U.S. patent application number 14/078983 was filed with the patent office on 2014-06-19 for use of steam-assisted gravity drainage with oxygen ("sagdox") in the recovery of bitumen in lean zones ("lz-sagdox").
This patent application is currently assigned to NEXEN ENERGY ULC. The applicant listed for this patent is Richard Kelso Kerr. Invention is credited to Richard Kelso Kerr.
Application Number | 20140166278 14/078983 |
Document ID | / |
Family ID | 50929599 |
Filed Date | 2014-06-19 |
United States Patent
Application |
20140166278 |
Kind Code |
A1 |
Kerr; Richard Kelso |
June 19, 2014 |
USE OF STEAM-ASSISTED GRAVITY DRAINAGE WITH OXYGEN ("SAGDOX") IN
THE RECOVERY OF BITUMEN IN LEAN ZONES ("LZ-SAGDOX")
Abstract
A process to recover hydrocarbons from a reservoir having at
least one lean zone, wherein said lean zone has an initial bitumen
saturation level less than about 0.6, said process including: i)
Initially injecting of oxygen into said reservoir; ii) Allowing for
combustion of said oxygen to vaporize connate water in said at
least one lean zone; and iii) Recovering said hydrocarbons from
said reservoir.
Inventors: |
Kerr; Richard Kelso;
(Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Kerr; Richard Kelso |
Calgary |
|
CA |
|
|
Assignee: |
NEXEN ENERGY ULC
Calgary
CA
|
Family ID: |
50929599 |
Appl. No.: |
14/078983 |
Filed: |
November 13, 2013 |
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14078983 |
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13543012 |
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Current U.S.
Class: |
166/261 ;
166/256; 166/52 |
Current CPC
Class: |
E21B 43/2408
20130101 |
Class at
Publication: |
166/261 ;
166/256; 166/52 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 43/243 20060101 E21B043/243 |
Claims
1. A process to recover hydrocarbons from a reservoir having at
least one lean zone, wherein said lean zone has an initial bitumen
saturation level less than about 0.6, said process comprising: i)
Initially injecting of oxygen into said reservoir; ii) Allowing for
combustion of said oxygen to vaporize connate water in said at
least one lean zone; and iii) Recovering said hydrocarbons from
said reservoir.
2. A process according to claim 1 further comprising initial steam
injection with oxygen into the reservoir then terminating said
steam injection.
3. The process of claim 1 where combustion occurs at temperatures
higher than 400.degree. C.
4. The process of claim 1 where the oxygen has an oxygen content of
95 to 99.9 (v/v) percent.
5. The process of claim 1 where the oxygen is air.
6. The process of claim 5 where the air is enriched air with an
oxygen containing content of 21 to 95 (v/v) percent.
7. The process of claim 1 where the hydrocarbons are bitumen API
density (<10; in situ viscosity>100,000 cp.).
8. The process of claim 1 where the hydrocarbons are heavy oil
(10<API<20); in situ viscosity>1000 cp.).
9. A steam assisted gravity drainage with oxygen system for
recovery of hydrocarbons from a reservoir having at least one lean
zone, wherein said lean zone has an initial bitumen saturation
level less than about 0.6, said system comprising: i) A first well,
having a toe and a heel, said first well within said lean zone
containing reservoir, for capturing said hydrocarbons; ii) A second
well within said lean zone containing reservoir, for injection of
oxygen into said lean zone containing reservoir; iii) Said second
well being located proximate said toe of said first well; and iv)
At least one vent gas means for venting any gas produced in said
reservoir.
10. A steam assisted gravity drainage with oxygen system for
recovery of hydrocarbons for a reservoir having at least one lean
zone, wherein said lean zone has an initial bitumen saturation
level less than about 0.6, said system comprising: i) A well,
having a toe and a heel, said well being located within said lean
zone containing reservoir; wherein said well further comprises: a.
At least one oxygen injection site proximate said toe, for
injecting oxygen into said reservoir; b. A hydrocarbon recovery
site for recovery of said hydrocarbons from said reservoir; and c.
At least one vent gas site for venting any gas produced in said
reservoir.
11. The system of claim 9 where the vent gas means is selected from
a group consisting of a single substantially vertical well or a
plurality of substantially vertical wells.
12. The system of claims 9 and 10 where the vent gas means is a
segregated annulus section in the heel section of the horizontal
well.
13. The system of claim 9 where the at least one oxygen injection
site is selected from a group consisting of a single substantially
vertical well or a plurality of substantially vertical wells.
14. The system of claim 10 where the at least one oxygen injection
site is a segregated toe section of the horizontal well.
15. The system of claim 10 wherein said toe of said well is at a
level in said reservoir different than said heel of said well.
16. The system of claim 10 wherein said toe level is at a level
higher in said reservoir than said heel of said well.
17. The system of claims 9 and 10 wherein said at least one vent
gas site is distant said toe of said well.
18. A process according to claim 1, 9 or 10 where the lean zone
thickness is less than 25 metres.
Description
BACKGROUND
[0001] Steam Assisted Gravity Drainage (SAGD) is a commercial,
thermal enhanced oil recovery ("EOR") process. The SAGD process
uses saturated steam injected into a horizontal well, where latent
heat is used to heat bitumen in the reservoir. The heating of the
bitumen lowers its viscosity, so it drains by gravity to an
underlying parallel, twin, horizontal well completed near the
reservoir bottom.
[0002] Since the process inception in the early 1980's, SAGD has
become the dominant, in situ process to recover bitumen from
Alberta's bitumen deposits (Butler, R., "Thermal Recovery of Oil
& Bitumen", Prentice-Hall, 1991). Today's SAGD bitumen
production in Alberta is about 300 Kbbl/d with installed capacity
at about 475 Kbbl/d (Oilsands Review, 2010). SAGD is now the
world's leading thermal EOR process.
[0003] FIG. 1 (PRIOR ART) shows the "traditional" SAGD geometry,
using twin, parallel horizontal wells 2,4 drilled in the same
vertical plane. There is a 5-metre spacing between the horizontal
wells 2,4, which are about 800 metres long 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. Fluid production
is accomplished by natural lift, gas lift, or submersible pump.
[0004] After conversion to "normal" SAGD operations, a steam
chamber 10 forms around the injection 2 and production wells 4
where the void space is occupied by steam 6. Steam 6 condenses at
the boundaries of the chamber 10, releases latent heat (heat of
condensation), and heats bitumen, connate water and the reservoir
matrix. Heated bitumen and water 8 drain by gravity to the lower
production well 4. The steam chamber 10 grows upward and outward as
bitumen is drained.
[0005] FIGS. 2A-2D (PRIOR ART) show how SAGD matures. A "young"
steam chamber 10 has bitumen drainage from steep chamber sides and
from the chamber ceiling. When the chamber growth hits the top of
the reservoir, ceiling drainage stops, bitumen productivity peaks,
and the slope of the side walls decreases as lateral growth
continues. Heat loss increases (and steam-to-oil ratio ("SOR")
increases) as ceiling contact 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.degree..
[0006] Produced fluids are near saturated-steam temperature, so it
is only the latent heat of steam that contributes to the process in
the reservoir. But, some of the sensible heat can be captured from
surface heat exchangers (a greater fraction at higher
temperatures), so a useful rule-of-thumb for net heat contribution
of steam is 1000 BTU/lb. for the P, T range of most SAGD projects
(FIG. 3 PRIOR ART).
[0007] The operational performance of SAGD can be characterized by
measurement of the following parameters: 1) saturated steam P, T in
the steam chamber (FIG. 4 PRIOR ART); 2) bitumen productivity; 3)
SOR, usually at the well head; 4) sub-cool target, the T difference
between saturated steam and produced fluids; and 5) Water Recycle
Ratio ("WRR"), the ratio of produced water to steam injected.
[0008] During the SAGD process, the SAGD operator has two choices
to make: 1) the sub-cool target T difference and 2) the operating
pressure in the reservoir. A typical sub-cool of about 10 to
30.degree. C. is meant to ensure no live steam breaks through to
the production well. Process pressure and temperature are linked
(FIG. 4 PRIOR ART) and relate mostly to bitumen productivity and
process efficiency.
[0009] Bitumen viscosity is a strong function of temperature (FIG.
5). SAGD productivity is proportional to the square root of the
inverse viscosity (FIG. 6 PRIOR ART) (Butler (1991)). Conversely if
pressure (and T) is increased, the latent heat content of steam
drops rapidly (FIG. 3). More energy is used to heat the rock matrix
and is lost to the overburden or other non-productive areas. So,
increased pressure increases bitumen productivity but harms process
efficiency (increases SOR). Because economic returns can be
dominated by bitumen productivity, the SAGD operator usually opts
to target operating pressures higher than native or hydrostatic
reservoir pressures.
[0010] Despite becoming the dominant thermal EOR process, SAGD has
some limitations and detractions. The requirements for a good SAGD
project are: [0011] a horizontal well completed near the bottom of
the pay zone to effectively collect and produce hot draining
fluids. [0012] the injected steam, at the sand face, has a high
quality (latent heat drives the process) [0013] the process start
up is effective and expedient [0014] the steam chamber grows
smoothly and is contained [0015] the reservoir matrix is good
quality (porosity (.phi.)>0.2); [0016] Initial Oil Saturation
(S.sub.io)>0.6; Vertical permeability (k.sub.v)>2D) [0017]
net pay is sufficient (>15 metres) [0018] proper design and
control must achieved to simultaneously; 1) prevent steam
breakthrough to the production well and injector flooding; 2)
stimulate steam chamber growth to productive zones; and 3) inhibit
water inflows to the steam chamber. [0019] there must be absence of
significant reservoir baffles (e.g. lean zones) or barriers (e.g.
shale)
[0020] If these conditions are not attained or other limitations
are experienced, SAGD can be impaired, as follows:
[0021] (1) The preferred dominant production mechanism is gravity
drainage, and the lower production well is horizontal. If the
reservoir is slanted, a horizontal production well will strand
significant resources.
[0022] (2) The SAGD steam-swept zone has significant residual
bitumen content that is not recovered, particularly for heavier
bitumens and low pressure steam (FIG. 7). 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.
[0023] (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.
[0024] (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 is not usually mobilized sufficiently to
be produced in SAGD. Produced Water-to-Oil Ratio ("PWOR") is
similar to SOR. This makes it difficult for SAGD to breach or
utilize lean zone resources.
[0025] (5) The existence of an active water zone--either top water,
bottom water or an interspersed lean zone within the pay zone--can
cause operational difficulties or project failures for SAGD (Nexen
Inc., "Second Quarter Results", Aug. 4, 2011) (Vanderklippe, N.,
"Long LakeProject Hits Sticky Patch", CTV News, 2011). Simulation
studies concluded that increasing production well stand-off
distances can 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 2010).
[0026] (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 or hydrostatic pressures,
the SAGD process can lose water or steam to zones outside the SAGD
steam chamber. If fluids are lost, the Water Recycle Ratio (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 breakthrough of steam, sand, and water can occur (Roche,
P., "Beyond Steam", New Tech. Mag., September 2011).
[0027] (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.
[0028] (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 barrels (bbls) of make-up water per barrel
(bbl) of bitumen produced.
[0029] (9) SAGD process efficiency is poor, and CO.sub.2 emissions
are significant. If SAGD efficiency is defined as [(bitumen
energy)-(surface energy used)]/(bitumen energy), where 1) bitumen
energy=6 MMBTU/bbl; 2) energy used at sand face=1MMBTU/bbl bitumen
(SOR.about.3); 3) steam is produced in a gas-fired boiler at 85%
efficiency; 4) there are heat losses of 10% each in distribution to
the well head and delivery from the well head to the sand face; 5)
usable steam energy is 1000 BTU/lb (FIG. 3 PRIOR ART); and 6)
boiler fuel is methane at 1000 BTU/SCF, then the SAGD process
efficiency=75.5% and CO2 emissions=0.077 tonnes/bbl bitumen.
[0030] (10) Practical 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 . . . ", Canada Heavy Oil
Association, pres., Nov. 2, 2006).
[0031] (11) Lastly, there is a natural hydraulic limit that
restricts well lengths or well diameters and can override pressure
targets for SAGD operations. FIGS. 8A and 8B show what can and has
happened. In SAGD, a steam/liquid interface 12 is formed. For a
good SAGD operation with sub-cool control, the interface is between
the injector 2 and producer wells 4. 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 fluid production rates are too high (or if the
production well is too small), the interface can be tilted so that
the toe 14 of the steam injector is flooded and/or the heel 16 of
the producer is exposed to steam 6 breakthrough (FIGS. 8A and 8B).
This limitation can occur when the pressure drop in the production
well 4 exceeds the hydrostatic head between steam injector 2 and
fluid producer 4 (about 8 psi (50 kPa) for a 5 m. spacing).
[0032] As discussed above, SAGD has significant problems, including
reduced efficiency (high Steam-to-Oil Ratio), poor productivity,
and poor bitumen recovery when dealing with Lean Zones. In
particular, SAGD cannot vaporize connate water because it uses
saturated steam.
[0033] Lean Zones (LZ) are reservoir zones where hydrocarbon pore
saturation is significantly reduced compared to most hydrocarbon
reservoirs (<0.6) and where the remaining saturation (>0.4)
is mostly water. Lean zones can be interspersed within a reservoir
that has higher hydrocarbon saturation. Lean zones can be near the
top of a reservoir (transition zone to top water), the bottom of a
reservoir (transition zone to bottom water), or the entire pay zone
can be classed as a lean zone (<0.6 hydrocarbon saturation).
Because of high water saturation, some lean zones can transmit
water. The zones can be active (>50 m.sup.3/d water recharge
rate) or limited (<50 m.sup.3/d recharge rate). Because bitumen
density is near water density (API=10) and because bitumen density
changed (rapidly) over time by bacterial degradation, bitumen
reservoirs can show multiple LZ's--interspersed, top, bottom or
whole reservoir.
[0034] A lean-zone reservoir, or part of a reservoir, has a low
original oil (bitumen) saturation (S.sub.io) and a corresponding
high original water saturation (S.sub.iw). For the purposes of this
invention, a lean zone is defined as (S.sub.io.ltoreq.0.6 (i.e. the
original oil/bitumen saturation is less than 60 percent of the pore
volume).
[0035] A thief zone is defined as an active zone to which fluids
are lost.
[0036] For example, FIGS. 9, 10, 11, and 12 characterize the
McMurray formation. FIG. 9 shows the depth of the top of the
formation--i.e. the overburden thickness. FIG. 10 shows the
thickness of the total 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 occupying 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)
[0037] Industry reports regarding Lean Zones include the following:
[0038] Suncor's Firebag SAGD project and Nexen's Long Lake project
each have reported interspersed lean zones that can behave as thief
zones when SAGD pressures are too high, forcing the operators to
choose SAGD pressures that are lower than desirable
(Triangle--"Technical Audit Report, Gas Over Bitumen Technical
Solutions", Triangle Three Engineering, December 2010). [0039]
Simulation studies of a particular reservoir concluded that a 3
metre standoff (3 metres from the SAGD producer well to the
bitumen/water interface) was sufficient to optimize production with
bottom water, allowing a 1 metre control for drilling accuracy
(Akram (2010)). Allowing for coring/seismic control, the standoff
may be higher. Nexen and OPTI have reported that interspersed lean
zones seriously impede SAGD bitumen productivity and increase SOR
beyond original expectations at Long Lake, Alberta (Vanderklippe
(2011), (Bouchard, J. et al, "Scratching Below the Surface Issues
at Long Lake--Part 2", Raymond James, Feb. 11, 2011), Nexen (2011),
(Haggett, J. et al, "Update 3--Long Lake Oilsands Output may lag
Targets", Reuters, Feb. 10, 2011). [0040] Long Lake lean zones have
been reported to make up from less than 3 to 5% (v/v) of the
reservoir (Vanderklippe (2011), Nexen (2011)). [0041] Oilsands
Quest reported a bitumen reservoir with top lean zones that are
"thin to moderate". Some areas had "continuous top thick lean
zones" (Oilsands Quest (2011)). [0042] Connacher Oil and Gas had an
oil sands project with a top lean zone (Johnson (2011). The lean
zone was reported to differ from an aquifer in two ways--"the lean
zone is not charged and is limited size". [0043] Shell's Peace
River Project reportedly had a lean zone, including a "basal lean
bitumen zone" (Thimm, H. F. et al, "A Statistical Analysis of the
early Peace River Thermal Project Performance," Journal Canadian
Petroleum Technology, January 1993). The statistical analysis of
the steam soak process (Cyclic Steam Stimulation ("CSS")) showed
performance correlated with the geology of the lean zone (i.e. the
lean zone quality was the important factor). The process chosen
took advantage of lean zone properties, particularly the good steam
injectivity in lean zones.
[0044] In-Situ Combustion ("ISC") is the oldest thermal recovery
technique. In-situ combustion is basically injection of an
oxidizing gas 20 (air or oxygen-enriched air) to generate heat by
burning a portion of the residual oil (FIG. 32). Most of the oil is
driven toward the producers by a combination of gas drive (from the
combustion gases), steam and water drive. This process is also
called fire flooding to describe the movement of a burning front
inside the reservoir. Based on the respective directions of front
propagation and air flow, the process can be forward, when the
combustion front advances in the same direction as the air flow, or
reverse, when the front moves against the air flow (Brigham,
William, et al. "In-situ Combustion" Chapter 16 Reservoir
Engineering).
[0045] The peak production period for ISC was in the 1980s, spurred
by government incentives. The peak production was 12 Kbbl/d. In the
USA, only 23 of the 1980's ISC projects were deemed economic. In
Canada, there has been little focus on bitumen ISC (Butler, 1991).
However, Petrobank has been pursuing a toe-to-heel version of ISC
called the Toe-to-Heel Air Injection (THAI) process. The THAI
process uses a horizontal production well and a vertical air
injector completed near the toe of the horizontal well. Field
testing of the THAI process started in 2006 but results have been
disappointing.
[0046] The Combustion Overhead Split Horizontal (COSH)/Combustion
Overhead Gravity Drainage ("COGD") process is another ISC process
using a horizontal production well with horizontal vent gas removal
wells on the pattern edges, and vertical air injectors are located
above the horizontal well. This process was first pursued by
Excelsior, but current activity has ceased (New Tech Magazine,
"Excelsior Searching . . . COGD Project" Nov. 20, 2009).
[0047] Ramey first suggested the use of oxygen gas, rather than
air, for ISC in 1954. Greenwich Oil at Forest Hill, Tex. in 1980
was the first demonstration of successful injection of high
concentration oxygen into an oil reservoir; however, other field
tests have since been conducted with mixed results (Sarathi, P.,
"ISC EOR Status", DOE, 1999).
[0048] It is important to note that there have been no specific
targets on lean reservoirs using ISC processes.
[0049] SAGDOX is an improved thermal enhanced oil recovery (EOR)
process for bitumen recovery. The process can use geometry similar
to SAGD (FIG. 13), but it also has versions with separate vertical
wells or segregated sites for oxygen injection and/or
non-condensable vent gas removal (FIGS. 14A, 14B, 15A, 15B,
16A-16C). The process can be considered as a hybrid SAGD+ISC
process.
[0050] 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 (FIGS. 17,
18 Butler (1991)). Combustion temperatures are independent of
pressure and they are higher than saturated steam temperatures
(FIGS. 3, 18). 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).
[0051] Table 1 compares EOR heat injectant properties of steam and
oxidant gases. Table 3 presents thermal properties of steam+oxygen
mixtures. Per unit heat delivered to the reservoir, oxygen volumes
are ten times less than steam, and oxygen costs including capital
charges are one half to one third the cost of steam.
[0052] The recovery mechanisms are more complex for SAGDOX than for
SAGD. The combustion zone is contained within the steam-swept zone
170. Residual bitumen, in the steam-swept zone 170, is heated,
fractionated and pyrolyzed by hot combustion gases to produce coke
that is the actual fuel for combustion. A gas chamber is formed
containing steam combustion gases, vaporized connate water, and
other gases (FIG. 19). The large gas chamber can be subdivided into
a combustion-swept zone 100, a combustion-zone, a pyrolysis zone
120, a hot bitumen bank 130, a superheated steam zone 140 and a
saturated steam zone 50 (FIG. 19). Condensed steam drains from the
saturated steam zone 150 and from the ceiling and walls of the gas
chamber. Hot bitumen drains from the ceiling and walls of the
chamber and from the hot bitumen zone 130 at the edge of the
combustion front 110 (FIG. 19). Condensed water and hot bitumen 8
are collected by the lower horizontal well 4 and conveyed (or
pumped) to the surface (FIG. 13).
[0053] Combustion non-condensable gases are collected and removed
by vent gas 22 wells or at segregated vent gas sites (FIGS. 13,
14A, 14B, 15A, 15B and 16A-16C). Process pressures can be
controlled (partially) by vent gas 22 production, independent of
fluid production rates. Vent gas 22 production can also be used to
influence direction and rate of gas chamber growth.
[0054] In rich reservoirs, SAGDOX cannot vaporize enough connate
water to obviate steam 6 injection.
[0055] To summarize, there is no thermal EOR or ISC technology
focused on lean zones to recover bitumen.
[0056] However, lean zones can have some redeeming advantages. They
are as follows: [0057] Connate water can be significant if it can
be mobilized and utilized as steam or produced and recycled as
steam [0058] Because of high initial water saturations (>0.4),
and possible water channels, lean zones can have some fluid
injectivity even if the bitumen fraction is immobile. [0059] Lean
zones with low bitumen saturation (between 0.05-0.20) may provide
enough fuel to sustain combustion within the lean zones.
[0060] But for thermal EOR processes using saturated steam, lean
zones present the following problems: [0061] (1) In order to
mobilize the oil by heating to steam temperatures, the connate
water and the rock matrix also have to be heated. The proportion of
heat going to the oil/bitumen drops dramatically as the initial oil
saturation drops. [0062] (2) For a process like SAGD, this is
manifested by a rapidly increasing SOR as initial oil saturation
drops, as shown in FIG. 20 for a 500 psia saturated steam
(242.degree. C.). [0063] (3) In any steam EOR process, including
SAGD, in the steam-swept zone (GD chamber), a residual oil/bitumen
is left behind, unrecovered. For bitumen EOR and for a reasonable
range of saturated steam temperatures (180.degree. C. to
260.degree. C.), the residual bitumen saturation is in the range of
0.10 to 0.20 (FIG. 7). This can limit steam EOR recoveries for
thermal steam EOR in lean zones, particularly for the lower
temperatures and lower initial bitumen saturation levels (FIG. 21).
[0064] (4) For lean zones with low bitumen (<0.20 initial
saturation), there may be zero recovery when steam sweeps the zone.
[0065] (5) As the initial bitumen saturation drops, most of the
(steam) heat goes to heating connate water (FIG. 22). [0066] (6)
Interspersed lean zones can interrupt SAGD steam chamber growth
patterns. Interspersed lean zones have to be heated so that GD
steam chambers can envelope the zone and continue growth above and
around the lean zone blockage. [0067] (7) An interspersed lean zone
has higher heat capacity and higher heat conductivity than a zone
with higher bitumen content. Even if an aquifer or bottom/top water
zone, does not recharge the lean zone for SAGD, the lean zone will
create a thermal penalty as the steam chamber moves through and
around the lean zone. For SAGD, bitumen productivity will also
suffer as the heated zone moves through (and around) the lean zone.
[0068] (8) If an interspersed lean zone acts as a thief zone, the
problems are most severe. The lean zone can channel steam away from
the SAGD steam chamber. If the steam condenses prior to removal,
the water is lost but some of the heat can be retained. But, if the
steam exits the SAGD steam chamber prior to condensing, both the
heat and the water are lost to the process. The obvious remedy is
to reduce SAGD pressure to minimize the steam/water outflow. But,
if this is done, bitumen productivity will be reduced.
[0069] Because of the above problems, lean zones have presented the
following disadvantages for thermal EOR: [0070] The EOR goal is to
heat bitumen to reduce its viscosity so it can drain to a
production well. But as the oil saturation drops, most of the
injected heat goes to heating connate water, particularly for the
leanest zones (FIG. 22). [0071] Saturated steam is not of
sufficient quality to vaporize water, only to heat it to near
saturated-steam temperature. [0072] The residual bitumen in a
steam-swept zone can be significant, particularly for heavy
bitumens and for cooler thermal EOR processes (FIG. 9). If the
initial bitumen saturation in a lean zone is close to (or below)
the residual bitumen in a steam-swept zone, steam EOR can recover
little or no bitumen from the lean zone. [0073] Using a simple
model for steam EOR, assuming all bitumen above 0.15 saturation is
recovered by heating to 242.degree. C. (500 psia), below an initial
bitumen saturation of about 0.4, with modest heat losses, SOR can
exceed 5 and steam EOR becomes impractical (FIG. 21).
[0074] Accordingly, there is a need for an EOR applicable to lean
reservoirs. Preferably, a SAGDOX process that is applicable to lean
reservoirs.
SUMMARY OF THE INVENTION
[0075] LZ-SAGDOX is a process similar to SAGDOX; however, the
process is tailored to lean reservoirs and no steam is injected.
LZ-SAGDOX creates steam in the reservoir by two ways: 1) vaporizing
connate water and 2) as a chemical production of combustion (water
of combustion).
[0076] According to one aspect, there is a provided a process to
recover oil from a reservoir having at least one lean zone.
Preferably, the lean zone has an initial bitumen saturation
(S.sub.io) level less than about 0.6. The process comprises an
injection of oxygen into the lean zone. The oxygen combustion
vaporizes the connate water in the lean zone. The vaporizing of the
connate water allows for recovery of oil from the reservoir.
[0077] In one embodiment, the lean zone thickness is less than 25
metres.
[0078] In one embodiment, an initial steam is injected with the
oxygen into the reservoir, then the initial steam injection is
terminated.
[0079] In one embodiment, combustion occurs at temperatures higher
than 400.degree. C.
[0080] In one embodiment, the oxygen has an oxygen content of 95 to
99.9 (v/v) percent.
[0081] In one embodiment, the oxygen is air. In a further
embodiment, the air is enriched air with an oxygen containing
content of 21 to 95 (v/v) percent.
[0082] In one embodiment, the hydrocarbons are bitumen with an API
density less than 10 and in situ viscosity greater than 100,000
cp.
[0083] In one embodiment, the hydrocarbons are heavy oil with an
API density greater than 10 but less than 20 and in situ viscosity
greater than 1,000 cp.
[0084] According to another aspect of the invention, there is
provided a SAGDOX system for recovery of hydrocarbons from a
reservoir having at least one lean zone. The lean zone has an
initial bitumen saturation level of less than 0.6. The system has a
first well, which has a toe and a heel allowing for capture of
hydrocarbons from the reservoir. The system has a second well
allowing for injection of oxygen into the lean zone containing
reservoir. The second well is proximate the toe of the first well.
The system further comprises a vent gas means for venting any gas
produced in the reservoir.
[0085] In one embodiment, the lean zone thickness is less than 25
metres.
[0086] In one embodiment, the vent gas means is selected from a
group consisting of a single substantially vertical well or a
plurality of substantially vertical wells.
[0087] In one embodiment, the vent gas means is a segregated
annulus section in the heel section of the horizontal well.
[0088] In a further embodiment, the vent gas means is distant said
toe of said well.
[0089] In one embodiment, the at least one oxygen injection site is
selected from a group consisting of a single substantially vertical
well or a plurality of substantially vertical wells.
[0090] According to yet another aspect of the invention, there is
provided a SAGDOX system for recovery of hydrocarbons from a
reservoir having at least one lean zone. The lean zone has an
initial bitumen saturation level of less than 0.6. The system has a
well with a toe and a heel, and the well is located within the lean
zone containing reservoir. The well further comprises at least one
oxygen injection site proximate the toe for injecting oxygen into
the reservoir. The well also has a hydrocarbon recovery site for
recovery of hydrocarbons from the reservoir. Even further, the well
has at least one vent gas site for venting any gas produced in the
reservoir.
[0091] In one embodiment, the lean zone thickness is less than 25
metres.
[0092] In one embodiment, the vent gas means is a segregated
annulus section in the heel section of the horizontal well.
[0093] In one embodiment, the vent gas means is distant the toe of
the well.
[0094] In one embodiment, the oxygen injection site is a segregated
toe section of the horizontal well.
[0095] In one embodiment, the toe of the well is at a different
level in the reservoir than the heel of the well.
[0096] In one embodiment, the toe of the well is at a higher level
in the reservoir than the heel of the well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0097] FIG. 1A is a perspective view of traditional SAGD well
geometry;
[0098] FIG. 1B is an end elevational view of FIG. 1A;
[0099] FIG. 2A is a schematic view of the early stages of the SAGD
life cycle;
[0100] FIG. 2B is a schematic view of optimum productivity of an
SAGD well;
[0101] FIG. 2C is a schematic view of a maturing/aging SAGD
well;
[0102] FIG. 2D is a schematic view of the end of life of an SAGD
well;
[0103] FIG. 3 depicts saturated steam properties;
[0104] FIG. 4 depicts the operational performance of an SAGD
process;
[0105] FIG. 5 depicts Long Lake bitumen viscosity;
[0106] FIG. 6 depicts the gravdrain equation for SAGD bitumen
productivity;
[0107] FIG. 7 depicts residual bitumen in steam-swept zones;
[0108] FIG. 8A depicts SAGD hydraulic limitations and good
operation of an SAGD well;
[0109] FIG. 8B depicts SAGD hydraulic limitations and poor
operation of an SAGD well;
[0110] FIG. 9 depicts the depth of the top of the McCurray
deposit;
[0111] FIG. 10 depicts the thickness of the total McCurray
deposit;
[0112] FIG. 11 depicts the net thickness of the porous portion of
the deposit of the McMurray deposit;
[0113] FIG. 12 shows the bitumen net pay thickness of the McMurray
deposit;
[0114] FIG. 13 depicts SAGDOX well geometry;
[0115] FIG. 14A is a schematic of the preferred embodiment of
THSAGDOX;
[0116] FIG. 14B is a piping schematic of THSAGDOX;
[0117] FIG. 15A is a schematic of a Single Well SAGDOX well
geometry;
[0118] FIG. 15B is a piping schematic of SWSAGDOX well;
[0119] FIG. 16A is a schematic of a preferred SAGDOX geometry;
[0120] FIG. 16B is a schematic of a preferred THSAGDOX
geometry;
[0121] FIG. 16C is a schematic of a preferred SWSAGDOX
geometry;
[0122] FIG. 17 depicts combustion heat release;
[0123] FIG. 18 depicts steam and oxygen tube tests 1;
[0124] FIG. 19 depicts SAGDOX mechanisms, including bitumen
saturation, water saturation, gas saturation and temperature in
relation to distance from an O.sub.2/steam injector;
[0125] FIG. 20 depicts a steam-to-oil ration for Steam EOR;
[0126] FIG. 21 depicts residual oil/bitumen saturation limits to
recovery;
[0127] FIG. 22 depicts Steam EOR Heat Distribution;
[0128] FIG. 23 depicts Produced Water-to-Oil Ratio for
LZ-SAGDOX;
[0129] FIG. 24A depicts preferred LZ-SAGDOX geometry;
[0130] FIG. 24B is a well configuration schematic for
LZ-SAGDOX;
[0131] FIG. 25 depicts ISC minimum air flux rates;
[0132] FIG. 26 depicts steam and oxygen combustion tube tests
II;
[0133] FIG. 27 depicts THAI process well geometry;
[0134] FIG. 28 depicts COGD/COSH process well geometry;
[0135] FIG. 29A is a schematic perspective view of LZ-SAGDOX;
[0136] FIG. 29B is a side schematic of LZ-SAGDOX;
[0137] FIG. 30 is a schematic of LZ-SAGDOX;
[0138] FIG. 31A is a perspective view of SWSAGD SAGDOX
(packers);
[0139] FIG. 31B is a side elevational schematic of SWSAGD;
[0140] FIG. 32 is a perspective view of conventional In-Situ
Combustion;
[0141] FIG. 33A is a schematic side elevational view of a gas
chamber in THSAGDOX in early life;
[0142] FIG. 33B is a schematic side elevational view of the well of
FIG. 33A at a mature stage;
[0143] FIG. 33C is a schematic view of the well of FIG. 33A at end
of life;
[0144] FIG. 34A is a schematic view of THSAGDOX liquid drawdown
heel production;
[0145] FIG. 34B is a schematic view of THSAGDOX liquid drawdown toe
production;
[0146] FIG. 35A is a schematic view of SWSAGDOX during mature
operations;
[0147] FIG. 35B is a schematic view of SWSAGDOX(U) during mature
operations;
[0148] FIG. 36A is a perspective view of LZ-SAGDOX A;
[0149] FIG. 36B is a side schematic view of the well of FIG.
36A;
[0150] FIG. 37 is a well schematic of LZ-SAGDOX A; and
[0151] FIG. 38 is a table illustrating combustion PWOR.
DETAILED DESCRIPTION OF THE INVENTION
[0152] The SAGDOX process injects some steam (with oxygen) to
improve combustion kinetics and to improve heat transfer
(particularly lateral heat transfer) in the reservoir. For high
bitumen-saturation reservoirs (0.6 to 1.0 saturation), steam
addition to oxygen is necessary to attain minimum steam levels in
the reservoir. A measure of this minimum has been suggested as
Produced Water-to-Oil Ratio ("PWOR").gtoreq.1.0.
[0153] For lean zones, vaporized connate water can capture these
benefits without any steam addition from outside the reservoir. For
the purpose of this invention, lean zones are porous rocks defined
to contain less than or equal to 60 percent of the pore volume, by
volume, bitumen and the remainder of the pore volume is mostly
water. A lean zone may occupy all or part of the pay zone.
[0154] As far as the reservoir is concerned, LZ-SAGDOX gas mixtures
(steam+oxygen) are similar to SAGDOX. The LZ-SAGDOX process simply
injects oxygen gas, with no steam (except for start-up) to achieve
a SAGDOX EOR process in a lean zone reservoir. Combustion
temperatures are in the 500 to 600.degree. C. range (FIG. 21), so
combustion heat is of sufficient quality to vaporize lean-zone
connate water creating and sustaining a good steam inventory in the
reservoir.
[0155] If one assumes the following: 1) the connate water
associated with bitumen production and bitumen consumed is all
vaporized and recovered as product water (e.g. if the initial
bitumen saturation is 0.3, the associated connate water is 2.33
bbl/bitumen); and 2) any water created as a chemical product of
combustion is also produced, then Table 4 and FIG. 23 show Produced
Water-to-Oil Ratio for LZ-SAGDOX processes. As shown in FIG. 23,
for LZ-SAGDOX, PWOR is not a strong function of the energy-to-oil
ratio ("ETOR"), but it is a strong function of initial bitumen
saturation. For leaner reservoirs (lower initial bitumen
saturation) higher ETOR is expected as most of the heat goes to
heat matrix and water zones (FIG. 20).
[0156] An assumption, to attain good water/steam benefits in the
reservoir, is that PWOR should equal or exceed 1.0. PWOR is a
reflection of steam in the reservoir per bbl of bitumen produced.
For LZ-SAGDOX (FIG. 23) this implies a maximum initial bitumen
saturation of 0.6. This sets a preferred limit value for the
LZ-SAGDOX process.
[0157] Referring to Tables 2 and 5, one can also see the similarity
of the processes (SAGDOX vs. LZ-SAGDOX) from the standpoint of the
reservoir and predicted PWOR. SAGDOX, using 35% oxygen (v/v) in
steam+oxygen injectants in a reservoir with 0.8 initial bitumen
saturation and with ETOR=2.0, has a PWOR of 1.3 (Table 2).
LZ-SAGDOX, in a reservoir with 0.6 initial bitumen saturation and
with ETOR=4.0, has a PWOR=1.2.
[0158] As long as the initial bitumen saturation in the lean zone
is above about 0.05, there is enough combustion energy available
from this fuel to vaporize all the water in the lean zone pores (95
(v/v) percent). If bitumen saturation is higher than this, some net
bitumen can be recovered. A combustion-swept zone has near-zero
residual hydrocarbons (FIG. 19), so the bitumen in a lean zone will
either be mobilized and produced or consumed as a fuel, as the
combustion front sweeps through the lean zone.
[0159] FIGS. 24A, 24B, 36A, 36B and 37 shows the preferred geometry
for LZ-SAGDOX, retaining a horizontal production well 4 and vent
gas 22 removal using a segregated section (annulus) of the
production well 4. Oxygen 26 is either injected in a separate
vertical well or in a segregated, upturned toe section of a single
well version of the process. No provision is made for continuous
steam 6 injection. Start-up can be accomplished by steam
circulation or steam huff-and-puff.
[0160] Preferably, oxygen 26 rather than air is the oxidant
injected. If the cost of treating vent gas 22 to remove sulphur
components and to recover volatile hydrocarbons is included, 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.
Further, oxygen occupies about one fifth the volume compared to air
for the same energy delivery. Well pipes/tubing are smaller and
oxygen can be transported further distances from a central plant
site. Another benefit of injecting oxygen is that in-situ
combustion using oxygen produces mostly non-condensable CO.sub.2,
undiluted with nitrogen. CO.sub.2 can dissolve in bitumen to
improve productivity. Dissolution is maximized using oxygen. Also,
vent gas, using oxygen, is mostly CO.sub.2, and it may be suitable
for sequestration Finally, there is a minimum oxygen flux to
sustain high temperature oxidation ("HTO") combustion (FIG. 25). It
is easier to attain/sustain this flux using oxygen.
[0161] Preferably, oxygen 26 injection should be kept at a
concentrated site. Because of the minimum O.sub.2 flux constraint
for in situ combustion (FIG. 25), the oxygen 26 injection well (or
a segregated section) should have no more than 50 metres of contact
with the reservoir.
[0162] Preferably, oxygen 26 and steam 6 injectants are segregated
as much as possible prior to injection. Condensed steam 6 (hot
water) and oxygen 26 are very corrosive to carbon steel. To
minimize corrosion, there are three options: 1) either oxygen 26
and steam 6 are injected separately (FIGS. 13, 14A and 14B); 2)
comingled steam and oxygen 30 have limited exposure to a section of
pipe that can be a corrosion resistant alloy, the section integrity
is not critical to the process (FIGS. 15A and 15B); or 3) the
entire injection string is a corrosion resistant alloy.
[0163] Preferably, the vent gas 22 well or site is near the top of
the reservoir, far from the oxygen 26 injection site and laterally
offset from the injection 2/production 4 wells. Because of steam 6
movement and condensation, non-condensable gas concentrates near
the top of the gas chamber. The vent gas 22 well should be far from
or distant the oxygen injector to allow time/space for
combustion.
[0164] Preferably, vent gas 22 should not be produced with
significant oxygen content. To mitigate explosions and to foster
good oxygen 6 utilization, any vent gas 22 production with oxygen
content greater than 5% (v/v) should be shut in.
[0165] Preferably, a minimum amount of steam 6 in the reservoir is
attained or retained.
[0166] Steam 6 is added or injected with oxygen 26 in SAGDOX
because steam helps combustion. Steam 6 preheats the reservoir so
ignition, for HTO, can be spontaneous. Steam 6 adds OH.sup.- and
H.sup.+ radicals to the combustion zone to improve and stabilize
combustion (FIGS. 18 and 26) (Moore, G. et al, "Parametric Study of
Steam Assisted ISC, unpublished, February 1994). This is also
confirmed by the operation of smokeless flares, where steam is
added to improve combustion and reduce smoke (Stone, D. et al,
"Flares," Chapter 7, gasflare.org, June 2012), (U.S. Environmental
Protection Agency "Industrial Flares," www.EPA.gov, June 2012),
(Shore, D. "Making the Flare Safe," Journal of Loss Prevention in
the Process Industries, 9, 363, 1996). The process to gasify fuels
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. Further, steam condensate adds water
to the production well to improve flow performance--water/bitumen
emulsions--compared to bitumen alone.
[0167] Steam is also a superior heat transfer agent in the
reservoir. If we compare hot combustion gases, mostly CO.sub.2 to
steam, the heat transfer advantages of steam are evident. For
example, if we have a hot gas chamber at about 200.degree. C. at
the edges, the heat available from cooling combustion gases from
500 to 200.degree. 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 can be mitigated by steam injection.
[0168] Finally, since one cannot 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+oxygen mix.
[0169] Preferably, a minimum oxygen injection is attained or
exceeded. Below about 5% (v/v) oxygen in the steam+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.
[0170] Preferably, oxygen injection is maximized. Within the
constraints of the above preferred embodiments, because per unit
energy oxygen is less costly than steam, the lowest-cost option to
produce bitumen is to maximize oxygen/steam ratios.
[0171] Preferred SAGDOX geometries should be used. 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 (FIGS. 16A-16C).
FIGS. 14A, 14B, 16B Toe-to-Heel SAGDOX ("THSAGDOX") and 16C (also
shown in FIGS. 33A-33C, 34A and 34B) Single Well SAGDOX
("SWSAGDOX") (see FIGS. 35A and 35B) are best suited to thinner pay
resources, with only one horizontal well required. Compared to
SAGDOX, THSAGDOX and SWSAGDOX have a reduced well count and lower
drilling costs. Also, internal tubulars and packers 18 should be
usable for multiple applications.
[0172] Preferably, SAGDOX is controlled or operated by the
following: [0173] 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. [0174] ii) Adjust oxygen/steam ratios (v/v) to meet a target
ratio, subject to a range limit of 0.05 to 1.00. [0175] iii) Adjust
vent gas removal rates so that the gases are predominantly
non-condensable gases; oxygen content is less than 5.0% (v/v); and
to attain/maintain pressure targets. [0176] iv) Adjust steam+oxygen
injection rates (subject to (ii) above), along with (iii) above, to
attain/maintain pressure targets.
[0177] To summarize, LZ-SAGDOX, as shown in FIGS. 29A, 29B and 30,
is superior to SAGDOX in LZ reservoirs for the following reasons:
[0178] LZ-SAGDOX doesn't inject steam (except for start-up). Steam
is more costly than oxygen (for combustion), so LZ-SAGDOX operating
costs are less than SAGDOX. [0179] Because of lower operating
costs, LZ-SAGDOX can be applied at lower bitumen saturations.
[0180] Also, because of lower operating costs, LZ-SAGDOX will
increase reserves compared to SAGDOX. [0181] LZ-SAGDOX saves one
well (or one completion zone) compared to SAGDOX (steam injector).
[0182] Fresh water or make-up water use for LZ-SAGDOX is zero
(except for start-up)
[0183] As discussed above, distinctions between LZ-SAGDOX and
SAGDOX include the following: [0184] LZ-SAGDOX has no steam
injected; SAGDOX has steam injection; [0185] LZ-SAGDOX has one less
injectant site (well, port), no steam injector; [0186] LZ-SAGDOX
has restricted range for bitumen saturation (5 to 60 percent);
SAGDOX doesn't; [0187] LZ-SAGDOX is a combustion EOR process (based
on injectants), SAGDOX is a combined steam and combustion EOR
process; [0188] SAGDOX uses surface water for steam; LZ-SAGDOX uses
no water (except for start-up).
[0189] Distinction between Toe-to-Heel Air Injection ("THAI") (FIG.
27) and LZ-SAGDOX include the following: [0190] THAI injects air;
LZ-SAGDOX prefers oxygen; [0191] THAI has no explicit restriction
on bitumen saturation; LZ-SAGDOX does; [0192] THAI is field tested
with poor results. [0193] THAI has had problems with lateral
growth; no steam added to foster heat transfer; LZ-SAGDOX generates
steam from LZ connate water.
[0194] Distinctions between SAGD and LZ-SAGDOX include the
following: [0195] SAGD is a pure steam EOR process; LZ-SAGDOX is a
pure combustion EOR process (based on injectants); [0196] SAGD has
no explicit bitumen saturation limits; [0197] SAGD doesn't perform
well on LZ (poor field history).
[0198] Distinctions between LZ-SAGDOX and Combustion Overhead Split
Horizontal ("COSH") or Combustion Overhead Gravity Drainage
("COGD") (FIG. 28) include the following: [0199] COSH/COGD prefer
air injection; [0200] COSH/COGD get lateral growth from position of
vent wells; LZ-SAGDOX gets lateral growth from steam produced in
situ; [0201] different geometry.
[0202] Distinctions between LZ-SAGDOX and Conventional ISC (FIG.
32) (neither injects water or steam) include the following: [0203]
ISC uses vertical wells (HZ for LZ-SAGDOX) [0204] ISC prefers air
(O.sub.2 for LZ-SAGDOX) [0205] no LZ preference for ISC
[0206] Distinctions between LZ-SAGDOX (SW version, FIGS. 29A, 29B,
30) and Single Well SAGD ("SWSAGD") (FIGS. 31A and 31B) include the
following: [0207] SWSAGD is a steam process; LZ-SAGDOX is a
combustion process [0208] no LZ preference for SWSAGD
[0209] Distinctions between LZ-SAGDOX and Combination of Forward
Combustion and Water ("COFCAW") include the following: [0210]
COFCAW injects water; LZ-SAGDOX has no water (or steam) injection
[0211] COFCAW uses vertical wells and conventional ISC geometry
(FIG. 28) [0212] COFCAW uses air injection; LZ-SAGDOX prefers
oxygen; [0213] no LZ preference for COFCAW
[0214] To summarize, the unique Features of LZ-SAGDOX include the
following: [0215] Limitation range of bitumen saturation for
process applicability [0216] ISC process where bitumen saturation
is a key factor [0217] Focus on lean zones; upper bitumen
saturation limit [0218] Consideration of connate water as a steam
source and the importance of steam in a ISC process [0219] Upturned
toe version for SW LZ-SAGDOX process [0220] Focus/preference for
oxygen as oxidant source [0221] Limitation of oxygen injection
contact-zone [0222] Focus/preference on bitumen [0223] Removal of
vent gas in separate well(s) or locations (vent gas not forced to
go to fluid production well) [0224] No other EOR processes are
specifically focused on lean zones [0225] Need for a minimum amount
of connate water for process to be successful [0226] Preferred
LZ-SAGDOX geometries (FIGS. 24A and 24B)
TABLE-US-00001 [0226] TABLE 1 Injectant Heat "Content" for Thermal
EOR Steam Oxygen Air (BTU/lb.) 1000 5700 1318 (BTU/SCF) 47.4 480
100 (MSCF/MMBTU) 21.1 2.08 10.0
[0227] Where--assumes: [0228] steam at 1000 BTU/lb. avg. [0229]
oxygen at 480 BTU/SCF avg (Butler, (1991)) [0230] ideal gas laws
[0231] air at 20.9% (v/v) oxygen
TABLE-US-00002 [0231] TABLE 2 SAGDOX: PWOR % O.sub.2 (v/v) in steam
and O.sub.2 mixes 0 5 35 50 100 ETOR = 1.0 (1) 3.18 2.07 0.49 0.29
0 (2) 0 0.09 0.21 0.23 0.25 (3) 0 0.01 0.02 0.03 0.03 (4) 0 0.013
.032 .035 .038 PWOR 3.18 2.18 0.75 0.59 0.32 ETOR = 2.0 (1) 6.36
4.14 0.98 0.58 0 (2) 0 0.09 0.21 0.23 0.25 (3) 0 0.02 0.05 0.05
0.05 (4) 0 0.026 0.064 0.07 0.076 PWOR 6.36 4.28 1.30 0.93 0.38
Where
[0232] (1)=condensed steam [0233] (2)=water (connate) associated
with produced bit from comb. [0234] (3) .dbd.water associated with
combusted bitumen [0235] (4)=water of combustion [0236]
PWOR=(1)+(2)+(3)+(4) (bbls.water/bblB) [0237] S.sub.io, =0.8; no
gas [0238] (2), (3), (4) are pro rated by heat from comb [0239] (1)
is prorated by heat from steam
TABLE-US-00003 [0239] TABLE 3 SAGDOX Injection Gases % (v/v)
O.sub.2 in Steam and O.sub.2 mixes 0 5 9 35 50 75 100 % heat from
O.sub.2 0 34.8 50.0 84.5 91.0 96.8 100.0 BTU/SCF mix 47.4 69.0 86.3
198.8 263.7 371.9 480.0 MSCF 21.1 14.5 11.6 5.0 3.8 2.7 2.1
mix/MMBTU MSCF 0.0 0.7 1.0 1.8 1.9 2.0 2.1 O.sub.2/MMBTU MSCF 21.1
13.8 10.6 3.3 1.9 0.7 0 Steam/MMBTU
[0240] Where: [0241] (1) Steam at 1000 BTU/lb. [0242] (2) Oxygen at
480 BTU/SCF
TABLE-US-00004 [0242] TABLE 4 LZ-SAGDOX: PWOR Initial Bitumen
Saturation .2 .4 .6 .8 .10 ETOR = 1.0 (1) 4.00 1.50 0.67 0.25 0.00
(2) 0.67 0.25 0.08 0.04 0.00 (3) 0.06 0.06 0.06 0.06 0.06 PWOR 4.73
1.81 0.81 0.35 0.06 ETOR = 2.0 (1) 4.00 1.50 0.67 0.25 0.00 (2)
1.34 0.50 0.17 0.08 0.00 (3) 0.11 0.11 0.11 0.11 0.11 PWOR 5.45
2.11 0.95 0.44 0.11 ETOR = 4.0 (1) 4.00 1.50 0.67 0.25 0.00 (2)
2.68 1.00 0.33 0.17 0.00 (3) .22 0.22 0.22 0.22 0.22 PWOR 6.90 2.72
1.22 0.64 0.22 ETOR = 8.0 (1) 4.00 1.50 0.67 0.25 0.00 (2) 5.36
2.00 0.66 0.34 0.00 (3) 0.45 0.45 0.45 0.45 0.45 PWOR 9.81 3.95
1.78 1.04 0.45
Where
[0243] Entries are bbl water/bbl bitumen [0244] (1)=connate water
associated with produced bitumen [0245] (2)=connate water
associated with bitumen combustion [0246] (3)=water of combustion
[0247] PWOR=(1)+(2)+(3) [0248] Water of combustion=0.056 bbl/MMBTU
[0249] Fuel=coke (CH..sub.5)
TABLE-US-00005 [0249] TABLE 5 PWOR LZ-SAGDOX (PWOR bbl water/bblB)
Initial Bitumen Saturation .2 .4 .6 .8 ETOR = 2: PWOR 5.45 2.11
0.95 0.44 ETOR = 4: PWOR 6.90 2.72 1.22 0.64 ETOR = 8: PWOR 9.81
3.95 1.78 1.04 ETOR = 12: PWOR 12.71 5.17 2.34 1.42 ETOR = 16: PWOR
15.62 6.40 2.90 1.82
Where:
[0250] PWOR=water associated with bitumen produced+bitumen
combusted+water of combustion [0251] fuel .dbd.CH..sub.5 coke
[0252] comb. Water=0.056 bbl/MMBTU [0253] complete HTO combustion
[0254] bit. fuel value=6 MMBTU/bbl [0255] O.sub.2 heat at 480
BTU/SCF
[0256] 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.
* * * * *
References