Note: Descriptions are shown in the official language in which they were submitted.
CA 02915431 2015-12-16
DESCRIPTION
FIELD OF THE INVENTION
[001] The invention relates to the recovery, extraction, and production of
hydrocarbons, including
heavy oil and bitumen.
BACKGROUND
[002] Fossil fuels and hydrocarbon based energy sources are widely used in the
world. A number
of recovery processes have been investigated and applied for developing the
heavy oil and bitumen
resources, such as the oil sands found in Canada, Venezuela, China, and the
United States.
[003] Methods that have been developed include non-thermal processes and
thermal processes.
Non-thermal processes include natural pressure depletion, water flooding,
polymer flooding, and gas
injection. Thermal processes include cyclic steam stimulation (CSS), steam
flooding, steam assisted
gravity drainage (SAGD), and in-situ combustion.
[004] Non-thermal recovery processes have their major disadvantages. Natural
pressure depletion
may have low recovery factor and production rate; water flooding and polymer
flooding consume a
large quantity of water with low production rates; gas injection may have low
recovery factor and
rate with a high consumption of energy.
[005] The in-situ combustion process is cost-effective when building the
surface facilities.
However, it is difficult to control the combustion development inside the
reservoir.
[006] While SAGD can have a better production rate (as shown in Canadian
Patent No. 1130201 to
Butler), the method consumes a large amount of water and its operating cost is
high. Particularly
during the later stage of the process, steam chamber widely contacts the base
of the cap rock. As a
result, a large amount of heat is lost to the overburden. In addition, over
the wind-down process,
steam injection is terminated and the steam chamber pressure gradually drops
with the
disappearance of the steam chamber. Moreover, due to the well alignment of the
SAGD process, the
method cannot be applied to develop the heavy oil and oil sands reservoirs
thinner than 10 meters.
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[007] While CSS can be applied to develop thinner reservoirs with higher
production rate, the
method is basically rely on the initial reservoir pressure. In the CSS
process, oil viscosity reduction
30 is only based on heating from the steam. Heat loss to the overburden and
underburden is also huge.
To improve the CSS recovery rate, companies has tested liquid solvent
additions into the injected
steam (as described in Canadian Patent No. 2342955 to Leaute et al.). However,
the cost of the
liquid solvent is high, which may limit its applications in the field.
[008] Steam flooding process can improve the heavy oil recovery factor
significantly if the
35 reservoir properties are appropriate for this process. Generally the
heavy oil reservoir needs to pass
the screen criteria for steam flooding process. Particularly, oil viscosity
needs to be lower than
10,000 centipoise. Due to the steam overriding characteristics, heat loss to
the overburden is
significant.
[009] SAGD, CSS, and steam flooding utilize the conventional steam generators,
which emit huge
40 amount of greenhouse gas into the atmosphere. Meanwhile, a large
quantity of heat is released into
the atmosphere with the air emission process.
[0010] A need therefore exists for improving SAGD, CSS, and steam flooding
processes to develop
heavy oil and oil sands reservoirs. A solution that addresses, at least in
part, the above and the other
shortcomings is desired.
SUMMARY OF THE INVENTION
[0011] The invention is related to a method of recovering hydrocarbons based
on SAGD, or CSS, or
steam flooding well operations. The composition of the injected thermal fluids
can be controlled and
adjusted based on two types of thermal fluids generators. One type is the
conventional steam
generator and the other type is the proprietary controllable steam and CO2
unit (CSCU).
[0012] According to one embodiment of the invention, the conventional steam
generator produces
steam with a certain steam quality; the CSCU produces steam with certain steam
quality, small
amount of liquid water, CO2, and N2.The two streams of thermal fluids from
both conventional
steam generator and CSCU are mixed based on pre-designed proportions. Then,
they are all injected
into a heavy oil or an oil sands reservoir.
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[0013] According to another embodiment of the invention, the proportions of
thermal fluids from
conventional generator can range from 0% to 100%; correspondingly, the thermal
fluids from CSCU
can range from 100% to 0%. At a certain time, proportions of thermal fluids
from both generators
are fixed.
60 [0014] According to one aspect of the invention, there is provided a
method for recovering
hydrocarbons from a heavy oil or oil sands reservoir based on the following
major mechanisms: oil
viscosity reduction by heating, oil viscosity reduction by CO2 dissolution in
oil, and reservoir energy
increase and maintenance by N2 injection.
[0015] According to another aspect of the invention, there is provided a
method to reduce heat loss
65 to the overburden of the reservoir by CO2 and N2 injection, which
spreads beneath the cap rock and
acts like an insulation layer.
[0016] According to another aspect of the invention, there is provided a
method of extracting
hydrocarbons wherein the hydrocarbon viscosity ranges from 1,000 centipoise to
over 1,000,000
centipoise.
70 [0017] According to another aspect of the invention, there is provided a
method of extracting
hydrocarbons wherein the SAGD, or CSS, or steam flooding operation mode is
applied with the
injection of the combined thermal fluids.
[0018] According to another aspect of the invention, there is provided a
method of combining the
two streams of thermal fluids from two generators wherein additional
combination equipment, such
75 as a buffer tank, may or may not be used.
[0019] According to another aspect of the invention, there is provided a
method of extracting
hydrocarbons wherein at least one injection well and at least One production
well contains at least
one sensor at the down hole.
[0020] According to another aspect of the invention, there is provided a
method of extracting
80 hydrocarbons wherein at least one injection well and at least one
production well contains at least
one temperature sensor at the down hole.
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[0021] According to another aspect of the invention, there is provided a
method of extracting
hydrocarbons wherein at least one injection well and at least one production
well contains at least
one pressure sensor at the down hole.
85 [0022] According to another aspect of the invention, there is provided a
method of extracting
hydrocarbons wherein at least one injection well and at least one production
well contains at least
one sensor at the well head.
[0023] According to another aspect of the invention, there is provided a
method of extracting
hydrocarbons wherein at least one injection well and at least one production
well contains at least
90 one temperature sensor at the well head.
[0024] According to another aspect of the invention, there is provided a
method of extracting
hydrocarbons wherein at least one injection well and at least one production
well contains at least
one pressure sensor at the well head.
[0025] According to another aspect of the invention, there is provided a
method of extracting
95 hydrocarbons wherein at least one flow meter is installed at the
conventional steam generator for
metering steam injection rate.
[0026] According to another aspect of the invention, there is provided a
method of extracting
hydrocarbons wherein at least three flow meters are installed at the CSCU for
metering water flow
rate, air flow rate, and fuel flow rate, respectively.
100 [0027] According to another aspect of the invention, there is provided
a method of extracting
hydrocarbons wherein at least one flow meter and at least one sampling point
are installed at the test
separator for metering and monitoring vapor (steam) production rate and gas
(N2, CO2, CH4, and
H2S) production rates.
[0028] According to another aspect of the invention, there is provided a
method of extracting
105 hydrocarbons wherein all injection wells have additive (chemicals or
corrosion inhibitors) co-
injection settings at the well head. The additive injection rate is determined
based on reservoir and
production engineering studies.
[0029] According to another embodiment of the invention, there is provided a
method of extracting
hydrocarbons wherein proportional amount of thermal fluids generated from
conventional steam
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110 generator and CSCU can be adjusted automatically based on the criteria
proposed from reservoir
and production engineering studies.
[0030] According to another embodiment of the invention, there is provided a
method of extracting
hydrocarbons wherein if injection/production data collected through [0019] ¨
[0029] do not satisfy
the pre-defined criteria, automatic control program will tune the injection
composition immediately.
115 [0031] According to another embodiment of the invention, there is
provided a method of extracting
hydrocarbons wherein observation wells are drilled some distance away from the
injection/production wells. Pressure and temperature sensors are installed
inside the observation
wells at the down hole to capture the reservoir pressure and temperature data
over the injection and
production phases.
120 [0032] All the metered, measured, sampled, and monitored data are sent
to the programmable logic
controller (PLC). The PLC is applied to analyze and adjust the operating
parameters based on pre-
defined criteria.
BRIEF DESCRIPTION OF THE DRAWINGS
125 [0033] For a further understanding of the nature and objects of the
present invention, reference
should be made to the following detailed description, taken in combination
with the accompanying
drawings, in which:
[0034] FIG. 1 is illustrating the working mechanism of the proprietary CSCU;
and
[0035] FIG. 2 is an perspective view illustrating the combination of the
thermal fluids generated
130 from conventional steam generator and CSCU according to an embodiment
of the invention; and
[0036] FIG. 3 is a 3D view illustrating the method of extracting hydrocarbons
based on the cyclic
operation mode according to an embodiment of the invention;
[0037] FIG. 4 is illustrating the method of extracting hydrocarbon based on
the cyclic operation
mode with a cross-section perpendicular to the horizontal wellbore in the
reservoir;
135 [0038] In the description which follows, like parts are marked
throughout the specification and the
drawings with the same respective reference numerals.
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DETAILED DESCRIPTION OF THE EMBODIMNETS
[0039] The description which follows and the embodiments described therein are
provided by way
140 of illustration of an example or examples of particular embodiments of
the principles of the present
invention. There examples are provided for the purposes of explanation and not
limitation of these
principles and of the invention. In some instances, certain structures and
techniques have not been
described or shown in detail in order not to obscure the invention.
[0040] As part of this patent application, a number of terms are being used in
accordance with what
145 is understood to be the ordinary meetings of these terms. For instance,
"fluid" includes both liquids
and gases.
[0041] "Heavy Oil" is defined as petroleum having an American Petroleum
Institute gravity below
22.3 API (920 to 1000 kg/m3). "Bitumen" is defined as petroleum existing in
semi-solid and solid
phases with a density of greater than 1000 kg/m3. While these terms are
commonly used and are
150 general categories, references to these terms in this application
include the continuum of such
substances and do not suggest some specific boundaries between the two
substances. The term
"heavy oil" includes within its scope "bitumen" of all forms.
[0042] "Petroleum" means mixtures consisting primarily of hydrocarbons in
different phases,
including liquid, gas, or solid phase. "Hydrocarbon" is an organic compound
consisting entirely of
155 hydrogen and carbon. In the context of this patent application, the
words "petroleum" and
"hydrocarbon" refer to mixtures with significant variation in composition.
[0043] A reservoir is a formation underneath the surface that contains natural
accumulation of
hydrocarbons.
[0044] Figure 1 is illustrating the CSCU working process. The water supply
system 10 provides the
160 softened water, the fuel system 20 provides fuel (compressed natural
gas or liquid fuel), and the air
system 30 provides the compressed air to the CSCU 100. The CSCU products
consist of steam, CO2,
N2, and some liquid water.
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[0045] In one embodiment, the combustion in the CSCU 100 may be started
automatically by
electronic igniter when the designed proportional amount of compressed air and
fuel are injected
165 into the CSCU.
[0046] Figure 2 is illustrating the mixing of thermal fluids from both CSCU
100 and conventional
steam generator 200. The preferred amount of thermal fluids generated from
CSCU 100 and
conventional steam generator 200 are mixed in the container 300.
[0047] In one embodiment, the volume of thermal fluids coming from CSCU 100 is
controlled by
170 valve 110 and the volume of thermal fluids coming from the conventional
steam generator 200 is
controlled by valve 210. By controlling the volume of thermal fluids coming
from the two
generators, nitrogen concentrations in the mixed thermal fluids 300 may be
reduced or increased.
[0048] In one embodiment, the mixture in the container 300 is injected into
the injection well 400
based on pre-defined injection rate.
175 [0049] Figure 3 is illustrating the multiple thermal fluids injection
into heavy oil or oil sands
reservoir. The thermal fluids reaches the horizontal wellbore 450 from the
well head 400. The
horizontal wellbore 450 is drilled in the reservoir 560 which is between the
overburden 570 and
underburden 580. The horizontal wellbore 450 is completed with slotted liner
or wire wrapped
screen liner or other preferred liner.
180 [0050] Figure 4 is a cross section normal to the horizontal wellbore.
From both Figures 3 and 4, it is
seen that the injected thermal fluids (steam, CO2, N2, and a small amount of
liquid water) comes out
of the horizontal wellbore 450 and are injected into the heavy oil or oil
sands reservoir 560. Since
reservoir is cold, the injected steam will condense when it enters the
reservoir. However, the N2 and
CO2 do not condense and they will propagate farther. Therefore, with
continuous injection, mainly
185 three zones are formed in the reservoir 560. Zone 500 is mainly steam
zone and zone 510 is non-
condensable gas zone, which consists of N2 and CO2. Zone 530 is mainly liquid
water. Boundary
520 approximately separates steam zone 500 and liquid water zone 530. Inside
boundary 460 is the
entire impacted region by the injected thermal fluids.
[0051] Figure 3 shows two observation wells 420 in reservoir 560. Pressure and
temperature sensors
190 are installed in these observations wells. Along the horizontal
wellbore 450, temperature and/or
pressure sensors are also installed. At Well head 400, pressure and
temperature sensors and flow
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meters are installed. Based on the flow rates, pressure, and temperature data,
three zones' status (500,
510, and 530) is analyzed.
[0052] Through the analysis of three zones' status and horizontal well
injection performance, the
195 proportions of thermal fluids coming from the two generators may be
adjusted accordingly. The N2
concentration in the mixture can be increased or decreased for optimizing the
injection process.
[0053] According to another embodiment of the invention, the process
monitoring, data collection,
analysis, and adjusting described in [0051] and [0052] are automatically
performed by the PLC.
