Note: Descriptions are shown in the official language in which they were submitted.
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Method of recovering thermal energy
FIELD OF THE INVENTION
The present invention relates to a method and system for recovering thermal
energy from a subterranean formation depleted of hydrocarbon. The invention is
also
concerned with a method of recovering hydrocarbon from hydrocarbon containing
subterranean formations and with an arrangement for such a recovery.
BACKGROUND
Heavy hydrocarbons, e.g. bitumen, represent a huge natural source of the
world's total potential reserves of oil. Present estimates place the quantity
of heavy
hydrocarbon reserves at several trillion barrels, more than 5 times the known
amount of
the conventional, i.e. non-heavy, hydrocarbon reserves. This is partly because
heavy
hydrocarbons are generally difficult to recover by conventional recovery
processes and
thus have not been exploited to the same extent as non-heavy hydrocarbons.
Heavy
hydrocarbons possess very high viscosities and low API (American Petroleum
Institute)
gravities which makes them difficult, if not impossible, to pump in their
native state.
A number of methods have been developed to extract and process heavy
hydrocarbon mixtures. The recovery of heavy hydrocarbons from subterranean
reservoirs is most commonly carried out by steam assisted gravity drainage
(SAGD) or
in situ combustion (ISO). In these methods the heavy hydrocarbon is heated and
thereby mobilised, by steam in the case of SAGD and by a combustion front in
the
case of ISO, to flow to a production well from where it can be pumped to the
surface
facilities. The transportability of the viscous heavy hydrocarbon mixture
recovered is
conventionally improved by dilution with a lighter hydrocarbon.
The thermal recovery processes currently used suffer from inherent drawbacks.
These include the consumption of vast amounts of energy, usually in the form
of
increasingly expensive natural gas, in the production of steam and the
concomitant
high CO2 emissions which occur. Of course it has already been recognised in
the
energy industry that CO2 emissions must be managed better.
Attempts were made in the sixties and seventies to reduce the amount of
energy that is required for thermal hydrocarbon recovery methods. US
3,258,069, for
example, discloses a method of discovering and using over-pressured water-
bearing
reservoirs containing aqueous liquids at pressures and/or temperatures that
yield
useful energy. The method involves completing a well into the identified
reservoir and
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recovering the liquid. The liquid may be used to perform different types of
work
including hydrocarbon recovery. In this case a tubing string is positioned in
the
formation to transport the superheated water from the over-pressured reservoir
to the
hydrocarbon-containing part of the formation. The heat of the water reduces
the
viscosity of the hydrocarbon and its pressure provides a drive force to
displace the
hydrocarbon from the formation.
In US 4,078,608 a slightly different strategy is employed whereby a formation
is
used to heat water that is introduced into it. US 4,078,608 discloses a method
of
recovering hydrocarbon wherein an aqueous fluid comprising water is injected
into a
second formation having a higher temperature than the first hydrocarbon-
containing
formation, recovering the heated aqueous fluid and then injecting the hot
water into the
first hydrocarbon-containing formation to displace viscous hydrocarbon toward
the
production well and thereby to the earth's surface. The second formation used
to carry
out the heating in US 4,078,608 is generally at a greater depth than the
formation from
which hydrocarbon is primarily extracted.
US 3,679,264 also discloses a similar approach. It describes the possibility
of
recovering hot liquids or gases from a deeper formation and transporting it to
a less
deep hydrocarbon containing formation to assist oil recovery therefrom as well
as the
possibility of injecting water into a deep, hot formation to generate hot
water for oil
recovery from another formation.
There is, however, a major drawback to all of these methods. They require at
least one additional well to be drilled into the formation and this well must
generally be
at a significant depth, generally much deeper than wells drilled for
hydrocarbon
recovery operations. The drilling of such wells is extremely expensive. As a
result, as
far as the Applicant is aware, this approach has not been utilised in any
commercial
SAGD operation.
Rather oil producers, in recent times, have instead looked for alternative and
cheaper sources of fuel to replace or supplement natural gas for steam
generation. It
has been suggested, for instance, that asphaltenes and/or coke recovered from
heavy
hydrocarbon may be combusted to generate steam.
A need, however, still exists for methods of generating thermal energy for
hydrocarbon recovery processes such as SAGD which are less demanding in terms
of
fuel consumption. Methods that additionally reduce the amount of CO2 emissions
would naturally be particularly beneficial given the commitments already made
by the
energy sector to achieve this.
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SUMMARY OF THE INVENTION
Viewed from a first aspect, the present invention provides a method of
recovering thermal energy from a subterranean formation depleted of
hydrocarbon
comprising:
i) selecting a formation that has been depleted of hydrocarbon by a thermal
recovery
method;
ii) injecting a fluid into said depleted hydrocarbon formation, wherein said
fluid has a
first temperature;
iii) allowing the formation to heat said fluid;
iv) recovering said fluid from said depleted hydrocarbon formation, wherein
said fluid
has a second temperature which is higher than said first temperature; and
v) recovering energy from said fluid having a second temperature.
Viewed from a further aspect, the present invention provides a method of
recovering hydrocarbon from a hydrocarbon containing subterranean formation
comprising:
(i) conducting a thermal recovery method in said formation to recover
hydrocarbon; and
(ii) recovering thermal energy from said formation by a method as hereinbefore
defined,
wherein further hydrocarbon production occurs during step (ii).
Viewed from a further aspect, the present invention provides a method of
recovering hydrocarbon from a hydrocarbon containing subterranean formation
comprising: conducting a steam based thermal recovery method in said formation
to
recover hydrocarbon, wherein at least some of the steam is generated by energy
recovered by the method as hereinbef ore defined.
Viewed from a further aspect, the present invention provides a method of
recovering hydrocarbon from a hydrocarbon containing subterranean formation
comprising:
(i) conducting a steam based thermal recovery method in said formation to
recover
hydrocarbon;
(ii) recovering thermal energy from a formation by a method as hereinbefore
defined;
(iii) generating steam from said recovered thermal energy; and
(iv) providing said steam to said steam based thermal recovery method.
4
Viewed from a further aspect, the present invention provides a system for
recovering thermal energy from a subterranean formation depleted of
hydrocarbon
comprising:
i) a means for injecting a fluid into a depleted hydrocarbon formation;
ii) a means for recovering said fluid from said formation; and
iii) a means for recovering energy from said fluid recovered from said
formation,
wherein said means for recovering energy is fluidly connected to said means
for
recovering fluid.
Viewed from a further aspect, the present invention provides an arrangement
for recovering hydrocarbon from a hydrocarbon containing subterranean
formation
comprising;
(i) an arrangement for conducting a thermal recovery method; and
(ii) a system for recovering thermal energy as hereinbefore defined.
Viewed from a further aspect, the present invention provides a method of
recovering thermal energy from a subterranean formation depleted of
hydrocarbon
comprising:
i) selecting a formation that has been depleted of hydrocarbon by a thermal
recovery method;
ii) injecting a fluid into said depleted hydrocarbon formation, wherein said
fluid
has a first temperature;
iii) allowing the formation to heat said fluid;
iv) recovering said fluid from said depleted hydrocarbon formation, wherein
said
fluid has a second temperature which is higher than said first temperature;
and
v) recovering energy from said fluid having a second temperature in a heat
pump,
wherein said heat pump comprises a first heat exchanger and a second heat
exchanger, and in said first heat exchanger said fluid having a second
temperature
heats a working fluid of the heat pump to generate heated working fluid and
cooled fluid
and in said second heat exchanger said heated working fluid heats feedwater to
generate steam and cooled working fluid.
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Viewed from a further aspect, the present invention provides a system for
recovering thermal energy from a subterranean formation depleted of
hydrocarbon
comprising:
i) a means for injecting a fluid into a depleted hydrocarbon formation;
ii) a means for recovering said fluid from said formation; and
iii) a means for recovering energy from said fluid recovered from said
formation,
wherein said means for recovering energy is a heat pump comprising:
(A) a first heat exchanger comprising:
(i) a first inlet for cooled working fluid;
(ii) a first outlet for heated working fluid;
(iii) a second inlet fluidly connected to said means for recovering fluid
from said formation; and
(iv) a second outlet for cooled fluid,
wherein said first inlet is fluidly connected to said first outlet and wherein
said
second inlet is fluidly connected to said second outlet; and
(B) a second heat exchanger comprising:
(v) a first inlet for feedwater;
(vi) a first outlet for steam;
(vii) a second inlet for heated working fluid fluidly connected to said first
outlet of said first heat exchanger; and
(viii) a second outlet for cooled working fluid fluidly connected to said
first inlet of said first heat exchanger,
wherein said first inlet is fluidly connected to said first outlet and wherein
said
second inlet is fluidly connected to said second outlet.
DETAILED DESCRIPTION OF THE INVENTION
To recover hydrocarbon, and particularly heavy hydrocarbon, from
subterranean formations, it is often necessary to employ thermal recovery
methods
such as Steam Assisted Gravity Drainage (SAGD) and In Situ Combustion (ISC).
Thermal recovery methods generally facilitate recovery of heavy hydrocarbon by
mobilising it by heating and in some cases by additionally reducing its
viscosity by
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dilution. These methods successfully facilitate the recovery of hydrocarbon
which
otherwise would remain in the formation.
There is, however, a significant energy cost associated with thermal recovery
methods. In SAGD the steam needed for injection into the formation is usually
generated using natural gas as the fuel. Since vast volumes of steam are
required in
an effective recovery operation that might last for 10-20 years this is a huge
cost.
Although an advantage of ISC is that the fuel for combustion is the in situ
hydrocarbon,
a steam treatment is usually required initially to heat the formation to a
temperature that
will sustain combustion.
The method of the present invention recovers thermal energy generated for
carrying out thermal recovery methods that is not recovered in the extracted
hydrocarbon. Typically this is the thermal energy that heats the formation,
i.e. the
energy that accumulates in the reservoir structure. The method of the present
invention comprises selecting a formation that has been depleted of
hydrocarbon by a
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thermal recovery method and injecting a fluid into the depleted hydrocarbon
formation.
The fluid has a first temperature at the point of injection into the
formation. The
method, however, further comprises allowing the formation to heat the fluid.
In other
words energy originally derived from, e.g. steam or in situ combustion and
stored in the
5 formation
is transferred from the heated formation into the fluid. Thus when the fluid
is
recovered from the depleted hydrocarbon formation the fluid has a second
temperature
which is higher than the first temperature. This temperature increase
represents the
energy that is recovered. As described below, the energy may be extracted from
the
fluid in a number of different ways. Preferably the energy is used in steam
generation.
The method of the present invention may be applied to any formation that has
been depleted of hydrocarbon by a thermal recovery method. Such methods are
characterised by the fact that the formation is itself heated by operation of
the recovery
method. In the method of the invention the formation has preferably been
depleted of
hydrocarbon by steam assisted gravity drainage (SAGD), cyclic steam
stimulation
(CSS), steam flooding, hot solvent injection or in situ combustion (ISC).
Particularly
preferably the formation has been depleted of hydrocarbon by steam assisted
gravity
drainage or in situ combustion, especially steam assisted gravity drainage.
These
methods heat the formation to a significant extent.
The fluid used in the present invention may be any fluid that is inert to the
formation. As used herein the term fluid encompasses liquids, vapours, gases
and
supercritical vapour. Preferably the fluid is a liquid. More preferably the
fluid is an
aqueous liquid, e.g. water. Particularly preferably the water comprises water
recovered
during a prior hydrocarbon recovery operation, e.g. water separated from
hydrocarbon
in a bulk separator. In a bulk separator a hydrocarbon and water mixture
recovered
from a formation is separated to yield separated hydrocarbon and separated
water.
The separated water predominantly comprises water but generally also contains
impurities such as hydrocarbon and dissolved organics and inorganics. The
separated
water is optionally cleaned prior to use in the method of the invention.
Conventional
cleaning methods may be used. An advantage of the method of the invention is
therefore that the water, can be recycled and hence the amount of fresh water
required
is minimised.
In the method of the present invention, heat is transferred from a depleted
formation to the fluid, e.g. water. The temperature of the formation should
therefore be
higher than the temperature of the injected fluid, e.g. under equivalent
pressure
conditions. Preferably the difference in temperature (e.g. at the same
pressure)
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between the formation and the first temperature of the fluid is 5 to 500 C,
more
preferably 10 to 200 C and still more preferably 15 to 150 C. Preferably the
temperature of the selected formation depleted of hydrocarbon into which the
fluid is
injected is 50 to 600 C, more preferably 60 to 300 C and still more
preferably 70 to
200 C, e.g. at formation pressure which typically is in the range 500 to 7000
kPa. The
formation obviously comprises a range of temperatures, e.g. at the cap rock,
in the
zone previously comprising hydrocarbon and in the underburden. The temperature
of
the formation referred to herein is the average temperature in the area of
formation that
previously comprised hydrocarbon and which is contacted by the fluid in the
method of
the invention.
In preferred methods of the invention the first temperature of the fluid, at
the
point of injection (e.g. at atmospheric pressure) is 10 to 150 C, more
preferably 30 to
120 C and still more preferably 50 to 100 C. The temperature of the fluid is
increased
in the method of the invention by contact with the hotter formation. After
injection into
the formation, the fluid permeates through the formation. Since the formation
has
previously been depleted by a thermal recovery method, the formation is
relatively
permeable. Thus the fluid travels through the pores and channels present in
the
formation and in so doing is in contact with the hot surface of the formation
where it
extracts heat therefrom.
In preferred methods of the invention the injected fluid moves through the
formation in a generally lateral or horizontal direction. Particularly
preferably the fluid is
injected via the injection well of a first SAGD well pair, moves through the
formation in
a horizontal direction to the production well of an adjacent SAGD well pair
from which
the heated fluid is recovered. The movement of the injected fluid from the
injection well
of a first SAGD well pair to the production well of an adjacent second SAGD
well pair is
referred to as cross flow.
In some methods of the present invention the fluid circulates through the
formation continuously. In other methods, the fluid is shut into the formation
for a
period of time.
After circulation through the formation, the fluid has a second temperature
that
is higher than its first temperature at the point of injection. Preferably the
difference
between the first and second temperatures of the fluid is 10 to 500 C, more
preferably
20 to 300 C and still more preferably 40 to 200 C, e.g. at atmospheric
pressure.
Preferably the fluid has a second temperature of 100 to 500 C, more
preferably 105 to
300 C and still more preferably 110 to 220 C, e.g. at atmospheric pressure.
The
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greater the temperature difference between the fluid returning from the
formation and
the fluid injected into the formation the greater the amount of energy that
has been
recovered from the formation.
In the method of the present invention, energy is recovered from the fluid
that is
circulated through the formation. The method of energy recovery depends on a
number of factors including the temperature of the fluid recovered. When the
fluid
returning from the formation has a temperature exceeding 170 C, e.g. at
atmospheric
pressure, the energy is preferably recovered in a heat exchanger. The heat
exchanger
may be, for example, an evaporator (e.g. an evaporator heating boiler feed
water).
Conventional commercially available evaporators may be used. In the heat
exchanger,
e.g. evaporator, the fluid having the second temperature heats feedwater to
generate
steam. Cooled fluid is simultaneously produced. Preferably the cooled fluid is
recycled
by injection into the hot depleted hydrocarbon formation. The fluid therefore
circulates
throughout the method in a loop. The fluid, at a first temperature, is
injected into the
formation and heated to a second temperature, then the fluid heats feedwater
(e.g. in a
heat exchanger) and in this process the fluid is cooled and then is reinjected
into the
formation.
When the fluid recovered from the formation has a temperature below boiler
feed water temperature, e.g. is between 50 and 200 C or 50 and 165 C, the
energy is
preferably recovered in a heat pump. Preferably the heat pump comprises a
first heat
exchanger. Preferably the heat pump further comprises a second heat exchanger.
Preferably one heat exchanger is an evaporator. Preferably the other heat
exchanger
is a condenser. Preferably the heat pump also comprises a working fluid that
circulates
between the two heat exchangers. Conventional heat pumps and working fluids
known
in the art may be used.
In a method of the invention employing a heat pump the fluid heated by the
depleted formation and having a second temperature preferably heats (e.g.
evaporates) a working fluid of the heat pump to generate heated working fluid
and
cooled fluid. Preferably the cooled fluid is recycled by injection into the
depleted
hydrocarbon formation. The heated working fluid is preferably compressed. In a
second heat exchanger the heated working fluid, preferably compressed heated
working fluid, preferably heats feedwater to generate steam and cooled working
fluid
(e.g. condensed working fluid). Preferably the cooled working fluid is
expanded. This
reduces its temperature so it can absorb further energy from further heated
fluid
recovered from the formation. Preferably the cooled working fluid is recycled
by
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transportation to the first heat exchanger where it is heated (e.g.
evaporated) by further
fluid recovered from the depleted formation and having a second temperature.
In the methods of the present invention the steam produced in the heat
exchanger, e.g. evaporator, is preferably pressurised. Conventional equipment
may be
used to carry out pressurisation. The pressure of the steam is preferably
increased to
the level required for injection into a hydrocarbon containing subterranean
formation to
produce hydrocarbon during a recovery operation from a depleted reservoir.
Preferably the steam is injected into a hydrocarbon containing formation to
recover
hydrocarbon.
The method of the present invention is particularly useful when the depleted
formation has been depleted of hydrocarbon by SAGD. In SAGD two horizontal
wells,
typically referred to as an injection well and a production well, are drilled
into the
reservoir, vertically separated by, e.g. 5-10 meters. This group of two wells
is typically
referred to as a well pair or a SAGD well pair. During hydrocarbon recovery
steam is
injected into the upper injection well, flows outward, contacts the
hydrocarbon above it,
condenses and transfers its latent heat to the hydrocarbon and the formation.
This
heating reduces the viscosity of the hydrocarbon, its mobility increases and
it flows due
to gravity to the lower production well from where it can be produced.
The method of the present invention is therefore especially useful when the
depleted formation comprises at least one SAGD well pair and more preferably
at least
two SAGD well pairs, e.g. a plurality of SAGD well pairs. The fluid may be
injected into
the formation in a number of different ways.
The fluid may, for example, be injected into the depleted formation through
the
injection well of a first SAGD well pair. Optionally the heated fluid is
recovered from the
production well of the SAGD well pair. This method and arrangement is
described as
cyclical since the fluid cycles through the injection and production wells of
a single
SAGD well pair. This method has the significant advantage that no new wells
need to
be drilled into the formation which is economically highly beneficial.
More preferably, however, the heated fluid is recovered from the formation via
the production well of a second adjacent SAGD well pair. Thus the fluid is
injected into
the formation via the injection well of a first SAGD well pair, the fluid
permeates through
the formation in a generally lateral or horizontal direction and the heated
fluid is
recovered via the production well of an adjacent second SAGD well pair. This
method
and system is described as cross flow since the fluid enters and leaves the
formation
via different SAGD well pairs. This method also has the significant advantage
that no
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new wells need to be drilled into the formation which is economically highly
beneficial.
It also has the further advantage that the distance between the incoming
colder fluid
and the outgoing hotter fluid is greater than in the above method and system.
This is
beneficial in the method of the invention
Alternatively the fluid may be injected into the depleted formation through a
vertical well located at the toe of the SAGD well pair. Such a vertical well
will not
typically be present during a SAGD operation and is preferably drilled into
the formation
once SAGD is completed or at least nearly completed. Preferably the vertical
well is
positioned so that it overlies the toe of the SAGD well pair. Particularly
preferably the
vertical well is positioned so that its end is above the height of the
horizontal section of
the injection well of the SAGD well pair. Preferably the vertical well is
located at the top
of the depleted reservoir. The fluid injected into the formation through the
vertical well
permeates through the formation towards the vertical section of the SAGD
production
well. The distance between the incoming colder fluid and the outgoing hotter
fluid is
significant and this is beneficial in the method of the invention.
Alternatively the fluid may be injected into the depleted formation through at
least one vertical well located near the top of the formation. Such vertical
wells will not
typically be present during a SAGD operation and are preferably drilled into
the
formation once SAGD is completed or at least nearly completed. Preferably a
plurality
of vertical injection wells is used. Preferably the vertical injection wells
are relatively
short and terminate in the upper part of the production zone of the depleted
formation.
Preferably the vertical wells are aligned with, and positioned above, the
horizontal
section of the injection well of the SAGD well pair. Preferably the end of
each of the
vertical injection wells is above the height of the injection well of the SAGD
well pair.
The advantage of this method is that the fluid travels through a significant
portion of the
depleted, hot formation. On the other hand, the drilling of a plurality of new
vertical
injection wells is expensive.
In a further alternative method the fluid is optionally injected into the
depleted
formation through a well present in a formation adjacent to, and in fluid
communication
with, the depleted formation. The well may be, for example, a vertical well or
a well in a
SAGD well pair, e.g. an injection well of a SAGD well pair.
In the methods of the present invention steam and/or light hydrocarbons are
optionally recovered through vent wells, e.g. vertical vent wells. Hydrocarbon
is
optionally recovered via SAGD production wells.
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The method of the present invention is also particularly useful when the
depleted formation has been depleted of hydrocarbon by ISO. In ISC at least
one, e.g.
a row, of vertical injection wells are drilled into the reservoir. Preferably
a row of
vertical vent wells, laterally spaced from the injection wells so that the
rows of injection
5 wells and
rows of vent wells are parallel, is also drilled into the reservoir. A
production
well is also drilled in the reservoir and is preferably aligned with, and
positioned below,
the row of injection wells. The production well is preferably located in a
lower region of
the hydrocarbon-bearing formation.
Thus in a preferred method of the present invention the depleted formation
10 comprises
an injection well, preferably a row of injection wells, and a production well,
preferably a horizontal well underlying the injection wells. Preferably the
fluid (i.e. the
fluid for extracting thermal energy) is injected into the formation through at
least one
injection well. Preferably the fluid is recovered through the production well.
The method of the present invention may be conducted on a formation which
1 5 has been
completely depleted of recoverable hydrocarbon by thermal recovery
methods. In other methods of the invention the formation is only partially
depleted of
recoverable hydrocarbon. In the methods of the invention, further hydrocarbon
recovery preferably occurs.
Further hydrocarbon is preferably recovered via
productions wells.
The method of the invention may, for example, be started during the wind down
stage of production. Advantageously hydrocarbon production occurs during the
method of the invention. This is particularly beneficial since it is during
this stage that
hydrocarbon recovery is least economical. The method of the invention,
however, can
make it worthwhile continuing the recovery operation for a much longer period
of time.
If hydrocarbon is recovered it is preferably separated from the fluid
recovered from the
formation, e.g. in a separator, prior to entry of the fluid into a heat
exchanger.
The method of the present invention may also be advantageously combined
with a steam-based method of recovering hydrocarbon, particularly heavy
hydrocarbon
mixtures, from a hydrocarbon containing subterranean formation. A heavy
hydrocarbon mixture comprises a greater proportion of hydrocarbons having a
higher
molecular weight than a relatively lighter hydrocarbon mixture. Terms such as
"light",
"lighter", "heavier" etc. are to be interpreted herein relative to "heavy".
Typical heavy
hydrocarbon mixtures have an API gravity of less than about 20 , preferably
less than
about 15 , more preferably less than 12 , still more preferably less than 10 ,
e.g. less
than 8 . It is particularly preferred if the API gravity of the heavy
hydrocarbon mixture
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recovered by the method of the present invention is from about 50 to about 15
, more
preferably from about 6 to about 12 , still more preferably about 7 to about
12 , e.g.
about 7.5-9 .
In such methods the energy recovered in the above-described method of the
invention is used to generate steam which, in turn, is used in the method of
recovering
hydrocarbon. More
preferably the method of recovering hydrocarbon from a
hydrocarbon containing subterranean formation comprises:
(i) conducting a steam based thermal recovery method in the formation to
recover
hydrocarbon;
(ii) recovering thermal energy from a depleted formation by a method as
hereinbef ore
defined;
(iii) generating steam from the recovered thermal energy; and
(iv) providing the steam to the steam based thermal recovery method.
In the above method, the steam based recovery method is preferably
conducted on a different formation to the formation used in the recovery of
thermal
energy. The recovery of thermal energy by the method of the invention has the
significant advantage that the amount of steam that needs to be generated from
a fuel
such as natural gas is greatly reduced. This in turn means that the cost of
generating
steam and the amount of CO2 emissions associated with this process are
reduced.
Preferably the steam based thermal recovery method is SAGD. SAGD is
preferably carried out using conventional equipment and under conventional
conditions. Thus preferably the steam is injected into a hydrocarbon
containing
formation via an injection well of a SAGD well pair. Preferably mobilised
hydrocarbon
mixture is recovered by pumping it from a production well of a SAGD well pair.
The present invention also relates to a system for recovering thermal energy
from a subterranean formation. The system comprises:
i) a means for injecting a fluid into a depleted hydrocarbon formation;
ii) a means for recovering the fluid from the formation; and
iii) a means for recovering energy from the fluid recovered from the
formation.
The fluid may be described as a heat extracting fluid since it removes heat
from
the formation and brings it to the surface where it may be recovered.
The means for recovering energy from the fluid is fluidly connected to the
means for recovering the fluid. Since the depleted formation is permeable and
permits
the flow of fluid therethrough, the means for injecting a fluid is in fluid
communication
with the means for recovering the fluid from the formation.
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Preferably the depleted hydrocarbon formation comprises at least one SAGD
well pair and still more preferably at least two SAGD well pairs. Preferably
the means
for injecting fluid is selected from a vertical well located at the toe of the
SAGD well
pair, the injection well of the SAGD well pair, at least one vertical well
located near the
top of the formation and a well present in a formation adjacent to, and in
fluid
communication with, said depleted hydrocarbon formation. More preferably the
means
for injecting fluid is selected from a vertical well located at the toe of the
SAGD well pair
and the injection well of the SAGD well pair. Still more preferably the means
for
injecting fluid is the injection well of the SAGD well pair.
Preferably the means for recovering the fluid from the formation is the
producer
well of the SAGD well pair. Still more preferably the means for recovering the
fluid
from the formation is the producer well of an adjacent second SAGD well pair.
Preferably the means for injecting fluid having a first temperature is the
injection
well of a first SAGD well pair and the means for recovering the fluid having a
second
temperature is the production well of a second adjacenet SAGD well pair.
In another preferred system the depleted hydrocarbon formation comprises a
well arrangement for in situ combustion. Preferably the means for injecting
fluid is the
injection well, e.g. vertical injection well, of the ISO well arrangement.
Preferably the
means for recovering the fluid is the production well of the ISO well
arrangement.
Preferably the production well comprises a horizontal section that underlies
the vertical
injection well.
In the system of the present invention the means for recovering energy is
preferably a heat exchanger and still more preferably an evaporator. Suitable
evaporators are commercially available.
Preferably the heat exchanger, e.g.
evaporator, comprises:
(i) a first inlet for feedwater, preferably fluidly connected to a separator;
(ii) a first outlet for steam;
(iii) a second inlet fluidly connected to the means for recovering fluid from
the
formation; and
(iv) a second outlet for cooled fluid;
wherein the first inlet is fluidly connected to the first outlet and wherein
the second inlet
is fluidly connected to the second outlet.
When heated fluid is recovered from the formation it is transported into the
heat
exchanger via the second inlet wherein it heats the feedwater also entering
the heat
exchanger via the first inlet. In this process the feedwater is converted to
steam and
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the fluid is cooled, i.e. heat transfer occurs between the two media. The
second outlet
for cooled fluid is preferably fluidly connected to the means for injecting a
fluid into a
depleted hydrocarbon subterranean formation, i.e. the cooled fluid is
preferably
recycled by reinjection into the depleted formation for reheating. Preferably
the first
outlet for steam is fluidly connected to a steam compressor. Preferably the
first outlet
for steam is fluidly connected to a well arrangement in a hydrocarbon
containing
subterranean formation.
In a further preferred system of the present invention the means for
recovering
energy comprises a heat pump. Preferably the heat pump comprises at least a
first
and second heat exchanger, e.g. an evaporator and a condenser. Further heat
exchangers may optionally be present. Preferably the heat pump further
comprises a
working fluid. Suitable heat pumps are commercially available.
Preferably the heat pump comprises:
(A) a first heat exchanger comprising:
(i) a first inlet for cooled working fluid;
(ii) a first outlet for heated working fluid;
(iii) a second inlet fluidly connected to the means for recovering fluid from
the
formation; and
(iv) a second outlet for cooled fluid;
wherein said first inlet is fluidly connected to the first outlet and wherein
the
second inlet is fluidly connected to the second outlet; and
(B) a second heat exchanger comprising:
(v) a first inlet for feedwater;
(vi) a first outlet for steam;
(vii) a second inlet for heated working fluid fluidly connected to the first
outlet of
the first heat exchanger; and
(viii) a second outlet for cooled working fluid fluidly connected to the first
inlet of
the first heat exchanger;
wherein the first inlet is fluidly connected to the first outlet and wherein
the
second inlet is fluidly connected to the second outlet.
When the heated fluid is recovered from the formation, it is transported into
the
first heat exchanger via the second inlet wherein it heats the working fluid
of the heat
pump also entering the first heat exchanger via the first inlet. In this
process the
working fluid is heated and the fluid deriving from the formation is cooled,
i.e. heat
transfer occurs between the two media. The cooled fluid is preferably fluidly
connected
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to the means for injecting a fluid into a depleted hydrocarbon subterranean
formation,
i.e. the cooled fluid is preferably recycled by reinjection into the depleted
formation for
reheating. The heated working fluid is preferably transported to a second heat
exchanger wherein it heats feedwater also entering the second heat exchanger
via the
first inlet. Preferably the first inlet for feedwater in the second heat
exchanger is fluidly
connected to a separator. In the second heat exchanger the feedwater is
converted to
steam and the heated working fluid is cooled, i.e. heat transfer occurs
between the two
media. The cooled working fluid is preferably transported to the first inlet
for cooled
working fluid in the first heat exchanger wherein it is reheated with fluid
recovered from
the depleted formation. Preferably the first outlet for steam is fluidly
connected to a
steam compressor. Preferably the first outlet for steam is fluidly connected
to a well
arrangement in a hydrocarbon containing subterranean formation.
A preferred system of the present invention further comprises an expansion
valve in between the second outlet for cooled working fluid of the second heat
exchanger and the inlet for cooled working fluid of the first heat exchanger.
A further
preferred system comprises a compressor in between the first outlet for heated
working
fluid of the first heat exchanger and the second inlet for heated working
fluid of the
second heat exchanger. This enables the temperature of the working fluid to be
heated by the fluid contacting the depleted formation to be controlled.
Further
preferred systems of the invention optionally comprise one or more further
expansion
valves and/or compressors that are required to regulate the temperature and
pressure
of the system. Optionally temperature and/or pressure monitors are included in
the
system.
The present invention further relates to an arrangement for recovering
hydrocarbon from a hydrocarbon containing subterranean formation comprising;
(i) an arrangement for conducting a thermal recovery method; and
(ii) a system for recovering thermal energy as hereinbefore defined.
Further preferred arrangements further comprise a means for transporting the
steam generated using the thermal energy recovered in the system into another
well
arrangement present in a hydrocarbon-containing formation. Such means
typically
comprises piping, optionally insulated piping.
Preferred arrangements comprise SAGD and ISC well arrangements.
Yet further preferred arrangements further comprise at least one Once Through
Steam Generator (OTSG). In such arrangements the steam generated in the
thermal
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recovery method of the present invention is combined with steam generated in
the
OTSG prior to injection into a hydrocarbon containing subterranean formation.
DESCRIPTION OF THE DRAWINGS
5 Figure 1 shows a schematic of a typical SAGD recovery operation and
the heat
losses that occur therein;
Figure 2(a) shows a schematic of a method and system of the present invention
wherein the hydrocarbon formation has been depleted by a prior SAGD operation;
Figure 2(b) shows a schematic of a method and system of the present invention
10 wherein the hydrocarbon formation has been depleted by a prior SAGD
operation;
Figure 2(c) shows a schematic of a formation comprising a plurality of SAGD
wells operating in a cross flow arrangment;
Figure 2(d) shows a schematic of a method and system of the present invention
wherein the hydrocarbon formation has been depleted by a prior SAGD operation
and
15 a further additional vertical well has been drilled into the formation
at the toe of the
SAGD well pair for injection of fluid;
Figure 2(e) shows a schematic of a method and system of the present invention
wherein the hydrocarbon formation has been depleted by a prior SAGD operation
and
a number of additional vertical wells have been drilled into the formation
having ends
located near the top of the formation;
Figure 2(f) shows a schematic of a method and system of the present invention
wherein the hydrocarbon formation has been depleted by a prior ISC operation;
Figure 3 shows a schematic of a system of the present invention for recovering
thermal energy from a subterranean formation; and
Figure 4 shows a schematic of a system of the present invention for recovering
thermal energy from a subterranean formation.
DETAILED DESCRIPTION OF THE DRAWINGS
Figure 1 shows a schematic of a typical SAGD recovery operation. Thus steam
is generated in a Once Through Steam Generator (OTSG) using natural gas as the
fuel. The steam is injected into a formation through an injection well and
hydrocarbon
is recovered, along with water, through a production well. The most
significant energy
consumption occurs during the generation of steam. Some of the energy in the
steam
is returned in the sense that the steam transfers its heat to heavy
hydrocarbon that is
then produced at the surface. A larger proportion of the energy in the steam
is,
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however, lost. Heat losses occur at the surface in the OTSGs and in the
processing
facilities (e.g. separator) and flow lines. The vast majority of heat losses,
however,
occur subsurface. The most significant subsurface heat losses are heat that is
stored
in the reservoir (sometimes referred to as accumulated heat) and heat lost to
the cap
rock, overburden and area of formation below the hydrocarbon containing
formation. In
some cases heat is also lost to thief zones.
Figure 2(a) shows a schematic of a method and system of the present invention
wherein the hydrocarbon formation has been depleted by a prior SAGD operation.
Thus the method and system comprise a subterranean formation 1 that has
previously
been depleted of hydrocarbon by a SAGD operation. The formation 1 therefore
comprises a SAGD well pair comprising an injection well 2 and a producer well
3. The
formation also comprises vent wells 9 for recovery of steam and/or light
hydrocarbons.
Water, which is transported from a bulk separator 4 receiving hydrocarbon and
water from a hydrocarbon recovery operation, is injected into the formation
through the
injection well 2 where it is then heated by the depleted formation. The
temperature of
the formation is typically 50-600 C whereas the temperature of the fluid is
typically 5-
200 C, thus the formation heats the water. The permeability of the formation
is
relatively high as hydrocarbon recovery has already occurred therefrom. The
water
can therefore flow through the formation to the production well 3 underlying
the
injection well 2. The water is recovered from the depleted hydrocarbon
formation
through the producer well 3 and transported to an evaporator 5. The evaporator
5 is
located above the earth's surface. In the evaporator the hot water heats
feedwater
received from separator 4 to generate steam which exits the evaporator and
passes to
steam compressor 6 where it is pressurised. The steam is then combined with
steam
from an OSTG 8 and injected into a hydrocarbon containing formation 7 to
recover
hydrocarbon. The heating of the feedwater cools the water returned from the
formation
and the cooled water is recycled through line 10 into the injection well of
the SAGD well
pair and therefrom into the depleted hydrocarbon formation where it is then
reheated
by the formation.
Figure 2(b) shows a schematic of a preferred method and system of the present
invention. Again the hydrocarbon formation has been depleted by a prior SAGD
operation. Those features of Figure 2(b) that are shared with Figure 2(a) have
been
given the same reference numbers. The difference between Figures 2(a) and (b)
is in
the well arrangement used to inject and recover the water. In Figure 2(b) the
water is
injected into the formation through an injection well 2 of a first SAGD well
pair 2, 3.
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The water pemeates through the formation in a generally lateral or horizontal
direction
(as shown by the dashed lines) and is heated by contact with the formation.
The
heated water is recovered from the formation via a production well 10 of an
adjacent
second SAGD well pair 10, 11. This method and system is sometimes referred to
as
cross flow since the water is injected into the formation via a first SAGD
well pair and
recovered from the formation via a second adjacent SAGD well pair. In a
particularly
preferred method and system of the present invention a plurality of SAGD well
pairs
operate in cross flow. A preferred cross flow system is shown diagrammatically
in
Figure 2(c). In Figure 2(c) the dark circles represent SAGD well pair
injection wells that
are used for injection of fluid and the open circles with a dark perimeter
represent
SAGD well pair production wells that the heated fluid is recovered from.
Figure 2(d) shows a schematic of an alternative method and system of the
present invention. Again the hydrocarbon formation has been depleted by a
prior
SAGD operation. Those features of Figure 2(d) that are shared with Figure 2(a)
have
been given the same reference numbers. The difference between Figures 2(a) and
(d)
is in the well arrangement used to inject and recover the water. In Figure
2(d) the
water is injected into the formation through a new vertical well 2' located at
the toe of
the SAGD well pair. Again the water can flow through the permeable formation
to the
production well 3 from where the water is recovered. Typically the injection
well of the
SAGD well pair is closed. Alternatively it may additionally be used to recover
heated
water, e.g. by installing a pump therein.
Figure 2(e) shows a schematic of an alternative method and system of the
present invention wherein again the hydrocarbon formation has been depleted by
a
prior SAGD operation. As above those features of Figure 2(e) that are shared
with
Figures 2(a) have been given the same reference numbers. The difference
between
Figures 2(a) and 2(e) is in the well arrangement used to inject and recover
the water.
In Figure 2(e) the water is injected into the formation through a plurality of
vertical wells
2" located at the top of the formation. The water flows through the permeable
formation, and due to the effect of gravity, will flow to producer well 3 from
where the
water is recovered. The water injected into the formation in this arrangement
typically
is in contact with the formation for a longer period of time than in the
arrangements in
Figures 2(a) and 2(d) due to the greater distance between the vertical
injection wells at
the top of the formation and the underlying producer well. A draw back of this
arrangement, however, is that a number of new wells need to be drilled into
the
formation which is an expensive operation.
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Figure 2(f) shows a schematic of an alternative method and system of the
present invention wherein the hydrocarbon formation has been depleted by a
prior ISC
operation. As above, those features of Figure 2(f) that are shared with Figure
2(a)
have been given the same reference numbers. The difference between Figures
2(a)-
(e) and Figure 2(f) is in the well arrangement present in the formation. In
Figure 2(f)
vertical well 11 is used to inject water and the L-shaped producer well 12 is
used to
recover the water. In other ISC arrangements the producer well is vertical.
The
temperature of the formation following an ISC operation is typically much
higher than
after a SAGD operation so typically more thermal energy may be recovered
therefrom.
Figure 3 shows a schematic of a system of the present invention for recovering
thermal energy from a subterranean formation. The energy recovered is used to
generate steam. The system comprises a heat exchanger, specifically an
evaporator
51 in which the heated water recovered from the formation heats feedwater to
generate
steam and cooled water. The cooled water is recycled by injection into the
hydrocarbon depleted formation.
More specifically the system comprises a first inlet for feedwater 52, a first
outlet for steam 53, a second inlet 54 fluidly connected to the means for
recovering
water from the formation and a second outlet for cooled water 55. The first
inlet 52 is
fluidly connected to the first outlet 53 and the second inlet 54 is fluidly
connected to the
second outlet 55. The first inlet 52 for feedwater is fluidly connected to a
separator
(shown in Figures 2) which receives produced water from a hydrocarbon recovery
operation. The first outlet 53 for steam is fluidly connected to a steam
compressor
(shown in Figures 2) which increases the steam pressure to a level appropriate
for
injection into a hydrocarbon containing formation during a hydrocarbon
recovery
operation. Thus the first outlet 53 for steam is fluidly connected, either
directly or
indirectly, to a well arrangement in a hydrocarbon containing subterranean
formation
(shown in Figures 2). The second outlet 55 for cooled water is fluidly
connected to the
means for injecting a fluid into a depleted hydrocarbon subterranean
formation.
Figure 4 shows a schematic of a further system of the present invention for
recovering thermal energy from a subterranean formation. Again the energy
recovered
is used to generate steam. The system is a heat pump 100. The heat pump 100
comprises as a first heat exchanger an evaporator 101 in which the heated
water
recovered from the formation heats a working fluid of the heat pump to
generate
heated working fluid and cooled water. The cooled water is recycled by
injection into
the depleted hydrocarbon formation wherein it is heated again. The heated
working
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fluid is compressed in compressor 102 and is transported to a second heat
exchanger
which is condenser 103. In condenser 103 the heated working fluid heats
feedwater to
generate steam and cooled working fluid. The cooled working fluid is recycled
by
transportation to the first heat exchanger of the heat pump where it is heated
by the
water recovered from the formation.
More specifically the heat pump 100 comprises a first heat exchanger 101
comprising a first inlet 104 for cooled working fluid, a first outlet 105 for
heated working
fluid, a second inlet 106 fluidly connected to the means for recovering water
from the
formation and a second outlet 107 for cooled water that is fluidly connected
to the
means for injecting water into the depleted formation. The first inlet 104 is
fluidly
connected to the first outlet 105. The second inlet 106 is fluidly connected
to the
second outlet 107. The heat pump also comprises a second heat exchanger 103
comprising a first inlet 108 for feedwater, a first outlet 109 for steam, a
second inlet 110
for heated working fluid, fluidly connected to the first outlet 105 of the
first heat
exchanger, and a second outlet 111 for cooled working fluid, fluidly connected
to the
first inlet 104 of the first heat exchanger. The first inlet 108 is fluidly
connected to the
first outlet 109 and the second inlet 110 is fluidly connected to the second
outlet 111.
The first inlet 108 for feedwater in the second heat exchanger 103 is fluidly
connected
to a separator. The first outlet 109 for steam in the second heat exchanger
103 is
fluidly connected to a steam compressor. The second outlet 107 for cooled
water is
fluidly connected to the means for injecting the water into a depleted
hydrocarbon
formation
The heat pump further comprises an expansion valve 112 in between the
second outlet 111 for cooled working fluid of the second heat exchanger 103
and the
inlet 104 for cooled working fluid of the first heat exchanger. The heat pump
further
comprises a compressor 102 in between the first outlet 105 for heated working
fluid of
the first heat exchanger 101 and the second inlet 110 for heated working fluid
of the
second heat exchanger 103.
