Systems and methods for post combustion mercury control using sorbent injection and wet scrubbing

Abstract

A sorbent composition for removing mercury from flue gas, including a powdered sorbent having a fifty percent distribution particle size of from about 20 micrometers to about 75 micrometers. The invention also include a method of cleaning flue gas, the method including injecting a powdered sorbent into the flue gas, wherein the powdered sorbent has a fifty percent distribution particle size of from about 20 micrometers to about 75 micrometers.

Claims

1. A sorbent composition for removing mercury from flue gas, comprising: a powdered sorbent having a fifty percent distribution particle size of from about 25 micrometers to about 75 micrometers, wherein said sorbent composition does not contain halogen and said powdered sorbent improves mercury removal from flue gas without halogen.

2. The sorbent composition of claim 1, wherein the powdered sorbent has a fifty percent distribution particle size of from about 30 micrometers to about 75 micrometers.

3. The sorbent composition of claim 1, wherein the powdered sorbent is powdered activated carbon.

4. The sorbent composition of claim 1, wherein the powdered sorbents reduce mercury concentrations in the air phase.

5. The sorbent composition of claim 1, wherein the powdered sorbents reduce mercury concentrations in the water phase.

6. A method of cleaning flue gas, the method comprising: injecting a powdered sorbent into the flue gas, wherein the powdered sorbent has a fifty percent distribution particle size of from about 25 micrometers to about 75 micrometers, wherein said powdered sorbent does not contain halogen and said powdered sorbent improves mercury removal from flue gas without halogen; collecting the powdered sorbent in a flue gas desulfurization system; and removing the powdered sorbent from a dewatered slurry in a flue gas desulfurization system using a hydrocyclone in communication with the flue gas desulfurization system.

7. The method of claim 6, further comprising: removing the powdered sorbent from a dewatered slurry in a flue gas desulfurization system using a hydrocyclone in communication with the flue gas desulfurization system.

8. The method of claim 7, further comprising: removing particulates/solids with a vacuum filter after the hydrocyclone prior to liquor discharge.

9. The method of claim 6, wherein the powdered sorbent is powdered activated carbon.

10. A method of cleaning flue gas, the method comprising: injecting a powdered sorbent into the liquor/slurry of a flue gas desulfurization system, wherein the powdered sorbent has a fifty percent distribution particle size of from about 20 micrometers to about 75 micrometers.

11. The method of claim 10, further comprising: removing the powdered sorbent from dewatered slurry in a flue gas desulfurization system using a hydrocyclone in communication with the flue gas desulfurization system.

12. The method of claim 11, further comprising: removing particulates/solids with a vacuum filter after the hydrocyclone prior to liquor discharge.

13. The method of claim 10, wherein the powdered sorbent is powdered activated carbon.

14. The method of claim 10, wherein the powdered activated carbon improves mercury removal without halogens.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) For a more complete understanding of the features and advantages of the present invention, reference is now made to the detailed description of the invention along with the accompanying figures in which corresponding numerals in the different figures refer to corresponding parts and in which:

(2) FIG. 1 is an illustration of a post combustion mercury control using sorbent (in many cases, activated carbon injection (ACI) system) and wet scrubbing according to an embodiment;

(3) FIG. 2 is a chart showing improved mercury capture when using an Improved Sorbent Injection System according to an embodiment;

(4) FIG. 3 is a diagram of the improved results of mercury removal after injection of the activated carbon according to an embodiment; and

(5) FIG. 4 is a flowchart of a process for controlling mercury from process gas according to an embodiment.

DETAILED DESCRIPTION OF THE INVENTION

(6) While the making and using of various embodiments of the present invention are discussed in detail below, it should be appreciated that the present invention provides many applicable inventive concepts, which can be embodied in a wide variety of specific contexts. The specific embodiments discussed herein are merely illustrative of specific ways to make and use the invention, and do not limit the scope of the present invention.

(7) Described herein are embodiments for post combustion mercury control using sorbent (in many cases, activated carbon injection (ACI) system) and wet scrubbing (hereinafter Improved Sorbent Injection System) and methods of using it and making it. In some embodiments, the Improved Sorbent Injection System includes injecting the sorbent at an improved point in the post-combustion cleaning system of a coal-fired power plant (or, in alternatives, other types of power plants and exhaust systems). In some embodiments, the Improved Sorbent Injection System includes injecting the sorbent at a point in the system where it later can be filtered out without affecting other cleaning processes. In many embodiments, the sorbent injected is activated carbon; however, in alternatives, other sorbents may be used. When the term sorbent is used herein, in many embodiments this may be activated carbon, although other sorbents may be used.

(8) The Improved Sorbent Injection System additionally includes the revelation that the available electrostatic precipitators may be on the hot side of an air-heater, which is a more challenging environment for sorbents to remove mercury because of the elevated temperatures and short residence times. Therefore, the Improved Sorbent Injection System includes the use of alternative injection strategies with longer residence times, better mixing, and lower temperatures that are more advantageous.

(9) For facilities burning bituminous coal with substantial levels of sulfur, sulfur trioxide (SO.sub.3) will be generated and be present in the flue gas stream. SO.sub.3 also can be found in substantial quantities when power plants inject it to condition fly ash aiding in its removal. In implementing embodiments of the Improved Sorbent Injection System, it has been noted that PAC and most sorbents traditionally lose their capacity for mercury removal with increasing concentrations of SO.sub.3. In implementing embodiments of the Improved Sorbent Injection System, it has been investigated and determined that SO.sub.3 concentration will be highest right after the boiler and will decrease through the duct system as it sorbs and reacts with fly ash. Additionally, once the temperature cools sufficiently, it will condense to sulfuric acid mist, which does not adversely affect PAC. In implementing embodiments of the Improved Sorbent Injection System, it has been discovered that with typical PAC injection locations before the electrostatic precipitator/fabric filter, SO.sub.3 concentrations are close to the maximum and will cause the largest detrimental effect on mercury removal. Previous mitigation methods are to add a dry sorbent to reduce SO.sub.3 concentrations to improve PAC performance. However, this adds more capital and operating costs. Therefore, embodiments of the Improved Sorbent Injection System have been designed to circumvent adverse impacts of SO.sub.3.

(10) In embodiments of the Improved Sorbent Injection System, alternative injection strategies are utilized. A standard power plant setup typically includes a boiler, followed by an air heater, and followed by a particulate control device (electrostatic precipitator or fabric filter) that exits in an exhaust stack. As air pollution regulations have become more stringent, additional pollution control devices have been added to the standard power plant configuration. Therefore, selective catalytic reduction (SCR) units could be added between the boiler and the air heater for controlling nitrogen oxides (NO.sub.xs). For SO.sub.2 control, flue gas desulfurization units (FGD) could be installed between the electrostatic precipitator and exhaust stack.

(11) Embodiments of Improved Sorbent Injection System provide that PAC will no longer accumulate with the fly ash, since the overwhelming majority of fly ash will occur in the traditional particulate capture equipment (i.e., electrostatic precipitator, fabric filter). Therefore, this fly ash byproduct can be used and sold for various purposes, such as for use in concrete. Since the injection point typically is further downstream, effluent will be cooler. The longer residence time and cooler temperature will lead to improved removal of mercury. After the electrostatic precipitator or other particulate control device, gases that might compete with the activity of the PAC in the removal of the mercury will be lessened. Furthermore, the re-emission of mercury likely is reduced, since more of the mercury will be captured in the PAC and is not available for the reaction in the slurry. Since the mercury will not be as available in the slurry, when the slurry is dewatered, the residual mercury and other reaction byproducts in the dewatered slurry will be lessened. By removing the PAC, the wet flue gas desulfurization solids byproduct integrity can be maintained for reuse, recycling, or disposal.

(12) Embodiments of the Improved Sorbent Injection System were not known or expected, since the wet flue gas desulfurization system is used for control of SO.sub.2 gases; and using it for particulate removal of powdered sorbents is an unexpected application. The wet flue gas desulfurization unit is quite suited for the removal of powders, even though this is not a typical application. Mercury removal will occur in the gas phase, and then be retained during contact in the wet flue gas desulfurization unit. Those in the art focus on capturing mercury from the liquid phase of a wet flue gas desulfurization unit. In contrast, the position of the injection of powdered sorbent provides gas phase capture of mercury in parallel with liquid phase mercury capture. SO.sub.3 will be lower downstream of the particulate control devices, thereby reducing the exposure of the sorbent to this detrimental acidic compound and thereby eliminate the need to apply dry sorbent injection to eliminate SO.sub.3 before it comes into contact with the sorbent. Also, since the temperature of the flue gas will be cooler at the point of injection, the activity of SO.sub.3 is reduced. Also for wet flue gas desulfurization units, the powdered sorbent materials contribute to the reduction of other unwanted reactions and constituents in the discharged liquid (such as heavy metals and nutrients) after contact with the slurry. In this way, there is the advantage of serving as two treatment processes (one for mercury removal and the other for wastewater treatment) encompassed by one material and system.

(13) In one embodiment, specifically engineered PACs for mercury removal are applied with sorbent injection for mercury removal from coal-fired power plant flue gas. In concert with the engineered PACs, complimentary improvements to the overall system are provided.

(14) Furthermore, if PAC is utilized as the sorbent, it can be engineered also to improve wet flue gas desulfurization slurry chemistry and improve the quality of the discharged wastewater. In fact, some systems may teach that merely the injection of PAC prior to the flue gas desulfurization is sub-optimal and call for the injection of additional materials and other treatments. However, by the proper positioning of the injection site of the PAC, at proper temperatures and after the removal of much particulate, with the proper PAC selection an advantageous system is achieved.

(15) Referring initially to FIG. 1, an embodiment of an Improved Sorbent Injection System (system) is schematically illustrated and generally designated 100. System 100 may be a coal-fired electric power generation plant, in one embodiment. System 100 may include a boiler 102, such as for a coal-fired power plant. Although the example described herein applies to coal-fired power plants, the process gas or flue gas to be treated may originate from many industrial facilities such as a power plant, cement plant, waste incinerator, or other facilities that will occur to one skilled in the art.

(16) Such gas streams contain many contaminants and/or pollutants, such as mercury, that are desirable to control and/or decrease in concentration for protection of health and the environment. Nevertheless, system 100 is being described for removing, controlling, and/or reducing pollutants, such as mercury, from a coal-fired power plant gas stream using one or more of activated carbon injection devices/units and additive injection devices/units as discussed herein. Boiler 102 may be a coal-fired boiler that burns or combusts coal to heat water into superheated steam for driving steam turbines that produce electricity. These types of power plants are common throughout the U.S. and elsewhere. Boiler 102 may further include an economizer 104, in one embodiment. Economizer 104 may be used to recover heat produced from boiler 102.

(17) The flue gas or process gas 106 exiting boiler 102 and/or economizer 104 may then be flowed, transported, ducted, piped, etc. via one or more process lines 108 to a selective catalytic reduction unit 110 for the removal of nitrogen containing compounds, in one embodiment. Typically, selective catalytic reduction unit 110 may convert NO.sub.x compounds to diatomic nitrogen (N.sub.2) and water (H.sub.2O) using a catalyst and a gaseous reductant, such as an ammonia containing compound.

(18) Process gas 106 may then be flowed, transported, ducted, piped, etc. to a heat exchanger, pre-heater, and/or air heater 112 where heat is transferred from process gas 106 to a feed of air to be fed back into boiler 102. Process gas 106 may then be transferred via process line 108 to an electrostatic precipitator 114 for removal of particulates contained in process gas 106, in one example.

(19) System 100 may also include an additive injection device/unit 116 for injecting one or more compounds, chemicals, etc., such as organosulfides, inorganic sulfides, acids, bases, metal oxides, oxides, metals, photocatalysts, and/or minerals to aid with sorbent performance. Preferably, additive injection unit 116 is located downstream of electrostatic precipitator 114 for injecting these compounds and/or chemicals prior to injection of activated carbon products as discussed herein. System 100 may further include one or more activated carbon injection (ACI) devices, units, systems, etc. (ACI unit 118). ACI unit 118 may include an activated storage vessel, such as a powdered activated carbon (PAC) storage vessel. Such vessels may be silos, and the like where activated carbon, such as PAC, may be stored for use in system 100. Activated carbon silo (not shown) may be any type of storage vessel such that it is capable of containing a supply and/or feedstock of activated carbon, such as PAC, for supplying the activated carbon to process gas 106 of system 100. Some additional exemplary activated carbon silos may include supersacs, silos, storage vessels, and the like.

(20) Activated carbon may be injected anywhere along process line 108 downstream of additive injection unit 116, preferably. In one embodiment, system 100 may include one or more fluidizing nozzles 120 that may assist in providing activated carbon in a fluidized form, such that it may be transported in a substantially fluid form downstream in system 100. Additionally, system 100 may include one or more control valves (not shown) that may be disposed and/or located substantially proximal to the exit or outlet of activated carbon and/or fluidizing nozzles 120 for controlling the flow of activated carbon from ACI unit 118 to system 100. The feed of activated carbon can also be controlled by a series of additional control valves, movable barriers, etc. (not shown). To assist the process of fluidizing activated carbon for exiting ACI unit 118, fluidization assistance may be applied in the form of physical agitation or the use of fluidizing nozzles. In addition, system 100 may include other types of control valves, such as manual valves (not shown), and the like as would be known to those skilled in the art.

(21) The treated process gas 106 may then be sent to a flue gas desulfurization unit 122 via process line 108 for removal of sulfur compounds, in one embodiment. After being treated in flue gas desulfurization unit 122, treated process gas 106 may then be sent to a stack 124 for emission into the environment. As is known to those skilled in the art, flue gas desulfurization unit 122 may have an gas/air phase and a liquid/water phase; system 100 described herein reduces mercury concentrations in the air phase and liquid phase of flue gas desulfurization unit 122, such that the discharge water of flue gas desulfurization unit 122 has a lower concentration of mercury in the process or flue gas than prior to upstream of ACI unit 118.

(22) Additionally, activated carbon is used to target reduced concentrations of nitrates/nitrites and heavy metals, such as mercury, arsenic, lead, and selenium in the liquid or wet phase of flue gas desulfurization unit 122 such that the discharge water of flue gas desulfurization unit 122 has lower concentrations of these contaminants in the process or flue gas than prior to upstream of ACI unit 118.

(23) In one embodiment, activated carbon of system 100 is used to target reduced concentrations of mercury in the gas/air phase and reduced concentrations of nitrates/nitrites and heavy metals such as mercury, arsenic, lead, and selenium in the wet phase of flue gas desulfurization unit 122. System 100 may also include a hydrocyclone 126 for further removal of particulates in the wet flue gas desulfurization unit liquor prior to discharges. Hydrocyclone 126 may be used to remove activated carbon, powdered sorbent, powdered activated carbon, and the like from the wastewater of the wet flue gas desulfurization unit 122. Hydrocyclone 126 may also be followed by a vacuum filter that will further remove particulates/solids prior to liquor discharge.

Example 1Preparation of PAC

(24) A magnetic activated carbon sample with 6% by weight of magnetite (Fe.sub.3O.sub.4) was prepared with PAC treated with a wet method to precipitate ferric chloride and ferrous sulfate in 200 lb. batches followed by dewatering and drying at 200 C. The dried product was sieved and resulted in about 95% of the final product passing through a 325-mesh sieve.

Mercury Removal

(25) The product was tested at the Mercury Research Center (MRC). The MRC removes a constant flow of approximately 20,500 actual cubic feet per minute (acfm) of flue gas (representative of a 5 mega watt [MW] boiler) from the Southern Company Plant Christ Boiler (78 MW). The boiler runs on a low-sulfur bituminous coal blend from varying sources. The typical SO.sub.3 concentration of the fuel blends resulted in about 2 parts per million (ppm) of SO.sub.3. FIG. 2 shows improved mercury capture when using an embodiment of an Improved Sorbent Injection System. The product was pneumatically injected at increasing injection rates upstream of the electrostatic precipitator (ACI 1 in FIG. 2) and downstream of the electrostatic precipitator (ACI 2 in FIG. 2). Particulate removal was achieved with the electrostatic precipitator for ACI 1. Particulates remained uncaptured for ACI 2, and returned to the Christ process train. Mercury concentrations were monitored at the MRC inlet and the MRC outlet, and the observed concentrations were converted to pounds per trillion British thermal units (lb/Tbtu) using the standard EPA Method 19. Mercury removal by the AC was calculated as the inlet mercury concentration minus the outlet mercury concentration and is illustrated in FIG. 2. At typical injection rates and above, less AC is necessary to remove the same amount of AC which would result in significant cost savings for the utility.

Example 2Preparation of PAC

(26) A coal-fired power plant with a 540 MW unit was conducting a trial to inject a powdered sorbent into the wet scrubber sump which was subsequently pumped into the absorber vessel. The powdered sorbent met the typical 95% passing the 325 mesh with a d50 particle size of 15 microns. Albeit vapor phase mercury emissions went down based on continuous emissions monitoring equipment, the unit began experiencing elevated levels of mercury in their sorbent traps. This was because Hg bound to the fine PAC particles was escaping past the mist eliminators and being captured in the sorbent trap. Furthermore, the fine PAC particles began clogging the rotary vacuum filters, causing the system to shut down.

(27) In a second trial of the Improved Sorbent Injection System, a powdered sorbent with 50% passing the 325 mesh and a d50 particle size of 45 microns was added to the sump and subsequently injected into the absorber.

(28) Turning now to FIG. 3, data shows the improved mercury capture when using an embodiment of an Improved Sorbent Injection System. The larger particle size sorbent decreased dusting during handling and injection of the sorbent into the sump. Furthermore, the rotary vacuum filters remained operational without any issues. In addition, sorbent trap data matched the continuous emissions monitor data to indicate that no opacity issues with sorbent past the mist eliminators was observed.

(29) Turning now to FIG. 4, a method for controlling mercury removal in flue gas or process gas is schematically illustrated and generally designated 400. In step 402, process or flue gas may be transferred to a pre-heater for heat transfer to an air source to be fed back into a particular unit, such as boiler 102. This step may also include transferring the process or flue gas to an economizer prior to transferring it to a SCR, such as selective catalytic reduction unit 110.

(30) In step 404, the process or flue gas may be transferred to a particulate collection device/unit, such as electrostatic precipitator 114. This step may include removing particulates from the process or flue gas. In step 406, a chemical and/or compound may be injected into process or flue gas downstream of the particulate collection device/unit, such as electrostatic precipitator 114. This step may include contacting the process and flue gas with one or more of organosulfides, inorganic sulfides, acids, bases, metal oxides, oxides, metals, photocatalyst and/or minerals to aid with activated carbon/sorbent performance.

(31) In step 408, the process or flue gas may be contacted with activated carbon, such as from ACI unit 118. In this step, activated carbon may be PAC. Preferably, such contact occurs downstream of the injection described in step 406. Such contacting of the process or flue gas with activated carbon after the injection described in step 406 reduces the mercury concentration of the process or flue gas. In step 410, the process or flue gas is transferred to a wet flue gas desulfurization unit, such as flue gas desulfurization unit 122, where the powdered sorbent material contributes to the reduction of other unwanted reactions and constituents in the discharged liquid (such as heavy metals and nutrients) after contact with the slurry in flue gas desulfurization unit 122. In this way, there is the advantage of serving as two treatment processes (one for mercury removal and the other for wastewater treatment) encompassed by one material and system.

(32) Additionally in this step, activated carbon is used to target reduced concentrations of nitrates/nitrites and heavy metals, such as mercury, arsenic, lead, and selenium in the liquid or wet phase of flue gas desulfurization unit 122 such that the discharge water of flue gas desulfurization unit 122 has lower concentrations of these contaminants in the process or flue gas than prior to upstream of ACI unit 118. In step 412, the process or flue gas may be transferred to a stack for emitting to the environment.

(33) In another embodiment of the present invention, the particle size of the sorbent may be increased to reduce or eliminate the issues of increased dusting and opacity issues, long wetting times, plugging of vacuum filters, and the like. In one aspect, the particle size for environment 50% distribution (d50) of the sorbent particles may be from about 20 micrometers to about 75 micrometers. This means that approximately 50% of the sorbent particles have a particle size of less than this range and 50% of the sorbent particles have a particle size of more than this range. Additionally, the systems and sorbents described herein may decrease the distribution and/or amount of sorbent having particle sizes of less than 20 micrometers, less than 15 micrometers, less than 10 micrometers, and less than 5 micrometers.

(34) In one embodiment, such sorbents having a d50 of from about 20 micrometers to about 75 micrometers may be injected in the flue gas just upstream of flue gas desulfurization unit 122. In another embodiment, such sorbents may be injected into the absorber vessel of flue gas desulfurization unit 122.

(35) While this invention has been described with reference to illustrative embodiments, this description is not intended to be construed in a limiting sense. Various modifications and combinations of the illustrative embodiments as well as other embodiments of the invention will be apparent to persons skilled in the art upon reference to the description. It is, therefore, intended that the appended claims encompass any such modifications or embodiments.