Note: Descriptions are shown in the official language in which they were submitted.
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TITLE OF THE INVENTION
Thermal Pulsing Procedure for Remediation of Cold Spots in Steam Assisted
Gravity
Drainage
Background
Steam Assisted Gravity Drainage ("SAGD") is currently the dominant in situ
enhanced oil
recovery ("EOR") process to recover bitumen from Canadian oil sands. SAGD has
two parallel
horizontal wells (a producer well and a steam injector well), about 5 metres
apart, with the lower
producer well completed in the pay zone, close to the bottom of the pattern
recovery zone, and a
steam injector well above the lower producer well. The pattern recovery zone
volume is about
100 metres wide (100 metres spacing) and up to 1000 metres long (1000 metres
well length).
SAGD is executed in 3 phases¨(i) at least one start-up phase, where steam
circulation from the
steam injector well and production well is used to establish communication
between the parallel
horizontal wells; (ii) at least one ramp-up phase where a steam chamber is
formed in the pattern
recovery zone and grows both laterally and vertically until it hits the pay
ceiling; and (iii) a
wind-up phase where vertical growth is stopped by the pay ceiling but lateral
growth continues
and productivity slows down as the slope of the chamber walls decrease.
In the at least one ramp-up phase of SAGD, there are 3 measures of
performance, namely the
steam-to-oil ratio ("SOR") (a measure of energy efficiency); bitumen
productivity; and water
return ratio (how much steam injected is returned as produced water). The
dominant economic
factors, in descending order, are: bitumen productivity; start-up time before
SAGD can be
started; SOR; and water return ratio.
Because SAGD is a saturated-steam process wherein temperature and pressure are
linked, an
operator will always have a strong incentive to operate SAGD at the highest
pressure possible,
even if the operating pressure is higher than native reservoir pressure (i.e.
overpressure
operation). The reason is simple. At higher pressure saturated steam
temperature is higher and
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bitumen is heated to a higher temperature, reducing viscosity significantly,
allowing for ease of
flow of bitumen. Bitumen viscosity is a strong function of temperature.
Bitumen productivity is
proportional to the inverse square root of viscosity (Butler (1991)), so
higher pressure results in
higher bitumen productivity¨the dominant economic factor. The choice of
increasing
temperature in SAGD may reduce process efficiency for two reasons. Since
bitumen is produced
at/near saturated steam temperature, it is predominantly the latent heat of
steam that drives the
SAGD process. As pressure and temperature are increased, the latent heat
content in saturated
steam drops, so efficiency is lost. Also, at higher temperature and pressure
conditions, the
reservoir matrix requires heating to higher temperatures. This increased heat
demand also
reduces efficiencies.
Bitumen reservoirs may be characterized by their hydraulic behaviour as
follows:
(1) Type A bitumen reservoir -- is essentially homogeneous, with no
bottom/top water, no top
gas, no lean zones and few shale baffles. Prior to bitumen production, water
injection
tests (Aherne, A.L. et al 'Fluid Movement in the SAGD Process: A Review of the
Dover
Project', Can. 1nel Pet. Conf., June 13, 2006) show no/little injectivity into
the pay zone.
A typical SAGD steam chambers is regular-shaped and pressure contained. Over-
pressurization (i.e. operating SAGD at pressures greater than native reservoir
pressure) is
feasible and it is the normal procedure.
(2) Type B bitumen reservoir ¨ exhibits some heterogeneities (shale baffles,
lean zones...)
but there is no "active" water from lean zones, and no "active" water from
bottom/top
water. There are "limited" lean zones and/or "limited" water incursion. SAGD
steam
injection volumes, at peak, arc about 500m3/d so "significant" water incursion
is more
than about 50m3/d (i.e. -active" water zones). Prior to bitumen production,
water
injection tests show some injectivity (i.e. linked to a "limited" water zone).
The degree of
impact of water incursion and/or water recharge rates is also a function of
pressure. At
higher SAGD operating pressure compared to native reservoir pressure, water
loss/recharge may become more significant. Over pressure operation of SAGD may
be
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feasible, but with increasing fluid losses. The usual remedy to reduce fluid
losses is to
reduce SAGD operating pressures to/near native reservoir pressure.
(3) Type C bitumen reservoir ¨ has significant active water zones from either
bottom/top
water or lean zones---that may act as thief zones during SAGD. Prior to
production, water
injection tests show significant injectivity (connection to active water
zones). Fluid loss
rates or recharge rates arc greater than about 50m3/d. Overpressure SAGD
operation is
not possible. SAGD must be operated at/near native reservoir pressure. Even
then,
operation may be difficult if natural pressure gradients (i.e. pressure
differentials in the
production well or pressure differentials produces as a result of formation of
a gas gravity
drainage chamber) cause influx or egress of significant fluid volumes.
Given the above reservoir categorization by hydraulic behaviour, the type of
classification of each reservoir is sensitive to hydraulic factors. For
example, at lower
SAGD pressure a Type B reservoir may behave like a Type A reservoir. Also,
reservoir
types above may change as a SAGD project matures, particularly if the growing
steam
chamber encounters an active water zone or even a limited water zone.
The objective of the SAGD start-up phase is to establish communications
between the
two horizontal wells and to heat/mobilize the bitumen between the wells,
uniformly to a
target temperature, usually about 100 C. The start-up phase is accomplished by
circulating steam in both the upper (injector) and lower (producer) horizontal
wells. The
start-up may also be broken into phases. If steam is injected at the well
heel, for
circulation, the first hurdle is to reach steam temperature at the well toe.
To reach steam
temperature it may take, at least, a few days (Vanegas (2006)). Then steam
injection/circulation is continued for several weeks (or a few months), with
both wells at
the same pressure. Heat is transferred to the reservoir by conduction. Then,
the operator
may establish a pressure differential between upper/lower wells, while still
circulating
steam in each well, with the upper well at the higher pressure. This well
pressure
differential is modest (-100 Kpa), so preferential flow channels are not
created. The
objective is to add a convection mechanism to heat transfer to speed up
communications
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(Vanegas P. et al, 'Impact of Operational Parameters and Reservoir Variables
during the
Start-up Phase of a SAGD Process', Pet. J. Online, Nov. 16, 2006, Yuan, J.Y.
et al
'Evaluation of Steam Circulation Strategies for SAGD Start-up' Can. Int'l.
Pet. Conf.,
Calgary, June 16, 2009, and Parmar, G. et al, 'Start-up of SAGD Wells: History
Match,
Wel lbore Design and Operation', JCPT, Jan. 2009).
After a few (several) months, SAGD may be started by injecting steam only in
the upper
well (injector) producing hot fluids in the lower well (hot bitumen +
condensed steam). In
SAGD, the start-up phase time is longer for reservoirs with heavier, more
viscous
bitumen. A small steam chamber is formed and the ramp-up SAGD phase starts and
matures as the chamber grows upward and outward. Production increases as the
chamber
grows and peaks when the ceiling of the pay zone is reached.
For a Type A reservoir, operating control for SAGD is simple. The operator
chooses a
pressure target, which can be higher than native reservoir pressure. Pressure
is monitored
by down-hole sensors. The steam injection rate is adjusted to attain pressure
target. The
production rate is controlled (electric submersible pump ("ESP") or gas lift)
to meet a
temperature target in the production well, monitored by down-hole
thermocouples. The
temperature target is set at a sub-cool target compared to saturated steam
temperature in
the reservoir (usually 10 ¨ 20 C sub-cool), to ensure that the production well
is producing
only liquids (bitumen + water) and not live steam. Sub-cool is the difference
between
the saturated steam temperature at the producer pressure and the actual
temperature at
where pressure is measured. This is also called steam-trap control
(VanderValk, P.A. et
al 'Investigation of Key Parameters in SAGD Wellbore Design and Operation',
JCPT,
June, 2007).
For type B and/or C reservoirs, steam-trap control may be much more difficult.
Overpressure operation of SAGD may not be feasible. If cold water or cold
spots are in
part of the production well (or producer well), steam-trap control may be
lost. For
homogeneous SAGD operation, if production is increased, temperature in the
production
well will also increase as hotter production fluids or some steam are drawn to
the
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production well. This directionality is used as the basis of steam-trap
control. If there is a
cold zone in the production well formed as the result of reservoir water
incursion, and if
production rate is increased, temperature in the production well may drop if
more cold
water is drawn in.
In an ideal world, during SAGD at the end of the start-up phase and in the
early ramp-up
phase, there would be a homogeneous distribution of heat in the reservoir and
a flat
temperature profile in the production well. Each segment of the reservoir
would
contribute equally to bitumen production. Steam chamber shape would be smooth
and
regular. Unfortunately, homogeneous production for SAGD is rare, even for Type
A
reservoirs, for the following reasons:
(I) Steam circulation during start-up is not homogeneous throughout the well.
Most heat
is delivered to the well heel.
(2) Bitumen reservoirs may have gross inhomogeneities ¨top/bottom water, top
gas, shale
baffles, shale barriers, lean zones... etc.
(3) Bitumen reservoirs may also have subtle inhomogeneities¨lateral and
vertical
permeability variations, porosity variations, matrix composition--that may
influence
conformance.
(4) A pressure gradient (between the parallel horizontal wells) used during
the start-up
phase may create high-permeability channels that transport steam, bitumen,
water and
heat between the parallel horizontal wells.
(5) Bitumen properties are not homogeneous within a reservoir. Vertical and
lateral
variation of bitumen quality may be significant and variations may easily
influence
start-up and ramp-up conformance (Larter, S. 'Viscous Variations and Asphaltic
Aspirations', Gushor Inc. Newsletter, Oct., 2010).
(6) Lean zones, where bitumen saturation is low, water saturation is high and
water has
some mobility, are a particular concern (Vanderklippe, N. 'Long Lake Project
hits
Sticky Patch', Globe & Mail, Feb. 10, 2011, Reuters, 'Update 3 ¨ Long Lake Oil
Sands, Output may lag Targets', Feb. 10, 2011). Many operators are concerned
about
lean zone effects (Oilsands Quest, 'Axe Lake, SAGD Test Horizontal Well Pair
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Configuration: Project Summary Document', July 14, 2010, Peterson, J.A. et at,
'conducting SAGD in Shoreface Oil Sands with Associated Basal Water', Laricina
Energy, 2009, Oilsands Quest, 'Management Presentation', Jan. 2011, Akram, F.
'Reservoir Simulation Optimizes SAGD', O&G Reporter, Sept. 2010, and Johnson,
M.D. et al, `Production Optimization at Connacher's Pod One (Great Divide) Oil
Sands Project', SPE Conf., July 19, 2011).
If start-up or ramp-up phases have created or established non-homogeneous heat
distribution, a
manifest measurement of the condition is -cold spots" in the production well.
If cold spots are
formed, they can be surprisingly resilient (Larter (2010)). In the ramp-up (or
wind-up) phase of
SAGE) the operator has limited tools to remediate the "cold spots" (VanderValk
(2007)). Sub-
cool may be varied, injection tubing size may be varied (or insulated), or
pressure targets may be
altered. These remedies are not very successful.
There is need for a method to remediate cold spots in the production well, and
in particular a
production well undergoing SAGD.
SUMMARY OF THE INVENTION
SAGD is now the dominant in-situ EOR process to recover bitumen from Canadian
oil sands.
SAGD comprises two parallel horizontal wells, about five metres apart,
completed near the
bottom of a bitumen reservoir. The upper well continuously injects steam and
the lower well
produces heated bitumen and condensed steam (water). For a healthy process,
all parts of the
producer well should be hot and contribute to production. If cold spots form
in this well it is an
indication of reduced productivity and poor conformance.
According to one aspect of the invention, there is provided a procedure to
heat up at least one
cold spot, preferably a plurality of cold spots, in a producer (or production)
well of a SAGD
process, to increase production and improve conformance by introducing a
"thermal pulse
procedure" to the SAGD process. The thermal pulse procedure (TP13) comprises
shutting in the
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producer well, increasing or maintaining steam injection rates from a steam
injector well,
opening up the producer well and reinstating normal SAGD operation.
According to another aspect of the invention there is provided a method for
remediation of at
least one cold spot in a SAGD process, said SAGD process comprising a steam
injector well, a
production well, a steam chamber, and at least one cold spot, preferably a
plurality of cold spots,
proximate said production well, the remediation method comprising:
(1) shutting the production well;
(2) maintaining or increasing steam injection through the steam injector well
until
pressure in the steam chamber increases, preferably less than or equal to a
0.3 MPa
increase, more preferably up to a 0.5 MPa increase;
(3) resuming the production well while continuing steam injection through the
steam
injector well at rates for normal SAGD or greater, until reservoir pressure
reaches
normal operational pressure; and optionally
(4) adjusting injection/production to return to normal SAGD operation;
This remediation method increases hydrocarbon recovery from a hydrocarbon
deposit. Typically
when adjusting steam injection, the following parameters are adjusted: steam
injection rate to
reach and/or maintain a preferred pressure target. Typically, when adjusting
the producer well,
fluid withdrawal rate from the producer well is adjusted to reach and/or
maintain a preferred sub
cool target.
According to yet another aspect of the invention, there is provided an
improvement in Steam
Assisted Gravity Drainage (-SAGD") for increasing hydrocarbon recovery from a
bitumen
reservoir, wherein said SAGD comprises at least one steam injector well, at
least one producer
well with at least one cold spot, and at least one steam chamber, said
improvement comprising:
(1) shutting the at least one producer well;
(2) maintaining or increasing steam injection through the at least one steam
injector well
until pressure in the at least one steam chamber increases, preferably less
than or
equal to a 0.3 MPa increase, more preferably up to a 0.5 MPa increase;
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(3) resuming the at least one producer well while continuing steam injection
through the
at least one steam injector well at rates for normal SAGD or greater, until
bitumen
reservoir pressure reaches normal operational pressure; and optionally
(4) adjusting injection/production to return to normal SAGD operation
hi a preferred embodiment, the at least one cold spot has a temperature of
about 10 C to about
20 C lower than SAGD sub-cool targets, more preferably at least 20 C lower
than SAGD sub-
cool targets. Preferably said sub-cool target in SAGD is in the range of from
about 0 C to about
25 C. more preferably from about 5 C to about 20 C. In yet another preferred
embodiment, the
cold spots are formed by cold water incursion from the reservoir water zone,
preferably the water
recharge rates from the reservoir water zone are less than about 500 m3/d,
more preferably less
than about 50 m3/d.
Preferably, said bitumen reservoir is selected from the group consisting of a
homogenous Type A
reservoir, heterogeneous Type B reservoir, Type C reservoir and mixtures
thereof
Preferably said at least one cold spot is monitored at some point, preferably
throughout said
process.
More preferably, said remediation process is carried out during the ramp-up
phase of SAGD.
BRIEF DESCRIPTION OF ITIE FIGURES
Figure 1 depicts a typical SAGD Well Configuration known in the art.
Figure 2 depicts a typical ramp-up phase in a SAGD process.
Figure 3 depicts a typical wind-up phase in a SAGD process.
Figure 4 depicts Saturated steam properties.
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Figure 5 depicts steam injection rates, electrical submersible pump rates of
bitumen and water,
and well heel temperatures when incorporating one embodiment of the present
invention.
Figure 6 depicts well heel temperature response when incorporating an
embodiment of the
present invention.
Figure 7 depicts the Steam to Oil Ratio (SOR) and Oil rates when incorporating
an embodiment
of the present invention.
Figure 8 depicts the Oil rates when incorporating an embodiment of the present
invention.
Figure 9 depicts well pair performance over a period of 4 years when
incorporating an
embodiment of the present invention.
Figure 10 depicts a proposed well pair configuration and monitoring layout
according to one
embodiment of the invention
DETAILED DESCRIPTION OF THE INVENTION
According to Figure 1, as discussed above, Steam Assisted Gravity Drainage
("SAGD") is
currently the dominant in situ enhanced oil recovery ("FOR") process to
recover bitumen from
Canadian oil sands. SAGD has two parallel horizontal wells (a producer well
(10) and a steam
injector well (20)), about 5 metres apart, with the lower producer well (10)
completed in the pay
zone (30), close to the bottom of the pattern recovery zone (40), and a steam
injector well (20)
above the lower producer well (10). The pattern recovery zone (40) volume is
about 100 metres
wide (100 metres spacing) (50) and up to 1000 metres long (1000 metres well
length).
SAGD is executed in 3 phases--(i) a start-up phase, where steam circulation
from the steam
injector well is used to establish communication between the parallel
horizontal wells; (ii) a
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ramp-up phase (as best seen in Figure 2) where a steam chamber (60) is formed
in the pattern
recovery zone (70)) and grows both laterally (61) and vertically (62) until it
hits the pay ceiling
(80); and (iii) a wind-up phase (as best seen in Figure 3) where vertical
growth is stopped by the
pay ceiling (80) but lateral growth continues and productivity slows down as
the slope of the
chamber walls (61) decrease.
As discussed above, the choice of increasing temperature in SAGD may reduce
process
efficiency for two reasons. Since bitumen is produced at/near saturated steam
temperature, it is
predominantly the latent heat of steam that drives the SAGD process. As
pressure and
temperature are increased, the latent heat content in saturated steam drops
(as best seen in Figure
4), so efficiency is lost. Also, at higher temperature and pressure
conditions, the reservoir matrix
requires heating to higher temperatures. This increased heat demand also
reduces efficiencies.
The "thermal pulse" remediation process (TPP) of the present invention may be
applied to a
SAGD process with at least one cold spot in a production well, as follows:
(1) shut-in the production well;
(2) increase or maintain steam injection rates;
(3) when pressure increases up to about 0.5 MPa (a few days or a week),
produce the
production well at/near maximum rates (gas lift or ESP) for a few days, up to
about I
week; and
(4) Restart normal SAGD operations optionally monitoring the at least one cold
spot
temperature.
Although not wanting to be limited by the following, it is believed the
invention is effective due
to as follows:
a. during the shut-in/steam injection phases ((I) and (2) above), steam will
displace water in
the zone proximate the at least one cold spot;
b. hot 'production fluids (hot bitumen + condensed steam) builds up at/near
the bottom of
the steam chamber;
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c. during the production phase (3) above), steam is removed quickly from the
water zone
creating a cold spot and before recharging by cold water can occur, hot
production fluids
(hot bitumen + condensed steam) will be drawn into the zone with the cold
spot; and
d. the hot production fluids inhibit recharging by cold water.
The present invention relies firstly on a slow/limited recharge rate of cold
water and a fast
saturation with hot production fluids. Secondly, the remediation based on the
present
invention may be temporary or permanent depending on the reservoir type and
operating
strategy following remediation. Thirdly, if the water recharge rate is rapid
(i.e. Type C
reservoir) the present invention may not produce ideal results. Fourth, the
present invention
relies on ability to increase reservoir pressure. Again, this condition may
not produce ideal
results for a Type C reservoir.
Example 1
(1) A field test of the thermal pulse process (TPP) according to the present
invention in a
SAGD well pair near Long Lake, Alberta was conducted over a period of two
days. The
pressure pulse for the test was about 260 kPa during the two day test. Prior
to the test, the
steam injector pressure was about 2000 kPa (saturated steam temperature= 213
C).
Figures 5-8 show process measurements over the two day testing period.
As best seen in Figure 5, prior to incorporating the remediation process in an
existing SAGD
well pair, the thermocouples in the heel of the producer well registered
temperatures from about
140 C to 160 C. Given the temperature of saturated steam is about 2I3 C, the
temperature
fluctuation of from about 140 C to 160 C indicates a cold spot is present in
the heel of the
producer well, given the heel zone is expected to be hot given the heel zone
is the first zone to
receive steam and collects all the production fluids. It is also observed that
subsequent to the
remediation process, the heel temperature rose quickly to between 180 C and
190 C and this
increased temperature was maintained for a period of time. As best seen in
Figures 6, 7, 8 and
9, the oil recovery rate increased concurrently with remediation of the cold
spot. Referring now
to Figures 7 and 9, the SOR varies considerably. Figure 9 shows the total
history of the well
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pair prior to, during, and post testing. SAGD was initiated in Jan 2008. The
SAGD pair was in
the ramp-up phase of SAGD. As best seen in Figure 10, the instrumentation in
the well pair (10,
20) is shown, including 6 thermocouples (90) in the production well, pressure
measurement at
the producer heel (100) and toe (110) and at the injector heel (120)
subsequent to implementation
of the present invention.
It is clear from the above that the current invention increases productivity
in SAGD processes
when a producer well has at least one cold spot.
Preferably, when incorporating the present invention in a type B reservoir, it
is preferred that
there are limited leaks and there is some ability to increase pressure; when
incorporating the
present invention during the ramp-up phase of SAGD, it is preferred to
remediate the cold spot(s)
as early as possible; it is preferred to limit repressurization to no more
than about -1-0.5MPa; and
the cold spot in the production well is preferably greater than about 10 C
below sub cool target
temperature.
As many changes can be made to the preferred embodiment of the invention
without departing
from the scope thereof; it is intended that all matter contained herein be
considered illustrative of
the invention and not in a limiting sense.
