Note: Descriptions are shown in the official language in which they were submitted.
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FLUE GAS INJECTION FOR HEAVY OIL RECOVERY
The present invention relates to the thermal recovery of values from a
subterranean formation by making use of a flue gas injection into the
formation.
In the heavy oil industry, there are a broad range of classifications
attributable to
the oil. The classes are essentially based on viscosity and density of the
material and are
generally broken down as follows:
i) Medium Heavy
25°> °API > 18°
100 cPs >p> 10 cPs, mobile at reservoir conditions
ii) Extra Heavy Oil
20°> °API > 12°
10,000 cPs >p,> 100 cPs, production enhancement techniques required
including reservoir stimulation such as thermal or water/solvent flooding
iii) Oil Sands and Bitumen
12°> °API > 6°, mined or thermal stimulation required
p> 10,000 cPs , production enhancement techniques required including
reservoir stimulation such as thermal or thermal/solvent injection.
In view of the recognized value of vast reserves of heavy oil and bitumen
potentially available in Canada, Central America, Russia, China and other
locations of
2 0 the world, a varied panoply of extraction and handling techniques have
come to light.
Currently, existing bitumen and extra heavy oil reservoirs are exploited using
enhanced thermal recovery techniques resulting in efficiency of recovery in
the range of
between 20 and 25%. The most common thermal technique is steam injection where
heat enthalpy from the steam is transferred to the oil by condensation. This,
of course,
2 5 reduces the viscosity of the oil allowing gravity drainage and collection.
Injection may
be achieved by the well known cyclic steam simulation (CSS), Huff and Puff and
Steam
Assisted Gravity Drainage (SAGD).
Although SAGD is becoming widely employed, it is not without several
detriments regarding efficiency. An area which presents significant costs is
the fuel to
3 0 drive the steam generators to produce steam for injection. The most
desirable fuel is
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natural gas, but the expense greatly reduces the overall efficiency and this
problem is
compounded with the fact that green house gases (GHG) are liberated in varied
amounts
during operation of the steam generators using all types of hydrocarbon fuels.
As an
example, approximately 8,000 to 15,000 Tonnes daily of carbon dioxide is
generated to
produce injection steam and produce 100,000 BOPD of bitumen.
A further problem in the SAGD process is the upgrading required in the
produced product to increase its value.
As noted briefly above, another factor affecting SAGD is the limitation in
recovery efficiency.
In an attempt to ameliorate some of the limitations noted, the use of
alternate
fuels other than natural gas has been proposed to at least reduce the ever
increasingly
impact of natural gas. An example of a suitable fuel for use in a SAGD
operation is
discussed in United States Patent No.6,530,965, issued to Warchol, March
11,2003.
The document teaches the formation of predispersed residuum in an aqueous
matrix
which is burnable as a alternate fuel.
Considering the problems with existing technologies, it remains desirable to
have a method of enhancing efficiency in a SAGD operation, reducing the
formation of
excessive amounts of GHG and lowering costs by providing an alternate fuel
with the
thermal performance of natural gas.
2 0 The present invention collates all of the most desirable features and
advantages
noted with an energy efficient, high yield green environmentally friendly
process.
One aspect of the present invention is to provide an improved thermal recovery
process with enhanced efficiency.
A further aspect of one embodiment is to provide a method for recovering heavy
2 5 oil and bitumen from a subterranean formation containing heavy oil and
bitumen,
comprising: providing a fuel; burning the fuel in a flue gas recirculation
circuit to
produce an injection flue gas for injection into the formation; and injecting
the injection
flue gas into the formation to displace the heavy oil and bitumen.
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A still further aspect of one embodiment of the present invention is to
provide a
method for recovering heavy oil and bitumen from a subterranean formation
containing
heavy oil and bitumen, comprising: providing a fuel; burning the fuel in a
flue gas
recirculation circuit to produce a flue gas for injection into the formation;
and injecting
the flue gas into the formation to displace the heavy oil and bitumen and
natural gas.
Still another aspect of one embodiment of the present invention is to provide
a
method for recovering gas and bitumen from at least one of a steam assisted
gravity
drainage formation containing gas over bitumen within the volume of the
formation
and/or from a geographically proximate formation, comprising; providing a flue
gas
recirculation circuit to produce modified flue gas; injecting the modified
flue gas
within the volume at a pressure sufficient to displace the gas over the
bitumen and to
displace the bitumen from within the formation; recovering displaced gas and
bitumen;
and maintaining the pressure or repressurizing the volume with the modified
flue gas to
a pressure substantially similar to a pressure prior to injection of the
modified flue gas.
Yet another aspect of one embodiment of the present invention is to provide a
method for recovering gas and bitumen from at least one of a steam assisted
gravity
drainage formation containing gas over bitumen within the volume of the
formation and
from a geographically proximate formation, comprising; a steam generation
phase for
generating steam for injection into the formation; a flue gas recirculation
phase for
2 0 modifying flue gas for injection into the formation; an injection phase
for injecting
modified flue gas into the formation for displacing gas over the bitumen and
maintaining the pressure or repressurizing the formation; and a processing
phase for
processing produced displaced gas and liquid liberated from the injection
phase.
Further features and advantages of the present invention will become apparent
2 5 from the following detailed description, taken in combination with the
appended
drawings.
Having thus generally described the invention, reference will now be made to
the accompanying drawings illustrating preferred embodiments and in which:
Figure 1 is a schematic illustration of the generic methodology according to
one
3 0 embodiment;
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Figure 2 is a more detailed schematic illustration of Figure 1;
Figure 3 is a graphical illustration of the oxygen requirement for flue gas
carbon
dioxide enrichment on a dry basis;
Figure 4 is a graphical illustration of the oxygen requirement for flue gas
carbon
dioxide enrichment on a wet basis;
Figure 5 is a schematic illustration of natural gas steam production in a SAGD
environment;
Figure 6 is a schematic illustration of bitumen or emulsion fuel steam
production
in a SAGD environment;
Figure 7 is a schematic illustration of residuum emulsion fuel steam
production
in a SAGD environment;
Figure 8 is a schematic illustration of a cogeneration flue gas compression
operation; and
Figure 9 is a schematic illustration of a cogeneration electric power
generation
operation.
Similar numerals employed in the description denote similar elements
It will be noted that throughout the appended drawings, like features are
identified by like reference numerals.
PREFACE
Unless otherwise indicated, SAGD refers to steam assisted gravity drainage,
SYNGAS, refers to synthetic gas, OTSG refers to once through steam generation,
GHG
refers to green house gas, BOPD refers to barrels of oil per day, COGEN refers
to
combined production of electric generation or compression service with heat
recovery
2 5 and steam generation, HRSG refers to heat recovery steam generator, and
"heavy oil"
embraces heavy oil, extra heavy oil and bitumen as understood in the art.
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Referring now to Figure 1, shown is a schematic illustration of one embodiment
of the present invention. Numeral 10 broadly denotes the overall process. An
air, fuel and
oxygen mixture combined with a Flue Gas Recirculation (FGR) stream is fed to a
steam
generation system 12 to generate steam 16 and flue gas 35. The air, fuel,
oxygen and
FGR mixture is selected to create an enriched flue gas 35 to optimize recovery
of gas and
heavy oil from within a formation containing these. This will be discussed in
greater
detail herein after.
The fuel 20, contained in any of air or oxygen mixture, may be selected from
any
suitable hydrocarbon fuel, non limiting examples of which include natural gas,
bitumen,
l0 fuel oil, heavy oil, residuum, emulsified fuel, multiphase superfine
atomized residue
(MSAR, a trademark of Quadrise Canada Fuel Systems), asphaltenes, petcoke,
coal, and
combinations thereof.
Flue gas 35 from the system 12 is treated or modified in a treatment operation
14
prior to injection within a formation. By products generated from treatment
unit 14 may
optionally be recovered. This flue gas may contain numerous gaseous compounds
including carbon dioxide, carbon monoxide, nitrogen, nitrogen oxides,
hydrogen, sulfur
dioxide, syngas inter alia. At excess oxygen burning conditions, where oxygen
levels are
present in the flue gas 35, the flue gas 35 will primarily contain carbon
dioxide, nitrogen
and water vapour. The treated injection gas 45 is injected into gas and heavy
oil
2 o formations) generically denoted by numeral 18, shown in the example as a
SAGD
(steam assisted gravity drainage) formation. As is well known, this technique
involves
the use of steam to assist in reducing the viscosity of viscous hydrocarbons
to facilitate
mobility. These formations also contain natural gas, bitumen and a variety of
other
hydrocarbons which have value, but which were previously marginally economic
or
2 5 fiscally unfeasible to recover. Steam 16 from system 12 is introduced into
the formation
18 as illustrated.
The gas in the formation 18 is now made recoverable in an efficient manner in
view of the flue gas circuit in combination with injection of the modified
flue gas 45. The
union of these operations has resulted in the success of the methodology of
the present
3 0 invention. Advantageously, the techniques set forth herein can be applied
not only to gas
over bitumen formations, but also geographically proximate formations
containing gas,
bitumen or a combination thereof. As a non limiting example, laterally or
vertically
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displaced formations can be exploited as well. This is generally shown in
Figure 1 and
denoted by numeral 18'. Modified flue gas may be injected into 18' at 45'. The
benefits
of the instant technology also accrue for abandoned SAGD chambers or for
blowdown
where flue gas can be injected to not only maintain heavy oil recovery, but
also to
displace the heavy oil.
Natural gas 25 displaced from formation 18 is collected and may be subjected
to
additional unit operations or a portion may be recirculated into the system as
fuel for
steam generation. This latter step is not shown in Figure 1, but is well
within the purview
of one skilled.
Mobilized production fluids, containing bitumen denoted by numeral 22 are then
subjected to an oil treatment operation 24 where the bitumen 26 is processed
for the
removal of entrained water to produce a saleable product. Produced water 26 is
further
treated in a suitable water treatment unit 28 to remove bitumen, hardness
compounds,
silica and any other undesirable compounds making the water suitable of boiler
feed
water 30. Any suitable water treatment operations may be employed to achieve
the
desired result. Boiler feed water 30 may then be recirculated into system 12
for steam 16
production, thus reducing water demands in the process to augment efficiency.
Further to
this, water evolved from the flue gas treatment operation, the water being
represented by
numeral 52 may be recirculated at 28, also to augment efficiency.
2 0 Having broadly discussed the overall process, numerous advantages
attributable
to the process are evinced. These include:
i) an efficient and environmentally safe disposal of harmful flue gas;
ii) improved gas recovery from the formation;
iii) enhanced thermal recovery operation to produce more bitumen per unit
2 5 steam;
iv) carbon dioxide sequestering to reduce GHG emissions;
v) volumetric replacement within the formation; and
vi) any combination of these features.
3 0 Referring now to Figure 2, shown is a more detailed schematic of the
process
according to one embodiment. In the embodiment shown, an air separator unit 40
is
provided for gaseous separation prior to injection of fuel and oxygen into the
steam
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generation system 12. Optionally, flue gas recirculation (FGR) circuit is
provided for the
system 12. The flue gas recirculation is useful to reduce the temperature of
the
combustion zone in the system 12 in order to maintain compatible steam
generator
performance for the full range of oxygen input versus combustionair used in
steam
generation process. Without the flue gas recirculation (FGR) for higher levels
of oxygen,
the heat generator temperature would exceed the design limitations of the
steam
generators. The flue gas exiting the circuit is processed in treatment unit
14, where it is
subjected to particulate removal, such as electrostatic precipitation or
baghouse 44, with
the ash discharged at 46. The so treated gas is further quenched prior to
being compressed
at 48 and further dehydrated at 50. Water 52 from the operation can be
circulated to the
water treatment unit 28 or a MSAR formulation phase 70 discussed herein after.
By
product gas from 14, if produced, can be separated and recovered from the flue
gas and
used for further operations such as CO fuel for process furnaces or boilers,
S02 for
commercial sales or H2 hydrogen supply for bitumen upgrading.
In this example, bitumen leaving oil treatment 24 may be processed in a
partial or
full upgrader 56 with partially upgraded bitumen or synthetic crude being
discharged at
58 and a hydrocarbon mixture consisting of bitumen, residuum, asphaltenes, or
coke etc.
may be further processed into MSAR, an efficient fuel discussed in detail in
United
States Patent No. 6,530,965, comprising essentially a predispersed residuum in
an
2 0 aqueous matrix which greatly reduces the fuel cost to operate the steam
generation
system. Traditionally, the latter was done with natural gas, the cost for
which greatly
exceeded the cost involved with the use of MSAR. As an option, the fuel may be
supplanted or augmented by those fuels previously taught.
Figures 3 and 4 graphically depict the oxygen requirement for flue gas carbon
2 5 dioxide enrichment on a dry and wet basis, respectively. As pure oxygen is
introduced to
the steam generator operation, the flue gas 35 will contain less nitrogen for
a fixed
quantity of carbon dioxide. Therefore both the volume of flue gas is reduced
and the
concentration of carbon dioxide in the injection treated gas 45 is increasing.
For
example, on a dry basis with reference to Figure 3, as the oxygen level used
approaches
3 0 100% (0% combustion air), then the composition of the treated flue gas
approaches near
100% CO2, including minor compounds of carbon monoxide, sulfur dioxide,
nitrogen
dioxide, etc. Figure 3 represents the primary composition of the treated
injection gas
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45. Referring to Figure 4, graphically illustrated is the primary composition
of the flue
gas stream 35 prior to flue gas treatment in 14.
Figure 5 is a schematic illustration of a natural gas steam production
circuit. In
the example, at least a portion of the displaced natural gas 20 may be
recirculated as a
fuel to drive the steam generation system 12. This is denoted by numeral 60.
The
enriched injection flue gas, which may be customized to contain between 30%
and 50%
nitrogen and between 70% and 50% carbon dioxide, is injected to displace the
produced
fluids, bitumen, natural gas, water etc processed for upgrading at 62. The
choice of
operations conducted at 62 will depend upon the desired products.
Recovered water 52 from the flue gas treatment unit 14 may be recirculated to
62.
Referring to Figure 6, shown is a further variation on the process where the
steam generation is achieved by making use of a liquid alternate fuel, shown
in the
example is a bitumen or heavy oil fuel, or alternatively, the bitumen or heavy
oil is
transformed into an emulsion fuel. In this arrangement, processed bitumen
exiting
central treatment plant 62 at line 66 may be diverted in terms of a portion of
the material
only at line 68 directly as heavy fuel oil or alternatively, directed into an
emulsion unit
for generating an alternate fuel. The emulsion unit stage being indicated by
numeral 70.
An additional amount of water recovered and circulated at 52 may be diverted
and
2 0 introduced into the unit ?0 via line 72. In the emulsion fuel unit, the
suitable chemicals
are added to the bitumen material (surfactants, etc.) in order to generate the
alternate
fuel. At this point, once formulated, the alternate fuel exiting the unit at
74 may be
introduced as a fuel to drive the steam generation system 12. The natural gas
feed from
the displaced gas in the formulation 18 used as fuel ceases. and the process
does not
2 5 deplete any further volume of the natural gas. In this manner, once the
emulsion unit is
operational and stabilized, the process simply relies on alternate fuel that
it generates on
its own.
Referring to Figure 7, shown is a further variation in the arrangement shown
in
Figure 6 where a bitumen upgrader 76 is shown added to the unit operation of
the
3 0 central treatment plant. In this manner, materials leaving central
treatment plant 66 are
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upgraded in the upgrader 76 to formulate heavy residuum exiting at 80 which
then can
be formulated into an emulsified alternate fuel and introduced into steam
system 12 as
noted with respect to Figure 6. Subsequent benefit can be realized in the
upgrading of
the bitumen quality to deasphalted oil or synthetic crude oil.
Referring to Figure 8, whereby one embodiment of the current invention is
employed in combination with a conventional gas cogeneration (COGEN) plant 600
to
enhance the overall thermal heavy oil recovery operation. Uniquely, when the
current
embodiment is combined, the steam generators 12 as described previously can be
suitably fitted with COGEN heat recovery steam generator (HRSG) to produce the
required total injection steam and provide the required power to drive the
treated
injection flue gas compressors.
Figure 9 further illustrates a further embodiment whereby the steam generators
12 are combined with a COGEN plant 600 to generate electric power. The
electric
power generated could be used to drive the treated flue gas compressors and
power the
full facility 10 to make it self sufficient in energy.
Although embodiments of the invention have been described above, it is limited
thereto and it will be apparent to those skilled in the art that numerous
modifications
fore part of the present invention insofar as they do not depart from the
spirit, nature
and scope of the claimed and described invention.
