U.S. patent application number 13/928895 was filed with the patent office on 2014-01-02 for sagd control in leaky reservoirs.
This patent application is currently assigned to NEXEN INC.. The applicant listed for this patent is Richard Kelso Kerr, Peter Yang. Invention is credited to Richard Kelso Kerr, Peter Yang.
Application Number | 20140000876 13/928895 |
Document ID | / |
Family ID | 49776933 |
Filed Date | 2014-01-02 |
United States Patent
Application |
20140000876 |
Kind Code |
A1 |
Yang; Peter ; et
al. |
January 2, 2014 |
SAGD CONTROL IN LEAKY RESERVOIRS
Abstract
The use of a water recycle ratio for controlling at least one
Steam Assisted Gravity Drainage (SAGD) parameter in a leaky bitumen
reservoir. Further, a process to control a steam injection rate for
an individual SAGD well pair, in a leaky bitumen reservoir wherein
the process replaces a pressure control for an SAGD steam injection
rate with a volume control determined by a Water Recycle Ratio
(WRR).
Inventors: |
Yang; Peter; (Calgary,
CA) ; Kerr; Richard Kelso; (Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Yang; Peter
Kerr; Richard Kelso |
Calgary
Calgary |
|
CA
CA |
|
|
Assignee: |
NEXEN INC.
Calgary
CA
|
Family ID: |
49776933 |
Appl. No.: |
13/928895 |
Filed: |
June 27, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61666132 |
Jun 29, 2012 |
|
|
|
Current U.S.
Class: |
166/250.08 |
Current CPC
Class: |
E21B 43/2406 20130101;
E21B 47/117 20200501; E21B 43/2408 20130101; E21B 43/12
20130101 |
Class at
Publication: |
166/250.08 |
International
Class: |
E21B 43/12 20060101
E21B043/12 |
Claims
1. The use of water recycle ratio for controlling at least one SAGD
parameter in a leaky bitumen reservoir.
2. A process to control a steam injection rate for an individual
Steam Assisted Gravity Drainage (SAGD) well pair, in a leaky
bitumen reservoir, wherein said process comprises replacing a
pressure control for an SAGD steam injection rate with a volume
control determined by a Water Recycle Ratio (WRR).
3. The use of claim 1 wherein said at least one parameter is
selected from volume rate, pressure, temperature, and
combinations.
4. The process of claim 2, where the leaky bitumen reservoir is
determined to be leaky by at least one of geological knowledge of
an interspersed Water Lean Zone (WLZ), top water or bottom
water.
5. The process of claim 2, where the leaky bitumen reservoir is
determined leaky by a cold water injection test prior to SAGD
initiation.
6. The process of claim 2, where the leaky bitumen reservoir is
deemed leaky when after 200 days or more of SAGD operation using
pressure control for steam injection, the SAGD has a WRR that
varies from 1.0 by more than 10 percent.
7. The process of claim 2, where a sub-cool control is maintained
for liquids production.
8. The process of claim 2, where volume rate control is instituted
by injecting a pre-set target volume rate of steam into the SAGD
injector well.
9. A process for controlling a steam injection volume rate in a
Steam Assisted Gravity Drainage (SAGD) process in an impaired
reservoir, wherein the steam injection volume rate is controlled by
i. Continually measuring a Water Recycle Ratio (WRR) for an SAGD
well pair; ii. Establishing a target for WRR; and iii. If the
actual WRR is less than the target WRR, reducing the steam
injection rate until the target is achieved; iv. If the actual WRR
is greater than the target WRR, increasing the steam injection rate
until the target is achieved.
10. The process of claim 9 where the target WRR is between 0.9 and
1.0.
11. The process of claim 9, where the target WRR is between 1.0 and
1.5.
12. The process of claim 2, wherein the leaky bitumen reservoir is
leaky due to an interspersed water lean zone (WLZ) within a net pay
zone in said reservoir.
13. The process of claim 2, where the leaky bitumen reservoir is
leaky due to a top water zone.
14. The process of claim 2, where the leaky bitumen reservoir is
leaky due to a bottom water zone
15. The process of claim 2, wherein the leaky bitumen reservoir is
leaky due to multiple factors comprising WLZ, top water and bottom
water.
16. The process of claim 2, wherein the bitumen is a hydrocarbon
with <10 API density and >100,000 cp viscosity, at native
reservoir conditions.
17. The process of claim 8, wherein the measured SAGD pressure in
the reservoir does not exceed: i) the reservoir parting pressure,
for unconsolidated reservoirs; ii) the reservoir fracturing
pressure, for consolidated reservoirs.
18. The process of claim 17, where the measured SAGD pressure does
not exceed about 80 percent of the parting pressure or the
fracturing pressure.
19. The process of claim 16, where the bitumen reservoir is located
in the Athabasca region of Alberta, Canada.
20. The process of claim 2, where the minimum operating pressure is
equal to the native reservoir pressure.
Description
BACKGROUND OF THE INVENTION
[0001] Steam assisted gravity drainage (SAGD) is now the leading in
situ thermal enhanced oil recovery (EOR) process to recover bitumen
from Alberta's oil sands. The oilsands are one of the world's
largest hydrocarbon deposits. SAGD has two parallel horizontal
wells up to about 1000 m long, in a vertical plane, separated by
about 5 m. The upper steam injector is controlled by injection
steam rate to attain a target pressure set by the operator (i.e.
"pressure control"). The lower bitumen and water producer is
controlled by pumping rate (or other methods) to maintain a fluid
temperature lower than saturated steam (sub-cool or steam-trap
control) to ensure no live steam breaks through to the well.
[0002] The above control methods work well where the steam chamber
is contained, even if the target pressure is higher than the native
reservoir pressure. But, the oil sands have a significant portion
of the resource that is impaired by water zones (top water, bottom
water, interspersed lean zones). These can cause the reservoir to
be "leaky" with significant water influx or egress. Under these
conditions, SAGD pressure control for steam injection does not work
well. Pressure gradients need only be modest to transport large
volumes of water and disrupt SAGD. It is hard to choose an
appropriate pressure target or to accurately measure an appropriate
pressure to minimize the harmful effects of a leaky reservoir. This
invention describes an alternate volume control method for SAGD
steam injection in leaky reservoirs. The technique involves using
WRR (the water recycle ratio) as the key measurement and control
parameter. WRR is volume ratio (measured as water) of water
produced to steam injected.
[0003] The Athabasca bitumen resource in Alberta, Canada is one of
the world's largest deposits of hydrocarbons. As describe above, a
significant portion of the resource can be impaired by a water
zone--causing the reservoir to be "leaky." Also, The Athabasce
bitumen resource in Alberta, Canada is unique for the following
reasons: [0004] (1) The resource, in Alberta, contains about 2.75
trillion bbls. of bitumen (Butler, R. M., "Thermal Recovery of Oil
& Bitumen", Prentice Hall, 1991), including carbonate deposits.
This is one of the world's largest liquid hydrocarbon resources.
The recoverable resource, excluding carbonate deposits, is
currently estimated as 170 billion bbls -20% mining (34 billion
bbls.) and 80% in-situ EOR (136 billion bbls) (CAPP, "The Facts on
Oilsands", November 2010). The in situ EOR estimate is based on
SAGD, or a similar process. [0005] (2) Conventional oil reservoirs
have a top seal (cap rock) that prevents oil from leaking and
contains the resource. Bitumen was formed by bacterial degradation
of lighter source oil to a stage where the degraded bitumen is
immobile under reservoir conditions. Bitumen reservoirs can be
self-sealed (no cap rock seal). If an in situ EOR process hits the
"ceiling", the process may not be contained and it can easily be
contaminated by water or gas from above the bitumen. [0006] (3)
Bitumen density is close to the density of water or brine. Some
bitumens are denser than water; some are less dense than water.
During the bacterial-degradation and formation of bitumen, the
hydrocarbon density can pass through a density transition and water
can, at first, be less dense than the reservoir "oil". Bitumen
reservoir water zones are found above the bitumen (top water),
below the bitumen (bottom water), or interspersed in the bitumen
net pay zone (water lean zones (WLZ)). [0007] (4) Most bitumen was
formed in a fluvial or estuary environment. Focusing on reservoir
impairments, this has two consequences. First, there will be
numerous reservoir inhomogeneities. Second, the scale of the
inhomogeneities is likely to be less than the scale of a SAGD
recovery pattern (FIG. 1) or less than about 1000 m in size. The
expectation is that an "average" SAGD EOR process will encounter
several inhomogeneities within each recovery pattern.
[0008] SAGD is a delicate process. Temperatures and pressures are
limited by saturated steam properties. Gravity drainage is driven
by a pressure differential as low as 25 psia. Low temperatures (in
a saturated steam process) and low pressure gradients make the SAGD
process susceptible to impairments from reservoir inhomogeneities,
as above.
[0009] This invention describes an alternate volume control method
for SAGD steam injection in leaky reservoirs. The technique
involves using WRR (the water recycle ratio) as the key measurement
and control parameter. WRR is volume ratio (measured as water) of
water produced to steam injected.
SUMMARY OF THE INVENTION
[0010] The following acronyms will be used herein.
TABLE-US-00001 AOGR American Oil & Gas Reporter CAPP Canadian
Association of Petroleum Producers CMG Computer Modeling Group
(Calgary) CSS Cyclic Steam Stimulation EOR Enhanced Oil Recovery
ETOR Energy to Oil Ratio (MMBTU/bbl) ESP Electric Submersible Pump
GD Gravity Drainage (chamber) JCPT Journal of Canadian Petroleum
Technology LZ Lean Zone P Pressure SAGD Steam Assisted Gravity
Drainage SOR Steam to Oil Ratio SPE Society of Petroleum Engineers
T Temperature WLZ Water Lean Zone WRR Water Recycle Ratio
[0011] According to one aspect of the invention, there is a
provided a use of water recycle ratio for controlling at least one
SAGD parameter in a leaky bitumen reservoir. In one embodiment,
said parameter is selected from volume rate, pressure, temperature,
and combinations thereof.
[0012] According to another aspect of the invention, there is
provided a process to control SAGD steam injection rate for an
individual SAGD well pair in a leaky bitumen reservoir, comprising
replacing pressure control of said SAGD steam injection rate with
volume control.
[0013] Preferably, said leaky bitumen reservoir is determined by
geological knowledge of an interspersed WLZ, top water or bottom
water in a SAGD pattern volume, more preferably said leaky bitumen
reservoir is determined by a cold water injection test prior to
SAGD initiation, most preferably the reservoir is deemed leaky when
WRR is measured and after 200 days of more of SAGD operation using
pressure control for steam injection, and the WRR varies from 1.0
by more than 10 percent.
[0014] Preferably, said process further comprises sub-cool control
(steam-trap control) for liquids production (bitumen+water).
[0015] In one embodiment, said volume rate control is instituted by
injecting a pre-set target volume rate of steam into the SAGD
injector well.
[0016] In another embodiment, said volume rate control is
instituted by [0017] i. Continually measuring WRR for the SAGD well
pair [0018] ii. Establishing a target for WRR; and [0019] iii. If
the actual WRR is less than the target WRR, reducing the steam
injection rate until the WRR target is achieved; or [0020] iv. If
the actual WRR is greater than the target WRR, increasing the steam
injection rate until the WRR target is achieved.
[0021] Preferably, for a near-homogeneous reservoir the target WRR
is between 0.9 and 1.0
[0022] Preferably, said process is applied to a leaky reservoir
with a high-water-saturation zone in or adjacent to the bitumen pay
zone, where the target WRR is set at between 1.0 and 1.5.
[0023] In one embodiment, said leaky reservoir is caused by an
interspersed water lean zone (WLZ) within the net pay zone.
[0024] In another embodiment, said leaky reservoir is caused by a
top water zone. And in yet another embodiment, said leaky reservoir
is caused by a bottom water zone. In yet another embodiment, said
leaky reservoir is caused by multiple factors comprising WLZ, top
water and/or bottom water.
[0025] Preferably, said bitumen is a hydrocarbon with <10 API
density and >100,000 cp viscosity, at native reservoir
conditions.
[0026] In one embodiment, SAGD pressure in the reservoir does not
exceed the reservoir parting pressure, for unconsolidated
reservoirs, or the reservoir fracturing pressure, for consolidated
reservoirs.
[0027] Preferably, the maximum SAGD pressure allowed is about 80
percent of the parting pressure and/or the fracturing pressure.
[0028] In another embodiment, the minimum SAGD operating pressure
is equal to the native reservoir pressure.
[0029] In one embodiment, the bitumen reservoir is located in the
Athabasca region of Alberta, Canada.
BRIEF DESCRIPTION OF THE DRAWINGS
[0030] FIG. 1 depicts a typical SAGD Well Configuration
[0031] FIG. 2 depicts SAGD stages
[0032] FIG. 3 depicts Saturated Steam Properties
[0033] FIG. 4 depicts Bitumen and Heavy Oil Viscosities
[0034] FIG. 5 depicts SAGD Productivity per Well
[0035] FIG. 6 depicts SAGD Hydraulic Limits
[0036] FIG. 7 depicts Interspersed Bitumen Lean Zones
[0037] FIG. 8 depicts Top/Bottom Water: Oilsands
[0038] FIG. 9 depicts SAGD Simulation
[0039] FIG. 10 depicts WRR Performance for a Homogeneous Reservoir
with Contained SAGD GD Chamber (Single well pair)
[0040] FIG. 11 depicts Bitumen Voidage and Steam Volumes
[0041] FIG. 12 depicts Well Pair Cross-Flow Model
[0042] FIG. 13 depicts SAGD performance Case 1
[0043] FIG. 14 depicts SAGD performance Case 2
[0044] FIG. 15 depicts SAGD performance Case 2(a)
[0045] FIG. 16 depicts SAGD performance Case 3
[0046] FIG. 17 depicts SAGD performance Case 4
[0047] FIG. 18 depicts SAGD performance Case 5
[0048] FIG. 19 depicts SAGD cumulative well pair performance of
Cases 1-3
[0049] FIG. 20 depicts SAGD cumulative well pair performance of
Cases 1, 4 and 5
[0050] FIG. 21 depicts SAGD dual well pair production/performance
of Base Case and Case 2
[0051] FIG. 22 depicts SAGD pressure control performance of
connected well pairs
[0052] FIG. 23 depicts SAGD WRR performance of connected well pairs
Case 3
[0053] FIG. 24 depicts SAGD WRR performance of connected well pairs
Case 1 and 3
[0054] FIG. 25 depicts bitumen production of individual well pair
Case 3
[0055] FIG. 26 depicts bitumen production rates of two well pair of
Base Case and Case 3
[0056] FIG. 27 depicts SOR Performance of Base Case and Case 3
DETAILED DESCRIPTION OF THE INVENTION
[0057] SAGD is a bitumen EOR process that uses saturated-steam to
deliver energy to a bitumen reservoir. FIG. 1 shows the basic SAGD
geometry, using twin, parallel horizontal wells (2, 4) (up to about
1000 m long) separated by about 2 to 8 m above the bottom of the
bitumen zone (floor 8). The upper well (2) is in the same vertical
plane and injects saturated steam into the reservoir. The steam
heats the bitumen and the reservoir matrix. As the interface
between steam and cold bitumen moves outward and upward it creates
a gas, gravity-drainage chamber (FIG. 2). The heated bitumen and
condensed steam drain, by gravity, to the lower horizontal well (4)
that produces the liquids. The heated liquids (bitumen+water) are
pumped (or conveyed) to the surface using ESP pumps or a gas-lift
system.
[0058] FIG. 2 shows how SAGD matures. A young steam chamber (1) has
bitumen drainage from steep sides and from the chamber ceiling When
the chamber grows (2) and hits the top of the net pay zone,
drainage from the chamber ceiling stops and the slope of the side
walls decreases as the chamber continues to grow outward. Bitumen
productivity peaks at about 1000 bbls/d, when the chamber hits the
top of the net pay zone and falls as the chamber grows outward (3),
until eventually (10-20 years) the economic limit is reached.
[0059] Since the produced fluids are at/near saturated steam
temperatures, it is only the latent heat of the steam that
contributes to the process in the reservoir. It is important to
ensure that steam is high quality as it is injected into the
reservoir.
[0060] A SAGD process in a good homogeneous reservoir may be
characterized by only a few measurements: [0061] (1) Saturated
steam T (or P) [0062] (2) Bitumen production rate (the key economic
factor), and [0063] (3) SOR--a measure of process efficiency
[0064] For an impaired reservoir, a fourth measurement may be
added--the water recycle ratio (WRR). WRR enables one to see how
much of the injected steam is returned as condensed water.
[0065] SAGD operation, in a good-quality reservoir, is
straightforward. Steam injection rate into the upper horizontal
well and steam pressure are controlled by pressure targets chosen
by the operator. If the pressure is below the target, steam
pressure and injection rates are increased. The opposite is done if
pressure is above the target. Production rates from the lower
horizontal well are controlled to achieve sub-cool targets in the
average temperature of the production fluids. The sub-cool is the
difference in temperature of saturated steam and the actual
temperature of produced liquids (bitumen+water). Produced fluids
are kept at a lower T than saturated steam to ensure that live
steam doesn't get produced. 20.degree. C. is a typical sub-cool
target. This is also called steam-trap control.
[0066] The SAGD operator has two choices to make--the sub-cool
target and the operating pressure of the process. Sub-cool is
safety issue, but operating pressure is more subtle and usually
more important. The higher the pressure, the higher the
temperature--linked by the properties of saturated steam (FIG. 3).
As operating temperature rises, so does the temperature of the
heated bitumen which, in turn, reduces bitumen viscosity. Bitumen
viscosity is a strong function of temperature (FIG. 4). The
productivity of a SAGD well pair is proportional to the square root
of the inverse bitumen viscosity (Butler (1991)). So the higher the
pressure, the faster bitumen can be recovered--a key economic
performance factor.
[0067] But, efficiency is lost if pressures are increased. It is
only the latent heat of steam that contributes (in the reservoir)
to SAGD. As steam P and T are increased to improve productivity,
the latent heat content of steam drops (FIG. 3). In addition, as P
and T are increased, more energy is needed to heat the reservoir
matrix up to saturated steam's T and heat losses increase (SOR and
ETOR increase).
[0068] The SAGD operator usually opts to maximize economic returns,
so the operator increases P and T as much as possible. Pressures
are usually much greater than native reservoir P. A few operators
have gone too far and exceeded parting pressure (fracture pressure)
and caused a surface breakthrough of steam and sand (Roche, P.,
"Beyond Steam", New Tech. Mag., September 2011). Bitumen
productivity peaks at about 1000 bbl/d for the best reservoirs, but
it can be significantly impaired for the poorer reservoirs (FIG.
27).
[0069] There also may be a hydraulic limit for SAGD (FIG. 6). The
hydrostatic head between the two SAGD wells (2, 4) is about 8 psia
(56 kPa). When pumping or producing bitumen and water (12), there
is a natural pressure drop in the well due to frictional forces. If
this pressure drop exceeds the hydrostatic head, the steam/liquid
interface may be "tilted" and intersect the producer or injector
well (2,4). If the producer (4) is intersected, steam can break
through. If the injector (2) is intersected, it may be flooded and
the effective injector length may be shortened. For current
standard pipe sizes and a 5 m spacing between wells (2,4), SAGD
well lengths are limited to about 1000 m.
[0070] One of the common remedies for an impaired SAGD reservoir,
that has water incursion, is to lower the SAGD operating pressure
to "match" native reservoir pressure--also called low-pressure
SAGD. But this at best is difficult and at worst impractical for
the following reasons: [0071] (1) There is a natural hydrostatic
pressure gradient in the net pay region. For example for 30 m of
net pay, the hydrostatic head is about 50 psi (335 kPa). Because
the steam chamber is a gas, it is at constant pressure. What
operating pressure is chosen to match reservoir P? [0072] (2) There
are also lateral pressure gradients in SAGD. The pipe size for the
SAGD producer is chosen so that the natural pressure gradient, when
pumping, is less than the hydrostatic pressure difference between
SAGD steam injector and bitumen producer (about 8 psi or 56 kPa).
How can SAGD P match to the reservoir P if there is a lateral
pressure gradient? [0073] (3) Pressure control for SAGD is
difficult and measurements are inexact. A pressure control
uncertainty of .+-.200 kPa is to be expected.
[0074] The above control methods work well where the steam chamber
is contained, even if the target pressure is higher than the native
reservoir pressure.
[0075] As discussed above, the oil sands have a significant portion
of the resource that is impaired by water lean zones (top water,
bottom water, interspersed lean zones). These may cause the
reservoir to be "leaky" with significant water influx or egress.
Under these conditions, SAGD pressure control for steam injection
does not work well. Pressure gradients need only be modest to
transport large volumes of water and disrupt SAGD. It is hard to
choose an appropriate pressure target or to accurately measure an
appropriate pressure to minimize the harmful effects of a leaky
reservoir.
[0076] Water Lean Zones (WLZ)
[0077] Water Lean Zones (WLZ) with high water saturation may be at
the top of the bitumen reservoir (top water), at the bottom (bottom
water), or interspersed within the pay zone.
[0078] FIG. 7 depicts an interspersed WLZ 18. When confronted with
this situation, the following is observed: [0079] i. Interspersed
WLZ have to be heated so that GD steam chambers can envelop the
zone and continue growth of the GD chamber above and around the WLZ
blockage. [0080] ii. A WLZ has a higher heat capacity than a
bitumen pay zone. Table 3 below shows a 25% heat capacity increase
for a WLZ compared to a pay zone. [0081] iii. A WLZ also has higher
heat conductivity than a bitumen pay zone. For example, WLZ has
more than double the heat conductivity of the bitumen pay zone
(Table 2). [0082] iv. So, even if the WLZ is not recharged by an
aquifer or bottom/top water, the WLZ will incur a thermal penalty
as the steam chamber moves through it. Also, since the WLZ has
little bitumen, bitumen productivity will also suffer as the steam
zone moves through a WLZ. [0083] v. SAGD steam can heat WLZ water
to/near saturated steam T, but it cannot vaporize WLZ water.
Breaching of the WLZ, will require water to drain as a liquid.
[0084] vi. If the interspersed WLZ acts as a thief zone, the
problems are most severe. The WLZ can channel steam away from the
SAGD steam chamber. If the steam condenses prior to removal, the
water is lost but the heat can be retained. But, if the steam exits
the GD steam chamber prior to condensing, both the heat and the
water are lost to the process. [0085] vii. The obvious remedy is to
reduce SAGD pressures to minimize the outflow of steam or water.
But, if this is done, bitumen productivity will be reduced. [0086]
viii. If pressures are reduced too far or if local pressures are
too low, cold water from a WLZ thief zone can flow into the steam
GD chamber or toward the SAGD production well. If this occurs,
water production can exceed steam injection. More importantly, for
a large water inflow, steam trap control (sub-cool control) is lost
as a method to control SAGD. [0087] ix. Interspersed WLZ's can
distort SAGD steam chamber shapes, particularly if the WLZ is
limited in lateral size. Normal growth is slowed down as the WLZ is
breached. This can reduce productivity, decrease efficiency, and
limit recovery.
[0088] With respect to bottom water zones 20, as best seen in FIG.
8, the issues are similar to interspersed WLZ except that 1) bottom
water underlies the bitumen and 2) the usual expectation is that
bottom water is more active. SAGD can operate at pressures greater
than reservoir pressure as long as the following occurs: 1)
pressure drops in the production well (due to flow/pumping) do not
reduce local pressures below reservoir P and 2) the bottom of the
reservoir, underneath the production well, is "sealed" by
high-viscosity immobile bitumen (basement bitumen). As the process
matures, basement bitumen will become heated by conduction from the
production well. After a few years, this bitumen will become
partially mobile and SAGD pressure will need to be reduced to match
reservoir pressure. This can be a delicate balance. SAGD pressures
cannot be too high or a channel may form, (reverse cone) allowing
communication with the bottom water. SAGD steam pressures cannot be
too low either or water will be drawn from the bottom water
(cresting). If this occurs, water production will exceed steam
injection. The higher the pressure drops in the production well,
the more delicate the balance and the more difficult it is to
achieve a balance.
[0089] If the reservoir is inhomogeneous or if the heating pattern
is inhomogeneous, the channel or crests can be partial and the
onset of the problem is accelerated.
[0090] In respect of top water 22 (as best seen in FIG. 8), again,
the issues are similar to interspersed WLZ and bottom water, with
the expectation that top water is also an active water supply. The
problems are similar to bottom water, as above, except that SAGD
wells are further away from top water. So, the initial period--when
the process can be operated at higher pressures than reservoir
pressure--can be extended compared to bottom water. The pressure
drop in the production well is less of a concern because it is far
away from the ceiling. The first problem is likely to be steam
breaching the top water interface. If the top water is active,
water will flood the chamber and may shut the SAGD process
down.
[0091] Industry has the following experience with WLZ [0092] i.
Suncor's Firebag SAGD project and Nexen's Long Lake project each
have reported interspersed WLZ that can behave as thief zones when
SAGD pressures are too high, forcing the operators to choose SAGD
pressures that are lower than desirable (Triangle Three
Engineering, "Technical Audit report, Gas Over Bitumen Technical
Solutions", December 2010). [0093] ii. Water encroachment from
bottom water for SAGD can also cause more well workovers (i.e.
downtime) because of unbalanced steam and lift issues (Jorshari, K.
"Technology Summary", JCPT, March 2011). [0094] iii. Simulation
studies of a particular reservoir concluded that a 3 m standoff (3
m from the SAGD producer to the bitumen/water interface) was
sufficient to optimize production with bottom water, allowing a 1 m
control for drilling accuracy (Akram, F. `Reservoir Simulation
Optimizes SAGD`, American O&G Reporter, September 2010).
Allowing for coring/seismic control, the standoff may be higher.
[0095] iv. Nexen and OPTI have reported that interspersed WLZ
seriously impedes SAGD bitumen productivity and increase SOR beyond
original expectations at Long Lake, Alberta (Vanderklippe, N. "Long
Lake Project hits Sticky Patch", Globe & Mail, Feb. 10, 2011),
(Bouchard, J. et al., "Scratching below the Surface Issues at Long
Lake--Part 2", Raymond James, Feb. 11, 2011), (Nexen Inc. "Second
Quarter Results", press release, Aug. 4, 2011), (Haggett, J et al.,
"Update 3-Long Lake oilsands output may lag targets", Reuters, Feb.
10, 2011). [0096] v. Long Lake lean zones have been reported to
make up from less than 3 to 5% (v/v) of the reservoir (Vanderklippe
(2011)), Nexen Inc (2011)). [0097] vi. Oilsands Quest reported a
bitumen reservoir with top lean zones that are "thin to moderate".
Some areas had a "continuous top thick lean zones" (Oilsands Quest,
"Management Presentation", January 2011). [0098] vii. Johnson
reported Connacher's oil sand project with a top bitumen water lean
zone. The lean zone was reported to differ from an aquifer in two
ways--"the lean zone is not charged and it limited size" (Johnson,
M. D. et al., "Production Optimization at Connacher's Pod One
(Great Divide) Oil Sands Project", SPE 145091-MS, 2011).
[0099] viii. Thimm reported on Shell's Peace River Project,
including a "basal lean bitumen zone". The statistical analysis of
the steam soak process (CSS) showed performance correlated with the
geology of the lean zone (i.e. the lean zone quality was the
important factor). The process chosen took advantage of WLZ
properties, particularly the good steam injectivity in WLZ's
(Thimm, H. F. et al., "A Statistical Analysis of the Early Peace
River Thermal Project Performance", JCPT, January, 1993).
[0100] ix. A cold water injectivity test is a way to potentially
detect connections between SAGD wells and WLZ, top water and/or
bottom water (Aherne, A. L. et al., "Fluid Movement in the SAGD
Process: A Review of the Dover Project", Can. Int'l Pet. Conf.,
Jun. 13, 2006).
[0101] The usual method of SAGD operations control for a
homogeneous reservoir is to first choose an operating pressure, in
excess of the native reservoir pressure P, to try to maximize
bitumen productivity. Then, with the chosen P as a target, the
steam injection rate and pressure is adjusted to attain the
pressure target (pressure control). For reason discussed in the
previous section, if a WLZ is breached, the normal operating
procedure becomes difficult.
[0102] This invention comprises a method to improve, preferably
optimize SAGD performance in WLZ reservoirs (including top water
and bottom water cases) or where the reservoir is a "leaky"
reservoir. A "leaky" reservoir loses injection fluids if operating
P>native reservoir P or has encroachment of fluids if operating
P<native reservoir P. The invention further comprises
measurement of the water recycle ratio (WRR) for reservoirs
containing WLZ zones. WRR is the volume ratio of produced
water/injected steam, where steam injection is measured as a
liquid-water equivalent. Rather than pressure control on steam
injection rates, steam injection should be adjusted to attain a WRR
target for each SAGD well.
EXAMPLE 1
[0103] A simulation of a homogeneous SAGD EOR process--a single
well pair--was conducted with the following key assumptions: [0104]
(1) EXOTHERM.TM. numerical model for SAGD [0105] (2) A homogeneous
Athabasca reservoir with no reservoir impairments [0106] (3)
Generic properties for bitumen [0107] (4) 25 m net pay [0108] (5)
800 m SAGD wells, 100 m spacing, 5 m separation [0109] (6)
10.degree. C. subcool for production control [0110] (7) 3 MPa
pressure for injection control [0111] (8) 4 months start-up period
using steam circulation [0112] (9) Discretized well bore model,
accounting for well bore pressure gradients.
[0113] FIG. 9 shows the predicted performance. As can be seen, the
predicted steam injection rate peaks at 2936 bbls/day and bitumen
production rate peaks at 1002 bbls/day. FIG. 10 shows the predicted
WRR performance. The WRR started around 0.9 and increased gradually
to greater than 0.99 after 1200 days (31/4 years).
[0114] Although not wanting to be bound by this, it is understood
there are two reasons why, for a contained heterogeneous reservoir,
WRR will approach but not exceed 1.0 (except for short excursions),
namely: [0115] (1) Some of the produced bitumen voidage is occupied
by steam to form the steam GD chamber. Assuming this voidage
replacement is done by saturated steam, FIG. 11 shows the
percentage steam injected occupying bitumen voidage as a result of
this. Depending on pressure and SOR, steam vapour can be lost to
recycle in the range of 0.2 to 0.5 percent. If this was the only
factor, one should expect the WRR to trend between 99.5 to 99.8% of
injected steam. [0116] (2) Some of the produced bitumen voidage
will be occupied by liquid water, particularly on the edges of the
steam GD chamber and/or near areas with heat losses (i.e. near the
ceiling). The expectation is this to be dominant near the start of
the SAGD process and tail off as the steam inventory builds. [0117]
(3) Near the end of the SAGD process, bitumen production is low and
SOR increases rapidly. Most of the steam injected is used to
compensate for heat losses. Little or no bitumen voidage is created
and steam/water "short circuits". Again, this is a reason for WRR
to approach 1.0.
[0118] FIG. 10 shows how a WRR-control strategy would work for SAGD
in a homogeneous, sealed reservoir. An early WRR target, up to
about year 2, would be for WRR=0.95. After year 2, the target can
be raised to WRR=0.98.
EXAMPLE 2
[0119] Simulations of a SAGD process in an impaired bitumen
reservoir--with a significant WLZ connecting adjacent SAGD well
pairs--were also conducted. The model used assumed the following:
[0120] (1) EXOTHERM.TM. SAGD numerical model; [0121] (2) 30 m net
pay; dual well pairs (FIG. 12); [0122] (3) WLZ impairment was a
limited lean zone, connecting both SAGD patterns as shown in FIG.
12; [0123] (4) The reservoir was otherwise homogeneous with
K.sub.h=5D ; K.sub.v=2.5D ; S.sub.o=80% in the main reservoir,
S.sub.o=15% in the lean zone; [0124] (5) In the WLZ, S.sub.w=85%;
[0125] (6) In the main reservoir S.sub.w=20%; 15% irreducible, 5%
mobile; [0126] (7) Well length=800 m; well separation=5 m; pattern
spacing=100 m; [0127] (8) Target SAGD P=2000 kPa for both pairs;
[0128] (9) Sub cool target constant for all case studies
(10.degree. C.);
[0129] 5 cases were run (Table 1) and summarized as follows:
[0130] Case 1--Base Case=Same pressure in both well pairs (6 m
thick WLZ with shale cap, WLZ is 10% of pay zone volume);
[0131] Case 2--allow 300 kPa .DELTA.P between well pairs;
[0132] Case 2(a)--extend production forecast to 3 yrs+;
[0133] Case 3--Same as Case 2, but after 1 year stop SAGD pressure
control and shift to constant volume control (steam injection is
constant);
[0134] Case 4--Same as Case 2, but with 3 m thick WLZ (WLZ is 5% of
pay zone volume);
[0135] Case 5--Same as Case 3, but with 3 m thick WLZ;
[0136] FIGS. 13, 14, 15, 16, 17 and 18 show the predicted
performance for each well pair, for Cases 1, 2, 2(a), 3, 4 and 5
respectively. FIGS. 19 and 20 show the cumulative performance of
both well pairs for the above cases. FIGS. 21 and 22 show
cumulative bitumen productivity for Case 1 (Base Case) and Case 2.
FIG. 23 shows WRR performance for Case 3 for each well pair. FIG.
24 shows cumulative WRR performance for Case 1 vs. Case 3. FIG. 25
shows individual well pair bitumen performance for Case 3.
[0137] Based on FIGS. 13-25, the following comments are noteworthy:
[0138] (1) Theoretically, pressure control is adequate for SAGD.
But, in practice it is difficult to measure pressure to a greater
accuracy of about .+-.200 kPa (or about 10%). The hydrostatic head
in a 30 m reservoir is about 335 kPa. Natural, lateral pressure
drops in the production well can be up to over 50 kPa. [0139] (2)
If there are active water zones, a small pressure differential can
make a big difference. A 300 kPa pressure difference was enough to
flood and quench SAGD in a well-pair (FIG. 14) in about 1 year.
[0140] (3) FIG. 15 shows that the quenched well-pair is revitalized
over the long term. However, steam injection had ceased (well pair
1) and steam migrated through the WLZ from well pair 2. In effect,
well pair 1 undergoes a steam flood starting at about 540 days (1.5
years). [0141] (4) The thickness of the WLZ has only a minor effect
on performance. If one compares FIGS. 14 and 17 and FIGS. 16 and
18, the performance factors for each well pair are about the same.
WLZ thickness is not a sensitive factor. [0142] (5) If after well
pair 1 has watered off, steam is injected at a fixed rate in each
well pair, some performance can be recovered (FIG. 16). The process
has switched from pressure control to volume control. An alternate
way to accomplish the same is to switch to WRR control. [0143] (6)
If one focuses on cumulative performance (both well pairs taken
together), FIGS. 19 and 20 show that balanced production Case 1 is
the preferred route. Unbalanced production (.DELTA.P between
wells=300 kPa) results in about half the productivity (FIG. 26).
Productivity can be restored partially by volume or WRR control
(Case 3, Case 5). WLZ thickness (Case 2 vs. Case 4) is not an
important variable. [0144] (7) FIG. 23 shows how volume control
dramatically influences WRR. Alternately, it shows how WRR control
would lead to short-term volume control. [0145] (8) FIG. 24 shows
that WRR profiles are similar for cumulative well pairs (well pair
1+well pair 2). [0146] (9) FIG. 27 shows how efficiency (as
measured by SOR) is improved for the balanced operation.
[0147] For the purposes of this invention, a "leaky" SAGD pattern
is one that produces an unusual amount of water. The "leaky" SAGD
pattern may have water leaks in/out of the pattern volume to other
portions of the reservoir; it may have water leaks to/from an
adjacent reservoir SAGD pattern; or, it may produce unusual water
volumes from WLZ within the reservoir. In order to further define
"leakiness," the WRR will be used as an indicator (the volume ratio
of produced water to steam injected, where steam is measured as a
water-volume equivalent).
[0148] As discussed above, for a homogeneous reservoir without
fluid leaks and without WLZ in the pay zone, FIG. 10 shows the
expected WRR behaviour. In the early SAGD stages (100-300 days),
WRR is between 0.90-0.95. For this period, the GD steam chamber is
forming, and the GD area is heating up. An inventory of liquid
water is created in the reservoir. As the SAGD process continues,
WRR increases gradually from about 0.96 to 0.99. If the bitumen
voidage is occupied by steam only, one would expect WRR to be
greater than 0.99 (FIG. 11). For the later stages of SAGD, bitumen
production (and voidage) is small and the WRR approaches the 0.99
value (FIG. 10). A reasonable target for WRR--for a perfectly
contained SAGD GD chamber and a homogeneous reservoir--during the
peak period of SAGD (500-1500 days) is about 0.97.
[0149] FIG. 23 shows WRR in a leaky reservoir and how a leaky
reservoir is defined. If WRR deviates from 1.0 by more than
.+-.0.10 after 200 or more days of continuous SAGD using normal
pressure control, the reservoir is deemed as "leaky". Using this
definition, the Case 3 simulation WRR performance in FIG. 23 would
result in both well pair patterns deemed as "leaky". Well pair 1
has a higher WRR, and well pair 2 has a lower WRR than the 1.0
control.
[0150] Alternatively, if prior geological knowledge places WLZ, top
water, or bottom water in or adjacent to the SAGD pattern volume
(FIG. 1), the SAGD pattern may be designated as "leaky" or
potentially "leaky".
[0151] Another alternative is to use a cold water injectivity test
to quantify SAGD well connectivity to WLZ, top water, or bottom
water zones (Aherne (2006)). This may also be used to designate a
SAGD pattern as "leaky" or potentially "leaky".
[0152] Pressure control for SAGD (injecting steam volumes to
attain/maintain a target pressure) in a leaky reservoir is not a
good idea. FIGS. 14 and 25 show what can happen for a leaky
reservoir. Well pair 1 (the low P pattern) is flooded with 1) water
from the WLZ and 2) from water condensed from steam injected into
the adjacent well pair 2. After about 1 year, bitumen production is
very small, and SOR is very high. SAGD pressure control shuts off
steam injection into well pair 1 after about 450 days. Well pair 2
(the adjacent, high-P pattern) produces bitumen, but SOR is high.
Eventually, steam from well pair 2 breaks through to well pair 1
(FIG. 15), and production from well pair 1 resumes as a pseudo
steam flood.
[0153] If one compares the cumulative performance for both well
pairs (FIG. 19, Case 2 or Case 4, FIG. 20) to the Base Case (Case
1), one observes that SAGD pressure control, in a leaky reservoir
with WLZ cross flow, has caused the following deficiencies: [0154]
(1) Reduced cumulative bitumen productivity [0155] (2) Reduced
cumulative bitumen recovery [0156] (3) Increased SOR (decreased
efficiency) [0157] (4) Increased water production (water from the
WLZ)
[0158] On the other hand, if one controls pressure in each well
pair so there is little or no cross flow, one would improve and
preferably optimize performance for each well pair and for the
cumulative of both well pairs (Case 1). But, in practice, using
SAGD pressure control may pose to be difficult. Water influx/egress
may occur with small pressure gradients, and it is difficult to set
and measure pressure targets. Pressure has 3 problems-1) where to
measure pressure; 2) the accuracy of pressure measurement; and 3)
choosing the right pressure target. Even for a homogeneous
reservoir, one can expect vertical and lateral pressure differences
as high as 300 kPa (the assumed pressure difference for the
simulation case study). For an active water incursion, pressure
control can be lost entirely. No change in steam injection rate can
significantly affect pattern pressures.
[0159] An alternative control mechanism is to control steam
injection rates, independent of reservoir pressure.
[0160] FIGS. 16 and 18 show that setting steam injection rates at
fixed volumes, even after 1 year of pressure control, can restore
bitumen productivity and improve other performance factors. But, a
somewhat arbitrary and equal setting of volume rate targets may
work partially because both well-pair patterns are homogeneous and
identical expect for the WLZ connecting the patterns for the Cases
studied.
[0161] A more rigorous approach, and a way to account for some
pattern differences, is to use WRR measurement for each pattern as
a way to set targets and to control SAGD in leaky reservoirs, as
follows: [0162] (1) Continually monitor pattern WRR, preferably
weekly. [0163] (2) After more than 200 days of continuous
operation, characterize the pattern reservoir using WRR (leaky or
not). [0164] (3) Set a target WRR (for a near-homogeneous,
contained GD chamber, target WRR .ltoreq.1.0; for a leaky pattern,
target WRR >1.0, to account for water production from WLZ, top
water or bottom water). [0165] (4) If the actual pattern WRR is
less than the target, decrease the steam injection rate until the
target is achieved. [0166] (5) If the actual pattern WRR is greater
than the target, increase the steam injection rate until the target
is achieved. [0167] (6) An overriding consideration is that
measured pressures should not exceed a fraction of reservoir
parting pressure (fracture pressure in a consolidated reservoir). A
fraction of 0.8 is a good safety margin.
[0168] Some preferred embodiments of the present invention further
comprise [0169] (1) Early designation, leaky reservoirs (geology or
water injection test) [0170] (2) Bitumen reservoirs (<10 API,
>100,000 cp) [0171] (3) On-the-fly leaky reservoir
determination, based on WRR performance [0172] (4) Volume control
for steam injection, preferred WRR control [0173] (5) Conventional
SAGD process [0174] (6) Athabasca bitumen [0175] Other embodiments
of the invention will be apparent to a person of ordinary skill in
the art and may be employed by a person of ordinary skill in the
art without departing from the spirit of the invention.
[0176] Tables
TABLE-US-00002 TABLE 1 WLZ Simulation Model Cases Case 1 (Base
Case) 6m thick water lean zone with 2m shale cap SAGD sub-cool
production control Injector P control (2000 kPa) Both well pairs at
2000 kPa Identical reservoirs, homogeneous except for shale or WLZ
Case 2 - (Same as Case 1, except) Pair 2 at 2200 kPa (high
pressure) Pair 1 at 1900 kPa (low pressure) Case 2(a) - (Same as
Case 2, except) extend run length to 3 years Case 3 - (Same as Case
2, except) After 1 year remove P control and inject fixed and equal
steam volumes to each well pair Case 4 - (Same as 2 except) 3m
thick lean zone Case 5 - (Same as 3 except) 3m thick lean zone
TABLE-US-00003 TABLE 2 Lean Zone Thermal Conductivities
[W/m.degree. C.] Lean Zone 2.88 Pay Zone 1.09
TABLE-US-00004 TABLE 3 Lean Zone Heat Capacities Heat Capacity Pay
Zone Lean Zone % Increase (kJ/kg) 1.004 1.254 24.9 (kJ/m.sup.3)
2071.7 2584.7 24.8
* * * * *