USE OF STEAM ASSISTED GRAVITY DRAINAGE WITH OXYGEN ("SAGDOX") IN THE RECOVERY OF BITUMEN IN THIN PAY ZONES

A SAGDOX process to recover liquid hydrocarbons from at least one thin pay zone in a hydrocarbon bitumen reservoir, via a substantially horizontal production well, where the hydrocarbon bitumen reservoir has a top and a bottom. The process includes: i) Injecting steam into the hydrocarbon bitumen reservoir above the substantially horizontal production well; ii) Injecting oxygen into the hydrocarbon bitumen reservoir above the substantially horizontal production well; iii) Recovering liquid hydrocarbon gravity drainage into the substantially horizontal production well.

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Description
CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. application Ser. No. 14/058,488, filed on Oct. 21, 2013, which claims benefit of U.S. Application Ser. No. 61/717, 267, filed on Oct. 23, 2012 and is a CIP of U.S. application Ser. No. 13/543,012, filed on Jul. 6, 2012, which claims benefit of U.S. Application Ser. No. 61/507,196, filed on Jul. 13, 2011. U.S. application Ser. No. 14/058,488 is also a CIP of U.S. application Ser. No. 13/628,164, filed on Sep. 27, 2012, which claims benefit of U.S. Application Ser. No. 61/549,770, filed on Oct. 21, 2011 and is a CIP of U.S. application Ser. No. 13/543,012, filed on Jul. 6, 2012. U.S. application Ser. No. 14/058,488 is also a CIP of U.S. application Ser. No. 13/628,178, filed on Sep. 27, 2012, which claims benefit of U.S. Application Ser. No. 61/550,479, filed on Oct. 24, 2011. U.S. application Ser. No, 14/058,488 is also a CIP of U.S. application Ser. No. 13/888,874, filed on May 7, 2013, which claims benefit of U.S. Application Ser. No. 61/643,538, filed on May 7, 2012, and is a CIP of U.S. application Ser. No. 13/543,012, filed on Jul. 6, 2012, which claims benefit of U.S. Application Ser. No. 61/507,196, filed on Jul. 13, 2011, and said U.S. application Ser. No, 13/888,874, filed on May 7, 2013, is a CIP of U.S. application Ser. No. 13/628,164, filed on Sep. 27, 2012, which claims benefit of U.S. Application Ser. No. 61/549,770, filed on Oct. 21, 2011. U.S. application Ser. No. 14/058,488 is also a CIP of U.S. application Ser. No. 13/893,902, filed on May 14, 2013, which claims benefit of U.S. Application Ser. No. 61/647,153, filed on May 15, 2012, and is a CIP of U.S. application Ser. No. 13/543,012, filed on Jul. 6, 2012, which claims benefit of U.S. Application Ser. No. 61/507,196, filed on Jul. 13, 2011 and said U.S. application Ser. No. 13/893,902, filed on May 14, 2013 is a CIP of U.S. application Ser. No. 13/628,164, filed on Sep. 27, 2012, which claims benefit of U.S. Application Ser. No. 61/549,770, filed on Oct. 21, 2011. U.S. application Ser. No. 14/058,488 is also a CIP of U.S. application Ser. No. 13/928,839, filed on Jun. 27, 2013, which claims benefit of U.S. Application Ser. No. 61/666,116, filed on Jun. 29, 2012.

U.S. application Ser. No. 14/058,488, filed on Oct. 21, 2013, is hereby incorporated by reference in its entirety.

BACKGROUND OF THE INVENTION

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 47 Kbbl/d (Oilsands Review, 2010). SAGD is now the world's leading, thermal EOR process.

FIG. 1 (Prior Art) shows 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.

FIG. 2 (Prior Art) shows how SAGD matures. A young steam chamber 10 has bitumen drainage from steep chamber sides and from the camber 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 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 in FIG. 3 (Prior Art).

The operational performance 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 (Φ>0.2, Sio>0.6, kv>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.
    • 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 makeup 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. FIG. 8 shows 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 (FIG. 8). 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).

Thin Pay Reservoirs (Thin Pay Zone)

For the purposes herein, “bitumen” is defined as an oil with high density (API<10) and high in situ viscosity (>100,000 cP), so that primary production is zero or very small. Bitumen is an immobile hydrocarbon under reservoir conditions.

The largest deposits are found in the Athabasca region of Alberta—the McMurray deposit (Table 1). FIGS. 9, 10, 11 and 12 characterize this deposit. FIG. 9 shows the depth of the top of the McMurray formation—i.e. the overburden thickness. FIG. 10 shows the thickness of the total McMurray deposit—both porous and non-porous zones. FIG. 11 shows the porosity internal—the net thickness of the porous portion of the deposit, with a 10% porosity cut off (this portion contains bitumen, water and gas occupy the pore volume). FIG. 12 shows the bitumen net pay thickness—a portion of the porosity interval. The difference between the porosity interval and the bitumen pay is an indication of impairment zones for EOR processes—gas, top water, bottom water or lean zones. These zones can be within the bitumen net pay or adjacent (top/ bottom).

It has been estimated that 410 billion bbls of bitumen are deposited in thin pay zones, less than 10 metres thick (Table 1) (Henrick, T. et al, “Oil Sands Research and Development, Alberta Energy Research Institute, March 2006). The vast majority of these thin pay reservoirs (zones) (380 billion bbls, 93%) are in the Athabasca region. If the thin pay cut off were set at 15 metres rather than 10 metres, the thin pay bitumen resource is larger than the carbonate bitumen resource (Table 1). By any account, thin pay bitumen in Alberta is a world-scale hydrocarbon resource.

FIG. 12 shows thin pay zones are focused on the western side of the McMurray deposit. FIG. 9 shows these deposits can have overburden depths ranging from about 100-300 metres, depending on location. Hydrostatic pressures range from about 160-500 psia, using a hydrostatic pressure gradient of 0.5 psia/ft. of depth.

FIG. 13 shows the API gravity of bitumen deposits in the McMurray formation. The bitumen density varies from 7 to 10 API, with the lighter bitumen (higher API) in the southwest part of the deposit.

Based on FIGS. 9, 10, 11, 12 and 13 we can characterize thin pay bitumen resources in Alberta as:

    • shallow to medium depth (100-300 m of overburden)
    • low to medium pressure (160-500 psia hydrostatic head)
    • location on the western side of the Athabasca deposit
    • high-moderate impairment for EOR (based on difference between net porosity interval and net bitumen pay)
    • large opportunity (>400 billion bbls original bitumen in place (“OBIP”))
    • no known technology to economically recover thin pay bitumen (Heinrick (2006))
    • very little, if any, R&D focused on the opportunity (Heinrick (2006))
    • API density in the 7 to 10 range
    • Thin zone, preferably less than about 25 metres, more preferably leas than about 15 metres

The limit for SAGD minimum net-pays has been estimated as 10-15 metres (Heindrick (2006)). The factors that determine this limit are as follows:

    • (1) SAGD Geometry
      • It is difficult to fit a SAGD well configuration within a net pay that is less than about 10 metres. Spacing between the injector 2 and producer 4 horizontal wells is about 5 metres (FIG. 1). The production well is placed near the reservoir bottom, but requires a stand-off of 1 to 2 metres. Similarly, the upper horizontal steam injector 2 needs a stand-off from the reservoir ceiling of a few meters. SAGD also requires that the horizontal wells are in (or near) a horizontal plane. If the reservoir is slanted, it is even more difficult to fit the SAGD geometry into a thin pay reservoir.
    • (2) Bitumen Productivity
      • The dominant economic factor for a SAGD project is the bitumen productivity. Productivity can be affected directly by pay thinness or by pressure, if the thin pay resource is shallow.
      • The Gravdrain Equation (Butler (1991), FIG. 6) has been shown to be a good predictor of productivity sensitivities. Productivity is proportional to the square root of the net pay. This equation can be used to predict productivity impairments due to net pay reductions. For example, if an ideal SAGD project with 50 metres net pay is used as the comparison, the following productivity reductions with smaller net pays (i.e. thin pay zones) are expected:
        • 25 metres net pay—29% productivity loss
        • 15 metres net pay—45% productivity loss
        • 10 metres net pay—55% productivity loss
        • 5 metres net pay—68% productivity loss
      • These estimates don't consider productivity losses due to heat losses in homogeneities, pattern boundary effects, containment losses, or pressure effects.
      • The effect of depth can be more dramatic. FIGS. 9 and 12 show that some thin pay resources are expected to be at lower depths than most of the thick pay resources. If one is close to the surface, it becomes too risky to operate SAGD at overpressures. One is forced to operate near native/hydrostatic pressures. Pressure reduction can have as dramatic effect on bitumen productivity.
      • By using 1) the properties of saturated steam (FIG. 4); 2) the viscosity curve for bitumen (FIG. 5); and 3) the Gravdrain Equation (FIG. 6) to estimate productivity changes with viscosity changes, one can estimate SAGD productivity losses for shallower reservoirs by assuming the following: 1) SAGD operation at hydrostatic pressures; 2) no changes in reservoir thickness; and 3) a base case at 300 metre depth. The estimated SAGD productivity losses for shallower reservoirs are as follows:
        • 200 metre depth—15% productivity loss
        • 100 metre depth—45% productivity loss
        • 50 metre depth—66% productivity loss
      • The effect of reduced thickness and reduced depth are independent and cumulative. So, if one takes a 50 metre net pay at a 300 metre overburden depth operating at hydrostatic pressures as a bench mark, then a 10 metre net pay at a 50 metre depth will have a productivity reduction of 85%. This can be devastating to SAGD economics.
    • (3) Bitumen Recovery
      • In the end-of-life stage of a SAGD project, at the economic limit, the cross section of a gravity drainage (GD) steam chamber (in a homogenous reservoir) takes the shape of linear, sloped drainage channels, with a fixed drainage angle (FIG. 2). If one assumes a sharp break between the steam-swept zone and the un-swept zone, and if one knows the drainage angle at end-of-life, one can calculate the recoverable reserves. FIG. 14 shows this calculation for a base-case SAGD project (25 metre net pay, 100 metre well spacing, 1 metre offset of bottom well, Φ=0.35, Sio=0.8, Sro=0.15, θ=15°). The recovery factor for such a project is 56% OBIP—a typical expectation for SAGD.
      • FIGS. 15, 16, 17 show some calculations for a 10 metre thin pay reservoir, assuming the same performance. Well spacings are for 100 metres (the same as our base case), 67.2 metres so the drainage interface intersects the corner of the recovery pattern, and 29.8 metres so that recoveries are similar to the base case.
      • The results can be summarized as follows:

Base A B C Net Pay (metres) 25 10 10 10 Well Spacing (metres) 100 100 67.2 29.8 Recovery Factor (metres) 0.562 0.213 0.366 0.568
      • So if we wish to have the same spacing as our base case, bitumen recovery (0.213) is unacceptable. If we keep the same recovery (˜0.56), we have to reduce well spacing from 100 metres to 29.8 metres. We are increasing well density by a factor of more than 3. This will increase capital expenses considerably per unit bitumen produced.
    • (4) Economic Limitations
      • To illustrate the economic issues and concerns for SAGD in thin pay bitumen reservoirs, we have constructed a simple model for end-of-life SAGD as shown in FIG. 18, with the following key assumptions:
      • A 2 metre stand-off of the lower production well from the bottom of the reservoir:
      • The aspect ratio (pattern width:pattern thickness) is 4. This results in a drainage angle of end-of-life at 10-13°;
      • Base case for 25 m net pay. Recovery rate equalized over 10 yrs. (Sio=0.80, Sro=0.15, Φ=0.35);
      • The average productivity for thin reservoirs is reduced according to FIG. 6 (no accounting for shallowness of net pay zone);
      • Assuming a $10/bbl net back for bitumen (to the well head) we calculate cumulative net backs at 0, 10 and 20% of discount rates.
    • For a 1000 metre length SAGD well pair geometry, we calculate the following:

pay thickness (m) 7 10 15 25 Well spacing (m) 28 40 60 100 Bitumen Recovery (Mbbl) .150 .344 .837 2.469 Recovery Factor .44 .49 .52 .56 Avg. Prod. (bbl/d) 358 428 525 677 Lifetime (yrs) 1.15 2.20 4.37 10.0 Cash Flow ($M) PV0 1.50 3.44 8.37 24.69 PV10 1.35 2.97 6.51 15.19 PV20 1.23 2.57 5.25 10.36
    • This simple model doesn't penalize the productivity of thin pay reservoirs due to reduced pressures (shallow resources), or heat losses proportionately larger than our base case, or start-up delays (instant start up is assumed). So, thin pay productivity is probably optimistic.
    • Based on our model we observe the following;
      • The end-of-life drainage angles (10-13°) are realistic for SAGD. The recovery factors are reasonable (44 to 56%).
      • In order to recover a reasonable amount of the resource, using SAGD, thin pay reservoir well spacing must be reduced considerably, (e.g. 40 metre spacing for 10 metre net pay zone).
      • If one can achieve productivities impaired only by pay thickness reduction (i.e. other factors are constant), thin pay resources are depleted very quickly (e.g. 2.2 yrs. for 10 m net pay)
      • The model assumes instant (avg.) productivity in year 1. Delays would hurt economics for thin pays more severely because of the short run lengths.
      • If one assumes a serviced, SAGD, 1000 metre well-pair costs $5-10 million, one sees a pay cut off of about 15 metre.
      • If net backs for bitumen were double, at $20/bbl, pay cut offs could be less than 15 metre for SAGD.
      • If one maintains a 2 metre stand off from reservoir bottom and if one also maintains a 5 metre spacing between steam injection and producer well, SAGD cannot be applied to reservoirs with less than 7 metre pay thickness.
      • FIG. 19 shows how the unrecovered bitumen, at end-of-life SAGD, is distributed between wedge zones, the portion of the reservoir underneath the plane of the production well and residual bitumen in the steam-swept zone. As the net pay is reduced, the bitumen beneath the plane of the production well becomes the most important unrecovered resource, unlike thick SAGD, where the wedge zone bitumen dominates.
    • (5) Recovery Inhomogeneties
      • So far, concerns with SAGD applied to thin reservoirs that are homogeneous have been discussed. But, no reservoir is truly homogeneous. Shale, mudstones, lean zones, top/bottom water, and top gas can all contribute to inhomogeneities.
      • SAGD is a mild process. It can also be termed as a delicate process. Production is driven by the gravity head in the reservoir. The hydrostatic gravity head for a 30 metre pay reservoir is very low-about only 50 psia (maximum). The gravity gradient is only about 0.5 psi/ft, or 1.6 psi/m. SAGD is also a 2D process. There are no significant reservoir flows in the direction of the horizontal wells. Water in the reservoir or in an inhomogenity cannot be vaporized by SAGD. For this reason, in a homogeneous reservoir, a Hele-Shaw 2D physical model can be a good predictor of actual SAGD performance. Also, SAGD temperatures are limited to saturated steam conditions.
      • For these reasons above, SAGD has difficulty to overcome any reservoir inhomogeneities that can disrupt flow patterns.
    • (6) Recovery Efficiency
      • The usual efficiency measure for SAGD is SOR. SOR is inversely related to efficiency—low SOR˜high thermal efficiency. SOR is determined by the energy needed to heat up the reservoir matrix, the energy needed to heat up the reservoir fluids (bitumen and water) and the heat lost to overburden and underburden (both during transit down the injection well and direct losses in the reservoir at the over/underburden interfaces). At lower steam pressures, SOR is reduced because less heat is needed to heat the reservoir and compensate for losses to over/underburden. Thin pay deposits will have increased losses to overburden because the steam interface will hit the ceiling quicker than for thick pay resources. Everything else being equal, energy losses to overburden are proportional to the surface area of the ceiling. Ceiling surface area per unit OBIP is proportional to (l/h) where h=net pay. Using this relationship, we can expect heat losses per unit OBIP to be 2.5 times greater for 10 metre pay reservoir compared to a 25 metre pay reservoir. So, in addition and to the concerns already expressed, (productivity and recovery factor), thin pay bitumen SAGD will have higher SOR (lower thermal efficiency) than thick pay bitumen SAGD.
    • (7) Summary
    • In summary, SAGD in thin pay bitumen reservoirs has the following deficiencies:
      • It becomes difficult, using traditional SAGD geometry (FIG. 1) to fit the wells within the reservoir.
      • Compared to thicker-pay reservoirs, thin pay bitumen reservoirs will have significant bitumen productivity reductions.
      • If the thin pay reservoir is shallow and SAGD is forced to operate at pressures near to native reservoir pressure, bitumen productivity is further reduced.
      • Unless well spacing is reduced, increasing well costs, bitumen recovery is poor compared to thicker pay bitumen resources.
      • Revenues, generated by thin pay bitumen recovery, are significantly less than revenues from thicker-pay resources. Even when productivity is reduced, accounting for reduced gravity heads, thin pay production may only last for a few years compared to over 10 years for thicker pay resources.
      • SAGD is sensitive to reservoir impairments (shales, lean zones . . . etc.). If these impairments are proportionately more prevalent in thin pay reservoirs, SAGD will have problems as discussed herein.
      • Heat losses can reduce process of efficiency. Thin pay reservoirs will have greater heat losses to overburden or underburden than thicker-pay resources.

Despite the deficiencies of SAGD, it is still being considered for thin pay bitumen recovery. Husky has proposed $35 million, thin pay SAGD project at McMullen, Alberta, with 10 to 16.5 ‘metre net pay zone in the Wabaskaw formation (Roche, P., “No Analogue”, New Tech. Mag. Apr. 1, 2009). The generally accepted pay thickness limit for SAGD is 15 metres, but this may be pushed downward to 10 metres.

Based on the previous analysis, desirable attributes improvements or new bitumen EOR processes for thin pay resources are as follows:

    • Reduce the well costs, per bbl, of bitumen recovered. This can be accomplished by new well configurations, reduced well sizes, longer (horizontal) wells, or the use of well components that are retrievable and reusable.
    • Reduce the unit operating expenses. This can be accomplished by injecting energy that is less costly than steam or by using processes that require less energy to produce bitumen.
    • Increase bitumen productivity. This can be accomplished by processes that run hotter than SAGD, introduce new recovery mechanisms, or increase well lengths.
    • Increase productivity in impaired reservoirs. This can be accomplished by processes that are 3 dimensional, processes that can more easily breach barriers (e.g. vaporize water . . . ) or processes that run hotter than SAGD.
    • Increase ultimate recovery. This can be accomplished by processes that recover some residual bitumen from a steam-swept zone, or recover more oil from wedge zones between recovery patterns.
    • Increase produced bitumen value. This can be accomplished by partial in situ upgrading.
    • Improve environmental performance. This can be accomplished by reducing (make-up) water use, increasing process efficiency, reducing CO2 emissions or reducing surface footprints.

In addition to SAGD, the following processes have been suggested as applicable for thin pay bitumen recovery:

    • (i) Expanding Solvent SAGD (ESSAGD) has been suggested as a process to target thin pay (Gates, I. “Solvent Aided SAGD in thin oil sand reservoirs, Journal of Petroleum Science and Engineering Apr. 24, 2010). The idea is simply that steam and solvent is more effective than steam alone. Solvent dissolution in bitumen can lower viscosity and provide a separate recovery mechanism compared to steam alone. But, the process has the following deficiencies:
      • The operating temperature is lower than SAGD at the same P, because steam is diluted by solvent gas. Heat losses can be reduced, but productivity, due solely to bitumen heating, is also reduced compared to SAGD.
      • The process geometry is similar to SAGD. The process is a 2D process, with no reservoir flows in the longitudinal direction. Well costs (capital expenses) are similar to SAGD.
      • Solvent (butane, condensate, BTX . . . ) is very costly (more valuable than bitumen). If there are any net solvent losses to the reservoir (leakage, retention), operating expenses can be comparable or higher than SAGD.
      • The extent of solvent losses is unknown until the end of the project.
      • No field tests for ESSAGD in thin pay bitumen, have been conducted.
    • (ii) It has also been suggested that SAGD geometry can be altered, in thin pay reservoirs, by offsetting the upper steam injector in a lateral direction, or by adding a multi-lateral producer to the SAGD geometry (Tavallali, “Assessment of SAGD . . . ” SPE 153128, March 2012). However, the process has the following deficiencies:
      • Capital expense is similar to SAGD. The well count and length are unchanged.
      • The focus of the process is on heavy oil not bitumen.
      • Other SAGD concerns—poor productivity, poor energy efficiency, and poor recovery or increased well spacing—are retained by this technology.
    • (iii) It has also been suggested to replace the parallel SAGD steam injector with a series of overlapping perpendicular horizontal injector wells (Stalder. “Cross SAGD (XSAGD) . . . ” SPE Reservoir Evaluation & Engineering, 2007). The process is called cross SAGD or XSAGD. This forms a grid of parallel horizontal steam injectors intersecting (at a spacing similar to SAGD (5 metres)) a grid of parallel horizontal producers. XSAGD deficiencies are similar to (ii) above.
    • (iv) Solvents without steam have also been suggested, using a VAPEX process (New Tech Mag., “VAPEX shows promise but stuck in lab”, 2005). But this pure solvent process has the following deficiencies:
      • The processes have been proven in field tests to be difficult (slow) to start.
      • Productivity has been much less than SAGD.
      • Solvents are expensive (more costly than bitumen), so that, even with modest losses, operating expenses are a concern.
      • The processes are 2D, without longitudinal flows in the reservoir.
      • Focus has shifted to heavy oils (with some initial injectivity) not to bitumen.
      • Solvent losses (to the reservoir) are a key economic concern. Unfortunately, net losses cannot be confirmed until the end of the project, when solvents are expected to be recovered in a blow-down phase.
    • (v) Single Well SAGD (“SWSAGD”) is another EOR alternative for thin pay bitumen and heavy oil applications (Elliot, K. et al, “Computer Simulation of SWSAGD”, U.S. Department of Energy, 14994-18, July 1999) (ELAN Energy, “Announces Six Month Results”, August 1996) (Improved Recovery Week, “Thermal System ups heavy oil . . . ”, Dec. 4, 1995). The idea is to incorporate steam 6 injection and bitumen+water 8 production into a single horizontal well, using thermal packers 18 (FIG. 20) (or not (FIG. 21), in order to isolate steam 6 injection and bitumen+water 8 production.
    • The original targets were thin heavy oil deposits in W. Saskatchewan and E. Alberta (Ashok, K. et al, “A Mechanistic Study of SWSAGD”, Society of Petroleum Engineers, 59333-MS, 2000) (ELAN Energy, “Announces Nine Month Earnings, November 1996) (Luft, H. B. et al, “Thermal Performance of Insulated Concentric Coiled Tubing (ICCT) for Continuous . . . , “SPE, 37534-MS, 1997). The first SWSAGD well was drilled at Cactus Lake, Saskatchewan in 1995 (HOSC (Heavy Oil Sci. Cent) “Completions and Workovers”, www.lloydminsterheavyoil.com, 2012). Several field tests were conducted by Elan and others in the 1990s (Elliot (1999), (Saltuklaroglu, M. at al, “Mobil's SAGD Experience at Celtic, Saskatchewan” SPE, 99-25, June 1999).
    • Compared to SAGD, SWSAGD has a definite longitudinal flow so it can more easily deal with barriers and it has a definite reduced well cost. But, the following concerns were also evident:
      • The centralized concentric steam line 6 is in contact with the produced fluids (water+bitumen 8) (FIGS. 20, 21). The produced fluids have a high heat capacity and normally (i.e. SAGD) the fluids would be at a lower temperature than saturated-steam (i.e. sub-cool control). Heat losses from the steam injector to the produced fluids can be considerable for uninsulated, concentric, carbon steel tubing. Heat losses from the steam 6 and produced liquids 8 are also a concern because the produced liquids have a high heat conductivity. The produced fluids 8 are heated rapidly to saturated steam temperatures and the steam quality is reduced considerably before injection to the reservoir. The use of a steam trap (sub cool) control for production rates will be difficult, at best. One solution is to use insulated tubing for the steam injection tube. Insulated concentric coiled tubing (ICCT) was developed for this purpose but has not resulted in widespread use today (Luft, H. B. et al. “Thermal Performance of Insulated Concentric Coiled Tubing (ICCT) for Continuous . . . , “SPE, 37534-MS, 1997) (Falk, K. et al “Concentric Coiled Tubing for SWSAGD”, World Oil, July 1996).
      • Start-up performance is another issue. Even for heavy oil deposits with some steam injectivity and some primary production, start up was difficult and protracted (Elliot (1999)). Initial production rates were disappointing (Elliot (1999)). At least partially, this problem could be due to 2 factors. Initial steam quality at the sand face was poor due to heat losses to produced fluids. Also, the steam injection site occurs at the same elevation as production (FIG. 20). These is no stand-off like SAGD to allow a liquid level to isolate the producer and prevent steam break through (FIG. 1). Steam by-passing is an issue (Ashok, K. et al, “A Mechanistic Study of SWSAGD”, SPE, 59333-MS, 2000). Stand influx problems were another issue (Elliot (1999)). Because of these issues, an alternative start-up procedure using cyclic steam has been suggested (Elliot (1999)), but this has not been field tested.
      • Even after start-up, SWSAGD performance has been disappointing (Saltuklaroglu (1999), Elliot (1999)). Elan Energy was the inventor and major operator of SWSAGD. Prior to late 1999, Elan had drilled 19 SWSAGD wells with 7 separate pilots. By the end of 1999, five of the seven pilots had been suspended or converted to other processes due to poor performance (Elliot (1999)). Best results were for high pressure, low viscosity, heavy oils with some primary production as foamy oil and no bottom water. This process is focussed on deep thin pay heavy oil, not bitumen.
      • In 1997, Ranger Oil & Gas acquired Elan (Business Day, “Ranger Oil . . . deal for Elan Energy”, Sep. 3, 1997). In 1999, Ranger was acquired by Canadian Natural Resources Limited (CNRL) (CNRL “Ranger Oil agrees to CNRL offer” 1999). Post 1999, there have been no indications of further SWSAGD developments, particularly none associated with bitumen.
      • Field testing of SWSAGD can be labelled unsuccessful.
    • (vi) A process has also been suggested using heated, vaporized solvent to get some advantages of both solvent EOR and thermal EOR. Similar to SAGD a gas gravity drainage (GD) chamber is formed containing vaporized solvent gas. The solvent condenses at the cold bitumen interface releasing its latent heat, similar to steam. The solvent liquid can then dissolve into bitumen to further reduce viscosity. The process is called N-Solv (Braswell, J., “New Heavy Oil Solvent Extraction Pilot to Test Experimental Process” The journal of Petroleum Technology Online, Jan. 9, 2012). The process claims reduced environmental impacts compared to SAGD. A field pilot is expected to start up in 2013 (Braswell (2012)).
    • But the process has the following concerns:
      • Well configuration similar to SAGD. No/little capital cost reduction.
      • Proposed test site is for thick bitumen pays, no focus on thin pay resources.
      • Similar to SAGD. 2D process. No longitudinal flows in reservoir. Hard to breach barriers.
      • Solvent is costly (more valuable than bitumen). Solvent losses are a key economic concern.
      • Solvent losses cannot be confirmed or estimated prior to end of process when solvent inventory recovery is attempted.
      • Productivity may be worse than SAGD.
      • Poor field test results for VAPEX—a similar process (NSolv, “Developing an In Situ Process . . . ” NSolv website, 2012).
      • Hard to start-up process.
    • (vii) A combustion process, using a toe-to-heel geometry, called THAI (Toe-to-Heel Air Injection) has also been suggested for thin pay resources (FIG. 22). The process uses a horizontal well to collect heated oil 8 and combustion gases 22. A vertical well, completed near the toe of the horizontal well, injects compressed air 20. Assuming good high temperature oxidation (HTO) combustion the process is potentially less costly than SAGD. The process was developed in the laboratory using physical models (Greaves, M. et al, “THAI—New Air Injection Technology . . . ”, SPE 99-15, June, 1995).
    • Petrobank Energy and Resources Ltd, Calgary, Alberta has purchased and developed proprietary rights to the technology and is developing a series of field pilots (“THAI” Wikipedia accessed 2012)). The initial pilot has been operating since 2006. Recently, Petrobank's reserves consultant dropped reserves related to THAI because of protracted poor performance (Energy Inc, “Petrobank suffers setback with THAI”. Mar. 8, 2012).
    • One of the problems with THAI is how to prevent air from short-circuiting the process and by-passing the reservoir by entering the production well upstream of the combustion front (FIG. 22). In the laboratory, the by-pass is prevented by the formation of a coke plug, in the production well, upstream of the combustion front. If this plug does not form in a field test, it is necessary to use a moveable high-temperature packer or a sliding sleeve. Either of these is a difficult task.
    • Another issue is that lateral growth can be slow. There is no/little steam to foster lateral growth and the geometry precludes a lateral flow component. Other problems, noted in the field tests, included corrosion, sand influx, plugging and explosions in the production well.
    • Other features/concerns with THAI include the following:
      • Air (not oxygen) is in the injectant oxygen-containing gas.
      • No steam is injected, except for start-up, concurrently with air (or oxygen).
      • Wet combustion (injection of water) is contemplated but not yet practiced.
      • There is no separate removal of non-condensable, combustion gases to vent wells or otherwise. These gases are forced to be removed by the single horizontal production well (FIG. 22). This can impair liquid production rates.
      • The field experience for THAI is poor (Calgary Herald, “Petrobank Technology earns Zero Grade”, 2012).
      • The current focus of THAI is on heavy oils, not bitumen (OGJ (2012))
    • (viii) Another, related combustion process is Combustion Overhead Gravity Drainage (COGD) also called Combustion Overhead Split Horizontal (COSH) (FIG. 23). Unlike THAI, this process is a top-down combustion EOR process. The process includes short paths for bitumen recovery, drainage to a horizontal production well, separate overhead vertical injector wells for compressed air 24 and separate vent gas wells 22 (horizontal or vertical) for combustion gas removal at the flank of the pattern boundaries (New Tech. Mag. “Excelsior files patent for ISC Process”, Sep. 25, 2009) (New Tech. Mag. “Excelsior searching . . . COGD . . . ” Nov. 20, 2009). The flank gas removal system promotes lateral growth—a problem for THAI. Also, unlike THAI, gas and liquid production is separate in the reservoir, the horizontal production well produces only liquids.
    • But the process has the following features/concerns:
      • The combustion reactions at the bitumen interface are complex and have not been verified by field tests.
      • There are no current/contemplated field tests for COGD or COSH.
      • The process contemplated air (not oxygen) injection.
      • The process has extra wells (extra capital expenses) compared to THAI or SAGD.
      • Focus of the process has been on heavy oil, not bitumen.
    • (ix) Toe-to-Heel Steam Flood (THSF) (FIG. 24) is another thermal EOR process suggested for thin pay reservoirs (Bagci. A. S. et al, “Investigation of THSF for heavy oil recovery” Energy Technology Data Exchange, 21025339, July, 2008). FIG. 55 (PRIOR ART) also depicts THSF but with a shared injection well.
    • So far, the focus for THSF has been in heavy oils not bitumen (Fatemi, S. M. et al, “Injection Well-Producer Well Combinations for Toe-to-Heel Steam Flooding (THSF), SPE 140703-MS, May 2011) (Fatemi, S. M. et al “Preliminary Considerations on the application of THSF . . . ”, Chem. Eng. Res. & Design, November 2011) (U.S. Pat. No. 5,626,193). Compared to conventional (vertical-well) steam floods, THSF has purported better stability (i.e. gravity stabilizes the process) and better recoveries (Turta, A. T. et al, “Preliminary Considerations on the application of THSF . . . ” SPW, 130444-PA, JCPT, November 2009). A small amount of non-condensable gas added to the steam was shown to improve performance (Turta (2009)). But by problems include high costs of steam and lack of field tests.
    • But once communication is established between the injector well 6 and the producer well 8, there is little pressure differential to push oil to the producer well, without significant steam breakthrough to the production well. Thus if steam breakthrough is avoided, the main mechanism is gravity drainage with progression of the GD steam chamber from toe-to-heel. The process is now a GD process not a SF.
    • (x) A single-well version of THSF (SWTHSF) was also identified with a geometry and process similar to SWSAGD (U.S. Pat. No. 5,626,193). The focus was on thin pay heavy oils, not bitumen, and insulated tubing was used for the steam injector. The proposed well trajectory, including the tow-region for steam injection, was horizontal. But, problems/concerns are similar to THSF.
    • (xi) We can summarize the currently proposed alternatives for thin pay bitumen EOR as follows:
      • All of the alternatives have been studies mostly using mathematical simulation models.
      • There has been little (or no) focus on thin pay bitumen resources.
      • There has been some focus on thin pay heavy oil resources (THSF, SWTHSF) with no discussion of bitumen EOR.
      • Some of alternatives have included physical model tests (e.g. ESSAGD, VAPEX, N-SOLV, THAI . . . ), but again, not focussed on thin pay bitumen resources.
      • A few of the bitumen alternatives (e.g. ESSAGD, VAPEX, SWSAGD, THAI . . . ) have been field tested, but not focussed on thin pay bitumen.
      • Some of the bitumen alternatives are now focussed on heavy oil applications (not bitumen) (e.g. THAI, VAPEX, SWSAGD . . . )
      • None of these processes has resulted in any field test or lab physical-model tests, focussed on thin pay bitumen resources.
      • Some of the processes are projecting field tests (e.g. N-SOLV) but again not focussed on thin pays.

Steam Assisted Gravity Drainage with added Oxygen (“SAGDOX”) is an improved thermal EOR process for bitumen recovery. The process may use a geometry similar to SAGD (FIG. 36), but it also has versions with separate wells or segregated sites for oxygen 26 injection and non-condensable vent gas 22 removal (FIGS. 26, 27, 28, 29, 30, 31, 32, 33). The process may be considered as a hybrid SAGD and ISC process. ISC is a process that so far, has shown little application for bitumen recovery. Examples of ISC are depicted in FIGS. 43 and 54 (PRIOR ART).

The 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. 34, Butler (1991)). Combustion temperatures are independent of pressure and they are higher than saturated steam temperatures (FIGS. 4, 56). 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 ha 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. Residual bitumen, in the steam-swept zone, is heated, fractionated and pyrolyzed by of combustion gages to provide coke that is the actual fuel for combustion. A gas chamber is formed containing steam combustion gases, vaporized connate water, and other gases (FIG. 35). The large gas chamber can be subdivided into a combustion-swept zone 100, a combustion zone 110, a pyrolysis zone 120, a hot bitumen bank 130, a superheated steam, zone 140 and a saturated steam zone 150 (FIG. 35). Condensed steam drains from the saturated steam zone 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 at the edge of the combustion front (FIG. 35). Condensed water and hot bitumen 8 are collected by the lower horizontal well and conveyed (or pumped) to the surface (FIG. 36).

Combustion non-condensable gases 22 are collected and removed by vent gas wells or at segregated vent gas sites (FIGS. 36, 31). Process pressures may be controlled (partially) by vent gas production, independent of liquid production rates. Vent has 22 production may also be used to influence direction and rate of gas chamber growth

This intention involves the application of the SAGDOX process to thin pay bitumen reservoirs (i.e. thin pay zones).

SUMMARY OF THE INVENTION

    • According to one aspect, them is provided, a process to recover liquid hydrocarbons, from at least one thin pay zone in a hydrocarbon bitumen reservoir via a substantially horizontal production well wherein said hydrocarbon bitumen reservoir further comprises, a top and a bottom; said process comprising the use of Steam Assisted Gravity Drainage with Oxygen (SAGDOX) wherein:
    • i) steam is injected into said hydrocarbon bitumen reservoir above said substantially horizontal production well;
    • ii) oxygen is injected into said hydrocarbon bitumen reservoir above said substantially horizontal production well; and
    • iii) liquid hydrocarbon is recovered via gravity drainage into said substantially horizontal production well.

Preferably, said at least one thin pay zone is segregated from said hydrocarbon reservoir, such that fluid flow is contained within said one thin pay zone.

Preferably, said steam is injected proximate said at least one thin pay zone.

Preferably, said oxygen is injected proximate said at least one thin pay zone.

More preferably both said steam and said oxygen are injected proximate said at least one thin pay zone.

More preferably, said oxygen to said steam are injected into said reservoir, preferably proximate said at least one thin pay zone, a ratio from about 0.05 to 1.00 v/v.

In one embodiment, said horizontal well further comprises a toe section and a heel section. Preferably, said toe section is at a first level in said reservoir and said heel section is at a second level in said reservoir. More preferably said heel section is closer to said bottom and said toe section is closer to said top of said reservoir.

In another embodiment, said SAGDOX has a geometry selected from a Toe-to-Heel SAGDOX (“THSAGDOX”) geometry and a Single Well SAGDOX (“SWSAGDOX”) geometry.

Preferably said at least one thin pay zone has a thickness of less than about 25 metres. More preferably said at least one thin pay zone has a thickness of less than about 15 metres.

Preferably the substantially horizontal production well is used to produce water and liquid hydrocarbons and is completed within 2 metres of the reservoir bottom.

Preferably the steam is injected within 20. metres from the substantially horizontal production well, and the oxygen is injected within 50 metres from the substantially horizontal production well; wherein, said substantially horizontal, production well further comprises at least one a perforation zone less than 50 metres in length.

In one embodiment, the injection of oxygen and steam is controlled in the range from 0.05 to 1.00 (v/v) oxygen:steam ratio.

Preferably the ratio of oxygen to steam is increased during the process so that the oxygen/steam ratio (v/v) is maximized proximate the end of the process.

In another embodiment, said THSAGDOX further comprises an uplifted toe section in said substantially horizontal production well.

According to one aspect, there is provided a process to recover liquid hydrocarbons, from a hydrocarbon bitumen reservoir, via a substantially horizontal production well, wherein said hydrocarbon bitumen reservoir has at least one thin pay zone, a top, and a bottom preferably at least one thin pay bitumen containing zone of less than about 25 metres thickness; said process comprising Steam Assisted Gravity Drainage with Oxygen (SAGDOX) selected from the group consisting of Toe-to Heel SAGDOX (THSAGDOX) and Single Well SAGDOX (SWSAGDOX).

In one embodiment, said substantially horizontal well further comprises a toe section and a heel section. Preferably said toe section is at a first level in said reservoir and said heel section is at a second level in said reservoir. Preferably said heel section is closer to said bottom and said toe section is closer to said top.

In one embodiment said SAGDOX is THSAGDOX, more preferably said THSAGDOX further comprises said horizontal well with an uplifted toe section.

In another embodiment said SAGDOX is SWSAGDOX.

In one embodiment, the horizontal production well is completed within about 2 metres of the bottom.

In another embodiment, steam is injected proximate said horizontal production well via at least one steam injector, preferably within about 20 metres from the horizontal production well.

In another embodiment, oxygen, preferably oxygen containing gas is injected proximate said horizontal productions well via at least one oxygen injector, preferably within about 50 metres from the horizontal production well and more preferably with a perforation (contact) zone less than about 50 metres in length.

In another embodiment, a ratio of oxygen to steam, is controlled in the range from about 0.05 to 1.00 (v/v).

In another embodiment, non-condensable gases produced by combustion and inert gases in the oxygen (vent gas) are removed by at least one vent gas outlet, preferably separately removed. Most preferably separately removed from about 5 to about 75 metres from the horizontal production well.

In another embodiment, said at least one steam injector and said at least one oxygen injector is separated from said at least one vent gas outlet by at least about 100 metres.

In another embodiment, the reservoir is slanted and the horizontal production well is less than about 2 metres from the bottom of the reservoir at its closest point.

In another embodiment, the at least one steam injector and the at least one oxygen containing gas injector is within 10 metres of the horizontal production well.

In another embodiment, said steam is injected into said reservoir using at least one parallel horizontal steam injection well in a plane substantially vertical to the horizontal production well, preferably from about 3 about 8 metres above the horizontal production well.

In another embodiment, said steam is injected using at least one single substantially vertical well, preferably a plurality of substantially vertical wells.

In another embodiment, oxygen containing gas is injected into the reservoir using at least one single substantially vertical well, preferably a plurality of substantially vertical wells.

In another embodiment, vent gas is removed from the reservoir using at least one single substantially vertical well, preferably a plurality of substantially vertical wells.

In another embodiment, said steam and oxygen containing gas are comingled, preferably at the surface, and, injected into the reservoir using at least one single substantially vertical well, preferably a plurality of substantially vertical wells.

In another embodiment, said steam and oxygen containing gas are substantially segregated preferably by at least one packer, more preferably by a plurality of packers, and injected separately into the reservoir, preferably by at least one single substantially vertical well, more preferably by a plurality of substantially vertical wells.

In another embodiment, said steam and oxygen containing gas are substantially segregated using concentric tubing and packers, preferably with steam in the central tubing surrounded by oxygen containing gas in an adjacent annulus, and with oxygen containing gas injected at an elevation in the reservoir higher than said steam injected elevation.

In another embodiment, a single substantially vertical well is used to inject steam and oxygen containing gas into said reservoir, where the single substantially vertical well is completed within about 50 metres from the toe of the horizontal production well.

In another embodiment, the oxygen containing gas injection is accomplished using as segregated toe section of the horizontal production well.

In another embodiment, the vent gas removal site is a segregated annulus section in the heel rise section of the horizontal well.

In another embodiment, said steam and oxygen containing gas are comingled at the surface and injected into the reservoir using a segregated toe section of the horizontal well.

In another embodiment, said oxygen containing gas and steam are substantially segregated and simultaneously injected into the reservoir from a segregated toe section of the horizontal well.

Preferably said oxygen containing gas and steam are substantially segregated by using concentric tubing and packers, said concentric tubing further comprising central tubing and an adjacent annulus, with steam in the central tubing surrounded by oxygen-containing gas in the adjacent annulus.

In another embodiment, said vent gas is removed in a segregated annulus in the heel rise section of the horizontal well.

In another embodiment, the toe of the horizontal production well is drilled upwards and completed so the lowest injection orifice (for injection of at least one of steam; oxygen, containing gas and both) is greater than 2 metres higher than the horizontal plane of the horizontal section of the horizontal production well.

In another embodiment, the horizontal production well is drilled parallel to the reservoir bottom in an up-dip direction in a slanted reservoir, so that the lowest injection orifice is more than 2 metres higher in elevation than the highest liquid production orifice.

In a preferred embodiment, the ratio of oxygen, in oxygen containing gas, to steam is increased during the maturation of the process so that the oxygen to steam ratio (v/v) is maximized at the end of the process life.

In a preferred embodiment, an extender tube proximate the toe of the horizontal production well is used, preferably to ensure that the lowest pressure in the production well is proximate the toe.

Preferably said vent gas wells (sites) and steam/oxygen injectors are separated by at least 100 metres.

In one embodiment, the oxygen containing gas is oxygen with an oxygen content of 95 to 99.9 (v/v) percent.

In another embodiment, the oxygen containing gas is air, preferably enriched air, with an oxygen content of 21 to 95 (v/v) percent.

In one embodiment the hydrocarbon liquid is bitumen (API density <10; in situ viscosity >100,000 cp.).

In another embodiment the hydrocarbon liquid is heavy oil (10<API<20; in situ viscosity 1000 cp.)

In one embodiment, the substantially horizontal production well has a length greater than 1000 metres.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 depicts a traditional SAGD geometry

FIG. 2 depicts a pattern end view of a SAGD life cycle

FIG. 3 depicts saturated steam properties

FIG. 4 depicts Pressure versus Temperature for Saturated Steam

FIG. 5 depicts bitumen Viscosity versus Temperature of Long Lake bitumen

FIG. 6 depicts the Gravdrain Equation for SAGD Bitumen Productivity

FIG. 7 depicts fractional residual bitumen in pores versus saturated steam temperature and equivalent hydrostatic depth for residual bitumen in steam-swept zones

FIG. 8 depicts SAGD hydraulic limitations

FIG. 9 depicts the Top of the McMurray Formation

FIG. 10 depicts the Thickness of the McMurray Formation

FIG. 11 depicts the Porosity Interval of the McMurray Formation

FIG. 12 depicts the Bitumen Pay Thickness of the McMurray Formation

FIG. 13 depicts the API Gravity of the McMurray Formation

FIG. 14 depicts a Traditional SAGD Recovery Geometry

FIG. 15 depicts a first SAGD geometry for recovery in a thin pay zone

FIG. 16 depicts a second SAGD geometry for recovery in a thin pay zone

FIG. 17 depicts a third SAGD geometry for recovery in a thin pay zone

FIG. 18 depicts a simple SAGD model

FIG. 19 depicts unrecovered bitumen at end of life processing versus net pay thickness

FIG. 20 depicts a SWSAGD schematic and well configuration (with packers)

FIG. 21 depicts a SWSAGD schematic and well configuration (without packers)

FIG. 22 depicts a THAI geometry for ISC

FIG. 23 depicts a COGD/COSH geometry for ISC

FIG. 24 depicts a typical SAGDOX geometry according to the present invention

FIG. 25 depicts SWSF geometries for SWSAGD, SWSAGDOX, SWSF(U) and SWSAGDOX(U)

FIG. 26 depicts a first embodiment of a THSAGDOX according to the present invention

FIG. 27 depicts a second embodiment of a THSAGDOX according to the present invention

FIG. 28 depicts a third embodiment of a THSAGDOX according to the present invention

FIG. 29 depicts a fourth embodiment of a THSAGDOX configuration and piping schematic according to the present invention

FIG. 30 depicts an embodiment of a SWSAGDOX configuration according to the present invention

FIG. 31A depicts an embodiment of a SWSAGDOX with centralized packers with steam and oxygen being premixed, according to the present invention.

FIG. 31B depicts an embodiment of a SWSAGDOX with centralized packers with steam and oxygen being segregated, according to the present invention.

FIG. 31C depicts an embodiment of a SWSAGDOX with centralized packers with steam and oxygen being segregated and isolated, according to the present invention.

FIG. 31D depicts an embodiment of a SWSAGDOX with centralized packers, steam and oxygen mixed, and a bitumen pump, according to the present invention.

FIG. 31E depicts an embodiment of a SWSAGDOX with centralized packers with steam and oxygen segregated, and a bitumen pump, according to the present invention.

FIG. 32 depicts an embodiment of a SWSAGDOX(U) schematic and associated piping schematic according to the present invention

FIG. 33 depicts a second embodiment of a SWSAGDOX(U) schematic and associated piping schematic according to the present invention

FIG. 34 depicts HHV versus H/C ratio of fuel

FIG. 35 depicts typical SAGDOX process mechanisms

FIG. 36 depicts a typical THSF

FIG. 37 depicts ISC minimum air flux rates

FIG. 38 depicts Steam and Oxygen Combustion Tube Tests II

FIG. 39A depicts a SAGDOX geometry according to the present invention.

FIG. 39B depicts a SAGDOX geometry (THSAGDOX) according to the present invention.

FIG. 39C depicts a SAGDOX geometry (SWSAGDOX) according to the present invention.

FIG. 40 depicts a multiple well THSAGDOX geometry with initial steam and oxygen injection at the toe of the production well according to the present invention

FIG. 41 depicts a multiple well THSAGDOX geometry with initial steam and oxygen injection at the middle of the production well according to the present invention

FIG. 42 depicts the recovery pattern of a gas chamber during various stages of THSAGDOX

FIG. 43 depicts a conventional ISC

FIG. 44 depicts a multiple well THSAGDOX geometry with alternating oxygen/steam and vent gas wells according to the present invention

FIG. 45 depicts SWSAGDOX and SWSAGDDOX(U) hydraulic limitations

FIG. 46 depicts a typical SWSAGD(U) schematic and associated piping schematic

FIG. 47 depicts oxygen pipe and tubing design

FIG. 48 depicts an embodiment of a THSAGDOX with a shared injection well for oxygen and steam according to the present invention

FIG. 49 depicts an embodiment of a SWSAGDOX geometry in a tilted thin pay zone according to the present invention

FIG. 50 depicts a THSAGDOX liquid drawdown at the heel and toe of the production well

FIG. 51 depicts a SWSAGD in tilted pay zones

FIG. 52 depicts SWSAGD in tilted pay zones

FIG. 53 depicts TH geometries for THSF, THISC (or THAI) and THSAGDOX

FIG. 54 depicts SWISC process

FIG. 55 depicts a THSF with a shared injection well

FIG. 56 depicts Steam and Oxygen Combustion Tube tests I

FIG. 57 depicts a three well THSAGDOX geometry according to the present invention

 DETAILED DESCRIPTION OF THE INVENTION

Preferred parameters in SAGDOX geometries of the present invention in thin pay zones include the following:

    • (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. 37)
      • 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. 37), 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. 36, 26); 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. 31(b); or 4) the entire injection string is a corrosion resistant alloy (FIG. 31(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. 56 and 38, Moore (1994)). This is also confirmed by the operation of smokeless flares, where steam is added to improve combustion and reduce smoke (Stone (2012), EPA (2012), Shore (1996)). The process to gasify fuel also adds steam to the partial combustor to minimize soot production (Berkowitz (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 geometries for SAGDOX (FIG. 39a-c).
      • 39b (THSAGDOX) and 39c (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:
      • (i) 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.
      • (ii) Adjust oxygen/steam ratios (v/v) to meet a target ratio, subject to a range limit of 0.05 to 1.00
      • (iii) Adjust vent gas removal rates so that the gases are predominantly non-condensable gases, oxygen cement is less than 5.0% (v/v), and to attain/maintain pressure targets.
      • (iv) Adjust steam and oxygen injection rates (subject to (ii) above), along with (iii) above, to attain/maintain pressure targets.

THSAGDOX

Although SAGDOX may also be used for thin pay bitumen recovery, the twin horizontal wells (FIG. 36) are difficult to fit within the thin pay resource limits, the well count is increased compared to SAGD the capital expenses are also increased.

THSAGDOX (Toe-to-Heel SAGDOX) is a preferred version of SAGDOX that can be applicable to thin pay EOR., using a mixture of steam 6 and oxygen 26 to supply energy rather than steam alone. The horizontal liquid-production well of SAGDOX (and SAGD) is retained so that bitumen drainage can be accomplished in short path lengths. Steam is much more mobile than heated bitumen, so the horizontal steam injection of SAGDOX or SAGD is replaced by a vertical well injecting steam 6 and oxygen 26, where oxygen 26 is preferably injected near the top of the pay zone. Vent gas 22 (non-condensable combustion gas) is removed either through a separate vertical well or wells, or in a segregated portion (annulus) near the vertical section of the horizontal production well. Vent gas 22 removal is preferably conducted near the top of the net pay zone.

The vertical oxygen/steam injector well is designed to 1) segregate steam 6 and oxygen 26 to minimize corrosion and 2) preferably inject oxygen 26 proximate the top of the pay zone and steam 6 proximate the lower region in the pay zone. This has the added benefit that oxygen gas 6 in the annulus, around a steam injector tubing, is a good heat insulator and this will prevent/minimize heat losses from steam to the overburden, as steam is conveyed from the well head to the reservoir.

FIGS. 26, 27, 28, 40, and 57 show schematics for various THSAGDOX process schemes. FIG. 29 shows a piping schematic that can apply to all of these process types.

The process is started by circulating steam 6 in the production horizontal well and by cycling steam 6 (huff-and-puff) in the vertical wells until the wells communicate with each other (i.e. fluids flow from one well to another). After communication is established, wells are converted to THSAGDOX operation with steam 6 and oxygen 26 injection and water/bitumen 8 and vent gas 22 production.

The THSAGDOX horizontal production well may be longer than a SAGD well for the same bitumen productivity, because there is less water flowing in the well. FIGS. 40, 41, and 57 show multiple vertical well versions of THSAGDOX to facilitate longer horizontal wells or easier start-up and operation of shorter wells. Separate vertical wells close to the toe steam/oxygen injector wells are initially used to vent as removal wells and subsequently, converted to steam/oxygen injectors as the combustion front moves from near the toe of the horizontal well toward the heal of the horizontal well (FIG. 42). This enables fast start-up and improved conformance during the maturation of the process.

Another version of this scheme starts the combustion near the mid point of the horizontal well, with the combustion front moving both toward the toe and heel of the horizontal production well (FIG. 41).

Feature of these THSAGDOX process schemes include the following:

    • Separation is retained between 02 injection and vent gas removal. Vent gas wells may be used to control conformance of the ISC process part of THSAGDOX.
    • The process adds a 3D component mechanism (flooding) with longitudinal reservoir flows forced by the geometry.
    • The process may reduce the capital cost of wells by reducing well count, reducing well length, using vertical rather than horizontal wells, or by reducing the size (diameter) of wells.
    • The process reduces operating costs. Oxygen is less costly than steam per unit energy delivered to the reservoir.
    • The process may use a tapered oxygen strategy, where oxygen concentration is increased during the life of the projects to reduce costs, extend useful project life and increase bitumen recovery.
    • The process may use a pump, in the horizontal well, if necessary to help produce bitumen and water.
    • The process will produce extra water compared to steam injection. Connate water will be vaporized in the combustion swept zone (FIG. 35). Water is also produced as a product of combustion. Depending on leakage or retention rates in the reservoir, THSAGDOX will likely produce more water than it injects as steam.
    • Hot combustion gases will reflux some water to maintain a good water/steam inventory in the reservoir.
    • The process also retains all of the SAGDOX benefits.
    • Carbon dioxide produced as a combustion product is concentrated in vent gas (or dissolved/concentrated in liquid product stream) and should be suitable for sequestration.
    • Oxygen may be economically pipelined from a distant site without energy losses.
    • Water produced from steam injection may help isolate the horizontal production well and minimize non-condensable gas intrusion into this well.
    • The vertical well used for oxygen and steam injection may minimize heat losses if steam is in the inner tube and oxygen is in the annulus. Oxygen gas is a good insulator to retain heat in the steam. It is preferable that steam injection is in the central tube and oxygen surrounds steam as an insulator (FIG. 29).

It may be suggested that conversion of THSAGDOX to a pure combustion (ISC) EOR process is appropriate particularly for this reason because oxygen is less costly than steam as a source of energy to heat up reservoir bitumen. But, retention of steam as injectant is desirable because:

    • Steam stabilizes combustion and improves combustion kinetics
    • Steam preheats combustion zones
    • Steam acts as a good heat transfer medium—better than hot combustion gases (heat pump effect)
    • Steam can effect lateral growth (a problem with some ISC processes)
    • Steam, when condensed, can help cover/seal the production well and inhibit non-condensable as break through to the well
    • Steam/water can be refluxed by hot combustion products
    • In the production well, water/bitumen mixtures have lower viscosities than bitumen by itself.
    • Steam injection increases the size of the steam-swept zone to help ensure that combustion is focussed on residual bitumen (coke)
    • Steam creates flow paths for combustion.

It may also be suggested that water injection, not steam, is a better way to produce steam in the reservoir and improve energy efficiency. Water may scavenge heat from the combustion swept zone (FIG. 35) to produce steam in situ, rather than using the on the surface to produce steam in a boiler. This was the preferred way to accomplish wet combustion using vertical injector/producer wells (FIG. 43). But, this is not a good idea using Steam Flood with Oxygen in Thin Pay Reservoirs (SFOXT) geometries for the following reasons:

    • In SAGDOX geometry compared to ISC geometry (FIG. 43), flow paths from injector to producer are very short. If water were injected, using a vertical injector (FIG. 29) it would easily by-pass the process and flow directly to the production well.
    • Alternately if the combustion front is close to the injector, water could quench combustion and cause low temperature oxidation (LTO) to start.

It may be suggested that because the hot zone in THSAGDOX is localized to the oxygen 26 injection zone and then proceeds toward the toe of the horizontal well (FIG. 42), that the bitumen production rate for THSAGDOX can be expected to be less than SAGD, where the steam chamber grows along the length of the horizontal producer at the same time (FIG. 2). THSAGDOX compensates for this by producing heat at a higher temperature than steam, by using steam 6 as a heat transfer agent and by refluxing some steam. This may also be improved by using multiple oxygen 26 injection sites (FIG. 44) so that combustion can be spread out along the well and multiple combustion sites will grow simultaneously.

Because there is less fluid in a THSAGDOX horizontal well compared to a SAGD horizontal well due to less water produced per barrel of bitumen, for the same pressure drop a THSAGDOX horizontal well can be much longer than a same-size SAGD horizontal well (up to about 2500 metres), depending on the oxygen level in the injectant oases

SWSAGDOX

THSAGDOX is better than SAGD for thin pay bitumen EOR because of the reduction in well count and cost (1 horizontal+1 vertical, were the vertical well can be shared between patterns) compared to SAGD (2 horizontal wells) and a reduction in energy costs by using oxygen gas for combustion. As pay thickness decreases, THSAGDOX capital expenses may be too much to justify bitumen EOR.

Another version of SAGDOX called SWSAGDOX (Single Well SAGDOX) may cut costs even more. The process uses a single horizontal well to effect the SAGDOX process. Portions of the well are segregated for steam 6 and oxygen 26 injection and for bitumen/water 8 and vent gas 22 production, using concentric tubing and segregation packers 18 (FIGS. 30 and 31a-e). Capital expenses are lowered both by reducing the well count (to 1) and by potential retrieval and reuse of various completion components (packers and tubing).

The simplest version of SWSAGDOX is shown in FIG. 31(a), 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 30 for the oxygen and steam mixture would be an alloy-steel or another corrosion-resistant material. An alternate scheme, to obviate corrosion, is to superheat the oxygen+steam mixture 30 to prevent steam condensation on the injectant tubular walls. Heat losses, particularly for deep thin pay bitumen reservoirs, from this mixture may be an issue. The toe of the horizontal well 40 (FIG. 31(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 improvement on this design (FIG. 31(b)) uses tubing to segregate oxygen and steam 30, with oxygen 26 surrounding the steam injector tube. The oxygen gas 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 40 is still exposed to steam+oxygen corrosion.

Yet another improvement is shown in FIG. 31(c) where a packer 18 used to segregate oxygen and steam 30 prior to entering the reservoir. This can minimize toe corrosion and still insulate the steam line to reduce heat losses.

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

Another issue for SWSAGDOX. (FIG. 30, 31a-e) is that steam injection is at the same (horizontal) level as liquid petroleum. SAGD prevents steam breakthrough to the producer or flooding of the steam injector, by completing the producer injector with an offset spacing of about 5 metres (FIG. 1) and controlling the process with a steam/liquid interface between the injector and producer (FIG. 8). The interface is tilted by the pressure drop in the producer, but with good operation prevents steam by-pass and flooding of the injector. The highest point of the interface is at the toe of the horizontal wells.

This sub-cool strategy can be retained by SAGDOX and THSAGDOX injection of steam (and oxygen) above the plane of the horizontal production well.

However, in SWSAGDOX (FIG. 45), if the steam 6+oxygen 26 section is flat, and one operates the process so that liquid covers the production section to obviate steam 6+oxygen 26 break through, the end of the horizontal well will be flooded. This will inhibit steam 6+oxygen 26 injection and harm conformance. If one produces liquid at a faster rate to remove this problem, the entire production section will be open to steam 6 and oxygen 26 breakthrough.

The solution shown at the bottom of FIG. 45 and in FIGS. 25, 32, 33, and 46 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 one to retain liquid covering the horizontal production section so that oxygen 26 and steam 6 don't break through to the producer well and to have oxygen 26 and steam 6 injection above the liquid interface 12 so the injection is not flooded (FIG. 45). The process for such a geometry is termed SWSAGDOX(U) where U denotes uplift of the toe region of the horizontal well. This is a preferred geometry for SWSAGDOX.

SWSAGDOX process has the advantages of THSAGDOX processes, with the following additional features:

    • The horizontal well interior tubing can be retrieved and reused so that its cost can be spread amongst several process units.
    • This is the least cost option (capital expenses) 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. 31(a))
    • The design retains separate vent gas removal
    • If steam 6 occupies the central injection tube, oxygen gas 26 can help insulate the steam tube and minimize heat losses (FIGS. 31a-e)
    • 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.

The geometry of SWSAGDOX (FIG. 30) is similar to the geometry for the SWSAGD (FIG. 20), but with the following process distinctions:

    • SWSAGDOX uses steam+oxygen injection. SWSAGD uses steam only
    • SWSAGD injects steam at the same elevation as production. A preferred version of SWSAGDOX (FIG. 32), injects steam and oxygen at higher elevation than liquid production.
    • SWSAGD has had disappointing field tests.
    • SWSAGD was focused on heavy oil EOR, not bitumen.
    • SWSAGD was concerned by heat leakage from steam injectors to produced fluids and spurred development of insulated tubing for steam injection. SWSAGDOX insulates the steam tubing using oxygen in the annulus (FIG. 31B).
    • Because oxygen has about 10 times the energy density as steam, piping for SWSAGDOX can be much smaller than piping for SWSAGD.
    • SWSAGD is a saturated steam process. Temperatures are limited by the properties of saturated steam. At the same pressure, SWSAGDOX will operate at higher T than SWSAGD.

An important issue for SAGDOX and SWSAGDOX is to isolate various zone using packers that are operable at high temperatures. This is an active area of development for oil suppliers (Haliburton, “Zonal Isolation for Steam Injection . . . ” website, May 2012) (Schlumberger, “Packer Systems”, website, May 2012). It is also of particular concern in the Geothermal industry, where conditions may be more severe and corrosive than for EOR (DOE “Enhanced Geothermal Systems Wellfield Construction Workshop” San Francisco, Oct. 16, 2007). Small, self-sealing packers are also being developed for smaller well sizes (OGJ “Self-Setting Thermal Packers Help Cyclic Steam” 1998).

Current technology (˜2012) is available for thermal packers for larger pipe sizes and up to 600° F. (316° C.) (Haliburton (2012)) and for small tubing packers up to 400° C. (OGJ (1998)). The pressure seals are rated for pressures exceeding expectations for SAGDOX and SWSAGDOX processes. Most packers are retrievable and can be used many times. The small tubing packers have been operated in the field for up to 5000 pressure cycles/yr. (OGJ (1998)).

Thermal packers for SAGDOX and SWSAGDOX processes are conventional technology, currently available.

SAGDOX and related processes (THSAGDOX, SWSAGDOX, SWSAGDOX(U)) can have a higher well count than SAGD, depending on process design. This can be partially (or totally) offset by reduced pipe sizes using SAGDOX. Pipe size reductions are due to 2 factors—oxygen contains about 10 times the energy content compared to steam (Table 2); also because SAGDOX injects less steam than SAGD for the same energy injection rate, the production fluids (water+bitumen) can be less than SAGD fluids for the same bitumen production rate.

Assuming the following pipe design criteria for a shallow SAGD project:

    • (i) 500 bbls/d bitumen productivity.
    • (ii) 1 MMBTU energy demand per bbl bitumen (SOR˜3)
    • (iii) Steam at 1000 BTU/lb. heat content.
    • (iv) 100 psia, 160° C. steam injection (50 m depth hydrostatic pressure (FIG. 4))
    • (v) 25 ft/sec. design for steam injection
    • (vi) 1 ft/sec. for liquid (water+bitumen) production
    • (vii) all steam injected is produced as hot water

One can then calculate for a SAGD project, that steam demand is 500,000 lb/day=1428.6 bbls/day=28.57 CF/sec, at reservoir conditions. Using the design criteria above, the steam injector pipe has a diameter of 7.23 inches and production tubing has a diameter of 4.79 inches.

Applying this to SAGDOX-related projects for the same conditions, FIG. 47 shows pipeline velocity limits for oxygen delivery design, using carbon steel or stainless steel pipes, where potential particulate impingement is the design limit—the worst case (Asia Industrial Gases Association “Oxygen Pipeline Systems” 2005). One may assume the following, in addition to the above:

(i) 100 ft/sec oxygen velocity design, at downhole conditions (FIG. 47)

    • (ii) Use a SAGDOX (35) mixture, 35% oxygen (v/v) in a steam oxygen mix; 84.5% of heat injected comes from oxygen combustion (Table 2)

One can then calculate pipe sizes for oxygen and steam delivered in separate pipes. The oxygen demand is 880 MSCFD=3.36 tonnes/day.

The steam demand drops to 77,500 lbs/day=221 bbls/day=4.18 cf/sec, at reservoir conditions. The pipe size for oxygen injection is 2.09 inches in diameter. The pipe size for steam injection is 2.76 inches in diameter.

If the steam and oxygen are conveyed in a single pipe (FIGS. 26, 27, 29), the total pipe size needed is 3.47 inches (ignoring wall thickness).

The production well is also downsized, because less steam is injected and water produced. The calculated well size is 2.93 inches, in diameter.

SAGDOX-related processes also must produce vent gases. The vent gas volumes are similar to the oxygen injection volumes, with the same size pipe requirements (2.09 inches, in diameter)

It is often assumed, for pipelines, that capital expense is proportional to pipe diameters or to cumulative pipe diameters for multiple piping. One can do the same here, as follows:

total D inches % SAGD (eg. FIG. 1) 12.02 100 SAGDOX with separate wells for 9.87 82 all streams (e.g. FIG. 36) SWSAGDOX with all fluids 5.00 42 contained in a single well. (Single well D only, eg. FIG. 30, 31)

The SAGDOX versions all have less total pipe diameter. All SWSAGDOX pipes could be retained in a single 5″ pipe (not accounting for pipe wall thickness).

The preferred embodiments of THSAGDOX and SWSAGDOX of the present invention depend on the nature of the target reservoir—specifically the reservoir thickness, the reservoir continuity, the reservoir quality and the reservoir depth. The preferred version for SWSAGDOX is SWSAGDOX(U) with the up-lifted toe region.

There are 3 versions of THSAGDOX to consider:

    • (i) The simple version (FIG. 26) with a single vertical injector well for oxygen 26 and steam 6 completed near the toe of the horizontal producer and vent gas 22 removal accomplished using a segregated portion of the horizontal well completed near the top of the pay zone. The piping/tubing is simple with oxygen 26 delivered in the annulus to insulate the steam tube and to minimize heat losses. The production well, with vent gas 22 removal retains the option to use submersible pumps if necessary (FIG. 29). This system can best be applied for deposits (10 to 25 metre thickness) preferably segregated from said reservoir, relatively unimpaired reservoirs (little/no shales, lean zones), and for moderate continuity (well lengths 500-1000 metres).
    • (ii) If a similar more extensive and unimpaired reservoir is present, one can have adjacent patterns and the patterns can share vertical wells, a scheme such as FIG. 36 can share separate vent wells. This is not too costly and offers the prospect of conformance control using the separate vent wells. Another version, show in FIG. 48, allows for sharing of vertical injection wells, to reduce costs,
    • (iii) If a similar deposit (10 to 25 metre thickness) is present but we expect some reservoir impairments, resulting in lower productivity expectations, it is preferred to consider longer horizontal wells with multiple injection/vent wells, where the injection/vent wells can be converted from injection to vent uses (and vice versa) depending on performance (FIGS. 40, 41, 57). This gives, added flexibility for conformance control and performance control and production management in cases where the reservoir is impaired or may be impaired. Productivity need not suffer because we can use multiple injectors simultaneously (FIG. 44) and drill longer horizontal wells than SAGD (500-2500 metres).

Because of reduced well count and reusable completion components (tubing, packers), the thinnest reservoirs (5-15 metres) are best exploited using SWSAGDOX(U) process shown in FIGS. 30, 31a-e, 32, 33, 49. The process doesn't lend itself to well sharing (no vertical wells), but the capital expenses should be minimized.

One also has the choice for THSAGDOX, where one draws down liquids from the horizontal well. The conventional choice draws liquids from the heel region of the horizontal producer. But, one can also draw from the toe using a pipe extender (FIG. 29). The advantage of toe down is illustrated in FIG. 50. One can prevent the steam injector portion of the vertical injector well from being flooded by the liquid interface.

(1) Distinctions of THSAGDOX Compared to THAI (FIG. 53)

    • THSAGDOX removes vent gases using separate wells or segregated zones. THAI forces vent gases to be produced in the horizontal production well.
    • THSAGDOX operates on a gravity drainage process. Pressure differentials between gas injection and liquid product are very small. THAI operates as a flood (gas drive) process with significant pressure differentials between injection/production wells.
    • THSAGDOX injects steam to improve combustion, and to cover the production well with liquid to inhibit gas breakthrough. THAI makes no attempt to add steam or to cover the production well. Gas breakthrough is essential to the THAI process.
    • THSAGDOX injects steam and oxygen as sources of energy in the reservoir. THAI injects compressed air.
    • THSAGDOX covers the production well and injects oxygen at a high spot to prevent oxygen breakthrough to the production well. THAI relies on a moving coke blockage formed upstream of the combustion front in the horizontal producer to prevent air (oxygen) breakthrough.
    • THSAGDOX injects water (and refluxes) steam to encourage/stimulate lateral growth of the heated zone. THAI relies on hot combustion gases/heat conduction for lateral growth.
    • THAI has had a disappointing field test history.
    • THAI is (now) focussed on heavy oil EOR. THSAGDOX is focused on bitumen EOR.
    • THSAGDOX can use sub-cool control on the production well to ensure there is no gas or steam breakthrough to be produced.

(2) Distinction Between SWSAGDOX (FIGS. 17, 31, 31(a)) and SWSAGD (FIG. 20)

    • SWSAGDOX uses a mixture of oxygen and steam to deliver energy to the reservoir. SWSAGD uses steam only.
    • SWSAGDOX has a version (SWSAGDOX(U)) (FIGS. 32, 33, 45) where the toe of the horizontal well is drilled upward to segregate liquid production and steam/oxygen injection. SWSAGD has as flat horizontal well completion, where liquid flow to the producer can flood the steam injector (FIGS. 20 & 52)
    • Both SWSAGDOX and SWSAGD operate as gravity drainage processes. But due to the combustion component, the average T of the gas chamber for SWSAGDOX is higher than saturated steam T for SWSAGD.
    • SWSAGD has a disappointed history of field tests.
    • The combustion gases from SWSAGDOX migrate to the ceiling area of the gas chamber (FIG. 42) and help insulate the interface to reduce heat losses.
    • SWSAGD was focussed on thin pay heavy oil EOR. SWSAGDOX is focused on thin pay bitumen EOR.

(3) Distinctions of THSAGDOX (FIG. 18) and/or SWSAGDOX (FIG. 30, 32) Compared to SAGD (FIG. 1)

    • SAGD uses 2 parallel horizontal wells. THSAGDOX and SWSAGDOX use only one horizontal well.
    • SAGD is a 2D process—no longitudinal steam/liquid flows in the longitudinal direction for a homogeneous reservoir. THSAGDOX and SWSAGDOX are both 3D processes—the GD chamber (the gas and steam swept zones) grow in a longitudinal direction (FIG. 28).
    • SAGD uses saturated steam. THSAGDOX and SWSAGDOX inject mixtures of steam and oxygen (separately or together).
    • SAGD temperatures are limited to saturated steam T. The combustion component of THSAGDOX and SWSAGDOX produces heat in the reservoir at much higher T (600° C. vs 200° C.).
    • SAGD steam cannot vaporize water in the reservoir (connate water, water in lean zones . . . ). THSAGDOX and SWSAGDOX can vaporize reservoir water.
    • SAGD steam is used in a once-through process. THSAGDOX and SWSAGDOX can reflux water/steam.
    • SAGD doesn't substantially produce any connate water. THSAGDOX and SWSAGDOX produce connate water from the combustion-swept zone.
    • Energy costs for SAGD (saturated steam) are significantly higher than energy costs for THSAGDOX and SWSAGDOX.
    • SAGD is a net user of water (produced water recycle <100%). For higher oxygen levels (>9%), THSAGDOX and SWSAGDOX is higher than for SAGD.
    • SAGD has been successfully field tested. THSAGDOX and SWSAGDOX are in the development phase.
    • SWSAGDOX and THSAGDOX are designed to focus on this-pay bitumen (e.g. <25 metres thickness). SAGD focuses on thicker pays (>15 m)
    • SWSAGDOX and THSAGDOX can recover bitumen from the steam swept zone. SAGD leaves significant residual bitumen behind the steam swept zone.
    • Ultimate recovery for THSAGDOX will exceed SAGD recovery, because THSAGDOX recovers bitumen from the steam-swept zone and THSAGDOX can continue production to higher ETOR values because energy costs are less.
    • SAGD is diluted with N2. THSAGDOX vent gas is mostly CO2, suitable for sequestration.

(4) Distinctions of THSAGDOX (FIG. 26) Compared to COSH/COGD (FIG. 23)

    • COSH has 3 horizontal wells+3 (or more) vertical wells per patter (FIG. 23). THSAGDOX has a single horizontal well and single vertical well.
    • COSH relies on lateral horizontal vent wells to stimulate lateral growth. THSAGDOX relies on steam to stimulate lateral growth.
    • COSH has multiple vertical air injectors. THSAGDOX has a single oxygen/team injector.
    • COSH uses compressed air as oxidant. THSAGDOX uses oxygen gas.
    • Neither COSH nor THSAGDOX have been field tested.
    • COSH vent gas is primarily CO2 diluted with N2. THSAGDOX vent gas is undiluted CO2.

(5) Unique Features of THSAGDOX:

    • co-injection of steam and oxygen
    • range of 02/steam (v/v) ratios
    • synergy between 02/steam
    • focus on bitumen reservoirs (<25 metres thickness, preferably 10-25 metres thickness)
    • multiple well versions (FIGS. 48, 40, 41, 57) for longer horizontal wells
    • multiple combustion zone versions (FIG. 44)
    • oxygen insulation for team injection lines
    • tapered oxygen strategy—increase oxygen as project matures
    • focus on oxygen not air
    • TH geometry with multiple injectants, products.

(6) Unique features of SWSAGDOX:

    • single well process, 2 injectants, 2 products
    • features as above (5), (except for multiple well cases)
    • focus on thin reservoirs
    • updip completion versions (FIG. 49)
    • uplift toe versions (FIG. 32, 33) SWSAGDOX(U)
    • oxygen insulation for steam injection lines
    • focus on bitumen reservoirs, preferably thin reservoirs (e.g. <25 metres, more preferably <15 metres)
    • SW geometry with multiple injectants, products

TABLE 1 Alberta Bitumen Deposits (109 bbls) Athabasca Cold Lake Peace 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 Unaccessible 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 28 0 0 28 too shallow for SAGD Top gas 14 0 0 14 Others 36 −10 1 27 subtotal 811 11 74 962 Grand total 1369 201 129 1699 1. Source - Heidrick and Godin (2006) 2. Thin Pay (cut off = 10 m) 3. Numbers may not be additive due to rounding

TABLE 2 SAGDOX Injection Gases SAGDOX SAGDOX SAGDOX SAGDOX SAGDOX SAGD (5) (9) (35) (50) (75) % (v/v) oxygen 0 5 9 35 50 75 % heat from O2 0 34.8 50.0 84.5 91.0 96.8 BTU/SCF mix 47.4 69.0 86.3 198.8 263.7 371.9 MSCF/MMBTU 21.1 14.5 11.6 5.0 3.8 2.7 MSCF O2/MMBTU 0.0 0.7 1.0 1.8 1.9 20 MSCF Steam/MMBTU 21.1 138 10.6 3.3 1.9 0.7 Where: (1) Steam heat value = 1000 BTU/lb (2) O2 heat/combustion value = 480 BTU/SCF O2 (3) SAGD = pure steam (4) SAGDOX (9) = 9% (v/v) oxygen in steam-oxygen mixture

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 liquid hydrocarbons, from at least one thin pay zone in a hydrocarbon bitumen reservoir via a substantially horizontal production well wherein said hydrocarbon bitumen reservoir further comprises, a top and a bottom; said process comprising the use of Steam Assisted Gravity Drainage with Oxygen (SAGDOX) wherein:

i) steam is injected into said hydrocarbon bitumen reservoir above said substantially horizontal production well,
ii) oxygen is injected into said hydrocarbon bitumen reservoir above said substantially horizontal production well,
iii) liquid hydrocarbon is recovered via gravity drainage into said substantially horizontal production well.

2. The process of claim 1 wherein said steam is injected proximate said at least one thin pay zone.

3. The process of claim 1 wherein said oxygen is injected proximate said at least one thin pay zone.

4. The process of claim 2 wherein said oxygen is injected proximate said at least one thin pay zone.

5. The process of claim 1 wherein said oxygen and said steam are injected into said reservoir at a ratio from about 0.05 to 1.00 v/v.

6. The process of claim 1 wherein said substantially horizontal well further comprises a toe section and a heel section.

7. The process of claim 6 wherein said toe section is at a first level in said reservoir and said heel section is at a second level in said reservoir.

8. The process of claim 7 wherein said heel section is closer to said bottom and said toe section is closer to said top of said reservoir.

9. The process of claim 1 wherein said SAGDOX has a Toe-to-Heel SAGDOX geometry.

10. The process of claim 1 wherein said SAGDOX has a Single Well SAGDOX geometry.

11. The process of claim 1 wherein said at least one thin pay zone is segregated from said hydrocarbon bitumen reservoir.

12. The process of claim 1 wherein said at least one thin pay zone has a thickness of less than about 25 metres.

13. The process of claim 1 wherein said at least one thin pay zone has a thickness of less than about 15 metres.

14. The process of claim 1 wherein the substantially horizontal production well is used to produce water and liquid hydrocarbons and is completed within 2 m metres of the reservoir bottom.

15. The process of claim 1 wherein the steam is injected within 20 metres from the substantially horizontal production well.

16. The process of claim 1 wherein the oxygen is injected within 50 metres from the substantially horizontal production well; wherein said substantially horizontal production well further comprises at least one a perforation zone less than 50 metres in length.

17. The process according to claim 16 wherein the oxygen and steam are controlled in the range from 0.05 to 1.00 (v/v) oxygen: steam.

18. A process according to claim 17 wherein the ratio of oxygen to steam is increased during the process so that the oxygen/steam ratio (v/v) is maximized proximate the end of the process.

19. The process of claim 9 wherein said THSAGDOX further comprises an uplifted toe section in said substantially horizontal well.

Patent History
Publication number: 20170002638
Type: Application
Filed: May 5, 2016
Publication Date: Jan 5, 2017
Inventor: Richard Kelso KERR (Calgary)
Application Number: 15/147,853
Classifications
International Classification: E21B 43/24 (20060101); E21B 43/16 (20060101); E21B 43/243 (20060101); E21B 43/14 (20060101);