Note: Descriptions are shown in the official language in which they were submitted.
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5~
FIELD OF THE I~VE~TION
This inven-tion is directed to a novel process
for the recovery of heavy petroleum type and solid coal
type hydrocarbons from surface and subterranean
hydrocarbon bearing or carrying formations or bodies.
In particular, this invention is directed to a process
for reducing in situ the viscosity of viscous
hydrocarbons in surface and subterranean formations
thereby permitting these hydrocarbons to migrate within
the formation to collection sites and ba recovered for
commercial purposes in an efficient, economical manner.
The process may also have application in the upgrading
of heavy oil and residue in oil refineries.
BACKGROUND OF THE INVENTIO~
With depleting conventional petroleum
(hydrocarbon) production, and consequent higher prices
for petroleum type hydrocarbon, extensive attention is
now being directed to "non-conventional" hydrocarbon
sources such as tar sand deposits in Alberta, Venezuela,
and other countries, shale oil deposits in the United
States, carbonate type deposits in northern Alberta, and
more conventional formation type heavy oil deposits such
as t~ose found around Cold Lake, Alberta and
Lloydminster, Saskatchewan. Attention is also being
directed to recovering hydrocarbons from coal deposits.
The econornical recovery of hydrocarbons from
"non-conventional" sources such as those described above
presents a major production problem. The principal
problem arises from the high viscosity of the
hydrocarbon and the resultant low flowability of the
S~
hydrocarbon in the deposit. Highly viscous hydrocarbons
do not migrate easily through the deposit formation and
hence cannot be readily and economically recovered at
collection sites such as the oil wells that are present
in conventional oil fields. Low gravity type crudes,
eg., 6 API, are not very mobile. To increase the
mobility of the hydrocarbons in such deposits, an
obvious point of attention has been directed to
techniques of reducing the viscosity of the hydrocarbons
in such deposits to flowable ranges.
A variety of methods have been and are now
being tested ~or reducing the viscosity of such
hydrocarbons, ranging from solvent injection using light
ends such as napthenes, to steam flocd, which thermally
favourably reduces the viscosity of the hydrocarbon, to
several variants of an in situ hydrocarbon combustion
technique.
The latter techniques (steam flood and in situ
combustion) seek to physically or chemically modiy the
hydrocarbon in situ to enable enhanced recovery.
Generally speaking, in steam flooding, enhanced
hydrocarbon recovery is achieved by physically lowering
the viscosity of the hydrocarbon by raising its
temperature. It is well known that hydrocarbons
generally become less viscous with increased
temperature.
A problem with steam flocd recovery is that it
relies primarily upon a decrease in hydrocarbon
viscosity by causing an increase in temperature of the
hydrocarbon but this decline in viscosity may not be
2:~59
sufficient to yield a readily flowable hydrocarbon to
permit enhanced recovery. Another problem is that
tremendous quantities of steam are often required, and
thus the process can rapidly become uneconomical because
of the high cost of generating heat.
The in situ combustion method enhances hydro-
carbon production by chemically altering the nature of
the hydrocarbon in the formation through various
processes such as (1) thermally decomposing the hydro-
carbon to form lighter low molecular type hydrocarbonsand coke, ~2) thermally "cracking" the hydrocarbon into
lower molecular weight components, (3) dehydrogenating
the hydrocarbon ~ith subsequent hydrogenation (wet
combustion process), and (4~ dehydrosulphurizing the
hydrocarbon.
In the "wet" combustion process, the well
known water shift reaction is a likely source of
hydrogen which, under the high temperatures and
pressures of combustion recovery in the formation, may
possibly hydrogenate the hydrocarbon in situ.
The combustion type recovery methods are
disadvantageous because they can often result în
substantial damage to the hydrocarbon deposits likely by
causing degradation of the hydrocarbons to coke, ie. a
charring efect. This generated coke deposits in and
plugs the pores in the formation, thereby obstructing
the migration of the hydrocarbon under pressure.
It has been proposed to chemically alter the
hydrocarbon in the reservoir by injecting surface active
agents, or other chernical type agents, into the
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reservoir. One technique for hydrocarbon recovery
process is disclosed and claimed in United States Patent
No. 4,156,462, Joseph C. Allen, assignee Texaco Inc~,
granted May 29, 1979. Allen discloses a two-step
process for recovering hydrocarbons Erom a subterranean
formation. The formation is ~irst heated by injecting
steam through an injection well. In a second step, a
mixture of carbon monoxide and hydrogen is pressured
into the formation by means of the injection well where
0 it i5 postulated that in the heated formation, reaction
with the carbon monoxide and steam takes place forming
additional hydrogen and carbon dioxide. The hydro-
carbons are recovered by means of a production well.
Optionally, after in~ection of the mixture o~ carbon
monoxide and hydrogen into the Eormation has been
terminated, water may be fur-ther injected into the
formation as a drive fluid. The injected water may
contain a small amount of a sul~ated interfacial tension
reducer.
SVMMARY OF THE INVENTION
The subject invention is directed to a process
for recovering hydrocarbon rom a hydrocarbon bearing
formation comprising introducing a hydrocarbon viscosity
reducing agent into the hydrocarbon formation and with-
drawing the viscosity reduced hydrocarbon from the
formation. The viscosity reducing agent may be a
hydrogenating agent and may chemically interact with the
hydrocarbon. There are at least two broad categories o~
viscosity reducing agents. The ~irst group includes any
aldehyde ~uch as aceta]dehyde or glyoxal, and
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specifically formaldehyde, and various formulations of
formaldehyde suc~ as:
(a) methanol-water-formaldehyde and its
oligomers, HO(CH2O)nEI; and
(b) paraformaldehyde, trioxane and
tetroxane.
In general terms, any substance that could in
principle lead to an aldehyde such as formaldehyde could
be used as a viscosity reducing agent in this category.
One example would be formaldoxime and another would be
~; formic acid which is known to decompose under certain
conditions to formaldehyde (ref. Encyclopedia of
Chemical Technology, 3rd Edition, Wiley-Interscience,
1978).
Another broad class of viscosity reducing
agents includes hydrazine, diimide (in-situ), chlor-
amine, hydroxylamine and any substances leading to the
foregoing.
The viscosity reducing agents of the present
invention have the advantage that, unllke gases such as
carbon monoxide, hydrogen, carbon dioxide, and the like,
the agents are generally liquids or are applied as
aqueous solutions. This reduces the tendency for the
agents to di6perse or diffuse Erom the formation
reservoir. The agents of the invention are water and
oil soluble and thus tend to be compatible with the
various substances usually present in the formation
reservoir.
The invention is directed to a process for
recovering hydrocarbon from a hydrocarbon bearing
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formation comprising (a) introducing a hydrocarbon
viscosity reducing agent into the hydrocarbon bearing
formation, and (b) withdrawing the viscosity reduced
hydrocarbon from the formation.
In the process, the viscosity reducing agellt
may be a hydrocarbon hydrogenating agent.
The viscosity reducing agent may be selected
from the group consisting of an aldehyde, an aldehyde
forming compound, hydrazine, chloramine, hydroxylamine,
and rela~ed diimide forming compounds.
The viscosity reducing agent may be introduced
into the for~ation in association with steam.
The viscosity reducing agent may also be
introduced into the formation in association with a
suitable mechanism Eor heating the formation.
A hydrocarbon hydrogenation promoting catalyst
may be included with the viscosity reducing agent.
The viscosity reducing agent may cause a
chemical structural modification to occur in the
chemical structure oE the hydrocarbon.
The hydrocarbon viscosity reducing agent may
be introduced in the hydrocarbon under conditions
external to -the hydrocarbon bearing formation.
DETAILED_DESCRIPTION OF THE INVENTION
The subject invention seems to be successful
by striking a balance between various known hydrocarbon
recovery techniques by taking advantage of the
substantial chemical alteration of the hydrocarbon in
formation that is achieved, for example, by the
combustion type recovery technique and at the same time
159
eliminating the deleterious effect that such combustion
type recovery has on hydrocarbon bearing reservoirs by
deposition therein of coke and the like, thereby
plugging up the formation. The subject invention is
directed to viscosity reducing the hydrocarbon in the
reservoir at reasonably moderate temperatures such as
100 - 300C. It is believed that the viscosity
reduction in the hydrocarbon is brought about by a
hydrogenating reaction, although I offer this as a
matter o~ possible explanation rather than as a binding
theory. Hydrogenation of hydrocarbons in this low
temperature range is difficult and in addition, most
catalysts that may be used for such hydrogenation are
metal impregnated aluminas which cannot be readily
transported to and dispersed into the formation in this
temperature range. Such catalysts are also subject to
decreased activity caused by sulphur poisoning. Sulphur
is commonly found in hydrocarbon bearing formations.
Hydrogenation o~ the hydrocarbon takes place more
readily at increased formation temperatures and this can
be achieved by steam 100d injection. Unfortunately,
steam injection provides an aqueous environment within
the formation and many common laboratory-type
hydrogenation agents are thus unsuitable in such an
environment because they decompose rapidly to hydrogen.
Hydrogenating or viscosity reducing agents
which are compatible with aqueous environments include
formaldehyde, and modifications thereof, hydrazine and
related compounds, and it is believed such agents may be
used in this invention.
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It has been postulated that the low gravity
and high viscosity charactsristic of heavy type oils and
hydrocarbons in tar sand type ~ormations is due to high
asphaltene and/or resin content in the hydrocarbon. It
is thought that asphaltenes are polymeric in nature with
large molecular weight units linked together. If these
links could be severed, there could be a substantial
reduction in viscosity. It has been proposed that
sulphur linkages are present in asphaltenes (H.V.
Drushal, "Preprints, Div. Petroleum Chem.", ACS/ 17(4),
F92 ~1972)) and cleavage of these linkages would break
the polymer into units o siynificantly lower molecular
weight thereby enhancing flowability and reducing the
viscosity. Relatively mild reducing conditions can lead
to as much as a ten-fold reduction in molecular weight
o~ the asphaltenes (T. Ignasiak, A.V. Kemp-Jones and
O.V. Strauss, "J. Org. Chem.", A2, 312 (1977)).
It is well known that hydrazine is a reducing
agent (L.F. Fieser, M. Fieser, "Reagents for Organic
Synthesis", John Wiley, New Yor~), and is capable of
attacking and cleaving carbon sulphur linkages (V.
GeGrgian, R. ~arrisson, ~. Gubish, "J. Am. Chem. Soc.,"
81, 5834 (1959)).
Formaldehyde can also act as a reducing agent
as it breaks down to atomic hydrogen as a likely step in
its ultimate decomposition to hydrogen and carbon
monoxide ("Encyclopedia o~ Chemical Technology", 3rd
Edition, Wiley-Interscience, 1978).
Thus, by treating a heavy oil reservoir, or a
coal seam, or even re~inery residue, with a hydroyen-
117ZlS9
ating agent such as hydrazine, for example, it should be
possible to cleave the sulphide links in the asphaltenes
and/or attack resin heteroatoms in the heavy crude to
obtain smaller molecular weight units. These smaller
units should typically have lower viscosities, which,
as discussed previously, is a desirable objective for
the economical production of hydrocarbons from heavy oil
formations.
~dditionally, a viscosity reducing agent, such
as hydrazine, in company with appropriate catalysts,
potentially may hydrogenate the high molecular weight
aromatic structures, other than asphaltenes, that are
found in heavy oils. If this occurs, it should increase
the hydrogen content of the produced hydrocarbon, which
is usually a desirable result for hydrocarbon upgrading
and recovery. Furthermore, in hydrogenating and
beneficiating the hydrocarbon in the heavy oil
formations, by the use o an agent such as hydrazine,
the agent, after reacting with the hydrocarbon should
produce nitrogen, and other gases, thereby providing
inherent drive pressure in the formation.
The agent, such as hydrazine, should also be
capable of reducing the sulphur, oxygen and nitrogen
content of the hydrocarbon in the formation and thereby
minimize the occurrence of a deleterious emulsion
problem in the formation.
In field application, it is contemplated that
the invention will be used in conjunction with a steam
drive carried out by flooding the hydrocarbon bearing
formation with steam. The steam flood would be
~17Z15~a
conducted to bring the formation temperature to a
desirable level such as 100 - 300C. Once the formation
was brought up to desired temperature, an alkaline
aqueous sol~tion of a viscosity reducing agent such as
hydrazine would be injected. The metals inherently
present in the formation reservoir should provide a
catalytic e~fect on the various postulated hydrogenation
reactions. Should it be found that the hydrogenating
agent alone ~as insuf~icient to achieve the desir~d
performance, a catalyst such as hydrogen peroxide or a
transition metal carbonyl could simultaneously or
subsequently be injected into the formation ~o increase
effi~iency.
Formaldehyde is another viscosity reducing
agent that may be used and characteristically thermally
decomposes to hydrogen and hydrogen monoxide. The
reaction steps are not compIetely understood but the
initial step is believed to be H2CO ~ HCO~ + H-. The
resultant HCO- -further breaks down to H- + CO. The
resultant CO, say in association with a steam drive,
could then react with water to prcduce hydrogen and
carbon dioxide. The hydrogen produced could extend the
hydrogenation reaction initiated by formaldehyde
decomposition in that the hydrocarbon radical initially
produced could abstract a hydrogen atom from the
hydrogen to thereby form RH2, thereby increasing the
hydrogen content. The mechanism and action of
formaldehyde in reducing viscosity may be similar to
that postulated or hydrazine type viscosity reducing
agents though the postulated free radical nature o~ the
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formaldehyde type viscosity reducing agents may mean
that it is less selective, ie. more reactive than
hydrazine type agents.
In view of the well-known reac-tivity of
formaldehyde with hetero-atom containing hydrocarbons,
the formaldehyde may also act to cap the polar
hetero-atom sites in the heavy oil.
Laboratory tests on a typical sample of
Athabasca tar sand obtained from Northern Alberta,
0 Canada, have been conducted and are detailed below.
Exam~le
A sample of Athabasca tar sand, commonly known
as "bitumen", was prepared to be used in a simulated
"pre-flood" steam 100d. This was done before treating
the sample with any viscosity reducing agent. A volume
of the tar sand was extracted to yield 29.1 grams of tar
sand extract. 35 cc of water was added to a .standard
autoclave containing the tar sand extract. The
"pre-flood" treatment was carried out for two weeks at
200C. Upon cooling to room temp~rature, the autoclaves
were opened. There was a small amount (10~ p5i) of gas
pressure. The bulk of the water was removed with a
pipatte leaving behind the still viscous bitumen. Two
samples were made using this technique.
The first sample was designated BC HY#l. The
sample was purged with nitrogen. 30 cc of 37% (w/w)
formaldeh~de, 1 gram oE a phase transfer catalyst-PTC-
(Bu4NCl), and a few drops of concentrated HCl were
added to the autoclave. The autoclave was heated to
200C for nine days and then cooled to room
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temperature.
A second sample designated BC HY#2 was purged
with helium and then 40 grams o 38% hydrazine in water,
l.0 grams of KOH and 1.0 PTC(BU4NCl) were added to the
vessel. The autoclave was heated at approximately 200C
for eight days and then removed.
The contents of the two vessels were examined
by cooling the autoclaves and contents, then measuring
the gas composition and pressure in the vessel at room
temperature. The vessels were then opened and the
contents were physically removed without the use of
solvents. There was excellent separation between water
and the oil phase, that is, there was no emulsion. The
contents were washed or triturated with water. The
viscosity of the recovered oil was measured at about
90C, which is a typical formation temperature near the
periphery of a steam flood.
B HY#l Sample (Formald h~e~
The 100 cc (nominal) autoclave (BC HY#l
sample3 had a room temperature gas pressure of 600 psi
using a psi gauge with an estimated Bourdon tube volume
of 20 cc.
The 100 cc (nominal) autoclave ~BC HY#2
sample3 had a room temperature gac pressure of 1500 psi
using a gauge with an estimated Burdon tube volume of 20
cc.
The gas analysis of sample BC HY#l
(formaldehyde) by the release of gas retained in the
vessel indicated greater than 1,000 cc of gas in the
system (it was likely around 1,300 - 1,400 cc as a 1.0
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litre backup reservoir expanded significantly.)
Hydrogen analysis (two tests) revealed 15.43
H2 and 15.67% H2 respectively.
Other gases found and percentages thereof are
listed as follows:
Component Percentage
CH4 4.390
C2 29.540
2 10.480
~2 34.746
CO 0.020
Total (calculating 15.5 E2) 95.530.
General Comments on Ru BC HY#l
While I do not wish to be bound to any
theories, the following comments are offered with a view
-to possibly assistlng in the understanding of the
function and operation of the invention. The analysis
shows a very high hydrogen and carbon dioxide content
which tends to indicate that under a short time ~rame,
there was substantial formaldehyde decomposition. The
~ormaldehyde probably decomposed to hydrogen and carbon
monoxide which then by a water shift reaction was
converted to more hydrogen and carbon dioxide (the
analysis indicates that there was very little carbon
monoxide present). If the formaldehyde had been
oxidizing due to air remnants in the autoclave, then the
product of such an oxidization would be formic acid
which might decompose to wa-ter and carbon rnonoxide.
Then, by a water shi~t reaction~ it would convert to
hydrogen and carbon dioxide. But, since approximately
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0.38 moles of formaldehyde were added, it is difficult
to see how sufficient oxygen was available for this
process -to take place. While, as explained previ.ously,
I do not want to be confined or held -to any theory, it
seems likely that carbon dioxide was not formed rom
formic acid in -this case but from the formaldehyde
decomposition. The presence of significant amounts of
2 and N2 maY indicate some gas sampling error.
BC HY#2 Sam~le (Hydrazine)
The release of gas contained in the 100 cc
vessel, at room temperature, indicated more than 1,000
cc and was estimated by the previously mentioned method
to be at least 1,500 - 1,800 cc. This does not take
into account the gas loss on the pressurq measurement
and the actual volume could therefore be in the two to
three litre range. This would then approach the
theoretical nitrogen available from hydrazine
decomposition.
The hydrogen analysis on two tests mea~ured
2.25 and 2.19% respectively.
The other gases and respective percentages are
set forth in the following column:
ComponentPercentage
CH4 1.412
C2 9 . 991
2 1.47g
N2 76.590
C0 1.546
Total (calculating 2.23 H2) 93.249.
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General Comments About_the BC HY#2 Run
Again, I wish -to emphasize that the following
comments are offered as a possible in-terpretation of the
mechanism behind the perormance of the invention, and
no-t as -the explanation of a binding theory. Since the
vessel was purged under helium before sealing, -the gas
analysis indicates approximately 80~ nitrogen, which in
turn indicates that most of -the hydrazine must have
decomposed. The resulting hydrogen was most likely
consumed as it only measured 2.24%.
Viscosity Analysis of the BC HY#l and BC HY#2 Samples
BC HY#l_Sample
Two days after the foregoing gas analyses were
conducted, the BC HY~l pressure vessel valve was cracked
at room temperature. Gas pressure was still evident
notwithstandiny there had been a blow down for purposes
of the gas analysis conducted two days earlier. After a
few seconds of gas release, bitumen froth carne out of
the vessel. This froth was directly collected by a
short tube in-to a 125 cc Erlenmeyer flask which was
under a nitrogen purge. The frothy bitumen flow ceased
after about 3 minutes. ~he vessel was then opened and
residual bitumen was scraped out with a spoon-type
spatula. This left an aqueous layer which indicated a
clear separation of bitumen and water in the vessel.
The aqueous layer had a pH of approximately 5.
The bitumen sample, after settling, and
presumably some de-gassing, flowed like 40 W crank case
oil at roo~ temperature. Thus, the oil viscosity of the
treated bitumen was drastically lower than that of the
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Athabasca bitumen sample prior to treatment with
formaldehyde.
Viscosity measurements on the sample BC HY#l
were conducted on a standard petroleum viscometer.
Table 1
Sample BC HY#l (Formaldehyde)
Temp. Viscosity
C Time (CPS)
11:56 3600
48 12:02 2720
49 12:06 2500
56 12:07 2440
61 12:10 2280
12:13 1760
12:14 12~0
12:15 880
12:17 540
12:19 320
91 12:21 240
91 12:25 228
91 12:24 220
91 12:35 196a
gl 12:45 196
91 1:02 196
a. more sensitive scale
It is noteworthy that at 91C, the viscosity
of the bitumen is only slightly greater than that of
water near its freezing point.
BC HY#2 Sam~le
The pressure vessel containing the BC HY~2
extract was valve cracked at room temperature and
residual gas was also evident (as with sample BC HY~l
above) despite the previous blow down for gas sampling.
Water was at first produced and then a slightly frothy
bitumen was expelled. The oil obtained from this
sample, after settling, was more viscous than that
obtained from sample BC HY#l. It flowed more like 40 W
motor oil at about -25C. However, the viscosity was
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still relatively low compared to the viscosity of the
initial Athabasca bitumen extract. Viscosity
measurements on the BC HY#2 were conducted on a standard
petroleum viscometer.
Table 2
BC HY#2 (Hydrazine)
Temp. Viscosity
C Ca 1 (CPS)
___
10:42 >4000
10:48 2200
72 10:54 1860
8~ 11:00 1720
11:06 1160
11:12 1000
11:14 900
91 11:17 700
91 11:18 740
As will be apparent to those skilled in the
art in the light of the foregoing disclosure, many
alterations and modifications are possible in the
practice of thls invention without departing from the
spirit or scope thereof. Accordingly, the scope of the
invention i,s to be construed in accordance with the
substance defined by the following claims.
