U.S. patent application number 14/109859 was filed with the patent office on 2014-04-17 for situ co-development of oil shale with mineral recovery.
The applicant listed for this patent is Robert D. Kaminsky, William A. Symington, Michele M. Thomas, Jesse D. Yeakel. Invention is credited to Robert D. Kaminsky, William A. Symington, Michele M. Thomas, Jesse D. Yeakel.
Application Number | 20140102693 14/109859 |
Document ID | / |
Family ID | 36443564 |
Filed Date | 2014-04-17 |
United States Patent
Application |
20140102693 |
Kind Code |
A1 |
Kaminsky; Robert D. ; et
al. |
April 17, 2014 |
SITU CO-DEVELOPMENT OF OIL SHALE WITH MINERAL RECOVERY
Abstract
A method of producing hydrocarbon fluids from a subsurface
organic-rich rock formation, for example an oil shale formation, in
which the oil shale formation contains water-soluble minerals, for
example nahcolite, is provided. In one embodiment, the method
includes the step of heating the organic-rich rock formation in
situ. Optionally, this heating step may be performed prior to any
substantial removal of water-soluble minerals from the organic-rich
rock formation. In accordance with the method, the heating of the
organic-rich rock formation both pyrolyzes at least a portion of
the formation hydrocarbons, for example kerogen, to create
hydrocarbon fluids, and converts at least a portion of the
water-soluble minerals, for example, converts nahcolite to soda
ash. Thereafter, the hydrocarbon fluids are produced from the
formation.
Inventors: |
Kaminsky; Robert D.;
(Houston, TX) ; Symington; William A.; (Houston,
TX) ; Yeakel; Jesse D.; (Missouri City, TX) ;
Thomas; Michele M.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Kaminsky; Robert D.
Symington; William A.
Yeakel; Jesse D.
Thomas; Michele M. |
Houston
Houston
Missouri City
Houston |
TX
TX
TX
TX |
US
US
US
US |
|
|
Family ID: |
36443564 |
Appl. No.: |
14/109859 |
Filed: |
December 17, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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12636345 |
Dec 11, 2009 |
8641150 |
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14109859 |
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|
11726651 |
Mar 22, 2007 |
7644993 |
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12636345 |
|
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60793841 |
Apr 21, 2006 |
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Current U.S.
Class: |
166/248 |
Current CPC
Class: |
E21B 41/0064 20130101;
Y02C 10/14 20130101; Y02C 20/40 20200801; E21B 43/241 20130101;
G06Q 99/00 20130101; E21B 43/2401 20130101 |
Class at
Publication: |
166/248 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. An in situ method of recovering natural resources, comprising:
(a) heating in situ an organic-rich rock formation that contains
both formation hydrocarbons and one or more formation water-soluble
minerals, wherein the heating of the organic-rich rock formation
both pyrolyzes at least a portion of the formation hydrocarbons to
create hydrocarbon fluids and makes available one or more migratory
contaminant species previously bound in the organic-rich rock
formation; (b) producing at least a portion of the hydrocarbon
fluids from the organic-rich rock formation, but wherein at least a
portion of the one or more migratory contaminant species remain in
the organic-rich rock formation; (c) injecting an aqueous fluid
into the organic-rich rock formation, wherein the injected aqueous
fluid dissolves at least a portion of one or more water-soluble
minerals and the one or more migratory contaminant species to form
a first aqueous solution; (d) producing the first aqueous solution
from the organic-rich rock formation; (e) processing the first
aqueous solution in a surface facility to remove a portion of the
one or more water-soluble minerals; and (f) processing the first
aqueous solution in the surface facility to remove at least some of
the one or more migratory contaminant species.
2. The method of claim 1, wherein the heating step (a) results in
at least a portion of the organic-rich rock formation reaching a
temperature of 270.degree. C. or greater.
3. The method of claim 2, wherein the formation hydrocarbons
include solid hydrocarbons.
4. The method of claim 3, wherein the organic-rich rock formation
is an oil shale formation.
5. The method of claim 2, wherein the formation hydrocarbons
include heavy hydrocarbons.
6. The method of claim 4, wherein the organic-rich rock formation
has an initial total permeability less than 1 millidarcy before the
heating step (a).
7. The method of claim 6, wherein the organic-rich rock formation
has a post heating total permeability of greater than 10
millidarcies after the heating step (a) and before the injecting
step (c).
8. The method of claim 4, wherein the one or more migratory
contaminant species include one or more of aromatic hydrocarbons,
polyaromatic hydrocarbons, oxygenated hydrocarbons, metal
contaminants, and ionic contaminants.
9. The method of claim 8, wherein the one or more migratory
contaminant species include one or more of benzene, toluene,
xylene, ethylbenzene, tri-methylbenzene, and polyaromatic
hydrocarbon species.
10. The method of claim 8, wherein the one or more migratory
contaminant species include one or more of metal contaminants
containing arsenic, boron, chromium, mercury, selenium, lead,
vanadium, nickel, cobalt, molybdenum and zinc.
11. The method of claim 4, wherein the one or more water-soluble
minerals include sodium.
12. The method of claim 11, wherein the one or more formation
water-soluble minerals comprise nahcolite (sodium bicarbonate),
soda ash (sodium carbonate), dawsonite (NaAl(CO.sub.3)(OH).sub.2),
or combinations thereof.
13. The method of claim 4, wherein the heating step (a) is
initiated prior to substantial removal of the one or more formation
water-soluble minerals from the organic-rich rock formation.
14. The method of claim 4, wherein the heating step (a) is
initiated prior to removal of greater than 7 weight percent of the
initially present one or more formation water-soluble minerals from
the organic-rich rock formation.
15. The method of claim 4, wherein the processing step (e) includes
removing the one or more water-soluble minerals by precipitation
caused by altering the temperature of the first aqueous
solution.
16. The method of claim 4, wherein the one or more formation
water-soluble minerals include nahcolite (sodium bicarbonate) and
the one or more water-soluble minerals include soda ash (sodium
carbonate).
17. The method of claim 16, wherein the heating step (a) includes
generating the soda ash by decomposition of the nahcolite.
18. The method of claim 4, wherein the heating step (a) is
accomplished through introducing heat into heater wells penetrating
at least partially through the organic-rich rock formation.
19. The method of claim 18, wherein the heater wells include
electrical resistance heating elements.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is a Divisional of U.S. patent application
Ser. No. 12/636,345 filed Dec. 11, 2009, which is a Divisional of
U.S. patent application Ser. No. 11/726,651 filed on Mar. 22, 2007,
which claims the benefit of U.S. Provisional Patent Application No.
60/793,841 filed on Apr. 21, 2006, the entirety of each of which
are incorporated by reference herein.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to the field of hydrocarbon
recovery. More specifically, the present invention relates to the
production of hydrocarbon fluids and the recovery of water-soluble
minerals, such as nahcolite and/or soda ash, from an organic-rich
rock formation, such as an oil shale formation.
[0004] 2. Background of the Invention
[0005] Certain geological formations are known to contain an
organic matter known as "kerogen." Kerogen is a solid, carbonaceous
material. When kerogen is imbedded in mineral formations, the
mixture may be referred to as oil shale. This is true whether or
not the mineral is, in fact, technically shale, that is, a rock
formed from compacted clay. Upon heating, kerogen produces oil, gas
and some water. Oil shale formations are typically found at
relatively shallow depths (<about 3,000 feet) in various areas
world-wide and of the United States, including for example Wyoming,
Colorado and Utah. Many such formations are known to have extremely
limited permeability.
[0006] Kerogen may be converted to mobile hydrocarbons by heating
the oil shale to temperatures generally in excess of 270.degree. C.
(518.degree. F.). The rate of conversion increases sharply with
increasing temperature. When kerogen is heated, chemical reactions
break the larger molecules forming the solid kerogen into smaller
molecules of oil and gas. The thermal conversion process is
referred to as pyrolysis or retorting.
[0007] Attempts have been made for many years to extract oil from
oil shale formations. Near-surface oil shales have been mined and
retorted at the surface for over a century. In 1862, James Young
began processing Scottish oil shales. The industry lasted for about
100 years. Commercial oil shale retorting has also been conducted
in other countries such as Australia, Brazil, China, Estonia,
France, Russia, South Africa, Spain, and Sweden. However, the
practice has been mostly discontinued in recent years because it
proved to be uneconomical or because of environmental constraints
on spent shale disposal. (T. F. Yen, and G. V. Chilingarian, "Oil
Shale," Amsterdam, Elsevier, p. 292). The entire disclosure of
which is incorporated herein by reference. Further, surface
retorting requires mining of the oil shale, which limits
application to shallow formations.
[0008] Research on oil shale production was generally carried out
through the 1900's. In 1947, U.S. Pat. No. 2,732,195 issued to
Ljungstrom, the entire disclosure of which is incorporated herein
by reference. That patent, entitled "Method of Treating Oil Shale
and Recovery of Oil and Other Mineral Products Therefrom," proposed
the application of heat at high temperatures to the oil shale
formation in situ. Ljungstrom coined the phrase "heat supply
channels" to describe bore holes drilled into the formation. The
bore holes received an electrical heat conductor which transferred
heat to the surrounding oil shale. Thus, the heat supply channels
served as heat injection wells.
[0009] The heat injection wells were equipped with electrical
heating elements. The elements, in turn, were surrounded by sand or
cement or other heat-conductive material. Each heat injection well
transmitted heat into the surrounding oil shale while preventing
any inflow of fluid. Along with the heat injection wells, fluid
producing wells were also completed in near proximity to the heat
injection wells. As kerogen was pyrolyzed upon heat conduction into
the rock matrix, the resulting oil and gas would be recovered
through the adjacent production wells.
[0010] Ljungstrom applied his approach of thermal conduction from
heated wellbores through the Swedish Shale Oil Company. A
full-scale plant was developed that operated from 1944 into the
1950's. (G. Salamonsson, "The Ljungstrom In Situ Method for
Shale-Oil Recovery," 2.sup.nd Oil Shale and Cannel Coal Conference,
v. 2, Glasgow, Scotland, Institute of Petroleum, London, p. 260-280
(1951)). The entire disclosure of which is incorporated herein by
reference.
[0011] Since 1947, various patents have been issued offering
modifications and improvements to Ljungstrom's ideas. For instance,
U.S. Pat. No. 3,468,376 issued to Slusser, et al. in 1969 entitled
"Thermal Conversion of Oil Shale into Recoverable Hydrocarbons",
the entire disclosure of which is incorporated herein by reference.
The '376 Slusser, et al. patent suggested a process for circulating
a heated pyrolyzing fluid through a flow channel. Abrasive
particles were added to the circulating fluid to erode a layer of
pyrolyzed oil shale being formed adjacent to the flow channel. This
provided a channel for the flow of converted kerogen.
[0012] It was recognized in the Slusser, et al. patent that
"[t]here are two mechanisms involved in the transport of heat
through the oil shale." First, heat is transferred through the
solid mass of oil shale by conduction. Second, heat is transferred
by convection through fluid flow of pyrolyzed kerogen within the
oil shale." Slusser, et al. noted that typically the transfer of
heat by conduction is a relatively slow process due to the oil
shale being an inherently poor conductor of heat. If significant
permeability does exist or is created, convective heat transfer by
fluids traveling through fine channels in the oil shale can
contribute to the overall rate of heat transfer.
[0013] Various means for heating the rock matrix and imbedded
kerogen have been proposed. U.S. Pat. No. 4,140,180, assigned to
the ITT Research Institute in Chicago, Ill. and issued in 1979,
suggested the application of in situ heat using radio frequency
(RF) electrical energy. The entire disclosure of which is
incorporated herein by reference. In doing so, the '180 patent
listed and described other methodologies for applying pyrolyzing
heat using electrical energy. The patent stated that, as of that
time, "there is no . . . acceptable economical way to extract the
hydrocarbon constituents."
[0014] Techniques for in situ retorting of oil shale were developed
and pilot tested with the Green River oil shale in the United
States in the 1970's and 1980's. In situ processing offers
advantages because it reduces costs associated with material
handling and disposal of spent shale. In a number of the in situ
pilots, the oil shale was first rubblized. Thereafter, combustion
was carried out by air injection. A rubble bed with substantially
uniform fragment size and substantially uniform distribution of
void volume was a key success factor in combustion sweep
efficiency. Fragment size was of the order of several inches.
[0015] Nevertheless, attempts to economically extract shale oil
continued. In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil
Company, the entire disclosure of which is incorporated herein by
reference. That patent, entitled "Conductively Heating a
Subterranean Oil Shale to Create Permeability and Subsequently
Produce Oil," declared that "[c]ontrary to the implications of . .
. prior teachings and beliefs . . . the presently described
conductive heating process is economically feasible for use even in
a substantially impermeable subterranean oil shale." (col. 6, ln.
50-54). The '118 patent proposed controlling the rate of heat
conduction within the rock surrounding each heat injection well to
provide a uniform heat front. The process was limited to formations
having a specified grade and thickness.
[0016] Additional history behind shale oil retorting and recovery
can be found in patent publication WO 2005/010320 entitled "Methods
of Treating a Subterranean Formation to Convert Organic Matter into
Producible Hydrocarbons," and in WO 2005/045192 entitled
"Hydrocarbon Recovery from Impermeable Oil Shales." The Background
and technical disclosures of these two patent publications are
incorporated herein by reference.
[0017] The WO 2005/010320 process involves the use of electrically
conductive fractures to heat the oil shale. A heat source is
constructed using wellbores and then hydraulically fracturing the
oil shale. The fractures are filled with an electrically conductive
material which forms a heating element. Calcined petroleum coke is
a suitable conductant material. Preferably, the fractures are
created in a vertical orientation along longitudinal, horizontal
planes formed by horizontal wellbores. Electricity is conducted
through the conductive fractures from the heel to the toe of each
well. The electrical circuit is completed by an additional
horizontal well that intersects one or more of the vertical
fractures near the toe to supply the opposite polarity. Modeling
suggests that temperatures in the immediate vicinity of the
fracture exceed 600.degree. C. Thermal conduction heats and
artificially matures the oil shale to conversion temperatures in
excess of 300.degree. C.
[0018] The WO 2005/045192 process involves the circulation of
supercritical naphtha through fractures. This means that the oil
shale is heated by circulating a dense, hot hydrocarbon vapor
through sets of closely-spaced hydraulic fractures. In this
instance, the fractures are horizontally formed and conventionally
propped. Fracture temperatures of 320.degree.-400.degree. C. are
maintained for five to ten years. Vaporized naphtha is typically
the preferred heating medium due to its high volumetric heat
capacity, ready availability and relatively low degradation rate at
the heating temperature. In the WO 2005/045192 process, as the
kerogen matures, fluid pressure will drive the generated oil to the
heated fractures, where it will be produced with the cycling
hydrocarbon vapor.
[0019] In some oil shale formations, additional minerals of
commercial value are present within the rock. One such mineral is
nahcolite. Nahcolite is a natural mineral (NaHCO.sub.3), and is
commonly known as baking soda or sodium bicarbonate. The mineral
can be associated with oil shale deposits such as those located in
parts of the Piceance Basin in Colorado. Nahcolite resources in the
Piceance Basin are estimated by the United States Geological Survey
at over 29 billon metric tons. (J. R. Dyni, "Stratigraphy and
Nahcolite Resources of the Saline Facies of the Green River
Formation in Northwest Colorado," in D. K. Murray (ed.), Guidebook
to the Energy Resources of the Piceance Creek Basin Colo., Rocky
Mountain Association of Geologists--1974 Guidebook, pp. 111-122
(1974)). The entire disclosure of which is incorporated herein by
reference.
[0020] Nahcolite typically occurs as finely disseminated crystals
and nodules within oil shale beds. It also occurs in several
discrete beds mixed with variable amounts of oil shale and
sometimes associated with halite. Much of the nahcolite in the
Piceance Basin occurs as either non-bedded crystalline aggregates
scattered through the oil shale, or as laterally continuous units
of fine crystals disseminated in the oil shale. The sodium
bicarbonate processed from nahcolite has value for use in food (as
baking soda), in pharmaceutical products, in flue gas clean-up
(such as SO.sub.2 removal), and in fire extinguishers.
[0021] Sodium bicarbonate can be converted to sodium carbonate
(Na.sub.2CO.sub.3; also known as soda ash). The conversion takes
place in the presence of heat according to the following chemical
reaction:
2NaHCO.sub.3Na.sub.2CO.sub.3+CO.sub.2+H.sub.2O
Sodium carbonate, or soda ash, is a large-scale commodity chemical.
Soda ash is used in glass making, chemical manufacture, and the
manufacture of detergents. Much of the sodium bicarbonate produced
via mining is converted in surface facilities to soda ash.
[0022] Nahcolite can be recovered from oil shale via solution
mining. (M. Prats, P. J. Closmann, A. T. Ireson, and G. Drinkard,
"Soluble-Salt Processes for In-Situ Recovery of Hydrocarbons from
Oil Shale," Journal of Petroleum Technology, pp. 1078-1088
(September 1977)). The entire disclosure of which is incorporated
herein by reference. The process involves injecting hot water under
pressure into the subsurface. Sodium bicarbonate is fairly soluble
in water.
[0023] American Soda previously developed a facility in the
Piceance region of Colorado for solution mining of Nahcolite. The
facility was operational in 2000. American Soda's production
operations are described in the 2004 publication M. Ramey and M.
Hardy, "The History and Performance of Vertical Well Solution
Mining of Nahcolite (NaHCO.sub.3) in the Piceance Basin,
Northwestern, Colorado, USA", Solution Mining Research Institute:
Fall 2004 Technical Meeting (Berlin, Germany) (2004). The entire
disclosure of which is incorporated herein by reference. American
Soda's solution mining technology is also discussed in U.S. Pat.
No. 6,609,761 issued in 2003. The entire disclosure of which is
incorporated herein by reference. According to the paper, the well
field included 26 solution mining wells which produced nahcolite
brine to a processing facility. Water at 350-420.degree. F. was
injected into the formation to remove the nahcolite at a depth of
2,200 to 2,600 feet.
[0024] By late 2004, the American Soda facility had produced 2.6
million tons of nahcolite. The facility converted the sodium
bicarbonate to sodium carbonate, produced liquid CO.sub.2, and
concentrated the sodium carbonate solution via evaporation. The
solution was then pumped to a second facility 44 miles away. The
conversion of sodium bicarbonate to sodium carbonate was necessary
to prevent solid precipitation in the pipeline as the solution
cooled during transit. Sodium carbonate is much more soluble than
sodium bicarbonate at the flow temperatures. The solution at the
second facility was then reconverted back to sodium bicarbonate via
contacting the solution with CO.sub.2 to precipitate the sodium
bicarbonate. The sodium bicarbonate was then sold and shipped from
the facility.
[0025] Other companies such as White River Nahcolite Minerals and
American Alkali have studied Nahcolite solution mining and
processing. (R. L. Day, "Solution Mining of Colorado Nahcolite,"
Wyoming State Geological Survey Public Information Circular 40,
Proceedings of the First International Soda Ash Conference, Volume
II (Rock Springs, Wyo., Jun. 10-12, 1997) pp. 121-130 (1998); K. R.
Nielsen, "Colorado Nahcolite: A Low Cost Source of Sodium
Chemicals," Seventh Annual Canadian Conference on Markets for
Industrial Minerals (Vancouver, Canada, Oct. 17-18, 1995) 1-9). The
entire disclosures of which are incorporated herein by reference.
In the disclosed processes, the produced sodium bicarbonate
solution is processed through a facility in order to generate three
dry products: sodium bicarbonate, light soda ash, and dense soda
ash. The processes start by crystallizing sodium bicarbonate out of
solution via cooling. Light soda ash is produced by drying wet
sodium bicarbonate at 600-800.degree. F. This results in
decomposition to a low bulk density (30-35 lbs/ft.sup.3) powder.
Dense soda ash is formed by crystallizing soda ash out of a
supersaturated solution. This results in granules with a bulk
density of about 63 lbs/ft.sup.3. The benefit of producing three
products is that each has a different market. The facility can
shift the distribution of products based on current market
conditions. Typically, sodium bicarbonate and light soda ash
command higher prices, but the markets are more limited than for
dense soda ash.
[0026] Another company involved in Nahcolite mining operations is
NaTec, Ltd. NaTec is the listed assignee of U.S. Pat. No. 4,815,790
which issued in 1989, the entire disclosure of which is
incorporated herein by reference. The patent is entitled "Nahcolite
Solution Mining Process." The patent discloses a process for
creating sodium bicarbonate using a "hot aqueous liquor." This
process also produced sodium bicarbonate solution which was then
processed through a facility to generate three dry products: sodium
bicarbonate, light soda ash, and dense soda ash. It is noted that
much of the nahcolite was converted to a soda ash product at the
surface facilities.
[0027] Because nahcolite and oil shale occur together in certain
oil shale deposits such as the Piceance Basin, the recovery of
either mineral impacts the fate of the other. It has been proposed
that nahcolite can be removed through solution mining prior to the
in situ production of shale oil. This was discussed by Prats, M.,
et al. in the 1977 articled cited above. This was also proposed by
Shell as early as 1972 in U.S. Pat. No. 3,700,280, entitled "Method
of Producing Oil from an Oil Shale Formation Containing Nahcolite
and Dawsonite", the entire disclosure of which is incorporated
herein by reference. See also U.S. Pat. No. 3,759,574 entitled
"Method of Producing Hydrocarbons from an Oil Shale Formation", the
entire disclosure of which is incorporated herein by reference. The
concept of nahcolite removal involves leaching the nahcolite (and
other water-soluble minerals such as halite and, to a lesser
degree, dawsonite) to create permeability in the otherwise fairly
impermeable oil shale. After the permeability is created, hot steam
is injected into the formation to convert the kerogen bound in the
oil shale to liquid (oil) and hydrocarbon gas. The oil and gas is
then recovered via production wells.
[0028] Recently, U.S. Pat. No. 6,997,518 issued to Vinegar, et al.
in 2006, the entire disclosure of which is incorporated herein by
reference. This patent is entitled "In Situ Thermal Processing and
Solution Mining of an Oil Shale Formation." The '518 patent
proposes developing nahcolite prior to in situ conversion of the
oil shale using downhole heat sources. Such heat sources include
electric heaters and downhole flameless combustors. Vinegar argues
that removing the nahcolite prior to shale oil production is
beneficial since it reduces the energy needed to convert the
kerogen. The decomposition reaction of nahcolite is endothermic
plus the nahcolite has thermal capacity and, hence, drains energy
otherwise useable for heating the oil shale. Additionally, in
certain areas regulatory conditions require that the oil shale be
developed in such a way as to preserve the value of the
nahcolite.
[0029] The '518 patent lists a variety of other perceived
advantages to removing nahcolite (and dawsonite) prior to kerogen
retorting. For instance, Vinegar states that removing the nahcolite
"may reduce mass within the formation and increase a permeability
of the formation. Reducing the mass within the formation may reduce
the heat required to heat to temperatures needed for the in situ
conversion process. Reducing the mass within the formation may also
increase a speed at which a heat front within the formation moves.
Increasing the speed of the heat front may reduce a time needed for
production to begin." (See col. 324, ln. 40-48).
[0030] A need exists for improved processes for the production of
shale oil which preserves the value of the nahcolite in-place. In
addition, a need exists for improved methods for co-developing
shale oil and nahcolite in soda ash form. Still further, a need
exists for a process by which the nahcolite may be recovered after
heating an oil shale zone and producing the shale oil.
SUMMARY OF THE INVENTION
[0031] In one embodiment, the invention includes an in situ method
of recovering natural resources. The method includes (a) heating in
situ an organic-rich rock formation that contains both formation
hydrocarbons and one or more formation water-soluble minerals,
wherein the heating of the organic-rich rock formation both
pyrolyzes at least a portion of the formation hydrocarbons to
create hydrocarbon fluids and makes available one or more migratory
contaminant species previously bound in the organic-rich rock
formation. The method may further include producing at least a
portion of the hydrocarbon fluids from the organic-rich rock
formation, but wherein at least a portion of the one or more
migratory contaminant species remain in the organic-rich rock
formation. The method may further include injecting an aqueous
fluid into the organic-rich rock formation, wherein the injected
aqueous fluid dissolves at least a portion of one or more
water-soluble minerals and the one or more migratory contaminant
species to form a first aqueous solution. The method may further
include producing the first aqueous solution from the organic-rich
rock formation. The method may further include processing the first
aqueous solution in a surface facility to remove a portion of the
one or more water-soluble minerals and processing the first aqueous
solution in the surface facility to remove at least some of the one
or more migratory contaminant species.
BRIEF DESCRIPTION OF THE DRAWINGS
[0032] So that the features of the present invention can be better
understood, certain drawings, graphs and flow charts are appended
hereto. It is to be noted, however, that the drawings illustrate
only selected embodiments of the inventions and are therefore not
to be considered limiting of scope, for the inventions may admit to
other equally effective embodiments and applications.
[0033] FIG. 1 is a perspective view of an illustrative oil shale
development area. A plurality of wellbores is shown completed in an
oil shale formation. A fluid processing area is also shown
schematically.
[0034] FIG. 2 is a flow chart showing a series of steps that may be
undertaken in the production of hydrocarbon fluids and the recovery
of nahcolite from an oil shale formation, in accordance with one
aspect of the present methods.
[0035] FIG. 3 is a bar chart comparing the volume of an oil shale
sample before and after an in situ, retorting process.
[0036] FIG. 4 is a schematic diagram of a solution mining and/or
groundwater clean-up operation.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
[0037] As used herein, the term "hydrocarbon(s)" refers to organic
material with molecular structures containing carbon and hydrogen.
Hydrocarbons may also include other elements, such as, but not
limited to, halogens, metallic elements, nitrogen, oxygen, and/or
sulfur.
[0038] As used herein, the term "hydrocarbon fluids" refers to
hydrocarbons that are gases or liquids. Hydrocarbon fluids may
include, for example, shale oil, pyrolysis oil, pyrolysis gas, a
pyrolysis product of coal, and other hydrocarbons that are in a
gaseous or liquid state.
[0039] As used herein, the terms "produced fluids" and "production
fluid" refer to liquids and/or gases removed from an organic-rich
rock formation and may include hydrocarbon fluids, shale oil,
pyrolysis oil, pyrolysis gas, a pyrolysis product of coal,
synthesis gas, and water (steam). Produced fluids may include
hydrocarbon fluids as well as non-hydrocarbon fluids.
[0040] As used herein, the term "heavy hydrocarbons" refers to
hydrocarbon fluids that are highly viscous at ambient conditions
(15.degree. C. and 1 atm pressure). Heavy hydrocarbons may include
highly viscous hydrocarbon fluids such as heavy oil, tar, and/or
asphalt. Heavy hydrocarbons may include carbon and hydrogen, as
well as smaller concentrations of sulfur, oxygen, and nitrogen.
Additional elements may also be present in heavy hydrocarbons in
trace amounts. Heavy hydrocarbons may be classified by API gravity.
Heavy hydrocarbons generally have an API gravity below about 20
degrees. Heavy oil, for example, generally has an API gravity of
about 10-20 degrees, whereas tar generally has an API gravity below
about 10 degrees. The viscosity of heavy hydrocarbons is generally
greater than about 100 centipoise at 15.degree. C. Heavy
hydrocarbons may also include aromatics or other complex ring
hydrocarbons.
[0041] As used herein, the term "solid hydrocarbons" refers to any
hydrocarbon material that is found naturally in substantially solid
form at formation conditions. Non-limiting examples include
kerogen, coal, shungites, asphaltites, and natural mineral
waxes.
[0042] As used herein, the term "formation hydrocarbons" refers to
both heavy hydrocarbons and solid hydrocarbons that are contained
in a formation. Formation hydrocarbons may be, but are not limited
to, kerogen, coal, bitumen, natural mineral waxes, and
asphaltites.
[0043] As used herein, the term "tar" refers to a viscous
hydrocarbon that generally has a viscosity greater than about
10,000 centipoise at 15.degree. C. The specific gravity of tar
generally is greater than 1.000. Tar may have an API gravity less
than 10 degrees.
[0044] As used herein, the term "kerogen" refers to a solid,
insoluble hydrocarbon that principally contains carbon, hydrogen,
nitrogen, oxygen, and sulfur. Oil shale contains kerogen.
[0045] As used herein, the term "bitumen" refers to a
non-crystalline solid or viscous hydrocarbon material that is
substantially soluble in carbon disulfide.
[0046] As used herein, the term "oil" refers to a fluid containing
a mixture of condensable hydrocarbons.
[0047] As used herein, the term "organic-rich rock" refers to any
rock matrix holding formation hydrocarbons (i.e. solid hydrocarbons
and/or heavy hydrocarbons). Rock matrices may include, but are not
limited to, sedimentary rocks, shales, stone silt, sands,
silicilytes, carbonates, and diatomites.
[0048] As used herein, the term "formation" refers to one or more
hydrocarbon containing layers, one or more non-hydrocarbon layers,
an overburden, and/or an underburden of any subsurface geologic
formation. An "overburden" and/or an "underburden" includes one or
more different types of substantially impermeable materials. For
example, overburden and/or underburden may include rock, shale,
mudstone, or wet/tight carbonate (i.e., an impermeable carbonate
without hydrocarbons). In some embodiments of in situ conversion
processes, an overburden and/or an underburden may include a
hydrocarbon containing layer or hydrocarbon containing layers that
are relatively impermeable and are not subjected to temperatures
during in situ conversion processing that result in significant
characteristic changes of the hydrocarbon containing layers of the
overburden and/or underburden. For example, an underburden may
contain shale or mudstone. In some cases, the overburden and/or
underburden may be somewhat permeable.
[0049] As used herein, the term "organic-rich rock formation"
refers to any formation containing organic-rich rock.
[0050] As used herein, the term "water-soluble minerals" refers to
minerals that are soluble in water. Water-soluble minerals include,
for example, nahcolite (sodium bicarbonate), soda ash (sodium
carbonate), dawsonite (NaAl(CO.sub.3)(OH).sub.2), or combinations
thereof.
[0051] As used herein, the term "formation water-soluble minerals"
refers to water-soluble minerals that are found naturally in a
formation.
[0052] As used herein, the term "migratory contaminant species"
refers to species that are both soluble or moveable in water or an
aqueous fluid and are considered to be harmful or of concern to
human health or the environment. Migratory contaminant species may
include inorganic and organic contaminants. Organic contaminants
may include saturated hydrocarbons, aromatic hydrocarbons, and
oxygenated hydrocarbons. Inorganic contaminants may include metal
contaminants, and ionic contaminants of various types that may
significantly alter pH or the formation fluid chemistry. Aromatic
hydrocarbons may include, for example, benzene, toluene, xylene,
ethylbenzene, and tri-methylbenzene, and various types of
polyaromatic hydrocarbons such as anthracenes, naphthalenes,
chrysenes and pyrenes. Oxygenated hydrocarbons may include, for
example, alcohols, ketones, phenols, and organic acids such as
carboxylic acid. Metal contaminants may include, for example,
arsenic, boron, chromium, cobalt, molybdenum, mercury, selenium,
lead, vanadium, nickel or zinc. Ionic contaminants include, for
example, sulfides, sulfates, chlorides, fluorides, ammonia,
nitrates, calcium, iron, magnesium, potassium, lithium, boron, and
strontium.
[0053] As used herein, the term "wellbore" refers to a hole in a
formation made by drilling or insertion of a conduit into the
formation. A wellbore may have a substantially circular cross
section, or other cross-sectional shapes (e.g., circles, ovals,
squares, rectangles, triangles, slits, or other regular or
irregular shapes). As used herein, the term "well", when referring
to an opening in the formation, may be used interchangeably with
the term "wellbore."
[0054] As used herein, the term "pyrolysis" refers to the breaking
of chemical bonds due to the application of heat. For example,
pyrolysis may include transforming a compound into one or more
other substances by heat alone or by heat in combination with an
oxidant.
[0055] Pyrolysis may include modifying the nature of the compound
by addition of hydrogen, water, carbon dioxide, or carbon monoxide.
Heat may be transferred to a section of the formation to cause
pyrolysis.
[0056] As used herein, the term "cracking" refers to a process
involving decomposition and molecular recombination of organic
compounds to produce a greater number of molecules than were
initially present. In cracking, a series of reactions take place
accompanied by a transfer of hydrogen atoms between molecules. For
example, naphtha may undergo a thermal cracking reaction to form
ethene and H.sub.2 among other molecules.
[0057] As used herein, the term "sequestration" refers to storing a
fluid that is a by-product of a process rather than discharging the
fluid to the atmosphere or open environment.
[0058] As used herein, the term "subsidence" refers to a downward
movement of a portion of a formation relative to an initial
elevation of the surface.
[0059] As used herein, the term "thickness" of a layer refers to
the thickness of a cross section of a layer, wherein the cross
section is normal to a face of the layer.
[0060] As used herein, the term "thermal fracture" refers to
fractures created in a formation caused directly or indirectly by
expansion or contraction of a formation and/or fluids within the
formation, which is in turn caused by increasing/decreasing the
temperature of the formation and/or fluids within the formation,
and/or by increasing/decreasing a pressure of fluids within the
formation due to heating. Thermal fractures may propagate into or
form in neighboring regions significantly cooler than the heated
zone.
[0061] As used herein, the term "hydraulic fracture" refers to a
fracture at least partially propagated along a plane in a
formation, wherein the fracture is created through injection of
fluids into a formation. The fracture may include proppant
material.
DESCRIPTION OF SPECIFIC EMBODIMENTS
[0062] The inventions are described herein in connection with
certain specific embodiments. However, to the extent that the
following detailed description is specific to a particular
embodiment or a particular use, this is intended to be illustrative
only, and is not to be construed as limiting the scope of the
invention.
[0063] The present invention provides an in situ method for
generating and recovering both hydrocarbon fluids and water-soluble
minerals (e.g., sodium minerals) from an organic-rich rock
formation (e.g., oil shale formations). In some oil shale
formations such as the Parachute Creek Member of the Green River
Formation located in the Piceance Basin in Colorado, the oil shale
holds both kerogen and nahcolite. It may be desirable in
multi-mineral leasing areas, such as those managed by the United
States Bureau of Land Management, that the production of shale oil
from kerogen does not squander or waste the value of the in situ
nahcolite. Thus, in one aspect, the present invention provides for
the production of shale oil, followed by the recovery of
water-soluble minerals, particularly nahcolite or decomposition
products of nahcolite, for example, soda ash. In another aspect,
shale oil and nahcolite (or nahcolite derivates) are co-produced.
In either aspect, the value of the water-soluble minerals is
preserved.
[0064] Sodium bicarbonate can be converted to sodium carbonate
(Na.sub.2CO.sub.3; also known as soda ash). The conversion takes
place in the presence of heat according to the following chemical
reaction formula:
2NaHCO.sub.3Na.sub.2CO.sub.3+CO.sub.2+H.sub.2O
[0065] The water generated via nahcolite decomposition may be in
the vapor state but can condense to liquid water as it migrates
away from the heated region. Water may also be generated via
decomposition of other minerals, such as dawsonite, decomposition
of kerogen, and expulsion of bound water from clays.
[0066] Sodium carbonate, or soda ash, is a large-scale commodity
chemical. Soda ash is used in glass making, chemical manufacture,
and the manufacture of detergents. Much of the sodium bicarbonate
produced via mining is converted in surface facilities to soda ash.
The decomposition of sodium bicarbonate to sodium carbonate can
occur at relatively low temperatures; however, the process is
pressure sensitive. As pressure increases, the concentration of
carbon dioxide in the vapor phase increases and retards the
decomposition. Templeton studied this effect and found that the
decomposition temperature increases as follows:
[0067] from .about.200.degree. F. at atmospheric pressure, to
[0068] .about.360.degree. F. at 1000 psia, to
[0069] .about.385.degree. F. at 2000 psia, and to
[0070] .about.405.degree. F. at 3000 psia.
(Templeton, C. C., "Pressure-Temperature Relationship for
Decomposition of Sodium Bicarbonate from 200 to 600.degree. F.,"
Journal of Chemical and Engineering Data, 23(1), pp. 7-11 (1978)).
The entire disclosure of which is incorporated herein by
reference.
[0071] Dawsonite decomposes via the following reaction:
2NaAl(OH).sub.2CO.sub.3Na.sub.2CO.sub.3+Al.sub.2O.sub.3+CO.sub.2+2H.sub.-
2O
[0072] Nahcolite can be recovered from oil shale via solution
mining. The process involves injecting hot water under pressure
into the subsurface. Sodium bicarbonate is fairly soluble in water.
Solubility increases with temperature as follows:
[0073] .about.0.1 lb NaHCO.sub.3/lb water at 100.degree. F.,
[0074] .about.0.2 lb NaHCO.sub.3/lb water at 200.degree. F.,
[0075] .about.0.4 lb NaHCO.sub.3/lb water 300.degree. F., and
[0076] .about.0.8 lb NaHCO.sub.3/lb water 400.degree. F.
[0077] Applicant believes that certain in situ oil shale retorting
processes, including the WO 2005/045192 and WO 2005/010320
processes disclosed in the above-referenced international patent
publications, will materially improve the accessibility of the
nahcolite and therefore increase the value derived from solution
mining.
[0078] It is noted that at very high temperatures, soda ash will
decompose to sodium oxide according to the following reaction:
Na.sub.2CO.sub.3.fwdarw.Na.sub.2O+CO.sub.2
[0079] In a swept atmosphere this will occur at about 800.degree.
C. In a CO.sub.2 atmosphere the decomposition is strongly
suppressed even at 1000.degree. C. (Newkirk, A. E. and Aliferis,
I., "Drying and Decomposition of Sodium Carbonate," Analytical
Chemistry, 30(5), pp. 982-984 (1958)). The entire disclosure of
which is incorporated herein by reference. In solution sodium
carbonate can decompose at much lower temperatures to sodium
hydroxide:
Na.sub.2CO.sub.3+H.sub.2O2NaOH+CO.sub.2
[0080] This reaction, however, is very much an equilibrium reaction
and unless the CO.sub.2 is continually removed, the conversion is
limited. (Thomas, A. M., "Thermal Decomposition of Sodium Carbonate
Solutions", Journal of Chemical and Engineering Data, 8(1), pp.
51-54 (1963)). The entire disclosure of which is incorporated
herein by reference. Indeed, sodium hydroxide reacts readily with
acid gases (such as CO.sub.2, H.sub.25 and SO.sub.2) to produce
Na.sub.2CO.sub.3. This reverse reaction is commonly used in the
chemical industry for scrubbing CO.sub.2 from gas streams.
(Encyclopedia of Chemical Technology (4.sup.th ed.), "Alkali and
Chlorine Products," pp. 1025-1039). The entire disclosure of which
is incorporated herein by reference.
[0081] FIG. 1 presents a perspective view of an illustrative oil
shale development area 10. A surface 12 of the development area 10
is indicated. Below the surface is an organic-rich rock formation
16. The illustrative formation 16 contains formation hydrocarbons
(such as, for example, kerogen) and valuable water-soluble minerals
(such as, for example, nahcolite). It is understood that the
representative formation 16 may be any organic-rich rock formation,
including a rock matrix containing coal or tar sands, for example.
In addition, the rock matrix making up the formation may be
permeable, semi-permeable or non-permeable. Preferably, the present
inventions may be practiced in oil shale development areas
initially having very limited or effectively no fluid
permeability.
[0082] In order to access formation 16 and recover natural
resources therefrom, a plurality of wellbores is formed. Wellbores
are shown at 14 in FIG. 1. The representative wellbores 14 are
essentially vertical in orientation relative to the surface 12.
However, it is understood that some or all of the wellbores 14
could deviate into an obtuse or even horizontal orientation. In the
arrangement of FIG. 1, each of the wellbores 14 is completed in the
oil shale formation 16. The completions may be either open or cased
hole. The well completions may also include propped or unpropped
hydraulic fractures.
[0083] In the view of FIG. 1, only seven wellbores 14 are shown.
However, it is understood that in an oil shale development project,
numerous additional wellbores 14 will most likely be drilled. The
wellbores 14 may be located in relatively close proximity, being
from 10 feet to up to 300 feet in separation. Alternatively, the
wellbores may be spaced from 30 to 200 feet or 50 to 100 feet.
Typically, the wellbores 14 are also completed at shallow depths,
being from 200 to 5,000 feet at total depth. Alternatively, the
wellbores may be completed at depths from 1,000 to 4,000 feet, or
1,500 to 3,500 feet. In some embodiments the oil shale formation
targeted for in situ retorting is at a depth greater than 200 feet
below the surface. In alternative embodiments, the oil shale
formation targeted for in situ retorting is at a depth greater than
1000, 1100, 1200, 1300 or 1500 feet below the surface. In
alternative embodiments, the oil shale formation targeted for in
situ retorting is at a depth between 200 and 5,000 feet,
alternatively between 1,000 and 4,000 ft, 1,200 and 3,700 feet, or
1,500 and 3,500 feet below the surface.
[0084] The wellbores 14 will be selected for certain functions and
may be designated as heat injection wells, water injection wells,
oil production wells or water-soluble mineral solution production
wells. In one aspect, the wellbores 14 are dimensioned to serve
two, three, or all four of these purposes. Suitable tools and
equipment may be sequentially run into and removed from the
wellbores 14 to serve the various purposes.
[0085] A fluid processing facility 20 is also shown schematically.
The fluid processing facility 20 is equipped to receive fluids
produced from the organic-rich rock formation 16 through one or
more pipelines or flow lines 22. The fluid processing facility 20
may include equipment suitable for receiving and separating oil,
gas, and water produced from the heated formation. The fluid
processing facility 20 may further include equipment for separating
out dissolved water-soluble minerals and/or migratory contaminant
species, including, for example, dissolved organic contaminants,
metal contaminants, or ionic contaminants in the produced water
recovered from the organic-rich rock formation 16. The contaminants
may include, for example, aromatic hydrocarbons such as benzene,
toluene, xylene, tri-methylbenzene, and polyaromatic hydrocarbons
such as anthracene, naphthalene, chrysene and pyrene. Metal
contaminants may include species containing arsenic, boron,
chromium, mercury, selenium, lead, vanadium, nickel, cobalt,
molybdenum, or zinc. Ionic contaminant species may include, for
example, sulfates, chlorides, fluorides, lithium, potassium,
aluminum, ammonia, and nitrates.
[0086] The contaminants may be removed in surface facilities by
various means. One such method is via an adsorbent material such as
activated carbon, activated alumina, silica gel, clay, or fuller's
earth. Another such method is to employ bio-oxidation to treat the
organic contaminants. Because of the potential for ground water
contaminants, one optional step in the method is to assess the
hydrological connectivity of the oil shale zone with aquifers to
determine the risk to ground water.
[0087] The dissolved water-soluble minerals removed from the oil
shale formation are preferably ones with chemical compositions that
include sodium. Examples of sodium minerals include nahcolite
(sodium bicarbonate), soda ash (sodium carbonate), or dawsonite
(NaAl(CO.sub.3)(OH).sub.2), or combinations thereof. In some
instances, the soluble minerals are generated via decomposition of
other minerals due to the oil shale heating. Preferably, the
original soluble mineral is nahcolite, and the decomposed mineral
is soda ash.
[0088] The dissolved water-soluble minerals may be removed from the
produced fluid in one aspect by precipitation caused by altering
the temperature of the solution. The soda ash (sodium carbonate)
may be converted back to nahcolite (sodium bicarbonate) in surface
facilities via reaction with CO.sub.2.
[0089] Alternatively, the equipment for separating out water
dissolved minerals and contaminants are in other facilities.
[0090] In order to recover oil, gas, and sodium (or other)
water-soluble minerals, a series of steps are undertaken. FIG. 2
presents a flow chart demonstrating a method of in situ thermal
recovery of oil and gas from an organic-rich rock formation 100, in
one embodiment. It is understood that the order of some of the
steps from FIG. 2 may be changed, and that the sequence of steps is
merely for illustration.
[0091] First, the oil shale (or other organic-rich rock) formation
16 is identified within the development area 10. This step is shown
in box 110. The targeted development area within the oil shale
formation may be identified by measuring or modeling the depth,
thickness and organic richness of the oil shale as well as
evaluating the position of the organic-rich rock formation relative
to other rock types, structural features (e.g. faults, anticlines
or synclines), or hydrogeological units (i.e. aquifers). This is
accomplished by creating and interpreting maps and/or models of
depth, thickness, organic richness and other data from available
tests and sources. This may involve performing geological surface
surveys, studying outcrops, performing seismic surveys, and/or
drilling boreholes to obtain subsurface rock samples. Rock samples
may be analyzed to assess kerogen content and fluid hydrocarbon
generating capability. The richness of the organic-rich rock
formation may be ascertained from well or outcrop samples using a
variety of data including but not limited to organic carbon
content, hydrogen index, or modified Fischer assay analyses.
Subsurface permeability may also be assessed via rock samples,
outcrops, or studies of ground water flow. Furthermore the
connectivity of the development area to ground water sources may be
assessed.
[0092] Next, a plurality of wellbores 14 is formed across the
targeted development area 10. This step is shown schematically in
box 115. The purposes of the wellbores 14 are set forth above and
need not be repeated. However, it is noted that for purposes of the
wellbore formation step of box 115, only a portion of the total
initial heat injection wells and hydrocarbon production wells need
be completed.
[0093] It is understood that petroleum engineers will develop a
strategy for the best depth and arrangement for the wellbores 14,
depending upon anticipated reservoir characteristics, economic
constraints, and work scheduling constraints. In addition,
engineering staff will determine what wellbores 14 shall be used
for initial formation 16 heating. This selection step is
represented by box 120. In one aspect, wellbores are placed in a
pattern such that untreated pillars of oil shale are left to
support the overburden and prevent subsidence.
[0094] There are various methods for applying heat to the
organic-rich rock formation 16. One such method involves the use of
electrical resistive heating elements in a cased or uncased
wellbore. Other methods include the use of circulated hot fluids,
downhole combustors, in situ combustion, radio-frequency (RF)
electrical energy, or microwave energy. Still others include
injecting a hot fluid into the oil shale formation to directly heat
it. The present methods are not limited to the heating technique
employed. The heating step is represented generally by box 130.
Preferably, for in situ processes the heating of a production zone
takes place over a period of months, or even four or more years.
Alternatively, the formation may be heated for one to fifteen
years, alternatively, 3 to 10 years, 1.5 to 7 years or 2 to 5
years. The bulk of the target zone of the formation may be heated
to between 270 to 800.degree. C. Alternatively, the bulk of the
target zone of the formation may be heated to between 300 to
400.degree. C. Preferably, the bulk of the target zone is
ultimately heated to a temperature below 400.degree. C.
(752.degree. F.).
[0095] In connection with the heating step 130, the rock formation
16 may optionally be fractured to aid heat transfer or hydrocarbon
fluid production. The optional fracturing step is shown in box 125.
Fracturing may also be accomplished by creating thermal fractures
within the formation through application of heating. Alternatively,
a process known as hydraulic fracturing may be used. By heating the
organic-rich rock and transforming the kerogen to oil and gas, the
permeability is increased via thermal fracture formation and
subsequent production of a portion of the hydrocarbon fluids
generated from the kerogen. Thermal fracture formation is caused by
thermal expansion of the rock and fluids and by chemical expansion
of the transforming kerogen into oil and gas. Thermal fracturing
can occur both in the immediate region undergoing heating, and in
cooler neighboring regions. The thermal fracturing in the
neighboring regions is due to propagation of fractures and tension
stresses developed due to the expansion in the hotter zones.
Thermal fractures increase permeability and aid fluid flow within
the formation. Hydraulic fracturing is a process known in the art
of oil and gas recovery where a fracture fluid is pressurized
within the wellbore above the fracture pressure of the formation,
thus developing fracture planes within the formation to relieve the
pressure generated within the wellbore. Hydraulic fractures may be
used to create additional permeability and/or be used to provide an
extended geometry for an extended heat source, such as in the WO
2005/010320 method.
[0096] Any in situ method that effectively produces oil and gas
from oil shale will create permeability in what was originally a
very low permeability rock. The extent to which this will occur is
illustrated by the large amount of expansion that must be
accommodated if fluids generated from kerogen are unable to flow.
The concept is illustrated in FIG. 3.
[0097] FIG. 3 provides a bar chart comparing one ton of Green River
oil shale before 50 and after 51 a simulated in situ, retorting
process. The simulated process was carried out at 2,400 psi and
750.degree. F. Before the conversion, a total of 15.3 ft.sup.3 of
rock matrix 52 existed. This matrix comprised 7.2 ft.sup.3 of
mineral 53, i.e., shale, and 8.1 ft.sup.3 of kerogen 54 imbedded
within the shale. As a result of the conversion the material
expanded to 26.1 ft.sup.3 55. This represented 7.2 ft.sup.3 of
mineral 56 (the same number as before the conversion), 6.6 ft.sup.3
of hydrocarbon liquid 57, i.e., oil, 9.4 ft.sup.3 of hydrocarbon
gas 58, and 2.9 ft.sup.3 of coke 59. It can be seen that
substantial volume expansion occurred during the conversion
process. This, in turn, increases permeability of the rock
structure.
[0098] The formation 16 is heated to a temperature sufficient to
pyrolyze at least a portion of the oil shale in order to pyrolyze
the kerogen and to create hydrocarbon fluids. The resulting liquids
and hydrocarbon gases may be refined into products which resemble
common commercial petroleum products. Such liquid products include
transportation fuels such as diesel, jet fuel and naphtha.
Generated gases include light alkanes, light alkenes, H.sub.2,
CO.sub.2, CO, and NH.sub.3. Conversion of the oil shale will create
permeability in the oil shale section in rocks that were originally
impermeable. Preferably, the heating process, shown by box 135,
occurs over a lengthy period of time. In one aspect, the heating
period is from three months to four or more years. Also as part of
box 135, the formation 16 is heated to a temperature sufficient to
convert at least a portion of nahcolite, if present, to soda ash.
Heat used to mature the oil shale and recover oil and gas will also
convert nahcolite to sodium carbonate (soda ash), a related sodium
mineral. The process of converting nahcolite (sodium bicarbonate)
to soda ash (sodium carbonate) has been described above.
[0099] As part of the hydrocarbon fluid production process 100,
certain wells 14 may be designated as oil and gas production wells.
This step is depicted by box 140. Oil and gas production might not
be initiated until it is determined that the kerogen has been
sufficiently retorted to allow maximum recovery of oil and gas from
the formation 16. In some instances, dedicated production wells are
not drilled until after heat injection wells (box 130) have been in
operation for a period of several weeks or months. Thus, box 140
may include the formation of additional wellbores 14.
[0100] After certain wellbores 14 have been designated as oil and
gas production wells, oil and/or gas is produced from the wellbores
14. The oil and/or gas production process is shown at box 145. At
this stage (box 145), the water-soluble minerals, such as nahcolite
and converted soda ash remain substantially trapped in the rock
formation 16 as finely disseminated crystals or nodules within the
oil shale beds, and are not produced. However, some nahcolite
and/or soda ash may be dissolved in the water created during
heating within the formation.
[0101] The impact of heating oil shale to produce oil and gas prior
to producing nahcolite is to convert the nahcolite to a more
recoverable form (soda ash), and provide permeability facilitating
its subsequent recovery. Water-soluble mineral recovery may take
place as soon as the retorted oil is produced, or it may be left
for a period of years for later recovery. If desired, the soda ash
can be readily converted back to nahcolite on the surface. The ease
with which this conversion can be accomplished makes the two
minerals effectively interchangeable.
[0102] Box 150 presents a typical next step in the oil and gas
recovery method 100. Here, certain wellbores 14 are designated as
water or aqueous fluid injection wells. Aqueous fluids are
solutions of water that may contain other species. The other
species may be present to alter the pH. Alternatively, the other
species may reflect the availability of brackish water not
saturated in the species wished to be leached from the subsurface.
As used herein, an aqueous fluid is meant to refer to water
including other species and water that does not include other
species. Preferably, the water injection wells are selected from
some or all of the wellbores used for heat injection or for oil
and/or gas production. However, the scope of the step of box 150
may include the drilling of yet additional wellbores 14 for use as
dedicated water injection wells. In this respect, it may be
desirable to complete water injection wells along a periphery of
the development area 10 in order to create a boundary of high
pressure.
[0103] Next, water or an aqueous fluid is injected through the
water injection wells and into the oil shale formation 16. This
step is shown at box 160. The water may be in the form of steam or
pressurized hot water. Alternatively the injected water may be cool
and becomes heated as it contacts the previously heated formation.
The injection process may further induce fracturing. This process
may create fingered caverns and brecciated zones in the
nahcolite-bearing intervals some distance, for example up to 200
feet out, from the water injection wellbores. In one aspect, a gas
cap, such as nitrogen, may be maintained at the top of each
"cavern" to prevent vertical growth.
[0104] In some cases water injection wells may not be necessary if
a sufficiently strong connected aquifer is present. In this case,
drawing on production wells may allow existing subsurface waters to
flow into the heated formation and serve the purpose of water
injection.
[0105] The injection of water into the organic-rich rock formation
16 causes the water to contact water-soluble minerals and various
migratory contaminant species. Preferably the water-soluble
minerals are soda ash and any unconverted nahcolite. As the heated
water sweeps through the rock formation 16, a water-soluble mineral
solution is formed. Sodium carbonate, or soda ash, is soluble in
water and is readily recovered by solution mining. Saturated sodium
carbonate solutions may have about 32 wt. % Na.sub.2CO.sub.3 in
water at temperatures between 30.degree. C. and 140.degree. C.,
about 23 wt. % at 200.degree. C., and about 8.4 wt. % at
300.degree. C.
[0106] Along with the designation of certain wellbores 14 as water
injection wells, the design engineers may also designate certain
wellbores 14 as water or water-soluble mineral solution production
wells. These wells may be the same as wells used to previously
produce hydrocarbons or inject heat. These recovery wells will
produce an aqueous solution of dissolved water-soluble minerals and
other species, including, for example, migratory contaminant
species. For example, the solution may be one primarily of
dissolved soda ash. This step is shown in box 165. Alternatively,
single wellbores may be used to both inject water and then to
recover a sodium mineral solution. Thus, box 165 includes the
option of using the same wellbores 14 for both water injection and
solution production (box 165).
[0107] It is also noted that producing hydrocarbons from pyrolyzed
oil shale will generally leave behind some migratory contaminant
species which are at least partially water-soluble. Depending on
the hydrological connectivity of the pyrolyzed shale oil to
shallower zones, these components may eventually migrate into
ground water in concentrations which are environmentally
unacceptable. The types of potential migratory contaminant species
depend on the nature of the oil shale pyrolysis and the composition
of the oil shale being converted. If the pyrolysis is performed in
the absence of oxygen or air, the contaminant species may include
aromatic hydrocarbons (e.g. benzene, toluene, ethylbenzene,
xylenes), polyaromatic hydrocarbons (e.g. anthracene, pyrene,
naphthalene, chrysene), metal contaminants (e.g. As, Co, Pb, Mo,
Ni, and Zn), and other species such as sulfates, ammonia, Al, K,
Mg, chlorides, flourides and phenols. If oxygen or air is employed,
contaminant species may also include ketones, alcohols, and
cyanides.
[0108] Temporary control of the migration of the migratory
contaminant species, especially during the pyrolysis process, can
be obtained via placement of the injection and production wells 14
such that fluid flow out of the heated zone is minimized.
Typically, this involves placing injection wells at the periphery
of the heated zone so as to cause pressure gradients which prevent
flow from inside the heated zone from leaving the zone.
[0109] FIG. 4 is a cross-sectional view of an illustrative oil
shale formation that is within or connected to ground water
aquifers and the formation leaching operation. Four separate oil
shale formation zones are depicted (23, 24, 25 & 26) within the
oil shale formation. The water aquifers are below the ground
surface 27, and are categorized as an upper aquifer 20 and a lower
aquifer 22. Intermediate between the upper and lower aquifers is an
aquitard 21. It can be seen that certain zones of the formation are
both aquifers or aquitards and oil shale zones. A plurality of
wells (28, 29, 30, & 31) is shown traversing vertically
downward through the aquifers. One of the wells is serving as a
water injection well 31, while another is serving as a water
production well 30. In this way, water is circulated 32 through at
least the lower aquifer 22.
[0110] FIG. 4 shows diagrammatically the water circulation 32
through an oil shale volume that was heated 33, that resides within
or is connected to an aquifer 22, and from which hydrocarbon fluids
were previously recovered. Introduction of water via the water
injection well 31 forces water into the previously heated oil shale
33 and water-soluble minerals and migratory contaminants species
are swept to the water production well 30. The water is then
processed in a facility 34 wherein the water-soluble minerals (e.g.
nahcolite or soda ash) and the migratory contaminants are
substantially removed from the water stream. Water is then
reinjected into the oil shale volume 33 and the formation leaching
is repeated. This leaching with water is intended to continue until
levels of migratory contaminant species are at environmentally
acceptable levels within the previously heated oil shale zone 33.
This may require 1 cycle, 2 cycles, 5 cycles or 10 cycles of
formation leaching, where a single cycle indicates injection and
production of approximately one pore volume of water. It is
understood that there may be numerous water injection and water
production wells in an actual oil shale development. Moreover, the
system may include monitoring wells (28 & 29) which can be
utilized during the oil shale heating phase, the shale oil
production phase, the leaching phase, or during any combination of
these phases to monitor for migratory contaminant species and/or
water-soluble minerals.
[0111] Alternatively, physical barriers can be placed around the
heated zone. These barriers may involve freeze walls or grout
walls. Freeze walls involve circulating refrigerant through
peripheral wells to freeze native water in the vicinity. Shell has
discussed freeze walls for oil shale production in a number of
patents, including U.S. Pat. No. 6,880,633. The entire disclosure
of which is incorporated herein by reference. Grout walls involve
injecting cement into the formation to fill permeable pathways.
[0112] As discussed herein, some embodiments of the invention
include an in situ method of recovering natural resources. The
natural resources may be recovered from an organic-rich rock
formation, including, for example, an oil shale formation. The
organic-rich rock formation may include formation hydrocarbons,
including, for example, kerogen, coal, and heavy hydrocarbons. In
some embodiments of the invention the natural resources may include
hydrocarbon fluids, including, for example products of the
pyrolysis of formation hydrocarbons such as shale oil. In some
embodiments of the invention the natural resources may also include
water-soluble minerals, including, for example, nahcolite (sodium
bicarbonate), soda ash (sodium carbonate) and dawsonite
(NaAl(CO.sub.3)(OH).sub.2).
[0113] Some embodiments of the invention include in situ heating an
organic-rich rock formation that contains both formation
hydrocarbons and formation water-soluble minerals prior to
substantial removal of the formation water-soluble minerals from
the organic-rich rock formation. In some embodiments of the
invention there is no need to partially, substantially or
completely remove the water-soluble minerals prior to in situ
heating. For example, in an oil shale formation that contains
naturally occurring nahcolite, the oil shale may be heated prior to
substantial removal of the nahcolite by solution mining.
Substantial removal of a water-soluble mineral means the degree of
removal of a water-soluble mineral that occurs from any commercial
solution mining operation as known in the art. Substantial removal
of a water-soluble mineral may be approximated as removal of
greater than 5 weight percent of the total amount of a particular
water-soluble mineral present in the zone targeted for hydrocarbon
fluid production in the organic-rich rock formation. In alternative
embodiments, in situ heating of the organic-rich rock formation to
pyrolyze formation hydrocarbons may be commenced prior to removal
of greater than 3 weight percent, alternatively 7 weight percent,
10 weight percent or 13 weight percent of the formation
water-soluble minerals from the organic-rich rock formation.
[0114] In some embodiments of the invention heating of the
organic-rich rock formation pyrolyzes at least a portion of the
formation hydrocarbons to create hydrocarbon fluids. The formation
hydrocarbons may be pyrolyzed in situ by raising the organic-rich
rock formation, or zones within the formation, to a pyrolyzation
temperature. In alternative embodiments, the heating rate of the
formation may be slowly raised through the pyrolysis temperature
range. For example, an in situ conversion process for formation
hydrocarbons may include heating at least a portion of an
organic-rich rock formation to raise the average temperature of the
zone above about 270.degree. C. by a rate less than a selected
amount (e.g., about 10.degree. C., 5.degree. C., 3.degree. C.,
1.degree. C., 0.5.degree. C., or 0.1.degree. C.) per day. In a
further embodiment the portion may be heated such that an average
temperature of the selected zone may be less than about 375.degree.
C. or, in some embodiments, less than about 400.degree. C. The
formation may be heated such that a temperature within the
formation reaches (at least) an initial pyrolyzation temperature
(e.g., a temperature at the lower end of the temperature range
where pyrolyzation occurs in a reasonable, e.g., days, weeks or
months, period of time). The pyrolysis temperature range may vary
depending on the types of formation hydrocarbons within the
formation, the heating methodology, and distribution of heating
sources. For example, a pyrolysis temperature range may include
temperatures between about 250.degree. C. and about 900.degree. C.
In an alternative embodiment, a pyrolysis temperature range may
include temperatures between about 270.degree. C. to about
400.degree. C.
[0115] In some embodiments, the hydrocarbon fluids may include a
pyrolysis oil component (or condensable component) and a pyrolysis
gas component (or non-condensable component). Condensable
hydrocarbons produced from the formation will typically include
paraffins, cycloalkanes, mono-aromatics, and di-aromatics as major
components. Such condensable hydrocarbons may also include other
components such as tri-aromatics and other hydro carbon
species.
[0116] In certain embodiments, a majority of the hydrocarbons in
the produced fluid may have a carbon number of less than
approximately 25. Alternatively, less than about 15 weight % of the
hydrocarbons in the fluid may have a carbon number greater than
approximately 25. The non-condensable hydrocarbons may include, but
are not limited to, hydrocarbons having carbon numbers less than
5.
[0117] In certain embodiments, the API gravity of the condensable
hydrocarbons in the produced fluid may be approximately 20 or above
(e.g., 25, 30, 40, 50, etc.). In certain embodiments, the hydrogen
to carbon atomic ratio in produced fluid may be at least
approximately 1.7 (e.g., 1.8, 1.9, etc.).
[0118] In some embodiments of the invention heating of the
organic-rich rock formation both pyrolyzes at least a portion of
the formation hydrocarbons to create hydrocarbon fluids and makes
available migratory contaminant species previously bound in the
organic-rich rock formation. The migratory contaminant species may
be formed through pyrolysis of the formation hydrocarbon, may be
liberated from the formation itself upon heating, or may be made
accessible through the creation of increased permeability upon
heating of the formation. The migratory contaminant species may be
soluble in water or aqueous fluids present in or injected into the
organic-rich rock formation.
[0119] Some embodiments include producing at least a portion of the
hydrocarbon fluids from the organic-rich rock formation. The
hydrocarbon fluids may be produced through production wells.
Production wells may be cased or uncased wells and drilled and
completed through methods known in the art.
[0120] In some embodiments, at least a portion of the migratory
contaminant species remain in the organic-rich rock formation after
the hydrocarbon fluids are produced. In such case, it may be
desirable to inject an aqueous fluid into the organic-rich rock
formation and have the injected aqueous fluid dissolve at least a
portion of the water-soluble minerals and/or the migratory
contaminant species to form an aqueous solution. The aqueous
solution may then be produced from the organic-rich rock formation
through, for example, solution production wells. The aqueous fluid
may be adjusted to increase the solubility of the migratory
contaminant species and/or the water-soluble minerals. The
adjustment may include the addition of an acid or base to adjust
the pH of the solution.
[0121] Some embodiments include processing the aqueous solution in
a surface facility to remove at least some of the migratory
contaminant species. The migratory contaminant species may be
removed through use of, for example, an adsorbent material, reverse
osmosis, chemical oxidation, bio-oxidation, and/or ion exchange.
Examples of these processes are individually known in the art.
Exemplary adsorbent materials may include activated carbon, clay,
or fuller's earth.
[0122] In one embodiment, the migratory contaminant species include
one or more of aromatic hydrocarbons, polyaromatic hydrocarbons,
oxygenated hydrocarbons, metal contaminants, and ionic
contaminants. In an alternative embodiment, the migratory
contaminant species include one or more of benzene, toluene,
xylene, ethylbenzene, tri-methylbenzene, and polyaromatic
hydrocarbon species. In an alternative embodiment, the migratory
contaminant species include one or more of metal contaminants
containing arsenic, boron, chromium, mercury, selenium, lead,
vanadium, nickel, cobalt, molybdenum and zinc.
[0123] Some embodiments of the invention include assessing the
connectivity of the organic-rich rock formation to aquifers. This
may be done to determine if, or to what extent, in situ pyrolysis
of formation hydrocarbons in the organic-rich rock formation may
create migratory species with the propensity to migrate into an
aquifer. If the organic-rich rock formation is hydrologically
connected to an aquifer, precautions may be taken to reduce or
prevent species generated or liberated during pyrolysis from
entering the aquifer. Alternatively, the organic-rich rock
formation may be flushed with water or an aqueous fluid after
pyrolysis as described herein to remove water-soluble minerals
and/or migratory contaminant species. In other embodiments, the
organic-rich rock formation may be substantially hydrologically
unconnected to any source of ground water. In such a case, flushing
the organic-rich rock formation may not be desirable for removal of
migratory contaminant species but may nevertheless be desirable for
recovery of water-soluble minerals.
[0124] In certain embodiments a mass of at least a portion of the
formation may be reduced due, for example, to pyrolysis of
formation hydrocarbons and the production of hydrocarbon fluids
from the formation. As such, the permeability and porosity of at
least a portion of the formation may increase. In addition,
removing water during the heating may also increase the
permeability and porosity of at least a portion of the
formation.
[0125] Certain embodiments may include increasing the permeability
of at least a portion of an organic-rich rock formation to greater
than about 0.01, 0.1, 1, 10, 20 and/or 50 Darcy. In addition,
certain embodiments may include substantially uniformly increasing
the permeability of at least a portion of an organic-rich rock
formation. Some embodiments may include increasing the porosity of
at least a portion of an organic-rich rock formation substantially
uniformly.
[0126] Certain systems and methods described herein may be used to
treat formation hydrocarbons in at least a portion of a relatively
low permeability formation (e.g., in "tight" formations that
contain formation hydrocarbons). Such formation hydrocarbons may be
heated to pyrolyze at least some of the formation hydrocarbons in a
selected zone of the formation. Heating may also increase the
permeability of at least a portion of the selected zone.
Hydrocarbon fluids generated from pyrolysis may be produced from
the formation, thereby further increasing the formation
permeability.
[0127] In an embodiment, heating a portion of an organic-rich rock
formation in situ to a temperature less than an upper pyrolysis
temperature may increase permeability of the heated portion. For
example, permeability may increase due to formation of fractures
within the heated portion caused by application of heat. As the
temperature of the heated portion increases, water may be removed
due to vaporization. The vaporized water may escape and/or be
removed from the formation. Removal of water may also increase the
permeability of the heated portion. In addition, permeability of
the heated portion may also increase as a result of production of
hydrocarbon fluids from pyrolysis of at least some of the formation
hydrocarbons within the heated portion on a macroscopic scale. In
an embodiment, the permeability of a selected zone within a heated
portion of an organic-rich rock formation may be substantially
uniform. For example, heating by conduction may be substantially
uniform, and thus a permeability created by conductive heating may
also be substantially uniform.
[0128] Permeability of a selected zone within the heated portion of
the organic-rich rock formation may also rapidly increase while the
selected zone is heated by conduction. For example, permeability of
an impermeable organic-rich rock formation may be less than about
0.1 millidarcy before heating. In some embodiments, pyrolyzing at
least a portion of organic-rich rock formation may increase a
permeability within a selected zone of the portion to greater than
about 10 millidarcies, 100 millidarcies, 1 Darcy, 10 Darcies, 20
Darcies, or 50 Darcies. Therefore, a permeability of a selected
zone of the portion may increase by a factor of more than about 10,
100, 1,000, 10,000, or 100,000. In one embodiment, the organic-rich
rock formation has an initial total permeability less than 1
millidarcy, alternatively less than 0.1 or 0.01 millidarcies,
before heating the organic-rich rock formation. In one embodiment,
the organic-rich rock formation has a post heating total
permeability of greater than 1 millidarcy, alternatively, greater
than 10, 50 or 100 millidarcies, after heating the organic-rich
rock formation.
[0129] In some embodiments, heating the organic-rich formation
includes generating soda ash by decomposition of nahcolite. In some
embodiments the method may include processing an aqueous solution
containing water-soluble minerals in a surface facility to remove a
portion of the water-soluble minerals. The processing step may
include removing the water-soluble minerals by precipitation caused
by altering the temperature of the aqueous solution. In some
embodiments, the water-soluble minerals include sodium.
Alternatively, the water-soluble minerals may include nahcolite
(sodium bicarbonate), soda ash (sodium carbonate), dawsonite
(NaAl(CO.sub.3)(OH).sub.2), or combinations thereof. The surface
processing may further include converting the soda ash back to
sodium bicarbonate (nahcolite) in the surface facility by reaction
with CO.sub.2. After partial or complete removal of the
water-soluble minerals, the aqueous solution may be reinjected into
a subsurface formation after a portion of the water-soluble
minerals and/or migratory contaminant species are removed and then
the solution may be sequestered in the subsurface formation. The
subsurface formation may be the same as or different from the
organic-rich rock formation.
[0130] In some embodiments, heating the organic-rich rock formation
includes generating soda ash by decomposition of nahcolite present
in the formation. In the decomposition process CO.sub.2 is
generated. Some embodiments include monitoring for the presence of
the formed CO.sub.2 and, alternatively, estimating the extent of
the heating of the organic-rich rock formation from the CO.sub.2
monitoring. The estimated extent may include estimating the
distribution of heating in the formation, estimating the overall
volume which has reached a given temperature, or estimating the
rate of progression of a heat front in the formation. Estimations
may be calculated based on (i) measured or estimated
stoichiometries, decomposition thermodynamics and/or kinetics of
nahcolite, kerogen, and/or other carbonate minerals and (ii)
measured or estimated distributions of nahcolite kerogen and/or
other carbonates in the formation. Additionally, heat transfer
models and/or simulations may be employed based on the heat input
rates to the formation and assumed heat transfer characteristics of
the formation and then the models and/or simulations refined based
on the measured CO.sub.2 data and calculations. Alternatively, the
CO.sub.2 monitoring data may be correlated to the extent of heating
through use of a computer model based on nahcolite conversion to
soda ash. The amount of the CO.sub.2 formed may be tracked in a
nahcolite conversion process to determine the extent to which soda
ash is present. The estimates of the extent of heating based on
CO.sub.2 data and calculations may be used to refine heat transfer
models of the organic-rich rock formation and/or simulations of the
generation and production of hydrocarbon fluids from the
organic-rich rock formation. The heating estimates may be used to
adjust the rate at which heat is input into the organic-rich rock
formation at one or more locations or production fluids are
produced from the formation.
[0131] The heating of the organic-rich rock formation may be
accomplished through use of heater wells. The heater wells may
include, for example, electrical resistance heating elements. The
production of hydrocarbon fluids from the formation may be
accomplished through use of production wells. The adjustment of the
rate at which heat is input into the organic-rich rock formation or
adjusting the rate at which production fluids are produced from the
formation may be accomplished through one or more of adjusting the
heat input to a heater well, adjusting the flow rate from a
production well, adjusting the back pressure of a production well,
or combinations thereof.
[0132] There may be several different types of wells used in
embodiments of the invention. For example, the heating of the
organic-rich rock formation may be accomplished through use of
heater wells. The heater wells may include, for example, electrical
resistance heating elements. The production of hydrocarbon fluids
from the formation may be accomplished through use of production
wells. The injecting of the aqueous fluid may be accomplished
through use of injection wells. The production of the aqueous
solution may be accomplished through use of solution production
wells. The different types of wells may be used for multiple
purposes. For example, the production wells may also be used as
injection wells for injecting water into the organic-rich rock
formation. Alternatively, the production wells may also be used as
solution production wells for producing the aqueous solution from
the organic-rich rock formation. This method may be combined with
any of the other aspects of the invention as discussed herein.
[0133] In one embodiment, the method includes an in situ method of
recovering natural resources including heating an organic-rich rock
formation in situ. The formation may be substantially impermeable
to fluid flow initially, contain formation hydrocarbons, and
water-soluble minerals. In some embodiments the heating occurs
prior to substantial removal of the formation water-soluble
minerals. The heating pyrolyzes at least a portion of the formation
hydrocarbons to create hydrocarbon fluids and thereby create
permeability within a matured (pyrolyzed) organic-rich rock zone in
of the organic-rich rock formation. The hydrocarbon fluids may be
produced from the formation. The method may include leaving a
second portion of the formation hydrocarbons substantially
unpyrolyzed, thereby preserving an unmatured organic-rich rock
zone. In some embodiments, the unmatured organic-rich rock zones
may be shaped as pillars running substantially the entire thickness
of the organic-rich rock formation. The heating rate and
distribution of heating of the formation may be designed and
implemented to leave sufficient unmatured pillars to prevent
subsidence. Further, the method may include converting at least a
portion of the formation water-soluble minerals to a different
water-soluble mineral. For example, naturally occurring nahcolite
may be decomposed to soda ash through heating. This method may be
combined with any of the other aspects of the invention as
discussed herein.
[0134] The method may include flushing the matured organic-rich
rock zone and the unmatured organic-rich rock zone with an aqueous
fluid. The aqueous fluid may be used to dissolve water-soluble
minerals and migratory contaminant species as discussed herein. The
flushing may optionally be completed after a substantial portion of
the hydrocarbon fluids have been produced from the matured
organic-rich rock zone. The resulting aqueous solution may then be
produced from the organic-rich rock formation to the surface for
processing as discussed herein. In some embodiments, the flushing
step may be delayed after the hydrocarbon fluid production step.
The flushing may be delayed to allow heat generated from the
heating step to migrate deeper into surrounding unmatured
organic-rich rock zones to convert nahcolite within the surrounding
unmatured organic-rich rock zones to soda ash. Alternatively, the
flushing may be delayed to allow heat generated from the heating
step to generate permeability within the surrounding unmatured
organic-rich rock zones. Further, the flushing may be delayed based
on current and/or forecast market prices of sodium bicarbonate,
soda ash, or both as further discussed herein. This method may be
combined with any of the other aspects of the invention as
discussed herein.
[0135] One embodiment may include an in situ method of recovering
natural resources including heating the organic-rich rock formation
in situ, where the formation contains formation water-soluble
minerals. The heating may occur prior to substantial removal of the
water-soluble minerals. The heating may both pyrolyze at least a
portion of the formation hydrocarbons to create hydrocarbon fluids
and generate water which migrates and at least partially dissolves
the formation water-soluble minerals in situ to form an aqueous
fluid within the formation. The generated water may be produced
from one or more occurrences. For example, the generated water may
be produced by decomposition of formation water-soluble minerals,
pyrolyzation of formation hydrocarbons, dehydration of formation
clays, or combinations thereof. This method may be combined with
any of the other aspects of the invention as discussed herein.
[0136] Some embodiments further include producing a production
fluid from the organic-rich rock formation where the production
fluid contains the hydrocarbon fluids and the aqueous fluid. The
aqueous fluid may contain water-soluble minerals and/or migratory
contaminant species. In such case, the production fluid may be
separated into a hydrocarbon stream and an aqueous stream at a
surface facility. Thereafter the water-soluble minerals and/or
migratory contaminant species may be recovered from the aqueous
stream. This embodiment may be combined with any of the other
aspects of the invention discussed herein.
[0137] One embodiment includes an in situ method of recovering
natural resources, including assessing the market price for a
water-soluble mineral and comparing the market price for the
water-soluble mineral to a cost-to-produce criterion. For example,
the method may utilize a market price that is representative of the
current market price, the forecasted market price, or a combination
thereof. There are many potential market prices that may be used in
the method. For example, the market price may be a listed commodity
price, the price used in an existing or potential contractual
arrangement or another measure of the current or potential value of
the water-soluble mineral or a commodity or consumer product
containing the water-soluble mineral or derivatives thereof. The
water-soluble mineral may be a sodium mineral, including, for
example, nahcolite or soda ash. The cost-to-produce criterion may
be any criterion that reflects a measurement of the cost to produce
the water-soluble mineral of interest or derivatives thereof. For
example, the cost-to-produce criterion may include the cost to
solution mine the water-soluble mineral of interest. The
cost-to-produce criterion may include a measure of the cost to
produce the water-soluble mineral before heating the organic-rich
rock formation to pyrolyze formation hydrocarbons as compared to
the cost to produce the water-soluble mineral after heating the
organic-rich rock formation to pyrolyze formation hydrocarbons. The
method may include determining that the market price of the
water-soluble-mineral is less than the cost-to-produce criterion.
In such case, an operator may opt to forego producing the
water-soluble minerals before pyrolyzing the formation hydrocarbons
in the organic-rich rock formation, thus delaying production of the
water-soluble minerals to a later time. The resulting multi-mineral
production scheme may be more economic than producing the
water-soluble minerals before pyrolyzation. This embodiment may be
combined with other embodiments and aspects of the invention
discussed herein.
[0138] An embodiment may include an in situ method of recovering
natural resources, including providing produced fluid processing
facilities which are sized to process a first hydrocarbon fluid
production rate produced during an initial production period
together with a first CO.sub.2 production rate produced during the
initial production period. The first CO.sub.2 production rate may
include CO.sub.2 generated from dissociation of nahcolite to form
soda ash. Thus the method may be used to adequately size produced
fluid processing facilities where the operator plans to pyrolyze
formation hydrocarbons without removing the naturally occurring
nahcolite before pyrolyzation. The method may enable one to
economically produce hydrocarbon fluids from an organic-rich rock
formation without the necessity of removing the nahcolite
beforehand, thus improving the overall project economics. This
embodiment may also be practiced by designing and/or constructing a
system that includes the produced fluid processing facilities. This
method may be combined with any of the other aspects of the
invention as discussed herein.
[0139] Methods to remove CO.sub.2, as well as other so-called acid
gases (such as H.sub.2S), from produced hydrocarbon gas include the
use of chemical reaction processes and of physical solvent
processes. Chemical reaction processes typically involve contacting
the gas stream with an aqueous amine solution at high pressure
and/or low temperature. This causes the acid gas species to
chemically react with the amines and go into solution. By raising
the temperature and/or lowering the pressure the chemical reaction
can be reversed and a concentrated stream of acid gases can be
recovered. An alternative chemical reaction process involves hot
carbonate solutions, typically potassium carbonate. The hot
carbonate solution is regenerated and the concentrated stream of
acid gases is recovered by contacting the solution with steam.
Physical solvent processes typically involve contacting the gas
stream with a glycol at high pressure and/or low temperature. Like
the amine processes, reducing the pressure or raising the
temperature allows regeneration of the solvent and recovery of the
acid gases. Certain amines or glycols may be more or less selective
in the types of acid gas species removed. Sizing of any of these
processes requires determining the amount of chemical to circulate,
the rate of circulation, the energy input for regeneration, and the
size and type of gas-chemical contacting equipment. Contacting
equipment typically involves packed or multi-tray countercurrent
towers. Optimal sizing for each of these aspects is highly
dependent on the rate at which gas is being produced from the
formation and the concentration of the acid gases in the gas
stream. Less commonly, cryogenic distillation is utilized to remove
acid gases. This method takes advantage of the differences in the
boiling points of the gas components.
[0140] In different embodiments, the initial production period may
include a one year period beginning from the point of the first
heating of the organic-rich rock formation. Alternatively, the
initial production period may include a two, three, four or a five
year period beginning from the point of the first heating of the
organic-rich rock formation. In different embodiments, the first
hydrocarbon fluid production rate may be the maximum daily
hydrocarbon fluid production rate reached during the initial
production period. Alternatively, the first hydrocarbon fluid
production rate may be the maximum hourly, monthly or yearly
hydrocarbon fluid production rate reached during the initial
production period. In different embodiments, the first CO.sub.2
production rate may be the maximum daily CO.sub.2 production rate
reached during the initial production period. Alternatively, the
first CO.sub.2 production rate may be the maximum hourly, monthly
or yearly CO.sub.2 production rate reached during the initial
production period. This embodiment may be combined with other
aspects of the invention discussed herein.
[0141] It can be seen that the current invention proposes to
recover the value of the water-soluble minerals such as nahcolite
after heating an oil shale zone and producing at least some of the
shale oil. There may be a one or more benefits to this approach,
including:
[0142] (1) The shale oil can be significantly more valuable than
the water-soluble mineral components. Thus, recovering the shale
oil value earlier can improve the net present value of the
development of a lease under development.
[0143] (2) Removing water-soluble minerals early in the process may
disrupt the ability to produce the oil shale by certain methods.
For instance, removal of the soluble minerals can hinder the
ability to produce hydraulic fractures in the formation and make
the shale more prone to cavern formation and subsidence. Subsidence
can cause substantial stresses on the wellbore completions and lead
to early and sudden failures.
[0144] (3) Solution mining after kerogen conversion can be combined
with leaching of migratory contaminant species, including, for
example, water-soluble organic components, heavy metal components
and ionic species left over from producing the oil shale. The
removal of such components may be environmentally necessary if the
shale oil zone is connected to a ground water source. The alkali
nature of sodium carbonate solutions can aid the washing of
organics from the shale oil zone.
[0145] (4) Project and field coordination can be simplified by
separating the oil shale and mineral removal activities. Moreover,
certain wells and facilities can be reused from the in situ shale
oil development for the mineral removal.
[0146] (5) The conversion of nahcolite to soda ash, with resultant
CO.sub.2 generation, during the oil shale heating can be used to
monitor the progression of the oil shale maturation. As the
nahcolite converts to soda ash, the production of generated
CO.sub.2 can be analyzed to help assess the position of the heat
front and the nature of the generated permeability. At lower
temperatures (<.about.250.degree. C.), the CO.sub.2 generation
in certain areas will be dominated by nahcolite decomposition. The
heating behavior of oil shale can be correlated to the amount of
CO.sub.2 present in the produced fluid return stream based on
estimates of the amount of nahcolite present in situ. At higher
temperatures, CO.sub.2 concentrations may more greatly reflect
generation from the kerogen converting to oil and gas and perhaps
from dawsonite decomposition. At even higher temperatures
(>.about.400.degree. C.), the CO.sub.2 generation also reflects
other carbonate mineral dissociation. Analyzing the isotopic nature
of the CO.sub.2 (typically via mass spectrography) can be used to
distinguish between CO.sub.2 gas from organic and inorganic
sources. Organic-sourced gas tends to be lighter (i.e., enriched in
.sup.12C vs. .sup.13C) than inorganic-sourced gas. (See, for
example, Laughrey, C. D. and Balassare, F. J., "Some Applications
of Isotope Geochemistry for Determining Sources of Stray Carbon
Dioxide Gas", Environmental Geosciences, 10(3), pp. 107-122,
(2003)). The entire disclosure of which is incorporated herein by
reference. CO.sub.2 concentrations can be measured in a number of
ways known in the art including gas chromatography, mass
spectrography, infrared spectrography, Raman spectrography,
photoacoustic spectrography, gas density measurements, and various
chemical-specific reactions. Isotopic concentrations are typically
measured via a combination of mass spectrography and gas
chromatography.
[0147] (6) Extracting the water-soluble minerals after the oil
shale maturation may increase their recovery since the maturation
process increases permeability and connectivity in the formation.
Thus, originally isolated concentrations of soluble minerals may
become accessible to the injected water.
[0148] (7) The sodium minerals are produced as soda ash, rather
than sodium bicarbonate. Produced nahcolite is often converted to
soda ash in a facility and thus a step is saved with the in situ
conversion.
[0149] (8) In addition to the benefits described above, if in situ
conversion of the oil shale necessitates a ground water cleanup by
intentional leaching, there may be additional synergies between
cleanup operations and facilities and mineral solution mining
operations and facilities.
[0150] The above-described processes may be of merit in connection
with the recovery of hydrocarbons and nahcolite in the Piceance
Basin of Colorado. Some have estimated that in some oil shale of
the Western United States, up to 1 million barrels of oil may be
recoverable per surface acre. One study has estimated the oil shale
resource within the nahcolite-bearing portions of the oil shale
formations of the Piceance Basin to be 400 billion barrels of shale
oil in place. Pitman, J. K., Pierce, F. W. and Grundy, W. D.,
"Thickness, Oil-Yield and Kriged Resource Estimates for the Eocene
Green River Formation, Piceance Creek Basin, Colo., United States
Geological Survey Oil and Gas Investigations Chart OC-132, 6 sheets
(1989)). The entire disclosure of which is incorporated herein by
reference.
[0151] Dyni estimates the total nahcolite resource in the Piceance
Basin at 32 billion short tons. This makes it the second largest
sodium carbonate deposit in the world behind the trona deposits of
southwest Wyoming (103 billion short tons). Resource density in the
basin center areas varies from 170-490 million short tons per
square mile.
[0152] As noted, it is preferred that thermal recovery of oil and
gas be conducted before solution mining of nahcolite or other
water-soluble minerals. In addition to the reasons discussed above,
it is noted that solution mining can generate large voids in a rock
formation and collapse breccias in an oil shale development unit.
These voids and brecciated zones may pose problems for in situ and
mining recovery of oil shale.
[0153] Also, when solution mining occurs first (as others have
proposed), it becomes necessary to remove large amounts of water
prior to oil shale heating. There are also inefficiencies
associated with heating void filling water or gas.
[0154] In addition, heated fracture methods of in situ conversion
of oil shale may not be possible within solution-mined areas. These
recovery processes may require the construction of hydraulic
fractures and the placement of a suitable proppant within those
fractures. Voids and breccia may permit too much leak-off of
fracture fluids, making pressure maintenance (required to form the
fracture) and proppant placement difficult or impossible. In the
virgin oil shale where nahcolite is present, the formation is tight
and can maintain high pressure with minimal bleed off. Solution
mining will probably change the fracturing behavior of the
formation dramatically. At the least, solution mining may create
the development of unpredictable fluid pathways resulting in lost
production in the subsurface.
[0155] Finally, it is noted that, if heated to high enough
temperature, sodium carbonate may further decompose into sodium
oxide and CO.sub.2, according to the following reaction.
Na.sub.2CO.sub.3.fwdarw.Na.sub.2O+CO.sub.2
[0156] One may track the amount of CO.sub.2 generated in a
nahcolite conversion process to determine the extent to which soda
ash might be present or even sodium oxide. This is based upon a
previously developed model which estimates the amount of nahcolite
originally within the rock formation.
[0157] Certain features of the present invention are described in
terms of a set of numerical upper limits and a set of numerical
lower limits. It should be appreciated that ranges formed by any
combination of these limits are within the scope of the invention
unless otherwise indicated. Although some of the dependent claims
have single dependencies in accordance with U.S. practice, each of
the features in any of such dependent claims can be combined with
each of the features of one or more of the other dependent claims
dependent upon the same independent claim or claims.
[0158] While it will be apparent that the invention herein
described is well calculated to achieve the benefits and advantages
set forth above, it will be appreciated that the invention is
susceptible to modification, variation and change without departing
from the spirit thereof.
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