CA2791323A1 - Steam assisted gravity drainage processes with the addition of oxygen addition - Google Patents

Abstract

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 into the hydrocarbon reservoir continuously 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.

Description

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

2 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, = 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, = 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.

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, = 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

3 = 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.

= 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

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)

4 = 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.

5 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

6 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

7 300 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)).

8 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).

9 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.

10 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.

II
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.

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).

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.

(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.

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.

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.

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).

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.

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.

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 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

Claims (36)

Claims

1. 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 into the hydrocarbon reservoir continuously 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.

2 The process of claim 1 wherein 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.

3. The process of claim 1 or 2 wherein vertical oxygen injection and vent gas wells are established in the reservoir.

4. The process of claim 3 wherein 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.

5. The process of claims 1, 2 or 3 wherein the oxygen-containing gas has an oxygen content of 95 to 99.9% (v/v).

6. The process of claims 1, 2, or 3 wherein the oxygen-containing gas is enriched air with an oxygen content of 20 to 95% (v/v).

7. The process of claims 1, 2 or 3 wherein the oxygen-containing gas has an oxygen content of 95 to 97% (v/v).

8. The process of claims 1, 2 or 3 wherein the oxygen-containing gas is air.

9. The process of claims 1, 2 or 3 further comprising an oxygen contact zone portion of the well within the reservoir less than 50 m long and said zone being implemented by aspects therein selected from perforations, slotted liners, and open holes.

10. The process of claim 2 where 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.

11. The process of claim 2 or 9 further comprising 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.

12. The process of claim 1 or 3 where a 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.

13. The process of claims 1, 2 or 3 where 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).

14. The process of claims 1, 2 or 3 wherein oxygen/steam ratios start at about 0.05 (v/v) and ramp up to about 1.00 (v/v) as the process matures.

15. The process of claims I, 2 or 3 wherein the oxygen/steam ratio is between 0.4 and 0.7 (v/v).

16. The process of claim 2 or 9 where SAGDOX is implemented and the horizontal well length of the pattern is extended when compared to an original SAGD design.

17. The process of claim 16 wherein the horizontal well length extends beyond 1000m.

18. The process of claim 10, 11 or 16 further comprising conversion of a mature SAGD
project whereat adjacent patterns are in communication, to a SAGDOX project using three adjacent patterns where the steam injector of the central pattern is converted to an oxygen injector and the injector wells of the peripheral patterns are continued to be used as steam injectors.

19. The process of claims 1, 2 or 3 wherein the oxygen/steam ratio is between 0.25 and 1.00 (v/v) and the gases are produced, as separate streams, by an integrated ASU:
Cogen Plant.

20. The process of claims I, 2 or 3 wherein 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.

21. The process of claim 9 wherein the oxygen injection well is no more than 50m of contact with the reservoir, to avoid oxygen flux rates dropping to less than that needed to start ignition or to sustain combustion.

22. The process of claim 21 wherein steam provides energy directly to the reservoir and the combustion zone is contained; residual bitumen being heated, fractionated and finally pyrolyze by hot combustion gases, to make coke, the actual fuel for combustion.

23. The process of claims 1, 2, 3, 9 or 22 wherein 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.

24. The process of claims 1, 2, 3, 9 or 22 wherein 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.

25. The process of claim 24 wherein;

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.

26. The process of claim 25 wherein 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.

27. The process of claim 26 wherein hot combustion gases transfer heat to bitumen, in addition to steam mechanisms.

28. The process of claim 26 wherein carbon dioxide, produced as a combustion product, can dissolve into bitumen and reduce viscosity.

29.

the 95-97% range whereat energy needed to produce oxygen from an ASU drops by about 25%
The process of claims 1, 2, 3, 9 or 22 wherein oxygen purity is reduced to substantially and SAGDOX efficiencies improve significantly.

30. The process of claims 1, 2, 3, 9 or 22 wherein 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.

31. The process of claim 14 wherein the maximum oxygen/steam ratio is 1.00 (v/v) with an oxygen concentration of 50.0%.

32. The process of claims 1, 2, 3, 9 or 22 wherein 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.

33. The process of claims 1, 2, 3, 9 or 22 wherein the SAGDOX gas mix is between 20 and 50% (v/v), oxygen in the steam/oxygen mixture.

34. The process of claim 33 wherein the SAGDOX gas mix is 35% oxygen (v/v), oxygen in the steam/oxygen mixture.

35. The process of claims 1, 2, 3, 9 or 22 wherein the oxygen injection point needs to be preheated to about 200 C so oxygen will spontaneously react with residual fuel.

36. A method of starting up of a SAGDOX process according to claims 1, 2, 3, 9 or 22 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, O2...) is present in the horizontal producer fluids, the production rate should be slowed and/or oxygen conformance adjusted and/or PG removal rates increased.