WO2007136340A1

WO2007136340A1 - Process for the regeneration of a used oil

Info

Publication number: WO2007136340A1
Application number: PCT/SE2007/050324
Authority: WO
Inventors: Björn HARRYSSON; Ahmad Kalantar; Gunnar Stang
Original assignee: Nynas Ab
Priority date: 2006-05-18
Filing date: 2007-05-10
Publication date: 2007-11-29
Also published as: EP2024038A1; EP2024038A4; EP2024038B1

Abstract

A process for the regeneration of a used oil by catalytic hydrogenation is disclosed, which process comprises: a) filtrating said used oil to remove sludge and insoluble in oil organometallic compounds in filters (1 and/or 2) whereafter pressurized hydrogen gas is added and the hydrogen-oil mixture thus obtained is subjected to a preheat-merit; b) passing the preheated mixture from step a) through a guard reactor (3, 4) in order to remove soluble in oil or-gano-metallic compounds primarily organo-copper and organo-iron compounds.c) subjecting the hydrogen-oil mixture from step b) to a catalytic hydrogenation in at least one hydrogenation fixed bed (5) at a temperature within the range of from 1000C to 4500C and at an elevated pressure. d) passing the effluent from step c) through an adsorbent bed (6, 7) to remove inorganic gases formed in step c); e) separating the stream from step d) in a warm high pressure separator (8) into a gas phase and a liquid hydrocarbon phase; f ) subjecting the liquid hydrocarbon phase from the warm high pressure separator (8) to a stripping process in a stripper unit (10); and g) recovering the regenerated oil from the bottom of the stripper unit (10).

Description

Process for the regeneration of a used oil

Technical field

The present invention relates to a process for the regeneration of a used oil. More particularly, the present invention relates to a process for the regeneration of a used oil, in particular a used transformer oil, by catalytic hydrogenation at an elevated pressure and at an elevated temperature.

Background

Hydrocarbon oils used in industrial and other environments, e.g. transformer oils, will gradually deteriorate over time due to oxidation of the hydrocarbons and contamination by other impurities. The oxidation results in compounds such as acids, ketones, phenols and other oxygen containing molecules being formed in the oil. Some of these molecules are strongly polar and will be oriented in an electrical field giving field losses when the oil is used as a transformer oil.

In addition some transformer oils may have been added/contaminated with halogenated organic compounds such as polychlorinated biphenyls (PCBs), the disposal or recycling of which possesses environmental hazards.

It is known to the people familiar with the transformers and transformer oil performance that metal dissolution from the copper winding or the core to the oil can take place. These metals; namely copper and to lower extent iron, will be present and are soluble in the oil as organo-copper and organo- iron compounds. Such compounds are detrimental to the transformer oil and to the insulation paper around the copper windings. Organo-copper and organo-iron compounds are known catalysts for catalytic oxidation of transformer oils. Hence, removal of these compounds from the used transformer oil will greatly improve the oxidation stability of the oil. Additionally, these organo-metallic compounds, mostly organo-copper compounds, could deteriorate the insulation properties of the insulation paper around the copper windings. In this case spots of copper oxide and/or copper sulphides can be formed on the insulation paper which will deteriorate the insulation properties of the insulating paper. Here the copper oxide is being formed by interaction of organo-copper compounds with oxygen (or oxygenated compounds in the oil), whereas the copper sulphides are formed by interaction of organo-copper compounds with reactive organic sulphur compounds (OSC) present in the used old transformer oil.

Therefore, ideally one should also be able to remove the reactive organic sulphur compounds from the used oil. The detection of the presence of the reactive, and hence corrosive OSC, in the oil is usually carried out by following their interactions with copper strip e.g. ASTM D130. The requirement for non-corrosiveness toward the copper surfaces has become increasingly stringent during the years. Used transformer oil which is in need of the regeneration may not pass the current anti-corrosion requirements although it has passed the requirements of the time when the oil was commissioned. Current state of the art test for corrosive sulphur compounds is the Cigre test A2Wg32, commonly known as CCD test (for 72 hours) . Ideally, regenerated oils should pass the CCD test. This means that the regeneration technique should be able to remove the corrosive organic sulphur compounds in the used transformer oil.

The oil to be regenerated can either be collected and trans- ported to the regeneration facilities or be regenerated on- site. The former approach involves blending and logistical complications .

The on-site oil-reclamation approach is commonly carried out using adsorption methods, in which the used oxidised oil, e.g. a transformer oil, to be regenerated is passed over a solid adsorbent, which adsorbs the highly polar oxidised molecules. The saturated solid adsorbent is itself regenerated by combustion at elevated temperatures.

A used oil containing oxygenated species can, however, also be regenerated chemically, in particular by the application of hydrotreatment technology. Hydrogenation effectively converts all the oxygenated organic molecules, both polar and non-polar oxygenated species, into less harmful compounds. The hydrogenation technique also provides the opportunity to remove polychlorinated biphenyls (PCBs) and other halogenated compounds from the oil.

Advantages in employment of the hydrotreatment technology to regeneration of oxidised oil is that in addition to the re- moval of highly polar oxidised molecules also less polar oxidised molecules could effectively be converted. This is of particular importance since if the oxidised molecules with lower polarity remain in the regenerated oil, they could continue the oxidation process and deteriorate the quality of the regenerated oil in a shorter period of time.

Regeneration of different kinds of used oils by means of hydrogenation is extensively described in patent literature.

Thus WO94/14731 discloses a process for simultaneous removal of halide from a halide containing organic compound and reduction of an oxygen containing compound in a hydrocarbon oil by exposing the oil to a catalyst in the presence of hydrogen and a hydrogen halide scavenger resulting in the reduction of the oxygen containing compound and the conversion of the halide to hydrohalic acid which is neutralized with the hydrogen halide scavenger. The hydrogen halide i.e. the HCl is formed by hydrogenation of the PCBs in the used transformer oil. Hydrogen halides, besides being harmful substances can also cause metallurgical corrosion problems.

The hydrogen halide scavenger used in this prior art process is basically ammonia or any nitrogen-containing compound which upon reaction with hydrogen over a hydrotreament catalyst can form ammonia.

The role of the hydrogen halide scavenger is to react with hydrogen chloride, HCl, (which is the prime hydrogen halide in this connection) to form ammonium chloride (NH₄Cl), hence "neutralising" the hydrochloric acid which can deactivate the catalyst. Since NH₄Cl is a salt and can deposit/precipitate on the catalyst or heat exchangers resulting in corrosion un- der hydrogen media, etc., it was found necessary to keep the temperature of the reactor and the lines thereafter at a sufficiently high level to keep the majority of the NH₄Cl in the gas phase.

The use of ammonia is disadvantageous since the ammonium chloride formed thereby has to be removed. According to this prior art process this is done by contacting the effluents from the reactor with wash water to dissolve the ammonium chloride in a static mixer. The mixed stream from the static mixer is then passed to a high pressure separator where oil, water and gas phases containing NH₄Cl, NH3 and H2S is then sent to a neutraliser drum. As mentioned the hydrogen halide scavenger used in this prior art process is ammonia (NH3)or any nitrogen-containing compound which upon reaction with hy- drogen over a hydrotreament catalyst (or thermal decomposition) can form ammonia (NH₃) . Ammonia is very corrosive and can cause serious corrosion problems to the equipment. Additionally, as in most of the transformer oils certain amount of organic sulphur compounds (OSC) exist. The concentration of these OSC can vary from 5-5000 ppm w/w on sulphur basis. During the hydrotreatment of the used transformer oils a certain amount of these OSC might react with hydrogen to form hydrogen sulphide, H₂S, gas. Another big source of H₂S formed in the hydrotreatment reactor is from the decomposition of so called spiking agents added to the feed oil. To those familiar with the art of hydrotreatment over conventional hydrotreatment catalysts consisting of cobalt, nickel, molybdenum, tungsten and their binary and tertiary combinations it is known that the catalyst should be kept on the so called sulphided state. This means that the metals on the catalyst are in sulphided form. This is achieved by addition of the so called spiking agents to the feed to the hydrotreater reac- tors. The spiking agents depending on their nature decompose at certain temperature yielding H₂S which in turn reacts with the metal to form metal sulphides. To keep the catalyst in sulphided state (that is active catalyst) a certain amount of H₂S should be present at any given time in the feed. H₂S will also react with ammonia resulting in the formation of ammonium sulphide. Ammonium sulphide can in turns result in pipe clogging at places where the temperature is relatively lower. Hence, addition of ammonia or other nitrogen containing compounds to the feed which over the catalyst can form ammonia will result in a) material corrosion b) formation of ammonium sulphide and ammonium chloride which could result in pipe clogging , c) slippage of NH3 from the system could result in pollution of a harmful compound; and d) need for additional processes and equipment for removal of ammonium chloride and ammonium sulphide such as a static mixer for water wash and neutralizer drum (see page 4, lines 16-23).

According to page 21 of WO94/14731 this prior art process may be configured as a mobile transformer oil treatment unit for on-site re-treatment of oils in transformers. In doing this the oil of the transformer is transferred to a transportable storage tank which is also brought on-site. Oil is processed from this tank through the hydrogenation unit and the regenerated oils is transferred to a transportable product oil tank from which regenerated oil later will be returned to the transformer via a vacuum de-gassing unit.

Emptying the transformer as thus contemplated by this process has disadvantages as insulating paper in the transformer, which has adsorbed a considerable quantity of oil, may be damaged by its own weight. The risks for such insulation paper damage are more probable in older transformers. Moreover, the insulating paper in the transformer may have very high contents of water which may have a negative impact on the performance of the transformer and the oil and water trapped in the insulation paper will retain impurities the removal of which is aimed at by means of the regeneration process thus causing contamination of the regenerated oil and faster oxidation thereof.

US-A-4 816 138 relates to a process for converting toxic liquid waste materials containing harmful amounts of biologi- cally difficult to degrade organic halogen compounds into an innocuous hydrocarbon stream wherein the liquid feed is first filtered and then mixed with hydrogen and heated. According to one embodiment the warm mixture is passed over an adsorption column filled with alumina of high porosity in order to remove catalyst poisons contained in the feed. Then it is fed to a hydrogenolysis reactor. The effluent from the reactor is cooled by being mixed with water; whereafter the mixture of water-effluent enters a separator. Oil + water go to an expansion tank. The vapour phase is discharged by a gas line and the liquid phase is sent to a phase separation where water and hydrocarbon phase (product line 22) is discharged.

The claimed process is contemplated for the treatment of water-containing wastes as well as wastes which are substan- tially water-free but although transformer oil is mentioned as one example of a waste material to be treated, the claimed process is not particularly suited for transformer oil in view of the fact that the product of the process will have a high content water (water dissolved in hydrocarbon (oil)) .

Summary of the invention

It is an object of the present invention to provide a process for the regeneration of a used oil which process may be oper- ated without any supply of water. It is another object of the present invention to provide a process for the regeneration of a used oil which process results in a minor waste water phase.

It is a further object of the present invention to provide a process for the regeneration of a used oil which process can be applied to a mobile processing unit for use on-site.

It is still another object of the present invention to pro- vide a process for the regeneration of a used transformer oil which process can be applied to a mobile processing unit for use on-site without the need of emptying the transformer completely of oil.

It is a further object of the present invention to provide a process for the regeneration of a used transformer oil which process can be applied to a mobile processing unit for use on-site with reduced risk of causing damage to insulation paper in the transformer.

It is a still further object of the present invention to provide a process for the regeneration of a used transformer oil which process can be applied to a mobile processing unit for use on-site resulting also in regeneration of used oil with- held by insulating paper in the transformer.

It is also an object of the present invention to provide a process for the regeneration of a used oil which process may be operated without addition of ammonia or any other nitro- gen-containing compound that can form ammonia upon decomposition or by hydrogenation over the catalyst bed. Hence, no supplementary processes for the removal of ammonia and/or the un-reacted nitrogen-containing compounds are required. In such way also no extra processes and equipment for the re- moval of the salts such as ammonium chloride and ammonium sulfide (which are formed upon the interaction of HCl or H₂S with ammonia and/or N-containing compounds) is required. These and other objects are achieved according to the present invention by a process for the regeneration of a used oil by catalytic hydrogenation at an elevated pressure and an elevated temperature wherein sludge and insoluble in oil organo- metallic compounds are removed by filtration and soluble in oil organo-metallic compounds, primarily organo-copper and organo-iron compounds are removed by means of a guard reactor before the used oil is subjected to hydrogenation, the effluent from the hydrogenation step is passed through an adsorb- ent bed to remove inorganic gases and then to a warm high pressure separator where the gas phase and the liquid hydrocarbon phases are separated. The latter is fed to a stripper unit from the bottom of which the regenerated oil is recovered .

When applying the process of the present invention to a mobile processing unit for use on-site for the regeneration of a transformer oil, used oil may be pumped from the bottom of the transformer via a buffer tank to the filters for the re- moval of sludge and insoluble in oil organo-metallic compounds and the regenerated oil is pumped back to the transformer while used oil is still remaining therein thus creating a back-mixing process.

Brief description of the figure

Figure 1 is a diagrammatic representation of the process for the regeneration of a used oil according to the invention. The flow pattern in Fig. 1 is presented as "up-flow" flow pattern. However, the invented process is not limited to "up- flow" flow pattern but down flow pattern could also be applied.

Detailed description of the invention

According to the present invention a process for the regeneration of a used oil, in particular a used transformer oil, by catalytic hydrogenation at an elevated pressure and an elevated temperature is provided, which process comprises:

a) filtrating said used oil to remove sludge and in- soluble in oil organometallic compounds whereafter pressur^¬ ized hydrogen gas is added and the hydrogen-oil mixture thus obtained is subjected to a preheatment ;

b) passing the preheated mixture from step a) through a guard reactor in order to remove soluble in oil organo^¬ metallic compounds primarily organo-copper and organo-iron compounds which may poison the hydrogenation catalysts and by their presence in the regenerated oil will cause problems in the quality of the regenerated oil as well as the performance of the transformer itself;

c) subjecting the hydrogen-oil mixture from step b) to a catalytic hydrogenation in at least one hydrogenation fixed-bed at a temperature within the range of from 100⁰C to 450⁰C and at an elevated pressure;

d) passing the effluent from step c) through an ad^¬ sorbent bed to remove inorganic gases (H₂S and HCl) formed in step c) ;

e) separating the stream from step d) in a warm high pressure separator into a gas phase and a liquid hydrocarbon phase;

f) subjecting the liquid hydrocarbon phase from the warm high pressure separator to a stripping process in a stripper unit; and

g) recovering the regenerated oil from the bottom of the stripper unit.

According to a preferred embodiment the process according to the present invention additionally comprises: h) separating the gas phase from the warm high pressure separator used in step e) into a gas phase, a liquid hydrocarbon phase and an aqueous phase in a cold high pressure separator; and

i) feeding said liquid hydrocarbon phase from step h) into the stripper unit and the aqueous phase to disposal.

Water of the aqueous phase mentioned in step h) is partially water initially dissolved in the used oil, partially water formed as a by-product of catalytic hydrogenation of oxygenated compounds presented in the used oil.

The invention will now become further described with refer- ence to the accompanying drawing which is a diagrammatic representation of the process according to the invention applied to the generation of used transformer oil and which embodiment represents the best mode contemplated at present for carrying out the invention.

Referring to Fig. 1, a feed of used transformer oil is passed through filters 1 and 2, which can be operated alternating. Examples of the applicable filters are filter bags or plated filter cartridges rating from 1 to 100 microns, preferably from 1 to 50 microns.

The flow pattern in Fig. 1 is schematically presented as up- flow mode (oil introduced from the bottom of the reactors 3, 4 and 5) . A down-flow mode (oil introduced from the top of the reactors 3, 4 and 5) is also in the scope of the present invention where the oil flows downwards through the reactors 3, 4 and 5. The rest of the process is the same with both down-flow and up-flow modes. The combinations of up-flow and down-flow modes through the reactors 3, 4 and 5 is also cov- ered by this invention. After the feed oil having passed a filter 1 or 2 hydrogen is introduced thereinto. Both fresh and recycled hydrogen gas can be used fully or partially. However, the purity of the hydrogen should be above 90% by volume.

The reaction mixture of oil and hydrogen thus obtained is heated up to a temperature within the range of from 100⁰C to 450⁰C, preferably from 200⁰C to 400⁰C and is then fed to catalytic guard reactors 3 and 4, operating alternatingly . The guard reactor is operated at pressure within the range of 1 to 200 bars and preferably at 1 to 100 bars. In the guard reactor (s) the reaction mixture is contacted with a catalyst with lower hydrotreatment activity, having wider pore size distribution. Hydrogenation refers to the process of addition of hydrogen to the oil molecules to be refined. Hydrogenation catalyst refers to substance which under operational condition by activation of hydrogen and the organic molecule could promote hydrogen addition reactions. The conventional hydrotreatment catalyst in hydrogenation reactor (5) is usually comprised of one or more components of Group VIB metals of Table of Elements with one or more Group VIII non-noble metals of Table of Elements as promoters on a refractory support. Hydrotreating catalyst generally contain Mo or W (or their combinations) as the group VI metal on alumina support promoted with cobalt, nickel, iron or combination thereof as the group VIII metal (s). The amount of group VIII metal (s) component on the catalyst can vary from about 0.5 to 15 wt%; and the amount of group VIB metal (s) component can vary from 1 to 30 wt%. The catalytic active metals are supported on low acidity porous support such as silica-alumina or alumina. The metals on the catalyst are in sulphided state and during the hydrotreatment they should stay sulphided in order to exhibit their highest activity. The catalyst can be: a) pre- sulphided, b) in-situ sulphided; or c) both a and b. During the hydrotreating process the active component of the catalyst should remain in sulphided state for highest activity. The sulphide state of the active catalyst component in the course of hydrotreatment is maintained by: i) interaction of the catalyst active metals with H₂S generated by hydrodesul- furization of sulphur-containing compound of the feed; and/or ii) by injection of a spiking agent to the feed. In the latter case any sulphur-containing compound, which upon hy- drotreating conditions can undergo hydrogenation and decomposition to form hydrogen sulphide can be used. Hydrotreating catalysts are commercially available, among others, catalysts from Topsøe, Albemarle; and Criterion could be used.

The catalyst in the guard reactor (3 and 4) is designated to trap and remove the metals from oil-soluble organo-metallic compounds such as organo-copper and organo-iron compounds in the feed used oil (de-metalation catalyst). Such catalysts are similar to hydrogenation catalyst discussed earlier. How- ever, in the case of guard reactor catalyst, the active metals are supported on a large surface area support having wider pores and wider average pore size distribution, preferably having bimodal pore size distribution. It is widely known to the people familiar with the art of hydrotreatment and hydroprocessing that the guard reactor performance is maximized by grading the catalyst bed. The optimum bed grading is achieved by combination of e.g. inert materials, low or medium hydrogenation activity catalyst, variation in the carrier's surface area/pore size distribution and the cata- lyst shape along with catalyst particle sizes. Examples of commercially available hydrotreatment guard reactor catalysts are Ketjenfine KG 5, Ketjenfine KF 542, Ketjenfine KG 1, Ketjenfine KG 3 from and TK-711 and TK-551 from Topsøe. The guard reactors 3 and 4 effectively remove organo-metallic species such as oil-soluble organo-copper and organo-iron compounds which may poison the hydrogenation catalyst from the oil to be regenerated. The presence of such organo-copper and organo-iron-compounds in the regenerated oil will deteriorate the performance of the transformer oil and the insu- lation properties of the transformer's copper windings insulation paper. According to an embodiment of the process according to the present invention doping of the used oil to be regenerated may be performed by adding an organo-sulfur compound or or- gano-sulphur compounds (so-called spiking agent) before the oil is fed to guard reactors 3 and 4. Such spiking agents may be any organo-sulphur compound which upon heating at a temperature >100°C over a hydrotreating catalyst can react with hydrogen or to decompose to produce H₂S. The aim of the spiking agent is to keep the catalyst in sulphide form. The con- centration of the spiking agent may vary between 10 and 1000 ppmw calculated on the feed oil.

The stream from guard reactors 3 and 4 is fed to a main hy- drogenation fixed-bed reactor 5 in which the oil-hydrogen mixture is contacted with a highly active hydrogenation catalyst at temperatures within the range of from 100⁰C to 450⁰C and at pressures within the range from 1 bar to 200 bars, preferably at a temperature of 200-400⁰C and a pressure of 1- 100 bars.

More than one reactor 5 can be applied in series, containing single bed or staged graded catalyst bed. Catalysts used are as aforementioned.

The undesired oxygen-containing molecules in the oil are catalytically converted in reactor 5 to desired ones by the catalytically addition of hydrogen to their structure. The undesired reactive organo-sulphur containing compounds in the oil are also catalytically converted in reactor 5 to de- sired ones by the catalytically addition of hydrogen to their structure (hence the regenerated oil will have less or non corrosivity tendency toward the metal surfaces in the transformer) . Hydrogenation, hydrodesulphurization, hydrodeoxy- genation and, if required, hydrodechlorination reactions are carried out simultaneously over the hydrogenation catalyst in reactor 5. The residence time of the oil in reactor 5, in terms of Liquid Hourly Space Velocity, LHSV, could be in the range of 0.1 to 15 h^"1; and preferably in the range of 2 to 8 h^"1. The preferred hydrogen-to-oil ratio (at STP) is in the range of 10 to 300 on volume basis and more preferably in the range of 10 to 100 (at STP) .

The effluent from reactor 5 is passed through an adsorbent bed 6 or 7 in order to remove inorganic gases, i.e. H₂S and possibly HCl, formed by the hydrogenation step in reactor 5 in which the H₂S is formed by hydrogenation of the reactive organic sulphur compounds in the used transformer oil whereas the HCl is formed by the hydrogenation of chlorine containing molecules such as PCBs in the feed used transformer oil (i.e. if the feed contain PCBs) . If the used oil to be treated by the process of the present invention contains PCBs, the hydrogen chloride gas formed in reactor 5 can be adsorbed in adsorbent beds 6 or 7. In addition to the use of the adsorbent of adsorbent beds 6 or 7 for the adsorption of hydrogen chloride gas part thereof may be used for adsorption of hydrogen sulphide gas .

Adsorbent materials for use in adsorbent beds 6 and 7 are primarily based on alkaline and alkaline earth compounds which are commercially available, such as those which are discussed later in the text in connection with sorbent beds 12 and 13.

After having passed an adsorbent bed 6 and/or 7 the stream thus purified from inorganic gases, mainly hydrogen sulphide and hydrogen chloride, is fed to a warm high pressure separator 8 where it is separated into a gas phase and a liquid hydrocarbon phase. Separator 8 is operated at a temperature within the range of from 40 to 200 ⁰C and at a pressure within the range from 1 to 200 bars, preferably at from 50 to 150⁰C and from 1 to 100 bars. The liquid hydrocarbon phase leaving the warm high pressure separator 8 is subjected to a stripping process in a stripper unit 10 which may be operated at atmospheric or sub- atmospheric pressures, i.e. under pressures within the range of 1-760 mmHg and a temperature within the range of 10-200⁰C. Preferably nitrogen gas is used for the stripping process.

Regenerated oil is recovered from the condenser bottom of the stripper unit 10 (Line 1), whereas the gas phase is fed to a cold separator 11 to be separated into one mostly hydrocarbon phase, one mostly aqueous phase (i.e. two liquid phases; and a gas phase) . The liquid phases from cold separator 11 are sent to disposal (Lines 2, 3).

According to a preferred embodiment of the process according to the invention said process also comprises a first additional step, wherein the gas phase leaving the warm high pressure separator 8 is separated into a gas phase, a liquid hydrocarbon phase and an aqueous phase in a cold high pres- sure separator 9, and a second additional step wherein the liquid hydrocarbon phase from the cold high pressure separator 9 is fed into the stripper unit 10 while the aqueous phase is sent to disposal (Line 3).

Cold high pressure separator 9 may be operated at pressures within the range of from 1 to 200 bars and at temperatures within the range of from 30 to 100⁰C. The separator 11 may be operated at atmospheric or sub-atmospheric pressures, preferably within the range of from 1 to 760 mmHg and at tempera- tures of 25⁰C to 12O⁰C.

The gas phase from the respective cold separators 9 and 11 is preferably passed through sorption beds 13 and 12, respectively, in order to remove hydrogen sulphide and potentially hydrogen chloride gases. Alternatively the gas phases from separators 9 and 11 may be mixed and passed through a common sorption bed. According to a modification of the process, especially when regenerating PCB free oils, illustrated in the drawing adsorbent beds 6 and 7 are omitted and thus the effluent from the hydrogenation fixed-bed 5 is fed directly into the warm high pressure separator 8. The gas phase leaving warm high pressure separator 8 is subjected to a further separation in a cold high pressure separator 9 into two liquid phases and a gas phase whereas the liquid phase leaving warm high pressure separator 8 is fed to the stripper unit 10 as in the basic process illustrated in the drawing. Like in case of the basic process the gas phase obtained from the stripper unit 10 is subjected to a separation in a cold separator 11 into two liquid phases (one thereof being a mostly hydrocarbon phase and the other being a mostly aqueous phase) and a gas phase. Furthermore, like in case of the basic process, the gas phases from the cold high pressure separator 9 and cold separator 11, respectively, are passed through at least one sor- bent bed 13 and 12, respectively, in order to remove at least one of mercaptanes and H2S therefrom.

As an alternative to the feeding of the gas streams from cold high pressure separator 9 and cold separator 11 to separate sorbent beds 13 and 12 as shown in the drawing, said streams may be combined and fed alternatingly to one of the two sor- bent beds 12 and 13 shown in the drawing.

Principally the sorbent beds 12 and 13 can be filled with any inorganic compound or mixture of inorganic compounds that upon reaction with H₂S and traces of HCl gases is able to form the corresponding stable metal sulphides and chlorides, respectively, and thereby removing said gases from the gas stream.

Materials suited for use in the sorbent beds 12 and 13 are commercially available and are based e.g. on iron oxides (such as Sulfatreat™, Sulfur-Rite™ and Meida-G2™) ; transition metal oxides such as ZnO and other mixed transition metal oxides doped with alkaline oxides deposited on alumina (e.g. Puraspec™ products); or activated carbon impregnated/deposited with alkali metal carbonate (such as Sofno- carb™) .

In order to obtain best possible removal of both H₂S and traces of HCl the sorbent beds 12 and 13 are preferably packed with dual trap materials, one thereof being specifically adapted for the removal of HCl and the other for the removal of H₂S.

The purified gas stream leaving sorbent beds 12 and 13 is passed through a catalytic combustor or a burner 14 where complete combustion of the flue gases to water and carbon dioxide is carried out or part or all of the purified gas stream is recycled through a gas compressor 15.

According to an alternative treatment of the gas phases leaving cold high pressure separator 9 and cold separator 11, said gas phases are passed through a hydrogen purifier mem- brane in order to separate hydrogen gas from H₂S, O₂, N₂ and CO₂. The hydrogen lean stream from the hydrogen purifying membrane is fed to sorbent beds 12 and 13. Hydrogen rich stream from the purifier membrane is fed to the gas compressor 15 to be recycled in the process whereas the hydrogen lean gases leaving sorbent beds 12 and 13 are sent to the catalytic combustor or burner 14. Part of the purified hydrogen may also be sent to burning by the burner 14.

The gas membrane to be used in this embodiment will be oper- ated by a size exclusion approach. Such membranes are commercially available, e.g. Medal™ from Air Liquide.

According to a preferred aspect of the invention the process according to the invention is carried out in a mobile plant unit.

According to a preferred embodiment of this aspect of the invention, which embodiment represents the best mode contem- plated at present of carrying out the invention, the mobile plant is placed on-site in the vicinity of a transformer and used transformer oil is pumped from the bottom of the transformer to a buffer tank before being subjected to the regen- eration process according to the invention starting with step a) of said process and regenerated transformer oil from step g) of said process is returned into the transformer thus carrying out the process in a recirculation mode avoiding complete emptying of the transformer.

Thus the regenerated oil, when being pumped back into the transformer, will be contacted with non-regenerated oil therein (back-mixing) and become contaminated. For that reason the regeneration process should be continued until the volume of oil that has passed through the regeneration system is several times the volume of oil originally contained in the transformer, preferably at least three times that volume. In this way even contaminated oil, that is held by the insulating paper in the transformer and that would remain therein if completely emptying the transformer, will be brought into the circulation system and thus regenerated according to the present invention and there is no risk of causing damage to the insulating paper due to the own weight of said paper with oil adsorbed therein. Such re-circulation will also help in removing the excess water in the transformer's insulating paper (in which some organic acid might be dissolved) and shift the paper water-oil equilibrium.

According to another aspect of the invention, the used trans- former oil is subjected to a treatment step before starting the regeneration process according to this embodiment. In this pre-treatment the used transformer oil, after being filtered for removal of coarse materials in filters (1 or 2), is fed to the stripper (10). This is done for dewatering (dehy- dration) of the transformer oil. The stripper (10) is in this case operated at temperatures of 10-150⁰C and pressures of 1- 760 mm Hg. The dehydrated oil is returned to the transformer and the removed water is collected from Line 3. In some cases, such as when the transformer is to be taken out of service for maintenance or e.g. the solid insulation is to be cleaned/dried, an embodiment wherein the process is carried out in a tank-to-tank mode may be preferred over that disclosed above. According to this embodiment, the used oil from the transformer is discharged to a separated dedicated tank called the feed tank. The used transformer oil is further pumped from the aforementioned feed tank to the mobile regeneration unit for being regenerated. The regenerated oil from the regeneration unit is fed to a receiver tank for the regenerated transformer oil with restored oil^'s electrical properties and will contain no or negligible amounts of oil- soluble organo-copper and organo-iron compounds.

The invention will now be further described by a number of examples illustrating the application of the process illustrated by the drawing for the regeneration of used oils.

Example 1 : An oxidized feedstock oil having a properties listed in Table one was feed to the regeneration unit at pressure, temperature and H₂/oil ratio of 50 bar, 25O⁰C and 100 m³/m³ (at STP) ; respectively. The product obtained after separator 10 (Figure 1) exhibited improved oxidation and electrical properties (Table 1). The TAN number of <0.01 and TanΔ90°C of < 0,001 is the requirements for a good transformer oil. In addition the reactive sulphur compounds which can further result in corrosion problems are removed.

Example 2:

A highly oxidised oil with properties tabulated in Table 2 was fed to the regeneration unit at pressure, temperature and H₂/oil ratio of 30 bar, 275⁰C and 50 m³/m³ (at STP); respectively .

*-500 hrs, 0,3%DBPC

Table 2: The properties of the feed and the regenerated oil

Similarly to Example 1 the required TAN and electrical properties are restored to the values required for good transformer oil .

Example 3 :

Highly oxidised transformer oils were subjected to regeneration at conditions typical of examples one and two. The copper content of the feed used oils (I-III) and their corresponding regenerated oils (I-III) were determined by atomic absorption spectrophotometry with graphite oven. As shown in Table 3 the invented process completely removed the soluble in oil organo-copper compounds. Up to 80% of the soluble in oil organo-iron compounds were also removed. All the non- treated used oil samples failed the CCD test. The regenera- tion of these oils resulted in an oil which passed the state of the art CCD test, indicating that the corrosive organic sulphur compounds in oil are removed by the process described in this invention.

Table 3: The properties of the feed used oils (I-III) and their corresponding regenerated oil (I-III).

a- Analysed by atom absorption spectrophotometry with graphite oven. b- Cigre test A2Wg 32 (CCD test 72 hrs) . F = Failed the test; P = Passed the test.

Claims

1. A process for the regeneration of a used oil, in particular a used transformer oil, by catalytic hydrogenation at an elevated pressure and an elevated temperature, which process comprises:

a) filtrating said used oil to remove sludge and insoluble in oil organometallic compounds in filters (1 and/or 2) whereafter pressurized hydrogen gas is added and the hydrogen-oil mixture thus obtained is subjected to a preheat- ment ;

b) passing the preheated mixture from step a) through a guard reactor (3, 4) in order to remove soluble in oil or- gano-metallic compounds primarily organo-copper and organo- iron compounds .

c) subjecting the hydrogen-oil mixture from step b) to a catalytic hydrogenation in at least one hydrogenation fixed bed (5) at a temperature within the range of from 100⁰C to 450⁰C and at an elevated pressure.

d) passing the effluent from step c) through an ad- sorbent bed (6, 7) to remove inorganic gases formed in step c);

e) separating the stream from step d) in a warm high pressure separator (8) into a gas phase and a liquid hydro- carbon phase;

f) subjecting the liquid hydrocarbon phase from the warm high pressure separator (8) to a stripping process in a stripper unit (10); and

g) recovering the regenerated oil from the bottom of the stripper unit (10).

2. A process according to claim 1, which additionally comprises :

h) separating the gas phase from the warm high pres- sure separator (8) used in step e) into a gas phase and liquid hydrocarbon phases in a cold high pressure separator (9); and

i) feeding said liquid hydrocarbon phase from step h) into the stripper unit (10) and the aqueous phase to disposal (Line 3) .

3. A process according to claim 1 or 2, wherein the guard (3 or 4) reactor in step b) is operated at a tempera- ture within the range of from 100⁰C to 450⁰C and at an elevated pressure of 1 to 100 bar over hydrotreatment catalyst.

4. A process according to claim 1, wherein the gas phase from the stripper unit (10) used in step f) is fed to a cold separator (11) to be separated into a gas phase and two liquid phases with the liquid phases from the separator 11 being sent to disposal (Lines 2 and 3).

5. A process according to claims 2 and 3, wherein the gas phase from the cold high pressure separator (9) and cold separator (11) is passed through sorption beds (12, 13) in order to remove hydrogen sulphide and hydrogen chloride gases .

6. A process according to claim 5, wherein the gas phase from the cold high pressure separator (9) and cold separator (11) is passed through hydrogen membrane system placed prior to the sorption beds (12, 13) for hydrogen gas purification .

7. A process according to claim 1, wherein the catalytic hydrogenation according to step c) is carried out at a pressure within the range of 1-200 bar, preferably 1-100 bar.

8. A process according to claim 1, wherein the catalytic hydrogenation according to step c) is carried out at a temperature within the range of 200-400⁰C.

9. A process according to any of claims 1 to 8, wherein the catalytic hydrogenation according to step c) is carried out at a temperature within the range of 200-400⁰C and at a pressure within the range of 1-100 bar.

10. A process according to any of claims 1 to 9, wherein the catalytic hydrogenation according to step c) is carried out at a Liquid Hourly Space Velocity (LSVH) within the range of 0.1 to 15 h^"1.

11. A process according to any of claims 1 to 10, wherein the hydrogen-to-oil ratio of the feed mixture from step b) to the catalytic hydrogenation reactor (5) is within the range of from 5 to 300 on volume basis (at STP) and preferably within the range of from 10 to 100 on volume basis (at STP) .

12. A process according to claim 1, wherein at least one member selected from the group consisting of hydrogen chloride gas and hydrogen sulphide gas is/are adsorbed by at least one of the adsorbent beds (6 and/or 7) in step d) .

13. A process according to any of claims 1 to 12, wherein the stripper unit (10) is operated at atmospheric or sub-atmospheric pressures and a temperature within the range of 10-200⁰C.

14. A process according to claim 13, wherein the stripper unit (10) is operated at a pressure within the range of from 1 to 760 mm Hg.

15. A process according to any of claims 1 to 14, wherein at least one spiking agent is added to the used oil to be generated prior to the guard reactor (3, 4).

16. A modification of the process according to claim 1, which modification comprises: omitting step d) of claim 1 ; subjecting the gas phase from step e) of claim 1 to a further separation in a cold high pressure separator (9) into two liquid phases and a gas phase; subjecting the gas phase obtained from the stripping process of step f) of claim 1 to a separation in a cold separator (11) into liquid phases and a gas phase; - passing the gas phase from the cold high pressure separator (9) through at least one sorbent bed (12, 13) in order to remove at least one of HCl and H₂S therefrom; and passing the gas phase from the cold separator (11) through at least one sorbent bed (12, 13) in order to re- move at least one of HCl and H₂S therefrom.

17. A process according to claim 1 for the regeneration of used transformer oil which process is carried out in a recirculation mode by pumping transformer oil from the bottom of the transformer to a buffer tank before step a) of claim 1 and returning regenerated transformer oil from step g) of claim 1 into the transformer.

18. A process according to any of claims 1 to 17, which is carried out in a mobile plant unit.

19. A process according to claim 17, wherein the used transformer oil is subjected to a pre-treatment in which the used transformer oil after having been filtered for removal of coarse materials in filters (1 or 2) is fed to the stripper (10) for dewatering and then returned to the transformer.