EXTENDED REACH STEAM ASSISTED GRAVITY DRAINAGE WITH OXYGEN ("ERSAGDOX")

Abstract

A process to recover hydrocarbons from a reservoir, where the hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, the process including: (a) Initially injecting oxygen into the reservoir; (b) Allowing for combustion of the oxygen to vaporize connate water in the hydrocarbon reservoir; (c) Collecting hydrocarbons in a substantially horizontal production well in the reservoir and where the substantially horizontal production well has a length greater than about 800 metres.

Description

BACKGROUND OF THE INVENTION

The bitumen resources in Alberta, Canada, are one of the world's largest liquid hydrocarbon deposits. The total resource that can potentially be exploited by thermal enhanced oil recovery (“EOR”) is about 1.4 trillion bbls. About 40% of this resource can be exploited using existing developed technology, such as Steam Assisted Gravity Drainage (“SAGD”) or Cyclic Steam Stimulation (“CSS”). But the remaining 60% cannot be exploited using known technology. Table 1 shows two other resources that could potentially be developed and exploited using thermal EOR—carbonate bitumen at 448 billion bbls and thin-pay bitumen at 410 billion bbls.

Steam Assisted Gravity Drainage (“SAGD”) is a commercial thermal enhanced oil recovery (“EOR”) process, using saturated steam injected into a horizontal well, where latent heat is used to heat bitumen and lower its viscosity so it drains, by gravity, to an underlying, parallel, twin horizontal well, completed near the reservoir floor.

Since the process inception in the early 1980's, SAGD has become the dominant, in situ process to recover bitumen from Alberta's bitumen deposits (Butler, R., “Thermal Recovery of Oil & Bitumen”, Prentice-Hall, 1991). Today's SAGD bitumen production in Alberta is about 300 Kbbl/d with installed capacity at about 475 Kbbl/d (Oilsands Review, 2010). SAGD is now the world's leading thermal EOR process.

FIGS. 1A and 1B (Prior Art) show the traditional SAGD geometry, using twin, parallel, horizontal wells 2,4 drilled in the same vertical plane, with a 5 metre spacing between the upper 2 and lower 4 wells, each well being about 800 metres long, and with the lower well 1 to 2 metres above the (horizontal) reservoir floor. Circulating steam 6 in both wells starts the SAGD process. After communication is established, the upper well 2 is used to inject steam 6 and the lower well 4 produces hot water and hot bitumen 8. Liquid production is accomplished by natural lift, gas lift, or submersible pump.

After conversion to normal SAGD operations, a steam chamber forms, around the injection 2 and production 4 wells, where the void space is occupied by steam 6. Steam condenses at the boundaries of the chamber, releases latent heat (heat of condensation) and heats bitumen, connate water and the reservoir matrix. Heated bitumen and water drain, by gravity, to the lower production well 4. The steam chamber grows upward and outward as bitumen is drained, by gravity, into the lower production well 4.

FIGS. 2A-2D (Prior Art) show how SAGD matures. A young steam chamber 10 has bitumen drainage from steep chamber sides and from the chamber ceiling. When the chamber growth hits the top of the reservoir, ceiling drainage stops, bitumen productivity peaks and the slope of the side walls decreases as lateral growth continues. Heat losses increase (steam to oil ratio (“SOR”) increases) as ceiling contact increases and the surface area of the steam chamber increases. Drainage rates slow down as the side wall angle decreases. Eventually, the economic limit is reached and the end-of-life drainage angle is small (10-20°), as shown in FIG. 2.

Produced fluids are near saturated steam temperature, so it is only the latent heat of steam that contributes to the process in the reservoir. But, some of the sensible heat can be captured from surface heat exchangers (a greater fraction at higher temperatures), so a useful rule-of-thumb for net heat contribution of steam is 1000 BTU/lb. for the pressure (“P”) and temperature (“T”) range of most SAGD projects, as best seen in FIG. 3 (Prior Art).

The operational performance of SAGD may be characterized by measurement of the following parameters: saturated steam pressure (“P”) and temperature (“T”) in the steam chamber, as best seen in FIG. 4 (Prior Art); bitumen productivity; SOR, usually at the well head; sub-cool—the T difference between saturated steam and produced fluids; and WRR—the ratio of produced water to steam injected (also known as the water recycle ratio).

During the SAGD process, the SAGD operator has two choices to make—the sub-cool target T difference and the operating pressure in the reservoir. A typical sub-cool target of about 10 to 30° C. is meant to ensure no live steam breaks through to the production well. Process pressure and temperature are linked (FIG. 4) and relate mostly to bitumen productivity and process efficiency. Bitumen viscosity is a strong function of temperature, as best seen in FIG. 5 (Prior Art). SAGD productivity is proportional to the square root of the inverse viscosity, as seen in FIG. 6 (Prior Art) (Butler (1991)). But, conversely if P (and T) is increased, the latent heat content of steam drops rapidly (FIG. 3) and more energy is used to heat the rock matrix as well as lost to the overburden or other non-productive areas. Increased pressure increases bitumen productivity but harms process efficiency (increases SOR). Because economic returns can be dominated by bitumen productivity, the SAGD operator typically opts to target operating pressures higher than native, hydrostatic reservoir pressures.

Despite becoming the dominant thermal EOR process, SAGD has some limitations and detractions. A good SAGD project includes:

• • a horizontal well is completed near the bottom of the pay zone to effectively collect and produce hot draining fluids;
  • injected steam, at the sand face, has a high quality;
  • process start up is effective and expedient;
  • the steam chamber grows smoothly and is contained;
  • the reservoir matrix is good quality (porosity Φ>0.2, initial oil saturation S_io>0.6, vertical permeability k_v>2D);
  • net pay is sufficient (>15 metres);
  • proper design and control to simultaneously prevent steam breakthrough, prevent injector flooding, stimulate steam chamber growth to productive zones and inhibit water inflows to the steam chamber; and
  • absence of significant reservoir baffles (e.g. lean zones) or barriers (e.g. shale).

If these characteristics are not attained or other limitations are experienced, SAGD may be impaired, as follows:

• • (1) The preferred dominant production mechanism is gravity drainage and the lower production well is horizontal. If the reservoir is highly slanted, a horizontal production well will strand a significant resource. In other words, bitumen under the horizontal well is not recoverable.
  • (2) The SAGD steam-swept zone has significant residual bitumen content that is not recovered, particularly for heavier bitumens and low-pressure steam as best seen in FIG. 7 (Prior Art). For example with a 20% residual bitumen (pore saturation) and a 70% initial saturation, the recovery factor is only 71%, not including stranded bitumen below the production well or in the wedge zone between recovery patterns.
  • (3) To “contain” a SAGD steam chamber, the oil in the reservoir must be relatively immobile. SAGD cannot work on heavy (or light) oils with some mobility at reservoir conditions. Bitumen is the preferred target.
  • (4) Saturated steam cannot vaporize connate water. By definition, the heat energy in saturated steam is not high enough quality (temperature) to vaporize water. Field experience also shows that heated connate water is not mobilized sufficiently to be produced in SAGD. Produced water to oil ratio (“WOR”) is similar to SOR. This makes it difficult for SAGD to breach or utilize lean zone resources.
  • (5) The existence of an active water zone—either top water, bottom water, or an interspersed lean zone within the pay zone—can cause operations difficulties for SAGD or ultimately can cause project failures (Nexen Inc., ‘Second Quarter Results”, Aug. 4, 2011) (Vanderklippe, N., “Long Lake Project Hits Sticky Patch”, CTV, 2011). Simulation studies concluded that increasing production well stand-off distances may optimize SAGD performance with active bottom waters, including good pressure control to minimize water influx (Akram, F., “Reservoir Simulation Optimizes SAGD, American Oil and Gas Reporter, September 2011).
  • (6) Pressure targets cannot (always) be increased to improve SAGD productivity and SAGD economics. If the reservoir is “leaky”, as pressure is increased beyond native hydrostatic pressures, the SAGD process can lose water or steam to zones outside the SAGD steam chamber. If liquids are lost, the WRR decreases and the process requires significant water make-up volumes. If steam is also lost, process efficiency drops and SOR increases. Ultimately, if pressures are too high, if the reservoir is shallow and if the high pressure is retained for too long, a surface break through of steam, sand and water can occur (Roche, P., “Beyond Steam”, New Tech. Mag., September 2011).
  • (7) Steam costs are considerable. If steam costs are over-the-fence for a utility, including capital charges and some profits, the costs for high-quality steam at the sand face is about $10 to 15/MMBTU. High steam costs can reflect on resource quality limits and on ultimate recovery factors.
  • (8) Water use is significant. Assuming SOR=3, WRR=1 and a 90% yield of produced water treatment (i.e. recycle), a typical SAGD water use is 0.3 bbls of make-up water per bbl of bitumen produced.
  • (9) SAGD process efficiency is “poor” and CO₂ emissions are significant. If SAGD efficiency is defined as [(bitumen energy)−(surface energy used)]/(bitumen energy) and bitumen energy=6 MMBTU/bbl; energy used at sand face=1 MMBTU/bbl bitumen (SOR ˜3); steam is produced in a gas-fired boiler at 85% efficiency; there are heat losses of 10% each in distribution to the well head and delivery from the well head to the sand face; usable steam energy is 1000 BTU/lb (FIG. 3) and boiler fuel is methane at 1000 BTU/SCF; then the SAGD process efficiency=75.5% and CO₂ emissions=0.077 tonnes/bbl bitumen.
  • (10) Steam distribution distance is limited to about 10 to 15 km (6 to 9 miles) due to heat losses, pressure losses and the cost of insulated distribution steam pipes (Finan, A., “Integration of Nuclear Power . . . ”, MIT thesis, June 2007) (Energy Alberta Corp., “Nuclear Energy . . . ”, Canadian Heavy Oil Association pres., Nov. 2, 2006).
  • (11) Lastly, there is a “natural” hydraulic limit that restricts well lengths or well diameters and can override pressure targets for SAGD operations. FIGS. 8A and 8B show what can and has happened. In SAGD, a steam/liquid interface 12 is formed. For a good SAGD operation, with sub-cool control, the interface is between the injector 2 and producer 4 wells. The interface is tilted because of the pressure drop in the production well 4 due to fluid flow. There is little/no pressure differential in the steam/gas chamber. If the liquid production rates are too high (or if the production well 4 is too small) the interface can be tilted so that the toe of the steam injector 14 is flooded and/or the heel of the producer 16 is exposed to steam breakthrough (FIGS. 8A and 8B). This limitation can occur when the pressure drop in the production well 4 exceeds the hydrostatic head between steam injector 2 and liquids producer 4 (about 8 psi (50 kPa) for a 5 metre spacing).

The simple SAGD control strategy (to inject steam to meet a pressure target and produce liquids to meet a sub-cool target) may be overridden if the system is constrained by hydraulic limits in the horizontal production well 4.

When SAGD is producing fluids near their maximum rates, hydraulic limitations may constrain operations. The steam chamber is well-developed. Pressures within the steam chamber are near constant, even though there can be a significant pressure drop in the steam injection well (Parappilly, R. & Zhao, L., “SAGD with a Longer Wellbore”, JCPT, June 2009). The injector pressure drop is mostly used to distribute steam injection evenly down the well length. Because steam is a gas with low viscosity and the steam chamber has a very high permeability, steam chamber pressures equilibrate rapidly.

The production well is a different story. Steam-trap (sub-cool) control ensures (or is intended to ensure) that liquids (water and bitumen) cover the horizontal production well so that steam breakthrough to the well is prevented. Ideally, the liquid/steam interface 12 would lay between the horizontal producer 4 and the horizontal injector 2. If the wells were shut-in, the steam/liquid interface 12 would form a horizontal plane between the two wells. At steady-state production, even though gas (steam) pressures are equilibrated, the interface 12 is tilted because the liquids are in direct contact with the production well 4, and there is a natural pressure drop in the well due to production flow down the length of the well. This pressure drop is present for each of natural lift, gas lift, or submersible pump. For draw-down at the well heel, the lowest pressure is near the heel, and the tilted interface has its high point at the well toe (FIGS. 8A and 8B).

If liquid production rates and pressure drops are too high, the top of the interface 12 can cover (flood) the toe of the steam injector 14 and/or the heel of the production well 16 can be opened to the steam chamber (FIGS. 8A and 8B). This can reduce the productivity and efficiency of the process by reducing the effective length of the steam injector 2 (harming steam conformance) and allowing steam breakthrough to the heel of the producer 16 (reducing productivity and efficiency). If caught early enough, both effects can be reversed by reducing liquid production rates and reducing steam injection rates, thus overriding normal SAGD operational strategy. Flooding the toe of the steam injector 14 inflicts no permanent damage. But, because the McMurray formation is mostly unconsolidated, steam bypass can mobilize sand particles and erode steal pipe causing permanent damage to the production well at its most vulnerable site.

FIGS. 8A and 8B show the steam/liquid interface 12 as a sloped straight line in 2D (or a tilted plane in 3D) for a steady-state, mature SAGD operation. Even for a homogeneous reservoir, this is a simplistic view. It may be accurate if the production well 4 was a closed, horizontal pipe. But, the well allows fluid inflow down the length of the well, using slotted liners or other orifice systems. As best seen in FIGS. 9A and 9B, a curved interface 12 and non-linear pressure distribution is expected. Most of the pressure drop occurs in the area where drawdown is located. For an inhomogeneous reservoir, steam/liquid interface patterns are complex.

Because the expected interface 12 is mostly flat, except near the drawdown site (FIGS. 9A and 9B), there is no significant advantage (related to hydraulic limitations in the production well) for completing horizontal wells on a slant to match slanted pay zones.

The rule-of-thumb for proper SAGD operation, to obviate potential hydraulic limitations, is that the pressure drop in the production well 4, due to liquid flow, should not exceed the hydrostatic head between the injection 2 and production well 4 locations. For a 5 metre well spacing, the hydrostatic head is about 50 KPa or 8 psi. Unfortunately, few SAGD operators can accurately measure these pressure drops.

Well trajectory variations may also affect hydraulic limits. As best seen in FIGS. 10A-10C, if the steam injector 2 well dips off and if the liquid production well 4 peaks, there can be further limitations. For example, if there is a high spot in the producer well 4 and a steam breakthrough zone is created, the toe of the producer well is isolated from producing bitumen. In another case, if there is a low spot in the injector well 2, an injector flooding zone is created along the injector well 2, hampering steam injection in the toe of the injector well 2. In such cases, the rule-of-thumb for good operation is modified so that the pressure drop in the production well 4 can't exceed the hydrostatic head for the minimum distance between the injector well 2 and the producer well 4.

From an operational standpoint the way to ameliorate hydraulic limitations is to reduce production rates (and steam injection) until pressure drops in the production well are within allowed limits. This can also be accomplished by increasing sub-cool targets.

From a design standpoint, increasing injector/producer separation, increasing pipe/tubing size, or decreasing horizontal well lengths may avoid hydraulic limitations. Each of these remedies has an economic penalty. Increased well spacing extends start-up times and reduces early bitumen productivity. Increased pipe/tubing sizes increases capital and drilling costs. Decreased well lengths reduce bitumen productivity.

With about 5 metre spacing between the injector well 2 and the producer well 4, industry has settled on horizontal well lengths of about 500 to 1000 metres. (Parappilly (2009), (Das, S., “Wellbore Hydraulics in a SAGD Well Pair” SPE 97922, November 2005), (Cenovus, “Telephone Lake Project”, website, December 2011), (Komery, D. et al, “Pilot Testing of Post-Steam Bitumen Recovery from Mature SAGD Wells in Canada”, University of Alberta Web, Feb. 14, 1998), (JACOS, “JACOS Hangingstone Expansion Project”, website, April 2010). Standard well lengths are about 500 to 800 m. (Cenovus (2011), JACOS (2010)).

Typical liner sizes for horizontal SAGD producers are about 7 inches in diameter (Smith, M., “SAGD Simplified”, New Tech Mag., Jun. 1, 2012). One study investigated SAGD well length extension feasibility using a well bore flow model (Q Flow) and a SAGD simulator (STARS-Steam, Thermal, and Advanced Process Reservoir Simulator) (Parappilly (2009)). The study concluded that well lengths of 1400 metres were feasible, if production well liner size was increased to 9% inches and if the pressure drop in the producer well was held to less than 50 KPa (Ross, E., “Going the Distance”, New Tech Mag., December 2008 (2012)).

The dominant process today is SAGD, using twin horizontal wells 2,4 to inject steam 6 and produce bitumen and water 8. But, SAGD has a hydraulic limitation that restricts well length to about 1000 metres, due to pressure drops in the production well.

Accordingly, there is a need for a process which overcomes the well length of prior art processes without hitting hydraulic limits, and preferably while maintaining productivity levels.

SUMMARY OF THE INVENTION

According to one aspect, a process to recover hydrocarbons from a reservoir is disclosed, where said hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, said process comprising:

• • (a) initially injecting oxygen into said reservoir;
  • (b) allowing for combustion of said oxygen to vaporize connate water in said hydrocarbon reservoir;
  • (c) collecting hydrocarbons in a substantially horizontal production well in said reservoir and where said substantially horizontal production well has a length greater than about 800 metres.

In one embodiment, the process further comprises initial steam injection into the reservoir then terminating said steam injection, where the ratio of oxygen to steam injected is controlled in the range from 0.05 to 1.00 (v/v).

In another aspect, a steam assisted gravity drainage with oxygen system for recovery of hydrocarbons from a reservoir is disclosed, where said hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, said system comprising:

• • (a) A first well for capturing said hydrocarbons, having a toe and a heel and a length greater than about 800 metres, said first well being substantially horizontal and at a first depth;
  • (b) A second well within said hydrocarbon containing reservoir, having a length greater than about 800 metres, for injection of oxygen into said hydrocarbon containing reservoir, being at second depth said second depth shallower than said first depth;
  • (c) Said second well being located proximate said toe of said first well; and
  • (d) A vent gas means for venting any gas produced in said reservoir.

In one embodiment of the system, the vent gas means is single or multiple vertical wells. In another embodiment of the system, at least one vent gas means is a segregated annulus section in the heel rise section of the substantially horizontal well.

A further aspect is a steam assisted gravity drainage with oxygen system for recovery of hydrocarbons from a reservoir, where said hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, said system comprising:

• • (a) A first well, having a toe and a heel and a length greater than about 800 metres, said first well within said hydrocarbon containing reservoir, for capturing said hydrocarbons;
  • (b) A second well within said hydrocarbon containing reservoir, having a length greater than about 800 metres, for injection of oxygen and steam into said hydrocarbon containing reservoir;
  • (c) Said second well being located proximate said toe of said first well; and
  • (d) At least one vent gas means for venting any gas produced in said reservoir.

In one embodiment of the system, the vent gas means is single or multiple vertical wells.

In a further embodiment of the system, at least one vent gas means is a segregated annulus section in the heel rise section of the substantially horizontal well.

In yet another embodiment of the system, the second well is single or multiple vertical wells used for said injection of oxygen and steam.

In another embodiment of the system, the steam and oxygen are comingled on the surface prior to injection.

In yet another embodiment of the system, the steam and oxygen are segregated using packers and injected separately into said single or multiple vertical wells. Even further, the steam and oxygen are segregated using concentric tubing and packers, with steam in the central tubing surrounded by oxygen in the adjacent annulus, with said oxygen injected at a higher elevation in the reservoir than said steam.

In another aspect, a steam assisted gravity drainage with oxygen system for recovery of hydrocarbons for a reservoir is disclosed, where said hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, said system comprising:

• • (a) A substantially horizontal well, having a toe and a heel and a length greater than 800 metres, said well being located within said hydrocarbon containing reservoir; wherein said well further comprises:
  • (b) At least one oxygen injection site proximate said toe, for injecting oxygen into said reservoir;
  • (c) A hydrocarbon recovery site for recovery of said hydrocarbons from said hydrocarbon containing reservoir; and
  • (d) At least one vent gas site for venting any gas produced in said reservoir.

In one embodiment of the system, the oxygen injection site is a segregated toe section of said substantially horizontal well.

In yet another aspect, a steam assisted gravity drainage with oxygen system for recovery of hydrocarbons for a reservoir is disclosed, where said hydrocarbons have an initial viscosity greater than 100,000 cp, preferably greater than 1,000 cp, said system comprising:

• • (a) A substantially horizontal well, having a toe and a heel and a length greater than 800 metres, said well being located within said hydrocarbon containing reservoir; wherein said well further comprises:
  • (b) At least one oxygen injection site proximate said toe, for injecting oxygen into said reservoir;
  • (c) At least one steam injection site, for injecting steam into said reservoir;
  • (d) A hydrocarbon recovery site for recovery of said hydrocarbons from said hydrocarbon containing reservoir; and
  • (e) At least one vent gas site for venting any gas produced in said reservoir.

In one embodiment of the system, the oxygen and steam injection site is a segregated toe section of said substantially horizontal well.

BRIEF DESCRIPTION OF THE FIGURES

FIGS. 1A and 1B depict a traditional SAGD Geometry (PRIOR ART);

FIGS. 2A-2D depict the life cycle of SAGD operation (PRIOR ART);

FIG. 3 depicts Saturated Steam Properties (PRIOR ART);

FIG. 4 depicts pressure versus temperature of saturated steam (PRIOR ART);

FIG. 5 depicts Bitumen viscosity versus Temperature (PRIOR ART);

FIG. 6 depicts the Gravdrain equation for SAGD bitumen productivity (PRIOR ART);

FIG. 7 depicts residual bitumen in Steam Swept Zones (PRIOR ART);

FIGS. 8A and 8B depict hydraulic limitations of SAGD (PRIOR ART);

FIGS. 9A and 9B depict SAGD wellbore hydraulics (PRIOR ART);

FIGS. 10A-10C depict SAGD hydraulic limits in well trajectories (PRIOR ART);

FIG. 11 depicts a SAGDOX geometry;

FIGS. 12A and 12B depict a toe to heel SAGDOX (THSAGDOX) with the pump at the heel of the well, according to one embodiment of the present invention;

FIGS. 13A-13C depict Single well SAGDOX (SWSAGDOX) piping schemes with centralized packers, according to several embodiments of the present invention;

FIGS. 14A and 14B depict SWSAGDOX piping schemes with off-set packers, according to several embodiments of the present invention;

FIGS. 15A and 15B depict SWSAGDOX uplift schematic, according to one embodiment of the present invention;

FIGS. 16A-16C depict several preferred SAGDOX geometries, according to one embodiment of the present invention;

FIG. 17 depicts combustion heat release (PRIOR ART);

FIG. 18 depicts SAGDOX process mechanisms;

FIG. 19 depicts steam and oxygen combustion tube tests I;

FIG. 20 depicts steam and oxygen combustion tube tests II;

FIG. 21 depicts ISC minimum air flux rates (PRIOR ART);

FIG. 22 depicts a SWSAGDOX well configuration;

FIG. 23 depicts extended reach THSAGDOX (ER-THSAGDOX), according to one embodiment of the present invention;

FIG. 24 depicts ER-THSAGDOX with three injectors, according to one embodiment of the present invention;

FIG. 25 depicts ER-THSAGDOX with lateral offsets and two injectors, according to one embodiment of the present invention;

FIGS. 26A-26D depict THSAGDOX hydraulic limitations;

FIG. 27 depicts THSAGOX optimal hydraulic design; and

FIGS. 28A and 28B depict SAGDOX (THSAGDOX) with the pump at the toe of the well, according to one embodiment of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

SAGDOX is an improved thermal enhanced oil recovery (EOR) process for bitumen recovery. The process can use geometry similar to SAGD (FIG. 11), but it also has versions with separate vertical wells or segregated sites for oxygen injection and/or non-condensable vent gas removal (FIGS. 12A, 12B, 13A-13C, 14A, 14B, 15A, 15B and 16A-16C). The process can be considered as a hybrid SAGD+ISC process.

One objective of SAGDOX is to reduce reservoir energy injection costs, while maintaining good efficiency and productivity. Oxygen combustion produces in situ heat at a rate of about 480 BTU/SCF oxygen independent of fuel combusted (FIG. 17 Butler (1991)). Combustion temperatures are independent of pressure and they are higher than saturated steam temperatures (FIGS. 3, 19). The higher temperature from combustion vaporizes connate water and refluxes some steam. Steam delivers EOR energy from latent heat released by condensation with a net value, including surface heat recovery of about 1000 BTU/lb. (FIG. 3).

Table 2 presents thermal properties of steam+oxygen mixtures. Per unit heat delivered to the reservoir, oxygen volumes are ten times less than steam, and oxygen costs including capital charges are one half to one third the cost of steam.

The recovery mechanisms are more complex for SAGDOX than for SAGD. The combustion zone is contained within the steam-swept zone 170. Residual bitumen, in the steam-swept zone 170, is heated, fractionated and pyrolyzed by hot combustion gases to produce coke that is the actual fuel for combustion. A gas chamber is formed containing steam combustion gases, vaporized connate water, and other gases (FIG. 18). The large gas chamber can be subdivided into a combustion-swept zone 100, a combustion-zone, a pyrolysis zone 120, a hot bitumen bank 130, a superheated steam zone 140 and a saturated steam zone 50 (FIG. 18). Condensed steam drains from the saturated steam zone 150 and from the ceiling and walls of the gas chamber. Hot bitumen drains from the ceiling and walls of the chamber and from the hot bitumen zone 130 at the edge of the combustion front 110 (FIG. 18). Condensed water and hot bitumen 8 are collected by the lower horizontal well 4 and conveyed (or pumped) to the surface (FIG. 11).

Combustion non-condensable gases are collected and removed by vent gas 22 wells or at segregated vent gas sites (FIGS. 16A-16C). Process pressures can be controlled (partially) by vent gas 22 production, independent of fluid production rates. Vent gas 22 production can also be used to influence direction and rate of gas chamber growth.

Because SAGDOX delivers both steam and oxygen energy and oxygen gas has 10 times the energy density as steam, pipe/tubing sizes for SAGDOX can be smaller (and less costly) than SAGD or other steam EOR processes. This can also reflect on production well sizes because reduced steam injection (with SAGDOX) results in less water production compared to SAGD.

Table 4 shows calculated pipe diameters for various SAGD and SAGDOX streams. Design criteria are presented in the table. When fluids use concentric pipe systems and annular flow, the total size of the combined pipe is indicated by brackets.

Often pipe costs are proportional to the diameter of the pipe. The total of pipe diameters can also be proportional to total costs. Table 4 shows total pipe diameters can be reduced by using SAGDOX and related processes.

Cumulative SAGDOX pipe diameters are 82% of SAGD for the case studied (35% oxygen in gas mix). THSAGDOX cumulative pipe diameters are 59% of SAGD, and SWSAGDOX cumulative diameter is only 42% of SAGD.

Preferred parameters in SAGDOX geometries include:

(1) Use Oxygen (rather than air) as the oxidant injected

• • If the cost of treating vent gas to remove sulphur components and to recover volatile hydrocarbons is factored in, even at low pressures the all-in cost of oxygen is less than the cost of compressed air, per unit energy delivered to the reservoir.
  • Oxygen occupies about one fifth the volume compared to air for the same energy delivery. Well pipes/tubing is smaller and oxygen can be transported further distances from a central plant site.
  • In situ combustion (ISC) using oxygen produces mostly non-condensable CO₂, undiluted with nitrogen. CO₂ can dissolve in bitumen to improve productivity. Dissolution is maximized using oxygen.
  • Vent gas, using oxygen, is mostly CO₂ and may be used for sequestration.
  • There is a minimum oxygen flux to sustain HTO combustion (FIG. 17).
  • It is easier to attain/sustain this flux using oxygen.
    (2) Keep oxygen injection at a concentrated site
  • Because of the minimum O₂ flux constraint from in situ combustion (FIG. 21), the oxygen injection well (or a segregated section) should have no more than 50 metres of contact with the reservoir.
    (3) Segregate Oxygen and steam injectants, as much as possible.
  • Condensed steam (hot water) and oxygen are very corrosive to carbon steel.
  • To minimize corrosion, either 1) oxygen 26 and steam 6 are injected separately (FIGS. 11,12A, 12B & 25); 2) comingled steam 6 and oxygen 26 have limited exposure to a section of pipe that can be a corrosion resistant alloy; 3) the section integrity is not critical to the process (FIG. 13(B); or 4) the entire injection string is a corrosion resistant alloy (FIG. 13(A)).
    (4) The vent gas well (or site) is near the top of the reservoir, far from the oxygen injection site
  • Because of steam movement and condensation, non-condensable gas concentrates near the top of the gas chamber.
  • The vent gas well should be far from the oxygen injector to allow time/space for combustion.
    (5) Vent gas should not be produced with significant oxygen content
  • To mitigate explosions and to foster good oxygen utilization, any vent gas production with oxygen content greater than 5% (v/v) should be shut in.
    (6) Attain/retain a minimum amount of steam in the reservoir
  • Steam is added/injected with oxygen in SAGDOX because steam helps combustion. It preheats the reservoir so ignition, for HTO, can be spontaneous. It adds OH⁻ and H⁺ radicals the combustion zone to improve and stabilize combustion (FIGS. 19 & 20) (Moore, R. G. et al “Parametric Study of Steam Assisted In Situ Combustion,” unpublished February 1994). This is also confirmed by the operation of smokeless flares, where steam is added to improve combustion and reduce smoke (Stone, D. et al “Flares,” Chapter 7 www.gasflare.org, June 2012), (Environmental Protection Agency “Industrial Flares,” www.epa.gov June 2012), (Shore, D. “Making the Flare Safe,” Journal of Loss Prevention in the Process Industries, 9, 363, 1996). The process to gasify fuel also adds steam to the partial combustor to minimize soot production (Berkowitz, N. “Fossil Hydrocarbons,” Academic Press 1997).
  • Steam also condenses and produces water that “covers” the horizontal production well and isolates it from gas or steam intrusion.
  • Steam condensate adds water to the production well to improve flow performance—water/bitumen emulsions—compared to bitumen alone.
  • Steam is also a superior heat transfer agent in the reservoir. When one compares hot combustion gases (mostly CO₂) to steam, the heat transfer advantages of steam are evident. For example, if one has a hot gas chamber at about 200° C. at the edges, the heat available from cooling combustion gases from 500° C. to 200° C. is about 16 BTU/SCF. The same volume of saturated steam contains 39 BTU/SCF of latent heat—more than twice the energy content of combustion gases. In addition, when hot combustion gases cool, they become effective insulators impeding further heat transfer. When steam condenses to deliver latent heat, it creates a transient low-pressure that draws in more steam—a heat pump, without the plumbing. The kinetics also favour steam/water. The heat conductivity of combustion gas is about 0.31 (mW/cmK) compared to the heat conductivity of water of about 6.8 (mW/cmK)—a factor of 20 higher. As a result of these factors, combustion (without steam) has issues of slow heat transfer and poor lateral growth. These issues may be mitigated by steam injection.
  • Since one can't measure the amount of steam in the reservoir, SAGDOX sets a steam minimum by a maximum oxygen/steam (v/v) ratio of 1.0 or alternately 50% (v/v) oxygen in the steam and oxygen mix.
    (7) Attain (or exceed) a minimum oxygen injection
  • Below about 5% (v/v) oxygen in the steam and oxygen mix, the combustion swept zone is small and the cost advantages of oxygen are minimal At this level, only about a third of the energy injected is due to combustion.
    (8) Maximum oxygen injection
  • Within the constraints of (6) and (7) above, because per unit energy oxygen is less costly than steam, the lowest-cost option to produce bitumen is to maximize oxygen/steam ratios.
    (9) Use preferred SAGDOX geometries
  • Depending on the individual application, reservoir matrix properties, reservoir fluid properties, depth, net pay, pressure and location factors, there are three preferred geometrics for SAGDOX (FIGS. 16A-16C).
  • FIGS. 16B (THSAGDOX) and 16C (SWSAGDOX) are most preferred for thinner pay resources, with only one horizontal well required. Compared to SAGD, THSAGDOX and SWSAGDOX have a reduced well count and lower drilling costs. Also, internal tubulars and packers should be usable for multiple applications.

(10) Control/operate SAGDOX by:

• • Sub-cool control on fluid production rates where produced fluid temperature is compared to saturated steam temperature at reservoir pressure. This assumes that gases, immediately above the liquid/gas interface, are predominantly steam.
  • Adjust oxygen/steam ratios (v/v) to meet a target ratio, subject to a range limit of 0.05 to 1.00.
  • Adjust vent gas removal rates so that the gases are predominantly non-condensable gases, oxygen content is less than 5.0% (v/v), and to attain/maintain pressure targets.
  • Adjust steam and oxygen injection rates (subject to (ii) above), along with (iii) above, to attain/maintain pressure targets.

Aside from the above benefits accruing to SAGDOX processes, compared to SAGD extended reach (>800 metre horizontal well length) SAGDOX has the following benefits/motivations:

• • (1) increased reservoir exposure, per recovery pattern;
  • (2) reduction in capital costs per unit bitumen production;
  • (3) increased bitumen productivity, per recovery pattern; and
  • (4) reduced surface footprint, per unit bitumen production.

There are 3 versions of SAGDOX for extended reach wells:

• • (1) basic SAGDOX, with extended twin horizontal wells (FIG. 11);
  • (2) THSAGDOX, where the horizontal steam injector is replaced with one (or more) vertical injection wells (FIGS. 12A, 12B, 23, 24, 25, 28A and 28B); and
  • (3) SWSAGDOX, preferably with an up-turned toe section (FIGS. 13A-13C, 14A, 14B, 15A, 15B, and 22)

THSAGDOX (Toe-to-Heel SAGDOX) retains the horizontal production well 4, but replaces the horizontal steam injector with vertical steam and oxygen injector(s). FIGS. 12A, 12B, 28A and 28B show how THSAGDOX are deployed. All injection (oxygen 26 and steam 6) is accomplished in a vertical well(s), with oxygen 26 preferably injected near the top of the pay zone and steam 6 preferably injected near the bottom of the pay zone, with steam 6 offset from the production horizontal well, preferably by 4 metres or more in elevation. Vent gas 22 may be removed using the outer annulus of the horizontal well in a section higher up in the pay zone (FIGS. 12A, 12B) or by using one (or more) vertical vent gas 22 wells (FIG. 23).

The vertical oxygen and steam injector well is designed to segregate steam 6 and oxygen 26 to minimize corrosion; inject oxygen 26 near the top of the pay zone; and to inject steam 6 lower in the pay zone (FIGS. 12A and 12B). This has the additional benefit that oxygen 26 in the annulus, around a central steam tubing, provides insulation to minimize heat losses from steam 6 to the overburden (FIGS. 12A and 12B).

The THSAGDOX process is started by circulating steam in the horizontal production well 4 and by injecting or cycling steam 6 (huff-and-puff) in the vertical well(s) until the wells communicate (i.e. fluids can flow between wells). After communication is established, wells are converted to THSAGDOX operation, with similar operation controls to SAGDOX.

Hydraulic constraints for THSAGDOX are also less restrictive than SAGD. For SAGD, production rates are constrained so that pressure drops in the production well are less than the hydrostatic head between injector and producer (about 8 psi). For the same well size as SAGD, the THSAGDOX well can be much longer because, per unit bitumen produced, there is less water, so total liquid volumes for THSAGDOX are less than SAGD for the same bitumen production. When the well length is extended, THSAGDOX bitumen productivity can exceed SAGD productivity for the same hydraulic constraints.

Table 3 shows why THSAGDOX (or SAGDOX) processes can have longer horizontal wells than SAGD, using the same hydraulic limit criteria in the production well. For the same Energy to Oil Ratio (MMBTU/bbl) (“ETOR”) design and the same bitumen production rates, fluid volume rates in the horizontal production well are reduced by a factor of about three as oxygen levels in the injectant gases (steam+oxygen) are increased (to a limit of 50 (v/v) percent oxygen in the steam+oxygen mix).

But, the typical well length for THSAGDOX can be extended even further if a tubing string is used to move the liquid draw down point to near the toe of the horizontal well (FIGS. 26A-26D & 28A, 28B). The toe of the vertical injector can be protected from flooding by proximity of the draw down site (FIGS. 26A-26D). The fluid level near the horizontal well toe can be allowed to elevate above the site that would normally flood a horizontal steam injector (FIG. 27). This remedy is not available to SAGD because steam injection is spread out over the entire horizontal length of the steam injector.

THSAGDOX also lends itself to extended-reach applications (ER-THSAGDOX) using multiple vertical injector wells (steam+oxygen) and vertical vent gas removal wells (FIGS. 23, 24, and 25). These wells can be very small particularly from SAGDOX mixes with elevated oxygen levels because the energy intensity for oxygen (BTU/SCF) is about 10 times greater than steam. Vent gas 22 wells are small because non-condensable gases produced by combustion are similar in volume to oxygen injection. Table 4 shows this for a specific case (35% oxygen). FIGS. 23, 24 and 25 show some options for multiple well THSAGDOX systems.

The second option for extended length wells is the SWSAGDOX process. SWSAGDOX contains all injection and production streams for SAGDOX within a single horizontal well bore (FIG. 22).

Portions of the well are segregated for steam 6 and oxygen injection 26 and for bitumen, water 8, and vent gas 22 production using concentric tubing and segregation packers (FIGS. 13A-13C & 14A, 14B). Capital expenditure is lowered by reducing the well count (to 1.0) and by potential retrieval and reuse of various completion components (packers and tubing).

The simplest version of SWSAGDOX is shown in FIGS. 13A-13C where steam and oxygen 30 are mixed at surface and injected premixed, rather than relying on mixing in the reservoir. To resist corrosion, the injection tubing for the steam+oxygen 30 mixture is an alloy-steel or another corrosion-resistant material. An alternate scheme, to obviate corrosion, is to superheat the steam+oxygen 30 mixture to prevent steam condensation on the injectant tubular wells. Heat losses, particularly for deep thin-pay bitumen reservoirs, from this mixture may be an issue. The toe of the horizontal well (FIG. 13(A)) is also exposed to oxygen+water corrosion. But, the integrity of the toe region of this well is not critical to the EOR process.

An alternative embodiment to SWSAGDOX, as shown in FIG. 13(B), uses tubing to segregate oxygen 26 and steam 6, with oxygen 26 surrounding the steam injector tube. The oxygen 26 acts as a good insulator for the steam tube and reduces heat losses to preserve steam quality. But, the toe region of the horizontal well is still exposed to steam+oxygen corrosion.

Yet another alternative SWSAGDOX embodiment is show in FIG. 13(C), where a packer 18 is used to segregate oxygen 26 and steam 6 prior to entering the reservoir. This can minimize toe corrosion and still insulate the steam line to reduce heat losses.

Another alternative embodiment is to complete the horizontal well using a corrosion resistant material, at least for the toe section of the well.

SWSAGDOX has the following features:

• • The horizontal well interior tubing and packers can be retrieved and reused so that its cost can be spread amongst several process units.
  • This is the least cost option (capex) for thin-pay steam+oxygen EOR.
  • This is the least well-count option.
  • The process has longitudinal flows with a drive recovery mechanism.
  • The production segment of the well can be isolated by fluid production if the well is drilled updip or if the toe portion of the well is drilled upward.
  • If a pump is necessary, it can be accommodated (e.g. FIG. 16(A)).
  • The design retains separate vent gas removal.
  • If steam occupies the central injection tube, oxygen gas can help insulate the steam tube and minimize heat losses (FIGS. 16(B) and 16(C)).
  • the SWSAGDOX (U) version of the process allows liquids to cover the horizontal production section to prevent or inhibit gas breakthrough (steam, oxygen, combustion gases), and at the same time, the gas injection zone (steam+oxygen) is not flooded by the liquids.

With SWSAGDOX, hydraulic limitations need to be addressed. Such as if the steam+oxygen section is flat and if we operate the process so that liquid covers the production section to obviate steam+oxygen breakthrough, the end of the horizontal well will be flooded. This will inhibit steam+oxygen injection and harm conformance. If we produce liquid at a faster rate to remove this problem, the entire production section will be open to steam and oxygen breakthrough.

The solution shown in FIGS. 15A and 15B is to drill and complete the horizontal well, so the toe section is slanted upwards to near the top of the pay zone. This enables us to retain liquid covering the horizontal production section so that oxygen 26 and steam 6 don't break through to the producer. Also, oxygen 26 and steam 6 injection should be above the liquid interface so the injection is not flooded. The process for such geometry is termed SWSAGDOX(U), where U denotes uplift of the toe region of the horizontal well. This is a preferred geometry for SWSAGDOX.

On the other hand, SWSAGDOX(U) doesn't get the double hydraulic limit advantage that THSAGDOX achieves because it is not practical to move the drawdown point for liquid production to near the toe section.

The following provide differences between several geometries.

• • (1) ERSAGDOX vs. SAGDOX
    • ERSAGDOX wells are >800 metres long; no length restrictions for SAGDOX.
    • ERSAGDOX geometry prefers THSAGDOX or SWSAGDOX versions.
    • SAGDOX also includes twin horizontal well version.
    • ERSAGDOX prefers thin-pay reservoirs (<25 metres thick).
  • (2) ERSAGDOX (SWSAGDOX) vs. SWSAGD
    • ERSAGDOX injects steam and oxygen; SWSAGD injects steam.
    • well lengths for ERSAGDOX.
    • elevated toe for SWSAGDOX version.
  • (3) ERSAGDOX (THSAGDOX) vs. THAI
    • extended well lengths for ERSAGDOX.
    • vent gas removal well.
    • steam+oxygen injection vs. air (no steam).
    • ERSAGDOX prefers oxygen; THAI prefers air.

To summarize, ERSAGDOX characteristics include the following:

• • well length >800 metres (preferably >1000 metres);
  • preferred geometry (FIGS. 12A, 12B, 15A, 15B); no consideration of dual horizontal wells;
  • prefers thin pays (preferably <25 metres thick); and
  • steam and oxygen injection is used.

TABLE 1
ALBERTA BITUMEN DEPOSITS
		Cold	Peace
	Athabasca	Lake	River	Total
Accessible Deposits
(known technology)
SAGD/CSS	420	51	54	526
Mining	59	0	0	59
Cold Production	13	138	0	151
Subtotal	492	189	54	736
Inaccessible Deposits
(no known technology)
Carbonates	383	0	65	448
Thin Pays	380	21	8	410
No cap rock	37	0	0	37
Too deep for mining but too shallow	28	0	0	28
for SAGD
Top gas	14	0	0	14
Others	36	−10	1	27
Subtotal	877	11	74	962
Grand total	1369	201	129	1699
(109 bbls)
(1) Source - (Heidrick, T. et al, “Oil Sands Research and Development”, AERI, March 2006) and (Godin (2006))
(2) Thin pay (cutoff = 10 m)
(3) Numbers may not be additive due to rounding

TABLE 2
Thermal EOR: Injection Gases
	% (v/v)	% heat from	BTU/SCF	MSCF/MMBTU
	O2	O2	mix	mix
SAGD (Steam)	0.0	0.0	47.4	21.1
SAGDOX
5% O2	5.0	34.8	69.0	14.5
9% O2	9.0	50.0	86.3	11.6
35% O2	35.0	84.5	198.8	5.0
50% O2	50.0	91.0	263.7	3.8
ISC
(oxygen)	100.0	100.0	480	2.1
(air)	20.9	100.0	100	10.0
Where:
(1) steam at 1000 BTU/lb
(2) oxygen at 480 BTU/SCF
(3) SAGDOX oxygen at (v/v)%

TABLE 3
SAGDOX Water Balance
% (v/v) O2 steam mix
	SAGD	5	9	35	50	ISC(O2)
Design
ETOR (sf)	1.00	1.00	1.00	1.00	1.00	1.00
SOR(sf)	2.86	1.86	1.43	0.40	0.26	0.00
SOR(wh)	3.18	2.07	1.59	0.49	0.29	0.00
ETOR (O2)(sf)	0	0.65	0.50	0.85	0.91	1.00
% ht. from O2	0	34.8	50.0	84.5	91.1	100.0
Water
Stm. water (bbl/Bbl)	3.18	2.07	1.59	0.49	0.29	0.00
Connate water (bbl/Bbl)	0	0.09	0.13	0.21	0.23	0.25
Comb. water (bbl/Bbl)	0	0.013	0.019	0.032	0.035	0.038
WWR	1.00	1.05	1.09	1.49	1.91	—
Production
Total water (bbl/Bbl)	3.18	2.17	1.74	0.73	0.56	0.29
Bitumen (bbl/Bbl)	1.00	1.00	1.00	1.00	1.00	1.00
Total (bbl/Bbl)	4.18	3.17	2.74	1.73	1.56	1.29
Cut % water (v/v)	76.1	68.4	63.5	42.2	35.9	22.5
Total % of SAGD	100.0	75.8	65.6	41.4	37.3	30.9
Where:
(1) Bbl = bbl bit.; sf = sand face; wh = well head
(2) connate water = .25 bbl/Bbl; prorated by % ht. from O2
(3) ETOR = MMBTU/Bbl = 1.0 at sf.
(4) WRR = prod. water/steam water
(5) S0 = .8; Sw = .2
(6) steam at 1000 BTU/lb; O2 at 480 BTU/SCF
(7) 10% loss in each of steam dist. and wh to sf.

TABLE 4
Process Pipe Sizes
	SAGD	SAGDOX		THSAGDOX		SWSAGDOX
Steam Injector	7.23	2.76	}	3.47
					{close oversize brace}	5.00
Oxygen Injector	—	2.09
Vent Gas Producer	—	2.09	}	3.60
Liquids Producer	4.79	2.93
Totals	12.02	9.87		7.07		5.00
Where:
(1) 500 Bbl/d @ ETOR = 1.0 (sf)
(2) 100 psia, 160° C. steam @ 25 ft./sec
(3) liquids producer @ 1 ft./sec
(4) oxygen injector @ 100 ft./sec
(5) 35% (v/v) oxygen in mix
(6) concentric piping doesn't account for wall thickness

As many changes therefore may be made to the embodiments of the invention without departing from the scope thereof. It is considered that all matter contained herein be considered illustrative of the invention and not in a limiting sense.

Claims

1. A process to recover hydrocarbons from a reservoir, where said hydrocarbons have an initial viscosity greater than 100,000 cp, said process comprising:

(a) Initially injecting oxygen into said reservoir;

(b) Allowing for combustion of said oxygen to vaporize connate water in said hydrocarbon reservoir;

(c) Collecting hydrocarbons in a substantially horizontal production well in said reservoir and where said substantially horizontal production well has a length greater than about 800 metres.

2. A process according to claim 1 further comprising initial steam injection into the reservoir then terminating said steam injection.

3. A process according to claim 2 where the ratio of oxygen to steam injected is controlled in the range from 0.05 to 1.00 (v/v).

4. A steam assisted gravity drainage with oxygen system for recovery of hydrocarbons from a reservoir, where said hydrocarbons have an initial viscosity greater than 100,000 cp, said system comprising:

(a) A first well for capturing said hydrocarbons, having a toe and a heel and a length greater than about 800 metres, said first well being substantially horizontal and at a first depth;

(b) A second well within said hydrocarbon containing reservoir, having a length greater than about 800 metres, for injection of oxygen into said hydrocarbon containing reservoir, being at second depth said second depth shallower than said first depth;

(c) Said second well being located proximate said toe of said first well; and

(d) A vent gas means for venting any gas produced in said reservoir.

5. A system according to claim 4 where said vent gas means is single or multiple vertical wells.

6. A system according to claim 4 where said vent gas means is a segregated annulus section in the heel rise section of the substantially horizontal well.

7. A steam assisted gravity drainage with oxygen system for recovery of hydrocarbons from a reservoir, where said hydrocarbons have an initial viscosity greater than 100,000 cp, said system comprising:

(a) A first well, having a toe and a heel and a length greater than about 800 metres, said first well within said hydrocarbon containing reservoir, for capturing said hydrocarbons;

(b) A second well within said hydrocarbon containing reservoir, having a length greater than about 800 metres, for injection of oxygen and steam into said hydrocarbon containing reservoir;

(c) Said second well being located proximate said toe of said first well; and

(d) At least one vent gas means for venting any gas produced in said reservoir.

8. A system according to claim 7 where said at least one vent gas means is single or multiple vertical wells.

9. A system according to claim 7 where said at least one vent gas means is a segregated annulus section in the heel rise section of the substantially horizontal well.

10. A system according to claim 7 where said second well is single or multiple vertical wells used for said injection of oxygen and steam.

11. A system according to claim 10 where said steam and oxygen are comingled on the surface prior to injection.

12. A system according to claim 10 where said steam and oxygen are segregated using packers and injected separately into said single or multiple vertical wells.

13. A system according to claim 12 where said steam and oxygen are segregated using concentric tubing and packers, with steam in the central tubing surrounded by oxygen in the adjacent annulus, with said oxygen injected at a higher elevation in the reservoir than said steam.

14. A steam assisted gravity drainage with oxygen system for recovery of hydrocarbons for a reservoir, where said hydrocarbons have an initial viscosity greater than 100,000 cp, said system comprising:

(a) A substantially horizontal well, having a toe and a heel and a length greater than 800 metres, said well being located within said hydrocarbon containing reservoir; wherein said well further comprises:

(b) At least one oxygen injection site proximate said toe, for injecting oxygen into said reservoir;

(c) A hydrocarbon recovery site for recovery of said hydrocarbons from said reservoir; and

(d) At least one vent gas site for venting any gas produced in said reservoir.

15. A system according to claim 14 where said oxygen injection site is a segregated toe section of said substantially horizontal well.

16. A steam assisted gravity drainage with oxygen system for recovery of hydrocarbons for a reservoir, where said hydrocarbons have an initial viscosity greater than 100,000 cp, said system comprising:

(a) A substantially horizontal well, having a toe and a heel and a length greater than 800 metres, said well being located within said hydrocarbon containing reservoir; wherein said well further comprises:

(b) At least one oxygen injection site proximate said toe, for injecting oxygen into said reservoir;

(c) At least one steam injection site, for injecting steam into said reservoir;

(d) A hydrocarbon recovery site for recovery of said hydrocarbons from said reservoir; and

(e) At least one vent gas site for venting any gas produced in said reservoir.

17. A system according to claim 16 where said oxygen and steam injection site is a segregated toe section of said substantially horizontal well.

18. The process according to claim 1 wherein said hydrocarbons have an initial viscosity range greater than 1,000 cp.

19. The system according to claim 4 wherein said hydrocarbons have an initial viscosity range greater than 1,000 cp.

20. The system according to claim 7 wherein said hydrocarbons have an initial viscosity range greater than 1,000 cp.