.
After the pressure reaches the target value, a long period of shut-down period may follow to further ensure that a seal is well formed. This long period is preferred to be from 30 to 250 minutes. In one embodiment, this long period is 60 minutes. In another embodiment, this long period is 120 minutes.
Step 3. Remove the Excess of the Seal
Some seals may grow back to inside the wellbore. This may later interfere with drilling operations and the excess of the seals inside the wellbore needs to be removed. This is done, after removing the packer or opening the blowout preventer (BOP), by rotating a drill bit in the zone of the fractures while circulating drilling fluid. After the excess of the seals is removed, a thin layer of drilling fluid cake may form on the seal newly exposed to the wellbore drilling fluid to have the seal protected and further tightened.
The following is an example of the implementation of the disclosure. It is one example only. It will be appreciated that it does not limit the scope of the disclosure. The disclosure is defined by the accompanying claims as they may be amended.
1. Define the target pressure equivalent to the required wellbore strength, Ptarget (e.g. Ptarget=750 psi)
2. Define the pump pressure limit, Plimit (e.g. Plimit=1000 psi) based on a weak zone (at the previous casing shoe) second to the loss zone.
3. Define the highest pump rate that has the corresponding pressure right below the pressure limit 1000 psi as 7.5 barrel per minute (by such as an injection test at such as 3, 5, 7.5 barrel per minute).
4. Estimate the original fracture size.
5. Select a sealing material some of which has a size larger than the estimated original fracture size.
6. Mixing 70 barrels of sealing fluid with the selected sealing material and carrying fluid in a mixing tank.
7. Close BOP to isolate the annulus.
8. Pump the sealing fluid from the mixing tank into drillpipe and displace it with drill fluid to the vicinity of the loss zone at a rate of 7.0 barrel per minute.
9. Pump to initialize a seal
10. Pump to grow the seal
11. Remove the excess of the seal: Ream through the loss zone with a drill bit at 100-200 feet/hour with mud circulation.
This specification is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the manner of carrying out the invention. It is to be understood that the forms of the invention herein shown and described are to be taken as the presently preferred embodiments. As already stated, various changes may be made in the shape, size and arrangement of components or adjustments made in the steps of the method without departing from the scope of this invention. For example, equivalent elements may be substituted for those illustrated and described herein and certain features of the invention maybe utilized independently of the use of other features, all as would be apparent to one skilled in the art after having the benefit of this description of the invention.
While specific embodiments have been illustrated and described, numerous modifications are possible without departing from the spirit of the invention, and the scope of protection is only limited by the scope of the accompanying claims.
