Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND APPARATUS FOR HANDLING ACID GASES GENERATED BY
PYROLYSIS OF KEROGEN
CROSS-REFERENCE TO RELATED APPLICATIONS
The present application claims priority to U.S Provisional Application No.
61/714.220 filed on October 15, 2012, which is incorporated by reference
herein in its
entirety.
FIELD OF THE INVENTION
Embodiments of the invention relate to techniques for pyrolyzing sulfur-rich
kerogen or bitumen (e.g. type IIs kerogen), and to related methods of handling
pyrolysis
gases derived therefrom.
BACKGROUND
The world's supply of conventional sweet, light crude oil is declining, and
discoveries and access to new resources for this premium oil are becoming more
challenging. To supplement this decline and to meet the rising global demand,
oils of
increasing sulfur content are being produced and brought to market. Sources of
sulfur-
rich oil may be found in Canada, Venezuela, the United States (California),
Mexico and
the Middle East.
Many sulfur-rich hydrocarbons are sourced from a subset of Type II kerogen
known to be sulfur-rich, called Type IIs or IIs. A schematic representation of
one type of
organic matter in Type IIs kerogen is illustrated below:
0
s
S'' . '''---IN-.,='''''s,-,'-'N.,,j'' S 'N.
S.- S
,.I."'-..
S
S \c/¨ (
S
---- S---(/
S
sI
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Originating from a marine-depositional environment, Type IIs kerogen is rich
in
sulfur-bearing organic compounds, and during thermal maturation produces oil
and
bitumen with high sulfur content.
It is possible to produce hydrocarbon fluids by pyrolyzing Type IIs kerogen
either
in situ or within an enclosure such as a pit or an impoundment. Unfortunately,
in
addition to valuable fluids (i.e. hydrocarbon fluids and hydrogen gas),
pyrolysis of
kerogen or bitumen also produces acid-gas (i.e. H2S and C0x)=
There is an ongoing need for economically-viable and environmentally-friendly
techniques for disposing of acid-gas derived from Type IIs kerogen.
SUMMARY OF EMBODIMENTS
Embodiments of the present invention relate to methods and apparatus for
pyrolysis of sulfur-rich kerogen or bitumen wherein recovery of hydrocarbon
fluids via
production wells or conduits is delayed in order to first recover a
significant quantity of
acid gases. The recovery of the hydrocarbon fluids may be delayed by reducing
power to
heaters (i.e. at the appropriate time) used to heat the kerogen or bitumen.
The significant
quantity of acid gases is recovered during early pyrolysis in a gas mixture
containing at
most low concentrations of valuable hydrogen gas and/or hydrocarbon gases.
By keeping the H2S-rich and C0x-rich formation gases that are generated and
recovered during early pyrolysis separate from the hydrocarbon gas-rich and/or
H2-rich
pyrolysis formation gases that are recovered at a later stage of pyrolysis, it
is possible to
sequester (e.g. within a deep injection well) the formation gases of early
pyrolysis
without subjecting them to significant gas component separation and treatment
before
sequestration.
Because the H2S-rich and C0x-rich early-stage pyrolysis formation gases are
not
mixed together with the later-stage pyrolysis formation gases (i.e. that have
relatively
high concentrations of H2 and/or hydrocarbon gas rich), these later-stage
pyrolysis
formation gases may require a lesser amount of desulfurizing and other gas
treatment
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than would be required if early-stage and later-stage pyrolysis formation
gases were
allowed to mix with each other. On a practical level, smaller or fewer amine
separation
units and Claus plants may be required for an in situ project for
unconventional oil
recovery.
The presently disclosed teachings are applicable both to in situ pyrolysis and
to
pyrolysis performed within an enclosure such as a pit.
A pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface
formation in situ so as to initiate pyrolysis of kerogen and/or bitumen
therein so that a
stream of pyrolysis formation gases is recovered via production wells; b.
monitoring
or estimating a concentration of acid gas within the gas stream; c. contingent
upon an
acid gas concentration being below a threshold value, subjecting pyrolysis
gases of the
stream to sequestration; and d. responding to an estimated or monitored
increase in acid
gas concentration of the gas stream by carrying at least one of: i. subjecting
a greater
fraction of the stream to an acid gas separation process and/or acid gas
elimination
process; and ii. subjecting a lesser fraction of the stream to a
sequestration.
A pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface
formation in situ so as to initiate pyrolysis of kerogen and/or bitumen
therein thereby
generating pyrolysis formation gases so that: i. early pyrolysis gases formed
during
early pyrolysis are acid-gas rich and have at most low concentrations of the
combination
of hydrogen gas and hydrocarbon gases; ii. a concentration of acid gases
within later
pyrolysis gases formed during later stages of pyrolysis is significantly less
than the
concentration within the early pyrolysis gases; and iii. the later pyrolysis
gases are rich
in hydrocarbon gases and/or hydrogen gas; b. sequestering the early pyrolysis
gases; and
c. subjecting the later pyrolysis gases to an acid gas separation process
and/or to an acid
gas elimination process.
A pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface
formation in situ by heaters so as to initiate pyrolysis of kerogen and/or
bitumen therein;
b. operating the heaters so as to maximize the quantity of acid formation
gases that are
formed as part of a gas mixture having at most low concentrations of the
combination of
hydrogen gas and hydrocarbon gases; and c. sequestering the acid gases.
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A pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface
formation in situ by heaters so as to initiate pyrolysis of kerogen and/or
bitumen therein;
b. operating the heaters so as to maximize the quantity of acid formation
gases that are
formed when a bulk temperature of the pyrolyzed portion of the formation is at
most
300 degrees Celsius or at most 295 degrees Celsius or at most 290 degrees
Celsius; and c.
sequestering the acid gases.
A pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface
formation in situ by heaters so as to initiate pyrolysis of kerogen and/or
bitumen therein;
b. monitoring or estimating content of a gas mixture stream of formation gases
formed
by the pyrolysis to determine an indication of an acid gas concentration
thereof; and
c. during an early stage of pyrolysis of the portion of the formation,
operating the
heater(s) at a power level determined in accordance with the acid gas
concentration.
In some embodiments, the heaters are subsurface heaters.
A pyrolysis method comprises: a. introducing hydrocarbon-containing rocks into
an interior region of an enclosure to form a bed of rocks therein; b. heating
the bed of
rocks so as to pyrolyze kerogen or bitumen thereof so that a stream of
pyrolysis
formation gases is recovered via production conduit(s); c. monitoring or
estimating a
concentration of acid gas within the gas stream;
d. contingent upon an acid gas concentration being below a threshold value,
subjecting
pyrolysis gases of the stream to sequestration; and d. responding to an
estimated or
monitored increase in acid gas concentration of the gas stream by carrying at
least one of:
i. subjecting a greater fraction of the stream to an acid gas separation
process and/or acid
gas elimination process; and ii. subjecting a lesser fraction of the stream to
a
sequestration.
A pyrolysis method comprises a. introducing hydrocarbon-containing rocks into
an interior region of an enclosure to form a bed of rocks therein; b. heating
the bed of
rocks so as to initiate pyrolysis of kerogen and/or bitumen therein thereby
generating
pyrolysis formation gases so that: i. early pyrolysis gases formed during
early pyrolysis
are acid-gas rich and have at most low concentrations of the combination of
hydrogen
gas and hydrocarbon gases; ii. a concentration of acid gases within later
pyrolysis gases
formed during later stages of pyrolysis is significantly less than the
concentration within
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the early pyrolysis gases; and iii. the later pyrolysis gases are rich in
hydrocarbon gases
and/or hydrogen gas ; b. sequestering the early pyrolysis gases; and c.
subjecting the
later pyrolysis gases to an acid gas separation process and/or acid gas
elimination
process.
5 A
pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface
formation in situ by heaters so as to initiate pyrolysis of kerogen and/or
bitumen therein;
a. introducing hydrocarbon-containing rocks into an interior region of an
enclosure to
form a bed of rocks therein; b. heating the bed of rocks by heaters so as to
pyrolyze
kerogen or bitumen thereof so as to initiate pyrolysis of kerogen and/or
bitumen thereof;
c. operating the heaters so as to maximize the quantity of acid formation
gases that are
formed as part of a gas mixture having at most low concentrations of the
combination of
hydrogen gas and hydrocarbon gases; and d. sequestering the acid gases.
A pyrolysis method comprises: a. introducing hydrocarbon-containing rocks into
an interior region of an enclosure to form a bed of rocks therein; b. heating
the bed of
rocks by heaters so as to pyrolyze kerogen or bitumen thereof so as to
initiate pyrolysis of
kerogen and/or bitumen thereof; c. operating the heaters so as to maximize the
quantity of
acid formation gases that are formed when a bulk temperature of the pyrolyzed
portion
of the formation is at most 300 degrees Celsius or at most 295 degrees Celsius
or at most
290 degrees Celsius; and d. sequestering the acid gases.
A pyrolysis method comprises: a. introducing hydrocarbon-containing rocks into
an interior region of an enclosure to form a bed of rocks therein; b. heating
the bed of
rocks by heaters so as to pyrolyze kerogen or bitumen thereof so as to
initiate pyrolysis of
kerogen and/or bitumen thereof; c. monitoring or estimating content of a gas
mixture
stream of formation gases formed by the
pyrolysis to determine an indication of an
acid gas concentration thereof; and d. during an early stage of pyrolysis of
the portion of
the formation, operating the heater(s) at a power level determined in
accordance with the
acid gas concentration.
In some embodiments, the interior region is maintained under anoxic conditions
during the heating.
In some embodiments, the enclosure is an excavated enclosure.
In some embodiments, the enclosure is a pit or an impoundment.
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In some embodiments, the sequestration is subsurface sequestration, for
example,
deep well sequestration.
In some embodiments, the sequestration is subsurface sequestration, for
example, deep
well sequestration in a well-confined saline aquifer gas cap.
In some embodiments, the acid gas threshold value is between 70% and
95%,.
In some embodiments, the acid gas threshold value is between 70% and 95%, for
example at least 85% and/or at most 90%.
In some embodiments, the sequestration is carried out immediately.
In some embodiments, the sequestration is carried out at a much later time.
In some embodiments, subsurface formation is an oil shale formation or a coal
formation or a bitumen formation.
In some embodiments, the kerogen is type IIs kerogen or the bitumen is derived
from type IIs kerogen.
In some embodiments, the kerogen is sulfur-rich type IIs kerogen or the
bitumen
is derived from sulfur-rich type IIs kerogen.
In some embodiments, the acid gas separation process is carried out in an
amine
unit.
In some embodiments, the acid gas elimination process is carried out in a
caustic
system, for example, based upon sodium hydroxide or potassium hydroxide.e.
DETAILED DESCRIPTION OF EMBODIMENTS
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The invention is herein described, by way of example only, with reference to
the
accompanying drawings. With specific reference now to the drawings in detail,
it is
stressed that the particulars shown are by way of example and for purposes of
illustrative
discussion of the preferred embodiments of the exemplary system only and are
presented
in the cause of providing what is believed to be a useful and readily
understood
description of the principles and conceptual aspects of the invention. In this
regard, no
attempt is made to show structural details of the invention in more detail
than is
necessary for a fundamental understanding of the invention, the description
taken with
the drawings making apparent to those skilled in the art how several forms of
the
invention may be embodied in practice and how to make and use the embodiments.
For brevity, some explicit combinations of various features are not explicitly
illustrated in the figures and/or described. It is now disclosed that any
combination of the
method or device features disclosed herein can be combined in any manner ¨
including
any combination of features ¨ and any combination of features can be included
in any
embodiment and/or omitted from any embodiments.
Definitions
For convenience, in the context of the description herein, various terms are
presented here. To the extent that definitions are provided, explicitly or
implicitly, here or
elsewhere in this application, such definitions are understood to be
consistent with the
usage of the defined terms by those of skill in the pertinent art(s).
Furthermore, such
definitions are to be construed in the broadest possible sense consistent with
such usage.
If two numbers A and B are "on the same order of magnitude", then ratio
between
(i) a larger of A and B and (ii) a smaller of A and B is at most 15 or at most
10 or at most
5.
Unless specified otherwise, a 'substantial majority' refers to at least 75%.
Unless
specified otherwise, 'substantially all' refers to at least 90%. In some
embodiments
'substantially all' refers to at least 95% or at least 99%.
For the present disclosure, 'gases' (e.g. hydrocarbon gases) refer to non-
condensable
gases - i.e. not condensable at STP 25 degrees C, 1 atm.
'Early pyrolysis gases' are pyrolysis formation gases that are formed when a
bulk
temperature of the pyrolyzed portion of the formation (or of a bed of kerogen-
containing
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or bitumen-containing rocks) is at most 300 degrees Celsius -- in some
embodiments, at
most 295 degrees Celsius or at most 290 degrees Celsius.
When one quantity A is less than a significantly less than a quantity B, its
value is
at most 30% less than that of B (i.e. A is equal to at most 0.7 B) or at most
one-half of B.
When formation gases are 'acid-gas rich' then a concentration of acid gas
therein
is at least 50% or at least 75% or at least 80% or at least 85% or at least
90%.
When formation gases have 'at most low concentrations of the combination of
hydrogen gas and hydrocarbon gases' then the sum of (i) a concentration of
hydrocarbon
gas; and (ii) a concentration of all non-condensable hydrocarbon gases is at
most 20% or
at most 15% or at most 10% or at most 5%.
For the present disclosure, 'low temperature pyrolysis' is pyrolysis that
occurs at
temperatures of at most 290 degrees Celsius over a period of at least 3 months
or at least
6 months or at least 1 year. In some embodiments, 'low temperature pyrolysis'
occurs
between 270 degrees Celsius and 290 degrees Celsius over this period of at
least 3
months or at least 6 months or at least 1 year. In some embodiments, 'low
temperature
pyrolysis' occurs between 280 degrees Celsius and 290 degrees Celsius over
this period
of at least 3 months or at least 6 months or at least 1 year. In this
temperature range,
pyrolysis proceeds quickly enough to be feasible, while favoring formation of
easier-to-
hydrotreat species.
For the present disclosure, unless otherwise noted, a 'boiling point' refers
to an
atmospheric boiling point.
For the present disclosure, sulfur-rich type IIs kerogen is at least 6% wt/wt
or at
least 7% wt/wt or at least 8% wt/wt sulfur.
FIG. 1 depicts a schematic view of an embodiment of a portion of the in situ
heat
treatment system for treating the hydrocarbon containing formation. The in
situ heat
treatment system may include barrier wells 1200. Barrier wells are used to
form a barrier
around a treatment area. The barrier inhibits fluid flow into and/or out of
the treatment
area. Barrier wells include, but are not limited to, dewatering wells, vacuum
wells,
capture wells, injection wells, grout wells, freeze wells, or combinations
thereof. In some
embodiments, barrier wells 1200 are dewatering wells. Dewatering wells may
remove
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liquid water and/or inhibit liquid water from entering a portion of the
formation to be
heated, or to the formation being heated. In the embodiment depicted in FIG.
1, the
barrier wells 1200 are shown extending only along one side of heater sources
1202, but
the barrier wells typically encircle all heat sources 1202 used, or to be
used, to heat a
treatment area of the formation.
Heat sources 1202 are placed in at least a portion of the formation. Heat
sources
1202 may include heaters such as insulated conductors, conductor-in-conduit
heaters,
surface burners, flameless distributed combustors, and/or natural distributed
combustors.
Heat sources 1202 may also include other types of heaters. Heat sources 1202
provide
heat to at least a portion of the formation to heat hydrocarbons in the
formation. Energy
may be supplied to heat sources 1202 through supply lines 1204. Supply lines
1204 may
be structurally different depending on the type of heat source or heat sources
used to heat
the formation. Supply lines 1204 for heat sources may transmit electricity for
electric
heaters, may transport fuel for combustors, or may transport heat exchange
fluid that is
circulated in the formation. In some embodiments, electricity for an in situ
heat treatment
process may be provided by a nuclear power plant or nuclear power plants. The
use of
nuclear power may allow for reduction or elimination of carbon dioxide
emissions from
the in situ heat treatment process.
When the formation is heated, the heat input into the formation may cause
expansion of the formation and geomechanical motion. The heat sources may be
turned
on before, at the same time, or during a dewatering process. Computer
simulations may
model formation response to heating. The computer simulations may be used to
develop a
pattern and time sequence for activating heat sources in the formation so that
geomechanical motion of the formation does not adversely affect the
functionality of heat
sources, production wells, and other equipment in the formation.
Heating the formation may cause an increase in permeability and/or porosity of
the
formation. Increases in permeability and/or porosity may result from a
reduction of mass
in the formation due to vaporization and removal of water, removal of
hydrocarbons,
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and/or creation of fractures. Fluid may flow more easily in the heated portion
of the
formation because of the increased permeability and/or porosity of the
formation. Fluid in
the heated portion of the formation may move a considerable distance through
the
formation because of the increased permeability and/or porosity. The
considerable
5
distance may be over 1000 m depending on various factors, such as permeability
of the
formation, properties of the fluid, temperature of the formation, and pressure
gradient
allowing movement of the fluid. The ability of fluid to travel considerable
distance in the
formation allows production wells 1206 to be spaced relatively far apart in
the
formation.
Production wells 1206 are used to remove formation fluid from the formation.
In
some embodiments, production well 1206 includes a heat source. The heat source
in the
production well may heat one or more portions of the formation at or near the
production
well. In some in situ heat treatment process embodiments, the amount of heat
supplied to
the formation from the production well per meter of the production well is
less than the
amount of heat applied to the formation from a heat source that heats the
formation per
meter of the heat source. Heat applied to the formation from the production
well may
increase formation permeability adjacent to the production well by vaporizing
and
removing liquid phase fluid adjacent to the production well and/or by
increasing the
permeability of the formation adjacent to the production well by formation of
macro
and/or micro fractures.
More than one heat source may be positioned in the production well. A heat
source
in a lower portion of the production well may be turned off when superposition
of heat
from adjacent heat sources heats the formation sufficiently to counteract
benefits
provided by heating the formation with the production well. In some
embodiments, the
heat source in an upper portion of the production well may remain on after the
heat
source in the lower portion of the production well is deactivated. The heat
source in the
upper portion of the well may inhibit condensation and reflux of formation
fluid.
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In some embodiments, the heat source in production well 1206 allows for vapor
phase removal of formation fluids from the formation. Providing heating at or
through the
production well may: (1) inhibit condensation and/or refluxing of production
fluid when
such production fluid is moving in the production well proximate the
overburden, (2)
increase heat input into the formation, (3) increase production rate from the
production
well as compared to a production well without a heat source, (4) inhibit
condensation of
high carbon number compounds (C6 hydrocarbons and above) in the production
well,
and/or (5) increase formation permeability at or proximate the production
well.
Subsurface pressure in the formation may correspond to the fluid pressure
generated in the formation. As temperatures in the heated portion of the
formation
increase, the pressure in the heated portion may increase as a result of
thermal expansion
of in situ fluids, increased fluid generation and vaporization of water.
Controlling rate of
fluid removal from the formation may allow for control of pressure in the
formation.
Pressure in the formation may be determined at a number of different
locations, such as
near or at production wells, near or at heat sources, or at monitor wells.
In some hydrocarbon containing formations, production of hydrocarbons from the
formation is inhibited until at least some hydrocarbons in the formation have
been
mobilized and/or pyrolyzed. Formation fluid may be produced from the formation
when
the formation fluid is of a selected quality. In some embodiments, the
selected quality
includes an API gravity of at least about 20 , 30 , or 40 . Inhibiting
production until at
least some hydrocarbons are mobilized and/or pyrolyzed may increase conversion
of
heavy hydrocarbons to light hydrocarbons. Inhibiting initial production may
minimize the
production of heavy hydrocarbons from the formation. Production of substantial
amounts
of heavy hydrocarbons may require expensive equipment and/or reduce the life
of
production equipment.
In some hydrocarbon containing formations, hydrocarbons in the formation may
be
heated to mobilization and/or pyrolysis temperatures before substantial
permeability has
been generated in the heated portion of the formation. An initial lack of
permeability may
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inhibit the transport of generated fluids to production wells 1206. During
initial heating,
fluid pressure in the formation may increase proximate heat sources 1202. The
increased
fluid pressure may be released, monitored, altered, and/or controlled through
one or more
heat sources 1202. For example, selected heat sources 1202 or separate
pressure relief
wells may include pressure relief valves that allow for removal of some fluid
from the
formation.
In some embodiments, pressure generated by expansion of mobilized fluids,
pyrolysis fluids or other fluids generated in the formation may be allowed to
increase
although an open path to production wells 1206 or any other pressure sink may
not yet
exist in the formation. The fluid pressure may be allowed to increase towards
a lithostatic
pressure. Fractures in the hydrocarbon containing formation may form when the
fluid
approaches the lithostatic pressure. For example, fractures may form from heat
sources
1202 to production wells 1206 in the heated portion of the formation. The
generation of
fractures in the heated portion may relieve some of the pressure in the
portion. Pressure in
the formation may have to be maintained below a selected pressure to inhibit
unwanted
production, fracturing of the overburden or underburden, and/or coking of
hydrocarbons
in the formation.
After mobilization and/or pyrolysis temperatures are reached and production
from
the formation is allowed, pressure in the formation may be varied to alter
and/or control a
composition of formation fluid produced, to control a percentage of
condensable fluid as
compared to non-condensable fluid in the formation fluid, and/or to control an
API
gravity of formation fluid being produced. For example, decreasing pressure
may result
in production of a larger condensable fluid component. The condensable fluid
component
may contain a larger percentage of olefins.
In some in situ heat treatment process embodiments, pressure in the formation
may
be maintained high enough to promote production of formation fluid with an API
gravity
of greater than 20 . Maintaining increased pressure in the formation may
inhibit
formation subsidence during in situ heat treatment. Maintaining increased
pressure may
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reduce or eliminate the need to compress formation fluids at the surface to
transport the
fluids in collection conduits to treatment facilities.
Maintaining increased pressure in a heated portion of the formation may
surprisingly allow for production of large quantities of hydrocarbons of
increased quality
and of relatively low molecular weight. Pressure may be maintained so that
formation
fluid produced has a minimal amount of compounds above a selected carbon
number.
The selected carbon number may be at most 25, at most 20, at most 12, or at
most 8.
Some high carbon number compounds may be entrained in vapor in the formation
and
may be removed from the formation with the vapor. Maintaining increased
pressure in
the formation may inhibit entrainment of high carbon number compounds and/or
multi-
ring hydrocarbon compounds in the vapor. High carbon number compounds and/or
multi-
ring hydrocarbon compounds may remain in a liquid phase in the formation for
significant time periods. The significant time periods may provide sufficient
time for the
compounds to pyrolyze to form lower carbon number compounds.
Generation of relatively low molecular weight hydrocarbons is believed to be
due,
in part, to autogenous generation and reaction of hydrogen in a portion of the
hydrocarbon containing formation. For example, maintaining an increased
pressure may
force hydrogen generated during pyrolysis into the liquid phase within the
formation.
Heating the portion to a temperature in a pyrolysis temperature range may
pyrolyze
hydrocarbons in the formation to generate liquid phase pyrolyzation fluids.
The generated
liquid phase pyrolyzation fluids components may include double bonds and/or
radicals.
Hydrogen (H2) in the liquid phase may reduce double bonds of the generated
pyrolyzation fluids, thereby reducing a potential for polymerization or
formation of long
chain compounds from the generated pyrolyzation fluids. In addition, H2 may
also
neutralize radicals in the generated pyrolyzation fluids. H2 in the liquid
phase may inhibit
the generated pyrolyzation fluids from reacting with each other and/or with
other
compounds in the formation.
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Formation fluid produced from production wells 1206 may be transported through
collection piping 1208 to treatment facilities 1210. Formation fluids may also
be
produced from heat sources 1202. For example, fluid may be produced from heat
sources
1202 to control pressure in the formation adjacent to the heat sources. Fluid
produced
from heat sources 1202 may be transported through tubing or piping to
collection piping
1208 or the produced fluid may be transported through tubing or piping
directly to
treatment facilities 1210. Treatment facilities 1210 may include separation
units, reaction
units, upgrading units, fuel cells, turbines, storage vessels, and/or other
systems and units
for processing produced formation fluids. The treatment facilities may form
transportation fuel from at least a portion of the hydrocarbons produced from
the
formation. In some embodiments, the transportation fuel may be jet fuel, such
as JP-8.
Formation fluid may be hot when produced from the formation through the
production wells. Hot formation fluid may be produced during solution mining
processes
and/or during in situ heat treatment processes. In some embodiments,
electricity may be
generated using the heat of the fluid produced from the formation. Also, heat
recovered
from the formation after the in situ process may be used to generate
electricity. The
generated electricity may be used to supply power to the in situ heat
treatment process.
For example, the electricity may be used to power heaters, or to power a
refrigeration
system for forming or maintaining a low temperature barrier. Electricity may
be
generated using a Kalina cycle, Rankine cycle or other thermodynamic cycle. In
some
embodiments, the working fluid for the cycle used to generate electricity is
aqua
ammonia.
Some embodiments of the present invention relate to type IIs kerogen (e.g.
sulfur-
rich) or bitumen derivatives thereof. Not wishing to be bound by theory, in
such kerogen
or bitumen (which may be referred to as 'sulfur-rich), the kerogen can be
classified into
two components - 1. Parts (abbreviated as KH_s ) with high concentrations of
sulfur-
sulfur bonds and 2. Parts (abbreviated as KL_s )with low concentrations of
sulfur-sulfur
bonds
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Upon heating a target portion of the kerogen formation to pyrolysis or near-
pyrolysis temperatures, the following chemical reactions may be observed:
KH¨S RR
>H2S Cg+MiSC
("REACTION 1")
AcidGases
5
K RR2 >Oil+ H2 HC
L¨S Gases ("REACTION 2")
It is appreciated that there are analogous reactions for the case of bitumen
formations - for the present disclosure, there is a bitumen analog of any
feature or
10 combination of feature(s) disclosed for the case of kerogen - for
the sake of brevity,
examples are only provided for the non-limiting example of kerogen.
One salient feature of sulfur-rich subsurface kerogen (e.g. Type IIs kerogen
for
example of the Ghareb formation) is that the respective reaction rates may be
15 significantly different at pyrolysis or near-pyrolysis temperatures.
FIG. 2 illustrates
Arrhenius plots of both reactions - the Arrhenius plot for low-sulfur kerogen
is presented
as a broken line while the Arrhenius plot for high-sulfur kerogen is presented
as a double
line. As evident from FIG. 2, (i) at sub-pyrolysis temperatures, the pyrolysis
reaction
rates for both kerogens are negligible; (ii) at low pyrolysis temperatures,
the pyrolysis
reaction rate for low-sulfur kerogen is 'significant' and greatly exceeds that
of the high-
sulfur kerogen; and (ii) at higher pyrolysis temperatures, the pyrolysis
reaction rate for
low-sulfur kerogen is at least on the same order of magnitude as that of high-
sulfur
kerogen, eventually overtaking it at increasing temperatures.
FIG. 3A is a schematic diagram of a system for in-situ thermal treatment of a
hydrocarbon-containing subsurface formation 280 located below an overburden
276 and
above an underburden 288. A plurality of heaters 220 (e.g. electrical heaters
or molten
salt heaters) are deployed within a target portion 284 of the hydrocarbon-
containing
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subsurface formation 280. Thermal energy is transferred from the heaters 220
to the
target portion 284 so as to heat the target portion 284 and to eventually
pyrolyze kerogen
therein. As evident from FIG. 2, pyrolysis may occur in stages - at lower
temperatures
(and during an earlier stage of pyrolysis), the formation fluids may include
significant
quantities of acid gases, while at higher temperatures (and during later
stages of
pyrolysis), the concentration of acid gases within the formation fluids may
drop.
FIG. 3A relates to the specific non-limiting example where the hydrocarbon-
containing subsurface formation 280 is a kerogen formation - in other
examples, the
hydrocarbon-containing subsurface formation 280 is a bitumen formation.
As illustrated in FIG. 3A, one or more production wells 224 are also deployed
within the pyrolyzed target portion 284. When sufficiently heated by heaters
220,
formation fluids including formation gases are recovered via production
well(s) 224. For
example, a gas mixture stream 296 of pyrolysis formation gases generated by
pyrolysis of
the target portion 284 may exit the production well(s) 224. As illustrated in
FIG. 7, gases
of the gas mixture stream 296 may flow to gas treatment facility 282.
Embodiments of the invention are described in the context of in-situ pyrolysis
as
illustrated in FIG. 3A. However, the presently disclosed teachings are equally
applicable
for pyrolysis of a kerogen or bitumen of bed of hydrocarbon-containing rocks
(e.g.
kerogen-containing rocks) located within an enclosure -- for example, an
excavated
enclosure such as a pit or embodiment. Examples of such pyrolysis are
illustrated in
FIGS. 3B-3D. Various modifications of the system of FIG. 3A are illustrated in
FIGS. 7-
8 -- the skilled artisan will appreciate that similar modifications may be
made to the
system of FIGS. 3B-D.
FIG. 4 describes the normalized cumulative production of acid gases (i.e.
hydrogen sulfide and carbon dioxide) and valuable gases (i.e. hydrogen gas and
hydrocarbon gases) as a function of time according to one example where
subsurface
heaters 220 are operated at constant and full power (see FIG. 5). Each curve
has a
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minimum of '0' and a maximum of '1' and is respectively normalized by the
total amount
of acid gases and total amount of valuable gases that are produced from the
subsurface
kerogen or bitumen formation during the pyrolysis process.
In FIG. 4, time(Ti) refers to the time when the temperature first reaches T1,
and
time(T2) refers to the time when the temperature first reaches T2.
In one non-example relating to the Ghareb formation in Jordan, T1 can be about
220 or about 230 or about 240 or about 250 degrees Celsius and T2 can be about
300 or
about 290 degrees Celsius.
Initially, a bulk temperature of the target portion 284 of the kerogen or
bitumen
formation 280 is very low (i.e. less than time(Ti)) and a rate of pyrolysis is
insignificant.
Once the bulk temperature reaches a certain temperature range between T1 and
T2
corresponding to the low temperature pyrolysis regime of FIG. 2, the reaction
rate R1 of
"REACTION 1" is significant, while the reaction rate R2 of "REACTION 2"
remains
insignificant. At this time, a formation gas mixture stream 296 is rich in
acid gases while
a concentration of H2- rich and hydrocarbon gas (i.e. the valuable gases)
therein is
relatively low. The time window corresponding to the (Ti , T2) temperature
window is
shaded in FIG. 4 - during this period of time the concentration of valuable
gases within
stream 296 is low, and the amount of normalized cumulative production of
valuable gases
from the target portion 284 of the formation 280 is also relatively small, as
illustrated in
FIG. 4.
During a later stage of pyrolysis, when the bulk temperature of the target
portion
284 of the kerogen or bitumen exceeds T2 and corresponds to the high pyrolysis
temperature regime of FIG. 2, the normalized amount of produced valuable gases
is
relatively high, and the concentration of valuable gases within gas mixture
stream 296 is
also significant. This is represented in FIG. 4 as the period of time after
time(T2)=
As noted above, both FIG. 4 and FIG. 5 relate to the case where subsurface
heaters 220 are operated at constant and full power (see the 'heater power
level' curve of
FIG. 5 represented as a triple line). Reference is now made to FIG. 5.
Initially, for times
less than time(T 1), the bulk temperature of the target portion 284 of kerogen
or bitumen
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formation 280 increases steadily - for example, at a substantially constant
rate. When the
temperature reaches the low pyrolysis temperature regime between T1 and T2,
heaters
continue to operate at or near full power, and a bulk temperature of the of
kerogen or
bitumen formation 280 continues to increase at a rate on the same order of
magnitude as
that observed at lower temperatures below T1. At bulk temperatures above T2,
in the high
pyrolysis temperature regime, the bulk temperature of the formation increases
at a much
lower rate and/or remains substantially constant. As illustrated in FIG. 5,
after time(T2),
the majority (e.g. a significant or very significant majority) of hydrocarbon
fluids are
produced - e.g. recovered via production well(s) 224.
FIG. 6 illustrates experimental data generated by pyrolyzing a sample of oil
shale
(i.e. a kerogeneous chalk) from the Ghareb formation in the laboratory. The
abscissa
T[ C] is the temperature of the oil shale sample and the ordinate Q [m]/min]
is the flow
rate of various pyrolysis gases when the oil shale sample is heated to a
particular
temperature. For temperatures less than 220 degrees Celsius, the absolute flow
rate of
pyrolysis formation gases Q is very small. At higher temperatures, the flow
rate is
significantly larger and the concentration of acid gases (H2S and C0x) within
the flow of
formation gases from the oil shale sample is quite significant. At higher
temperatures
(e.g. above 300 degrees Celsius), the absolute flow rate of acid gases drops
slowly, while
the concentration of acid gases within the flow stream of pyrolysis formation
gases drops
dramatically as significant flow rates of hydrogen, hydrocarbons fluids are
observed.
In the apparatus of FIG. 7, a gas detector 270 (for example, a Gas
Chomotography
instrument) may detect a concentration of acid gases within the formation gas
mixture
stream 296. One manufacturer of Gas chromatography instruments is Agilent of
Colorado (United States of America).
In the apparatus of FIG. 3 all gases of the gas mixture stream 296 of
pyrolysis
formation gases are directed to a gas treatment facility 282. In contrast, in
FIG. 7, flow
control 224 may direct gases of gas mixture stream 296 to deep injection well
260. In a
first example related to time-based separation of acid gases from valuable
gases, (i) for a
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first period of time (e.g. corresponding to the time window TW T1_ T2 defined
by
(time(Ti), time(T2))), all gases of formation gas mixture stream 296 are
directed by flow
control 224 to deep injection well 260 for sequestration, and (ii) for a
second period of
time, for example, commencing at time(T2), all gases of formation gas mixture
stream
296 are directed by flow control 224 to gas treatment facility 282.
In the example of FIG. 3, all gases of formation gas mixture stream 296 are
sent
to gas treatment facility 282 - in this situation, 'early pyrolysis gases' of
gas mixture
stream 296 formed during time window TW T1_ T2 and when the bulk temperature
of
the target portion 284 may mix with 'later pyrolysis gases' that formed after
time(T2). As
noted above, the early pyrolysis gases are H2S-rich and C0x-rich and are
characterized
by at most low concentrations of H2 and hydrocarbon gases while the
concentration of
H2S and COx within hydrocarbon-rich and H2-rich 'later gases' is much lower.
In order to
obtain, from the mixture of the early pyrolysis gases and the later pyrolysis
gases, a
product of valuable gases that is relatively free of acid gases, it is
necessary to subject a
relatively large quantity of gases (i.e. the combined quantity of early and
later pyrolysis
gases) to a gas component separation process - for example, within gas
treatment facility
282.
Additional Discussion Related to FIGS. 3B-3D
Embodiments of the present invention relate to apparatus and methods for
heating
hydrocarbon-containing matter (e.g. tar sands or kerogen-containing rocks such
as pieces
of coal or pieces of oil shale) within an enclosure such as a pit or an
impoundment or a
container. Hydrocarbon-containing rocks are introduced into the enclosure to
form a bed
(e.g. a packed-bed) of rock therein. Oxygen may be evacuated (e.g. under
vacuum or by
means of an inert sweep gas) to create a substantially oxygen-free environment
within the
enclosure. In different embodiments, the enclosure may be a pit, or an
impoundment or a
container. The enclosure may be entirely below ground level, partially below
and
partially above, or entirely above ground level.
Operation of heaters in thermal communication with the hydrocarbon-containing
rocks may sufficiently heat the rocks to convert kerogen or bitumen thereof
into pyrolysis
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formation fluids comprising hydrocarbon pyrolysis fluids. The formation fluids
may be
recovered via production conduits, or via a liquid outlet located at or near
the bottom of
the enclosure and/or via a vapor outlet located near the top of the enclosure,
or in any
other manner.
5
Examples of hydrocarbon-containing rocks are kerogen-containing rocks (e.g.
mined oil shale or mined coal) and bitumen-containing rocks (e.g. tar sands).
In the description and claims of the present application, each of the verbs,
"comprise" "include" and "have", and conjugates thereof, are used to indicate
that the
10 object
or objects of the verb are not necessarily a complete listing of members,
components, elements or parts of the subject or subjects of the verb.
All references cited herein are incorporated by reference in their entirety.
Citation
of a reference does not constitute an admission that the reference is prior
art.
The articles "a" and "an" are used herein to refer to one or to more than one.
(i.e.,
15 to at
least one) of the grammatical object of the article. By way of example, "an
element"
means one element or more than one element.
The term "including" is used herein to mean, and is used interchangeably with,
the
phrase "including but not limited" to.
The term "or" is used herein to mean, and is used interchangeably with, the
term
20 "and/or," unless context clearly indicates otherwise.
The term "such as" is used herein to mean, and is used interchangeably, with
the
phrase "such as but not limited to".
The present invention has been described using detailed descriptions of
embodiments thereof that are provided by way of example and are not intended
to limit
the scope of the invention. The described embodiments comprise different
features, not
all of which are required in all embodiments of the invention. Some
embodiments of the
present invention utilize only some of the features or possible combinations
of the
features. Variations of embodiments of the present invention that are
described and
embodiments of the present invention comprising different combinations of
features
noted in the described embodiments will occur to persons skilled in the art.
