Note: Descriptions are shown in the official language in which they were submitted.
1
TITLE OF THE INVENTION
USE OF STEAM ASSISTED GRAVITY DRAINAGE WITH OXYGEN IN THE RECOVERY
OF BITUMEN IN THIN PAY ZONES
BACKGROUND OF THE INVENTION
Steam Assisted Gravity Drainage ("SAGD") is a commercial thermal enhanced oil
recovery
("EOR") process, using saturated steam injected into a horizontal well, where
latent heat is used
to heat bitumen and lower its viscosity so it drains, by gravity, to an
underlying, parallel, twin
horizontal well, completed near the reservoir floor.
Since the process inception in the early 1980's, SAGD has become the dominant,
in situ process
to recover bitumen from Alberta's bitumen deposits (Butler, R., "Thermal
Recovery of Oil &
Bitumen", Prentice-Hall, 1991). Today's SAGD bitumen production in Alberta is
about 300
Kbbl/d with installed capacity at about 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, with a 5 metre spacing between the
upper 2 and lower 4
wells, each well being about 800 metres long, and with the lower well 1 to 2
metres above the
(horizontal) reservoir floor. Circulating steam 6 in both wells starts the
SAGD process. After
communication is established, the upper well 2 is used to inject steam 6 and
the lower well 4
produces hot water and hot bitumen 8. Liquid production is accomplished by
natural lift, gas lift,
or submersible pump.
After conversion to normal SAGD operations, a steam chamber forms, around the
injection 2 and
production 4 wells, where the void space is occupied by steam 6. Steam
condenses at the
boundaries of the chamber, releases latent heat (heat of condensation) and
heats bitumen,
connate water and the reservoir matrix. Heated bitumen and water drain, by
gravity, to the lower
production well 4. The steam chamber grows upward and outward as bitumen is
drained, by
gravity, into the lower production well 4.
Figure 2 (Prior Art) shows how SAGD matures. In early stages (A), a young
steam chamber 10,
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and cold bitumen-steam interface 10a, has bitumen drainage from steep chamber
sides and from
the chamber ceiling. Optimum Productivity (B) may occur when the chamber
growth hits the top
of the reservoir 10b, ceiling drainage stops, bitumen productivity peaks
(optimum productivity)
and the slope of the side walls decreases as lateral growth continues. During
maturing/aging (C),
heat losses increase (steam to oil ratio ("SOR") increases) as ceiling contact
increases and the
surface area of the steam chamber increases. Drainage rates slow down as the
side wall angle
decreases. Eventually, at End of Life (D), the economic limit is reached and
the end-of-life
drainage angle 0 is small (10-200), as shown in Figure 2. Shut down may occur
when bitumen
netback is equal to operating expenses.
Produced fluids are near saturated temperature, so it is only the latent heat
of steam that
contributes to the process in the reservoir. But, some of the sensible heat
can be captured from
surface heat exchangers (a greater fraction at higher temperatures), so a
useful rule- of-thumb,
for net heat contribution of steam, is 1000 BTU/lb. for the pressure ("P") and
temperature ("T")
range of most SAGD projects as best seen in Figure 3 (Prior Art).
The operational performance of SAGD may be characterized by measurement of the
following
parameters: saturated steam pressure ("P") and temperature("T") in the steam
chamber, as best
seen in Figure 4 (Prior Art); bitumen productivity; SOR, usually at the well
head; sub-cool - the
T difference between saturated steam and produced fluids; and WRR - the ratio
of produced
water to steam injected (also known as the water recycle ratio).
During the SAGD process. the SAGD operator has two choices to make - the sub-
cool target T
difference and the operating pressure in the reservoir. A typical sub-cool
target of about 10 to
30 C is meant to ensure no live steam breaks through to the production well.
Process pressure
and temperature are linked (Figure 4) and relate mostly to bitumen
productivity and process
efficiency. Bitumen viscosity is a strong function of temperature, as best
seen in Figure 5 (Prior
Art). SAGD productivity is proportional to the square root of the inverse
viscosity, as seen in
Figure 6, (Prior Art) (Butler (1991)). But, conversely if P (and T) is
increased, the latent heat
content of steam drops rapidly (Figure 3) and more energy is used to heat the
rock matrix as well
as lost to the overburden or other non-productive areas. Increased pressure
increases bitumen
productivity but harms process efficiency (increases SOR). Because economic
returns can be
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dominated by bitumen productivity, the SAGD operator typically opts to target
operating
pressures higher than native, hydrostatic reservoir pressures.
Despite becoming the dominant thermal EOR process, SAGD has some limitations
and
detractions. A good SAGD project includes:
= a horizontal well is completed near the bottom of the pay zone to
effectively collect and
produce hot draining fluids.
= injected steam, at the sand face, has a high quality.
= process start up is effective and expedient.
= the steam chamber grows smoothly and is contained.
= the reservoir matrix is good quality (40> .2, Sio> .6, kv > 2D).
= net pay is sufficient (>15 metres).
= proper design and control to simultaneously prevent steam breakthrough,
prevent injector
flooding, stimulate steam chamber growth to productive zones and inhibit water
inflows to
the steam chamber.
= absence of significant reservoir baffles (e.g. lean zones) or barriers
(e.g. shale).
If these characteristics are not attained or other limitations are
experienced, SAGD may be
impaired, as follows:
(1) The preferred dominant production mechanism is gravity drainage and the
lower
production well is horizontal. If the reservoir is highly slanted, a
horizontal
production well will strand a significant resource. In other words, bitumen
under
the horizontal well is not recoverable.
(2) The SAGD steam-swept zone has significant residual bitumen content that
is not
recovered, particularly for heavier bitumens and low-pressure steam as best
seen
in Figure 7 (Prior Art). For example with a 20% residual
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bitumen (pore saturation) and a 70% initial saturation, the recovery factor
is only 71%, not including stranded bitumen below the production well or
in the wedge zone between recovery patterns.
(3) To "contain" a SAGD steam chamber, the oil in the reservoir must be
relatively immobile. SAGD cannot work on heavy (or light) oils with
some mobility at reservoir conditions. Bitumen is the preferred target.
(4) Saturated steam cannot vaporize connate water. By definition, the heat
energy in saturated steam is not high enough quality (temperature) to
vaporize water. Field experience also shows that heated connate water is
not mobilized sufficiently to be produced in SAGD. Produced water to oil
ratio ("WOR") is similar to SOR. This makes it difficult for SAGD to
breach or utilize lean zone resources.
(5) The existence of an active water zone ¨ either top water, bottom water,
or
an interspersed lean zone within the pay zone ¨ can cause operations
difficulties for SAGD or ultimately can cause project failures (Nexen Inc.,
'Second Quarter Results", Aug 4, 2011)( Vanderklippe, N., "Long Lake
Project Hits Sticky Patch", CTV, 2011). Simulation studies concluded
that increasing production well stand-off distances may optimize SAGD
performance with active bottom waters, including good pressure control to
minimize water influx (Akram, F., "Reservoir Simulation Optimizes
SAGD, American Oil and Gas Reporter, Sept. 2011).
(6) Pressure targets cannot (always) be increased to improve SAGD
productivity and SAGD economics. If the reservoir is "leaky", as pressure
is increased beyond native hydrostatic pressures, the SAGD process can
lose water or steam to zones outside the SAGD steam chamber. If liquids
are lost, the WRR decreases and the process requires significant water
make-up volumes. If steam is also lost, process efficiency drops and SOR
increases. Ultimately, if pressures are too high, if the reservoir is shallow
and if the high pressure is retained for too long, a surface break through of
steam, sand and water can occur (Roche, P., "Beyond Steam", New Tech.
Mag., Sept 2011).
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(7) Steam costs are considerable. If steam costs are over-the-fence for a
utility,
including capital charges and some profits, the costs for high- quality steam
at the
sand face is about $10 to 15/MMBTU. High steam costs can reflect on resource
quality limits and on ultimate recovery factors.
(8) Water use is significant. Assuming SOR = 3, WRR = 1 and a 90% yield of
produced water treatment (i.e. recycle), a typical SAGD water use is 0.3 bbls
of
make-up water per bbl of bitumen produced.
(9) SAGD process efficiency is "poor" and CO2 emissions are significant. If
SAGD
efficiency is defined as [(bitumen energy) - (surface energy used)] / (bitumen
energy) and bitumen energy = 6 MMBTU/bbl; energy used at sand face =
1MMBTU/bbl bitumen (SOR ¨ 3); steam is produced in a gas- fired boiler at 85%
efficiency; there are heat losses of 10% each in distribution to the well head
and
delivery from the well head to the sand face; usable steam energy is 1000
BTU/lb
(Figure 3) and boiler fuel is methane at 1000 BTU/SCF; then the SAGD process
efficiency = 75.5% and CO2 emissions = .077 tonnes/bbl bitumen.
(10) Steam distribution distance is limited to about 10 to 15 km (6 to 9
miles) due to
heat losses, pressure losses and the cost of insulated distribution steam
pipes
(Finan, A., "Integration of Nuclear Power ...", MIT thesis, June 2007) (Energy
Alberta Corp., "Nuclear Energy ...", Canadian Heavy Oil Association pres., Nov
2, 2006).
(11) Lastly, there is a "natural" hydraulic limit that restricts well
lengths or well
diameters and can override pressure targets for SAGD operations. Figure 8
shows
what can and has happened. In SAGD, a steam/liquid interface 12 is formed. As
illustrated in Figure 8 "A. Good Operation", for a good SAGD operation, with
sub-cool control, the interface is between the injector 2 and producer 4
wells. The
interface is tilted because of the pressure drop in the production well 4 due
to fluid
flow. There is little/no pressure differential in the steam/gas chamber. As
illustrated in Figure 8 "B. Poor Operation", if the liquid production rates
are too
high (or if the production well 4 is too small) the interface can be tilted so
that the
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toe of the steam injector 14 is flooded and/or the heel of the producer 16 is
exposed to steam 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 liquids producer 4 (about 8 psi (50 kPa) for a 5 metre
spacing).
Thin Pay Reservoirs (Thin Pay Zone)
For the purposes herein, "bitumen" is defined as an oil with high density
(API<10) and high in
situ viscosity (> 100,000 cP), so that primary production is zero or very
small. Bitumen is an
immobile hydrocarbon under reservoir conditions.
The largest deposits are found in the Athabasca region of Alberta - the
McMurray deposit (Table
1). Figures 9, 10, 11 and 12 characterize this deposit. Figure 9 shows the
depth of the top of the
McMurray formation - i.e. the overburden thickness. Figure 10 shows the
thickness of the total
McMurray deposit - both porous and non-porous zones. Figure 11 shows the
porosity internal -
the net thickness of the porous portion of the deposit, with a 10% porosity
cut off (this portion
contains bitumen, water and gas occupy the pore volume). 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 FOR processes - gas, top
water, bottom
water or lean zones. These zones can be within the bitumen net pay or adjacent
(top/bottom).
It has been estimated that 410 billion bbls of bitumen are deposited in thin
pay zones, less than
metres thick (Table 1) (Henrick, T. et al, "Oil Sands Research and
Development, Alberta
Energy Research Institute, Mar, 2006). The vast majority of these thin pay
reservoirs (zones)
(380 billion bbls, 93%) are in the Athabasca region. If the thin pay cut off
were set at 15 metres
rather than 10 metres, the thin pay bitumen resource is larger than the
carbonate bitumen
resource (Table 1). By any account, thin pay bitumen in Alberta is a world-
scale hydrocarbon
resource.
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Figure 12 shows thin pay zones are focused on the western side of the McMurray
deposit.
Figure 9 shows these deposits can have overburden depths ranging from about
100 ¨ 300
metres, depending on location. Hydrostatic pressures range from about 160 ¨
500 psia,
using a hydrostatic pressure gradient of 0.5 psia/ft. of depth.
Figure 13 shows the API gravity of bitumen deposits in the McMurray formation.
The
bitumen density varies from 7 to 10 API, with the lighter bitumen (higher API)
in the
southwest part of the deposit.
Based on Figures 9, 10, 11, 12 and 13 we can characterize thin pay bitumen
resources in
Alberta as:
= shallow to medium depth (100 ¨ 300m of overburden)
= low to medium pressure (160 ¨ 500 psia hydrostatic head)
= location on the western side of the Athabasca deposit
= high-moderate impairment for EOR (based on difference between net
porosity
interval and net bitumen pay)
= large opportunity (> 400 billion bbls original bitumen in place ("OBIP"))
= no known technology to economically recover thin pay bitumen (Heinrick
(2006))
= very little, if any, R&D focused on the opportunity (Heinrick (2006))
= API density in the 7 to 10 range
= Thin zone, preferably less than about 25 metres, more preferably less
than about 15
metres
The limit for SAGD minimum net-pays has been estimated as 10 ¨ 15 metres
(Heindrick
(2006)). The factors that determine this limit are as follows:
(1) SAGD Geometry
It is difficult to fit a SAGD well configuration within a net pay that is less
than about 10 metres. Spacing between the injector 2 and producer 4
horizontal wells is about 5 metres (Figure 1). The production well is
placed near the reservoir bottom, but requires a stand-off of 1 to 2 metres.
Similarly, the upper horizontal steam injector 2 needs a stand-off from the
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reservoir ceiling of a few meters. SAGD also requires that the horizontal
wells are in (or near) a horizontal plane. If the reservoir is slanted, it is
even more difficult to fit the SAGD geometry into a thin pay reservoir.
(2) Bitumen Productivity
The dominant economic factor for a SAGD project is the bitumen
productivity. Productivity can be affected directly by pay thinness or by
pressure, if the thin pay resource is shallow.
The Gravdrain Equation (Butler (1991), Figure 6) has been shown to be a
good predictor of productivity sensitivities. Productivity is proportional to
the square root of the net pay. This equation can be used to predict
productivity impairments due to net pay reductions. For example, if an
ideal SAGD project with 50 metres net pay is used as the comparison, the
following productivity reductions with smaller net pays (i.e. thin pay
zones) are expected:
25 metres net pay ¨ 29% productivity loss
15 metres net pay ¨ 45% productivity loss
metres net pay ¨ 55% productivity loss
5 metres net pay ¨68% productivity loss
These estimates don't consider productivity losses due to heat losses in
homogeneities, pattern boundary effects, containment losses, or pressure
effects.
The effect of depth can be more dramatic. Figures 9 and 12 show that
some thin pay resources are expected to be at lower depths than most of
the thick pay resources. If one is close to the surface, it becomes too risky
to operate SAGD at overpressures. One is forced to operate near
native/hydrostatic pressures. Pressure reduction can have a dramatic
effect on bitumen productivity.
By using 1) the properties of saturated steam (Figure 4); 2) the viscosity
curve for bitumen (Figure 5); and 3) the Gravdrain Equation (Figure 6) to
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estimate productivity changes with viscosity changes, one can estimate
SAGD productivity losses for shallower reservoirs by assuming the
following: 1) SAGD operation at hydrostatic pressures; 2) no changes in
reservoir thickness; and 3) a base case at 300 metre depth. The estimated
SAGD productivity losses for shallower reservoirs are as follows:
200 metre depth ¨ 15% productivity loss
100 metre depth ¨45% productivity loss
50 metre depth ¨ 66% productivity loss
The effect of reduced thickness and reduced depth are independent and
cumulative. So, if one takes a 50 metre net pay at a 300 metre overburden
depth operating at hydrostatic pressures as a bench mark, then a 10 metre
net pay at a 50 metre depth will have a productivity reduction of 85%.
This can be devastating to SAGD economics.
(3) Bitumen Recovery
In the end-of-life stage of a SAGD project, at the economic limit, the cross
section of a gravity drainage (GD) steam chamber (in a homogenous
reservoir) takes the shape of linear, sloped drainage channels, with a fixed
drainage angle (Figure 2). If one assumes a sharp break between the
steam-swept zone and the un-swept zone, and if one knows the drainage
angle at end-of-life, one can calculate the recoverable reserves. Figure 14
shows this calculation for a base-case SAGD project (25 metre net pay,
100 metre well spacing, 1 metre offset of bottom well, 0= .35, Si0 = .8, Sro
= .15, 0 = 150). The recovery factor for such a project is 56% OBIP ¨ a
typical expectation for SAGD.
Figures 15, 16, 17 show some calculations for a 10 metre thin pay
reservoir, assuming the same performance. Well spacings are for 100
metres (the same as our base case), 67.2 metres so the drainage interface
intersects the corner of the recovery pattern, and 29.8 metres so that
recoveries are similar to the base case.
The results can be summarized as follows:
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Base A
Net Pay (metres) 25 10 10 10
Well Spacing 100 100 67.2 29.8
(metres)
Recovery Factor 0.562 0.213 0.366 0.568
(metres)
So if we wish to have the same spacing as our base case, bitumen recovery
(0.213) is unacceptable. If we keep the same recovery (-0.56), we have to
reduce well spacing from 100 metres to 29.8 metres. We are increasing
well density by a factor of more than 3. This will increase capital expenses
considerably per unit bitumen produced.
(4) Economic Limitations
To illustrate the economic issues and concerns for SAGD in thin pay
bitumen reservoirs, we have constructed a simple model for end-of-life
SAGD as shown in Figure 18, with the following key assumptions:
= A 2 metre stand-off of the lower production well from the bottom of the
reservoir:
= The aspect ratio (pattern width: pattern thickness) is 4. This results in
a
drainage angle of end-of-life at 10-13';
= Base case for 25 m net pay. Recovery rate equalized over 10 yrs. (Sic, =
0.80, Sro = 0.15, (I)=0 .35);
= The average productivity for thin reservoirs is reduced according to
Figure 6 (no accounting for shallowness of net pay zone);
= Assuming a $10/bbl net back for bitumen (to the well head) we calculate
cumulative net backs at 0, 10 and 20% of discount rates.
For a 1000 metre length SAGD well pair geometry, we calculate the
following:
_________________________ pay thickness (m)
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7 10 15 25
Well spacing (m) 28 40 60 100
Bitumen Recovery .150 .344 .837 2.469
(Mbbl)
Recovery Factor .44 .49 .52 .56
Avg. Prod. (bbl/d) 358 428 525 677
Lifetime (yrs) 1.15 2.20 4.37 10.0
Cash Flow ($M)
PV0 1.50 3.44 8.37 24.69
PVio 1.35 2.97 6.51 15.19
PV20 1.23 2.57 5.25 10.36
This simple model doesn't penalize the productivity of thin pay reservoirs due
to reduced pressures (shallow resources), or heat losses proportionately
larger
than our base case, or start-up delays (instant start up is assumed). So, thin
pay
productivity is probably optimistic.
Based on our model we observe the following:
= The end-of-life drainage angles (10-13 ) are realistic for SAGD. The
recovery factors are reasonable (44 to 56%).
= In order to recover a reasonable amount of the resource, using SAGD,
thin pay reservoir well spacing must be reduced considerably. (e.g. 40
metre spacing for 10 metre net pay zone).
= If one can achieve productivities impaired only by pay thickness
reduction (i.e. other factors are constant), thin pay resources are depleted
very quickly (e.g. 2.2 yrs. for 10 m net pay)
= The model assumes instant (avg.) productivity in year 1. Delays would
hurt economics for thin pays more severely because of the short run
lengths.
= If one assumes a serviced, SAGD, 1000 metre well-pair costs $5-10
million, one sees a pay cut off of about 15 metre.
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= If net backs for bitumen were double, at $20/bbl, pay cut offs could be
less than 15 metre for SAGD.
= If one maintains a 2 metre stand off from reservoir bottom and if one
also
maintains a 5 metre spacing between steam injection and producer well,
SAGD cannot be applied to reservoirs with less than 7 metre pay
thickness.
= Figure 19 shows how the unrecovered bitumen, at end-of-life SAGD, is
distributed between wedge zones, the portion of the reservoir underneath
the plane of the production well and residual bitumen in the steam-swept
zone. As the net pay is reduced, the bitumen beneath the plane of the
production well becomes the most important unrecovered resource, unlike
thick SAGD, where the wedge zone bitumen dominates.
(5) Recovery Inhomogeneties
So far, concerns with SAGD applied to thin reservoirs that are
homogeneous have been discussed. But, no reservoir is truly
homogeneous. Shale, mudstones, lean zones, top/bottom water, and top
gas can all contribute to inhomogeneities.
SAGD is a mild process. It can also be termed as a delicate process.
Production is driven by the gravity head in the reservoir. The hydrostatic
gravity head for a 30 metre pay reservoir is very low-about only 50 psia
(maximum). The gravity gradient is only about 0.5 psi/ft, or 1.6 psi/m.
SAGD is also a 2D process. There are no significant reservoir flows in the
direction of the horizontal wells. Water in the reservoir or in an
inhomogenity cannot be vaporized by SAGD. For this reason, in a
homogeneous reservoir, a Hele-Shaw 2D physical model can be a good
predictor of actual SAGD performance. Also, SAGD temperatures are
limited to saturated steam conditions.
For these reasons above, SAGD has difficulty to overcome any reservoir
inhomogeneities that can disrupt flow patterns.
(6) Recovery Efficiency
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The usual efficiency measure for SAGD is SOR. SOR is inversely related
to efficiency ¨ low SOR ¨ high thermal efficiency. SOR is determined by
the energy needed to heat up the reservoir matrix, the energy needed to
heat up the reservoir fluids (bitumen and water) and the heat lost to
overburden and underburden (both during transit down the injection well
and direct losses in the reservoir at the over/underburden interfaces). At
lower steam pressures, SOR is reduced because less heat is needed to heat
the reservoir and compensate for losses to over/underburden. Thin pay
deposits will have increased losses to overburden because the steam
interface will hit the ceiling quicker than for thick pay resources.
Everything else being equal, energy losses to overburden are proportional
to the surface area of the ceiling. Ceiling surface area per unit OBIP is
proportional to (1/h) where h = net pay. Using this relationship, we can
expect heat losses per unit OBIP to be 2.5 times greater for 10 metre pay
reservoir compared to a 25 metre pay reservoir. So, in addition and to the
concerns already expressed, (productivity and recovery factor), thin pay
bitumen SAGD will have higher SOR (lower thermal efficiency) than
thick pay bitumen SAGD.
(7) Summary
In summary, SAGD in thin pay bitumen reservoirs has the following
deficiencies:
= It becomes difficult, using traditional SAGD geometry (Figure 1) to fit
the wells within the reservoir.
= Compared to thicker-pay reservoirs, thin pay bitumen reservoirs will have
significant bitumen productivity reductions.
= If the thin pay reservoir is shallow and SAGD is forced to operate at
pressures near to native reservoir pressure, bitumen productivity is further
reduced.
= Unless well spacing is reduced, increasing well costs, bitumen recovery
is
poor compared to thicker pay bitumen resources.
= Revenues, generated by thin pay bitumen recovery, are significantly less
than revenues from thicker-pay resources. Even when productivity is
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reduced, accounting for reduced gravity heads, thin pay production may
only last for a few years compared to over 10 years for thicker pay
resources.
= SAGD is sensitive to reservoir impairments (shales, lean zones... etc.).
If
these impairments are proportionately more prevalent in thin pay
reservoirs, SAGD will have problems as discussed herein.
= Heat losses can reduce process of efficiency. Thin pay reservoirs will
have greater heat losses to overburden or underburden than thicker-pay
resources.
Despite the deficiencies of SAGD, it is still being considered for thin pay
bitumen
recovery. Husky has proposed a $35 million, thin pay SAGD project at McMullen,
Alberta, with 10 to 16.5 metre net pay zone in the Wabaskaw formation (Roche,
P., "No
Analogue", New Tech. Mag, April 1, 2009). The generally accepted pay thickness
limit
for SAGD is 15 metres, but this may be pushed downward to 10 metres.
Based on the previous analysis, desirable attributes for SAGD improvements or
new
bitumen EOR processes for thin pay resources are as follows:
= Reduce the well costs, per bbl. of bitumen recovered. This can be
accomplished by new well configurations, reduced well sizes, longer
(horizontal) wells, or the use of well components that are retrievable and
reusable.
= Reduce the unit operating expenses. This can be accomplished by
injecting energy that is less costly than steam or by using processes that
require less energy to produce bitumen.
= Increase bitumen productivity. This can be accomplished by processes
that run hotter than SAGD, introduce new recovery mechanisms, or
increase well lengths.
= Increase productivity in impaired reservoirs. This can be accomplished by
processes that are 3 dimensional, processes that can more easily breach
barriers (e.g. vaporize water...) or processes that run hotter than SAGD.
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= Increase ultimate recovery. This can be accomplished by processes that
recover some residual bitumen from a steam-swept zone, or recover more
oil from wedge zones between recovery patterns.
= Increase produced bitumen value. This can be accomplished by partial in
situ upgrading.
= Improve environmental performance. This can be accomplished by
reducing (make-up) water use, increasing process efficiency, reducing
CO2 emissions or reducing surface footprints.
In addition to SAGD, the following processes have been suggested as applicable
for thin
pay bitumen recovery:
(i) Expanding Solvent SAGD (ESSAGD) has been suggested as a process to
target thin pay (Gates, I. "Solvent Aided SAGD in thin oil sand reservoirs,
Journal of Petroleum Science and Engineering April 24, 2010). The idea is
simply that steam and solvent is more effective than steam alone. Solvent
dissolution in bitumen can lower viscosity and provide a separate recovery
mechanism compared to steam alone. But, the process has the following
deficiencies:
= The operating temperature is lower than SAGD, at the same P,
because steam is diluted by solvent gas. Heat losses can be
reduced, but productivity, due solely to bitumen heating, is also
reduced compared to SAGD.
= The process geometry is similar to SAGD. The process is a 2D
process, with no reservoir flows in the longitudinal direction. Well
costs (capital expenses) are similar to SAGD.
= Solvent (butane, condensate, BTX...) is very costly (more valuable
than bitumen). If there are any net solvent losses to the reservoir
(leakage, retention), operating expenses can be comparable or
higher than SAGD.
= The extent of solvent losses is unknown until the end of the
project.
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= No field tests for ESSAGD in thin pay bitumen, have been
conducted.
(ii) It has also been suggested that SAGD geometry can be altered, in thin
pay
reservoirs, by offsetting the upper steam injector in a lateral direction, or
by adding a multi-lateral producer to the SAGD geometry (Tavallali,
"Assessment of SAGD ..." SPE 153128, Mar, 2012). However, the
process has the following deficiencies:
= Capital expense is similar to SAGD. The well count and length are
unchanged.
= The focus of the process is on heavy oil not bitumen.
= Other SAGD concerns ¨ poor productivity, poor energy efficiency,
and poor recovery or increased well spacing ¨ are retained by this
technology.
(iii) It has also been suggested to replace the parallel SAGD steam
injector
with a series of overlapping perpendicular horizontal injector wells
(Stalder, "Cross SAGD (XSAGD)..." SPE Reservoir Evaluation &
Engineering, 2007). The process is called cross SAGD or XSAGD. This
forms a grid of parallel horizontal steam injectors intersecting (at a
spacing similar to SAGD (5 metres)) a grid of parallel horizontal
producers. XSAGD deficiencies are similar to (ii) above.
(iv) Solvents without steam have also been suggested, using a VAPEX process
(New Tech Mag., "VAPEX shows promise but stuck in lab", 2005). But
this pure solvent process has the following deficiencies:
= The processes have been proven in field tests to be difficult (slow)
to start.
= Productivity has been much less than SAGD.
= Solvents are expensive (more costly than bitumen), so that, even
with modest losses, operating expenses are a concern.
= The processes are 2D, without longitudinal flows in the reservoir.
= Focus has shifted to heavy oils (with some initial injectivity) not to
bitumen.
CA 02830405 2013-10-21
17
= Solvent losses (to the reservoir) are a key economic concern.
Unfortunately, net losses cannot be confirmed until the end of the
project, when solvents are expected to be recovered in a blow-
down phase.
(v) Single Well SAGD ("SWSAGD") is another EOR alternative for thin pay
bitumen and heavy oil applications (Elliot, K. et al, "Computer Simulation
of SWSAGD", U.S. Department of Energy, 14994-18, July 1999) ( ELAN
Energy, "Announces Six Month Results", Aug., 1996) ( Improved
Recovery Week, "Thermal System ups heavy oil ...", Dec 4, 1995). The
idea is to incorporate steam 6 injection and bitumen + water 8 production
into a single horizontal well, using thermal packers 18 (Figure 20) (or not
(Figure 21), in order to isolate steam 6 injection and bitumen + water 8
production.
The original targets were thin heavy oil deposits in W. Saskatchewan and
E. Alberta (Ashok, K. et al, "A Mechanistic Study of SWSAGD", Society
of Petroleum Engineers, 59333-MS, 2000) (ELAN Energy, "Announces
Nine Month Earnings, Nov. 1996) ( Luft, H.B. et al, "Thermal
Performance of Insulated Concentric Coiled Tubing (ICCT) for
Continuous ..., "SPE, 37534-MS, 1997). The first SWSAGD well was
drilled at Cactus Lake, Saskatchewan in 1995 (HOSC (Heavy Oil Sci.
Cent.) "Completions and Workovers", vvww.11oydminsterheavyoil.com,
2012). Several field tests were conducted by Elan and others in the 1990s
(Elliot (1999), (Saltuklaroglu, M. et al, "Mobil's SAGD Experience at
Celtic, Saskatchewan" SPE, 99-25, June 1999).
Compared to SAGD, SWSAGD has a definite longitudinal flow so it can
more easily deal with barriers and it has a defmite reduced well cost. But,
the following concerns were also evident:
= The centralized concentric steam line 6 is in contact with the
produced fluids (water + bitumen 8) (Figures 20, 21). The
CA 02830405 2013-10-21
18
produced fluids have a high heat capacity and normally (i.e.
SAGD) the fluids would be at a lower temperature than saturated-
steam (i.e. sub-cool control). Heat losses from the steam injector to
the produced fluids can be considerable for uninsulated,
concentric, carbon steel tubing. Heat losses from the steam 6 and
produced liquids 8 are also a concern because the produced liquids
have a high heat conductivity. The produced fluids 8 are heated
rapidly to saturated steam temperatures and the steam quality is
reduced considerably before injection to the reservoir. The use of a
steam trap (sub cool) control for production rates will be difficult,
at best. One solution is to use insulated tubing for the steam
injection tube. Insulated concentric coiled tubing (ICCT) was
developed for this purpose but has not resulted in widespread use
today (Luft, H.B. et al, "Thermal Performance of Insulated
Concentric Coiled Tubing (ICCT) for Continuous ..., "SPE,
37534-MS, 1997) (Falk, K. et al, "Concentric Coiled Tubing for
SWSAGD", World Oil, July 1996).
= Start-up performance is another issue. Even for heavy oil deposits
with some steam injectivity and some primary production, start up
was difficult and protracted (Elliot (1999)). Initial production rates
were disappointing (Elliot (1999)). At least partially, this problem
could be due to 2 factors. Initial steam quality at the sand face was
poor due to heat losses to produced fluids. Also, the steam
injection site occurs at the same elevation as production (Figure
20). There is no stand-off like SAGD to allow a liquid level to
isolate the producer and prevent steam break through (Figure 1).
Steam by-passing is an issue (Ashok, K. et al, "A Mechanistic
Study of SWSAGD", SPE, 59333-MS, 2000). Stand influx
problems were another issue (Elliot (1999)). Because of these
issues, an alternative start-up procedure using cyclic steam has
been suggested (Elliot (1999)), but this has not been field tested.
CA 02830405 2013-10-21
19
= Even after start-up, SWSAGD performance has been disappointing
(Saltuklaroglu (1999), Elliot (1999)). Elan Energy was the
inventor and major operator of SWSAGD. Prior to late 1999, Elan
had drilled 19 SWSAGD wells with 7 separate pilots. By the end
of 1999, five of the seven pilots had been suspended or converted
to other processes due to poor performance (Elliot (1999)). Best
results were for high pressure, low viscosity, heavy oils with some
primary production as foamy oil and no bottom water. This
process is focussed on deep thin pay heavy oil, not bitumen.
= In 1997, Ranger Oil & Gas acquired Elan (Business Day, "Ranger
Oil ... deal for Elan Energy", Sept 3, 1997). In 1999, Ranger was
acquired by Canadian Natural Resources Limited (CNRL) (CNRL
"Ranger Oil agrees to CNRL offer" 1999). Post 1999, there have
been no indications of further SWSAGD developments,
particularly none associated with bitumen.
= Field testing of SWSAGD can be labelled unsuccessful.
(vi) A process has also been suggested using heated, vaporized solvent to get
some advantages of both solvent EOR and thermal EOR. Similar to SAGD
a gas gravity drainage (GD) chamber is formed containing vaporized
solvent gas. The solvent condenses at the cold bitumen interface releasing
its latent heat, similar to steam. The solvent liquid can then dissolve into
bitumen to further reduce viscosity. The process is called N-Solv
(Braswell, J., "New Heavy Oil Solvent Extraction Pilot to Test
Experimental Process" The Journal of Petroleum Technology Online, Jan
9, 2012). The process claims reduced environmental impacts compared to
SAGD. A field pilot is expected to start up in 2013 (Braswell (2012)).
But the process has the following concerns:
= Well configuration similar to SAGD. No/little capital cost
reduction.
CA 02830405 2013-10-21
= Proposed test site is for thick bitumen pays, no focus on thin pay
resources.
= Similar to SAGD. 2D process. No longitudinal flows in reservoir.
Hard to breach barriers.
= Solvent is costly (more valuable than bitumen). Solvent losses are
a key economic concern.
= Solvent losses cannot be confirmed or estimated prior to end of
process when solvent inventory recovery is attempted.
= Productivity may be worse than SAGD.
= Poor field test results for VAPEX ¨ a similar process (NSolv,
"Developing an In Situ Process..." NSolv website, 2012).
= Hard to start-up process.
(vii) A combustion process, using a toe-to-heel geometry, called THAI (Toe-to-
Heel Air Injection) has also been suggested for thin pay resources (Figure
22). The process uses a horizontal well to collect heated oil 8 and
combustion gases 22. A vertical well, completed near the toe of the
horizontal well, injects compressed air 20. Assuming good high
temperature oxidation (HTO) combustion, the process is potentially less
costly than SAGD. The process was developed in the laboratory using
physical models (Greaves, M. et al, "THAI ¨ New Air Injection
Technology ...", SPE 99-15, June, 1995).
Petrobank Energy and Resources Ltd., Calgary, Alberta has purchased and
developed proprietary rights to the technology and is developing a series
of field pilots ("THAI" Wikipedia accessed 2012)). The initial pilot has
been operating since 2006. Recently, Petrobank's reserves consultant
dropped reserves related to THAI because of protracted poor performance
(Energy Inc, "Petrobank suffers setback with THAI", Mar 8, 2012).
One of the problems with THAI is how to prevent air from short-circuiting
the process and by-passing the reservoir by entering the production well
upstream of the combustion front (Figure 22). In the laboratory, the by-
pass is prevented by the formation of a coke plug, in the production well,
CA 02830405 2013-10-21
21
upstream of the combustion front. If this plug does not form in a field test,
it is necessary to use a moveable high-temperature packer or a sliding
sleeve. Either of these is a difficult task.
Another issue is that lateral growth can be slow. There is no/little steam to
foster lateral growth and the geometry precludes a lateral flow component.
Other problems, noted in the field tests, included corrosion, sand influx,
plugging and explosions in the production well.
Other features/concerns with THAI include the following:
= Air (not oxygen) is in the injectant oxygen-containing gas.
= No steam is injected, except for start-up, concurrently with air (or
oxygen).
= Wet combustion (injection of water) is contemplated but not yet
practiced.
= There is no separate removal of non-condensable, combustion
gases in vent wells or otherwise. These gases are forced to be
removed by the single horizontal production well (Figure 22).
This can impair liquid production rates.
= The field experience for THAI is poor (Calgary Herald, "Petrobank
Technology earns Zero Grade", 2012).
= The current focus of THAI is on heavy oils, not bitumen (OGJ
(2012))
(viii) Another, related combustion process is Combustion Overhead Gravity
Drainage (COGD) also called Combustion Overhead Split Horizontal
(COSH) (Figure 23). Unlike THAI, this
process is a top-down
combustion EOR process. The process includes short paths for bitumen
recovery, drainage to a horizontal production well, separate overhead
vertical injector wells for compressed air 24 and separate vent gas wells 22
(horizontal or vertical) for combustion gas removal at the flank of the
pattern boundaries (New Tech. Mag. "Excelsior files patent for ISC
CA 02830405 2013-10-21
22
Process", Sep 25, 2009) (New Tech. Mag. "Excelsior searching ... COGD
..." Nov 20, 2009). The flank gas removal system promotes lateral
growth ¨ a problem for THAI. Also, unlike THAI, gas and liquid
production is separate in the reservoir, the horizontal production well
produces only liquids.
But the process has the following features/concerns:
= The combustion reactions at the bitumen interface are complex and
have not been verified by field tests.
= There are no current/contemplated field tests for COGD or COSH.
= The process contemplated air (not oxygen) injection.
= The process has extra wells (extra capital expenses) compared to
THAI or SAGD.
= Focus of the process has been on heavy oil, not bitumen.
(ix) Toe-to-Heel Steam Flood (THSF) (Figure 24) is another thermal EOR
process suggested for thin pay reservoirs (Bagci, A.S. et al, "Investigation
of THSF for heavy oil recovery" Energy Technology Data Exchange,
21025339, July, 2008). Figure 55 (PRIOR ART) also depicts THSF but
with a shared injection well.
So far, the focus for THSF has been in heavy oils not bitumen (Fatemi,
S.M. et al, "Injection Well-Producer Well Combinations for Toe-to-Heel
Steam Flooding (THSF), SPE 140703-MS, May 2011) (Fatemi, S.M. et al,
"Preliminary Considerations on the application of THSF...", Chem. Eng.
Res. & Design, Nov 2011) (US Patent 5626193). Compared to
conventional (vertical-well) steam floods, THSF has purported better
stability (i.e. gravity stabilizes the process) and better recoveries (Turta,
A.T. et al, "Preliminary Considerations on the application of THSF..."
SPW, 130444-PA, JCPT, Nov 2009). A small amount of non-condensable
CA 02830405 2013-10-21
23
gas added to the steam was shown to improve performance (Turta (2009)).
But by problems include high costs of steam and lack of field tests.
But once communication is established between the injector well 6 and the
producer well 8, there is little pressure differential to push oil to the
producer well, without significant steam breakthrough to the production
well. Thus if steam breakthrough is avoided, the main mechanism is
gravity drainage with progression of the GD steam chamber from toe-to-
heel. The process is now a GD process not a SF.
(x) A single-well
version of THSF (SWTHSF) was also identified with a
geometry and process similar to SWSAGD (US 5626193). The focus was
on thin pay heavy oils, not bitumen, and insulated tubing was used for the
steam injector. The proposed well trajectory, including the tow-region for
steam injection, was horizontal. But, problems/concerns are similar to
THSF.
(xi) We can summarize the currently proposed alternatives for thin pay
bitumen EOR as follows:
= All of the alternatives have been studies mostly using
mathematical simulation models.
= There has been little (or no) focus on thin pay bitumen resources.
= There has been some focus on thin pay heavy oil resources (THSF,
SWTHSF) with no discussion of bitumen EOR.
= Some of alternatives have included physical model tests (e.g.
ESSAGD, VAPEX, N-SOLV, THAI ...), but again, not focussed
on thin pay bitumen resources.
= A few of the bitumen alternatives (e.g. ESSAGD, VAPEX,
SWSAGD, THAI ...) have been field tested, but not focussed on
thin pay bitumen.
= Some of the bitumen alternatives are now focussed on heavy oil
applications (not bitumen) (e.g. THAI, VAPEX, SWSAGD ...)
CA 02830405 2013-10-21
24
= None of these processes has resulted in any field test or lab
physical-model tests, focussed on thin pay bitumen resources.
= Some of the processes are projecting field tests (e.g. N-SOLV) but
again not focussed on thin pays.
Steam Assisted Gravity Drainage with added Oxygen ("SAGDOX") is an improved
thermal EOR process for bitumen recovery. The process may use a geometry
similar to
SAGD (Figure 36), but it also has versions with separate wells or segregated
sites for
oxygen 26 injection and non-condensable vent gas 22 removal (Figures 26, 27,
28, 29,
30, 31, 32, 33). The process may be considered as a hybrid SAGD and ISC
process. ISC
is a process that, so far, has shown little application for bitumen recovery.
Examples of
ISC are depicted in Figures 43 and 54 (PRIOR ART).
The objective of SAGDOX is to reduce reservoir energy injection costs, while
maintaining good efficiency and productivity. Oxygen combustion produces in
situ heat
at a rate of about 480 BTU/SCF oxygen, independent of fuel combusted (Figure
34,
Butler (1991)). Combustion temperatures are independent of pressure and they
are
higher than saturated steam temperatures (Figures 4, 56). The higher
temperature from
combustion vaporizes connate water and refluxes some steam. Steam delivers EOR
energy from latent heat released by condensation with a net value, including
surface heat
recovery, of about 1000 BTU/lb (Figure 3). Table 2 presents thermal properties
of steam
+ oxygen mixtures. Per unit heat delivered to the reservoir, oxygen volumes
are ten
times less than steam, and oxygen costs (including capital charges) are one
half to one
third the cost of steam.
The recovery mechanisms are more complex for SAGDOX than for SAGD. The
combustion zone is contained within the steam-swept zone. Residual bitumen, in
the
steam-swept zone, is heated, fractionated and pyrolyzed by hot combustion
gases to
provide coke that is the actual fuel for combustion. A gas chamber is formed
containing
steam combustion gases, vaporized connate water, and other gases (Figure 35).
The large
gas chamber can be subdivided into a combustion-swept zone 100, a combustion
zone
CA 02830405 2013-10-21
110, a pyrolysis zone 120, a hot bitumen bank 130, a superheated steam zone
140 and a
saturated steam zone 150 (Figure 35). Condensed steam drains from the
saturated steam
zone and from the ceiling and walls of the gas chamber. Hot bitumen drains
from the
ceiling and walls of the chamber and from the hot bitumen zone at the edge of
the
combustion front (Figure 35). Condensed water and hot bitumen 8 are collected
by the
lower horizontal well and conveyed (or pumped) to the surface (Figure 36).
Combustion non-condensable gases 22 are collected and removed by vent gas
wells or at
segregated vent gas sites (Figures 36, 31). Process pressures may be
controlled
(partially) by vent gas production, independent of liquid production rates.
Vent gas 22
production may also be used to influence direction and rate of gas chamber
growth
This invention involves the application of the SAGDOX process to thin pay
bitumen
reservoirs (i.e. thin pay zones).
SUMMARY OF THE INVENTION
According to one aspect, there is provided a process to recover liquid
hydrocarbons, from
at least one thin pay zone in a hydrocarbon bitumen reservoir via a
substantially
horizontal production well wherein said hydrocarbon bitumen reservoir further
comprises, a top and a bottom; said process comprising the use of Steam
Assisted Gravity
Drainage with Oxygen (SAGDOX) wherein:
i) steam is injected into said hydrocarbon bitumen reservoir above said
substantially horizontal production well;
ii) oxygen is injected into said hydrocarbon bitumen reservoir above said
substantially horizontal production well; and
iii) liquid hydrocarbon is recovered via gravity drainage into said
substantially
horizontal production well.
CA 02830405 2013-10-21
26
Preferably, said at least one thin pay zone is segregated from said
hydrocarbon reservoir,
such that fluid flow is contained within said one thin pay zone.
Preferably, said steam is injected proximate said at least one thin pay zone.
Preferably, said oxygen is injected proximate said at least one thin pay zone.
More preferably both said steam and said oxygen are injected proximate said at
least one
thin pay zone.
More preferably, said oxygen to said steam are injected into said reservoir,
preferably
proximate said at least one thin pay zone, at a ratio from about 0.05 to 1.00
v/v.
In one embodiment, said substantially horizontal well further comprises a toe
section and
a heel section. Preferably, said toe section is at a first level in said
reservoir and said heel
section is at a second level in said reservoir. More preferably said heel
section is closer
to said bottom and said toe section is closer to said top of said reservoir.
In another embodiment, said SAGDOX has a geometry selected from a Toe-to-Heel
SAGDOX ("THSAGDOX") geometry and a Single Well SAGDOX ("SWSAGDOX")
geometry.
Preferably said at least one thin pay zone has a thickness of less than about
25 metres.
More preferably said at least one thin pay zone has a thickness of less than
about 15
metres.
Preferably the substantially horizontal production well is used to produce
water and
liquid hydrocarbons and is completed within 2 metres of the reservoir bottom.
Preferably the steam is injected within 20 metres from the substantially
horizontal
production well, and the oxygen is injected within 50 metres from the
substantially
CA 02830405 2013-10-21
27
horizontal production well; wherein said substantially horizontal production
well further
comprises at least one a perforation zone less than 50 metres in length.
In one embodiment, the injection of oxygen and steam is controlled in the
range from
0.05 to 1.00 (v/v) oxygen: steam ratio.
Preferably the ratio of oxygen to steam is increased during the process so
that the
oxygen/steam ratio (v/v) is maximized proximate the end of the process.
In another embodiment, said THSAGDOX further comprises an uplifted toe section
in
said substantially horizontal production well.
According to one aspect, there is provided a process to recover liquid
hydrocarbons, from
a hydrocarbon bitumen reservoir, via a substantially horizontal production
well, wherein
said hydrocarbon bitumen reservoir has at least one thin pay zone, a top, and
a bottom
preferably at least one thin pay bitumen containing zone of less than about 25
metres
thickness; said process comprising Steam Assisted Gravity Drainage with Oxygen
(SAGDOX) selected from the group consisting of Toe-to Heel SAGDOX (THSAGDOX)
and Single Well SAGDOX (SWSAGDOX).
In one embodiment, said substantially horizontal well further comprises a toe
section and
a heel section. Preferably said toe section is at a first level in said
reservoir and said heel
section is at a second level in said reservoir. Preferably said heel section
is closer to said
bottom and said toe section is closer to said top.
In one embodiment said SAGDOX is THSAGDOX, more preferably said THSAGDOX
further comprises said horizontal well with an uplifted toe section.
In another embodiment said SAGDOX is SWSAGDOX.
In one embodiment, the horizontal production well is completed within about 2
metres of
the bottom.
CA 02830405 2013-10-21
28
In another embodiment, steam is injected proximate said horizontal production
well via at
least one steam injector, preferably within about 20 metres from the
horizontal
production well.
In another embodiment, oxygen, preferably oxygen containing gas is injected
proximate
said horizontal productions well via at least one oxygen injector, preferably
within about
50 metres from the horizontal production well and more preferably with a
perforation
(contact) zone less than about 50 metres in length.
In another embodiment, a ratio of oxygen to steamõ is controlled in the range
from about
0.05 to 1.00 (v/v).
In another embodiment, non-condensable gases produced by combustion and inert
gases
in the oxygen (vent gas) are removed by at least one vent gas outlet,
preferably separately
removed. Most preferably separately removed from about 5 to about 75 metres
from the
horizontal production well.
In another embodiment, said at least one steam injector and said at least one
oxygen
injector is separated from said at least one vent gas outlet by at least about
100 metres.
In another embodiment, the reservoir is slanted and the horizontal production
well is less
than about 2 metres from the bottom of the reservoir at its closest point.
In another embodiment, the at least one steam injector and the at least one
oxygen
containing gas injector is within 10 metres of the horizontal production well.
In another embodiment, said steam is injected into said reservoir using at
least one
parallel horizontal steam injection well in a plane substantially vertical to
the horizontal
production well, preferably from about 3 to about 8 metres above the
horizontal
production well.
CA 02830405 2013-10-21
29
In another embodiment, said steam is injected using at least one single
substantially
vertical well, preferably a plurality of substantially vertical wells.
In another embodiment, oxygen containing gas is injected into the reservoir
using at least
one single substantially vertical well, preferably a plurality of
substantially vertical wells.
In another embodiment, vent gas is removed from the reservoir using at least
one single
substantially vertical well, preferably a plurality of substantially vertical
wells.
In another embodiment, said steam and oxygen containing gas are comingled,
preferably
at the surface, and injected into the reservoir using at least one single
substantially
vertical well, preferably a plurality of substantially vertical wells.
In another embodiment, said steam and oxygen containing gas are substantially
segregated, preferably by at least one packer, more preferably by a plurality
of packers,
and injected separately into the reservoir, preferably by at least one single
substantially
vertical well, more preferably by a plurality of substantially vertical wells.
In another embodiment, said steam and oxygen containing gas are substantially
segregated using concentric tubing and packers, preferably with steam in the
central
tubing surrounded by oxygen containing gas in an adjacent annulus, and with
oxygen
containing gas injected at an elevation in the reservoir higher than said
steam injected
elevation.
In another embodiment, a single substantially vertical well is used to inject
steam and
oxygen containing gas into said reservoir, where the single substantially
vertical well is
completed within about 50 metres from the toe of the horizontal production
well.
In another embodiment, the oxygen containing gas injection is accomplished
using a
segregated toe section of the horizontal production well.
CA 02830405 2013-10-21
In another embodiment, the vent gas removal site is a segregated annulus
section in the
heel rise section of the horizontal well.
In another embodiment, said steam and oxygen containing gas are comingled at
the
surface and injected into the reservoir using a segregated toe section of the
horizontal
well.
In another embodiment, said oxygen containing gas and steam are substantially
segregated and simultaneously injected into the reservoir from a segregated
toe section of
the horizontal well.
Preferably said oxygen containing gas and steam are substantially segregated
by using
concentric tubing and packers, said concentric tubing further comprising
central tubing
and an adjacent annulus, with steam in the central tubing surrounded by oxygen-
containing gas in the adjacent annulus.
In another embodiment, said vent gas is removed in a segregated annulus in the
heel rise
section of the horizontal well.
In another embodiment, the toe of the horizontal production well is drilled
upwards and
completed so the lowest injection orifice (for injection of at least one of
steam; oxygen
containing gas and both) is greater than 2 metres higher than the horizontal
plane of the
horizontal section of the horizontal production well.
In another embodiment, the horizontal production well is drilled parallel to
the reservoir
bottom in an up-dip direction in a slanted reservoir, so that the lowest
injection orifice is
more than 2 metres higher in elevation than the highest liquid production
orifice.
In a preferred embodiment, the ratio of oxygen, in oxygen containing gas, to
steam is
increased during the maturation of the process so that the oxygen to steam
ratio (v/v) is
maximized at the end of the process life.
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31
In a preferred embodiment, an extender tube proximate the toe of the
horizontal
production well is used, preferably to ensure that the lowest pressure in the
production
well is proximate the toe.
Preferably said vent gas wells (sites) and steam/oxygen injectors are
separated by at least
100 metres.
In one embodiment, the oxygen containing gas is oxygen with an oxygen content
of 95 to
99.9 (v/v) percent.
In another embodiment, the oxygen containing gas is air, preferably enriched
air, with an
oxygen content of 21 to 95 (v/v) percent.
In one embodiment the hydrocarbon liquid is bitumen (API density <10; in situ
viscosity
>100,000 cp.).
In another embodiment the hydrocarbon liquid is heavy oil (10 < API <20; in
situ
viscosity 1000cp.)
In one embodiment, the substantially horizontal production well has a length
greater than
1000 metres.
BRIEF DESCRIPTION OF THE FIGURES
Figure 1 depicts a traditional SAGD geometry.
Figure 2 depicts a pattern end view of a SAGD life cycle.
Figure 3 depicts saturated steam properties.
CA 02830405 2013-10-21
32
Figure 4 depicts Pressure versus Temperature for Saturated Steam.
Figure 5 depicts bitumen Viscosity versus Temperature of Long Lake bitumen.
Figure 6 depicts the Gravdrain Equation for SAGD Bitumen Productivity.
Figure 7 depicts fractional residual bitumen in pores versus saturated steam
temperature
and equivalent hydrostatic depth for residual bitumen in steam-swept zones.
Figure 8 depicts SAGD hydraulic limitations.
Figure 9 depicts the Top of the McMurray Formation.
Figure 10 depicts the Thickness of the McMurray Formation.
Figure 11 depicts the Porosity Interval of the McMurray Formation.
Figure 12 depicts the Bitumen Pay Thickness of the McMurray Formation.
Figure 13 depicts the API Gravity of the McMurray Formation.
Figure 14 depicts a Traditional SAGD Recovery Geometry.
Figure 15 depicts a first SAGD geometry for recovery in a thin pay zone.
Figure 16 depicts a second SAGD geometry for recovery in a thin pay zone.
Figure 17 depicts a third SAGD geometry for recovery in a thin pay zone.
Figure 18 depicts a simple SAGD model.
CA 02830405 2013-10-21
33
Figure 19 depicts unrecovered bitumen at end of life processing versus net pay
thickness.
Figure 20 depicts a SWSAGD schematic and well configuration (with packers).
Figure 21 depicts a SWSAGD schematic and well configuration (without packers).
Figure 22 depicts a THAI geometry for ISC.
Figure 23 depicts a COGD/COSH geometry for ISC.
Figure 23(a) depicts an embodiment of a SVVSAGDOX with off-set packers with
steam
and oxygen being mixed and segregated, according to the present invention.
Figure 24 depicts a typical SAGDOX geometry according to the present
invention.
Figure 25 depicts SWSF geometries for SWSAGD, SWSAGDOX, SWSF(U) and
SWSAGDOX(U).
Figure 26 depicts a first embodiment of a THSAGDOX according to the present
invention.
Figure 27 depicts a second embodiment of a THSAGDOX according to the present
invention.
Figure 28 depicts a third embodiment of a THSAGDOX according to the present
invention.
Figure 29 depicts a fourth embodiment of a THSAGDOX configuration and piping
schematic according to the present invention.
34
Figure 30 depicts an embodiment of a SWSAGDOX(U) schematic and associated
piping
schematic according to the present invention.
Figure 31 depicts a second embodiment of a SWSAGDOX(U) schematic and
associated piping
schematic according to the present invention.
Figure 32 depicts an embodiment of a SWSAGDOX configuration according to the
present
invention.
Figure 33 depicts an embodiment of a SWSAGDOX with centralized packers with
steam and
oxygen being premixed, segregated and segregated and isolated, according to
the present
invention.
Figure 34 depicts HHV versus H/C ratio of fuel.
Figure 35 depicts typical SAGDOX process mechanisms.
Figure 36 depicts a typical THSF.
Figure 37 depicts ISC minimum air flux rates.
Figure 38 depicts Steam and Oxygen Combustion Tube Tests II.
Figure 39 depicts three SAGDOX geometries according to the present invention.
Figure 40 depicts a multiple well THSAGDOX geometry (illustrated by example
wells #1-4)
with initial steam and oxygen injection at the toe of the production well
according to the present
invention. Well 2 is initially used to remove vent gas. As the combustion
front approaches the
well, it is converted to a steam and oxygen injector and well 3 is then used
as a vent gas removal
well, and so on as the process matures.
Figure 41 depicts a conventional ISC. Oxygen and steam injection is initiated
in well 1. Wells 2
and 3 are initially used as vent gas wells. As the combustion front nears
wells 2&3 they are
converted to oxygen and steam injectors and wells 4 & 5 are used to remove
vent gas
CAN_DMS. \130875725\1
CA 2830405 2019-12-06
35
Figure 42 depicts the a side view of a recovery pattern of a gas chamber,
comprising a
combustion swept zone (CSZ), during various stages of THSAGDOX.
Figure 43 depicts a multiple well THSAGDOX geometry with initial steam and
oxygen injection
at the middle of the production well according to the present invention.
Surface well pattern of
vertical wells is often in a geometric pattern, i.e. 5 spot, 7 spot, 9 spot,
etc.
Figure 44 depicts a multiple well THSAGDOX geometry with alternating
oxygen/steam and vent
gas wells according to the present invention which may permit long(er)
horiztonal wells and
impairment flexibility.
Figure 45 depicts SWSAGDOX and SWSAGDDOX(U) hydraulic limitations.
Figure 46 depicts a typical SWSAGD(U) schematic and associated piping
schematic.
Figure 47 depicts oxygen pipe and tubing design.
Figure 48 depicts an embodiment of a THSAGDOX with a shared injection well for
oxygen and
steam according to the present invention.
Figure 49 depicts an embodiment of a SWSAGDOX geometry in a tilted thin pay
zone according
to the present invention.
Figure 50 depicts a THSAGDOX liquid drawdown at the heel and toe of the
production well.
Figure 51 depicts a SWSAGD in tilted pay zones.
Figure 52 depicts SWSAGD in tilted pay zones.
Figure 53 depicts TH geometries for THSF, THISC (or THAI) and THSAGDOX.
Figure 54 depicts SWISC process.
Date Recue/Date Received 2020-06-05
36
Figure 55 depicts a THSF with a shared injection well.
Figure 56 depicts Steam and Oxygen Combustion Tube tests I.
Figure 57 depicts a three well THSAGDOX geometry according to the present
invention. A
central vertical well may initially be used to remove vent gas, and after the
combustion front
approaches this well, it is converted to a steam and oxygen injector.
DETAILED DESCRIPTION OF THE INVENTION
Preferred parameters in SAGDOX geometries of the present invention in thin pay
zones include
the following:
(1) Use Oxygen (rather than air) as the oxidant injected
= If the cost of treating vent gas to remove sulphur components and to
recover volatile hydrocarbons is factored in, even at low pressures the all-
in cost of oxygen is less than the cost of compressed air, per unit energy
delivered to the reservoir.
= Oxygen occupies about one fifth the volume compared to air for the same
energy delivery. Well pipes/tubing is smaller and oxygen can be
transported further distances from a central plant site.
= In situ combustion (ISC) using oxygen produces mostly non-condensable
CO2, undiluted with nitrogen. CO2 can dissolve in bitumen to improve
productivity. Dissolution is maximized using oxygen.
= Vent gas, using oxygen, is mostly CO2 and may be used for sequestration.
= There is a minimum oxygen flux to sustain HTO combustion (Figure 37)
= It is easier to attain/sustain this flux using oxygen
(2) Keep oxygen injection at a concentrated site
= Because of the minimum 02 flux constraint from in situ combustion
(Figure 37), the oxygen injection well (or a segregated
CAN_DMS. \130875725\1
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CA 02830405 2013-10-21
37
section) should have no more than 50 metres of contact with the
reservoir.
(3) Segregate Oxygen and steam injectants, as much as possible
= Condensed steam (hot water) and oxygen are very corrosive to
carbon steel.
= To minimize corrosion, either 1) oxygen 26 and steam 6 are
injected separately (Figures 36, 26); 2) comingled steam 6 and
oxygen 26 have limited exposure to a section of pipe that can be a
corrosion resistant alloy; 3) the section integrity is not critical to
the process (Figure 31(b); or 4) the entire injection string is a
corrosion resistant alloy (Figure 31(a)).
(4) The vent gas well (or site) is near the top of the reservoir, far from
the
oxygen injection site.
= Because of steam movement and condensation, non-condensable
gas concentrates near the top of the gas chamber.
= The vent gas well should be far from the oxygen injector to allow
time/space for combustion.
(5) Vent gas should not be produced with significant oxygen content
= To mitigate explosions and to foster good oxygen utilization, any
vent gas production with oxygen content greater than 5% (v/v)
should be shut in.
(6) Attain/retain a minimum amount of steam in the reservoir
= Steam is added/injected with oxygen in SAGDOX because steam
helps combustion. It preheats the reservoir so ignition, for HTO,
can be spontaneous. It adds OH- and H+ radicals the combustion
zone to improve and stabilize combustion (Figures 56 and 38,
Moore (1994)). This is also confirmed by the operation of
smokeless flares, where steam is added to improve combustion and
reduce smoke (Stone (2012), EPA (2012), Shore (1996)). The
process to gasify fuel also adds steam to the partial combustor to
minimize soot production (Berkowitz (1997)).
CA 02830405 2013-10-21
38
= Steam also condenses and produces water that "covers" the
horizontal production well and isolates it from gas or steam
intrusion.
= Steam condensate adds water to the production well to improve
flow performance ¨ water/bitumen emulsions ¨ compared to
bitumen alone.
= Steam is also a superior heat transfer agent in the reservoir. When
one compares hot combustion gases (mostly CO2) to steam, the
heat transfer advantages of steam are evident. For example, if one
has a hot gas chamber at about 200 C at the edges, the heat
available from cooling combustion gases from 500 C to 200 C is
about 16 BTU/SCF. The same volume of saturated steam contains
39 BTU/SCF of latent heat ¨ more than twice the energy content of
combustion gases. In addition, when hot combustion gases cool,
they become effective insulators impeding further heat transfer.
When steam condenses to deliver latent heat, it creates a transient
low-pressure that draws in more steam-a heat pump, without the
plumbing. The kinetics also favour steam/water. The heat
conductivity of combustion gas is about 0.31 (mW/cmK)
compared to the heat conductivity of water of about 6.8
(mW/cmK) ¨ a factor of 20 higher. As a result of these factors,
combustion (without steam) has issues of slow heat transfer and
poor lateral growth. These issues may be mitigated by steam
injection.
= Since one can't measure the amount of steam in the reservoir,
SAGDOX sets a steam minimum by a maximum oxygen/steam
(v/v) ratio of 1.0 or alternately 50% (v/v) oxygen in the steam and
oxygen mix.
(7) Attain (or exceed) a minimum oxygen injection
= Below about 5% (v/v) oxygen in the steam and oxygen mix, the
combustion swept zone is small and the cost advantages of oxygen
CA 02830405 2013-10-21
39
are minimal. At this level, only about a third of the energy injected
is due to combustion.
(8) Maximum oxygen injection
= Within the constraints of (6) and (7) above, because per unit
energy oxygen is less costly than steam, the lowest-cost option to
produce bitumen is to maximize oxygen/steam ratios.
(9) Use preferred SAGDOX geometrics
= 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 39 a-c).
= 39b (THSAGDOX) and 39c (SWSAGDOX) are most preferred for
thinner pay resources, with only one horizontal well required.
Compared to SAGD, THSAGDOX and SWSAGDOX have a
reduced well count and lower drilling costs. Also, internal tubulars
and packers should be usable for multiple applications.
(10) Control/operate SAGDOX by:
(i) Sub-cool control on fluid production rates where produced fluid
temperature is compared to saturated steam temperature at reservoir
pressure. This assumes that gases, immediately above the liquid/gas
interface, are predominantly steam.
(ii) Adjust oxygen/steam ratios (v/v) to meet a target ratio, subject to a
range limit of 0.05 to 1.00
(iii) Adjust vent gas removal rates so that the gases are predominantly
non-condensable gases, oxygen content is less than 5.0% (v/v), and to
attain/maintain pressure targets.
(iv) Adjust steam and oxygen injection rates (subject to (ii) above),
along with (iii) above, to attain/maintain pressure targets.
CA 02830405 2013-10-21
THSAGDOX
Although SAGDOX may also be used for thin pay bitumen recovery, the twin
horizontal
wells (Figure 36) are difficult to fit within the thin pay resource limits,
the well count is
increased compared to SAGD and the capital expenses are also increased.
THSAGDOX (Toe-to-Heel SAGDOX) is a preferred version of SAGDOX that can be
applicable to thin pay EOR, using a mixture of steam 6 and oxygen 26 to supply
energy
rather than steam alone. The horizontal liquid-production well of SAGDOX (and
SAGD)
is retained so that bitumen drainage can be accomplished in short path
lengths. Steam is
much more mobile than heated bitumen, so the horizontal steam injection of
SAGDOX or
SAGD is replaced by a vertical well injecting steam 6 and oxygen 26, where
oxygen 26 is
preferably injected near the top of the pay zone. Vent gas 22 (non-condensable
combustion gas) is removed either through a separate vertical well or wells,
or in a
segregated portion (annulus) near the vertical section of the horizontal
production well.
Vent gas 22 removal is preferably conducted near the top of the net pay zone.
The vertical oxygen/steam injector well is designed to 1) segregate steam 6
and oxygen
26 to minimize corrosion and 2) preferably inject oxygen 26 proximate the top
of the pay
zone and steam 6 proximate the lower region in the pay zone. This has the
added benefit
that oxygen gas 6 in the annulus, around a steam injector tubing, is a good
heat insulator
and this will prevent/minimize heat losses from steam to the overburden, as
steam is
conveyed from the well head to the reservoir.
Figures 26, 27, 28, 40, and 57 show schematics for various THSAGDOX process
schemes. Figure 29 shows a piping schematic that can apply to all of these
process types.
The process is started by circulating steam 6 in the production horizontal
well and by
cycling steam 6 (huff-and-puff) in the vertical wells until the wells
communicate with
each other (i.e. fluids flow from one well to another). After communication is
established, wells are converted to THSAGDOX operation with steam 6 and oxygen
26
injection and water/bitumen 8 and vent gas 22 production.
CA 02830405 2013-10-21
41
The THSAGDOX horizontal production well may be longer than a SAGD well for the
same bitumen productivity, because there is less water flowing in the well.
Figures 40,
41, and 57 show multiple vertical well versions of THSAGDOX to facilitate
longer
horizontal wells or easier start-up and operation of shorter wells. Separate
vertical wells
close to the toe steam/oxygen injector wells are initially used to vent gas
removal wells
and subsequently, converted to steam/oxygen injectors as the combustion front
moves
from near the toe of the horizontal well toward the heal of the horizontal
well (Figure 42).
This enables fast start-up and improved conformance during the maturation of
the
process.
Another version of this scheme starts the combustion near the mid point of the
horizontal
well, with the combustion front moving both toward the toe and heel of the
horizontal
production well (Figure 41).
Feature of these THSAGDOX process schemes include the following:
= Separation is retained between 02 injection and vent gas removal.
Vent gas wells may be used to control conformance of the ISC
process part of THSAGDOX.
= The process adds a 3D component mechanism (flooding) with
longitudinal reservoir flows forced by the geometry.
= The process may reduce the capital cost of wells by reducing well
count, reducing well length, using vertical rather than horizontal
wells, or by reducing the size (diameter) of wells.
= The process reduces operating costs. Oxygen is less costly than
steam per unit energy delivered to the reservoir.
= The process may use a tapered oxygen strategy, where oxygen
concentration is increased during the life of the projects to reduce
costs, extend useful project life and increase bitumen recovery.
= The process may use a pump, in the horizontal well, if necessary to
help produce bitumen and water.
CA 02830405 2013-10-21
42
= The process will produce extra water compared to steam injection.
Connate water will be vaporized in the combustion swept zone
(Figure 35). Water is also produced as a product of combustion.
Depending on leakage or retention rates in the reservoir,
THSAGDOX will likely produce more water than it injects as
steam.
= Hot combustion gases will reflux some water to maintain a good
water/steam inventory in the reservoir.
= The process also retains all of the SAGDOX benefits.
= Carbon dioxide produced as a combustion product is concentrated
in vent gas (or dissolved/concentrated in liquid product stream)
and should be suitable for sequestration.
= Oxygen may be economically pipelined from a distant site without
energy losses.
= Water produced from steam injection may help isolate the
horizontal production well and minimize non-condensable gas
intrusion into this well.
= The vertical well used for oxygen and steam injection may
minimize heat losses if steam is in the inner tube and oxygen is in
the annulus. Oxygen gas is a good insulator to retain heat in the
steam. It is preferable that steam injection is in the central tube and
oxygen surrounds steam as an insulator (Figure 29).
It may be suggested that conversion of THSAGDOX to a pure combustion (ISC) EOR
process is appropriate particularly for this reason because oxygen is less
costly than
steam as a source of energy to heat up reservoir bitumen. But, retention of
steam as
injectant is desirable because:
= Steam stabilizes combustion and improves combustion kinetics
= Steam preheats combustion zones
= Steam acts as a good heat transfer medium ¨ better than hot
combustion gases (heat pump effect)
CA 02830405 2013-10-21
43
= Steam can effect lateral growth (a problem with some ISC
processes)
= Steam, when condensed, can help cover/seal the production well
and inhibit non-condensable gas break through to the well
= Steam/water can be refluxed by hot combustion products
= In the production well, water/bitumen mixtures have lower
viscosities than bitumen by itself.
= Steam injection increases the size of the steam-swept zone to help
ensure that combustion is focussed on residual bitumen (coke)
= Steam creates flow paths for combustion.
It may also be suggested that water injection, not steam, is a better way to
produce steam
in the reservoir and improve energy efficiency. Water may scavenge heat from
the
combustion swept zone (Figure 35) to produce steam in situ, rather than using
fuel on the
surface to produce steam in a boiler. This was the preferred way to accomplish
wet
combustion using vertical injector/producer wells (Figure 43). But, this is
not a good idea
using Steam Flood with Oxygen in Thin Pay Reservoirs (SFOXT) geometries for
the
following reasons:
= In SAGDOX geometry compared to ISC geometry (Figure 43),
flow paths from injector to producer are very short. If water were
injected, using a vertical injector (Figure 29) it would easily by-
pass the process and flow directly to the production well.
= Alternately if the combustion front is close to the injector, water
could quench combustion and cause low temperature oxidation
(LTO) to start.
It may be suggested that because the hot zone in THSAGDOX is localized to the
oxygen
26 injection zone and then proceeds toward the toe of the horizontal well
(Figure 42), that
the bitumen production rate for THSAGDOX can be expected to be less than SAGD,
where the steam chamber grows along the length of the horizontal producer at
the same
time (Figure 2). THSAGDOX compensates for this by producing heat at a higher
CA 02830405 2013-10-21
44
temperature than steam, by using steam 6 as a heat transfer agent and by
refluxing some
steam. This may also be improved by using multiple oxygen 26 injection sites
(Figure 44)
so that combustion can be spread out along the well and multiple combustion
sites will
grow simultaneously.
Because there is less fluid in a THSAGDOX horizontal well compared to a SAGD
horizontal well due to less water produced per barrel of bitumen, for the same
pressure
drop a THSAGDOX horizontal well can be much longer than a same-size SAGD
horizontal well (up to about 2500 metres), depending on the oxygen level in
the injectant
gases.
SWSAGDOX
THSAGDOX is better than SAGD for thin pay bitumen EOR because of the reduction
in
well count and cost (1 horizontal + 1 vertical, where the vertical well can be
shared
between patterns) compared to SAGD (2 horizontal wells) and a reduction in
energy
costs by using oxygen gas for combustion. As pay thickness decreases, THSAGDOX
capital expenses may be too much to justify bitumen EOR.
Another version of SAGDOX called SWSAGDOX (Single Well SAGDOX) may cut
costs even more. The process uses a single horizontal well to effect the
SAGDOX
process. Portions of the well are segregated for steam 6 and oxygen 26
injection and for
bitumen/water 8 and vent gas 22 production, using concentric tubing and
segregation
packers 18 (Figure 30 and 31 a-e). Capital expenses are lowered both by
reducing the
well count (to 1) and by potential retrieval and reuse of various completion
components
(packers and tubing).
The simplest version of SWSAGDOX is shown in Figure 31(a), where steam and
oxygen
30 are mixed at surface and injected premixed, rather than relying on mixing
in the
reservoir. To resist corrosion, the injection tubing 30 for the oxygen and
steam mixture
would be an alloy-steel or another corrosion-resistant material. An alternate
scheme, to
obviate corrosion, is to superheat the oxygen + steam mixture 30 to prevent
steam
CA 02830405 2013-10-21
condensation on the injectant tubular walls. Heat losses, particularly for
deep thin pay
bitumen reservoirs, from this mixture may be an issue. The toe of the
horizontal well 40
(Figure 31(a)) is also exposed to oxygen + water corrosion. But, the integrity
of the toe
region of this well is not critical to the EOR process.
An improvement on this design (Figure 31(b)) uses tubing to segregate oxygen
and steam
30, with oxygen 26 surrounding the steam injector tube. The oxygen gas 26 acts
as a
good insulator for the steam tube and reduces heat losses to preserve steam
quality. But,
the toe region of the horizontal well 40 is still exposed to steam + oxygen
corrosion.
Yet another improvement is shown in Figure 31(c) where a packer 18 is used to
segregate
oxygen and steam 30 prior to entering the reservoir. This can minimize toe
corrosion and
still insulate the steam line to reduce heat losses.
Yet another embodiment is to complete the horizontal well using a corrosion
resistant
material, at least for the toe section of the well.
Another issue for SWSAGDOX (Figure 30, 31 a-e) is that steam injection is at
the same
(horizontal) level as liquid petroleum. SAGD prevents steam breakthrough to
the
producer or flooding of the steam injector, by completing the producer
injector with an
offset spacing of about 5 metres (Figure 1) and controlling the process with a
steam/liquid interface between the injector and producer (Figure 8). The
interface is tilted
by the pressure drop in the producer, but with good operation it prevents
steam by-pass
and flooding of the injector. The highest point of the interface is at the toe
of the
horizontal wells.
This sub-cool strategy can be retained by SAGDOX and THSAGDOX by injection of
steam (and oxygen) above the plane of the horizontal production well.
However, in SWSAGDOX (Figure 45), if the steam 6 + oxygen 26 section is flat,
and
one operates the process so that liquid covers the production section to
obviate steam 6 +
CA 02830405 2013-10-21
46
oxygen 26 break through, the end of the horizontal well will be flooded. This
will inhibit
steam 6 + oxygen 26 injection and harm conformance. If one produces liquid at
a faster
rate to remove this problem, the entire production section will be open to
steam 6 and
oxygen 26 breakthrough.
The solution shown at the bottom of Figure 45 and in Figures 25, 32, 33, and
46 is to drill
and complete the horizontal well so the toe section is slanted upwards to near
the top of
the pay zone. This enables one to retain liquid covering the horizontal
production section
so that oxygen 26 and steam 6 don't break through to the producer well and to
have
oxygen 26 and steam 6 injection above the liquid interface 12 so the injection
is not
flooded (Figure 45). The process for such a geometry is termed SWSAGDOX (U)
where
U denotes uplift of the toe region of the horizontal well. This is a preferred
geometry for
SWSAGDOX.
SWSAGDOX process has the advantages of THSAGDOX processes, with the following
additional features:
= The horizontal well interior tubing can be retrieved and reused so
that its cost can be spread amongst several process units.
= This is the least cost option (capital expenses) for thin pay steam +
oxygen EOR
= This is the least well-count option
= The process has longitudinal flows with a drive recovery
mechanism
= The production segment of the well can be isolated by fluid
production if the well is drilled updip or if the toe portion of the
well is drilled upward
= If a pump is necessary, it can be accommodated (e.g. Figure 31(a))
= The design retains separate vent gas removal
= If steam 6 occupies the central injection tube, oxygen gas 26 can
help insulate the steam tube and minimize heat losses (Figures 31
a-e)
CA 02830405 2013-10-21
47
= The SWSAGDOX (U) version of the process allows liquids to
cover the horizontal production section to prevent or inhibit gas
breakthrough (steam, oxygen, combustion gases) and, at the same
time, the gas injection zone (steam + oxygen) is not flooded by the
liquids.
The geometry of SWSAGDOX (Figure 30) is similar to the geometry for the SWSAGD
(Figure 20), but with the following process distinctions:
= SWSAGDOX uses steam + oxygen injection. SWSAGD uses
steam only
= SWSAGD injects steam at the same elevation as production. A
preferred version of SWSAGDOX (Figure 32), injects steam and
oxygen at higher elevation than liquid production.
= SWSAGD has had disappointing field tests.
= SWSAGD was focused on heavy oil EOR, not bitumen.
= SWSAGD was concerned by heat leakage from steam injectors to
produced fluids and spurred development of insulated tubing for
steam injection. SWSAGDOX insulates the steam tubing using
oxygen in the annulus (Figure 31B).
= Because oxygen has about 10 times the energy density as steam,
piping for SWSAGDOX can be much smaller than piping for
SWSAGD.
= SWSAGD is a saturated steam process. Temperatures are limited
by the properties of saturated steam. At the same pressure,
SWSAGDOX will operate at higher T than SWSAGD.
An important issue for SAGDOX and SWSAGDOX is to isolate various zones using
packers that are operable at high temperatures. This is an active area of
development for
oil suppliers (Haliburton, "Zonal Isolation for Steam Injection ..." website,
May 2012)
(Schlumberger, "Packer Systems", website, May 2012). It is also of particular
concern in
CA 02830405 2013-10-21
48
the Geothermal industry, where conditions may be more severe and corrosive
than for
EOR (DOE "Enhanced Geothermal Systems Wel'field Construction Workshop" San
Francisco, Oct 16, 2007). Small, self-sealing packers are also being developed
for smaller
well sizes (OGJ "Self-Setting Thermal Packers Help Cyclic Steam" 1998).
Current technology (-2012) is available for thermal packers for larger pipe
sizes and up
to 600 F (316 C) (Haliburton (2012)) and for small tubing packers up to 400 C
(OGJ
(1998)). The pressure seals are rated for pressures exceeding expectations for
SAGDOX
and SWSAGDOX processes. Most packers are retrievable and can be used many
times.
The small tubing packers have been operated in the field for up to 5000
pressure
cycles/yr. (OGJ (1998)).
Thermal packers for SAGDOX and SWSAGDOX processes are conventional
technology, currently available.
SAGDOX and related processes (THSAGDOX, SWSAGDOX, SWSAGDOX(U)) can
have a higher well count than SAGD, depending on process design. This can be
partially
(or totally) offset by reduced pipe sizes using SAGDOX. Pipe size reductions
are due to 2
factors ¨ oxygen contains about 10 times the energy content compared to steam
(Table
2); also because SAGDOX injects less steam than SAGD for the same energy
injection
rate, the production fluids (water + bitumen) can be less than SAGD fluids for
the same
bitumen production rate.
Assuming the following pipe design criteria for a shallow SAGD project:
(i) 500 bbls/d bitumen productivity.
(ii) 1 MMBTU energy demand per bbl. bitumen (SOR ¨3)
(iii) Steam at 1000 BTU/lb. heat content
(iv) 100 psia, 160 C steam injection (50m depth hydrostatic
pressure (Figure 4))
(v) 25 ft/sec. design for steam injection
(vi) 1 ft/sec. for liquid (water + bitumen) production
(vii) all steam injected is produced as hot water
CA 02830405 2013-10-21
49
One can then calculate for a SAGD project, that steam demand is 500,000 lb/day
=
1428.6 bbls/day = 28.57 CF/sec, at reservoir conditions. Using the design
criteria above,
the steam injector pipe has a diameter of 7.23 inches and production tubing
has a
diameter of 4.79 inches.
Applying this to SAGDOX-related projects for the same conditions, Figure 47
shows
pipeline velocity limits for oxygen delivery design, using carbon steel or
stainless steel
pipes, where potential particulate impingement is the design limit ¨ the worst
case (Asia
Industrial Gases Assoication "Oxygen Pipeline Systems" 2005). One may assume
the
following, in addition to the above:
(i) 100 ft/sec oxygen velocity design, at downhole conditions
(Figure 47)
(ii) Use a SAGDOX (35) mixture, 35% oxygen (v/v) in a steam
oxygen mix; 84.5% of heat injected comes from oxygen
combustion (Table 2)
One can then calculate pipe sizes for oxygen and steam delivered in separate
pipes. The
oxygen demand is 880 MSCFD = 3.36 tonnes/day.
The steam demand drops to 77,500 lbs/day = 221 bbls/day = 4.18 cf/sec, at
reservoir
conditions. The pipe size for oxygen injection is 2.09 inches in diameter. The
pipe size
for steam injection is 2.76 inches in diameter.
If the steam and oxygen are conveyed in a single pipe (Figures 26, 27, 29),
the total pipe
size needed is 3.47 inches (ignoring wall thickness).
The production well is also downsized, because less steam is injected and
water
produced. The calculated well size is 2.93 inches, in diameter.
CA 02830405 2013-10-21
SAGDOX-related processes also must produce vent gases. The vent gas volumes
are
similar to the oxygen injection volumes, with the same size pipe requirements
(2.09
inches, in diameter)
It is often assumed, for pipelines, that capital expense is proportional to
pipe diameters or
to cumulative pipe diameters for multiple piping. One can do the same here, as
follows:
total D
inches
SAGD (eg. Fig. 1) 12.02 100
SAGDOX with separate wells for 9.87 82
all streams (e.g. Fig 36)
SWSAGDOX with all fluids 5.00 42
contained in a single well. (Single
well D only, eg. Fig 30, 31)
The SAGDOX versions all have less total pipe diameter. All SWSAGDOX pipes
could
be retained in a single 5" pipe (not accounting for pipe wall thickness).
The preferred embodiments of THSAGDOX and SWSAGDOX of the present invention
depend on the nature of the target reservoir ¨ specifically the reservoir
thickness, the
reservoir continuity, the reservoir quality and the reservoir depth. The
preferred version
for SWSAGDOX is SWSAGDOX(U) with the up-lifted toe region.
There are 3 versions of THSAGDOX to consider:
(i) The simple version (Figure 26) with a single vertical
injector
well for oxygen 26 and steam 6 completed near the toe of the
horizontal producer and vent gas 22 removal accomplished
using a segregated portion of the horizontal well completed
near the top of the pay zone. The piping/tubing is simple with
CA 02830405 2013-10-21
51
oxygen 26 delivered in the annulus to insulate the steam tube
and to minimize heat losses. The production well, with vent
gas 22 removal retains the option to use submersible pumps
if necessary (Figure 29). This system can best be applied for
deposits (10 to 25 metre thickness), preferably segregated
from said reservoir, relatively unimpaired reservoirs (little/no
shales, lean zones), and for moderate continuity (well lengths
500-1000 metres).
(ii) If a similar more extensive and unimpaired reservoir is
present, one can have adjacent patterns and the patterns can
share vertical wells, a scheme such as Figure 36 can share
separate vent wells. This is not too costly and offers the
prospect of conformance control using the separate vent
wells. Another version, show in Figure 48, allows for sharing
of vertical injection wells, to reduce costs.
(iii) If a similar deposit (10 to 25 metre thickness) is present but
we expect some reservoir impairments, resulting in lower
productivity expectations, it is preferred to consider longer
horizontal wells with multiple injection/vent wells, where the
injection/vent wells can be converted from injection to vent
uses (and vice versa) depending on performance (Figures 40,
41, 57). This gives added flexibility for conformance control
and performance control and production management in
cases where the reservoir is impaired or may be impaired.
Productivity need not suffer because we can use multiple
injectors simultaneously (Figure 44) and drill longer
horizontal wells than SAGD (500-2500 metres).
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Because of reduced well count and reusable completion components (tubing,
packers),
the thinnest reservoirs (5-15 metres) are best exploited using SWSAGDOX(U)
process
shown in Figures 30, 31 a-e, 32, 33, 49. The process doesn't lend itself to
well sharing
(no vertical wells), but the capital expenses should be minimized.
One also has the choice for THSAGDOX, where one draws down liquids from the
horizontal well. The conventional choice draws liquids from the heel region of
the
horizontal producer. But, one can also draw from the toe using a pipe extender
(Figure
29). The advantage of toe down is illustrated in Figure 50. One can prevent
the steam
injector portion of the vertical injector well from being flooded by the
liquid interface.
(1) Distinctions of THSAGDOX compared to THAI (Figure 53)
= THSAGDOX removes vent gases using separate wells or segregated zones.
THAI
forces vent gases to be produced in the horizontal production well.
= THSAGDOX operates on a gravity drainage process. Pressure differentials
between gas injection and liquid product are very small. THAI operates as a
flood
(gas drive) process with significant pressure differentials between
injection/production wells.
= THSAGDOX injects steam to improve combustion, and to cover the production
well with liquid to inhibit gas breakthrough. THAI makes no attempt to add
steam
or to cover the production well. Gas breakthrough is essential to the THAI
process.
= THSAGDOX injects steam and oxygen as sources of energy in the reservoir.
THAI injects compressed air.
= THSAGDOX covers the production well and injects oxygen at a high spot to
prevent oxygen breakthrough to the production well. THAI relies on a moving
coke blockage formed upstream of the combustion front in the horizontal
producer to prevent air (oxygen) breakthrough.
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= THSAGDOX injects water (and refluxes) steam to encourage/stimulate
lateral
growth of the heated zone. THAI relies on hot combustion gases/heat conduction
for lateral growth.
= THAI has had a disappointing field test history.
= THAI is (now) focussed on heavy oil EOR. THSAGDOX is focused on bitumen
EOR.
= THSAGDOX can use sub-cool control on the production well to ensure there
is
no gas or steam breakthrough to be produced.
(2) Distinction between SWSAGDOX (Figures 17, 31, 31(a)) and SWSAGD (Figure
20)
= SWSAGDOX uses a mixture of oxygen and steam to deliver energy to the
reservoir. SWSAGD uses steam only.
= SWSAGDOX has a version (SWSAGDOX(U)) (Figures 32, 33, 45) where the toe
of the horizontal well is drilled upward to segregate liquid production and
steam/oxygen injection. SWSAGD has a flat horizontal well completion, where
liquid flow to the producer can flood the steam injector (Figure 20 & 52)
= Both SWSAGDOX and SWSAGD operate as gravity drainage processes. But due
to the combustion component, the average T of the gas chamber for SWSAGDOX
is higher than saturated steam T for SWSAGD.
= SWSAGD has a disappointed history of field tests.
= The combustion gases from SWSAGDOX migrate to the ceiling area of the gas
chamber (Figure 42) and help insulate the interface to reduce heat losses.
= SWSAGD was focussed on thin pay heavy oil EOR. SWSAGDOX is focused on
thin pay bitumen EOR.
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(3) Distinctions of THSAGDOX (Figure 18) and/or SWSAGDOX (Figure 30, 32)
compared to SAGD (Figure 1)
= SAGD uses 2 parallel horizontal wells. THSAGDOX and SWSAGDOX use only
one horizontal well.
= SAGD is a 2D process ¨ no longitudinal steam/liquid flows in the
longitudinal
direction for a homogeneous reservoir. THSAGDOX and SWSAGDOX are both
3D processes ¨ the GD chamber (the gas and steam swept zones) grow in a
longitudinal direction (Figure 28).
= SAGD uses saturated steam. THSAGDOX and SWSAGDOX inject mixtures of
steam and oxygen (separately or together).
= SAGD temperatures are limited to saturated steam T. The combustion
component
of THSAGDOX and SWSAGDOX produces heat in the reservoir at much higher
T (600 C vs 200 C).
= SAGD steam cannot vaporize water in the reservoir (connate water, water
in lean
zones...). THSAGDOX and SWSAGDOX can vaporize reservoir water.
= SAGD steam is used in a once-through process. THSAGDOX and SWSAGDOX
can reflux water/steam.
= SAGD doesn't substantially produce any connate water. THSAGDOX and
SWSAGDOX produce connate water from the combustion-swept zone.
= Energy costs for SAGD (saturated steam) are significantly higher than
energy
costs for THSAGDOX and SWSAGDOX.
= SAGD is a net user of water (produced water recycle <100%). For higher
oxygen
levels (>9%), THSAGDOX and SWSAGDOX is higher than for SAGD.
= SAGD has been successfully field tested. THSAGDOX and SWSAGDOX are in
the development phase.
= SWSAGDOX and THSAGDOX are designed to focus on this-pay bitumen (e.g.
<25 metres thickness). SAGD focuses on thicker pays (>15m)
= SWSAGDOX and THSAGDOX can recover bitumen from the steam swept zone.
SAGD leaves significant residual bitumen behind the steam swept zone.
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= Ultimate recovery for THSAGDOX will exceed SAGD recovery, because
THSAGDOX recovers bitumen from the steam-swept zone and THSAGDOX can
continue production to higher ETOR values because energy costs are less.
= SAGD is diluted with N2. THSAGDOX vent gas is mostly CO2, suitable for
sequestration.
(4) Distinctions of THSAGDOX (Figure 26) compared to COSH/COGD (Figure 231
= COSH has 3 horizontal wells + 3 (or more) vertical wells per patter
(Figure 23).
THSAGDOX has a single horizontal well and single vertical well.
= COSH relies on lateral horizontal vent wells to stimulate lateral growth.
THSAGDOX relies on steam to stimulate lateral growth.
= COSH has multiple vertical air injectors. THSAGDOX has a single
oxygen/team
injector.
= COSH uses compressed air as oxidant. THSAGDOX uses oxygen gas.
= Neither COSH nor THSAGDOX have been field tested.
= COSH vent gas is primarily CO2 diluted with N2. THSAGDOX vent gas is
undiluted CO2.
(5) Unique features of THSAGDOX:
= co-injection of steam and oxygen
= range of 02/steam (v/v) ratios
= synergy between 02/steam
= focus on bitumen reservoirs (<25 metres thickness, preferably 10-25
metres
thickness)
= multiple well versions (Figures 48, 40, 41, 57) for longer horizontal
wells
= multiple combustion zone versions (Figure 44)
= oxygen insulation for team injection lines
= tapered oxygen strategy ¨ increase oxygen as project matures
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= focus on oxygen not air
= TH geometry with multiple injectants, products.
(6) Unique features of SWSAGDOX:
= single well process, 2 injectants, 2 products
= features as above (5), (except for multiple well cases)
= focus on thin reservoirs
= updip completion versions (Figure 49)
= uplift toe versions (Figure 30, 31), SWSAGDOX(U)
= oxygen insulation for steam injection lines
= focus on bitumen reservoirs, preferably thin reservoirs (e.g. <25 metres,
more
preferably <15 metres)
= SW geometry with multiple injectants, products
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Table 1
Alberta Bitumen Deposits
(109 bbls)
Athabasca Cold Lake Peace River Total
Accessible Deposits
(known technology)
SAGD/CSS 420 51 54 526
Mining 59 0 0 59
Cold Production 13 138 0 151
subtotal 492 189 54 736
Unaccessible Deposits
(no known technology)
Carbonates 383 0 65 448
Thin Pays 380 21 8 410
No cap rock 37 0 0 37
Too deep for mining but too shallow 28 0 0 28
for SAGD
Top gas 14 0 0 14
Others 36 -10 1 27
subtotal 811 11 74 962
Grand total 1369 201 129 1699
I. Source - Heidrick and Godin (2006)
2. Thin Pay (cut off= 10m)
3. Numbers may not be additive due to rounding
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Table 2
SAGDOX Injection Gases
SAGD SAGDOX SAGDOX SAGDOX SAGDOX SAGDOX
(5) (9) (35) (50)
(75)
% (v/v) oxygen 0 5 9 35 50 75
% heat from 02 0 34.8 50.0 84.5 91.0 96.8
BTU/SCF mix 47.4 69.0 86.3 198.8 263.7 371.9
MSCF/MMBTU 21.1 14.5 11.6 5.0 3.8 2.7
MSCF 0.0 0.7 1.0 1.8 1.9 20
02/MMBTU
MSCF 21.1 138 10.6 3.3 1.9 0.7
Steam/MMBTU
Where:
(I) Steam heat value = 1000 BTU/lb
(2) 02 heat/combustion value = 480 BTU/SCF 02
(3) SAGD = pure steam
(4) SAGDOX (9) =9% (v/v) oxygen in steam-oxygen mixture
As many changes therefore may be made to the embodiments of the invention
without
departing from the scope thereof. It is considered that all matter contained
herein be
considered illustrative of the invention and not in a limiting sense.
