Note: Descriptions are shown in the official language in which they were submitted.
USE OF FOAM WITH IN SITU COMBUSTION PROCESS
FIELD OF THE INVENTION
[0003] The invention relates to methods of improving the effectiveness of
wet in situ
combustion (ISC) processes to accelerate oil production and particularly to an
improved wet in
situ combustion process utilizing foam. Water containing a foaming agent is
injected along with
an oxygen-containing gas to maintain a consistent water-gas ratio, to
facilitate water-reservoir
rock contact and to prevent separation of water and gas.
BACKGROUND OF THE INVENTION
[0004] Conventional oil reserves are preferred sources of oil because they
provide a high
ratio of extracted energy over energy used in regards to the extraction and
refining processes it
undergoes. Unfortunately, due to the physics of fluid flow, not all
conventional oil can be
produced. Additionally, as conventional oil sources become scarce or
economically non-viable
due to depletion, unconventional oil sources are becoming a potential supply
of oil. But,
unconventional oil production is also problematic because it consists of extra
heavy oils having a
consistency ranging from that of heavy molasses to a solid at room temperature
and may also be
located in the reservoir rocks. These properties make it difficult to simply
pump the oil out of the
ground; thus, its production is a less efficient process than conventional
oil.
[0005] As a result, enhanced oil recovery (EOR) techniques are often
employed to increase
the amount of subterranean crude oil extracted. Using EOR, 30-60% or more of
the original oil
can be extracted. Additionally, EOR finds applications in both conventional
and unconventional
oil reserves.
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[0006] During EOR, compounds not naturally found in the reservoir are
injected into the
reservoir in a well other than the producing well to assist in oil recovery.
Simply stated, EOR
techniques overcome the physical forces holding the oil hydrocarbons
underground. There are
many types of EOR techniques that are categorized by the compound being
injection: gas
injection, chemical injection, microbial injection or thermal recovery. While
there are many
types of EOR techniques, reservoirs containing heavier crude oils tend to be
more amenable to
thermal EOR methods, which heat the crude oil to reduce its viscosity and thus
decrease the
mobility ratio. The increased heat reduces the surface tension of the oil and
increases the
permeability of the oil. A summary of various EOR techniques is presented in
Table 1.
TABLE 1. Enhanced Oil Recovery (EOR) Techniques
CSS Cyclic Steam Stimulation or "huff and puff." Steam is
injected into a well at a
temperature of 300-340 C for a period of weeks to months. The well is allowed
to sit for days to weeks to allow heat to soak into the formation, and, later,
the
hot oil is pumped out of the well for weeks or months. Once the production
rate
falls off, the well is put through another cycle of steam injection, soak and
production. This process is repeated until the cost of injecting steam becomes
higher than the money made from producing oil. Recovery factors are around
20 to 25%, but the cost to inject steam is high.
SAGD Steam Assisted Gravity Drainage uses at least two horizontal
wells--one at the
bottom of the formation and another about 5 meters above it. Steam is injected
into the upper well, the heat melts the heavy oil, which allows it to drain by
gravity into the lower well, where it is pumped to the surface. SAGD is
cheaper
than CSS, allows very high oil production rates, and recovers up to 60% of the
oil in place.
VAPEX Vapor Extraction Process is similar to SAGD, but instead of
steam, hydrocarbon
solvents are injected into an upper well to dilute heavy oil and enables the
diluted heavy oil to flow into a lower well.
ISO In situ combustion involves a burning of a small amount of
the oil in situ, the
heat thereby mobilizing the heavy oil.
THAI Toe to Heel Air Injection is an ISO method that combines a
vertical air injection
well with a horizontal production well. The process ignites oil in the
reservoir
and creates a vertical wall of fire moving from the "toe" of the horizontal
well
toward the "heel", which burns the heavier oil components and upgrades some
of the heavy bitumen into lighter oil right in the formation.
COGD Combustion Overhead Gravity Drainage is another ISO method
that employs a
number of vertical air injection wells above a horizontal production well
located
at the base of the bitumen pay zone. An initial Steam Cycle similar to CSS is
used to prepare the bitumen for ignition and mobility. Following that cycle,
air is
injected into the vertical wells, igniting the upper bitumen and mobilizing
(through heating) the lower bitumen to flow into the production well. It is
expected that COGD will result in water savings of 80% compared to SAGD.
EM A variety of electromagnetic methods of heating oil in situ
are also being
developed.
GAS A variety of gas injection methods are also used or being
developed, including
INJECTION the use of cryogenic gases.
COMBO Any of the above methods can be used in combination.
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[0007] One technique less commonly used is in situ combustion (ISC), which
involves the
oxidative generation of heat within the reservoir itself. During a dry in situ
combustion (FIG. 1),
an oxygen-containing gas such as air is injected into an underground oil
reservoir and burned
with part of the hydrocarbons to create heat. The fire can be started by
either lowering an
incendiary device, such as a phosphorus bomb or a gas burner, into the well,
or the injection of a
large amount of air can cause spontaneous combustion. Once burning, large
volumes of air, or
other oxygen source gas, must be continually injected into the reservoir to
sustain the fire. This
combustion reaction also creates steam that, along with light hydrocarbons,
condenses and
releases heat to the nearby oil. During ISC, a frontal advance containing
different layers of
combustion gases, steam, and heated oil is created. This frontal advance acts
as a production
drive, thus driving the heated oil towards producing wells.
[0008] Fireflood projects are not extensively used due to the difficulty in
controlling the
flame front and a propensity to set the producing wells on fire. However, the
method uses less
freshwater, produces 50% less greenhouse gases, and has a smaller footprint
than other
production techniques. Thus, there is a certain interest in further developing
combustion based
methods for future use.
[0009] ISC can either be forward or reverse combustion. In forward
combustion, the fire and
injected oxygen source gas originate at the injection well. Thus, the gas
flow, combustion front
and oil flow advance in the same horizontal direction towards the producing
well. In reverse
combustion, the gas flow is counter-current to the combustion front.
[0010] The main cost associated with dry ISC is the cost of compression for
the air injection
system. Furthermore, the effectiveness of this technique depends on the
velocity and stability of
the frontal advance, as well as the heat generated from the combustion. During
the dry ISC
process, as the oil is produced, depleted volumes remaining in the reservoir
rock are primarily
filled with air, steam and other gases resulting from the combustion. The rock
absorbs much of
the energy resulting from the heat of combustion reaction and heat of
condensation of the steam.
Thus, this energy is wasted because it is not used to further produce oil,
resulting in
inefficiencies in the dry ISC process.
[0011] Other novel techniques have been developed to increase the
efficiency of EOR oil
production through the use of liquids instead of gases.
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[0012] Water has also been utilized in dry ISC methods. A polymer colloidal
system mixed
with water was used to transport ozone gas into the reservoir. [1] This system
allowed for quicker
autoignition of the dry ISC process.
[0013] Also, the injection of water for a wet in situ combustion process
(Fig. 2) has been
found to improve oil production. In the wet ISC process, water and an oxygen
gas source are
injected together into the reservoir. The heat in the reservoir converts the
water into steam. The
generated steam from the water combines with the frontal advance to help drive
the oil.
Additionally, water aids in scavenging the heat left in the reservoir rock
after the combustion
front has advanced through. The water is heated by the rock, which creates
more steam that can
condense in the burning front and transfer heat to nearby oil, resulting in
increased oil
production. The addition of injected water also reduces the gas injection
rates, thereby reducing
compression costs seen in dry ISC.
[0014] However, a disadvantage of the wet combustion process is the
difficulty in
maintaining proper water-gas ratios. If water-gas ratio is too low, then there
is not enough water
to effectively recover all of the available energy in the reservoir rock. If
the water-gas ratio is too
high, then there is too much water that is not converted into steam and
interferes with the
combustion front by cooling the temperature or extinguishing the combustion
front. Thus, an
optimum water-gas ratio would effectively recover the energy stored in the
reservoir rock by
converting the water to steam, but not cool or quench the combustion front
such that it is
extinguished. Furthermore, the proper ratio will all reduce the amount of fuel
needed, which
decreases the gas requirements needed to heat the oil.
[0015] Another disadvantage of the wet combustion process is the separation
of water and
the gas in the reservoir. This separation is also dependent on the water-gas
ratio. If the water
does not travel horizontally or vertically through the reservoir to scavenge
the heat, then only gas
will reach the combustion front, which will essentially be a dry combustion.
If there is too much
water, then the gas cannot travel through the reservoir to reach the
combustion front, thus
potentially allowing water to extinguish the combustion front. Also, because
water is denser, it
could cumulate at the base of the reservoir and not reach hotter rock. As
such, it is imperative
that a proper water-gas ratio is maintained for the water and the as to travel
together through the
oil reserve for optimal oil production efficiencies.
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[0016] Finding the optimum water-gas ratio is difficult because the
reservoir heterogeneities
and gravity override can affect the fluid movement. Usually, water and gas
injection rates are
varied until a reasonable water-gas ratio is found. The rates are then
adjusted throughout the wet
ISC to maintain this ratio. This method produces inconsistent results, nor is
there a method to
quickly determine the proper ratio or injection rates.
[0017] US4691773 discloses a wet in situ combustion method wherein a non-
oxygen
containing fluid, such as water, is introduced along with air cyclically to
produce periodic high
volume rates of injected fluid. However, both techniques can result in over-
injecting water and
extinguishing the combustion front can occur, leading to a loss of time and
money to re-start the
process.
[0018] US7882893 discloses the use of surfactant, salt brine and oxygen to
create a foam
during ISC. The foam decreases the mobility of the displacing fluid (brine) in
the higher
permeability zones and diverts more oxygen-containing gas into the lower
permeability zones.
Thus, the foam prevents the water from segregating from the oxygen gas. As the
displacing fluid
evaporates from the foam, the foam breaks and becomes an oxygen-rich steam and
alkaline
brine.
[0019] US20090194278 discloses an ISC technique that uses a surfactant-
based foam that is
injected with or prior to the oxygen gas. The purpose of the foam is to
increase the amount of
oxygen available for combustion and to control the mobility of the oxygen
through the already
swept zones. The foam also prevents the heated gas from seeping into porous
sections of the
reservoir. Furthermore, water or steam can be mixed with the foam to enhance
the effectiveness
of the oxygen utilization and displacement of oil. The focus of this technique
is the prevention of
heat transfer to the surrounding reservoir rock. It does not address the
possibility of scavenging
heat.
[0020] Therefore, what is needed in the art is a better method for
maintaining water-gas
ratios during the wet in situ combustion process and scavenging heat from
rocks after the
combustion front advances that also prevents separation of water and air.
SUMMARY OF THE DISCLOSURE
[0021] The present disclosure describes an improved wet ISC technique to
recover oil from
depleted reservoirs. During wet ISC, water containing a foaming agent, an
oxygen-containing
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gas, and, optionally, additional gases, are injected into a subterranean oil
containing reservoir.
The foaming agent aids in maintaining a consistent water-gas ratio and
prevents separation of
water and gas as they move through the reservoir.
BRIEF DESCRIPTION OF THE DRAWINGS
[0022] FIG. 1 is a schematic depicting dry forward in situ combustion.
[0023] FIG. 2 is a schematic depicting wet forward in situ combustion
[0024] FIG. 3 is a schematic depicting foam-assisted wet forward in situ
combustion
DESCRIPTION OF EMBODIMENTS OF THE INVENTION
[0025] The disclosure relates to a heat scavenging method using an agent
for forming
foams/aerosols/hydrosols/other emulsions or colloidal dispersions. For
conciseness hereafter
hereafter, foaming agent is used for exemplary purposes only given possibility
of creating the
aerosols/hydrosols/other emulsions or colloidal dispersions.
[0026] Generally, the invention provides an improved wet in situ combustion
process in
which a foaming agent is injected together with the water. The novel feature
of this improved
method is the ability of the foam to carry water through the reservoir and
combustion zone. The
foaming agent has a low density and viscosity, which can efficiently carry
water into overburden
rock. The use of such a foaming agent ensures proper water-to-oxygen-
containing gas ratios are
maintained during wet in situ combustion by carrying water throughout the
reservoir. Consistent
water-to-oxygen ratios will allow for maximum heat scavenging and minimum
combustion
quenching by the water. Another advantage of using foam to carry water through
the reservoir is
an increase in contact between the water and heated reservoir rock. This will
create more steam,
which will heat the oil and allow for greater production of oil. The foam will
also prevent the
water from pooling.
[0027] Additionally, the foam will also prevent the water and gas from
separating in the
reservoir, thus preventing a dry ISC process. Additionally, the foam can also
contain oxygen,
which will help in providing a consistent amount of oxygen to the combustion
front.
[0028] In a preferred embodiment, the oxygen-containing gas is air. Further
preferred
embodiments include generating foam on the surface before injection into the
subterranean oil
formation.
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[0029] In one embodiment, the water being mixed with the foaming agent is
brine water
recovered from the reservoir being treated. Alternatively, surface water or
sea water can be used.
[0030] In another embodiment, the foaming agent contains oxygen, which will
aid in
maintaining a consistent amount of oxygen at the combustion front.
[0031] In yet another embodiment, the water and foaming agent are injected
some time after
the oxygen-containing gas and optional additional gases have been injected
into the subterranean
formation.
[0032] In the present disclosure, the foaming agent can generate foam on
the surface before
injection into the oil formation. In another variation, the foaming agent can
generate foam in situ
in the subsurface after injection into the oil formation.
[0033] The invention also describes the use of the above methods to recover
more oil from
steam assisted gravity drainage (SAGD) depleted reservoirs.
[0034] The foaming agent can include, but is not limited to, other
colloidal foams, aerosols,
hydrosols, emulsions, or dispersions capable of creating a suitable foam.
Preferred foam
components have thermal and chemical properties that are stable at the high
temperatures
(>200 C) used in ISC and should have low adsorption onto reservoir rock/clay
surfaces.
Additionally, the foaming capabilities should be effective at the particular
reservoir brine pH.
Thus, the foaming agent can be any foaming agent that is stable under
reservoir conditions, and
increases the transport of water, thus maintaining a consistent water-to-gas
ratio.
[0035] Foam agents can be surfactant- or alkali-based. Thermally and
chemically stable,
non-ionic, anionic, cationic, and amphoteric/zwitterionic surfactants
including, but are not
limited to, alkyl benzene, aromatic sulfonates, alpha/internal olefin,
sulfonates, alkyl aryl
sulfonates, and alkoxy sulfates can be used. High alkyl chain lengths should
be chosen since the
efficiency of foam generation increases with increases in chain length.
[0036] Examples of alkali-based components are alkaline metal carbonates,
bicarbonates and
hydroxides, including but not limited to, sodium carbonate, sodium
bicarbonate, sodium
hydroxide, potassium carbonate, potassium bicarbonate, potassium hydroxide,
magnesium
carbonate, and calcium carbonate.
[0037] Other agents that can be used are in other colloidal foams,
aerosols, hydrosols,
emulsions, or dispersions which could create a suitable and stable foam.
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[0038] The chosen foaming agent will depend of the characteristics of the
reservoir. Because
the foaming agent is being used to increase the sweep efficiency of the
water/gases, the foaming
agent should not react with the formation. For example, cationic and
amphoteric surfactants have
strong interactions with sand particles, thus they would not be ideal foaming
agents for a sandy
reservoir. Interactions with reservoir formation will result in an increase in
concentration of
foaming agent and will be cost prohibited, or at least less cost effective.
[0039] The chosen foaming agent also depends on the water. High salinity
water can cause
precipitation of surfactant molecules, especially when high divalent ion
concentrations are
present. Non-ionic surfactants and alkali-based surfactants are considered to
be more resistant to
high salinity water.
[0040] Many high temperature surfactant- and alkali-based foaming agents
are commercially
available from vendors such as BASF, ChemEOR Inc., Down Chemical Company,
Huntsman
Corporation, OilChem Technologies, Sasol and Tiorco.
[0041] The desired properties of the generated foam arc densities in the
range of 0.000598 ¨
0.0770 g/cm3 and viscosities in the range of 0.0123 ¨ 0.0216 cP. The lightness
of the foam
enables it to transport/lift the water and gas(es) being injected instead of
blocking the high
permeability zones in the reservoir. This will maintain the water-gas ratio as
it moves through the
reservoir.
[0042] The foam can be generated on the surface or sub-surface. Sub-surface
methods for
generating foam include a static mixer downhole, foam generation through a
perforation in the
well, natural mixing in the well, in situ foam generation in the reservoir or
any combination
thereof.
[0043] Additionally, the foaming agent/water mix can be injected at the
same time as the
gas(es), or can be injected some time after the gas(es) has been injected.
Furthermore, the
foaming agent/water can be injected continuously or in slugs. Also, the
foaming agent/water can
be injected into vertical or horizontal wells to improve the wet ISC process,
including both
forward and reverse combustion.
[0044] An oxygen-containing gas is injected to fuel the combustion process
in the reservoir.
Typical gases include air, oxygen, carbon dioxide, carbon monoxide or any
combination thereof.
An additional non-oxygen containing gas can also be injected to fill in gas
drive, including
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hydrogen, nitrogen, methane, hydrogen sulfide, propane, butane, natural gas,
flue gas and any
combination thereof. Gases may be in a liquid form, a liquid/gas mixture, or
gas form.
[0045] As used herein, "oil," "crude oil," and "hydrocarbons" are used
interchangeable to
describe the hydrocarbons remaining in oil reservoirs after conventional
drilling methods.
[0046] As used herein, "foaming agent" means an additive to water used to
generate foam
either above the surface before injection or sub-surface using a mechanical or
natural mixing
method. The additive can include, but is not limited to, colloidal foams,
aerosols, hydrosols,
emulsions, or dispersions.
[0047] As used herein, "oxygen-containing gas" or "oxygen source gas" mean
a gas
containing oxygen and capable of igniting and fueling the combustion front
within the reservoir.
[0048] The use of the word "a" or "an" when used in conjunction with the
term "comprising"
in the claims or the specification means one or more than one, unless the
context dictates
otherwise.
[0049] The term "about" means the stated value plus or minus the margin of
error of
measurement or plus or minus 10% if no method of measurement is indicated.
[0050] The use of the term "or" in the claims is used to mean "and/or"
unless explicitly
indicated to refer to alternatives only or if the alternatives are mutually
exclusive.
[0051] The terms "comprise", "have", "include" and "contain" (and their
variants) are open-
ended linking verbs and allow the addition of other elements when used in a
claim.
[0052] The phrase "consisting of" is closed, and excludes all additional
elements.
[0053] The phrase "consisting essentially of' excludes additional material
elements, but
allows the inclusions of non-material elements that do not substantially
change the nature of the
invention.
9
[0054] The following abbreviations are used herein:
ABBREVIATION TERM
ISC In situ combustion
SAGD Steam assisted gravity drainage
PSI Pounds per square inch
[0055] Fig. 1 depicts a dry forward ISC. Here, dry air is injected into a
reservoir to fuel the
combustion process and help push the combustion front towards the oil
production well. Note
that the heat formed during the combustion process is absorbed by the
reservoir rock. Also, the
heated oil bank, i.e. displaced oil, has not traveled close to the oil
production well.
[0056] In contrast, the addition of water to the air injection results in
the contact of water
with heated reservoir rock, as shown in Fig. 2. After contacting the heated
rock, the water is
converted into steam and is pushed forward the water-air injection. As the
steam contacts cooler
rock in the reservoir, it condenses and transfers heat to the nearby oil. This
additional heat results
in the heated oil bank travelling further towards the oil production well then
the dry forward ISC
depicted in Fig. 1.
[0057] Fig. 3 depicts the present invention¨use of a foaming agent in the
water. Here, the
foaming agent helps carry the water into the reservoir, thus facilitating
increased contact with the
heated reservoir rock. Furthermore, the foam also prevents the water and air
from separating due
to differences in density. As before, the resulting steam heats the oil;
however, the increased
water/rock contact has allowed water to scavenge more heat from the rock to
transfer to the oil.
As such, the oil is able to move towards the oil production well more
efficiently than either a
water-air injection or air only injection.
[0058] Reference is made to the following:
[0059] 1. Limkar, Parikshit S., "Novel In-Situ Combustion Technique Using a
Semi-
Permeable Igniter Assembly," Society of Petroleum Engineers, SPE 125583, 2009.
[0060] 2. Burger, Jacques G., Sahuquet, Bernard C., "Laboratory Research on
Wet
Combustion," Journal of Petroleum Technology, 1973, 1137-46.
[0061] 3. Falls, Andrew H., Lawson, Jimmie B. and Hirasaki, George J., "The
Role of
Noncondensable Gas in Steam Foams", Journal of Petroleum Technology, January
1988.
[0062] US3993133
[0063] US3994345
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PCT/1JS2014/010718
[0064] US4691773
[0065] US7882893
[0066] US20090194278
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