JPH0662961B2 - Method for selectively removing NH3 and H2S from hydrocarbon material - Google Patents

Description

DETAILED DESCRIPTION OF THE INVENTION Hydrocarbon oils derived from petroleum and similar resources contain varying amounts of nitrogen and sulfur compounds. In the process of refining the oil, these are unpleasant odors to the products sold,
To give undesirable properties such as corrosiveness, bad color,
Removal of these compounds is often desirable.
In addition, this compound can have deleterious effects on various catalytic refining processes, and nitrogen compounds in particular deactivate certain hydrocracking catalysts, and generate excess gas and coke in the cracking process. It tends to be generated.
Although various approaches have been made to remove nitrogen and sulfur compounds from oils, perhaps the most common and optimal method is to react nitrogen and sulfur compounds with hydrogen to convert them to NH ₃ and H ₂ S. , Catalitic hydrofining, usually promoted by elevated temperature and pressure and the use of hydrotreating catalysts. NH ₃ and H ₂ S by reacting nitrogen and sulfur compounds with hydrogen
Similar reactions that lead to the formation of catalitic crac are not specifically designed for this purpose.
king), reforming and hydrocracking (hydrocr)
other methods, such as acking). There are then various reaction effluents containing NH ₃ and H ₂ S thus produced.

NH ₃ and H ₂ S from such hydrocarbon reaction effluent streams
Removal could be accomplished by scrubbing with water, preferably at elevated pressure and low temperature. However, to achieve some removal often requires the use of large amounts of water, resulting in the formation of a dilute aqueous solution of NH ₃ and H ₂ S.
In order to make this sour water ready for discharge under the NPDES permit, it must generally be treated to remove NH ₃ and H ₂ S.

In a typical prior art technique for upgrading raw shale oil, this oil is treated under mild hydrotreating conditions,
It removes the reactive metal-organic compounds normally present in shale oils such as iron, arsenic, nickel and vanadium. These compounds deposit on the hydrotreating catalyst and eventually deplete the hydrotreating activity of the catalyst. Furthermore, the contaminated catalyst cannot be regenerated economically. As a result, the severe hydrotrea- tions (severe hydrotrea) ultimately required for the complete improvement of shale oil are carried out.
Usually, low cost, high metal capacity catalysts that are inherently unsuitable for ting) will be selected. Therefore, this mild hydrotreatment is only the first step of the overall process. A highly active catalyst is used in the severe hydrotreatment for converting nitrogen in shale oil to NH ₃ in the second step. Since the metal compound is essentially removed in the first step, the catalyst may not be resistant to the metal compound, thus allowing the catalyst formulation to be optimized for nitrogen conversion. it can. In one prior art process, a third upgrading step was used to preferentially hydrocrack wax compounds with a shape-selected catalyst to lower the pour point of shale oil. Process rock oil.

Each of these prior art upgrade processes involves some NH from the nitrogen and sulfur compounds contained in the shale oil.
₃ and H ₂ S. As described above, at elevated pressure and low temperature, to form a thin aqueous solution of NH ₃ and H _{2 S} which water and scrubbing the reactor effluent stream to remove NH ₃ and H _{2 S} called sour water . In a typical prior art recovery process, these sour water streams are combined and fed to an interconnected distillation column operating at overpressure, where NH ₃ is removed by stripping distillation. And H
₂ S are collected separately.

The H ₂ S vapor is withdrawn as an overhead from one column (H ₂ S stripper), and the bottoms of that column pass to the other column (NH ₃ stripper), where the NH ₃ vapor Is recovered by partial condensation of the overhead vapor and a portion of the condensate is recycled to the first column. The pure water is withdrawn as the bottom of the second tower. In this method, typically the weight ratio between NH ₃ and H _{2 S} is 0.5, but may operate in order to recover the NH ₃ and H _{2 S} from the effluent derived from petroleum, NH ₃ pairs In the case of effluent streams with high H ₂ S ratios (such as effluent streams from shale oil), the ammonia level in the H ₂ S stripper column feed is further increased by the ammonia in the condensate stream being recycled. To increase. This NH ₃ vs. H ₂ S
H _{2 S} removal is difficult in that during the H _{2 S} Sutoritsupa the ratio is further increased, the removal of the made to the feed of a NH ₃ vs. H _{2 S} ratio H _{2 S} becomes impossible.

SUMMARY OF THE INVENTION In the process of the present invention, when the hydrocarbon material has a low metal content and contains at least 1 part by weight of sulfur to 3 parts by weight of nitrogen, severe hydrotreating in the presence of hydrogen is carried out. When doing so, most of the nitrogen present in the hydrocarbon material is converted to ammonia and most of the sulfur in the hydrocarbon material is converted to hydrogen sulfide. The hydrotreated hydrocarbon material is then washed with an amount of water sufficient to absorb most of the hydrogen sulfide present in the hydrocarbon material, but only part of the ammonia, thereby A washed hydrotreated hydrocarbon material containing a vapor phase containing ammonia plus a small amount of hydrogen sulfide and a first sour water consisting of water, ammonia and hydrogen sulfide is then formed. The washed hydrotreated hydrocarbon material is then separated from the first sour water stream and the vapor phase present in the washed hydrotreated hydrocarbon material is
Separated from the washed hydrotreated hydrocarbon material in the high pressure separator to form a liquid hydrotreated hydrocarbon material and a vapor phase. The vapor phase is scrubbed with water to form a second sour water stream containing very little H ₂ S. A first sour water stream and strips in H _{2 S} Sutoritsupa, essentially free of NH ₃ H ₂ S
Overhead stream and a bottom stream consisting of NH ₃ , H ₂ S and water. This bottom stream is then combined with a second sour water stream, stripped in an ammonia stripper, withdrawing an overhead vapor consisting of water, hydrogen sulfide and ammonia into a stream and consisting of stripped water. Drain bottoms liquid into another stream. The overhead vapor from the ammonia stripper partially condenses, forming an uncondensed portion of ammonia substantially free of hydrogen sulfide and water and a condensed portion of water, hydrogen sulfide and ammonia. Part of this condensed part is returned to the ammonia stripper and the other part of the condensed part is recycled to the hydrogen sulfide stripper.

When the hydrocarbon material has a high metal content, the present invention overcomes the deficiencies of the prior art by treating each effluent separately. The effluent stream from the mild hydrotreating step is treated by the hydrogen sulfide stripper in a wastewater treatment step preceding the ammonia stripper, while the effluent stream from the severe hydrotreating step is processed by the ammonia stripper. It is treated in the wastewater treatment process preceding the hydrogen sulfide stripper.

In the second method, the hydrocarbon material is mildly hydrotreated in the presence of hydrogen. During this mild hydrotreatment, some nitrogen present in the hydrocarbon material is converted to ammonia and some sulfur present in the hydrocarbon material is converted to hydrogen sulfide. This hydrotreated hydrocarbon material is then washed to form a washed hydrotreated hydrocarbon material oil and a first effluent stream consisting of water, ammonia and hydrogen sulfide, which is then washed hydrotreated. Hydrocarbon material is separated from the first effluent stream. The washed hydrotreated hydrocarbon material is subjected to severe hydrotreatment in the presence of hydrogen, where most of the nitrogen remaining in the hydrocarbon material is converted to ammonia and the hydrocarbon Most of the sulfur remaining in the material is converted to hydrogen sulfide. The hydrotreated hydrocarbon material is then washed with an amount of water sufficient to absorb most of the hydrogen sulfide present in the hydrocarbon material but only partially absorb ammonia, thereby About
A second effluent stream is formed consisting of washed hydrotreated hydrocarbon material containing water and a vapor phase containing a small amount of H ₂ S and water, ammonia and hydrogen sulfide. The washed hydrotreated hydrocarbon material is then separated from the second effluent stream, and the vapor phase present in the water washed hydrotreated hydrocarbon material is separated in a high pressure separator,
A liquid hydrotreated hydrocarbon material and a vapor phase are produced. The vapor phase is scrubbed with water NH _3: H _{2 S} ratio of at least 6: forming an aqueous solution of NH ₃ is 1. The first effluent stream is stripped in a hydrogen sulfide stripper, an overhead head consisting essentially of ammonia-free hydrogen sulfide is withdrawn into one stream, and a bottom liquid consisting of water, hydrogen sulfide and ammonia is removed. In the flow of. This bottoms liquid is added to the second effluent stream, and the second effluent stream is stripped in an ammonia stripper, with an overhead of water, hydrogen sulfide and ammonia being drawn into a stream,
The bottom liquid consisting of stripped water is then drained into another stream. The overhead vapor from the ammonia stripper partially condenses, forming an uncondensed portion of ammonia vapor substantially free of hydrogen sulfide and water and a condensed portion of water, hydrogen sulfide and ammonia. A portion of this condenser is returned to the ammonia stripper and the other portion of the condenser is recycled to the hydrogen sulfide stripper.

Description of the Preferred Embodiments In the broadest application of the present invention, it is sufficient to absorb most of the H ₂ S present in the hydrocarbon material in the effluent stream, but only a portion of the ammonia. Use an amount of water that does not absorb. The effluent stream is then separated from the hydrocarbon material and the vapor phase is then separated from the hydrocarbon material. This vapor phase is scrubbed with water to form an aqueous solution of ammonia having an ammonia to hydrogen sulfide ratio of at least 6: 1.

When the hydrocarbons have a high metal content, the effluent streams from each step of the hydrocarbon material upgrade process are separated so that each can feed the optimum section of the recovery step.

The term "stripping" is used herein by raising the hot vapor or gas generated or introduced at the bottom of a multi-stage contacting column in a descending liquid, Used to characterize distillation or fractionation which reduces the most volatile components of the This distillation zone consists of one or more such columns and the ancillary equipment normally associated with them.

Hydrocarbon materials treated by conventional methods should have a low metal content. Mild hydrotreating to achieve low metal content, recycle cokin
g), or various methods such as removal of the highest boiling fraction by distillation.

The method of the present invention will be described with reference to FIG. 1 which illustrates a preferred embodiment of the present invention.

In this embodiment, the shale oil has been previously treated by recirculation coking and cracked to have a true boiling end point of 850 ° F nominal.
It is a low pour point shale oil. This shale oil contains about 18,000 parts nitrogen, 5400 parts sulfur and 18 parts all metals (mainly iron and arsenic) per million parts shale oil.

This shale oil was introduced into hydrotreating zone 20 via inlet pipe 10 with the primary purpose of reducing the nitrogen content to about 1,000 parts or less. Two types of catalysts are used in series in this hydrotreatment zone. The first catalyst is
It is usually a low cost, high metal capacity catalyst. This catalyst removes essentially all 18 parts of metal. The second catalyst usually has a high hydrogen activity, but is optimized to have no cracking activity. During the denitrification process, the sulfur content is also reduced to about 100 parts or less.

In the present invention, a limited amount of scrubbing water (about 1.8 gallons / barrel shale oil) is used in the line 30 for the purpose of ensuring the co-absorption of most of H ₂ S while absorbing only a small amount of NH _3. Was added to the reactor effluent in line 40 via. In this way, after cooling in the cooler 50 and withdrawing sour water in the line 60, the vapor phase remaining in the line 70 leaving the HP (high pressure) separator 80 contains only a small amount of H ₂ S. I can't. The sour water in line 30
Contains about 20 wt% NH ₃ and 7.6 wt% H ₂ S when the recirculation gas flow rate is about 11,000 standard cubic feet per shale oil barrel and when the pressure in the HP separator 80 is about 1,500 psia. To do. Steam in line 70 is about 0.5 mol%
Of NH ₃ and about 0.024 mol% H ₂ S. That N
H ₃ and H _{2 S} is by connexion removed to countercurrent contact with scrubbing water from line 100 in the absorption tower 110. When the scrubbing water flow rate is about 5.4 gallons per shale oil barrel, the NH ₃ content of the recycle gas is ideally in three stages of contact in the absorption tower 110 operating at about 140 ° F. In that case, it is reduced to less than 0.025 mol% and H ₂ S is reduced to less than 0.001 mol%.
With this operation, about 5.3 wt% of sour water in line 130
Of NH ₃ and 0.5 wt% H ₂ S content.
The liquid hydrocarbon phase exits the HP separator via line 140 and enters strip zone 150 where light hydrocarbons are removed via line 160 to produce shale oil in line 170, which is shale. It contains about 1,000 parts by weight or less nitrogen and 100 parts or less sulfur per million oils.

The sour water in line 60 with an NH ₃ : H ₂ S ratio of about 2.6 is combined with the recirculating solution from line 210 and fed to H ₂ S stripper 200 after being preheated in heat exchanger 220.
Cold scrubbing water was added to the top of the H ₂ S stripper via line 230, and the NH ₂ S of the H ₂ S product in line 240 was added.
₃ content is reduced to about 200 ppm or less, and the bottom of the H ₂ S stripper in line 250 is diluted to about 1
Use 5 wt% NH ₃ . The H ₂ S stripper 200 has a reboiler 26 that is preferably heated with steam.
Heat for distillation is supplied from 0. H ₂ in this case
The operating conditions of the S Stripper 200 are as follows: H 2 _S stripper par bottom of NH _3: H _{2 S} ratio, H ₂ O to _S connexion approximately 6 to be removed over head: increases to 1 (by weight). NH ₃ as mentioned in the prior art
Complete separation of H ₂ S from an aqueous solution containing
It is impossible even at high temperature such as ° F. Line 250
The inside H ₂ S stripper bottom flows to the NH ₃ stripper 300 after joining with the preheated sour water from line 130. Exchanger 320 is the overhead in line 310.
And partially condensed in condenser 330 and flow to reflux drum 340. The condensed liquid in line 350 is approximately
It contains 50 wt% NH ₃ and 16.5 wt% H ₂ S. Some of the condensed liquid is returned to NH ₃ via line 360 as reflux.
Returned to the stripper and recycle the retentate to H ₂ S stripper 200 via line 210. Reboiler 370 to NH ₃ stripper 3 preferably heated with steam
Distillation heat is applied to 00. The operating conditions of the NH ₃ stripper in this case are as follows: The NH ₃ stripper bottoms in line 380 will contain less than 1,000 ppm, preferably less than 100 ppm, each of NH ₃ and H ₂ S. This stripped water is used in the exchanger
Cool in 220 and cooler 390 and then use as scrubbing water. The vapor exiting the reflux drum 340 via line 400 is about 96% NH ₃ and a small amount of H 2.
₂ and water. This vapor is used in the NH ₃ purification zone 41.
0, where additional scrubbing water in line 420 is used to remove H ₂ S, which water is supplied to line 430, line 3
Recycle to H ₂ S stripper 200 via 50 and 210.

The operation of the method for treating high metal content materials will be described with reference to FIG. 2, which illustrates a preferred embodiment of the present invention. In this embodiment, crude shale oil containing about 21,000 parts of nitrogen, 6,000 parts of sulfur and 100 parts of all metals (iron, arsenic and nickel) per million parts of shale oil has a metal content of about 5 parts. Through an inlet pipe 10 to a mild hydrotreating zone 20 with the main purpose of reducing the volume to 10 parts or less. The metal deposited on the catalyst and eventually replaced it. In the process of this metal removal reaction,
2,100 parts by weight of nitrogen (about 10%) and about 4,000 parts of sulfur (about 67%) was also converted to NH ₃ and H _{2 S,} respectively. The optimum amount of scrubbing water (about 2 gallons per shale oil barrel) for the purpose of absorbing the formed NH ₃ and H ₂ S is injected via line 40 into the reactor effluent line 30 and thereby the cooler. Effectively removes H ₂ S and NH ₃ in the aqueous solution which is removed from the HP (high pressure) separator 60 via line 70 after cooling at 50. This solution is
It contains about 5.1 wt% NH ₃ and 8.5 wt% H ₂ S. The hydrogen-rich gas is recycled to the hydrotreatment zone 20 via line 80. The gas, to be simultaneously absorbed into the scrubbing water in approximately equimolar _amounts, NH ₃ and H _{2 S,} is substantially free of NH ₃ and H _{2 S.} The liquid hydrocarbon phase enters the stripping zone 100 from the HP separator 60 via line 90 where the soft hydrocarbons are transferred to line 110.
The demetallized shale oil is obtained in line 120 and contains about 18,900 parts by weight of nitrogen and 2,000 parts of sulfur per million parts of shale oil.

The demetalized shale oil has a nitrogen content of about 1,000.
Parts into the severe hydrotreating zone 130 with the primary purpose of reducing the volume to below. The catalyst used in this zone can be highly adapted for nitrogen removal due to almost complete metal removal in the previous mild hydrotreating zone. During the course of this nitrogen removal reaction, the sulfur content is also reduced to about 100 parts or less. In the main process of the invention, NH ₃ absorbs slightly but a limited amount of scrubbing water (about 2 gallons per shale oil barrel) is used in line 140 to ensure simultaneous absorption of most of the H ₂ S. To the reactor effluent in line 150 via. Therefore, the steam remaining in the line 180 after being cooled in the cooler 160 and leaving the sour water in the line 170 and remaining in the line 180 is about 3% of the H ₂ S formed in the hydrotreatment zone.
Contains only Sour water in line 170 is line 180
When the recirculated gas flow rate in the shale oil barrel was 11,000 standard cubic feet and the pressure in the HP separator 190 was about 2,000 psia, about 18 wt% NH ₃ and 4.2 wt.
% H ₂ S. The recycle gas in line 180 is
Containing NH ₃ and 0.02 mol% of _{H 2} S to about 0.8 mole%. The NH ₃ and H ₂ S are absorbed by the line 200
Is removed in contact with scrubbing water from.
When the scrubbing water flow rate in line 200 is about 6 gallons / barrel shale oil, the three stages of ideal contact in the absorber operating at about 140 ° F. The NH ₃ content can be reduced by about 97%. As a result of this operation, NH ₃ in the solution in the line 220 is about 8.5 wt% and H ₂ S is
0.4 wt%, and NH in the recycle gas in line 230
₃ is about 0.04 mol% and H ₂ S is zero. The liquid hydrocarbon phase exits the HP separator 190 via line 240 into strip zone 250 where light hydrocarbons are removed and produce shale oil in line 260, which is one million shale oil. It contains about 1000 parts by weight or less nitrogen and 100 parts or less sulfur per part.

Often, this operation is a full range of shale oil upgrade before pipeline transportation to a conventional refinery for further processing. However, in some cases, the shale oil may be subjected to a third quality improvement treatment to lower its pour point and thereby reduce pipe transportation costs.
In this case, the shale oil is removed from the selective hydrocracking zone 27 in a manner similar to the previous two-stage upgrading process.
Process in 0, cooler 280, HP separator 290 and stripping zone 300. Further formed N
Scraping water can be added via the illustrated line 310 to absorb H ₃ and H ₂ S, and these are removed as a solution in line 320. Alternatively, the NH
₃ and H ₂ S can also be removed by absorption by water in strip zone 300.

All of the above description in this embodiment may be referred to as the shale oil upgrading and NH ₃ and H ₂ S removal portion of the present invention. The next description is NH ₃ and H ₂ S
Can be called the recovery part of. The essence of the present invention is that the various sour waters generated in the removal section can be separated and each fed to the recovery section at their optimum point.

The sour water in line 70 has an NH ₃ : H ₂ S ratio of about 0.6 and, if desired, after preheating in heat exchanger 340, H ₂
Supply at midpoint of S Stripper 330. Reflux drum 360
The recycle stream in line 350 from is fed to the low point of H ₂ S stripper 330 via line 380 together with the dilution water from line 370 because its NH ₃ : H ₂ S ratio is about 3.0. . Reflux around the pump in the line 390 and 400 and 410, and cooled in exchanger 340 and cooler 420, H ₂
Returned to the top of the S stripper. Cold scrubbing water was added to the top of the H ₂ S stripper 330 via line 430 to reduce the NH ₃ content of the H ₂ S product in line 440 to about 200 pp.
Reduce to m or less. The heat for distillation is added to the H ₂ S stripper 330 via a reboiler 450, which is preferably steam heated. Preferred operating conditions of H 2 _S Sutoritsupa 330 are as follows: pressure, psia 100 to 400 bottom temperature, ° F 300 to 400 over head temperature, ° F 60 to 120 H 2 _S stripper par bottom of the NH ₃ vs. H _{2 S} ratio increases to between 5 and 10: 1 for the H _{2 S} which is removed over head. As pointed out in the prior art, the complete removal of H ₂ S from aqueous solutions containing NH ₃ is not possible even at temperatures as high as 450 ° F.
The bottom of the H ₂ S stripper is NH ₃ via line 460.
Enter Stripper 470. NH ₃ : H ₂ S ratio line of about 4.3
The sour water in 170 is also fed to NH ₃ stripper 470 after preheating in exchangers 480 and 490. Overhead vapor in line 500 is partially condensed in exchanger 480 and condenser 510 and flows to reflux drum 360 via lines 520, 530 and 540. The condensed liquid in line 550 is approximately 50 wt% NH ₃ and 16.5 wt% H ₂ S.
Contains. A portion of this condensate is returned to the NH ₃ stripper 470 as reflux and the rest is diluted with water from line 370 and then recycled to the H ₂ S stripper 330. Reboiler 570, which is preferably heated with steam for distillation
Via NH ₃ stripper 470. The preferred operating conditions for this NH ₃ stripper are as follows: Pressure psia 50-100 Bottom temperature ° F 280-330 Overhead temperature ° F 220-270 Reflux drum temperature ° F 90-150 NH _{3 in} line 580. Stripper bottoms are 1000ppm each
Less, preferably less than 100 ppm each, of NH ₃ and H ₂ S. This stripped water may be cooled in exchanger 490 and cooler 590 and then used as scrubbing water as follows: -Scalbing water from the effluent of the mild hydrotreating zone via line 40. as - as scrubbing water effluent severe hydrotreating zone via line 140, - as top reflux H _{2 S} Sutoritsupa via line 430.

About 96% of the steam leaving the reflux drum 360 via line 610
Contains NH ₃ and a small amount of H ₂ S and water. This vapor is fed to the NH ₃ purification zone 620, where additional scrubbing water in line 630 is used to remove H ₂ S and it is recycled through line 640, at the same time as lines 550,3.
Recycle to H ₂ S stripper 330 via 50 and 380.

The sour water in line 220 merges with the sour water from line 320, is preheated in exchanger 670, and is passed through line 660 to NH3.
₃ Supply to the fractionator 650. This NH ₃ fluxioner 650 is an ordinary reboiler (r
eboiled) and reflux distillation columns, operated under the following conditions, to obtain essentially pure liquid NH ₃ overhead and purified water as bottoms. Operating conditions: Pressure psia About 215 Reflux temperature ° F About 100 Bottom temperature ° F About 390 Bottom scrubbing effluent from absorption tower 210 and selective hydrocracking zone 270 after cooling with exchanger 670 and cooler 680 Used as water. The side of the small amount of liquid draw (side draw), taken out through a line 690, back to H _{2 S} in H _{2 S} Sutoritsupa 330 via lines 550,530 and 380.

Although the present invention has been described with reference to particular embodiments, the present application
It is intended to cover improvements and modifications made by those skilled in the art without departing from the spirit and scope of the appended claims.

[Brief description of drawings]

In order to facilitate understanding of the present invention, preferred embodiments of the present invention will be described with reference to the drawings. The drawings are for purposes of illustration and not limitation of the invention. 1, 2A and 2B are process diagrams of two preferred embodiments of the present invention.

Claims (2)

[Claims] 1. A method for treating a hydrocarbon oil containing at least 3 parts by weight of nitrogen per 1 part by weight of sulfur, comprising: (a) hydrotreating the hydrocarbon oil in the presence of hydrogen, Converting most of the nitrogen remaining in the hydrocarbon oil to ammonia, and most of the sulfur remaining in the hydrocarbon oil to hydrogen sulfide, (b) the hydrotreated carbonization described above. A hydrogenated oil is washed with enough water to absorb most of its hydrogen sulfide but only part of its ammonia, thereby washing hydrogenation containing ammonia and hydrogen sulfide in the vapor phase. Forming a treated hydrocarbon oil and a first sour water stream comprising water, ammonia and hydrogen sulfide, and (c) separating the washed hydrotreated hydrocarbon oil from the first sour water stream, and High pressure Separating the vapor phase from the washed hydrotreated hydrocarbon oil in a pallet, (d) scrubbing the vapor phase with water, containing ammonia having an ammonia to hydrogen sulfide ratio of at least 6: 1; (E) stripping the first sour water stream in a hydrogen sulfide stripper, and (f) withdrawing overhead steam from the hydrogen sulfide stripper, where the steam is (G) withdrawing a bottom liquid from said hydrogen sulfide stripper, wherein said liquid consists of water, hydrogen sulfide and ammonia; h) adding the bottoms liquid to the second sour water stream, and (i) adding the second sour water stream to ammonia stream. Stripping in par, (j) withdrawing overhead vapor from the ammonia stripper, where the vapor consists of water, hydrogen sulfide and ammonia, (k) withdrawing bottom liquid from the ammonia stripper. Where the liquid comprises stripped water, (l) from the ammonia vapor which does not substantially condense the hydrogen vapor and water, and which partially condenses the overhead vapor from the ammonia stripper. Forming an uncondensed part consisting of and a condensed part consisting of water, hydrogen sulphide and ammonia, (m) returning part of said condensed part to said ammonia stripper, and (n) the other part of said condensed part Before recycling to the hydrogen sulfide stripper described above. Method. 2. A method according to claim 1 wherein said hydrocarbon oil is shale oil.