Method of and apparatus for drilling a subterranean borehole

Method of and Apparatus for Drilling a Subterranean Borehole

Full description

Background of the invention

The present invention relates to a method for drilling a subterranean borehole. A drill hole or well is typically drilled using a steel pipe known as a drill pipe or drill pole with a drill string with a drill bit on the lowermost end of it. The drill shaft includes a series of tubular sections, connected from one end to the other.

The drill string can be completely rotated using a rotary table, or using a ground drill motor mounted on top of the drill pipe, typically known as a "top-drive", or the drill bit can be rotated separately from the drill string Using a fluid-driven motor or motors installed in the drill shaft directly above the drill bit. As drilling progresses, a flow of silt is used to carry debris resulting from the drilling process out of the drill hole. Silt is pumped down the shaft, passes through the drill bit, and returns to the surface through the annular space between the outer diameter of the drill shaft and the drill hole (commonly referred to as the annulus). Mud flow also serves to cool the drill bit, and to pressurise the borehole, thus largely preventing the entry of fluid flow, from formations into which the drill shaft penetrates, into the drill hole. The term mud is a very broad drilling term in the context in which it is used to describe any fluid or fluid mixture used during drilling and covers a wide range of air, nitrogen, foamed fluids with air or nitrogen, fluids formed with air or nitrogen, Fluids exposed to air or nitrogen are heavy weighted mixtures of oil and/or water with solid particles.

Significant pressure is needed to push the mud along the flow path, and to achieve this, the mud is typically pumped into the drill column using one or more positive displacement pumps connected to the top of the drill string through a pipe and manifold. Therefore, the rate of mud circulation down the drill pipe and upward through the well bore is determined by the operating speed of those pumps.

The pressure of the mud at the bottom of the well bore ("bottom hole pressure") is usually monitored in an effort to ensure that it is sufficient to reduce or eliminate the risk of formation fluid entering the well bore in an uncontrolled manner commonly known as In the term “well surge”, also to ensure that it is not so high that there is a risk of fracturing the formation and/or pushing silt into the formation.

While the main mud flow into the wellbore is achieved by pumping mud into the main bore at the upper end of the drilling column, it is also known that the drilling column is supplied with a side hole extending to the main hole from an opening provided in the side of the drilling column, so that it can be pumped Silt into the main hole at an alternate position to the top of the drill string.

For example, as drilling progresses, and the drill hole becomes deeper and deeper, it is necessary to increase the length of the drill column, and this is typically achieved by disconnecting the top-drive from the top of the drill string, adding a new section of piping to the drill column, and engaging the top-drive With the free end of the new pipe section, then re-start drilling.

Therefore, it can be recognized that if mud pumping down the shaft occurs only through the main bore at the upper end of the shaft, it will be necessary to stop pumping during that process.

Stopping mud flow in the middle of the drilling process causes problems for a number of reasons, which is why it has been proposed to facilitate the continuous pumping of mud through the drilling column through a side hole in each part of the drill string. This means that mud can be pumped into the drill shaft through the side hole while the top of the drill string is closed, the top-drive is disconnected and the new drill string is connected.

In such a system, as disclosed in U.S. Patent No. 2,158,356, at the top of each portion of the drill shaft, a side hole is provided closed with a plug, and a valve member positionable between a first position where the side hole is closed and the main hole is bore for the drill shaft open, and a second position where the side hole is open while the main hole is closed. During drilling, the valve is held in the first position, but when the time comes to increase the length of the drill shaft, the plug is removed from the side hole, and a hose, extending from the pumping, is connected to the side hole, and the valve in the hose is open so that the silt begins to be pumped to Drill shaft through side hole. Next, the valve in the main hose from the pump to the top of the drill string is closed, and the silt pressure at the side hole causes the valve member to move from the first position to the second position, thus closing the main bore of the drill string. .

Next, the main hose is disconnected, the new section of tubing is mounted on the drill shaft, and the main hose is connected to the top of the new section. The valve in the main hose is opened so that mud pumping is restarted to the top of the drill string, and the valve in the hose to the side hole is closed. The pressure from the mud entering the top of the drill string causes the valve member to return to its initial position, allowing the hose to be removed from the side hole, without significant leakage of mud from the drill string.

The side hole can then be permanently sealed, for example, by welding a plug to the side hole, before lowering that part of the drilling shaft into the well.

The drilling shaft may also be provided with a side hole in what is known as “pumping in a branch connection”, and is used in an emergency situation, for example, to facilitate the provision of additional mud pressure required to control a sudden surge in well bore pressure due to fluid flow in, from a permeable formation The well goes to him, and the well enters what is called a “kick.”

This type of drilling is generally known as continuous circulation drilling.

General description of the invention

The invention includes a method for drilling with continuous rotation, where the rate of rotation of drilling mud is related to the speed of rotation of the drill pipe.

According to a first aspect of the invention, a method for drilling a subterranean borehole is provided comprising:

A) Pumping a drilling fluid down a drill string, and the drill string has a drill bit at an end thereof,

b) Rotating the drill string around its longitudinal axis so that the bit forms a bore hole in the ground,

The method also includes the following steps:

c) Changing the rate of pumping of the drilling fluid in the drill column in response to a change in the speed of rotation of the drill string, and/or changing the speed of rotation of the drill string in response To change the rate of pumping of the drilling fluid in the drilling column.

Well bore bottom hole pressure depends on various factors. When there is no silt flow, it is determined by the pressure from the constant weight of the silt column in the wellbore. When silt is pumped down the drill pipe into the wellbore, there is an increase in bottom hole pressure due to the frictional effects resulting from the rotation of the drill pipe. This effect is significant as it constitutes a large percentage, specifically 10% to 40% of the previously described frictional effect. Therefore, by linking the drilling mud rotation rate to the speed of the drill pipe rotation, an increase in bottom hole pressure resulting from an increase in the drill pipe rotation speed can be reversed due to a decrease in bottom hole pressure (BHP) resulting from a decrease in Drilling mud turnover rate, or vice versa. As a result, improved BHP control can be achieved. This is an important requirement for drilling a well with a small drilling window as determined by the hole pressure gradient, fracture gradient and drill hole collapse pressure, which is dictated by the physical properties of the drilled formation.

In one embodiment of the invention, the rate of pumping of the drilling fluid increases as the speed of rotation of the drill string decreases, the rate of pumping of the drilling fluid decreases as the speed of rotation of the drill string increases, and/or the rotation speed of the shaft increases Drilling when the drilling fluid pumping rate decreases, and the drilling shaft rotation speed decreases when the drilling fluid pumping rate increases.

The method also includes the following steps:

d) Stop the rotation of the drill shaft.

e) Pumping the drilling fluid into a side port adjacent to the upper end of the drilling column,

f) Stop pumping drilling fluid to the upper end of the drilling column,

g) Connecting a new drill pipe section to the upper end of the drill shaft,

h) Start pumping the drilling fluid to the upper end of the new part of the drill pipe,

i) Stop pumping drilling fluid into the side hole, and

j) Resuming the start of drilling column rotation.

In this case, it is preferable to increase the rate of fluid pumping to the drill column when the speed of rotation of the drill string decreases in step D, and the rate of pumping fluid to the drill column decreases when the speed of rotation of the drill string increases in step J.

In one embodiment of the invention, the method further includes directing the drilling fluid emerging from the drill hole along a return line in the annular space, and changing the fluid pressure in the well bore by changing the degree of restriction of fluid flow along the return line in the annular space.

In one embodiment of the invention, the method further includes measuring the fluid pressure at the bottom of the drilling hole, and varying the rate of pumping of the drilling fluid in the drilling column to bring the measured pressure to a preferred level.

In one embodiment of the invention, the method further includes automatically changing the rate of pumping the drilling fluid into the drilling column in response to a change in the rotational speed of the drilling column, or automatically changing the rate of pumping of the drilling fluid into the column. Drilling.

According to a second aspect of the invention, an apparatus for drilling a drill hole is provided comprising a down a drill string, a rotator that rotates the drill string along its longitudinal axis, a pump that pumps drilling fluid into the drill string, and a rotator control unit that operates On controlling the rotor to change the speed of rotation of the drill string, and a pumping control unit that works to control the pump to change the rate of pumping of the drilling fluid in the drilling column, it is characterized by the fact that the unit The rotator control and the pumping control unit are in communication such that the pumping control unit automatically changes the rate of pumping of the drilling fluid into the drilling column in response to a change in the rotation speed of the drill column, and/or the rotator control unit automatically changes the rotation speed Drilling column in response to a change in the rate of pumping drilling fluid into the drilling column.

In one embodiment of the invention, the circulator control unit is an electronic circulator control unit, the pumping control unit is an electronic pumping control unit, and there is an electrical connection between the circulator control unit and the pumping control unit, to provide transmission of a control signal between Top-drive controller and pump controller.

The pumping control unit is programmed to monitor this signal and automatically change the operating speed of the pump according to the instructions given in the control signal.

In one embodiment of the invention, the upper circulation control unit is programmed to send a control signal that directs the pumping control unit to reduce the operating speed of the pump when the rotational speed of the drill pipe increases, and to increase the operating speed of the pump when the rotational speed of the drill pipe decreases. In this case, the rotor control unit is programmed to send to the pumping control unit a control signal that directs the pumping control unit to either increase or decrease the operating speed of the pump based on whether the drill pipe rotational speed is decreasing or increasing.

The pumping control unit can be programmed to monitor this signal and automatically change the pump's rotational speed according to the instructions given in the control signal.

The rotator control unit can be programmed to send a control signal to the pumping control unit that directs the pumping control unit to reduce the rotational speed of the pump when the rotational speed of the drill pipe increases, and to increase the rotational speed of the pump when the rotational speed of the drill pipe decreases.

The pumping control unit can be equipped with an input to receive a signal indicating the speed of rotation of the drill pipe.

The pumping control unit can be programmed to respond to a signal indicating that the drill pipe speed is decreasing as the pump rotation speed increases, or where more than one pump and one or more pumps are supplied, and vice versa.

In one embodiment of the invention, the rotor control unit and the pumping control unit are integrated into a single electronic control unit that serves to control the speed of rotation of the pump and the speed of rotation of the drill string.

In one embodiment of the invention, the controller, one or both controllers, have a pressure input to receive a signal from a pressure sensor located on the drill shaft which sends a signal indicating the fluid pressure in the drill hole to the controller or each controller connected to it.

In this case, the controller or each controller with said pressure input is programmed so that said pressure signal is used to determine whether the fluid pressure is at a preferred level and, if not, to make further adjustments to the pumping speed and/or drill shaft rotation speed. speed of rotation of the drill string to bring the fluid pressure to the preferred level or within an acceptable range.

In one embodiment of the invention, the controller, one or both controllers, have a flow input to receive a signal from a flow meter that sends a signal expressing the drilling fluid flow rate down the drilling column to the controller or each connected controller.

Alternatively, a flow measurement of fluid flow down the drill pipe by a pump stroke counter can be used as a measurement to provide input to the control unit.

In one embodiment of the invention, the device further includes an annular space return line connecting the annular space in the drill hole around the drill column to a pressurized fluid reservoir, a valve and choke in the annular space return line, and an electronic choke control unit that controls the operation of A choke that can be adjusted to vary the restriction of fluid flow along the return line in the annular space.

Otherwise, the invention may be used in combination with available systems that control downhole pressure by backpressure control using a choke, such as the system described in U.S. Pat. No. 7,395,878. In such a system, backpressure control throttle operation may be used in addition to controlling The pump speed described above to achieve the desired bottom hole pressure.

Brief explanation of the drawings

Embodiments of the invention will now be described, by way of example only, by reference to the following figures where:

Figure 1 is a schematic illustration of an embodiment of a drilling rig operating according to the invention,

Figure 2 is a schematic illustration of an embodiment of a control device that may be used to operate the drilling rig shown in Figure 1 according to the invention, and

Figure 3 is a schematic illustration of an alternative embodiment of a drilling rig operating according to the invention.

Detailed description:

Referring now to Figure 1, a drilling rig 10 is shown with a top drive 12 attached to a down a drill string 14 extending from the drilling rig 10 down into a wellbore 16. A bottom hole assembly is provided ( BHA 18 at the bottom end of the drill string 14. The BHA 18 includes a drill bit and various sensors including, at a minimum, a pressure sensing device that transmits a signal expressing fluid pressure around a bottom hole assembly. assembly (BHA) 18. The BHA may also include 18 down-hole motors to drive rotation of the drill bit, as is known in the art.

As shown in Figure 1, a manifold 20 is mounted on the uppermost end of the drill pipe 14 and connected to a mud pump 22 through an outlet pump or hose 22a. The mud pump 22 is connected to the mud reservoir 24 through an inlet pipe or hose 22b such that operation of the mud pump 22 causes mud to be pumped from the mud reservoir 24 along the inlet pipe 22b and outlet pipe 22a and into the main bore of the drill pipe 14 through Manifold manifold 20. A channel (not shown) was provided to return the mud to the tank (pumped from the mud reservoir 24) after rotating down the main bore of the drill pipe 14, and back to the top of the ring 15.

The drill pipe 14 is also provided at its upper end with a side hole and a continuous circulation valve assembly 26 that is movable between a first position where the main bore of the drill pipe 14 is open and the side hole is largely closed, and a second position where the main bore of the drill pipe 14 is open and the side hole is largely closed. The main bore is largely closed and the side bore is open. Valve assemblies are disclosed in US Patents 2,158,356, UK 2,426,274, and UK 2,427,217. The side hole is equipped with a bore with a connector 28 to which an auxiliary outlet hose (not pictured for clarity) from the mud pump 22 can be connected, to facilitate the pumping of mud into the main bore of the drill pipe 14 through the side hole while connecting a new pipe end. At the uppermost end of drill pipe 14.

The top-drive 12 rotates the drill string 14 about its longitudinal axis, and various examples of suitable top-drivers 12 are well known in the art. Such a top drive 12 is disclosed in US Patent No. 6,050,348, for example, and the invention will be described with reference to this type of top-drive.

The drilling rig type 10 can be used for open hole drilling.

An alternative embodiment of a drilling rig 110 that can be used to exploit the invention is illustrated in Figure 3. As shown in an embodiment of Figure 1, a top drive 112 is connected to a drilling shaft 114 extending from the drilling rig 110 down to a wellbore 116 A bottom hole assembly (BHA) 118 is provided at the lower end of the drill shaft 114. In this case, the manifold 120 is connected to the mud pump 122 through an outlet pipe or hose 122a at the upper end of the drill shaft 114, and the top-drive 112 is connected to the drill shaft 114 below the manifold 120. The mud pump 122 is connected to a mud tank mud reservoir 124 through an outlet pipe or hose 122b such that operation of the pump 122 causes mud to be pumped from the mud reservoir 124 along the inlet pipe 122b and outlet pipe 122a to the main bore of the drill shaft 114 through the manifold 120.

The drilling shaft 114 of this embodiment of the invention is also usefully provided at its upper end with a side hole and a continuous circulation valve assembly, but is not included in the depiction, for clarity.

In this embodiment of drilling rig 10, the well bore 116 is covered by a wellhead 146 and a closure device 144 such as a blow out preventer (BOP) or rotating control device (RCD). The drill shaft 114 extends through the well head 146 and the closure device 144, and the closure device 20 has seals that close around the outside of the drill shaft 114 to provide a substantially fluid-tight seal around the outside of the drill shaft 114 while allowing rotation of the drill shaft. About its longitudinal axis, it also moves down into the well bore 116. Together, the well head 146 and closure device 144 contain fluid in the annular space around the drill shaft 114 (ring 115).

The well head 146 includes a side port 146a connected to a return line in the annular space 148, which provides an outlet for fluid from the annulus 115. The return line in the annular space 148 extends to the reservoir 124 through a choke Or a valve that can be adjusted 150 and a flow meter (such as a Coriolis flow meter) that is after the throttle/valve 150. Filters and/or shakers (not shown) are generally provided to remove particulate matter such as drill cuttings from the drilling fluid before returning to the reservoir 124.

For the drilling rig model 10, 110, during drilling, the top-drive rotor 12, 112 rotates the drilling shaft 14, 114 about its longitudinal axis so that the drill bit cuts into the formation 11, 111, and the pump 22, 122 is operated to pump the drilling fluid From the reservoir 24, 124 to the manifold 20, 120 and to the drill shaft 14, 114 where it flows to the annulus 15, 115 through the bottom hole assembly (BHA) 18, 118.

In one embodiment of the drilling rig shown in Figure 3, silt and drilling cuttings flow up the annulus 115 to the well head 146, and to the return line in the annular space 148, and the choke or adjustable valve 150 can be operated so that the flow is restricted. Drilling fluid along the return line in the annular space 148, thus applying back pressure to the annulus 115. The backpressure may be increased until the fluid pressure at the bottom of the well bore 116 (bottom hole pressure) is sufficient to contain the formation fluids in the formation 111 while minimizing the risk of fracturing the formation or causing drilling fluid to penetrate the formation. The fluid flow rate out of the annulus 115 is monitored using a flow meter 152 and compared to the flow rate into the drill column 114, and that data can be used to detect well surge or just the hole fluid into the formation.

The drilling type is known as managed pressure drilling (MPD) and is disclosed in US Patent No. 6,575,244, US Patent No. 7,044,237, and US Patent No. 7,395,878, as examples.

The invention provides a means of controlling bottom hole pressure (BHP) using an open-hole drilling rig shown in Figure 1, and an additional means of controlling bottom hole pressure (BHP) in a pressure-controlled drilling rig as described above in connection with Figure 3.

Figure 2 is an illustration of a schematic illustration of an embodiment of a control device that may be used to control the operation of any of the drilling rigs 10, 110 shown in Figures 1 or 3. In embodiments of the invention, the operation of the top-drive rotor 12, 112 is controlled by a control unit Electronic control unit (ECU) 30, which in this example includes a microprocessing unit 32, an input device 34 such as a keyboard, or a drive shaft and a display device 36 such as a screen.

A rotational speed sensor 38 was also provided that provides an electrical signal expressing the speed of rotation of the drill string 14, 114.

The rotating speed sensor 38 may, for example, be a special sensing device as described in US Patent No. 6,050,348, but any other device that detects and measures the rotational speed of an object may be used instead. The speed sensing device 38 is electrically connected to the microprocessing unit 32 so that the electrical signal produced by the speed sensing device 38 that expresses the speed of rotation of the drill string 14, 114 can be sent to the microprocessing unit 32.

The microprocessor 32 is programmed as described in US Patent No. 6,050,348 to change the speed of rotation of the drill string 14, 114, and an actuator may use an input device 34 to issue instructions to the microprocessor 32. To switch the rotation speed of the drill pipe shaft 14, 114. For example, an actuator may use the input device 34 to stop the rotation of the drill string 14, 114 when a new portion of the shaft needs to be connected to the top of the drill string 14, 114.

Another electronic control unit (ECU) has also been provided for the pump 40, through which the rotational speed of the mud pump 22 and 122 is controlled. These electronically controlled pumps are also well known in the art.

In this embodiment of the invention, the top-drive electronic control unit (ECU) microprocessor unit 32 is electrically connected to the pump electronic control unit (ECU) 40, and is programmed to send to the pump ECU 40, a control signal that directs Instructs the pump ECU 40 to either increase or decrease the operating speed of the pump 22, 122. The pump ECU 40 is programmed to monitor that signal and automatically alter the rotational speed of the pump 22, 122 according to the instructions given in the control signal.

In this embodiment of the invention, the microprocessor 32 of the top-drive ECU 30 is programmed to send a control signal that instructs the pump ECU 40 to reduce the operating speed of the pump 22, 122 by increasing the speed of rotation of the drill shaft. the drill string 14, 114 (as determined using the signal from the speed sensor 38), or to increase the operating speed of the pump 22, 122 when the speed of rotation of the drill string 14, 114 is decreased.

In an alternative embodiment of the invention, the microprocessor 32 of the top-drive ECU 30 can have a further input of an electrical pressure signal from a pressure sensing device fitted on a bottom hole assembly (BHA) 18, 118. In this case, it can Programming the microprocessor 32 to monitor the pressure signal, and adjust the control signal according to the pressure signal. For example, when the rotational speed of the drill pipe 14 decreases, the microprocessing unit 32 sends to the pump electronic control unit (ECU) 40 a control signal that instructs the pump ECU 40 to increase the pump speed, if the pressure signal is from a means If the pressure sensor indicates that the bottom hole pressure (BHP) is actually decreasing, the microprocessor 32 can be programmed to modify the control signal to instruct the pump ECU 40 to increase the pump speed at a faster rate. Alternatively, if the pressure signal from the pressure sensing device indicates that the BHP is actually increasing, the microprocessor 32 can be programmed to modify the control signal to instruct the pump ECU 40 to increase the pump speed at a slower rate. Likewise, even if the drill pipe 14 rotation speed is increased, the microprocessing unit 32 sends to the pump ECU 40 a control signal instructing the pump ECU 40 to reduce the pump speed, if the pressure signal from the pressure sensing device is If the BHP actually decreases, the microprocessor 32 can be programmed to modify the control signal to direct the pump ECU 40 to reduce the pump speed at a slower rate. Alternatively, if the pressure signal from the pressure sensing device indicates that the BHP is actually increasing, the microprocessor 32 can be programmed to modify the control signal to direct the pump (ECU) 40 to reduce the pump speed at a faster rate.

It should be realized that the invention can be used in other ways. For example, the pump ECU 40 may be electrically connected to the speed sensing device 38 so that the signal indicating the rotational speed of the drill pipe 14 is received. If the pump electronic control unit (ECU) 40 is programmed to reduce the rotational speed of the pump 22 when the speed increases Drill pipe 14 rotation (as determined using the signal from the speed sensor 38, or by increasing the operating speed of the pump 22 when the drill pipe 14 rotation speed decreases. Alternatively, the top-drive ECU 30 and pump ECU 40 may share a common microprocessing unit that is programmed to operate as described above.

To use the present invention, algorithms can be developed that calculate the effect of pipe rotation friction F(pr) on the total friction factor F(T). The other component of friction is the well bore friction factor F(wb). The friction factors are not longitudinal and the process of forming a system like this reliably is a complex process as there are many variables such as the geometric shape of the pipe, the shape of the wellbore, the hardness of the drill pipe, the hardness of the wellbore, and the properties of the mud (Newtonian fluids versus non-Newtonian fluids, viscosity, etc.), and temperature affect the frictional forces present.

There is a relatively simple way for those skilled in the art of drilling wells, which is to perform a calibration procedure using the system to determine the relationship between the speed of rotation of the pipe and its effect on bottom hole pressure (BHP). This calibration can be performed at intervals during the well drilling, usually after the final casing (steel pipe) separating the wellbore has been placed and grouted.

This procedure will require a near-bottom pressure measurement as is commonly used in the industry and is called Pressure While Drilling (PWS).

With a constant pumping rate of the fluid being pumped, a series of scaled measurements are prepared with increasing rotation of the drill pipe in 20 revolution per minute (rpm) steps from zero to maximum (usually 200 rpm).

These 10 steps can be repeated for 5 to 10 different pumping rates from zero gallons per minute (gpm) to the maximum extent planned to drill that section.

This will produce a series of calibration data that can be fed into the microprocessor unit 32, and with this information the system can determine how to adjust the pump operating speed in response to changes in pipe rotation and still achieve the desired bottom hole pressure (BHP).

Alternatively, mathematical models relating drill pipe rotation speed to BHP can be used, such as those disclosed in:

SPE 135587 (“The Effect of Drillstring Rotation on Equivalent Circulation Density: Modeling and Analysis of Field Measurements”, Ramadan Ahmed et al) or SPE 20305 “Reduction of the Annular Friction Pressure Drop Caused by Drillpipe Rotation”, Yuejin Luo and JM Peden

By the control unit to determine how a change in drill pipe speed affects the BHP, and therefore any change in pump speed is required to balance it.

It should be understood that when applied during pressure-controlled drilling as described above in relation to Figure 3, the method's control of bottom hole pressure (BHP), mentioned above, can be used in addition to the control provided by the operation of a choke or adjustable valve. To set 150. Typically, the choke or adjustable valve 150 is electronically controlled using an electronic control unit (ECU), said ECU may be combined with a top-drive ECU 30 and/or pump ECU 40.

While in those embodiments of the drilling rig 10, 110, the use of a top drive 12, 112 is disclosed, it should be understood that the principles of the present invention apply to any rotating the drill string 14, 114 system, including A rotating table, for example. Furthermore, although the invention has been described with reference to the use of a single mud pump 22, 122, a plurality of pumps may be used with one or more of these controlled in accordance with the invention.

The invention may be enhanced by any means or coating that increases or decreases the friction factor F(pr). For example, a Teflon TM coated pipe can be used to reduce the frictional effects of the rotating drill pipe on bottom hole pressure (BHP), or fan blades can be used on the drill pipe body to increase the frictional effects of the rotating drill pipe. rotating drill pipe.

When used in this specification and in safeguards, the expressions “including,” “including” and their synonyms mean including special features, steps or integers. Expressions should not be construed to exclude the presence of other features, steps or components.