U.S. patent application number 14/099472 was filed with the patent office on 2014-06-19 for extended reach steam assisted gravity drainage with oxygen ("ersagdox").
This patent application is currently assigned to NEXEN ENERGY ULC. The applicant listed for this patent is Richard Kelso Kerr. Invention is credited to Richard Kelso Kerr.
Application Number | 20140166279 14/099472 |
Document ID | / |
Family ID | 50929600 |
Filed Date | 2014-06-19 |
United States Patent
Application |
20140166279 |
Kind Code |
A1 |
Kerr; Richard Kelso |
June 19, 2014 |
EXTENDED REACH STEAM ASSISTED GRAVITY DRAINAGE WITH OXYGEN
("ERSAGDOX")
Abstract
A process to recover hydrocarbons from a reservoir, where the
hydrocarbons have an initial viscosity greater than 100,000 cp,
preferably greater than 1,000 cp, the process including: (a)
Initially injecting oxygen into the reservoir; (b) Allowing for
combustion of the oxygen to vaporize connate water in the
hydrocarbon reservoir; (c) Collecting hydrocarbons in a
substantially horizontal production well in the reservoir and where
the substantially horizontal production well has a length greater
than about 800 metres.
Inventors: |
Kerr; Richard Kelso;
(Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Kerr; Richard Kelso |
Calgary |
|
CA |
|
|
Assignee: |
NEXEN ENERGY ULC
Calgary
CA
|
Family ID: |
50929600 |
Appl. No.: |
14/099472 |
Filed: |
December 6, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13543012 |
Jul 6, 2012 |
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14099472 |
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13628164 |
Sep 27, 2012 |
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13543012 |
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61734626 |
Dec 7, 2012 |
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61507196 |
Jul 13, 2011 |
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61549770 |
Oct 21, 2011 |
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Current U.S.
Class: |
166/261 ;
166/256; 166/52 |
Current CPC
Class: |
E21B 43/2408
20130101 |
Class at
Publication: |
166/261 ;
166/256; 166/52 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 43/243 20060101 E21B043/243 |
Claims
1. A process to recover hydrocarbons from a reservoir, where said
hydrocarbons have an initial viscosity greater than 100,000 cp,
said process comprising: (a) Initially injecting oxygen into said
reservoir; (b) Allowing for combustion of said oxygen to vaporize
connate water in said hydrocarbon reservoir; (c) Collecting
hydrocarbons in a substantially horizontal production well in said
reservoir and where said substantially horizontal production well
has a length greater than about 800 metres.
2. A process according to claim 1 further comprising initial steam
injection into the reservoir then terminating said steam
injection.
3. A process according to claim 2 where the ratio of oxygen to
steam injected is controlled in the range from 0.05 to 1.00
(v/v).
4. A steam assisted gravity drainage with oxygen system for
recovery of hydrocarbons from a reservoir, where said hydrocarbons
have an initial viscosity greater than 100,000 cp, said system
comprising: (a) A first well for capturing said hydrocarbons,
having a toe and a heel and a length greater than about 800 metres,
said first well being substantially horizontal and at a first
depth; (b) A second well within said hydrocarbon containing
reservoir, having a length greater than about 800 metres, for
injection of oxygen into said hydrocarbon containing reservoir,
being at second depth said second depth shallower than said first
depth; (c) Said second well being located proximate said toe of
said first well; and (d) A vent gas means for venting any gas
produced in said reservoir.
5. A system according to claim 4 where said vent gas means is
single or multiple vertical wells.
6. A system according to claim 4 where said vent gas means is a
segregated annulus section in the heel rise section of the
substantially horizontal well.
7. A steam assisted gravity drainage with oxygen system for
recovery of hydrocarbons from a reservoir, where said hydrocarbons
have an initial viscosity greater than 100,000 cp, said system
comprising: (a) A first well, having a toe and a heel and a length
greater than about 800 metres, said first well within said
hydrocarbon containing reservoir, for capturing said hydrocarbons;
(b) A second well within said hydrocarbon containing reservoir,
having a length greater than about 800 metres, for injection of
oxygen and steam into said hydrocarbon containing reservoir; (c)
Said second well being located proximate said toe of said first
well; and (d) At least one vent gas means for venting any gas
produced in said reservoir.
8. A system according to claim 7 where said at least one vent gas
means is single or multiple vertical wells.
9. A system according to claim 7 where said at least one vent gas
means is a segregated annulus section in the heel rise section of
the substantially horizontal well.
10. A system according to claim 7 where said second well is single
or multiple vertical wells used for said injection of oxygen and
steam.
11. A system according to claim 10 where said steam and oxygen are
comingled on the surface prior to injection.
12. A system according to claim 10 where said steam and oxygen are
segregated using packers and injected separately into said single
or multiple vertical wells.
13. A system according to claim 12 where said steam and oxygen are
segregated using concentric tubing and packers, with steam in the
central tubing surrounded by oxygen in the adjacent annulus, with
said oxygen injected at a higher elevation in the reservoir than
said steam.
14. A steam assisted gravity drainage with oxygen system for
recovery of hydrocarbons for a reservoir, where said hydrocarbons
have an initial viscosity greater than 100,000 cp, said system
comprising: (a) A substantially horizontal well, having a toe and a
heel and a length greater than 800 metres, said well being located
within said hydrocarbon containing reservoir; wherein said well
further comprises: (b) At least one oxygen injection site proximate
said toe, for injecting oxygen into said reservoir; (c) A
hydrocarbon recovery site for recovery of said hydrocarbons from
said reservoir; and (d) At least one vent gas site for venting any
gas produced in said reservoir.
15. A system according to claim 14 where said oxygen injection site
is a segregated toe section of said substantially horizontal
well.
16. A steam assisted gravity drainage with oxygen system for
recovery of hydrocarbons for a reservoir, where said hydrocarbons
have an initial viscosity greater than 100,000 cp, said system
comprising: (a) A substantially horizontal well, having a toe and a
heel and a length greater than 800 metres, said well being located
within said hydrocarbon containing reservoir; wherein said well
further comprises: (b) At least one oxygen injection site proximate
said toe, for injecting oxygen into said reservoir; (c) At least
one steam injection site, for injecting steam into said reservoir;
(d) A hydrocarbon recovery site for recovery of said hydrocarbons
from said reservoir; and (e) At least one vent gas site for venting
any gas produced in said reservoir.
17. A system according to claim 16 where said oxygen and steam
injection site is a segregated toe section of said substantially
horizontal well.
18. The process according to claim 1 wherein said hydrocarbons have
an initial viscosity range greater than 1,000 cp.
19. The system according to claim 4 wherein said hydrocarbons have
an initial viscosity range greater than 1,000 cp.
20. The system according to claim 7 wherein said hydrocarbons have
an initial viscosity range greater than 1,000 cp.
Description
BACKGROUND OF THE INVENTION
[0001] The bitumen resources in Alberta, Canada, are one of the
world's largest liquid hydrocarbon deposits. The total resource
that can potentially be exploited by thermal enhanced oil recovery
("EOR") is about 1.4 trillion bbls. About 40% of this resource can
be exploited using existing developed technology, such as Steam
Assisted Gravity Drainage ("SAGD") or Cyclic Steam Stimulation
("CSS"). But the remaining 60% cannot be exploited using known
technology. Table 1 shows two other resources that could
potentially be developed and exploited using thermal EOR--carbonate
bitumen at 448 billion bbls and thin-pay bitumen at 410 billion
bbls.
[0002] 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.
[0003] 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.
[0004] FIGS. 1A and 1B (Prior Art) show the traditional SAGD
geometry, using twin, parallel, horizontal wells 2,4 drilled in the
same vertical plane, with a 5 metre spacing between the upper 2 and
lower 4 wells, each well being about 800 metres long, and with the
lower well 1 to 2 metres above the (horizontal) reservoir floor.
Circulating steam 6 in both wells starts the SAGD process. After
communication is established, the upper well 2 is used to inject
steam 6 and the lower well 4 produces hot water and hot bitumen 8.
Liquid production is accomplished by natural lift, gas lift, or
submersible pump.
[0005] 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.
[0006] FIGS. 2A-2D (Prior Art) show how SAGD matures. A young steam
chamber 10 has bitumen drainage from steep chamber sides and from
the chamber ceiling. When the chamber growth hits the top of the
reservoir, ceiling drainage stops, bitumen productivity peaks and
the slope of the side walls decreases as lateral growth continues.
Heat losses increase (steam to oil ratio ("SOR") increases) as
ceiling contact increases and the surface area of the steam chamber
increases. Drainage rates slow down as the side wall angle
decreases. Eventually, the economic limit is reached and the
end-of-life drainage angle is small (10-20.degree.), as shown in
FIG. 2.
[0007] Produced fluids are near saturated steam temperature, so it
is only the latent heat of steam that contributes to the process in
the reservoir. But, some of the sensible heat can be captured from
surface heat exchangers (a greater fraction at higher
temperatures), so a useful rule-of-thumb for net heat contribution
of steam is 1000 BTU/lb. for the pressure ("P") and temperature
("T") range of most SAGD projects, as best seen in FIG. 3 (Prior
Art).
[0008] The operational performance of SAGD may be characterized by
measurement of the following parameters: saturated steam pressure
("P") and temperature ("T") in the steam chamber, as best seen in
FIG. 4 (Prior Art); bitumen productivity; SOR, usually at the well
head; sub-cool--the T difference between saturated steam and
produced fluids; and WRR--the ratio of produced water to steam
injected (also known as the water recycle ratio).
[0009] 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.degree. C. is meant to ensure no live steam breaks through to
the production well. Process pressure and temperature are linked
(FIG. 4) and relate mostly to bitumen productivity and process
efficiency. Bitumen viscosity is a strong function of temperature,
as best seen in FIG. 5 (Prior Art). SAGD productivity is
proportional to the square root of the inverse viscosity, as seen
in FIG. 6 (Prior Art) (Butler (1991)). But, conversely if P (and T)
is increased, the latent heat content of steam drops rapidly (FIG.
3) and more energy is used to heat the rock matrix as well as lost
to the overburden or other non-productive areas. Increased pressure
increases bitumen productivity but harms process efficiency
(increases SOR). Because economic returns can be dominated by
bitumen productivity, the SAGD operator typically opts to target
operating pressures higher than native, hydrostatic reservoir
pressures.
[0010] Despite becoming the dominant thermal EOR process, SAGD has
some limitations and detractions. A good SAGD project includes:
[0011] a horizontal well is completed near the bottom of the pay
zone to effectively collect and produce hot draining fluids; [0012]
injected steam, at the sand face, has a high quality; [0013]
process start up is effective and expedient; [0014] the steam
chamber grows smoothly and is contained; [0015] the reservoir
matrix is good quality (porosity .PHI.>0.2, initial oil
saturation S.sub.io>0.6, vertical permeability k.sub.v>2D);
[0016] net pay is sufficient (>15 metres); [0017] proper design
and control to simultaneously prevent steam breakthrough, prevent
injector flooding, stimulate steam chamber growth to productive
zones and inhibit water inflows to the steam chamber; and [0018]
absence of significant reservoir baffles (e.g. lean zones) or
barriers (e.g. shale).
[0019] If these characteristics are not attained or other
limitations are experienced, SAGD may be impaired, as follows:
[0020] (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. [0021] (2) The SAGD steam-swept
zone has significant residual bitumen content that is not
recovered, particularly for heavier bitumens and low-pressure steam
as best seen in FIG. 7 (Prior Art). For example with a 20% residual
bitumen (pore saturation) and a 70% initial saturation, the
recovery factor is only 71%, not including stranded bitumen below
the production well or in the wedge zone between recovery patterns.
[0022] (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. [0023] (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. [0024] (5) The existence of
an active water zone--either top water, bottom water, or an
interspersed lean zone within the pay zone--can cause operations
difficulties for SAGD or ultimately can cause project failures
(Nexen Inc., `Second Quarter Results", Aug. 4, 2011) (Vanderklippe,
N., "Long Lake Project Hits Sticky Patch", CTV, 2011). Simulation
studies concluded that increasing production well stand-off
distances may optimize SAGD performance with active bottom waters,
including good pressure control to minimize water influx (Akram,
F., "Reservoir Simulation Optimizes SAGD, American Oil and Gas
Reporter, September 2011). [0025] (6) Pressure targets cannot
(always) be increased to improve SAGD productivity and SAGD
economics. If the reservoir is "leaky", as pressure is increased
beyond native hydrostatic pressures, the SAGD process can lose
water or steam to zones outside the SAGD steam chamber. If liquids
are lost, the WRR decreases and the process requires significant
water make-up volumes. If steam is also lost, process efficiency
drops and SOR increases. Ultimately, if pressures are too high, if
the reservoir is shallow and if the high pressure is retained for
too long, a surface break through of steam, sand and water can
occur (Roche, P., "Beyond Steam", New Tech. Mag., September 2011).
[0026] (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. [0027] (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. [0028] (9) SAGD
process efficiency is "poor" and CO.sub.2 emissions are
significant. If SAGD efficiency is defined as [(bitumen
energy)-(surface energy used)]/(bitumen energy) and bitumen
energy=6 MMBTU/bbl; energy used at sand face=1 MMBTU/bbl bitumen
(SOR .about.3); steam is produced in a gas-fired boiler at 85%
efficiency; there are heat losses of 10% each in distribution to
the well head and delivery from the well head to the sand face;
usable steam energy is 1000 BTU/lb (FIG. 3) and boiler fuel is
methane at 1000 BTU/SCF; then the SAGD process efficiency=75.5% and
CO.sub.2 emissions=0.077 tonnes/bbl bitumen. [0029] (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). [0030] (11) Lastly, there is a "natural"
hydraulic limit that restricts well lengths or well diameters and
can override pressure targets for SAGD operations. FIGS. 8A and 8B
show what can and has happened. In SAGD, a steam/liquid interface
12 is formed. For a good SAGD operation, with sub-cool control, the
interface is between the injector 2 and producer 4 wells. The
interface is tilted because of the pressure drop in the production
well 4 due to fluid flow. There is little/no pressure differential
in the steam/gas chamber. If the liquid production rates are too
high (or if the production well 4 is too small) the interface can
be tilted so that the toe of the steam injector 14 is flooded
and/or the heel of the producer 16 is exposed to steam breakthrough
(FIGS. 8A and 8B). This limitation can occur when the pressure drop
in the production well 4 exceeds the hydrostatic head between steam
injector 2 and liquids producer 4 (about 8 psi (50 kPa) for a 5
metre spacing).
[0031] The simple SAGD control strategy (to inject steam to meet a
pressure target and produce liquids to meet a sub-cool target) may
be overridden if the system is constrained by hydraulic limits in
the horizontal production well 4.
[0032] When SAGD is producing fluids near their maximum rates,
hydraulic limitations may constrain operations. The steam chamber
is well-developed. Pressures within the steam chamber are near
constant, even though there can be a significant pressure drop in
the steam injection well (Parappilly, R. & Zhao, L., "SAGD with
a Longer Wellbore", JCPT, June 2009). The injector pressure drop is
mostly used to distribute steam injection evenly down the well
length. Because steam is a gas with low viscosity and the steam
chamber has a very high permeability, steam chamber pressures
equilibrate rapidly.
[0033] The production well is a different story. Steam-trap
(sub-cool) control ensures (or is intended to ensure) that liquids
(water and bitumen) cover the horizontal production well so that
steam breakthrough to the well is prevented. Ideally, the
liquid/steam interface 12 would lay between the horizontal producer
4 and the horizontal injector 2. If the wells were shut-in, the
steam/liquid interface 12 would form a horizontal plane between the
two wells. At steady-state production, even though gas (steam)
pressures are equilibrated, the interface 12 is tilted because the
liquids are in direct contact with the production well 4, and there
is a natural pressure drop in the well due to production flow down
the length of the well. This pressure drop is present for each of
natural lift, gas lift, or submersible pump. For draw-down at the
well heel, the lowest pressure is near the heel, and the tilted
interface has its high point at the well toe (FIGS. 8A and 8B).
[0034] If liquid production rates and pressure drops are too high,
the top of the interface 12 can cover (flood) the toe of the steam
injector 14 and/or the heel of the production well 16 can be opened
to the steam chamber (FIGS. 8A and 8B). This can reduce the
productivity and efficiency of the process by reducing the
effective length of the steam injector 2 (harming steam
conformance) and allowing steam breakthrough to the heel of the
producer 16 (reducing productivity and efficiency). If caught early
enough, both effects can be reversed by reducing liquid production
rates and reducing steam injection rates, thus overriding normal
SAGD operational strategy. Flooding the toe of the steam injector
14 inflicts no permanent damage. But, because the McMurray
formation is mostly unconsolidated, steam bypass can mobilize sand
particles and erode steal pipe causing permanent damage to the
production well at its most vulnerable site.
[0035] FIGS. 8A and 8B show the steam/liquid interface 12 as a
sloped straight line in 2D (or a tilted plane in 3D) for a
steady-state, mature SAGD operation. Even for a homogeneous
reservoir, this is a simplistic view. It may be accurate if the
production well 4 was a closed, horizontal pipe. But, the well
allows fluid inflow down the length of the well, using slotted
liners or other orifice systems. As best seen in FIGS. 9A and 9B, a
curved interface 12 and non-linear pressure distribution is
expected. Most of the pressure drop occurs in the area where
drawdown is located. For an inhomogeneous reservoir, steam/liquid
interface patterns are complex.
[0036] Because the expected interface 12 is mostly flat, except
near the drawdown site (FIGS. 9A and 9B), there is no significant
advantage (related to hydraulic limitations in the production well)
for completing horizontal wells on a slant to match slanted pay
zones.
[0037] The rule-of-thumb for proper SAGD operation, to obviate
potential hydraulic limitations, is that the pressure drop in the
production well 4, due to liquid flow, should not exceed the
hydrostatic head between the injection 2 and production well 4
locations. For a 5 metre well spacing, the hydrostatic head is
about 50 KPa or 8 psi. Unfortunately, few SAGD operators can
accurately measure these pressure drops.
[0038] Well trajectory variations may also affect hydraulic limits.
As best seen in FIGS. 10A-10C, if the steam injector 2 well dips
off and if the liquid production well 4 peaks, there can be further
limitations. For example, if there is a high spot in the producer
well 4 and a steam breakthrough zone is created, the toe of the
producer well is isolated from producing bitumen. In another case,
if there is a low spot in the injector well 2, an injector flooding
zone is created along the injector well 2, hampering steam
injection in the toe of the injector well 2. In such cases, the
rule-of-thumb for good operation is modified so that the pressure
drop in the production well 4 can't exceed the hydrostatic head for
the minimum distance between the injector well 2 and the producer
well 4.
[0039] From an operational standpoint the way to ameliorate
hydraulic limitations is to reduce production rates (and steam
injection) until pressure drops in the production well are within
allowed limits. This can also be accomplished by increasing
sub-cool targets.
[0040] From a design standpoint, increasing injector/producer
separation, increasing pipe/tubing size, or decreasing horizontal
well lengths may avoid hydraulic limitations. Each of these
remedies has an economic penalty. Increased well spacing extends
start-up times and reduces early bitumen productivity. Increased
pipe/tubing sizes increases capital and drilling costs. Decreased
well lengths reduce bitumen productivity.
[0041] With about 5 metre spacing between the injector well 2 and
the producer well 4, industry has settled on horizontal well
lengths of about 500 to 1000 metres. (Parappilly (2009), (Das, S.,
"Wellbore Hydraulics in a SAGD Well Pair" SPE 97922, November
2005), (Cenovus, "Telephone Lake Project", website, December 2011),
(Komery, D. et al, "Pilot Testing of Post-Steam Bitumen Recovery
from Mature SAGD Wells in Canada", University of Alberta Web, Feb.
14, 1998), (JACOS, "JACOS Hangingstone Expansion Project", website,
April 2010). Standard well lengths are about 500 to 800 m. (Cenovus
(2011), JACOS (2010)).
[0042] Typical liner sizes for horizontal SAGD producers are about
7 inches in diameter (Smith, M., "SAGD Simplified", New Tech Mag.,
Jun. 1, 2012). One study investigated SAGD well length extension
feasibility using a well bore flow model (Q Flow) and a SAGD
simulator (STARS-Steam, Thermal, and Advanced Process Reservoir
Simulator) (Parappilly (2009)). The study concluded that well
lengths of 1400 metres were feasible, if production well liner size
was increased to 9% inches and if the pressure drop in the producer
well was held to less than 50 KPa (Ross, E., "Going the Distance",
New Tech Mag., December 2008 (2012)).
[0043] The dominant process today is SAGD, using twin horizontal
wells 2,4 to inject steam 6 and produce bitumen and water 8. But,
SAGD has a hydraulic limitation that restricts well length to about
1000 metres, due to pressure drops in the production well.
[0044] Accordingly, there is a need for a process which overcomes
the well length of prior art processes without hitting hydraulic
limits, and preferably while maintaining productivity levels.
SUMMARY OF THE INVENTION
[0045] According to one aspect, a process to recover hydrocarbons
from a reservoir is disclosed, where said hydrocarbons have an
initial viscosity greater than 100,000 cp, preferably greater than
1,000 cp, said process comprising: [0046] (a) initially injecting
oxygen into said reservoir; [0047] (b) allowing for combustion of
said oxygen to vaporize connate water in said hydrocarbon
reservoir; [0048] (c) collecting hydrocarbons in a substantially
horizontal production well in said reservoir and where said
substantially horizontal production well has a length greater than
about 800 metres.
[0049] In one embodiment, the process further comprises initial
steam injection into the reservoir then terminating said steam
injection, where the ratio of oxygen to steam injected is
controlled in the range from 0.05 to 1.00 (v/v).
[0050] In another aspect, a steam assisted gravity drainage with
oxygen system for recovery of hydrocarbons from a reservoir is
disclosed, where said hydrocarbons have an initial viscosity
greater than 100,000 cp, preferably greater than 1,000 cp, said
system comprising: [0051] (a) A first well for capturing said
hydrocarbons, having a toe and a heel and a length greater than
about 800 metres, said first well being substantially horizontal
and at a first depth; [0052] (b) A second well within said
hydrocarbon containing reservoir, having a length greater than
about 800 metres, for injection of oxygen into said hydrocarbon
containing reservoir, being at second depth said second depth
shallower than said first depth; [0053] (c) Said second well being
located proximate said toe of said first well; and [0054] (d) A
vent gas means for venting any gas produced in said reservoir.
[0055] In one embodiment of the system, the vent gas means is
single or multiple vertical wells. In another embodiment of the
system, at least one vent gas means is a segregated annulus section
in the heel rise section of the substantially horizontal well.
[0056] A further aspect is a steam assisted gravity drainage with
oxygen system for recovery of hydrocarbons from a reservoir, where
said hydrocarbons have an initial viscosity greater than 100,000
cp, preferably greater than 1,000 cp, said system comprising:
[0057] (a) A first well, having a toe and a heel and a length
greater than about 800 metres, said first well within said
hydrocarbon containing reservoir, for capturing said hydrocarbons;
[0058] (b) A second well within said hydrocarbon containing
reservoir, having a length greater than about 800 metres, for
injection of oxygen and steam into said hydrocarbon containing
reservoir; [0059] (c) Said second well being located proximate said
toe of said first well; and [0060] (d) At least one vent gas means
for venting any gas produced in said reservoir.
[0061] In one embodiment of the system, the vent gas means is
single or multiple vertical wells.
[0062] In a further embodiment of the system, at least one vent gas
means is a segregated annulus section in the heel rise section of
the substantially horizontal well.
[0063] In yet another embodiment of the system, the second well is
single or multiple vertical wells used for said injection of oxygen
and steam.
[0064] In another embodiment of the system, the steam and oxygen
are comingled on the surface prior to injection.
[0065] In yet another embodiment of the system, the steam and
oxygen are segregated using packers and injected separately into
said single or multiple vertical wells. Even further, the steam and
oxygen are segregated using concentric tubing and packers, with
steam in the central tubing surrounded by oxygen in the adjacent
annulus, with said oxygen injected at a higher elevation in the
reservoir than said steam.
[0066] In another aspect, a steam assisted gravity drainage with
oxygen system for recovery of hydrocarbons for a reservoir is
disclosed, where said hydrocarbons have an initial viscosity
greater than 100,000 cp, preferably greater than 1,000 cp, said
system comprising: [0067] (a) A substantially horizontal well,
having a toe and a heel and a length greater than 800 metres, said
well being located within said hydrocarbon containing reservoir;
wherein said well further comprises: [0068] (b) At least one oxygen
injection site proximate said toe, for injecting oxygen into said
reservoir; [0069] (c) A hydrocarbon recovery site for recovery of
said hydrocarbons from said hydrocarbon containing reservoir; and
[0070] (d) At least one vent gas site for venting any gas produced
in said reservoir.
[0071] In one embodiment of the system, the oxygen injection site
is a segregated toe section of said substantially horizontal
well.
[0072] In yet another aspect, a steam assisted gravity drainage
with oxygen system for recovery of hydrocarbons for a reservoir is
disclosed, where said hydrocarbons have an initial viscosity
greater than 100,000 cp, preferably greater than 1,000 cp, said
system comprising: [0073] (a) A substantially horizontal well,
having a toe and a heel and a length greater than 800 metres, said
well being located within said hydrocarbon containing reservoir;
wherein said well further comprises: [0074] (b) At least one oxygen
injection site proximate said toe, for injecting oxygen into said
reservoir; [0075] (c) At least one steam injection site, for
injecting steam into said reservoir; [0076] (d) A hydrocarbon
recovery site for recovery of said hydrocarbons from said
hydrocarbon containing reservoir; and [0077] (e) At least one vent
gas site for venting any gas produced in said reservoir.
[0078] In one embodiment of the system, the oxygen and steam
injection site is a segregated toe section of said substantially
horizontal well.
BRIEF DESCRIPTION OF THE FIGURES
[0079] FIGS. 1A and 1B depict a traditional SAGD Geometry (PRIOR
ART);
[0080] FIGS. 2A-2D depict the life cycle of SAGD operation (PRIOR
ART);
[0081] FIG. 3 depicts Saturated Steam Properties (PRIOR ART);
[0082] FIG. 4 depicts pressure versus temperature of saturated
steam (PRIOR ART);
[0083] FIG. 5 depicts Bitumen viscosity versus Temperature (PRIOR
ART);
[0084] FIG. 6 depicts the Gravdrain equation for SAGD bitumen
productivity (PRIOR ART);
[0085] FIG. 7 depicts residual bitumen in Steam Swept Zones (PRIOR
ART);
[0086] FIGS. 8A and 8B depict hydraulic limitations of SAGD (PRIOR
ART);
[0087] FIGS. 9A and 9B depict SAGD wellbore hydraulics (PRIOR
ART);
[0088] FIGS. 10A-10C depict SAGD hydraulic limits in well
trajectories (PRIOR ART);
[0089] FIG. 11 depicts a SAGDOX geometry;
[0090] FIGS. 12A and 12B depict a toe to heel SAGDOX (THSAGDOX)
with the pump at the heel of the well, according to one embodiment
of the present invention;
[0091] FIGS. 13A-13C depict Single well SAGDOX (SWSAGDOX) piping
schemes with centralized packers, according to several embodiments
of the present invention;
[0092] FIGS. 14A and 14B depict SWSAGDOX piping schemes with
off-set packers, according to several embodiments of the present
invention;
[0093] FIGS. 15A and 15B depict SWSAGDOX uplift schematic,
according to one embodiment of the present invention;
[0094] FIGS. 16A-16C depict several preferred SAGDOX geometries,
according to one embodiment of the present invention;
[0095] FIG. 17 depicts combustion heat release (PRIOR ART);
[0096] FIG. 18 depicts SAGDOX process mechanisms;
[0097] FIG. 19 depicts steam and oxygen combustion tube tests
I;
[0098] FIG. 20 depicts steam and oxygen combustion tube tests
II;
[0099] FIG. 21 depicts ISC minimum air flux rates (PRIOR ART);
[0100] FIG. 22 depicts a SWSAGDOX well configuration;
[0101] FIG. 23 depicts extended reach THSAGDOX (ER-THSAGDOX),
according to one embodiment of the present invention;
[0102] FIG. 24 depicts ER-THSAGDOX with three injectors, according
to one embodiment of the present invention;
[0103] FIG. 25 depicts ER-THSAGDOX with lateral offsets and two
injectors, according to one embodiment of the present
invention;
[0104] FIGS. 26A-26D depict THSAGDOX hydraulic limitations;
[0105] FIG. 27 depicts THSAGOX optimal hydraulic design; and
[0106] FIGS. 28A and 28B depict SAGDOX (THSAGDOX) with the pump at
the toe of the well, according to one embodiment of the present
invention.
DETAILED DESCRIPTION OF THE INVENTION
[0107] SAGDOX is an improved thermal enhanced oil recovery (EOR)
process for bitumen recovery. The process can use geometry similar
to SAGD (FIG. 11), but it also has versions with separate vertical
wells or segregated sites for oxygen injection and/or
non-condensable vent gas removal (FIGS. 12A, 12B, 13A-13C, 14A,
14B, 15A, 15B and 16A-16C). The process can be considered as a
hybrid SAGD+ISC process.
[0108] One objective of SAGDOX is to reduce reservoir energy
injection costs, while maintaining good efficiency and
productivity. Oxygen combustion produces in situ heat at a rate of
about 480 BTU/SCF oxygen independent of fuel combusted (FIG. 17
Butler (1991)). Combustion temperatures are independent of pressure
and they are higher than saturated steam temperatures (FIGS. 3,
19). The higher temperature from combustion vaporizes connate water
and refluxes some steam. Steam delivers EOR energy from latent heat
released by condensation with a net value, including surface heat
recovery of about 1000 BTU/lb. (FIG. 3).
[0109] 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.
[0110] The recovery mechanisms are more complex for SAGDOX than for
SAGD. The combustion zone is contained within the steam-swept zone
170. Residual bitumen, in the steam-swept zone 170, is heated,
fractionated and pyrolyzed by hot combustion gases to produce coke
that is the actual fuel for combustion. A gas chamber is formed
containing steam combustion gases, vaporized connate water, and
other gases (FIG. 18). The large gas chamber can be subdivided into
a combustion-swept zone 100, a combustion-zone, a pyrolysis zone
120, a hot bitumen bank 130, a superheated steam zone 140 and a
saturated steam zone 50 (FIG. 18). Condensed steam drains from the
saturated steam zone 150 and from the ceiling and walls of the gas
chamber. Hot bitumen drains from the ceiling and walls of the
chamber and from the hot bitumen zone 130 at the edge of the
combustion front 110 (FIG. 18). Condensed water and hot bitumen 8
are collected by the lower horizontal well 4 and conveyed (or
pumped) to the surface (FIG. 11).
[0111] Combustion non-condensable gases are collected and removed
by vent gas 22 wells or at segregated vent gas sites (FIGS.
16A-16C). Process pressures can be controlled (partially) by vent
gas 22 production, independent of fluid production rates. Vent gas
22 production can also be used to influence direction and rate of
gas chamber growth.
[0112] Because SAGDOX delivers both steam and oxygen energy and
oxygen gas has 10 times the energy density as steam, pipe/tubing
sizes for SAGDOX can be smaller (and less costly) than SAGD or
other steam EOR processes. This can also reflect on production well
sizes because reduced steam injection (with SAGDOX) results in less
water production compared to SAGD.
[0113] Table 4 shows calculated pipe diameters for various SAGD and
SAGDOX streams. Design criteria are presented in the table. When
fluids use concentric pipe systems and annular flow, the total size
of the combined pipe is indicated by brackets.
[0114] Often pipe costs are proportional to the diameter of the
pipe. The total of pipe diameters can also be proportional to total
costs. Table 4 shows total pipe diameters can be reduced by using
SAGDOX and related processes.
[0115] Cumulative SAGDOX pipe diameters are 82% of SAGD for the
case studied (35% oxygen in gas mix). THSAGDOX cumulative pipe
diameters are 59% of SAGD, and SWSAGDOX cumulative diameter is only
42% of SAGD.
[0116] Preferred parameters in SAGDOX geometries include:
(1) Use Oxygen (rather than air) as the oxidant injected [0117] 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. [0118] 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. [0119] In
situ combustion (ISC) using oxygen produces mostly non-condensable
CO.sub.2, undiluted with nitrogen. CO.sub.2 can dissolve in bitumen
to improve productivity. Dissolution is maximized using oxygen.
[0120] Vent gas, using oxygen, is mostly CO.sub.2 and may be used
for sequestration. [0121] There is a minimum oxygen flux to sustain
HTO combustion (FIG. 17). [0122] It is easier to attain/sustain
this flux using oxygen. (2) Keep oxygen injection at a concentrated
site [0123] Because of the minimum O.sub.2 flux constraint from in
situ combustion (FIG. 21), the oxygen injection well (or a
segregated section) should have no more than 50 metres of contact
with the reservoir. (3) Segregate Oxygen and steam injectants, as
much as possible. [0124] Condensed steam (hot water) and oxygen are
very corrosive to carbon steel. [0125] To minimize corrosion,
either 1) oxygen 26 and steam 6 are injected separately (FIGS.
11,12A, 12B & 25); 2) comingled steam 6 and oxygen 26 have
limited exposure to a section of pipe that can be a corrosion
resistant alloy; 3) the section integrity is not critical to the
process (FIG. 13(B); or 4) the entire injection string is a
corrosion resistant alloy (FIG. 13(A)). (4) The vent gas well (or
site) is near the top of the reservoir, far from the oxygen
injection site [0126] Because of steam movement and condensation,
non-condensable gas concentrates near the top of the gas chamber.
[0127] 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 [0128] 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
[0129] 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.sup.- and H.sup.+ radicals the
combustion zone to improve and stabilize combustion (FIGS. 19 &
20) (Moore, R. G. et al "Parametric Study of Steam Assisted In Situ
Combustion," unpublished February 1994). This is also confirmed by
the operation of smokeless flares, where steam is added to improve
combustion and reduce smoke (Stone, D. et al "Flares," Chapter 7
www.gasflare.org, June 2012), (Environmental Protection Agency
"Industrial Flares," www.epa.gov June 2012), (Shore, D. "Making the
Flare Safe," Journal of Loss Prevention in the Process Industries,
9, 363, 1996). The process to gasify fuel also adds steam to the
partial combustor to minimize soot production (Berkowitz, N.
"Fossil Hydrocarbons," Academic Press 1997). [0130] Steam also
condenses and produces water that "covers" the horizontal
production well and isolates it from gas or steam intrusion. [0131]
Steam condensate adds water to the production well to improve flow
performance--water/bitumen emulsions--compared to bitumen alone.
[0132] Steam is also a superior heat transfer agent in the
reservoir. When one compares hot combustion gases (mostly CO.sub.2)
to steam, the heat transfer advantages of steam are evident. For
example, if one has a hot gas chamber at about 200.degree. C. at
the edges, the heat available from cooling combustion gases from
500.degree. C. to 200.degree. C. is about 16 BTU/SCF. The same
volume of saturated steam contains 39 BTU/SCF of latent heat--more
than twice the energy content of combustion gases. In addition,
when hot combustion gases cool, they become effective insulators
impeding further heat transfer. When steam condenses to deliver
latent heat, it creates a transient low-pressure that draws in more
steam--a heat pump, without the plumbing. The kinetics also favour
steam/water. The heat conductivity of combustion gas is about 0.31
(mW/cmK) compared to the heat conductivity of water of about 6.8
(mW/cmK)--a factor of 20 higher. As a result of these factors,
combustion (without steam) has issues of slow heat transfer and
poor lateral growth. These issues may be mitigated by steam
injection. [0133] 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 [0134] Below about 5% (v/v) oxygen in the steam and
oxygen mix, the combustion swept zone is small and the cost
advantages of oxygen are minimal At this level, only about a third
of the energy injected is due to combustion. (8) Maximum oxygen
injection [0135] Within the constraints of (6) and (7) above,
because per unit energy oxygen is less costly than steam, the
lowest-cost option to produce bitumen is to maximize oxygen/steam
ratios. (9) Use preferred SAGDOX geometries [0136] Depending on the
individual application, reservoir matrix properties, reservoir
fluid properties, depth, net pay, pressure and location factors,
there are three preferred geometrics for SAGDOX (FIGS. 16A-16C).
[0137] FIGS. 16B (THSAGDOX) and 16C (SWSAGDOX) are most preferred
for thinner pay resources, with only one horizontal well required.
Compared to SAGD, THSAGDOX and SWSAGDOX have a reduced well count
and lower drilling costs. Also, internal tubulars and packers
should be usable for multiple applications.
(10) Control/operate SAGDOX by:
[0137] [0138] 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. [0139] Adjust oxygen/steam ratios (v/v) to meet a target
ratio, subject to a range limit of 0.05 to 1.00. [0140] 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. [0141] Adjust steam and oxygen
injection rates (subject to (ii) above), along with (iii) above, to
attain/maintain pressure targets.
[0142] Aside from the above benefits accruing to SAGDOX processes,
compared to SAGD extended reach (>800 metre horizontal well
length) SAGDOX has the following benefits/motivations: [0143] (1)
increased reservoir exposure, per recovery pattern; [0144] (2)
reduction in capital costs per unit bitumen production; [0145] (3)
increased bitumen productivity, per recovery pattern; and [0146]
(4) reduced surface footprint, per unit bitumen production.
[0147] There are 3 versions of SAGDOX for extended reach wells:
[0148] (1) basic SAGDOX, with extended twin horizontal wells (FIG.
11); [0149] (2) THSAGDOX, where the horizontal steam injector is
replaced with one (or more) vertical injection wells (FIGS. 12A,
12B, 23, 24, 25, 28A and 28B); and [0150] (3) SWSAGDOX, preferably
with an up-turned toe section (FIGS. 13A-13C, 14A, 14B, 15A, 15B,
and 22)
[0151] THSAGDOX (Toe-to-Heel SAGDOX) retains the horizontal
production well 4, but replaces the horizontal steam injector with
vertical steam and oxygen injector(s). FIGS. 12A, 12B, 28A and 28B
show how THSAGDOX are deployed. All injection (oxygen 26 and steam
6) is accomplished in a vertical well(s), with oxygen 26 preferably
injected near the top of the pay zone and steam 6 preferably
injected near the bottom of the pay zone, with steam 6 offset from
the production horizontal well, preferably by 4 metres or more in
elevation. Vent gas 22 may be removed using the outer annulus of
the horizontal well in a section higher up in the pay zone (FIGS.
12A, 12B) or by using one (or more) vertical vent gas 22 wells
(FIG. 23).
[0152] The vertical oxygen and steam injector well is designed to
segregate steam 6 and oxygen 26 to minimize corrosion; inject
oxygen 26 near the top of the pay zone; and to inject steam 6 lower
in the pay zone (FIGS. 12A and 12B). This has the additional
benefit that oxygen 26 in the annulus, around a central steam
tubing, provides insulation to minimize heat losses from steam 6 to
the overburden (FIGS. 12A and 12B).
[0153] The THSAGDOX process is started by circulating steam in the
horizontal production well 4 and by injecting or cycling steam 6
(huff-and-puff) in the vertical well(s) until the wells communicate
(i.e. fluids can flow between wells). After communication is
established, wells are converted to THSAGDOX operation, with
similar operation controls to SAGDOX.
[0154] Hydraulic constraints for THSAGDOX are also less restrictive
than SAGD. For SAGD, production rates are constrained so that
pressure drops in the production well are less than the hydrostatic
head between injector and producer (about 8 psi). For the same well
size as SAGD, the THSAGDOX well can be much longer because, per
unit bitumen produced, there is less water, so total liquid volumes
for THSAGDOX are less than SAGD for the same bitumen production.
When the well length is extended, THSAGDOX bitumen productivity can
exceed SAGD productivity for the same hydraulic constraints.
[0155] Table 3 shows why THSAGDOX (or SAGDOX) processes can have
longer horizontal wells than SAGD, using the same hydraulic limit
criteria in the production well. For the same Energy to Oil Ratio
(MMBTU/bbl) ("ETOR") design and the same bitumen production rates,
fluid volume rates in the horizontal production well are reduced by
a factor of about three as oxygen levels in the injectant gases
(steam+oxygen) are increased (to a limit of 50 (v/v) percent oxygen
in the steam+oxygen mix).
[0156] But, the typical well length for THSAGDOX can be extended
even further if a tubing string is used to move the liquid draw
down point to near the toe of the horizontal well (FIGS. 26A-26D
& 28A, 28B). The toe of the vertical injector can be protected
from flooding by proximity of the draw down site (FIGS. 26A-26D).
The fluid level near the horizontal well toe can be allowed to
elevate above the site that would normally flood a horizontal steam
injector (FIG. 27). This remedy is not available to SAGD because
steam injection is spread out over the entire horizontal length of
the steam injector.
[0157] THSAGDOX also lends itself to extended-reach applications
(ER-THSAGDOX) using multiple vertical injector wells (steam+oxygen)
and vertical vent gas removal wells (FIGS. 23, 24, and 25). These
wells can be very small particularly from SAGDOX mixes with
elevated oxygen levels because the energy intensity for oxygen
(BTU/SCF) is about 10 times greater than steam. Vent gas 22 wells
are small because non-condensable gases produced by combustion are
similar in volume to oxygen injection. Table 4 shows this for a
specific case (35% oxygen). FIGS. 23, 24 and 25 show some options
for multiple well THSAGDOX systems.
[0158] The second option for extended length wells is the SWSAGDOX
process. SWSAGDOX contains all injection and production streams for
SAGDOX within a single horizontal well bore (FIG. 22).
[0159] Portions of the well are segregated for steam 6 and oxygen
injection 26 and for bitumen, water 8, and vent gas 22 production
using concentric tubing and segregation packers (FIGS. 13A-13C
& 14A, 14B). Capital expenditure is lowered by reducing the
well count (to 1.0) and by potential retrieval and reuse of various
completion components (packers and tubing).
[0160] The simplest version of SWSAGDOX is shown in FIGS. 13A-13C
where steam and oxygen 30 are mixed at surface and injected
premixed, rather than relying on mixing in the reservoir. To resist
corrosion, the injection tubing for the steam+oxygen 30 mixture is
an alloy-steel or another corrosion-resistant material. An
alternate scheme, to obviate corrosion, is to superheat the
steam+oxygen 30 mixture to prevent steam condensation on the
injectant tubular wells. Heat losses, particularly for deep
thin-pay bitumen reservoirs, from this mixture may be an issue. The
toe of the horizontal well (FIG. 13(A)) is also exposed to
oxygen+water corrosion. But, the integrity of the toe region of
this well is not critical to the EOR process.
[0161] An alternative embodiment to SWSAGDOX, as shown in FIG.
13(B), uses tubing to segregate oxygen 26 and steam 6, with oxygen
26 surrounding the steam injector tube. The oxygen 26 acts as a
good insulator for the steam tube and reduces heat losses to
preserve steam quality. But, the toe region of the horizontal well
is still exposed to steam+oxygen corrosion.
[0162] Yet another alternative SWSAGDOX embodiment is show in FIG.
13(C), where a packer 18 is used to segregate oxygen 26 and steam 6
prior to entering the reservoir. This can minimize toe corrosion
and still insulate the steam line to reduce heat losses.
[0163] Another alternative embodiment is to complete the horizontal
well using a corrosion resistant material, at least for the toe
section of the well.
[0164] SWSAGDOX has the following features: [0165] The horizontal
well interior tubing and packers can be retrieved and reused so
that its cost can be spread amongst several process units. [0166]
This is the least cost option (capex) for thin-pay steam+oxygen
EOR. [0167] This is the least well-count option. [0168] The process
has longitudinal flows with a drive recovery mechanism. [0169] 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. [0170] If a pump is necessary, it can be
accommodated (e.g. FIG. 16(A)). [0171] The design retains separate
vent gas removal. [0172] If steam occupies the central injection
tube, oxygen gas can help insulate the steam tube and minimize heat
losses (FIGS. 16(B) and 16(C)). [0173] 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.
[0174] With SWSAGDOX, hydraulic limitations need to be addressed.
Such as if the steam+oxygen section is flat and if we operate the
process so that liquid covers the production section to obviate
steam+oxygen breakthrough, the end of the horizontal well will be
flooded. This will inhibit steam+oxygen injection and harm
conformance. If we produce liquid at a faster rate to remove this
problem, the entire production section will be open to steam and
oxygen breakthrough.
[0175] The solution shown in FIGS. 15A and 15B is to drill and
complete the horizontal well, so the toe section is slanted upwards
to near the top of the pay zone. This enables us to retain liquid
covering the horizontal production section so that oxygen 26 and
steam 6 don't break through to the producer. Also, oxygen 26 and
steam 6 injection should be above the liquid interface so the
injection is not flooded. The process for such geometry is termed
SWSAGDOX(U), where U denotes uplift of the toe region of the
horizontal well. This is a preferred geometry for SWSAGDOX.
[0176] On the other hand, SWSAGDOX(U) doesn't get the double
hydraulic limit advantage that THSAGDOX achieves because it is not
practical to move the drawdown point for liquid production to near
the toe section.
[0177] The following provide differences between several
geometries. [0178] (1) ERSAGDOX vs. SAGDOX [0179] ERSAGDOX wells
are >800 metres long; no length restrictions for SAGDOX. [0180]
ERSAGDOX geometry prefers THSAGDOX or SWSAGDOX versions. [0181]
SAGDOX also includes twin horizontal well version. [0182] ERSAGDOX
prefers thin-pay reservoirs (<25 metres thick). [0183] (2)
ERSAGDOX (SWSAGDOX) vs. SWSAGD [0184] ERSAGDOX injects steam and
oxygen; SWSAGD injects steam. [0185] well lengths for ERSAGDOX.
[0186] elevated toe for SWSAGDOX version. [0187] (3) ERSAGDOX
(THSAGDOX) vs. THAI [0188] extended well lengths for ERSAGDOX.
[0189] vent gas removal well. [0190] steam+oxygen injection vs. air
(no steam). [0191] ERSAGDOX prefers oxygen; THAI prefers air.
[0192] To summarize, ERSAGDOX characteristics include the
following: [0193] well length >800 metres (preferably >1000
metres); [0194] preferred geometry (FIGS. 12A, 12B, 15A, 15B); no
consideration of dual horizontal wells; [0195] prefers thin pays
(preferably <25 metres thick); and [0196] steam and oxygen
injection is used.
TABLE-US-00001 [0196] TABLE 1 ALBERTA BITUMEN DEPOSITS Cold Peace
Athabasca Lake River Total Accessible Deposits (known technology)
SAGD/CSS 420 51 54 526 Mining 59 0 0 59 Cold Production 13 138 0
151 Subtotal 492 189 54 736 Inaccessible Deposits (no known
technology) Carbonates 383 0 65 448 Thin Pays 380 21 8 410 No cap
rock 37 0 0 37 Too deep for mining but too shallow 28 0 0 28 for
SAGD Top gas 14 0 0 14 Others 36 -10 1 27 Subtotal 877 11 74 962
Grand total 1369 201 129 1699 (10.sup.9 bbls) (1) Source -
(Heidrick, T. et al, "Oil Sands Research and Development", AERI,
March 2006) and (Godin (2006)) (2) Thin pay (cutoff = 10 m) (3)
Numbers may not be additive due to rounding
TABLE-US-00002 TABLE 2 Thermal EOR: Injection Gases % (v/v) % heat
from BTU/SCF MSCF/MMBTU O.sub.2 O.sub.2 mix mix SAGD (Steam) 0.0
0.0 47.4 21.1 SAGDOX 5% O.sub.2 5.0 34.8 69.0 14.5 9% O.sub.2 9.0
50.0 86.3 11.6 35% O.sub.2 35.0 84.5 198.8 5.0 50% O.sub.2 50.0
91.0 263.7 3.8 ISC (oxygen) 100.0 100.0 480 2.1 (air) 20.9 100.0
100 10.0 Where: (1) steam at 1000 BTU/lb (2) oxygen at 480 BTU/SCF
(3) SAGDOX oxygen at (v/v)%
TABLE-US-00003 TABLE 3 SAGDOX Water Balance % (v/v) O.sub.2 steam
mix SAGD 5 9 35 50 ISC(O.sub.2) Design ETOR (sf) 1.00 1.00 1.00
1.00 1.00 1.00 SOR(sf) 2.86 1.86 1.43 0.40 0.26 0.00 SOR(wh) 3.18
2.07 1.59 0.49 0.29 0.00 ETOR (O.sub.2)(sf) 0 0.65 0.50 0.85 0.91
1.00 % ht. from O.sub.2 0 34.8 50.0 84.5 91.1 100.0 Water Stm.
water (bbl/Bbl) 3.18 2.07 1.59 0.49 0.29 0.00 Connate water
(bbl/Bbl) 0 0.09 0.13 0.21 0.23 0.25 Comb. water (bbl/Bbl) 0 0.013
0.019 0.032 0.035 0.038 WWR 1.00 1.05 1.09 1.49 1.91 -- Production
Total water (bbl/Bbl) 3.18 2.17 1.74 0.73 0.56 0.29 Bitumen
(bbl/Bbl) 1.00 1.00 1.00 1.00 1.00 1.00 Total (bbl/Bbl) 4.18 3.17
2.74 1.73 1.56 1.29 Cut % water (v/v) 76.1 68.4 63.5 42.2 35.9 22.5
Total % of SAGD 100.0 75.8 65.6 41.4 37.3 30.9 Where: (1) Bbl = bbl
bit.; sf = sand face; wh = well head (2) connate water = .25
bbl/Bbl; prorated by % ht. from O.sub.2 (3) ETOR = MMBTU/Bbl = 1.0
at sf. (4) WRR = prod. water/steam water (5) S.sub.0 = .8; S.sub.w
= .2 (6) steam at 1000 BTU/lb; O.sub.2 at 480 BTU/SCF (7) 10% loss
in each of steam dist. and wh to sf.
TABLE-US-00004 TABLE 4 Process Pipe Sizes SAGD SAGDOX THSAGDOX
SWSAGDOX Steam Injector 7.23 2.76 } 3.47 {close oversize brace}
5.00 Oxygen Injector -- 2.09 Vent Gas Producer -- 2.09 } 3.60
Liquids Producer 4.79 2.93 Totals 12.02 9.87 7.07 5.00 Where: (1)
500 Bbl/d @ ETOR = 1.0 (sf) (2) 100 psia, 160.degree. C. steam @ 25
ft./sec (3) liquids producer @ 1 ft./sec (4) oxygen injector @ 100
ft./sec (5) 35% (v/v) oxygen in mix (6) concentric piping doesn't
account for wall thickness
[0197] As many changes therefore may be made to the embodiments of
the invention without departing from the scope thereof. It is
considered that all matter contained herein be considered
illustrative of the invention and not in a limiting sense.
* * * * *
References