Note: Descriptions are shown in the official language in which they were submitted.
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TITLE OF THE INVENTION
USE OF STEAM-ASSISTED GRAVITY DRAINAGE WITH OXYGEN ("SAGDOX")
IN THE RECOVERY OF BITUMEN IN LEAN ZONES ("LZ-SAGDOX")
BACKGROUND
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.
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.
Figure 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.
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
grows upward and outward as bitumen is drained.
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Figure 2 (PRIOR ART) shows 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').
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 (Figure 3 PRIOR ART).
The operational performance of SAGD can be characterized by measurement of the
following parameters: 1) saturated steam P, T in the steam chamber (Figure 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.
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 C is meant to ensure no live steam breaks through to the
production well.
Process pressure and temperature are linked (Figure 4 PRIOR ART) and relate
mostly to
bitumen productivity and process efficiency.
Bitumen viscosity is a strong function of temperature (Figure 5). SAGD
productivity is
proportional to the square root of the inverse viscosity (Figure 6 PRIOR ART)
(Butler
(1991)). Conversely if pressure (and T) is increased, the latent heat content
of steam
drops rapidly (Figure 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
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can be dominated by bitumen productivity, the SAGD operator usually opts to
target
operating pressures higher than native or hydrostatic reservoir pressures.
Despite becoming the dominant thermal EOR process, SAGD has some limitations
and
detractions. The requirements for a good SAGD project are:
= a horizontal well completed near the bottom of the pay zone to
effectively collect
and produce hot draining fluids.
= the injected steam, at the sand face, has a high quality (latent heat
drives the
process)
= the process start up is effective and expedient
= the steam chamber grows smoothly and is contained
= the reservoir matrix is good quality (porosity ((1))> .2);
Initial Oil Saturation (SO> .6; Vertical permeability (kv)> 2D)
= net pay is sufficient (>15 metres)
= 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.
= there must be absence of significant reservoir baffles (e.g. lean zones)
or barriers
(e.g. shale)
If these conditions are not attained or other limitations are experienced,
SAGD can be
impaired, as follows:
(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.
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(2) The SAGD steam-swept zone has significant residual bitumen content that
is not
recovered, particularly for heavier bitumens and low pressure steam (Figure
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.
(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 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.
(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, Sept. 2010).
(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
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steam, sand, and water can occur (Roche, P., "Beyond Steam", New Tech. Mag.,
Sept
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
barrels (bbls) of
make-up water per barrel (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),
where 1) bitumen energy = 6 MMBTU/bbl; 2) energy used at sand face =
1MMBTU/bbl
bitumen (SOR ¨ 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 (Figure 3 PRIOR
ART);
and 6) boiler fuel is methane at 1000 BTU/SCF, then the SAGD process
efficiency =
75.5% and CO2 emissions = .077 tonnes/bbl bitumen.
(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).
(11) Lastly, there is a natural hydraulic limit that restricts well lengths or
well
diameters and can override pressure targets for SAGD operations. Figure 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 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
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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 (Figure 8). 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).
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.
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 m3/d water recharge rate) or limited (<50 m3/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.
A lean-zone reservoir, or part of a reservoir, has a low original oil
(bitumen) saturation
(SO and a corresponding high original water saturation (Siw). For the purposes
of this
invention, a lean zone is defined as (Sk, < 0.6 (i.e. the original oil/bitumen
saturation is
less than 60 percent of the pore volume).
A thief zone is defined as an active zone to which fluids are lost.
For example, Figures 9, 10, 11, and 12 characterize the McMurray formation.
Figure 9
shows the depth of the top of the formation ¨ i.e. the overburden thickness.
Figure 10
shows the thickness of the total deposit ¨ both porous and non-porous zones.
Figure 11
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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). Figure 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)
Industry reports regarding Lean Zones include the following:
= 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, Dec 2010).
= 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).
= 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)).
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= 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)).
= 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".
= 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, Jan 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.
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 (Figure 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).
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
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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.
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).
Ramey first suggested the use of oxygen gas, rather than air, for ISC in 1954.
Greenwich
Oil at Forest Hill, Texas 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).
It is important to note that there have been no specific targets on lean
reservoirs using
ISC processes.
SAGDOX is an improved thermal enhanced oil recovery (EOR) process for bitumen
recovery. The process can use geometry similar to SAGD (Figure 13), but it
also has
versions with separate vertical wells or segregated sites for oxygen injection
and/or non-
condensable vent gas removal (Figures 14, 15, 16). The process can be
considered as a
hybrid SAGD + ISC process.
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 (Figures
17, 18
Butler (1991)). Combustion temperatures are independent of pressure and they
are
higher than saturated steam temperatures (Figures 3, 18). The higher
temperature from
combustion vaporizes connate water and refluxes some steam. Steam delivers EOR
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energy from latent heat released by condensation with a net value, including
surface heat
recovery of about 1000 BTU/lb. (Figure 3).
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.
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 (Figure 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 (Figure 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 (Figure 19). Condensed water and hot bitumen 8 are
collected by
the lower horizontal well 4 and conveyed (or pumped) to the surface (Figure
13).
Combustion non-condensable gases are collected and removed by vent gas 22
wells or at
segregated vent gas sites (Figures 13, 14, 15 and 16). 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.
In rich reservoirs, SAGDOX cannot vaporize enough connate water to obviate
steam 6
injection.
To summarize, there is no thermal EOR or ISC technology focused on lean zones
to
recover bitumen.
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However, lean zones can have some redeeming advantages. They are as follows:
= Connate water can be significant if it can be mobilized and utilized as
steam
or produced and recycled as steam
= 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.
= Lean zones with low bitumen saturation (between 0.05-0.20) may provide
enough fuel to sustain combustion within the lean zones.
But for thermal EOR processes using saturated steam, lean zones present the
following
problems:
(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.
(2) For a process like SAGD, this is manifested by a rapidly increasing SOR
as initial oil saturation drops, as shown in Figure 20 for a 500 psia
saturated steam (242 C).
(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 C to 260 C), the residual bitumen saturation is in the range of 0.10 to
0.20 (Figure 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 (Figure 21).
(4) For lean zones with low bitumen (< 0.20 initial saturation), there may
be
zero recovery when steam sweeps the zone.
(5) As the initial bitumen saturation drops, most of the (steam) heat goes
to
heating connate water (Figure 22).
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(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.
(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.
(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.
Because of the above problems, lean zones have presented the following
disadvantages
for thermal EOR:
= 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 (Figure 22).
= Saturated steam is not of sufficient quality to vaporize water, only to
heat it to near saturated-steam temperature.
= The residual bitumen in a steam-swept zone can be significant,
particularly for heavy bitumens and for cooler thermal EOR processes
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(Figure 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.
= Using a simple model for steam EOR, assuming all bitumen above
0.15saturation is recovered by heating to 242 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 (Figure 21).
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
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).
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
(S10) 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.
In one embodiment, the lean zone thickness is less than 25 metres.
In one embodiment, an initial steam is injected with the oxygen into the
reservoir, then
the initial steam injection is terminated.
In one embodiment, combustion occurs at temperatures higher than 400 C.
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In one embodiment, the oxygen has an oxygen content of 95 to 99.9 (v/v)
percent.
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.
In one embodiment, the hydrocarbons are bitumen with an API density less than
10 and
in situ viscosity greater than 100,000 cp.
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.
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.
In one embodiment, the lean zone thickness is less than 25 metres.
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.
In one embodiment, the vent gas means is a segregated annulus section in the
heel section
of the horizontal well.
In a further embodiment, the vent gas means is distant said toe of said well.
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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.
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.
In one embodiment, the lean zone thickness is less than 25 metres.
In one embodiment, the vent gas means is a segregated annulus section in the
heel section
of the horizontal well.
In one embodiment, the vent gas means is distant the toe of the well.
In one embodiment, the oxygen injection site is a segregated toe section of
the horizontal
well.
In one embodiment, the toe of the well is at a different level in the
reservoir than the heel
of the well.
In one embodiment, the toe of the well is at a higher level in the reservoir
than the heel of
the well.
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BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 depicts traditional SAGD well geometry.
Figure 2 depicts the SAGD lifecycle.
Figure 3 depicts saturated steam properties.
Figure 4 depicts the operational performance of SAGD.
Figure 5 depicts Long Lake bitumen viscosity.
Figure 6 depicts the gravdrain equation for SAGD bitumen productivity.
Figure 7 depicts residual bitumen in steam-swept zones.
Figure 8 depicts SAGD hydraulic limitations.
Figure 9 depicts the depth of the top of the McMurray deposit.
Figure 10 depicts the thickness of the total McMurray deposit.
Figure 11 depicts the net thickness of the porous portion of the deposit of
the McMurray
deposit.
Figure 12 shows the bitumen net pay thickness of the McMurray deposit.
Figure 13 depicts SAGDOX well geometry.
Figure 14 depicts the preferred embodiment of THSAGDOX.
Figure 15 depicts Single Well SAGDOX (SWSAGDOX) well geometry.
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Figure 16 depicts preferred SAGDOX geometry.
Figure 17 depicts combustion heat release.
Figure 18 depicts steam + oxygen tube tests 1.
Figure 19 depicts SAGDOX mechanisms.
Figure 20 depicts steam-to-oil ratio for Steam EOR.
Figure 21 depicts residual oil/ bitumen saturation limits to recovery.
Figure 22 depicts Steam EOR Heat Distribution.
Figure 23 depicts Produced Water ¨to- Oil Ratio for LZ-SAGDOX.
Figure 24 depicts preferred LZ-SAGDOX geometry.
Figure 25 depicts ISC minimum air flux rates.
Figure 26 depicts steam + oxygen combustion tube tests II.
Figure 27 depicts THAI process well geometry.
Figure 28 depicts COGD/COSH process well geometry.
Figure 29 depicts a 3D schematic of LZ-SAGDOX.
Figure 30 depicts a LZ-SAGDOX schematic.
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Figure 31 depicts a LZ-SAGDOX schematic.
Figure 32 depicts conventional In-Situ Combustion.
DETAILED DESCRIPTION OF THE INVENTION
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") > 1Ø
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.
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 C range (Figure 21), so
combustion heat
is of sufficient quality to vaporize lean-zone connate water creating and
sustaining a good
steam inventory in the reservoir.
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 2.33bbl/bitumen);
and 2) any
water created as a chemical product of combustion is also produced, then Table
4 and
Figure 23 show Produced Water-to-Oil Ratio for LZ-SAGDOX processes. As shown
in
Figure 23, for LZ-SAGDOX, PWOR is not a strong function of the energy-to-oil
ratio
CA 02832770 2013-11-13
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("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 (Figure 20).
An assumption, to attain good water/steam benefits in the reservoir, is that
PWOR should
equal or exceed 1Ø PWOR is a reflection of steam in the reservoir per bbl of
bitumen
produced. For LZ-SAGDOX (Figure 23) this implies a maximum initial bitumen
saturation of 0.6. This sets a preferred limit value for the LZ-SAGDOX
process.
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.
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
(Figure
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.
Figures 24, 36, 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.
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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 CO2, undiluted with nitrogen. CO2 can dissolve in bitumen to
improve
productivity. Dissolution is maximized using oxygen. Also, vent gas, using
oxygen, is
mostly CO2, and it may be suitable for sequestration. Finally, there is a
minimum oxygen
flux to sustain high temperature oxidation ("HTO") combustion (Figure 25). It
is easier
to attain/sustain this flux using oxygen.
Preferably, oxygen 26 injection should be kept at a concentrated site. Because
of the
minimum 02 flux constraint for in situ combustion (Figure 25), the oxygen 26
injection
well (or a segregated section) should have no more than 50 metres of contact
with the
reservoir.
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 (Figures 13, 14); 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 (Figure 15); or 3) the entire injection string is
a corrosion
resistant alloy.
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.
CA 02832770 2013-11-13
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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.
Preferably, a minimum amount of steam 6 in the reservoir is attained or
retained.
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 01-1¨ and H+ radicals to the combustion zone to improve and
stabilize
combustion (Figures 18 and 26) (Moore, G. et al, "Parametric Study of Steam
Assisted
ISC, unpublished, Feb 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.
Steam is also a superior heat transfer agent in the reservoir. If we compare
hot
combustion gases, mostly CO2 to steam, the heat transfer advantages of steam
are
evident. For example, if we have a hot gas chamber at about 200 C at the
edges, the heat
available from cooling combustion gases from 500 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
CA 02832770 2013-11-13
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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.
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.
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.
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.
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 (Figure 16 a-
c).
Figures 14, 16b Toe-to-Heel SAGDOX ("THSAGDOX") and 16c Single Well SAGDOX
("SWSAGDOX") 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.
Preferably, SAGDOX is controlled or operated by the following:
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.
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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 content is less than 5.0% (v/v); and to
attain/maintain pressure targets.
iv) Adjust steam + oxygen injection rates (subject to (ii) above), along with
(iii)
above, to attain/maintain pressure targets.
To summarize, LZ-SAGDOX is superior to SAGDOX in LZ reservoirs for the
following
reasons:
= 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.
= Because of lower operating costs, LZ-SAGDOX can be applied at lower
bitumen saturations.
= Also, because of lower operating costs, LZ-SAGDOX will increase reserves
compared to SAGDOX.
= LZ-SAGDOX saves one well (or one completion zone) compared to
SAGDOX (steam injector).
= Fresh water or make-up water use for LZ-SAGDOX is zero (except for start-
up)
As discussed above, distinctions between LZ-SAGDOX and SAGDOX include the
following:
= LZ-SAGDOX has no steam injected; SAGDOX has steam injection;
= LZ-SAGDOX has one less injectant site (well, port), no steam injector;
= LZ-SAGDOX has restricted range for bitumen saturation (5 to 60 percent);
SAGDOX doesn't;
= LZ-SAGDOX is a combustion EOR process (based on injectants), SAGDOX
is a combined steam and combustion EOR process;
CA 02832770 2013-11-13
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= SAGDOX uses surface water for steam; LZ-SAGDOX uses no water (except
for start-up).
Distinction between Toe-to-Heel Air Injection ("THAI") (Figure 27) and LZ-
SAGDOX
include the following:
= THAI injects air; LZ-SAGDOX prefers oxygen;
= THAI has no explicit restriction on bitumen saturation; LZ-SAGDOX does;
= THAI is field tested with poor results.
= THAI has had problems with lateral growth; no steam added to foster heat
transfer; LZ-SAGDOX generates steam from LZ connate water.
Distinctions between SAGD and LZ-SAGDOX include the following:
= SAGD is a pure steam EOR process; LZ-SAGDOX is a pure combustion EOR
process (based on injectants);
= SAGD has no explicit bitumen saturation limits;
= SAGD doesn't perform well on LZ (poor field history).
Distinctions between LZ-SAGDOX and Combustion Overhead Split Horizontal
("COSH") or Combustion Overhead Gravity Drainage ("COGD") (Figure 28) include
the
following:
= COSH/COGD prefer air injection;
= COSH/COGD get lateral growth from position of vent wells; LZ-SAGDOX
gets lateral growth from steam produced in situ;
= different geometry.
Distinctions between LZ-SAGDOX and Conventional ISC (Figure 32)
(neither injects water or steam) include the following:
CA 02832770 2013-11-13
= ISC uses vertical wells (HZ for LZ-SAGDOX)
= ISC prefers air (02 for LZ-SAGDOX)
= no LZ preference for ISC
Distinctions between LZ-SAGDOX (SW version, Figures 29, 30) and Single Well
SAGD
("SWSAGD") (Figure 31) include the following:
= SWSAGD is a steam process; LZ-SAGDOX is a combustion process
= no LZ preference for SWSAGD
Distinctions between LZ-SAGDOX and Combination of Forward Combustion and Water
("COFCAW") include the following:
= COFCAW injects water; LZ-SAGDOX has no water (or steam) injection
= COFCAW uses vertical wells and conventional ISC geometry (Figure 28)
= COFCAW uses air injection; LZ-SAGDOX prefers oxygen;
= no LZ preference for COFCAW
To summarize, the unique Features of LZ-SAGDOX include the following:
= Limitation range of bitumen saturation for process applicability
= ISC process where bitumen saturation is a key factor
= Focus on lean zones; upper bitumen saturation limit
= Consideration of connate water as a steam source and the importance of
steam
in a ISC process
= Upturned toe version for SW LZ-SAGDOX process
= Focus/preference for oxygen as oxidant source
= Limitation of oxygen injection contact-zone
= Focus/preference on bitumen
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= Removal of vent gas in separate well(s) or locations (vent gas not forced
to go
to fluid production well)
= No other EOR processes are specifically focused on lean zones
= Need for a minimum amount of connate water for process to be successful
= Preferred LZ-SAGDOX geometries (Figure 24)
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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
Where ¨ assumes:
- steam at 1000 BTU/lb. avg.
- oxygen at 480 BTU/SCF avg (Butler, (1991))
- ideal gas laws
- air at 20.9% (v/v) oxygen
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Table 2
SAGDOX: PWOR
% 02 (v/v) in steam and 02 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
(1) = condensed steam
(2) = water (connate) associated with produced bit from comb.
(3)= water associated with combusted bitumen
(4) = water of combustion
= PWOR = (1) + (2) + (3) + (4) (bbls.wateribb1B)
= Sio = 0.8; no gas
= (2), (3), (4) are pro rated by heat from comb
= (1) is prorated by heat from steam
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Table 3
SAGDOX Injection Gases
% (v/v) 02 in Steam and 02 mixes
0 5 9 35 50 75
100
% heat from 02 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
02/MMBTU
MSCF 21.1 13.8 10.6 3.3 1.9 0.7 0
Steam/MMBTU
Where:
(1) Steam at 1000 BTU/lb.
(2) Oxygen at 480 BTU/SCF
CA 02832770 2013-11-13
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
(a) 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
L3) 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
(l) .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
a) 0.45 0.45 0.45 0.45 0.45
PWOR 9.81 3.95 1.78 1.04 0.45
Where
= Entries are bbl water / bbl bitumen
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= (1) = connate water associated with produced bitumen
= (2) = connate water associated with bitumen combustion
= (3) = water of combustion
= PWOR = (1) + (2) + (3)
= Water of combustion = .056 bbl / MMBTU
= Fuel = coke (CH.5)
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Table 5
PWOR LZ-SAGDOX
(PWOR bbl water/bb1B)
Initial Bitumen Saturation
ETOR = 2: 5.45 2.11 0.95 0.44
PWOR
ETOR = 4: 6.90 2.72 1.22 0.64
PWOR
ETOR = 8: 9.81 3.95 1.78 1.04
PWOR
ETOR = 12: 12.71 5.17 2.34 1.42
PWOR
ETOR = 16: 15.62 6.40 2.90 1.82
PWOR
Where:
= PWOR = water associated with bitumen produced + bitumen
combusted + water of combustion
= fuel = CH.5 coke
= comb. Water = .056 bbl/MMBTU
= complete HTO combustion
= bit. fuel value = 6 MMBTU/bbl
= 02 heat at 480 BTU/SCF
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.
