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Title:
REDUCED PRESSURE DROP IN WET GAS PIPELINES BY INJECTION OF CONDENSATE
Document Type and Number:
WIPO Patent Application WO/2021/066659
Kind Code:
A1
Abstract:
A method of reducing pressure drop between an inlet and an outlet of a flowline carrying a multiphase flow of gas and liquids, wherein at least 99% of the volume flow rate of the multiphase flow is gas, and wherein the liquids comprise water and hydrocarbon condensates; the method comprising: injecting hydrocarbon condensate to the multiphase flow.

Inventors:
JOHANSSON PETER SASSAN (NO)
KÖNZ FLURIN MATTIA (NO)
Application Number:
PCT/NO2020/050244
Publication Date:
April 08, 2021
Filing Date:
October 05, 2020
Export Citation:
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Assignee:
EQUINOR ENERGY AS (NO)
International Classes:
E21B43/00; F17D1/00
Foreign References:
US20100145115A12010-06-10
US5816280A1998-10-06
US5983915A1999-11-16
US20080023071A12008-01-31
Attorney, Agent or Firm:
MATTHIJS BRANDERHORST (GB)
Download PDF:
Claims:
CLAIMS:

1 . A method of reducing pressure drop between an inlet and an outlet of a flowline carrying a multiphase flow of gas and liquids, wherein at least 99% of the volume flow rate of the multiphase flow is gas, and wherein the liquids comprise water and hydrocarbon condensates; the method comprising: injecting hydrocarbon condensate to the multiphase flow.

2. The method of claims 1 , wherein the hydrocarbon condensate is injected at a subsea well head of a gas producing system, or wherein the inlet of the flowline is an inlet of a gas export pipeline.

3. The method of claim 1 or 2, further comprising injecting hydrate inhibitor at the inlet of the flowline.

4. The method of claim 3, wherein the hydrate inhibitor is monoethylene glycol, MEG, or triethylene glycol, TEG.

5. The method of any one of the preceding claims, wherein the gas is saturated with water at the flowline inlet at a temperature higher than 40°C

6. The method of any one of the preceding claims, further comprising prior to said injecting one or more of: removing water from the multiphase flow, wherein the water is in liquid phase; compressing the gas; passing the multiphase flow through a scrubber; and heating the gas.

7. The method of any one of the preceding claims, wherein the flowline inlet pressure is between 50 and 150 bara, and optionally 100 bara.

8. The method of any one of the preceding claims, wherein the total gas mass flow rate is in the range of 30 to 500 kg/s.

9. The method of any one of the preceding claims, wherein the amount of condensate added to the flowline is around between 0.1 to 3 kg/s, and optionally 2 kg/s. 10. The method of claim 4, wherein the mass flow rate of MEG or TEG is in the range of 0.1 to 2 kg/s.

11. The method of any one of the preceding claims, wherein the inlet temperature is between 40°C and 60°C.

12. The method of any one of the preceding claims, wherein injecting hydrocarbon condensate to the multiphase flow comprises varying the rate of hydrocarbon condensate injection and measuring the pressure drop with a pressure sensor at the inlet and a pressure sensor at the outlet, and empirically determining the optimal amount of hydrocarbon injection by determining the minimal pressure drop.

Description:
REDUCED PRESSURE DROP IN WET GAS PIPELINES BY INJECTION OF

CONDENSATE

Field of the invention

The invention relates to transporting gas from a hydrocarbon producing well, and more specifically to improving the efficiency of multiphase gas, water and condensate transport through a pipe.

Background

The term “natural gas” is used here to refer to gas extracted from underground reservoirs, where natural gas is often associated with oil deposits. Natural gas is a combustible mixture of hydrocarbon gases. While it is typically primarily methane, it can also include ethane, propane, butane and pentane. The particular composition will depend on the reservoir. It is well-known to extract natural gas from underground reservoirs, where natural gas is often associated with oil deposits. The reservoirs are frequently located under the seabed. When natural gas is extracted its temperature (e.g. 100° C) is significantly higher than that of the sea and its pressure (e.g. 80 bar) is much higher than atmospheric pressure.

In some wells, the extracted natural gas contains a significant amount of water, which is typically laden with impurities such as salts and minerals. These are removed from the gas in a dehydration/desalting process. Natural-gas condensates are preferably also removed before transport. Typically, some of the gas is inadvertently removed also, and this gas has to be re-pressurized and added back to the natural gas which was not removed. The re-pressurization process is carried out by re-compressors which consume significant energy, which is often supplied by burning fossil fuels.

Once the separation is complete, the natural gas is further compressed by one of more compressor stages to a much higher pressure (such as 100 bara) for transportation to the shore in a pipeline or on a container vessel. A proportion of the natural gas may be pressurized to a yet higher pressure (such as 200 bara) by an injection compressor for reinjection into the gas well to increase oil extraction. Again, both of these processes consume significant amount of energy, which is often supplied by burning fossil fuels. The process, as noted, consumes a large amount of energy. This is particularly true if the system includes drying and cooling units respectively before and after each compressor, as is common. Secondly, due to the fossil fuel which is used to generate the energy, the process generates a large amount of carbon dioxide (CO2) as a by product. Further, the pressure of a reservoir declines over time which means that more energy is required to transport the gas to a processing plant.

Statement of invention

According to a first aspect of the invention there is provided a method of reducing pressure drop between an inlet and an outlet of a flowline carrying a multiphase flow of gas and liquids, wherein at least 99% of the volume flow rate of the multiphase flow is gas, and wherein the liquids comprise water and hydrocarbon condensates; the method comprising: injecting hydrocarbon condensate to the multiphase flow.

The hydrocarbon condensate may, for example, be injected at a subsea well head of a gas producing system, or at an inlet of a gas export pipeline as a specific example of the flowline.

Optionally, hydrate inhibitor may be injected at the inlet of the flowline because the gas may be saturated with water at the flowline inlet at a temperature higher than 40°C. The expression ‘inlet’ used herein may refer to a set of different inlet channels and valves located, for example, near a well-head. The inlet channel into the flowline for hydrate inhibitor does therefore not need to be the same as the inlet channel for the gas, which again may be different from the inlet channel for the hydrocarbon condensates. Examples of hydrate inhibitors are monoethylene glycol, MEG, or triethylene glycol, TEG.

Prior to the step of injecting hydrocarbon condensate, one or more of the following steps may be carried out: removing free water from the multiphase flow; compressing the gas; passing the multiphase flow through a scrubber; and heating the gas.

The flowline inlet pressure may be between 50 and 150 bara, and optionally 100 bara. The total gas mass flow rate can be in the range of 30 to 500 kg/s. The amount of condensate added to the flowline is around between 0.1 to 3 kg/s, and optionally 2kg/s. The mass flow rate of MEG or TEG may be in the range of 0.1 to 2 kg/s. The inlet temperature can be between 40 and 60 °C.

Injecting hydrocarbon condensate to the multiphase flow may further comprise varying the rate of hydrocarbon condensate injection and measuring the pressure drop with a pressure sensor at the inlet and a pressure sensor at the outlet, and empirically determining the optimal amount of hydrocarbon injection by determining the minimal pressure drop.

Figures

Some embodiments of the invention will now be described by way of example only and with reference to the accompanying drawings, in which:

Figure 1 is a graph illustrating the relationship between water-cut and friction or pressure drop in a flow through a pipe;

Figure 2 is a table showing data providing evidence of pressure drop in pipe flow;

Figure 3 shows measured pressure drop data of a gas export pipeline with and without condensate injection;

Figure 4 is a flow diagram;

Figure 5 is a graph illustrating friction factors;

Figure 6 is a schematic cross section of a pipeline with multiphase flow;

Figure 7 is a schematic cross section of the pipeline with multiphase flow; and Figure 8 are graphs illustrating multiple friction factors.

Specific description Natural gas is extracted from reservoirs and subsequently transported to a processing facility on- or offshore. The gas will be a mixture of hydrocarbon gases, but there will also be water and natural-gas condensates present during transport. Natural-gas condensates, also called condensates, are hydrocarbon liquids which are present in a liquid state or as a vapour in the gas flow emerging from the well. Condensates can also be formed from natural gas when it condenses if the temperature and/or pressure drops below the condensation point.

A separator is typically used to remove water and condensates from the raw gas after the raw gas is extracted from the gas well. After the separator, a so-called scrubber can be used to further remove undesired components such as dirt, water and condensates from the gas. However, a small flow rate of condensates and water will inevitably remain and the flow will be a gas-condensate-water three-phase flow.

Hydrate formation in gas pipelines is a further concern for the production process. Hydrates are formed when water molecules arrange themselves around gas molecules, and the hydrate can form a slush which inhibits or even blocks the flow of gas through the pipeline. After the scrubber, a heater may be used to heat the dry gas because hot gas will be less likely to form hydrates, in particular over shorter distances and if the flowline is insulated to maintain the temperature. Hydrate inhibitor is also added to the gas to help prevent hydrate formation, in particular when the gas is transported at a temperature equal to the ambient sea water. Examples of hydrate inhibitors are glycols such as monoethylene glycol (MEG) or triethylene glycol (TEG).

The next stage is compressing the gas in a compressor before feeding the gas into a transport pipeline. The pipeline may be long, for example 50km to 100 km, and placed on the seabed at a depth of 300m below sea level, for example. During transport through the pipeline the temperature of the gas will drop, which will cause condensation of water and heavier gas components in the form of a light condensate.

As such, it is established practice to remove as much water and condensates as possible before transport. Not only is the chance of hydrate formation reduced, but the dry gas is thought to have a lower viscosity which will require less compression by the compressors to transport the gas. A lower viscosity will cause less friction which in turn will correspond to a lower pressure drop between the start and end of the pipeline when compared to a gas with a higher viscosity. It was previously thought that the lower the content of water and condensates, the more efficient the transport process is because a high liquid content will cause high friction, while a low liquid content will cause low friction. However, the inventors have realised that for small concentrations of water and hydrocarbon condensates in the multiphase flow, the pressure drop can be decreased by adding a small amount of condensate, contrary to what would be expected when adding condensate. The effect provided by adding a small amount of condensate is related to a reduction of the water-cut. When yet more condensate is added, however, the pressure drop will increase again and eventually the benefit of adding condensate will disappear. The effect has been observed empirically and has not been arrived at as a result of a theoretical study. The effect has been confirmed with numerical simulations using typical parameters of multiphase gas flow through a flowline.

The effect of a pressure drop as a result of adding condensate does not depend strongly on the diameter of a flowline. The effect appears to depend on the pressure in the flowline, and on the relative concentrations of the multiphase flow component. From the laboratory experiments, it can be observed that the water-cut effect (or three phase effect) on the pressure drop is considerably larger for low pressure compared to high pressure. The observed reduction in pressure drop at field conditions is around 1 or 2 bar from a pressure drop of around 15 bar without condensate being injected to a pressure drop of around 13 or 14 bar when condensate is injected. At higher flow rates the observed reduction is higher: at a higher flow rate than the previous example, a pressure drop of around 35 bar is reduced to almost 30 bar when condensates are injected. A reduction of around 15% of pressure drop will provide a corresponding reduction of energy required from a compressor, with clear benefits of a reduction of energy consumption and CO2 emissions.

Examples of ranges of parameters which are suitable for achieving the effect of a pressure drop are: a flowline inlet pressure of 10 to 150 bara; a flowline outlet pressure of 5 to 130 bara with a corresponding pressure drop (the difference between flowline inlet pressure and flowline outlet pressure), in the range of 5 to 80 bara. The superficial gas velocity is in the range of 5 to 20 m/s. The total gas mass flow rate can be in the range of 30 to 500 kg/s depending on the flowline diameter. The amount of added condensate must be in the same order of magnitude as the as the added hydrate inhibitor in order to affect the water-cut of the flowline.

The volume flow rate percentage of gas in the shown field test flowline is around 99.9%, but the effect is also observed at both lower (at least down to 98%) and higher gas volume (at least up to 99.999%) flow rate percentages than 99.9%.The remaining 0.1% of liquids at inlet conditions includes around 70-90% water and a corresponding amount of 30-10% of condensates. When condensates are added, the ratio between water and condensates is altered and this reduces the liquid dispersion viscosity (see figure 1). However, the above ratios will change along the length of the flowline: while at the inlet water can be up to 100% of the liquids (when no condensates are added), at the outlet the amount of water may be 20% due to the condensation of condensates due to the temperature drop and pressure drop. The volume flow rate ratio of water compared to the total liquid is also referred to as water-cut.

The effect of a reduced pressure drop can be observed without the use of hydrate inhibitor. However, if the water saturation is sufficiently high, condensation will give rise to free water and it is therefore required to add hydrate inhibitor if the temperature goes towards the ambient temperature, which typically is the case for a gas export flowline. A typical inlet temperature for a flowline is 40°C, and the temperature will drop towards the ambient temperature of seawater during transport over typically tens of kilometres. Adding the hydrate inhibitor will produce a viscous water phase. Pure water rather than viscous water can be used if the temperature can be maintained sufficiently high and/or if the pipeline is sufficiently short to avoid condensation. The observed benefit when adding condensate is larger for the viscous water phase than for pure water.

Figure 1 illustrates a typical variation in friction factor for varying water-cut for a constant gas and liquid rate. A higher friction factor corresponds to a higher pressure drop. Adding condensate decreases the water-cut. When starting from the rightmost side of Fig. 1 , the water-cut is 100%, and moving to the left the water-cut decreases when condensate is injected, but the friction factor (and pressure drop) increases up to a peak corresponding to a critical condensate flow rate. When further condensate is added, the condensate flow rate exceeds the critical flow rate and the friction factor (and pressure drop) decreases. Figure 1 is an illustration of what can be observed in laboratory tests.

Fig. 2 illustrates a very specific numerical example of six sets of operating conditions, three with condensate and three without condensate. Test 1 without condensate has comparable settings to test 4 with condensate, and similarly tests 2 and 5, and tests 3 and 6 can be compared to demonstrate the reduced friction factor when condensate is added. The examples are clearly not intended as limiting the inventive concept in any way, not least because the conditions themselves fluctuate over time and are difficult to replicate exactly. The parameters in the table of Fig. 2 are superficial gas velocity, U sg = Qg/A, where Q g is the actual volume flow rate of gas and A is the cross-sectional area of the flowline. The superficial of condensate (U so ) and water (U sw ) are defined similarly. p g , p o and p w represent the gas, condensate and water density, respectively. m 9 , m 0 and p w denote the gas, condensate and water viscosities. The shown numbers are estimated average numbers along the flowline. The friction factor is defined as f = (DR D)/(1/2 p g U sg 2 L). As shown in the table, the friction factor is on average 11% higher when no condensate is added to the flowline.

Fig. 3 illustrates field data showing the reduced pressure when condensate is added to a gas flow where lean MEG is added at the inlet for hydrate inhibition. The closed (blue) dots show the case were small amounts of condensate are added (about 0.4 weight % of the total mass flow rate flow). The open (green) dots show the case where no condensate is added at the inlet. Lines fitted through each set of dots show that the case where a small amount of condensate is added the pressure drop is smaller than when no condensate is added.

The step of injecting hydrocarbon condensate to the multiphase flow is illustrated as S1 in figure 4.

These examples illustrate that by injecting small rates of condensate into gas export pipelines or flowlines from gas producing wells where lean MEG is injected as a hydrate inhibitor, the pressure drop can be reduced. One of the effects of injection of condensate is a reduction of the water-cut of the flow, and the apparent dispersion viscosity of the oil/water viscosity is also reduced. The operational cost is reduced and also the amount of energy consumed by the compressors. Further, production rates may be increased. An advantage is that in most platforms condensate is readily available for free and existing chemical injection lines may be used for injection of the condensate.

The rate of hydrocarbon condensate injection can be varied while measuring the pressure drop with a pressure sensor at or near the inlet and a pressure sensor at or near the outlet. The optimal amount of hydrocarbon injection can be determined empirically by determining the minimal pressure drop.

As mentioned above, the claimed method has been experimentally validated and the skilled person will be able to implement the claimed method without any undue burden based on the above description. The method was not arrived at by way of a theoretical derivation, but the inventors have developed hypotheses of the underlying physics process, which are provided by way of background.

A first hypothesis relates to two-phase (i.e. two substance) flow through a pipeline. The two-phase friction factor depends at least on three contributing parts: (1) friction due to the single-phase gas flow / sp ; (2) a contribution to the friction factor from the continuous liquid film D/ ( ; and (3) a contribution to the friction factor from entrained liquid droplets in the gas layer, Af l e . The term ‘entrainment’ is a technical term for the entrapment of one substance by another substance, in this case the liquid droplets being entrapped in the gas.

The effect of the three contributions is graphically illustrated in Fig. 5, where a two- phase gas-viscous water-phase and two-phase gas-condensate (oil) friction factor are shown on the vertical axis. The horizontal axis shows liquid superficial velocity (U si = Qi/A, where 0/ is the actual volume flow rate of liquid and A is the cross-sectional area of the flowline). The vertical axis of the left subplot shows the friction factor ratio, i.e. the relative friction factor increase compared to single-phase flow. The fc oiebrook is the friction factor corresponding to the Colebrook equation and represents the single-phase gas-flow friction factor. The top solid line is the two-phase gas-viscous-water friction factor; the bottom solid line is the two-phase gas-oil friction factor (both lines being the combination of contributions 1 , 2, and 3 mentioned above). The contribution from the continuous liquid layer combined with single-phase gas flow is shown for the viscous water-phase by the top dashed line, while the low viscous oil phase contribution is shown as the bottom dashed line (both dashed lines being the contributions 1 and 2 combined). Although the friction factor functions in the figure are only illustrative, they show qualitatively the behaviour observed in the measured data. In particular, there is a rapid increase in the friction factor with increasing liquid flow rate for very low liquid flow rates just above zero. The increase is typically more rapid for a water phase when compared to a condensate phase. Experimental data indicates that the entrained fraction of liquid as droplets in the gas layer approaches 100% when the liquid flow rate approaches zero and the gas velocity is high. In other words, most of the liquid is suspended within the gas and only a small fraction resides within the flowing liquid film at the bottom of the pipe. It is therefore postulated that the sharp increase with the initial increase of liquid flow is caused by liquid droplets initially entrained into the gas layer being deposited onto the walls. These deposited droplets increase the apparent wall roughness, thereby also increasing the overall friction and increasing the pressure drop. The effect of entrained liquid droplets being deposited rapidly reaches saturation such that increasing the liquid flow rate further will not contribute much to the overall friction factor, which can be seen in Fig. 5 as the different curves flattening off for increasing values of the inflow on the horizontal axis.

Furthermore, the following assumptions are made.

Liquid droplets of a viscous liquid increase the apparent roughness of the walls more than a liquid with a low viscosity.

A liquid with a high surface tension with the gas-phase will result in larger liquid droplets and therefore a larger apparent roughness of the walls. For gas-condensates with a water-phase, the interfacial tension between the gas and the condensate typically decreases with increasing pressure. The interface tension between the gas- condensate phases is about an order of magnitude lower than for the gas-water interface. The condensate-water interfacial tension is between the two gas-liquid interfacial tensions.

A high turbulence intensity, typically occurring at high gas velocities, will reduce the size of the liquid droplets and the apparent roughness; A high gas density will reduce the size of the liquid droplets and the apparent roughness consequently.

A high wall roughness will conceal some of the effect from the entrained liquid droplets. The effect of the liquid will be relatively higher on a wall surface with a low roughness such as an epoxy-coated wall compared with a steel wall. For a rough wall surface, the deposited liquid droplets may partly reside between the roughness elements.

When the liquid flow rate increases, a film is formed along the internal wall of the pipe instead of individual droplets being deposited. The film is thicker towards the lower part of the pipe due to gravity, while the film may be absent or very thin towards the top of the internal wall. The thickness of the film and the fraction of the wall covered by the film will increase with liquid flow rate. This increase is gradual with increasing liquid flow rate. A continuous film with a viscous liquid will contribute more to the total friction factor than a liquid with low viscosity.

A different hypothesis of three-phase flow will now be described with reference to Fig.6. The three phases are gas, water and condensate. Fig. 6A illustrates a radial cross section through a pipeline 61 , and Fig. 6B illustrates a close-up view of the lower part of the cross section where most of the liquid (water) 62 flows. Condensate droplets 63 are suspended (entrained) both in the gas 64 and in the water 62. A thin condensate layer 65 is formed on top of the water layer, but the layer is too thin to be able to entrain water droplets. When the condensate layer becomes very thin, turbulent eddies within the layer will lose strength and the condensate layer is unable to entrain water droplets. The condensate layer still has the effect of lubricating the water-phase, i.e. reduce the friction between the gas and the water phase, such that fewer water-phase droplets are entrained in the gas phase compared to the case where no condensate is present. In the case with a thin condensate layer on top of the water layer, a drag reduction effect can be observed, i.e. the pressure drop is less than if the condensate phase had not been present. The condensate layer may be very thin due to a high condensate droplet entrainment into the gas phase, a high gas density or a high gas velocity. High water-cut or low liquid flow rate will also reduce the thickness of the condensate layer. A different situation than the one described with reference to Fig. 6 is now considered, with reference to Fig. 7. In this situation, the condensate layer illustrated in Fig. 6 with reference number 65 disintegrates. Fig. 7 illustrates the start of the disintegration of the condensate film, whereby some water-phase droplets 71 escape from the water layer on the bottom of the pipe and become entrained in the gas. When the condensate layer becomes sufficiently thin, the layer will partially or fully disintegrate. In this case, the gas phase encounters the water-phase directly as there is no significant intermediate layer and water-phase droplets will be entrained in the gas. This situation occurs when the condensate entrainment in gas is high (due to high gas velocity or gas density) and the water-cut approaches one. In this case, the condensate phase loses its lubricating effect towards the water-phase and the friction factor increases towards the two-phase gas-water friction factor. There might also be a combined effect of gas- entrained condensate droplets and water-phase droplets, which results in a local maximum in the pressure drop as a function of water-cut. The local maximum is shown in Fig. 1 and in Fig. 8B. The situation of a local maximum in pressure drop is discussed next.

In order to explain the local maximum hypothesis, the two-phase hypothesis discussed above is used, i.e. the two-phase friction factor comprises three parts: f= f sv +Afi +Afi ,e where there is a contribution to the friction factor from (1) the single phase gas flow, (2) the liquid film and (3) the entrained droplets.

The oil-phase flow rate may become so low relative to other parameters that the condensate film will disintegrate. Flere, the limit for the oil phase flow rate is assumed to be Uso,c= 0.0015 m/s. This break down superficial oil velocity will generally depend on gas and oil densities, gas velocity and liquid velocity. The contribution to the total friction factor from the other liquid phase will vanish at pure two-phase flow, i.e. there is no contribution from the viscous water-phase for two-phase gas-oil flow and vice versa, and no contribution from the oil-phase for two-phase gas-water flow. In other words, at WC = 0, the water phase is gone and only gas/condensate is left. At the other end of the scale, WC = 100%, the condensate phase is gone and only the gas and water phases are left. If the superficial oil velocity is above Uso,c the following is assumed

Here, it is assumed that the entrainment of water-phase droplets into the gas phase is reduced with a factor of in situ water-cut (symbol wc in the equation) to the power of a. The value a can be considered a tuning factor as it has not been determined empirically. A high value will delay the entrainment of water droplets into the gas phase towards higher water-cuts.

If the superficial oil velocity is below Uso,c the condensate layer is disintegrating, and the following is assumed for the friction factor: where the contribution from the entrained condensate phase is reduced by a factor Uso/Uso,c. The functional form of the terms Af 0, f, Af 0,e , Af W f andi Af w,e are the same as shown in Figure 5.

Fig. 8A illustrates the friction factor as a function of superficial liquid flow rate, with the same qualitative behaviour as in Fig. 5. Fig. 8 B shows the variation with water-cut for a liquid inflow rate of 0.02 m/s. The horizontal axis of Fig 8B shows water-cut (wc = Usw/Usi). The vertical axis of the right subplot shows the friction factor ratio relative to the friction factor corresponding to the two-phase gas-oil flow (f ga s-oii) · The solid curve without markers is the high-resolution curve (i.e. very small water-cut steps) with respect to water-cut. The red curve with circles shows what would have been measured with a typical laboratory experiment water-cut step of 10%. Laboratory flow experiments are time consuming such that a finer resolution than 10% on the water-cut axis is not feasible. It is only with the higher resolution curve that the phenomenon of the peak is revealed.

With the above considerations, a peak in the pressure drop at very high water-cut can be arrived at without using arguments of increased liquid viscosity due to oil/water emulsions.

Although the invention has been described in terms of preferred embodiments as set forth above, it should be understood that these embodiments are illustrative only and that the claims are not limited to those embodiments. Those skilled in the art will be able to make modifications and alternatives in view of the disclosure, which are contemplated as falling within the scope of the appended claims. Each feature disclosed or illustrated in the present specification may be incorporated in the invention, whether alone or in any appropriate combination with any other feature disclosed or illustrated herein.