U.S. patent number 3,908,762 [Application Number 05/401,529] was granted by the patent office on 1975-09-30 for method for establishing communication path in viscous petroleum-containing formations including tar sand deposits for use in oil recovery operations.
This patent grant is currently assigned to Texaco Exploration Canada Ltd.. Invention is credited to David Arthur Redford.
United States Patent |
3,908,762 |
Redford |
September 30, 1975 |
Method for establishing communication path in viscous
petroleum-containing formations including tar sand deposits for use
in oil recovery operations
Abstract
Many oil recovery techniques for viscous oil recovery such as
recovery of bitumen from tar sand deposits, including steam
injection and in situ combustion, require establishment of a high
permeability interwell fluid flow path in the formation. The method
of the present invention comprises forming an initial entry zone
into the formation by means such as noncondensible gas sweep or
hydraulic fracturing and propping, or utilizing high permeability
streaks naturally occurring within the formation, and expanding the
zone by injecting steam and a noncondensible gas into the gas swept
zone, propped fracture zone or high permeability streak. The
mixture of steam and noncondensible gas is injected into the
formation at a pressure in pounds per square inch not exceeding
numerically the overburden thickness in feet, and the
steam-noncondensible gas-bitumen mixture is produced either from
the same or a remotely located well. The operation may be repeated
through several cycles in order to enlarge the flow channel.
Suitable noncondensible gases include nitrogen, air, carbon
dioxide, flue gas, exhaust gas, methane, natural gas, ethane,
propane, butane and mixtures thereof. Saturated or supersaturated
steam may be used.
Inventors: |
Redford; David Arthur (Fort
Saskatchewan, CA) |
Assignee: |
Texaco Exploration Canada Ltd.
(CA)
|
Family
ID: |
23588136 |
Appl.
No.: |
05/401,529 |
Filed: |
September 27, 1973 |
Current U.S.
Class: |
166/402; 166/269;
166/271; 166/403 |
Current CPC
Class: |
E21B
43/2405 (20130101); E21B 43/40 (20130101); E21B
43/168 (20130101) |
Current International
Class: |
E21B
43/24 (20060101); E21B 43/34 (20060101); E21B
43/40 (20060101); E21B 43/16 (20060101); E21B
043/24 (); E21B 043/26 () |
Field of
Search: |
;166/272,271,263 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Novosad; Stephen J.
Attorney, Agent or Firm: Whaley; Thomas H. Ries; Carl G.
Park; Jack H.
Claims
I claim:
1. In a method of recovering viscous petroleum including bitumen
from a subterranean, viscous petroleum-containing formation
including a tar sand deposit, said formation being penetrated by at
least one injection well and by at least one production well, said
recovery method being of the type wherein a fluid is injected into
the injection well for the purpose of increasing the mobility of
the petroleum contained in the formation, the improvement for
creating a permeable, stable, fluid communication path between the
injection well and production well which comprises:
a. fracturing the formation adjacent to at least one of the wells
by hydraulic fracturing and injecting into the fractured zone a
propping agent to establish a permeable, propped fracture zone
extending at least a portion of the way into the tar sand deposit
toward the other well;
b. injecting steam and a gas selected from the group consisting of
methane, ethane, propane and butane into the propped fractured zone
via the well adjacent thereto at a preselected pressure; and
c. recovering bitumen, steam and steam condensate from at least one
of said wells.
2. A method as recited in claim 1 wherein steam and gas are
injected into at least one well and travels through the propped
fracture to at least one remotely located well.
3. A method as recited in claim 1 wherein repetitive cycles are
performed with injection alternating between the wells.
4. A method as recited in claim 3 wherein repetitive cycles of
injecting steam and gas and producing fluids from the same wells
are continued until communication between wells is established.
5. A method as recited in claim 1 wherein steam and gas are
injected into injection and production wells simultaneously.
6. A method as recited in claim 1 wherein the pressure at which the
steam and gas are injected into the formation is equal to a value
between the original formation pressure and a value in pounds per
square inch numerically equal to the thickness of the overburden in
feet.
7. A method as recited in claim 1 wherein the recovery fluid
injected into the communication path is steam.
8. A method as recited in claim 1 wherein the recovery fluid
injected into the communication path is a mixture of steam and an
alkaline material including caustic.
9. In a method of recovering viscous petroleum including bitumen
from a viscous petroleun containing formation including a tar sand
deposit, the formation being permeable to gas, the formation being
penetrated by at least one injection well and by at least one
production well, the recovery method being of the type wherein a
fluid is injected into the formation to increase the mobility of
the petroleum contained in the formation, the improvement for
creating a permeable, stable communication path between the
injection and production well which comprises:
a. introducing a first gas which is noncondensible at formation
conditions into the formation via the injection well and recovering
the gas from the formation via the production well for a
preselected period of time to create a gas swept zone in the
formation;
b. introducing a mixture of steam and a second gas which is
noncondensable at formation conditions into the gas swept zone;
and
c. recovering bitumen, steam condensate and the noncondensible gas
from the production well.
10. A method as recited in claim 9 wherein the first noncondensible
gas is selected from the group consisting of nitrogen, carbon
dioxide, flue gas, exhaust gas, methane, natural gas, ethane,
propane, butane, and mixtures thereof.
11. A method as recited in claim 9 wherein the second
noncondensible gas is selected from the group consisting of
nitrogen, carbon dioxide, flue gas, exhaust gas, methane, natural
gas, ethane, propane, butane, and mixtures thereof.
12. A method as recited in claim 9 wherein the first noncondensible
gas and second noncondensible gas are the same.
13. In a method of recovering viscous petroleum including bitumen
from a subterranean, viscous petroleum-containing formation
including a tar sand deposit, said formation being penetrated by at
least one injection well and by at least one production well, said
recovery method being of the type wherein a fluid is injected into
the injection well for the purpose of increasing the mobility of
the petroleum contained in the formation, the improvement for
creating a stable, permeable fluid communication path between the
injection well and production well which comprises:
a. hydraulically fracturing and introducing a propping agent into
the formation adjacent the injection well and the production well
to form a propped fracture zone adjacent each well extending only
part way from that well to the fracture adjacent the other
well;
b. injected steam and a gas selected from the group consisting of
methane, ethane, propane and butane into the fracture zone adjacent
each well until the injection pressure reaches a predetermined
value;
c. maintaining steam and the gas in each fracture for a
predetermined soak period;
d. reducing the pressure in each well to permit steam,
non-condensible gas and viscous petroleum to flow from each propped
fracture zone into each well.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention pertains to a method for recovering petroleum from
viscous petroleum-containing formations including tar sand
deposits, and more specifically to a method for establishing a
stable interwell communication path in the formation, and to a
method for using the communication path in an oil recovery process
involving injection of a recovery fluid such as solvent, steam or
air for in situ combustion into the communication path.
2. Description of the Prior Art
There are many subterranean, petroleum-containing formations
throughout the world from which petroleum cannot be recovered by
conventional means because of the high viscosity of the petroleum
contained therein. The best known and most extreme example of such
viscous petroleum-containing formations are the so-called tar sands
or bituminous sand deposits. The largest and most famous such
deposit is in the Athabasca area in the northeastern part of the
Province of Alberta, Canada, which deposit contains in excess of
700 billion barrels of petroleum. Other extensive tar sand deposits
exist in the western United States and in Venezuela, and lesser
deposits are located in Europe and Asia.
Tar sands are defined as sand saturated with a highly viscous crude
petroleum material not recoverable in its natural state through a
well by ordinary production methods. The petroleum or
hydrocarbon/materials contained in tar sand deposits are highly
bituminous in character, with viscosities ranging in the millions
of centipoise at formation temperature and pressure. The tar sand
deposits are about 35 percent by volume or 83 percent by weight
sand, and the sand is generally a fine grain quartz material. The
sand grains are coated with a layer of water, and the void space
between the water coated sand grains is filled with bituminous
petroleum. Some tar sand deposits have a gas saturation, generally
air or methane, although many tar sand deposits contain essentially
no gas. The sum of bitumen and water concentrations consistently
equals about 17 percent by weight, with the bitumen portion thereof
varying from about two percent to about 16 percent. One of the
striking differences between tar sand deposits and more
conventional petroleum reservoirs is the absence of a consolidated
matrix. While the sand grains are in grain-to-grain contact, they
are not cemented together. The API gravity of the bitumen ranges
from about 6.degree. to about 8.degree., and the specific gravity
at 60.degree. Fahrenheit is from about 1.006 to about 1.027.
Recovery methods for tar sand deposits are classifiable as strip
mining or in situ processes. Most of the recovery to date has been
by means of strip mining, although strip mining is economically
feasible at the present time only in those deposits wherein the
ratio of overburden thickness to tar sand deposit thickness is
around 1 or less. In situ processes which have been proposed in the
prior art include thermal methods such as fire flooding and steam
injection, as well as steam-emulsification drive processes.
It has been recognized in the prior art that many of the thermal
processes and the steam-emulsification drive process require the
establishment of a communication path between one or more injection
wells and one or more production wells, through which the recovery
fluid may be injected. Many failures to recover appreciable
quantities of bitumen from tar sand deposits by in situ recovery
processes are related to plugging of the communication path between
injection wells and production wells. Plugging can occur in a
propped fracture zone as a result of two phenomena. (1) Bitumen
heated by the injected fluid to a sufficiently high temperature
will flow in the fracture zone for a brief period, but will lose
heat and become so viscous that it is essentially immobile after
traveling only a short distance from the thermal recovery fluid
injection point. (2) When a heated fluid such as steam is injected
into a propped fracture communication path between injection and
production wells, bitumen above the communication path is heated,
softens and flows down into and plugs the propped fracture
zone.
In view of the foregoing, it can be seen that there is a
substantial, unfulfilled need for a method for establishing a
stable communication path between injection wells and production
wells within a tar sand deposit, which communication path will not
be plugged or otherwise affected during the subsequent injection
thereinto of a thermal recovery fluid.
SUMMARY OF THE INVENTION
I have discovered, and this constitutes my invention, that a
stable, permeable communication path may be established between
wells drilled into and completed in a subterranean, viscous
petroleum-containing formation such as a tar sand deposit according
to the process described below. My process requires that there be
at least moderate gas permeability or a high permeability streak
within the formation, which may be a naturally occurring high
permeability streak or one which is formed by means of conventional
hydraulic fracturing and propping according to techniques well
known in the prior art. My process utilizes simultaneous injection
of steam and a noncondensible gas. The steam may be supersaturated
or saturated. Gases suitable for use in my invention include carbon
dioxide, methane, nitrogen, air, and mixtures thereof.
If the permeability of the formation is sufficient to permit
injection of gas from one well to the other through the formation,
then gas injection should be the first step in this process. Any
noncondensible gas such as nitrogen, air, carbon dioxide, natural
gas or methane may be used. If a permeable streak is present, gas
may be injected briefly through this permeable streak. Otherwise,
hydraulic fracturing and propping are required to open a zone into
which steam and noncondensible gas are injected.
Steam and the noncondensible gas may be mixed prior to injection or
injected sequentially or separately to mix in the formation. The
injection pressure of the steam-noncondensible gas mixture should
not exceed a value in pounds per square inch numerically equal to
the overburden thickness in feet in order to avoid fracturing the
overburden. Steam and noncondensible gas are injected into one
well, and flow through the gas swept zone, permeable streak or
propped fracture zone to a remotely located well. Flow reversal may
be used to insure creation of a uniform thickness communication
path. Recovery of bituminous petroleum by more conventional, high
efficiency techniques such as steam emulsification drive, combined
thermal-solvent injection, or in situ combustion operations may be
undertaken next using the communication path.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 presents an illustrative embodiment of my invention, wherein
an injection well and production well are treated to produce the
desired stable commmunication path according to the process of my
invention.
FIG. 2 shows the temperature profile of a test cell after 10
minutes of injection during evaluation of the process of my
invention.
FIG. 3 shows the temperature profile similar to FIG. 2 but after 70
minutes .
DESCRIPTION OF THE PREFERRED EMBODIMENTS
I. The Process
My invention may best be understood by reference to the attached
drawings, which shows in cross-sectional view, a tar sand deposit
type of petroleum formation being subjected to one illustrative
embodiment of the process of my invention. In the drawing, tar sand
formation 1 is penetrated by wells 2 and 3, which are in fluid
communication with the tar sand deposit 1 by means of perforations
4 and 5 respectively. Wells 2 and 3 are both equipped on the
surface for injection of fluid thereinto or production of fluid
from the well. This is accomplished by providing well 2 with valves
6 and 7, and by providing well 3 with valves 8 and 9.
Hydraulic fracturing and propping is performed in the formation via
both wells, which gives rise to the creation of a thin, high
permeability streak 10 extending at least part way between wells 2
and 3. Even though propping material is injected into the hydraulic
fracture, the fracture is not adequate for sustained injection
thereinto of steam in the final recovery phase of the operation
because of the tendency for heated bitumen to cool and plug the
propped fracture of bitumen above the zone to flow down into the
fracture zone. Accordingly, valve 7 is closed and valve 6 is
opened, and a mixture of steam and noncondensible gas is injected
into well 2 through perforation 4 into the propped fracture zone
10. Noncondensible gas is supplied by a compressor or contained
under pressure in vessel 11 and pumped therefrom by pump 12 into
mixing vessel 13. Steam is supplied from generator 14 by a pump 15.
The injection pressure is raised to the desired value and pumps 12
and 15 insure mixing steam and noncondensible gas in the desired
ratio. The material being injected into the fracture zone is
preferably essentially 100% noncondensible gas initially, with the
steam content being increased with time.
The hydraulic fracturing operation may establish an interwell
connecting fracture as shown in the figure, or fracture zones may
extend into the formation only part way to the other wells. If an
interwell fracture cannot be established, steam and noncondensible
gas should be injected into each discrete fracture zone via each
well. The maximum injection pressure is still limited by the
overburden thickness. The preferred method is to inject steam and
noncondensible gas up to a pressure in pounds per square inch not
greater numerically than the overburden thickness in feet.
Injection of fluid should be stopped and pressure should then be
held at the above described level on all wells for a soak period of
from 4 to 24 hours. The pressure is then reduced and production of
steam, noncondensible gas, steam condensate and bitumen taken from
all of the wells. This procedure is repeated until interwell
communication is established.
The presence of noncondensible gas in the fracture zone is thought
to help avoid formation plugging in several ways. The rate of
heating is reduced because the presence of a noncondensible gas
with steam reduces the heat transfer rate significantly. The gas
pressure is higher in the fracture zone than it would be if steam
alone is present, and this higher pressure helps hold softened tar
sand material in place above the fracture. Moreover, if hot,
liquefied bitumen tends to cool and become immobile as its flows
through the propped fracture zone and cools, the presence of
noncondensible gas in the zone maintains small flow channels open
in the immobile bitumen plug through which hot fluids can flow to
heat and reliquefy the bitumen plugs. The reason for this effect is
related to the high mobility ratio of noncondensible gas and
viscous liquid bitumen. Such high mobility ratio is normally
detrimental to recovery efficiency because the high mobility (low
viscosity) gas tends to channel or finger through the viscous
petroleum. Channeling in this instance is beneficial, since it
facilitates passing the hot steam through the immobile bitumen,
resulting in heating and consequent viscosity reduction of the
bitumen. When bitumen becomes immobile and plugs a propped fracture
zone such as when steam alone is being injected, the portion of the
steam vapor near the obstruction cools and eventually condenses, so
neither channeling nor heating of the immobile bitumen obstruction
results. Injection of additional steam alone is not helpful since
is cannot reach the immobile bitumen obstruction, and the only
heating effect is by conduction along the long dimension, of the
fracture, a very inefficient heat transfer process.
Passage of the mixture of steam and gas through the propped
fracture zone results in gradual enlargement of the vertical
thickness by continually heating bitumen above and below the zone.
The viscosity of bitumen is reduced by heating and flows through
the fracture toward the production well 3, carried along by the
flowing steam and gas in propped fracture zone 10. Although
injection of 100% steam would heat and liquefy bitumen along the
faces of the zone more rapidly than steam and noncondensible gas,
plugging usually results when pure steam is injected into a
fracture.
Since the heating effect is a function of temperature of the fluid
flowing in zone 10, and since the fluid cools as it passes through
the zone from injection well to production well, the extent of
removal of bitumen from the formation adjacent to the zone is
greatest near the injection well, decreasing steadily with distance
from the point of injection. This results in a non-uniform, wedge
shaped communication zone. Although this is not always
objectionable, certain recovery processes which may be used give
better results if the vertical thickness of the communication path
is more nearly uniform. Accordingly, when it is desired to produce
a more nearly uniform communication path, the injection-production
functions of wells 2 and 3 are reversed, with injection of steam
and noncondensible gas being into well 3 and production of steam,
steam condensate and liquefied bitumen being taken from well 2,
this is accomplished using an arrangement such as is shown in the
attached figure by closing valves 6 and 9 and opening valves 8 and
7 so the mixture of steam and noncondensible gas is introduced into
well 3 and passes therefrom into interval 10 via perforations 5.
Fluid consisting mainly of steam, noncondensible gas, steam
condensate and liquefied bitumen are produced via well 2 through
valve 7 to surface located treating facilities.
Whichever injection sequence is being utilized, the fluid produced
will be a mixture of steam, water (steam condensate), bitumen and
noncondensible gas, which must be treated on the surface to
separate water and bitumen. Gravity separation tanks are
satisfactory for separating bitumen and water unless a
substantially stable emulsion has been formed due to the presence
of naturally occuring emulsifiers in the bitumen. Resolution of
water-in-oil emulsions must also be accomplished and is easily done
by contacting the water-in-oil emulsion with an acid.
Depending on the type of recovery process contemplated in the
communication path, from one to four or even more repetitive cycles
of the above treatment may be required to convert the propped
fracture zone into a satisfactory communication path.
When developing a communication path for an in situ separation
process involving steam injection, the transition from the
communication path development phase to the in situ recovery phase
can occur smoothly. The first fluid injected into the propped
fracture zone will ordinarily consist of from 50% to 100% inert
gas, the remainder being steam. After production of inert gas is
detected at the production well, the steam fraction of the fluid
being injected into the production well is increased. The maximum
safe rate of increase in steam to noncondensible gas ratio varies
from one formation to another because of differences in bitumen
composition and content, sand particle size, etc. It is generally
preferred to inject essentially 100 percent noncondensible gas
initially, and then include gradually increasing quantities of
steam with the noncondensible gas.
One may include a small quantity of an alkalinity agent such as
caustic (sodium hydroxide or ammonia) in the first portion of
steam-noncondensible gas mixture injected to aid in forming of
bitumen-in-water emulsion. Emulsion formation makes possible the
movement of bitumen which is otherwise immobile. Removal of bitumen
from the zone immediately adjacent to the original fracture is
necessary in order to expand the fracture into a communication path
which will remain open upon injection of thermal fluids during the
main recovery portion of the process.
The above cycles are continued through a series of separate steps,
simultaneously in each well or alternating from one well to the
other, until a satisfactory stable, permeable flow path between
well 2 and well 3 is achieved.
The communication path between wells 2 and 3 established according
to the above procedure may be utilized for a subsequent in situ
recovery process such as steam injection, steam plus emulsifying
chemical injection, or numerous other recovery techniques
applicable to tar sand deposits which required the establishment of
an interwell communication path. Although steam injected into the
communication path via well 2 will channel through the
communication path, heating of bituminous petroleum contained in
the tar sand deposit will continue along the surfaces exposed to
the communication path through which the heated fluid is being
injected. Bituminous petroleum along the interface between the tar
sand deposit and the communication path will be heated, the
viscosity will be reduced, and the material will flow into the
communication path. The bituminous petroleum will then flow toward
the production well and will be produced along with steam
condensate. The recovery process is aided materially by including a
small amount of a basic material such as caustic or sodium
hydroxide in the steam, which enhances the formation of a low
viscosity oil-in-water emulsion. The produced fluid in such a
recovery program is an oil-in-water emulsion which has a viscosity
only slightly greater than water. Surface equipment for separating
bituminous petroleum from the oil-in-water emulsion must be
provided.
The communication path established according to the above described
procedural steps may also be utilized in the refluxing solvent
recovery process described in pending application Ser. No. 357,425,
filed May 4, 1973.
II. The Noncondensible Gaseous Constituent
Gases suitable for use in combination with steam in the process of
my invention include carbon dioxide, methane, nitrogen and air.
Carbon dioxide and methane are preferred gases because of their
high solubility in petroleum, although this solubility must be
taken into consideration in selecting the ratio of noncondensible
gas, to insure that more than the amount which will dissolve in the
petroleum is injected, so some gas-phase will remain at formation
conditions. Also, crude gases such as flue gas or engine exhaust
gas, both rich in carbon dioxide and nitrogen content, may be used.
Ethane or propane may also be used. Nitrogen and air are also
preferred noncondensible gases because of their widespread
availability.
III. Field Example
My invention may be better understood by reference to the following
pilot field example, which is offered only as an illustrative
embodiment of my invention, and is not intended to be limitative or
restrictive thereof.
A tar sand deposit is covered with 300 feet of overburden, and it
is determined that the thickness of the tar sand deposit is 75
feet. An injection and a production well are drilled, 100 feet
apart, and completed into the full interval of the tar sand
deposit. Spinner surveys indicate that there are no intervals of
high permeability within this particular segment of the tar sand
deposit, and gas permeability of the entire formation is quite low.
Hydraulic fracturing must be undertaken in order to establish an
injection zone for the process of my invention. Conventional
hydraulic fracturing is applied to the formation adjacent to both
the injection well and production well, and coarse sand propping
material is injected into the fracture to prevent healing thereof
after fracture pressure is removed. Gas injectivity tests are
performed, and it is determined that communication between wells
has been achieved by fracturing.
Pure nitrogen is injected into the fracutre zone via the injection
well at a pressure of 200 pounds per square inch. After production
of nitrogen from the production well is observed, a mixture of 80
percent quality steam and nitrogen is injected into the well. The
volume ratio of nitrogen to steam is initially 1 standard cubic
feet per pound, with the ratio decreasing gradually to about 0.20
over a 6 day period. Approximately 0.2 percent caustic soda (sodium
hydroxide) is added to the steam during the first 10 days of steam
injection to aid in forming an emulsion with the bitumen, so that
bitumen may be removed more effectively from the zone around the
fracture more readily. Caustic soda is not needed after 10
days.
Injection of the nitrogen and steam continues for approximately 1
week, which is sufficient to establish a communication path of
sufficient extent that pure steam may be injected without danger of
plugging occurring in the communication path as a result of cooling
of bitumen or slumping of heated bitumen into the path. As a safety
measure, the steam content is increased gradually rather than
abruptly, over a 10 day period. Injection of steam is continued as
the principal recovery technique, bitumen being produced in the
form of an oil-in-water emulsion.
IV. Experimental
In order to establish the operability of the process of my
invention, and further to determine the optimum materials and
procedures, the following laboratory work was performed. A
laboratory cell was utilized in these experiments in order to
simulate underground tar sand deposits. The model is a pipe, 15
inches long and 18 inches in diameter. One inch diameter wells, one
for injection and one for production, are included, each being
positioned three inches from the cell wall and 180.degree. apart.
The top of the well is equipped with a piston and sealing rings
which impose overburden pressure.
The cell described above was packed with a mined tar sand sample
and compressed by pneumatic tamping to a density of 2 gm/cc,
followed by application of an overburden pressure of 500 psig for 6
days. A 1/8 inch .times. 2 inch clean sand path was provided
between wells in this sample to simulate a fracture.
Nitrogen gas flow was adjusted to 24 standard cubic feet per hour
at a pressure of 300 pounds per square inch into the injection
well, through the simulated fracture in the compressed tar sand
material and out the production well, and this was continued for
several hours. Steam and nitrogen were injected at a pressure of
300 pounds per square inch. The first production of bitumen occured
after only 2 minutes, and the pressure at the model's production
well quickly rose to above 250.degree.F. The rapid occurrence of
bitumen production and low pressure differential between the
injection and production wells are indicative of formation of a
communication path between the injection well and production well.
Throughout the run, large amounts of "free" bitumen (appearance of
pure bitumen but was actually a water-in-oil emulsion) floated on
the oil-in-water emulsion in the production receiver. Steam and
noncondensible gas were injected at a pressure of 290 to 350 pounds
per square inch for 4 5/6 hours, followed by injection of steam
only for 2 hours before terminating the run. There was no
indication of plugging during the run.
Analysis of data obtained from thermocouples placed in the cell
indicated a hot flow path across the tar sand between wells and
movement of heat outwards from this path. The temperature profile
of FIG. 2 illustrates this result after 10 minutes of steam
injection, and FIG. 3 shows the result after 70 minutes of steam
injection.
The cell was unpacked in the usual manner and inspected. Major
depletion was noted around the injection port and extending toward
the production port, with lesser degree of depletion throughout
most of the cell.
While my invention has been described in terms of the number of
illustrative embodiments, it should be understood that it is not so
limited, since many variations of the process of my invention will
be apparent to persons skilled in the related art without departing
from the true spirit and scope of my invention. Similarly, while a
mechanism has been proposed to explain the benefits resulting from
the process of my invention, I do not wish to be restricted to any
particular mechanism responsible for the benefits achieved through
the use of my process. It is my desire and intention that my
invention be limited only by such restrictions and limitations as
are imposed in the appended claims.
* * * * *