Note: Descriptions are shown in the official language in which they were submitted.
CA 02791323 2012-09-27
TITLE OF THE INVENTION
STEAM ASSISTED GRAVITY DRAINAGE PROCESSES WITH THE ADDITION OF
OXYGEN ADDITION
FIELD OF THE INVENTION
A process to conduct an improved SAGD process for bitumen recovery, by
injecting oxygen and
steam separately, into a bitumen reservoir; and to remove, as necessary, non-
condensable gases
produced by combustion, to control the reservoir pressures. In one aspect of
the invention a
cogeneration operation is locally provided to supply oxygen and steam
requirements.
Acronyms Used Herein:
SAGD Steam Assisted Gravity Drainage
SAGDOX SAGD + Oxygen
SAGDOX (9) SAGDOX with 9% (v/v) oxygen in steam + oxygen
ISC In Situ Combustion
EOR Enhanced Oil Recovery
LTO Low Temperature Oxidation (150-300 C)
HTO High Temperature Oxidation (380-800 C)
ETOR Energy to Oil Ratio (MMBTU/bbl)
ETOR (steam) ETOR of steam component
VT Vertical (well)
HZ Horizontal (well)
OB1P Original Bitumen in Place
STARS Steam Thermal and Advanced Reservoir Simulator (CMG, Calgary)
SOR Steam to Oil Ratio (bbls/bbl)
PG Produced (non-condensable) Gas
ASU Air Separation Unit (to produce oxygen gas)
JCPT Journal of Canadian Petroleum Technology
OGJ Oil & Gas Journal
JPT Journal of Petroleum Technology
SPE Society of Petroleum Engineers
COFCAW Combination of Forward Combustion and Waterfiood
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CAGD Combustion Assisted Gravity Drainage
CHOA Canadian Heavy Oil Association
DOE (US) Department of Energy
GOR Gas to Oil Ratio
BACKGROUND OF THE INVENTION
References used:
= Anderson, R.E. et al. ¨ "Method of Direct Steam Generation using an Oxyfuel
Combustor",
Intl Pat, W02010/101647 A2, 2010.
= Balog, S. et al ¨ "The WAO Boiler for Enhanced Oil Recovery", JCPT, 1982.
= Belgrave, J.D.M. et al ¨ "SAGD Optimization with Air Injection" SPE 106901,
2007
= Bousard, J.S. ¨ "Recovery of Oil by a Combustion of LTO and Hot Water or
Steam
Injection", US Pat. 3976137, Avg., 1976
= Butler, R.M. ¨"Thermal Recover of Oil & Bitumen", Prentice-Hall, 1991
= Cenovus ¨ OGT, Sept 6, 2010
= Chinna, H. et al ¨ "Hydrocarbon Recovery Facilitated by In Situ Combustion
using
Horizontal Well", 1nel Pat. WO 2006/074555 Al, 2006.
= Chu, C. ¨ "A Study of Fireflood Field Projects", JPT, Feb. 1977
= Craig. F.F. et al ¨ "A Multipilot Evaluation of the COF'CAW Process", JPT,
June 1974
= Dietz D.N. et al ¨ "Wet and Partially Quenched Combustion", JPT, April, 1968
= Doschner, T.M. ¨ "Factors that Spell Success in Steaming Viscous Crudes".
OGJ, July 11,
1996
= Gates, 1. et al ¨ "A Process for In Situ Recovery of Bitumen and Heavy Oil"
US Pat.
2005/0211434 Al, Sept 2005
= Gates, 1. et al ¨ "In Situ Heavy Oil and Bitumen Recovery Process" US Pat.
2010/0065268
Al, Mar. 2010.
= Gates. C.F. et al ¨ "In Situ Combustion in the Tulane Formation, South
Belridge Field, Kerm
County California", SPE 6554, April 1977
= Graves, M. et al, "In Situ Combustion (ISC) Process Using Horizontal Wells"
JCPT, April,
1996
= Gutierrez, D. et al- "In Situ Combustion Modeling", JCPT, Apr. 2009
= Herbeck, E.F. et al ¨ "Fundamentals of Tertiary Oil Recovery, Pet. Eng.,
Feb., 1977
CA 02791323 2012-09-27
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= Javad, S eta!, "Feasibility of In Situ Combustion in the SAGD Chamber",
JCPT, Apr. 2001
= Kerr, R. et at ¨ "Sulphur Plant Waste Gases: Incineration Kinetics and Fuel
Consumption" ¨
Report for Alberta Gov't, July, 1975.
= Kjorholt, H. ¨ "Single Well SAGD", Int'l Pat. WO 2010/092338 A2, June 2010.
= Lim. G. et al ¨ "System and Method for the Recovery of Hydrocarbons by In
Situ
Combustion", US Pat. 7740062. June, 2010
= Moore. R.E. et at ¨ "In Situ Performance in Steam Flooded Heavy Oil Cores",
JCPT, Sept.
1999
= Moore, R.G. et al ¨ "Parametric Study of Steam Assisted In Situ Combustion",
published,
Feb., 1994
= New Tech, Magazine, Nov. 2009.
= Parrish D.R. et al ¨ "Laboratory Study of a Combination of Forward
Combustion and
Waterflooding ¨ the COFCAW Process", JPT, Feb. June 1969
= Petrobank, website, 2009
= Pfefferle,W.C. "Method for In Situ Combustion of In-Place Oils", US Pat.
7,581,587 B2,
Sept. I, 2009
= Pfefferle, W.C. ¨ "Method for CAGD Recovery of Heavy Oil", Int' I Pat. WO
2008/060311
A2, May 2008
= Pfefferle, W.C. "Method for CAGD Recovery of Heavy Oil" US Pat. 2007/0187094
Al,
Aug. 16, 2007
= Prats, M. et al ¨ "In Situ Combustion Away from Thin, Horizontal Gas
Channels", SPE
1898, Oct. 1967
= Praxair, website, 2010
= Ramey Jr., H.J. "In Situ Combustion", Proc. 8th World Pet. Long., 1970
= Sarathi, P. "In Situ Combustion EOR Status", DOE, 1999
= Sullivan. J. ct al ¨ "Low Pressure Recovery Process for Acceleration of In
Situ Bitumen
Recovery", US Pat. 2010/0096126 Al Apr. 2010.
= Weiers, L. et al ¨ "In Situ Combustion in Gas over Bitumen formations", US
Pat. 9700701
B2, Mar. 2011
= Wylie, I. et at ¨ lot Fluid Recovery of Heavy Oil with Steam and Carbon
Dioxide", US Pat.
2010/0276148 Al, Nov. 2010.
= Yang X et al¨ "Design of hybrid Steam ¨ ISC Bitumen Recovery Processes" Nat.
Resources
Res., Sept. 3, 2009(1)
CA 02791323 2012-09-27
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= Yang, X. et at -- "Design and Optimization of Hybrid Ex Situ/In Situ Steam
Generation
Recovery Processes for Heavy Oil and Bitumen". SPE Symposium, Calgary, Alta.,
Can.,
Oct.. 2008.
= Yang, X. et al¨ "Combustion Kinetics of Athabasca Bitumen from 1 D
Combustion Tube
Experiments", Nat. Res. 18 No 3, Sept. 2009(x)
Today (2011), the leading in situ EOR process to recover bitumen from oil
sands reservoirs, such
as found in the Athabasca region of Alberta in Canada, is SAGD (steam assisted
gravity
drainage). Bitumen is a very heavy type of oil that is essentially immobile at
reservoir
conditions, so it is difficult to recover. In situ combustion (ISC) is an
alternative process that, so
far, has shown little application for bitumen recovery.
SAGDOX (SAGD with oxygen) is another alternative process, for bitumen EOR that
can be
considered as a hybrid process combining the attributes of SAGD (steam) and
ISC (oxygen).
SAGDOX uses a modified SAGD geometry with extra wells or segregated injector
systems to
allow for separate continuous injection of oxygen and steam and removal on non-
condensable
gases produced by combustion.
1. Prior Art Review ¨ Bitumen EOR
2.1 SAGD
In the early days of steam EOR, the focus was on heavy oil (not bitumen) and
two process types,
using vertical well geometry ¨ steam floods (SF), where a steam injector would
heat and drive
oil to a producer well (California heavy oil EOR used this process) and cyclic
steam simulation
(CCS); where, using a single vertical well, steam was injected, often at
pressures that fractured
the reservoir. This was followed by a soak period to allow oil time to be
heated by conduction
and then a production cycle (Cold Lake, Alberta oil is recovered using this
process).
But, compared to these processes and heavy oil, bitumen causes some
difficulties. At reservoir
conditions, bitumen viscosity is large (> 100,000 cp.), bitumen will not flow
and gas/steam
injectivity is very poor or near zero. Vertical well geometry will not easily
work for bitumen
EOR. We need a new geometry with short paths for bitumen recovery and a method
to start-up
the process so we can inject steam to heat bitumen.
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In the 1970-1980's using new technology to directionally drill wells and
position the wells
accurately, it became possible to drill horizontal wells for short-path
geometry. Also, in the early
1970's, Dr. Roger Butler invented the SAGD process, using horizontal wells to
recover bitumen
(Butler (1991)). Figure 1 shows the basic SAGD geometry using twin parallel
horizontal wells
with a separation of about 5m, with the lower horizontal well near the
reservoir bottom (about 2
to 8m. above the floor), and with a pattern length of about 500 to 1000m. The
SAGD process is
started by circulating steam until the horizontal well pair can communicate
and form a steam
(gas) chamber containing both wells. Figure 17 shows how the process works.
Steam is injected
through the upper horizontal well and rises into the steam chamber. The steam
condenses at/near
the cool chamber walls (the bitumen interface) and releases latent heat to the
bitumen and the
matrix rock. Hot bitumen and condensed steam drain by gravity to the lower
horizontal
production well and are pumped (or conveyed) to the surface. Figure 18 shows
how SAGD
matures ¨ A young steam chamber has oil drainage from steep sides and from the
chamber top.
When the chamber grows and hits the ceiling (top of the net pay zone),
drainage from the
chamber top ceases and the sides become flatter, so bitumen drainage slows
down.
Steam injection (i.e. energy injection) is controlled by pressure targets, but
there also may be a
hydraulic limit. The steam/water interface is controlled to be between the
steam injector and the
horizontal production well. But when fluids move along the production well
there is a natural
pressure drop that will tilt the water/steam interface (Figure 13). If the
interface floods the steam
injector, we reduce the effective length. If the interface hits the producer,
we short circuit the
process and produce some live steam, reducing process efficiency. With typical
tubulars/pipes,
this can limit well lengths to about 1000m.
SAGD has another interesting feature. Because it is a saturated-steam process
and only latent
heat contributes directly to bitumen heating, if pressure is raised (higher
than native reservoir
pressure) the temperature of saturated-steam is also increased, Bitumen can be
heated to a higher
temperature, viscosity reduced and productivity increased. But, at higher
pressures, the latent
heat content of steam is reduced, so energy efficiency is reduced (SOR
increases). This is a trade
off. But, productivity dominates the economics, so most producers try to run
at the highest
feasible pressures.
For bitumen SAGD, we expect recoveries of about 50 to 70% OBIP and the
residual bitumen in
the steam-swept chamber to be about 10 to 20% of the pore volume, depending on
steam
temperatures (Figure 19). Since about 1990, SAGD has now become the dominant
in situ
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process to recover Canadian bitumen and the production growth is exponential
(Figure 20).
Canada has now exceeded USA EOR steam heavy oil production and it is the world
leader.
The current SAGD process is still similar to the original concept, but there
are still expectations
of future improvements (Figure 21). The improvements are focused on 2 areas ¨
using steam
additives (solvents or non-condensable gases) e.g. Gates (2005) or
improvements/alterations in
SAGD geometry (Sullivan (2010), Kjorholt (2010), Gates (2010)).
2.2 In Situ Combustion (ISC)
In situ combustion (ISC) started with field trials in the 1950's (Ramey
(1970)). ISC was the
-holy grail" of EOR, because it was potentially the low-cost process. Early
applications were for
medium and heavy oils (not bitumen). where the oil had some in situ mobility.
A simple vertical
well was used to inject compressed air that would "push" out heated oil toward
a vertical
production well. The first version of ISC was dry combustion using only
compressed air as an
injectant (Gates (1977)) (Figure 24). A combustion-swept zone is behind the
combustion front.
Downstream of the combustion front, in order, is a vaporizing zone with oil
distillate and
superheated steam, a condensing zone where oil and steam condense and an oil
bank that is
"pushed" by the injectant gas toward a vertical production well. The
vaporizing zone fractionates
oil and pyrolyzes the residue to produce a "coke" that is consumed as the
combustion fuel.
Another version of ISC also emerged, called wet combustion or COFCAW. After a
period of dry
combustion, liquid water was injected with compressed air (or alternating
injection). The idea
was that water would capture heat inventoried in the combustion-swept zone to
produce steam
prior to the combustion front. This would improve productivity and efficiency
(Dietz (1968),
Parrish (1969), Craig (1974)). Figure 31 shows how wet combustion worked,
using the same
simple vertical well geometry as dry combustion. A liquid water zone precedes
the combustion-
swept zone, otherwise the mechanisms are similar to dry ISC as shown in Figure
24. The
operator of a wet combustion process has to be careful not to inject water too
early in the process
or not to inject too much water, or the water zone can overtake the combustion
front and quench
HTO combustion.
The principles of dry and wet ISC were well known in the early days (Doschner
(1966), Ramey
(1970), Chu (1977)). The mechanisms were well documented. It was also
recognized that these
were two kinds of in situ combustion ¨ low temperature oxidation (LTO), from
about 150 to
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300 C, where oxidation is incomplete, some oxygen can break through to the
production well,
organic compounds containing oxygen are formed, acids and emulsions are
produced and the
heat release per unit oxygen injected is lower; and high temperature oxidation
(1-IT0), from
about 400 to 800 C where most (all) oxygen is consumed to produce combustion
gases (CO2,
CO, H20...) and the heat release per unit oxygen consumed is maximized. It was
generally
agreed that HTO was desirable and LTO was undesirable (Butler (1991)). [For
Athabasca
bitumen, LTO is from 150 to 300 C and HTO is from 380 to 800 C (Yang
(2009(2))]. A
screening guide for ISC (Chu(1977)) (() > .22, So > 50%, (I) So > .13, API<
24, pi< 1000cP.)
indicates that ISC, using vertical-well geometry, is best applied to heavy or
medium oils, not
bitumen.
Despite decades of field project trials, ISC has only seen limited success,
for a variety of reasons.
In a 1999 DOE review (Sarathi (1999)), more than half of the North American
field tests of ISC
were deemed "failures". By the turn of the century the total world ISC
projects dropped to 28
(Table 12).
ISC using oxygen or enriched air (ISC(02)) was attempted in a few field
projects. In the 1980's
"hey day" for EOR, there were 10 ISC(02) projects active in North America ¨ 4
in the USA and
6 in Canada (Sarathi (1999)). The advantages of using oxygen were purported as
higher energy
injectivity, production of near-pure CO2 gas as a product of combustion, some
CO2 solubility in
oil to reduce viscosity, sequestration of some CO2, improved combustion
efficiency, better
sweep efficiency and reduced GOR for produced oil. The purported disadvantages
of using
oxygen were safety, corrosion, higher capital costs and 1,TO risks (Sarathi
(1999), Butler
(1991)).
Only a few tests of ISC were undertaken for bitumen recovery using vertical
well geometries.
For a true bitumen (>100,000 c.p in situ viscosity) gas injectivity (air or
oxygen) is very poor.
So, even though bitumen is very reactive and has lower HTO and LTO
temperatures than other
oils and HTO can be sustained at very low oxygen/air flux rates (Figure 25),
bitumen ISC EOR
processes are very difficult. New well geometries using horizontal wells, with
short paths for
bitumen recovery and perhaps a gravity drainage recovery mechanism, can
improve the
prospects for bitumen ISC EOR.
One such process that is currently field testing is the THAI process using a
horizontal production
well and horizontal or vertical air injector wells (Figure 22, Graves (1996),
Petrobank (2009)).
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So far, success has been only limited. Another geometry is shown in Figure 23
for the COSH or
COGD process (New Tech. Magazine (2009)).
Others (Moore 1999, Javad (2001), Be(grave (2007)) have proposed to conduct
bitumen ISC in
the steam-swept gravity drainage chamber produced by a SAGD process, using the
residual
bitumen in the steam-swept zone as ISC fuel after the SAGD process has matured
or reached its
economic limit. These studies have concluded that ISC is feasible for these
conditions.
2.3 Steam + Oxygen
It may be considered that COFCAW (water + air/oxygen injection for ISC) may be
similar to
steam + oxygen processes. ISC using COFCAW and air or oxygen could create
steam + oxygen
or steam +CO2 mixtures when water was vaporized in the combustion-swept zone
prior to (or
after) the combustion front. But, if we have a modern geometry suited to
bitumen recovery, we
have short paths between wells. If liquid water is injected we would have a
serious risk of
quenching FITO reactions. COFCAW works for vertical well geometries (eg.
Parrish (1969))
because of the long distance between injector and producer and the ability to
segregate liquid
water from the combustion zone until it is vaporized.
There is not much literature on steam + oxygen, but steam + CO2 has been
considered for EOR
for some time. Assuming we have good HTO combustion, a steam + oxygen mixture
will
produce a steam + CO2 mixture in the reservoir. Also, there has been some
focus to produce
steam + oxygen or steam + flue gas mixtures using surface or down hole
equipment (Balog
(1982), Wylie (2010), Anderson (2010)). Carbon dioxide can improve steam-only
processes by
providing other mechanisms for recovery ¨ e.g. Solution gas drive or gas drive
mechanisms. For
example, steam + CO2 was evaluated by Balog (1982) for a CSS process, using a
mathematical
simulation model. Compared to steam, steam + CO2 (about 9% (v/v) CO2) improved
productivity
by 35 to 38%, efficiency (OSR) by 49 to 57% and showed considerable CO2
retention in the
reservoir¨about 1.8 MSCF/bbl. heavy oil after 3 CSS cycles.
There have only been a few studies of steam + 02. Combustion tube tests have
been performed
using mixtures of steam and oxygen (Moore (1994)(1999)). The results have been
positive,
showing good HTO combustion, even for very low oxygen concentrations in the
mixture (Figure
28). The combustion was stable and more complete than other oxidant mixes
(Figure 29).
Oxygen concentrations in the mix varied from just under 3% (v/v) to over 12%
(v/v).
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Yang ((2008) (2009(1)) proposed to use steam + oxygen as an alternative to
steam in a SAGD
process. The process was simulated using a modified STARS simulation model,
incorporating
combustion kinetics. Yang demonstrated that for all oxygen mixes, the
combustion zone was
contained in the gas/steam chamber, using residual bitumen as a fuel and the
combustion front
never intersected the steam chamber walls. Figure 30 shows production
forecasts using steam +
oxygen mixtures varying from 0 to 80% (v/v) oxygen. But, the steam/gas chamber
was contained
with no provision to remove non-condensable gases. So, back pressure in the
gas chamber
inhibited gas injection and bitumen production, using steam + oxygen mixtures,
was worse than
steam-only (SAGD) performance (Figure 30). Also, there was no consideration of
the corrosion
issue for steam oxygen injection into a horizontal well, nor was there any
consideration of
minimum oxygen flux rates to initiate and sustain HTO combustion using a long
horizontal well
for 02 injection.
Yang ((2008), 2009(1)) also proposed an alternating steam/oxygen process as an
alternative to
continuous injection of steam + 02 mixes. But, issues of corrosion, minimum
oxygen flux
maintenance, ignition risks and combustion stability, were not addressed.
Bousard (1976) proposed to inject air or oxygen with hot water or steam to
propogate LTO
combustion as a method to inject heat into a heavy oil reservoir. But HTO is
desirable and LTO
is undesirable, as discussed above.
Pfefferle (2008) suggested using oxygen + steam mixtures in a SAGD process, as
a way to
reduce steam demands and to partially upgrade heavy oil. Combustion was
purported to occur at
the bitumen interface (the chamber wall) and combustion temperature was
controlled by
adjusting oxygen concentrations. But, as shown by Yang, combustion will not
occur at the
chamber walls. It will occur inside the steam chamber, using coke produced
from residual
bitumen as a fuel not bitumen from/at the chamber wall. Also, combustion
temperature is almost
independent of oxygen concentration (Butler, 1991). It is dependant on fuel
(coke) lay down
rates by the combustion/pyrolysis process. Pfefferle also suggested oxygen
injection over the full
length of a horizontal well and did not address the issues of corrosion, nor
of maintaining
minimum oxygen flux rates if a long horizontal well is used for injection.
Pfefferle, W.C. "Method for CAGD Recovery of Heavy Oil" US Pat. 2007/0187094
Al, Aug.
16, 2007 describes - a process similar to SAGD to recover heavy oil, using a
steam chamber.
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There are 2 versions described. The first version, injects a steam + oxygen
mixture using a
SAGD steam injector well. The second version injects oxygen into a new
horizontal well,
parallel to the SAGD well pair, but completed in the upper part of the
reservoir. With the
separate oxygen injector, steam is injected into the reservoir from the upper
SAGD well to limit
access of oxygen to the lower SAGD producer. Pfefferle(2007) proposes
combustion occurs at
the chamber walls (i.e. the steam - cold bitumen interface) and that
temperature of combustion
can be controlled by changing oxygen concentrations. It is proposed to
increase combustion
temperatures at the chamber walls sufficiently to crack and upgrade the oil.
But Pfefferle (2007)
(1) doesn't focus on bitumen but uses the term oil or heavy oil.
(2) there is no provision to remove non-condensable gases produced by
combustion
(3) except for the second version of the process, oxygen and steam are not
segregated to
control/minimize corrosion
(4) there is no consideration for a preferred range of oxygen/steam ratios or
oxygen
concentrations
(5) in both cases oxygen injection is spread out over a long horizontal well.
In thc first case
oxygen is also diluted with steam. There is no consideration to limiting
oxygen-reservoir contact
to ensure and control oxygen flux rates.
Pfefferle(2007) alleges that combustion will occur at the steam chamber wall
(claims 1,2,7,9). In
reality this will never occur. Combustion will always occur in the steam-swept
zone, using a
coke fraction of residual bitumen as a fuel. Even without steam injected, a
steam-swept zone will
be formed using connate water from the reservoir. The combustion zone will
always be far away
from the steam chamber walls.
Pfefferle (2007) also alleges that the combustion temperature can be adjusted
by changing the
oxygen concentration (claims 2,7,9). This is not possible. Combustion
temperature is controlled
by the coke concentration in the matrix where combustion occurs. This has been
confirmed by
lab combustion tube tests. Combustion temperatures are substantially
independent of oxygen
concentration at the combustion site.
Finally Pfefferle(2007) also alleges that temperature at the chamber walls can
be controlled by
oxygen concentration (claims 7, 9) even to the extent of cracking and
upgrading oil at the walls.
In view of the discussion above, this will not happen.
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Pfefferle,W.C. "Method for In Situ Combustion of In-Place Oils", US Pat.
7,581,587 B2, Sept. I,
2009 describes a geometry for dry in situ combustion using a vertical well and
a horizontal
production well. The vertical well has a dual completion and is located near
the heel of the
production well. The lower completion in the vertical well is near the
horizontal producer and is
used to inject air for ISC. The concentric upper completion is near the top of
the reservoir and is
used to remove non-condensable gases produced by combustion. Production is
adjusted so the
lower horizontal well is full of liquids (oil + water) at all times. The bleed
well (gas removal
well) may also have a horizontal section. Multiple bleed wells are also
proposed. This is a heel-
to-toe process. Most ISC processes using horizontal producers (eg THAI) are
toe-to-heel
processes. This process is for dry ISC and really doesn't apply to SAGDOX
except, perhaps, for
well configurations.
None of the SAGDOX versions described herein are for heel-to-toe processes.
SAGDOX always
has steam injection. Pfefferle doesn't discuss steam as an additive or as an
option.
There exists therefore a long felt need to provide an effective SAGDOX process
which is energy
efficient and can be utilized to recover bitumen from a reservoir over a
number of years until the
reservoir is depleted.
It is therefore a primary object of the invention to provide a SAGDOX process
wherein oxygen
and steam are injected separately into a bitumen reservoir.
It is a further object of the invention to provide at least one well to vent
produced gases from the
reservoir to control reservoir pressures.
It is yet a further object of the invention to provide production wells
extending a distance of
greater than 1000 metres.
It is yet a further object of the invention to provide oxygen at an amount of
substantially 35%
(v/v) and corresponding steam levels at 65%.
It is yet a further object of the invention to provide oxygen and steam from a
local cogeneration
and air separation unit located proximate a SAGDOX process.
CA 02791323 2012-09-27
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Further and other objects of the invention will be apparent to one skilled in
the art when
considering the following summary of the invention and the more detailed
description of the
preferred embodiments illustrated herein.
SUMMARY OF THE INVENTION
According to a primary aspect of the invention there is provided a process to
recover
hydrocarbons from a hydrocarbon reservoir, namely bitumen (API < 10; in situ
viscosity >
100,000 c.p.), said process comprising;
establishing a horizontal production well in said reservoir;
separately injecting an oxygen-containing gas and steam continuously into the
hydrocarbon
reservoir to cause heated hydrocarbons and water to drain, by gravity, to the
horizontal
production well, the ratio of oxygen/steam injectant gases being controlled in
the range from
0.05 to 1.00 (v/v).
removing non-condensable combustion gases from at least one separate vent-gas
well, which is
established in the reservoir to avoid undesirable pressures in the reservoir.
In one embodiment steam is injected into a horizontal well of the same length
as the production
well, and parallel to said production well with a separation of 4 to 10 m,
directly above the
production well using for example a typical SAGD geometry.
Preferably vertical oxygen injection and vent gas wells are established in the
reservoir.
In another embodiment said vertical wells for oxygen injection and vent gas
removal are not
separate wells but tubing strings are inserted within the existing horizontal
steam injection well
proximate the vertical section of the well, and packers are used to segregate
oxygen injection
and/or vent -gas venting.
Preferably the oxygen-containing gas has an oxygen content of 95 to 99.9%
(v/v). In another
embodiment oxygen-containing gas is enriched air with an oxygen content of 20
to 95% (v/v).
CA 02791323 2012-09-27
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In another embodiment oxygen-containing gas has an oxygen content of 95 to 97%
(v/v).
Alternatively the oxygen-containing gas is air.
In one embodiment said process further comprises an oxygen contact zone
portion of the well
within the reservoir less than 50m long and said zone being implemented by
aspects therein
selected from perforations, slotted liners, and open holes.
In another embodiment the horizontal wells are part of an existing SAGD
recovery process and
incremental SAGDOX wells, for oxygen injection and for non-condensable vent
gas removal,
are added subsequent to SAGD operation.
In another embodiment said process further comprises a SAGDOX process that is
started up by
operating a horizontal well pair in the SAGD process and subsequently
circulating steam in
incremental SAGDOX wells until all the wells are communicating, prior to
starting oxygen
injection and vent gas removal.
Preferably the SAGDOX process is started by circulating steam in all wells
until all the wells are
communicating, prior to starting oxygen injection and vent gas removal.
In another embodiment a SAGDOX process is controlled and operated by steps
selected from:
i. Adjusting steam and oxygen flows to attain a predetermined; oxygen/steam
ratio and
energy injection rate targets,
ii. Adjusting vent gas removal rates to control process pressures and to
improve/control
conformance,
iii. Controlling bitumen and water production rates to attain sub-cool
targets, assuming
fluids close to the production well are steam-saturated (steam trap control).
Steam trap control (also called sub cool control) for steam EOR or SAGDOX is
used to control
the production well rate so that only liquids (bitumen and water) are produced
, not steam or
other gases. The way this is done is as follows:
(1) it is assumed that the region around the well is predominantly saturated
steam. For SAGD
this is easy since steam is the only injectant. For SAGDOX this means that
noncondesable gases
produced from combustion are near the top of the reservoir away from the
production well. This
has been confirmed by several lab tests and some field tests.
CA 02791323 2012-09-27
14
(2) pressure is measured either at the steam injection well or at the
production well. Saturated
steam T is calculated using the measured pressure.
(3) the production well fluid production rate is controlled (pump or gas lift
rates) so that the
average T (or heel T) is less than the saturated steam T calculated, usually
by 10 to 20 C of sub
cool.
Preferably oxygen/steam ratios start at about 0.05 (v/v) and ramp up to about
1.00 (v/v) as the
process matures.
In a preferred embodiment the oxygen/steam ratio is between 0.4 and 0.7 (v/v).
Preferably when SAGDOX is implemented the horizontal well length of the
pattern is extended
when compared to an original SAGD design.
In one example the horizontal well length extends beyond 1000 m.
In one embodiment the process further comprises conversion of a mature SAGD
project whereat
adjacent patterns are in communication, to a SAGDOX project using 3 adjacent
patterns where
the steam injector of the central pattern is converted to an oxygen injector
and the injector wells
of the peripheral patterns arc continued to be used as steam injectors.
Preferably the oxygen/steam ratio is between 0.05 and 1.00 (v/v). Preferably
the gases are
produced, as separate streams, by an integrated ASU: Cogen Plant.
In another embodiment further process steps are selected from:
I. The ratio of oxygen/steam is between 0.4 and 0.7 (v/v),
ii. The oxygen purity in the oxygen-containing gas is between 95 and 97%
(v/v),
iii. Steam and oxygen are produced in an integrated ASU: Cogen plant,
iv. The oxygen contact zone with the reservoir is less than 50 m.
In another preferred embodiment of the process the oxygen injection well is no
more than 50 m.
of contact with the reservoir, to avoid oxygen flux rates dropping to less
than that needed to start
ignition or to sustain combustion.
CA 02791323 2012-09-27
15
In a further preferred embodiment of the process steam provides energy
directly to the reservoir
and oxygen provides energy by combusting residual bitumen (coke) in the steam
chamber
whereat the combustion zone is contained; residual bitumen being heated,
fractionated and
finally pyrolyzed by hot combustion gases, to make coke, the actual fuel for
combustion.
Preferably the bitumen and water production well is controlled assuming
saturated conditions
using steam-trap control, without producing significant amounts of live steam,
non-condensable
combustion gases or unused oxygen.
In another embodiment the steam-swept zone of the steam chamber in a SAGDOX
process
further comprises;
a combustion-swept zone with substantially zero residual bitumen and connate
water,
a combustion front,
a bank of bitumen heated by combustion gases,
a superheated steam zone,
a saturated-steam zone, and
a gas/steam bitumen interface or chamber wall where steam condenses and
releases latent heat.
In one embodiment:
bitumen drains, by gravity, from a hot bitumen bank and from a bitumen
interface,
water drains, by gravity, from a saturated steam zone and from the bitumen
interface, and
energy (heat) in the hot bitumen and in the superheated-steam zone is
partially used to reflux
some steam. The fuel for combustion and the source of bitumen in the hot
bitumen zone is
residual bitumen in the steam-swept zone, combustion being contained inside of
the steam
chamber and preferably wherein hot combustion gases transfer heat to bitumen,
in addition to
steam mechanisms.
In another embodiment carbon dioxide, produced as a combustion product, can
dissolve into
bitumen and reduce viscosity.
In an alternative embodiment oxygen purity is reduced to substantially the 95-
97% range
whereat energy needed to produce oxygen from an ASU drops by about 25% and
SAGDOX
efficiencies improve significantly.
CA 02791323 2012-09-27
16
In a preferred embodiment of the process the SAGDOX process uses water
directly as steam is
injected, but it also produces water directly from 2 sources, namely water
produced as a
combustion product and connate water vaporized in the combustion-swept zone.
Preferably the maximum oxygen/steam ratio is 1.00 (v/v) with an oxygen
concentration of
50.0%.
In another embodiment of the process as a SAGDOX process matures, the
combustion front will
move further away from the oxygen injector and requires increasing oxygen
rates to sustain High
Temperature Oxidation reactions.
Preferably the SAGDOX gas mix is between 20 and 50% (v/v), oxygen in the
steam/oxygen
mixture.
More preferably the SAGDOX gas mix is 35% oxygen (v/v), oxygen in the
steam/oxygen
mixture.
In a preferred embodiment the oxygen injection point needs to be preheated to
about 200 C so
oxygen will spontaneously react with residual fuel.
According to yet another aspect of the invention there is provided a method of
starting up of a
SAGDOX process described herein comprising the following steps:
1. Start oxygen injection and reduce steam flow to achieve a proscribed oxygen
concentration target at the same energy rates as SAGD,
2. as reservoir pressures approach a target pressure, partially open one (or
more) produced
gas (PG) removal wells to remove non-condensable combustion gases and to
control P.
3. If split/multiple PG wells are provided adjust PG removal rates to
improve/optimize 02
conformance,
4. If oxygen gas is present in PG removal well gas, the well should be choked
back or
shut in,
5. If non-condensable gas (CO2. CO, 02...) is present in the horizontal
producer fluids,
the production rate should be slowed and/or oxygen conformance adjusted and/or
PG
removal rates increased.
CA 02791323 2012-09-27
BRIEF DESCRIPTION OF THE FIGURES17
Figure 1 is a SAGD Geometry.
Figure 2 is a SAGD Production Simulation.
Figure 3 is a SAGDOX Geometry 1.
Figures 3A through 3E provide additional details of SAGDOX geometry regarding
Figure 3.
Figure 4 is a SAGDOX Bitumen Saturation Schematic.
Figure 5 is a SAGDOX Geometry 2.
Figure 6 is a SAGDOX Geometry 3.
Figure 7 is a SAGDOX Geometry 4.
Figure 8 is a SAGDOX Geometry 5.
Figure 9 is a SAGDOX Geometry 6.
Figure 10 is a SAGDOX Geometry 7.
Figure 11 is a SAGDOX Geometry 8.
Figure 12 is a SAGDOX Geometry 9.
Figurc 13 is a SAGD Hydraulic Limits.
Figure 14 is a SAGD/SAGDOX Pattern Extension.
Figure 15 is a SAGDOX ¨ 3 well-pair pattern.
Figure 16 is a Cogen Electricity Production (Cogen/ASU).
CA 02791323 2012-09-27
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Figure 16A is a schematic representation of an integral ASU & COGEN for a
SAGDOX process.
Figure 17 is a SAGD Steam Chamber.
Figure 18 is SAGD stages.
Figure 19 is a Residual Bitumen in Steam-Swept Zones.
Figure 20 is a SAGD Production History.
Figure 21 is SAGD Technology.
Figure 22 is the THAI Process.
Figure 23 is COSH, COGD Processes.
Figure 24 is an In situ Combustion Schematic.
Figure 25 is 1SC Minimum Air Flux Rates.
Figure 26 is CSS using Steam + CO2: Production.
Figure 27 is CSS using Steam + CO2: Gas Retention (9% CO2 in steam mix).
Figure 28 is Steam + Oxygen Combustion Tube Tests 1.
Figure 29 is Steam + Oxygen Combustion Tube Tests II.
Figure 30 is SAGD using Steam + Oxygen mixes.
Figure 31 is a Wet ISC.
CA 02791323 2012-09-27
19
DETAILED DESCRIPTION OF THE INVENTION
Problems Solved
3.1 SAGD Problems
(1) Steam is costly
(2) SAGD uses a lot of water (0.25 to 0.50 bbl water/bbl bitumen)
(3) Production well (bitumen + water) pressure gradients can limit SAGD
productivity and
energy (steam) injectivity. For a typical horizontal well length of 1000 m.,
using a
typical tubing/pipe sizes fluid productivity is limited to about 4000 bbl/d,
otherwise the
liquid/gas interface (steam/water) can flood the toe of the steam injector
and/or steam
can break through to the producer heel. Alternately for the above production
rates, the
effective well length is limited to about 1000 m, so the pattern size is also
limited. If the
well separation is increased from say 5 to 10 meters, the effective well
length (or
injectivity) can be increased, but the start up period is prolonged
significantly. If
well/pipe sizes are increased to increase well length or injectivity, capital
costs and heat
losses are increased.
(4) Carbon dioxide emissions from SAGD steam boilers are significant (about
0.08 tonnes
CO2/bbl bitumen). The emitted CO2 is not easily captured for sequestration. It
is diluted
in boiler flue gas, or in cogen flue gas.
(5) Steam cannot be economically transported for more than about 5 miles. A
central steam
plant can only service a limited area.
(6) SAGD is a steam-only, saturated-steam process. Temperature is determined
by
operating pressure
(7) SAGD cannot mobilize connate water by vaporization.
(8) SAGD cannot reflux steam/water in the reservoir. It is a once-through
water process.
(9) SAGD, in the steam-swept zone, leaves behind (not recoverable) 10 to 20%
(v/v) of the
pore volume as residual bitumen.
(10) When SAGD reaches its economic limit, zones of unswept reservoir ("wedge
oil") are
not recovered.
(11) If we measure energy efficiency as the percentage of net energy produced,
considering
energy used on the surface to produce bitumen and the fuel value of the
bitumen
produced, SAGD is relatively inefficient.
CA 02791323 2012-09-27
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3.2 SAGDOX Problems
(1) Mixtures of saturated steam and oxygen are very corrosive to carbon steel
and other
alloys. New wells or a segregation system are needed to keep oxygen and steam
separated prior to injection into the reservoir.
(2) One suggestion (Yang (2009)) is to use the SAGD steam injector well for
alternating
volumes of steam and oxygen. But to sustain HTO combustion we need a constant
supply and a minimum flux of oxygen, otherwise we will breakthrough oxygen to
producer wells or start LTO combustion.
(3) It has also been suggested (Yang (2009), Pfefferle (2008)) that we can
simply mix
oxygen with steam and use the horizontal steam injector for SAGD. Aside from
severe
corrosion issues noted above (1), oxygen flux rates are a concern. If oxygen
is mixed
with steam and injected in a horizontal well, oxygen flux is diluted over the
length of
the horizontal well (-1000m.) Flux of oxygen, in some areas, may be too low to
initiate
and sustain HTO combustion. Even if average flux rates are satisfactory,
inhomogeneities in the reservoir may cause some areas to be depleted in
oxygen. As a
result, oxygen breaks through to production wells or low flux oxygen can
result in [TO
oxidation.
(4) Separate control of oxygen and steam rates is needed to adjust energy
input rates and
relative contributions from each component.
(5) Oxygen needs to be injected, at first, into (or near to) a steam- swept
zone, so
combustion of residual fuel components occurs and injectivity is not a serious
limit.
The zone also needs to be preheated (at start-up) so spontaneous HTO ignition
occurs
(not [TO).
(6) The well configuration should ensure that oxygen (and steam) is mostly
contained
within the well pattern volume.
(7) If new SAGDOX wells are too far away from the steam-swept zone, start-up
time to
transition from SAGD to SAGDOX can be prolonged. Because SAGDOX energy is
less costly than SAGD, it is desirable to start SAGDOX quickly.
How to shut down a SAGDOX process
Since oxygen is much less costly than steam as a way to provide energy to a
bitumen reservoir
for EOR and during normal SAGDOX operations we have built up a large inventory
of steam in
CA 02791323 2012-09-27
21
the reservoir, when the process reaches its economic limit (i.e. when oxygen 4
steam costs =
produced bitumen value) the following shut down procedure is suggested:
(1) shut off steam injection
(2) continue to inject 02 at previous rates
(3) continue to use sub-cool control for the production well
(4) when the process reaches its new economic limit (when 02 cost = produced
bitumen
value) shut in the oxygen injector
(5) continue to produce bitumen until production rates fall below a
predetermined target (eg
bbls/d)
SAGDOX Technical Description
4.1 SAGD Simulation
SAGD is a process that uses 2 parallel horizontal wells separated by about 5
m., each up to about
1000 m. long, with the lower horizontal well (the bitumen + water producer)
about 2 to 8 m.
above the bottom of the reservoir (see Figure 1). After a startup period where
steam is circulated
in each well to attain communication between the wells, steam is injected into
the upper
horizontal well and bitumen + water are produced from the lower horizontal
well.
We have simulated a SAGD process using the following assumptions:
(1) A homogeneous sandstone (or sand) reservoir containing bitumen
(2) Generic properties for an Athabasca bitumen
(3) 25 m homogeneous pay zone
(4) 800 m. SAGD well pair at 100 m spacing, with 5 m spacing between the
parallel
horizontal wells
(5) 10 C sub cool for production control (i.e. produced fluids are 10 C lower
than
saturated-steam '1' at reservoir P)
(6) 2 MPa pressure for injection control
(7) 4 mos. steam circulation prior to SAGD start-up
