Note: Descriptions are shown in the official language in which they were submitted.
CA 02820705 2013-06-27
TITLE OF THE INVENTION
SAGD Control in Leaky Reservoirs
BACKGROUND OF THE INVENTION
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 1000m long, in a vertical plane, separated by about 5m. 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.
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.
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
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by a water zone ¨ causing the reservoir to be "leaky." Also, The Athabasce
bitumen
resource in Alberta, Canada is unique for the following reasons:
(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", Nov. 2010). The in situ EOR
estimate is based on SAGD, or a similar process.
(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.
(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)).
(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 (Figure 1) or less than about
1000m in size. The expectation is that an "average" SAGD EOR process will
encounter several inhomogeneities within each recovery pattern.
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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.
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
The following acronyms will be used herein.
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
Pressure
SAGD Steam Assisted Gravity Drainage
SOR Steam to Oil Ratio
SPE Society of Petroleum Engineers
Temperature
WLZ Water Lean Zone
WRR Water Recycle Ratio
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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.
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.
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.
Preferably, said process further comprises sub-cool control (steam-trap
control) for
liquids production (bitumen + water).
In one embodiment, said volume rate control is instituted by injecting a pre-
set target
volume rate of steam into the SAGD injector well.
In another embodiment, said volume rate control is instituted by
i. Continually measuring WRR for the 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 WRR target is achieved; or
iv. If the actual WRR is greater than the target WRR, increasing the steam
injection rate until the WRR target is achieved.
Preferably, for a near-homogeneous reservoir the target WRR is between 0.9 and
1.0
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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.
In one embodiment, said leaky reservoir is caused by an interspersed water
lean zone
(WLZ) within the net pay zone.
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.
Preferably, said bitumen is a hydrocarbon with < 10 API density and > 100,000
cp
viscosity, at native reservoir conditions.
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.
Preferably, the maximum SAGD pressure allowed is about 80 percent of the
parting
pressure and/or the fracturing pressure.
In another embodiment, the minimum SAGD operating pressure is equal to the
native
reservoir pressure.
In one embodiment, the bitumen reservoir is located in the Athabasca region of
Alberta,
Canada.
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BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 depicts a typical SAGD Well Configuration
Figure 2 depicts SAGD stages
Figure 3 depicts Saturated Steam Properties
Figure 4 depicts Bitumen and Heavy Oil Viscosities
Figure 5 depicts SAGD Productivity per Well
Figure 6 depicts SAGD Hydraulic Limits
Figure 7 depicts Interspersed Bitumen Lean Zones
Figure 8 depicts Top/Bottom Water: Oilsands
Figure 9 depicts SAGD Simulation
Figure 10 depicts WRR Performance for a Homogeneous Reservoir with Contained
SAGD GD Chamber (Single well pair)
Figure 11 depicts Bitumen Voidage and Steam Volumes
Figure 12 depicts Well Pair Cross-Flow Model
Figure 13 depicts SAGD performance Case 1
Figure 14 depicts SAGD performance Case 2
Figure 15 depicts SAGD performance Case 2(a)
Figure 16 depicts SAGD performance Case 3
Figure 17 depicts SAGD performance Case 4
Figure 18 depicts SAGD performance Case 5
Figure 19 depicts SAGD cumulative well pair performance of Cases 1-3
Figure 20 depicts SAGD cumulative well pair performance of Cases 1, 4 and 5
Figure 21 depicts SAGD dual well pair production/performance of Base Case and
Case 2
Figure 22 depicts SAGD pressure control performance of connected well pairs
Figure 23 depicts SAGD WRR performance of connected well pairs Case 3
Figure 24 depicts SAGD WRR performance of connected well pairs Case I and 3
Figure 25 depicts bitumen production of individual well pair Case 3
Figure 26 depicts bitumen production rates of two well pair of Base Case and
Case 3
Figure 27 depicts SOR Performance of Base Case and Case 3
DETAILED DESCRIPTION OF THE INVENTION
SAGD is a bitumen EOR process that uses saturated-steam to deliver energy to a
bitumen
reservoir. Figure 1 shows the basic SAGD geometry, using twin, parallel
horizontal wells
(2, 4)(up to about 1000m 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
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gas, gravity-drainage chamber (Figure 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.
Figure 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.
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.
A SAGD process in a good homogeneous reservoir may be characterized by only a
few
measurements:
(1) Saturated steam T (or P)
(2) Bitumen production rate (the key economic factor), and
(3) SOR ¨ a measure of process efficiency
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.
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
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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 C is a typical sub-cool target. This is also called
steam-trap
control.
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 (Figure 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 (Figure 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.
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 (Figure 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).
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., Sept 2011). Bitumen productivity peaks at = about 1000 bbl/d for
the best
reservoirs, but it can be significantly impaired for the poorer reservoirs
(Figure 27).
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There also may be a hydraulic limit for SAGD (Figure 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 5m
spacing
between wells (2,4), SAGD well lengths are limited to about 1000m.
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:
(1) There is a natural hydrostatic pressure gradient in the net pay region.
For example
for 30m of net pay, the hydrostatic head is about 50 psi (335kPa). Because the
steam chamber is a gas, it is at constant pressure. What operating pressure is
chosen to match reservoir P?
(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?
(3) Pressure control for SAGD is difficult and measurements are inexact. A
pressure
control uncertainty of 200 kPa is to be expected.
The above control methods work well where the steam chamber is contained, even
if the
target pressure is higher than the native reservoir pressure.
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
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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.
Water Lean Zones (WLZ)
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.
Figure 7 depicts an interspersed WLZ 18. When confronted with this situation,
the
following is observed:
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.
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.
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).
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.
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.
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
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retained. But, if the steam exits the GD steam chamber prior to
condensing, both the heat and the water are lost to the process.
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.
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.
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.
With respect to bottom water zones 20, as best seen in Figure 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.
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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.
In respect of top water 22 (as best seen in Figure 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.
Industry has the following experience with WLZ
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", Dec.2010).
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, Mar.2011).
iii. Simulation studies of a particular reservoir concluded that a 3m standoff
(3m from the SAGD producer to the bitumen/water interface) was sufficient
to optimize production with bottom water, allowing a lm control for drilling
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accuracy (Akram, F. 'Reservoir Simulation Optimizes SAGD', American
O&G Reporter, Sept.2010). Allowing for coring/seismic control, the
standoff may be higher.
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).
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)).
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", Jan. 2011).
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).
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
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WLZ's (Thimm, H.F. et al., "A Statistical Analysis of the Early Peace River
Thermal Project Performance", JCPT, Jan., 1993).
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. Intl Pet. Conf., June 13, 2006).
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.
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
A simulation of a homogeneous SAGD EOR process ¨ a single well pair¨was
conducted with the following key assumptions:
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(1) EXOTHERMTm numerical model for SAGD
(2) A homogeneous Athabasca reservoir with no reservoir impairments
(3) Generic properties for bitumen
(4) 25m net pay
(5) 800m SAGD wells, 100m spacing, 5m separation
(6) 10 C subcool for production control
(7) 3 MPa pressure for injection control
(8) 4 months start-up period using steam circulation
(9) Discretized well bore model, accounting for well bore pressure gradients.
Figure 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. Figure
shows the predicted WRR performance. The WRR started around 0.9 and increased
gradually to greater than 0.99 after 1200 days (3 1/4 years).
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:
(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,
Figure 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.
(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.
(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
CA 02820705 2013-06-27
no bitumen voidage is created and steam/water "short circuits". Again, this is
a
reason for WRR to approach 1Ø
Figure 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
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:
(1) EXOTHERMTm SAGD numerical model;
(2) 30m net pay; dual well pairs (Figure 12) ;
(3) WLZ impairment was a limited lean zone, connecting both SAGD patterns as
shown in Figure 12;
(4) The reservoir was otherwise homogeneous with K1, = 5D ; Kv = 2.5D; So =
80%
in the main reservoir, Se, = 15% in the lean zone;
(5) In the WLZ, Sw = 85%;
(6) In the main reservoir Sw = 20%; 15% irreducible, 5% mobile;
(7) Well length = 800m; well separation = 5m; pattern spacing = 100m;
(8) Target SAGD P = 2000 kPa for both pairs;
(9) Sub cool target constant for all case studies (10 C);
cases were run (Table 1) and summarized as follows:
Case 1 ¨ Base Case = Same pressure in both well pairs (6m thick WLZ with shale
cap,
WLZ is 10% of pay zone volume);
Case 2 ¨ allow 300 kPa AP between well pairs;
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Case 2 (a) ¨ extend production forecast to 3 yrs +;
Case 3 ¨ Same as Case 2, but after 1 year stop SAGD pressure control and shift
to
constant volume control (steam injection is constant);
Case 4 ¨ Same as Case 2, but with 3m thick WLZ (WLZ is 5% of pay zone volume);
Case 5 ¨ Same as Case 3, but with 3m thick WLZ;
Figures 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. Figures 19 and 20 show the
cumulative
performance of both well pairs for the above cases. Figures 21 and 22 show
cumulative
bitumen productivity for Case 1 (Base Case) and Case 2. Figure 23 shows WRR
performance for Case 3 for each well pair. Figure 24 shows cumulative WRR
performance for Case 1 vs. Case 3. Figure 25 shows individual well pair
bitumen
performance for Case 3.
Based on Figures 13-25, the following comments are noteworthy:
(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 30m reservoir is about 335 kPa. Natural,
lateral
pressure drops in the production well can be up to over 50 kPa.
(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 (Figure 14) in about 1 year.
(3) Figure 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).
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(4) The thickness of the WLZ has only a minor effect on performance. If one
compares Figures 14 and 17 and Figures 16 and 18, the performance factors for
each well pair are about the same. WLZ thickness is not a sensitive factor.
(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 (Figure 16). The process has switched
from pressure control to volume control. An alternate way to accomplish the
same
is to switch to WRR control.
(6) If one focuses on cumulative performance (both well pairs taken together),
Figures 19 and 20 show that balanced production Case 1 is the preferred route.
Unbalanced production (AP between wells = 300 kPa) results in about half the
productivity (Figure 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.
(7) Figure 23 shows how volume control dramatically influences WRR.
Alternately,
it shows how WRR control would lead to short-term volume control.
(8) Figure 24 shows that WRR profiles are similar for cumulative well pairs
(well
pair 1 + well pair 2).
(9) Figure 27 shows how efficiency (as measured by SOR) is improved for the
balanced operation.
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).
As discussed above, for a homogeneous reservoir without fluid leaks and
without WLZ in
the pay zone, Figure 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
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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 (Figure 11). For the later stages of SAGD, bitumen
production (and
voidage) is small and the WRR approaches the 0.99 value (Figure 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.
Figure 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 Figure 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.
Alternatively, if prior geological knowledge places WLZ, top water, or bottom
water in
or adjacent to the SAGD pattern volume (Figure 1), the SAGD pattern may be
designated
as "leaky" or potentially "leaky".
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".
Pressure control for SAGD (injecting steam volumes to attain/maintain a target
pressure)
in a leaky reservoir is not a good idea. Figures 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
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pair 2 breaks through to well pair I (Figure 15), and production from well
pair 1 resumes
as a pseudo steam flood.
If one compares the cumulative performance for both well pairs (Figure 19,
Case 2 or
Case 4, Figure 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:
(1) Reduced cumulative bitumen productivity
(2) Reduced cumulative bitumen recovery
(3) Increased SOR (decreased efficiency)
(4) Increased water production (water from the WLZ)
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.
An alternative control mechanism is to control steam injection rates,
independent of
reservoir pressure.
Figures 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.
CA 02820705 2013-06-27
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:
(1) Continually monitor pattern WRR, preferably weekly.
(2) After more than 200 days of continuous operation, characterize the pattern
reservoir using WRR (leaky or not).
(3) Set a target WRR (for a near-homogeneous, contained GD chamber, target WRR
< 1.0; for a leaky pattern, target WRR > 1.0, to account for water production
from
WLZ, top water or bottom water).
(4) If the actual pattern WRR is less than the target, decrease the steam
injection rate
until the target is achieved.
(5) If the actual pattern WRR is greater than the target, increase the steam
injection
rate until the target is achieved.
(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.
Some preferred embodiments of the present invention further comprise
(1) Early designation, leaky reservoirs (geology or water injection test)
(2) Bitumen reservoirs (<10 API, >100,000 cp)
(3) On-the-fly leaky reservoir determination, based on WRR performance
(4) Volume control for steam injection, preferred WRR control
(5) Conventional SAGD process
(6) Athabasca bitumen
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.
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Tables
Table 1:
WLZ Simulation Model Cases
Case I (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
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Table 2:
Lean Zone Thermal Conductivities
[W/m C]
Lean Zone 2.88
Pay Zone 1.09
Where:
1. Lean zone = 80% water saturation; pay zone = 80% oil saturation
2. 4) =0.35
3. Algorithm as per Butler (1991) for sandstone (quartz) reservoir.
Table 3:
Lean Zone Heat Capacities
Heat Capacity Pay Zone Lean Zone % Increase
(kJ/kg) 1.004 1.254 24.9
(kJ/m3) 2071.7 2584.7 24.8
Where:
1. Uses Butler's algorithms for (p of bitumen, water, sandstone (Butler
(1991)).
2. Assumes API = 8.0 S.G. = 1.0143
3. Assumes T = 25 C
4. Pay zone = 35% porosity with 80% bitumen saturation
5. Lean zone = 35% porosity with 80% water saturation
23
