STEAM INJECTION PRESSURE IN A STEAM-ASSISTED GRAVITY DRAINAGE PROCESS

PRESSION D'INJECTION DE VAPEUR POUR PROCEDE DE DRAINAGE GRAVITAIRE PAR INJECTION DE VAPEUR

English Abstract

The pressure at which cold water is initially injectable into an oil sand formation is determined. In the practice of steam-assisted gravity drainage in that formation, steam is injected at a pressure greater than the cold water initial injectivity pressure but no more than 1500 kPa grater than that pressure.

French Abstract

La pression à laquelle l'eau froide est initialement injectable dans une formation de sable pétrolifère est déterminée. Dans la pratique de vapeur pour procédé de drainage gravitaire dans cette formation, on injecte de la vapeur à une pression supérieure à la pression de l'injectivité initiale de l'eau froide, mais sans excéder 1500 kPa de plus que cette pression.

Claims

6

THE EMBODIMENTS OF THE INVENTION IN WHICH AN
EXCLUSIVE PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS
FOLLOWS:
1. In an in-situ steam-assisted gravity drainage process for the recover of
heavy oil from a subterranean oil formation, the improvement comprising:
determining the pressure at which cold water is initially injectable into the
formation; and
establishing steam injection and steam chamber growth by injecting steam at a
pressure greater than but within 1 500kPa of the cold water initial
injectivity pressure.

2. The improvement as set forth in claim 1 wherein:
the oil formation is the McMurray oil sand.

Description

CA 02358555 2001-10-04
1 "STEAM INJECTION PRESSURE IN A STEAM-ASSISTED
2 GRAVITY DRAINAGE PROCESS"
3
4 FIELD OF THE INVENTION
The present invention relates to a method for practicing steam-assisted
gravity
6 drainage.
7
8 BACKGROUND OF THE INVENTION
9 Steam-assisted gravity drainage ("SAGD") is the accepted label for an in
situ
thermal oil recovery process now being used commercially in the subterranean
11 McMurray oil sand deposits in Northern Alberta and Saskatchewan.
12 The oil (or bitumen) in these deposits is heavy and very viscous. It will
not
13 flow readily and therefore must be heated by steam injection to reduce its
viscosity, so
14 that it becomes mobile and can be moved through the formation to a
production well.
The SAGD process which is used involves the following steps:
16 ~ A pair of parallel co-extensive horizontal wells are established in close
17 proximity (for example 7 meters apart), one above the other, in the oil
zone;
18 ~ Fluid communication through the span of oil sand between the wells is
19 established - this may be done by circulating steam through the two wells
simultaneously to create "hot fingers" which heat the span by conductance;
21 ~ When the span is hot, steam is injected through the upper well to
displace
22 oil in the span into the lower well, through which it is produced to ground
23 surface;
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2
1 ~ The upper well is then dedicated to steam injection and the lower well to
2 fluid production. Steam, injected through the upper injection well, rises
and
3 heats cold oil in the reservoir. The heated oil and steam condensate drains
4 by gravity to the production well and is produced. An upwardly ascending
chamber, depleted of oil and filled with steam, is gradually developed. This
6 chamber is capable of readily allowing fluid to move therethrough. Newly
7 injected steam can rise through the chamber to heat cold oil along the
8 chamber boundary and the heated oil and steam condensate can drain down
9 under the impetus of gravity to the production well.
The conventional wisdom in the industry is that steam injection needs to be
11 carried out at less than formation break through pressure. The McMurray oil
sand is at
12 relatively shallow depth (for example 300 m). If steam is injected at a
pressure greater
13 than break through pressure, there is a strong possibility that vertical
channeling will
14 occur into an adjacent or close porous permeable formation (referred to as
a "thief
zone") and injected steam will preferentially move into the thief zone and be
wasted.
16 However, the process proceeds slowly when steam is injected at a pressure
less
17 than formation break through pressure. It is desirable to find a workable
technique
18 whereby the rate of growth of the steam chamber may be substantially
accelerated.
19
SUMMARY OF THE INVENTION
21 The present invention is based on the discovery that steam injection can be
22 advantageously conducted at an elevated pressure that is:
23 ~ greater than the pressure at which cold water begins to be readily
injectable
24 into the oil zone; but
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CA 02358555 2001-10-04
3
1 ~ less than the pressure at which steam begins to preferentially escape into
a
2 thief zone.
3 By way of example, in the Fort McMurray region of Alberta, we have
4 determined:
~ that steam injection rate into the McMurray oil formation is low (less than
6 10 m3/day, cold water equivalent volume) and steam chamber growth is
7 negligible at a steam injection pressure of 2000-4300 kPa;
8 ~ that cold water can be effectively injected into the oil formation
9 commencing at a pressure above 4300 kPa;
~ that steam injection rate is higher (over 200 m3/day, cold water equivalent
11 volume) and steam chamber growth is rapid at a steam injection pressure in
12 the range 4500 - 5200 kPa; and
13 ~ that steam begins to be lost to the overlying thief zone if the steam is
14 injected at a pressure above 6500 kPa.
In summary then, we have discovered that steam chamber development can be
16 surprisingly enhanced, without breakthrough to the overlying thief zone, if
steam
17 injection in connection with the SAGD process is conducted at a pressure
narrowly
18 greater than the pressure at which cold water first becomes injectable into
the heavy oil
19 zone. Preferably, the steam injection pressure should be less than 1500 kPa
greater
than the pressure at which cold water first is injectable. In numbers, if the
initial cold
21 water injectivity pressure is 4500 kPa, then steam injection should be
conducted in the
22 range 4500 - 6000 kPa.
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CA 02358555 2004-10-29
1 4
2 By way of explanation, we believe that the McMurray oil formation can be
3 mildly fractured by injecting steam at a pressure greater than but close to
the cold
4 water initial injectivity pressure, without having the fractures penetrate
to the thief
zone. We find that relatively good steam injectivity and steam chamber growth
can
6 be achieved, without steam loss to the overlying thief zone, provided that
the steam
7 injection pressure is preferably within 1500 kPa of the cold water initial
injectivity
8 pressure.
9 In one embodiment, the invention is concerned with an improvement in an in-
situ steam-assisted gravity drainage process for the recover of heavy oil from
a
11 subterranean oil formation, comprising: determining the pressure at which
cold water
12 is initially injectable into the formation; and establishing steam
injection and steam
13 chamber growth by injecting steam at a pressure greater than the cold water
initial
14 injectivity pressure and less than 1500 kPa greater than the cold water
initial
injectivity pressure.
16
17 DESCRIPTION OF THE DRAWINGS
18 Figure 1 is a plot of pressure versus injection rate for a typical mini-
frac test,
19 showing the pressure at which cold water is initially injectable into the
McMurray oil
zone in the Fort McMurray region; and
21 Figure 2 is a plot of the height of the steam chamber associated with a
SAGD
22 steam injection well over time, as observed by a nearby injection well.
23
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1 4a
2 DESCRIPTION OF THE PREFERRED EMBODIMENT
3 The steps of the process are exemplified by the following examples.
4 Example I
S A "mini-frac" test was carried out to establish the pressure at which cold
water
6 is initially injectable into the McMurray formation.
7 More particularly a vertical steam injection well was completed in the
8 McMurray oil formation. The well was filled with cold water and the water
was
9 pressured up. 32 liters of water at a rate of 8 liters/minute were fed into
the formation,
commencing when the pressure reached 4800 kPa, as shown in Figure 1.
11
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I Example II
2 Figure 2 is a plot showing the growth rate of the steam chamber associated
with
3 a steam injection well being used in a SAGD operation being conducted in the
Lower
4 McMurray oil sand formation.
5 As shown, steam was initially injected for a period of about 7 months at a
6 pressure of 5100 kPa and injection rate of 300 m3/day. This was an injection
pressure
7 greater than the pressure (4500 kPa) at which cold water could initially be
injected.
8 The steam chamber grew at a rate of 3.0 to 5.0 cm/day. It was then necessary
for a
9 period of about 9 months to reduce the injection pressure to 4400 kPa, due
to a shortage
of available steam. As shown, the growth of the steam chamber became
negligible. At
11 this point, more steam became available and the injection pressure was
increased to
12 5200 kPa with an accompanying growth of the steam chamber at a rate of
about 3.0 to
13 6.0 cm/day.
14
Examine III
16 At another nearby SAGD injection well, steam was injected into the McMurray
17 formation at a pressure of 6500 kPa. Significant losses of steam to the
overlying thief
I 8 zone were experienced.
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Representative Drawing