Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
1313639
1 FIELD OF THE INVENTION
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
-
~ ",
1313639
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
1313639
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.
12 SUMMARY OF THE INVENTION
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
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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
1313639
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
1 DESCRIPTION OF THE PREFERRED EMBODIMENT
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
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
14
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
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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:
16
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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.
17
~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
1 TABLE I
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 -
