Patent Application
20130306310
The invention relates generally to a process, method, and system for removing heavy metals including mercury from hydrocarbon fluids such as crude oil and gases.
Pipelines are widely used in a variety of industries, allowing a large amount of material to be transported from one place to another. The transport can be for a short distance as within a plant or over a long distance such as a continent. A variety of fluids, such as oil and/or gas, as well as particulate, and other small solids suspended in fluids, are transported cheaply and efficiently using pipelines. Pipelines can be subterranean, submarine, on the surface of the earth, and even suspended above the earth. Submarine pipelines especially carry enormous quantities of oil and gas products indispensable to energy-related industries, often under tremendous pressure and at low temperatures and at high flow rates.
Oil and gas pipelines, including undersea or submarine pipelines, typically carry production fluids from one of the production wells including subsea wells. These fluids may be, but are not limited to, a gas, a liquid, an emulsion, a slurry and/or a stream comprising solid particles (oil sand). The production fluid can be a single phase, a two phase or even a three phase admixture.
Methods have been disclosed to remove heavy metals from produced fluids. Common approaches utilize treatments for the fluids once the fluids are recovered from subterranean reservoirs and brought to a surface production installation. U.S. Pat. No. 4,551,237 discloses the use of an aqueous solution of sulfide materials to remove arsenic from oil shale. U.S. Pat. No. 4,877,515 discloses a process for removing mercury from hydrocarbon streams, gas or liquid. U.S. Pat. No. 4,915,818 discloses a method of removing mercury from liquid hydrocarbons (natural gas condensate) by contact with a dilute aqueous solution of alkali metal sulfide salt. U.S. Pat. No. 6,268,543 discloses a method for removing elemental mercury with a sulfur compound. U.S. Pat. No. 6,350,372 discloses removing mercury from a hydrocarbon feed by contact with an oil soluble or oil miscible sulfur compound U.S. Pat. No. 4,474,896 discloses using polysulfide based absorbents to remove elemental mercury)(Hg° from gaseous and liquid hydrocarbon streams.
Given the cost of expensive installations of equipment in production facilities for the removal of heavy metals from produced fluids, there is a need for the efficient removal of trace levels of heavy metals from hydrocarbon fluids from production wells, before reaching refineries, shipping terminals, or upstream oil processing facilities that separate and prepare crude oil for sale including land-based oil processing facilities, and offshore oil processing platforms including floating production, storage and offloading (FPSO) units and others performing similar functions.
In one aspect, the invention relates to a method for simultaneously transporting and removing a trace amount of heavy metals from a produced fluid. The method comprises: extracting a produced fluid containing heavy metals from a production well; injecting into the produced fluid an effective amount of at least fixing agent and a dilution fluid forming a mixture; transferring the mixture through a pipeline from the production well for a sufficient distance for at least a portion of the heavy metals to react with the mixture, at least a fixing agent, and be extracted into the dilution fluid as complexes; and separating the dilution fluid containing the heavy metal complexes from the produced fluid for a treated produced fluid having a reduced concentration of heavy metals.
In another aspect, the invention relates to a method for simultaneously transporting and removing mercury from a crude. The method comprises: extracting the crude containing a trace amount of mercury from a production well; injecting into the crude an effective amount of at least fixing agent and a sufficient amount of water forming a mixture; transferring the mixture through a pipeline for a sufficient distance for at least a portion of mercury to react with the fixing agent forming a soluble mercury complex in water; separating the water containing the soluble mercury complex from the crude for a treated crude having reduced mercury concentration.
The following terms will be used throughout the specification with following meanings unless otherwise indicated.
“Hydrocarbons” refers to hydrocarbon streams such as crude oils and/or natural gases.
“Produced fluids” refers hydrocarbon gases and/or liquids such as crude oil that is removed from a geologic formation via a production well, including mixtures of hydrocarbons and water that is typically extracted with the hydrocarbons.
“Crude oil” refers to a hydrocarbon material, including both crude oil and condensate, which is typically in liquid form. Under some formation conditions of temperature and/or pressure, the crude may be in a solid phase. Under some conditions, the oil may be in a very heavy liquid phase that flows slowly, if at all, e.g., as a slurry phase comprising oil sand or bitumen flecks. While the description described herein sometimes refers to “crude” or “crude oil,” the description of “crude oil” also includes hydrocarbon gases unless specified otherwise.
“Production well” is a well through which produced fluids are carried from an oil-bearing geological formation to the earth's surface, whether the surface is the seafloor, a fixed or floating structure on water, or land. Surface facilities are provided for handling and processing the produced fluids from the formation upon the surface. Production well may be used interchangeably with wellhead or well.
“Produced water” refers to the water generated in the production of oil and gas, including formation water (water present naturally in a reservoir), as well as water previously injected into a formation either by matrix or fracture injection, which can be any of connate water, aquifer water, seawater, desalinated water, industrial by-product water, and combinations thereof. In one embodiment, produced water is a component of produced fluids.
“FPSO” (floating production, storage and offloading unit) is a floating vessel for the processing of hydrocarbons and for storage of oil/gas. In one embodiment, the FPSO processes an incoming stream of crude oil, water, gas, and sediment, and produce a shippable crude oil with acceptable properties including levels of heavy metals such as mercury, vapor pressure, basic sediment & water (BS&W) values, etc.
“Pipeline conditioning system” refers to a pipeline that contains produced fluids and at least one chemical reagent for the removal of at least a heavy metal from the produced fluids.
“Trace amount” refers to the amount of heavy metals in a produced fluid. The amount varies depending on the source of the fluid and the type of heavy metal, for example, ranging from a few ppb to up to 30,000 ppb for mercury and arsenic.
“Heavy metals” refers to gold, silver, mercury, osmium, ruthenium, uranium, cadmium, tin, lead, and arsenic. While the description described herein refers to mercury removal, in one embodiment, the treatment removes one or more of the heavy metals from the produced fluids.
“Mercury sulfide” may be used interchangeably with HgS, referring to mercurous sulfide, mercuric sulfide, or mixtures thereof. Normally, mercury sulfide is present as mercuric sulfide with a stoichiometric equivalent of one mole of sulfide ion per mole of mercury ion.
Mercuric sulfide can be in any of the common crystal forms, e.g., cinnabar, metacinnabar, hypercinnabar, or combinations thereof.
“Fixing agent” refers to chemical reagents that are added to the pipeline to form complexes with the heavy metals in the produced fluid, or to convert the heavy metals into compounds that are soluble in the dilution fluid, e.g., water, that is added to the pipeline to assist the flow of the produced fluid in the pipeline.
The invention relates to a method for simultaneously transporting and removing heavy metals contained in produced fluids such as crude oil, gases and the like. In the course of being transferred through a pipeline with a sufficient amount of dilution fluid, e.g., water including produced water and/or lighter hydrocarbon, sufficient mixing occurs in the pipeline for reactions to take place between the fixing agent and heavy metals such as mercury, arsenic, etc. to be extracted into the dilution fluid or to precipitate out of the crude.
Produced Fluids for Removal of Heavy Metals:
Heavy metals such as lead, zinc, mercury, silver, arsenic and the like can be present in trace amounts in all types of hydrocarbon streams such as crude oils and natural gases. Some crude oils contain trace amounts of heavy mercury and/or arsenic. The amount of mercury and/or arsenic can range from below the analytical detection limit to several thousand ppb depending on the feed source.
Arsenic species can be present in produced fluids in various forms including but not limited to trimethylarsine, arsine (AsH3), triphenylarsine (Ph3As), triphenylarsine oxide (Ph3AsO), arsenic sulfide minerals (e.g., As4S4 or AsS or As2S3), metal arsenic sulfide minerals (e.g., FeAsS; (Co, Ni, Fe)AsS; (Fe, Co)AsS), arsenic selenide (e.g., As2Se5, As2Se3), arsenic-reactive sulfur species, organo-arsenic species, and inorganic arsenic held in small water droplets.
Mercury can be present in produced fluids as elemental mercury Hg°, ionic mercury, inorganic mercury compounds, and/or organic mercury compounds. Examples include but are not limited to: mercuric halides, mercurous halides, mercuric oxides, mercuric sulfide, mercuric sulfate, mercurous sulfate, mercury selenide mercury hydroxides, organo-mercury compounds and mixtures of thereof. Mercury can be present as particulate mercury, which can be removed by filtration or centrifugation. The particulate mercury in one embodiment is predominantly non-volatile.
In one embodiment, the produced fluid is a crude oil containing at least 50 pbbw mercury. In another embodiment, the mercury level is at least 100 pbbw. In one embodiment of a mercury-containing crude, less than 50% of the mercury can be removed by stripping (or more than 50% of the mercury is non-volatile). In another embodiment, at least 65% of the mercury in the crude is non-volatile. In a third embodiment, at least 75% of the mercury is of the particulate or non-volatile type.
In one embodiment, the produced fluid for transporting in the pipeline is in the form of a mixture of crude oil and water. For some production wells, the amount of produced water in the crude can be as much as 98% of the crude/water mixture transported in the pipeline.
Pipeline Reaction:
The pipeline reaction system effectively reduces levels of heavy metals such as mercury and/or arsenic from produced fluids with the addition of at least a chemical reagent as a fixing agent to the pipeline. The fixing agent can be introduced into the pipeline along with a dilution fluid or separately by itself without a dilution fluid, into the production well at the well head, into a manifold, into a location downhole in the wellbore, an intermediate location into a pipeline between the production well and a processing facility, or combinations of the above. In one embodiment, the dilution fluid is produced water in the production fluids.
In one embodiment, the fixing agent is introduced into the pipeline at an entry point at the wellhead or close to the well head, e.g., within 1000 ft of the well head, and separate from the dilution fluid. In another embodiment, the fixing agent is introduced into the production well along with a dilution fluid. In yet another embodiment, the fixing agent is introduced into a pipeline carrying a crude in a processing facility for the reaction to take place in the pipeline before the crude reaches its destination such as a piece of equipment in the facility.
In one embodiment, the dilution fluid is non-potable water, e.g., connate water, aquifer water, seawater, desalinated water, oil field produced water, industrial by-product water, or combinations thereof. In another embodiment, the dilution fluid is a lighter hydrocarbon, e.g., pentane, diesel oil, gas oil, kerosene, gasoline, benzene, toluene, heptane, and the like. Depending on the produced fluids to be transported and the type of dilution fluid employed, the volume ratio of dilution fluid to the produced fluid in the pipeline may range from 20:1 to 1:20 in one embodiment, 5:1 to 1:5 in another embodiment, and 4:1 to 1:1 in a yet another embodiment.
In the pipeline, the fixing agent effectively extracts heavy metals from the produced fluid into a dilution fluid such as water. The pipeline is of sufficient length so that, in the course of transferring produced fluid through it, sufficient mixing of produced fluids and water occurs for reactions to take place between the fixing agent and the heavy metals, for heavy metals such as mercury to form insoluble complexes, or be extracted from the produced fluid into the water phase. In one embodiment wherein mercury reacts with the fixing agent to form insoluble complexes, the heavy metals can then be removed by filtration, settling, or other methods known in the art, e.g., removal of solids from a or gas liquid stream to produce a hydrocarbon product with reduced mercury content. In another embodiment wherein mercury reacts with the fixing agent and is extracted into the dilution fluid as a soluble compound, the Hg-enriched water phase can be separated from the crude by means known in the art, e.g., gravity settler, coalescer, separator, etc., at a processing facility at the destination of the pipeline to produce a hydrocarbon product with reduced mercury content.
The pipeline is sufficiently long for a residence time of at least one minute in one embodiment, at least 10 minutes in another embodiment, at least 30 minutes in yet another embodiment, at least 10 hours in a fourth embodiment. The pipeline can be in the range of 20-200 hours that extends for hundreds if not thousands of kilometers. In one embodiment, the reaction takes place over a relatively short pipeline, e.g., at least 10 m but less than 50 meters for intra-facility transport. In yet another embodiment, the reaction takes place in pipeline sections for a long distance transport of at least 0.5 km, at least 50 km, at least 500 km and less than 10,000 km in another embodiment. In one embodiment the flow in the pipeline is turbulent, and in another embodiment the flow is laminar.
For effective removal of mercury from the produced fluids with sufficient mixing to create a dispersion of water in a produced fluid such as crude oil, or oil in the water, the pipeline has a minimum superficial liquid velocity (based on combined oil and water phases) of at least 0.1 m/s in one embodiment; at least 0.5 m/s in a second embodiment; and at least 5 m/s in a third embodiment. In one embodiment with the transport of certain produced fluids or under certain transport conditions, e.g., heavy oil and/or at or low superficial velocities, the natural mixing in the pipeline can be augmented with the use of mixers at the point of introduction of the fixing agent, or at intervals downstream in the pipeline. Examples include static or in-line mixers as described in Kirk-Othmer Encyclopedia of Chemical Technology, Mixing and Blending by David S. Dickey, Section 10, incorporated herein by reference.
Depending on the produced fluid being carried in the pipeline, e.g., oil sand with low viscosity, crude oil, etc., the temperature of the pipeline is maintained at a temperature of at least 5° C. in one embodiment, at least 10° C. in a second embodiment, and at least 10° C. in a second embodiment. The produced fluid can be mixed with a heated dilution fluid at the production site before being pumped through the pipeline for the mixture in the pipeline to have a temperature in the range of 5-70° C. at the entry point of the fixing agent. In one embodiment, steam or hot water containing fixing agents is injected at the entry point, or at intervals along the pipeline for the desired chemistry and temperature for the pipeline reaction to take place.
The pipeline reaction system can be either land-based or located subsea, extending from a production site to a crude processing facility and receiving production flow from a surface wellhead or other sources. Examples include subsea pipelines, where the great depth of the pipeline can make the pipeline relatively inaccessible, and where the pipelines include a header or vertical section that forms a substantial pressure head. The pipeline system can be on-shore, off-shore (as a platform, FPSO, etc), or combinations thereof. For off-shore locations, the pipeline system can be a structure rising above the surface of the water (well platform) or it can be sub-surface (on the sea bed).
In one embodiment where the production site is at a sufficient distance from the processing facility, the pipeline system includes intermediate separation, collection and/or processing facilities. The intermediate facilities contain one or more supply tanks to dispense fixing agents and/or other process aids, e.g., foamants, NaOH, diluents, etc., to facilitate the flow of produced fluids in into the pipeline. The intermediate facilities may also include equipment such as gravity separator, plate separator, hydroclone, coalescer, centrifuge, filter, collection tanks, etc. for the separation, storage, and treatment of recovered water after separation from the crude. The separation is carried out at the destination in one embodiment, and at intervals along the pipeline in another embodiment.
In one embodiment for a pipeline system within a production or processing facility, the pipeline may extend from a first equipment to another equipment located at a different location or section of the facility. The first equipment can be a vessel where the fixing agent is first introduced or mixed with the produced fluid. The second equipment can be a separator for the oil/water separation or another vessel. In one embodiment, additional chemical reagents such as complexing agents can be added to the second equipment to facilitate the oil/water separation to recover treated crude oil and waste water for subsequent water treatment or discharge.
The wastewater after being separated from the treated crude is injected back into the oil or gas reservoir (in production or depleted) in one embodiment. In another embodiment, the wastewater is further treated being injected into the reservoir prior to being discharged. In another embodiment the wastewater is treated to meet environmental regulations for water quality and discharged.
In one embodiment after the pipeline reaction, at least 50% of mercury is removed from the produced fluid for a mercury concentration of less than 100 ppbw in the treated hydrocarbon. In another embodiment, at least 50% of arsenic is removed from a produced fluid such as shale oil for an treated shale oil having less than 100 ppbw arsenic in the treated hydrocarbon. In yet another embodiment after the pipeline reaction, at least 50% of mercury is removed from the produced fluid for a mercury concentration of less than 50 ppbw in the treated hydrocarbon. In another embodiment, at least 50% of arsenic is removed from a produced fluid such as shale oil for an treated shale oil having less than 50 ppbw arsenic in the treated hydrocarbon. A least 75% of the heavy metals such as mercury and/or arsenic is removed from a produced fluid such as crude oil in one embodiment; and at least 90% in a second embodiment.
Fixing Agent:
In one embodiment for the removal of arsenic and/or mercury, the fixing agent is a sulfur-based compound for forming sulfur complexes with the heavy metals. Examples include organic and inorganic sulfide materials (including polysulfides), which in some embodiments, convert the heavy metal complexes into a form which is more soluble in an aqueous dilution fluid than in a produced fluid such as shale oil. In one embodiment, the sulfur based compounds are selected from sodium polysulfide, ammonium polysulfide, and mixtures thereof.
In one embodiment, the fixing agent is a water-soluble monatomic sulfur species, e.g., sodium sulfides and alkali sulfides such as hydrosulfides or ammonium sulfides, for the extraction of mercury into an aqueous dilution fluid as soluble mercury sulfur complexes. In another embodiment, the sulfur-based compound is any of hydrogen sulfide, bisulfide salt, or a polysulfide, for the formation of precipitates which require separation from the treated produced fluid by filtration, centrifugation, and the like. In yet another embodiment, the fixing agent is an organic polysulfide such as di-tertiary-nonyl-polysulfide. In another embodiment, the sulfur based compound is an organic compound containing at least a sulfur atom that is reactive with mercury as disclosed in U.S. Pat. No. 6,685,824; the relevant disclosure is included herein by reference. Examples include but are not limited to dithiocarbamates, sulfurized olefins, mercaptans, thiophenes, thiophenols, mono and dithio organic acids, and mono and dithiesters.
In one embodiment for the treatment/removal of heavy metals such as elemental mercury in the gas phase, the fixing agent is a polysulfide (organic or inorganic) which converts the elemental Hg into a species that is dissolved in the dilution fluid, e.g., HgS2H—.
In another embodiment, the fixing agent is an oxidizing agent which converts the heavy metal to an oxidation state that is soluble in water. Examplary fixing agents include elemental halogens or halogen containing compounds, e.g., chlorine, iodine, fluorine or bromine, alkali metal salts of halogens, e.g., halides, chlorine dioxide, etc; iodide of a heavy metal cation; ammonium iodide; an alkaline metal iodide; etheylenediamine dihydroiodide; hypochlorite ions (OCl− such as NaOCl, NaOCl2, NaOCl3, NaOCl4, Ca(OCl)2, NaClO3, NaClO2, etc.); vanadium oxytrichloride; Fenton's reagent; hypobromite ions; chlorine dioxine; iodate IO3 (such as potassium iodate KIO3 and sodium iodate NaIO3); monopersulfate; alkali salts of peroxide like calcium hydroxide; peroxidases that are capable of oxidizing iodide; oxides, peroxides and mixed oxides, including oxyhalites, their acids and salts thereof. In one embodiment, the fixing agent is selected from KMnO4, K2S2O8, K2CrO7, and Cl2. In another embodiment, the fixing agent is selected from the group of persulfates. In yet another embodiment, the fixing agent is selected from the group of sodium perborate, potassium perborate, sodium carbonate perhydrate, potassium peroxymonosulfate, sodium peroxocarbonate, sodium peroxodicarbonate, and mixtures thereof.
In one embodiment in addition to at least a fixing agent, a complexing agent is also added to the fixing agent to form strong complexes with the heavy metal cations in the produced fluids, e.g., Hg2+, extracting heavy metal complexes from the oil phase and/or the interface phase of the oil-water emulsion into the water phase by forming water soluble complexes. Examples of complexing agents to be added to an oxidizing fixing agent include hydrazines, sodium metabisulfite (Na2S2O5), sodium thiosulfate (Na2S2O3), thiourea, thiosulfates (such as Na2S2O3), ethylenediaminetetraacetic acid, and combinations thereof. In one embodiment with the addition of a complexing agent to a fixing agent, the fixing agent is added to the pipeline first to oxidize the heavy metal, then the complexing agent is subsequently added to form a complex that is soluble in water. The complexing agent can be injected at intervals along the pipeline, or it can be subsequently added after the introduction of the fixing agent.
The fixing agent can be added as in a solid form, or slurried/dissolved in a diluent, e.g., water, alcohol (such as methanol, ethanol, propanol), a light hydrocarbon diluent, or combinations thereof, in an effective amount for the treated produced fluid to have a mercury concentration of less than 100 ppbw. Effective amount means a sufficient amount for a molar ratio of fixing agent to heavy metals ranging from 1:1 to 100,000:1 in one embodiment, 5:1 to 20,000:1 in a second embodiment; from 50:1 to 10,000:1 in a third embodiment; from 100:1 to 5,000:1 in a fourth embodiment; and from 150:1 to 500:1 in a fifth embodiment. If a complexing agent is to be added to the pipeline reaction to effectively stabilize (forming complexes with) soluble heavy metals, e.g., mercury, in the oil-water mixture, the amount as molar ratio of complexing agent to soluble mercury ranges from 2:1 to about 100,000:1 in one embodiment; from 5:1 to about 3,000:1 in a second embodiment; and from 20:1 to 500:1 in a third embodiment.
The fixing agent can be injected into the pipeline or into a location downhole using conventional equipment known in the art such as metering pumps or jet pumps. In one embodiment with the addition of both an oxidant as a fixing agent and a complexing agent, the oxidant can be added to the pipeline and then mixed by a first static mixer. The complexing agent can be added and mixed with a second static mixer, then allowed to enter the pipeline for the reaction to go to sufficient conversion.
Some of the fixing agents may require special handling, e.g., corrosion resistant equipment and/or safety procedures. In one embodiment with the use of sodium hypochlorite as a fixing agent, the solution can be generated on-site with the use of commercially available electro-chlorination system, allowing the generation of sodium hypochlorite on-site for injection directly into the pipeline. In another embodiment, the pipeline reaction is allowed to take place in a section that provides sufficient residence time for the removal of the target heavy metals from the produced fluids. For example, the pipeline reaction section requiring special handling can run from the production well to an intermediate processing facility located a short distance from the production well, for the collection and separation of the treated produced fluids from waste water containing heavy metals and corrosive fixing agents. Additional aqueous dilution fluid can be injected into the pipeline for the transport of the treated produced fluids from the intermediate processing facility to the final destination, e.g., shipping terminal or FPSO.
Figures Illustrating Embodiments:
Reference will be made to the figures to further illustrate embodiments of the invention.
The flow line 120 includes a vertical section or riser 124 (not shown) that terminates at the FPSO 100. The dispensing system 104 continuously or intermittently injects at least a fixing agent into the flow line 120 or the well 102 for the removal of heavy metals.
In one embodiment, the dispensing system 104 can be utilized with one or more sensors 132 positioned along selected locations along the flow line 120 and the well 102. During production operations, the dispensing system 104 supplies (or pumps) one or more fixing agents to the flow line 120. This supply of fixing agents may be continuous, intermittent or actively controlled in response to sensor measurements. In one mode of controlled operation, the dispensing system 104 receives signals from the sensors 132 regarding a parameter of interest relating to a characteristic of the produced fluid, e.g., temperature, pressure, flow rate, amount of water, concentration of heavy metals in the produced fluids based on the formation of intermediate complexes, etc. Based on the data provided by the sensors 132, the dispensing system 104 determines the appropriate type and/or amount of fixing agents needed for the pipeline reactions to take place to reduce the concentration of mercury, arsenic, and the like.
In embodiments, the dispensing system 104 can include one or more supply lines 140, 142, 144 that dispense fixing agents, e.g., fixing agents such as sodium hypochlorite, etc., into the pipeline 120 at a location close to the wellhead, or right at the wellhead 102, in a manifold (not shown) or into a location downhole in the wellbore 114, respectively. The supply tank or tanks 146 and injection units 148 can be positioned on the surface facility 110 for continuous supply to the dispensing system 104. In other embodiments, one or more of the supply lines 140, 142, 144 can be inside or along the pipeline 120, for intermittent dispensing of fixing agents into the pipeline 120 for the removal of heavy metals.
While multiple dispensation points are shown in
In one embodiment as shown in
For the purposes of this specification and appended claims, unless otherwise indicated, all numbers expressing quantities, percentages or proportions, and other numerical values used in the specification and claims are to be understood as being modified in all instances by the term “about.” Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that can vary depending upon the desired properties sought to be obtained by the present invention. It is noted that, as used in this specification and the appended claims, the singular forms “a,” “an,” and “the,” include plural references unless expressly and unequivocally limited to one referent.
As used herein, the term “include” and its grammatical variants are intended to be non-limiting, such that recitation of items in a list is not to the exclusion of other like items that can be substituted or added to the listed items. The terms “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. Unless otherwise defined, all terms, including technical and scientific terms used in the description, have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs.
This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to make and use the invention. The patentable scope is defined by the claims, and can include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. All citations referred herein are expressly incorporated herein by reference.
This application claims benefit under 35 USC 119 of U.S. Patent Application Ser. No. 61/647,674 with a filing date of May 16, 2012. This application claims priority to and benefits from the foregoing, the disclosures of which are incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 61647674 | May 2012 | US |
