GB2102019A - Method for desulphurisation of liquid hydrocarbon streams - Google Patents

Abstract

A method for removal of sulfur compounds from liquid hydrocarbons, in particular, a mixture of liquid propane and liquid propylene, and olefins under liquid contact conditions by contacting the liquid hydrocarbons containing sulfur compounds, for example, hydrogen sulfide, carbonyl sulfide, and mercaptans with 2-(2- aminoethoxy) ethanol as a principal agent for sulfur removal. The 2-(2- aminoethoxy) ethanol is reclaimed and reused for further sulfur removal. <IMAGE>

Description

SPECIFICATION Method for desulphurisation of liquid hydrocarbon streams This invention relates to the removal of sulfur present in various forms from liquid hydrocarbons, and in particular liquid propane, propylene and other olefins utilizing 2- (2-aminoethoxy) ethanol as the primary extraction agent. In another aspect, this invention relates to a method for regenerating 2 (2-aminoethoxy) ethanol from the reaction products of 2- (2-aminoethoxy) ethanol and sulfur compounds.

Treatment of liquid hydrocarbon products to remove or convert impurities requires complex and costly processes in the refinery and processing plants. Various sulfur compounds represent the most common impurities sought to be removed.

Sulfur compounds normally sought to be removed include hydrogen sulfide, carbonyl sulfide, mercaptans and othersulfides.

The most prevalent practice in industry is to reduce the sulfur content by processing the hydrocarbons in the gaseous state. Widely accepted practice has been to remove sulfides from the gaseous state fuel gases with diethanolamine (DEA), diisopropyl amine (DIPA), monoethanolamine (MEA) and tetraethyleneglycol (TETRA). Those skilled in the art will appreciate that these solvents may also be used for processing hydrocarbons in the liquid state.

However, these solvents, when used for extraction from liquid hydrocarbons, do not remove significant quantities of carbonyl sulfide.

It has been well established that 2 (2-aminoethoxy) ethanol, also known by the trademark "Diglycolamine", hereinafter often referred to as DGA, sold by Jefferson Chemical Company, Inc., Houston, Texas, has been used either alone or in combination with other materials to remove sulfide components from gaseous streams of petroleum fuels and products. The use of DGA for removing acid gases from a gaseous mixture of wet or dry hydrocarbons is the subject of U.S. Patent No.

3,712,978 and of Canadian Patent No.505,164.

The use of DGA for removing carbonyl sulfide from liquid propane is the subject of U.S. Patent No.

4,208,541 issued to McClure on June 1980. As discussed therein, DGA has been found to be a more efficientsolventforthe removal of acid gas impurities when compared with other solvents, resulting in reductions of solution pumping horsepower, reclaimer drive steam and cooling tower ioads. As discussed in U.S. Patent No.

4,208,541,the use of DGA in the treatment of gas plant liquids was reported by the Signal Oil Company. These plant liquids were straight chain hydrocarbons containing low levels of sulfur impurities and the treatment removed only 54.5% of H2S, and 27.5% of total mercaptans (see Table 1, U.S.

Patent No.4,208,541).

The present invention is directed to the use of DGA to remove all types of sulfur compounds from liquid hydrocarbons including olefin streams. While prior applications used DGA to treat liquid paraffin streams, DGA had not been used in the treatment of olefins due to the belief that DGA would react with the olefin double bond which would prohibit regeneration or reclaiming. However, it has been discovered that DGA may successfully be employed to treat liquid olefins as discussed herein. In addition, it has been discovered that DGA may be used to remove a substantially higher percentage of impurities than suggested by the Signal Oil data.

One would not expect to achieve a greater percentage of removal for sulfur impurities from streams containing higher concentrations of sulfur impurities than those treated by Signal Oil. In another aspect, the present invention relates to a method for regeneration of DGA by providing a condensate media for more complete DGA regeneration. In a further aspect, the invention relates to removal of hydrogen sulfide from the liquid hydrocarbons, thereby eliminating the need to remove hydrogen sulfide from the gaseous petroleum gas before liquifying.

According to the present invention, there is provided a method for the removal of sulfur impurities from liquid olefins, which comprises mixing under liquid-iiquid contact conditions a hydrocarbon stream consisting of liquid paraffins and olefins containing sulfur compounds as impurities and 2 (2-aminoethoxy) ethanol in a concentration effective to remove substantially 95% or more of said sulfur compounds, the mixing being performed at a temperature and a pressure at which said hydrocarbon stream remains in the liquid state; and removing the hydrocarbon stream from contact with said 2 (2-aminoethoxy) ethanol.

The present invention is directed to a method of desulfurization of hydrocarbon streams consisting essentially of liquid hydrocarbons containing sulfur compounds as impurities and for the substantial 100% removal of the sulfur compounds from the liquid hydrocarbon streams. In particular, these hydrocarbon streams contain propane, propylene and higherolefins.

In one aspect, the invention providesforthe removal of sulfur compounds from liquid hydrocarbons by mixing under liquid-liquid contact conditions, liquid hydrocarbons containing sulfur compounds as an impurity with DGA as the principal agent for desulfurization. The mixing is conducted at a pressure and temperature which retains the liquid hydrocarbon streams in the liquid state. Upon leaving the contactor the mixture is separated into two components, one being liquid hydrocarbon substantially free of sulfur and the other comprising DGA and DGA degradation products, including absorbed H2S and mercaptans.

The principal mechanism for carbonyl sulfide removal involves the reaction of DGA with carbonyl sulfide to yield the degradation product N, N' bis (hydroxyethoxyethyl) urea (commonly called BHEEU and hereinafter referred to as BHEEU) according to the following equation:

DGA BHEEU where R = HO-CH2-CH2-O-CH2-CH2- As a result of this reaction, the rich amine leaving the liquid-liquid contactor will comprise unreacted DGA, water, the BHEEU degradation product, hydrogen sulfide, and other sulfide compounds absorbed by the DGA.

The mechanism by which the other sulfur compounds, such as H2S and mercaptans, are removed by DGA is not known. It is not understood whether these other sulfur compound react with DGA, associate in some manner with DGA, or merely are absorbed by DGA. For simplicity, these sulfur compounds will be referred to as being "absorbed".

The BHEEU can be reconverted to DGA in a suitable reclaimer at temperatures ranging from 350 to 400"F. Reversal ofthe above reaction is enhanced by providing a condensate media of super heated steam (or hot oil) in the reclaimer. The stripper converts the degradation products of DGA and H2S, or mercaptans, backto DGA by adding heat. The off gas of the stripper is principally steam, carbon dioxide, and hydrogen sulfide. The regenerated DGA forms the stripper bottoms. The DGA is then used for further desulfurization. The stripper off gas is made less corrosive by the addition of a slight recycle of lean DGA. As used herein, "lean DGA" indicates a DGA solution which is substantially free of BHEEU absorbed H2S and other impurities.

A further aspect of the present invention is the utilization of an anti-foaming agent One commonly encountered problem with the method of U.S. Patent No.4,208,541 was excessive foaming. Foaming is controlled by utilizing a water soluble anti-foaming agent.

The present invention will now be illustrated, by way of example only, with reference to the sole figure of the accompanying drawings which illustrates a typical flow diagram for desulfurization of two separate liquid hydrocarbon streams in accordance with the present invention.

The present invention embodies a method whereby sulfur is removed from liquid hydrocarbon streams by utilizing certain characteristics of DGA.

The figure illustrates the treatment of two separate liquid hydrocarbon streams. Stream 10 is composed of liquid propane and liquid propylene and higher olefins from a catalytic cracker, for example. Stream 12 is comprised primarily of liquid propane from a reformer. These two streams are each contacted with lean DGA in separate contactors. Preferably the lean DGA solution is an aqueous solution of 30% to 85% DGA. The two liquid hydrocarbon streams remain separate throughout the process.The rich DGA streams which have contacted each of the liquid hydrocarbon streams are later combined for reclaiming. (As used herein, "rich DGA" indicates a stream containing a mixture of DGA, DGA degradation compounds, such as BHEEU, absorbed H2S and other absorbed sulfur compounds.) The combining of the rich DGA strearns is for the purpose of economy and efficiency of operation. It will be apparent to one skilled in the art that separate apparatus may be constructed for each hydrocarbon stream, and that such independent construction would require duplication of various pieces of equipment for reclaiming the lean DGA from the rich DGA.

The liquid hydrocarbon streams will be referred to as "sour" to indicate those liquid hydrocarbon streams containing sulfur impurities dissolved within it. The term "sweet" when used: in reference to the hydrocarbon streams will indicate liquid hydrocarbon streams substantially free of sulfur impurities. The sour liquid propane, propylene and heavier olefins stream 10 is contacted with lean DGA in liquid contactor 14. Contactor 14 is of any suitable commercial type. The contact time is dependent upon the concentration of the lean DGA solution in stream 16 and the concentrations of impurities in the sour liquid hydrocarbon stream 10. The desired contact time may be readiiy determined by one skilled in the art. Counter current flow of the two streams in contactor 14 is desirable for increased efficiency.

Leaving the contactor 14 are two streams one being the sweet liquid hydrocarbon stream 18 which is liquid propane, propylene and higher olefins substantially free of sulfur impurities but does contain some dissolved DGA. The second stream is rich DGA 19. The sweet liquid hydrocarbon stream 18 is flowed into water wash 20. Water from stream 22 is contacted with the sweet liquid hydrocarbons in order to remove any DGA which has been dissolved in the sweet liquid hydrocarbon. The streams exiting the water wash 20 are sweet liquid hydrocarbon streams 24 which are substantially free of dissolved DGA and sulfur impurities. The other stream 26 exiting the water wash 20 is water containing DGA.

Stream 26 passes to surge tank 28 where it is used to make up additional lean DGA, or recirculated to the contactors. The moisture content of stream 24 is reduced by passing stream 24 through a potassium hydroxide tower 25. After stream 24 has been dried in the potassium hydroxide tower 25, stream 24 may then be passed to a propylene splitter or other fractionator for further processing orto storage.

Rich DGA stream 19 passes into separator30 where any liquid hydrocarbon which may be present is flashed off through line 32 to use as fuel gas. The rich DGA34from separator30 isthenflowed through carbon filter 36. Carbon filter 36 may be of any design known in the prior art and is preferably a full stream filter. This filter permits the removal of particulate impurities which if allowed to circulate would lead to failure of the equipment and would contribute to foaming. The rich DGA exits the carbon filter 36 in stream 38 and is flowed into heat exchanger 40.

Heat exchanger 40 may be of any suitable design such as a shell and tube exchanger or double pipe exchanger. Rich DGA stream 38 enters the heat exchanger 40 where it is heated by lean DGA stream 42. Stream 42 which is lean DGA is a portion of the DGA regenerated in the regenerator 46. Lean DGA stream 42 is hotterthan rich DGA stream 38, and is used to preheatthe rich DGA which exits the heat exchanger in stream 44. Preheating of the rich DGA reduces the heating load placed on the regenerator 46.

The lean DGA which has been cooled exits the the heat exchanger 40 in stream 48 and passes to surge tank 28. Lean DGA stream 48 may be cooled further, if desired, in an additional heat exchanger. It will be appreciated by one skilled in the art that heat exchanger 40 may use other fluids but it is desirable to use the DGA streams because energy is used more efficiently.

Before discussing the operation of regenerator 46 and the regeneration processforthe rich DGA, the processing of sour liquid propane stream 12 will be discussed.

Sour liquid propane stream 12 is contacted with lean DGA in contactor 50. The lean DGA enters by stream 52 from the surge tank 28. As in contactor 14, the flow is preferably counter current and the contact time is a function of many parameters, such as the concentration of the lean DGA, the concentration of sulfur in sour liquid propane stream 12 and the construction of the contactor 50.

The mixture resuiting from the flow in contactor 50 is separated into two components, the first is sweet liquid propane stream 54 which is flowed to a potassium hydroxide tower for drying and further processing. The second component rich DGA stream 56 is removed from the contactor 50 and flowed to separator 58.

Rich DGA stream 62 exiting separator 58 is mixed into the rich DGA stream from contactor 14. The figure illustrates rich DGA stream 62 being mixed with preheated rich DGA stream 44 exiting heat exchanger40. Rich DGA stream 62 could be combined with the rich DGA from contactor 14 before heat exchanger 40, for example, in stream 38. The combined rich DGA streams from contactors 14 and 50 enter the regenerator 46 through stream 44.

Regenerator46 may be of any conventional still design.

Two streams leave regenerator 46, one is sour steam 64, containing principally steam, H2S and CO2.

The sour steam 64 is very corrosive and this characteristic may be reduced by a slight recycle of lean DGA at stream 66. Sour steam 64 with the recycled lean DGA from stream 66 flows into a condenser 68 and then into overhead receiver70. Two streams exit the overhead receiver 70, the first component stream is stream 72 composed of H2S and CO2, the second is sour water stream 74 which contains a slight amount of DGA.

Sour water stream 74 is recycled to the regenerator 46 and a portion may be recycled to the overhead receiver 70 or into reclaimer 78. Reclaimer 78 is a shell and tube heat exchanger with the tube side being heated preferably by hot oil or steam. A portion of sour water stream 74, if recycled, may be mixed with sparge stream entering in line 76 and may further be mixed with recycled lean DGA stream 77 prior to entering reclaimer 78. The superheated recycle water stream 74, if any, sparge stream entering in line 76 and recycled lean DGA stream 77, if any, exit reclaimer 78 as superheated reclaimer vapor 80.

The bottoms from regenerator 46 consist of lean DGA in stream 82. A portion of stream 82 is flowed through heat exchanger 84 from which it engages as vapor in line 86 and is combined with the reclaimed vaporfed into regenerator46. Heat exchanger 84 operates on a thermal siphon principle. Therefore, the flow rate through heat exchanger 84 varies with the heating load on regenerator 46. The combined vapors in lines 80 and 86 provide steam which decreases the partial pressure of the DGAto a level where the DGA degradation reaction is more readily reversed upon application of heat. Reclaimer 78 is a shell and tube heat exchanger with the tube side being heated preferably by hot oil or steam.A portion of sour water stream 74, if recycled, may be mixed with sparge steam entering in line 76 and may further be mixed with recycle lean DGA stream 77 (which still contains BHEEU) prior to entering reclaimer 78. In reclaimer 78, DGA is recovered from the degradation products of DGA and carbonyl sulfide (BHEEU) by the application of heat in the presence of stream according to the reaction.

RN-C-N-R + H20 > 2 (R-HN2) + CO2 BHEEU DGA Regeneration of DGAfrom the degradation products of DGA and carbonyl sulfide requires temperatures in the range of 275 to 450"F and a pressure of 3 to 50 psi.

The reaction vapors from the reclaimer, stream 80, combine with the vapors from exchanger 84 and are fed into regenerator 46. Regeneration of DGA from the degradation products of reactions of other sulfur compounds occurs in the regenerator at significantly lower temperatures, in the range of 250-350"F.

The portion of lean DGAfrom regenerator 46 in stream 82 that is not flowed through heat exchanger 84 forms stream 42 which is used in heat exchanger 40 to preheat the rich DGA. The flow rate in stream 42 varies as the flow rates to the reclaimer 78 and heat exchanger 84 vary. Normally, from 53% to 93% ofthe regenerator bottoms, stream 82, is contained in stream 42. While the flow of the reclaimer 78 in stream 77 is from 2% to 14% of the total flow regenerator bottoms in stream 82. The remaining portion of the regenerator bottoms comprises the flow th rough heat exchanger 84 and is a function of heating load on regenerator 46.

Surge tank 28 serves as a reservoir for lean DGA and as a mixing vessel to make up DGAto replace DGA lost during processing. In normal operation, DGA loss is experienced through entrainment of DGA in various streams exiting the desulfurization unit.

A significant problem in liquid-liquid contact systems utilizing DGA has been the formation of foam. Foaming in the system of the present invention is controlled by removal of particulate impurities by the carbon alter and the addition of 3 water soluble anti--foa.naing agent containing silicon emulsion.

An additional benefit of the invention is the more economical operation of the potassium hydroxide tower 25. The function of the potassium hydroxide tower 25 is to remove moisture from the product stream. However, the potassium hydroxide also reacts with the sulfur impurities which remain in the sweet hydrocarbon stream. Thus, as the concentration of impurities in the sweet hydrocarbon stream increases, the useful life of the potassium hydroxide charge decreases. Before utilizing the method of the present invention, sulfur impurities were removed utilizing DEA. The DEA process was not as efficient as the DGA process of the present invention, and as a result, the useful life of the potassium hydroxide charge was substantially lessened.The potassium hydroxide tower 25 had to be recharged approximately once a week when sulfur impurities were removed by the DEA method; whereas, with the DGA method of the present invention, the potassium hydroxide tower 25 requires recharging approximately once a month.

The following Examples further illustrate the present invention.

tion system of the present invention while in operation. In this example, both contactors 14 and 50 were in operation. An analysis of the sour liquid propane, propylene and olefin stream 10 entering contactor 14 was made, and a similar analysis of the sweet liquid propane, propylene and olefin stream 18 leaving the contactor was analyzed. The liquid propane, propylene and olefin stream 10 entering the contactor was overhead from a catalytic cracker and entered the contactor at a temperature of approximately 1 00'F and a pressure of about 295 pounds per square inch. Flow rate of the liquid propane, propylene and olefin stream was approximately 2,300 standard barrels per day.

The sour liquid propane, propylene and olefin stream 10 was contacted with 60% aqueous lean DGA solution, stream 16, in the contactor 14 at a temperature of about 100"Fto about 130"F and a pressure of approximately 295 pounds per square inch.

The effectiveness of the DGA in removing the various sulfur impurities is illustrated in the tables below. Table 1 illustrates the hydrogen sulfide removal, Table 2 illustrates the mercaptan (abbreviated RSH) removal, and Table 3 illustrates the carbonyl sulfide (abbreviated COS) during test runs under the above conditions.

EXAMPLE 1 A series of samples were taken from a desulfuriza TABLE I -- H2S Removal Run 1 2 3 4 5 6 Concentration (ppm) 6,560 13,000 12,000 10,000 24,000 44,000 before contactor Concentration (ppm) 0 0 0 15 33 8 after contactor %removal 100 100 100 99.8 99.9 99.99 TABLE2 - RSHRemoval Run 1 2 3 4 5 6 Concentration (ppm) 1,012 3,000 2,000 1,000 3,000 4,000 before contactor Concentration (ppm) 292 373 374 397 42 307 after contactor %removal 71.1 87.6 81.3 60.3 98.6 92.6 TABLE3 - COS Removal Run 1 2 3 4 5 6 Concentration (ppm) 0 20 14 18 28 12 before contactor Concentration (ppm) 0 9 6 5 0 8 after contactor % removal n/a 55 57.1 72.2 100.0 33.3 EXAMPLE II During normal operation of the system with only contactor 14 in operation, a series of samples were taken from the desulfurization unit of the present invention. Samples were taken every hour over a two day period and averaged. Samples ofthe sour liquid hydrocarbon stream 10 were taken prior to contactor 14. Samples of the corresponding portion, based on residence time, of the sweet hydrocarbon stream 24 leaving the potassium hydroxide tower 25 were taken every hour and averaged. Table 4 sets out the typical analysis of the sour liquid hydrocarbon stream 10 entering contactor 14.

TABLE 4 - Typical Hydrocarbon Analysis Component Weight % Ethane 0.1 Propane 18.3 Propylene 54.8 Isobutane 14.2 N-Butane 1.2 Isobutylene 8.9 and l-Butene Trans-Butene 1.7 Cis-Butene 0.8 The sour liquid hydrocarbon stream 10 entered contactor 14 at a feed temperature of approximately 80-105"F and a pressure of about 295 pounds per square inch absolute. The average charge ofthe sour hydrocarbon stream 10 was approximately 2,400 barrels per day.

The sour liquid hydrocarbon stream 10 was contacted with a lean aqueous DGA solution (stream 16) in the range of 40-60%, fed at a rate in the range of 15-30 gallons per minute. The effectiveness of DGA in removing the various sulfur impurities from the typical hydrocarbon stream reported in Table 4 is illustrated in Table 5.

TABLE 5 -- Typical Sulfur Analysis (Low-High Range)* Component Feed* Effluent Conc.* Percent Removal COS 3-9 0 < 1. 100 H2S 5,900-7,000 5-12 99.9 SO2 5-20 Not detectable 100 RSH 282-393 52-77 70 *All values in ppm.

During steady state operation, the lean DGA circulating in the system contained sulfur impurities in the range of 50-120 grains per gallon (parts per million) with a maximum concentration of 150 grains per gallon. The rich DGA solution contained sulfur impurities in the range of 1,000 to 3,500 grains per gallon (parts per million) up to a maximum of 4,000 grains per gallon.

As can be seen from Table 1 and Table 5, the present system effectively removes large amounts of H2S. Table 2 and Table 5 illustrate that the mercaptan content can be significantly decreased. The carbonyl sulfide concentration, although present in small quantities, can also be significantly decreased. The net result is a substantial reduction in total sulfur compound and the elimination of the need to perform a separate desulfurization step with the hydrocarbons in the gaseous state.

Those skilled in the art will appreciate that the sweet hydrocarbon stream 24 which has been processed in accordance with the present invention may be further fractionated to separate propane and propylene from the heavier components. In this case, the mercaptan level ofthe propane and propylene split from stream 24 will be less than that of the stream 24 feed because of the higher boiling point of mercaptans.

Claims (17)

1. A method for the removal of sulfur impurities from liquid olefins, which comprises mixing under liquid-liquid contact conditions a hydrocarbon stream consisting of liquid paraffins and olefins containing sulfur compounds as impurities, and 2 (2-aminoethoxy) ethanol in a concentration effective to remove substantially 95% or more of said sulfur compounds, the mixing being performed at a temperature and a pressure at which said hydrocarbon stream remains in the liquid state; and removing the hydrocarbon stream from contact with said 2 (2-aminoethoxy) ethanol.

2. A method according to Claim 1, wherein the sulfur compound is hydrogen sulfide, carbonyl sulfide or a mercaptan, or a combination thereof.

3. A method according to Claim 1 or 2, wherein the hydrocarbon stream consists of liquid propane and liquid propylene containing sulfur compounds as impurities.

4. A method according to Claim 1,2 or3, wherein the 2-(2-aminoethoxy) ethanol contains a water soi uble anti-foaming agent.

5. A method according to Claim 3 or 4, compris ing: (a) admixing under liquid-liquid contact condi tions; (i) a hydrocarbon stream consisting essentially of liquid propane and liquid propylene containing sulfur compounds as impurities including H2S and mercaptans; and (ii) unreacted 2-(2-aminoethoxy) ethanol, such that said 2-(2-aminoethoxy) ethanol reacts or absorbs the sulfur compounds to produce a reaction product of 2-(2-aminoethoxy) ethanol and absorbed sulfur compounds; (b) separating the mixture of step (a) into (i) a liquid hydrocarbon stream consisting essen tially of liquid propane and propylene substantially free of sulfur impurities; and (ii) a second stream of 2-(2-aminoethoxy) ethanol and the 2-(2-aminoethoxy) ethanol reaction product and absorbed sulfur compounds; and (c) heating said second stream with steam to con vert said 2-(2-aminoethoxy) ethanol reaction product to 2-(2-aminoethoxy) ethanol, and to drive off absorbed hydrogen sulfide and mercaptans thereby removing substantially 95% or more of the sulfur impurities.

6. A method according to Claim 5, further com prising the step of reusing the regenerated 2 (2-aminoethoxy) ethanol formed in step (c) for further desulfurization of liquid hydrocarbon streams.

7. A method according to Claim 5 or 6, wherein the liquid-liquid contact is carried out at a tempera ture of 70into 1600F, and a pressure of 275 pounds per square inch gauge to 335 pounds per square inch.

8. A method according to Claim 5,6 or 7, wherein ) the regeneration step is carried out at a temperature of 275"F to 450"F and at a pressure from 3 pounds per square inch absolute to 50 pounds per square inch absolute.

9. A method according to Claim 1 substantially i as hereinbefore described with reference to the accompanying drawing.

10. A method according to Claim 1 substantially as hereinbefore described in Example I or Example II.

11. A method for generating 2-(2-aminoethoxy) ethanol from the nrcuuci of the rer';ion CT- (2-arninoethexy) ethanol and carbonyl suicide cum- prising: (a) introducing a first stream containing the reaction product of 2-(2-aminoethoxy) ethanol and carbonyl sulfide into a reclaiming vessel; (b) introducing a second stream of steam into the reclaiming vessel; (c) mixing said first stream and said second stream; (d) heating the mixture formed in step (c) at sufficient temperature to convert the reaction product formed by the 2-(2-aminoethoxy) ethanol into 2 (2-aminoethoxy) ethanol; and (e) removing from the reclaiming vessel a (i) third stream of 2-(2-aminoethoxy) ethanol; and (ii) a fourth stream of steam and the products formed by the regeneration of 2-(2-aminoethoxy) ethanol in step (d).

12. A method according to Claim 11, wherein the second stream consists of steam and recycled 2 (2-aminoethoxy) ethanol from step (e).

13. A method according to Claim 11 or 12, wherein the heating of the mixture in step (d) is supplied by steam in said second stream.

14. A method according to Claim 11 or 12, wherein the heating ofthe mixture in step (d) is supplied by hot oil in said second stream,

15. A method according to any one of Claims 11 to 14, wherein the mixture of step (c) is heated in step (d) to a temperature of 330"F to 410"F and at a pressure of 3 pounds per square inch absolute to 75 pounds per square inch absolute.

16. A method according to Claim 11 substantially as herein before described with reference to the accompanying drawing.

17. Purified liquid olefins whenever prepared by a process as claimed in any one of Claims 1 to 10.