Conventional systems for the absorption of acid gases employ a liquid solvent; typical solvents include amines such as methyldiethanolamine (MDEA), monoethanolamine (MEA) or diethanolamine (DEA) and mixtures of solvents. These solvents absorb CO2, NOx, H2S and other acid gases. The solvent is contacted with the sour gas mixture (gas mixture including acid gases) in a column which may be a packed column, a plate column or a bubble- cap column, or a column with some other form of contact medium. In these systems, the gas and liquid streams flow countercurrently.

The prior art absorption systems suffer the disadvantage that in order to achieve a significant degree of gas/liquid contact, the columns have to be large and their operation is hampered by excessive foaming. In addition, the subsequent stripping section which removes the acid gas from solution must also be large, to handle the large volume of solvent used. Since the fluids involved are highly corrosive, the capital costs of the large columns and subsequent stripping section is high. Furthermore, operating costs and maintenance costs are high.

It is an object of the present invention to provide a system for removing CO2 from flue gas which does not suffer from the disadvantages of the prior art.

According to one aspect of the invention, there is provided apparatus for separating carbon dioxide from flue gas, comprising a sea water supply member, a flue gas supply member, a plurality of turbulent contactors and a gas/liquid separation vessel, in which: each turbulent contactor comprises a housing, a sea water inlet from the sea water supply member, a flue gas inlet from the flue gas supply member, an outlet leading to a venturi passage and a

tube within the housing extending from the outlet back upstream, the tube being perforated and/or being spaced from the outer periphery of the outlet; each venturi passage extends into an elongate contact pipe which communicates with the interior of the separation vessel; and the separation vessel has a cleaned gas outlet and a used sea water outlet.

Thus, the flue gas is brought into contact with the sea water in the turbulent contactors where the turbulent mixing conditions cause part of the CO2 to be absorbed. Further absorption takes place in the contact pipes. The gaseous and liquid phases are separated in the separator vessel into a cleaned flue gas and the used or CO2-loaded sea water. The system is capable of removing 40% or more of the CO2 present.

Using seawater as an absorbing medium, leads to a considerably simpler process with lower installation and operational costs than a CO2-removal plant based on e.g. chemical absorption of CO2 in an amine solvent.

There may also be no need to treat the loaded sea water to remove the absorbed CO2 since sea water is plentiful and does not need to be recovered for re-use.

This means that no downstream regeneration section is necessary. The presence of carbon dioxide in sea water does not represent an environmental hazard in the same way as atmospheric carbon dioxide and since the concentrations are relatively low, the carbon dioxide loading of the sea water remains well below the saturation capacity of sea water. Typically, the CO2 loading of the enriched sea water is 1% of the saturation capacity when released at a water depth of 100 m. In addition, the ocean currents efficiently dilute the CO2-loaded sea water. The CO2-loaded sea water can therefore be conveniently disposed of offshore where it will quickly be dispersed and will therefore have no detrimental effect on the environment.

If the sea water does absorb harmful acid gas components, they can be neutralised with suitably selected reagents. Again then, the CO2-loaded sea water can be disposed of offshore.

The turbulent mixing is very intense and results in extremely efficient gas liquid contact. The liquid entrained in the gas may be in the form of droplets for gas continuous fluid phase distribution. The efficient mixing means that absorption can take place very rapidly. The mixing system used is simple and inexpensive compared to prior art systems, and requires no solvent regeneration.

The method is carried out as a continuous process with the flue gas and sea water flowing co-currently. The co-current flow eliminates the problems associated with foaming, and separation is effected without difficulty downstream of the contactors in the separation vessel.

Preferably, the separation vessel is generally cylindrical and arranged with its axis generally vertical, and the sea water supply member is a pipe extending upwards with the separation vessel. Preferably, the turbulent contactors and contact pipes are arranged circumferentially around the separation vessel, extending generally vertically with the inlets to the turbulent contactors in their respective upper parts and the communication between the contact pipes and the separation vessel being a direct connection at the bottom of each contact pipe. Preferably, the flue gas supply member is a manifold connected to the flue gas inlet of each turbulent contactor.

Preferably, the tube is located in a housing which includes the gas inlet, the liquid inlet and the outlet. In a preferred regime, the flue gas is supplied to the tube, preferably directly, and the sea water is supplied to the housing and so the gas stream draws the sea water into the venturi and the two phases are mixed. Preferably, the end of the tube defines the inner periphery of the outlet.

In another regime, the flue gas is supplied to the housing and the sea water is supplied to the tube, optionally directly, whereby the flue gas is drawn into the venturi by the sea water and the two phases are mixed. In a third regime, the sea water and the flue gas are supplied to the housing, the sea water being supplied to a level above the level of the outlet, whereby the flue gas is forced out through the outlet via the tube, thereby drawing the sea water into venturi so that the two phases are mixed. In the contact pipes, one or several secondary mixer stages can be installed to maintain the gas/liquid mixing efficiency.

Preferably, the flue gas and the sea water are formed into a homogeneous mixture in the contactor, and the homogeneous mixture may be cooled prior to separation into a gas phase and a liquid phase. Preferably, the cooled homogeneous mixture is then separated into a gas phase and a liquid phase in the gas-liquid separator vessel.

According to another aspect of the invention, there is provided an installation for removing and disposing of carbon dioxide from flue gas from a gas turbine electricity generating plant, which comprises: apparatus for separating carbon dioxide from the flue gas comprising a sea water supply member, a flue gas supply member, a gas/liquid separation vessel having a cleaned gas outlet and a used sea water outlet, and a plurality of turbulent contactors, each having respective inlets from the sea water and flue gas supply members and an outlet to the separation vessel; means for supplying sea water to the sea water supply member; means for supplying the flue gas to the flue gas supply member; and means for transporting used sea water from the used sea water outlet back to the sea.

Preferably, the CO2 separation is effected by means of the separation apparatus described above. Preferably, the means for supplying sea water is a sea water lift pump. Preferably, the flue gas supply member is a flue gas

manifold and the means for supplying flue gas is a fan connecting duct to the gas turbine exhaust. Preferably, the means for transporting used sea water is a transport pump and associated piping arranged to open beneath the sea at a depth of at least lOOm.

In cases of flue gas purification at low pressure, the sea water is pumped to the contactors and can thereby draw the combustion gas with it through the contactors. The system may include a pump for the flue gas so that the flue gas is conveyed to the contactors at a high pressure and thereby draws the sea water with it through the contactors.

The invention may be considered to extend to the use of sea water and the apparatus and installation described in order to remove CO2 from flue gas, and to return CO2-loaded sea water to the environment at an appropriate location and depth.

The realisation that a material as plentiful and inexpensive as sea water can be used as an absorbent for acid gas, coupled with the fact that it can be returned to the environment safely is particularly valuable as awareness is increased of the potential damage to the environment that can be caused by acid gases in gaseous effluents such as combustion gas from fossil fuel power stations and gas turbines in general.

Furthermore, the small size of the preferred apparatus compared to conventional absorption columns, which also require regeneration apparatus for the solvents used, render the invention especially advantageous.

The invention may be put into practice in various ways and some specific embodiments will be described by way of example to illustrate the invention with reference to the accompanying drawings, in which: Figure 1 is a schematic view of an installation in accordance with the invention;

Figure 2 is an elevation of a CO2 separator arrangement; Figure 3 is a perspective view of the separator arrangement of Figure 2; Figure 4 is a simplified vertical section through the separator arrangement; Figure 5 is a block diagram of the apparatus used in a series of experiments; Figure 6 is a schematic diagram of a sampling point; and Figure 7 is a simplified section through the contactor used in the experiments.

The installation shown in Figure 1 comprises a flue gas inlet 11, and a sea water supply 12. The flue gas first passes through a primary heat recovery unit 13 and then a heat exchanger 14 on its way to a low pressure fan 15. The fan 15 conveys the flue gas to a CO2 separator arrangement 16 comprising a mixing unit 17 and a gas/liquid separation vessel 18. Sea water is also conveyed to the separator arrangement 16 by a lift pump 19.

The flue gas and sea water first enter the mixing unit 17 where turbulent mixing takes place, producing a homogenous mixture. During the mixing, CO2 in the flue gas is absorbed by the sea water and the mixture is conveyed immediately to the separation vessel 18. In the separation vessel 18, cleaned flue gas is obtained and discharged in a discharge line 21 via the heat exchanger 14. CO2-loaded sea water is also obtained and is discharged back into the sea by a transport pump 22 via a used sea water line 23. A part of the sea water may also be re-routed to the gas/liquid mixer in order to gain a higher CO2 loading of the liquid pumped back into the sea. This serves to increase the energy efficiency of the CO2 removal (power consumed per mass CO2 removed). Attention is drawn to the present applicants co-pending application number ... .. (Our case P20557WO) entitled "Separation of acid gases from

combustion gas".

The heat recovery unit 13 is a standard gas turbine waste heat recovery unit using sea water as the coolant. The heat exchanger 14 is a gas/gas conventional Advanced Plate-type heat exchanger. The fan 15 comprises a pair of compressor units, each having an inlet flow equal to half the total flow. The lift pump 19 comprises a pair of standard electric submersible pumps providing a flow rate of about 10,000 to 15,000 m3/hr. Alternatively, existing sea water cooling pumps could be employed to provide the necessary sea water for the process. The transport pump 22 may be similar to the pump 19, though other pump designs could be employed.

The separator arrangement 16 is shown in more detail in Figures 2 to 4.

It comprises essentially a series of (in this case, fourteen) turbulent contactors 31, each leading down directly to a respective vertical contact pipe 32, and a common separation vessel 33. The separation vessel 33 is generally cylindrical with its axis vertical and the contactors 31 and their contact pipes 32 are arranged around its periphery. A sea water inlet pipe 34 receives sea water from the lift pump 19 and leads to a distribution column 35 within the separation vessel 33. A flue gas inlet pipe 36 receives flue gas from the fan 15 and leads to a flue gas manifold 37. The separation vessel 33 has a cleaned gas outlet 38 at the top leading to the outlet line 21 and a used sea water outlet 39 at the bottom leading to line 23.

Each turbulent contactor 31 comprises a frusto-conical housing 41 having a sea water inlet 42 connected to the column 35 via a radial pipe 43, and a flue gas inlet pipe 45 connected to the manifold 37. The flue gas inlet pipe 45 extends into a tube 48 within the housing 41 and together with the wall of the housing 41, defines an annular outlet 46 leading to a venturi passage 47. The venturi passage 47 opens into the contact pipe 32 which in turn opens into the

bottom of the separation vessel 33. The liquid entering the turbulent contactor may also have one or more non-radial liquid inlets 43 in the sense that the inlets are circularly located in the same plane and are fed by a centrally or non- centrally located distribution column 35.

In use, sea water is supplied to the contactors 31 by the lift pump 19 via the inlet pipe 34, the column 35 and the radial pipes 43, while flue gas is supplied to the contactors by the fan 15 via the inlet pipe 36, the manifold 37 and the feed pipes 45. Turbulent mixing takes place in the contactors 31 and as the homogeneous gas/liquid mixture leaves the venturi passages, further contact takes place in the contact pipes 32. This results in CO2 from the flue gas being absorbed by the sea water.

The mixture is conveyed to the separation vessel 33 where the two phases separate out into a cleaned gas and CO2-loaded sea water. The cleaned gas is removed via the gas outlet 38. The CO2 content is sufficiently low for the gas to be discharged to atmosphere. The CO2-loaded sea water is removed via the outlet 39 and is returned to the sea by the transport pump 22 at a distance of 8km and a depth of 33m. The absorbed CO2 remains in solution and is dispersed.

In the practical embodiment described, typical values for the various operating parameters are shown in Table 1, below.

Table 1 Flue gas flow rate 4.5x105 Nm3/h Flue gas temperature 1500C - 200"C (at contactor inlet) CO2 content 4.3 mol % Sea water flow rate 1.1 x 104 m3/hr Sea water temp. 110C Residence time in contactor/ 0.6 seconds

contact pipe CO2 removal efficiency 41% (CO2 in - out out [in Kg/s]) CO2 in Solubility potential of 23% sea water utilised No. of contactors 14 Contactor height 3.34m Contact pipe height 7.0m Pipe diameter 1.0m Separation vessel diameter 5.0m Separation vessel height 15.0m The invention is further illustrated by reference to the following experiments which were carried out on a laboratory scale. These serve to verify the operating principles of the invention.

In a series of experiments conducted, the ability of sea water to absorb CO2 from a diesel engine exhaust was investigated. The contactor used was a FRAMO contactor generally as described in EP 379319 and shown in Figure 7.

The turbulent contactor 100 comprises a vessel 101 having a gas inlet 102, a liquid inlet 103 and an outlet 104 leading to a venturi passage 105. There is a tube 106 (which may or may not be perforated) extending from the outlet 104 back into the vessel 101. The mixer injection pipe was adjusted to yield gas/liquid ratios in the range of about 4.5 to about 14, depending on the total flow rate.

A schematic diagram of the apparatus for the series of experiments is shown in Figure 5.

The apparatus in Figure 5 comprises a contactor 51, corresponding to that shown in Figure 7, a vertical pipe section 56 leading from the venturi 52,

and a horizontal pipe section 59 joining the vertical section 56 to a receiver 61.

The vertical section 56 has two quick closing valves 57,58. A sea water tank 54 leads to the contactor 51 via a valve 55. A diesel engine 75 has its exhaust connected to the contactor via a line 71 including an orifice plate 74. The line 71 is provided with a by-pass valve 70 in a by-pass line 72.

The receiver 61 is slightly inclined and has a liquid drain 65 at its lowest point, leading to a tank 67 via a valve 66. The tank 67 has an outlet 68 with a valve 69. The receiver 61 also has a gas cylinder 62 (not used) which can be used to pressurise the reservoir 61 via a line 63 with a valve 64.

Measurements are taken variously at eight sampling points designated SP in Figure 5. Exhaust is located at the exhaust entry to the contactor 51. SP, is 1 metre after the contactor with SP2 and SP3 within the next 1.5 metres. SP4 is in the horizontal portion 59, SP5 is at the entry to the receiver 61 and SP6 is at the opposite end of the receiver 61. The final SP7 is in the receiver outlet.

Each sampling point, as shown in Figure 6, comprises a centrally located sampling tube 81 opening in the downstream direction and protected by a cap 82. The cap serves to reduce liquid entrainment in the gas sample. The sampling tube leads to a hydrocyclone 83 which removes any residual moisture so that dry gas leaves the gas outlet 84 for analysis.

The contactor 51 and pipe section 56 were charged with sea water taken from a Norwegian fjord. Exhaust gas from a YANNMAR 4TN84E 15 KVA water-cooled diesel engine 75 was used as the feed gas. A 30% load was placed on the diesel engine to increase the exhaust gas temperature and also to obtain a higher level of CO2 on the exhaust gas. The orifice plate 74 provided for continuous flow measurement of the exhaust gas.

The approach was based on sampling continuous flow in the pipe. The sampling probes were situated in the centre of the pipe with a cover, which

accommodated the retrieval of a gas/liquid sample with low liquid content. This two-phase flow from each sampling was then routed through a gas/liquid cyclone from which a dry gas sample was taken from the gas outlet. [This arrangement with the sampling probe described was repeated in seven different locations downstream of the first contactor as well as in the exhaust feed entering the contactor.] The sampling locations are shown on Figure 5 and referred to in Table 2.

The experiments were carried out either by pre-filling the first stage contactor with sea water and/or continuously supplying sea water from the fjord. In the former case, experiments have been carried out with different levels of sea water temperature.

An experiment would commence by initially charging exhaust gas into the first stage contactor to the steady state pressure level experienced for a long run. The quick opening/closing valves were then triggered to open and two- phase flow admitted through the system. After steady state conditions were achieved, gas samples were taken from the sampling points. The residence time as reported in Table 2 was calculated from the total flow rate of gas and liquid, local position in a give pipe section and the pipe length and diameter of the connected sections. The predicted CO2 concentration as presented in Table 2 was calculated assuming an exponential decay of the CO2 concentration in the gas versus the residence time in the contactor. Only experimental conditions with a certain statistical basis for calculating a time constant have been reported with predicated values. The analyses were carried out using a Chromopack Model CP 2002 chromatograph.

The results of the experiments are shown in Table 2.

With the exception of the upper temperature level tested (50"C), it can be seen that considerable absorption is achieved. The experimental series 1801 to 1903, shows that a significant absorption was achieved through the contactor.

However the CO2 concentration continues to drop as the flow propagates along the contactor pipe line. Generally, it can be seen that the absorption efficiency is lower for the high gas liquid ratios (GLR).

For the experimental series 1004 to 1009, it can be seen that the exponential decay of the CO2 concentration applies to the propagation of the multiphase flow in the contactor pipe line. However, the CO) absorption in the contactor is less pronounced as compared to 1801 - 1903.

Table 2. Experimental summary - absorption with sea water as solvent Run No. Flowrates GLR Temp. Sampl Resid CO2-concentration Gas Liquid Mixture Liq. Point Time Measured Predicated (mili] [m 'hi [m 'hi [-] deg C No. (s) lmol%j (mol%] 1801 31 5.7 36.7 5.5 23 exhaust 0 53.1 1801 31 5.7 36.7 5.5 23 1 0.105 34.9 1801 31 5.7 36.7 5.5 23 2 0.19 37.3 1801 31 5.7 36.7 5.5 23 3 0.256 33.3 1801 31 5.7 36.7 5.5 23 4 0.455 30.3 1801 31 5.7 36.7 5.5 23 5 0.581 23.5 1802 32 5.3 37.3 6.0 19 exhaust 0 57.0 1802 32 5.3 37.3 6.0 19 1 0.103 32.7 1802 32 5.3 37.3 6.0 19 2 0.186 28.7 1802 32 5.3 37.3 6.0 19 3 0.251 34.2 1802 32 5.3 37.3 6.0 19 4 0.447 30.3 1802 32 5.3 37.3 6.0 19 5 0.57 25.8 1803 24 5.3 29.3 4.5 23 exhaust 0 2.7 1803 24 5.3 29.3 4.5 23 1 0.13 1.6 1803 24 5.3 29.3 4.5 23 2 0.236 1.5 1803 24 5.3 29.3 4.5 23 3 0.317 1.2 1803 24 5.3 29.3 4.5 23 4 0.564 1.2 1804 24 5.0 29.0 4.8 23 exhaust 0 2.63 1804 24 5.0 29.0 4.8 23 1 0.13 2.07 1804 24 5.0 29.0 4.8 23 2 0.236 1.38 1804 24 5.0 29.0 4.8 23 3 0.317 1.29 1804 24 5.0 29.0 4.8 23 4 0.564 0.99 1804 24 5.0 29.0 4.8 23 5 0.72 1.19 1805 24 4.1 28.1 5.9 20 Exhaust 0 5.25 1805 24 4.1 28.1 5.9 20 1 0.13 2.73 1805 24 4.1 28.1 5.9 20 2 0.236 2.67 Run No. Flowrates IGLR Temp. Sampl. Resid CO2-concentration Gas Liquid Mixture Liq. Point Time Measured Predicated [m3/h] [m3/h] [m3h] [-] deg C No. (s) [mol%] [mol%] 1805 24 4.1 28.1 5.9 20 3 0.317 2.67 1805 24 4.1 28.1 5.9 20 4 0.564 1.90 1805 24 4.1 28.1 5.9 20 5 0.72 2.71 1805 24 4.1 28.1 5.9 20 6 25 2.19 1902 33.0 2.4 35.4 13.7 24 exhaust 0 4.52 1902 33.0 24 35.4 13.7 24 1 0.106 2.95 1902 33.0 2.4 35.4 13.7 24 2 0.192 3.03 1902 33.0 2.4 35.4 13.7 24 3 0.258 3.47 1902 33.0 2.4 35.4 13.7 24 4 0.46 2.95 1902 33.0 2.4 35.4 13.7 24 5 0.587 3 10 1902 33.0 2.4 35.4 13.7 24 6 17.4 3.74 1903 33.0 2.4 35.4 13.8 24 exhaust 0 4.56 1903 33.0 2.4 35.4 13.8 24 1 0.106 3.30 1903 33.0 2.4 35.4 13.8 24 2 0.192 3.00 1903 33.0 2.4 35.4 13.8 24 3 0.258 3.70 1903 33.0 2.4 35.4 18.8 24 4 0.46 3.10 1903 33.0 2.1 36.4 13.8 21 5 0.587 3.10 1903 33.0 2.4 35.4 13.8 24 6 17.4 3.70 1004 23.9 4.9 28.8 4.9 6 exhaust 0 1.21 1004 23.9 4.9 28.8 4.9 6 1 0.134 3.85 1004 23.9 4.9 28.8 4.9 6 3 0.325 3.44 3.50 1004 23.9 4.9 28.8 4.9 6 4 0.578 3.17 3.09 1004 23.9 4.9 28.8 4.9 6 7 20.7 3.32 1005 23.9 4.9 28.8 4.9 6 exhaust 0 4.25 1005 23.9 4.9 28.8 4.9 6 exhaust 0 4.25 1005 23.9 4.9 28.8 4.9 6 1 0.134 3.77 Run No. Flowrates OLR Temp. Scampi. Resid CO2- concentration Gas Liquid Mixture Liq. Point Time Measured Predicated [m3/hl [m'/h] [m /h] [ - ] deg C No. (s) [mol%] [mol%] 1005 23.9 4.9 28.8 4.9 6 3 0.325 3.34 3.42 1005 23.9 4.9 28.8 4.9 6 4 0.578 3.00 3.02 1006 23.9 4.9 28.8 4.9 27 exhaust O 4.24 1006 23.9 4.9 28.8 4.9 27 exhaust 0 4.25 1006 23.9 4.9 28.8 4.9 27 1 0.134 3.80 1006 23.9 4.9 28.8 4.9 27 3 0.325 3.72 1006 23.9 4.9 28.8 4.9 27 4 0.578 3.46 1006 23.9 4.9 28.8 4.9 27 6 19.99 3.53 1007 23.9 4.9 28.8 4.9 6 exhaust 0 12.1 0 12.1 1007 23.9 4.9 28.8 49 6 exhaust 0 12.0 1007 23.9 4.9 28.8 4.9 6 1 0.134 10 9 1007 23.9 4.9 28.8 4.9 6 3 0.325 9.9 9.9 1007 23.9 4.9 28.8 4.9 6 6 19 99 7.8 1008 23.9 4.9 28.8 4.9 52 exhaust 0 4.28 1008 23.9 4.9 28.8 4.9 52 exhaust 0 4.39 1008 23.9 4.9 28.8 4.9 52 1 0.134 4.17 1008 23.9 4.9 28.8 4.9 52 3 0.325 4.18 1008 23.9 4.9 28.8 4.9 52 1 6 19.99 4.07 1009 23.9 4.9 28.8 4.9 52 exhaust 0 4.36 1009 23.9 4.9 28.8 4.9 52 exhaust 0 4.27 1009 23.9 4.9 28.8 4.9 52 3 0.325 4.10 1009 23.9 4.9 28.8 4.9 52 4 0.578 3.97 1009 23.9 4.9 28.8 4.9 52 6 19.99 3.78