U.S. patent number 3,706,341 [Application Number 05/079,346] was granted by the patent office on 1972-12-19 for process for developing interwell communication in a tar sand.
This patent grant is currently assigned to Canadian Fina Oil Limited. Invention is credited to David Arthur Redford.
United States Patent |
3,706,341 |
Redford |
December 19, 1972 |
PROCESS FOR DEVELOPING INTERWELL COMMUNICATION IN A TAR SAND
Abstract
A hot, competent, permeable communications zone, connecting
injection and production wells completed in a tar sand, is
developed as follows: A cold, aqueous solution containing sodium
hydroxide and a non-ionic surfactant is injected into a propped
fracture system connecting the wells. The solution is circulated
between the wells at a pressure below the fracture propping
pressure. Bitumen is slowly emulsified in the solution and removed
through the fracture system; a competent, bitumen -- depleted zone
contiguous to the fracture zone is thereby developed. The
temperature of the solution is then slowly increased and the
quantities of sodium hydroxide and surfactant gradually decreased
until pure steam only is being circulated.
Inventors: |
Redford; David Arthur (Fort
Saskatchewan, Alberta, CA) |
Assignee: |
Canadian Fina Oil Limited
(Alberta, CA)
|
Family
ID: |
22149944 |
Appl.
No.: |
05/079,346 |
Filed: |
October 8, 1970 |
Current U.S.
Class: |
166/275; 166/271;
166/270.1 |
Current CPC
Class: |
C09K
8/592 (20130101) |
Current International
Class: |
C09K
8/592 (20060101); C09K 8/58 (20060101); E21b
043/22 (); E21b 043/24 () |
Field of
Search: |
;166/266,271,272,274,259,261,260,257,302,303 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
|
|
|
|
|
|
|
639,050 |
|
Mar 1962 |
|
CA |
|
692,073 |
|
Aug 1964 |
|
CA |
|
Primary Examiner: Novosad; Stephen J.
Claims
What is claimed is:
1. A method for establishing a hot, permeable communication zone in
a bitumen-containing sand formation extending between production
and injection wells, said formation having a propped fracture zone
extending between the wells, which comprises:
pumping a solution, having a temperature substantially the same as
the formation temperature, into the fracture zone, said solution
being capable of emulsifying bitumen at temperatures between
40.degree. and 90.degree.F;
forcing the solution from the injection well to the production well
by pumping it through the fracture zone at a bottom hole pumping
pressure which is substantially less than the fracture propping
pressure;
contuing to pump the solution, while simultaneously gradually
increasing its temperature, through the formation at a bottom hole
pumping pressure which is substantially less than the fracture
propping pressure, whereby bitumen in and adjacent to the fracture
zone TABLE emulsified and forced to the production well, through
which it is removed, thereby gradually developing a hot, permeable
communication zone extending between the wells.
2. The method as set forth in claim 1 wherein:
the solution comprises water containing sodium hydroxide in an
amount less than 1.0 percent by weight, and a non-ionic surfactant
in an amount between 0.1 and 5 percent by weight.
3. The method as set forth in claim 2 wherein:
the non-ionic surfactant is octylphenoxypolyethyleneoxy ethanol and
it is provided in the solution in an amount less than 0.4% by
weight.
4. The method as set forth in claim 2 wherein:
the non-ionic surfactant content of the solution is gradually
decreased after the injection temperature of the solution rises
above about 60.degree.F.
Description
BACKGROUND OF THE INVENTION
This invention relates to a method for establishing a competent,
permeable communication zone within a bitumen-containing sand bed.
When formed, the zone connects injection and production wells
penetrating into the bed. The zone is permeable to steam and is
used to enable injected steam to gain access to the bed across a
wide area of contact. In this way, steam is used, in accordance
with known processes, to heat and emulsify bitumen contained in the
bed and render it mobile so that it can be driven to and recovered
from the production well.
There are a number of known, bitumen-containing sand reservoirs
scattered around the world. One of the largest of these is the
deposit located in the Athabasca region of Alberta, Canada. The
present invention is discussed with reference to this particular
deposit since the investigations leading up to the invention were
carried out there. However, it will be appreciated that the process
may find application in other deposits of the same type.
The Athabasca tar sand deposit has a lateral area of several
thousand square miles. The bitumen or oilbearing sandstone
reservoir (referred to hereafter as "the oil sand") is, in some
areas of the deposit, exposed at ground surface. These areas lend
themselves to open-pit type mining operations - the oil and sand
are separated in a plant. The greatest part of the deposit,
however, is covered with overburden. This overburden can range up
to 1,000 feet in thickness. These portions of the deposit cannot
economically be mined by open-pit methods. As a result, researchers
in the field have worked toward developing in situ methods for
recovering the oil.
The oil sand is mainly comprised of water-wet quartz grains. The
oil or bitumen is located in the interstices between the
water-sheathed grains.
The oil is extremely viscous at reservoir conditions. In fact it is
a brittle solid having a viscosity of several million centipoises
at 40.degree.F, the approximate reservoir temperature. It is
self-evident that the oil cannot be pushed through the formation to
a production well using conventional means, such as a pressure
gradient.
Workers have long been investigating ways and means for
economically unlocking the subterranean tar sands so as to recover
the contained oil. Generally speaking, these investigations have
been concerned with converting the oil to a less viscous state so
that it can be driven to and recovered from production wells using
conventional pumping or gas lift means.
One such procedure which is particularly promising involves
spontaneously emulsifying the oil to form an oil-in-water emulsion.
The product emulsion has a viscosity approaching that of water.
This procedure is described in the following patents: U.S. Pat.
Nos. 2,882,973, 3,221,813, 3,279,538, 3,379,250 and 3,396,791; and
Canadian Pat. No. 639,050.
From these patents, the following teachings are known:
Canadian Pat. No. 639,050 discloses the composition of a solution
which, when injected into a tar sand, spontaneously emulsifies
contained oil. The solution comprises water containing between
0.001 and 1.0 percent by weight of sodium hydroxide. According to
U.S. Pat. No. 2,882,973, the emulsifying power of the caustic
solution described in Canadian Pat. No. 639,050 is improved by
admixing with it a non-ionic surfactant, such as an oil-soluble
monohydric alcohol. The surfactant is provided in an amount between
0.1 and 5 percent by weight.
The prior art also teaches drilling production an injection wells
into the formation, fracturing the tar sand horizontally to
establish communications between the wells and then pumping steam
through the fracture system. The steam moves upwardly from the
fracture into the sand reservoir. In so doing, it heats the cold
oil while the steam condenses. The heated oil and water combine to
form an oil-in-water emulsion. This emulsion accumulates in the
fracture and is forced to the production well by the pressure of
the injected steam.
One problem with this system is that the emulsion cools as it moves
away from the hot zone surrounding the injection well. As it cools,
the oil again solidifies to form an impermeable block in the
fracture system. The injection pressure then rises and undesirable
vertical fracturing can occur.
Another problem is that the tar sand softens as it is heated to
emulsifying temperatures; the formation then tends to slump into
the fracture, thereby blocking it.
To overcome these problems, U.S. Pat. No. 3,221,813 teaches a
procedure wherein steam is injected into the fracture at a pressure
above the theoretical fracture propping pressure (about 0.7 p.s.i.
per foot of overburden) but below the theoretical formation
fracturing pressure. This apparently avoids the problems which
arise from slumping. If blockage of the fracture system occurs,
caustic solution is injected into the fractures to clean out the
block. Steam injection is then again resumed.
While the procedure taught in patent 3221813 has application in
areas having a thick overburden, it is not feasible in those areas
where the overburden is thin, as in the order of 200-300 feet. Here
the fracturing and propping pressures are so close to each other
that vertical fracturing easily occurs if one attempts to operate
at the propping pressure. This, of course, leads to blow-outs or
migration of the steam into thief zones.
SUMMARY OF THE INVENTION
The present invention is based on the proposition that it is
desirable, before introducing steam to the formation, to create a
hot, competent, permeable, depleted sand zone contiguous to the
fracture zone and extending between the wells. By "hot" is meant
that the temperature within the two zones is sufficient to cause
reservoir oil to combine with water to form a mobile emulsion. The
availability of this continuous hot zone within the tar sand
formation means that solidification by cooling of emulsified
bitumen moving through the fractures does not occur to any
substantial extent. Slumping of the formation is not a problem as
the high temperature of the fracture and depleted sand zones
ensures rapid emulsification of the bitumen; the slumping bitumen
is therefore removed, leaving competent clean sand.
Now, this is not a novel proposition. It has, for example, been
suggested in U.S. Pat. No. 3,396,791. However, the prior art has
only used techniques involving high pressure and temperature to
form the hot zone. Such processes are not suitable for use in tar
sand areas where the overburden is thin.
It is an object of this invention to provide a low pressure process
which can be used to develop a zone of communication between
injection and production wells.
It is another object of this invention to provide a low pressure
process for establishing a zone, permeable to steam, which extends
through a tar sand formation and connects two wells which penetrate
the sand, said zone being competent and having a temperature at
which the reservoir oil will combine readily with water in the zone
to form a mobile emulsion.
It is another object to provide a cheap, effective agent which is
adapted to react with bitumen to render part of it soluble in water
and increase its susceptibility to emulsification.
I have found that the emulsifying sodium hydroxide solutions of the
prior art do not emulsify bitumen at temperatures up to about
60.degree.F; additionally, they have slow emulsifying effect at
temperatures between about 60.degree. and 90.degree.F. It is not
until the solutions are at temperatures above about 90.degree.F
that they become emulsifying agents of any practical value. I have
also found that the bitumen or oil in tar sand is brittle at
40.degree.-60.degree.F, begins to soften (so that it can slump) at
about 60.degree.-90.degree.F and begins to form mobile, viscous
fluid at temperatures above 90.degree.F. As heating is continued,
more of the bitumen becomes fluid and the viscosity of the fluid
lessens. Finally, I have found that a non-ionic surfactant, of the
type described in U.S. Pat. No. 2,882,973, together with critical
concentrations of sodium hydroxide slowly but effectively
emulsifies bitumen at temperatures between 40.degree. and
90.degree.F. The emulsifying power of this solution increases with
temperature. Having made these observations, I have developed the
series of steps which comprises the invention.
For purposes of this disclosure, a "cold" solution is one whose
temperature, when injected into the tar sand formation, is about
the same as the formation temperature.
In accordance with the first stage of the invention, a cold agent
is pumped through the fracture zone to emulsify and remove bitumen
at temperatures below 90.degree.F. The agent is capable of
emulsifying and/or dissolving bitumen at temperatures between
40.degree. and 90.degree.F. One preferred agent is an aqueous
solution containing sodium hydroxide and a non-ionic surfactant.
Another preferred agent is ozone.
The agent is injected into the fracture zone at a bottom hole
pumping pressure which is kept substantially below the fracture
propping pressure. It is circulated between the wells for a period
of time at low pressure so as to gradually emulsify and/or dissolve
bitumen adjoining the fracture zone. In this manner a competent,
bitumen-depleted zone contiguous to the fracture zone is developed.
The fracture zone and contiguous depleted zone combine to provide a
permeable communication zone connecting the wells.
After initial interwell communication has been developed using a
cold solution containing sodium hydroxide and non-ionic surfactant,
the injection temperature of the solution is slowly increased. It
will be appreciated that, as the temperature of the injected
solution is raised, the bitumen becomes mobile in increasing
quantities; simultaneously, the emulsifying power of the solution
is increased. The rate of injection and the composition and
temperature of the solution are therefore controlled to achieve two
objects:
a. removal from the formation of the bitumen which is emulsified;
and
b. the maintenance of a bottom hole injection pressure which is
substantially less than the fracture propping pressure.
After the injection temperature of the solution reaches about
60.degree.F, one can begin to decrease the non-ionic surfactant
content while simultaneously continuing to slowly raise the
solution temperature and pumping rate. This is continued until the
surfactant is eliminated from the solution. At about 70.degree.F,
one can also begin to gradually reduce the sodium hydroxide content
of the solution. This is continued until the sodium hydroxide has
been eliminated from the solution. Both the surfactant and the
sodium hydroxide may be eliminated from the solution by the time
its temperature is raised to 200.degree.F.
It is found at this stage that the communication zone connecting
the wells is sufficiently permeable to allow steam to be injected
thereinto at desirable rates at pressures below the fracture
propping pressure.
In the case where ozone has been used to develop the initial
communication zone, an aqueous solution containing emulsifying
compounds can be introduced to the zone and circulated at gradually
increasing temperature, as just described.
DESCRIPTION OF THE PREFERRED EMBODIMENT
Geology and Completion:
The vertical geology of the Athabasca tar sand formation varies at
different locations. In some areas, the oil-saturated zone is 100
feet thick with relatively few clay stringers or permeable
water-saturated zones. In other areas, the formation may only be 35
feet thick and crowded with clay and water-saturated lenses. In
some areas, the pay zone is capped with a thick, impermeable shale
bed; in others, it is not.
The selection of a suitable area for carrying on an in situ oil
recovery programme is important to its success. Ideally, the
vertical section of the well should have a reasonably thick
overburden and an impermeable cap rock over the pay zone. The
overburden and cap rock thicknesses preferably are at least 100
feet each. The fewer the potential thief zones within the bed, the
better.
I prefer to complete both the injection and production wells by
drilling each well to the base of the tar sands and casing off all
but the bottom 5-10 feet. By fracturing the formation at its base,
a vertical steam sweep of the entire pay zone is a possibility; by
casing off the potential thief zones the probability of directing
the emulsifying fluids into the desirable regions of the reservoir
is increased.
Well Spacing:
Spacing is controlled to a large extent by the thickness of the
overburden. The thicker it is, the higher will be the pressures
which can be used during fracturing without incurring blow-outs or
excessive vertical fracturing.
I space the wells apart by about 1 foot of spacing for each pound
of injection pressure which is applied. In other words, if one
injects at 100 p.s.i., the two wells can be spaced about 100 feet
apart.
Fracturing:
At the present time, hydraulic fracturing with a propping agents
provides the best means for establishing initial interwell
communication. Conventional techniques are used. To illustrate, I
obtain communication between two wells 100 feet apart by breaking
down the formation using cold water and then injecting water,
carrying 1/2 lb/gal. of 20-40 mesh sand, into one well at a rate of
about 180 bbl/hr until sand returns are obtained at the second
well.
Completion:
It is desirable to provide means for excluding sand in the
production well after fracturing. I use conventional slotted liners
packed with 8-12 mesh sand.
Fluid Lifting:
Experience has shown that bottom hole pumps are inadequate for
bringing the emulsion to surface through the production well. The
produced sand and silt soon leaves the pump inoperative, even with
a liner present. However, good results can be obtained using
conventional air lift procedures.
Communications development:
Once communication has been achieved through a fracture system at
the base of the tar sand, it is necessary to develop the system
into a usable flow path which will accept large volumes of steam
without sealing off. This is initiated by causing cold
emulsification of the bitumen to occur within or immediately
adjacent to the fracture path.
Cold emulsification is carried out by injecting an aqueous solution
of sodium hydroxide and non-ionic surfactant into the fracture
system. The sodium hydroxide is provided in an amount less than 1.0
percent by weight; the non-ionic surfactant is provided in an
amount within the range 0.1 to 5 percent by weight.
It is found that caustic does not emulsify bitumen below about
56.degree.F. At about 79.degree.F, bitumen is emulsified on
prolonged contact (18 hours or more) with solutions containing 0.10
to 0.20 percent by weight of caustic. At 90.degree.-100.degree.F,
emulsions readily form when using solutions containing 0.05 percent
caustic but take at least 3 hours to form when using solutions
containing 0.10 percent. From the foregoing it will be noted that
the effective bitumen emulsification power of caustic begins at
about 90.degree.F and increases with temperature. It will also be
noted that the optimum concentration for emulsion formation shifts
to lower values as the temperature is increased.
With reference to the non-ionic surfactant, it is preferable to use
an octylphenoxypolyethyleneoxy ethanol wherein the side chain of
the benzene ring is branched and wherein there are 5 polyethylene
groups. This compound is sold by Rohm and Haas under the
designation Triton X-45. The quantity used is preferably within the
range 0.4 to 0.1 percent by weight.
The optimum concentrations of these agents, relative to
temperature, are in the order of the following:
TABLE I
TX45 NaOH concentra- Temperature (.degree.F) concentration (%) tion
(%) 40-50 .degree.F 0.4 0.2 50-60 0.4 0.2 60-70 0.2 0.2 70-80 0.2
0.15 80-90 0.1 0.15 90-100 0.1 0.15 100-110 0.1 0.1 110-120 0.1 0.1
__________________________________________________________________________
the solution is pumped at low pressure throughout the period of
developing the communication zone. For example, I try to keep the
wellhead injection pressure for a 230 foot deep well below 140
p.s.i. When working with deeper wells which have a thicker
overburden, one can use higher injection pressures.
The following example further illustrates the invention:
EXAMPLE 1
Three wells, A,B and C were drilled into the Athabasca tar sand at
50 foot intervals along a line. The injection well A was bottomed
in limestone at 223 feet. It was cased to 212 feet. The temperature
survey well B was bottomed in limestone at 225 feet and cased to
total depth. It was perforated in the tar sand at 223 feet. The
production well C was bottomed in limestone at 230 feet and cased
to 209 feet.
The tar sand, about 60 feet thick, immediately overlaid the
limestone. The formation was, in turn, overlain with glacial till.
There was no impermeable cap rock, such as a shale bed, above the
tar sand.
The tar sand was hydraulically fractured through the temperature
well B. The formation was broken down using water at 550-200
p.s.i.g. Water carrying 1/2 lb/gal. of 20-40 mesh round sand was
fed to the formation at 3 bbls/min. until sand returns were
observed at wells A and C.
The production well was then completed with a gravel pack.
Following completion, injection down well A was begun. The solution
used contained 0.4% by weight Triton X-45 and 0.2 percent by weight
caustic. It had an injection temperature of 40.degree.F. The
solution was fed to the formation at 2-4 bbls/hour for 8 days at
less than 25 p.s.i.g. Returns of 3/4 bbl/hour were observed at the
production well C 6 hours after lifting began. After 3 days, the
returns comprised an emulsion containing 1.5 percent by weight
bitumen. These conditions remained constant throughout this
injection period. The returns were removed from the production well
using an air lift. Injection through well A was stopped for 6
weeks.
After this period, injection was resumed through temperature well
B. Production was recovered through both the injection and
production wells A and C. The well head temperature of the solution
was increased from a starting temperature of 50.degree.F to a final
temperature of 200.degree.F over a period of days at a rate of
approximately 10.degree.F every 2 days. During this period, the
wellhead pressure rose from 50 to 140 p.s.i.g. and then dropped to
a steady level of 50-100 p.s.i.g. at an injection rate of 4-5
bbls/hour. The composition of the solution was varied as
follows:
TABLE II
Triton Temperature (.degree.F) X-45 (lb/gal.) NaOH (lb/gal.)
__________________________________________________________________________
50-60 0.4 0.2 60-70 0.2 0.2 70-80 0.2 .15 80-100 0.1 .15 100-150
0.1 .1 150-200 0.1 .05
__________________________________________________________________________
Production commenced through well C at 2 bbl/hour, declined after a
week to 1/4 bbl/hour, remained at that level for 3 weeks and then
increased to 3-4 bbls/hour for the last week. The product contained
1-2 percent by weight bitumen during the first 3 weeks; this
content rose to 7-10 percent by weight during the final week.
The final wellhead injection temperature was about 200.degree.F and
the final production temperature about 140.degree.F.
Low quality steam was then injected through well A at temperatures
up to 350.degree.F and bitumen emulsion produced at well C at
temperatures up to 280.degree.F.
EXAMPLE II
This example illustrates the use of ozone as a means for
establishing a bitumen-depleted zone within the tar sand.
A 1 1/2 .times. 18 inch glass tube was packed with 800 grams of
Athabasca tar sand. Oxygen containing 6-7 percent by volume ozone
was passed through the tube for 2 days at 170 millimeters per
minute. The experiment was carried out at room temperature.
During this period, the color of the sample changed from black to
gray as many white, clean sand grains appeared.
At the end of the period, water was passed through the tube. The
collected solution was dark brown in color and foamed when shaken
lightly. It was evaporated to dryness and the solid product
analyzed as follows:
TABLE III
Constituent % by weight
__________________________________________________________________________
carbon 41.6 hydrogen 5.0 oxygen 37.3 nitrogen 1.3 sulphur 6.6
drying loss 8.2
__________________________________________________________________________
A portion of the remaining tar sand was divided into three 50 gram
parts A, B and C. These parts were each placed in a tube.
Part A was saturated at 40.degree.F with water containing 0.2
percent by weight sodium hydroxide and 0.4 percent by weight Triton
X-45. Within 30 minutes the solution turned dark brown, indicating
very rapid emulsification.
Part B was saturated at 40.degree.F with water containing 0.2
percent by weight sodium hydroxide. No change in the color of the
solution had occurred after 2 days.
Part C was saturated at 40.degree.F with water containing .4% by
weight Triton X-45. Some darkening of this solution occurred in 30
minutes.
A fourth part D of the ozonized tar sand was stirred with water at
room temperature under a microscope. The sand grains became water
wet and bitumen separated to form globules in the water phase. When
non-ozonized tar sand was subjected to the same test, nothing
happened.
From these results it will be noted that:
a. treatment of tar sand with ozone converts some bitumen to a
water-soluble form;
b. some of the ozonized bitumen has surface active characteristics;
and
c. ozonized tar sand is more amenable to spontaneous emulsification
with an aqueous solution of sodium hydroxide and non-ionic
surfactant than is otherwise the case.
EXAMPLE III
This example illustrates that ozone is effective at formation
temperature.
A horizontal 3 foot .times. 2 inch column was tightly packed with
5.2 pounds of Athabasca tar sand. A 1/8 inch diameter path of 20-40
mesh round sand was incorporated in the tar sand along the bottom
of the column.
Oxygen containing 5-6 percent by volume ozone was passed through
the column for 61 hours. The exit gas contained only 1 percent
ozone.
A 50 gram sample of the ozonized tar sand was extracted in 500
milliliters of water. The product solution was dark brown in color
and foamed when shaken slightly. The solution was evaporated to
dryness and 0.237 grams of solid collected. This solid analyzed as
follows:
TABLE IV
Component % by weight
__________________________________________________________________________
carbon 28.7 hydrogen 3.7 oxygen 51.3 nitrogen 1.3 sulphur 8.2
drying loss 6.8
__________________________________________________________________________
A second 50 gram sample was extracted with 1.1 liters of water. The
solution required 41.4 cubic centimeters of 0.1 sodium hydroxide to
neutralize it. This test indicated the formation of acid groups due
to reaction between the ozone and bitumen.
* * * * *