PROCESS FOR OPERATING A UTILITY BOILER AND METHODS THEREFOR

Abstract

A process for operating a utility boiler. The process has the following steps: (a) providing fuel to the boiler; (b) providing one or more additives selected from the group consisting of (i) one or more slag control agents, (ii) one or more oxygen-generating agents, (iii) one or more acid mitigation agents, (iv) one or more fouling prevention agents, (v) one or more oxidizer agents, (vi) one or more heavy metal capturing agents, and (vii) any combination of the foregoing to the boiler or an auxiliary device thereof; (c) providing air to the boiler; (d) burning the fuel in the boiler to generate heat and an exhaust gas; (e) intermittently or continuously monitoring one or more physical and/or chemical parameters of the fuel and/or intermittently or continuously monitoring one or more emissions variables of the exhaust gas to obtain one or more values therefor; and (f) varying or maintaining the rate at which either or both of the fuel and the one or more additives are provided to the boiler based on the one or more values obtained.

Description

CROSS-REFERENCE TO A RELATED APPLICATION

The present application is a continuation application of U.S. Ser. No. 12/769,152, filed Apr. 28, 2010, which is incorporated herein by reference in its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to a process for operating a utility boiler. The present invention also relates to a process for operating a utility boiler in which physical and/or chemical parameters of the fuel and emissions variables of the exhaust gas and/or flue gas of the utility boiler are monitored and fuel and/or additive feed rates are varied accordingly.

2. Description of the Related Art

Utility boilers or furnaces are employed in industry for generation of heat, production of steam, and generation of electricity utilizing steam. Utility boilers typically have a furnace therein where a fuel fuel, such as coal, biomass, residual oil or #6 fuel oil, is oxidized or burned to generate heat. Along with generating heat, utility boilers will generate or evolve an exhaust gas and/or a flue gas that will contain carbon dioxide (product of oxidation of coal, biomass, and fuel oil), residual oxygen (unreacted), inert air components, i.e., nitrogen and argon, and emissions, such as sulfur-based and nitrogen-based compounds. Exhaust gas and/or a flue gas is typically treated and then vented to the atmosphere.

A variety of problems are encountered when operating utility boilers. Such problems generally relate to slag deposition, fouling, cleanliness, efficiency, and emissions.

Emissions problems relate to sulfur-based emissions, such as sulfur dioxide (SO₂), sulfur trioxide (SO₃), and sulfuric acid (H₂SO₄); nitrogen-based emissions (NO_x), such as emissions include nitrous oxide (NO) and nitrogen dioxide (NO₂); mercury-based emissions (Hg) and particulates. Free sulfur trioxide in an exhaust gas and/or a flue gas imparts an undesirable opaque appearance (a blue haze or trailing plume) to the gas when vented to the atmosphere. Free sulfuric acid can cause corrosion of process surfaces in utility boilers as well as acid rain in the atmosphere. Particulate emissions are made up of unburned carbon and ash. Unburned carbon is formed when burning of oil in the boiler is incomplete. Ash is naturally present in coal and is present in fuel oil as a leftover from oil refining. Particulates also present cleanliness and industrial hygiene problems.

Slag deposition can take the form of one or more layers caked/baked onto process surfaces. The one or more layers typically contain silica, aluminum, calcium, and metal complexes of vanadium with sodium, nickel, iron, or magnesium. Slag can deposit on the surfaces of tube bundles or other heat transfer devices within the utility boiler denuding a boiler's heat transfer efficiency.

It would be desirable to have a process for operating a utility boiler wherein slag deposition, fouling, cleanliness, and undesirable emissions can be reduced or minimized. It would also be desirable to have a process for operating a utility boiler that affords enhanced operational efficiency.

SUMMARY OF THE INVENTION

According to the present invention, there is a process for operating a utility boiler. The process has the steps of (a) providing fuel to the boiler; (b) providing one or more additives selected from the group consisting of (i) one or more slag control agents, (ii) one or more oxygen-generating agents, (iii) one or more acid mitigation agents, (iv) one or more fouling prevention agents, (v) one or more oxidizer agents, (vi) one or more heavy metal capturing agents, and (vii) any combination of the foregoing to the boiler or an auxiliary device thereof; (c) providing air to the boiler; (d) burning the fuel in the boiler to generate heat and an exhaust gas and/or a flue gas; (e) intermittently or continuously monitoring one or more physical and/or chemical parameters of the fuel and/or intermittently or continuously monitoring one or more emissions variables of the exhaust gas and/or a flue gas to obtain one or more values therefor; and (f) varying or maintaining the rate at which the fuel and/or one or more of the additives is provided to the boiler based on the one or more values obtained.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a schematic representation of a boiler system useful in carrying out the present invention.

DETAILED DESCRIPTION OF THE INVENTION

In the process of the present invention, the fuel is intermittently or continuously monitored for one or more physical and/or chemical parameters of the fuel to obtain one or more values therefor. The feed rates of the fuel and one or more additives to the boiler and/or an auxiliary device(s) thereof are varied or maintained based on the one or more values obtained.

The actual monitoring on the physical and/or chemical parameters of the fuel and emissions variables of the exhaust gas and/or a flue gas can take place intermittently or continuously as desired. In a preferred embodiment, the monitoring takes place substantially continuously, i.e., a test is repeated as soon as it ends over a continuum of time. In other embodiments, a period of time can elapse between the end of a test and repeat of the test. For example, a period of time elapse can be five minutes or less, one minute or less, or 30 seconds or less. The values obtained from monitoring are used to vary the rate at which fuel and/or one or more of the additives is provided to the boiler. In a preferred embodiment, the results or values obtained in a test are used to effect variance or maintenance of existing fuel and/or additive rates.

A preferred process of the present invention monitors the physical and/or chemical parameters of the fuel and emissions variables of the exhaust gas and/or a flue gas in “real time”. The term “in real time” means that (a) physical and/or chemical parameters of the fuel and emissions variables of the exhaust gas and/or a flue gas are monitored substantially continuously, i.e., one test is administered as soon as the previous one is finished; (b) communication of the results or values obtained from the analytical testing or monitoring of physical and/or chemical parameters of the fuel and/or emissions variables to a processor or controller is substantially instantaneous; (c) after results or values are obtained, the processor or controller then substantially instantaneously instructs process components that effect regulation or control of feed rates of the fuel and/or the additives to vary or maintain fuel and/or additive rates, accordingly.

An embodiment of the process of the present invention has a boiler system that includes a boiler and conduits for feedstocks, steam, and exhaust. Associated peripheral equipment, such as pumps, flowmeters, a programmable logic controller (PLC) interface or similar control device, and remote communication devices can be arranged on a “skid” separate from but in communication with the boiler along with necessary electric cabinets, wiring, plumbing, and other infrastructure. Boiler systems are typically equipped with a host of instrumentation and diagnostic systems routed through a distributed control system (DCS). A DCS takes the form of control room software and a network, and interacts with one or more PLCs in the boiler's system. In a preferred embodiment, a skid has its own PLC. Data obtained can include, for example, include fuel transfer rate, coal firing rate, heat input, various boiler temperatures and pressures,

emission variables (e.g., SO₂, NO_x, NH3, O, CO, acid level, particulates, opacity, and heavy metals such as Hg), component system operating parameters, and the like. Data can be transmitted to a skid and used to control and adjust process variables, such as dosage level, blend ratio, and duration of the treatment. Information is fed into a PLC and manipulated via algorithms and other programming to continuously adjust and optimize treatment of the fuel.

An embodiment of the process of the present invention is set forth in FIG. 1 in the form of a boiler system 10. System 10 has a boiler 12. Feed streams 14, 16, 18, 20, and 22 provide conduits for feeding a fuel, a first additive, a second additive, water, and air, respectively, into boiler 12. Exit stream 24 delivers steam produced in boiler 12. Exit stream 26 delivers exhaust gas. Controller 28 monitors the physical and/or chemical parameters of the fuel to obtain one or more values corresponding to same and provides instructions in real time to one or more components of the process (not shown) to vary or maintain the rate at which the fuel and/or the first and second additives is provided to boiler 12.

Various additives are employed in the present invention for controlling slag formation, fouling, emissions levels, and the like.

The slag control agent can be employed in the process of the present invention to prevent buildup of slag deposits within the furnace of the utility boiler and other process surfaces during the combustion of the coal, biomass, or fuel oil. The slag control agent also reacts or complexes with any undesirable vanadium compounds that may be present in fuel oil. Conversion of undesirable vanadium compounds, such as vanadium pentoxide and sodium vanadium pentoxide, to more innocuous vanadium compounds or forms helps to prevent or reduce catalysis of sulfur dioxide to sulfur trioxide, corrosion of process surfaces due to acid exposure, and deposition of vanadium compounds on process surfaces inside the utility boiler.

Useful slag control agents include, but are not limited to, the following: magnesium hydroxide; magnesium oxide; magnesium carbonate; and magnesium organometallic compounds, such as magnesium carboxylate, magnesium salicylate, magnesium naphthenate, and magnesium sulfonate. Preferred slag control agents are magnesium hydroxide, magnesium oxide, and organometallic magnesium carboxylate with magnesium carbonate overlay.

The oxygen-generating agent can be employed in the process of the present invention to provide additional oxygen at the situs of oxidation or burning in the furnace, which allows the feed rate of air supplied to the utility boiler to be reduced and/or minimized. Use of the oxygen-generating agent also reduces the incidence of unburned carbon due to more efficient combustion or burning. Reduction of unburned carbon also reduces the incidence and retention of sulfuric acid, which is absorbed by unburned carbon.

Useful oxygen-generating agents include, but are not limited to, the following: calcium nitrate, calcium organometallic compounds, calcium salicylate, calcium sulfonate, overbased calcium carboxylate, iron oxides, iron carboxylates, iron organometallic compounds, iron sulfonates, barium oxide, barium carbonate, barium carboxylate, barium organometallic compounds, and barium sulfonate. Preferred oxygen-generating agents are the calcium compounds. Most preferred oxygen-generating agents are calcium nitrate and calcium carboxylate.

The acid mitigation agents can be employed in the process of the present invention to reduce or minimize the amount of acidic compounds in the boiler and the exhaust gas and/or flue gas. Particularly, the agent reacts with sulfuric acid to form innocuous, non-acidic compounds, thereby reducing acid emissions in the exhaust gas and/or flue gas and corrosion of process surfaces within the boiler. Acid mitigation agents can either neutralize or absorb/adsorb acids. Examples of acid mitigation agents include magnesium oxide, magnesium hydroxide, magnesium carbonate, sodium bicarbonate carbonate, and calcium carbonate.

The fouling prevention agents can be employed in the process of the present invention to reduce or minimize buildup on process surfaces within the boiler and maintain operational efficiency. Examples of fouling prevention agents include magnesium oxide, magnesium hydroxide, magnesium carbonate, and

sodium borate.

The oxidizer agents can be employed in the process of the present invention to (i) reduce or minimize excessive makeup air addition to the furnace and (ii) help convert mercury and heavy metal constituents to an oxidized form that is easier to capture. Examples of oxidizer agents include calcium bromide,

calcium chloride, and sodium bromide.

The heavy metal capture agents and can be employed in the process of the present invention to reduce or minimize mercury emissions. A preferred heavy metal capture agent is a mercury capture agent. Examples of mercury capture agents include calcium sulfide, calcium polysulfide, and sodium sulfide. Heavy metal capture agents are preferably incorporated outside the boiler into one of its auxiliary devices. For example, the agent can be injected into the exhaust system or added to a flue gas desulfurization unit. The agent can take the form of a dry or wet system.

The additives can be added or mixed into the coal, fuel oil, or biomass prior to combustion or added into the furnace of the utility boiler during combustion or burning. The treatment of the coal or fuel oil can be homogeneous or non-homogeneous, i.e., the agents can be homogeneously admixed within the coal or fuel oil or non-homogeneously applied, such as to the surface or some portion of the coal or fuel oil. Some additives may be added to a boiler system at an auxiliary device thereof. An auxiliary device is an inlet or outlet apparatus or component of a boiler outside of the furnace or direct heating section thereof. For instance, particularly heavy metal capture agents such as mercury capturing agents, are typically added in an exhaust system and/or a flue gas desulfurization unit.

The additives can be used in any known product form, such as a mineral ore, a powder, or liquid. Liquids may be water-based, oil-based, or a combination thereof. Liquids may take any known liquid form, such as solutions, slurries, suspensions, dispersions, or emulsions. Liquid forms are preferred since they can be injected or sprayed with precision via conventional pumping and metering devices. A preferred means of adding additives to the coal or fuel oil is via injection in liquid form.

The amount of slag control agent(s) employed can vary depending upon a variety of process and composition conditions, such as type of slag control agent selected, load or feed rate of fuel, amount and type of oxygen-generating agent used, amount or feed rate of air, impurity composition of fuel, and the like. When a liquid form of the slag control agent is used, the amount employed will typically vary from about 1:2000 to about 1:6000 agent:agent/fuel oil, volume:volume.

The amount of slag control agent(s) or other additives employed in coal is subject to the same variables as other fuels, and is usually expressed in terms of parts per million (ppm) and weight percent. The amount of slag control agent(s) employed in terms of “times stoichiomentry” in reference to a certain emission, such as SO₃. Dosage typically ranges from about 100 ppm to about 5 weight percent based on the weight of the coal and may vary depending on the type of additive.

The amount of oxygen-generating agent employed can vary depending upon a variety of process and composition conditions, such as type of oxygen-generating agent selected, load or feed rate of fuel oil, coal, or biomass, amount and type of slag control agent used, amount or feed rate of air, impurity composition of fuel, and the like. When a liquid form of the oxygen-generating agent is used, the amount employed will typically vary from about 1:1000 to about 1:10000 and preferably about 1:2500 to about 1:4000 agent:coal/fuel oil, volume:volume. Expressed as a function of weight, the amount of slag control agent(s) employed typically varies from about 25 ppm to about 3 weight percent.

Additives can be employed separately or in combinations of two or more at the same time and may also be controlled and/or adjusted in real time in accordance with the present invention. The relative ratio of amount or rate of an additive(s) to another additive(s) and/or to the fuel may also be controlled and/or adjusted in real time in accordance with the present invention.

Fuels useful in the process of the present invention can be of any form known in the art, such as fuel oil, coal, or biomass.

Coal useful in the process of the present invention can be of any form known in the art, such as anthracite, bituminous, sub-bituminous, lignite, pet coke, and charcoal.

Fuel oil useful in the process of the present invention is a mixture of flammable, medium-weight hydrocarbons principally used for heating or power generation. It is alternately referred to as residual oil, #6 oil, Bunker C.

Conventional process components and equipment may be utilized to control and vary the feed rates of the fuel and/or additives. Examples of useful process components and equipment include, but are not limited to, flow limiting/controlling devices such as valves; pumps; fans; and conveyor belts.

The process of the present invention is carried out substantially continuously as the operation of a conventional utility boiler is substantially continuous.

Additional teachings regarding the use of additives in coal-fired utility boilers are found in U.S. Ser. No. 12/319,994, filed Jan. 14, 2009, and in oil-fired utility boilers in U.S. Ser. No. 11/311,069, filed Dec. 19, 2005, both of which are incorporated herein by reference in their entireties.

The fuel can be analyzed for a variety of physical and/or chemical properties or parameters. Examples of parameters include the following: calorific value (BTUs); volatile matter (VM); ash; moisture; carbon/free carbon; hydrogen; sulfur; sulfur dioxide; sulfur trioxide; sulfate compounds; nitrogen; oxygen (by difference); ash fusion temperatures (reducing and oxidizing atmospheres); oxides of silica; alumina; iron; calcium; magnesium; potassium; sodium; zinc; copper; titanium; chlorine; bromine; arsenic; mercury; cobalt; nickel; chromium; lead; and cadmium.

Exhaust gas and flue gas can be analyzed for a variety of emissions. Emissions of interest include SO₂, SO₃, H₂SO₄, NO_x, NO, NO₂, Hg, and particulates.

Useful analytical devices and techniques include the following: prompt gamma neutron activation analysis (PGNAA), nuclear magnetic resonance spectroscopy (NMR), and laser induced breakdown spectroscopy (LIBS).

In PGNAA, neutrons are emitted from a radioactive source of Cf-252 and are directed at coal and captured by nuclei of elements (coal constituents). The nuclei become excited and a gamma ray is released (detected by a sodium iodide detector or similar device). The gamma ray energy is characteristic of each element. Cs-137 may also be used as a gamma ray source in some applications.

In NMR, a magnetic field is applied to the sample. The nuclei of the sample absorb the field and radiate the energy back out. The strength of the field is radiated back out and identifies the constituents.

In LIBS, a high power laser is used to form a plasma gas from the sample. A spectrometer analyzes the “plume” that is emitted from the laser pulse to qualify the constituents of the sample.

Other useful analytical devices and techniques include the following: mass spectroscopy (mass spec); inductively coupled plasma spectroscopy (ICP); microwave analyzer for moisture readings; atomic absorption spectroscopy (AA); optical emission spectroscopy (OES); X-ray diffraction spectroscopy (XRD); X-ray fluorescence spectroscopy (XRF); and pulsed fast and thermal neutron analysis (PFTNA).

In the process of the present invention, the number of physical and/or chemical parameters of the fuel and/or emissions variables subject to monitoring can be as few as one or plural, i.e., two or more.

It should be understood that the foregoing description is only illustrative of the present invention. Various alternatives and modifications can be devised by those skilled in the art without departing from the invention. Accordingly, the present invention is intended to embrace all such alternatives, modifications and variances that fall within the scope of the appended claims.

Claims

1. A process for operating a utility boiler, comprising:

a) providing fuel to the boiler;

b) providing one or more additives selected from the group consisting of (i) one or more slag control agents, (ii) one or more oxygen-generating agents, (iii) one or more acid reduction agents, (iv) one or more fouling prevention agents, (v) one or more oxidizer agents, (vi) one or more heavy metal capturing agents and (vii) any combination of the foregoing to the boiler or an auxiliary device thereof;

c) providing air to the boiler;

d) burning the fuel in the boiler to generate heat and an exhaust gas and/or a flue gas; and

e) intermittently or continuously monitoring one or more physical and/or chemical parameters of the fuel and/or intermittently or continuously monitoring one or more emissions variables of the exhaust gas and/or a flue gas to obtain one or more values; and

f) varying or maintaining the rate at which the one or more additives is provided to the boiler or an auxiliary device based on the one or more values obtained.

2. The process of claim 1, wherein the one or more values are communicated in real time to a controller, and wherein the controller provides instructions based on the one or more values in real time to one or more components of the process to vary the rate at which either or both of the fuel and the one or more additives is provided to the boiler and/or its auxiliary devices.

3. The process of claim 3, wherein the one or more emissions variables in the exhaust gas are selected from the group consisting of opacity, particulates, NOx, SO2, SO3, acid level, and Hg.

4. The process of claim 1, wherein the one or more additives is one or more slag control agents selected from the group consisting of magnesium hydroxide, magnesium oxide, magnesium carbonate, magnesium organometallic compounds, magnesium carboxylate, magnesium salicylate, magnesium napthenate, and magnesium sulfonate.

5. The process of claim 1, wherein the one or more additives is one or more oxygen-generating agents selected from the group consisting of calcium hydroxide, calcium oxide, calcium carbonate, calcium carboxylate, calcium organometallic compounds, calcium sulfonate, iron hydroxides, iron oxides, iron carbonates, iron carboxylates, iron organometallic compounds, iron sulfonates, barium hydroxide, barium oxide, barium carbonate, barium carboxylate, barium organometallic compounds, and barium sulfonate.

6. The process of claim 1, wherein the one or more additives is added to the fuel to form a treated fuel, and wherein the treated fuel is then provided to the boiler.

7. The process of claim 1, wherein the one or more additives is provided directly to the boiler.

8. The process of claim 1, wherein the fuel is coal

9. The process of claim 1, wherein the fuel is fuel oil.

10. The process of claim 1, wherein the fuel is biomass.

11. The process of claim 2, wherein the one or more components is selected from the group consisting of a flow limiting/controlling device, a pump, a fan, or a belt speeds.

12. The process of claim 1, wherein the physical and/or chemical parameters of the fuel are monitored by a technique selected from the group consisting of one or more of prompt gamma neutron activation analysis, nuclear magnetic resonance spectroscopy, laser induced breakdown spectroscopy, mass spectroscopy; inductively couple plasma; microwave analyzer for moisture readings; atomic absorption; optical emission spectroscopy; X-ray diffraction; X-ray fluorescence; and pulsed fast and thermal neutron analysis.

13. The process of claim 1, wherein the physical and/or chemical parameters of the fuel is selected from the group consisting of one or more of calorific value; volatile matter; ash; moisture; carbon/free carbon; hydrogen; sulfur; sulfur dioxide; sulfur trioxide; sulfate compounds; nitrogen; oxygen (by difference); reducing and oxidizer ash fusion temperatures; and one or more oxides of any of silica, alumina, iron, calcium, magnesium, potassium, sodium, zinc, copper, titanium, chlorine, bromine, arsenic, mercury, cobalt, nickel, chromium, lead, and cadmium.

14. The process of claim 1, wherein further in step (e) the exhaust gas and/or a flue gas is intermittently or continuously monitored with respect to one or more emissions variables to obtain one or more additional values, wherein varying or maintaining the rate at which either or both of the fuel and the one or more additives is provided to the boiler based on the one or more additional values obtained, and wherein the one or more emissions variables is maintained within pre-determined limits.

15. The process of claim 1, wherein in step (e) the one or more physical and/or chemical parameters of the fuel is intermittently monitored.

16. The process of claim 16, wherein in step (e) the one or more physical and/or chemical parameters of the fuel is intermittently monitored at a period of time elapse of five minutes or less between the end of a test and repeat of the test.

17. The process of claim 1, wherein the physical and/or chemical parameters of the fuel is selected from the group consisting of ash; sulfur; and one or more oxides of any of silica, alumina, iron, calcium, magnesium, potassium, sodium, copper, titanium, chlorine, bromine, arsenic, and mercury.

18. The process of claim 1, wherein the one or more additives are provided to the boiler.

19. The process of claim 1, wherein the rate at which the one or more additives is provided to the boiler is varied or maintained based on the one or more values obtained.