Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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MODIFIED STEAM AND GAS PUSH WITH ADDITIONAL
HORIZONTAL PRODUCTION WELLS TO ENHANCE
HEAVY OIL / BITUMEN RECOVERY PROCESS
FIELD OF THE INVENTION
This invention is related to the recovery of hydrocarbons such as heavy
oil or bitumen from an underground formation, using a combination of steam-
assisted
gravity drainage, modified steam and gas push, and additional production
wells.
PRIOR ART
1.0 Steam-assisted gravity drainage ("SAGD") is the process commonly
employed in commercial projects for hydrocarbon recovery from heavy oil and
bitumen deposits. The SAGD process, based on Canadian Patent 1130201, makes
use of a pair of essentially parallel horizontal wells, separated by a short
vertical
distance (typically 4 ¨ 10 m), to recover immobile oil at initial reservoir
conditions.
Steam is injected into the oil reservoir continuously from the top horizontal
well and
the heated oil in the reservoir drains by gravity from the reservoir into the
bottom
horizontal well. During the start-up phase, steam is normally circulated
within both
wells to heat up the region between the wells and thereby render the oil
mobile.
Continuous steam injection and production of oil and steam condensate during
the
SAGD phase results in the formation of a steam chamber, from which most of the
oil
has drained.
A modification of SAGD to improve the thermal efficiency of the process
was suggested by Butlerl. Consider SAGD carried out at a (nearly) constant
steam
chamber pressure. The entire steam chamber has to be maintained at the high
temperature corresponding to the chamber pressure (typically 200 to 250 C) by
steam injection. Butler's idea was to reduce the temperatures in the top
portion of
the chamber, but maintain the high temperature near the SAGD well pair in
order to
minimize the tendency for gas coning into the producer. This may be
accomplished
by co-injection with steam of a small quantity (typically less than 1 mole
percent) of
non-condensable gas, typically natural gas which is readily available in the
field, but
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also nitrogen, methane, or any other non-condensable gas (collectively,
"NCG"). He
called the modified process "Steam and Gas Push" or "SAGP". Unlike steam, the
NCG can travel large distances (since it does not condense) and convey the
pressure of the steam/NCG chamber, thereby providing pressure support and
facilitating gravity drainage of oil.
The NCG accumulates near the top of the chamber and reduces the
partial pressure of steam. This results in temperature reduction (as compared
to
SAGD) in the region of NCG accumulation. This NCG and steam mixture provides
some insulation near the top of the reservoir which in turn reduces heat
losses to the
overburden.
As originally conceived by Butlerl, in SAGP NCG co-injection begins at
the initiation of the production process, immediately following the initial
steam
circulation period. NCG fingers quickly move to the top of the pay zone during
the
chamber rise period. The pressure support provided by the fast-moving NCG
tends
to increase the oil flow rate by accelerating the gravity drainage process. At
the
same time, the colder temperatures in the top region for SAGP tend to decrease
the
oil flow rate. Based on laboratory results (as shown in Figure 14 on p. 57 of
Ref. 2),
in the chamber rising phase the production rates for SAGP are approximately
the
same as for SAGD with reduced steam requirements. However, once the bulk of
the
chamber reaches the top of the reservoir, there is a risk that the SAGP oil
rates could
become progressively lower as compared to SAGD. To minimize the possibility of
reduced oil rates for SAGP during the spreading phase, a modification of SAGP
is
proposed in this invention.
Another advantage of SAGP is that it provides more flexibility in
selecting operating pressures. There are situations for which the chamber
pressure
of SAGD cannot be reduced below the initial pressure of the reservoir. For
example,
if bottom water is present, the chamber pressure must be maintained close to
the
bottom water pressure to prevent the incursion of water into the chamber. SAGP
circumvents this limitation by lowering the steam partial pressure without
reducing the
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total pressure of the steam/NCG chamber. SAGP thus provides the opportunity to
decrease individual well instantaneous steam-oil ratio ("ISOR") and thereby
free up
steam for redeployment in other wells. By applying this strategy, it is
possible to
achieve overall oil production rates above design capacity without increasing
the
steam generation capacity of the project.
Other processes to improve the thermal efficiency of SAGD are
described in Canadian Patents 2277378 and 2591498. In Patent 2277378, a SAGD
well pair is supplemented by a horizontal "offset" well located at the
elevation of the
SAGD producer. The offset well begins operation in the cyclic steam
stimulation
("CSS") mode after the SAGD well pair has undergone a few years of operation.
Once fluid communication is established between the SAGD well pair and the
offset
well, CSS is discontinued at the offset well. The offset well then becomes a
full time
producer. A small amount of nitrogen or methane may also be injected with the
steam in the SAGD injector after the fluid communication between the SAGD well
pair and the offset well is established. Based on reservoir simulation
results, it was
claimed that the process in Patent 2277378 resulted in increased oil rates,
oil
recovery and reduced steam consumption as compared to SAGD.
The well arrangement in Patent 2591498 consists of an infill well drilled
between two adjacent SAGD well pairs. Separate mobilized zones are created
initially using SAGD at each of the SAGD well pairs. Over a period of time,
the two
mobilized zones merge to form a common mobilized zone. A bypassed region of
oil
is then formed beneath the common mobilized zone between the adjacent well
pairs.
The main objective of the infill well is to recover this bypassed oil, after
the common
mobilized zone has been formed, substantially by gravity drainage. Based on
reservoir simulation results, the process in Patent 2591498 is claimed to
reduce the
cumulative steam-oil ratio ("CSOR") significantly, and increase the calendar
day oil
rate, for a given oil recovery, as compared to SAGD.
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SUMMARY OF THE INVENTION
A purpose of the present invention is to further enhance the thermal
efficiency of SAGD and SAGP while maintaining high oil recovery. Referring to
Figure 1, the invention in one embodiment requires two horizontal injector-
producer
well pairs 50, 60, of the type used in SAGD schemes (commonly referred to as
"adjacent well pairs"). The elevation is nearly the same for the two injectors
30, 31,
and for the two producers 40, 41. A horizontal well, herein referred to as an
"additional producer" 70, is placed at or near the elevation of the producers
40, 41 of
the adjacent well pairs 50, 60, approximately midway between those producers
40,
io 41. The two well pairs 50, 60 are initially operated, for example in a
SAGD mode,
with steam injection through the injectors 30, 31 and oil production from the
producers 40, 41. This operation results in the formation of steam chambers
55, 65
around the two well pairs 50, 60. The steam chambers 55, 65 are allowed to
rise to
the top 15 of the pay zone 20 and spread sideways. It is to be understood
that, while
is a SAGD process is used as the example, the invention may be practiced in
any
suitable setting which involves injection of thermal energy into a reservoir
containing
hydrocarbons, such as heavy oil, or bitumen (any of which are referred to as
"Oil").
In another embodiment, the present invention provides an in situ
recovery process for Oil in an underground reservoir comprising the steps of:
drilling
20 a SAGD well pair, with associated steam generation, injection, and
production
facilities, with facilities for co-injection of NCG; drilling a second,
essentially parallel
and adjacent, well pair; and producing Oil from the well pairs using a SAGD
process
until the average temperature of a producible adjacent volume of the reservoir
outside the chamber reaches a temperature which permits included Oil to be
25 mobilisable; and then co-injecting NCG with steam into the injector of
at least one
well pair.
In another embodiment, adding the further steps of drilling an additional
horizontal well essentially parallel with and equidistant from the producers
of the
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adjacent well pairs; and producing the Oil using the additional horizontal
well, without
or prior to co-injecting NCG.
In yet another embodiment, production of the Oil using the additional
horizontal well follows or is contemporaneous with co-injection of NCG. If the
additional horizontal well does not produce at satisfactory rates, stimulation
of the
additional horizontal well will be carried out prior to production.
In any embodiment, the average temperature of the producible Oil
adjacent to the chambers is within the range of temperature required to alter
viscosity
of the heavy oil/ bitumen being specific to the type of heavy oil/bitumen to
be
1.0 produced. In the case of typical Athabasca bitumen, the range is
between about 60
and 100 C, while the temperature range will be lower for the less viscous
Cold Lake
type of bitumen.
The process is workable when the viscosity of the Oil becomes
producible, below approximately 10,000 mPa.s and preferably below about 2,000
mPa.s.
The invention may also be economic where the heat injection process
is not SAGD or SAGP but is another method of increasing temperature of the
reservoir in situ.
The present invention makes use of the heat stored in the reservoir 20
to improve the thermal efficiency of SAGD, without requiring the two SAGD
chambers
55, 65 to merge. The average temperature in the Oil between the adjacent
chambers
90 may be estimated from the cumulative Oil production and steam injection. As
the
average temperature of the Oil in the region 90 continues to increase, the
viscosity of
the initially immobile Oil will be reduced to a point where it is mobile
enough to be
produced from the additional producer 70, using methods that are commonly used
to
produce heavy oil. In the case of typical Athabasca bitumen, this point is
achieved at
a temperature range of 60 ¨ 100 C at which time the viscosity has been
reduced
from more than 1,000,000 mPa.s to less than 2,000 mPa.s.
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Since the initially immobile Oil is now mobile enough to be produced by
conventional techniques, there is no need to continue steam injection at full
rates.
NCG is then co-injected with steam to maintain chamber pressure and recover
the
heat stored in the chambers 55, 65. The heat recovered by the NCG injection
boils
residual water in the chambers 55, 65 and further steam is produced. The in
situ
generated steam flows to chamber boundaries where it condenses and transfers
heat
to the Oil and continues the recovery operation. The steam and NCG also
provide a
pressure drive to push the heated Oil to the additional producer 70. This
combination
of heat recovery by NCG co-injection and production via the additional
producer 70
results in significant reductions in steam consumption and CSOR while
maintaining
high recoveries similar to SAGD. NCG/steam co-injection begins when sufficient
heat has been stored outside the steam chamber, and not from the beginning of
steam injection (as in SAGP processes), for a preferred embodiment of the
present
process.
Although the average temperature in the region 90 outside the
chambers is estimated to be 60 ¨ 100 C for typical Athabasca bitumen, at the
time
the additional producer 70 operation begins, according to the criterion here,
it is
possible for the temperature at the additional producer 70 location to be
lower. If this
is the case, it may be necessary or useful to stimulate the additional
producer 70, for
example by steam stimulation, to initiate Oil production. This wellbore
stimulation
may be required periodically to maintain reasonable production rates.
It is not necessary for the steam chambers 55, 65 or the "mobilized
zones" in the terminology of Patent 2591498 to merge, before commencing
additional
producer 70 operations, as per the criterion on stored heat used here. In this
respect, the present process differs from the one described in Patent 2591498.
It is also not necessary to achieve hydraulic communication between a
steam chamber from the additional producer 70, created by CSS operations, and
the
chamber from either SAGD well pair 55 or 65, as in Patent 2277378. The present
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process is therefore different from the processes described in Patents 2591498
and
2277378.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 (which is not to scale) is a cross-sectional portrayal of a
fictional formation on a plane perpendicular to surface and to horizontal well
bores in
the formation.
DETAILED DESCRIPTION
The well system consists of two adjacent horizontal and essentially
parallel injector-producer well pairs 50, 60, vertically separated by a short
distance
(typically 4-10 m), of the type used for SAGD, with an additional horizontal
production
well 70 (referred to as an "additional producer") approximately midway between
the
well pairs 50, 60 at about the elevation of the adjacent SAGD well pairs'
producers
40, 41. It is understood that in the field implementation of the invention,
there may be
several SAGD well pairs 50, 60 with additional producers 70 approximately mid-
way
between at least some of the adjacent pairs as part of a planned array of
wells. The
process here is based on the following two modifications of SAGP which itself
is a
modification of SAGD:
1)
The first modification is called "Modified SAGP" or "MSAGP". A key
feature of MSAGP is that co-injection of NCG with steam begins, when
the average temperature in the reservoir region 90 outside the
chambers is in a range for which the Oil becomes mobile. For typical
Athabasca bitumen, this range is 60 ¨ 100 C and is realized after 3 to
5 years of SAGD operation. The concentration of NCG in the injection
stream may be steadily increased or even made 100%, resulting in
significant reduction in steam consumption compared to SAGD or
SAGP. For a given chamber pressure, ISOR and CSOR are
significantly lower for MSAGP as compared to SAGD or SAGP.
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,
2)
In the second modification, MSAGP is further enhanced by
incorporating at least one additional producer 70. (More than one
additional producer may be deployed within an array of well pairs.)
These additional producers 70 capture Oil by steam/NCG push (mainly
pressure drive) from the chambers 55, 65 of the adjacent well pairs 50,
60. This is not to be confused with the infill wells capturing bypassed oil
by gravity drainage in Patent 2591498 and similar techniques of the
prior art. The twice modified process is called "enhanced MSAGP" or
"eMSAGP".
As described earlier, SAGP is a modification of SAGD in which a small
quantity of NCG (typically less than 1 mole percent) is co-injected with steam
right
from the beginning of steam injection. SAGP is an attractive process as it
provides
comparable Oil production rates to SAGD in the chamber rising phase with
reduced
energy requirements. It appears that evolved solution gas and reservoir gas
generated as a result of steam heating will provide most of the amount of gas
required to capture the early SAGP benefits in SAGD itself. Once the bulk of
the
chambers 55, 65 have reached the top 15 of the reservoir 20, the Oil
production rate
for SAGP may be lower than the rate for SAGD, as the horizontal spreading of
the
gas/liquid interface slows down due to the accumulation of NCG and the
subsequent
reduction in temperature. The addition of significant amounts of NCG to steam
at this
phase of the operation could pose the risk of further reducing the spreading
rate of
the chambers 55, 65.
When the chambers 55, 65 approach the vertical plane A-A midway
between the SAGD well pairs, after recovering typically 30 ¨ 40% of Oil in
place
above the SAGD producers 40, 41 there is a large amount of heat stored in the
chambers 55, 65 and the associated region 90. At this point in time,
approximately
two thirds of the injected heat remains underground for typical SAGD projects
that
have a CSOR between 2.5 and 3. The stored heat is in most cases divided
roughly
evenly between the chambers 55, 65 and the region outside the chambers. The
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average temperature of the Oil in the producible region 90 of the reservoir
outside the
chamber can reach the point where the Oil's viscosity has been reduced to
within
producible ranges without the need for further heating of the Oil. These
temperatures
may be reached well before the chambers 55, 65 around the adjacent well pairs
50,
60 merge or come into fluid communication with each other. For typical
Athabasca
bitumen, the Oil will be mobile at a viscosity below 2,000 mPa.s which will be
achieved at temperatures between about 60 C and 100 C.
With the Oil warmed and a considerable amount of heat already stored
in the reservoir 20, steam injection can be curtailed significantly. Any
reduction in the
steam injection rate will be supplemented by NCG injection to maintain
suitable
chamber pressure. Maintaining chamber pressure is important as it provides the
pressure drive for the recovery process.
When steam injection rates are reduced, the partial pressure of steam
in the chambers 55, 65 falls as the system cools. The heat stored in the
rocks,
particularly within the core of the chambers 55, 65 where temperature is the
highest,
is recovered and transferred to water in the pores, and additional steam is
produced.
The in situ generated steam flows to chamber boundaries where it heats the Oil
and
continues the recovery operation. By controlling the NCG and steam injection
rates,
significant amounts of stored heat will be systemically extracted from the
chamber to
continue the recovery operation leading to higher overall thermal efficiency
of the
production processes over the life of the wells. The NCG concentration in the
co-
injection stream may be increased over time perhaps up to 100%.
To accelerate and increase Oil recovery, an additional producer 70 is
placed approximately midway between two adjacent SAGD well pairs 50, 60 at
about
the elevation of the SAGD producers 40. The producer 70 will likely be in the
coolest
region of the reservoir from a geometrical perspective. However, it is also a
location
that should have the full gravity head to aid production. Periodic stimulation
of the
wellbore 70 may be required to reduce the viscosity of the Oil surrounding the
additional producer 70 to maintain reasonable production rates. It is expected
that
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only a limited number of wellbore stimulations will be required, as the
average
temperature outside the chamber is high enough to achieve reasonable
production
rates.
The chamber(s) 55, 65 of one or both adjacent well pairs 50, 60 act(s)
as a pressure support for the additional producer 70. Pressure drive from such
chamber(s) 55, 65, combined with gravity drainage, will result in improved
production
rates and a lower overall CSOR. The injected NCG also helps to insulate the
top of
the chambers 55, 65 to reduce heat losses to the overburden 10.
The preferred embodiment of this invention is as follows. Initially the
io two well pairs 50, 60 are operated in the SAGD mode. eMSAGP operations
begin
when the SAGD chamber(s) 55, 65 has(have) risen to near the top of the pay
zone
20 and spread sideways sufficiently so as to render a sufficient volume of
adjacent
producible Oil in the reservoir region 90 outside the chamber(s) hot enough to
be
mobile ¨ for typical Athabasca bitumen, the temperature range is 60 ¨ 100 C.
At
any given time during the SAGD phase of the process, the volume of the
chambers
55, 65 (associated with an adjacent well pair 50, 60) may be estimated from
the
cumulative Oil production and associated reservoir parameters, such as initial
and
residual Oil saturations and porosity. From the volumes of chambers 55, 65 and
the
drainage volumes associated with the well pairs 50, 60, the average
temperature in
zo the region 90 outside the chambers may be estimated from the cumulative
steam
injection, by assuming that between 20% and 30% of the injected heat is stored
in
the reservoir region 90 outside the chambers for typical SAGD projects that
have a
CSOR between 2.5 and 3. This average temperature may also be estimated by
setting up a history-matched reservoir simulation model. The decision to begin
eMSAGP may then be based on the estimated average temperature in the reservoir
region 90 outside the chamber between the two well pairs ¨ for Athabasca
bitumen,
this time typically corresponds to 3 to 5 years after the beginning of SAGD.
At that
point in time NCG/steam co-injection begins in the SAGD injectors 30, 31 with
reduced steam injection rates. The NCG and steam rates are adjusted so as to
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maintain chamber pressure. The steam rates are slowly reduced with time and
the
NCG concentration in the co-injection stream is slowly increased. It may
become
possible to shut off steam injection altogether and inject NCG only.
Additional producer 70 operations begin at about the same time as
NCG/steam co-injection. Although at this time the average temperature in the
region
90 outside the chamber is high enough for the Oil be mobile, it is possible
that the
additional producer 70 may be cold. If this is the case, the additional
producer
wellbore 70 is stimulated for a suitable period of time before commencing
production.
Multiple wellbore stimulations may be required to achieve reasonable sustained
production from the additional producer 70. Wellbore stimulations may be
discontinued when sustained production is achieved in the additional producer
70. In
the process here, there is no steam chamber surrounding the additional
producer 70,
at least during the early stages of operation, and the mobile Oil in the
reservoir region
90 outside the chambers flows into the additional producer well 70 because of
pressure drive from the well pairs' 50, 60 associated chambers 55, 65, and
some
gravity head ¨ in this respect the process of this invention differs from the
processes
described in Patents 2277378 and 2591498, which require the formation of
conjoined
or merged chambers surrounding their associated infill/offset wells, and the
merging
of at least two steam chambers.
Reservoir simulation results show that considerable reduction in
cumulative steam injected and CSOR may be achieved by eMSAGP while
maintaining high recoveries similar to SAGD.
References
1. Butler, R., "The Steam and Gas Push (SAGP)", Journal of Canadian Petroleum
Technology, Vol. 38, No. 3, pp. 54-61, March 1999.
2. Butler, R.M., Jiang, Q. and Yee, C.-T., "Steam and Gas Push (SAGP) -- 3;
Recent
Theoretical Developments and Laboratory Results", Journal of Canadian
Petroleum Technology, Vol. 39, No. 8, pp. 51-60, August 2000.
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The above-described embodiments of the invention are provided as
examples. Alterations, modifications and variations can be effected to
particular
portions of these embodiments by those with skill in the art without departing
from the
scope of the invention, which is solely defined by the claims appended hereto.
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