WO2000015323A1

WO2000015323A1 - Process for the removal of pollutants from flue gases

Info

Publication number: WO2000015323A1
Application number: PCT/AU1999/000761
Authority: WO
Inventors: David Sterling
Original assignee: Individual
Current assignee: Individual
Priority date: 1998-09-11
Filing date: 1999-09-13
Publication date: 2000-03-23
Anticipated expiration: 2001-03-11

Abstract

Disclosed is a process for removal of pollutants from flue gases including the following sequential steps: a) recovering waste heat from said flue gases in a waste heat recovery stage; b) removing particulates from said flue gases in a particulate removal stage; c) removing sulphur dioxide from said flue gases in a sulphur dioxide removal stage; d) removing NOx from said flue gases in an NOx removal stage; e) controlling pressure with a make up feed gas stage; and discharging treated flue gases to atmosphere. Carbon monoxide and/or carbon dioxide removal stages may be incorporated following NOx removal, as necessary.

Description

PROCESS FOR THE REMOVAL OF POLLUTANTS FROM FLUE

GASES Field of the Invention

The present invention relates to a process for removal of pollutants from all types of flue gas systems associated with combustion cycle equipment, for^{^} example, flue gas systems for treating flue gases emitted from industrial installations, such as power plants. Background to the Invention

The effective removal of industrial flue gas stream pollutants is of growing concern throughout the world and there is common agreement between climatic scientists that the earth is going through a global warming cycle.

Key pollutants are gases such as sulphur dioxide, nitrous oxide; and solids or particulates associated with burning fossil fuels. Also of concern are emissions consisting of carbon monoxide, a poisonous gas, and carbon dioxide, a greenhouse gas. The former gases are commonly called "acid gases" and are responsible for both acid rain and respiratory complaints in humans, while the latter gases can be referred to as "greenhouse gases" and contribute to the overall greenhouse effect associated with natural events such as volcanism, lightning strikes, bush and forest fires; and seeps from hydrocarbon sources. The atmospheric load of such gases is contributed to by all types of industrial plants such as power stations, petrochemical plants, oil and gas facilities, and general industry. Deforestation and aircraft emissions may also be major contributors to the atmospheric load of polluting gases.

Both fossil and hydrocarbon fuels are used as a feedstock and hydrocarbons are used in many industries because of their unique properties that allow fractionation, reaction, reforming and conversion into many different products which are seen as indispensable to the modern world.

The users of hydrocarbons produce exhaust gases which, when added to coal, refined extractions such as naphtha and methanol, methane (untreated gas), and LPGs (butanes, propanes and so on), discharge polluting elements to the atmosphere.

For power, petrochemical and other industries using combustion operations, simple modifications to burner systems may reduce NO_x emissions by improved control using excess air during the combustion sequence.

Current treatment systems may utilize various combinations of particulate separation by electrostatic precipitators with lime injection; SO₂ removal units; N Oχ removal units; in-line filtration (as demonstrated by the Argonne laboratories); selective catalytic removal; sorbent and ammonia injection systems.

Such systems are installed using existing flue gas system designs via

"take-offs". The resultant 'stripped' flue gas stream then passes to atmosphere, generally through high dispersion types of flue stacks suitable for dispersal of flue gases still remaining environmentally unacceptable levels of pollutant gases.

Summary of the Invention

It is the object of the present invention to provide a process for removing pollutants from flue gases which is adaptive to particular feedstocks used in combustion, for example, in power generation and like installations.

With this object in view, the present invention provides a process for removal of pollutants from flue gases including the following sequential steps: (a) recovering waste heat from flue gases in a waste heat recovery stage; (b) removing particulates from said flue gases in a particulate removal stage;

(c) removing sulphur dioxide from said flue gases in a sulphur dioxide removal stage;

(d) removing NO_x from said flue gases in an NO_x removal stage;

(e) controlling pressure with a make up feed gas stage; and discharging treated flue gases to atmosphere.

Advantageously, the process includes, as further steps, one or both of

(f) removing CO from said flue gases in a CO removal stage; and

(g) removing CC^ from said flue gases in a CO₂ removal stage.

Where combustion systems are of low flow, the process may exclude the carbon monoxide and carbon dioxide removal stages. Carbon monoxide and carbon dioxide pass to atmosphere with the stripped flue gases. In normal or high mass flow, flue gases are passed through stages (a) to (g) to maximise the effective and efficient removal of both pollutants and emissions with gases, substantially consisting of nitrogen, oxygen and trace pollutants, passing to atmosphere.

In the case where CO/CO₂ removal steps are employed, heat exchange is conducted following the NO_x removal stage to control temperature of gases^~ entering any CO₂ removal stage which advantageously employs temperature sensitive diglycol amine ("DGA") as stripping agent. Heat exchange following

NO_x removal in other embodiments employing only steps (a) to (e) is possible but probably redundant. Flue gases treated in steps (f) and/or (g) may then be discharged to atmosphere.

The flue gases treated by the process may include those produced by combustion of feedstocks such as fossil fuels, liquid or gaseous hydrocarbons, cracked hydrocarbons and any other HHV or LHV product used for feedstock. Treated flue gases are suitable for discharge through a welded pipe-section cold vent rather than a high dispersion reinforced concrete flue stack, following final removal of any remaining liquid in a knock out vessel located prior to the cold vent.

Fossil fuels may include coals of anthracitic or lignitic type. Hydrocarbon liquids may include Bunker C oil, crude oil, diesel and kerosene. Liquid or gaseous hydrocarbon gases may include fractionated elements such as butanes, propanes, ethane and methane. Cracked hydrocarbons may include naphtha.

The feedstocks produce different levels of pollutants and emissions and the process is adaptive to suit pollutant variations while maintaining high efficiency in removal of these.

The process may be implemented within an existing plant without affecting design criteria of the combustion processes used within the plant, whether involving furnaces, fired heaters or other combustive sources. The process is suitable for all types of industry in which combustion processes are used.

The process may be used in conjunction with large power generation facilities at present in use or in design and can be downsized to suit small, independent package boiler power generation systems, or diesel engine powered systems. The processes can be used with petrochemical fired heaters that are linked in tandem, gas turbine power generation sets, cogeneration power generation systems, mining power generation units, steel manufacturing- furnaces and power generation systems, food and beverage industries that use waste heat and package boiler systems.

Each removal stage may comprise of a modular system that is interconnected, as desired, with other removal stages. The stages can be independently constructed and transported to any particular plant area in which the pollutant removal system is used. The process, mechanical, electrical and instrumentation design may allow for each module to be fully self-contained with all required systems and sub-systems ready to be connected as the pollutant removal system is assembled. The system comprises utility and process modules. The utility module acts as either a direct connection between a single particular service or multiple, that is, two or more services, installations or plants supplying treatable flue gases (or what can be termed a "centralised system") and the rest of the pollutant removal system. It may comprise a waste heat recovery stage, taking the form of one or more of the following: air preheating, radiant/convective heat removal and attemporation system with injection media control dependent upon the size of the system.

The particulate removal stage may include variable load plate assemblies operating on the principle of impingement separation; and filters, for example a drum screen filter for final cleaning; as well as pumping systems, separation vessel make up facilities and export facilities.

The sulphur dioxide removal stage may involve absorption, for example scrubbing in packed beds using a suitable absorbing agent. Sodium sulphite solution is one example. Pumping systems, reaction and regeneration vessels, export facilities and make up facilities are included.

The NO_x removal stage involves decomposition of nitrous oxides to nitrogen and oxygen at temperature above decomposition temperature. Heaters are included to heat the NO_x decomposition reactor to required temperature.

Carbon monoxide is catalytically converted to carbon dioxide in the carbon monoxide removal stage where employed in the process.

Carbon dioxide removal from the flue gas stream is to be recovered by amine scrubbing, advantageously with diglycol amine, and stored for re-use.^' Carbon dioxide is advantageously injected into oil and gas reservoirs as these deplete, improving the recovery of oil and gas. Such reservoirs provide good storage availability and capacity, though other storage systems may less advantageously be used. Carbon dioxide is advantageously stored after treatment for re-use and may be used in a wide variety of industrial applications.

In a further aspect of the invention, there is provided a system for removal of pollutants from flue gases including the following sequential stages

(a) a waste heat recovery stage;

(b) a particulate removal stage; (c) a sulphur oxide removal stage;

(d) an NO_x removal stage;

(e) a pressure control stage; and a treated flue gas discharge system, particularly a cold vent, from which treated flue gases are discharged to atmosphere. Advantageously, as described above, the system may include as further stages, one or both of

(f) a CO removal stage; and

(g) a C0 removal stage.

In the case where CO/CO₂ removal stages are employed, a heat exchange stage is conducted following the NO_x removal stage to control the temperature of gases entering any CO₂ removal stage which advantageously employs diglycol amine ("DGA") as stripping agent. Heat exchange in other embodiments, employing only steps (a) to (e), is possible but probably redundant. In such case, flue gases subjected to additional treatment in stages (f) and/or (g) are discharged to atmosphere.

The system and process may be designed to treat flue gases from multiple installations operating a combustion cycle. Such multiple installations would be connected or tied-in to the waste heat recovery stage.

The various aspects of the inventive system and process are most suited to the treatment of emissions from fossil fuel systems. However, the system is equally effective with other feedstock types such as hydrocarbon gases anch liquids, methane, ethane, butane, propane, crude oil, Bunker C oil, diesel and kerosene, and fractionated products such as naphtha. Description of the Drawings

The process and system of the invention will be more fully understood from the following description of a preferred embodiment thereof made with reference to the accompanying drawings in which:

Figure 1 is a flowsheet of a process and system operated in accordance with a first embodiment of the invention;

Figure 2 is a flowsheet of a process and system operated in accordance with a second embodiment of the invention; and

Figure 3 is a flowsheet of a process and system operated in accordance with a third embodiment of the invention;

Figure 4 shows a modification of the process and system flowsheet of Figure 1 for treatment of flue gases from multiple installations. Detailed Description of Preferred Embodiment of the Invention

Referring now to Figure 1 , flue gases that exit from the exhaust opening 12 of a furnace or plant in which combustion takes place pass first to the utility module 10. The design of this particular module is based on the particular requirements of the furnace or plant in which the pollutant removal system is installed and takes into account feedstock nature, plant size and flue gas mass flow. Utility requirements may also impact on design of this module. For example, where the plant is capable of providing uninterrupted utility services such as electrical power and thermal energy, such as high pressure superheated steam, then the utility module 10 design may reflect that. The utility module 10 has a steel outer casing 10a and is designed to connect into the exhaust opening 12 of the furnace or plant where the combustion cycle takes place. The connection is made at a flange which is fitted with a flexible collar which prevents the casing 10a from having external applied static and dynamic loads imposed upon it by weight, operating characteristics and environmental conditions, including seismic loading where applicable.

The casing 10a has flanged ends 14 to allow connection both to the combustion stage and the remaining modules of the pollutant treatment system. ^~

The utility module 10 may be a waste heat recovery stage or unit. This option is used where flue gas mass flow, temperature, and economic considerations justify the pollutant removal system raising its own High Pressure

Superheated steam passed through steam drum 120 for the purposes of driving a steam turbine 122 which, in turn, drives electrical alternator 124 to provide power within the pollutant removal system. Produced steam can be used in other stages or modules such as the nitrous oxide removal module heat exchanger tube bank bundles; and as jacket steam for a cyclonic separator vessel for the particulate removal module. The waste heat recovery unit includes tube bundle(s) which may be supplied by the plant with boiler feed water from the boiler feed water line 1200 at temperature and pressure to allow the contra flow tube bundle to convert the introduced boiler feed water 1200 into high pressure superheated steam. The resultant steam is then passed to a high pressure steam drum 120, drives steam turbine 122 with recovered medium pressure steam 1000 used as required within the pollutant removal system or exported back to the plant.

Electrical power excess to the pollutant removal system requirement may also be exported to the plant for use or onward sale.

The utility module 10 may take the form of an air pre-heater tube bundle. Where utility supplies of both electrical power and superheated steam are sufficiently reliable, the utility module 10 or section can be used as an air pre- heater for preheating air supplied to the boiler or furnace to which the pollutant removal system is connected. In such a case, supplied utilities such as electrical power provide the electrical and control requirements of the pollutant removal system. Superheated steam provides heat energy for the modules of the pollutant removal system.

The utility module 10 may take the form of a radiant/convection section. For small operating facilities where steam raising is not possible, but electrical power is supplied, where the pollutant removal system - electrical resistance heating may be used as an alternative, and still provide the same levels of efficiency in the removal and treatment of pollutants and emissions. Thermal control within such a small system may be through a radiant/convection section^" where the utility module casing may act as a cooling medium.

Attemporation may be employed. Where combustion systems use clean feedstock such as LNG, or fractionated gases such as LPGs, the utility module or section can be fitted with attemporation spray nozzles. This option provides temperature control via a quenching medium such as water.

Whatever the option employed, the utility module 10 forms the first and essential link between the combustion source and the rest of the pollutant removal system.

From the utility module 10, the flue gases pass to the process stages of the flue gas treatment process. Each process module 20-50 and 80 making up each stage of the flue gas treatment system is designed to create a direct flow path through the entire pollutant removal system so that only treated or produced product is drawn off from the process. At no stage of the process do the flue gases exit and return to the pollutant removal system. From inlet at the utility module 10 until discharged as warm non-toxic, non-acidic gases through the cold vent(s) 90, the process and system steps are in-line, inter-related and continuous.

Each utility and process module is designed such that servicing and maintenance can be conducted while each module remains on-line. The first process module is the particulate removal module 20. This module achieves very high, up to 100%, removal of suspended solid matter present in the flue gases that form in a complete or incomplete combustion process.

The amount and nature of suspended solids present within the flue gases are dependent on the type of feedstock used, combustion process efficiency, and design of the particular furnace or combustion equipment.

Where fossil type fuels such as crushed coal, pulverised coal, brown coal or lignite are used, or in fluidised bed furnaces, high levels of particulate matter, including fly ash, mining detritus or other unburnt solids pass into the flue gas system through the utility module and enter the particulate removal module 20. The particulate removal module 20 outer casing 20a is constructed of steel and is designed with flanged connections 20b designed to connect bothr the utility module and the sulphur dioxide removal module. The flanged connections include flexible sleeves which prevent the casing 20a from having external applied static and dynamic loads imposed on it by weight, operating characteristics and environmental conditions, including seismic loading where applicable.

Particulate and unburnt hydrocarbons removal involves impingement separation which advantageously involves use of variable load plates (VLPs) 22 with one final 'clean up' drum filter 24. Dependent on the size of the pollutant removal system, two or three variable load plates 22 are provided. Two variable load plates 22 are shown. Each variable load plate 22 consists of HT alloy steel drilled with pathway holes that vary in size from small (50mm diameter) to large (100mm diameter). Each variable load plate 22 is welded together with spacer bars and side and top plates to form a tortuous path for the flue gas stream, enhancing capture of particulate matter. Each variable load plate 22 is suspended from variable load supports angled away from the flow path to maximize the surface area to reduce high differential pressure losses at each stage.

Each variable load plate 22 sits in guides 24 fitted internal to module 20. With radial clearance in the guides 24, the variable load plates 22 are allowed to 'float' suspended from the variable load plate supports. Through vibration and turbulence within the flow particulate matter will be collected in a hot sump 26.

Hydrated lime is injected into the entry of the particulate removal module, 20 upstream of the first variable load plate 22 through lime line 300, and via directed flow path through the VLPs 22 and the drum filter 24, the resultant gypsum will be removed via a hot well, treated and pumped to export 200 for use in building materials. Each variable load plate 22 extends into the hot sump where the combination of hydrated lime and particulate residue is water washed, the resultant slurry is then drawn from the hot sump by PD screw type NEMO mono pumps 28 and pumped to a cyclone separator 27. The cyclone separator 27 removes water and allows it to be recovered, filtered and re-injected into the water wash system 210. The resultant gypsum is drawn out of the bottom nozzle of the vessel and shipped by screw type mono pumps 29 to export facilities 220.

Liquid flashed off within the cyclone separator 27 pass out of a top vent nozzle, are cooled and reintroduced to the filtration process as make-up water stream 210.

Where used with gas or fractionated gases, such as LPG, particulate removal module 20 may include only the final filter as particulate levels are negligible in comparison with solid combustion processes. Sulphur dioxide removal module 30 is the second stage of the pollutant removal process and is conducted by chemical injection, reaction and regeneration.

Various scrubbing solutions may be used for sulphur dioxide removal, for example sodium sulphite, magnesium oxide, sodium citrate, ammonia or potassium carbonate and other salts.

Sodium sulphite scrubbing, in association with hydrated lime injection, may be preferred for large coal fired power stations. Actual selection depends on cost, equipment complexity and lifetime costs.

The sulphur dioxide removal module 30 involves spray injection, water and solution. Sodium sulphite and hydrated lime, from lime storage 320 are injected in an upstream direction such that the wetted sulphur dioxide combines with the sodium sulphite solution. The resultant dense phase vapour passes through two stage packing beds 32 which may usefully be packed with prill rings for capture and discharge of the absorbed materials. Each packed bed 32 is sized for maximum recovery of the scrubbing solution with the primary bed 34 being provided with an additional water wash.

The amount and rate of water injected into the flue gas stream is controlled to prevent precipitation. Passing into a linked hot sump, the resultant sodium sulphite solution is pumped by the sodium sulphite pumps into a heated reaction vessel 31 where product calcium sulphide slurry is drawn off and remaining liquids are passed into a regenerator vessel 33. The temperature of reaction vessel 31 is maintained high enough to prevent scaling. Calciurrr sulphide is exported at 310.

Active absorbed sodium sulphite is regenerated in regeneration vessel 33 and passed back into the injection system. Make up sodium sulphite solution is drawn from a bulk storage tank 35, as required. Sulphur dioxide removal efficiency is between 90 and 99%.

The N0_X removal module 40 forms the third stage of the process for the pollutant removal system. Its location is selected to minimise inlet temperature at module 40 to maximize reactor efficiency and to act as a transition section to make-up feed module 50. To effect removal of nitrous oxides, remaining flue gases enter the NO_x reactor at a temperature of less than 150°C. The reactor itself is maintained at 600°C - a temperature above that minimum threshold temperature consistent with the optimum breakdown of the molecular structure from NO_x to nitrogen and oxygen which is 580°C.

The reactor 40 is a venturi type reactor. The flue gas enters a small nozzle to reactor 40 and expands, velocity falls and a number of baffles ensure reaction takes place.

The reactor 40 is lined with high density Gunnite refractory and has three high pressure superheated steam tube banks (not shown) installed in-line through the reactor 40. Each stage of the steam tube banks maintains the inside of the reactor at 600°C ensuring that optimal decomposition of NO_x into nitrogen and oxygen takes place. Partition plates for the tube tanks may be coated with a suitable catalyst/catalyst mixture to aid in cracking out of oxides.

The NO_x removal module 40 also includes a transition 42 from rectangular section of previous portions of the pollutant removal system to a round section. The inlet plenum casing 43 is provided with air dampers and interlinked control system for the make-up feed air or pressure control module 50 which is the next stage in the process via flexible bellows. As shown in Figure 3, a heat exchanger module 55, which may include one or a number of shell/tube heat exchangers, is provided between the NO_x removal module 40 and the make up feed module 50 to reduce flue gas temperature passing to CO and CO₂ removal stages. This is necessary to keep CO₂ amine stripping agent degradation level low. The heat exchanger may be^" of any acceptable kind but may consist of a rectangular section casing with a large bore single pass tube bundle to remove heat from the process stream. Ambient air is supplied to the inlet side of the tube bank as a cooling medium and, following preheating, discharges at the end of the single pass tubes preferably to be used for heating of combustion air at the boiler or other heating duties around the plant.

Target exit temperature at the discharge end of the heat exchanger should be a maximum of 130°F, but the nominal temperature at discharge should be 100°F. Higher temperature may adversely affect amine performance, whether or not DGA, DEA or MEA stripping agents are used.

In this case, the heat exchanger module 55 includes a transition from the rectangular section of previous portion of the pollution removal system to a round section. The inlet phenum casing is provided with air dampers and interlocked control system for the make up feed air module which is the next stage of the system via flexible bellows.

The make-up feed module 50 (MUF module) forms the next stage of the pollutant removal system and is the third stage of the non-process utility modules. The primary purpose of the MUF module 50 is to maintain the design operating parameters at the burner fronts in the boiler/furnace by controlling the differential pressure (Dp) across the pollutant removal system. The MUF module may be configured to allow ambient air into the pollutant removal system by controlled dampers on the inlet of the fan casing 45. Such ambient air may be used to cool exit gases from the NO_x reactor 40. Where CO and CO₂ removal stages are included, however, no make up air should be introduced as such may cause CO₂ amine stripping agent degradation. Rather, heat exchanger 50 is used for temperature control purposes.

The MUF module 50 comprises an adaptive tie-in stage to the preceding NO_x module 40. The casing 50a design comprises a flexible connection to the previous module and the discharge plenum to the cold vent 90, inlet dampers and actuation control and includes a semi-enclosed impeller type fan 44 operated by a variable speed motor 46 under PLC or other control systems as dictated by the design criteria.

The ID fan 44 may be provided with a second electric motor if warranted to protect the operation of the pollutant removal system.

The MUF module 50 is controlled by the pollutant control system PLC controller, or other control system as dictated by the design criteria, and is directly linked to furnace-boiler-burner and air controls to establish differential pressure and furnace pressure control. With control established, and subject to the constraints above that air should not be introduced where CO₂ is removed by amine stripping, the secondary function of the MUF module 50 is to provide cooling to the flue gas stream exiting the NO_x module 40 and maintains velocity within the gas stream. The MUF module 50 is designed to operate from 0% to 110% at continuous load.

During start-up, the air dampers are fully open to prevent the potential of a vacuum occurring within the system. Once flow is established in the boiler, the damper control is taken over by the PLC, or other control system as dictated by the design criteria, boiler controls and operated on command.

The MUF module 50 fan is dynamically balanced and fitted with sealed "lifed" bearings. Materials of construction should be suitable for a corrosive atmosphere and all parts exposed to flue gas stream must conform to the requirements of NACE MR 0175. Following the MUF module 50, the remaining flue gas stream is passed to atmosphere via one or more cold vents. The cold vent(s) 90 is/are designed on the principle of a pipe flue with a steel support structure being distinguishable from a high dispersion stack. Welded pipe sections comprising the cold vent(s) 90 can be elevated to any desired height to release the stripped flue gas stream. The vented gas has low levels of CO present, if no re-burn design exists within the furnace/boiler, and CO₂.

Sizing of the cold vent(s) 90 is determined in line with the capacity of the pollutant removal system. The cold vent(s) 90 may include monitoring equipment such as sensor probes or gas probes monitoring discharge levels of pollutants and emissions for compliance with regulatory levels. Expected levels are extremely low and the bulk of the gas is nitrogen with CO₂ present, as well as oxygen from the MUF module 50.

It will be noted that this embodiment of the pollutant removal system does not include provision for CO and/or C0₂ removal. It is suitable for treatment of low mass flow flue gas streams.

Where CO and CO₂ removal is required, as in the case of higher mass flow flue gas streams, for example, the pollutant removal systems may be modified accordingly as shown in Figure 2.

The system of Figure 2 may be designed similarly to that of Figure 1 but the system further includes CO and CO₂ removal modules 60 downstream of the MUF module. Either one or both of CO and CO₂ removal modules may be omitted, if desired, and appropriate.

In such case, each process module 20-80 making up each stage of the flue gas treatment system is designed to create a direct flowpath through the entire pollutant removal system so that only treated or produced product is drawn off from the process. At no stage do the flue gases exit and return to the pollutant removal system. From inlet at the utility module 10, until discharged as warm non-toxic, non-acidic gases through the cold vent(s) 290, the process and system steps are in-line, inter-related and continuous.

Accordingly, description is continued of the treatment step downstream of MUF module 50. Again, excess air is not introduced to the flue gases in this embodiment because of deleterious effects on amine degradation

In this embodiment, the next step is the carbon monoxide removal module 60. Carbon monoxide removal is by conventional catalytic method using absorption or reduction catalysis. The "in-line" CO removal process contains a number of catalyst beds 62 arranged to form a continuous bed and is partitioned for on-line dumping and make-up of each bed 62. Based on reprocessing capabilities of such catalyst the overall life of each load is increased and capital cost should be reduced. Suitable catalysts include activated carbon catalysts and copper/nickel catalysts.

The two catalyst beds 62 must be sized to the capacity of the carbon monoxide removal module 60 and provide stripping capabilities from 0% to 110% at maximum continuous load. Each catalyst bed design is in vertical sections with each section divided into four or eight beds dependent on the size^" of the carbon monoxide module and the carbon monoxide throughput.

The CO removal module 60 continues the in-line configuration of the modules of the pollutant removal system and the catalyst chosen will have service life selected in accordance with operator requirements. Following removal of carbon monoxide, removal of carbon dioxide takes place. Remaining flue gas from the CO removal module 60 and excess air enter the CO₂ removal module 70 by adequately sized inlet lines 75 at the bottom of the contactor vessels 71 and 72, the flue gas stream passes up through the contactors 71 and 72 while diglycol amine (DGA) stripping agent is injected through lines 176 and 276 at the top of each contactor vessel 71 and 72. The module receives the remaining flue gas stream and passes it into the bottom of the CO₂ contactor 71 while DGA (Diglycolamine) enters at the top of the contactor 71. As the flue gas stream rises, the CO₂ reacts with the DGA and forms a regenerable salt which passes out of the contactors 71 and 72 and through rich/lean heat exchangers 76 where heat is absorbed from the lean solution (DGA). Also, CO₂ is partially desorbed and removed from the rich solution and passed through to the expander 730. The remaining rich solution

(CO₂/DGA) passes into the top of the Stills Column 77 on the reboiler vessel 78.

After passing through the reboiler vessel 78, where the CO₂ is drawn off, the DGA, now a lean solution, is pumped back, by pumps 78a, or 78b, through a rich/lean heat exchanger 76 and is returned into the amine stripping process. As there are no other contaminants applicable to amine type processes present the degradation of the DGA is not at a level where constant/batch treatment of the DGA to remove such contaminants is required. The remaining CO₂ is drawn off the reboiler vessel 78 by the overhead condenser 73 where it combines with the rest of the CO₂ and passes through expander 730 to drier 74. The dry CO₂ is sent directly to either a chill down unit or is exported by line 830 to liquid storage and onward selling. Separated liquid is removed to drain 840. Alternatively, as the gas may be compressed into a transmission system for re-injection into either oil reservoirs, depleted reservoirs, water aquifers, and suitable geological formations. CO₂ could be injected into the ocean for deep-sea storage. Gas re-use at the plant/facility is also possible.

The recovered amine is recycled into the system with make-up, as required, pumped from DGA bulk storage 700. The leaned out DGA may also be reintroduced at the contactors 71 , 72. As it is unlikely that the pollutant gases will include large quantities of mercaptans and COS, actual amine losses during reclamation are expected to be negligible, reducing make-up costs. An advantage of using DGA over other stripping agents, such as MEA and DEA, is that both stripping temperature and pressure are lower. DGA has a higher concentration of 50-70% and is therefore more effective in removal of carbon dioxide per litre of stripping agent used. DGA has the lower treating circulation rate unit volume of flue gas passed through the carbon dioxide module 70.

Following carbon dioxide removal, the remaining flue gas stream, now at low temperature, with all pollutants removed at levels exceeding 97% passes through a knockout vessel 80 which removes any remaining entrained liquids in the flue gas stream. Remaining gas then passes through to the cold vent 90 for atmospheric release. Any liquids, containing water and DGA, are removed from the knockout vessel, 80 and separated in DGA/water separator 85, DGA recovery pump 86 pumping DGA back into the CO₂ removal module 60 while water is exported to drain 800.

Multiple cold vents 290 are provided. The cold vents 290 are designed on the principle of a low pressure pipe flare with a steel support structure but is quite distinguishable from a high dispersion stack. Welded pipe sections comprising the cold vents 90 can be elevated to any desired height to release the cleaned flue gas stream. The vented gas has low pollutant levels and will not be harmful to the environment or local population.

Sizing of the cold vents 290 is determined in line with the capacity of the pollutant removal system and is expected to form a small fraction of the capital cost of the pollutant removal system.

The cold vent 290 structure may include monitoring equipment such as sensor probes or gas probes monitoring discharge levels of pollutant and emission gases for compliance with regulatory levels. These levels are^" extremely low and nitrogen forms the bulk of the discharged gases. These readings are monitored in the control room of the plant facility when the pollutant removal system is located and remedial action may be initiated as necessary. Once CO₂ has been recovered from the DGA stripping agent there are a number of options for its storage and re-use. These options include use in mining and leaching processes; fertiliser and, urea plants, methanol production; polymer production, for example, polyurethane and polycarbonate production; carbamate production; refrigerant production; production of additives and modifiers. Primary among these storage options is transmission and storage of recovered C0₂ in geological structures such as depleting or depleted oil and gas reservoirs. Such transmission, storage and re-use may be highly favourable to the economics of the treatment system.

A suitable transmission system can be built using pipework constructed from inert, medium strength material such as GRE, GRC, ABS and other suitable polymers which are suitable for low-pressure applications. The pipes, and suitable transmission stages such as pumps, connect the CO₂ removal module to the reservoir. If the carbon dioxide is injected into a geological structures, for example, an oil or gas reservoir the injection well head forms the only high- pressure point of the system and capital costs may correspondingly be reduced.

Further, storage of carbon dioxide in this manner presents minimal threat to the environment and may be well-utilised to increase recovery of oil and gas from the reservoir from which the oil and gas is stored. Carbon dioxide is suitable for many applications and the current invention promotes availability for re-use.

Other geological structures in which the carbon dioxide may be stored include existing and abandoned oil reservoirs, salt domes, fractured rock, sedimentary structures and other mines. Such structures may be identified by use of seismic techniques with particular emphasis on location of suitable geological structures close to industrial plants utilising the pollutant removal system of the present invention. Further modifications and variations to any of the embodiments may be^" apparent to the skilled reader on considering the disclosure and such modifications and variations form part of the present invention. In one such modification common to all embodiments, as shown in Figure 4, the pollutant removal system is used for multiple users and acts as a "centralised" system. In the "centralised" system, which can otherwise be designed as shown schematically in any one of Figures 1 to 3 (the Figure 1 embodiment is illustrated for convenient understanding) the inlet casing of the utility module is provided with multiple inlets 1 1. Four such inlets 11 are provided but this is variable at the designer's option. Each inlet 1 1 connects, selectively or otherwise, the pollutant removal system with each user plant or installation which generates flue gases susceptible to treatment in the system and process of the present invention. For purposes of illustration, four user plants or installations are connected in this embodiment. Any desired number can be connected. Dampers 1 1 a are provided in each inlet 1 1 and are set as appropriate for handling flue gas loading which may be steady or variable. Damper(s) 11 a may be closed, partially open or fully open with settings of each damper 11 a possibly being different from each other.

In such case, the inlet utility module casing 10a is of suitable structural strength to deal with any unequal stress loading created by dynamic operating conditions. Static stress loading should also be taken into account in design. It will be understood that Figure 4 is only indicative of a suitable casing 10a design and others may be developed dependent on design criteria.

Claims

THE CLAIMS DEFINING THE INVENTION ARF AS FOLLOWS:

1. A process for removal of pollutants from flue gases including the sequential steps of:

(a) recovering waste heat from said flue gases in a waste heat recovery^" stage;

(b) removing particulates from said flue gases in a particulate removal stage;

(d) removing NO_x from said flue gases in an NO_x removal stage;

(e) controlling pressure with a make up feed gas stage; discharging treated flue gases to atmosphere.

2. The process of claim 1 further including one or both of:

(f) a CO removal stage; and

(g) a CO₂ removal stage.

3. The process of claim 2 wherein CO₂ is removed by use of diglycol amine as stripping agent.

4. The process of claim 2 or 3 wherein a heat exchanger module is provided between the NO_x removal stage and the make up feed gas stage.

5. A system for removal of pollutants from flue gases including the stages:

(a) a waste heat recovery stage;

(b) a particulate removal stage;

(c) a sulphur oxide removal stage;

(d) an NO_x removal stage;

(e) a make up feed stage; and a treated flue gas discharge system, particularly a cold vent, from which treated flue gases are discharged to atmosphere.

6. The system of claim 5 further including one or both of:

(f) a CO removal stage; and

(g) a CO2 removal stage.

7. The system of claim 6 wherein said CO₂ removal stage removes COjT using diglycol amine as stripping agent.

8. The systems of claim 6 or 7 wherein a heat exchanger module is provided between the NO_x removal stage and the make up feed gas stage.

9. The system of any one of claims 5 to 8 wherein said system treats flue gases from multiple installations operating a combustion cycle.