CA1313639C - Process and apparatus for partial upgrading of a heavy oil feedstock - Google Patents

Abstract

"PROCESS AND APPARATUS FOR PARTIAL UPGRADING
OF A HEAVY OIL FEEDSTOCK"
ABSTRACT OF THE DISCLOSURE
The invention involves visbreaking heavy oil under mild conditions in a vertical vessel containing a vertical elongate ring spaced inwardly from the vessel wall to form an outer open-ended annular chamber and an inner open-ended soak chamber.
Heavy oil at 220 - 600°F is fed to top of annular chamber. A
mixture of visbroken residuum and heavy oil at 730 - 800°F is fed to top of soak chamber. There is heat transfer through the ring from the soak liquid to the annulus liquid to assist in maintaining mild temperature in the soak chamber. The two streams mix in the base of the vessel whereby the visbreaking reaction is quenched. Part of the product is recycled and heated to provide the feed to the soak chamber.

Description

2 The invention relates to treating produced heavy crude

3 oil in a coalescing treater and visbreaking the treated heavy

4 oil under mild conditions in a compartmentalized flash separator to produce a pipelineable product.

6 BAC~GROU~ OF THE INVENTION
7 The invention finds application in the treatment of 8 the production streams of heavy oil re~ervoirs, particularly 9 where thermal recovery techniques are utilized.
Exemplary thermal recovery techniques include steam 11 injection, in-situ combustion and cyclic steam injection ("huff 12 and puff"). Such techniques focus on reducing the viscosity of 13 the immobile oil in place, so that it can be driven to a 14 production well and recovered.
Typically, the compo6ition of the production 16 stream from a thermal recovery process can vary, from a 17 stream comprising oil, water, gases and 601ids in an 18 emulsified state to a relatively clean but viscous oil.
19 The composition, and also the viscosity of the produced stream, thus can vary widely and depend to some extent on the 21 type or stage of productlon. For example, when employing a 'huff 22 and puff' operatlon, in the initial stages of the production 23 cycle, water and sand concentrations will be high. However, 24 as the well continue~ to produce, the oil content will increase, with concomltant diminuation of solids and water -~ ", 1 weights. To offset this advantage, the temperature of the 2 produced stream decreases as the cycle progresses, with resultant 3 increase in viscosity thereof.
4A typical production stream would comprise about 20%
water content and 5% solids content. However, in order to be 6 acceptable to meet pipeline specifications, the basic sediments 7 plus water content (BS & W) must not exceed 0.5% (by volume).
8Additionally, the produced oil stream could well be at 9a temperature of 50 to 100~C and display a viscosity of 5,000 cps. In order to meet current pipe line requirements it is 11stipulated that the viscosity of the stream be 250 cps at 20 C.
12Hence, it is necessary to clean the produced crude oil 13 stream by removing water and solids therefrom and, by some means, 14 to obtain a reduction in the viscosity of the heavy oil, so as to render it transportable in a pipe line.
16It is conventional practice to subject the production 17 stream initially to a free water knock-out step,by retaining the 18 stream in a holding vessel where a large portion of the water 19 content separates out under gravity. After this step,the water concentration of the production stream is typically 10%. However, 21 this residual water is in a non-readily disengageable emulsified 22 state. Therefore it is necessary to subject the stream to a more 23 rigorous treatment. This i9 done by passing the oil/water 24 emulsion stream to a phase separation vessel, termed a coalescing treater. In the treater, the oil is heated and admixed with 26 emulsion-breaking chemicals, if necessary, to separate the 1 water phase and solids from the lighter oil phase. Typically, 2 once treated, the relatively pu~e oil exhibits a B S & W
3 content below 0.5% by weight.
4The treater vessel per se typically comprises a horizontal cylindrical vessel forming a sump portion at its 6lower end. In smaller units the treater vessel may be 7 vertically disposed. Meating means, usually fire tubes, are 8 provided to heat the vessel contents to the requisite 9 temperature.
10Operating conditions of the treater commonly 11 comprise a pressure of up to 100 psig and temperature range 12 of 50 to 65C. rrhe low temperature is maintained to ensure 13 that the loss of light liquid hydrocarbons entrained in the vented gas product is minimized. Additionally, equipment problems arise when one attempts to operate fire tubes at 16 higher temperatures.
17 After processing in a conventional treater, the 18 pure heavy 'treated' oil typically exhibits a viscosity in 19the range 5,000 - 25,000 cps at 20 C - although the actual viscosity of the oil, because of its elevated temperature, is 21 somewhat lower.
22As the viscosity of the treated oil fails to meet 23 pipe line specifications, it has been the practice of 24 oilfield operators to lower the viscosity thereof by addition thereto of a light hydrocarbon diluent. Typically, the 26 diluent comprises condensates from a natural gas well or gas 27 recovery plant. The dilution ratio required varies from one 28 heavy oil reservoir to another, however it can be of the 13~3639 1 order of 20 - 40% ~y volume. A small portion of the diluent 2 may be added upstream of the treater.
3 The principal disadvantage of this practice resides 4 in the high costs of purchasing the diluent and transporting it to the well site and subsequently pumping it to tAe 6 refinery site. Additionally, it is acknowledged that 7 supplies of condensate are decreasing, whereas demand 8 therefor remains high.
9 Before arriving at the present invention, applicant~s original concept was to generate diluent at the 11 well head and inject components of the formed diluent as a 12 high temperature gaseous solvent into the reservoir, thereby 13 mobilizing the oil contained therein. However, a study suggested that such a process would not be economically viable at this time and the concept was modified.
16 Applicants then considered the possibility of 17 providing an on-site heavy oil partial up-grading process 18 wherein either the viscosity of the oil would be reduced in 19 the up-grading process or a diluent would be generated from the production stream. This would reduce or eliminate the 21 necessity of purchasing the diluent and transporting it to 22 the well site.
23 Consideration was given to existing processes for 24 up-grading heavy oil. Prior art processes for upgrading heavy oil may be broadly classified as either refining with 26 carbon elimination as a solid or refining without carbon 27 rejection. The first class includes coking and heavy solYent 28 de-asphalting processes. The second class encompasses 1~13fi3~
1 thermal processes, exemplary of which are visbreaking, hydro-2 visbreaking and catalytic processes.
3 Delayed coking is a well known process in the art.
4 It is directed toward the production of distillates by

5 rejection of excess carbon in the form of co~e.

6 Traditionally, delayed coking takes place at pressures of

7 about lO - 20 psig and temperatures in the range of 800 - 850

8 F (425 to 450 C).

9 Visbreaking involves the partial thermal decomposition of long hydrocarbon molecular chains by 11 cleavage thereof into shorter chains. The extent, or 12 severity, of a visbreaking process is parametric, depending 13 upon reaction (or retention) time, temperature and pressure.
14 Conventional visbreaking operates at a pressure in the range of 50 - 200 psig at temperatures ranging from 780 - 840~F
16 (415 to 450 C). Typical retention times range from a few 17 minutes to 2 hours. Conventional visbreaking is normally 18 associated with refineries and consists of passing a heavy 19 oil or the bottoms from a topping still through a single pass coil in a direct fired heater. The heater effluent can go to 21 a fractionation column or be blended with other lighter feed 22 streams. A thermal ~uenching occurs which prevents the 23 reaction from proceeding to the point of producing unwanted 24 coke. Preheating and partial recycle may also be employed to improve efficiency and control.
26 With this background in mind, we have sought to 27 devise a process which would provide the extent of cleaning 28 and viscosity reduction needed to approach or meet pipe line 29 specifications for oil over approximately 12 API and reduce 13~3639 1 the diluent requirements for oil below 12 API, which process 2 would be characterlzed by:
3 - minimal coke production;
4 - mild conditions, so that high pressure equipment would not be needed;
6 - flexibility, to cope with feeds having varying 7 compositions, flow rates and pumping requirements;
8 - adaptability for use on a small scale at a well 9 or battery site in the oilfield or pipeline receivi.ng station; and 11 - simplicity of operation.

13 In accordance with the present invention, there is 14 provided a process and apparatus for cleaning and reducing the viscosity of a heavy oil production stream; preferably to convert 16 it to a form acceptable to a pipeline. The apparatus is 17 preferably adapted for use in the oilfield at a well or battery 18 site.
19 It will be noted that the heavy oil feedstock of 20; the process of the present invention, hereinafter termed 21 'feedstock', comprises an oil production stream, preferably 22 a heavy oil stream after it has been subjected to a 23 free-water knockout treatment. Such a treatment is conventional 24 in the art. Further, it is to be understood that by the term 'treated oil' i6 meant the product leaving a coalescing 26 treater into which the feedstock is fed and treated in accordance 27 with a preferred form of the invention. Preferably, this A

1313~39 1 product is a blend comprising: feedstock, from which contained 2 solids and water have been separated; recycled light hydrocarbon 3 fractions from a visb~eaking step; and, optionally re-cycled 4 visbroken residuum.
The i~vention is centered upon but not restricted to 6 combining at an oilfield site two interdependent processes which 7 advantageously feed each other to yield beneficial cleaning and 8 viscosity reduction and increased API gravity of the previously 9 defined feedstock. The first process involves treating the feedstock in a coalescing treater in a novel manner. The second 11 process involves partially thermally decomposing the treated oil 12 from the treater under mild conditions (i.e. "visbreaking") in 13 a novel manner and vessel. Preferably the overhead light 14 hydrocarbon vapour stream from the visbreaking process is partially condensed and at least part of the hot gassy 16 condensation product is recycled to the inlet of the treater, to 17 provide heating, mixing and dilution of the oil feedstock.
18 Preferably, part of the hot residuum product from the visbreaking 19 process is also recycled to the inlet of the treater, to provide additional heat to the mixture. The overhead vapour stream from 21 the treater is preferably cooled and partially refluxed to return 22 contained heavier fractions to the treater mixture.
23 By supplying heat to the treater contents by the 24 medium of fluids recycled from the visbreaking process, the need for fire tube~ in the treater may be eliminated or 26 reduced and the treater may be operated at a much higher 27 temperature than that which would conventionally be used if 28 fire tubes alone were used. Thus, in the front end of the ~,, 1313g39 1 treater the feedstock is mixed with light hydrocarbon diluent and 2 heated to relatively high temperature (e.g. 180 F). This is done 3 in order to disperse emulsions and increase the gravity 4 difference between oil and water. In the settling compartment of the treater, water and solids are thus separated by gra~ity 6 with relatively high efficiency. Also, of course, the viscosity 7 of the feedstock is greatly reduced with a concomitant increase 8 in API gravity due to its relatively dramatic temperature 9 increase.
When the treater process is operated in this manner, 11 a treated product may be obtained which is capable of meeting the 12 previously mentioned pipe line specification with respect to BS
13 ~ W.
14 With feedstocks above 12 API, no additional dilution with condensate is required. However when the feedstock iB below 16 about 12 API, a viscosity reduction i8 provided using this 17 process. In order to meet pipeline specifications it will 18 usually be nece6sary to add condensates as a diluent.
19 The visbreaking process and apparatus are novel in themselves. The visbreaking process is fed treated oil 21~ and conducted so as to minimize or eliminate the formation 22 of coke. Use of untreated oil in the process would 23 deleteriously affect the heat balance and lead to rapid 24 fouling of the heat exchangers. The treated oil may be oil ~treated~ in accordance with the present invention.
26 Alternatively, the oil may have been treated using a 27 conventional coalescing treater. The process i~ carried out in 28 conjunction with a novel compartmentalized flash separator/soak 29 vessel having a bottom outlet for combined treated oil and ., ~

13~3639 1 visbroken residuum. ~he bottom outlet is connected to an 2 indirect heat exchanger ~rain ("the recycle exchanger train") 3 adapted to provide a substantially conservative uniform flux rate 4 of heat exchange, whereby part of the visbroken residuum stream may be heated to a uniform and controlled temperature and 6 recycled to the upper end of the central soak chamber of the 7 flash separator vessel. One suitable heating system for this 8 purpose involves a train of shell and tube heat exchangers 9 supplied with burner-heated eutectic salt mixture heating medium.
In another preferred aspect, the treated product from 11 the treater is pre-heated by indirect heat exchange with the 12 overhead light hydrocarbon vapour stream from the visbreaking 13 vessel, to thereby partly condense said vapour stream. This heat 14 exchange. is carried out in an inlet process-to-process heat exchanger train. The treated product is now at a temperature 16 which is greater than the treater temperature but substantially 17 less than the temperature of the stream of visbroken residuum and 18 treated oil being recycled to the visbreaking flash 19 separator/soak vessel.
The flash separator vessel is formed with an internal 21 elongate tubular member, such as an elongate ring, extending 22 parallel to the vessel side wall in spaced relation therewith 23 through the intermediate length of the vessel, to form a central 24 soak chamber, an outer annular chamber and a bottom zone in which the streams from the two open-ended compartments may mix. The 26 pre-heated treated product stream from the inlet exchanger train 27 is fea into the annular chamber and the recycled residuum from 2B the recycle exchanger train is fed into the soak chamber. Light 29 hydrocarbon fractions contained in the treated oil and the partially thermally decomposed recycled residuum are evaporated 1 and recovered as overhead vapour. The relatively cool treated 2 oil in the annulus functions to keep the ~essel ring at a 3 temperature less than that prevailing in the centre of the soak 4 chamber and below the coking temperature of the oil, to thereby reduce, or eliminate, the extent of coke accumulation on the 6 ring.
7 Stated otherwise, heat is transferred from the hot 8 liquid in the soak chamber, through the annular wall of the ring, 9 to the cooler liquid in the annular chamber. This heat transfer occurs along the vertical length of the ring. This provides a 11 mechanism for cooling the liquid in the soak chamber to maintain 12 it at mild visbreaking temperatures. By isolating the incoming 13 relatively cool treated oil in the annular chamber from the 14 incoming relatively hot recycled visbroken resid, premature quenching of the resid is avoided. By commingling the treated 16 oil and visbroken residuum in the base of the vessel, the former 17 does quench the latter at that point to terminate visbreaking and 18 associated coke production. By providing open-ended passages or 19 chambers and a vented common flash zone at the top end of the vessel, provision is made for flaQhing and removal of light ends 21 from the two incoming streams.

22 DESCRIPTION OF THE DRAW~S
23 Figure 1 is a schematic depicting the process circuit 24 of a preferred embodiment of the invention;
Figure 2 is a detailed sectional side view of the flash 26 separator and eutectic salt heating system employed in the 27 circuit of Figure 1;
28 Figure 3 is a side-sectional view of the treater vessel 29 employed in the circuit of Figure 1; and Figure 4 is a schematic showing the pilot plant used 31 for the visbreaking tests.

1313~39 2 Having reference to the accompanying drawings, 3 the heavy oil partial up-grading plant and process for 4 the treatment of a heavy oil production stream will now be described. It will be appreciated, although not illustrated in 6 the drawings, that the apparatus is sized and adapted for skid-7 mounting, so as to be readily transportable.
8 A typical circuit, illu6trated in Figure 1, comprises 9 a coalescing treater 1, a flash separator 2, a eutectic salt heating unit 3 (or recycle exchanger train~, and a process-to-11 process heat exchanger train 4.
12 As shown, production from the wells is introduced to 13 the circuit through line 5 and is passed into treater 1. The 14 production stream has previously been subjected to a free water knockout treatment in a conventional vessel (not shown). The 16 heavy oil feedstock entering treater 1 typically has a water 17 content of about 10% (by wt.), and solids content of about 5%.
18 Its temperature typically is about 120 - 140F (50 to 60~C).
19 However, at the beginning of the production phase in a huff and puff system its temperature may be higher.
21 Also introduced through line 5 into treater 1 is a 22 process rscycle stream, fed into line 5 from line 6. The process 23 recycle stream comprises, in combination, partially condensed 24 overhead light hydrocarbon vapour obtained from flash separator 2 (as will be described hereinafter) and, 26 optionally, hot residuum bled from the flash separator 27 circuit (also to be further described hereinafter). The 28 ratio of overhead vapour component content and residuum 29 component content will vary, depending on process parameter variations and material and heat balance requirements, as 31 would be evident to one skilled in the art. However, the 32 ratio of heavy oil feedstock-to process recycle stream i~

1 31 ~9 1 typically maintained at approximately 3:1. The temperature 2 of the process recycle stream is typically between about 250 3 - 300 F (120 and 150 C).
4 The process recycle stream, therefore, because of its high temperature, gaseousness, and light hydrocarbon 6 content, heats, mixes and dilutes the heavy oil feedstock.
7 Thus the requirement for heating means such as fire tubes in 8 the treater may be eliminated or significantly reduced.
g Addition of the diluent assists in phase separation of the heavy oil components. And the turoulence induced in the 11 front end of the treater by the addition of the gaseous 12 recycle stream assists in disseminating emulsion-breaking 13 chemicals which would normally be introduced into the treater 14 in conventional fashion. Such emulsion-breaking (or 15 ' treating~) chemicals may be added as required to the treater 16 1 through line 7.
l7 Treater 1, as shown in Figure 3, comprises a vessel 18 having a baffle 8 affixed as illustrated, dividing the l9 internal chamber 9 of said vessel into a front end mixing 20 zone 9a and a downstream coalescing/phase-separating zone 9b.
21 A sump zone 9c is located at the base of the vessel. Water 22 and solids which settle and collect therein are withdrawn 23 from the vessel through line 10.
24 Conditions in the treater 1 are typically maintained at a temperature of 180 - 220~F (85 - 105 ~ C) and 26 a pressure of 15 - 20 psig.
27 A reflux condenser 11 is mounted on the upper 28 section of treater 1, for condensing lighter hydrocarbon 29 distillates and returnlng them to the treater. As a result, 13~3639 1 overhead losses of these distillates are minimized and 2 further dilution of the treated oil is achieved. The 3 remaining gas is used as fuel. The reflux condenser 11 4 contains a conventional cooling coil assembly (not shown).
~ith high asphaltic oil, it may be desirable to draw off 6 reflux condensate to thereby reduce the tendency for 7 paraffins and unsaturates to form precipitates in the 8 treater. Operation of the reflux condenser 11 is controlled g by varying coolant flow in response to variations in treater temperature and fuel requirements. As an additional 11 refinement, a heating coil is provided to augment the 12 temperature of the treater should this be necessary during 13 start-up.
14 Effluent gases leave the top of the reflux condenser 11 through line 12.
16 The treated oil leaves the treater 1 through line 7 13. Up to 50% of the treated oil can be bled off via line 14 18 as product for market when all the residuum is back fed to 19 the treater as opposed to downstream blending.
After withdrawal of product oil, the remainder of 21 the treated oil is passed to the process heat exchanger train 22 4. ~here it is heated to approximately 350 - 400F (175 to 23 205 CJ by indirect countercurrent heat exchange with the 24 overhead light hydrocar~on vapour stream leaving the flash separator 2.
26 More particularly, heat exchanger train 4 comprises 27 four or five serially connected shell-and-tube heat 28 exchangers 15. As will be evident to one skilled in the art, 29 by providing each exchanger with a product bleed line tnot 1313~39 1 shown) there is the possibility of providing a means of 2 separating a series of rough petroleum cuts from the condensing 3 vapours. As stated earlier, the exit temperature of the treated 4 oil is about 350 - 400F (175 to 205C). The inlet temperature of the vapour stream is about 700F (370DC) and its exit 6 temperature is about 240F (115 C). The train 4 is operated at 7 a pressure of 45 psig - 10 (310 kPa - 70).
8 From the last heat exchanger 15, the heated treated 9 oil is passed through line 16 to a gas/liquid heat exchanger 17.
There the temperature of the oil is further raised up to 600F
11 (315 C) by indirect heat exchange with residuum bled from the 12 separator circuit.
13 The heated treated oil then flows via line 18 into the 14 flash separator 2.
The flash separator 2, as shown in Figure 2, comprises 16 an upright cylindrical vessel 19 having an internal stainless 17 steel ring 20 mounted therein in spaced relation from the side 18 wall of the vessel. The ring 20 extends through most of the 19 length of the vessel but ends short of the top and bottom transverse walls thereof. Thus the vessel walls and the ring 20 21 combine to form an open-ended outer annular chamber 21, an open-22 ended central soak chamber 22, a top chamber 23 communicating 23 with the annular and soak chambers 21, 22, and a bottom chamber 24 24 also communicating with said chambers 21, 22. Retention times in the soa~ chamber are controlled by level and recycle rate.
26 Turning now to the lines connecting the flash 27 separator 2 with the other units of the system, the line 28 18, from the outlet end of the heat exchanger train 4, 29 communicates with the annular chamber 21. A vapour outlet line 25 extends from the upper chamber 23 and communicates with the 31 inlet end of the heat exchanger train 4. A recycle line 26 1313~39 1 extends from the outlet end of a train 27 of eutectic salt heater 2 exchangers 28 and communicates with the upper end of the soak 3 chamber 22. And a line 29 connects the base of the flash 4 separator bottom chamber 24 with the inlet end of the exchanger train 27. The exchanger train 27 is supplied with hot eutectic 6 salt mixture from a reservoir 30 and heater 31 circuit, as shown.
7 The line 29, carrying a mixture of visbroken residuum and flashed 8 treated oil (referred to as "combined product~) connects with the 9 line 32. A portion of the hot combined product is withdrawn through line 32, passed through heat exchanger 17, and/or 11 returned to the treater 1 through lines 6 and 5.
12 In the operation of the flash separator 2, treated oil 13 is partially flashed in the annular chamber 21 and then combined 14 in the bottom quench chamber 24 with partially visbroken residuum issuing from the soak chamber 22, to thereby quench the 16 visbreaking reaction. Part of the resulting combined product is 17 then recycled through the salt heater exchanger train 27 and 18 uniformly heated to about 750 - 800F (400 - 425 C). This heated 19 combined product portion is then introduced into the soak chamber 22 and temporarily retained therein to effect partial thermal 21 decomposition or visbreaking. The overhead vapours from the 22 separator are passed to the heat exchanger train 4, as previously 23 mentioned.
24 The flash separator is operated to maintain the following preferred combination of conditions, namely:

1313~39 1 soak temperature 730 - 800 F
2 pressure 30 - 55 psig 3 retention time 15 - 90 minutes 4 From the foregoing, the following advantages will be noted:
6 - visbreaking is preferably conducted at process 7 conditions which can be characterized as mild and 8 which are non-conducive to coke formation;
9 - there are provided concentric contiguous chambers separated by a heat-conducting ring, whereby there 11 is heat exchange from the soak chamber liquid to 12 the annular chamber liquid, thereby assisting in 13 maintaining mild temperature in the soak chamber 14 liquid undergoing visbreaking, to reduce coking;
- the retention time in the separator can be 16 controlled by the withdrawal rate of pump 29, to 17 thereby avoid excessive retention that can lead 18 to coking;
19 - recycling of residuum can be controlled with the pump 29 to add heat slowly and reduce coking;
21 - the provision of the reflux condenser, the 22 controlled recycle of separator product streams 23 to the treater to provide heating, mixing and 24 dilution, and control of residuum heating in the heater circuit of the flash separator all 26 contribute to provide a flexible process that is 27 adapted to cope with f eedstock variations; and 28 - the process and apparatus are relatively simple 29 and are adapted for use preferably in the oilfield site environment.

~313~39 1 It also needs to be understood that, while the process 2 has been developed in conjunction with heavy oil feedstocks 3 having an API gravity in the order of 10 - 16, it is applicable 4 with utility to medium crudes as well. Thus the phrase ~heavy oil' used in this specification is to be given a wide 6 interpretation.
7 The following example is included to demonstrate the 8 operability of the visbreaking process.

9 E~ample The tests were conducted on a bench scale pilot plant 11 using the set-up shown in Figure 4. The tests were run on a 12 batch and continuous basis. The results obtained are given in 13 Table I herebelow.

1313~39 2Fort Kent Glen Nevis Cold Lake 3~contin us) (continuous) (batch) 4Feed Product Feed Product Product Feed Product Run l Run 2 _ 6 API gravity 13.617.0 17.5 18.9 23.7 11.1 15.9 7 Viscosity cps 8 @ 20C 14500133 514.2 149 47 2071 @ 909 9 Soak Time (mins.) 34 43 55 50C 33

10 Soak Temp C 420 402 407 425

11 System Pres. kPa(g)270 276 276 345

12 Products wt %

13 Gas 3.1 5.1

14 IBP-200C 20.1 12.3

15 200 - 350C 15.8 56.1

16 350 - 525C 29.6 31.6 @ +425C

17 + 525C 31.1 1 51.9

18 Insolubles (coke) 0.2 0.4

19 Water 0.1 0.7

20 Recovery Efficiency

21 Wt. % liquids 96.6 92.2

22 Vol. $ liquidS 98.9 95.3

23 Gas Analysis Yol.%

24 Hydrogen 11.3 13.9 7.2

25 Carbon Monoxide 1.7 1.6 1.6

26 Carb~n Dioxide 1.7 0.43 1.1

27 Hydrogen Sulphide26.4 1.0 20.7

28 Methane 26.8 34-4 33 9

29 Ethane 10.7 16.7 12.7

30 Ethylene 0-9 3 9

31 Propane 8.5 10.7 7.8 - 18a -131363~

TABLE I ( cont; nued) 2 Propylene 4.1 5.4 4.6 3 Butane `3.3 4.1 2.0 4 Iso-Butane 0.8 0.9 0.5 Butene 1.8 3.1 Z.4 6 Pentane 1.3 1.1 0.4 7 Iso-Pentane 0.7 0-9 0 3 - 18b -

Claims (11)

THE EMBODIMENTS OF THE INVENTION IN WHICH AN EXCLUSIVE
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:

1. A process for visbreaking heavy oil, which is substantially free of water and solids, in a closed upstanding flash separator having top, bottom and side walls and forming an internal chamber, said separator having an elongate upright tubular member mounted in the chamber in spaced relation to its side wall, said tubular member terminating short of the top and bottom walls of the separator whereby the separator forms flash and quench chambers at the top and bottom ends respectively of the tubular member, said tubular member forming an internal soak chamber and cooperating with the separator side wall to form an outer annular chamber, said soak and annular chambers being open-ended at top and bottom and communicating with the flash and quench chambers, said separator having first means for feeding the heavy oil feed to the upper end of the annular chamber, second means for removing a product of visbroken residuum and heavy oil from the quench chamber, third means for removing produced vapour from the flash chamber, and fourth means, including pump means and heat exchanger means, for recycling and heating part of the product and feeding it to the top end of the soak chamber, said process comprising:
(a) feeding a stream of heavy oil through the first means into the top end of the annular chamber, said heavy oil having an elevated temperature that is in the range of about 220°F to about 600°F;

(b) feeding a recycle stream, comprising a mixture of visbroken residuum and heavy oil and having a temperature in the range of about 750°F to about 800°F, through the fourth means into the top end of the soak chamber;
(c) removing light hydrocarbons flashed from the heavy oil and the recycled mixture streams in the form of an overhead vapour stream;
(d) passing the heavy oil and the recycled mixture streams separately and co-currently down through the annular and soak chambers, whereby the liquid in the soak chamber is sufficiently cooled by heat exchange, through the wall of the tubular member, with the liquid moving through the annular chamber, to maintain the liquid in the soak chamber at a mild visbreaking temperature in the range of about 730°F - 800°F, thereby enabling visbreaking to proceed in the soak chamber without significant coke formation;
(e) commingling the liquids, issuing from the bottom ends of the annular and soak chambers, in the quench chamber, to quench the visbreaking reaction;
(f) withdrawing a product mixture of visbroken residuum and heavy oil at a controlled rate from the quench chamber through the second means; and (g) recycling part of the product mixture through the fourth means and heating it therein to 750°F - 800°F, to provide the recycle stream of step (b).

2. The process as set fourth in claim 1 comprising:
preheating the heavy oil, prior to introducing it into the separator, by indirect heat exchange with the overhead light hydrocarbon vapour stream leaving the flash separator.

3. The process as set forth in claim 1 wherein:
the fourth means comprises a pump feeding a heat exchanger train; and the recycled stream is substantially uniformly heated in the heat exchanger train using a eutectic salt mixture heating medium.

4. The process as set forth in claim 2 wherein:
the fourth means comprises a pump feeding a heat exchanger train; and the recycled stream is substantially uniformly heated in the heat exchanger train using a eutectic salt mixture heating medium.

5. The process as set forth in claim 1 wherein the pressure maintained in the separator is in the range of between 30 psig and 55 psig and the retention time in the soak chamber is in the range of about 15 - 90 minutes.

6. The process as set forth in claim 2 wherein the pressure maintained in the separator is in the range of between 30 psig and 55 psig and the retention time in the soak chamber is in the range of about 15 - 90 minutes.

7. The process as set forth in claim 3 wherein the pressure maintained in the separator is in the range of between 30 psig and 55 psig and the retention time in the soak chamber is in the range of about 15 - 90 minutes.

8. The process as set forth in claim 4 wherein the pressure maintained in the separator is in the range of between 30 psig and 55 psig and the retention time in the soak chamber is in the range of about 15 - 90 minutes.

9. The process as set forth in claim 1 comprising:
partly condensing the overhead vapour stream by heat exchange with the incoming heavy oil feed for the separator, to produce a partly condensed vapour stream;
supplying as-produced heavy oil containing water and solids to a coalescing treater;
contacting the as-produced oil with the partly condensed vapour stream in the treater to heat and dilute the oil; and temporarily retaining the mixture in the treater to settle and separate contained water and solids and produce the feedstock for the separator.

10. The process as set forth in claim 3 comprising:
partly condensing the overhead vapour stream by heat exchange with the incoming heavy oil feed for the separator, to produce a partly condensed vapour stream;
supplying as-produced heavy oil containing water and solids to a coalescing treater;
contacting the as-produced oil with the partly condensed vapour stream in the treater to heat and dilute the oil; and temporarily retaining the mixture in the treater to settle and separate contained water and solids and produce the feedstock for the separator.

11. The process as set forth in claim 5 comprising:
partly condensing the overhead vapour stream by heat exchange with the incoming heavy oil feed for the separator, to produce a partly condensed vapour stream;
supplying as-produced heavy oil containing water and solids to a coalescing treater;
contacting the as-produced oil with the partly condensed vapour stream in the treater to heat and dilute the oil; and temporarily retaining the mixture in the treater to settle and separate contained water and solids and produce the feedstock for the separator.