U.S. patent number 3,572,437 [Application Number 04/799,177] was granted by the patent office on 1971-03-30 for oil recovery by steam injection followed by hot water.
This patent grant is currently assigned to Mobil Oil Corporation. Invention is credited to Henry C. Coutret, Jr, James E. Marberry.
United States Patent |
3,572,437 |
Marberry , et al. |
March 30, 1971 |
OIL RECOVERY BY STEAM INJECTION FOLLOWED BY HOT WATER
Abstract
This specification discloses methods of recovering oil from
subsurface oil reservoirs penetrated by at least an injection and a
production well. Steam is injected into the reservoir to form a
steam zone intermediate the injection and production wells.
Subsequently hot water at the same temperature as the injected
steam is injected into the reservoir to fill the steam zone.
Thereafter cold water is injected into the reservoir to drive the
hot water toward the production well and oil is recovered from the
reservoir via the production well.
Inventors: |
Marberry; James E. (Calgary,
Alberta, CA), Coutret, Jr; Henry C. (Shreveport,
LA) |
Assignee: |
Mobil Oil Corporation
(N/A)
|
Family
ID: |
25175225 |
Appl.
No.: |
04/799,177 |
Filed: |
February 14, 1969 |
Current U.S.
Class: |
166/272.3 |
Current CPC
Class: |
E21B
43/24 (20130101) |
Current International
Class: |
E21B
43/24 (20060101); E21B 43/16 (20060101); E21b
043/24 () |
Field of
Search: |
;166/272,273,274 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Novosad; Stephen J.
Claims
We claim:
1. A method of recovering oil from a subsurface oil reservoir
penetrated by an injection well and a production well, comprising
the steps of:
a. injecting steam via said injection well into said reservoir to
form a steam zone intermediate said injection well and said
production well;
b. subsequently injecting hot water via said injection well into
said reservoir in an amount sufficient to fill said steam zone,
said hot water being at the same temperature as said injected steam
of step (a); and
c. recovering oil from said reservoir through said production
well.
2. A method of recovering oil from a subsurface oil reservoir
penetrated by an injection well and a production well, comprising
the steps of:
a. injecting steam via said injection well into said reservoir to
form a steam zone intermediate said injection well and said
production well;
b. subsequently injecting hot water via said injection well into
said reservoir in an amount sufficient to fill said steam zone,
said hot water being at the same temperature as said injected steam
of step (a);
c. subsequently injecting cold water via said injection well into
said reservoir to move said hot water toward said production well;
and
d. recovering oil from said reservoir through said production
well.
3. The method of claim 2 wherein said injected steam is of a
quality within the range of 60 to 90 percent.
4. The method of claim 2 wherein said injected hot water contains
steam in an amount of not more than 5 percent.
5. The method of claim 2 wherein said hot water is injected at a
rate at least as great as the steam injection rate.
6. A method of recovering oil from a subsurface oil reservoir
penetrated by an injection well and a production well, comprising
the steps of:
a. injecting steam via said injection well into said reservoir to
form a steam zone having an areal sweep of a size less than the
size of the areal sweep which would exist at steam breakthrough
into said production well;
b. subsequently injecting hot water via said injection well into
said reservoir in an amount sufficient to fill said steam zone,
said hot water being at the same temperature as said injected steam
of step (a);
c. injecting cold water via said injection well into said reservoir
to move said hot water toward said production well; and
d. producing oil from said reservoir through said production well.
production
7. The method of claim 6 wherein said areal sweep of said steam
zone is within the range of 40 to 60 percent of the areal sweep of
a steam zone which would exist at breakthrough of steam into said
production well.
8. A method of recovering oil from a subsurface oil reservoir
penetrated by an injection well and a production well, comprising
the steps of:
a. injecting through said injection well into said reservoir 0.25
to 1.0 pore volume of 60 to 90 percent quality steam thereby
forming a steam zone intermediate said injection well and said
production well;
b. subsequently injecting into said reservoir through said
injection well 0.02 to 0.03 pore volume of hot water of the same
temperature as said injected steam of step (a) thereby filling said
steam zone with hot water;
c. subsequently injecting into said reservoir through said
injection well at least 0.60 pore volume of cold water; and
d. recovering oil from said reservoir through said production
well.
9. A method of recovering oil from a subsurface oil reservoir
penetrated by a multiplicity of injection wells and production
wells, comprising:
a. injecting steam through a first injection well into said
reservoir to form a first steam zone intermediate said first
injection well and a production well;
b. subsequent to step (a) injecting through said first injection
well hot water of the same temperature as said injected steam into
said reservoir in an amount sufficient to fill said first steam
zone with said hot water;
c. subsequent to step (b) injecting cold water through said first
injection well into said reservoir to move said hot water toward
said production well;
d. subsequent to step (b) injecting steam through a second
injection well into said reservoir to form a second steam zone
intermediate said second injection well and a production well;
e. subsequent to step (d) injecting hot water at the same
temperature as said injected steam into said oil reservoir to fill
said second steam zone with said hot water; and
f. subsequent to step (e) injecting cold water through said second
injection well into said oil reservoir to move said hot water in
said second steam zone toward said production well.
10. The method of claim 9 wherein 0.25 to 1.0 pore volume of 60 to
90 percent quality steam is injected through each of said first and
second injection wells.
11. The method of claim 10 wherein 0.02 to 0.03 pore volume of hot
water at the same temperature as said injected steam is injected
through each of said first and second injection wells.
12. The method of claim 11 wherein at least 0.60 pore volume of
cold water is injected through each of said first and second
injection wells.
13. A method of recovering oil from a subsurface oil reservoir
penetrated by an injection well and a production well, comprising
the steps of:
a. injecting steam via said injection well into said reservoir to
form a steam zone having an areal sweep within the range of 40 to
60 percent of the areal sweep of a steam zone which would exist at
breakthrough of steam into said production well;
b. subsequently injecting hot water via said injection well into
said reservoir in an amount sufficient to fill said steam zone,
said hot water being at the same temperature as said injected steam
of step (a); and
c. recovering oil from said reservoir through said production well.
Description
BACKGROUND OF THE INVENTION
This invention relates to a thermal method of recovering oil from a
subsurface oil reservoir. More particularly, this invention relates
to a method of recovering oil from a subsurface oil reservoir
wherein steam is injected into the reservoir through at least one
injection well and oil is produced therefrom through at least one
production well.
Oil recovery from reservoirs is normally characterized either as
primary recovery or secondary recovery. Primary recovery utilizes
the naturally occurring forces within the reservoir to force the
oil from the formation into production wells. These naturally
occurring forces include: (1) the expanding force of high-pressure
gas, (2) the buoyant force of encroaching water, and (3) the force
of gravity. Secondary recovery utilizes forces applied from
extraneous energy sources to supplement the naturally occurring
forces in the reservoir to produce oil therefrom. These secondary
forces may result from, for example, gas injection, steam
injection, water injection or in situ combustion. It is not
necessary that the primary forces of the reservoir be exhausted
before secondary recovery be initiated. In fact, good reservoir
engineering practices many times dictate that secondary recovery be
begun early in the primary recovery cycle though this is sometimes
called pressure maintenance rather than secondary recovery.
The amount of oil recovered by primary means usually varies from 10
to 50 percent of the original oil in place with 15 to 40 percent
recovery being normal. Therefore more oil usually remains in the
reservoir as unrecoverable by primary means than is produced
therefrom. Secondary recovery is thus extremely important in its
application of recovering a portion of this otherwise unrecoverable
oil.
A high-pressure steam drive is an example of a secondary recovery
process which is utilized in the recovery of oil. Such a steam
drive process is described in U.S. Pat. No. 3,353,598, to R. V.
Smith. A depleted reservoir containing a pattern of injection and
production wells is first waterflooded. The waterflood is then
terminated and steam is injected into the reservoir. Thereafter
steam injection is terminated and water at normal reservoir
temperature is injected into the reservoir to drive the steam and
heat through the well pattern to the production wells. The
injection of water at normal reservoir temperature effects steam
condensation at the interface of the water and steam, thereby
avoiding later condensation of steam behind the driving front or
water-steam interface. Another steam drive process is described in
U.S. Pat. No. 3,360,045, to M. Santourian. This process is
concerned with stratum blocking that results when steam is injected
into a reservoir containing heavy crude oil. By this process, a
hot, nonaqueous gas is first driven through a horizontal zone of
the stratum between an injection and a production well. Steam is
then injected into the reservoir for a substantial period of time.
Subsequently, it is preferred to follow the steam with a waterflood
drive. The waterflood may utilize water at atmospheric temperature
or hot water, the latter being preferred.
SUMMARY OF THE INVENTION
In accordance with the present invention there is provided a method
for recovering oil from a subsurface oil reservoir penetrated by at
least an injection and a production well. Steam is injected into
the reservoir to form a steam zone intermediate the injection and
production wells. Thereafter, hot water at the same temperature as
the injected steam is injected into the reservoir in an amount
sufficient to fill the steam zone with this hot water. Oil is
recovered from the reservoir through the production well. In a
preferred embodiment of the invention cold water then is injected
into the reservoir to drive the hot water through the reservoir
toward the production well thus further aiding in the recovery of
oil from the reservoir.
Another preferred embodiment of this invention is directed to
recovering oil from a subsurface oil reservoir penetrated by a
pattern of injection and production wells. Steam is injected
through a first injection well into the reservoir to form a steam
zone intermediate the first injection well and one or more
production wells. Subsequently, hot water of the same temperature
as the injected steam is injected through the first injection well
into the reservoir in an amount sufficient to fill this first steam
zone. Upon filling the steam zone, hot water injection is
terminated and cold water is injected through the first injection
well into the reservoir to move the hot water toward the production
well. This process is repeated by selectively using a second
injection well and a production well which may be the same as or
different from the production well used in conjunction with the
first injection well.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a vertical section of an oil reservoir penetrated by an
injection and production well and illustrates a steam zone formed
intermediate the wells; and
FIG. 2 is a plan view illustrating a normal five-spot pattern
located within the outlines of an oil reservoir.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
This invention is directed to a secondary recovery process for
recovering oil from a subsurface oil reservoir penetrated by at
least an injection well and a production well. Steam is injected
into the reservoir to from a steam zone intermediate the injection
and production wells. Thereafter an amount of hot water at the same
temperature as the injected steam is injected into the reservoir
until the steam zone is filled with this hot water. By injecting
hot water of the same temperature as the steam into the steam zone
rather than simply terminating steam injection or injecting cold
water into steam zone, collapse of the steam zone is prevented. The
injection of cold water into the steam zone or simply terminating
steam injection would result in rapid condensation of the steam and
collapse of the steam zone. Such a collapse would result in a lower
pressure or pressure sink in the former steam zone and would draw
back into this zone oil which had previously been swept
therefrom.
Preferably after hot water injection is terminated, cold water is
injected as a driving fluid into the reservoir to drive the hot
water and heat zone formed from the steam and hot water through the
reservoir toward the production well. The heat of the steam and hot
water is thereby efficiently utilized in recovering oil from the
reservoir.
More particularly and with reference to FIG. 1, there is shown a
subsurface oil reservoir 2 which is penetrated by an injection well
4 and a production well 6. The injection well 4 is equipped with
tubing 8 for the injection of fluids into the reservoir. Production
well 6 is equipped with tubing 10 for the production of fluids from
the reservoir. Steam 12 from surface equipment (not shown) is
injected through tubing 8 into reservoir 2 to form a steam zone 14
intermediate the injection and production wells. Subsequently, hot
water at the same temperature as the injected steam is injected
through tubing 8 into reservoir 2 to fill steam zone 14. During the
process oil is recovered from reservoir 2 through tubing 10 of
production well 6. Subsequent to the injection of hot water into
reservoir 2 cold water may be injected into the reservoir to move
the hot water toward the production well and further facilitate oil
recovery from the reservoir through tubing 10 of production well 6.
The term "cold water" is used in a comparative sense to mean water
at a temperature significantly less than the injected steam
temperature. Normally the injected cold water will be at ambient
temperature, e.g., a temperature in the range of 40.degree. F. to
90.degree. F.
Steam zone 14 is characterized by the existence of a positive steam
saturation. The steam saturation need only be sufficient to permit
vapor to flow within it. Such a steam saturation is on the order of
10 to 14 percent. The remainder of the pore space within the steam
zone is filled with water and residual oil. The residual oil
saturation is relatively low, typically on the order of 5 to 15
percent. The water in the steam zone is comprised of water
originally present in the reservoir, water formed by partial
condensation of the steam, and water injected into the reservoir
along with steam. The vapor and liquid within the steam zone are in
thermal equilibrium. Thus, the temperature of the steam zone is
determined by the pressure within it. The pressure decreases in the
steam zone 14 in going from injection well 4 toward production well
6. Thus the temperature also decreases toward production well 6.
Much of the pressure drop and consequent temperature decrease
occurs in the immediate vicinity of injection well 4. The remainder
of steam zone 14 is at a relatively constant temperature which is
somewhat lower than the injection temperature.
As steam 12 is injected into reservoir 2, steam zone 14 is formed
having a steam front 15 as the lead boundary. Steam flows through
steam zone 14 to steam front 15 where it condenses to form hot
condensate which flows away from the front. As the steam front
moves past a point in the reservoir the oil saturation is reduced
to a relatively low value as a result of several mechanisms. Just
ahead of the front, the hot condensate begins heating the reservoir
rock and fluids contained there by conduction and convection. The
boundary between the heated and unheated rock is indicated by
boundary 18. The effect of heating the oil is to decrease the
viscosity of the oil and improve the oil mobility ratio. Thermal
expansion of the oil also occurs, thereby displacing a further
small amount of oil. Movement of the steam front through this
preheated portion of the reservoir causes a further reduction in
the oil saturation through a multiphase flow (gas drive) effect.
Behind the steam front in the steam zone through which steam is
flowing the process of steam stripping takes place Little or no
liquid oil flow takes place in the steam zone. The stripping
process volatilizes the lighter components of the oil and reduces
the oil saturation to its final low value. The volatilized light
components flow with the steam to the steam front where both
materials condense. The light components dilute the oil just ahead
of the steam front and thus form a solvent drive or light oil bank
which adds to the effectiveness of the other mechanisms in reducing
the oil saturation.
The steam zone 14 is formed and maintained as the result of steam
injection into reservoir 2. With the start of steam injection
condensation begins immediately as the steam contacts the cool rock
of the reservoir. Condensation continues at the boundary of the
steam zone while this zone exists. Thus, condensation of steam
takes place at the upper and lower surfaces of the steam zone and
reduces the quantity of steam which arrives at steam front 15. A
hot water zone 16 is thus formed surrounding steam zone 14. The hot
water in hot water zone 16 essentially flows parallel to the steam
flow toward production well 6.
This invention is directed to a steam injection secondary recovery
process which increases the amount of oil recovered from a
reservoir per unit volume of injected steam. An amount of steam is
injected which contains sufficient heat to efficiently produce the
oil present within a selected pattern of the reservoir. In
injecting this steam a steam zone is formed intermediate the
injection and production wells. Preferably steam is injected in an
amount less than that resulting in breakthrough of the steam into
the production well. In most reservoirs this amount of steam forms
a steam zone which has an areal sweep within the range of 40 to 60
percent of the areal sweep of a steam zone which would exist at
breakthrough of steam into the production well. In most reservoirs
the preferred amount of steam injected into the reservoir varies
within the range of 0.25 to 1.0 pore volume measured as water.
After the steam zone has been formed an amount of hot water at the
same temperature as the steam is injected into the reservoir to
fill the steam zone. This injection of hot water into the steam
zone prevents collapse of the steam zone and formation of a
pressure sink, thereby preventing oil which has been swept from the
steam zone from being drawn back into it. An increased amount of
oil recovery per unit volume of injected steam is thus
achieved.
The preferred quality of the steam injected into the reservoir
varies within the range of 60 to 90 percent with 80 percent being
preferred. The amount of heat contained by steam increases with the
quality of the steam up to 100 percent quality, i.e., saturated
steam. However, with the waters available for producing steam in an
oil field, it is difficult to get higher than about 80 percent
quality steam without severe depositional problems within the steam
generating equipment. Therefore, 80 percent quality steam is
normally used in carrying out the invention.
Subsequent to steam injection into the reservoir, hot water at the
same temperature as the injected steam is injected into reservoir 2
in an amount sufficient to fill steam zone 14. Normally in most
reservoirs the amount of hot water to be injected into the
reservoir to fill the steam zone varies within the range of 0.02 to
0.03 pore volume. Oil is produced from reservoir 2 through
production well 6 during the steam injection and hot water
injection steps described above. Further, in a preferred embodiment
of the invention, cold water is injected into reservoir 2
subsequent to termination of hot water injection in an amount
sufficient to displace the hot water within the reservoir into
production well 6. The amount of cold water injected is at least
0.60 pore volume and in most reservoirs normally falls within the
range of 0.60 to 1.2 pore volumes.
For reasons previously given the hot water injected into the
reservoir should be at the same temperature as the injected steam
to prevent collapse of the steam zone and a resulting pressure sink
within the reservoir. Preferably the hot water injected into the
reservoir contains steam in an amount of 5 percent or less. This
small amount of steam will ensure that the hot water is at exactly
the same temperature as the previously injected steam. While some
latitude can be allowed in the temperature equivalency between the
hot water and the previously injected steam, a difference of only a
few degrees Fahrenheit will result in some condensation in the
steam zone with an attendant reduction in pressure. While this can
be tolerated in carrying out the present invention, it is preferred
that the hot water be at exactly the same temperature as the
previously injected steam. This hot water may be supplied simply by
applying a sufficient amount of heat to water to raise the
temperature to that of the injected steam. On practical way to
supply this hot water is by continuing to utilize surface steam
generating equipment but apply only enough heat to the boiler water
to produce a fluid which is 5 percent or less quality steam.
Another practical means of supplying the hot water for injection
into the injection well is to continue injecting 80 percent quality
steam f from surface steam generating equipment into the injection
well and to mix a stream of cold water with the steam in an amount
such that the stream of steam and water reaching the reservoir is
hot water containing 5 percent or less steam.
The hot water may be injected into the reservoir at a rate
commensurate with the capabilities of the hot water generating
equipment and the capabilities of the injection well in the
particular reservoir. However, it is preferred that the hot water
be injected at a rate at least as great as the steam injection
rate, measured as liquid. This further minimizes the pressure
decline at the steam front during fill-up of the steam zone. A
still further preferred embodiment of this invention concerns
recovering oil from a subsurface oil reservoir penetrated by a
multiplicity of injection wells and one or more production wells.
Steam is injected through a first injection well into the reservoir
to form a first steam zone intermediate the first injection well
and a production well. Subsequently, hot water of the same
temperature as the injected steam is injected into the reservoir
through the first injection well in an amount sufficient to fill
the first steam zone with hot water. Cold water then is injected
through the first injection well into the reservoir to move the hot
water toward the production well. Upon terminating steam injection
in the first injection well after forming the first steam zone,
steam is injected into a second injection well into the reservoir
to form a second steam zone intermediate the second injection well
and a production well, which well may be the same as or different
from the production well used in conjunction with the first
injection well. Subsequently, hot water at the same temperature as
the injected steam is injected via the second injection well into
the reservoir to fill the second steam zone with hot water.
Thereafter, cold water is injected via the second injection well
into the reservoir to move the hot water of the second steam zone
toward the production well.
This preferred embodiment of the invention is best described by
reference to the normal five-spot pattern of FIG. 2. Wells 21, 22,
23, and 24 are injection wells and well 25 is a production well.
Steam is first injected via injection well 21 to form a first steam
zone 26 intermediate injection well 21 and production well 25.
Preferably steam zone 26 is formed by injecting 0.25 to 1.0 pore
volume of 60 to 90 percent quality steam measured as water into
injection well 21. Thereafter hot water at the same temperature as
the injected steam is injected via injection well 21 into the
pattern in an amount sufficient to fill the first steam zone 26.
The amount of hot water injected desirably is within the range of
0.02 to 0.03 pore volume. This normally will ensure that the steam
zone is filled with hot water. Thereafter, cold water is injected
via injection well 2- into the pattern to displace the hot water
toward production well 25. Preferably cold water in the amount of
at least 0.60 pore volume is injected through the injection well
into the reservoir. Subsequent to the injection of steam into the
injection well 21 steam is injected via injection well 22 into the
pattern to form a second steam zone 28 intermediate injection well
22 and production well 25. Again, about 0.25 to about 1.0 pore
volume of 60 to 90 percent quality steam measured as water may be
injected via injection well 22 to form second steam zone 28.
Thereafter, hot water in the amount of 0.02 to 0.03 pore volume may
be injected via injection well 22 to fill the second steam zone.
Subsequently at least 0.60 pore volume of cold water is injected
via injection well 22 to move the hot water toward production well
25. This procedure is then repeated utilizing injection well 23 and
production well 25 and thereafter utilizing injection well 24 and
production well 25.
While this invention has been described with particular reference
to the normal five-spot pattern of FIG. 2, it is of course
understood that it is applicable to other patterns as well. For
example, it may be employed in a direct line drive wherein
injection wells are formed in a line and production wells are
formed in another line with each injection well being directly
offset by a production well. In such a direct line drive there is
realized the nearest approach to a complete vertical planar advance
of the flooding medium. A modification of the direct line drive is
the staggered line drive wherein production wells are diagonally
offset from injection wells. A developed five-spot pattern is a
case of the staggered line drive wherein the distance between all
like wells is constant.
In addition, this invention is applicable with normal four-spot,
seven-spot, and nine-spot patterns. The normal four-spot pattern
employs three injection wells surrounding one production well; a
normal seven-spot pattern employs six injection wells surrounding a
production well; and a normal nine-spot pattern consists of eight
injection wells surrounding one production well. This invention is
further applicable to inverted patterns. For example, it is
applicable to an inverted nine-spot pattern which has eight
production wells that surround on injection well.
As used herein "pore volume" means pattern pore volume or, in other
words, the pore space within a reservoir encompassed by a
particular pattern. Pore volume is normally expressed in accordance
with equation (1) below:
P.V. =A.times. .times.h .times..phi. (1)
where:
P.V. = pattern pore volume of the reservoir;
A = area of the pattern;
h = thickness of the reservoir; and
.phi. = porosity of the reservoir.
In case of a two-well pattern consisting of an injection and a
production well, the pattern is generally considered elliptical in
shape. In such a two-well pattern the area A may be calculated by
squaring the distance between injection and production wells.
* * * * *