U.S. patent number 3,779,602 [Application Number 05/278,407] was granted by the patent office on 1973-12-18 for process for solution mining nahcolite.
This patent grant is currently assigned to Shell Oil Company. Invention is credited to Thomas N. Beard, Peter Van Meurs.
United States Patent |
3,779,602 |
Beard , et al. |
December 18, 1973 |
PROCESS FOR SOLUTION MINING NAHCOLITE
Abstract
The process of solution mining sodium bicarbonate (e.g.,
nahcolite) from a subsurface sodium bicarbonate containing, oil
shale formation with water is improved by conducting leaching
operations at a selected temperature greater than 250.degree.F and
adjusting pressure to a particular preferred value for the selected
leaching temperature.
Inventors: |
Beard; Thomas N. (Denver,
CO), Van Meurs; Peter (Houston, TX) |
Assignee: |
Shell Oil Company (Houston,
TX)
|
Family
ID: |
23064857 |
Appl.
No.: |
05/278,407 |
Filed: |
August 7, 1972 |
Current U.S.
Class: |
299/5; 423/206.2;
166/303 |
Current CPC
Class: |
E21B
43/281 (20130101); E21B 36/00 (20130101) |
Current International
Class: |
E21B
43/00 (20060101); E21B 36/00 (20060101); E21B
43/28 (20060101); E21b 043/28 () |
Field of
Search: |
;299/4,5
;166/272,303 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Purser; Ernest R.
Claims
We claim as our invention:
1. In a method for solution-mining heat sensitive water-soluble
sodium bicarbonate minerals from a subsurface bicarbonate mineral
containing oil-shale formation of the type wherein a hot aqueous
fluid is injected into the formation to leach bicarbonate mineral
therefrom, the improvement comprising:
injecting steam into the formation at a temperature greater than
250.degree.F to leach water-soluble mineral from the formation and
thereby create a leached zone;
maintaining the temperature of fluid in the leached zone at a
temperature greater than 250.degree.F; and
adjusting pressure in the leached zone to an optimum pressure at
which the sodium mineral carrying capacity of water at the selected
temperature is a maximum.
2. The method of claim 1 further comprising producing liquid
containing dissolved sodium bicarbonate from a liquid layer
adjacent the bottom of the leached zone through a production tubing
string using artificial lift means to lift the liquid to the
surface.
3. The method of claim 2 further comprising withdrawing gas
containing CO.sub.2 from a gas layer adjacent the top of the
leached zone.
4. A method for solution-mining nahcolite from a subsurface
oil-shale formation comprising the steps of:
traversing a nahcolite-containing zone of the oil-shale formation
with a well;
extending a production string of tubing into the well to a point
adjacent the bottom of the nahcolite-containing zone;
extending an injection tubing string into the well to a point
adjacent the top of the nahcolite-containing zone;
injecting steam into contact with the nahcolite containing zone
through the injection tubing at a temperature such that upon
contacting the formation at least some of the steam condenses to
liquid which liquid flows to the bottom of the nahcolite zone
leaching nahcolite therefrom;
producing nahcolite-containing aqueous liquid from the nahcolite
zone through the production tubing;
controlling the rate and temperature of steam injection to maintain
a selected temperature of aqueous liquid adjacent the bottom of the
nahcolite zone;
adjusting the pressure in the aqueous liquid adjacent the bottom of
the nahcolite zone to an operating pressure substantially equal to
that pressure at which the amount of sodium mineral the aqueous
liquid can carry at the selected temperature is a maximum; and
maintaining the pressure in the aqueous liquid adjacent the bottom
of the nahcolite zone substantially constant at the operating
pressure.
5. The method of claim 4 wherein the operating pressure is a
pressure less than that required to hydraulically fracture the
formation.
6. The method of claim 5 wherein the operating pressure is greater
than the pressure at which the rate of nahcolite decomposition is a
maximum at the selected temperature.
Description
BACKGROUND OF THE INVENTION
Field of the Invention
This invention relates to the field of producing minerals from
subsurface formations; and more particularly, to a process for
solution mining nahcolite from subsurface oil shale formations
Description of the Prior Art
The recovery of water-soluble minerals from subsurface deposits by
solution mining with aqueous fluids is well known. In such a
process, aqueous fluid is flowed down a well into contact with a
subsurface deposit. The solution dissolves some of the soluble
mineral. The mineral-containing solvent is then flowed to the
surface where it is treated to remove the dissolved mineral, e.g.,
by evaporation.
The solubility of most commercially interesting water-soluble
minerals increases with increasing temperature. Therefore, aqueous
solution-mining fluid is often heated to increase its mineral
carrying capacity before it is injected into a subsurface mineral
deposit. For example, U.S. Pat. No. 1,649,385 issued Nov. 15, 1927,
to H. Blumenberg, Jr. teaches a method of solution-mining
crystallized boron compounds by using a mixture of hot air and
steam.
In the western United States, there are large subsurface oil shale
formations which contain substantial amounts of water-soluble,
heat-sensitive bicarbonate minerals such as trona and nahcolite.
These minerals are present both in inter-bedded substantially pure
soluble mineral layers and as dispersed nodules in certain layers
which predominently contain oil shale.
It is known that these heat-sensitive, water-soluble minerals can
be solution-mined with hot aqueous solutions. See, for example,
U.S. Pat. 3,050,290, issued Aug. 21, 1962, to N. A. Caldwell et al.
A co-pending commonly assigned application of T. N. Beard, Ser. No.
75,009, filed Sept. 24, 1970, teaches a method of producing oil
from such mineral-containing oil-shale formations which includes
permeabilization of the formation by dissolution of mineral with
hot aqueous solution.
SUMMARY OF THE INVENTION
We have now found that the process of removing heat-sensitive,
water-soluble bicarbonate minerals from subsurface oil shale
deposits by solution-mining with hot aqueous solutions is improved
by injecting steam into the formation at a selected temperature
greater than 250.degree.F, and advantageously, greater than
300.degree.F, to leach water-soluble mineral from the formation;
maintaining the temperature of fluid in the leached zone greater
than 250.degree.F; and adjusting pressure in the leached zone to a
particular optimum pressure for the selected temperature.
The optimum pressure is that pressure at which the sodium
mineral-carrying capacity of the aqueous leaching fluid is at a
maximum. At pressures below the optimum, excessive conversion of
bicarbonate material to carbonate with attendant precipitation of
carbonate leads to a reduced mineral-carrying capacity. At higher
pressures than the optimum, conversion of bicarbonate material to
carbonate is inhibited and the mineral-carrying capacity of the
leaching fluid is thereby reduced.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a graphical representation of cavity growth rate versus
cavity temperature for a nahcolite leaching operation conducted in
a nahcolite-containing oil shale formation.
FIG. 2 is a graph of sodium content expressed as equivalent pounds
of nahcolite per pound of water for a sodium carbonate saturated,
sodium bicarbonate-water system as a function of temperature.
FIG. 3 is a schematic view, partly in cross section, of a
solution-mining well equipped for the practice of this
invention.
FIG. 4 is a schematic view, partly in cross-section, of another
well system for use in the practice of this invention.
DESCRIPTION OF A PREFERRED EMBODIMENT
Referring to FIG. 3, we see a subsurface oil shale formation 10
containing strata 11 of substantially pure nahcolite (NaHCO.sub.3)
and strata 12 which are predominantly oil shale but which contain a
substantial amount of nahcolite, e.g. 20 to 40 percent nahcolite
dispersed in discreet nodules.
A solution-mining well 13 extends into the oil shale formation 10
from the earth surface. The well 13 has been completed in a
conventional manner with casing 14 sealed in place with cement 15.
A solution-mining fluid injection tubing string 16 and a
solution-mining fluid production tubing string 17 are extended into
the well 13. The lower end of the injection tubing 16 is preferably
positioned adjacent the top of a zone 9 of the oil shale formation
10 to be solution-mined. The lower end of the production tubing
string is preferably positioned near the bottom of the zone 9.
Pack-off means such as packer 18 may be positioned in the casing 14
above the lower end of the tubing string 16. Production tubing
string 17 is provided with suitable means for lifting
solution-mining fluid to the surface. For example, pumping
apparatus may be positioned adjacent the bottom of production
string 17 or the production string 17 may be equipped for gas lift
as shown in FIG. 3. In the embodiment illustrated, a pressure
actuated gas lift valve 19 is operatively connected to production
tubing 17 at a point above packer 18. A conduit 20 for injection
gas is connected to the casing 14 at the surface. To lift fluid in
the tubing 17, gas is injected through conduit 20 into casing 14.
When the pressure of this gas exceeds a certain threshold value,
valve 19 opens and admits gas into the interior of tubing 17. This
gas lightens the column of fluid in tubing 17 thereby reducing the
pressure necessary to cause fluid to flow from the bottom of tubing
17 to the earth surface.
To solution mine nahcolite from formation 10, hot aqueous
solution-mining fluid, preferably low quality steam, is injected
down tubing 16. This fluid contacts water-soluble minerals in the
formation 10 and dissolves them thereby forming a leached zone and,
eventually, a cavity 21. The cavity 21 may be at least partially
filled with fragmented particles of oil shale and nahcolite 22.
We have found that in leaching formations similar to that shown in
FIG. 1 with steam, the cavity growth rate varies logarithmically
with the cavity temperature as shown in FIG. 1 and that cavity
growth rate is only slightly dependent upon the rate of fluid
injection. It is believed that this increase in cavity growth rate
with temperature is at least in part due to more rapid thermal
fracturing at higher temperatures of oil shale surrounding discreet
nahcolite nodules. Such fracturing allows injected aqueous fluid to
reach the nahcolite nodule and leach it from the formation leaving
an exposed oil shale face which is in turn thermally fractured
opening up communication to yet another nodule.
As can be seen in FIG. 1, for temperatures below 250.degree.F,
growth rate of cavity radius is quite low, less than 0.08 feet per
day; whereas at 300.degree.F, growth rate is almost doubled to 0.15
feet per day. Thus, for maximum mineral removal, cavity temperature
should be maintained above 250.degree.F and preferably above
300.degree.F.
We have also found that in solution-mining nahcolite from an oil
shale formation with aqueous fluid, the rate of mineral recovery
can be maximized by selecting an operating temperature for maximum
desired cavity growth rate as by reference to FIG. 1, and then
during operation adjusting cavity pressure to a pressure at which
the sodium carrying capacity of the aqueous leaching fluid is a
maximum for the selected cavity temperature. This pressure is less
than that required to hydraulically fracture the formation and is
greater than the pressure at which nahcolite decomposition to
sodium carbonite, carbon dioxide and water is maximized.
Operating in this manner can significantly reduce the energy
requirement for carrying out the process since heat can be carried
to the formation by relatively low pressure steam. Additionally,
water requirements are reduced because the total amount of sodium
mineral removed from the cavity 21 by a given volume of leaching
luid is maximized.
The particular selected leaching temperature will vary from
operation to operation depending upon economic conditions and the
desired cavity growth rate for each particular case. Operating
pressure for a particular selected temperature is determined from
pressure, temperature, saturation relationships such as those given
in FIG. 2. That figure shows total sodium concentration in pounds
of nahcolite per pound of water for a sodium carbonate saturated,
sodium carbonate/sodium bicarbonate--water system. The graph
reflects the amount of nahcolite removed from a nabcolite formation
which is present in the solution even though the actual composition
of the solution includes both sodium bicarbonate and sodium
carbonate generated by nahcolite decomposition. Best results are
obtained by operating at the pressure for which the isobar
intersects the upper dashed curve at the selected operating
temperature. Good results are obtained at pressures varying as much
as 10 percent above or below this pressure.
Looking at FIG. 2 for a temperature of 400.degree., it can be seen
that at that temperature and about 200 psi only sodium bicarbonate
is present in the solution (as given by the lower dotted line of
the Figure) and that the total amount of equivalent nahcolite
dissolved is around 0.55 pounds per pound of water. However as
pressure is increased, the amount of sodium bicarbonate in the
system increases until at about 1,000 psi, the total sodium content
is equivalent to about 1.25 pounds per pound of water even though
sodium carbonate saturation remains the same. Further pressure
increase to a pressure for which the extention of an isobar would
intersect the 400.degree.F isotherm above the upper dotted line
results in the precipitation of sodium bicarbonate and an effective
reduction in the equivalent nahcolite saturation of the system.
Thus at 400.degree.F, leaching operations can be maximized if
pressure in the cavity 21 is maintained at about 1,000 psi. To
maintain this pressure, it is necessary to artifically lift fluid
from the cavity 21 if the fluid head of solution-mining fluid in
production tubing 17 is greater than 1,800 psi. Therefore, the well
13 is provided with a gas lift system as heretofore described.
FIG. 4 shows a well 22 extending into the formation 10 that is
completed in a manner particularly advantageous for the practice of
this invention. The well 22 is completed with casing 23 which
extends into the nahcolite-containing formation 10. The casing 23
is cemented in place with cement 24 and perforated adjacent
formation 10 with perforations 25 to open the interior of the
casing into communication with the formation 10.
A liquid production tubing string 26 and a gas production tubing
string 27 extend into the well from the surface. The liquid
production tubing string 26 preferably terminates at the point
adjacent the bottom of the interval of the formation 10 to be
treated whereas the gas production tubing string 27 terminates at a
point above the lower end of the liquid production tubing 26 but
below the perforations 25. The interior of the casing is preferably
sealed to fluid flow by pack-off means such as packer 28 at a point
above the terminal ends of the two tubing strings 26 and 27 and
below the perforations 25.
The liquid production tubing string is provided with means for
lifting liquid from the formation 10 to the surface. This may be a
down-hole pump or gas lift means (as illustrated in FIG. 4) in
which a gas injection string extends into the well 22 and is
connected in communication with production tubing 26 at a point
near the lower end of that tubing. The particular point of
intersection will be determined by the fluid head desired to be
maintained in liquid production string 26.
In operation, hot aqueous fluid having a temperature greater than
250.degree. and preferably greater than 300.degree.F is injected
into casing 23 through conduit 30 and then down the casing until it
passes through perforations 25 into the formation 10. This fluid
leaches nahcolite from the formation creating a cavity 31 which may
be filled with fragmented particles of oil shale and nahcolite 32.
The aqueous fluid advantageously contains high proportion of steam
which upon contacting the formation 10 condenses to form a liquid
phase capable of carrying dissolved mineral in solution.
Simultaneously with the injection of steam down the casing 22,
liquid is produced from the lower part of the cavern 31 through
production tubing string 26 and gas is produced from the cavern 31
through gas production tubing string 27. The production rate of
these fluids is preferably adjusted to maintain the pressure in the
cavern 31 at a particular preferred value for the selected
temperature operation. The removal of gas through the tubing 26
draws both steam and CO.sub.2 from the cavern 31. This results in a
reduction of the partial pressure of CO.sub.2 in the cavern and
further promotes the decomposition of nahcolite (NaHCO.sub.3) to
sodium carbonate, CO.sub.2, and water (e.g., 2 NaHCO.sub.3
.fwdarw.Na.sub.2 CO.sub.3 + CO.sub.2 + H.sub.2 O).
Both FIGS. 3 and 4 illustrates single well systems for the practice
of this invention. However, it should be understood that two or
more wells may at any one time be in communication with any
particular cavern 21 or 31 or other permeabilized zone. In such a
case, aqueous fluid may be injected into the formation 10 through
one well and produced from the formation through a separate
well.
Both FIGS. 3 and 4 illustrate the process after a cavity 21 or 31
has been formed. It should be understood that in many cases,
initial treatment will be confined to a substantially cylindrical
wellbore and that the cavern is formed only after a period of
leaching has expanded the wellbore radically.
* * * * *